Order No. 1920: FERC Reshapes the Transmission Planning Landscape

The Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 1920 on May 13, 2024 to increase the pace of transmission grid expansion and strengthen regional transmission planning.[1] The landmark order, as well as the concurrence and dissent of the Commissioners voting on the order, is summarized below. At bottom, it represents a fundamental reshaping of the transmission planning landscape, requiring long-term transmission planning, closer coordination between generation interconnection and regional transmission planning, and revisions to the local transmission planning process to close loopholes created by Order No. 1000 in 2011.

The order’s effective date will be August 12, 2024, 60 days after the date it was published in the Federal Register on June 11, 2024. Compliance filings will be due on June 12, 2025, unless the date is extended on rehearing.

Executive Summary

At its core, Order No. 1920 achieves four major goals, requiring that all transmission providers, in regions with independent system operators and regional transmission organizations (“ISO/RTO”) and in non-ISO/RTO regions, do the following:

1. Plan transmission on a 20-year horizon, with multiple transmission needs scenarios, and thorough, long-term consideration of the benefits of a proposed regional transmission project;
2. Revise local transmission planning processes to include greater transparency, public notice stakeholder engagement, and allow for regional “right sizing” of local projects to meet longer term needs;
3. Consider unresolved recurring interconnection network upgrades in the regional transmission planning process; and
4. Consider specified alternative transmission technologies, including dynamic line ratings, advanced power flow control devices, advanced conductors and transmission switching.

The order was approved 2 to 1, with Chairman Willie Phillips and Commissioner Allison Clements voting in favor and issuing a joint concurrence, and Commissioner Mark Christie voting against, and issuing a dissent. Chairman Phillips and Commissioner Clements wrote a strong concurrence, emphasizing the need for action and rebutting Commissioner Christie’s dissent. Commissioner Christie wrote a long and detailed dissent, objecting to the order as a whole and specifically, to what he sees as the diminishment of states’ roles in the transmission planning process.

Background

Order No. 1920 is built on the shoulders of three significant prior Commission orders related to transmission and transmission planning: Order Nos. 888, 890 and 1000. In 1996, the Commission issued Order No. 888, which required public utilities to give open access on the transmission facilities they own or operate, and also included minimum requirements on transmission planning.[2] In 2007, the Commission issued Order No. 890, which set forth nine transmission planning criteria: (1) coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; (7) regional participation; (8) economic planning studies; and (9) cost allocation for new projects.[3] In 2011, the Commission issued Order No. 1000 to require regional transmission planning and cost allocation, created the concept of a public policy driven transmission need, and developed principles for cost allocation.

A decade after Order No. 1000, the Commission began assessing the current status of regional transmission planning and considering whether further changes were necessary given the lack of regional transmission project planning and the growing need for transmission given the changing resource mix. The process began with technical conferences and the development of the Joint Federal-State Task Force on Transmission, then led to an advance notice of proposed rulemaking (“ANOPR”) in 2022 and a notice of proposed rulemaking (“NOPR”) in 2023. Commenters broadly agreed that existing transmission planning processes were not ensuring efficient and cost-effective transmission development, and are not achieving the goals set out in Order Nos. 890 and 1000. Some commenters specifically noted that transmission owners were using local transmission planning processes as a means to evade Order No. 1000 regional planning requirements, leading to excessive costs. Others noted that transmission planning is happening through other mechanisms outside of regional transmission planning process, including through the generator interconnection process and the local transmission planning process. Conversely, some commenters expressed concerns that the Commission may use the process of revisiting transmission planning to improperly favor certain energy resources.

In issuing Order No. 1920, the Commission found that the absence of “sufficiently long-term, forward-looking, and comprehensive transmission requirements is causing transmission providers to fail to adequately anticipate and plan for future system conditions.”[4]

Long-Term Regional Planning

Order No. 1920 finds that many transmission providers are using shorter time horizons to plan transmission. For example, the order points to ISO New England using a 10-year horizon, and PJM using horizons ranging from 5 years to 6-15 years. It finds that the lack of longer-term planning horizons renders the transmission planning process unjust and unreasonable, in part, because consumers are bearing the cost of less effective, piecemeal transmission investment and expansion, instead of a larger, longer-term solution to an identified problem.

Therefore, the order holds, regional transmission planners must use a time horizon of no less than 20 years starting from the in-service date of each transmission facility, to evaluate proposed facilities under seven (7) specific benefits.

Long-Term Scenarios

Order No. 1920 requires transmission providers to develop at least three Long-Term Scenarios extended over a time horizon of not less than 20 years. The Long-Term Scenarios should be developed using the best available data sets, reassessed and revised every 5 years, and include sensitivities for potential extreme weather events. Each of the three scenarios must be plausible and diverse. The Long-Term Scenarios should include:

• • forecasts of the level and pattern (i.e., hourly and seasonal variability) of future electricity demand;
  • the quantity, location, and type of resource additions and retirements;
  • other relevant forecasts about the electric power system that are used as inputs to the transmission model and determine the need for new transmission facilities over the transmission planning horizon;
  • forecasts for natural gas prices;
  • increasing outage trends due to extreme weather and climatic trends; and
  • other future events.[5]

These scenarios will be used in the Long-Term Regional Transmission Planning process, and also to identify, evaluate and re-evaluate proposed projects. Order No. 1920 requires that transmission providers use the seven benefits discussed below in determining Long-Term Scenarios, and when analyzing or re-evaluating the benefits of proposed projects.

Order No. 1920 also sets forth the following categories of factors transmission providers must consider when developing Long-Term Scenarios:

• • federal, federally-recognized Tribal, state, and local laws and regulations that affect the future resource mix and demand;
  • federal, federally-recognized Tribal, state, and local laws and regulations on decarbonization and electrification;
  • state-approved integrated resource plans and expected supply obligations for load serving entities;
  • trends in fuel costs and in the cost, performance, and availability of generation, electric storage resources, and building and transportation electrification technologies;
  • resource retirements;
  • generator interconnection requests and withdrawals; and
  • utility and corporate commitments and federal, federally-recognized Tribal, state, and local goals that affect Long-Term Transmission Needs.

Transmission planners may include other factors into Long-Term Scenarios if they wish, as long as the scenarios remain plausible.

Benefits Analysis

Under Order No. 1920, transmission providers must use seven required benefits to build Long-Term Scenarios, conduct transmission planning, and assess and re-evaluate proposed projects. These benefits must be considered over the same 20-year time horizon required for Long-Term Scenarios. The seven benefits are:

• • Benefit 1: Avoided or deferred reliability transmission facilities and aging transmission infrastructure replacement;
  • Benefit 2(a): Reduced loss of load probability or
  • Benefit 2(b): Reduced planning reserve margin;
  • Benefit 3: Production cost savings;
  • Benefit 4: Reduced transmission energy losses;
  • Benefit 5: Reduced congestion due to transmission outages;
  • Benefit 6: Mitigation of extreme weather events and unexpected system conditions;
  • Benefit 7: Capacity cost benefits from reduced peak energy losses.

Order No. 1920 mandates consideration of these seven benefits in each Long-Term Scenario, and evaluation of proposed facilities for selection. However, transmission providers retain flexibility to consider other benefits, including the five additional benefits proposed in the NOPR but not included in the final rule – mitigation of weather and load uncertainty, generation capacity investments, access to lower-cost generation, increased competition, and increased market liquidity.

On compliance, transmission providers must identify the benefits they will use in planning, how they will calculate those benefits, and how those benefits will reflect the benefits of regional transmission facilities.

Evaluation, Selection and Reevaluation of Transmission Projects

Under Order No. 1920, transmission providers must establish a long-term regional transmission planning process that (1) identifies proposed facilities that address long-term needs; (2) evaluates the benefits of those proposed facilities; and (3) designates a point at which the planners will decide whether to select a particular proposed project for cost allocation. Transmission providers have flexibility to propose selection criteria, within the guidelines set out by the Commission. At a minimum, however, those criteria must be (1) transparent and not unduly discriminatory; (2) ensure that more efficient or cost-effective transmission facilities are selected; and (3) maximize benefits without overbuilding. Transmission providers must propose their selection criteria on compliance.

In evaluating projects, transmission providers must follow at least four steps. First, they must identify one or more projects, or portfolios of projects, that address identified Long-Term Needs. Second, the evaluation process must estimate the costs of any proposed project or portfolio, and measure its benefits. Third, transmission providers must identify a point when the selection will be done, within three years of the start of the planning cycle. Fourth, the planning cycle’s decisions must be sufficiently detailed and transparent that stakeholders can understand why a particular project was selected, and the determination must include the measured benefits. Order No. 1920 does not mandate the use of a “least regrets” or “weighted benefits” approach, leaving flexibility to transmission providers to determine how they will evaluate and select transmission facilities within a minimum cost-benefit ratio higher than 1.25-to-1, as previously approved in Order 1000.

Order No. 1920 requires that transmission providers make good faith efforts to coordinate with, and seek support from, state entities as they develop their criteria on compliance. Further, transmission providers must develop a process to allow states to voluntarily fund all or part of the cost of a transmission facility that would not otherwise meet the transmission provider’s selection criteria.

Finally, transmission providers must establish a reevaluation process for cases of delay in development, cost increases, or significant changes in laws or regulations which might result in a proposed project no longer meeting selection criteria.

Coordination with Generator Interconnection Process

Order No. 1920 requires transmission providers to coordinate the regional transmission planning process with the generator interconnection process. Specifically, transmission providers must consider interconnection-related transmission needs that have been identified in the interconnection process in at least two interconnection cycles across a five-year period, but not resolved due to the withdrawal of the underlying interconnection requests, in the regional transmission planning process.

Order No. 1920 finds that on an increasingly common basis generators withdraw due to the “sticker shock” of its responsibility for network upgrades. These facilities should be considered for selection first in the regional transmission planning process, not the long-term regional transmission planning process. The order finds that the network upgrades at issue should exceed $30 million and have a voltage of at least 200 kV.

Alternative Transmission Technologies

Order No. 1920 holds that transmission planners must consider commercially-available alternative transmission technologies, including dynamic line ratings, advanced power flow control devices, advanced conductors and transmission switching. These technologies must be considered in both the regional transmission planning process and the long-term transmission planning process. The use of the specified technologies is not mandated by the order, but transmission planners must at least consider such technologies as potential solutions to identified needs. Order No. 1920 finds that transmission planners frequently overlook or undervalue the benefits of alternative transmission technologies, which results in higher transmission rates to consumers.

Cost Allocation

Order No. 1920 requires transmission providers to propose in their compliance filings at least one (or more) ex ante cost allocation method, with the State Agreement Process serving as an additional (and optional) ex post cost allocation method. Participant funding may not be the only ex ante process, though it is not forbidden. Transmission providers must establish a six-month engagement period and a forum during which state entities may provide input on cost allocation, but state entities’ agreement is not required.

State Agreement Process

Transmission providers may propose a State Agreement Process, whereby a state or a group of states may voluntarily agree to a cost allocation method for a proposed transmission project or portfolio. This proposal is similar to PJM’s State Agreement Approach (“SAA”). Any cost allocation method arising from a State Agreement Process must be filed with the Commission within six months of the transmission project’s selection. Cost allocations resulting from the State Agreement Process do not need to comply with the cost allocation principles.

Cost Allocation Principles

Order No. 1920 finds that any cost allocation methodology proposed for the long-term regional transmission planning process must comply with five of the six cost allocation principles established by Order 1000. The five principles are: (1) the costs of selected transmission facilities must be allocated to those that benefit from those facilities in a manner that is at least roughly commensurate with estimated benefits; (2) those that receive no benefit from transmission facilities, either at present or in a likely future scenario, must not be involuntarily allocated any of those costs; (3) a benefit to cost threshold ratio, if adopted, cannot exceed 1.25 to 1; (4) costs must be allocated solely within the transmission planning region unless another entity outside the region voluntarily assumes a portion of those costs; and (5) the method for determining benefits and identifying beneficiaries must be transparent.

CWIP

In the NOPR, the Commission proposed to limit the availability of the Construction Work in Progress (“CWIP”) incentive for long-term regional transmission facilities. Order No. 1920 makes no changes to the status quo: it does not adopt the proposed elimination of CWIP and allows it to remain in place, subject to another, future proceeding on transmission incentives.

ROFR

Order No. 1000 eliminated the right of first refusal (“ROFR”) granted to incumbent transmission owners to build regional transmission facilities within their geographic footprint. In essence, this opened the doors to competitive transmission developers by eliminating the ROFR. In the NOPR, the Commission proposed to amend Order No. 1000 to reinstate the ROFR in certain limited situations, including potential joint ownership.

Order No. 1920 does not adopt the NOPR proposal; it leaves Order No. 1000’s elimination of ROFR intact. The order explains that the Commission will continue to consider the proposal to reinstate the ROFR in certain limited conditions in other proceedings.

Local Transmission Planning

Order No. 1920 finds that local transmission processes are unjust and unreasonable, and unduly discriminatory or preferential, because they lack transparency and opportunity for meaningful stakeholder input, and are not coordinated with regional transmission planning. It explains that transmission owners may be using the local transmission process to replace transmission facilities at the end of their useful life, rather than considering through the regional transmission planning process whether those facilities should be upgraded or “right-sized” to more efficiently address transmission needs.

Therefore, transmission planners must propose two changes to their local transmission planning processes. First, they must enhance the transparency of the local transmission planning process. The transparency requirements apply to the criteria, models and assumptions used in the local process; the identified local needs; and the potential local facilities being considered. Transmission providers must publicly post information and conduct at least three publicly-noticed stakeholder meetings.

Second, they must evaluate whether transmission facilities that need replacing can be “right sized” to more efficiently or cost effectively address long-term transmission needs. Transmission providers may propose on compliance a threshold for the size of the facility subject to right-sizing, as long as the minimum size does not exceed 200 kV. Order No. 1920 defines right-sizing as the process of modifying an in-kind replacement of an existing transmission facility to increase that facility’s transfer capability. However, the order establishes a ROFR for right-sized replacement transmission facilities, permitting the transmission owner to opt to build the replacement itself.

Interregional Planning

Order No. 1920 requires transmission providers to revise existing interregional transmission coordination procedures to provide for (1) the sharing of information regarding long-term transmission needs and the facilities that might meet those needs; and (2) the identification and joint evaluation of interregional transmission projects that might be a more efficient or cost-effective way to meet long-term needs. Entities may propose interregional transmission facilities to meet long-term needs in a long-term regional transmission planning process. Transmission providers must post information about the long-term transmission needs discussed in any interregional coordination meeting, any interregional facilities proposed in response to a need, the costs and cost-benefit analysis of any such interregional facility, and the decision made regarding that facility.

Compliance

The effective date of Order 1920 will be August 12, 2024, 60 days after publication in the Federal Register on June 11, 2024. Compliance filings are due within 10 months of the effective date, by June 12, 2025. The first long-term transmission planning cycle must commence within one year of the date of filing the compliance filing, by June 2026, unless transmission providers opt for an earlier date. However, compliance filings on the interregional coordination portion are due within twelve months of the effective date, or by August 12, 2025.  When issuing other significant rulemakings, including Order No. 2023, the Commission extended the compliance filing dates until 30 days after the effective date of the order on rehearing.[6] Therefore, it is possible that these dates might be extended on rehearing.

Concurrence by Chairman Phillips and Commissioner Clements

Chairman Willie Phillips and Commissioner Allison Clements wrote a strong concurrence, explaining the significant need for action given the “pivotal moment for the electricity system” that we are in. They explain that issuing Order No. 1920 is a critical step the Commission must take to meet its reliability imperative and affordability imperative. They explain that failing to act would hamper the reliability of the grid and lead to increased costs to consumers in the future.

They respond in depth to Commissioner Christie’s dissent, explaining that his view violates cost causation principles, harms electric reliability, and ignores the significant opportunities for federal and state cooperation created by Order No. 1920. They assert that under Commissioner Christie’s view that states should voluntarily agree to pay, no transmission would be built and states could benefit from reliability improvements while refusing to pay. They disagree that long-term transmission needs are equivalent to public policy projects seeking to shape resource mix. Rather, they explain, the requirement to consider state public policies is one input into comprehensive long-term regional transmission planning considering all relevant factors and drivers. Further, they disagree that Order No. 1920 deprives states of any long-standing authority over retail rates and transmission siting, explaining that in fact, Order No. 1920 creates new opportunities for federal-state cooperation on transmission.

They also rebut Commissioner Christie’s assertions regarding the Major Questions doctrine. They first explain that Commissioner Christie is incorrect in claiming that the Commission’s intention in issuing Order No. 1920 is to elicit trillions of dollars in transmission spending. Rather, they explain, the goal of the order is to facilitate the development of transmission needed to maintain reliability and affordability. Second, they explain that Commissioner Christie’s arguments about the scope of the Commission’s jurisdiction are incorrect, as courts have found that transmission planning falls within the Commission’s jurisdiction.

Finally, Chairman Phillips and Commissioner Clements address the ROFR issue, explaining that they support joint ownership and that the issue overall is better considered in the transmission planning and cost management docket.

Dissent by Commissioner Christie

Commissioner Mark Christie wrote a scathing dissent, asserting that Order No. 1920 will cost consumers trillions of dollars and is a jurisdictional overreach by the Commission. He asserts that the Commission’s job is to provide consumers with reliable power at the least cost possible. He claims that Order No. 1920, however, is enacted to serve the interests of “politically preferred generation … and corporate ‘green energy’ preferential purchasing policies.” Commissioner Christie asserts that the scope of the rule implicates the major questions doctrine as it is a sweeping policy agenda.

Commissioner Christie explains that he voted for the NOPR because it was a compromise whereby projects could be incorporated into long-term planning, but only if states agreed to both the criteria for consideration and the cost allocation itself. He therefore expressed his belief that states must be allowed to agree – or disagree – with cost allocation for a selected project meeting an identified transmission need. He claims that the final rule takes away the NOPR’s proposals that states must agree to the planning and selection criteria, as well as the cost allocation itself. He believes this approach is unfair as policymakers can impose costs on consumers. He objects to Order No. 1920 because it:

• Imposes preferential policy and corporate-driven project costs on consumers in non-consenting states;
• Mandates planning criteria and purported benefits, rather than permitting flexibility to transmission providers;
• Abandons regional cost allocation principle (6), related to the incorporation of public policy projects;
• Effectively eliminates a voluntary state agreement process, such as the PJM SAA;
• Leaves the CWIP incentive intact; and
• Makes the local transmission planning process less transparent.

Further, Commissioner Christie asserts that Order No. 1920 exceeds the Commission’s jurisdiction under the Federal Power Act (“FPA”) and goes far beyond the scope of Order No. 1000, as affirmed by the courts. He asserts that Order No. 1000 was upheld by the courts because it mandated processes and not outcomes, while Order No. 1920 nakedly intends to produce specific outcomes. He asserts the rule identifies specific policies through the seven categories of factors to consider, and specific outcomes through the seven benefits that must be considered. He argues that Order No. 1920 violates the FPA because it infringes on states’ rights related to resource planning.

He also asserts that Order No. 1920 violates the Major Questions doctrine because Congress has not designated the Commission as a national resource planner, and left both transmission siting and generation development to the states.

At bottom, Commissioner Christie does not see the need for transmission build-out, and believes that the alleged need for transmission is driven only by green policies and corporate green buying. If there were to be transmission planning reform, Commissioner Christie believes it should involve closer cooperation with, and likely deference to, state regulators.