FERC’s New Transmission Rule: From “Band-Aids” to Open Heart Surgery or Something in Between?

A version of this client alert was published in Law360.

I. Introduction

The United States transmission system is getting ready to run a marathon during a heart attack.  Vast projected increases in demand on the system due to electrification, explosive growth in data centers, and other drivers (the marathon), coupled with ineffective transmission development leading to congestion exacerbated by the proliferation of renewable generation resources located far from load centers (the heart attack) has created growing concern that the grid will not be able to deliver electricity where needed at reasonable prices.

The ailment is not new, but the Federal Energy Regulatory Commission’s (the Commission) prescription is. Prior transmission planning reform efforts, including Order No. 1000,^[1]centered on process and were widely regarded as ineffective. Despite the long-known and well-recognized need for transmission build out, not a single non-RTO/ISO transmission facility has been selected for cost allocation as a more efficient or cost-effective transmission facility needed to meet regional transmission needs under Order No. 1000.^[2]Navigating the mosaic of state and local interests has been a major challenge while Senator Manchin’s permitting reform efforts in Congress have failed to gain traction.

The rule, for example, doesn’t address expanding transmission capacity between regions, according to Manchin.

Lack of an effective transmission planning process led to de facto abdication of transmission planning to the generator interconnection process, a job for which it was never intended. Overreliance on the generator interconnection process for transmission upgrades has led to “Band-Aid fixes,” to use Commission Chairman Willie Phillips’ words, because the process identifies upgrades necessary to interconnect individual generators or clusters of generators on an ad hoc basis. According to the Commission, the result has been a patchwork of sometimes inefficient and short-sighted upgrades to the transmission system at unnecessarily high costs.^[3]

In Order No. 1920, Building for the Future Through Electric Regional Transmission Planning and Cost Allocation (the Transmission Rule), the Commission determined that the status quo is no longer just and reasonable and imposed greater control over the process. Under the new rule, transmission providers must plan twenty years into the future and consider a minimum set of criteria necessary to identify, evaluate, and select more efficient and cost-effective long-term regional transmission solutions. Costs may now be allocated pursuant to a state-agreed process or, if none is agreed, the backstop process, ensuring cost allocation even if states cannot agree.

With Order No. 1920, the Commission has taken a big step forward. Senator Manchin applauded the rule, expressing his belief that it would enhance reliability, but more must be done. “These rules help with one aspect of one part of a bigger set of grid permitting problems, but, as my friend Senator Hickenlooper said, they’re ‘a Band-Aid on Congress’s inaction,’” he said.^[4]Senator Manchin observed that the Commission did what it could within its authority but that Congress must act to address expanding transmission capacity between regions—for example, between the electrically islanded Electric Reliability Committee of Texas and its neighbors.^[5]The success of the new Transmission Rule remains to be seen as transmission providers and stakeholders implement important details, but only Congress has the authority to perform the open heart surgery on the grid that Senator Manchin believes is necessary.

II. Order No. 1920 Imposes a More Prescriptive Transmission Planning Regime

The Transmission Rule fills gaps in the Order No. 1000 framework without otherwise disturbing the regional transmission planning structure required by Order No. 1000. The Transmission Rule requires consideration of specific factors over at least a twenty-year planning horizon in the regional planning process. Recognizing the gap-filling role that the generator interconnection process has played in identifying needed transmission build-out, the Transmission Rule requires coordination between the generator interconnection and regional transmission planning processes. And the Commission requires transmission providers to consider whether advanced technologies may be more efficient or cost-effective than traditional transmission projects.

A. Long-Term (20-Year) Regional Transmission Planning and Development Using Long-Term Scenarios

The foundation of the Transmission Rule lies in requiring a longer-term, more comprehensive planning horizon. The Commission determined that unduly short planning horizons failed to plan for the future. The twenty-year minimum time horizon is intended to better account for the benefits that a long-term transmission facility is likely to provide over its useful life.^[6]The Commission’s regional planning framework occurs in three stages:

• • Identification of long-term transmission needs;
  • Evaluation of long-term transmission facilities to determine whether they are “more efficient or cost-effective transmission solutions” to meet identified transmission needs; and
  • Selection of qualifying transmission facilities for development as part of a regional transmission plan.

The Commission adopted reforms in its Transmission Rule that affect the identification, evaluation, and selection phases as discussed below.

1. Identification

Transmission providers will identify long-term transmission needs using at least three long-term modeling scenarios that include a minimum of seven categories of factors:

• • Federal, Tribal, state, and local laws and regulations affecting the resource mix and demand;
  • Federal, 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 policy goals that affect long-term transmission needs.^[7]

Taken together, the Commission believes consideration of these factors will yield a more comprehensive understanding of planning needs. Transmission providers must provide stakeholders with a meaningful opportunity to propose potential factors within the above categories as well as to provide input on how to account for specific factors in the development of modeling scenarios.^[8]Implementation in the coming years will be very important, and developers should engage in these processes. The Commission stated that the burden of making transmission providers aware of laws, regulations, and goals that should be considered lies with stakeholders.^[9] 

2. Evaluation and Selection

The Transmission Rule does not require transmission providers to select any particular transmission facility, even where a proposed transmission facility meets the transmission providers’ selection criteria in their transmission tariffs.^[10]The evaluation process and selection criteria will be developed by transmission providers individually after consultation with states and other stakeholders. But the Commission specified that an evaluation has three phases:

• • Identifying transmission facilities that address identified long-term transmission needs;
  • Estimating the costs and benefits of the identified transmission facilities; and
  • The point in the evaluation process at which transmission providers will determine whether to select or not select identified transmission facilities in the regional transmission plan.^[11]

The Transmission Rule introduces a new requirement to consider use of alternative technologies—dynamic line ratings, advanced power flow control devices, advanced conductors, and transmission switching—when evaluating new regional transmission facilities and upgrades to existing transmission facilities.^[12]

The Commission sought to balance the importance of investment certainty in long-term transmission development with the need to adjust plans to materially changed circumstances by providing for the reevaluation of selected long-term transmission facilities in limited circumstances where: (i) delays in the development of a previously selected long-term facility would jeopardize a transmission provider’s ability to meet reliability needs; (ii) the actual or projected costs of a previously selected long-term facility significantly exceed cost estimates used in the selection process; or (iii) significant changes in laws or regulations cause reasonable concern that a previously selected long-term facility may no longer meet the transmission providers’ selection criteria.^[13]Following reevaluation, a transmission provider may take no action, impose a mitigation plan, reassign the selected facility to a different transmission developer, modify the selected facility, or remove the selected facility from the regional transmission plan.^[14] 

Other aspects of the evaluation and selection process remain unchanged from Order No. 1000’s transmission planning requirements. It remains the case that selected facilities must more efficiently or cost-effectively meet the transmission planning region’s identified long-term transmission needs than other options.^[15]And, although the Commission declined to adopt a general federal right of first refusal allowing investor-owned utilities and public power utilities to build facilities without going out to bid (the ROFR), it left unchanged the applicability of the ROFR to alternative advanced transmission technologies being incorporated into existing transmission facilities.^[16]

3. Cost Allocation

Consistent with Order No. 1000, the transmission developer of a selected long-term transmission facility, whether incumbent or nonincumbent, will be eligible to use the applicable cost allocation method filed by the transmission provider.^[17]Transmission providers must file one or more cost allocation methods that apply to selected long-term transmission facilities.^[18]Any cost allocation methodology must allocate costs in a manner that is at least roughly commensurate with the estimated benefits of the facility and is consistent with cost causation principles and applicable legal precedent.^[19]

Acknowledging that states play a critical role in transmission planning, the Commission determined that facilitating state regulatory involvement in the cost allocation process could minimize delays and costs associated with state and local siting proceedings by increasing state and stakeholder support for selected facilities.^[20]To encourage such involvement, the Transmission Rule permits transmission providers to adopt a State Agreement Process for allocating the costs of all, or a subset of selected long-term transmission facilities, meaning a process by which one or more state entities responsible for electric utility regulation or siting electric transmission facilities may voluntarily agree to a cost allocation method.^[21]

But with the Commission’s adoption of a backstop cost allocation methodology, states can no longer create a logjam that frustrates project development due to a failure to agree. Transmission providers filing a State Agreement Process must file at least one other cost allocation method which would apply as a backstop in case a long-term facility is selected but the State Agreement Process fails to produce a cost allocation method agreed to by the relevant state entities or the transmission provider chooses not to file the cost allocation method agreed to pursuant to the State Agreement Process or the Commission ultimately finds that the cost allocation method resulting from the State Agreement Process is unjust, unreasonable, or unduly discriminatory or preferential.^[22]

B. Coordination of Regional Transmission Planning and Generator Interconnection Processes

Generating project developers are all too familiar with the risk that the generator interconnection process will identify costly upgrades necessary to interconnect their generating facilities. At times, the required upgrade costs are so large that the only economic choice for a developer is to withdraw an otherwise viable and needed generating facility from the queue. Individual generating companies or even clusters of such companies are not suited to finance the construction of major transmission upgrades.^[23]As a result, needed transmission upgrades identified in the generator interconnection process do not get built and have too often gone unaddressed in the regional transmission planning process that is designed to equitably allocate costs of large transmission upgrades. The Transmission Rule addresses this problem by mandating greater coordination between the regional transmission planning and generator interconnection processes.

The Transmission Rule requires transmission providers to evaluate regional transmission facilities to address interconnection-related transmission upgrades identified in the generator interconnection process where the network upgrade(s) has a voltage of at least 200 kV and an estimated cost of at least US $30M and:^[24]

• • The transmission provider has identified network upgrades in interconnection studies to address those interconnection-related transmission needs in at least two interconnection queue cycles during the preceding five years;
  • Such interconnection-related network upgrades are not currently planned to be developed because the interconnection request(s) driving the need for the network upgrades has been withdrawn; and
  • The transmission provider has not identified a network upgrade to address the relevant interconnection-related transmission need in an executed generator interconnection agreement.

Any additional capacity that results from this process would be made available to all interconnection and transmission customers consistent with the Commission’s open access policy.^[25]

III. Backstop Siting Authority

The Commission’s adoption of a backstop cost allocation methodology to fill the gap where states are unable to cooperate complements efforts by the Department of Energy (DOE) to establish backstop federal siting authority. Section 216 of the Federal Power Act authorizes the Secretary of Energy to designate a National Interest Electric Transmission Corridor (NIETC) if the Secretary finds that lack of transmission development in the area harms or is expected to harm consumers and new transmission development would advance important national interests. NIETC designation unlocks federal financing tools such as public-private partnerships through the Department of Energy’s Transmission Facilitation and Transmission Facility Financing Programs. NIETC designation also allows the Commission to issue siting permits under circumstances where state authorities do not have authority to site the line, have not acted on an application for over one year, or have denied an application. 

DOE’s Grid Deployment Office recently released a preliminary list of potential NIETCs.^[26]By June 4, 2024, the DOE invites the public to submit comments on the potential NIETCs on the preliminary list, including about transmission needs within the potential NIETCs and associated consumer harms, the geographic boundaries of the NIETCs, and potential impacts on environmental, community, and other resources within the potential NIETCs. Concurrently with the Transmission Rule, the Commission also issued Order No. 1977 (the Siting Rule).^[27]The Siting Rule updates the process used in the limited circumstances when the Commission exercises its siting authority. It includes a Landowner Bill of Rights, codifies an Applicant Code of Conduct to guide applicants engaging with landowners in the permitting process, directs applicants to develop engagement plans for outreach to environmental justice communities and Tribes, and adds new resource report requirements for air quality and environmental noise, environmental justice, and Tribal resources.

The common theme shared by DOE’s NIETC designations and the Commission’s Transmission Rule is the effort by federal regulators to provide alternatives to get needed transmission built where state and local interests may have frustrated or stymied that process in the past.

IV. Commissioner Christie Dissent and Possible Grounds for Challenge

The FERC commissioners’ individual statements appended to the Transmission Rule provide starkly contrasting interpretations of the rule’s purpose and impact, as well as its suitability to the Commission’s raison d’etre to protect consumer interests. It is an open question which narrative would prevail in the courts.

FERC Commissioner Mark Christie’s dissent outlines likely grounds for litigation seeking to overturn the Transmission Rule. He argues that the Transmission Rule exceeds the Commission’s legal authority while infringing on states’ authority over electric generation reserved to them by Congress and “is nothing but a pretext to enact a sweeping policy agenda that Congress never passed” that will “produce the preferred generation mix that the current presidential administration, some huge multinational corporations, some members of Congress, and other special interests want now.”^[28]The Transmission Rule, he continues, will hurt consumers by socializing trillions of dollars of costs for the transmission necessary to pursue that transformational policy agenda.^[29]Christie says he could have overlooked all of these failings in the name of compromise “had the states been given the authority to protect their consumers,” but the “final rule denies states that essential role.”^[30]

FERC Chairman Willie Phillips and Commissioner Allison Clements’ joint concurrence argues that failure to act now would “leav[e] consumers holding the bag for the inevitable more costly upgrades in the future.”^[31]They contest Christie’s focus on the requirement for transmission providers to consider state public policies and argue that “other factors, including the fundamental economic and reliability drivers, [will] play a much bigger role.”^[32]Viewing the Transmission Rule’s contemplated long-term transmission projects as “reliability and affordability projects” leads Phillips and Clements to conclude there is nothing new about the “transmission provider’s role in deciding, without state approval, whether to invest in a transmission project and determine, subject to Commission oversight, which consumers must pay for it.”^[33]

V. Conclusion

The Commission’s Transmission Rule has been hailed as “historic,” “watershed,” and “landmark.”  Indeed, the Commission’s prescription for the many challenges limiting significant interregional transmission projects press further than it has gone before. More comprehensive and consistent analysis of transmission needs over a longer time horizon, a backstop cost allocation option, and greater coordination with generator interconnection processes have potential to facilitate larger-scale transmission investment. The Commission’s Siting Rule issued in conjunction with DOE’s NEITCs may also unlock needed investment. The heavy lifting is far from over, however. The Commission will need to defend its order on rehearing and likely on appeal. Transmission providers, stakeholders, states, and others face a long road ahead to implement the Rule in the coming years. And Congress, pressed by Senator Manchin and others, will continue to consider whether open heart surgery is needed for the United States transmission system to be healthy enough to perform in the marathon ahead of ever-increasing demand.

---

^{[1] Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11, 2011), 136 FERC ¶ 61,051 (2011), Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132 (2012), order on reh'g & clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) (“Order No. 1000”).}

^{[2] Building for the Future Through Electric Regional Transmission Plan. & Cost Allocation., Order No. 1920, 187 FERC ¶ 61,068, P 101 (May 13, 2024).  “Selected” is a term of art that means the facility has been selected for cost allocation as opposed to merely listed in a regional transmission plan.  See id. PP 18-19.}

^{[3] Id., PP 101, 103.}

^{[4] Ethan Howland, Sens. Manchin, Barrasso craft bipartisan permitting reform bill amid growing load forecasts, Utility Dive, May 22, 2024, https://www.utilitydive.com/news/manchin-barrasso-permitting-reform-bill-demand-hearing-aep/716809/?utm_source=Sailthru&utm_medium=email&utm_campaign=Issue:%202024-05-22%20Utility%20Dive%20Newsletter%20%5Bissue:62303%5D&utm_term=Utility%20Dive.}

^{[5] See Id.}

^{[6] Transmission Rule, P 859.}

^{[7] Id., P 409.}

^{[8] Id., P 528.}

^{[9] Id., P 509.}

^{[10] Id., P 1026.}

^{[11] Id., P 916.}

^{[12] Id., P 1198.  The Commission declined, however, to require consideration of topology optimization as well as the use of storage that performs a transmission function.  Id., PP 1245-46.}

^{[13] Id., P 1049.}

^{[14] Id., P 1052.}

^{[15] Id., P 957.}

^{[16] Id., P 1202.}

^{[17] Id., P 912.}

^{[18] Id., PP 1291, 1469.}

^{[19] Id., P 1305.}

^{[20] Id., PP 1293, 1362-64.}

^{[21] Id., P 1402.}

^{[22] Id., P1292-93.}

^{[23] Id., P 1103.}

^{[24] Id., P 1145.}

^{[25] Id., P 1115.}

^{[26] Department of Energy, Grid Deployment Office, NIETC Designation Process, https://www.energy.gov/gdo/national-interest-electric-transmission-corridor-designation-process.}

^{[27] Applications for Permits to Site Interstate Electric Trans. Facilities, 187 FERC ¶ 61,069 (May 13, 2024) (“Siting Rule”).}

^{[28] Transmission Rule, Christie Dissent, PP 5, 42, 125.}

^{[29] Id., PP 30, 42.}

^{[30] Transmission Rule, Phillips/Clements Concurrence, PP 122-25.}

^{[31] Id., P 4.}

^{[32] Id., P 14.}

^{[33] Id., PP 17, 22.}