At a special Open Meeting held May 13, 2024, the Federal Energy Regulatory Commission ("Commission" or "FERC") issued a long-awaited order on regional transmission planning and cost allocation: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation, Order No. 1920, 187 FERC ¶ 61,068 (2024) ("Order No. 1920" or the "Final Rule"). The Final Rule comes approximately 13 years after Order No. 1000, the Commission's last major transmission reform directive. Although Order No. 1000 laid the groundwork for regional transmission planning and competitive transmission development in 2011, in practice, it has catalyzed little of the investment needed to update the country's aging power grid.
Narrowly approved in a 2-1 party-line vote (with Republican Commissioner Mark Christie issuing a pointed 77-page dissent), Order No. 1920 makes major reforms to transmission planning requirements applicable to transmission providers. Such reforms, the majority argues, are necessary to preserve reliability and keep electricity rates down amid a number of factors affecting the electric power sector, including more frequent and intense extreme weather events, load growth associated with electrification and new technologies, and the evolution of the country's generation resource mix to meet public policy and customer demands for lower carbon emissions and an increase in renewable resources.
Chief among the reforms established by Order No. 1920 include requirements that transmission providers: (i) engage in regional long-term transmission planning to identify transmission needs; (ii) develop processes and criteria for selecting transmission facilities to resolve those needs; and (iii) devise and file ex ante cost allocation methods to apportion the associated costs. These reforms reflect the Commission's finding in the Final Rule of substantial evidence that existing planning and cost allocation processes are broadly unjust, unreasonable, and unduly discriminatory or preferential and require revision under Federal Power Act section 206.
The Final Rule upholds many of the proposals from the April 21, 2022, Notice of Proposed Rulemaking ("NOPR"), but with modifications to several key proposals. Notably absent from the Final Rule are two of the most contentious proposals from the NOPR: proposed limitations on the construction work in progress ("CWIP") incentive and the proposed re-establishment of a federal right of first refusal ("ROFR") for incumbent transmission owners. In the NOPR, the Commission proposed to prohibit Long-Term Regional Transmission Facilities from being eligible for the CWIP incentive, which allows a transmission developer to begin recovering construction costs in its rate base before the facility is placed in service. The CWIP incentive helps de-risk projects by providing additional revenue certainty earlier in the development cycle, but has long been criticized for shifting risk to ratepayers for projects from which they are not (yet) deriving any benefit.
In Order No. 1920, the Commission declined to limit the availability of the CWIP incentive at this time, but indicated it plans to review this issue in an action that comprehensively addresses transmission incentives. The Commission similarly declined to adopt its proposal to re-establish a ROFR, eliminated by Order No. 1000, which would have allowed incumbent transmission owners the right to construct facilities over which they agreed to exercise joint ownership. As with the CWIP incentive, the Commission indicated an interest in acting on the broad ROFR issue in a future proceeding. As discussed in more detail below, the Commission also adopted a limited ROFR applicable only to certain "right-sized" replacement transmission facilities.
As with any significant Commission order (and indeed, as was the case with respect to Order No. 1000), we expect to see a number of legal challenges to Order No. 1920. Judging by the language of the Final Rule itself, the concurrence, and the dissent, it appears the Commissioners expect the same. The Final Rule includes a robust discussion of the Commission's authority to develop transmission planning requirements and how such action does not infringe upon those areas left to the states (e.g., resource planning, generation mix, siting and construction of transmission and generation). In an unusual move, Chair Phillips and Commissioner Clements issued a concurrence for the order they both joined in full that rebuffs the challenges raised in Commissioner Christie's dissent—a dissent that tees up significant issues we expect to see challenged on appeal. These include the issue of whether Order No. 1920 implicates the major questions doctrine, under which courts presume that Congress has not delegated to a federal agency questions of significant economic and political significance unless there is explicit statutory authorization.
In this alert, we provide a high-level summary of the reforms made by the Commission in Order No. 1920 and a discussion of how we expect to see this play out over the next year. The Foley Hoag FERC team will be closely monitoring this proceeding.
We note at the same May 13, 2024 meeting that produced Order No. 1920, the Commission also issued Order No. 1977, which concerns FERC's transmission siting backstop authority.
Applicability
The Final Rule applies to all Commission-jurisdictional transmission providers. The Commission rejected stakeholder comments to only apply these requirements to Regional Transmission Operator ("RTO") and Independent System Operator ("ISO") planning regions, noting that if the Final Rule's applicability was narrowed, then non-RTO/ISO regions could continue to invest in inefficient or less cost-effective transmission, resulting in rates that are not just and reasonable or are unduly discriminatory or preferential.
Long-Term Planning
Requirement to Participate in Long-Term Transmission Planning
As expected, the Final Rule requires transmission providers to participate in regional transmission planning processes, under which they will be required to produce long-term regional transmission plans. As part of this process, transmission providers must develop at least three distinct Long-Term Scenarios that utilize planning horizons of not less than 20 years to predict Long-Term Transmission Needs that will materialize based on changes in the electric system during that time, predicted using the best available data. In defending the use of a 20-year planning timeline, the Commission found that this duration balanced future uncertainty with the need to proactively plan and would not result in an increase in speculative transmission projects. The Long-Term Scenarios must be reviewed and updated at least once every five years, and transmission providers can either update the data and assumptions used in them or they can be replaced by new scenarios.
Order No. 1920 prescribes that transmission providers must incorporate the following seven factors when creating the Long-Term Scenarios: "(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." Notably, the Commission declined to include energy equity and justice as a distinct factor, noting that it was sufficiently incorporated into the other factors.
Each Long-Term Scenario must incorporate the first three factors without any "discounts" (in other words, transmission providers should assume that legally-binding obligations will be met), but the Final Rule expressly gives transmission providers discretion on how they weight or account for the remaining four factors. Transmission providers must also give stakeholders an opportunity to propose factors and provide input on how to account for them in the Long-Term Scenarios and must publicly post information regarding the factors and how they intend to use them. To account for low-frequency, high-impact events such as sustained outages from extreme weather, each Long-Term Scenario must include a sensitivity to account for the "uncertain operational outcomes" during these types of events, which the Commission refers to as a "stress test" of the scenarios.
Regional Transmission Facility Benefits
Order No. 1920 also requires transmission providers to measure seven required benefits under each scenario and use these benefits to evaluate Long-Term Regional Transmission Facilities for resolution of the Long-Term Transmission Needs identified through the development of the Long-Term Scenarios. The seven benefits are, "(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." The Commission declined to require evaluation of the other five factors discussed in the NOPR (i.e., mitigation of weather and load uncertainty, generation capacity investments, access to lower-cost generation, increased competition, and increased market liquidity), finding that the seven factors enumerated above were sufficient. As part of their tariff filings, transmission providers must explain how they will measure each of the benefits.
Transmission Project Selection
The Final Rule also requires transmission providers to propose an evaluation process, including selection criteria, that will be used to identify and evaluate the Long-Term Regional Transmission Facilities used to address the identified Long-Term Transmission Needs. The Commission has given transmission providers flexibility to design and propose these processes, which must be transparent, result in the selection of the most efficient and cost-effective proposals, and estimate the costs and measure the benefits of Long-Term Regional Transmission Facilities. The processes and selection criteria should maximize benefits while also considering costs. On compliance, transmission providers must demonstrate that they made a good faith effort to consult with state entities and other stakeholders on the creation of the processes and selection criteria. It is worth noting that there is no mandate under Order No. 1920 for a transmission provider to select a Long-Term Regional Transmission Facility, even if it meets the approved selection criteria. Order No. 1920 requires transmission providers to propose a process through which state entities and interconnection customers may volunteer to pay for some or all of the costs of a Long-Term Regional Transmission Facility that does not otherwise meet selection criteria. The Final Rule also requires transmission providers to reevaluate selected projects in certain instances where there are significant changes in circumstances.
Coordination of Regional Transmission Planning and Generator Interconnection Processes
In the Final Rule, the Commission noted a pattern of generators withdrawing from interconnection queues due to high network upgrade costs, leaving the identified system upgrades unbuilt through multiple cycles of interconnection processes. To remedy this, the Final Rule requires transmission providers to evaluate for selection regional transmission facilities that will address identified interconnection-related transmission needs through the existing Order No. 1000 processes. The Commission granted transmission providers flexibility to design the evaluation and selection process. To qualify for this process, the network upgrades must: (i) have been identified in at least two interconnection queue cycles in the preceding five years; (ii) have a voltage of at least 200 kV; (iii) have an estimated cost of $30 million or more; (iv) not be currently in development; and (v) not be an identified need that will be resolved through facilities in large generator interconnection agreements.
Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices
The Final Rule adopts and expands upon the NOPR's proposal for consideration of advanced transmission technologies. The NOPR proposed to require transmission providers to incorporate review of dynamic line ratings and advanced power flow control devices in both Long-Term Regional Transmission Planning and existing Order No. 1000 regional transmission planning processes for each transmission need. The Final Rule expands on the NOPR proposal and requires transmission providers to also consider advanced conductors and transmission switching and also specifies that these four technologies must be considered for both new transmission facilities and also when upgrading existing facilities. In practice, transmission providers will need to evaluate whether transmission proposals that incorporate these technologies are more efficient or cost-effective than proposed facilities that do not. The Commission made clear that the costs and benefits of incorporating the alternative transmission facilities must be considered and that transmission providers must also continue to adhere to Good Utility Practice in their evaluations.
Cost Allocation
Ex Ante Cost Allocation Methods and State Agreement
Processes
In the Final Rule, the Commission modified the cost allocation
provisions proposed in the NOPR to require (rather than permit)
transmission providers to include in their Order No. 1920
compliance filings one or more default ex ante Long
Term-Regional Transmission Cost Allocation Methods to allocate
costs for Long-Term Regional Transmission Facilities (or a
portfolio of such Facilities) that are selected for regional cost
allocation.
Additionally, transmission providers may, but are not required to, include in their compliance filings a State Agreement Process by which state entities (most likely, but not necessarily only, state electric utility regulators) may voluntarily agree to a cost allocation method for projects before or for a limited time after they are selected for regional cost allocation. As envisioned by the Final Rule, a State Agreement Process would permit relevant state entities to volunteer to agree to a cost allocation method for a Long-Term Regional Transmission Facility (or a portfolio of the same) before they are selected in the regional transmission plan for cost allocation and up to six months thereafter. Additionally, the state entities involved in the State Agreement Process can choose the level of agreement (e.g., unanimity or majority) to establish a cost allocation method.
The Final Rule indicates that a State Agreement Process cannot be the only cost allocation method filed. Should a State Agreement Process fail to produce a cost allocation method agreed to by the involved parties (or should the Commission find that the method produced by the State Agreement Process violates the Federal Power Act), then the relevant Long-Term Regional Transmission Cost Allocation Method on file would apply as the default.
To facilitate participation of state entities in transmission providers' development of their Order No. 1920 compliance filings, the Final Rule requires transmission providers to hold a six-month "Engagement Period" providing a forum for communication and negotiation between state entities and transmission providers regarding not only the potential for a State Agreement Process but also the development and selection of ex ante Long-Term Regional Transmission Cost Allocation Method(s). The Engagement Period replaces the NOPR proposal to seek agreement of state entities regarding the cost allocation method to be applied to Long-Term Regional Transmission Facilities.
Applicability of Order No. 1000 Cost Allocation Principles
The Commission also required that the proposed cost allocation methods comply with five of the Order No. 1000 regional cost allocation principles unless the cost allocation method was agreed to by the relevant state entities during the Engagement Period or as part of a State Agreement Process. These principals are: (i) allocation of costs in a manner roughly commensurate with estimated benefits; (ii) those that receive no present or likely future benefit must not be made to pay; (iii) a benefit to cost ratio, if adopted, cannot exceed 1.25 to 1; (iv) costs must be allocated only within the relevant planning region, unless another entity outside the region voluntarily assumes a portion of the costs; and (v) the method used for determining benefits and identifying beneficiaries must be transparent.
In a departure from the Order No. 1000 regime, costs may not be allocated according to project type, unless by agreement of relevant state entities. Under Order No. 1920, transmission providers may not apply classifications of reliability, economic, or public policy transmission to projects when it comes to assigning a cost allocation method unless the relevant state entities indicate that they have agreed to a voluntary cost sharing arrangement.
Local Transmission Planning and "Right-Sizing" Replacement Transmission Facilities
In the NOPR, the Commission expressed concerns regarding the lack of adequate transparency and provisions for meaningful stakeholder input in local transmission planning processes and expressed that incumbent transmission providers appear to be replacing aging transmission infrastructure without considering whether those facilities could be "right-sized" to better address regional transmission needs.
To address the first concern, the Final Rule requires that transmission providers revise regional transmission planning processes to enhance transparency, including by (i) publicly posting information relevant to assumptions, needs, and solutions considered throughout local transmission planning processes; (ii) conducting several publicly-noticed stakeholder meetings, subject to specifically identified requirements; and (iii) establishing an iterative process for stakeholders to provide feedback and have that feedback incorporated into local transmission planning.
To help ensure that replacement transmission facilities are sized in a manner that will help address regional transmission needs, Order No. 1920 also requires that, as part of Long-Term Regional Planning cycles, transmission providers consider whether transmission facilities operating above certain kilovolt threshold that are anticipated to be replaced in-kind with a new facility during the next 10 years can be "right-sized" to increase that facility's transfer capability. Transmission providers must propose a kilovolt threshold, not to exceed 200 kV, on compliance. Notably, the Order gives incumbent transmission providers a limited, federally-recognized ROFR to develop the in-kind replacement transmission facility if it is selected to meet Long-Term Transmission Needs. The Commission directed transmission providers to propose cost allocation methodologies for right-sizing transmission facilities that are just and reasonable and meets certain other standards.
Interregional Transmission Coordination
The Final Rule adopts the NOPR proposal to require transmission providers in adjacent transmission planning regions to update existing interregional transmission coordination procedures to contemplate sharing information regarding Long-Term Transmission Needs and Long-Term Regional Transmission Facilities and also 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. In addition, Order No. 1920 also requires neighboring transmission providers to identify and jointly evaluate interregional transmission facilities that may provide more efficient or cost effective means to address Long-Term Transmission Needs.
Variations from the Final Rule
The Commission declined to adopt requests to provide RTOs and ISOs access to an independent entity variation standard for deviations from the Final Rule, instead choosing to continue to apply the "consistent with or superior to" standard that was used in Order Nos. 888, 2000, 890, and 1000 to all types of transmission providers.
Commissioner Christie's Dissent
Dissenting from the majority, Commissioner Mark Christie expressed his view that Order No. 1920 is legally flawed and is beyond the Commission's power to issue. In the dissent, Commissioner Christie not only criticized various legal arguments made by the majority in support of the substance of the Final Rule, but also opined that the process by which the Final Rule evolved from the NOPR (for which he voted in 2022) was improper and itself could be subjected to legal challenges.
Among these challenges is Commissioner Christie's argument that the Final Rule violates the Administrative Procedure Act requirement that agency decisions be adequately supported by the evidence and not arbitrary and capricious. In support of this argument, Commissioner Christie cited the length and complexity of the order, which he claimed will enable the Commission to unduly guide regulated entities toward certain compliance filings during the compliance process. Additionally, Commissioner Christie suggested that the Final Rule is substantially different enough from the NOPR that a court might remand the rule to the Commission with instructions to open a public comment period.
Commissioner Christie also alleged that Order No. 1920 violates the Federal Power Act on a number of fronts, including that: (i) the record does not adequately support the Commission's finding that the on-file rates in question are unjust or unreasonable (and therefore does not meet the burdens of Federal Power Act section 206); (ii) the Final Rule is unduly preferential toward certain types of generators (i.e., wind and solar); (iii) the Final Rule does not provide a just and reasonable replacement rate because it serves the profit-making interest of the developers of certain types of generation and shifts the interconnection and network upgrade costs of projects driven by public policies or corporate preferences onto ratepayers who may not have agreed to those policies or preferences; and (iv) the Final Rule infringes on the authority of the states over energy resource mixes.
Commissioner Christie also argued that the Final Rule violates the major questions doctrine, the interpretive doctrine employed by the U.S. Supreme Court in voiding emissions-related regulations promulgated by the U.S. Environmental Protection Agency in the 2022 case West Virginia v. EPA. (That doctrine calls courts to presume that Congress has not delegated to a federal agency questions of significant economic and political importance unless there is explicit statutory authorization, and encourages courts to scrutinize unusually impactful agency actions with an eye for clear authorization by Congress.) In the case of Order No. 1920, Commissioner Christie alleges that the rule (i) is designed to implement a "sweeping" policy agenda unauthorized by Congress and (ii) will cause "trillions" of dollars to be spent and thus implicates the major questions doctrine on at least two fronts.
Next Steps and Compliance Filings
As described above, in the near term, we expect to see significant activity regarding legal challenges to the Final Rule; stakeholders seeking rehearing must do so by June 12, 2024. Rehearing requests are the first step of the lengthy process for appealing electricity-related FERC orders to the federal courts. Notably, requests for rehearing and appeals typically do not stay FERC's compliance processes, so any legal changes will be pursued contemporaneously with the rehearing and appeal process unless a regulatory or legal body orders otherwise.
The Final Rule directs transmission providers to make their compliance filings within 10 months of the effective date of the Final Rule (i.e., 60 days from the date of the publication in the Federal Register), which should be just over a year from today. Transmission providers will have an additional two months to submit compliance filings to implement the interregional planning reforms in the Final Rule. In their principal compliance filings, transmission providers must propose a date no later than one year after their initial compliance filing due date on which they will commence the first Long-Term Regional Transmission Planning cycle (with a narrow exception to accommodate existing planning cycle schedules). In other words, we are unlikely to see the first Order No. 1920 long-term transmission planning cycles kick off before the second quarter of 2026.
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.