Thought Leadership

FERC Issues Consequential Final Rules on Transmission Grid Development

Client Updates

Rules are Designed to Ensure the Transmission Grid
Can Reliably Meet the Needs of the Energy Transition

       On May 13, 2024, the Federal Energy Regulatory Commission (Commission) issued two orders designed to facilitate expansion of the interstate transmission grid.

       Order No. 1920, Building for the Future Through Electric Regional Transmission Planning and Cost Allocation, fundamentally changes the process for developing major transmission infrastructure in the United States and the method for allocating the costs of that infrastructure to customers.  The Commission approved Order No. 1920, in a 2-1 vote, to address concerns over an absence of sufficiently long-term and comprehensive transmission planning processes, resulting in inefficient investments in transmission infrastructure and piecemeal expansion of the interstate transmission grid.  In the Commission’s view, the lack of sufficient existing long-term regional transmission planning and cost allocation processes to develop effective and cost-efficient transmission solutions led to unjust, unreasonable, and unduly discriminatory rates for consumers.  To remedy these issues, the Commission adopted the reforms highlighted below.

       Separately, the Commission adopted Order No. 1977, Applications for Permits to Site Interstate Electric Transmission Facilities, to clarify the Commission’s authority to issue permits for transmission projects located within national interest electric transmission corridors designated by the U.S. Department of Energy (NIETCs or Transmission Corridors) when necessary permits are denied by state agencies.  The order also establishes the requirements necessary to support Transmission Corridor permit applications submitted to the Commission.

ORDER NO. 1920

Long-Term Regional Transmission Planning

       To ensure meaningful regional transmission planning that adopts a sufficiently long-term, forward-looking basis to identify transmission needs, the Commission is requiring public utility transmission providers to conduct “Long-Range Regional Transmission Planning.”  Long-Range Regional Transmission Planning includes the: (1) identification of transmission needs and transmission solutions through the development of Long-Term Scenarios; (2) evaluation of benefits of regional transmission facilities to meet identified needs over a time horizon that covers, at a minimum, 20 years; and (3) establishment of transparent and not unduly discriminatory criteria to select efficient and cost-effective Long-Term Regional Transmission Facilities for the purposes of cost allocation.  Specific elements of Long-Range Transmission Planning include:

  • Use of Long-Term Scenarios.   The Commission is requiring the use of Long-Term Scenarios—a hypothetical sequence of events that includes assumptions about the future electric power system—to forecast long-term transmission needs. Public utility transmission providers would be required to develop sets of a least three scenarios, update the scenarios at least once every five years, and use “best available data” (e.g., data inputs that are timely and developed using best practices and diverse and expert perspectives) in the development of the scenarios.  In developing these scenarios, utilities must incorporate, at a minimum: (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.  Transmission providers are prohibited from discounting the first three categories of factors because the Commission finds they are more certain drivers of Long-Term Transmission Needs.  In contrast, Transmission Providers have discretion in how they account for the last four categories of factors.  While scenarios must be updated every five years, transmission providers are required to complete the Long-Term Regional Transmission Planning cycle and determine whether to select Long-Term Regional Transmission Facilities no later than three years from the date the cycle began.

  • Geographic Zones.  The Commission declined to adopt the proposed requirement that public utility transmission providers consider whether to identify, with stakeholder input, specific geographic zones within the transmission planning region that have the potential for development of large amounts of new generation and assess generation developers’ commercial interest in developing generation within the identified geographic zones.

  • Selection of Transmission Solutions.  After transmission needs are identified through Long-Term Scenarios, the Commission requires public utility transmission providers to evaluate the benefits of potential regional transmission facility solutions (on an individual or portfolio basis) over a time horizon of at least 20 years from the estimated in-service date of the facilities.  There are at least seven economic or reliability benefits that must be included in the evaluation and selection of long-term regional facilities, including: (1) avoided or deferred reliability transmission facilities and aging infrastructure replacement; (2) 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 has provided flexibility to transmission providers, in consultation with stakeholders (including relevant state entities), to ultimately select transmission solutions for their region, provided the selection criteria is transparent and not unduly discriminatory.  The Commission does not require that transmission providers select a Long-Term Regional Transmission Facility, even where a particular transmission facility meets the transmission providers’ selection criteria. The final rule also requires transmission providers to provide state entities and interconnection customers with an opportunity to voluntarily fund the cost of (or a portion of the cost of) a Long-Range Regional Transmission Facility that otherwise would not meet applicable selection criteria.  Finally, Order 1920 requires transmission providers to reevaluate selected projects based on delays, cost overruns, or changes in law.

  • Coordination with Generator Interconnection Processes.  The Commission is requiring greater coordination between regional transmission planning and generator interconnection processes.  Specifically, public utility transmission providers must evaluate regional transmission facilities to address certain identified interconnection-related transmission needs in their existing regional transmission planning and cost allocation process (rather than as part of their Long-Term Regional Transmission Planning as proposed in the Notice of Proposed Rulemaking (NOPR)) to help ensure near-term regional transmission solutions. For a regional transmission facility to address an interconnection-related transmission need, the interconnection-related network upgrades must have been, among other things, identified in at least two interconnection queue cycles during the preceding five years, have a voltage of at least 200 kV, and an estimated cost of at least $30 million.

  • Alternative Transmission Technologies.  The Commission is requiring public utility transmission providers to consider the use of dynamic line ratings, advanced power flow control devices, advanced conductors, and transmission switching in the transmission regional transmission planning process.  The Commission believes the use of these technologies may offer a more efficient or more cost-effective solution in certain circumstances as compared to other regional transmission facilities.

Regional Transmission Cost Allocation  

       The Commission also adopts fundamental reforms to its regional cost allocation methodologies for transmission facilities selected as part of a long-term regional transmission plan.  The Commission requires public utility transmission providers in each transmission planning region to file one or more ex ante cost allocation methods that apply to selected Long-Term Regional Transmission Facilities.  Order No. 1920 adopts a six-month Engagement Period, during which transmission providers must provide a forum for negotiation of a Long-Term Regional Transmission Cost Allocation Method and/or a State Agreement Process that enables meaningful participation by relevant state entities.  The Commission believes that providing state regulators with a formal opportunity to develop a cost allocation method for regional transmission facilities will increase the likelihood that these facilities are sited and developed with fewer costly delays. 

       The State Agreement Process enables one or more states to voluntarily agree to a cost allocation method for a transmission facility or portfolio of facilities either before or no later than six months after selection of those facilities in the regional plan.  However, transmission providers are required to detail in their Open Access Transmission Tariffs the process by which the state entities would reach a voluntary agreement, including the timeline for such processes and the procedures by which such voluntary agreements would be filed with the Commission pursuant to Section 205 of the Federal Power Act.  Note, however, that the ultimate decision to file a Long-Term Regional Transmission Cost Allocation Method and/or State Agreement Process to which relevant state entities have agreed remains with transmission providers.   

Retention of the CWIP Incentive

       The Commission declined to eliminate the Construction Work in Progress (CWIP) incentive for Long-Term Regional Transmission Facilities as had been proposed in the NOPR.  The CWIP incentive allows transmission providers to include 100% of construction costs in rate base prior to the commercial operation of the facilities to improve cash flow in the form of an immediate earned return, rather than delaying recovery of these costs until the facility was placed in service.  

Rejection of a Conditional Federal ROFR

       The NOPR had proposed a federal right of first refusal (ROFR) to incumbent utilities, conditioned on the incumbent transmission provider establishing joint ownership of the regional transmission facilities.  The ROFR would have enabled an incumbent utility to exercise a right to construct regionally cost-allocated transmission facilities located in their retail distribution territory or footprint subject to the incumbent establishing qualifying joint ownership structures with unaffiliated nonincumbent transmission developers or another unaffiliated entity (including another incumbent transmission provider).  Order No. 1920 does not provide for a conditional ROFR, although the Commission has indicated that it will consider potential federal right of first refusal issues in other proceedings.   

Enhanced Transparency of Local Planning Inputs and Opportunities to “Right-Size”

       To increase transparency into local transmission planning processes and increase the coordination between local and regional transmission planning, the Commission is requiring process changes to inform the development of regional transmission plans.  These process changes include disclosure of criteria, models, and assumptions used to inform local transmission planning and publicly noticed stakeholder meetings.  In circumstances where a proposed in-kind facility can be “right-sized” to result in a more efficient or cost-effective transmission facility to meet a need identified by the regional transmission plan, Order No. 1920 requires transmission providers to provide a federal ROFR to an incumbent utility developing a “right-sized” facility.  With respect to cost allocation, the Commission rejected the NOPR’s proposal that only the incremental costs of right-sizing the transmission facility will be eligible for regional cost-sharing.  Rather, the Commission decided to provide flexibility to transmission providers to propose a cost allocation method for selected right-sized replacement transmission facilities.

Interregional Transmission Coordination and Cost Allocation

       Public utility transmission providers in neighboring transmission planning regions are required to have procedures for: (1) sharing information regarding the respective transmission needs of each region and potential solutions to those needs; and (2) the identification and joint evaluation of interregional transmission facilities that may be more efficient or cost-effective transmission facilities. Transmission providers are required to revise their interregional transmission coordination processes to incorporate the long-term transmission planning reforms adopted in Order No. 1920.
Effective Date and Compliance Filings

       Order No. 1920 will become effective 60 days after publication in the Federal Register.  Transmission providers must submit a compliance filing to the Commission within 10 months of the effective date, although the submission of a compliance filing to address Order No. 1920’s interregional transmission coordination requirements is required within 12 months of the effective date.   

Christie Dissent

       Order No. 1920 did not receive unanimous support as Commissioner Christie issued a 78-page dissent asserting the order exceeds FERC’s authority under the Federal Power Act and fails to protect consumer interests.  Commissioner Christie believes “the final rule inflicts staggering costs on consumers by promoting the construction of trillions of dollars of transmission projects, not to serve consumers in accordance with the FPA, but to serve a major policy agenda never passed by Congress, to serve the profit-making interests of developers of politically preferred generation, primarily wind and solar, and to serve corporate “green energy” preferential purchasing policies.”

ORDER NO. 1977

       The Commission issued Order No. 1977 to address amendments to Section 216 of the Federal Power Act enacted as part of the Infrastructure Investment and Jobs Act of 2021 (Jobs Act).  Section 216(a) authorizes the U.S. Department of Energy to designate certain transmission-congested or congested geographic areas as National Corridors. Section 216(b) authorizes the Commission, under certain circumstances, to issue permits for the construction or modification of electric transmission facilities in National Corridors.  Among other things, the Jobs Act clarified that the Commission’s authority to issue permits is triggered when a state commission or other entity with authority to approve the siting of transmission facilities has (i) not made a determination on a siting application by one year after the later of the date on which the application was filed or the date on which the relevant National Corridor was designated; (ii) conditioned its approval such that the proposed project will not significantly reduce transmission capacity constraints or congestion in interstate commerce or is not economically feasible; or (iii) denied an application.  The Jobs Act also requires the Commission to determine—as a precondition to the exercise of eminent domain authority—whether a permit holder has made a good faith effort to engage with landowners and other stakeholders early in the permitting process.

       Order No. 1977 revises the Commission’s regulations (Parts 50 and 380) to align with the requirements of the Jobs Act and clarify the information needed to support a permit application to the Commission.  Specifically, applicants will be required to comply with an “Applicant Code of Conduct” as one mechanism to demonstrate a good faith effort to engage and work constructively with affected landowners early in the permitting process. The Code of Conduct includes recordkeeping and information-sharing requirements addressing engagement with affected landowners, and general prohibitions against certain misconduct during stakeholder engagement.  Order No. 1977 also requires applicants to develop engagement plans to govern outreach to environmental justice communities and Indian Tribes.  A Tribal Engagement Plan will be required as part of an applicant’s Project Participation Plan.  The Project Participation Plan: (1) identifies specific tools and actions to facilitate stakeholder communications and public information; (2) lists locations throughout the project area where the applicant will provide copies of all project filings; and (3) explains how the applicant intends to respond to requests for information from the public and other entities.  The Commission also adopted its proposal to require an Environmental Justice Public Engagement Plan as a component of the Project Participation Plan.  In a departure from the NOPR, the Commission determined that applicants should not begin the FERC prefiling process under Section 216 until one year after relevant state applications have been filed.

       Regarding applicant-prepared resource reports filed in support of a permit application, Order No. 1977 clarifies the Commission’s informational requirements including the preparation of reports to address air quality and environmental noise; environmental justice considerations; and effects on Indian Tribes and tribal resources.  Each report must address a project’s potential impacts and describe proposed mitigation measures to address those impacts.

       Order No. 1977 will become effective 60 days after publication in the Federal register.


       These two orders represent the most substantial reforms to the Commission’s transmission policies in over a decade.  Order No. 1920, in particular, will significantly impact the manner in which transmission infrastructure is planned, developed, constructed, and cost-allocated. We expect that, as with any major agency rule, several stakeholders will seek rehearing of Order No. 1920 and, ultimately, judicial review of FERC’s new transmission planning and cost allocation policies.

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