Recent Developments in FERC-Jurisdictional Transmission Planning: Orders No. 1920 and 1977

On May 13, 2024, the Federal Energy Regulatory Commission (the “Commission” or “FERC”) issued two Orders which seek to address shortfalls in existing transmission planning: Order Nos. 1920¹ and 1977.² In this Legal Update, we contextualize the orders and provide insight into the likely effect that these Orders will have on the transmission development landscape.

Existing Landscape

In 2011, FERC issued Order No. 1000, which outlined a mandatory regional transmission planning process that takes into account seven planning principles: coordination, openness, transparency, information exchange, comparability, dispute resolution, and economic planning studies.³ It also required that each transmission planning region develop ex ante cost allocation methods.

However, the Commission did not impose a firm obligation to build or obtain commitments to build transmission facilities selected in any such regional transmission plan and did not curtail the use of local transmission planning processes. As a result, nearly all Commission-jurisdictional transmission built since Order No. 1000’s implementation has been proposed, designed, constructed, and funded through generator interconnection processes and local transmission planning processes that shift costs to merchant generators in the short term, and electric consumers in the long term.

In the early 2020s, economies of scale in the production of wind turbines, solar modules, and battery storage units hit tipping points as projections for future electricity demand surged and state and federal subsidies for renewable generation took effect. This led to fierce competition between generators for a dwindling supply of economically feasible interconnection points. In order to probe the transmission grid for a sound point of interconnection, some generators would place multiple speculative requests for interconnection, go through the expensive multi-round study process, and withdraw projects from the interconnection queue where interconnection expenses caused a project to be economically infeasible. Every time a generator dropped its request to connect at a particular point, this would have a cascading effect on the studies of other, nearby points of interconnection undertaken by other prospective generators. Over time, the interconnection process became increasingly longer, more expensive, and less certain. While these generator interconnection applications and studies piled up, transmitting utilities that control the interconnection process experienced years of delays in which many hundreds of pending projects were simply not studied and were effectively afforded no interconnection process rights,⁴ with thousands of generator interconnection requests remaining backlogged, many for years.⁵

In an effort to reverse this negative feedback loop, FERC issued Order No. 2023 on July 28, 2023.⁶ Among other things, Order No. 2023 requires transmission operators to study interconnection requests and allocate costs for transmission buildouts in clusters rather than on a “serial” piecemeal basis and significantly increases several kinds of sunk costs for generators that drop out of the interconnection process after the initial study, disincentivizing speculative interconnection requests. The first cluster studies are expected to take place in mid- to late-2024.

Order No. 1920: Long-Term Regional Transmission Planning

If Order No. 2023 is intended to improve the interconnection process that has resulted (and will continue to result) in piecemeal transmission buildouts, Order No. 1920 is intended to address deficiencies in the Order No. 1000 regional planning process. Rather than amending the Order No. 1000 planning process, however, FERC is requiring a new, additional planning process (“Long-Term Regional Transmission Planning”), which will mirror the Order No. 1000 planning process in many respects but will be focused on, among other things, long-term changes projected in the supply-side resource mix and in demand-side usage patterns.

In Order No. 1920, in addition to laying out guidelines for the development of different substantive criteria for the Long-Term Regional Transmission Planning process from those in the existing Order No. 1000 process, the Commission seeks in various ways to make it more likely that transmission projects are selected and built. Obligations related to methodological transparency, opportunities for stakeholder involvement, and timelines for selection are defined in more detail in Order No. 1920 than they are in Order No. 1000. However, the primary causes of the underbuilding of regional facilities (e.g., regulatory difficulties of multi-jurisdictional projects, misaligned incentives of incumbent transmission owners, and risk asymmetry between incumbent transmission providers and competitive transmission developers) will likely persist. As Order No. 1920 acknowledges, “[T]his final rule does not require . . . the selection or construction of any specific transmission facilities” nor does it “entitle the transmission developer of a selected Long-Term Regional Transmission Facility to site or construct that transmission facility.”⁷

A high-level summary of the Order is below, followed by a discussion of additional considerations that will add uncertainty during its implementation.

Long-Term Regional Transmission Planning

Under Order No. 1920, each FERC-jurisdictional transmission provider must engage in a cycle of Long-Term Regional Transmission Planning at least every five years. Each cycle is expected to unfold in four stages: (1) development of long-term projections for power supply and demand (“Long-Term Scenarios”), (2) evaluation of benefits certain proposed regional transmission facilities could provide, (3) selection of those transmission facilities, and (4) allocation of costs for selected transmission facilities. Each step has robust process requirements, including stakeholder involvement activities, but gives transmission providers broad flexibility in establishing criteria and making substantive determinations.

1. Development of Long-Term Scenarios

Under Order No. 1920, transmission providers must create at least three Long-Term Scenarios representing a diverse but reasonable range of probable future outcomes over a minimum 20-year planning horizon. Each scenario must:

• Incorporate assumptions derived from timely data inputs developed using best practices and diverse and expert perspectives after providing stakeholders a meaningful opportunity to give input on how the scenarios will be developed. Interested parties must have the right to challenge data inputs via a dispute resolution mechanism developed by the transmission provider;
• Apply at least one sensitivity (or “stress test”) to account for uncertain operational outcomes during multiple concurrent and sustained generation and/or transmission outages due to an extreme weather event across a wide area;
• Take into account publicly disclosed factors in at least the following seven categories:

(1) Laws and regulations affecting resource mix and demand;

(2) Laws and regulations on decarbonization or electrification;

(3) State-approved integrated resource plans and load-serving entity supply obligations;

(4) Trends in fuel costs and the availability of technologies related to electric generation and storage, and to building and transportation electrification;

(5) Resource retirements;

(6) Interconnection requests and withdrawals; and

(7) Utility, corporate, and governmental commitments and/or policy goals that affect long-term transmission needs.

2. Evaluation of Benefits

Each transmission provider must amend its tariff to give a general description of how it will measure benefits of proposed transmission facilities against each Long-Term Scenario over a 20-year time frame beginning with the in-service date. The description need not propose a rigid formula but must be sufficient to enable stakeholders to “understand the manner by which transmission providers will measure,” at minimum, these seven benefits:

(1) Reduced net costs due to avoided or delayed transmission investment otherwise required to address reliability needs or replace aging transmission facilities;

(2) Reduced net costs related to resource adequacy benefits (demonstrated either by holding load loss probability constant and measuring system-wide planning reserve margin or by holding the reserve margin constant and measuring load loss probability);

(3) Savings in fuel and other variable operating costs of power generation, including savings realized as a result of lower-cost suppliers setting market clearing prices;

(4) Reduced total energy necessary to meet demand stemming from reduced line losses;

(5) Reduced production costs resulting from avoided congestion during transmission outages;

(6) Reduced production costs and reduced loss of load during extreme weather events and unexpected system conditions; and

(7) Reduced generation capacity investment needed to meet peak load.

The determination of benefits is separate from the cost-allocation process discussed below.

3. Selection of Transmission Facilities

Each transmission provider must develop and include in its tariff ex ante cost-benefit criteria used for selecting projects in good faith consultation with (but not requiring the consent of) the provider’s state energy regulatory agencies and siting authorities. As with benefit evaluation, the criteria can be qualitative and need not be rigidly formulaic. Transmission providers can choose between portfolio, facility-by-facility, and hybrid approaches to evaluating potential projects for selection and must provide a process whereby both states and interconnection customers have an opportunity to voluntarily fund all or a portion of a long-term transmission facility in order to cause the cost-benefit analysis employed by the transmission provider to come out in favor of selection.

In its compliance filing, each transmission provider must identify a deadline, no later than three years after the start of its planning cycle, when it will determine whether to select identified facilities. The deadline is soft: The transmission provider may select additional facilities after that point in time (including if an interconnection customer or state agency opts to voluntarily fund a facility in whole or in part).

While transmission providers must defend their selections in sufficient detail to allow stakeholders to understand selections, transmission providers are not required to actually select a facility even where a particular facility meets the transmission provider’s selection criteria in its tariff.

4. Cost Allocation

Each transmission provider must revise its tariff to include one or more ex ante long-term regional transmission cost allocation methods that apply to selected long-term facilities; however, the transmission provider may opt to include a process by which state energy regulatory agencies and siting authorities in the provider’s footprint can reach an agreement to preclude the application of the provider’s ex ante cost allocation method. The engagement period must conclude no later than six months after selection of facilities. If state agencies and siting authorities cannot reach consensus, the ex ante method proposed in the transmission provider’s tariff serves as the backstop cost allocation method.

While the Commission requires each transmission provider to include a cost allocation method in its tariff, it expressly declines to require transmission providers to identify the benefits they will use to allocate costs and does not set a time frame over which benefits must be considered for purposes of cost allocation. This suggests that each transmission provider will be provided with significant flexibility to implement ad hoc cost allocation methods, so long as it can defend those methods after the fact in cost allocation compliance filings.

Unless state agencies and siting authorities reach an agreement on cost allocation with respect to a selected facility, the compliance filing must show that cost allocation meets the following criteria, which are duplicative (but not exhaustive) of criteria required under the Order No. 1000 transmission planning process:

(1) Parties that receive no benefit from a transmission facility or portfolio must not be involuntarily allocated any of the costs of that facility or portfolio;

(2) If a cost/benefit ratio threshold is adopted, it cannot exceed 1.25:1;

(3) Costs must be allocated solely within a transmission planning region unless another entity outside the region consents to assume a portion of the costs; and

(4) The method for determining benefits and beneficiaries must be transparent.

Whether or not the cost allocation method is by consensus of state regulatory agencies and siting authorities, the allocation method must comply with the cost causation principle and other legal standards, meaning that cost allocation must be at least roughly commensurate with estimated benefits.

Other Order No. 1920 Developments

Order No. 1920 also addresses some matters outside of the core four-step Long-Term Regional Transmission Planning process discussed above:

• “Right-Sizing” Replacement Facilities: As part of each long-term planning cycle, transmission providers must evaluate whether transmission facilities operating above a certain identified threshold (which can be no greater than 200 kV) can be more effectively “right-sized” rather than replaced at the same voltage rating. Incumbent transmission providers will continue to have a right of first refusal to undertake “right-sizing.”
• Grid-Enhancing Technologies: In both the Long-Term Regional Transmission Planning and in existing Order No. 1000 planning, transmission providers must consider dynamic line ratings, advanced power flow control devices, advanced conductors, and transmission switching for each new regional transmission facility or each upgrade to existing transmission facilities.
• Network Upgrades in Regional Planning: As part of their existing Order No. 1000 planning processes, the Commission will require transmission providers to evaluate for selection, using both voltage and cost criteria, regional transmission facilities that address certain interconnection-related transmission needs identified in two or more interconnection processes in the last five years where (1) the network upgrade in question has an estimated cost of at least $30 million and a voltage of at least 200 kV and (2) there is no existing plan to address that network upgrade.
• Transparency In Local Transmission Planning: Transmission providers must revise their existing tariffs to increase stakeholder involvement and enhance transparency in their local transmission planning processes, including (1) the criteria, models, and assumptions used; (2) the local transmission needs identified; and (3) the potential local or regional transmission facilities that they will evaluate to address local transmission needs.
• Interregional Coordination: Transmission providers are required to revise existing interregional transmission coordination procedures to reflect long-term planning reforms adopted in Order No. 1920.

Implementation Challenges

As noted above, the Commission expressly stated that projects need not be selected even if they meet ex ante selection criteria and need not be built even if selected. In addition to the limitations acknowledged by Order No. 1920 itself, there are a number of extrinsic timing issues and other challenges with respect to its implementation which could delay or hinder its effectiveness.

Order No. 1920 requires transmission providers to provide compliance filings, including proposed tariff revisions, within 10 months (i.e., by mid-March 2025).⁸ Each must then begin its first Long-Term Regional Transmission Planning cycle within one year following the compliance filing deadline unless it can provide adequate support for a later date by explaining how that date is necessary to align with existing planning processes. However, there will inevitably be rehearing requests, and it is not uncommon for FERC to extend the deadline for compliance filings in response to these rehearing requests, particularly if the Commission makes material changes. Furthermore, there will almost certainly be appellate litigation challenging FERC’s authority to issue Order No. 1920 and intermediate review by the DC Circuit might not be Order No. 1920’s last stop before effectiveness.

Every compliance filing will be the subject of full notice-and-comment proceedings, finalization, and rehearing requests, and these requests may cause the Commission to further extend the deadline for commencement of the first planning cycle for some or all transmission providers. The submission of protests and motions for substantive relief can be expected to produce answering filings, and it is foreseeable that multiple rounds of pleadings may be submitted, cumulatively consuming months of time before FERC can issue orders accepting the compliance filings. This makes it unlikely that the first transmission planning cycles will begin before late 2026 or early 2027. Selection determinations will not be required until three years after the cycle commences. After that, any selected transmission facilities will have to obtain necessary local, state, and federal permits and authorizations before beginning construction. In short, Long-Term Regional Transmission Planning is unlikely to directly result in construction of any transmission facility before 2030.

Furthermore, with cloture filed on three commissioner nominations as of June 5, 2024, it appears that Commissioner Allison Clements, a supporter of Order No. 1920, will exit the Commission on or soon after June 30, 2024. Given the strong language in a dissent to Order No. 1920, it is safe to assume that the dissenting commissioner would not vote to uphold it on rehearing and may lead an effort to weaken or even replace it with a new order if there is support among new commissioners to do so. And in the meantime, if FERC dips below its statutory three-commissioner quorum, no final action can be taken.

Order No. 1977: FERC Backstop Authority

Simultaneous with the release of Order No. 1920, FERC issued Order No. 1977,⁹ which is the latest step in FERC’s star-crossed effort to deploy the “backstop” electric transmission siting authority first conferred on FERC under the Energy Policy Act of 2005. FERC’s transmission siting authority is limited to certain transmission routes designated by the Department of Energy (“DOE”) as “National Interest Electric Transmission Corridors”. Days before the release of Order No. 1977, DOE issued a list of 10 designated corridors¹⁰ scattered about the United States and ranging in size from a few miles to several hundred miles each. Order No. 1977 modifies existing standards for FERC’s approval of permits for the construction or modification of electric transmission facilities in DOE-designated corridors as well as preconditions to the use of eminent domain authority.

Implementation Challenges

DOE’s authority to designate corridors, and FERC’s authority to then take action to confer federal transmission rights-of-way and allow project sponsors to exercise eminent domain authority, were both rejected by appellate courts over a decade ago.¹¹ As a result, FERC has never once deployed the authority provided by legislation that is almost 19 years old. While the 2021 Infrastructure Investment and Jobs Act revived this authority, there are a number of challenges that could hinder the effectiveness of its exercise.

DOE’s corridor designation is not effective unless and until the state siting authority has denied an application, failed to make any determination at all within a year, or imposed conditions that are economically or operationally insurmountable. Furthermore, as DOE’s release acknowledges, extensive environmental, permitting, and related steps will also be required prior to the corridor designations becoming effective. Also, the Commission declined to adopt a proposed rule that would allow applicants to pre-file for siting and eminent domain authority while they await a decision from state siting authorities, and therefore state and local siting authorities will retain significant leverage to delay construction of transmission projects notwithstanding FERC’s backstop authority.

Between conditions relating to state action, inevitable rehearing requests and appeals of Order No. 1977, and compulsory permitting actions and statutory requirements that every contested exercise of eminent domain authority proceed in a federal or state court subject to judicial valuation proceedings,¹² we question whether final FERC backstop authority will be conferred on any project until 2027 at the earliest.

Conclusion

It is clear that Order No. 1000 did not accomplish its goal of developing efficient and cost-effective regional transmission planning. Orders No. 1920 and 1977 seek explicitly to remedy the deficiencies in Order No. 1000 that caused it to fall short of that goal. Whether they are able to do so will depend in large part on how these Orders are implemented and perhaps in even larger part on how the fragile process is affected by intervening administrative, judicial, and political processes.

Mayer Brown will continue to monitor the implementation of both Orders, as well as Order No. 2023.

¹ Building for the Future Through Electric Regional Transmission Planning and Cost Allocation, Order No. 1920, Docket No. RM21-17-000; 187 FERC ¶ 61,068 (May 13, 2024) (hereinafter, “Order No. 1920”).

² Applications for Permits to Site Interstate Electric Transmission Facilities, Order No. 1977, Docket No. RM22-7-000; 187 FERC ¶ 61,069 (May 13, 2024) (hereinafter, “Order No. 1977”).

³ Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, Docket No. RM10-23-000; 136 FERC ¶ 61,051 (July 21, 2011); order on reh’g, Order No. 1000-A, Docket No. RM10-23-001; 139 FERC ¶ 61,132 (May 17, 2012); order on reh’g and clarification, Order No. 1000-B, Docket No. RM10-23-002; 141 FERC ¶ 61,044 (October 18, 2012) (hereinafter, collectively “Order No. 1000”).

⁴ See gen’lly, PJM Interconnection, L.L.C., Tariff Revisions for Interconnection Process Reform, Docket No. ER22-2110 (filed June 14, 2022).

⁵ See, e.g., PJM Interconnection, L.L.C., Docket No. ER19-1958-003, Informational Report on Interconnection Study Performance Metrics (filed February 14, 2024).

⁶ Improvements to Generator Interconnection Procedures and Agreements, Order No. 2023, Docket No. RM22-14-000; 184 FERC ¶ 61,054 (July 28, 2023) (hereinafter, “Order No. 2023”).

⁷ Order No. 1920 at ¶¶ 266, 917.

⁸ The tariff revision process can be intricate and is far from ministerial. In some markets (such as PJM), extensive stakeholder consultation processes are required. In ISO New England, the market participants may act independently of ISO New England itself and, in the event of certain disputes, may propose alternative tariff provisions. We would not be surprised if the tariff drafting process takes longer than FERC expects and proceeds disuniformly.

⁹ FERC Docket No. RM22-7, citing 16 U.S.C. § 824p.

¹⁰ All of the corridors are, and must be, on the interstate power grid. Purely intrastate corridors are not authorized by the legislation, which is inapplicable in the ERCOT area of Texas, Alaska, Hawaii, and U.S. insular jurisdictions.

¹¹ See Cal. Wilderness Coalition v. U.S. Dept. of Energy, 631 F.3d 1072 (9th Cir. 2011); Piedmont Envtl. Council v. FERC, 558 F.3d 304 (4th Cir. 2009).

¹² 16 U.S.C. §§ 824p (e) and (f).