On November 21, 2024, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 1920-A1 addressing requests for rehearing and clarification of FERC’s landmark final rule on transmission planning and cost allocation issued in May 2024. While the Commission largely affirmed the final rule, the order grants rehearing of some of the more controversial aspects of Order No. 1920.
The most notable shift in Order No. 1920-A is the elevation of the role of state regulators in long-term transmission planning and cost allocation. The notice of proposed rulemaking (NOPR) that preceded Order No. 1920 proposed to require transmission owners to obtain approval from state regulators for aspects of their long-term transmission planning and cost allocation processes, including requiring transmission providers to obtain the agreement of state regulators—referred to as Relevant State Entities—on the cost allocation method for long-term regional transmission facilities. In Order No. 1920, however, the Commission declined to grant Relevant State Entities control over such decisions. Due to this and other shifts made by the Commission in Order No. 1920, the final rule was approved by a party-line vote, with the lone Republican commissioner, Commissioner Christie, issuing a lengthy dissent criticizing the rule for diminishing the role of state regulators in the long-term regional planning and cost allocation process and for favoring the development of renewable and zero-emission resources at the expense of customers.
In Order No. 1920-A, the Commission partially reversed course by mandating an expanded role for Relevant State Entities in the long-term regional planning and cost allocation processes. Among other things, Order No. 1920-A requires transmission providers to:
- include in their compliance filing any cost allocation proposal agreed to by Relevant State Entities in a region.
- consult with Relevant State Entities prior to making any future changes to their cost allocation methodologies.
- consider the input of Relevant State Entities when conducting the long-term regional planning process, including considering the views of such entities regarding how to account for the impact of state public policies on transmission needs.
- provide greater transparency into the benefits derived by each state within the region from a given transmission facility.
Collectively, the result of these changes is that all commissioners participating in the decision-making process2 voted to approve Order No. 1920. Commissioner Christie, in particular, issued a concurrence praising the other commissioners for “their willingness to negotiate in good faith and ultimately agree to” changes that “go a long way towards restoring the state role to what the NOPR promised.” The fact that Order No. 1920-A was approved by both Democrats and Republicans is likely to reduce the incentive of future commissions to seek to undermine the long-term regional transmission planning and cost allocation reforms adopted by the Commission.
The following sections provide an overview of the more notable changes and clarifications made by the Commission in Order No. 1920-A. For a comprehensive overview of Order No. 1920, see the presentation given by Akin’s energy regulatory team.
Long-Term Regional Transmission Planning
The central reform of Order No. 1920 was to require transmission providers to participate in a long-term regional transmission planning process that evaluates transmission needs over a long-term planning horizon of 20 years or more. The long-term regional transmission planning process must evaluate transmission needs using a “plausible and diverse” set of at least three distinct long-term scenarios that consider a minimum of seven factors identified by FERC as giving rise to long-term transmission needs:
- federal, tribal, state and local laws affecting the resource mix and demand;
- federal, tribal, state and local laws and regulations on decarbonization and electrification;
- state-approved integrated resource plans and expected supply obligations for load-serving entities;
- trends in fuel costs and in cost, performance and availability of generation, storage and building and transportation electrification technologies;
- resource retirements;
- generator interconnection requests and withdrawals;
- utility and corporate commitments and federal, tribal, state and local policy goals that affect long-term transmission needs.
Order No. 1920 also required transmission providers to adopt a process for identifying and evaluating long-term regional transmission facilities for selection in the planning process for purposes of cost allocation. As part of the evaluation process, transmission providers were required to consider a minimum set of seven benefits identified by FERC:
- avoided or deferred reliability transmission facilities and aging infrastructure replacement;
- loss of load probability or reduced planning reserve margin;
- production cost savings;
- reduced transmission energy losses;
- reduced congestion due to transmission outages;
- mitigation of extreme weather events and unexpected system conditions;
- capacity cost benefits from reduced peak energy losses.
In adopting Order No. 1920, the Commission explained that the long-term regional transmission planning process was not intended to replace the existing regional planning processes focused on reliability and economic transmission needs that had been adopted to comply with FERC Order No. 1000.3 Order No. 1920 also did not alter the requirement adopted in Order No. 1000 that transmission providers consider public policy requirements in the regional planning process, but found that transmission providers would be deemed to be in compliance with this requirement by conducting long-term regional transmission planning in accordance with the requirements of Order No. 1920. FERC explained that transmission providers that wished to continue to use their existing regional planning and cost allocation processes to consider transmission needs driven by public policy requirements were required to demonstrate that such processes would not interfere with or otherwise undermine the long-term regional planning mandated by Order No. 1920.
Order No. 1920-A largely leaves intact the long-term regional planning process reforms adopted by the Commission in the final rule, but gives states greater control over the scenarios and criteria used to identify long-term transmission planning needs and solutions, clarifies the relationship with certain existing planning processes and modifies and clarifies the factors and benefits adopted in Order No. 1920.
Requirement To Consult With Relevant State Entities When Establishing Planning Scenarios. Order No. 1920-A imposes a new requirement that transmission providers consult with and consider the positions of Relevant State Entities when incorporating state laws, policies and regulations into the development of long-term planning scenarios.4 In particular, the Commission required that “transmission providers . . . consult with Relevant State Entities . . . as to whether a specific state policy must be accounted for as a factor within each category (i.e., if the specific state policy will likely affect long-term transmission needs), how to account for the specific state policy in the development of long-term scenarios (e.g., the method and data used to forecast generation resources added because of a specific state policy), and how to adjust the treatment of the specific state policy across long-term scenarios (e.g., assume certain policy-related outcomes materialize in some but not all long-term scenarios).”5 The Commission explained that it expects “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.”6 For instance, “[i]f . . . 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.”7 The Commission also stated that transmission providers should incorporate states’ preferred “power system trajectories” (i.e., supply or demand-side solutions) as appropriate in each long-term scenario or include different state-preferred power system systems in different long-term scenarios.8
Requirement To Conduct Additional Scenario Analyses At Relevant State Entities’ Request. In Order No. 1920-A, the Commission determines that transmission providers must conduct a “reasonable number of additional [planning] scenarios” if requested by Relevant State Entities to help inform the application of the long-term regional cost allocation method or the development of cost allocation methods through the state agreement process.9 The Commission found that transmission providers may include in their compliance filings a process for Relevant State Entities to make such requests and for determining the number of additional scenarios that will be run by the transmission provider.10
Elimination Of Requirement To Consider Corporate Commitments. The Commission eliminated the requirement that transmission providers consider “corporate commitments” in their planning scenarios. In modifying this requirement, the Commission expressed concern that requiring transmission providers to consider corporate commitments could “introduce the risk of one class of transmission users cross-subsidizing another class of transmission users.”11 The Commission acknowledged that transmission providers must continue to consider corporate commitments to the extent that they affect transmission customers’ transmission needs, as transmission providers must plan for the needs of all transmission customers on a comparable basis. However, the Commission found that it was unnecessary to identify corporate commitments as a separate factor in the development of long-term planning scenarios.
Clarification Of Evaluation Of Long-Term Regional Transmission Facilities. FERC clarified that transmission providers’ evaluation processes must compare the measured benefits of long-term regional transmission facilities against the estimated costs when determining whether to select a facility.12 The Commission further imposed a requirement that transmission providers make available on a password-protected portion of their Open Access Same-Time Information System (OASIS) site or other website “a breakdown of how those estimated costs will be allocated, by zone . . . and a quantification of those estimated benefits as imputed to each zone, as such benefits can be reasonably estimated.”13 The Commission explains that the additional transparency provided by this requirement will ensure that stakeholders understand why a particular long-term regional transmission facility was selected or not selected through the long-term planning process.14
Order No. 1920-A clarified other aspects of the evaluation process. Among other things, the Commission explained that Order No. 1920 does not require a specific method for measuring the benefits of a facility. Thus, transmission providers may “use production cost savings from one or more state integrated resource plans as an appropriate method to measure the value of” production cost savings.15 Similarly, Order No. 1920-A clarifies that transmission providers may propose processes by which they would rely on resource planners and load-serving entities to provide generation-based data and information to assess the benefits of transmission facilities.16
Elimination Of Requirement To Consider Benefits In Evaluation Of Projects. Although the Commission affirmed the minimum set of benefits that transmission providers are required to measure and use in long-term regional planning, the Commission eliminated the requirement that transmission providers use these benefits to help inform their identification of long-term transmission needs.17 Instead, Order No. 1920-A clarifies that the identification of long-term transmission needs should rely on economic and reliability drivers, and that the categories of benefits mandated by the Commission should be used when evaluating for selection transmission facilities to resolve transmission needs identified through the planning process.18
Timeline For Implementation Of Long-Term Regional Transmission Planning. The Commission modified the required timeline for a transmission provider’s initial long-term regional transmission planning cycle. While Order No. 1920 directed transmission providers to propose a date no later than one year from the date of its compliance filing to commence the initial long-term regional transmission planning cycle, Order No. 1920-A provides transmission providers the ability to propose a date that is no later than two years from the date on which initial compliance filings are due.19 FERC further clarified that transmission providers’ compliance filings must explain why the date proposed is necessary and appropriately tailored for the relevant planning region, including any interaction with Order No. 1000-compliance processes.20
Re-Litigation Of PJM’s State Agreement Approach Not Required. The Commission clarified that PJM’s existing State Agreement Approach is separate and distinct from PJM’s compliance with Order No. 1000 requirement to consider transmission needs driven by Public Policy Requirements. Thus, PJM is not required to justify continued use of that process unless the State Agreement Approach is relied on as an Order No. 1920 state agreement process.21
Treatment Of HVDC Lines. FERC denied requests that the list of factors to be considered when developing long-term scenarios be modified to include merchant high-voltage direct current (HVDC) transmission facilities. However, the Commission acknowledged that transmission providers have the flexibility to consider and incorporate such facilities into their long-term scenarios “where proposed HVDC transmission facilities may play a role in shaping Long-Term Transmission Needs.”22
Regional Transmission Cost Allocation
Order No. 1920 required transmission providers to revise their tariffs to include one or more ex ante long-term regional transmission cost allocation methodologies that would apply to transmission facilities selected through the planning process in the absence of Relevant State Entities reaching an agreement on a cost allocation methodology for particular transmission facilities. Although the Commission required transmission providers to consult with Relevant State Entities on this “backstop” cost allocation methodology for a period of six months, it did not require transmission providers to obtain the consent of Relevant State Entities. Order No. 1920 also allowed, but did not require transmission providers to file cost allocation methodologies agreed upon by Relevant State Entities. These requirements led numerous state public service commissions and Commissioner Christie, in his dissent, to argue that states’ role in the allocation of costs for long-term regional transmission facilities had been eroded by the final rule and that the requirements imposed on transmission providers to consult with Relevant State Entities were little more than “check the box” exercises that once satisfied allowed transmission providers to file their preferred cost allocation methodology without meaningful state input.23
Order No. 1920-A makes significant changes to expand the role that Relevant State Entities play in determining the ex ante cost allocation methodology that transmission providers must adopt for all facilities selected through their long-term regional transmission planning process. Although Order No. 1920-A continues to allow transmission providers to file a cost allocation methodology of their choosing, including a methodology that has not been agreed upon by Relevant State Entities, it expands the role that Relevant State Entities can play in the determination of the ex ante cost allocation methodology that ultimately applies to long-term regional transmission facilities in numerous ways.
Requirement To File Alternative Cost Allocation Methodologies. While transmission providers may continue to file whatever cost allocation methodology they elect, Order No. 1920-A requires that they also submit with their Order No. 1920 compliance filing any cost allocation methodology or state agreement approach that has been agreed upon by the Relevant State Entities by the applicable deadline.24 The cost allocation methodology agreed upon by Relevant State Entities must be incorporated into the transmission provider’s compliance filing or included as a separate attachment and contain “any and all supporting evidence and/or justification” related to the Relevant State Entities’ agreed-upon approach.25 Additionally, the Commission requires that as part of their compliance filings transmission providers include “any information” that Relevant State Entities provide to transmission providers regarding the negotiations over cost allocation methodologies during the required engagement window.26
Although the Commission maintains that transmission providers “remain ultimately responsible for transmission planning,” which is “fundamentally linked with cost allocation,”27 the Commission nevertheless acknowledges that the requirement that transmission providers include any cost allocation methodologies agreed to by Relevant State Entities in their filings requires a transmission provider to submit an “alternative” cost allocation methodology if the Relevant State Entities reach agreement on such alternative.28 Indeed, the Commission even states that the alternative cost allocation methodology agreed to by Relevant State Entities will be evaluated by the Commission “on equal footing” as the cost allocation methodology preferred by a transmission provider.29 The Commission also “strongly encourages” transmission providers to establish a process that commits them to requesting Commission approval for any cost allocation methodology that is agreed upon by Relevant State Entities.30
The Commission justifies the requirement that transmission providers file alternative cost allocation proposals by explaining that states play a unique role in implementing the policies that drive the need for long-term regional transmission facilities and that states are ultimately responsible for permitting such facilities.31 The Commission also asserts that it has authority to both require transmission providers to file alternative cost allocation methodologies and to accept such methodologies over the cost allocation methodologies filed by transmission providers.32
Extended Engagement Window. In response to arguments that the six-month engagement window that the Commission provided for Relevant State Entities to reach agreement on a cost allocation methodology was not sufficiently flexible,33 the Commission agreed to grant extensions of the engagement window for up to an additional six months when Relevant State Entities request additional time to complete negotiations over their preferred cost allocation approach.34 The Commission also explained that consistent with such extensions it would, as appropriate, sua sponte extend other relevant Order No. 1920 compliance deadlines.35
Consultation Prior To Cost Allocation Amendments. In response to concerns that a transmission provider could file with the Commission to amend their cost allocation methodologies at any time after their initial Order No. 1920 compliance filing without engaging with Relevant State Entities, on rehearing the Commission requires transmission providers to consult with Relevant State Entities prior to proposing any amendments to any cost allocation methodologies accepted by the Commission.36 The Commission also requires that transmission providers must consult with Relevant State Entities if those entities seek to amend a cost allocation methodology and, if the transmission providers ultimately elect not to pursue amendments recommended by the Relevant State Entities, provide an explanation on their OASIS or website for why they declined to adopt such amendments.37
Increased Obligations For Transmission Providers. The Commission imposed additional obligations on transmission providers related to cost allocation and how they engage with Relevant State Entities. The Commission, for example, clarifies that transmission providers must describe how the forum they are required to provide for negotiations with Relevant State Entities will result in such entities’ meaningful participation and disclose any deadlines that the transmission provider intends to apply to Relevant State Entities during the engagement period.38 Moreover, if Relevant State Entities request, transmission providers must “facilitate and participate in a cost allocation discussion” with Relevant State Entities given that they “may have more experience with transmission providers’ OATTs and with the Commission’s processes and precedent.”39 Transmission providers must also, as noted above, publicly document on their websites or OASIS the results of their required engagement efforts prior to filing an amendment to a cost allocation methodology, including an explanation as to why a transmission provider has not adopted the cost allocation methodology proposed by Relevant State Entities.40 And the Commission clarifies that transmission providers must make available a breakdown of how the costs for any long-term regional transmission facility that is selected will be allocated by zone and a quantification of the estimated benefits the facility will provide to each zone.41
Coordination Of Regional Transmission Planning and Generator Interconnection Processes
Order No. 1920 required transmission providers to evaluate for selection in their existing Order No. 1000 regional transmission planning processes transmission facilities addressing interconnection-related transmission needs if:
- The transmission provider has identified network upgrades to address those interconnection-related transmission needs in at least two interconnection queue cycles during the preceding five years;
- An interconnection-related network upgrade identified to meet those needs has a voltage of at least 200 kV and an estimated cost of at least $30 million;
- Such upgrades have not been developed and are not currently planned to be developed because the interconnection requests driving the need for the network upgrade have been withdrawn;
- The transmission provider has not identified an interconnection-related network upgrade to address the transmission need in an executed generator interconnection agreement or an agreement that has been filed unexecuted with the Commission.42
Order No. 1920-A modifies the criteria used to determine whether a transmission provider must consider for selection a transmission facility addressing an interconnection-related need in several respects.
First, the Commission modified the first criterion to clarify that transmission providers that use a first-come, first-served serial generator interconnection process should include an interconnection-related need if it is identified “in at least two individual interconnection studies” rather than interconnection queue cycles.43
Second, the Commission clarified that a transmission provider is not required to evaluate an interconnection-related transmission need if more than five calendar years separate the withdrawal of the earlier and later interconnection requests associated with the need at issue.44
Third, the Commission adopted a new criterion requiring that the withdrawals associated with the interconnection-related transmission needs must have occurred within seven calendar years prior to the commencement date of a given regional planning and cost allocation cycle.45
1 Building for the Future Through Electric Regional Transmission Planning and Cost Allocations, Order No. 1920-A, 189 FERC ¶ 61,126, at P 275 (2024) (“Order No. 1920-A”).
2 Commissioner See did not participate.
3 Transmission Planning & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051 (2011), order on reh’g and clarification, Order No. 1000-A, 139 FERC ¶ 61,132 (2012), order on reh’g and clarification, Order No. 1000-B, 151 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
4 Order No. 1920-A, at P 275.
5 Order No. 1920-A at P 344.
6 Order No. 1920-A at P 299.
7 Order No. 1920-A at P 275.
8 Order No. 1920-A at PP 275, 345, 352.
9 Order No. 1920-A at PP 364-367.
10 Order No. 1920-A at P 367.
11 Order No. 1920-A at P 303.
12 Order No. 1920-A at P 450.
13 Order No. 1920-A at P 450.
14 Order No. 1920-A at P 450.
15 Order No. 1920-A at P 410.
16 Order No. 1920-A at P 420.
17 Order No. 1920-A at PP 392.
18 Order No. 1920-A at P 225.
19 Order No. 1920-A at P 507.
20 Order No. 1920-A at P 509.
21 Order No. 1920-A at P 213.
22 Order No. 1920-A at P 331.
23 Order No. 1920-A at P 629.
24 Order No. 1920-A at P 651.
25 Order No. 1920-A at P 651.
26 Order No. 1920-A at P 651. The Commission says that it will not require transmission providers to “independently characterize this information.” Order No. 1920-A at P 655.
27 Order No. 1920-A at P 653.
28 Order No. 1920-A at P 659.
29 Order No. 1920-A at P 692.
30 Order No. 1920-A at P 662. The Commission provides an example of a cost allocation methodology that Relevant State Entities could agree to which would allocate the costs of long-term regional transmission facilities on a region-wide basis based on economic and reliability benefits, but would limit incremental costs associated with particular state laws and policies to customers in the state with such laws or policies. Order No. 1920-A at PP 767-68.
31 Order No. 1920-A at P 659.
32 Order No. 1920-A at PP 658-59.
33 Order No. 1920-A at P 675.
34 Order No. 1920-A at P 678.
35 Order No. 1920-A at PP 33, 678.
36 Order No. 1920-A at P 691.
37 Order No. 1920-A at P 691.
38 Order No. 1920-A at P 684.
39 Order No. 1920-A at P 656.
40 Order No. 1920-A at P 691.
41 Order No. 1920-A at P 773.
42 Order No. 1920-A at P 525.
43 Order No. 1920-A at P 545.
44 Order No. 1920-A at P 547.
45 Order No. 1920-A at P 547.