97174 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

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. 

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 LongTerm Regional Transmission Planning 

to ensure the identification, evaluation, 

and selection, as well as the allocation 

of the costs, of more efficient or costeffective 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, 

michael.kellermann@ferc.gov. 

Patrick T. Metz (Legal Information), 

Office of the General Counsel, 888 First 

Street NE, Washington, DC 20426, (202) 

502–8197, patrick.metz@ferc.gov. 

David Tobenkin (Technical 

Information), Office of Energy Policy 

and Innovation, 888 First Street NE, 

Washington, DC 20426, (202) 502–6445, 

david.tobenkin@ferc.gov. 

Noah Lichtenstein (Technical 

Information), Office of Energy Market 

Regulation, 888 First Street NE, 

Washington, DC 20426, (202) 502–8696, 

noah.lichtenstein@ferc.gov. 

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 or Preferential Commission-Jurisdictional Transmission Planning 

and Cost Allocation Processes ............................................................................................................................................... 46 

3. Benefits of Long-Term Regional Transmission Planning and Cost Allocation To Identify and Plan for Long-Term 

Transmission Needs ............................................................................................................................................................... 59 

B. The Commission Adequately Demonstrated That Existing Rates, or Practices Affecting Rates, Are Unjust and Unreasonable ................................................................................................................................................................................................. 61 

1. The Commission Correctly Characterized Its Statutory Burden ......................................................................................... 62 

2. The Commission Adequately Supported Its Determination on Step One of Section 206 ................................................ 70 

3. The Commission Identified Deficiencies That Exist Beyond Isolated Pockets .................................................................. 87 

4. The Commission Has the Authority To Conduct a Generic Rulemaking .......................................................................... 98 

C. The Commission Demonstrated That the Replacement Rate is Just and Reasonable .............................................................. 104 

1. Requests for Rehearing .......................................................................................................................................................... 104 

2. Commission Determination ................................................................................................................................................... 107 

D. The Commission’s Section 206 Findings Were Not Circular .................................................................................................... 115 

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 Transmission Planning .......................................................................... 200 

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 Seven Required Benefits To Help To Inform Their Identification of Long-Term Transmission Needs ................................................................................................................................ 218 

2. Transmission Planning Horizon ............................................................................................................................................ 227 

3. Frequency of Long-Term Scenario Revisions ....................................................................................................................... 248 

4. Categories of Factors .............................................................................................................................................................. 263 

5. Requests for Additional Flexibility Regarding Long-Term Scenarios Requirements ........................................................ 351 

C. Evaluation of the Benefits of Regional Transmission Facilities ................................................................................................ 369 

1. Requirement for Transmission Providers To Use and Measure a Set of Seven Required Benefits .................................. 369 

2. Measurement and Use of Other Benefits .............................................................................................................................. 411 


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Paragraph 

Nos. 

3. Identification, Measurement, and Evaluation of Benefits ................................................................................................... 417 

4. Benefits Horizon .................................................................................................................................................................... 421 

5. Evaluation of the Benefits of Portfolios of Transmission Facilities ................................................................................... 428 

D. Evaluation and Selection of Long-Term Regional Transmission Facilities .............................................................................. 434 

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 Planning .............................................................................................. 502 

1. Order No. 1920 Requirements ............................................................................................................................................... 502 

2. Requests for Rehearing and Clarification ............................................................................................................................. 505 

3. Commission Determination ................................................................................................................................................... 507 

VI. Coordination of Regional Transmission Planning and Generator Interconnection Processes ....................................................... 511 

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 Power Flow Control Devices ................................................................ 594 

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 Clarification .......................................................................................... 601 

VIII. Regional Transmission Cost Allocation .......................................................................................................................................... 610 

A. Obligation To File an Ex Ante Long-Term Regional Transmission Cost Allocation Method and Its Use as a Backstop ..... 610 

1. Logical Outgrowth ................................................................................................................................................................. 610 

2. Substantive Issues .................................................................................................................................................................. 618 

B. Requirements Concerning Relevant State Entities ...................................................................................................................... 635 

1. Requested Requirement To Obtain the Agreement of Relevant State Entities .................................................................. 635 

2. Requirements Concerning Relevant State Entities’ Preferred Cost Allocation Methods ................................................... 642 

C. Design and Operation of the Engagement Period ....................................................................................................................... 663 

1. Logical Outgrowth ................................................................................................................................................................. 663 

2. Requests Arguing the Engagement Period is Inferior to a Requirement That Transmission Providers Seek the Agreement of Relevant State Entities .............................................................................................................................................. 669 

3. Duration of the Engagement Period ...................................................................................................................................... 674 

4. Content of the Engagement Period ........................................................................................................................................ 679 

5. Consultation With Relevant State Entities After the Engagement Period .......................................................................... 687 

D. Design and Operation of State Agreement Processes ................................................................................................................. 693 

1. Definition of Relevant State Entities ..................................................................................................................................... 693 

2. Extensions of Time for Negotiation of Cost Allocation Methods Under State Agreement Processes .............................. 705 

E. Use of Existing Cost Allocation Methods in Long-Term Regional Transmission Planning or Existing Regional Processes 709 

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 Regional Transmission Facilities ........................................................... 718 

1. Logical Outgrowth ................................................................................................................................................................. 718 

2. Omission of Regional Cost Allocation Principle No. 6 and Ability To Allocate Costs by Type of Project ..................... 728 

3. Concerns Regarding Cost Causation ..................................................................................................................................... 753 

G. General Benefits Requirements Related to Cost Allocation ....................................................................................................... 769 

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 


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97176 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

1Bldg. 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. 

3See infra Introduction and Background section 

(defining ‘‘Long-Term Transmission Needs’’). 

4Order No. 1920, 187 FERC ¶ 61,068 at P 1. 

5See infra Introduction and Background section 

(defining ‘‘Long-Term Regional Transmission 

Planning). 

6See 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. 

Paragraph 

Nos. 

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 Commission-Jurisdictional Tariffs and Agreements ............................................. 801 

A. Order No. 1920 Requirements ..................................................................................................................................................... 801 

B. Request for Rehearing ................................................................................................................................................................... 802 

C. Commission Determination .......................................................................................................................................................... 803 

XI. Local Transmission Planning Inputs in the Regional Transmission Planning Process ................................................................. 804 

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 Inputs in the Regional Transmission Planning Process ............. 847 

1. Order No. 1920 ....................................................................................................................................................................... 847 

2. Requests for Additional Reforms .......................................................................................................................................... 851 

3. Stakeholder Meeting Clarifications ....................................................................................................................................... 859 

C. Identifying Potential Opportunities to Right-Size Replacement Transmission Facilities ........................................................ 863 

1. Eligibility ................................................................................................................................................................................ 863 

2. Right of First Refusal for Right-Sized Replacement Transmission Facilities Selected To Meet Long-Term Transmission Needs ......................................................................................................................................................................... 882 

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 LongTerm Transmission Needs; 3 (2) 

adequately account on a forwardlooking 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 LongTerm 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 


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S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 

2014) (per curiam). 

7See infra Introduction and Background section 

(defining ‘‘Long-Term Scenario’’). 

8See infra Introduction and Background section 

(defining ‘‘Long-Term Regional Transmission 

Facility’’). 

processes remain just and reasonable 

and meet the needs of the American 

people. 

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 longterm, forward-looking, and 

comprehensive transmission planning 

and cost allocation processes. At least 

once every five years, transmission 

providers are required to conduct LongTerm 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. 

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 LongTerm 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 LongTerm 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 LongTerm 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 costeffective 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 


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9See 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). 

10See 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). 

11See infra Introduction and Background section 

(defining ‘‘Relevant State Entity’’). 

12See infra Introduction and Background section 

(defining ‘‘State Agreement Process’’). 

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

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 costeffective 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. 

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 LongTerm 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 


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13See infra Introduction and Background section 

(defining ‘‘Engagement Period’’). 

14Section 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 NonDiscriminatory 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 (crossreferenced 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). 

15For 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. 

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. 

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 LongTerm Transmission Needs; 15 (2) 


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16Order No. 1920, 187 FERC ¶ 61,068 at P 1. 

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. 

18For 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 LongTerm Transmission Needs and enable the 

identification and evaluation of transmission 

facilities to meet such transmission needs. Id. P 

302. 

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. 

22 Id. P 911. 

23For 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. 

26For 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. 

31 Id. PP 1106–1107. 

adequately account on a forwardlooking 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

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 LongTerm Scenarios to identify Long-Term 

Transmission Needs and Long-Term 

Regional Transmission Facilities 18 to 

meet those needs.19

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 LongTerm 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 inservice 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

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 LongTerm Regional Transmission Facilities 

for potential selection to address LongTerm 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

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 LongTerm 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 LongTerm 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

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 interconnectionrelated transmission needs associated 

with certain interconnection-related 

network upgrades originally identified 

through the generator interconnection 

process.31


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32 Id. P 1198. 

33 Id. PP 1625, 1677. 

34 Id. P 1751. 

35 Id. 

36Appendix 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.’’). 

37Susann 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. 

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.’’). 

40Allegheny 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. 

41See 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.’’). 

42See 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, federallyrecognized Tribal, state, and local policy goals that 

affect Long-Term Transmission Needs, in the 

development of Long-Term Scenarios.’’). 

43See 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.’’). 

44See 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.’’). 

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

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

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

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. 

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

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. 

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 


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45Order No. 1920, 187 FERC ¶ 61,068 at P 85. 46 Id. 

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). 

55See 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)). 

56Order No. 1920, 187 FERC ¶ 61,068 at P 87. 

57 Id. 

58 Id. P 88. 

59 Id. P 89. 

60 Id. P 90 (citations omitted). 

61 Id. P 91. 

62 Id. P 92 (citations omitted). 

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 longterm, 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 nearterm 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

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 costeffectively 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

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 costeffective 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

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 longterm, 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

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

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 


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63 Id. P 93 (citations omitted). 

64 Id. P 94 (citations omitted). 

65 Id. (citations omitted). 

66 Id. PP 96–99 (citations omitted). 

67 Id. P 100 (citations omitted). 

68 Id. P 101. 

69 Id. (citations omitted). 

70 Id. P 102. 

71 Id. P 103 (citations omitted). 

72 Id. PP 104–105 (citations omitted). 

73 Id. P 106. 

74 Id. P 108. 

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. 

78 Id. P 112. 

transmission investment is likely to 

increase substantially in coming years.63

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, federallyrecognized Tribal, state, and local 

policies, customer demands, utility 

commitments, and the shifting 

economics of resources that comprise 

the resource mix.66

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

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

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

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

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 costeffective transmission development for 

customers, which contributes to rates 

for transmission that are unjust and 

unreasonable.77

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 nearterm transmission needs, transmission 

providers undertaking investments in 

relatively inefficient or less costeffective transmission infrastructure, 

and transmission customers paying 

more than is necessary or appropriate to 

meet their transmission needs and/or 


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79 Id. 

80 Id. P 114. 

81 Id. P 115. 

82 Id. (citations omitted). 

83 Id. P 116 (citations omitted). 

84 Id. (citations omitted). 

85 Id. P 117 (citations omitted). 

86 Id. P 118. 

87 Id. P 119. 

88 Id. P 120. 

89 Id. P 121 (citations omitted). 

90 Id. P 122 & n.312. 

91 Id. P 123. 

92 Id. P 124. 

93 Id. P 126. 

forgoing benefits that outweigh their 

costs.79

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 LongTerm Transmission Needs; (2) 

adequately account on a forwardlooking 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

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 longerterm 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

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

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 LongTerm 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 Commissionjurisdictional regional transmission 

planning and cost allocation processes 

unjust and unreasonable.89

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 Commissionjurisdictional rates that are unjust and 

unreasonable.91

52. The Commission determined that, 

given its findings concerning the 

deficiencies in existing transmission 

planning requirements, and its 

conclusion that long-term, forwardlooking, 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

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 LongTerm 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 


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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. 

97 Id. P 127 (citations omitted). 

98 Id. 

99 Id. (citations omitted). 

100 Id. P 128 (citations omitted). 

101 Id. P 129. 

102 Id. (citation omitted). 

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)). 

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). 

112 Id. P 133 (citation omitted). 

113 Id. (citing Order No. 1000, 136 FERC ¶ 61,051 

at PP 46, 50). 

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

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 LongTerm 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

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

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

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 regionspecific in every case and is instead 

empowered to ‘‘rely on ‘generic’ or 

‘general’ findings of a systemic problem 

to support imposition of an industrywide 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

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

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 Commissionjurisdictional rates by addressing 

deficiencies in the existing regional 

transmission planning and cost 

allocation requirements and promoting 


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114 Id. P 134. 

115 Id. P 135. 

116 Id. P 136 (citation omitted). 

117 Id. (citations omitted). 

118 Id. (citations omitted). 

119 Id. P 137. 

120 Id. P 138 (citations omitted). 

121Alabama 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. 

122SERTP 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. 

126 Industrial Customers Rehearing Request at 16– 

17 (emphasis in original). 

127SERTP Sponsors Rehearing Request at 31. 

128 Industrial Customers Rehearing Request at 16– 

17. 

129See, 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). 

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

60. The Commission found that LongTerm 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, forwardlooking, and more comprehensive 

regional transmission planning can 

better identify reliability needs and 

resolve those needs with more efficient 

or cost-effective transmission 

solutions.120

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, thirdparty 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. 

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

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

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 


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130S.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. 

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.’’). 

137 Id. at 66. 

138See id.at 67. 

139 Industrial Customers Rehearing Request at 16– 

17; SERTP Sponsors Rehearing Request at 34. 

140See 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’’). 

141See Industrial Customers Rehearing Request at 

16–17. 

142S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 64, 

67. 143SERTP Sponsors Rehearing Request at 29. 144S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 65 

(quoting Associated Gas Distributors, 824 F.2d at 

1008). 

145 Designated Retail Regulators Rehearing 

Request at 20–21. 

146Undersigned States Rehearing Request at 21. 

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. 

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

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

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

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

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. 

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 


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147Arizona Commission Rehearing Request at 19. 148 Industrial Customers Rehearing Request at 16. 149 Id. at 13 (alteration omitted). 150 Id. at 17. 151 Id. at 17–18. 152Order No. 1920, 187 FERC ¶ 61,068 at PP 114– 

122. 

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; Ju ̈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-ofthe-NA-Economy.pdf)). 

155The 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 Ju ̈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-ofthe-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.’’)). 

158See 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-energyfuture (‘‘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.’’’ 

consists largely of comments from 

special interest groups that will profit 

from Order No. 1920 and not evidence 

specific to the Arizona Commission.147

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

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 Commissionjurisdictional 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. 

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 


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(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). 

163 Id. P 112. 

164Order 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 costeffective 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%20AddendumLRTP%20Tranche%201%20Report%20with%20

Executive%20Summary625790.pdf)). 

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’’)). 

emission commitments,161 and the 

changing economics of resources that 

comprise the resource mix.162

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

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

76. The second deficiency that the 

Commission identified is that 

transmission providers are not required 

to account adequately on a forwardlooking 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 costeffective 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 LongTerm 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 


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97190 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

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). 

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.’’)). 

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-99FBA31B360DC685); 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)). 

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). 188 Id. P 109 (citing NOPR, 179 FERC ¶ 61,028 at 

PP 39–40 (2022)). 189 Id. (citing PIOs NOPR Initial Comments at 9). 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 longterm 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)). 

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

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

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

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

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

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 


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Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 97191 

192See 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. 

193Associated 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)). 

194Associated Gas Distributors, 824 F.2d at 1008. 

195S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 66 

(emphasis added). 

196See Order No. 1920, 187 FERC ¶ 61,068 at PP 

117, 121, 123. 

197 Id. P 126. 

198 Id. P 113. 

199 Designated Retail Regulators Rehearing 

Request at 20–21; Undersigned States Rehearing 

Request at 21. 

200See 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. 

201See Arizona Commission Rehearing Request at 

19. 

202See, 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. 

203See, e.g., id. P 120 (citing Pattern Energy 

NOPR Initial Comments); id. P 127 (citing NextEra 

ANOPR Initial Comments; LS Power NOPR Initial 

Comments). 

204See, e.g., id. P 116 (citing SEIA ANOPR Initial 

Comments); id. P 137 (citing EEI NOPR Initial 

Comments). 

205See, 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). 

206See, 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). 

207See, 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%20

FINAL%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-transmissionhighest-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/2021-22tsepoverview.pdf; John Wilson and Zach Zimmerman, 

The Era of Flat Demand is Over, Grid Strategies 

(Dec. 2023), https://gridstrategiesllc.com/wpcontent/uploads/2023/12/National-Load-GrowthReport-2023.pdf). 

reflects that existing regional 

transmission planning requirements are 

leading to relatively inefficient or less 

cost-effective results. 

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

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 LongTerm 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. 

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

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. 

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 


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97192 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

208 Industrial Customers Rehearing Request at 17. 

209See supra Unjust, Unreasonable, and Unduly 

Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

210Alabama Commission Rehearing Request at 3; 

SERTP Sponsors Rehearing Request at 28–29, 31. 

211Alabama Commission Rehearing Request at 3. 

212 Id. at 3–4. 

213 Id. at 4. 

214SERTP Sponsors Rehearing Request at 34 

n.100. 

215 Id. at 32. 

216 Id. at 33. 

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)). 

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). 

224Alabama 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. 

225S.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). 

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. 

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

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 costeffective than those identified through 

SERTP’s integrated resource plan and 

request for proposal-driven transmission 

planning.216

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 costeffectively integrate needed generation 

resources.219 SERTP Sponsors contend 

that Order No. 1920 ignored this 

evidence.220

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

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. 

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- 


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226Order 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 longterm 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’’)). 

233SERTP Sponsors Rehearing Request at 36. 

234Order No. 1920, 187 FERC ¶ 61,068 at P 109– 

111. 

235SERTP Sponsors Rehearing Request at 34 & 

n.100. 

236Alabama Commission Rehearing Request at 3. 

237Order 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)). 

240See 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)). 

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

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

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 longterm 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

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 


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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). 

243SPP NOPR Initial Comments at 3. 

244See 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.’’). 

246Order No. 1920, 187 FERC ¶ 61,068 at P 94. 

247 Id. P 95. 

248 Id. P 96. 

249See 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.’’). 

250Order 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)). 

251Undersigned States Rehearing Request at 23. 

252 Id. at 23–24 (citing 16 U.S.C. 824e). 

253 Id. at 24. 

254Arizona Commission Rehearing Request at 19. 

255 Id. at 19–20. 

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.’’ 

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 LongTerm 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

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. 

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

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

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 


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256 16 U.S.C. 824e. 

257Order No. 1920, 187 FERC ¶ 61,068 at P 86 

(citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 

55). 

258S.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). 

260S.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. 

261Associated 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). 

262See, 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. 

263Order No. 1920, 187 FERC ¶ 61,068 at PP 1 

n.2, 253. 

264See 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.’’). 

265See 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)). 

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. 

269 Designated Retail Regulators Rehearing 

Request at 23. 

270 Id. at 23–24. 

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

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. 

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-andcomment 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 § 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 utilityspecific 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

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

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

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 


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271 Industrial Customers Rehearing Request at 19– 

20 (citing State Farm, 463 U.S. at 43). 

272Arizona Commission Rehearing Request at 20. 

273 Id. at 21. 

274Order 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). 

276S.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. 

277Order No. 1920, 187 FERC ¶ 61,068 at P 232. 

278See infra Federal/State Division of Authority 

section. 

279Order 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. 

282See supra Concerns Regarding Cost Causation 

section. 

283 Designated Retail Regulators Rehearing 

Request at 23–24. 284See 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)). 

285Order No. 1920, 187 FERC ¶ 61,068 at P 1305. 286See 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.’’’). 

287Order No. 1920, 187 FERC ¶ 61,068 at P 134. 

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

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

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 longestablished 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

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

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 costeffective 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, 


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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). 

289 Id. P 135. 

290 Id. (MTEP2017 Review at 6). 

291 Id. P 136. 

292See id. 

293 Id. P 112. 

294See Arizona Commission Rehearing Request at 

20–21; Industrial Customers Rehearing Request at 

19–20. 

295Order 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)). 

297E.g., Id. P 135 (citing MTEP2017 Review at 6). 

298 Industrial Customers Rehearing Request at 20 

(emphasis in original). 

299See 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). 

300Arizona Commission Rehearing Request at 21. 

301Order 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.’’). 

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. 

which indicate that long-term, forwardlooking, 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. 

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 costeffective 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

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 LongTerm 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

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 LongTerm Transmission Needs, so that 

customers do not continue to pay for 

relatively inefficient or less costeffective 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. 

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. 

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 


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307 Id. at 14. 308 Id. at 15 (citing Emera Me. v. FERC, 854 F.3d 

9, 22, 25 (D.C. Cir. 2017)). 309SERTP Sponsors Rehearing Request at 30. 310 Id. at 31–32. 

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. 

316 Id. at 35. 

317 Id. 

318 Id. at 35–36 (citation omitted). 

319 Id. at 36 & n.104 (citations omitted). 

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). 

321Emera 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. 

324 16 U.S.C. 824e(a), (b); Pub. Serv. Elec. & Gas 

Co. v. FERC, 989 F.3d at 13. 

325See supra Unjust, Unreasonable, and Unduly 

Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

326Order No. 1920, 187 FERC ¶ 61,068 at P 115; 

see supra Unjust, Unreasonable, and Unduly 

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

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

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

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

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

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. 

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 longterm regional transmission planning, the 

Commission noted that most 

transmission planning regions do not 

plan beyond a 10-year time horizon.326


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Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

327Emera Maine, 854 F.3d at 22. 

328Order No. 1920, 187 FERC ¶ 61,068 at P 118; 

see supra Unjust, Unreasonable, and Unduly 

Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

329Order No. 1920, 187 FERC ¶ 61,068 at P 122; 

see supra Unjust, Unreasonable, and Unduly 

Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

330Order 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. 

332SERTP Sponsors Rehearing Request at 28, 31– 

34. 

333See supra Unjust, Unreasonable, and Unduly 

Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

334Order 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)). 

335SERTP Sponsors Rehearing Request at 32. 

336See 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.’’). 

337SERTP Sponsors Rehearing Request at 35. 

338Order No. 1920, 187 FERC ¶ 61,068 at P 112. 

339Order 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). 

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 LongTerm Regional Transmission Facilities 

that produce a broader set of benefits, 

and therefore warrant a different 

approach to cost allocation for such 

transmission facilities.331

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. 

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 costeffective transmission facilities across 

utility footprints. We continue to find 

that ‘‘the absence of sufficiently longterm, 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

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 LongTerm 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

126. The Commission disagreed with 

arguments that the requirements 

adopted in Order No. 1920 infringe on 


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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.’’). 

346See 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). 

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.’’). 

353See 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). 

355See id. PP 264, 271–272. 

356See 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)). 

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

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 Commissionregulated 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

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

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

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 


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359See id. PP 277–279. 360See id. PP 277–278. 

361 Id. P 279. 

362See id. 

363See id. PP 280–282. 

364 Id. P 280. 

365See 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’’). 

366See 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). 

371See 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)). 

372Undersigned 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). 

373Undersigned States Rehearing Request at 13; 

Designated Retail Regulators Rehearing Request at 

14–15; see also Undersigned States Rehearing 

Request at 33–34. 

374Undersigned 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.’’). 

375Alabama 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. 

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

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 costcausation 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

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

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

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 


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378Arizona 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. 

380Montana 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’’). 

381Utah 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.’’). 

383Order No. 1920, 187 FERC ¶ 61,068 at PP 253– 

54. 

384See, 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. 

385See 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). 

386See, 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. 

387Order 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 . . . .’’). 

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. 

392 Id. P 38; see also id. PP 1–13, 225. 

393See id. PP 40, 248. 

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

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 Commissionpreferred 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

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

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

138. Order No. 1920 required 

transmission providers to conduct LongTerm 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 


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394See id. PP 248, 387–537. 

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. 

396See Order No. 1920, 187 FERC ¶ 61,068 at PP 

90–111, 299–300, 432, 440, 447, 456, 463, 472, 481. 

397See id. P 412. 

398See id. PP 415, 417. 

399See id. PP 1–3, 40, 225, 719–720. 

400See id. P 3; see also id. PP 729, 737. 

401 Id. P 269; see also id. P 720 (identifying the 

benefits to be considered). 

402See, e.g., id. PP 728, 735, 839. 

403 Id. P 5; see also id. P 43 (defining Long-Term 

Regional Transmission Cost Allocation Method); id. 

P 1291. 

404See 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. 

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. 

411See, 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.’’). 

412This summary addresses aspects of Order No. 

1920 as pertinent to the challenges to the 

Commission’s statutory authority raised on 

rehearing. 

413EPSA, 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.’’). 

414See Order No. 1920, 187 FERC ¶ 61,068 at PP 

265–66. 

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 LongTerm Transmission Needs.394

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 LongTerm 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

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

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

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, federallyrecognized 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 longterm, 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

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 Commissionjurisdictional targets.414 Rather, they 

argue that Order No. 1920 intrudes on 

state resource selection because, in 

regulating such transmission planning 


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415See 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). 

416See 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. 

417See 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). 

418See 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). 

419See id. PP 129–130, 233, 261–62, 419, 436. 

420See supra Unjust, Unreasonable, and Unduly 

Discriminatory or Preferential CommissionJurisdictional Transmission Planning and Cost 

Allocation Processes section. 

421See Order No. 1920, 187 FERC ¶ 61,068 at PP 

230, 266. 

422See 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’’)). 

423We 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. 

424See 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.’’). 

425See 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’’). 

426See id. PP 130, 233, 261–262. 

427See supra P 143 n.416. 

428See 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.’’). 

429Similarly, 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. 

and cost allocation, Order No. 1920 is 

purportedly biased toward the 

construction of transmission facilities 

that will serve allegedly Commissionfavored 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

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

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. 

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 LongTerm 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 LongTerm Scenarios irrespective of the 

substantive content of any given factor 

in a category. 

147. In this respect, the categories of 

factors identified in Order No. 1920 are 

best understood as a non-exhaustive 

identification of essential inputs 


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430We 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. 

431See id. P 248 (summarizing those processfocused requirements). 

432See id. P 412. 

433See id. P 417 (further providing that 

transmission providers must ‘‘assume that the laws, 

regulations, state-approved integrated resource 

plans, and expected supply obligations for loadserving 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. 

434Transmission 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. 

435See, 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. 

436Order 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 LongTerm Transmission Needs.’’); id. P 723. 

437Order 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.’’). 

439See id. PP 90–99. 

440See 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 . . . .’’). 

441Claims 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. 

442EPSA, 577 U.S. at 281. 

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 LongTerm 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

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

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

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

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. 

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 


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443 16 U.S.C. 824(b)(1) (‘‘The Commission shall 

have jurisdiction over all facilities for such 

transmission or sale of electric energy . . . .’’). 

444N.Y. v. FERC, 535 U.S. at 15. 

445EPSA, 577 U.S. at 290. 

446 16 U.S.C. 824e(a). 

447S.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.’’). 

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)). 

450See 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). 

451Order 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’’). 

452See 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.’’). 

453See 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’’). 

454See 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. 

455EPSA, 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. 

456Order No. 1920, 187 FERC ¶ 61,068 at P 409. 

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

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

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. 

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, federallyrecognized Tribal, state, and local laws 

and regulations affecting the resource 

mix and demand; (2) federal, federallyrecognized 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 


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457See 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. 

458FPA 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. 

459See 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. 

460Order 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. 

462S.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)). 

463As 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). 

464El 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))). 

465See, 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. 

466Undersigned States Rehearing Request at 11– 

12; Designated Retail Regulators Rehearing Request 

at 13. 

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

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

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

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 


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467Undersigned States Rehearing Request at 12– 

13; Designated Retail Regulators Rehearing Request 

at 14. 

468Undersigned 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). 

469No 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’’). 

470Ark. 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.’’). 

471See 16 U.S.C. 824(a), (b)(1), 824d, 824e. 

472EPSA, 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). 

475See 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.’’). 

476Order 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 costeffective 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. 

477The 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’’). 

478S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 81; 

see id. at 82–83 (discussing these reforms in more 

detail). 

479See id. at 84. 

480See id. at 84–87. 

481See 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)). 

482Cf. 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’’). 

483See Order No. 1920, 187 FERC ¶ 61,068 at PP 

1291–1292. 

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

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

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. 

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 LongTerm Regional Transmission Facilities, 

particularly with respect to the 


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484See 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. 

486Similarly, 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. 

487See 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). 

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). 

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

490 597 U.S. 697. 

491See 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. 

492Undersigned 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.’’). 

493Undersigned 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. 

494Undersigned States Rehearing Request at 15; 

Designated Retail Regulators Rehearing Request at 

16–17. 

495Undersigned States Rehearing Request at 16– 

17; Designated Retail Regulators Rehearing Request 

at 16–17, 18–19. 

496Arizona 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. 

implementation and effect of state 

public policies. 

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 LongTerm 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

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

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

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

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 


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498See Arizona Commission Rehearing Request at 

6; cf. id. at 16 (citing the cost of achieving net-zero 

on the transmission grid). 

499See id. at 4–5. 

500See id. at 20. 

501See id. at 5. 

502Utah 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). 

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. 

505Ohio Commission Federal Advocate Rehearing 

Request at 20. 

506 Id. 

507SERTP 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’’). 

509See supra Federal/State Division of Authority 

section. 

510See West Virginia, 597 U.S. at 721. 

511 Id. at 722–23; see also id. at 721. 

512See 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). 

513West 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). 

514West 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). 

515West 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.’’). 

516West 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)). 

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 fossilfueled generation and toward renewable 

resources’’ is a major question, pointing 

to its social and political context and 

economic consequences.502

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

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

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

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

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 


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517West 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. 

518West 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 technologybased 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). 

521West 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.’’). 

522West 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’’). 

523N.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). 

527Order 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). 

529See 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). 

530See 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. 

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-a`-vis 

EPA’s ordinary regulatory role. 

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

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. 

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 ‘‘gapfiller’’ 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’’ 


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531See N.Y. v. FERC, 535 U.S. at 11, 17. 

532See, 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). 

533See 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)). 

534See 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. 

535Order 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.’’). 

536See Order No. 1920, 187 FERC ¶ 61,068 at P 

278 (describing the rule as implementing 

‘‘incremental process improvements’’). 

537See supra Federal/State Division of Authority 

section. 

538Arguments 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. 

539See supra Federal/State Division of Authority 

section (noting that these forces would continue to 

exist, driving transmission needs, even absent 

Commission action). 

540See, 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). 

541See Order No. 1920, 187 FERC ¶ 61,068 at P 

278 (‘‘The incremental process improvements 

required by the final rule, however, do not 

in West Virginia) to its limits, thereby 

stripping the relevant term of meaning. 

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 costeffective 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 Commissionjurisdictional rates unjust and 

unreasonable. 

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

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


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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. 

542Undersigned States Rehearing Request at 15; 

see Designated Retail Regulators Rehearing Request 

at 15–16. 

543Arizona 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. 

545See 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). 

546See supra Order No. 1920 Does Not Attempt 

to Control the Generation Mix or Intrude in Areas 

of State Authority section. 

547Order No. 1920, 187 FERC ¶ 61,068 at PP 278– 

279. 

548 372 F.3d 395 (D.C. Cir. 2004) (CAISO). 

549See 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. 

550See 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’’). 551S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 57. 

552 Id. at 56. 

553 Id. at 57. 

554See West Virginia, 597 U.S. at 721–23. 

555See 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). 

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 costeffective 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. 

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. 

FERC548 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

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

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

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 


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556See 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. . . .’’). 

557See 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. 

558See 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. 

559See 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). 

560See 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. 

561SERTP Sponsors Rehearing Request at 39; see 

also id. at 41, 43 (issue statements 1 and 15). 

562 Id. at 44–45. 

563See, 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). 

564See 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.’’). 

565See 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). 

566Arizona 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). 

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

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 singlesentence assertions that provide little or 

nothing to illuminate why they believe 

this is the case.564

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. 

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 


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567 Id. at 13. 

568See Montana Commission Rehearing Request 

at 2–4; West Virginia Commission Rehearing 

Request at 10–12; Wyoming Commission Rehearing 

Request at 2–4. 

569See Montana Commission Rehearing Request 

at 4; West Virginia Commission Rehearing Request 

at 12; Wyoming Commission Rehearing Request at 

4. 

570Utah Commission Rehearing Request at 8 n.17. 

571Undersigned States Rehearing Request at 7–8; 

see id. at 24–26; Designated Retail Regulators 

Rehearing Request at 8, 24–26. 

572Undersigned 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. 

574See 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. 

575See Montana Commission Rehearing Request 

at 6–7; West Virginia Commission Rehearing 

Request at 9–10; Wyoming Commission Rehearing 

Request at 7–8. 

576Montana 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. 

577Arizona 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’’). 

578 Id. at 7–9. 

579 Id. at 8–9. 580Undersigned 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)). 

583Ohio 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). 

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

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 decisionmaking power by requiring that the 

states measure their long-term 

transmission plans against seven factors 

identified in the Order.’’ 573

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

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

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

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

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 


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585S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 57. 

586Order No. 1920, 187 FERC ¶ 61,068 at PP 134, 

667, 721–723. 

587See 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.’’). 

588Order No. 1920, 187 FERC ¶ 61,068 at P 257; 

see id. P 419 (‘‘We are not requiring that 

transmission providers select any particular LongTerm Regional Transmission Facility and therefore 

are not directing the development of any particular 

transmission facilities.’’). 

589See 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.’’). 

592S.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. 

594See 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. 

595See infra Requirement to Incorporate 

Categories of Factors section. 

596See 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 LongTerm Transmission Needs differ is their 

identification through the long-term, forwardlooking, and more comprehensive regional 

transmission planning and cost allocation processes 

established in this final rule.’’). 

597See infra Requirement to Incorporate 

Categories of Factors section. 

598See Montana Commission Rehearing Request 

at 2–4; West Virginia Commission Rehearing 

Request at 10–12; Wyoming Commission Rehearing 

Request at 2–4. 

599See 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). 

600See 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. 

602See Undersigned States Rehearing Request at 

7–8; Designated Retail Regulators Rehearing 

Request at 8, 24–26; Georgia PSC Rehearing Request 

at 4. 

603See 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). 

604Order No. 1920, 187 FERC ¶ 61,068 at P 259. 

605See 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 

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

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. 

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. 

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 


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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). 

606See, 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. 

607See 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). 

608Undersigned States Rehearing Request at 18– 

19. 

609Order 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). 

610See 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). 

611See 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’’). 

612See Undersigned States Rehearing Request at 

17–18. 

613See 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’’). 

614See 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.’’). 

615See 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). 

616Whitman 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). 

617Cf. 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)). 

618See Undersigned States Rehearing Request at 

17–18. 

619See 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). 

620This 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’’). 

621See supra Major Questions Doctrine section; 

Order No. 1920, 187 FERC ¶ 61,068 at PP 253–62, 

275–78. 

622Ohio Commission Federal Advocate Rehearing 

Request at 18–19. 

623See supra Federal/State Division of Authority 

section. 

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

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

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

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

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 


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624See 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 . . . .’’). 

625Order No. 1920, 187 FERC ¶ 61,068 at P 224. 

626 Id. P 241. 

627 Id. P 246. 

628 Id. P 242. 

629 Id. P 243. 

630 Id. P 244. 

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

V. Long-Term Regional Transmission 

Planning 

A. Requirement To Participate in LongTerm 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 costeffective 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

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

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

203. The Commission also allowed 

transmission providers to propose a 

regional transmission planning process 

that simultaneously plans for shorterterm reliability and economic 

transmission needs, as well as LongTerm 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

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 LongTerm Regional Transmission Planning 

and existing Order No. 1000 regional 

transmission planning processes. The 


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631 Id. P 1071. 

632 Id. (citation omitted). 

633Large 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. 

637Pennsylvania Commission Rehearing Request 

at 2. 

638Order No. 1920, 187 FERC ¶ 61,068 at PP 252, 

256; see Pennsylvania Commission Rehearing 

Request at 2. 639Pennsylvania Commission Rehearing Request 

at 2–3 (citing Order No. 1920, 187 FERC ¶ 61,068 

at P 243). 640 Id. 641PJM States Rehearing Request at 6–7. 642Pennsylvania Commission Rehearing Request 

at 1. 643See generally PIOs Rehearing Request at 16– 

25. 644 Id. at 16–18. 

Commission recognized that there may 

be overlap in the time horizon for LongTerm 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 nearterm reliability or economic benefits, 

and thus could displace regional 

transmission facilities that are under 

consideration as part of existing regional 

transmission planning processes.632

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

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 LongTerm Regional Transmission Planning 

and therefore would not be subject to relitigation.640

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

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 


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645 Id. at 20. 

646 Id. at 21–23. 

647 Id. at 23–24. 

648 Id. at 24–25. 

649Order 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). 

650 Id. P 244. 

651 Id. PP 252, 256; see Pennsylvania Commission 

Rehearing Request at 2–3. 

652Order No. 1920, 187 FERC ¶ 61,068 at P 242. 

transmission planning processes or 

aligning them with Long-Term Regional 

Transmission Planning will perpetuate 

unjust and unreasonable rates.645

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 LongTerm 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 LongTerm 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

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. 

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 shorterterm reliability and economic 

transmission needs, as well as LongTerm 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

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 relitigation 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 


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653 Id. P 243. 

654See 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.’’). 

655Order No. 1920, 187 FERC ¶ 61,068 at P 245. 

656 Id. P 114. 

657 Id. PP 1071–1073. 

658 Id. P 224. 

659 Id. PP 39, 299. 

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 LongTerm Regional Transmission Planning 

as set forth in Order No. 1920.653

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. 

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 shorterterm 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

215. Furthermore, we find that 

requiring transmission providers to use 

a combined process to plan for shorterterm 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 LongTerm Transmission Needs; (2) 

adequately account on a forwardlooking 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. 

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 LongTerm 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. 

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 LongTerm 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 LongTerm 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

219. Order No. 1920 generally 

addressed the identification of LongTerm Transmission Needs and the 

measurement of the benefits of LongTerm Regional Transmission Facilities 


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660E.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.’’). 

663PJM 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. 

667SERTP 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. 

670PIOs Rehearing Request at 59 (citing Order No. 

1920, 187 FERC ¶ 61,068 at PP 301, 719). 671 Id. at 59–60. 

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

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 LongTerm 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 LongTerm 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

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

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

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 


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672Order No. 1920, 187 FERC ¶ 61,068 at P 409. 

673 Id. P 344. 

674 Id. P 414. 

675See 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). 

676We 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. 

677Order No. 1920, 187 FERC ¶ 61,068 at P 302. 

678 Id. P 633. 

679 Id. P 344. 

680 Id. P 345. 

681 Id. P 348. 

682 Id. P 349. 

683Alabama Commission Rehearing Request at 4; 

Dominion Rehearing Request at 11–14; Ohio 

Commission Federal Advocate Rehearing Request at 

20–21. 

684 Dominion Rehearing Request at 7, 12–15. 

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. 

225. Thus, we are clarifying here that 

the categories of factors will help 

transmission providers identify LongTerm 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

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 LongTerm 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 LongTerm Scenarios.678

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 LongTerm 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

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 LongTerm 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

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 leadtime requirements or to compare 

alternative transmission solutions to 

identify more efficient or cost-effective 

transmission solutions to meet LongTerm Transmission Needs.682

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

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 


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685 Id. at 13–14 (citing Dominion NOPR Initial 

Comments at 18–19). 

686 Id. at 14 (citing Dominion NOPR Initial 

Comments at 20). 

687 Id. (citing Dominion NOPR Initial Comments 

at 20). 

688 Id. 

689 Id. at 15. 

690 Id. at 16–18. 

691 Id. at 15. 

692 Id. at 12–13, 16. 

693Ohio Commission Federal Advocate Rehearing 

Request at 20–21. 

694 Id. at 21. 

695Alabama Commission Rehearing Request at 4. 

696See 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). 

699 Id. P 349. 

700Alabama 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. 

702Order No. 1920, 187 FERC ¶ 61,068 at P 348. 

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

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

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

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

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

i. Commission Determination 

237. We sustain the requirement that 

transmission providers in each 

transmission planning region develop 

Long-Term Scenarios as part of LongTerm 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

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. 

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 overbuilding 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 


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703 Id. P 231. 704 Id. P 229. 

705 Dominion Rehearing Request at 16–18. 

706For 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. 

707 Infra Stakeholder Process and Transparency 

section. 

708We 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. 

709Order No. 1920, 187 FERC ¶ 61,068 at P 914. 

710 Id. P 349. 

711See, 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). 

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

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 scenarioplanning 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. 

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 LongTerm Regional Transmission Planning. 

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 LongTerm 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 LongTerm Transmission Needs.709

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 


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712 Id. P 345. 

713See Dominion Rehearing Request at 12–13, 16. 

714See Ohio Commission Federal Advocate 

Rehearing Request at 20. 

715See Order No. 1920, 187 FERC ¶ 61,068 at PP 

345, 349. 

716 Id. P 134. 

717See id. PP 345, 349. 

718 Id. P 377. 

719NOPR, 179 FERC ¶ 61,028 at P 97. 

720Order No. 1920, 187 FERC ¶ 61,068 at P 377. 

721At 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. 

724 Id. P 379 n.873. 

725 Id. 

726Order No. 1920, 187 FERC ¶ 61,068 at P 379 

(citations omitted). 

727 Id. (citations omitted). 

728 Id. 

729 Id. P 381. 

730 Id. 

transmission needs beyond a 20-year 

horizon.712

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. 

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 longterm, 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

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 LongTerm Scenarios that they use in LongTerm 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 LongTerm 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 LongTerm Regional Transmission Facilities 

to address those needs, and evaluating 

and deciding whether to select LongTerm 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

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

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

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 LongTerm Regional Transmission Planning 

cycle.730 The Commission further stated 

that transmission providers may 

propose on compliance to conduct 


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731 Id. P 384. 

732PIOs Rehearing Request at 9–15. 

733 Id. at 6 (citations omitted). 

734 Id. at 10–11. 

735 Id. at 9–11 (citations omitted). 

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. 

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. 

743SERTP Sponsors Rehearing Request at 26–27 

(citing Order No. 1920, 187 FERC ¶ 61,068 at PP 

382, 1031). 

744See Order No. 1920, 187 FERC ¶ 61,068 at P 

377. 745PIOs Rehearing Request at 9–11. 746Order No. 1920, 187 FERC ¶ 61,068 at P 380. 

747See 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). 

Long-Term Regional Transmission 

Planning more frequently than every 

five years.731

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

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

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 rerunning 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

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 LongTerm 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

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. 

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, federallyrecognized 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 LongTerm 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 


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748See id. P 384. 

749See id. P 379. 

750PIOs Rehearing Request at 12–13. 

751 Id. at 13–15. 

752Order No. 1920, 187 FERC ¶ 61,068 at PP 379, 

955. 

753 Id. P 379 n.873. 

754PIOs Rehearing Request at 14. 

755See Order No. 1920, 187 FERC ¶ 61,068 at P 

955. 

756 Id. P 379 n.873. 

757PIOs Rehearing Request at 14. 

758See Order No. 1920, 187 FERC ¶ 61,068 at P 

954. 

759See id. P 382. 

760See id. P 1031. 

Regional Transmission Planning more 

frequently than every five years.748

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 LongTerm Scenarios that they use in LongTerm 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 LongTerm 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 fiveyear 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. 

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 LongTerm 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

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

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 LongTerm 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 LongTerm Regional Transmission Planning 

cycle.758

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 LongTerm 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

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; 


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761 Id. P 409. 

762 Id. P 410. 

763 Id. P 411. 

764 Id. P 413. 

765 Id. 

766 Id. P 414. 

767 Id. P 415. 

768 Id. P 417. 

769 Id. P 419. 

770Arizona Commission Rehearing Request at 18. 

771 Id. 

772SERTP Sponsors Rehearing Request at 12–13. 

773 Id. at 13. 

774 Id. 

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. 

778Order No. 1920, 187 FERC ¶ 61,068 at P 233. 

779 Infra Stakeholder Process and Transparency 

section. 

(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 LongTerm 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

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

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 LongTerm 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

266. The Commission stated that 

requiring transmission providers to 

incorporate the seven categories of 

factors into the development of LongTerm 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

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 ‘precooking’ 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

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

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

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 LongTerm 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

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 LongTerm 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 


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780See, e.g., NOPR, 179 FERC ¶ 61,028 at PP 9, 

245; Order No. 1920, 187 FERC ¶ 61,068 at PP 232, 

266. 

781Order No. 1920, 187 FERC ¶ 61,068 at PP 

1026–1027. 

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. 

784For 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. 

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. 

786Order No. 1920, 187 FERC ¶ 61,068 at P 413. 

787 Id. P 417. 

788 Id. P 528. 

789 Infra Stakeholder Process and Transparency 

section. 

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 LongTerm 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

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 LongTerm Scenarios. We also acknowledge 

that factors in different categories of 

factors may overlap.783

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. 

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 LongTerm 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. 

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 LongTerm 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 LongTerm Scenario, or include different 

state-preferred power system trajectories 

in different Long-Term Scenarios. 

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 


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790See, 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 LongTerm 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. 

792Order No. 1920, 187 FERC ¶ 61,068 at P 417. 

793 Id. P 964. 

794 Id. PP 112–133. 

795 Id. P 411. 

796Order No. 1920, 187 FERC ¶ 61,068 at PP 448– 

449, 457–458, 464–466, 472–473, 481–484. 

797 Id. PP 492–494. 

798 Id. P 507. 

799 Id. 

800 Id. P 515. 

801 Id. P 508. 

802 Id. PP 510, 512. 

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 LongTerm 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

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 LongTerm 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 forwardlooking basis for known determinants of 

Long-Term Transmission Needs.794

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 LongTerm 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 categoryspecific 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

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, federallyrecognized Tribal, state, and local laws 

and regulations) are followed, stateapproved 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 LongTerm 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 LongTerm 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

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 


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803 Id. P 511. 

804 Id. P 516. 

805 Id. P 518. 

806 Id. 

807 Id. P 420. 

808 Designated Retail Regulators Rehearing 

Request at 7; Undersigned States Rehearing Request 

at 7. 

809Arizona Commission Rehearing Request at 15. 

810 Id. at 22. 

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). 

814Ohio Commission Federal Advocate Rehearing 

Request at 15. 

815 Id. at 16–17. 

816 Id. at 17. 

817 Id. 

818Alabama Commission Rehearing Request at 4– 

5; Industrial Customers Rehearing Request at 49–54; 

Northern Virginia Rehearing Request at 4–7; 

government entities, federallyrecognized Tribes, utilities, and loadserving entities provide during the 

required open and transparent 

stakeholder process to determine if 

specific factors are likely to affect LongTerm Transmission Needs and how to 

account for those specific factors in 

Long-Term Scenarios.803

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 LongTerm 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

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

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

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

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

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 buildout 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

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, federallyrecognized Tribal, state, and local policy 

goals that affect long-term transmission 

needs) should be excluded from the 

development of Long-Term 

Scenarios.818


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NRECA Rehearing Request at 55; SERTP Sponsors 

Rehearing Request at 15–17; Virginia and North 

Carolina Commissions Rehearing Request at 6–8. 

819SERTP Sponsors Rehearing Request at 16 

(citations omitted). 

820 Id. at 15. 

821 Id. at 16. 

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). 

826 Id. at 54–55 (citations omitted). 

827 Id. at 55 (quoting Order No. 1920, 187 FERC 

¶ 61,068 at P 261). 

828 Id. at 49–50. 

829 Id. at 50. 

830Northern Virginia Rehearing Request at 4. 

831 Id. at 3–4. 

832 Id. at 4. 

833 Id. at 7–9. 

834 Virginia and North Carolina Commissions 

Rehearing Request at 7. 

835 Id. 

836 Id. at 8 (citation omitted). 

837NRECA Rehearing Request at 54–55. 

838 Id. at 55. 

839Harvard ELI Rehearing Request at 9–11; PIOs 

Rehearing Request at 61. 

840Harvard ELI Rehearing Request at 9–11. 

841PIOs Rehearing Request at 61. 

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

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

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

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

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

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

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

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

(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. 


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842Order No. 1920, 187 FERC ¶ 61,068 at P 410. 

843Arizona Commission Rehearing Request at 15. 

844Order No. 1920, 187 FERC ¶ 61,068 at PP 232, 

437. 

845Arizona Commission Rehearing Request at 22; 

NRECA Rehearing Request at 54–55. 

846Order 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). 

847E.g., Designated Retail Regulators Rehearing 

Request at 28; Ohio Commission Federal Advocate 

Rehearing Request at 16–17; Undersigned States 

Rehearing Request at 27–28. 

848Order No. 1920, 187 FERC ¶ 61,068 at P 435. 

849 Id. P 436. 

850E.g., Designated Retail Regulators Rehearing 

Request at 28; Ohio Commission Federal Advocate 

Rehearing Request at 16–17; Undersigned States 

Rehearing Request at 27–28. 

851See infra Stakeholder Process and 

Transparency section; Requests for Additional 

Flexibility Regarding Long-Term Scenarios 

Requirements section. 

852See, e.g., Order No. 1920, 187 FERC ¶ 61,068 

at PP 419, 1419, 1471, 1513. 

853E.g., Designated Retail Regulators Rehearing 

Request at 8; Undersigned States Rehearing Request 

at 8. 

854E.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). 

856See infra Requests for Additional Flexibility 

Regarding Long-Term Scenarios Requirements 

section. 

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 LongTerm Scenarios is necessary because 

without doing so, transmission 

providers will fail to adequately 

consider drivers of Long-Term 

Transmission Needs.842

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

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

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

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 LongTerm 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

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 buildout 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 


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857Order No. 1920, 187 FERC ¶ 61,068 at PP 229, 

231, 473. 

858 Id. PP 484, 507. 

859We 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. 

860See, 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)). 

861Order 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. 864SERTP Sponsors Rehearing Request at 16; 

Industrial Customers Rehearing Request at 54. 865See, e.g., Order No. 890, 118 FERC ¶ 61,119 at 

P 435. 866Order No. 1920, 187 FERC ¶ 61,068 at PP 415, 

417. 867 Id. P 516 

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

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 LongTerm 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 LongTerm 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 (stateapproved integrated resource plans and 

expected supply obligations for loadserving entities). 

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 loadserving 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, federallyrecognized 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 LongTerm 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, federallyrecognized 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 LongTerm Scenarios at all.863

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, federallyrecognized 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 


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868 Id. P 261; Industrial Customers Rehearing 

Request at 55. 869Order No. 1920, 187 FERC ¶ 61,068 at P 415. 870Supra 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). 871Order No. 1920, 187 FERC ¶ 61,068 at P 530. 872 Industrial Customers Rehearing Request at 49– 

50. 

873Order 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). 

874 Industrial Customers Rehearing Request at 51– 

53. 

875 Id. at 52. 

876Order No. 1920, 187 FERC ¶ 61,068 at P 508. 

877See infra Stakeholder Process and 

Transparency section. 

878 Industrial Customers Rehearing Request at 53. 

879SERTP 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). 

880Supra Requirement to Incorporate Categories 

of Factors section. 

881Order No. 1920, 187 FERC ¶ 61,068 at P 299. 

882See supra Requirement for Transmission 

Providers To Use the Seven Required Benefits To 

Help To Inform Their Identification of Long-Term 

Transmission Needs section. 

‘‘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. 

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

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, federallyrecognized 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. 

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

312. We recognize that utility 

commitments and federal, federallyrecognized 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. 

313. We disagree with NRECA’s claim 

that the inclusion of Factor Category 

Seven expands the definition of LongTerm 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 


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883Order No. 1920, 187 FERC ¶ 61,068 at P 418. 

884NRECA 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’’). 

885NRECA 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). 891SERTP 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. 

895PIOs Rehearing Request at 33–35. 

896 Id. at 33. 

897 Id. 

898 Id. 

899 Id. at 34. 

900 Id. at 35. 

901Order No. 1920, 187 FERC ¶ 61,068 at PP 447, 

510. 

deficiencies in the Commission’s 

existing regional transmission planning 

requirements, including the failure to 

ensure that transmission providers 

adequately account on a forwardlooking basis for known determinants of 

Long-Term Transmission Needs.883

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 (stateapproved integrated resource plans and 

expected supply obligations for loadserving entities) may not affect LongTerm 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

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 nonjurisdictional 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

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

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

(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 LongTerm 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 


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902 Id. P 417. 

903Cf. 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). 

905 Infra Stakeholder Process and Transparency 

section. 

906Order No. 1920, 187 FERC ¶ 61,068 PP 283, 

420. 

907 144 S.Ct. 2244 (2024). 

908NRECA Rehearing Request at 41 (citing S.C. 

Pub. Serv. Auth. v. FERC, 762 F.3d at 54). 

909S.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. 

910Compare 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)). 

911Order No. 1920, 187 FERC ¶ 61,068 at P 528. 

912SERTP Sponsors Rehearing Request at 6. 

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-andchoose 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 LongTerm 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

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 stateapproved integrated resource plans are 

incorporated in the manner they are 

expected to be implemented. 

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 loadserving entities’ expected supply 

obligations) that are likely to affect 

Long-Term Transmission Needs in the 

development of Long-Term Scenarios. 

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 loadserving entities, and therefore we find 

that it complies with FPA section 

217(b)(4). 

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. 

323. In addition, we grant SERTP 

Sponsors’ request for clarification 

regarding non-jurisdictional entities,912

in part. We clarify that, where a nonVerDate Sep<11>2014 19:15 Dec 05, 2024 Jkt 265001 PO 00000 Frm 00066 Fmt 4701 Sfmt 4700 E:\FR\FM\06DER2.SGM 06DER2

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913Order No. 1920, 187 FERC ¶ 61,068 at PP 507, 

510. 

914Cf. 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)). 

915El Paso Elec. Co. v. FERC, 76 F.4th at 363–66. 

916NOPR, 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. 

917Order 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. 

919PIOs Rehearing Request at 33. 

920Order No. 1920, 187 FERC ¶ 61,068 at P 417. 

921 Id. PP 413–414. 

922PIOs Rehearing Request at 33. 

923See 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). 

924The 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. 

926PIOs Rehearing Request at 33. 

927 Invenergy Rehearing Request at 2, 6–7. 

928 Id. at 10. 

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 nonjurisdictional 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

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

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, federallyrecognized 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 LongTerm Scenarios with the best available 

data,921 are adequate to safeguard 

against ‘‘boundless discounting’’ and 

opportunities to ‘‘functionally ignore 

the Commission’s mandate.’’ 922

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 LongTerm 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. 

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

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 


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929 Invenergy Rehearing Request at 9 (citing AEE 

NOPR Reply Comments at 19). 

930 Id. at 8–9. 

931 Id. at 9. 

932See Order No. 1920, 187 FERC ¶ 61,068 at P 

493. 

933NOPR, 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.). 

934Order 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.’’). 

936 Invenergy Rehearing Request at 8. 

937Order 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. . . .’’). 

939Order No. 1920, 187 FERC ¶ 61,068 at P 493. 

940See id. PP 528–533. 

941 Id. P 534. 

942 Invenergy Rehearing Request at 9. 

943Order No. 1920, 187 FERC ¶ 61,068 at P 633. 

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

(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 advancedstage 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. 

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

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, LongTerm 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 LongTerm 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 LongTerm 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. 

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 


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944 Id. 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.’’). 

946Order 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). 

948 Invenergy Rehearing Request at 10. 

949Order No. 1920, 187 FERC ¶ 61,068 at P 472. 950 Id. P 528. 

951 Id. P 533. 

952 Id. P 534. 

953 Id. P 535. 

954 Id. P 305 (citing Order No. 890, 118 FERC 

¶ 61,119 at P 471). 

955 Id. PP 529–530. 

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

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 advancedstage 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

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 advancedstage 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. 

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 federallyrecognized 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 LongTerm 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 LongTerm 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

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

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 


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956 Id. P 530. 

957 Id. P 531. 

958NESCOE Rehearing Request at 11. 

959 Id. at 20–21. 

960PJM States Rehearing Request at 4. 

961PIOs Rehearing Request at 36. 

962 Id. 963 Id. at 37–38. 964 Id. at 38 (citing Order No. 1920, 187 FERC 

¶ 61,068 at P 305). 965SERTP Sponsors Rehearing Request at 13–14. 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. 

969 Id. at 26. 

970Order No. 1920, 187 FERC ¶ 61,068 at PP 528– 

537, 560–562, 634. 

971A 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 

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

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

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

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

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 costeffective or efficient transmission 

planning.965

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

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 LongTerm 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

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 


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this case, the Relevant State Entity may authorize 

the other state entity as its representative in 

discussions with transmission providers. 

972See id. P 417. 

973 Id. 

974See 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.’’). 

975PIOs 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.’’). 

976Supra P 346 n.975. 

977Order No. 1920, 187 FERC ¶ 61,068 at P 305. 

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. 

979Order No. 1920, 187 FERC ¶ 61,068 at P 1027. 

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 

Continued 

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 policyrelated outcomes materialize in some 

but not all Long-Term Scenarios).972

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 LongTerm 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

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

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

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 


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identification by stakeholders of this factor or these 

factors. 

981 Id. P 533. 

982See id. P 534 (discussing the value of posting 

requirement in terms of the transparency into how 

transmission providers develop Long-Term 

Scenarios). 

983 Id. P 559. 

984 Id. P 560. 

985 Id. PP 575–577. 

986 Id. P 576. 

987 Id. P 593. 

988 Id. P 594. 

989 Id. P 597. 

990 Id. P 598. 

991See 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 

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 dayto-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. 

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 LongTerm 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. 

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

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 LongTerm 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

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

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. 


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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. 

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. 

999PJM States Rehearing Request at 4–6; West 

Virginia Commission Rehearing Request at 14–16. 

1000Ohio Commission Federal Advocate 

Rehearing Request at 18. 

1001 Virginia and North Carolina Commissions 

Rehearing Request at 4–5. 

1002PJM Rehearing Request at 16. 

1003PJM States Rehearing Request at 4–5; West 

Virginia Commission Rehearing Request at 14–16. 

1004Order No. 1920, 187 FERC ¶ 61,068 at PP 409, 

559. 

1005See supra Long-Term Scenarios 

Requirements, Stakeholder Process and 

Transparency section. 

1006Order No. 1920, 187 FERC ¶ 61,068 at P 410. 

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

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

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, stateapproved 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

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

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 LongTerm 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

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

c. Commission Determination 

361. We disagree with PJM’s rehearing 

arguments and deny its requested 

clarification with respect to flexibility 

regarding the development of LongTerm 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 forwardlooking 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 


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1007 Id. P 411. 

1008We 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. 

1010PJM Rehearing Request at 18–19. 

1011To 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. 

1012Order No. 1920, 187 FERC ¶ 61,068 at P 298. 

1013 Id. P 417. 

1014 Id. P 421. 

1015 Id. P 559. 

1016The 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. 

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 LongTerm 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. 

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

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 loadserving 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

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 LongTerm 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 LongTerm Scenarios in Long-Term Regional 

Transmission Planning.1015

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. 

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 LongTerm 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 LongTerm 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 LongTerm Scenarios as defined in Order No. 

1920.1017 In other words, transmission 

providers may not use any such 

additional analyses to identify LongTerm Transmission Needs, identify 

Long-Term Regional Transmission 

Facilities, or to meet the requirement 

that transmission providers estimate the 

costs and measure the benefits of LongTerm 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. 

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 


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1018For 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. 

1019Order No. 1920, 187 FERC ¶ 61,068 at PP 

1472, 1477. 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); OneTime 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). 

1021Order No. 1920, 187 FERC ¶ 61,068 at P 597. 

1022Order No. 1920, 187 FERC ¶ 61,068 at P 719. 

1023 Id. P 720. 

1024 Id. P 722. 

1025 Id. P 723. 

1026 Id. 

1027NOPR, 179 FERC ¶ 61,028 at P 183 (citation 

omitted). 

1028 Id. P 185. 

1029 Id. P 184. 

1030 Id. P 188. 

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

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

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 LongTerm 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

370. The Commission found that the 

record demonstrated that, in order to 

ensure just and reasonable Commissionjurisdictional transmission rates, it was 

necessary to require transmission 

providers to measure and use in LongTerm 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 LongTerm 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 costeffective regional transmission 

solution(s) to specific Long-Term 

Transmission Needs.1025

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 LongTerm Regional Transmission Benefits as 

a minimum set of benefits for their 

Long-Term Regional Transmission 

Planning process.’’ 1030


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1031East 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)). 

1032NRECA Rehearing Request at 10 (quoting 

NOPR, 179 FERC ¶ 61,028 at P 183). 

1033 Id. at 11. 

1034See Order No. 1920, 187 FERC ¶ 61,068 at P 

719. 

1035Brennan 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)). 

1036See NRECA Rehearing Request at 10 (citing 

NOPR, 179 FERC ¶ 61,028 at P 188). 

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. 

1044PJM Rehearing Request at 5, 26–27 & n.106. 

1045 Id. at 26–29, 42. 

1046 Id. at 29. 

1047 Designated Retail Regulators Rehearing 

Request at 29; Undersigned States Rehearing 

Request at 29. 

1048NRECA Rehearing Request at 11–12. 

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-sizefits all’’ and the ‘‘exact opposite’’ of the 

proposed rule.1033

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 LongTerm 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. 

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 LongTerm 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 primarybenefits 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

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

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


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1049Order No. 1920, 187 FERC ¶ 61,068 at PP 

723–724. 

1050See 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). 

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). 1054See infra No Selection Requirement section. 

1055Order 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. 

1059 Id. P 721. 

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 Commissionjurisdictional 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

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 LongTerm 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 LongTerm 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

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 LongTerm 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 LongTerm Transmission Needs.’’ 1057 The 

Commission also stated that ‘‘[b]y 

requiring the measurement and use of 

the seven enumerated benefits in LongTerm 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

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: 

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, 


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1060 Id. P 722. 

1061 Dominion Rehearing Request at 20. 

1062Order No. 1920, 187 FERC ¶ 61,068 at P 727. 

1063 Id. P 122. 

1064Contrary 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 costeffective 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 LongTerm 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.’’). 

1065PJM 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.’’). 

1066See Order No. 1920, 187 FERC ¶ 61,068 at PP 

722–723, 725, 727–728. 

1067 Id. PP 723, 728. 

1068 Id. P 724. 1069 Id. P 735. 

1070 Id. P 770. 

1071 Id. 

evaluate, and select regional transmission 

facilities that are more efficient or costeffective transmission solutions to LongTerm 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

381. Indeed, as Dominion concedes, 

the seven benefits that Order No. 1920 

requires transmission providers to use 

and measure when evaluating LongTerm Regional Transmission Facilities 

are ‘‘inherent benefits of all 

transmission.’’ 1061

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 Commissionjurisdictional 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 costeffective 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

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 Commissionjurisdictional 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

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: 

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 doublecounting. 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

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 doublecounting 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 Commissionjurisdictional transmission planning 

process.1071

387. The Commission in Order No. 

1920 also offered guidance regarding the 


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1072 Id. P 804. 

1073 Designated Retail Regulators Rehearing 

Request at 8 (citation omitted); Undersigned States 

Rehearing Request at 8 (citation omitted). 

1074 Designated Retail Regulators Rehearing 

Request at 29; Undersigned States Rehearing 

Request at 29. 

1075Order 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. 

1078 Id. P 954. 

1079 Id. PP 954, 966. 

1080 Id. P 837. 

1081 Id. P 822. 

1082 Designated Retail Regulators Rehearing 

Request at 31–33 (citing Organization of MISO 

Continued 

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

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

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

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 doublecounting.’’ 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 LongTerm 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

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. 

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 LongTerm 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 LongTerm Regional Transmission Planning. 

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, nonduplicative, 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


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97252 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

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). 

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%20

Resolution%20re%20MISO%20South%20Cost%20

Allocation%20for%20Tranche%203629421.pdf). 

1084NESCOE Rehearing Request at 11 (citation 

omitted). 

1085Order No. 1920, 187 FERC ¶ 61,068 at P 277 

(citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 

68–69). 1086See 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). 1087See 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.’’). 1088See Order No. 1920, 187 FERC ¶ 61,068 at PP 

722–723, 725, 728. 1089 Id. P 745. 1090 Id. P 727. 

1091Organization 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. 

1092Order 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 . . . .’’). 

1096Entergy 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%20

MISO%20South%20Cost%20Allocation%20

for%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, forwardlooking, and replicable metrics that are supported 

by data.’’). 

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: 

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, forwardlooking, 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 standalone 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

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

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

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 LongTerm Regional Transmission Planning is 

necessary to ensure that Commissionjurisdictional 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. 

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

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 


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1097Order No. 1920, 187 FERC ¶ 61,068 at P 822. 

1098Entergy Regional State Committee, Resolution 

of the Entergy Regional State Committee, at 3 

(adopted June 30, 2023), https://

cdn.misoenergy.org/20230630%20-%20ERSC%20

Resolution%20re%20MISO%20South%20Cost%20

Allocation%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.’’) 

1099Order 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’’). 

1100See id. PP 914, 994. 

1101Further, 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. 

1102Order No. 1920, 187 FERC ¶ 61,068 at P 755. 

1103SERTP Sponsors Rehearing Request at 18. 

1104Order No. 1920, 187 FERC ¶ 61,068 at P 727. 

1105 Id. P 748. 

1106See SERTP Sponsors Rehearing Request at 18 

n.46, 43 (Issue Statement 15) (citations omitted). 

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

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

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

(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 LongTerm Regional Transmission Facilities 

that may under certain planning 

scenarios suggest a potential benefit.1103

(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

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 


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1107Order No. 1920, 187 FERC ¶ 61,068 at P 767. 

1108 Id. P 773 (citations omitted). 

1109SERTP Sponsors Rehearing Request at 19. 

1110 Designated Retail Regulators Rehearing 

Request at 30–31. 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. 

1112Order No. 1920, 187 FERC ¶ 61,068 at PP 

821–822. 

1113 Id. P 737. 

1114PIOs Rehearing Request at 26–27. 

reduction in market prices as lower-cost 

suppliers set market clearing prices.1107

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

(b) Requests for Rehearing and 

Clarification 

407. SERTP Sponsors argue that the 

Commission should clarify that 

production cost analysis from stateapproved 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, stateregulated integrated-resource-plan 

planning must control in accordance 

with FPA section 201.1109

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 loadserving entity receives any benefit or 

harm from transmission 

construction.1110

(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 Commissionjurisdictional 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

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 loadserving 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

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 


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1115 Id. at 27 (citing NOPR, 179 FERC ¶ 61,028 at 

PP 208–209, 213–225). 

1116TAPS Rehearing Request at 12–13. 

1117 Id. at 11. 

1118Order No. 1920, 187 FERC ¶ 61,068 at P 724. 

1119 Id. P 724. 

1120 Id. PP 821–822. 

1121 Id. P 737. 

1122 Id. PP 837, 840. 

1123 Id. P 839. 

1124 Id. P 822. 

1125SERTP Sponsors Rehearing Request at 17–18. 

proposed benefits have a proven track 

record, can be discretely measured, and 

are unlikely to cause duplication.1115

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 doublecounting. 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

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

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. 

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

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

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 


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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). 

1127Order No. 1920, 187 FERC ¶ 61,068 at P 840. 

1128 Id. P 859. 

1129 Id. P 865. 

1130 Id. PP 861, 865. 

1131 Id. P 862. 

1132 Id. PP 862, 865. 

1133SERTP 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. 

1135Under 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 LongTerm Scenario. The total estimated benefits of the 

Long-Term Regional Transmission Facility would 

then be calculated by summing the probabilityadjusted 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 LongTerm Scenario’s benefits multiplied by 40%). 

basis to cause transmission providers to 

engage in resource planning.1126

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 generationbased 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 generationbased 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

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 inservice 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

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 LongTerm 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

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

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 


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1136Order No. 1920, 187 FERC ¶ 61,068 at P 865. 

1137See supra Long-Term Scenarios 

Requirements, Stakeholder Process and 

Transparency section. 

1138SERTP 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). 

1139See supra Statutory Authority section. 

1140Order No. 1920, 187 FERC ¶ 61,068 at P 889. 

1141PIOs 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). 1145Undersigned 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. 

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. 

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 LongTerm 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

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 LongTerm 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 statejurisdictional 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. 

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

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 LongTerm 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

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 nonbeneficiaries.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

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 


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1149See PIOs Rehearing Request at 47. 

1150Order 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. 

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). 1152See 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). 1153Order No. 1920, 187 FERC ¶ 61,068 at P 911. 

1154 Id. P 924. 

1155 Id. P 954. 

1156 Id. P 955. 

1157 Id. P 964. 

1158 Id. P 954. 

1159 Id. PP 954, 966. 

1160 Id. P 966 n.2121. 

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

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 LongTerm 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 nonbeneficiaries, 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 LongTerm 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. 

D. Evaluation and Selection of LongTerm 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. 

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 costeffective 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

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

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) 


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1161 Id. P 955. As to the identification of LongTerm 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 LongTerm 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). 

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. 

1166NRECA Rehearing Request at 14. 

1167NRECA Rehearing Request at 14–15 (citing 

Order No. 1920, 187 FERC ¶ 61,068 at PP 381, 955). 

1168See 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. 

1169PIOs Rehearing Request at 48–49 (citing PIOs 

NOPR Initial Comments, ex. A at 12–17). 

1170 Id. at 48–49. 

1171 ITC Rehearing Request at 11–12. 

1172 Dominion Rehearing Request at 25 (emphasis 

added) (citing Order No. 1920, 187 FERC ¶ 61,068 

at PP 955, 964–965). 

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 LongTerm Regional Transmission Facilities; 

and (4) culminate in determinations that 

are sufficiently detailed for stakeholders 

to understand why a particular LongTerm 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

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 LongTerm Transmission Needs, such as by 

using a least-regrets or weightedbenefits 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

b. Requests for Rehearing and 

Clarification 

439. NRECA argues that the 

Commission violated the APA’s noticeand-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

440. NRECA also requests that the 

Commission grant rehearing and require 

that transmission providers’ selection 

criteria ensure the selection of LongTerm Regional Transmission Facilities 

that meet the reasonable needs of loadserving 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

441. PIOs request rehearing of the 

Commission’s determination to allow 

transmission providers to adopt benefitcost 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

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

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


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1173 Id. at 25–26 (punctuation omitted) (quoting 

Order No. 1920, 187 FERC ¶ 61,068 at P 737). 

1174 Id. 

1175TAPS 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)). 

1176NRECA 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). 

1178See 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). 

1179NOPR, 179 FERC ¶ 61,028 at P 245. 1180Order No. 1920, 187 FERC ¶ 61,068 at P 955. 1181 Id. 1182Conn. 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). 

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

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 LongTerm 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

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

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 costeffective Long-Term Regional 

Transmission Facilities to address LongTerm 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

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 


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1183Order 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. 

1184 Id. P 958. 

1185See 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. 

1187See id. P 967 (describing least-regrets and 

weighted-benefits approaches to selecting LongTerm Regional Transmission Facilities as potential 

methods to manage uncertainty). 

1188 Id. P 968. 

1189See 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). 

1190See 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. 

1192See id. PP 954–971. 

1193See 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). 

1194Order No. 1920, 187 FERC ¶ 61,068 at PP 737, 

954–955, 966, 1214. 

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

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 LongTerm 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 LongTerm Regional Transmission Facilities 

may differ depending on the Long-Term 

Scenario or sensitivity in which they are 

measured.1186

449. We also disagree with the 

rehearing arguments advanced by ITC. 

While we agree with ITC that a leastregrets 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 LongTerm Regional Transmission Planning 

or by requiring a particular selection 

approach. 

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 LongTerm 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 passwordprotected 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. 

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 


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1195 Id. P 994. 

1196 Id. P 995. 

1197 Id. P 994. 

1198 Id. P 996. 

1199Arizona 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. 

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)). 

1201NRECA Rehearing Request at 6, 17–19. 

1202See Arizona Commission Rehearing Request 

at 16. 

1203NARUC Rehearing Request at 17. 

1204NESCOE Rehearing Request at 12. 

1205 Designated Retail Regulators Rehearing 

Request at 48–49. 

1206See NOPR, 179 FERC ¶ 61,028 at PP 241, 244. 

1207NRECA Rehearing Request at 17–18. 

1208N.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’’). 

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

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

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 LongTerm 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

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

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

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. 

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 


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1209Order 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. 

1211See Arizona Commission Rehearing Request 

at 16. 

1212Order 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. 1215See 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). 

1216Reasonable Efforts, Black’s Law Dictionary 

(12th ed. 2024). 

1217As 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. 

1218 Id. P 1012. 

1219 Id. 

1220 Id. P 1013. 

1221 Id. 

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

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. 

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 LongTerm 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. 

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

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

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

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 


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1222SERTP 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. 

1223Order 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. 

1225Order No. 1920, 187 FERC ¶ 61,068 at P 1026 

(citations omitted). 

1226 Id. P 968. 

1227SERTP Sponsors Rehearing Request at 9–10 

(citing Order No. 1920, 187 FERC ¶ 61,068 at PP 

968, 1026). 

1228PJM Rehearing Request at 19. 

1229Order No. 1920, 187 FERC ¶ 61,068 at P 1026. 

1230NOPR, 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. 

1231NOPR, 179 FERC ¶ 61,028 at P 247. 

1232 Id. P 248. 

1233Order No. 1920, 187 FERC ¶ 61,068 at PP 

1048–1049. 

1234 Id. P 1050. 

otherwise is prohibiting voluntary 

funding in other circumstances.1222

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

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

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

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

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

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 nearterm 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

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 LongTerm 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

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 


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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. 

1237 Id. 

1238 Id. P 1051. 

1239 Id. P 1050. 

1240 Id. 

1241 Id. P 1052 (citing MISO, FERC Electric Tariff, 

MISO OATT, attach. FF (Transmission Expansion 

Planning Protocol) (90.0.0), § IX.E, which sets forth 

potential outcomes of MISO’s variance analysis 

procedures). 

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 costeffective regional transmission solution to LongTerm Transmission Needs). 

1244 Id. P 1052 n.2254. 

1245 Id. P 1052. 

1246 Id. 

1247East 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. 

1248EEI 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 PostTechnical Conference Comments, Transmission 

Planning and Cost Mgmt., Docket No. AD22–8–000, 

et al. (Dec. 23, 2022)). 

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

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, federallyrecognized 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 overbuilding 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 LongTerm 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

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 LongTerm 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

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 overbuilding transmission facilities.1246

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 LongTerm 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 


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1252 Id. at 10–11. 

1253NRECA Rehearing Request at 4–6. 

1254 Id. at 14. 

1255 Id. at 4, 19. 

1256WIRES Rehearing Request at 3–5. 

1257 Id. at 2–4. 

1258 Id. at 10. 

1259See, e.g., EEI Rehearing Request at 7–8; 

WIRES Rehearing Request at 7–8. 

1260MISO TOs Rehearing Request at 21–22 (citing 

Order No. 1920, 187 FERC ¶ 61,068 at P 1048). 1261WIRES Rehearing Request at 6–7 (quoting 

NOPR, 179 FERC ¶ 61,028 at P 248). 1262See NOPR, 179 FERC ¶ 61,028 at P 248. 1263EEI Rehearing Request at 5–6. 1264 Id. at 8–9. 

1265NRECA 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). 

1268MISO TOs Rehearing Request at 19–21. 

1269 ITC Rehearing Request at 16. 

1270MISO TOs Rehearing Request at 19, 22. 

facilities that may not be cost-effective, 

but asserts that the appropriate remedy 

in this instance is to return to the NOPR 

proposal.1252

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-andcomment requirements, the Commission 

withdraw the final rule and issue a 

supplemental NOPR.1255

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

479. Several rehearing parties contend 

that, while the NOPR proposed a 

structure that would permit but not 

require transmission providers to 

reevaluate previously selected LongTerm 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

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

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

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 LongTerm 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

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 


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1271WIRES Rehearing Request at 14–16 (quoting 

Order No. 1920, 187 FERC ¶ 61,068 at P 1053). 

1272MISO TOs Rehearing Request at 4; ITC 

Rehearing Request at 17; WIRES at 11–12. 

1273MISO TOs Rehearing Request at 17–19 (citing 

Order No. 1920, 187 FERC ¶ 61,068 at P 1059). 

1274 Id. at 13. 

1275 ITC Rehearing Request at 15–19. 1276WIRES Rehearing Request at 14. 1277NRECA 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). 1278Large 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). 

1279Large Public Power Rehearing Request at 17– 

18 (citing Order No. 1920, 187 FERC ¶ 61,068 at PP 

1054, 1059). 

1280NRECA Rehearing Request at 30–32. 

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’’). 

1282 ITC Rehearing Request at 13–14. 

1283Large Public Power Rehearing Request at 19– 

20. 

1284NRECA Rehearing Request at 36 (quoting 

State Farm, 463 U.S. at 43). 

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

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 LongTerm 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

485. ITC argued that, while 

reevaluating a previously selected LongTerm 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 LongTerm 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 LongTerm 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

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 pencilsdown point, such that the transmission 

developer of the selected facility would 

have adequate certainty to make 

investment decisions.1277

487. Large Public Power and NRECA 

requested that the Commission require 

on rehearing that transmission providers 

reevaluate previously selected LongTerm 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 LongTerm Transmission Needs have 

changed.1280

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

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 LongTerm 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. 

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

491. Several parties requested that the 

Commission provide transmission 

providers with more flexibility to 

reevaluate previously selected LongTerm Regional Transmission Facilities 

in other situations. Dominion sought 


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1285 Dominion Rehearing Request at 17. 1286SERTP Sponsors Rehearing Request at 20–21. 1287Brennan 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). 

1289NOPR, 179 FERC ¶ 61,028 at P 68; Order No. 

1920, 187 FERC ¶ 61,068 at P 224. 

1290Order No. 1000, 136 FERC ¶ 61,051 at P 329. 

1291NOPR, 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). 

1293 Id. P 248. 

1294 Id. 

1295NOPR, 179 FERC ¶ 61,028 at P 245. 

1296 Id. P 248. 

1297Order No. 1920, 187 FERC ¶ 61,068 at P 1055 

& n.2256. 

1298 Id. PP 1048–1055. 

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

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. 

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

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 overbuilding [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 LongTerm 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

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 inservice within 10 years (i.e., unless its 


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1299 Id. PP 1050–1051. 

1300Brennan v. Dickson, 45 F.4th at 69. 

1301We 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. 

1302See e.g., East Kentucky Rehearing Request at 

2; NRECA Rehearing Request at 33. 

1303See e.g., ITC Rehearing Request at 15–19; 

MISO TOs Rehearing Request at 17–19. 

1304Order No. 1920, 187 FERC ¶ 61,068 at P 1054. 

1305Large Public Power Rehearing Request at 17– 

19; NRECA Rehearing Request at 29–30. 

1306NRECA Rehearing Request at 30–32. 

1307 Id. at 33. 

1308 Dominion Rehearing Request at 17; SERTP 

Sponsors Rehearing Request at 20–21. 1309Order No. 1920, 187 FERC ¶ 61,068 at P 1053. 1310 ITC Rehearing Request at 4–5. 1311Order No. 1920, 187 FERC ¶ 61,068 at P 1056. 1312MISO TOs Rehearing Request at 17–19; ITC 

Rehearing Request at 15–19. 

1313Order No. 1920, 187 FERC ¶ 61,068 at P 1059. 

1314This 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. 

1315 ITC Rehearing Request at 6–9; MISO TOs 

Rehearing Request at 17–19. 

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 finetuning of a proposed rule in response to 

comments that is the raison d’eˆtre for 

APA notice-and-comment 

requirements.1301

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 LongTerm 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 costeffective Long-Term Regional 

Transmission Facilities.1309

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. 

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 LongTerm Regional Transmission Facilities, 

because otherwise the transmission 

provider would compare the facility’s 

currently determined costs with its 

previously determined benefits.1313

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. 

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 LongTerm 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 


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1316Order No. 1920, 187 FERC ¶ 61,068 at P 1052. 

1317 Id. P 1071. 

1318 Id. 

1319 Id. P 1072. 

1320 Id. 

1321 Id. P 1073. 

1322PJM Rehearing Request at 41. 

1323 Id. 

1324TAPS Rehearing Request at 6–9. 

1325 Id. at 8. 

1326 Id. at 6–9. 

1327Order No. 1920, 187 FERC ¶ 61,068 at P 1072. 

1328See id. 

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. 

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 LongTerm 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 nearterm reliability or economic benefits, 

and thus could displace regional 

transmission facilities that are under 

consideration as part of existing regional 

transmission planning processes.1318

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 LongTerm 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 LongTerm 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 LongTerm 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 LongTerm Regional Transmission Planning 

cycle is necessary and appropriately 

tailored for their transmission planning 

region.1320

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 nearterm transmission needs and toward a 

more robust, well-planned transmission 

system.1321

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

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 LongTerm 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

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 


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1329See id. 

1330 Id. 

1331 Id. P 245. 

1332 Id. P 1073. 

1333Order No. 1920, 187 FERC ¶ 61,068 at P 1100. 

1334 Id. P 1101. 

1335 Id. 

1336 Id. P 1102. 

1337 Id. PP 1106, 1145. 

transmission planning cycles, which 

may be longer than a single year. 

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. 

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 LongTerm 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. 

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 LongTerm 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

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 interconnectionrelated 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

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


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1338SERTP Sponsors Rehearing Request at 22; 

Large Public Power Rehearing Request at 23; 

Industrial Customers Rehearing Request at 46–47. 

1339SERTP 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)). 

1341PJM Rehearing Request at 31. 

1342 Id. 

1343 Id. 

1344PJM 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). 

1346NRECA Rehearing Request at 48–49. 

1347Order No. 1920, 187 FERC ¶ 61,068 at P 1106. 

1348 Id. P 1100. 

1349See id. P 1108. 

1350 Id. P 1103. 

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

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

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

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. 

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. 

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 


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1351See id. P 1113. 

1352 Id. P 1126. 

1353See 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. 

1355See, 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-GeneratorInterconnection-Policy-1.pdf (ACEG 2021 

Interconnection Report) at 17. 

1357See id. P 1147. 

1358 Id. P 1148. 

1359 Id. P 1149. 

1360 Id. P 1103. 

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. 

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 nearerterm interconnection-related transmission 

needs identified through the generator 

interconnection process.1352

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

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

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 interconnectionrelated 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

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

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 


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1361 Id. P 1145. 

1362 Id. P 1146. 

1363 Id. PP 1146–1147. 

1364 Id. P 1150. 

1365 Id. P 1130. 

1366 Id. PP 1145, 1150–1151. 

1367 Id. P 1151. 

1368 Id. P 1146, n. 2433. 

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.). 

1372 Id. P 1145. 

1373 Id. P 1150. 

1374 Id. PP 1150, 1158. 

1375 Id. P 1150. 

1376 Id. PP 1145, 1158–1160. 

interconnection process by meeting four 

qualifying criteria. Specifically, the 

Commission required transmission 

providers to evaluate interconnectionrelated 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 Commissionaccepted tariff provisions proposed to 

comply with this reform, and the laterin-time withdrawn interconnection 

request occurring after the effective date 

of the Commission-accepted tariff 

provisions); (2) an interconnectionrelated 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

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

527. As relevant here, the 

Commission proposed in the NOPR that 

part of the criteria regarding 

interconnection-related transmission 

needs is met where an interconnectionrelated 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 interconnectionrelated 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

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 interconnectionrelated 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 interconnectionrelated 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

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 interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated transmission needs.1375

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 fiveyear period means looking back from 

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1377 Id. P 1145. 

1378 Id. P 1159. 

1379We 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. 

1380Order No. 1920, 187 FERC ¶ 61,068 at P 1159. 

1381 Id. P 1150 (citations omitted). 

1382Clean Energy Associations Rehearing Request 

at 13–22. 

1383 Id. at 21–22. 

1384 Id. 

1385 Id. at 22–26. 

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)). 

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. 

1392 Id. at 18. 

1393 Id. at 18–21. 

accepted tariff provisions proposed to 

comply with this reform and the laterin-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

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

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 interconnectionrelated 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 interconnectionrelated network upgrades for inclusion 

in the initial regional transmission 

planning cycle exceeds five years, or 

alternatively, grant rehearing to require 

so.1385

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 interconnectionrelated 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

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

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 


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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’’)). 

1395 Id. at 23–24. 

1396 Id. at 24. 

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. 

1399Order No. 1920, 187 FERC ¶ 61,068 at P 1146. 

1400 Id. P 1112. 

1401 Id. P 1151. 

1402 Id. PP 1103–1104. 

1403Clean 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)). 

1404Order No. 1920, 187 FERC ¶ 61,068 at PP 

1106–1121. 

adopting its unduly restrictive criteria 

‘‘does not hold water.’’ 1394

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: 

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 interconnectionrelated 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 timeperiod over which network upgrades could 

be identified for evaluation as 

interconnection-related transmission needs is 

seven years and nine months.1396

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

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 interconnectionrelated 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

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 interconnectionrelated 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 interconnectionrelated network upgrades meet both of 

these thresholds for an interconnectionrelated 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. 

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 interconnectionrelated 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 


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Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 97277 

1405 Id. P 1150. 

1406 Id. 

1407 Id. 

1408 Id. PP 1150, 1158. 

1409We 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. 

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). 

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. 

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 interconnectionrelated 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 costeffective transmission solution, 

compared to interconnection-related 

transmission needs that satisfy only the 

cost threshold, or only the voltage 

threshold. 

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 interconnectionrelated transmission needs is 

required.1408

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

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 


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97278 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

We also modify the double 

withdrawal criterion in Attachment K to 

read (with additions in bold and 

italicized and deletions struck through): 

We make a slight modification to 

criterion (4) so that it reads (with 

additions in bold and italicized and 

deletions struck through): 

We also add a new criterion (5), the 

withdrawal window criterion, as 

follows (with additions in bold and 

italicized): 


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(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)duriHg the pFeeediHg fr;e 

yeaFS (lookiHg back from the effective date of the accepted tariff 

prnvisioHs prnposed to eomply v;ith this FefoFm iH OFdeF No. 1920, 

and the lateF iH time v;ithdmvm irnernonnectioH rnquest occurriHg 

afteF the effecti•;e date of the aecepted tariff pFo•;isioHs); 

(3) the irnernonnectioH Felated NetwoFk Upgmde idernified 

ilirough the geHeFatoF irneFcoHHeetioH prneess to meet the FelevaHt 

irnernoHHectioH rnlated traHsmissioH Heed is Hot currernly planned 

to be de•;eloped because the interconnection requestfst 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 firstcome, 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; aHe: 

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 
Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 97279 

1410See pro forma LGIP § 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. 

1411See, e.g., pro forma §§ LGIP 3.1.1 (Study 

Deposits), 7 (Cluster Study), 8 (Interconnection 

Facilities Study), 9 (Affected Systems Study), 10 

(Option Interconnection Study). 

1412Order 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.’’) 

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 laterin-time withdrawn interconnection request 

occurring after the effective date of the 

Commission-accepted tariff provisions)’’). 

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

547. The modifications that we make 

here clarify that a transmission provider 

need not evaluate an interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated 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

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 


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(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. 
97280 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

1414 Id. P 1159. 

1415See id. P 1145. 

1416 Id. P 1111. 

1417 Id. P 1112. 

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. 

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 interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated 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. 

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 


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1418 Id. P 1117. 

1419 Id. P 1118. 

1420Retail 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. 

1421Retail Regulators Rehearing Request at 43–44; 

Undersigned States Rehearing Request at 37; West 

Virginia Commission Rehearing Request at 16. 

1422Undersigned States at 37. 

1423PJM 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. 

1424NRECA Rehearing Request at 48. 

1425 Industrial Customers Rehearing Request at 

41. 

1426East Kentucky Rehearing Request at 3. 

1427 Industrial Customer Rehearing Request at 41. 

1428 Id. at 43. 

1429 Id. at 45. 

1430Ohio Consumers Rehearing Request at 8–9; 

see also Industrial Consumers Rehearing Request at 

42. 

1431NRECA Rehearing Request at 46. 

1432 Id. at 48. 

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 costeffective 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

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

559. NRECA states that the 

Commission has failed to consider that 

its policies governing interconnectionrelated 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: 

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

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

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 interconnectionrelated 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

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 Commissionaccepted 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 


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1433See Order No. 1920, 187 FERC ¶ 61,068 at P 

1156. 

1434 Id. P 1117. 

1435 Id. 

1436 Id. P 1119. 

1437PJM Rehearing Request at 33; NRECA 

Rehearing Request at 44, 46–47. 

1438PJM Rehearing Request at 33; NRECA 

Rehearing Request at 46. 

1439PJM Rehearing Request at 34. 

1440Order No. 1920, 187 FERC ¶ 61,068 at P 1155. 

1441PJM Rehearing Request at 35. 

1442 Id. at 36. 

1443 Id. at 35. 

1444 Id. 

1445PJM Rehearing Request at 36. 

1446Order No. 1920, 187 FERC ¶ 61,068 at P 1119. 

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 costeffective 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. 

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

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

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

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 nonselection in RTEP that a developer may 

face.1445

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 


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1447 Id. PP 1119, 1145. 

1448See id. P 1119. 1449 Id. P 1126. 

1450 Id. P 1127. 

1451East Kentucky Rehearing Request at 1–2; 

NRECA Rehearing Request at 15–16. 

1452Clean Energy Associations Rehearing Request 

at 4–6. 

1453 Id. at 6. 

1454 Id. at 7. 

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. 

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. 

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 LongTerm 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

573. The Commission agreed with 

commenters that future interconnectionrelated 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, federallyrecognized 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, federallyrecognized Tribal, state, and local policy 

goals that affect Long-Term 

Transmission Needs, through LongTerm Regional Transmission 

Planning.1450

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

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 LongTerm 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’’ LongTerm Regional Transmission Planning, 

which they believe is consistent with 

the Commission’s justifications of the 

reform and supported by the record.1454

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 


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1455 Id. at 7–8. 

1456 Id. at 8. 

1457 Id. at 9. 

1458 Id. at 10–11. 

1459 Id. at 11–12. 

1460 Id. at 12–13. 

1461Large Public Power Rehearing Request at 21. 

1462 Id. at 21–22. 

1463Large Public Power Rehearing Request at 22. 

1464PJM Rehearing Request at 37–38. 

1465 Id. 

1466 Id. at 38. 

1467 Id. 

1468East Kentucky Rehearing Request at 1–2; 

NRECA Rehearing Request at 15–16. 

1469Telesat 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 costeffective 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. 

1470NOPR, 179 FERC ¶ 61,028 at P 174. 

and Withdrawals), is no grounds to 

deny a parallel path for transmission 

providers to evaluate interconnectionrelated 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. 

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 interconnectionrelated network upgrades in both LongTerm Regional Transmission Planning 

and the existing Order No. 1000 regional 

transmission planning and cost 

allocation processes.1457

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

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

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

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

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

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 


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1471Brennan v. Dickson, 45 F.4th at 69 (quoting 

CSX Transp., Inc. v. Surface Transp. Bd., 584 F.3d 

at 1081). 

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)). 

1473NOPR, 179 FERC ¶ 61,028 at P 166. 

1474Order No. 1920, 187 FERC ¶ 61,068 at P 1126. 

1475NOPR, 179 FERC ¶ 61,028 at P 167. 

1476Conn. Light & Power Co. v. Nuclear 

Regulatory Comm’n, 673 F.2d at 533. 

1477Order No. 1920, 187 FERC ¶ 61,068 at P 1126. 

1478 Id. PP 1127–1128. 1479 Id. P 1111. 

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. 

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 interconnectionrelated 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

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 interconnectionrelated 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. 

586. In addition, we reiterate that 

transmission providers must consider 

future interconnection-related 

transmission needs as a driver of LongTerm 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 interconnectionrelated 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 LongTerm 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 interconnectionrelated transmission needs that 

transmission providers consider in 

Long-Term Regional Transmission 

Planning. 

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 LongTerm Scenarios requirements (in LongTerm 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 LongTerm 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 interconnectionrelated transmission needs through 

Long-Term Regional Transmission 

Planning. 

588. In response to Clean Energy 

Associations’ request for clarification 

that Order No. 1920 does not prohibit 

transmission providers from evaluating 


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1480 Id. P 1127. 

1481 Id. P 1145. 

1482 Id. 

1483 Id. P 1111. 

1484 Id. 

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 interconnectionrelated transmission needs in LongTerm 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. 

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

590. Furthermore, the evaluation 

requirement only requires transmission 

providers to evaluate interconnectionrelated 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 interconnectionrelated 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

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

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 interconnectionrelated 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 interconnectionrelated 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 interconnectionrelated 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 costeffective 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 


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1485Order 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. 

1486NOPR, 179 FERC ¶ 61,028 at P 272. 

1487Order No. 1920, 187 FERC ¶ 61,068 at P 1198. 

1488 Id. P 1199. 

1489 Id. P 1214. 1490Large Public Power Request for Rehearing at 

13–16. 1491NESCOE Request for Rehearing at 6, 22–25, 

34. 

1492 Id. at 25. 

1493 Id. at 24–25. 

1494Large Public Power Request for Rehearing at 

13–16. 

1495We 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. 

1496Order No. 1920, 187 FERC ¶ 61,068 at P 1198. 

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

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

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

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 costeffective 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

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

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 


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1497 Id. P 1199. 

1498Large Public Power Request for Rehearing at 

16. 

1499See Order No. 1920, 187 FERC ¶ 61,068 at P 

1214. 

1500See, 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. 

1501NESCOE Request for Rehearing at 6, 22–25. 

1502See, 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.’’). 

1503Order 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.’’). 

1504See id. 

1505Clean Energy Associations Rehearing Request 

at 26–30; PIOs Rehearing Request at 7, 38–43 

(citations omitted). 1506Clean Energy Associations Rehearing Request 

at 26 (quoting Order No. 1920, 187 FERC ¶ 61,068 

at P 1245); PIOs Rehearing Request at 40. 

1507Clean Energy Associations Rehearing Request 

at 26. 

1508 Id. at 27. 

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. 1513PIOs Rehearing Request at 38, 42–43 

(citations omitted). 1514 Id. at 43. 

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). 

1517CTC Global Rehearing Request at 2–3. 

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

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 costeffective 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 costeffective solution in all instances. 

Consequently, Order No. 1920 mandates 

a process for the consideration of 

alternative transmission technologies, 

not specific outcomes.1504

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 caseby-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

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 LongTerm Regional Transmission 

Planning.1512

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

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

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


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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. 

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. 

1523Order 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)). 1525Order No. 2023, 184 FERC ¶ 61,054 at P 1599; 

Order No. 2023–A, 186 FERC ¶ 61,199 at P 640. 1526Sw. Power Pool, Inc., 183 FERC ¶ 61,153, at 

P 29 (2023). 

1527Order No. 1920, 187 FERC ¶ 61,068 at P 1247. 

1528See, 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%20

Technologies%20Report%20-%20final%20

as%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-GridDeployment_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. § 16422(a) (defining 

‘‘advanced transmission technology’’ as ‘‘a 

technology that increases the capacity, efficiency, or 

reliability of an existing or new transmission 

facility’’). 

1529See CTC Global Rehearing Request at 4–5 

(setting forth proposed modified definition). 1530Order No. 1920, 187 FERC ¶ 61,068 at P 1198 

n.2553. 1531 Id. P 1243. 1532CTC 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). 

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

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

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 caseby-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

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 


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1533 Invenergy Rehearing Request at 10–13. 

1534Order No. 1920, 187 FERC ¶ 61,068 at P 1247. 

1535NOPR, 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. 

1536 Id. P 315. 1537 Id. P 318. 1538 Id. P 310. 1539The 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. 

1541 Id. P 1429. 

1542Arizona Commission Rehearing Request at 

19; Idaho Commission Rehearing Request at 2, 5– 

6. 

1543Arizona Commission Rehearing Request at 

19. 

1544 Idaho Commission Rehearing Request at 5 

(quotation marks omitted). 

1545 Designated Retail Regulators Rehearing 

Request at 47–50. 

required consideration certain advanced 

conductors that may be more efficient or 

cost-effective in specific circumstances. 

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. 

VIII. Regional Transmission Cost 

Allocation 

A. Obligation To File an Ex Ante LongTerm 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 LongTerm 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

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

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

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 Commissionapproved State Agreement Process in 

their OATTs.1541

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, LongTerm 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

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 


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1546Arizona Commission Rehearing Request at 

18; Designated Retail Regulators Rehearing Request 

at 47, 49–50. 

1547NOPR, 179 FERC ¶ 61,028 at P 302. 

1548Order No. 1920, 187 FERC ¶ 61,068 at PP 

1291–1292. 

1549NOPR, 179 FERC ¶ 61,028 at P 318. 

1550Brennan v. Dickson, 45 F.4th at 69 (quoting 

CSX Transp., Inc. v. Surface Transp. Bd., 584 F.3d 

at 1081). 

1551Further, 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-andcomment 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. 

1552See 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. 

1553Order No. 1920, 187 FERC ¶ 61,068 at P 1291. 

1554 Id.; see also id. PP 1292, 1403. 

1555 Id. PP 1292, 1361, 1404. 

1556 Id. PP 1291–1292. 

1557 Id. PP 1359, 1429; see also id. PP 1296, 1363. 

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. 

policy and corporate-driven projects 

when states do not consent.1546

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

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 LongTerm 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

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

619. In addition to the required LongTerm 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 LongTerm Regional Transmission Cost 

Allocation Method on file would apply 

as a backstop.1556

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 LongTerm 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

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 


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1559NARUC Rehearing Request at 12–17. 

1560 Id. at 16. 

1561 Id. at 15. 

1562Ohio Commission Federal Advocate 

Rehearing Request at 7–8. 

1563 Id. at 8. 

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. 

1566Wyoming Commission Rehearing Request at 

2–3. 

1567 Id. at 3. 

1568 Idaho Commission Rehearing Request at 5–6. 

1569 Id. 

1570 Id. 

1571See infra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section. 1572Order 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). 

1573See infra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section. 

1574See Idaho Commission Rehearing Request at 

5–6; Wyoming Commission Rehearing Request at 3. 

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

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

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

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

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

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 LongTerm 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 LongTerm 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. 

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 LongTerm Regional Transmission Cost 

Allocation Method on file would apply 

as a backstop. While we sustain the 

requirement to have a backstop LongTerm 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

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 LongVerDate Sep<11>2014 19:15 Dec 05, 2024 Jkt 265001 PO 00000 Frm 00120 Fmt 4701 Sfmt 4700 E:\FR\FM\06DER2.SGM 06DER2

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1575NOPR, 179 FERC ¶ 61,028 at P 302. 

1576Order 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.’’). 

1577NARUC 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. 

1578Order No. 1920, 187 FERC ¶ 61,068 at PP 

1354, 1356–1357. 

1579 Id. PP 1415–1416. 

1580See infra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section. 

1581Order 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.’’). 

1582See infra Consultation with Relevant States 

Entities After the Engagement Period section. 

1583See supra Requests for Additional Flexibility 

Regarding Long-Term Scenarios Requirements 

section. 

1584See 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 . . . .’’). 

1585Order 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))). 

1586See infra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section; Duration of the Engagement Period section. 

1587Order No. 1920, 187 FERC ¶ 61,068 at P 1293. 

1588 Idaho Commission Rehearing Request at 5–6. 

1589See infra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section; Duration of the Engagement Period section. 

1590Order No. 1920, 187 FERC ¶ 61,068 at P 1296. 

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

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 LongTerm Regional Transmission Cost 

Allocation Method(s) or the 

development of cost allocation methods 

through the State Agreement 

Process(es).1583

630. To the extent that Wyoming 

Commission argues that requiring an ex 

ante cost allocation method for LongTerm 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

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 Commissionjurisdictional rates are just and 

reasonable.1587

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 


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1591See infra Consultation with Relevant State 

Entities After the Engagement Period section. 

1592Order No. 1920, 187 FERC ¶ 61,068 at P 1293. 

1593 Id. 

1594 Id. 

1595See 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.’’). 

1596Order No. 1920, 187 FERC ¶ 61,068 at P 1293 

(citation omitted). 

1597 Id. 

1598 Id. P 1354. 

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. 

1602See 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. 

1603Order 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. 

allocation amendments.1591 Relevant 

State Entities therefore have a 

meaningful opportunity to participate in 

cost allocation decisions related to 

Long-Term Regional Transmission 

Facilities. 

633. We continue to find that if 

transmission providers were to rely 

solely on a State Agreement Process to 

determine the cost allocation for LongTerm 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

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

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

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

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

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 


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1604See id. PP 1354, 1357. 1605 Id. P 1363. 1606 Id. 1607 Designated Retail Regulators Rehearing 

Request at 37–38; Undersigned States Rehearing 

Request at 33. 1608See supra P 628 n.1577. 

1609See Designated Retail Regulators Rehearing 

Request at 38. 

1610Order No. 1920, 187 FERC ¶ 61,068 at P 1357. 

1611 Id. 

1612 Id. P 1360. 

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. 

1616NARUC 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. 

1617NARUC Rehearing Request at 12. 

1618PJM States Rehearing Request at 2–3 (citing 

Order No. 1920, 187 FERC ¶ 61,068 at PP 1469, 

1472, 1476). 

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

639. With respect to requests that we 

require agreement of state regulators for 

any cost allocation method for LongTerm 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. 

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 LongTerm 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 nonconsenting states paying for costs they 

did not cause. 

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

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 LongTerm 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

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 


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1619West Virginia Commission Rehearing Request 

at 13–14. 

1620NARUC Rehearing Request at 17–18; PIOs 

Rehearing Request at 55–57; PJM States Rehearing 

Request at 7–8. 

1621West Virginia Commission Rehearing Request 

at 9. 

1622 Id. 

1623NARUC Rehearing Request at 17–18. 

1624 Id. at 17; PJM States Rehearing Request at 7; 

Virginia and North Carolina Commissions 

Rehearing Request at 10. 

1625PIOs Rehearing Request at 54–57. 

1626NESCOE 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 LongTerm Regional Transmission Planning, and 

specifically cost allocation. Vermont Commission 

Rehearing Request at 1–2. 

1628NESCOE 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), § 7.2)). 

1630 Id. at 16. 

1631Harvard 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. 

1636NARUC Rehearing Request at 21–22. 

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

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

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

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

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 


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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. 1638PIOs Rehearing Request at 55–56. 1639See, e.g., Order No. 1920, 187 FERC ¶ 61,068 

at P 1415. 

1640Order 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. 

1641E.g., Harvard ELI Rehearing Request at 4; 

NESCOE Rehearing Request at 15. 

1642Order No. 1920, 187 FERC ¶ 61,068 at PP 

113–114; supra The Overall Need for Reform 

section. 

1643 16 U.S.C. 824e(a). 

1644See 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’’). 

1645See 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. 

1646NARUC 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. 

1647Order 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. 

1649Order 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.’’). 

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

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

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. 

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 LongTerm 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. 

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

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 


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1650See NARUC Rehearing Request at 17–18; 

PIOs Rehearing Request at 55–57; PJM States 

Rehearing Request at 7–8. 

1651We 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. 

1652Order No. 1920, 187 FERC ¶ 61,068 at P 1360. 

1653NARUC 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. 

1654Order No. 1920, 187 FERC ¶ 61,068 at P 1357. 

1655 16 U.S.C. 824e; 16 U.S.C 825l(b). 

1656See 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). 

1657See, 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). 

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. 

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. 

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. 

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. 

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

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 


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1658 FCC v. Fox Television Stations, Inc., 556 U.S. 

at 515. 

1659Supra Categories of Factors section. 

1660Order 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. 

1662We 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. 

1663See infra Consultation with Relevant State 

Entities After the Engagement Period section. 

1664Harvard 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. 

1665NARUC Rehearing Request at 21–22. 

1666See 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. 

1667Harvard ELI Rehearing Request at 6–7. 1668See Design and Operation of the Engagement 

Period section. 1669Order No. 1920, 187 FERC ¶ 61,068 at P 126. 1670See supra P 654; infra Duration of the 

Engagement Period section; Consultation with 

Relevant State Entities After the Engagement Period 

section. 1671PIOs Rehearing Request at 55–56. 1672NESCOE Rehearing Request at 15–16. 1673See 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.’’). 

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 costeffective 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

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

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. 

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 


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1674See Infra Consultation with Relevant State 

Entities After the Engagement Period section. 1675NOPR, 179 FERC ¶ 61,028 at PP 278, 303, 

305, 308. 

1676 Id. P 306. 

1677 Id. P 314. 

1678 Id. P 319. 

1679 Id. P 321. 

1680Order No. 1920, 187 FERC ¶ 61,068 at P 1354. 

1681 Id. PP 1354, 1357. 

1682 Id. P 1456. 

1683NRECA Rehearing Request at 17–18. 

1684Undersigned States Rehearing Request at 38 

(quoting Int’l Union, United Mine Workers of Am., 

407 F.3d at 1259–60). 

1685West Virginia Commission Rehearing Request 

at 3. 

1686Utah Commission Rehearing Request at 11– 

12. 

1687See 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. 

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

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 LongTerm Regional Transmission Facilities 

an opportunity to do so.1677

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

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

c. Requests for Rehearing and 

Clarification 

666. NRECA asserts that the 

requirement in Order No. 1920 for 

transmission providers to file a LongTerm 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

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

668. In the NOPR, the Commission 

proposed to require transmission 


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1688NOPR, 179 FERC ¶ 61,028 at PP 278, 303, 

305, 308. 

1689 Id. P 299. 

1690Conn. 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’’). 

1691Order No. 1920, 187 FERC ¶ 61,068 at PP 

1354, 1357. 

1692See NOPR, 179 FERC ¶ 61,028 at P 299. 

1693Order No. 1920, 187 FERC ¶ 61,068 at P 1362. 

1694See, 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). 

1695Order No. 1920, 187 FERC ¶ 61,068 at P 1354. 

1696West Virginia Commission Rehearing Request 

at 8; Virginia and North Carolina Commissions 

Rehearing Request at 8–10. 

1697West Virginia Commission Rehearing Request 

at 8. 

1698 Virginia and North Carolina Commissions 

Rehearing Request at 9–10. 

1699West Virginia Commission Rehearing Request 

at 8; Virginia and North Carolina Commissions 

Rehearing Request at 8–10. 

1700Order No. 1920, 187 FERC ¶ 61,068 at PP 124, 

1362. 

1701See id. P 1362 & n.2906 (citing Minnesota 

State Entities NOPR Initial Comments). 

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

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

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

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. 

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 LongTerm 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 


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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). 

1703 Id. PP 124, 1362. 

1704 Id. P 1362. 

1705 Id. 

1706West Virginia Commission Rehearing Request 

at 8. 

1707 Virginia and North Carolina Commissions 

Rehearing Request at 10. 

1708See infra Content of the Engagement Period 

section. 

1709See supra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section. 

1710See supra Requirements Concerning Relevant 

State Entities’ Preferred Cost Allocation Methods 

section. 

1711Order No. 1920, 187 FERC ¶ 61,068 at P 1358. 

1712PJM 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. 

1713PJM States Rehearing Request at 3–4; 

Pennsylvania Commission Rehearing Request at 1. 

1714West Virginia Commission Rehearing Request 

at 13. 

1715SERTP Sponsors Rehearing Request at 7–8. 

1716PJM 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. 

1718Wyoming Commission Rehearing Request at 

7. 

1719Arizona 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. 

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

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

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

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

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


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1722Order No. 1920, 187 FERC ¶ 61,068 at P 124. 

1723 Id. 

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. 

1726 Id. 

1727 Id. PP 1360–1361 (citations omitted). 

1728 Id. P 1363. 

1729NARUC Rehearing Request at 17; PJM States 

Rehearing Request at 7. 

1730PJM States Rehearing Request at 8. 

1731 Id. (emphasis in original). 

1732 Id. at 8–9. 

1733See id. at 7; NARUC Rehearing Request at 17– 

18. 

1734See Order No. 1920, 187 FERC ¶ 61,068 at P 

1357. 

1735We 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 

Continued 

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. 

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

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

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

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

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

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


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method in its compliance filing above in the 

Requirements Concerning Relevant State Entities’ 

Preferred Cost Allocation Methods section. 

1736PJM States Rehearing Request at 8–9. 

1737Order No. 1920, 187 FERC ¶ 61,068 at P 1363. 

1738 Id. P 1402. 

1739 Id. P 1355. 

1740 Id. P 1364. 

1741PJM States Rehearing Request at 8. 

1742Order No. 1920, 187 FERC ¶ 61,068 at P 1368. 

1743NARUC Rehearing Request at 21–22; 

NESCOE Rehearing Request at 13–14. 

1744NESCOE 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))). 

1745NARUC 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. 

1746 Virginia and North Carolina Commissions 

Rehearing Request at 11 n.27. 

1747We 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. 

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

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. 

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

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 LongTerm 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

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

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

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. 

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 


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1748E.g., Order No. 1920, 187 FERC ¶ 61,068 at PP 

124, 126. 

1749See, 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). 

1750SPP, 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). 

1751MISO 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). 

1752Order No. 1920, 187 FERC ¶ 61,068 at P 1355. 1753 Id. PP 1364 & n.2914, 1402. 1754APPA Rehearing Request at 2. 1755 Id. at 4. 1756 Id. at 5 (citing 16 U.S.C. 796(15)) (emphasis 

in original). 

1757Large Public Power Rehearing Request at 11. 

1758 Id. 

1759 Id. at 12. 1760 Id. at 12–13. 1761 Id. at 13. 1762City of New Orleans Council Rehearing 

Request at 4. 1763 Id. (citing La. Const., art. IV, § 21(c); Home 

Rule Charter of the City of New Orleans, § 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-statecommittee/ (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. 

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

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

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

695. Large Public Power claims that 

non-jurisdictional self-regulating nonpublic 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

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

697. City of New Orleans Council 

requests rehearing in the event that the 

Commission does not grant its request 


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1768 Id. at 8. 

1769 Id. at 9. 

1770NESCOE Rehearing Request at 17–20. 

1771 Id. at 18–19. 

1772 Id. at 19. 

1773NRECA Rehearing Request at 57–58. 

1774APPA Rehearing Request at 2, 4–5; Large 

Public Power Rehearing Request at 11–13. 

1775Order No. 1920, 187 FERC ¶ 61,068 at P 1364 

(quoting NOPR, 179 FERC ¶ 61,028 at P 297 

(footnote omitted)). 

1776As 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. 

1777Order No. 1920, 187 FERC ¶ 61,068 at P 1364 

(alterations omitted) (citing NOPR, 179 FERC 

¶ 61,028 at P 299). 

1778City of New Orleans Council Rehearing 

Request at 4, 8; NESCOE Rehearing Request at 17– 

20. 

1779Order 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. 

1781NRECA Rehearing Request at 57–58. 

1782APPA Rehearing Request at 5 (citing 16 

U.S.C. 796(15)) (emphasis in original). 

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

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

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

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

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: 

[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 Commissionjurisdictional rates.1777

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. 

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 


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1783See 16 U.S.C. 796(15)) and 16 U.S.C. 796(6), 

respectively. 1784Order No. 1920, 187 FERC ¶ 61,068 at P 1406. 1785 Id. P 1413. 1786 Id. P 1414. 1787 Designated Retail Regulators Rehearing 

Request at 9; Undersigned States Rehearing Request 

at 8. 

1788SERTP Sponsors Rehearing Request at 7–8. 

1789 Id. 

1790Order No. 1920, 187 FERC ¶ 61,068 at P 1414. 

1791 Id. P 1413. 

1792 Id. PP 1302–1303. 

1793 Id. P 243. 

1794PJM 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. 

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

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 LongTerm 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

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

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

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. 

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

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 widelyaccepted 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


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1801Ohio Commission Federal Advocate 

Rehearing Request at 12–13. 

1802PJM Rehearing Request at 19–23. 

1803Order 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). 

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). 

1806PJM 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. 

1807Ohio Commission Federal Advocate 

Rehearing Request at 12–13. 

1808Order No. 1920, 187 FERC ¶ 61,068 at PP 

1302–1303. 

1809See 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). 

1810See 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). 

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

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 LongTerm 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

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 LongTerm 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

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 reapproved 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 


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1811NOPR, 179 FERC ¶ 61,028 at PP 302, 312. 

1812 Id. P 312. 

1813Order No. 1000, 136 FERC ¶ 61,051 at PP 622, 

637, 646, 657, 668, 685. 

1814Order No. 1920, 187 FERC ¶ 61,068 at P 1469. 

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)). 

1818Arizona Commission Rehearing Request at 

17–19; East Kentucky Rehearing Request at 1–2; 

NRECA Rehearing Request at 6, 16–17. 

1819NRECA Rehearing Request at 16–17. 

1820 Id. at 6, 17. 

allocation method and, as a result, is not 

in any way affected by Order No. 1920. 

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 LongTerm 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 Commissionjurisdictional 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

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

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

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

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 LongTerm Regional Transmission Cost 

Allocation Methods and the cost 

allocation methods resulting from a 

State Agreement Process are not a 


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1821 Id. at 16–17. 

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.’’). 

1824NOPR, 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. 

1827See 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. 

1828NOPR, 179 FERC ¶ 61,028 at P 325. 

1829Order No. 1920, 187 FERC ¶ 61,068 at P 1474. 

1830Ariz. 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). 

1831New 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’’). 

1832See NOPR, 179 FERC ¶ 61,028 at PP 67, 325. 

1833New 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.’’). 

1835NOPR, 179 FERC ¶ 61,028 at P 302. 

1836New York v. EPA, 413 F.3d at 44. 

logical outgrowth of the NOPR’s exactly 

opposite proposals.’’ 1821

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-andcomment 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

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 projecttype-limited Long-Term Regional 

Transmission Cost Allocation Methods, 

because such an approach would be 

inconsistent with Order No. 1920’s longterm, 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. 

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

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 


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1837Cf. 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). 

1838Order 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). 

1839 Id. P 1469. 

1840 Id. P 1474. 

1841 Id. 

1842 Id. P 1469. 1843Arizona 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. 

1844Arizona 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. 

1845Utah 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). 

1848Ohio Commission Federal Advocate 

Rehearing Request at 13–15. 

1849E.g., Northern Virginia Rehearing Request at 

5. 

1850East Kentucky Rehearing Request at 3. 

1851Ohio Commission Federal Advocate 

Rehearing Request at 10. 

1852 Dominion Rehearing Request at 29–30. 

Commission’s decision to refrain from 

adopting the entire proposal as to LongTerm 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

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-typelimited 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

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 LongTerm 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

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

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 


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1853 Id. at 29. 

1854 Id. at 29–31. 

1855NRECA 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. 

1858 Id. 

1859 Id. at 55. 

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. 

1861Arizona 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). 

1863 Indicated PJM TOs Rehearing Request at 2– 

3, 4–6. 1864 Virginia and North Carolina Commissions 

Rehearing Request at 5–6. 1865See infra Concerns Regarding Cost Causation 

section. 

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

732. Dominion argues that Order No. 

1920 inappropriately treats all LongTerm 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

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

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

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

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-fitsall 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

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 LongTerm 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 longstanding cost causation principles and 

nothing in regional cost allocation 

principle (6) prevents transmission 

providers from having this 

flexibility.1863

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

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 


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1866Order 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.’’). 

1867Order No. 1920, 187 FERC ¶ 61,068 at PP 123, 

126, 722. 

1868See id. PP 719–720. 

1869 Id. PP 737, 822; see also id. P 1515 & n.3220. 

1870 Id. P 1474. 

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). 

1873 Dominion Rehearing Request at 30. 

1874Order No. 1920, 187 FERC ¶ 61,068 at P 1478. 

1875See 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.’’). 

1876See infra Concerns Regarding Cost Causation 

section. 

1877NRECA Rehearing Request at 53–55. 

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 LongTerm 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. 

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, forwardlooking, more comprehensive regional 

transmission planning required in Order 

No. 1920.1870

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

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). 

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

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

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 


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1878Order No. 1920, 187 FERC ¶ 61,068 at PP 85, 

112. 

1879 Id. P 270. 

1880See e.g., East Kentucky Rehearing Request at 

3. 

1881NRECA Rehearing Request at 55. 

1882Order No. 1000, 136 FERC ¶ 61,051 at P 657 

(emphasis added). 

1883See Arizona Commission Rehearing Request 

at 18–19; Ohio Commission Federal Advocate 

Rehearing Request at 14. 

1884See Dominion Rehearing Request at 29–31. 

1885See Idaho Commission Rehearing Request at 

3; NRECA Rehearing Request at 52–53. 

1886NRECA Rehearing Request at 53. 

1887Order 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. 

1889 Indicated PJM TOs Rehearing Request at 2– 

3, 4–6. 

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. 

746. Moreover, we reiterate that LongTerm 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

747. Consequently, and contrary to 

certain parties’ arguments,1880 these 

requirements will protect customers 

from unjust, unreasonable, and unduly 

discriminatory or preferential 

transmission rates. 

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. 

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. 

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 stateagreed-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 


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1890 Virginia and North Carolina Commissions 

Rehearing Request at 5–6. 

1891See infra Concerns Regarding Cost Causation 

section. 

1892Order No. 1920, 187 FERC ¶ 61,068 at PP 

1469, 1472–1473. 

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. 

1901NRECA 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). 

providers may propose ex ante LongTerm Regional Transmission Cost 

Allocation Methods that, for example, 

assign a portion of the costs of a LongTerm 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. 

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

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

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

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 


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1904 Id. at 56–57 (citing Order No. 1920, 187 FERC 

¶ 61,068 at P 1476 n.3150). 1905 Id. at 52. 1906Arizona Commission Rehearing Request at 

20–21. 1907 Id. at 20. 1908Ohio Consumers Rehearing Request at 9. 

1909 Virginia and North Carolina Commissions 

Rehearing Request at 3–4. 

1910West Virginia Commission Rehearing Request 

at 10; Wyoming Commission Rehearing Request at 

7. 

1911West Virginia Commission Rehearing Request 

at 10; Wyoming Commission Rehearing Request at 

7. 

1912West Virginia Commission Rehearing Request 

at 10; Wyoming Commission Rehearing Request at 

7–8. 

1913Wyoming Commission Rehearing Request at 

8. 

1914NRECA Rehearing Request at 55–56. 

1915Order No. 1920, 187 FERC ¶ 61,068 at P 1477. 1916 Id. (citation omitted). 1917See, e.g., id. P 1506 (citing ICC v. FERC I, 576 

F.3d at 477; ICC v. FERC III, 756 F.3d at 564). 1918 Id. P 1476 (quoting State Voluntary 

Agreements to Plan & Pay for Transmission 

Facilities, 175 FERC ¶ 61,225 at P 3). 

allocations methods reached under the 

State Agreement Process.1904

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

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

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 crosssubsidization 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 costcausation 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

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

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-agreedupon cost allocation methods for LongTerm 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. 

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. 

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 


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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. 

1921NRECA Rehearing Request at 52. 

1922See Order No. 1920, 187 FERC ¶ 61,068 at P 

1477. 

1923 Id. P 1305 & n.2786. 

1924Arizona Commission Rehearing Request at 

20; Ohio Consumers Rehearing Request at 9. 

1925Order 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). 

1926 Virginia and North Carolina Commissions 

Rehearing Request at 3–4. 

1927See Order No. 1920, 187 FERC ¶ 61,068 at 

1510. 

1928West Virginia Commission Rehearing Request 

at 10; Wyoming Commission Rehearing Request at 

7. 

1929See 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.’’). 

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

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. 

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

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 LongTerm 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

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

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 


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1930NOPR, 179 FERC ¶ 61,028 at PP 185, 326. 1931 Id. P 326. 1932 Id. 

1933 Id. P 327. 

1934Order No. 1920, 187 FERC ¶ 61,068 at P 1505. 

1935 Id. PP 1470, 1476–1477. 

1936 Id. P 1506. 

1937 Id. 

1938 Id. P 1507 (citing Order No. 1000, 136 FERC 

¶ 61,051 at PP 560, 624). 

1939NRECA Rehearing Request at 12–13. 

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 LongTerm 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

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 LongTerm 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

771. The Commission explained that 

the modified approach to the 

relationship of benefits used in LongTerm 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

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 


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1940 Id. 

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)). 

1942NOPR, 179 FERC ¶ 61,028 at PP 325–326. 

1943Order 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). 

1944Conn. Light & Power Co. v. Nuclear Regul. 

Comm’n, 673 F.2d at 533. 

1945Telesat Canada v. FCC, 999 F.3d 707, 713 

(D.C. Cir. 2021) (quotations omitted). 

1946Order No. 1920, 187 FERC ¶ 61,068 at PP 

1505–1506. 

1947Clean Energy Associations Rehearing Request 

at 30–32. 

1948 Id. at 31. 

1949 Id. at 32–33. 

1950 Dominion Rehearing Request at 26–27. 

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

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 passwordprotected 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

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

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

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

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 


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1951Order No. 1920, 187 FERC ¶ 61,068 at PP 

1475, 1506. See supra P 749. 

1952Order No. 1920, 187 FERC ¶ 61,068 at P 1305. 

1953See 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.’’). 

1954 Id. P 1521. 

1955 Id. P 1296. 

1956 Id. P 1305 (citations omitted). 

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)). 

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. 

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

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

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

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

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

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 LongTerm 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

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 


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1963 Id. at 31, 33–34. 1964 Designated Retail Regulators Rehearing 

Request at 39; Undersigned States Rehearing 

Request at 34. 1965Wyoming Commission Rehearing Request at 

8. 

1966 Industrial Customers Rehearing Request at 

21–23 (citing State Farm, 463 U.S. at 43). 

1967Order No. 1920, 187 FERC ¶ 61,068 at P 1521. 

1968 Id. P 1291. 

1969 Id. P 1521. 

1970For 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. 

1971Order 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. 

1973 Id. P 259. 

1974 Id. P 998. 

1975See 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). 

1976See supra The Overall Need for Reform 

section. 

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

786. Designated Retail Regulators and 

Undersigned States argue that any LongTerm 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

787. Wyoming Commission asserts 

that if a portion of the costs of a LongTerm 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

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

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

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

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-stamptype 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

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 Commissionjurisdictional rates to retail 

customers.1975

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 costeffective 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 


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1977Order No. 1920, 187 FERC ¶ 61,068 at P 1523. 

1978 Industrial Customers Rehearing Request at 23 

(citing State Farm, 463 U.S. at 43). 

1979State Farm, 463 U.S. at 34. 

1980See 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). 

1981Order No. 1920, 187 FERC ¶ 61,068 at PP 

1524, 1547. 

1982 Id. P 1547. 

1983 Id. (quoting 16 U.S.C. 824s(a)). 

1984 Industrial Customers Rehearing Request at 

24, 26; NARUC Rehearing Request at 5, 8, 10–11; 

Ohio Consumers Rehearing Request at 11–12. 

1985NARUC Rehearing Request at 9–11. 

1986Ohio Consumers Rehearing Request at 12. 

1987NARUC 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. 

1988Ohio Consumers Rehearing Request at 11–12. 

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. 

1991Arizona Commission Rehearing Request at 

17–19 (citing 5 U.S.C. 706(2)(A), (2)(C), (2)(D)). 

1992Order No. 1920, 187 FERC ¶ 61,068 at P 1547. 

1993 Id. (quoting 16 U.S.C. 824s(a)). 

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

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

2. Requests for Rehearing and 

Clarification 

795. Several parties request rehearing 

on the grounds that the Commission 

failed to conduct reasoned decisionmaking 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

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 LongTerm 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

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

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

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. 

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 


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1994New 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’’). 

1995Order No. 1920, 187 FERC ¶ 61,068 at PP 

1548, 1563–1564. 

1996NRECA Rehearing Request at 2. 

1997Order 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. 

1998Order No. 1920, 187 FERC ¶ 61,068 at P 1564. 

1999Order No. 1920, 187 FERC ¶ 61,068 at PP 

1565, 1569. 

2000 Id. P 1569. 

2001 Id. P 1570. 

2002 Id. P 1570. 

2003 Id. P 1570. 

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. 

2008P 1572. 

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. 

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

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

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

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

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 Commissionjurisdictional rates are just and 

reasonable.2003

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 


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2009 Id. 

2010 Id. P 1573 (citations omitted). 

2011 Id. 

2012 Id. P 1574. 

2013 Id. P 1574. 

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). 

2016 Id. P 1576 (citations omitted). 

2017 Id. P 1577. 

2018 Id. 

2019Advanced Energy Rehearing Request at 4; 

Competition Coalition Rehearing Request at 8. 

2020Competition Coalition Rehearing Request at 

59–60. 

2021Competition 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. 

2022Competition Coalition Rehearing Request at 

14; Industrial Customers Rehearing Request at 4–5. 

not unduly discriminatory or 

preferential.2009

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

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 inkind 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

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

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 LongTerm Regional Transmission 

Facilities.2016

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

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

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 decisionmaking.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 


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Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 97325 

2023 Designated Retail Regulators Rehearing 

Request at 7. 

2024Competition Coalition Rehearing Request at 

18. 

2025 Id. at 6, 11–19, 36–37; Industrial Customers 

Rehearing Request at 13–15. 

2026Competition Coalition Rehearing Request at 

12–13; Industrial Customers Rehearing Request at 

12–13. 

2027Competition Coalition Rehearing Request at 

13. 

2028 Id. at 13. 

2029 Id. at 13–14. 

2030 Id. at 9. 

2031Order No. 1920, 187 FERC ¶ 61,068 at P 1569. 

2032 Id. P 1572; see also id. P 109. 

2033 Id. P 1570. 

2034 Id. 

2035 Id. P 1571. 

2036 Id. P 1573, nn.3363–3365. 

2037 Id. PP 1573–1574, 1576. 

2038See 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). 

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

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

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

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 Commissionjurisdictional rates are just, reasonable, 

and not unduly discriminatory or 

preferential. 

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

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 costeffective. 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

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

821. The Commission next identified 

the lack of a requirement for 

transmission providers in each 

transmission planning region to 


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2042 Id. P 1573, nn.3363–3365. 

2043 Id. P 1574. 

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. 

2045See infra Right of First Refusal for RightSized Replacement Transmission Facilities Selected 

to Meet Long-Term Transmission Needs section. 

2046Competition 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). 

2047Competition 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. 

2049Order 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. 2051Order No. 1920, 187 FERC ¶ 61,068 at P 1705 

(citing Order No. 1000, 136 FERC ¶ 61,051 at P 257). 2052See 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. 

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 Commissionjurisdictional 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. 

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 LongTerm Transmission Needs.2045

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. 

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

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 rightsized 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 rightsized 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 costeffective potential transmission 

solutions proposed at the regional level, 

which could lead to unjust and 

unreasonable rates for Commissionjurisdictional 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

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 inkind 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 


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2054See infra Right of First Refusal for RightSized Replacement Transmission Facilities Selected 

to Meet Long-Term Transmission Needs section. 

2055Order No. 1920, 187 FERC ¶ 61,068 at PP 

1706–1707; see infra Right of First Refusal for RightSized Replacement Transmission Facilities Selected 

to Meet Long-Term Transmission Needs section. 

2056Order No. 1920, 187 FERC ¶ 61,068 at P 1704. 

2057See infra Right of First Refusal for RightSized Replacement Transmission Facilities Selected 

to Meet Long-Term Transmission Needs section. 

2058Order No. 1920, 187 FERC ¶ 61,068 at PP 

1706–1707. 

2059Competition Coalition Rehearing Request at 

36. 

2060Advanced 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. 

2062Advanced 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). 

2063Advanced 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). 

2065 Id. at 8 (citing 16 U.S.C. 824p(g)). 

2066 Id. at 5, 8. 

2067Competition Coalition Rehearing Request at 

7, 21–23. 

2068Undersigned States Rehearing Request at 36. 

2069See Advanced Energy Rehearing Request at 

4–12; Competition Coalition Rehearing Request at 7, 

20–40; Undersigned States Rehearing Request at 36. 

2070See supra Federal/State Division of Authority 

section. 

2071 577 U.S. at 278. 

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

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 inkind 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 rightsizing 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 rightsized 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 Commissionjurisdictional rates are just and 

reasonable. 

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

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

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

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 Commissionjurisdictional rates are just and 

reasonable.2070 As explained in EPSA, 

this jurisdiction extends to practices 

that ‘‘directly affect’’ such rates.2071 The 


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2072Order No. 1920, 187 FERC ¶ 61,068 at P 1707. 

2073S.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.’’). 

2075Order 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). 

2077See supra Major Questions Doctrine section. 

2078See West Virginia, 597 U.S. at 746. 

2079 Id. at 722–23. 

2080Advanced Energy Rehearing Request at 9–10. 

2081Competition Coalition Rehearing Request at 

34, 36. 

2082See 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. 

2083See supra Major Questions Doctrine section. 

2084See 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. 

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. 

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

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 Commissionjurisdictional service.2076

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

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

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 rightsized replacement transmission 

facilities. 

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

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 


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2086See 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). 

2087See supra Federal/State Division of Authority 

section; See also Order No. 1920, 187 FERC 

¶ 61,068 at P 271. 

2088We 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. 

2089Competition Coalition Rehearing Request at 

67–68 (citing Exec. Order No. 14,036, 3 CFR 100.1); 

Advanced Energy Rehearing Request at 10–11. 

2090Advanced Energy Rehearing Request at 10–11 

(citing Otter Tail v. U.S., 410 U.S. 366, 374 (1973)). 

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). 

2092Advanced Energy Rehearing Request at 10– 

11. 

2093See id. at 10 n.30. 

2094Competition Coalition Rehearing Request at 

24–29. 

2095 Id. at 61, 68–71. 

2096 Id. at 24–29 (arguing that such provisions 

were not based on requirements of the FPA or rights 

inherent in the FPA). 

federal right of first refusal for rightsized 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 rightsized 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. 

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 rightsizing 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

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. 

b. Commission Determination 

841. Order No. 1920’s conclusion that 

the federal right of first refusal for rightsized 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

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

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

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. 

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 


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97330 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

2097See id. at 32–40 (arguing that Order No. 1920 

departs from the approach of previous Commission 

orders seeking to curtail transmission provider selfinterest 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’’). 

2098See supra The Commission Demonstrated 

that the Replacement Rate is Just and Reasonable 

section. 

2099Order 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)). 

2103 Id. P 1627. 

2104 Id. 

2105 Id. 

2106 Id. 

2107 Id. P 1628. 

2108 Id. 

2109 Id. 

2110 Id. P 1648. 

2111Transmission Planning and Cost 

Management, Notice of Technical Conference, 

Docket No. AD22–8–000 (Apr. 21, 2022). 

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. 

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

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

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

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

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 


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2112NESCOE Rehearing Request at 26–31; Ohio 

Commission Federal Advocate Rehearing Request at 

21–24; Old Dominion Rehearing Request at 4, 5–9. 

2113Old 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. 

2116NESCOE 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. 

2121Ohio 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. 

2125 Industrial Customers Rehearing Request at 

29–31. 

2126 Id. at 33–34. 

2127 Id. at 38. 

2128PIOs 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). 

2131Order 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. 

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

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

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

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

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 leastcost 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

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 


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97332 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

2133NOPR, 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)). 

2134Order No. 1920, 187 FERC ¶ 61,068 at P 1629. 

2135 Id. P 1632. 2136See 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). 

2137See Order No. 1920, 187 FERC ¶ 61,068 at PP 

1648, 1737. 

2138We note, for example, the ongoing proceeding 

in Docket No. AD22–8–000 on Transmission 

Planning and Cost Management. 

2139SERTP 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. 2142 Id. at 24–25. 2143 Id. at 25. 2144 Id. at 25 (citations omitted). 2145 Id. at 24. 

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. 

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

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

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

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

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 


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2146See 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.’’). 

2147SERTP Sponsors Rehearing Request at 25. 

2148Order No. 1920, 187 FERC ¶ 61,068 at P 1677. 

2149 Id. 

2150 Id. P 1678 & n.3580. 

2151 Id. P 1678. 

2152 Id. P 1679. 

2153 Id. P 1681. 

2154 Id. 

2155 Id. 

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

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. 

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

864. The Commission further adopted 

the NOPR proposal to define ‘‘rightsizing’’ 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

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

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 rightsized replacement transmission facility 

as a potential solution to a Long-Term 

Transmission Need as part of LongTerm 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 costeffective 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 rightsized to more efficiently or costeffectively address a Long-Term 

Transmission Need(s).2155 Finally, the 

Commission required that, if a rightsized 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 


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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. 

2157 Id. PP 1677, 1683 & n.3584. 2158 Id. at P 1685. 2159Advanced Energy Rehearing Request at 14–15 

(citing Order No. 1920, 187 FERC ¶ 61,068 at P 

1678). 2160Competition 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)). 

2161Competition Coalition at 51–52 (citing Order 

No. 1000–A, 139 FERC ¶ 61,132 at P 426). 

2162 Id. at 52. 

2163Advanced 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). 

2164Advanced Energy Rehearing Request at 14 

(citing Order No. 1920, 187 FERC ¶ 61,068 at P 

1678). 

2165 Id. at 14–15. 

2166NESCOE Rehearing Request at 32–33. 

2167Competition 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). 

2169 Id. at 72. 

2170 Id. at 73–74. 

2171 Id. at 74. 

2172 Dominion Rehearing Request at 35. 

2173 Id. at 35–36. 

2174 Id. P 1679. 

replacement transmission facility must 

be considered for selection.2156

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

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

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 wellestablished ‘‘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

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 rightof-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-ofway since the Commission determined 

that issues surrounding rights-of-way is 

an issue for the authority granting the 

rights-of-way.2168

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 ‘‘costeffectively’’ 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

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

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 


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2175 Id. P 1702. 

2176 Id. P 1682. 

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). 

2178See 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. 

2179Order 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). 

2181 Id. P 1706. 

2182 Id. 

2183 Id. 

2184 Id. P 1703. 

2185 Id. P 1706. 

2186See id. P 1703. 

2187 Id. P 319. 

highlighted in Order No. 1920, a rightsized 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 inkind replacement transmission facility 

or another Long-Term Regional 

Transmission Facility.2176

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 rightsized 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. 

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 LongTerm 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 rightsized 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 costeffective 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 costeffective regional solutions that could 

encompass both replacements of aging 

transmission infrastructure and regional 

transmission solutions to address LongTerm 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

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 Commissionjurisdictional 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. 

877. We are unpersuaded by 

Advanced Energy’s, Competition 

Coalition’s, and NESCOE’s claims 

regarding the use of the term ‘‘rights-ofway’’ 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-ofway,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 


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2188 Id. P 1680. 

2189 Id. PP 1678, 1679. 

2190 Id. P 1680. 

2191Order 1000–A, 139 FERC ¶ 61,132 at P 427. 

2192 Id. 

2193Order No. 1920, 187 FERC ¶ 61,068 at P 1678. 

2194 Id. P 1678 n.3580. 

2195The 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. 

2196Order No. 1920, 187 FERC ¶ 61,068 at P 1702; 

see also supra Analysis under Section 206 section. 

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 LongTerm Transmission Needs. 

878. Moreover, we disagree that Order 

No. 1920’s inclusion of the term 

‘‘general route’’ in the definition of ‘‘inkind 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 rightsized replacement transmission facility 

may require changes to or expansions of 

rights-of-way to accommodate that rightsized 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 rightsized 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-ofway 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 rightsizing,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 rightsizing 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. 

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-ofway.’’ 2191 The Commission stated that 

‘‘[t]he issue is not whether the upgrade 

would be located in an existing right-ofway, 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. 

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 rightsizing reform. We sustain the definition 

of ‘‘right-sizing’’ to mean ‘‘the process of 

modifying a transmission provider’s inkind 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

881. We grant clarification to 

Dominion’s requests regarding the 200 

kV threshold for determining whether a 

transmission facility is eligible for rightsizing. 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 LongTerm 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 


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2197 Id. P 1704 (citing Order No. 1000, 136 FERC 

¶ 61,051 at P 313). 

2198 Id. P 1706. 

2199 Id. P 1705 (citing Order No. 1000, 136 FERC 

¶ 61,051 at P 319 (internal citation omitted)). 

2200Advanced 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. 

2201Advanced 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). 

2202 Id. at 10–11; see also Competition Coalition 

Rehearing Request at 67–68. 

2203Advanced Energy Rehearing Request at 13– 

14; Competition Coalition Rehearing Request at 69– 

71; PIOs Rehearing Request at 51–54. 

2204Competition Coalition Rehearing Request at 

69–70. 

2205Order No. 1000, 136 FERC ¶ 61,051 at PP 253, 

256, 313. 

2206 Id. P 257. 2207Order No. 1920, 187 FERC ¶ 61,068 at P 1682. 2208 Id. P 1706. 2209 Id. PP 1574, 1706. 2210Although we find that the Commission has 

supported the inclusion of the right-sizing reforms 

Continued 

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 rightsized replacement transmission 

facilities does not undermine the 

consideration of more efficient or costeffective 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 costeffective regional transmission solution 

to address Long-Term Transmission 

Needs (otherwise it would not be 

selected).2198

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

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 rightsized 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

885. Advanced Energy further argues 

that the Commission’s provision of a 

federal right of first refusal for rightsized replacement transmission 

facilities is inconsistent with the general 

federal policy against anticompetitive 

practices.2202

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

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

888. In Order No. 1920, the 

Commission found that that a rightsized 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 LongTerm 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 costeffective regional transmission solution 

to address Long-Term Transmission 

Needs (otherwise, they would not be 

selected).2208

889. We recognize that requiring the 

federal right of first refusal for rightsized 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 rightsized 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


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as a component of a just and reasonable 

replacement rate, we consider these reforms as an 

enhancement to, rather than essential to, the LongTerm 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. 

2211Order No. 1920, 187 FERC ¶ 61,068 at P 1703. 

2212 Id. P 1706. 

2213 Id. P 85. 2214 Id. P 1706. 

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 rightsized 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. 

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 LongTerm 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 costeffective 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. 

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. 

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 rightsizing 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 


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2215 Id. P 1681. 

2216Order No. 1920, 187 FERC ¶ 61,068 at P 1736. 

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. 

2219 Indicated PJM TOs Rehearing Request at 8– 

9. 

2220 Id. at 9 (citing FERC, CEII General NonDisclosure 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. 

2222Order No. 890, 118 FERC ¶ 61,119 at P 460. 

2223Tri-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 nondisclosure 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). 

2224Order No. 1920, 187 FERC ¶ 61,068 at P 1751. 

selection of more efficient or costeffective 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 rightsized 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. 

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

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

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 NonDisclosure 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 NonDisclosure 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

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

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 LongTerm Transmission Needs.2224

Additionally, the Commission required 

transmission providers in neighboring 

transmission planning regions to revise 

their interregional transmission 

coordination procedures (and regional 


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2225 Id. P 1752. 

2226Order No. 1920, 187 FERC ¶ 61,068 at P 1753. 

2227 Grid United June 12, 2024 Comments at 1– 

2. 

2228As 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. 

2229Order No. 1920, 187 FERC ¶ 61,068 at PP 

1740–1758. 

2230 Id. P 1754. 

2231See Supplemental Notice of Staff-Led 

Workshop, Establishing Interregional Transfer 

Capability Transmission Planning and Cost 

Allocation Requirements, Docket No. AD23–3–000 

(Nov. 30, 2022). 

2232See 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.’’). 

2233Order 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. 

2235 Id. P 1770. 

2236 Id. P 1771 (citing Order No. 888, FERC Stats. 

& Regs. ¶ 31,036 at 31,760–63). 

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). 

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

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

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

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. 

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 oneyear deadline to commence the first 

Long-Term Regional Transmission 

Planning cycle.2234

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

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

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 


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2239 Id. P 1773. 

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). 

2242NARUC Rehearing Request at 20–21. 

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. 

2246PJM Rehearing Request at 10–11, 41; see also 

Dairyland Rehearing Request at 7. 

2247PJM Rehearing Request at 11–14, 42. 

2248APPA Rehearing Request at 6–7; TAPS 

Rehearing Request at 14–19. 

2249APPA Rehearing Request at 7. 

2250TAPS Rehearing Request at 18–19. 

2251Large Public Power Rehearing Request at 23– 

24. 

2252SPP Rehearing Request at 2–4. 

2253WIRES Rehearing Request at 5–6, 16–18. 

2254WIRES Rehearing Request at 16–18. 

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. 

2256Order No. 1920, 187 FERC ¶ 61,068 at P 1768. 

2257 Id. P 1770. 

specific tariff sheets already on file with 

the Commission.2239

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

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 LongTerm Regional Transmission 

Planning.2247

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

910. In its rehearing request, Large 

Public Power argues that the 

Commission should clarify that nonpublic 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

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

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

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

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 


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2258 Id. P 1768. 

2259 Id. P 1772 (citing Order No. 890, 118 FERC 

¶ 61,119 at P 160). 

2260 Dairyland Rehearing Request at 3, 6. 

2261Order 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. 

2262Order No. 1920, 187 FERC ¶ 61,068 at P 1772. 

2263See FCC v. Fox Television Stations, Inc., 556 

U.S. at 515. 

2264PJM Rehearing Request at 11–12; Dairyland 

Rehearing Request at 7. 

2265For 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. 

2266Order No. 1920, 187 FERC ¶ 61,068 at P 237. 

2267PJM 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). 

2268Order 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. 

2270See Order No. 1920, 187 FERC ¶ 61,068 at PP 

87, 89. 

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. 

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. 

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

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. 

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

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 LongTerm Transmission Needs and therefore 

to ensure just and reasonable rates.2270

The need for regional transmission 

planning processes that meet the 


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2271See, 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). 

2272N.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). 

2273N.Y. State Elec. & Gas Corp., 82 FERC at 

61,822 n.4. 2274Order No. 1920, 187 FERC ¶ 61,068 at P 1772. 2275We 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. 2276See., 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. 

2277Order No. 1920, 187 FERC ¶ 61,068 at P 1771 

(citing Order No. 888, FERC Stats. & Regs. ¶ 31,036 

at 31,760–63). 

2278Order No. 888, FERC Stats. & Regs. ¶ 31,036 

at 31,760–63. 

2279Order No. 1920, 187 FERC ¶ 61,068 at P 1072. 

2280Order No. 1920, 187 FERC ¶ 61,068 at P 1768. 

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. 

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. 

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. 

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

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 nonpublic 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

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. 

926. We note that Versant Power’s 

rehearing request has been 


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2281See 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. 

2282Order 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.’’). 

2283Arizona 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). 

2284Arizona Commission Rehearing Request at 

18–19. 

2285Arizona Commission Rehearing Request at 

18–19. Id. 

2286NRECA Rehearing Request at 6. 

2287 Id. at 19. 

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. 

2291 16 U.S.C. 825l(a) (emphasis added). 

2292A 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. 

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 caseby-case basis from any entity that 

believes it meets the criteria for such 

waiver. 

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-andcomment 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 noticeand-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

928. NRECA alleges that Order No. 

1920 violated the APA’s notice-andcomment 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

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

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

931. In any event, these arguments 

also lack merit. As discussed throughout 

this order, the individual provisions of 


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2293See 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. 

2294 44 U.S.C. 3501–3521. 

2295See 5 CFR 1320.12 (2024). 

2296Order No. 1920, 187 FERC ¶ 61,068 at P 409. 

2297 Id. P 559. 

2298 Id. P 528. 

2299 Id. P 533. 

2300 Id. P 954. 

2301Order No. 1920, 187 FERC ¶ 61,068 at P 1368. 

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-andcomment requirements.2293 Thus, given 

that the constituent components of 

Order No. 1920 satisfy the APA’s noticeand-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. 

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. 

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 LongTerm 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 LongTerm 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. 

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). 

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 federallyrecognized 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 LongTerm 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 LongTerm Scenarios. 

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 passwordprotected 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. 

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 


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97346 Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 

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. 2303The 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. 

transmission providers’ obligations with 

respect to transmission planning and 

cost allocation, transmission providers 

shall consult with Relevant State 

Entities (1) prior to amending the LongTerm 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. 

939. Public Reporting Burden: The 

estimated burden and cost for the 

requirements contained in this order on 

rehearing follow. 

CHANGES DUE TO ORDER ON REHEARING IN DOCKET NO. RM21–17–001 2302

A. 

Area of modification 

B. 

Annual number of 

respondents 

C. 

Total annual 

estimated 

number of 

responses 

D. 

Average 

burden hours & cost 2303

per response 

E. 

Total estimated burden hours 

& total estimated cost 

(column C × column D) 

FERC–917, Electric Transmission Facilities (OMB Control No. 1902–0233) 

Establish a six-month time period during which 

transmission providers must, among other 

things, provide a forum for negotiation that 

enables 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.

48 transmission providers with 

OATTs.

48 One Time: 390 hours; $36,307 

Ongoing: 39 hours per year; 

$3,631 per year.

One Time: 18,720 hours; 

$1,742,734. 

Ongoing: 1,872 hours per year; 

$174,274 per year. 

Participate in Long-Term Regional Transmission Planning, which includes creating 

and updating datasets, developing LongTerm Scenarios, evaluating the benefits of 

Long-Term Regional Transmission Facilities, 

and establishing criteria in consultation with 

Relevant State Entities and stakeholders to 

select Long-Term Regional Transmission Facilities in the regional transmission plan for 

purposes of cost allocation.

48 transmission providers with 

OATTs.

77 transmission providers without OATTs.

48 

77 

One Time: 0 hours; $0 .............

Ongoing: 4,995 hours per year; 

$465,010 per year.

One Time: 0 hours; $0 .............

Ongoing: 202 hours per year; 

$18,805 per year.

One Time: 0 hours; $0. 

Ongoing: 239,760 hours per 

year; $22,320,457 per year. 

One Time: 0 hours; $0. 

Ongoing: 15,554 hours per 

year; $1,448,000 per year. 

Total new burden for FERC 917 (due to Docket 

No. RM21–17–001).

48 transmission providers with 

OATTs.

48 One Time: 1,113 hours; 

$103,614.

Ongoing: 5,329 hours per year; 

$496,103 per year.

One Time: 53,424 hours; 

$4,973,495 

Ongoing: 255,792 hours per 

year; $23,812,956 per year 

77 transmission providers without OATTs.77 One Time: 20 hours; $1,862 ....

Ongoing: 262 hours per year; 

$24,391 per year.

One Time: 1,540 hours; 

$143,366. 

Ongoing: 20,174 hours 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 passwordprotected 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. 


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Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 97347 

2304Reguls. Implementing the Nat’l Env’l Pol’y 

Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), 

FERC Stats. & Regs. ¶ 30,783 (1987) (crossreferenced at 41 FERC ¶ 61,284). 

2305 18 CFR 380.4(a)(15). 

2306 5 U.S.C. 601–612. 

2307 13 CFR 121.201. 

2308The 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). 

2309Order No. 1920, 187 FERC ¶ 61,068 at P 1788. 

2310See id. 

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 

(DataClearance@ferc.gov) 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: oira_submission@

omb.eop.gov. 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. 

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

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. 

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 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. Email the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

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. 


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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 Advocate .............................. Public Utilities Commission of Ohio’s 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. 


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Federal Register / Vol. 89, No. 235 / Friday, December 6, 2024 / Rules and Regulations 97349 

Abbreviation Rehearing party(ies) 

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 Commissioners ................................... Riley Allen (Commissioner, State of 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 Commissions ..................... Virginia State Corporation Commission; 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 

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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 LongTerm 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 costeffectively 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 overbuilding 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 


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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 


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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)). 

3The specific changes which I support and to 

which I concur are described in the Appendix to 

this statement. 

4Bldg. 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). 

5Bldg. 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). 

6See Appendix at P 1. 

7 Id. P 2. 

8 Id. at P 7. 

9 Id. P 4. 

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 LongTerm 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 costeffective transmission solutions to LongTerm 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

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. 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

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

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

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


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10 Id. PP 3, 8–11. 

11 Id. P 6. 

12 Id. P 10. 

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, multidriver 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

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 smallbusiness consumers already struggling 

to pay their monthly power bills. 

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

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’ agreedupon 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 


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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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