1. Introduction

On May 13, 2024, the Federal Energy Regulatory Commission (FERC) issued Order No. 1920, its long‑awaited transmission planning and cost allocation final rule (Transmission Order) regarding proposed reforms to the regional planning and cost allocation requirements.^[1]; After determining that there is “substantial evidence” that the existing regional transmission planning and cost allocation processes are unjust, unreasonable, and unduly discriminatory,^[2] the Transmission Order, as contemplated in the Notice of Proposed Rulemaking (NOPR),^[3] builds on Order Nos. 888, 890, and 1000 to address Long‑Term Transmission Needs through procedural efficiencies.^[4]; FERC intends for the Transmission Order to remedy the identified transmission planning and cost allocation deficiencies and lead to more effective regional transmission solutions to address Long‑Term Transmission Needs.^[5]

Public utility transmission providers (transmission providers)^[6] will submit a compliance filing by June 12, 2025 revising, in part, their Open Access Transmission Tariffs (OATTs) to demonstrate compliance with the Transmission Order.^[7]; The Transmission Order also requires transmission providers to propose a compliance date, which must be before August 12, 2025 by which they will begin the first Long‑Term Regional Transmission Planning cycle.^[8]

The old adage that “you can’t judge a book by its cover” does not apply to FERC’s landmark decision, the Transmission Order. The title of the Transmission Order‑‑“Building for the Future Through Electric Regional Transmission Planning and Cost Allocation”—is spot on as to what FERC delivers in its 1,269 page Transmission Order.^[9]; The Transmission Order represents a comprehensive reform of FERC’s policies on regional transmission planning and cost allocation, with very specific requirements to be covered in compliance filings and implemented by public utility transmission providers, as detailed below.

2. Long‑Term Regional Transmission Planning
   1. Reforms Implemented in Order No. 1920

FERC has implemented several reforms in the Transmission Order specific to long‑term regional planning, an issue that has been front of mind for the Commissioners. These reforms include:

1. The use of scenarios to identify Long‑Term Transmission Needs and Long‑Term Regional Transmission Facilities to meet those needs
2. Requirements to measure and use at least seven specified benefits to evaluate Long‑Term Regional Facilities, at least 20 years out of the estimated in‑service date
3. Requirements that the transmission providers include evaluation processes in their Open Access Transmission Tariffs to identify and address long‑term needs of the facilities (OATTs)
4. Requirements that the Transmission providers file one or more ex ante (i.e., based on forecasts, rather than actual results) cost allocation methods for the identified facilities^[10]
   2. Requirement to participate in Long‑Term Regional Transmission Planning

A key driver behind the reforms in the Transmission Order is the practice of transmission investment decisions resulting from local planning or generator interconnection processes. Similarly, transmission owners’ use of in‑kind replacement of transmission facilities avoids regional planning processes. As a result, considerable transmission investment occurs outside of long‑term, forward‑looking planning processes, at the same time that overall investment in transmission infrastructure is failing to keep up with demand.^[11]

To address these concerns, the Transmission Order is intended to foster the development of regional transmission plans that consider the multitudinous factors driving Long‑Term Transmission Needs, and produce efficient and cost‑effective transmission solutions to address those needs. FERC derogates piecemeal transmission solutions that address needs in the short‑term as “relatively inefficient and less cost‑effective.”^[12]

The Transmission Order attempts to balance the shortcoming of short‑term planning with the risk inherent of long‑term planning by requiring transmission planners to (1) develop Long‑Term Scenarios to address Long‑Term Transmission Needs and Long‑Term Regional Transmission Facilities^[13] to meet those needs; (2) apply a set of seven required benefits to evaluate Long‑Term Regional Transmission Facilities over a 20‑year minimum planning horizon; and (3) evaluate Long‑Term Regional Transmission Facilities based on their efficiency and cost‑effectiveness compared to other solutions and adopt appropriate criteria to enable their selection.^[14]

In response to concerns that FERC’s Transmission Order is an overreach, FERC concludes it has legal authority under Section 206 of the FPA to enact these reforms.^[15]

1. 3. The Transmission Order Requires Transmission Owners to Develop Long‑Term Scenarios as Part of Long Term Regional Transmission Planning

As part of Long‑Term Regional Transmission Planning, FERC requires transmission providers in each transmission planning region to (1) develop and use 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 (Long‑Term Scenarios) and (2) use those Long‑Term Scenarios to identify and evaluate Long‑Term Regional Transmission Facilities needed to meet Long‑Term Transmission Needs.^[16]; FERC does not, however, require the incorporation of Long‑Term Scenarios in existing Order No. 1000 Regional Transmission Planning.^[17]

Specifically, 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.^[18]; Further, at least once every five years, transmission providers must reassess whether the data inputs and factors incorporated in previously developed Long‑Term Scenarios need to be updated and then revise those Long‑Term Scenarios, as needed, to reflect update data inputs and factors.^[19]

In developing Long‑Term Scenarios, transmission providers must incorporate the following seven specific categories of factors: (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 demand; (3) state‑approved integrated resource plans and expected supply obligations for load‑servicing 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 request and withdrawals; and (7) utility and corporate commitments and federal, federally recognized Tribal, state and local policy goals that affect Long‑Term Transmission Needs.^[20]

With respect to these seven required categories of factors, the issue is whether FERC is pursuing transmission planning in a particular direction, or whether FERC merely is acknowledging the realities of future transmission needs. In his Dissent to the Transmission Order, Commissioner Christie stated that these “mandatory features are transparently intended to ‘pre‑cook’ outcomes by manipulating the planning and evaluations that determines which projects are selected for regional transmission plans.”^[21]; On the contrary, according to Chairman Phillips and Commissioner Clements, “[r]equiring planning to be based upon documented drivers of transmission needs and to incorporate objective measures of ow potential investments pay off improves the planning process, it does not mandate any particular outcome.”^[22]

As part of Long‑Term Regional Transmission Planning, transmission providers must develop, at least once during the five‑year Long‑Term Regional Transmission Planning cycle, at least three distinct Long‑Term Scenarios that incorporate the seven categories of factors.^[23]; FERC also requires transmission providers to give stakeholders an opportunity to provide timely and meaningful input into how Long‑Term Scenarios are developed.^[24]; At least three Long‑Term Scenarios must be plausible and diverse.^[25]

The Transmission Order requires transmission providers to use “best available data inputs” when developing Long‑Term Scenarios, meaning data inputs that are timely, developed using best practices and diverse and expert perspectives, and adopted via a process that satisfies the transmission planning principles of Order Nos. 890 and 1000. The Transmission Order also requires that best available data inputs reflect the list of factors that transmission providers account for in their Long‑Term Scenarios.^[26]

FERC noted that transmission providers retain the ultimate responsibility for transmission planning, having discretion subject to the limits imposed in the Transmission Order, to weigh more heavily one source of information over another, such as weighing information, related to a factor provided by a state regulatory, more heavily than information provided by other stakeholders.^[27]; Transmission providers are not precluded from relying on scenarios developed by state agencies, provided that FERC finds the OATT provisions governing the development of those Long‑Term Scenarios comply with the Transmission Order, including transmission planning horizon and stake holder input requirements.^[28]

Transmission providers also must revise the regional transmission planning processes in their OATTs to outline an open and transparent process that provides stakeholders^[29] with a meaningful opportunity to engage in the Long‑Term Planning process. Stakeholders are encouraged to provide information and identify sources of best available data, propose how a factor may affect Long‑Term Transmission Needs, and explain how that factor could be reflected in the development of Long‑Term Scenarios, including the extent to which it is appropriate to discount the effects of certain factors on Long‑Term Transmission Needs.^[30]

After stakeholders, including states, have had the meaningful opportunity to participate in the development of Long‑Term Scenarios,^[31] transmission providers must publish on the public portion of an OASIS or other public website: (1) the list of factors in each of the seven required categories of factors that they will account of in the Long‑Term Scenarios; (2) a description of each factor that they will account for in their Long‑Term Scenarios; (3) a general statement explaining how they will account for each of those factors in their Long‑Term Scenarios; (4) a description of the extent to which they will discount any factors in Factor Categories Four through Seven in each Long‑Term Scenarios; and (5) a list of the factors that they considered but did not incorporate in their Long‑Term Scenarios.^[32]

1. 4. Evaluation of the Benefits of Regional Transmission Facilities

In order to adequately evaluate whether certain proposed Long Term Transmission Facilities would satisfy Long Term Transmission Needs, FERC established metrics to assess the benefits of the proposed facilities. In the Transmission Order, FERC identified seven benefits that transmission providers would be required to measure and assess in each scenario studied as part of the Long Term Transmission Need.^[33]; Those seven benefits (down from twelve as proposed in the NOPR)^[34] include the following: (1) avoided or deferred reliability transmission facilities and aging infrastructure replacement; (2) 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 events and system conditions; and (7) capacity cost benefits from reduced peak energy losses.^[35]; Transmission providers are required, in their compliance filings, to discuss how these benefits will be measured and used to evaluate Long‑Term Regional Transmission Facilities. In response to concerns voiced by certain transmission providers, that the measurement and use of the seven benefits would increase costs and require significant additional efforts, FERC concluded that those commenters “did not provide persuasive evidence to suggest that requiring the measurement and use of a required set of benefits would be unduly burdensome.”^[36]; FERC noted that while there may be some additional burden on transmission providers to measure these benefits, this requirement is “necessary to ensure that rates are just and reasonable.”^[37]

Once transmission providers have identified transmission needs through Long‑Term Scenarios, FERC proposes to require providers evaluate the benefits of their regional transmission facilities over a minimum of a 20‑year time horizon.^[38]; FERC selected a 20‑year time period because it strikes a reasonable balance between acknowledging many transmission facilities have useful lives, that can exceed 40 years, and recognizing inherent difficulties in predicting system conditions many decades in the future.

FERC adopted the NOPR proposal of allowing, but not requiring, transmission providers in each region the flexibility to use a portfolio approach in evaluating the facility benefits identified through Long‑Term Regional Transmission Planning.^[39]; In doing so, FERC will not require transmission providers to run separate analyses for each and every facility they own, but instead will allow them to holistically plan larger subsets of their transmission systems. FERC also declined to adopt the NOPR proposal to require transmission providers to note whether the portfolio approach will be used universally or only in certain circumstances, or to describe how they will analyze the benefits of regional transmission facilities under a portfolio approach. FERC further clarified that transmission providers may use either or both facility‑by‑facility and portfolio approaches within the same Long‑Term Regional Transmission Planning cycle.^[40]

1. 5. Evaluation and Selection of Long‑Term Regional Transmission Facilities

As part of FERC’s regional planning reforms, the Transmission Order aims at implementing reforms through the evaluation and selection of long‑term regional transmission facilities in order to increase efficiencies and help ensure that transmission providers’ Commission‑jurisdictional rates are just and reasonable and not unduly discriminatory or preferential.^[41]

FERC adopted the NOPR proposal requiring transmission providers in each transmission planning region to include an evaluation process in their OATT, for identifying and evaluating Long‑Term Regional Transmission Facilities.^[42]; FERC also adopted criteria for evaluating such Long‑Term Regional Transmission Facilities.^[43]; To meet the Transmission Order’s requirements, each transmission planning region must establish a Long‑Term Transmission Planning evaluation process that: (1) identifies Long‑Term Regional Transmission Facilities that address Long‑Term Regional Transmission Needs; (2) measures the benefits of the identified Long‑Term Regional Transmission Facilities; and (3) designates a point by which transmission providers will determine whether to select identified Long‑Term Regional Transmission Facilities in the regional transmission plan for purposes of cost allocation.^[44]; Transmission providers, after consulting with stakeholders, are tasked with, and afforded flexibility in, proposing selection criteria to more efficiently and cost‑effectively address the transmission planning region’s Long‑Term Transmission Needs.^[45]

The selection criteria must meet certain minimum requirements for transmission providers’ evaluation of transmission facilities. First, such an evaluation process must be transparent and not unduly discriminatory, resulting in a sufficiently detailed determination so that stakeholders may understand why a given Long‑Term Regional Transmission Facility was, or was not, selected.^[46]; Second, transmission providers in each transmission planning region shall propose evaluation processes that account for costs over time without over‑building transmission facilities.^[47]; Any determination of selecting or not selecting a Long‑Term Regional Transmission Facility must include the estimated cost and measured benefits of each alternative Long‑Term Regional Transmission Facility evaluated by the transmission providers, regardless of whether the Long‑Term Regional Transmission Facility is selected.^[48]

As part of the evaluation process, transmission providers must consult with, and seek support from, Relevant State Entities^[49] in identifying and evaluating Long‑Term Regional Transmission Facilities for selection.^[50]; Specifically, on compliance, transmission providers will demonstrate their good faith efforts to consult with, and seek support for, such Relevant State Entities in their transmission planning region’s footprint when developing the evaluation process and selection criteria that the transmission providers propose to incorporate in their OATTs.^[51]

The Transmission Order permits voluntary funding opportunities for Long‑Term Regional Transmission Facilities that do not meet the transmission providers’ selection criteria.^[52]; Specifically, in the Transmission Order, FERC requires that transmission providers in each transmission planning region include in their OATTs a process providing Relevant State Entities and interconnection customers with the opportunity to voluntarily fund the cost of, or a portion of the cost of, a Long‑Term Regional Transmission Facility that would otherwise not meet the transmission providers’ selection criteria.^[53]; Transmission providers have flexibility in the features of the voluntary funding process in their compliance filings, but such voluntary funding process must be transparent and unduly discriminatory.^[54]

Lastly, the Transmission Order requires transmission providers in each transmission planning region to include in their OATTs provisions requiring them to reevaluate previously selected Long‑Term Regional Transmission Faculties in certain circumstances.^[55]; Transmission providers will reevaluate selected Long‑Term Regional Transmission Facilities where: (1) delays in developing a previously selected Long‑Term Regional Transmission Facility “jeopardize” the transmission provider’s reliability needs or obligations; (2) actual or projected costs of a previously selected Long‑Term Regional Transmission Facility “significantly exceed” cost estimates; or (3) significant changes in laws or regulations cause “reasonable concern” that a previously selected Long‑Term Regional Transmission Facility may no longer meet the transmission providers’ selection criteria.^[56]; Transmission providers will include criteria in the OATTs that they will use to determine when one of the above situations occurs.^[57]

3. Coordination of Regional Transmission Planning and Generator Interconnection Processes

Based on the record, FERC determined that there is substantial evidence supporting the conclusion that the regional transmission planning requirements are unjust and unreasonable because they do not adequately consider certain interconnection‑related transmission needs.^[58]; As a result, the Transmission Order requires transmission providers to evaluate for selection certain identified interconnection‑related transmission needs in their regional transmission and cost allocation processes.^[59]; Transmission Order also requires that interconnection‑related network upgrades, associated with identified interconnection‑related transmission needs, must satisfy the minimum cost and voltage criteria proposed in the NOPR to qualify for evaluation for selection.^[60]; FERC intends for these reforms to result in the selection of more efficient transmission solutions.^[61]

First, to better alleviate transmission limitations by providing a starting point for identifying and evaluating more efficient regional transmission solutions, the Transmission Order requires transmission providers in each transmission planning region to evaluate regional transmission facilities that address certain interconnection‑related transmission needs in their existing regional transmission planning and cost allocation process.^[62]; Specifically, the Transmission Order requires transmission providers to evaluate identified interconnection‑related transmission needs in existing transmission planning and cost allocation processes to allow such needs to be addressed in a more efficient timeframe, resulting in more expeditious development of regional transmission facilities.^[63]

Second, all identified interconnection‑related network upgrades associated with an identified interconnection‑related transmission need must meet the proposed voltage and cost criteria.^[64]; Transmission providers are required to evaluate for selection, in their existing regional transmission planning processes, regional transmission facilities to address interconnection‑related transmission needs that were identified in the generator interconnection process as requiring interconnection‑related network upgrades under four criteria where:

1. the transmission provider 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;
2. an interconnection‑related network upgrade identified to meet those interconnection‑related transmission needs and has a voltage of at least 200 kV and an estimated cost of at least $30 million;
3. the interconnection‑related network upgrade has not been developed and is not currently planned to be developed because the interconnection request driving the need for the upgrade has been withdrawn; and
4. the transmission provider has not identified an interconnection‑related network upgrade to address the relevant interconnection‑related transmission need.^[65]

FERC concluded that each of the above criteria are needed to identify interconnection‑related transmission needs, while striking a workable balance between precision and workability.^[66]

4. Consideration of Certain Transmission Technologies

The Transmission Order reforms the regional transmission planning process by requiring transmission providers to consideration certain transmission technologies. FERC found that the existing regional transmission planning requirements are unjust, unreasonable, and unduly discriminatory or preferential because they do not require consideration of alternative transmission technologies in the regional transmission planning process.^[67]; As a result, the Transmission Order requires transmission providers to consider dynamic line ratings, advance power flow control devices, advanced conductors, and transmission switching for each identified transmission need in the Long‑Term Regional Transmission Planning and existing Order No. 1000 regional transmission planning.^[68]; FERC anticipates that consideration of these transmission technologies will provide cost savings by improving the operational efficiency of transmission facilities, deferring the need for new regional transmission facilities.^[69]

5. Regional Transmission Cost Allocation

Transmission planning is incomplete without considering the costs of proposed Long‑Term Transmission Facilities and how such costs are proposed to be allocated. As such, the cost allocation section of the Transmission Order is the key concomitant to the Regional Transmission Planning rules and requirements set forth in the Transmission Order.

FERC decided upon the following reforms with regard to regional cost allocation.

First, the Transmission Order requires (rather than just permits, as in the NOPR) transmission providers in each transmission region to file one or more Long‑Term Regional Transmission Cost Allocation Methods (defined as an ex ante approach, as they are based on forecasts) for Long‑Term Regional Transmission Facilities selected as part of the process.^[70]; Second, the Transmission Order permits (rather than requires, as in the NOPR) a State Agreement Process (defined as an ex post approach), if Relevant State Entities indicate they have agreed to such a process.^[71]; FERC cautioned that the State Agreement Process cannot be the sole cost allocation methodology. A default Long‑Term Regional Transmission Cost Allocation Methodology must be in the transmission provider’s tariff to cover situations where the State Agreement Process fails to result in a Commission‑accepted cost allocation method for that facility or facilities.^[72]; Whether the cost allocation is selected through a Long‑Term Regional Transmission Cost Allocation Method or through a state allocation process, the cost allocation must be roughly commensurate with the benefits of the facility.^[73]

As to one of the more controversial issues raised by the NOPR, in terms of the sheer number and length of comments submitted, FERC declined to adopt the NOPR proposal that would have required transmission providers to seek the agreement of Relevant State Entities within the transmission region with regard to the cost allocation method to be utilized in the review of options for Long‑Term Regional Transmission Facilities.^[74]; Instead, FERC established a six‑month time period (the Engagement Process) during which transmission providers must: (1) provide notice of the starting and end dates for the six‑month time period; (2) post contact information that Relevant State Entities may use to communicate with transmission providers about any agreement among Relevant State Entities, either on a Long‑Term Regional Transmission Cost Allocation Method and/or a State Agreement Process, as well as a deadline for communicating the agreement; and (3) provide a forum for negotiation of a Long‑Term Regional Transmission Cost Allocation Method or a State Agreement Process that enables meaningful participation by Regional State Entities.^[75]; FERC determined that the six month Engagement Period strikes a balance between ensuring that Relevant State Entities have sufficient time to negotiate a Long‑Term Regional transmission Cost Allocation Method and/or a State Agreement Process, whichever they choose to do, but also that the implementation of the reforms does not “unduly delay the implementation of the reforms that we adopt in this Transmission Order.”^[76]

In the rulemaking process, there was considerable debate over the applicability under the new reforms of the Order No. 1000 principles as to how the cost allocation of new transmission facilities selected in regional transmission plans. In Order No. 1000, FERC established six cost allocation principles, that must be met, and their requirements.^[77]; Together, these six principles were intended to ensure that the costs of new transmission facilities would be allocated in a manner roughly commensurate with their benefits. FERC did not require adoption of a universal or comprehensive definition of “benefits,” instead permitting regional flexibility.^[78]

In the Transmission Order, FERC requires Long‑Term Regional Transmission Cost Allocation Methods to comply with Order No. 1000 regional cost allocation principles numbers 1‑5, where Relevant State Entities have not indicated that they agree with the proposed cost allocation method. With respect to Order No. 1000 cost allocation principle number 6 that there may be different regional cost allocation methods for different types of facilities in the regional plan, FERC found it “inconsistent with Long‑Term Regional Transmission Planning as directed in this Transmission Order.”^[79]; FERC determined that allowing consideration of reliability, economic, or public policy transmission facility types, such as provided under Order No. 1000 principle number 6, would “reflect a more siloed approach to regional transmission planning that is misaligned with our Long‑Term Regional Transmission Planning reforms…”^[80]

6. FERC Declined to Reestablish a Federal Right of First Refusal in FERC‑Jurisdictional Tariffs and Agreements

In an effort to promote competition in the development of transmission facilities, Order No. 1000 rescinded a right of first refusal previously granted to incumbent transmission owners to build regional transmission facilities within their geographic footprint. In the NOPR, FERC proposed to amend Order No. 1000 to once again permit transmission providers to propose, pursuant to Section 205 of the FPA, new federal rights of first refusal for incumbent transmission providers, conditioned on the incumbent transmission provider with the federal right of first refusal for such regional transmission facilities, establishing joint ownership of the transmission facilities consistent with certain requirements.^[81]; As proposed in the NOPR, an incumbent transmission provider could establish qualifying joint ownership with unaffiliated nonincumbent developers, or another unaffiliated entity including another incumbent transmission provider.^[82]

In the Transmission Order, however, FERC declined to finalize the proposal in the NOPR.^[83]; FERC found that commenters on the NOPR had raised substantial concerns about whether incumbent transmission providers, as a result of Order No. 1000’s reforms, face perverse investment incentive 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.^[84]; FERC stated it will continue to consider potential federal right of first refusal issues in future proceedings.^[85]

By maintaining Order No. 1000’s elimination of the right of first refusal, FERC has not made it easier for incumbent transmission owners to prevent competitors from bidding and building new interstate transmission facilities. Nonetheless, in their Concurring Statement, Chairman Phillips and Commissioner Clements clarified that the Transmission Order should not be construed as a lack of support for the concept of joint ownership or the potential for a federal right of first refusal to effectively encourage its use.^[86]

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

Local transmission planning has been the focus, from different angles, of a number of industry participants. In the NOPR, after addressing concerns about a perceived lack of visibility into the local planning process, FERC took the side of proposing steps to increase transparency, and opportunity to participate, in the local planning process. FERC proposed steps to enhance transparency over the objections or commenters who wanted the local transmission process to remain the province of the incumbent utility with state commission oversight.^[87]

In order to enhance transparency, the Transmission Order requires transmission providers in each of the transmission planning regions to revise the regional transmission planning sections of their OATTs to include: (i) the criteria, models, and assumptions used in their local transmission planning process; (ii) local transmission needs that they identify through that process; and (iii) the potential local or regional transmission facilities that they will evaluate to address those local transmission needs.^[88]

In order to ensure that stakeholders have meaningful opportunities to participate in, and provide feedback on local transmission planning throughout the regional transmission planning process, FERC established some prescriptive requirements as part of this greater coordination between local and regional planning. Each public utility transmission provider will need to hold at least three stakeholder meetings and post relevant information to enable stakeholders to submit comments.^[89]; The three meetings are designated as the: (i) Assumptions Meeting—review of the criteria, assumptions and models related to each public utility transmission provider’s local planning; (ii) Needs Meeting—review of reliability criteria violations and local transmission planning drivers (to be held no fewer than 25 days after the Assumptions Meeting); and (iii) Solutions meeting—no fewer than 25 days after the Needs Meeting, transmission providers must collectively convene to review the range of potential solutions to address reliability criteria violations and other transmission needs. In addition, the materials for these three meetings must be publicly posted, and stakeholders must have opportunities before and after each meeting to submit comments.^[90]

Various commenters noted that incumbent utilities during local transmission planning sometimes automatically approve in‑kind lower voltage facilities that would serve more of a local function, rather than consider higher voltage facilities as a replacement of older lower voltage facilities, where the higher voltage facilities would satisfy the local transmission needs, but they also would have a better ability to enhance the regional transmission system. To address this concern over automatic in‑kind replacement of local transmission facilities without sufficient input on regional facility options, the Transmission Order requires that public utility transmission providers in each transmission planning region “evaluate whether transmission facilities (1) operating above a specified kV threshold and (2) that an individual transmission provider, that owns the transmission facility, anticipates replacing in‑kind with a new transmission facility during the next 10 years that can be ‘right sized’ to more efficiently or cost‑effectively address a Long‑Term Transmission Need.^[91]; Right sizing could include increasing the facility’s voltage level, adding circuits to the towers, or incorporating advanced technologies. Transmission providers must propose on compliance a threshold that does not exceed 200 kV.^[92]

FERC did establish a federal right of first refusal for a right‑sized replacement transmission facility. As to scope of this right, it would apply to the transmission provider who had included in its in‑kind replacement estimate “the existing transmission facility that the right‑sized replacement transmission facility would replace,” and it “extends to any portion of the right‑sized replacement facility located within that transmission provider’s retail distribution service territory or footprint…”^[93]; FERC noted that this federal right of first refusal for right‑sized transmission facilities acts as an exception to the general requirement of Order No. 1000 that transmission providers eliminate any federal right of first refusal for regional facilities selected in a regional transmission plan.^[94]

As to cost allocation of right‑sized replacement transmission facilities, FERC changed course from its NOPR proposal that only the incremental costs of right‑sizing the transmission facility will be eligible to use the applicable Long‑Term Regional Transmission Cost Allocation Method, while the costs that the transmission provider would otherwise have incurred to construct the in‑kind replacement facility would be allocated consistent with the allocation that would have otherwise occurred for such facility.^[95]; FERC was persuaded by comments that it would be challenging to track the costs of a right‑sized transmission facility pursuant to two separate cost allocation methods.^[96]; Instead, transmission providers will be accorded flexibility in proposing a cost allocation method for selected right‑sized replacement facilities.^[97]

Nevertheless, the cost allocation method chosen by the transmission provider must be just and reasonable and not unduly discriminatory or preferential, and must allocate costs at least commensurate with the estimated benefits of the facility.^[98]

8. Interregional Transmission Coordination

Inter‑regional transmission coordination occurs if the regions are sharing information and results of Long‑Term Regional Transmission Plans prepared consistently with the Transmission Order. To better identify cost‑efficient solutions in transmission planning, FERC adopted the NOPR proposal that public utility transmission providers revise their existing interregional transmission coordination procedures to take into account the Long‑Term Regional Transmission Planning developed in compliance with the Transmission Order.^[99]

Specifically, transmission providers in neighboring transmission planning regions are required to revise their interregional transmission coordination procedures (as well as regional transmission planning processes, as needed), for (i) the sharing of information regarding the respective transmission needed identified in the Long‑Term Transmission Plans as well as Long‑Term Regional Transmission Facilities to meet those needs; and (ii) identifying and jointly evaluating interregional transmission facilities that could more efficiently or cost‑effectively meet the transmission needs identified through the Long‑Term Regional Transmission Planning process.^[100]

FERC also adopted the NOPR proposal to require public utility transmission providers in neighboring transmission planning regions to revise their interregional transmission coordination procedures (and regional transmission planning processes as needed) to allow an entity to propose an interregional transmission facility as a potential solution to through Long‑Term Transmission Needs.^[101]; To enhance transparency, FERC went further than its NOPR proposal and required that transmission providers provide additional information on their public website or through and email list related to concerning specifics of their Long‑Term Regional Transmission Planning processes and types of facilities that are being considered as part of that process.^[102]

9. The Commissioners Dissent and Concurrence

Commissioner Christie issued a colorful dissent, stating that the Order is “an absurdly complex bureaucratic blizzard of mandates and micromanagement.”^[103]; Commissioner Christie states the Transmission Order inflicts unduly costs on consumers, and states the Transmission Order effectively terminates the state agreement approach regarding selection criteria, benefits and cost allocation. Commissioner Christie also views the Transmission Order as foundationally different from the NOPR in the following ways:

1. Including ex ante cost allocation methods;
2. Specifying a set of planning criteria and purported benefits;
3. Shifting the regional cost allocation principle of different facility types using different cost allocation methods to a “one‑size‑fits‑all model;”
4. The “effective elimination” of a voluntary state agreement process;
5. Leaving the CWIP Incentive intact; and
6. Changing Local Transmission Planning disclosure and transparency requirements to no longer apply for asset management projects.^[104]

Commissioner Christie asserts the Transmission Order exceeds FERC’s authority under a cornucopia of provisions,^[105] stating the Transmission Order “nakedly intends to produce very specific outcomes”^[106] by issuing the categories of factors and benefits mandated in the Transmission Order. Commissioner Christie also argues the Transmission Order called for an “evisceration” of the states’ role in transmission planning^[107] by instituting the ex ante cost allocation method as the default approach, rather than the State Agreement Process.^[108]; This includes both the provision^[109] regarding the filing of ex ante cost allocations, and the Engagement Period process.^[110]; Commissioner Christie believes the Transmission Order leaves states with the “sword of Damocles”^[111] over their heads if they disagree with transmission providers in the cost allocation processes. Commissioner Christie continues through the remainder of his dissent discussing his belief of “vacuous” cost shifts that are intended subsidize preferred resources^[112] and elevate corporate preferences^[113] rather than protecting consumers as required by the FPA.^[114]

Also issued with the Transmission Order, Chairman Phillips and Commissioner Clements (the Concurring Commissioners) issued a succinct concurrence in response, stating “the cost of continued inaction is immeasurable.”^[115]

The Concurring Commissioners state Order No. 1920 provides maximum flexibility^[116] and challenge the dissent posited by Commissioner Christie. They counter Commissioner Christie’s claims that states have lost rights and authorities given to them is categorically false,^[117] and assert that such a “myopic” view would allow states to receive benefits, “but not be charged a single cent unless they expressly agreed to pay.”^[118]; The Concurring Commissioners argue the dissent would allow “free ridership”^[119] and allow states to avoid payment while still receiving transmission benefits, and, as a result of the Transmission Order, states now have a designated forum for participation^[120] while retaining the same rights held prior to the Transmission Order.^[121]

The Concurring Commissioners reject Commissioner Christie’s assertions that Order No. 1000 and the Major Questions Doctrine have been compromised, stating that the Transmission Order institutes planning requirements to the planning process generally—not imposing an obligation to develop a particular regional transmission project—^[122] and interpret the D.C. Circuit decision “where a practice that meets the directly affecting standard, it falls within FERC’s exclusive jurisdiction.”^[123]

The Concurring Commissioners also highlight the creation of a federal right of first refusal and joint ownership should be encouraged both in compliance of the Transmission Order and elsewhere.^[124]

10. Conclusion

The Transmission Order established or substantially revamped regional transmission planning and related cost allocation. While transmission providers have not yet made their compliance filings, the Transmission Order, which builds on Order Nos. 888, 890, and 1000, is poised to reform transmission planning and cost allocation. Industry participants should be ready to review transmission providers’ compliance filings to evaluate whether each of the Transmission Order’s objectives are sufficiently addressed. Going forward, transmission providers and other stakeholders across the spectrum of the industry will have ample opportunities to participate in the extensive planning and cost allocation processes established by the Transmission Order.