On May 13, 2024, the Federal Energy Regulatory Commission (“FERC” or “Commission”) established “a new foundation” upon which new electric transmission facilities can be planned, paid for, and built. The Commission did so through the unveiling of its final rules on (1) transmission planning and cost allocation (Order No. 1920) and (2) its backstop authority to site transmission projects in areas designated by the U.S. Department of Energy (“DOE”) as National Interest Electric Transmission Corridors (“NIETCs”) (Order No. 1977) (together, the “Final Rules”). The Final Rules were years in the making and represent perhaps the most significant development in federal transmission policy since FERC Order No. 888.

As discussed in the first section of this alert, Order No. 1920 mandates changes to regional planning and cost allocation requirements in an effort to promote the development of electric transmission infrastructure and to establish long-term transmission planning processes. However, Order No. 1920 differs from the originally proposed rule in significant ways that appear to limit states’ participation in planning and cost allocation processes. Accordingly, rehearing requests and challenges in the U.S. Court of Appeals are all but certain.

As discussed in the second section of this alert, Order No. 1977 attempts to realign the Commission’s regulations with its long dormant backstop authority empowering it to site certain qualified electric transmission projects. Significant roadblocks remain because the Commission lacks the authority to grant the right of eminent domain over state-owned land, thus allowing an opposing state to thwart a project’s viability through its refusal to grant land rights.

Cost Allocation and Transmission Planning, Order No. 1920 (RM21-17)

According to White House advisors, the United States needs to “more than double [its] transmission capacity” to meet the Biden administration’s climate goals. For years, transmission capacity has been expanding on a localized level that is primarily driven by individual generation interconnection requests. However, as experts have noted, this growth through individual interconnection requests is an inefficient way to expand the nation’s transmission system.

In addition, previous cost allocation methods for transmission projects were criticized for allocating transmission project costs to ratepayers who did not truly benefit from the project. The Commission first attempted to tackle these complex issues and receive input through the Advanced Notice of Proposed Rulemaking, released July 15, 2021, and again in the Notice of Proposed Rulemaking (“NOPR”), released April 21, 2022.

The Commission’s Order No. 1920 attempts to finalize this multi-year effort. Order No. 1920 establishes more proactive transmission planning by requiring FERC-regulated transmission providers to develop long-term, 20-year plans that identify “Long-Term Transmission Needs” and to evaluate transmission facilities that can be used to meet those needs through an evaluation process developed with stakeholders and certain responsible state entities (“Relevant State Entities”). Order No. 1920 also takes steps toward linking cost responsibility with the ratepayers that benefit from a project by requiring transmission providers to revise their tariffs to adopt one or more ex ante regional cost allocation methods (“Long-Term Regional Transmission Cost Allocation Methods”) to apply to regional transmission facilities that are selected in the regional transmission planning process.

Order No. 1920 includes numerous significant changes from the proposals set forth in the NOPR — so many changes that Commissioner Christie stated at the Open Meeting that the number of changes were too numerous to list in his comments or in his (78-page) dissent. Most notably, Order No. 1920 decreases the flexibility the Commission proposed to afford to transmission providers in the NOPR by mandating transmission providers (1) file one or more ex ante cost allocation methods (rather than adopting the NOPR proposal to allow providers to choose between an ex ante approach, a State Agreement Approach, or a combination of the two) and (2) adopt a specific set of benefits to use when evaluating proposed transmission facilities (rather than adopting the NOPR proposal allowing transmission providers to propose all of the benefits they will use to evaluate transmission facilities in their plans). Similarly, Order No. 1920 decreases regional flexibility by abandoning Order No. 1000’s regional cost allocation principles and prohibiting providers from adopting different regional cost allocation methods for different types of regional transmission facilities. Additionally, Order No. 1920 abandons the NOPR’s proposal to establish a conditional federal right of first refusal for incumbent transmission providers based on joint ownership criteria and retains the availability of the construction work in progress incentive that the NOPR sought to eliminate.

Transmission Planning

In an effort to make the transmission planning process more forward-looking, Order No. 1920 requires FERC-jurisdictional transmission providers to:

• Engage in a six-month “Engagement Period” before compliance filings, during which transmission providers must: (1) provide notice of the starting and end dates for the six-month time period and provide a deadline by which the “Relevant State Entities” must communicate any agreements among themselves; (2) post their contact information that Relevant State Entities can use to communicate with them about agreements among the entities on the cost allocation method and/or a “State Agreement Process”; and (3) provide a forum for negotiation about the cost allocation method and/or a State Agreement Process that enables Relevant State Entities to meaningfully participate. Transmission providers are permitted, but not required, to adopt a State Agreement Process that results from this process.
• Develop a “Long-Term Regional Transmission Plan” that includes an evaluation of transmission facilities’ needs over a 20-year planning horizon, to be reassessed at least once every five years. The Long-Term Regional Transmission Plan must include at least three plausible “Long-Term Scenarios,” which are scenarios that incorporate different assumptions about the future electric power system over a long-term planning horizon, in order to identify future needs and evaluate how transmission facilities can meet those needs. Each of the three Long-Term Scenarios must: (1) incorporate the Commission-identified categories of factors that give rise to Long-Term Transmission Needs; (2) be developed using “best available data” in developing the Long-Term Scenarios; and (3) undergo at least one sensitivity analysis that analyzes the impact of extreme weather events on each Long-Term Scenario.
• Consider in their Long-Term Regional Transmission Plan regional transmission facilities that would address interconnection-related needs identified in the generator interconnection process, specifically those needs for which: (1) the transmission provider identified such need in interconnection studies in at least two interconnection queue cycles during the last five years; (2) the interconnection-related upgrade identified to meet such need has a voltage of at least 200 kV and an estimated cost of at least $30 million; (3) the upgrades to meet such need have not been developed and are not currently planned to be developed because the interconnection requests have been withdrawn; and (4) the public utility transmission provider has not identified an interconnection-related network upgrade to address the relevant need in a final generator interconnection agreement.
• Consider certain technologies in their Long-Term Regional Transmission Plan when evaluating both new regional transmission facilities and upgrades to existing transmission facilities, including: (1) dynamic line ratings; (2) advanced power flow control devices; (3) advanced conductors; and (4) transmission switching.
• Develop an evaluation process with Relevant State Entities including selection criteria by which transmission facilities identified in the Long-Term Scenarios will be selected. Evaluation processes, including the selection criteria, must: (1) be transparent; (2) not be unduly discriminatory; and (3) seek to maximize benefits accounting for costs over time without over-building transmission facilities.
  • During this evaluation process, transmission providers will be required to measure and use at least a prescribed list of seven benefits for each transmission facility that is evaluated as part of the Long-Term Regional Transmission Planning. These required benefits include: (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.

Cost Allocation

To clarify the cost allocation methodology, Order No. 1920 requires transmission providers to revise their open access transmission tariffs (“OATTs”) to include:

• One or more ex ante “Long-Term Regional Transmission Cost Allocation Methods” to allocate the costs of individual transmission facilities or a portfolio of transmission facilities that are selected under the evaluation process. Unless Relevant State Entities agree to a certain cost allocation method or State Agreement Process during an “Engagement Period,” a Long-Term Regional Transmission Cost Allocation Method must adhere to most of the Order No. 1000 regional cost allocation principles, including that: (1) the costs of selected 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; (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; (3) a benefit to cost threshold ratio, if adopted, cannot exceed 1.25 to 1; (4) costs must be allocated solely within the transmission planning region unless another entity outside the region voluntarily assumes a portion of those costs; and (5) the method for determining benefits and identifying beneficiaries must be transparent.
• A process that provides Relevant State Entities and interconnection customers the opportunity to voluntarily fund all of or a portion of the cost of transmission facilities that would otherwise not meet the selection criteria. The provisions that detail this process must describe: (1) the process by which the transmission providers will make voluntary funding opportunities available to Relevant State Entities and interconnection customers, which must ensure that Relevant State Entities and interconnection customers receive timely notice of such opportunities and provide a meaningful opportunity for Relevant State Entities and interconnection customers; (2) the period during which Relevant State Entities and interconnection customers may exercise the option to provide voluntary funding; (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, for example, a pro forma agreement in the OATT.

OATT Changes Required

In addition to requiring transmission providers to undergo a six-month Engagement Period before making their compliance filings, Order No. 1920 includes required changes to the pro forma OATT to incorporate the new requirements that must be filed within 12 months for the interregional transmission coordination requirements and 10 months for all other requirements. Each transmission provider’s filing will have to show that it adopts the pro forma language adopted by Order No. 1920. Order No. 1920 also requires the compliance filing to include updates to all other documents, subject to the Commission’s jurisdiction necessary to demonstrate that it has met all of the requirements of Order No. 1920.

Key Remaining Considerations

Although Order No. 1920 may make transmission planning more proactive and holistic, it is all but certain to be challenged by state agencies and ratepayers in states that arguably do not benefit from certain regional transmission projects or that view Order No. 1920 as a “federal transmission planning regime.” A primary issue with Order No. 1920 is that it includes major changes from the NOPR that limit states’ participation in the transmission planning and cost allocation process, which could create more resistance to these reforms and could make it subject to a challenge in court. The National Association of Regulatory Utility Commissioners released a statement on May 14, 2024, expressing its general disappointment in Order No. 1920 due to the “significantly diminished state role” thereunder and signaled that it is evaluating its options in response to Order No. 1920. The release of Order No. 1920 could impact state participation in the processes developed by Order No. 1920 and future participation in joint task forces.

Transmission providers may also be feeling a sense of déjà vu with respect to the compliance filing deadlines under Order No. 1920, considering the difficulties many had in complying with Order Nos. 2023 and 2023-A. As noted, once it is published in the Federal Register, Order No. 1920 will require that each transmission provider submit a compliance filing to revise its OATT and related documents to align with the new requirements promulgated under Order No. 1920 within 12 months for the interregional transmission coordination requirements and 10 months for all other requirements. Although this seems like ample time for regional transmission organizations and independent system operators, other transmission providers operating in bilateral markets and especially smaller-scale transmission providers will likely find to harder to implement the significant changes in that period. Many may end up seeking extensions, which was the case for compliance filings for Order Nos. 2023 and 2023-A. Moreover, certain aspects of Order No. 1920 are certain to be clarified upon rehearing or in individual compliance filing orders which could necessitate further unforeseen revisions to individual OATTs and implementation of the rules of similarly-situated utilities. The result may be a complex and somewhat messy compliance period a year from now, if the compliance filing deadlines are not extended, and an administrative avalanche for the Commission Staff processing the compliance filings.

FERC Backstop Authority, Order No. 1977 (RM22-7)

Over the past several years, Congress, FERC, and the DOE have tried repeatedly to alleviate the difficulties associated with siting interstate electric transmission facilities. The Energy Policy Act of 2005 promulgated Section 216 of the Federal Power Act (“FPA”), which allows the DOE to designate NIETCs and empowers the Commission to site projects within NIETCs over state objections or inaction. However, as we have previously explained, two circuit court decisions faulted DOE for its initial NIETC designations and rejected the Commission’s backstop authority regulations. FERC has never exercised its backstop authority as a result.

DOE is slowly but surely doing its part to designate new NIETCs. On May 8, 2024, the DOE released a list of ten potential NIETC designations. The next phase of DOE’s process involves the preparation of draft environmental reports for each proposed NIETC, which is expected to take approximately two years to complete. Thus, we do not expect to see an official NIETC designation until at least 2026.

In the interim, if FERC is ever going to exercise its backstop authority within a NIETC, then it needs to get its house in order after the Commission’s initial regulations under FPA Section 216 were struck down by the Fourth Circuit in 2009. Congress jumpstarted this process with the passage of the Infrastructure Investment and Jobs Act (“IIJA”) in 2021. The IIJA revised FPA Section 216 specifically in response to the Fourth Circuit’s holding 15 years ago that rejected FERC’s self-proposed ability to exercise its backstop authority where a state siting authority timely denied a siting application. Accordingly, the IIJA clarified that FERC’s backstop authority can be triggered when a state siting authority has: (i) not made a determination on the siting application within one year; (ii) conditioned its approval such that the project is no longer economically feasible or a reduction in transmission capacity constraints would not be realized; or (iii) denied a transmission siting application. The IIJA also mandated that FERC determine whether any backstop authority permit holder has made good faith efforts to engage with landowners and other stakeholders before granting the project company eminent domain authority under Section 216.

Order No. 1977 revises FERC’s regulations to adopt the backstop authority triggers set forth in the IIJA. It also clarifies that an applicant may provide evidence that a state does not have statutory authority to consider the interregional benefits expected to be achieved by the project. However, Order No. 1977 does not stop there. It also (1) explains how FERC will determine whether an applicant has made “good faith efforts” to engage with landowners and other stakeholders; (2) requires that applicants develop an “Environmental Justice Public Engagement Plan”; and (3) adds three new mandatory resource reports to be provided as part of the National Environmental Policy Act (“NEPA”) process.

• Eminent Domain and Stakeholder Outreach – Order No. 1977 implements a voluntary “Applicant Code of Conduct.” Supplementing the existing “Project Participation Plan” that an applicant is required to submit, the Applicant Code of Conduct includes additional recordkeeping and information-sharing requirements for engagement between the applicant and affected landowners and general prohibitions against misconduct by an applicant. While voluntary, if an applicant chooses not to use the Applicant Code of Conduct, it must specify an alternative method of demonstrating that it has made “good faith efforts” to engage with landowners and other stakeholders, as required under the IIJA, and explain why the alternative method is equal or superior to the Applicant Code of Conduct.
• Environmental Justice Public Engagement Plan – Order No. 1977 requires applicants to develop an Environmental Justice Public Engagement Plan, which must include a description of the applicant’s outreach activities targeted towards potential or identified environmental justice communities. Additionally, this plan requires applicants to summarize comments received from impacted environmental justice communities during previous outreach activities and to describe planned outreach activities during the permitting process, including efforts to identify, engage, and accommodate people with limited English proficiency.
• Environmental Resource Reports – Order No. 1977 requires an applicant to produce three new resource reports as part of the NEPA review process, including: an air quality and environmental report, tribal resources report, and environmental justice report. To accommodate the additions, the Commission has redesignated the existing resource reports, bringing the total number to 14.

Key Remaining Considerations

Despite the Commission’s best efforts, its backstop authority is not a silver-bullet to developing and building new long-distance transmission. The reason is that the Commission’s backstop siting authority does not include the ability to convey eminent domain authority over state-owned lands, like the Natural Gas Act does under Section 7(h) for interstate natural gas pipelines that receive a certificate of public convenience and necessity. Therefore, even with the Commission’s support, a project developer will not be able to condemn state-owned land. Considering that a state owns every navigable waterway within its borders, even with the Commission’s enhanced regulations under Order No. 1977, a state that is committed to holding up a project will likely still be able to do so. The Commission’s backstop authority will not truly be viable unless Congress amends the FPA to provide for eminent domain authority over state-owned lands. That appears unlikely anytime soon.

In addition, while FERC initially proposed allowing applicants to simultaneously initiate the pre-filing process with Commission and apply for siting authority from the relevant state authority, after further consideration, Order No. 1977 declines to adopt simultaneous processing. As a result, applicants will still be required to wait at least one year after the relevant state applications have been filed before initiating the pre-filing process at the Commission. While Order No. 1977 acknowledges striking a balance between efficient process and respect for States’ primacy in siting transmission infrastructure, the Commission noted that it continues to believe the statute allows parallel state and Commission processes and signaled that it may reexamine the issue at a later time.