What’s in FERC’s 500-Page Transmission NOPR?

A (Relatively) Quick Guide

Last week, at its April 2022 open meeting, the Federal Energy Regulatory Commission announced its long-awaited Notice of Proposed Rulemaking (NOPR) on its reforms for transmission planning, project selection, and cost allocation. The rule is substantial — both in its content and length. It responds to a growing clamor for accelerated development of transmission capacity to ensure that the electric grid continues to support cost-effective reliability and resilience amid big changes on the supply and demand sides of the power sector. The reforms it proposes are process-oriented. They do not favor particular outcomes, but instead direct open and transparent processes for transmission development.

Introducing the NOPR, Chair Glick emphasized the relationship between reliability and “a longer-term forward-looking approach” to transmission planning. Commissioners Clements and Christie both emphasized that the NOPR would create a formal role for states in transmission planning and cost allocation — Clements said they could be “decision partners”; Christie said they “are going to be at the heart of the planning.”

This blogpost provides an overview of each of the NOPR’s component parts and distills key points from the rhetoric surrounding the proposal (as well as its nearly 500 pages).

To begin, the NOPR identifies several significant problems with the current approach taken to transmission planning, project selection, and cost allocation. According to the Commission, that approach has resulted in the development of inefficient and often undersized transmission projects that reflect short-term and piecemeal thinking. More specifically, the Commission has found that current planning and cost allocation processes fail to identify and address transmission needs driven by changes happening on the supply and demand sides of the power sector. Instead, they prioritize near-term reliability and effectively assume a static energy system. The transmission projects that result are inefficient and a source of FERC-jurisdictional rates that are unjust and unreasonable and unduly discriminatory and preferential. The NOPR’s process reforms are intended to redirect transmission planning away from this outcome.

The rest of this blogpost summarizes the six types of reforms proposed in the NOPR, which relate to: regional transmission planning, regional transmission cost allocation, a construction work in progress (CWIP) Incentive, restoration of a conditional federal right of first refusal (ROFR), enhancements to transparency in planning and project selection, and interregional transmission coordination and cost allocation. These proposals are all directed at public utility transmission providers — the entities that own, control, or operate transmission facilities.[1] This blogpost refers to those entities as “transmission providers.”

1. Long-Term Regional Transmission Planning

The NOPR’s first 150 pages describe changes to the regional transmission planning process. The Commission explains that the basic aim of this reform is to depart from an approach to planning that effectively assumes the future will look like the past and to instead require forward-looking, long-term scenario planning to meet transmission needs driven by “changes in the resource mix and demand.” As numerous commenters described to the Commission — and as the modeling outputs shown in the maps below illustrate — those changes will be significant and arise quickly. To achieve its basic aim, the Commission’s NOPR proposes prescribing the use of long-term scenarios, requires some coordination with the interconnection process, and suggests a list of benefits to consider when assessing transmission project proposals that can meet the needs of the future supply and demand.

Source: Vibrant Clean Energy

* DPV indicates distributed solar PV; UPV indicates utility-scale solar PV

Concretely, it calls for transmission providers to conduct regional transmission planning by:

• using a 20-year time horizon (or longer) for scenario development (P 92) and reassessing those scenarios at least every 3 years (P 93);
• incorporating into those scenarios “a set of Commission-identified categories of factors that may affect transmission needs driven by changes in the resource mix and demand” (P 91). Those factors include enacted federal, state, and local laws that bear upon the resource mix (P 106), market trends in technology and fuel costs, electrification, resource retirements, and generation interconnection (P 107), and nonbinding clean energy or emissions goals of governments and corporations (P 108).
• developing at least four “plausible and diverse” scenarios that reasonably capture probable future outcomes and make it possible to distinguish among the effects of distinct transmission facilities or distinct benefits for similar transmission facilities (P 123);
• employing “best available data,” meaning data that are timely, were developed using diverse and expert perspectives, were adopted through a process that satisfies the transparency principles of various transmission orders, and reflect a list of Commission-defined factors (P 130); and
• possibly identifying for inclusion in the scenarios geographic zones with strong potential for new generation resource development (P 145) — this is not a requirement, but the Commission will require planning entities to consider it and spells out a process for employing such zones (PP 147–51).

In addition to these key features of the Long-Term Scenario planning called for by the Commission, several other reform measures aimed at the transmission planning and project selection process deserve mention: coordination with the generation interconnection process, characterizing transmission’s benefits, requiring greater transparency and consistency in project selection decisions, and several other technical requirements. These are summarized below.

Coordination with the interconnection process: Transmission needs are often identified through the generation interconnection process rather than through the transmission planning process. This results in parallel efforts that are at best uncoordinated, at worst incoherent, and are, in any case, inefficient. The NOPR takes a step toward better coordinating these processes. Transmission providers are to consider proposed transmission facilities in the regional planning process if those facilities would address interconnection-related needs that (1) have been identified in at least two queue cycles in the past five years, (2) require an upgrade of at least 200 kV or have an estimated cost of at least $30 million, (3) have not been developed due to request withdrawals, and (4) are not slated for address by an upgrade in an executed agreement (or in an agreement the developer requested to be filed unexecuted) (P 166). This modest form of coordination is meant to ensure that transmission needs identified through interconnection applications are not ignored in the regional transmission planning process.

Benefits of transmission: Responses to the Commission’s Advance Notice of Proposed Rulemaking were full of discussions of transmission’s benefits and of the need to capture those benefits accurately and completely in the contexts of planning, project selection, and cost allocation. In the NOPR, the Commission proposes several reforms related to identifying and evaluating benefits of transmission facilities that address needs driven by changes in the resource mix and electricity demand. The Commission stopped short of prescribing a list of benefits, but the NOPR includes a list of benefits (see Table 1) that could be considered to reasonably capture the benefits of transmission facilities that meet identified needs.

In addition to the quick summary provided in that table, the NOPR elaborates further on the nature of those benefits (which do not include decarbonization) and suggests ways to estimate them:

• Avoided or deferred reliability transmission projects and aging infrastructure replacement (P 189);
• Either reduced loss of load probability or reduced planning reserve margin (P 194);
• Production cost savings (P 198);
• Reduced transmission energy losses (P 202);
• Reduced congestion due to transmission outages (P 205);
• Mitigation of extreme events and system contingencies (P 206);
• Mitigation of weather and load uncertainty (P 208);
• Capacity cost benefits from reduced peak energy losses (P 210);
• Deferred generation capacity investments (P 213);
• Access to lower-cost generation (P 216);
• Increased competition (P 219); and
• Increased market liquidity (P 205).

Whether or not transmission providers make use of some or all of this list, they are required to evaluate the benefits of facilities proposed to meet identified transmission needs. That evaluation must identify the effects that will be treated as benefits, explain how they will be calculated, and justify their inclusion. Further, benefits must be evaluated over at least a 20-year time horizon, starting from the estimated in-service date of the transmission facilities (P 227). The Commission also encourages, but doesn’t require, transmission providers to evaluate benefits for a portfolio of transmission facilities rather than on a facility-by-facility basis (P 233).

Project selection: The NOPR contains two meaningful requirements with respect to project selection. First, transmission providers must specify project selection criteria that are transparent, not unduly discriminatory, and intended to maximize benefits to consumers over time without overbuilding transmission facilities (P 241). The NOPR leaves it to transmission providers to decide how exactly to assess a given facility’s efficiency or cost-effectiveness — for instance, by using a benefit-cost ratio or net benefits (P 243). Second, transmission providers must create a process to consult and coordinate with affected states before developing these criteria (P 244). This is just one element of the formal role that the NOPR creates for states in transmission development.

Further minor requirements: Sprinkled throughout the NOPR’s description of transmission planning measures are several small but important suggestions and directives. For instance, at least one of the four or more plausible long-term scenarios must account for “uncertain operational outcomes” due to a high-impact, low-frequency event, which could include an extreme weather event or a cyber attack (P 124). In addition, while the Commission does not require the use of probabilistic or stochastic techniques, its NOPR details some advantages of their use (P 124). The Commission’s NOPR does require full consideration of the potential of incorporating dynamic line ratings and advanced power flow control devices into transmission facilities (P 272). That is, for each identified transmission need, project selection must entail consideration for whether a facility that incorporates these technologies would be more efficient and cost-effective (P 273).

In addition to noting things that the NOPR will change about transmission planning and project selection, it is important to also note one basic feature that can remain the same: transmission providers can continue identifying transmission needs in terms of reliability concerns or economic considerations (P 89). While transmission providers may use an approach that combines more than one driver of transmission need, they are not required to, and they carry the burden of demonstrating why a combined approach would comply with the NOPR and Order 1000. Simply put, the NOPR does not put a stop to siloing transmission needs according to Order 1000’s categories of reliability, economics, and public policy.

2. Cost Allocation of Long-Term Regional Transmission Facilities

FERC wants to give states a seat at the cost allocation negotiating table. That is, the NOPR proposes creating a formal role for states to work with transmission providers to resolve questions about how to allocate the costs of projects developed through the long-term planning process. The Commission explains that “providing state regulators with a formal opportunity to develop a cost allocation method for regional transmission facilities . . . could help increase stakeholder — and state — support for those facilities, which, in turn, may increase the likelihood that those facilities are sited and ultimately developed with fewer costly delays and better ensure just and reasonable Commission-jurisdictional rates” (P 299). The proposal for how exactly to give states a formal role rests on a straightforward foundation: transmission providers are to amend their tariffs to incorporate prescribed reforms, and before doing so they must seek the agreement of “relevant state entities” (defined at P 304) in their region and indicate to the Commission that those entities agreed or that they did not agree in spite of good faith efforts to obtain their agreement (PP 302–03). The state or states in a given transmission provider’s region can also opt to forgo any role in determining the method of cost allocation for transmission projects developed through the long-term planning process (P 305).

The core features of the cost allocation reforms proposed in the NOPR, which are summarized below, include: prescribed approaches to developing cost allocation methods; the nature of “agreement” between relevant state entities and a transmission provider regarding those methods; and the benefits that are to be considered for cost allocation purposes.

Approaches to developing a method of cost allocation: The NOPR offers two methods of cost allocation — a Long-Term Regional Transmission Cost Allocation Method, and the State Agreement Process. A transmission provider, after consulting with and seeking agreement from the relevant state entities, can opt for one, the other, or a combination of the two. The Cost Allocation Method would be an ex ante method for determining how to allocate the costs of regional transmission projects developed through the long-term planning process (P 302 n508). By contrast, the State Agreement Process would be an ex post process that would begin upon selection of a project through a long-term regional planning process and would establish the method for allocating the costs of that project — or project portfolio (P 302 n509). Whatever method is selected through the State Agreement Process must be approved by the Commission and must comply with the cost allocation principles in Order 1000 (P 312).

Even where states don’t select the State Agreement Approach, the NOPR still directs transmission providers to give them a role in selecting the cost allocation method for a project proposed through the long-term planning process (P 319). Specifically, the transmission provider must set out a specified time-frame — the NOPR preliminarily prescribes a 90-day period (P 323) — during which the states in the planning region can negotiate an alternative allocation method to be applied. Any agreement to this method must be unanimous (P 319). However, while the transmission provider would be required to give states this time and opportunity, it does not need to file the alternative method they propose with FERC (P 319). Further, if either the states do not come to agreement, the transmission provider decides not to file the alternative, or the Commission does not approve the alternative, then the transmission developer may use whatever ex ante cost allocation method would have applied in the first place.

Agreement on a cost allocation method: The NOPR directs transmission providers to seek agreement from the relevant state entities about what method to employ for allocating costs of one or more projects developed through the long-term planning process. The transmission providers have discretion in determining what constitutes “agreement” (P 306). However, when filing tariff changes, they must also explain why the revisions reflect state agreement, or how good faith efforts to reach agreement failed (P 308).

The NOPR also contemplates what should happen where agreement is not reached, and seeks comment on its three suggestions for how to handle disagreement: (1) the transmission provider could be required to establish a cost allocation method; (2) the states could be afforded additional time to reach agreement; or (3) FERC could be responsible for establishing the cost allocation method (P 310). Where the states forgo involvement, the transmission provider simply must propose a cost allocation method that is consistent with Order 1000 (P 307).

Benefits: The Commission finds that current approaches to cost allocation may undervalue the benefits of long-term regional transmission facilities, particularly because those approaches considers only a subset of benefits based on the type of transmission need that is being studied (P 325). To improve the situation, the Commission directs transmission providers to consider adopting — for the purposes of cost allocation — the same list of benefits described in relation to long-term planning (P 326). As with planning, the transmission provider is to identify the benefits that will be incorporated into its cost allocation methodology, explain how those benefits will be calculated, and justify their inclusion (P 326).

Finally, the Commission clarifies that nothing in this NOPR amends the existing rules under Order. 1000 for cost allocation of interregional projects selected in the regional planning process (P 278 n. 441).

3. Replacing the CWIP Incentive

The Commission proposes to cease granting transmission providers the construction-work-in-progress (CWIP) incentive first authorized by the Energy Policy Act of 2005 and implemented by FERC with Order 679. In that order, the Commission acknowledged that it was departing from the standard practice of only allowing cost recovery for projects that were used and useful to consumers. It justified that departure as striking a balance between transmission providers’ need for more certain cost recovery with the risk that projects receiving the CWIP incentive would never enter into service, such that consumers would bear a cost but reap no benefit from it (P 331).

Now that the Commission is directing use of a 20-year planning horizon, that balance has tipped and authorizing use of the CWIP incentive would, in the Commission’s view, impose too great a risk on consumers. As such, it proposes replacing the CWIP incentive with an Allowance for Funds Used During Construction (P 333), meaning that transmission providers can recover costs — including financing costs — once their transmission facility is put into service.

4. Restoring a Federal ROFR for Jointly Owned Facilities

The NOPR proposes to restore a version of the federal right of first refusal (ROFR), so that an incumbent transmission provider — that is, an entity that develops a transmission facility within its own service territory — can have first crack at developing a transmission project (P 337). The federal ROFR was largely eliminated when the Commission adopted Order 1000 in 2011, although FERC allowed exceptions for local projects and upgrades to existing projects (P 342). That change was intended to remove a potential barrier to entry for non-incumbents, and to prevent incumbents from foreclosing efficient projects out of self-interest. (P 340). But the years since Order 1000 have seen a shift, and now “transmission investment has . . . largely been concentrated in transmission facilities generally not subject to competitive transmission development processes.” (P 344). After observing that eliminating ROFR inadvertently discouraged investment in regional transmission projects, (P 350), the Commission proposed restoring it — with an important condition. The NOPR proposes to make an incumbent eligible for federal ROFR if it would own the proposed transmission facility jointly with an unaffiliated non-incumbent or incumbent transmission provider (P 358). This solution was suggested by several commenters based on their experience with the successful development of projects jointly owned by incumbent and non-incumbent transmission providers (PP 360–61).

Recognizing that granting even a conditional ROFR can introduce risks, the Commission’s proposal spells out specific process steps that it envisions an incumbent would follow when making use of this measure (PP 367–70).

5. Coordinating Local Planning and Replacements with Regional Transmission Planning By Enhancing Transparency

The NOPR seeks to better integrate local transmission replacement decisionmaking into the regional transmission planning process by adding transparency requirements to local planning and asking regional planners to consider whether replacements might be more efficiently upgraded as a part of the regional planning process.

When local facilities (those located entirely in a transmission provider’s retail distribution service territory) begin to age and need to be replaced, that information is generally not considered in the regional planning process. When replacements do not incrementally increase the facility’s capacity (known as an “in-kind replacement”), then the replacement is not subject to regional planning requirements. Thus, regional planning generally does not consider whether these replacements of local facilities could be modified to more efficiently or cost-effectively address regional transmission needs (P 385).

The Commission’s proposed reforms in relation to replacement of local facilities reflect the concern that local planning lacks adequate transparency and stakeholder input, and that regional planning and local planning are not adequately coordinated (P 398). FERC also justifies its proposals for reform on the grounds that much of the existing transmission infrastructure is aging and needs to be replaced, which — absent reform — will be done without considering how replacements could be modified to more efficiently and cost-effectively meet regional needs (P 399). Right-sizing replacements (i.e., modifying replacement to increase the facility’s transfer capability) can address both the need for replacement and regional needs, but requires enhancing transparency with respect to in-kind replacements and coordination with regional planning, neither of which currently occurs (P 399). As summarized below, the NOPR’s proposals focus on fostering transparency and identifying facilities for right-sizing.

Greater transparency: The Commission’s reforms begin with several requirements to imbue transparency into the local planning process. Transmission providers will be required to update their tariffs to include: the criteria, models, and assumptions that they use in their local transmission planning process; the local transmission needs that they identify through that process; and the potential local or regional transmission facilities that they will evaluate to address those local transmission needs (P 400).

Transmission providers would also implement a process for stakeholder input on local planning through the regional planning process, laid out by the Commission (P 401). As part of the regional planning process, transmission providers will be required to hold at least three meetings focused on the local planning process of each member provider in the region. This must occur before local plans can be incorporated into regional planning models (P 400). These new stakeholder meetings on local planning are intended to add transparency to local planning and help identify regional facilities that may be better suited than proposed local facilities (P 402).

Identification of right-sized replacements: As part of the long-term regional planning, transmission providers are also required to identify facilities operating at or above 230kV that the transmission provider plans to replace during the next 10 years and to evaluate whether those facilities could be right-sized to more efficiently or cost-effectively meet needs identified in the long-term regional planning process (PP 403–04). The Commission lays out the specific process that should occur to implement this reform (P 407).

The Commission will require transmission providers to amend the planning process to provide greater transparency on which right-size replacements have been selected for the regional plan for purposes of cost allocation, and which facilities are simply being included in the regional plan for informational purposes (P 413).

Cost allocation and ROFR: Right-sized replacements can be selected in the regional transmission plan for purposes of cost allocation (P 407). However, only the incremental cost of right-sizing the facilities is eligible to use the long-term regional transmission cost allocation method (P 410). Costs that would have otherwise been incurred for the in-kind replacement should be allocated as they would have been (P 410). And, these right-size replacements are eligible for a federal ROFR for the transmission provider that included the in-kind replacement in its in-kind replacement estimate (P 409).

Coordination with a caveat: But, even with these reforms, the Commission clarifies that it does not intend to alter transmission providers’ rights to choose to simply replace the regional facility. Thus, even where a right-size replacement is selected in a regional transmission plan, the transmission provider can decide to proceed with the in-kind replacement and forego inclusion in the regional plan for purposes of cost allocation (P 412).

6. Updating Interregional Transmission Coordination and Cost Allocation for Long Term Planning

The proposed reforms for interregional coordination and cost allocation focus on ensuring that interregional facilities can be considered where they would more efficiently or cost-effectively meet transmission needs identified in the long-term regional planning process (P 429). The goal is to ensure that interregional facilities can be considered in the long-term regional planning process laid out in the NOPR (P 428), rather than making fundamental changes to the interregional coordination and cost allocation procedures. Neighboring transmission providers need to share information regarding their respective transmission needs identified in the long-term regional planning process and about the potential facilities to meet those needs, and must have procedures to jointly identify and evaluate interregional facilities that can meet those needs (P 427).

So Will the NOPR Deliver?

The Commission’s NOPR seeks to reorient transmission planning to the future, and to resolve tensions with state-level decisionmakers by giving them a formal role in decisions about how to allocate the costs of transmission projects. As the NOPR describes at length, the need for this reorientation and resolution is pressing. The transmission system has become a major bottleneck with respect to several priorities, including, most importantly, cost-effective reliability and resilience amid rapid changes on the supply and demand sides of the power sector. Regional planning under existing rules has largely failed to deliver the kind of long-distance, high-voltage transmission capacity that the nation needs. The measures called for by this NOPR could loosen that bottleneck.

However, the process changes proposed in the NOPR still give transmission providers a great deal of discretion for the sake of respecting regional differences. Previous orders did the same, and transmission providers have consistently taken advantage of opportunities to avoid the sort of regional and interregional projects that are needed. Close scrutiny of compliance efforts will be important for realizing the NOPR’s potential.

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[1] The NOPR defines this term at P 3 n.5: “A public utility transmission provider means a public utility that owns, controls, or operates transmission facilities. The term public utility transmission provider should be read to include a public utility transmission owner when the transmission owner is separate from the transmission provider, as is the case in regional transmission organizations (RTO) and independent system operators (ISO). The term ‘public utility’ means ‘any person who owns or operates facilities subject to the jurisdiction of the Commission . . . .’ 16 U.S.C. 824(e).”

By Justin Gundlach and Sarah Ladin.