May 22, 2024 | 18 minute read

On May 13, 2024, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued a landmark final rule implementing transmission planning and cost allocation reforms intended to promote the more efficient and cost-effective integration of new renewable generation and battery energy storage resources and help meet the needs of a rapidly evolving grid. Order No. 1920 (the “Final Rule”) adopts a variety of requirements concerning how transmission providers conduct and update long-term transmission plans, evaluate the relative benefits of new investment in transmission facilities, identify opportunities to replace existing transmission infrastructure to enhance transfer capability and allocate costs among customers. The Final Rule also seeks to expand states’ role in planning, selecting and allocating the costs of transmission facilities.

The Final Rule passed with a narrow margin, with the support of two of the three sitting FERC Commissioners. Notably, Allison Clements, who voted in support of the Final Rule, will be departing FERC as soon as June 30, 2024. Three new commissioners are currently progressing through the Senate confirmation process. Therefore, it is possible that a “new” FERC (expected to be five seated commissioners, including three new members and one member, Commissioner Mark Christie, squarely opposed to the Final Rule) may modify the reforms on rehearing. FERC is certain to receive requests for rehearing and clarification and is under no obligation to rule on such requests. Therefore, it may take some time before FERC issues an order on rehearing in this proceeding.

I. Background

The Final Rule follows a Notice of Proposed Rulemaking (“NOPR”), issued on April 21, 2022, which received more than 15,000 pages of comments from nearly 200 interested stakeholders – the largest procedural record in the Commission’s history. The Final Rule represents a further evolution of the transmission planning reforms it adopted over more than 25 years in Order No. 888, Order No. 890 and Order No. 1000. Taken together, these transformative prior reforms required open access to the transmission facilities owned by FERC jurisdictional transmission providers and required transmission providers to participate in regional planning that included consideration of transmission needs driven by public policy requirements. In the Final Rule, the Commission found that these processes do not proactively identify transmission needs nor develop much needed solutions associated with a rapidly changing resource mix. Therefore, the reforms implemented through the Final Rule are intended to implement long-term transmission planning and incent the near-term development of cost-effective transmission solutions.

II. Executive Summary of Final Rule

The Final Rule’s primary reforms require transmission providers to

  • Participate in a regional transmission planning process. In doing so, transmission providers must do the following:
    1. Develop Long-Term Scenarios for Long-Term Regional Transmission Facilities (“LTRTFs”) to meet Long-Term Transmission Needs;
    2. Use and measure no less than a set of seven specific, enumerated benefits to evaluate LTRTFs over a horizon of at least 20 years; and
    3. Evaluate LTRTFs to determine whether more efficient or cost-effective solutions exist to meet Long-Term Transmission Needs.
  • Revise their Open Access Transmission Tariffs (“OATTs”) to include, among other mechanisms, processes for evaluating LTRTFs that include descriptions of how the LTRTFs will measure the required benefits and selection criteria for new facilities. These processes must be transparent, not unduly discriminatory and rely on the best available data.
  • Consult with and seek support from Relevant State Entities during the development and implementation of the transmission provider’s evaluation and selection processes.
  • Evaluate, for possible selection in the regional transmission plan and corresponding cost allocation, regional transmission facilities to address interconnection-related needs that meet the following criteria:
    1. Have been identified in at least two interconnection queue cycles during the preceding five years;
    2. Have a voltage of at least 200 kV and an estimated cost of at least $30 million;
    3. Have not been developed due to the withdrawal of interconnection customers; and
    4. Have no network upgrades identified to address the need in an executed GIA or in an unexecuted GIA on file with the Commission.
  • Revise the regional transmission planning processes in their OATTs to enhance the transparency of various inputs to those processes. Among the requirements for compliance is a mandate that transmission providers conduct specific stakeholder meetings at various stages of their planning processes.
  • File one or more ex ante cost allocation methods that apply to selected LTRTFs. The proposed cost allocation methods must allocate costs in a manner that is at least roughly commensurate with the estimated benefits on a fact-specific basis.
  • Convene a six-month planning period with Relevant State Entities to define a State Agreement Process. If an agreement is reached and the transmission provider elects to implement the State Agreement Process, it must file with FERC to amend its OATT accordingly.
  • Evaluate whether an individual transmission facility slated to be replaced in-kind with a new transmission facility can be modified to increase that facility’s transfer capacity, in lieu of in-kind replacement.
  • Implement a limited ROFR for transmission providers electing to “right-size” facilities under certain circumstances.

Notably, the Final Rule does not do the following:

  • Adopt any changes to Order No. 1000 to permit the exercise of a federal ROFR for incumbent transmission providers, except for transmission providers electing to “right-size” facilities under certain circumstances.
  • Implement any changes to the existing interregional transmission coordination and cost allocation requirements of Order No. 1000.
    • Although the Final Rule directs transmission providers to exchange information regarding Long-Term Regional Transmission Planning in existing interregional transmission planning processes, this change does not otherwise fundamentally alter the existing interregional transmission planning regulatory framework.
  • Restrict the availability of the Construction Work in Progress (“CWIP”) incentive for transmission providers developing LTRTFs, leaving the door open for transmission providers to seek authorization from FERC to recover 100% CWIP in rate base for specific projects.

III. Commissioner Mark Christie’s Dissent

In a lengthy dissent, Commissioner Mark Christie argues that the Final Rule exceeds FERC’s legal authority, does not preserve the role of states in transmission planning and fails to protect consumers. Commissioner Christie describes the Final Rule as a “shell game” that conflates transmission projects that solve a reliability problem or reduce congestion with those intended to support renewable energy, imposes planning requirements that favor the selection of such projects and allocates the costs of such projects to consumers in states that have not affirmatively supported the underlying policy goals. He asserts that the Final Rule is beyond the authority delegated to the Commission by Congress and, therefore, is not entitled to deference under Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc.[1] Furthermore, Commissioner Christie argues that the Final Rule is the epitome of the improper expansion of a limited grant of authority in violation of the Major Questions Doctrine established in West Virginia v. EPA.[2]

Commissioner Christie’s dissent is notable because it may provide a partial roadmap to those seeking to challenge the Final Rule on appeal and also previews arguments the new commissioners expected to join FERC in the near term may consider. In fact, industry stakeholders have already expressed public disapproval of the Final Rule, echoing some of the points raised in Commissioner Christie’s dissent.[3]

IV. Compliance

The Final Rule requires FERC jurisdictional transmission providers to submit compliance filings consistent with the Final Rule’s requirements approximately one year from now. More specifically, compliance filings are due ten months after the effective date of the Final Rule, and the Final Rule will become effective 60 days after its publication in the Federal Register. As context regarding the approximate compliance deadline of one year, the Commission has extended compliance filing deadlines associated with prior major rulemaking proceedings. For example, in connection with the interconnection reforms of Order No. 2023, the Commission extended several times what may have been an overly aggressive compliance deadline that was established in the initial order. Also, it may take some time to publish the Final Rule in the Federal Register – there is no set deadline for such publication. Therefore, the actual deadline could be a year or longer from now, even if the Commission does not extend the deadline. The Commission may decide not to grant any extension, given its strongly stated preference to implement these reforms as soon as possible.

V. Detailed Summary of Final Rule

A. Long-Term Regional Transmission Planning

The Final Rule builds on the directives established in FERC Orders No. 890 and 1000 that transmission providers in each transmission planning region participate in a regional transmission planning process. However, the Final Rule introduces new mandates intended to prevent inefficient and piecemeal transmission development and, at the same time, acknowledges the inherent uncertainty involved in long-term transmission planning. Specifically, subject to extensive specifications, FERC will require transmission providers in each transmission planning region to do the following:

  1. Identify Long-Term Transmission Needs and LTRTFs to meet those Transmission Needs through the development of certain Long-Term Scenarios;
  2. Use and measure no less than a set of seven specified and required benefits to evaluate LTRTFs over a time horizon that covers, at a minimum, 20 years; and
  3. Evaluate LTRTFs to determine whether they are more efficient or cost-effective transmission solutions to meet Long-Term Transmission Needs and use selection criteria that provide the opportunity for transmission providers to select such LTRTFs.

A summary of the principal qualifications for compliance with each of the above requirements is provided below.

1. Developing Long-Term Scenarios

The Final Rule directs transmission providers to develop Long-Term Scenarios to identify Long-Term Transmission Needs that will materialize in any period during the 20 years or more following the commencement of the Long-Term Regional Transmission Planning cycle. Transmission providers in each planning region must “reassess and revise” the data inputs and factors used in these Long-Term Scenarios at least once every five years.

FERC will require transmission providers to develop at least three distinct and plausible Long-Term Scenarios that, at a minimum, incorporate the following seven factors:

  1. Federal, state, and local laws and regulations that affect the future resource mix and demand;
  2. Federal, state, and local laws and regulations on decarbonization and electrification;
  3. State-approved utility integrated resource plans and expected supply obligations for load-serving entities;
  4. Trends in technology and fuel costs within and outside of the electricity supply industry, including shifts toward electrification of buildings and transportation;
  5. Resource retirements;
  6. Generator interconnection requests and withdrawals; and
  7. Utility and corporate commitments and federal, state, and local goals that affect the future resource mix and demand.

2. Evaluating the Benefits of Regional Transmission Facilities

The Final Rule requires transmission providers to measure a set of seven required benefits (“Required Benefits”) for Long-Term Transmission Facilities under each Long-Term Scenario in their Long-Term Regional Transmission Planning. Transmission providers must also use the Required Benefits in evaluating LTRTFs. The seven Required Benefits are as follows:

  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.

Transmission providers will be required to include in their OATTs a description of how they will measure each of the Required Benefits, though they may include additional benefits in addition to the specified Required Benefits. In measuring benefits for the selection of LTRTFs, transmission providers must calculate the benefits over those facilities over a time horizon covering, at a minimum, 20 years from the estimated in-service date of the transmission facilities. Transmission providers may, but are not required to, use a “portfolio approach” when evaluating the benefits of LTRTFs. The Final Rule does not adopt the NOPR proposal to require a minimum 20-year horizon to calculate benefits for cost allocation purposes.

3. Evaluation and Selection of Long-Term Regional Transmission Facilities

The Final Rule compels transmission providers to include in their OATTs an evaluation process, including selection criteria, that they will use to identify and evaluate LTRTFs for potential selection to address Long-Term Transmission Needs. Transmission providers must also designate a point in the evaluation process at which they will determine whether to select or not select LTRTFs for cost allocation. Consistent with Order No. 1000, the developer of a Long-Term Regional Transmission Facility selected will be eligible to use the cost allocation method applicable to that facility.

In proposing evaluation processes, including selection criteria, transmission providers must be sure their methods are transparent and not unduly discriminatory. Put another way, transmission providers’ evaluations of transmission facilities must result in determinations sufficiently detailed for stakeholders to understand why particular LTRTFs were or were not selected. These evaluations must estimate the costs and benefits of the LTRTFs identified for potential selection alongside the consideration of other factors. Transmission providers must also include in their OATTs provisions that require them to reevaluate previously selected projects when they are significantly delayed or subject to significant cost overruns.

Relevant State Entities[4] will play a role in the development of a transmission provider’s evaluation processes and selection criteria. Specifically, transmission providers must consult with and seek support from Relevant State Entities regarding the evaluation processes and selection criteria to be used. While state support is not a prerequisite to compliance, transmission providers must demonstrate on compliance the good-faith efforts made to consult with and seek support from Relevant State Entities.

Transmission providers in each transmission planning region will be required to, as part of their compliance filing, propose a date, within one year of the compliance deadline under the Final Rule, on which they will commence their first Long-Term Regional Transmission Planning Cycle.

B. Coordination with the Generator Interconnection Process

In the NOPR proposal, the Commission proposed requiring transmission providers to account for certain interconnection-related transmission needs identified through the interconnection process in their Long-Term Regional Transmission Planning. In the NOPR, the Commission expressed concern regarding the tendency for certain needs to be repeatedly identified in interconnection studies, only to have these needs never constructed due to withdrawal of generation resources from the interconnection process. In response to the NOPR, some commenters suggested that “the most significant factor” causing the withdrawal of generation resources from the interconnection queue is typically the cost of assigned interconnection-related network upgrades, while others argue this is an incorrect assumption.[5]

To address this issue, the Final Rule requires transmission providers in each transmission planning region to revise the regional transmission planning processes in their OATTs to evaluate for possible selection in the regional transmission plan and corresponding cost allocation, regional transmission facilities to address interconnection-related needs associated with certain interconnection-related network upgrades originally identified through the interconnection process. Unlike the NOPR proposal, the Final Rule requires transmission providers to conduct this evaluation through their existing Order No. 1000 regional transmission planning and cost allocation processes, rather than in Long-Term Regional Transmission Planning. This approach is intended to allow transmission providers to adopt an evaluation method and selection criteria from existing processes, such as economic or reliability processes to evaluate and select transmission facilities. The Commission asserts this “permit[s] transmission providers to propose the best method to incorporate this requirement within their existing regional transmission planning processes.”[6]

The Final Rule also requires transmission providers to evaluate regional transmission facilities to address interconnection-related needs that satisfy both the minimum cost and voltage criteria in the NOPR proposal to qualify for evaluation selection. Transmission providers must evaluate facilities to address interconnection-related needs that meet the following criteria:

  1. Have been identified in at least two interconnection queue cycles during the preceding five years;
  2. Have a voltage of at least 200 kV and an estimated cost of at least $30 million;[7]
  3. Have not been developed due to the withdrawal of interconnection customers; and
  4. Have no network upgrade identified to address the need in an executed GIA or in an unexecuted GIA on file with the Commission.

The five-year period for the qualifying criteria begins five calendar years prior to the initial effective date of the Commission-accepted tariff provisions proposed to comply with the Final Rule, and the evaluation must occur in the first Order No. 1000 planning cycle beginning after the later-in-time withdrawn interconnection request occurring after the effective date of the Commission-accepted tariff provisions. In limited circumstances where it is possible there may be only one interconnection queue cycle during a five-year period, the Commission clarifies that the criterion should be read to include the interconnection queue cycle immediately preceding the current interconnection queue where the interconnection-related transmission need is identified. In circumstances where there are no queue cycles in the preceding five-year period because the transmission provider uses a first-come, first-served serial interconnection process, if the interconnection-related transmission need is identified in at least two individual interconnection studies during the preceding five-year period for interconnection customers that subsequently withdrew, the first criterion is met.

C. Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices

The Final Rule requires each transmission planning region to consider additional transmission enhancements and advanced technologies for each transmission need identified as part of a transmission planning region’s Long-Term Regional Transmission Planning and existing Order No. 1000 regional transmission planning processes. These additional transmission enhancements and advanced technologies include the following:

  1. Dynamic line ratings;[8]
  2. Advanced power flow control devices;[9]
  3. Advanced conductors; and[10]
  4. Transmission line switching[11]

Transmission providers are required to consider these technologies for both new regional transmission facilities and upgrades to existing facilities and evaluate the extent to which the proposed facilities would be more efficient or cost-effective than transmission facilities that do not incorporate such technology.

The Final Rule clarifies that the transmission providers must, nonetheless, continue to follow the selection criteria in their tariffs. The consideration of the costs and benefits associated with the use of these advanced technologies does not necessarily require their selection and deployment. Instead, transmission providers should continue to follow Good Utility Practice while ensuring that these advanced technologies are considered as part of the evaluation process.

The Final Rule also clarifies that the incorporation of any of the advanced transmission technologies into an existing transmission facility should be treated as an upgrade to an existing transmission facility and, therefore, is not subject to any federal ROFR, and the incumbent transmission provider will be designated as the developer. For advanced transmission technologies added or deployed to a new regional transmission facility, the transmission developer selected to develop the underlying regional transmission facility must also be designated to develop any associated advanced transmission technology, regardless of whether that transmission developer is the incumbent or a nonincumbent transmission developer. As such, the relevant transmission developer or the transmission developer who sponsored the new regional transmission facility would be eligible to use the applicable regional cost allocation method.

D. Regional Transmission Cost Allocation

The Final Rule requires transmission providers in each transmission planning region to file one or more ex ante cost allocation methods that apply to selected LTRTFs. The proposed cost allocation methods must allocate costs in a manner that is at least roughly commensurate with estimated benefits on a fact-specific basis, based on the record in a given proceeding. Transmission providers are required to modify their OATTs to reflect the chosen LTRTF Cost Allocation Method(s). Separately, transmission providers are permitted, but not required, to revise their OATTs to include a State Agreement Process if the relevant state entities agree to such a process. In this way, transmission providers must establish at least one LTRTF Cost Allocation Method and may optionally choose to establish a State Agreement Process.

Notably, if a LTRTF, or portfolio of such projects, is selected, but the State Agreement Process fails to result in an applicable cost allocation methodology or FERC rejects the proposed cost allocation methodology, then the LTRTF Cost Allocation Method that would otherwise apply will control. The Commission reasoned that using the LTRTF Cost Allocation Method as a “backstop” under these circumstances was necessary because, absent this requirement, it is unlikely that the transmission solution would be developed.

Importantly, the cost allocation reforms adopted in the Final Rule apply only to new LTRTFs. Existing regional cost allocation methods will continue to apply to regional reliability and economic transmission facilities that are selected pursuant to existing Order No. 1000 regional transmission planning processes. To the extent a transmission provider believes that its existing cost allocation methodology complies with the requirements set forth in the Final Rule they may make such a demonstration as part of their compliance filing.

1. Coordination with Relevant State Entities

Instead of requiring that a transmission provider seek the agreement of the Relevant State Entities within the transmission planning region, as proposed in the NOPR, The Final Rule establishes a six-month planning period (“Engagement Period”) between the transmission provider and the Relevant State Entities to define a State Agreement Process.[12] As part of the Engagement Period, the transmission provider is required to do the following:

  1. Provide notice of the starting and end dates for the six-month time period;
  2. Post contact information that Relevant State Entities may use to communicate with transmission providers about any agreement among Relevant State Entities on an LTRTF Cost Allocation Method(s) and/or a State Agreement Process, as well as a deadline for communicating such agreement; and
  3. Provide a forum for negotiation of a LTRTF Cost Allocation Method(s) and/or a State Agreement Process that enables meaningful participation by Relevant State Entities.

The Relevant State Entities can utilize existing engagement mechanisms to satisfy this requirement, but transmission providers must still demonstrate compliance with the time period, contact information and deadline for communicating agreement notice requirements outlined above. It is left up to the Relevant State Entities that participate in the Engagement Period to determine if they will use existing state processes for negotiation, what constitutes agreement among Relevant State Entities, how such agreement is reached and which Relevant State Entities must reach such agreement.

The Commission clarifies that it will be the transmission provider’s decision as to whether to file an LTRTF Cost Allocation Method(s) and/or State Agreement Process to which Relevant State Entities have agreed. On compliance, transmission providers must demonstrate that they established and provided notice of an Engagement Period and that they provided a forum for negotiation. After the required initial Engagement Period, a State Agreement Process can include other entities beyond the Relevant State Entities. To the extent a transmission provider chooses to establish a State Agreement Process, the process must be described in proposed tariff revisions to their OATTs. The OATT provisions must describe the following:

  1. The event triggering the beginning of the State Agreement Process;
  2. The duration of the State Agreement Process (not to exceed six months after selection);
  3. The LTRTFs to which the process applies;
  4. How voluntary agreements by the Relevant State Entities may be shared with transmission providers;
  5. Whether the transmission providers voluntarily agree to undertake an obligation to file the agreed-upon cost allocation method with the Commission for consideration under FPA section 205; and
  6. The manner in which a transmission provider would file a section 205 filing to seek Commission acceptance of a cost allocation method resulting from a State Agreement Process.

Once established through the Engagement Period described above, the State Agreement Process can occur either before or no later than six months after the selection of an LTRTF. In any case, the resulting cost allocation method must be filed with the Commission no later than six months after the selection of the LTRTF.

E. Construction Work in Progress Incentive

The Final Rule declines to adopt the restriction proposed in the NOPR that would have prevented transmission providers from taking advantage of the allowance for inclusion of 100% of CWIP in rate base for LTRTFs. As proposed in the NOPR, transmission providers would have still been permitted to accrue carrying costs incurred during the pre-construction or construction phase as Allowance for Funds Used During Construction (“AFUDC”) but would only be able to recover those costs from customers after the project is in service, consistent with the existing accounting principles applicable to that mechanism.

The Commission agrees with comments raised by stakeholders that the CWIP incentive is more appropriately addressed in a separate proceeding as part of a holistic review of transmission incentives after the reforms embodied in this order have been finalized. Therefore, the Commission decides not to make any changes to its CWIP policy in the Final Rule.

F. Exercise of a Federal Right of First Refusal in Commission-Jurisdictional Tariffs and Agreements

One particularly notable aspect of the NOPR proposal was the Commission’s proposal to modify Order No. 1000 to allow incumbent transmission providers to retain a federal ROFR conditioned on a demonstration that the incumbent has established a qualifying joint ownership arrangement with an unaffiliated nonincumbent transmission developer or other unaffiliated entity. In the NOPR, the Commission expressed concern that the ROFR requirements of Order No. 1000 may be discouraging incumbent transmission developers from pursuing the development of regional transmission facilities yet emphasized that competition can promote efficient and cost-effective transmission development. Pursuant to the NOPR proposal, an incumbent transmission provider would be provided with a right to submit a jointly-owned regional transmission facility proposal in partnership with one or more qualifying entities—such as unaffiliated public power entities, load-serving entities or other non-affiliates—before the opportunity to develop the project would be made available to nonincumbents.

In the Final Rule, the Commission declines to adopt any changes to Order No. 1000 to permit the exercise of a federal ROFR for incumbent transmission providers.[13] The Commission acknowledges commenters’ concerns about whether incumbent transmission providers actually face perverse investment incentives to develop and advocate for transmission facilities that benefit more than just their own local retail distribution service territory or footprint because of Order No. 1000’s reforms, including additional concerns that the Commission’s NOPR proposal would actually address the Commission’s unsubstantiated concerns. The Commission asserts that although it did not adopt any ROFR reforms in the Final Rule, it will continue to consider potential federal ROFR reforms in the future. As discussed below, the Final Rule does require the establishment of a federal ROFR for a right-sized replacement transmission facility that is selected to meet Long-Term Transmission Needs.

G. Local Transmission Planning Inputs in the Regional Transmission Planning Process

In the Final Rule, FERC concludes that “existing requirements governing transparency in local transmission planning processes and coordination between local and regional transmission planning processes are unjust, unreasonable and unduly discriminatory or preferential.”[14] Accordingly, the Final Rule requires transmission providers to enhance the transparency of local transmission planning processes and evaluate whether transmission facilities that need replacing can be “right-sized” to more efficiently or cost-effectively address Long-Term Transmission Needs identified in Long-Term Regional Transmission Planning.

​​​​​​​1. Enhancing Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process

As to transparency, the Final Rule requires transmission providers to revise the regional transmission planning processes in their OATTs to enhance the transparency of the following:

  1. The criteria, models, and assumptions used in their local transmission planning processes;
  2. The local transmission needs that they identify through the local transmission planning process; and
  3. The potential local or regional transmission facilities that they will evaluate to address those local transmission needs.

For each of these categories of local transmission planning information, transmission providers must identify and publicly post the information identified, then conduct focused, publicly noticed stakeholder meetings at various stages of their planning. This requirement applies only to local transmission planning that is within the scope of Order No. 890, but nothing in the Final Rule prohibits transmission providers from choosing to apply these requirements to asset management projects.

​​​​​​​​​​​​​​2. Identifying Potential Opportunities to “Right-Size” Replacement Transmission Facilities

FERC defines “right-sizing” as the process of modifying a transmission provider’s in-kind replacement of an existing transmission facility to increase that facility’s transfer capacity.” Put simply, FERC will require transmission providers to consider whether modifications to increase the transfer capacity of a transmission facility would be more cost-effective or efficient than full replacement of that facility, particularly where the in-kind replacement would result in no more than an incidental increase in capacity over the existing facility. The Final Rule requires transmission providers to evaluate whether,

  1. Transmission facilities are operating above a specified kV threshold, and
  2. An individual transmission provider that owns the transmission facility anticipates replacing in-kind with a new transmission facility during the next 10 years that can be “right-sized” to address a Long-Term Transmission Need more efficiently or cost-effectively.

Importantly, the Final Rule requires the establishment of a federal ROFR for a right-sized replacement transmission facility that is selected to meet Long-Term Transmission Needs. This limited ROFR will apply to the transmission provider that included in its in-kind replacement estimate the existing transmission facility that right-sized replacement facility would replace and extends to any portion of the right-sized replacement facility within the transmission provider’s footprint. This federal ROFR is an exception to Order No. 1000’s general requirement to eliminate the federal ROFR for regional transmission facilities. Additionally, transmission providers must provide transparency with respect to which right-sized replacement transmission facilities will be included in the regional transmission plan for cost allocation purposes.

Please do not hesitate to reach out with any questions you may have.

[1] 467 U.S. 837 (1984).

[2] 597 U.S. 697 (2022).

[3] See, e.g., Nat’l Ass. Of Reg. Util. Commr’s, NARUC Expresses Disappointment in FERC’s Order on Transmission Planning, Press Release (May 14, 2024)

[4] Relevant State Entities are defined as “any state entity responsible for electric utility regulation or siting electric transmission facilities within the state or portion of a state located in the transmission planning region, including any state entity as may be designated for that purpose by the law of such state.” (emphasis added). The Final Rule revised the definition proposed in the NOPR to include electric to clarify that the state agencies within the scope of the definition are only those responsible for electric utility regulation, not other types of utility regulation.

[5] Final Rule at PP 1083, 1090.

[6] Id. at P 1111.

[7] As compared to the NOPR proposal, the Final Rule to requires the network upgrade identified to meet the need has a voltage of at least 200 kV and (rather than “or”) an estimated cost of at least $30 million. This modification narrows the scope of the requirements for evaluation and the Commission’s reform.

[8] For the purposes of the Final Rule, dynamic line ratings are defined in the same way as proposed in the NOPR, “a transmission line rating that applies to a time period of not greater than one hour and reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating, transmission line tension, or transmission line sag.”

[9] For the purposes of the Final Rule, advanced power flow control devices are defined in the same way as proposed in the NOPR, devices that serve a transmission function and “can help the system operator control power flows over a given path and can include phase shifting transformers (also known as phase angle regulators) and devices or systems necessary for implementing optimal transmission switching. Advanced power flow control devices allow power to be pushed and pulled to alternate lines with spare capacity leading to maximum utilization of existing transmission capacity.”

[10] Advanced conductors were not proposed in the NOPR, but for the purposes of the Final Rule, include “present and future transmission line technologies whose power flow capacities exceed the power flow capacities of conventional aluminum conductor steel reinforced conductors.”  This includes but is not limited to superconducting cables, advanced composite conductors, advanced steel cores, high temperature low-sag conductors, fiber optic temperature sensing conductors, and advanced overhead conductors.

[11] Transmission line switching was not proposed in the NOPR, but for the purposes of the Final Rule, is defined as “the opening or closing of transmission elements to safely route power and direct flows away from congestion, based on pre-existing forward analysis.”

[12] The State Agreement Process is defined as “a process by which one or more Relevant State Entities may voluntarily agree to a cost allocation method for Long-Term Regional Transmission Facilities (or a portfolio of such Facilities) either before or no later than six months after the facilities are selected in the regional transmission plan for purposes of cost allocation.”

[13] Note that the Commission did adopt a narrow federal ROFR for “right-sized” replacement transmission facilities, discussed further below.

[14] Final Rule at P 1569.

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