Summary: Divided FERC Issues Order No. 1920—Makes Sweeping and Controversial Changes to Transmission Planning and Cost Allocation Rules

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May 21, 2024

Legal Update

On May 13, 2024, the Federal Energy Regulatory Commission (FERC) issued its long-awaited Final Rule, Building for the Future Through Electric Regional Transmission Planning and Cost Allocation. FERC’s Chairman, Willie Phillips, believes that the new rule is so historic that it was designated Order No. 1920, invoking the year that the original Federal Power Act (FPA) first became law and FERC’s predecessor, the Federal Power Commission, was formed.

The underlying premise of Order No. 1920 is that there are deficiencies in FERC’s existing regional and local transmission planning and cost allocation requirements that must be remedied under FPA section 206. FERC is therefore requiring all public utility transmission providers to “conduct Long-Term Regional Transmission Planning that will ensure the identification, evaluation, and selection, as well as the allocation of the costs, of more efficient or-cost-effective regional transmission solutions to address Long-Term Transmission Needs.” Other FERC directives are intended to “improve coordination of regional transmission planning and generator interconnection processes, require consideration of certain alternative transmission technologies in regional transmission planning processes, and improve transparency of local transmission planning processes and coordination between regional and local transmission planning processes.”

Order No. 1920 was adopted by a 2-1 party-line vote. The joint concurrence by FERC’s two Democrats, Chairman Willie Phillips and Commissioner Alison Clements, states that Order No. 1920 will create a “forward-looking, comprehensive, and holistic transmission planning and cost allocation framework” that provides “transmission planners with the maximum flexibility we can legally allow in order to facilitate negotiated, regionally appropriate, solutions.” They also state that Order No. 1920 gives states “unprecedented, expanded opportunities to work with transmission providers to shape the cost allocation approaches of their regions.”

FERC’s lone Republican Commissioner, Mark Christie, strongly disagrees and systematically attacked the Final Rule in a 77-page dissent. Christie argues that Order No. 1920 is:

[A] pretext to enact, through administrative action, a sweeping legislative and policy agenda that Congress never passed. The final rule claims statutory authority the Commission does not have to issue an absurdly complex bureaucratic blizzard of mandates and micromanagement to be imposed on every transmission provider in the United States for the transparent goal of spending trillions of consumers’ dollars on transmission not to serve consumers in accordance with the FPA, but instead to serve political, corporate, and other special-interest agendas that were never enacted into law. (Footnotes omitted).

Commissioner Christie’s core objection is that Order No. 1920 is likely to result in consumers in some states having to pay the costs for transmission facilities that do not actually benefit them but rather serve the policy objectives of other states or large corporate energy buyers. According to Commissioner Christie, the Final Rule is a “shell game” that requires transmission planners to consider ”pre-cooked” inputs that will necessarily result in the selection of “green energy” projects. He also argues that the Final Rule: (i) is so fundamentally different from the NOPR that it should have been issued as a new proposal for notice and comment; (ii) exceeds FERC’s authority under the FPA; (iii) trespasses into jurisdictional terrain reserved to the states under FPA section 201; (iv) violates the “major questions” doctrine; (v) is not based on a record that justifies Commission action under FPA section 206; (vi) adopts “reforms” that are not just and reasonable; (vii) deprives the states of their proper role in planning and cost allocation; (viii) will impose costs associated with state clean energy policy choices, and corporate clean energy purchasing programs, on “non-consenting” states; and (ix) represents an abandonment of FERC’s consumer protection responsibilities.

The joint concurrence by Chairman Phillips and Commissioner Clements counters by arguing that the dissent “misrepresents” both the content of the Final Rule and applicable law. They deny that Order No. 1920 is materially different from what was proposed in the NOPR or designed to drive particular outcomes. They claim that Commissioner Christie’s approach would not foster needed transmission expansion and would create a “free rider” problem.

The stark partisan split over Order No. 1920 clouds the Final Rule’s future in a way that is unusual for major FERC rules. Past FERC Chairmen have often said that FERC “speaks loudest,” and produces more legally durable rules, when it “speaks with one voice.” In this case, FERC is sharply divided. Commissioner Christie’s dissent likely will serve as a roadmap for petitions for judicial review. Meanwhile, the Commissioners have continued to argue their positions in social media posts and interviews. Commissioner Christie has pointed to statements by Democratic politicians[1] and newspaper accounts to support his claim that Order No. 1920 “was literally orchestrated by politicians on Capitol Hill” even though, “FERC is supposed to be independent.”[2] Commissioner Clements has repeated her claims that “ Commissioner Christie strikingly mischaracterizes the rule and how far it goes,” while insisting that Order No. 1920 represents “just one important step on a longer staircase, forged through compromise.”[3]

Order No. 1920 has also already drawn close attention in Congress. Democrats have generally praised the Final Rule as consistent with clean energy policies while Republicans, echoing Commissioner Christie, have attacked it as a scheme to make red states pay for blue states’ environmental preferences. It has been suggested that adoption of the Final Rule will put an end to efforts to enact energy permitting legislation. It also seems likely that there will be hearings addressing the Final Rule and perhaps even investigations into FERC’s independence. The three nominees to become FERC Commissioners, who are expected to be voted on by the Senate Energy and Natural Resources Committee in June, may be negatively impacted by the controversy. Finally, if the White House changes hands in 2024, FERC will be under new leadership and may have a majority of Republican Commissioners, in 2025. Order No. 1920 might then be substantially changed or even withdrawn by a different group of Commissioners in the near future.

EXECUTIVE SUMMARY

Order No. 1920 requires transmission providers to take the following major actions:

Develop a Long-Term Regional Transmission Plan at least every five years using at least a 20-year time horizon and Long-Term Scenario planning to identify Long-Term Transmission Needs through the consideration of seven categories of factors that may drive such transmission needs;
Identify and evaluate proposed transmission facilities for addressing Long-Term Transmission Needs using seven specified benefits to determine more efficient or cost effective transmission solutions and to determine whether to select a Long-Term Transmission Facility for cost allocation under the transmission provider’s Open Access Transmission Tariff (OATT);
Develop ex ante Long-Term Regional Transmission Cost Allocation Methods, with the opportunity to include a State Agreement Process, to allocate the costs of selected Long-Term Transmission Facility that address Long-Term Transmission Needs, including what FERC’s majority describes as increased opportunities for coordination with states in developing such methodologies;
Provide for reevaluations of selected Long-Term Transmission Facilities to address delays or cost overruns;
Consider the use of grid enhancing technologies in transmission projects (e.g., dynamic line ratings);
Consider transmission facilities to address interconnection-related needs identified multiple times in the interconnection process but not built;
Enhance the stakeholder process for reviewing local transmission planning;
Provide for the opportunity to “right size” replacement transmission facilities; and
Revise existing interregional transmission coordination processes to reflect the new Long-Term Regional Transmission Planning cycle requirements.

These requirements are summarized in Parts II-XIII below.

Order No. 1920 is also notable for the topics that FERC opted not to address at this time. The Advanced Notice of Proposed Rulemaking and Notice of Proposed Rulemaking (NOPR) that preceded Order No. 1920 sought comment on a number of issues related to transmission cost management. These included a proposal to restore a federal right of first refusal to Transmission Owners that would jointly own transmission facilities with non-affiliates. Many parties argued that this controversial proposal represented a retreat from the competitive transmission development rules adopted in FERC’s Order No. 1000. Similarly, many NOPR commenters had urged FERC to establish “independent transmission monitors,” akin to independent market monitors, or take other steps to control transmission development costs. Order No. 1920 did not act on any of these proposals but suggested that they could be taken up in the future, perhaps through the pending proceeding in Docket No. AD22-8 on Transmission Planning and Cost Management. But that proceeding is at a very early stage so it is unlikely that FERC will be adopting “cost management” requirements any time soon. Finally, with limited exceptions, the proposed new rules do not modify FERC’s existing requirements for regional transmission planning for reliability or economic transmission needs or for interregional transmission planning.

Order No. 1920’s new transmission planning and cost allocation requirements will become effective 60 days after the Final Rule is published in the Federal Register. Transmission providers will have 10 months from the effective date to submit compliance filings on regional transmission matters and 12 months to make filings addressing regional coordination issues. Transmission providers that are not FERC-jurisdictional public utilities must still comply with all of Order No. 1920’s requirements if they wish to continue to receive transmission service from FERC-jurisdictional providers under FERC’s “reciprocity” rules.

Requests for rehearing of Order No. 1920 are due on June 12.

I. FERC’s Rationale for Action[4]

In Order No. 1920, FERC determined under FPA section 206 that there was substantial evidence to conclude that FERC’s existing regional transmission planning and cost allocation requirements are unjust, unreasonable, and unduly discriminatory or preferential. Specifically, FERC concluded that the absence of long-term and comprehensive transmission planning requirements is causing transmission providers to inadequately anticipate and plan for future threats to their systems, thereby resulting in piecemeal transmission expansion focused only on short-term transmission needs. FERC emphasized that transmission investment decisions are currently occurring outside of regional transmission planning processes and inside the much more short term-focused generator interconnection and local transmission planning processes. This piecemeal arrangement, FERC concluded, is causing transmission providers to make inefficient investments in transmission infrastructure, the costs of which are ultimately passed onto consumers through rates. FERC expects that what it calls Long-Term Regional Transmission Planning—i.e., planning on a sufficiently long-term and forward looking basis to identify Long-Term Transmission Needs and the facilities that meet those needs—will reduce these inefficiencies and costs to consumers.

Some critics alleged that FERC is attempting to steer the resource mix toward certain preferred resources, especially renewables. FERC denied these comments, asserting that Order No. 1920 is meant to account for changes occurring outside of FERC’s jurisdiction, including resource decisions that fall under the states’ exclusive jurisdiction, as well as the increasing frequency of extreme weather events, changes in customer preferences, and demand growth, among other things.

In his dissent, Commissioner Christie alleged that Order No. 1920 favors states that are shaping the resource mix towards their preferred forms of renewable generation. The Final Rule, he argued, is meant “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.” On this basis, he concluded that the Final Rule is not entitled to deference under Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc. In response, Chairman Philips and Commissioner Clements denied that Order No. 1920 is based on a political agenda or favoritism towards certain resources, emphasizing that state efforts to shape the resource mix are only one of the many factors shaping future transmission needs that transmission providers must consider under the Final Rule.

II. Mandatory Long-Term Regional Transmission Planning[5]

To remedy the perceived inadequacies of the existing regional transmission planning process, FERC adopted the NOPR proposal requiring transmission providers in each transmission planning region to engage in Long-Term Regional Transmission Planning. In addition to needing to comply with the existing planning principles adopted in Order Nos. 890 and 1000, Long-Term Regional Transmission Planning must: (1) identify Long-Term Transmission Needs and Long-Term Regional Transmission Facilities to meet those needs through the development of Long-Term Scenarios; (2) use and measure at least seven required benefits for evaluating Long-Term Regional Transmission Facilities over a time horizon that covers at least 20 years starting from the estimated in-service date of each transmission facility; and (3) evaluate Long-Term Regional Transmission Facilities 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 Long-Term Regional Transmission Facilities. FERC emphasized that the Final Rule is focused on the process of long-term planning and not any particular substantive outcomes.

FERC rejected arguments that Long-Term Regional Transmission Planning would introduce excessive uncertainty and speculation into regional transmission planning and that transmission providers would make forecasting errors. Instead, FERC concluded that Order No. 1920 provides transmission providers “a critical tool for managing uncertainty, facilitating regional transmission planning that accounts for a range of potential futures, as well as an assessment of the likelihood of each scenario manifesting, when identifying, evaluating, and selecting Long-Term Regional Transmission Facilities.” According to FERC, Long-Term Regional Transmission Planning also protects against excessive transmission development in response to speculative transmission needs, in part, through stakeholder engagement and “substantial flexibility” granted to transmission providers to select new, or reevaluate existing, Long-Term Regional Transmission Facilities.

Commissioner Christie raised similar concerns. However, he argued that Order No. 1920 was intended to make FERC “a national [integrated resource] planner and bring about a preferred generation mix through transmission planning by manipulating and shaping the future generation mix.” Congress, he stated, never intended for FERC to play this role, and thus the FPA leaves the siting of transmission and the development of generation to the states. In his view, FERC has encroached on the states’ traditional roles without any Congressional authorization.

III. Development of Long-Term Scenarios[6]

With some modifications, FERC adopted the NOPR proposals requiring transmission providers in each transmission planning region to (1) develop and use Long-Term Scenarios as part of Long-Term Regional Transmission Planning and (2) use those Long-Term Scenarios to identify and evaluate Long-Term Regional Transmission Facilities needed to meet Long-Term Transmission Needs. First, FERC defined Long-Term Transmission Needs as “transmission needs identified through Long-Term Regional Transmission Planning by . . . “running scenarios” that meet the requirements described below, and consider seven enumerated “categories of factors” described below. Next, FERC amended the NOPR’s definition of Long-Term Scenarios to mean “scenarios that incorporate various assumptions using best available data inputs about the future electric power system over a sufficiently long-term, forward-looking transmission planning horizon to identify Long-Term Transmission Needs and enable the identification and evaluation of transmission facilities to meet such transmission needs.” FERC anticipates the development of Long-Term Scenarios will mitigate planning uncertainties by allowing transmission providers to (1) evaluate whether Long-Term Regional Transmission Facilities are beneficial in more than one scenario, (2) examine whether Long-Term Transmission Needs appear in one or more scenarios, and (3) determine whether identified Long-Term Regional Transmission Facilities provide sufficient benefits across more than one scenario.

A. Transmission Planning Horizon[7]

FERC adopted the NOPR proposal to require transmission providers in each transmission planning region to adopt Long-term Scenarios using no less than a 20-year transmission planning horizon. FERC clarified that this “means that transmission providers must develop Long-Term Scenarios to identify Long-Term Transmission Needs that will materialize in the 20 years or more following the commencement of the Long-Term Regional Transmission Planning cycle.” This 20-year horizon is designed to provide enough time to fully develop Long-Term Regional Transmission Facilities.

B. Frequency of Long-Term Scenario Revisions[8]

Order No. 1920 requires transmission providers to reassess and revise Long-Term Scenarios every five years, instead of every three years as the NOPR proposed. Thus, the Long-Term Regional Transmission Planning cycle must conclude at a date no later than five years after commencement. However, FERC clarified that while transmission providers must commence a new Long-Term Regional Transmission Planning cycle only every five years, FERC requires transmission providers to “complete the steps of 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 when the Long-Term Regional Transmission Planning cycle began.” Thus, a transmission provider must make a decision to select or not select Long-Term Regional Transmission Facilities at least two years before the next cycle must commence. Transmission providers must conclude a Long-Term Regional Transmission Planning cycle before developing Long-Term Scenarios at the beginning of the next cycle. This five-year reassessment requirement is designed to ensure that Long-Term Scenarios accurately reflect changing factors, such as technology, load forecasts, and legislation.

C. “Categories of Factors”[9]

FERC adopted a modified list of seven categories of factors that transmission providers must incorporate into the development of Long-Term Scenarios. These categories of factors include: (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. Each of these categories must be incorporated into Long-Term Scenarios regardless of whether a transmission provider determines that certain factors may not be relevant to its transmission planning region. The transmission provider is required to assume in Long-Term Scenarios that any factors drawn from the first three categories will be followed and met, whereas transmission providers have more flexibility in how to account for and weigh factors drawn from the final four categories, so long as the determinations result in a set of plausible and diverse Long-Term Scenarios.

FERC deviated from and/or clarified several NOPR proposals. First, FERC declined to require transmission providers to demonstrate that the incorporation of additional categories of factors into Long-Term Scenarios is consistent with or superior to the seven categories of factors. Thus, transmission providers may incorporate additional categories of factors into the development of Long-Term Scenarios as long as the scenarios remain plausible. FERC also clarified that incorporating the seven categories of factors into Long-Term Scenarios means more than merely considering each category of factors—transmission providers must actually use the factors to determine the assumptions that will be used in the development of Long-Term Scenarios. However, “exacting precision” is not required, and transmission providers may generalize how all of the discrete factors in a category of factors will, in the aggregate, affect the development of Long-Term Scenarios. As for the discrete factors within each category, FERC clarified that transmission providers need to account for the factors that they have determined are likely to affect Long-Term Transmission Needs but not those that they determine are unlikely to affect Long-Term Transmission Needs.

Commissioner Christie cited these categories of factors as evidence of the “Final Rule’s pretextual agenda,” i.e., ensuring that preferential policies and corporate-driven projects are selected for regional transmission plans. Commenters raised similar concerns, asserting that FERC was directing the development of specific transmission facilities. FERC denied these contentions, and Chairman Phillips and Commissioner Clements, as discussed, rejected the notion that Order No. 1920 is designed to prefer certain projects over others.

D. Number and Development of Long-Term Scenarios[10]

Order No. 1920 requires transmission providers to develop at least three, rather than four, distinct Long-Term Scenarios during the five-year Long-Term Regional Transmission Planning cycle. FERC determined that three scenarios would be more consistent with existing planning processes.

FERC adopted a number of other proposals pertaining to the number and development of Long-Term Scenarios. First, transmission providers must publicly disclose information and data inputs that they use to create each Long-Term Scenario. Second, stakeholders must have an opportunity to provide input into how Long-Term Scenarios are developed. Transmission providers must also, with the input of customers and stakeholders, craft coordination requirements that satisfy the transmission providers and their customers and stakeholders. Finally, transmission providers must revise the regional transmission planning process in their respective tariffs to include an “open and transparent process that provides stakeholders, including states, with a meaningful opportunity to propose which future outcomes are probable and can be captured through assumptions made in the development of Long-Term Scenarios.”

FERC emphasized that it expects transmission providers to respect states’ concerns during the planning process. Commissioner Christie, however, criticized the Final Rule for reducing the states’ role. In his view, “[o]ther than a few cosmetic gestures, the Final Rule essentially treats the state regulators like other stakeholders in the RTO/ISO. But states are not mere ‘stakeholders’ . . . The evisceration of the states’ role in transmission planning and cost allocation and the relegation of state regulators to mere ‘stakeholder’ status is alone reason enough for me to dissent.”

The National Association of Regulatory Utility Commissioners has responded to Order No. 1920 by stating it is “generally disappointed by the significantly diminished state role envisioned by the FERC order with respect to transmission planning and cost allocation.” This indicates that a substantial number of state regulators share Commissioner Christie’s concerns.

E. Types of Long-Term Scenarios[11]

The three Long-Term Scenarios developed at the end of Long-Term Regional Transmission Planning cycle must be: (1) plausible, i.e., each individual scenario must be reasonably probable, and collectively the set of plausible scenarios must reasonably capture probable future outcomes, and (2) diverse, meaning that transmission providers can distinguish distinct transmission facilities or distinct benefits of similar transmission facilities in each Long-Term Scenario. FERC declined to prescribe specific types of Long-Term Scenarios because transmission providers, with stakeholder input, are in the better position to determine which Long-Term Scenarios are applicable to their region.

F. Sensitivities for High-Impact, Low-Frequency Events[12]

After developing the three prescribed Long-Term Scenarios, transmission providers must develop a sensitivity for each of those scenarios to account for uncertain operational outcomes that determine the benefits of and/or need for transmission facilities during multiple concurrent and sustained generation and/or transmission outages due to a widespread extreme weather event. Transmission providers are free to conduct this sensitivity either before or after identifying potential regional transmission solutions to their Long-Term Transmission Needs.

The sensitivity operates as a stress test for the Long-Term Scenarios. FERC describes the process as follows:

[T]ransmission providers change the data inputs of the underlying Long-Term Scenarios—in terms of load, generation, generator outages, and transmission outages—to account for uncertain operational outcomes that determine the benefits of or need for regional transmission facilities during multiple concurrent and sustained generation and/or transmission outages due to an extreme weather event across a wide area, while maintaining the underlying longer-term determinants of the Long-Term Scenario.

FERC has now more narrowly defined the number of conditions that must be considered during the sensitivity, focusing on extreme weather events, instead of a broad range of high-impact, low frequency events. Transmission providers are free, however, to apply their own sensitivities to account for other high-impact events, such as cyber-attack, significant forecast error, or fuel price volatility.

G. Specificity of Data Inputs[13]

The Final Rule requires transmission providers to use “best available data inputs” when developing Long-Term Scenarios. “Best available data inputs” are defined as those data inputs that are timely, developed using best practices and diverse and expert perspectives, and adopted in a way that satisfies the requirements of Order Nos. 890 and 1000. These inputs must also reflect the list of factors that transmission providers account for in their Long-Term Scenarios, meaning that they must reflect the data inputs that correspond to the list of factors that transmission providers have determined might affect Long-Term Transmission Needs. Best available data inputs should be updated, as necessary, every time transmission providers reassess and revise their Long-Term Scenarios. Transmission providers must give stakeholders an opportunity to provide meaningful input during each Long-Term Regional Transmission Planning cycle concerning which data inputs to use, and interested parties may challenge via dispute resolution the transmission providers’ chosen data inputs.

H. Identification of Geographic Zones[14]

FERC declined to adopt the NOPR’s proposal that each transmission provider consider whether to establish geographic zones within the transmission planning region that have the potential to develop large amounts of new generation. Ultimately, FERC agreed with commenters that such a requirement was unnecessary “at this time” to ensure that Long-Term Regional Transmission Planning ensures just and reasonable rates. Regardless, FERC still encouraged transmission providers to consider geographic zones, and transmission providers may propose to identify geographic zones as part of Long-Term Regional Transmission Planning, provided that the transmission providers demonstrate that their process for identifying geographic zones is consistent with or superior to the Long-Term Regional Transmission Planning requirements.

IV. Evaluation of the Benefits of Regional Transmission Facilities

A. Mandatory Consideration of Seven “Required Benefits”[15]

The Final Rule requires transmission providers in each transmission planning region to measure and assess seven specific benefits for Long-Term Regional Transmission Facilities under every Long-Term Scenario as part of Long-Term Regional Transmission Planning. The seven required benefits are: (1) avoided or deferred reliability transmission facilities and aging infrastructure replacement; (2) benefit categorized 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. FERC deemed these requirements necessary to ensure that transmission providers can effectively evaluate Long-Term Regional Transmission Facilities and select those that efficiently or cost-effectively address Long-Term Transmission Needs.

While FERC did not propose to mandate the use of specific benefits in the NOPR, it received feedback indicating the necessity of requiring transmission providers to measure and utilize a particular set of benefits in Long-Term Regional Transmission Planning. This approach aims to identify, evaluate, and select regional transmission facilities that offer more efficient or cost-effective solutions to Long-Term Transmission Needs. The Final Rule states that Long-Term Regional Transmission Facilities offer benefits beyond what transmission providers currently consider in their planning and cost allocation processes. Therefore, the Final Rule concludes that failing to use the specified benefits to assess Long-Term Regional Transmission Facilities could lead to the selection of less efficient or cost-effective solutions and result in unjust and unreasonable transmission rates.

B. The Required Benefits[16]

Benefit 1: Avoided or Deferred Reliability Transmission Facilities and Aging Transmission Infrastructure Replacement

Benefit 1 refers to the reduced costs from avoiding or delaying transmission investment needed for reliability or to replace aging infrastructure. This benefit aims to ensure that Long-Term Regional Transmission Facilities efficiently address long-term transmission needs by potentially obviating or delaying the need for reliability transmission facilities or aging infrastructure replacements. This benefit does not restrict incumbent transmission providers from developing local transmission facilities for their reliability needs, nor does it mandate keeping transmission facilities operational beyond their useful life. Transmission providers can use Benefit 1 to calculate avoided or deferred costs for Long-Term Regional Transmission Facilities, potentially displacing local or regional transmission facilities.

Benefit 2(a): Reduced Loss of Load Probability or Benefit 2(b): Reduced Planning Reserve Margin

Benefit 2 can be divided into Benefit 2(a), Reduced Loss of Load Probability, or Benefit 2(b), Reduced Planning Reserve Margin, with both methods aiming to measure the same underlying reliability benefits. To avoid redundancy, transmission providers must choose either 2(a) or 2(b) to assess each proposed Long-Term Regional Transmission Facility. Benefit 2(a) quantifies the decreased frequency of loss of load events and improved physical reliability by offering additional pathways for connecting generation resources with load. Benefit 2(b) focuses on the reduction in capital costs of generation needed to meet resource adequacy requirements while holding loss of load probability constant.

Benefit 3: Production Cost Savings

Benefit 3 encompasses savings in fuel and variable operating costs of power generation from the displacement of higher-cost supplies through increased dispatch of lower-cost suppliers facilitated by transmission facilities. The Final Rule asserts that consideration of this benefit is necessary to ensure the identification and selection of Long-Term Regional Transmission Facilities that efficiently address Long-Term Transmission Needs. Unlike other benefits, no standardized method is prescribed for measuring production cost savings, allowing flexibility for transmission providers.

Benefit 4: Reduced Transmission Energy Losses

Benefit 4 refers to the decreased total energy required to meet demand due to minimized energy losses during transmission from generation to loads. Benefit 4 aims to ensure that transmission providers identify, assess, and select more efficient or cost-effective regional transmission solutions to address Long-Term Transmission Needs. Despite concerns raised in the NOPR regarding the difficulty of quantifying this benefit in advance, the Final Rule asserts that transmission providers possess multiple feasible methods for calculating it, as evidenced by existing practices in various transmission planning regions.

Benefit 5: Reduced Congestion Due to Transmission Outages

Benefit 5 entails the reduction in production costs from the avoidance of congestion during transmission outages, including decreased costs during significant transmission congestion events. The Final Rule asserts that this benefit aims to ensure that transmission providers identify, assess, and select more efficient or cost-effective regional transmission solutions to address Long Term Transmission Needs. FERC states this benefit is necessary because most current production cost simulations typically only address generation outages, neglecting transmission outages.

Benefit 6: Mitigation of Extreme Weather Events and Unexpected System Conditions

This revised benefit amalgamates two benefits proposed in the NOPR: (1) mitigation of extreme events and system contingencies, and (2) mitigation of weather and load uncertainty. The revised Final Rule Benefit 6 encompasses reduced production costs and reduced loss of load during extreme weather events and unexpected system conditions, including instances of multiple concurrent and sustained generation and/or transmission outages. The Final Rule makes three key modifications to the NOPR’s version of this benefit: (1) inclusion of reduced loss of load, not solely reduced production costs, as part of Benefit 6 measurement; (2) incorporation of both extreme weather events and unexpected system conditions into the assessment when transmission facilities have particularly high value; and (3) measurement of benefits associated with any increase in Interregional Transfer Capability provided by a Long-Term Regional Transmission Facility during extreme weather events and unexpected system conditions.

Benefit 7: Capacity Cost Benefits From Reduced Peak Energy Losses

Benefit 7 pertains to reduced generation capacity investment costs required to meet peak load. According to FERC, standard production cost modeling and other mandated benefits might not adequately capture this benefit, potentially leading to inefficient or less cost-effective transmission development. The Final Rule concludes that omitting the evaluation of potential cost savings from reduced peak energy losses may lead to higher capacity costs and less efficient transmission development.

Other Benefits

The Final Rule declines to mandate the measurement and use of five benefits described in the NOPR for Long-Term Regional Transmission Planning. These benefits include mitigation of weather and load uncertainty, generation capacity investments, access to lower-cost generation, increased competition, and increased market liquidity. According to FERC, the required set of benefits already adopted is comprehensive enough to ensure that transmission providers identify, evaluate, and select Long-Term Regional Transmission Facilities effectively to address Long-Term Transmission Needs while maintaining just and reasonable rates. However, the Final Rule allows transmission providers the discretion to measure and use additional benefits, including on a transmission facility or plan-specific basis.

C. Identification, Measurement, and Evaluation of the Benefits of Long-Term Regional Transmission Facilities[17]

The Final Rule requires each transmission provider’s OATT to include a general measurement description for each of the seven required benefits measured and used in Long-Term Regional Transmission Planning. The description of each required benefit must be sufficient to enable stakeholders to understand the manner of measurement. FERC rejected objections that the rule constitutes an “excessive quantification of benefits,” finding that it “represents a reasonable balance between specificity and flexibility.” Transmission providers have the flexibility to specify the method for measuring each of the seven required benefits and may also use and measure additional benefits.

D. Evaluation of Transmission Benefits Over a Longer Time Horizon[18]

As part of Long-Term Regional Transmission Planning, transmission providers must calculate the benefits of Long-Term Regional Transmission Facilities over a time horizon of no less than twenty years. The time horizon begins from the estimated in-service date of the transmission facility. The minimum 20-year benefit horizon must be used to evaluate and select Long-Term Regional Transmission Facilities. The Final Rule allows transmission providers to propose to consider longer time horizons, which must be included in their compliance filing.

If a transmission provider estimates the costs of Long-Term Regional Transmission facilities beyond the in-service date, it must estimate those future costs over the same time horizon as the estimated benefits.

The Final Rule requires transmission providers to develop multiple plausible and diverse Long-Term Scenarios. Transmission providers must update their assumptions periodically.

The Final Rule permits transmission providers to discount the benefits calculated to determine the present value of those benefits; however, transmission providers are prohibited from further discounting those benefits to reflect uncertainty over the minimum 20-year time horizon.

E. Evaluation of the Benefits of Portfolios of Transmission Facilities[19]

The Final Rule does not require, but allows, transmission providers to use a portfolio approach in evaluating the benefits of Long-Term Regional Transmission Facilities. Transmission providers may use either or both facility-by-facility and portfolio approaches within the same Long-Term Regional Transmission Planning cycle. Transmission providers that propose to use a portfolio approach must include provisions addressing their use of the approach in their OATT.

F. Use of Additional Benefits[20]

The Final Rule encourages transmission providers to consult with the applicable states to develop proposals. Specifically, the consultation should consider whether, and if so, how, to use any additional benefits in Long-Term Regional Transmission Planning.

V. Evaluation Process and Selection Criteria[21]

The Final Rule requires transmission providers’ OATT to include a Long Term Regional Transmission Planning evaluation process, including selection criteria, to identify and evaluate Long-Term Regional Transmission Facilities for potential selection to address Long-Term Transmission Needs. A Long-Term Regional Transmission Planning evaluation process must: (1) identify Long-Term Regional Transmission Facilities that address Long-Term Transmission Needs; (2) measure the benefits of the identified Long-Term Regional Transmission Facilities consistent with the Final Rule requirements; and (3) designate a point in the evaluation process at which transmission providers will determine whether to select or not select identified Long-Term Regional Transmission Facilities in the regional transmission plan for purposes of cost allocation.

The Final Rule does not require that transmission providers select particular Long-Term Regional Transmission Facilities; the Final Rule requires the adoption of an evaluation process and selection criteria in accordance with the Final Rule.

The Final Rule does not require transmission providers to modify or replace selection criteria used in their existing reliability and economic regional transmission planning processes. However, transmission providers that wish to alter their existing processes or criteria must propose the evaluation process and selection criteria they will use in Long-Term Regional Transmission Planning and must demonstrate that the process and criteria satisfy the requirements of the Final Rule.

A. Flexibility

The Final Rule requires transmission providers to propose an evaluation process, including selection criteria, for selecting more efficient or cost-effective Long-Term Regional Facilities to address their region’s Long-Term Transmission Needs. Transmission providers must consult with Relevant State Entities and other stakeholders to develop their proposal.

The Final Rule does not require transmission providers to select any particular Long-Term Regional Transmission Facility; instead, it sets forth minimum requirements for the evaluation process and selection criteria.

B. Minimum Requirements

The Final Rule provides minimum requirements for the evaluation process and selection criteria.

The evaluation process and selection criteria must ensure that more efficient or cost-effective Long-Term Regional Transmission Facilities are selected to address Long-Term Transmission Needs. The Final Rule adopted several requirements: (1) transmission providers must identify one or more facilities (or portfolio) that address Long-Term Transmission Needs identified through Long-Term Regional Transmission Planning; in particular, transmission providers’ OATTs must specify the point in the planning evaluation process when they will accept proposals from stakeholders and nonincumbent transmission developers; (2) the evaluation process must estimate the costs and measure the benefits of the facilities identified or proposed for potential selection in addition to evaluating the identified facilities using any qualitative or other quantitative selection criteria transmission providers propose to apply; (3) transmission providers must designate a point in the evaluation process when they will determine whether to select or not select identified facilities, and this point must be no later than three years after the start of the long term regional transmission planning cycle; and (4) the evaluation process must result in determinations sufficiently detailed for stakeholders to understand why a facility was or was not selected.

The Final Rule requires that transmission providers propose evaluation processes and selection criteria that maximize benefits accounting for costs over time without overbuilding transmission facilities. Transmission providers must not disregard benefits the Final Rule requires them to use and measure when implementing their approved evaluation process and selection criteria. However, transmission providers’ evaluation process and selection criteria may account for the fact that certain benefits are only measured under certain conditions.

Transmission providers have the discretion to select or not select any facility identified through Long-Term Regional Transmission Planning, which includes a facility that otherwise meets the selection criteria. However, the final determination must (1) contain sufficient detail for stakeholders to understand why or why not a certain transmission facility was or was not selected and (2) include the estimated cost and measured benefits of each facility evaluated.

C. Role of Relevant State Entities

The Final Rule requires transmission providers to consult with and seek support from Relevant State Entities concerning the evaluation process and selection criteria. Transmission providers must demonstrate that they made good faith efforts to consult with and seek such support from the Relevant State Entities in their region’s footprint. Although the Final Rule requires transmission providers to seek support, it does not require them to obtain support from Relevant State Entities.

D. Voluntary Funding Opportunities

The Final Rule requires transmission providers to include a voluntary funding process in their OATTs. Such voluntary funding process must provide Relevant State Entities and interconnection customers the option to voluntarily fund, partially or fully, a Long-Term Regional Transmission Facility that would otherwise not meet the selection criteria. Any portion of the costs of a selected Long-Term Regional Transmission Facility not voluntarily funded must be allocated according to the applicable Long-Term Regional Transmission Cost Allocation Method or, if applicable, the cost allocation method provided for in a State Agreement Process.

Transmission providers must consult with and seek support from Relevant State Entities when developing this process.

The OATT provisions regarding the voluntary funding process must describe: (1) the process for transmission providers to make voluntary funding opportunities available, which must include timely notice; (2) the period for exercising the option to provide voluntary funding; (3) the method used to determine the amount of voluntary funding required; and (4) the mechanism to be used to memorialize any voluntary funding agreement. The Final Rule does not require transmission providers to file agreements memorializing voluntary funding arrangements; rather, FERC will evaluate on compliance the proposed mechanism.

Transmission providers may seek to demonstrate that their proposal is consistent with or superior to what is required in the Final Rule or submit an FPA section 205 filing to propose OATT provisions that go beyond the requirements in the Final Rule.

E. Reevaluation

Transmission providers must propose OATT provisions that require, in certain circumstances, the reevaluation of Long-Term Regional Transmission Facilities previously selected. In addition to meeting the minimum requirements for the evaluation process and selection criteria, these OATT provisions must require revaluation in three situations, subject to certain limitations: (1) development delays would jeopardize a transmission provider’s ability to meet its reliability needs or reliability-related service obligations; (2) the actual or projected costs significantly exceed cost estimates used for selection; or (3) significant changes in federal, federally-recognized Tribal, state, or local laws or regulations cause reasonable concern that the selected facility may no longer meet the selection criteria. Transmission providers’ OATTs must include specific criteria to be used to determine when one of the three situations occurs. Transmission providers are provided flexibility in their proposals for this criteria, but such criteria are subject to the requirement that it must seek to maximize benefits accounting for costs over time without overbuilding transmission facilities. Further, the OATT reevaluation provisions must include the process and procedures to be used to reevaluate the potential outcomes and the conditions that would require removing a facility from a project transmission plan.

VI. Implementation of Long-Term Regional Transmission Planning[22]

The Final Rule requires transmission providers to explain how the initial timing sequence for Long-Term Regional Transmission Planning will interact with the existing regional transmission planning processes. Specifically, transmission providers must (1) address the possible interaction between the transmission planning cycle for Long-Term Regional Transmission Planning and the existing process; and (2) address the possible displacement of regional transmission facilities from the existing process.

Transmission providers must propose a date, no later than one year from the initial compliance filing due date, on which they will commence the first Long-Term Regional Transmission Planning cycle. However, only to the extent needed to align transmission planning cycles, transmission providers may propose a date later than one year from the initial compliance filing due date.

FERC plans to organize and host periodic forums for transmission providers, transmission experts, federal and state agencies, and stakeholders that will provide an opportunity to share best practices for the implementation of Long-Term Regional Transmission Planning.

VII. Coordination of Regional Transmission Planning and Generator Interconnection Processes[23]

The Final Rule requires transmission providers to evaluate for selection regional transmission facilities that address qualifying interconnection-related transmission needs associated with related network upgrades originally identified in the generator interconnection process to be considered as part of their existing regional transmission planning and cost allocation processes. The Final Rule does not alter existing cost allocation methods or regional transmission planning processes.

The Final Rule provides criteria for transmission providers to use to identify regional transmission facilities that qualify for evaluation. Transmission providers must evaluate for selection in their existing regional transmission planning process regional transmission facilities to address interconnection-related transmission needs identified in the generator interconnection process as requiring related network upgrades where:

(1) the transmission provider has identified interconnection-related network upgrades in interconnection studies to address those interconnection-related transmission needs in at least two interconnection queue cycles during the preceding five years – beginning five calendar years prior to the effective date of the Commission-accepted tariff provisions proposed to comply with this rule;

(2) the identified interconnection-related network upgrade has a voltage of at least 200 kV and an estimated cost of at least $30 million;

(3) interconnection-related network upgrade(s) have not been developed and are not currently planned to be developed because the interconnection request(s) driving the need for the network upgrade(s) has been withdrawn; and

(4) the transmission provider has not identified an interconnection-related network upgrade to address the relevant interconnection-related transmission need in an executed generator interconnection agreement or in a generator interconnection agreement that the interconnection customer requested that the transmission provider file unexecuted with the Commission.

The Final Rule places an obligation on transmission providers to evaluate facilities for selection that meet the qualifying criteria. Satisfaction of qualifying criteria does not require transmission providers to select any particular regional transmission facility to address interconnection related transmission needs. The rule allows for flexibility in how transmission providers evaluate facilities for selection. Transmission providers may still separately assess whether any particular facility qualifies for selection according to their existing regional transmission planning processes.

If transmission planners wish to change their existing regional transmission planning cost allocation methods, they must do so in a separate FPA section 205 filing rather than through Order No. 1920 compliance filings.

VIII. Consideration of Dynamic Line Ratings and Advanced Power Flow Control Devices[24]

As part of both Long-Term Regional Transmission Planning and existing regional transmission planning processes, the Final Rule augments the NOPR by requiring transmission providers to consider four, rather than two, alternative transmission technologies: (1) dynamic line ratings; (2) advanced power flow control devices; (3) advanced conductors; and (4) transmission switching.

Transmission providers are required to consider each of these technologies when evaluating new regional transmission facilities and upgrades to existing transmission facilities. Transmission providers’ evaluations of the enumerated alternative transmission technologies must be consistent with the requirements in their OATTs for other transmission solutions. Transmission providers will be required to update their energy management systems to implement dynamic line ratings or any of the alternative transmission technologies, if necessary.

In an evaluation of regional transmission facilities for potential selection for each identified transmission need, transmission providers must consider whether those facilities incorporate or solely consist of the enumerated alternative transmission technologies and whether those alternatives would be more efficient or cost effective than selecting new regional transmission facilities or upgrades that do not incorporating these technologies.

Transmission providers are required to explain why dynamic line ratings, advanced power flow control devices, advanced conductors, and/or transmission switching were or were not incorporated into selected regional transmission facilities.

FERC emphasized that nothing in the Final Rule changes or alters transmission providers’ obligations to ensure long-term reliability of the bulk electric system in their transmission planning process.

IX. Regional Transmission Cost Allocation[25]

A. General Approaches

The Final Rule differs significantly from the NOPR proposals addressing cost allocation for Long-Term Regional Transmission Facilities. The NOPR proposal would have required transmission providers to have either an ex ante Long-Term Regional Transmission Cost Allocation Method to allocate the costs of Long-Term Regional Transmission Facilities or an ex post State Agreement Process by which one or more Relevant State Entities would voluntarily agree to a cost allocation method. Tariffs could also have a combination of both approaches. In addition, the NOPR required transmission providers to “seek the agreement” of Relevant State Entities regarding any Long-Term Regional Cost Allocation Method and State Agreement Process included in the tariff.

The NOPR identified several policy considerations favoring the State Agreement Process. These included that it would allow states to voluntarily pursue public policy goals and should be expected to minimize delays associated with state siting proceedings. But the NOPR also recognized that if the State Agreement Process were the only available option under the transmission provider’s tariff, situations could arise in which the Relevant State Entities participating in a State Agreement Process would be unable to reach agreement and no ex ante Long-Term Regional Transmission Cost Allocation Method would be available. The ability of the transmission provider to move forward with an identified transmission project in those circumstances could be hampered. The NOPR asked for comments as to whether an ex ante Long-Term Regional Transmission Cost Allocation Method should be mandatory.

The Final Rule largely reverses the priorities of the NOPR approach. While the NOPR proposal did not mandate the use of the State Agreement Process as a prerequisite for approval of Long-Term Regional Transmission Facilities, it clearly favored the use of that mechanism. But the Final Rule reflects greater concern over the risk that Relevant State Entities would not always reach agreement in the State Agreement Process. To address this possibility, the Final Rule requires that there be a default ex ante Long-Term Regional Transmission Cost Allocation Method in the tariff. The State Agreement Process option detailed below in section IX.E. remains available[26] but if agreement among Relevant State Entities is not reached, the default mechanism will apply and the selected project can move forward. Commissioner Christie strongly opposed the Final Rule’s changes in this area, asserting that they would effectively make existing and any potential future State Agreement Processes irrelevant while “locking in” the use of FERC-mandated ex ante allocation methodologies.

Under the Final Rule, the default cost allocation method applicable to a project will be known to all stakeholders at the time the project is approved. Negotiations among Relevant State Entities utilizing the State Agreement Process will occur with all participants being aware of each state’s allocation of transmission costs in the absence of any agreement. The Final Order acknowledges that this dynamic could undermine productive negotiations among Relevant State Entities but finds that potential complication outweighed by the risk that the most efficient Long-Term Regional Transmission Facilities otherwise may not be constructed. Further, the Final Rule indicates that FERC believes that allowing the use of a State Agreement Process will continue to allow state preferences to be taken into account notwithstanding the requirement that transmission providers adopt a default cost allocation mechanism.

The Final Rule also includes a new procedural step, not proposed in the NOPR, that a transmission provider must demonstrate it held a one-time, six-months long “Engagement Period” to provide Relevant State Entities with the opportunity to reach agreement regarding a Long-Term Regional Transmission Cost Allocation Method and/or a State Agreement Process. If the Relevant State Entities agree, the transmission providers may file the agreed-upon process(es), but will not be required to do so. This new “engagement” requirement was adopted in lieu of the NOPR proposal that transmission providers had to “seek the agreement” of the Relevant State Entities regarding the relevant cost allocation method or process.

B. Scope of Projects Covered by the New Rules

The Final Rule adopted the NOPR proposal that cost allocation reforms should only apply to new Long-Term Regional Transmission Facilities. FERC found that the cost allocation changes should not apply to regional reliability and economic transmission projects identified under Order No. 1000 procedures noting that the Final Rule does not change the existing regional reliability and economic transmission planning processes. Further, the Final Rule states that allowing the use of different cost allocation methods for different regional transmission planning processes is reasonable because Long-Term Regional Transmission Planning considers needs over a longer time frame and is more comprehensive than the existing Order No. 1000 regional transmission planning process. Finally, the Final Rule clarifies that the entire cost of a “multi-value” project that is selected as a Long-Term Regional Transmission Facility will be recovered under the applicable Long-Term Regional Transmission Cost Allocation Method or other acceptable cost allocation method resulting from a State Agreement Process except to the extent that an entity may agree to voluntarily funding.

C. The Engagement Period

As noted above, the Final Rule, unlike the NOPR, obligates transmission providers to establish a six month “Engagement Period” to allow Relevant State Entities to reach agreement regarding a Long-Term Regional Transmission Cost Allocation Method(s) and/or a State Agreement Process. On compliance, the transmission provider must: (1) provide notice of the start and end dates; (2) post contact information for the transmission provider and a deadline for communicating any agreement; and (3) provide a suitable forum for negotiations. The transmission provider may use an allocation method devised during the Engagement Period process, but is not required to do so.

The Final Rule defines Relevant State Entities 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.” If multiple agencies within a given state meet this definition, the Final Order allows the group of participating Relevant State Entities to choose whether one or more agencies of a particular state should participate. Similarly, the participating Relevant State Entities have the flexibility to decide what constitutes “agreement” among them, e.g., majority support, unanimous support, or a threshold of one-half of the participating Relevant State Entities.

The Engagement Period process is intended to substitute the NOPR proposal to “seek the agreement” of Relevant State Entities, but this change clearly reduces the amount of leverage they had under the NOPR proposal. Achieving consensus, even as to the process for reaching agreement as to a cost allocation method, may be particularly difficult in multi-state RTOs that include states with opposing policies.

D. Acceptable Cost Allocation Methodologies

1. Default Cost Allocation Mechanisms

a. Default Cost Allocation Methodologies That Do Not Originate Either From the Engagement Period or a State Agreement Process

The NOPR proposed that any Long-Term Regional Transmission Cost Allocation Method would need to satisfy the existing six Order No. 1000 regional cost allocation principles. These are: (1) the allocation of costs 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) entities that do not benefit from transmission facilities must not be allocated costs involuntarily; (3) if benefit to cost threshold ratio is adopted, it cannot exceed 1.25 to 1; (4) costs must be allocated solely within the transmission planning region unless entities outside the region voluntarily assume some costs; (5) the method for determining benefits and identifying beneficiaries must be transparent; and (6) different regional cost allocation methods are permitted for different types of transmission projects, such as those needed for reliability, congestion relief, or to achieve Public Policy Requirements.

The Final Rule stresses the importance of compliance with the first and second principles, which are fundamental cost allocation principles long recognized in judicial precedent. However, unlike the NOPR, the Final Rule rejects compliance with principle 6 in the context of cost allocation methodologies that are not produced through the Engagement Period or a State Agreement Process. The Final Rule prohibits the use of different cost allocation methods for different types of Long-Term Regional Transmission Facilities. No particular cost allocation methodology is mandated, but participant funding is prohibited for ex ante methodologies that are not produced through the State Agreement Process.

Further, benefits used in the evaluation and selection of projects need not be reflected in the Long-Term Regional Transmission Cost Allocation Method that is selected. According to the Final Rule, allowing flexibility will enable stakeholders to address regional differences. The Final Rule indicates that FERC will evaluate “whether a proposed cost allocation method allocates costs in a manner that is at least roughly commensurate with estimated benefits on a fact-specific basis, relying on the record in a given proceeding.” In addition, the Final Rule states that the allocation of costs based on load-ratio share “is a cost allocation approach that may be consistent with the beneficiary-pays approach.”

The Final Rule rejects a NOPR proposal that would have transmission providers filing a Long-Term Regional Transmission Cost Allocation Method to identify the benefits that underlie the cost allocation methodology, the manner of calculating those benefits and an explanation of how the identified benefits meet transmission needs driven by changes in the resource mix and demand. Compliance filings must only demonstrate that the methodology meets Order No. 1000 principles 1 though 5 and that the methodology does not allocate costs by project type. Multiple cost allocation methodologies are allowed, but they must be differentiated by factors such as by voltage thresholds or geography.

The Final Rule also responded to concerns that cost allocation methods could be approved by FERC that do not adequately recognize the achievement of Public Policy goals as driving the need for selected transmission projects and thereby result in an overallocation of costs to states or other stakeholders that may not share those goals. Rejecting these concerns as “misplaced,” FERC responded that Public Policy goals do not constitute the entirety of the factors considered, and that judicial cost allocation principles and compliance with the Order No. 1000 principles provide additional safeguards to prevent costs from being allocated improperly. Moreover, because the Final Rule requires transmission providers to disclose estimates of the benefits associated with selected Long-Term Regional Transmission Facilities, stakeholders will be able to understand the correlation between the costs paid and the benefits received.

Commissioner Christie was extremely critical of the approach in the Final Rule of “lumping reliability and economic projects into the same planning bucket as public and corporate-driven policy projects.” According to the Commissioner, “the intent and effect of this shell game is to enable the costs of corporate and public policy-driven projects to be socialized across an entire multi-state region and thus shifted onto consumers in states that never agreed to bear such costs.”

b. Default Cost Allocation Methodologies That Originate From the Engagement Period or a State Agreement Process

A different standard applies to Long-Term Regional Transmission Cost Allocation Methods that result from either the Engagement Period negotiations or as the result of a State Agreement Process. FERC “decline[d] to require those methods to adhere to the six Order No. 1000 regional cost allocation principles.” Despite this statement, FERC still requires cost allocation methodologies to meet the statutory just and reasonable standard and to allocate costs in a manner that is at least roughly commensurate with estimated benefits—both of which essentially restate Order No. 1000 principles 1 and 2. Further, the use of participant funding as an allocation element will be prohibited.

In addition, the Final Rule provides that no particular benefits need to be reflected in such a cost allocation method, a feature that Commissioner Christie criticized as “as further proof of the nature of the shell game” to obtain approval of preferential policy and corporate driven projects. But FERC viewed this standard as preferable for Long-Term Regional Transmission Cost Allocation Methods that result from either the Engagement Period negotiations or as the result of a State Agreement Process based on the belief that it will increase the chances that more efficient or cost-effective Long-Term Regional Transmission Facilities will be selected and developed.

E. State Agreement Process Allocation Mechanism

As discussed above, the Final Rule relegates the State Agreement Process to a less prominent role than the NOPR did. Nonetheless, at least in some instances, the State Agreement Process can be expected to result in the use of cost allocations methods that differ from the ex ante default cost allocation that transmission providers are required to file with FERC.

The Final Rule defines the State Agreement Process 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.” The Final Rule specifies that transmission provider tariffs must describe “how the State Agreement Process will result in a cost allocation being filed, including which entities can participate in the State Agreement Process; what constitutes an agreement on cost allocation in that process; how agreement is communicated to the transmission provider; and the circumstances under which, or the information necessary for, a transmission provider to file or to consider filing the agreed cost allocation.” Entities other than Relevant State Entities may be allowed to participate in the State Agreement Process and participant funding is permitted to be an element of a cost allocation methodology that is developed.

Transmission providers are not required to replace a default cost allocation method that is already on file with a new and different method developed for a specific project developed through the State Agreement Process. However, if the transmission provider elects to file the cost allocation method developed for a specific project in the State Agreement Process, then the standard of review for the cost allocation method developed through the State Agreement Process will be the less demanding standard applied to cost allocation methods developed during the Engagement Period process.

X. Construction Work in Progress Incentive[27]

The NOPR proposed to eliminate the existing Construction Work In Progress (CWIP) Incentive for Long-Term Regional Transmission Facilities whereby transmission owners are allowed to recover 100% of their CWIP in rate base before a facility was placed into service. The concern expressed in the NOPR was that applying the CWIP Incentive to Long-Term Regional Transmission Facilities would shift excessive risk to consumers due to the long lead-times associated with these projects and the higher level of uncertainty that they will be built. FERC noted that even if the CWIP Incentive were eliminated, transmission providers would still have the ability to accrue carrying costs incurred during the pre-construction or construction phase as Allowance for Funds Used During Construction (AFUDC). As with AFUDC, the costs could then be recovered from customers after the project was placed into service.

The Final Rule declined to take any action regarding the CWIP Incentive as applied to Long-Term Regional Transmission Facilities, finding that the incentive should be considered in a separate proceeding to enable a “holistic approach” to transmission incentives. For example, a number of commenters raised concerns about the interaction between the CWIP Incentive and the policy that allows companies to seek to recover 100% of prudently-incurred costs associated with an abandoned project. It appears that FERC may want to consider the possibility of reforms affecting both of these transmission incentives and perhaps others.

FERC’s decision not to address the CWIP Incentive in the Final Rule drew strong criticism in Commissioner Christie’s dissent. In his view, the NOPR proposal to eliminate the CWIP Incentive for Long-Term Regional Transmission Facilities “was one of [its] strongest consumer protection features” and that FERC’s failure to enact the reform “is a fundamental change from the NOPR.”

XI. Rejection of NOPR Proposal to Establish a Federal Right of First Refusal for Jointly Owned Projects[28]

The NOPR proposed to modify the requirements of Order No. 1000 by allowing an incumbent transmission provider in whose territory a project would be built to have a right of first refusal to construct the project if the facilities would be jointly owned by an unaffiliated nonincumbent transmission developer or another unaffiliated entity including another incumbent transmission provider. The NOPR suggested that this modification could promote new entry and create a greater diversity of transmission ownership. FERC also indicated that this joint-ownership approach might help to mitigate against the “unintended emphasis” that the current Order No. 1000 process seemed to place on development of local transmission facilities.

The Final Rule declined to adopt the NOPR proposal, noting that commenters raised “substantial concerns about whether incumbent transmission providers, as a result of Order No. 1000’s reforms, face perverse investment incentives that do not adequately encourage those incumbent transmission providers to develop and advocate for transmission facilities that benefit more than just their own local retail distribution service territory or footprint.” FERC indicated that it would continue to consider reforms to its Order No. 1000 right of first refusal policies in other proceedings, specifically identifying Docket No. AD22-8 on Transmission Planning and Cost Management.

The Joint Concurrence of Chairman Phillips and Commissioner Clements also underscore their support for the concept of joint ownership. The adoption of a federal right of first refusal that would promote joint ownership of transmission projects appears to be something they wish to explore.

XII. Local Transmission Planning Inputs in the Regional Transmission Planning Process[29]

A. Need for Reform

Regarding local and regional transmission planning processes, the Final Rule adopts two reforms: (1) enhanced transparency of local transmission planning processes; and (2) required “right-sized” evaluations of transmission facilities in need of replacing.

B. Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process

The Final Rule requires transmission providers to revise their regional transmission planning process OATT provisions. The revisions must enhance the transparency of three local transmission planning information categories: (1) the criteria, models, and assumptions that they use in their local transmission planning process; (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.

The Final Rule requires transmission providers to establish an iterative process to allow stakeholders to participate in local transmission planning during the regional transmission process. The regional transmission planning process must include at least three publicly noticed stakeholder meetings per regional transmission planning cycle to address local transmission planning. The three stakeholder meetings are as follows:

(1) Before the submission of local transmission planning information to the transmission planning region, an Assumptions Meeting must be held by the transmission providers. The Assumptions Meeting will review the criteria, assumptions, and models related to each transmission provider’s local transmission planning.

(2) Following the Assumptions Meeting, but no fewer than 25 calendar days afterward, transmission providers must hold a Needs Meeting. The Needs Meeting aims to review identified reliability criteria violations and other transmission needs driving the local transmission facilities need. If necessary, this information may be disclosed under applicable confidentiality provisions.

(3) Transmission providers must hold a Solutions Meeting no fewer than 25 calendar days after the Needs Meeting. At the Solutions Meeting, stakeholders will review potential solutions to the reliability criteria violations and other transmission needs.

Transmission providers must ensure stakeholders are able to participate meaningfully in the three required meetings. The materials for stakeholder review must be publicly posted at least 5 calendar days prior to each meeting to provide stakeholders time to review the material and to give stakeholders the opportunity to submit comments before and after each meeting. Stakeholders must be provided the opportunity to participate meaningfully, and the Final Rule requires transmission providers to respond to questions or comments appropriately.

Following the Solutions Meeting, transmission providers must establish a period of no fewer than 25 calendar days to review and consider stakeholder feedback. The local transmission plan may not be incorporated in the transmission planning region’s planning models before the conclusion of this period.

Any disputes related to this increased transparency should be dealt with according to the transmission provider’s existing dispute resolution process.

C. Identifying Potential Opportunities to Right-Size Replacement Transmission Facilities

1. Eligibility

In each Long-Term Regional Transmission Planning cycle, transmission providers must evaluate whether certain transmission facilities can be “right-sized” to more efficiently or cost-effectively address a Long-Term Transmission Need. The transmission facilities that must be evaluated are those operating above a specified kV threshold and anticipated to be replaced in-kind with a new transmission facility during the next 10 years. Transmission providers must propose a threshold in their compliance filing, which may not exceed 200 kV.

The Final Rule defines “right-sizing” as modifying an in-kind replacement of an existing transmission facility to increase that facility’s transfer capability. Further, “in-kind replacement transmission facility” is defined as a new transmission facility that: “(1) would replace an existing transmission facility that a transmission provider has identified in its in-kind replacement estimate as needing to be replaced; (2) would result in no more than an incidental increase in capacity over the existing transmission facility identified as needing to be replaced; and (3) is located in the same general route as, and/or uses the existing rights-of-way of, the existing transmission facility identified as needing to be replaced.”

The Final Rule delineates the steps that make up the process for the right-sizing reform. Transmission providers must describe this process in their OATTs. The process consists of the following steps:

(1) transmission providers must propose a sufficiently early point in each Long-Term Regional Transmission Planning cycle at which individual transmission providers must submit their in-kind replacement estimates.

(2) if a right-sized replacement transmission facility is identified as a potential solution to a Long-Term Transmission Need, it must be evaluated in the same manner as other proposed Long-Term Regional Transmission Facilities to determine its comparative efficiency or cost-effectiveness.

(3) A right-sized replacement transmission facility must be considered for selection if it (i) addresses a need to replace an existing transmission facility, (ii) meets the Long-Term Regional Transmission Planning selection criteria, and (iii) is found to be the more efficient or cost-effective solution.

2. Right of First Refusal for Right-Sized Replacement Facilities

The Final Rule establishes a federal right of first refusal for any right-sized replacement transmission facility selected to meet Long-Term Transmission Needs.

3. Cost Allocation

The final rule declined to adopt the NOPR proposal to require that only the incremental costs of a right-sizing a transmission facility be eligible to use the applicable Long-Term Regional Transmission Cost Allocation Method with the remaining costs allocated consistent with the otherwise applicable cost allocation method for the superseded in-kind replacement. However, to the extent a transmission provider proposes to allocate the costs of right-sized replacement transmission facilities according to this approach, the Final Rule requires the transmission provider to explain in its compliance filing: (1) the method to be used to determine the portion of the costs incremental to the costs that would have been incurred for the underlying facility and (2) the method to be used to track the portion of costs over time allocated following the Long-Term Regional Transmission Cost Allocation Method and the portion of costs that would have been allocated that otherwise would have applied to the in-kind replacement facility.

XIII. Interregional Transmission Coordination[30]

Transmission providers must revise their existing interregional transmission coordination procedures and regional transmission planning processes as needed. These revisions must provide for: (1) sharing information regarding Long-Term Transmission Needs and Long-Term Regional Transmission Facilities and (2) identifying and jointly evaluating interregional transmission facilities that may be more efficient or cost-effective to address Long-Term Transmission Needs. Transmission providers must revise their interregional transmission coordination procedures to permit an entity to propose an interregional transmission facility in the regional transmission planning process.

The Final Rule requires transmission providers to provide the following Long-Term Regional Transmission Planning information on their public website or through an appropriate email list:

(1) Long-Term Transmission Needs discussed in the interregional transmission coordination meetings;

(2) any proposed or identified interregional transmission facilities;

(3) the voltage level, estimated cost, and estimated in-service date of those proposed or identified interregional transmission facilities;

(4) the results of any cost-benefit evaluation of such interregional transmission facilities; and

(5) if any, the interregional transmission facilities selected to meet Long-Term Transmission Needs.

XIV. Conclusion

Order No. 1920 is one of the lengthiest and most complex rules ever issued by FERC. It also seems likely to be one of the most controversial. Its proponents hope that it will reform and improve transmission planning in a way that will help to facilitate the ongoing “clean energy transition.” Opponents contend that it exceeds the Commission’s legal authority and will force consumers to subsidize other states’ clean energy policy choices. Congress seems certain to pay considerable attention to the issues that Order No. 1920 raises. And unlike most major FERC rules in the past, it seems clear that Order No. 1920 could be subject to major changes depending on the results of the presidential election.

If you have any questions or would like to discuss any aspect of Order No. 1920, please reach out to any of the contact attorneys identified in this document.

[1] See https://x.com/ChristieFERC/status/1790356461404471591 (“FERC is doing just about everything we asked, [Senator Schumer] said. Yet more proof that my characterization of the transmission rule was 100% accurate: a sweeping policy agenda that Congress has never passed into law”).

[2] https://x.com/ChristieFERC/status/1790380213601255805.

[3] https://www.utilitydive.com/news/ferc-order-1920-transmission-planning-clements/716247/.

[4] This section summarizes Order No. 1920 Part II, PP 47-139.

[5] This section summarizes Order No. 1920 Part III.A, PP 140-283.

[6] This section summarizes Order No. 1920 Part III.B, PP 284-306.

[7] This section summarizes Order No. 1920 Part III.C.1, PP 307-51.

[8] This section summarizes Order No. 1920 Part III.C.2, PP 352-86.

[9] This section summarizes Order No. 1920 Part III.C.3, PP 387-537.

[10] This section summarizes Order No. 1920 Part III.C.4, PP 538-63.

[11] This section summarizes Order No. 1920 Part III.C.5, PP 564-77.

[12] This section summarizes Order No. 1920 Part III.C.6, PP 578-601.

[13] This section summarizes Order No. 1920 Part III.C.7, PP 602-44.

[14] This section summarizes Order No. 1920 Part III.C.8, PP 645-66.

[15] This section summarizes Order No. 1920 Part III.D.1, PP 667-739.

[16] This section summarizes Order No. 1920 Part III.D.2, PP 740-822.

[17] This section summarizes Order No. 1920 Part III.D.3, PP 823-42.

[18] This section summarizes Order No. 1920 Part III.D.4, PP 843-70.

[19] This section summarizes Order No. 1920 Part III.D.5, PP 871-90.

[20] This section summarizes Order No. 1920 Part III.D.6, PP 891-903.

[21] This section summarizes Order No. 1920 Part III.E, PP 904-1061.

[22] This section summarizes Order No. 1920 Part III.F, PP 1062-75.

[23] This section summarizes Order No. 1920 Part IV, PP 1076-1162.

[24] This section summarizes Order No. 1920 Part V, PP 1163-1247.

[25] This section summarizes Order No. 1920 Part VI, PP 1248-1523.

[26] The components of the State Agreement Process are discussed in detail infra. As an initial matter, however, it should be noted that a transmission provider has the right not to file a State Agreement Process.

[27] This section summarizes Order No. 1920 Part VII, PP 1524-47.

[28] This section summarizes Order No. 1920 part VIII, PP 1548-64. Order No. 1920 adopted a different right of first refusal proposal regarding “right-sized replacement transmission facilities” which is discussed infra in Section XII.C.2.

[29] This section summarizes Order No. 1920 Part IX, PP 1565-1739.

[30] This section summarizes Order No. 1920 Part X, PP 1740-58.