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[Federal Register Volume 89, Number 235 (Friday, December 6, 2024)]
[Rules and Regulations]
[Pages 97174-97354]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-27982]

[[Page 97173]]

Vol. 89

Friday,

No. 235

December 6, 2024

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation; Final Rule

Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / 
Rules and Regulations

[[Page 97174]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM21-17-001; Order No. 1920-A]

Building for the Future Through Electric Regional Transmission 
Planning and Cost Allocation

AGENCY: Federal Energy Regulatory Commission, Department of Energy 
(DOE).

ACTION: Order on rehearing and clarification.

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SUMMARY: In this order, the Federal Energy Regulatory Commission 
addresses arguments raised on rehearing, sets aside, in part, and 
clarifies Order No. 1920, which required transmission providers to 
conduct Long-Term Regional Transmission Planning to ensure the 
identification, evaluation, and selection, as well as the allocation of 
the costs, of more efficient or cost-effective regional transmission 
solutions to address Long-Term Transmission Needs. Order No. 1920 also 
directed other reforms to improve coordination of regional transmission 
planning and generator interconnection processes, require consideration 
of certain alternative transmission technologies in regional 
transmission planning processes, and improve transparency of local 
transmission planning processes and coordination between regional and 
local transmission planning processes.

DATES: The changes to Order No. 1920 made in this order on rehearing 
and clarification will be effective on January 6, 2025.

FOR FURTHER INFORMATION CONTACT: 
    Michael Kellermann (Legal Information), Office of the General 
Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8491, 
[email protected].
    Patrick T. Metz (Legal Information), Office of the General Counsel, 
888 First Street NE, Washington, DC 20426, (202) 502-8197, 
[email protected].
    David Tobenkin (Technical Information), Office of Energy Policy and 
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6445, 
[email protected].
    Noah Lichtenstein (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696, 
[email protected].

SUPPLEMENTARY INFORMATION: 

 
                                                               Paragraph
                                                                 Nos.
 
I. Executive Summary........................................           1
II. Introduction and Background.............................          20
III. The Overall Need for Reform............................          34
    A. Order No. 1920.......................................          34
        1. The Transmission Investment Landscape Today......          38
        2. Unjust, Unreasonable, and Unduly Discriminatory            46
         or Preferential Commission-Jurisdictional
         Transmission Planning and Cost Allocation Processes
        3. Benefits of Long-Term Regional Transmission                59
         Planning and Cost Allocation To Identify and Plan
         for Long-Term Transmission Needs...................
    B. The Commission Adequately Demonstrated That Existing           61
     Rates, or Practices Affecting Rates, Are Unjust and
     Unreasonable...........................................
        1. The Commission Correctly Characterized Its                 62
         Statutory Burden...................................
        2. The Commission Adequately Supported Its                    70
         Determination on Step One of Section 206...........
        3. The Commission Identified Deficiencies That Exist          87
         Beyond Isolated Pockets............................
        4. The Commission Has the Authority To Conduct a              98
         Generic Rulemaking.................................
    C. The Commission Demonstrated That the Replacement Rate         104
     is Just and Reasonable.................................
        1. Requests for Rehearing...........................         104
        2. Commission Determination.........................         107
    D. The Commission's Section 206 Findings Were Not                115
     Circular...............................................
        1. Requests for Rehearing...........................         115
        2. Commission Determination.........................         119
IV. Statutory Authority.....................................         125
    A. Order No. 1920 Determination.........................         125
    B. Federal/State Division of Authority..................         132
        1. Requests for Rehearing...........................         132
        2. Commission Determination.........................         135
    C. Major Questions Doctrine.............................         166
        1. Requests for Rehearing...........................         166
        2. Commission Determination.........................         171
    D. Other Issues.........................................         186
        1. Requests for Rehearing...........................         186
        2. Commission Determination.........................         192
V. Long-Term Regional Transmission Planning.................         200
    A. Requirement To Participate in Long-Term Regional              200
     Transmission Planning..................................
        1. Order No. 1920 Requirements......................         200
        2. Requests for Rehearing and Clarification.........         205
        3. Commission Determination.........................         210
    B. Long-Term Scenarios Requirements.....................         218
        1. Requirement for Transmission Providers To Use the         218
         Seven Required Benefits To Help To Inform Their
         Identification of Long-Term Transmission Needs.....
        2. Transmission Planning Horizon....................         227
        3. Frequency of Long-Term Scenario Revisions........         248
        4. Categories of Factors............................         263
        5. Requests for Additional Flexibility Regarding             351
         Long-Term Scenarios Requirements...................
    C. Evaluation of the Benefits of Regional Transmission           369
     Facilities.............................................
        1. Requirement for Transmission Providers To Use and         369
         Measure a Set of Seven Required Benefits...........
        2. Measurement and Use of Other Benefits............         411

[[Page 97175]]

 
        3. Identification, Measurement, and Evaluation of            417
         Benefits...........................................
        4. Benefits Horizon.................................         421
        5. Evaluation of the Benefits of Portfolios of               428
         Transmission Facilities............................
    D. Evaluation and Selection of Long-Term Regional                434
     Transmission Facilities................................
        1. Minimum Requirements.............................         434
        2. Role of Relevant State Entities..................         452
        3. Voluntary Funding................................         461
        4. No Selection Requirement.........................         466
        5. Reevaluation.....................................         469
    E. Implementation of Long-Term Regional Transmission             502
     Planning...............................................
        1. Order No. 1920 Requirements......................         502
        2. Requests for Rehearing and Clarification.........         505
        3. Commission Determination.........................         507
VI. Coordination of Regional Transmission Planning and               511
 Generator Interconnection Processes........................
    A. Need for Reform and Overall Requirement..............         511
        1. Order No. 1920 Requirements......................         511
        2. Requests for Rehearing...........................         513
        3. Commission Determination.........................         516
    B. Qualifying Criteria..................................         525
        1. Order No. 1920 Requirements......................         525
        2. Requests for Rehearing and Clarification.........         532
        3. Commission Determination.........................         538
    C. Cost Allocation......................................         557
        1. Order No. 1920 Requirements......................         557
        2. Requests for Rehearing and Clarification.........         558
        3. Commission Determination.........................         562
    D. Gaming...............................................         566
        1. Order No. 1920 Requirements......................         566
        2. Requests for Rehearing and Clarification.........         567
        3. Commission Determination.........................         570
    E. Transmission Planning Process Evaluation.............         572
        1. Order No. 1920 Requirements......................         572
        2. Requests for Rehearing and Clarification.........         574
        3. Commission Determination.........................         582
VII. Consideration of Dynamic Line Ratings and Advanced              594
 Power Flow Control Devices.................................
    A. Order No. 1920 Requirements..........................         594
    B. Requests for Rehearing and Clarification.............         596
        1. General Requests for Rehearing and Clarification.         596
        2. Technology Specific Requests for Rehearing and            601
         Clarification......................................
VIII. Regional Transmission Cost Allocation.................         610
    A. Obligation To File an Ex Ante Long-Term Regional              610
     Transmission Cost Allocation Method and Its Use as a
     Backstop...............................................
        1. Logical Outgrowth................................         610
        2. Substantive Issues...............................         618
    B. Requirements Concerning Relevant State Entities......         635
        1. Requested Requirement To Obtain the Agreement of          635
         Relevant State Entities............................
        2. Requirements Concerning Relevant State Entities'          642
         Preferred Cost Allocation Methods..................
    C. Design and Operation of the Engagement Period........         663
        1. Logical Outgrowth................................         663
        2. Requests Arguing the Engagement Period is                 669
         Inferior to a Requirement That Transmission
         Providers Seek the Agreement of Relevant State
         Entities...........................................
        3. Duration of the Engagement Period................         674
        4. Content of the Engagement Period.................         679
        5. Consultation With Relevant State Entities After           687
         the Engagement Period..............................
    D. Design and Operation of State Agreement Processes....         693
        1. Definition of Relevant State Entities............         693
        2. Extensions of Time for Negotiation of Cost                705
         Allocation Methods Under State Agreement Processes.
    E. Use of Existing Cost Allocation Methods in Long-Term          709
     Regional Transmission Planning or Existing Regional
     Processes..............................................
        1. Order No. 1920 Requirements......................         709
        2. Requests for Rehearing and Clarification.........         710
        3. Commission Determination.........................         712
    F. Regional Cost Allocation Principles for Long-Term             718
     Regional Transmission Facilities.......................
        1. Logical Outgrowth................................         718
        2. Omission of Regional Cost Allocation Principle            728
         No. 6 and Ability To Allocate Costs by Type of
         Project............................................
        3. Concerns Regarding Cost Causation................         753
    G. General Benefits Requirements Related to Cost                 769
     Allocation.............................................
        1. Logical Outgrowth................................         769
        2. Substantive Issues...............................         775
    H. Additional Cost Allocation Issues....................         781
        1. Order No. 1920 Requirements......................         781
        2. Requests for Rehearing and Clarification.........         784
        3. Commission Determination.........................         789
IX. Construction Work in Progress Incentive.................         794
    A. CWIP.................................................         794

[[Page 97176]]

 
        1. Order No. 1920...................................         794
        2. Requests for Rehearing and Clarification.........         795
        3. Commission Determination.........................         799
X. Exercise of a Federal Right of First Refusal in                   801
 Commission-Jurisdictional Tariffs and Agreements...........
    A. Order No. 1920 Requirements..........................         801
    B. Request for Rehearing................................         802
    C. Commission Determination.............................         803
XI. Local Transmission Planning Inputs in the Regional               804
 Transmission Planning Process..............................
    A. Need for Reform......................................         804
        1. Order No. 1920...................................         804
        2. Analysis Under FPA Section 206...................         813
        3. Departure From Commission Precedent..............         824
        4. Commission Authority Under the FPA...............         828
        5. Policy Against Anticompetitive Practices.........         840
        6. Other Arguments..................................         843
    B. Enhanced Transparency of Local Transmission Planning          847
     Inputs in the Regional Transmission Planning Process...
        1. Order No. 1920...................................         847
        2. Requests for Additional Reforms..................         851
        3. Stakeholder Meeting Clarifications...............         859
    C. Identifying Potential Opportunities to Right-Size             863
     Replacement Transmission Facilities....................
        1. Eligibility......................................         863
        2. Right of First Refusal for Right-Sized                    882
         Replacement Transmission Facilities Selected To
         Meet Long-Term Transmission Needs..................
        3. Confidentiality of In-Kind Replacement Estimates.         895
XII. Interregional Transmission Coordination................         899
    A. Order No. 1920.......................................         899
    B. Comments.............................................         901
    C. Commission Determination.............................         902
XIII. Compliance Procedures.................................         903
    A. Order No. 1920.......................................         903
    B. Requests for Rehearing and Clarification.............         907
    C. Commission Determination.............................         914
XIV. Overarching Logical Outgrowth Challenges...............         927
    A. Requests for Rehearing...............................         927
    B. Commission Determination.............................         930
XV. Information Collection Statement........................         932
XVI. Environmental Analysis.................................         950
XVII. Regulatory Flexibility Act............................         951
XVIII. Document Availability................................         953
XIX. Effective Date.........................................         956
Appendix A: Abbreviated Names of Parties....................  ..........
Appendix B: Pro Forma Open Access Transmission Tariff         ..........
 Attachment K...............................................
 

I. Executive Summary

    1. In Order No. 1920,\1\ the Federal Energy Regulatory Commission 
(Commission) revised the pro forma Open Access Transmission Tariff 
(OATT) to adopt reforms to its existing electric transmission planning 
and cost allocation requirements pursuant to section 206 of the Federal 
Power Act (FPA).\2\ The Commission found that existing regional 
transmission planning and cost allocation processes are unjust, 
unreasonable, and unduly discriminatory or preferential because, inter 
alia, the Commission's existing transmission planning and cost 
allocation requirements do not require transmission providers to: (1) 
perform a sufficiently long-term assessment of transmission needs that 
identifies Long-Term Transmission Needs; \3\ (2) adequately account on 
a forward-looking basis for known determinants of Long-Term 
Transmission Needs; and (3) consider a set of benefits of regional 
transmission facilities planned to meet those Long-Term Transmission 
Needs.\4\ Order No. 1920 addressed these deficiencies by establishing 
requirements to ensure that Commission-jurisdictional rates remain just 
and reasonable and not unduly discriminatory or preferential including, 
inter alia, requiring transmission providers to conduct Long-Term 
Regional Transmission Planning \5\ that will ensure the identification, 
evaluation, and selection of more efficient or cost-effective regional 
transmission facilities to address Long-Term Transmission Needs, as 
well as the just and reasonable allocation of the costs of those 
facilities. By expanding the time horizon and scope of Commission-
jurisdictional regional transmission planning processes, Order No. 1920 
reflected an evolutionary step in the Commission's ongoing commitment 
\6\ to ensure that those

[[Page 97177]]

processes remain just and reasonable and meet the needs of the American 
people.
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    \1\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation, Order No. 1920, 89 FR 49280 (June 11, 
2024), 187 FERC ] 61,068 (2024).
    \2\ 16 U.S.C. 824e.
    \3\ See infra Introduction and Background section (defining 
``Long-Term Transmission Needs'').
    \4\ Order No. 1920, 187 FERC ] 61,068 at P 1.
    \5\ See infra Introduction and Background section (defining 
``Long-Term Regional Transmission Planning).
    \6\ See Preventing Undue Discrimination & Preference in 
Transmission Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC 
Stats. & Regs. ] 31,241, 118 FERC ] 61,119 (2007), order on reh'g, 
Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 
31,261 (2007) (cross-referenced at 118 FERC ] 61,119), order on 
reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 
2008), 123 FERC ] 61,299 (2008), order on reh'g, Order No. 890-C, 74 
FR 12540 (Mar. 25, 2009), 126 FERC ] 61,228 (2009), order on 
clarification, Order No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 
FERC ] 61,126 (2009); Transmission Plan. & Cost Allocation by 
Transmission Owning & Operating Pub. Utils., Order No. 1000, 76 FR 
49842 (Aug. 11, 2011), 136 FERC ] 61,051 (2011), Order No. 1000-A, 
77 FR 32184 (May 31, 2012), 139 FERC ] 61,132 (2012), order on reh'g 
& clarification, Order No. 1000-B, 141 FERC ] 61,044 (2012), aff'd 
sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) 
(per curiam).
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    2. In this order, we refine and improve Long-Term Regional 
Transmission Planning by building on the reforms adopted in Order No. 
1920, with a particular focus on ensuring that states have a robust 
role in Long-Term Regional Transmission Planning and cost allocation 
processes established in this rule. We continue to find, as the 
Commission did in the final rule, that the key components of Order No. 
1920 together ensure that transmission providers will conduct 
sufficiently long-term, forward-looking, and comprehensive transmission 
planning and cost allocation processes. At least once every five years, 
transmission providers are required to conduct Long-Term Regional 
Transmission Planning, a process that includes looking ahead over a 20-
year transmission planning horizon. This process further requires 
developing at least three plausible and diverse Long-Term Scenarios \7\ 
that are based upon known drivers of transmission needs and informed by 
best available data; analyzing the impacts of events like extreme 
weather under each Long-Term Scenario; and evaluating potential Long-
Term Regional Transmission Facilities.\8\ This evaluation includes 
assessing whether these facilities would yield reliability and economic 
benefits to transmission customers and, if so, identifying those 
benefits. Together, these reforms ensure that transmission providers, 
state regulators, and stakeholders possess the information necessary 
for each transmission planning region to identify, evaluate, and select 
(i.e., determine whether to pursue the development of facilities) more 
efficient or cost-effective transmission facilities that provide 
significant benefits for customers.
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    \7\ See infra Introduction and Background section (defining 
``Long-Term Scenario'').
    \8\ See infra Introduction and Background section (defining 
``Long-Term Regional Transmission Facility'').
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    3. Here, we adopt a number of modifications and clarifications to 
address the concerns raised in response to Order No. 1920. Order No. 
1920 recognized the important role that states will play in Long-Term 
Regional Transmission Planning and established various requirements to 
facilitate their participation in those processes, including requiring 
transmission providers to engage with states in developing cost 
allocation approaches for Long-Term Regional Transmission Facilities. 
With this order, we reaffirm and enhance that finding by recognizing 
that meaningful engagement with states is critical to the success of 
the Long-Term Regional Transmission Planning reforms established in 
Order No. 1920. Specifically, in response to rehearing and 
clarification requests, we better integrate states' input into regional 
transmission planning and cost allocation processes, both in the 
transmission providers' development of Order No. 1920 compliance 
filings and the ongoing implementation of these reforms in the future. 
These modifications and clarifications address many of the concerns 
raised in the rehearing requests submitted in response to Order No. 
1920, and they will increase the likelihood that Long-Term Regional 
Transmission Planning results in efficient and cost-effective 
transmission investment.
    4. In this order, we also clarify what this rule does, and does 
not, require. Because Order No. 1920 mandates only improvements to 
transmission planning processes which, in turn, ensures foundational 
transparency about potential transmission development, Order No. 1920 
does not force or mandate the development of certain transmission 
facilities. A requirement to develop a structured process to analyze 
whether building certain transmission facilities would yield benefits 
greater than their costs, over the long term and based upon various 
future scenarios, will help transmission providers and states to assess 
the value that those projects could bring. However, such process-based 
requirements are not the same as a requirement to build any particular 
transmission facilities. More precisely, Order No. 1920 does not 
require transmission providers to select any particular transmission 
facility; does not automatically authorize transmission developers to 
develop or construct any specific facilities; and does not mandate any 
specific set of transmission customers to pay for any particular 
transmission facilities. Instead, Order No. 1920 and this order 
together set out processes that direct transmission planning regions to 
systematically consider various drivers of transmission needs and 
develop cost allocation approaches that yield the development of cost-
effective transmission projects and thereby yield just and reasonable 
rates for customers.
    5. As such, Long-Term Regional Transmission Planning as required by 
Order No. 1920 is a significant step forward in the Commission's 
responsibility to ensure just and reasonable and not unduly 
discriminatory or preferential rates. By establishing minimum standards 
based on transmission planning best practices observed around the 
country for forecasting future scenarios and managing the uncertainty 
inherent in forward-looking planning, the Long-Term Regional 
Transmission Planning requirements established in this proceeding will 
lead transmission providers to re-direct investment toward more 
efficient or cost-effective regional transmission facilities, and 
ultimately produce greater benefits for transmission customers.
    6. Moreover, improving regional transmission planning practices is 
an urgent concern in light of the uncontroverted, rapidly changing 
circumstances on the grid, including load growth; the increased impacts 
of extreme weather; affordability concerns; and changing economics and 
policies that shape the resource mix and demand, which are increasing 
the need for transmission across the country. To cost-effectively meet 
these needs, Order No. 1920 and this order set out systematic processes 
that transmission providers will use to identify and analyze 
transmission projects that bring benefits to consumers, while 
recognizing the need for flexibility to account for regional 
differences.
    7. Order No. 1920 follows in the footsteps of Order Nos. 890 and 
1000 when it comes to the requirements governing the selection of 
potential regional transmission facilities identified through Long-Term 
Regional Transmission Planning. Consistent with the core theory of 
Order Nos. 890 and 1000, even though Order No. 1920 does not require 
the buildout of specific transmission facilities, it will reveal the 
benefits of designing and developing transmission projects and enable 
investment in those that yield great benefits for electricity customers 
across the country. Ultimately, we expect Order No. 1920 to lead to the 
development of more efficient or cost-effective transmission facilities 
through improved analysis and transparency that empower the 
transmission planning regions with the information needed to make 
prudent investments in beneficial transmission infrastructure for 
customers.
    8. Order No. 1920's requirements for regional cost allocation 
practices are similarly well grounded in Commission and court 
precedent. If more efficient or cost-effective Long-Term Regional 
Transmission Facilities are identified and determined to be worth 
developing as a result of the enhanced regional transmission planning 
required by Order No. 1920, customers will pay for these facilities 
only to the extent that

[[Page 97178]]

they benefit from them. That is because Order No. 1920 requires, 
consistent with well-established law and Orders No. 890 and 1000, that 
any cost allocation must comply with cost causation and the 
``beneficiary pays'' principle.\9\ Thus, Order No. 1920 will not lead 
one group of customers to pay for more than their fair share of the 
costs of transmission development because any proposal to charge 
customers for costs that are not ``roughly commensurate'' with the 
benefits they are expected to receive from Long-Term Regional 
Transmission Facilities would contravene the final rule.\10\
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    \9\ See PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ] 
61,063, at P 66 (2007) (requiring PJM to set forth a ``beneficiary 
pays'' method in its tariff and consistently apply that approach 
each time a new regionally-planned transmission facility is 
approved), on reh'g, Opinion No. 494-A, 122 FERC ] 61,082 (2008), 
remanded Ill. Com. Comm'n v. FERC, 576 F.3d 470, 474-78 (7th Cir. 
2009) (ICC v. FERC I) (remanding Commission order for further 
proceedings in light of Commission's failure to provide substantial 
evidence supporting Commission's approval of cost allocation method 
as complying with ``beneficiary pays'' principle).
    \10\ See ICC v. FERC I, 576 F.3d at 477 (holding that, if the 
Commission cannot quantify the benefits of particular transmission 
facilities to a particular class of transmission customers, it must 
have ``an articulable and plausible reason to believe that the 
benefits [of those facilities] are at least roughly commensurate 
with'' the costs to be paid by those customers).
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    9. Order No. 1920 builds on Order No. 1000's cost allocation 
requirements. Order No. 1000 required transmission providers to 
incorporate into their tariffs a default (``ex ante'') cost allocation 
approach that, if transmission facilities are determined to be worth 
investing in based upon the results of the regional transmission 
planning process, would provide a mechanism for those transmission 
customers that benefit to pay for those projects. Prior to Order No. 
1000, transmission providers did not necessarily have the means to 
charge transmission customers located within a particular transmission 
planning region, but outside their individual service territories, for 
the costs of regional transmission facilities that benefit customers 
throughout the region. Thus, the requirement to establish an ex ante 
cost allocation method in each OATT that would apply if a regional 
transmission planning process resulted in the selection of more 
efficient or cost-effective transmission facilities was central to 
ensuring that those facilities could actually be developed. Like Order 
No. 1000, Order No. 1920 requires each transmission provider to 
establish at least one ex ante cost allocation method through which the 
costs of Long-Term Regional Transmission Facilities will be allocated 
in a manner consistent with the ``beneficiary pays'' principle. Just 
like in Order No. 1000, the requirement to establish a mechanism by 
which the costs of selected transmission facilities may be allocated to 
relevant benefitting transmission customers does not mandate any 
particular method that transmission providers or planning regions must 
adopt.
    10. Importantly, Order No. 1920 provides additional flexibility to 
transmission providers and states regarding cost allocation. While 
transmission providers under Order No. 1000 must adopt a cost 
allocation method for each type of transmission facility, Order No. 
1920 relaxes this requirement. Furthermore, the modifications and 
clarifications granted on rehearing expand states' critical role in 
determining the cost allocation approach most suitable for each 
transmission planning region. These modifications and clarifications 
are necessary because the Commission recognizes that states play a 
critical role in the successful planning of, the decision about how to 
pay for, and ultimately, the deployment of beneficial regional 
transmission facilities.
    11. For example, under Order No. 1920 as modified in this order, 
Relevant State Entities have an opportunity to negotiate their 
preferred ex ante cost allocation method(s) in the first instance, 
including being able to secure an extension of time if needed to 
continue those negotiations. Upon reaching agreement, Relevant State 
Entities can present their preferred approach to the transmission 
provider, which then will either propose that approach to the 
Commission in its compliance filing for this rule, or if the 
transmission provider submits a different proposal, will include in its 
compliance filing the states' preferred approach for the Commission to 
consider.
    12. This order further improves states' ability to negotiate cost 
allocation methods. Under Order No. 1920, states, through Relevant 
State Entities,\11\ have an opportunity to secure the right to 
negotiate alternate cost allocation methods in the future, for either 
an individual transmission facility or a group of them, instead of 
using the ex ante cost allocation method on file in transmission 
providers' OATTs. This State Agreement Process \12\ allows Relevant 
State Entities to consider, for example, whether certain Long-Term 
Regional Transmission Facilities largely provide a unique set of 
benefits such that the costs of those facilities are appropriately paid 
for in a different manner than under the ex ante cost allocation 
method. And, going forward, we require transmission providers to 
consult with Relevant State Entities regarding potential future changes 
to ex ante cost allocation methods and State Agreement Processes used 
in Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \11\ See infra Introduction and Background section (defining 
``Relevant State Entity'').
    \12\ See infra Introduction and Background section (defining 
``State Agreement Process'').
---------------------------------------------------------------------------

    13. Order No. 1920 provides greater flexibility than Order No. 1000 
to deviate from the ex ante cost allocation method or to establish more 
than one ex ante cost allocation method. We also provide new 
opportunities for states to influence each of these choices because 
better enabling state input into cost allocation choices helps to 
ensure that more efficient or cost-effective Long-Term Regional 
Transmission Facilities that are likely to be sited and constructed 
only with state regulatory approval are ultimately developed 
successfully. Given that Order No. 1920 continues to afford 
considerable flexibility to transmission providers and Relevant State 
Entities to determine the cost allocation methods appropriate for their 
transmission planning region and retains the core obligation that any 
cost allocation method filed must be consistent with cost causation, 
the beneficiary pays principle, and other statutory requirements, we 
believe that cost allocation under this rule will result in just and 
reasonable rates. Order No. 1920 requires no more than Order No. 1000--
that some mechanism for charging customers for more efficient or cost-
effective transmission facilities be available in case such facilities 
are determined, after evaluation through Long-Term Regional 
Transmission Planning, to be worth developing. In fact, Order No. 1920 
expands the opportunities for transmission providers, state regulators, 
and stakeholders to ensure that the costs of Long-Term Regional 
Transmission Facilities are allocated only ``roughly commensurate'' 
with the benefits expected to result from those facilities.
    14. As noted above, we agree with certain arguments raised on 
rehearing and/or clarification of Order No. 1920. The instances where 
we modify the discussion in Order No. 1920 and set aside the result of 
Order No. 1920 generally fall into three categories. First, as 
discussed above, we further enhance the role of Relevant State Entities 
in Long-Term Regional Transmission Planning, especially their role in 
shaping the development of Long-Term Scenarios and cost allocation 
methods. Second, we clarify that, when Relevant State Entities request, 
transmission providers must develop a reasonable

[[Page 97179]]

number of additional scenarios to help inform the development or 
application of cost allocation methods. And third, we remove the 
requirement that transmission providers include corporate commitments 
in Factor Category Seven.
    15. In the first category, Order No. 1920 provided an opportunity 
for states to influence how transmission is planned and ultimately paid 
for. This order goes even farther by agreeing with the rehearing 
arguments advanced by several states seeking additional and expanded 
opportunities for states to engage. Specifically, we require 
transmission providers to incorporate input from states about how Long-
Term Scenarios used in Long-Term Regional Transmission Planning will be 
developed, particularly given that these scenarios will necessarily 
reflect how the states plan to meet their laws, policies, and 
regulations. In addition, we require transmission providers to include 
in the transmittal or as an attachment to their Order No. 1920 
compliance filings any ex ante cost allocation method and/or State 
Agreement Process agreed to by the Relevant State Entities (to the 
extent the transmission provider does not adopt such an agreed-to cost 
allocation method and/or process as its own proposal), along with any 
information related to the Engagement Period \13\ requested by a 
Relevant State Entity to be included. We are further persuaded by 
arguments on rehearing that Relevant State Entities may, in some cases, 
need time beyond the six-month Engagement Period allowed under Order 
No. 1920. We therefore clarify that the Commission will grant 
extensions of time requested by Relevant State Entities where there is 
a showing that additional time is needed to resolve cost allocation 
discussions, up to a period of an additional six months. We believe 
this clarification ensures states who are engaged in working toward 
agreed-upon cost allocation methods and/or a State Agreement Process 
will have the time they need to resolve those discussions.
---------------------------------------------------------------------------

    \13\ See infra Introduction and Background section (defining 
``Engagement Period'').
---------------------------------------------------------------------------

    16. Furthermore, to ensure that Relevant State Entities have a role 
in cost allocation for Long-Term Regional Transmission Facilities going 
forward, we require that transmission providers consult with Relevant 
State Entities (1) prior to amending the Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es), or (2) if Relevant State Entities seek, consistent with 
their chosen method to reach agreement, to amend that method or 
process. Finally, we clarify that the flexibility Order No. 1920 
affords to transmission providers and Relevant State Entities to 
determine cost allocation methods appropriate for their region does not 
preclude proposed methods that allocate costs commensurate with 
reliability and economic benefits region-wide, while allocating costs 
commensurate with additional benefits to a subset of states that agree 
to such cost allocation, e.g., based on the incremental costs and 
benefits of transmission needed to achieve state laws, policies, and 
regulations beyond the cost of transmission needed in the absence of 
those laws, policies, and regulations.
    17. In the second category, we clarify in response to requests for 
rehearing that, while transmission providers are obligated to develop 
three Long-Term Scenarios that meet all of the requirements of the 
rule, Order No. 1920 permits transmission providers to develop 
additional analyses, including other scenarios, to help inform who pays 
for those selected facilities. We further modify Order No. 1920 on 
rehearing to now require that transmission providers develop a 
reasonable number of additional scenarios at Relevant State Entities' 
request. The aim of Order No. 1920 is to ensure that transmission 
providers engage in the sufficiently long-term, forward-looking, and 
comprehensive transmission planning that is essential to have the 
information necessary to determine which investments are worth making. 
As long as transmission providers engage in that robust planning 
process and achieve the transparency required through that process, 
transmission providers can develop and consider additional information 
beyond that required as part of Long-Term Regional Transmission 
Planning.
    18. In the third category of changes, on rehearing we modify, in 
one respect, the requirement to use seven categories of factors in the 
development of the three Long-Term Scenarios that are used to identify 
Long-Term Transmission Needs, and potential solutions to those needs. 
Several parties raise concerns regarding the inclusion of corporate 
commitments in Factor Category Seven, which they argue may elevate the 
needs of particular transmission customers above those of others. Upon 
further consideration, we eliminate the requirement to incorporate 
corporate commitments from Factor Category Seven into each Long-Term 
Scenario and thus we eliminate the potential for confusion around the 
treatment of particular transmission customers, while enabling 
transmission providers to give appropriate weight to corporate 
commitments as an indicator of customer preference in a region where 
those preferences are known.
    19. Taken together, we believe the requirements of Order No. 1920 
with the modifications and clarifications we make on rehearing will 
remedy the deficiencies of current regional transmission planning 
processes, establish sufficiently long-term, forward-looking, and 
comprehensive transmission planning, and ensure that transmission 
providers and Relevant State Entities in each region have the 
flexibility to devise cost allocation methods that reasonably and 
fairly assign the costs of Long-Term Regional Transmission Facilities 
to those that benefit from such facilities.

II. Introduction and Background

    20. In Order No. 1920, the Commission found that existing regional 
transmission planning and cost allocation processes are unjust, 
unreasonable, and unduly discriminatory or preferential because the 
Commission's existing transmission planning and cost allocation 
requirements do not require transmission providers to: \14\ (1) perform 
a sufficiently long-term assessment of transmission needs that 
identifies Long-Term Transmission Needs; \15\ (2)

[[Page 97180]]

adequately account on a forward-looking basis for known determinants of 
Long-Term Transmission Needs; and (3) consider the broader set of 
benefits of regional transmission facilities planned to meet those 
Long-Term Transmission Needs.\16\
---------------------------------------------------------------------------

    \14\ Section 201(e) of the FPA, 16 U.S.C. 824(e), defines 
``public utility'' to mean ``any person who owns or operates 
facilities subject to the jurisdiction of the Commission under this 
subchapter.'' As stated in the Order No. 888 pro forma Open Access 
Transmission Tariff (OATT), ``transmission provider'' is a ``public 
utility (or its Designated Agent) that owns, controls, or operates 
facilities used for the transmission of electric energy in 
interstate commerce and provides transmission service under the 
Tariff.'' Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Servs. by Pub. Utils.; Recovery of 
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, 
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036 (1996) 
(cross-referenced at 75 FERC ] 61,080), order on reh'g, Order No. 
888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048 
(cross-referenced at 78 FERC ] 61,220), order on reh'g, Order No. 
888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 82 
FERC ] 61,046 (1998), aff'd in relevant part sub nom. Transmission 
Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000) 
(TAPS), aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002); Pro forma 
OATT section I.1 (Definitions). The term ``transmission provider'' 
includes a public utility transmission owner when the transmission 
owner is separate from the transmission provider, as is the case in 
regional transmission organizations (RTO) and independent system 
operators (ISO).
    \15\ For purposes of Order No. 1920, Long-Term Transmission 
Needs are transmission needs identified through Long-Term Regional 
Transmission Planning by, among other things and as discussed in 
Order No. 1920, running scenarios and considering the enumerated 
categories of factors. Order No. 1920, 187 FERC ] 61,068 at P 299.
    \16\ Order No. 1920, 187 FERC ] 61,068 at P 1.
---------------------------------------------------------------------------

    21. Order No. 1920 therefore established requirements to ensure 
that Commission-jurisdictional rates remain just and reasonable and not 
unduly discriminatory or preferential. First, Order No. 1920 required 
transmission providers in each transmission planning region to 
participate in a regional transmission planning process that includes 
Long-Term Regional Transmission Planning.\17\ Order No. 1920 
established specific requirements regarding how transmission providers 
must conduct Long-Term Regional Transmission Planning, including, among 
other things, the use of Long-Term Scenarios to identify Long-Term 
Transmission Needs and Long-Term Regional Transmission Facilities \18\ 
to meet those needs.\19\
---------------------------------------------------------------------------

    \17\ Id. P 224. Long-Term Regional Transmission Planning means 
regional transmission planning on a sufficiently long-term, forward-
looking, and comprehensive basis to identify Long-Term Transmission 
Needs, identify transmission facilities that meet such needs, 
measure the benefits of those transmission facilities, and evaluate 
those transmission facilities for potential selection in the 
regional transmission plan for purposes of cost allocation as the 
more efficient or cost-effective regional transmission facilities to 
meet Long-Term Transmission Needs. Id. For purposes of Order No. 
1920, and consistent with Order No. 1000, a transmission planning 
region is one in which transmission providers, in consultation with 
stakeholders and affected states, have agreed to participate for 
purposes of regional transmission planning and development of a 
single regional transmission plan. Id. P 2 n.7; see Order No. 1000, 
136 FERC ] 61,051 at P 160.
    \18\ For purposes of Order No. 1920, a Long-Term Regional 
Transmission Facility is a regional transmission facility that is 
identified as part of Long-Term Regional Transmission Planning to 
address Long-Term Transmission Needs. Order No. 1920, 187 FERC ] 
61,068 at P 250. For the purposes of Order No. 1920, and consistent 
with Order No. 1000, a regional transmission facility is a 
transmission facility located entirely in one transmission planning 
region. An interregional transmission facility is a transmission 
facility that is located in two or more transmission planning 
regions. A local transmission facility is a transmission facility 
located solely within a transmission provider's retail distribution 
service territory or footprint that is not selected in the regional 
transmission plan for purposes of cost allocation. Id. P 41 n.58 
(citing Order No. 1000, 136 FERC ] 61,051 at PP 63, 482 n.374).
    \19\ Id. P 298. For purposes of Order No. 1920, Long-Term 
Scenarios are scenarios that incorporate various assumptions using 
best available data inputs about the future electric power system 
over a sufficiently long-term, forward-looking transmission planning 
horizon to identify Long-Term Transmission Needs and enable the 
identification and evaluation of transmission facilities to meet 
such transmission needs. Id. P 302.
---------------------------------------------------------------------------

    22. Order No. 1920 required transmission providers to measure and 
use at least seven specified benefits to evaluate Long-Term Regional 
Transmission Facilities as part of Long-Term Regional Transmission 
Planning.\20\ Order No. 1920 required transmission providers to 
calculate the benefits of Long-Term Regional Transmission Facilities 
over a time horizon that covers, at a minimum, 20 years starting from 
the estimated in-service date of the transmission facilities and 
required that this minimum 20-year benefit horizon be used both for the 
evaluation and selection of Long-Term Regional Transmission Facilities 
in the regional transmission plan for purposes of cost allocation.\21\
---------------------------------------------------------------------------

    \20\ Id. P 719.
    \21\ Id. P 859. The Commission recognized that some transmission 
planning regions may include Long-Term Regional Transmission 
Facilities, or a portfolio of such Facilities, in a regional 
transmission plan, but may not necessarily include these Facilities 
for purposes of cost allocation. Id. P 3 n.8 (citing Order No. 1000, 
136 FERC ] 61,051 at P 63). For purposes of Order No. 1920, unless 
otherwise noted, when referencing Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) that are selected, we 
intend that the word ``selected'' mean that those Facilities are 
selected in the regional transmission plan for purposes of cost 
allocation. Id.
---------------------------------------------------------------------------

    23. Order No. 1920 required transmission providers to include in 
their OATTs an evaluation process, including selection criteria, that 
they will use to identify and evaluate Long-Term Regional Transmission 
Facilities for potential selection to address Long-Term Transmission 
Needs.\22\ Further, Order No. 1920 required transmission providers to 
include in their OATTs a process to provide Relevant State Entities 
\23\ and interconnection customers with the opportunity to voluntarily 
fund the cost of, or a portion of the cost of, a Long-Term Regional 
Transmission Facility that otherwise would not meet transmission 
providers' selection criteria.\24\ Order No. 1920 also required 
transmission providers to include in their OATTs provisions that 
require transmission providers--in certain circumstances--to reevaluate 
Long-Term Regional Transmission Facilities that previously were 
selected.\25\
---------------------------------------------------------------------------

    \22\ Id. P 911.
    \23\ For the purposes of Order No. 1920, a Relevant State Entity 
is any state entity responsible for electric utility regulation or 
siting electric transmission facilities within the state or portion 
of a state located in the transmission planning region, including 
any state entity as may be designated for that purpose by the law of 
such state. Id. P 1355.
    \24\ Id. P 1012.
    \25\ Id. P 1048.
---------------------------------------------------------------------------

    24. Order No. 1920 required transmission providers to file one or 
more ex ante Long-Term Regional Transmission Cost Allocation Methods 
\26\ to allocate the costs of Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) that are selected.\27\ 
Order No. 1920 further allowed, but did not require, transmission 
providers to adopt a State Agreement Process for allocating the costs 
of all, or a subset of, Long-Term Regional Transmission Facilities.\28\ 
Where Relevant State Entities agree to such a State Agreement Process, 
and transmission providers choose to file such a process, a State 
Agreement Process would provide Relevant State Entities up to six 
months after selection for its participants to determine, and 
transmission providers to file, a cost allocation method for specific 
Long-Term Regional Transmission Facilities.\29\ Order No. 1920 also 
established a six-month time period (Engagement Period), during which 
transmission providers must: (1) provide notice of the starting and end 
dates for the six-month time period; (2) post contact information that 
Relevant State Entities may use to communicate with transmission 
providers about any agreement among Relevant State Entities on a Long-
Term Regional Transmission Cost Allocation Method(s) and/or a State 
Agreement Process, as well as a deadline for communicating such 
agreement; and (3) provide a forum for negotiation of a Long-Term 
Regional Transmission Cost Allocation Method(s) and/or a State 
Agreement Process that enables robust participation by Relevant State 
Entities.\30\
---------------------------------------------------------------------------

    \26\ For purposes of Order No. 1920, a Long-Term Regional 
Transmission Cost Allocation Method is an ex ante regional cost 
allocation method for one or more Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) that are selected in 
the regional transmission plan for purposes of cost allocation. Id. 
P 1291.
    \27\ Id.
    \28\ Id. P 1402. For purposes of Order No. 1920, a State 
Agreement Process is a process by which one or more Relevant State 
Entities may voluntarily agree to a cost allocation method for Long-
Term Regional Transmission Facilities (or a portfolio of such 
Facilities) before or no later than six months after they are 
selected. Id.
    \29\ Id.
    \30\ Id. P 1354.
---------------------------------------------------------------------------

    25. Order No. 1920 required transmission providers to evaluate for 
potential selection in their existing Order No. 1000 regional 
transmission planning processes regional transmission facilities that 
will address certain identified interconnection-related transmission 
needs associated with certain interconnection-related network upgrades 
originally identified through the generator interconnection 
process.\31\
---------------------------------------------------------------------------

    \31\ Id. PP 1106-1107.

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[[Page 97181]]

    26. Order No. 1920 required transmission providers to consider more 
fully the alternative transmission technologies of dynamic line 
ratings, advanced power flow control devices, advanced conductors, and 
transmission switching in Long-Term Regional Transmission Planning and 
existing Order No. 1000 regional transmission planning and cost 
allocation processes.\32\
---------------------------------------------------------------------------

    \32\ Id. P 1198.
---------------------------------------------------------------------------

    27. Order No. 1920 required transmission providers to adopt 
enhanced transparency requirements for local transmission planning 
processes and improve coordination between regional and local 
transmission planning with the aim of identifying potential 
opportunities to ``right-size'' replacement transmission 
facilities.\33\
---------------------------------------------------------------------------

    \33\ Id. PP 1625, 1677.
---------------------------------------------------------------------------

    28. Order No. 1920 required transmission providers to revise their 
interregional transmission coordination procedures to reflect the Long-
Term Regional Transmission Planning reforms adopted in Order No. 
1920.\34\ Order No. 1920 also required transmission providers to meet 
additional information sharing and transparency requirements with 
respect to their interregional transmission coordination processes.\35\
---------------------------------------------------------------------------

    \34\ Id. P 1751.
    \35\ Id.
---------------------------------------------------------------------------

    29. The Commission received 49 timely filed requests for rehearing 
and/or clarification \36\ and several additional filings.\37\ The 
rehearing requests raise issues related to nearly all reforms adopted 
in Order No. 1920.
---------------------------------------------------------------------------

    \36\ Appendix A provides the short names of the entities that 
filed requests for rehearing or clarification. To the extent that 
they intend to seek rehearing, the pleadings filed by Grid United, 
PJM States, Vermont Commission, and Virginia and North Carolina 
Commissions are deficient because they fail to include a separate 
section entitled ``Statement of Issues'' listing each issue 
presented to the Commission in a separately enumerated paragraph 
that includes representative precedent on which the participant is 
relying, as required by Rule 713(c)(2) of the Commission's Rules of 
Practice and Procedure (18 CFR 385.713(c)(2)). Consistent with Rule 
713, we deem these petitioners to have waived the issues for which 
they seek rehearing. We consider petitioners' requests for 
clarification and, to provide clarity, address their arguments on 
rehearing below. EEI, PJM States, and PJM Utilities filed answers to 
certain requests for rehearing. Rule 713(d)(1) (18 CFR 
385.713(d)(1)) prohibits an answer to a request for rehearing. 
Accordingly, we deny EEI's, PJM States', and PJM Utilities' motions 
to answer and reject their answers. Although PJM States style their 
July 3, 2024 pleading as comments, we treat the pleading as an 
answer to PJM's request for rehearing. See, e.g., San Diego Gas & 
Elec. Co., 133 FERC ] 61,014, at P 15 (2010) (``[W]e are not 
obligated to accept a filing solely on the basis of its party-
bestowed title. Instead, we examine the substance of the 
pleading.'').
    \37\ Susann Rizzo, Gary Andrews, and Cher Gilmore filed letters 
supporting Order No. 1920. They also urged the Commission to require 
interregional transmission planning and establish environmental 
justice liaisons. In addition, E. Andrews, Illinois Commission, and 
Minnesota Commission each submitted late-filed pleadings that are 
generally supportive of Order No. 1920. Further, on June 12, 2024, 
Missouri Commission filed a letter addressing Order No. 1920. On 
September 3, 2024, Chairman Willie Phillips responded to the 
Missouri Commission letter. On July 22, 2024, State Regulatory 
Commissioners filed a letter expressing views on Order No. 1920. On 
October 9, 2024, Chairman Willie Phillips responded to the State 
Regulatory Commissioners' letter.
---------------------------------------------------------------------------

    30. Pursuant to Allegheny Defense Project v. FERC, \38\ the 
rehearing requests filed in this proceeding may be deemed denied by 
operation of law. However, as permitted by section 313(a) of the 
FPA,\39\ we are modifying the discussion in Order No. 1920, setting 
aside the order, in part, and clarifying the order, as discussed 
below.\40\
---------------------------------------------------------------------------

    \38\ 964 F.3d 1 (D.C. Cir. 2020) (en banc).
    \39\ 16 U.S.C. 825l(a) (``Until the record in a proceeding shall 
have been filed in a court of appeals, as provided in subsection 
(b), the Commission may at any time, upon reasonable notice and in 
such manner as it shall deem proper, modify or set aside, in whole 
or in part, any finding or order made or issued by it under the 
provisions of this chapter.'').
    \40\ Allegheny Def. Project, 964 F.3d at 16-17. In Appendix B, 
we provide the revisions to the provisions of Attachment K to the 
pro forma OATT made in this order on rehearing and clarification.
---------------------------------------------------------------------------

    31. Specifically, we set aside the order, in part, to specify that: 
(1) transmission providers are not required to use the set of seven 
required benefits to help inform their identification of Long-Term 
Transmission Needs; \41\ (2) Factor Category Seven no longer includes 
corporate commitments; \42\ (3) transmission providers must propose an 
effective date for the OATT revisions necessary to comply with Order 
No. 1920 that is no later than two years from the date on which they 
will commence the first Long-Term Regional Transmission Planning cycle; 
\43\ (4) when Relevant State Entities agree on a Long-Term Regional 
Transmission Cost Allocation Method or State Agreement Process 
resulting from the Engagement Period, transmission providers must 
include that method or process in the transmittal or as an attachment 
to their compliance filing, even if transmission providers propose a 
different Long-Term Regional Transmission Cost Allocation method or do 
not propose to adopt a State Agreement Process along with any 
information that Relevant State Entities provide to transmission 
providers regarding the state negotiations during the Engagement 
Period; \44\ and (5) transmission providers shall consult with Relevant 
State Entities prior to amending the Long-Term Regional Transmission 
Cost Allocation Method(s) and/or State Agreement Process(es), or if 
Relevant State Entities seek, consistent with their chosen method to 
reach agreement, for the transmission provider to amend that method or 
process.
---------------------------------------------------------------------------

    \41\ See Order No. 1920, 187 FERC ] 61,068 at P 301 
(``Transmission providers must use [the set of seven required 
benefits] to help to inform their identification of Long-Term 
Transmission Needs.'').
    \42\ See id. P 481 (``We adopt the NOPR proposal, with 
modification, to require transmission providers in each transmission 
planning region to incorporate Factor Category Seven: utility and 
corporate commitments and federal, federally-recognized Tribal, 
state, and local policy goals that affect Long-Term Transmission 
Needs, in the development of Long-Term Scenarios.'').
    \43\ See id. P 1072 (``Thus, we require transmission providers 
in each transmission planning region to propose on compliance a 
date, no later than one year from the date on which initial filings 
to comply with this final rule are due, on which they will commence 
the first Long-Term Regional Transmission Planning cycle.'').
    \44\ See id. P 1359 (``We note, however, that the ultimate 
decision as to whether to file a Long-Term Regional Transmission 
Cost Allocation Method(s) and/or State Agreement Process to which 
Relevant State Entities have agreed will continue to lie with the 
transmission providers.'').
---------------------------------------------------------------------------

    32. Additionally, we grant multiple clarifications on most elements 
of Order No. 1920, as further discussed below. For example, among other 
clarifications, we clarify that transmission providers may develop 
additional scenarios, beyond the three Long-Term Scenarios that Order 
No. 1920 requires, to provide Relevant State Entities with information 
that they can use to inform the application of Long-Term Regional Cost 
Allocation Method(s) or the development of cost allocation methods 
through the State Agreement Process(es), and that Order No. 1920 does 
not prevent transmission providers from recognizing different types of 
benefits and using them to allocate costs in proportion to those 
benefits.
    33. Finally, we specify that the Commission will grant an extension 
of the required Engagement Period for up to an additional six months 
when Relevant State Entities request an extension and represent to the 
Commission that they agree, consistent with their chosen method to 
reach agreement, that they need additional time to finish cost 
allocation discussions. If the Commission grants such an extension 
request, it will also, as appropriate, extend, sua sponte, the relevant 
Order No. 1920 compliance deadlines to ensure that any extension of the 
Engagement Period would not conflict with the required compliance 
deadlines.

III. The Overall Need for Reform

A. Order No. 1920

    34. In Order No. 1920, the Commission found substantial evidence to 
support the conclusion that the

[[Page 97182]]

Commission's existing regional transmission planning and cost 
allocation requirements are unjust, unreasonable, and unduly 
discriminatory or preferential. Specifically, the Commission explained 
that the absence of sufficiently long-term, forward-looking, and 
comprehensive transmission planning requirements causes transmission 
providers to fail to adequately anticipate and plan for future system 
conditions and to fail to appropriately evaluate the benefits of 
transmission infrastructure.\45\ The Commission found that this status 
quo results in piecemeal transmission expansion to address relatively 
near-term needs and causes transmission providers to make relatively 
inefficient investments in transmission infrastructure, the costs of 
which are ultimately recovered through Commission-jurisdictional rates. 
One result of this dynamic, the Commission explained, is that 
transmission customers overpay to meet their transmission needs and 
forgo benefits that outweigh their costs, which results in less 
efficient or cost-effective transmission investments. Such 
deficiencies, the Commission found, render Commission-jurisdictional 
regional transmission planning and cost allocation processes unjust, 
unreasonable, and unduly discriminatory or preferential.\46\
---------------------------------------------------------------------------

    \45\ Order No. 1920, 187 FERC ] 61,068 at P 85.
    \46\ Id.
---------------------------------------------------------------------------

    35. The Commission explained that it has the authority to issue 
Order No. 1920 under FPA section 206, which ``instructs the Commission 
to remedy `any . . . practice' that `affect[s]' a rate for interstate 
electricity service `demanded' or `charged' by `any public utility' if 
such practice `is unjust, unreasonable, unduly discriminatory or 
preferential.' '' \47\ The Commission concluded that the D.C. Circuit 
has recognized that regional transmission planning and cost allocation 
processes are practices affecting rates subject to the Commission's 
exclusive jurisdiction \48\ and that transmission providers use those 
processes to ``determine which transmission facilities will more 
efficiently or cost-effectively meet'' transmission needs, the 
development of which directly impacts the rates, terms, and conditions 
of Commission-jurisdictional service.\49\ The Commission found that, 
because these processes identify, evaluate, and select the regional 
transmission facilities whose costs will be recovered through 
transmission rates, they directly affect those rates.\50\ The 
Commission found that, because such regional transmission facilities 
lead to a more robust transmission system, regional transmission 
planning and cost allocation processes, as well as ``the rules and 
practices that determine how those [processes] operate,'' \51\ directly 
affect rates that customers pay for both transmission and sale of 
electric energy in interstate commerce.\52\ The Commission noted that 
it may act pursuant to FPA section 206 if the Commission first 
establishes, through substantial evidence,\53\ that existing practices 
are unjust, unreasonable, or unduly discriminatory or preferential and, 
second, establishes that the replacement practices are just and 
reasonable.\54\
---------------------------------------------------------------------------

    \47\ Id. P 86 (citation omitted) (quoting S.C. Pub. Serv. Auth. 
v. FERC, 762 F.3d at 55).
    \48\ Id. (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-
59, 84).
    \49\ Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 
56).
    \50\ Id.; see also id. P 86 n.186 (citing Conn. Dep't of Pub. 
Util. Control v. FERC, 569 F.3d 477, 485 (D.C. Cir. 2009)).
    \51\ Id. P 86 (quoting FERC v. Elec. Power Supply Ass'n, 577 
U.S. 260, 279 (2016) (EPSA)).
    \52\ Id. (citing 16 U.S.C. 824e(a)).
    \53\ Id. (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 54). 
The Commission explained that FPA section 206 empowers the 
Commission to address the mere threat of unjust and unreasonable 
rates and, in this context the Commission need not necessarily 
provide empirical evidence for every proposition to satisfy the 
substantial evidence standard. Order No. 1920, 187 FERC ] 61,068 at 
P 86 n.189 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64-65, 
85).
    \54\ Id. (citing 16 U.S.C. 824e(a); EPSA, 577 U.S. at 277).
---------------------------------------------------------------------------

    36. Addressing whether existing rates, or practices affecting 
rates, remain just and reasonable--i.e., the first prong under FPA 
section 206 \55\--the Commission found that existing Order No. 890 and 
Order No. 1000 transmission planning and cost allocation requirements 
do not result in regional transmission planning that is conducted on a 
sufficiently long-term, forward-looking, and comprehensive basis, and 
transmission providers therefore often do not identify, evaluate, or 
select more efficient or cost-effective regional transmission solutions 
to meet Long-Term Transmission Needs.\56\ The Commission determined 
that this results in piecemeal, inefficient, and less cost-effective 
transmission planning, which imposes real costs on customers \57\ and 
renders the Commission's existing transmission planning and cost 
allocation requirements unjust, unreasonable, and unduly discriminatory 
or preferential in violation of FPA section 206.\58\
---------------------------------------------------------------------------

    \55\ See Pub. Serv. Elec. & Gas Co. v. FERC, 989 F.3d 10, 13 
(D.C. Cir. 2021) (explaining that section 206 ``mandates a two-step 
procedure'' whereby the Commission, on the first step, must make an 
explicit finding that the existing rate is unlawful and then, on the 
second step, must set a new rate. (quotation omitted)).
    \56\ Order No. 1920, 187 FERC ] 61,068 at P 87.
    \57\ Id.
    \58\ Id. P 88.
---------------------------------------------------------------------------

    37. The Commission also found that existing transmission planning 
and cost allocation requirements are insufficient to ensure just and 
reasonable and not unduly discriminatory or preferential rates. Thus, 
pursuant to FPA section 206, the Commission stated that it is now 
requiring transmission providers to engage in and conduct sufficiently 
long-term, forward-looking, and comprehensive transmission planning and 
cost allocation processes to identify and plan for Long-Term 
Transmission Needs. The Commission found that such reforms will 
facilitate a process by which transmission providers can better 
identify, evaluate, and select more efficient or cost-effective 
transmission solutions to meet Long-Term Transmission Needs, which will 
ensure that Commission-jurisdictional rates are just and reasonable and 
not unduly discriminatory or preferential.\59\
---------------------------------------------------------------------------

    \59\ Id. P 89.
---------------------------------------------------------------------------

1. The Transmission Investment Landscape Today
    38. The Commission explained that due to continuing changes in the 
industry, ongoing investment in transmission facilities is necessary to 
ensure the transmission system remains reliable, affordable, and 
economically efficient. More comprehensive transmission planning can 
enable transmission providers to proactively identify potential 
reliability problems and economic constraints and evaluate potential 
transmission solutions, which can facilitate the selection of more 
efficient or cost-effective transmission facilities to meet Long-Term 
Transmission Needs.\60\ Transmission infrastructure can also increase 
competition among generators, which results in a host of benefits for 
customers, including cost savings from greater access to low-cost 
power.\61\
---------------------------------------------------------------------------

    \60\ Id. P 90 (citations omitted).
    \61\ Id. P 91.
---------------------------------------------------------------------------

    39. The Commission cited evidence demonstrating a nationwide 
increase in transmission spending since the issuance of Order No. 1000 
and explained that, unsurprisingly, transmission costs have become an 
increasing share of customers' overall electricity bills in regions 
that saw a significant increase in transmission expenditures.\62\ 
Further, the Commission highlighted several studies in the record 
demonstrating that

[[Page 97183]]

transmission investment is likely to increase substantially in coming 
years.\63\
---------------------------------------------------------------------------

    \62\ Id. P 92 (citations omitted).
    \63\ Id. P 93 (citations omitted).
---------------------------------------------------------------------------

    40. The Commission found that a number of factors are driving the 
growing need for new transmission infrastructure.\64\ First, the 
Commission found that longer-term reliability needs are changing and 
driving a significant shift in the demands placed on the transmission 
system, and transmission system operators are increasingly depending on 
regional transmission facilities to ensure operational stability and 
system reliability, particularly due to the growing frequency of 
extreme weather events and increasing share of variable resources 
entering the resource mix.\65\ Second, after many years of flat or 
minimal load growth in regions across the country, the Commission found 
that both regional and national demand is projected to increase 
significantly in the coming decades, which will require an increasingly 
robust transmission system to serve this growing load reliably. Third, 
the Commission found that supply is changing, driven by federal, 
federally-recognized Tribal, state, and local policies, customer 
demands, utility commitments, and the shifting economics of resources 
that comprise the resource mix.\66\
---------------------------------------------------------------------------

    \64\ Id. P 94 (citations omitted).
    \65\ Id. (citations omitted).
    \66\ Id. PP 96-99 (citations omitted).
---------------------------------------------------------------------------

    41. The Commission also found that the record in this proceeding 
affirms the Commission's longstanding recognition that regional 
transmission planning that identifies more efficient or cost-effective 
transmission solutions helps to ensure cost-effective transmission 
development for customers and can yield better returns for every dollar 
spent than localized or piecemeal transmission solutions, while 
inadequate or poorly designed transmission planning processes can cause 
customers to foot the bill for piecemeal, inefficient, and less cost-
effective transmission solutions.\67\
---------------------------------------------------------------------------

    \67\ Id. P 100 (citations omitted).
---------------------------------------------------------------------------

    42. Based on its experience implementing Order No. 1000, the 
Commission found that existing regional transmission planning processes 
are not of sufficient scope and duration to adequately or consistently 
identify transmission needs and associated opportunities to evaluate 
and select, on a more comprehensive basis, more efficient or cost-
effective transmission solutions to those needs.\68\ The Commission 
explained that, in some regions, investment in regional transmission 
facilities has declined as compared to prior to Order No. 1000 and 
that, across all non-RTO/ISO regions, not a single transmission 
facility has been selected pursuant to the regional planning processes 
since implementation of Order No. 1000. The Commission noted that, 
within some RTO/ISO regional transmission planning processes, even 
where investments through the regional transmission planning process 
occur, much of that investment has been in transmission projects that 
only address immediate reliability needs.\69\ The Commission also cited 
evidence showing that, in the limited instances in which transmission 
providers have followed processes that share many of the elements that 
Order No. 1920 requires, customers have seen clear and quantifiable 
benefits.\70\
---------------------------------------------------------------------------

    \68\ Id. P 101.
    \69\ Id. (citations omitted).
    \70\ Id. P 102.
---------------------------------------------------------------------------

    43. Further, the Commission explained that a substantial amount of 
new transmission investment is occurring in generator interconnection 
processes and local transmission planning processes, which, unlike 
regional transmission planning processes, do not comprehensively assess 
either broader transmission needs or solutions to those needs. The 
Commission concluded that overreliance on those processes can result in 
relatively inefficient or less cost-effective transmission development 
for customers, which contributes to rates for transmission that are 
unjust and unreasonable.\71\
---------------------------------------------------------------------------

    \71\ Id. P 103 (citations omitted).
---------------------------------------------------------------------------

    44. The Commission cited evidence showing a sharp growth in both 
the total cost of interconnection-related network upgrades and in the 
cost of such upgrades relative to generation project costs, as well as 
evidence showing that increases in interconnection costs are being 
driven, in many cases, by an expansion in the scope and complexity of 
interconnection-related network upgrades.\72\ The Commission noted 
that, unlike regional transmission planning processes, the generator 
interconnection process is not designed to consider how to address 
transmission needs more efficiently or cost-effectively beyond the 
discrete interconnection request (or requests) being studied.\73\ The 
Commission found that increasingly relying on interconnection 
customers' interconnection-related network upgrades to expand the 
capacity of the transmission system is inefficient and leads to less 
cost-effective transmission development than would result from long-
term, forward-looking, and more comprehensive regional transmission 
planning, to the detriment of customers.\74\
---------------------------------------------------------------------------

    \72\ Id. PP 104-105 (citations omitted).
    \73\ Id. P 106.
    \74\ Id. P 108.
---------------------------------------------------------------------------

    45. The Commission also cited evidence that, since the issuance of 
Order No. 1000, the majority of investment in transmission facilities 
has been in local transmission facilities, a trend that is accelerating 
across multiple regions.\75\ The Commission noted evidence that 
transmission expansion through local transmission planning and in-kind 
replacement processes is incremental and misses the potential to 
identify, evaluate, and select more efficient or cost-effective 
transmission facilities to solve transmission needs, as well as to 
afford system-wide benefits that may not be achieved through piecemeal, 
one-off local transmission facilities.\76\ Such transmission planning, 
the Commission stated, results in relatively inefficient or less cost-
effective transmission development for customers, which contributes to 
rates for transmission that are unjust and unreasonable.\77\
---------------------------------------------------------------------------

    \75\ Id. P 109.
    \76\ Id. P 110 (citations omitted).
    \77\ Id. The Commission acknowledged the important roles played 
by generator interconnection processes and local transmission 
planning processes and underscored that the Commission's findings 
were not intended to call into question the justness and 
reasonableness of either process. Id. P 111.
---------------------------------------------------------------------------

2. Unjust, Unreasonable, and Unduly Discriminatory or Preferential 
Commission-Jurisdictional Transmission Planning and Cost Allocation 
Processes
    46. The Commission concluded that there is substantial evidence in 
the record to support the determination that sufficiently long-term, 
forward-looking, and comprehensive regional transmission planning and 
cost allocation to meet Long-Term Transmission Needs is not occurring 
on a consistent and sufficient basis.\78\ The Commission found that the 
absence of a sufficiently long-term, forward-looking, and comprehensive 
regional transmission planning process results in relatively 
unfavorable outcomes, including: piecemeal transmission expansion to 
address relatively near-term transmission needs, transmission providers 
undertaking investments in relatively inefficient or less cost-
effective transmission infrastructure, and transmission customers 
paying more than is necessary or appropriate to meet their transmission 
needs and/or

[[Page 97184]]

forgoing benefits that outweigh their costs.\79\
---------------------------------------------------------------------------

    \78\ Id. P 112.
    \79\ Id.
---------------------------------------------------------------------------

    47. The Commission determined that there is substantial evidence in 
the record to support the conclusion that the Commission's regional 
transmission planning and cost allocation requirements are deficient, 
thus rendering Commission-jurisdictional regional transmission planning 
and cost allocation processes unjust and unreasonable. Specifically, 
the Commission found that existing regional transmission planning and 
cost allocation requirements fail to require transmission providers to: 
(1) perform a sufficiently long-term assessment of transmission needs 
that identifies Long-Term Transmission Needs; (2) adequately account on 
a forward-looking basis for known determinants of Long-Term 
Transmission Needs; and (3) consider the broader set of benefits of 
regional transmission facilities planned to meet those Long-Term 
Transmission Needs.\80\
---------------------------------------------------------------------------

    \80\ Id. P 114.
---------------------------------------------------------------------------

    48. As to the first deficiency--the lack of sufficiently long-term 
planning--the Commission cited evidence in the record demonstrating 
that, under the status quo, most transmission planning regions do not 
plan beyond a 10-year transmission planning horizon.\81\ The Commission 
stated that the absence of any consistent and sufficient longer-term 
assessment of transmission needs prevents transmission providers from 
identifying Long-Term Transmission Needs and considering regional 
transmission facilities that may be more efficient or cost-effective 
solutions to address those needs.\82\ The Commission added that short-
term transmission planning fails to take advantage of the potential for 
efficiencies or economies of scale that regional transmission 
facilities can provide and fails to create opportunities to ``right 
size'' the replacement of aging transmission facilities to address 
multiple transmission needs over the longer term. Further, the 
Commission stated that the time horizon over which much transmission 
planning is often occurring is shorter than the time needed to plan and 
construct large (e.g., high voltage or long distance) transmission 
facilities \83\ and much too short to capture all of the benefits that 
regional transmission facilities can provide.\84\
---------------------------------------------------------------------------

    \81\ Id. P 115.
    \82\ Id. (citations omitted).
    \83\ Id. P 116 (citations omitted).
    \84\ Id. (citations omitted).
---------------------------------------------------------------------------

    49. The Commission noted that the likelihood that near-term 
assessments will fail to identify Long-Term Transmission Needs and more 
efficient or cost-effective regional transmission facilities to meet 
those needs is higher during periods of rapid change, as the electric 
sector is now experiencing, during which the need for transmission 
infrastructure is expected to grow considerably.\85\
---------------------------------------------------------------------------

    \85\ Id. P 117 (citations omitted).
---------------------------------------------------------------------------

    50. The second deficiency the Commission discussed is that the 
Commission's existing regional transmission planning and cost 
allocation requirements fail to require transmission providers to 
account adequately on a forward-looking basis for known determinants of 
Long-Term Transmission Needs; moreover, the Commission stated, 
transmission providers are not consistently or sufficiently doing 
so.\86\ The Commission further stated that the record demonstrates that 
there are numerous factors that increasingly shape Long-Term 
Transmission Needs, are known and identifiable, and have reasonably 
predictable effects, especially in the aggregate, such as reliability 
needs driven by the impact of extreme weather; trends in future 
generation additions and retirements; load growth; federal, federally-
recognized Tribal, state, and local laws and regulations; and utility 
goals.\87\ The Commission determined, however, that existing regional 
transmission planning processes frequently undervalue or do not 
consider some or all of these factors, and that the Commission's 
existing regional transmission planning requirements do not ensure that 
such factors will be sufficiently accounted for in that planning.\88\ 
The Commission noted that the failure to adequately consider such 
factors delays planning for the transmission system's changing 
operational needs until shortly before those transmission needs 
manifest. As a result, the Commission stated, existing regional 
transmission planning processes are piecemeal and fail to take 
advantage of economies of scale in transmission investment or 
opportunities to address multiple transmission needs over multiple time 
horizons, which leads to transmission investment that is not more 
efficient or cost-effective and renders Commission-jurisdictional 
regional transmission planning and cost allocation processes unjust and 
unreasonable.\89\
---------------------------------------------------------------------------

    \86\ Id. P 118.
    \87\ Id. P 119.
    \88\ Id. P 120.
    \89\ Id. P 121 (citations omitted).
---------------------------------------------------------------------------

    51. The third deficiency that the Commission identified is that the 
Commission's regional transmission planning and cost allocation 
requirements fail to require transmission providers to adequately 
consider the broader set of benefits of regional transmission 
facilities planned to meet Long-Term Transmission Needs. The Commission 
pointed to evidence demonstrating that many regional transmission 
planning processes focus too narrowly only on some benefits, while 
other regional transmission planning processes fail entirely to 
consider cost savings associated with certain transmission 
facilities.\90\ The Commission also explained that the cost-benefit 
analyses that transmission providers often use provide an inaccurate 
portrayal of the comparative benefits of different transmission 
facilities, which results in transmission customers forgoing benefits 
that may significantly outweigh their costs and in less efficient or 
cost-effective transmission investments, and ultimately contributes to 
Commission-jurisdictional rates that are unjust and unreasonable.\91\
---------------------------------------------------------------------------

    \90\ Id. P 122 & n.312.
    \91\ Id. P 123.
---------------------------------------------------------------------------

    52. The Commission determined that, given its findings concerning 
the deficiencies in existing transmission planning requirements, and 
its conclusion that long-term, forward-looking, and more comprehensive 
regional transmission planning is needed, existing cost allocation 
requirements are also deficient and must be modified to properly 
account for Long-Term Regional Transmission Planning.\92\
---------------------------------------------------------------------------

    \92\ Id. P 124.
---------------------------------------------------------------------------

    53. The Commission determined that its current cost allocation 
requirements, which were designed in the context of the Order No. 1000 
regional transmission planning process, are insufficient to 
appropriately allocate costs associated with regional transmission 
facilities selected in accordance with Order No. 1920's Long-Term 
Regional Transmission Planning requirements.\93\ The Commission's 
existing Order No. 1000 cost allocation requirements contemplate the 
application of differing cost allocation methods to different types of 
transmission facilities, but Order No. 1920's approach to Long-Term 
Regional Transmission Planning accounts for multiple drivers of Long-
Term Transmission Needs and results in Long-Term Regional Transmission 
Facilities that produce a broader set of benefits and therefore 
warrants a

[[Page 97185]]

different approach to cost allocation.\94\ The Commission also 
explained that existing Order No. 1000 regional transmission planning 
processes do not mandate the consideration of specific benefits and 
that information concerning these benefits may be relevant when 
allocating the costs of Long-Term Regional Transmission Facilities in a 
manner that is at least roughly commensurate with their benefits.\95\ 
Further, the Commission noted that under existing cost allocation 
requirements, there is no dedicated process to engage states in the 
development of regional cost allocation methods. The Commission 
explained that engaging states in cost allocation is particularly 
relevant to Long-Term Regional Transmission Planning given the long 
lead times for construction of transmission projects, which create 
uncertainty for Long-Term Regional Transmission Facilities and increase 
the importance of ensuring that such facilities will obtain needed 
siting approvals from the states and are thus timely and cost-
effectively developed. The Commission therefore concluded that it is 
both necessary and appropriate to establish specific cost allocation 
requirements tailored to the Long-Term Regional Transmission Planning 
reforms.\96\
---------------------------------------------------------------------------

    \93\ Id. P 126.
    \94\ Id.
    \95\ Id. (citing ICC v. FERC I, 576 F.3d at 477; Order No. 1000, 
136 FERC ] 61,051 at PP 622, 639).
    \96\ Id.
---------------------------------------------------------------------------

    54. The Commission found that there is substantial evidence in the 
record demonstrating that Long-Term Regional Transmission Planning and 
cost allocation to identify and plan for Long-Term Transmission Needs 
does not occur on a consistent and sufficient basis.\97\ The Commission 
added that this is largely due to the deficiencies it identified 
regarding existing regional transmission planning and cost allocation 
requirements.\98\ The Commission also found that, under the status quo, 
transmission providers are meeting many transmission needs by 
identifying transmission solutions and developing transmission 
facilities outside of the regional transmission planning and cost 
allocation processes or in response to near-term reliability needs.\99\ 
The Commission stated that this approach may not identify more 
efficient or cost-effective transmission solutions and will saddle 
consumers with the costs of relatively inefficient or less cost-
effective piecemeal transmission investment and expansion.\100\
---------------------------------------------------------------------------

    \97\ Id. P 127 (citations omitted).
    \98\ Id.
    \99\ Id. (citations omitted).
    \100\ Id. P 128 (citations omitted).
---------------------------------------------------------------------------

    55. Moreover, the Commission found that transmission needs in most 
transmission planning regions are rapidly changing and exacerbating 
concerns arising from the absence of sufficiently long-term, forward-
looking, and comprehensive regional transmission planning and cost 
allocation processes and the corresponding failure by transmission 
providers to identify and evaluate more efficient or cost-effective 
transmission solutions to Long-Term Transmission Needs.\101\ The 
Commission emphasized that it is reacting to well-documented factors, 
which the record demonstrates are driven by exogenous forces beyond the 
Commission's jurisdiction or control, including, but not limited to, 
the increasing frequency of extreme weather events, customer 
preferences, demand growth, economic and technological trends, and 
federal, federally-recognized Tribal, state, and local policies.\102\
---------------------------------------------------------------------------

    \101\ Id. P 129.
    \102\ Id. (citation omitted).
---------------------------------------------------------------------------

    56. The Commission stated that Order No. 1920 does not aim to 
affect--either facilitate or hinder--any changes or decisions that 
occur outside of the Commission's jurisdiction.\103\ Instead, the 
Commission explained, Order No. 1920 focuses on ensuring that 
Commission-jurisdictional processes associated with regional 
transmission planning and cost allocation result in rates that are just 
and reasonable and not unduly discriminatory or preferential; Order No. 
1920 seeks to ensure that such regional transmission planning processes 
are adequately ``accounting for'' changes occurring outside of the 
Commission's jurisdiction, including the resource decisions that are 
the exclusive jurisdiction of states.\104\
---------------------------------------------------------------------------

    \103\ Id. P 130 (emphasis in original).
    \104\ Id. (citing PJM Power Providers Grp. v. FERC, 88 F.4th 
250, 275 (3d Cir. 2023); Elec. Power Supply Ass'n v. Star, 904 F.3d 
518, 524 (7th Cir. 2018)).
---------------------------------------------------------------------------

    57. The Commission disagreed with arguments that it could not rely 
on general findings, rather than individualized analyses of each, 
specific transmission planning region, as the basis for Order No. 
1920.\105\ The Commission explained that it was acting pursuant to 
relevant precedent, which makes clear that the Commission need not make 
findings that are region-specific in every case and is instead 
empowered to ``rely on `generic' or `general' findings of a systemic 
problem to support imposition of an industry-wide solution,'' \106\ 
notwithstanding regional variation among regional transmission planning 
processes. Moreover, the Commission acknowledged that, while 
transmission planning practices vary considerably between transmission 
planning regions, the record demonstrates that deficiencies in 
transmission planning processes ``reach well beyond `isolated pockets' 
'' \107\ and instead pervade large swathes of the country, including 
RTO/ISO and non-RTO/ISO planning regions.\108\ Thus, the Commission 
added, Order No. 1920 does not present an ``extreme `disproportion of 
remedy to ailment.' '' \109\ The Commission also noted that it has 
discretion to decide the most efficient approach for resolving 
industry-wide problems.\110\ Further, the Commission reasoned, 
``region-specific solutions will lead to `siloed and disjunctive 
transmission planning policies [that] will not solve the problems 
facing the nation's electric grid.' '' \111\
---------------------------------------------------------------------------

    \105\ Id. P 132 (citations omitted).
    \106\ Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67 
(quoting Interstate Nat. Gas Ass'n of Am. v. FERC, 285 F.3d 18, 37 
(D.C. Cir. 2002))).
    \107\ Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 
67) (alteration omitted).
    \108\ Id. (citations omitted).
    \109\ Id. (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 
67) (alteration omitted).
    \110\ Id. (citing Order No. 1000, 136 FERC ] 61,051 at P 60).
    \111\ Id. (quoting ACEG NOPR Reply Comments at 17).
---------------------------------------------------------------------------

    58. The Commission stated that the record shows that significant 
changes in transmission needs are well underway nationwide and that 
failing to account for Long-Term Transmission Needs threatens just and 
reasonable rates across the country.\112\ The Commission also noted 
that significant investments in new transmission facilities are 
expected to occur and substantially affect Commission-jurisdictional 
rates that customers pay, which underscores the importance of 
addressing deficiencies in its regional transmission planning and cost 
allocation requirements now.\113\
---------------------------------------------------------------------------

    \112\ Id. P 133 (citation omitted).
    \113\ Id. (citing Order No. 1000, 136 FERC ] 61,051 at PP 46, 
50).
---------------------------------------------------------------------------

3. Benefits of Long-Term Regional Transmission Planning and Cost 
Allocation To Identify and Plan for Long-Term Transmission Needs
    59. Based on the record, the Commission found that Order No. 1920's 
requirements will help to ensure just and reasonable Commission-
jurisdictional rates by addressing deficiencies in the existing 
regional transmission planning and cost allocation requirements and 
promoting

[[Page 97186]]

enhanced reliability and more efficient or cost-effective transmission 
solutions.\114\ The Commission noted evidence in the record 
demonstrating that the kind of regional transmission planning required 
by Order No. 1920 will help transmission providers to identify, 
evaluate, and select more efficient or cost-effective transmission 
solutions to Long-Term Transmission Needs.\115\
---------------------------------------------------------------------------

    \114\ Id. P 134.
    \115\ Id. P 135.
---------------------------------------------------------------------------

    60. The Commission found that Long-Term Regional Transmission 
Planning that expands the transmission planning horizon and considers 
factors affecting Long-Term Transmission Needs as well as a broader 
list of benefits will: (1) reduce reliance on transmission solutions 
that are relatively inefficient or less cost-effective because they 
address only short-term transmission needs; (2) unlock the benefits of 
economies of scale in transmission investment; \116\ (3) enable 
opportunities to ``right size'' replacement transmission facilities; 
\117\ (4) facilitate the selection of regional transmission facilities 
that could address multiple transmission needs over different time 
horizons; and (5) provide states, utilities, customers, and other 
stakeholders with greater insight and transparency into the costs and 
benefits of particular transmission solutions to address Long-Term 
Transmission Needs. The Commission concluded that these regional 
transmission planning and cost allocation reforms will help to ensure 
just and reasonable rates.\118\ The Commission added that sufficiently 
long-term, forward-looking, and comprehensive regional transmission 
planning and cost allocation processes will also enhance reliability 
because a robust, well-planned transmission system is foundational to 
ensuring an affordable, reliable supply of electricity.\119\ 
Additionally, the Commission cited evidence demonstrating how long-
term, forward-looking, and more comprehensive regional transmission 
planning can better identify reliability needs and resolve those needs 
with more efficient or cost-effective transmission solutions.\120\
---------------------------------------------------------------------------

    \116\ Id. P 136 (citation omitted).
    \117\ Id. (citations omitted).
    \118\ Id. (citations omitted).
    \119\ Id. P 137.
    \120\ Id. P 138 (citations omitted).
---------------------------------------------------------------------------

B. The Commission Adequately Demonstrated That Existing Rates, or 
Practices Affecting Rates, Are Unjust and Unreasonable

    61. We sustain the Commission's determination in Order No. 1920 
that existing regional transmission planning and cost allocation 
processes are unjust and unreasonable, and unduly discriminatory or 
preferential. We conclude that this finding, as well as the 
Commission's finding that the identified deficiencies in transmission 
planning and cost allocation processes render existing Commission-
jurisdictional rates unjust and unreasonable, was based on substantial 
record evidence, reflecting significant input from nearly 200 
stakeholders across the country, third-party reports and studies, and 
the Commission's extensive knowledge of the industry and expert 
predictions regarding the transmission planning processes and cost 
allocation requirements that the Commission itself has established and 
oversees in carrying out its statutory responsibilities. We disagree 
with several rehearing parties who argue that the Commission failed to 
satisfy its burden under the first prong of FPA section 206 to show 
that Order No. 1000 regional transmission planning and cost allocation 
processes are unjust, unreasonable, or unduly discriminatory and 
preferential.\121\ First, we disagree with certain rehearing parties as 
to the nature of the Commission's evidentiary burden under FPA section 
206. Second, we conclude that the Commission's factual findings and the 
substantial evidence supporting those findings satisfies, and exceeds, 
the Commission's burden under FPA section 206. Third, we find that the 
``deficiencies identified by the Commission'' in Order No. 1920 do not 
```exist[ ] only in isolated pockets' '' and such evidence is supported 
by the record. Finally, we conclude that the Commission has authority 
to conduct a nationwide rulemaking. We address these points in turn.
---------------------------------------------------------------------------

    \121\ Alabama Commission Rehearing Request at 3-4; Designated 
Retail Regulators Rehearing Request at 3, 7-8, 19-22; Industrial 
Customers Rehearing Request at 3-4, 6, 11-18; SERTP Sponsors 
Rehearing Request at 28-29, 31-37; Undersigned States Rehearing 
Request at 7, 19-21; Arizona Commission Rehearing Request at 19-20.
---------------------------------------------------------------------------

1. The Commission Correctly Characterized Its Statutory Burden
a. Requests for Rehearing
    62. SERTP Sponsors contend that the Commission must demonstrate 
more than theoretical deficiencies to support nationwide policies and 
that systemic problems must be demonstrated beyond isolated 
issues.\122\ SERTP Sponsors argue that Order No. 1920's findings, which 
are based on theory and supposition, are insufficient to carry the 
applicable burden and are contradicted by substantial specific evidence 
about SERTP.\123\ SERTP Sponsors argue that South Carolina Public 
Service Authority v. FERC ``does not stand for the proposition that any 
assertion of any theoretical problem by FERC is enough to satisfy the 
first step of the analysis under [s]ection 206.'' \124\ SERTP Sponsors 
contend that except in limited circumstances--e.g., when there is a 
lack of empirical evidence--the D.C. Circuit requires more than 
theoretical deficiencies to support nationwide policies.\125\
---------------------------------------------------------------------------

    \122\ SERTP Sponsors Rehearing Request at 34 (citing S.C. Pub. 
Serv. Auth. v. FERC, 762 F.3d at 71).
    \123\ Id.
    \124\ Id. at 31 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 65).
    \125\ Id. at 29, 31, 34.
---------------------------------------------------------------------------

    63. Relatedly, Industrial Customers claim that Order No. 1920 is 
``legally infirm'' because it does not make specific findings that 
rates and practices are unjust, unreasonable, or unduly discriminatory 
or preferential and instead ``proposes to amend Order No. 1000 based 
upon mere concerns that Order No. 1000 may not be planning transmission 
in a manner that comports with the FPA.'' \126\
---------------------------------------------------------------------------

    \126\ Industrial Customers Rehearing Request at 16-17 (emphasis 
in original).
---------------------------------------------------------------------------

b. Commission Determination
    64. We sustain our determination under the first prong of FPA 
section 206 and find that the Commission relied on sufficient and 
appropriate evidence to support its determination that existing rates 
are unjust and unreasonable. We disagree with SERTP Sponsors' and 
Industrial Customers' arguments that the Commission did not satisfy its 
section 206 burden because its analysis under the first prong of FPA 
section 206 was predicated ``entirely on theory and supposition'' \127\ 
or on ``mere concerns'' that Order No. 1000 processes ``may not be 
planning transmission in a manner that comports with the FPA.'' \128\ 
Setting aside that in making this determination the Commission did not 
rely solely on ``supposition'' or ``mere concerns'' about deficiencies 
in the Order No. 1000 regional transmission planning and cost 
allocation processes,\129\ SERTP

[[Page 97187]]

Sponsors' and Industrial Customers' arguments disregard well-
established principles regarding the findings and type of evidence 
sufficient to support a conclusion that the Commission's burden under 
the first prong of FPA section 206 has been satisfied, as established 
by longstanding authority, including the D.C. Circuit's opinion in 
South Carolina Public Service Authority v. FERC.
---------------------------------------------------------------------------

    \127\ SERTP Sponsors Rehearing Request at 31.
    \128\ Industrial Customers Rehearing Request at 16-17.
    \129\ See, e.g., Order No. 1920, 187 FERC ] 61,068 at PP 93-97, 
114-123 (discussed below in The Commission Adequately Supported Its 
Determination on Step One of Section 206 section).
---------------------------------------------------------------------------

    65. In South Carolina Public Service Authority v. FERC, the D.C. 
Circuit--reviewing Order No. 1000, which the Commission adopted to 
address the ``theoretical threat'' of unjust or unreasonable rates 
``stemm[ing] from the absence of [transmission] planning processes that 
take a sufficiently broad view of both the tasks involved and the means 
of addressing them''--rejected arguments similar to those made here by 
Industrial Customers.\130\ In particular, petitioners there, similar to 
Industrial Customers here, argued that the ```theoretical threat' 
described by the Commission fail[ed] to satisfy its evidentiary burden 
under [s]ection 206 . . . .'' \131\
---------------------------------------------------------------------------

    \130\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64 (alteration 
omitted) (quoting Order No. 1000, 136 FERC ] 61,051 at P 52).
    \131\ Id.
---------------------------------------------------------------------------

    66. The court squarely rejected that contention.\132\ It explained 
that the substantial evidence required to support a finding that an 
existing practice affecting rates is ``unjust, unreasonable, unduly 
discriminatory or preferential'' pursuant to FPA section 206 ``requires 
`more than a scintilla' but `less than a preponderance' of evidence.'' 
\133\ Substantial evidence, however, ``does not necessarily mean 
empirical evidence,'' \134\ and, in satisfying the substantial evidence 
standard, the Commission may rely on its own predictions as long as 
they are ```at least likely enough to be within the Commission's 
authority' and [are] based on reasonable economic propositions.'' \135\ 
As the court recognized, ``[a]gencies do not need to conduct 
experiments in order to rely on the prediction that an unsupported 
stone will fall.'' \136\
---------------------------------------------------------------------------

    \132\ Id.
    \133\ Id. at 54 (quoting Fla. Gas Transmission Co. v. FERC, 604 
F.3d 636, 645 (D.C. Cir. 2010)), 64-65 (citing 16 U.S.C. 824e(a)), 5 
U.S.C. 706(2)(E))).
    \134\ Id. at 65 (citing 5 U.S.C. 706(2)(E)); see also Xcel 
Energy Servs. Inc. v. FERC, 41 F.4th 548, 560-61 (D.C. Cir. 2022) 
(``In making decisions, it is `perfectly legitimate for the 
Commission to base its findings on basic economic theory,' including 
relying on `generic factual predictions,' as long as the agency 
`explains and applies the relevant economic principles in a 
reasonable manner.''' (cleaned up) (quoting Sacramento Mun. Util. 
Dist. v. FERC, 616 F.3d 520, 531 (D.C. Cir. 2010) (per curiam))); 
id. (``Where the `promulgation of generic rate criteria clearly 
involves the determination of policy goals or objectives, and the 
selection of means to achieve them,' the `courts reviewing an 
agency's selection of means are not entitled to insist on empirical 
data for every proposition on which the selection depends.''' 
(alterations omitted) (quoting Associated Gas Distribs. v. FERC, 824 
F.2d 981, 1008 (D.C. Cir. 1987) (Associated Gas Distributors))).
    \135\ Id.; see also id. at 76 (``[A]t least in circumstances 
where it would be difficult or even impossible to marshal empirical 
evidence, the Commission is free to act based upon reasonable 
predictions rooted in basic economic principles.'').
    \136\ Id. at 65 (quoting Associated Gas Distributors, 824 F.2d 
at 1008); see also Cent. Hudson Gas & Elec. Corp. v. FERC, 783 F.3d 
92, 109 (2d Cir. 2015) (``FERC may permissibly rely on economic 
theory alone to support its conclusions so long as it has applied 
the relevant economic principles in a reasonable manner and 
adequately explained its reasoning.'').
---------------------------------------------------------------------------

    67. The court in reviewing Order No. 1000 determined that the 
Commission had satisfied its evidentiary burden under section 206. In 
particular, the Commission had identified ``significant changes in the 
nation's electric power industry'' that presented ``significant 
challenges to the development and cost allocation of interstate 
transmission projects'' and highlighted five deficiencies in Order No. 
890's transmission planning and cost allocation processes.\137\ 
Ultimately, the court held that the Commission's determination that the 
then-current transmission planning and cost allocation practices were 
unjust or unreasonable was based on substantial evidence.\138\
---------------------------------------------------------------------------

    \137\ Id. at 66.
    \138\ See id.at 67.
---------------------------------------------------------------------------

    68. By insisting that the Commission was required to demonstrate 
that rates or practices are, in fact, unjust, unreasonable, or unduly 
discriminatory or preferential,\139\ SERTP Sponsors and Industrial 
Customers overlook principles articulated in South Carolina Public 
Service Authority v. FERC, including that the Commission need not 
provide empirical evidence for every proposition and may instead rely 
upon the threat of unjust and unreasonable rates as a basis for taking 
action.\140\ Their argument is predicated on a faulty premise that, in 
a rulemaking setting, the Commission must wait for a threat to result 
in actual harm, and may not act where it anticipates harmful 
consequences.\141\ But in South Carolina Public Service Authority v. 
FERC, the court explicitly reached the opposite conclusion, holding 
that the Commission satisfied its evidentiary burden under section 206 
by relying on the theoretical threat to just and reasonable rates even 
though the Commission acknowledged other evidence in the record.\142\ 
SERTP Sponsors are thus incorrect to suggest that the South Carolina 
Public Service Authority v. FERC court allowed the Commission to rely 
on generic factual findings only because the record lacked empirical 
evidence.\143\
---------------------------------------------------------------------------

    \139\ Industrial Customers Rehearing Request at 16-17; SERTP 
Sponsors Rehearing Request at 34.
    \140\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64-65; see 
also id. at 85 (``[W]hether a threat of unjust or unreasonable rates 
derives from a practice or the absence thereof, Section 206 empowers 
the Commission to address it.''); Nat'l Fuel Gas Supply Corp. v. 
FERC, 468 F.3d 831, 844 (D.C. Cir. 2006) (stating that the 
Commission could choose to ``rely solely on a theoretical threat'').
    \141\ See Industrial Customers Rehearing Request at 16-17.
    \142\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64, 67.
    \143\ SERTP Sponsors Rehearing Request at 29.
---------------------------------------------------------------------------

    69. South Carolina Public Service Authority v. FERC makes clear 
that, because ``substantial evidence'' is not limited to empirical 
evidence and may include generic factual predictions, the Commission 
could have satisfied its evidentiary burden under the first prong of 
FPA section 206 with analysis based on theoretical threats and 
predictions regarding such threats based on reasonable economic 
propositions within the Commission's expertise.\144\ Here, however, the 
Commission established a theoretical threat and, as discussed below, 
also cited substantial empirical and other record evidence to support 
its finding that the existing regional transmission planning processes 
and cost allocation requirements--and the rates that have resulted from 
them--are unjust and unreasonable.
---------------------------------------------------------------------------

    \144\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65 (quoting 
Associated Gas Distributors, 824 F.2d at 1008).
---------------------------------------------------------------------------

2. The Commission Adequately Supported Its Determination on Step One of 
Section 206
a. Requests for Rehearing
    70. Designated Retail Regulators argue that, in its analysis under 
the first prong of section 206 of the FPA, the Commission made 
conclusory, ``blanket claims that are unsupported by evidence.'' \145\ 
Undersigned States similarly assert that the Commission does not 
``point to evidence in the record sufficient to support'' a finding 
that existing regional transmission planning and cost allocation 
processes are resulting in unjust, unreasonable, unduly discriminatory, 
and preferential Commission-jurisdictional rates because ``such 
evidence does not exist.'' \146\ Arizona Commission contends that the 
evidence in the record used to support Order No. 1920's section 206 
finding

[[Page 97188]]

consists largely of comments from special interest groups that will 
profit from Order No. 1920 and not evidence specific to the Arizona 
Commission.\147\
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    \145\ Designated Retail Regulators Rehearing Request at 20-21.
    \146\ Undersigned States Rehearing Request at 21.
    \147\ Arizona Commission Rehearing Request at 19.
---------------------------------------------------------------------------

    71. Industrial Customers claim that, rather than making specific 
findings that existing practices are unjust and unreasonable, the 
Commission made ``several generic assertions . . . to reach very broad 
conclusions,'' \148\ and ``generically assert[ed]'' that the Commission 
satisfies its burden under the first prong of the FPA section 206 
inquiry ``based on the record.'' \149\ Industrial Customers assert that 
the failure to reach specific findings, supported by substantial 
evidence, under the first prong of FPA section 206 renders Order No. 
1920 legally infirm.\150\ Industrial Customers claim that the absence 
of detailed and substantiated findings makes it ``difficult, if not 
impossible'' for transmission providers to file compliance filings 
because it will be challenging to develop and propose solutions without 
an understanding of the root problem the Commission is trying to 
fix.\151\
---------------------------------------------------------------------------

    \148\ Industrial Customers Rehearing Request at 16.
    \149\ Id. at 13 (alteration omitted).
    \150\ Id. at 17.
    \151\ Id. at 17-18.
---------------------------------------------------------------------------

b. Commission Determination
    72. We continue to find that the Commission made adequate findings 
under the first prong of FPA section 206 and marshalled substantial 
evidence to support those findings. We are therefore not persuaded by 
rehearing parties' arguments to the contrary. Below, we first summarize 
the empirical and other record evidence the Commission cited to support 
its findings that Commission-jurisdictional regional transmission 
planning and cost allocation processes are unjust and unreasonable 
because they result in transmission providers failing to identify Long-
Term Transmission Needs, to evaluate and select more efficient or cost-
effective transmission solutions to meet those transmission needs, and 
to allocate the costs of transmission facilities selected to meet those 
transmission needs in a manner that is at least roughly commensurate 
with benefits.\152\ Next, we summarize the Commission's generic factual 
predictions. We conclude that this evidence is more than sufficient to 
meet the Commission's evidentiary burden under section 206.
---------------------------------------------------------------------------

    \152\ Order No. 1920, 187 FERC ] 61,068 at PP 114-122.
---------------------------------------------------------------------------

    73. Based on the robust record before it, the Commission concluded 
that transmission investment, which has increased nationwide since the 
Commission issued Order No. 1000,\153\ is likely to grow substantially 
in coming years due to three factors that are driving a growing need 
for new transmission infrastructure.\154\ First, reports and comments 
in the record demonstrated that longer-term reliability needs are 
changing as transmission providers increasingly rely on regional 
transmission facilities to ensure operational stability as extreme 
weather events become more frequent and variable resources increasingly 
enter the resource mix.\155\ Based on evidence in the record, the 
Commission concluded that transmission investment is likely to be more 
critical, and produce more reliability benefits for customers, as 
extreme weather and other system contingencies become more 
frequent.\156\ Second, the Commission noted evidence that electric 
demand is projected to increase significantly in the coming decades due 
to electrification trends and new large loads associated with evolving 
industrial and commercial needs.\157\ Again, relying on record 
evidence, the Commission found that these increases in aggregate 
electricity demand will have significant consequences for the 
transmission system.\158\ Third, the Commission found that the resource 
mix is changing due to federal, federally-recognized Tribal, state, and 
local policies,\159\ customer demands for clean energy,\160\ utility

[[Page 97189]]

emission commitments,\161\ and the changing economics of resources that 
comprise the resource mix.\162\
---------------------------------------------------------------------------

    \153\ Id. P 92 (referencing a study by the US DOE, which found 
that annual investment in transmission first exceeded $5 billion per 
year in 2006, doubled to more than $10 billion per year by 2010, 
doubled again by 2016, and has been between $18 billion and $22 
billion annually since 2014 (quoting US DOE, National Electric 
Transmission Congestion Study, at 9-10 (Sept. 2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf)); id. (citing 
estimates from The Brattle Group and Grid Strategies that 
transmission developers in the United States invested $20 to $25 
billion annually in transmission facilities from 2013 to 2020 
(citing Brattle-Grid Strategies Oct. 2021 Report at 2); Brattle Apr. 
2019 Competition Report at 2-3 & fig.1)).
    \154\ Id. P 93 (citing a number of studies projecting sustained 
transmission spending through at least 2050, including one by 
Princeton University projecting that high voltage transmission 
capacity must expand by 60 percent by 2030 at a capital cost of $330 
billion and must triple by 2050 at a capital cost of $2.2 trillion, 
as well as another by The Brattle Group projecting $750 billion of 
new transmission investment between 2023 and 2050. (citing Eric 
Larson et al., Princeton Univ., Net-Zero America: Potential 
Pathways, Infrastructure, and Impacts, at 108 (Oct. 2021), https://netzeroamerica.princeton.edu/the-report; J[uuml]rgen Weiss et al., 
The Brattle Group, The Coming Electrification of the North American 
Economy, at iii (2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf)).
    \155\ The Commission cited comments and reports demonstrating 
that transmission infrastructure can be critical to system 
reliability during extreme weather events such as Winter Storm Uri. 
Id. P 94 & n.209 (citing ACEG NOPR Initial Comments at 22 n.63 
(stating that during Winter Storm Uri, ``[a]n additional 1 gigawatt 
(GW) of transmission ties between ERCOT and the Southeastern U.S. 
could have saved nearly $1 billion and kept power flowing to 
hundreds of thousands of Texans.''); Grid Strategies July 2021 
Extreme Weather Report at 7-8 (``The value of transmission for 
resilience can be seen in the drastically different outcomes of MISO 
and SPP relative to ERCOT during [Winter Storm Uri]. . . . In 
contrast to the 13,000 MW MISO was importing during the peak of 
[the] event, ERCOT was only able to import about 800 MW of power 
throughout the event.'')). The Commission also cited research from 
US DOE's Lawrence Berkeley National Laboratory suggesting that 50% 
of the value created by alleviating transmission system congestion 
occurs during only 5% of the hours during which the transmission 
system is used, further evidence of the significant value of 
transmission during unanticipated events. Id.P 94 (citing LBNL Aug. 
2022 Transmission Value Study at 33).
    \156\ Id. P 94 (citing LBNL Aug. 2022 Transmission Value Study 
at 33; Clean Energy Associations NOPR Initial Comments at 5).
    \157\ Id. P 95 (citing J[uuml]rgen Weiss et al., The Brattle 
Group, The Coming Electrification of the North American Economy 
(Mar. 2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf); John D. Wilson and Zach Zimmerman, Grid Strategies, 
The Era of Flat Power Demand is Over, at 3 (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (``Over [2023], grid planners nearly doubled 
the 5-year load growth forecast. The nationwide forecast of 
electricity demand shot up from 2.6% to 4.7% growth over the next 
five years, as reflected in 2023 FERC [Form 714] filings. Grid 
planners forecast peak demand growth of 38 gigawatts (GW) through 
2028.''); N. Amer. Elec. Reliability Corp., 2023 Long-Term 
Reliability Assessment, at 33 (Dec. 2023), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf 
(``Electricity peak demand and energy growth forecasts over the 10-
year assessment period are higher than at any point in the past 
decade. The aggregated assessment area summer peak demand forecast 
is expected to rise by 79 GW, and aggregated winter peak demand 
forecasts are increasing by nearly 91 GW. Furthermore, the growth 
rates of forecasted peak demand and energy have risen sharply since 
the 2022 [Long-Term Reliability Assessment], reversing a decades-
long trend of falling or flat growth rates.'')).
    \158\ See id. P 95 (citing National Grid NOPR Initial Comments 
at 6 (discussing preliminary findings of the ISO-NE 2050 
Transmission Study, which show ``significant new transmission will 
be needed to reliably serve'' increased future loads assumed in the 
study (citing ISO-NE, 2050 Transmission Study (2023), https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf))).
    \159\ Id. P 96 & nn.223-227 (noting numerous jurisdictions that 
have adopted decarbonization, electrification, and renewable energy-
related laws and policies); id. (citing ACORE NOPR Initial Comments 
at 1-2 & n.2; American Clean Power Ass'n, It's a Big Deal for Job 
Growth and for a Clean Energy Future (2022), https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future 
(``Analysis suggests that the [Inflation Reduction Act] could more 
than triple clean energy production in the U.S. and lead to $600 
billion in capital investment in clean energy infrastructure.''); 
Evergreen Action NOPR Initial Comments at 3-4; NextEra NOPR Reply 
Comments at 5); id. P 99.
    \160\ Id. P 97 (``Since 2014, for example, `commercial and 
industrial customers have contracted for more than 52 GW of clean 
energy.''' (alteration omitted) (quoting Advanced Energy Buyers NOPR 
Initial Comments at 5)).
    \161\ Id. P 97 & nn.233-37 (noting that Exelon, Dominion, AEP, 
Southern, Entergy, Duke Energy, NextEra, and Tennessee Valley 
Authority have all announced some version of a net-zero carbon 
emission plan or commitment).
    \162\ Id. P 97 & n.239 (citing ACORE ANOPR NOPR Initial Comments 
at app. 1, p. 22 (``Wind and solar energy costs have fallen 70 and 
89 percent, respectively, in the last ten years, from 2009 through 
2019.'')); Order No. 1920, 187 FERC ] 61,068 at P 99 (``[A]s of 
2021, nearly 70% of capacity additions across the country were from 
new, utility-scale wind and solar resources[,] . . . [and] those 
trends are projected to continue, with over 1,300 GW of wind, solar, 
and storage resources in interconnection queues across the country 
as of 2021.'' (citing SREA NOPR Initial Comments at 1-2; AEE NOPR 
Initial Comments at 12-13; California Commission NOPR Initial 
Comments at 65; Renewable Northwest NOPR Initial Comments at 36; 
FERC, State of the Markets 2020, at 10, 12 (Mar. 2021); FERC, State 
of the Markets 2023, at 4 (Mar. 2024); US DOE Initial Comments at 
app. B, PP. 8-9, 26).
---------------------------------------------------------------------------

    74. Considering the changing transmission investment landscape, the 
Commission then relied on substantial record evidence to find that the 
Commission's existing regional transmission planning and cost 
allocation requirements are deficient in three ways and therefore fail 
to require transmission providers to adequately plan on a sufficiently 
long-term, forward-looking, and comprehensive basis.\163\
---------------------------------------------------------------------------

    \163\ Id. P 112.
---------------------------------------------------------------------------

    75. The first deficiency that the Commission identified is the lack 
of a sufficiently long-term assessment of transmission needs.\164\ The 
Commission explained that most transmission planning regions do not 
plan beyond a 10-year transmission planning horizon,\165\ which is 
shorter than the time needed to plan and construct large (e.g., high 
voltage or long distance) transmission facilities \166\ or to capture 
all of the benefits that regional transmission facilities can 
provide.\167\ According to comments and studies in the record, short-
term transmission planning also fails to take advantage of the 
potential for efficiencies or economies of scale that regional 
transmission facilities can provide and does not create opportunities 
to ``right size'' the replacement of aging transmission 
facilities.\168\ Based on this evidence, the Commission concluded that 
relying solely on shorter-term transmission planning and studies fails 
to identify Long-Term Transmission Needs and consequently undervalues 
or entirely ignores the benefits of transmission investments to meet 
those needs.\169\
---------------------------------------------------------------------------

    \164\ Order No. 1920, 187 FERC ] 61,068 at P 115 (citing MISO 
ANOPR Reply Comments at 5 (``[G]iven long-term needs of an evolving 
system, additional transmission is necessary to reliably serve 
customers now and into the future. These challenges require 
immediate action and further delay only increases the risk that 
system enhancements may not be in place in the timeframe needed.''); 
PIOs NOPR Initial Comments at 13 (``[A] short-term outlook under-
forecasts longer-term transmission needs, preventing the development 
of more cost-effective transmission facilities, and fails to 
consider how the needs of the transmission system are shifting.''); 
US DOE ANOPR Initial Comments at 10 (stating that failure to plan 
transmission far enough ahead results in ``adverse implications for 
system reliability, resilience, consumers' electricity rates, and 
the achievement of clean energy goals'')).
    \165\ Id. (noting that commenters point out that ISO-NE, SERTP, 
and NorthernGrid use a 10-year transmission planning horizon, while 
PJM uses a 5-year transmission planning horizon for what it refers 
to as its short-term transmission planning process and a 6-to-15-
year transmission planning horizon for what it refers to as its 
intermediate-term transmission planning process).
    \166\ Id. P 116 (citing AEP NOPR Initial Comments at 11; Nevada 
Commission NOPR Initial Comments at 7 n.24; PIOs NOPR Initial 
Comments at 14; Renewable Northwest NOPR Initial Comments at 5; SEIA 
NOPR Initial Comments at 6). The Commission discussed MISO's MVP 
initiative, which took a decade to move from approval by the MISO 
Board of Directors in 2011 to completion of most of the projects by 
2021, a 10-year period that does not even account for the 
significant transmission facility development efforts that occurred 
prior to the MISO Board of Directors' approval. Order No. 1920, 187 
FERC ] 61,068 at P 116 (citing AESL Consulting, A Transmission 
Success Story: The MISO MVP Transmission Portfolio, at 39 (2021)).
    \167\ Id. (citing SEIA NOPR Initial Comments at 6; US DOE NOPR 
Initial Comments at 33).
    \168\ Id. (citing ACORE NOPR Initial Comments at 4 (``The 
narrowly focused current approaches [to transmission planning] do 
not identify opportunities to take advantage of the large economies 
of scale in transmission that come from `up-sizing' reliability 
projects to capture additional benefits, such as congestion relief, 
reduced transmission losses, and facilitating the more cost-
effective interconnection of the renewable and storage resources 
needed to meet public policy goals.'' (quoting Brattle-Grid 
Strategies Oct. 2021 Report at 3)); PIOs ANOPR Initial Comments at 
10-11; SEIA ANOPR Initial Comments at 14).
    \169\ Id. P 117 & n.290 (``Relying on successive small 
transmission expansion projects to meet foreseeable long-term needs 
may lead to the need for expensive retrofits (at customers' expense) 
at a later date. Economies of scale and network economies suggest 
that an initial larger-scale buildout will often represent a lower-
cost solution.'' (quoting US DOE ANOPR Initial Comments at 10)); id. 
(``While the Tranche 1 Portfolio is the result of MISO's long-range 
planning process being executed for only the second time, the rapid 
change within the industry will require that it become a more 
routine aspect of the MISO planning process going forward.'' 
(quoting Midcontinent Independent System Operator, MTEP21 Report 
Addendum: Long Range Transmission Planning Tranche 1 Portfolio 
Report, at 6 (July 28, 2022), https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary625790.pdf)).

---------------------------------------------------------------------------

    76. The second deficiency that the Commission identified is that 
transmission providers are not required to account adequately on a 
forward-looking basis for known determinants of Long-Term Transmission 
Needs or to account for such known determinants in a manner that 
ensures the identification and evaluation of more efficient or cost-
effective regional transmission facilities to meet Long-Term 
Transmission Needs.\170\ The Commission highlighted concrete evidence 
of this deficiency, including that some regional transmission planning 
processes ignore factors relevant to identifying transmission 
needs,\171\ while others fail to account for factors that will shape 
future load.\172\ The Commission added that, while forecasting 
necessarily involves uncertainty, the record demonstrates that there 
are numerous factors that increasingly shape Long-Term Transmission 
Needs, that are known and identifiable, and have reasonably predictable 
effects, especially in the aggregate.\173\ These include, for example, 
reliability needs driven by the impact of extreme weather,\174\ trends 
in future generation additions and retirements,\175\ load growth,\176\ 
federal, federally-recognized Tribal, state, and local laws and

[[Page 97190]]

regulations,\177\ and utility goals.\178\ The Commission explained, 
however, that existing regional transmission planning processes 
frequently undervalue or do not consider some or all of these factors, 
and the Commission's existing regional transmission planning 
requirements do not ensure otherwise.\179\ The Commission found that 
the failure to adequately consider such factors delays planning for the 
transmission system's changing operational needs until shortly before 
those transmission needs manifest, resulting in transmission planning 
processes that are piecemeal and fail to take advantage of economies of 
scale in transmission investment or opportunities to address multiple 
transmission needs over multiple time horizons.\180\
---------------------------------------------------------------------------

    \170\ Id. P 118.
    \171\ Id. (discussing record evidence that some existing 
regional transmission planning processes ignore trends in future 
generation, the impact of extreme weather, state laws, and utility 
goals) (citing Acadia Center and CLF NOPR Initial Comments at 1; 
GridLab NOPR Initial Comments at 4-5; Brattle-Grid Strategies Oct. 
2021 Report at 36; Grid Strategies July 2021 Extreme Weather Report 
at 5; SPP Market Monitor ANOPR Initial Comments at 3 & n.5; 
Renewable Northwest NOPR Initial Comments at 4, 8, 12; SREA NOPR 
Initial Comments at 25)).
    \172\ Id. (discussing record evidence that existing regional 
transmission planning processes fail to account for factors shaping 
electrification trends like electric vehicles and data centers 
(citing AEE ANOPR Initial Comments at 18; Clean Energy Buyers NOPR 
Initial Comments at 7-8; National Grid NOPR Initial Comments at 8; 
AEE ANOPR Initial Comments at 18; Rocky Mountain Institute NOPR 
Supplemental Comments at 1; WIRES NOPR Supplemental Comments at 
attach. 1, p. 36)).
    \173\ Id. P 119.
    \174\ Id. P 120 (citing ACEG NOPR Initial Comments at 63; NERC 
NOPR Initial Comments at 6; Evergreen Action NOPR Initial Comments 
at 2 (``[A]dditional transmission built under improved planning 
procedures would [ ] create large reliability benefits. With 
increasing extreme weather events due to climate change--including 
wildfires, winter storms, hurricanes, and more--additional 
transmission infrastructure and grid improvements are increasingly 
necessary for resilience purposes.''); WE ACT NOPR Initial Comments 
at 2).
    \175\ Id. P 120 (citing Pattern Energy NOPR Initial Comments at 
26; SEIA NOPR Initial Comments at 9).
    \176\ Id. (citing Northwest and Intermountain NOPR Initial 
Comments at 5 n.12; John Wilson and Zach Zimmerman, The Era of Flat 
Demand is Over, Grid Strategies, at 3, 6 (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (noting the 5-year load growth forecast has 
nearly doubled from 2.6% to 4.7% and ``transmission investments need 
to increase just to keep up with demand'')).
    \177\ Id. PP 119, 120 (citing Acadia Center and CLF NOPR Initial 
Comments at 8; AEE NOPR Initial Comments at 10 (noting that ``[a]s 
of September 2020, 38 states and the District of Columbia had 
adopted renewable portfolio standards, and 21 states (plus the 
District of Columbia and Puerto Rico)--representing more than half 
of the U.S. population--include a target of 100% renewable energy by 
2050 or sooner. Many of these requirements have been enacted in 
statute and are binding on utilities and retail energy 
providers.'')).
    \178\ Id. P 120 (citing Renewable Northwest NOPR Initial 
Comments at 6; SREA NOPR Initial Comments at 41-46).
    \179\ Id.
    \180\ Id. P 121 (PIOs NOPR Initial Comments at 10-11; Renewable 
Northwest NOPR Initial Comments at 8).
---------------------------------------------------------------------------

    77. The Commission explained that the third deficiency is that 
transmission providers are not required to adequately consider the 
broader set of benefits that accrue to regional transmission facilities 
planned to meet Long-Term Transmission Needs.\181\ Relying on record 
evidence, the Commission found that many current regional transmission 
planning and cost allocation processes consider only a narrow subset of 
benefits that regional transmission facilities provide \182\ or fail 
entirely to consider cost savings associated with certain transmission 
facilities.\183\
---------------------------------------------------------------------------

    \181\ Id. P 122 (citation omitted).
    \182\ Id. (citing Brattle-Grid Strategies Oct. 2021 Report at 2 
(``[M]ost of [the nation's recent transmission] investment addresses 
individual local asset replacement needs, near-term reliability 
compliance, and generation-interconnection-related reliability needs 
without considering a comprehensive set of multiple regional needs 
and system-wide benefits.''); Massachusetts Attorney General ANOPR 
Initial Comments at 22; PIOs NOPR Initial Comments at 10-11).
    \183\ Id. (citing SREA NOPR Initial Comments at 24 (``SERTP 
participants explained that SERTP is unable to conduct adjusted 
production cost savings, because none of the utilities involved in 
SERTP have the software capable of doing so. In effect, the 
`Economic Planning Studies' only evaluate the costs of potential 
upgrades to the system, but none of the benefits.'')).
---------------------------------------------------------------------------

    78. These deficiencies have concrete consequences that illustrate 
the deleterious effects of inadequate regional transmission planning 
processes. For instance, the Commission cited evidence showing that 
investment in regional transmission facilities has declined in some 
regions as compared to the investment that was occurring prior to Order 
No. 1000 and that, across all non-RTO/ISO regions, not a single 
transmission facility has been selected since implementation of Order 
No. 1000.\184\ Further, the Commission noted that within some RTO/ISO 
regional transmission planning processes, even where investments 
through the regional transmission planning process occur, much of that 
investment has been in transmission projects that only address 
immediate reliability needs.\185\
---------------------------------------------------------------------------

    \184\ Id. P 101 (citing Rob Gramlich and Jay Caspary, Americans 
for a Clean Energy Grid, Planning for the Future: FERC's Opportunity 
to Spur More Cost-Effective Transmission Infrastructure, at 25 & fi. 
8 (Jan. 2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf; ACORE ANOPR Initial Comments 
at 4 (``Despite the potential benefits, regional transmission 
investment has not increased and in some regions even has declined 
over the past decade.'') (citation omitted); State Agencies NOPR 
Initial Comments at 23 (``Regionally planned projects have [ ] 
declined in RTOs/ISOs . . . .'' (citing John C. Gravan & Rob 
Gramlich, NRRI Insights, A New State-Federal Cooperation Agenda for 
Regional and Interregional Transmission, at 2 (Sept. 2021), https://pubs.naruc.org/pub/FF5D0E68-1866-DAAC-99FB-A31B360DC685); FERC, 
Staff Report, 2017 Transmission Metrics, at 19 (Oct. 6, 2017), 
https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf).
    \185\ Id. P 101 (citing Southwestern Power Group NOPR Initial 
Comments at 15; PIOs ANOPR Initial Comments at 93 & n.276; Ari 
Peskoe, Is the Utility Syndicate Forever?, 42 Energy L.J. 1, 56-57 
(2021)).
---------------------------------------------------------------------------

    79. At the same time, the Commission found, significant expansion 
of the transmission system is occurring through one-off, piecemeal, 
interconnection-related network upgrades constructed in response to 
individual generator interconnection requests.\186\ The Commission 
noted the shortcomings of relying on the generator interconnection 
process for addressing transmission needs, including that the generator 
interconnection process does not look at time horizons beyond the 
specific interconnection request(s) being studied, comprehensively 
assess any transmission needs beyond those created by the specific 
interconnection request(s), or achieve the economies of scale in 
transmission investment that long-term, forward-looking, and more 
comprehensive regional transmission planning processes can 
provide.\187\
---------------------------------------------------------------------------

    \186\ Id. P 104 (citing Pine Gate NOPR Initial Comments at 6, 8-
10; PIOs NOPR Initial Comments at 9).
    \187\ Id. P 106 (citing Anbaric NOPR Initial Comments at 5; 
Clean Energy Associations NOPR Initial Comments at 15; Exelon NOPR 
Initial Comments at 5; Pine Gate NOPR Initial Comments at 9; PIOs 
NOPR Initial Comments at 10; SEIA NOPR Initial Comments at 2; 
Southeast PIOs NOPR Initial Comments at 37).
---------------------------------------------------------------------------

    80. The Commission also cited evidence that, since the issuance of 
Order No. 1000, the majority of investment in transmission facilities 
has been in local transmission facilities, a trend that is accelerating 
across multiple regions.\188\ The Commission pointed out that in RTO/
ISO regions one half of the nearly $70 billion in aggregate 
transmission investments by Commission-jurisdictional transmission 
providers between 2013 and 2017 was approved outside of regional 
transmission planning processes.\189\
---------------------------------------------------------------------------

    \188\ Id. P 109 (citing NOPR, 179 FERC ] 61,028 at PP 39-40 
(2022)).
    \189\ Id. (citing PIOs NOPR Initial Comments at 9).
---------------------------------------------------------------------------

    81. Relying on the foregoing record of empirical and other record 
evidence, the Commission found that existing regional transmission 
planning requirements are deficient and fail to require transmission 
providers to adequately plan on a sufficiently long-term, forward-
looking, and comprehensive basis.\190\ Substantial facts in the record 
also supported the Commission's finding that the absence of 
sufficiently long-term, forward-looking, and comprehensive regional 
transmission planning processes is resulting in piecemeal transmission 
expansion to address relatively near-term transmission needs,\191\ a 
trend that

[[Page 97191]]

reflects that existing regional transmission planning requirements are 
leading to relatively inefficient or less cost-effective results.
---------------------------------------------------------------------------

    \190\ Id. P 127 (citing New Jersey Commission NOPR Initial 
Comments at 8 (explaining that, outside of limited circumstances, 
PJM, Florida, ISO-NE, Southeastern Regional, South Carolina 
Regional, WestConnect, NorthernGrid, NYISO, SPP, and CAISO do not 
conduct multi-driver or portfolio transmission planning, which has 
required ratepayers to pay for tens of billions of dollars in 
unnecessary transmission projects); NextEra ANOPR Initial Comments 
at 71 (``While there are examples of longer-term planning currently 
being utilized by some regions, such as MISO's annual 15-year 
Futures assessment or SPP's 20-year Integrated Transmission Plan run 
every five years, there is no standard as to what time horizon long-
term planning must study, nor how often this planning should be 
done. Further, no standards or guidelines exist as to what should be 
included in such long-term planning to ensure that customers are 
charged just and reasonable rates for the most efficient and cost-
effective investments given the most comprehensive and up-to-date 
information available.''); Western PIOs NOPR Initial Comments at 4-
28 (arguing that in the Western United States transmission planning 
outside of CAISO is not developed and is ineffective); Brattle-Grid 
Strategies Oct. 2021 Report at 13-15 & tbl. 2 (documenting 
inconsistent ``use of proactive, scenario-based, multi-value 
processes'' across various planning authorities, including NYISO, 
CAISO, MISO, PJM, ISO-NE, Florida, Southeast Regional, and South 
Carolina'')).
    \191\ Id. PP 127-128 (citing LS Power NOPR Initial Comments at 
46-50; PIOs NOPR Initial Comments at 9-10 (explaining that about 
half of the approximately $70 billion in aggregate transmission 
investment by Commission-jurisdictional transmission owners in RTO/
ISO regions was approved outside of regional transmission planning 
processes)).
---------------------------------------------------------------------------

    82. Moreover, as courts have made clear, the Commission was also 
entitled to base its findings regarding the need for reform on generic 
factual predictions.\192\ In Associated Gas Distributors, the court 
explained that the Commission is permitted to act on predictions that 
are unsupported by record evidence when such predictions are ``at least 
likely enough to be within the Commission's authority'' and based on 
reasonable behavioral or economic assumptions.\193\ Indeed, 
``[a]gencies do not need to conduct experiments in order to rely on the 
prediction that an unsupported stone will fall.'' \194\ Thus, in South 
Carolina Public Service Authority v. FERC, the court held that the 
Commission satisfied its burden on the first prong of FPA section 206 
analysis where ``[t]he threat to just and reasonable rates arose, in 
the Commission's judgment, from existing planning and cost allocation 
practices that could thwart the identification of more efficient and 
cost-effective transmission solutions.'' \195\
---------------------------------------------------------------------------

    \192\ See Citadel FNGE Ltd. v. FERC, 77 F.4th 842, 858 (D.C. 
Cir. 2023); Xcel Energy Servs. Inc. v. FERC, 41 F.4th at 560-61; 
Associated Gas Distributors, 824 F.2d at 1008.
    \193\ Associated Gas Distributors, 824 F.2d at 1008 (discussing 
Wis. Gas Co. v. FERC, 770 F.2d 1144 (D.C. Cir. 1985); Elec. 
Consumers Res. Council v. FERC, 747 F.2d 1511 (D.C. Cir. 1984)).
    \194\ Associated Gas Distributors, 824 F.2d at 1008.
    \195\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 66 (emphasis 
added).
---------------------------------------------------------------------------

    83. Here, relying on its expertise and knowledge of the industry, 
the Commission made several predictions that were fully consistent with 
the grounds for action that courts have accepted in the past, including 
in Associated Gas Distributors and South Carolina Public Service 
Authority v. FERC. First, the Commission made such predictions when it 
explained how observed deficiencies in existing regional transmission 
planning and cost allocation requirements are resulting in deleterious 
consequences and ultimately rendering rates unjust and 
unreasonable.\196\ Next, the Commission predicted that existing cost 
allocation requirements--which were designed and established in the 
context of existing shorter-term Order No. 1000 regional transmission 
planning processes and lack a dedicated process through which states 
have an opportunity to participate in the development of regional cost 
allocation methods--are insufficient to appropriately allocate costs 
associated in the context of the Long-Term Regional Transmission 
Planning requirements established in Order No. 1920.\197\ Finally, the 
Commission anticipated that, absent Order No. 1920's reforms, regional 
transmission planning processes will continue to fail to identify, 
evaluate, and select regional transmission facilities that can more 
efficiently or cost-effectively meet Long-Term Transmission Needs, 
requiring customers to pay for relatively inefficient or less cost-
effective transmission development.\198\ Such predictions are precisely 
the type of evidence that courts have permitted the Commission to use 
as the basis for section 206 rulemaking.
---------------------------------------------------------------------------

    \196\ See Order No. 1920, 187 FERC ] 61,068 at PP 117, 121, 123.
    \197\ Id. P 126.
    \198\ Id. P 113.
---------------------------------------------------------------------------

    84. Given both the empirical and other record evidence and the 
generic factual predictions on which the Commission relied, we are 
unpersuaded by Designated Retail Regulators' and Undersigned States' 
arguments \199\ that the Commission's determination under the first 
prong of FPA section 206 was unsupported by substantial evidence. 
Indeed, the Commission's findings regarding ongoing changes to the 
nation's electric power industry and deficiencies in existing 
transmission planning and cost allocation processes, along with the 
evidence supporting those findings, are similar to, or the same as, the 
type of findings and evidence that formed the basis for action in Order 
No. 1000 and that the South Carolina Public Service Authority v. FERC 
court determined satisfied the Commission's burden under the first 
prong of FPA section 206.\200\
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    \199\ Designated Retail Regulators Rehearing Request at 20-21; 
Undersigned States Rehearing Request at 21.
    \200\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65-67; see 
also Order No. 1000, 136 FERC ] 61,051 at PP 44-47, 78-83.
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    85. For these same reasons, we disagree with Arizona Commission's 
unsubstantiated contention that the evidence in the record on which the 
Commission relied to satisfy its section 206 burden consists largely of 
comments from special interest groups that will profit from the final 
rule.\201\ The Commission's findings were based on an extensive record 
consisting of over 30,000 pages of comments from nearly 200 
stakeholders, including industry participants such as transmission 
providers,\202\ generation developers,\203\ trade associations,\204\ 
customer groups,\205\ and governmental entities.\206\ The Commission's 
findings also relied upon many reports and studies in the record and 
the Commission's expert predictions.\207\ Arizona Commission disregards 
this substantial evidence.
---------------------------------------------------------------------------

    \201\ See Arizona Commission Rehearing Request at 19.
    \202\ See, e.g., Order No. 1920, 187 FERC ] 61,068 at P 115 
(citing PJM NOPR Initial Comments; MISO ANOPR Reply Comments; ITC 
NOPR Initial Comments); id. P 116 (citing AEP NOPR Initial 
Comments); id. P 118 (citing National Grid NOPR Initial Comments); 
id. P 136 (citing Exelon NOPR Initial Comments.
    \203\ See, e.g., id. P 120 (citing Pattern Energy NOPR Initial 
Comments); id. P 127 (citing NextEra ANOPR Initial Comments; LS 
Power NOPR Initial Comments).
    \204\ See, e.g., id. P 116 (citing SEIA ANOPR Initial Comments); 
id. P 137 (citing EEI NOPR Initial Comments).
    \205\ See, e.g., id. P 118 (citing Clean Energy Buyers NOPR 
Initial Comments; ELCON NOPR Initial Comments); id. PP 119-120 
(citing Industrial Customers NOPR Initial Comments).
    \206\ See, e.g., id. P 115 (citing Massachusetts Attorney 
General NOPR Initial Comments; US DOE ANOPR Initial Comments); id. P 
116 (citing Nevada Commission NOPR Initial Comments); id. P 120 
(citing NERC NOPR Initial Comments); id. PP 121, 127, 135 (citing 
New Jersey Commission NOPR Initial Comments); id. P 128 (citing 
Michigan State Entities NOPR Initial Comments).
    \207\ See, e.g., id. P 92 (citing US DOE, National Electric 
Transmission Congestion Study, (Sept. 2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf); Brattle-Grid 
Strategies Oct. 2021 Report); id. P 101 (citing ACEG Jan. 2021 
Planning Report; John C. Gravan & Rob Gramlich, NRRI Insights, A New 
State-Federal Cooperation Agenda for Regional and Interregional 
Transmission (Sept. 2021), https://pubs.naruc.org/pub/FF5D0E68-1866-DAAC-99FB-A31B360DC685); FERC, Staff Report, 2017 Transmission 
Metrics (Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf)); id. P 102 (citing 
Midcontinent Indep. Sys. Operator, RGOS: Regional Generation Outlet 
Study (Nov. 2020)); MTEP2017 Review); id. P 116 (citing AESL 
Consulting, A Transmission Success Story: The MISO MVP Transmission 
Portfolio (2021); Midcontinent Independent System Operator, MTEP21 
Report Addendum: Long Range Transmission Planning Tranche 1 
Portfolio Report (July 28, 2022), https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary625790.pdf); 
id. P 118 (citing Grid Strategies July 2021 Extreme Weather Report; 
Regulatory Assistance Project, FERC Transmission: The Highest-Yield 
Reforms (July 2022), https://www.raponline.org/wp-content/uploads/2023/09/rap-littell-prause-weston-FERC-transmission-highest-yield-reforms-2022-july.pdf; Rob Gramlich, et al., Fostering Collaboration 
Would Help Build Needed Transmission (Feb. 2024)); id. P 120 (citing 
BPA, TSR Study and Expansion Process (Dec. 7, 2021), https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf; John Wilson and Zach Zimmerman, The Era of Flat Demand 
is Over, Grid Strategies (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf).
---------------------------------------------------------------------------

    86. We are also unpersuaded by Industrial Customers' assertion that 
the absence of substantial evidence makes it ``difficult if not 
impossible'' for transmission providers to submit compliance filings 
because it will be challenging to develop and propose solutions without 
an understanding of

[[Page 97192]]

the root problem that the Commission is trying to fix.\208\ As 
discussed above, the Commission made detailed findings addressing the 
deficiencies of existing transmission planning and cost allocation 
requirements and the processes related to those requirements.\209\ 
Moreover, in developing their compliance filings, transmission 
providers will rely on the Commission's specific identification of the 
new requirements established under the second prong of FPA section 206, 
not on the deficiencies in existing transmission planning and cost 
allocation processes and requirements identified under the first prong 
of the Commission's section 206 analysis. We are therefore not 
persuaded that Order No. 1920's findings lack the requisite specificity 
to enable transmission providers to make compliance filings.
---------------------------------------------------------------------------

    \208\ Industrial Customers Rehearing Request at 17.
    \209\ See supra Unjust, Unreasonable, and Unduly Discriminatory 
or Preferential Commission-Jurisdictional Transmission Planning and 
Cost Allocation Processes section.
---------------------------------------------------------------------------

3. The Commission Identified Deficiencies That Exist Beyond Isolated 
Pockets
a. Requests for Rehearing
    87. Alabama Commission and SERTP Sponsors assert that Order No. 
1920's generalized observations criticizing the effectiveness of 
existing transmission planning processes are based on examples from 
other parts of the country and do not apply to, or address evidence 
regarding, Alabama and the Southeast.\210\ According to Alabama 
Commission, Alabama and SERTP already achieve many, if not most, of the 
goals of the final rule.\211\ Alabama Commission contends that Alabama 
has a resource planning process that accounts for needed transmission 
buildout to maintain reliable service and proactively plans its 
transmission system to maintain deliveries from existing resources and 
accommodate generation additions.\212\ Alabama Commission adds that the 
SERTP process ensures that there are no regional transmission solutions 
that are more efficient and cost-effective than the solutions 
identified through the underlying state-jurisdictional process.\213\
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    \210\ Alabama Commission Rehearing Request at 3; SERTP Sponsors 
Rehearing Request at 28-29, 31.
    \211\ Alabama Commission Rehearing Request at 3.
    \212\ Id. at 3-4.
    \213\ Id. at 4.
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    88. SERTP Sponsors allege that the SERTP process has been highly 
efficient, and that its integrated resource plan and request for 
proposal-driven transmission planning and other similar processes 
effectively address the Commission's concerns regarding siloed 
planning, lack of scenario planning, and local versus regional project 
focus. SERTP Sponsors argue that, while the court in South Carolina 
Public Service Authority v. FERC allowed the Commission to support a 
rulemaking by finding a systemic problem not limited to isolated 
pockets, given SERTP's scale, scope, and that it does not suffer from 
the theoretical deficiencies identified in Order No. 1920, the 
Commission has not satisfied the standard set out in South Carolina 
Public Service Authority v. FERC.\214\ SERTP Sponsors claim that they 
ensure a comprehensive and proactive approach to transmission system 
development by incorporating various factors into their planning, 
including reliability, economic growth, environmental attributes, and 
public policy requirements.\215\ According to SERTP Sponsors, the 
alternative projects identified through its regional transmission 
planning analyses have not proved to be more efficient or cost-
effective than those identified through SERTP's integrated resource 
plan and request for proposal-driven transmission planning.\216\
---------------------------------------------------------------------------

    \214\ SERTP Sponsors Rehearing Request at 34 n.100.
    \215\ Id. at 32.
    \216\ Id. at 33.
---------------------------------------------------------------------------

    89. SERTP Sponsors also disagree with Order No. 1920's finding that 
nationwide transmission grid expansion is primarily driven through the 
generator interconnection process, because in the Southeast, 
transmission expansion is driven by the underlying integrated resource 
plan/request for proposal and other similar planning processes.\217\ 
SERTP Sponsors state that Southern Companies added $5.3 billion in 
transmission capital expenditures from 2017-2021, with only $57 million 
(just over 1%) related to generation interconnection.\218\ Similarly, 
SERTP Sponsors explain that Duke Energy added an estimated $503 million 
of transmission facilities to its transmission plan, targeted at 
unlocking areas of its transmission system that were repeatedly 
identified in past generator interconnection studies as constrained to 
more timely and cost-effectively integrate needed generation 
resources.\219\ SERTP Sponsors contend that Order No. 1920 ignored this 
evidence.\220\
---------------------------------------------------------------------------

    \217\ Id. at 36.
    \218\ Id. at 36-37.
    \219\ Id. at 37 (citing Duke NOPR Initial Comments at 8-9).
    \220\ Id. (citing Motor Vehicle Mfrs. Ass'n v. State Farm Mut. 
Auto Ins. Co., 463 U.S. 29, 43 (1983) (State Farm) (internal 
citation omitted)).
---------------------------------------------------------------------------

    90. Designated Retail Regulators and Undersigned States aver that, 
contrary to the Commission's claims, the evidence in the record 
demonstrates that a substantial portion of transmission providers have 
been and are engaging in long-term planning.\221\ For example, 
Designated Retail Regulators and Undersigned States point to MISO's 
Multi-Value Projects (MVP) process, which they claim includes most of 
the requirements of Order No. 1920.\222\ Designated Retail Regulators 
and Undersigned States also contend that CAISO, NYISO, Southern 
Companies, and other transmission planners also have sufficient long-
term planning and that SPP indicated in its NOPR comments that its OATT 
requires planning processes that are sufficient to meet the intent and 
desired outcomes of Order No. 1920.\223\
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    \221\ Designated Retail Regulators Rehearing Request at 21-22; 
Undersigned States Rehearing Request at 22-23.
    \222\ Designated Retail Regulators Rehearing Request at 21-22; 
Undersigned States Rehearing Request at 22.
    \223\ Designated Retail Regulators Rehearing Request at 22 
(citing Order No. 1920, 187 FERC ] 61,068 (Christie, Comm'r, 
dissenting, at PP 65-66); SPP NOPR Initial Comments at 3); 
Undersigned States Rehearing Request at 22-23 (citing Order No. 
1920, 187 FERC ] 61,068 (Christie, Comm'r, dissenting, at PP 65-66); 
SPP NOPR Initial Comments at 3).
---------------------------------------------------------------------------

b. Commission Determination
    91. We disagree with rehearing parties who argue that the 
Commission did not satisfy its burden under the first prong of FPA 
section 206 because certain transmission providers may already engage 
in some form of long-term transmission planning.\224\ We are satisfied 
that the Commission identified deficiencies in existing regional 
transmission planning and cost allocation processes that exist beyond 
isolated pockets.
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    \224\ Alabama Commission at 3-4; Designated Retail Regulators 
Rehearing Request at 21-22; Undersigned States Rehearing Request at 
22-23; SERTP Sponsors Rehearing Request at 28-37.
---------------------------------------------------------------------------

    92. First, ``[t]hat some commenters may engage in sufficient 
transmission planning processes `is as unastonishing as it is 
irrelevant,' '' where, as here, the deficiencies identified by the 
Commission and supported by substantial evidence reach well beyond 
``isolated pockets.'' \225\ Record evidence demonstrates that 
transmission planning regions across the country--including ISO-NE, 
SERTP, and NorthernGrid--do not plan beyond a 10-

[[Page 97193]]

year transmission planning horizon,\226\ which is problematic for 
several reasons, including that regional transmission facilities often 
have lead times that exceed 10 years \227\ and that a 10-year 
transmission planning horizon is much too short to capture all of the 
benefits that regional transmission facilities can provide.\228\ 
Further, comments and reports in the record establish that transmission 
planning processes in several regions do not account for known 
determinants of Long-Term Transmission Needs such as trends in future 
generation \229\ and extreme weather.\230\ The record demonstrates that 
many regional transmission planning processes also fail to adequately 
consider the range of benefits of regional transmission facilities 
planned to meet Long-Term Transmission Needs.\231\ And the Commission 
cited evidence showing that, except in limited cases, transmission 
providers in many regions do not conduct multi-driver or portfolio 
transmission planning, which has led to ratepayers paying for 
relatively inefficient or less cost-effective transmission 
projects.\232\
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    \225\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67 (first 
quoting Wis. Gas Co. v. FERC, 770 F.2d at 1157; and then quoting 
Associated Gas Distributors, 824 F.2d at 1019).
    \226\ Order No. 1920, 187 FERC ] 61,068 at P 115 & n.282 (citing 
ITC NOPR Initial Comments at 9 (referring to the ``broad use of a 
10-year planning horizon in the existing transmission planning 
processes of many major planning regions'')).
    \227\ Id. P 116 (citing AEP NOPR Initial Comments at 11; Nevada 
Commission NOPR Initial Comments at 7 n.24; PIOs NOPR Initial 
Comments at 14; Renewable Northwest NOPR Initial Comments at 5; SEIA 
NOPR Initial Comments at 6). The Commission discussed MISO's MVP 
initiative, which took a decade to move from approval by the MISO 
Board of Directors in 2011 to completion of most of the projects by 
2021, a 10-year period that does not even account for the 
significant transmission facility development efforts that occurred 
prior to the MISO Board of Directors' approval. Order No. 1920, 187 
FERC ] 61,068 at P 116 (citing AESL Consulting, A Transmission 
Success Story: The MISO MVP Transmission Portfolio, at 39 (2021)).
    \228\ Id. (citing SEIA NOPR Initial Comments at 6; US DOE NOPR 
Initial Comments at 33).
    \229\ Id. P 118 & n.294.
    \230\ Id. P 118 & n.293.
    \231\ Id. P 122 & nn.309-12 (citing Massachusetts Attorney 
General ANOPR Initial Comments at 22 (``New England's siloed 
approach to transmission planning inhibits identification of multi-
value solutions.''); PIOs Initial Comments at 10 (``[T]he vast 
majority of current transmission projects are focused solely either 
on network reliability or connecting the next generator in the 
interconnection queue and ignore any other potential benefits, 
possible economies of scale or other efficiencies that might occur 
by considering multiple future needs . . . . [M]ultiple quantifiable 
benefits to transmission . . . are being ignored in the transmission 
planning process.''); SREA Initial Comments at 24 (``SERTP 
participants explained that SERTP is unable to conduct adjusted 
production cost savings, because none of the utilities involved in 
SERTP have the software capable of doing so. In effect, the 
`Economic Planning Studies' only evaluate the costs of potential 
upgrades to the system, but none of the benefits.'').
    \232\ Id. P 127 & n.318 (citing New Jersey Commission NOPR 
Initial Comments at 8 (explaining that, outside of limited 
circumstances, PJM, Florida, ISO-NE, Southeastern Regional, South 
Carolina Regional, WestConnect, NorthernGrid, NYISO, SPP, and CAISO 
do not conduct multi-driver or portfolio transmission planning, 
which has required ratepayers to pay for tens of billions of dollars 
in unnecessary transmission projects); NextEra ANOPR Initial 
Comments at 71 (``While there are examples of longer-term planning 
currently being utilized by some regions, such as MISO's annual 15-
year Futures assessment or SPP's 20-year Integrated Transmission 
Plan run every five years, there is no standard as to what time 
horizon long-term planning must study, nor how often this planning 
should be done. Further, no standards or guidelines exist as to what 
should be included in such long-term planning to ensure that 
customers are charged just and reasonable rates for the most 
efficient and cost-effective investments given the most 
comprehensive and up-to-date information available.''); Western PIOs 
NOPR Initial Comments at 4-28 (arguing that in the Western United 
States transmission planning outside of CAISO is not developed and 
is ineffective); Brattle-Grid Strategies Oct. 2021 Report at 13-15 & 
tbl. 2 (documenting inconsistent ``use of proactive, scenario-based, 
multi-value processes'' across various planning authorities, 
including NYISO, CAISO, MISO, PJM, ISO-NE, Florida, Southeast 
Regional, and South Carolina'')).
---------------------------------------------------------------------------

    93. We are unpersuaded by SERTP Sponsors' argument that the 
Commission failed to satisfy its burden under the first prong of FPA 
section 206 analysis because it ignored evidence that transmission 
expansion in SERTP is driven by ``planning processes that proactively 
anticipate[ ] a changing resource mix and the use of firm `physical' 
transmission service--and not by interconnection requests.'' \233\ As 
Order No. 1920 makes clear, the deficiencies of existing transmission 
planning and cost allocation processes result in various detrimental 
outcomes reflecting that existing requirements are unjust and 
unreasonable. Over-reliance on generator interconnection requests to 
expand the transmission system is just one such example. The Commission 
noted other existing deficiencies as well, including that the majority 
of investments in transmission facilities are occurring through local 
transmission planning processes and in-kind replacements, which focus 
on the needs of individual transmission provider footprints and miss 
the potential for more efficient or cost-effective regional 
transmission facilities.\234\
---------------------------------------------------------------------------

    \233\ SERTP Sponsors Rehearing Request at 36.
    \234\ Order No. 1920, 187 FERC ] 61,068 at P 109-111.
---------------------------------------------------------------------------

    94. Moreover, although SERTP Sponsors assert that SERTP ``does not 
suffer from [Order No. 1920's] theoretical deficiencies,'' \235\ and 
Alabama Commission asserts that that the Commission ignored evidence 
that transmission planning in SERTP ``achieves many, if not most, of 
the goals in the Final Rule,'' \236\ the Commission, in fact, cited 
evidence that SERTP's transmission planning process suffers from each 
of the three deficiencies that the Commission identified in Order No. 
1920. Record evidence demonstrates that SERTP's regional transmission 
planning and cost allocation process (1) does not perform a 
sufficiently long-term assessment of transmission needs; \237\ (2) does 
not adequately account on a forward-looking basis for known 
determinants of Long-Term Transmission Needs; \238\ and (3) fails to 
adequately consider the broader set of benefits of regional 
transmission facilities planned to meet Long-Term Transmission 
Needs.\239\
---------------------------------------------------------------------------

    \235\ SERTP Sponsors Rehearing Request at 34 & n.100.
    \236\ Alabama Commission Rehearing Request at 3.
    \237\ Order No. 1920, 187 FERC ] 61,068 at P 115 (noting that 
SERTP uses a 10-year transmission planning horizon (citing Southeast 
PIOs NOPR Initial Comments at 12)).
    \238\ Id. P 118 n.294 (explaining that in 2021, SERTP stated 
that because it did not receive any proposals for transmission needs 
driven by Public Policy Requirements for the 2021 planning cycle, it 
identified no possible transmission needs driven by Public Policy 
Requirements for further evaluation of potential transmission 
solutions in that planning cycle (citing SREA NOPR Initial Comment 
at 25)).
    \239\ Id. P 122 n.312 (``SERTP participants explained that SERTP 
is unable to conduct adjusted production cost savings, because none 
of the utilities involved in SERTP have the software capable of 
doing so. In effect, the `Economic Planning Studies' only evaluate 
the costs of potential upgrades to the system, but none of the 
benefits.'' (quoting SREA NOPR Initial Comments at 24)).
---------------------------------------------------------------------------

    95. Further, Designated Retail Regulators and Undersigned States 
provide no support for their claim that ``a substantial portion of 
transmission providers'' are currently conducting ``effective long-term 
planning.'' \240\ Instead, they assert that CAISO, NYISO, Southern 
Companies, and ``[o]ther regions . . . have sufficient long-term 
planning'' \241\ without explaining how the transmission planning 
processes in those regions do not suffer from the deficiencies that the 
Commission identified in Order No. 1920 as necessitating reform of its 
existing regional transmission planning and cost allocation 
requirements. Similarly, Designated Retail Regulators' and Undersigned 
States' conclusion that SPP's transmission planning processes are 
``sufficient to meet the Commission's

[[Page 97194]]

desired outcomes'' \242\ cites to a single sentence in comments SPP 
filed nearly two years before the Commission adopted Order No. 1920, in 
which SPP stated only that it ``believe[d] its current study processes 
and initiatives [to be] sufficient to meet the Commission's desired 
outcomes.'' \243\ Such unsupported statements about the sufficiency of 
transmission planning processes in various transmission planning 
regions similarly fail to establish that those transmission providers' 
existing transmission planning and cost allocation processes do not 
suffer the deficiencies that the Commission identified in Order No. 
1920. While MISO's regional transmission planning process may satisfy 
certain of Order No. 1920's requirements, this does not establish that 
deficiencies in existing regional transmission planning and cost 
allocation processes are occurring only in ``isolated pockets.''
---------------------------------------------------------------------------

    \240\ See Designated Retail Regulators Rehearing Request at 21; 
Undersigned States Rehearing Request at 22.
    \241\ Designated Retail Regulators Rehearing Request at 22 
(citing Order No. 1920, 187 FERC ] 61,068 (Christie, Comm'r, 
dissenting, at PP 65-66)); Undersigned States Rehearing Request at 
23 (citing Order No. 1920, 187 FERC ] 61,068 (Christie, Comm'r, 
dissenting, at PP 65-66)).
    \242\ Designated Retail Regulators Rehearing Request at 22 
(citing SPP NOPR Initial Comments at 3); Undersigned States 
Rehearing Request at 22 (citing SPP NOPR Initial Comments at 3).
    \243\ SPP NOPR Initial Comments at 3.
---------------------------------------------------------------------------

    96. Moreover, SERTP Sponsors do not identify any authority 
supporting the contention that the Commission cannot make a generic 
finding under section 206 unless it shows that every transmission 
provider's OATT is unjust and unreasonable or unduly discriminatory or 
preferential. Nor are we convinced by SERTP Sponsors' attempts to 
distinguish South Carolina Public Service Authority v. FERC, where the 
court held that ``the Commission may act by generic rule . . . without 
first finding that the rates charged by individual utilities are unjust 
or unlawful when it concludes that any tariff violating the rule would 
have such adverse effects on the interstate gas or energy market as to 
render it unjust and unreasonable.'' \244\ SERTP Sponsors assert that, 
given ``SERTP's scale and scope and the fact that it does not suffer 
from [Order No. 1920's] theoretical deficiencies,'' the reasoning of 
South Carolina Public Service Authority v. FERC is inapplicable here. 
However, while we do not need to make specific findings regarding 
individual transmission providers, we note, as discussed above, that 
record evidence demonstrates that SERTP does suffer from each of the 
theoretical deficiencies that the Commission identified in Order No. 
1920. Significantly, in finding that existing regional transmission 
planning and cost allocation requirements are not just and reasonable, 
the Commission also recognized that ``the present is not a prediction 
of the future'' \245\ in light of the threat, documented by substantial 
evidence, that, absent Order No. 1920's reforms, regional transmission 
planning processes will continue to fail to identify, evaluate, and 
select regional transmission facilities that can more efficiently or 
cost-effectively meet Long-Term Transmission Needs, requiring customers 
to pay for relatively inefficient or less cost-effective transmission 
development. That ``the present is not a prediction of the future'' is 
especially true in a period of rapid change like the electric sector is 
now experiencing. Given industry trends that the Commission highlighted 
in Order No. 1920--changing longer-term reliability needs due to more 
frequent extreme weather events and the increasing share of variable 
resources entering the resource mix,\246\ significantly increasing 
demand,\247\ and changes to the nation's resource mix \248\--even if 
the identified deficiencies in existing regional transmission planning 
and cost allocation requirements have yet to manifest clearly in every 
transmission planning region, we can reasonably predict that they will 
in the near future. The Commission acted within its authority to 
prevent that eventuality from materializing.\249\
---------------------------------------------------------------------------

    \244\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 86 (quoting 
Associated Gas Distributors, 824 F.2d at 1008).
    \245\ Id. at 67 (quoting Order No. 1000-A, 139 FERC ] 61,132 at 
P 65); see also Order No. 1000-A, 139 FERC ] 61,132 at P 65 (``The 
Commission is authorized to make rules with prospective effect that 
will prevent situations that are inconsistent with the FPA from 
occurring, which means that it is authorized to consider how the 
future may be different from the present if the rules it proposes 
are not adopted.'').
    \246\ Order No. 1920, 187 FERC ] 61,068 at P 94.
    \247\ Id. P 95.
    \248\ Id. P 96.
    \249\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64-65, 85 
(``[W]hether a threat of unjust or unreasonable rates derives from a 
practice or the absence thereof, Section 206 empowers the Commission 
to address it.'').
---------------------------------------------------------------------------

    97. Moreover, the Commission found that the existing regional 
transmission planning and cost allocation requirements are unjust and 
unreasonable under of the first prong of FPA section 206.\250\ While 
transmission planning regions vary in their specific approaches, and 
some transmission providers, within their discretion, may have adopted 
practices that satisfy some of Order No. 1920's requirements, there is 
no guarantee that these practices will continue in the absence of Order 
No. 1920's requirements. If transmission providers believe that they 
already satisfy any of the requirements of Order No. 1920, they may 
seek to demonstrate that they do so in their compliance filings.
---------------------------------------------------------------------------

    \250\ Order No. 1920, 187 FERC ] 61,068 at P 114 (``Based on the 
record, including the comments submitted in response to the NOPR, we 
find that there is substantial evidence to support the conclusion 
that deficiencies in the Commission's existing regional transmission 
planning and cost allocation requirements are resulting in 
Commission-jurisdictional rates that are unjust, unreasonable, and 
unduly discriminatory or preferential.'') (emphasis added)).
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4. The Commission Has the Authority To Conduct a Generic Rulemaking
a. Requests for Rehearing
    98. Undersigned States argue that the Commission lacks authority to 
make rate determinations on a generic, national level.\251\ Undersigned 
States note that under section 206, the Commission has the power to 
determine, after a hearing held upon its own motion or upon complaint, 
that the rates charged by a specific utility subject to Commission 
jurisdiction are unjust, unreasonable, unduly discriminatory, or 
preferential, and if so, to adjust that rate.\252\ Undersigned States 
claim that this does not authorize the Commission to issue Order No. 
1920.\253\
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    \251\ Undersigned States Rehearing Request at 23.
    \252\ Id. at 23-24 (citing 16 U.S.C. 824e).
    \253\ Id. at 24.
---------------------------------------------------------------------------

    99. Arizona Commission argues that there is no evidence that it has 
acted in a discriminatory or unfair way while creating rates and 
processes.\254\ Therefore, Arizona Commission argues, Order No. 1920's 
section 206 finding is unlawful when applied to the Arizona Commission 
because there must be an individual finding as to the Arizona 
Commission before section 206 can be applied to it. Arizona Commission 
states that it is arbitrary and capricious ``to infer any evidence in 
the record supports the conclusion the [Arizona Commission] has acted 
in a discriminatory or unfair way.'' \255\
---------------------------------------------------------------------------

    \254\ Arizona Commission Rehearing Request at 19.
    \255\ Id. at 19-20.
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b. Commission Determination
    100. We continue to find that the Commission has the authority to 
institute the reforms adopted in Order No. 1920 and that it was not 
required to demonstrate that transmission planning and cost allocation 
processes are unjust, unreasonable, or unduly discriminatory or 
preferential with respect to specific transmission providers. Rehearing 
parties' arguments to the contrary seem to rely on a misinterpretation 
of FPA section 206. Section 206 delegates substantial responsibility to 
the Commission:
    101. Whenever the Commission, after a hearing held upon its own 
motion or

[[Page 97195]]

upon complaint, shall find that any rate, charge, or classification, 
demanded, observed, charged, or collected by any public utility for any 
transmission or sale subject to the jurisdiction of the Commission, or 
that any rule, regulation, practice, or contract affecting such rate, 
charge, or classification is unjust, unreasonable, unduly 
discriminatory or preferential, the Commission shall determine the just 
and reasonable rate, charge, classification, rule, regulation, 
practice, or contract to be thereafter observed and in force, and shall 
fix the same by order.\256\
---------------------------------------------------------------------------

    \256\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    102. As the Commission explained in Order No. 1920, and as courts 
have confirmed, transmission planning and cost allocation processes are 
``are practices affecting rates subject to the Commission's exclusive 
jurisdiction.'' \257\ Rehearing parties cite no precedent suggesting 
that section 206 requires the Commission to act on an individual, 
utility-by-utility basis, and we are aware of none.
---------------------------------------------------------------------------

    \257\ Order No. 1920, 187 FERC ] 61,068 at P 86 (citing S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 55).
---------------------------------------------------------------------------

    103. Contrary to Undersigned States' argument that the Commission 
lacks authority to make rate determinations on a generic, national 
level, courts have consistently interpreted section 206 to allow the 
Commission to regulate on a national level, through notice-and-comment 
rulemakings, when the Commission finds systemic issues throughout the 
industry that cause practices affecting rates charged by public 
utilities to be unjust, unreasonable, or unduly discriminatory or 
preferential.\258\ Nearly 40 years of precedent has consistently 
interpreted the Commission's FPA section 206 authority--and the 
corresponding, nearly identical authority in the Natural Gas Act 
\259\--as providing the Commission with the authority to ``rely on 
`generic' or `general' findings of a systemic problem to support 
imposition of an industry-wide solution.'' \260\ In fact, in 
interpreting the nearly identical provision of the Natural Gas Act, the 
D.C. Circuit stated that ``[t]he Commission is not required to make 
individual findings, however, if it exercises its Natural Gas Act Sec.  
5 authority by means of a generic rule.'' \261\ The Commission has, 
time and time again, exercised section 206 authority through generic 
rulemakings that rely on industry-wide findings rather than region-by-
region or utility-specific findings.\262\ Indeed, Order No. 1920 itself 
builds upon existing transmission planning and cost allocation 
requirements adopted by the Commission through other generally 
applicable, nationwide rulemakings. Thus, the Commission was not 
required to make specific findings as to the Arizona Commission or 
transmission planning and cost allocation processes within Arizona or 
any given state. Moreover, Order No. 1920's reforms are directed to 
transmission providers, consistent with the Commission's 
jurisdiction,\263\ and do not require any action by state regulatory 
authorities.\264\ In light of the Commission's authority to act on a 
generic basis to reform the practices of all transmission providers, 
the Commission reasonably exercised its broad discretion to proceed by 
nationwide rulemaking to remedy the deficiencies that it determined in 
Order No. 1920 render its existing regional transmission planning and 
cost allocation requirements unjust and unreasonable.\265\
---------------------------------------------------------------------------

    \258\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (upholding 
Order No. 1000); TAPS, 225 F.3d 667, aff'd sub nom. N.Y. v. FERC, 
535 U.S. 1 (upholding Order No. 888).
    \259\ 15 U.S.C. 717d(a).
    \260\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67 (quoting 
Interstate Nat. Gas of Am. v. FERC, 285 F.3d at 37; see also TAPS, 
225 F.3d at 687-88; Associated Gas Distributors, 824 F.2d 981; Wis. 
Gas Co. v. FERC, 770 F.2d at 1166 & n.36.
    \261\ Associated Gas Distributors, 824 F.2d at 1008. It is 
``well settled that comparable provisions of the Natural Gas Act and 
[FPA] are to be construed in pari materia.'' Ky. Utils. Co. v. FERC, 
760 F.2d 1321, 1325 n.6 (D.C. Cir. 1985).
    \262\ See, e.g., TAPS, 225 F.3d 667 (upholding Order No. 888, 
which was promulgated under FPA section 206 and premised on general 
systemic conditions rather than evidence regarding individual 
utilities); S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (same for 
Order No. 1000); Elec. Storage Participation in Mkts. Operated by 
Reg'l Transmission Organs. and Indep. Sys. Operators, Order No. 841, 
83 FR 9580 (Mar. 6, 2018), 162 FERC ] 61,127, at P 21 (2018), order 
on reh'g, Order No. 841-A, 167 FERC ] 61,154 (2019), aff'd sub nom. 
Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 964 F.3d 1177 (D.C. 
Cir. 2020) (NARUC); Order No. 890, 118 FERC ] 61,119 at PP 41-43.
    \263\ Order No. 1920, 187 FERC ] 61,068 at PP 1 n.2, 253.
    \264\ See Order No. 1920, 187 FERC ] 61,068 at P 263 (``[T]his 
final rule directly regulates transmission planning and cost 
allocation processes, . . . directly regulates only those practices, 
and it does not directly regulate any matter reserved to the states 
by FPA section 201.'').
    \265\ See Wis. Gas Co. v. FERC, 770 F.2d at 1157 (``An 
administrative agency must be equipped to act either by general rule 
or individual order. To insist upon one form of action to the 
exclusion of the other is to exalt form over necessity. The choice 
made between proceeding by general rule or by individual, ad hoc 
litigation is one that lies primarily in the informed discretion of 
the administrative agency.'' (alterations omitted) (quoting SEC v. 
Chenery Corp., 332 U.S. 194, 202-03 (1947)).
---------------------------------------------------------------------------

C. The Commission Demonstrated That the Replacement Rate is Just and 
Reasonable

1. Requests for Rehearing
    104. Several rehearing parties argue that the Commission did not 
demonstrate that the replacement tariff and transmission planning 
requirements are just and reasonable.\266\ According to Designated 
Retail Regulators, Order No. 1920 ``requires the construction of 
transmission to socialize the costs of policies of some States and 
parties over others and shifts the costs caused by interconnecting 
remotely located generators to everyone,'' but provides ``no analysis 
showing that the resulting rates are just and reasonable.'' \267\ 
Industrial Customers contend that Order No. 1920 generically asserts, 
without ``evidence, proof, or data,'' that its reforms ``should provide 
cost savings.'' \268\
---------------------------------------------------------------------------

    \266\ Designated Retail Regulators Rehearing Request at 22-23; 
Undersigned States Rehearing Request at 23.
    \267\ Designated Retail Regulators Rehearing Request at 22-23; 
see also Undersigned States Rehearing Request at 23 (similar).
    \268\ Industrial Customers Rehearing Request at 20.
---------------------------------------------------------------------------

    105. Designated Retail Regulators also claim that Order No. 1920 
contradicts Order Nos. 888 and 890, under which the cost of 
transmission is generally borne by load. Designated Retail Regulators 
argue that, in contrast, the final rule promotes the construction of 
long-haul transmission designed to move energy from remote resources 
located in one state to load located in another without any contractual 
or other assurance to the load-serving entity that the remotely located 
resource will provide firm energy. Designated Retail Regulators contend 
that, in the absence of a contractual or regulatory requirement to 
supply firm energy, there is no reasonable rationale that would justify 
allocating the cost for this transmission to remotely located 
load.\269\ Designated Retail Regulators also argue that remotely 
located customers who are required to pay for transmission facilities 
without regulatory or contractual guarantees of receiving firm energy 
are not beneficiaries, must less cost causers.\270\
---------------------------------------------------------------------------

    \269\ Designated Retail Regulators Rehearing Request at 23.
    \270\ Id. at 23-24.
---------------------------------------------------------------------------

    106. Industrial Customers argue that Order No. 1920 is arbitrary 
and capricious and does not reflect reasoned decision-making because it 
fails to consider and address costs to consumers, which is an essential 
element of the problem of transmission

[[Page 97196]]

planning and cost allocation.\271\ Arizona Commission echoes this 
argument and contends that Order No. 1920 fails to protect consumers 
and will saddle ratepayers with trillions of dollars in increased rates 
in coming years, resulting in unfair rates.\272\ Arizona Commission 
adds that the ``several factors'' that Order No. 1920 requires 
transmission providers to ``consider[ ] in transmission planning and 
cost allocation'' should have included fairness, reasonableness of 
cost, or consideration of who caused the cost, as mandated by the 
FPA.\273\
---------------------------------------------------------------------------

    \271\ Industrial Customers Rehearing Request at 19-20 (citing 
State Farm, 463 U.S. at 43).
    \272\ Arizona Commission Rehearing Request at 20.
    \273\ Id. at 21.
---------------------------------------------------------------------------

2. Commission Determination
    107. We continue to find that the replacement regional transmission 
planning and cost allocation requirements that the Commission adopted 
in Order No. 1920 are just and reasonable.\274\ We disagree with 
rehearing parties' arguments that the Commission did not demonstrate 
that the replacement rate is just and reasonable, as it appears that 
these arguments may mischaracterize Order No. 1920. Designated Retail 
Regulators argue that Order No. 1920 ``requires the construction of 
transmission to socialize the costs of the policies of some States and 
parties over others and shifts the costs caused by interconnecting 
remotely located generators to everyone.'' \275\ Like Order No. 1000, 
Order No. 1920's ``transmission planning reforms are concerned with 
process, and are not intended to dictate substantive outcomes.'' \276\ 
Order No. 1920 specifically provided that ``[t]he regional transmission 
planning requirements and cost allocation requirements in this final 
rule, like those of Order Nos. 890 and 1000, are focused on the 
transmission planning process, and do not require any substantive 
outcomes from this process.'' \277\
---------------------------------------------------------------------------

    \274\ Order No. 1920, 187 FERC ] 61,068 at PP 134-138.
    \275\ Designated Retail Regulators Rehearing Request at 22-23; 
see also Undersigned States Rehearing Requests at 23 (similar).
    \276\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 58 (quoting 
Order No. 1000-A, 139 FERC ] 61,132 at P 188); see infra Statutory 
Authority section.
    \277\ Order No. 1920, 187 FERC ] 61,068 at P 232.
---------------------------------------------------------------------------

    108. Moreover, Order No. 1920 did not change the Commission's cost 
causation requirements and does not contradict Order Nos. 888 and 890, 
under which the cost of transmission is generally borne by load.\278\ 
Order No. 1920 reiterated that ``any cost allocation method applied to 
a Long-Term Regional Transmission Facility must ensure that costs are 
allocated in a manner that is at least roughly commensurate with the 
estimated benefits of the facility, consistent with cost causation and 
court precedent.'' \279\ Order No. 1920 further stated that ``[n]othing 
in this final rule requires states to subsidize other states' public 
policies and, indeed, this final rule requires, consistent with long-
established Commission and court precedent, that transmission customers 
within a transmission planning region need only pay costs that are 
`roughly commensurate' with the benefits that transmission providers 
estimate they will receive from a regional transmission facility.'' 
\280\ Thus, ``even if one state's public policy is a driver of a Long-
Term Transmission Need, the costs of a Long-Term Regional Transmission 
Facility that transmission providers select will be allocated to 
transmission customers only to the extent that they benefit from that 
facility and only to a degree that is at least roughly commensurate 
with the benefits that facility provides to them.'' \281\ For these 
reasons, we also disagree with Designated Retail Regulators' argument 
that Order No. 1920 contradicts Order Nos. 888 and 890. Nonetheless, we 
believe certain clarifications discussed further below will alleviate 
Designated Retail Regulators' and Undersigned States' concerns 
regarding Order No. 1920's impact on multi-state cost allocation.\282\
---------------------------------------------------------------------------

    \278\ See infra Federal/State Division of Authority section.
    \279\ Order No. 1920, 187 FERC ] 61,068 at P 1305 (citing S.C. 
Pub. Serv. Auth. v. FERC, 762 F. 3d at 87; Order No 1000, 136 FERC ] 
61,051 at P 10; ICC v. FERC I, 576 F.3d at 476); see also Order No. 
1920, 187 FERC ] 61,068 at P 1297 (``Any cost allocation method(s) 
that transmission providers propose . . . must allocate costs in a 
manner that is at least roughly commensurate with estimated benefits 
. . . .'').
    \280\ Id. P 267 (citing Ill. Com. Comm'n v. FERC, 756 F.3d 556, 
562 (7th Cir. 2014) (ICC v. FERC III); ICC v. FERC I, 576 F.3d at 
477; Sw. Power Pool, Inc., 182 FERC ] 61,141, at P 12 (2023)); see 
also Order No. 1920, 187 FERC ] 61,068 at P 280 (``[T]he final rule 
categorically does not require states to subsidize other states' 
public policies or generation decisions,'' but instead, ``consistent 
with the cost causation principle, [the] final rule requires 
customers to pay for a share of the costs of new Long-Term Regional 
Transmission Facilities only to the extent that they benefit from 
those facilities and, even then, any share they pay must be roughly 
commensurate with the benefits they receive.'').
    \281\ Id. P 282.
    \282\ See supra Concerns Regarding Cost Causation section.
---------------------------------------------------------------------------

    109. We are similarly unpersuaded by Designated Retail Regulators' 
assertion that the Commission failed to satisfy its burden under the 
second prong of FPA section 206 because, under Order No. 1920, ``there 
is no reasonable rationale that would justify . . . remotely located 
customers being required to pay for transmission facilities without 
regulatory or contractual guarantees of receiving firm energy.'' \283\ 
The physics of an interconnected electric transmission system are such 
that even customers distant from new Long-Term Regional Transmission 
Facilities and without specific contractual arrangements with such 
facilities may benefit from those facilities.\284\ And any proposed 
cost allocation method for Long-Term Regional Transmission Facilities 
must allocate the costs of a new Long-Term Regional Transmission 
Facility in a manner at least roughly commensurate with the estimated 
benefits of the facility.\285\ Beyond arguing that Order No. 1920 
contradicts Order Nos. 888 and 890, Designated Retail Regulators do not 
argue that the Commission lacks authority to mandate the allocation of 
costs where there is no contractual or regulatory requirement to supply 
firm energy, and we do not believe that such a limitation exists.\286\
---------------------------------------------------------------------------

    \283\ Designated Retail Regulators Rehearing Request at 23-24.
    \284\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 85 
(``Entities that contract for service on the transmission grid 
cannot choose to affect only the transmission facilities for which 
they have entered into a contract and cannot claim that they are not 
using or benefiting from such transmission facilities simply because 
they did not enter a contract to use them.'' (quoting Order No. 
1000-A, 139 FERC ] 61,132 at P 561 (cleaned up)).
    \285\ Order No. 1920, 187 FERC ] 61,068 at P 1305.
    \286\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 84 
(reasoning that the text of section 206 does not limit ``cost 
allocation to entities with preexisting commercial relationships,'' 
and instead ``empowers the Commission to fix `any rate' `demanded, 
observed, charged, or collected by any public utility for any 
transmission . . . subject to the jurisdiction of the Commission,' 
and `any . . . practice' `affecting such rate.''').
---------------------------------------------------------------------------

    110. Additionally, the Commission found that Order No. 1920's 
requirements--that transmission providers conduct Long-Term Regional 
Transmission Planning that will ensure the identification, evaluation, 
and selection, as well as the allocation of costs, of more efficient or 
cost-effective regional transmission solutions to address Long-Term 
Transmission Needs--will address the deficiencies in the existing 
regional transmission planning and cost allocation requirements. 
Furthermore, the Commission determined, these requirements will promote 
enhanced reliability and more efficient or cost-effective transmission 
solutions, which will help to ensure just and reasonable rates.\287\ 
The Commission's finding was based on consideration of the record and 
reasonable economic predictions,

[[Page 97197]]

which indicate that long-term, forward-looking, and more comprehensive 
regional transmission planning that identifies Long-Term Transmission 
Needs helps transmission providers to identify, evaluate, and select 
more efficient or cost-effective transmission solutions to meet those 
needs.\288\ These points are especially true considering the 
clarifications we adopt below.
---------------------------------------------------------------------------

    \287\ Order No. 1920, 187 FERC ] 61,068 at P 134.
    \288\ Id. PP 135-138 (citing ACEG NOPR Initial Comments 53-56; 
Brattle-Grid Strategies Oct. 2021 Report at 7 & nn.13-14; Clean 
Energy Associations NOPR Initial Comments at 25-27; Exelon NOPR 
Initial Comments 5; ITC NOPR Initial Comments at 44; MISO NOPR 
Initial Comments at 88; MTEP2017 Review at 6, 8; New Jersey 
Commission NOPR Initial Comments at 4; PIOs NOPR Initial Comments at 
10, 35; SEIA NOPR Initial Comments 25-26).
---------------------------------------------------------------------------

    111. For instance, the Commission was persuaded by empirical 
evidence demonstrating the success of MISO's Long-Range Transmission 
Plan in delivering more efficient or cost-effective transmission 
solutions.\289\ By addressing public policy, economic, and reliability 
transmission planning needs simultaneously through its MVP category, 
MISO eliminated the need for $300 million in future baseline 
reliability upgrades and provided production cost savings that exceeded 
the entire cost of the portfolio by $10 billion.\290\ The Commission 
noted that the cost savings that MISO experienced were the direct 
product of more comprehensive, longer-term regional transmission 
planning.\291\
---------------------------------------------------------------------------

    \289\ Id. P 135.
    \290\ Id. (MTEP2017 Review at 6).
    \291\ Id. P 136.
---------------------------------------------------------------------------

    112. The Commission also made several reasonable economic 
predictions regarding the effects of Order No. 1920. It was, for 
instance, reasonable for the Commission to predict that the 
transmission planning reforms adopted in Order No. 1920, which bear 
many similarities to MISO's MVP process, will have similar results and 
that longer-term regional transmission planning that considers a wider 
array of relevant factors will yield a more efficient or cost-effective 
selection of regional transmission facilities to meet Long-Term 
Transmission Needs, thus saving customers money.\292\ The Commission 
reasonably concluded, and we continue to find, that forgoing this type 
of planning and requiring customers to bear the costs of relatively 
inefficient and less cost-effective transmission development results in 
unjust and unreasonable Commission-jurisdictional rates.\293\
---------------------------------------------------------------------------

    \292\ See id.
    \293\ Id. P 112.
---------------------------------------------------------------------------

    113. We understand concerns raised by Arizona Commission and 
Industrial Customers that Order No. 1920 fails to protect consumers and 
will impose substantial costs on ratepayers.\294\ However, in Order No. 
1920, the Commission found that the existing approach to regional 
transmission planning is resulting in customers paying more than 
necessary or appropriate to meet their transmission needs, forgoing 
benefits that outweigh their costs, or some combination thereof.\295\ 
Thus, the Commission adopted reforms in Order No. 1920 that are 
necessary to ensure that regional transmission planning processes 
identify, evaluate, and select regional transmission facilities that 
can more efficiently or cost-effectively meet Long-Term Transmission 
Needs, so that customers do not continue to pay for relatively 
inefficient or less cost-effective transmission development.\296\ 
Addressing costs to ratepayers was central to the reforms that the 
Commission adopted in Order No. 1920, and the Commission cited evidence 
that more comprehensive, longer-term regional transmission planning 
results in significant cost saving for customers.\297\ Further, we 
disagree with Industrial Customers' argument that Order No. 1920 
states, without ``evidence, proof, or data,'' that its reforms ``should 
provide cost savings.'' \298\ As discussed above, the Commission cited 
robust and diverse evidence to support its finding that the type of 
regional transmission planning required by the final rule will likely 
result in cost savings to customers relative to the status quo 
approach.\299\ Nonetheless, we believe the clarifications adopted 
herein will alleviate Industrial Customers' concerns.
---------------------------------------------------------------------------

    \294\ See Arizona Commission Rehearing Request at 20-21; 
Industrial Customers Rehearing Request at 19-20.
    \295\ Order No. 1920, 187 FERC ] 61,068 at P 117.
    \296\ Id. P 113; see also id. P 136 (``[R]egional transmission 
planning and cost allocation reforms [adopted in Order No. 1920] 
will benefit customers by leading to more efficient or cost-
effective transmission investment, thereby helping to ensure just 
and reasonable rates.'' (citations omitted)).
    \297\ E.g., Id. P 135 (citing MTEP2017 Review at 6).
    \298\ Industrial Customers Rehearing Request at 20 (emphasis in 
original).
    \299\ See supra The Commission Adequately Supported Its 
Determination on Step One of Section 206 section; see also Order No. 
1920, 187 FERC ] 61,068 at P 135 & n.346 (citing a projection that 
proactive, portfolio-based transmission planning in PJM could 
ultimately save ratepayers over $30 billion compared to the status 
quo).
---------------------------------------------------------------------------

    114. We also recognize Arizona Commission's argument that the 
``several factors'' that Order No. 1920 requires transmission providers 
to ``consider[ ] in transmission planning and cost allocation'' should 
have included fairness or reasonableness of cost or consideration of 
who caused the cost.\300\ We believe these factors are appropriately 
accounted for in other stages of the regional transmission planning and 
cost allocation process. For example, the evaluation process considers 
reasonableness of costs by considering cost estimates for, as well as 
the benefits of, identified Long-Term Regional Transmission 
Facilities.\301\ The cost allocation process also considers fairness 
and cost causation, as ``transmission customers within a transmission 
planning region need only pay costs that are `roughly commensurate' 
with the benefits that transmission providers estimate they will 
receive from a regional transmission facility.'' \302\ However, we 
believe certain clarifications adopted herein will address the concerns 
underlying Arizona Commission's argument.
---------------------------------------------------------------------------

    \300\ Arizona Commission Rehearing Request at 21.
    \301\ Order No. 1920, 187 FERC ] 61,068 at PP 955, 958.
    \302\ Id. P 267; see BNP Paribas Energy Trading GP v. FERC, 743 
F.3d 264, 268-69 (D.C. Cir. 2014) (``[T]he cost causation principle 
itself manifests a kind of equity.'').
---------------------------------------------------------------------------

D. The Commission's Section 206 Findings Were Not Circular

1. Requests for Rehearing
    115. Industrial Customers and SERTP Sponsors argue that the 
Commission's findings under the two prongs of section 206 are 
circular.\303\ According to Industrial Customers, rather than cite 
specific record evidence or specify the problems that the Commission 
seeks to address, the Commission relies on the benefits of Order No. 
1920's remedy--e.g., longer-term, more comprehensive regional 
transmission planning--to support its threshold finding under the first 
prong of FPA section 206.\304\ Industrial Customers thus assert that 
Order No. 1920 relies on ``circular reasoning,'' whereby the Commission 
develops a desired solution and then finds that the current absence of 
that desired solution renders the status quo unjust and 
unreasonable.\305\ This approach, Industrial Customers contend, does 
not reflect reasoned decision making.\306\ Further, Industrial 
Customers argue that proceeding in this fashion exceeds the 
Commission's authority under the FPA and could allow the Commission to 
``essentially legislate to achieve any desired

[[Page 97198]]

outcome.'' \307\ Industrial Customers assert that the D.C. Circuit has 
previously determined that the Commission failed to meet its section 
206 burden and therefore committed error by ``beg[inning] with the 
remedy to show that the status quo is not just and reasonable.'' \308\
---------------------------------------------------------------------------

    \303\ Industrial Customers Rehearing Request at 13-15; SERTP 
Sponsors Rehearing Request at 29-32, 34-35.
    \304\ Industrial Customers Rehearing Request at 13.
    \305\ Id. at 14.
    \306\ Id. at 15.
    \307\ Id. at 14.
    \308\ Id. at 15 (citing Emera Me. v. FERC, 854 F.3d 9, 22, 25 
(D.C. Cir. 2017)).
---------------------------------------------------------------------------

    116. SERTP Sponsors claim that Order No. 1920's broad conclusion 
that the regional transmission planning processes conducted by all 
transmission providers in each transmission planning region are unjust, 
unreasonable, unduly discriminatory, and preferential is based on the 
absence of the unique form of long-term regional transmission planning 
that meets the Commission's current view of what a regional 
transmission planning process should be.\309\ SERTP Sponsors also 
contend that Order No. 1920 assumes that all regions follow the same 
generic approach and, while the Commission's pro forma transmission 
planning requirements may be subject to improvement, the Commission has 
not satisfied its burden of showing that the SERTP regional 
transmission planning process is unjust and unreasonable.\310\
---------------------------------------------------------------------------

    \309\ SERTP Sponsors Rehearing Request at 30.
    \310\ Id. at 31-32.
---------------------------------------------------------------------------

    117. SERTP Sponsors assert that Order No. 1920 imposes its 
preferred solution in line with the Commission's vision instead of 
addressing a real need for reform specific to the SERTP regional 
transmission planning process, thereby imposing a ``solution in search 
of a problem.'' \311\ SERTP Sponsors argue that, in doing so, the 
Commission misapplied section 206 by collapsing the two-step standard 
into one step, echoing the mistake described in Emera Maine.\312\ SERTP 
Sponsors contend that Order No. 1920 does not demonstrate widespread 
failures in transmission planning practices, but rather theorizes 
potential inadequacies in meeting the Commission's desired 
outcomes.\313\ SERTP Sponsors aver that Order No. 1920's discussion of 
the growing need for transmission investments and perceived 
insufficiencies of current planning standards does not prove that 
existing processes fail to meet the evolving demands of the electric 
grid.\314\ SERTP Sponsors allege that the SERTP process has been highly 
efficient, and that its integrated resource plan and request for 
proposal-driven transmission planning and other similar processes 
effectively address the Commission's concerns regarding siloed 
planning, lack of scenario planning, and local versus regional project 
focus.\315\
---------------------------------------------------------------------------

    \311\ Id. at 30.
    \312\ Id. (citing Emera Me., 854 F.3d at 22-26).
    \313\ Id. at 34.
    \314\ Id.
    \315\ Id. at 32.
---------------------------------------------------------------------------

    118. SERTP Sponsors argue that Order No. 1920 incorrectly 
characterizes SERTP's and other similar transmission planning regions' 
transmission planning processes as deficient due to the absence of 
alternative regional transmission facilities selected since the 
implementation of Order No. 1000.\316\ SERTP Sponsors contend that the 
fact that no regional transmission projects have been selected 
underscores the success of existing integrated resource plan/request 
for proposal-driven planning systems rather than a failure or 
deficiency in the regional transmission planning process.\317\ SERTP 
Sponsors also contend that the success of the Southeast's process has 
been confirmed by the absence of a National Interest Electric 
Transmission Corridor (NIETC) designation in the Southeast.\318\ SERTP 
Sponsors state that Order No. 1920's attempt to characterize this 
success as a deficiency collapses the first and second steps of section 
206 in the way that the courts have struck down in the past and means 
that this aspect of the order is unsupported by substantial evidence 
and is otherwise arbitrary and capricious.\319\
---------------------------------------------------------------------------

    \316\ Id. at 35.
    \317\ Id.
    \318\ Id. at 35-36 (citation omitted).
    \319\ Id. at 36 & n.104 (citations omitted).
---------------------------------------------------------------------------

2. Commission Determination
    119. We conclude that the Commission's section 206 findings, 
identifying specific deficiencies in regional transmission planning and 
cost allocation requirements at prong one and establishing specific new 
requirements at prong two, are--as they are required to be--closely 
related, in contrast to rehearing parties' arguments. Industrial 
Customers and SERTP Sponsors' arguments on this point \320\ both rely 
on Emera Maine, in which the D.C. Circuit found that the Commission 
erred in basing its determination that the utility's existing 11.14% 
base return on equity (ROE) was unjust and unreasonable because it 
exceeded the 10.57% ROE that the Commission had concluded was the just 
and reasonable base ROE.\321\ The court explained that the Commission 
must first determine that an existing rate is unjust and unreasonable 
(prong one) before it imposes a replacement rate (prong two).\322\ 
Industrial Customers and SERTP Sponsors argue that, like the 
Commission's error in Emera Maine, Order No. 1920 based its finding 
that the status quo is unjust and unreasonable on the absence of the 
Commission's specific desired replacement.\323\
---------------------------------------------------------------------------

    \320\ Industrial Customers Rehearing Request at 15 (citing Emera 
Maine, 854 F.3d at 9, 22, 25); SERTP Sponsors Rehearing Request at 
30 (citing the same).
    \321\ Emera Maine, 854 F.3d at 25-26.
    \322\ Id. at 25-26.
    \323\ Industrial Customers Rehearing Request at 15; SERTP 
Sponsors Rehearing Request at 30.
---------------------------------------------------------------------------

    120. When acting under section 206, the Commission must make two 
findings: (1) that the existing rate, or a practice affecting a rate, 
is unjust, unreasonable, or unduly discriminatory or preferential; and 
(2) that the Commission's replacement rate, or practice affecting a 
rate, is just and reasonable and not unduly discriminatory or 
preferential.\324\ As discussed above, the Commission appropriately 
made both findings in Order No. 1920, so Emera Maine is inapposite.
---------------------------------------------------------------------------

    \324\ 16 U.S.C. 824e(a), (b); Pub. Serv. Elec. & Gas Co. v. 
FERC, 989 F.3d at 13.
---------------------------------------------------------------------------

    121. The Commission's findings under the first prong of section 206 
do not rely on the specific replacement rate that it created in Order 
No. 1920. Rather, the Commission's findings under the first prong of 
section 206 rest on deficiencies, identified based on substantial 
record evidence, in existing regional transmission planning and cost 
allocation requirements, specifically that they are insufficiently 
long-term, forward-looking, and comprehensive. The fact that there is a 
relationship between the deficiencies identified in prong one and the 
new requirements established as the just and reasonable replacement 
under prong two of FPA section 206 demonstrates that the replacement 
regional transmission planning and cost allocation requirements are 
appropriately tailored toward remedying the deficiencies that the 
Commission identified in existing regional transmission planning and 
cost allocation requirements.
    122. Order No. 1920 made explicit findings that the Commission's 
existing regional transmission planning and cost allocation 
requirements are unjust, unreasonable, and unduly discriminatory or 
preferential in several respects.\325\ First, with regard to long-term 
regional transmission planning, the Commission noted that most 
transmission planning regions do not plan beyond a 10-year time 
horizon.\326\

[[Page 97199]]

The Commission's finding that a 10-year transmission planning horizon 
is insufficient does not rely on the Commission's finding that 20 years 
is the just and reasonable time horizon for Long-Term Regional 
Transmission Planning. The reasoning underlying the finding that a 10-
year transmission planning horizon is insufficient would hold true even 
if the Commission had determined a different number (e.g., 17 or 25 or 
31 years) was the just and reasonable replacement. This result is in 
stark contrast to Emera Maine, where the Commission's finding that the 
existing base ROE was unjust and unreasonable rested entirely on the 
finding that it did not equal the Commission's replacement ROE.\327\ 
Second, the Commission found, based on substantial evidence, that 
existing regional transmission planning and cost allocation 
requirements fail to require transmission providers to adequately 
account for known determinants of Long Term Transmission Needs.\328\ 
Third, the Commission found, also based on substantial evidence, that 
the Commission's regional transmission planning and cost allocation 
requirements fail to require transmission providers to adequately 
consider a sufficiently broad and standard set of benefits of regional 
transmission facilities.\329\ These findings are not based on the 
precise list of determinants or benefits that the Commission identified 
in establishing the replacement under of the second prong under FPA 
section 206, but rather on the conclusion that most transmission 
providers focus too narrowly on only some determinants and benefits, 
ignoring other relevant factors, which leads to relatively inefficient 
or less cost-effective transmission development.\330\ Lastly, the 
Commission's findings that existing cost allocation requirements are 
deficient relied on the fact that the Commission's previous cost 
allocation requirements were tailored to the Order No. 1000 regional 
transmission planning requirements, but Order No. 1920's new 
requirements for Long-Term Regional Transmission Planning account for 
multiple drivers of Long-Term Transmission Needs and result in Long-
Term Regional Transmission Facilities that produce a broader set of 
benefits, and therefore warrant a different approach to cost allocation 
for such transmission facilities.\331\
---------------------------------------------------------------------------

    \325\ See supra Unjust, Unreasonable, and Unduly Discriminatory 
or Preferential Commission-Jurisdictional Transmission Planning and 
Cost Allocation Processes section.
    \326\ Order No. 1920, 187 FERC ] 61,068 at P 115; see supra 
Unjust, Unreasonable, and Unduly Discriminatory or Preferential 
Commission-Jurisdictional Transmission Planning and Cost Allocation 
Processes section.
    \327\ Emera Maine, 854 F.3d at 22.
    \328\ Order No. 1920, 187 FERC ] 61,068 at P 118; see supra 
Unjust, Unreasonable, and Unduly Discriminatory or Preferential 
Commission-Jurisdictional Transmission Planning and Cost Allocation 
Processes section.
    \329\ Order No. 1920, 187 FERC ] 61,068 at P 122; see supra 
Unjust, Unreasonable, and Unduly Discriminatory or Preferential 
Commission-Jurisdictional Transmission Planning and Cost Allocation 
Processes section.
    \330\ Order No. 1920, 187 FERC ] 61,068 at PP 122-123.
    \331\ Id. PP 124-126; see supra Unjust, Unreasonable, and Unduly 
Discriminatory or Preferential Commission-Jurisdictional 
Transmission Planning and Cost Allocation Processes section.
---------------------------------------------------------------------------

    123. We also disagree with SERTP Sponsors' contention that Order 
No. 1920 assumes that all transmission planning regions follow the same 
generic approach.\332\ To the contrary, and as discussed above, Order 
No. 1920 highlights deficiencies in regional transmission planning 
processes around the country.\333\ Moreover, the Commission found that 
its existing regional transmission planning and cost allocation 
requirements are unjust and unreasonable.\334\ While regions vary in 
specific approaches, those approaches are all based on the same 
requirements. It is those requirements that we continue to find are 
unjust and unreasonable given the record before us.
---------------------------------------------------------------------------

    \332\ SERTP Sponsors Rehearing Request at 28, 31-34.
    \333\ See supra Unjust, Unreasonable, and Unduly Discriminatory 
or Preferential Commission-Jurisdictional Transmission Planning and 
Cost Allocation Processes section.
    \334\ Order No. 1920, 187 FERC ] 61,068 at P 114 (``Based on the 
record, including the comments submitted in response to the NOPR, we 
find that there is substantial evidence to support the conclusion 
that deficiencies in the Commission's existing regional transmission 
planning and cost allocation requirements are resulting in 
Commission-jurisdictional rates that are unjust, unreasonable, and 
unduly discriminatory or preferential.'') (emphasis added)).
---------------------------------------------------------------------------

    124. Additionally, although SERTP Sponsors contend that SERTP's 
process is highly efficient,\335\ the Commission is not required to 
make findings with respect to individual transmission owners' 
transmission planning and cost allocation processes to remedy the 
deficiencies that it determined in Order No. 1920 render its existing 
regional transmission planning and cost allocation requirements unjust 
and unreasonable.\336\ We also are not persuaded by SERTP Sponsors' 
argument that the absence of regional transmission facilities selected 
since the implementation of Order No. 1000 necessarily demonstrates the 
success of integrated resource plan/request for proposal-driven 
planning systems instead of a deficiency in regional transmission 
planning processes.\337\ Integrated resource plan/request for proposal-
driven planning systems do not replace the need for effective regional 
transmission planning, as only regional transmission planning ensures 
consideration of more efficient or cost-effective transmission 
facilities across utility footprints. We continue to find that ``the 
absence of sufficiently long-term, forward-looking, and comprehensive 
regional transmission planning processes is resulting in piecemeal 
transmission expansion to address relatively near-term transmission 
needs,'' which results in ``transmission providers undertaking 
investments in relatively inefficient or less cost-effective 
transmission infrastructure, the costs of which are ultimately 
recovered through Commission-jurisdictional rates.'' \338\
---------------------------------------------------------------------------

    \335\ SERTP Sponsors Rehearing Request at 32.
    \336\ See supra The Commission Has the Authority to Conduct a 
Generic Rulemaking section. Moreover, we note that the record 
reflects disagreement on this point. See Order No. 1920, 187 FERC ] 
61,068 at P 56 (``SREA argues that `transmission planning in the 
Southeast has many holes and is threadbare.''); id. P 115 
(``[C]ommenters point out that . . . SERTP . . . plan[s] using a 10-
year transmission planning horizon.''); id. P 333 (``SERTP's 10-year 
transmission planning horizon prevented Georgia Power from using 
that process to plan for its long-term North Georgia Reliability & 
Resilience Plan and its goal to integrate 6,000 MW of renewable 
resources by 2035.''); id. P 709 (``Kentucky Commission Chair 
Chandler argues against SERTP Sponsors' comments that suggest that 
integrated resource plan/request for proposal processes already 
consider four of the proposed categories of benefits . . . [and] 
contends that [those] process[es] can only address these four 
categories on a utility-by-utility basis and, thus, [are] unable to 
plan for transmission facilities across utilities or transmission 
planning regions by nature.'').
    \337\ SERTP Sponsors Rehearing Request at 35.
    \338\ Order No. 1920, 187 FERC ] 61,068 at P 112.
---------------------------------------------------------------------------

IV. Statutory Authority

A. Order No. 1920 Determination

    125. In Order No. 1920, the Commission reaffirmed its conclusion in 
the NOPR that it was acting within its legal authority under FPA 
section 206 by requiring transmission providers to participate in a 
regional transmission planning process that includes Long-Term Regional 
Transmission Planning.\339\ In doing so the Commission found--and noted 
that no commenter disputed--that transmission planning and cost 
allocation processes are practices affecting the rates charged by 
public utilities in connection with the Commission-jurisdictional 
transmission of electric energy in interstate commerce.\340\
---------------------------------------------------------------------------

    \339\ Order No. 1920, 187 FERC ] 61,068 at P 253.
    \340\ Id. (citing 16 U.S.C. 824e; S.C. Pub. Serv. Auth. v. FERC, 
762 F.3d at 55-59; Emera Me. v. FERC, 854 F.3d at 673-74).
---------------------------------------------------------------------------

    126. The Commission disagreed with arguments that the requirements 
adopted in Order No. 1920 infringe on

[[Page 97200]]

the authority reserved to the states by FPA section 201 or are 
otherwise barred by certain prudential or constitutional 
principles.\341\ Noting that it believed that these concerns mainly 
arose from misunderstandings regarding the substance of Order No. 1920, 
the Commission explained that Order No. 1920 builds on more than a 
quarter century of Commission action on transmission planning and cost 
allocation, which courts have affirmed notwithstanding objections 
similar to those presented to Order No. 1920, by addressing specific 
gaps in the existing framework.\342\ It emphasized that Order No. 1920 
``does not regulate, aim at, or otherwise attempt to influence 
integrated resource planning, the generation mix, decisions related to 
the siting and construction of transmission facilities or generation 
resources, or any other matters reserved to states under FPA section 
201.'' \343\ To the contrary, Order No. 1920 ``directly regulates 
transmission planning and cost allocation processes, . . . directly 
regulates only those practices, and it does not directly regulate any 
matter reserved to the states by FPA section 201.'' \344\ Moreover, 
Order No. 1920 ``is not aiming to indirectly regulate any matter 
reserved to the states by FPA section 201'' but, instead, only to 
improve existing transmission and cost allocation processes to address 
identified deficiencies with those processes.\345\
---------------------------------------------------------------------------

    \341\ Id. P 254.
    \342\ Id. PP 254-256.
    \343\ Id. P 254; see also id. P 257 (``[T]his rule does not 
mandate development of any particular transmission facility.''); id. 
P 258 (``[T]his final rule does not authorize or require any entity 
to adopt a particular siting plan for Long-Term Regional 
Transmission Facilities that transmission providers select; or to 
forego state-jurisdictional siting proceedings where they are 
necessary; or to begin construction on such Long-Term Regional 
Transmission Facilities.''); id. P 259 (explaining that Order No. 
1920 ``does not change existing mechanisms for cost-recovery through 
retail rates; authorize or require states or state commissions to 
change the laws or regulations that govern the conduct of integrated 
resource planning or request for proposal processes; authorize or 
require transmission providers or transmission developers to bypass 
any applicable state-regulated integrated resource planning or 
request for proposal processes; or authorize or require states or 
public utilities to adopt a different mix of generation 
resources''); id. P 266.
    \344\ Id. P 263.
    \345\ Id.; see also id. P 265 (``[T]his final rule aims to 
regulate and, in fact, does regulate only practices that affect the 
transmission of electric energy in interstate commerce, which are 
squarely within the Commission's jurisdiction under the FPA.'').
---------------------------------------------------------------------------

    127. The Commission explained that these considerations confirmed 
that Order No. 1920 was well within its authority under the FPA, 
particularly in light of U.S. Supreme Court precedent in EPSA.\346\ 
Applying that decision, the Commission stated that ``what matters is 
that this final rule aims to regulate and, in fact, does regulate only 
practices that affect the transmission of electric energy in interstate 
commerce, which are squarely within the Commission's jurisdiction under 
the FPA.'' \347\ In Order No. 1920, the Commission ``aim[ed] to improve 
Commission-regulated transmission planning processes, in this instance 
by ensuring that they are sufficiently long-term, forward-looking, and 
comprehensive such that they are capable of identifying and meeting 
Long-Term Transmission Needs.'' \348\ Likewise, and consistent with 
EPSA, the Commission found that every aspect of Order No. 1920 
``happens exclusively as part of a process that is subject to the 
Commission's jurisdiction and governs exclusively how those processes 
work.'' \349\ The Commission further explained that Order No. 1920 does 
not require that transmission providers achieve any particular 
substantive outcome of the transmission planning process, aim to alter 
states' or the nation's generation mix, or otherwise regulate matters 
within state jurisdiction.\350\
---------------------------------------------------------------------------

    \346\ See id. PP 264-266.
    \347\ Id. P 265.
    \348\ Id.
    \349\ Id. P 266 (quotation marks omitted).
    \350\ Id.; cf. id. P 267 (also rejecting arguments that Order 
No. 1920 required states to subsidize other state's public policies, 
explaining that Order No. 1920 required following long-extant 
precedent that transmission customers need only pay costs that are 
``roughly commensurate'' with the benefits received from a regional 
transmission facility).
---------------------------------------------------------------------------

    128. The Commission further explained that, applying EPSA, Order 
No. 1920 was within its jurisdiction to regulate the practices 
affecting the rates for the transmission of electric energy in 
interstate commerce, notwithstanding that the rule might have effects 
on matters reserved to state jurisdiction under FPA section 201.\351\ 
The Commission explained that such effects are inevitable--a ``fact of 
economic life'' as the Supreme Court put it--given ``Congress's 
decision in the FPA to divide jurisdiction over the industry, including 
both generation and transmission, into spheres of Commission and state 
jurisdiction that are not `hermetically sealed' from one another.'' 
\352\
---------------------------------------------------------------------------

    \351\ Id. P 264 (explaining that such effects are of ```no legal 
consequence''' (quoting EPSA, 577 U.S. at 281)); see id. P 262 n.612 
(quoting EPSA, 577 U.S. at 281-82 (``When FERC regulates what takes 
place on the wholesale market, as part of carrying out its charge to 
improve how that market runs, then no matter the effect on retail 
rates, [16 U.S.C.] 824(b) imposes no bar.'' (emphasis added))).
    \352\ Id. (quoting EPSA, 577 U.S. at 281); see id. P 272 (``We 
acknowledge that Long-Term Regional Transmission Planning will 
affect matters that are within the states' jurisdiction. As stated, 
this is inevitable.'').
---------------------------------------------------------------------------

    129. The Commission therefore disagreed with arguments that Order 
No. 1920 unlawfully intruded on areas of reserved state authority under 
FPA section 201.\353\ The Commission stated that Long-Term Regional 
Transmission Planning ``necessarily involves taking into account 
assumptions about the generation resources that will be available, 
because transmission needs arise from the relative amounts, locations, 
and timing of supply (i.e., generation) and of demand (i.e., load).'' 
\354\ It stated that the effects of such planning on areas of state 
authority, however, do not divest the Commission of the jurisdiction 
Congress conferred on it to regulate the transmission of electric 
energy in interstate commerce.\355\
---------------------------------------------------------------------------

    \353\ See id. PP 271-274.
    \354\ Id. P 272 (noting also that existing transmission planning 
processes already take these assumptions into account, and that 
Order No. 1920 ``simply modifies the scope and duration of these 
assumptions'' to ensure more effective transmission planning).
    \355\ See id. PP 264, 271-272.
---------------------------------------------------------------------------

    130. The Commission was also not persuaded by arguments that Order 
No. 1920 was unlawful under the ``major questions doctrine.'' \356\ It 
found that commenters were misinterpreting the Supreme Court's decision 
in West Virginia v. EPA as suggesting that, in every instance, agency 
regulations affecting energy policy and the generation mix are ``major 
questions'' requiring direct authorization from Congress.\357\ Rather, 
the Commission stated that the Supreme Court in that decision 
considered a specific United States Environmental Protection Agency 
(EPA) action in light of a particular statutory provision and concluded 
that this action implicated the major questions doctrine based on a 
variety of factors specific to that context.\358\ The Commission noted 
that commenters had not analyzed whether Order No. 1920 would, based on 
the factors the Supreme Court examined, constitute a major question; 
when the Commission

[[Page 97201]]

considered those factors, it concluded that Order No. 1920 would not 
implicate the major questions doctrine.\359\ Among other things, the 
Commission found that Order No. 1920, as an incremental improvement 
building on past regulation, did not represent a transformative 
expansion of the Commission's regulatory authority and did not have 
vast economic or political significance; \360\ did not resemble EPA's 
assertion of authority related to the electric system; \361\ was not 
reliant on a ``backwater'' statutory provision; and was not promulgated 
notwithstanding Congress's repeated rejection of legislation to enact 
reforms similar to those in the rule.\362\
---------------------------------------------------------------------------

    \356\ See id. PP 275-279.
    \357\ Id. PP 275-276.
    \358\ Id. P 276 (noting that these factors ``include[d] whether 
the EPA's administrative action was a `transformative' expansion of 
its power, whether the EPA had relevant technical and policy 
expertise, whether the relevant statutory provision was `ancillary' 
to the broader statutory construct, and whether the EPA's 
administrative action implicated significant economic and political 
questions'' (citing W.V. v. EPA, 597 U.S. 697, 710, 724-25, 729, 
731-32 (2022) (West Virginia)).
    \359\ See id. PP 277-279.
    \360\ See id. PP 277-278.
    \361\ Id. P 279.
    \362\ See id.
---------------------------------------------------------------------------

    131. The Commission also disagreed with arguments that Order No. 
1920 effectively required certain states to subsidize other states' 
vision of what resources should be used in electricity generation and, 
therefore, violated the Constitution's ``equal sovereignty doctrine.'' 
\363\ Here, the Commission again explained that Order No. 1920 
``categorically does not require states to subsidize other states' 
public policies or generation decisions,'' but rather was consistent 
with longstanding cost-causation principles.\364\ Moreover, the 
Commission pointed out that no court has ever applied the equal 
sovereignty doctrine invoked by commenters as a limit on Congress's 
Article I powers, including legislation enacted under the Commerce 
Clause, such as the FPA.\365\
---------------------------------------------------------------------------

    \363\ See id. PP 280-282.
    \364\ Id. P 280.
    \365\ See id. P 281 (noting that the FPA, in turn, ``empowers 
the Commission to regulate the rates and practices affecting rates 
for the transmission of electricity in interstate commerce'').
---------------------------------------------------------------------------

B. Federal/State Division of Authority

1. Requests for Rehearing
    132. Several of the requests for rehearing argue that Order No. 
1920 exceeds the Commission's statutory authority under FPA section 206 
and is, therefore, unlawful.\366\ Many of these requests for rehearing 
acknowledge the Commission's authority under the FPA over ``the 
transmission of electric energy in interstate commerce and . . . the 
sale of electric energy at wholesale in interstate commerce.'' \367\ 
However, rehearing parties argue that the Commission's jurisdiction 
``extend[s] only to those matters which are not subject to regulation 
by the States'' and that the Commission, with certain exceptions, 
``shall not have jurisdiction . . . over facilities used for the 
generation of electric energy or over facilities used in local 
distribution or only for the transmission of electric energy in 
intrastate commerce.'' \368\ Undersigned States and Designated Retail 
Regulators also state that FPA section 215(i)(3) reserves jurisdiction 
to the states over the ``safety, adequacy, and reliability of electric 
service.'' \369\ Designated Retail Regulators aver that the 
Commission's authority is limited by the National Interest Electric 
Transmission Corridor process.\370\
---------------------------------------------------------------------------

    \366\ See Undersigned States Rehearing Request at 2-3, 6, 10-13, 
17; Designated Retail Regulators at 2-3, 6, 11-15, 18; Alabama 
Commission Rehearing Request at 5; Georgia Commission Rehearing 
Request at 3-4; Arizona Commission Rehearing Request at 2, 9-12, 15; 
Idaho Commission Rehearing Request at 2, 4-5; Montana Commission 
Rehearing Request at 1-4; Wyoming Commission Rehearing Request at 1-
4; Utah Commission Rehearing Request at 1, 3-7; West Virginia 
Commission Rehearing Request at 3-4, 10-12.
    \367\ 16 U.S.C. 824(b)(1); see also 16 U.S.C. 824d(a), 824e(a); 
Undersigned States Rehearing Request at 10-11 (arguing that the FPA 
is ``primarily, and perhaps exclusively, an economic regulation 
statute''); Designated Retail Regulators at 12 (same); Alabama 
Commission Rehearing Request at 5; Arizona Commission Rehearing 
Request at 10; Utah Commission Rehearing Request at 3.
    \368\ 16 U.S.C. 824(a), (b)(1); see Undersigned States Rehearing 
Request at 11; Designated Retail Regulators at 12-13; Alabama 
Commission Rehearing Request at 5 (asserting that the Commission's 
jurisdiction does not extend to ``electric power generation, 
transmission siting, distribution, retail supply, and service 
models,'' including ``oversight of the IRP process and the 
associated selection of resources to provide reliable retail 
service''); Arizona Commission Rehearing Request at 10-11; Idaho 
Commission Rehearing Request at 4; Montana Commission Rehearing 
Request at 2-3.
    \369\ 16 U.S.C. 824o(i)(3); Undersigned States Rehearing Request 
at 11; Designated Retail Regulators Rehearing Request at 13.
    \370\ Designated Retail Regulators Rehearing Request at 18-19 
(citing 16 U.S.C. 824p).
---------------------------------------------------------------------------

    133. Several rehearing requests posit that Order No. 1920 exceeds 
the Commission's authority because it invades or undermines state 
authority over the choice of generating resources maintained or 
constructed within each state's jurisdiction.\371\ Undersigned States 
and Designated Retail Regulators argue that Order No. 1920 ``puts into 
place planning processes that will favor renewables over other 
generation and ignore the combined generation/transmission benefits 
that other solutions could provide.'' \372\ They argue that this will 
result in ``shift[ing] costs to deliver those renewables to customers 
that do not cause those costs to be incurred and that have selected 
other generation options with different transmission requirements.'' 
\373\ In this vein, Undersigned States and Designated Retail Regulators 
assert that ``[r]equiring customers in states to pay for infrastructure 
to support the public policies and generation resource mixes chosen by 
other states, without demonstrable benefits to that load, would be a 
major intrusion on the States' right to choose the resources that best 
fit their public policies.'' \374\
---------------------------------------------------------------------------

    \371\ See Undersigned States Rehearing Request at 11-13 (citing 
Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. 
Comm'n, 461 U.S. 190, 212 (1983); Nw. Cent. Pipeline Corp. v. State 
Corp. Comm'n of Kan., 489 U.S. 493, 522 (1989); Monongahela Power 
Co., 40 FERC ] 61,256, at 61,861 (1987); Calpine Corp. v. PJM 
Interconnection, L.L.C., 171 FERC ] 61,035 (2020) (Glick, Comm'r, 
dissenting at P 5)); Designated Retail Regulators Rehearing Request 
at 13-14; Idaho Commission Rehearing Request at 4; Utah Commission 
Rehearing Request at 3-5; West Virginia Commission Rehearing Request 
at 11; Arizona Commission Rehearing Request at 10-11; cf. id. at 2-3 
(```The states have traditionally assumed all jurisdiction to 
approve or deny permits for the siting and construction of electric 
transmission facilities.''' (quoting Piedmont Envt'l Council v. 
FERC, 558 F.3d 304, 310 (4th Cir. 2009)).
    \372\ Undersigned States Rehearing Request at 13; Designated 
Retail Regulators Rehearing Request at 14-15; see also Undersigned 
States Rehearing Request at 3-4 (arguing that Order No. 1920's 
``building-block concepts (`Sufficiently long-term,' `Long-Term 
Transmission Needs,' `known determinants of Long-Term Transmission 
Needs,' the `broader set of benefits,' and particularly, the inputs 
to this elaborate scheme) mandate new planning processes for 
transmission facilities that are designed to (1) move remote 
renewables over long distances and (2) socialize their costs''); id. 
at 27-29; Designated Retail Regulators Rehearing Request at 3-4, 27-
28 (similar).
    \373\ Undersigned States Rehearing Request at 13; Designated 
Retail Regulators Rehearing Request at 14-15; see also Undersigned 
States Rehearing Request at 33-34.
    \374\ Undersigned States Rehearing Request at 12-13; Designated 
Retail Regulators Rehearing Request at 14; see also id. at 38 
(``FERC has no statutory authority to pick winners and losers among 
differing types of generation or use the cost allocation process as 
an alternative means to dilute financial responsibility for policy 
decisions.'').
---------------------------------------------------------------------------

    134. Many of the other arguments challenging the Commission's 
statutory authority proceed along similar lines. Alabama Commission 
argues that the Commission in Order No. 1920 is ``putting a `thumb on 
the scale' and intruding on resource selection in Alabama.'' \375\ 
Georgia Commission contends that in Order No. 1920 the Commission is 
acting as a national integrated resource planner, attempting to change 
the future generation mix,\376\ and will require states to subsidize 
the renewable generation policies of other states.\377\ Arizona 
Commission argues that the Commission lacks ``jurisdiction to impose 
mandated energy policies for intrastate distribution or to foist costs 
on rate payers for costs created in other

[[Page 97202]]

states.'' \378\ Idaho Commission asserts that certain of the categories 
of factors that transmission providers must consider in developing 
Long-Term Scenarios will ``disproportionately favor certain projects in 
the planning process, provide disparate treatment to states' policy 
goals, affect resource planning and selection at the state level, and 
infringe on states' authority with respect to generation.'' \379\ 
Montana Commission, Wyoming Commission, and West Virginia Commission 
argue that, absent a voluntary State Agreement Process, the cost 
allocation approach in Order No. 1920 ensures that nonconsenting states 
will be swept up in their neighbors' preferred policy projects, 
invading the jurisdiction of states.\380\ Utah Commission argues that 
the Commission stated its intention in the ANOPR and NOPR to unlawfully 
influence the generation mix.\381\ It claims that Order No. 1920 
``effectively rigs the planning and cost allocation process to ensure 
(i) FERC's preferred stakeholders' projects are selected in the 
planning process and (ii) these preferred stakeholders are not required 
to bear the full costs associated with their choices.'' \382\
---------------------------------------------------------------------------

    \375\ Alabama Commission Rehearing Request at 5.
    \376\ Georgia Commission Rehearing Request at 3-4 (arguing that 
Order No. 1920 violates states' reserved decision-making power by 
requiring that they ``measure their long-term transmission plans 
against seven factors identified in the Order,'' because these 
factors allegedly favor certain policies and projects).
    \377\ Id. at 5-6.
    \378\ Arizona Commission Rehearing Request at 11-12 (citing Fed. 
Power Comm'n v. S. Cal. Edison Co., 376 U.S. 205, 210 (1964), for 
the proposition that Congress intended to draw an easily ascertained 
bright line between state and federal jurisdiction); id. at 13; cf. 
id. at 6-7 (arguing that ``nothing in federal jurisprudence or the 
FPA allows FERC to usurp these traditional state functions of 
intrastate transmission and balancing such energy source costs with 
ratepayer fairness'').
    \379\ Idaho Commission Rehearing Request at 4-5.
    \380\ Montana Commission Rehearing Request at 2-4 (citing EPSA, 
577 U.S. at 295-96; Pac. Gas & Elec. Co., 461 U.S. at 212; S.C. Pub. 
Serv. Auth. v. FERC, 762 F.3d at 56-59; Wyoming Commission Rehearing 
Request at 2-4 (similar); West Virginia Commission Rehearing Request 
at 3-4, 10-12 (similar, also arguing that ``[w]ithout a meaningful 
voluntary state agreement process, the Commission erred by exceeding 
its jurisdiction and interfering with state decisions about 
generation resource planning and approval'').
    \381\ Utah Commission Rehearing Request at 4-5.
    \382\ Id. at 5-6 (arguing that Order No. 1920 ``precludes 
transmission planners and cost allocation from distinguishing 
between transmission projects that are necessary to resolve an 
identified reliability or economic concern from those that are only 
necessary because some state, local government, or corporation has 
unilaterally adopted a policy''); see id. at 8 (``[T]he FPA gives 
FERC no authority to regulate electricity generation and 
specifically reserves that power to the states.'').
---------------------------------------------------------------------------

2. Commission Determination
    135. We appreciate these concerns articulated on rehearing and 
believe several clarifications that we adopt below will alleviate these 
concerns. Nonetheless, we sustain the Commission's determination that 
Order No. 1920 is a valid exercise of our statutory authority under the 
FPA and does not unlawfully intrude into areas of reserved state 
authority.\383\ In arguing to the contrary, the rehearing requests fail 
to meaningfully address the substance of Order No. 1920 and fail to 
respond to the Commission's explanation for why that rule falls within 
its jurisdiction. Instead, they misconstrue that rule as attempting to 
control or influence the generation mix in favor of allegedly 
Commission-preferred resources.\384\ Moreover, the arguments on 
rehearing are unjustified as a legal matter as they fail to apply EPSA 
to Order No. 1920 (and in many cases, do not even acknowledge this 
controlling precedent).\385\ They also depend on the mistaken view that 
the policies of one state may not have permissible extraterritorial 
effects on other states through interstate commerce, including in the 
context of interstate transmission of electricity as regulated under 
the FPA.\386\
---------------------------------------------------------------------------

    \383\ Order No. 1920, 187 FERC ] 61,068 at PP 253-54.
    \384\ See, e.g., Undersigned States Rehearing Request at 3-4, 
12-13; Designated Retail Regulators Rehearing Request at 11-15; 
Georgia Commission Rehearing Request at 3-4; Idaho Commission 
Rehearing Request at 2, 4-5; Alabama Commission Rehearing Request at 
5; Arizona Commission Rehearing Request at 2, 11-12, 15; Montana 
Commission Rehearing Request at 3-4; Wyoming Commission Rehearing 
Request at 3-4; West Virginia Commission Rehearing Request at 12; 
Utah Commission Rehearing Request at 1, 3-7.
    \385\ See Designated Retail Regulators Rehearing Request at 3-4, 
6, 11-15 (no citation of EPSA); Georgia Commission Rehearing Request 
at 3-4 (same); Idaho Commission Rehearing Request at 2, 4-5 (same); 
Arizona Commission Rehearing Request at 2, 9-12, 15 (same); Alabama 
Commission Rehearing Request at 5 (same); Utah Commission Rehearing 
Request at 1, 3-7; Undersigned States Rehearing Request at 14 
(citing EPSA as recognizing the steady flow of jurisdictional 
disputes under the FPA); Montana Commission Rehearing Request at 3 
(citing EPSA as establishing that ``FERC regulation of 
jurisdictional subject matters (wholesale sales and transmission) 
may influence matters within the states' power to regulate''); 
Wyoming Commission Rehearing Request at 2-3 (same); West Virginia 
Commission Rehearing Request at 11 (same).
    \386\ See, e.g., Undersigned States Rehearing Request at 12-13; 
Designated Retail Regulators Rehearing Request at 11, 14; Utah 
Commission Rehearing Request at 12; West Virginia Commission 
Rehearing Request at 12; see also infra Order No. 1920 Does Not 
Require Unlawful Subsidization of State Policies section.
---------------------------------------------------------------------------

a. Order No. 1920 Does Not Attempt To Control the Generation Mix or 
Intrude in Areas of State Authority
    136. We begin our discussion of the Commission's statutory 
authority to issue Order No. 1920 with the substance of Order No. 1920. 
In broad strokes, Order No. 1920 required transmission providers to 
``(1) perform a sufficiently long-term assessment of transmission needs 
that identifies Long-Term Transmission Needs; (2) adequately account on 
a forward-looking basis for known determinants of Long-Term 
Transmission Needs; and (3) consider the broader set of benefits of 
regional transmission facilities planned to meet those Long-Term 
Transmission Needs.'' \387\ As affirmed by the D.C. Circuit, regional 
transmission planning and cost allocation processes are practices 
directly affecting rates subject to the Commission's sole jurisdiction, 
as transmission providers ``use those processes to `determine which 
transmission facilities will more efficiently or cost-effectively meet' 
transmission needs.'' \388\
---------------------------------------------------------------------------

    \387\ Order No. 1920, 187 FERC ] 61,068 at P 1; see also id. PP 
224-248.
    \388\ Id. P 86 (quoting S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 56); id. (``[T]hese processes identify, evaluate, and select the 
regional transmission facilities whose costs will be recovered 
through transmission rates . . . .'').
---------------------------------------------------------------------------

    137. In light of the direct effects that transmission planning 
processes have on Commission-jurisdictional rates, ``the Commission has 
taken multiple significant actions on transmission planning and cost 
allocation, including issuing Order Nos. 888, 890, and 1000.'' \389\ 
Order No. 1920 thus does not stand in a vacuum, but rather ``build[s] 
upon more than a quarter century of significant actions taken by the 
Commission on transmission planning and cost allocation,'' \390\ 
particularly by addressing specific gaps in the existing regional 
transmission planning process set forth in Order No. 1000.\391\
---------------------------------------------------------------------------

    \389\ Id. P 14; see also id. PP 15-19 (describing the reforms in 
Order No. 1000).
    \390\ Id. P 255.
    \391\ Id. P 256; see also id. PP 257-259 (describing how Order 
No. 1920 is consistent with the approach in Order No. 1000, 
including in that Order No. 1920 does not mandate the development of 
particular transmission facilities, intrude on siting processes for 
transmission facilities, or change existing mechanisms for cost 
recovery); id. P 266.
---------------------------------------------------------------------------

    138. Order No. 1920 required transmission providers to conduct 
Long-Term Regional Transmission Planning to identify Long-Term 
Transmission Needs, identify transmission facilities that meet such 
needs, measure the benefits of those transmission facilities, and 
evaluate those transmission facilities for potential selection in the 
regional transmission plan for purposes of cost allocation.\392\ To 
identify these Long-Term Transmissions Needs and transmission 
facilities that meet such needs, transmission providers must develop a 
set of at least three plausible and diverse Long-Term Scenarios, using 
the best available data inputs about the future electric power system, 
over a transmission planning horizon of no less than 20 years.\393\ In 
developing such scenarios, transmission providers

[[Page 97203]]

must consider certain known determinants of transmission needs, which 
the Commission identified in Order No. 1920 as falling within seven 
categories of factors that affect Long-Term Transmission Needs.\394\
---------------------------------------------------------------------------

    \392\ Id. P 38; see also id. PP 1-13, 225.
    \393\ See id. PP 40, 248.
    \394\ See id. PP 248, 387-537.
---------------------------------------------------------------------------

    139. The categories of factors the Commission identified were ``(1) 
federal, federally-recognized Tribal, state, and local laws and 
regulations affecting the resource mix and demand; (2) federal, 
federally-recognized Tribal, state, and local laws and regulations on 
decarbonization and electrification; (3) state-approved integrated 
resource plans and expected supply obligations for load-serving 
entities; (4) trends in fuel costs and in the cost, performance, and 
availability of generation, electric storage resources, and building 
and transportation electrification technologies; (5) resource 
retirements; (6) generator interconnection requests and withdrawals; 
and (7) utility and corporate commitments and federal, federally-
recognized Tribal, state, and local policy goals that affect Long-Term 
Transmission Needs.'' \395\ The Commission identified these categories 
of factors because they provide information about the drivers of Long-
Term Transmission Needs, including changes in reliability needs, 
demand, and supply (such as the generation resource mix) that, in turn, 
affect what transmission facilities will be required going 
forward.\396\ The Commission stated that transmission providers have 
discretion, however, to consider additional factors \397\ and may, in 
developing their Long-Term Scenarios, find that any factor is not, in 
fact, likely to affect Long-Term Transmission Needs.\398\
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    \395\ Id. P 409. As discussed below, we are setting aside the 
requirement in Factor Category Seven to consider corporate 
commitments. See infra Requests to Omit One or More Specific 
Categories of Factors section. That change does not affect our 
conclusion as to the Commission's statutory authority, including our 
response to the arguments on rehearing addressing the federal/state 
division of authority under the FPA.
    \396\ See Order No. 1920, 187 FERC ] 61,068 at PP 90-111, 299-
300, 432, 440, 447, 456, 463, 472, 481.
    \397\ See id. P 412.
    \398\ See id. PP 415, 417.
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    140. Under Order No. 1920, transmission providers must also 
identify and evaluate transmission facilities to meet such Long-Term 
Transmission Needs and for potential selection as Long-Term Regional 
Transmission Facilities in the regional transmission plan for purposes 
of cost allocation.\399\ Here, the Commission required that 
transmission providers measure and use at least seven specified 
benefits as part of that analysis,\400\ which measurement reflects 
``the value that the transmission providers expect a particular Long-
Term Regional Transmission Facility to provide to transmission 
customers in the transmission planning region.'' \401\ The Commission 
provided transmission providers with extensive flexibility in the 
measurement of such benefits.\402\
---------------------------------------------------------------------------

    \399\ See id. PP 1-3, 40, 225, 719-720.
    \400\ See id. P 3; see also id. PP 729, 737.
    \401\ Id. P 269; see also id. P 720 (identifying the benefits to 
be considered).
    \402\ See, e.g., id. PP 728, 735, 839.
---------------------------------------------------------------------------

    141. The Commission also required transmission providers to ``file 
one or more ex ante Long-Term Regional Transmission Cost Allocation 
Methods to allocate the costs of Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) that are selected.'' 
\403\ It provided a process for robust participation by Relevant State 
Entities to seek to reach agreement on a Long-Term Regional 
Transmission Cost Allocation Method(s) and/or a State Agreement 
Process.\404\ However, the Commission found that ``[w]hile we permit 
transmission providers to include a State Agreement Process in their 
OATTs . . . it cannot be the sole method filed for cost allocation for 
Long-Term Regional Transmission Facilities,'' \405\ and required that 
``the relevant Long-Term Regional Transmission Cost Allocation Method 
on file would apply as a backstop.'' \406\
---------------------------------------------------------------------------

    \403\ Id. P 5; see also id. P 43 (defining Long-Term Regional 
Transmission Cost Allocation Method); id. P 1291.
    \404\ See id. PP 5, 1291.
    \405\ Id. P 1292; see id. P 1293 (explaining that, if 
transmission providers were to rely solely on a State Agreement 
Process, this gives rise to the possibility there would be no cost 
allocation method for Long-Term Regional Transmission Facilities 
such that selected facilities would be less likely to be developed 
and their benefits less likely to be realized).
    \406\ Id. P 1292.
---------------------------------------------------------------------------

    142. The bases for the reforms in Order No. 1920 are entirely 
focused on improving Commission-jurisdictional processes. The 
Commission found that existing transmission planning and cost 
allocation processes are inadequate, such that ``transmission providers 
are often not identifying, evaluating, or selecting more efficient or 
cost-effective regional transmission solutions to meet Long-Term 
Transmission Needs.'' \407\ Trends in ``economics, growing demand, and 
federal, federally-recognized Tribal, state, and local policies [that] 
are already resulting in significant changes in the resource mix'' 
\408\ have reinforced that more effective transmission planning ``helps 
to ensure cost-effective transmission development for customers and can 
yield better returns for every dollar spent.'' \409\ In fact, ``in the 
limited instances in which transmission providers have followed 
processes that share many of the elements of the long-term, forward-
looking, and more comprehensive regional transmission planning this 
rule requires, customers have seen clear and quantifiable benefits.'' 
\410\ In issuing Order No. 1920, the Commission was thus acting in a 
responsive capacity to account for observable, large-scale, and 
preexisting trends driven by external forces, which highlighted the 
need for improved transmission planning and cost allocation 
processes.\411\
---------------------------------------------------------------------------

    \407\ Id. P 87.
    \408\ Id. P 99 (noting that ``as of 2021, nearly 70% of capacity 
additions across the country were from new, utility-scale wind and 
solar resources'' whereas most capacity retirements were from coal 
resources, with these trends projected to continue); see also id. PP 
94-98 (discussing trends that shape transmission needs and reflect 
the need for more efficient and cost-effective transmission 
planning).
    \409\ Id. P 100 (``Conversely, inadequate or poorly designed 
transmission planning processes can lead to relatively inefficient 
or less cost-effective transmission investment, with customers 
footing the bill . . . .''); see also, e.g., id. PP 103-06, 121, 
123, 236; cf. id. P 101 (discussing that existing transmission 
planning requirements have ``yielded only limited investments in 
regional transmission projects'').
    \410\ Id. P 102.
    \411\ See, e.g., id. P 129 (``[T]he Commission is reacting to 
well-documented factors, which the record demonstrates are driven by 
exogenous forces beyond the Commission's jurisdiction or control . . 
. .''); id. P 130; id. P 261 (``[T]his final rule responds to 
changes in the electric industry that have arisen in the years since 
the Commission's last regulatory action related to transmission 
planning.'').
---------------------------------------------------------------------------

    143. As this summary reflects,\412\ Order No. 1920 directly 
regulates transmission planning and cost allocation processes, 
effectuating one of the ``core objects'' of the FPA, as identified by 
the Supreme Court: ``ensur[ing] effective transmission of electric 
power.'' \413\ And the parties arguing that Order No. 1920 unlawfully 
intrudes into reserved areas of state authority do not identify any 
aspect of Order No. 1920 that is not, on its face, directed toward 
these Commission-jurisdictional targets.\414\ Rather, they argue that 
Order No. 1920 intrudes on state resource selection because, in 
regulating such transmission planning

[[Page 97204]]

and cost allocation, Order No. 1920 is purportedly biased toward the 
construction of transmission facilities that will serve allegedly 
Commission-favored resources, which will in turn affect the generation 
resource mix.\415\ Here, they focus on the categories of factors that 
the Commission identified as reflecting known determinants of 
transmission needs, arguing that certain of these factors are not 
resource neutral.\416\
---------------------------------------------------------------------------

    \412\ This summary addresses aspects of Order No. 1920 as 
pertinent to the challenges to the Commission's statutory authority 
raised on rehearing.
    \413\ EPSA, 577 U.S. at 290; see also S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d at 57 (``Reforming the practices of failing to engage 
in regional planning and ex ante cost allocation for development of 
new regional transmission facilities . . . involves a core reason 
underlying Congress' instruction in Section 206.'').
    \414\ See Order No. 1920, 187 FERC ] 61,068 at PP 265-66.
    \415\ See Undersigned States Rehearing Request at 13; Designated 
Retail Regulators Rehearing Request at 14; Georgia Commission 
Rehearing Request at 3-4; Arizona Commission Rehearing Request at 9-
12, 15; Idaho Commission Rehearing Request at 4-5; Utah Commission 
Rehearing Request at 4-5; Montana Commission Rehearing Request at 3-
4; West Virginia Commission Rehearing Request at 12; Wyoming 
Commission Rehearing Request at 3-4; Alabama Commission Rehearing 
Request at 5; cf. Ohio Commission Federal Advocate Rehearing Request 
at 18-20 (asserting that, in doing so, the Commission is violating 
the Commerce Clause of the Constitution).
    \416\ See Undersigned States Rehearing Request at 10-13, 27-28 
(arguing that Order No. 1920 and that the categories of factors, in 
particular, ``are not resource neutral''); Designated Retail 
Regulators Rehearing Request at 14-15, 26-28 (same); Georgia 
Commission Rehearing Request at 4; Idaho Commission Rehearing 
Request at 4-5; Ohio Commission Federal Advocate Rehearing Request 
at 18-20; Utah Commission Rehearing Request at 4-5; Montana 
Commission Rehearing Request at 3-4; West Virginia Commission 
Rehearing Request at 12; Wyoming Commission Rehearing Request at 3-
4.
---------------------------------------------------------------------------

    144. The rhetoric in the rehearing requests suggesting that the 
Commission exceeded its statutory authority by directing reforms 
targeted at certain transmission planning outcomes demonstrates a 
misunderstanding of Order No. 1920, and particularly the categories of 
factors.\417\ The Commission found that the categories of factors set 
forth in Order No. 1920 reflect known determinants of transmission 
needs,\418\ such that requiring that transmission providers consider 
these factors in Long-Term Regional Transmission Planning is 
appropriate and reasonable. The substantive content of these factors 
(for example, a state law or policy implementing the state's reserved 
authority over resource choices) and how they affect transmission 
providers' development of Long-Term Scenarios (for example, the extent 
to which they may lead to the identification of specific Long-Term 
Transmission Needs) will be attributable to exogenous forces 
independent of Commission action.\419\ Indeed, these forces are drivers 
of the pre-existing trends, discussed above, that have demonstrated the 
urgency of more effective transmission planning.\420\ In other words, 
the Commission is not requiring consideration of these factors in order 
to achieve particular outcomes in the transmission planning process, 
but rather acting in a responsive capacity to identify and account for 
the most likely variables that are relevant to effective Long-Term 
Regional Transmission Planning and ensure that those variables are 
considered in such planning.\421\
---------------------------------------------------------------------------

    \417\ See Order No. 1920, 187 FERC ] 61,068 at P 260 (``In this 
final rule, the Commission neither aims to influence the resource 
mix, nor, as a practical matter, could the final rule achieve such 
an outcome.''); see also id. PP 129-30, 254, 419; cf. Dep't of Com. 
v. N.Y., 588 U.S. 752, 780-81 (2019) (``A court is ordinarily 
limited to evaluating the agency's contemporaneous explanation in 
light of the existing administrative record.''); Pharm. Rsch. & 
Mfrs. of Am. v. F.T.C., 790 F.3d 198, 212 (D.C. Cir. 2015) (noting 
the presumption of procedural regularity and substantive rationality 
that attaches to final agency action).
    \418\ See Order No. 1920, 187 FERC ] 61,068 at PP 119-120, 130, 
412, 415; see also id. PP 422-84 (discussing the adoption of the 
specific categories of factors).
    \419\ See id. PP 129-130, 233, 261-62, 419, 436.
    \420\ See supra Unjust, Unreasonable, and Unduly Discriminatory 
or Preferential Commission-Jurisdictional Transmission Planning and 
Cost Allocation Processes section.
    \421\ See Order No. 1920, 187 FERC ] 61,068 at PP 230, 266.
---------------------------------------------------------------------------

    145. Factor Category One (federal, federally-recognized Tribal, 
state, and local laws and regulations affecting the resource mix and 
demand) is illustrative,\422\ although these same points also apply to 
the other categories of factors. Because such laws and regulations, by 
definition, ``affect[ ] the resource mix and demand'' and, in turn, 
changes in resource mix and demand can affect Long-Term Transmission 
Needs,\423\ these laws and regulations are relevant to determining such 
transmission needs. The effect of such laws and regulations on 
transmission needs is inevitable \424\ and would be the same even in 
the absence of Order No. 1920.\425\ Furthermore, the existence and 
content of such laws and regulations are independent of any Commission 
action, as they are attributable instead to the lawful exercise of the 
authority of the entities, including states, responsible for enacting 
or promulgating such laws and regulations. Order No. 1920 thus requires 
Long-Term Regional Transmission Planning that accounts for the effects 
of these laws and regulations on transmission needs, because failure to 
adequately do so has had, and will continue to have, significant 
deleterious consequences.\426\ Order No. 1920 does not create these 
effects or aim to influence them.
---------------------------------------------------------------------------

    \422\ See id. P 130 n.328 (citing PJM Power Providers Grp. v. 
FERC, 88 F.4th 250, 275 (3d Cir. 2023) (holding that the Commission 
is ``unambiguously authorize[d] . . . to take state policies into 
account to the extent that such policies affect [the Commission's] 
statutorily prescribed area of focus . . . .''); Elec. Power Supply 
Ass'n v. Star, 904 F.3d at 524 (approving of the Commission's 
decision to take state zero-emissions credit systems like that in 
Illinois ``as givens and set out to make the best of the situation 
[these systems] produce'')).
    \423\ We note that the arguments on rehearing require 
recognizing that different types of generating resources, located in 
different areas, may have different transmission needs. See, e.g., 
Undersigned States Rehearing Request at 10, 16. In this respect, the 
rehearing requests tend to reinforce, rather than rebut, that the 
categories of factors set forth in Order No. 1920 are salient 
considerations for effective transmission planning.
    \424\ See Order No. 1920, 187 FERC ] 61,068 at P 435 (``Rather 
than a unique feature of Long-Term Regional Transmission Planning, 
transmission planning of any kind will inherently reflect the policy 
choices of multiple decisionmakers, because the quantity and 
location of generation and load are shaped by multiple 
decisionmakers.'').
    \425\ See id. P 436 (explaining that ``because . . . Long-Term 
Transmission Needs driven by disparate policy decisions would 
continue to exist, regardless of whether they were identified in 
Long-Term Regional Transmission Planning, failing to identify, 
evaluate, and select Long-Term Regional Transmission Facilities to 
address those needs will result in unjust and unreasonable rates'').
    \426\ See id. PP 130, 233, 261-262.
---------------------------------------------------------------------------

    146. Contrary to claims in the rehearing requests,\427\ the 
categories of factors set forth in Order No. 1920 are also resource-
neutral. Factor Category One is, again, illustrative. To the extent a 
law or regulation affects the resource mix or demand, transmission 
providers must consider how that law or regulation may affect Long-Term 
Transmission Needs. This requirement applies to all laws and 
regulations falling within Factor Category One, irrespective of their 
substantive content.\428\ Thus, to the extent a state law may affect 
the resource mix because, for example, it encourages or discourages the 
development of any particular type of generation, that would be a 
relevant consideration in Long-Term Regional Transmission 
Planning.\429\ This same point applies to all of the categories of 
factors specified in Order No. 1920: transmission providers must 
consider those categories of factors in developing Long-Term Scenarios 
irrespective of the substantive content of any given factor in a 
category.
---------------------------------------------------------------------------

    \427\ See supra P 143 n.416.
    \428\ See Order No. 1920, 187 FERC ] 61,068 at P 437 (``We are 
not endorsing the merits of any specific federal, federally-
recognized Tribal, state, or local laws and regulations or of any 
specific state-approved integrated resource plans. We emphasize that 
the Commission's policies are technology neutral, and we are not 
establishing a preference for certain types of generation or energy 
end uses.'').
    \429\ Similarly, where a state has laws or regulations that are, 
themselves, resource neutral or lacks laws or regulations affecting 
the generation mix or demand, the relevant transmission providers 
must conduct their Long-Term Regional Transmission Planning 
considering those considerations.
---------------------------------------------------------------------------

    147. In this respect, the categories of factors identified in Order 
No. 1920 are best understood as a non-exhaustive identification of 
essential inputs

[[Page 97205]]

relevant to Long-Term Regional Transmission Planning. To the extent 
that, in developing any Long-Term Scenarios, these inputs may point 
toward identification of particular Long-Term Transmission Needs, this 
will be the result of external forces that determine the substance of 
these inputs. In fact, the evaluation of these inputs will be conducted 
by transmission providers in consultation with relevant stakeholders 
without the Commission imposing any requirements that dictate the 
substantive outcome of the transmission planning process.\430\ Indeed, 
all the requirements that the Commission has established for conducting 
Long-Term Regional Transmission Planning--such as the number of Long-
Term Scenarios to be developed, the time horizon to be considered, that 
scenarios be ``plausible and diverse,'' and that the best available 
data be used--are also process-focused and resource-neutral.\431\
---------------------------------------------------------------------------

    \430\ We further strengthen those consultation requirements in 
this order by requiring transmission providers to consult with and 
consider the positions of Relevant State Entities as to how to 
account for factors related to state public policies in Long-Term 
Regional Transmission Planning assumptions.
    \431\ See id. P 248 (summarizing those process-focused 
requirements).
---------------------------------------------------------------------------

    148. Moreover, the discretion afforded to transmission providers in 
conducting their analyses further precludes the Commission from 
attempting to ``put a thumb on the scale'' of the transmission planning 
process to favor certain generation resources. Transmission providers 
may consider additional factors, beyond those specified in the 
categories of factors set forth in Order No. 1920, in developing Long-
Term Scenarios and identifying Long-Term Transmission Needs.\432\ 
Transmission providers also ``have discretion to determine whether 
specific factors must be accounted for within each category (i.e., if 
the specific factor will likely affect Long-Term Transmission Needs).'' 
\433\ Thus, the categories of factors set forth in Order No. 1920 
reflect minimum standards that transmission providers may not ignore 
when developing Long-Term Scenarios. However, as long as these 
scenarios otherwise meet the requirements of Order No. 1920 (e.g., they 
are plausible and diverse), Order No. 1920 ensures that transmission 
providers may consider all of the relevant factors and may also 
determine, in any given case, that any factor is not likely to affect 
such needs. This construct is wholly consistent with resource-neutral 
transmission planning.\434\
---------------------------------------------------------------------------

    \432\ See id. P 412.
    \433\ See id. P 417 (further providing that transmission 
providers must ``assume that the laws, regulations, state-approved 
integrated resource plans, and expected supply obligations for load-
serving entities identified in the first three categories of 
factors--that transmission providers have determined are likely to 
affect Long-Term Transmission Needs--are fully met''); see also id. 
P 415.
    \434\ Transmission providers also have discretion regarding 
``how to account for specific factors in the development of Long-
Term Scenarios (e.g., the method and data used to forecast resource 
retirements), and how to vary the treatment of each category of 
factors across Long-Term Scenarios (e.g., assume all forecasted 
resource retirements materialize in some but not all Long-Term 
Scenarios).'' Id. P 417.
---------------------------------------------------------------------------

    149. Certain rehearing requests state that other aspects of Order 
No. 1920 (such as the seven required benefits to evaluate Long-Term 
Regional Transmission Facilities) are preferential toward allegedly 
Commission-favored resources. These arguments are not well 
developed.\435\ Nonetheless, based on our best understanding of these 
arguments, we disagree with them for reasons similar to those 
articulated above and in Order No. 1920. Requiring that transmission 
providers measure and use, at a minimum, the seven required benefits in 
evaluating Long-Term Regional Transmission Facilities does not attempt 
to influence the external forces driving the need for new transmission 
facilities or displace the authority of other actors. Rather, this 
requirement helps to ensure that transmission providers conducting 
Long-Term Regional Transmission Planning have sufficient information to 
make their decisions, including as to which Long-Term Regional 
Transmission Facilities will ``more efficiently or cost-effectively 
address Long-Term Transmission Needs.'' \436\ Here, too, the 
Commission's approach has not been overly prescriptive, as transmission 
providers may propose on compliance to measure additional benefits as 
part of Long-Term Regional Transmission Planning \437\ and the 
Commission has afforded transmission providers flexibility as to how to 
measure each required benefit.\438\
---------------------------------------------------------------------------

    \435\ See, e.g., Undersigned States Rehearing Request at 3-4, 8, 
27-29 (asserting that the ``factors and benefit metrics'' will 
``favor some resources over others''; arguing that particular 
factors are not ``resource neutral'' but no similar argument or 
explanation as to the benefits metrics); Designated Retail 
Regulators Rehearing Request at 3-4, 8, 26-29 (similar); Arizona 
Commission Rehearing Request at 15.
    \436\ Order No. 1920, 187 FERC ] 61,068 at PP 667, 721; see also 
id. P 722 (``[W]ithout consideration of such benefits, Long-Term 
Regional Transmission Planning cannot be reasonably expected to 
identify, evaluate, and select more efficient or cost-effective 
regional transmission solutions to address Long-Term Transmission 
Needs.''); id. P 723.
    \437\ Order No. 1920, 187 FERC ] 61,068 at P 667.
    \438\ Id. P 728; cf. id. P 734 (``[W]hile this final rule 
requires the measurement and use of the required set of benefits, it 
is the evaluation process, including selection criteria, that 
transmission providers propose on compliance that will inform which 
Long-Term Regional Transmission Facilities are selected.'').
---------------------------------------------------------------------------

    150. Thus, Order No. 1920 reflects a modest exercise of well-
established Commission authority. To be sure, there is an urgent and 
growing need for new transmission infrastructure, driven by a wide 
variety of factors, including those leading to changes in the 
generation resource mix.\439\ Order No. 1920 identifies those factors, 
which are occurring independent of Commission action, and gives 
transmission providers the tools they need to respond to this need and 
these changes.\440\ The parties that argue that the Commission is 
attempting to influence the generation resource mix by requiring 
transmission providers to consider these factors to inform their Long-
Term Regional Transmission Planning are reversing cause and effect that 
necessitated the issuance of Order No. 1920.\441\
---------------------------------------------------------------------------

    \439\ See id. PP 90-99.
    \440\ See id. P 233 (``These changes are occurring independent 
of any action that we take in this final rule, and they are being 
driven by a wide variety of factors. This final rule provides 
transmission providers with the tools that they need to respond to 
these factors . . . .'').
    \441\ Claims that the Commission ``advertised'' its ``unlawful 
purpose'' in the ANOPR and NOPR, see Utah Commission Rehearing 
Request at 4-5, are erroneous for much the same reason: they 
misconstrue statements in which the Commission discussed the need 
for transmission reform to respond to changes in the resource mix 
driven by external factors, including increased penetration of 
renewable resources, as indicative of an intention to drive such 
changes.
---------------------------------------------------------------------------

b. Order No. 1920 Is Consistent with the FPA and Precedent Regarding 
the Commission's Authority
    151. As discussed above, in filling the discrete gaps in the Order 
No. 1000 regional transmission planning and cost allocation process, 
the Commission carefully tailored the reforms it adopted to avoid 
intruding on areas of reserved state authority. But because the spheres 
of federal and state authority over electricity are not ``hermetically 
sealed'' from one another,\442\ we recognize the possibility that Order 
No. 1920's requirements--although entirely focused on addressing 
practices within the Commission's jurisdiction--may have effects on 
areas of reserved state authority.
---------------------------------------------------------------------------

    \442\ EPSA, 577 U.S. at 281.
---------------------------------------------------------------------------

    152. While the rehearing requests discuss the text of the FPA and 
precedent reflecting that states have reserved authority in certain 
areas, including over the selection and approval of generation 
resources, they fail to discuss key Supreme Court precedent in EPSA as 
it applies Order

[[Page 97206]]

No. 1920. Despite the Commission's lengthy discussion of EPSA in Order 
No. 1920, on rehearing we are confronted with no argument that the 
Commission erred in its analysis or misapplied that decision to the 
facts here.
    153. Under the FPA, the Commission has exclusive jurisdiction over 
``the transmission of electric energy in interstate commerce,'' and 
``the sale of electric energy at wholesale in interstate commerce.'' 
\443\ The Supreme Court has ``construed broadly'' this grant of 
jurisdiction over interstate transmission of electricity.\444\ Under 
this grant of authority, ``ensur[ing] effective transmission of 
electric power'' is one of the ``core objects'' of the FPA.\445\ FPA 
section 206 is one of the principal tools Congress afforded the 
Commission to exercise this authority, under which it may find that 
practices affecting Commission-jurisdictional rates are ``unjust, 
unreasonable, unduly discriminatory or preferential,'' and determine 
the just and reasonable practice to be thereafter observed and in 
force.\446\ As the D.C. Circuit has recognized, the authority afforded 
to the Commission under FPA section 206 is ``broadly stated'' and not a 
``subtle device.'' \447\
---------------------------------------------------------------------------

    \443\ 16 U.S.C. 824(b)(1) (``The Commission shall have 
jurisdiction over all facilities for such transmission or sale of 
electric energy . . . .'').
    \444\ N.Y. v. FERC, 535 U.S. at 15.
    \445\ EPSA, 577 U.S. at 290.
    \446\ 16 U.S.C. 824e(a).
    \447\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56 (``The 
authority and obligation that Congress vested in the Commission to 
remedy certain practices is broadly stated and the only question is 
what limits are fairly implied.''); see also id. at 55 (``The text 
does not define `practice,' although use of the word `any' amplifies 
the breadth of the delegation to the Commission.'').
---------------------------------------------------------------------------

    154. The Commission does not, however, have jurisdiction over 
``facilities used for the generation of electric energy or over 
facilities used in local distribution or only for the transmission of 
electric energy in intrastate commerce, or over facilities for the 
transmission of electric energy consumed wholly by the transmitter,'' 
except as specifically provided.\448\ FPA section 201 also contains a 
policy statement recognizing the need for Federal regulation in areas 
subject to the Commission's jurisdiction, but also providing that 
``Federal regulation, however, [is] to extend only to those matters 
which are not subject to regulation by the States.'' \449\ Thus, as the 
rehearing requests point out, courts and the Commission have recognized 
certain reserved areas of state authority, including over electricity 
generation.\450\
---------------------------------------------------------------------------

    \448\ 16 U.S.C. 824(b)(1).
    \449\ Id. 824(a). This policy statement does not nullify the 
grant of authority to the Commission in the FPA. See N.Y. v. FERC, 
535 U.S. at 22 (``Moreover, we have described the precise reserved 
state powers language in [FPA section] 201(a) as a mere policy 
declaration that cannot nullify a clear and specific grant of 
jurisdiction, even if the particular grant seems inconsistent with 
the broadly expressed purpose.'' (quotation marks omitted)).
    \450\ See Pac. Gas & Elec. Co., 461 U.S. at 205 (``Need for new 
power facilities, their economic feasibility, and rates and 
services, are areas that have been characteristically governed by 
the States.''); Monongahela Power Co., 40 FERC ] 61,256 at 61,861 
(``[J]urisdiction over the capacity planning, determination of power 
needs, plant siting, 1icensing, construction, and the operations of 
coal-fired plants had been deliberately withheld from our control or 
responsibility . . . .''); cf. Nw. Cent. Pipeline Corp., 489 U.S. at 
522 (``Unless clear damage to federal goals would result, FERC's 
exercise of its authority [under the Natural Gas Act] must 
accommodate a State's regulation of production [of natural gas].''); 
Piedmont Env't Council, 558 F.3d at 310 (``The states have 
traditionally assumed all jurisdiction to approve or deny permits 
for the siting and construction of electric transmission 
facilities.''); Calpine Corp. v. PJM Interconnection, 171 FERC ] 
61,035 (Glick, Comm'r, dissenting at P 5).
---------------------------------------------------------------------------

    155. Under EPSA, Order No. 1920 is a lawful exercise of the 
Commission's authority because it regulates practices that directly 
affect the rates for the transmission of electric energy in interstate 
commerce--transmission planning and cost allocation processes--and 
directly regulates only those practices.\451\ These findings are not 
contested in the rehearing requests challenging the Commission's 
authority. As discussed in Order No. 1920 and above, Order No. 1920 is 
also not aimed at and does not regulate any area of reserved state 
authority, whether over electricity generation or otherwise, confirming 
that the rule is within the Commission's authority.\452\ While it would 
be unlawful for the Commission to regulate within reserved state areas 
of authority, even as a means of accomplishing objectives within the 
Commission's statutorily granted authority,\453\ a Commission 
regulation does not run afoul of FPA section 201(b) just because it 
affects, even substantially, a reserved area of state authority.\454\ 
To the contrary, the rule is exactly the opposite: when the Commission 
regulates within the areas set forth for its authority in FPA sections 
201 and 206 (here, practices directly affecting rates for interstate 
transmission of electricity) as part of ``carrying out its charge to 
improve how that market runs . . . [FPA section 201(b)] imposes no 
bar'' to such regulation, ``no matter the effect'' on areas of state 
authority.\455\ EPSA is, therefore, fatal to the arguments asserting 
that Order No. 1920 is unlawful on the theory that, by regulating 
transmission planning processes and cost allocation, Order No. 1920 may 
affect state generation resource planning or other areas of state 
authority.
---------------------------------------------------------------------------

    \451\ Order No. 1920, 187 FERC ] 61,068 at P 263 (noting that 
``no commenter contests'' this point); see id. P 265-66; EPSA, 577 
U.S. at 278 (construing the text of FPA section 206 regarding the 
Commission's ```affecting' jurisdiction'' as limited to rules or 
practices that ``directly affect'' the rates within the Commission's 
jurisdiction); NARUC, 964 F.3d at 1186-87 (applying EPSA, 
considering whether the practice at issue meets the ``directly 
affects'' test, whether the Commission directly regulates state 
areas of authority, and whether the Commission action does not 
conflict with the FPA's core purposes); S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d at 63 (``[B]ecause the orders' planning mandate is 
directed at ensuring the proper functioning of the interconnected 
grid spanning state lines, the mandate fits comfortably within 
Section 201(b)'s grant of jurisdiction over `the transmission of 
electric energy in interstate commerce.''' (citation omitted)); 
Conn. Dep't of Pub. Util. Control v. FERC, 569 F.3d at 481-82 (where 
economic impact of FERC regulation would likely cause States to 
construct new generation facilities, such state response was not the 
result of a ``direct regulation'' of generation facilities but the 
product of a state's response to changed incentives and ``has little 
relevance'').
    \452\ See NARUC, 964 F.3d at 1186-87 (finding that Commission 
order did not unlawfully regulate matters left to the States; 
``States remain equipped with every tool they possessed prior to 
Order No. 841 to manage their facilities and systems.'').
    \453\ See EPSA, 577 U.S. at 279-80 (positing a hypothetical in 
which the Commission ``issued a regulation compelling every consumer 
to buy a certain amount of electricity on the retail market'' as a 
means of altering wholesale prices falling with the Commission's 
jurisdiction and explaining that this would be unlawful ``because it 
specifies terms of sale at retail--which is a job for the States 
alone'').
    \454\ See id. at 281 (``[A] FERC regulation does not run afoul 
of 824(b)'s proscription just because it affects--even 
substantially--the quantity or terms of retail sales.''); NARUC, 964 
F.3d at 1186-87; Order No. 1920, 187 FERC ] 61,068 at P 264; see 
also id. PP 265-266.
    \455\ EPSA, 577 U.S. at 281-82 (such effects are ``of no legal 
consequence''); Order No. 1920, 187 FERC ] 61,068 at P 264; see also 
id. PP 265-66.
---------------------------------------------------------------------------

    156. Furthermore, the rehearing requests disregard how Order No. 
1920 ensures that Long-Term Regional Transmission Planning processes 
facilitate and respect the lawful authority of actors, including 
states, in areas such as generation resource planning, electricity 
production, and electricity demand. Factor Categories One, Two, and 
Three, in particular, require transmission providers to consider ``(1) 
federal, federally-recognized Tribal, state, and local laws and 
regulations affecting the resource mix and demand; (2) federal, 
federally-recognized Tribal, state, and local laws and regulations on 
decarbonization and electrification; [and] (3) state-approved 
integrated resource plans and expected supply obligations for load-
serving entities.'' \456\ Far from intruding on the authority of states 
in these domains, Order No. 1920 requires that in

[[Page 97207]]

developing Long-Term Scenarios transmission providers account for that 
authority in Long-Term Regional Transmission Planning and, in fact, 
afford states maximum respect for that authority by assuming that these 
laws, regulations, integrated resource plans, and expected supply 
obligations will be fully met.\457\ If anything, the Commission has 
adopted a conservative approach to ensure that Order No. 1920 is 
consistent with the structure of federalism set forth in the FPA.\458\
---------------------------------------------------------------------------

    \456\ Order No. 1920, 187 FERC ] 61,068 at P 409.
    \457\ See id. PP 417, 507. At the same time, the Commission in 
Order No. 1920 reasonably recognized that the first three categories 
of factors are not the only known determinants of transmission 
needs.
    \458\ FPA section 215(i)(3), 16 U.S.C. 824o(i)(3), and section 
216, 16 U.S.C. 824p, which certain rehearing requests cite in 
passing, see Undersigned States Rehearing Request at 6, 11; 
Designated Retail Regulators Rehearing Request at 6-7, 13, 18-19, do 
not affect this conclusion. Neither provision limits the 
Commission's authority over transmission planning processes or cost 
allocation under the FPA. Rather, section 215(i)(3) establishes that 
``[n]othing in this section,'' relating to establishment of Electric 
Reliability Organizations, ``shall be construed to preempt any 
authority of any State to take action to ensure the safety, 
adequacy, and reliability of electric service within that State, as 
long as such action is not inconsistent with any reliability 
standard.'' The National Interest Electric Transmission Corridor 
process in section 216 affords the Commission, in certain 
circumstances, authority over siting of interstate electric 
transmission facilities; the siting of particular transmission 
facilities is not at issue in Order No. 1920. See Order No. 1920, 
187 FERC ] 61,068 at PP 254, 258.
---------------------------------------------------------------------------

c. Order No. 1920 Does Not Require Unlawful Subsidization of State 
Policies
    157. We also remain unpersuaded by arguments that Order No. 1920 
exceeds the Commission's authority because it will allegedly intrude 
into state authority by requiring them to effectively subsidize the 
policies or generation resource mixes of other states.\459\ Nothing in 
Order No. 1920 requires a state to subsidize the policies of other 
states.\460\ In particular, and among other requirements to ensure such 
subsidization will not occur, Order No. 1920 mandates ``consistent with 
long-established Commission and court precedent, that transmission 
customers within a transmission planning region need only pay costs 
that are `roughly commensurate' with the benefits that transmission 
providers estimate they will receive from a regional transmission 
facility.'' \461\
---------------------------------------------------------------------------

    \459\ See Undersigned States Rehearing Request at 12-13; 
Designated Retail Regulators Rehearing Request at 14-15; Georgia 
Commission Rehearing Request at 5-6; Arizona Commission Rehearing 
Request at 11-12; Montana Commission Rehearing Request at 2-4; West 
Virginia Commission Rehearing Request at 2-4, 10-12.
    \460\ Order No. 1920, 187 FERC ] 61,068 at P 267; see also, 
e.g., id. PP 232, 268-70, 280; cf. id. P 1419 (``[W]e reiterate that 
all cost allocation methods, including those resulting from a State 
Agreement Process, must allocate costs in a manner that is at least 
roughly commensurate with estimated benefits.'').
    \461\ Id. P 267; see id. P 268 (discussing various requirements 
in Order No. 1920, including the beneficiary-pays cost allocation 
principle, that ``provide robust assurance that the cost allocation 
methods ultimately proposed under the final rule will not result in 
improper cost subsidization.''); id. P 280.
---------------------------------------------------------------------------

    158. No cost allocation method proposals have yet been submitted to 
the Commission in response to Order No. 1920, let alone approved, and 
application of any such hypothetical Commission-approved proposals to 
particular Long-Term Regional Transmission Facilities is even further 
in the future. As a result, disputes about the precise cost allocation 
method that transmission providers may file, the benefits associated 
with particular transmission facilities, or how the costs of those 
particular facilities may be allocated are necessarily theoretical and 
premature. Regardless, Order No. 1920's bedrock requirement that the 
cost allocation proposals that will eventually be filed must comply 
with the beneficiary-pays cost allocation principle is inconsistent 
with parties' claims that the Commission is unlawfully requiring 
consumers who do not benefit from Long-Term Regional Transmission 
Facilities to subsidize such facilities. This beneficiary-pays approach 
is a just and reasonable basis for allocating costs of regional 
transmission projects.\462\ Indeed, courts and the Commission have 
explained that requiring that the costs imposed must be at least 
roughly commensurate to the benefits received \463\ ensures that rates 
remain ``just'' by avoiding subsidization.\464\
---------------------------------------------------------------------------

    \462\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 84; see id. at 
85 (noting that the court had ``repeatedly embraced'' the ``basic 
tenet'' of beneficiary-pays cost allocation as a logical extension 
of the cost causation principle and that the Commission has 
``reasonably identified the lack of beneficiary-based cost 
allocation as a practice likely to result in rates that are not just 
and reasonable or are unduly discriminatory or preferential'' 
(citing Order No. 1000, 136 FERC ] 61,051 at P 487); Neb. Pub. Power 
Dist. v. FERC, 957 F.3d 932, 941 (8th Cir. 2020) (``[I]t is certain 
that to the extent that a utility benefits from the costs of new 
facilities, it may be said to have caused a part of those costs to 
be incurred. Because NPPD has greatly benefitted from Tri-State's 
facilities, it is likely that some of the costs have been caused by 
NPPD.'' (internal quotations and alterations omitted)); ICC v. FERC 
I, 576 F.3d at 476 (``Not surprisingly, we evaluate compliance with 
this unremarkable principle by comparing the costs assessed against 
a party to the burdens imposed or benefits drawn by that party. To 
the extent that a utility benefits from the costs of new facilities, 
it may be said to have `caused' a part of those costs to be incurred 
. . . .'' (citations omitted)).
    \463\ As discussed in greater detail below, Order No. 1920 
recognized that Long-Term Regional Transmission Facilities are 
likely to provide a diverse array of benefits. The Commission 
specifically required that transmission providers consider seven 
economic and reliability benefits in Long-Term Regional Transmission 
Planning, but did not prohibit them from also considering public 
policy benefits. See infra Omission of Regional Cost Allocation 
Principle No. 6 and Ability to Allocate Costs by Type of Project 
section (reiterating the fundamental principle that costs will be 
allocated in a manner that is at least roughly commensurate with 
estimated benefits, ensuring that ratepayers will not pay for 
facilities from which they do not benefit).
    \464\ El Paso Elec. Co. v. FERC, 76 F.4th 352, 361-63 (5th Cir. 
2023) (``The cost-causation principle, as understood by the courts 
and articulated in Order No. 1000, . . . ensure[s] that rates are 
`just' . . . [by] prevent[ing] `subsidization by ensuring that costs 
and benefits correspond to each other.''' (quoting Order No. 1000-A, 
139 FERC ] 61,132 at P 578; citing BNP Paribas Energy Trading GP v. 
FERC, 743 F.3d at 268; Nat'l Ass'n of Reg. Util. Comm'rs v. FERC, 
475 F.3d 1277, 1285 (D.C. Cir. 2007))).
---------------------------------------------------------------------------

    159. Furthermore, the requests for rehearing arguing that Order No. 
1920 intrudes on their authority by requiring such subsidization place 
too much weight on the broad premise that states have reserved 
authority over generation resource planning and electricity production 
within their own borders.\465\ This, however, is a far cry from 
establishing that state authority over generation within that state's 
own borders also includes a right to be free from the incidental 
effects of policies of other states (e.g., as to generation planning) 
as those effects may manifest through interstate commerce in 
electricity. For example, Undersigned States and Designated Retail 
Regulators cite the federal/state division of authority set forth in 
the FPA, and argue that ``[e]ach state has authority over the choice of 
which generating resources are maintained and constructed within its 
own jurisdiction.'' \466\ However, they then recast this as a broader 
``right to choose the resources that best fit their public policies,'' 
a framing that omits the geographic limitation that states' reserved 
authority over such resources applies only to resources within their

[[Page 97208]]

own jurisdiction.\467\ As a consequence, they claim, it is ``an over-
reach into the traditional area of regulation reserved for the States'' 
for their residents ``to pay for infrastructure to support[ ] the 
public policies and resource mixes of other States, without 
demonstrable benefits to that load'' as the costs of those policies 
manifest in interstate transmission facility cost allocations.\468\
---------------------------------------------------------------------------

    \465\ See, e.g., Undersigned States Rehearing Request at 10-13; 
Designated Retail Regulators Rehearing Request at 11-14; Montana 
Commission Rehearing Request at 2-4 (arguing that Order No. 1920 
intrudes on state authority because ``without a voluntary state 
agreement process, the Final Rule's regional cost allocation scheme 
ensures that nonconsenting states will be swept up in their 
neighbors' preferred policy projects''); Wyoming Commission 
Rehearing Request at 2-4 (similar); West Virginia Commission 
Rehearing Request at 3-4, 10-12 (similar); Arizona Commission 
Rehearing Request at 13 (``[S]tates without renewable resource 
policy objectives will be forced to absorb costs generated by the 
transmission of (often rurally sited) renewable energy.'' (emphasis 
omitted)); Georgia Commission Rehearing Request at 5-6; Utah 
Commission Rehearing Request at 6-7.
    \466\ Undersigned States Rehearing Request at 11-12; Designated 
Retail Regulators Rehearing Request at 13.
    \467\ Undersigned States Rehearing Request at 12-13; Designated 
Retail Regulators Rehearing Request at 14.
    \468\ Undersigned States Rehearing Request at 12-13; Designated 
Retail Regulators Rehearing Request at 14. This reference to 
``demonstrable benefits to load'' appears to reflect the view that 
certain states may disagree with the choices of other states in 
terms of generation resource selection, particularly on the basis 
that ``less-remote resources of any type might be less expensive, 
more reliable, and environmentally beneficial.'' Undersigned States 
Rehearing Request at 4-5; Designated Retail Regulators Rehearing 
Request at 4-5 (similar).
---------------------------------------------------------------------------

    160. Neither statutory text in the FPA nor any of the precedent 
cited by the rehearing requests establishes that states' authority, 
when they participate in interstate commerce in electricity, includes a 
right to be free from the incidental extraterritorial effects of the 
policies of other states as they may manifest through such interstate 
commerce.\469\ To the contrary, as the Supreme Court has recognized, 
``the production and transmission of energy is an activity particularly 
likely to affect more than one State.'' \470\ The FPA is a 
congressional enactment authorizing the Commission to regulate in this 
area.\471\
---------------------------------------------------------------------------

    \469\ No such generic right to avoid the extraterritorial 
effects of the policies of other states as they may manifest through 
interstate commerce exists under the Constitution. See Nat'l Pork 
Producers Council v. Ross, 598 U.S. 356, 371-74 (2023) (rejecting 
arguments, under the dormant Commerce Clause, ``invoking . . . an 
`almost per se' rule forbidding enforcement of state laws that have 
the `practical effect of controlling commerce outside the State,' 
even when those laws do not purposely discriminate against out-of-
state economic interests'').
    \470\ Ark. Elec. Co-op. Corp. v. Ark. Pub. Serv. Comm'n, 461 
U.S. 375, 377 (1983) (explaining also that the effect of such 
production and transmission ``on interstate commerce is often 
significant enough that uncontrolled regulation by the States can 
patently interfere with broader national interests''); see Order No. 
1920, 187 FERC ] 61,068 at P 282 (``The nature of the interconnected 
transmission system is such that states naturally affect one another 
in pursuing policies available to them while exercising the 
authority reserved to them under FPA section 201.'').
    \471\ See 16 U.S.C. 824(a), (b)(1), 824d, 824e.
---------------------------------------------------------------------------

    161. In fact, the FPA was enacted in response to a Supreme Court 
decision holding that the Commerce Clause prevents states from 
regulating certain transactions between electric utilities located in 
other states--thereby creating the ``Attleboro gap.'' \472\ Congress 
responded by passing the FPA,\473\ preventing the ``creation of any 
regulatory `no man's land.' Some entity must have jurisdiction to 
regulate each and every practice that takes place in the electricity 
markets.'' \474\ Attleboro and Congress's enactment of the FPA thus 
reflect the authority vested in the Commission to regulate in these 
domains precisely because states are constitutionally incapable of 
doing so, including as to how the interaction of state policies may 
manifest in interstate commerce.\475\ Moreover, the purported 
requirement that states must voluntarily agree to any cost allocation 
for interstate transmission facilities would run the risk of creating 
the sort of ``regulatory void'' that the FPA was designed to preclude. 
In particular, it would effectively assign to the states the regulatory 
responsibility for cost allocation of interstate transmission 
facilities (notwithstanding that this falls within an area Congress 
assigned to the Commission in the FPA), creating the possibility that 
this area goes entirely unregulated should states fail to reach 
agreement.\476\ In other words, far from prohibiting any 
extraterritorial effects, the FPA's statutory standard puts the 
Commission in charge of regulating those effects pursuant to the just 
and reasonable standard, which includes the cost causation principle.
---------------------------------------------------------------------------

    \472\ EPSA, 577 U.S. at 266 (citing Pub. Util. Comm'n of R.I. v. 
Attleboro Steam & Elec. Co., 273 U.S. 83, 89-90 (1927)).
    \473\ Id.
    \474\ Id. at 289 (citation omitted).
    \475\ See Appalachian Power Co. v. Pub. Serv. Comm'n of W. Va., 
812 F.2d 898, 905 (4th Cir. 1987) (enactment of the FPA reflects 
``the judgment embodied in the commerce clause that there are 
situations in which the broader perspective of federal authority is 
necessary''); cf. id. at 904 (``[S]tates are powerless to exert 
authority that potentially conflicts with FERC determinations 
regarding rates or agreements affecting rates.'').
    \476\ Order No. 1920, 187 FERC ] 61,068 at P 1293 (``[I]f 
transmission providers were to rely solely on a State Agreement 
Process to determine the cost allocation for Long-Term Regional 
Transmission Facilities and that process fails to result in 
agreement, there would be no cost allocation method for Long-Term 
Regional Transmission Facilities selected as the more efficient or 
cost-effective solutions to Long-Term Transmission Needs.''); see 
also infra Obligation to File an Ex Ante Long-Term Regional 
Transmission Cost Allocation Method and Its Use as a Backstop 
section.
---------------------------------------------------------------------------

    162. The argument that, particularly absent state agreement to cost 
allocation, Order No. 1920 exceeds the Commission's authority is also 
ahistorical when viewed in the regulatory context.\477\ In Order No. 
1000, the Commission required that transmission providers ``devise 
methods for allocating the costs of certain new transmission facilities 
to those entities that benefit from them.'' \478\ The D.C. Circuit held 
that this requirement fell within the Commission's statutory authority 
to regulate practices affecting rates \479\ and otherwise rejected 
challenges to the Commission's authority to adopt these cost allocation 
reforms under FPA section 206.\480\ In addition, Order No. 1000 also 
adopted Cost Allocation Principle 1, requiring (like Order No. 1920) 
that the cost of transmission facilities be allocated to those that 
will benefit from those facilities in a manner at least roughly 
commensurate with the estimated benefits of that facility.\481\ In 
doing so, the Commission neither required state agreement to ex ante 
cost allocation methods, nor that any such method ensure that costs be 
allocated based on whether a state agreed with the public policies of 
other states associated with the generating facilities connected to the 
relevant transmission facilities.\482\ Order No. 1920's approach of 
requiring an Engagement Period directed toward state agreement on cost 
allocation, with an ex ante cost allocation backstop,\483\ thus 
reflects an expansion of states' ability to participate in the 
development of regional cost allocation methods as compared to the 
status quo ante, while recognizing the bounds of state authority. And 
we take further steps in this order to ensure that states have a 
meaningful opportunity to inform both Long-Term Regional Transmission 
Planning and cost allocation for Long-Term Regional Transmission 
Facilities, particularly with respect to the

[[Page 97209]]

implementation and effect of state public policies.
---------------------------------------------------------------------------

    \477\ The Supreme Court has observed that ``[i]n our 
interconnected national marketplace, many (maybe most) state laws 
have the `practical effect of controlling' extraterritorial 
behavior'' such that application of an ``extraterritoriality 
doctrine'' to preclude such effects would lead to ``strange 
places.'' Nat'l Pork Producers Council, 598 U.S. at 374-75 (citing 
examples and concluding that adopting this rule would ``cast a 
shadow over laws long understood to represent valid exercises of the 
States' constitutionally reserved powers''); id. at 390 (noting that 
the Supreme Court has ``recognized since Gibbons [v. Ogden], 9 Wheat 
1, 22 U.S. 1 (1824), that virtually all state laws create ripple 
effects beyond their borders'').
    \478\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 81; see id. at 
82-83 (discussing these reforms in more detail).
    \479\ See id. at 84.
    \480\ See id. at 84-87.
    \481\ See Order No. 1000, 136 FERC ] 61,051 at P 622; see S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 85 (``The Commission therefore 
reasonably identified the lack of beneficiary-based cost allocation 
as a practice likely to result in rates that are not just and 
reasonable or are unduly discriminatory or preferential.'' (citing 
Order No. 1000, 136 FERC ] 61,051 at P 487)).
    \482\ Cf. Order No. 1000, 136 FERC ] 61,051 at P 685 
(permitting, but not requiring, transmission providers to use 
different types of cost allocation methods for different types of 
transmission facilities, ``such as transmission facilities needed 
for reliability, congestion relief, or to achieve Public Policy 
Requirements'').
    \483\ See Order No. 1920, 187 FERC ] 61,068 at PP 1291-1292.
---------------------------------------------------------------------------

    163. Order No. 1920 regulates within, and only within, Commission 
authority, while ensuring that state policy choices in areas of 
reserved state authority are respected and effectuated. Order No. 1920 
treats such choices evenhandedly and as antecedent to Long-Term 
Regional Transmission Planning, requiring transmission providers to 
consider those choices, among other factors, when they identify Long-
Term Transmission Needs and (ultimately) Long-Term Regional 
Transmission Facilities.\484\ Long-Term Regional Transmission Planning 
is, in turn, focused on evaluating the Long-Term Regional Transmission 
Facilities that will reliably and cost-effectively deliver the power 
needed to serve the load that is expected given these (and other) 
drivers of transmission needs.\485\ As to cost allocation, transmission 
providers have flexibility to propose specific cost allocation methods 
for Long-Term Regional Transmission Facilities, but the prospect of 
unlawful subsidization of such a transmission facility by customers 
that do not benefit from it is foreclosed by the requirement that any 
such method must conform to the beneficiary-pays cost allocation 
requirement.\486\ To be clear, that means that no state or its 
customers will be required to pay for the costs of Long-Term Regional 
Transmission Facilities unless they benefit from those transmission 
facilities and in a manner that is at least roughly commensurate with 
those costs. This approach toward the interplay of federal and state 
regulation of electricity wholly comports with the jurisdictional lines 
drawn in the FPA.\487\
---------------------------------------------------------------------------

    \484\ See supra Requests to Omit One or More Categories of 
Factors section.
    \485\ Id.; see also supra Evaluation and Selection of Long-Term 
Regional Transmission Facilities section.
    \486\ Similarly, we find that Undersigned States and Designated 
Retail Regulators assertion that they may be required to pay for 
infrastructure ``without demonstrable benefits to that load,'' 
Undersigned States Rehearing Request at 12-13; Designated Retail 
Regulators Rehearing Request at 14, is misplaced. Under the 
beneficiary-pays principle, costs are assigned to customers only to 
the extent that they receive demonstrable benefits that are at least 
roughly commensurate with those costs.
    \487\ See EPSA, 577 U.S. at 282 (``considering `the target at 
which a law aims''' in deciding whether FERC's wholesale market rule 
fell within its power to regulate wholesale sales (quoting Oneok, 
Inc. v. Learjet, Inc., 575 U.S. 373, 385 (2015)); cf. Hughes v. 
Talen Energy Mktg., LLC, 578 U.S. 150, 165 (2016) (holding that 
states may not set retail rates, a power typically falling on the 
states' side of the FPA's jurisdictional line, 16 U.S.C. 824(b)(1), 
in a way that fails to ``give effect'' to a wholesale rate); Oneok, 
575 U.S. at 385-86 (contrasting a state policy properly aimed at its 
field of jurisdiction with one aimed directly at the federal field).
---------------------------------------------------------------------------

    164. Contrast this with the rehearing requests challenging the 
Commission's authority under the FPA. By virtue of states' connection 
to the interstate transmission grid, consumers in those states 
participate in interstate commerce. However, certain parties seeking 
rehearing object to the potential consequences of that connection, 
particularly the amount that these ratepayers may be required to pay 
for the transmission facilities connecting to those resources. But 
where a ratepayer in one state benefits from a transmission facility, 
it is appropriate that they bear costs at least roughly commensurate 
with that benefit.\488\
---------------------------------------------------------------------------

    \488\ Indeed, a contrary rule would arguably be inconsistent 
with judicial precedent governing cost causation. See, e.g., El Paso 
Elec. Co., 76 F.4th at 360-63 (finding that the Commission 
impermissibly ``prohibited the WestConnect region from imposing 
binding cost allocation on the non-jurisdictional utilities although 
they will `cause,' in part, the costs of new grid improvements''); 
id. at 361-62 (explaining that it was of fundamental legal 
importance that the non-jurisdictional utilities at issue were 
specifically and intentionally designated as beneficiaries, rather 
than incidental, unintended beneficiaries, such that they were 
impermissible ``free riders'' if not allocated an appropriate share 
of costs).
---------------------------------------------------------------------------

    165. For the reasons stated above and in Order No. 1920, we 
disagree with arguments that, under the FPA, the Commission's authority 
to regulate interstate transmission planning processes and cost 
allocation is limited as these rehearing requests claim. We find that 
the requirements of Order No. 1920 are within our authority over the 
``transmission of electric energy in interstate commerce,'' and 
particularly to ensure that practices affecting rates for such 
transmission are just and reasonable.\489\
---------------------------------------------------------------------------

    \489\ 16 U.S.C. 824(b)(1), 824d(a), 824e(a).
---------------------------------------------------------------------------

C. Major Questions Doctrine

1. Requests for Rehearing
    166. Several of the rehearing requests also invoke the ``major 
questions'' doctrine, particularly the Supreme Court's decision in West 
Virginia v. EPA,\490\ in connection with their contention that Order 
No. 1920 exceeds the Commission's statutory authority.\491\ Undersigned 
States and Designated Retail Regulators argue that Order No. 1920 
involves a ``major question'' such that Order No. 1920 must be 
supported by clear congressional authorization because the Commission 
is attempting to supplant state generation planning authority in favor 
of promoting distantly located renewable energy.\492\ They assert that 
West Virginia supports concluding that Order No. 1920 implicates the 
major questions doctrine.\493\ Undersigned States and Designated Retail 
Regulators also point to the claimed economic consequences of Order No. 
1920, citing alleged costs in the hundreds of billions or trillions of 
dollars; the breadth of the transmission grid; and the importance of 
electricity in everyday life.\494\ They argue that Order No. 1920 is 
``blatantly preferential,'' will not ensure just and reasonable rates, 
and that attempting to influence the generation resource mix exceeds 
both the Commission's expertise and the scope of the FPA as a consumer-
protection statute geared toward ensuring such just and reasonable 
rates.\495\
---------------------------------------------------------------------------

    \490\ 597 U.S. 697.
    \491\ See Undersigned States Rehearing Request at 7, 14-17; 
Designated Retail Regulators Rehearing Request at 7, 15-19; Arizona 
Commission Rehearing Request at 2, 3-6 & n.8; Idaho Commission 
Rehearing Request at 2, 6-7; Utah Commission Rehearing Request at 1, 
7-8; Ohio Commission Federal Advocate Rehearing Request at 20.
    \492\ Undersigned States Rehearing Request at 14-15; Designated 
Retail Regulators Rehearing Request at 15-16; see also id. at 17-18 
(``[T]here is no clear delegated authority allowing FERC to 
determine what type of generating resources should be transmitted 
from where in the United States.'').
    \493\ Undersigned States Rehearing Request at 14-15 (also 
asserting that this is a major question because ``it implicates a 
unique and complex jurisdictional divide between state and federal 
regulatory authority'' (citing Ala. Ass'n of Realtors v. HHS, 594 
U.S. 758, 764 (2021); EPSA, 577 U.S. at 264-65)); Designated Retail 
Regulators Rehearing Request at 17.
    \494\ Undersigned States Rehearing Request at 15; Designated 
Retail Regulators Rehearing Request at 16-17.
    \495\ Undersigned States Rehearing Request at 16-17; Designated 
Retail Regulators Rehearing Request at 16-17, 18-19.
---------------------------------------------------------------------------

    167. Likewise, Arizona Commission argues that the Commission has 
``implemented a nationwide scheme, foisted on all 50 states, to adopt 
energy generation modes to its liking'' even though ``nothing in th[e 
FPA] authorizes the adoption of the Biden Administration's renewable 
energy policy goals.'' \496\ Arizona Commission and Utah Commission 
assert that in West Virginia the Supreme Court stated that it is highly 
unlikely that Congress would leave to agency discretion how much coal-
based generation there should be over the coming decades, and assert 
that major policy changes must occur pursuant to an express statement 
of Congress.\497\ Arizona Commission argues that commenters have 
observed the breadth and consequences of Order

[[Page 97210]]

No. 1920 \498\ and cites a characterization of the Commission's 
approach as controversial,\499\ asserts that the FPA is a consumer 
protection statute,\500\ and states that Congress has not enacted the 
``Green New Deal.'' \501\ Utah Commission contends that ``transitioning 
the grid away from fossil-fueled generation and toward renewable 
resources'' is a major question, pointing to its social and political 
context and economic consequences.\502\
---------------------------------------------------------------------------

    \496\ Arizona Commission Rehearing Request at 4-6.
    \497\ Id. at 5-6; see also id. at 3-4 (arguing that Congress 
does not use oblique or elliptical language to empower fundamental 
changes to a statutory scheme); Utah Commission Rehearing Request at 
7-8.
    \498\ See Arizona Commission Rehearing Request at 6; cf. id. at 
16 (citing the cost of achieving net-zero on the transmission grid).
    \499\ See id. at 4-5.
    \500\ See id. at 20.
    \501\ See id. at 5.
    \502\ Utah Commission Rehearing Request at 8 & n.17 (arguing 
that Order No. 1920 ``patently dictates outcomes and cost allocation 
and does so to discriminate and favor the policy preferences of 
certain preferred stakeholders''; citing Commissioner Christie's 
dissent claiming that Order No. 1920 is intended to cost consumers 
trillions of dollars).
---------------------------------------------------------------------------

    168. In arguing that Order No. 1920 involves a major question, 
Idaho Commission points to statements in the concurrence to Order No. 
1920 that the nation's energy grid is at a crossroads, with `` 
`consequential action' . . . emphatically warranted'' and 
``proselytiz[ing] for states to join it in building an `electric 
transmission grid for the 21st century.' '' \503\ It contends that the 
Commission has ``gone to great lengths to enact a sweeping policy 
agenda, in the absence of congressional authority, that infringes on 
states' authority, and impermissibly attempts to expand the 
Commission's jurisdiction under the FPA, in violation of the major 
questions doctrine.'' \504\
---------------------------------------------------------------------------

    \503\ Idaho Commission Rehearing Request at 6 (quoting Order No. 
1920, 187 FERC ] 61,068 (Phillips & Clements Comm'rs, concurring at 
PP 34-35)).
    \504\ Id. at 6-7.
---------------------------------------------------------------------------

    169. Ohio Commission Federal Advocate argues, citing West Virginia, 
that the Commission has not identified a clear congressional 
authorization to ``use its power under the FPA to facilitate federal, 
state, Tribal, local, and corporate policies, including decarbonization 
and electrification policies, under the guise of building a robust 
transmission system.'' \505\ It argues that the Commission lacks this 
authority.\506\
---------------------------------------------------------------------------

    \505\ Ohio Commission Federal Advocate Rehearing Request at 20.
    \506\ Id.
---------------------------------------------------------------------------

    170. SERTP Sponsors bring several requests for clarification of 
Order No. 1920, which we summarize and address in detail below. 
Focusing on the ``respect afforded to state-approved IRPs and LSE 
supply obligations,'' SERTP Sponsors state that, absent certain of 
those clarifications, ``particularly [in] Sections II.A.1 and II.C.3'' 
of their argument, Order No. 1920 could encroach on state 
jurisdiction.\507\ They particularly contend that if these 
clarifications are not granted ``Order No. 1920 would be seeking to 
influence the makeup of the nation's energy policy and generation mix, 
which would constitute a `major question,' given the vast economic 
consequences that would result from an exercise of such authority.'' 
\508\
---------------------------------------------------------------------------

    \507\ SERTP Sponsors Rehearing Request at 37-41; see also id. at 
41-45.
    \508\ Id. at 39-40 (arguing that ``the application or 
implementation of Order No. 1920 in a manner that would undercut or 
conflict with state-regulated IRPs and resource adequacy decisions 
would transform the regulatory paradigm from an electric system 
expansion process driven by state-regulated resource assumptions 
made in state-regulated IRPs to one driven by FERC-regulated 
resource assumptions made in the FERC-regulated LTRTP processes,'' 
exceeding the scope of the Commission's expertise and previous 
regulation of ``practices affecting rates'').
---------------------------------------------------------------------------

2. Commission Determination
    171. We continue to find that Order No. 1920 does not implicate the 
major questions doctrine. As the summary above reflects, the rehearing 
requests provide little to no discussion of the scope of the 
Commission's authority under the FPA or the statutory context and, as 
discussed in the preceding sections, they misinterpret Order No. 1920 
itself.\509\ The Supreme Court has described the major questions 
doctrine as applicable only in ``extraordinary cases,'' which it has 
identified through a detailed analysis of the statutory context and 
agency action at issue.\510\ Specifically, that doctrine comes into 
play where, despite a ``colorable textual basis'' for the agency's 
claim of authority, the agency action was so extravagant when viewed in 
light of the statutory context that it was unlikely that Congress would 
have afforded this claimed authority to the agency, and particularly 
would not have done so in an oblique or subtle way.\511\ As a rule, 
Congress does not ``hide `elephants in mouseholes.' '' \512\
---------------------------------------------------------------------------

    \509\ See supra Federal/State Division of Authority section.
    \510\ See West Virginia, 597 U.S. at 721.
    \511\ Id. at 722-23; see also id. at 721.
    \512\ See id. at 746 (Gorsuch, J., concurring) (quoting Whitman 
v. Am. Trucking Ass'ns, 531 U.S. 457, 468 (2001)); see also Nat'l 
Fed'n of Indep. Bus. v. Dep't of Lab., Occupational Safety & Health 
Admin., 595 U.S. 109, 125 (2022) (Gorsuch, J., concurring).
---------------------------------------------------------------------------

    172. In West Virginia, the Supreme Court held that EPA claimed a 
``newfound,'' ``transformative,'' ``extravagant,'' and ``unheralded'' 
\513\ authority to ``substantially restructure the American energy 
market'' by devising emission limitations that were based on EPA's 
judgment of how much coal-fired electricity generation should be in the 
overall mix of electricity generation.\514\ The Supreme Court concluded 
that this authority swept far beyond the ordinary understanding of 
EPA's purview, inserting the agency into areas into which it lacked 
technical expertise and in which it was required to make ``a very 
different kind of policy judgment.'' \515\ EPA did so against the 
backdrop of the significant policy questions involved that would 
ordinarily be addressed by Congress.\516\ In fact, the Supreme Court 
recognized that EPA's newly claimed authority

[[Page 97211]]

enabled it to enact a program addressing the dangers posed by 
greenhouse gas emissions even though Congress had considered (but 
rejected) legislative proposals to create such programs.\517\ Thus, in 
West Virginia, the Supreme Court confronted an EPA assertion of 
authority that it concluded was elephantine--surprising not just in 
scope, but also in character vis-[agrave]-vis EPA's ordinary regulatory 
role.
---------------------------------------------------------------------------

    \513\ West Virginia, 597 U.S. at 724; see also Util. Air Regul. 
Grp. v. EPA, 573 U.S. 302, 323-24 (2014) (UARG) (rejecting EPA's 
``enormous and transformative expansion in EPA's regulatory 
authority'' in ``discover[ing] in a long-extant statute an 
unheralded power'' to require certain permits for greenhouse gas 
emissions).
    \514\ West Virginia, 597 U.S. at 721, 724-25; see also Nat'l 
Fed'n of Indep. Bus., 595 U.S. at 117 (``The Secretary has ordered 
84 million Americans to either obtain a COVID-19 vaccine or undergo 
weekly medical testing at their own expense. This is no everyday 
exercise of federal power.'' (citation omitted)); UARG, 573 U.S. at 
321-22 (explaining that EPA itself acknowledged the ``calamitous 
consequences of interpreting the [Clean Air] Act in that way,'' 
thereby rendering the relevant provisions multiple orders of 
magnitude more burdensome and expensive); id. at 324 (``[W]e 
confront a singular situation: an agency laying claim to extravagant 
statutory power over the national economy while at the same time 
strenuously asserting that the authority claimed would render the 
statute `unrecognizable to the Congress that designed' it.'' 
(citation omitted)); Food & Drug Admin. v. Brown & Williamson 
Tobacco Corp., 529 U.S. 120, 159-60 (2000) (explaining that ``[t]his 
is hardly an ordinary case'' given that the FDA was now purporting 
to have authority that would allow it to outright ban tobacco 
products, notwithstanding the unique place such products have in 
American history and the existing regulatory scheme adopted by 
Congress).
    \515\ West Virginia, 597 U.S. at 728-29 (noting that, in this 
context, EPA was required to make judgments as to the reliability of 
the energy grid and the effects of its action on energy prices, such 
that EPA's exercise of authority required ``technical and policy 
expertise not traditionally needed in EPA regulatory development'' 
(quotation marks omitted)); see also Nat'l Fed'n of Indep. Bus., 595 
U.S. at 118 (``[N]o provision of the Act addresses public health 
more generally, which falls outside of OSHA's sphere of 
expertise.''); King v. Burwell, 576 U.S. 473, 485-86 (2015) 
(declining to defer to the Internal Revenue Service (IRS) 
interpretation of the Affordable Care Act's guarantee of tax credits 
for health insurance purchases, noting that that decisions about 
``health insurance policy'' fell beyond the IRS's zone of 
``expertise,'' making it ``especially unlikely that Congress would 
have delegated th[e] decision'' over tax credits ``to the IRS.'').
    \516\ West Virginia, 597 U.S. at 729-30; see also King, 576 U.S. 
at 485-86 (noting that the tax credits at issue ``involv[e] billions 
of dollars in spending each year and affect[ ] the price of health 
insurance for millions of people,'' the Court deemed their provision 
``a question of deep economic and political significance'' that 
Congress would not have implicitly delegated to the agency 
(quotation marks omitted)).
    \517\ West Virginia, 597 U.S. at 731-32 (``Congress, however, 
has consistently rejected proposals to amend the Clean Air Act to 
create such a program.''); see also Brown & Williamson, 529 U.S. at 
160 (adopting FDA's statutory interpretation required ignoring ``the 
plain implication of Congress' subsequent tobacco-specific 
legislation''); id. at 142-58.
---------------------------------------------------------------------------

    173. The Supreme Court concluded that EPA purported to find that 
authority in a statutory mousehole: the ``ancillary,'' ``backwater,'' 
``gap-filler'' authority in section 111(d) of the Clean Air Act, under 
which it was to identify the ``best system of emission reduction'' for 
existing stationary sources of air pollutants.\518\ Reflecting the 
ancillary nature of this provision, the Supreme Court noted that EPA 
had only used it a handful of times over more than four decades,\519\ 
and in doing so had uniformly based its regulatory approach on 
identifying systems that would reduce pollution by causing the 
regulated source to operate more cleanly.\520\ As a result, according 
to the Supreme Court, EPA's claim that it had authority to base 
emission limitations on its policy judgment regarding the appropriate 
generation resource mix ``was not only unprecedented; it also effected 
a fundamental revision of the statute, changing it from [one sort of] 
scheme of . . . regulation into an entirely different kind.'' \521\ The 
Supreme Court held that, to justify this power, EPA offered only a 
``vague statutory grant'' supported by such an expansive, acontextual 
reading of the ``definitional possibilities'' of the word ``system'' 
that accepting this construction would have rendered the statutory text 
an ``empty vessel.'' \522\
---------------------------------------------------------------------------

    \518\ West Virginia, 597 U.S. at 709-710 (noting that the 
``thrust of Section 111 focuses on emissions limits for new and 
modified sources'' rather than the existing sources that EPA was 
regulating under the challenged rule); id. at 730.
    \519\ Id. at 710-11 (``It was thus only a slight overstatement 
for one of the architects of the 1990 amendments to the Clean Air 
Act to refer to Section 111(d) as an `obscure, never-used section of 
the law.' '' (citation omitted)).
    \520\ Id. at 725-26 (citing EPA's view, in its inaugural 
rulemaking under this provision, that Congress in this provision 
intended a technology-based approach); see also Nat'l Fed'n of 
Indep. Bus., 595 U.S. at 118-19 (``It is telling that OSHA, in its 
half century of existence, has never before adopted a broad public 
health regulation of this kind . . . . [A] vaccine mandate is 
strikingly unlike the workplace regulations that OSHA has typically 
imposed.''); Brown & Williamson, 529 U.S. at 144 (noting FDA's 
``consistent and repeated statements'' that it lacked jurisdiction 
to regulate tobacco products).
    \521\ West Virginia, 597 U.S. at 728 (quotation marks omitted); 
see also Nat'l Fed'n of Indep. Bus., 595 U.S. at 117-18 (``The Act 
empowers the Secretary to set workplace safety standards, not broad 
public health measures.''); UARG, 573 U.S. at 322 (explaining that 
EPA itself recognized that the results of its statutory 
interpretation ``would be so `contrary to congressional intent,' and 
would so `severely undermine what Congress sought to accomplish,' 
that they necessitated as much as a 1,000-fold increase in the 
permitting thresholds set forth in the statute''); id. at 322-23 
(explaining how a ``brief review of the relevant statutory 
provisions leaves no doubt that the PSD program and Title V are 
designed to apply to, and cannot rationally be extended beyond, a 
relative handful of large sources capable of shouldering heavy 
substantive and procedural burdens''); MCI Telecomms. Corp. v. Am. 
Tel. & Telegraph Co., 512 U.S. 218, 234 (1994) (``[FCC's statutory 
interpretation] is effectively the introduction of a whole new 
regime of regulation (or of free-market competition), which may well 
be a better regime but is not the one that Congress established.''); 
cf. Brown & Williamson, 529 U.S. at 156 (``Under these 
circumstances, it is clear that Congress' tobacco-specific 
legislation has effectively ratified the FDA's previous position 
that it lacks jurisdiction to regulate tobacco.'').
    \522\ West Virginia, 597 U.S. at 732; see also Brown & 
Williamson, 529 U.S. at 160 (explaining that FDA's statutory 
interpretation required adopting ``an extremely strained 
understanding of `safety' as it is used throughout the Act'' even 
though the concept is ``central to the [Act's] regulatory scheme''); 
MCI, 512 U.S. at 229-34 (rejecting agency interpretation concluding 
that a statutory provision authorizing the FCC to ``modify'' the 
provisions of 47 U.S.C. 203 authorized the agency to make ``radical 
or fundamental changes to the statutory requirements'').
---------------------------------------------------------------------------

    174. West Virginia thus reflects the sort of ``extraordinary case'' 
meriting application of the major questions doctrine and illustrating 
the factors relevant to that inquiry. Moreover, West Virginia and other 
cases in this area reflect that application of that doctrine does not 
boil down to a facile examination, divorced from the statutory context, 
of the agency action at issue. The major questions doctrine does not 
provide, for example, that courts should find that an agency action 
requires express Congressional authorization based simply on the 
economic consequences of that action, the fact that the agency is 
addressing a significant problem, or the sector of industry that the 
agency is regulating. As the Fourth Circuit recently explained, while 
the ``doctrine applies only when the question at issue--i.e., the 
authority the agency is claimed to have--is a major one,'' that is a 
necessary, not a sufficient, condition triggering the doctrine's 
application.\523\ ``The [Supreme] Court has highlighted several other 
[relevant] hallmarks,'' such as (1) whether the statute's ``structure 
indicates that Congress did not mean to regulate the issue in the way 
claimed,'' \524\ (2) whether a ```distinct regulatory scheme' [is] 
already in place to deal with the issue which would conflict with the 
agency's newly asserted authority,'' \525\ (3) where the agency has 
``fail[ed] to invoke the[ ] [asserted powers] previously,'' (4) where 
the ``asserted authority falls outside the agency's traditional 
expertise,'' and (5) where the ``asserted authority . . . is found in 
an `ancillary provision.' '' \526\ As discussed below, none of these 
``hallmarks'' is present here.
---------------------------------------------------------------------------

    \523\ N.C. Coastal Fisheries Reform Grp. v. Capt. Gaston LLC, 76 
F.4th 291, 296-97 (4th Cir. 2023).
    \524\ Id.
    \525\ Id. (quoting Brown & Williamson, 529 U.S. at 143-46).
    \526\ Id. (quoting Whitman v. Am. Trucking Ass'ns, Inc., 531 
U.S. at 468).
---------------------------------------------------------------------------

    175. We continue to conclude that the major questions doctrine does 
not apply to Order No. 1920.\527\ The Commission's authority under FPA 
section 206 is no statutory ``mousehole.'' Far from being an 
``ancillary,'' ``back-water,'' or ``gap-filler'' provision as the court 
referenced in West Virginia, FPA section 206 sets forth core Commission 
regulatory authority to remedy unjust and unreasonable rates, and 
practices affecting rates, for the transmission of electric energy in 
interstate commerce.\528\ As discussed above, the Commission's action 
in Order No. 1920 falls well within the ordinary understanding of its 
statutory authority under this provision, as it is regulating practices 
directly affecting such rates,\529\ such that Order No. 1920 does not 
involve converting the authority set forth to regulate such practices 
into a new kind of regulatory scheme.\530\ By the same token, since it 
is based on this core statutory authority, Order No. 1920 also does not 
involve invoking definitional possibilities to stretch a statutory term 
or phrase (e.g., ``system''

[[Page 97212]]

in West Virginia) to its limits, thereby stripping the relevant term of 
meaning.
---------------------------------------------------------------------------

    \527\ Order No. 1920, 187 FERC ] 61,068 at PP 275-279.
    \528\ 16 U.S.C. 824e(a); see S.C. Pub. Serv. Auth. v. FERC, 762 
F.3d at 56 (explaining that the Commission's authority under FPA 
section 206 is ``broadly stated and the only question is what limits 
are fairly implied''; this provision is not a ``subtle device''); 
id. at 55 (``The text does not define `practice,' although use of 
the word `any' amplifies the breadth of the delegation to the 
Commission.''); cf. N.Y. v. FERC, 535 U.S. at 15 (upholding Order 
No. 888, noting that the Supreme Court has ``construed broadly'' the 
Commission's jurisdiction under FPA section 201).
    \529\ See supra Order No. 1920 Is Consistent with the FPA and 
Precedent Regarding the Commission's Authority section (discussing 
the application of EPSA and related precedent to Order No. 1920 as 
confirming that the Commission is acting within its authority).
    \530\ See EPSA, 577 U.S. at 290 (``ensur[ing] effective 
transmission of electric power'' is one of the ``core objects'' of 
the FPA); S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 57.
---------------------------------------------------------------------------

    176. Also, unlike the provision at issue in West Virginia, FPA 
section 206 is not a rarely used provision; the Commission has acted 
under this authority countless times, including in significant 
rulemakings. This includes the Commission's landmark Order No. 888, in 
which the Commission addressed fundamental shifts in the landscape of 
the electric industry by requiring functional unbundling of wholesale 
generation and transmission services and imposing a similar open access 
requirement on unbundled retail transmission in interstate 
commerce,\531\ as well as oversight of those processes and cost 
allocation via more targeted FPA section 206 complaints and Commission-
initiated FPA section 206 proceedings.\532\ The Supreme Court upheld 
Order No. 888 order, underscoring the breadth of the Commission's 
authority under FPA section 206. The Commission's exercise of this 
authority in the field of transmission planning processes and cost 
allocation is, itself, far from unprecedented considering the 
Commission's issuance of Order Nos. 890 and 1000, upon which Order No. 
1920 now builds.\533\ In Order No. 890, the Commission required--among 
other things--that public utility transmission providers' local 
transmission planning processes satisfy nine transmission planning 
principles to ensure that transmission planning processes were just and 
reasonable and not unduly discriminatory and preferential.\534\ The 
Commission's next step, Order No. 1000, sought to further ensure that 
transmission planning and cost allocation requirements embodied in the 
pro forma OATT could facilitate the development of more efficient or 
cost-effective regional transmission facilities.\535\ Order No. 1920 is 
a continuation of these prior efforts to ensure that transmission 
planning and cost allocation processes support the reliable and cost-
effective operation of the transmission grid, by addressing identified 
deficiencies in those processes that render Commission-jurisdictional 
rates unjust and unreasonable.
---------------------------------------------------------------------------

    \531\ See N.Y. v. FERC, 535 U.S. at 11, 17.
    \532\ See, e.g., Pub. Serv. Elec. & Gas Co. v. FERC, 989 F.3d 
10, 15 (D.C. Cir. 2021) (denying petitions for review of Commission 
order, under FPA section 206, regarding cost allocation for the 
Artificial Island Project); Coal. of MISO Transmission Customers v. 
Midcontinent Indep. Sys. Operator, Inc., 172 FERC ] 61,099, 61,770 
(2020) (denying complaint, under FPA section 206, challenging MISO's 
location-based cost allocation method for Baseline Reliability 
Projects); City Utilities of Springfield, Mo. v. Sw. Power Pool, 
Inc., 168 FERC ] 61,085, 61,467 (2019) (denying complaint, under FPA 
section 206, asserting that SPP's administration of the unintended 
consequences review process for SPP's allocation of the costs of 
transmission facilities was unjust, unreasonable, unduly 
discriminatory, or preferential); N. Ind. Pub. Serv. Co. v. 
Midcontinent Indep. Sys. Operator, Inc., 155 FERC ] 61,058 (2016) 
(granting in part and denying in part a complaint under FPA section 
206 requesting that the Commission reform the interregional 
transmission planning process of the Joint Operating Agreement 
between MISO and PJM); Monongahela Power Co., 156 FERC ] 61,134 
(2016) (instituting a proceeding under FPA section 206 to determine 
whether PJM transmission owners are complying with their Order No. 
890 transmission planning obligations), order accepting in part 
proposed tariff revisions and requiring tariff revisions, 162 FERC ] 
61,129 (2018).
    \533\ See Order No. 1920, 187 FERC ] 61,068 at PP 14-19, 47-48, 
255; S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 58 (``Commission-
mandated transmission planning is not new. [Order No. 1000] builds 
on Order No. 890's requirements in light of changed circumstances 
and is simply the next step in a series of related reforms that 
began no later than Order No. 888.'' (citation omitted)).
    \534\ See Order No. 890, 118 FERC ] 61,119 at PP 418-601 
(requiring, among other things, that local transmission planning 
processes satisfy nine transmission planning principles: (1) 
coordination; (2) openness; (3) transparency; (4) information 
exchange; (5) comparability; (6) dispute resolution; (7) regional 
participation; (8) economic planning studies; and (9) cost 
allocation for new projects); Order No. 1920, 187 FERC ] 61,068 at 
PP 14, 277.
    \535\ Order No. 1000, 136 FERC ] 61,051 at PP 11-12, 42-44; 
Order No. 1000-A, 139 FERC ] 61,132 at PP 3-6; see also Order No. 
1920, 187 FERC ] 61,068 at P 16 (``The reforms in Order No. 1000 
included: (1) regional transmission planning; (2) transmission needs 
driven by Public Policy Requirements; (3) nonincumbent transmission 
developer reforms; (4) regional and interregional cost allocation, 
including a set of principles for each category of cost allocation; 
and (5) interregional transmission coordination. The reforms focused 
on the process by which transmission providers engage in regional 
transmission planning and the associated cost allocation rather than 
on the outcomes of the process.'').
---------------------------------------------------------------------------

    177. Turning to the agency action at issue, Order No. 1920 is not 
an ``elephant'': while it addresses a significant problem, it does so 
through an improvement of the already existing Commission-
jurisdictional regional transmission planning and cost allocation 
processes, building on and consistent with the Commission's exercise of 
authority in past actions,\536\ and is not aimed at areas of reserved 
state authority. Rehearing requests arguing to the contrary--and 
particularly those claiming that the Commission is attempting to 
control or influence the resource mix or install itself as a national 
integrated resource planner--are based on mischaracterizations or 
misunderstandings of Order No. 1920, as discussed above.\537\ Order No. 
1920 is well within the Commission's ordinary remit and technical 
expertise of regulating practices affecting interstate transmission 
rates, unlike the cases discussed above which involved agency forays 
into areas well beyond their ordinary purview, such as EPA regulating 
the generation resource mix, Occupational Safety and Health 
Administration (OSHA) regulating the general public health, or the IRS 
addressing health insurance policy. Nor is this an instance in which 
the Commission has acted against a backdrop of contrary congressional 
action.\538\
---------------------------------------------------------------------------

    \536\ See Order No. 1920, 187 FERC ] 61,068 at P 278 (describing 
the rule as implementing ``incremental process improvements'').
    \537\ See supra Federal/State Division of Authority section.
    \538\ Arguments to the contrary suggesting, for example, that 
the Commission is attempting to implement the ``Green New Deal,'' 
rest on the incorrect premise that the Commission is attempting to 
preferentially favor renewable resources or influence the generation 
mix. Moreover, even the references cited in the rehearing requests 
describe the ``Green New Deal'' as a broad set of goals aimed at 
achieving net zero carbon emissions, without specific policies, 
rather than a specific proposal to enact the sort of transmission 
planning process and cost allocation reforms at issue in Order No. 
1920. See, e.g., Arizona Commission Rehearing Request at 4-5.
---------------------------------------------------------------------------

    178. Moreover, the Commission in Order No. 1920 acted in a 
fundamentally responsive capacity to require more effective 
transmission planning processes and cost allocation to ensure cost-
effective and reliable Long-Term Regional Transmission Planning in 
light of preexisting forces beyond the Commission's control that give 
rise to transmission needs.\539\ This stands in contrast to cases in 
which the Supreme Court has applied the major questions doctrine, which 
involved agency actions that, in themselves, affirmatively and 
proactively caused the transformative consequences that the Court 
identified as demonstrative of extravagant exercises of agency 
power.\540\ For similar reasons, it is incorrect to ascribe to Order 
No. 1920, which aims to ensure that Long-Term Transmission Needs are 
met more efficiently and cost-effectively, the economic consequences 
associated with the construction of new transmission infrastructure, as 
the need for this infrastructure would still exist independent of Order 
No. 1920.\541\
---------------------------------------------------------------------------

    \539\ See supra Federal/State Division of Authority section 
(noting that these forces would continue to exist, driving 
transmission needs, even absent Commission action).
    \540\ See, e.g., West Virginia, 597 U.S. at 721, 724-25 
(addressing EPA rule seeking to ``substantially restructure the 
American energy market''); Nat'l Fed'n of Indep. Bus., 595 U.S. at 
117 (addressing agency rule requiring vaccination or medical 
testing); UARG, 573 U.S. at 321-22 (addressing agency change in 
statutory interpretation subjecting millions of sources to 
permitting requirements).
    \541\ See Order No. 1920, 187 FERC ] 61,068 at P 278 (``The 
incremental process improvements required by the final rule, 
however, do not fundamentally change the economic or political 
stakes of ensuring that Commission-jurisdictional rates remain just 
and reasonable.''); id. PP 92-93; S.C. Pub. Serv. Auth. v. FERC, 762 
F.3d at 51 (noting the expense associated with construction of 
transmission infrastructure at the time of the promulgation of Order 
No. 1000). No case applying the major questions doctrine has done so 
solely based on the economic consequences of the agency action at 
issue or suggested that agencies are not empowered to address 
significant problems falling within their general grants of 
statutory authority. Cf., e.g., N.Y. v. FERC, 535 U.S. at 11, 17 
(affirming Commission order adopting reforms restructuring 
electricity markets); Flyers Rts. Educ. Fund, Inc. v. U.S. Dep't of 
Transp., 810 F. App'x 1, 3 (D.C. Cir. 2020) (explaining that FCC v. 
Fox Television Stations, Inc., 556 U.S. 502 (2009) ``permits, but 
does not require, an agency to act incrementally''); WildEarth 
Guardians v. EPA, 751 F.3d 649, 655-56 (D.C. Cir. 2014) (summarizing 
Defs. of Wildlife v. Gutierrez, 532 F.3d 913 (D.C. Cir. 2008), 
upholding a decision to focus on a comprehensive approach). Creating 
such a rule would be inconsistent with the Supreme Court's 
discussion of the history of the major questions doctrine reflecting 
its application only in extraordinary cases, and then only upon a 
detailed consideration of the statutory context. See West Virginia, 
597 U.S. at 721.

---------------------------------------------------------------------------

[[Page 97213]]

    179. In particular, arguments asserting that Order No. 1920 will 
impose ``billions or trillions of dollars in transmission cost[s]'' 
\542\ claims that attempt to link the transmission costs of achieving a 
``net zero'' carbon emission policy as ``caused by Order No. 1920'' 
\543\ are not supported by the record and, instead, depend entirely on 
an unfounded logical leap. These arguments incorrectly portray the 
consequences of decisions made by other actors,\544\ which represent 
preexisting and independent forces driving transmission needs that are 
outside of the Commission's control,\545\ as attributable to Order No. 
1920. As noted above, such arguments fundamentally reverse cause and 
effect by mischaracterizing Order No. 1920's process-focused 
requirements that transmission providers adequately plan for these 
drivers of Long-Term Transmission Needs--which requirements do not seek 
to achieve any substantive outcome or direct the construction of any 
particular transmission facilities--as causing these transmission 
needs.\546\ This has no basis in fact. The drivers of these 
transmission needs (including those that flow from the policy decisions 
of actors lawfully entitled to make such choices) and the costs 
associated with building transmission infrastructure to meet such needs 
will exist independent of Order No. 1920's requirements. Indeed, 
because a major focus of Order No. 1920 is ensuring that more efficient 
or cost-effective transmission facilities are evaluated and selected, 
not only would these needs still exist absent the Commission's action 
but we expect that meeting these needs would impose higher costs on 
ratepayers.
---------------------------------------------------------------------------

    \542\ Undersigned States Rehearing Request at 15; see Designated 
Retail Regulators Rehearing Request at 15-16.
    \543\ Arizona Commission Rehearing Request at 16.
    \544\ In particular, Order No. 1920 is neutral on the policy 
choices that may drive certain of these decisions, including whether 
``net zero'' is an appropriate policy goal; these questions are not 
for the Commission to resolve.
    \545\ See supra Order No. 1920 Does Not Attempt to Control the 
Generation Mix or Intrude in Areas of State Authority section 
(explaining that Order No. 1920 is resource neutral, treating these 
exogenous forces that drive Long-Term Transmission Needs as inputs 
to Long-Term Regional Transmission Planning).
    \546\ See supra Order No. 1920 Does Not Attempt to Control the 
Generation Mix or Intrude in Areas of State Authority section.
---------------------------------------------------------------------------

    180. We therefore continue to conclude that Order No. 1920 is not a 
transformative exercise of Commission authority, whether in magnitude 
or character, and FPA section 206 is not a surprising basis for the 
Commission's action, meaning that the major questions doctrine does not 
apply here.\547\ The Supreme Court's decision in EPSA and D.C. Circuit 
decisions in California Independent System Operator v. FERC \548\ and 
South Carolina Public Service Authority v. FERC further confirm the 
inapplicability of the major questions doctrine to Order No. 1920. Each 
of those cases addressed the scope of the Commission's authority under 
FPA section 206 over ``practice[s] . . . affecting'' rates, the same 
grant of statutory authority supporting issuance of Order No. 1920, and 
are thus of particular significance here.\549\
---------------------------------------------------------------------------

    \547\ Order No. 1920, 187 FERC ] 61,068 at PP 278-279.
    \548\ 372 F.3d 395 (D.C. Cir. 2004) (CAISO).
    \549\ See EPSA, 577 U.S. at 277-78; S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d at 56-57; CAISO, 732 F.3d at 399-404.
---------------------------------------------------------------------------

    181. In EPSA and CAISO, the Courts' statutory construction limiting 
the Commission to regulating practices ``directly affecting'' rates was 
motivated by the same concern animating the major questions doctrine: 
effectuating congressional intent by ensuring that the Commission's 
exercise of this authority was reasonably constrained by more than the 
definitional possibilities as to what constitutes a ``practice . . . 
affecting'' rates.\550\ South Carolina Public Service Authority v. FERC 
considered the scope of this authority as applied to the same context 
presented here, transmission planning and cost allocation processes, in 
reviewing the highly similar Order No. 1000. The court held that 
``[r]eforming the practices of failing to engage in regional planning 
and ex ante cost allocation for development of new regional 
transmission facilities is not the kind of interpretive `leap' that 
concerned the court in CAISO but rather involves a core reason 
underlying Congress' instruction in [FPA] Section 206.'' \551\ It 
likewise distinguished MCI--one of the cases the Supreme Court in West 
Virginia discussed as part of the lineage of the major questions 
doctrine--holding that FPA section 206 ``cannot be fairly viewed as the 
type of `subtle device' at issue'' in that case.\552\
---------------------------------------------------------------------------

    \550\ See EPSA, 577 U.S. at 277-78 (adopting the ``directly 
affecting'' construction of FPA section 206(a) because ``[t]aken for 
all it is worth, that statutory grant could extend FERC's power to 
some surprising places'' given that markets in all of electricity's 
inputs might affect the supply of power and ``markets in just about 
everything'' might affect load-serving entities' demand); CAISO, 372 
F.3d at 400 (explaining that ambiguity, in statutory construction, 
is not a creature of definitional possibilities but of statutory 
context); id. at 401 (rejecting the argument that there is an 
``infinitude of acceptable definitions for what constitutes a 
`practice' to give [the Commission] the authority to regulate 
anything done by or connected with a regulated utility, as any act 
or aspect of such an entity's corporate existence could affect, in 
some sense, the rates'').
    \551\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 57.
    \552\ Id. at 56.
---------------------------------------------------------------------------

    182. Thus, EPSA and CAISO reflect that the Supreme Court and the 
D.C. Circuit already have construed the statutory grant of authority to 
the Commission over practices affecting rates in FPA section 206 as 
imposing guardrails to ensure consistency with congressional intent and 
to avoid the use of this authority in ways that would implicate the 
major questions doctrine. South Carolina Public Service Authority v. 
FERC, in turn, applied these guardrails in the same context as Order 
No. 1920 and found that the Commission was acting within its statutory 
authority to address ``a core reason underlying Congress' instruction 
in [FPA] Section 206.'' \553\ Particularly given the major questions 
doctrine's focus on discerning congressional intent as to the scope of 
a legislative delegation,\554\ these cases further support our 
conclusion (in addition to the discussion already set forth) that the 
major questions doctrine does not require enhanced skepticism of Order 
No. 1920.\555\
---------------------------------------------------------------------------

    \553\ Id. at 57.
    \554\ See West Virginia, 597 U.S. at 721-23.
    \555\ See supra Order No. 1920 Is Consistent with the FPA and 
Precedent Regarding the Commission's Authority section (explaining, 
as discussed in Order No. 1920 and not disputed on rehearing, that 
Order No. 1920 is consistent with the Supreme Court's decision in 
EPSA).
---------------------------------------------------------------------------

    183. We are, therefore, unpersuaded by arguments that the major 
questions doctrine should apply to Order No. 1920. Claims that Order 
No. 1920 presents a major question because the Commission has 
overstepped the jurisdictional boundaries set forth in the FPA and 
intruded into areas of state

[[Page 97214]]

authority \556\ are mistaken because the Commission has acted well 
within its authority to regulate practices affecting interstate 
transmission rates, honoring the jurisdictional divide set forth by 
Congress in the FPA.\557\ Arguments that the Commission is misusing the 
FPA to enact preferential policies \558\ are misplaced for the same 
reasons. As already discussed, arguments invoking the purported 
economic consequences of Order No. 1920 \559\ misattribute the costs of 
constructing transmission infrastructure to Order No. 1920. Regardless, 
while the economic impact is relevant to this inquiry, the major 
questions doctrine is a nuanced, context-specific doctrine that does 
not require clear congressional authorization for every agency action 
that may have significant economic consequences or addresses a 
significant problem.\560\
---------------------------------------------------------------------------

    \556\ See Undersigned States Rehearing Request at 14-15 (citing 
Ala. Ass'n of Realtors v. HHS, 594 U.S. at 764 (finding that one 
consideration favoring application of the major questions doctrine 
was that the agency action ``intrudes into an area that is the 
particular domain of state law: the landlord-tenant 
relationship'')); id. at 16 (arguing that the Commission was 
attempting to determine ``what resources should be powering the grid 
twenty years into the future''); Designated Retail Regulators 
Rehearing Request at 15-19 (similar); Arizona Commission Rehearing 
Request at 5-6; Utah Commission Rehearing Request at 7-8; cf. Ohio 
Commission Federal Advocate Rehearing Request at 20 (``FERC points 
to no `clear congressional authorization' for it to use its power 
under the FPA to facilitate federal, state, Tribal, local, and 
corporate policies. . . .'').
    \557\ See supra Federal/State Division of Authority section; 
Order No. 1920, 187 FERC ] 61,068 at PP 263-267. We also reiterate, 
in response to arguments that the Supreme Court in West Virginia 
found it `` `highly unlikely that Congress would leave to agency 
discretion the decision of how much . . . generation there should be 
over the coming decades' on a resource-by-resource basis,'' 
Undersigned States Rehearing Request at 15 (quoting West Virginia, 
597 U.S. at 729; also citing ``the breadth of the transmission grid 
[and] the importance of electricity in everyday life''), that ``the 
Court did not determine that energy policy and the mix of generation 
resources are in every instance a major question.'' Order No. 1920, 
187 FERC ] 61,068 at P 276; see also id. PP 277-278. In any event, 
Order No. 1920 still would not implicate the major questions 
doctrine because it is not aimed at this end.
    \558\ See Undersigned States Rehearing Request at 16-17; 
Designated Retail Regulators Rehearing Request at 16-17; Arizona 
Commission Rehearing Request at 3 n.2, 4, 20.
    \559\ See Undersigned States Rehearing Request at 14-15; 
Designated Retail Regulators Rehearing Request at 15-16; Utah 
Commission Rehearing Request at 8; cf. Arizona Commission Rehearing 
Request at 16 (citing the cost of achieving net-zero on the 
transmission grid).
    \560\ See id.; cf. also Arizona Commission Rehearing Request at 
6 (``Under West Virginia, a major doctrinal change in the law, and 
the making of a federal rule that fundamentally reshapes policy, has 
to be done pursuant to an express statement of Congress''); Idaho 
Commission Rehearing Request at 6.
---------------------------------------------------------------------------

    184. We also are not persuaded by SERTP Sponsors' arguments that, 
unless the Commission grants its requests for clarification, Order No. 
1920 runs afoul of the major questions doctrine, encroaches on state 
jurisdiction, or otherwise exceeds the Commission's authority. SERTP 
Sponsors do not clearly set forth the basis for many of their purported 
concerns regarding the Commission's statutory authority or application 
of the major questions doctrine, or even which arguments raise these 
concerns. For instance, while SERTP Sponsors identify Sections II.A.1 
and II.C.3 of their argument as particularly raising these 
concerns,\561\ in their Statement of Issues they more broadly state 
that the clarifications in ``Sections II.A and II.C'' of their argument 
are necessary to avoid intruding into state jurisdiction or application 
of the major questions doctrine.\562\ But it is far from clear, and 
SERTP Sponsors do not explain, why many of the requested clarifications 
in Sections II.A and II.C would be necessary to avoid SERTP Sponsors' 
stated concerns about the Commission failing to afford adequate respect 
to state-approved integrated resource plans and load-serving entities' 
supply obligations or otherwise implicate concerns that the Commission 
is intruding into state jurisdiction.\563\ Certain of SERTP Sponsors' 
other claims that, absent clarification, other aspects of Order No. 
1920 would exceed the Commission's authority, are single-sentence 
assertions that provide little or nothing to illuminate why they 
believe this is the case.\564\
---------------------------------------------------------------------------

    \561\ SERTP Sponsors Rehearing Request at 39; see also id. at 
41, 43 (issue statements 1 and 15).
    \562\ Id. at 44-45.
    \563\ See, e.g., id. at 7-8 (arguing that states should be 
allowed to lengthen the time, upon agreement or motion, to reach an 
agreement as to cost allocation method); id. at 8 (requesting 
clarification on voluntary funding opportunities); id. at 11-12 
(arguing that Long Term Transmission Needs have been defined in a 
circular fashion and that transmission providers should have 
discretion to use their expertise where they lack certain 
information); id. at 12-17 (requesting clarification that the 
factors affecting a single assumption will not necessarily have an 
additive effect; clarification on how specific factors will be 
identified; clarification on whether the Commission has expanded 
what constitutes legally binding obligations; and rehearing 
regarding adoption of Factor Category Seven).
    \564\ See id. at 41 (``Absent the requested clarification in 
section II.A.2, the six-month period permitted for states to 
negotiate an extension of the time period [sic] for negotiating ex 
ante or ex post state agreements on cost allocation, Order No. 1920 
is contrary to FPA section 201, is ultra vires, and arbitrary and 
capricious''); id. (``Absent the requested clarification in section 
II.A.3, Order No. 1920 is contrary to FPA section 201 because it 
effectively mandates selection and/or construction of an LTRTF.''); 
id. at 43 (``Absent the clarifications requested in section 
II.C.2.d, requiring the utilization of Factor Category Seven 
intrudes into matters involving retail customers subject to state 
regulation, thereby being ultra vires and contrary to FPA section 
201.'').
---------------------------------------------------------------------------

    185. We address SERTP Sponsors' requests for clarification on their 
substance at various points in our discussion below. In several 
instances, we find that SERTP Sponsors have failed to plead their 
arguments that, absent their requested clarification, the Commission 
has exceeded its authority with the specificity required on rehearing, 
and we reject them on that basis.\565\ Regardless, to the extent that 
we do not grant those requests for clarification, whether in whole or 
in part, we find that the explanations in Order No. 1920 and herein 
establishing that Order No. 1920 is within the Commission's authority, 
does not unlawfully intrude into state areas of reserved authority, and 
does not implicate the major questions doctrine render SERTP Sponsors' 
arguments to the contrary unpersuasive. Where we believe further 
additional explanation is warranted in response to addressing a 
specific request for clarification made by SERTP Sponsors, we provide 
that explanation in conjunction with addressing the relevant request 
for clarification.
---------------------------------------------------------------------------

    \565\ See ZEP Grand Prairie Wind, LLC, 183 FERC ] 61,150, at P 
10 (2023); see also Ind. Util. Regul. Comm'n v. FERC, 668 F.3d 735, 
736 (D.C. Cir. 2012).
---------------------------------------------------------------------------

D. Other Issues

1. Requests for Rehearing
    186. Several of the parties seeking rehearing argue that Order No. 
1920 is not supported by the D.C. Circuit's decision in South Carolina 
Public Service Authority v. FERC, asserting that the Commission has 
attempted to direct substantive outcomes affecting the generation 
resource mix. Arizona Commission contends that Order No. 1000 
``confined mandatory consideration [of factors affecting transmission 
needs] to pertinent laws and regulations, whereas Order No. 1920 now 
mandates consideration of broader `policy goals,''' which are ``more 
nebulous political agendas susceptible to significant fluctuations.'' 
\566\ It contends that the Commission ``is not authorized to compel 
Arizona to use

[[Page 97215]]

specific energy resources.'' \567\ Montana Commission, West Virginia 
Commission, and Wyoming Commission argue that Order No. 1000 was upheld 
in South Carolina Public Service Authority v. FERC because of its light 
touch, which did not mandate a ``backstop'' ex ante cost allocation 
method to a voluntary state agreement, whereas Order No. 1920 has 
placed states in the untenable position of either agreeing to unjust 
and unreasonable cost allocations or having that burden foisted on them 
by default.\568\ They further assert that Order No. 1920's ``influence 
over the selection of transmission projects will inevitably affect 
resource planning and selection at the state level,'' invading the 
jurisdiction of the states.\569\ Utah Commission argues that Order No. 
1920, unlike Order No. 1000, ``patently dictates outcomes and cost 
allocation and does so to discriminate and favor the policy preferences 
of certain preferred stakeholders.'' \570\
---------------------------------------------------------------------------

    \566\ Arizona Commission Rehearing Request at 12-13 (arguing 
also that Arizona law ``does not allow the [Arizona Commission] to 
adopt, create, or mandate energy policy goals, and Order No. 1920's 
effort to compel the [Arizona Commission] to do so is unlawful'' and 
that Order No. 1920's approach will lead to unjust cost allocations 
wherein states without renewable policy objectives must absorb costs 
generated by the transmission of renewable energy).
    \567\ Id. at 13.
    \568\ See Montana Commission Rehearing Request at 2-4; West 
Virginia Commission Rehearing Request at 10-12; Wyoming Commission 
Rehearing Request at 2-4.
    \569\ See Montana Commission Rehearing Request at 4; West 
Virginia Commission Rehearing Request at 12; Wyoming Commission 
Rehearing Request at 4.
    \570\ Utah Commission Rehearing Request at 8 n.17.
---------------------------------------------------------------------------

    187. Undersigned States and Designated Retail Regulators argue that 
Order No. 1920 ``mandates transmission planning criteria that 
marginalize the input from Relevant Electric Retail Regulatory 
Authorit[ies] [(RERRAs)] in transmission planning, instead favoring 
selected generation.'' \571\ In particular, they argue that Order No. 
1920 adopts monolithic nationwide criteria that remove the states' role 
in planning and cost allocation, and that those criteria are ``designed 
to allow the preferred policy goals of certain states, utilities, and 
corporate interests to dictate transmission planning for all,'' rather 
than prioritizing reliability and consumer impacts.\572\ Similarly, 
Georgia Commission argues that Order No. 1920 ``violates the states' 
reserved decision-making power by requiring that the states measure 
their long-term transmission plans against seven factors identified in 
the Order.'' \573\
---------------------------------------------------------------------------

    \571\ Undersigned States Rehearing Request at 7-8; see id. at 
24-26; Designated Retail Regulators Rehearing Request at 8, 24-26.
    \572\ Undersigned States Rehearing Request at 24; id. at 26 
(``With its rigid planning and cost allocation criteria, the Rule 
will result in the imposition of massive transmission costs 
necessary to accomplish certain states' policy goals upon other 
states.''); Designated Retail Regulators Rehearing Request at 24-26 
(similar).
    \573\ Georgia Commission Rehearing Request at 4.
---------------------------------------------------------------------------

    188. Relatedly, Montana Commission, West Virginia Commission, and 
Wyoming Commission argue that Order No. 1920 undermines states' role in 
transmission planning and ratemaking, and does not result in just and 
reasonable rates.\574\ In particular, they assert that under Order No. 
1920, transmission providers would be required to plan projects while 
considering the policy goals of various states (e.g., decarbonization), 
such that ``the leading transmission projects may not be the most 
economical, let alone necessary, but for the policy goals of other 
states.'' \575\ They contend that the costs allocated to retail 
customers may exceed the benefits that state policy recognizes from 
regional transmission projects, such that state commissions ``would be 
forced to either assign unjust and unreasonable rates to retail 
customers, or deny the utility a potentially significant portion of its 
expected cost recovery.'' \576\ Arizona Commission argues that Order 
No. 1920 usurps state authority mandating that it ``apply rates that 
are fair and reasonable and not to cost share with rate payers who did 
not cause (and do not benefit from) a particular cost.'' \577\
---------------------------------------------------------------------------

    \574\ See Montana Commission Rehearing Request at 6-7 (arguing 
that a significant share of the costs of transmission facilities are 
allocated to retail customers, a question which is best left to the 
expertise of the states); West Virginia Commission Rehearing Request 
at 9-10; Wyoming Commission Rehearing Request at 6-8.
    \575\ See Montana Commission Rehearing Request at 6-7; West 
Virginia Commission Rehearing Request at 9-10; Wyoming Commission 
Rehearing Request at 7-8.
    \576\ Montana Commission Rehearing Request at 6-7 (noting that 
the Montana Commission typically conducts post hoc rather than ex 
ante rate reviews and that it is not clear that Order No. 1920 is 
designed to accommodate this process); West Virginia Commission 
Rehearing Request at 9-10; Wyoming Commission Rehearing Request at 
7-8.
    \577\ Arizona Commission Rehearing Request at 20-22 (claiming 
that Order No. 1920 ``usurps the Arizona Constitution and its 
methodology'' because it ``provides several factors that must be 
considered in transmission planning and cost allocation'' which 
``include neither the fairness nor reasonableness of the costs nor 
any consideration of who causes the costs mandated by the FPA'').
---------------------------------------------------------------------------

    189. Arizona Commission also states that it owes its existence to 
the Arizona Constitution and that it has plenary power to set just and 
reasonable rates and charges collected by public service 
corporations.\578\ It asserts that even the Arizona state legislature 
is ``precluded by state constitutional law from legislating rate making 
decisions,'' and contends that, by the same token, the federal 
government ``is certainly precluded from directing Arizona utilities to 
adopt energy plans that could cost hundreds of billions of dollars to 
Arizona consumers.'' \579\
---------------------------------------------------------------------------

    \578\ Id. at 7-9.
    \579\ Id. at 8-9.
---------------------------------------------------------------------------

    190. On rehearing, Undersigned States again argue that Order No. 
1920 is beyond the Commission's authority because, if the FPA were 
interpreted to authorize the rule, it ``would likely violate the 
Constitution's equal sovereignty doctrine.'' \580\ They argue that 
Order No. 1920 ``sets up a scheme where one state can effectively 
require other states to subsidize their own public policy agenda--a 
core, sovereign state function.'' \581\ Undersigned States also now 
bring a single sentence argument that ``even if the Rule were supported 
by statutory authorization . . . then it would violate the 
nondelegation doctrine,'' on the theory that Congress is entirely 
precluded from delegating any ``major policy question[s]'' to 
agencies.\582\
---------------------------------------------------------------------------

    \580\ Undersigned States Rehearing Request at 18-19.
    \581\ Id. (arguing that Order No. 1920 subverts the democratic 
process, encroaches on state prerogatives, and is inconsistent with 
principles of cooperative federalism (citing Coyle v. Smith, 221 
U.S. 559, 567 (1911); Franchise Tax Bd. v. Hyatt, 578 U.S. 171, 179 
(2016); Stearns v. Minn., 179 U.S. 223, 245 (1900); Shelby Cnty. v. 
Holder, 570 U.S. 529, 544 (2013)).
    \582\ Id. at 17-18 (citing Paul v. U.S., 140 S. Ct. 342, 342 
(2019) (Mem.) (Kavanaugh, J., statement respecting denial of 
certiorari); Indus. Union Dep't, AFL-CIO v. Am. Petroleum Inst., 448 
U.S. 607, 685-86 (1980) (Rehnquist, J., concurring in judgment); 
A.L.A. Schechter Poultry Corp. v. U.S., 295 U.S. 495 (1935)).
---------------------------------------------------------------------------

    191. Ohio Commission Federal Advocate contends that in issuing 
Order No. 1920 the Commission has violated the Commerce Clause because 
Commission authority ``does not reach . . . attempts to use it to 
assist utilities and corporations with meeting their goals and 
commitments.'' \583\ It particularly asserts that ``[t]he U.S. Supreme 
Court has held that in the absence of federal legislation, commerce is 
generally open to control by states'' and that Order No. 1920 will 
disproportionately benefit certain states, e.g., those with policies in 
favor of electrification of the transportation and building 
sectors.\584\
---------------------------------------------------------------------------

    \583\ Ohio Commission Federal Advocate Rehearing Request at 18-
19 (citing City of Phila. v. N.J., 437 U.S. 617, 623 (1978); Gen. 
Motors Corp. v. Tracy, 519 U.S. 278, 300 (1997); H. P. Hood & Sons, 
Inc. v. Du Mond, 336 U.S. 525 (1949); N.Y. v. U.S., 505 U.S. 144 
(1992); Printz v. United States, 521 U.S. 898 (1997)).
    \584\ Id. (also arguing that Order No. 1920 will also benefit 
certain types of generation developers).
---------------------------------------------------------------------------

2. Commission Determination
    192. We find that arguments that Order No. 1920 is not supported by 
the D.C. Circuit's decision in South Carolina Public Service Authority 
v. FERC upholding Order No. 1000 are

[[Page 97216]]

erroneous because, as the court in that case put it, they 
``misperceive[ ] what the Commission has required in the Final Rule.'' 
\585\ Order No. 1920 is directed toward ensuring just and reasonable 
rates by requiring Long-Term Regional Transmission Planning, including 
requiring transmission providers to evaluate which Long-Term Regional 
Transmission Facilities will more efficiently or cost-effectively 
address Long-Term Transmission Needs.\586\ As in South Carolina Public 
Service Authority v. FERC,\587\ the Commission has declined to impose 
obligations to ``mandate development of any particular transmission 
facility,'' \588\ change applicable siting requirements and 
processes,\589\ or ``change existing mechanisms for cost-recovery 
through retail rates.'' \590\ Order No. 1920 ``does not regulate, aim 
at, or otherwise attempt to influence integrated resource planning, the 
generation mix, decisions related to the siting and construction of 
transmission facilities or generation resources, or any other matters 
reserved to states under FPA section 201.'' \591\ Under Order No. 1920, 
like Order No. 1000, ``the substance of a regional transmission plan 
and any subsequent formation of agreements to construct or operate 
regional transmission facilities remain within the discretion of the 
decision-makers in each planning region.'' \592\ The Commission also 
maintains Order No. 1000's light touch as to regional cost allocation: 
``[i]t does not dictate how costs are to be allocated. Rather, the Rule 
provides for general cost allocation principles and leaves the details 
to transmission providers to determine in the planning processes.'' 
\593\
---------------------------------------------------------------------------

    \585\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 57.
    \586\ Order No. 1920, 187 FERC ] 61,068 at PP 134, 667, 721-723.
    \587\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 57-58 
(explaining that the Commission did not impose obligations to build 
or mandatory processes to construct transmission facilities in the 
regional transmission plan and disavowed that it was purporting to 
determine what needs to be built, where it needs to be built, and 
who needs to build it); see id. at 62 (``The orders neither require 
facility construction nor allow a party to build without securing 
necessary state approvals.'').
    \588\ Order No. 1920, 187 FERC ] 61,068 at P 257; see id. P 419 
(``We are not requiring that transmission providers select any 
particular Long-Term Regional Transmission Facility and therefore 
are not directing the development of any particular transmission 
facilities.'').
    \589\ See id. P 258.
    \590\ Id. P 259.
    \591\ Id. P 254; see also id. P 256 (``[W]e direct reforms to 
close these gaps without otherwise disturbing the regional 
transmission planning structure required by Order No. 1000, which 
was fully affirmed on appeal in the face of similar objections to 
those raised here.'').
    \592\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 58.
    \593\ Id. at 81; see, e.g., Order No. 1920, 187 FERC ] 61,068 at 
PP 268-269, 723, 916, 954, 1291-1294.
---------------------------------------------------------------------------

    193. We disagree with the arguments in the rehearing requests that 
Order No. 1920 attempts to direct substantive outcomes, including as to 
the generation resource mix.\594\ As already explained, Order No. 1920 
remains process-focused and does not seek to achieve particular 
substantive outcomes, influence or direct the generation mix, 
preferentially favor certain transmission facilities, or require 
unlawful subsidization of state policies.\595\ While it requires 
consideration of certain categories of factors in assessing Long-Term 
Transmission Needs,\596\ these factors are resource-neutral and, within 
the broad parameters set by Order No. 1920, transmission providers have 
significant discretion in developing Long-Term Scenarios that further 
precludes the Commission from attempting to dictate outcomes.\597\ 
Moreover, as described, transmission providers must consult with and 
consider the positions of the Relevant State Entities as to how to 
account for factors related to state public policies in Long-Term 
Regional Transmission Planning assumptions.
---------------------------------------------------------------------------

    \594\ See Arizona Commission Rehearing Request at 12-13; Montana 
Commission Rehearing Request at 3-4; West Virginia Commission 
Rehearing Request at 10-12; Wyoming Commission Rehearing Request at 
2-4; Utah Commission Rehearing Request at 8 n.17.
    \595\ See infra Requirement to Incorporate Categories of Factors 
section.
    \596\ See Order No. 1920, 187 FERC ] 61,068 at P 300 (``Long-
Term Transmission Needs are similar in kind to transmission needs 
identified through existing regional transmission planning processes 
established under Order No. 1000. Where Long-Term Transmission Needs 
differ is their identification through the long-term, forward-
looking, and more comprehensive regional transmission planning and 
cost allocation processes established in this final rule.'').
    \597\ See infra Requirement to Incorporate Categories of Factors 
section.
---------------------------------------------------------------------------

    194. We disagree with claims that Commission has departed from the 
``light touch'' of Order No. 1000 because Order No. 1000 did not 
mandate a ``backstop'' ex ante cost allocation method to a voluntary 
State Agreement Process.\598\ As South Carolina Public Service 
Authority v. FERC recognized and upheld, Order No. 1000 required 
transmission providers to file an ex ante cost allocation method.\599\ 
Order No. 1920 did not diminish states' role compared to Order No. 1000 
but, instead, increased the available opportunities for robust 
participation by Relevant State Entities to seek to reach agreement on 
a Long-Term Regional Transmission Cost Allocation Method(s) and/or a 
State Agreement Process.\600\ By virtue of these requirements, Order 
No. 1920 is more solicitous of state input and uses an even lighter 
touch than Order No. 1000 in this respect. As discussed elsewhere,\601\ 
we take further steps in this rehearing order to strengthen states' 
role in Long-Term Regional Transmission Planning and cost allocation 
for Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \598\ See Montana Commission Rehearing Request at 2-4; West 
Virginia Commission Rehearing Request at 10-12; Wyoming Commission 
Rehearing Request at 2-4.
    \599\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 53 (``The 
cost-allocation reforms in Order No. 1000 require each transmission 
provider to include in its OATT a method (or set of methods) for 
allocating ex ante the costs of new regional transmission facilities 
that complies with six regional cost allocation principles.'' 
(citing Order No. 1000, 136 FERC ] 61,051 at P 558)); see id. at 82-
87 (rejecting challenges to the Commission's authority to adopt such 
reforms).
    \600\ See id. PP 5, 268, 1291.
    \601\ Infra Transmission Planning Horizon section; Obligation to 
File an Ex Ante Long-Term Regional Transmission Cost Allocation 
Method and Its Use as a Backstop section.
---------------------------------------------------------------------------

    195. We are also not persuaded by arguments that Order No. 1920 
exceeds the Commission's authority because it thwarts the role of 
RERRAs \602\ or unlawfully intrudes on the authority of state bodies 
that regulate retail rates.\603\ Order No. 1920 ``does not change 
existing mechanisms for cost-recovery through retail rates,'' but, 
instead, regulates transmission planning and cost allocation processes 
falling within the Commission's jurisdiction.\604\ To the extent that 
Order No. 1920 might affect retail rates or other areas of state 
authority, this does not defeat the Commission's authority; as a valid 
exercise of the Commission's jurisdiction over practices affecting 
interstate transmission rates, Order No. 1920 is lawful notwithstanding 
such effects.\605\ Finally, assertions that the

[[Page 97217]]

Commission is attempting to dictate substantive outcomes or prefer 
certain energy resources or policies or that Order No. 1920 does not 
comport with principles of cost causation \606\ are not convincing for 
the reasons already explained.\607\
---------------------------------------------------------------------------

    \602\ See Undersigned States Rehearing Request at 7-8; 
Designated Retail Regulators Rehearing Request at 8, 24-26; Georgia 
PSC Rehearing Request at 4.
    \603\ See Montana Commission Rehearing Request at 6-7; West 
Virginia Commission Rehearing Request at 9-10; Wyoming Commission 
Rehearing Request at 6-8; Arizona Commission Rehearing Request at 
20-22 (arguing that the primary focus of transmission planning and 
cost allocation has been reliability and low cost, and that Order 
No. 1920 introduces other considerations).
    \604\ Order No. 1920, 187 FERC ] 61,068 at P 259.
    \605\ See supra Federal/State Division of Authority section; 
EPSA, 577 U.S. at 281-82 (``When FERC regulates what takes place on 
the wholesale market, as part of carrying out its charge to improve 
how that market runs, then no matter the effect on retail rates, 
824(b) imposes no bar.'' (emphasis added))); see also Arizona 
Commission Rehearing Request at 20-22 (claiming that Order No. 1920 
``usurps the Arizona Constitution and its methodology'' and 
otherwise conflicts with state law); U.S. Const. Art. VI (``This 
Constitution, and the Laws of the United States which shall be made 
in Pursuance thereof . . . shall be the supreme Law of the Land . . 
. any Thing in the Constitution or Laws of any State to the Contrary 
notwithstanding.''); NARUC, 964 F.3d at 1186-88 (discussing the 
application of the Supremacy Clause in the context of the FPA in 
rejecting an argument that a Commission regulation unlawfully 
regulated matters falling within state authority).
    \606\ See, e.g., States Rehearing Request at 7-8, 24; Designated 
Retail Regulators Rehearing Request at 8, 25-26; Georgia PSC 
Rehearing Request at 4; Arizona Commission Rehearing Request at 22; 
Utah Commission Rehearing Request at 9.
    \607\ See supra Federal/State Division of Authority 
section(explaining that Order No. 1920 is not directed at achieving 
substantive outcomes and that the categories of factors are 
resource-neutral); supra Order No. 1920 Does Not Require Unlawful 
Subsidization of State Policies section (explaining that arguments 
that the Commission is requiring subsidization of state policies are 
incorrect and unpersuasive).
---------------------------------------------------------------------------

    196. We are also not persuaded by Undersigned States' argument 
\608\ that if Order No. 1920 were authorized by the FPA, the FPA would 
violate equal sovereignty principles. The Commission in Order No. 1920 
explained at length its reasons for rejecting that argument.\609\ On 
rehearing, Undersigned States repeat their arguments from their 
comments on the NOPR while failing to engage with, let alone rebut, the 
Commission's reasoning in Order No. 1920.\610\ We therefore sustain 
Order No. 1920's rejection of this argument for the reasons stated 
therein. We particularly note that Undersigned States have pointed to 
no precedent applying the equal sovereignty doctrine in circumstances 
comparable to those here.\611\
---------------------------------------------------------------------------

    \608\ Undersigned States Rehearing Request at 18-19.
    \609\ Order No. 1920, 187 FERC ] 61,068 at PP 280-282 
(explaining that this argument was not supported by precedent and is 
incorrect because Order No. 1920 does not require subsidization of 
other states policies or generation decisions).
    \610\ See Undersigned States Rehearing Request at 18-19; Order 
No. 1920, 187 FERC ] 61,068 at P 212 & n.535 (citing Undersigned 
States Reply Comments at 5-6).
    \611\ See Order No. 1920, 187 FERC ] 61,068 at PP 280-282. In 
addition to the discussion in Order No. 1920, we observe that, 
unlike here, the cases on which Undersigned States rely addressed 
the validity of direct and de jure limitations of the rights of 
certain states relative the rights provided to other states. See 
Franchise Tax Bd. v. Hyatt, 578 U.S. at 178 (explaining that Nevada 
``has applied a special rule of law applicable only in lawsuits 
against its sister States''); Shelby Cnty. v. Holder, 570 U.S. at 
544 (``And despite the tradition of equal sovereignty, the Act 
applies to only nine States (and several additional counties).''); 
Coyle v. Smith, 221 U.S. at 579 (``Has Oklahoma been admitted upon 
an equal footing with the original states? If she has, she, by 
virtue of her jurisdictional sovereignty as such a state, may 
determine for her own people the proper location of the local seat 
of government.''); cf. Stearns v. Minn., 179 U.S. at 244-45 
(discussing the validity of certain provisions of the enabling act 
admitting Minnesota to the Union, as incorporated in the Minnesota 
Constitution, in noting that ``a state admitted into the Union 
enters therein in full equality with all the others'').
---------------------------------------------------------------------------

    197. Also unpersuasive is Undersigned States' nondelegation 
argument.\612\ To begin with, this argument was not raised prior to 
rehearing, as required by the Commission's Rule of Practice and 
Procedure 713(c)(3).\613\ We typically do not consider arguments raised 
for the first time on rehearing, unless those arguments could not have 
been previously presented, e.g., claims based on information that only 
recently became available or concerns prompted by a change in material 
circumstances.\614\ Commenters had the opportunity to raise this 
argument, but did not do so.\615\
---------------------------------------------------------------------------

    \612\ See Undersigned States Rehearing Request at 17-18.
    \613\ See 18 CFR 385.713(c)(3) (providing that any request for 
rehearing must ``[s]et forth the matters relied upon by the party 
requesting rehearing, if rehearing is sought based on matters not 
available for consideration by the Commission at the time of the 
final decision or final order'').
    \614\ See Ala. Power Co., 179 FERC ] 61,128, at P 15 (2022); KEI 
(Me.) Power Mgmt. (III) LLC, 173 FERC ] 61,069, at P 38 n.77 (2020); 
Tex. E. Transmission, LP, 141 FERC ] 61,043, at P 19 (2012) (``We do 
so because (1) our regulations preclude other parties from 
responding to a request for rehearing and (2) such behavior is 
disruptive to the administrative process because it has the effect 
of moving the target for parties seeking a final administrative 
decision.'' (quotation marks omitted)); Calpine Oneta Power v. Am. 
Elec. Power Serv. Corp., 114 FERC ] 61,030, at P 7 (2006); Iroquois 
Gas Transmission Sys., L.P., 86 FERC ] 61,261, at 61,949 (1999)); 
Ocean State Power II, 69 FERC ] 61,146, at 61,548 (1994); NO Gas 
Pipeline v. FERC, 756 F.3d 764, 770 (``We finally note that Jersey 
City's alleged constitutional claim of actual bias is also barred as 
untimely. Jersey City has shown us nothing of record to establish 
that it raised this issue before FERC's issuance of the initial 
order.'').
    \615\ See U.S. v. L.A. Tucker Truck Lines, Inc., 344 U.S. 33, 37 
(1952) (``Simple fairness to those who are engaged in the tasks of 
administration, and to litigants, requires as a general rule that 
courts should not topple over administrative decisions unless the 
administrative body not only has erred but has erred against 
objection made at the time appropriate under its practice.''); cf. 
Reytblatt v. U.S. Nuclear Regul. Comm'n, 105 F.3d 715, 723 (D.C. 
Cir. 1997) (agencies are not required to respond to untimely 
comments).
---------------------------------------------------------------------------

    198. In any event, a statute does not violate the nondelegation 
doctrine so long as Congress has set forth an ``intelligible 
principle'' to guide the delegee's exercise of authority.\616\ 
Undersigned States fail to apply (or even acknowledge) this test, 
address the precedent setting it forth, or engage with the text of the 
FPA.\617\ Instead, distinct from their major questions doctrine 
argument, they assert a per se bar on Congress delegating ``major 
policy questions'' to agencies.\618\ They cite no case adopting this 
sweeping rule,\619\ and we therefore decline to apply this approach 
here.\620\ Moreover, Undersigned States' single-sentence argument fails 
to explain the parameters of this test or how we would apply it to the 
statutory text of the FPA or Order No. 1920. And even were we to set 
aside the foregoing, we would still disagree that Order No. 1920 
involves the delegation of such a ``major policy question'' for the 
reasons stated herein and in Order No. 1920.\621\
---------------------------------------------------------------------------

    \616\ Whitman v. Am. Trucking Ass'ns, 531 U.S. at 472 (citing 
J.W. Hampton, Jr., & Co. v. United States, 276 U.S. 394, 409 
(1928)); see also Fox Television Stations, Inc., 556 U.S. at 536; 
Nat'l Postal Pol'y Council v. Postal Regul. Comm'n, 17 F.4th 1184, 
1192 (D.C. Cir. 2021).
    \617\ Cf. Gundy v. United States, 588 U.S. 128, 146 (2019) 
(plurality opinion) (``We have sustained authorizations for agencies 
to set ``fair and equitable'' prices and ``just and reasonable'' 
rates.'' (citing Yakus v. United States, 321 U.S. 414, 422, 427 
(1944); FPC v. Hope Nat. Gas Co., 320 U.S. 591 (1944)).
    \618\ See Undersigned States Rehearing Request at 17-18.
    \619\ See id. (citing Paul v. U.S., 140 S. Ct. at 342 (2019) 
(Mem.) (Kavanaugh, J., statement respecting denial of certiorari) 
(expressly recognizing that ``the Court has not adopted a 
nondelegation principle for major questions''); Union Dep't, AFL-CIO 
v. Am. Petroleum Inst., 448 U.S. at, 685-86 (Rehnquist, J., 
concurring in judgment) (similar); A.L.A. Schechter Poultry Corp. v. 
United States, 295 U.S. 495).
    \620\ This argument is also in tension with the Court's 
articulation of the major questions doctrine in West Virginia. See 
597 U.S. at 721, 723 (explaining that the major questions doctrine 
applied only in extraordinary cases, based on specific statutory 
context and a variety of factors, and that ``delegation[s]'' to 
address major questions were permissible with clear congressional 
authorization); cf. Paul v. U.S., 140 S. Ct. at 342 (Mem.) 
(Kavanaugh, J., statement respecting denial of certiorari) 
(recognizing that application of this test would overturn the aspect 
of major questions doctrine allowing Congress to ``delegate to the 
agency the authority both to decide the major policy question and to 
regulate and enforce'').
    \621\ See supra Major Questions Doctrine section; Order No. 
1920, 187 FERC ] 61,068 at PP 253-62, 275-78.
---------------------------------------------------------------------------

    199. Finally, Ohio Commission Federal Advocate incorrectly claims 
that Order No. 1920 ``violates the federal Commerce Clause'' on the 
theory that Order No. 1920 may disproportionately benefit commerce in 
certain states, which have implemented policies allegedly favored by 
the rule, as compared to other states.\622\ As discussed above, Order 
No. 1920 is a valid exercise of congressionally granted authority under 
the FPA. It does not favor particular state policies or transmission 
planning outcomes, but rather takes state policies as inputs into Long-
Term Regional Transmission Planning.\623\ Furthermore, the precedent

[[Page 97218]]

that Ohio Commission Federal Advocate cites does not support concluding 
that a generally applicable Commission rule promulgated pursuant to its 
authority under the FPA (itself a valid exercise of Congress's Commerce 
Clause authority) violates the Commerce Clause if that rule may have 
disparate effects on commerce in various states.\624\
---------------------------------------------------------------------------

    \622\ Ohio Commission Federal Advocate Rehearing Request at 18-
19.
    \623\ See supra Federal/State Division of Authority section.
    \624\ See Ohio Commission Federal Advocate Rehearing Request at 
18-19; Gen. Motors Corp. v. Tracy, 519 U.S. at 281-82, 287-88, 311-
12 (addressing whether state sales and use taxes were impermissible 
as discriminatory under dormant Commerce Clause or Equal Protection 
Clause jurisprudence; holding that the taxes violated neither 
provision of the Constitution); City of Phila. v. N.J., 437 U.S. at 
623 (similarly addressing issues arising under dormant Commerce 
Clause jurisprudence, in the absence of controlling federal 
legislation, particularly as to whether New Jersey could close its 
borders to importation of certain waste); H.P. Hood & Sons, Inc. v. 
Du Mond, 336 U.S. at 545 (``Since the [state] statute as applied 
violates the [dormant] Commerce Clause and is not authorized by 
federal legislation pursuant to that Clause, it cannot stand.''); 
cf. Printz v. United States, 521 U.S. at 935 (``We held in New York 
that Congress cannot compel the States to enact or enforce a federal 
regulatory program. Today we hold that Congress cannot circumvent 
that prohibition by conscripting the State's officers directly.''); 
New York v. U.S. 505 U.S. at 161 (``This litigation . . . concerns 
the circumstances under which Congress may use the States as 
implements of regulation . . . .'').
---------------------------------------------------------------------------

V. Long-Term Regional Transmission Planning

A. Requirement To Participate in Long-Term Regional Transmission 
Planning

1. Order No. 1920 Requirements
    200. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to participate in a 
regional transmission planning process that includes Long-Term Regional 
Transmission Planning, meaning regional transmission planning on a 
sufficiently long-term, forward-looking, and comprehensive basis to 
identify Long-Term Transmission Needs, identify transmission facilities 
that meet such needs, measure the benefits of those transmission 
facilities, and evaluate those transmission facilities for potential 
selection in the regional transmission plan for purposes of cost 
allocation as the more efficient or cost-effective transmission 
facilities to meet Long-Term Transmission Needs. The Commission 
required that Long-Term Regional Transmission Planning comply with the 
following Order Nos. 890 and 1000 transmission planning principles: (1) 
coordination; (2) openness; (3) transparency; (4) information exchange; 
(5) comparability; and (6) dispute resolution.\625\
---------------------------------------------------------------------------

    \625\ Order No. 1920, 187 FERC ] 61,068 at P 224.
---------------------------------------------------------------------------

    201. The Commission explained that Long-Term Regional Transmission 
Planning will enhance the existing regional transmission planning and 
cost allocation processes required by Order No. 1000. The Commission 
also stated that, except as set forth in Order No. 1920, it does not 
require any transmission provider to replace or otherwise make changes 
to its existing Order No. 1000-compliant regional transmission planning 
processes that plan for reliability or economic transmission needs, or 
the associated Order No. 1000-compliant regional cost allocation 
method(s). As such, the Commission explained, transmission providers 
may continue to rely on their existing regional transmission planning 
and cost allocation processes to comply with Order No. 1000's 
requirements related to transmission needs driven by reliability 
concerns or economic considerations.\626\ The Commission also declined 
a request to mandate that the ``base cases'' used in Order No. 1000 
regional transmission planning processes and the Long-Term Scenarios 
used in Long-Term Regional Transmission Planning be defined in the same 
process.\627\
---------------------------------------------------------------------------

    \626\ Id. P 241.
    \627\ Id. P 246.
---------------------------------------------------------------------------

    202. The Commission further explained that Order No. 1920 does not 
alter the existing Order No. 1000 requirement to consider Public Policy 
Requirements in the regional transmission planning process, and further 
stated that it will instead deem transmission providers to be in 
compliance with this existing requirement by conducting Long-Term 
Regional Transmission Planning in accordance with the requirements set 
for in Order No. 1920.\628\ The Commission allowed transmission 
providers to propose in their Order No. 1920 compliance filings to 
continue using some or all aspects of the existing regional 
transmission planning and cost allocation processes that they use to 
consider transmission needs driven by Public Policy Requirements. The 
Commission held that transmission providers nevertheless must comply 
with the Long-Term Regional Transmission Planning requirements set 
forth in Order No. 1920, such that continued use of existing regional 
transmission planning and cost allocation processes related to 
transmission needs driven by Public Policy Requirements will not 
supplant transmission providers' obligation to comply with Order No. 
1920. The Commission required that, in their Order No. 1920 compliance 
filings, transmission providers that wish to continue to use some or 
all of their existing regional transmission planning and cost 
allocation processes to consider transmission needs driven by Public 
Policy Requirements must demonstrate that continued use of any such 
processes does not interfere with or otherwise undermine Long-Term 
Regional Transmission Planning as set forth in Order No. 1920.\629\
---------------------------------------------------------------------------

    \628\ Id. P 242.
    \629\ Id. P 243.
---------------------------------------------------------------------------

    203. The Commission also allowed transmission providers to propose 
a regional transmission planning process that simultaneously plans for 
shorter-term reliability and economic transmission needs, as well as 
Long-Term Transmission Needs as defined in Order No. 1920, through a 
combined process. The Commission required transmission providers 
proposing to address all of these transmission needs in a single 
regional transmission planning process to demonstrate that such a 
unified regional transmission planning process continues to comply with 
Order No. 1000, as well as with the Long-Term Regional Transmission 
Planning requirements set forth in Order No. 1920, by demonstrating 
that such a combined process is consistent with or superior to the 
requirements of both Order Nos. 1000 and 1920. The Commission explained 
that, in the case that the requirements of Order Nos. 1000 and 1920 
conflict, the Order No. 1920 requirements will prevail, and 
transmission providers must demonstrate that their proposed regional 
transmission planning process is consistent with or superior to the 
applicable Order No. 1920 requirements.\630\
---------------------------------------------------------------------------

    \630\ Id. P 244.
---------------------------------------------------------------------------

    204. As described further in the Implementation of Long-Term 
Regional Transmission Planning section below, in Order No. 1920, the 
Commission required transmission providers to explain on compliance how 
the initial timing sequence for Long-Term Regional Transmission 
Planning interacts with existing regional transmission planning 
processes. The Commission required transmission providers to provide in 
their explanations any information necessary to ensure that 
stakeholders understand this interaction, including at least the 
following two components. First, the Commission required transmission 
providers to address the possible interaction between the transmission 
planning cycle for Long-Term Regional Transmission Planning and 
existing Order No. 1000 regional transmission planning processes. The

[[Page 97219]]

Commission recognized that there may be overlap in the time horizon for 
Long-Term Regional Transmission Planning and existing Order No. 1000 
regional transmission planning processes and that these processes will 
likely inform each other.\631\ Second, the Commission required 
transmission providers to address the possible displacement of regional 
transmission facilities from the existing regional transmission 
planning processes. The Commission recognized that it is possible that, 
in some cases, Long-Term Regional Transmission Facilities selected to 
address Long-Term Transmission Needs may provide near-term reliability 
or economic benefits, and thus could displace regional transmission 
facilities that are under consideration as part of existing regional 
transmission planning processes.\632\
---------------------------------------------------------------------------

    \631\ Id. P 1071.
    \632\ Id. (citation omitted).
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    205. Multiple parties request rehearing and clarification on the 
requirement that, in their Order No. 1920 compliance filings, 
transmission providers that wish to continue to use some or all of 
their existing regional transmission planning and cost allocation 
processes to consider transmission needs driven by Public Policy 
Requirements must demonstrate that continued use of any such processes 
does not interfere with or otherwise undermine Long-Term Regional 
Transmission Planning as set forth in Order No. 1920. Large Public 
Power requests clarification that the Commission will presume the 
existing regional transmission planning and cost allocation processes 
that transmission providers use to consider transmission needs driven 
by Public Policy Requirements to be just and reasonable. Large Public 
Power claims that this is an issue on which the Commission was not 
clear in Order No. 1920, because the Commission stated that Order No. 
1920 ``do[es] not alter the existing Order No. 1000 requirement to 
consider transmission needs driven by Public Policy Requirements in the 
regional transmission planning process,'' that transmission providers 
may propose to continue using these processes, and that transmission 
providers proposing to do so ``must demonstrate that continued use of 
any such processes does not interfere with or otherwise undermine Long-
Term Regional Transmission Planning as set forth in this final rule.'' 
\633\ Large Public Power contends that its members see value in 
existing regional transmission planning processes that transmission 
providers use to consider transmission needs driven by Public Policy 
Requirements, and requests that the Commission not disrupt these 
processes--in particular the process conducted by NYISO. Large Public 
Power describes certain aspects of NYISO's regional transmission 
planning process and explains that the New York Commission and the 
Commission each have approved these processes.\634\ Large Public Power 
therefore requests that, in reviewing transmission providers' Order No. 
1920 compliance filings, the Commission presume that these existing 
processes are just and reasonable, and argues that the Commission 
should not require transmission providers and their stakeholders to 
face the burden of demonstrating that these processes are just and 
reasonable.\635\ If the Commission does not grant clarification, Large 
Public Power requests rehearing on the ground that the Commission did 
not advance in Order No. 1920 any ``cogent rationale'' for treating 
regional transmission planning processes that consider Public Policy 
Requirements differently from those that plan for reliability or 
economic transmission needs.\636\
---------------------------------------------------------------------------

    \633\ Large Public Power Rehearing Request at 4-6 (quoting Order 
No. 1920, 187 FERC ] 61,068 at PP 242-243).
    \634\ Id. at 6-9.
    \635\ Id. at 4, 6, 9.
    \636\ Id. at 7.
---------------------------------------------------------------------------

    206. Similar to Large Public Power's rehearing request, 
Pennsylvania Commission argues that requiring transmission providers in 
Order No. 1920 to demonstrate that continued use of existing regional 
transmission planning and cost allocation processes to consider 
transmission needs driven by Public Policy Requirements does not 
interfere with or otherwise undermine Long-Term Regional Transmission 
Planning is an abuse of discretion, and that the Commission failed to 
engage in reasoned decision making.\637\ Pennsylvania Commission 
further argues that this requirement is inconsistent with the 
Commission's statements that, outside the context of Long-Term Regional 
Transmission Planning, Order No. 1920 will not ``otherwise disturb[] 
the regional transmission planning structure required by Order No. 
1000'' or ``inadvertently cause the re-litigation of aspects of those 
existing processes.'' \638\ Pennsylvania Commission contends that Order 
No. 1920 requires full re-litigation on compliance of all processes 
used to satisfy Public Policy Requirements, including PJM's State 
Agreement Approach because it addresses state Public Policy 
Requirements.\639\ Pennsylvania Commission argues that the Commission 
should amend Order No. 1920 to either remove this compliance 
requirement, explicitly limit it to processes used for Long-Term 
Regional Transmission Planning, or to clarify that PJM's State 
Agreement Approach does not interfere with Long-Term Regional 
Transmission Planning and therefore would not be subject to re-
litigation.\640\
---------------------------------------------------------------------------

    \637\ Pennsylvania Commission Rehearing Request at 2.
    \638\ Order No. 1920, 187 FERC ] 61,068 at PP 252, 256; see 
Pennsylvania Commission Rehearing Request at 2.
    \639\ Pennsylvania Commission Rehearing Request at 2-3 (citing 
Order No. 1920, 187 FERC ] 61,068 at P 243).
    \640\ Id.
---------------------------------------------------------------------------

    207. Similarly, PJM States request that the Commission clarify that 
PJM's State Agreement Approach does not conflict with Order No. 1920, 
and that states within PJM can continue to pursue public policies 
through the voluntary election of the State Agreement Approach in its 
current form.\641\ Pennsylvania Commission also supports and adopts the 
clarification request of PJM States.\642\
---------------------------------------------------------------------------

    \641\ PJM States Rehearing Request at 6-7.
    \642\ Pennsylvania Commission Rehearing Request at 1.
---------------------------------------------------------------------------

    208. PIOs argue that existing Order No. 1000 regional transmission 
planning processes that plan for reliability or economic transmission 
needs are unjust, unreasonable, and unduly discriminatory, and they 
request rehearing of various aspects of Order No. 1920 to ensure that 
these existing processes complement Long-Term Regional Transmission 
Planning rather than conflict with and undermine it.\643\ Citing a 
number of statements in Order No. 1920, PIOs contend that these 
existing regional transmission planning processes threaten the 
reliability of the transmission system, fail to build transmission 
infrastructure necessary to meet regional transmission needs over the 
long term, and instead invest in transmission facilities addressing 
narrower, shorter-term needs, which ultimately leads to transmission 
customers paying unjust and unreasonable rates.\644\ PIOs contend that 
evidence in the record demonstrates that failing to address the 
``systemic inadequacies'' of existing regional

[[Page 97220]]

transmission planning processes or aligning them with Long-Term 
Regional Transmission Planning will perpetuate unjust and unreasonable 
rates.\645\
---------------------------------------------------------------------------

    \643\ See generally PIOs Rehearing Request at 16-25.
    \644\ Id. at 16-18.
    \645\ Id. at 20.
---------------------------------------------------------------------------

    209. PIOs therefore request that the Commission amend Order No. 
1920 in three ways. First, PIOs argue that the Commission should 
require transmission providers either to conduct a regional 
transmission planning process that simultaneously plans for shorter-
term reliability and economic transmission needs and Long-Term 
Transmission Needs through a combined process or to align the methods 
of all regional transmission planning processes, including Long-Term 
Regional Transmission Planning.\646\ Second, PIOs argue that the 
Commission should delineate clear boundaries between and align the 
timing of Long-Term Regional Transmission Planning and existing 
processes, such that transmission providers would address only the 
limited regional transmission needs that cannot be reasonably 
anticipated and cannot be addressed during a Long-Term Regional 
Transmission Planning cycle. Otherwise, PIOs contend, these processes 
all would identify transmission facilities over the same planning 
periods despite different underlying assumptions, benefits assessments, 
and cost allocation.\647\ Third, PIOs argue that the Commission should 
require Long-Term Regional Transmission Planning and existing processes 
to use the same ``base case'' embodying transmission providers' best 
assessment of future system conditions. Otherwise, PIOs contend, 
transmission providers ultimately may identify redundant transmission 
facilities, fail to identify more efficient or cost-effective Long-Term 
Regional Transmission Facilities, or be motivated to undermine Long-
Term Regional Transmission Planning in favor of existing 
processes.\648\
---------------------------------------------------------------------------

    \646\ Id. at 21-23.
    \647\ Id. at 23-24.
    \648\ Id. at 24-25.
---------------------------------------------------------------------------

3. Commission Determination
    210. We decline to grant the clarification sought by Large Public 
Power that the Commission will presume the existing regional 
transmission planning and cost allocation processes that transmission 
providers use to consider transmission needs driven by Public Policy 
Requirements to be just and reasonable. We disagree with Large Public 
Power that Order No. 1920 was unclear as to how the Commission will 
evaluate any proposals transmission providers may make in their 
compliance filings to continue using some or all aspects of the 
existing regional transmission planning and cost allocation processes 
that they use to consider transmission needs driven by Public Policy 
Requirements. We also disagree with the Pennsylvania Commission that 
the Commission failed to engage in reasoned decision making. The 
Commission stated clearly in Order No. 1920, and we continue to find, 
that, while transmission providers may propose to retain existing Order 
No. 1000 regional transmission planning and cost allocation processes 
related to transmission needs driven by Public Policy Requirements, 
transmission providers that do so must demonstrate that continued use 
of any such processes does not interfere with or otherwise undermine 
Long-Term Regional Transmission Planning as set forth in Order No. 
1920.\649\ In other words, the Commission will not presume the existing 
regional transmission planning and cost allocation processes used to 
consider transmission needs driven solely by Public Policy Requirements 
are just and reasonable.
---------------------------------------------------------------------------

    \649\ Order No. 1920, 187 FERC ] 61,068 at P 243; see also id. P 
240 (declining to pre-judge whether any existing regional 
transmission planning processes meet the requirements of Order No. 
1920).
---------------------------------------------------------------------------

    211. We also disagree with Large Public Power's argument that the 
Commission did not justify the differential treatment of regional 
transmission planning processes that consider transmission needs driven 
by Public Policy Requirements compared to those that plan for 
reliability or economic transmission needs. The Commission found that 
conducting Long-Term Regional Transmission Planning as set forth in 
Order No. 1920 is sufficient to comply with the Order No. 1000 
requirement to consider Public Policy Requirements in the regional 
transmission planning process. In other words, Long-Term Regional 
Transmission Planning may subsume the purpose of existing regional 
transmission planning and cost allocation processes used to consider 
transmission needs driven by Public Policy Requirements. Given that 
potential, it is necessary and appropriate to require transmission 
providers to demonstrate that continued use of Order No. 1000 processes 
to consider transmission needs driven by Public Policy Requirements 
does not interfere with or otherwise undermine Long-Term Regional 
Transmission Planning under Order No. 1920. We also note that Order No. 
1920 allows transmission providers to propose a regional transmission 
planning process that simultaneously plans for shorter-term reliability 
and economic transmission needs, as well as Long-Term Transmission 
Needs, through a combined process, and that transmission providers 
proposing to address all of these transmission needs in a single 
regional transmission planning process must demonstrate that the 
combined regional transmission planning process continues to comply 
with Order No. 1000, as well as with the Long-Term Regional 
Transmission Planning requirements set forth in Order No. 1920, by 
demonstrating that such a combined process is consistent with or 
superior to the requirements of both Order No. 1000 and Order No. 
1920.\650\
---------------------------------------------------------------------------

    \650\ Id. P 244.
---------------------------------------------------------------------------

    212. Similarly, we disagree with the Pennsylvania Commission that 
this requirement is inconsistent with the Commission's statements that, 
except for Long-Term Regional Transmission Planning, Order No. 1920 
will not ``otherwise disturb[ ] the regional transmission planning 
structure required by Order No. 1000'' or ``inadvertently cause the re-
litigation of aspects of those existing processes.'' \651\ That said, 
we appreciate the Pennsylvania Commission's concern that Order No. 1920 
requires re-litigation of PJM's State Agreement Approach and its 
request that the Commission limit the requirement to processes used for 
Long-Term Regional Transmission Planning. We also recognize PJM States' 
request for clarification that PJM's State Agreement Approach does not 
interfere or conflict with Long-Term Regional Transmission Planning. As 
the Commission explained in Order No. 1920, this requirement does not 
alter the existing Order No. 1000 requirement to consider transmission 
needs driven by Public Policy Requirements in the regional transmission 
planning process, and transmission providers will be deemed to be in 
compliance with this existing requirement by conducting Long-Term 
Regional Transmission Planning in accordance with the requirements set 
forth in Order No. 1920.\652\ Thus, Order No. 1920 allows transmission 
providers to propose in their Order No. 1920 compliance filings to 
continue using some or all aspects of the existing Order No. 1000 
regional transmission planning and cost allocation processes that they 
use to consider transmission needs

[[Page 97221]]

driven by Public Policy Requirements, if they so choose. But the 
Commission held that transmission providers nevertheless must comply 
with the Long-Term Regional Transmission Planning requirements set 
forth in Order No. 1920 and that continued use of existing Order No. 
1000 regional transmission planning and cost allocation processes 
related to transmission needs driven by Public Policy Requirements 
alone is insufficient to comply with Order No. 1920. Stated 
differently, transmission providers that wish to continue to use some 
or all of their existing Order No. 1000 regional transmission planning 
and cost allocation processes to consider transmission needs driven by 
Public Policy Requirements must demonstrate that the continued use of 
any such processes does not interfere with or otherwise undermine Long-
Term Regional Transmission Planning as set forth in Order No. 
1920.\653\
---------------------------------------------------------------------------

    \651\ Id. PP 252, 256; see Pennsylvania Commission Rehearing 
Request at 2-3.
    \652\ Order No. 1920, 187 FERC ] 61,068 at P 242.
    \653\ Id. P 243.
---------------------------------------------------------------------------

    213. With respect to PJM's State Agreement Approach specifically, 
we note that it is separate and apart from PJM's compliance with the 
Order No. 1000 requirement to consider transmission needs driven by 
Public Policy Requirements.\654\ Therefore, PJM's State Agreement 
Approach is unaffected by Order No. 1920's requirement to justify 
continued use of regional transmission planning and cost allocation 
processes to consider transmission needs driven by Public Policy 
Requirements. In response to PJM States and Pennsylvania Commission, we 
note that Order No. 1920 does not prohibit PJM from continuing to use 
its existing State Agreement Approach. If the Relevant State Entities 
in PJM agree to rely on PJM's existing State Agreement Approach as an 
Order No. 1920 State Agreement Process that applies to selected Long-
Term Regional Transmission Facilities, and PJM agrees, PJM must propose 
and demonstrate on compliance that its State Agreement Approach 
complies with all of the State Agreement Process requirements set forth 
in Order No. 1920.
---------------------------------------------------------------------------

    \654\ See PJM Interconnection, L.L.C., 142 FERC ] 61,214, at P 
142 (2013) (``We find PJM's proposed State Agreement Approach is not 
needed for PJM to comply with the provisions of Order No. 1000 
addressing transmission needs driven by public policy requirements. 
PJM's State Agreement Approach supplements, but does not conflict or 
otherwise replace, PJM's process to consider transmission needs 
driven by public policy requirements as required by Order No. 1000 . 
. . . Accordingly, the Commission need not find that the State 
Agreement Approach and corresponding cost allocation method comply 
with Order No. 1000.'').
---------------------------------------------------------------------------

    214. We also disagree with PIOs' rehearing arguments related to 
existing regional transmission planning processes that plan for 
reliability and economic needs and the relationship of these processes 
to Long-Term Regional Transmission Planning. First, we decline PIOs' 
request that we require transmission providers to conduct a regional 
transmission planning process that simultaneously plans for shorter-
term reliability and economic transmission needs and Long-Term 
Transmission Needs through a combined process. We continue to find that 
transmission providers may propose on compliance such a combined 
process, but we do not require that transmission providers do so 
because the difficulty of transitioning to this kind of combined 
regional transmission planning process may outweigh any potential 
benefits of requiring such a process.\655\
---------------------------------------------------------------------------

    \655\ Order No. 1920, 187 FERC ] 61,068 at P 245.
---------------------------------------------------------------------------

    215. Furthermore, we find that requiring transmission providers to 
use a combined process to plan for shorter-term reliability and 
economic transmission needs and Long-Term Transmission Needs is 
unnecessary to address the deficiencies in existing regional 
transmission planning and cost allocation requirements that the 
Commission identified in Order No. 1920. Specifically, the Commission 
found that existing regional transmission planning and cost allocation 
requirements fail to require transmission providers to: (1) perform a 
sufficiently long-term assessment of transmission needs that identifies 
Long-Term Transmission Needs; (2) adequately account on a forward-
looking basis for known determinants of Long-Term Transmission Needs; 
and (3) consider the broader set of benefits of regional transmission 
facilities planned to meet those Long-Term Transmission Needs.\656\ 
Because we find that Order No. 1920's Long-Term Regional Transmission 
Planning and cost allocation requirements adequately remedy these 
deficiencies, we decline to impose the additional requirements that 
PIOs suggest.
---------------------------------------------------------------------------

    \656\ Id. P 114.
---------------------------------------------------------------------------

    216. Second, we find premature PIOs' arguments as to the need to 
align methods and timing between existing regional transmission 
planning processes and Long-Term Regional Transmission Planning. In 
Order No. 1920, the Commission required transmission providers to 
explain how Long-Term Regional Transmission Planning will interact with 
existing regional transmission planning processes to plan for 
transmission needs driven by reliability concerns or economic 
considerations, including their timing and the potential that Long-Term 
Regional Transmission Facilities may displace transmission facilities 
that are under consideration in those processes.\657\ The Commission 
will evaluate the interaction between these processes on compliance and 
address any potential issues with this interaction in the orders on 
transmission providers' compliance filings.
---------------------------------------------------------------------------

    \657\ Id. PP 1071-1073.
---------------------------------------------------------------------------

    217. Third, we disagree with PIOs as to the necessity of requiring 
that transmission providers use the same ``base case'' in existing 
regional transmission planning and in Long-Term Regional Transmission 
Planning. The Commission neither proposed such a requirement in the 
NOPR nor adopted one in Order No. 1920, and we are not persuaded to 
adopt PIOs' suggestion in this order. However, we note that nothing in 
Order No. 1920 precludes transmission providers from using the same 
base case in existing regional transmission planning and in Long-Term 
Regional Transmission Planning if they so choose.

B. Long-Term Scenarios Requirements

1. Requirement for Transmission Providers To Use the Seven Required 
Benefits To Help To Inform Their Identification of Long-Term 
Transmission Needs
a. Order No. 1920 Requirements
    218. Order No. 1920 required transmission providers to participate 
in a regional transmission planning process that includes Long-Term 
Regional Transmission Planning, which is defined as a multi-step 
process to: (1) identify Long-Term Transmission Needs; (2) identify 
transmission facilities that meet such needs; (3) measure the benefits 
of those transmission facilities; and (4) evaluate those transmission 
facilities for potential selection in the regional transmission plan 
for purposes of cost allocation.\658\ Order No. 1920 defined Long-Term 
Transmission Needs as ``transmission needs identified through Long-Term 
Regional Transmission Planning by, among other things and as discussed 
in this final rule, running scenarios and considering the enumerated 
categories of factors.'' \659\
---------------------------------------------------------------------------

    \658\ Id. P 224.
    \659\ Id. PP 39, 299.
---------------------------------------------------------------------------

    219. Order No. 1920 generally addressed the identification of Long-
Term Transmission Needs and the measurement of the benefits of Long-
Term Regional Transmission Facilities

[[Page 97222]]

separately.\660\ The Commission stated, however, that transmission 
providers ``must use [the seven required benefits] to help to inform 
their identification of Long-Term Transmission Needs.'' \661\ The 
Commission provided an example of how transmission providers can use 
one of the required benefits (the production cost savings benefit, 
Benefit 3) to help identify Long-Term Transmission Needs.\662\
---------------------------------------------------------------------------

    \660\ E.g., id. P 224 (describing these two requirements as 
separate steps).
    \661\ Id. PP 301, 719; see id. P 667 n.1485, P 859 n.1910.
    \662\ Id. P 301 (``[W]hen transmission providers are working to 
identify Long-Term Transmission Needs, areas of significant 
congestion on the transmission system--where Long-Term Regional 
Transmission Facilities could reduce congestion and in turn 
facilitate production cost savings--may indicate a Long-Term 
Transmission Need.'').
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    220. PJM requests clarification that the Commission did not intend 
to require transmission providers to use any of the seven benefits 
outlined in Order No. 1920 to help inform the identification of Long-
Term Transmission Needs. If the Commission did intend to require 
transmission providers to use the set of seven required benefits to 
help inform the identification of Long-Term Transmission Needs, PJM 
requests that the Commission grant rehearing, either to eliminate this 
requirement or to provide transmission providers with flexibility as to 
this requirement to accommodate regional differences. PJM asserts that 
Order No. 1920 contains only one discussion of a requirement for 
transmission providers to use the seven required benefits to help 
inform their identification of Long-Term Transmission Needs, and, as 
such, PJM questions whether the Commission intended to impose this 
requirement.\663\ PJM further asserts that the Commission offered only 
one hypothetical example of how one of these seven benefits might help 
inform the identification of Long-Term Transmission Needs, and PJM 
argues that the Commission did not provide any evidence, let alone 
substantial evidence, to demonstrate why transmission providers should 
be required to use the seven benefits to inform the identification of 
Long-Term Transmission Needs.\664\ PJM further claims that requiring 
the use of all seven benefits outlined in Order No. 1920 to help inform 
the identification of Long-Term Transmission Needs is inconsistent with 
PJM's sponsorship model because, in such a model, transmission 
developers propose transmission facilities after and in response to 
identified transmission needs, such that using the benefits of such 
transmission facilities to identify transmission needs is 
circular.\665\ PJM also asserts that the NOPR did not provide notice of 
the requirement that transmission providers use the seven benefits to 
help inform the identification of Long-Term Transmission Needs, and PJM 
therefore lacked opportunity to provide comments as to why the 
requirement is inappropriate for the PJM region.\666\
---------------------------------------------------------------------------

    \663\ PJM Rehearing Request at 24-26 (citing Order No. 1920, 187 
FERC ] 61,068 at P 301).
    \664\ Id. at 25.
    \665\ Id. at 25-26.
    \666\ Id. at 25 n.103.
---------------------------------------------------------------------------

    221. SERTP Sponsors argue that Order No. 1920 defines Long-Term 
Transmission Needs in a circular fashion by describing them as 
``transmission needs identified through Long-Term Regional Transmission 
Planning by, among other things and as discussed in this final rule, 
running scenarios and considering the enumerated categories of 
factors,'' \667\ but also requiring that the seven required benefits 
should inform the identification of Long-Term Transmission Needs.\668\ 
SERTP Sponsors claim that this creates a potential chicken-or-egg 
conundrum, because Long-Term Transmission Needs are driven by factors 
and must be identified before the use and measurement of the seven 
required benefits to evaluate Long-Term Regional Transmission 
Facilities.\669\
---------------------------------------------------------------------------

    \667\ SERTP Sponsors Rehearing Request at 11 (quoting Order No. 
1920, 187 FERC ] 61,068 at P 39).
    \668\ Id. (citing Order No. 1920, 187 FERC ] 61,068 at P 719).
    \669\ Id.
---------------------------------------------------------------------------

    222. PIOs request three clarifications related to the requirement 
that transmission providers use the seven benefits to help to inform 
the identification of Long-Term Transmission Needs.\670\ First, PIOs 
request that the Commission clarify what ``help to inform'' means in 
this context, in order to avoid an outcome in which the seven benefits 
are only considered superficially rather than as meaningful 
determinants of Long-Term Transmission Needs. Second, PIOs request that 
the Commission clarify that transmission providers may not identify 
Long-Term Transmission Needs solely on the basis of one of the Order 
No. 1000 ``silos,'' e.g., reliability. PIOs claim that, if a 
transmission provider were to identify Long-Term Transmission Needs 
solely based on reliability, for example, and then use the seven 
required benefits only to compare potential solutions, the resulting 
set of needs would be incomplete, and the resulting solutions would be 
inefficient. Third, PIOs request clarification that the requirement to 
use the seven required benefits to help identify Long-Term Transmission 
Needs applies equally to transmission providers that use a competitive 
bidding process and to those that use a sponsorship model. Regarding 
the sponsorship model in particular, PIOs also request clarification as 
to how the Commission envisions the process by which transmission 
providers could use the seven required benefits to help identify needs, 
without these needs being so granular that the transmission provider 
has effectively defined a specific project.\671\
---------------------------------------------------------------------------

    \670\ PIOs Rehearing Request at 59 (citing Order No. 1920, 187 
FERC ] 61,068 at PP 301, 719).
    \671\ Id. at 59-60.
---------------------------------------------------------------------------

c. Commission Determination
    223. We agree with certain of the rehearing arguments raised by PJM 
and SERTP Sponsors and therefore we set aside the requirement for 
transmission providers to use the set of seven required benefits to 
help inform their identification of Long-Term Transmission Needs. 
Specifically, we find that PJM and SERTP Sponsors highlight potential 
challenges and difficulty transmission providers may have in 
implementing this requirement. As further explained below, although we 
find that it is appropriate to set this requirement aside, we clarify 
and emphasize that the identification of Long-Term Transmission Needs 
should rely on economic and reliability drivers.
    224. In requiring transmission providers to use the set of seven 
required benefits to help to inform their identification of Long-Term 
Transmission Needs, the Commission intended in Order No. 1920 to ensure 
that transmission providers would use their experience evaluating both 
the reliability and economic benefits of transmission facilities--as 
reflected in the seven required benefits--and technical expertise 
assessing the transmission system to identify whether there are 
reliability issues or opportunities to relieve constraints that could 
be resolved through Long-Term Regional Transmission Facilities 
identified through Long-Term Regional Transmission Planning. Upon 
further consideration, we find that Order No. 1920's Long-Term Regional 
Transmission Planning requirements, including the requirements to 
develop Long-Term Scenarios using the

[[Page 97223]]

minimum required Factor Categories,\672\ to use the minimum required 
transmission planning horizon,\673\ and to develop Long-Term Scenarios 
that are plausible and diverse,\674\ taken together, will ensure that 
transmission providers identify Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \672\ Order No. 1920, 187 FERC ] 61,068 at P 409.
    \673\ Id. P 344.
    \674\ Id. P 414.
---------------------------------------------------------------------------

    225. Thus, we are clarifying here that the categories of factors 
will help transmission providers identify Long-Term Transmission Needs, 
consistent with the Commission's statements in Order No. 1920.\675\ 
Potential Long-Term Regional Transmission Facilities that address Long-
Term Transmission Needs, as identified by the Long-Term Scenarios and 
sensitivities, will then be evaluated for their economic and 
reliability benefits, which will ensure that Long-Term Regional 
Transmission Planning leads to transmission solutions that more 
efficiently or cost-effectively address reliability and economic 
transmission needs over the appropriate transmission planning 
horizon.\676\
---------------------------------------------------------------------------

    \675\ See id. P 299 (stating that ``the drivers of transmission 
needs are diverse and include, but are not limited to, evolving 
reliability concerns, changes in the resource mix, and changes in 
demand''); id. P 300 (stating that ``Long-Term Transmission Needs 
are similar in kind to transmission needs identified through 
existing regional transmission planning processes established under 
Order No. 1000,'' which include both reliability and economic 
considerations).
    \676\ We note that this understanding that potential Long-Term 
Regional Transmission Facilities that address Long-Term Transmission 
Needs are evaluated for both reliability and economic benefits is 
consistent with the Commission's determination in Order No. 1920 
that, while transmission providers have significant flexibility to 
determine a regionally appropriate ex ante cost allocation, such 
cost allocation may not be based on a siloed approach that assumes 
Long-Term Regional Transmission Planning addresses only reliability 
or only economic needs. However, as also noted below, transmission 
providers and Relevant State Entities have broad flexibility to 
recognize the different types of benefits provided by Long-Term 
Regional Transmission Facilities and allocate costs in proportion to 
those benefits. See infra General Benefits Requirements Related to 
Cost Allocation section.
---------------------------------------------------------------------------

    226. Finally, because we are setting aside the requirement for 
transmission providers to use the set of seven required benefits to 
help inform their identification of Long-Term Transmission Needs, we 
find moot PIOs' request for clarification concerning this requirement.
2. Transmission Planning Horizon
a. Order No. 1920 Requirements
    227. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to develop Long-Term 
Scenarios as part of Long-Term Regional Transmission Planning using no 
less than a 20-year transmission planning horizon. The Commission 
defined Long-Term Scenarios as scenarios that incorporate various 
assumptions using best available data inputs about the future electric 
power system over a sufficiently long-term, forward-looking 
transmission planning horizon to identify Long-Term Transmission Needs 
and enable the identification and evaluation of transmission facilities 
to meet such transmission needs.\677\ The Commission defined best 
available data inputs as data inputs that are timely, developed using 
best practices and diverse and expert perspectives, adopted via a 
process that satisfies the transmission planning principles of Order 
Nos. 890 and 1000, and reflect the list of factors that transmission 
providers account for in their Long-Term Scenarios.\678\
---------------------------------------------------------------------------

    \677\ Order No. 1920, 187 FERC ] 61,068 at P 302.
    \678\ Id. P 633.
---------------------------------------------------------------------------

    228. The Commission clarified that using a transmission planning 
horizon of no less than 20 years means that transmission providers must 
develop Long-Term Scenarios to identify Long-Term Transmission Needs 
that will materialize in the 20 years or more following the 
commencement of the Long-Term Regional Transmission Planning 
cycle.\679\ The Commission explained that requiring a transmission 
planning horizon of not less than 20 years strikes a balance. On the 
one hand, the Commission stated, a 20-year transmission planning 
horizon extends far enough into the future that transmission providers 
can proactively identify Long-Term Transmission Needs that could be met 
with more efficient or cost-effective Long-Term Regional Transmission 
Facilities and allows sufficient time to identify, plan, obtain siting 
and permitting approval for, and construct more efficient or cost-
effective Long-Term Regional Transmission Facilities. On the other 
hand, the Commission found that there may be sufficient uncertainty 
regarding system conditions and transmission needs beyond a 20-year 
transmission planning horizon such that it may be challenging for 
transmission providers to forecast Long-Term Transmission Needs across 
that time period.\680\
---------------------------------------------------------------------------

    \679\ Id. P 344.
    \680\ Id. P 345.
---------------------------------------------------------------------------

    229. In adopting the minimum 20-year transmission planning horizon 
requirement in Order No. 1920, the Commission disagreed that a 20-year 
transmission planning horizon could result in Long-Term Regional 
Transmission Planning based on speculative transmission needs. The 
Commission explained that the Long-Term Regional Transmission Planning 
requirements adopted in Order No. 1920 are designed to avoid over-
building transmission in response to speculative transmission needs 
through a series of tools and safeguards, which include the requirement 
that transmission providers reevaluate Long-Term Regional Transmission 
Facilities in certain circumstances.\681\
---------------------------------------------------------------------------

    \681\ Id. P 348.
---------------------------------------------------------------------------

    230. The Commission also disagreed with requests that it adopt a 
shorter transmission planning horizon, reasoning that a shorter 
planning horizon would fail to sufficiently capture Long-Term 
Transmission Needs given that some drivers of such needs extend up to 
20 years into the future. The Commission added that a shorter minimum 
transmission planning horizon might not allow for sufficient time to 
develop Long-Term Regional Transmission Facilities with long lead-time 
requirements or to compare alternative transmission solutions to 
identify more efficient or cost-effective transmission solutions to 
meet Long-Term Transmission Needs.\682\
---------------------------------------------------------------------------

    \682\ Id. P 349.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    231. Alabama Commission, Ohio Commission Federal Advocate, and 
Dominion seek rehearing of Order No. 1920's requirement that 
transmission providers in each transmission planning region develop 
Long-Term Scenarios as part of Long-Term Regional Transmission Planning 
using no less than a 20-year transmission planning horizon.\683\
---------------------------------------------------------------------------

    \683\ Alabama Commission Rehearing Request at 4; Dominion 
Rehearing Request at 11-14; Ohio Commission Federal Advocate 
Rehearing Request at 20-21.
---------------------------------------------------------------------------

    232. Dominion contends that Order No. 1920 is arbitrary and 
capricious because the Commission failed to address Dominion's concerns 
regarding the use of a 20-year transmission planning horizon.\684\ 
Dominion asserts that the Commission failed to address its NOPR 
comments, which argued that a 20-year transmission planning horizon 
runs the risk of essentially implementing a ``transmission Integrated 
Resource Plan'' that mandates potentially speculative transmission 
projects. Dominion avers that integrated resource plans are snapshots 
in time that show potential pathways for meeting future needs and are 
not

[[Page 97224]]

concrete, definitive plans.\685\ Dominion states that in its NOPR 
comments it explained that predicting the future resource mix is 
challenging and that numerous planning considerations that apply today 
could change over the next 20 years, which is why Dominion cautioned 
against requiring transmission providers to make investment and cost 
allocation decisions based on speculation 20 years into the 
future.\686\
---------------------------------------------------------------------------

    \684\ Dominion Rehearing Request at 7, 12-15.
    \685\ Id. at 13-14 (citing Dominion NOPR Initial Comments at 18-
19).
    \686\ Id. at 14 (citing Dominion NOPR Initial Comments at 20).
---------------------------------------------------------------------------

    233. According to Dominion, its NOPR comments also asserted that a 
20-year transmission planning horizon requires using less reliable 
assumptions, which can lead to stranded or misallocated costs,\687\ 
especially because cost allocation under Order No. 1920 could occur 
much earlier than before.\688\ Dominion argues that planning further 
into the future decreases certainty, likely has diminishing returns, 
and requires transmission providers to deploy personnel with scarce 
planning expertise--a highly valuable resource--who could be used more 
efficiently by planning for likelier scenarios.\689\
---------------------------------------------------------------------------

    \687\ Id. (citing Dominion NOPR Initial Comments at 20).
    \688\ Id.
    \689\ Id. at 15.
---------------------------------------------------------------------------

    234. Further, Dominion argues that because Order No. 1920 would not 
necessarily permit reevaluation in certain circumstances that could 
render a transmission project unnecessary--e.g., where changes in 
technology or load growth obviate the need for a project in a 
particular location--the reevaluation process is insufficient to 
address concerns regarding the speculative nature of a 20-year planning 
horizon.\690\
---------------------------------------------------------------------------

    \690\ Id. at 16-18.
---------------------------------------------------------------------------

    235. Dominion also argues that the Commission arbitrarily dismissed 
its requests for flexibility to adopt a timeline that is suited to a 
particular transmission planning region to reduce the risk of selection 
of transmission projects that may not actually be needed.\691\ Dominion 
states that, if the Commission must prescribe a minimum transmission 
planning horizon, it would be more reasonable to continue allowing PJM/
Dominion Energy Virginia to use a 15-year forecast horizon, which 
strikes a balance between long-term needs and avoiding speculative 
projects, and to continue allowing South Carolina Regional Transmission 
Planning/Dominion Energy South Carolina to use a 10-year transmission 
planning horizon. Such transmission planning horizons, Dominion claims, 
would be more tailored to the transmission planning regions' 
needs.\692\
---------------------------------------------------------------------------

    \691\ Id. at 15.
    \692\ Id. at 12-13, 16.
---------------------------------------------------------------------------

    236. Ohio Commission Federal Advocate also asserts that the 
Commission acted arbitrarily and capriciously and violated the consumer 
protection provisions of the FPA by adopting the 20-year transmission 
planning horizon requirement. Ohio Commission Federal Advocate argues 
that a 20-year transmission planning horizon puts transmission planners 
in the ``impossible position'' of having to predict the resource mix 
and location of resources 20 years in the future and will lead to 
inefficient and potentially unnecessary investment decisions.\693\ In 
the alternative to seeking rehearing on the 20-year transmission 
planning horizon requirement, Ohio Commission Federal Advocate requests 
that the Commission clarify that the 20-year planning horizon should be 
informational only and should not be relied upon for investment 
decisions until the future can be better ascertained.\694\ Similarly, 
Alabama Commission contends that a 20-year transmission planning 
horizon is likely to produce speculative outputs that lack sufficient 
basis for actionable planning decisions and that action on these 
outputs should be determined at the state level to avoid costly 
transmission facilities that are not actually needed.\695\
---------------------------------------------------------------------------

    \693\ Ohio Commission Federal Advocate Rehearing Request at 20-
21.
    \694\ Id. at 21.
    \695\ Alabama Commission Rehearing Request at 4.
---------------------------------------------------------------------------

    i. Commission Determination
    237. We sustain the requirement that transmission providers in each 
transmission planning region develop Long-Term Scenarios as part of 
Long-Term Regional Transmission Planning using no less than a 20-year 
transmission planning horizon. The Commission's adoption of a 20-year 
transmission planning horizon was reasonable and supported by record 
evidence,\696\ and the Commission did not disregard arguments to the 
contrary. As the Commission explained in Order No. 1920, a transmission 
planning horizon of less than 20 years would fail to sufficiently 
capture Long-Term Transmission Needs given that drivers of such needs 
can extend up to 20 years into the future, such as state laws that 
include requirements to be met 15 to 20 years in the future.\697\ In 
addition, a 20-year transmission planning horizon allows for more time 
between when a transmission facility is identified to meet a future 
transmission need and when the transmission need materializes, allowing 
for sufficient time to identify, plan, obtain siting and permitting 
approval for, and construct Long-Term Regional Transmission 
Facilities.\698\
---------------------------------------------------------------------------

    \696\ See Order No. 1920, 187 FERC ] 61,068 at PP 309-318 
(describing support for a transmission planning horizon of at least 
20 years).
    \697\ Id. P 349.
    \698\ Id. P 345; see also id. P 312 (describing arguments of 
commenters whose comments supported a 20-year transmission planning 
horizon).
---------------------------------------------------------------------------

    238. Moreover, we continue to find that a shorter minimum 
transmission planning horizon may not allow for sufficient time to 
develop Long-Term Regional Transmission Facilities with long lead-time 
requirements or to compare alternative transmission solutions to 
identify more efficient or cost-effective transmission solutions to 
meet Long-Term Transmission Needs.\699\ We therefore are not convinced 
by arguments that the Commission should have adopted a minimum 
transmission planning horizon shorter than 20 years.
---------------------------------------------------------------------------

    \699\ Id. P 349.
---------------------------------------------------------------------------

    239. We disagree with arguments that the minimum 20-year 
transmission planning horizon could result in the selection of 
speculative transmission projects or will lead to inefficient and 
potentially unnecessary investment decisions,\700\ including Dominion's 
related argument that a 20-year transmission planning horizon runs the 
risk of ``essentially implementing a transmission Integrated Resource 
Plan [] that mandates investments in potentially speculative 
transmission projects'' or may result in imprecision and could lead to 
stranded or misallocated costs.\701\ As the Commission found in Order 
No. 1920, the Long-Term Regional Transmission Planning requirements 
include tools and safeguards designed to avoid over-building 
transmission in response to speculative transmission needs.\702\ These 
tools and safeguards include: (1) the requirement that transmission 
providers develop (and periodically update) multiple plausible and 
diverse Long-Term Scenarios based upon best available data; (2) 
transmission providers' flexibility to develop evaluation processes, 
including selection criteria, that will enable them to select Long-Term 
Regional Transmission Facilities in a way that maximizes benefits 
accounting for costs

[[Page 97225]]

over time without over-building transmission facilities; and (3) the 
lack of a selection mandate.\703\ We continue to find that, by 
facilitating regional transmission planning that accounts for a range 
of potential futures, Order No. 1920 ensures that transmission 
providers will be able to manage uncertainty, which, in turn, mitigates 
the risk of speculative transmission development.\704\
---------------------------------------------------------------------------

    \700\ Alabama Commission Rehearing Request at 4; Dominion 
Rehearing Request at 11-15; Ohio Commission Rehearing Request at 20-
21.
    \701\ Dominion Rehearing Request at 13-14.
    \702\ Order No. 1920, 187 FERC ] 61,068 at P 348.
    \703\ Id. P 231.
    \704\ Id. P 229.
---------------------------------------------------------------------------

    240. Although Dominion argues that the reevaluation process is 
insufficient to address concerns that a 20-year transmission planning 
horizon could lead to the selection of speculative transmission 
projects,\705\ Dominion does not demonstrate how Order No. 1920's other 
tools and safeguards beyond the reevaluation requirement are 
individually or collectively insufficient to prevent over-building 
transmission in response to speculative transmission needs.\706\ 
Moreover, robust scenario-planning allows transmission providers to 
compare the costs and benefits of Long-Term Regional Transmission 
Facilities under different future conditions, which informs selection 
and consequently helps to mitigate uncertainty.
---------------------------------------------------------------------------

    \705\ Dominion Rehearing Request at 16-18.
    \706\ For example, Order No. 1920 requires transmission 
providers to develop (and periodically update) multiple plausible 
and diverse Long-Term Scenarios based upon best available data, 
provides transmission providers with flexibility to develop 
evaluation processes, including selection criteria, that will enable 
them to select Long-Term Regional Transmission Facilities in a way 
that maximizes benefits accounting for costs over time without over-
building transmission facilities, and lacks a selection mandate.
---------------------------------------------------------------------------

    241. In addition, as discussed later,\707\ we also clarify that 
transmission providers must consult with and consider the positions of 
the Relevant State Entities as to how to account for factors related to 
states' laws, policies, and regulations in transmission planning 
assumptions, which will ensure that such factors are effectively 
accounted for in the development of Long-Term Scenarios. We believe 
this clarification mitigates Ohio Commission Federal Advocate's 
concerns that the 20-year transmission planning horizon could result in 
unnecessary investment.\708\ With this clarification, Order No. 1920 
provides transmission providers with the tools and safeguards that they 
need to manage uncertainty and mitigate the risk of speculative 
regional transmission development while preserving the benefits of 
Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \707\ Infra Stakeholder Process and Transparency section.
    \708\ We also note that the transparency requirements adopted 
herein, see infra Evaluation and Selection of Long-Term Regional 
Transmission Facilities, will provide states with additional insight 
into the efficiency and cost-effectiveness of any Long-Term Regional 
Transmission Facilities that transmission providers select.
---------------------------------------------------------------------------

    242. For the same reason, we are unpersuaded by Alabama 
Commission's related argument that action on transmission plans should 
be determined at the state level to avoid costly transmission 
facilities that may not be needed. Nonetheless, as further discussed in 
this order, we clarify Order No. 1920 to require transmission providers 
to include and consider the perspective of Relevant State Entities in 
multiple ways, including: (1) to consult with and consider the 
positions of the Relevant State Entities and any other entity 
authorized by a Relevant State Entity as its representative as to how 
to account for factors related to states' laws, policies, and 
regulations when determining the assumptions that will be used in the 
development of Long-Term Scenarios; (2) to include any Long-Term 
Regional Transmission Cost Allocation Method and/or State Agreement 
Process that Relevant State Entities agree to in the transmittal or as 
an attachment to their compliance filings; (3) to consult with Relevant 
State Entities (a) prior to amending the ex ante Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es) agreed to by Relevant State Entities or (b) if Relevant 
State Entities seek for a transmission provider to amend the method on 
file; (4) to develop a reasonable number of additional scenarios, when 
requested by Relevant State Entities, for the purposes of informing the 
application of Long-Term Regional Cost Allocation Method(s) or the 
development of cost allocation methods through the State Agreement 
Process(es); and (5) to make available, on a password-protected portion 
of OASIS or other password-protected website, a breakdown of the 
allocated costs, by zone (i.e., by transmission provider retail 
distribution service territory/footprint or RTO/ISO transmission 
pricing zone), and a quantification of the benefits imputed to each 
zone, as such benefits can be reasonably estimated, when a cost 
allocation method is agreed upon under a State Agreement Process or, if 
no State Agreement Process is used, at the time the transmission 
provider selects the Long-Term Regional Transmission Facility. These 
additional measures to involve states will resolve Alabama Commission's 
concern and prevent costly transmission facilities that are not 
actually needed from being constructed.
    243. As to another argument raised by Alabama Commission, which we 
interpret to argue that Long-Term Regional Transmission Planning should 
serve only to inform other transmission planning processes, we continue 
to find that remedying the deficiencies in the Commission's existing 
regional transmission planning requirements requires that transmission 
providers adopt the requirements herein, which will allow them to 
identify and have the opportunity to select more efficient or cost-
effective Long-Term Regional Transmission Facilities to meet Long-Term 
Transmission Needs.\709\
---------------------------------------------------------------------------

    \709\ Order No. 1920, 187 FERC ] 61,068 at P 914.
---------------------------------------------------------------------------

    244. We disagree with Dominion's argument that the Commission 
failed to address commenters' request for flexibility regarding the 
length of the minimum transmission planning horizon. The Commission has 
already justified its decision not to adopt a shorter transmission 
planning horizon, reasoning that a planning horizon of less than 20 
years would be insufficient to capture Long-Term Transmission Needs, 
develop and construct Long-Term Regional Transmission Facilities with 
long lead-time requirements, and compare alternative transmission 
solutions to identify more efficient or cost-effective transmission 
solutions to meet Long-Term Transmission Needs.\710\ The Commission 
explained why providing transmission providers with flexibility to 
choose a shorter transmission planning horizon would limit transmission 
providers' ability to adequately plan for Long-Term Transmission Needs 
and perpetuate the status quo, thus failing to address the deficiencies 
that the Commission identified in its existing regional transmission 
planning and cost allocation requirements.\711\ Moreover, in adopting 
the 20-year minimum transmission planning horizon, the Commission 
struck a balance between, on the one hand, providing transmission 
providers with sufficient time to proactively identify Long-Term 
Transmission Needs and ultimately construct more efficient or cost-
effective Long-Term Regional Transmission Facilities to meet those 
needs, and, on the other hand, avoiding uncertainty regarding system 
conditions and

[[Page 97226]]

transmission needs beyond a 20-year horizon.\712\
---------------------------------------------------------------------------

    \710\ Id. P 349.
    \711\ See, e.g., id. PP 115-116 (finding that, under the status 
quo, most transmission planning regions do not plan beyond a 10-year 
transmission planning horizon, which prevents transmission providers 
from identifying Long-Term Transmission Needs and considering 
regional transmission facilities that may be more efficient or cost-
effective solutions to address those needs and fails to take 
advantage of the potential for efficiencies or economies of scale 
that regional transmission facilities can provide).
    \712\ Id. P 345.
---------------------------------------------------------------------------

    245. Finally, we reiterate that, in this order, the Commission 
clarifies Order No. 1920 to increase the states' involvement in the 
Long-Term Transmission Planning Process to provide them with a greater 
role in determining Long-Term Transmission Needs, and ensuring that 
they are able to provide input into the method used to allocate the 
costs of Long-Term Regional Transmission Facilities.
    246. For these reasons, we reject Dominion's request that the 
Commission allow PJM/Dominion Energy Virginia to continue to use a 15-
year transmission planning horizon and South Carolina Regional 
Transmission Planning/Dominion Energy South Carolina to continue to use 
a 10-year transmission planning horizon.\713\ Likewise, for these same 
reasons, we decline Ohio Commission Federal Advocate's request that the 
Commission clarify that Long-Term Scenarios resulting from a 20-year 
transmission planning horizon will be used for informational purposes 
only.
---------------------------------------------------------------------------

    \713\ See Dominion Rehearing Request at 12-13, 16.
---------------------------------------------------------------------------

    247. Further, we find unpersuasive Ohio Commission Federal 
Advocate's allegation that the Commission contravened the consumer-
protection requirements of the FPA by adopting a 20-year minimum 
transmission planning horizon.\714\ Ohio Commission Federal Advocate 
does not state how the 20-year minimum transmission planning horizon 
contravenes the FPA nor does it specify which requirements of the FPA 
the Commission allegedly transgressed by adopting the 20-year minimum 
transmission planning horizon requirement. To the extent that Ohio 
Commission Federal Advocate is claiming that the 20-year minimum 
transmission planning horizon requirement will result in unjust and 
unreasonable rates, as discussed above, we have provided a number of 
flexibilities to increase the states' involvement in Long-Term Regional 
Transmission Planning and to ensure that there is a significant degree 
of transparency in Long-Term Regional Transmission Planning, both of 
which will ensure that rates are just and reasonable. Recognizing these 
additional flexibilities, we continue to find the required 20-year 
minimum transmission planning horizon is integral to the requirement 
that transmission providers conduct long-term, forward-looking, and 
more comprehensive regional transmission planning.\715\ The Commission 
found that such a requirement is necessary to remedy the deficiencies 
that it identified in its existing regional transmission planning and 
cost allocation requirements \716\ and will help transmission providers 
to identify, evaluate, and select more efficient or cost-effective 
transmission solutions to Long-Term Transmission Needs, which will help 
ensure just and reasonable rates.\717\
---------------------------------------------------------------------------

    \714\ See Ohio Commission Federal Advocate Rehearing Request at 
20.
    \715\ See Order No. 1920, 187 FERC ] 61,068 at PP 345, 349.
    \716\ Id. P 134.
    \717\ See id. PP 345, 349.
---------------------------------------------------------------------------

3. Frequency of Long-Term Scenario Revisions
a. Order No. 1920 Requirements
    248. In Order No. 1920, the Commission modified the NOPR proposal 
and required transmission providers in each transmission planning 
region to reassess and revise the Long-Term Scenarios that they use in 
Long-Term Regional Transmission Planning at least once every five 
years,\718\ rather than at least every three years as the NOPR 
proposed.\719\ The Commission explained that, in implementing this 
requirement, transmission providers in each transmission planning 
region must reassess whether the data inputs and factors incorporated 
in previously developed Long-Term Scenarios need to be updated and then 
revise those Long-Term Scenarios, as needed, to reflect updated data 
inputs and factors.\720\ The Commission clarified that a Long-Term 
Regional Transmission Planning cycle, which begins with the development 
of Long-Term Scenarios using best available data inputs,\721\ and 
proceeds to identifying Long-Term Transmission Needs, measuring the 
benefits of Long-Term Regional Transmission Facilities to address those 
needs, and evaluating and deciding whether to select Long-Term Regional 
Transmission Facilities, must conclude no later than five years after 
the date it began.\722\ Transmission providers must complete these 
steps of the Long-Term Regional Transmission Planning cycle, including 
selection decisions, no later than three years from the date that the 
Long-Term Regional Transmission Planning cycle began.\723\
---------------------------------------------------------------------------

    \718\ Id. P 377.
    \719\ NOPR, 179 FERC ] 61,028 at P 97.
    \720\ Order No. 1920, 187 FERC ] 61,068 at P 377.
    \721\ At the outset of a Long-Term Regional Transmission 
Planning cycle, transmission providers may develop the new Long-Term 
Scenarios either by crafting entirely new Long-Term Scenarios or by 
updating the data inputs and factors for previously developed Long-
Term Scenarios. Id.
    \722\ Id. P 378.
    \723\ Id. P 379.
---------------------------------------------------------------------------

    249. The Commission stated that nothing in Order No. 1920 prevents 
transmission providers from evaluating and selecting additional Long-
Term Regional Transmission Facilities after year three of the Long-Term 
Regional Transmission Planning cycle and before the next five-year 
Long-Term Regional Transmission Planning cycle begins.\724\ However, 
the Commission explained that, if Long-Term Regional Transmission 
Facilities are selected at year three of the Long-Term Regional 
Transmission Planning cycle, those same Long-Term Regional Transmission 
Facilities cannot be de-selected during the remainder of the current 
five-year planning cycle.\725\
---------------------------------------------------------------------------

    \724\ Id. P 379 n.873.
    \725\ Id.
---------------------------------------------------------------------------

    250. The Commission found that, while three years provides 
sufficient time for transmission providers to complete the steps of the 
Long-Term Regional Transmission Planning cycle,\726\ requiring the 
Long-Term Regional Transmission Planning cycle to repeat at three-year 
intervals could be administratively burdensome and the benefit of 
updating Long-Term Scenarios every three years may not outweigh those 
additional burdens.\727\ Thus, the Commission found that requiring 
selection decisions to occur within three years of commencing a Long-
Term Regional Transmission Planning cycle, while allowing as long as 
five years between the commencement of each planning cycle, strikes an 
appropriate balance between various benefits and burdens.\728\ Order 
No. 1920 required that transmission providers conclude one Long-Term 
Regional Transmission Planning cycle before developing Long-Term 
Scenarios at the beginning of the next Long-Term Regional Transmission 
Planning cycle.\729\
---------------------------------------------------------------------------

    \726\ Order No. 1920, 187 FERC ] 61,068 at P 379 (citations 
omitted).
    \727\ Id. (citations omitted).
    \728\ Id.
    \729\ Id. P 381.
---------------------------------------------------------------------------

    251. Order No. 1920 also required transmission providers to 
designate a point in the evaluation process at which they will decide 
to either select or not select the relevant Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) along with a 
point in time or action that concludes a Long-Term Regional 
Transmission Planning cycle.\730\ The Commission further stated that 
transmission providers may propose on compliance to conduct

[[Page 97227]]

Long-Term Regional Transmission Planning more frequently than every 
five years.\731\
---------------------------------------------------------------------------

    \730\ Id.
    \731\ Id. P 384.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    252. PIOs request rehearing of the Commission's decision to extend 
the Long-Term Regional Transmission Planning Cycle from three years to 
five years. They request that the Commission reduce the Long-Term 
Regional Transmission Planning cycle to three years.\732\ PIOs argue 
that the Commission's decision to extend the Long-Term Regional 
Transmission Planning cycle from three years, as it proposed in the 
NOPR, to five years lacked support in the record, was not based on the 
Commission's findings, and was arbitrary and capricious given the 
urgency of the problem.\733\ PIOs assert that the faster transmission 
drivers change, the more frequently Long-Term Scenarios should be 
updated.\734\ PIOs contend that, in decreasing the frequency of Long-
Term Regional Transmission Planning cycles, the Commission disregarded 
evidence that transmission drivers--e.g., reliability concerns, demand, 
interconnection request capacity--have changed at an accelerating pace, 
since the issuance of the NOPR.\735\
---------------------------------------------------------------------------

    \732\ PIOs Rehearing Request at 9-15.
    \733\ Id. at 6 (citations omitted).
    \734\ Id. at 10-11.
    \735\ Id. at 9-11 (citations omitted).
---------------------------------------------------------------------------

    253. PIOs aver that under Order No. 1920, transmission providers 
complete the entire substance of the planning cycle projects in the 
first three years, followed by a ``fallow period'' for up to two 
years.\736\ This structure, PIOs argue, fails to alleviate the 
purported administrative burdens associated with the NOPR's three-year 
proposal and undermines Order No. 1920's essential purpose of requiring 
transmission providers to identify and address rapidly-shifting and 
critical regional transmission needs with urgency.\737\ PIOs assert 
that it is illogical for the Commission to claim that transmission 
providers need two additional years at the end of each cycle to update 
model inputs in preparation for the next transmission planning cycle 
when they initially assembled that same information, from scratch, in 
three years.\738\
---------------------------------------------------------------------------

    \736\ Id. at 11 (citing Order No. 1920, 187 FERC ] 61,068 at PP 
378-379).
    \737\ Id. at 12.
    \738\ Id. at 12-13.
---------------------------------------------------------------------------

    254. In support of their request that the Commission grant 
rehearing and adopt the NOPR's proposed three-year transmission 
planning cycle, PIOs also assert that the structure of the five-year 
planning structure is unclear. PIOs argue that Order No. 1920 nearly 
contradicts itself by stating that transmission providers must 
``determine whether to select Long-Term Regional Transmission 
Facilities no later than three years'' after the cycle begins and then 
adding that ``nothing in this final rule prevents transmission 
providers from evaluating and selecting additional Long-Term Regional 
Transmission Facilities after year three'' of the cycle and before the 
next cycle begins.\739\ PIOs argue that, while these and similar 
statements are facially irreconcilable, they could be harmonized under 
a reading that would allow transmission providers to make final 
selection decisions on any Long-Term Regional Transmission Facilities 
up until the end of the five-year transmission planning cycle as long 
as they make a selection decision on at least one Long-Term Regional 
Transmission Facility before the end of year three.\740\ According to 
PIOs, however, such a structure would undermine stakeholder concerns 
about changes to the planning process that occur mid-stream that would 
require re-running an analysis and would encourage transmission 
providers to make decisions when stakeholders are no longer at the 
table.\741\ PIOs request that the Commission grant rehearing and adopt 
the NOPR's widely supported three-year transmission planning 
cycle.\742\
---------------------------------------------------------------------------

    \739\ Id. at 13 (quoting Order No. 1920, 187 FERC ] 61,068 at PP 
379, 381).
    \740\ Id. at 14.
    \741\ Id. at 13-14.
    \742\ Id. at 15. PIOs also argue that, for the small minority of 
entities that need more initial flexibility beyond the one-year 
period entities already have to file compliance filings, the 
Commission could allow for case-by-case extensions. Id.
---------------------------------------------------------------------------

    255. SERTP Sponsors request clarification as to what Order No. 1920 
requires with respect to the inclusion of previously selected Long-Term 
Regional Transmission Facilities in updated base or reference cases 
that transmission providers use in the subsequent Long-Term Regional 
Transmission Planning cycle. SERTP Sponsors claim that Order No. 1920 
may be inconsistent on this question because one section of the rule 
appears to require transmission providers to include such facilities in 
these updated base or reference cases while another section of the rule 
appears to provide flexibility on this issue.\743\
---------------------------------------------------------------------------

    \743\ SERTP Sponsors Rehearing Request at 26-27 (citing Order 
No. 1920, 187 FERC ] 61,068 at PP 382, 1031).
---------------------------------------------------------------------------

c. Commission Determination
    256. We sustain the requirement that transmission providers in each 
transmission planning region reassess and revise the Long-Term 
Scenarios that they use in Long-Term Regional Transmission Planning at 
least once every five years.\744\ We disagree with PIOs that the 
decision to extend the Long-Term Regional Transmission Planning cycle 
from three years to five years lacked support in the record, was not 
based on the Commission's findings, and was arbitrary and capricious.
---------------------------------------------------------------------------

    \744\ See Order No. 1920, 187 FERC ] 61,068 at P 377.
---------------------------------------------------------------------------

    257. First, we are not persuaded by PIOs' argument that, by 
extending the Long-Term Regional Transmission Planning cycle, the 
Commission acted inconsistently with its findings in Order No. 1920 
that transmission needs are changing at an increasingly rapid 
pace.\745\ In Order No. 1920, the Commission addressed the pace at 
which transmission drivers are changing, finding that transmission 
providers must reassess and revise their Long-Term Scenarios at least 
once every five years to ensure that the Long-Term Scenarios accurately 
reflect factors that may change over the five-year time span, such as 
changes in technology, load forecasts, or federal, federally-recognized 
Tribal, state, or local laws.\746\ While transmission needs, and the 
factors driving those needs, are indeed changing rapidly, PIOs provide 
insufficient and unconvincing support for their argument that a five-
year Long-Term Regional Transmission Planning cycle is incapable of 
accounting for that pace of change. Further, we underscore that Order 
No. 1920 provides transmission providers with flexibility to address 
evolving transmission needs. For instance, nothing in Order No. 1920 
prohibits transmission providers from updating the assumptions, inputs, 
and factors, used to inform Long-Term Scenarios during a Long-Term 
Regional Transmission Planning cycle,\747\ and, to the extent that 
transmission providers believe that a shorter Long-Term Regional 
Transmission Planning cycle is necessary to account for the pace of 
change, they may propose on compliance to conduct Long-Term

[[Page 97228]]

Regional Transmission Planning more frequently than every five 
years.\748\
---------------------------------------------------------------------------

    \745\ PIOs Rehearing Request at 9-11.
    \746\ Order No. 1920, 187 FERC ] 61,068 at P 380.
    \747\ See id. PP 380-381. We also note that, consistent with 
Order No. 890's transparency transmission planning principle, Order 
No. 1920 requires transmission providers in each transmission 
planning region to publicly disclose (subject to any applicable 
confidentiality protections) information and data inputs that they 
use to create each Long-Term Scenario. See id. P 560 (citing Order 
No. 890, 118 FERC ] 61,119 at P 471).
    \748\ See id. P 384.
---------------------------------------------------------------------------

    258. Second, the Commission's decision to require that Long-Term 
Regional Transmission Planning cycles occur at least every five years 
was guided by comments in the record urging the Commission to address 
competing priorities, including: (1) ensuring timely identification, 
evaluation, and selection of more efficient or cost-effective Long-Term 
Regional Transmission Facilities; (2) providing transmission providers 
with sufficient flexibility to address regional differences; and (3) 
limiting the administrative burdens placed on transmission 
providers.\749\ Order No. 1920's requirement that transmission 
providers reassess and revise the Long-Term Scenarios that they use in 
Long-Term Regional Transmission Planning at least once every five years 
strikes a reasonable balance between those priorities. Further, we 
disagree with PIOs' assertion that extending the Long-Term Regional 
Transmission Planning cycle from three years to five years does not 
ease administrative burdens or improve planning accuracy.\750\ In Order 
No. 1920, the Commission decreased the frequency at which Long-Term 
Regional Transmission Planning cycles must occur, meaning that 
transmission providers have the option to develop fewer Long-Term 
Scenarios over a five-year period than they would have been required to 
develop under the NOPR proposal, thus decreasing the administrative 
burden associated with updating the Long-Term Scenarios that form the 
basis for Long-Term Regional Planning during each planning cycle.
---------------------------------------------------------------------------

    \749\ See id. P 379.
    \750\ PIOs Rehearing Request at 12-13.
---------------------------------------------------------------------------

    259. Third, we are not persuaded by PIOs' argument that the 
structure of the Long-Term Regional Transmission Planning cycle is 
unclear or that its implementation will exclude meaningful stakeholder 
participation.\751\ Order No. 1920 requires transmission providers to 
complete the steps of the Long-Term Regional Transmission Planning 
cycle and make selection decisions no later than three years from the 
date when the Long-Term Regional Transmission Planning cycle 
began.\752\ To the extent that transmission providers decide to 
evaluate additional Long-Term Regional Transmission Facilities after 
year three but before the next Long-Term Regional Transmission Planning 
cycle begins, Order No. 1920 gives them the flexibility to do so.\753\ 
One possible outcome of this structure is that transmission providers 
may make selection decisions on additional Long-Term Regional 
Transmission Facilities until the end of the five-year Long-Term 
Regional Transmission Planning cycle. But we disagree with PIOs' 
contention that Order No. 1920 could be read to allow transmission 
providers to make ``final'' selection decisions on ``any'' Long-Term 
Regional Transmission Facilities until the five-year Long-Term Regional 
Transmission Planning cycle's end so long as they make a selection 
decision on at least one Long-Term Regional Transmission Facility 
before the end of year three.\754\
---------------------------------------------------------------------------

    \751\ Id. at 13-15.
    \752\ Order No. 1920, 187 FERC ] 61,068 at PP 379, 955.
    \753\ Id. P 379 n.873.
    \754\ PIOs Rehearing Request at 14.
---------------------------------------------------------------------------

    260. Order No. 1920 requires that transmission providers complete 
their evaluation and selection processes in the first three years of a 
Long-Term Regional Transmission Planning cycle, including identifying 
Long-Term Regional Transmission Facilities that address the Long-Term 
Transmission Needs that transmission providers identified, estimating 
the costs and measuring the benefits of those facilities, and making a 
selection decision on those facilities, including a determination that 
is sufficiently detailed for stakeholders to understand why particular 
facilities or portfolios of facilities were selected or not 
selected.\755\ After transmission providers have completed these steps, 
no later than three years after the beginning of the Long-Term Regional 
Transmission Planning cycle, transmission providers may select 
``additional'' Long-Term Regional Transmission Facilities, but they may 
not deselect any Long-Term Regional Transmission Facilities selected 
earlier in that Long-Term Regional Transmission Planning cycle.\756\
---------------------------------------------------------------------------

    \755\ See Order No. 1920, 187 FERC ] 61,068 at P 955.
    \756\ Id. P 379 n.873.
---------------------------------------------------------------------------

    261. We therefore disagree with PIOs' argument that the five-year 
structure of the Long-Term Regional Transmission Planning cycle would 
encourage transmission providers to make planning decisions when 
stakeholders are ``no longer at the table.'' \757\ Such arguments are 
predicated on a misunderstanding of what Order No. 1920 requires. We 
emphasize that any Long-Term Regional Transmission Facilities selected 
after year three of the Long-Term Regional Transmission Planning cycle 
are selected in the Long-Term Regional Transmission Planning process. 
Thus, contrary to PIOs' suggestion, the requirements for selecting 
Long-Term Regional Facilities apply, including the transparency 
requirements adopted in Order No. 1920, should transmission providers 
choose to evaluate and select additional Long-Term Regional 
Transmission Facilities after year three of the Long-Term Regional 
Transmission Planning cycle.\758\
---------------------------------------------------------------------------

    \757\ PIOs Rehearing Request at 14.
    \758\ See Order No. 1920, 187 FERC ] 61,068 at P 954.
---------------------------------------------------------------------------

    262. Finally, we provide clarification to SERTP Sponsors as to the 
inclusion of previously selected Long-Term Regional Transmission 
Facilities in the updated base or reference cases that transmission 
providers will use in subsequent Long-Term Regional Transmission 
Planning cycles. In most circumstances, we expect that transmission 
providers will include previously selected Long-Term Regional 
Transmission Facilities, including those that are not yet in service, 
in these updated planning models, and we continue to find that doing so 
will improve the accuracy of Long-Term Regional Transmission 
Planning.\759\ We expect that if transmission providers conclude that 
previously-selected Long-Term Regional Transmission Facilities are not 
appropriate to use in a base case, they would provide an explanation to 
stakeholders who may be relying on the base case in future transmission 
planning or generator interconnection studies as to why these 
facilities are not included. Nevertheless, we clarify that Order No. 
1920 does not require that transmission providers include previously 
selected Long-Term Regional Transmission Facilities in the planning 
models that they use in a subsequent Long-Term Regional Transmission 
Planning cycle, and we continue to find that it is appropriate to 
provide flexibility to transmission providers on how they update their 
planning models.\760\
---------------------------------------------------------------------------

    \759\ See id. P 382.
    \760\ See id. P 1031.
---------------------------------------------------------------------------

4. Categories of Factors
a. Requirement To Incorporate Categories of Factors
i. Order No. 1920 Requirements
    263. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to incorporate in the 
development of Long-Term Scenarios seven specific categories of 
factors: (1) federal, federally-recognized Tribal, state, and local 
laws and regulations affecting the resource mix and demand;

[[Page 97229]]

(2) federal, federally-recognized Tribal, state, and local laws and 
regulations on decarbonization and electrification; (3) state-approved 
integrated resource plans and expected supply obligations for load-
serving entities; (4) trends in fuel costs and in the cost, 
performance, and availability of generation, electric storage 
resources, and building and transportation electrification 
technologies; (5) resource retirements; (6) generator interconnection 
requests and withdrawals; and (7) utility and corporate commitments and 
federal, federally-recognized Tribal, state, and local policy goals 
that affect Long-Term Transmission Needs.\761\ The Commission found 
that incorporating these categories of factors in the development of 
Long-Term Scenarios is necessary because these categories are essential 
to identifying Long-Term Transmission Needs, and that incorporating 
them will ensure that transmission providers are accounting for known 
and identifiable drivers of Long-Term Transmission Needs.\762\ The 
Commission stated that transmission providers may not exclude any of 
the proposed categories of factors from the development of Long-Term 
Scenarios because each category of factors includes important drivers 
of Long-Term Transmission Needs, and that not incorporating all of the 
categories of factors will increase the likelihood that transmission 
providers will continue to underestimate or omit certain drivers of 
Long-Term Transmission Needs.\763\
---------------------------------------------------------------------------

    \761\ Id. P 409.
    \762\ Id. P 410.
    \763\ Id. P 411.
---------------------------------------------------------------------------

    264. The Commission explained that incorporating a category of 
factors in the development of Long-Term Scenarios requires transmission 
providers to use factors in the category, for each factor individually 
or collectively, to determine the assumptions that will be used in the 
development of Long-Term Scenarios.\764\ The Commission stated that it 
expects that similar factors (or groups of factors) affecting a single 
assumption used in the development of Long-Term Scenarios will have an 
additive effect on that assumption.\765\ Further, transmission 
providers must incorporate the categories of factors in the development 
of Long-Term Scenarios in a way that results in plausible and diverse 
Long-Term Scenarios.\766\
---------------------------------------------------------------------------

    \764\ Id. P 413.
    \765\ Id.
    \766\ Id. P 414.
---------------------------------------------------------------------------

    265. With respect to factors within each category of factors, Order 
No. 1920 requires that transmission providers account for the factors 
that they have determined are likely to affect Long-Term Transmission 
Needs. Order No. 1920 further requires transmission providers, in 
coordination with stakeholders through an open and transparent process, 
to determine how each of those factors (or group of similar factors) is 
likely to affect Long-Term Transmission Needs. Transmission providers 
must then account for the factors that they have determined are likely 
to affect Long-Term Transmission Needs in the development of Long-Term 
Scenarios but need not account for a factor that they determine is 
unlikely to affect Long-Term Transmission Needs.\767\
---------------------------------------------------------------------------

    \767\ Id. P 415.
---------------------------------------------------------------------------

    266. The Commission stated that requiring transmission providers to 
incorporate the seven categories of factors into the development of 
Long-Term Scenarios strikes the right balance between prescriptive 
requirements and flexibility.\768\ The Commission also stated that the 
final rule does not direct the development of specific transmission 
facilities because transmission providers retain discretion to 
determine how specific factors will affect Long-Term Transmission 
Needs.\769\
---------------------------------------------------------------------------

    \768\ Id. P 417.
    \769\ Id. P 419.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    267. Arizona Commission argues that Order No. 1920's requirement 
that transmission providers use a specific set of ``planning 
criteria,'' i.e., that transmission providers incorporate seven 
categories of factors in Long-Term Scenarios, is ``simply a way of 
`pre-cooking' outcomes.'' \770\ Arizona Commission argues that this is 
inconsistent with the NOPR, which required transmission providers to 
implement a process, not achieve specific outcomes.\771\
---------------------------------------------------------------------------

    \770\ Arizona Commission Rehearing Request at 18.
    \771\ Id.
---------------------------------------------------------------------------

    268. SERTP Sponsors request that the Commission clarify or, in the 
alternative, grant rehearing to specify that Order No. 1920 does not 
require each factor to have an additive effect on a common assumption 
because, in their view, such a requirement would be arbitrary and 
capricious and not supported by substantial evidence.\772\ SERTP 
Sponsors assert that requiring each factor to have an additive effect 
would undermine transmission providers' discretion over how to account 
for different factors.\773\
---------------------------------------------------------------------------

    \772\ SERTP Sponsors Rehearing Request at 12-13.
    \773\ Id. at 13.
---------------------------------------------------------------------------

    269. Further, SERTP Sponsors argue that the record does not 
demonstrate that each individual factor will have an additive effect, 
and a finding to this effect risks overstating the effect of each 
factor, which would render the resulting scenarios implausible and more 
likely to misidentify Long-Term Transmission Needs and Facilities.\774\
---------------------------------------------------------------------------

    \774\ Id.
---------------------------------------------------------------------------

    270. Designated Retail Regulators and Undersigned States request 
that the Commission grant rehearing on the grounds that the Order No. 
1920 requirement to use the seven categories of factors in Long Term 
Regional Transmission Planning will overvalue transmission benefits and 
will result in unjust, unreasonable, and unduly discriminatory 
rates.\775\ Designated Retail Regulators and Undersigned States argue 
that transmission planning assumptions should reflect regional 
differences, and that requiring transmission providers to develop Long-
Term Scenarios that incorporate Order No. 1920's seven categories of 
factors will result in unjust and unreasonable rates because the 
categories of factors overlap and may result in double counting.\776\ 
Designated Retail Regulators and Undersigned States also assert that 
there is insufficient evidence and analysis to conclude that use of the 
factors will result in cost-effective solutions.\777\
---------------------------------------------------------------------------

    \775\ Designated Retail Regulators Rehearing Request at 8, 26; 
Undersigned States Rehearing Request at 8, 26.
    \776\ Designated Retail Regulators Rehearing Request at 8, 26-
29; Undersigned States Rehearing Request at 8, 26-29.
    \777\ Designated Retail Regulators Rehearing Request at 8; 
Undersigned States Rehearing Request at 8.
---------------------------------------------------------------------------

iii. Commission Determination
    271. Regarding Arizona Commission's argument that Order No. 1920's 
requirement that transmission providers incorporate seven categories of 
factors into their development of Long-Term Scenarios predetermines 
outcomes in Long-Term Regional Transmission Planning, we reiterate 
that, in Order No. 1920, as clarified herein, the Commission gives 
transmission providers the tools necessary to respond to changing 
factors that drive Long-Term Transmission Needs.\778\ As discussed 
below in further detail,\779\ transmission providers must consult with 
and consider the positions of the Relevant State Entities and any other

[[Page 97230]]

entity authorized by a Relevant State Entity as its representative as 
to how to account for factors related to states' laws, policies, and 
regulations when determining the assumptions that will be used in the 
development of Long-Term Scenarios. The Commission also explained in 
both the NOPR and in Order No. 1920 that it is not requiring that 
transmission providers achieve any particular outcome via Long-Term 
Regional Transmission Planning,\780\ and Order No. 1920 does not 
mandate selection of any Long-Term Regional Transmission 
Facilities.\781\
---------------------------------------------------------------------------

    \778\ Order No. 1920, 187 FERC ] 61,068 at P 233.
    \779\ Infra Stakeholder Process and Transparency section.
    \780\ See, e.g., NOPR, 179 FERC ] 61,028 at PP 9, 245; Order No. 
1920, 187 FERC ] 61,068 at PP 232, 266.
    \781\ Order No. 1920, 187 FERC ] 61,068 at PP 1026-1027.
---------------------------------------------------------------------------

    272. In response to SERTP Sponsors' request for clarification, we 
clarify that Order No. 1920 does not require transmission providers, 
when determining the assumptions that they will use when developing 
Long-Term Scenarios where similar factors (or groups of factors) affect 
a single assumption, to assume that the factors have additive effects 
on the relevant assumptions. The Commission stated in Order No. 1920 
that it expected that similar factors (or groups of factors) affecting 
a single assumption used in the development of Long-Term Scenarios will 
have an additive effect on that assumption,\782\ but we agree with 
SERTP Sponsors that this may not always be the case, and at times, 
similar factors may not have an additive effect on assumptions used to 
develop Long-Term Scenarios. We also acknowledge that factors in 
different categories of factors may overlap.\783\
---------------------------------------------------------------------------

    \782\ Id. P 413.
    \783\ Id. P 440 (``We acknowledge that there could be overlap 
between Factor Categories One and Two because a certain law or 
regulation could reasonably be considered to fit into both 
categories. In such a circumstance, transmission providers must 
account for the law or regulation in one of the two categories, not 
both, to avoid double-counting of that factor's anticipated effect 
on Long-Term Transmission Needs.''). As another example, a utility 
commitment in Factor Category Seven would overlap with an integrated 
resource plan if the utility commitment was incorporated in the 
development of the integrated resource plan.
---------------------------------------------------------------------------

    273. We clarify that, where factors may have overlapping effects on 
the planning assumptions, transmission providers must avoid double 
counting the effect that those factors have on assumptions used to 
develop Long-Term Scenarios. Specifically, where there is overlap 
between factors in Factor Categories One through Three and factors in 
Factor Categories Four through Seven, or a factor could arguably be 
considered in a Factor Category in the first three categories or the 
last four categories, transmission providers must incorporate that 
factor in the appropriate Factor Category in the first three 
categories.\784\ Because Relevant State Entities and their designated 
representatives will participate in developing Long-Term Scenarios by 
informing how transmission providers account for the impact of 
individual factors, we believe that Relevant State Entities, working in 
concert with transmission providers, will be able to identify and 
minimize instances where factors overlap. Further, to the extent that 
factors in Factor Categories One through Three have overlapping effects 
on planning assumptions, transmission providers must ensure that each 
Long-Term Scenario accounts for the factors in Factor Categories One 
through Three without double counting their effects on planning 
assumptions. Finally, although we agree with SERTP Sponsors that 
similar factors will not always have an additive effect on assumptions 
used to develop Long-Term Scenarios, where similar factors do not 
overlap, we clarify our expectation that similar factors (or groups of 
factors) affecting certain assumptions used in the development of Long-
Term Scenarios will have a combined effect on those assumptions 
accordingly.
---------------------------------------------------------------------------

    \784\ For example, if a transmission provider determines that a 
factor will affect Long-Term Transmission Needs, but the factor 
could arguably be incorporated in Factor Category Three or Factor 
Category Seven, the transmission provider must incorporate this 
factor in Factor Category Three.
---------------------------------------------------------------------------

    274. In response to SERTP Sponsors' argument that the requirements 
in Order No. 1920 risk overstating the effect of each factor, which 
would render the resulting scenarios implausible and more likely to 
misidentify Long-Term Transmission Needs, we explain that Order No. 
1920 addresses this issue by allowing transmission providers to 
exercise discretion in how they account for each factor, provided that 
each Long-Term Scenario account for and be consistent with factors in 
the first three categories of factors.\785\ As the Commission noted in 
Order No. 1920, incorporating a category of factors into the 
development of Long-Term Scenarios does not require exacting precision; 
transmission providers may generalize how all of the discrete factors 
in a category of factors will, in the aggregate, affect the development 
of Long-Term Scenarios.\786\ In addition, the Commission held in Order 
No. 1920 that transmission providers have the discretion to determine 
whether specific factors must be accounted for within each category, 
how to account for specific factors in the development of Long-Term 
Scenarios, and how to vary the treatment of each category of factors 
across Long-Term Scenarios, provided that transmission providers assume 
that the laws, regulations, state-approved integrated resource plans, 
and expected supply obligations for load-serving entities that 
transmission providers have determined are likely to affect Long-Term 
Transmission Needs are fully met.\787\ Finally, we believe that the 
clarification discussed below will mitigate SERTP Sponsors' concern by 
ensuring that the effects of factors used to develop Long-Term 
Scenarios are not overstated.
---------------------------------------------------------------------------

    \785\ It is unclear whether SERTP Sponsors intended to argue 
that failure to grant clarification in this respect would result in 
Order No. 1920 exceeding the Commission's authority; to the extent 
they intended to do so, we find this argument has not been raised 
with the specificity required on rehearing. See supra Major 
Questions Doctrine section.
    \786\ Order No. 1920, 187 FERC ] 61,068 at P 413.
    \787\ Id. P 417.
---------------------------------------------------------------------------

    275. More specifically, Order No. 1920 states that transmission 
providers must give states and stakeholders a meaningful opportunity to 
provide timely input on how and what information to incorporate in 
Long-Term Scenarios, including how specific factors may affect Long-
Term Transmission Needs.\788\ We clarify below that, when incorporating 
planning for states' laws, policies, and regulations' into the 
development of Long-Term Scenarios, transmission providers must consult 
with and consider the positions of the Relevant State Entities and 
their designated representatives as to how those requirements will be 
realized.\789\ If, for example, states have laws regarding the future 
resource mix or decarbonization targets, the assumptions for how the 
power industry would need to evolve to meet those legal requirements 
should be developed in close consultation with the Relevant State 
Entities. We clarify that, for a state that has required integrated 
resource planning processes, transmission providers should include one 
of the state's preferred power system trajectories, including both the 
supply and demand side resource trajectory as appropriate, in each 
Long-Term Scenario, or include different state-preferred power system 
trajectories in different Long-Term Scenarios.
---------------------------------------------------------------------------

    \788\ Id. P 528.
    \789\ Infra Stakeholder Process and Transparency section.
---------------------------------------------------------------------------

    276. While we disagree with the rehearing arguments of Designated 
Retail Regulators and Undersigned States that the Order No. 1920 
requirement to use the seven categories

[[Page 97231]]

of factors in Long Term Regional Transmission Planning will result in 
overvaluing transmission benefits, we believe that the clarifications 
discussed herein will alleviate the concerns underlying their rehearing 
arguments. As an initial matter, we find arguments that the categories 
of factors overlap to be moot because, as clarified above, transmission 
providers should avoid double counting the effects of overlapping 
factors when developing Long-Term Scenarios. While these rehearing 
parties are correct that Order No. 1920 requires transmission providers 
to incorporate seven categories of factors, transmission providers 
retain specific discretion with respect to how they account for each 
individual factor within a category to develop the required Long-Term 
Scenarios.\790\ Further, as discussed below,\791\ we clarify that 
transmission providers must consult with and consider the positions of 
the Relevant State Entities and any other entity authorized by a 
Relevant State Entity as its representative as to how to account for 
factors related to states' laws, policies, and regulations when 
determining the assumptions that will be used in the development of 
Long-Term Scenarios, which will ensure that states have input into 
these factors and that these factors are not over or undervalued. We 
further note the Commission's finding in Order No. 1920 that 
transmission providers have discretion to reflect regional differences 
in the development of Long-Term Scenarios.\792\
---------------------------------------------------------------------------

    \790\ See, e.g., Order No. 1920, 187 FERC ] 61,068 at P 412 
(allowing transmission providers to propose to use additional 
categories of factors); id. P 413 (clarifying that incorporating 
categories of factors does not require exacting precision and 
allowing transmission providers to generalize how factors within the 
categories will, in the aggregate, affect the development of Long-
Term Scenarios); id. P 415 (allowing transmission providers to 
determine whether specific factors will affect Long-Term 
Transmission Needs and allowing transmission providers not to 
account for specific factors that they determine do not affect such 
needs); id. P 417 (allowing transmission providers to determine how 
to account for specific factors within different Long-Term 
Scenarios).
    \791\ Infra Stakeholder Process and Transparency section.
    \792\ Order No. 1920, 187 FERC ] 61,068 at P 417.
---------------------------------------------------------------------------

    277. We disagree with Designated Retail Regulators and with 
Undersigned States that Order No. 1920 provides insufficient evidence 
and analysis to conclude that use of the factors will result in cost-
effective solutions. As discussed above and below, we, in this order, 
adopt a number of clarifications to ensure that states are consulted 
regarding the use of factors to develop Long-Term Scenarios, which, in 
turn, affect which Long-Term Regional Transmission Facilities are 
selected. We also emphasize that the states have a significant role in 
working to create a cost allocation method that ensures any solutions 
that are selected have costs allocated appropriately to beneficiaries. 
Because of this involvement, we find that the potential risk of the 
categories of factors leading to solutions that are not cost-effective 
is diminished, particularly in light of the requirement that selection 
criteria used in Long-Term Regional Transmission Planning must seek to 
maximize benefits accounting for costs over time without over-building 
transmission facilities.\793\ Finally, we add that Order No. 1920 
included substantial evidence in the record to demonstrate that 
existing transmission planning and cost allocation processes were 
insufficient to ensure just and reasonable rates by inadequately 
accounting on a forward-looking basis for known determinants of Long-
Term Transmission Needs.\794\
---------------------------------------------------------------------------

    \793\ Id. P 964.
    \794\ Id. PP 112-133.
---------------------------------------------------------------------------

b. Specific Categories of Factors and the Treatment of Factors in the 
Development of Long-Term Scenarios
i. Order No. 1920 Requirements
    278. As stated above, in Order No. 1920, the Commission found that 
incorporating the seven categories of factors in the development of 
Long-Term Scenarios was necessary. The Commission stated that 
transmission providers may not exclude any of the categories of factors 
from being incorporated into the development of Long-Term Scenarios 
because each category includes important determinants of Long-Term 
Transmission Needs, and failing to incorporate all of the proposed 
categories of factors into Long-Term Scenarios would increase the 
likelihood that transmission providers would continue to underestimate 
or omit known determinants of Long-Term Transmission Needs.\795\ The 
Commission considered category-specific record evidence in support of 
its determination to adopt each of the seven categories of 
factors.\796\ The Commission declined to adopt additional categories of 
factors proposed by commenters because of a lack of substantial record 
evidence, or a finding that the commenter-proposed category of factors 
is already accounted for in other parts of Long-Term Regional 
Transmission Planning.\797\
---------------------------------------------------------------------------

    \795\ Id. P 411.
    \796\ Order No. 1920, 187 FERC ] 61,068 at PP 448-449, 457-458, 
464-466, 472-473, 481-484.
    \797\ Id. PP 492-494.
---------------------------------------------------------------------------

    279. The Commission in Order No. 1920 also required transmission 
providers in each transmission planning region to assume that legally 
binding obligations (i.e., federal, federally-recognized Tribal, state, 
and local laws and regulations) are followed, state-approved integrated 
resource plans are followed, and expected supply obligations for load-
serving entities are fully met.\798\ The Commission therefore required 
each Long-Term Scenario to account for and be consistent with, and not 
discount, factors in the first three categories of factors (i.e., (1) 
federal, federally-recognized Tribal, state, and local laws and 
regulations affecting the resource mix and demand; (2) federal, 
federally-recognized Tribal, state, and local laws and regulations on 
decarbonization and electrification; and (3) state-approved integrated 
resource plans and expected supply obligations for load-serving 
entities) once transmission providers have determined that such a 
factor is likely to affect Long-Term Transmission Needs. The Commission 
found that it is necessary to prohibit the discounting of factors in 
the first three categories of factors because they are more certain 
drivers of Long-Term Transmission Needs, relative to factors in other 
Factor Categories.\799\ Where two legally binding factors have 
conflicting or opposite implications for Long-Term Transmission Needs, 
however, transmission providers must reconcile this information while 
giving full effect to the maximum extent possible to all legally 
binding factors.\800\
---------------------------------------------------------------------------

    \798\ Id. P 507.
    \799\ Id.
    \800\ Id. P 515.
---------------------------------------------------------------------------

    280. The Commission allowed transmission providers to rely on the 
open and transparent stakeholder process discussed below to identify 
the factors in the first three required categories of factors. 
Transmission providers may independently identify factors in the first 
three categories of factors, but Order No. 1920 does not obligate 
transmission providers to do so.\801\ Transmission providers retain the 
discretion to determine whether and how particular factors, including 
those in the first three categories of factors, are likely to affect 
Long-Term Transmission Needs.\802\ Further, the Commission stated in 
Order No. 1920 that it expects that transmission providers will rely, 
at least in part, on information that relevant federal, state, and 
local

[[Page 97232]]

government entities, federally-recognized Tribes, utilities, and load-
serving entities provide during the required open and transparent 
stakeholder process to determine if specific factors are likely to 
affect Long-Term Transmission Needs and how to account for those 
specific factors in Long-Term Scenarios.\803\
---------------------------------------------------------------------------

    \801\ Id. P 508.
    \802\ Id. PP 510, 512.
    \803\ Id. P 511.
---------------------------------------------------------------------------

    281. The Commission provided transmission providers with additional 
discretion in how they account for each factor in Factor Categories 
Four through Seven (i.e., (4) trends in fuel costs and in the cost, 
performance, and availability of generation, electric storage 
resources, and building and transportation electrification 
technologies; (5) resource retirements; (6) generator interconnection 
requests and withdrawals; and (7) utility and corporate commitments and 
federal, federally-recognized Tribal, state, and local policy goals 
that affect Long-Term Transmission Needs) compared to how they account 
for each factor in the first three categories. For purposes of 
developing plausible and diverse Long-Term Scenarios, Order No. 1920 
requires transmission providers, after they have determined that a 
specific factor in Factor Categories Four through Seven is likely to 
affect Long-Term Transmission Needs over the transmission planning 
horizon, to assess the extent to which the anticipated effects on Long-
Term Transmission Needs due to that factor are likely to be realized in 
part, in full, or exceeded.\804\ Transmission providers may choose to 
discount or to put more weight on the effects of factors in Factor 
Categories Four through Seven on Long-Term Transmission Needs, but only 
to the extent that each Long-Term Scenario remains plausible.\805\
---------------------------------------------------------------------------

    \804\ Id. P 516.
    \805\ Id. P 518.
---------------------------------------------------------------------------

    282. The Commission disagreed with concerns that the additional 
flexibility afforded to transmission providers in how they account for 
each factor in Factor Categories Four through Seven could allow 
transmission providers to ignore these categories of factors. The 
Commission explained that Order No. 1920 requires transmission 
providers to incorporate all categories of factors in each Long-Term 
Scenario, even if they discount specific factors within the category, 
and requires all Long-Term Scenarios to be plausible.\806\
---------------------------------------------------------------------------

    \806\ Id.
---------------------------------------------------------------------------

    283. Further, the Commission explained that, because Order No. 1920 
requires that all Long-Term Scenarios be consistent with and fully 
account for factors in Factor Category Three, which includes state-
approved integrated resource plans and expected supply obligations of 
load-serving entities, the final rule does not ignore the Commission's 
fundamental responsibility under FPA section 217 to facilitate planning 
to meet the needs of load-serving entities.\807\
---------------------------------------------------------------------------

    \807\ Id. P 420.
---------------------------------------------------------------------------

ii. Requests To Omit One or More Specific Categories of Factors
(a) Requests for Rehearing and Clarification
    284. Designated Retail Regulators and Undersigned States request 
that the Commission grant rehearing on the grounds that Order No. 1920 
requires transmission providers to consider several factors in Long-
Term Regional Transmission Planning, and including these factors will 
result in rates that are unjust and unreasonable.\808\ Arizona 
Commission avers that through Order No. 1920, the Commission is 
promoting certain preferred ``green'' energy generation resources by 
requiring transmission providers to incorporate seven categories of 
factors.\809\ Arizona Commission states that these factors have 
political and policy considerations that do not belong in Arizona where 
the legislature has not mandated such costs, planning, or 
experimentation to the detriment of ratepayers.\810\
---------------------------------------------------------------------------

    \808\ Designated Retail Regulators Rehearing Request at 7; 
Undersigned States Rehearing Request at 7.
    \809\ Arizona Commission Rehearing Request at 15.
    \810\ Id. at 22.
---------------------------------------------------------------------------

    285. Designated Retail Regulators and Undersigned States both argue 
that Order No. 1920 usurps the role of the states in transmission 
planning by requiring that the plans and goals of some states, tribes, 
local governments, and private companies override the plans and goals 
of other entities while also forcing these entities to bear the cost 
burden.\811\ Designated Retail Regulators and Undersigned States assert 
that Factor Categories One, Two, Four, Six, and Seven unjustly involve 
the policy goals of state and local governments and the commitments of 
utilities, and thus impose construction costs upon ratepaying loads 
without sufficient and measurable benefits.\812\ Designated Retail 
Regulators and Undersigned States both state that there is insufficient 
evidence and analysis to support that use of these factors will result 
in cost-effective solutions.\813\
---------------------------------------------------------------------------

    \811\ Designated Retail Regulators Rehearing Request at 8; 
Undersigned States Rehearing Request at 7-8.
    \812\ Designated Retail Regulators Rehearing Request at 28; 
Undersigned States Rehearing Request at 27-28.
    \813\ Designated Retail Regulators Rehearing Request at 8 
(citation omitted); Undersigned States Rehearing Request at 8 
(citation omitted).
---------------------------------------------------------------------------

    286. Ohio Commission Federal Advocate requests that the Commission 
grant rehearing on the grounds that the Commission acted arbitrarily 
and capriciously and abused its discretion because Order No. 1920 
requires transmission providers to incorporate unreasonable categories 
of factors in the development of Long-Term Scenarios.\814\ 
Specifically, Ohio Commission Federal Advocate is concerned that 
several factors would encourage a massive transmission build-out at 
unjust and unreasonable rates and requests that the Commission grant 
rehearing to remove Factor Categories One, Two, Six, and Seven as these 
factors are highly speculative and subject to change.\815\ Ohio 
Commission Federal Advocate asserts that the Commission has not engaged 
in reasoned decision making by asserting that a best-available-data 
requirement will ensure these factors are incorporated in a meaningful 
way because even the best available data for a corporate commitment 
still amounts to nothing more than a corporate commitment.\816\ Ohio 
Commission Federal Advocate claims that the Commission's attempt to 
mitigate the flaws of requiring transmission providers to incorporate 
factors in Factor Categories Four through Seven by allowing 
transmission providers to discount or give special weight to these 
factors is arbitrary and capricious. Further, Ohio Commission Federal 
Advocate asserts that Factor Categories Three, Four, and Five may be 
problematic if transmission projects are chosen to satisfy state or 
federal policies and, due to the other provisions of Order No. 1920, 
may not be properly cost allocated.\817\
---------------------------------------------------------------------------

    \814\ Ohio Commission Federal Advocate Rehearing Request at 15.
    \815\ Id. at 16-17.
    \816\ Id. at 17.
    \817\ Id.
---------------------------------------------------------------------------

    287. Several petitioners request that the Commission grant 
rehearing on the grounds that the Order No. 1920 requirement to include 
Factor Category Seven (utility and corporate commitments and federal, 
federally-recognized Tribal, state, and local policy goals that affect 
long-term transmission needs) should be excluded from the development 
of Long-Term Scenarios.\818\
---------------------------------------------------------------------------

    \818\ Alabama Commission Rehearing Request at 4-5; Industrial 
Customers Rehearing Request at 49-54; Northern Virginia Rehearing 
Request at 4-7; NRECA Rehearing Request at 55; SERTP Sponsors 
Rehearing Request at 15-17; Virginia and North Carolina Commissions 
Rehearing Request at 6-8.

---------------------------------------------------------------------------

[[Page 97233]]

    288. SERTP Sponsors argue that Factor Category Seven does not 
demonstrate reasoned decision making, is not supported by substantial 
evidence, and could intrude into matters involving retail customers 
subject to state regulation in an unduly discriminatory and 
preferential manner.\819\ SERTP Sponsors assert that utility or 
corporate commitments and local policy goals are fundamentally retail 
concerns with arrangements subject to state-regulated tariffs and 
proceedings, and that the other categories of factors already encompass 
the transmission needs from these arrangements.\820\ SERTP Sponsors 
also request clarification that Factor Category Seven is not intended 
to give preferential treatment to certain retail customers, like 
corporations, over others.\821\
---------------------------------------------------------------------------

    \819\ SERTP Sponsors Rehearing Request at 16 (citations 
omitted).
    \820\ Id. at 15.
    \821\ Id. at 16.
---------------------------------------------------------------------------

    289. Industrial Customers state that the Commission did not 
satisfactorily explain in Order No. 1920 why it found unpersuasive 
comments on the NOPR questioning the inclusion of utility or corporate 
commitments in Factor Category Seven, given that such commitments may 
not be firm or could change over the transmission planning 
horizon.\822\ Further, Industrial Customers assert that the 
Commission's attempt to alleviate concerns by emphasizing in Order No. 
1920 that transmission providers ``have discretion'' to account for 
ambiguity concerning these commitments actually raises several 
additional issues.\823\ Industrial Customers argue that there are no 
clear rules to guide such discretion and that there is an alleged 
contradiction with Order No. 1920's ``earlier mandate to use publicly 
available information on goals and aspirations around corporate energy 
purchasing strategies.'' \824\ Industrial Customers add that one 
transmission provider, PJM, has publicly stated that it does not want 
such discretion due to the significant administrative burdens.\825\
---------------------------------------------------------------------------

    \822\ Industrial Customers Rehearing Request at 51 (citation 
omitted).
    \823\ Id. at 51-52 (quoting Order No. 1920, 187 FERC ] 61,068 at 
P 484).
    \824\ Id. at 52 (citing Order No. 1920, 187 FERC ] 61,068 at P 
413).
    \825\ Id. at 52-53 (citing PJM NOPR Initial Comments at 68).
---------------------------------------------------------------------------

    290. Industrial Customers additionally state that Order No. 1920's 
inclusion of Factor Category Seven unduly discriminates against load 
that may be served by generation that may not be considered ``clean 
energy.'' \826\ Industrial Customers highlight the Commission's 
statement that Order No. 1920 responds to ``corporate, governmental, 
and utility commitments to rely on certain generation resources'' and 
argue that the word ``certain'' implies without definition or 
justification a limited subset within possible generation 
resources.\827\
---------------------------------------------------------------------------

    \826\ Id. at 54-55 (citations omitted).
    \827\ Id. at 55 (quoting Order No. 1920, 187 FERC ] 61,068 at P 
261).
---------------------------------------------------------------------------

    291. Industrial Customers contend that many companies consider 
corporate sustainability and clean energy strategies to be proprietary 
and sensitive, so utilizing known and available corporate commitments 
and information without also having the underpinning analytical 
evidence cannot be reasonably relied on to inform future transmission 
planning scenarios.\828\ Similarly, Industrial Customers state that 
Order No. 1920 does not demonstrate that corporate strategies and goals 
are known determinants or representative and reliable anecdotes able to 
be utilized in Long-Term Scenarios.\829\
---------------------------------------------------------------------------

    \828\ Id. at 49-50.
    \829\ Id. at 50.
---------------------------------------------------------------------------

    292. Northern Virginia argues that the inclusion of ``corporate 
commitments'' as an independent factor in Category Factor Seven is 
arbitrary and capricious as this inclusion circumvents the planning 
process utilized by load serving utilities and state regulators to also 
meet these commitments.\830\ Additionally, Northern Virginia states 
that corporate commitments are too ephemeral and uncertain to be 
included in Long-Term Scenarios, and asserts that transmission planning 
processes should utilize best data from utilities and state regulators 
that are required to plan to serve load.\831\ Northern Virginia also 
argues that the Commission should not give special status to private 
corporations not charged with planning for the greater good, and that 
corporate commitments are not comparable to utility planning or 
governmental policy goals.\832\ Northern Virginia states that any 
entities with corporate commitments can participate in existing 
stakeholder and customer processes.\833\
---------------------------------------------------------------------------

    \830\ Northern Virginia Rehearing Request at 4.
    \831\ Id. at 3-4.
    \832\ Id. at 4.
    \833\ Id. at 7-9.
---------------------------------------------------------------------------

    293. Virginia and North Carolina Commissions argue that the 
Commission should remove Factory Category Seven from the development of 
Long-Term Scenarios as transmission providers may not have the 
resources and should not be in a position to assess the reasonableness 
or accuracy of corporate or utility commitments.\834\ Similarly, 
Virginia and North Carolina Commissions contend that it would be 
unreasonable to expect state entities to use their limited resources to 
evaluate and opine on such commitments or policy goals and that many 
states may be constrained from doing so if these commitments impact 
filings before the state entity.\835\ Additionally, Virginia and North 
Carolina Commissions request that the Commission only permit the 
incorporation of public policy goals previously approved through a 
state regulatory process or, alternatively, clarify that transmission 
providers can fully discount any public policy factors that fall under 
Factor Category Seven.\836\
---------------------------------------------------------------------------

    \834\ Virginia and North Carolina Commissions Rehearing Request 
at 7.
    \835\ Id.
    \836\ Id. at 8 (citation omitted).
---------------------------------------------------------------------------

    294. NRECA states that the Commission expanded the concept of Long-
Term Transmission Needs well beyond reliability, economic, and public 
policy issues by adopting seven categories of factors, including Factor 
Category Seven.\837\ NRECA asserts that the costs of facilities built 
to satisfy corporate commitments should be borne by the relevant 
corporations, not by those who do not benefit from the facility.\838\
---------------------------------------------------------------------------

    \837\ NRECA Rehearing Request at 54-55.
    \838\ Id. at 55.
---------------------------------------------------------------------------

    295. Harvard ELI and PIOs request clarification to reframe Factor 
Category Seven.\839\ Harvard ELI requests that the Commission clarify 
whether Factor Category Seven implements the existing requirement to 
plan for all transmission users on a comparable basis and further 
clarify that all long-term planning rules are similarly rooted in the 
open access comparability standard.\840\ PIOs request clarification on 
whether required scenario factors additionally include city and 
consumer-side market preferences.\841\
---------------------------------------------------------------------------

    \839\ Harvard ELI Rehearing Request at 9-11; PIOs Rehearing 
Request at 61.
    \840\ Harvard ELI Rehearing Request at 9-11.
    \841\ PIOs Rehearing Request at 61.
---------------------------------------------------------------------------

(b) Commission Determination
    296. We are unpersuaded by parties that request that the Commission 
set aside the requirement for transmission providers to incorporate the 
seven specified categories of factors into the development of Long-Term 
Scenarios, including requests to set aside the requirement to 
incorporate certain specific categories of factors.

[[Page 97234]]

Nevertheless, we believe certain clarifications adopted herein will 
alleviate the concerns these parties raise on rehearing. Specifically, 
our clarification that transmission providers must consult with and 
consider the positions of the Relevant State Entities and any other 
entity authorized by a Relevant State Entity as its representative as 
to how to account for factors related to states' laws, policies, and 
regulations when determining the assumptions that will be used in the 
development of Long-Term Scenarios will help ensure that each Long-Term 
Scenario reflects states' preferences and future needs. However, with 
respect to Factor Category Seven, we set aside the requirement to 
include corporate commitments, as discussed further below.
    297. We continue to find that existing regional transmission 
planning requirements fail to ensure that transmission providers 
adequately account on a forward-looking basis for known determinants of 
Long-Term Transmission Needs. We reiterate that requiring transmission 
providers to incorporate the seven categories of factors into the 
development of Long-Term Scenarios is necessary because without doing 
so, transmission providers will fail to adequately consider drivers of 
Long-Term Transmission Needs.\842\
---------------------------------------------------------------------------

    \842\ Order No. 1920, 187 FERC ] 61,068 at P 410.
---------------------------------------------------------------------------

    298. With regard to Arizona Commission's claim that Order No. 1920 
favors ``green'' energy,\843\ we reiterate that nothing in Order No. 
1920 favors, promotes, or subsidizes particular types of generation 
resources over others and that the Commission's policies are technology 
and fuel neutral. Order No. 1920 does not endorse the merits of any 
laws and regulations or of any specific state-approved integrated 
resource plans.\844\ Rather, we reiterate that states play a vital role 
in identifying the factors, especially in Factor Categories One, Two, 
and Seven, that transmission providers account for in Long-Term 
Regional Transmission Planning. We are unpersuaded by Arizona 
Commission and NRECA that the categories of factors requirements in 
Order No. 1920 include policy factors that have not been previously 
considered in regional transmission planning.\845\ In Order No. 1000, 
the Commission required transmission providers to establish procedures 
that provide for the consideration of transmission needs driven by 
Public Policy Requirements in the local and regional transmission 
planning processes.\846\
---------------------------------------------------------------------------

    \843\ Arizona Commission Rehearing Request at 15.
    \844\ Order No. 1920, 187 FERC ] 61,068 at PP 232, 437.
    \845\ Arizona Commission Rehearing Request at 22; NRECA 
Rehearing Request at 54-55.
    \846\ Order No. 1000, 136 FERC ] 61,051 at P 203; see also S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 89-92 (upholding this Order 
No. 1000 requirement).
---------------------------------------------------------------------------

    299. We are not persuaded by arguments that Factor Category One and 
Factor Category Two, which include state and local laws and 
regulations, will unjustly impose the policy goals of certain state and 
local governments on others.\847\ We reiterate that transmission 
planning of any kind will inherently reflect the policy choices of 
multiple decisionmakers because the quantity and location of generation 
and load are shaped by multiple decisionmakers.\848\ In this case, we 
expect transmission providers to work with states to ensure the way 
those state laws and regulations are incorporated into Long-Term 
Scenarios reflects states' preferred implementation of those laws and 
regulations. We also reiterate that transmission providers must 
appropriately value the effect of states' policy decisions in regional 
transmission planning in order to ensure just and reasonable 
rates.\849\
---------------------------------------------------------------------------

    \847\ E.g., Designated Retail Regulators Rehearing Request at 
28; Ohio Commission Federal Advocate Rehearing Request at 16-17; 
Undersigned States Rehearing Request at 27-28.
    \848\ Order No. 1920, 187 FERC ] 61,068 at P 435.
    \849\ Id. P 436.
---------------------------------------------------------------------------

    300. Parties argue that the Commission's categories of factors 
requirements will impose formidable costs upon ratepaying loads that 
neither caused the need for the construction of additional transmission 
facilities nor measurably benefit from that construction and therefore 
are unjust and unreasonable and unduly discriminatory and 
preferential.\850\ We disagree. The requirements of Order No. 1920, as 
clarified herein, ensure that Relevant States Entities, which represent 
consumers, have a voice in how factors within the categories of factors 
are accounted for, the development of Long-Term Scenarios that results 
from those factors, and the allocation of costs after a Long-Term 
Regional Transmission Facility is selected.\851\ Nothing in Order No. 
1920 changed the Commission's policy that costs must be allocated in a 
manner that is at least roughly commensurate with benefits, which 
ensures that ratepayers are not paying unjust and unreasonable 
rates.\852\
---------------------------------------------------------------------------

    \850\ E.g., Designated Retail Regulators Rehearing Request at 
28; Ohio Commission Federal Advocate Rehearing Request at 16-17; 
Undersigned States Rehearing Request at 27-28.
    \851\ See infra Stakeholder Process and Transparency section; 
Requests for Additional Flexibility Regarding Long-Term Scenarios 
Requirements section.
    \852\ See, e.g., Order No. 1920, 187 FERC ] 61,068 at PP 419, 
1419, 1471, 1513.
---------------------------------------------------------------------------

    301. We also disagree with arguments from Designated Retail 
Regulators and Undersigned States that there is insufficient evidence 
and analysis to support the conclusion that use of Factor Categories 
One, Two, Four, Six, and Seven will result in cost-effective 
solutions.\853\ We believe the collaboration between transmission 
providers and Relevant State Entities, where relevant, will ensure that 
those categories of factors are incorporated into the development of 
Long-Term Scenarios that identify Long-Term Regional Transmission 
Facilities that both meet the needs of states and provide reliability 
and economic value. At the same time, we believe that transmission 
providers cannot identify more efficient or cost-effective solutions to 
Long-Term Transmission Needs if they undervalue or entirely omit the 
consideration of some or all of the seven categories of factors.\854\ 
The Commission based its determination for each category of factors on 
record evidence specific to each category of factors indicating that 
each required category of factors is essential to identifying Long-Term 
Transmission Needs.\855\ To the extent states may be concerned about 
the resulting cost allocation, we note certain clarifications below 
that provide greater opportunities for input to Relevant State Entities 
with respect to cost allocation.\856\
---------------------------------------------------------------------------

    \853\ E.g., Designated Retail Regulators Rehearing Request at 8; 
Undersigned States Rehearing Request at 8.
    \854\ E.g., Order No. 1920, 187 FERC ] 61,068 at PP 120, 228.
    \855\ Id. P 410; see also id. PP 391-395, 423-424, 438, 443-445, 
450-452, 459, 467, 474-477 (summarizing record evidence that 
indicates that the seven categories of factors are essential to 
identifying Long-Term Transmission Needs).
    \856\ See infra Requests for Additional Flexibility Regarding 
Long-Term Scenarios Requirements section.
---------------------------------------------------------------------------

    302. For this reason, we also disagree with Ohio Commission Federal 
Advocate that the categories of factors requirements are unreasonable, 
arbitrary, and capricious, and will encourage a massive transmission 
build-out at unjust and unreasonable rates. We continue to find that 
the categories of factors that Order No. 1920 requires transmission 
providers to incorporate into the development of Long-Term Scenarios 
reflect the wide variety of drivers of Long-Term Transmission Needs and 
therefore are necessary to ensure the identification of more efficient 
or cost-effective transmission solutions to such needs. We also note

[[Page 97235]]

that, in Order No. 1920, the Commission responded to concerns that 
certain categories of factors are too speculative or subject to change 
and should not be incorporated into the development of Long-Term 
Scenarios.\857\ Further, the Commission justified the framework for 
treating different types of categories of factors differently in the 
development of Long-Term Scenarios.\858\
---------------------------------------------------------------------------

    \857\ Order No. 1920, 187 FERC ] 61,068 at PP 229, 231, 473.
    \858\ Id. PP 484, 507.
---------------------------------------------------------------------------

    303. However, we set aside, in part, the requirement for 
transmission providers to incorporate seven specific categories of 
factors in the development of Long-Term Scenarios. Specifically, we set 
aside the requirement for transmission providers to incorporate 
corporate commitments \859\ in Factor Category Seven when developing 
Long-Term Scenarios. We find that requiring transmission providers to 
consider corporate commitments when developing Long-Term Scenarios may 
introduce the risk of one class of transmission users cross-subsidizing 
another class of transmission users. We clarify that we continue to 
require transmission providers to consider corporate commitments that 
are likely to affect Long-Term Transmission Needs as part of Long-Term 
Regional Transmission Planning to the extent that these commitments 
affect transmission customers' transmission needs, because transmission 
providers must plan for the needs of all transmission customers on a 
comparable basis under Order Nos. 888, 890, and 1000.\860\ As such, we 
find that it is unnecessary to require transmission providers to 
separately identify corporate commitments as a factor in their 
development of Long-Term Scenarios given that the effects of such 
commitments will be sufficiently incorporated into Long-Term Regional 
Transmission Planning through the incorporation of other Factor 
Categories, such as Factor Category Three (state-approved integrated 
resource plans and expected supply obligations for load-serving 
entities).
---------------------------------------------------------------------------

    \859\ We clarify that we distinguish in this context between 
``corporate commitments'' and utility commitments that are made by 
transmission providers and load-serving entities, regardless of 
their corporate form.
    \860\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 435 
(``The Commission has broad authority to remedy undue discrimination 
by ensuring that transmission providers plan for the needs of their 
customers on a comparable basis. That fundamental requirement was 
adopted in Order No. 888 and the reforms adopted herein should 
ensure that it will be implemented properly.'' (footnote omitted)).
---------------------------------------------------------------------------

    304. We agree with Harvard ELI's argument that transmission 
providers must consider how the contracts and purchasing plans of all 
transmission customers may affect Long-Term Transmission Needs in a 
comparable way to how transmission providers must consider utility 
purchasing plans and decisions. However, we disagree with Harvard ELI 
that the Commission's existing open access comparability standard 
requires transmission providers to plan for all transmission users on a 
comparable basis. Instead, as noted above, the open access 
comparability standard requires planning for transmission customers on 
a comparable basis. We emphasize this distinction because, in the 
context of Order No. 1920, transmission ``users'' could refer to retail 
customers of load-serving entities, and those load-serving entities are 
either transmission providers or transmission customers of transmission 
providers. In focusing on transmission users, Harvard ELI's request 
would inappropriately expand scope of the open access comparability 
standard to include retail customers. Therefore, we deny Harvard ELI's 
requested clarification.
    305. Finally, we deny Northern Virginia's request to assign 
transmission facility costs related to corporate commitments through 
the Large Generator Interconnection Procedures. The Commission did not 
propose such a requirement in the NOPR and, as such, this request is 
beyond the scope of this proceeding.
    306. Aside from corporate commitments, we otherwise sustain the 
requirement for transmission providers in each transmission planning 
region to incorporate Factor Category Seven into the development of 
Long-Term Scenarios, while recognizing the role of states in the 
incorporation of this category. Specifically, transmission providers 
must incorporate utility commitments and federal, federally-recognized 
Tribal, state, and local policy goals that affect Long-Term 
Transmission Needs into the development of Long-Term Scenarios. While 
we require transmission providers to incorporate this category of 
factors into the development of Long-Term Scenarios, we emphasize that, 
where relevant, each of the factors within the category should be the 
subject of discussion with the states who have the policy goals, and 
their preferences as far as how to integrate these goals should be 
taken into account when developing Long-Term Scenarios. We also find 
that utility commitments and federal, federally-recognized Tribal, 
state, and local policy goals could be drivers of Long-Term 
Transmission Needs.
    307. We disagree with SERTP Sponsors and Industrial Customers that 
this requirement does not constitute reasoned decision making or engage 
with counterarguments in Order No. 1920 and note, as described above, 
that the requirement to incorporate Factor Category Seven into the 
development of Long-Term Scenarios was based on record evidence.\861\ 
Further, the Commission acknowledged commenter concerns that utility, 
federally-recognized Tribal, and governmental goals may be more likely 
to change over the transmission planning horizon than factors in other 
required Factor Categories.\862\ However, the Commission did not find 
that these commitments and goals are so speculative, amorphous, or 
unreliable that they should not be incorporated into Long-Term 
Scenarios at all.\863\
---------------------------------------------------------------------------

    \861\ Order No. 1920, 187 FERC ] 61,068 at PP 474-477 
(summarizing record evidence indicating that Factor Category Seven 
is essential to identifying Long-Term Transmission Needs).
    \862\ Id. P 484.
    \863\ Id.
---------------------------------------------------------------------------

    308. We also disagree with arguments that the inclusion of Factor 
Category Seven is unduly discriminatory or preferential.\864\ The 
Commission requires that transmission providers plan for all 
transmission customers' transmission needs on a comparable basis.\865\ 
We clarify that Factor Category Seven, as modified above, is not 
intended to single out certain utility commitments or federal, 
federally-recognized Tribal, state, and local policy goals that affect 
Long-Term Transmission Needs; instead, Factor Category Seven, as 
modified above, captures factors that are not fully represented in the 
other six categories of factors and also affect Long-Term Transmission 
Needs. As noted in Order No. 1920, transmission providers have 
discretion to determine whether a proposed factor in Factor Category 
Seven likely affects Long-Term Transmission Needs \866\ and how such 
factors in Factor Category Seven should be considered,\867\ but we 
clarify such discretion must be applied in a manner that ensures 
comparability among transmission customers. We also clarify that 
``certain generation resources'' in Order No. 1920's reference to 
``corporate, governmental, and utility commitments to rely on certain 
generation resources,'' which, as modified on rehearing, is now

[[Page 97236]]

``governmental and utility commitments,'' does not refer to a certain 
resource type, or limit consideration of such government or utility 
commitments to only those commitments to rely on renewable 
resources.\868\ Rather, this requirement means that transmission 
providers must consider the generation resources that a federal, state, 
or local government entity, federally-recognized Tribe, or utility has 
chosen to rely on regardless of the resource type.
---------------------------------------------------------------------------

    \864\ SERTP Sponsors Rehearing Request at 16; Industrial 
Customers Rehearing Request at 54.
    \865\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 435.
    \866\ Order No. 1920, 187 FERC ] 61,068 at PP 415, 417.
    \867\ Id. P 516
    \868\ Id. P 261; Industrial Customers Rehearing Request at 55.
---------------------------------------------------------------------------

    309. In response to Virginia and North Carolina Commissions' 
request as to whether transmission providers may discount public policy 
factors within Factor Category Seven to zero, we reiterate that, with 
respect to Factor Category Seven, transmission providers have 
discretion as to how they account for these factors. We also clarify 
that transmission providers may conclude that certain factors within 
Factor Category Seven do not affect Long-Term Transmission Needs and, 
therefore, do not need to account for them when incorporating Factor 
Category Seven into the development of Long-Term Scenarios.\869\
---------------------------------------------------------------------------

    \869\ Order No. 1920, 187 FERC ] 61,068 at P 415.
---------------------------------------------------------------------------

    310. Regarding Industrial Customers' concern that the quality of 
information on utility commitments make Factor Category Seven 
unworkable, we note the clarification below that transmission providers 
may rely on the open and transparent stakeholder process to identify 
the factors in Factor Category Seven, as modified above, in the same 
manner that they may rely on the open and transparent stakeholder 
process to identify the factors in Factor Categories One through 
Three.\870\ We continue to believe that federal, state, and local 
government entities, federally-recognized Tribes, utilities, load-
serving entities, and their retail regulators that participate in the 
stakeholder process are distinctly well-positioned to provide 
transmission providers with vital information regarding factors in 
Factor Category Seven, as modified above.\871\ In response to 
Industrial Customers' claim that the best information may be 
confidential,\872\ we clarify that transmission providers may include 
what they believe to be appropriate confidentiality protections in 
their compliance proposals to account for proprietary commitments. The 
Commission will evaluate those proposals by using the established 
principles in Order No. 890,\873\ as well as precedent on existing 
confidentiality protections with respect to transmission planning that 
the Commission has previously found comply with the Order No. 890 
transmission planning principles.
---------------------------------------------------------------------------

    \870\ Supra infra Stakeholder Process and Transparency section 
(clarifying that transmission providers have no independent 
obligation to identify factors in Factor Category Seven and may rely 
on stakeholders to identify factors in Factor Category Seven).
    \871\ Order No. 1920, 187 FERC ] 61,068 at P 530.
    \872\ Industrial Customers Rehearing Request at 49-50.
    \873\ Order No. 890, 118 FERC ] 61,119 at PP 471-476; see also 
Order No. 1920, 187 FERC ] 61,068 at P 466 (clarifying that 
transmission providers may include what they believe to be 
appropriate confidentiality protections in their proposals to 
account for resource retirements that might take place over the 
transmission planning horizon).
---------------------------------------------------------------------------

    311. We disagree with Industrial Customers' argument that the 
Commission's emphasis on transmission provider discretion is 
problematic.\874\ Order No. 1920, with Factor Category Seven as 
modified above, strikes the right balance by allowing transmission 
providers discretion as to the treatment of factors within Factor 
Category Seven when developing Long-Term Scenarios. In contrast to 
Industrial Customers' claim,\875\ we do not believe that transmission 
providers need clear rules or standards for implementing their 
discretion over incorporating Factor Category Seven, as modified above, 
in the development of Long-Term Scenarios. We find that transmission 
providers can rely on their expert judgement and the information 
provided to them through the open and transparent stakeholder process 
to develop three plausible Long-Term Scenarios for purposes of 
identifying Long-Term Transmission Needs. Furthermore, we continue to 
find that concerns regarding the administrative burden of identifying 
specific factors are addressed by allowing transmission providers to 
rely on the open and transparent stakeholder process to identify 
factors.\876\ We find that our clarification that transmission 
providers may rely on the open and transparent stakeholder process to 
identify the factors in Factor Category Seven,\877\ as well as our 
decision to exclude corporate commitments from that Factor Category, 
renders moot Industrial Customers' claim that Order No. 1920 forces 
transmission providers to account for corporate energy commitments and 
goals of ``all potentially known or capable-of-being known energy 
commitments or contracts.'' \878\
---------------------------------------------------------------------------

    \874\ Industrial Customers Rehearing Request at 51-53.
    \875\ Id. at 52.
    \876\ Order No. 1920, 187 FERC ] 61,068 at P 508.
    \877\ See infra Stakeholder Process and Transparency section.
    \878\ Industrial Customers Rehearing Request at 53.
---------------------------------------------------------------------------

    312. We recognize that utility commitments and federal, federally-
recognized Tribal, state, and local policy goals in Factor Category 
Seven may initially surface as retail concerns that are addressed 
through arrangements with retail providers; \879\ however, this fact 
does not obviate the need for transmission providers to account for 
them in the development of Long-Term Scenarios. We acknowledge that 
there could be an overlap between Factor Category Seven, as modified 
above, and other categories (e.g., integrated resource plans in Factor 
Category Three), because utility commitments and policy goals may be 
addressed through arrangements with retail providers. As discussed 
above,\880\ transmission providers should avoid double counting the 
anticipated effects that those factors have on assumptions used to 
develop Long-Term Scenarios where the impact of factors overlaps, such 
that transmission providers must incorporate those factors once in the 
appropriate Factor Categories One through Three, not Factor Categories 
Four through Seven.
---------------------------------------------------------------------------

    \879\ SERTP Sponsors Rehearing Request at 15. In light of the 
discussion above, we continue to conclude that Order No. 1920--
including Factor Category Seven, as modified--is within the 
Commission's authority notwithstanding that considerations relevant 
to Factor Category Seven may also arise in the context of retail 
transactions. See supra Order No. 1920 Is Consistent with the FPA 
and Precedent Regarding the Commission's Authority section 
(explaining that where the Commission regulates within its statutory 
authority, that regulation does not run afoul of the jurisdictional 
lines drawn in the FPA irrespective of any effects on areas of 
reserved state authority).
    \880\ Supra Requirement to Incorporate Categories of Factors 
section.
---------------------------------------------------------------------------

    313. We disagree with NRECA's claim that the inclusion of Factor 
Category Seven expands the definition of Long-Term Transmission Needs 
beyond reliability, economic, or public policy issues. The Commission 
was clear that the drivers of transmission needs are diverse and 
include, but are not limited to, evolving reliability concerns, changes 
in the resource mix, and changes in demand.\881\ Foundationally, and 
consistent with our clarification that economic drivers contribute to 
Long-Term Transmission Needs,\882\ we find that all seven categories of 
factors in Order No. 1920 pertain to Long-Term Transmission Needs 
because they affect the reliable and economic operation of the 
interconnected transmission system. The categories of factors 
requirements are intended to address certain

[[Page 97237]]

deficiencies in the Commission's existing regional transmission 
planning requirements, including the failure to ensure that 
transmission providers adequately account on a forward-looking basis 
for known determinants of Long-Term Transmission Needs.\883\
---------------------------------------------------------------------------

    \881\ Order No. 1920, 187 FERC ] 61,068 at P 299.
    \882\ See supra Requirement for Transmission Providers To Use 
the Seven Required Benefits To Help To Inform Their Identification 
of Long-Term Transmission Needs section.
    \883\ Order No. 1920, 187 FERC ] 61,068 at P 418.
---------------------------------------------------------------------------

iii. Other Specific Required Categories of Factors
(a) Requests for Rehearing and Clarification
    314. NRECA requests rehearing of the Commission's holding in Order 
No. 1920 that transmission providers have the discretion to determine 
that factors in Factor Category Three (state-approved integrated 
resource plans and expected supply obligations for load-serving 
entities) may not affect Long-Term Transmission Needs.\884\ NRECA 
argues that Order No. 1920 is in error because the Commission took 
action in this regard that is at odds with the needs of load-serving 
entities in violation of FPA section 217(b)(4).\885\ NRECA acknowledges 
that the Commission explained in Order No. 1920 that the final rule is 
consistent with FPA section 217(b)(4) and the interpretation of that 
statute adopted when the D.C. Circuit upheld Order No. 1000 in South 
Carolina Public Service Authority v. FERC.\886\ Nonetheless, NRECA 
claims that Order No. 1920 is different from Order No. 1000, and 
therefore that decision is not dispositive--particularly as to Order 
No. 1920's treatment of state-approved integrated resource plans and 
the expected supply obligations as discretionary.\887\ NRECA further 
argues that the Commission should revisit its conclusion that South 
Carolina Public Service Authority v. FERC remains binding precedent, 
because the D.C. Circuit upheld Order No. 1000's compliance with 
section 217(b)(4) using the deferential standard of review in Chevron 
U.S.A. Inc. v. Natural Resources Defense Council, Inc.,\888\ which was 
under review by the U.S. Supreme Court at the time NRECA submitted its 
request for rehearing.\889\ NRECA further argues that the Commission's 
decision in this regard was arbitrary and capricious because Order No. 
1920 was not ``based on a consideration of the relevant factors'' and 
``entirely failed to consider an important aspect of the problem.'' 
\890\
---------------------------------------------------------------------------

    \884\ NRECA Rehearing Request at 37-39 (citing Order No. 1920, 
187 FERC ] 61,068 PP 507, 510); see also East Kentucky Rehearing 
Request at 2-3 (arguing that Order No. 1920 violates FPA section 
217(b)(4) by treating state-approved integrated resource plans and 
expected supply obligations for load-serving entities as 
discretionary factors in Factor Category Three (citation omitted)); 
id. at 1 (stating that East Kentucky ``specifically adopts the 
majority of issues identified by NRECA and incorporates the bases 
and arguments for rehearing set forth in the NRECA Rehearing Request 
for those issues'').
    \885\ NRECA Rehearing Request at 39-40 (citing 16 U.S.C. 
824q(b)(4)).
    \886\ Id. at 40-41 (citing Order No. 1920, 187 FERC ] 61,068 at 
P 283).
    \887\ Id. at 41.
    \888\ Id. (citing Chevron U.S.A. Inc. v. Nat. Res. Def. Council, 
Inc., 467 U.S. 837 (1984); S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 54).
    \889\ Id. (citing Loper Bright Enters. v. Raimondo, No. 22-451; 
Relentless, Inc. v. Dep't of Commerce, No. 22-1219 (U.S. argued Jan. 
17, 2024)).
    \890\ Id. at 41-42 (quoting State Farm, 463 U.S. at 43).
---------------------------------------------------------------------------

    315. SERTP Sponsors request the following clarifications regarding 
specific categories of factors. With regard to Factor Categories One 
through Three, SERTP Sponsors request that the Commission expressly 
clarify that the open and transparent stakeholder process established 
by transmission providers is not intended to create an opportunity to 
relitigate or dispute the underlying integrated resource plans, 
resource projections, or laws and regulations, but instead, simply 
intends to create a forum in which such inputs can be brought forth to 
examine the potential impact on Long-Term Transmission Needs.\891\ 
Regarding Factor Category Three, SERTP Sponsors request that the 
resource planning and procurement processes of non-jurisdictional 
transmission providers, such as those of the non-jurisdictional SERTP 
Sponsors, that have been approved by their respective governing 
authorities should be included in this Factor Category Three as 
scenario inputs that are to be included without discount.\892\ SERTP 
Sponsors also request clarification that ``federal, federally-
recognized Tribal, state, and local laws and regulations'' is intended 
to encompass only ``enacted statutes (i.e., passed by the legislature 
and signed by the executive) and regulations promulgated by a relevant 
jurisdiction, whether within a state or at the federal level'' as 
established in Order No. 1000, albeit with the addition of Tribal laws 
and regulations.\893\ Similarly, SERTP Sponsors request clarification 
that for Factor Category One, such legally binding obligations, 
incentives (e.g., tax credits), and/or restrictions must be enacted by 
legislatures or promulgated by the relevant agency or Tribal 
authority.\894\
---------------------------------------------------------------------------

    \891\ SERTP Sponsors Rehearing Request at 5.
    \892\ Id. at 6.
    \893\ Id. at 14-15 (quoting Order No. 1000, 136 FERC ] 61,051 at 
P 2).
    \894\ Id.
---------------------------------------------------------------------------

    316. PIOs request rehearing of the Commission's findings regarding 
Factor Categories Four and Seven because they assert that the 
Commission erred when it failed to create specific guardrails to 
prevent transmission providers from minimizing these two categories of 
factors.\895\ PIOs argue that the Commission must provide specific 
guardrails for Factor Categories Four and Seven to ensure that 
transmission needs are accurately assessed.\896\ PIOs argue that Order 
No. 1920 allows ``boundless discounting'' of these categories, which 
``creates an opportunity for transmission providers to functionally 
ignore the Commission's mandate.'' \897\
---------------------------------------------------------------------------

    \895\ PIOs Rehearing Request at 33-35.
    \896\ Id. at 33.
    \897\ Id.
---------------------------------------------------------------------------

    317. PIOs contend that the evidence in the record does not 
substantiate the Commission's dismissal of the concern that the 
additional discretion granted to transmission providers regarding the 
last four categories of factors could functionally minimize these 
categories.\898\ Regarding Factor Category Four, PIOs urge the 
Commission to maintain a list of best available data.\899\ Regarding 
Factor Category Seven, PIOs request that the Commission limit the 
discounting of utility and corporate commitments by creating a 
presumption that transmission providers' discounting cannot assume 
greater failure to reach utility and corporate commitments than has 
occurred in the previous 10 years.\900\
---------------------------------------------------------------------------

    \898\ Id.
    \899\ Id. at 34.
    \900\ Id. at 35.
---------------------------------------------------------------------------

(b) Commission Determination
    318. We disagree with NRECA's rehearing arguments and continue to 
find that, while transmission providers must incorporate into the 
development of Long-Term Scenarios all factors in Factor Category Three 
(state-approved integrated resource plans and expected supply 
obligations for load-serving entities) that the transmission providers 
determine are likely to affect Long-Term Transmission Needs, 
transmission providers have the discretion as to whether they must 
account for a specific factor in Factor Category Three in the 
development of Long-Term Scenarios by concluding it is likely to affect 
Long-Term Transmission Needs.\901\ We continue to believe that the 
framework adopted in Order No. 1920 regarding categories of factors 
strikes the right balance between prescriptive

[[Page 97238]]

requirements and flexibility.\902\ Transmission providers determining 
whether a particular factor is likely to affect Long-Term Transmission 
Needs does not allow them to simply pick-and-choose one factor that 
they may prefer over another factor. Instead, allowing transmission 
providers to determine whether to account for a specific factor by 
concluding it is likely to affect Long-Term Transmission Needs is 
necessary to ensure that transmission providers develop accurate 
assumptions on which to base their Long-Term Scenarios.\903\ Further, 
Order No. 1920 builds on the foundation of Order No. 890, and 
specifically the comparability principle, which requires that 
transmission providers treat similarly situated customers comparably in 
the transmission planning process.\904\
---------------------------------------------------------------------------

    \901\ Order No. 1920, 187 FERC ] 61,068 at PP 447, 510.
    \902\ Id. P 417.
    \903\ Cf. id. P 530 (discussing importance of transmission 
providers being able to develop more accurate assumptions to serve 
as the basis for their Long-Term Scenarios).
    \904\ Id. P 14 (citing Order No. 890, 118 FERC ] 61,119 at PP 
418-601); see also Order No. 890, 118 FERC ] 61,119 at PP 494-495 
(discussing the comparability principle).
---------------------------------------------------------------------------

    319. We believe that the vast majority of factors in Factor 
Category Three, which represent state-approved integrated resource 
plans and expected supply obligations for load-serving entities, will 
likely affect Long-Term Transmission Needs. Nevertheless, we cannot 
foresee every potential factor that may be identified, and we therefore 
find it appropriate to preserve transmission providers' discretion to 
conclude that a specific factor (even in Factor Category Three) will 
have limited or no impact on Long-Term Transmission Needs. We also 
emphasize, as discussed below,\905\ that transmission providers must 
consult with and consider the positions of the Relevant State Entities 
as to how to incorporate categories of factors into the development of 
Long-Term Scenarios in such a way that states will play an important 
role in ensuring that state-approved integrated resource plans are 
incorporated in the manner they are expected to be implemented.
---------------------------------------------------------------------------

    \905\ Infra Stakeholder Process and Transparency section.
---------------------------------------------------------------------------

    320. We also disagree with NRECA's argument that the Commission 
acted at odds with the needs of load-serving entities in violation of 
FPA section 217(b)(4) by providing transmission providers with the 
discretion to not account for factors in Factor Category Three that a 
transmission provider finds are unlikely to affect Long-Term 
Transmission Needs. If a factor is unlikely to affect Long-Term 
Transmission Needs, excluding that factor in the transmission planning 
process is unlikely to negatively affect the needs of load-serving 
entities. Contrary to NRECA's claims, FPA section 217(b)(4) does not 
require the Commission to require transmission providers to account for 
factors in the development of Long-Term Scenarios that do not affect 
Long-Term Transmission Needs. We continue to find that Order No. 1920 
satisfies the Commission's obligation under FPA section 217(b)(4) 
because Order No. 1920 facilitates the planning and expansion of 
transmission facilities to meet load-serving entities' needs.\906\ 
Long-Term Regional Transmission Planning, as clarified herein, is 
intended to enhance the transmission planning process for states, load-
serving entities, and other interested parties, and, to that end, 
requires transmission providers to account for factors (including load-
serving entities' expected supply obligations) that are likely to 
affect Long-Term Transmission Needs in the development of Long-Term 
Scenarios.
---------------------------------------------------------------------------

    \906\ Order No. 1920, 187 FERC ] 61,068 PP 283, 420.
---------------------------------------------------------------------------

    321. Further, we disagree with NRECA that the U.S. Supreme Court's 
decision in Loper Bright Enterprises v. Raimondo \907\--in which the 
Court overruled Chevron U.S.A. Inc. v. Natural Resources Defense 
Council, Inc.--requires us to reconsider the D.C. Circuit's holding in 
South Carolina Public Service Authority v. FERC as to the meaning of 
FPA section 217(b)(4).\908\ The D.C. Circuit interpreted section 
217(b)(4) and determined that this provision requires the Commission to 
``facilitate the planning of a reliable grid'' by ``seek[ing] to ensure 
that adequate transmission capacity is built to allow load-serving 
entities to meet their service obligations.'' \909\ Order No. 1920 did 
not reinterpret FPA section 217(b)(4), but rather applied the 
interpretation adopted by the D.C. Circuit. Moreover, we believe the 
interpretation set forth by the Commission in Order No. 1000, endorsed 
by the D.C. Circuit in South Carolina Public Service Authority v. FERC 
and applied in Order No. 1920, remains the most reasonable reading of 
this statutory provision.\910\ Fundamentally, meeting the reasonable 
needs of load-serving entities to satisfy their service obligations 
requires that sufficient transmission capacity is available to deliver 
power when it is needed, and fostering a reliable transmission system 
is the best way to ensure that such capacity is available. Order No. 
1920's requirements are designed to achieve precisely that development 
of sufficient transmission capacity to ensure reliable and affordable 
delivery of needed power to meet the reasonable needs of load-serving 
entities, and therefore we find that it complies with FPA section 
217(b)(4).
---------------------------------------------------------------------------

    \907\ 144 S.Ct. 2244 (2024).
    \908\ NRECA Rehearing Request at 41 (citing S.C. Pub. Serv. 
Auth. v. FERC, 762 F.3d at 54).
    \909\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 90. Moreover, 
even if the D.C. Circuit had relied on Chevron in reaching this 
conclusion, the Supreme Court confirmed that ``mere reliance'' on 
Chevron is ``not enough to justify overruling a statutory 
precedent.'' Loper Bright, 144 S.Ct. at 2273.
    \910\ Compare Order No. 1000, 136 FERC ] 61,051 at P 108 
(``[T]his Final Rule is consistent with section 217 because it 
supports the development of needed transmission facilities, which 
ultimately benefits load-serving entities.''), with S.C. Pub. Serv. 
Auth. v. FERC, 762 F.3d at 90 (``Section 217 (b)(4) requires the 
Commission to facilitate the planning of a reliable grid, which is 
exactly what the Commission has done in the challenged orders.''); 
Order No. 1920, 187 FERC ] 61,068 at P 283 (``As articulated in 
South Carolina Public Service Authority v. FERC, FPA section 
217(b)(4) requires the Commission to `facilitate the planning of a 
reliable grid,' and we do so by `seek[ing] to ensure that adequate 
transmission capacity is built to allow load-serving entities to 
meet their service obligations.''' (alteration in original) 
(citation omitted)).
---------------------------------------------------------------------------

    322. We grant SERTP Sponsors' request for clarification regarding 
the first three categories of factors and clarify that nothing in Long-
Term Regional Transmission Planning is intended to relitigate or 
dispute the outcomes of the underlying integrated resource plans, 
resource projections, or laws and regulations that are (or are not) 
incorporated into the development of Long-Term Scenarios. The open and 
transparent stakeholder process required in Order No. 1920 is a forum 
that provides stakeholders, including states, with a meaningful 
opportunity to propose potential factors and to provide timely input on 
how to account for specific factors in the development of Long-Term 
Scenarios.\911\ For purposes of identifying Long-Term Transmission 
Needs, every factor is an input that transmission providers consider 
when determining the assumptions to use in the development of Long-Term 
Scenarios. Through the stakeholder process, states, transmission 
providers and stakeholders will have the opportunity to discuss how a 
factor would affect assumptions used to develop Long-Term Scenarios, if 
it does at all, and how the effect varies in different Long-Term 
Scenarios.
---------------------------------------------------------------------------

    \911\ Order No. 1920, 187 FERC ] 61,068 at P 528.
---------------------------------------------------------------------------

    323. In addition, we grant SERTP Sponsors' request for 
clarification regarding non-jurisdictional entities,\912\ in part. We 
clarify that, where a non-

[[Page 97239]]

jurisdictional entity is a transmission customer of one or more 
transmission providers in a transmission planning region, the 
transmission providers must plan for the non-jurisdictional entity's 
needs as a transmission customer as it would for the needs of any other 
transmission customer, including any resource planning and procurement 
processes that have been approved by the respective governing 
authorities under Factor Category Three, for purposes of complying with 
the requirements of Order No. 1920. For example, each Long-Term 
Scenario must account for and be consistent with these factors once the 
transmission providers have determined that such a factor is likely to 
affect Long-Term Transmission Needs.\913\ However, we further clarify 
that transmission providers may not plan for the needs of a non-
jurisdictional utility transmission provider if that non-jurisdictional 
transmission provider has not enrolled in the transmission planning 
region and thereby has not agreed to any cost allocation method 
applicable to selected Long-Term Regional Transmission Facilities.\914\ 
If the transmission provider were to plan for and consider non-
jurisdictional transmission providers' Long-Term Transmission Needs 
without a way to ensure the non-jurisdictional transmission provider 
contributes to the costs of the resulting Long-Term Regional 
Transmission Facilities, the resulting cost allocation could violate 
the cost causation principle and result in free-ridership.\915\
---------------------------------------------------------------------------

    \912\ SERTP Sponsors Rehearing Request at 6.
    \913\ Order No. 1920, 187 FERC ] 61,068 at PP 507, 510.
    \914\ Cf. Order No. 1000-A, 139 FERC ] 61,132 at P 276 (``[T]he 
regional transmission planning process is not required to plan for 
the transmission needs of such a non-[jurisdictional] utility 
transmission provider that has not made the choice to join a 
transmission planning region.'' (emphasis added)).
    \915\ El Paso Elec. Co. v. FERC, 76 F.4th at 363-66.
---------------------------------------------------------------------------

    324. In response to SERTP Sponsors' request for clarification 
regarding the meaning of ``laws and regulations,'' we clarify that 
Order No. 1920 adopts the meaning of the terms used in the NOPR, namely 
``enacted statutes (i.e., passed by the legislature and signed by the 
executive) and regulations promulgated by a relevant jurisdiction.'' 
\916\ Order No. 1920 amended the term ``statutes'' used in the NOPR by 
adding the duly enacted and legally binding obligations of federally-
recognized Tribes.\917\ We reiterate that Factor Categories One and Two 
include laws and regulations at the federal, federally-recognized 
Tribal, state, and local level.\918\
---------------------------------------------------------------------------

    \916\ NOPR, 179 FERC ] 61,028 at P 104 n.189; see also Order No. 
1000, 136 FERC ] 61,051 at P 2. We clarify here that the definition 
of ``laws and regulations'' includes laws and regulations duly 
enacted by local jurisdictions, even where there are differences in 
how these jurisdictions enact laws or promulgate regulations.
    \917\ Order No. 1920, 187 FERC ] 61,068 at P 434.
    \918\ Id. P 409. It is unclear whether SERTP Sponsors intended 
to argue that failure to grant clarification in this respect would 
result in Order No. 1920 exceeding the Commission's authority; to 
the extent they intended to do so, we find this argument has not 
been raised with the specificity required on rehearing. See supra 
Major Questions Doctrine section.
---------------------------------------------------------------------------

    325. We disagree with PIOs' request for rehearing to create more 
prescriptive requirements for Factor Category Four (trends in fuel 
costs and in the cost, performance, and availability of generation, 
electric storage resources, and building and transportation 
electrification technologies) and Factor Category Seven (utility and 
corporate commitments and federal, federally-recognized Tribal, state, 
and local policy goals that affect Long-Term Transmission Needs).\919\ 
We reiterate that the framework that the Commission adopted in Order 
No. 1920 regarding the incorporation of categories of factors into the 
development of Long-Term Scenarios strikes the right balance between 
prescriptive requirements and flexibility.\920\ We believe that the 
requirements for transmission providers to incorporate (i.e., more than 
merely consider) categories of factors in the development of Long-Term 
Scenarios, as well as to develop plausible Long-Term Scenarios with the 
best available data,\921\ are adequate to safeguard against ``boundless 
discounting'' and opportunities to ``functionally ignore the 
Commission's mandate.'' \922\
---------------------------------------------------------------------------

    \919\ PIOs Rehearing Request at 33.
    \920\ Order No. 1920, 187 FERC ] 61,068 at P 417.
    \921\ Id. PP 413-414.
    \922\ PIOs Rehearing Request at 33.
---------------------------------------------------------------------------

    326. More specifically, we disagree with PIOs' request to require 
on rehearing that transmission providers incorporate certain factors 
from a Commission-maintained list of data sources for Factor Category 
Four. As an initial matter, we find that it is unnecessary to grant 
PIOs' request because transmission providers' technical expertise and 
the required open and transparent stakeholder process to identify 
factors are sufficient to ensure that transmission providers implement 
the requirements of Long-Term Regional Transmission Planning. In 
addition to the Commission's concerns regarding regional variation and 
stifled innovation identified in Order No. 1920,\923\ we conclude that 
there are practical challenges associated with the Commission 
establishing and maintaining a list of data sources. For example, 
transmission providers already collect data similar to the data needed 
for these factors for other applications, and the Commission would be 
duplicating this data collection effort. We believe that transmission 
providers working with Relevant State Entities and other stakeholders 
in their regions are better equipped to understand the unique 
circumstances of their regions and to compile data and inputs for the 
required categories of factors.
---------------------------------------------------------------------------

    \923\ See Order No. 1920, 187 FERC ] 61,068 at P 639 (declining 
to impose further requirements as to data uniformity because 
regional variation may make uniformity challenging and because it 
could stifle innovation that may improve Long-Term Regional 
Transmission Planning).
---------------------------------------------------------------------------

    327. With respect to Factor Category Seven, we decline to limit the 
discounting of utility and corporate commitments as proposed by 
PIOs.\924\ In this case, we find that transmission providers may face 
practical challenges in accurately quantifying the historical rate of 
failure for utility commitments; moreover, the historical rate of 
failure is not necessarily determinative of future achievement rates 
for such commitments. In addition, limiting how transmission providers 
manage the uncertainty associated with utility commitments may have 
unintended consequences. For example, such a limit would not allow 
transmission providers to adapt their treatment of utility commitments 
in response to, for example, industry-wide changes that make it more 
challenging for utilities to meet prior commitments. We believe that 
the existing requirements in Order No. 1920 \925\ are adequate to 
safeguard against boundless discounting of factors in Factor Category 
Seven.\926\
---------------------------------------------------------------------------

    \924\ The issue of discounting corporate commitments is rendered 
moot by our decision to set aside the requirement to include these 
commitments in Factor Category Seven above.
    \925\ Id. PP 413-414.
    \926\ PIOs Rehearing Request at 33.
---------------------------------------------------------------------------

iv. Requests for Additional Requirements
(a) Requests for Rehearing
    328. Invenergy requests rehearing, asserting that the Commission 
erred by not requiring transmission providers to include ``advanced-
stage'' merchant high-voltage direct current (HVDC) transmission 
facilities in the list of factors to be considered when developing 
Long-Term Scenarios.\927\ Invenergy claims this omission is unduly 
discriminatory against advanced-stage merchant HVDC transmission.\928\ 
Invenergy also asserts that the Commission failed to consider 
significant evidence in Order No. 1920 because the Commission failed to

[[Page 97240]]

address AEE's comments, which argued that merchant HVDC transmission 
facilities must be included in at least one Long-Term Scenario in order 
to address potential undue discrimination against merchant HVDC 
transmission facilities. According to Invenergy, AEE asserted that it 
is important to include merchant HVDC transmission facilities in at 
least one Long-Term Scenario because merchant HVDC transmission 
facilities are developed by nonincumbent transmission developers and 
this inclusion guards against potential undue discrimination.\929\ In 
addition, Invenergy claims that failure to utilize critical and readily 
available information will result in Long-Term Scenarios that do not 
accurately reflect the topography of the system, and that this 
information should be included to guard against potential undue 
discrimination from incumbent transmission owners.\930\ Invenergy 
argues that the Commission ignored significant evidence in the record 
from Invenergy and others on this issue.\931\
---------------------------------------------------------------------------

    \927\ Invenergy Rehearing Request at 2, 6-7.
    \928\ Id. at 10.
    \929\ Invenergy Rehearing Request at 9 (citing AEE NOPR Reply 
Comments at 19).
    \930\ Id. at 8-9.
    \931\ Id. at 9.
---------------------------------------------------------------------------

(b) Commission Determination
    329. In response to Invenergy's request for rehearing, we reiterate 
that the Commission did not propose specific requirements in the NOPR 
regarding merchant HVDC transmission facilities under development and 
was not persuaded by the evidence in the record that it should include 
advanced-stage HVDC transmission facilities in the minimum set of known 
determinants of Long-Term Transmission Needs.\932\ Invenergy has not 
clearly articulated how merchant HVDC transmission facilities are 
essential to identifying, or are known and identifiable drivers of, 
Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \932\ See Order No. 1920, 187 FERC ] 61,068 at P 493.
---------------------------------------------------------------------------

    330. In the NOPR, the Commission referenced merchant transmission 
facilities only once,\933\ and that reference was in the context of a 
larger proposed requirement that the Commission declined to adopt in 
Order No. 1920.\934\ Order No. 1920 addressed specific deficiencies 
with the Commission's existing regional transmission planning and cost 
allocation requirements but did not identify issues surrounding 
merchant transmission as one of those deficiencies.\935\
---------------------------------------------------------------------------

    \933\ NOPR, 179 FERC ] 61,028 at P 150 (In the context of the 
NOPR proposal for the identification of geographic zones, the 
Commission proposed to include ``any merchant or other entity 
commitments to build . . . transmission facilities'' as one of seven 
mandatory considerations to assess generation developers' commercial 
interest in developing generation within each designated geographic 
zone.).
    \934\ Order No. 1920, 187 FERC ] 61,068 at P 665 (stating that 
``the [identification of geographic zones] NOPR proposal is not 
warranted at this time'').
    \935\ Id. P 139 (``[W]e find that the Commission's regional 
transmission planning and cost allocation requirements fail to 
require transmission providers to: (1) perform a sufficiently long-
term assessment of transmission needs that identifies Long-Term 
Transmission Needs; (2) adequately account on a forward-looking 
basis for known determinants of Long-Term Transmission Needs; and 
(3) consider the broader set of benefits of regional transmission 
facilities planned to meet those Long-Term Transmission Needs. We 
find that reforms to those requirements are thus necessary to ensure 
that Commission-jurisdictional rates are just, reasonable, and not 
unduly discriminatory or preferential.'').
---------------------------------------------------------------------------

    331. We disagree with Invenergy's claim that the exclusion of 
proposed but not yet built merchant HVDC transmission facilities from 
the required factors underlying the Long-Term Scenarios is unjust and 
unreasonable.\936\ In Order No. 1920, the Commission described the 
seven specific categories of factors required by the Commission as 
``essential to identifying Long-Term Transmission Needs'' and ``known 
and identifiable drivers of Long-Term Transmission Needs.'' \937\ 
Although Invenergy claimed that one of its merchant HVDC transmission 
facilities could address transmission needs,\938\ Invenergy has failed 
to clearly articulate how proposed but not yet built merchant HVDC 
transmission facilities are essential to identifying, or are known and 
identifiable drivers of, Long-Term Transmission Needs. However, as 
indicated in Order No. 1920, transmission providers may be aware of 
additional categories of factors beyond those adopted in the final rule 
that drive Long-Term Transmission Needs and may incorporate additional 
categories of factors into the development of Long-Term Scenarios.\939\ 
We clarify that, if transmission providers elect to use additional 
categories of factors beyond the required categories of factors in 
Order No. 1920 in the development of Long-Term Scenarios, the 
transparency requirements set forth in Order No. 1920 also apply to the 
additional categories of factors.\940\ Pursuant to this clarification, 
transmission providers must publish on the public portion of an OASIS 
or other public website: (1) the list of each additional categories of 
factors, and the factors in each of the additional categories of 
factors that they will account for in their Long-Term Scenarios; (2) a 
description of each additional category of factors and a description of 
each factor that they will account for in their Long-Term Scenarios; 
(3) a general statement explaining how they will account for each 
additional category of factors and each of the additional factors in 
their Long-Term Scenarios; (4) a description of the extent to which 
they will discount any factors in each additional category of factors; 
and (5) a list of the factors that they considered but did not 
incorporate in each additional category of factors in their Long-Term 
Scenarios. Consistent with Order No. 1920, we find that this 
transparency is necessary to make clear to stakeholders which specific 
additional categories of factors and factors transmission providers 
incorporate into Long-Term Scenarios and how they are incorporated. We 
believe this posting requirement for additional categories of factors 
will also provide greater transparency into how transmission providers 
develop Long-Term Scenarios, while still providing transmission 
providers with flexibility regarding whether, and if so, how they 
choose to incorporate relevant factors.\941\ Accordingly, in 
transmission planning regions where proposed HVDC transmission 
facilities may play a role in shaping Long-Term Transmission Needs, 
transmission providers have the flexibility to consider and incorporate 
such facilities into their Long-Term Scenarios.
---------------------------------------------------------------------------

    \936\ Invenergy Rehearing Request at 8.
    \937\ Order No. 1920, 187 FERC ] 61,068 at P 410.
    \938\ Invenergy Initial NOPR Comments at 7 (``A planned 5,000 MW 
HVDC line such as Grain Belt's would be a significant system 
addition, and could itself provide system benefits or even address 
transmission needs otherwise identified through the planning 
process. . . .'').
    \939\ Order No. 1920, 187 FERC ] 61,068 at P 493.
    \940\ See id. PP 528-533.
    \941\ Id. P 534.
---------------------------------------------------------------------------

    332. We also disagree with Invenergy's argument that the Commission 
has failed to direct transmission providers to use critical--and 
readily available--information related to the future electric power 
system, which renders the resulting Long-Term Scenarios unjust and 
unreasonable.\942\ Order No. 1920 requires transmission providers to 
develop Long-Term Scenarios with data inputs that are timely, developed 
using best practices and diverse and expert perspectives, and adopted 
via a process that satisfies the transmission planning principles of 
Order Nos. 890 and 1000.\943\ In addition, in Order No. 1920, the 
Commission found that transmission providers must use best available 
data when determining whether each factor is likely to affect Long-Term

[[Page 97241]]

Transmission Needs. Once transmission providers have determined that a 
factor is likely to affect Long-Term Transmission Needs, they must use 
the best available data when they then account for that factor in the 
development of Long-Term Scenarios.\944\
---------------------------------------------------------------------------

    \942\ Invenergy Rehearing Request at 9.
    \943\ Order No. 1920, 187 FERC ] 61,068 at P 633.
    \944\ Id.
---------------------------------------------------------------------------

    333. We also disagree with Invenergy's claim that the Commission 
ignored significant evidence in the record.\945\ We remain unpersuaded 
by the evidence in the record that the Commission should include 
advanced-stage HVDC transmission facilities in the minimum set of known 
determinants of Long-Term Transmission Needs.\946\ Invenergy's 
experience with its Grain Belt project in the MISO Long Range 
Transmission Plan speaks to a separate issue currently before the 
Commission.\947\
---------------------------------------------------------------------------

    \945\ Invenergy Rehearing Request at 9 (``As demonstrated above, 
multiple commenters, including Invenergy, the Clean Energy 
Associations, and others placed evidence into the record explaining 
why merchant HVDC transmission facilities must be included.'').
    \946\ Order No. 1920, 187 FERC ] 61,068 at P 493.
    \947\ Invenergy Transmission LLC v. Midcontinent Indep. Sys. 
Operator, Inc., Complaint, Docket No. EL22-83-000 (filed Aug. 8, 
2022).
---------------------------------------------------------------------------

    334. Finally, we disagree with Invenergy's argument that the 
Commission's inclusion of a wide range of factors, including generation 
interconnections, but exclusion of advanced-stage merchant HVDC 
facilities is unduly discriminatory and opens such developers to 
further potential undue discrimination.\948\ The Commission found it 
appropriate to require transmission providers to incorporate Factor 
Category Six (generator interconnection requests and withdrawals) into 
the development of Long-Term Scenarios because generation 
interconnection queues provide important information about future 
generation development over the transmission planning horizon and 
therefore affect Long-Term Transmission Needs.\949\ We cannot make a 
similar finding for advanced-stage merchant HVDC transmission based on 
the record in this proceeding, nor do we conclude (and Invenergy has 
not demonstrated) that the exclusion of advanced-stage merchant HVDC 
facilities from the required categories of factors opens merchant 
transmission developers to potential undue discrimination. We also are 
not persuaded by Invenergy's reference to AEE's comments claiming that 
being a nonincumbent transmission developer rises to the level of 
potential undue discrimination that must be remedied by requiring 
merchant HVDC to be included in Long-Term Scenarios. To the extent that 
similar potential undue discrimination claims for nonincumbent merchant 
HVDC transmission developers are pending in other proceedings, the 
Commission will address those claims based on the evidence in those 
proceedings. We note that AEE provides no evidence of potential undue 
discrimination and that AEE itself has not filed a rehearing request on 
this issue. Finally, we clarify that transmission providers, in 
addressing interconnection requests and withdrawals under Factor 
Category Six, must include merchant transmission developer 
interconnection requests in the development of Long-Term Scenarios, and 
in a manner comparable to other interconnection requests.
---------------------------------------------------------------------------

    \948\ Invenergy Rehearing Request at 10.
    \949\ Order No. 1920, 187 FERC ] 61,068 at P 472.
---------------------------------------------------------------------------

c. Stakeholder Process and Transparency
i. Order No. 1920 Requirements
    335. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to revise the regional 
transmission planning process in their OATTs to outline an open and 
transparent process that provides stakeholders, including federally-
recognized Tribes and states, with a meaningful opportunity to propose 
potential factors and to provide timely input on how to account for 
specific factors in the development of Long-Term Scenarios. The 
Commission further required transmission providers to publish on the 
public portion of an OASIS or other public website the following 
information: (1) the list of the factors in each of the seven required 
categories of factors that they will account for in their Long-Term 
Scenarios; (2) a description of each factor that they will account for 
in their Long-Term Scenarios; (3) a general statement explaining how 
they will account for each of those factors in their Long-Term 
Scenarios; (4) a description of the extent to which they will discount 
any factors in Factor Categories Four through Seven in each Long-Term 
Scenario; and (5) a list of the factors that they considered but did 
not incorporate in their Long-Term Scenarios.\950\ In addition, the 
Commission required transmission providers to post this information 
after stakeholders, including states, have had the meaningful 
opportunity to propose potential factors and to provide input on how to 
account for specific factors in the development of Long-Term 
Scenarios.\951\ The Commission explained that this requirement will 
provide greater transparency into how transmission providers develop 
Long-Term Scenarios, while still providing transmission providers with 
flexibility regarding whether, and if so, how they choose to 
incorporate relevant factors,\952\ and the Commission explained that 
this transparency also ensures that transmission providers review 
stakeholder-proposed factors in a fair and non-discriminatory 
manner.\953\
---------------------------------------------------------------------------

    \950\ Id. P 528.
    \951\ Id. P 533.
    \952\ Id. P 534.
    \953\ Id. P 535.
---------------------------------------------------------------------------

    336. The Commission also required transmission providers, 
consistent with Order No. 890's transparency transmission planning 
principle, to make transparent the methodology, criteria, assumptions, 
and data used to develop each Long-Term Scenario.\954\ Given the 
importance of a robust stakeholder process to developing more accurate 
assumptions to serve as the basis for Long-Term Scenarios, Order No. 
1920 required transmission providers to give stakeholders a meaningful 
opportunity to provide timely input on how and what information to 
incorporate into the development of Long-Term Scenarios, including how 
to account for a specific factor in terms of how the factor may affect 
Long-Term Transmission Needs. The Commission explained that this 
meaningful opportunity includes the opportunity to propose factors, 
provide information and identify sources of best available data, 
propose how a factor may affect Long-Term Transmission Needs, and 
explain how that factor could be reflected in the development of Long-
Term Scenarios, including the extent to which it is appropriate to 
discount the effects of certain factors on Long-Term Transmission 
Needs.\955\
---------------------------------------------------------------------------

    \954\ Id. P 305 (citing Order No. 890, 118 FERC ] 61,119 at P 
471).
    \955\ Id. PP 529-530.
---------------------------------------------------------------------------

    337. The Commission further found in Order No. 1920 that 
stakeholder input is particularly important for factors in the first 
three categories of factors, because federal, state, and local 
government entities, federally-recognized Tribes, and utilities, load-
serving entities, and their retail regulators that participate in the 
stakeholder process are distinctly well-positioned to provide 
transmission providers with vital information on how the factors over 
which they have authority or that they govern are likely to influence 
Long-Term Transmission Needs over the transmission planning

[[Page 97242]]

horizon.\956\ The Commission recognized that different stakeholders may 
provide information about the same factor that is contradictory and 
allowed transmission providers to weigh more heavily one source of 
information over another.\957\
---------------------------------------------------------------------------

    \956\ Id. P 530.
    \957\ Id. P 531.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    338. NESCOE requests clarification that transmission providers must 
rely on states in developing Long-Term Scenarios where state laws, 
regulations, and/or policies are driving Long-Term Transmission Needs. 
If the Commission does not provide this clarification, NESCOE requests 
rehearing.\958\ NESCOE explains that state officials have expertise in 
connection with these matters such that transmission providers should 
rely on states for input regarding the details of state requirements in 
Factor Categories One, Two, and Seven. NESCOE claims that, in the 
absence of this clarification, transmission providers may devote 
resources to developing Long-Term Scenarios that are less useful to 
transmission planning regions.\959\ Similarly, PJM States request 
clarification of the degree to which transmission providers should 
defer to, weigh, or consider the input of states as it relates 
specifically to state laws and integrated resource plans. PJM States 
argue that states have a unique role as to these subjects, and that 
transmission providers should not treat state perspectives the same as 
those of any other stakeholder.\960\
---------------------------------------------------------------------------

    \958\ NESCOE Rehearing Request at 11.
    \959\ Id. at 20-21.
    \960\ PJM States Rehearing Request at 4.
---------------------------------------------------------------------------

    339. PIOs request rehearing such that the Commission would 
strengthen the transparency provisions by requiring transmission 
providers to provide more detailed explanations of the factors to be 
used and to justify any discounting of factors in Factor Categories 
Four through Seven. PIOs argue that stronger transparency provisions 
would foster more meaningful stakeholder processes.\961\ Specifically, 
PIOs contend that, with respect to the information that transmission 
providers must publish on the public portion of an OASIS or other 
public website, the Commission should replace the third item, i.e., ``a 
general statement explaining how [transmission providers] will account 
for each of [the factors that they will account for in their Long-Term 
Scenarios],'' with ``a detailed description of the reasoning and 
methodology used to account for each factor, as well as providing the 
actual data inputs when possible.'' \962\
---------------------------------------------------------------------------

    \961\ PIOs Rehearing Request at 36.
    \962\ Id.
---------------------------------------------------------------------------

    340. PIOs criticize the Commission's rationale for declining to 
include this requirement, i.e., that the burden would not be justified 
by the benefit of such additional information. PIOs argue that 
requiring transmission providers to justify their discounting decisions 
would help hold transmission providers accountable, incentivize more 
accurate discounting assumptions, and guard against pressure from self-
interested stakeholders to excessively discount factors.\963\ PIOs 
contend that Order No. 1920 is arbitrary and capricious because failing 
to require more detailed explanations of the factors to be used or to 
justify any discounting of factors in Factor Categories Four through 
Seven does not flow rationally from Order No. 1920's ``more fundamental 
findings'' as to the requirements for transmission providers to provide 
meaningful opportunity for stakeholder input and to make the 
development of Long-Term Scenarios transparent.\964\
---------------------------------------------------------------------------

    \963\ Id. at 37-38.
    \964\ Id. at 38 (citing Order No. 1920, 187 FERC ] 61,068 at P 
305).
---------------------------------------------------------------------------

    341. SERTP Sponsors request that the Commission clarify that 
transmission providers have the discretion to include or to exclude an 
assumption from the development of a Long-Term Scenario where 
stakeholders do not provide transmission providers with sufficient 
information as to whether a potential assumption or factor is likely to 
affect Long-Term Transmission Needs. SERTP Sponsors provide the example 
of a generator whose point of interconnection is unknown and contend 
that transmission providers should not be obligated to hypothesize 
arbitrarily as to that point of interconnection, because doing so 
likely would yield implausible Long-Term Scenarios and would not result 
in cost-effective or efficient transmission planning.\965\
---------------------------------------------------------------------------

    \965\ SERTP Sponsors Rehearing Request at 13-14.
---------------------------------------------------------------------------

    342. SERTP Sponsors request that the Commission clarify that 
transmission providers may rely on stakeholders to identify factors in 
Factor Categories Four through Seven, and, if stakeholders identify no 
such factors, that transmission providers may but need not do so. SERTP 
Sponsors contend that Order No. 1920 implies but does not clearly 
provide for this requested clarification.\966\ SERTP Sponsors also 
request that the Commission clarify that transmission providers may 
rely upon stakeholders to identify factors that, unlike factors in 
Factor Categories One through Three, do not pertain directly to a 
specific transmission provider in the relevant transmission planning 
region.\967\ If the Commission does not so clarify, SERTP Sponsors 
request rehearing on the grounds that requiring transmission providers 
to identify such factors would be unduly burdensome.\968\
---------------------------------------------------------------------------

    \966\ Id. at 13 (citing Order No. 1920, 187 FERC ] 61,068 at P 
516).
    \967\ Id. at 14 & n.33.
    \968\ Id. at 14.
---------------------------------------------------------------------------

    343. Finally, SERTP Sponsors request that the Commission clarify 
the required timing of when transmission providers must publish on the 
public portion of an OASIS or other public website the information 
about factors required by Order No. 1920. SERTP Sponsors contend that 
Order No. 1920 does not make clear whether this information must be 
published in conjunction with transmission providers' compliance 
filings or by the start of the first Long-Term Regional Transmission 
Planning cycle. SERTP Sponsors argue that the Commission should require 
transmission providers to post this information after the conclusion of 
the period during which stakeholders provide input into these 
matters.\969\
---------------------------------------------------------------------------

    \969\ Id. at 26.
---------------------------------------------------------------------------

iii. Commission Determination
    344. In response to NESCOE's and PJM States' requested 
clarification that transmission providers must rely on states in 
developing Long-Term Scenarios where state laws, regulations, and/or 
policies are driving Long-Term Transmission Needs, we grant the 
following clarifications. We clarify that states must have a meaningful 
opportunity to provide timely input on the development of Long-Term 
Scenarios, including factors and data inputs, and to explain how their 
own policies and planning affect Long-Term Transmission Needs.\970\ 
Furthermore, we clarify that transmission providers must consult with 
and consider the positions of the Relevant State Entities and any other 
entity authorized by a Relevant State Entity as its representative as 
to how to account for factors related to states' laws, policies, and 
regulations when determining the assumptions that will be used in the 
development of Long-Term Scenarios.\971\ Specifically, transmission

[[Page 97243]]

providers shall consult with Relevant State Entities and any other 
authorized entities as to whether a specific state policy must be 
accounted for as a factor within each category (i.e., if the specific 
state policy will likely affect Long-Term Transmission Needs), how to 
account for the specific state policy in the development of Long-Term 
Scenarios (e.g., the method and data used to forecast generation 
resources added because of a specific state policy), and how to adjust 
the treatment of the specific state policy across Long-Term Scenarios 
(e.g., assume certain policy-related outcomes materialize in some but 
not all Long-Term Scenarios).\972\
---------------------------------------------------------------------------

    \970\ Order No. 1920, 187 FERC ] 61,068 at PP 528-537, 560-562, 
634.
    \971\ A Relevant State Entity may believe that a different state 
entity would be better situated to advise transmission providers as 
to how state policy may affect Long-Term Transmission Needs. For 
example, the state entity responsible for electric utility 
regulation may believe that the state entity responsible for energy 
policy is in a better position to advise on state energy policy 
implementation. In this case, the Relevant State Entity may 
authorize the other state entity as its representative in 
discussions with transmission providers.
    \972\ See id. P 417.
---------------------------------------------------------------------------

    345. We further clarify that, where transmission providers 
determine that a factor based on a state's law, regulation, or policy 
is likely to affect Long-Term Transmission Needs, transmission 
providers should rely on the state in determining how to account for 
such a state-related factor when developing Long-Term Scenarios. For 
example, for a state that has required integrated resource planning 
processes, transmission providers should include one of the state's 
preferred power system trajectories, including both the supply and 
demand side resource trajectory as appropriate, in each of Long-Term 
Scenarios, or include different state-preferred power system 
trajectories in different Long-Term Scenarios. As such, transmission 
providers could include in the development of Long-Term Scenarios the 
set of resource capacity additions and/or retirements expected by a 
state based on the incentives or requirements in that state's law. If 
transmission providers determine, based on input provided by the state 
or their own judgment, that a factor based on a state's law, 
regulation, or policy is likely to affect Long-Term Transmission Needs, 
transmission providers should then determine whether and how to account 
for that factor in the development of Long-Term Scenarios.
    346. We disagree with PIOs that a more detailed explanation of the 
factors that transmission providers will account for in their Long-Term 
Scenarios and justification of the factors that they will discount is 
warranted. Broadly, we affirm that Order No. 1920 strikes the right 
balance between prescriptive requirements and flexibility with respect 
to the development of Long-Term Scenarios.\973\ We also find that this 
is true with respect specifically to Order No. 1920's requirements on 
stakeholder process and transparency. PIOs request that we require ``a 
detailed description of the reasoning and methodology used to account 
for each factor, as well as providing the actual data inputs when 
possible'' and that we require transmission providers to justify their 
discounting decisions of factors in Factor Categories Four through 
Seven. We find that such requirements are not necessary to ensure that 
stakeholders have a meaningful opportunity to provide input. We further 
find that the requirements of Order No. 1920 ensure that the 
development of Long-Term Scenarios is sufficiently transparent,\974\ 
and that PIOs' requested requirements are not needed to ensure that 
transmission providers use accurate data.\975\
---------------------------------------------------------------------------

    \973\ Id.
    \974\ See id. P 533 (requiring transmission providers to 
publicly post ``(1) the list of the factors in each of the seven 
required categories of factors that they will account for in their 
Long-Term Scenarios; (2) a description of each factor that they will 
account for in their Long-Term Scenarios; (3) a general statement 
explaining how they will account for each of these factors in their 
Long-Term Scenarios; (4) a description of the extent to which they 
will discount any factors in Factor Categories Four through Seven in 
each Long-Term Scenario; and (5) a list of the factors that they 
considered but did not incorporate in their Long-Term Scenarios.'').
    \975\ PIOs Rehearing Request at 36-37. See Order No. 1920, 187 
FERC ] 61,068 at P 636 (``We find that a requirement to use the best 
available data inputs is warranted to ensure that transmission 
providers are regularly updating data inputs and using timely and 
accurate data inputs to inform Long-Term Scenarios.'').
---------------------------------------------------------------------------

    347. We emphasize that Order No. 1920 sets minimum requirements 
with which all transmission providers must comply, and we are not 
convinced that the level of information that PIOs seek is necessary. 
Further, we clarify that nothing in Order No. 1920 prevents 
transmission providers from providing more than the minimum amount of 
information that we require, including the level of detail requested by 
PIOs. Moreover, we conclude that granting PIOs' request is unnecessary 
because the existing transparency requirements in Order No. 1920 \976\ 
are sufficient to ensure that ``the methodology, criteria, assumptions, 
and data used to develop each Long-Term Scenario'' are 
transparent.\977\
---------------------------------------------------------------------------

    \976\ Supra P 346 n.975.
    \977\ Order No. 1920, 187 FERC ] 61,068 at P 305.
---------------------------------------------------------------------------

    348. We decline to provide clarification to SERTP Sponsors with 
respect to the inclusion or exclusion of factors for which stakeholders 
provide insufficient information, and we similarly decline to address 
SERTP Sponsors' hypothetical in the abstract.\978\ Generally, 
transmission providers can rely on stakeholders for input on the 
development of Long-Term Scenarios, including factors and data inputs, 
and must consult with and consider the positions of Relevant State 
Entities and any other entity authorized by a Relevant State Entity as 
its representative regarding how their policies and planning affect 
Long-Term Transmission Needs and the assumptions that will be used in 
the development of Long-Term Scenarios. Transmission providers 
implementing Long-Term Regional Transmission Planning necessarily will 
balance competing interests from within the transmission planning 
region when developing Long-Term Scenarios, and Order No. 1920 provides 
transmission providers with sufficient flexibility to exercise 
engineering judgment to ensure the reliable operation of the 
transmission system and compliance with a variety of regulatory 
requirements.\979\
---------------------------------------------------------------------------

    \978\ It is unclear whether SERTP Sponsors intended to argue 
that failure to grant clarification in this respect would result in 
Order No. 1920 exceeding the Commission's authority; to the extent 
they intended to do so, we find this argument has not been raised 
with the specificity required on rehearing. See supra Major 
Questions Doctrine section.
    \979\ Order No. 1920, 187 FERC ] 61,068 at P 1027.
---------------------------------------------------------------------------

    349. In response to SERTP Sponsors' request for clarification 
regarding the identification of factors in Factor Categories Four 
through Seven, we clarify that transmission providers must identify 
factors in Factor Categories Four, Five, and Six but need not 
independently identify factors in Factor Category Seven--rather, 
transmission providers may rely on stakeholders, including states, to 
bring such factors to their attention. We believe that factors in 
Factor Categories One, Two, Three, and Seven arise from stakeholder 
decision-making and legal processes that generally are external to the 
transmission provider and are therefore suitable for identification by 
the states and other stakeholders that govern or have authority over 
those processes. Therefore, as with factors in Factor Categories One, 
Two, and Three, transmission providers may rely on stakeholders to 
identify factors in Factor Category Seven in the development of Long-
Term Scenarios, particularly through the open and transparent 
stakeholder process required by Order No. 1920.\980\ In contrast, we 
believe that

[[Page 97244]]

factors in Factor Categories Four, Five, and Six relate to the 
expertise of transmission providers arising from their day-to-day 
operations. For example, transmission providers manage processes for 
processing interconnection requests and withdrawals (Factor Category 
Six) and determining the impact of resource retirements (Factor 
Category Five). In managing those processes and the day-to-day 
operations of the transmission system, transmission providers also gain 
information about trends in technology and fuel costs within and 
outside the electricity supply industry (Factor Category Four). 
Therefore, we clarify that transmission providers have an independent 
obligation to identify factors in Factor Categories Four, Five, and Six 
regardless of whether any such factors are identified by stakeholders 
and must, where relevant, consult with and consider the positions of 
Relevant State Entities and any entities authorized by the Relevant 
State Entities. In response to SERTP Sponsors' argument that, if 
transmission providers must independently identify factors in Factor 
Categories Four through Seven, the Commission would be holding 
transmission providers to a burdensome unattainable standard, we 
clarify that the independent obligation to identify factors in Factor 
Categories Four through Six does not require transmission providers to 
identify every potentially knowable factor within those categories. 
Transmission providers can use their prior experience and professional 
judgement to independently identify factors in Factor Categories Four, 
Five, and Six.
---------------------------------------------------------------------------

    \980\ Id. P 508. We note, however, an exception to this general 
rule. Where the transmission provider is the entity that has made a 
commitment that affects Long-Term Transmission Needs, the 
transmission provider may not rely on the identification by 
stakeholders of this factor or these factors.
---------------------------------------------------------------------------

    350. Finally, in response to SERTP Sponsors' request for 
clarification regarding the timing of transmission providers' 
publication of information regarding the factors to be incorporated 
into the development of Long-Term Scenarios on the public portion of an 
OASIS or other public website, we clarify that transmission providers 
do not need to include this information with the filings that they 
submit to comply with Order No. 1920. Rather, we clarify that Order No. 
1920 requires transmission providers to post this information as part 
of each Long-Term Regional Transmission Planning cycle after 
stakeholders, including states, have had a meaningful opportunity to 
propose potential factors and to provide input on how to account for 
specific factors in the development of Long-Term Scenarios for that 
planning cycle.\981\ We further clarify that publication of information 
regarding the factors to be incorporated into the development of Long-
Term Scenarios must occur before transmission providers finish 
developing Long-Term Scenarios,\982\ and, in any event, well before the 
transmission provider has identified Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \981\ Id. P 533.
    \982\ See id. P 534 (discussing the value of posting requirement 
in terms of the transparency into how transmission providers develop 
Long-Term Scenarios).
---------------------------------------------------------------------------

5. Requests for Additional Flexibility Regarding Long-Term Scenarios 
Requirements
    351. This section responds to requests for rehearing or 
clarification to permit additional flexibility with respect to multiple 
interrelated Long-Term Scenario requirements, including transmission 
providers' incorporation of factors from seven categories of factors; 
the treatment of factors in the first three categories of factors; and 
the number, type, and plausibility of Long-Term Scenarios.
a. Order No. 1920 Requirements
    352. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to develop, at least 
once during the five-year Long-Term Regional Transmission Planning 
cycle, at least three distinct Long-Term Scenarios that, at a minimum, 
incorporate the seven categories of factors listed in the Categories of 
Factors section.\983\ The Commission adopted the NOPR proposals to 
require transmission providers in each transmission planning region to 
publicly disclose information and data inputs used to create each Long-
Term Scenario and provide stakeholders an opportunity to provide timely 
and meaningful input into how Long-Term Scenarios are developed.\984\
---------------------------------------------------------------------------

    \983\ Id. P 559.
    \984\ Id. P 560.
---------------------------------------------------------------------------

    353. The Commission required transmission providers in each 
transmission planning region to develop a plausible and diverse set of 
at least three Long-Term Scenarios.\985\ The Commission also required 
that each individual Long-Term Scenario be plausible to avoid resting 
on assumptions about factors and data inputs that do not reasonably 
capture possible future outcomes. The Commission clarified that the 
term ``diverse'' means that the set of Long-Term Scenarios must 
represent a reasonable range of probable future outcomes consistent 
with the requirement for plausibility, based on assumptions about the 
factors and data inputs.\986\
---------------------------------------------------------------------------

    \985\ Id. PP 575-577.
    \986\ Id. P 576.
---------------------------------------------------------------------------

    354. The Commission also required transmission providers in each 
transmission planning region to develop at least one sensitivity, 
applied to each Long-Term Scenario, to account for uncertain 
operational outcomes that determine the benefits of and/or need for 
transmission facilities during multiple concurrent and sustained 
generation and/or transmission outages due to an extreme weather event 
across a wide area.\987\ In Order No. 1920, the Commission provided 
transmission providers with flexibility to conduct this sensitivity 
either before or after identifying potential regional transmission 
solutions to the Long-Term Transmission Needs identified using those 
Long-Term Scenarios.\988\ Order No. 1920 did not preclude transmission 
providers from considering additional sensitivities, and the Commission 
encouraged transmission providers to assess the need to develop other 
sensitivities as part of Long-Term Regional Transmission Planning.\989\ 
The Commission found that modeling extreme weather events as 
sensitivities is appropriate for Long-Term Regional Transmission 
Planning.\990\
---------------------------------------------------------------------------

    \987\ Id. P 593.
    \988\ Id. P 594.
    \989\ Id. P 597.
    \990\ Id. P 598.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    355. PJM requests rehearing such that the Commission either would 
consider requests for flexibility or permit flexibility that PJM 
contends would be required for PJM to develop Long-Term Scenarios and 
sensitivities consistent with a draft long-term transmission planning 
process that PJM has developed.\991\ PJM argues that Order No.

[[Page 97245]]

1920's requirements with respect to the development of Long-Term 
Scenarios are overly prescriptive, particularly with respect to the 
requirements that transmission providers develop three Long-Term 
Scenarios that each incorporate seven categories of factors and that 
transmission providers cannot discount factors in Factor Categories One 
through Three.\992\ PJM contends that these requirements would 
``complicate'' PJM's efforts to promote more efficient or cost-
effective regional transmission planning and development.\993\
---------------------------------------------------------------------------

    \991\ See PJM Rehearing Request at 12 (``Granting rehearing and 
permitting flexibility with respect to the issues identified below 
would allow PJM to use the PJM Long Term Regional Transmission 
Planning process as the foundation for a long-term planning process 
that achieves the objectives of the Final Rule, even though 
implementation details may differ in some way from those the Final 
Rule prescribes.'' (footnote omitted)); id. at 14 (``PJM urges the 
Commission to grant rehearing and confirm that it will consider 
requests for flexibility to accommodate regional differences.''); 
id. at 19 (``[G]iven the diversity among regions, PJM believes it is 
appropriate to allow transmission planners to work with states and 
stakeholders within their respective regions to determine the 
appropriate number of and specific scenarios to be used in the Long-
Term Regional Transmission Planning process, as well as giving the 
transmission provider flexibility to determine how to weigh specific 
factors used to develop the assumptions upon which Long-Term 
Scenarios are based.''); id. (``PJM urges the Commission to grant 
rehearing and confirm that it will consider requests for flexibility 
to develop Long-Term Scenarios and conduct sensitivity analyses in 
such a way as to accommodate regional differences.'').
    \992\ Id. at 13 n.59, 16, 18.
    \993\ Id. at 16, 18.
---------------------------------------------------------------------------

    356. PJM explains that, under the draft long-term transmission 
planning process that PJM developed, PJM would develop three distinct 
scenarios that would ``generally account for the seven factors'' 
required by Order No. 1920: the ``Base Reliability Scenario,'' the 
``Medium Public Policy Scenario,'' and the ``High Public Policy 
Scenario.'' \994\ The Base Reliability Scenario would include certain 
``categories of factors,'' including: the PJM Load Forecast Report; 
announced retirements and retirements required by Public Policy 
Requirements; in-service generation and generation that is not yet in 
service but with an executed service agreement or State Agreement 
Approach reservation; and replacement generation taken mainly from the 
PJM Service Request process.\995\ The Medium Public Policy Scenario 
would build on the Base Reliability Scenario by including certain 
additional Public Policy Requirements that otherwise would be brought 
to PJM as part of the State Agreement Approach process, such as state 
renewable portfolio standards.\996\ The High Public Policy Scenario 
would in turn build on the Medium Public Policy Scenario by modeling 
``Public Policy Objectives,'' defined as Public Policy Requirements 
that are not yet in a statute or regulation.\997\ PJM argues that this 
draft process would demonstrate a wide range of possible transmission 
needs, and would be a prudent way to account for long-term needs 
without overbuilding the transmission system.\998\
---------------------------------------------------------------------------

    \994\ Id. at 16-18.
    \995\ Id. at 16-17.
    \996\ Id. at 17-18.
    \997\ Id. at 18 & n.80.
    \998\ Id. at 19.
---------------------------------------------------------------------------

    357. PJM States and West Virginia Commission request that the 
Commission clarify that--or, in the alternative, request rehearing such 
that--Order No. 1920 does not prohibit the development by transmission 
providers of a fourth Long-Term Scenario or additional sensitivities 
that are designed to provide information to states on the factors 
driving the need for transmission facilities and on their costs and 
benefits. PJM States and West Virginia Commission explain that Order 
No. 1920 requires that transmission providers assume that all legally 
binding obligations are followed, state-approved integrated resource 
plans are followed, and expected supply obligations for load-serving 
entities are met and not discounted. PJM States and West Virginia 
therefore express concern that Order No. 1920 places ``undue 
restrictions'' on the development of scenarios or sensitivities that 
can provide the information sought by states, which PJM States contend 
would be necessary to assist in cost allocation determinations and in 
siting and safety decisions.\999\
---------------------------------------------------------------------------

    \999\ PJM States Rehearing Request at 4-6; West Virginia 
Commission Rehearing Request at 14-16.
---------------------------------------------------------------------------

    358. Ohio Commission Federal Advocate argues that Order No. 1920 
makes it impossible to identify and evaluate transmission facilities 
that are required due to other states' laws, as well as to ``isolate 
the incremental costs'' arising from those laws. Ohio Commission 
Federal Advocate states that this lack of transparency is not in the 
public interest, and that the Commission should clarify that 
counterfactual scenarios that do not reflect compliance with state law 
are permissible because they provide important insights into the 
factors driving transmission needs.\1000\
---------------------------------------------------------------------------

    \1000\ Ohio Commission Federal Advocate Rehearing Request at 18.
---------------------------------------------------------------------------

    359. Virginia and North Carolina Commissions argue that the 
Commission should grant rehearing such that Order No. 1920 would 
require or allow for one or more ``baseline'' planning scenarios that 
exclude all or some policy-driven factors. Virginia and North Carolina 
Commissions explain that Order No. 1920 requires transmission providers 
to incorporate seven categories of factors in each Long-Term Scenario, 
and that the Commission did not allow flexibility for additional 
scenarios that exclude some or all of these factors. Virginia and North 
Carolina Commissions contend that, without a ``baseline'' scenario, 
Relevant State Entities and other stakeholders will not have adequate 
transparency regarding the critical drivers of transmission needs or 
the costs associated with a particular transmission facility, nor will 
they be able to evaluate whether cost allocation methods comply with 
the Commission's cost causation principles.\1001\
---------------------------------------------------------------------------

    \1001\ Virginia and North Carolina Commissions Rehearing Request 
at 4-5.
---------------------------------------------------------------------------

    360. Finally, in PJM's general request for additional flexibility 
in the development of Long-Term Scenarios, PJM identified the 
requirement in Order No. 1920 to conduct a specific sensitivity for 
each Long-Term Scenario as an example of a requirement that it believes 
to be overly burdensome.\1002\ PJM States and West Virginia Commission 
request that the Commission clarify that--or grant rehearing such 
that--transmission providers are required, or even permitted, to 
provide additional sensitivity analyses to the states that best inform 
them on required transmission facility needs, costs, and benefits based 
on variations or exclusions of specific factors or categories of 
factors, including those in the first three categories of 
factors.\1003\
---------------------------------------------------------------------------

    \1002\ PJM Rehearing Request at 16.
    \1003\ PJM States Rehearing Request at 4-5; West Virginia 
Commission Rehearing Request at 14-16.
---------------------------------------------------------------------------

c. Commission Determination
    361. We disagree with PJM's rehearing arguments and deny its 
requested clarification with respect to flexibility regarding the 
development of Long-Term Scenarios. Specifically, we continue to find 
that transmission providers must develop at least three distinct Long-
Term Scenarios as defined in Order No. 1920, and that transmission 
providers must incorporate the seven categories of factors set forth in 
Order No. 1920 into each of those Long-Term Scenarios,\1004\ as also 
clarified above.\1005\ As the Commission held in Order No. 1920, and as 
we continue to find here, the Commission's regional transmission 
planning requirements currently fail to adequately account on a 
forward-looking basis for known determinants of Long-Term Transmission 
Needs, and the incorporation of the seven categories of factors is 
necessary because these categories of factors are essential to 
identifying Long-Term Transmission Needs.\1006\ Failing to require that 
transmission providers incorporate these categories of factors into the

[[Page 97246]]

development of each Long-Term Scenario would increase the likelihood 
that transmission providers will continue to underestimate--or omit 
entirely--certain known determinants of Long-Term Transmission Needs in 
their regional transmission planning processes.\1007\
---------------------------------------------------------------------------

    \1004\ Order No. 1920, 187 FERC ] 61,068 at PP 409, 559.
    \1005\ See supra Long-Term Scenarios Requirements, Stakeholder 
Process and Transparency section.
    \1006\ Order No. 1920, 187 FERC ] 61,068 at P 410.
    \1007\ Id. P 411.
---------------------------------------------------------------------------

    362. We also continue to find that transmission providers must 
assume that legally binding obligations (i.e., federal, federally-
recognized Tribal, state, and local laws and regulations) are followed, 
state-approved integrated resource plans are followed, and expected 
supply obligations for load-serving entities are fully met.\1008\ Each 
Long-Term Scenario must account for and be consistent with factors in 
these first three categories of factors, because these categories of 
factors are part of the primary drivers of Long-Term Transmission 
Needs.\1009\
---------------------------------------------------------------------------

    \1008\ We continue to find that it is appropriate for 
transmission providers to assume that legally binding obligations 
are met, unless and until there is a change in law. Id. P 512.
    \1009\ Id. PP 507, 512.
---------------------------------------------------------------------------

    363. We disagree with PJM's apparent contention that complying with 
Order No. 1920 requirements with respect to Long-Term Scenarios will 
``complicate'' PJM's efforts to conduct Long-Term Regional Transmission 
Planning \1010\ as it is set forth in Order No. 1920.\1011\ Instead, we 
reiterate that Order No. 1920's Long-Term Scenarios requirements strike 
a reasonable balance between, on the one hand, ensuring that 
transmission providers identify Long-Term Transmission Needs and 
identify, evaluate, and select Long-Term Regional Transmission 
Facilities that would meet those needs, and, on the other hand, 
providing sufficient flexibility for transmission providers to develop 
and use Long-Term Scenarios in a way that reflects the unique 
characteristics of their respective transmission planning 
regions.\1012\ We continue to find that Order No. 1920's categories of 
factors requirements strike the right balance between prescriptive 
requirements and flexibility \1013\ and that they are sufficiently 
detailed to address the need for reform without limiting regional 
flexibility.\1014\ Further, we continue to find that the requirement to 
develop at least three distinct Long-Term Scenarios that meet Order No. 
1920's requirements strikes the appropriate balance between 
establishing a sufficient number of Long-Term Scenarios and the 
associated burden of developing and using Long-Term Scenarios in Long-
Term Regional Transmission Planning.\1015\
---------------------------------------------------------------------------

    \1010\ PJM Rehearing Request at 18-19.
    \1011\ To the extent that PJM was requesting that the Commission 
address in this order PJM's proposed long-term transmission planning 
process, we decline to address such a request here because doing so 
would be premature and more properly the subject of compliance.
    \1012\ Order No. 1920, 187 FERC ] 61,068 at P 298.
    \1013\ Id. P 417.
    \1014\ Id. P 421.
    \1015\ Id. P 559.
---------------------------------------------------------------------------

    364. In response to the requests for clarification and/or rehearing 
of various Order No. 1920 requirements related to Long-Term Scenarios 
and sensitivities submitted by PJM States, Virginia and North Carolina 
Commissions, Ohio Commission Federal Advocate, and West Virginia 
Commission, we clarify that Order No. 1920 allows transmission 
providers to conduct analyses in addition to those required by Order 
No. 1920--including additional scenarios or sensitivities \1016\--at 
the transmission providers' discretion or at the request of the 
transmission planning region's Relevant State Entities and/or other 
stakeholders.
---------------------------------------------------------------------------

    \1016\ The use of ``scenarios'' in this context indicates that 
these analyses are not required to meet Order No. 1920's 
requirements as to the development of Long-Term Scenarios and 
therefore are not ``Long-Term Scenarios'' within the meaning 
provided in Order No. 1920.
---------------------------------------------------------------------------

    365. Specifically, we clarify that transmission providers may 
develop additional scenarios, beyond the three Long-Term Scenarios that 
Order No. 1920 requires, to provide Relevant State Entities with 
information that they can use to inform the application of Long-Term 
Regional Cost Allocation Method(s) or the development of cost 
allocation methods through the State Agreement Process(es). We believe 
that additional analyses may help transmission providers and 
stakeholders to better understand the potential impact of Long-Term 
Regional Transmission Facilities on the transmission system, as well as 
the costs and benefits of Long-Term Regional Transmission Facilities. 
Particularly, consistent with the flexibility the Commission provided 
in Order No. 1920 as to cost allocation methods for Long-Term Regional 
Transmission Facilities (or portfolios of such Facilities), we find 
that additional analyses may help inform the application of ex ante 
Long-Term Regional Transmission Cost Allocation Methods or the 
development of cost allocation methods through the State Agreement 
Process.
    366. We further clarify that, when developing these additional 
analyses or scenarios used to inform cost allocation, transmission 
providers have the flexibility to depart from Order No. 1920's 
requirements related to the development of Long-Term Scenarios. For 
example, transmission providers may develop scenarios that consider the 
incremental cost and benefits of Long-Term Regional Transmission 
Facilities needed to achieve state laws, policies, and regulations 
beyond the cost and benefits of Long-Term Regional Transmission 
Facilities needed in the absence of those laws, policies, and 
regulations. Finally, as discussed below, we clarify that, if the 
Relevant State Entities wish for the transmission provider to develop a 
reasonable number of additional scenarios for Long-Term Regional 
Transmission Planning or Long-Term Regional Cost Allocation, then the 
transmission providers will develop these scenarios. While transmission 
providers may conduct such additional analyses, additional analyses 
that do not meet Order No. 1920's Long-Term Scenario requirements are 
not considered Long-Term Scenarios as defined in Order No. 1920.\1017\ 
In other words, transmission providers may not use any such additional 
analyses to identify Long-Term Transmission Needs, identify Long-Term 
Regional Transmission Facilities, or to meet the requirement that 
transmission providers estimate the costs and measure the benefits of 
Long-Term Regional Transmission Facilities for purposes of selection 
(i.e., to apply the transmission provider's selection criteria). 
Transmission providers also may not, consistent with the requirement 
that transmission providers have the opportunity to select more 
efficient or cost-effective Long-Term Regional Transmission Facilities 
to meet Long-Term Transmission Needs, condition the selection of a 
Long-Term Regional Transmission Facility on the information provided in 
these additional analyses.
---------------------------------------------------------------------------

    \1017\ Generally, to comply with Order No. 1920, including as 
clarified herein, transmission providers must develop at least three 
Long-Term Scenarios and perform at least one sensitivity analysis 
for each such Long-Term Scenario; identify Long-Term Transmission 
Needs using those Long-Term Scenarios and sensitivities thereto; 
identify Long-Term Regional Transmission Facilities (or portfolios 
of Long-Term Regional Transmission Facilities) that meet the 
identified Long-Term Transmission Needs; use and measure the seven 
required benefits of Long-Term Regional Transmission Facilities 
within those Long-Term Scenarios and sensitivities; otherwise 
evaluate those Long-Term Regional Transmission Facilities in the 
manner prescribed by Order No. 1920; and make a selection decision 
as to the Long-Term Regional Transmission Facilities identified and 
evaluated by transmission providers.
---------------------------------------------------------------------------

    367. Next, we clarify that, when requested by Relevant State 
Entities in a transmission planning region, transmission providers are 
required to conduct a reasonable number of additional analyses or 
scenarios. On

[[Page 97247]]

compliance, transmission providers may propose processes to determine 
when Relevant State Entities have requested additional analyses and how 
to determine what a reasonable number of additional analyses may 
be.\1018\ We reiterate that any cost allocation method--whether an ex 
ante Long-Term Regional Transmission Cost Allocation Method or a cost 
allocation method developed through the State Agreement Process for a 
specific Long-Term Regional Transmission Facility or portfolio 
thereof-- that results from such additional analyses or scenarios must 
satisfy the cost causation principle.\1019\
---------------------------------------------------------------------------

    \1018\ For example, in Order No. 890, the Commission required 
that stakeholders be given the right to request that transmission 
providers conduct a certain number of economic planning studies, to 
be determined on a regional basis, and the Commission offered the 
``merely illustrative'' example of five to ten such studies. Order 
No. 890, 118 FERC ] 61,119 at P 547 & n.323.
    \1019\ Order No. 1920, 187 FERC ] 61,068 at PP 1472, 1477.
---------------------------------------------------------------------------

    368. Finally, in response to the request for rehearing from PJM 
related to sensitivity analyses required by Order No. 1920 to account 
for uncertain operational outcomes that determine the benefits of and/
or need for transmission facilities during multiple concurrent and 
sustained generation and/or transmission outages due to an extreme 
weather event across a wide area, we disagree with the arguments on 
rehearing and decline to provide clarification. We continue to find 
that Order No. 1920's requirements in this regard are necessary to 
ensure just and reasonable Commission-jurisdictional rates. In 
particular, extreme weather events have occurred more frequently in 
recent years, represent periods during which regional transmission 
facilities have particularly high value, and create stressed system 
conditions that transmission providers can readily compare with non-
stressed scenarios to determine the value of specific transmission 
facilities under these types of conditions.\1020\ PJM did not provide 
adequate information to explain why additional flexibility in 
developing sensitivities for each Long-Term Scenario is necessary, and 
we are unconvinced that PJM's regional circumstances justify 
flexibility on this issue. To the extent that PJM's regional 
circumstances require other specific sensitivities, we reiterate that 
we encourage transmission providers to assess the need to develop other 
sensitivities as part of Long-Term Regional Transmission 
Planning.\1021\
---------------------------------------------------------------------------

    \1020\ Id. P 596. See also Transmission Sys. Plan. Performance 
Requirements for Extreme Weather, Order No. 896, 88 FR 41262 (June 
23, 2023), 183 FERC ] 61,191, at P 2 (2023) (explaining that extreme 
heat and cold weather events have occurred more frequently in recent 
years); One-Time Informational Reps. on Extreme Weather 
Vulnerability Assessments Climate Change, Extreme Weather, & Elec. 
Sys. Reliability, Order No. 897, 88 FR 41477 (June 27, 2023), 183 
FERC ] 61,192, at P 2 (2023) (same).
    \1021\ Order No. 1920, 187 FERC ] 61,068 at P 597.
---------------------------------------------------------------------------

C. Evaluation of the Benefits of Regional Transmission Facilities

1. Requirement for Transmission Providers To Use and Measure a Set of 
Seven Required Benefits
a. Order No. 1920 Requirements
    369. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to measure a set of 
seven required benefits (required benefits) for Long-Term Regional 
Transmission Facilities under each Long-Term Scenario and to use these 
measured benefits to evaluate Long-Term Regional Transmission 
Facilities.\1022\ The Commission required transmission providers to 
measure and use the following required benefits in Long-Term Regional 
Transmission Planning: (1) avoided or deferred reliability transmission 
facilities and aging infrastructure replacement; (2) a benefit that can 
be characterized and measured as either reduced loss of load 
probability or reduced planning reserve margin; (3) production cost 
savings; (4) reduced transmission energy losses; (5) reduced congestion 
due to transmission outages; (6) mitigation of extreme weather events 
and unexpected system conditions; and (7) capacity cost benefits from 
reduced peak energy losses.\1023\
---------------------------------------------------------------------------

    \1022\ Order No. 1920, 187 FERC ] 61,068 at P 719.
    \1023\ Id. P 720.
---------------------------------------------------------------------------

    370. The Commission found that the record demonstrated that, in 
order to ensure just and reasonable Commission-jurisdictional 
transmission rates, it was necessary to require transmission providers 
to measure and use in Long-Term Regional Transmission Planning a set of 
particular benefits so that they may identify, evaluate, and select 
regional transmission facilities that are more efficient or cost-
effective transmission solutions to Long-Term Transmission Needs. 
Further, the Commission found that the benefits that Long-Term Regional 
Transmission Facilities generally provide extend beyond the benefits 
that transmission providers currently consider as part of their 
regional transmission planning and cost allocation processes, and 
without consideration of such benefits, Long-Term Regional Transmission 
Planning could not be reasonably expected to identify, evaluate, and 
select more efficient or cost-effective regional transmission solutions 
to address Long-Term Transmission Needs.\1024\ The Commission concluded 
that requiring the measurement and use of the seven required benefits 
in Long-Term Regional Transmission Planning ensured that transmission 
providers will consider a sufficiently broad range of benefits when 
determining whether to select a Long-Term Regional Transmission 
Facility as a more efficient or cost-effective regional transmission 
solution to Long-Term Transmission Needs. In contrast, the Commission 
found that not requiring transmission providers to use any specific 
benefits in Long-Term Regional Transmission Planning, as proposed in 
the NOPR, would fail to ensure that transmission providers consider the 
broader set of benefits provided by, and the beneficiaries receiving 
the benefits of, Long-Term Regional Transmission Facilities, and, thus, 
may fail to identify the potentially more efficient or cost-effective 
regional transmission solution(s) to specific Long-Term Transmission 
Needs.\1025\
---------------------------------------------------------------------------

    \1024\ Id. P 722.
    \1025\ Id. P 723.
---------------------------------------------------------------------------

    371. The requirement that transmission providers measure and use 
the required benefits in Long-Term Regional Transmission Planning was a 
change from the NOPR proposal.\1026\ In the NOPR, the Commission did 
not propose to require the use of any specific benefits and instead 
acknowledged the benefits of regional flexibility, and consistent with 
Order No. 1000, proposed to consider such matters on review of 
compliance proposals.\1027\ The NOPR included a non-exhaustive list of 
12 benefits \1028\ that the Commission stated could be considered by 
transmission providers in Long-Term Regional Transmission Planning and 
cost allocation processes.\1029\ The Commission also sought comment on 
``whether public utility transmission providers should be required to 
use some or all of the Long-Term Regional Transmission Benefits as a 
minimum set of benefits for their Long-Term Regional Transmission 
Planning process.'' \1030\
---------------------------------------------------------------------------

    \1026\ Id.
    \1027\ NOPR, 179 FERC ] 61,028 at P 183 (citation omitted).
    \1028\ Id. P 185.
    \1029\ Id. P 184.
    \1030\ Id. P 188.

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[[Page 97248]]

b. Logical Outgrowth
i. Requests for Rehearing and Clarification
    372. East Kentucky and NRECA argue that Order No. 1920 violates the 
APA's notice-and-comment requirements because it mandates that 
transmission providers use a set of seven benefits for evaluating Long-
Term Regional Transmission Facilities, a requirement that East Kentucky 
and NRECA argue is not a logical outgrowth of the NOPR, which proposed 
non-mandatory and non-exhaustive examples of benefits that transmission 
providers could use.\1031\ NRECA asserts that the NOPR made clear that 
the list of potential benefits was neither mandatory nor exhaustive and 
that transmission providers would have flexibility to determine what 
benefits they use in their Long-Term Regional Transmission 
Planning.\1032\ NRECA describes the final rule's seven required 
benefits as ``nationwide, mandatory, [and] one-size-fits all'' and the 
``exact opposite'' of the proposed rule.\1033\
---------------------------------------------------------------------------

    \1031\ East Kentucky Rehearing Request at 1-2 (citing 5 U.S.C. 
553(b)); NRECA Rehearing Request at 4, 10-13 (citing 5 U.S.C. 
553(b)).
    \1032\ NRECA Rehearing Request at 10 (quoting NOPR, 179 FERC ] 
61,028 at P 183).
    \1033\ Id. at 11.
---------------------------------------------------------------------------

ii. Commission Determination
    373. We disagree with the argument that the Commission failed to 
provide adequate notice and opportunity to comment on Order No. 1920's 
requirement that transmission providers measure a set of seven required 
benefits for Long-Term Regional Transmission Facilities under each 
Long-Term Scenario as part of Long-Term Regional Transmission Planning 
and use these measured benefits to evaluate Long-Term Regional 
Transmission Facilities.\1034\ As courts have explained, ``[n]otice 
suffices when [an agency] has `expressly asked for comments on a 
particular issue or otherwise made clear that the agency was 
contemplating a particular change.' '' \1035\ NRECA acknowledges that 
the NOPR sought comment on whether transmission providers should be 
required to use some or all of the potential benefits described in the 
NOPR as a minimum set of benefits for their Long-Term Regional 
Transmission Planning process.\1036\ By requesting comment on whether 
to make mandatory some or all of the benefits in the NOPR, the 
Commission sufficiently put parties on notice that the Commission was 
considering the exact change that East Kentucky and NRECA now argue was 
unanticipated and violated the APA's notice-and-comment requirements. 
Thus, in adopting the requirement that transmission providers measure 
and use the set of seven required benefits in Long-Term Regional 
Transmission Planning, the Commission adhered to the APA's notice-and-
comment requirements.
---------------------------------------------------------------------------

    \1034\ See Order No. 1920, 187 FERC ] 61,068 at P 719.
    \1035\ Brennan v. Dickson, 45 F.4th 48, 69 (D.C. Cir. 2022) 
(quoting CSX Transp., Inc. v. Surface Transp. Bd., 584 F.3d 1076, 
1081 (D.C. Cir. 2009)).
    \1036\ See NRECA Rehearing Request at 10 (citing NOPR, 179 FERC 
] 61,028 at P 188).
---------------------------------------------------------------------------

c. Flexibility Regarding Benefits Rather Than a Minimum Set
i. Requests for Rehearing and Clarification
    374. Dominion requests rehearing and argues that the seven required 
benefits are not directly tied or correlated to the seven categories of 
factors establishing Long-Term Transmission Needs.\1037\ Dominion 
contends that the seven required benefits ``are generic, almost 
inherent benefits of all transmission,'' whereas the seven categories 
of factors that transmission providers must incorporate in the 
development of Long-Term Scenarios ``are mostly restatements of public 
policy driven needs for transmission facilities.'' \1038\ Dominion 
states that it ``is not suggesting that Factor Category No. 1 must 
match Benefit No. 1, etc.; rather, individually, and as a whole, the[] 
seven Factor Categories do not correlate to any or all of the seven 
Benefits.'' \1039\ Dominion opines that, because the seven required 
benefits do not correspond to the seven categories of factors, 
regardless of the public policy issues driving the need for a 
transmission facility, Order No. 1920's requirement that transmission 
providers use the seven required benefits in determining whether to 
select a transmission facility will likely result in a public policy 
project always being selected.\1040\ Further, Dominion opines that, 
because the seven required benefits do not correspond to the seven 
categories of factors, the seven required benefits are ``secondary or 
incidental'' to the primary purpose of the Long-Term Regional 
Transmission Facilities. Dominion states that the United States Court 
of Appeals for the Seventh Circuit ``rejected the use of `incidental' 
benefits because `the incidental-benefits tail mustn't be allowed to 
wag the primary-benefits dog.' '' \1041\ Dominion contends that Order 
No. 1920 should have required that Long-Term Transmission Needs and the 
benefits of Long-Term Regional Transmission Facilities correspond to 
each other, and failure to impose such a requirement was not reasoned 
decision making.\1042\ Dominion states that the Commission should 
provide flexibility to transmission providers to allow them to identify 
the benefits that they will measure in their compliance filings and 
ensure that those benefits are tied to the underlying needs.\1043\
---------------------------------------------------------------------------

    \1037\ Dominion Rehearing Request at 18.
    \1038\ Id. at 20.
    \1039\ Id. at 19 n.83.
    \1040\ Id. at 20.
    \1041\ Id. (alteration omitted) (quoting ICC v. FERC III, 756 
F.3d at 564).
    \1042\ Id.
    \1043\ Id. at 18-19, 21.
---------------------------------------------------------------------------

    375. PJM requests rehearing and argues that Order No. 1920 is 
arbitrary and capricious because the requirement that transmission 
providers measure and use seven required benefits to evaluate Long-Term 
Regional Transmission Facilities is an unexplained departure from the 
NOPR's recognition of the value of allowing regional flexibility with 
respect to benefits.\1044\ PJM argues that the Commission should 
provide flexibility to transmission providers to allow them to identify 
the benefits that they will measure in their compliance filings (except 
for Final Rule Benefits 1, 2, and 3, which PJM agrees should be 
required).\1045\ PJM asserts that Final Rule Benefits 4 and 5 are 
additional benefits that RTOs could add as they gain experience and 
determine to be quantitatively important. PJM also argues that Final 
Rule Benefit 6 has three different subcomponents and could be very 
cumbersome to measure if each one of them must be quantified.\1046\
---------------------------------------------------------------------------

    \1044\ PJM Rehearing Request at 5, 26-27 & n.106.
    \1045\ Id. at 26-29, 42.
    \1046\ Id. at 29.
---------------------------------------------------------------------------

    376. Designated Retail Regulators and Undersigned States request 
rehearing and assert that the benefit metrics used to evaluate Long-
Term Regional Transmission Facilities should be developed as part of 
RTO stakeholder processes, not mandated by the Commission.\1047\ NRECA 
alleges that by prescribing the required benefits that transmission 
providers must use for evaluation and selection of Long-Term Regional 
Transmission Facilities, the final rule will likely change the results 
of the evaluation and selection processes in unanticipated ways.\1048\
---------------------------------------------------------------------------

    \1047\ Designated Retail Regulators Rehearing Request at 29; 
Undersigned States Rehearing Request at 29.
    \1048\ NRECA Rehearing Request at 11-12.

---------------------------------------------------------------------------

[[Page 97249]]

ii. Commission Determination
    377. We are not persuaded by arguments raised on rehearing that the 
Commission should not require transmission providers to use and measure 
the seven required benefits. We continue to find that allowing 
transmission providers to determine which benefits they will use and 
measure, rather than requiring the measurement and use of a minimum set 
of benefits, may result in transmission providers not measuring 
important potential benefits of Long-Term Regional Transmission 
Facilities.\1049\ This, in turn, would not resolve the deficiencies 
that the Commission identified in the final rule, such as transmission 
providers failing to adequately consider the benefits of regional 
transmission facilities and thereby not selecting the more efficient or 
cost-effective solutions, leading to unjust and unreasonable 
Commission-jurisdictional rates.\1050\ Additionally, as the Commission 
noted in Order No. 1920, requiring transmission providers to measure 
and use a required set of benefits will help improve interregional 
transmission coordination among different transmission planning 
regions.\1051\
---------------------------------------------------------------------------

    \1049\ Order No. 1920, 187 FERC ] 61,068 at PP 723-724.
    \1050\ See id. P 123 (``Failing to adequately identify and 
consider the benefits of [Long-Term Regional Transmission 
Facilities] may lead to relatively inefficient or less cost-
effective transmission development. In particular, the cost-benefit 
analyses that transmission providers often use as part of the 
evaluation process may fail to identify more efficient or cost-
effective regional transmission facilities for selection because 
they provide an inaccurate portrayal of the comparative benefits of 
different transmission facilities. Thus, the failure to adequately 
consider the benefits of regional transmission facilities results 
in, among other things, transmission customers forgoing benefits 
that may significantly outweigh their costs, which results in less 
efficient or cost-effective transmission investments and, in turn, 
contributes to Commission-jurisdictional rates that are unjust and 
unreasonable.''); id. P 723.
    \1051\ Id. P 729 (citations omitted).
---------------------------------------------------------------------------

    378. We disagree with Dominion's argument that Order No. 1920 does 
not constitute reasoned decision making or is arbitrary and capricious 
because the seven required benefits are not tied or correlated to the 
seven categories of factors that Order No. 1920 requires transmission 
providers to incorporate into the development of Long-Term Scenarios. 
We understand Dominion's argument to be that, even though Long-Term 
Regional Transmission Facilities address Long-Term Transmission Needs 
that are driven primarily by the incorporation of certain categories of 
factors that Dominion considers to be ``public policy issues,'' the 
required benefits, which Dominion contends are designed to measure a 
broader range of benefits of transmission facilities unrelated to 
public policy-related factors, will likely result in a public policy 
project always being selected. We disagree with this argument. We first 
note that Dominion provides only speculation that such a result will 
occur. As the Commission found in Order No. 1920, while state policies 
make up some of the drivers of Long-Term Transmission Needs, they do 
not comprise the entirety of those drivers.\1052\ Accordingly, Long-
Term Transmission Needs will be driven by factors (e.g., resource 
retirements and trends in fuel costs) in addition to and unrelated to 
``public policy issues,'' and Long-Term Transmission Facilities will 
likely be designed to address multiple Long-Term Transmission Needs. In 
any case, Order No. 1920 does not require that transmission providers 
select any particular Long-Term Regional Transmission Facility, even 
where it meets the transmission provider's selection criteria,\1053\ 
which this order maintains on rehearing.\1054\
---------------------------------------------------------------------------

    \1052\ Id. P 1478. The Commission recognized that state policy 
goals do not necessarily need to be given the same weight as state 
laws and regulations when determining the assumptions that will be 
used in the development of Long-Term Scenarios because government 
entities have an interest and ability to ensure that the 
requirements of state laws and regulations are fully achieved. Id. 
PP 512, 516.
    \1053\ Id. P 1026 (citations omitted).
    \1054\ See infra No Selection Requirement section.
---------------------------------------------------------------------------

    379. We disagree with Dominion's assertion that the seven required 
benefits are ``secondary or incidental'' to Long-Term Transmission 
Needs. As the Commission explained in Order No. 1920, the drivers of 
transmission needs are diverse and include, but are not limited to, 
grid reliability, changes in the resource mix, and increased demand for 
electricity.\1055\ As discussed in the Requirement for Transmission 
Providers To Use the Seven Required Benefits To Help To Inform Their 
Identification of Long-Term Transmission Needs section above, we 
clarify in this order that Long-Term Transmission Needs as defined in 
Order No. 1920 are driven by both reliability and economic 
considerations and, as such, both reliability and economic 
considerations must inform transmission providers' identification of 
Long-Term Transmission Needs. The seven required benefits measure 
distinct, well-understood benefits of potential Long-Term Regional 
Transmission Facilities and are well supported in the record.\1056\ 
Because the seven required benefits reflect many of the reliability and 
economic benefits that Long-Term Regional Transmission Facilities can 
provide, we disagree with Dominion that such benefits are secondary or 
incidental to Long-Term Transmission Needs. Further, the Commission 
noted in Order No. 1920 that, ``[w]e find that the benefits that Long-
Term Regional Transmission Facilities generally provide extend beyond 
the benefits that transmission providers currently consider as part of 
their regional transmission planning and cost allocation processes, and 
without consideration of such benefits, Long-Term Regional Transmission 
Planning cannot be reasonably expected to identify, evaluate, and 
select more efficient or cost-effective regional transmission solutions 
to address Long-Term Transmission Needs.'' \1057\ The Commission also 
stated that ``[b]y requiring the measurement and use of the seven 
enumerated benefits in Long-Term Regional Transmission Planning, we 
ensure that transmission providers will consider a sufficiently broad 
range of benefits when determining whether to select a Long-Term 
Regional Transmission Facility as a more efficient or cost-effective 
regional transmission solution to Long-Term Transmission Needs.'' 
\1058\
---------------------------------------------------------------------------

    \1055\ Order No. 1920, 187 FERC ] 61,068 at P 299. See also id. 
PP 39, 299 (defining Long-Term Transmission Needs as ``transmission 
needs identified through Long-Term Regional Transmission Planning 
by, among other things . . . running scenarios and considering the 
enumerated categories of factors'').
    \1056\ Id. P 724 (noting that the seven required benefits ``have 
a proven track record''); id. P 746 (Final Rule Benefit 1), PP 749-
750 (Final Rule Benefit 2), P 761 (Final Rule Benefit 3), P 782 
(Final Rule Benefit 4), P 784 (Final Rule Benefit 5), P 791 (Final 
Rule Benefit 6), P 812 (Final Rule Benefit 7); see also id. P 731 
(``[A]ll seven required benefits have either been approved for use 
in regional transmission planning in at least one non-RTO/ISO 
transmission planning region or may be implemented by building upon 
the modeling or techniques used to measure benefits in RTO/ISO or 
non-RTO/ISO regions, or both.''); id. P 732 (explaining that the 
Commission has accepted the use of several of the seven benefits to 
evaluate transmission facilities and projects).
    \1057\ Id. P 722.
    \1058\ Id. P 723.
---------------------------------------------------------------------------

    380. Finally, the Commission found in Order No. 1920, and we 
continue to find here, that transmission providers must measure, at a 
minimum, this set of seven required benefits and then use them to 
evaluate Long-Term Regional Transmission Facilities in order to ensure 
just and reasonable rates.\1059\ The Commission noted:
---------------------------------------------------------------------------

    \1059\ Id. P 721.

    The record in this proceeding shows that, in order to ensure 
just and reasonable Commission-jurisdictional transmission rates, it 
is necessary to require transmission providers to measure and use in 
Long-Term Regional Transmission Planning a set of particular 
benefits so that they may identify,

[[Page 97250]]

evaluate, and select regional transmission facilities that are more 
efficient or cost-effective transmission solutions to Long-Term 
Transmission Needs. We find that the benefits that Long-Term 
Regional Transmission Facilities generally provide extend beyond the 
benefits that transmission providers currently consider as part of 
their regional transmission planning and cost allocation processes, 
and without consideration of such benefits, Long-Term Regional 
Transmission Planning cannot be reasonably expected to identify, 
evaluate, and select more efficient or cost-effective regional 
transmission solutions to address Long-Term Transmission 
Needs.\1060\
---------------------------------------------------------------------------

    \1060\ Id. P 722.

    381. Indeed, as Dominion concedes, the seven benefits that Order 
No. 1920 requires transmission providers to use and measure when 
evaluating Long-Term Regional Transmission Facilities are ``inherent 
benefits of all transmission.'' \1061\
---------------------------------------------------------------------------

    \1061\ Dominion Rehearing Request at 20.
---------------------------------------------------------------------------

    382. In addition, we disagree with PJM's assertion that Order No. 
1920 is arbitrary and capricious because the requirement that 
transmission providers measure and use seven required benefits to 
evaluate Long-Term Regional Transmission Facilities is an unexplained 
departure from the NOPR's recognition of the value of allowing regional 
flexibility with respect to benefits. We continue to find that the 
requirement for transmission providers to measure and use the minimum 
set of seven required benefits in Long-Term Regional Transmission 
Planning is necessary to ensure that Commission-jurisdictional rates 
are just and reasonable.\1062\ Specifically, absent a requirement that 
transmission providers measure and use a sufficiently broad range of 
the benefits of Long-Term Regional Transmission Facilities when 
evaluating them for potential selection, transmission providers may not 
identify, evaluate, and select more efficient or cost-effective 
regional transmission solutions to Long-Term Transmission Needs, which 
may lead to relatively inefficient or less cost-effective transmission 
development. Therefore, we find that allowing the regional flexibility 
that PJM suggests would fail to remedy the deficiencies in existing 
regional transmission planning and cost allocation processes--namely, 
the failure to require transmission providers to adequately consider 
the broader set of benefits of regional transmission facilities planned 
to meet Long-Term Transmission Needs \1063\--that the Commission 
identified in the final rule.\1064\ We also note that PJM itself 
previously recognized that certain benefits should be required; in its 
comments on the NOPR, PJM called for the adoption of a nationwide 
consideration of benefits that are similar to certain benefits that the 
Commission adopted in Order No. 1920 as part of the set of seven 
required benefits that transmission providers must measure and use in 
Long-Term Regional Transmission Planning.\1065\
---------------------------------------------------------------------------

    \1062\ Order No. 1920, 187 FERC ] 61,068 at P 727.
    \1063\ Id. P 122.
    \1064\ Contrary to PJM's assertion, in Order No. 1920 the 
Commission explained its reasons for not adopting the more flexible 
approach proposed in the NOPR. The Commission found:
    [A]dopting the more flexible approach proposed in the NOPR would 
not address the identified deficiencies in existing regional 
transmission planning and cost allocation processes because such an 
approach would fail to ensure that transmission providers consider 
the broader set of benefits provided by, and the beneficiaries 
receiving the benefits of, Long-Term Regional Transmission 
Facilities, and thus, may fail to identify the potentially more 
efficient or cost-effective regional transmission solution. We find 
that failing to use the set of benefits that we require in this 
final rule to evaluate Long-Term Regional Transmission Facilities 
for potential selection could render resulting Commission-
jurisdictional rates unjust and unreasonable. We find that not 
requiring transmission providers to use certain benefits to evaluate 
Long-Term Regional Transmission Facilities would be expected to lead 
to relatively inefficient and less cost-effective transmission 
development, as Long-Term Regional Transmission Facilities that 
provide significant net benefits may not be selected.
    Id. P 723; see also id. P 728 (``We conclude that it would be 
inappropriate to provide flexibility not to consider this required 
set of benefits in Long-Term Regional Transmission Planning because 
. . . requiring the measurement and use of these benefits ensures 
that transmission providers are able to identify, evaluate, and 
select regional transmission solutions to more efficiently or cost-
effectively address Long-Term Transmission Needs, and thereby 
ensures just and reasonable rates.'').
    \1065\ PJM NOPR Initial Comments at 96 (``[T]he following 
benefit categories should be considered on a nationwide basis: (i) 
Enhanced Reliability; (ii) Avoided or Deferred Reliability 
Transmission Projects and Aging Infrastructure Replacement; (iii) 
Deferred Capacity Investment; and (iv) Production Cost Savings.'').
---------------------------------------------------------------------------

    383. In response to Designated Retail Regulators' and Undersigned 
States' requests for flexibility to establish the benefits for 
transmission providers to measure through RTO/ISO stakeholder 
processes, we reiterate that the measurement and use of certain 
benefits in Long-Term Regional Transmission Planning is essential to 
ensuring just and reasonable Commission-jurisdictional rates.\1066\ As 
such, we find that it is necessary for the Commission to mandate the 
measurement and use of these benefits--the required benefits--in Long-
Term Regional Transmission Planning rather than deferring to RTO/ISO 
stakeholder processes.\1067\
---------------------------------------------------------------------------

    \1066\ See Order No. 1920, 187 FERC ] 61,068 at PP 722-723, 725, 
727-728.
    \1067\ Id. PP 723, 728.
---------------------------------------------------------------------------

    384. We also are not persuaded by NRECA's assertion that, by 
prescribing the required benefits that transmission providers must use 
for evaluation and selection of Long-Term Regional Transmission 
Facilities, the final rule will likely change the results of the 
evaluation and selection processes in unanticipated ways. NRECA does 
not explain what unanticipated consequences it foresees arising, and we 
find this assertion speculative and unsupported.
d. Overlap and Double-Counting
i. Order No. 1920 Requirements
    385. In Order No. 1920, the Commission noted that, ``rather than 
requiring transmission providers to measure and use all 12 benefits 
enumerated in the NOPR, we only require transmission providers to 
measure and use seven specific benefits that have a proven track 
record, can be discretely measured, and are unlikely to cause 
duplication.'' \1068\ In response to concerns raised by commenters 
regarding the potential for overlap and double-counting, the Commission 
further noted:
---------------------------------------------------------------------------

    \1068\ Id. P 724.

    We believe that the seven benefits that we include in the 
required set of benefits that transmission providers must measure 
and use in Long-Term Regional Transmission Planning are distinct 
enough that they will not overlap in a way that results in double-
counting. Nonetheless, to the extent that transmission providers are 
concerned that any possibility of double-counting remains, we 
provide transmission providers with flexibility on the measurement 
of such benefits and expect that transmission providers can use such 
flexibility to develop methods for measuring each required benefit 
that address those concerns.\1069\
---------------------------------------------------------------------------

    \1069\ Id. P 735.

    386. With respect to Final Rule Benefit 3, Production Cost Savings, 
the Commission in Order No. 1920 explained why it did not believe that 
this benefit would result in double-counting of benefits merely because 
such benefits may also be considered in state resource planning.\1070\ 
Specifically, the Commission found that while integrated resource 
planning processes, where they exist, may consider similar benefits 
compared to those required by Order No. 1920, the consideration of 
benefits in a state-jurisdictional process does not result in the 
double-counting of benefits within any Commission-jurisdictional 
transmission planning process.\1071\
---------------------------------------------------------------------------

    \1070\ Id. P 770.
    \1071\ Id.
---------------------------------------------------------------------------

    387. The Commission in Order No. 1920 also offered guidance 
regarding the

[[Page 97251]]

manner of measurement of certain aspects of Final Rule Benefit 6, 
mitigation of extreme weather events and unexpected system conditions, 
to avoid double-counting. The Commission noted, for example, that ``to 
avoid double-counting of similar circumstances, transmission providers 
must account for extreme weather events and unexpected system 
conditions that are separate and distinct such that the benefits of 
mitigating each system condition can be combined into a single benefit 
measure.'' \1072\
---------------------------------------------------------------------------

    \1072\ Id. P 804.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    388. Designated Retail Regulators and Undersigned States request 
rehearing and assert that Order No. 1920's requirements to use seven 
required factors and seven required benefits will result in unjust and 
unreasonable rates. They argue that the seven required factors and 
seven required benefits overlap and will double-count or exaggerate the 
potential benefits of Long-Term Regional Transmission Facilities, with 
Undersigned States adding that this renders the rule arbitrary and 
capricious.\1073\
---------------------------------------------------------------------------

    \1073\ Designated Retail Regulators Rehearing Request at 8 
(citation omitted); Undersigned States Rehearing Request at 8 
(citation omitted).
---------------------------------------------------------------------------

    389. Designated Retail Regulators and Undersigned States assert 
that with respect to the seven required benefits, it is unclear whether 
these metrics will result in double-counting of potential 
benefits.\1074\
---------------------------------------------------------------------------

    \1074\ Designated Retail Regulators Rehearing Request at 29; 
Undersigned States Rehearing Request at 29.
---------------------------------------------------------------------------

iii. Commission Determination
    390. We disagree with Designated Retail Regulators and Undersigned 
States that the seven required benefits will overlap and will double-
count or exaggerate the potential benefits of Long-Term Regional 
Transmission Facilities. As an initial matter, the Commission found in 
Order No. 1920, and we continue to find here, that ``the seven benefits 
that we include in the required set of benefits that transmission 
providers must measure and use in Long-Term Regional Transmission 
Planning are distinct enough that they will not overlap in a way that 
results in double-counting.'' \1075\ Designated Retail Regulators and 
Undersigned States fail to provide evidence in support of their 
arguments to the contrary, and they do not provide any specific 
examples of the alleged overlap. Given the descriptions of the required 
benefits adopted in Order No. 1920,\1076\ we conclude that each of 
these required benefits captures a different type of benefit that Long-
Term Regional Transmission Facilities may provide. However, we 
reiterate, as the Commission stated in the final rule, that Order No. 
1920 provides transmission providers with flexibility on the 
measurement of the required benefits, and we expect that transmission 
providers can use such flexibility to develop methods for measuring 
each required benefit that address any concerns about the possibility 
of double-counting benefits.\1077\
---------------------------------------------------------------------------

    \1075\ Order No. 1920, 187 FERC ] 61,068 at P 735. As noted 
above, the Commission also addressed arguments relating to double-
counting and/or overlap between Final Rule Benefit 3 and integrated 
resource planning processes and provided guidance regarding the 
manner of measurement of certain aspects of Final Rule Benefit 6, 
mitigation of extreme weather events and unexpected system 
conditions, to avoid double-counting.
    \1076\ Id. PP 745, 756, 758, 767, 781, 788, 800, 817.
    \1077\ Id. P 735.
---------------------------------------------------------------------------

    391. Moreover, the Commission explained in Order No. 1920 that 
transmission providers' evaluation of Long-Term Regional Transmission 
Facilities must culminate in a determination that is sufficiently 
detailed for stakeholders to understand why a particular Long-Term 
Regional Transmission Facility (or portfolio of Long-Term Regional 
Transmission Facilities) was selected or not selected.\1078\ The 
Commission also explained that this determination must include the 
estimated costs and measured benefits of each alternative Long-Term 
Regional Transmission Facility (or portfolio of Long-Term Regional 
Transmission Facilities) that transmission providers evaluated in the 
Long-Term Regional Transmission Planning process, regardless of whether 
or not the Long-Term Regional Transmission Facility (or portfolio of 
such Facilities) is selected.\1079\ We find that these requirements 
will further safeguard against potential overlap and double-counting of 
benefits.
---------------------------------------------------------------------------

    \1078\ Id. P 954.
    \1079\ Id. PP 954, 966.
---------------------------------------------------------------------------

    392. With respect to Undersigned States' and Designated Retail 
Regulators' concerns regarding the relationship between benefits and 
factors, we address this issue in the Requirement for Transmission 
Providers to Use the Seven Required Benefits to Help to Inform Their 
Identification of Long-Term Transmission Needs section above. As noted 
there, we are setting aside Order No. 1920's requirement for 
transmission providers to use the set of seven required benefits to 
help to inform their identification of Long-Term Transmission Needs. As 
such, we find that there is no overlap between the categories of 
factors that transmission providers must incorporate into the 
development of Long-Term Scenarios, which are developed prior to the 
identification of Long-Term Transmission Needs and Long-Term Regional 
Transmission Facilities to address those needs, and the required 
benefits, which are subsequently used to evaluate the identified Long-
Term Regional Transmission Facilities.
    393. With respect to Designated Retail Regulators' and Undersigned 
States' concerns about potential overlaps between the seven required 
benefits and other benefits that transmission providers may use and 
measure, we find that Order No. 1920 provides for sufficient 
transparency to prevent any such overlap. Specifically, Order No. 1920 
requires transmission providers to describe how they will measure the 
seven required benefits in OATT filings.\1080\ Additionally, it 
requires transmission providers to measure and use any additional 
benefits beyond those included in the required set of benefits, 
including on a transmission facility or plan-specific basis, in a 
manner that is consistent with their obligations under Order No. 890 
and Order No. 1000 transmission planning principles to be open and 
transparent as to their transmission planning processes.\1081\ As such, 
stakeholders will have the information necessary to identify any 
potential double-counting of the required benefits and any other 
benefits that transmission providers choose to measure and use in Long-
Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \1080\ Id. P 837.
    \1081\ Id. P 822.
---------------------------------------------------------------------------

e. Conflicts With State Authority
i. Requests for Rehearing and Clarification
    394. Designated Retail Regulators assert that the seven required 
benefits conflict with the state authority reflected in both the 
transmission planning principles adopted by OMS that project metrics 
should be quantifiable, subject to accurate measurement, verifiable, 
non-duplicative, and forward looking and the Entergy Regional State 
Committee's adoption of ``even more stringent requirements to ensure 
that any metrics adopted reflected actual, not hypothetical, value that 
would justify major transmission investment.'' \1082\

[[Page 97252]]

For instance, Designated Retail Regulators state that the Entergy 
Regional State Committee (E-RSC) adopted stringent requirements to 
ensure that any metrics adopted reflected actual, not hypothetical, 
value that would justify major transmission investment:
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    \1082\ Designated Retail Regulators Rehearing Request at 31-33 
(citing Organization of MISO States, Inc., Organization of MISO 
States Statement of Principles: Cost Allocation for Long Range 
Transmission Planning Projects, https://www.misostates.org/images/PositionStatements/OMS_Position_Statement_of_Principles_Cost_Allocation_for_LRTPs.pdf).

    The cost-benefit and other analyses that are used to inform the 
business case and cost allocation for Tranche 3 shall be based only 
on accurate, objective, measurable, quantifiable, non-duplicative, 
forward-looking, and replicable metrics that are supported by data;
    Tranche 3 costs shall be allocated using an exclusive list of 
benefit metrics identified by the E-RSC, with advice from MISO and 
MISO South Stakeholders, that meet the criteria identified in 
Paragraph 3 above. These metrics shall be memorialized after being 
approved by the E-RSC;
    Each Tranche 3 project must individually satisfy the cost-
benefit analysis used for the business case and cost allocation on a 
stand-alone basis. Where two or more transmission facility upgrades 
combine to address a specific transmission issue, they may be 
evaluated as a single project for the purpose of analysis and cost 
allocation.\1083\
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    \1083\ Designated Retail Regulators Rehearing Request at 32-33 
(quoting Entergy Regional State Committee, Resolution of the Entergy 
Regional State Committee, 3 (adopted June 30, 2023), https://cdn.misoenergy.org/20230630%20-%20ERSC%20Resolution%20re%20MISO%20South%20Cost%20Allocation%20for%20Tranche%203629421.pdf).

    395. NESCOE requests that the Commission grant rehearing to require 
transmission providers to defer to states in the identification of 
benefits that Long-Term Regional Transmission Facilities may provide 
when the driver of the Long-Term Transmission Need is related to 
satisfying state laws, regulations, or policies.\1084\
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    \1084\ NESCOE Rehearing Request at 11 (citation omitted).
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ii. Commission Determination
    396. We are not persuaded by requests for rehearing that argue that 
the Commission's establishment of a set of required benefits in Order 
No. 1920 impermissibly or improperly intrudes upon state authority. We 
continue to find that, while the Long-Term Regional Transmission 
Planning required in Order No. 1920 may be more comprehensive than the 
status quo, as a matter of the Commission's jurisdiction, it is 
fundamentally no different than the regional transmission planning 
already required by the Commission and upheld by the appellate 
courts.\1085\ Using the required benefits to evaluate Long-Term 
Regional Transmission Facilities is an incremental improvement to the 
Commission's Order No. 890 and Order No. 1000 reforms requiring 
processes for evaluating the merits of proposed transmission solutions 
offered by potential developers.\1086\ The D.C. Circuit upheld the 
Commission's Order No. 1000 regional transmission planning reforms 
against challenges rooted in similar misunderstandings of the 
Commission's jurisdiction as those advanced by the rehearing 
parties.\1087\
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    \1085\ Order No. 1920, 187 FERC ] 61,068 at P 277 (citing S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 68-69).
    \1086\ See Order No. 1000, 136 FERC ] 61,051 at P 315 (citing 
Order No. 890, 118 FERC ] 61,119 at P 494; Order No. 890-A, 121 FERC 
] 61,297 at PP 215-216).
    \1087\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 63 
(``Taken together, these points support the Commission's assertion 
of authority over transmission planning matters in the challenged 
orders, notwithstanding petitioners' contention that the orders 
intrude on the States' authority.'').
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    397. Further, we reiterate the Commission's finding in Order No. 
1920 that some benefits are so essential to Long-Term Regional 
Transmission Planning that they must be required and not left to the 
discretion of stakeholders, whether RTOs/ISOs or state 
committees.\1088\ Order No. 1920, for example, found that requiring the 
measurement and use of Final Rule Benefit 1, Avoided or Deferred 
Reliability Transmission Facilities and Aging Transmission 
Infrastructure Replacement, as described, is necessary because Long-
Term Regional Transmission Facilities may obviate or delay the need for 
reliability transmission facilities identified in the near term, or the 
need for later replacements of aging transmission infrastructure.\1089\ 
Moreover, as discussed in the Flexibility Regarding Benefits Rather 
than a Minimum Set section above, the Commission found in Order No. 
1920 that the requirement for transmission providers to measure and use 
the seven required benefits in Long-Term Regional Transmission Planning 
is necessary to ensure that Commission-jurisdictional rates are just 
and reasonable.\1090\ We sustain this finding and, as a result, 
continue to find that the measurement and use of these minimum set of 
required benefits in Long-Term Regional Transmission Planning cannot be 
left to the discretion of transmission providers or stakeholders.
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    \1088\ See Order No. 1920, 187 FERC ] 61,068 at PP 722-723, 725, 
728.
    \1089\ Id. P 745.
    \1090\ Id. P 727.
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    398. We also question the degree of intrusion cited by certain 
rehearing parties. We note, for example, that many of the OMS and 
Entergy Regional State Committee transmission planning principles cited 
by Designated Retail Regulators are similar to provisions governing the 
measurement and use of the required benefits in Order No. 1920. For 
example, Order No. 1920's findings and requirements with respect to the 
seven required benefits are consistent with the second of OMS's 
transmission planning principles \1091\ that benefit metrics be 
quantifiable,\1092\ capable of replication,\1093\ non-
duplicative,\1094\ and forward-looking.\1095\
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    \1091\ Organization of MISO States, Inc., Organization of MISO 
States Statement of Principles: Cost Allocation for Long Range 
Transmission Planning Projects, https://www.misostates.org/images/PositionStatements/OMS_Position_Statement_of_Principles_Cost_Allocation_for_LRTPs.pdf.
    \1092\ Order No. 1920, 187 FERC ] 61,068 at P 724 (``[W]e only 
require transmission providers to measure and use seven specific 
benefits that . . . can be discretely measured.'').
    \1093\ Id. P 837 (``[We] require transmission providers in each 
transmission planning region to include in their OATTs a general 
description of how they will measure each of the seven benefits 
included in the required set of benefits . . . .'').
    \1094\ Id. P 735 (``We believe that the seven benefits that we 
include in the required set of benefits that transmission providers 
must measure and use in Long-Term Regional Transmission Planning are 
distinct enough that they will not overlap in a way that results in 
double-counting.'').
    \1095\ Id. P 859 (``[We] require transmission providers in each 
transmission planning region, as part of Long-Term Regional 
Transmission Planning, to calculate the benefits of Long-Term 
Regional Transmission Facilities over a time horizon that covers, at 
a minimum, 20 years starting from the estimated in-service date of 
the transmission facilities . . . .'').
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    399. With respect to Designated Retail Regulators' assertions 
regarding the Entergy Regional State Committee requirements, we note 
that many of the metrics for analysis raised by the first cited 
requirement \1096\ are similar to those required by the final rule and 
by OMS. With respect to the second requirement (``Tranche 3 costs shall 
be allocated using an exclusive list of benefit metrics identified by 
the E-RSC''), we note that transmission providers are free to measure 
and use additional benefits in Long-Term Regional Transmission Planning 
so long as they also measure and use the required benefits and measure 
and use any other benefits in a manner that is

[[Page 97253]]

consistent with their obligations under Order No. 890 and Order No. 
1000 transmission planning principles to be open and transparent as to 
their transmission planning processes.\1097\ With respect to the third 
requirement,\1098\ the final rule noted the potential to use cost-
benefit metrics as a means for evaluating and selecting Long-Term 
Regional Transmission Facilities.\1099\
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    \1096\ Entergy Regional State Committee, Resolution of the 
Entergy Regional State Committee, at 3 (adopted June 30, 2023), 
https://cdn.misoenergy.org/20230630%20-%20ERSC%20Resolution%20re%20MISO%20South%20Cost%20Allocation%20for%20Tranche%203629421.pdf (``The cost-benefit and other analyses that 
are used to inform the business case and cost allocation for Tranche 
3 shall be based only on accurate, objective, measurable, 
quantifiable, non-duplicative, forward-looking, and replicable 
metrics that are supported by data.'').
    \1097\ Order No. 1920, 187 FERC ] 61,068 at P 822.
    \1098\ Entergy Regional State Committee, Resolution of the 
Entergy Regional State Committee, at 3 (adopted June 30, 2023), 
https://cdn.misoenergy.org/20230630%20-%20ERSC%20Resolution%20re%20MISO%20South%20Cost%20Allocation%20for%20Tranche%203629421.pdf (``Each Tranche 3 project must individually 
satisfy the cost-benefit analysis used for the business case and 
cost allocation on a stand-alone basis.'')
    \1099\ Order No. 1920, 187 FERC ] 61,068 at P 966 (noting that 
transmission provider evaluation processes must result in 
determinations that ``include the estimated costs and measured 
benefits of each alternative Long-Term Regional Transmission 
Facility (or portfolio of such Facilities) evaluated by the 
transmission providers, whether or not the Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) is 
selected'').
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    400. We are also unpersuaded by NESCOE's request that we defer to 
state preferences regarding benefits when the driver of the Long-Term 
Transmission Need is related to satisfying state laws, regulations, or 
policies. As noted above, the measurement and use of the required 
benefits in Long-Term Regional Transmission Planning is essential to 
ensuring just and reasonable Commission-jurisdictional rates such that 
the Commission cannot defer to states on this point. However, we note 
that Order No. 1920 requires consultation with the states regarding 
aspects of Long-Term Regional Transmission Planning, including a 
requirement that transmission providers consult with and seek the 
support of Relevant State Entities regarding the evaluation process, 
including selection criteria, that transmission providers propose to 
use to identify and evaluate Long-Term Regional Transmission Facilities 
and that provide transmission providers with the opportunity to select 
Long-Term Regional Transmission Facilities to address Long-Term 
Transmission Needs, including those related to satisfying state laws, 
regulations, or policies.\1100\ Further, as clarified in this order in 
the Stakeholder Process and Transparency section above, transmission 
providers must provide states with a meaningful opportunity to provide 
timely input on the development of Long-Term Scenarios, including 
factors and data inputs, and an opportunity to explain how their own 
policies and planning affect Long-Term Transmission Needs.\1101\
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    \1100\ See id. PP 914, 994.
    \1101\ Further, as discussed in the General Benefits 
Requirements Related to Cost Allocation section below, transmission 
providers can consider additional benefits for cost allocation 
purposes, including, but not limited to, those agreed to by Relevant 
State Entities and described elsewhere in Order No. 1920, provided 
that costs are allocated in a way that is at least roughly 
commensurate with estimated benefits.
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f. Individual Benefits
i. Final Rule Benefit 2(a): Reduced Loss of Load Probability; or Final 
Rule Benefit 2(b): Reduced Planning Reserve Margin
(a) Order No. 1920 Requirements
    401. With respect to Final Rule Benefit 2, the Commission stated 
that this benefit can be characterized and measured as Final Rule 
Benefit 2(a), Reduced Loss of Load Probability, or as Final Rule 
Benefit 2(b), Reduced Planning Reserve Margin, two different methods 
for measuring the same underlying benefit. The Commission found that 
because there is an overlap between the reduced loss of load 
probability benefits and reduced planning reserve margin benefits, for 
purposes of Long-Term Regional Transmission Planning, transmission 
providers must either measure reduced loss of load events by holding 
the planning reserve margin constant or measure the reduction in 
planning reserve margins by holding loss of load events constant but 
may not measure both simultaneously for purposes of using and measuring 
Final Rule Benefit 2(a) or 2(b).\1102\
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    \1102\ Order No. 1920, 187 FERC ] 61,068 at P 755.
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(b) Requests for Rehearing and Clarification
    402. SERTP Sponsors argue that the Commission should clarify that 
it does not intend to require transmission providers to establish a 
planning reserve margin other than the planning reserve margin 
established by the resource planners and load-serving entities on that 
transmission provider's system. SERTP Sponsors also assert that the 
Commission should clarify that any analysis under Final Rule Benefit 2 
should not be used as a basis to challenge the planning reserve margin 
of a resource planner or load-serving entity established through state 
resource planning processes, and that the use of such an analysis is 
only intended for the purpose of evaluating potential Long-Term 
Regional Transmission Facilities that may under certain planning 
scenarios suggest a potential benefit.\1103\
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    \1103\ SERTP Sponsors Rehearing Request at 18.
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(c) Commission Determination
    403. We clarify that Order No. 1920 does not require transmission 
providers to establish a different planning reserve margin than the one 
established by resource planners or load-serving entities in a 
particular transmission provider's system, including in measuring Final 
Rule Benefit 2. We underscore here that any calculation of this benefit 
will only serve to support the benefits assessment of potential Long-
Term Regional Transmission Facilities during the Long-Term Regional 
Transmission Planning process. While the Commission described examples 
of how transmission providers could measure certain benefits, the 
Commission did not require a specific measurement method for any of the 
required benefits.\1104\ Further, the Commission noted that Final Rule 
Benefit 2 can be measured in one of two ways: (a) using reduced loss of 
load probability or (b) reduced planning reserve margin.\1105\ In light 
of this clarification, we need not reach SERTP Sponsors' alternative 
argument that, absent this clarification, Order No. 1920 would raise 
concerns that the Commission has exceeded its jurisdiction.\1106\
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    \1104\ Order No. 1920, 187 FERC ] 61,068 at P 727.
    \1105\ Id. P 748.
    \1106\ See SERTP Sponsors Rehearing Request at 18 n.46, 43 
(Issue Statement 15) (citations omitted).
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    404. In response to SERTP Sponsors' request to clarify that any 
analysis under Final Rule Benefit 2 should not be used as the basis for 
challenging a resource planner's or load-serving entity's planning 
reserve margin established through state resource planning processes, 
we clarify that any state resource planning process is a separate 
process subject to state jurisdiction and is beyond the scope of Order 
No. 1920.
ii. Final Rule Benefit 3: Production Cost Savings
(a) Order No. 1920 Requirements
    405. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to measure and use Final 
Rule Benefit 3 in Long-Term Regional Transmission Planning. The 
Commission described this benefit as savings in fuel and other variable 
operating costs of power generation that are realized when transmission 
facilities allow for displacement of higher-cost supplies through the 
increased dispatch of suppliers that have lower incremental costs of 
production, as well as a

[[Page 97254]]

reduction in market prices as lower-cost suppliers set market clearing 
prices.\1107\
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    \1107\ Order No. 1920, 187 FERC ] 61,068 at P 767.
---------------------------------------------------------------------------

    406. In Order No. 1920, the Commission disagreed with the assertion 
made in comments that production cost savings may not always be 
applicable, such as where financial transmission rights fully hedge the 
cost of congestion. The Commission stated that financial transmission 
rights are required in RTO/ISO markets and allow the market participant 
that owns the right to mitigate the congestion charge along an existing 
transmission path for the capacity of that path. The Commission further 
stated that a new transmission facility could reduce congestion and 
allow that market participant to purchase more electricity, exceeding 
the capacity of the transmission path for the financial transmission 
right, at a lower price. The Commission observed that this reduced 
congestion allows load to access lower cost resources and results in 
more efficient dispatch of resources and, thus, provides avoided 
production cost benefits that are distinct from the avoided congestion 
charges associated with financial transmission rights.\1108\
---------------------------------------------------------------------------

    \1108\ Id. P 773 (citations omitted).
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(b) Requests for Rehearing and Clarification
    407. SERTP Sponsors argue that the Commission should clarify that 
production cost analysis from state-approved integrated resource plans 
may be used to the extent feasible to satisfy the requirement to 
consider Final Rule Benefit 3. SERTP Sponsors further argue that, in 
the event of conflict, state-regulated integrated-resource-plan 
planning must control in accordance with FPA section 201.\1109\
---------------------------------------------------------------------------

    \1109\ SERTP Sponsors Rehearing Request at 19.
---------------------------------------------------------------------------

    408. Designated Retail Regulators assert that the Commission was 
mistaken in stating that a load-serving entity may benefit from reduced 
production costs associated with transmission construction even when 
its congestion costs are fully hedged. Designated Retail Regulators 
argue that as congestion is eliminated by transmission construction, 
the value of the load-serving entity's financial transmission rights 
decreases, and the load-serving entity incurs additional transmission 
charges associated with the new transmission facilities. Designated 
Retail Regulators assert that any benefit based on adjusted production 
cost must therefore consider congestion to determine if a load-serving 
entity receives any benefit or harm from transmission 
construction.\1110\
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    \1110\ Designated Retail Regulators Rehearing Request at 30-31.
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(c) Commission Determination
    409. In response to SERTP Sponsors, we note that Order No. 1920 
does not require a specific measurement method for any of the seven 
required benefits. We clarify that if transmission providers in a 
transmission planning region believe they can use production cost 
savings from one or more state integrated resource plans as an 
appropriate method to measure the value of Final Rule Benefit 3, they 
may propose to do so on compliance. As a general matter, we agree that 
states have authority over generation resource adequacy, which may 
include evaluation of production cost savings in state-regulated 
integrated resource plans. Order No. 1920, however, addresses 
transmission planning practices directly affecting Commission-
jurisdictional rates, including by requiring that transmission 
providers consider the broader set of benefits (such as Final Rule 
Benefit 3) associated with Long-Term Regional Transmission Facilities. 
We therefore decline SERTP Sponsors' request to clarify that 
transmission providers must, in all circumstances, rely on such state 
evaluations of production cost savings in assessing the benefits 
associated with such facilities.\1111\
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    \1111\ In light of this clarification, we continue to conclude 
that Order No. 1920 is a lawful exercise of the Commission's 
statutory authority and does not intrude into areas of reserved 
state jurisdiction. See supra Statutory Authority section; SERTP 
Sponsors Rehearing Request at 18-19 nn.46 & 48, 43 (Issue Statement 
15) (citations omitted). To the extent that transmission providers 
propose a different evaluation of production cost savings than 
reflected in state-regulated integrated resource plans, they will be 
doing so in the context of Order No. 1920's regulation of 
Commission-jurisdictional transmission planning processes.
---------------------------------------------------------------------------

    410. We decline Designated Retail Regulators' request for 
clarification regarding Final Rule Benefit 3 with respect to financial 
transmission rights. We continue to find that financial transmission 
rights allow the market participant that owns the right to mitigate the 
congestion charge along an existing path for the capacity of that path 
and note that a new transmission facility could reduce congestion and 
allow that market participant to purchase more electricity, exceeding 
the capacity of the transmission path for the financial transmission 
right, at a lower price. While the extent of production cost savings 
from any Long-Term Regional Transmission Facility or portfolio of such 
Facilities may vary among representative transmission providers, and 
transmission providers may propose on compliance to consider the 
effects of financial transmission rights on Final Rule Benefit 3, we 
decline to prospectively determine how any load-serving entity may or 
may not benefit from a reduction in regional production costs, 
including whether the degree to which a particular load-serving entity 
may have hedged against congestion would affect such benefits.
2. Measurement and Use of Other Benefits
a. Order No. 1920 Requirements
    411. In Order No. 1920, the Commission declined to require 
transmission providers to measure and use the remaining five benefits 
described in the NOPR in Long-Term Regional Transmission Planning 
(i.e., mitigation of weather and load uncertainty, generation capacity 
investments, access to lower-cost generation, increased competition, 
and increased market liquidity), but permitted transmission providers 
to measure and use additional benefits beyond the set of seven required 
benefits (other benefits), including on a transmission facility or 
plan-specific basis, subject to the requirement that they do so in a 
manner that is consistent with their obligations under Order No. 890 
and Order No. 1000 transmission planning principles to be open and 
transparent as to their transmission planning processes.\1112\ The 
Commission stated that, in particular, the evaluation process must 
result in a determination that is sufficiently detailed for 
stakeholders to understand why a particular Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) was selected or 
not selected to address Long-Term Transmission Needs, which necessarily 
means that stakeholders must understand which benefits transmission 
providers considered in the evaluation process, including any beyond 
the seven benefits that the Commission required transmission providers 
to include in their OATTs.\1113\
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    \1112\ Order No. 1920, 187 FERC ] 61,068 at PP 821-822.
    \1113\ Id. P 737.
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b. Requests for Rehearing and Clarification
    412. PIOs assert that the Commission erred by not requiring 
transmission providers to measure and use the five additional benefits 
identified in the NOPR.\1114\ PIOs assert that the Commission ignores 
its own evidence in the NOPR that the five additional

[[Page 97255]]

proposed benefits have a proven track record, can be discretely 
measured, and are unlikely to cause duplication.\1115\
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    \1114\ PIOs Rehearing Request at 26-27.
    \1115\ Id. at 27 (citing NOPR, 179 FERC ] 61,028 at PP 208-209, 
213-225).
---------------------------------------------------------------------------

    413. TAPS asserts that Order No. 1920's lack of a requirement for 
transmission providers to fully explain and justify additional benefits 
used to evaluate Long-Term Regional Transmission Facilities is an 
unjustified departure from the NOPR and inconsistent with the final 
rule's directive requiring transmission providers to describe how they 
will measure each of the seven required benefits on compliance. TAPS 
states that the final rule invites transmission providers to supplement 
Order No. 1920's required benefits, seemingly abandoning concerns about 
double-counting. TAPS further argues that the flexibility regarding 
additional benefits also provides an opportunity to selectively apply 
additional benefits on a transmission facility or plant-specific basis, 
inviting discrimination.\1116\ TAPS also asserts that it is unclear 
whether the final rule's requirements for transmission providers to be 
``open and transparent'' applies to the process of deciding whether to 
use and how to measure additional benefits or to the implementation of 
the additional benefits for specific projects. TAPS contends that it 
should apply to both.\1117\
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    \1116\ TAPS Rehearing Request at 12-13.
    \1117\ Id. at 11.
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c. Commission Determination
    414. We are not persuaded by PIOs' rehearing request concerning the 
Commission's decision in Order No. 1920 to not require the measurement 
and use of benefits other than the seven required benefits, such as the 
five additional benefits identified by the Commission in the NOPR. The 
Commission determined that measurement and use of the set of seven 
required benefits constituted the just and reasonable replacement rate. 
Furthermore, the Commission explained its reasoning in Order No. 1920 
for only requiring the measurement and use of seven required benefits 
and not other benefits, including recognizing commenters' concerns 
about duplication of certain benefits and the difficulty of measuring 
certain benefits.\1118\ The Commission also explained that the list of 
seven required benefits only requires transmission providers to measure 
and use seven specific benefits that have a proven track record, can be 
discretely measured, and are unlikely to cause duplication.\1119\
---------------------------------------------------------------------------

    \1118\ Order No. 1920, 187 FERC ] 61,068 at P 724.
    \1119\ Id. P 724.
---------------------------------------------------------------------------

    415. With respect to TAPS' concerns regarding a lack of a 
requirement for transmission providers to explain and justify other 
benefits on compliance, we believe that the approach in the final rule 
is reasonable because it provides transmission providers with greater 
flexibility to consider potential additional benefits of Long-Term 
Regional Transmission Facilities beyond the seven required benefits. We 
further find that, by providing transparency, the requirements of the 
final rule are sufficient to avoid undue discrimination. Specifically, 
Order No. 1920 requires transmission providers that measure and use any 
other benefits beyond the set of seven required benefits to do so in a 
manner that is consistent with their obligations under Order No. 890 
and Order No. 1000 transmission planning principles to be open and 
transparent as to their transmission planning processes.\1120\ 
Moreover, the Commission stated that the evaluation process must result 
in a determination that is sufficiently detailed for stakeholders to 
understand why a particular Long-Term Regional Transmission Facility 
(or portfolio of such Facilities) was selected or not selected to 
address Long-Term Transmission Needs, which necessarily means that 
stakeholders must understand which benefits transmission providers 
considered in the evaluation process, including any beyond the seven 
benefits that the Commission required transmission providers to include 
in their OATTs.\1121\ Such transparency will limit the opportunities 
for transmission providers to measure and use in Long-Term Regional 
Transmission Planning any benefits in addition to the required benefits 
in an unduly discriminatory manner.
---------------------------------------------------------------------------

    \1120\ Id. PP 821-822.
    \1121\ Id. P 737.
---------------------------------------------------------------------------

    416. We therefore grant TAPS' request for clarification that the 
final rule's requirements for transmission providers to be ``open and 
transparent'' applies to the process of deciding whether to use and how 
to measure other benefits in addition to the required benefits as well 
as to the implementation of other benefits for specific Long-Term 
Regional Transmission Facilities, as discussed above.
3. Identification, Measurement, and Evaluation of Benefits
a. Order No. 1920 Requirements
    417. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to include in their 
OATTs a general description of how they will measure each of the set of 
seven required benefits, sufficient only to enable stakeholders to 
understand the manner by which transmission providers will measure 
these benefits.\1122\ Order No. 1920 provided flexibility to 
transmission planners to specify the method for measuring each of the 
seven required benefits,\1123\ as well as discretion to measure and use 
additional benefits that go beyond the set of seven required benefits, 
subject to the requirement that they do so in a manner that is 
consistent with their obligations under Order No. 890 and Order No. 
1000 transmission planning principles to be open and transparent as to 
their transmission planning processes.\1124\
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    \1122\ Id. PP 837, 840.
    \1123\ Id. P 839.
    \1124\ Id. P 822.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    418. SERTP Sponsors request that the Commission clarify that it did 
not intend for transmission providers to engage in generation or 
resource planning as part of the Long-Term Regional Transmission 
Planning process, as doing so would violate FPA section 201 because it 
would intrude upon state-jurisdictional resource decisions. SERTP 
Sponsors also request clarification that it is reasonable for 
transmission providers to establish protocols by which they can rely, 
to the extent available, on resource planners and load-serving entities 
for data in support of generation-based benefits.\1125\
---------------------------------------------------------------------------

    \1125\ SERTP Sponsors Rehearing Request at 17-18.
---------------------------------------------------------------------------

c. Commission Determination
    419. In response to SERTP Sponsors' request, we clarify that Order 
No. 1920 does not require transmission providers to engage in 
generation or resource planning as part of Long-Term Regional 
Transmission Planning. The requirement for transmission providers to 
measure and use the set of seven required benefits in Long-Term 
Regional Transmission Planning is necessary for transmission providers 
to consider a sufficiently broad range of benefits when evaluating and 
determining whether to select a Long-Term Regional Transmission 
Facility as the more efficient or cost-effective regional transmission 
solution to Long-Term Transmission Needs and for purposes of conducting 
Long-Term Regional Transmission Planning, and not as a

[[Page 97256]]

basis to cause transmission providers to engage in resource 
planning.\1126\
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    \1126\ In light of this clarification, we need not reach SERTP 
Sponsors' alternative argument that, absent this clarification, 
Order No. 1920 would raise concerns that the Commission has exceeded 
its jurisdiction. See id. at 19 n.48, 43 (Issue Statement 15) 
(citations omitted).
---------------------------------------------------------------------------

    420. Further, as requested by SERTP Sponsors, we clarify that Order 
No. 1920 does not prohibit transmission providers from proposing to 
establish protocols by which they can rely, to the extent available, on 
resource planners and load-serving entities for generation-based data 
and information in satisfying the requirement to measure the benefits 
of Long-Term Regional Transmission Facilities. In Order No. 1920, the 
Commission provided flexibility to transmission providers to specify 
the method for measuring each of the seven required benefits and did 
not mandate any specific method for measuring those seven benefits. 
Order No. 1920 also provided the flexibility for transmission providers 
to establish protocols to obtain data, to the extent available, from 
resource planners and load-serving entities to measure the benefits of 
specific Long-Term Regional Transmission Facilities. However, we re-
emphasize that, whether the transmission providers themselves measure 
the benefits of Long-Term Regional Transmission Facilities, or instead 
establish protocols by which they can rely on resource planners or 
load-serving entities for generation-based data and information to 
measure the benefits, the general description in the OATT of the method 
that the transmission provider uses to measure each of the required 
benefits must be sufficient to enable stakeholders to understand the 
manner by which transmission providers will measure those benefits, as 
noted in Order No. 1920.\1127\
---------------------------------------------------------------------------

    \1127\ Order No. 1920, 187 FERC ] 61,068 at P 840.
---------------------------------------------------------------------------

4. Benefits Horizon
a. Order No. 1920 Requirements
    421. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region, as part of Long-Term 
Regional Transmission Planning, to calculate the benefits of Long-Term 
Regional Transmission Facilities over a time horizon that covers, at a 
minimum, 20 years starting from the estimated in-service date of the 
transmission facilities, and the Commission stated that this minimum 
20-year benefit horizon must be used both for the evaluation and 
selection of Long-Term Regional Transmission Facilities.\1128\ In 
addition, in Order No. 1920, the Commission stated that, while 
transmission providers may discount the benefits calculated for 
purposes of determining a present value of those benefits, they may not 
further discount those benefits to reflect uncertainty over the minimum 
20-year time horizon for calculating benefits.\1129\
---------------------------------------------------------------------------

    \1128\ Id. P 859.
    \1129\ Id. P 865.
---------------------------------------------------------------------------

    422. In prohibiting transmission providers from discounting 
benefits to reflect uncertainty over the 20-year benefits horizon, the 
Commission stated that Order No. 1920 affords transmission providers 
with considerable flexibility in how to address uncertainty in Long-
Term Regional Transmission Planning through the process to develop 
Long-Term Scenarios.\1130\ In addition, the Commission noted that 
transmission providers have the flexibility to evaluate Long-Term 
Regional Transmission Facilities and their measured benefits across the 
different Long-Term Scenarios and sensitivities in a manner that 
addresses the inherent uncertainty in Long-Term Regional Transmission 
Planning, for example, through the use of a least-regrets or a 
weighted-benefits approach.\1131\ As a result, the Commission 
determined that transmission providers have considerable flexibility in 
how to address uncertainty in Long-Term Regional Transmission Planning, 
including the calculation of benefits under different future scenarios, 
and that transmission providers did not need additional flexibility 
that would be realized by discounting benefits over time specifically 
due to future uncertainty.\1132\
---------------------------------------------------------------------------

    \1130\ Id. PP 861, 865.
    \1131\ Id. P 862.
    \1132\ Id. PP 862, 865.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    423. SERTP Sponsors request rehearing of the Commission's 
determination in Order No. 1920 to prohibit discounting of the measured 
benefits of Long-Term Regional Transmission Facilities based on 
uncertainty over the minimum 20-year benefit horizon. According to 
SERTP Sponsors, by requiring a 20-year benefits estimation without 
permitting discounting to reflect uncertainty, while also allowing a 
weighted-benefits approach to account for uncertainty, Order No. 1920's 
requirement and authorization are unclear and contradictory, and 
therefore arbitrary and capricious.\1133\ Similarly, Dominion states 
that the Commission must provide transmission providers with the 
flexibility to discount the measured benefits to reflect uncertainty 
over the minimum 20-year horizon for purposes of selection and 
evaluation of projects.\1134\
---------------------------------------------------------------------------

    \1133\ SERTP Sponsors Rehearing Request at 19-20, 43 (Issue 
Statement 16) (citations omitted); see also id. at 43 (Issue 
Statement 15) (citations omitted) (asserting that failure to grant 
clarification of the issues in Section II.C.3 of SERTP Sponsors' 
argument would result in the Commission intruding on state-
jurisdictional resource decisions).
    \1134\ Dominion Rehearing Request at 21-25.
---------------------------------------------------------------------------

c. Commission Determination
    424. We sustain the finding in Order No. 1920 that, while 
transmission providers may discount the value of the benefits 
calculated for purposes of determining the present value of those 
benefits, they may not further reduce the estimates of those benefits 
to reflect uncertainty over the minimum 20-year time horizon for 
calculating benefits. We disagree with SERTP Sponsors that Order No. 
1920 is contradictory in allowing the use of a weighted-benefits 
approach for evaluating Long-Term Regional Transmission Facilities 
while also prohibiting the reduction in estimates of measured benefits 
based on uncertainty over the minimum 20-year horizon. These two 
techniques are not the same, and allowing one but prohibiting the other 
is not contradictory. Permitting transmission providers to use a 
weighted-benefits approach for Long-Term Regional Transmission 
Facilities allows transmission providers to measure the estimated total 
benefits that a particular Long-Term Regional Transmission Facility may 
provide across a range of Long-Term Scenarios, each with a different 
probability of occurrence.\1135\ This method can help account for 
uncertainty in the total benefits that a Long-Term Regional 
Transmission Facility may provide and help to balance an over-reliance 
on any particular Long-Term Scenario. While we understand that applying 
a probability to a Long-Term Scenario, and its resulting benefits, may 
reduce

[[Page 97257]]

the benefits measured for that particular Long-Term Scenario, when 
aggregated, the probability-weighted benefits measured across all Long-
Term Scenarios results in a representative estimate of the total 
benefits of the Long-Term Regional Transmission Facility as a whole 
while also accounting for uncertainty regarding the likelihood of 
different Long-Term Scenarios being realized.
---------------------------------------------------------------------------

    \1135\ Under a weighted-benefits approach, transmission 
providers that use three Long-Term Scenarios with expected 
likelihoods of, for example, 30%, 30%, and 40%, would attribute 
these expected likelihoods to the benefits that the transmission 
provider measures under each Long-Term Scenario. The total estimated 
benefits of the Long-Term Regional Transmission Facility would then 
be calculated by summing the probability-adjusted benefits across 
these three Long-Term Scenarios (i.e., the sum of the measured 
benefits in the first Long-Term Scenario multiplied by its 30% 
probability, plus the second Long-Term Scenario's benefits 
multiplied by 30%, plus the third Long-Term Scenario's benefits 
multiplied by 40%).
---------------------------------------------------------------------------

    425. On the other hand, we continue to find that allowing 
transmission providers to reduce the estimates of certain benefits 
based only on the relative certainty over the 20-year benefits horizon 
is unnecessary given other flexibilities provided to transmission 
providers to manage uncertainty in planning over a minimum of 20 years, 
for the reasons discussed in Order No. 1920.\1136\ For example, in 
addition to the use of a weighted-benefits approach, transmission 
providers have flexibility in how they account for the factors that go 
into Long-Term Scenario development once, as discussed elsewhere in 
this rule, transmission providers consult with Relevant State Entities 
and their authorized representatives as to how to account for factors 
related to state policy when determining the assumptions that will be 
used in the development of Long-Term Scenarios, as well as in 
determining how to account for such a state-related factor when 
developing Long-Term Scenarios when such state input is 
available.\1137\
---------------------------------------------------------------------------

    \1136\ Order No. 1920, 187 FERC ] 61,068 at P 865.
    \1137\ See supra Long-Term Scenarios Requirements, Stakeholder 
Process and Transparency section.
---------------------------------------------------------------------------

    426. As a result, we continue to believe that prohibiting the 
discounting of benefits based on relative certainty over the 20-year 
benefits horizon is reasonable and strikes an appropriate balance 
between preventing an excessive undercounting of benefits and allowing 
transmission providers to account for uncertainty in measuring benefits 
of Long-Term Regional Transmission Facilities across Long-Term 
Scenarios. For these reasons, we also disagree with Dominion that 
transmission providers must be afforded the flexibility to discount 
benefits based on the uncertainty in planning over a minimum 20-year 
horizon.
    427. SERTP Sponsors do not explain how, in the absence of their 
requested clarification regarding discounting the benefits of Long-Term 
Regional Transmission Facilities, Order No. 1920 would ``intrude[ ] 
upon state-jurisdictional resource decisions.'' \1138\ Regardless, we 
would be unpersuaded by this argument on its merits because, as 
described above, Order No. 1920 falls comfortably within the 
Commission's jurisdiction to regulate practices directly affecting 
Commission-jurisdictional rates.\1139\ The manner in which benefits of 
Long-Term Regional Transmission Facilities are assessed is such a 
Commission-jurisdictional practice.
---------------------------------------------------------------------------

    \1138\ SERTP Sponsors Rehearing Request at 43 (Issue Statement 
15) (citations omitted); id. at 37-41 (generic argument that failure 
to grant certain clarifications intrudes on state jurisdiction or 
may implicate the major questions doctrine, without discussion of 
discounting benefits).
    \1139\ See supra Statutory Authority section.
---------------------------------------------------------------------------

5. Evaluation of the Benefits of Portfolios of Transmission Facilities
a. Order No. 1920 Requirements
    428. In Order No. 1920, the Commission allowed, but not did not 
require, transmission providers in each transmission planning region to 
use a portfolio approach when evaluating the benefits of Long-Term 
Regional Transmission Facilities. Further, the Commission required 
transmission providers that propose to use a portfolio approach when 
evaluating the benefits of Long-Term Regional Transmission Facilities 
to include provisions in their OATTs regarding their use of the 
portfolio approach.\1140\
---------------------------------------------------------------------------

    \1140\ Order No. 1920, 187 FERC ] 61,068 at P 889.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    429. PIOs request rehearing of the Commission's decision in Order 
No. 1920 to not require transmission providers to use a portfolio 
approach when evaluating the benefits of Long-Term Regional 
Transmission Facilities.\1141\ PIOs state that the record in this 
docket includes widespread commenter support and substantial evidence, 
ranging from expert reports to examples of existing processes, 
demonstrating the benefits of using a portfolio approach when 
evaluating the benefits of Long-Term Regional Transmission 
Facilities.\1142\ PIOs argue that by allowing transmission providers to 
continue to evaluate the benefits of Long-Term Regional Transmission 
Facilities on a facility-by-facility basis, the Commission undermines 
Order No. 1920's central purpose of requiring planning for system-wide 
transmission needs on a comprehensive and regional basis and leaves in 
place unjust and unreasonable rates.\1143\ PIOs state that the 
Commission could provide transmission providers with flexibility while 
meeting the goals of Order No. 1920 by establishing a rebuttable 
presumption that Long-Term Regional Transmission Facilities be assessed 
on a portfolio basis, which transmission providers could overcome by 
demonstrating that the portfolio approach is inapplicable in a 
particular instance.\1144\
---------------------------------------------------------------------------

    \1141\ PIOs Rehearing Request at 47 (citations omitted).
    \1142\ Id. at 44-46.
    \1143\ Id. at 47.
    \1144\ Id. 47-48 (citing US DOE NOPR Initial Comments at 34-35).
---------------------------------------------------------------------------

    430. Undersigned States \1145\ and Designated Retail Regulators 
request rehearing of Order No. 1920's decision to allow transmission 
providers to use a portfolio approach when evaluating the benefits of 
Long-Term Regional Transmission Facilities.\1146\ Designated Retail 
Regulators and Undersigned States opine that the Commission should 
prohibit transmission providers from using the portfolio approach 
because, by allowing the bundling of economic and uneconomic facilities 
such that all facilities in a portfolio appear economic on a collective 
basis, the portfolio approach spreads uneconomic project costs to non-
beneficiaries.\1147\ Designated Retail Regulators and Undersigned 
States further argue that the portfolio approach results in the unjust 
and unreasonable recovery of costs exceeding benefits and that every 
facility approved for construction should be economic and meet the 
required benefits-to-cost ratio on a stand-alone basis.\1148\
---------------------------------------------------------------------------

    \1145\ Undersigned States note that the state of North Dakota 
does not join in the portion of Undersigned States' request for 
rehearing that addresses the final rule's determinations concerning 
the portfolio approach. Undersigned States Rehearing Request at 29 
n.19.
    \1146\ Designated Retail Regulators Rehearing Request at 33-34; 
Undersigned States Rehearing Request at 29-30.
    \1147\ Designated Retail Regulators Rehearing Request at 34; 
Undersigned States Rehearing Request at 30.
    \1148\ Designated Retail Regulators Rehearing Request at 34; 
Undersigned States Rehearing Request at 30.
---------------------------------------------------------------------------

c. Commission Determination
    431. We are unpersuaded by PIOs', Undersigned States', and 
Designated Retail Regulators' requests for rehearing of the 
Commission's decision to allow, but not require, transmission providers 
in each transmission planning region to use a portfolio approach when 
evaluating the benefits of Long-Term Regional Transmission Facilities. 
We disagree with PIOs' arguments that the Commission's decision not to 
require transmission providers to use a portfolio approach undermines 
the goals or purpose of Order No. 1920 or leaves unjust and 
unreasonable rates in

[[Page 97258]]

place.\1149\ We continue to find that the advantages of a portfolio 
approach to evaluating benefits must be balanced against other 
considerations and that it is appropriate to provide transmission 
providers in each transmission planning region with flexibility as to 
whether to use a portfolio approach, subject to the requirement that 
transmission providers that propose to use a portfolio approach include 
provisions in their OATTs regarding their use of the portfolio 
approach.\1150\
---------------------------------------------------------------------------

    \1149\ See PIOs Rehearing Request at 47.
    \1150\ Order No. 1920, 187 FERC ] 61,068 at PP 889-890. Order 
No. 1920 requires transmission providers that propose to use a 
portfolio approach to indicate in their proposed OATTs that they 
will use a portfolio approach. However, Order No. 1920 does not 
require transmission providers to indicate whether they will use a 
portfolio approach for all Long-Term Regional Transmission 
Facilities or only in certain specified instances, nor to describe 
how they will analyze the benefits of Long-Term Regional 
Transmission Facilities under a portfolio approach, as such 
requirements could impede transmission provider consideration and 
development of portfolio approaches. Id. P 889.
---------------------------------------------------------------------------

    432. Specifically, we find that the advantages of a portfolio 
approach to evaluating benefits--including administrative efficiencies 
related to economies of scale and a more stable or even distribution of 
benefits, which is likely to facilitate agreement on regional cost 
allocation--must be weighed against the fact that a portfolio approach 
may not be appropriate in all instances. For example, a facility-by-
facility approach may be more appropriate if Long-Term Scenarios reveal 
the same or nearly identical constraints in discrete and isolated areas 
of the transmission system where system upgrades would be beneficial. 
We find that transmission providers are in the best position to 
determine in any given circumstance whether a portfolio or facility-by-
facility approach to evaluate the benefits of Long-Term Regional 
Transmission Facilities is more appropriate. Therefore, we sustain the 
determination in Order No. 1920 to provide transmission providers in 
each transmission planning region with flexibility as to whether to use 
a portfolio approach, subject to the requirement that transmission 
providers that propose to use a portfolio approach when evaluating the 
benefits of Long-Term Regional Transmission Facilities include 
provisions in their OATTs regarding their use of the portfolio 
approach.
    433. We are also unpersuaded by Designated Retail Regulators' and 
Undersigned States' requests that the Commission prohibit transmission 
providers from using a portfolio approach to evaluate the benefits of 
Long-Term Regional Transmission Facilities. We note that the Commission 
has previously accepted the use of the portfolio approach to the 
evaluation of transmission facilities.\1151\ In response to Undersigned 
States' claim that the portfolio approach allocates uneconomic project 
costs to non-beneficiaries, we note that the measurement and use of the 
benefits of Long-Term Regional Transmission Facilities, whether on a 
portfolio or facility-by-facility basis, is a requirement for the 
evaluation of Long-Term Regional Transmission Facilities for the 
purposes of potential selection. Order No. 1920 provides transmission 
providers with flexibility as to the consideration of benefits in their 
cost allocation methods for Long-Term Regional Transmission Facilities, 
subject to the requirement that transmission providers demonstrate that 
such cost allocation methods allocate costs in a manner that is at 
least roughly commensurate with estimated benefits.\1152\ Thus, 
Designated Retail Regulators' and Undersigned States' arguments that 
the portfolio approach to evaluation of benefits will result in the 
allocation of costs for uneconomic facilities are unfounded.
---------------------------------------------------------------------------

    \1151\ Midwest Indep. Transmission Sys. Operator, Inc., 133 FERC 
] 61,221, at PP 221-222 (2010), order on reh'g and compliance 
filing, 137 FERC ] 61,074 (2011), aff'd in part, dismissed in part 
and remanded in part sub nom. Ill. Com. Comm'n v. FERC, 721 F.3d 
764, 780 (7th Cir. 2013).
    \1152\ See Order No. 1920, 187 FERC ] 61,068 at PP 1478, 1506 
(citing ICC v. FERC I, 576 F.3d at 477; ICC v. FERC III, 756 F.3d at 
564).
---------------------------------------------------------------------------

D. Evaluation and Selection of Long-Term Regional Transmission 
Facilities

1. Minimum Requirements
a. Order No. 1920 Requirements
    434. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to include in their 
OATTs an evaluation process, including selection criteria, that they 
will use to identify and evaluate Long-Term Regional Transmission 
Facilities for potential selection to address Long-Term Transmission 
Needs.\1153\ The Commission further held that the transmission 
developer of a selected Long-Term Regional Transmission Facility will 
be eligible to use the applicable cost allocation method for that Long-
Term Regional Transmission Facility.
---------------------------------------------------------------------------

    \1153\ Order No. 1920, 187 FERC ] 61,068 at P 911.
---------------------------------------------------------------------------

    435. The Commission provided flexibility to transmission providers 
to propose, after consultation with Relevant State Entities and other 
stakeholders, evaluation processes, including selection criteria,\1154\ 
provided that they (1) are transparent and not unduly discriminatory; 
\1155\ (2) aim to ensure that more efficient or cost-effective Long-
Term Regional Transmission Facilities are selected to address Long-Term 
Transmission Needs; \1156\ and (3) seek to maximize benefits accounting 
for costs over time without over-building transmission 
facilities.\1157\
---------------------------------------------------------------------------

    \1154\ Id. P 924.
    \1155\ Id. P 954.
    \1156\ Id. P 955.
    \1157\ Id. P 964.
---------------------------------------------------------------------------

    436. As to the requirement that transmission providers' evaluation 
processes, including selection criteria, are transparent and not unduly 
discriminatory, the Commission explained that transmission providers' 
evaluation of Long-Term Regional Transmission Facilities must culminate 
in a determination that is sufficiently detailed for stakeholders to 
understand why a particular Long-Term Regional Transmission Facility 
(or portfolio of Long-Term Regional Transmission Facilities) was 
selected or not selected.\1158\ The Commission also explained that this 
determination must include the estimated costs and measured benefits of 
each Long-Term Regional Transmission Facility (or portfolio of Long-
Term Regional Transmission Facilities) that transmission providers 
evaluated in the Long-Term Regional Transmission Planning process, 
regardless of whether the Long-Term Regional Transmission Facility (or 
portfolio of such Facilities) is selected.\1159\ The Commission further 
explained that, where transmission providers employ a portfolio 
approach to evaluating and selecting Long-Term Regional Transmission 
Facilities, transmission providers may provide the measured benefits 
included in this determination on an aggregate basis.\1160\
---------------------------------------------------------------------------

    \1158\ Id. P 954.
    \1159\ Id. PP 954, 966.
    \1160\ Id. P 966 n.2121.
---------------------------------------------------------------------------

    437. As to the requirement that transmission providers' evaluation 
processes, including selection criteria, must aim to ensure that more 
efficient or cost-effective Long-Term Regional Transmission Facilities 
are selected to address Long-Term Transmission Needs, the Commission 
explained that evaluation processes must: (1) identify one or more 
Long-Term Regional Transmission Facilities (or portfolio of Long-Term 
Regional Transmission Facilities) that address the Long-Term 
Transmission Needs that transmission providers identify in Long-Term 
Regional Transmission Planning; (2)

[[Page 97259]]

estimate the costs and measure the benefits of Long-Term Regional 
Transmission Facilities that are identified or proposed for potential 
selection; (3) designate a point in the evaluation process that is no 
later than three years following the beginning of the Long-Term 
Regional Transmission Planning cycle at which transmission providers 
will determine to select or not to select identified or proposed Long-
Term Regional Transmission Facilities; and (4) culminate in 
determinations that are sufficiently detailed for stakeholders to 
understand why a particular Long-Term Regional Transmission Facility 
(or portfolio of Long-Term Regional Transmission Facilities) was 
selected or not selected.\1161\ The Commission also provided 
transmission providers with flexibility to determine how they will 
evaluate whether Long-Term Regional Transmission Facilities more 
efficiently or cost-effectively address Long-Term Transmission Needs, 
including by using benefit-cost ratios, assessing their net benefits, 
and/or using some other method. Consistent with cost allocation 
principle (3), however, the Commission prohibited transmission 
providers from imposing as a selection criterion a minimum benefit-cost 
ratio that is higher than 1.25-to-1.00.\1162\
---------------------------------------------------------------------------

    \1161\ Id. P 955. As to the identification of Long-Term Regional 
Transmission Facilities, Order No. 1920 requires, consistent with 
Order Nos. 890 and 1000, that nonincumbent transmission developers 
be able to propose transmission facilities in Long-Term Regional 
Transmission Planning, and that therefore transmission providers 
make clear in their OATTs the point in the Long-Term Regional 
Transmission Planning evaluation process at which they will accept 
Long-Term Regional Transmission Facility proposals from 
stakeholders, including nonincumbent transmission developers. Id.
    \1162\ Id. P 958 (citation omitted).
---------------------------------------------------------------------------

    438. Finally, as to the requirement that transmission providers' 
evaluation processes, including selection criteria, must seek to 
maximize benefits accounting for costs over time without over-building 
transmission facilities, the Commission stated that transmission 
providers could adopt evaluation processes and selection criteria that 
would allow transmission providers to make selection decisions while 
addressing the uncertainty inherent in Long-Term Regional Transmission 
Planning. For example, transmission providers could include features 
that minimize the future risk of developing a previously selected Long-
Term Regional Transmission Facility that is not the more efficient or 
cost-effective regional transmission solution to Long-Term Transmission 
Needs, such as by using a least-regrets or weighted-benefits 
approaches.\1163\ The Commission explained that, consistent with this 
requirement, transmission providers may not disregard benefits that 
they are required to use and measure, and may not do so even where 
those benefits only are measured under certain transmission system 
conditions.\1164\ The Commission further explained that transmission 
providers may not adopt an approach under which a Long-Term Regional 
Transmission Facility would be required to meet the selection criteria 
in every Long-Term Scenario and sensitivity.\1165\
---------------------------------------------------------------------------

    \1163\ Id. P 967. The Commission explained that, under a least-
regrets approach, transmission providers would select Long-Term 
Regional Transmission Facilities if those facilities are net 
beneficial in more than one Long-Term Scenario and sensitivity 
analysis even if other transmission facilities have a higher 
benefit-cost ratio or provide more net benefits in a single Long-
Term Scenario or particular sensitivity. Under a weighted-benefits 
approach, transmission providers would select a Long-Term Regional 
Transmission Facility based on its probability-weighted average 
benefits, where probabilities have been assigned to each Long-Term 
Scenario or sensitivity thereof that is studied. Id.
    \1164\ Id. P 965.
    \1165\ Id. P 968.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    439. NRECA argues that the Commission violated the APA's notice-
and-comment requirements because the NOPR did not propose the 
``prescriptive'' requirements set forth in Order No. 1920 related to 
the evaluation of Long-Term Regional Transmission Facilities.\1166\ 
These include the requirement that transmission providers identify 
Long-Term Regional Transmission Facilities that address Long-Term 
Transmission Needs, estimate the costs and measure the benefits of such 
facilities, and designate a point in the evaluation process, no later 
than three years from the date when the Long-Term Regional Transmission 
Planning cycle begins, at which time the transmission provider will 
determine whether to select or not select those identified Long-Term 
Regional Transmission Facilities.\1167\
---------------------------------------------------------------------------

    \1166\ NRECA Rehearing Request at 14.
    \1167\ NRECA Rehearing Request at 14-15 (citing Order No. 1920, 
187 FERC ] 61,068 at PP 381, 955).
---------------------------------------------------------------------------

    440. NRECA also requests that the Commission grant rehearing and 
require that transmission providers' selection criteria ensure the 
selection of Long-Term Regional Transmission Facilities that meet the 
reasonable needs of load-serving entities, which NRECA argues that they 
must do under FPA section 217(b)(4). Further, NRECA contends that FPA 
section 217(b)(4) requires that selection criteria enable load-serving 
entities to secure firm transmission rights (or equivalent tradable or 
financial rights) on a long-term basis for long-term power supply 
arrangements made, or planned, to meet such needs.\1168\
---------------------------------------------------------------------------

    \1168\ See NRECA Rehearing Request at 39-43. As with its 
arguments related to the discretion provided under Order No. 1920 
for transmission providers to determine that factors in Factor 
Category Three may not affect Long-Term Transmission Needs, NRECA 
also argues with respect to selection criteria that the Commission 
should revisit its conclusion that South Carolina Public Service 
Authority v. FERC remains good law on the meaning of FPA section 
217(b)(4). Id. at 40-41.
---------------------------------------------------------------------------

    441. PIOs request rehearing of the Commission's determination to 
allow transmission providers to adopt benefit-cost ratios as high as 
1.25-to-1.00 and request that the Commission require benefit-cost 
ratios no higher than 1.00-to-1.00. PIOs contend that a 1.25-to-1.00 
benefit-cost ratio does not work in the context of scenario-based 
planning using a portfolio approach because some Long-Term Regional 
Transmission Facilities may, in isolation, be below 1.25-to-1.00 
despite raising the value of a portfolio of Long-Term Regional 
Transmission Facilities above such a threshold.\1169\ PIOs also argue 
that the measured benefits of certain Long-Term Regional Transmission 
Facilities may depend on the Long-Term Scenario or sensitivity within 
which benefits are measured, and that it does not make sense to apply a 
benefit-cost ratio threshold to Long-Term Regional Transmission 
Facilities whose benefits are not fixed.\1170\
---------------------------------------------------------------------------

    \1169\ PIOs Rehearing Request at 48-49 (citing PIOs NOPR Initial 
Comments, ex. A at 12-17).
    \1170\ Id. at 48-49.
---------------------------------------------------------------------------

    442. ITC requests rehearing of the Commission's decision to allow, 
but not to require, transmission providers to adopt least-regrets 
approaches to selecting Long-Term Regional Transmission Facilities. ITC 
argues that, given other requirements in Order No. 1920, a least-
regrets approach would hedge against the inherent uncertainty of Long-
Term Regional Transmission Planning by ensuring that selected Long-Term 
Regional Transmission Facilities provide robust benefits over a wide 
variety of future system conditions.\1171\
---------------------------------------------------------------------------

    \1171\ ITC Rehearing Request at 11-12.
---------------------------------------------------------------------------

    443. Dominion states that Order No. 1920 is clear that transmission 
providers ``can compare calculated benefits [of Long-Term Regional 
Transmission Facilities] to costs for purposes of project evaluation 
and selection.'' \1172\

[[Page 97260]]

Dominion requests that the Commission clarify that transmission 
providers may weigh measured benefits against ``other factors'' and 
that transmission providers may propose ``what factors will be 
considered,'' provided that transmission providers' selection criteria 
are ``sufficiently detailed for stakeholders to understand why a 
particular Long-Term Regional Transmission Facility was selected or not 
selected.'' \1173\ Dominion further requests that the Commission 
clarify what different ``costs'' transmission providers can consider 
and weigh against measured benefits beyond the direct costs of the 
construction and operation of the specific Long-Term Regional 
Transmission Facility. By way of example, Dominion explains that some 
Long-Term Regional Transmission Facilities may allow for the delivery 
of more generation to an area of high load demand, while also creating 
reliability issues on another transmission facility. If upgrades to 
that transmission facility are made in response to those reliability 
issues, Dominion requests clarification that transmission providers can 
consider the costs of those upgrades to be a ``cost'' of the Long-Term 
Regional Transmission Facility.\1174\
---------------------------------------------------------------------------

    \1172\ Dominion Rehearing Request at 25 (emphasis added) (citing 
Order No. 1920, 187 FERC ] 61,068 at PP 955, 964-965).
    \1173\ Id. at 25-26 (punctuation omitted) (quoting Order No. 
1920, 187 FERC ] 61,068 at P 737).
    \1174\ Id.
---------------------------------------------------------------------------

    444. Finally, TAPS requests rehearing of the Commission's decision 
not to require that transmission providers calculate and provide to the 
transmission planning region's stakeholders TAPS's proposed 
``affordability metrics.'' TAPS explains that this proposed requirement 
would include the projected incremental transmission rate impact that 
each Long-Term Regional Transmission Facility would provide, if 
selected, and the projected total transmission rate that transmission 
customers would pay if all selected Long-Term Regional Transmission 
Facilities are placed in service. TAPS explains that transmission 
providers should make these calculations on the basis of the default ex 
ante Long-Term Regional Transmission Cost Allocation Method (in the 
absence of any state agreement), covering a period extending at least 
20 years after the Long-Term Regional Transmission Facility is expected 
to be in commercial operation, and would be required to share their 
assumptions and calculations. TAPS explains that transmission providers 
should also provide a process for stakeholders to submit questions and 
verify information. TAPS argues that the Commission's rejection of 
affordability metrics was ``conclusory'' and did not satisfy the 
Commission's obligation to engage with comments.\1175\
---------------------------------------------------------------------------

    \1175\ TAPS Rehearing Request at 20-22 (``[T]he `Commission 
cannot satisfy its mandate to engage with parties' comments by 
relying on conclusory statements that dismissed a party's concerns 
without providing reasoned analysis.''' (internal quotation and 
alteration omitted) (quoting Cal. Pub. Utils. Comm'n v. FERC, 20 
F.4th 795, 804 (D.C. Cir. 2021)).
---------------------------------------------------------------------------

c. Commission Determination
    445. We disagree with the rehearing arguments submitted by NRECA. 
First, the Commission did not violate the APA's notice-and-comment 
requirements when it modified the NOPR proposal to be more 
``prescriptive'' \1176\ by requiring that the evaluation and selection 
processes that transmission providers propose must: (1) identify Long-
Term Regional Transmission Facilities that address the Long-Term 
Transmission Needs they have identified; (2) estimate the costs and 
measure the benefits of such facilities; and (3) designate a point in 
the evaluation process when the transmission provider will determine 
whether to select or not select those facilities. Agency final rules 
need not be identical to proposed rules, and notice is sufficient if 
the final rule represents a ``logical outgrowth'' of the proposed 
rule.\1177\
---------------------------------------------------------------------------

    \1176\ NRECA Rehearing Request at 14.
    \1177\ Long Island Care at Home, Ltd. v. Coke, 551 U.S. 158, 
174-75 (2007) (Long Island Care). See also Am. Paper Inst. v. EPA, 
660 F.2d 954, 959 n.13 (4th Cir. 1981) (``An agency may make even 
substantial changes in its original proposed rule without a further 
comment period if the changes are in character with the original 
proposal and are a logical outgrowth of the notice and comments 
already given.'') (emphasis added).
---------------------------------------------------------------------------

    446. The final rule is a logical outgrowth of the NOPR in this 
regard. The Commission described Long-Term Regional Transmission 
Planning in the NOPR as regional transmission planning that: (1) 
identifies transmission needs driven by changes in the resource mix and 
demand; (2) evaluates transmission facilities that meet such needs; and 
(3) identifies and evaluates such transmission facilities for potential 
selection to meet those needs.\1178\ The NOPR also proposed to require 
that transmission providers' selection criteria ``aim to ensure that 
more efficient or cost-effective transmission facilities are selected 
in the regional transmission plan for purposes of cost allocation to 
address transmission needs driven by changes in the resource mix and 
demand.'' \1179\ In Order No. 1920, the Commission modified the NOPR 
proposal ``to provide additional clarity as to how transmission 
providers' evaluation processes must aim to ensure the selection of 
more efficient or cost-effective Long-Term Regional Transmission 
Facilities to address Long-Term Transmission Needs.'' \1180\ The 
Commission then set forth procedural requirements that require 
transmission providers to meet the NOPR definition of Long-Term 
Regional Transmission Planning by: (1) identifying Long-Term Regional 
Transmission Facilities that address Long-Term Transmission Needs; (2) 
estimating the costs and measuring the benefits of such facilities as 
part of the evaluation process; and (3) designating a point when 
transmission providers will make a decision to select or not select 
such facilities.\1181\ These additional procedural clarifications 
satisfy the logical outgrowth test because the requirements in Order 
No. 1920 achieve the same ends using very similar means to those 
proposed in the NOPR. Accordingly, we find that the evaluation 
requirements follow logically from the NOPR and that the NOPR 
adequately framed the subjects for discussion such that a reasonable 
member of the regulated class would anticipate the general aspects of 
the final rule.\1182\
---------------------------------------------------------------------------

    \1178\ See NOPR, 179 FERC ] 61,028 at P 68. Order No. 1920 
adopted a definition of Long-Term Transmission Needs that includes 
transmission needs driven by changes in the resource mix and demand. 
See Order No. 1920, 187 FERC ] 61,068 at P 299 (describing the 
drivers of Long-Term Transmission Needs as including changes in the 
resource mix and changes in demand).
    \1179\ NOPR, 179 FERC ] 61,028 at P 245.
    \1180\ Order No. 1920, 187 FERC ] 61,068 at P 955.
    \1181\ Id.
    \1182\ Conn. Light & Power Co. v. Nuclear Regul. Comm'n, 673 
F.2d 525, 533 (D.C. Cir. 1982); Telesat Canada v. FCC, 999 F.3d 707, 
713-14 (D.C. Cir. 2021).
---------------------------------------------------------------------------

    447. Second, we disagree with NRECA's rehearing argument that, in 
order to satisfy FPA section 217(b)(4), the Commission must impose a 
specific requirement that transmission providers' selection criteria 
ensure the selection of Long-Term Regional Transmission Facilities that 
meet the reasonable needs of load-serving entities and enable load-
serving entities to secure firm transmission rights (or equivalent 
tradable or financial rights) on a long-term basis for long-term power 
supply arrangements made, or planned, to meet such needs. Fulfilling 
the requirements of FPA section 217(b)(4) does not require that the 
Commission impose the selection criterion that NRECA prefers, and we 
find that the criteria that the Commission required represent a 
superior and, in any case, just and reasonable and not unduly 
discriminatory or preferential approach to this issue. Moreover, the 
Commission explained in Order No. 1920 that, ``[t]hrough the 
requirements of this final rule, we seek to ensure that adequate

[[Page 97261]]

transmission capacity is built to allow load-serving entities to meet 
their service obligations and facilitate the planning of a reliable 
grid, consistent with FPA section 217(b)(4).'' \1183\
---------------------------------------------------------------------------

    \1183\ Order No. 1920, 187 FERC ] 61,068 at P 1001. See also id. 
PP 283, 447 (discussing Commission's obligations under FPA section 
217(b)(4) and its application to Order No. 1920). We also reject 
NRECA's argument that the Commission should revisit its conclusion 
that South Carolina Public Service Authority v. FERC remains good 
law for the same reasons provided in the Other Specific Required 
Categories of Factors section above.
---------------------------------------------------------------------------

    448. We further disagree with the rehearing arguments submitted by 
PIOs, and we sustain the Commission's holding that, consistent with 
Order No. 1000 regional cost allocation principle (3), transmission 
providers may not impose as a selection criterion a minimum benefit-
cost ratio that is higher than 1.25-to-1.00.\1184\ We do not agree with 
PIOs that this holding is inconsistent with the use of a portfolio 
approach to selecting Long-Term Regional Transmission Facilities. While 
PIOs are correct that the benefits of Long-Term Regional Transmission 
Facilities may depend on the Long-Term Scenario or sensitivity in which 
they are measured, Order No. 1920 does not require transmission 
providers to apply benefit-cost ratios within specific Long-Term 
Scenarios or sensitivities.\1185\ Further, the fact that the measured 
benefits of Long-Term Regional Transmission Facilities may differ among 
the Long-Term Scenarios or sensitivities studied does not render the 
use of benefit-cost ratios incompatible with Long-Term Regional 
Transmission Planning. In fact, the least-regrets and weighted-benefits 
approaches to selecting Long-Term Regional Transmission Facilities 
described in Order No. 1920 are examples of how transmission providers 
may make selection decisions notwithstanding the fact that the measured 
benefits of Long-Term Regional Transmission Facilities may differ 
depending on the Long-Term Scenario or sensitivity in which they are 
measured.\1186\
---------------------------------------------------------------------------

    \1184\ Id. P 958.
    \1185\ See id. P 956 (requiring transmission providers to make 
transparent the methods that they used to analyze each individual 
Long-Term Scenario and the sensitivity or sensitivities applied to 
each scenario to determine the Long-Term Transmission Needs that 
exist in the transmission planning region, the Long-Term Regional 
Transmission Facilities that would resolve those needs, and the 
benefits of those Long-Term Regional Transmission Facilities for 
purposes of selection).
    \1186\ Id. P 967. See infra Benefits Horizon section.
---------------------------------------------------------------------------

    449. We also disagree with the rehearing arguments advanced by ITC. 
While we agree with ITC that a least-regrets approach to selecting 
Long-Term Regional Transmission Facilities may allow transmission 
providers to address the inherent uncertainty of Long-Term Regional 
Transmission Planning, we disagree that this is the only such 
approach,\1187\ and therefore we sustain the Commission's holding that 
transmission providers are not required to use this approach.\1188\ 
Generally, the Commission attempted in Order No. 1920 to ensure that 
transmission providers have the flexibility that they need to develop 
evaluation processes, including selection criteria, that meet the 
minimum requirements set forth in Order No. 1920, and we are not 
persuaded by PIOs or ITC to limit that flexibility here, either by 
reducing the maximum benefit-cost ratio that transmission providers may 
propose to use as a selection criterion in Long-Term Regional 
Transmission Planning or by requiring a particular selection approach.
---------------------------------------------------------------------------

    \1187\ See id. P 967 (describing least-regrets and weighted-
benefits approaches to selecting Long-Term Regional Transmission 
Facilities as potential methods to manage uncertainty).
    \1188\ Id. P 968.
---------------------------------------------------------------------------

    450. We grant clarification, in part, to Dominion. As an initial 
matter, we clarify that transmission providers' evaluation processes 
must--not can--compare the measured benefits of Long-Term Regional 
Transmission Facilities against their estimated costs.\1189\ The 
purpose of such a comparison is for transmission providers to determine 
the benefits of Long-Term Regional Transmission Facilities for purposes 
of applying the transmission provider's selection criteria.\1190\ We 
further clarify that, once a transmission provider makes a selection 
decision, i.e., for each selected Long-Term Regional Transmission 
Facility (or portfolio of such Facilities), and, if a State Agreement 
Process is used, once a cost allocation method is agreed upon, 
transmission providers must make available, on a password-protected 
portion of OASIS or other password-protected website, a breakdown of 
how those estimated costs will be allocated, by zone (i.e., by 
transmission provider retail distribution service territory/footprint 
or RTO/ISO transmission pricing zone), and a quantification of those 
estimated benefits as imputed to each zone, as such benefits can be 
reasonably estimated. The increase in transparency from this posting 
requirement ensures that transmission providers make available 
information that is sufficiently detailed for stakeholders to 
understand why a particular Long-Term Regional Transmission Facility 
was selected or not selected. As to Dominion's request that the 
Commission clarify what--aside from project costs--transmission 
providers may compare to measured benefits, we reiterate here that 
transmission providers may propose qualitative measures in their 
evaluation processes or qualitative selection criteria,\1191\ provided 
that they meet the minimum requirements set forth in Order No. 1920 
with which transmission providers' evaluation processes, including 
selection criteria, must comply.\1192\ We further clarify that, 
contrary to Dominion's understanding,\1193\ transmission providers' 
evaluation processes must culminate in a determination--not selection 
criteria--that is sufficiently detailed for stakeholders to understand 
why a particular Long-Term Regional Transmission Facility (or portfolio 
of such Facilities) was selected or not selected.\1194\ Finally, we 
clarify that the Commission generally provides transmission providers 
with the discretion to use engineering judgment in designing and 
conducting transmission planning studies, and we therefore decline to 
address Dominion's hypothetical in the abstract.
---------------------------------------------------------------------------

    \1189\ See id. P 955 (``Second, transmission providers' 
evaluation processes must estimate the costs and measure the 
benefits of the Long-Term Regional Transmission Facilities (or 
portfolio of such Facilities) that are identified or proposed for 
potential selection, in addition to evaluating the identified Long-
Term Regional Transmission Facilities (or portfolio of such 
Facilities) using any qualitative or other quantitative selection 
criteria that the transmission providers in a transmission planning 
region propose to apply.'' (emphasis added)); id. P 964 (requiring 
transmission providers to propose evaluation processes, including 
selection criteria, that seek to maximize benefits accounting for 
costs over time without over-building transmission facilities) 
(emphasis added).
    \1190\ See id. P 956 (holding that transmission providers must 
make clear the methods they used to analyze the benefits of Long-
Term Regional Transmission Facilities for purposes of selection).
    \1191\ Id. P 961.
    \1192\ See id. PP 954-971.
    \1193\ See Dominion Rehearing Request at 26 (``Dominion Energy 
understands that the Final Rule gives Transmission Providers an 
opportunity to propose what factors will be considered so long as 
the selection criteria is `sufficiently detailed to understand why a 
particular Long-Term Regional Transmission Facility . . . was 
selected or not selected.'') (quoting Order No. 1920, 187 FERC ] 
61,068 at P 737) (emphasis added).
    \1194\ Order No. 1920, 187 FERC ] 61,068 at PP 737, 954-955, 
966, 1214.
---------------------------------------------------------------------------

    451. Finally, we are not persuaded by the arguments raised on 
rehearing by TAPS regarding its proposed ``affordability metrics.'' We 
find that the potential benefits of requiring that transmission 
providers make these metrics available are outweighed by the potential 
burden on transmission providers, who would need to determine on a 
customer-by-customer basis the effect on incremental rates of

[[Page 97262]]

a wide variety of rate design and cost recovery factors in order to 
produce a meaningful analysis. Therefore, we decline to adopt any 
requirement to calculate and make available the ``affordability 
metrics'' as described by TAPS. However, even though we do not require 
transmission providers to calculate rate impacts, as discussed above, 
we do require transparency regarding the allocation of costs after 
Long-Term Transmission Facilities are selected.
2. Role of Relevant State Entities
a. Order No. 1920 Requirements
    452. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to consult with and seek 
support from Relevant State Entities regarding the evaluation process, 
including selection criteria, that transmission providers propose to 
use to identify and evaluate Long-Term Regional Transmission Facilities 
for selection.\1195\ The Commission declined to adopt the NOPR proposal 
to require that transmission providers include in their OATTs a process 
to coordinate with the transmission planning region's Relevant State 
Entities in developing selection criteria.\1196\ Instead, the 
Commission required transmission providers to demonstrate on compliance 
that they made good faith efforts to consult with and seek support from 
Relevant State Entities in their transmission planning region's 
footprint when developing the evaluation processes and selection 
criteria that they propose to include in their OATTs.\1197\ The 
Commission did not require transmission providers to obtain the support 
of Relevant State Entities before proposing evaluation processes and 
selection criteria on compliance.\1198\
---------------------------------------------------------------------------

    \1195\ Id. P 994.
    \1196\ Id. P 995.
    \1197\ Id. P 994.
    \1198\ Id. P 996.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    453. Several parties request rehearing or clarification of Order 
No. 1920's requirements related to the role that Relevant State 
Entities will play in developing the evaluation processes, including 
selection criteria, that transmission providers will propose.\1199\
---------------------------------------------------------------------------

    \1199\ Arizona Commission Rehearing Request at 16; Designated 
Retail Regulators Rehearing Request at 48-50; NARUC Rehearing 
Request at 17-21; NESCOE Rehearing Request at 12; NRECA Rehearing 
Request at 6, 17-19.
---------------------------------------------------------------------------

    454. Designated Retail Regulators claim that the Commission 
violated the APA's notice-and-comment requirements because the NOPR 
required that states approve the selection criteria that transmission 
providers will propose to use in Long-Term Regional Transmission 
Planning, whereas the Commission did not require transmission providers 
to obtain their support in Order No. 1920. As such, Designated Retail 
Regulators conclude that Order No. 1920 is not a logical outgrowth of 
the NOPR proposal because it is ``surprisingly distant'' from the 
NOPR.\1200\ Similarly, NRECA argues that Order No. 1920 is not a 
logical outgrowth of the NOPR because the Commission declined to adopt 
the NOPR proposal that transmission providers include a formal tariff 
process for coordinating with Relevant State Entities regarding 
transmission providers' selection criteria.\1201\
---------------------------------------------------------------------------

    \1200\ Designated Retail Regulators Rehearing Request at 48-50 
(quoting Int'l Union, United Mine Workers of Am. v. Mine Safety & 
Health Admin., 407 F.3d 1250, 1260 (D.C. Cir. 2005)).
    \1201\ NRECA Rehearing Request at 6, 17-19.
---------------------------------------------------------------------------

    455. Arizona Commission argues that the Commission erred in not 
requiring transmission providers to obtain the agreement of the State 
of Arizona as to the evaluation processes, including selection 
criteria, that transmission providers will propose, and requests 
rehearing because the Commission did not offer any legitimate legal 
reason or sufficient justification for not requiring such state 
approval. Arizona Commission asserts that states alone have the 
inherent police power to regulate the utilities within their states and 
that the final rule improperly eliminates the State of Arizona's role 
with respect to selection criteria.\1202\ NARUC requests that the 
Commission grant rehearing such that transmission providers would be 
required to include in their compliance filings any selection criteria 
that are ``promulgated and supported'' by Relevant State 
Entities.\1203\
---------------------------------------------------------------------------

    \1202\ See Arizona Commission Rehearing Request at 16.
    \1203\ NARUC Rehearing Request at 17.
---------------------------------------------------------------------------

    456. Finally, NESCOE requests that the Commission clarify Order No. 
1920 to provide guidance as to what constitutes ``good faith efforts'' 
on the part of transmission providers as they consult with and seek 
support from Relevant State Entities. NESCOE requests further 
clarification that the requirement that transmission providers 
``consult with'' Relevant State Entities means that there is an 
``unambiguous pathway'' for states' feedback to be heard and taken into 
account. Further, NESCOE observes that ``consult with'' can mean a 
range of things, from an offer of a one-hour meeting to preview 
potential selection criteria to interactive and substantive 
discussions, and it requests that the Commission confirm that the 
obligation to consult with Relevant State Entities means something more 
consequential than the former.\1204\
---------------------------------------------------------------------------

    \1204\ NESCOE Rehearing Request at 12.
---------------------------------------------------------------------------

c. Commission Determination
    457. We disagree with the arguments raised on rehearing by 
Designated Retail Regulators and NRECA that Order No. 1920 is not a 
logical outgrowth of the NOPR proposal. In particular, we disagree with 
Designated Retail Regulators that the NOPR proposed to require that 
states approve transmission providers' selection criteria.\1205\ 
Instead, the NOPR proposed to require that transmission providers 
``coordinate'' with Relevant State Entities in developing selection 
criteria, and the Commission explained that this would mean that 
transmission providers ``must consult with and seek support from'' 
Relevant State Entities.\1206\ Neither statement can be construed as 
imposing a requirement that states approve the selection criteria to be 
proposed by transmission providers on compliance. In any event, the 
Commission adopted the exact proposal from the NOPR, namely, that 
transmission providers must consult with and seek support from Relevant 
State Entities, which was subject to a notice and comment period, as 
required under the APA.
---------------------------------------------------------------------------

    \1205\ Designated Retail Regulators Rehearing Request at 48-49.
    \1206\ See NOPR, 179 FERC ] 61,028 at PP 241, 244.
---------------------------------------------------------------------------

    458. Further, while NRECA is correct that in Order No. 1920, the 
Commission declined to adopt the NOPR proposal for transmission 
providers to propose on compliance OATT provisions providing for a 
``process'' to coordinate with Relevant State Entities in developing 
selection criteria,\1207\ this does not mean that Order No. 1920 is not 
a logical outgrowth of the NOPR proposal in this regard. As the D.C. 
Circuit has explained, ``[o]ne logical outgrowth of a proposal is 
surely . . . to refrain from taking the proposed step.'' \1208\ The 
same is true here. Further, the Commission required that transmission 
providers

[[Page 97263]]

demonstrate good faith efforts as they consult with and seek support 
from Relevant State Entities.\1209\ We continue to believe that these 
requirements are sufficient to ensure that transmission providers 
benefit from Relevant State Entities' views. Nevertheless, we note that 
Order No. 1920 does not prohibit transmission providers from adopting 
additional approaches for coordinating with Relevant State Entities 
regarding selection criteria and/or consulting with Relevant State 
Entities in the selection of particular Long-Term Regional Transmission 
Facilities, and we encourage transmission providers to do so.\1210\
---------------------------------------------------------------------------

    \1207\ NRECA Rehearing Request at 17-18.
    \1208\ N.Y. v. EPA, 413 F.3d 3, 44 (D.C. Cir. 2005) (per curiam) 
(quoting Am. Iron & Steel Inst. v. EPA, 886 F.2d 390, 400 (D.C. Cir. 
1989)). See also Long Island Care, 551 U.S. at 175 (stating, in the 
context of rejecting claims that an agency provided legally 
defective notice because it did not finalize a proposed rule, ``[w]e 
do not understand why such a possibility was not reasonably 
foreseeable''); Vanda Pharms., Inc. v. Ctrs. for Medicare & Medicaid 
Servs., 98 F.4th 483, 498 (4th Cir. 2024) (Vanda Pharms) (The APA's 
``notice-and-comment procedure is designed so that an agency can 
float a potential rule to the public without committing itself to 
enacting the proposed rule's content'').
    \1209\ Order No. 1920, 187 FERC ] 61,068 at P 994.
    \1210\ Id. PP 994, 996. We reiterate, however, that transmission 
providers may not include in their evaluation process or selection 
criteria any prohibition on the selection of a Long-Term Regional 
Transmission Facility based on the transmission providers' 
anticipated response of a state public utility commission or 
consumer advocates to particular Long-Term Regional Transmission 
Facilities. Id. P 962. Doing so would deny transmission providers 
the opportunity to select more efficient or cost-effective Long-Term 
Regional Transmission Facilities to meet Long-Term Transmission 
Needs, and therefore may lead to failing to address the deficiencies 
in the Commission's existing regional transmission planning 
requirements identified in Order No. 1920. Id. P 914.
---------------------------------------------------------------------------

    459. We also disagree with the rehearing arguments of Arizona 
Commission and NARUC. Arizona Commission incorrectly claims that the 
Commission did not offer any ``legitimate legal or sufficient 
justification'' for not requiring state approval of evaluation 
processes.\1211\ As the Commission explained, it is transmission 
providers who must propose on compliance an evaluation process and 
selection criteria that comply with the requirements of Order No. 1920, 
because Long-Term Regional Transmission Planning is the tariff 
obligation of each transmission provider.\1212\ As the Commission 
further explained, achieving consensus may not be possible in every 
instance, and transmission providers nevertheless must submit 
compliance filings consistent with Order No. 1920 and the compliance 
timelines set forth therein.\1213\ We deny NARUC's request to require 
transmission providers to include in their compliance filings any 
selection criteria that are ``promulgated and supported'' by Relevant 
State Entities. That said, we continue to believe that Long-Term 
Regional Transmission Planning is more likely to be successful where 
transmission providers, Relevant State Entities, and other stakeholders 
collaborate to develop an evaluation process and selection 
criteria.\1214\ As such, we strongly encourage transmission providers 
to consider any selection criteria supported by Relevant State 
Entities.
---------------------------------------------------------------------------

    \1211\ See Arizona Commission Rehearing Request at 16.
    \1212\ Order No. 1920, 187 FERC ] 61,068 at P 996 (citing Order 
No. 1000, 136 FERC ] 61,051 at P 153 (``[T]he ultimate 
responsibility for transmission planning remains with . . . 
transmission providers.'')).
    \1213\ Id. P 996.
    \1214\ Id. P 996.
---------------------------------------------------------------------------

    460. Finally, we grant in part NESCOE's requests for clarification. 
We believe that ``good faith efforts'' is a reasonably well-understood 
standard that parties use in their contractual dealings with one 
another.\1215\ We further believe that the good faith efforts standard 
is similar to a ``reasonable efforts'' standard, which can be defined 
as ``one or more actions rationally calculated to achieve a usually 
stated objective, but not necessarily with the expectation that all 
possibilities are to be exhausted.'' \1216\ We expect that transmission 
providers can determine how to apply the ``good faith efforts'' 
standard as they consult with and seek support from Relevant State 
Entities as to the evaluation processes and selection criteria they 
will use in Long-Term Regional Transmission Planning. Therefore, we 
find that Order No. 1920 requires transmission providers to provide 
opportunities for Relevant State Entities to provide input on those 
proposed processes and to consider that feedback.\1217\ We otherwise 
deny clarification and decline to address NESCOE's hypothetical 
interpretation of the standard.
---------------------------------------------------------------------------

    \1215\ See Zady Natey, Inc. v. United Food & Comm. Workers Int'l 
Union, Loc. No. 27, 995 F.2d 496, 499-500 (4th Cir. 1993) 
(determining whether contractual counterparty made good faith 
efforts to perform obligation on the basis of facts developed in 
adjudicating contractual dispute); Creative Mktg. Assocs., Inc. v. 
AT&T, 476 F.3d 536, 538-39 (8th Cir. 2007) (same); Zinn v. Parrish, 
644 F.2d 360, 366 (7th Cir. 1981) (same); Taco Bell Corp. v. Bloor 
Auto., Inc., No. 90-1442, 1991 WL 11618, at *6 (6th Cir. Feb. 5, 
1991) (same); Gulati v. Coyne Int'l Enters. Corp., 805 F.Supp. 365, 
370-71 (E.D. Va. 1992) (same).
    \1216\ Reasonable Efforts, Black's Law Dictionary (12th ed. 
2024).
    \1217\ As the Commission explained in Order No. 1920, however, 
the transmission provider's failure to obtain Relevant State 
Entities' support is not necessarily evidence that transmission 
providers did not exercise good faith efforts to seek their support. 
Order No. 1920, 187 FERC ] 61,068 at P 997.
---------------------------------------------------------------------------

3. Voluntary Funding
a. Order No. 1920 Requirements
    461. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to include in their 
OATTs a process to provide Relevant State Entities and interconnection 
customers with the opportunity to voluntarily fund the cost of, or a 
portion of the cost of, a Long-Term Regional Transmission Facility that 
otherwise would not meet transmission providers' selection 
criteria.\1218\
---------------------------------------------------------------------------

    \1218\ Id. P 1012.
---------------------------------------------------------------------------

    462. The Commission provided transmission providers with 
flexibility to propose certain features of such a voluntary funding 
process in their compliance filings, provided that: (1) the process is 
transparent and not unduly discriminatory or preferential; and (2) they 
consult with and seek support from Relevant State Entities when 
developing such processes.\1219\
---------------------------------------------------------------------------

    \1219\ Id.
---------------------------------------------------------------------------

    463. The Commission further required that transmission providers' 
proposed OATT provisions must describe: (1) the process by which 
transmission providers will make voluntary funding opportunities 
available to Relevant State Entities and interconnection customers, 
which must ensure that they receive timely notice and a meaningful 
opportunity; (2) the period during which Relevant State Entities and 
interconnection customers may exercise the voluntary funding option; 
(3) the method that transmission providers will use to determine the 
amount of voluntary funding required to ensure that the Long-Term 
Regional Transmission Facility meets the transmission providers' 
selection criteria; and (4) the mechanism through which transmission 
providers and Relevant State Entities or interconnection customers will 
memorialize any voluntary funding agreement.\1220\ Finally, the 
Commission explained that, for any portion of the costs of a selected 
Long-Term Regional Transmission Facility that is not voluntarily 
funded, such remaining costs must be allocated according to either the 
applicable Long-Term Regional Transmission Cost Allocation Method or a 
cost allocation method resulting from a State Agreement Process.\1221\
---------------------------------------------------------------------------

    \1220\ Id. P 1013.
    \1221\ Id.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    464. SERTP Sponsors request that the Commission clarify that the 
requirement in Order No. 1920 that transmission providers include in 
their OATTs a process to provide Relevant State Entities and 
interconnection customers with voluntary funding opportunities does not 
imply that the Commission

[[Page 97264]]

otherwise is prohibiting voluntary funding in other 
circumstances.\1222\
---------------------------------------------------------------------------

    \1222\ SERTP Sponsors Rehearing Request at 8. SERTP Sponsors 
further contend that, if the Commission fails to clarify that Order 
No. 1920 does not prohibit voluntary funding in other circumstances, 
Order No. 1920 would be arbitrary and capricious and exceed the 
Commission's authority. Id.
---------------------------------------------------------------------------

c. Commission Determination
    465. In response to SERTP Sponsors' request for clarification, we 
reiterate that Order No. 1920 does not prohibit voluntary funding 
approaches that are not described therein.\1223\ Transmission providers 
may seek to demonstrate on compliance that other voluntary funding 
approaches are consistent with or superior to Order No. 1920's 
requirements, or they may submit a filing under FPA section 205 to 
propose such approaches.\1224\
---------------------------------------------------------------------------

    \1223\ Order No. 1920, 187 FERC ] 61,068 at P 1017.
    \1224\ Id. It is unclear whether SERTP Sponsors intended to 
argue that failure to grant clarification in this respect would 
result in Order No. 1920 exceeding the Commission's authority; to 
the extent they intended to do so, we find this argument has not 
been raised with the specificity required on rehearing. See supra 
Major Questions Doctrine section.
---------------------------------------------------------------------------

4. No Selection Requirement
a. Order No. 1920 Requirements
    466. In Order No. 1920, the Commission stated that it would not 
require transmission providers to select any particular Long-Term 
Regional Transmission Facility, even where it meets the transmission 
provider's selection criteria.\1225\ The Commission also prohibited 
transmission providers from adopting an approach under which they would 
not select a Long-Term Regional Transmission Facility unless it meets 
their selection criteria in every Long-Term Scenario and 
sensitivity.\1226\
---------------------------------------------------------------------------

    \1225\ Order No. 1920, 187 FERC ] 61,068 at P 1026 (citations 
omitted).
    \1226\ Id. P 968.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    467. SERTP Sponsors request clarification that the Commission's 
statement, i.e., that ``transmission providers may not adopt an 
approach under which they would not select a Long-Term Regional 
Transmission Facility unless it meets their selection criteria in every 
Long-Term Scenario and sensitivity,'' does not undercut the 
Commission's determination that Order No. 1920 does not require a 
transmission provider to select any Long-Term Regional Transmission 
Facility, even where it meets the transmission provider's selection 
criteria.\1227\ PJM also requests that the Commission clarify that PJM 
is not required to select Long-Term Regional Transmission Facilities 
under any of the Long-Term Scenarios that it develops.\1228\
---------------------------------------------------------------------------

    \1227\ SERTP Sponsors Rehearing Request at 9-10 (citing Order 
No. 1920, 187 FERC ] 61,068 at PP 968, 1026).
    \1228\ PJM Rehearing Request at 19.
---------------------------------------------------------------------------

c. Commission Determination
    468. In response to SERTP Sponsors' and PJM's requests for 
clarification, we clarify that Order No. 1920 does not require 
transmission providers to select any Long-Term Regional Transmission 
Facility, even where it meets the transmission providers' selection 
criteria.\1229\
---------------------------------------------------------------------------

    \1229\ Order No. 1920, 187 FERC ] 61,068 at P 1026.
---------------------------------------------------------------------------

5. Reevaluation
a. NOPR Proposal
    469. The Commission proposed in the NOPR that, consistent with 
Order No. 1000, the developer of a transmission facility selected 
through Long-Term Regional Transmission Planning to address 
transmission needs driven by changes in the resource mix and demand 
would be eligible to use the applicable cost allocation method for the 
Long-Term Regional Transmission Facility. The Commission proposed that 
the existing transmission developer requirements would apply, including 
that the developer of the selected regional transmission facility must 
submit a development schedule that indicates the required steps, such 
as the granting of state approvals necessary to develop and construct 
the transmission facility such that it meets the transmission needs of 
the transmission planning region.\1230\ The Commission proposed that, 
to the extent the Relevant State Entities in a transmission planning 
region agree to a State Agreement Process, the development schedule 
should also include relevant steps related to that process.\1231\
---------------------------------------------------------------------------

    \1230\ NOPR, 179 FERC ] 61,028 at P 247 (citing Order No. 1000-
A, 139 FERC ] 61,132 at P 442). The Commission also stated in Order 
No. 1000-A that, as part of the ongoing monitoring of the progress 
of a transmission facility once it is selected, the transmission 
providers in a transmission planning region must establish a date by 
which state approvals to construct must have been achieved that is 
tied to when construction must begin to timely meet the need that 
the facility is selected to address. The Commission stated that if 
such critical steps have not been achieved by that date, then the 
transmission providers in a transmission planning region may 
``remove the transmission project from the selected category and 
proceed with reevaluating the regional transmission plan to seek an 
alternative solution.'' Order No. 1000-A, 139 FERC ] 61,132 at P 
442.
    \1231\ NOPR, 179 FERC ] 61,028 at P 247.
---------------------------------------------------------------------------

    470. The Commission noted that, given the longer-term nature of 
transmission needs driven by changes in the resource mix and demand, 
the required development schedule for a transmission facility selected 
may make it unnecessary for the developer to take actions or incur 
expenses in the near-term if the transmission facility will not need to 
be in service in the near-term. The Commission also noted that a 
transmission provider may make that Long-Term Regional Transmission 
Facility's selection status subject to the outcomes of subsequent Long-
Term Regional Transmission Planning cycles, such that the previously 
selected transmission facility is no longer needed. The Commission 
proposed that transmission providers include in their selection 
criteria how they will address the selection status of a previously 
selected transmission facility based on the outcomes of subsequent 
Long-Term Regional Transmission Planning cycles.\1232\
---------------------------------------------------------------------------

    \1232\ Id. P 248.
---------------------------------------------------------------------------

b. Order No. 1920 Requirements
    471. In Order No. 1920, the Commission required transmission 
providers to include in their OATTs provisions that require them to 
reevaluate previously selected Long-Term Regional Transmission 
Facilities in three situations, where: (1) delays in the development of 
a previously selected Long-Term Regional Transmission Facility would 
jeopardize a transmission provider's ability to meet its reliability 
needs or reliability-related service obligations; (2) the actual or 
projected costs of a previously selected Long-Term Regional 
Transmission Facility significantly exceed cost estimates used in that 
Long-Term Regional Transmission Facility's selection; or (3) 
significant changes in federal, federally-recognized Tribal, state, or 
local laws or regulations cause reasonable concern that a previously 
selected Long-Term Regional Transmission Facility may no longer meet 
the transmission provider's selection criteria.\1233\ The Commission 
further required transmission providers to include in these 
reevaluation provisions the specific criteria they will use to 
determine when one of these situations occurs.\1234\
---------------------------------------------------------------------------

    \1233\ Order No. 1920, 187 FERC ] 61,068 at PP 1048-1049.
    \1234\ Id. P 1050.
---------------------------------------------------------------------------

    472. With respect to reevaluation on the basis of development 
delays, the Commission explained that Order No. 1920's requirement is 
the same requirement as that set forth by the

[[Page 97265]]

Commission in Order No. 1000.\1235\ The Commission explained that, as 
is required for regional transmission planning processes under Order 
No. 1000, transmission providers must have the ability to take action 
when delays in developing a Long-Term Regional Transmission Facility 
risk jeopardizing a transmission provider's ability to meet its 
reliability needs or reliability-related service obligations.\1236\
---------------------------------------------------------------------------

    \1235\ Id. P 1049 n.2250. See id. P 1033 & n.2224 (explaining 
that the Commission proposed in the NOPR that existing transmission 
developer requirements would apply to Long-Term Regional 
Transmission Planning and that, if a transmission facility's 
developer did not achieve development milestones, transmission 
providers may remove that facility from the regional transmission 
plan and reevaluate the regional transmission plan to seek an 
alternative solution).
    \1236\ Id. P 1056.
---------------------------------------------------------------------------

    473. The Commission provided transmission providers with the 
flexibility to develop these reevaluation criteria \1237\ provided 
that, with respect to reevaluation on the basis of significant changes 
in federal, federally-recognized Tribal, state, or local laws or 
regulations, transmission providers may not reevaluate a previously 
selected Long-Term Regional Transmission Facility unless its targeted 
in-service date was in the latter half of the 20-year transmission 
planning horizon when it was selected.\1238\ The Commission also 
required that the reevaluation criteria seek to maximize benefits 
accounting for costs over time without over-building transmission 
facilities. The Commission further explained that it expected 
transmission providers to balance the need to provide transmission 
developers with adequate investment certainty, absent which more 
efficient or cost-effective Long-Term Regional Transmission Facilities 
will not be developed, against the risk that, due to significant 
changes in circumstances, failing to reevaluate a selected Long-Term 
Regional Transmission Facility may result in the over-building of 
transmission.\1239\ The Commission also required transmission providers 
to designate a point after which all selected Long-Term Regional 
Transmission Facilities will no longer be subject to reevaluation--
e.g., when the facility's transmission developer has secured all 
relevant permits and authorizations--such that the transmission 
developer of the selected Long-Term Regional Transmission Facility has 
adequate certainty to make investment decisions.\1240\
---------------------------------------------------------------------------

    \1237\ Id.
    \1238\ Id. P 1051.
    \1239\ Id. P 1050.
    \1240\ Id.
---------------------------------------------------------------------------

    474. The Commission further required transmission providers to 
include in their OATTs provisions detailing the process and procedures 
they will use to reevaluate a previously selected Long-Term Regional 
Transmission Facility, including the potential outcomes of reevaluation 
(e.g., taking no action, imposing a mitigation plan, reassigning the 
Long-Term Regional Transmission Facility to a different transmission 
developer, modifying the Long-Term Regional Transmission Facility, or 
removing the Long-Term Regional Transmission Facility from the regional 
transmission plan), and in particular the conditions under which they 
would remove a previously selected Long-Term Regional Transmission 
Facility from the regional transmission plan.\1241\
---------------------------------------------------------------------------

    \1241\ Id. P 1052 (citing MISO, FERC Electric Tariff, MISO OATT, 
attach. FF (Transmission Expansion Planning Protocol) (90.0.0), 
Sec.  IX.E, which sets forth potential outcomes of MISO's variance 
analysis procedures).
---------------------------------------------------------------------------

    475. The Commission otherwise allowed flexibility as to the design 
of the reevaluation processes and procedures, subject to three 
requirements.\1242\ First, the Commission stated that any reevaluation 
on the basis of cost increases or of significant changes in federal, 
federally-recognized Tribal, state, or local laws or regulations must 
occur in a subsequent Long-Term Regional Transmission Planning cycle 
and must take into account not only the updated costs but also the 
updated benefits of the Long-Term Regional Transmission Facility.\1243\ 
The Commission stated that, when performing these reevaluations, it 
expected that transmission providers will use the updated Long-Term 
Scenarios and associated transmission system models that are developed 
for the Long-Term Regional Transmission Planning cycle in which the 
transmission provider reevaluates the selected Long-Term Regional 
Transmission Facility.\1244\ Second, the Commission required 
transmission providers to include in the reevaluation processes and 
procedures mechanisms for tracking the costs of Long-Term Regional 
Transmission Facilities.\1245\ Third, the Commission required that the 
reevaluation processes and procedures seek to maximize benefits 
accounting for costs over time without over-building transmission 
facilities.\1246\
---------------------------------------------------------------------------

    \1242\ Id.
    \1243\ Id.; see also id. P 1059 (explaining that the requirement 
that the reevaluation processes and procedures update not only 
actual and projected costs but also their calculation of the 
benefits of the selected Long-Term Regional Transmission Facility 
will ensure that transmission providers compare the updated costs 
and benefits when determining whether the Long-Term Regional 
Transmission Facility continues to be a more efficient or cost-
effective regional transmission solution to Long-Term Transmission 
Needs).
    \1244\ Id. P 1052 n.2254.
    \1245\ Id. P 1052.
    \1246\ Id.
---------------------------------------------------------------------------

c. Requests for Rehearing and Clarification
i. Logical Outgrowth
    476. Several parties argue that the Commission did not provide 
sufficient notice of, and opportunity to comment on, Order No. 1920's 
reevaluation requirements.\1247\ For example, EEI claims that the 
Commission cannot require transmission providers to adopt OATT 
provisions that require them to reevaluate previously selected Long-
Term Regional Transmission Facilities without providing notice of and 
an opportunity to comment on these requirements.\1248\ EEI argues that 
Order No. 1920's reevaluation requirements are not within the scope of 
the NOPR's reevaluation proposal and therefore were not ``reasonably 
foreseeable'' by interested parties and that these requirements cannot 
stand because they are not a logical outgrowth of the NOPR 
proposal.\1249\ EEI notes that the Commission stated in Order No. 1920 
that a number of parties expressed support for the reevaluation 
requirements in their NOPR comments but contends that applicable 
precedent makes clear that comments on the proposed rule are not a 
substitute for the Commission itself providing notice of its intention 
to impose these requirements.\1250\ EEI further notes that the 
Commission has invited consideration of the reevaluation of previously 
selected transmission facilities in a different proceeding and states 
that it would have been more appropriate for the Commission to have 
acted in that proceeding rather than in Order No. 1920 because the NOPR 
lacked any description of the range of reevaluation alternatives.\1251\ 
EEI states that it does not oppose ``reasonable mechanisms'' to protect 
consumers from over-building Long-Term Regional Transmission Facilities 
and from the possibility of building transmission

[[Page 97266]]

facilities that may not be cost-effective, but asserts that the 
appropriate remedy in this instance is to return to the NOPR 
proposal.\1252\
---------------------------------------------------------------------------

    \1247\ East Kentucky Rehearing Request at 1-2; EEI Rehearing 
Request at 4-11; ITC Rehearing Request at 16; MISO TOs Rehearing 
Request at 8, 19-22; NRECA Rehearing Request at 13-15, 22; WIRES 
Rehearing Request at 2-4, 6-16.
    \1248\ EEI Rehearing Request at 5.
    \1249\ Id. at 6-7 (citing Brennan v. Dickson, 45 F.4th at 69-
70).
    \1250\ Id. (citing Small Refiner Lead Phase-Down Task Force v. 
EPA, 705 F.2d 506, 549 (D.C. Cir. 1983)).
    \1251\ Id. at 10 (citing Notice Inviting Post-Technical 
Conference Comments, Transmission Planning and Cost Mgmt., Docket 
No. AD22-8-000, et al. (Dec. 23, 2022)).
    \1252\ Id. at 10-11.
---------------------------------------------------------------------------

    477. NRECA argues that Order No. 1920 departs from the NOPR 
proposal by adopting ``completely new'' requirements for the 
reevaluation of previously selected Long-Term Regional Transmission 
Facilities.\1253\ NRECA contends that the reevaluation requirements 
result in an ``inflexible, final selection of Long-Term Regional 
Transmission Facilities for purposes of regional cost allocation in the 
first three years of each Long-Term Regional Transmission Planning 
cycle.'' \1254\ NRECA recommends that, to ensure compliance with the 
APA's notice-and-comment requirements, the Commission withdraw the 
final rule and issue a supplemental NOPR.\1255\
---------------------------------------------------------------------------

    \1253\ NRECA Rehearing Request at 4-6.
    \1254\ Id. at 14.
    \1255\ Id. at 4, 19.
---------------------------------------------------------------------------

    478. WIRES asserts that the NOPR did not provide notice to 
interested parties of Order No. 1920's ``detailed and prescriptive'' 
reevaluation requirements and that these requirements represent major 
changes from the NOPR proposal.\1256\ WIRES asserts that the 
reevaluation requirements are significant because they could lead to 
modifying Long-Term Regional Transmission Facilities or removing them 
from the regional transmission plan, and, as such, the Commission 
should have clearly and unambiguously set forth a proposal in the NOPR 
before adopting Order No. 1920's reevaluation requirements.\1257\ WIRES 
alleges that instead, the Commission adopted ``almost word-for-word'' a 
proposal submitted in comments by Large Public Power without first 
providing notice of and an opportunity to comment on this 
proposal.\1258\
---------------------------------------------------------------------------

    \1256\ WIRES Rehearing Request at 3-5.
    \1257\ Id. at 2-4.
    \1258\ Id. at 10.
---------------------------------------------------------------------------

    479. Several rehearing parties contend that, while the NOPR 
proposed a structure that would permit but not require transmission 
providers to reevaluate previously selected Long-Term Regional 
Transmission Facilities, Order No. 1920 requires that transmission 
providers do so and includes a number of prescriptive requirements that 
were not included in the NOPR.\1259\ MISO TOs argue that Order No. 1920 
states that it adopted with modification the NOPR proposal, despite the 
fact that the NOPR proposed a ``flexible and open-ended opportunity'' 
in accordance with which transmission providers could have tailored 
their compliance proposals, whereas Order No. 1920's reevaluation 
requirements are ``a wholly new and tightly prescriptive process with 
new triggering events and new requirements for reassessing 
facilities.'' \1260\ WIRES notes that the NOPR did not use the term 
``reevaluate,'' that it proposed to provide flexibility for 
transmission providers to propose their own processes, and did not 
include any relevant details or requirements other than to propose that 
transmission providers ``should include in their selection criteria how 
they will address the selection status of a previously selected 
transmission facility based on the outcomes of subsequent Long-Term 
Regional Transmission Planning cycles.'' \1261\
---------------------------------------------------------------------------

    \1259\ See, e.g., EEI Rehearing Request at 7-8; WIRES Rehearing 
Request at 7-8.
    \1260\ MISO TOs Rehearing Request at 21-22 (citing Order No. 
1920, 187 FERC ] 61,068 at P 1048).
    \1261\ WIRES Rehearing Request at 6-7 (quoting NOPR, 179 FERC ] 
61,028 at P 248).
---------------------------------------------------------------------------

    480. Several parties acknowledge that, in setting forth Order No. 
1920's reevaluation requirements, the Commission cited the NOPR 
proposal that would have allowed transmission providers to make the 
selection status of previously selected Long-Term Regional Transmission 
Facilities subject to the outcome of subsequent Long-Term Regional 
Transmission Planning cycles,\1262\ but contend nonetheless that that 
notice was inadequate. EEI states that the NOPR proposal contained none 
of the detail or the rationale regarding specific elements of Order No. 
1920's reevaluation requirements, such as the specific situations in 
which reevaluation would be required or the requirement for 
transmission providers to include in their OATTs the potential outcomes 
of reevaluation.\1263\ EEI further argues that, whereas the NOPR 
proposal focused on how the outcome of subsequent Long-Term Regional 
Transmission Planning cycles could give rise to the need to reevaluate, 
the three situations in which Order No. 1920 requires reevaluation do 
not depend on the results of or actions in a subsequent Long-Term 
Regional Transmission Planning cycle.\1264\
---------------------------------------------------------------------------

    \1262\ See NOPR, 179 FERC ] 61,028 at P 248.
    \1263\ EEI Rehearing Request at 5-6.
    \1264\ Id. at 8-9.
---------------------------------------------------------------------------

    481. NRECA states that it did not oppose the Commission's NOPR 
proposal to require transmission providers to participate in a regional 
transmission planning process that includes Long-Term Regional 
Transmission Planning--and particularly, the requirements that 
transmission providers use a 20-year transmission planning horizon and 
measure the benefits of transmission facilities over 20 years--because 
of the NOPR proposal to allow transmission providers to subject the 
selection status of Long-Term Regional Transmission Facilities to the 
outcome of subsequent Long-Term Regional Transmission Planning 
cycles.\1265\ NRECA states that it interpreted the NOPR as allowing 
transmission providers to develop selection criteria under which 
transmission providers could conditionally select a Long-Term Regional 
Transmission Facility but delay selecting that Facility for purposes of 
cost allocation until later.\1266\ NRECA states that the Commission did 
not adopt the NOPR proposal and instead adopted ``completely different, 
prescriptive [reevaluation] requirements.'' \1267\
---------------------------------------------------------------------------

    \1265\ NRECA Rehearing Request at 13 (citing NOPR, 179 FERC ] 
61,028 at P 248).
    \1266\ Id. at 24.
    \1267\ Id. at 25 (citing Order No. 1920, 187 FERC ] 61,068 at P 
1055 & n.2257).
---------------------------------------------------------------------------

    482. MISO TOs and ITC each argue that the Commission did not 
provide adequate notice of or an opportunity to comment on the 
requirement that transmission providers update their measurement of the 
benefits of Long-Term Regional Transmission Facilities. MISO TOs state 
that the NOPR proposed ``the option of a routine review'' and did not 
include any requirement for a ``general reevaluation of benefits of the 
facilities,'' and that this deprived regulated parties of the fair 
notice required by the APA.\1268\ ITC contends that Order No. 1920's 
reevaluation requirements depart substantially from the original 
reevaluation proposal, and that the Commission has not provided 
commenters a meaningful opportunity to comment on the requirement ``to 
perform a full update of the calculation of the benefits'' resulting in 
a factual record that does not address the relative merits of this 
approach.\1269\
---------------------------------------------------------------------------

    \1268\ MISO TOs Rehearing Request at 19-21.
    \1269\ ITC Rehearing Request at 16.
---------------------------------------------------------------------------

    483. MISO TOs and WIRES each argue that, had the Commission 
provided notice of and an opportunity to comment, Order No. 1920's 
reevaluation requirements would ultimately have been improved. MISO TOs 
argue that Order No. 1920 is not as clear or as workable as it might 
have been if MISO TOs and other commenters had fair notice, and that 
the Commission instead could have adopted ``a more nuanced and workable 
requirement.'' \1270\ WIRES claims that the Commission did not have the 
benefit of sufficient input from regulated

[[Page 97267]]

parties. WIRES contends that, while the Commission stated that it set 
forth Order No. 1920's reevaluation requirements having ``carefully 
reviewed the record developed here and weighed commenters' 
countervailing arguments,'' the comments submitted were specific to the 
NOPR proposal that was not adopted--not Order No. 1920's reevaluation 
requirements.\1271\
---------------------------------------------------------------------------

    \1270\ MISO TOs Rehearing Request at 19, 22.
    \1271\ WIRES Rehearing Request at 14-16 (quoting Order No. 1920, 
187 FERC ] 61,068 at P 1053).
---------------------------------------------------------------------------

ii. Other Issues
    484. Several parties sought rehearing or clarification of the 
requirement to update the measurement of benefits when reevaluating a 
previously selected Long-Term Regional Transmission Facility or 
Facilities.\1272\ MISO TOs argued that the requirement for transmission 
providers to update their measurement of the benefits of Long-Term 
Regional Transmission Facilities risks significant disruption to the 
use of portfolio approaches to selecting such facilities. MISO TOs 
argued that the Commission had not provided substantial evidence to 
support requiring transmission providers to update their measurement of 
the benefits of Long-Term Regional Transmission Facilities during 
reevaluations, as the Commission acknowledged that updating the 
measurement of benefits is ``not as straightforward as tracking 
costs,'' reassessing benefits is different than reassessing costs, and 
reevaluation could create ``unnecessary disruptions and potentially 
impede the efficient conduct'' of Long-Term Regional Transmission 
Planning.\1273\ MISO TOs requested that, on rehearing, the Commission 
modify Order No. 1920's requirement such that transmission providers 
would ``consider benefits and the broader needs of the region in the 
reevaluation process and choose an outcome based on that assessment.'' 
\1274\
---------------------------------------------------------------------------

    \1272\ MISO TOs Rehearing Request at 4; ITC Rehearing Request at 
17; WIRES at 11-12.
    \1273\ MISO TOs Rehearing Request at 17-19 (citing Order No. 
1920, 187 FERC ] 61,068 at P 1059).
    \1274\ Id. at 13.
---------------------------------------------------------------------------

    485. ITC argued that, while reevaluating a previously selected 
Long-Term Regional Transmission Facility on the basis of cost increases 
is reasonable, Order No. 1920's requirement for transmission providers 
to update their measurement of the benefits of Long-Term Regional 
Transmission Facilities will burden transmission providers and deter 
investment in such facilities. ITC therefore requested that the 
Commission eliminate the requirement to update the measurement of the 
benefits or, in the alternative, clarify that transmission providers 
may adopt a more qualitative assessment that takes into account the 
benefits and costs of a Long-Term Regional Transmission Facility in the 
context of the transmission planning region's Long-Term Transmission 
Needs, and also that transmission providers may adopt flexible remedial 
measures such as those available under MISO's variance analysis 
process.\1275\ Similarly, WIRES requested clarification as to whether 
Order No. 1920 would allow transmission providers flexibility to 
determine how they will update their measurement of the benefits of 
Long-Term Regional Transmission Facilities, and argued that 
transmission providers should have the flexibility to address the 
concerns raised by the Commission in developing their reevaluation 
criteria in a manner compatible with their transmission planning 
process.\1276\
---------------------------------------------------------------------------

    \1275\ ITC Rehearing Request at 15-19.
    \1276\ WIRES Rehearing Request at 14.
---------------------------------------------------------------------------

    486. NRECA requested that the Commission eliminate the requirement 
for transmission providers to designate a point after which all 
previously selected Long-Term Regional Transmission Facilities will no 
longer be subject to reevaluation, i.e., a pencils-down point, such 
that the transmission developer of the selected facility would have 
adequate certainty to make investment decisions.\1277\
---------------------------------------------------------------------------

    \1277\ NRECA Rehearing Request at 33 (citing Order No. 1920, 187 
FERC ] 61,068 at P 1050); see also East Kentucky Rehearing Request 
at 2 (arguing that Order No. 1920 permits arbitrary and unreasonable 
deadlines on reevaluations).
---------------------------------------------------------------------------

    487. Large Public Power and NRECA requested that the Commission 
require on rehearing that transmission providers reevaluate previously 
selected Long-Term Regional Transmission Facilities not only when there 
is a significant increase in costs, but also when there is a 
significant decrease in the benefits of a particular facility.\1278\ 
Large Public Power further requested that the Commission clarify that 
Order No. 1920 requires transmission providers to track both the costs 
and the benefits of previously selected Long-Term Regional Transmission 
Facilities.\1279\ In addition to reevaluation on the basis of cost 
increases, NRECA argued that transmission providers should be required 
to reevaluate previously selected Long-Term Regional Transmission 
Facilities when the transmission planning region's Long-Term 
Transmission Needs have changed.\1280\
---------------------------------------------------------------------------

    \1278\ Large Public Power Rehearing Request at 17-19; NRECA 
Rehearing Request at 29-30; see also East Kentucky Rehearing Request 
at 2 (arguing that the Order No. 1920 requirement related to 
reevaluation on the basis of cost increases is ``too narrowly 
drawn'' and inconsistent with other aspects of Order No. 1920).
    \1279\ Large Public Power Rehearing Request at 17-18 (citing 
Order No. 1920, 187 FERC ] 61,068 at PP 1054, 1059).
    \1280\ NRECA Rehearing Request at 30-32.
---------------------------------------------------------------------------

    488. ITC, Large Public Power, and NRECA argued that the Commission 
should grant rehearing and eliminate Order No. 1920's requirements to 
reevaluate on the basis of significant changes in federal, federally-
recognized Tribal, state, or local laws or regulations, because these 
requirements are either too narrow or too broad.\1281\
---------------------------------------------------------------------------

    \1281\ ITC Rehearing Request at 4-5; Large Public Power 
Rehearing Request at 19-20; NRECA Rehearing Request at 36; see also 
East Kentucky Rehearing Request at 2 (stating that Order No. 1920 
``arbitrarily [and] unreasonably prohibits some reevaluations due to 
changes in laws or regulations'').
---------------------------------------------------------------------------

    489. ITC stated that Order No. 1920 encourages the use of portfolio 
approaches to select Long-Term Regional Transmission Facilities, as 
they generate considerable interdependency among the various Long-Term 
Regional Transmission Facilities selected in a particular Long-Term 
Regional Transmission Planning cycle. ITC therefore recommended that 
the Commission require periodic project portfolio reporting modeled 
after MISO's Multi-Value Project Triennial Reporting framework, which 
ITC contended provides a regular check to ensure transmission customers 
receive the benefits they are promised and allows for regional 
transmission planning process improvement.\1282\ If the Commission did 
not grant rehearing and eliminate reevaluations on the basis of 
significant changes in law or regulations, ITC requested that the 
Commission allow such reevaluation only for Long-Term Regional 
Transmission Facilities whose targeted in-service date is more than 10 
years from the point at which the transmission provider conducts the 
reevaluation.
---------------------------------------------------------------------------

    \1282\ ITC Rehearing Request at 13-14.
---------------------------------------------------------------------------

    490. In contrast, Large Public Power argued that the ``blanket ten-
year moratorium'' is arbitrary and capricious.\1283\ NRECA argued that 
the Commission provided no rationale for this limitation, which it 
characterized as ``so implausible that it could not be ascribed to a 
difference in view or the product of agency expertise.'' \1284\
---------------------------------------------------------------------------

    \1283\ Large Public Power Rehearing Request at 19-20.
    \1284\ NRECA Rehearing Request at 36 (quoting State Farm, 463 
U.S. at 43).
---------------------------------------------------------------------------

    491. Several parties requested that the Commission provide 
transmission providers with more flexibility to reevaluate previously 
selected Long-Term Regional Transmission Facilities in other 
situations. Dominion sought

[[Page 97268]]

rehearing or, as applicable, clarification of the Commission's 
reevaluation process to allow transmission providers to reevaluate a 
previously selected Long-Term Regional Transmission Facility in 
situations other than those identified in Order No. 1920.\1285\ 
Similarly, SERTP Sponsors requested that the Commission clarify that 
the three situations described in Order No. 1920 in which reevaluation 
of previously selected Long-Term Regional Transmission Facilities is 
required are illustrative, arguing that Order No. 1920 grants 
transmission providers inadequate flexibility in developing OATT 
provisions regarding the reevaluation of previously selected Long-Term 
Regional Transmission Facilities.\1286\
---------------------------------------------------------------------------

    \1285\ Dominion Rehearing Request at 17.
    \1286\ SERTP Sponsors Rehearing Request at 20-21.
---------------------------------------------------------------------------

d. Commission Determination
i. Logical Outgrowth
    492. We disagree with the argument that the Commission failed to 
provide adequate notice of and opportunity to comment on Order No. 
1920's requirement that transmission providers include provisions in 
their OATTs that require them to reevaluate previously selected Long-
Term Regional Transmission Facilities in certain circumstances. As the 
D.C. Circuit explained recently, ``the very premise of agencies' duty 
to solicit, consider, and respond appropriately to comments is that 
rules evolve from conception to completion.'' \1287\ Indeed, notice is 
sufficient if the final rule represents a ``logical outgrowth'' of the 
proposed rule.\1288\ Order No. 1920's reevaluation requirements are 
closely related to and fully in character with the NOPR proposal, and 
represent the kind of reasonable evolution of an initial proposal in 
response to comments that rehearing parties could have reasonably 
anticipated.
---------------------------------------------------------------------------

    \1287\ Brennan v. Dickson, 45 F.4th at 69.
    \1288\ Long Island Care, 551 U.S. at 174-75. See also Am. Paper 
Inst. v. EPA, 660 F.2d at 959 n.13 (``An agency may make even 
substantial changes in its original proposed rule without a further 
comment period if the changes are in character with the original 
proposal and are a logical outgrowth of the notice and comments 
already given.'') (emphasis added).
---------------------------------------------------------------------------

    493. As an initial matter, we note that the NOPR proposed to 
require the reevaluation of previously selected transmission facilities 
in certain circumstances. Because Long-Term Regional Transmission 
Planning is a form of regional transmission planning,\1289\ the 
Commission's regional transmission planning requirements apply. This 
includes a requirement that transmission providers describe in their 
OATTs the circumstances in which and the procedures under which 
transmission providers will conduct a reevaluation. This reevaluation 
is necessary to determine how a transmission provider will respond if 
development delays affecting a previously selected regional 
transmission facility jeopardize incumbent transmission owners' ability 
to meet their reliability needs or service obligations.\1290\ The 
Commission made this explicit in the NOPR when it proposed that Order 
No. 1000's transmission developer requirements would apply to Long-Term 
Regional Transmission Planning \1291\ and noted that in the event of 
development delays, transmission providers may ``remove the 
transmission facility from the selected category and proceed with 
reevaluating the regional transmission plan to seek an alternative 
solution.'' \1292\
---------------------------------------------------------------------------

    \1289\ NOPR, 179 FERC ] 61,028 at P 68; Order No. 1920, 187 FERC 
] 61,068 at P 224.
    \1290\ Order No. 1000, 136 FERC ] 61,051 at P 329.
    \1291\ NOPR, 179 FERC ] 61,028 at P 247.
    \1292\ Id. P 247 n.395 (citing Order No. 1000-A, 139 FERC ] 
61,132 at P 442).
---------------------------------------------------------------------------

    494. The Commission further proposed in the NOPR to allow 
transmission providers to make the selection status of a previously 
selected Long-Term Regional Transmission Facility ``subject to the 
outcomes of subsequent Long-Term Regional Transmission Planning 
cycles,'' such that it ``is no longer needed'' and proposed that 
transmission providers ``should include in their selection criteria how 
they will address the selection status of a previously selected 
transmission facility based on the outcomes of subsequent Long-Term 
Regional Transmission Planning cycles.'' \1293\ The Commission 
suggested that this proposal was warranted because the development 
schedule for a Long-Term Regional Transmission Facility may not require 
its developer to undertake actions or incur expenses in the near-
term,\1294\ and it explained that the NOPR's proposed reforms were 
intended to be responsive to ``commenters' concerns about over-building 
[transmission facilities] due to uncertainties of future transmission 
system conditions.'' \1295\ Therefore, although the Commission used 
other language, the Commission effectively proposed in the NOPR that 
transmission providers could reevaluate certain Long-Term Regional 
Transmission Facilities (i.e., those for which near-term development 
activities are not necessary) in light of changed circumstances 
apparent in the subsequent Long-Term Regional Transmission Planning 
cycle to determine whether to continue developing that facility or find 
that it was no longer needed.\1296\
---------------------------------------------------------------------------

    \1293\ Id. P 248.
    \1294\ Id.
    \1295\ NOPR, 179 FERC ] 61,028 at P 245.
    \1296\ Id. P 248.
---------------------------------------------------------------------------

    495. In other words, the NOPR provided adequate notice of and an 
opportunity to comment on proposals to require reevaluation of 
previously selected Long-Term Regional Transmission Facilities due to 
development delays and to permit reevaluation of previously selected 
Long-Term Regional Transmission Facilities due to changed circumstances 
from one Long-Term Regional Transmission Planning cycle to the next.
    496. Commenters objected to the NOPR proposal on the grounds that 
providing open-ended allowance for reevaluation of previously selected 
Long-Term Regional Transmission Facilities would undermine selection as 
a ``reasonably final'' step and create too much uncertainty for 
transmission developers, which would impede the development of the 
relevant transmission facilities and ultimately could raise concerns 
about reliability impacts or other consequences.\1297\ Upon 
consideration of the record before it and these comments in particular, 
the Commission modified the NOPR proposal to allow for the reevaluation 
of previously selected Long-Term Regional Transmission Facilities due 
to changed circumstances from one transmission planning cycle to the 
next. Specifically, Order No. 1920 required the reevaluation of Long-
Term Regional Transmission Facilities only in certain circumstances 
that could affect the need for the facility--i.e., where the costs of 
the transmission facility significantly exceed estimates or where 
significant changes in federal, federally-recognized Tribal, state, or 
local laws or regulations cause reasonable concern that the facility no 
longer meets selection criteria.\1298\ Further, consistent with the 
Commission's reasoning in the NOPR that reevaluation may be appropriate 
where near-term development actions or expenditures are not needed in 
order to meet the targeted in-service date, the Commission limited the 
availability of reevaluation due to significant changes in laws or 
regulations to only those facilities that are not needed to be in-
service within 10 years (i.e., unless its

[[Page 97269]]

targeted in-service date was in the latter half of the 20-year 
transmission planning horizon during the Long-Term Regional 
Transmission Planning cycle in which it was selected) and required a 
``pencils-down'' point in the development of a facility at which 
reevaluation would no longer be permitted.\1299\ The Commission's 
modifications are not ``surprisingly distant'' from the proposal so as 
to be wholly unexpected; \1300\ instead, the changes merely refine the 
proposals included in the NOPR and are thus precisely the kind of 
tailoring and fine-tuning of a proposed rule in response to comments 
that is the raison d'[ecirc]tre for APA notice-and-comment 
requirements.\1301\
---------------------------------------------------------------------------

    \1297\ Order No. 1920, 187 FERC ] 61,068 at P 1055 & n.2256.
    \1298\ Id. PP 1048-1055.
    \1299\ Id. PP 1050-1051.
    \1300\ Brennan v. Dickson, 45 F.4th at 69.
    \1301\ We note that, while the reevaluation requirements are one 
tool to manage the inherent uncertainties of Long-Term Regional 
Transmission Planning and to limit the risk of over-building 
transmission in response to speculative transmission needs, we 
believe that other requirements in Order No. 1920 also address these 
concerns. The inability to include reevaluation requirements would 
not have prevented the Commission from issuing Order No. 1920.
---------------------------------------------------------------------------

ii. Other Issues
    497. We also disagree with rehearing parties' substantive 
objections to the reevaluation requirements. While certain parties 
object to the reevaluation requirements as too lax,\1302\ and other 
parties object to them as too stringent,\1303\ we conclude that they 
strike a reasonable balance between providing adequate certainty to 
transmission developers to support capital investment, such that more 
efficient or cost-effective Long-Term Transmission Facilities actually 
may be developed, and mitigating the inherent uncertainty involved in 
Long-Term Regional Transmission Planning, given that continued 
selection of Long-Term Regional Transmission Facilities that no longer 
meet selection criteria could be costly to consumers.\1304\ 
Specifically, though several rehearing parties object that reevaluation 
should be required in additional circumstances, such as whenever there 
is a reduction in benefits,\1305\ whenever there is a change in 
transmission needs,\1306\ or at points of time beyond the ``pencils-
down'' date,\1307\ and others argue that the transmission provider 
should have more discretion to determine when to reevaluate previously 
selected Long-Term Regional Transmission Facilities,\1308\ we continue 
to find that such open-ended allowance for reevaluation would fail to 
account for the degree of certainty that is needed to support capital 
investment, and would therefore fail to adequately ensure development 
of more efficient or cost-effective Long-Term Regional Transmission 
Facilities.\1309\
---------------------------------------------------------------------------

    \1302\ See e.g., East Kentucky Rehearing Request at 2; NRECA 
Rehearing Request at 33.
    \1303\ See e.g., ITC Rehearing Request at 15-19; MISO TOs 
Rehearing Request at 17-19.
    \1304\ Order No. 1920, 187 FERC ] 61,068 at P 1054.
    \1305\ Large Public Power Rehearing Request at 17-19; NRECA 
Rehearing Request at 29-30.
    \1306\ NRECA Rehearing Request at 30-32.
    \1307\ Id. at 33.
    \1308\ Dominion Rehearing Request at 17; SERTP Sponsors 
Rehearing Request at 20-21.
    \1309\ Order No. 1920, 187 FERC ] 61,068 at P 1053.
---------------------------------------------------------------------------

    498. On the other hand, we also reject requests to eliminate the 
requirement to reevaluate facilities where significant changes in laws 
or regulations cause reasonable concern that a previously selected 
Long-Term Regional Transmission Facility may no longer meet the 
transmission provider's selection criteria.\1310\ We remain concerned 
that, absent an opportunity to determine whether selection of such a 
facility remains warranted in light of a significant change in laws or 
regulations, transmission providers may be reluctant to select certain 
Long-Term Regional Transmission Facilities,\1311\ and we find that 
requiring reevaluation in such a circumstance helps to mitigate the 
inherent uncertainty of Long-Term Regional Transmission Planning and 
the risk of over-building transmission facilities. With the limitations 
we impose--i.e., that such reevaluation only occur for facilities with 
a targeted in-service date that is in the latter half of the Long-Term 
Regional Transmission Planning cycle in which it is selected and that 
reevaluation may only occur up to the ``pencils-down'' point in the 
facility's development--we are not persuaded that reevaluation under 
these circumstances will create such uncertainty for transmission 
developers as to significantly impede the development of more efficient 
of cost-effective Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \1310\ ITC Rehearing Request at 4-5.
    \1311\ Order No. 1920, 187 FERC ] 61,068 at P 1056.
---------------------------------------------------------------------------

    499. While we appreciate rehearing parties' concerns that assessing 
a change in a transmission facility's benefits is more complex than 
assessing a change in its costs, we decline requests to set aside the 
requirement to account for updated benefits when transmission providers 
reevaluate a Long-Term Regional Transmission Facility based on a 
significant increase in the facility's estimated costs.\1312\ We 
continue to find that such a requirement will help to ensure there is 
an opportunity to select more efficient or cost-effective Long-Term 
Regional Transmission Facilities, because otherwise the transmission 
provider would compare the facility's currently determined costs with 
its previously determined benefits.\1313\
---------------------------------------------------------------------------

    \1312\ MISO TOs Rehearing Request at 17-19; ITC Rehearing 
Request at 15-19.
    \1313\ Order No. 1920, 187 FERC ] 61,068 at P 1059.
---------------------------------------------------------------------------

    500. We further find that rehearing parties' concerns about the 
burdens of accounting for updated benefits are misplaced, as Order No. 
1920 provided significant flexibility to transmission providers as to 
how to account for changes in benefits. While Order No. 1920 requires 
that such reevaluations must only occur during a subsequent Long-Term 
Regional Transmission Planning cycle (i.e., rather than in between such 
cycles) because doing so during such a cycle enables transmission 
providers to make use of updated assumptions, inputs, and the Long-Term 
Scenarios that must be developed in any event during the subsequent 
cycle, Order No. 1920 does not prescribe any particular method for 
assessing updated benefits.\1314\ We note that, because Order No. 1920 
provides transmission providers the flexibility to propose qualitative 
measures in their evaluation processes and qualitative selection 
criteria, transmission providers will need flexibility to develop a 
process for determining if a previously selected Long-Term Regional 
Transmission Facility continues to meet those selection criteria.
---------------------------------------------------------------------------

    \1314\ This clarification resolves WIRES's request for 
clarification regarding the flexibility allowed transmission 
providers to determine how to account for updated benefits. See 
WIRES Rehearing Request at 14.
---------------------------------------------------------------------------

    501. We are also not persuaded by rehearing parties' arguments that 
the reevaluation requirements will undermine the ability of 
transmission providers to use a portfolio approach to evaluating 
benefits or selecting Long-Term Regional Transmission Facilities.\1315\ 
As described above, transmission providers have significant flexibility 
to determine how to update benefits, and they may propose to use a 
method that accommodates Order No. 1920's reevaluation requirements in 
the context of portfolio approaches to selecting Long-Term Regional 
Transmission Facilities. Likewise, provided the process seeks to 
maximize benefits accounting for costs over time without over-building 
transmission facilities, transmission providers have significant 
flexibility to determine the appropriate outcomes that may result from 
reevaluation, including the potential mitigation measures that may

[[Page 97270]]

be regionally appropriate.\1316\ Thus, transmission providers have 
scope to tailor both how reevaluation is conducted and the outcomes of 
the reevaluation process to the portfolio approach.
---------------------------------------------------------------------------

    \1315\ ITC Rehearing Request at 6-9; MISO TOs Rehearing Request 
at 17-19.
    \1316\ Order No. 1920, 187 FERC ] 61,068 at P 1052.
---------------------------------------------------------------------------

E. Implementation of Long-Term Regional Transmission Planning

1. Order No. 1920 Requirements
    502. In Order No. 1920, the Commission required transmission 
providers to explain on compliance how the initial timing sequence for 
Long-Term Regional Transmission Planning interacts with existing 
regional transmission planning processes. The Commission required 
transmission providers to provide in their explanations any information 
necessary to ensure that stakeholders understand this interaction, 
including at least the following two components. First, the Commission 
required transmission providers to address the possible interaction 
between the transmission planning cycles for Long-Term Regional 
Transmission Planning and existing Order No. 1000 regional transmission 
planning processes. The Commission recognized that there may be overlap 
in the time horizon for Long-Term Regional Transmission Planning and 
existing Order No. 1000 regional transmission planning processes and 
that these processes will likely inform each other.\1317\ Second, the 
Commission required transmission providers to address the possible 
displacement of regional transmission facilities from the existing 
regional transmission planning processes. The Commission recognized 
that it is possible that, in some cases, Long-Term Regional 
Transmission Facilities selected to address Long-Term Transmission 
Needs may provide near-term reliability or economic benefits, and thus 
could displace regional transmission facilities that are under 
consideration as part of existing regional transmission planning 
processes.\1318\
---------------------------------------------------------------------------

    \1317\ Id. P 1071.
    \1318\ Id.
---------------------------------------------------------------------------

    503. The Commission found that transmission providers should have 
the flexibility to integrate the existing regional transmission 
planning processes with Long-Term Regional Transmission Planning in a 
manner that mitigates the potential for disruption of the existing 
regional transmission planning processes. However, the Commission 
expressed concern that too much flexibility for transmission providers 
with respect to the date by which they must begin the first Long-Term 
Regional Transmission Planning cycle could lead to unnecessary delay in 
realizing these beneficial reforms for customers. Thus, the Commission 
required transmission providers in each transmission planning region to 
propose on compliance a date, no later than one year from the date on 
which initial filings to comply with the final rule are due, on which 
they will commence the first Long-Term Regional Transmission Planning 
cycle. The Commission stated that transmission providers in a 
transmission planning region may propose to start the first Long-Term 
Regional Transmission Planning cycle on a date later than one year from 
the initial compliance filing due date, only to the extent needed to 
align the Long-Term Regional Transmission Planning cycle with existing 
transmission planning cycles.\1319\ While the Commission encouraged 
transmission providers to align transmission planning cycles if useful, 
to ensure that there is no inappropriate delay to starting Long-Term 
Regional Transmission Planning, the Commission stated that transmission 
providers in a transmission planning region that propose a commencement 
date of later than one year from the compliance due date must include 
adequate support explaining how the proposed date to begin the first 
Long-Term Regional Transmission Planning cycle is necessary and 
appropriately tailored for their transmission planning region.\1320\
---------------------------------------------------------------------------

    \1319\ Id. P 1072.
    \1320\ Id.
---------------------------------------------------------------------------

    504. The Commission encouraged transmission providers to address in 
their explanations how their proposed Long-Term Regional Transmission 
Planning would facilitate moving beyond piecemeal transmission 
expansion to address relatively near-term transmission needs and toward 
a more robust, well-planned transmission system.\1321\
---------------------------------------------------------------------------

    \1321\ Id. P 1073.
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    505. PJM states that it recognizes that the long-term transmission 
planning horizon can and will inform Order No. 1000 processes but 
argues that it is imperative that these two processes function 
effectively together so that PJM can respond to short-term needs 
quickly and nimbly.\1322\ Accordingly, PJM requests flexibility in 
designing its Long-Term Regional Transmission Planning process in a way 
that would minimize harmful interaction from the overlap between Order 
No. 1000 and Order No. 1920 regional transmission planning processes 
and would allow for the efficient use of PJM's resources.\1323\
---------------------------------------------------------------------------

    \1322\ PJM Rehearing Request at 41.
    \1323\ Id.
---------------------------------------------------------------------------

    506. TAPS asserts that Order No. 1920 does not adequately clarify 
how the Order No. 1000 economic and reliability processes and the Long-
Term Regional Transmission Planning process will interact after the 
initial implementation phase.\1324\ TAPS argues that Order No. 1920 
does not address whether, or the circumstances under which, 
transmission projects may be moved from an Order No. 1000 reliability 
or economic planning process to the Long-Term Regional Transmission 
Planning process, or vice versa.\1325\ As a result, TAPS requests that 
the Commission recognize that these regional transmission planning 
processes will continue to interact after the initial implementation of 
Long-Term Regional Transmission Planning and require that transmission 
providers demonstrate how these processes will interact on an ongoing 
basis, including how and when transmission projects may be moved 
between the two processes.\1326\
---------------------------------------------------------------------------

    \1324\ TAPS Rehearing Request at 6-9.
    \1325\ Id. at 8.
    \1326\ Id. at 6-9.
---------------------------------------------------------------------------

3. Commission Determination
    507. As an initial matter, upon further consideration, we set 
aside, in part, Order No. 1920's requirement that transmission 
providers in each transmission planning region must propose on 
compliance a date, no later than one year from the date on which 
initial filings to comply with the final rule are due, on which they 
will commence the first Long-Term Regional Transmission Planning 
cycle.\1327\ Instead, we require that transmission providers must 
propose on compliance a date, no later than two years from the date on 
which initial filings to comply with Order No. 1920 are due, on which 
they will commence the first Long-Term Regional Transmission Planning 
cycle. We find that this modification balances the need to ensure that 
transmission providers timely implement Order No. 1920's requirements 
to avoid unnecessary delay in realizing these beneficial reforms for 
customers, as explained in Order No. 1920,\1328\ with the need to 
provide transmission providers with sufficient time to implement Long-
Term Regional Transmission Planning and align the Long-Term Regional 
Transmission Planning cycle with existing

[[Page 97271]]

transmission planning cycles, which may be longer than a single year.
---------------------------------------------------------------------------

    \1327\ Order No. 1920, 187 FERC ] 61,068 at P 1072.
    \1328\ See id.
---------------------------------------------------------------------------

    508. Moreover, we modify Order No. 1920's requirement that 
transmission providers that propose a commencement date of later than 
one year from the compliance due date must include adequate support 
explaining how the proposed date to begin the first Long-Term Regional 
Transmission Planning cycle is necessary and appropriately tailored for 
their transmission planning region.\1329\ Instead, we require that 
regardless of the date that transmission providers propose on 
compliance, they must explain in their compliance filing why the 
proposed date on which they will commence the first Long-Term Regional 
Transmission Planning cycle is necessary and appropriately tailored for 
their transmission planning region. We find that this modification will 
allow the Commission to ensure that the proposed date will not 
unnecessarily delay the realization of Order No. 1920's beneficial 
reforms for customers.
---------------------------------------------------------------------------

    \1329\ See id.
---------------------------------------------------------------------------

    509. We sustain the requirement that transmission providers must 
explain on compliance how the initial timing sequence for Long-Term 
Regional Transmission Planning will interact with the existing regional 
transmission planning processes under Order No. 1000. As the Commission 
recognized in Order No. 1920, there may be overlap in the time horizons 
for these processes, and transmission providers should have the 
flexibility to integrate the existing regional transmission planning 
processes with Long-Term Regional Transmission Planning in a manner 
that mitigates the potential for disruption of the existing regional 
transmission planning processes.\1330\ While Long-Term Regional 
Transmission Planning processes must still meet all requirements set 
forth in Order No. 1920, we believe that this flexibility extends to 
and addresses concerns raised by PJM, including its request for 
flexibility to design its Long-Term Regional Transmission Planning 
process in a way that minimizes potential harmful impacts to existing 
regional transmission planning processes.
---------------------------------------------------------------------------

    \1330\ Id.
---------------------------------------------------------------------------

    510. In response to TAPS' request for rehearing, we recognize that 
Long-Term Regional Transmission Planning and existing Order No. 1000 
economic and reliability transmission planning processes may continue 
to interact after the initial implementation of Long-Term Regional 
Transmission Planning. However, while this interaction is possible, we 
believe that, after the first Long-Term Regional Transmission Planning 
cycle concludes, the overlap between the existing Order No. 1000 
regional transmission planning processes and Long-Term Regional 
Transmission Planning will likely diminish. As the Commission found in 
Order No. 1920, existing regional transmission planning processes that 
plan for reliability and economic transmission needs may in the future 
come to address only residual needs not already addressed through Long-
Term Regional Transmission Planning.\1331\ As a result, the potential 
for overlap between Long-Term Regional Transmission Planning and the 
existing Order No. 1000 regional transmission planning process should 
decrease. Further, we do not believe that it is necessary to require 
transmission providers to explain how a transmission facility selected 
in one regional transmission process may ``move'' to another regional 
transmission planning process. Nevertheless, as the Commission stated 
in Order No. 1920, we encourage transmission providers to address in 
their explanation on compliance how their proposed Long-Term Regional 
Transmission Planning process will facilitate moving beyond piecemeal 
transmission expansion to address relatively near-term transmission 
needs and toward a more robust, well-planned transmission system.\1332\
---------------------------------------------------------------------------

    \1331\ Id. P 245.
    \1332\ Id. P 1073.
---------------------------------------------------------------------------

VI. Coordination of Regional Transmission Planning and Generator 
Interconnection Processes

A. Need for Reform and Overall Requirement

1. Order No. 1920 Requirements
    511. In Order No. 1920, the Commission found that there is 
substantial evidence to support the conclusion that the Commission's 
existing regional transmission planning requirements are unjust, 
unreasonable, and unduly discriminatory or preferential because they do 
not adequately consider certain interconnection-related transmission 
needs that the transmission provider has identified multiple times in 
the generator interconnection process but that have never been resolved 
due to the withdrawal of the underlying interconnection 
request(s).\1333\ The Commission made this finding in response to 
(among other things) evidence in the record that the level of spending 
on interconnection-related network upgrades has dramatically increased 
in recent years and evidence that this trend leads to more 
interconnection requests withdrawing in the face of significant costs 
associated with interconnection-related network upgrades.\1334\ The 
Commission stated that, while interconnection customers may choose to 
withdraw from the interconnection queue for a number of reasons, in 
recent years, the deciding factor has increasingly become the 
interconnection customer's sticker shock at its cost responsibility for 
interconnection-related network upgrades.\1335\ The Commission also 
based its finding on evidence that in many cases when an 
interconnection-related transmission need is not addressed via 
development of interconnection-related network upgrades in one 
interconnection queue cycle, the same interconnection-related 
transmission need--and oftentimes the same or a substantially similar 
interconnection-related network upgrade--will appear in subsequent 
interconnection queue cycles.\1336\
---------------------------------------------------------------------------

    \1333\ Order No. 1920, 187 FERC ] 61,068 at P 1100.
    \1334\ Id. P 1101.
    \1335\ Id.
    \1336\ Id. P 1102.
---------------------------------------------------------------------------

    512. Consequently, the Commission adopted requirements for 
transmission providers in each transmission planning region to revise 
their regional transmission planning processes in their OATTs to 
evaluate for selection regional transmission facilities that address 
certain interconnection-related transmission needs associated with 
specific interconnection-related network upgrades originally identified 
through the generator interconnection process. In particular, the 
Commission adopted four qualifying criteria for when transmission 
providers must evaluate interconnection-related transmission needs in 
the regional transmission planning process. The Commission found that 
this requirement will ensure that more efficient or cost-effective 
transmission expansion can be effectuated through regional transmission 
planning processes and will eliminate a potential barrier to entry for 
new generation resources, thereby enhancing competition in wholesale 
electricity markets and facilitating access to lower-cost generation. 
The Commission stated that, as a result, this reform will ensure just 
and reasonable and not unduly discriminatory or preferential 
Commission-jurisdictional rates.\1337\
---------------------------------------------------------------------------

    \1337\ Id. PP 1106, 1145.

---------------------------------------------------------------------------

[[Page 97272]]

2. Requests for Rehearing
    513. SERTP Sponsors, Large Public Power, and Industrial Customers 
argue that this reform is premature in light of Order No. 2023, which 
is intended to, among other things, reduce speculative interconnection 
requests and withdrawals.\1338\ SERTP Sponsors argue that the 
Commission should grant rehearing and revisit this reform after 
experience is gained to determine whether interconnection withdrawals 
could ``reasonably be expected to be indicative of a need for new 
regional transmission facilities that have `a voltage of at least 200 
kV and an estimated cost of at least $30 million.' '' \1339\ SERTP 
Sponsors argue that accordingly, the Commission has not established a 
rational basis supported by substantial evidence for this 
requirement.\1340\
---------------------------------------------------------------------------

    \1338\ SERTP Sponsors Rehearing Request at 22; Large Public 
Power Rehearing Request at 23; Industrial Customers Rehearing 
Request at 46-47.
    \1339\ SERTP Sponsors Rehearing Request at 22 (citing Order No. 
1920, 187 FERC ] 61,068 at P 1145).
    \1340\ Id. at 22-23 (citing Samaritan Health Serv. v. Bowen, 811 
F.2d 1524, 1528 (D.C. Cir. 1987) (finding that agency's 
classification of costs had ``no rational basis'' and was, 
therefore, arbitrary and capricious)).
---------------------------------------------------------------------------

    514. PJM argues that the Commission failed to provide substantial 
evidence for its conclusion that, nationwide, the deciding factor for 
interconnection customers' withdrawals is sticker shock at their 
assigned network upgrade costs.\1341\ PJM argues that the Commission 
ignored its analysis of more than 700 interconnection requests in one 
transmission zone over a six-year period that demonstrated that only 14 
requests or 2% would have likely met the voltage and cost thresholds in 
Order No. 1920 and that nine of the 14 withdrew before a feasibility 
study was issued. Additionally, PJM argues that, of the remaining five, 
two were ultimately responsible for network upgrades of less than $30 
million, thus leaving only three interconnection requests potentially 
withdrawing due to the cost of network upgrades.\1342\ PJM argues that 
this data suggesting a withdrawal rate of less than one half percent in 
a large sample indicates insignificant correlation between network 
upgrade costs, voltage level, and business decisions to withdraw.\1343\
---------------------------------------------------------------------------

    \1341\ PJM Rehearing Request at 31.
    \1342\ Id.
    \1343\ Id.
---------------------------------------------------------------------------

    515. PJM further argues that, on the other hand, over the past six 
years, several dozen generation projects that executed interconnection 
agreements had associated network upgrades of less than $5 million but 
nonetheless terminated their interconnection agreements. Thus, PJM 
argues that factors other than sticker shock are common reasons for 
delay or failure to advance.\1344\ PJM argues that the Commission 
disregarded this evidence and relied on studies in MISO and SPP to 
justify a one-size-fits-all approach, and it argues that this decision 
was arbitrary and capricious.\1345\ NRECA argues that if the Commission 
believes that its existing generator interconnection polices are unjust 
and unreasonable and impose barriers to generation development, it 
should develop the appropriate evidentiary record, make the required 
findings, and direct a just and reasonable replacement policy.\1346\
---------------------------------------------------------------------------

    \1344\ PJM Rehearing Request at 32.
    \1345\ Id. at 32 (citing 5 U.S.C. 706(2); 16 U.S.C. 825l(b); 
S.C. Pub. Serv. Auth., 762 F.3d at 66-67; TAPS, 225 F.3d at 687; 
Env't Def. Fund, 2 F.4th 953).
    \1346\ NRECA Rehearing Request at 48-49.
---------------------------------------------------------------------------

3. Commission Determination
    516. We continue to find that this reform will ensure just and 
reasonable and not unduly discriminatory or preferential Commission-
jurisdictional rates.\1347\ While SERTP Sponsors, Large Public Power, 
and Industrial Customers argue that this reform is premature in light 
of Order No. 2023, we find that the scope of the Order No. 1920 
coordination reform operates independently of, and is more limited 
than, the Order No. 2023 reforms. Order No. 2023 adopts reforms to the 
generator interconnection process through changes to the pro forma 
generation interconnection procedures and agreements. By comparison, 
Order No. 1920 adopts no changes to the generator interconnection 
process and instead implements the coordination reform through changes 
to the transmission planning process and the pro forma OATT.
---------------------------------------------------------------------------

    \1347\ Order No. 1920, 187 FERC ] 61,068 at P 1106.
---------------------------------------------------------------------------

    517. Additionally, the purpose of the coordination reform in Order 
No. 1920 is to address a specific problem--insufficient coordination 
between the existing generator interconnection processes and regional 
transmission planning and cost allocation processes regarding 
interconnection-related transmission needs that are repeatedly 
identified in the generator interconnection process.\1348\ Order No. 
1920 recognizes the generator interconnection process is unlikely to 
result in the construction of transmission facilities that resolve such 
interconnection-related transmission needs because of the rate of 
withdrawal from the interconnection queue, due at least in part to 
interconnection customers' cost responsibility for expensive 
interconnection-related network upgrades.\1349\ While Order No. 2023 
aims to fix inefficiencies in the generator interconnection process, it 
does not direct any reforms regarding specific interconnection-related 
network upgrades that are unlikely to be developed.
---------------------------------------------------------------------------

    \1348\ Id. P 1100.
    \1349\ See id. P 1108.
---------------------------------------------------------------------------

    518. The Commission reasonably concluded that reforms regarding 
these types of network upgrades are better addressed through 
improvement of coordination between the generator interconnection and 
regional transmission planning processes. The purpose of the Order No. 
1920 coordination reform is to (1) require evaluation of regional 
transmission facilities that address certain (i.e., that qualify under 
the criteria established in Order No. 1920) interconnection-related 
transmission needs associated with specific interconnection-related 
network upgrades in existing Order No. 1000 regional transmission 
planning and cost allocation processes to determine whether to select 
such facilities in the regional transmission plan for purposes of cost 
allocation, and (2) determine whether such facilities may address other 
regional transmission needs more efficiently or cost-effectively. For a 
limited set of interconnection-related transmission needs, this reform 
will allow transmission providers to identify, evaluate, and select the 
more efficient or cost-effective regional transmission solution 
independent of the success or failure of a particular interconnection 
request in the generator interconnection process. Additionally, if this 
requirement is triggered (i.e., because interconnection-related network 
upgrades meet all of the established qualifying criteria), that is an 
indication of the continued existence of the concerns described in 
Order No. 1920, namely a barrier to entry in locations that, absent 
sticker shock, are ``otherwise desirable for generators to locate.'' 
\1350\ Moreover, it may be that eventually, as a result of Order No. 
2023, fewer withdrawals from the generator interconnection queue occur 
and that this provision is triggered less often. Further, there may be 
fewer instances of this requirement as the Order No. 1920 Long-Term 
Regional Transmission Planning process proactively addresses 
transmission needs related to generation additions on a forward-looking 
basis. These

[[Page 97273]]

developments would not, however, address the present concerns that 
necessitate this coordination requirement. Given the low administrative 
burden associated with this reform,\1351\ we conclude that its 
potential benefits outweigh the costs.
---------------------------------------------------------------------------

    \1350\ Id. P 1103.
    \1351\ See id. P 1113.
---------------------------------------------------------------------------

    519. We disagree with PJM's claim that the Commission does not 
provide substantial evidence to demonstrate that existing Order No. 
1000 regional transmission planning and cost allocation processes do 
not adequately address interconnection-related transmission needs 
associated with withdrawn interconnection requests. PJM's claim is 
unpersuasive because, as explained above, the Commission has 
sufficiently demonstrated the need for reform.
    520. The Commission in Order No. 1920 also explained why it is 
appropriate to establish the coordination requirement in existing Order 
No. 1000 regional transmission planning and cost allocation processes, 
stating that:

    Evaluation of interconnection-related transmission needs in the 
existing Order No. 1000 regional transmission planning and cost 
allocation processes is most appropriate because such evaluation 
would occur at shorter intervals and would likely result in more 
expeditious development of regional transmission facilities to 
address the nearer-term interconnection-related transmission needs 
identified through the generator interconnection process.\1352\
---------------------------------------------------------------------------

    \1352\ Id. P 1126.

    521. Further, courts have recognized the Commission can rely on 
general findings of systemic conditions to impose an industry-wide 
remedy under FPA section 206.\1353\ The Commission found that there was 
substantial evidence to conclude that the Commission's existing 
regional transmission planning requirements are unjust, unreasonable, 
and unduly discriminatory or preferential because they do not 
adequately consider certain interconnection-related transmission needs 
that the transmission provider has identified multiple times in the 
generator interconnection process but that have never been resolved due 
to the withdrawal of the underlying interconnection request(s).\1354\
---------------------------------------------------------------------------

    \1353\ See TAPS, 225 F.3d at 687-88 S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d at 67 (citing Interstate Nat. Gas Ass'n of Am. v. 
FERC, 285 F.3d at 37).
    \1354\ Id. PP 1100-05.
---------------------------------------------------------------------------

    522. We also are not persuaded by the evidence that PJM presented 
in this proceeding, which it argues demonstrates that only a small 
fraction of network upgrades that are the subject of its analysis would 
meet the voltage and cost thresholds established by Order No. 1920. We 
do not reach the same conclusions as PJM for multiple reasons. To 
begin, PJM's evidence pertains only to the Dominion zone in PJM from 
2014 to 2020 and is not necessarily reflective of circumstances across 
the region, or nationwide, or over different time periods. Further, in 
Order No. 1920, the Commission cited to evidence from the record to 
support the conclusion that, in recent years, sticker shock over an 
interconnection customer's assigned network upgrade costs is often the 
deciding factor that leads to that interconnection customer's 
withdrawal of its interconnection request.\1355\ For instance, the 
Commission cited analysis from a report showing that between January 
2016 and July 2020, 245 generation projects in advanced stages in the 
MISO generator interconnection process withdrew from the queue, with 
the project developers citing high interconnection-related network 
upgrade costs as the primary reason for their withdrawal.\1356\
---------------------------------------------------------------------------

    \1355\ See, e.g., id. P 1101 (citing See ACORE ANOPR Comments at 
12; D.C. and Maryland Office of People's Counsel Initial Comments at 
16; Invenergy Reply Comments at 14; Northwest and Intermountain 
Initial Comments at 14; see also Improvements to Generator 
Interconnection Procs. & Agreements, Order No. 2023, 88 FR 61014 
(Sept. 6, 2023), 184 FERC ] 61,054, at 41, order on reh'g, Order No. 
2023-A, 89 FR 27006 (Apr. 16, 2024), 186 FERC ] 61,199, at P 14 
(2024).
    \1356\ Id. (citing Jay Caspary et al., ACEG, Disconnected: The 
Need for a New Generator Interconnection Policy, 14 (2021)), https://cleanenergygrid.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-aNew-Generator-Interconnection-Policy-1.pdf (ACEG 2021 
Interconnection Report) at 17.
---------------------------------------------------------------------------

    523. We also disagree with PJM's interpretation of its data, namely 
the claim that there is no need for reform because the data shows that 
the number of withdrawals due to sticker shock is small. PJM's 
reasoning suggests that the Commission found that sticker shock is only 
ever a deciding factor for an interconnection request's withdrawal if 
the withdrawn interconnection request was allocated interconnection-
related network upgrade costs of $30 million or more or has a voltage 
of at least 200 kV (i.e., the cost and voltage thresholds established 
by Order No. 1920 to limit the applicability of this new requirement). 
However, the Commission did not suggest that interconnection-related 
network upgrades below this cost threshold or below the 200 kV voltage 
threshold do not cause sticker shock. Instead, the established 
qualifying criteria are intended to strike a reasonable balance between 
precision and workability.\1357\ To accomplish this workability, the 
Commission adopted requirements that do not require evaluation in the 
existing Order No. 1000 regional transmission planning and cost 
allocation processes of all interconnection-related transmission needs 
that were not addressed because the corresponding interconnection 
request withdrew in part or entirely due to sticker shock. Instead, as 
the Commission stated in Order No. 1920, the established criteria are 
necessary to limit the scope of the requirement to interconnection-
related transmission needs associated with high-cost interconnection-
related network upgrades ``that are likely to persist, . . . not unique 
to a single interconnection request, and . . . that have the potential 
to provide more widespread benefits to transmission customers.'' \1358\ 
We again find that this targeted approach and criteria are ``broad 
enough to capture interconnection-related network upgrades that are 
likely to produce benefits beyond the interconnection customer'' while 
retaining flexibility for transmission providers.\1359\
---------------------------------------------------------------------------

    \1357\ See id. P 1147.
    \1358\ Id. P 1148.
    \1359\ Id. P 1149.
---------------------------------------------------------------------------

    524. In response to NRECA, we note that the focus of Order No. 1920 
is to remedy deficiencies in the regional transmission planning and 
cost allocation requirements and not the generator interconnection 
process. Nonetheless, we reiterate the findings in Order No. 1920 that 
the repeated identification of interconnection-related network upgrades 
in the generator interconnection process is indicative of a ``barrier 
to accessing the transmission system and [establishes] a known 
interconnection-related transmission need . . . [that] can hinder the 
timely development of new generation, thereby stifling competition in 
wholesale electricity markets and limiting access to lower-cost 
generation'' and that by ``failing to consider such interconnection-
related transmission needs, the regional transmission planning process 
is unable to identify the more efficient or cost-effective regional 
transmission solutions.'' \1360\
---------------------------------------------------------------------------

    \1360\ Id. P 1103.
---------------------------------------------------------------------------

B. Qualifying Criteria

1. Order No. 1920 Requirements
    525. In Order No. 1920, the Commission required transmission 
providers to evaluate for selection in their existing Order No 1000 
regional transmission planning processes regional transmission 
facilities to address interconnection-related transmission needs that 
have been identified in the generator

[[Page 97274]]

interconnection process by meeting four qualifying criteria. 
Specifically, the Commission required transmission providers to 
evaluate interconnection-related network upgrades where: (1) the 
transmission provider has identified interconnection-related network 
upgrades in interconnection studies to address those interconnection-
related transmission needs in at least two interconnection queue cycles 
during the preceding five years (looking back from the effective date 
of the Commission-accepted tariff provisions proposed to comply with 
this reform, and the later-in-time withdrawn interconnection request 
occurring after the effective date of the Commission-accepted tariff 
provisions); (2) an interconnection-related network upgrade identified 
to meet those interconnection-related transmission needs has a voltage 
of at least 200 kV and an estimated cost of at least $30 million; (3) 
such interconnection-related network upgrade(s) have not been developed 
and are not currently planned to be developed because the 
interconnection request(s) driving the need for the network upgrade(s) 
has been withdrawn; and (4) the transmission provider has not 
identified an interconnection-related network upgrade to address the 
relevant interconnection-related transmission need in an executed 
generator interconnection agreement or in a generator interconnection 
agreement that the interconnection customer requested that the 
transmission provider file unexecuted with the Commission.\1361\
---------------------------------------------------------------------------

    \1361\ Id. P 1145.
---------------------------------------------------------------------------

    526. The Commission found it necessary to establish these criteria 
to limit the scope of the requirement to those interconnection-related 
transmission needs that are likely to persist, are not unique to a 
single interconnection request, and might be addressed by regional 
transmission facilities that have the potential to provide more 
widespread benefits to transmission customers.\1362\ The Commission 
found that these criteria strike a reasonable balance between precision 
and workability, and that each of the four criteria is necessary to 
identify the appropriate set of interconnection-related transmission 
needs.\1363\ The Commission further found that the purpose of the 
criteria established in Order No. 1920 is to limit the number of 
interconnection-related transmission needs that transmission providers 
must evaluate to those that merit consideration in the existing Order 
No. 1000 regional transmission planning and cost allocation 
processes.\1364\
---------------------------------------------------------------------------

    \1362\ Id. P 1146.
    \1363\ Id. PP 1146-1147.
    \1364\ Id. P 1150.
---------------------------------------------------------------------------

    527. As relevant here, the Commission proposed in the NOPR that 
part of the criteria regarding interconnection-related transmission 
needs is met where an interconnection-related network upgrade 
identified to meet interconnection-related transmission needs in the 
generator interconnection process has a voltage of at least 200 kV and/
or an estimated cost of at least $30 million.\1365\ In Order No. 1920, 
the Commission found it necessary and just and reasonable to modify the 
NOPR proposal such that any interconnection-related network upgrade 
identified to meet that interconnection-related transmission need must 
have a voltage of at least 200 kV and an estimated cost of at least $30 
million (the cost-and-voltage criterion).\1366\ The Commission found it 
necessary to establish a cost threshold that is stringent enough to 
capture those interconnection-related network upgrades that are likely 
to have caused the underlying interconnection requests to withdraw and 
a voltage threshold that is high enough that any regional transmission 
facility evaluated to address the underlying interconnection-related 
transmission need(s) is likely to produce benefits that extend beyond 
the interconnection customer.\1367\ The Commission provided additional 
support for the voltage threshold in stating that the Commission has 
also previously found, and the record demonstrates, that higher-voltage 
transmission facilities are more likely to provide widespread benefits 
to transmission customers.\1368\
---------------------------------------------------------------------------

    \1365\ Id. P 1130.
    \1366\ Id. PP 1145, 1150-1151.
    \1367\ Id. P 1151.
    \1368\ Id. P 1146, n. 2433.
---------------------------------------------------------------------------

    528. The Commission stated that requiring an interconnection-
related network upgrade identified to meet an interconnection-related 
transmission need to satisfy both the cost and voltage criteria will 
prevent transmission providers from evaluating interconnection-related 
transmission needs associated with interconnection-related network 
upgrades that are less likely to provide more widespread benefits to 
transmission customers.\1369\ The Commission found that requiring both 
the cost threshold and the voltage threshold be met better limits the 
scope of the reform compared to the NOPR proposal and thus the reform 
is more likely to produce a smaller and more practicable set of 
interconnection-related needs that transmission providers must evaluate 
in their existing Order No. 1000 regional transmission planning 
processes.\1370\ The Commission also stated that the change to require 
that both the cost threshold and the voltage threshold be met addresses 
commenters' concerns that relying on only one threshold would identify 
interconnection-related network upgrades that are less likely to 
provide more widespread benefits to transmission customers.\1371\
---------------------------------------------------------------------------

    \1369\ Id. P 1152.
    \1370\ Id. P 1146; id. P 1151; id. P 1153.
    \1371\ Id. P 1153 (citing Pine Gate Initial Comments at 32; SEIA 
Initial Comments at 15; US DOE Initial Comments at 28.).
---------------------------------------------------------------------------

    529. In Order No. 1920, the Commission also established as another 
qualifying criterion that transmission providers must have identified 
interconnection-related network upgrades in interconnection studies to 
address the same interconnection-related transmission need in at least 
two interconnection queue cycles during the preceding five years 
(repeat identification criterion).\1372\ Like for the cost-and-voltage 
criterion, the Commission stated that the repeat identification 
criterion provides an important limit on the extent to which evaluation 
of regional transmission facilities to address interconnection-related 
transmission needs is required.\1373\ The Commission further explained 
that repeat identification indicates that the constraint that the 
interconnection-related network upgrades were identified to address is 
not unique to a single interconnection request at a single point in 
time and that the interconnection-related transmission need is likely 
to persist.\1374\ The Commission explained that, if it did not limit 
the requirements in this way, the burden of evaluation would be greater 
because transmission providers could have to evaluate more 
interconnection-related transmission needs.\1375\
---------------------------------------------------------------------------

    \1372\ Id. P 1145.
    \1373\ Id. P 1150.
    \1374\ Id. PP 1150, 1158.
    \1375\ Id. P 1150.
---------------------------------------------------------------------------

    530. The Commission also clarified the timing of the requirement 
that transmission providers have identified interconnection-related 
network upgrades in interconnection studies to address those 
interconnection-related transmission needs in at least two 
interconnection queue cycles during the preceding five years.\1376\ The 
Commission explained that this five-year period means looking back from 
the effective date of the Commission-

[[Page 97275]]

accepted tariff provisions proposed to comply with this reform and the 
later-in-time withdrawn interconnection request occurring after the 
effective date of the Commission-accepted tariff provisions.\1377\ 
Separately, the Commission explained that transmission providers must 
evaluate an interconnection-related transmission need that has been 
previously identified multiple times within the five years prior to the 
effective date of the Commission-accepted tariff provisions but never 
been resolved due to the withdrawal of the underlying interconnection 
request(s).\1378\ The Commission also clarified that if there are no 
``queue cycles'' in the preceding five-year period because the 
transmission provider uses a first-come, first-served serial 
interconnection process, then this criterion will be met if the 
interconnection-related transmission need is identified in at least two 
individual interconnection studies during the preceding five-year 
period for interconnection customers that subsequently withdrew from 
the interconnection queue.\1379\ Finally, the Commission stated that 
evaluation for selection of regional transmission facilities that 
address certain (i.e., that qualify under the criteria established in 
Order No. 1920) identified interconnection-related transmission needs 
must occur in the first Order No. 1000 regional transmission planning 
and cost allocation processes cycle that commences after the later-in-
time withdrawn interconnection request occurring after the effective 
date of the accepted tariff provisions.\1380\
---------------------------------------------------------------------------

    \1376\ Id. PP 1145, 1158-1160.
    \1377\ Id. P 1145.
    \1378\ Id. P 1159.
    \1379\ We note that this accommodation will eventually become 
moot because transmission provides that do not already do so must 
transition to a cluster study rather than a serial process pursuant 
to the requirements of Order No. 2023. See Order No. 2023, 184 FERC 
] 61,054 at P 223.
    \1380\ Order No. 1920, 187 FERC ] 61,068 at P 1159.
---------------------------------------------------------------------------

    531. For both the cost-and-voltage criterion and the repeat 
identification criterion, the Commission disagreed with commenters that 
argued for the adoption of different criteria or for the elimination of 
one or both criteria and found that requiring both criteria is just and 
reasonable.\1381\
---------------------------------------------------------------------------

    \1381\ Id. P 1150 (citations omitted).
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    532. Clean Energy Associations contend that the Commission acted 
arbitrarily and capriciously and failed to engage in reasoned decision-
making by adopting the cost-and-voltage criterion and repeat 
identification criterion.\1382\ Clean Energy Associations ask that the 
Commission, at a minimum, only require either a voltage criterion or 
cost criterion, such that the eligibility threshold is met if an 
interconnection-related network upgrade has a voltage of at least 200 
kV or an estimated cost of at least $30 million.\1383\ Clean Energy 
Associations also request that the Commission grant rehearing to change 
the repeat identification criterion, such that the criterion is met if 
an interconnection-related network upgrade was identified in at least 
one interconnection queue cycle.\1384\ Separately, Clean Energy 
Associations ask the Commission to clarify that the time period 
transmission providers must use to identify interconnection-related 
network upgrades for inclusion in the initial regional transmission 
planning cycle exceeds five years, or alternatively, grant rehearing to 
require so.\1385\
---------------------------------------------------------------------------

    \1382\ Clean Energy Associations Rehearing Request at 13-22.
    \1383\ Id. at 21-22.
    \1384\ Id.
    \1385\ Id. at 22-26.
---------------------------------------------------------------------------

    533. As to the cost-and-voltage criterion, Clean Energy 
Associations contend that the Commission acted arbitrarily and 
capriciously because it failed to explain how interconnection-related 
network upgrades that satisfy both the voltage threshold and cost 
threshold (as required in Order No. 1920) are more likely to provide 
widespread benefits to customers compared to interconnection-related 
network upgrades that meet only the voltage threshold or only the cost 
threshold (as proposed in the NOPR).\1386\ Clean Energy Associations 
claim that the Commission ignored record evidence and adopted 
eligibility criteria that arbitrarily exclude lower voltage facilities 
that cost more than $30 million from consideration in regional 
transmission planning processes regardless of the degree to which those 
interconnection-related network upgrades benefit transmission 
customers.\1387\ Clean Energy Associations assert that the Commission 
ignored evidence that requiring both the cost threshold and the voltage 
threshold to be met is even more harmful in certain parts of the 
country.\1388\
---------------------------------------------------------------------------

    \1386\ Id. at 13-14.
    \1387\ Id. at 15 (citing Order No. 1920, 187 FERC ] 61,068 at P 
1137 (referencing comments of Pattern Energy, Pine Gate, and 
Shell)).
    \1388\ Id. (citing Order No. 1920, 187 FERC ] 61,068 at P 1140 
(referencing comments of PJM)).
---------------------------------------------------------------------------

    534. Clean Energy Associations also claim that the Commission 
mischaracterized certain comments opposing the imposition of a 
requirement to meet both the cost threshold and the voltage threshold 
as comments favoring ``elimination of one or both criteria'' when many 
of such comments actually support what Clean Energy Associations refer 
to as the ``flexibility'' in the NOPR that only required an 
interconnection-related network upgrade to satisfy one of the 
thresholds to be eligible for evaluation.\1389\ Clean Energy 
Associations further argue that the record shows that the NOPR's 
``flexibility'' is more likely to identify interconnection-related 
transmission needs that warrant evaluation compared to the requirements 
in Order No. 1920, because Order No. 1920's requirement to meet both 
the cost threshold and the voltage threshold unduly limits the universe 
of transmission solutions in a manner that jeopardizes transmission 
providers' ability to evaluate transmission solutions that might be 
more efficient or cost-effective than other options.\1390\ Clean Energy 
Associations claim that the Commission did not directly address the 
record evidence and arguments on this issue, which renders this aspect 
of the Order No. 1920 arbitrary and capricious.\1391\
---------------------------------------------------------------------------

    \1389\ Id. at 16 (citing Pattern Energy Initial Comments at 28; 
Pine Gate Initial Comments at 32; Interwest Initial Comments at 3, 
11).
    \1390\ Id. at 16-17.
    \1391\ Id. at 17.
---------------------------------------------------------------------------

    535. On the repeat identification criterion, Clean Energy 
Associations contend that this criterion is arbitrary and inconsistent 
with Order No. 1920's goal of removing barriers to entry, increasing 
competition, and promoting more efficient or cost-effective solutions 
to interconnection-related transmission needs.\1392\ Clean Energy 
Associations believe that the repeat identification criterion will 
render Order No. 1920's reforms to coordinate the regional transmission 
planning and generator interconnection processes ineffective for 
several reasons that the Commission failed to address, including the 
Commission's shift to cluster-based studies, the self-defeating nature 
of the repeat identification criterion, and the adverse effects of the 
repeat identification criterion in conjunction with the cost-and-
voltage criterion.\1393\ Clean Energy Associations claim that the 
Commission also ignored substantial record evidence and arguments 
relevant to the eligibility criteria and that the Commission's stated 
rationale for

[[Page 97276]]

adopting its unduly restrictive criteria ``does not hold water.'' 
\1394\
---------------------------------------------------------------------------

    \1392\ Id. at 18.
    \1393\ Id. at 18-21.
    \1394\ Id. at 20-21 (quoting e.g., Interwest Initial Comments at 
11 (``the NOPR imposes so many procedural hurdles that . . . it 
could not be expected to produce results . . . requiring that the 
same interconnection upgrades be identified twice . . . is simply 
impractical'')).
---------------------------------------------------------------------------

    536. Clean Energy Associations also request clarification on two 
issues related to the time period for the repeat identification 
criterion. First, Clean Energy Associations request that the Commission 
clarify that, for each transmission provider's initial regional 
transmission planning cycle under an Order No. 1920-compliant tariff, 
the review window for identifying interconnection-related network 
upgrades that are required to be considered as interconnection-related 
transmission needs may span more than five years in duration.\1395\ As 
an example, Clean Energy Associations state that:
---------------------------------------------------------------------------

    \1395\ Id. at 23-24.

if a transmission provider's Order No. 1920-compliant tariff takes 
effect on August 1, 2025, [and] the first regional transmission 
planning cycle in which interconnection-related transmission needs 
must be considered commences on August 1, 2027, and the date on 
which the transmission provider will identify the transmission 
solutions to be evaluated in that planning cycle is April 1, 2028, 
then the transmission provider must include for evaluation any 
network upgrades that were identified in interconnection cycles 
between August 1, 2020 (i.e., five years before the effective date) 
and April 1, 2028 (i.e., the date on which transmission solutions 
are identified for inclusion in the transmission planning process) 
and that meet the eligibility criteria. In that hypothetical 
example, the total time-period over which network upgrades could be 
identified for evaluation as interconnection-related transmission 
needs is seven years and nine months.\1396\
---------------------------------------------------------------------------

    \1396\ Id. at 24.

    537. Second, noting the requirement in Order No. 1920, Clean Energy 
Associations request that the Commission clarify that any eligible 
interconnection-related network upgrade that is identified in any two 
interconnection cycles within the review window--even if both 
occurrences took place in the five years prior to the effective date--
must be evaluated in the transmission providers' initial Order No. 1000 
regional transmission planning cycle following the effective date of 
its Order No. 1920 compliance filing.\1397\ Clean Energy Associations 
argue that there is no reason why the ``later in time withdrawn 
interconnection request'' must occur after the ``effective date of the 
Commission-accepted tariff provisions'' rather than at any point during 
the relevant lookback period. Clean Energy Associations claim that, 
absent the requested clarification, the Commission acted arbitrarily 
and capriciously and failed to engage in reasoned decision-making by 
failing to clearly identify the time period at which transmission 
providers must look to implement this reform.\1398\
---------------------------------------------------------------------------

    \1397\ Id. at 25 (citing Order No. 1920, 187 FERC ] 61,068 at P 
1145 (establishing the requirement that the time period is ``the 
preceding five years (looking back from the effective date of the 
Commission-accepted tariff provisions proposed to comply with this 
reform, and the later-in-time withdrawn interconnection request 
occurring after the effective date of the Commission-accepted tariff 
provisions)'')).
    \1398\ Id. at 3, 25.
---------------------------------------------------------------------------

3. Commission Determination
    538. We disagree with Clean Energy Associations' requests for 
rehearing and decline to revise the cost-and-voltage criterion and the 
repeat identification criterion. We continue to find that it is 
necessary to limit the scope of the requirement to those 
interconnection-related transmission needs that are likely to persist, 
are not unique to a single interconnection request, and might be 
addressed by regional transmission facilities that have the potential 
to provide more widespread benefits to transmission customers.\1399\ We 
reiterate the Commission's stated purpose of this reform, which is to 
address the narrow issue of interconnection-related transmission needs 
being repeatedly identified yet continuing to go unresolved through the 
generator interconnection process, even though more efficient or cost-
effective regional transmission solutions could be achieved if such 
needs were evaluated through the regional transmission planning and 
cost allocation process.\1400\
---------------------------------------------------------------------------

    \1399\ Order No. 1920, 187 FERC ] 61,068 at P 1146.
    \1400\ Id. P 1112.
---------------------------------------------------------------------------

    539. We disagree with Clean Energy Associations' argument that the 
Commission acted arbitrarily and capriciously in adopting the 
requirement to meet both the cost threshold and the voltage threshold. 
In Order No. 1920, the Commission explained how the cost threshold is 
intended to capture interconnection-related network upgrades that cause 
underlying interconnection requests to withdraw (i.e., are likely to 
persist), and the voltage threshold is intended to capture 
interconnection-related transmission needs that are likely to produce 
more widespread benefits.\1401\ These explanations for requiring that 
previously identified interconnection-related network upgrades meet 
both of these thresholds for an interconnection-related transmission 
need to satisfy the cost-and-voltage criterion are consistent with the 
Commission's stated purpose and the necessary scope of this reform. 
Namely, the cost threshold identifies interconnection-related 
transmission needs associated with prohibitive interconnection-related 
network upgrade costs that contribute to a barrier to accessing the 
transmission system, and the voltage threshold identifies 
interconnection-related transmission needs with the potential for 
transmission benefits that extend beyond the interconnection 
customer.\1402\ We also disagree with Clean Energy Associations' claim 
that the Commission ignored record evidence on this issue.\1403\ As 
stated above, the Commission adopted this reform and the associated 
qualifying criteria to address a narrow issue with limited scope, not 
to address an expansive set of interconnection-related transmission 
needs as requested by some commenters in response to the NOPR.
---------------------------------------------------------------------------

    \1401\ Id. P 1151.
    \1402\ Id. PP 1103-1104.
    \1403\ Clean Energy Associations Rehearing Request at 15 (citing 
Order No. 1920, 187 FERC ] 61,068 at P 1137 (referencing comments of 
Pattern Energy, Pine Gate, and Shell); Order No. 1920, 187 FERC ] 
61,068 at P 1140 (referencing comments of PJM)).
---------------------------------------------------------------------------

    540. We disagree with Clean Energy Associations that providing for 
the ``flexibility'' of meeting either the cost threshold or the voltage 
threshold is more consistent with Order No. 1920's objectives. Allowing 
such flexibility places Clean Energy Associations' preferred policy 
outcome in place of the need for reform articulated by the 
Commission.\1404\ The Commission in Order No. 1920 explained that the 
coordination reform is not intended to create an expansive set of 
interconnection-related transmission needs that transmission providers 
must evaluate in the regional transmission planning and cost allocation 
processes. Instead, this reform is intended to identify a limited set 
of interconnection-related transmission needs that are likely to 
persist, are not unique to a single interconnection request, and might 
be addressed by regional transmission facilities that have the 
potential to provide more widespread benefits to transmission 
customers. We believe that requiring transmission providers to consider 
a more limited set of interconnection-related transmission needs 
through their existing regional transmission planning and cost 
allocation processes is warranted

[[Page 97277]]

because a more expansive set could include transmission needs 
associated with expensive but relatively low voltage interconnection-
related network upgrades (which are less likely to provide widespread 
benefits to transmission customers compared to higher voltage 
transmission facilities) and transmission needs associated with high 
voltage but relatively inexpensive network upgrades (which are less 
likely to remain unbuilt by interconnection customers).
---------------------------------------------------------------------------

    \1404\ Order No. 1920, 187 FERC ] 61,068 at PP 1106-1121.
---------------------------------------------------------------------------

    541. As explained in Order No. 1920, in the context of the repeat 
identification criterion, we are also concerned that relaxing the 
qualifying criteria would create greater burdens on transmission 
providers by increasing the number of interconnection-related 
transmission needs that transmission providers must evaluate in their 
Order No. 1000 regional transmission planning and cost allocation 
processes without widespread benefits to transmission customers.\1405\ 
Additionally, the repeat identification criterion is meant to refine 
the evaluation to apply to more actionable and valuable 
interconnection-related transmission needs that may be better suited 
for evaluation and development in the existing Order No. 1000 regional 
transmission planning and cost allocation processes.
---------------------------------------------------------------------------

    \1405\ Id. P 1150.
---------------------------------------------------------------------------

    542. We disagree with Clean Energy Associations' claim that the 
requirement to meet both the cost threshold and the voltage threshold 
unduly limits the universe of transmission solutions in a manner that 
jeopardizes transmission providers' ability to evaluate transmission 
solutions that might be more efficient or cost-effective than other 
options. Clean Energy Associations conflate transmission needs and 
transmission solutions to address those needs. The purpose of the 
qualifying criteria adopted in Order No. 1920 is to limit the number of 
interconnection-related transmission needs that transmission providers 
must evaluate to those that merit consideration.\1406\ Contrary to 
Clean Energy Associations' claim, the qualifying criteria in Order No. 
1920 do not limit the transmission solutions that transmission 
providers may evaluate to address the identified interconnection-
related transmission needs. Instead, the qualifying criteria in Order 
No. 1920 limit the set of interconnection-related transmission needs 
that transmission providers must evaluate. We believe requiring 
transmission providers to evaluate this subset of transmission needs is 
justified because interconnection-related transmission needs that 
satisfy both the cost threshold and the voltage threshold can be solved 
with transmission facilities that are more likely to provide widespread 
benefits to the transmission system and be selected in the regional 
transmission for purposes of cost allocation as the more efficient and 
cost-effective transmission solution, compared to interconnection-
related transmission needs that satisfy only the cost threshold, or 
only the voltage threshold.
---------------------------------------------------------------------------

    \1406\ Id.
---------------------------------------------------------------------------

    543. We also disagree with Clean Energy Associations' claim that 
the Commission's decision to adopt the repeat identification criterion 
is arbitrary and inconsistent with the goals of Order No 1920. Clean 
Energy Associations' request for rehearing effectively asks the 
Commission to eliminate the repeat identification criterion to require 
the evaluation of more interconnection-related transmission needs in 
regional transmission planning processes, an argument that some 
commenters made in response to the NOPR and with which the Commission 
disagreed in Order No. 1920.\1407\ The Commission explained in Order 
No. 1920 that the purpose of this criterion is to indicate that an 
interconnection-related transmission need is likely to persist and to 
limit the extent to which evaluation of regional transmission 
facilities to address interconnection-related transmission needs is 
required.\1408\
---------------------------------------------------------------------------

    \1407\ Id.
    \1408\ Id. PP 1150, 1158.
---------------------------------------------------------------------------

    544. In response to Clean Energy Associations' request to clarify 
the timing requirements, and as more fully described below, we clarify 
that the time period that transmission providers use to identify 
interconnection-related transmission needs for potential consideration 
during any Order No. 1000 regional transmission planning and cost 
allocation process cycle will be longer than five calendar years. 
Additionally, we modify the requirements adopted in Order No. 1920 to 
resolve ambiguity about timing. We find that these modifications are 
necessary for transmission providers to determine precisely when the 
coordination requirements are triggered. Specifically, we modify 
criterion (1), the repeat identification criterion, and criterion (3), 
which specifies the maximum time period between withdrawals of 
interconnection requests associated with the same interconnection-
related transmission need (the double withdrawal criterion). We also 
adopt a new criterion (5), which specifies the timing for identifying 
withdrawn interconnection requests associated with the same 
interconnection-related transmission need in the initial and successive 
Order No. 1000 regional transmission planning and cost allocation 
cycles (the withdrawal window criterion). The withdrawal window 
criterion clarifies the intent of the repeat identification criterion 
in Order No. 1920.\1409\
---------------------------------------------------------------------------

    \1409\ We also make a minor modification to criterion (4) to 
account for the fact that we are adopting an additional qualifying 
criterion. All the revisions detailed below are reflected in the 
Attachment K Appendix to this order.
---------------------------------------------------------------------------

    545. In particular, we modify the repeat identification criterion 
to read (with additions in bold and italicized and deletions struck 
through):
BILLING CODE 6717-01-P

[[Page 97278]]

[GRAPHIC] [TIFF OMITTED] TR06DE24.000

    We also modify the double withdrawal criterion in Attachment K to 
read (with additions in bold and italicized and deletions struck 
through):
[GRAPHIC] [TIFF OMITTED] TR06DE24.001

    We make a slight modification to criterion (4) so that it reads 
(with additions in bold and italicized and deletions struck through):
[GRAPHIC] [TIFF OMITTED] TR06DE24.002

    We also add a new criterion (5), the withdrawal window criterion, 
as follows (with additions in bold and italicized):

[[Page 97279]]

[GRAPHIC] [TIFF OMITTED] TR06DE24.003

BILLING CODE 6717-01-C
    546. We make these modifications to resolve confusion about the 
timing requirements for this reform. The Commission's pro forma 
generator interconnection procedures require an annual cluster request 
window for interconnection customers to submit interconnection 
requests.\1410\ Over the span of the interconnection cycle, the 
transmission provider studies the interconnection requests and provides 
more refined interconnection study results.\1411\ The requirements of 
this reform provide an opportunity for transmission providers to 
evaluate interconnection-related transmission needs associated with 
repeatedly identified interconnection-related network upgrades that are 
not developed through the generator interconnection process because the 
interconnection requests associated with interconnection-related 
network upgrade withdraw from the interconnection queue.\1412\
---------------------------------------------------------------------------

    \1410\ See pro forma LGIP Sec.  3.4.1. As Order No. 1920 
recognizes, however, for a transmission provider that operates a 
serial process and studies interconnection requests on a first-come, 
first served basis, the criterion will be met if the 
interconnection-related transmission need is identified in at least 
two individual interconnection studies during the preceding five-
year period for interconnection customers that subsequently withdrew 
from the interconnection queue. Order No. 1920, 187 FERC ] 61,068 at 
P 1160. As noted above, however, this intricacy will be rendered 
moot as transmission providers with serial queues come into 
compliance with Order No. 2023, which requires them to transition to 
a cluster study process. Supra P 530 n.1380; see Order No. 2023, 184 
FERC ] 61,054 at P 223.
    \1411\ See, e.g., pro forma Sec. Sec.  LGIP 3.1.1 (Study 
Deposits), 7 (Cluster Study), 8 (Interconnection Facilities Study), 
9 (Affected Systems Study), 10 (Option Interconnection Study).
    \1412\ Order No. 1920, 187 FERC ] 61,068 at P 1108 (because 
``the high cost of interconnection is increasing the rate at which 
generators withdraw from the interconnection queue. . . . 
interconnection customers are unlikely to resolve these 
interconnection-related transmission needs through the generator 
interconnection process.'')
---------------------------------------------------------------------------

    547. The modifications that we make here clarify that a 
transmission provider need not evaluate an interconnection-related 
transmission need if more than five calendar years separate the 
withdrawal of the earlier and later interconnection requests associated 
with an interconnection-related transmission need (the double 
withdrawal criterion). Additionally, the withdrawal window criterion 
makes clear that a transmission provider need only evaluate an 
interconnection-related transmission need in its Order No. 1000 
regional transmission planning and cost allocation cycle if the 
withdrawal of the interconnection requests associated with the 
repeatedly identified interconnection-related transmission need 
occurred within the seven calendar years prior to the commencement date 
of the Order No. 1000 regional transmission planning and cost 
allocation cycle.
    548. We find that seven years is an appropriate period because it 
accounts for the time between withdrawn interconnection requests 
associated with otherwise eligible interconnection-related transmission 
needs (at most five years, as specified in the double withdrawal 
criterion) and accounts for the fact that the timing of generator 
interconnection queue cluster cycles likely does not coincide with the 
Order No. 1000 regional transmission planning and cost allocation 
cycle. Additionally, this seven-year period also accounts for the 
potential lag between the effective date of the Commission-approved 
tariff revisions and the initial Order No. 1000 regional transmission 
planning and cost allocation cycle (for the initial Order No. 1000 
cycle) or the time between Order No. 1000 cycles (for subsequent Order 
No. 1000 cycles). Consequently, by establishing a seven-year withdrawal 
window period, we avoid the possibility of otherwise qualifying 
interconnection-related transmission needs being ineligible for 
evaluation in an Order No. 1000 regional transmission planning and cost 
allocation cycle due to an inadequate withdrawal window period that 
does not account for lags between processes.
    549. We also believe this seven-year period for the withdrawal 
window is simpler to calculate than the language that the Commission 
previously adopted for the repeat identification criterion in Order No. 
1920 (before the modifications described here). The reason is that 
transmission providers will only need to look back seven calendar years 
from a single date (the commencement date of the Order No. 1000 
regional transmission planning and cost allocation cycle). Without the 
modifications adopted here, the first qualifying criterion of the 
repeat identification criterion in Order No. 1920 established several 
look-back periods in reference to multiple dates.\1413\
---------------------------------------------------------------------------

    \1413\ Id. P 1145 (``(1) the transmission provider has 
identified interconnection-related network upgrades in 
interconnection studies to address those interconnection-related 
transmission needs in at least two interconnection queue cycles 
during the preceding five years (looking back from the effective 
date of the Commission-accepted tariff provisions proposed to comply 
with this reform, and the later-in-time withdrawn interconnection 
request occurring after the effective date of the Commission-
accepted tariff provisions)'').
---------------------------------------------------------------------------

    550. As a result of the modifications above, there is no need to 
distinguish between the initial Order No. 1000 regional transmission 
planning and cost allocation cycle and subsequent No. 1000 regional 
transmission planning and cost allocation cycles. Thus, for the initial 
implementation of this reform, the transmission provider need only 
determine if the qualifying criteria are satisfied for the period 
beginning seven calendar years before the initial Order No. 1000 
regional transmission planning and cost allocation cycle commencement 
date. We acknowledge

[[Page 97280]]

that, in implementation, this start date is likely to be earlier than 
the start date established in Order No. 1920.\1414\ As a result, 
transmission providers may need to consider one or two additional years 
of withdrawn interconnection requests during the initial Order No. 1000 
regional transmission planning and cost allocation cycle. However, we 
believe this departure from Order No. 1920 is necessary to resolve the 
ambiguity raised on rehearing and to establish clear qualifying 
criteria for transmission providers to implement going forward.
---------------------------------------------------------------------------

    \1414\ Id. P 1159.
---------------------------------------------------------------------------

    551. In addition, the withdrawal window criterion makes clear that 
a transmission provider need not evaluate an interconnection-related 
need that meets all the qualifying criteria if it has already evaluated 
that interconnection-related transmission need in an Order No. 1000 
regional transmission planning and cost allocation cycle. This 
modification is necessary to prevent transmission providers from having 
to evaluate an interconnection-related transmission need in more than 
one Order No. 1000 regional transmission planning and cost allocation 
cycle.
    552. Consistent with the adoption of the withdrawal window 
criterion, we clarify for Clean Energy Associations that the time 
period that transmission providers use to identify interconnection 
withdrawals is longer than five calendar years. In particular, the 
withdrawal window criterion requires the transmission provider to 
determine if the interconnection request withdrawals associated with 
the repeatedly identified interconnection-related transmission need 
occur within seven calendar years prior to the commencement of the 
relevant Order No. 1000 regional transmission planning and cost 
allocation cycle.
    553. To explain how this would work, consider the following 
hypothetical and assume that the voltage-and-cost threshold criterion 
is satisfied:
     Transmission provider identifies interconnection-related 
transmission need A as necessary to interconnect interconnection 
request A in interconnection cluster cycle 1.
     Interconnection request A withdraws from interconnection 
cluster cycle 1 on August 1, 2035.
     In interconnection cluster cycle 2, transmission provider 
identifies interconnection-related transmission need A as necessary to 
interconnect interconnection request B.
     Interconnection request B withdraws from interconnection 
cluster cycle 2 on or before August 1, 2040.
     The first Order No. 1000 regional transmission planning 
and cost allocation cycle following the withdrawal of interconnection 
request B commences on January 1, 2042.
    In this example, the repeat identification criterion would be 
satisfied because the same interconnection-related transmission need 
was identified for interconnection request A and interconnection 
request B in interconnection cluster cycle 1 and interconnection 
cluster cycle 2, respectively. The double withdrawal criterion would be 
satisfied because no more than five calendar years have passed between 
the withdrawal of interconnection request A and interconnection request 
B. The withdrawal window criterion would be satisfied because the 
withdrawals of interconnection request A and interconnection request B 
occurred within seven calendar years prior to the commencement date of 
the Order No. 1000 regional transmission planning and cost allocation 
cycle. Consequently, the transmission provider would be required to 
evaluate interconnection-related transmission need A in the Order No. 
1000 regional transmission planning and cost allocation cycle that 
commences on January 1, 2042.
    554. We turn now back to Clean Energy Associations' first 
clarification request and explain these requirements using the dates 
provided in Clean Energy Associations' example, where the relevant 
tariff revisions would become effective August 1, 2025, the initial 
Order No. 1000 regional transmission planning and cost allocation cycle 
would commence on August 1, 2027, and the transmission solutions to be 
evaluated will be identified on April 1, 2028.
    555. We clarify that the April 1, 2028 date would not be relevant 
for determining whether a transmission provider must evaluate an 
interconnection-related transmission need. The relevant dates are the 
interconnection request withdrawal dates and the commencement date of 
the Order No. 1000 regional transmission planning and cost allocation 
cycle. In Clean Energy Associations' example, the transmission provider 
would identify interconnection request withdrawals between August 1, 
2020 (seven calendar years prior to the commencement date of the Order 
No. 1000 regional transmission planning and cost allocation cycle 
provided in this example) and August 1, 2027 (the commencement date of 
the Order No. 1000 regional transmission planning and cost allocation 
cycle provided in this example). Of those withdrawals, the repeat 
identification criterion will be satisfied if no more than five 
calendar years elapsed between the earlier and later interconnection 
request withdrawal dates for interconnection requests associated with 
the same repeatedly identified interconnection-related transmission 
need. Thus, withdrawals of interconnection requests with the earlier 
occurring on August 1, 2020 and the later occurring August 1, 2025 
would satisfy the double withdrawal criterion. The same is true for 
withdrawals of interconnection requests with the earlier occurring on 
August 1, 2022 and the later occurring August 1, 2027. The double 
withdrawal criterion would not be satisfied, however, if the first 
withdrawal occurred on August 1, 2020 and the later occurred on August 
2, 2025 because more than five calendar years occur between the earlier 
and later interconnection request withdrawals.
    556. Additionally, in response to Clean Energy Associations' second 
request for clarification, we note that the modifications to the repeat 
identification criterion adopted here delete the Attachment K language 
adopted in Order No. 1920 that created confusion.\1415\ Consistent with 
the modifications adopted here, we clarify that the double withdrawal 
criterion requires that no more than five calendar years occur between 
the earlier and later interconnection request withdrawals and that the 
withdrawal window criterion makes clear that transmission providers 
need not evaluate an interconnection-related transmission need if the 
relevant interconnection request withdrawals do not occur within the 
seven calendar years prior to the commencement date of the Order No. 
1000 regional transmission planning and cost allocation cycle.
---------------------------------------------------------------------------

    \1415\ See id. P 1145.
---------------------------------------------------------------------------

C. Cost Allocation

1. Order No. 1920 Requirements
    557. In Order No. 1920, the Commission adopted new coordination 
requirements to require that transmission providers evaluate regional 
transmission facilities that address certain interconnection-related 
transmission needs identified by this reform in the existing Order No. 
1000 regional transmission planning and cost allocation 
processes.\1416\ The Commission also stated that requests to modify 
existing cost allocation criteria were outside the scope of the 
proceeding.\1417\ Additionally, the

[[Page 97281]]

Commission stated that transmission providers will still have to 
evaluate and select any regional transmission facilities that address 
the interconnection-related transmission needs as the more efficient or 
cost-effective regional transmission solution as part of the regional 
transmission planning process in order for any regional cost allocation 
method to apply. Further, Order No. 1920 did not alter the existing 
cost allocation methods in either the generator interconnection or 
existing Order No. 1000 regional transmission planning process.\1418\ 
The Commission went on to explain that, to the extent that transmission 
providers wish to propose changes to their Order No. 1000 regional cost 
allocation method(s) because of this new requirement, they would need 
to do so in separate FPA section 205 filings rather than on compliance 
with Order No. 1920.\1419\
---------------------------------------------------------------------------

    \1416\ Id. P 1111.
    \1417\ Id. P 1112.
    \1418\ Id. P 1117.
    \1419\ Id. P 1118.
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    558. Retail Regulators, Ohio Consumers, NRECA, Undersigned States, 
and West Virginia Commission argue that Order No. 1920's coordination 
reform shifts the costs of generator interconnection to load.\1420\ In 
particular, Retail Regulators and Undersigned States argue that this 
requirement is another means to transfer network upgrade costs 
necessitated by generator interconnection to load and they contend, 
along with West Virginia Commission, that shifting these costs is not 
just and reasonable.\1421\ Undersigned States further argue that this 
shift violates the FPA, and that Order No. 1920's failure to account 
for these effects is arbitrary and capricious.\1422\ Relatedly, PJM 
argues that this reform is arbitrary and capricious because it reopens 
accepted cost allocation methods in Order Nos. 1000 and 2023 that were 
built on the premise that the cost causer pays for the interconnection 
costs.\1423\
---------------------------------------------------------------------------

    \1420\ Retail Regulators Rehearing Request at 43-44; Ohio 
Consumers Rehearing Request at 8; NRECA Rehearing Request at 45; 
Undersigned States Rehearing Request at 37; West Virginia Commission 
Rehearing Request at 16.
    \1421\ Retail Regulators Rehearing Request at 43-44; Undersigned 
States Rehearing Request at 37; West Virginia Commission Rehearing 
Request at 16.
    \1422\ Undersigned States at 37.
    \1423\ PJM Rehearing Request at 36 (citing Midwest ISO 
Transmission Owners, 373 F.3d at 1368 (citing 5 U.S.C. 706(2)(A)); 
State Farm, 463 U.S. at 43; Wis. Gas Co. v. FERC, 770 F.2d at 1156; 
see also Industrial Consumers Rehearing Request at 48.
---------------------------------------------------------------------------

    559. NRECA states that the Commission has failed to consider that 
its policies governing interconnection-related network upgrades--
particularly allowing participant funding in RTOs/ISOs--are intended to 
result in a just and reasonable allocation of the costs of 
interconnection-related network upgrades.\1424\ Industrial Customers 
argue that Order No. 1920 abruptly abandons participant funding, which 
it characterizes as a ``longstanding'' model that sends proper pricing 
signals for generation developers to select projects close to load 
while also protecting existing transmission customers from subsidizing 
interconnection of new generation.\1425\ East Kentucky argues that the 
Commission:
---------------------------------------------------------------------------

    \1424\ NRECA Rehearing Request at 48.
    \1425\ Industrial Customers Rehearing Request at 41.

has not provided a reasonable explanation of how this requirement 
does not result in unjust, unreasonable, and unduly discriminatory 
transmission rates in violation of Section 206 of the Federal Power 
Act, 16 U.S.C. 824e, and does not alter, without adequate 
explanation or evidence, the Commission's existing interconnection 
pricing and participant funding polices.\1426\
---------------------------------------------------------------------------

    \1426\ East Kentucky Rehearing Request at 3.

    560. Industrial Customers state that the Commission ignored 
arguments that the Commission must rationally explain its decision to 
depart from the existing just and reasonable ``but for'' policy of 
Order No. 2003.\1427\ Industrial Customers argue that the Commission 
should not justify its ``cost allocation techniques by arguing that 
interconnection costs for renewable energy resources are too high and 
should be socialized across all transmission customers.'' \1428\ 
Industrial Customers further argue that Order No. 1920 changes prior 
Commission policies without setting forth a reasonable and adequate 
explanation for resulting shifting of costs.\1429\
---------------------------------------------------------------------------

    \1427\ Industrial Customer Rehearing Request at 41.
    \1428\ Id. at 43.
    \1429\ Id. at 45.
---------------------------------------------------------------------------

    561. Ohio Consumers argue that Order No. 1920 is inconsistent with 
Order No. 2003 incentives because it shifts network upgrade costs that 
would have incentivized generation developers to locate in ``the right 
area.'' \1430\ NRECA argues that requiring evaluation and selection of 
unbuilt interconnection-related network upgrades in the existing Order 
No. 1000 regional transmission planning and cost allocation processes 
gives an undue preferential treatment to generation developers, a group 
that would ordinarily fund the network upgrades in the first 
instance.\1431\ Further, NRECA states that the Commission has made no 
finding that the Commission's policies allowing participant funding in 
RTOs/ISOs for interconnection-related network upgrades have become 
unjust and unreasonable and should be replaced.\1432\
---------------------------------------------------------------------------

    \1430\ Ohio Consumers Rehearing Request at 8-9; see also 
Industrial Consumers Rehearing Request at 42.
    \1431\ NRECA Rehearing Request at 46.
    \1432\ Id. at 48.
---------------------------------------------------------------------------

3. Commission Determination
    562. We sustain Order No. 1920 and find that the coordination 
requirements in Order No. 1920 do not require changes to existing cost 
allocation methods that transmission providers have adopted in either 
the generator interconnection or existing Order No. 1000 regional 
transmission planning and cost allocation processes. Therefore, those 
existing cost allocation methods adopted by transmission providers 
remain intact.
    563. To this point, in response to Retail Regulators, Ohio 
Consumers, NRECA, Undersigned States, West Virginia Commission, and 
PJM, we first note that the coordination reform does not alter existing 
cost allocation methods or create a new cost allocation method for 
generator interconnection processes. Rather, the purpose of the 
coordination reform is to require transmission providers to evaluate, 
in the existing Order No. 1000 regional transmission planning and cost 
allocation processes, certain (i.e., that qualify under the criteria 
established in Order No. 1920) interconnection-related transmission 
needs that were not addressed through the generator interconnection 
process because the identified interconnection-related network upgrades 
were never constructed pursuant to that process. If an interconnection 
customer enters into a generator interconnection agreement, the 
transmission provider will construct the identified interconnection-
related network upgrades and allocate their costs in accordance with 
the transmission provider's Commission-accepted cost allocation 
approach for such interconnection-related network upgrades. If an 
interconnection customer does not enter into a generator 
interconnection agreement for its interconnection request, however, the 
identified interconnection-related network upgrades will not be 
constructed pursuant to the generator interconnection process; thus, 
the generator interconnection cost allocation approach would not apply.
    564. Moreover, in response to NRECA and PJM, the coordination 
reform does

[[Page 97282]]

not create a new regional cost allocation method for the existing Order 
No. 1000 regional transmission planning and cost allocation processes. 
Instead, transmission providers must now, pursuant to this reform, 
evaluate certain interconnection-related transmission needs pursuant to 
their existing Order No. 1000 regional transmission planning and cost 
allocation processes. The transmission provider may adopt the 
evaluation method and selection criteria from any of its existing Order 
No. 1000 regional transmission planning and cost allocation processes 
(e.g., economic or reliability process) to evaluate and potentially 
select transmission facilities that address these transmission needs. 
To the extent that such a transmission facility is selected, it will 
have met the selection criteria for the applicable Order No. 1000 
regional transmission planning process and be eligible for cost 
allocation pursuant to a regional cost allocation method that has been 
found to allocate costs of transmission facilities selected through 
that process in a manner that is at least roughly commensurate with 
benefits.
    565. We reiterate, however, that there is no obligation for 
transmission providers to select a transmission facility that addresses 
the interconnection-related transmission need that must be evaluated 
pursuant to this reform.\1433\ As the Commission stated in Order No. 
1920, in order for the transmission facility associated with the 
relevant interconnection-related transmission need to be eligible for 
cost allocation pursuant to transmission providers' existing Order No. 
1000 regional cost allocation method, the transmission provider ``will 
still have to evaluate and select any regional transmission facilities 
that address the interconnection-related transmission needs as the more 
efficient or cost-effective regional transmission solution.'' \1434\ 
The Commission also stated that ``if a regional transmission facility 
that addresses identified interconnection-related transmission needs is 
not selected as part of the regional transmission planning process, 
then the associated regional cost allocation method would not apply.'' 
\1435\ The Commission explained that, to the extent that the 
coordination reform results in transmission providers selecting a 
transmission facility that, among other things, addresses an 
interconnection-related transmission need in the existing Order No. 
1000 regional transmission planning and cost allocation processes, they 
would have done so because the selected transmission facility was 
evaluated and determined by the transmission provider to be eligible 
for selection in the regional transmission plan for purposes of cost 
allocation and is the more efficient or cost-effective regional 
transmission solution. Moreover, we reiterate that the reform adopted 
here does not compel transmission providers to adopt a new cost 
allocation method for transmission facilities that address 
interconnection-related transmission needs.
---------------------------------------------------------------------------

    \1433\ See Order No. 1920, 187 FERC ] 61,068 at P 1156.
    \1434\ Id. P 1117.
    \1435\ Id.
---------------------------------------------------------------------------

D. Gaming

1. Order No. 1920 Requirements
    566. In Order No. 1920 the Commission did not adopt revisions to 
the proposed coordination reform in response to assertions that the 
reform would lead to ``gaming,'' resulting in spurious interconnection 
requests. The Commission explained that interconnection requests 
require significant financial commitments from interconnection 
customers, which the Commission made more stringent in Order No. 2023. 
Consequently, the Commission considered it unlikely that an 
interconnection customer would submit multiple interconnection requests 
in multiple interconnection queue cycles to trigger the requirement for 
transmission providers to evaluate, as part of their existing Order No. 
1000 regional transmission planning and cost allocation processes, 
regional transmission facilities that may address certain 
interconnection-related transmission needs. The Commission noted that 
an interconnection customer would face various risks pursuing such a 
strategy, including the risk that the regional transmission solution 
for the interconnection-related transmission need is not selected, and 
the risk that the newly created interconnection or transmission 
capacity is allocated to a different transmission or interconnection 
customer.\1436\
---------------------------------------------------------------------------

    \1436\ Id. P 1119.
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    567. PJM and NRECA argue that Order No. 1920 is arbitrary and 
capricious because it creates perverse incentives for generation 
developers to game the interconnection process and shift 
interconnection-related network upgrade costs in an unduly 
discriminatory manner onto transmission customers.\1437\ PJM and NRECA 
argue that the evidence does not support the Commission's reasoning 
that the stringent financial commitments required in the 
interconnection process will prevent gaming.\1438\
---------------------------------------------------------------------------

    \1437\ PJM Rehearing Request at 33; NRECA Rehearing Request at 
44, 46-47.
    \1438\ PJM Rehearing Request at 33; NRECA Rehearing Request at 
46.
---------------------------------------------------------------------------

    568. PJM states that, in its generator interconnection process, an 
interconnection customer's initial readiness deposit is only at risk 
prior to the interconnection customer learning its assigned network 
upgrade cost responsibility.\1439\ PJM further states that, for a 
hypothetical 300 MW project that would trigger the $30 million dollar 
threshold in the final rule,\1440\ the interconnection customer would 
only risk its readiness deposit of $1.2 million prior to withdrawing 
and having to post an additional deposit.\1441\ PJM asserts that a 
sophisticated developer can leverage that low risk and enhance its 
chances of selection for PJM's Regional Transmission Expansion Plan 
(RTEP) by submitting well-formed and strategically positioned, but 
specious, interconnection requests.\1442\ PJM asserts that, as a 
result, such developers can flood the PJM interconnection process with 
speculative and larger than necessary interconnection requests and 
withdraw shortly after the required network upgrade costs are 
identified.\1443\ PJM asserts that this would force it to reconsider 
RTEP upgrades that would incorporate the needed network upgrades and 
assign cost responsibility to load rather than to the generation 
developers.\1444\
---------------------------------------------------------------------------

    \1439\ PJM Rehearing Request at 34.
    \1440\ Order No. 1920, 187 FERC ] 61,068 at P 1155.
    \1441\ PJM Rehearing Request at 35.
    \1442\ Id. at 36.
    \1443\ Id. at 35.
    \1444\ Id.
---------------------------------------------------------------------------

    569. PJM asserts that the final rule discounts these concerns 
despite PJM's demonstration that the risk-to-benefit ratio heavily 
favors the submission of speculative interconnection requests for a 
relatively low at-risk deposit. PJM argues that this risk-to-benefit 
ratio justifies the potential risk of non-selection in RTEP that a 
developer may face.\1445\
---------------------------------------------------------------------------

    \1445\ PJM Rehearing Request at 36.
---------------------------------------------------------------------------

3. Commission Determination
    570. We do not find persuasive arguments raised on rehearing and 
continue to find that no revisions to Order No. 1920's coordination 
requirement are necessary to address the speculative gaming concerns 
raised in this proceeding.\1446\ With respect to PJM's specific 
generator interconnection

[[Page 97283]]

process, we disagree with PJM that the risk an interconnection customer 
faces of losing only its readiness deposit if it withdraws is too low a 
risk to mitigate gaming concerns. Specifically, PJM's own hypothetical 
example demonstrates that an interconnection customer would risk losing 
$1.2 million for a single interconnection request, a risk that that we 
do not consider inconsequential. Moreover, for a single interconnection 
customer to attempt this gaming strategy, it would have to put its 
study and readiness deposits at risk in at least two interconnection 
queue cycles, and therefore would put at risk $2.4 million ($1.2 
million per cycle) for the underlying interconnection-related 
transmission need to trigger the repeat identification criterion to 
qualify for evaluation in the Order No. 1000 regional transmission 
planning and cost allocation processes.\1447\ Therefore, the risk is 
higher than what PJM asserts.
---------------------------------------------------------------------------

    \1446\ Order No. 1920, 187 FERC ] 61,068 at P 1119.
    \1447\ Id. PP 1119, 1145.
---------------------------------------------------------------------------

    571. Additionally, we continue to find it unlikely that an 
interconnection customer would submit multiple interconnection requests 
(in multiple interconnection queue cycles) to trigger this requirement 
because the interconnection customer would face additional uncertainty 
in that transmission providers may not select a transmission facility 
that addresses the interconnection-related network upgrade in a 
regional transmission plan for purposes of cost allocation. We also 
reiterate that pursuing such a strategy would entail other risks, 
including the risk that any of the five qualifying criteria will not be 
met and the possibility that the newly created interconnection or 
transmission capacity will not benefit the interconnection customer 
that submitted, and withdrew, the interconnection requests in multiple 
interconnection queue cycles because the entity that withdrew the 
interconnection requests has no preferential claim to that 
capacity.\1448\ For these reasons, we believe the financial risks and 
process-related restrictions make it unlikely that a generation 
developer would risk time and resources to ``game'' this process in the 
hope of benefiting from an uncertain process, which is highly unlikely 
to produce the generation developer's preferred result.
---------------------------------------------------------------------------

    \1448\ See id. P 1119.
---------------------------------------------------------------------------

E. Transmission Planning Process Evaluation

1. Order No. 1920 Requirements
    572. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to evaluate regional 
transmission facilities that address certain interconnection-related 
transmission needs in their existing Order No. 1000 regional 
transmission planning and cost allocation processes instead of in Long-
Term Regional Transmission Planning, as was proposed in the NOPR. The 
Commission explained that by requiring transmission providers to 
evaluate identified interconnection-related transmission needs in 
existing Order No. 1000 regional transmission planning and cost 
allocation processes, such needs will be addressed within a timeframe 
that is relevant for identifying more efficient or cost-effective near-
term regional transmission solutions.\1449\
---------------------------------------------------------------------------

    \1449\ Id. P 1126.
---------------------------------------------------------------------------

    573. The Commission agreed with commenters that future 
interconnection-related transmission needs will be considered as part 
of Long-Term Regional Transmission Planning and incorporated in the 
development of Long-Term Scenarios. The Commission disagreed with 
commenters that asserted that the Commission's coordination proposal is 
unnecessary because well-executed Long-Term Regional Transmission 
Planning will identify the transmission needed to support generator 
interconnections. The Commission anticipated that as transmission 
providers gain experience with Long-Term Regional Transmission Planning 
they will identify fewer interconnection-related transmission needs 
associated with certain interconnection-related network upgrades 
originally identified through the generator interconnection process 
because transmission providers will plan to address Long-Term 
Transmission Needs, including those driven by Factor Category One: 
federal, federally-recognized Tribal, state, and local laws and 
regulations that affect the future resource mix and demand; Factor 
Category Two: federal, federally-recognized Tribal, state, and local 
laws and regulations on decarbonization and electrification; Factor 
Category Six: generator interconnection requests and withdrawals, and 
Factory Category Seven: utility and corporate commitments and federal, 
federally-recognized Tribal, state, and local policy goals that affect 
Long-Term Transmission Needs, through Long-Term Regional Transmission 
Planning.\1450\
---------------------------------------------------------------------------

    \1450\ Id. P 1127.
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    574. NRECA and East Kentucky argue that the Commission did not 
provide sufficient notice and opportunity to comment on the final 
rule's requirement to evaluate for selection transmission facilities to 
address identified interconnection-related transmission needs in 
existing Order No. 1000 regional transmission planning and cost 
allocation processes rather than in Long Term-Regional Transmission 
Planning process, as the NOPR proposed.\1451\
---------------------------------------------------------------------------

    \1451\ East Kentucky Rehearing Request at 1-2; NRECA Rehearing 
Request at 15-16.
---------------------------------------------------------------------------

    575. Clean Energy Associations claim that the Commission failed to 
engage in reasoned decision-making by not requiring transmission 
providers to evaluate network upgrades that address interconnection-
related transmission needs in Long-Term Regional Transmission 
Planning.\1452\ Clean Energy Associations argue that if one assumes 
that the Order No. 1920 rationale is true, i.e., that the existing 
Order No. 1000 regional transmission planning and cost allocation 
processes are a faster and more effective means of getting these 
facilities built, then such rationale does not justify the Commission's 
failure to also require evaluation of those upgrades in Long-Term 
Regional Transmission Planning.\1453\ Clean Energy Associations allege 
that Order No. 1920, by limiting the mandatory consideration of 
interconnection-related network upgrades to the existing Order No. 1000 
regional transmission planning and cost allocation processes, will 
necessarily fail to require transmission providers to evaluate benefits 
of transmission facilities that would result from their selection. 
Clean Energy Associations allege that any transmission upgrade, 
including interconnection-related network upgrades, is more likely to 
be selected in the ``more robust'' Long-Term Regional Transmission 
Planning, which they believe is consistent with the Commission's 
justifications of the reform and supported by the record.\1454\
---------------------------------------------------------------------------

    \1452\ Clean Energy Associations Rehearing Request at 4-6.
    \1453\ Id. at 6.
    \1454\ Id. at 7.
---------------------------------------------------------------------------

    576. Clean Energy Associations assert that the Commission's 
expectation that fewer interconnection-related network upgrades would 
be identified over time, in part due to transmission providers' 
consideration of Factor Category Six (Generator Interconnection 
Requests

[[Page 97284]]

and Withdrawals), is no grounds to deny a parallel path for 
transmission providers to evaluate interconnection-related transmission 
needs through Long-Term Regional Transmission Planning because the 
categories of factors apply to identifying Long-Term Transmission 
Needs, rather than evaluating specific facilities for possible 
selection.\1455\ Clean Energy Associations claim that the Commission's 
requirement to evaluate interconnection-related transmission needs is 
more analogous to the evaluation requirements than to the Long-Term 
Scenarios requirements of Long-Term Regional Transmission Planning. 
Clean Energy Associations argue, therefore, that it is not just and 
reasonable, nor is it comparable, to assume that Factor Category Six is 
duplicative of evaluating interconnection-related network upgrades in 
Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \1455\ Id. at 7-8.
---------------------------------------------------------------------------

    577. Clean Energy Associations further argue that evaluating 
interconnection-related transmission needs in Long-Term Regional 
Transmission Planning may serve as a needed fail-safe for addressing 
current interconnection-related transmission needs if a particular 
transmission provider's existing Order No. 1000 regional transmission 
planning and cost allocation processes prove to be ineffective for that 
purpose.\1456\ Clean Energy Associations assert that to maximize the 
chances that more efficient or cost-effective projects will be 
successfully developed, the Commission should require transmission 
providers to evaluate qualifying interconnection-related network 
upgrades in both Long-Term Regional Transmission Planning and the 
existing Order No. 1000 regional transmission planning and cost 
allocation processes.\1457\
---------------------------------------------------------------------------

    \1456\ Id. at 8.
    \1457\ Id. at 9.
---------------------------------------------------------------------------

    578. Clean Energy Associations claim that the record demonstrates 
that interconnection-related network upgrades provide transmission 
benefits beyond the interconnection customers triggering them, and it 
is therefore reasonable to require their evaluation with comparable 
high-voltage, high-cost facilities in Long-Term Regional Transmission 
Planning.\1458\ Clean Energy Associations also state that evaluation of 
interconnection-related network upgrades in Long-Term Regional 
Transmission Planning is the logical precedent for the voluntary 
funding option for interconnection customers because it will provide 
potential funders of the transmission facilities with a comparable way 
to evaluate the benefits of that facility.\1459\
---------------------------------------------------------------------------

    \1458\ Id. at 10-11.
    \1459\ Id. at 11-12.
---------------------------------------------------------------------------

    579. Finally, Clean Energy Associations request that, at a minimum, 
the Commission clarify that Order No. 1920 does not prohibit 
transmission providers from evaluating interconnection-related 
transmission needs in Long-Term Regional Transmission Planning.\1460\
---------------------------------------------------------------------------

    \1460\ Id. at 12-13.
---------------------------------------------------------------------------

    580. Large Public Power argues that by specifying that 
interconnection applications and withdrawals are the sole criterion for 
project selection in existing Order No. 1000 regional transmission 
planning and cost allocation processes, Order No. 1920 will 
dramatically skew the Order No. 1000 processes and is fundamentally at 
odds with the Commission's objective of not disrupting planning for 
reliability and economic needs put in place under Order No. 1000.\1461\ 
Large Public Power also argues that specifying that interconnection 
applications and withdrawals are the sole criterion for project 
selection in existing Order No. 1000 regional transmission planning and 
cost allocation processes is inconsistent with the approach to 
developing Long-Term Scenarios, which ``call[s] for a holistic analysis 
which enables system planners to make informed, balanced decisions to 
address the unique Long-Term Transmission Needs of each planning 
region.'' \1462\ Large Public Power asserts that the Commission failed 
to explain why generation interconnection application withdrawals 
should be the only consideration to determine transmission needs under 
existing Order No. 1000 regional transmission planning and cost 
allocation processes.\1463\
---------------------------------------------------------------------------

    \1461\ Large Public Power Rehearing Request at 21.
    \1462\ Id. at 21-22.
    \1463\ Large Public Power Rehearing Request at 22.
---------------------------------------------------------------------------

    581. PJM claims that the withdrawn and speculative interconnection 
requests, as potential drivers of regional transmission needs, would 
insert an unjustified level of uncertainty into its existing Order No. 
1000 regional transmission planning and cost allocation 
processes.\1464\ PJM also asserts that the final rule is arbitrary and 
capricious because it requires consideration of withdrawn 
interconnection requests in its near-term RTEP and provides them undue 
preference over interconnection requests that have taken all required 
steps to obtain site control, permits, and regulatory approvals and 
have paid deposits.\1465\ PJM contends that under the final rule, the 
output of the RTEP process, which is used in the generator 
interconnection process, ``would be inflated by the addition of 
questionable transmission upgrades.'' \1466\ Thus, PJM claims, the RTEP 
and generator interconnection processes, which are meant to work in 
tandem, would become unnecessarily separated and infused with dubious 
inputs and drivers.\1467\
---------------------------------------------------------------------------

    \1464\ PJM Rehearing Request at 37-38.
    \1465\ Id.
    \1466\ Id. at 38.
    \1467\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    582. We disagree with NRECA and East Kentucky that the Commission 
failed to provide adequate notice of and opportunity to comment on 
Order No. 1920's requirement that transmission providers in each 
transmission planning region evaluate for selection regional 
transmission facilities that address certain interconnection-related 
transmission needs in their existing Order No. 1000 regional 
transmission planning and cost allocation processes instead of in Long-
Term Regional Transmission Planning.\1468\
---------------------------------------------------------------------------

    \1468\ East Kentucky Rehearing Request at 1-2; NRECA Rehearing 
Request at 15-16.
---------------------------------------------------------------------------

    583. A final rule is a logical outgrowth of a proposed rule where 
``a reasonable member of the regulated class'' could ``anticipate the 
general aspects of the [final] rule.'' \1469\ Order No. 1920 satisfies 
this standard because the NOPR explicitly requested comment on how the 
proposed reform ``should interact with existing regional transmission 
planning processes and the Long-Term Regional Transmission Planning 
proposed herein,'' \1470\ which put parties on notice that the 
Commission was contemplating the change that NRECA and East Kentucky 
now argue is not a logical outgrowth of the NOPR. Courts have explained 
that ``[n]otice suffices when [an agency] has `expressly asked for 
comments on a particular issue or

[[Page 97285]]

otherwise made clear that the agency was contemplating a particular 
change.' '' \1471\ Here, by requesting comment on the issue, the 
Commission put parties on notice that it was continuing to contemplate 
how the proposed reform should interact with both proposed Long-Term 
Regional Transmission Planning and existing Order No. 1000 regional 
transmission planning processes.
---------------------------------------------------------------------------

    \1469\ Telesat Canada v. FCC, 999 F.3d at 713-14 (quotations 
omitted). We note that, while requiring transmission providers to 
evaluate identified interconnection-related transmission needs in 
existing Order No. 1000 regional transmission planning and cost 
allocation processes will allow such needs to be addressed within a 
timeframe that is relevant for identifying more efficient or cost-
effective near-term regional transmission solutions, we believe that 
evaluating interconnection-related transmission needs in Long-Term 
Regional Transmission Planning would also be appropriate. The 
inability to require that transmission providers consider regional 
transmission facilities to address interconnection-related 
transmission needs in Order No. 1000 processes would not have 
prevented the Commission from issuing Order No. 1920.
    \1470\ NOPR, 179 FERC ] 61,028 at P 174.
    \1471\ Brennan v. Dickson, 45 F.4th at 69 (quoting CSX Transp., 
Inc. v. Surface Transp. Bd., 584 F.3d at 1081).
---------------------------------------------------------------------------

    584. Agency final rules need not be identical to proposed rules, 
and notice is sufficient if the final rule represents a ``logical 
outgrowth'' of the proposed rule.\1472\ The final rule is a logical 
outgrowth of the NOPR in this regard. In the NOPR, the Commission 
proposed to require that transmission providers evaluate for selection 
in the regional transmission plan for purposes of cost allocation 
regional transmission facilities to address certain interconnection-
related needs that meet specific qualifying criteria established by the 
Commission.\1473\ Order No. 1920 adopted this requirement and mandated 
that such consideration occur in existing Order No. 1000 regional 
transmission planning and cost allocation processes,\1474\ rather than 
in Long-Term Regional Transmission Planning, as the NOPR 
proposed.\1475\ The Commission explained that this change will allow 
interconnection-related transmission needs to be addressed within a 
timeframe that is relevant for identifying more efficient or cost-
effective near-term regional transmission solutions. We find that this 
change satisfies the logical outgrowth test because while the 
Commission modified the type of regional transmission planning and cost 
allocation processes that would be subject to coordination with 
interconnection-related transmission needs, it retained the underlying 
requirement that such coordination occur. Thus, Order No. 1920's 
requirement ``follow[s] logically from'' the NOPR because the NOPR 
``adequately frame[d] the subjects for discussion.'' \1476\
---------------------------------------------------------------------------

    \1472\ Long Island Care, 551 U.S. at 174-75; see also Am. Paper 
Inst. v. EPA, 660 F.2d at 959 n.13 (``An agency may make even 
substantial changes in its original proposed rule without a further 
comment period if the changes are in character with the original 
proposal and are a logical outgrowth of the notice and comments 
already given.'' (emphasis added)).
    \1473\ NOPR, 179 FERC ] 61,028 at P 166.
    \1474\ Order No. 1920, 187 FERC ] 61,068 at P 1126.
    \1475\ NOPR, 179 FERC ] 61,028 at P 167.
    \1476\ Conn. Light & Power Co. v. Nuclear Regulatory Comm'n, 673 
F.2d at 533.
---------------------------------------------------------------------------

    585. We are unpersuaded by Clean Energy Associations' assertion 
that the Commission failed to engage in reasoned decision-making by not 
requiring transmission providers to evaluate network upgrades that 
address interconnection-related transmission needs in Long-Term 
Regional Transmission Planning. We continue to find that evaluating 
interconnection-related transmission needs associated with this 
coordination requirement is more appropriate in the existing Order No. 
1000 regional transmission planning and cost allocation processes than 
in Long-Term Regional Transmission Planning because such evaluation 
would occur at shorter intervals and would be more likely to result in 
expeditious development of regional transmission facilities to address 
the nearer-term interconnection-related transmission needs identified 
through the generator interconnection process.\1477\ We find that it is 
unnecessary to require transmission providers to also evaluate 
interconnection-related transmission needs associated with this 
coordination requirement in Long-Term Regional Transmission Planning 
because the coordination requirement in Order No. 1920 is just and 
reasonable and sufficient to address the need for reform.
---------------------------------------------------------------------------

    \1477\ Order No. 1920, 187 FERC ] 61,068 at P 1126.
---------------------------------------------------------------------------

    586. In addition, we reiterate that transmission providers must 
consider future interconnection-related transmission needs as a driver 
of Long-Term Transmission Needs in Long-Term Regional Transmission 
Planning through the development of Long-Term Scenarios, which must 
incorporate generator interconnection withdrawals in Factor Category 
Six (Generator Interconnection Requests and Withdrawals).\1478\ Factor 
Category Six allows transmission providers to consider a broader range 
of potential interconnection-related transmission needs compared to the 
interconnection-related transmission needs that meet the coordination 
requirement's qualifying criteria. Moreover, to the extent that an 
interconnection-related transmission need is not addressed according to 
this coordination requirement, transmission providers may choose to 
consider similar interconnection-related transmission needs as Long-
Term Transmission Needs and evaluate Long-Term Regional Transmission 
Facilities to address those needs in Long-Term Regional Transmission 
Planning. Therefore, we believe that requiring transmission providers 
to evaluate interconnection-related transmission needs identified by 
this coordination requirement in Long-Term Regional Transmission 
Planning would be redundant to existing Order No. 1920 requirements and 
could inappropriately limit the scope of the interconnection-related 
transmission needs that transmission providers consider in Long-Term 
Regional Transmission Planning.
---------------------------------------------------------------------------

    \1478\ Id. PP 1127-1128.
---------------------------------------------------------------------------

    587. On this point, we disagree with Clean Energy Associations' 
claim that it is not just and reasonable, nor is it comparable, to 
assume Factor Category Six is duplicative of evaluating 
interconnection-related network upgrades in Long-Term Regional 
Transmission Planning, and that this coordination requirement is more 
analogous to the Long-Term Regional Transmission Planning evaluation 
requirements. Both the qualifying criteria of the coordination 
requirement and the categories of factors of the Long-Term Scenarios 
requirements (in Long-Term Regional Transmission Planning) establish 
how transmission providers identify transmission needs. We recognize 
that the coordination requirement mandates the evaluation of regional 
transmission facilities to address interconnection-related transmission 
needs associated with this coordination requirement, albeit allowing 
for flexibility in how transmission providers evaluate such facilities 
for selection, but Long-Term Regional Transmission Planning does not 
mandate evaluation of a specific type of transmission facility.\1479\ 
However, the requirement to evaluate regional transmission facilities 
associated with the coordination requirement is similar to the Long-
Term Regional Transmission Planning requirement for transmission 
providers to establish a process, including selection criteria, that 
they will use to identify and evaluate Long-Term Regional Transmission 
Facilities for potential selection to address Long-Term Transmission 
Needs (which, as discussed above, will include future interconnection-
related transmission needs). This explanation addresses Clean Energy 
Associations' concern that Order No. 1920 will necessarily fail to 
require transmission providers to evaluate benefits of transmission 
facilities to address interconnection-related transmission needs 
through Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \1479\ Id. P 1111.
---------------------------------------------------------------------------

    588. In response to Clean Energy Associations' request for 
clarification that Order No. 1920 does not prohibit transmission 
providers from evaluating

[[Page 97286]]

interconnection-related transmission needs in Long-Term Regional 
Transmission Planning, we reiterate that future interconnection-related 
transmission needs must be considered as part of Long-Term Regional 
Transmission Planning and incorporated in the development of Long-Term 
Scenarios.\1480\ We clarify that Order No. 1920 does not prohibit 
transmission providers from proposing on compliance how they will 
identify and evaluate future interconnection-related transmission needs 
in Long-Term Regional Transmission Planning. However, we will not 
prejudge Clean Energy Associations' proposal for a ``parallel path'' 
for identifying and evaluating interconnection-related transmission 
needs in Long-Term Regional Transmission Planning using the 
coordination requirement's qualification criteria.\1481\ If any 
transmission provider chooses to develop additional processes to 
address interconnection-related transmission needs in Long-Term 
Regional Transmission Planning, they must demonstrate that the proposal 
is consistent with or superior to Order No. 1920's requirements.
---------------------------------------------------------------------------

    \1480\ Id. P 1127.
    \1481\ Id. P 1145.
---------------------------------------------------------------------------

    589. We are not persuaded by Large Public Power's argument that, in 
Order No. 1920, the Commission is specifying that interconnection 
applications and withdrawals are the sole criterion for project 
selection in existing Order No. 1000 regional transmission planning and 
cost allocation processes. To this point, we first note that Order No. 
1920 adopts not one, but five, criteria for interconnection-related 
transmission needs to be evaluated through existing Order No. 1000 
regional transmission planning and cost allocation processes. That is, 
evaluation is only required when the interconnection-related network 
upgrades driving interconnection-related transmission needs meets the 
five qualification criteria established in Order No. 1920.\1482\
---------------------------------------------------------------------------

    \1482\ Id.
---------------------------------------------------------------------------

    590. Furthermore, the evaluation requirement only requires 
transmission providers to evaluate interconnection-related transmission 
needs in the Order No. 1000 regional transmission planning process. It 
does not require that transmission providers use interconnection-
related transmission needs as a criterion to decide whether to select a 
regional transmission facility in the Order No. 1000 regional 
transmission planning process nor does it require that the 
interconnection-related transmission need be resolved. As the 
Commission explained, these requirements provide flexibility in how 
transmission providers evaluate transmission facilities for selection 
by allowing them to adopt the evaluation method and selection criteria 
from any of their existing Order No. 1000 regional transmission 
planning and cost allocation processes (e.g., economic or reliability 
processes) to evaluate and potentially select these types of 
transmission facilities. The Commission thus permitted transmission 
providers to propose the best method to incorporate this new 
requirement for their transmission planning region and encouraged 
transmission providers to consider, as part of the evaluation process, 
whether regional transmission facilities that address certain 
identified interconnection-related transmission needs may also address 
other regional transmission needs more efficiently or cost-
effectively.\1483\
---------------------------------------------------------------------------

    \1483\ Id. P 1111.
---------------------------------------------------------------------------

    591. We also disagree with PJM's assertions that the Order No. 1920 
requirement is arbitrary and capricious because the requirement would 
insert an unjustified level of uncertainty into its existing Order No. 
1000 regional transmission planning and cost allocation processes by 
requiring consideration of withdrawn interconnection requests in its 
near-term RTEP. As explained here and in Order No. 1920, we are not 
requiring that transmission providers develop transmission facilities 
through the Order No. 1000 regional transmission planning and cost 
allocation processes as transmission solutions to address 
interconnection-related transmission needs. The coordination reform 
simply creates an avenue for evaluation of qualifying interconnection-
related transmission needs in the existing Order No. 1000 regional 
transmission planning and cost allocation processes. Further, Order No. 
1920 gives transmission providers flexibility to ``adopt the evaluation 
method and selection criteria from any of their existing Order No. 1000 
regional transmission planning and cost allocation processes (e.g., 
economic or reliability processes) to evaluate and potentially select 
these types of transmission facilities'' \1484\
---------------------------------------------------------------------------

    \1484\ Id.
---------------------------------------------------------------------------

    592. Additionally, we disagree with PJM that the Order No. 1920 
requirement gives undue preference to withdrawn interconnection 
requests. Instead, the requirement addresses a barrier to entry for new 
generation resources, where repeated interconnection requests are 
increasingly withdrawn due to sticker shock from the estimated costs of 
the required interconnection-related network upgrades. The qualifying 
requirements, however, disqualify from these requirements 
interconnection-related transmission needs memorialized in generator 
interconnection agreements (i.e., that are ready to move forward with 
project development in the generator interconnection process). 
Consequently, pursuant to the coordination reformation requirements, no 
interconnection customer would benefit from having the upgrade costs 
that it would otherwise pay allocated instead through transmission 
rates. Rather, in the circumstance that Order No. 1920 addresses, no 
interconnection customer is willing to pay the estimated costs of the 
interconnection-related network upgrades. Therefore, there would be no 
undue preference because if the qualifying criteria are met, there is 
no longer an interconnection request or interconnection customer 
associated with the qualifying interconnection-related transmission 
need.
    593. Moreover, in response to PJM's assertion that the output of 
the RTEP process, which is used in its generator interconnection 
process, ``would be inflated by the addition of questionable 
transmission upgrades,'' we again note that the Order No. 1920 
requirement does not require that transmission providers resolve 
interconnection-related transmission needs, including resolving them 
through selection of transmission facilities; that is, Order No. 1920 
neither requires nor guarantees a specific outcome. Rather, 
transmission providers must consider the interconnection-related 
transmission needs in their existing Order No. 1000 regional 
transmission planning and cost allocation processes and determine 
whether there is a more efficient or cost-effective transmission 
solution, under the existing evaluation and selection criteria in the 
existing Order No. 1000 regional transmission planning and cost 
allocation processes.

VII. Consideration of Dynamic Line Ratings and Advanced Power Flow 
Control Devices

A. Order No. 1920 Requirements

    594. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to consider, in Long-
Term Regional Transmission Planning and existing Order No. 1000 
regional transmission planning processes, the following enumerated 
alternative transmission technologies for each

[[Page 97287]]

identified transmission need: (1) dynamic line ratings; (2) advanced 
power flow control devices; (3) advanced conductors; and (4) 
transmission switching.\1485\ This list of enumerated alternative 
transmission technologies that the Commission required transmission 
providers in each transmission planning region to consider expanded on 
the Commission's proposed list of alternative transmission 
technologies, which only proposed to require the consideration of 
dynamic line ratings and advanced power flow control devices.\1486\ The 
Commission further required that transmission providers consider each 
of these enumerated technologies when evaluating new regional 
transmission facilities, as well as upgrades to existing transmission 
facilities. Thus, the Commission required that for each identified 
transmission need, when evaluating regional transmission facilities for 
potential selection, transmission providers must consider whether 
regional transmission facilities that incorporate, or solely consist 
of, any of the enumerated list of alternative transmission technologies 
would be more efficient or cost-effective than selecting new regional 
transmission facilities or upgrades to existing transmission facilities 
that do not incorporate these technologies.\1487\
---------------------------------------------------------------------------

    \1485\ Order No. 1920, 187 FERC ] 61,068 at P 1198. In Order No. 
1920, the Commission defined advanced transmission technologies as 
``a range of permissible present and future technologies, and is 
defined relative to conventional aluminum conductor steel reinforced 
conductors.'' Id. P 1243. The Commission further clarified that 
``advanced conductors include, but are not limited to, 
superconducting cables, advanced composite conductors, advanced 
steel cores, high temperature low-sag conductors, fiber optic 
temperature sensing conductors, and advanced overhead conductors.'' 
Id.
    \1486\ NOPR, 179 FERC ] 61,028 at P 272.
    \1487\ Order No. 1920, 187 FERC ] 61,068 at P 1198.
---------------------------------------------------------------------------

    595. The Commission further required that transmission providers' 
evaluation of the enumerated alternative transmission technologies must 
be consistent with the requirements in their OATTs for other 
transmission solutions.\1488\ In response to requests for additional 
transparency, the Commission adopted the NOPR proposal to expand the 
existing requirement established in Order No. 1000 for transmission 
providers' evaluation processes to culminate in a determination that is 
sufficiently detailed for stakeholders to understand why a particular 
transmission facility was selected or not selected. Specifically, the 
Commission required that the determination include an explanation that 
is sufficiently detailed for stakeholders to understand why dynamic 
line ratings, advanced power flow control devices, advanced conductors, 
and/or transmission switching were or were not incorporated into 
selected regional transmission facilities.\1489\
---------------------------------------------------------------------------

    \1488\ Id. P 1199.
    \1489\ Id. P 1214.
---------------------------------------------------------------------------

B. Requests for Rehearing and Clarification

1. General Requests for Rehearing and Clarification
a. Requests for Rehearing and Clarification
    596. Large Public Power requests clarification that transmission 
providers may use engineering judgment in considering which 
transmission elements should be analyzed as candidates for alternative 
transmission technologies. Specifically, Large Public Power explains 
that, while it does not challenge the Commission's general approach to 
alternative transmission technologies, requiring transmission providers 
to conduct resource intensive and detailed production cost simulations 
for each technology for each existing transmission element would be 
burdensome and expensive. Large Public Power asks the Commission to 
clarify that planning engineers may exercise informed discretion 
regarding the planning horizon within which alternative transmission 
technologies are of value. Finally, Large Public Power states that it 
understands that all relevant judgments must be supported and subject 
to examination and review.\1490\
---------------------------------------------------------------------------

    \1490\ Large Public Power Request for Rehearing at 13-16.
---------------------------------------------------------------------------

    597. On rehearing, NESCOE argues that the Commission should require 
transmission providers to prioritize alternative transmission 
technologies to serve as the starting point for addressing identified 
transmission needs.\1491\ NESCOE states that, absent such 
prioritization of alternative transmission technologies, rates remain 
at risk of being unjust and unreasonable.\1492\ NESCOE asks the 
Commission to direct transmission providers to incorporate tariff 
procedures establishing a rebuttable presumption that the incorporation 
of alternative transmission technologies as a solution to an identified 
Long-Term Transmission Need or existing Order No. 1000 transmission 
need would result in a more efficient or cost-effective transmission 
solution. NESCOE asserts that such a directive would both maintain the 
flexibility envisioned by Order No. 1920 and place the burden on 
transmission providers to demonstrate why alternative transmission 
technologies are not, either alone or as a solution component, a more 
efficient or cost-effective solution.\1493\
---------------------------------------------------------------------------

    \1491\ NESCOE Request for Rehearing at 6, 22-25, 34.
    \1492\ Id. at 25.
    \1493\ Id. at 24-25.
---------------------------------------------------------------------------

b. Commission Determination
    598. We grant, in part, Large Public Power's request for 
clarification regarding ``engineering judgment'' in analyzing 
transmission elements for alternative transmission technologies.\1494\ 
In particular, we do not require detailed production cost simulations 
to demonstrate costs and benefits of each alternative transmission 
technology for each existing transmission element, and we clarify that 
transmission providers have flexibility to apply good engineering 
judgment to identify the specific transmission elements that are likely 
candidates for specific enumerated alternative transmission 
technologies. We recognize that a transmission provider's consideration 
of alternative transmission technologies will likely depend on the 
particulars of the transmission provider's transmission system. In that 
context, transmission providers may be able to rapidly determine if a 
certain alternative transmission technology is inappropriate for 
further study on a specific transmission element.\1495\
---------------------------------------------------------------------------

    \1494\ Large Public Power Request for Rehearing at 13-16.
    \1495\ We note that this is consistent with the Commission's 
findings in Order No. 2023. See, e.g., Order No. 2023, 187 FERC ] 
61,068 at P 1590.
---------------------------------------------------------------------------

    599. We reiterate, however, that transmission providers in each 
transmission planning region must consider, as discussed above, dynamic 
line ratings, advanced power flow control devices, advanced conductors, 
and transmission switching for each identified transmission need during 
Long-Term Regional Transmission Planning and existing Order No. 1000 
regional transmission planning processes. We further reiterate that 
transmission providers must consider each of those alternative 
transmission technologies when evaluating new regional transmission 
facilities, as well as upgrades to existing transmission 
facilities.\1496\ Such consideration of the enumerated alternative 
transmission technologies must be consistent with the requirements in 
their OATTs for other transmission solutions and with the Commission's 
requirements

[[Page 97288]]

established in Order No. 1920.\1497\ Finally, consistent with Large 
Public Power's understanding,\1498\ nothing in this clarification 
obviates the requirement for transmission providers to support their 
determinations,\1499\ the Commission's transparency requirements, or 
the potential to challenge a transmission provider's consideration of 
the enumerated alternative transmission technologies.\1500\
---------------------------------------------------------------------------

    \1496\ Order No. 1920, 187 FERC ] 61,068 at P 1198.
    \1497\ Id. P 1199.
    \1498\ Large Public Power Request for Rehearing at 16.
    \1499\ See Order No. 1920, 187 FERC ] 61,068 at P 1214.
    \1500\ See, e.g., id. P 224. The Order No. 890 transmission 
planning principles include transparency and obligate transmission 
providers to disclose to all customers and other stakeholders the 
basic criteria, assumptions, and data that underlie their 
transmission system plans. See Order No. 890, 118 FERC ] 61,119 at 
PP 435, 471. In Order No. 890, the transparency transmission 
planning principle also requires transmission providers to reduce to 
writing and make available the basic methodology, criteria, and 
processes they use to develop their transmission plans, including 
how they treat retail native loads, in order to ensure that 
standards are consistently applied. Order No. 890, 118 FERC ] 61,119 
at P 471.
---------------------------------------------------------------------------

    600. We deny NESCOE's request that the Commission establish a 
rebuttable presumption in favor of alternative transmission 
technologies.\1501\ Rather, it is the Commission's longstanding policy 
to remain fuel and technology neutral.\1502\ As such, and consistent 
with the Commission's finding in Order No. 2023,\1503\ we decline to 
create a presumption in favor of substituting alternative transmission 
technologies in either Long-Term Regional Transmission Planning or the 
existing Order No. 1000 regional transmission planning processes. There 
is insufficient evidence in the record to presume that an alternative 
transmission technology would be the more efficient or cost-effective 
solution as a replacement for a traditional wires-based solution or 
that the addition of an alternative transmission technology to a 
potential transmission solution would necessarily result in a more 
efficient or cost-effective solution in all instances. Consequently, 
Order No. 1920 mandates a process for the consideration of alternative 
transmission technologies, not specific outcomes.\1504\
---------------------------------------------------------------------------

    \1501\ NESCOE Request for Rehearing at 6, 22-25.
    \1502\ See, e.g., Order No. 1920, 187 FERC ] 61,068 at P 437 
(``We emphasize that the Commission's policies are technology 
neutral, and we are not establishing a preference for certain types 
of generation or energy end uses.'').
    \1503\ Order No. 2023, 184 FERC ] 61,054 at P 1582 (``This final 
rule does not create a presumption in favor of substituting 
alternative transmission technologies for necessary traditional 
network upgrades, either categorically or in specific cases.'').
    \1504\ See id.
---------------------------------------------------------------------------

2. Technology Specific Requests for Rehearing and Clarification
a. Requests for Rehearing and Clarification
    601. Clean Energy Associations and PIOs assert that the Commission 
failed to engage in reasoned decision-making by not requiring 
transmission providers to evaluate storage resources that perform a 
transmission function as alternative transmission technologies.\1505\ 
Clean Energy Associations and PIOs disagree that the Commission's 
finding that ``whether an electric storage resource performs a 
transmission function requires a case-by-case analysis'' justifies its 
exclusion from the list of enumerated alternative transmission 
technologies because, they argue, all transmission solutions are 
studied on a case-by-case basis.\1506\ Clean Energy Associations 
further argue that whether a particular storage resource is performing 
a transmission function is completely separate and distinct from the 
issue of whether a storage resource that has been determined on a case-
specific basis to be providing a transmission function should be 
included in the list of enumerated alternative transmission 
technologies.\1507\ Clean Energy Associations argue that the proper 
approach is to require storage resources that would be providing a 
transmission function be included in the enumerated list of alternative 
transmission technologies.\1508\
---------------------------------------------------------------------------

    \1505\ Clean Energy Associations Rehearing Request at 26-30; 
PIOs Rehearing Request at 7, 38-43 (citations omitted).
    \1506\ Clean Energy Associations Rehearing Request at 26 
(quoting Order No. 1920, 187 FERC ] 61,068 at P 1245); PIOs 
Rehearing Request at 40.
    \1507\ Clean Energy Associations Rehearing Request at 26.
    \1508\ Id. at 27.
---------------------------------------------------------------------------

    602. Clean Energy Associations assert that the Commission's 
decision to exclude storage providing a transmission function is not 
supported by substantial evidence and is unduly discriminatory.\1509\ 
Clean Energy Associations argue that the record evidence demonstrates 
that storage can provide efficient or cost-effective solutions and that 
the Commission did not cite evidence that considering storage in 
transmission planning is potentially detrimental or lacks stakeholder 
support.\1510\ Clean Energy Associations further argue that the 
Commission failed to distinguish storage resources providing a 
transmission function from advanced conductors and transmission 
switching technologies, which were added to the advanced technologies 
enumerated in the final rule. Clean Energy Associations assert that 
there is no rational basis to exclude storage resources from the list 
and that it is unduly discriminatory to exclude storage.\1511\ Clean 
Energy Associations state that the Commission should grant rehearing 
and require transmission providers to consider storage as a 
transmission asset in Long-Term Regional Transmission Planning.\1512\
---------------------------------------------------------------------------

    \1509\ Id. at 26-30.
    \1510\ Id. at 27-28 (citing Emera Me., 854 F.3d at 22).
    \1511\ Id. at 29-30 (citing FPL Energy Marcus Hook, L.P. v. 
FERC, 430 F.3d 441, 449 (D.C. Cir. 2005); Emera Me., 854 F.3d at 
22).
    \1512\ Id. at 30.
---------------------------------------------------------------------------

    603. PIOs assert that the Commission's omission of storage as a 
transmission asset from the list of alternative transmission 
technologies that transmission providers must consider in Long-Term 
Regional Transmission Planning and existing Order No. 1000 regional 
transmission planning processes was arbitrary and capricious because 
the Commission did not meaningfully engage with commenters or provide a 
reasoned basis for its decision.\1513\ PIOs urge the Commission to 
grant rehearing to require transmission providers to evaluate storage 
as a part of Long-Term Regional Transmission Planning.\1514\
---------------------------------------------------------------------------

    \1513\ PIOs Rehearing Request at 38, 42-43 (citations omitted).
    \1514\ Id. at 43.
---------------------------------------------------------------------------

    604. PIOs observe that the Commission has identified considerations 
that, together, ensure that a selected storage resource will serve a 
transmission function; nevertheless, they argue the Commission failed 
to explain why it did not simply note that the use of storage as a 
transmission asset will ultimately need to comply with these 
considerations, rather than omitting it as an alternative transmission 
technology.\1515\ PIOs state that under the Commission's approach in 
Order No. 1920, in which it explained that ``transmission providers are 
the appropriate entity to identify, evaluate, and select specific 
solutions to specific transmission needs,'' it need not dictate how 
transmission providers evaluate storage as transmission.\1516\
---------------------------------------------------------------------------

    \1515\ Id. at 41-42 (citing Order No. 1920, 187 FERC ] 61,068 at 
P 1245, n.2671; Sw. Power Pool, Inc., 183 FERC ] 61,153, at P 29 
(2023)).
    \1516\ Id. at 41 (quoting Order No. 1920, 187 FERC ] 61,068 at P 
1210).
---------------------------------------------------------------------------

    605. CTC Global states that the Commission's definition of advanced 
conductors allows for the consideration of advanced conductors that are 
not representative of the capabilities represented by the 
Commission.\1517\

[[Page 97289]]

CTC Global states that this may allow transmission providers to avoid 
consideration of the types of advanced conductors that Congress 
intended to be reviewed in the Energy Policy Act of 2005 and that the 
US DOE has described in reports.\1518\ For this reason, CTC Global 
requests clarification, or in the alternative rehearing, that the 
definition of advanced conductors will ensure that sufficiently 
advanced conductors--which at a given voltage increase power flow 
capabilities by at least 1.5 times, decrease losses by 20% or more, and 
improve conductor sag performance--are included in regional 
transmission planning processes. CTC Global states that such a 
clarification is needed to ensure that the conditions that the 
Commission identified as leading to unjust and unreasonable rates are 
addressed and argues that failure to do so will continue to result in 
project identification that may not be more efficient or cost-effective 
than alternatives.\1519\
---------------------------------------------------------------------------

    \1517\ CTC Global Rehearing Request at 2-3.
    \1518\ Id. (citing Energy Policy Act of 2005, Public Law 109-58, 
1223, 119 Stat. 594, 953-954 (2005)).
    \1519\ Id. at 2-5, 10-17.
---------------------------------------------------------------------------

    606. Invenergy argues that the Commission should clarify that HVDC 
is an alternative transmission technology that may be considered in 
long-term and nearer-term regional transmission planning 
processes.\1520\ Invenergy explains that the Commission did not 
specifically address the use of HVDC, despite PIOs arguing for its 
consideration as an alternative transmission technology. Invenergy 
agrees with PIOs' comments and states that PIOs clearly demonstrated in 
their comments how HVDC can be beneficial.\1521\ In light of this 
demonstration, Invenergy asks the Commission to grant clarification 
that transmission providers are not precluded from considering HVDC 
like other alternative transmission technologies or other potential 
solutions that may be considered in long-term and nearer-term regional 
transmission planning processes.\1522\
---------------------------------------------------------------------------

    \1520\ Invenergy Rehearing Request at 10-13.
    \1521\ Id. at 11-12 (citing PIOs NOPR Initial Comments at 22, 
Ex. A at PP 20, 22,).
    \1522\ Id. at 13.
---------------------------------------------------------------------------

b. Commission Determination
    607. We sustain the Commission's decision in Order No. 1920 to not 
include storage as a transmission asset in the enumerated list of 
alternative transmission technologies that transmission providers must 
consider.\1523\ We continue to find that the evaluation of whether an 
electric storage resource performs a transmission function requires a 
case-by-case analysis of how a particular electric storage resource 
would be operated as well as any requirements set forth in an OATT 
governing selection of such electric storage resources as transmission 
solutions.\1524\ Therefore, we continue to find that it is 
inappropriate to require the consideration of storage that performs a 
transmission function on a generic basis. While Clean Energy 
Associations and PIOs argue that any transmission solution requires a 
case-by-case analysis, electric storage resources require an additional 
case-by-case analysis that distinguishes them from other transmission 
solutions and from the enumerated list of alternative transmission 
technologies.\1525\ Namely, that type of analysis would require the 
transmission provider to determine, among other considerations: (1) 
that the electric storage resource would strictly act as a transmission 
asset, connected to the transmission system as a transmission facility 
solely to support that transmission provider's transmission system; (2) 
the electric storage resource's cost recovery, by ensuring that the 
electric storage resource's participation in markets is limited to only 
charging from, and discharging to, the transmission provider's 
transmission system as necessary to provide the services for which it 
was selected based on the cost of the maximum capacity needed to 
address the identified transmission issue; and (3) that the electric 
storage resource's construction would not impact the generator 
interconnection queue.\1526\ We reiterate, however, that Order No. 1920 
does not preclude transmission providers from considering other 
alternative transmission technologies that were not included in the 
enumerated list of alternative transmission technologies, including 
storage as a transmission asset, in their Long-Term Regional 
Transmission Planning and existing Order No. 1000 regional transmission 
planning processes.\1527\
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    \1523\ Order No. 1920, 187 FERC ] 61,068 at P 1245.
    \1524\ Id. In Order No. 2023, the Commission pointed to the 
process in SPP, which takes into account five considerations that, 
together, ensure that a selected electric storage resource will 
serve a transmission function. Order No. 2023, 184 FERC ] 61,054 at 
P 1599 (citing Sw. Power Pool, Inc., 183 FERC ] 61,153, at P 29 
(2023)).
    \1525\ Order No. 2023, 184 FERC ] 61,054 at P 1599; Order No. 
2023-A, 186 FERC ] 61,199 at P 640.
    \1526\ Sw. Power Pool, Inc., 183 FERC ] 61,153, at P 29 (2023).
    \1527\ Order No. 1920, 187 FERC ] 61,068 at P 1247.
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    608. In response to CTC Global, we clarify that the requirement to 
consider alternative transmission technologies necessitates that 
transmission providers consider the types of advanced conductors that 
Congress intended to be reviewed in the Energy Policy Act of 2005 and 
that the US DOE has described in its reports.\1528\ However, we decline 
to alter the definition of an advanced conductor.\1529\ We continue to 
find that advanced conductors include present and future transmission 
line technologies whose power flow capacities exceed the power flow 
capacities of conventional aluminum conductor steel reinforced 
conductors,\1530\ and that advanced conductors include, but are not 
limited to, superconducting cables, advanced composite conductors, 
advanced steel cores, high temperature low-sag conductors, fiber optic 
temperature sensing conductors, and advanced overhead conductors.\1531\ 
However, we clarify that transmission providers, rather than 
considering just one of the six advanced conductor examples listed, 
must instead consider each of the six advanced conductor examples 
listed, and, as they determine appropriate, any additional advanced 
conductor which that transmission provider determines might be more 
efficient or cost-effective. In doing so, transmission providers must 
consider a range of advanced conductor options with a variety of 
performance and cost attributes, including those with the performance 
capabilities described by CTC Global.\1532\ We deny CTC Global's 
request to add performance metrics to the definition of an advanced 
conductor because it would limit the scope of advanced conductors 
required to be considered and thereby eliminate from

[[Page 97290]]

required consideration certain advanced conductors that may be more 
efficient or cost-effective in specific circumstances.
---------------------------------------------------------------------------

    \1528\ See, e.g., U.S. Dep't of Energy, Advanced Transmission 
Technologies 25-28 (Dec. 2020), https://www.energy.gov/sites/prod/files/2021/02/f82/Advanced%20Transmission%20Technologies%20Report%20-%20final%20as%20of%2012.3%20-%20FOR%20PUBLIC.pdf; see also U.S. Dep't of Energy, 
Pathways to Commercial Liftoff: Innovative Grid Deployment 77 
(2024), https://liftoff.energy.gov/wp-content/uploads/2024/05/Liftoff_Innovative-Grid-Deployment_Final_5.2-1.pdf; see also 42 
U.S.C. 16422(b) (directing the Commission to ``encourage, as 
appropriate, the deployment of advanced transmission 
technologies''); id. Sec.  16422(a) (defining ``advanced 
transmission technology'' as ``a technology that increases the 
capacity, efficiency, or reliability of an existing or new 
transmission facility'').
    \1529\ See CTC Global Rehearing Request at 4-5 (setting forth 
proposed modified definition).
    \1530\ Order No. 1920, 187 FERC ] 61,068 at P 1198 n.2553.
    \1531\ Id. P 1243.
    \1532\ CTC Global Rehearing Request at 2-5 (requesting that the 
Commission clarify that advanced conductors are those that have 
power flow capabilities that exceed those of conventional aluminum 
conductor steel reinforced conductors at a given voltage by a factor 
of at least 1.5 times while decreasing electrical losses by 20% or 
more, and improve conductor sag performance, at the same or reduced 
weight per foot).
---------------------------------------------------------------------------

    609. In response to Invenergy,\1533\ we clarify that transmission 
providers are not precluded from considering HVDC facilities in Long-
Term Regional Transmission Planning and existing Order No. 1000 
regional transmission planning processes. In Order No. 1920, the 
Commission clarified that transmission providers are not precluded from 
considering other alternative transmission technologies that are not 
included in the enumerated list of alternative transmission 
technologies or other potential solutions in their Long-Term Regional 
Transmission Planning and existing Order No. 1000 regional transmission 
planning processes.\1534\ That clarification applies to the 
consideration of HVDC technologies.
---------------------------------------------------------------------------

    \1533\ Invenergy Rehearing Request at 10-13.
    \1534\ Order No. 1920, 187 FERC ] 61,068 at P 1247.
---------------------------------------------------------------------------

VIII. Regional Transmission Cost Allocation

A. Obligation To File an Ex Ante Long-Term Regional Transmission Cost 
Allocation Method and Its Use as a Backstop

1. Logical Outgrowth
a. NOPR Proposals
    610. In the NOPR, the Commission proposed to require transmission 
providers in each transmission planning region to revise their OATTs to 
include one of the following: (1) a Long-Term Regional Transmission 
Cost Allocation Method to allocate the costs of Long-Term Regional 
Transmission Facilities; (2) a State Agreement Process by which one or 
more Relevant State Entities may voluntarily agree to a cost allocation 
method; or (3) a combination thereof.\1535\
---------------------------------------------------------------------------

    \1535\ NOPR, 179 FERC ] 61,028 at P 302. The Commission 
explained that, for example, a ``combination'' approach may entail 
(i) providing a Long-Term Regional Transmission Cost Allocation 
Method for certain types of Long-Term Regional Transmission 
Facilities and providing a State Agreement Process for others; or 
(ii) providing for cost allocation for a Long-Term Regional 
Transmission Facility, portfolio, or type of such facilities 
partially based on a Long-Term Regional Transmission Cost Allocation 
Method and partially based on funding contributions in accordance 
with a State Agreement Process. Id. P 302 n.510.
---------------------------------------------------------------------------

    611. The Commission noted that if states agree to a State Agreement 
Process instead of a Long-Term Regional Transmission Cost Allocation 
Method, certain Long-Term Regional Transmission Facilities selected in 
the regional transmission plan for purposes of cost allocation would 
lack a clear ex ante cost allocation method,\1536\ and sought comment 
on whether the Commission should require transmission providers to 
include a Long-Term Regional Transmission Cost Allocation Method in 
their OATTs, in lieu of the proposed reform.\1537\ The Commission 
requested comment on the appropriate outcome when Relevant State 
Entities fail to agree on a cost allocation method for all or a portion 
of Long-Term Regional Transmission Facilities, including whether in 
such circumstances the transmission providers should be required to 
establish a Long-Term Regional Transmission Cost Allocation 
Method.\1538\
---------------------------------------------------------------------------

    \1536\ Id. P 315.
    \1537\ Id. P 318.
    \1538\ Id. P 310.
---------------------------------------------------------------------------

b. Order No. 1920 Requirements
    612. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to revise their OATTs to 
include one or more Long-Term Regional Transmission Cost Allocation 
Methods \1539\ for Long-Term Regional Transmission Facilities that are 
selected and permitted transmission providers to additionally revise 
their OATTs to include a State Agreement Process, if Relevant State 
Entities indicate that they have agreed to such a process. The 
Commission required that a State Agreement Process cannot be the sole 
method filed for cost allocation for Long-Term Regional Transmission 
Facilities, and that if a State Agreement Process fails to result in a 
cost allocation method agreed to by Relevant State Entities and any 
other authorized entities, or if the Commission ultimately finds that 
the cost allocation method that results from a State Agreement Process 
is unjust, unreasonable, or unduly discriminatory or preferential, then 
the relevant Long-Term Regional Transmission Cost Allocation Method on 
file would apply as a backstop.\1540\
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    \1539\ The Commission defined Long-Term Regional Transmission 
Cost Allocation Method as an ex ante regional cost allocation method 
for one or more Long-Term Regional Transmission Facilities (or a 
portfolio of such Facilities) that are selected in the regional 
transmission plan for purposes of cost allocation. Order No. 1920, 
187 FERC ] 61,068 at P 1291.
    \1540\ Id. PP 1291-1292.
---------------------------------------------------------------------------

    613. In Order No. 1920, the Commission stated that it was not 
imposing any obligation on transmission providers to file a cost 
allocation method for Long-Term Regional Transmission Facilities with 
which they disagree, even if such a method were proposed to the 
transmission providers pursuant to a Commission-approved State 
Agreement Process, unless the transmission providers have clearly 
indicated their assent to do so as part of a Commission-approved State 
Agreement Process in their OATTs.\1541\
---------------------------------------------------------------------------

    \1541\ Id. P 1429.
---------------------------------------------------------------------------

c. Requests for Rehearing and Clarification
    614. Several commenters argue that Order No. 1920 substantially 
departs from and is not a logical outgrowth of the NOPR because Order 
No. 1920 does not require transmission providers to adopt a State 
Agreement Process, consequently denying Relevant State Entities any 
meaningful opportunity to determine regional cost allocation.\1542\ 
Arizona Commission asserts that, contrary to the NOPR, Order No. 1920 
``effectively eliminates the use of a voluntary State Agreement 
Process, such as the one that has been used by PJM since Order No. 
1000,'' which it asserts is ``directly contrary to comments filed by 
state regulators.'' \1543\ Idaho Commission argues that ``[i]n a 
substantial departure from the NOPR, Order No. 1920 allows, but does 
not require, transmission providers in each transmission planning 
region to adopt a State Agreement Process for allocating the costs of 
all, or a subset of, Long-Term Regional Transmission Facilities.'' 
\1544\ Designated Retail Regulators similarly contend that Order No. 
1920 ``drastically depart[s] from the NOPR'' because it gives 
transmission providers complete discretion to decide whether to file a 
State Agreement Process or Long-Term Regional Transmission Cost 
Allocation method in its OATT, even if agreed to by the Relevant State 
Entities, which would relegate states to a transmission planning role 
akin to any other stakeholder.\1545\
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    \1542\ Arizona Commission Rehearing Request at 19; Idaho 
Commission Rehearing Request at 2, 5-6.
    \1543\ Arizona Commission Rehearing Request at 19.
    \1544\ Idaho Commission Rehearing Request at 5 (quotation marks 
omitted).
    \1545\ Designated Retail Regulators Rehearing Request at 47-50.
---------------------------------------------------------------------------

    615. Designated Retail Regulators and Arizona Commission also 
contend that Order No. 1920 violates the APA's notice-and-comment 
requirements because it requires transmission providers to set an ex 
ante cost allocation method that would apply as a backstop in certain 
circumstances, reducing states' bargaining power and setting up a 
mechanism to impose a regional cost allocation for preferential

[[Page 97291]]

policy and corporate-driven projects when states do not consent.\1546\
---------------------------------------------------------------------------

    \1546\ Arizona Commission Rehearing Request at 18; Designated 
Retail Regulators Rehearing Request at 47, 49-50.
---------------------------------------------------------------------------

d. Commission Determination
    616. We find that the Commission's decision in Order No. 1920 not 
to require that transmission providers adopt a State Agreement Process 
is a logical outgrowth of the NOPR, and we thus disagree with arguments 
to the contrary. The NOPR did not propose to require a State Agreement 
Process but rather proposed to require transmission providers to 
include in their OATTs either a Long-Term Regional Transmission Cost 
Allocation Method, or a State Agreement Process, or a combination 
thereof.\1547\ Furthermore, contrary to Arizona Commission's arguments, 
Order No. 1920 did not eliminate the State Agreement Process and 
instead permits transmission providers to revise their OATTs to include 
a State Agreement Process, if Relevant State Entities indicate that 
they have agreed to such a process.\1548\
---------------------------------------------------------------------------

    \1547\ NOPR, 179 FERC ] 61,028 at P 302.
    \1548\ Order No. 1920, 187 FERC ] 61,068 at PP 1291-1292.
---------------------------------------------------------------------------

    617. We also disagree with Arizona Commission's and Designated 
Retail Regulators' argument that Order No. 1920's requirement for 
transmission providers to revise their OATTs to include at least one ex 
ante Long-Term Regional Transmission Cost Allocation Method is not a 
logical outgrowth of the NOPR proposal to allow transmission providers 
to choose to include either an ex ante regional cost allocation method, 
or a State Agreement Process, or a combination of both. Although the 
Commission in the NOPR proposed to allow transmission providers to 
choose between filing an ex ante Long-Term Regional Transmission Cost 
Allocation Method, a State Agreement Process, or some combination of 
both, the Commission also sought comment on ``whether the Commission 
should require, instead of the reforms proposed in this section of the 
NOPR, public utility transmission providers to include a Long-Term 
Regional Transmission Cost Allocation Method in their OATTs.'' \1549\ 
As courts have explained, notice is sufficient when an agency has 
``expressly asked for comments on a particular issue or otherwise made 
clear that the agency was contemplating a particular change.'' \1550\ 
By requesting comment on whether the Commission should require 
inclusion of an ex ante Long-Term Regional Transmission Cost Allocation 
Method, the Commission put parties on notice that the Commission was 
considering the exact change that it ultimately adopted in Order No. 
1920. Therefore, in adopting the requirement that transmission 
providers file at least one ex ante Long-Term Regional Transmission 
Cost Allocation Method, the Commission adhered to the APA's notice-and-
comment requirements.\1551\ To the extent Arizona Commission's and 
Designated Retail Regulators' argument was based on concerns about the 
states' role more broadly in Long-Term Regional Transmission Planning 
and cost allocation processes, we note that we adopt a number of 
modifications and clarifications herein to strengthen the states' role 
in those processes.\1552\
---------------------------------------------------------------------------

    \1549\ NOPR, 179 FERC ] 61,028 at P 318.
    \1550\ Brennan v. Dickson, 45 F.4th at 69 (quoting CSX Transp., 
Inc. v. Surface Transp. Bd., 584 F.3d at 1081).
    \1551\ Further, Order No. 1920's requirement that transmission 
providers revise their OATTs to include at least one ex ante Long-
Term Regional Transmission Cost Allocation Method separately and 
independently satisfies the APA's notice-and-comment requirements 
because courts have indicated that a final rule is a logical 
outgrowth of a proposal where, as here, an agency adopts only part 
of a proposal such that ``the final rule [is] not wholly unrelated 
or surprisingly distant'' from what the agency initially suggested. 
Ariz. Pub. Serv. Co. v. EPA, 211 F.3d 1280, 1297-1300 (D.C. Cir. 
2000) (finding sufficient notice where agency first proposed that 
Indian tribes be required to meet the ``same requirements'' as 
states with respect to judicial review of permits issued pursuant to 
the Clean Air Act, but then adopted a final rule that exempted 
tribes from some, though not all, such requirements). Order No. 1920 
is a logical outgrowth of the NOPR in this respect because the 
Commission adopted one of three proposed methods for complying with 
the requirement--i.e., part of the NOPR proposal--and the challenged 
provision therefore hews closely to the NOPR proposal such that it 
is ``not wholly unrelated or surprisingly distant'' from the NOPR 
proposal. Id.
    \1552\ See supra Stakeholder Process and Transparency section; 
Requests for Additional Flexibility Regarding Long-Term Scenarios 
Requirements section; infra Consultation with Relevant State 
Entities After the Engagement Period section.
---------------------------------------------------------------------------

2. Substantive Issues
a. Order No. 1920 Requirements
    618. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to revise their OATTs to 
include one or more ex ante cost allocation methods that apply to Long-
Term Regional Transmission Facilities that are selected in the regional 
transmission plan for purposes of cost allocation (Long-Term Regional 
Transmission Cost Allocation Method).\1553\
---------------------------------------------------------------------------

    \1553\ Order No. 1920, 187 FERC ] 61,068 at P 1291.
---------------------------------------------------------------------------

    619. In addition to the required Long-Term Regional Transmission 
Cost Allocation Method, Order No. 1920 permits transmission providers 
to revise their OATTs to include a State Agreement Process. However, 
the Commission found in Order No. 1920 that any State Agreement Process 
that transmission providers voluntarily propose to include in their 
OATTs would not comply with the requirements of Order No. 1920 unless 
Relevant State Entities indicate to the transmission provider that 
Relevant State Entities have agreed to that process during the 
Engagement Period.\1554\ The Commission also found in Order No. 1920 
that a State Agreement Process cannot be the sole method filed for cost 
allocation for Long-Term Regional Transmission Facilities.\1555\ The 
Commission explained in Order No. 1920 that, if a State Agreement 
Process that transmission providers voluntarily include in their OATTs 
fails to result in a cost allocation method agreed to by Relevant State 
Entities and any other authorized entities, or if the Commission 
ultimately finds the cost allocation method that results from a State 
Agreement Process is unjust, unreasonable, or unduly discriminatory or 
preferential, then the relevant Long-Term Regional Transmission Cost 
Allocation Method on file would apply as a backstop.\1556\
---------------------------------------------------------------------------

    \1554\ Id.; see also id. PP 1292, 1403.
    \1555\ Id. PP 1292, 1361, 1404.
    \1556\ Id. PP 1291-1292.
---------------------------------------------------------------------------

    620. Order No. 1920 does not require transmission providers to 
obtain state agreement to a cost allocation method for any Long-Term 
Regional Transmission Facilities and states that the ultimate decision 
as to which Long-Term Regional Transmission Cost Allocation Method(s) 
to file on compliance, and whether to file a State Agreement Process to 
which Relevant State Entities have agreed, lies with transmission 
providers.\1557\
---------------------------------------------------------------------------

    \1557\ Id. PP 1359, 1429; see also id. PP 1296, 1363.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    621. On rehearing, a number of parties argue that the Commission's 
decision in Order No. 1920 to require transmission providers to file an 
ex ante cost allocation method for Long-Term Regional Transmission 
Facilities will undermine Relevant State Entities' efforts to determine 
an alternative cost allocation method through a State Agreement 
Process.\1558\ NARUC requests that the Commission adopt the NOPR 
proposal of mandatory agreement

[[Page 97292]]

on filed method(s) and/or a State Agreement Process and eliminate the 
backstop ex ante method.\1559\ NARUC argues that Order No. 1920's 
requirement that transmission providers have a backstop Long-Term 
Regional Transmission Cost Allocation Method in their OATTs undermines 
Relevant State Entities' negotiation of an alternative cost allocation 
method and turns such negotiations into a ``check the box'' 
exercise.\1560\ NARUC asserts that allowing transmission providers to 
ignore or not even report on state input is the definition of an 
arbitrary and capricious action, and constitutes unreasonable decision 
making.\1561\
---------------------------------------------------------------------------

    \1558\ Designated Retail Regulators Rehearing Request at 35-36; 
Idaho Commission Rehearing Request at 5-6; NARUC Rehearing Request 
at 12-17; Ohio Commission Federal Advocate Rehearing Request at 8; 
Undersigned States Rehearing Request at 31-32; Wyoming Commission 
Rehearing Request at 2-4.
    \1559\ NARUC Rehearing Request at 12-17.
    \1560\ Id. at 16.
    \1561\ Id. at 15.
---------------------------------------------------------------------------

    622. Ohio Commission Federal Advocate states that Order No. 1920 
arbitrarily and capriciously requires an Engagement Period for states 
to participate in reaching a cost allocation agreement for Long-Term 
Regional Transmission Facilities while providing no assurance that it 
will amount to anything since the final rule allows the transmission 
provider to have the final say.\1562\ Ohio Commission Federal Advocate 
argues that, because of this, states ultimately have no authority on 
cost allocation for Long-Term Regional Transmission Facilities.\1563\
---------------------------------------------------------------------------

    \1562\ Ohio Commission Federal Advocate Rehearing Request at 7-
8.
    \1563\ Id. at 8.
---------------------------------------------------------------------------

    623. Designated Retail Regulators and Undersigned States state that 
Order No. 1920's requirement that transmission providers file one or 
more ex ante cost allocation methods that apply to selected Long-Term 
Regional Transmission Facilities eliminates the effectiveness of the 
State Agreement Process, as states are unlikely to agree to a 
negotiated cost allocation proposal under the State Agreement Process 
if the default ex ante cost allocation results in lower costs for those 
states.\1564\ Designated Retail Regulators and Undersigned States argue 
that if states jointly agree on a cost allocation process, the rules 
should require the transmission provider to accept those cost 
allocation processes, subject to Commission approval.\1565\
---------------------------------------------------------------------------

    \1564\ Designated Retail Regulators Rehearing Request at 35-36; 
Undersigned States Rehearing Request at 31-32.
    \1565\ Designated Retail Regulators Rehearing Request at 35; 
Undersigned States Rehearing Request at 31.
---------------------------------------------------------------------------

    624. Wyoming Commission states that the Commission's decision to 
remove the voluntary state agreement without a backstop reform in the 
final rule was a significant change from the NOPR, as the NOPR proposal 
would have allowed states to represent their public policy interests 
and, in the event of a conflict, prevent other states from exporting 
their policy decisions and an unreasonable share of related costs to 
nonconsenting neighbors. Wyoming Commission argues, however, that as a 
result of reducing states' roles to mere stakeholders in the final 
rule, the Commission has forced states into agreeing to unjust and 
unreasonable cost allocations by defaulting to an ex ante cost 
allocation in lieu of requiring a voluntary agreement of the states as 
a prerequisite.\1566\ Wyoming Commission asserts that a voluntary state 
agreement process is essential to avoid interfering with states' rights 
with respect to transmission planning and selection, and to prevent 
nonconsenting states from being ``swept up'' in their neighbors' 
identified public policy transmission projects.\1567\
---------------------------------------------------------------------------

    \1566\ Wyoming Commission Rehearing Request at 2-3.
    \1567\ Id. at 3.
---------------------------------------------------------------------------

    625. Idaho Commission argues that by permitting, but not requiring, 
transmission providers to adopt a State Agreement Process in compliance 
with Order No. 1920, the states lack a meaningful opportunity to 
determine a reasonable cost allocation.\1568\ Idaho Commission claims 
that the Commission's reasoning in not requiring a State Agreement 
Process is unsupported in the record and ignores that Relevant State 
Entities have statutory duties to ensure fair, just, and reasonable 
rates for customers.\1569\ Idaho Commission further contends that 
requiring state agreement for cost allocation for Long-Term Regional 
Transmission Facilities, as the Commission proposed in the NOPR, would 
have allowed states to represent public policy interests and prevent 
other states from forcing policy decisions on nonconsenting neighbors. 
However, Idaho Commission asserts that as a result of Order No. 1920, 
states now have no meaningful opportunity to determine reasonable cost 
allocation and will be faced with cost allocation that violates the 
cost causation principle.\1570\
---------------------------------------------------------------------------

    \1568\ Idaho Commission Rehearing Request at 5-6.
    \1569\ Id.
    \1570\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    626. While we sustain the determination in Order No. 1920 that 
transmission providers in each transmission planning region must file 
one or more ex ante cost allocation methods that apply to selected 
Long-Term Regional Transmission Facilities, we believe that certain 
modifications adopted in this order help address, at least in part, 
concerns raised on rehearing by ensuring that the Commission may 
consider any Long-Term Regional Transmission Cost Allocation Methods 
supported by Relevant State Entities.\1571\ We believe the balance 
struck in this order will assist the Commission, with the input of 
Relevant State Entities, in establishing just and reasonable Long-Term 
Regional Transmission Cost Allocation Methods that meet the 
requirements of Order No. 1920.
---------------------------------------------------------------------------

    \1571\ See infra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section.
---------------------------------------------------------------------------

    627. In Order No. 1920, the Commission required that, if a State 
Agreement Process fails to result in a cost allocation method agreed to 
by Relevant State Entities and any other entities authorized by 
Relevant State Entities to participate in a State Agreement 
Process,\1572\ a transmission provider chooses not to file an agreed 
upon cost allocation method, or if the Commission ultimately finds the 
cost allocation method that results from a State Agreement Process is 
unjust, unreasonable, or unduly discriminatory or preferential, then 
the relevant Long-Term Regional Transmission Cost Allocation Method on 
file would apply as a backstop. While we sustain the requirement to 
have a backstop Long-Term Regional Transmission Cost Allocation Method 
on file, we revise the portion of this requirement related to the 
transmission providers' choice as to whether to file Long-Term Regional 
Transmission Cost Allocation Methods and/or State Agreement Processes 
agreed to by Relevant State Entities, as discussed in further detail 
below.\1573\
---------------------------------------------------------------------------

    \1572\ Order No. 1920, 187 FERC ] 61,068 at P 1402 (noting that 
Relevant State Entities have the option to include the participation 
of other entities in a State Agreement Process).
    \1573\ See infra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section.
---------------------------------------------------------------------------

    628. Turning to the rehearing requests challenging the requirement 
to have an ex ante cost allocation method on file, we disagree with 
Wyoming Commission and Idaho Commission that this requirement forces 
states into agreeing to unjust and unreasonable cost allocations that 
allow states to foist the cost of their policy decisions on 
nonconsenting neighbors.\1574\ Under the NOPR proposal, the Commission 
proposed that transmission providers in each transmission planning 
region file OATTs to include either (1) a Long-

[[Page 97293]]

Term Regional Transmission Cost Allocation Method to allocate the costs 
of Long-Term Regional Transmission Facilities, or (2) a State Agreement 
Process by which one or more relevant state entities may voluntarily 
agree to a cost allocation method, or (3) a combination thereof.\1575\ 
Pursuant to the FPA, the Commission may accept only proposed rates, 
terms, and conditions that are just and reasonable. Therefore, the 
Commission could not accept a cost allocation method that would force 
states into agreeing to unjust and unreasonable cost allocations, and 
any just and reasonable cost allocation method must ensure that the 
costs of Long-Term Regional Transmission Facilities are allocated in a 
manner that is at least roughly commensurate with the estimated 
benefits.\1576\
---------------------------------------------------------------------------

    \1574\ See Idaho Commission Rehearing Request at 5-6; Wyoming 
Commission Rehearing Request at 3.
    \1575\ NOPR, 179 FERC ] 61,028 at P 302.
    \1576\ Order No. 1920, 187 FERC ] 61,068 at PP 1510, 1515; see, 
e.g., ICC v. FERC I, 576 F.3d at 476 (``To the extent that a utility 
benefits from the costs of new facilities, it may be said to have 
`caused' a part of those costs to be incurred, as without the 
expectation of its contributions the facilities might not have been 
built, or might have been delayed.''); Order No. 1000, 136 FERC ] 
61,051 at P 690 (``If a regional transmission plan determines that a 
transmission facility serves several functions, as many commenters 
point out it may, the regional cost allocation method must take the 
benefits of these functions of the transmission facility into 
account in allocating costs roughly commensurate with benefits.'').
---------------------------------------------------------------------------

    629. We also disagree with arguments that the State Agreement 
Process will ultimately be a ``check the box'' exercise or that 
requiring an ex ante Long-Term Regional Transmission Cost Allocation 
Method otherwise limits the effectiveness of a State Agreement 
Process.\1577\ Order No. 1920 places an affirmative obligation on 
transmission providers to supply a forum for states to negotiate cost 
allocation,\1578\ providing ample room for states to allocate costs in 
a manner that they agree to,\1579\ and, as discussed below, in this 
order we require transmission providers to include in the transmittal 
or as an attachment to their compliance filing any Long-Term Regional 
Transmission Cost Allocation Method and/or State Agreement Process that 
Relevant State Entities agree upon.\1580\ Relevant State Entities may 
structure the processes used to determine those cost allocation methods 
in a manner that would require a level of agreement of their choosing, 
including, as one potential option, unanimity.\1581\ In this order, we 
also establish a requirement that transmission providers shall consult 
with Relevant State Entities (1) prior to amending the Long-Term 
Regional Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es), or (2) if Relevant State Entities seek, consistent with 
their chosen method to reach agreement, for the transmission provider 
to amend that method or process.\1582\ And as we have already 
discussed, transmission providers shall develop a reasonable number of 
additional scenarios, when requested by Relevant State Entities, for 
the purposes of informing the application of Long-Term Regional 
Transmission Cost Allocation Method(s) or the development of cost 
allocation methods through the State Agreement Process(es).\1583\
---------------------------------------------------------------------------

    \1577\ NARUC Rehearing Request at 16; Ohio Commission Federal 
Advocate Rehearing Request at 7-8; Designated Retail Regulators 
Rehearing Request at 35-36; Undersigned States Rehearing Request at 
31-32.
    \1578\ Order No. 1920, 187 FERC ] 61,068 at PP 1354, 1356-1357.
    \1579\ Id. PP 1415-1416.
    \1580\ See infra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section.
    \1581\ Order No. 1920, 187 FERC ] 61,068 at P 1418 (``We will 
not specify the level of agreement among Relevant State Entities or 
other entities that is necessary before a transmission provider 
files a cost allocation method derived from a State Agreement 
Process. As a state-led process, we believe that Relevant State 
Entities should have the ability to determine this important facet 
of their State Agreement Process.'').
    \1582\ See infra Consultation with Relevant States Entities 
After the Engagement Period section.
    \1583\ See supra Requests for Additional Flexibility Regarding 
Long-Term Scenarios Requirements section.
---------------------------------------------------------------------------

    630. To the extent that Wyoming Commission argues that requiring an 
ex ante cost allocation method for Long-Term Regional Transmission 
Facilities intrudes on states' rights with respect to transmission 
planning and selection, we disagree. We note that the D.C. Circuit held 
that requiring ex ante cost allocation methods under Order No. 1000 
regional transmission planning does not intrude on state 
authority.\1584\ We continue to find that Long-Term Regional 
Transmission Planning is a subset of regional transmission planning 
that closes specific gaps of the existing Order No. 1000 framework 
without otherwise disturbing the regional transmission planning 
structure required by Order No. 1000, which was fully affirmed on 
appeal.\1585\
---------------------------------------------------------------------------

    \1584\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-59, 62-
64, 82-89; id. at 64 ((``[W]e hold that [Order No. 1000] does not 
interfere with the traditional state authority that is preserved by 
[FPA] Section 201 . . . .'').
    \1585\ Order No. 1920, 187 FERC ] 61,068 at P 256 (citing S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 55-64 (rejecting arguments 
that the requirement to engage in regional transmission planning, as 
prescribed in Order No. 1000, exceeded the Commission's jurisdiction 
under FPA section 206, interfered with traditional state authority 
reserved under FPA section 201, or improperly interpreted and 
applied FPA section 202(a))).
---------------------------------------------------------------------------

    631. With respect to the assertion that states are unlikely to 
agree to a negotiated cost allocation proposal under the State 
Agreement Process if the default ex ante cost allocation results in 
lower costs for those states, we note that Order No. 1920 provides 
Relevant State Entities with the opportunity to negotiate ex ante cost 
allocation methods in the first instance, and we take steps in this 
order to further enable states to do so.\1586\ Further, states are 
likely to have an incentive to negotiate with other states in order to 
ensure timely and efficient development of Long-Term Regional 
Transmission Facilities that benefit their ratepayers, but would not be 
developed without the support of other states. We find that the 
opportunity for Relevant State Entities to negotiate ex ante cost 
allocation methods in the first instance and agree to a State Agreement 
Process, coupled with the benefits of certainty provided by a backstop 
ex ante cost allocation method, strike a reasonable balance, and we 
otherwise sustain, as explained in greater detail below, the 
Commission's finding in Order No. 1920 that requiring transmission 
providers to include a Long-Term Regional Transmission Cost Allocation 
Method in their OATTs is necessary to ensure that Commission-
jurisdictional rates are just and reasonable.\1587\
---------------------------------------------------------------------------

    \1586\ See infra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section; Duration of the 
Engagement Period section.
    \1587\ Order No. 1920, 187 FERC ] 61,068 at P 1293.
---------------------------------------------------------------------------

    632. We disagree with Idaho Commission's contention that Order No. 
1920 denies Relevant State Entities any meaningful opportunity to 
determine reasonable cost allocation methods.\1588\ We recognize the 
critical role that states play in regional transmission planning and 
that Relevant State Entities have their own statutory obligations. As 
discussed in Order No. 1920, and expanded upon here,\1589\ we are 
placing an affirmative obligation on transmission providers to provide 
a meaningful opportunity for Relevant State Entities to share their 
views on cost allocation during the Engagement Period, during 
subsequent implementation of a State Agreement Process to which the 
Relevant State Entities have agreed that has been filed by a 
transmission provider and accepted by the Commission,\1590\ and, as 
described herein, before future cost

[[Page 97294]]

allocation amendments.\1591\ Relevant State Entities therefore have a 
meaningful opportunity to participate in cost allocation decisions 
related to Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \1588\ Idaho Commission Rehearing Request at 5-6.
    \1589\ See infra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section; Duration of the 
Engagement Period section.
    \1590\ Order No. 1920, 187 FERC ] 61,068 at P 1296.
    \1591\ See infra Consultation with Relevant State Entities After 
the Engagement Period section.
---------------------------------------------------------------------------

    633. We continue to find that if transmission providers were to 
rely solely on a State Agreement Process to determine the cost 
allocation for Long-Term Regional Transmission Facilities and that 
process did not result in agreement on a cost allocation method, there 
would be no cost allocation method for Long-Term Regional Transmission 
Facilities selected as the more efficient or cost-effective solutions 
to Long-Term Transmission Needs.\1592\ As a result, these selected 
Long-Term Regional Transmission Facilities would be less likely to be 
developed, and the benefits that these facilities would provide would 
not be realized.\1593\ Furthermore, we continue to find that, if these 
selected Long-Term Regional Transmission Facilities were not ultimately 
built, transmission providers would likely rely on relatively 
inefficient or less cost-effective transmission facilities to address 
the identified Long-Term Transmission Needs, or they may not even 
address these needs at all, leading to unjust and unreasonable 
Commission-jurisdictional rates.\1594\
---------------------------------------------------------------------------

    \1592\ Order No. 1920, 187 FERC ] 61,068 at P 1293.
    \1593\ Id.
    \1594\ Id.
---------------------------------------------------------------------------

    634. In addition, we are concerned that a state-agreement 
requirement could lead to a situation in which a transmission project 
was planned based on benefits that it provides to customers in several 
states, and that, if one or more of those states declined to 
voluntarily agree to a cost allocation method, it would raise free-
ridership concerns.\1595\ For that reason, sole reliance on a State 
Agreement Process has the potential to suffer from the same flaws that 
led the Commission to require ex ante cost allocation for selected 
regional transmission facilities in Order No. 1000, as the allocation 
of transmission costs can be contentious and prone to litigation in 
multi-state transmission planning regions.\1596\ The level of certainty 
for transmissions providers in having a Long-Term Regional Transmission 
Cost Allocation Method on file, even when a State Agreement Process is 
used, remains critical to the development of needed Long-Term Regional 
Transmission Facilities.\1597\
---------------------------------------------------------------------------

    \1595\ See El Paso Elec. Co. v. FERC, 76 F.4th at 361-63 (``No 
amount of emphasizing other competing interests permits FERC to 
sacrifice the foundational principle of cost-causation by refusing 
to allocate costs to those who cause the costs to be incurred and 
who reap the resulting benefits.'' (citations omitted)); Order No. 
1000, 136 FERC ] 61,051 at P 535 (``[If] the Commission could not 
address free rider problems associated with new transmission 
investment, [ ] it could not ensure that rates, terms and conditions 
of jurisdictional service are just and reasonable and not unduly 
discriminatory.'').
    \1596\ Order No. 1920, 187 FERC ] 61,068 at P 1293 (citation 
omitted).
    \1597\ Id.
---------------------------------------------------------------------------

B. Requirements Concerning Relevant State Entities

1. Requested Requirement To Obtain the Agreement of Relevant State 
Entities
a. Order No. 1920 Requirements
    635. In Order No. 1920, the Commission declined to adopt the NOPR 
proposal to require transmission providers to seek the agreement of 
Relevant State Entities within the transmission planning region 
regarding the relevant cost allocation method to be applied to Long-
Term Regional Transmission Facilities. Instead, the Commission modified 
the NOPR proposal to establish a six-month time period (Engagement 
Period), during which transmission providers must, among other 
requirements, provide a forum for negotiation of a Long-Term Regional 
Transmission Cost Allocation Method(s) and/or a State Agreement Process 
that enables meaningful participation by Relevant State Entities.\1598\
---------------------------------------------------------------------------

    \1598\ Id. P 1354.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    636. Undersigned States and Designated Retail Regulators argue that 
the Engagement Period is not a ``fair replacement of a requirement for 
regulator consent'' because Order No. 1920 does not require 
transmission providers to propose on compliance a Long-Term Regional 
Transmission Cost Allocation Method agreed to by the states.\1599\ 
Undersigned States and Designated Retail Regulators further argue that 
Order No. 1920's lack of a requirement for transmission providers to 
obtain the consent of retail regulators on the cost allocation 
method(s) that apply to Long-Term Regional Transmission Facilities 
usurps state authority because it enables the ratepayers of non-
consenting states to be assessed the costs of the public policy 
projects of other states and speculative investment based on conjecture 
about future resource trends.\1600\ Designated Retail Regulators argue 
that existing regulator organizations such as OMS ``may not be the best 
forums to confect state agreements'' because the ``authority to reach 
agreement on cost allocation rests in each State'' and cannot be 
delegated to such organizations in order to reach general consensus on 
issues.\1601\
---------------------------------------------------------------------------

    \1599\ Designated Retail Regulators Rehearing Request at 36; 
Undersigned States Rehearing Request at 32.
    \1600\ Designated Retail Regulators Rehearing Request at 36-39; 
Undersigned States Rehearing Request at 32-35.
    \1601\ Designated Retail Regulators Rehearing Request at 38.
---------------------------------------------------------------------------

c. Commission Determination
    637. While we sustain our decision not to adopt the NOPR proposal 
and instead establish the Engagement Period for cost allocation 
negotiations, we believe that certain modifications in this order help 
address, at least in part, the concerns raised by Designated Retail 
Regulators and Undersigned States by providing additional opportunities 
for Relevant State Entities to help establish just and reasonable cost 
allocation methods for Long-Term Regional Transmission 
Facilities.\1602\
---------------------------------------------------------------------------

    \1602\ See infra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section; Duration of the 
Engagement Period section; Consultation with Relevant State Entities 
After the Engagement Period section.
---------------------------------------------------------------------------

    638. Turning to Designated Retail Regulators' and Undersigned 
States' arguments, the Commission did not propose in the NOPR to 
require transmission providers to obtain the consent of Relevant State 
Entities within the transmission planning region regarding the relevant 
cost allocation method to be applied to Long-Term Regional Transmission 
Facilities. Rather, the Commission proposed to require transmission 
providers to seek the agreement of Relevant States Entities within the 
transmission planning region regarding the relevant cost allocation 
method to be applied to Long-Term Regional Transmission 
Facilities.\1603\ In Order No. 1920, the Commission did not adopt the 
requirement for transmission providers to seek the agreement of 
Relevant State Entities (while affording transmission providers 
flexibility in the process by which they seek agreement

[[Page 97295]]

from the Relevant State Entities) and instead adopted a requirement for 
transmission providers to provide a forum for states to meaningfully 
participate in negotiating cost allocation methods.\1604\
---------------------------------------------------------------------------

    \1603\ Order No. 1920, 187 FERC ] 61,068 at P 1354 (``We decline 
to adopt the NOPR proposal to require transmission providers to seek 
the agreement of Relevant State Entities within the transmission 
planning region regarding the relevant cost allocation method to be 
applied to Long-Term Regional Transmission Facilities.'' (emphasis 
added)). We address arguments concerning the Commission's decision 
not to require transmission providers to seek the agreement of 
Relevant State Entities in the Requests Arguing the Engagement 
Period is Inferior to a Requirement that Transmission Providers Seek 
the Agreement of Relevant State Entities section below.
    \1604\ See id. PP 1354, 1357.
---------------------------------------------------------------------------

    639. With respect to requests that we require agreement of state 
regulators for any cost allocation method for Long-Term Regional 
Transmission Facilities, we continue to find that the views of state 
regulators regarding the appropriate cost allocation approach are 
important, but ultimately the transmission provider is the public 
utility that must respond and comply with Order No. 1920.\1605\ 
Furthermore, the Commission has a statutory responsibility to review 
the compliance filings from transmission providers to ensure that any 
proposed cost allocation is just and reasonable and not unduly 
discriminatory or preferential, and Order No. 1920 recognizes these 
statutory roles.\1606\ Nonetheless, we reiterate that robust state 
engagement can valuably inform a cost allocation approach and, as 
discussed further below, we take steps in this order to further that 
engagement.
---------------------------------------------------------------------------

    \1605\ Id. P 1363.
    \1606\ Id.
---------------------------------------------------------------------------

    640. In response to Designated Retail Regulators' and Undersigned 
States' argument that Order No. 1920's lack of a requirement for 
transmission providers to obtain the consent of states on the cost 
allocation method(s) that apply to Long-Term Regional Transmission 
Facilities enables the ratepayers of non-consenting states to be 
assessed the costs of other states' public policies and speculative 
investment,\1607\ in addition to the steps to further state engagement 
taken herein, we note that all cost allocation methods for Long-Term 
Regional Transmission Facilities, including Long-Term Regional 
Transmission Cost Allocation Methods and cost allocation methods 
resulting from State Agreement Processes, must allocate the costs of 
Long-Term Regional Transmission Facilities in a manner that is at least 
roughly commensurate with the estimated benefits, consistent with legal 
precedent.\1608\ We find that this requirement addresses Designated 
Retail Regulators' and Undersigned States' concern that Order No. 
1920's requirements will result in non-consenting states paying for 
costs they did not cause.
---------------------------------------------------------------------------

    \1607\ Designated Retail Regulators Rehearing Request at 37-38; 
Undersigned States Rehearing Request at 33.
    \1608\ See supra P 628 n.1577.
---------------------------------------------------------------------------

    641. In response to Designated Retail Regulators' assertion that 
the ``authority to reach agreement on cost allocation rests in each 
State'' and that this authority cannot be ``delegated to organizations 
that States participate in to attempt to reach general consensus on 
issues,'' \1609\ we note that Order No. 1920 did not require 
transmission providers to use existing mechanisms for state involvement 
in regional transmission planning and cost allocation processes, such 
as the SPP Regional State Committee and OMS, as a forum for negotiation 
of a Long-Term Regional Transmission Cost Allocation Method(s) and/or a 
State Agreement Process.\1610\ In fact, Order No. 1920 specified that 
it is Relevant State Entities--and not transmission providers--who may 
choose to use such an existing mechanism to negotiate a Long-Term 
Regional Transmission Cost Allocation Method(s) and/or a State 
Agreement Process.\1611\ Similarly, the Commission left to the Relevant 
State Entities participating in the Engagement Period matters including 
what constitutes agreement among Relevant State Entities, how such 
agreement is reached, and which Relevant State Entities must reach such 
agreement.\1612\
---------------------------------------------------------------------------

    \1609\ See Designated Retail Regulators Rehearing Request at 38.
    \1610\ Order No. 1920, 187 FERC ] 61,068 at P 1357.
    \1611\ Id.
    \1612\ Id. P 1360.
---------------------------------------------------------------------------

2. Requirements Concerning Relevant State Entities' Preferred Cost 
Allocation Methods
a. Order No. 1920 Requirements
    642. In Order No. 1920, the Commission found that, if the Relevant 
State Entities participating in an Engagement Period agree on a Long-
Term Regional Transmission Cost Allocation Method(s) and/or State 
Agreement Process and provide that Method(s) and/or State Agreement 
Process to the transmission providers no later than the deadline for 
communicating agreement, the transmission providers may file the 
agreed-to Long-Term Regional Transmission Cost Allocation Method(s) 
and/or State Agreement Process on compliance. The Commission noted, 
however, that the ultimate decision as to whether to file a Long-Term 
Regional Transmission Cost Allocation Method(s) and/or State Agreement 
Process to which Relevant State Entities have agreed will continue to 
lie with the transmission providers.\1613\ In addition, the Commission 
found that its directives in Order No. 1920 regarding the development 
of a State Agreement Process and any cost allocation methods to which 
the Relevant State Entities agree pursuant to that process do not alter 
existing FPA section 205 filing rights that would govern subsequent 
filings regarding the cost allocation for Long-Term Regional 
Transmission Facilities.\1614\ The Commission did not impose any 
obligation on transmission providers to file a cost allocation method 
for Long-Term Regional Transmission Facilities with which they 
disagree, even if such a method were proposed to the transmission 
providers pursuant to a Commission-approved State Agreement Process, 
unless the transmission providers have clearly indicated their assent 
to do so as part of a Commission-approved State Agreement Process in 
their OATT.\1615\
---------------------------------------------------------------------------

    \1613\ Id. PP 1359, 1363.
    \1614\ Id. P 1430 (``We further clarify that unless voluntarily 
waived, a transmission provider retains its FPA section 205 filing 
rights to submit an ex ante cost allocation method for Long-Term 
Regional Transmission Facilities at any time, consistent with any 
limitations a transmission provider may have agreed to, for example, 
as part of its membership in an RTO/ISO.'') (citation omitted).
    \1615\ Id. PP 1359, 1429.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    643. NARUC, PJM States, Designated Retail Regulators, Undersigned 
States, and West Virginia Commission request rehearing of Order No. 
1920's decision not to require transmission providers to adopt any cost 
allocation method that Relevant State Entities agree upon during the 
Engagement Period.\1616\ NARUC argues that Order No. 1920 ``arbitrarily 
and without adequate explanation removes protections proposed in the 
NOPR for states and their ratepayers by not requiring [t]ransmission 
[providers] to incorporate state consensus to cost allocation methods 
for filing as part of the OATT.'' \1617\ PJM States argue that, absent 
such a requirement, state engagement in the development of cost 
allocation methods for Long-Term Regional Transmission Facilities is 
not likely to materialize. PJM States argue that, by contrast, 
incenting state agreement (and the filing of that agreement) makes it 
more likely that Order No. 1920's goals are met, as a state-agreed upon 
cost allocation method has a lower burden of proof than a transmission 
provider filing without state agreement.\1618\ West

[[Page 97296]]

Virginia Commission agrees with PJM States and argues that the 
Commission should either require transmission providers to adopt any 
cost allocation method that Relevant State Entities agree upon during 
the Engagement Period or ``grant the States 205 filing rights as it 
pertains to State-agreed cost allocation methods.'' \1619\
---------------------------------------------------------------------------

    \1616\ NARUC Rehearing Request at 12; PJM States Rehearing 
Request at 2-3; Designated Retail Regulators Rehearing Request at 
35; Undersigned States Rehearing Request at 31; West Virginia 
Commission Rehearing Request at 13-14.
    \1617\ NARUC Rehearing Request at 12.
    \1618\ PJM States Rehearing Request at 2-3 (citing Order No. 
1920, 187 FERC ] 61,068 at PP 1469, 1472, 1476).
    \1619\ West Virginia Commission Rehearing Request at 13-14.
---------------------------------------------------------------------------

    644. PIOs, PJM States, and NARUC request clarification that, where 
a particular cost allocation method garnered state support during the 
Engagement Period and the transmission provider elects not to adopt 
that method in its compliance filing, the transmission provider must 
include the states' preferred cost allocation method in its compliance 
filing and explain why that method was not used.\1620\ West Virginia 
Commission requests the same clarification in the alternative to its 
request that the Commission require transmission providers to adopt any 
cost allocation method that Relevant State Entities agree upon during 
the Engagement Period.\1621\ West Virginia Commission requests that the 
Commission require transmission providers to include the states' 
preferred cost allocation method ``for informational purposes.'' \1622\ 
NARUC further requests that the Commission clarify that transmission 
providers' compliance filings must also include a general description 
of the discussions during the Engagement Period, including transmission 
providers' outreach to Relevant State Entities.\1623\ Similarly, NARUC, 
PJM States, and Virginia and North Carolina Commissions request that 
the Commission clarify that transmission providers must disclose the 
extent to which states agreed or disagreed with the filed cost 
allocation method.\1624\ PIOs also request that the Commission clarify 
that: (1) transmission providers must ``clearly disclose and explain 
the outcome'' of the Engagement Period; (2) the Commission will 
carefully evaluate the existence of a state agreement regarding cost 
allocation and any departure from that agreement in reviewing cost 
allocation methods proposed by transmission providers on compliance; 
and (3) transmission providers must explain how their chosen cost 
allocation methods are just and reasonable and not unduly 
discriminatory or preferential. PIOs contend that their requested 
clarifications would offer states additional confidence that 
participation in the Engagement Period will be meaningful.\1625\
---------------------------------------------------------------------------

    \1620\ NARUC Rehearing Request at 17-18; PIOs Rehearing Request 
at 55-57; PJM States Rehearing Request at 7-8.
    \1621\ West Virginia Commission Rehearing Request at 9.
    \1622\ Id.
    \1623\ NARUC Rehearing Request at 17-18.
    \1624\ Id. at 17; PJM States Rehearing Request at 7; Virginia 
and North Carolina Commissions Rehearing Request at 10.
    \1625\ PIOs Rehearing Request at 54-57.
---------------------------------------------------------------------------

    645. NESCOE requests rehearing of Order No. 1920's decision to not 
require transmission providers to file states' preferred cost 
allocation method along with transmission providers' own preferred cost 
allocation method. NESCOE argues that because states are not public 
utilities, absent language in the transmission providers' 
organizational documents or OATTs, states are unable to file cost 
allocation methods themselves. NESCOE argues that ``[r]elegating states 
to commenting on a transmission provider's cost allocation filing does 
not enable the states to put before the Commission their preferred cost 
allocation method; rather, it shifts the burden to states to show that 
the transmission provider's FPA section 205 filing is not just and 
reasonable.'' \1626\ NESCOE contends that Order No. 1920 envisions that 
the only path for states to have their preferred cost allocation method 
approved would be through a complaint proceeding in which states would 
bear the burden of first proving that a transmission provider's 
Commission-approved cost allocation method is unjust and 
unreasonable.\1627\ NESCOE argues that requiring each transmission 
provider to file states' preferred cost allocation method alongside its 
own would comport with precedent holding that the Commission may not 
require transmission providers `` `to cede rights expressly given to 
them' in FPA section 205.'' \1628\ In the alternative, NESCOE requests 
that the Commission strongly encourage transmission providers to 
``voluntarily codify existing or new approaches on compliance'' that 
would facilitate transmission providers' filing of alternative region-
wide state agreement on cost allocation, such as the approaches used in 
the NYISO and SPP regions.\1629\ NESCOE opines that ``[i]ncluding the 
state-agreed upon cost allocation method in a transmission provider's 
section 205 filing is a lawful and rational means to effectuate in a 
concrete way the respect for the state role the Commission 
articulates.'' \1630\
---------------------------------------------------------------------------

    \1626\ NESCOE Rehearing Request at 14-15.
    \1627\ Id. Vermont Commission states that it supports the NESCOE 
Rehearing Request, including strengthening the state role in all 
phases of Long-Term Regional Transmission Planning, and specifically 
cost allocation. Vermont Commission Rehearing Request at 1-2.
    \1628\ NESCOE Rehearing Request at 15 (quoting Atl. City Elec. 
Co. v. FERC, 295 F.3d at 9).
    \1629\ Id. at 15-16 (citing NESCOE NOPR Initial Comments at 69-
70 (citing N.Y. Indep. Sys. Operator, Inc., 151 FERC ] 61,040, at P 
119 (2015) (NYISO); SPP, Governing Documents Tariff, Bylaws, First 
Revised Volume No. 4 (0.0.0), Sec.  7.2)).
    \1630\ Id. at 16.
---------------------------------------------------------------------------

    646. Harvard ELI requests that the Commission grant rehearing by 
requiring transmission providers to revise their OATTs to include a 
process for filing all regional cost allocation methods approved by 
Relevant State Entities.\1631\ Harvard ELI contends that, by not 
requiring transmission providers to file all cost allocation methods 
agreed to by Relevant State Entities, Order No. 1920 fails to remedy 
unjust and unreasonable cost allocation processes.\1632\ Harvard ELI 
argues that such a requirement would not violate the D.C. Circuit's 
holding in Atlantic City because it would neither ``deny utilities 
their right to unilaterally file rate and term changes'' nor ``force 
public utilities to file particular rates.'' \1633\ Harvard ELI argues 
that, because the Commission ``has authority to approve utility filing 
rights arrangements under FPA section 205,'' it also has the authority 
under FPA section 206 to order changes to filing processes and may do 
so here to require transmission providers to file all cost allocation 
methods approved by the Relevant State Entities.\1634\ In the 
alternative, Harvard ELI requests that the Commission clarify that it 
did not intend to imply that it lacks authority under FPA section 206 
to amend the pro forma OATT to include a process for filing all 
regional cost allocation methods approved by Relevant State 
Entities.\1635\
---------------------------------------------------------------------------

    \1631\ Harvard ELI Rehearing Request at 1-3.
    \1632\ Id. at 6 (stating that existing cost allocation 
requirements do not provide a ``dedicated process through which 
states have an opportunity to participate in the development of 
regional cost allocation methods'' (quoting Order No. 1920, 187 FERC 
] 61,068 at P 126)).
    \1633\ Id. at 4-5 (alteration omitted) (quoting Atl. City Elec. 
Co. v. FERC, 295 F.3d at 10).
    \1634\ Id. at 4.
    \1635\ Id. at 1, 8-9.
---------------------------------------------------------------------------

    647. NARUC requests that the Commission provide a mechanism to 
ensure that transmission providers ``remain in compliance with the 
requirement to include [R]elevant [S]tate [E]ntities in cost allocation 
for Long-Term Regional Transmission Facilities.'' \1636\ NARUC asserts 
that the Commission should either require transmission providers to 
periodically open new Engagement Periods or require transmission 
providers to file a

[[Page 97297]]

modification to their OATTs if states reach the requisite agreement on 
a different cost allocation method than that reflected in the 
transmission providers' OATTs.\1637\
---------------------------------------------------------------------------

    \1636\ NARUC Rehearing Request at 21-22.
    \1637\ Id. In the Consultation with Relevant State Entities 
After the Engagement Period section below, we discuss NARUC's 
request that the Commission require transmission providers to 
periodically open a new negotiation period with Relevant State 
Entities concerning cost allocation for Long-Term Regional 
Transmission Facilities.
---------------------------------------------------------------------------

    648. PIOs request clarification that transmission providers may, in 
their compliance filings, voluntarily commit to a process that will 
ensure that, where a state agreement on cost allocation exists, the 
agreed-upon cost allocation method will be put before the Commission 
for approval.\1638\
---------------------------------------------------------------------------

    \1638\ PIOs Rehearing Request at 55-56.
---------------------------------------------------------------------------

c. Commission Determination
    649. As the Commission recognized in Order No. 1920, and we 
reiterate in this order, it is critical to the success of the Long-Term 
Regional Transmission Planning reforms that states have an opportunity 
to have a significant role in the establishment of just and reasonable 
Long-Term Regional Transmission Cost Allocation Methods and State 
Agreement Processes.\1639\ At the same time, the Commission has an 
independent responsibility to ensure that those cost allocation methods 
conform to the cost causation principle and are otherwise just and 
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \1639\ See, e.g., Order No. 1920, 187 FERC ] 61,068 at P 1415.
---------------------------------------------------------------------------

    650. To address these considerations and the concerns raised on 
rehearing, we simultaneously (1) expand Relevant State Entities' 
opportunities to inform and provide alternatives to the transmission 
providers' proposed Long-Term Regional Transmission Cost Allocation 
Method, and (2) sustain Order No. 1920's determination that 
transmission providers retain the right to determine which cost 
allocation methods for Long-Term Regional Transmission Facilities they 
will propose on compliance. Accordingly, while we decline rehearing 
parties' requests that the Commission require transmission providers to 
adopt any cost allocation method that Relevant State Entities agree 
upon during the Engagement Period, we take steps to ensure that the 
Commission may consider the Relevant State Entities' preferred Long-
Term Regional Transmission Cost Allocation Method(s) and/or State 
Agreement Process, to the extent those differ from the Method(s) filed 
by transmission providers on compliance.
    651. To that end, we set aside Order No. 1920, in part, and require 
that when Relevant State Entities notify transmission providers by the 
deadline for communicating agreement \1640\ that they agree on a Long-
Term Regional Transmission Cost Allocation Method and/or State 
Agreement Process resulting from the Engagement Period, the 
transmission providers must include that method or process in the 
transmittal or as an attachment to their compliance filing, even if the 
transmission providers propose a different Long-Term Regional 
Transmission Cost Allocation Method or do not propose to adopt a State 
Agreement Process. We further direct transmission providers to include 
in the transmittal or as an attachment to their compliance filings any 
information that Relevant State Entities provide to them regarding the 
state negotiations during the Engagement Period. We also set aside 
Order No. 1920, in part, to require that, upon the request of Relevant 
State Entities, transmission providers must facilitate and participate 
in a cost allocation discussion during the Engagement Period with 
Relevant State Entities.
---------------------------------------------------------------------------

    \1640\ Order No. 1920 requires that transmission providers in 
each transmission planning region provide notice, such as on its 
OASIS page or public website, of the deadline for Relevant State 
Entities to communicate their agreement on a Long-Term Regional 
Transmission Cost Allocation Method(s) and/or a State Agreement 
Process, and this deadline must be no earlier than the end date of 
the Engagement Period. Id. P 1356.
---------------------------------------------------------------------------

    652. At the outset, in response to arguments concerning the 
Commission's authority to impose the various cost allocation 
requirements proposed by parties on rehearing,\1641\ we reiterate that 
the Commission in Order No. 1920 determined that the Commission's 
existing regional transmission planning and cost allocation 
requirements are unjust, unreasonable, and unduly discriminatory or 
preferential under FPA section 206.\1642\ The Commission thus had both 
the authority and responsibility to ``determine the just and reasonable 
. . . practice . . . to be thereafter observed and in force,'' \1643\ 
consistent with Order No. 1920's findings. Pursuant to its authority 
under FPA section 206, the Commission required transmission providers 
to submit on compliance an ex ante cost allocation method. This 
compliance filing submitted pursuant to FPA section 206 is not an FPA 
section 205 filing,\1644\ and is thus distinct from any FPA section 205 
filing that a transmission provider might file in the future following 
compliance to propose a change to its cost allocation method(s) for 
Long-Term Regional Transmission Facilities.\1645\
---------------------------------------------------------------------------

    \1641\ E.g., Harvard ELI Rehearing Request at 4; NESCOE 
Rehearing Request at 15.
    \1642\ Order No. 1920, 187 FERC ] 61,068 at PP 113-114; supra 
The Overall Need for Reform section.
    \1643\ 16 U.S.C. 824e(a).
    \1644\ See ISO New England Inc., 165 FERC ] 61,202 (2018), order 
on reh'g, 173 FERC ] 61,204, at P 8 (2020) (clarifying that the 
Commission would review ISO-NE's proposed tariff revisions as a new 
FPA section 205 filing, rather than a compliance filing, because the 
Commission had not previously made ``a finding that ISO-NE's tariff 
was unjust and unreasonable without such revisions, a necessary 
precursor to the Commission considering ISO-NE's tariff revisions as 
a compliance filing setting forth a proposed replacement rate'').
    \1645\ See Order No. 1920, 187 FERC ] 61,068 at P 1430. As 
discussed below in the Consultation with Relevant State Entities 
After the Engagement Period section, we adopt, as part of this rule, 
a requirement that transmission providers revise their OATTs to add 
a requirement that they consult with Relevant State Entities (1) 
prior to amending the Long-Term Regional Transmission Cost 
Allocation Method(s) and/or State Agreement Process(es), or (2) if 
Relevant State Entities seek, consistent with their chosen method to 
reach agreement, for the transmission provider to amend that method 
or process.
---------------------------------------------------------------------------

    653. We believe the balance struck herein should address, at least 
in part, the concerns driving the rehearing requests of NARUC, PJM 
States, Designated Retail Regulators, Undersigned States, and West 
Virginia Commission, who request that the Commission require 
transmission providers to adopt any cost allocation method that 
Relevant State Entities agree upon during the Engagement Period, and 
NESCOE, which argues that the Commission should require transmission 
providers to propose on compliance Relevant State Entities' preferred 
cost allocation method along with transmission providers' preferred 
cost allocation method.\1646\ While we continue to find that robust 
state engagement is valuable to informing cost allocation,\1647\ we 
also recognize transmission providers, subject to Commission oversight, 
remain ultimately responsible for transmission planning,\1648\ which we 
find is fundamentally linked with cost allocation.\1649\ Consistent 
with this responsibility, while reiterating the balance the Commission 
seeks to strike

[[Page 97298]]

in this order regarding the role of Relevant State Entities, we decline 
to require transmission providers, on compliance, to propose to adopt a 
State Agreement Process or Long-Term Regional Transmission Cost 
Allocation Method to which Relevant State Entities agreed, particularly 
if transmission providers prefer an alternative approach to cost 
allocation.
---------------------------------------------------------------------------

    \1646\ NARUC Rehearing Request at 12; NESCOE Rehearing Request 
at 14-15; PJM States Rehearing Request at 2-3; Designated Retail 
Regulators Rehearing Request at 35; Undersigned States Rehearing 
Request at 31; West Virginia Commission Rehearing Request at 13-14.
    \1647\ Order No. 1920, 187 FERC ] 61,068 at P 1363.
    \1648\ Id. See also Order No. 1000, 136 FERC ] 61,051 at P 153; 
Order No. 890, 118 FERC ] 61,119 at P 454.
    \1649\ Order No. 1000, 136 FERC ] 61,051 at P 559 (``[T]here is 
a fundamental link between cost allocation and planning, as it is 
through the planning process that benefits, which are central to 
cost allocation, can be assessed.'').
---------------------------------------------------------------------------

    654. However, we are persuaded by PIOs', PJM States', and NARUC's 
arguments that the Commission should consider any Long-Term Regional 
Transmission Cost Allocation Method and/or State Agreement process to 
which the Relevant State Entities agree. We agree that the Commission 
should require transmission providers to include in the transmittal of 
their compliance filings any Long-Term Regional Transmission Cost 
Allocation Method and/or State Agreement Process to which the Relevant 
State Entities agreed but that transmission providers elect not to 
propose to comply with Order No. 1920.\1650\ Therefore, we set aside 
Order No. 1920, in part, and require that, when Relevant State Entities 
communicate to transmission providers by the deadline for communicating 
agreement that they agree on a Long-Term Regional Transmission Cost 
Allocation Method and/or State Agreement Process resulting from the 
Engagement Period, the transmission providers must include that method 
or process in the transmittal or as an attachment to their compliance 
filings, even if the transmission providers propose to adopt a 
different Long-Term Regional Transmission Cost Allocation Method or do 
not propose to revise their tariffs to include a State Agreement 
Process.\1651\ We continue to decline to define what constitutes 
agreement among Relevant State Entities,\1652\ but we note that, at the 
choosing of the Relevant State Entities in a transmission planning 
region, existing relevant state committee processes may guide Relevant 
State Entities in defining what constitutes agreement, such as the 
processes of OMS and NESCOE.
---------------------------------------------------------------------------

    \1650\ See NARUC Rehearing Request at 17-18; PIOs Rehearing 
Request at 55-57; PJM States Rehearing Request at 7-8.
    \1651\ We clarify that, under this approach, the transmission 
providers decide what to submit as their actual Order No. 1920 
compliance proposal, including relevant tariff language and 
supporting evidence or arguments, whether they decide to propose the 
Relevant State Entities' agreed-upon Long-Term Regional Transmission 
Cost Allocation Method and/or State Agreement Process or a different 
Long-Term Regional Transmission Cost Allocation Method. The 
requirement to include Relevant State Entities' Long-Term Regional 
Transmission Cost Allocation Method and/or State Agreement Process 
as an addition to the compliance filing does not constitute a 
``proposal'' from the transmission provider.
    \1652\ Order No. 1920, 187 FERC ] 61,068 at P 1360.
---------------------------------------------------------------------------

    655. We are also persuaded by NARUC's, PIOs', PJM States', and 
Virginia and North Carolina Commissions' arguments that the Commission 
should require transmission providers to provide additional information 
related to Relevant State Entities' participation in the Engagement 
Period even when transmission providers propose on compliance a 
separate cost allocation method and/or decline to propose a State 
Agreement Process,\1653\ and we therefore further direct transmission 
providers to include in the transmittal or as an attachment to their 
compliance filings any information that any Relevant State Entities 
provide to them regarding the state negotiations during the Engagement 
Period. As part of this requirement, we clarify that transmission 
providers must include any and all supporting evidence and/or 
justification related to Relevant State Entities' agreed-upon Long-Term 
Regional Transmission Cost Allocation Method and/or State Agreement 
Process that Relevant State Entities request that transmission 
providers include in their compliance filing. We expect that the 
information that Relevant State Entities provide to transmission 
providers could include, for example, a description of the discussions 
that took place at the Engagement Period forum for negotiation and 
whether each Relevant State Entity agreed or disagreed with the cost 
allocation method proposed on compliance. However, we decline to 
require transmission providers to independently characterize this 
information. For example, we do not require transmission providers to 
separately characterize Relevant State Entities' agreement or 
independently justify Relevant State Entities' preferred Long-Term 
Regional Transmission Cost Allocation Method and/or State Agreement 
Process. We find that a requirement for transmission providers to 
include in the transmittal or as an attachment to their compliance 
filings the information received from any Relevant State Entities 
during the Engagement Period will sufficiently capture the results of 
the Engagement Period.
---------------------------------------------------------------------------

    \1653\ NARUC Rehearing Request at 17; PIOs Rehearing Request at 
54-57; PJM States Rehearing Request at 7; Virginia and North 
Carolina Commission Rehearing Request at 10.
---------------------------------------------------------------------------

    656. Furthermore, upon review of the requests for rehearing and 
clarification about the Engagement Period, we also believe that 
Relevant State Entities would benefit from the assistance of 
transmission providers in some cases, as transmission providers may 
have more experience with the transmission providers' OATTs and with 
the Commission's processes and precedent. Therefore, we set aside Order 
No. 1920, in part, and now include a requirement that upon the request 
of Relevant State Entities, transmission providers must facilitate and 
participate in a cost allocation discussion during the Engagement 
Period with Relevant State Entities.
    657. We find that these additional requirements will allow the 
Commission to better evaluate whether transmission providers have 
complied with Order No. 1920's requirement to provide a forum for 
negotiation that enables meaningful participation by Relevant State 
Entities during the Engagement Period.\1654\ Furthermore, given that we 
direct these facilitation and informational requirements on compliance 
pursuant to the Commission's authority under FPA section 206, we find 
that these requirements do not implicate or infringe upon transmission 
providers' filing rights under FPA section 205.
---------------------------------------------------------------------------

    \1654\ Order No. 1920, 187 FERC ] 61,068 at P 1357.
---------------------------------------------------------------------------

    658. When acting under FPA section 206, the Commission's statutory 
burden is to establish a just and reasonable and not unduly 
discriminatory replacement rate that is supported by substantial 
evidence.\1655\ The statute does not necessarily require the Commission 
to adopt the transmission provider's proposal on compliance, even if 
that proposal complies with the final rule's requirements. Rather, the 
Commission need only select a replacement rate that complies with the 
final rule and that is adequately supported in the record, and then 
intelligibly explain the reasons for its choice.\1656\
---------------------------------------------------------------------------

    \1655\ 16 U.S.C. 824e; 16 U.S.C 825l(b).
    \1656\ See Entergy Ark., LLC v. FERC, 40 F.4th 689, 701-02 (D.C. 
Cir. 2022) (noting that the Commission ``is not required to choose 
the best solution, only a reasonable one'') (first quoting Petal Gas 
Storage, LLC v. FERC, 496 F.3d 695, 703 (D.C. Cir. 2007); and then 
quoting EPSA, 577 U.S. at 295).
---------------------------------------------------------------------------

    659. We recognize that the Commission generally does not consider 
alternate compliance proposals other than those filed by the relevant 
public utility (here, the transmission provider).\1657\ Nevertheless, 
as the Commission explained in Order No. 1920, and as we reiterate on 
rehearing, there are ``good reasons'' for considering such alternatives 
here with respect to

[[Page 97299]]

cost allocation under Order No. 1920.\1658\ States play a unique role 
in Long-Term Regional Transmission Planning, as their laws, 
regulations, and policies drive the need for Long-Term Regional 
Transmission Facilities,\1659\ and they typically will have 
responsibility to consider and approve the siting, permitting, and 
construction of Long-Term Regional Transmission Facilities selected in 
a regional transmission plan. As such, states affect whether Long-Term 
Regional Transmission Facilities are timely, efficiently, and cost-
effectively developed such that customers actually receive the benefits 
associated with the selection of more efficient or cost-effective 
transmission solutions.\1660\ We further find that, given the inherent 
uncertainty involved in planning to meet Long-Term Transmission 
Needs,\1661\ state-developed cost allocation methods and State 
Agreement Process take on heightened importance. This means that the 
Commission will consider the entire record--including the Relevant 
State Entities' agreed-upon Long-Term Regional Transmission Cost 
Allocation Method and/or State Agreement Process and the transmission 
provider's proposal--when setting the replacement rate. Specifically, 
when the Commission reviews transmission providers' compliance filings, 
the Commission is not required to accept a cost allocation proposal 
from a transmission provider simply because it may comply with Order 
No. 1920. Instead, the Commission may adopt any cost allocation method 
proposed by the Relevant State Entities and submitted on compliance so 
long as it complies with Order No. 1920.\1662\
---------------------------------------------------------------------------

    \1657\ See, e.g., PJM Interconnection, L.L.C., 173 FERC ] 
61,134, at P 117 n.175 (2020); PJM Interconnection, L.L.C., 119 FERC 
] 61,318, at P 115 (2007); ANR Pipeline Co., 110 FERC ] 61,069, at P 
49 (2005).
    \1658\ FCC v. Fox Television Stations, Inc., 556 U.S. at 515.
    \1659\ Supra Categories of Factors section.
    \1660\ Order No. 1920, 187 FERC ] 61,068 at PP 124, 126, 268, 
1293, 1362-1364, 1404, 1407, 1410-1411, 1415, 1477, 1515.
    \1661\ Id. P 227.
    \1662\ We believe that these findings address NESCOE's arguments 
that Order No. 1920's cost allocation requirements ``[r]elegat[ed] 
states to commenting on a transmission provider's cost allocation 
filing,'' or that the ``only path the Commission envision[ed] for 
approval of the states' cost allocation method would be through the 
vehicle of a complaint.'' NESCOE Rehearing Request at 14.
---------------------------------------------------------------------------

    660. We believe Order No. 1920, as modified here on rehearing, 
strikes a reasonable balance between, on the one hand, recognizing the 
rights and responsibilities of the Commission and transmission 
providers over regional transmission planning and, on the other, the 
states' critical interests in the resulting Long-Term Regional 
Transmission Facilities and how the costs associated with those 
facilities will be allocated. We also believe that this balance, 
including the requirement that transmission providers consult with 
Relevant State Entities (1) prior to amending the Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es), or (2) if Relevant State Entities seek, consistent with 
their chosen method to reach agreement, for the transmission provider 
to amend that method or process,\1663\ addresses, at least in part, 
concerns underlying arguments by Harvard ELI and NARUC that the 
Commission should establish a prospective mechanism through which 
transmission providers would be required to file for Commission 
approval any cost allocation methods approved by Relevant State 
Entities \1664\ or if states reach the requisite agreement on a 
different cost allocation method than that reflected in the OATT then 
on file.\1665\
---------------------------------------------------------------------------

    \1663\ See infra Consultation with Relevant State Entities After 
the Engagement Period section.
    \1664\ Harvard ELI Rehearing Request at 1-3. Because we are 
unpersuaded by Harvard ELI's request for rehearing in this respect, 
we find it unnecessary to address Harvard ELI's request for 
clarification in the alternative that FPA section 206 provides the 
Commission the authority to amend the pro forma OATT to include a 
process for filing all cost allocation methods approved by Relevant 
State Entities. Id. at 8.
    \1665\ NARUC Rehearing Request at 21-22.
---------------------------------------------------------------------------

    661. Nonetheless, consistent with our findings above with respect 
to requests that the Commission require transmission providers to adopt 
any cost allocation method that Relevant State Entities agree upon 
during the Engagement Period, we decline to adopt Harvard ELI's and 
NARUC's proposals. Transmission planning is the tariff obligation of 
each transmission provider and transmission providers retain, subject 
to Commission oversight, responsibility for regional transmission 
planning, including Long-Term Regional Transmission Planning, as well 
as complying with the obligations of Order No. 1920.\1666\ We disagree 
with Harvard ELI's contention that Order No. 1920's cost allocation 
requirements fail to remedy unjust and unreasonable cost allocation 
processes because Order No. 1920 does not require transmission 
providers to file all cost allocation methods approved by Relevant 
State Entities.\1667\ As discussed below,\1668\ we find that the 
Engagement Period established in Order No. 1920 provides the 
``dedicated process through which states have an opportunity to 
participate in the development of regional cost allocation methods'' 
\1669\ that the Commission recognized was absent from existing cost 
allocation requirements. We further find that, combined with existing 
opportunities for state engagement in the development of regional cost 
allocation methods along with those established herein,\1670\ Order No. 
1920's cost allocation requirements remedy the unjust, unreasonable, 
and unduly discriminatory or preferential existing regional cost 
allocation requirements.
---------------------------------------------------------------------------

    \1666\ See Order No. 1920, 187 FERC ] 61,068 at PP 996 (citing 
Order No. 1000, 136 FERC ] 61,051 at P 153), 1363; see also Order 
No. 890, 118 FERC ] 61,119 at P 454 (``[T]ransmission planning is 
the tariff obligation of each transmission provider.''). To the 
extent that West Virginia Commission, in stating that the Commission 
should ``grant the States 205 filing rights as it pertains to State-
agreed cost allocations,'' is requesting that the Commission confer 
filing rights to states under FPA section 205, West Virginia 
Commission does not explain the authority or legal theory upon which 
it believes the Commission could do so. West Virginia Commission 
Rehearing Request at 14.
    \1667\ Harvard ELI Rehearing Request at 6-7.
    \1668\ See Design and Operation of the Engagement Period 
section.
    \1669\ Order No. 1920, 187 FERC ] 61,068 at P 126.
    \1670\ See supra P 654; infra Duration of the Engagement Period 
section; Consultation with Relevant State Entities After the 
Engagement Period section.
---------------------------------------------------------------------------

    662. In response to PIOs' request that the Commission clarify that 
transmission providers may voluntarily commit to a process that will 
ensure that, where a state agreement on cost allocation exists, the 
agreed-upon cost allocation will be put before the Commission for 
approval,\1671\ and NESCOE's request that the Commission strongly 
encourage transmission providers to commit to such processes,\1672\ we 
reiterate that transmission providers may voluntarily adopt a process 
in their OATTs, whether it be a State Agreement Process or another 
Commission-approved process, under which they commit to file with the 
Commission pursuant to FPA section 205 any cost allocation method that 
garners state agreement subsequent to the Commission's acceptance of 
transmission providers' filings made in compliance with Order No. 
1920.\1673\ We also agree with NESCOE's request and strongly encourage 
transmission providers to commit to a process that will ensure that, 
where a state agreement on cost allocation exists, the agreed-upon cost 
allocation will be put before the Commission for approval. As discussed

[[Page 97300]]

further below, such a process could satisfy the requirement we 
establish for transmission providers to consult with Relevant State 
Entities (1) prior to amending the Long-Term Regional Transmission Cost 
Allocation Method(s) and/or State Agreement Process(es), or (2) if 
Relevant State Entities seek, consistent with their chosen method to 
reach agreement, for the transmission provider to amend that method or 
process.\1674\
---------------------------------------------------------------------------

    \1671\ PIOs Rehearing Request at 55-56.
    \1672\ NESCOE Rehearing Request at 15-16.
    \1673\ See Order No. 1920, 187 FERC ] 61,068 at P 1412 n.3013 
(``[T]ransmission providers may voluntarily agree as part of a State 
Agreement Process in their OATTs that transmission providers shall 
file any cost allocation method that meets the requirements of their 
State Agreement Process, even if those transmission providers do not 
agree with that method.'').
    \1674\ See Infra Consultation with Relevant State Entities After 
the Engagement Period section.
---------------------------------------------------------------------------

C. Design and Operation of the Engagement Period

1. Logical Outgrowth
a. NOPR Proposals
    663. To implement the NOPR proposal to require transmission 
providers to include in their OATTs either a Long-Term Regional 
Transmission Cost Allocation Method or a State Agreement Process, or a 
combination thereof, the Commission proposed to require transmission 
providers to ``seek the agreement'' of relevant state entities 
regarding the cost allocation method or methods that will apply to 
transmission facilities selected in the regional transmission plan for 
purposes of cost allocation through Long-Term Regional Transmission 
Planning and to revise their OATTs to include the method or 
methods.\1675\ The Commission additionally proposed to afford 
transmission providers flexibility in the process by which they seek 
agreement from the Relevant State Entities.\1676\ The Commission stated 
that the proposed reforms would enable Relevant State Entities who seek 
greater involvement in cost allocation for Long-Term Regional 
Transmission Facilities an opportunity to do so.\1677\
---------------------------------------------------------------------------

    \1675\ NOPR, 179 FERC ] 61,028 at PP 278, 303, 305, 308.
    \1676\ Id. P 306.
    \1677\ Id. P 314.
---------------------------------------------------------------------------

    664. In the NOPR, the Commission also proposed to require 
transmission providers to establish a process, detailed in their OATTs, 
to provide a state or states (in multi-state transmission planning 
regions) a time period to negotiate a cost allocation method for a 
transmission facility (or portfolio of facilities) selected for 
purposes of cost allocation through Long-Term Regional Transmission 
Planning that is different than any ex ante regional cost allocation 
method that would otherwise apply. The Commission proposed that, during 
that time period, if a state or all states within the transmission 
planning region in which the selected regional transmission facility 
would be located unanimously agree on an alternate cost allocation 
method, the transmission provider may elect to file it with the 
Commission.\1678\ The Commission explained that providing states with a 
time period to propose alternate cost allocation methods could help 
facilitate the timely development of more efficient or cost-effective 
regional transmission facilities.\1679\
---------------------------------------------------------------------------

    \1678\ Id. P 319.
    \1679\ Id. P 321.
---------------------------------------------------------------------------

b. Order No. 1920 Requirements
    665. In Order No. 1920, the Commission declined to adopt the NOPR 
proposal to require transmission providers to seek the agreement of 
Relevant State Entities regarding the cost allocation method to be 
applied to Long-Term Regional Transmission Facilities.\1680\ Instead, 
the Commission established a six-month Engagement Period, during which 
transmission providers must, among other things, provide a forum for 
the negotiation of a Long-Term Regional Transmission Cost Allocation 
Methods(s) and/or a State Agreement Process that enables meaningful 
participation by Relevant State Entities, and required transmission 
providers to explain on compliance how they complied with the six-month 
Engagement Period requirements.\1681\ The Commission also declined to 
adopt the NOPR proposal to require transmission providers to establish 
a process, detailed in their OATTs, to provide a state or states (in 
multi-state transmission planning regions) a time period to negotiate a 
cost allocation method for a transmission facility (or portfolio of 
facilities) selected for purposes of cost allocation through Long-Term 
Regional Transmission Planning that is different than any ex ante 
regional cost allocation method that would otherwise apply.\1682\
---------------------------------------------------------------------------

    \1680\ Order No. 1920, 187 FERC ] 61,068 at P 1354.
    \1681\ Id. PP 1354, 1357.
    \1682\ Id. P 1456.
---------------------------------------------------------------------------

c. Requests for Rehearing and Clarification
    666. NRECA asserts that the requirement in Order No. 1920 for 
transmission providers to file a Long-Term Regional Transmission Cost 
Allocation Method with or without the agreement of Relevant State 
Entities, and to conduct a six-month Engagement Period to provide a 
forum for negotiation of Long-Term Regional Transmission Cost 
Allocation Methods and/or a State Agreement Process, is not a logical 
outgrowth of the NOPR proposal to require the transmission providers in 
a transmission planning region to seek agreement with Relevant State 
Entities as to a Long-Term Regional Transmission Cost Allocation Method 
and/or State Agreement Process.\1683\ Undersigned States argue that the 
NOPR ``placed the states in a central role in the regulatory structure 
by requiring transmission providers to seek the agreement of states for 
cost allocation,'' but that Order No. 1920 ``removed the requirement 
that states give their consent on cost allocation,'' which is 
```surprisingly distant' from the states' role in the NOPR and is in 
essence a new rule that requires new opportunities for comment and 
input.'' \1684\ West Virginia Commission argues that Order No. 1920 
``effectively exceeds the substantive notice of the NOPR'' by removing 
realistic opportunities for states to work cooperatively on cost 
allocation agreements that will be proposed as ex ante cost allocation 
methods and adding ``an ineffective substitute for seeking state 
agreement for cost allocation'' by establishing the six-month 
Engagement Period.\1685\ Utah Commission similarly contends that the 
elimination of any requirement that a state agree to a cost allocation 
that its residents must bear, no matter how detached the states' 
residents are from causing the associated costs or from the associated 
policies, does not constitute a logical outgrowth of the NOPR.\1686\
---------------------------------------------------------------------------

    \1683\ NRECA Rehearing Request at 17-18.
    \1684\ Undersigned States Rehearing Request at 38 (quoting Int'l 
Union, United Mine Workers of Am., 407 F.3d at 1259-60).
    \1685\ West Virginia Commission Rehearing Request at 3.
    \1686\ Utah Commission Rehearing Request at 11-12.
---------------------------------------------------------------------------

d. Commission Determination
    667. As discussed elsewhere in this rule, we take steps in this 
order to expand Relevant State Entities' opportunities to inform and, 
as needed, provide alternatives to, transmission providers' proposed 
Long-Term Regional Transmission Cost Allocation Method(s). Therefore, 
while we disagree with rehearing parties' arguments that the Engagement 
Period and associated reforms are not a logical outgrowth of the NOPR, 
we note that certain modifications in this order address, at least in 
part, concerns that Order No. 1920 diminished the role of states in 
contrast to the NOPR.\1687\
---------------------------------------------------------------------------

    \1687\ See supra Requirement Concerning Relevant State Entities' 
Preferred Cost Allocation Methods section; infra Duration of the 
Engagement Period section; Consultation with Relevant State Entities 
After the Engagement Period section.
---------------------------------------------------------------------------

    668. In the NOPR, the Commission proposed to require transmission

[[Page 97301]]

providers to ``seek the agreement'' \1688\ of Relevant State Entities 
based upon its finding that ``providing state regulators with a formal 
opportunity to develop a cost allocation method for regional 
transmission facilities selected through Long-Term Regional 
Transmission Planning could help increase . . . state[ ] support for 
those facilities,'' \1689\ thereby framing such a formal opportunity 
for state regulators as the subject for commenter discussion.\1690\ 
Although Order No. 1920 did not adopt the proposed requirement to 
``seek the agreement'' of Relevant State Entities, the Commission 
adopted a materially similar requirement--the Engagement Period--for 
transmission providers to provide, over a six-month period, a forum for 
negotiation of cost allocation methods for Long-Term Regional 
Transmission Facilities that enables meaningful participation by 
Relevant State Entities.\1691\ The Engagement Period ``provide[s] state 
regulators with a formal opportunity to develop a cost allocation 
method for regional transmission facilities selected through Long-Term 
Regional Transmission Planning,'' precisely as contemplated in the 
NOPR.\1692\ Indeed, as the Commission explained in Order No. 1920, 
``requiring an Engagement Period provides the same opportunity for 
robust engagement in the cost allocation process as the NOPR proposal, 
and thus has the potential to achieve the same important benefits, but 
will reduce the practical challenges associated with requiring 
transmission providers to seek the agreement of Relevant State 
Entities.'' \1693\ The Engagement Period, which facilitates the 
meaningful involvement of Relevant State Entities in determining cost 
allocation methods for selected Long-Term Regional Transmission 
Facilities, is in character with, and consequently a logical outgrowth 
of, the proposal to require transmission providers to ``seek the 
agreement'' of Relevant State Entities for the applicable cost 
allocation method for selected transmission facilities.\1694\
---------------------------------------------------------------------------

    \1688\ NOPR, 179 FERC ] 61,028 at PP 278, 303, 305, 308.
    \1689\ Id. P 299.
    \1690\ Conn. Light & Power Co. v. Nuclear Regul. Comm'n, 673 
F.2d at 533 (holding that an agency's proposed rule must 
``adequately frame the subjects for discussion'').
    \1691\ Order No. 1920, 187 FERC ] 61,068 at PP 1354, 1357.
    \1692\ See NOPR, 179 FERC ] 61,028 at P 299.
    \1693\ Order No. 1920, 187 FERC ] 61,068 at P 1362.
    \1694\ See, e.g., Am. Paper Inst. v. EPA, 660 F.2d at 959 n.13 
(``An agency may make even substantial changes in its original 
proposed rule without a further comment period if the changes are in 
character with the original proposal and are a logical outgrowth of 
the notice and comments already given.''); accord Chocolate Mfrs. 
Ass'n of U.S. v. Block, 755 F.2d 1098, 1105 (4th Cir. 1985).
---------------------------------------------------------------------------

2. Requests Arguing the Engagement Period Is Inferior to a Requirement 
That Transmission Providers Seek the Agreement of Relevant State 
Entities
a. Order No. 1920 Requirements
    669. In Order No. 1920, the Commission established a six-month 
Engagement Period, during which transmission providers must: (1) 
provide notice of the starting and end dates for the six-month time 
period; (2) post contact information that Relevant State Entities may 
use to communicate with transmission providers about any agreement 
among Relevant State Entities on a Long-Term Regional Transmission Cost 
Allocation Method(s) and/or a State Agreement Process, as well as a 
deadline for communicating such agreement; and (3) provide a forum for 
negotiation of a Long-Term Regional Transmission Cost Allocation 
Method(s) and/or a State Agreement Process that enables meaningful 
participation by Relevant State Entities.\1695\
---------------------------------------------------------------------------

    \1695\ Order No. 1920, 187 FERC ] 61,068 at P 1354.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    670. Virginia and North Carolina Commissions and West Virginia 
Commission request rehearing of Order No. 1920's decision to not adopt 
the NOPR proposal to require transmission providers to seek the 
agreement of Relevant State Entities within the transmission planning 
region regarding the relevant cost allocation method to be applied to 
Long-Term Regional Transmission Facilities.\1696\ West Virginia 
Commission argues that the Engagement Period is an ineffective 
substitute for the NOPR proposal to require transmission providers to 
seek the agreement of Relevant State Entities within the transmission 
planning region regarding the relevant cost allocation method to be 
applied to Long-Term Regional Transmission Facilities.\1697\ Virginia 
and North Carolina Commissions argue that, to provide the robust 
engagement required by Order No. 1920, the Commission should specify 
and bolster transmission providers' requirements to meaningfully engage 
with and proactively seek (but not necessarily obtain) the agreement of 
Relevant State Entities concerning cost allocation issues during the 
Engagement Period.\1698\
---------------------------------------------------------------------------

    \1696\ West Virginia Commission Rehearing Request at 8; Virginia 
and North Carolina Commissions Rehearing Request at 8-10.
    \1697\ West Virginia Commission Rehearing Request at 8.
    \1698\ Virginia and North Carolina Commissions Rehearing Request 
at 9-10.
---------------------------------------------------------------------------

c. Commission Determination
    671. As discussed in Order No. 1920 and reiterated in this order, 
it is critical to the success of the Long-Term Regional Transmission 
Planning reforms that states have an opportunity to have a significant 
role in the establishment of just and reasonable Long-Term Regional 
Transmission Cost Allocation Methods and State Agreement Processes. 
While we are unpersuaded by arguments that the Commission erred in 
declining to adopt the NOPR proposal to require transmission providers 
to seek the agreement of Relevant State Entities within the 
transmission planning region regarding the relevant cost allocation 
method to be applied to Long-Term Regional Transmission Facilities and 
instead establishing the Engagement Period,\1699\ we believe that the 
requirements related to the Engagement Period, discussed below, that we 
adopt herein address the concerns underlying those rehearing requests.
---------------------------------------------------------------------------

    \1699\ West Virginia Commission Rehearing Request at 8; Virginia 
and North Carolina Commissions Rehearing Request at 8-10.
---------------------------------------------------------------------------

    672. In Order No. 1920, the Commission carefully weighed the 
appropriate level of transmission providers' engagement with Relevant 
State Entities regarding the cost allocation method to be applied to 
Long-Term Regional Transmission Facilities by considering the potential 
challenges inherent in such engagement. Specifically, the Commission 
found that while ``states play a critical role in transmission 
planning'' and ``facilitating their engagement in cost allocation may 
minimize delays and additional costs that can be associated with 
associated transmission siting proceedings,'' mandating that 
transmission providers seek the agreement of Relevant State Entities on 
a Long-Term Regional Transmission Cost Allocation Method(s) would 
present potential difficulties that counseled against adoption of this 
proposed reform.\1700\ For example, the Commission considered the 
possibility that requiring transmission providers to seek the agreement 
of Relevant State Entities might create disputes over the rights and 
responsibilities of individual states or state commissions to veto or 
otherwise hold up needed region-wide transmission plans.\1701\ The

[[Page 97302]]

Commission also considered the challenges of adopting a definition for 
``agreement'' that would be necessary under a requirement for 
transmission providers to seek the agreement of Relevant States 
Entities.\1702\
---------------------------------------------------------------------------

    \1700\ Order No. 1920, 187 FERC ] 61,068 at PP 124, 1362.
    \1701\ See id. P 1362 & n.2906 (citing Minnesota State Entities 
NOPR Initial Comments).
    \1702\ Id. P 1361 (discussing commenter arguments that the 
Commission adopt different criteria for ``agreement,'' including a 
majority, a threshold of one-half of the participating Relevant 
State Entities, or unanimity).
---------------------------------------------------------------------------

    673. We continue to find, as stated above, that states ``play a 
critical role in transmission planning'' and ``facilitating their 
engagement in cost allocation may minimize delays and additional costs 
that can be associated with associated transmission siting 
proceedings,'' \1703\ and we find that establishing an Engagement 
Period recognizes that critical role while reducing the potential 
practical challenges discussed above, as compared to requiring 
transmission providers to seek the agreement of Relevant State 
Entities.\1704\ We also continue to find that the Engagement Period 
provides the same opportunity for robust engagement in the cost 
allocation process as the NOPR proposal, and thus has the potential to 
achieve the same important benefits.\1705\ Beyond that, the 
modification we make here, to require transmission providers to submit 
any cost allocation methods agreed to by Relevant State Entities in the 
transmittal or as an attachment to their compliance filings, addresses 
the same concern and provides Relevant State Entities with additional 
means to demonstrate to the Commission any preferences around the cost 
allocation of Long-Term Regional Transmission Facilities. We therefore 
are unpersuaded by arguments raised by West Virginia Commission on 
rehearing that the Engagement Period is ``ineffective'' compared to the 
NOPR proposal.\1706\ Similarly, with respect to Virginia and North 
Carolina Commissions' request that the Commission require transmission 
providers to ``proactively seek'' the agreement of Relevant State 
Entities to the transmission providers' preferred Long-Term Regional 
Transmission Cost Allocation Method,\1707\ we find that Order No. 1920, 
as modified on rehearing, provides more opportunities for state 
engagement than a requirement to simply seek agreement with states for 
a Long-Term Regional Transmission Cost Allocation Method. Specifically, 
transmission providers must (1) provide the opportunity for Relevant 
State Entities from all states in a transmission planning region to 
participate in the Engagement Period; \1708\ (2) upon the request of 
Relevant State Entities, facilitate and participate in a cost 
allocation discussion during the Engagement Period with Relevant State 
Entities; \1709\ and (3) include, in the transmittal or as an 
attachment to their compliance filings, any Long-Term Regional 
Transmission Cost Allocation Method and/or State Agreement Process 
agreed to by Relevant State Entities.\1710\
---------------------------------------------------------------------------

    \1703\ Id. PP 124, 1362.
    \1704\ Id. P 1362.
    \1705\ Id.
    \1706\ West Virginia Commission Rehearing Request at 8.
    \1707\ Virginia and North Carolina Commissions Rehearing Request 
at 10.
    \1708\ See infra Content of the Engagement Period section.
    \1709\ See supra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section.
    \1710\ See supra Requirements Concerning Relevant State 
Entities' Preferred Cost Allocation Methods section.
---------------------------------------------------------------------------

3. Duration of the Engagement Period
a. Order No. 1920 Requirements
    674. In Order No. 1920, the Commission found that limiting the 
Engagement Period to six months was necessary to ensure that 
transmission providers have sufficient time to prepare their compliance 
filings in advance of the compliance deadlines established in Order No. 
1920.\1711\
---------------------------------------------------------------------------

    \1711\ Order No. 1920, 187 FERC ] 61,068 at P 1358.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    675. Several rehearing parties request extension of the Engagement 
Period.\1712\ PJM States and Pennsylvania Commission request that the 
Commission clarify that the six-month Engagement Period will be 
extended for up to 12 months if states file a unanimous declaration 
that they are engaged in, but require additional time to complete, cost 
allocation discussions.\1713\ West Virginia Commission requests that 
the Commission extend the Engagement Period to a minimum of 12 months 
or, in the alternative, authorize the extension of the Engagement 
Period if Relevant State Entities submit a declaration stating that 
they are continuing to engage in cost allocation discussions.\1714\ 
SERTP Sponsors request that the Commission clarify that, upon unanimous 
consent of all affected state commissions (and the governing 
authorities for non-jurisdictional transmission providers), the 
Commission will allow (or, at a minimum, consider good-cause motions 
for) an extension of time for the development of ex ante state 
agreements to provide those entities with additional time to negotiate 
during the Engagement Period.\1715\ PJM States, Pennsylvania 
Commission, and West Virginia Commission argue that the Commission 
should permit an extension of the Engagement Period because there are a 
large number of Relevant State Entities in PJM, there are highly 
diverse regulatory models used in those Relevant State Entities in PJM, 
and there are a wide variety of state laws and procedures applicable to 
those Relevant State Entities.\1716\ Virginia and North Carolina 
Commissions argue that it would likely be beneficial to afford 
transmission providers greater flexibility with respect to the 
``timeline'' of the Engagement Period, to the extent this flexibility 
would facilitate productive engagement with states without unduly 
delaying or impeding Order No. 1920's other requirements.\1717\
---------------------------------------------------------------------------

    \1712\ PJM States Rehearing Request at 3-4; Pennsylvania 
Commission Rehearing Request at 1 (adopting PJM States' arguments); 
West Virginia Commission Rehearing Request at 13; SERTP Sponsors 
Rehearing Request at 7-8; Virginia and North Carolina Commissions 
Rehearing Request at 11 n.27.
    \1713\ PJM States Rehearing Request at 3-4; Pennsylvania 
Commission Rehearing Request at 1.
    \1714\ West Virginia Commission Rehearing Request at 13.
    \1715\ SERTP Sponsors Rehearing Request at 7-8.
    \1716\ PJM States Rehearing Request at 3; Pennsylvania 
Commission Rehearing Request at 1; West Virginia Commission 
Rehearing Request at 13.
    \1717\ Virginia and North Carolina Commissions Rehearing Request 
at 11 n.27.
---------------------------------------------------------------------------

    676. Wyoming Commission asserts that providing states with six 
months ``to reach agreement with the default cost allocation looming is 
an illusory acknowledgement of state authority.'' \1718\ Arizona 
Commission states that ``the provision for states to negotiate 
acceptable cost allocations among them is limited to six months'' and 
that ``[s]ix months is not enough time for the states to establish rate 
cases.'' \1719\ Designated Retail Regulators and Undersigned States 
argue that ``reaching an agreement in MISO within the six-month 
window'' may be difficult given states' different goals and 
agendas,\1720\ and that six months is an insufficient amount of time to 
provide the due process required to approve any State Agreement 
Process.\1721\
---------------------------------------------------------------------------

    \1718\ Wyoming Commission Rehearing Request at 7.
    \1719\ Arizona Commission Rehearing Request at 17 n.14.
    \1720\ Designated Retail Regulators Rehearing Request at 35; 
Undersigned States Rehearing Request at 31.
    \1721\ Designated Retail Regulators Rehearing Request at 9; 
Undersigned States Rehearing Request at 9.

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[[Page 97303]]

c. Commission Determination
    677. We set aside, in part, Order No. 1920's requirements on the 
duration of the Engagement Period. In Order No. 1920, the Commission 
noted that experience with Order No. 1000 has reinforced the critical 
role that states play in the development of new transmission 
infrastructure, particularly at the regional level, where transmission 
projects may physically span, and their costs may be allocated across, 
multiple states.\1722\ Moreover, the Commission found that facilitating 
state involvement in the regional cost allocation process could 
minimize delays and additional costs associated with state and local 
siting proceedings.\1723\ In keeping with these findings, and upon 
further consideration, we find that extending the Engagement Period may 
be appropriate when Relevant State Entities represent to the Commission 
that they need additional time to complete cost allocation discussions.
---------------------------------------------------------------------------

    \1722\ Order No. 1920, 187 FERC ] 61,068 at P 124.
    \1723\ Id.
---------------------------------------------------------------------------

    678. Providing the opportunity for such an extension is consistent 
with the critical role that states play in addressing these issues and 
ensuring that they have the time necessary to adequately engage in 
these issues. Therefore, in response to arguments raised by PJM States, 
Pennsylvania Commission, and West Virginia Commission, we set aside 
Order No. 1920's requirements, in part, to specify that the Commission 
will grant an extension of the required Engagement Period for up to an 
additional six months when Relevant State Entities, consistent with 
their chosen method to reach agreement, request additional time to 
complete cost allocation discussions. We find that such an extension is 
warranted in that circumstance to ensure that Relevant State Entities 
have sufficient time to engage in fulsome discussions. We also clarify 
that in such circumstances, the Commission will also, as appropriate, 
extend, sua sponte, the relevant Order No. 1920 compliance deadlines to 
accommodate an extension of the Engagement Period and to ensure that 
any such extension would not conflict with the required compliance 
deadlines.
4. Content of the Engagement Period
a. Order No. 1920 Requirements
    679. In Order No. 1920, the Commission required the transmission 
providers in each transmission planning region to provide notice, such 
as on their OASIS pages or public websites, of the opportunity for any 
Relevant State Entity to participate in, and the starting and end dates 
of, the Engagement Period. The Commission required that such notice 
include contact information for a single point of contact in the 
transmission planning region that the Relevant State Entities can use 
to communicate any agreement among Relevant State Entities on a Long-
Term Regional Transmission Cost Allocation Method(s) and/or a State 
Agreement Process, as well as a deadline for communicating such 
agreement, which must be no earlier than the end date of the Engagement 
Period.\1724\ The Commission also required transmission providers in 
each transmission planning region to provide a forum for negotiation 
that enables meaningful participation by Relevant State Entities during 
the Engagement Period.\1725\
---------------------------------------------------------------------------

    \1724\ Id. P 1356. The Commission noted Relevant State Entities 
must indicate that they have agreed to any State Agreement Process 
for any such process to be eligible for acceptance by the Commission 
in compliance with Order No. 1920. Id. P 1356 n.2895.
    \1725\ Id. P 1357.
---------------------------------------------------------------------------

    680. The Commission required that transmission providers explain on 
compliance how they complied with the requirement to establish and 
provide notice of an Engagement Period for Relevant State Entities to 
negotiate a Long-Term Regional Transmission Cost Allocation Method(s) 
and/or State Agreement Process, as well as how they complied with the 
requirement to provide a forum for such negotiation.\1726\
---------------------------------------------------------------------------

    \1726\ Id.
---------------------------------------------------------------------------

    681. The Commission declined to define what constitutes agreement 
among Relevant State Entities, how such agreement is reached, and which 
Relevant State Entities must reach such agreement during the Engagement 
Period, or to establish a minimum set of criteria for a state 
agreement. Instead, the Commission left such matters, including whether 
to use existing state processes as a forum for negotiations, to the 
Relevant State Entities participating in the Engagement Period to 
determine.\1727\ The Commission also declined to expand participation 
in the Engagement Period beyond Relevant State Entities, stating that 
it did not find it necessary to allow other stakeholders to participate 
in the Engagement Period.\1728\
---------------------------------------------------------------------------

    \1727\ Id. PP 1360-1361 (citations omitted).
    \1728\ Id. P 1363.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    682. PJM States and NARUC request that the Commission require 
transmission providers to include in their compliance filings, at 
minimum, the setting and communicating of deadlines and the general 
forum for transmission provider discussions with and outreach to state 
entities concerning the Engagement Period.\1729\ PJM States contend 
that these and other clarifications would demonstrate the extent to 
which transmission providers engaged with states during the Engagement 
Period.\1730\
---------------------------------------------------------------------------

    \1729\ NARUC Rehearing Request at 17; PJM States Rehearing 
Request at 7.
    \1730\ PJM States Rehearing Request at 8.
---------------------------------------------------------------------------

    683. PJM States request clarification that the Engagement Period is 
actually a ``State Engagement Period'' and that ``states are the 
stakeholder(s) to engage.'' \1731\ PJM States explain that any such 
clarification should not prohibit states from inviting other entities 
that might be helpful in assisting states in reaching agreement on cost 
allocation. Rather, PJM States argue that the Commission should make 
clear that the Engagement Period is ``not for the engagement of all 
stakeholders'' but is instead intended to provide a forum for 
transmission providers and states to attempt to reach agreement on cost 
allocation.\1732\
---------------------------------------------------------------------------

    \1731\ Id. (emphasis in original).
    \1732\ Id. at 8-9.
---------------------------------------------------------------------------

c. Commission Determination
    684. In response to the requests of PJM States and NARUC for 
clarification as to the information that transmission providers must 
include in their compliance filings concerning the Engagement 
Period,\1733\ we clarify that, in order to comply with the requirement 
that transmission providers explain how they provided a forum for 
negotiation of a Long-Term Regional Transmission Cost Allocation 
Method(s) and/or a State Agreement Process during the Engagement Period 
that enables meaningful participation by Relevant State Entities,\1734\ 
transmission providers must at minimum disclose any deadlines set by 
transmission providers during the Engagement Period and how 
transmission providers communicated any such deadlines to Relevant 
State Entities, and provide a general description of the forum for 
negotiation.\1735\
---------------------------------------------------------------------------

    \1733\ See id. at 7; NARUC Rehearing Request at 17-18.
    \1734\ See Order No. 1920, 187 FERC ] 61,068 at P 1357.
    \1735\ We address the requests of PJM States, NARUC, and other 
parties that the Commission require transmission providers to 
include additional information related to the Engagement Period in 
their compliance filings--such as requests that the Commission 
require each transmission provider to include states' preferred cost 
allocation method in its compliance filing above in the Requirements 
Concerning Relevant State Entities' Preferred Cost Allocation 
Methods section.

---------------------------------------------------------------------------

[[Page 97304]]

    685. With respect to PJM States' argument that the Commission 
should clarify that the Engagement Period is ``not for the engagement 
of all stakeholders,'' \1736\ we reiterate that the Commission declined 
to expand participation in the Engagement Period beyond Relevant State 
Entities, and did not find it necessary to allow other stakeholders to 
participate in the Engagement Period.\1737\ However, we also reiterate 
that the Commission allowed Relevant State Entities to permit the 
participation of other entities subsequently during implementations of 
a State Agreement Process.\1738\ We also reiterate our determination in 
Order No. 1920 to define Relevant State Entities as any state entity 
responsible for electric utility regulation or siting electric 
transmission facilities within the state or portion of a state located 
in the transmission planning region, including any state entity as may 
be designated for that purpose by the law of such state,\1739\ and we 
continue to find that this definition recognizes the important role of 
states while providing sufficient regional flexibility for effective 
Engagement Period participation.\1740\
---------------------------------------------------------------------------

    \1736\ PJM States Rehearing Request at 8-9.
    \1737\ Order No. 1920, 187 FERC ] 61,068 at P 1363.
    \1738\ Id. P 1402.
    \1739\ Id. P 1355.
    \1740\ Id. P 1364.
---------------------------------------------------------------------------

    686. With respect to PJM States' request for clarification that the 
Engagement Period is actually a ``State Engagement Period'' and that 
the states are the stakeholders with which transmission providers must 
engage during the Engagement Period,\1741\ we grant clarification, in 
part, and clarify that transmission providers must provide the 
opportunity for Relevant State Entities from all states in each 
transmission planning region to participate in the Engagement Period.
---------------------------------------------------------------------------

    \1741\ PJM States Rehearing Request at 8.
---------------------------------------------------------------------------

5. Consultation With Relevant State Entities After the Engagement 
Period
a. Order No. 1920 Requirements
    687. In Order No. 1920, the Commission declined to require future 
Engagement Periods, but noted that transmission providers may hold 
future Engagement Periods if they believe that such periods would be 
beneficial.\1742\
---------------------------------------------------------------------------

    \1742\ Order No. 1920, 187 FERC ] 61,068 at P 1368.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    688. NARUC and NESCOE request rehearing of Order No. 1920's 
decision not to require future Engagement Periods.\1743\ NESCOE argues 
that following the initial Engagement Period, any proposed modification 
to the transmission planning region's Long-Term Regional Transmission 
Cost Allocation Method should trigger an obligation to establish a new 
Engagement Period to provide a forum for Relevant State Entities to 
discuss the proposed Long-Term Regional Transmission Cost Allocation 
Method. NESCOE explains that absent this obligation, a transmission 
provider could undo the efforts of Relevant State Entities in agreeing 
to a Long-Term Regional Transmission Cost Allocation Method during the 
initial Engagement Period by filing a new Long-Term Regional 
Transmission Cost Allocation Method without consulting with Relevant 
State Entities.\1744\
---------------------------------------------------------------------------

    \1743\ NARUC Rehearing Request at 21-22; NESCOE Rehearing 
Request at 13-14.
    \1744\ NESCOE Rehearing Request at 13-14 (citing Order No. 1920, 
187 FERC ] 61,068 at P 1430 (``We further clarify that unless 
voluntarily waived, a transmission provider retains its FPA section 
205 filing rights to submit an ex ante cost allocation method for 
Long-Term Regional Transmission Facilities at any time, consistent 
with any limitations a transmission provider may have agreed to, for 
example, as part of its membership in an RTO/ISO.'' (citations 
omitted))).
---------------------------------------------------------------------------

    689. NARUC requests that the Commission create a mechanism that 
ensures regular re-examination of the Long-Term Regional Transmission 
Cost Allocation Method(s) and any State Agreement Process in a 
transmission provider's OATT. Specifically, NARUC argues that the 
Commission should require each transmission provider to periodically 
open a new negotiation period with Relevant State Entities.\1745\
---------------------------------------------------------------------------

    \1745\ NARUC Rehearing Request at 21-22. In the Requirements 
Concerning Relevant State Entities' Preferred Cost Allocation 
Methods section above, we discuss NARUC's alternative request that 
the Commission require each transmission provider to file a 
modification to its OATT if states reach the requisite agreement on 
a different cost allocation method than that reflected in its OATT.
---------------------------------------------------------------------------

    690. Virginia and North Carolina Commissions argue that it would 
likely be beneficial to afford transmission providers greater 
flexibility with respect to the ``frequency'' of the Engagement Period, 
to the extent this flexibility would facilitate productive engagement 
with states without unduly delaying or impeding Order No. 1920's other 
requirements.\1746\
---------------------------------------------------------------------------

    \1746\ Virginia and North Carolina Commissions Rehearing Request 
at 11 n.27.
---------------------------------------------------------------------------

c. Commission Determination
    691. We are persuaded by NARUC's and NESCOE's arguments raised on 
rehearing. Accordingly, we set aside Order No. 1920, in part, and 
require that, as part of transmission providers' obligations with 
respect to transmission planning and cost allocation, transmission 
providers shall consult with Relevant State Entities (1) prior to 
amending the Long-Term Regional Transmission Cost Allocation Method(s) 
and/or State Agreement Process(es), or (2) if Relevant State Entities 
seek, consistent with their chosen method to reach agreement, for the 
transmission provider to amend that method or process. The consultation 
requirement will provide a mechanism through which transmission 
providers and Relevant State Entities can engage regarding possible 
future changes via FPA section 205 to cost allocation methods accepted 
by the Commission in compliance with Order No. 1920.\1747\ We require 
transmission providers to include in their OATTs a description of how 
they will consult with Relevant State Entities in these circumstances. 
Additionally, for a consultation initiated by the transmission 
providers, we require transmission providers to document publicly on 
their OASIS or other public website the results of their consultation 
with Relevant State Entities prior to filing their amendment. For a 
consultation initiated by Relevant State Entities, if the transmission 
providers choose not to propose any amendments to the Long-Term 
Regional Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es) preferred by Relevant State Entities during the required 
consultation, we also require transmission providers to document 
publicly on their OASIS or other public website the results of their 
consultation with Relevant State Entities, including an explanation for 
why they have chosen not to propose any amendments.
---------------------------------------------------------------------------

    \1747\ We clarify that this consultation requirement neither 
requires transmission providers to submit, nor prohibits 
transmission providers from submitting, FPA section 205 filings to 
modify cost allocation methods accepted in compliance with Order No. 
1920, and transmission providers therefore retain their currently 
effective FPA section 205 rights. That said, as noted below, 
transmission providers may satisfy the consultation requirement by 
voluntarily agreeing to submit FPA section 205 proposals supported 
by Relevant State Entities. Infra P 692.
---------------------------------------------------------------------------

    692. We find that these requirements will ensure that states have 
the opportunity to be involved in establishing cost allocation methods 
for Long-Term Regional Transmission Facilities subsequent to the 
Commission's acceptance of transmission providers' filings made in 
compliance with Order No. 1920, which has the potential to minimize 
additional costs and delays in the siting process and to facilitate the 
development of Long-Term Regional Transmission

[[Page 97305]]

Facilities.\1748\ While we provide transmission providers flexibility 
as to the form and duration of their required consultation with 
Relevant State Entities, we note that one way transmission providers 
could satisfy the requirement to consult with Relevant State Entities 
is by revising their OATTs to include a process under which the 
transmission provider must present to the Commission, in addition to 
its own FPA section 205 proposal, an alternative cost allocation method 
proposed by Relevant State Entities for evaluation by the Commission on 
equal footing.\1749\ Transmission providers could also satisfy the 
requirement to consult with Relevant State Entities by revising their 
OATTs to include mechanisms similar to those used in SPP \1750\ and 
MISO.\1751\
---------------------------------------------------------------------------

    \1748\ E.g., Order No. 1920, 187 FERC ] 61,068 at PP 124, 126.
    \1749\ See, e.g., ISO New England Inc., FERC FPA Electric 
Tariff, ISO New England Inc. Agreements and Contracts, TOA, 
Transmission Operating Agreement (5.0.0), 3.04(h)(vi)(C); see also 
The Governors of Conn., Me., Mass., N.H., R.I., Vt., 112 FERC ] 
61,049, at P 25 (2005).
    \1750\ SPP, Governing Documents Tariff, Bylaws, First Revised 
Volume No. 4 (0.0.0), 7.2 (Regional State Committee) (providing that 
the Regional State Committee has primary responsibility for 
determining regional proposals regarding, among other things, 
``whether license plate or postage stamp rates will be used for the 
regional access charge,'' and that when the Regional State Committee 
``reaches decisions on the methodology that will be used to address 
any of these issues, SPP will file this methodology pursuant to 
Section 205 of the [FPA]''); see also Sw. Power Pool, Inc., 106 FERC 
] 61,110, at PP 218-220, order on reh'g, 109 FERC ] 61,010, at PP 
92-94 (2004); Sw. Power Pool, Inc., 108 FERC ] 61,003, at P 127 & 
n.90 (2004), order on reh'g, 110 FERC ] 61,138, at P 33 (2005).
    \1751\ MISO FERC Electric Tariff, MISO Rate Schedules, MISO 
Transmission Owner Agreement, app. K (Filing Rights Pursuant To 
Section 205 Of The FPA) (3.0.0), II.E.3.a.i-ii (providing the 
circumstances under which the OMS Committee ``shall have the right 
to request and MISO shall file for a new or an amendment of any 
regional cost allocation methodology''); see also Midwest Indep. 
Transmission Sys. Operator, Inc., 143 FERC ] 61,165, at PP 30, 32 
(2013).
---------------------------------------------------------------------------

D. Design and Operation of State Agreement Processes

1. Definition of Relevant State Entities
a. Order No. 1920 Requirements
    693. In Order No. 1920, the Commission defined Relevant State 
Entities as any state entity responsible for electric utility 
regulation or siting electric transmission facilities within the state 
or portion of a state located in the transmission planning region, 
including any state entity as may be designated for that purpose by the 
law of such state. The Commission stated that it modified the NOPR 
proposal's definition to add the word ``electric'' before ``utility 
regulation'' in order to make clear that Relevant State Entities are 
those state agencies responsible for electric utility regulation, and 
not other types of utility regulation.\1752\ In Order No. 1920, the 
Commission declined requests to expand or clarify the definition of 
Relevant State Entities and did not modify the definition beyond adding 
the word ``electric,'' but permitted other participants beyond Relevant 
State Entities to participate in a State Agreement Process, if agreed 
to by Relevant State Entities.\1753\
---------------------------------------------------------------------------

    \1752\ Order No. 1920, 187 FERC ] 61,068 at P 1355.
    \1753\ Id. PP 1364 & n.2914, 1402.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    694. APPA contends that the Commission erred in excluding municipal 
electric regulatory bodies from the Relevant State Entity 
definition.\1754\ APPA claims that excluding public power utilities and 
municipal governing bodies is arbitrary and capricious because: (1) the 
Commission failed to justify excluding customers served by municipal 
utilities during the Engagement Period, which is unduly discriminatory; 
\1755\ (2) the Commission gave no meaningful rationale for excluding 
self-regulated public utilities from the Relevant State Entity 
definition, and inclusion would increase local support and reduce 
uncertainty and risk for development of Long-Term Regional Transmission 
Facilities; and (3) the definition of Relevant State Entity conflicts 
with the FPA's definition of ``state commission'' as ``the regulatory 
body of the State or municipality having jurisdiction to regulate rates 
and charges for the sale of electric energy to consumers within the 
State or municipality.'' \1756\
---------------------------------------------------------------------------

    \1754\ APPA Rehearing Request at 2.
    \1755\ Id. at 4.
    \1756\ Id. at 5 (citing 16 U.S.C. 796(15)) (emphasis in 
original).
---------------------------------------------------------------------------

    695. Large Public Power claims that non-jurisdictional self-
regulating non-public utilities under FPA section 201(f) could be 
profoundly affected by the Engagement Period without representation, 
and their exclusion from the definition of Relevant State Entity is 
arbitrary and capricious.\1757\ Large Public Power states that its 
members are self-regulating entities that possess many of the same 
regulatory characteristics as state commissions, undertake retail 
ratemaking publicly, are not represented by state commissions, and in 
some states represent a market share larger than most individual 
investor-owned utilities.\1758\ Large Public Power states that the FPA 
explicitly recognizes political subdivisions' authority through 
exemptions.\1759\ Large Public Power argues that the Commission should 
provide an opportunity for municipal utilities to have a voice equal to 
that of state utility commissions to ensure that Long-Term Regional 
Transmission Facilities are not built and paid for by their customers 
unless such facilities are needed and wanted.\1760\ Large Public Power 
states that the most obvious solution to this issue would be to grant 
municipal utilities representation on a load ratio share basis.\1761\
---------------------------------------------------------------------------

    \1757\ Large Public Power Rehearing Request at 11.
    \1758\ Id.
    \1759\ Id. at 12.
    \1760\ Id. at 12-13.
    \1761\ Id. at 13.
---------------------------------------------------------------------------

    696. City of New Orleans Council requests clarification to confirm 
that it meets the definition of a Relevant State Entity.\1762\ City of 
New Orleans Council states that it is designated and recognized by the 
State of Louisiana and the Home Rule Charter of the City of New Orleans 
as the governmental body that supervises, regulates, and controls 
public utilities within New Orleans.\1763\ City of New Orleans Council 
states that MISO recognizes the City of New Orleans Council's unique 
regulatory authority and status.\1764\ Noting that Order No. 1920 
refers to OMS as an existing mechanism for state involvement, City of 
New Orleans Council states that it is a member of OMS that represents 
the collective interests of its members, which are state and local 
regulators within MISO's footprint.\1765\ City of New Orleans Council 
states that it is also a member of the Entergy Regional State Committee 
(ERSC), which is comprised of retail regulators from the MISO-South 
subregion and recognized in MISO stakeholder forums, and that the ERSC 
bylaws recognize that the City of New Orleans Council is included as a 
``state regulatory agency.'' \1766\ City of New Orleans Council also 
argues that its recognition within MISO is consistent with PJM's 
recognition of the District of Columbia.\1767\
---------------------------------------------------------------------------

    \1762\ City of New Orleans Council Rehearing Request at 4.
    \1763\ Id. (citing La. Const., art. IV, Sec.  21(c); Home Rule 
Charter of the City of New Orleans, Sec.  3-130).
    \1764\ Id. at 5.
    \1765\ Id. (citing Order No. 1920, 187 FERC ] 61,068 at P 1357).
    \1766\ Id. at 6 (citing Entergy Regional State Committee (ERSC), 
https://www.misoenergy.org/engage/committees/entergy-regional-state-committee/ (ERSC Mission Statement); ERSC Bylaws, https://cdn.misoenergy.org/ERSC%20Bylaws%20(Amended%202%2014%2022)%20217600.pdf (amended Feb. 
14, 2022)).
    \1767\ Id. at 6-7.
---------------------------------------------------------------------------

    697. City of New Orleans Council requests rehearing in the event 
that the Commission does not grant its request

[[Page 97306]]

for clarification, noting that the Constitution of the State of 
Louisiana and the Home Rule Charter of the City of New Orleans 
recognize City of New Orleans Council's status as the governmental body 
with the power of supervision, regulation, and control over public 
utilities, and noting MISO's recognition of the City of New Orleans 
Council's status.\1768\ City of New Orleans Council states that finding 
that it does not meet the definition of Relevant State Entity would be 
contrary to such legal and regulatory recognition.\1769\
---------------------------------------------------------------------------

    \1768\ Id. at 8.
    \1769\ Id. at 9.
---------------------------------------------------------------------------

    698. NESCOE requests that the Commission clarify that Regional 
State Committees are included in the definition of Relevant State 
Entities, or in the alternative, NESCOE seeks rehearing.\1770\ NESCOE 
states that it is unclear that Regional State Committees, such as 
NESCOE, which do not necessarily appear in state laws and are not 
necessarily state agencies, are Relevant State Entities.\1771\ NESCOE 
states that it appears that the Commission did not deliberately exclude 
Regional State Committees from the definition of Relevant State 
Entities, but that the Commission appears to have misapprehended 
NESCOE's argument in its comments as solely concerned about its unique 
structure of achieving consensus among the New England states.\1772\
---------------------------------------------------------------------------

    \1770\ NESCOE Rehearing Request at 17-20.
    \1771\ Id. at 18-19.
    \1772\ Id. at 19.
---------------------------------------------------------------------------

    699. NRECA states that, even following its comments to the NOPR, 
the definition of Relevant State Entity excludes cooperatives and 
public power utilities not subject to regulation by a state utility 
commission and the Engagement Period includes only Relevant State 
Entities. NRECA argues that, as a result, Order No. 1920 allows a 
Relevant State Entity to dictate cost allocation to electric utilities 
it does not regulate.\1773\
---------------------------------------------------------------------------

    \1773\ NRECA Rehearing Request at 57-58.
---------------------------------------------------------------------------

c. Commission Determination
    700. We deny the requests for clarification and disagree with 
APPA's and Large Public Power's requests for rehearing asking to expand 
the definition of Relevant State Entity.\1774\ As discussed in Order 
No. 1920, we continue to find that ``regional transmission facilities 
face significant uncertainty and risk of not reaching construction if 
certain stakeholders--in particular, a state regulator responsible for 
permitting transmission facilities--do not perceive the regional 
transmission facilities' value as commensurate with their costs.'' 
\1775\
---------------------------------------------------------------------------

    \1774\ APPA Rehearing Request at 2, 4-5; Large Public Power 
Rehearing Request at 11-13.
    \1775\ Order No. 1920, 187 FERC ] 61,068 at P 1364 (quoting 
NOPR, 179 FERC ] 61,028 at P 297 (footnote omitted)).
---------------------------------------------------------------------------

    701. Municipal electric regulatory bodies and non-public utility 
entities provide valuable insight as stakeholders in Commission-
sanctioned processes. But in defining Relevant State Entities for the 
purposes of Order No. 1920, we find that state entities responsible for 
electric utility regulation or siting electric transmission facilities 
within the state or portion of a state located in the transmission 
planning region are, as discussed above, uniquely situated to influence 
whether or not a Long-Term Regional Transmission Facility reaches 
completion. On balance, while we recognize the important role that 
other stakeholders play in Long-Term Regional Transmission Planning, we 
continue to find that the definition of Relevant State Entities should 
encompass only any state entities responsible for electric utility 
regulation or siting electric transmission facilities within the state 
or portion of a state located in the transmission planning region, 
including any state entity as may be designated for that purpose by the 
law of such state.\1776\ In Order No. 1920, the Commission further 
stated, and we continue to believe, that:
---------------------------------------------------------------------------

    \1776\ As noted below, we make no findings here regarding 
whether any individual municipal electric regulatory body or non-
public utility entity meets the definition of a Relevant State 
Entity, as those determinations properly rest with entities in a 
state, based upon their interpretation of their state laws. Infra P 
703.

    [P]roviding state regulators with a formal opportunity to 
develop a cost allocation method for Long-Term Regional Transmission 
Facilities selected through Long-Term Regional Transmission Planning 
could help increase stakeholder--and state--support for those 
facilities, which, in turn, may increase the likelihood that those 
facilities are sited and ultimately developed with fewer costly 
delays and better ensure just and reasonable Commission-
jurisdictional rates.\1777\
---------------------------------------------------------------------------

    \1777\ Order No. 1920, 187 FERC ] 61,068 at P 1364 (alterations 
omitted) (citing NOPR, 179 FERC ] 61,028 at P 299).

    702. For the same reasons, we also do not find it necessary to 
expand the definition of Relevant State Entities for the purposes of 
Order No. 1920.
    703. In response to City of New Orleans Council's and NESCOE's 
requests,\1778\ we will not make a finding on whether an individual 
state's laws, regulations, and/or policies, or inclusion in a larger 
association of regulators, deem a certain entity to be a Relevant State 
Entity, though we note that state law may be a persuasive or 
dispositive factor in such determinations.\1779\ Instead, entities 
within a state must determine if they qualify as Relevant State 
Entities based on the definition the Commission provided in Order No. 
1920 and based upon their interpretation of their state laws. We also 
reiterate that Order No. 1920 permits other participants, including 
municipal electric regulatory bodies and non-public utility entities 
that do not otherwise meet the definition of a Relevant State Entity, 
to participate in a State Agreement Process, if agreed to by Relevant 
State Entities.\1780\ Finally, we disagree with NRECA's assertion that 
Order No. 1920 permits Relevant State Entities to dictate cost 
allocation to utilities they do not regulate.\1781\ Order No. 1920, as 
modified here on rehearing, provides robust opportunities for Relevant 
State Entities to participate in the development of Long-Term Regional 
Transmission Cost Allocation Methods, given the critical role that 
states will play in the success of Long-Term Regional Transmission 
Planning. However, it is ultimately the Commission that will determine 
whether cost allocation methods proposed on compliance are just and 
reasonable and not unduly discriminatory or preferential, and all 
interested parties will have a full and fair opportunity to participate 
both in regional stakeholder proceedings and in compliance proceedings 
before the Commission.
---------------------------------------------------------------------------

    \1778\ City of New Orleans Council Rehearing Request at 4, 8; 
NESCOE Rehearing Request at 17-20.
    \1779\ Order No. 1920 also allows Relevant State Entities to 
participate in cost allocation negotiations through a regional body. 
See, e.g., Order No. 1920, 187 FERC ] 61,068 at P 999 (declining to 
impose specific requirements regarding how consultation with 
Relevant State Entities will occur, and recognizing need for 
flexibility ``based on the specific needs and makeup of their 
transmission planning region'').
    \1780\ Id. PP 1364 & n.2914, 1402.
    \1781\ NRECA Rehearing Request at 57-58.
---------------------------------------------------------------------------

    704. In response to APPA's contention that the definition of 
Relevant State Entity conflicts with the FPA's definition of ``state 
commission'' as ``the regulatory body of the State or municipality 
having jurisdiction to regulate rates and charges for the sale of 
electric energy to consumers within the State or municipality,'' \1782\ 
we find that the definition of Relevant State Entity for purposes of 
Long-Term Regional Transmission Facility cost allocation is distinct 
from the purpose of the definition of ``state commission'' in the

[[Page 97307]]

FPA and need not align with it. We note, for example, that the FPA 
defines ``state commission'' and ``state'' separately, and in the final 
rule we use neither of these two definitions.\1783\
---------------------------------------------------------------------------

    \1782\ APPA Rehearing Request at 5 (citing 16 U.S.C. 796(15)) 
(emphasis in original).
    \1783\ See 16 U.S.C. 796(15)) and 16 U.S.C. 796(6), 
respectively.
---------------------------------------------------------------------------

2. Extensions of Time for Negotiation of Cost Allocation Methods Under 
State Agreement Processes
a. Order No. 1920 Requirements
    705. In Order No. 1920, the Commission required that any State 
Agreement Process be completed, i.e., any resulting cost allocation 
method must be filed with the Commission, no later than six months 
after selection of the applicable Long-Term Regional Transmission 
Facility (or portfolio of such Facilities).\1784\ The Commission found 
that the State Agreement Process can only be effective if there is a 
limit on the time to reach agreement before defaulting to the Long-Term 
Regional Transmission Cost Allocation Method that the Commission 
required transmission providers to include in their OATTs, that the 
lack of such a deadline could cause delay and increase uncertainty 
regarding selected Long-Term Regional Transmission Facilities, and that 
a deadline, bolstered by a default Long-Term Regional Transmission Cost 
Allocation Method, may increase the incentive for Relevant State 
Entities to reach agreement on cost allocation for a particular Long-
Term Regional Transmission Facility through a State Agreement 
Process.\1785\ The Commission found that six months is a reasonable 
period for State Agreement Process deliberations on a cost allocation 
method because it balances the need for adequate time for negotiations 
with transmission providers' need for finality in their Long-Term 
Regional Transmission Planning.\1786\
---------------------------------------------------------------------------

    \1784\ Order No. 1920, 187 FERC ] 61,068 at P 1406.
    \1785\ Id. P 1413.
    \1786\ Id. P 1414.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    706. Designated Retail Regulators and Undersigned States argue that 
the State Agreement Process is unreasonable because Order No. 1920 does 
not provide adequate time for the adoption of a cost allocation method 
that follows any approved State Agreement Process.\1787\
---------------------------------------------------------------------------

    \1787\ Designated Retail Regulators Rehearing Request at 9; 
Undersigned States Rehearing Request at 8.
---------------------------------------------------------------------------

    707. SERTP Sponsors request that the Commission clarify that upon 
unanimous consent of state commissions and relevant governing 
authorities for SERTP Sponsors not subject to the Commission's 
jurisdiction, the Commission will allow an extension of time for the 
development of methods resulting from a State Agreement Process.\1788\ 
SERTP Sponsors request that at a minimum, the Commission clarify that 
it will consider motions for an extension of time for good cause.\1789\
---------------------------------------------------------------------------

    \1788\ SERTP Sponsors Rehearing Request at 7-8.
    \1789\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    708. We believe that the six-month deadline by which transmission 
providers must file any cost allocation method that results from a 
State Agreement Process is reasonable and are thus unpersuaded by 
parties who challenge the sufficiency of this deadline. While we 
emphasize the benefits of a State Agreement Process, we continue to 
find that this deadline balances the need for adequate time for 
Relevant State Entities to conduct negotiations with the need for 
finality in Long-Term Regional Transmission Planning.\1790\ Consistent 
with Order No. 1920, we find that a deadline, coupled with a default 
Long-Term Regional Transmission Cost Allocation Method, may encourage 
Relevant State Entities to timely reach agreement on cost allocation 
for a particular Long-Term Regional Transmission Facility through a 
State Agreement Process.\1791\ While we grant SERTP Sponsors' request 
to clarify that transmission providers may file motions for an 
extension of time for good cause to the State Agreement Process beyond 
six months after selection of the applicable Long-Term Regional 
Transmission Facility (or portfolio of such Facilities), we decline at 
this time to categorically pre-approve extensions (even if unanimous), 
and thus we deny SERTP Sponsors' associated request for clarification. 
Instead, the Commission will consider any such requests on the record 
before it at that time.
---------------------------------------------------------------------------

    \1790\ Order No. 1920, 187 FERC ] 61,068 at P 1414.
    \1791\ Id. P 1413.
---------------------------------------------------------------------------

E. Use of Existing Cost Allocation Methods in Long-Term Regional 
Transmission Planning or Existing Regional Processes

1. Order No. 1920 Requirements
    709. In Order No. 1920, the Commission required that, to the extent 
transmission providers believe that their existing cost allocation 
methods comply with the requirements of Order No. 1920, they may 
demonstrate in their compliance filings that such methods, as applied 
to Long-Term Regional Transmission Facilities, would comply with the 
requirements of Order No. 1920.\1792\ The Commission also required that 
transmission providers that wish to continue using existing 
transmission planning and cost allocation processes to consider 
transmission needs driven by Public Policy Requirements must 
demonstrate that continued use of any such processes does not interfere 
with or otherwise undermine Long-Term Regional Transmission 
Planning.\1793\
---------------------------------------------------------------------------

    \1792\ Id. PP 1302-1303.
    \1793\ Id. P 243.
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    710. PJM requests that the Commission grant rehearing and confirm 
that it will consider requests to maintain existing cost allocation 
methods on compliance unless and until an alternative is filed.\1794\ 
PJM argues that the Commission has not justified why Order No. 1920 
``categorically prohibit[s] existing cost allocation methodologies from 
remaining in place'' in such circumstances.\1795\ PJM states that it is 
concerned that requiring transmission owners to re-justify existing 
cost allocation methods will set back efforts to implement its Long-
Term Regional Transmission Planning Process.\1796\ PJM argues that the 
requirement to renegotiate all cost allocation methods undercuts the 
longstanding and widely-accepted notion that knowing how costs for 
transmission facilities will be allocated is critical for their 
development.\1797\ PJM further states that its existing cost allocation 
method includes specific cost allocations for reliability-based 
projects, market efficiency projects, public policy projects addressing 
state-identified needs, and multi-driver projects.\1798\ PJM argues 
that requiring transmission owners to re-justify the existing cost 
allocation methods undermines the certainty regarding the development 
of transmission facilities PJM selects to be built.\1799\ PJM states 
that its existing cost allocation methods are the result of years of 
close consultation and extensive work among the states in the PJM 
region and litigation before the Commission. PJM argues that Order No. 
1920 effectively erases these efforts.\1800\
---------------------------------------------------------------------------

    \1794\ PJM Rehearing Request at 19-23.
    \1795\ Id. at 20.
    \1796\ Id. at 20-21.
    \1797\ Id. at 21 (citing Order No. 1920, 187 FERC ] 61,068 at P 
124).
    \1798\ Id. at 22-23.
    \1799\ Id. at 21.
    \1800\ Id. at 22-23.

---------------------------------------------------------------------------

[[Page 97308]]

    711. Ohio Commission Federal Advocate asserts that Order No. 1920 
arbitrarily and capriciously requires continued use of PJM's State 
Agreement Approach to be re-approved by the Commission. Specifically, 
Ohio Commission Federal Advocate argues that the State Agreement 
Approach has long been approved and used in the PJM region to ensure 
just and reasonable cost allocation for public policy projects and asks 
the Commission to revise Order No. 1920 to explicitly allow the 
continued use of the State Agreement Approach at least to the projects 
to which it currently applies.\1801\
---------------------------------------------------------------------------

    \1801\ Ohio Commission Federal Advocate Rehearing Request at 12-
13.
---------------------------------------------------------------------------

3. Commission Determination
    712. Upon consideration of the rehearing requests, we sustain Order 
No. 1920's requirement that transmission providers that wish to 
continue using existing transmission planning and cost allocation 
processes to consider transmission needs driven by Public Policy 
Requirements must demonstrate that continued use of any such processes 
does not interfere with or otherwise undermine Long-Term Regional 
Transmission Planning. We similarly decline to set aside Order No. 
1920's requirement that to use an existing cost allocation method as a 
Long-Term Regional Transmission Cost Allocation Method, a transmission 
provider must demonstrate in its compliance filings that such methods, 
as applied to Long-Term Regional Transmission Facilities, comply with 
Order No. 1920.
    713. We disagree with PJM's request to continue to use existing 
regional cost allocation methods for Long-Term Regional Transmission 
Facilities without a showing that such use complies with the 
requirements of Order No. 1920.\1802\ However, we note that Order No. 
1920 does not prohibit transmission providers from proposing to use 
existing regional cost allocation methods to comply with the 
requirements for Long-Term Regional Transmission Cost Allocation 
Methods, so long as the transmission providers demonstrate that the 
existing methods are just and reasonable and not unduly discriminatory 
or preferential when applied to Long-Term Regional Transmission 
Facilities and comply with the requirements of Order No. 1920 and the 
cost causation principle.\1803\ Nevertheless, given the deficiencies 
identified in existing transmission planning and cost allocation 
processes identified by the Commission in Order No. 1920 and the 
numerous reforms adopted in Order No. 1920 for Long-Term Regional 
Transmission Planning to address those deficiencies, it would be unjust 
and unreasonable for the Commission to accept existing cost allocation 
methods for Long-Term Regional Transmission Facilities without ensuring 
that such methods are consistent with Order No. 1920.\1804\
---------------------------------------------------------------------------

    \1802\ PJM Rehearing Request at 19-23.
    \1803\ Order No. 1920, 187 FERC ] 61,068 at PP 1302-1303.
    \1804\ Id. PP 124-125 (citations omitted), 1302-1303 (citing 
Order No. 1000, 136 FERC ] 61,051 at P 565; Order No. 1000-A, 139 
FERC ] 61,132 at P 747).
---------------------------------------------------------------------------

    714. We recognize that it may be just and reasonable to apply 
existing regional cost allocation methods to Long-Term Regional 
Transmission Facilities for many of the same reasons that the 
Commission found these methods to be just and reasonable when initially 
approving them. For this reason, Order No. 1920 specifically provided 
that transmission providers may demonstrate in their compliance filings 
that their existing regional cost allocation methods, as applied to 
Long-Term Regional Transmission Facilities, would comply with the 
requirements of Order No. 1920.\1805\ As such, we disagree with PJM's 
assertion that Order No. 1920 will ignore past efforts to facilitate 
consensus on cost allocation methods.\1806\
---------------------------------------------------------------------------

    \1805\ Id. PP 1302-1303. In Order No. 1000, in response to 
``concerns regarding relitigation of existing Commission-approved 
transmission cost allocation methods,'' the Commission declined ``to 
prejudge whether any such existing cost allocation methods 
compl[ied] with the requirements of [Order No. 1000],'' and noted 
that ``[t]o the extent [transmission providers] believe[d] that to 
be the case with their region, they [could] take such positions 
during the development of compliance proposals and during Commission 
review of compliance filings.'' Order No. 1000, 136 FERC ] 61,051 at 
P 565. On compliance, the Commission found that SPP's existing 
Balanced Portfolio and Highway/Byway regional cost allocation 
methods and MISO's existing regional cost allocation methods for 
Multi-Value Projects (MVPs) and Market Efficiency Projects (MEP) 
complied with the requirements of Order No. 1000. Sw. Power Pool, 
Inc., 144 FERC ] 61,059, at PP 336, 347 (2013), order on reh'g and 
compliance, 149 FERC ] 61,048, at P 276 (2014), order on reh'g and 
compliance, 151 FERC ] 61,045, order on compliance, 152 FERC ] 
61,106 (2015); Midwest Indep. Transmission Sys. Operator, Inc., 142 
FERC ] 61,215, at PP 420, 434 (2013), order on reh'g and compliance, 
147 FERC ] 61,127, at P 404 (2014), order on reh'g and compliance, 
150 FERC ] 61,037 (2015), order on compliance, Docket No. ER13-187-
010 (Mar. 31, 2015) (delegated order).
    \1806\ PJM Rehearing Request at 22-23. With respect to PJM's 
request to continue using its existing regional cost allocation 
method for public policy projects addressing state-identified needs 
outside of Long-Term Regional Transmission Planning, we address this 
issue above in the Requirement to Participate in Long-Term Regional 
Transmission Planning section.
---------------------------------------------------------------------------

    715. We disagree with Ohio Commission Federal Advocate's assertion 
that Order No. 1920 requires that the continued use of PJM's State 
Agreement Approach must be re-approved by the Commission and that the 
final rule limits use of PJM's State Agreement Approach.\1807\ We note 
that Order No. 1920 requires reapproval for existing cost allocation 
methods' use in Long-Term Regional Transmission Planning only if those 
methods are to be used for compliance with Order No. 1920.\1808\ PJM's 
State Agreement Approach is not a regional cost allocation method used 
to comply with the requirements of Order No. 1000. The Commission 
approved the existing PJM State Agreement Approach in an order on 
compliance in the Order No. 1000 proceeding, but did not find that the 
PJM State Agreement Approach was a regional cost allocation method 
compliant with the requirements of Order No. 1000.\1809\ In addition, 
PJM's State Agreement Approach is different than the ``State Agreement 
Process'' as discussed in Order No. 1920. The State Agreement Process 
referenced in Order No. 1920 is a new construct under which Relevant 
State Entities may agree to a different cost allocation method for 
Long-Term Regional Transmission Facilities than the generally 
applicable Long-Term Regional Transmission Cost Allocation Method on 
file. Therefore, we clarify that Order No. 1920 does not prohibit PJM 
from maintaining its existing State Agreement Approach for transmission 
facilities that are not selected in either its Order No. 1000 regional 
transmission planning process or through Long-Term Regional 
Transmission Planning.\1810\ To clarify further, PJM's State Agreement 
Approach is supplemental to PJM's existing regional transmission cost

[[Page 97309]]

allocation method and, as a result, is not in any way affected by Order 
No. 1920.
---------------------------------------------------------------------------

    \1807\ Ohio Commission Federal Advocate Rehearing Request at 12-
13.
    \1808\ Order No. 1920, 187 FERC ] 61,068 at PP 1302-1303.
    \1809\ See PJM Interconnection, L.L.C. 142 FERC ] 61,214, at P 
142 (2013) (``We find PJM's proposed State Agreement Approach is not 
needed for PJM to comply with the provisions of Order No. 1000 
addressing transmission needs driven by public policy requirements. 
PJM's State Agreement Approach supplements, but does not conflict or 
otherwise replace, PJM's process to consider transmission needs 
driven by public policy requirements as required by Order No. 1000 
addressed above. Accordingly, the Commission need not find that the 
State Agreement Approach and corresponding cost allocation method 
comply with Order No. 1000.''), order on reh'g and compliance, 147 
FERC ] 61,128 (2014), order on reh'g and compliance, 150 FERC ] 
61,038, order on reh'g and compliance, 151 FERC ] 61,250 (2015).
    \1810\ See supra Requirement to Participate in Long-Term 
Regional Transmission Planning section (responding to Pennsylvania 
Commission's and PJM States' requests regarding the PJM State 
Agreement Approach).
---------------------------------------------------------------------------

    716. However, if the Relevant State Entities in PJM agree to rely 
on its existing PJM State Agreement Approach as an Order No. 1920 State 
Agreement Process that applies to selected Long-Term Regional 
Transmission Facilities, and if PJM agrees, PJM would have to propose 
and demonstrate on compliance that its State Agreement Approach 
complies with all of the State Agreement Process requirements set forth 
in Order No. 1920. In addition, we reiterate that the ex ante Long-Term 
Regional Transmission Cost Allocation Method(s) that Order No. 1920 
prescribes would be used to allocate the costs of selected Long-Term 
Regional Transmission Facilities if any Order No. 1920-compliant State 
Agreement Process does not result in a cost allocation method within 
six months after a project is selected, as described in the final rule. 
As noted above, the Commission will consider the entire record--
including the Relevant State Entities' agreed-upon Long-Term Regional 
Transmission Cost Allocation Method and/or State Agreement Process and 
the transmission provider's proposal--when setting the replacement 
rate.
    717. In addition, more generally, we clarify that we permit 
continued use of other existing state agreement approaches and similar 
voluntary measures under Order No. 1920, so long as they are consistent 
with the requirements stated above.

F. Regional Cost Allocation Principles for Long-Term Regional 
Transmission Facilities

1. Logical Outgrowth
a. NOPR Proposals
    718. In the NOPR, the Commission proposed to require that the Long-
Term Regional Transmission Cost Allocation Method and any cost 
allocation method resulting from the State Agreement Process for Long-
Term Regional Transmission Facilities comply with the existing six 
Order No. 1000 regional cost allocation principles.\1811\ The 
Commission made a preliminary finding that compliance with such 
principles will help ensure that Commission-jurisdictional rates 
resulting from any State Agreement Process will be just and reasonable 
and not unduly discriminatory or preferential.\1812\ The six regional 
transmission cost allocation principles adopted in Order No. 1000 are: 
principle (1), the costs of transmission facilities must be allocated 
to those within the transmission planning region that benefit from 
those facilities in a manner that is at least roughly commensurate with 
estimated benefits; principle (2), those that receive no benefit from 
transmission facilities, either at present or in a likely future 
scenario, must not be involuntarily allocated any of the costs of those 
transmission facilities; principle (3), a benefit to cost threshold 
ratio, if adopted, cannot exceed 1.25 to 1; principle (4), costs must 
be allocated solely within the transmission planning region unless 
another entity outside the region voluntarily assumes a portion of 
those costs; principle (5), the method for determining benefits and 
identifying beneficiaries must be transparent; and principle (6), there 
may be different regional cost allocation methods for different types 
of transmission facilities, such as those needed for reliability, 
congestion relief, or to achieve Public Policy Requirements.\1813\
---------------------------------------------------------------------------

    \1811\ NOPR, 179 FERC ] 61,028 at PP 302, 312.
    \1812\ Id. P 312.
    \1813\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 637, 646, 
657, 668, 685.
---------------------------------------------------------------------------

b. Order No. 1920 Requirements
    719. In Order No. 1920, the Commission adopted the NOPR proposal, 
with modification, to require compliance with Order No. 1000 regional 
cost allocation principles (1) through (5) for Long-Term Regional 
Transmission Cost Allocation Methods that transmission providers 
propose but to which Relevant State Entities have not indicated their 
agreement. The Commission explained that, because compliance with 
regional cost allocation principle (6) is not required, transmission 
providers cannot adopt different ex ante Long-Term Regional 
Transmission Cost Allocation Methods for different types of Long-Term 
Regional Transmission Facilities, such as those needed for reliability, 
congestion relief, or to achieve Public Policy Requirements.\1814\
---------------------------------------------------------------------------

    \1814\ Order No. 1920, 187 FERC ] 61,068 at P 1469.
---------------------------------------------------------------------------

    720. The Commission additionally determined that compliance with 
the Order No. 1000 regional cost allocation principles is not required 
in two situations: (1) Long-Term Regional Transmission Cost Allocation 
Methods to which Relevant State Entities have agreed as part of the 
Engagement Period; and (2) cost allocation methods resulting from a 
State Agreement Process.\1815\ The Commission explained that this 
decision was consistent with application of Order No. 1000 and past 
precedent, noting that the Commission has previously found that ``Order 
No. 1000 allows market participants, including states, to negotiate 
voluntarily alternative cost sharing arrangements that are distinct 
from the relevant regional cost allocation method(s).'' \1816\ 
Additionally, the Commission noted that where transmission providers 
have proposed cost allocation methods corresponding to such voluntary 
arrangements, the Commission has held that it need not find that those 
cost allocation methods comply with Order No. 1000.\1817\
---------------------------------------------------------------------------

    \1815\ Id. P 1470.
    \1816\ Id. P 1476 (quoting State Voluntary Agreements to Plan & 
Pay for Transmission Facilities, 175 FERC ] 61,225, at P 3 (2021)).
    \1817\ Id. (citing PJM Interconnection, L.L.C., 142 FERC ] 
61,214 at PP 142-143, order on reh'g and compliance, 147 FERC ] 
61,128 at P 92; ISO New England Inc., 143 FERC ] 61,150, at P 121 
(2013); Consol. Edison Co. of N.Y., Inc., 180 FERC ] 61,106, at PP 
48-50 (2022)).
---------------------------------------------------------------------------

c. Requests for Rehearing and Clarification
    721. Several commenters argue that Order No. 1920 violates the 
APA's notice-and-comment requirements because, contrary to the NOPR 
proposal, it does not require cost allocation methods to comply with 
Order No. 1000's regional cost allocation principle (6) and prohibits 
transmission providers from adopting different cost allocation methods 
for different types of transmission facilities.\1818\ NRECA 
characterizes the change as an ``about face'' from both the NOPR and 
existing Commission policy.\1819\
---------------------------------------------------------------------------

    \1818\ Arizona Commission Rehearing Request at 17-19; East 
Kentucky Rehearing Request at 1-2; NRECA Rehearing Request at 6, 16-
17.
    \1819\ NRECA Rehearing Request at 16-17.
---------------------------------------------------------------------------

    722. NRECA additionally argues that Order No. 1920 violates the 
APA's notice-and-comment requirements because, contrary to the NOPR, 
Order No. 1920 does not require a transmission provider's Long-Term 
Regional Transmission Cost Allocation Method to comply with any of the 
Order No. 1000 regional cost allocation principles if Relevant State 
Entities indicate that they agreed to that method as part of the 
required Engagement Period, and does not require a cost allocation 
method resulting from the State Agreement Process to comply with any of 
the Order No. 1000 regional cost allocation principles.\1820\ NRECA 
argues that the ``Final Rule's flip-flops on these fundamental 
requirements for Long-Term Regional Transmission Cost Allocation 
Methods and the cost allocation methods resulting from a State 
Agreement Process are not a

[[Page 97310]]

logical outgrowth of the NOPR's exactly opposite proposals.'' \1821\
---------------------------------------------------------------------------

    \1820\ Id. at 6, 17.
    \1821\ Id. at 16-17.
---------------------------------------------------------------------------

d. Commission Determination
    723. We find, and disagree with rehearing requests to the contrary, 
that the Commission provided adequate notice of and opportunity to 
comment on the determination in Order No. 1920 to require transmission 
providers to demonstrate compliance with Order No. 1000 regional cost 
allocation principles (1) through (5) but not Order No. 1000 regional 
cost allocation principle (6) for Long-Term Regional Transmission Cost 
Allocation Methods to which Relevant State Entities have not agreed.
    724. Courts applying the logical outgrowth doctrine have permitted 
agencies to drop elements of proposed rules ``even if a resulting final 
rule effectively abandons an agency's initial proposal'' if the result 
is ``reasonably foreseeable.'' \1822\ Order No. 1920 is a logical 
outgrowth of the NOPR in this regard, and the APA's notice-and-comment 
requirements are therefore satisfied.\1823\ In the NOPR, the Commission 
expressed concern that transmission providers are not engaging in long-
term, more comprehensive regional transmission planning and cost 
allocation processes like MISO's MVP process, which identifies projects 
that are projected to provide multiple kinds of reliability and 
economic benefits.\1824\ The Commission proceeded to endorse this kind 
of transmission planning.\1825\ The Commission also noted expressly 
that ``we preliminarily find that the cost allocation requirements for 
transmission facilities identified and selected in the regional 
transmission plan through Long-Term Regional Transmission Planning 
proposed in this proceeding may differ in part from those established 
in Order No. 1000.'' \1826\
---------------------------------------------------------------------------

    \1822\ Mid Continent Nail Corp. v. U.S., 846 F.3d 1364, 1374 
(Fed. Cir. 2017) (citing Long Island Care, 551 U.S. at 174-75).
    \1823\ Id. at 1373 (``The dispositive question in assessing the 
adequacy of notice under the APA is whether an agency's final rule 
is a `logical outgrowth' of an earlier request for comment.'').
    \1824\ NOPR, 179 FERC ] 61,028 at P 31.
    \1825\ Id. P 33.
    \1826\ Id. P 299. Although the Commission then gave the example 
of greater state involvement as one way that the cost allocation 
requirements might differ, that statement was sufficient to put 
commenters on notice that the Commission would not necessarily adopt 
in full Order No. 1000's requirements regarding cost allocation. 
Indeed, as noted below, multiple commenters, including New Jersey 
Commission and PIOs, expressed support for modifying Order No. 
1000's cost allocation principles, indicating their understanding 
that such potential modifications could be adopted in a final rule.
---------------------------------------------------------------------------

    725. But allowing transmission providers to establish reliability, 
economic, or public policy transmission facility types, which would 
have been possible under the NOPR proposal, reflects a more siloed 
approach to regional transmission planning and cost allocation that 
commenters argued is misaligned with the reforms in Order No. 1920 and 
urged the Commission to avoid.\1827\ Indeed, the Commission 
specifically noted its concern that using ``only a subset of benefits 
in assigning the cost of Long-Term Regional Transmission Facilities may 
contribute to the risk of free rider problems that impede development 
of the more efficient or cost-effective regional transmission 
facilities.'' \1828\ That observation, which was made in the context of 
benefits used as the basis to allocate the costs of Long-Term Regional 
Transmission Facilities, further indicated the Commission's concerns 
with the siloed status quo approach and mirrored the rationale that the 
Commission adopted in eliminating regional cost allocation principle 
(6). It was therefore reasonably foreseeable that Order No. 1920 would 
not require compliance with regional cost allocation principle (6), 
which allows for project-type-limited Long-Term Regional Transmission 
Cost Allocation Methods, because such an approach would be inconsistent 
with Order No. 1920's long-term, forward-looking, more comprehensive 
regional transmission planning.\1829\ However, as noted below, 
transmission providers and Relevant State Entities have broad 
flexibility to recognize the different types of benefits provided by 
Long-Term Regional Transmission Facilities and allocate costs in 
proportion to those benefits.
---------------------------------------------------------------------------

    \1827\ See Acadia Center and CLF NOPR Initial Comments at 16-17; 
Massachusetts Attorney General NOPR Initial Comments at 21; PIOs 
NOPR Initial Comments at 46, 60-62.
    \1828\ NOPR, 179 FERC ] 61,028 at P 325.
    \1829\ Order No. 1920, 187 FERC ] 61,068 at P 1474.
---------------------------------------------------------------------------

    726. Further, courts have held that a final rule satisfies the 
logical outgrowth standard where an agency either finalizes only part 
of a multi-segment proposal \1830\ or chooses not to finalize a 
proposal.\1831\ Order No. 1920 is a logical outgrowth of the NOPR in 
this regard. Because the NOPR proposed to require compliance with the 
existing six Order No. 1000 regional cost allocation principles, the 
Commission's decision to refrain from requiring compliance with one of 
those principles--principle (6)--could have been reasonably anticipated 
by commenters, especially given the Commission's frequently stated 
concerns regarding the siloing of transmission facilities into 
different categories under Order No. 1000.\1832\ Indeed, in NOPR 
comments, parties expressed support for modifying Order No. 1000's cost 
allocation principles.\1833\ Such comments are evidence that parties 
had adequate notice that the Commission might refrain from taking the 
NOPR's proposed step--i.e., requiring compliance with all six regional 
cost allocation principles.\1834\
---------------------------------------------------------------------------

    \1830\ Ariz. Pub. Serv. Co. v. EPA, 211 F.3d at 1297-1300 
(finding sufficient notice where agency first proposed that Indian 
tribes be required to meet the ``same requirements'' as states with 
respect to judicial review of permits issued pursuant to the Clean 
Air Act, but then adopted a final rule that exempted tribes from 
some, though not all, such requirements).
    \1831\ New York v. EPA, 413 F.3d at 44 (per curiam) (``One 
logical outgrowth of a proposal is surely . . . to refrain from 
taking the proposed step.'' (quoting Am. Iron & Steel Inst. v. EPA, 
886 F.2d at 400); see also Long Island Care, 551 U.S. at 175 
(stating, in the context of rejecting claims that an agency provided 
legally defective notice because it did not finalize a proposed 
rule, ``[w]e do not understand why such a possibility was not 
reasonably foreseeable''); Vanda Pharms., 98 F.4th at 498 (finding 
that the APA's ``notice-and-comment procedure is designed so that an 
agency can float a potential rule to the public without committing 
itself to enacting the proposed rule's content'').
    \1832\ See NOPR, 179 FERC ] 61,028 at PP 67, 325.
    \1833\ New Jersey Commission NOPR Initial Comments at 18 
(expressing support for a requirement that any cost allocation 
method comply with the Order No. 1000 regional cost allocation 
principles except principle (4)); PIOs NOPR Initial Comments at 61 & 
n.172 (requesting ``that the Commission specifically find that cost 
allocation of public policy projects without consideration of 
economic and reliability benefits is unjust, unreasonable, and 
unduly discriminatory'').
    \1834\ Miami-Dade Cnty. v. EPA, 529 F.3d 1049, 1059 (11th Cir. 
2008) (``[A]lthough they may not provide the only basis upon which 
an agency claims to have satisfied the notice requirement, comments 
may be adduced as evidence of the adequacy of notice.'').
---------------------------------------------------------------------------

    727. For similar reasons, we also disagree that the Commission 
failed to provide adequate notice of and opportunity to comment on the 
determination in Order No. 1920 to not adopt the requirement that 
transmission providers demonstrate compliance with any of the six Order 
No. 1000 regional cost allocation principles for Long-Term Regional 
Transmission Cost Allocation Methods to which Relevant State Entities 
have agreed as part of the Engagement Period or for cost allocation 
methods resulting from a State Agreement Process. In the NOPR, the 
Commission proposed to require that the Long-Term Regional Transmission 
Cost Allocation Method and any cost allocation method resulting from 
the State Agreement Process comply with the six Order No. 1000 regional 
cost allocation principles.\1835\ As noted above, because ``[o]ne 
logical outgrowth of a proposal is surely . . . to refrain from taking 
the proposed step,'' \1836\ the

[[Page 97311]]

Commission's decision to refrain from adopting the entire proposal as 
to Long-Term Regional Transmission Cost Allocation Methods to which 
Relevant State Entities have agreed or for cost allocation methods 
resulting from a State Agreement Process could have been reasonably 
anticipated by commenters. Moreover, the decision to refrain from 
adopting the proposal was all the more foreseeable because, as a result 
of that decision, the cost allocation requirements adopted in Order No. 
1920 are more closely aligned with the Commission's existing cost 
allocation requirements,\1837\ which it had already articulated at the 
time it issued the NOPR, and under which cost allocation methods 
corresponding to voluntarily negotiated alternative cost sharing 
arrangements that are distinct from the relevant regional cost 
allocation method(s) need not comply with Order No. 1000.\1838\
---------------------------------------------------------------------------

    \1835\ NOPR, 179 FERC ] 61,028 at P 302.
    \1836\ New York v. EPA, 413 F.3d at 44.
    \1837\ Cf. New York v. EPA, 413 F.3d at 44 (agency satisfied 
APA's notice-and-comment requirements where it adopted the approach 
of the ``status quo ante'' rather than the proposed approach).
    \1838\ Order No. 1920, 187 FERC ] 61,068 at P 1476 (citing PJM 
Interconnection, L.L.C., 142 FERC ] 61,214 at PP 142-143, order on 
reh'g and compliance, 147 FERC ] 61,128 at P 92; ISO New England 
Inc., 143 FERC ] 61,150 at P 121).
---------------------------------------------------------------------------

2. Omission of Regional Cost Allocation Principle No. 6 and Ability To 
Allocate Costs by Type of Project
a. Order No. 1920 Requirements
    728. In Order No. 1920, the Commission declined to require 
transmission providers to demonstrate that any Long-Term Regional 
Transmission Cost Allocation Methods that they propose complies with 
Order No. 1000 regional cost allocation principle (6).\1839\ The 
Commission explained that Order No. 1000 regional cost allocation 
principle (6) allows for cost allocation methods based on different 
types of transmission facilities (i.e., reliability, economic, or 
public policy transmission facility types), but that there can be only 
one cost allocation method for each type of facility, and that method 
must be determined in advance.\1840\ The Commission found that project-
type-limited Long-Term Regional Transmission Cost Allocation Methods 
that would be permitted by applying regional cost allocation principle 
(6) are inconsistent with the long-term, forward-looking, more 
comprehensive regional transmission planning required in Order No. 
1920.\1841\ As a result, unlike under Order No. 1000, transmission 
providers cannot adopt different Long-Term Regional Transmission Cost 
Allocation Methods for different types of Long-Term Regional 
Transmission Facilities, such as those needed for reliability, 
congestion relief, or to achieve Public Policy Requirements.\1842\
---------------------------------------------------------------------------

    \1839\ Id. P 1469.
    \1840\ Id. P 1474.
    \1841\ Id.
    \1842\ Id. P 1469.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    729. Many parties argue that the Commission erred in not requiring 
the application of Order No. 1000 regional cost allocation principle 
(6) and request that the Commission implement such a requirement so 
that transmission providers may allocate the cost of Long-Term Regional 
Transmission Facilities by project type.\1843\ Nearly all of these 
parties argue that not requiring the application of regional cost 
allocation principle (6) will result in cost allocation that violates 
cost causation or the ``beneficiary pays'' principle.\1844\ Utah 
Commission asserts that the Commission not requiring the application of 
regional cost allocation principle (6) in Order No. 1920 violates cost 
causation principles by flatly enjoining any cost allocation method 
that distinguishes between projects that are based on economic or 
engineering necessity and those based on the ``public policy'' 
preferences of states, local governments, and corporations.\1845\ 
Several parties argue that Order No. 1920 will result in cost 
allocation that fails to reflect the role of state policy in causing 
costs and will shift the financial burden away from the cost-causing 
states that imposed those policies.\1846\ Idaho Commission argues that 
Order No. 1920 contradicts the Commission's position in Order No. 1000, 
which stresses the role of states in consideration of costs potentially 
allocated across multiple states with respect to transmission needs 
driven by states' individual Public Policy Requirements.\1847\
---------------------------------------------------------------------------

    \1843\ Arizona Commission Rehearing Request at 18-19; Dominion 
Rehearing Request at 28-31; East Kentucky Rehearing Request at 3; 
Idaho Commission Rehearing Request at 2-4; Indicated PJM TOs 
Rehearing Request at 2-3, 4-6; Montana Commission Rehearing Request 
at 1, 4-6; Northern Virginia Rehearing Request at 5, 9-13; NRECA 
Rehearing Request at 49-55; Ohio Commission Federal Advocate 
Rehearing Request at 13-15; Utah Commission Rehearing Request at 9-
10; West Virginia Commission Rehearing Request at 6-8; Wyoming 
Commission Rehearing Request at 4-6.
    \1844\ Arizona Commission Rehearing Request at 18-19; Idaho 
Commission Rehearing Request at 2-4; Indicated PJM TOs Rehearing 
Request at 2-3, 4-6; Montana Commission Rehearing Request at 1, 4-6; 
Northern Virginia Rehearing Request at 5, 9-13; NRECA Rehearing 
Request at 53-54; Utah Commission Rehearing Request at 9-10; West 
Virginia Commission Rehearing Request at 6-8; Wyoming Commission 
Rehearing Request at 4-6.
    \1845\ Utah Commission Rehearing Request at 9-10.
    \1846\ Idaho Commission Rehearing Request at 3-4; Montana 
Commission Rehearing Request 5-6; West Virginia Commission Rehearing 
Request at 7-8; Wyoming Commission Rehearing Request at 5-6.
    \1847\ Idaho Commission Rehearing Request at 3 (citing Order No. 
1000, 136 FERC ] 61,051 at P 486).
---------------------------------------------------------------------------

    730. Ohio Commission Federal Advocate argues that the prohibition 
against transmission providers allocating costs for Long-Term Regional 
Transmission Facilities based on reliability, economic, and Public 
Policy Requirement project types is not possible to reconcile with the 
principle that cost allocation ought to be roughly commensurate with 
benefits. Ohio Commission Federal Advocate offers as an example a 
transmission facility that would not exist but for the policy of one or 
more states, does not affect the power flow in any neighboring states, 
and does not provide any tangible benefit to any other states, arguing 
that the Commission ought to clarify that, in this instance, it is 
wholly appropriate that the sponsoring state or states bear the full 
cost of the facility and that it would be an unjust and unreasonable 
result to assign any costs to any other state. Ohio Commission Federal 
Advocate argues that Ohioans were not afforded the opportunity to weigh 
in on the policies of other states, nor were they granted a vote on the 
politicians enacting them, and, as such, should not be assigned any 
costs associated with those policies.\1848\
---------------------------------------------------------------------------

    \1848\ Ohio Commission Federal Advocate Rehearing Request at 13-
15.
---------------------------------------------------------------------------

    731. Some parties assert that the Commission's decision not to 
require the application of regional cost allocation principle (6) and 
the prohibition against Long-Term Regional Transmission Facility types 
and associated cost allocation methods is arbitrary and capricious 
\1849\ because the Commission has not provided a reasonable explanation 
or any supporting evidence as to how, among other things, this policy 
will protect consumers from unjust, unreasonable, and unduly 
discriminatory transmission rates; \1850\ the Commission did not 
explain how the rejection of project-type cost allocation is forward-
looking or comprehensive; \1851\ and the Commission did not 
meaningfully distinguish how Long-Term Regional Transmission Planning 
differs from regional transmission planning under Order No. 1000.\1852\ 
Dominion asserts

[[Page 97312]]

that Order No. 1920 does not cite any record evidence, nor is it clear 
whether any commenters to the NOPR requested this change to Order No. 
1000's cost allocation principles.\1853\
---------------------------------------------------------------------------

    \1849\ E.g., Northern Virginia Rehearing Request at 5.
    \1850\ East Kentucky Rehearing Request at 3.
    \1851\ Ohio Commission Federal Advocate Rehearing Request at 10.
    \1852\ Dominion Rehearing Request at 29-30.
    \1853\ Id. at 29.
---------------------------------------------------------------------------

    732. Dominion argues that Order No. 1920 inappropriately treats all 
Long-Term Regional Transmission Facilities as equal for cost allocation 
purposes under the guise of the holistic transmission planning that 
Order No. 1920 seeks to foster. Dominion further argues that holistic 
transmission planning can acknowledge that certain projects provide 
different types of benefits and serve different needs, but together, as 
a package, serve a variety of needs. Dominion asserts that, if cost 
allocation cannot be tied to an identified underlying driver for the 
project, costs are more likely to be inappropriately socialized to 
customers who did not cause the need and do not benefit from it. 
Dominion states that the Commission should continue to allow 
transmission providers to develop different project types and 
associated cost allocations, but also require that transmission 
providers have a category of projects to act as a backstop that 
accounts for all potential benefits.\1854\
---------------------------------------------------------------------------

    \1854\ Id. at 29-31.
---------------------------------------------------------------------------

    733. NRECA argues that the Commission's argument in support of its 
prohibition on using different cost allocation methods for different 
types of Long-Term Regional Transmission Facilities is essentially that 
the Commission can restrict cost allocation methods by dictating 
planning methods.\1855\ NRECA contends that this prohibition and 
reasoning is contrary to precedent and the Order No. 1000 regional cost 
allocation principle (1) that Order No. 1920 adopts because it would 
result in the costs of transmission facilities being allocated in a 
manner that is not at least roughly commensurate with estimated 
benefits.\1856\ NRECA argues that, if Long-Term Regional Transmission 
Facilities produce multiple types of benefits that must be accounted 
for in Long-Term Regional Transmission Planning, this is an argument 
for a more flexible and more tailored approach to cost allocation with 
different cost allocation methods, not a more prescriptive and less 
tailored approach.\1857\
---------------------------------------------------------------------------

    \1855\ NRECA Rehearing Request at 53.
    \1856\ Id. (citing ICC v. FERC I, 576 F.3d at 477; Order No. 
1000, 136 FERC ] 61,051 at P 622).
    \1857\ Id. at 54.
---------------------------------------------------------------------------

    734. NRECA contends that allocating costs of a Long-Term Regional 
Transmission Facility built to satisfy Public Policy Requirements or 
other expansive factors required by the rule, such as corporate 
commitments, in the same manner as a facility built for reliability or 
economic purposes also likely conflicts with Order No. 1000's regional 
cost allocation principle (2) because those that receive no benefits 
would likely be involuntarily allocated costs.\1858\ NRECA argues that 
costs associated with Long-Term Regional Transmission Facilities built 
to satisfy transmission needs driven by corporate commitments should be 
borne by the relevant corporations, not by other transmission customers 
that do not benefit from the facility.\1859\
---------------------------------------------------------------------------

    \1858\ Id.
    \1859\ Id. at 55.
---------------------------------------------------------------------------

    735. NRECA further argues that the omission of principle (6) and 
prohibition on using different cost allocation methods for different 
types of Long-Term Regional Transmission Facilities violates Order No. 
1000's regional cost allocation principle (4) because it will likely 
allow the costs of Long-Term Regional Transmission Facilities built to 
satisfy a state's Public Policy Requirements to be allocated to 
customers in other states.\1860\
---------------------------------------------------------------------------

    \1860\ Id. Order No. 1000 regional cost allocation principle (4) 
provides that costs must be allocated ``solely within th[e] 
transmission planning region unless another entity outside the 
region or another transmission planning region voluntarily agrees to 
assume a portion of those costs.'' Order No. 1000, 136 FERC ] 61,051 
at P 657.
---------------------------------------------------------------------------

    736. Arizona Commission, Ohio Commission Federal Advocate, and 
NRECA argue that the Commission's decision not to require the 
application of regional cost allocation principle (6) and the 
prohibition against Long-Term Regional Transmission Facility types and 
associated cost allocation methods replaces flexibility with a one-
size-fits-all requirement.\1861\ Idaho Commission contends that Order 
No. 1920 strays from Order No. 1000's ``light touch,'' highlighted in 
South Carolina Public Service Authority v. FERC, where the Commission 
did not ``dictate how costs are to be allocated.'' \1862\
---------------------------------------------------------------------------

    \1861\ Arizona Commission Rehearing Request at 18-19; Ohio 
Commission Federal Advocate Rehearing Request at 14; NRECA Rehearing 
Request at 52, 54.
    \1862\ Idaho Commission Rehearing Request at 3 (quoting S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 81).
---------------------------------------------------------------------------

    737. Indicated PJM TOs request that the Commission clarify that, by 
precluding transmission providers from adopting Long-Term Regional 
Transmission Cost Allocation Methods for different project types, it 
did not intend to preclude transmission providers from adopting cost 
allocation methods that allocate costs based on the different benefits 
associated with a particular facility. Indicated PJM TOs argue that 
such a clarification would be consistent with the Commission's 
obligation to ensure that the transmission provider allocates the cost 
in a manner that is at least roughly commensurate with estimated 
benefits. Indicated PJM TOs state that, if the Commission does not 
grant this clarification, they seek rehearing of the decision to 
preclude transmission providers from adopting different Long-Term 
Regional Transmission Cost Allocation Methods based on a facility's 
benefits because this outcome is inconsistent with other statements in 
the NOPR and Order No. 1920 and long-standing cost causation principles 
and nothing in regional cost allocation principle (6) prevents 
transmission providers from having this flexibility.\1863\
---------------------------------------------------------------------------

    \1863\ Indicated PJM TOs Rehearing Request at 2-3, 4-6.
---------------------------------------------------------------------------

    738. Virginia and North Carolina Commissions argue that the 
Commission should afford transmission providers, in coordination with 
Relevant State Entities and other stakeholders, the maximum flexibility 
possible with respect to potential ex ante cost allocation methods, so 
long as such methods are in compliance with the Commission's cost-
causation principles. As a result, Virginia and North Carolina 
Commissions assert that the Commission should clarify on rehearing that 
Order No. 1920 does not expressly preclude cost allocation methods that 
allocate costs based on the incremental costs associated with the 
inclusion of one or more public policy factors.\1864\
---------------------------------------------------------------------------

    \1864\ Virginia and North Carolina Commissions Rehearing Request 
at 5-6.
---------------------------------------------------------------------------

c. Commission Determination
    739. We sustain Order No. 1920's decision to not require Long-Term 
Regional Transmission Cost Allocation Methods to which Relevant State 
Entities do not agree to comply with Order No. 1000 regional cost 
allocation principle (6), and also sustain the prohibition of cost 
allocation methods that allocate costs based solely on one type of 
benefit, such as reliability, economic, and public policy transmission 
facility types. However, we note our clarification below that 
transmission providers and Relevant State Entities may consider 
different types of benefits provided by Long-Term Regional Transmission 
Facilities and allocate costs in proportion to those benefits.\1865\ 
Recognizing the flexibility

[[Page 97313]]

to allocate costs in proportion to different types of benefits, we 
disagree with arguments raised on rehearing that the Commission should 
require the application of Order No. 1000 regional cost allocation 
principle (6) to Long-Term Regional Transmission Cost Allocation 
Methods to which Relevant State Entities have not agreed and arguments 
that the Commission's decision on this issue is arbitrary and 
capricious. First, because of the flexibility the Commission provided 
to transmission providers to propose different cost allocation methods 
for Long-Term Regional Transmission Facilities, we disagree that a 
requirement not to use cost allocation methods that allocate costs 
based on project types will result in adoption of cost allocation 
methods that violate the cost causation principle. We reiterate that, 
as stated in Order No. 1920, the Commission will evaluate each proposed 
Long-Term Regional Transmission Cost Allocation Method to ensure that 
it will allocate costs in a manner that is at least roughly 
commensurate with the estimated benefits that Long-Term Regional 
Transmission Facilities will provide, which will ensure compliance with 
the cost causation principle and the just and reasonable standard more 
broadly.\1866\ To the extent that a party believes that any Long-Term 
Regional Transmission Cost Allocation Method submitted on compliance, 
including those discussed herein, violates the cost causation 
principle, it will have the opportunity to raise those concerns in 
response to the compliance filing.
---------------------------------------------------------------------------

    \1865\ See infra Concerns Regarding Cost Causation section.
    \1866\ Order No. 1920, 187 FERC ] 61,068 at PP 1305 & n.2786, 
1478; see Old Dominion Elec. Coop. v. FERC, 898 F.3d 1254, 1255 
(D.C. Cir. 2018) (``Under the [FPA], electric utilities must charge 
`just and reasonable' rates. For decades, the Commission and the 
courts have understood this requirement to incorporate a `cost-
causation principle'--the rates charged for electricity should 
reflect the costs of providing it.'' (internal citations omitted)); 
K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) 
(``FERC and the courts have added flesh to these bare statutory 
bones [i.e., the just and reasonable standard], establishing what 
has become known in Commission parlance as the 'cost-causation' 
principle.'').
---------------------------------------------------------------------------

    740. Additionally, as the Commission found in Order No. 1920, Long-
Term Regional Transmission Facilities are likely to provide a diverse 
array of benefits,\1867\ and Order No. 1920 specifically required that 
transmission providers consider seven economic and reliability 
benefits,\1868\ while not prohibiting them from also considering public 
policy benefits.\1869\ We conclude that Long-Term Regional Transmission 
Facilities will likely have benefits beyond addressing transmission 
needs driven by Public Policy Requirements and allowing transmission 
providers to allocate costs based solely on one type of benefit, such 
as reliability, economic, or public policy transmission project types, 
would likely underestimate the benefits provided by the project and, 
for that reason, be inconsistent with the goals underlying long-term, 
forward-looking, more comprehensive regional transmission planning 
required in Order No. 1920.\1870\
---------------------------------------------------------------------------

    \1867\ Order No. 1920, 187 FERC ] 61,068 at PP 123, 126, 722.
    \1868\ See id. PP 719-720.
    \1869\ Id. PP 737, 822; see also id. P 1515 & n.3220.
    \1870\ Id. P 1474.
---------------------------------------------------------------------------

    741. Nevertheless, we emphasize the fundamental principle that 
costs must be allocated in a manner that is at least roughly 
commensurate with estimated benefits, ensuring that ratepayers will not 
pay for facilities from which they do not benefit.\1871\ Regardless of 
the factors driving the need for that project, if a customer does not 
derive benefits from the project or if they derive only trivial 
benefits in relation to the project's costs, the customer cannot be 
forced to pay for the costs of the project without violating the cost 
causation principle.\1872\
---------------------------------------------------------------------------

    \1871\ Id. P 267.
    \1872\ ICC v. FERC I, 576 F.3d at 476-77; ICC v. FERC III, 756 
F.3d at 564-65; see Coal. of MISO Transmission Customers v. FERC, 45 
F.4th 1004, 1009 (D.C. Cir. 2022); LSP Transmission Holdings II, LLC 
v. FERC, 45 F.4th 979, 984 (D.C. Cir. 2022).
---------------------------------------------------------------------------

    742. Additionally, contrary to Dominion's argument,\1873\ the long-
term, forward-looking, more comprehensive nature of Long-Term Regional 
Transmission Planning distinguishes it from regional transmission 
planning under Order No. 1000. Order No. 1000 did not establish 
similarly long-term, forward-looking, or comprehensive regional 
transmission planning requirements. As a result, the Commission engaged 
in reasoned decision-making in relying on the different attributes of 
Long-Term Regional Transmission Planning when not adopting Order No. 
1000 regional cost allocation principle (6).
---------------------------------------------------------------------------

    \1873\ Dominion Rehearing Request at 30.
---------------------------------------------------------------------------

    743. As the Commission also found in Order No. 1920, the 
application of Order No. 1000 regional cost allocation principles (1) 
through (5) safeguards against cost causation concerns. Notably, the 
Commission explained:

    [P]rinciples (1) and (2) require that benefits received are at 
least roughly commensurate with costs paid and that costs may not be 
involuntarily allocated to those that do not benefit, respectively. 
Further, Order No. 1000 regional cost allocation principle (5), as 
well as the requirements in this final rule to disclose estimates of 
the benefits of selected Long-Term Regional Transmission Facilities, 
ensures sufficient transparency for stakeholders to understand how 
the costs of selected Long-Term Regional Transmission Facilities 
will be allocated to transmission customers in relation to the 
benefits that they are forecasted to provide.\1874\
---------------------------------------------------------------------------

    \1874\ Order No. 1920, 187 FERC ] 61,068 at P 1478.

    744. Therefore, even if a Long-Term Regional Transmission Facility 
helps to address a transmission need driven by a state or states' 
Public Policy Requirements, the costs of that transmission facility 
will only be allocated to ratepayers in states without those Public 
Policy Requirements in relation to the benefits they receive. We note 
that the benefits of a transmission facility go beyond any particular 
need that it may address.\1875\ As noted below, where Relevant State 
Entities agree, one potential cost allocation method that could be 
proposed to comply with Order No. 1920 would allocate costs 
commensurate with reliability and economic benefits region-wide, while 
allocating costs commensurate with additional benefits to a subset of 
states that agree to such cost allocation.\1876\
---------------------------------------------------------------------------

    \1875\ See ICC v. FERC I, 576 at 476 (``To the extent that a 
utility benefits from the costs of new facilities, it may be said to 
have `caused' a part of those costs to be incurred, as without the 
expectation of its contributions the facilities might not have been 
built, or might have been delayed.''). See also Order No. 1000, 136 
FERC ] 61,051 at P 690 (``If a regional transmission plan determines 
that a transmission facility serves several functions, as many 
commenters point out it may, the regional cost allocation method 
must take the benefits of these functions of the transmission 
facility into account in allocating costs roughly commensurate with 
benefits.'').
    \1876\ See infra Concerns Regarding Cost Causation section.
---------------------------------------------------------------------------

    745. For these reasons, we disagree with rehearing arguments that 
seem to suggest that, for any Long-Term Regional Transmission Cost 
Allocation Method to satisfy the cost causation principle or, in 
NRECA's case, not contradict Order No. 1000 principles (1) and 
(2),\1877\ transmission providers must disaggregate all disparate 
drivers of Long-Term Transmission Needs so that each identified Long-
Term Regional Transmission Facility may precisely be attributed to a 
particular policy goal or other driver of the transmission need. As we 
emphasize throughout this section, transmission providers and Relevant 
State Entities have broad flexibility to develop cost allocation 
approaches, provided such approaches comply with the cost causation 
principle and are otherwise just and reasonable. Consistent with that 
flexibility, as we clarify below, transmission providers and Relevant 
State Entities are not precluded from considering in their proposed 
cost

[[Page 97314]]

allocation methods the incremental cost of transmission needed to 
achieve state laws, policies, and regulations beyond the cost of 
transmission needed in the absence of those laws, policies, and 
regulations. Nevertheless, we find that requiring transmission 
providers to conduct Long-Term Regional Transmission Planning in the 
manner suggested by NRECA might risk undermining the scaling of Long-
Term Regional Transmission Facilities to provide a more efficient or 
cost-effective solution to multiple transmission needs by encouraging 
piecemeal transmission expansion (e.g., two separate transmission 
facilities to address two separate transmission needs may be more 
expensive than one facility meeting both needs) that caused the need 
for reform in the first place.\1878\ In addition, that exercise would 
likely stymie transmission providers' selection of more efficient or 
cost-effective transmission solutions by leading them to ignore or 
otherwise discount the diverse range of benefits that Long-Term 
Regional Transmission Facilities can provide, likely leading them to 
underestimate the benefits that the facilities provide to customers.
---------------------------------------------------------------------------

    \1877\ NRECA Rehearing Request at 53-55.
    \1878\ Order No. 1920, 187 FERC ] 61,068 at PP 85, 112.
---------------------------------------------------------------------------

    746. Moreover, we reiterate that Long-Term Regional Transmission 
Cost Allocation Methods to which Relevant State Entities have not 
agreed must satisfy Order No. 1000 regional cost allocation principles 
(1) through (5), such that transmission customers will only pay for 
Long-Term Regional Transmission Facilities (or portfolios of such 
Facilities) when the transmission provider has determined that they 
meet the transmission providers' selection criteria and transmission 
customers will only be allocated costs that are at least roughly 
commensurate with the estimated benefits they receive. As Order No. 
1920 noted:

    [U]nder this final rule, customers pay for a more reliable and 
economic transmission system as identified through open and 
transparent Long-Term Regional Transmission Planning, and any 
state's ratepayers only fund the construction of Long-Term Regional 
Transmission Facilities that provide them with such benefits that 
are at least roughly commensurate with the costs of those 
facilities.\1879\
---------------------------------------------------------------------------

    \1879\ Id. P 270.

    747. Consequently, and contrary to certain parties' 
arguments,\1880\ these requirements will protect customers from unjust, 
unreasonable, and unduly discriminatory or preferential transmission 
rates.
---------------------------------------------------------------------------

    \1880\ See e.g., East Kentucky Rehearing Request at 3.
---------------------------------------------------------------------------

    748. Regarding NRECA's arguments that the cost allocation 
requirements of Order No. 1920 violate Order No. 1000 regional cost 
allocation principle (4),\1881\ we disagree. NRECA's arguments are 
based on an incorrect interpretation of Order No. 1000 regional cost 
allocation principle (4), which states that ``[t]he allocation method 
for the cost of a transmission facility selected in a regional 
transmission plan must allocate costs solely within that transmission 
planning region unless another entity outside the region or another 
transmission planning region voluntarily agrees to assume a portion of 
those costs.'' \1882\ Order No. 1000 regional cost allocation principle 
(4) concerns transmission planning regions, not individual states as 
contemplated by NRECA's arguments, and it does not prohibit allocation 
of costs among customers in states within a single transmission 
planning region.
---------------------------------------------------------------------------

    \1881\ NRECA Rehearing Request at 55.
    \1882\ Order No. 1000, 136 FERC ] 61,051 at P 657 (emphasis 
added).
---------------------------------------------------------------------------

    749. We disagree with rehearing parties who argue that the lack of 
a requirement to apply regional cost allocation principle (6), with its 
prohibition against adopting different Long-Term Regional Transmission 
Cost Allocation Methods for reliability, economic, and public policy 
transmission project types, creates a one-size-fits-all approach,\1883\ 
inappropriately treats all Long-Term Regional Transmission Facilities 
as equal for cost allocation purposes,\1884\ or otherwise conflicts 
with the Commission's ``light touch'' in Order No. 1000.\1885\ In 
particular, NRECA is incorrect that the prohibition against adopting 
different Long-Term Regional Transmission Cost Allocation Methods for 
reliability, economic, and public policy transmission project types 
means that ``transmission providers must similarly use a single cost 
allocation method.'' \1886\ Rehearing parties' arguments focus on the 
prohibition against economic, reliability, and public policy types, but 
do not recognize the broad flexibility otherwise afforded under Order 
No. 1920's application of Order No. 1000 regional cost allocation 
principles (1)-(5) and allowance of multiple cost allocation methods 
for Long-Term Regional Transmission Facilities.\1887\ Under Order No. 
1920, transmission providers may craft different ex ante cost 
allocation methods to reflect the different proportion of benefits 
provided by Long-Term Regional Facilities with different underlying 
drivers.\1888\ Thus, we clarify that Order No. 1920's prohibition 
against types is a prohibition against the allocation of costs based on 
a single category of benefits--whether reliability, economic, public 
policy, or another category of benefits. In other words, transmission 
providers could not allocate all costs of Long-Term Regional 
Transmission Facilities on the basis of public policy benefits, if 
doing so ignores economic and reliability benefits associated with 
those facilities. Allocating the costs of Long-Term Regional 
Transmission Facilities entirely on a single category of benefits would 
likely ignore the diverse range of benefits those Facilities likely 
provide, as described above, and in doing so violate the cost causation 
principle.
---------------------------------------------------------------------------

    \1883\ See Arizona Commission Rehearing Request at 18-19; Ohio 
Commission Federal Advocate Rehearing Request at 14.
    \1884\ See Dominion Rehearing Request at 29-31.
    \1885\ See Idaho Commission Rehearing Request at 3; NRECA 
Rehearing Request at 52-53.
    \1886\ NRECA Rehearing Request at 53.
    \1887\ Order No. 1920, 187 FERC ] 61,068 at P 1475 (``We clarify 
that this final rule does not preclude the adoption of multiple 
Long-Term Regional Transmission Cost Allocation Methods, provided 
that the Long-Term Regional Transmission Cost Allocation Method that 
will apply to a Long-Term Regional Transmission Facility (or 
portfolio of such Facilities) is known before selection, i.e., is an 
ex ante cost allocation method, and does not allocate costs by 
project type.'').
    \1888\ Infra Concerns Regarding Cost Causation section.
---------------------------------------------------------------------------

    750. We reiterate the fact that Order No. 1920 provides flexibility 
previously unafforded in regional transmission planning both in the new 
types of compliant cost allocation methods (i.e., Long-Term Regional 
Transmission Cost Allocation Methods agreed to by Relevant State 
Entities during the Engagement Period and cost allocation methods 
resulting from a State Agreement Process) and in the lack of 
restrictions placed on these new state-agreed-to methods (i.e., the 
only requirement for such methods is compliance with the cost causation 
principle). We believe the possibilities afforded by state agreement 
under Order No. 1920 may address the concerns underlying rehearing 
parties' arguments.
    751. Further, we grant Indicated PJM TOs' request for clarification 
that Order No. 1920 does not preclude transmission providers from 
adopting Long-Term Regional Transmission Cost Allocation Methods that 
allocate costs based on the different benefits associated with a 
particular Long-Term Regional Transmission Facility (or portfolio of 
Facilities).\1889\ Transmission

[[Page 97315]]

providers may propose ex ante Long-Term Regional Transmission Cost 
Allocation Methods that, for example, assign a portion of the costs of 
a Long-Term Regional Transmission Facility that are associated with 
reliability benefits to one set of beneficiaries, a portion of the 
costs associated with economic benefits to another set of 
beneficiaries, and a portion of costs associated with public policy 
benefits to a different set of beneficiaries. Such a method would not 
violate the Commission's decision to not apply regional cost allocation 
principle (6) because the Long-Term Regional Transmission Cost 
Allocation Method would not create a cost allocation method that is 
specific to, for example, a transmission facility that satisfies a 
transmission need driven by economic benefits. As such, elimination of 
Order No. 1000 regional cost allocation principle (6) does not yield as 
inflexible an outcome as rehearing partis assert.
---------------------------------------------------------------------------

    \1889\ Indicated PJM TOs Rehearing Request at 2-3, 4-6.
---------------------------------------------------------------------------

    752. In response to Virginia and North Carolina Commissions' 
request that the Commission clarify that Order No. 1920 does not 
preclude cost allocation methods that allocate costs based on the 
incremental costs associated with the inclusion of one or more public 
policy factors,\1890\ we clarify that Order No. 1920's cost allocation 
requirements allow for, but do not require, transmission providers to 
account for the benefits associated with addressing transmission needs 
driven by Public Policy Requirements in any ex ante cost allocation 
method.\1891\
---------------------------------------------------------------------------

    \1890\ Virginia and North Carolina Commissions Rehearing Request 
at 5-6.
    \1891\ See infra Concerns Regarding Cost Causation section.
---------------------------------------------------------------------------

3. Concerns Regarding Cost Causation
a. Order No 1920 Requirements
    753. In Order No. 1920, the Commission required Long-Term Regional 
Transmission Cost Allocation Methods not agreed to by Relevant State 
Entities to comply with Order No. 1000 regional cost allocation 
principles (1) through (5). The Commission found that Order No. 1000 
regional cost allocation principles (1) through (5) remain relevant for 
ex ante cost allocation methods for Long-Term Regional Transmission 
Facilities that transmission providers propose on compliance but for 
which Relevant State Entities have not indicated their agreement.\1892\
---------------------------------------------------------------------------

    \1892\ Order No. 1920, 187 FERC ] 61,068 at PP 1469, 1472-1473.
---------------------------------------------------------------------------

    754. In Order No. 1920, the Commission did not require transmission 
providers to demonstrate that Long-Term Regional Transmission Cost 
Allocation Methods that Relevant State Entities indicate they have 
agreed to or cost allocation methods resulting from a State Agreement 
Process comply with any of the Order No. 1000 regional cost allocation 
principles.\1893\ The Commission chose not to adopt the NOPR proposal 
to require adherence to the six Order No. 1000 regional cost allocation 
principles in these circumstances because cost allocation methods 
resulting from a State Agreement Process and Long-Term Regional 
Transmission Cost Allocation Methods that Relevant State Entities 
indicate that they have agreed to are likely to facilitate agreement 
over development of such Long-Term Regional Transmission Facilities by, 
for example, making the Relevant State Entities more confident that 
customers in the state are receiving benefits at least roughly 
commensurate with their share of the cost of such facilities and by 
reducing the likelihood that selected Long-Term Regional Transmission 
Facilities cannot be constructed because they do not receive necessary 
state regulatory approvals.\1894\ The Commission further reasoned that 
affording additional flexibility for these methods by not requiring the 
application of the six Order No. 1000 regional cost allocation 
principles may encourage their use, and consequently facilitate the 
selection of more efficient or cost-effective Long-Term Regional 
Transmission Facilities.\1895\ The Commission noted, however, that such 
methods must still be just and reasonable and not unduly discriminatory 
or preferential, and must allocate costs in a manner that is at least 
roughly commensurate with estimated benefits.\1896\ The Commission 
further explained that this decision was consistent with past 
precedent, noting that the Commission has previously found that ``Order 
No. 1000 allows market participants, including states, to negotiate 
voluntarily alternative cost sharing arrangements that are distinct 
from the relevant regional cost allocation method(s).'' \1897\ 
Additionally, the Commission noted that where transmission providers 
have proposed cost allocation methods corresponding to such voluntary 
arrangements, the Commission has held that it need not find that those 
cost allocation methods comply with Order No. 1000.\1898\ Consistent 
with this precedent, the Commission found that cost allocation methods 
resulting from a State Agreement Process and Long-Term Regional 
Transmission Cost Allocation Methods that Relevant State Entities 
indicate they have agreed to and have asked transmission providers to 
file also qualify as voluntary alternative cost sharing arrangements 
and, accordingly, the Commission declined to require those methods to 
adhere to the six Order No. 1000 regional cost allocation 
principles.\1899\ However, the Commission did require that any 
voluntary alternative cost sharing arrangements still comply with the 
cost causation principle and any other legal requirements for cost 
allocation.\1900\
---------------------------------------------------------------------------

    \1893\ Id. PP 1470, 1476.
    \1894\ Id. P 1477.
    \1895\ Id.
    \1896\ Id. (citation omitted).
    \1897\ Id. P 1476 (quoting State Voluntary Agreements to Plan & 
Pay for Transmission Facilities, 175 FERC ] 61,225 at P 3).
    \1898\ Id. (citing PJM Interconnection, L.L.C., 142 FERC ] 
61,214 at PP 142-143, order on reh'g and compliance, 147 FERC ] 
61,128 at P 92; ISO New England Inc., 143 FERC ] 61,150 at P 121; 
Consol. Edison Co. of N.Y., Inc., 180 FERC ] 61,106 at PP 48-50).
    \1899\ Id.
    \1900\ Id.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    755. NRECA argues that Order No. 1920 does not provide a reasonable 
explanation for its decision not to require a Long-Term Regional 
Transmission Cost Allocation Method to comply with any of the Order No. 
1000 regional cost allocation principles when Relevant State Entities 
indicate their agreement with such a method as part of the Engagement 
Period.\1901\ NRECA further argues that Order No. 1920 similarly does 
not provide a reasonable explanation as to why the Commission did not 
require a cost allocation method resulting from a State Agreement 
Process to comply with the Order No. 1000 regional cost allocation 
principles.\1902\ NRECA contends that neither Order No. 1920's reliance 
on a 2021 Commission policy statement nor Order No. 1000 allows the 
Commission to waive the Order No. 1000 regional cost allocation 
principles as NRECA alleges the Commission does in the final 
rule.\1903\ NRECA asserts that Order No. 1920's reference to prior 
instances where the Commission has approved voluntary agreements on a 
case-by-case basis without finding that their cost allocation methods 
comply with Order No. 1000 does not constitute precedent for a 
categorical waiver of Order No. 1000's requirements for future cost

[[Page 97316]]

allocations methods reached under the State Agreement Process.\1904\
---------------------------------------------------------------------------

    \1901\ NRECA Rehearing Request at 55.
    \1902\ Id. at 55-56.
    \1903\ Id. at 56 (citing Order No. 1920, 187 FERC ] 61,068 at P 
1476; State Voluntary Agreements to Plan and Pay for Transmission 
Facilities, 175 FERC ] 61,225).
    \1904\ Id. at 56-57 (citing Order No. 1920, 187 FERC ] 61,068 at 
P 1476 n.3150).
---------------------------------------------------------------------------

    756. NRECA argues that Order No. 1920 adopts cost allocation 
requirements that are more prescriptive in some respects (e.g., 
prohibiting transmission providers from using different cost allocation 
methods for different project types) but less prescriptive in other 
respects (e.g., not requiring compliance with any Order No. 1000 
regional cost allocation principles when states agree on a cost 
allocation method). NRECA contends that this results in opaque, lax, 
and inconsistent standards for cost allocation for Long-Term Regional 
Transmission Facilities. NRECA asserts that, as a result, the 
Commission will be unable to enforce the FPA's requirements against 
unjust, unreasonable, or unduly discriminatory or preferential 
rates.\1905\
---------------------------------------------------------------------------

    \1905\ Id. at 52.
---------------------------------------------------------------------------

    757. Arizona Commission argues that Order No. 1920 usurps Arizona's 
constitutional requirements that the Arizona Commission must apply 
rates that are fair and reasonable and that it must not recover costs 
from ratepayers that do not cause, or benefit from, a particular 
cost.\1906\ Arizona Commission further argues that the cost allocation 
methods adopted in the final rule are contrary to existing ratemaking 
principles, which include providing customers with reliable power at 
the least cost and allocating costs to the entities that cause 
them.\1907\ Ohio Consumers similarly claim that Order No. 1920 is 
arbitrary and capricious and violates policy and precedent that 
requires that costs be allocated consistent with those who receive 
benefits.\1908\
---------------------------------------------------------------------------

    \1906\ Arizona Commission Rehearing Request at 20-21.
    \1907\ Id. at 20.
    \1908\ Ohio Consumers Rehearing Request at 9.
---------------------------------------------------------------------------

    758. Virginia and North Carolina Commissions assert that the 
Commission must ensure public policies considered in planning criteria 
and scenarios are also appropriately accounted for in any ex ante cost 
allocation method to avoid cross-subsidization of state public policy 
goals. Virginia and North Carolina Commissions state that the 
Commission should clarify on rehearing that to comport with the 
Commission's cost-causation principles, any proposed ex ante cost 
allocation method must adequately account for not only the benefits 
resulting from an identified transmission project, but also the cost 
drivers (or cost causers) that contribute to the need for the 
transmission project. Alternatively, Virginia and North Carolina 
Commissions argue that the Commission should expressly require the same 
public policy factors included in the Long-Term Scenarios to be 
considered as potential benefits for cost allocation purposes.\1909\
---------------------------------------------------------------------------

    \1909\ Virginia and North Carolina Commissions Rehearing Request 
at 3-4.
---------------------------------------------------------------------------

    759. West Virginia Commission and Wyoming Commission argue that 
Order No. 1920's transmission planning and cost allocation requirements 
force transmission providers within their states to plan projects based 
on decarbonization goals of other states in the region.\1910\ West 
Virginia Commission and Wyoming Commission further argue that this 
would require transmission providers in the state to account for 
abstract assumed benefits for its retail customers.\1911\ West Virginia 
Commission and Wyoming Commission contend that, in the event that the 
costs allocated to retail customers exceed benefits that their 
respective state policies realize from regional transmission projects, 
they will be forced to assign unjust and unreasonable costs to retail 
customers or deny a utility a potentially significant portion of its 
expected cost recovery.\1912\ Wyoming Commission argues that this 
result is contrary to core principles of utility regulation and 
wrongfully empowers states to exact the costs of their policy 
initiatives from ratepayers in other states.\1913\
---------------------------------------------------------------------------

    \1910\ West Virginia Commission Rehearing Request at 10; Wyoming 
Commission Rehearing Request at 7.
    \1911\ West Virginia Commission Rehearing Request at 10; Wyoming 
Commission Rehearing Request at 7.
    \1912\ West Virginia Commission Rehearing Request at 10; Wyoming 
Commission Rehearing Request at 7-8.
    \1913\ Wyoming Commission Rehearing Request at 8.
---------------------------------------------------------------------------

c. Commission Determination
    760. We disagree with NRECA's arguments that the Commission did not 
provide a reasonable explanation for its decision not to require cost 
allocation methods resulting from a State Agreement Process or Long-
Term Regional Transmission Cost Allocation Methods that Relevant State 
Entities indicate that they have agreed to and have asked transmission 
providers to file to comply with any of the Order No. 1000 regional 
cost allocation principles.\1914\ We continue to find that cost 
allocation methods resulting from a State Agreement Process and Long-
Term Regional Transmission Cost Allocation Methods that Relevant State 
Entities indicate that they have agreed to are likely to facilitate 
agreement concerning development of such Long-Term Regional 
Transmission Facilities by, for example, making the Relevant State 
Entities more confident that customers in the state are receiving 
benefits at least roughly commensurate with their share of the costs of 
such facilities and by reducing the likelihood that selected Long-Term 
Regional Transmission Facilities cannot be constructed because they do 
not receive necessary state regulatory approvals.\1915\ Further, we 
continue to find that affording additional flexibility for these 
methods may encourage their use, which would facilitate the selection 
of more efficient or cost-effective Long-Term Regional Transmission 
Facilities.\1916\ In short, we find that the benefits of providing 
additional flexibility for state-agreed-upon cost allocation methods 
for Long-Term Regional Transmission Facilities outweigh NRECA's 
concerns regarding not applying the Order No. 1000 regional cost 
allocation principles, such that it represents a just and reasonable 
approach to these issues.
---------------------------------------------------------------------------

    \1914\ NRECA Rehearing Request at 55-56.
    \1915\ Order No. 1920, 187 FERC ] 61,068 at P 1477.
    \1916\ Id. (citation omitted).
---------------------------------------------------------------------------

    761. Additionally, we highlight that the cost causation principle 
and Commission precedent require the Commission to evaluate each 
proposed cost allocation method to determine whether it will allocate 
costs in a manner that is at least roughly commensurate with estimated 
benefits and whether the proposed method is just and reasonable and not 
unduly discriminatory or preferential, as stated in Order No. 
1920.\1917\ This is the case whether or not we specifically require 
these cost allocation methods to comply with the Order No. 1000 
regional cost allocation principles.
---------------------------------------------------------------------------

    \1917\ See, e.g., id. P 1506 (citing ICC v. FERC I, 576 F.3d at 
477; ICC v. FERC III, 756 F.3d at 564).
---------------------------------------------------------------------------

    762. For cost allocation methods resulting from a State Agreement 
Process or Long-Term Regional Transmission Cost Allocation Methods that 
Relevant State Entities indicate that they have agreed to and have 
asked transmission providers to file, we continue to find that such 
methods qualify as voluntary alternative cost sharing arrangements, 
consistent with the Commission's previous findings that ``Order No. 
1000 allows market participants, including states, to negotiate 
voluntarily alternative cost sharing arrangements that are distinct 
from the relevant regional cost allocation method(s)'' \1918\ and that 
the

[[Page 97317]]

Commission need not find that cost allocation methods corresponding to 
such voluntary agreements comply with Order No. 1000.\1919\ Therefore, 
in response to NRECA, we continue to decline to require such cost 
allocation methods to adhere to the six Order No. 1000 regional cost 
allocation principles.\1920\
---------------------------------------------------------------------------

    \1918\ Id. P 1476 (quoting State Voluntary Agreements to Plan & 
Pay for Transmission Facilities, 175 FERC ] 61,225 at P 3).
    \1919\ Id. (citing See PJM Interconnection, L.L.C., 142 FERC ] 
61,214 at PP 142-143, order on reh'g and compliance, 147 FERC ] 
61,128 at P 92; ISO New England Inc., 143 FERC ] 61,150 at P 121; 
Consol. Edison Co. of N.Y., Inc., 180 FERC ] 61,106 at PP 48-50).
    \1920\ Id.
---------------------------------------------------------------------------

    763. We further disagree with NRECA's arguments that the cost 
allocation requirements adopted in Order No. 1920 will result in 
inconsistent standards for cost allocation for Long-Term Regional 
Transmission Facilities and will result in the Commission's inability 
to enforce the FPA's requirements against unjust, unreasonable, and 
unduly discriminatory or preferential rates.\1921\ We recognize that 
there are different requirements for cost allocation methods resulting 
from a State Agreement Process or Long-Term Regional Transmission Cost 
Allocation Methods that Relevant State Entities indicate that they have 
agreed to and have asked transmission providers to file as compared to 
Long-Term Regional Transmission Cost Allocation Methods to which states 
do not agree, but we find that the potential for differences is 
appropriate to give states flexibility.\1922\ Regardless, we reiterate 
that all cost allocation methods must comply with the cost causation 
principle, as required by the FPA.\1923\ Additionally, we note that 
nothing in FPA section 206 requires that transmission providers adopt 
the same or similar proposals on compliance provided that they comply 
with Order No. 1920.
---------------------------------------------------------------------------

    \1921\ NRECA Rehearing Request at 52.
    \1922\ See Order No. 1920, 187 FERC ] 61,068 at P 1477.
    \1923\ Id. P 1305 & n.2786.
---------------------------------------------------------------------------

    764. We also disagree with arguments raised by Arizona Commission 
and Ohio Consumers on rehearing that Order No. 1920's transmission 
planning and cost allocation requirements are inconsistent with cost 
causation principles.\1924\ All cost allocation methods for Long-Term 
Regional Transmission Facilities, including Long-Term Regional 
Transmission Cost Allocation Methods, regardless of whether they are 
agreed to by Relevant State Entities, and cost allocation methods 
resulting from Commission-approved State Agreement Processes, must 
comply with the cost causation principle and ensure that the costs of 
transmission facilities are allocated in a manner at least roughly 
commensurate with estimated benefits.\1925\
---------------------------------------------------------------------------

    \1924\ Arizona Commission Rehearing Request at 20; Ohio 
Consumers Rehearing Request at 9.
    \1925\ Order No. 1920, 187 FERC ] 61,068 at PP 1305 & n.2786, 
1506 (citing ICC v. FERC I, 576 F.3d at 477; ICC v. FERC III, 756 
F.3d at 564).
---------------------------------------------------------------------------

    765. In light of our clarification noted below, we find it 
unnecessary, as requested by Virginia and North Carolina 
Commissions,\1926\ to require transmission providers to demonstrate on 
compliance how both the benefits resulting from an identified 
transmission project and the cost drivers contributing to the need for 
that project are appropriately accounted for in their proposed Long-
Term Regional Transmission Cost Allocation Method, or alternatively to 
require that the same public policy factors included in Long-Term 
Scenarios be considered as potential benefits for the purposes of cost 
allocation. Specifically, we note that our clarification regarding the 
recognition of benefits below in response to West Virginia Commission 
and Wyoming Commission's request may address Virginia and North 
Carolina Commissions' concerns regarding the consideration of public 
policy factors in cost allocation methods. Further, we find that 
requiring transmission providers to show that the relevant cost 
allocation methods comply with cost causation by ensuring that costs 
are allocated in a manner roughly commensurate with benefits will 
provide flexibility and account for regional diversity while also 
ensuring that those cost allocation methods comply with the 
requirements of the FPA.\1927\
---------------------------------------------------------------------------

    \1926\ Virginia and North Carolina Commissions Rehearing Request 
at 3-4.
    \1927\ See Order No. 1920, 187 FERC ] 61,068 at 1510.
---------------------------------------------------------------------------

    766. We disagree with arguments raised on rehearing by West 
Virginia Commission and Wyoming Commission that Order No. 1920's 
transmission planning and cost allocation requirements force 
transmission providers within their states to plan transmission 
projects based on decarbonization goals of other states in the 
transmission planning region and require transmission providers to 
account for abstract assumed benefits.\1928\ First, as discussed above, 
because of the flexibility provided by the Commission regarding cost 
allocation, it is premature and speculative to assert that a 
requirement not to use cost allocation methods based on project type 
will result in adoption of cost allocation methods that violate cost 
causation principles. We also reiterate that, in the context of 
transmission facilities, the cost causation principle requires the 
Commission to ensure that any cost allocation method allocates costs in 
a manner roughly commensurate with estimated benefits, meaning that if 
consumers do not benefit from a project they will not be required to 
pay for it nor will they be required to bear a share of project costs 
that does not reflect their share of the project's benefits.\1929\
---------------------------------------------------------------------------

    \1928\ West Virginia Commission Rehearing Request at 10; Wyoming 
Commission Rehearing Request at 7.
    \1929\ See Order No. 1920, 187 FERC ] 61,068 at P 1305 & n.2786 
(``The cost causation principle requires costs to be allocated to 
those who cause the costs to be incurred and reap the resulting 
benefits.'') (citation omitted)); ICC v. FERC I, 576 F.3d at 476 
(``To the extent that a utility benefits from the costs of new 
facilities, it may be said to have `caused' a part of those costs to 
be incurred, as without the expectation of its contributions the 
facilities might not have been built, or might have been 
delayed.''); see also Order No. 1000, 136 FERC ] 61,051 at P 690 
(``If a regional transmission plan determines that a transmission 
facility serves several functions, as many commenters point out it 
may, the regional cost allocation method must take the benefits of 
these functions of the transmission facility into account in 
allocating costs roughly commensurate with benefits.'').
---------------------------------------------------------------------------

    767. Further, we clarify that Order No. 1920 does not prevent 
transmission providers from recognizing different types of benefits and 
using them to allocate costs in proportion to those benefits. As an 
example, one potential cost allocation method that could be proposed to 
comply with Order No. 1920 would allocate costs commensurate with 
reliability and economic benefits region-wide, while allocating costs 
commensurate with additional benefits to a subset of states that agree 
to such cost allocation. Under this potential cost allocation method, 
these costs and benefits could be identified based on one or more 
additional analyses, such as additional scenarios, run by the 
transmission providers for the purposes of informing cost allocation, 
e.g., scenarios that consider the incremental cost of transmission 
needed to achieve state laws, policies, and regulations beyond the cost 
of transmission needed in the absence of those laws, policies, and 
regulations. For example, the cost allocation method agreed to by the 
Relevant State Entities may allocate those incremental costs to states 
with those applicable laws, policies, and regulations.
    768. Noting this clarification, and where Long-Term Regional 
Transmission Cost Allocation Methods that Relevant State Entities agree 
to are concerned, at the request of the Relevant State Entities in a 
multistate region, the

[[Page 97318]]

following ex ante method for cost allocation may be proposed. In 
providing this example, we are not foreclosing other approaches for 
allocating the costs of Long-Term Regional Transmission Facilities on 
either an ex ante basis or through a State Agreement Process. Nor are 
we suggesting that cost allocation methods must adopt a similar 
approach to this framework in order to comply with the requirements of 
Order No. 1920. This example is as follows:
    (1) For the purposes of cost allocation, transmission providers 
shall run an additional scenario analysis to identify transmission 
needs using the same Long-Term Scenarios and sensitivities used in its 
Long-Term Regional Transmission Planning process, except that the 
inputs to such additional scenarios shall not include state laws, 
policies and regulations. Transmission providers shall identify 
transmission facilities to meet the needs identified in such additional 
scenario analysis and those facilities' costs. Transmission providers 
shall then determine the difference in costs between the set of Long-
Term Regional Transmission Facilities selected in the regional 
transmission plan for purposes of cost allocation and the set of 
transmission facilities that would be selected based upon the 
additional scenario analysis.
    (2) The portion of total selected Long-Term Regional Transmission 
Facility costs identified in (1) could be cost allocated according to 
an existing Commission-accepted cost allocation method that may be 
proposed on compliance with Order No. 1920.
    (3) The amount representing the cost difference between the costs 
of projects selected pursuant to the Long-Term Regional Transmission 
Planning process and (1) shall be allocated as follows:

    a. The transmission providers shall identify by state the 
specific state laws, policies, and regulations that were used to 
plan and select the Long-Term Regional Transmission Facilities and 
shall quantify by state the specific costs of such Facilities.
    b. The costs identified in 3(a) shall be allocated solely to the 
state or states that are the sources of the policies used in 
planning and selection. The total difference between the costs of 
Long-Term Regional Transmission Facilities selected pursuant to the 
Long-Term Regional Transmission Planning process and (1) would be 
fully accounted for using this method of allocating costs among the 
states. For RTOs/ISOs, the cost allocation to transmission customers 
in a transmission pricing zone within a state would be developed by 
the applicable Transmission Owner(s). For non-RTOs/ISOs, the costs 
allocated to transmission customers in a transmission provider's 
retail distribution service territory or footprint within a state 
would be developed by the applicable transmission provider.

G. General Benefits Requirements Related to Cost Allocation

1. Logical Outgrowth
a. NOPR Proposals
    769. In the NOPR, the Commission proposed for consideration a list 
of Long-Term Regional Transmission Benefits for transmission providers 
to apply in Long-Term Regional Transmission Planning and cost 
allocation processes.\1930\ Additionally, the Commission proposed to 
require that transmission providers identify on compliance the benefits 
they will use in any ex ante cost allocation method, how they will 
calculate those benefits, and how the benefits will reasonably reflect 
the benefits of regional transmission facilities to meet identified 
transmission needs driven by changes in the resource mix and 
demand.\1931\ The NOPR also proposed to require transmission providers 
to explain the rationale for using the benefits identified.\1932\ 
Additionally, the Commission requested comment on the proposed 
requirements, whether the Commission should require that transmission 
providers account for the full list of benefits contained in the NOPR's 
Evaluation of the Benefits of Regional Transmission Facilities section, 
or whether no change to the benefits used in existing regional 
transmission processes was needed.\1933\
---------------------------------------------------------------------------

    \1930\ NOPR, 179 FERC ] 61,028 at PP 185, 326.
    \1931\ Id. P 326.
    \1932\ Id.
    \1933\ Id. P 327.
---------------------------------------------------------------------------

b. Order No. 1920 Requirements
    770. In Order No. 1920, the Commission declined to adopt the NOPR 
proposal regarding the use of benefits in Long-Term Regional 
Transmission Cost Allocation Methods.\1934\ Instead, as discussed above 
in the Regional Cost Allocation Principles for Long-Term Regional 
Transmission Facilities section, the Commission required transmission 
providers in each transmission planning region to demonstrate that any 
Long-Term Regional Transmission Cost Allocation Method(s) that Relevant 
State Entities have not indicated that they agree to complies with 
Order No. 1000 regional cost allocation principles (1) through (5). The 
Commission did not require transmission providers to demonstrate that 
Long-Term Regional Transmission Cost Allocation Methods that Relevant 
State Entities indicate they have agreed to or cost allocation methods 
resulting from a State Agreement Process comply with any of the Order 
No. 1000 regional cost allocation principles, but the Commission noted 
that such methods must still be just and reasonable and not unduly 
discriminatory or preferential, and must allocate costs in a manner 
that is at least roughly commensurate with estimated benefits.\1935\ 
The Commission did not require that any particular benefit used in the 
evaluation and selection of Long-Term Regional Transmission Facilities 
be reflected in a Long-Term Regional Transmission Cost Allocation 
Method filed with the Commission.\1936\
---------------------------------------------------------------------------

    \1934\ Order No. 1920, 187 FERC ] 61,068 at P 1505.
    \1935\ Id. PP 1470, 1476-1477.
    \1936\ Id. P 1506.
---------------------------------------------------------------------------

    771. The Commission explained that the modified approach to the 
relationship of benefits used in Long-Term Regional Transmission 
Planning and Long-Term Regional Transmission Cost Allocation Methods 
provides transmission providers with flexibility to propose a Long-Term 
Regional Transmission Cost Allocation Method(s), allowing for 
negotiation in the Engagement Period, which the Commission believed 
will increase the likelihood that Long-Term Regional Transmission 
Facilities selected as the more efficient or cost-effective regional 
transmission solution will be developed. The Commission additionally 
explained that the requirements in Order No. 1920 to disclose estimates 
of the benefits of selected Long-Term Regional Transmission Facilities 
will provide transparency and help to ensure cost allocation is just 
and reasonable.\1937\ Additionally, the Commission reasoned that this 
flexible approach is consistent with the approach the Commission took 
in Order No. 1000 and in subsequent orders on transmission providers' 
Order No. 1000 compliance filings, where the Commission allowed a wide 
variety of cost allocation methods and did not require that such 
methods specifically account for all benefits used in evaluation and 
selection processes.\1938\
---------------------------------------------------------------------------

    \1937\ Id.
    \1938\ Id. P 1507 (citing Order No. 1000, 136 FERC ] 61,051 at 
PP 560, 624).
---------------------------------------------------------------------------

c. Requests for Rehearing and Clarification
    772. NRECA contends that Order No. 1920's determination not to 
require transmission providers to disclose which benefits, if any, they 
use in their regional cost allocation proposals is not a logical 
outgrowth of the NOPR.\1939\ NRECA argues that the requirement to use a 
stated set of benefits in evaluating

[[Page 97319]]

and selecting Long-Term Regional Transmission Facilities, without 
requiring transmission providers to disclose which benefits were used 
in their regional cost allocation proposals, allows cost allocation to 
be ``completely opaque and divorced from the measured benefits.'' 
\1940\
---------------------------------------------------------------------------

    \1939\ NRECA Rehearing Request at 12-13.
    \1940\ Id.
---------------------------------------------------------------------------

d. Commission Determination
    773. In response to NRECA's argument that the Commission violated 
the APA's notice-and-comment requirements by declining to adopt the 
NOPR proposal to require transmission providers to disclose the 
benefits used in Long-Term Regional Transmission Cost Allocation 
Methods, we note that certain clarifications adopted herein may 
alleviate the concerns underlying NRECA's argument. Specifically, as 
discussed in the Minimum Requirements section above, we clarify in this 
order that, once transmission providers make a selection decision, 
i.e., for each selected Long-Term Regional Transmission Facility (or 
portfolio of such Facilities) and the applicable cost allocation method 
is determined, transmission providers must make available, on a 
password-protected portion of OASIS or other password-protected 
website, a breakdown of how those estimated costs will be allocated, by 
zone (i.e., by transmission provider retail distribution service 
territory/footprint or RTO/ISO transmission pricing zone), and a 
quantification of the estimated benefits as imputed to each zone, as 
such benefits can be reasonably estimated, when a cost allocation 
method is agreed upon under a State Agreement Process or, if no State 
Agreement Process is used, at the time of project selection.
    774. Noting this clarification, we nevertheless disagree with NRECA 
that the Commission violated the APA's notice-and-comment requirements. 
Agency final rules need not be identical to proposed rules, and notice 
is sufficient if the final rule represents a ``logical outgrowth'' of 
the proposed rule.\1941\ Here, the NOPR proposed to require 
transmission providers to disclose the benefits used in Long-Term 
Regional Transmission Cost Allocation Methods after noting the 
Commission's concern that, among other things, the Commission's 
existing regional transmission planning and cost allocation 
requirements may result in transmission providers undervaluing the 
benefits of Long-Term Regional Transmission Facilities for purposes of 
allocating the costs of such facilities to beneficiaries in a manner 
that is roughly commensurate with estimated benefits.\1942\ While Order 
No. 1920 did not adopt the NOPR proposal, it included safeguards that 
will ensure an adequate accounting for benefits in cost allocation 
methods for Long-Term Regional Transmission Facilities, in addition to 
the new safeguard we adopt in this order, noted above. For instance, 
Order No. 1920 noted that any cost allocation method for Long-Term 
Regional Transmission Facilities will be required to comply with cost 
allocation precedent, including that costs be allocated in a manner at 
least roughly commensurate with estimated benefits.\1943\ That standard 
requires that transmission providers show, on compliance, that their 
proposed cost allocation methods match the allocation of costs 
associated with the project in a manner that is at least roughly 
commensurate with the estimated benefits of the project. We find that 
this approach is sufficiently similar, in practice, to the proposal in 
the NOPR that it can be said to ``follow logically from'' the NOPR, 
that the NOPR ``adequately frame[d] the subjects for discussion,'' 
\1944\ and that ``a reasonable member of the regulated class'' could 
``anticipate the general aspects of the [final] rule.'' \1945\
---------------------------------------------------------------------------

    \1941\ Long Island Care, 551 U.S. at 174-75. See also Am. Paper 
Inst. v. EPA, 660 F.2d at 959 n.13 (``An agency may make even 
substantial changes in its original proposed rule without a further 
comment period if the changes are in character with the original 
proposal and are a logical outgrowth of the notice and comments 
already given.'' (emphasis added)).
    \1942\ NOPR, 179 FERC ] 61,028 at PP 325-326.
    \1943\ Order No. 1920, 187 FERC ] 61,068 at P 1305 & n.2786 
(citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 87; Order No. 
1000, 136 FERC ] 61,051 at P 10; ICC v. FERC I, 576 F.3d at 476).
    \1944\ Conn. Light & Power Co. v. Nuclear Regul. Comm'n, 673 
F.2d at 533.
    \1945\ Telesat Canada v. FCC, 999 F.3d 707, 713 (D.C. Cir. 2021) 
(quotations omitted).
---------------------------------------------------------------------------

2. Substantive Issues
a. Order No. 1920 Requirements
    775. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to demonstrate on 
compliance that the required Long-Term Regional Transmission Cost 
Allocation Method(s) that Relevant State Entities have not indicated 
that they agree to comply with Order No. 1000 regional transmission 
cost allocation principles (1) through (5) and do not allocate costs by 
project type (i.e., reliability, economic, or transmission needs driven 
by Public Policy Requirements).\1946\
---------------------------------------------------------------------------

    \1946\ Order No. 1920, 187 FERC ] 61,068 at PP 1505-1506.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    776. Clean Energy Associations assert that the Commission should 
clarify the rights, obligations, and limits associated with 
transmission providers' adoption of multiple Long-Term Regional 
Transmission Cost Allocation Methods for comparable transmission 
facilities within its overall footprint. Further, Clean Energy 
Associations argue that the Commission should clarify that transmission 
providers must allocate the costs of similarly situated transmission 
facilities similarly to avoid undue discrimination and unjust and 
unreasonable rates.\1947\ Clean Energy Associations assert that, 
although presently unclear, it seems plausible that under Order No. 
1920, transmission providers could attempt to allocate the costs of two 
comparable transmission facilities (similar in costs and benefits) 
using entirely different methods if the transmission provider considers 
them to be different ``types'' of projects, based on any categorization 
rubric other than Order No. 1000's regional cost allocation principle 
(6).\1948\ Clean Energy Associations also request clarification that 
Order No. 1920 does not preclude transmission providers from adopting a 
cost allocation approach that seeks to maximize net benefits.\1949\
---------------------------------------------------------------------------

    \1947\ Clean Energy Associations Rehearing Request at 30-32.
    \1948\ Id. at 31.
    \1949\ Id. at 32-33.
---------------------------------------------------------------------------

    777. Dominion seeks clarification on the consideration of the seven 
required benefits in cost allocation such that if a transmission 
provider opts to rely on all or some of the seven benefits in its cost 
allocation method, then it may apply different weighting to different 
benefits, e.g., based on probability of occurrence and certainty of 
benefit in later years.\1950\
---------------------------------------------------------------------------

    \1950\ Dominion Rehearing Request at 26-27.
---------------------------------------------------------------------------

c. Commission Determination
    778. We deny Clean Energy Association's request to clarify the 
rights, obligations, and limits associated with transmission providers' 
potential adoption of multiple Long-Term Regional Transmission Cost 
Allocation Methods for comparable transmission facilities within its 
overall footprint. Order No. 1920 provided guidance regarding 
transmission providers' use of multiple Long-Term Regional Transmission 
Cost Allocation Methods, including that transmission providers may 
adopt multiple Long-Term Regional Transmission Cost Allocation Methods, 
provided that the Long-Term Regional

[[Page 97320]]

Transmission Cost Allocation Method that will apply to a Long-Term 
Regional Transmission Facility (or portfolio of such Facilities) is 
known before selection and does not allocate costs by project type 
(i.e., reliability, economic, or transmission needs driven by Public 
Policy Requirements).\1951\
---------------------------------------------------------------------------

    \1951\ Order No. 1920, 187 FERC ] 61,068 at PP 1475, 1506. See 
supra P 749.
---------------------------------------------------------------------------

    779. In response to Clean Energy Associations' concern that 
transmission providers could attempt to allocate the costs of two 
comparable transmission facilities (similar in costs and benefits) 
using entirely different cost allocation methods if the transmission 
provider considers them to be different ``types'' of projects (other 
than those delineated in Order No. 1000's regional cost allocation 
principle (6)), we note that even if the costs of similar facilities 
are allocated using different cost allocation methods, the fundamental 
requirements associated with a just and reasonable rate (i.e., 
adherence to the cost causation principle and the requirement that 
costs be allocated in a manner that is at least roughly commensurate 
with estimated benefits) remain the same.\1952\ Therefore, a 
transmission provider may allocate the costs of two similar 
transmission facilities using different cost allocation methods and 
meet the requirements of Order No. 1920. In addition, we note that 
Order No. 1920 also does not preclude transmission providers from 
proposing on compliance a cost allocation approach that seeks to 
maximize net benefits.\1953\
---------------------------------------------------------------------------

    \1952\ Order No. 1920, 187 FERC ] 61,068 at P 1305.
    \1953\ See id. P 964 (``We adopt the NOPR proposal, with 
modification, to require that transmission providers in each 
transmission planning region propose evaluation processes, including 
selection criteria, that seek to maximize benefits accounting for 
costs over time without over-building transmission facilities.'').
---------------------------------------------------------------------------

    780. Regarding Dominion's request for clarification that if a 
transmission provider opts to rely on all or some of the seven required 
benefits in its cost allocation method for Long-Term Regional 
Transmission Facilities, then it may apply different weighting to 
different benefits, we note that Order No. 1920 includes no limitation 
on weighting of the seven required benefits for purposes of accounting 
for such benefits in the cost allocation method for Long-Term Regional 
Transmission Facilities save that costs must be allocated in a manner 
that is at least roughly commensurate with estimated benefits. Further, 
transmission providers can consider additional benefits for cost 
allocation purposes, including, but not limited to, those agreed to by 
Relevant State Entities and those described elsewhere in Order No. 
1920, provided that costs are allocated in a way that is at least 
roughly commensurate with estimated benefits.

H. Additional Cost Allocation Issues

1. Order No. 1920 Requirements
    781. In Order No. 1920, the Commission declined to adopt a 
particular time frame for determining the cost allocation for a Long-
Term Regional Transmission Facility. The Commission stated that 
imposing a standardized time frame to determine cost allocation was 
unnecessary and could impede the regional flexibility that the 
Commission provided to transmission providers under Order No. 1920. The 
Commission added, however, that the determination of the applicable 
cost allocation must occur by or before selection of a particular Long-
Term Regional Transmission Facility (or portfolio of such Facilities) 
if only a Long-Term Regional Transmission Cost Allocation Method is 
available for that Facility (or portfolio of such Facilities).\1954\
---------------------------------------------------------------------------

    \1954\ Id. P 1521.
---------------------------------------------------------------------------

    782. Also in Order No. 1920, the Commission stated that, following 
the Engagement Period, Relevant State Entities may agree to, and ask 
the transmission providers to file, a State Agreement Process, which, 
if accepted by the Commission, would be the cost allocation process 
used by the transmission providers in the transmission planning region 
prior to using the relevant Long-Term Regional Transmission Cost 
Allocation Method as a backstop.\1955\ Further, in response to NOPR 
comments requesting that a beneficiary-pays approach be used rather 
than a postage stamp load ratio share model for cost allocation 
methods, the Commission in Order No. 1920 found that any cost 
allocation method applied to a Long-Term Regional Transmission Facility 
must ensure that costs are allocated in a manner that is at least 
roughly commensurate with the estimated benefits of the facility, 
consistent with cost causation and court precedent, and noted that the 
Commission will evaluate whether a proposed cost allocation method 
satisfies this standard on a fact-specific basis, relying on the record 
in a given proceeding. The Commission found that load ratio share, 
which charges transmission customers in proportion to their use of the 
transmission system as measured by their relative share of load, is a 
cost allocation method that may be consistent with the beneficiary-pays 
approach.\1956\
---------------------------------------------------------------------------

    \1955\ Id. P 1296.
    \1956\ Id. P 1305 (citations omitted).
---------------------------------------------------------------------------

    783. Separately, in Order No. 1920, the Commission found that 
commenters' statements regarding cost containment were outside the 
scope of the proceeding.\1957\ The Commission noted that it is 
examining issues related to transmission planning and cost containment 
in other proceedings.\1958\
---------------------------------------------------------------------------

    \1957\ Id. P 1523. Specifically, the Commission was responding 
to comments by: (1) Joint Commenters in support of a cost management 
framework overseen by the Commission; and (2) State Water 
Contractors, who asserted that the need for cost containment is 
acute for consumers in California and an essential component of the 
justness and reasonableness of any final rule. Id. P 1518.
    \1958\ Id. P 1523 (citing Supplemental Notice of Technical 
Conference, Transmission Planning and Cost Management, Docket No. 
AD22-8-000 (Oct. 4, 2022)).
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    784. Dominion seeks clarification regarding the deadline imposed by 
Order No. 1920's requirement that ``the determination of the applicable 
cost allocation must occur by or before its selection.'' \1959\ 
Dominion avers that this requirement implies that there could be 
situations ``when a Long-Term Regional Transmission Facility Cost 
Allocation Method would not be applied to a Long-Term Regional 
Transmission Facility.'' \1960\ Dominion states that its understanding 
is that ``a Long-Term Regional Transmission Facility Cost Allocation 
Method must be used, and that method could be one of several methods: 
the Transmission Provider's default ex ante cost allocation method, 
some other approved ex ante cost allocation method, or a State 
Agreement Process.'' \1961\ Dominion requests that, to the extent the 
Commission was referring to the deadline of six months after project 
selection for submission of cost allocation methods resulting from a 
State Agreement Process, the Commission provide clarification.\1962\
---------------------------------------------------------------------------

    \1959\ Dominion Rehearing Request at 32 (quoting Order No. 1920, 
187 FERC ] 61,068 at P 1521).
    \1960\ Id. (emphasis omitted).
    \1961\ Id.
    \1962\ Id. at 32-33.
---------------------------------------------------------------------------

    785. Dominion further asks the Commission to clarify whether only 
the cost allocation method must be determined by project selection, or 
whether it must be applied (and costs actually allocated) by project 
selection. Dominion notes its understanding is that only the method 
must be determined by selection and states that this clarification on 
timing would help to alleviate the concern about the challenges 
transmission developers will face in obtaining state regulatory

[[Page 97321]]

approval for transmission projects designed to meet a predicted need 20 
years in the future. Specifically, Dominion states that it is 
impossible to meet even a ``roughly commensurate'' standard when 
projected beneficiaries subject to the cost allocation decision are so 
far removed from the in-service date of the facilities, particularly in 
the context of an RTO/ISO in which transmission owning entities are 
permitted to leave and join.\1963\
---------------------------------------------------------------------------

    \1963\ Id. at 31, 33-34.
---------------------------------------------------------------------------

    786. Designated Retail Regulators and Undersigned States argue that 
any Long-Term Regional Transmission Cost Allocation Method should not 
include a postage-stamp-type cost allocation, as the costs imposed on 
non-consenting states should be allocated to cost causers and 
beneficiaries on as granular a basis as possible. They further argue 
that postage stamp-type cost allocation method should not be adopted 
merely to simplify the work of an RTO and to facilitate the 
construction of such projects.\1964\
---------------------------------------------------------------------------

    \1964\ Designated Retail Regulators Rehearing Request at 39; 
Undersigned States Rehearing Request at 34.
---------------------------------------------------------------------------

    787. Wyoming Commission asserts that if a portion of the costs of a 
Long-Term Regional Transmission Facility are to be recovered from 
Wyoming retail customers, the Wyoming Commission must evaluate the 
costs and benefits derived from the project on a post hoc basis to 
determine that costs allocated to retail customers and rates designed 
to recover those costs are just and reasonable. Wyoming Commission 
avers that Order No. 1920 does not accommodate this process.\1965\
---------------------------------------------------------------------------

    \1965\ Wyoming Commission Rehearing Request at 8.
---------------------------------------------------------------------------

    788. Industrial Customers request rehearing of Order No. 1920's 
finding that commenters' statements regarding cost containment are 
outside the scope of this proceeding, arguing that such a finding is 
arbitrary and capricious because the Commission failed to meaningfully 
engage arguments and evidence supporting the current need for cost 
management and cost containment. According to Industrial Customers, 
while the Commission in Order No. 1920 stated that it is examining 
issues related to transmission planning and cost containment in other 
proceedings, Order No. 1920 does not compel the Commission to act in 
the proceeding in Docket No. AD22-8-000, which is the only pending 
proceeding that is sufficiently broad to complement Order No. 1920. 
Industrial Customers add that Order No. 1920 does not demonstrate that 
cost containment and cost mitigation measures are unrelated to the cost 
issues at hand or are, in fact, outside the scope of Order No. 
1920.\1966\
---------------------------------------------------------------------------

    \1966\ Industrial Customers Rehearing Request at 21-23 (citing 
State Farm, 463 U.S. at 43).
---------------------------------------------------------------------------

3. Commission Determination
    789. Regarding Dominion's request for clarification regarding the 
intent of the requirement that ``the determination of the applicable 
cost allocation must occur by or before its selection,'' \1967\ we 
clarify that this requirement applies only to Long-Term Regional 
Transmission Cost Allocation Methods. We further clarify that Long-Term 
Regional Transmission Cost Allocation Methods refer only to ex ante 
cost allocation methods used to allocate the costs of selected Long-
Term Regional Transmission Facilities.\1968\
---------------------------------------------------------------------------

    \1967\ Order No. 1920, 187 FERC ] 61,068 at P 1521.
    \1968\ Id. P 1291.
---------------------------------------------------------------------------

    790. Dominion requested clarification as to whether ``the 
determination of the applicable cost allocation must occur by or before 
its selection'' \1969\ means that only the cost allocation method must 
be determined by a Long-Term Regional Transmission Facility's selection 
or whether it must be applied (and costs actually allocated) by project 
selection. Noting our clarification above that this requirement applies 
only to Long-Term Regional Transmission Cost Allocation Methods, we 
clarify that Dominion is correct that only the applicable cost 
allocation method must be determined by project selection. While it is 
possible that certain Long-Term Regional Transmission Cost Allocation 
Methods will be designed in a way that actual costs to be allocated may 
be known by selection, such a requirement would needlessly limit the 
flexibility provided to transmission providers and could, in 
particular, create unnecessary obstacles to transmission providers' 
ability pursuant to Order No. 1920 to demonstrate that use of existing 
cost allocation methods to allocate the cost of Long-Term Regional 
Transmission Facilities would be compliant with Order No. 1920's 
requirements.\1970\
---------------------------------------------------------------------------

    \1969\ Id. P 1521.
    \1970\ For example, requiring that actual costs be allocated 
would preclude transmission providers from proposing that DFAX-based 
or postage-stamp cost allocation methods comply with Order No. 1920 
because the amounts each transmission customer will pay are not 
known at the time of selection for those methods.
---------------------------------------------------------------------------

    791. We are not persuaded by arguments raised by Designated Retail 
Regulators and Undersigned States regarding postage-stamp cost 
allocation. As in Order No. 1920,\1971\ we continue to find that the 
record does not support a blanket prohibition on postage-stamp-type 
cost allocation. We will evaluate whether a proposed cost allocation 
method allocates costs in a manner that is at least roughly 
commensurate with estimated benefits on a case-specific basis, relying 
on the record to ensure that it complies with the cost-causation 
principle by allocating costs in a manner that is at least roughly 
commensurate with estimated benefits. We continue to find that the 
flexibility that we provide to consider benefits in cost allocation 
does not prevent transmission providers in a particular transmission 
planning region from adopting a more granular approach.\1972\
---------------------------------------------------------------------------

    \1971\ Order No. 1920, 187 FERC ] 61,068 at P 1305 (citing 
Certain TDUs NOPR Initial Comments at 2, 7, 8-9; R Street NOPR 
Initial Comments at 4, 12).
    \1972\ Id. P 1512.
---------------------------------------------------------------------------

    792. In response to Wyoming Commission, we reiterate that Order No. 
1920 does not change existing mechanisms for cost-recovery through 
retail rates.\1973\ We also emphasize that Order No. 1920 neither aims 
at nor conflicts with state authority over retail rates.\1974\ However, 
we decline to modify Order No. 1920 to enable states to conduct a post 
hoc review of costs allocated to retail customers. Order No. 1920 does 
not alter the requirement for states to pass through Commission-
jurisdictional rates to retail customers.\1975\
---------------------------------------------------------------------------

    \1973\ Id. P 259.
    \1974\ Id. P 998.
    \1975\ See Narragansett Elec. Co. v. Burke, 381 A.2d 1358, 1361-
63 (R.I. 1977) (holding that the state could not inquire into the 
reasonableness of the Commission-approved wholesale rate and, 
consequently, must treat it as a reasonable operating expense in the 
company's retail cost of service).
---------------------------------------------------------------------------

    793. Finally, we disagree with Industrial Customers that the 
Commission failed to engage in reasoned decision making by determining 
that various NOPR comments regarding cost containment were outside the 
scope of the proceeding. First, to the extent that Industrial Customers 
are arguing that the Commission did not consider transmission-related 
costs to consumers, as noted above, addressing costs to ratepayers was 
central to the reforms the Commission adopted in Order No. 1920, and 
the Commission cited evidence that more comprehensive, longer-term 
regional transmission planning results in the selection of more 
efficient or cost-effective transmission solutions, which has 
significant benefits for customers.\1976\ Second, the NOPR did not 
propose to address cost containment reform per se, and we continue to 
find that certain comments regarding cost containment reform, including 
those proposing a specific cost management

[[Page 97322]]

framework, are outside the scope of this proceeding.\1977\ Third, we 
are unpersuaded by Industrial Customers' unsupported argument that the 
Commission was required to make a binding commitment to finalize cost 
containment and cost mitigation measures in another docket--we are 
unaware of any such requirement. Finally, we disagree that Order No. 
1920 is arbitrary and capricious because it failed to meaningfully 
engage with arguments and evidence supporting the need for transmission 
cost management and cost containment, in contravention of State 
Farm.\1978\ State Farm, which held that rescission of a prior 
regulation was arbitrary and capricious because it was done without 
adequate explanation,\1979\ did not hold that every aspect of a problem 
within an agency's jurisdiction must be addressed in a single 
rulemaking, or that a final rule must include requirements that address 
comments that were outside the scope of the proceeding.\1980\
---------------------------------------------------------------------------

    \1976\ See supra The Overall Need for Reform section.
    \1977\ Order No. 1920, 187 FERC ] 61,068 at P 1523.
    \1978\ Industrial Customers Rehearing Request at 23 (citing 
State Farm, 463 U.S. at 43).
    \1979\ State Farm, 463 U.S. at 34.
    \1980\ See N.Y. v. FERC, 535 U.S. at 27 (holding that 
``[b]ecause FERC determined that the remedy it ordered constituted a 
sufficient response to the problems FERC had identified in the 
wholesale market, FERC had no [FPA section] 206 obligation'' to 
adopt further reforms).
---------------------------------------------------------------------------

IX. Construction Work in Progress Incentive

A. CWIP

1. Order No. 1920
    794. In Order No. 1920, the Commission declined to act to finalize 
the NOPR proposal to not permit transmission providers to take 
advantage of the allowance for inclusion of 100% of Construction Work 
in Progress (CWIP) costs in rate base (CWIP Incentive) for Long-Term 
Regional Transmission Facilities.\1981\ The Commission concluded that 
any action on the CWIP Incentive is more appropriately considered in a 
separate proceeding to allow for a holistic approach to transmission 
incentives after the Commission has finalized its Long-Term Regional 
Transmission Planning reforms.\1982\ The Commission found that, in 
particular, whether the Commission's incentives are appropriately 
``benefitting consumers by ensuring reliability and reducing the cost 
of delivered power'' is a question better evaluated by considering the 
Commission's transmission incentives comprehensively for all regional 
transmission facilities.\1983\
---------------------------------------------------------------------------

    \1981\ Order No. 1920, 187 FERC ] 61,068 at PP 1524, 1547.
    \1982\ Id. P 1547.
    \1983\ Id. (quoting 16 U.S.C. 824s(a)).
---------------------------------------------------------------------------

2. Requests for Rehearing and Clarification
    795. Several parties request rehearing on the grounds that the 
Commission failed to conduct reasoned decision-making in declining to 
act to finalize the NOPR proposal to limit the availability of the CWIP 
Incentive for Long-Term Regional Transmission Facilities.\1984\ NARUC, 
for instance, states that the Commission not only failed to rebut 
arguments that ratepayers will have to pay in advance for facilities 
that may not ever be used, but also simply declined to finalize the 
NOPR proposal until the Commission can address other incentives at the 
same time, which NARUC contends is not reasoned decision-making.\1985\ 
Ohio Consumers agree, and argue that retaining the CWIP Incentive for 
Long-Term Regional Transmission Facilities without an analysis on the 
justness and reasonableness of rates of return is arbitrary and 
capricious.\1986\
---------------------------------------------------------------------------

    \1984\ Industrial Customers Rehearing Request at 24, 26; NARUC 
Rehearing Request at 5, 8, 10-11; Ohio Consumers Rehearing Request 
at 11-12.
    \1985\ NARUC Rehearing Request at 9-11.
    \1986\ Ohio Consumers Rehearing Request at 12.
---------------------------------------------------------------------------

    796. Some parties argue on rehearing that not adopting the NOPR 
proposal to limit the availability of the CWIP Incentive for Long-Term 
Regional Transmission Facilities will shift risks to ratepayers.\1987\ 
Ohio Consumers state that the failure of the Commission to eliminate 
the CWIP Incentive for Long-Term Regional Transmission Facilities 
shifts the risk of long-term transmission planning to consumers who may 
never benefit from a project if it does not go into service, but who 
will still be required to pay for it.\1988\
---------------------------------------------------------------------------

    \1987\ NARUC Rehearing Request at 8-9; Ohio Consumers Rehearing 
Request at 11; Virginia Attorney General Rehearing Request at 4-5; 
West Virginia Commission Rehearing Request at 16-17; see Designated 
Retail Regulators Rehearing Request at 42.
    \1988\ Ohio Consumers Rehearing Request at 11-12.
---------------------------------------------------------------------------

    797. Certain parties request that, if the Commission does not grant 
rehearing in this proceeding and eliminate the CWIP Incentive for Long-
Term Regional Transmission Facilities, the Commission should move 
quickly to address the CWIP Incentive in a separate proceeding.\1989\ 
For instance, Virginia Attorney General implores the Commission to act 
with expediency to scale back transmission incentives comprehensively 
in Docket No. RM20-10-000, or another docket as appropriate, if the 
Commission does not grant rehearing in this proceeding and limit the 
availability of the CWIP Incentive for Long-Term Regional Transmission 
Facilities.\1990\
---------------------------------------------------------------------------

    \1989\ Designated Retail Regulators Rehearing Request at 42-43; 
Industrial Customers Rehearing Request at 28; PJM States Rehearing 
Request at 9; Virginia Attorney General Rehearing Request at 5; West 
Virginia Commission Rehearing Request at 17; see also Identified 
Consumer Advocates Rehearing Request at 4, 8-9.
    \1990\ Virginia Attorney General Rehearing Request at 5.
---------------------------------------------------------------------------

    798. Arizona Commission argues that ``walk[ing] back'' the proposal 
to disallow the CWIP Incentive is not a logical outgrowth of the NOPR, 
and failure to provide for additional notice and comment on this 
``fundamental'' change is a direct violation of the APA.\1991\
---------------------------------------------------------------------------

    \1991\ Arizona Commission Rehearing Request at 17-19 (citing 5 
U.S.C. 706(2)(A), (2)(C), (2)(D)).
---------------------------------------------------------------------------

3. Commission Determination
    799. We are unpersuaded by arguments raised on rehearing that the 
Commission erred by failing to limit the availability of the CWIP 
Incentive for Long-Term Regional Transmission Facilities. We continue 
to find that any action on the CWIP Incentive is more appropriately 
considered in a separate proceeding to allow for a holistic approach to 
transmission incentives,\1992\ and we disagree with parties that argue 
that the Commission's decision in Order No. 1920 to defer acting on the 
CWIP Incentive was arbitrary and capricious. The Commission reviewed 
all of the comments received on this proposal in response to the NOPR 
and concluded that whether the Commission's transmission incentives, 
including the CWIP Incentive, are appropriately ``benefitting consumers 
by ensuring reliability and reducing the cost of delivered power'' is a 
question better evaluated by considering the Commission's transmission 
incentives comprehensively for all regional transmission 
facilities.\1993\ We continue to reach this conclusion and find that 
evaluating a single transmission incentive for a regional transmission 
facility may fail to holistically consider benefits and risks to 
consumers from transmission incentives.
---------------------------------------------------------------------------

    \1992\ Order No. 1920, 187 FERC ] 61,068 at P 1547.
    \1993\ Id. (quoting 16 U.S.C. 824s(a)).
---------------------------------------------------------------------------

    800. Further, with respect to the argument that the Commission's 
decision declining to finalize the NOPR proposal to limit the 
availability of the CWIP Incentive for Long-Term Regional Transmission 
Facilities was not a logical outgrowth of the NOPR, we disagree. As 
courts have explained, ``[o]ne logical outgrowth of a proposal is 
surely . . . to refrain from taking the proposed

[[Page 97323]]

step.'' \1994\ The same is true here. We acknowledge the interest and 
support for evaluating the CWIP Incentive, particularly among several 
states, along with other transmission incentives, and note that the 
Commission will continue to evaluate the appropriate manner for 
considering transmission incentives, including the CWIP Incentive, for 
all regional transmission facilities.
---------------------------------------------------------------------------

    \1994\ New York v. EPA, 413 F.3d at 44 (quoting Am. Iron & Steel 
Inst. v. EPA, 886 F.2d at 400); see also Long Island Care, 551 U.S. 
at 175 (stating, in the context of rejecting a claim that an agency 
provided legally defective notice because it did not finalize a 
proposed rule, ``[w]e do not understand why such a possibility was 
not reasonably foreseeable''); Vanda Pharms., 98 F.4th at 498 
(stating that the APA's ``notice-and-comment procedure is designed 
so that an agency can float a potential rule to the public without 
committing itself to enacting the proposed rule's content'').
---------------------------------------------------------------------------

X. Exercise of a Federal Right of First Refusal in Commission-
Jurisdictional Tariffs and Agreements

A. Order No. 1920 Requirements

    801. In Order No. 1920, the Commission stated that, after careful 
consideration of the record, it was declining to finalize the NOPR 
proposal to amend Order No. 1000's findings and nonincumbent 
transmission developer reforms, in part, to permit the exercise of 
federal rights of first refusal for selected regional transmission 
facilities, conditioned on the incumbent transmission provider with the 
federal right of first refusal for such regional transmission 
facilities establishing joint ownership of the transmission facilities 
consistent with certain proposed requirements described in the NOPR. 
The Commission stated that it will continue to consider potential 
federal right of first refusal reforms along with other transmission 
reforms in the future.\1995\
---------------------------------------------------------------------------

    \1995\ Order No. 1920, 187 FERC ] 61,068 at PP 1548, 1563-1564.
---------------------------------------------------------------------------

B. Request for Rehearing

    802. NRECA states that declining to adopt the NOPR's conditional 
federal right of first refusal proposal was a missed opportunity 
because it would have encouraged transmission providers to pursue 
planning and expanding transmission through joint ownership 
arrangements with load-serving entities.\1996\
---------------------------------------------------------------------------

    \1996\ NRECA Rehearing Request at 2.
---------------------------------------------------------------------------

C. Commission Determination

    803. The Commission explained in Order No. 1920 that it will 
continue to consider the NOPR proposal and potential federal rights of 
first refusal issues in other proceedings, a course of action we 
continue to find to be reasonable.\1997\ As noted in Order No. 1920, 
comments on the NOPR raised both concerns about whether incumbent 
transmission providers face perverse investment incentives due to Order 
No. 1000's reforms and concerns about whether the NOPR proposal would 
adequately and appropriately address those incentives.\1998\
---------------------------------------------------------------------------

    \1997\ Order No. 1920, 187 FERC ] 61,068 at PP 1563-1564. NRECA 
did not request rehearing on this issue or include it in NRECA's 
Statement of Issues. See 18 CFR 385.713(c)(2) (any issue not listed 
in the Statement of Issues will be deemed waived). We nevertheless 
address NRECA's concern.
    \1998\ Order No. 1920, 187 FERC ] 61,068 at P 1564.
---------------------------------------------------------------------------

XI. Local Transmission Planning Inputs in the Regional Transmission 
Planning Process

A. Need for Reform

1. Order No. 1920
    804. In Order No. 1920, the Commission found substantial evidence 
to support the conclusion that existing requirements governing 
transparency in local transmission planning processes and coordination 
between local and regional transmission planning processes are unjust, 
unreasonable, and unduly discriminatory or preferential.\1999\ 
Therefore, the Commission adopted the NOPR findings that local 
transmission planning processes may lack adequate provisions for 
transparency and meaningful input from stakeholders, and that regional 
transmission planning processes may not adequately coordinate with 
local transmission planning processes.\2000\
---------------------------------------------------------------------------

    \1999\ Order No. 1920, 187 FERC ] 61,068 at PP 1565, 1569.
    \2000\ Id. P 1569.
---------------------------------------------------------------------------

    805. The Commission explained that local and regional transmission 
planning processes serve essential and complementary roles in ensuring 
that customers' transmission needs are identified and met at a just and 
reasonable cost.\2001\ The Commission added that information and 
transmission solutions developed through local transmission planning 
serve as a foundation for regional transmission planning, and it is 
therefore critical that the processes are appropriately designed and 
aligned to ensure that transmission providers and stakeholders have the 
information needed, including from the local transmission planning 
process, to conduct effective regional transmission planning.\2002\ 
Additionally, the Commission stated that, while the broader reforms 
directed in Order No. 1920 are focused on improving the regional 
transmission planning process, there are discrete deficiencies in the 
local transmission planning process and its coordination with the 
regional transmission planning process that must be addressed to ensure 
Commission-jurisdictional rates are just and reasonable.\2003\
---------------------------------------------------------------------------

    \2001\ Id. P 1570.
    \2002\ Id. P 1570.
    \2003\ Id. P 1570.
---------------------------------------------------------------------------

    806. The Commission first found that local transmission planning 
processes lack adequate provisions for transparency and meaningful 
input from stakeholders. The Commission recognized the critical role 
stakeholders serve in effective transmission planning,\2004\ and noted 
prior reforms to facilitate their meaningful participation in both 
local and regional transmission planning.\2005\ However, the Commission 
found that the record demonstrates that existing transparency and 
coordination requirements in local transmission planning do not 
consistently provide stakeholders with sufficient information regarding 
the development of local transmission plans.\2006\ The Commission found 
that the absence of minimal standards or specified procedures to 
implement the transmission planning principles required by Order No. 
890 contributes to inadequate transparency and opportunities for 
stakeholders to engage in local transmission planning processes.\2007\ 
The Commission explained that the combined effect of these deficiencies 
is that stakeholders who wish to participate in transmission planning, 
at both the local and regional level, may not be able to effectively do 
so. More specifically, the Commission found that, when engaging in the 
regional transmission planning process, stakeholders lack sufficient 
information about underlying local transmission needs and potential 
solutions that is necessary to ensure that the more efficient or cost-
effective regional transmission solutions are identified, evaluated, 
and selected.\2008\ The Commission stated that, given the importance of 
stakeholder participation in effective transmission planning, reforms 
were needed to ensure that Commission-jurisdictional local and regional 
transmission planning processes remain just, reasonable, and

[[Page 97324]]

not unduly discriminatory or preferential.\2009\
---------------------------------------------------------------------------

    \2004\ Id. P 1571 (citing Order No. 890, 118 FERC ] 61,119 at P 
454; Order No. 1000, 136 FERC ] 61,051 at P 152).
    \2005\ Id. (citing Order No. 890, 118 FERC ] 61,119 at PP 454, 
488, 557; Order No. 1000, 136 FERC ] 61,051 at P 152.).
    \2006\ Id. (citations omitted).
    \2007\ Id.
    \2008\ P 1572.
    \2009\ Id.
---------------------------------------------------------------------------

    807. The Commission also concluded that additional coordination 
between the local and regional transmission planning processes 
regarding the replacement of aging infrastructure is needed. The 
Commission found that the record showed that many incumbent 
transmission providers are replacing aging transmission infrastructure 
as it reaches the end of its useful life. The Commission specifically 
noted that, in PJM and NYISO, a significant portion of transmission 
assets either need to be replaced or will soon need to be 
replaced.\2010\ The Commission stated that replacing these transmission 
facilities will require substantial investment, which will directly 
affect Commission-jurisdictional rates.\2011\
---------------------------------------------------------------------------

    \2010\ Id. P 1573 (citations omitted).
    \2011\ Id.
---------------------------------------------------------------------------

    808. The Commission stated, however, that because its existing 
requirements do not obligate transmission providers to share sufficient 
information regarding these replacement projects, transmission 
providers in the regional transmission planning process are not 
consistently evaluating whether those replacement transmission 
facilities could be modified (i.e., right-sized) to more efficiently or 
cost-effectively address transmission system needs.\2012\ Therefore, 
the Commission concluded, the lack of a requirement for transmission 
providers in each transmission planning region to evaluate whether 
those replacement transmission facilities could be modified (i.e., 
right-sized) to more efficiently or cost-effectively address Long-Term 
Transmission Needs results in a regional transmission planning process 
that fails to identify opportunities to right-size planned in-kind 
replacement transmission facilities and may result in the development 
of inefficiently sized or designed, duplicative, or unnecessary 
transmission facilities that increase costs to customers and render 
Commission-jurisdictional rates unjust and unreasonable.\2013\
---------------------------------------------------------------------------

    \2012\ Id. P 1574.
    \2013\ Id. P 1574.
---------------------------------------------------------------------------

    809. The Commission disagreed with claims from commenters that the 
Commission lacked jurisdiction to impose the requirements in Order No. 
1920 or that the Commission did not justify those requirements.\2014\ 
The Commission explained that consistent with Order Nos. 890 and 1000, 
the Commission has the authority to establish requirements related to 
local transmission planning processes and the inputs to regional 
transmission planning processes.\2015\
---------------------------------------------------------------------------

    \2014\ Id. P 1575 (citations omitted).
    \2015\ Id. (citing Order No. 890, 118 FERC ] 61,119 at P 435; 
Order No. 1000, 136 FERC ] 61,051 at PP 68, 148, 1520).
---------------------------------------------------------------------------

    810. In response to claims from commenters questioning whether the 
Commission properly demonstrated under FPA section 206 that existing 
rates are unjust, unreasonable, or unduly discriminatory or 
preferential in instituting a federal right of first refusal for right-
sized replacement transmission facilities, the Commission explained 
that it found transmission providers' OATTs to be unjust and 
unreasonable due to the lack of right-sizing requirements that may lead 
to the identification, evaluation, and selection of more efficient or 
cost-effective Long-Term Regional Transmission Facilities.\2016\
---------------------------------------------------------------------------

    \2016\ Id. P 1576 (citations omitted).
---------------------------------------------------------------------------

    811. Because the Commission found that existing requirements 
governing transparency in the local transmission planning process and 
coordination between local and regional transmission planning processes 
were insufficient to ensure just and reasonable and not unduly 
discriminatory or preferential rates, the Commission required, pursuant 
to FPA section 206, transmission providers to adopt, with 
modifications, the two reforms the Commission identified in the NOPR: 
(1) enhance the transparency of the local transmission planning 
process; and (2) require transmission providers to evaluate whether 
transmission facilities that need replacing can be ``right-sized'' to 
more efficiently or cost-effectively address Long-Term Transmission 
Needs identified in Long-Term Regional Transmission Planning.\2017\ The 
Commission found that the first reform will result in transmission 
providers providing enhanced transparency for stakeholders while 
providing those same stakeholders with opportunities to more 
effectively engage in local and regional transmission planning 
processes. The Commission found that the second reform will result in 
transmission providers identifying, evaluating, and selecting 
replacement transmission facilities that more efficiently or cost-
effectively address Long-Term Transmission Needs. Finally, the 
Commission found that, taken together, these reforms will ensure that 
Commission-jurisdictional rates are just and reasonable and not unduly 
discriminatory or preferential.\2018\
---------------------------------------------------------------------------

    \2017\ Id. P 1577.
    \2018\ Id.
---------------------------------------------------------------------------

    812. On rehearing, several parties challenge the Commission's 
findings. We address their arguments below.
2. Analysis Under FPA Section 206
a. Rehearing Requests
    813. Advanced Energy and Competition Coalition contend that the 
Commission failed to engage in reasoned decision-making, in violation 
of the APA and the required analysis under FPA section 206, by ignoring 
relevant considerations, failing to address applicable precedent, and 
inadequately explaining its decision to grant incumbent transmission 
providers a right of first refusal for right-sized replacement 
transmission facilities.\2019\ Competition Coalition adds that the 
Commission has failed to prove that the reform is just and reasonable, 
supported by substantial evidence, the product of reasoned decision-
making, and consistent with the public interest.\2020\
---------------------------------------------------------------------------

    \2019\ Advanced Energy Rehearing Request at 4; Competition 
Coalition Rehearing Request at 8.
    \2020\ Competition Coalition Rehearing Request at 59-60.
---------------------------------------------------------------------------

    814. Competition Coalition, Industrial Customers, and Designated 
Retail Regulators request rehearing on the grounds that, in adopting 
the reforms in Order No. 1920 regarding enhanced transparency of local 
transmission planning inputs and identifying opportunities to right-
size replacement transmission facilities, the Commission failed to 
satisfy the requirement to make a finding, supported by substantial 
evidence, that the existing relevant tariff provisions result in rates 
that are unjust, unreasonable, or unduly discriminatory.\2021\ 
Competition Coalition and Industrial Customers, for example, argue that 
Order No. 1920 does not support with substantial evidence the 
Commission's claim that the interrelationship between local and 
regional transmission planning yields unjust, unreasonable, or unduly 
discriminatory rates, and therefore does not reflect reasoned decision-
making.\2022\ Similarly, Designated Retail Regulators argue that the 
Commission failed to provide an analysis of the justness and 
reasonableness of the local transmission planning processes as a 
prerequisite to adopting the local transmission planning and right-
sizing

[[Page 97325]]

reforms in Order No. 1920.\2023\ Competition Coalition contends that 
Order No. 1920's findings on encouraging transmission providers to 
provide their best in-kind replacement estimates and removing other 
disincentives do not provide a basis for satisfying the first prong of 
FPA section 206.\2024\
---------------------------------------------------------------------------

    \2021\ Competition Coalition Rehearing Request at 14 (citing 
Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017) (Emera Maine)); 
Industrial Customers Rehearing Request at 4-5; Designated Retail 
Regulators Rehearing Request at 7, 41.
    \2022\ Competition Coalition Rehearing Request at 14; Industrial 
Customers Rehearing Request at 4-5.
    \2023\ Designated Retail Regulators Rehearing Request at 7.
    \2024\ Competition Coalition Rehearing Request at 18.
---------------------------------------------------------------------------

    815. Several parties separately assert that the Commission failed 
to satisfy the first prong of FPA section 206 when it adopted the 
federal right of first refusal requirement for right-sized replacement 
transmission facilities.\2025\ Competition Coalition contends, and 
Industrial Customers agree, that Order No. 1920 fails to identify the 
specific regional transmission planning and cost allocation tariff 
requirements, particularly those that relate to in-kind replacement 
processes, that are unjust, unreasonable, or unduly discriminatory or 
preferential as a result of the lack of an incumbent preference.\2026\ 
Rather, Competition Coalition argues, the identified concern--lack of 
transparency in local transmission planning as an input to regional 
transmission planning--has nothing to do with the lack of a right of 
first refusal in the regional transmission planning process.\2027\ 
Competition Coalition further states that the absence of any nexus 
between the identified problem in Order No. 1920--that existing 
regional transmission planning processes are unjust and unreasonable--
and the prescribed remedy is glaring as it concerns the federal right 
of first refusal for right-sized replacement transmission 
facilities.\2028\
---------------------------------------------------------------------------

    \2025\ Id. at 6, 11-19, 36-37; Industrial Customers Rehearing 
Request at 13-15.
    \2026\ Competition Coalition Rehearing Request at 12-13; 
Industrial Customers Rehearing Request at 12-13.
    \2027\ Competition Coalition Rehearing Request at 13.
    \2028\ Id. at 13.
---------------------------------------------------------------------------

    816. Competition Coalition also asserts that Order No. 1920 fails 
to provide substantial evidence that the existing regional transmission 
planning framework as it relates to incumbent public utility 
preferences for regionally planned, regionally cost allocated projects 
in existing transmission provider tariff provisions is unjust, 
unreasonable, or unduly discriminatory or preferential. Competition 
Coalition also contends that Order No. 1920 does not elaborate on, or 
support with substantial evidence, the reference to ``coordination'' in 
the context of its finding under the first prong of FPA section 
206.\2029\ Competition Coalition states that substantial evidence is 
``relevant evidence that a reasonable mind might accept as adequate to 
support a conclusion.'' \2030\
---------------------------------------------------------------------------

    \2029\ Id. at 13-14.
    \2030\ Id. at 9.
---------------------------------------------------------------------------

b. Commission Determination
    817. We sustain the finding in Order No. 1920 that existing 
requirements governing transparency in local transmission planning 
processes and coordination between local and regional transmission 
planning processes are unjust, unreasonable, and unduly discriminatory 
or preferential.\2031\ We continue to find that Order No. 1920's 
reforms to transparency in local transmission planning inputs and 
coordination between local and regional transmission planning processes 
are necessary to ensure that Commission-jurisdictional rates are just, 
reasonable, and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \2031\ Order No. 1920, 187 FERC ] 61,068 at P 1569.
---------------------------------------------------------------------------

    818. We disagree with Competition Coalition and Advanced Energy 
that the Commission failed to satisfy the required analysis of FPA 
section 206 in adopting the reforms to enhance the transparency of 
local transmission planning inputs and coordination between the local 
and regional transmission planning processes. As the Commission noted 
in Order No. 1920, reforms to better ensure more consistent 
implementation of the Order No. 890 transmission planning principles 
are timely and important in light of the significant investments in 
transmission infrastructure that now occur through local transmission 
planning processes.\2032\ Further, we continue to find that local and 
regional transmission planning processes serve essential and 
complementary roles in ensuring that customers' transmission needs are 
identified and met at just and reasonable rates, including through the 
identification, evaluation, and selection of more efficient or cost-
effective transmission solutions through regional transmission 
planning.\2033\ As the Commission stated in Order No. 1920, information 
and transmission solutions developed through local transmission 
planning serve as a foundation for regional transmission 
planning.\2034\
---------------------------------------------------------------------------

    \2032\ Id. P 1572; see also id. P 109.
    \2033\ Id. P 1570.
    \2034\ Id.
---------------------------------------------------------------------------

    819. The Commission supported its findings in Order No. 1920 with 
comments and studies in the record highlighting that the lack of 
transparency and coordination requirements in local transmission 
planning do not consistently provide stakeholders with sufficient 
information regarding the development of local transmission 
plans.\2035\ Specifically, the Commission also found that additional 
coordination between the local and regional transmission planning 
processes regarding the replacement of aging infrastructure is needed, 
especially in light of the record evidence that incumbent transmission 
providers across the country are replacing aging transmission 
infrastructure as it reaches the end of its useful life \2036\ without 
considering whether a regional transmission solution could be more 
efficient or cost-effective. Ultimately, the Commission concluded, 
based on these findings, that the existing requirements governing 
transparency in local transmission planning processes and coordination 
between local and regional transmission planning processes were unjust, 
unreasonable, and unduly discriminatory or preferential.\2037\
---------------------------------------------------------------------------

    \2035\ Id. P 1571.
    \2036\ Id. P 1573, nn.3363-3365.
    \2037\ Id. PP 1573-1574, 1576.
---------------------------------------------------------------------------

    820. We also disagree with arguments raised by Competition 
Coalition, Industrial Customers, and Designated Retail Regulators that 
the Commission's findings under FPA section 206 are not supported by 
substantial evidence and find that Competition Coalition's reliance on 
Emera Maine is misplaced.\2038\ Rehearing parties' arguments on this 
issue ignore the Commission's extensive explanation of the 
circumstances that have rendered the existing rates and practices 
affecting those rates unlawful.\2039\ The Commission first identified a 
lack of adequate provisions for transparency and meaningful input from 
stakeholders within local transmission planning processes.\2040\ In 
support of this finding, the Commission: (1) cited prior final rules 
recognizing stakeholders' critical role in effective transmission 
planning; and (2) found that those prior final rules required reforms 
to provide for stakeholders' meaningful participation in both local and 
regional transmission planning processes.\2041\
---------------------------------------------------------------------------

    \2038\ See Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017).
    \2039\ Id. PP 1571, 1572.
    \2040\ Id. P 1571.
    \2041\ Id. P 1571 (citing Order No. 890, 118 FERC ] 61,119 at PP 
454, 488, 557; Order No. 1000, 136 FERC ] 61,051 at P 152).
---------------------------------------------------------------------------

    821. The Commission next identified the lack of a requirement for 
transmission providers in each transmission planning region to

[[Page 97326]]

evaluate whether replacement transmission facilities could be modified 
(i.e., right-sized) to more efficiently or cost-effectively address 
transmission needs. As noted above, the Commission highlighted evidence 
from the record that, for example, PJM and NYISO anticipate soon 
replacing a substantial portion of their aging transmission 
infrastructure as it reaches the end of its useful life, which will 
directly affect Commission-jurisdictional rates.\2042\ Based on this 
evidence, the Commission concluded that existing requirements governing 
transparency in local transmission planning processes and coordination 
between local and regional transmission planning processes may result 
in the development of inefficiently sized or designed, duplicative, or 
unnecessary transmission facilities that increase costs to customers 
and render Commission-jurisdictional rates unjust and 
unreasonable.\2043\ We therefore conclude that the Commission found, 
based on substantial evidence, that these requirements are unjust, 
unreasonable, or unduly discriminatory, and determined that the 
identified deficiencies must be addressed to ensure that Commission-
jurisdictional rates are just and reasonable.
---------------------------------------------------------------------------

    \2042\ Id. P 1573, nn.3363-3365.
    \2043\ Id. P 1574.
---------------------------------------------------------------------------

    822. Order No. 1920 also pointed out that the federal right of 
first refusal for selected right-sized replacement transmission 
facilities will provide transmission providers with certainty that they 
will not lose the opportunity to invest in any in-kind replacement 
transmission facility that is then selected as a right-sized 
replacement transmission facility, and this, in turn, will encourage 
transmission providers to provide their best in-kind replacement 
estimates.\2044\ Accordingly, the Commission found that that a federal 
right of first refusal will remove a disincentive for transmission 
providers to consider right-sizing in Long-Term Regional Transmission 
Planning. The Commission added that this will help to ensure that 
transmission providers identify and select the more efficient or cost-
effective regional transmission solution to Long-Term Transmission 
Needs.\2045\
---------------------------------------------------------------------------

    \2044\ Id. P 1703; see infra Identifying Potential Opportunities 
to Right-Size Replacement Transmission Facilities section. The 
Commission defined ``in-kind replacement estimates'' as ``estimates 
of the transmission facilities operating at and above the specified 
kV threshold that an individual transmission provider that owns the 
transmission facility anticipates replacing in-kind with a new 
transmission facility during the next 10 years . . . .'' Order No. 
1920, 187 FERC ] 61,068 at P 1677. We clarify that these estimates 
include, at minimum, identification of the transmission facilities 
themselves.
    \2045\ See infra Right of First Refusal for Right-Sized 
Replacement Transmission Facilities Selected to Meet Long-Term 
Transmission Needs section.
---------------------------------------------------------------------------

    823. As Competition Coalition points out in its rehearing request, 
substantial evidence is ``relevant evidence that a reasonable mind 
might accept as adequate to support a conclusion.'' \2046\ The above 
discussion makes clear that the Commission examined the relevant data 
and articulated a rational connection between the facts found and the 
choices made in enacting the reforms in Order No. 1920. We thus 
continue to find that the Commission engaged in reasoned decision-
making and considered all important aspects of the problem and 
meaningfully responded to the arguments raised before it.
---------------------------------------------------------------------------

    \2046\ Competition Coalition Rehearing Request at 9 (citing N.J. 
Bd. of Pub. Utils. v. FERC, 744 F.3d 74, 94 (3d Cir. 2014)) (citing 
Mars Home for Youth v. NLRB, 666 F.3d 850, 853 (3rd Cir. 2011).
---------------------------------------------------------------------------

3. Departure From Commission Precedent
a. Rehearing Requests
    824. Competition Coalition opines that no explanation can be 
offered for how the right-sizing proposal is not in conflict with FPA 
section 206 because Order Nos. 1000 and 1000-A required the elimination 
of federal rights of first refusal.\2047\ Competition Coalition also 
asserts that Order No. 1920 departs from Commission precedent without 
explanation.\2048\
---------------------------------------------------------------------------

    \2047\ Competition Coalition Rehearing Request at 36-37 (citing 
S. C. Pub. Serv. Auth. v. FERC, 762 F.3d at 71-76).
    \2048\ Id. at 37 n.112, 40.
---------------------------------------------------------------------------

b. Commission Determination
    825. We are unpersuaded by Competition Coalition's argument that 
Order No. 1920 does not provide a reasoned explanation regarding Order 
No. 1920's departure from Order Nos. 1000 and 1000-A in establishing a 
federal right of first refusal for right-sized replacement transmission 
facilities. In Order No. 1920, the Commission recognized that the 
establishment of a federal right of first refusal for right-sized 
replacement transmission facilities is an exception to Order No. 1000's 
general requirement for transmission providers to eliminate any federal 
right of first refusal for regional transmission facilities selected in 
a regional transmission plan. The Commission then found that requiring 
a federal right of first refusal for right-sized replacement 
transmission facilities aligns with Order No. 1000.\2049\ The 
Commission explained that, in Order No. 1000, transmission providers 
were required to remove federal rights of first refusal from their 
OATTs because they undermined the consideration of more efficient or 
cost-effective potential transmission solutions proposed at the 
regional level, which could lead to unjust and unreasonable rates for 
Commission-jurisdictional services.\2050\ The Commission also explained 
that, in Order No. 1000, it found that federal rights of first refusal 
created a barrier to entry that discouraged nonincumbent transmission 
developers from proposing alternative solutions for consideration at 
the regional level.\2051\
---------------------------------------------------------------------------

    \2049\ Order No. 1920, 187 FERC ] 61,068 at P 1704.
    \2050\ Id. P 1705; infra Right of First Refusal for Right-Sized 
Replacement Transmission Facilities Selected to Meet Long-Term 
Transmission Needs section.
    \2051\ Order No. 1920, 187 FERC ] 61,068 at P 1705 (citing Order 
No. 1000, 136 FERC ] 61,051 at P 257).
---------------------------------------------------------------------------

    826. The Commission further explained that Order No. 1000 did not 
require the elimination of federal rights of first refusal for local 
transmission facilities, nor did it alter the rights of incumbent 
transmission providers to build, own, and recover costs for upgrades to 
their own transmission facilities, regardless of whether the upgrade is 
selected in the regional transmission plan for the purposes of cost 
allocation.\2052\ Because a right-sized replacement transmission 
facility has the potential to both meet an individual transmission 
provider's responsibility to maintain the reliability of its existing 
transmission system and also address a Long-Term Transmission Need more 
efficiently or cost-effectively than an in-kind replacement 
transmission facility or another Long-Term Regional Transmission 
Facility, which includes the need for replacements of existing 
transmission facilities via local transmission planning processes, the 
Commission concluded that the reasons for removing federal rights of 
first refusal in Order No. 1000 do not apply to right-sized replacement 
transmission facilities.\2053\ Specifically, Order No. 1920 found that 
requiring a federal right of first refusal for right-sized replacement 
transmission facilities does not undermine the consideration of more 
efficient or cost-effective potential transmission solutions proposed 
at the regional level. Rather, the Commission found that a federal 
right of first refusal will promote the consideration of more efficient 
or cost-effective potential

[[Page 97327]]

regional transmission solutions to address Long-Term Transmission Needs 
because it captures both an individual transmission provider's 
responsibilities and a Long-Term Transmission Need, we believe the 
right-sizing reform preserves transmission providers' ability to invest 
in replacements of their own transmission facilities, even if such 
facilities are right-sized and selected in the regional transmission 
plan for purposes of cost allocation.\2054\ Furthermore, the Commission 
noted that the reasons for removing federal rights of first refusal in 
Order No. 1000 do not apply to right-sized replacement transmission 
facilities because transmission providers may have existing rights and 
responsibilities with respect to maintaining and, when necessary, 
replacing their transmission facilities.\2055\
---------------------------------------------------------------------------

    \2052\ See id. P 1705 (citing Order No. 1000, 136 FERC ] 61,051 
at P 319.)
    \2053\ Id. P 1706; see infra Right of First Refusal for Right-
Sized Replacement Transmission Facilities Selected to Meet Long-Term 
Transmission Needs section.
    \2054\ See infra Right of First Refusal for Right-Sized 
Replacement Transmission Facilities Selected to Meet Long-Term 
Transmission Needs section.
    \2055\ Order No. 1920, 187 FERC ] 61,068 at PP 1706-1707; see 
infra Right of First Refusal for Right-Sized Replacement 
Transmission Facilities Selected to Meet Long-Term Transmission 
Needs section.
---------------------------------------------------------------------------

    827. We therefore continue to find that providing for a federal 
right of first refusal for right-sized replacement transmission 
facilities aligns with the text and stated purpose of Order No. 1000 by 
ensuring that transmission providers consider more efficient or cost-
effective regional transmission solutions.\2056\ We also reaffirm that 
the right-sizing reform does not depart, without explanation, from 
Commission precedent related to an individual transmission provider's 
ability to proceed with an in-kind replacement transmission facility. 
Further, we believe that, without a federal right of first refusal, the 
incumbent transmission provider whose in-kind replacement transmission 
facility is selected to be right-sized would likely opt to develop the 
less efficient or cost-effective in-kind replacement transmission 
facility rather than a right-sized replacement transmission 
facility.\2057\ Therefore, we continue to find that the establishment 
of the federal right of first refusal for right-sized replacement 
transmission facilities that are evaluated and selected as part of 
Long-Term Regional Transmission Planning is necessary to effectuate 
this reform and ensure that Commission-jurisdictional rates are just 
and reasonable.\2058\ As the Commission reasoned in Order No. 1920, by 
establishing a process that requires transmission providers to evaluate 
opportunities to right-size in-kind replacement transmission facilities 
to meet transmission needs, the right-sizing reform will encourage 
transmission providers to provide their best in-kind replacement 
estimates, as they will have certainty that they will not lose the 
opportunity to invest in any in-kind replacement transmission facility 
that is then selected as a right-sized replacement transmission 
facility. The Commission concluded that together, these reforms will 
enable transmission providers to ensure that the more efficient or 
cost-effective regional solution to transmission needs is identified, 
evaluated, and selected, and therefore that Commission-jurisdictional 
rates are just and reasonable.
---------------------------------------------------------------------------

    \2056\ Order No. 1920, 187 FERC ] 61,068 at P 1704.
    \2057\ See infra Right of First Refusal for Right-Sized 
Replacement Transmission Facilities Selected to Meet Long-Term 
Transmission Needs section.
    \2058\ Order No. 1920, 187 FERC ] 61,068 at PP 1706-1707.
---------------------------------------------------------------------------

4. Commission Authority Under the FPA
a. Rehearing Requests
    828. Competition Coalition argues that FPA section 206 cannot 
support the Commission's adoption of a monopoly preference when FPA 
section 206 mandates the opposite result (prohibition on unduly 
discriminatory or preferential rates or practices affected 
rates).\2059\ Advanced Energy argues that the FPA lacks a plausible 
textual basis for the Commission to bestow on the incumbent utilities a 
``monopoly right'' to develop and own certain types of transmission 
infrastructure.\2060\ Thus, Advanced Energy and Competition Coalition 
assert, the Commission exceeded its authority under FPA section 
206.\2061\
---------------------------------------------------------------------------

    \2059\ Competition Coalition Rehearing Request at 36.
    \2060\ Advanced Energy Rehearing Request at 5, 6-7 (citing 16 
U.S.C. 824e(a)).
    \2061\ Id. at 5, 8; Competition Coalition Rehearing Request at 
22-23.
---------------------------------------------------------------------------

    829. Both Advanced Energy and Competition Coalition assert that the 
Commission's application of FPA section 206 is inconsistent with U.S. 
Supreme Court precedent.\2062\ Advanced Energy states that the 
Commission's reliance on FPA section 206 to bestow a federal right of 
first refusal raises serious constitutional questions and, therefore, 
is inconsistent with the constitutional-doubt canon of statutory 
construction.\2063\ Advanced Energy claims that since FPA section 206 
contains no explicit language regarding development or ownership of 
transmission facilities or authorizing the establishment of a federal 
right of first refusal, relying on FPA section 206 to adopt the right-
sizing reform calls into question whether Congress delegated such 
authority to the Commission and, if so, whether that delegation was 
proper.\2064\
---------------------------------------------------------------------------

    \2062\ Advanced Energy Rehearing Request at 8-10 (citing West 
Virginia, 597 U.S. at 721, 723, 730; Whitman v. Am. Trucking Ass'ns, 
531 U.S. at 468); Competition Coalition Rehearing Request at 36 
(citing West Virginia, 597 U.S. at 723).
    \2063\ Advanced Energy Rehearing Request at 10 (citing Antonin 
Scalia & Bryan A. Garner, Reading Law: The Interpretation of Legal 
Texts 247-48 (2012) (citing Crowell v. Benson, 285 U.S. 22, 62 
(1932))).
    \2064\ Id. at 10, 21 (citing West Virginia, 597 U.S. 697).
---------------------------------------------------------------------------

    830. Advanced Energy states that, in enacting FPA section 216, 
Congress reinforced the FPA's longstanding jurisdictional framework 
that the Commission does not possess the authority to prevent ``any 
person'' from constructing or modifying a transmission facility.\2065\ 
Advanced Energy argues that, as a result, the Commission exceeded its 
authority under the FPA by granting incumbents a right of first refusal 
to develop and own right-sized replacement transmission facilities, to 
the exclusion of all others.\2066\ Similarly, Competition Coalition 
attests that Order No. 1920 failed to demonstrate that the Commission 
has the legal authority under the FPA to mandate the federal right of 
first refusal of transmission facilities, and further argues that the 
FPA provides the Commission no authority to do so.\2067\ Undersigned 
States argue that right-sizing intrudes upon state authority.\2068\
---------------------------------------------------------------------------

    \2065\ Id. at 8 (citing 16 U.S.C. 824p(g)).
    \2066\ Id. at 5, 8.
    \2067\ Competition Coalition Rehearing Request at 7, 21-23.
    \2068\ Undersigned States Rehearing Request at 36.
---------------------------------------------------------------------------

b. Commission Determination
    831. We disagree with Advanced Energy's, Competition Coalition's, 
and Undersigned States' arguments that the reforms in this section, 
specifically the right-sizing reform and the federal right of first 
refusal for right-sized replacement transmission facilities, exceed the 
Commission's authority.\2069\ The Commission's authority under FPA 
section 201 includes ``the transmission of electric energy in 
interstate commerce,'' and under FPA section 206 the Commission's 
authority is to ensure that practices affecting Commission-
jurisdictional rates are just and reasonable.\2070\ As explained in 
EPSA, this jurisdiction extends to practices that ``directly affect'' 
such rates.\2071\ The

[[Page 97328]]

federal right of first refusal acknowledges existing precedent 
recognizing state laws providing an individual transmission provider's 
ability to proceed with an in-kind replacement transmission facility 
and encourages transmission providers to provide their best in-kind 
replacement estimates by preserving the transmission providers' ability 
to invest in facilities selected as right-sized replacement 
transmission facilities.\2072\ The Commission explained that the 
establishment of a federal right of first refusal in this regard will 
result in transmission providers identifying, evaluating, and selecting 
replacement transmission facilities that more efficiently or cost-
effectively address transmission needs.
---------------------------------------------------------------------------

    \2069\ See Advanced Energy Rehearing Request at 4-12; 
Competition Coalition Rehearing Request at 7, 20-40; Undersigned 
States Rehearing Request at 36.
    \2070\ See supra Federal/State Division of Authority section.
    \2071\ 577 U.S. at 278.
    \2072\ Order No. 1920, 187 FERC ] 61,068 at P 1707.
---------------------------------------------------------------------------

    832. Indeed, rights of first refusal have generally been found to 
be practices affecting rates, thus confirming that they are within the 
Commission's jurisdiction--albeit in the context of their 
removal.\2073\ Thus, the Commission's action in Order No. 1920 is 
entirely consistent with Order No. 1000 in that respect. Advanced 
Energy and Competition Coalition fail to recognize the inherent 
contradiction in their arguments. When addressing our statutory 
authority, the relevant question is whether the Commission can regulate 
rights of first refusal, not how it chooses to regulate them. The claim 
that the establishment of a federal right of first refusal for right-
sized replacement transmission facilities is beyond the Commission's 
authority is squarely contrary to Order No. 1000 and South 
Carolina.\2074\
---------------------------------------------------------------------------

    \2073\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 72.
    \2074\ Id. at 73-76 (finding that the Commission was authorized 
to regulate the right of first refusal provisions in Commission-
jurisdictional tariffs and that the Commission correctly concluded 
that inclusion of rights of first refusal in tariffs and agreements 
was a ``practice affecting a rate triggering the Commission's 
authority under FPA section 206.'').
---------------------------------------------------------------------------

    833. We are unpersuaded by arguments that the Commission lacks 
authority under the FPA to require the right-sizing reform. FPA section 
206 provides the Commission with the authority to determine the just 
and reasonable rate following a finding that any rate, charge, 
regulation, or practice is unjust, unreasonable, unduly discriminatory 
or preferential. The D.C. Circuit has recognized that regional 
transmission planning and cost allocation processes are practices 
affecting rates subject to the Commission's exclusive jurisdiction 
\2075\ and that transmission providers use those processes to 
``determine which transmission facilities will more efficiently or 
cost-effectively meet'' transmission needs, the development of which 
directly impacts the rates, terms, and conditions of Commission-
jurisdictional service.\2076\
---------------------------------------------------------------------------

    \2075\ Order No. 1920, 187 FERC ] 61,068 at P 86 (citing S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d 41 at 55-59, 84; see Order No. 
1000-A, 139 FERC ] 61,132 at P 577).
    \2076\ Id. (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 
56).
---------------------------------------------------------------------------

    834. We also are unpersuaded by Advanced Energy's and Competition 
Coalition's claims that the right of first refusal for right-sized 
replacement transmission facilities requires explicit congressional 
authorization and find that, notwithstanding references to West 
Virginia in their rehearing requests, the major questions doctrine is 
not implicated here. As discussed in detail above,\2077\ the major 
questions doctrine is a context-specific analysis that applies only in 
``extraordinary cases'' where an agency action is so extravagant that 
it is akin to discovering an ``elephant in a mousehole.'' \2078\ More 
specifically, the major questions doctrine comes into play where, 
despite a ``colorable textual basis'' for the agency's claim of 
authority, the agency action was so extravagant when viewed in light of 
the statutory context that it was unlikely that Congress would have 
afforded this claimed authority to the agency, and particularly would 
not have done so in an oblique or subtle way.\2079\
---------------------------------------------------------------------------

    \2077\ See supra Major Questions Doctrine section.
    \2078\ See West Virginia, 597 U.S. at 746.
    \2079\ Id. at 722-23.
---------------------------------------------------------------------------

    835. The Advanced Energy and Competition Coalition rehearing 
requests do not meaningfully engage with the context-specific factors 
associated with the application of the major questions doctrine. 
Advanced Energy's theory that the doctrine applies boils down to its 
characterization of the federal right of first refusal as a ``monopoly 
franchise right'' and assertion that replacing transmission projects is 
extremely expensive.\2080\ Competition Coalition similarly relies on a 
largely conclusory invocation of West Virginia, without analysis beyond 
asserting that this is an ``extraordinary case'' because the Commission 
has never previously asserted that Congress granted it this 
power.\2081\
---------------------------------------------------------------------------

    \2080\ Advanced Energy Rehearing Request at 9-10.
    \2081\ Competition Coalition Rehearing Request at 34, 36.
---------------------------------------------------------------------------

    836. We continue to conclude that the major questions doctrine does 
not apply to Order No. 1920, which is a rulemaking under the 
Commission's broad authority over transmission planning processes 
affecting Commission-jurisdictional rates. Specifically, here, Order 
No. 1920's inclusion of a federal right of first refusal for right-
sized replacement transmission facilities falls well within the 
Commission's authority under FPA section 206 over ``practice[s] . . . 
affecting'' rates, the same grant of statutory authority supporting 
issuance of Order No. 1920.\2082\ As a result, for all the reasons that 
we find that the major questions doctrine is inapplicable to Order No. 
1920 as a whole,\2083\ we likewise find that Advanced Energy and 
Competition Coalition have not shown that the major questions doctrine 
applies to Order No. 1920's inclusion of a federal right of first 
refusal for right-sized replacement transmission facilities.
---------------------------------------------------------------------------

    \2082\ See EPSA, 577 U.S. at 277-78; S.C. Pub. Serv. Auth. v. 
FERC, 762 at 56-57; CAISO, 372 F.3d at 399-404.
    \2083\ See supra Major Questions Doctrine section.
---------------------------------------------------------------------------

    837. We are also unpersuaded by Advanced Energy's claims that Order 
No. 1920's establishment of a federal right of first refusal for right-
sized replacement transmission facilities raises constitutional 
questions and is therefore inconsistent with the constitutional-doubt 
canon of statutory construction.\2084\ Advanced Energy does not discuss 
the substance of this doctrine, cite any authority that relates to this 
doctrine, or explain how--by authorizing the Commission to regulate 
practices affecting rates, which includes the local transparency 
improvements and the right-sizing reform--Congress would have 
impermissibly delegated legislative power to the Commission.\2085\
---------------------------------------------------------------------------

    \2084\ See Advanced Energy Rehearing Request at 10 (citing 
Antonin Scalia & Bryan A. Garner, Reading Law: The Interpretation of 
Legal Texts, at 247-48 (2012) (citing Crowell v. Benson, 285 U.S. at 
62)).
    \2085\ Id.; see also supra Major Questions Doctrine section.
---------------------------------------------------------------------------

    838. We also disagree with Advanced Energy that the Commission 
exceeded its authority under FPA section 216 and find such arguments to 
be misplaced. FPA section 216 governs the Commission's authority with 
respect to authorization of a construction permit for a transmission 
facility located within a National Interest Electric Transmission 
Corridor under certain circumstances. FPA section 216 does not alter or 
restrict the Commission's authority to identify a replacement rate 
under section 206 of the FPA, including the provision for or the 
removal of a federal right of first refusal, to ensure transmission 
providers' OATTs are just and reasonable and not unduly discriminatory 
or preferential. The

[[Page 97329]]

federal right of first refusal for right-sized replacement transmission 
facilities is not aimed at, nor does it directly regulate, an area of 
state authority.\2086\ As discussed in Order No. 1920 and above, the 
Commission is not unlawfully supplanting state authority, including 
siting and development processes.\2087\ States retain their authority 
over those processes and the federal right of first refusal for right-
sized replacement transmission facilities is not directed at those 
practices nor does it divest states of their authority. As explained 
above, the right-sizing processes, including the right of first refusal 
for right-sized replacement transmission facilities, are directed at 
Commission-jurisdictional transmission planning processes.
---------------------------------------------------------------------------

    \2086\ See supra Federal/State Division of Authority section 
(explaining that Commission regulations are not unlawful even if 
they substantially affect areas of reserved state jurisdiction so 
long as the Commission is directly regulating within its areas of 
authority under the FPA, rather than attempting to directly regulate 
within state jurisdiction).
    \2087\ See supra Federal/State Division of Authority section; 
See also Order No. 1920, 187 FERC ] 61,068 at P 271.
---------------------------------------------------------------------------

    839. We are not persuaded by Advanced Energy's acontextual reading 
of FPA section 216(g) which posits that--in providing backstop siting 
authority to the Commission under FPA section 216 and allowing the 
Commission, in certain circumstances, to grant construction permits for 
transmission facilities within designated National-Interest Electric 
Transmission Corridors--Congress was subtly intending to negate the 
Commission's authority in FPA sections 205 or 206, particularly with 
respect to the right-sizing rights of first refusal or rights of first 
refusal more generally. The far more natural interpretation of this 
provision is that it means what it says, clarifying the impact of 
``this section'' of the FPA: that despite creating such backstop 
permitting authority residing with the Commission, FPA section 216 does 
not preclude the construction or modification of transmission 
facilities in accordance with state law.\2088\
---------------------------------------------------------------------------

    \2088\ We note, further, that Order No. 1920 is not a regulation 
under FPA section 216 and no part of the right-sizing right of first 
refusal relies on Commission authority under FPA section 216.
---------------------------------------------------------------------------

5. Policy Against Anticompetitive Practices
a. Rehearing Requests
    840. Both Competition Coalition and Advanced Energy claim that 
Order No. 1920's establishment of a federal right of first refusal for 
right-sized replacement transmission facilities is inconsistent with 
federal policy against anticompetitive practices.\2089\ Specifically, 
Advanced Energy asserts that the federal right of first refusal is 
inconsistent with Supreme Court finding that ``the history of Part II 
of the Federal Power Act indicates an overriding policy of maintaining 
competition to the maximum extent possible consistent with the public 
interest.'' \2090\ Competition Coalition contends that the reform is 
contrary to appellate courts' affirmation that monopoly preferences are 
against the public interest.
---------------------------------------------------------------------------

    \2089\ Competition Coalition Rehearing Request at 67-68 (citing 
Exec. Order No. 14,036, 3 CFR 100.1); Advanced Energy Rehearing 
Request at 10-11.
    \2090\ Advanced Energy Rehearing Request at 10-11 (citing Otter 
Tail v. U.S., 410 U.S. 366, 374 (1973)).
---------------------------------------------------------------------------

b. Commission Determination
    841. Order No. 1920's conclusion that the federal right of first 
refusal for right-sized replacement transmission facilities is within 
the Commission's authority is further supported by the history and 
context of the FPA broadly, and rights of first refusal generally--
contrary to the arguments in the rehearing requests. As the Supreme 
Court has recognized, electric utilities have historically been 
vertically integrated monopolies, including as to transmission.\2091\
---------------------------------------------------------------------------

    \2091\ Morgan Stanley Cap. Grp. Inc. v. Pub. Util. Dist. No. 1 
of Snohomish Cnty., Wash., 554 U.S. 527, 535-36 (2008) (finding 
that, historically, electric utilities have been monopolies).
---------------------------------------------------------------------------

    842. When Congress enacted the FPA, it charged the Commission with 
ensuring that rates and practices were ``just and reasonable'' and not 
unduly discriminatory or preferential. Within these parameters, the 
statutory text does not require a particular approach. Thus, Advanced 
Energy's and Competition Coalition's invocation of a policy against 
anticompetitive practices is unpersuasive.\2092\ The Commission's 
authority is defined and delineated by the FPA, not by reference to a 
general policy that may favor competition. Notably, the case Advanced 
Energy cites in this context, Otter Tail, did not address the 
Commission's authority under FPA section 205 or 206, and instead 
considered whether provisions of the FPA implicitly repealed otherwise 
applicable antitrust laws.\2093\
---------------------------------------------------------------------------

    \2092\ Advanced Energy Rehearing Request at 10-11.
    \2093\ See id. at 10 n.30.
---------------------------------------------------------------------------

6. Other Arguments
a. Rehearing Requests
    843. Competition Coalition asserts that Order No. 1920 fails to 
meaningfully engage with NOPR arguments and rebut arguments presented 
in those comments. Competition Coalition also asserts that the phrase 
federal rights of first refusal is a ``made-up phrase'' that has no 
history in the FPA.\2094\ Competition Coalition adds that the federal 
right of first refusal for right-sized replacement transmission 
facilities is likely to encourage gaming.\2095\
---------------------------------------------------------------------------

    \2094\ Competition Coalition Rehearing Request at 24-29.
    \2095\ Id. at 61, 68-71.
---------------------------------------------------------------------------

b. Commission Determination
    844. We also find that Competition Coalition's remaining arguments 
are unpersuasive as they fail to engage with the statutory text or 
context and, ultimately, have little to do with the Commission's 
statutory authority, notwithstanding how they are categorized in 
Competition Coalition's rehearing request.
    845. A large swath of Competition Coalition's arguments discuss the 
history of the phrase ``federal right of first refusal,'' arguing that 
``the phrase was nothing more than a made-up general reference for 
clauses in [Commission]-jurisdictional contracts or tariffs implemented 
by existing transmission owners to impede independent transmission 
developers seeking to develop cost-of-service transmission.'' \2096\ We 
find that this discussion has little bearing on the issue of the 
Commission's authority, which is defined by the statutory text and 
relevant precedent construing this text. As discussed above, we find 
that establishing the federal right of first refusal for right-sized 
replacement transmission facilities is within our authority and 
consistent with that history. We also note that Order No. 1000 did not 
require the removal of all rights of first refusal. Thus, Order No.1000 
does not suggest that establishment of a federal right of first refusal 
for right-sized replacement transmission facilities is beyond the 
Commission's authority.
---------------------------------------------------------------------------

    \2096\ Id. at 24-29 (arguing that such provisions were not based 
on requirements of the FPA or rights inherent in the FPA).
---------------------------------------------------------------------------

    846. We also find that most of Competition Coalition's other 
arguments--although housed in a portion of their request for rehearing 
contending that Order No. 1920 exceeds the Commission's statutory 
authority--are mislabeled. On their substance, these arguments amount 
to disputes over whether the federal right of first refusal for right-
sized replacement transmission facilities is just and reasonable and 
not unduly discriminatory or preferential and whether the Commission 
departed from

[[Page 97330]]

its precedent without adequate explanation, albeit peppered with 
assertions that the federal right of first refusal for right-sized 
replacement transmission facilities is not supported by the FPA.\2097\ 
Throughout this order, we affirm that the replacement rate set by the 
Commission in Order No. 1920 is just and reasonable and not unduly 
discriminatory.\2098\ We find that the Commission's authority is 
plainly stated in FPA section 206 to evaluate rates and practices to 
determine whether they are unjust and unreasonable or unduly 
discriminatory or preferential, and, if so, prescribe a replacement 
rate that is just and reasonable and not unduly discriminatory or 
preferential. On its face, the federal right of first refusal for 
right-sized replacement transmission facilities is an exercise of that 
authority, as discussed above.
---------------------------------------------------------------------------

    \2097\ See id. at 32-40 (arguing that Order No. 1920 departs 
from the approach of previous Commission orders seeking to curtail 
transmission provider self-interest and challenging the Commission's 
rationale for adopting the federal right of first refusal for right-
sized replacement transmission facilities); id. at 35-36 (arguing 
that the rationale of Orangeburg, S.C. v. FERC, 862 F.3d 1071 
(2017), and the Commission's findings in Order No. 1000, require the 
elimination of disparate treatment of nonincumbent transmission 
providers); id. at 36-40 (arguing that FPA section 206 requires 
``elimination of preferential rates or practices affecting rates'' 
and that the federal right of first refusal for right-sized 
replacement transmission facilities is inconsistent with this 
requirement, that the Commission cannot ``ignore its prior 
declaration that rights of first refusal are unduly discriminatory 
or preferential,'' and that Order No. 1920 is disingenuous in 
distinguishing precedent or claiming that it is not creating a ``new 
preference''); cf. id. at 29-32 (discussing Order Nos. 1000 and 
1000-A, arguing that because the Commission rejected ``monopoly 
preference provisions'' in those orders, even applying a heightened 
contract review, there is ``no support for an assumption that the 
Commission enjoys Congressionally granted authority to simply create 
a federally sanctioned `cartel-like' monopoly preference'').
    \2098\ See supra The Commission Demonstrated that the 
Replacement Rate is Just and Reasonable section.
---------------------------------------------------------------------------

B. Enhanced Transparency of Local Transmission Planning Inputs in the 
Regional Transmission Planning Process

1. Order No. 1920
    847. In Order No. 1920, the Commission required transmission 
providers to revise the regional transmission planning process in their 
OATTs to enhance the transparency of: (1) the criteria, models, and 
assumptions that they use in their local transmission planning process; 
(2) the local transmission needs that they identify through the local 
transmission planning process; and (3) the potential local or regional 
transmission facilities that they will evaluate to address those local 
transmission needs.\2099\ Specifically, the Commission required that 
the regional transmission planning process include at least three 
publicly noticed stakeholder meetings per regional transmission 
planning cycle concerning the local transmission planning process of 
each transmission provider that is a member of the transmission 
planning region before each transmission provider's local transmission 
plan can be incorporated into the transmission planning region's 
planning models.\2100\ The Commission stated that the requirement to 
establish this process ensures that stakeholders have meaningful 
opportunities to participate in and provide feedback on local 
transmission planning throughout the regional transmission planning 
process.\2101\ The Commission also clarified that these requirements 
applied only to local transmission planning that is within the scope of 
Order No. 890 and is therefore already subject to Order No. 890 
transparency requirements. As such, the Commission stated, this 
requirement does not apply to asset management projects.\2102\
---------------------------------------------------------------------------

    \2099\ Order No. 1920, 187 FERC ] 61,068 at P 1625.
    \2100\ Id. P 1626.
    \2101\ Id.
    \2102\ Id. P 1625 (citing S. Cal. Edison Co., 164 FERC ] 61,160, 
at PP 30-40 (2018); Cal. Pub. Utils. Comm'n v. Pac. Gas. & Elec. 
Co., 164 FERC ] 61,161, at PP 65-74 (2018) (finding that Order No. 
890's local transmission planning requirements do not apply to asset 
management projects that do not increase capacity or do so 
incidentally)).
---------------------------------------------------------------------------

    848. The Commission required that prior to the submission of local 
transmission planning information to the transmission planning region 
for inclusion in the regional transmission planning process, 
transmission providers in each transmission planning region must 
convene, collectively, as part of the regional transmission planning 
process, a stakeholder meeting to review the criteria, assumptions, and 
models related to each transmission provider's local transmission 
planning (Assumptions Meeting).\2103\ Furthermore, the Commission 
required that no fewer than 25 calendar days after the Assumptions 
Meeting, transmission providers in each transmission planning region 
must convene, collectively, as part of the regional transmission 
planning process a stakeholder meeting to review identified reliability 
criteria violations and other transmission needs that drive the need 
for local transmission facilities (Needs Meeting).\2104\ Finally, the 
Commission required that, no fewer than 25 calendar days after the 
Needs Meeting, transmission providers in each transmission planning 
region must convene, collectively, as part of the regional transmission 
planning process, a stakeholder meeting to review potential solutions 
to those reliability criteria violations and other transmission needs 
(Solutions Meeting).\2105\
---------------------------------------------------------------------------

    \2103\ Id. P 1627.
    \2104\ Id.
    \2105\ Id.
---------------------------------------------------------------------------

    849. Additionally, the Commission required that the materials for 
stakeholder review during these three meetings be publicly posted and 
that stakeholders have opportunities before and after each meeting to 
submit comments.\2106\ Specifically, the Commission required 
transmission providers to publicly post the meeting materials no fewer 
than five calendar days prior to each of the three publicly noticed 
stakeholder meetings to allow time for stakeholders to review materials 
in advance of each meeting.\2107\ The Commission also required that 
transmission providers allow for a period of no fewer than 25 calendar 
days following the Solutions Meeting to review and consider stakeholder 
feedback on the local transmission solutions identified to meet the 
local transmission needs before the local transmission plan can be 
incorporated in the transmission planning region's planning 
models.\2108\ Lastly, the Commission required that transmission 
providers must respond to questions or comments from stakeholders such 
that it allows stakeholders to meaningfully participate in these three 
required stakeholder meetings.\2109\
---------------------------------------------------------------------------

    \2106\ Id.
    \2107\ Id. P 1628.
    \2108\ Id.
    \2109\ Id.
---------------------------------------------------------------------------

    850. In Order No. 1920, the Commission declined to adopt 
alternatives requested by commenters to this set of reforms because 
such proposals were not included in the NOPR and, as a result, the 
requests were beyond the scope of the proceeding.\2110\ The Commission 
noted, however, that several of these issues may be examined in the 
Commission's ongoing Transmission Planning and Cost Management 
proceeding.\2111\
---------------------------------------------------------------------------

    \2110\ Id. P 1648.
    \2111\ Transmission Planning and Cost Management, Notice of 
Technical Conference, Docket No. AD22-8-000 (Apr. 21, 2022).
---------------------------------------------------------------------------

2. Requests for Additional Reforms
a. Requests for Rehearing and Clarification
    851. Several parties request rehearing of the Commission's decision 
to exclude asset management projects from the local transmission 
planning

[[Page 97331]]

transparency requirements in the final rule.\2112\ Old Dominion states 
that the Commission failed to address the lack of meaningful 
transparency in local transmission planning by deciding to exclude 
asset management projects from the local transmission planning 
transparency requirements, which it argues is an error that will 
perpetuate unjust and unreasonable rates.\2113\ Further, Old Dominion 
contends that the Commission's assertion that there is not sufficient 
record evidence or that it would be outside the scope of the proceeding 
to adopt reforms that were not proposed in the NOPR is unreasonable and 
inconsistent with other aspects of the final rule where the Commission 
adopted proposals that were neither supported by sufficient record 
evidence nor included in the NOPR.\2114\ Old Dominion states that if 
the Commission does not grant rehearing on this issue, then the 
Commission should undertake further reforms for local transmission 
planning, such as in Docket No. AD22-8-000.\2115\
---------------------------------------------------------------------------

    \2112\ NESCOE Rehearing Request at 26-31; Ohio Commission 
Federal Advocate Rehearing Request at 21-24; Old Dominion Rehearing 
Request at 4, 5-9.
    \2113\ Old Dominion Rehearing Request at 5, 9.
    \2114\ Id. at 5-6, 8 (contending that Order No. 1920 prohibits 
different cost allocation methods for economic, reliability, and 
public policy requirements, which the Commission did not propose in 
the NOPR).
    \2115\ Id. at 9.
---------------------------------------------------------------------------

    852. NESCOE states that the Commission's decision to exclude asset 
management projects \2116\ from the scope of the local transmission 
planning transparency enhancements does not constitute reasoned 
decision-making, because the final rule does not sufficiently address 
concerns that asset condition projects are not subject to sufficient 
transparency, scrutiny, and review requirements.\2117\ NESCOE further 
argues that, despite the Commission's acknowledgement that reforms are 
needed to ensure regional transmission planning and cost allocation are 
just and reasonable, the Commission's failure to adopt such reforms 
based on a single-sentence rationale demonstrates that the Commission 
has not ``made a reasoned decision based upon substantial evidence in 
the record,'' nor has it ``articulate[d] a satisfactory explanation for 
its action including a rational connection between the facts found and 
the choice made.'' \2118\ NESCOE argues that the exemption of asset 
management projects from the local transmission planning transparency 
requirements results in a regulatory gap where transmission costs are 
unreviewed at both the state and federal level.\2119\ NESCOE contends 
that this is a particularly acute concern in New England where, since 
February 2023, transmission owners have brought $3.3 billion in asset 
management projects through ISO-NE's Planning Advisory Committee.\2120\
---------------------------------------------------------------------------

    \2116\ NESCOE notes that these in-kind replacement projects are 
known as asset condition projects in New England. NESCOE Rehearing 
Request at 6.
    \2117\ Id. at 26-33, 34.
    \2118\ Id. at 30-31 (citing Cal. Pub. Utils. Comm'n v. FERC, 20 
F.4th at 800).
    \2119\ Id. at 29.
    \2120\ Id. at 28.
---------------------------------------------------------------------------

    853. Ohio Commission Federal Advocate argues that the Commission's 
adoption of ``perfunctory'' transparency reforms for local planning 
processes was arbitrary and capricious, and will do nothing to close 
the regulatory gap or provide oversight for local projects.\2121\ Ohio 
Commission Federal Advocate notes that given the increasing portion of 
transmission facilities that are considered ``supplemental projects'' 
\2122\ in PJM, the reforms adopted in Order No. 1920 do little to shift 
the scales and the reforms may increase the portion of the transmission 
system built through a local transmission planning process.\2123\ As 
such, Ohio Commission Federal Advocate contends that the Commission 
neglected its duty under the FPA to ensure just and reasonable rates by 
imposing reforms that will not curb rising transmission costs or result 
in holistic transmission planning.\2124\
---------------------------------------------------------------------------

    \2121\ Ohio Commission Federal Advocate Rehearing Request at 21-
22.
    \2122\ In PJM, ``supplemental projects'' is the term used for 
local projects. Id. at 23.
    \2123\ Id.at 23-24.
    \2124\ Id. at 21, 23.
---------------------------------------------------------------------------

    854. Industrial Customers request rehearing and argue the 
Commission failed to engage requests that call for implementation of an 
independent transmission monitor. Given the increase in spending on 
transmission projects, Industrial Customers argue that clarifying or 
expanding existing independent market monitor functions or creating an 
independent transmission monitor would be a timely and appropriate 
exercise of the Commission's authority to remedy unjust and 
unreasonable rates.\2125\ Moreover, Industrial Customers contend that 
Order No. 1920 falls short of ensuring just and reasonable rates 
because it does not undertake reforms of transmission formula rates or 
the Commission's prudence standard.\2126\ Industrial Customers argue 
that since Order No. 1920 failed to implement any concrete reforms to 
protect consumers, rehearing is warranted.\2127\
---------------------------------------------------------------------------

    \2125\ Industrial Customers Rehearing Request at 29-31.
    \2126\ Id. at 33-34.
    \2127\ Id. at 38.
---------------------------------------------------------------------------

    855. PIOs request rehearing arguing that the Commission has 
sidestepped evidence that they and other parties offered when the 
Commission concluded that certain suggestions regarding the local 
transmission planning process were outside the scope of the 
proceeding.\2128\ PIOs argue that while Order No. 1920's reforms take 
some steps in the right direction, Order No. 1920 does not actually 
require the kind of comprehensive information transparency, scenario-
based planning, multi-benefit analysis, and process coordination 
necessary for stakeholders to verify whether local transmission 
projects are prudent or whether a regional solution is more 
appropriate.\2129\ PIOs argue that the Commission must require 
transmission providers to meet their burden under FPA section 205(e) to 
prove that their local transmission projects are the least-cost way to 
meet the needs of the transmission system. PIOs further argue the 
Commission should grant rehearing to ensure that utilities only 
construct local transmission projects when they are the best option for 
maintaining reliability and at least cost to consumers.\2130\
---------------------------------------------------------------------------

    \2128\ PIOs Rehearing Request at 50.
    \2129\ Id. at 51-52.
    \2130\ Id. at 53-54 (citing Ky. Mun. Energy Agency v. FERC, 45 
F.4th 162, 178 (D.C. Cir. 2022)) (other citations omitted).
---------------------------------------------------------------------------

b. Commission Determination
    856. We sustain the determination in Order No. 1920 to exclude 
asset management projects from the information on local transmission 
planning inputs that transmission providers must include for 
stakeholder review as part of the Assumptions, Needs, and Solutions 
Meetings. We reiterate that planning for asset management projects, 
which do not increase transmission capacity or only do so incidentally, 
is not required to be included within the scope of local transmission 
planning that is subject to Order No. 890 transparency 
requirements,\2131\ and as such, it was reasonable for the Commission 
to exclude them from the requirements in Order No. 1920.\2132\ 
Moreover, the Commission did not propose in the NOPR to require 
transmission providers

[[Page 97332]]

to include information related to asset management projects in the 
information that they provide as part of the Assumptions, Needs, and 
Solutions Meetings. Instead, to enhance stakeholders' visibility into 
local transmission planning inputs as they are integrated into the 
regional transmission planning process, the Commission proposed in the 
NOPR--and adopted in the final rule--requirements to enhance the 
transparency of such inputs, which are already subject to the local 
transmission planning transparency requirements of Order No. 890, in 
the regional transmission planning process.\2133\ We continue to expect 
these reforms to enhance the transparency between the local and 
regional transmission planning processes, which will help reduce the 
possibility that transmission providers will develop local transmission 
facilities without adequately considering whether there is a more 
efficient or cost-effective regional transmission solution that could 
address their local transmission needs.\2134\ That said, we note that 
nothing in Order No. 1920 prevents transmission providers from choosing 
to apply Order No. 1920's requirements to enhance the transparency of 
local transmission planning inputs to asset management projects.
---------------------------------------------------------------------------

    \2131\ Order No. 1920, 187 FERC ] 1625 (citing S. Cal. Edison 
Co., 164 FERC ] 61,160 at PP 30-40; Cal. Pub. Utils. Comm'n v. Pac. 
Gas. & Elec. Co., 164 FERC ] 61,161 at PP 65-74 (finding that Order 
No. 890's local transmission planning requirements do not apply to 
asset management projects that do not increase capacity or do so 
incidentally)).
    \2132\ Id. P 1625.
    \2133\ NOPR, 179 FERC ] 61,028 at P 398 (identifying the need 
for reform based in part on a finding that ``implementation of [the 
Order No. 890 local transmission planning principles] in local 
transmission planning processes appears to remain uneven'', and that 
``reforms to better ensure more consistent implementation of these 
principles may be timely''); id. P 400 (proposing to require 
transmission providers to revise their OATTs ``to enhance 
transparency of: (1) the criteria, models, and assumptions that they 
use in their local transmission planning process; (2) the local 
transmission needs that they identify through that process; and (3) 
the potential local or regional transmission facilities that they 
will evaluate to address those local transmission needs.''); id. P 
402 (stating that ``requirements are needed to ensure just and 
reasonable Commission-jurisdictional rates because the information 
provided will better facilitate the identification of regional 
transmission facilities''); Order No. 1920, 187 FERC ] 61,068 at P 
1625 (clarifying that the requirement ``applies only to local 
transmission planning that is within the scope of Order No. 890 and 
is therefore already subject to Order No. 890 transparency 
requirements'' and does not apply to asset management projects)).
    \2134\ Order No. 1920, 187 FERC ] 61,068 at P 1629.
---------------------------------------------------------------------------

    857. We disagree with parties that request rehearing on the grounds 
that the Commission's decision-making was arbitrary and capricious or 
failed to consider the record evidence. Further, we disagree with Ohio 
Commission Federal Advocate that the Commission neglected its duty 
under the FPA to ensure just and reasonable rates. We continue to find, 
as we found in Order No. 1920, that the enhanced transparency 
requirements are specifically designed to provide needed transparency 
to ensure that Commission-jurisdictional rates are just and reasonable 
and not unduly discriminatory or preferential.\2135\ As such, we find 
that the scope of the relevant reforms required by Order No. 1920 is 
sufficient to remedy the deficiencies in local transmission planning 
that the Commission set out to resolve in Order No. 1920, even if some 
parties would have preferred that the Commission had gone 
further.\2136\
---------------------------------------------------------------------------

    \2135\ Id. P 1632.
    \2136\ See New York v. FERC, 531 U.S. at 26-27 (affirming that 
the Commission did not have an obligation extend its open access 
remedy to bundled retail transmissions because the remedy it ordered 
constituted a sufficient response to the problems the Commission had 
identified in the wholesale market).
---------------------------------------------------------------------------

    858. For similar reasons, we are unpersuaded by Industrial 
Customers' and PIOs' requests for additional reforms to transmission 
planning processes generally. The proposals raised by these parties in 
their rehearing requests were not included in either the NOPR or Order 
No. 1920 and, as noted above, we find that the relevant reforms 
required pursuant to Order No. 1920 are sufficient to remedy the 
problem that Order No. 1920 set out to solve.\2137\ The Commission will 
continue to consider potential additional local transmission planning 
reforms, such as independent transmission monitors, along with other 
transmission reforms in the future.\2138\
---------------------------------------------------------------------------

    \2137\ See Order No. 1920, 187 FERC ] 61,068 at PP 1648, 1737.
    \2138\ We note, for example, the ongoing proceeding in Docket 
No. AD22-8-000 on Transmission Planning and Cost Management.
---------------------------------------------------------------------------

3. Stakeholder Meeting Clarifications
a. Request for Rehearing and Clarification
    859. SERTP Sponsors request clarification that the standard for 
evaluating transmission providers' obligation to respond to stakeholder 
feedback is consistent with Order No. 890 and applies equally to local, 
regional, and Long-Term Regional Transmission Planning.\2139\ 
Specifically, SERTP Sponsors assert that further clarification is 
necessary with respect to the Commission's statement that transmission 
providers are encouraged ``to be as responsive as possible to 
stakeholder comments and questions'' because this statement could be 
read to go beyond standards previously established in Order No. 890 and 
expand transmission providers' obligation to respond beyond what is 
necessary to support meaningful participation in stakeholder 
meetings.\2140\ Thus, SERTP Sponsors request that the Commission 
clarify that transmission providers are not obligated to incorporate 
stakeholder proposals or comments into their transmission plans and 
that the ultimate transmission planning responsibility is with the 
transmission provider.\2141\
---------------------------------------------------------------------------

    \2139\ SERTP Sponsors Rehearing Request at 23-24.
    \2140\ Id. at 24 (citing Order No. 1920, 187 FERC ] 61,068 at P 
1645) (emphasis omitted).
    \2141\ Id.
---------------------------------------------------------------------------

    860. Regarding the Assumptions Meeting, the Needs Meeting, and the 
Solutions Meeting, SERTP Sponsors also request that the Commission 
clarify that these meetings of different transmission providers do not 
need to be held as one. SERTP Sponsors explain that their transmission 
planning region consists of multiple transmission providers over a 12-
state footprint, and they contend that the Commission should clarify 
that this requirement can be satisfied by a single transmission 
provider holding separate meetings that include its own Assumptions, 
Needs, and Solutions Meetings.\2142\ SERTP Sponsors assert that, in the 
event that the Commission does not so clarify, the requirements for the 
Assumptions Meeting, the Needs Meeting, and the Solutions Meeting may 
become unduly burdensome and inconsistent with Order No. 1920's 
requirement, which is based on the model used by PJM's transmission 
owners to hold separate meetings for different local transmission 
owners' local plans.\2143\ SERTP Sponsors argue that holding 
``collective'' Assumptions, Needs, and Solutions Meetings is 
unnecessary to achieve the Commission's transparency objections, and 
further contends that requiring so would be an unexplained departure 
from the PJM precedent and otherwise arbitrary and capricious.\2144\
---------------------------------------------------------------------------

    \2142\ Id. at 24-25.
    \2143\ Id. at 25.
    \2144\ Id. at 25 (citations omitted).
---------------------------------------------------------------------------

b. Commission Determination
    861. We clarify, in response to SERTP Sponsors' request, that 
transmission providers are not obligated to incorporate stakeholder 
proposals or comments resulting from the stakeholder meeting process 
into their transmission plans, and we agree with SERTP Sponsors that 
the ultimate transmission planning responsibility remains with the 
transmission provider.\2145\ In encouraging transmission providers to 
be as responsive as possible to stakeholder comments and questions as 
part of the stakeholder meeting process, the Commission in Order No. 
1920 did not establish new requirements for

[[Page 97333]]

transmission providers that did not previously apply; rather, the 
description of the requirement that transmission providers respond to 
questions or comments in a manner that allows stakeholders to 
meaningfully participate in the stakeholder meetings explains existing 
requirements established under Order No. 890 and that apply to local 
transmission planning processes, existing Order No. 1000 regional 
transmission planning processes, and Long-Term Regional Transmission 
Planning processes.\2146\
---------------------------------------------------------------------------

    \2145\ Id. at 24.
    \2146\ See Order No. 890, 118 FERC ] 61,119 at P 452 
(``Transmission providers are, however, required to craft a process 
that allows for a reasonable and meaningful opportunity to meet or 
otherwise interact meaningfully.''); id. P 454 (``This means that 
customers must be included at the early stages of the development of 
the transmission plan and not merely given an opportunity to comment 
on transmission plans that were developed in the first instance 
without their input.''); id. P 488 (``The transmission planning 
required by this Final Rule is intended to provide transmission 
customers and other stakeholders a meaningful opportunity to engage 
in planning along with their transmission providers.'').
---------------------------------------------------------------------------

    862. In response to SERTP Sponsors' request that the Commission 
clarify that the stakeholder meetings of the different transmission 
providers do not need to be held collectively as a single 
meeting,\2147\ we agree and clarify that, provided that the 
transmission provider meets the requirements of Order No. 1920 with 
respect to public notices and opportunities for stakeholders to submit 
comments before and after each meeting, transmission providers need not 
hold a single stakeholder meeting among all transmission providers in a 
transmission planning region. We recognize that transmission planning 
regions often cover significant geographic range and are comprised of 
many diffuse transmission providers, such that imposing a requirement 
that each stakeholder meeting includes all transmission providers and 
stakeholders may create undue burden and impede meaningful 
participation. Instead, transmission providers may hold separate 
Assumptions Meetings, Needs Meetings, and Solutions Meetings for 
individual transmission providers within a transmission planning 
region, provided that the process ensures that stakeholders have 
meaningful opportunities to participate in and provide feedback on 
local transmission planning information throughout the regional 
transmission planning process and otherwise meets all the Order No. 
1920 requirements described above.
---------------------------------------------------------------------------

    \2147\ SERTP Sponsors Rehearing Request at 25.
---------------------------------------------------------------------------

C. Identifying Potential Opportunities to Right-Size Replacement 
Transmission Facilities

1. Eligibility
a. Order No. 1920
    863. In Order No. 1920, the Commission required transmission 
providers, as part of each Long-Term Regional Transmission Planning 
cycle, to evaluate whether transmission facilities (1) operating above 
a specified kV threshold and (2) that an individual transmission 
provider that owns the transmission facility anticipates replacing in-
kind with a new transmission facility during the next 10 years, can be 
``right-sized'' to more efficiently or cost-effectively address a Long-
Term Transmission Need.\2148\ The Commission also required that each 
transmission provider submit its in-kind replacement estimates (i.e., 
estimates of the transmission facilities operating at and above the 
specified kV threshold that an individual transmission provider that 
owns the transmission facilities anticipates replacing in-kind with a 
new transmission facility during the next 10 years) for use in Long-
Term Regional Transmission Planning sufficiently early in each Long-
Term Regional Transmission Planning cycle.\2149\
---------------------------------------------------------------------------

    \2148\ Order No. 1920, 187 FERC ] 61,068 at P 1677.
    \2149\ Id.
---------------------------------------------------------------------------

    864. The Commission further adopted the NOPR proposal to define 
``right-sizing'' as the process of modifying a transmission provider's 
in-kind replacement of an existing transmission facility to increase 
that facility's transfer capability.\2150\ The Commission clarified 
that, for the purposes of the right-sizing reform, an ``in-kind 
replacement transmission facility'' is a new transmission facility 
that: (1) would replace an existing transmission facility that a 
transmission provider has identified in its in-kind replacement 
estimate as needing to be replaced; (2) would result in no more than an 
incidental increase in capacity over the existing transmission facility 
identified as needing to be replaced; and (3) is located in the same 
general route as, and/or uses the existing rights-of-way of, the 
existing transmission facility identified as needing to be 
replaced.\2151\
---------------------------------------------------------------------------

    \2150\ Id. P 1678 & n.3580.
    \2151\ Id. P 1678.
---------------------------------------------------------------------------

    865. Similarly, the Commission also clarified that, for the 
purposes of the right-sizing reform, a ``right-sized replacement 
transmission facility'' is a new transmission facility that: (1) would 
meet the need to replace an existing transmission facility that a 
transmission provider has identified in its in-kind replacement 
estimate as one that it plans to replace with an in-kind replacement 
transmission facility while also addressing a Long-Term Transmission 
Need; (2) results in more than an incidental increase in the capacity 
of an existing transmission facility that a transmission provider has 
identified for replacement in its in-kind replacement estimate; and (3) 
is located in the same general route as, and/or uses or expands the 
existing rights-of-way of, the existing transmission facility that a 
transmission provider has identified for replacement in its in-kind 
replacement estimate.\2152\
---------------------------------------------------------------------------

    \2152\ Id. P 1679.
---------------------------------------------------------------------------

    866. In Order No. 1920, the Commission also required transmission 
providers to establish a multi-step process in their OATTs that 
provides for the implementation of the right-sizing reform. 
Specifically, the Commission required that transmission providers in 
each transmission planning region must propose a point sufficiently 
early in each Long-Term Regional Transmission Planning cycle at which 
each individual transmission provider in the transmission planning 
region will submit its in-kind replacement estimates for use in Long-
Term Regional Transmission Planning.\2153\ Next, the Commission 
required that, if transmission providers identify a right-sized 
replacement transmission facility as a potential solution to a Long-
Term Transmission Need as part of Long-Term Regional Transmission 
Planning, that right-sized replacement transmission facility must be 
evaluated in the same manner as any other proposed Long-Term Regional 
Transmission Facility to determine whether it is the more efficient or 
cost-effective transmission facility to address the transmission 
need.\2154\ The Commission clarified that it is at this stage that 
transmission providers must use the in-kind replacement estimates to 
determine if in-kind replacement transmission facilities could be 
right-sized to more efficiently or cost-effectively address a Long-Term 
Transmission Need(s).\2155\ Finally, the Commission required that, if a 
right-sized replacement transmission facility addresses the 
transmission provider's need to replace an existing transmission 
facility, meets the applicable selection criteria included in Long-Term 
Regional Transmission Planning, and is found to be the more efficient 
or cost-effective solution, then the right-sized

[[Page 97334]]

replacement transmission facility must be considered for 
selection.\2156\
---------------------------------------------------------------------------

    \2153\ Id. P 1681.
    \2154\ Id.
    \2155\ Id.
    \2156\ Id. As explained in the Right of First Refusal section 
below, the Commission required the establishment of a federal right 
of first refusal for a right-sized replacement transmission facility 
that is selected to meet Long-Term Transmission Needs. Id. P 1702.
---------------------------------------------------------------------------

    867. The Commission further required that, for the purposes of 
implementing the right-sizing reform, transmission providers must 
propose on compliance a threshold that does not exceed 200 kV to be 
used in identifying transmission facilities that an individual 
transmission provider anticipates replacing in-kind with a new 
transmission facility during the next 10 years, which it must then 
include in its in-kind replacement estimates.\2157\ The Commission 
clarified that the 10-year timeframe for in-kind replacement estimates 
should reflect a transmission provider's estimates of the transmission 
facilities operating at and above the specified kV threshold that an 
individual transmission provider that owns the transmission facility 
anticipates replacing in-kind with a new transmission facility during 
the next 10 years beginning at the start of each Long-Term Regional 
Transmission Planning cycle.\2158\
---------------------------------------------------------------------------

    \2157\ Id. PP 1677, 1683 & n.3584.
    \2158\ Id. at P 1685.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    868. In its rehearing request, Advanced Energy argues that the term 
``right-sized replacement facility'' is too vague.\2159\ Competition 
Coalition argues that the definition of the term ignores Order No. 
1000-A because the Commission has already determined in Order No. 1000-
A that the replacement of an entire transmission facility is an 
entirely new transmission facility.\2160\ Competition Coalition notes 
that, in Order No. 1000-A, the Commission addressed the issue of 
granting a preference for an incumbent transmission owner to build a 
transmission project for upgrades and not an entirely new transmission 
facility, determining that an upgrade involves the replacement of only 
part of an existing facility.\2161\ Competition Coalition argues that 
since Order No. 1920 fails to acknowledge the justification for the 
Commission's departure from existing Commission precedent that limits 
retention of a preference only for a regional transmission project that 
represents a replacement of part of an existing transmission facility 
and not the replacement of an entire transmission facility, Order No. 
1920 is arbitrary and capricious.\2162\
---------------------------------------------------------------------------

    \2159\ Advanced Energy Rehearing Request at 14-15 (citing Order 
No. 1920, 187 FERC ] 61,068 at P 1678).
    \2160\ Competition Coalition Rehearing Request at 51-57 (citing 
Order No. 1000-A, 139 FERC ] 61,132 at P 426; NYISO, 151 FERC ] 
61,040 at P 96 (additional citation omitted)).
    \2161\ Competition Coalition at 51-52 (citing Order No. 1000-A, 
139 FERC ] 61,132 at P 426).
    \2162\ Id. at 52.
---------------------------------------------------------------------------

    869. Similarly, some petitioners argue that Order No. 1920's 
findings regarding rights-of-way are flawed or inconsistent with 
Commission precedent.\2163\ For example, Advanced Energy highlights 
that language regarding the ``same general route as, and/or use [ ] the 
existing rights-of-way of, the existing transmission facility 
identified as needing to be replaced'' could require anything from zero 
land acquisition cost (if the facility is entirely within a wholly 
owned right-of-way) to millions of dollars (if the facility is entirely 
outside of an existing right-of-way but follows the same general 
route).\2164\ Advanced Energy argues that, given such vagueness, to 
have the chance of passing muster under the APA, the Commission should 
remove this ambiguity by limiting any right of first refusal to a 
right-sized replacement facility that is entirely within existing, 
permanent rights-of-way.\2165\ NESCOE similarly argues that the final 
rule's lack of a definition of ``general route'' or discussion of why 
it is appropriate to use a vague term in place of the well-established 
``rights-of-way'' necessitates the Commission to act to fulfill its 
statutory duty under the FPA and that, as written, the right-sizing 
reform could be interpreted to the detriment of consumers.\2166\
---------------------------------------------------------------------------

    \2163\ Advanced Energy Rehearing Request at 14-15 (citing Order 
No. 1920, 187 FERC ] 61,068 at P 1678); Competition Coalition 
Rehearing Request at 57-59 (citing Order No. 1920, 187 FERC ] 61,068 
at P 1678; MISO, 147 FERC ] 61,127 at P 244; NYISO, 151 FERC ] 
61,040 at P 96).
    \2164\ Advanced Energy Rehearing Request at 14 (citing Order No. 
1920, 187 FERC ] 61,068 at P 1678).
    \2165\ Id. at 14-15.
    \2166\ NESCOE Rehearing Request at 32-33.
---------------------------------------------------------------------------

    870. Competition Coalition argues that the Commission's right-
sizing reform contravenes existing Commission precedent regarding the 
use of rights-of-way, noting that, under Order No. 1000-A, the 
Commission found that the use of an existing right-of-way is not 
determinative of whether the facility is a new transmission facility 
but rather the relevant issue was ``whether the new transmission 
facility is an upgrade to an incumbent transmission provider's own 
facilities.'' \2167\ Competition Coalition further points to Commission 
rejection of a proposal from MISO to give preference to transmission 
owners for facilities built on the existing rights-of-way since the 
Commission determined that issues surrounding rights-of-way is an issue 
for the authority granting the rights-of-way.\2168\
---------------------------------------------------------------------------

    \2167\ Competition Coalition Rehearing Request at 57-58 (citing 
Order No. 1000-A, 139 FERC ] 61,132 at P 427).
    \2168\ Id. (citing MISO, 147 FERC ] 61,127 at P 244).
---------------------------------------------------------------------------

    871. Competition Coalition argues that the OATT language associated 
with the right-sizing reform is ambiguous, unworkable, and will cause 
confusion and litigation.\2169\ Competition Coalition highlights the 
terms ``anticipates,'' ``right-sizing,'' ``as discussed in Order No. 
1920,'' ``not to exceed 200 kV,'' ``more efficiently,'' and ``cost-
effectively'' as being undefined in the final rule.\2170\ Competition 
Coalition also contends that the absence of OATT language that gives an 
independent entity the responsibility to carry out and administer 
right-sizing opportunities or monitor against potential planning abuses 
confirms the need for an independent transmission system planner or 
monitor.\2171\
---------------------------------------------------------------------------

    \2169\ Id. at 72.
    \2170\ Id. at 73-74.
    \2171\ Id. at 74.
---------------------------------------------------------------------------

    872. In its rehearing request, Dominion requests clarification of 
the proposed 200 kV threshold for determining whether a transmission 
facility is eligible for right-sizing.\2172\ Specifically, Dominion 
explains that while the Commission refers to a ``maximum threshold,'' 
Dominion seeks clarification that the use of the word ``maximum'' does 
not foreclose evaluation of projects above and below that threshold. 
Dominion explains that, in simpler terms, transmission providers must 
consider for right-sizing purposes all transmission facilities with 
projected in-kind replacements currently operating at or above 200 kV, 
but they may propose a lower threshold on compliance.\2173\
---------------------------------------------------------------------------

    \2172\ Dominion Rehearing Request at 35.
    \2173\ Id. at 35-36.
---------------------------------------------------------------------------

c. Commission Determination
    873. We sustain our findings in response to Advanced Energy's, 
Competition Coalition's, and NESCOE's rehearing requests pertaining to 
the term ``right-sized replacement facility.'' As the Commission 
explained in Order No. 1920, the right-sizing reform was adopted, as 
modified from the NOPR proposal, with additional requirements to ensure 
that the use of the right-sizing reform addresses replacement 
transmission facilities and not entirely new transmission 
facilities.\2174\ As

[[Page 97335]]

highlighted in Order No. 1920, a right-sized replacement transmission 
facility would replace the existing transmission facility that the 
transmission provider included in its in-kind replacement estimate, and 
extends to any portion of the right-sized replacement facility located 
within a given transmission provider's retail distribution service 
territory or footprint.\2175\ The Commission found that a right-sized 
replacement transmission facility has the potential to both meet an 
individual transmission provider's responsibility to maintain the 
reliability of its existing transmission system and address a Long-Term 
Transmission Need more efficiently or cost-effectively than an in-kind 
replacement transmission facility or another Long-Term Regional 
Transmission Facility.\2176\
---------------------------------------------------------------------------

    \2174\ Id. P 1679.
    \2175\ Id. P 1702.
    \2176\ Id. P 1682.
---------------------------------------------------------------------------

    874. In response to Competition Coalition's argument that Order No. 
1920 is inconsistent with Order No. 1000-A, which specified that 
upgrades do not include entirely new transmission facilities, we note 
that the Commission is entitled to change its approach and depart from 
prior precedent, provided that it acknowledges the change in policy and 
provides a reasoned explanation for the new approach.\2177\ We 
acknowledge that in Order No. 1920, the Commission, with explanation, 
departed from its precedent in Order No. 1000-A, as well as in MISO and 
NYISO.\2178\ In Order No. 1920, the Commission explicitly recognized 
that ``the establishment of a federal right of first refusal for right-
sized replacement transmission facilities is an exception to Order No. 
1000's general requirement for transmission providers to eliminate any 
federal right of first refusal for regional transmission facilities 
selected in a regional transmission plan.'' \2179\ However, the 
Commission found that the Commission's reasons for removing federal 
rights of first refusal in Order No. 1000 do not apply to right-sized 
replacement transmission facilities.\2180\ The Commission then 
explained at length why this is the case, satisfying the Commission's 
obligation to provide a reasoned explanation for its new policy.
---------------------------------------------------------------------------

    \2177\ FCC v. Fox Television Stations, Inc., 556 U.S. at 515-
516; In re Permian Basin Area Rate Cases, 390 U.S. 747, 784 (1968); 
see also State Farm, 463 U.S. at 42 (``[W]e fully recognize that 
regulatory agencies do not establish rules of conduct to last 
forever.'') (internal quotations omitted); Greater Bos. Television 
Corp. v. FCC, 444 F.2d 841, 852 (D.C. Cir. 1970) (an agency may 
change its course as long as it ``suppl[ies] a reasoned analysis 
indicating that prior policies and standards are being deliberately 
changed, not casually ignored.''), cert. denied, 403 U.S. 923 
(1971).
    \2178\ See MISO, 147 FERC ] 61,127 at P 238; NYISO, 151 FERC ] 
61,040 at P 96. In Order No. 1000-A, the Commission clarified that 
``the term upgrade means an improvement to, addition to, or 
replacement of a part of, an existing transmission facility. The 
term upgrades does not refer to an entirely new transmission 
facility.'' Order No. 1000-A, 139 FERC ] 61,132 at P 426.
    \2179\ Order No. 1920, 187 FERC ] 61,068 at P 1704.
    \2180\ Id. P 1706; see also Order No. 1920, 187 FERC ] 61,068 at 
P 1705 (explaining that Order No. 1000 required transmission 
providers to remove federal rights of first refusal from their OATTs 
because they undermined the consideration of more efficient or cost-
effective potential transmission solutions proposed at the regional 
level and created a barrier to entry that discouraged nonincumbent 
transmission developers from proposing alternative solutions at the 
regional level) (citations omitted).
---------------------------------------------------------------------------

    875. Specifically, the Commission found that requiring a federal 
right of first refusal for right-sized replacement transmission 
facilities does not undermine the consideration of more efficient or 
cost-effective potential transmission solutions at the regional level; 
instead, it will promote the consideration of potential regional 
transmission solutions to address Long-Term Transmission Needs.\2181\ 
When compared against the alternative of piecemeal development of in-
kind replacement facilities, the right-sizing reform ensures that Long-
Term Regional Transmission Planning considers a broader set of needs, 
including needs related to replacement of aging transmission 
infrastructure.\2182\ The Commission further stated that, absent a 
federal right of first refusal for right-sized replacement transmission 
facilities, the incumbent transmission provider whose in-kind 
replacement transmission facility is selected to be right-sized would 
likely proceed to develop the less efficient or cost-effective in-kind 
replacement transmission facility because it would prefer the assurance 
of a federal right of first refusal for the in-kind replacement 
transmission facility over the uncertainty of subjecting a right-sized 
replacement transmission facility to the Order No. 1000 competitive 
transmission development process.\2183\ Thus, the federal right of 
first refusal for right-sized replacement transmission facilities will 
remove a barrier to development of more efficient or cost-effective 
regional solutions that could encompass both replacements of aging 
transmission infrastructure and regional transmission solutions to 
address Long-Term Transmission Needs. Similarly, the Commission found 
that requiring the establishment of a federal right of first refusal 
for a right-sized replacement transmission facility that is selected to 
meet Long-Term Transmission Needs will encourage transmission providers 
to provide their best in-kind replacement estimates because they will 
have certainty that they will not lose the opportunity to invest in any 
in-kind replacement transmission facility that is then selected as a 
right-sized replacement transmission facility.\2184\
---------------------------------------------------------------------------

    \2181\ Id. P 1706.
    \2182\ Id.
    \2183\ Id.
    \2184\ Id. P 1703.
---------------------------------------------------------------------------

    876. The Commission found that, given this incentive structure and 
the fact that the transmission provider holds the leverage as to 
whether to build a right-sized replacement transmission facility or a 
less efficient in-kind replacement transmission facility, the 
establishment of a federal right of first refusal for right-sized 
replacement transmission facilities is necessary to effectuate the 
right-sizing reform and ensure that Commission jurisdictional rates are 
just and reasonable.\2185\ We sustain this finding, and we continue to 
conclude that a federal right of first refusal for right-sized 
replacement transmission facilities will remove a disincentive for 
transmission providers to consider right-sizing in Long-Term Regional 
Transmission Planning, helping to ensure that the more efficient or 
cost-effective regional transmission solution to Long-Term Transmission 
Needs is selected and likely built, and therefore that the Commission-
jurisdictional rates that customers pay are just and reasonable.\2186\ 
As such, we find that the Commission has provided a reasoned 
explanation for its decision to depart from prior precedent and require 
a federal right of first refusal for right-sized replacement 
transmission facilities.
---------------------------------------------------------------------------

    \2185\ Id. P 1706.
    \2186\ See id. P 1703.
---------------------------------------------------------------------------

    877. We are unpersuaded by Advanced Energy's, Competition 
Coalition's, and NESCOE's claims regarding the use of the term 
``rights-of-way'' in defining a right-sized replacement transmission 
facility. As in Order No. 1000, we find that the retention, 
modification, or transfer of rights-of-way remain subject to relevant 
law or regulation granting the rights-of-way,\2187\ and nothing in the 
definition of ``in-kind replacement transmission facility'' or ``right-
sized replacement transmission facility'' would affect the retention, 
modification, or transfer of rights-of-way. While we recognize Advanced 
Energy's argument that a right-sized replacement transmission facility 
may require additional land for a right-of-way, we decline to speculate 
on land acquisition costs because land acquisition costs vary from 
transmission

[[Page 97336]]

facility to transmission facility. In any case, the fact that there may 
be additional land acquisition costs does not, as Advanced Energy 
argues, render the definition of a right-sized replacement transmission 
facility vague. We note, however, that transmission providers could 
consider the potential for such costs when they are evaluating whether 
a particular right-sized replacement transmission facility is a more 
efficient or cost-effective regional transmission solution to address 
Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \2187\ Id. P 319.
---------------------------------------------------------------------------

    878. Moreover, we disagree that Order No. 1920's inclusion of the 
term ``general route'' in the definition of ``in-kind replacement 
transmission facility'' and ``right-sized replacement transmission 
facility'' renders those definitions vague. Rather, we find the term 
``general route,'' when read in the context of Order No. 1920's example 
detailing which transmission facilities would be eligible for right-
sizing,\2188\ makes clear that the right-sizing reform considers 
existing topology of the transmission system to ensure that the right-
sizing reform applies to replacement transmission facilities 
only.\2189\ We find that it is important to include this term to 
provide a reasonable bound of the definition of both in-kind 
replacement transmission facilities and right-sized replacement 
transmission facilities. Further, a right-sized replacement 
transmission facility may require changes to or expansions of rights-
of-way to accommodate that right-sized replacement transmission 
facility, and it is not feasible to list every type or circumstance 
that may bear upon existing rights-of-way. Accordingly, we find that 
the requirement for a right-sized replacement transmission facility to 
also be located in the same general route as the existing transmission 
facility identified for replacement provides a reasonable limitation on 
the location of such a right-sized replacement transmission facility. 
For example, if a transmission provider anticipates replacing an 
existing transmission facility because it has reached the end of its 
useful life and the replacement transmission facility (either in-kind 
or right-sized) requires modifications to that facility's rights-of-way 
to accommodate other infrastructure projects or avoid environmentally 
sensitive areas, those modifications to existing rights-of-way are 
permitted under the term ``same general route.'' We note that Order No. 
1920's example relied on interconnection points to describe which in-
kind replacement transmission facilities would be eligible for right-
sizing,\2190\ specifically, that a right-sized replacement transmission 
facility that connects the same interconnection points to which an in-
kind replacement transmission facility connects qualifies under the 
term ``same general route.'' We reiterate that these limitations are 
appropriate to ensure that the right-sizing reform applies to 
replacement transmission facilities only. For example, a new 
transmission facility would not qualify as a right-sized replacement 
transmission facility if it has significantly different interconnection 
points than the in-kind replacement facility.
---------------------------------------------------------------------------

    \2188\ Id. P 1680.
    \2189\ Id. PP 1678, 1679.
    \2190\ Id. P 1680.
---------------------------------------------------------------------------

    879. Furthermore, we find Competition Coalition's contention that 
the definition of ``right-sized replacement transmission facility'' is 
inconsistent with Order No. 1000 regarding the use of rights-of-way to 
be inapposite. In Order No. 1000, the Commission stated that the 
requirement to ``eliminate a federal right of first refusal does not 
apply to any upgrade, even where the upgrade requires the expansion of 
an existing right-of-way.'' \2191\ The Commission stated that ``[t]he 
issue is not whether the upgrade would be located in an existing right-
of-way, but whether the new transmission facility is an upgrade to an 
incumbent transmission provider's own facilities.'' \2192\ In other 
words, the Commission found in Order No. 1000 that whether a regional 
transmission facility does or does not require the expansion of an 
existing right-of-way is not relevant to whether that facility is an 
upgrade. In contrast, for the reasons discussed directly above, in 
Order No. 1920 the Commission found it necessary that, to qualify as a 
right-sized replacement transmission facility, a transmission facility 
must be located in the same general route as, and/or use or expand the 
existing rights-of-way of, the existing transmission facility that a 
transmission provider has identified for replacement in its in-kind 
replacement estimate.
---------------------------------------------------------------------------

    \2191\ Order 1000-A, 139 FERC ] 61,132 at P 427.
    \2192\ Id.
---------------------------------------------------------------------------

    880. We are unpersuaded by Competition Coalition's arguments 
regarding specific terminology in the right-sizing reform. However, we 
provide additional context for certain terms and phrases included in 
the right-sizing reform. We sustain the definition of ``right-sizing'' 
to mean ``the process of modifying a transmission provider's in-kind 
replacement of an existing transmission facility to increase that 
facility's transfer capability.'' \2193\ The Commission noted that 
right-sizing could include, for example, increasing the transmission 
facility's voltage level, adding circuits to the towers (e.g., 
redesigning a single-circuit line as a double circuit line), or 
incorporating advanced technologies (such as advanced conductor 
technologies).\2194\ Regarding the other terms highlighted by 
Competition Coalition, we find that, read in the context of the right-
sizing reform, as well as Order No. 1920, these terms are clear, and we 
disagree with Competition Coalition that the absence of independent 
transmission monitor language confirms the need for such an entity in 
the context of right-sizing.\2195\
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    \2193\ Order No. 1920, 187 FERC ] 61,068 at P 1678.
    \2194\ Id. P 1678 n.3580.
    \2195\ The Commission will continue to consider potential 
additional local transmission planning reforms, such as independent 
transmission monitors, along with other transmission reforms in the 
future. See supra Enhanced Transparency of Local Transmission 
Planning Inputs in the Regional Transmission Planning Process 
section.
---------------------------------------------------------------------------

    881. We grant clarification to Dominion's requests regarding the 
200 kV threshold for determining whether a transmission facility is 
eligible for right-sizing. We clarify that the Commission's finding in 
Order No. 1920 that the kV threshold must not exceed 200 kV means that 
transmission providers must include in their in-kind replacement 
estimates all transmission facilities operating at or above 200 kV that 
they anticipate replacing in-kind during the next 10 years. We also 
clarify that transmission providers may establish a threshold lower 
than 200 kV to ensure that a larger number of transmission facilities 
may be included. Put simply, transmission providers may propose a 
threshold for all transmission facilities that are eligible to be 
right-sized, so long as that threshold is under 200 kV.
2. Right of First Refusal for Right-Sized Replacement Transmission 
Facilities Selected To Meet Long-Term Transmission Needs
a. Order No. 1920
    882. In Order No. 1920, the Commission required the establishment 
of a federal right of first refusal for a right-sized replacement 
transmission facility that is selected to meet Long-Term Transmission 
Needs.\2196\ In adopting a federal right of first refusal requirement 
for a right-sized replacement transmission facility, the Commission 
noted that a federal right of first refusal is an exception to Order 
No. 1000's general requirement for transmission providers to eliminate 
any

[[Page 97337]]

federal right of first refusal for regional transmission facilities 
selected in a regional transmission plan.\2197\ The Commission 
explained that requiring a federal right of first refusal for right-
sized replacement transmission facilities does not undermine the 
consideration of more efficient or cost-effective potential 
transmission solutions proposed at the regional level; rather, the 
Commission found that it will promote the consideration of more 
efficient or cost-effective potential regional transmission solutions 
to address Long-Term Transmission Needs. Further, the Commission 
explained that, when compared against the alternative of piecemeal 
development of in-kind replacement transmission facilities, the right-
sized replacement transmission facility represents the more efficient 
or cost-effective regional transmission solution to address Long-Term 
Transmission Needs (otherwise it would not be selected).\2198\
---------------------------------------------------------------------------

    \2196\ Order No. 1920, 187 FERC ] 61,068 at P 1702; see also 
supra Analysis under Section 206 section.
    \2197\ Id. P 1704 (citing Order No. 1000, 136 FERC ] 61,051 at P 
313).
    \2198\ Id. P 1706.
---------------------------------------------------------------------------

    883. Additionally, the Commission explained that, in requiring a 
federal right of first refusal for a right-sized replacement 
transmission facility, Order No. 1000 did not alter the rights of 
incumbent transmission providers to build, own, and recover costs for 
upgrades to their own transmission facilities, regardless of whether 
the upgrade is selected.\2199\
---------------------------------------------------------------------------

    \2199\ Id. P 1705 (citing Order No. 1000, 136 FERC ] 61,051 at P 
319 (internal citation omitted)).
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    884. Certain parties request rehearing of Order No. 1920's 
establishment of a federal right of first refusal for a right-sized 
replacement transmission facility that is selected to meet Long-Term 
Transmission Needs, on the grounds that the Commission deviated from 
prior precedent without reasoned explanation and, therefore, such 
requirements are arbitrary and capricious.\2200\ For example, Advanced 
Energy states that the Commission failed to explain how providing for a 
right of first refusal for right-sized replacement transmission 
facilities in Order No. 1920 was consistent with prior Commission 
findings that granting an incumbent utility a federal right of first 
refusal can lead to rates that are unjust and unreasonable.\2201\
---------------------------------------------------------------------------

    \2200\ Advanced Energy Rehearing Request at 15-16; Competition 
Coalition Rehearing Request at 40-43; Designated Retail Regulators 
Rehearing Request at 41-42; Industrial Customers Rehearing Request 
at 9.
    \2201\ Advanced Energy Rehearing Request at 16 (citing Order No. 
1000-A, 139 FERC ] 61,132 at P 360; FCC v. Fox Television Stations, 
556 U.S. at 515).
---------------------------------------------------------------------------

    885. Advanced Energy further argues that the Commission's provision 
of a federal right of first refusal for right-sized replacement 
transmission facilities is inconsistent with the general federal policy 
against anticompetitive practices.\2202\
---------------------------------------------------------------------------

    \2202\ Id. at 10-11; see also Competition Coalition Rehearing 
Request at 67-68.
---------------------------------------------------------------------------

    886. Relatedly, Advanced Energy, Competition Coalition, and PIOs 
argue that the inclusion of a federal right of first refusal as part of 
the right-sizing reform will create incentives for incumbent 
transmission owners to use the local transmission planning processes to 
undermine the regional transmission planning process, resulting in less 
efficient or cost-effective solutions and, therefore, unjust and 
unreasonable rates.\2203\ For instance, Competition Coalition argues 
that a profit-motivated incumbent transmission owner will have 
incentives to add even more in-kind replacements into its local 
transmission plan because of the possibility that the transmission 
planning region will then right-size those projects into an even larger 
facility in which the incumbent utility would be allowed to invest 
without any competition, thus preserving, reinforcing, and expanding 
its monopoly position.\2204\
---------------------------------------------------------------------------

    \2203\ Advanced Energy Rehearing Request at 13-14; Competition 
Coalition Rehearing Request at 69-71; PIOs Rehearing Request at 51-
54.
    \2204\ Competition Coalition Rehearing Request at 69-70.
---------------------------------------------------------------------------

c. Commission Determination
    887. We are unpersuaded by rehearing requests arguing that Order 
No. 1920's establishment of a federal right of first refusal for right-
sized replacement transmission facilities selected to meet Long-Term 
Transmission Needs is arbitrary and capricious. In Order No. 1000, the 
Commission required transmission providers to eliminate federal rights 
of first refusal because those federal rights of first refusal allowed 
transmission providers to undermine the consideration of more efficient 
or cost-effective potential transmission solutions proposed at the 
regional level, which could lead to unjust and unreasonable rates for 
Commission-jurisdictional services.\2205\ Moreover, in Order No. 1000 
the Commission found that federal rights of first refusal created a 
barrier to entry that discouraged nonincumbent transmission developers 
from proposing alternative solutions at the regional level.\2206\
---------------------------------------------------------------------------

    \2205\ Order No. 1000, 136 FERC ] 61,051 at PP 253, 256, 313.
    \2206\ Id. P 257.
---------------------------------------------------------------------------

    888. In Order No. 1920, the Commission found that that a right-
sized replacement transmission facility has the potential to both meet 
an individual transmission provider's responsibility to maintain the 
reliability of its existing transmission system and to address a Long-
Term Transmission Need more efficiently or cost-effectively than an in-
kind replacement transmission facility or another Long-Term Regional 
Transmission Facility.\2207\ The Commission further explained that, 
compared to the alternative of piecemeal development of in-kind 
replacement transmission facilities, a federal right of first refusal 
for right-sized transmission facilities is appropriate because right-
sized replacement transmission facilities represent the more efficient 
or cost-effective regional transmission solution to address Long-Term 
Transmission Needs (otherwise, they would not be selected).\2208\
---------------------------------------------------------------------------

    \2207\ Order No. 1920, 187 FERC ] 61,068 at P 1682.
    \2208\ Id. P 1706.
---------------------------------------------------------------------------

    889. We recognize that requiring the federal right of first refusal 
for right-sized replacement transmission facilities is a departure from 
the Order No. 1000's requirement that transmission providers eliminate 
federal rights of first refusal for transmission facilities selected in 
a regional transmission plan for purposes of cost allocation. However, 
we find the departure, in this instance, to be necessary in order to 
shift the balance of transmission facility construction and remove a 
barrier to the selection of more efficient or cost-effective regional 
transmission facilities. As the Commission found, the existing 
piecemeal approach to upgrading the transmission system results in 
inefficiencies and increased rates for consumers.\2209\ The Commission 
is improving the efficiency of the transmission planning process and 
ensuring rates are just and reasonable by promoting the consideration 
of right-sized replacement transmission facilities, subject to 
evaluation and selection processes in Long-Term Regional Transmission 
Planning, and by establishing the availability of the federal right of 
first refusal for such right-sized replacement transmission 
facilities.\2210\
---------------------------------------------------------------------------

    \2209\ Id. PP 1574, 1706.
    \2210\ Although we find that the Commission has supported the 
inclusion of the right-sizing reforms as a component of a just and 
reasonable replacement rate, we consider these reforms as an 
enhancement to, rather than essential to, the Long-Term Regional 
Transmission Planning process. Absent the right-sizing reforms, the 
Commission would have established the other Long-Term Regional 
Transmission Planning requirements as a sufficient just and 
reasonable replacement rate.

---------------------------------------------------------------------------

[[Page 97338]]

    890. We sustain Order No. 1920's finding that the right-sizing 
reform will promote the consideration of more efficient or cost-
effective potential regional transmission solutions to address Long-
Term Transmission Needs. Specifically, the federal right of first 
refusal will provide transmission providers with certainty that they 
will not lose the opportunity to invest in any in-kind replacement 
transmission facility that is then selected as a right-sized 
replacement transmission facility, and this, in turn, will encourage 
transmission providers to provide their best in-kind replacement 
estimates.\2211\ Accordingly, we continue to find that a federal right 
of first refusal will remove a disincentive for transmission providers 
to consider right-sizing in Long-Term Regional Transmission Planning, 
helping to ensure that the more efficient or cost-effective regional 
transmission solution to Long-Term Transmission Needs is identified and 
selected, and therefore that Commission-jurisdictional rates are just 
and reasonable.
---------------------------------------------------------------------------

    \2211\ Order No. 1920, 187 FERC ] 61,068 at P 1703.
---------------------------------------------------------------------------

    891. In Order No. 1920, the Commission explained that, in the 
context of the right-sizing reform, a federal right of first refusal 
will promote the consideration of more efficient or cost-effective 
potential regional transmission solutions to address Long-Term 
Transmission Needs because, absent the right-sizing reform, those needs 
would be addressed in a piecemeal manner.\2212\ This will in turn 
benefit consumers by helping to ensure that the rates that they pay are 
just and reasonable. Furthermore, we believe that providing a federal 
right of first refusal for selected right-sized replacement 
transmission facilities is consistent with Order No. 1920's finding 
that the absence of sufficiently long-term, forward-looking, and 
comprehensive transmission planning requirements causes transmission 
providers to fail to appropriately evaluate the benefits of 
transmission infrastructure, and results in piecemeal transmission 
expansion to address relatively near-term transmission needs.\2213\ As 
such, as discussed in the Eligibility section above, we find that it is 
appropriate to alter the Commission's policy regarding the removal of 
the federal right of first refusal by providing a federal right of 
first refusal for selected right-sized replacement transmission 
facilities. This is particularly true because the reforms that we 
require here serve a similar purpose as removing the federal right of 
first refusal for regional transmission facilities selected in the 
regional transmission plan for purposes of cost allocation in Order No. 
1000. In each instance, the Commission's goal was to ensure that the 
more efficient or cost-effective regional transmission facilities are 
considered, thereby ensuring that Commission-jurisdictional rates are 
just and reasonable--in Order No. 1000, that was accomplished by 
removing the federal right of first refusal for selected regional 
transmission facilities in certain instances, while in Order No. 1920, 
it was by establishing a federal right of first refusal in the limited 
instances where it incentivizes transmission providers to consider 
right-sized replacement transmission facilities as more efficient or 
cost-effective regional transmission solutions to Long-Term 
Transmission Needs. The reforms related to the federal right of first 
refusal in Order Nos. 1000 and 1920 each seek to ensure that more 
efficient or cost-effective regional transmission facilities are 
considered thereby resulting in just and reasonable rates. Protecting 
consumers and ensuring Commission-jurisdictional rates are just and 
reasonable are fundamental requirements of the Federal Power Act and we 
believe that the reforms in Order No. 1920 accomplish these mandates.
---------------------------------------------------------------------------

    \2212\ Id. P 1706.
    \2213\ Id. P 85.
---------------------------------------------------------------------------

    892. We also note that this federal right of first refusal applies 
only to selected right-sized replacement transmission facilities, 
which, absent the right-sizing reform, would likely not otherwise be 
identified for potential selection in either the existing Order No. 
1000 regional transmission planning process or the Long-Term Regional 
Transmission Planning process. That is because there is currently no 
requirement for transmission providers to submit their in-kind 
replacement transmission facilities to the regional transmission 
planning process for potential right-sizing. In addition, as the 
Commission explained in Order No. 1920, the right-sizing reform does 
not alter existing laws related to an individual transmission 
provider's ability to proceed with an in-kind replacement transmission 
facility, and we continue to find that, absent a federal right of first 
refusal, the incumbent transmission provider whose in-kind replacement 
transmission facility is selected to be right-sized would likely 
proceed to develop the less efficient or cost-effective in-kind 
replacement transmission facility.\2214\ This is because, absent the 
federal right of first refusal, the incumbent transmission provider 
would not be assured that it would have the opportunity to invest in 
the right-sized replacement transmission facility and therefore very 
likely would chose to build the less efficient or cost-effective in-
kind replacement transmission facility. Therefore, the right-sizing 
reform's federal right of first refusal provides the needed incentives 
to ensure that in-kind replacement transmission facilities are 
considered in the Long-Term Regional Transmission Planning process and 
selected when they are more efficient or cost-effective transmission 
solutions while also not substantially reducing the number of 
transmission facilities that would otherwise be subject to a 
competitive transmission development process.
---------------------------------------------------------------------------

    \2214\ Id. P 1706.
---------------------------------------------------------------------------

    893. We are also unpersuaded by Advanced Energy's arguments that 
the federal right of first refusal associated with the right-sizing 
reform is inconsistent with federal policies against anticompetitive 
practices. As we note above, given the existing federal rights of first 
refusal that transmission owners have and that we are not altering 
here, it is unlikely that right-sized replacement transmission 
facilities would ever be considered in competitive transmission 
development processes. Therefore, we do not believe that the right-
sizing reform will significantly decrease competition compared to the 
status quo.
    894. We are unpersuaded by rehearing requests that argue that the 
federal right of first refusal associated with the right-sizing reform 
will create incentives for incumbent transmission providers to use 
local transmission planning processes to undermine regional 
transmission planning processes. Under Order No. 1920's right-sizing 
reforms, incumbent transmission owners will have an incentive to 
identify in-kind replacement transmission facilities that could be 
right-sized to retain a federal right of first refusal over regional 
transmission facilities, but that incentive does not undermine the 
regional transmission planning process. Instead, it will enhance 
regional transmission planning by expanding the range of potential 
regional transmission solutions to Long-Term Transmission Needs 
considered through Long-Term Regional Transmission Planning, 
facilitating the identification and

[[Page 97339]]

selection of more efficient or cost-effective regional transmission 
facilities and helping to ensure just and reasonable Commission-
jurisdictional rates. Moreover, because Order No. 1920 requires that a 
right-sized replacement transmission facility be evaluated in the same 
manner as any other proposed Long-Term Regional Transmission Facility 
to determine whether it is the more efficient or cost-effective 
transmission facility to address the transmission need,\2215\ a right-
sized replacement transmission facility will be selected only where it 
is the more efficient or cost-effective transmission solution. As such, 
there is no guarantee that an in-kind replacement transmission facility 
that a transmission provider identifies in its in-kind replacement 
estimates list will be right-sized and selected. To the extent that the 
evaluation of a transmission provider's in-kind replacement 
transmission facility determines that the in-kind replacement 
transmission facility cannot be right-sized to more efficiently or 
cost-effectively address Long-Term Transmission Needs, then it will not 
be selected as a right-sized replacement transmission facility.
---------------------------------------------------------------------------

    \2215\ Id. P 1681.
---------------------------------------------------------------------------

3. Confidentiality of In-Kind Replacement Estimates
a. Order No. 1920
    895. In Order No. 1920, the Commission explained that to the extent 
customers or stakeholders request access to a transmission provider's 
list of in-kind replacement estimates, that transmission provider may 
subject access to that list of in-kind replacement estimates to 
confidentiality provisions. However, the Commission added that, once 
transmission providers have determined, as part of Long-Term Regional 
Transmission Planning, that an in-kind replacement transmission 
facility can be right-sized to constitute a right-sized replacement 
transmission facility, the transmission providers must make public the 
underlying in-kind replacement transmission facility.\2216\
---------------------------------------------------------------------------

    \2216\ Order No. 1920, 187 FERC ] 61,068 at P 1736.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    896. In their rehearing requests, Dominion and Indicated PJM TOs 
argue that the Commission's decision on confidentiality for in-kind 
replacement estimate lists fails to adequately address concerns 
regarding the possible harm caused by release of the in-kind 
replacement estimate lists.\2217\ Both Dominion and Indicated PJM TOs 
argue that considering the Commission's determination that once a 
replacement transmission facility can be right-sized, that information 
will be made publicly available to stakeholders, there is limited value 
in providing the in-kind replacement estimate list to others.\2218\
---------------------------------------------------------------------------

    \2217\ Dominion Rehearing Request at 36-37; Indicated PJM TOs 
Rehearing Request at 6-7.
    \2218\ Dominion Rehearing Request at 36-37; Indicated PJM TOs 
Rehearing Request at 7-8.
---------------------------------------------------------------------------

    897. Further, Indicated PJM TOs argue that confidentiality 
agreements or provisions do not provide adequate protection against the 
damage of disclosure of in-kind replacement estimate lists since non-
disclosure agreements do not impose any specific safeguards on the 
information disclosed.\2219\ Indicated PJM TOs note that the 
Commission's general Non-Disclosure Agreement for CEII provides that 
violations of that agreement ``may result in criminal or civil 
sanctions'' against the recipient, and the Commission's Model 
Protective Order provides that ``[a]ny violation of this Protective 
Order and of any Non-Disclosure Certificate executed hereunder shall 
constitute a violation of an order of the Commission.'' \2220\ 
Indicated PJM TOs argue that the requirement that a transmission owner 
make public 10-years' worth of replacement information before 
transmission plans are made public as part of the Long-Term Regional 
Transmission Planning process gives competing developers a competitive 
advantage that is inconsistent with the FPA's prohibition on undue 
discrimination and preferences.\2221\
---------------------------------------------------------------------------

    \2219\ Indicated PJM TOs Rehearing Request at 8-9.
    \2220\ Id. at 9 (citing FERC, CEII General Non-Disclosure 
Agreement (Apr. 19, 2020), https://www.ferc.gov/media/1928; FERC, 
Model Protective Order (May 11, 2020), available at https://www.ferc.gov/administrative-litigation-0).
    \2221\ Id. at 10.
---------------------------------------------------------------------------

c. Commission Determination
    898. In response to Dominion's and Indicated PJM TOs' arguments 
regarding the possible harm caused by release of the in-kind 
replacement estimate lists, we continue to find that existing rules 
governing confidential or commercially sensitive information provide 
for the safekeeping of that information. We note that Order No. 890 
required transmission providers, in consultation with affected parties, 
to develop mechanisms like confidentiality agreements and password-
protected access to information, in order to manage confidentiality and 
CEII concerns.\2222\ To the extent that transmission providers believe 
that existing provisions are inadequate, they may submit an FPA section 
205 filing with additional protections, and the Commission will 
evaluate them to ensure they are just and reasonable and otherwise 
comply with the applicable requirements. Moreover, in determining that 
disclosure of in-kind replacement estimate lists may occur subject to 
confidentiality provisions, the Commission balanced concerns about 
disclosure against the importance of transparency and meaningful 
stakeholder participation in regional transmission planning and cost 
allocation processes, as required under Order Nos. 890 and 1000. We 
continue to find, consistent with prior precedent, that disclosure 
subject to appropriate mechanisms for confidentiality strikes an 
appropriate balance between these interests.\2223\
---------------------------------------------------------------------------

    \2222\ Order No. 890, 118 FERC ] 61,119 at P 460.
    \2223\ Tri-State Generation & Transmission Ass'n, 170 FERC ] 
61,222, at P 27 (2020); see also Astoria Generating Co. v. N.Y. 
Indep. Sys. Operator, Inc., 136 FERC ] 61,155, at PP 21-25 (2011) 
(adopting protective order and directing respondent to file 
confidential information and simultaneously release the information 
to parties who signed non-disclosure certificate); Pac. Gas 
Transmission Co., 44 FERC ] 61,209, at 61,766-67 (1988) (remanding 
matter to administrative law judge with direction to balance 
potential harm of disclosing confidential business information 
sought during discovery against the requesting parties' need for the 
information).
---------------------------------------------------------------------------

XII. Interregional Transmission Coordination

A. Order No. 1920

    899. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to revise their existing 
interregional transmission coordination procedures to reflect the Long-
Term Regional Transmission Planning reforms adopted in Order No. 1920. 
More specifically, the Commission required transmission providers in 
neighboring transmission planning regions to revise their existing 
interregional transmission coordination procedures (and regional 
transmission planning processes, as needed) to provide for: (1) the 
sharing of information regarding their respective Long-Term 
Transmission Needs, as well as Long-Term Regional Transmission 
Facilities to meet those needs; and (2) the identification and joint 
evaluation of interregional transmission facilities that may be more 
efficient or cost-effective transmission facilities to address Long-
Term Transmission Needs.\2224\ Additionally, the Commission required 
transmission providers in neighboring transmission planning regions to 
revise their interregional transmission coordination procedures (and 
regional

[[Page 97340]]

transmission planning processes, as needed) to allow an entity to 
propose an interregional transmission facility in the regional 
transmission planning process as a potential solution to Long-Term 
Transmission Needs.\2225\
---------------------------------------------------------------------------

    \2224\ Order No. 1920, 187 FERC ] 61,068 at P 1751.
    \2225\ Id. P 1752.
---------------------------------------------------------------------------

    900. The Commission also required transmission providers in each 
transmission planning region to provide certain additional information 
concerning Long-Term Regional Transmission Planning on their public 
websites or through the email list used for communication of 
information related to interregional transmission coordination 
procedures.\2226\
---------------------------------------------------------------------------

    \2226\ Order No. 1920, 187 FERC ] 61,068 at P 1753.
---------------------------------------------------------------------------

B. Comments

    901. In its comments, Grid United argues that Order No. 1920 does 
not solve the challenges of developing transmission, including 
interregional transmission, and requests that the Commission open a new 
proceeding focused on interregional transmission and its 
challenges.\2227\
---------------------------------------------------------------------------

    \2227\ Grid United June 12, 2024 Comments at 1-2.
---------------------------------------------------------------------------

C. Commission Determination

    902. Although we acknowledge Grid United's request that the 
Commission continue to build upon the progress in Order No. 1920 for 
regional transmission planning by addressing interregional 
transmission, we decline to open a new docket at this time, as 
requested by Grid United.\2228\ We find that Order No. 1920 adequately 
addressed the interregional transmission coordination reforms needed to 
account for the rule's Long-Term Regional Transmission Planning 
reforms.\2229\ In particular, we continue to find that the reforms in 
Order No. 1920, taken together, will ensure that Long-Term Transmission 
Needs identified through Long-Term Regional Transmission Planning can 
be considered in existing interregional transmission coordination and 
cost allocation processes, and that there is an opportunity for 
transmission providers in neighboring transmission planning regions to 
consider whether there are interregional transmission facilities that 
could more efficiently or cost-effectively address the identified Long-
Term Transmission Needs, helping to ensure just and reasonable 
Commission-jurisdictional rates.\2230\ Furthermore, as the Commission 
found in Order No. 1920, and we reiterate here, the Commission 
currently has an open proceeding in Docket No. AD23-3-000 to consider 
whether and how to establish a minimum requirement for Interregional 
Transfer Capability including the transmission planning and cost 
allocation related to such a requirement.\2231\ To the extent that the 
Commission determines that further investigation of this issue is 
warranted, it can open a new docket at an appropriate time or consider 
such issues in pending proceedings,\2232\ as appropriate.
---------------------------------------------------------------------------

    \2228\ As noted above, the pleading filed by Grid United is 
deficient under 18 CFR 385.712(c)(2). Nevertheless, we address Grid 
United's arguments to provide clarity. See infra Introduction and 
Background section.
    \2229\ Order No. 1920, 187 FERC ] 61,068 at PP 1740-1758.
    \2230\ Id. P 1754.
    \2231\ See Supplemental Notice of Staff-Led Workshop, 
Establishing Interregional Transfer Capability Transmission Planning 
and Cost Allocation Requirements, Docket No. AD23-3-000 (Nov. 30, 
2022).
    \2232\ See Order No. 1920, 187 FERC ] 61,068 at P 1758 (``[W]e 
note that the Commission currently has an open proceeding in Docket 
No. AD23-3-000 to consider whether and how to establish a minimum 
requirement for Interregional Transfer Capability, and may consider 
further reforms in other proceedings, as appropriate.'').
---------------------------------------------------------------------------

XIII. Compliance Procedures

A. Order No. 1920

    903. In Order No. 1920, the Commission required each transmission 
provider to submit a compliance filing revising its OATT and other 
document(s) subject to the Commission's jurisdiction as necessary to 
demonstrate that it meets all of the requirements adopted in Order No. 
1920, except those adopted in the Interregional Transmission 
Coordination section above, within 10 months of the effective date of 
Order No. 1920. The Commission explained that a 10-month compliance 
period allows transmission providers to fully develop proposals to 
comply with Order No. 1920 and allows stakeholders, including Relevant 
State Entities, to meaningfully engage in the process of developing 
such proposals. Additionally, the Commission required transmission 
providers in each transmission planning region to propose an effective 
date for the OATT revisions necessary to comply with Order No. 1920 
that is no later than the date on which they will commence the first 
Long-Term Regional Transmission Planning cycle.\2233\ The Commission 
noted, however, that transmission providers may propose an earlier 
effective date for some or all parts of their revised OATTs to allow 
them to begin implementing any aspects of the required reforms sooner 
than the one-year deadline to commence the first Long-Term Regional 
Transmission Planning cycle.\2234\
---------------------------------------------------------------------------

    \2233\ Order No. 1920, 187 FERC ] 61,068 at P 1768. The 
Commission noted that Order No. 1920 required transmission providers 
in each transmission planning region to propose on compliance a 
date, no later than one year from the date on which initial filings 
to comply with Order No. 1920 are due, on which they will commence 
the first Long-Term Regional Transmission Planning cycle (unless 
additional time is needed to align the first Long-Term Regional 
Transmission Planning cycle with existing transmission planning 
cycles). Id.
    \2234\ Id. P 1768.
---------------------------------------------------------------------------

    904. The Commission further required each transmission provider to 
submit a compliance filing revising its OATT and other document(s) 
subject to the Commission's jurisdiction as necessary to demonstrate 
that it meets the interregional transmission coordination requirements 
within 12 months of the effective date of Order No. 1920. The 
Commission explained that a longer compliance timeframe will allow 
transmission providers to coordinate with the transmission providers in 
each of their neighboring transmission planning regions to develop 
interregional transmission coordination proposals.\2235\
---------------------------------------------------------------------------

    \2235\ Id. P 1770.
---------------------------------------------------------------------------

    905. Additionally, the Commission required transmission providers 
that are not public utilities to adopt the requirements of Order No. 
1920 as a condition of maintaining the status of their safe harbor 
tariffs or otherwise satisfying the reciprocity requirement of Order 
No. 888.\2236\
---------------------------------------------------------------------------

    \2236\ Id. P 1771 (citing Order No. 888, FERC Stats. & Regs. ] 
31,036 at 31,760-63).
---------------------------------------------------------------------------

    906. Finally, in Order No. 1920, the Commission explained that it 
made no changes to the standards used to judge requested variations, as 
described in Order Nos. 888, 2000, 890, and 1000 and, accordingly, 
declined a request to apply the independent entity variation standard, 
rather than the ``consistent with or superior to'' standard, for 
proposed deviations from the requirements of Order No. 1920.\2237\ The 
Commission stated that, consistent with findings in Order No. 890, the 
Commission will continue to apply the ``consistent with or superior 
to'' standard in the context of transmission planning.\2238\ The 
Commission explained that, to the extent that a transmission provider 
believes that it already complies with any of the requirements in Order 
No. 1920, it should describe in its compliance filing how the relevant 
requirements are satisfied, including by referencing

[[Page 97341]]

specific tariff sheets already on file with the Commission.\2239\
---------------------------------------------------------------------------

    \2237\ Id. P 1772 (citing Order No. 888, FERC Stats. & Regs. ] 
31,036, at 31,769-70; Order No. 2000, FERC Stats. & Regs. ] 31,089 
at 31,164; Order No. 890, 118 FERC ] 61,119 at P 109; Order No. 
1000, 136 FERC ] 61,051 at P 815).
    \2238\ Id. P 1772 (citing Order No. 890, 118 FERC ] 61,119 at P 
160).
    \2239\ Id. P 1773.
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B. Requests for Rehearing and Clarification

    907. Dominion and NARUC request rehearing of Order No. 1920's 
compliance timeframes.\2240\ Dominion argues that the Commission failed 
to consider that many of the same personnel responsible for 
implementing Order No. 2023 are also responsible for managing the 
implementation of Order No. 1920's requirements.\2241\ NARUC asserts 
that Order No. 1920's 10-month compliance deadline is insufficient to 
allow state entities to meaningfully engage on developing cost 
allocation proposals given existing state retail regulatory duties, the 
steep learning curve on issues related to Order No. 1920, and internal 
legal and procedural issues they will need to sort through. NARUC 
suggests that the record justifies a 14-month compliance period.\2242\
---------------------------------------------------------------------------

    \2240\ Dominion Rehearing Request at 37-39; NARUC Rehearing 
Request at 18-21.
    \2241\ Dominion Rehearing Request at 38 (citing State Farm, 463 
U.S. at 43).
    \2242\ NARUC Rehearing Request at 20-21.
---------------------------------------------------------------------------

    908. Dairyland and PJM request rehearing of Order No. 1920's 
requirement that transmission providers demonstrate proposed deviations 
from the requirements of Order No. 1920 are ``consistent with or 
superior to'' the requirements of Order No. 1920.\2243\ Both Dairyland 
and PJM request that the Commission adopt an independent entity 
variation standard for compliance with the final rule. Dairyland argues 
that the Commission failed to consider information and arguments 
submitted in support of the independent entity variation \2244\ and 
made no attempt to explain why the precedent of Order No. 2003, which 
identified bases for a different compliance standard for independent 
entities, is distinguishable or should not be used here.\2245\ Along 
similar lines, PJM argues that aspects of Order No. 1920 are arbitrary 
and capricious because: (1) the final rule is internally inconsistent 
given the Commission's recognition of the need for regional flexibility 
while also including ``numerous prescriptive requirements'' and 
rejecting requests to apply an ``independent entity variation'' 
standard of review and instead applying the ``consistent with or 
superior to'' standard for proposed deviations from the final rule; 
\2246\ and (2) the Commission failed to consider the evidence offered 
by ISO/RTOs that they need flexibility to implement Long-Term Regional 
Transmission Planning.\2247\
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    \2243\ Dairyland Rehearing Request at 3-7; PJM Rehearing Request 
at 10-14.
    \2244\ Dairyland Rehearing Request at 4.
    \2245\ Id. at 3-4, 6-7; see also PJM Rehearing Request at 13 
n.60.
    \2246\ PJM Rehearing Request at 10-11, 41; see also Dairyland 
Rehearing Request at 7.
    \2247\ PJM Rehearing Request at 11-14, 42.
---------------------------------------------------------------------------

    909. APPA and TAPS request clarification of Order No. 1920's 
requirements for consultation with stakeholders.\2248\ APPA requests 
that the Commission clarify that transmission providers have an 
obligation to consult with stakeholders--including public power 
entities and load-serving entities--in developing compliance 
filings.\2249\ TAPS requests the Commission to clarify that Order No. 
1000's general obligation to consult with stakeholders in developing 
the associated transmission provider's compliance filing applies to all 
aspects of Order No. 1920 compliance filings, including the evaluation 
process, selection criteria, and the calculation of benefits.\2250\
---------------------------------------------------------------------------

    \2248\ APPA Rehearing Request at 6-7; TAPS Rehearing Request at 
14-19.
    \2249\ APPA Rehearing Request at 7.
    \2250\ TAPS Rehearing Request at 18-19.
---------------------------------------------------------------------------

    910. In its rehearing request, Large Public Power argues that the 
Commission should clarify that non-public utilities can satisfy the 
reciprocity requirement of Order No. 888 through one of three means: 
(1) providing service to a public utility transmission provider under a 
safe harbor tariff; (2) providing service under a bilateral agreement; 
or (3) seeking waiver.\2251\
---------------------------------------------------------------------------

    \2251\ Large Public Power Rehearing Request at 23-24.
---------------------------------------------------------------------------

    911. SPP requests clarification from the Commission that SPP can 
deviate from the specific requirements of Order No. 1920 and propose 
its own Consolidated Planning Process. SPP requests that the Commission 
clarify that a transmission provider may propose on compliance a new 
transmission planning process and cost allocation method that deviates 
from the requirements of Order No. 1920, and that the Commission could 
issue an order approving such a cost allocation process as consistent 
with or superior to the requirements of Order No. 1920.\2252\
---------------------------------------------------------------------------

    \2252\ SPP Rehearing Request at 2-4.
---------------------------------------------------------------------------

    912. WIRES states that the Commission should grant clarification 
or, in the alternative, rehearing, that transmission providers are not 
required to implement the proposed tariff revisions submitted in 
compliance with Order No. 1920 until the Commission issues ``a final 
order on compliance.'' \2253\ WIRES states that Order No. 1920 could be 
read to create a scenario where transmission providers would be 
required to begin implementing their OATT provisions submitted in 
compliance with the requirements of Order No. 1920 before receiving a 
Commission order on compliance accepting such revised Tariff 
provisions. WIRES argues that this would put transmission providers in 
the untenable position of expending a significant amount of time and 
resources in implementing Long-Term Regional Transmission Planning 
cycles that the Commission could find in a later order are not 
compliant with Order No. 1920.\2254\
---------------------------------------------------------------------------

    \2253\ WIRES Rehearing Request at 5-6, 16-18.
    \2254\ WIRES Rehearing Request at 16-18.
---------------------------------------------------------------------------

    913. Versant Power requests that the Commission clarify, or in the 
alternative grant rehearing, regarding: (1) what is generally required 
for a transmission provider to receive a waiver of Order No. 1920's 
requirements; and (2) whether and how waivers of previous, relevant 
orders affect Order No. 1920's requirements for transmission providers 
with those waivers.\2255\
---------------------------------------------------------------------------

    \2255\ Versant Power Rehearing Request at 9-16. Versant Power 
notes that its request for clarification may be withdrawn because of 
a separate waiver filing. Id. at 1 n.4. Versant Power withdrew its 
rehearing request on September 10, 2024.
---------------------------------------------------------------------------

C. Commission Determination

    914. We sustain Order No. 1920's requirement that each transmission 
provider submit a compliance filing within 10 months of the effective 
date of Order No. 1920 revising its OATT and other document(s) subject 
to the Commission's jurisdiction as necessary to demonstrate that it 
meets the requirements adopted in Order No. 1920, except those 
requirements adopted in the Interregional Transmission Coordination 
section above. As we noted in Order No. 1920, we continue to find that 
a 10-month compliance period will allow transmission providers adequate 
time to fully develop proposals to comply with Order No. 1920.\2256\ We 
also sustain Order No. 1920's requirement that each transmission 
provider submit a separate compliance filing within 12 months of the 
effective date of Order No. 1920 revising its OATT and other 
document(s) subject to the Commission's jurisdiction as necessary to 
demonstrate that it meets the interregional transmission coordination 
requirements adopted in Order No. 1920.\2257\ Nevertheless, as noted 
above

[[Page 97342]]

in the Duration of the Engagement Period section above, if we grant an 
extension of the required Engagement Period when Relevant State 
Entities make a showing that they require additional time to finalize 
cost allocation discussions, we will also, as appropriate, extend, sua 
sponte, the relevant Order No. 1920 compliance deadlines to ensure that 
any extension of the Engagement Period would not conflict with the 
required compliance deadlines.
---------------------------------------------------------------------------

    \2256\ Order No. 1920, 187 FERC ] 61,068 at P 1768.
    \2257\ Id. P 1770.
---------------------------------------------------------------------------

    915. We clarify that the effective date associated with this order 
on rehearing and clarification does not extend the relevant compliance 
deadlines associated with Order No. 1920. In calculating the required 
dates for compliance filings (e.g., 10 months for revisions to a 
transmission provider's OATT and other document(s) subject to the 
Commission's jurisdiction as necessary to demonstrate that it meets the 
requirements adopted in Order No. 1920, and 12 months for revisions to 
a transmission provider's OATT and other document(s) subject to the 
Commission's jurisdiction as necessary to demonstrate that it meets the 
interregional transmission coordination requirements adopted in Order 
No. 1920), transmission providers should use the effective date of 
Order No. 1920 (i.e., August 12, 2024) and not the effective date for 
the changes to Order No. 1920 made in this order on rehearing and 
clarification.
    916. We are unpersuaded by Dominion's and NARUC's arguments that 
the Commission should require a longer compliance period. We note that 
in Order No. 1920 the Commission modified the NOPR proposal for an 
eight-month compliance period to allow an additional two months.\2258\ 
While we appreciate Dominion's concerns regarding personnel responsible 
for implementing both Order Nos. 1920 and 2023, we believe that we have 
provided sufficient time for transmission providers to develop 
compliance filings.
---------------------------------------------------------------------------

    \2258\ Id. P 1768.
---------------------------------------------------------------------------

    917. We also sustain Order No. 1920's requirement that, consistent 
with the Commission's findings in Order No. 890, transmission providers 
must demonstrate that proposed deviations from the requirements of 
Order No. 1920 are ``consistent with or superior to'' the requirements 
in Order No. 1920.\2259\
---------------------------------------------------------------------------

    \2259\ Id. P 1772 (citing Order No. 890, 118 FERC ] 61,119 at P 
160).
---------------------------------------------------------------------------

    918. We disagree with Dairyland's assertion that the Commission's 
use of the ``consistent with or superior to'' standard in Order No. 
1920 is an unexplained departure from Commission precedent.\2260\ To 
the contrary, in Order No. 1920, the Commission made no changes to the 
standard used to judge requested variations in the context of 
transmission planning, including in Order Nos. 888, 2000, 890, and 
1000,\2261\ and instead followed precedent in applying the ``consistent 
with or superior to'' standard of review to proposed new and existing 
variations from its transmission planning and cost allocation 
requirements.\2262\ Rather, allowing for the use of the independent 
entity variation standard of review in this proceeding, as Dairyland 
and PJM request, would be a departure from this line of precedent and 
an importation of the independent entity variation standard from the 
interconnection context into the transmission planning context that 
would require further explanation.\2263\ As discussed below, neither 
Dairyland nor PJM justify such a departure.
---------------------------------------------------------------------------

    \2260\ Dairyland Rehearing Request at 3, 6.
    \2261\ Order No. 1000, 136 FERC ] 61,051 at P 815; Order No. 
890, 118 FERC ] 61,119 at P 109; Order No. 2000, FERC Stats. & Regs. 
] 31,089 at 31,164; Order No. 888, FERC Stats. & Regs. ] 31,036, at 
31,769-70.
    \2262\ Order No. 1920, 187 FERC ] 61,068 at P 1772.
    \2263\ See FCC v. Fox Television Stations, Inc., 556 U.S. at 
515.
---------------------------------------------------------------------------

    919. Further, we disagree with PJM's and Dairyland's claims that 
Order No. 1920 is internally inconsistent because it recognizes the 
need for regional flexibility while also including prescriptive 
requirements without allowing for independent entity variations.\2264\ 
In a number of areas, Order No. 1920 provides transmission providers 
with the flexibility to accommodate regional differences, and this 
flexibility can be incorporated into the regional transmission planning 
requirements.\2265\ Although in other areas the Commission provided 
less flexibility, we believe that the Commission struck a reasonable 
overall balance in Order No. 1920 between, on the one hand, 
transmission providers' need for flexibility in implementing Long-Term 
Regional Transmission Planning in their transmission planning regions 
and, on the other hand, ensuring that transmission providers adopt 
reforms that will result in transmission providers identifying, 
evaluating, and selecting more efficient or cost-effective regional 
transmission facilities to address Long-Term Transmission Needs and 
thus Commission-jurisdictional rates that are just and reasonable and 
not unduly discriminatory or preferential.\2266\
---------------------------------------------------------------------------

    \2264\ PJM Rehearing Request at 11-12; Dairyland Rehearing 
Request at 7.
    \2265\ For example, Order No. 1920 provides for flexibility such 
as: (1) allowing transmission providers to measure and use 
additional benefits in Long-Term Regional Transmission Planning; (2) 
allowing transmission providers to develop evaluation processes and 
selection criteria that can accommodate regional differences; and 
(3) declining to impose a selection requirement as transmission 
providers require the flexibility to balance competing interests in 
the transmission planning region and to exercise engineering 
judgment to ensure the reliable operation of the transmission system 
and compliance with a variety of regulatory requirements. See Order 
No. 1920, 187 FERC ] 61,068 at PP 729, 924, 1027.
    \2266\ Order No. 1920, 187 FERC ] 61,068 at P 237.
---------------------------------------------------------------------------

    920. We are unpersuaded by PJM's and Dairyland's arguments that the 
rationale for application of the independent entity variation standard 
to RTOs/ISOs in the interconnection context in Order No. 2003 applies 
equally to the circumstances of Order No. 1920.\2267\ The requirements 
of Order No. 2003 were established to achieve greater standardization 
of interconnection terms and conditions and to address evidence of 
undue discrimination in interconnection processes.\2268\ The Commission 
granted independent entities greater flexibility to deviate from the 
provisions of the pro forma OATT on the basis that these entities do 
not own generation and therefore face fewer incentives to act in an 
unduly discriminatory or preferential manner toward certain 
generators.\2269\ That rationale does not apply to the requirements in 
Order No. 1920, which were adopted to address deficiencies in regional 
transmission planning processes, as those processes fail to identify, 
evaluate, and select regional transmission facilities that can more 
efficiently or cost-effectively meet Long-Term Transmission Needs and 
therefore to ensure just and reasonable rates.\2270\ The need for 
regional transmission planning processes that meet the

[[Page 97343]]

Commission's requirements in Order No. 1920 applies to all transmission 
providers to the same extent regardless of their independence or 
complexity. Beyond noting the independence and complexity of RTOs/ISOs, 
neither PJM nor Dairyland have justified or offered evidence of why 
RTOs/ISOs should be treated differently than other transmission 
providers for purposes of compliance with Order No. 1920's 
requirements.
---------------------------------------------------------------------------

    \2267\ PJM Rehearing Request at 13 n.60 (citing Standardization 
of Generator Interconnection Agreements & Procs., Order No. 2003, 68 
FR 49846 (Aug. 19, 2003), 104 FERC ] 61,103 (2003), order on reh'g, 
Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ] 61,220, at 
PP 756, 759, order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 
2005), 109 FERC ] 61,287 (2004), order on reh'g, Order No. 2003-C, 
70 FR 37661 (June 30, 2005), 111 FERC ] 61,401 (2005), aff'd sub 
nom. Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d 1277; 
Improvements to Generator Interconnection Procs. & Agreements, Order 
No. 2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC ] 61,054, at P 1764, 
order on reh'g, 185 FERC ] 61,063 (2023), order on reh'g, Order No. 
2023-A, 89 FR 27006 (Apr. 16, 2024), 186 FERC ] 61,199, errata 
notice, 188 FERC ] 61,134 (2024)); Dairyland Rehearing Request at 5, 
6 (citing MISO NOPR Reply Comments at 5-8).
    \2268\ Order No. 2003, 104 FERC ] 61,103 at PP 11-12.
    \2269\ Id. PP 822, 827; Order No. 2003-A, 106 FERC ] 61,220 at P 
759.
    \2270\ See Order No. 1920, 187 FERC ] 61,068 at PP 87, 89.
---------------------------------------------------------------------------

    921. However, in light of PJM's and Dairyland's arguments, we 
clarify that, in analyzing Order No. 1920 compliance filings, we will 
apply the ``consistent with or superior to'' standard to proposed 
variations from all requirements of Order No. 1920 and not limit the 
standard to proposed variations from pro forma OATT provisions 
developed in Order No. 1920. Consistent with Commission practice,\2271\ 
it is appropriate to apply the ``consistent with or superior to'' 
standard both to variations from pro forma OATT provisions and to 
variations from requirements not accompanied by pro forma OATT 
provisions (i.e., those requirements that transmission providers must 
satisfy by developing or revising their own OATT provisions). The 
``consistent with or superior to'' standard ``is a tool for ensuring 
that a proposed tariff revision will still meet the standards of the 
FPA'' despite varying from the ``minimum provisions necessary'' to 
ensure just, reasonable, and not unduly discriminatory or preferential 
Commission-jurisdictional rates.\2272\ Both pro forma OATT provisions 
and requirements not accompanied by pro forma OATT provisions set 
``common starting point[s]'' \2273\ to ensure that Commission-
jurisdictional rates satisfy the requirements of the FPA. The 
Commission will review proposed variations from requirements 
established in Order No. 1920 to ensure that they continue to meet the 
requirements of FPA sections 205 and 206.
---------------------------------------------------------------------------

    \2271\ See, e.g., Pub. Util. Transmission Rate Changes to 
Address Accumulated Deferred Income Taxes, Order No. 864, 84 FR 
65281 (Nov. 27, 2019), 169 FERC ] 61,139, at P 66 n.101 (2019), 
order on reh'g, Order No. 864-A, 85 FR 27681 (May 11, 2020), 171 
FERC ] 61,033 (2020); Uplift Cost Allocation & Transparency in Mkts. 
Operated by Reg'l Transmission Orgs. & Indep. Sys. Operators, Order 
No. 844, 83 FR 18134 (Apr. 25, 2018), 163 FERC ] 61,041, at P 103 
(2018); Settlement Intervals & Shortage Pricing in Mkts. Operated by 
Reg'l Transmission Orgs. & Indep. Sys. Operators, Order No. 825, 81 
FR 42882 (June 30, 2016), 155 FERC ] 61,276, at PP 88, 90 (2016); 
Order No. 1000, 136 FERC ] 61,051 at P 583 n.452; Demand Response 
Comp. in Organized Wholesale Energy Mkts., 76 FR 16658 (Mar. 24, 
2011), Order No. 745, 134 FERC ] 61,187, at P 4 n.7; order on reh'g 
& clarification, Order No. 745-A, 137 FERC ] 61,215 (2011), reh'g 
denied, Order No. 745-B, 138 FERC ] 61,148 (2012), vacated sub nom. 
Elec. Power Supply Ass'n v. FERC, 753 F.3d 216 (D.C. Cir. 2014), 
rev'd & remanded sub nom. EPSA, 577 U.S. 260; Regional Transmission 
Orgs., Order No. 2000, 65 FR 810 (Jan. 6, 2000), FERC Stats. & Regs. 
] 31,089, at 31,164 (1999) (amending 18 CFR 35.34(k)(1)-(2), (k)(4), 
(k)(6)-(7)), order on reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 
2000), FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. 
Util. Dist. No. 1 of Snohomish Cty. v. FERC, 272 F.3d 607 (D.C. Cir. 
2001).
    \2272\ N.Y. State Elec. & Gas Corp., 78 FERC ] 61,114 (1997), 
order on reh'g, 82 FERC ] 61,209, at 61,822 n.4 (1998) (rejecting 
proposed deviations from the pro forma OATT and explaining that the 
``consistent with or superior to'' inquiry does not impermissibly 
supplant or narrow the ``just and reasonable'' standard; rather, it 
evaluates whether a proposed deviation from the ``common starting 
point'' set out in a rule is consistent with or superior to that 
``common starting point'' and therefore remains just and 
reasonable); Commonwealth Edison Co., 83 FERC ] 61,274, at 62,143 
(1998) (citing N.Y. State Elec. & Gas Corp., 82 FERC at 61,822 & 
n.4). See also Xcel Energy Servs. Inc. v. FERC, 41 F.4th 548, 557-58 
(D.C. Cir. 2022) (explaining that the Commission has used its 
``broad discretion'' to craft the ``consistent with or superior to'' 
standard to assess whether proposed deviations are just, reasonable, 
and not unduly discriminatory).
    \2273\ N.Y. State Elec. & Gas Corp., 82 FERC at 61,822 n.4.
---------------------------------------------------------------------------

    922. In response to SPP's clarification request regarding its own 
Consolidated Planning Process, we reiterate that Order No. 1920 
requires transmission providers to demonstrate that proposed deviations 
from Order No. 1920 are ``consistent with or superior to'' the 
requirements in Order No. 1920.\2274\ To the extent that a transmission 
provider, like SPP, believes that its existing practices or potential 
provisions submitted as part of its compliance filing deviate from 
Order No. 1920's requirements, it must demonstrate that any such 
deviations, including any existing processes or OATT provisions, are 
consistent with or superior to the requirements of Order No. 1920.
---------------------------------------------------------------------------

    \2274\ Order No. 1920, 187 FERC ] 61,068 at P 1772.
---------------------------------------------------------------------------

    923. We grant APPA's and TAPS' requests for clarification on the 
role of stakeholders in developing transmission providers' compliance 
filings. Specifically, we clarify that transmission providers must 
consult with their stakeholders to develop the processes, procedures, 
and OATT revisions necessary to comply with Order No. 1920.\2275\ We 
note that this requirement is consistent with the approach that the 
Commission took in Order Nos. 890 and 1000.\2276\
---------------------------------------------------------------------------

    \2275\ We note that the requirement for transmission providers 
to consult with stakeholders to develop their compliance filings is 
separate from and in addition to Order No. 1920's requirement for 
transmission providers to conduct an Engagement Period for Relevant 
State Entities, as discussed in the Cost Allocation section above.
    \2276\ See., e.g., Order No. 890, 118 FERC ] 61,119 at P 582; 
Order No. 1000, 136 FERC ] 61,051 at PP 151, 206, 227, 336, 588, 
793.
---------------------------------------------------------------------------

    924. We grant Large Public Power's clarification request regarding 
reciprocity. Order No. 1920 required that transmission providers that 
are not public utilities must adopt the requirements of Order No. 1920 
as a condition of maintaining the status of their safe harbor tariffs 
or otherwise satisfy the reciprocity requirement of Order No. 
888.\2277\ As relevant to Large Public Power's clarification request, 
Order No. 888 provides that a non-public transmission provider may 
satisfy the reciprocity condition in one of three ways: (1) it may 
provide service under a tariff that has been approved by the Commission 
under the voluntary ``safe harbor'' provision of the pro forma OATT; 
(2) it may provide service to a public utility transmission provider 
under a bilateral agreement; or (3) it may seek a waiver of the 
reciprocity condition from the transmission provider.\2278\
---------------------------------------------------------------------------

    \2277\ Order No. 1920, 187 FERC ] 61,068 at P 1771 (citing Order 
No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63).
    \2278\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------

    925. Issues concerning effective dates are most appropriately 
addressed in specific compliance proceedings and, therefore, we decline 
to grant WIRES' clarification request. However, as explained in the 
Implementation of Long-Term Regional Transmission Planning section 
above, we set aside, in part, Order No. 1920's requirement that 
transmission providers in each transmission planning region must 
propose on compliance a date, no later than one year from the date on 
which initial filings to comply with the final rule are due, on which 
they will commence the first Long-Term Regional Transmission Planning 
cycle \2279\ and instead require transmission providers to propose on 
compliance a date, no later than two years from the date on which 
initial filings to comply with Order No. 1920 are due, on which they 
will commence the first Long-Term Regional Transmission Planning cycle. 
Because we sustain Order No. 1920's requirement that transmission 
providers must propose an effective date for the OATT revisions 
necessary to comply with Order No. 1920 that is no later than the date 
on which they will commence the first Long-Term Regional Transmission 
Planning cycle,\2280\ we note that this modification should help to 
address WIRES' concern.
---------------------------------------------------------------------------

    \2279\ Order No. 1920, 187 FERC ] 61,068 at P 1072.
    \2280\ Order No. 1920, 187 FERC ] 61,068 at P 1768.
---------------------------------------------------------------------------

    926. We note that Versant Power's rehearing request has been

[[Page 97344]]

withdrawn.\2281\ Nevertheless, we clarify that, consistent with Order 
No. 890 and Order No. 1000, entities that have existing waivers of the 
obligation to file an OATT or otherwise offer open access transmission 
service in accordance with Order No. 888, as well as entities that have 
been granted waiver of the regional transmission planning requirements 
of Order No. 1000, do not also have to seek waiver of Order No. 
1920.\2282\ This clarification, however, is not meant to affect the 
ability of an entity that does not have an existing waiver to seek one. 
The Commission will consider requests for waiver of Order No. 1920 on a 
case-by-case basis from any entity that believes it meets the criteria 
for such waiver.
---------------------------------------------------------------------------

    \2281\ See Versant Power September 10, 2024 Notice of 
Withdrawal. Pursuant to Rule 216 of the Commission's Rules of 
Practice and Procedure, the withdrawal of any pleading is effective 
at the end of 15 days from the date of the filing if no motion in 
opposition to the notice of withdrawal is filed within that period 
and if the Commission takes no action disallowing withdrawal. 18 CFR 
385.216. No motion in opposition to Versant Power's Notice of 
Withdrawal has been filed, and its request for rehearing accordingly 
is withdrawn.
    \2282\ Order No. 1000-A, 139 FERC ] 61,132 at P 753 & n.880 
(2012); see also Order No. 890, 118 FERC ] 61,119 at P 135 n.105 
(``The Commission clarifies that existing waivers of the obligation 
to file an OATT or otherwise offer open access transmission service 
in accordance with Order No. 888 shall remain in place. The reforms 
to the pro forma OATT adopted in this Final Rule therefore do not 
apply to transmission providers with such waivers, although we 
expect those transmission providers to participate in the regional 
planning processes in place in their regions, as discussed in more 
detail in section V.B. Whether an existing waiver of OATT 
requirements should be revoked will be considered on a case-by-case 
basis in light of the circumstances surrounding the particular 
transmission provider.'').
---------------------------------------------------------------------------

XIV. Overarching Logical Outgrowth Challenges

A. Requests for Rehearing

    927. Several rehearing parties argue broadly that Order No. 1920 is 
not a logical outgrowth of the NOPR and therefore violates the notice-
and-comment requirements of the APA.\2283\ Arizona Commission asserts 
that the Commission failed to provide notice of and opportunity to 
comment on six ``fundamental'' changes between the NOPR and Order No. 
1920 and that, because such changes are not logical outgrowths of the 
NOPR, the Commission violated the APA's notice-and-comment 
requirements, rendering Order No. 1920 unlawful.\2284\ Specifically, 
Arizona Commission alleges that Order No. 1920, unlike the NOPR: (1) 
imposed preferential and corporate-driven costs on consumers in non-
consenting states by requiring the filing of one or more ex ante cost 
allocation methods to apply to selected Long-Term Transmission 
Facilities; (2) mandated a specific set of ``planning criteria'' and 
purported benefits, which is ``simply a way of `pre-cooking' 
outcomes''; (3) abandoned regional cost allocation principle (6); (4) 
effectively eliminated the use of a voluntary State Agreement Process; 
(5) left the CWIP incentive intact; and (6) made local transmission 
planning less transparent.\2285\
---------------------------------------------------------------------------

    \2283\ Arizona Commission Rehearing Request at 18-19 (citing 5 
U.S.C. 706(2)(A), (C), (D)); Designated Retail Regulators Rehearing 
Request at 44, 49 (citing 5 U.S.C. 553); NRECA Rehearing Request at 
6, 19 (citing 5 U.SC. 553).
    \2284\ Arizona Commission Rehearing Request at 18-19.
    \2285\ Arizona Commission Rehearing Request at 18-19. Id.
---------------------------------------------------------------------------

    928. NRECA alleges that Order No. 1920 violated the APA's notice-
and-comment requirements by: (1) mandating that transmission providers 
use a set of seven required benefits for evaluating and selecting Long-
Term Regional Transmission Facilities; (2) imposing specific 
requirements for limited reevaluation of previously selected Long-Term 
Regional Transmission Facilities; (3) requiring that certain 
interconnection-related transmission needs must be evaluated for 
selection in existing Order No. 1000 regional transmission planning and 
cost allocation processes; (4) not requiring Long-Term Regional 
Transmission Planning cost allocation methods to comply with all of the 
Commission's six regional cost allocation principles; and (5) 
substantially diminishing the proposed role of state regulators in 
Long-Term Regional Transmission Planning and cost allocation.\2286\ 
NRECA requests that the Commission withdraw Order No. 1920 and issue a 
supplemental NOPR because ``so many of [Order No. 1920's] key 
provisions'' are ``brand new'' and were not subjected to public 
comment.\2287\
---------------------------------------------------------------------------

    \2286\ NRECA Rehearing Request at 6.
    \2287\ Id. at 19.
---------------------------------------------------------------------------

    929. Designated Retail Regulators contend that Order No. 1920 
contains a number of significant changes that drastically depart from 
the NOPR, rendering the final rule ``surprisingly distant'' from and 
not a logical outgrowth of the NOPR, in violation of the APA's notice-
and-comment requirements.\2288\ Designated Retail Regulators add that 
Order No. 1920 ``is in essence a new rule that requires new 
opportunities for comment and input.'' \2289\ Designated Retail 
Regulators claim that Order No. 1920 differs from the NOPR because 
Order No. 1920: (1) declined to adopt the NOPR proposal requiring 
transmission providers to seek the agreement of Relevant State Entities 
and substantially diminished Relevant State Entity involvement in cost 
allocation; (2) provided transmission providers complete discretion to 
decide whether to file a State Agreement Process or Long-Term Regional 
Transmission Cost Allocation Method in its tariff, even if agreed to by 
Relevant State Entities; and (3) did not require transmission providers 
to obtain the support of Relevant State Entities prior to proposing an 
evaluation process and selection criteria on compliance.\2290\
---------------------------------------------------------------------------

    \2288\ Designated Retail Regulators Rehearing Request at 46-50 
(quoting Int'l Union, United Mine Workers of Am. v. Mine Safety and 
Health Admin., 407 F.3d 1250, 1260 (D.C. Cir. 2005)).
    \2289\ Id. at 10.
    \2290\ Id. at 46-50.
---------------------------------------------------------------------------

B. Commission Determination

    930. We disagree with Arizona Commission's, Designated Retail 
Regulators', and NRECA's arguments that Order No. 1920 violates the 
APA's notice-and-comment requirements and is not a logical outgrowth of 
the NOPR. Relatedly, we decline to adopt NRECA's suggestion that the 
Commission withdraw Order No. 1920 in its entirety and issue a 
supplemental NOPR. As an initial matter, rehearing parties' conclusory 
arguments lack the specificity required to satisfy FPA section 313(a), 
which states that an ``application for rehearing shall set forth 
specifically the ground or grounds upon which such application is 
based.'' \2291\ In claiming that Order No. 1920 violated the APA's 
notice-and-comment requirements, rehearing parties merely point to 
sections or provisions of Order No. 1920 that allegedly run afoul of 
those requirements and then assert, without support or further 
explanation, that Order No. 1920, as a whole, violates the APA's 
notice-and-comment provision. Arizona Commission, Designated Retail 
Regulators, and NRECA do not cite, and we are unaware of, any precedent 
supporting what appears to be their claim that cumulative logical 
outgrowth challenges to individual provisions would compel a finding 
that Order No. 1920, as a whole, is not a logical outgrowth of the 
NOPR. Accordingly, we reject this sweeping argument as lacking the 
specificity required on rehearing.\2292\
---------------------------------------------------------------------------

    \2291\ 16 U.S.C. 825l(a) (emphasis added).
    \2292\ A rehearing request must set forth with specificity the 
grounds on which the request is based. 16 U.S.C. 825l(a); 18 CFR 
385.713(c)(2) (2024); see ZEP Grand Prairie Wind, LLC, 183 FERC ] 
61,150, at P 10; Ind. Util. Regul. Comm'n v. FERC, 668 F.3d at 738-
40.
---------------------------------------------------------------------------

    931. In any event, these arguments also lack merit. As discussed 
throughout this order, the individual provisions of

[[Page 97345]]

Order No. 1920, which certain rehearing parties claim the Commission 
adopted without adequate notice and opportunity to comment, are, in 
fact, logical outgrowths of the NOPR and otherwise satisfy the APA's 
notice-and-comment requirements.\2293\ Thus, given that the constituent 
components of Order No. 1920 satisfy the APA's notice-and-comment 
requirements, the sum of those components--i.e., Order No. 1920 as a 
whole--necessarily also satisfies these requirements, and rehearing 
parties have not shown otherwise.
---------------------------------------------------------------------------

    \2293\ See supra Requirement for Transmission Providers to Use 
and Measure a Set of Seven Required Benefits section; Minimum 
Requirements section; Role of Relevant State Entities section; 
Reevaluation section; Transmission Planning Process Evaluation 
section; Obligation to File an Ex Ante Long-Term Regional 
Transmission Cost Allocation Method and Its Use as a Backstop 
section; Design and Operation of the Engagement Period section; 
Regional Cost Allocation Principles for Long-Term Regional 
Transmission Facilities section; General Benefits Requirements 
Related to Cost Allocation section; CWIP section.
---------------------------------------------------------------------------

XV. Information Collection Statement

    932. The Paperwork Reduction Act \2294\ requires each Federal 
agency to seek and obtain the Office of Management and Budget's (OMB) 
approval before undertaking a collection of information directed to 10 
or more persons or contained in a rule of general applicability. OMB 
regulations require approval of certain information collection 
requirements contained in final rules published in the Federal 
Register.\2295\ Upon approval of a collection of information, OMB will 
assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of this order on rehearing will not 
be penalized for failing to respond to the collection of information 
unless the collection of information displays a valid OMB control 
number.
---------------------------------------------------------------------------

    \2294\ 44 U.S.C. 3501-3521.
    \2295\ See 5 CFR 1320.12 (2024).
---------------------------------------------------------------------------

    933. Summary: On rehearing of Order No. 1920, the Commission is 
further revising the pro forma OATT to remedy deficiencies in the 
Commission's existing regional transmission planning and cost 
allocation and local transmission planning requirements. This order on 
rehearing addresses arguments raised on rehearing, sets aside, in part, 
and clarifies Order No. 1920. The information collection requirements 
included in Order No. 1920 were previously approved by OMB under the 
FERC information collection number FERC-917: Electric Transmission 
Facilities (OMB Control No. 1902-0233). Order No. 1920 required 
transmission providers to conduct Long-Term Regional Transmission 
Planning to ensure the identification, evaluation, and selection, as 
well as the allocation of the costs, of more efficient or cost-
effective regional transmission solutions to address Long-Term 
Transmission Needs.
    934. Previously, the Commission submitted to OMB the information 
collection requirements arising from Order No. 1920, and OMB approved 
those requirements. In this order on rehearing, the Commission makes 
five substantive changes to those requirements. In Order No. 1920, the 
Commission required transmission providers in each transmission 
planning region to incorporate seven specific categories of factors in 
the development of Long-Term Scenarios.\2296\ Here, we set aside, in 
part, the requirement for transmission providers to incorporate seven 
specific categories of factors in the development of Long-Term 
Scenarios by excluding corporate commitments from Factor Category 
Seven. We no longer require transmission providers to separately 
identify corporate commitments as a factor in their development of 
Long-Term Scenarios given that the effects of such commitments will be 
sufficiently incorporated in Long-Term Regional Transmission Planning 
through the incorporation of other Factor Categories.
---------------------------------------------------------------------------

    \2296\ Order No. 1920, 187 FERC ] 61,068 at P 409.
---------------------------------------------------------------------------

    935. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to develop, at least 
once during the five-year Long-Term Regional Transmission Planning 
cycle, at least three distinct Long-Term Scenarios.\2297\ Here, we 
clarify that transmission providers, when requested by Relevant State 
Entities in a transmission planning region, are required to conduct a 
reasonable number of additional analyses or scenarios, to provide 
Relevant State Entities with information that they can use to inform 
the application of Long-Term Regional Cost Allocation Method(s) or the 
development of cost allocation methods through the State Agreement 
Process(es).
---------------------------------------------------------------------------

    \2297\ Id. P 559.
---------------------------------------------------------------------------

    936. In Order No. 1920, the Commission required transmission 
providers in each transmission planning region to revise the regional 
transmission planning process in their OATTs to outline an open and 
transparent process that provides stakeholders, including federally-
recognized Tribes and states, with a meaningful opportunity to propose 
potential factors and to provide timely input on how to account for 
specific factors in the development of Long-Term Scenarios.\2298\ In 
addition, the Commission required transmission providers to post this 
information after stakeholders, including states, have had the 
meaningful opportunity to propose potential factors and to provide 
input on how to account for specific factors in the development of 
Long-Term Scenarios.\2299\ Here, we clarify that transmission providers 
must consult with and consider the positions of the Relevant State 
Entities and any other entity authorized by a Relevant State Entity as 
its representative as to how to account for factors related to states' 
laws, policies, and regulations when determining the assumptions that 
will be used in the development of Long-Term Scenarios.
---------------------------------------------------------------------------

    \2298\ Id. P 528.
    \2299\ Id. P 533.
---------------------------------------------------------------------------

    937. In Order No. 1920, the Commission required transmission 
providers' evaluation processes, including selection criteria, to be 
transparent and not unduly discriminatory, and the Commission explained 
that transmission providers' evaluation of Long-Term Regional 
Transmission Facilities must culminate in a determination that is 
sufficiently detailed for stakeholders to understand why a particular 
Long-Term Regional Transmission Facility (or portfolio of Long-Term 
Regional Transmission Facilities) was selected or not selected.\2300\ 
Here, we clarify that, once a transmission provider makes a selection 
decision, i.e., for each selected Long-Term Regional Transmission 
Facility (or portfolio of such Facilities), and, if a State Agreement 
Process is used, once a cost allocation method is agreed upon, 
transmission providers must make available, on a password-protected 
portion of OASIS or other password-protected website, a breakdown of 
how those estimated costs will be allocated, by zone (i.e., by 
transmission provider retail distribution service territory/footprint 
or RTO/ISO transmission pricing zone), and a quantification of those 
estimated benefits as imputed to each zone, as such benefits can be 
reasonably estimated.
---------------------------------------------------------------------------

    \2300\ Id. P 954.
---------------------------------------------------------------------------

    938. In Order No. 1920, the Commission declined to require future 
Engagement Periods, but noted that transmission providers may hold 
future Engagement Periods if they believe that such periods would be 
beneficial.\2301\ Here, we set aside Order No. 1920, in part, and 
require that, as part of

[[Page 97346]]

transmission providers' obligations with respect to transmission 
planning and cost allocation, transmission providers shall consult with 
Relevant State Entities (1) prior to amending the Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es), or (2) if Relevant State Entities seek, consistent with 
their chosen method to reach agreement, for the transmission provider 
to amend that method or process.
---------------------------------------------------------------------------

    \2301\ Order No. 1920, 187 FERC ] 61,068 at P 1368.
---------------------------------------------------------------------------

    939. Public Reporting Burden: The estimated burden and cost for the 
requirements contained in this order on rehearing follow.
---------------------------------------------------------------------------

    \2302\ In the table, Year 1 figures are one-time implementation 
hours and cost. ``Subsequent years'' show ongoing burdens and costs 
starting in Year 2.
    \2303\ The hourly cost (for salary plus benefits) uses the 
figures from the Bureau of Labor Statistics (BLS) for three 
positions involved in the reporting and recordkeeping requirements. 
These figures include salary (based on BLS data for May 2022, issued 
April 25, 2023, http://bls.gov/oes/current/naics2_22.htm) and 
benefits (based on BLS data for September 2023; issued December 15, 
2023, http://www.bls.gov/news.release/ecec.nr0.htm) and are Manager 
(Occupation Code 11-0000, $122.48/hour), Electrical Engineer 
(Occupation Code 17-2071, $89.04/hour), and File Clerk (Occupation 
Code 43-4071, $42.43/hour). The hourly cost for the reporting 
requirements ($105.76) is an average of the hourly cost (wages plus 
benefits) of a manager and engineer. The hourly cost for 
recordkeeping requirements uses the cost of a file clerk.

                       Changes Due to Order on Rehearing in Docket No. RM21-17-001 \2302\
----------------------------------------------------------------------------------------------------------------
                                                           C. Total                           E. Total estimated
                                                            annual       D. Average burden      burden hours &
     A. Area of modification        B. Annual number of    estimated    hours & cost \2303\    total estimated
                                        respondents        number of       per response        cost (column C x
                                                           responses                              column D)
----------------------------------------------------------------------------------------------------------------
                     FERC-917, Electric Transmission Facilities (OMB Control No. 1902-0233)
----------------------------------------------------------------------------------------------------------------
Establish a six-month time period  48 transmission                 48  One Time: 390 hours;  One Time: 18,720
 during which transmission          providers with                      $36,307.              hours; $1,742,734.
 providers must, among other        OATTs.                             Ongoing: 39 hours     Ongoing: 1,872
 things, provide a forum for                                            per year; $3,631      hours per year;
 negotiation that enables                                               per year.             $174,274 per year.
 participation by Relevant State
 Entities and to discuss
 potential Long-Term Regional
 Transmission Cost Allocation
 Methods and/or a State Agreement
 Process. Also require
 transmission providers to
 consult with Relevant State
 Entities prior to amending Long-
 Term Regional Transmission Cost
 Allocation Methods and/or State
 Agreement Process on file with
 the Commission.
----------------------------------------------------------------------------------------------------------------
Participate in Long-Term Regional  48 transmission                 48  One Time: 0 hours;    One Time: 0 hours;
 Transmission Planning, which       providers with       ............   $0.                   $0.
 includes creating and updating     OATTs.               ............  Ongoing: 4,995 hours  Ongoing: 239,760
 datasets, developing Long-Term    ....................            77   per year; $465,010    hours per year;
 Scenarios, evaluating the         77 transmission                      per year.             $22,320,457 per
 benefits of Long-Term Regional     providers without                  One Time: 0 hours;     year.
 Transmission Facilities, and       OATTs.                              $0.                  One Time: 0 hours;
 establishing criteria in                                              Ongoing: 202 hours     $0.
 consultation with Relevant State                                       per year; $18,805    Ongoing: 15,554
 Entities and stakeholders to                                           per year.             hours per year;
 select Long-Term Regional                                                                    $1,448,000 per
 Transmission Facilities in the                                                               year.
 regional transmission plan for
 purposes of cost allocation.
Total new burden for FERC 917      48 transmission                 48  One Time: 1,113       One Time: 53,424
 (due to Docket No. RM21-17-001).   providers with                      hours; $103,614.      hours; $4,973,495
                                    OATTs.                             Ongoing: 5,329 hours  Ongoing: 255,792
                                                                        per year; $496,103    hours per year;
                                                                        per year.             $23,812,956 per
                                                                                              year
                                   77 transmission                 77  One Time: 20 hours;   One Time: 1,540
                                    providers without                   $1,862.               hours; $143,366.
                                    OATTs.                             Ongoing: 262 hours    Ongoing: 20,174
                                                                        per year; $24,391     hours per year;
                                                                        per year.             $1,878,099 per
                                                                                              year.
                                  ----------------------------------------------------------
                                           Totals for all 125 transmission providers         One Time: 54,964
                                                                                              hours; $5,116,861.
                                                                                             Ongoing: 275,966
                                                                                              hours per year;
                                                                                              $25,691,055 per
                                                                                              year.
----------------------------------------------------------------------------------------------------------------

    940. Order No. 1920 estimated the ongoing total burden and cost for 
the 48 transmission providers with OATTs to be 230,160 total hours per 
year and $21,426,693 per year. Similarly, Order No. 1920 estimated the 
ongoing total burden and cost for the 77 transmission providers without 
OATTs to be 20,020 total hours per year and $1,863,757 per year. Given 
the prior discussion regarding excluding corporate commitments from 
Factor Category Seven and clarifications related to the potential for 
additional scenarios, additional consultation with Relevant State 
Entities, and posting or making available certain details of a 
selection decision on OASIS or other password-protected website, we 
estimate that these changes will result in an increase of burden hours. 
Therefore, we estimate that the ongoing total burden and cost, as 
revised herein, for the 48 transmission providers with OATTs to be 
255,792 total hours per year and $23,812,956 per year. Similarly, we 
estimate that the ongoing total burden and cost, as revised herein, for 
the 77 transmission providers without OATTs to be 20,174 total hours 
per year and $1,878,099 per year. No other information collection 
requirements contained in Order No. 1920 are affected by this order on 
rehearing.
    941. Title: Electric Transmission Facilities (FERC-917).
    942. Action: Revision of collections of information in accordance 
with Docket No. RM21-17-001.
    943. OMB Control No.: 1902-0233 (FERC-917).
    944. Respondents: Transmission providers, including RTOs/ISOs.
    945. Frequency of Information Collection: One time during Year 1. 
Occasional times during subsequent years, at least once every five 
years.

[[Page 97347]]

    946. Necessity of Information: The modifications in this order on 
rehearing will correct deficiencies in the Commission's existing 
regional transmission planning and cost allocation and local 
transmission planning requirements to ensure that Commission-
jurisdictional rates remain just and reasonable and not unduly 
discriminatory or preferential.
    947. Internal Review: We have reviewed the requirements set forth 
in this order on rehearing that impose information collection burdens 
and have determined that such requirements are necessary. These 
requirements conform to the Commission's need for efficient information 
collection, communication, and management within the energy industry. 
We have specific, objective support for the burden estimates associated 
with the information collection requirements.
    948. Interested persons may obtain information on the reporting 
requirements by contacting Kayla Williams, Office of the Executive 
Director, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426 via email ([email protected]) or telephone 
(202) 502-6468.
    949. Comments concerning the collection of information and the 
associated burden estimates may also be sent to: Office of Information 
and Regulatory Affairs, Office of Management and Budget, 725 17th 
Street NW, Washington, DC 20503 [Attention: Desk Officer for the 
Federal Energy Regulatory Commission]. Due to security concerns, 
comments should be sent electronically to the following email address: 
[email protected]. Comments submitted to OMB should refer to 
FERC-917 (OMB Control No. 1902-0233). Copies of the comments can be 
sent to the Commission (identified by Docket No. RM21-17-001 and the 
specific FERC collection number (FERC-917) electronically through 
https://www.ferc.gov. For those unable to file electronically, comment 
copies may be filed by USPS mail or by hand (including courier) 
delivery: Mail via U.S. Postal Service Only: Addressed to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street NE, Washington, DC 20426. Or hand (including courier) delivery: 
Deliver to: Federal Energy Regulatory Commission, 12225 Wilkins Avenue, 
Rockville, MD 20852.

XVI. Environmental Analysis

    950. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\2304\ The 
Commission has categorically excluded certain actions from this 
requirement including approval of actions under FPA sections 205 and 
206 relating to the filing of schedules containing all rates and 
charges for the transmission or sale of electric energy subject to the 
Commission's jurisdiction, plus the classification, practices, 
contracts and regulations that affect rates, charges, classifications, 
and services.\2305\ Because the final rule promulgated by Order No. 
1920, and revised herein, falls within this categorical exclusion, 
preparation of an environmental assessment or an environmental impact 
statement is not required.
---------------------------------------------------------------------------

    \2304\ Reguls. Implementing the Nat'l Env'l Pol'y Act, Order No. 
486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ] 30,783 
(1987) (cross-referenced at 41 FERC ] 61,284).
    \2305\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

XVII. Regulatory Flexibility Act

    951. The Regulatory Flexibility Act of 1980 (RFA) \2306\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small entities. 
The Small Business Administration (SBA) sets the threshold for what 
constitutes a small business. Under SBA's size standards,\2307\ RTOs/
ISOs, transmission planning regions, and transmission owners all fall 
under the category of Electric Bulk Power Transmission and Control 
(NAICS code 221121), with a size threshold of 950 employees (including 
the entity and its associates).\2308\
---------------------------------------------------------------------------

    \2306\ 5 U.S.C. 601-612.
    \2307\ 13 CFR 121.201.
    \2308\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
SBA's regulations define the threshold for a small Electric Bulk 
Power Transmission and Control entity (NAICS code 221121) to be 950 
employees. 13 CFR 121.201; see 5 U.S.C. 601(3) (citing section 3 of 
the Small Business Act, 15 U.S.C. 632).
---------------------------------------------------------------------------

    952. In Order No. 1920, the Commission, pursuant to RFA section 
605(b), certified that the final rule would not have a significant 
economic impact on a substantial number of small entities.\2309\ This 
order on rehearing does not disturb that conclusion. For the same 
reasons cited in Order No. 1920,\2310\ the final rule, as revised 
herein, would not have a significant economic impact on a substantial 
number of small entities.
---------------------------------------------------------------------------

    \2309\ Order No. 1920, 187 FERC ] 61,068 at P 1788.
    \2310\ See id.
---------------------------------------------------------------------------

XVIII. Document Availability

    953. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the Commission's Home Page (http://www.ferc.gov).
    954. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    955. User assistance is available for eLibrary and the Commission's 
website during normal business hours from FERC Online Support at 202-
502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

XIX. Effective Date

    956. The changes to Order No. 1920 made in this order on rehearing 
and clarification are effective January 6, 2025.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission. Commissioner Christie is concurring in part with 
a separate statement attached. Commissioner See is not participating.

    Issued: November 21, 2024.
Debbie-Anne A. Reese,
Secretary.
    Note: The following appendices will not appear in the Code of 
Federal Regulations.

[[Page 97348]]

Appendix A: Abbreviated Names of Parties

------------------------------------------------------------------------
         Abbreviation                     Rehearing party(ies)
------------------------------------------------------------------------
Advanced Energy..............  Advanced Energy United.
Alabama Commission...........  Alabama Public Service Commission.
APPA.........................  American Public Power Association.
Arizona Commission...........  Arizona Corporation Commission.
Cher Gilmore.................  Cher Gilmore.
City of New Orleans Council..  Council of the City of New Orleans.
Clean Energy Associations....  Advanced Energy United; American Clean
                                Power Association; American Council on
                                Renewable Energy; Solar Energy
                                Industries Association.
Clean Energy Buyers..........  Clean Energy Buyers Association.
Competition Coalition........  Electricity Transmission Competition
                                Coalition; Resale Power Group of Iowa;
                                LS Power Grid, LLC.
CTC Global...................  CTC Global Corporation.
Dairyland....................  Dairyland Power Cooperative.
Designated Retail Regulators.  Louisiana Public Service Commission;
                                Mississippi Public Service Commission;
                                Arkansas Public Service Commission;
                                South Dakota Public Utilities
                                Commission.
Dominion.....................  Dominion Energy Services, Inc.
E. Andrews...................  E. Andrews.
East Kentucky................  East Kentucky Power Cooperative, Inc.
EEI..........................  Edison Electric Institute.
Gary Andrews.................  Gary Andrews.
Georgia Commission...........  Georgia Public Service Commission.
Grid United..................  Grid United LLC.
Harvard ELI..................  Harvard Electricity Law Initiative.
Idaho Commission.............  Idaho Public Utilities Commission.
Identified Consumer Advocates  Office of the Massachusetts Attorney
                                General; Connecticut Office of Consumer
                                Counsel; Maine Office of Public
                                Advocate; Maryland Office of People's
                                Counsel; New Hampshire Office of
                                Consumer Advocate; Rhode Island Division
                                of Public Utilities and Carriers.
Illinois Commission..........  Illinois Commerce Commission.
Indicated PJM TOs............  American Electric Power Service
                                Corporation on behalf of its affiliates,
                                Appalachian Power Company, Indiana
                                Michigan Power Company, Kentucky Power
                                Company, Kingsport Power Company, Ohio
                                Power Company, Wheeling Power Company,
                                AEP Appalachian Transmission Company,
                                Inc., AEP Indiana Michigan Transmission
                                Company, Inc., AEP Kentucky Transmission
                                Company, Inc., AEP Ohio Transmission
                                Company, Inc., and AEP West Virginia
                                Transmission Company, Inc.; Dayton Power
                                and Light Company; Dominion Energy
                                Services, Inc. on behalf of Virginia
                                Electric and Power Company; Duke Energy
                                Corporation on behalf of its affiliates
                                Duke Energy Ohio, Inc., Duke Energy
                                Kentucky, Inc., and Duke Energy Business
                                Services LLC; Duquesne Light Company;
                                East Kentucky Power Cooperative; Exelon
                                Corporation on behalf of its affiliates
                                Atlantic City Electric Company,
                                Baltimore Gas and Electric Company,
                                Commonwealth Edison Company, Delmarva
                                Power & Light Company, PECO Energy
                                Company, and Potomac Electric Power
                                Company; FirstEnergy Service Company, on
                                behalf of its affiliates American
                                Transmission Systems, Incorporated,
                                Jersey Central Power & Light Company,
                                Mid-Atlantic Interstate Transmission
                                LLC, West Penn Power Company, Potomac
                                Edison Company, Monongahela Power
                                Company, Keystone Appalachian
                                Transmission Company, and Trans-
                                Allegheny Interstate Line Company; PPL
                                Electric Utilities Corporation; Public
                                Service Electric and Gas Company; UGI
                                Utilities Inc.
Industrial Customers.........  American Forest & Paper Association;
                                Coalition of MISO Transmission
                                Customers; Industrial Energy Customers
                                of America; PJM Industrial Customer
                                Coalition.
Invenergy....................  Invenergy Solar Development North America
                                LLC; Invenergy Thermal Development LLC;
                                Invenergy Wind Development North America
                                LLC; Invenergy Transmission LLC.
ITC..........................  International Transmission Company;
                                Michigan Electric Transmission Company,
                                LLC; ITC Midwest LLC; ITC Great Plains,
                                LLC.
Large Public Power...........  Large Public Power Council.
MISO TOs.....................  Ameren Services Company, as agent for
                                Union Electric Company, Ameren Illinois
                                Company, and Ameren Transmission Company
                                of Illinois; American Transmission
                                Company LLC; Big Rivers Electric
                                Corporation; Central Minnesota Municipal
                                Power Agency; City Water, Light & Power
                                (Springfield, IL); Cleco Power LLC;
                                Cooperative Energy; Dairyland Power
                                Cooperative; Duke Energy Business
                                Services, LLC for Duke Energy Indiana,
                                LLC; Great River Energy; Hoosier Energy
                                Rural Electric Cooperative, Inc.;
                                Indiana Municipal Power Agency;
                                Indianapolis Power & Light Company;
                                International Transmission Company; ITC
                                Midwest LLC; Lafayette Utilities System;
                                Michigan Electric Transmission Company,
                                LLC; MidAmerican Energy Company;
                                Minnesota Power (and its subsidiary
                                Superior Water, L&P); Montana-Dakota
                                Utilities Co.; Northern Indiana Public
                                Service Company LLC; Northern States
                                Power Company, a Minnesota corporation,
                                and Northern States Power Company, a
                                Wisconsin corporation, subsidiaries of
                                Xcel Energy Inc.; Northwestern Wisconsin
                                Electric Company; Otter Tail Power
                                Company; Prairie Power, Inc.; Southern
                                Illinois Power Cooperative; Southern
                                Indiana Gas & Electric Company; Southern
                                Minnesota Municipal Power Agency; Wabash
                                Valley Power Association, Inc.;
                                Wolverine Power Supply Cooperative, Inc.
Minnesota Commission.........  Minnesota Public Utilities Commission.
Missouri Commission..........  Missouri Public Service Commission.
Montana Commission...........  Montana Public Service Commission.
NARUC........................  National Association of Regulatory
                                Utility Commissioners.
NESCOE.......................  New England States Committee on
                                Electricity.
Northern Virginia............  Northern Virginia Electric Cooperative,
                                Inc.
NRECA........................  National Rural Electric Cooperative
                                Association.
Ohio Commission Federal        Public Utilities Commission of Ohio's
 Advocate.                      Office of the Federal Energy Advocate.
Ohio Consumers...............  Office of the Ohio Consumers Council.
Old Dominion.................  Old Dominion Electric Cooperative.
Pennsylvania Commission......  Pennsylvania Public Utility Commission.
PIOs.........................  Appalachian Voices; Energy Alabama;
                                Environmental Defense Fund;
                                Environmental Law & Policy Center;
                                Natural Resources Defense Council; North
                                Carolina Sustainable Energy Association;
                                Sierra Club; South Carolina Coastal
                                Conservation League; Southern Alliance
                                for Clean Energy; Southern Renewable
                                Energy Association; Sustainable FERC
                                Project.
PJM..........................  PJM Interconnection, L.L.C.
PJM States...................  Organization of PJM States, Inc.

[[Page 97349]]

 
PJM Utilities................  East Kentucky Power Cooperative, Inc.;
                                Buckeye Power, Inc.; Old Dominion
                                Electric Cooperative; Wabash Valley
                                Power Association.
SERTP Sponsors...............  Associated Electric Cooperative, Inc.;
                                Dalton Utilities; Duke Energy Carolinas,
                                LLC and Duke Energy Progress, LLC;
                                Georgia Transmission Corporation;
                                Louisville Gas and Electric Company and
                                Kentucky Utilities Company; Municipal
                                Electric Authority of Georgia;
                                PowerSouth Energy Cooperative; Southern
                                Company Services, Inc., acting as agent
                                for Alabama Power Company, Georgia Power
                                Company, and Mississippi Power Company;
                                Tennessee Valley Authority.
SPP..........................  Southwest Power Pool, Inc.
State Regulatory               Riley Allen (Commissioner, State of
 Commissioners.                 Vermont Public Utility Commission);
                                Philip L. Bartlett II (Chair, Maine
                                Public Utilities Commission); Kumar P.
                                Barve (Commissioner, Maryland Public
                                Service Commission); Eric Blank
                                (Chairman, Colorado Public Utilities
                                Commission); Alessandra Carreon
                                (Commissioner, Michigan Public Service
                                Commission); Michael T. Carrigan
                                (Commissioner, Illinois Commerce
                                Commission); David W. Danner (Chair,
                                Washington Utilities and Transportation
                                Commission); Megan Decker (Chair, Oregon
                                Public Utilities Commission); Milt
                                Doumit (Commissioner, Washington
                                Utilities and Transportation
                                Commission); Sarah Freeman
                                (Commissioner, Indiana Utility
                                Regulatory Commission); Andrew French
                                (Chairperson, Kansas Corporation
                                Commission); Marissa P. Gillett
                                (Chairman, Connecticut Public Utilities
                                Regulatory Authority); Hwikwon Ham
                                (Commissioner, Minnesota Public
                                Utilities Commission); Frederick H.
                                Hoover (Chair, Maryland Public Service
                                Commission); Darcie Houck (Commissioner,
                                California Public Utilities Commission);
                                Davante Lewis (Commissioner, Louisiana
                                Public Service Commission); Ann McCabe
                                (Commissioner, Illinois Commerce
                                Commission); Valerie Means
                                (Commissioner, Minnesota Public
                                Utilities Commission); Stacey Paradis
                                (Commissioner, Illinois Commerce
                                Commission); Katherine Peretick
                                (Commissioner, Michigan Public Service
                                Commission); Les Perkins (Commissioner,
                                Oregon Public Utilities Commission); Ann
                                E. Rendahl (Commissioner, Washington
                                Utilities and Transportation
                                Commission); Alice Reynolds (President,
                                California Public Utilities Commission);
                                Michael T. Richard (Commissioner,
                                Maryland Public Service Commission);
                                Doug P. Scott (Chairman, Illinois
                                Commerce Commission); Dan Scripps
                                (Chair, Michigan Public Service
                                Commission); Katie Sieben (Chair,
                                Minnesota Public Utilities Commission);
                                Bonnie A. Suchman (Commissioner,
                                Maryland Public Service Commission);
                                Joseph Sullivan (Vice Chair, Minnesota
                                Public Utilities Commission); Letha
                                Tawney (Commissioner, Oregon Public
                                Utilities Commission); Emile C. Thompson
                                (Chairman, District of Columbia Public
                                Service Commission); Ted Trabue
                                (Commissioner, District of Columbia
                                Public Service Commission); John Tuma
                                (Commissioner, Minnesota Public
                                Utilities Commission).
Susann Rizzo.................  Susann Rizzo.
TAPS.........................  Transmission Access Policy Study Group.
Undersigned States...........  Texas Attorney General; Alabama Attorney
                                General; Arkansas Attorney General;
                                Florida Attorney General; Georgia
                                Attorney General; Idaho Attorney
                                General; Iowa Attorney General; Kansas
                                Attorney General; Kentucky Attorney
                                General; Louisiana Attorney General;
                                Mississippi Attorney General; Montana
                                Attorney General; Nebraska Attorney
                                General; North Dakota Attorney General;
                                Oklahoma Attorney General; South
                                Carolina Attorney General; South Dakota
                                Attorney General; Tennessee Attorney
                                General; Utah Attorney General.
Utah Commission..............  Utah Public Service Commission.
Vermont Commission...........  Vermont Public Utility Commission.
Versant Power................  Versant Power.
Virginia Attorney General....  Virginia Office of the Attorney General,
                                Division of Consumer Counsel.
Virginia and North Carolina    Virginia State Corporation Commission;
 Commissions.                   North Carolina Utilities Commission.
West Virginia Commission.....  Public Service Commission of West
                                Virginia.
WIRES........................  WIRES.
Wyoming Commission...........  Wyoming Public Service Commission.
------------------------------------------------------------------------

Appendix B: Pro Forma Open Access Transmission Tariff Attachment K

    Note: Proposed deletions are in brackets and proposed additions 
are in italics.

Attachment K

Transmission Planning Process

Local Transmission Planning

    The Transmission Provider shall establish a coordinated, open, 
and transparent local transmission planning process with its Network 
and Firm Point-to-Point Transmission Customers and other interested 
parties to ensure that the Transmission System is planned to meet 
the needs of both the Transmission Provider and its Network and Firm 
Point-to-Point Transmission Customers on a comparable and not unduly 
discriminatory basis. The Transmission Provider's coordinated, open, 
and transparent local transmission planning process shall be 
provided as an attachment to the Transmission Provider's Tariff. The 
Transmission Provider's local transmission planning process shall 
provide stakeholders with meaningful opportunities to participate 
and provide feedback, and shall satisfy the following nine 
principles, as defined in Order No. 890: coordination, openness, 
transparency, information exchange, comparability, dispute 
resolution, regional participation, economic planning studies, and 
cost allocation for new transmission projects. The local 
transmission planning process also shall include the procedures and 
mechanisms for considering transmission needs driven by Public 
Policy Requirements consistent with Order No. 1000. The local 
transmission planning process also shall provide a mechanism for the 
recovery and allocation of transmission planning costs consistent 
with Order No. 890. The description of the Transmission Provider's 
local transmission planning process must include sufficient detail 
to enable Transmission Customers to understand:
    (i) The process for consulting with customers;
    (ii) The notice procedures and anticipated frequency of 
meetings;
    (iii) The methodology, criteria, and processes used to develop a 
transmission plan;
    (iv) The method of disclosure of criteria, assumptions, and data 
underlying a transmission plan;
    (v) The obligations of and methods for Transmission Customers to 
submit data to the Transmission Provider;
    (vi) The dispute resolution process;
    (vii) The Transmission Provider's study procedures for economic 
upgrades to address congestion or the integration of new resources;
    (viii) The Transmission Provider's procedures and mechanisms for 
considering transmission needs driven by Public Policy Requirements, 
consistent with Order No. 1000; and
    (ix) The relevant cost allocation method or methods.

Regional Transmission Planning

    The Transmission Provider shall participate in a regional 
transmission planning process through which transmission facilities 
and non-transmission alternatives may be proposed and evaluated. The 
regional transmission planning process also shall develop a regional 
transmission plan that identifies the transmission facilities 
necessary to meet the needs of transmission providers and 
transmission customers in the transmission planning region. The 
regional transmission planning process must be consistent with the 
provision of Commission-

[[Page 97350]]

jurisdictional services at rates, terms, and conditions that are 
just and reasonable and not unduly discriminatory or preferential, 
as described in Order Nos. 1000 and 1920. The regional transmission 
planning process shall be described in an attachment to the 
Transmission Provider's Tariff.
    The Transmission Provider's regional transmission planning 
process shall satisfy the following seven principles, as established 
in Order Nos. 890 and 1000: coordination, openness, transparency, 
information exchange, comparability, dispute resolution, and 
economic planning studies. The description of the regional 
transmission planning process in the Tariff also shall include the 
procedures and mechanisms for considering transmission needs driven 
by Public Policy Requirements, consistent with Order No. 1000. The 
regional transmission planning process shall provide a mechanism for 
the recovery and allocation of ``transmission planning costs'' 
consistent with Order Nos. 890 and 1000.
    The regional transmission planning process shall include a clear 
enrollment process for public and non-public utility transmission 
providers that make the choice to become part of a transmission 
planning region. The regional transmission planning process shall be 
clear that enrollment will subject enrollees to cost allocation if 
they are found to be beneficiaries of new transmission facilities 
selected in the regional transmission plan for purposes of cost 
allocation. Each Transmission Provider shall maintain a list of 
enrolled entities in the Transmission Provider's Tariff.
    The regional transmission planning process must include at least 
three stakeholder meetings concerning the local transmission 
planning process of each Transmission Provider that is a member of 
the transmission planning region. The three meetings must occur 
before each Transmission Provider's local transmission planning 
information can be incorporated into the transmission planning 
region's transmission planning models. The three stakeholder 
meetings for local transmission planning information are the 
Assumptions Meeting, the Needs Meeting, and the Solutions Meeting, 
and the three stakeholder meetings must meet the requirements in 
Order No. 1920.
    As part of the regional transmission planning process, the 
Transmission Providers in each transmission planning region shall 
conduct Long-Term Regional Transmission Planning, meaning regional 
transmission planning on a sufficiently long-term, forward-looking, 
and comprehensive basis to identify Long-Term Transmission Needs, 
identify transmission facilities that meet such needs, measure the 
benefits of those transmission facilities, and evaluate those 
transmission facilities for potential selection in the regional 
transmission plan for purposes of cost allocation as the more 
efficient or cost-effective regional transmission facilities to meet 
Long-Term Transmission Needs. As part of this Long-Term Regional 
Transmission Planning, the Transmission Providers in each 
transmission planning region shall meet the requirements set forth 
in Order No. 1920, including: (1) identifying Long-Term Transmission 
Needs and Long-Term Regional Transmission Facilities to meet those 
needs through the development of Long-Term Scenarios that satisfy 
the requirements set forth in Order No. 1920; (2) measuring the 
required seven benefits consistent with the requirements set forth 
in Order No. 1920; (3) using the measured benefits to evaluate Long-
Term Regional Transmission Facilities; and (4) using selection 
criteria consistent with the requirements set forth in Order No. 
1920 that provide the opportunity for Transmission Providers to 
select Long-Term Regional Transmission Facilities in the regional 
transmission plan for purposes of cost allocation that more 
efficiently or cost-effectively address Long-Term Transmission 
Needs.
    The process through which the Transmission Providers in each 
transmission planning region develop Long-Term Scenarios must comply 
with the following six transmission planning principles established 
in Order No. 890: coordination; openness; transparency; information 
exchange; comparability; and dispute resolution. The Transmission 
Providers in each transmission planning region shall outline in 
their Tariffs an open and transparent process that provides 
stakeholders, including states, with a meaningful opportunity to 
propose potential factors and to provide input on how to account for 
specific factors in the development of Long-Term Scenarios. The 
Transmission Providers in each transmission planning region shall 
also outline in their Tariffs an open and transparent process that 
provides stakeholders, including states, with a meaningful 
opportunity to propose which future outcomes are probable and can be 
captured through assumptions made in the development of Long-Term 
Scenarios. Transmission Providers shall consult with and consider 
the positions of the Relevant State Entities, and any other entity 
authorized by a Relevant State Entity as its representative, as to 
whether a specific state policy must be accounted for as a factor 
within each category, how to account for the specific state policy 
in the development of Long-Term Scenarios, and how to adjust the 
treatment of the specific state policy across Long-Term Scenarios. 
When requested by Relevant State Entities in a transmission planning 
region, Transmission Providers shall conduct a reasonable number of 
additional analyses or scenarios to inform the application of Long-
Term Regional Cost Allocation Method(s) or the development of cost 
allocation methods through the State Agreement Process(es). 
Transmission Providers shall not use any such additional analyses to 
identify Long-Term Transmission Needs, identify Long-Term Regional 
Transmission Facilities, or to meet the requirement that 
Transmission Providers estimate the costs and measure the benefits 
of Long-Term Regional Transmission Facilities for purposes of 
selection. Transmission Providers also shall not condition the 
selection of a Long-Term Regional Transmission Facility on the 
information provided in these additional analyses.
    The Transmission Providers in each transmission planning region 
shall include in their Tariffs a general description of how they 
will measure each of the seven required benefits used to evaluate 
Long-Term Regional Transmission Facilities. The Transmission 
Providers in each transmission planning region shall measure and use 
the seven benefits, as described in Order No. 1920, in Long-Term 
Regional Transmission Planning.
    As part of Long-Term Regional Transmission Planning, the 
Transmission Providers in each transmission planning region shall 
include in their Tariffs an evaluation process, including selection 
criteria, that: (1) is transparent and not unduly discriminatory; 
(2) aims to ensure that more efficient or cost-effective 
transmission facilities are selected in the regional transmission 
plan for purposes of cost allocation; (3) seeks to maximize benefits 
accounting for costs over time without over-building transmission 
facilities; and (4) otherwise satisfies the requirements set forth 
in Order No. 1920. Once Transmission Providers make a selection 
decision, and, if a State Agreement Process is used, once a cost 
allocation method is agreed upon, Transmission Providers shall make 
available, on a password-protected portion of OASIS or other 
password-protected website, a breakdown of how the estimated costs 
of a Long-Term Regional Transmission Facility will be allocated, by 
zone, and a quantification of the Long-Term Regional Transmission 
Facility's estimated benefits as imputed to each zone, as such 
benefits can be reasonably estimated.
    The Transmission Providers in each transmission planning region 
shall include in their Tariffs one or more Long-Term Regional 
Transmission Cost Allocation Methods, which is an ex ante regional 
cost allocation method for one or more Long-Term Regional 
Transmission Facilities (or portfolio of such Facilities) that are 
selected in the regional transmission plan for purposes of cost 
allocation and that complies with the requirements set forth in 
Order No. 1920. The Transmission Providers in each transmission 
planning region may also, subject to (1) the agreement of Relevant 
State Entities and (2) Commission acceptance, include in their 
Tariffs a State Agreement Process. A State Agreement Process is a 
process by which one or more Relevant State Entities may voluntarily 
agree to a cost allocation method for Long-Term Regional 
Transmission Facilities (or a portfolio of such Facilities) either 
before or no later than six months after the facilities are selected 
in the regional transmission plan for purposes of cost allocation. 
The Tariff must describe how the State Agreement Process will result 
in a cost allocation being filed, including which entities can 
participate in the State Agreement Process; what constitutes an 
agreement on cost allocation in that process; how agreement is 
communicated to the T[t]ransmission P[p]rovider; and the 
circumstances under which, or the information necessary for, a 
T[t]ransmission P[p]rovider to file or to consider filing the agreed 
cost allocation.
    Transmission Providers shall include in their Tariffs a 
description of how they will

[[Page 97351]]

consult with Relevant State Entities (1) prior to amending the Long-
Term Regional Transmission Cost Allocation Method(s) and/or State 
Agreement Process(es), or (2) if Relevant State Entities seek, 
consistent with their chosen method to reach agreement, for the 
Transmission Provider to amend that method or process. For a 
consultation initiated by the Transmission Providers, Transmission 
Providers shall document publicly on their OASIS or other public 
website the results of their consultation with Relevant State 
Entities prior to filing their amendment. For a consultation 
initiated by Relevant State Entities, if the Transmission Providers 
choose not to propose any amendments to the Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement 
Process(es) preferred by Relevant State Entities during the required 
consultation, Transmission Providers shall document publicly on 
their OASIS or other public website the results of their 
consultation with Relevant State Entities, including an explanation 
for why they have chosen not to propose any amendments.
    As part of evaluating new regional transmission facilities, as 
well as upgrades to existing transmission facilities, the 
Transmission Providers in each transmission planning region shall 
consider in all of their regional transmission planning and cost 
allocation processes whether selecting transmission facilities that 
incorporate the following technologies would be more efficient or 
cost-effective than selecting new regional transmission facilities 
or upgrades to existing transmission facilities that do not 
incorporate these technologies: dynamic line ratings, as defined in 
18 CFR 35.28(b)(14), advanced power flow control devices, advanced 
conductors, and/or transmission switching. Specifically, such 
consideration must include both: (1) whether incorporating dynamic 
line ratings, advanced power flow control devices, advanced 
conductors, and/or transmission switching into existing transmission 
facilities could meet the same regional transmission need more 
efficiently or cost-effectively than other potential transmission 
facilities; and (2) when evaluating transmission facilities for 
potential selection in the regional transmission plan for purposes 
of cost allocation, whether incorporating dynamic line ratings, 
advanced power flow control devices, advanced conductors, and/or 
transmission switching as part of any potential regional 
transmission facility would be more efficient or cost-effective. 
Transmission P[p]roviders must evaluate the benefits of 
incorporating the enumerated alternative transmission technologies 
into Long-Term Regional Transmission Facilities in a manner 
consistent with the requirements in the Evaluation of Benefits of 
Regional Transmission Facilities and Evaluation and Selection of 
Long-Term Regional Transmission Facilities sections of Order No. 
1920.
    The Transmission Providers in each transmission planning region 
shall evaluate for potential selection in the regional transmission 
plan for purposes of cost allocation regional transmission 
facilities that address interconnection-related transmission needs 
originally identified through the generator interconnection process. 
This requirement applies in the existing Order No. 1000 regional 
transmission planning processes. The Transmission Providers must 
modify their Tariffs to include these requirements. The 
interconnection-related transmission needs that Transmission 
Providers must evaluate in the existing Order No. 1000 regional 
transmission planning process are those for which:
    (1) Transmission Providers in the transmission planning region 
have identified the relevant interconnection-related transmission 
need in interconnection studies in at least two interconnection 
queue cycles (or in at least two individual interconnection studies 
for Transmission Providers that use a first-come, first-served 
serial generator interconnection process) [during the preceding five 
years (looking back from the effective date of the accepted tariff 
provisions proposed to comply with this reform in Order No. 1920, 
and the later-in-time withdrawn interconnection request occurring 
after the effective date of the accepted tariff provisions)];
    (2) the interconnection-related Network Upgrade identified 
through the generator interconnection process to meet the relevant 
interconnection-related transmission need has a voltage of at least 
200 kV and an estimated cost of at least $30 million;
    (3) [the interconnection-related Network Upgrade identified 
through the generator interconnection process to meet the relevant 
interconnection-related transmission need is not currently planned 
to be developed because] the interconnection request[(]s[)] that led 
to the identification of the interconnection-related transmission 
need in two or more interconnection queue cycles (or two individual 
interconnection studies if the Transmission Provider uses a first-
come, first-served serial generator interconnection process) have [ 
has ]been withdrawn and no more than five calendar years have passed 
between the date of an earlier interconnection request withdrawal 
and the date of a later interconnection request withdrawal;[ and]
    (4) the Transmission Providers have not identified a different 
interconnection-related Network Upgrade to meet the relevant 
interconnection-related transmission need in an executed Generator 
Interconnection Agreement or in a Generator Interconnection 
Agreement that the interconnection customer requested that the 
Transmission Provider file unexecuted with the Commission[.]; and
    (5) The interconnection request withdrawals associated with the 
repeatedly identified interconnection-related transmission need 
occurred no earlier than seven calendar years prior to the 
commencement date of the Order No. 1000 regional transmission 
planning and cost allocation cycle. The initial evaluation should 
occur in the first Order No. 1000 regional transmission planning and 
cost allocation cycle to occur after the effective date of the 
tariff revisions implementing this reform. The Transmission Provider 
need not evaluate an interconnection-related transmission need that 
has been evaluated in a previous Order No. 1000 regional 
transmission planning and cost allocation cycle.
    The description of the regional transmission planning process 
must include sufficient detail to enable Transmission Customers to 
understand:
    (i) The process for enrollment in the regional transmission 
planning process;
    (ii) The process for consulting with customers;
    (iii) The notice procedures and anticipated frequency of 
meetings;
    (iv) The methodology, criteria, and processes used to develop a 
transmission plan;
    (v) The method of disclosure of criteria, assumptions, and data 
underlying a transmission plan;
    (vi) The obligations of and methods for transmission customers 
to submit data;
    (vii) The process for submission of data by nonincumbent 
developers of transmission projects that wish to participate in the 
regional transmission planning process and seek regional cost 
allocation;
    (viii) The process for submission of data by merchant 
transmission developers that wish to participate in the regional 
transmission planning process;
    (ix) The dispute resolution process;
    (x) The study procedures for economic upgrades to address 
congestion or the integration of new resources; and
    (xi) The relevant cost allocation method or methods.
    The regional transmission planning process must include cost 
allocation methods that satisfy the requirements set forth in Order 
Nos. 1000 and 1920.
    Identifying Potential Opportunities to Right-Size Replacement 
Transmission Facilities
    As part of each Long-Term Regional Transmission Planning cycle, 
Transmission Providers in each transmission planning region shall 
evaluate whether transmission facilities operating at or above a 
voltage threshold not to exceed 200 kV that an individual 
Transmission Provider that owns the transmission facility 
anticipates replacing in-kind with a new transmission facility 
during the next 10 years can be ``right-sized'' to more efficiently 
or cost-effectively address Long-Term Transmission Needs, as 
discussed in Order No. 1920. The process to identify potential 
opportunities to right-size replacement transmission facilities must 
follow the process outlined in Order No. 1920. The Transmission 
Providers in each transmission planning region shall include in 
their Tariffs a cost allocation method for right-sized replacement 
transmission facilities that are selected in the regional 
transmission plan for purposes of cost allocation.

Interregional Transmission Coordination

    The Transmission Provider, through its regional transmission 
planning process, must coordinate with the public utility 
transmission providers in each neighboring transmission planning 
region within its interconnection to address transmission planning 
coordination issues related to interregional transmission 
facilities. The interregional transmission coordination procedures 
must include a detailed

[[Page 97352]]

description of the process for coordination between public utility 
transmission providers in neighboring transmission planning regions 
(i) with respect to each interregional transmission facility that is 
proposed to be located in both transmission planning regions and 
(ii) to identify possible interregional transmission facilities that 
could address transmission needs more efficiently or cost-
effectively than separate regional transmission facilities. The 
interregional transmission coordination procedures shall be 
described in an attachment to the Transmission Provider's Tariff.
    The Transmission Provider must ensure that the following 
requirements are included in any applicable interregional 
transmission coordination procedures:
    (1) A commitment to coordinate and share the results of each 
transmission planning region's regional transmission plans 
(including information regarding the Long-Term Transmission Needs 
and potential transmission facilities to meet those needs) to 
identify possible interregional transmission facilities that could 
address transmission needs more efficiently or cost-effectively than 
separate regional transmission facilities, as well as a procedure 
for doing so;
    (2) A formal procedure to identify and jointly evaluate 
transmission facilities that are proposed to be located in both 
transmission planning regions, including those that may be more 
efficient or cost-effective transmission solutions to Long-Term 
Transmission Needs;
    (3) An agreement to exchange, at least annually, planning data 
and information; and
    (4) A commitment to maintain a website or email list for the 
communication of information related to the coordinated planning 
process, including:
    (a) the Long-Term Transmission Needs discussed in the 
interregional transmission coordination meetings;
    (b) any interregional transmission facilities proposed or 
identified in response to the Long-Term Transmission Needs;
    (c) the voltage level, estimated cost, and estimated in-service 
date of the interregional transmission facilities proposed or 
identified as part of Long-Term Regional Transmission Planning;
    (d) the results of any cost-benefit evaluation of such 
interregional transmission facilities, with results including both 
any overall benefits identified, as well as any benefits particular 
to each transmission planning region; and
    (e) the interregional transmission facilities, if any, selected 
in the regional transmission plan for purposes of cost allocation to 
meet Long-Term Transmission Needs.
    The Transmission Provider must work with transmission providers 
located in neighboring transmission planning regions to develop a 
mutually agreeable method or methods for allocating between the two 
transmission planning regions the costs of a new interregional 
transmission facility that is located within both transmission 
planning regions. Such cost allocation method or methods must 
satisfy the six interregional cost allocation principles set forth 
in Order No. 1000 and must be included in the Transmission 
Provider's Tariff.

United States of America

Federal Energy Regulatory Commission

Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation

Docket No. RM21-17-001
(Issued November 21, 2024)
CHRISTIE, Commissioner, concurring in part:

    1. Today's order makes major changes to Order No. 1920. I am deeply 
grateful to my colleagues for their willingness to negotiate in good 
faith and ultimately to agree to these changes.
    2. Order No. 1920 was based on purported authority derived from 
section 206 of the Federal Power Act (FPA).\1\ Section 206 essentially 
requires that two prongs must be satisfied: First, the complainant, 
here the Commission, bears the burden to prove that existing rates--in 
this case, the transmission planning procedures of every transmission 
provider in the country, both Regional Transmission Organization (RTO)/
Independent System Operator (ISO) and non-RTO/ISO--are unjust, 
unreasonable and/or unduly discriminatory or preferential. If the first 
prong (burden of proof) is met, in the second prong, the Commission 
must establish a just and reasonable replacement rate.\2\ I concur with 
this order solely as to specific changes made in Order No. 1920-A to 
the replacement rate established in Order No. 1920.\3\
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824e.
    \2\ Id. (``Whenever the Commission, after a hearing held upon 
its own motion or upon complaint, shall find that any rate, charge, 
or classification, demanded, observed, charged, or collected by any 
public utility for any transmission or sale subject to the 
jurisdiction of the Commission, or that any rule, regulation, 
practice, or contract affecting such rate, charge, or classification 
is unjust, unreasonable, unduly discriminatory or preferential, the 
Commission shall determine the just and reasonable rate, charge, 
classification, rule, regulation, practice, or contract to be 
thereafter observed and in force, and shall fix the same by order. . 
. .'' (emphasis added)).
    \3\ The specific changes which I support and to which I concur 
are described in the Appendix to this statement.
---------------------------------------------------------------------------

    3. In my dissent to Order No. 1920, I made it clear that one of my 
major areas of disagreement was that it failed to fulfill the promise 
of a necessary and appropriate role for the states that was established 
in the Notice of Proposed Rulemaking (NOPR) that preceded Order No. 
1920.\4\ This promised state role was the primary reason I voted for 
the NOPR. As I have said repeatedly, state utility regulators are the 
first line of defense for their consumers and must have the authority 
to protect their consumers from unwarranted or excessive transmission 
costs, which are the fastest rising part of most consumers' monthly 
power bills and are reaching ever more burdensome levels.\5\ The 
changes made today in Order No. 1920-A to the replacement rate set by 
Order No. 1920 go a long way towards restoring the state role to what 
the NOPR promised, and I am pleased to support these changes. Among 
them are the following positive and fundamental changes:
---------------------------------------------------------------------------

    \4\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation & Generator Interconnection, NOPR, 179 
FERC ] 61,028 (2022) (Christie, Comm'r, concurring at PP 5, 11, 14).
    \5\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation, Order No. 1920, 187 FERC ] 61,068 (2024) 
(Christie, Comm'r, dissenting at P 15 & nn.49-54).
---------------------------------------------------------------------------

    4. Submission of State-Agreed Alternative. In contrast to Order No. 
1920, Order No. 1920-A requires that, if the states in a region agree 
to a cost allocation proposal, the transmission provider must include 
that agreement in its compliance filing. Furthermore, the Commission 
can choose the state agreement over the transmission provider's 
proposal.\6\
---------------------------------------------------------------------------

    \6\ See Appendix at P 1.
---------------------------------------------------------------------------

    5. Pre-Amendment State Consultation. In addition, states must be 
consulted before the transmission provider considers any future changes 
to the cost allocation method or state agreement processes or if the 
states seek to amend the cost allocation method or state agreement 
processes.\7\
---------------------------------------------------------------------------

    \7\ Id. P 2.
---------------------------------------------------------------------------

    6. Cost Allocation Flexibility. In contrast to Order No. 1920, 
states are given far more flexibility to develop and agree to cost 
allocation processes and ex ante formulae that will suit their needs in 
diverse multistate regions such as PJM Interconnection, L.L.C. (PJM), 
Midcontinent Independent System Operator, Inc., and the Southeastern 
Regional Transmission Planning region. For example, states in PJM will 
now have explicit assurance that the PJM State Agreement Approach, in 
use for more than a decade, is preserved as an option for allocating to 
the sponsoring states the costs of public policy-driven projects, such 
as New Jersey's offshore wind and others that would not be selected for 
regional cost allocation.\8\
---------------------------------------------------------------------------

    \8\ Id. at P 7.
---------------------------------------------------------------------------

    7. State Input on Factors. As part of the planning process, 
transmission providers must consult with the states before running the 
scenarios required by Order No. 1920 and must consider the views of the 
states as to how to account for and weigh the factors related to, or 
derived from, state public policies.\9\
---------------------------------------------------------------------------

    \9\ Id. P 4.

---------------------------------------------------------------------------

[[Page 97353]]

    8. State Input on Baseline Scenarios. Order No. 1920-A also 
clarifies that, for purposes of cost allocation, states in PJM and 
other diverse multistate regions can now choose a new ex ante process 
that will enable the states to request that the transmission provider 
run additional scenarios, including a baseline scenario that contains 
only optimal reliability or economic projects and excludes public 
policy-driven projects, so that states can compare the costs of the 
baseline scenario versus the larger, multi-driver scenarios that 
include public policy-driven projects. Most importantly, states can 
agree that the difference in costs between the baseline scenario and 
the larger, multi-driver scenarios that include projects derived from 
state policies or other policy goals will be allocated to the states 
whose policies are the source of the added costs and will not be 
regionally cost allocated.\10\
---------------------------------------------------------------------------

    \10\ Id. PP 3, 8-11.
---------------------------------------------------------------------------

    9. Removal of Corporate Power Preferences and Cost-Shifting. The 
requirement in Order No. 1920 that large corporate power-purchasing 
preferences must be a factor in planning long-term scenarios is 
explicitly removed.\11\ That was one of the most unconscionable, 
special-interest driven features of Order No. 1920, directing 
transmission providers to plan hundreds of billions of dollars of 
transmission projects to subsidize the power-purchasing preferences of 
huge multinational corporations and shifting the costs to residential 
and small-business consumers already struggling to pay their monthly 
power bills.
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    \11\ Id. P 6.
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    10. New Required Transparency. Order No. 1920-A also emphasizes 
transparency and clarifies that the purported benefits of one or more 
states' public policies are clearly identified and quantified. This 
will enable states to determine whether they are being charged for 
other states' public policies, which benefits they are paying for, and 
how much.\12\
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    \12\ Id. P 10.
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    11. Collectively, these changes give the states a much bigger 
toolbox containing far more effective tools they can use to protect 
their consumers and the interests of their states. I urge state 
regulators to use them aggressively. Further, let me emphasize that, if 
the process of compliance--always complicated and challenging even with 
rulemakings of far smaller size and less complexity than this one--
demonstrates that state flexibility and authority remain materially 
insufficient, further action by the Commission may become necessary.
    12. And on the issue of compliance, I would add that the broad 
purpose of these changes is to allow the states sufficient flexibility 
and authority to protect their consumers from paying unfair or 
unnecessary costs. That purpose should and must inform the compliance 
process.
    13. For these reasons, I respectfully concur to these changes 
established in Order No. 1920-A that are listed specifically in the 
Appendix. Again, I express my deep appreciation to my colleagues for 
their willingness to engage in good-faith negotiations leading to these 
important changes to the replacement rate.

    For these reasons I respectfully concur in part.

Mark C. Christie,
Commissioner.

Appendix--Major Changes Incorporated in Order No. 1920-A

    1. Require transmission providers to include in their filings 
state agreements on cost allocation, with enough detail so that any 
separate proposals can be considered and enable the Commission to 
adopt the states' agreement on compliance.
    The order directs transmission providers to include in the 
transmittal of their compliance filings any Long-Term Regional 
Transmission Cost Allocation Method(s), and/or State Agreement 
Process(es) agreed to by Relevant State Entities, during the 
Engagement Period. The order also clarifies that transmission 
providers must include such cost allocation methods and/or State 
Agreement Processes in the transmittal of their compliance filings 
even when transmission providers propose on compliance a separate 
cost allocation method and/or declined to propose a State Agreement 
Process.
    As part of this requirement, the order clarifies that 
transmission providers must include any and all supporting evidence 
and/or justification related to Relevant State Entities' agreed-upon 
cost allocation method and/or State Agreement Process that Relevant 
State Entities request that transmission providers include in their 
compliance filing. However, the order clarifies that transmission 
providers are not required to separately characterize Relevant State 
Entities' agreement or independently justify Relevant State 
Entities' preferred cost allocation.
    When acting under FPA section 206, the Commission's statutory 
burden is to establish a just and reasonable and not unduly 
discriminatory replacement rate that is supported by substantial 
evidence and is the product of reasoned decision making. In 
satisfying this burden with respect to cost allocation, it is not 
the case that the Commission necessarily must adopt the transmission 
provider's proposal if that proposal complies with the final rule's 
requirements; rather, the Commission need only weigh competing views 
(if they exist), select an approach with adequate support in the 
record, and then intelligibly explain the reasons for its choice.
    To be clear, this means that the Commission will consider the 
entire record--including the Relevant State Entities' agreed-upon 
cost allocation and the transmission provider's proposal. 
Specifically, when the Commission reviews transmission providers' 
compliance filings, the Commission is not required to accept a cost 
allocation proposal from a transmission provider simply because it 
may comply with Order No. 1920. Instead, the Commission may accept 
any cost allocation method proposed by the Relevant State Entities 
and submitted on compliance so long as it complies with Order No. 
1920.
    2. Require transmission providers to revise their OATTs to add a 
requirement that they consult with Relevant State Entities before 
making a future filing under FPA section 205 to revise the Long-Term 
Regional Transmission Cost Allocation Method and/or State Agreement 
Process(es) that is on file.
    The order requires that, as part of transmission providers' 
obligations with respect to transmission planning and cost 
allocation, transmission providers shall consult with Relevant State 
Entities prior to amending the ex ante Long-Term Regional 
Transmission Cost Allocation Method and/or State Agreement 
Process(es) agreed to by Relevant State Entities, or if Relevant 
State Entities seek to amend that method or process. The order 
requires transmission providers to document publicly on their 
website the results of that consultation prior to submitting their 
amendment. In addition, transmission providers must describe their 
reasoning for not using the results of the consultation with the 
Relevant State Entities. As an example, a jumpball framework, such 
as exists in MISO, SPP, and ISO-NE, could satisfy these 
requirements.
    3. If Relevant State Entities request additional scenarios to 
inform their consideration of cost allocation methods, transmission 
providers shall develop those additional scenarios.
    The order clarifies that transmission providers may develop 
additional scenarios, beyond the three Long-Term Scenarios that 
Order No. 1920 requires, to provide Relevant State Entities with 
information that they can use to inform the development of Long-Term 
Regional Transmission Cost Allocation Method(s) and/or State 
Agreement Process(es). The order further clarifies that, when 
developing these additional scenarios used to inform cost 
allocation, transmission providers have the flexibility to depart 
from Order No. 1920's requirements related to the development of 
Long-Term Scenarios. For example, transmission providers may develop 
scenarios that consider the incremental cost of transmission needed 
to achieve state laws, policies, and regulations beyond the cost of 
transmission needed in the absence of those laws, policies, and 
regulations. The order further clarifies that, if the Relevant State 
Entities wish for the transmission provider to develop a reasonable 
number of additional scenarios for cost allocation, then the 
transmission providers will develop these scenarios.
    4. Clarify that, while transmission providers have discretion 
over how to

[[Page 97354]]

consider the effects of factors, transmission providers must consult 
with Relevant State Entities regarding factors related to state 
public policies.
    The order clarifies that transmission providers must consult 
with and consider the positions of the Relevant State Entities as to 
how to account for factors related to state public policies in 
transmission planning assumptions. Specifically, the transmission 
provider shall consult with Relevant State Entities as to how to run 
the Long-Term Scenarios mandated by the final rule, as they may 
incorporate planning for state laws, policies, and regulations, 
including assumptions of transmission needs that may be attributable 
to, or derived from, state or local policies, such as assumptions 
about changing generation resources.
    5. Allow states six additional months for the engagement period, 
upon request.
    The order clarifies that, if Relevant State Entities, consistent 
with their chosen method to reach agreement, request additional time 
to complete cost allocation discussions, the Commission will extend 
the Engagement Period for up to an additional six months. The order 
finds that such an extension is warranted in that circumstance to 
ensure that Relevant State Entities have sufficient time to engage 
in fulsome discussions. The order also clarifies that the Commission 
will extend the relevant compliance deadlines, as appropriate, to 
accommodate an extension to the Engagement Period.
    6. Exclude corporate commitments from Factor Category Seven.
    The order eliminates the requirement for transmission providers 
to incorporate corporate commitments in Factor Category Seven when 
developing Long-Term Scenarios. The order finds that requiring 
transmission providers to consider corporate commitments when 
developing Long-Term Scenarios may introduce the risk of one class 
of transmission users cross-subsidizing another class of 
transmission users.
    7. Expressly permit continued use of both new and/or existing 
state agreement approaches and similar voluntary measures.
    The order clarifies that Order No. 1920 does not require 
reapproval of PJM's State Agreement Approach. The order clarifies 
that the Commission interprets PJM's State Agreement Approach to be 
supplemental to PJM's existing regional transmission cost allocation 
method. As a result, it is not in any way affected by the final 
rule. The order further clarifies (see #1 above) that, in their 
compliance filings, transmission providers shall include any State 
Agreement Process(es) agreed to by Relevant State Entities.
    8. Transmission providers will allocate the costs of a Long-Term 
Regional Transmission Facility commensurate to its benefits.
    The order clarifies that Order No. 1920 does not prevent 
transmission providers from recognizing different types of benefits 
and using them to allocate costs in proportion to those benefits. 
One potential cost allocation method that could be proposed to 
comply with Order No. 1920 would allocate costs commensurate with 
reliability and economic benefits region-wide, while allocating 
costs commensurate with additional benefits to a subset of states 
that agree to such cost allocation. Under this potential cost 
allocation method, these costs and benefits could be identified 
based on one or more additional scenarios run by the transmission 
planner for the purposes of informing cost allocation, e.g., 
scenarios that consider the incremental cost of transmission needed 
to achieve state laws, policies, and regulations beyond the cost of 
transmission needed in the absence of those laws, policies, and 
regulations. For example, the cost allocation method agreed to by 
the Relevant State Entities may allocate those incremental costs to 
states with those applicable laws, policies, and regulations.
    9. Clarify that states and/or transmission providers may define 
additional benefits to those enumerated in Order No. 1920.
    Further, the order clarifies that costs borne by ratepayers must 
be roughly commensurate with benefits received. Transmission 
providers can consider additional benefits for cost allocation 
purposes, including as agreed to by Relevant State Entities and 
described elsewhere in this rule, provided that costs are allocated 
in a way that is at least roughly commensurate with estimated 
benefits.
    10. Clarify that, for a selected project or tranche of projects, 
transmission providers shall, for each pricing zone, quantify the 
benefits and costs associated with such project or tranche.
    The order clarifies that, for each selected project or tranche 
of projects, each transmission provider is required to make publicly 
available, on OASIS or other password-protected website, a breakdown 
of the allocated costs, by transmission pricing zone, and a 
quantification of the benefits imputed to each zone, as such 
benefits can be reasonably estimated.
    11. Include, as an example of an approach that could be proposed 
to comply with Order No. 1920, the below ex ante cost allocation 
method language for Relevant State Entities. The inclusion of this 
example does not foreclose states from agreeing to other cost 
allocation approaches, each of which shall be evaluated on its own 
merits.
    At the request of the Relevant State Entities in a multistate 
region, the following ex ante method for cost allocation may be 
proposed. In providing this example, the order is not foreclosing 
other approaches for allocating the costs of Long-Term Regional 
Transmission Facilities on either an ex ante or project-specific 
basis. Nor is the order suggesting that cost allocation 
methodologies must adopt a similar approach to this framework in 
order to comply with the requirements of this final rule:
    (1) For purposes of cost allocation, the transmission providers 
shall run a scenario that otherwise complies with the Long-Term 
Regional Transmission Planning requirements of Order No. 1920 but 
does not include state laws, policies, and regulations and quantify 
the costs of the projects that would be selected from this scenario.
    (2) The costs identified in (1) could be cost allocated 
according to an alternative ex ante formula filed by the 
transmission owners for the region.
    (3) The amount representing the cost difference between the 
costs of projects selected pursuant to the Long-Term Regional 
Transmission Planning process and (1) shall be allocated as follows:
    a. The transmission provider shall identify by state the 
specific state laws, policies, and regulations that were used to 
plan and select the facilities and shall quantify by state the 
specific costs of such facilities.
    b. The costs identified in 3(a) shall be allocated solely to the 
state or states that are the sources of the policies used in 
planning and selection. The total difference between the costs of 
projects selected pursuant to the Long-Term Regional Transmission 
Planning process and (1) would be fully accounted for using this 
method of allocating costs among the states. The costs by zone 
within a state (Intrastate Costs) would be developed and filed by 
the applicable Transmission Owner(s).

[FR Doc. 2024-27982 Filed 12-5-24; 8:45 am]
BILLING CODE 6717-01-P
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