On April 21, 2022, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued a much-anticipated Notice of Proposed Rulemaking (“NOPR”) proposing changes to its transmission planning and cost allocation policies that are intended to promote the more efficient and cost-effective integration of new generation resources and help meet the needs of a rapidly evolving grid.  According to the Commission, the failure of existing planning processes to perform a forward assessment of transmission needs associated with changes in the resource mix and demand has led to anemic regional development and a shift towards greater transmission expansion occurring outside of the regional transmission planning process, including expansion resulting from the generator interconnection process.  In response to these deficiencies, the Commission proposes to require transmission providers to modify their tariffs to evaluate transmission needs associated with changes in the resource mix and demand over a forward-looking, 20-year period through the use of long-term, portfolio scenarios.

The NOPR represents an acknowledgment by the Commission that the transmission planning reforms it adopted in Order No. 1000¹ have not ensured that regional transmission planning processes proactively identify transmission needs associated with a changing resource mix.  While Order No. 1000 required that transmission providers participate in a regional planning process that included consideration of transmission needs driven by public policy requirements, the Commission recognizes that those reforms have not been effective in planning transmission on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the generation resource mix and demand.  At the same time, the NOPR appears to concede that certain changes required by Order No. 1000—such as the elimination of the federal right of first refusal (“ROFR”)—may have been counterproductive and served to reduce investment occurring through the regional planning process.

While implementation of the modifications proposed in the NOPR would represent a significant change to the Commission’s policies respecting transmission planning and cost allocation, it is worth noting that the NOPR covers only a subset of the reforms that were outlined in the Commission’s related July 15, 2021 Advanced Notice of Proposed Rulemaking (“ANOPR”).  For instance, although many commenters in the ANOPR proceeding urged the Commission to pursue generator interconnection process reforms, including reducing reliance on participant-funding of network upgrades, the NOPR does not propose any changes respecting these matters.  Instead, the NOPR explains that the Commission plans to “continue to review the record developed to date and . . . to address possible inadequacies through subsequent proceedings that propose reforms, as warranted, related to these topics.”²  In addition, the Commission does not propose any changes to the existing interregional transmission coordination and cost allocation requirements of Order No. 1000.  Chairman Richard Glick’s Press Conference Remarks indicate that, in the months ahead, he hopes FERC will also take action on:  (1) generator interconnection process reforms to ensure new resources can come online in a “timely manner and at a reasonable cost”; (2) interregional transmission development reforms to “capture economies of scale”; (3) transmission incentive regime reforms to protect customers; and (4) transmission development reforms to protect customers from unnecessary or excessive costs.³

The following sections provide an overview of the proposals outlined in the NOPR.  Comments on the NOPR are due 75 days after publication of the NOPR in the Federal Register.⁴

Long-Term Regional Transmission Planning

The cornerstone of the reforms outlined in the NOPR is a requirement that public utility transmission service providers comply with the public policy planning requirement of Order No. 1000 by participating in a regional transmission planning process that includes a “Long-Term Regional Transmission Planning” process that:

• identifies transmission needs driven by changes in the generation resource mix and demand through the development of long-term scenarios that satisfy the NOPR requirements;

• evaluates the benefits, on a 20-year basis beginning with the estimated in-service date of the proposed transmission facilities, of regional transmission facilities to meet identified transmission needs; and  

• includes transparent and not unduly discriminatory criteria to select regional transmission facilities in the regional transmission plan for purposes of cost allocation that more efficiently or cost-effectively address transmission needs driven by changes in the resource mix and demand. 

• Long-Term Scenario Planning

The Commission proposes to require transmission service providers to develop and use “Long-Term Scenarios” as a tool to identify transmission needs driven by changes in the resource mix and demand across multiple scenarios incorporating different assumptions about the future electric power system over a sufficiently long-term, forward looking transmission planning horizon.  These Long-Term Scenarios would be required to employ a transmission planning horizon of no less than 20 years, with scenarios updated at least every three years.  The Commission also proposes to require that transmission providers, at a minimum, incorporate the following categories of factors into the development of Long-Term Scenarios:

• Federal, state, and local laws, regulations, and goals that affect the future resource mix and demand, including policies respecting decarbonization and electrification;

• State-approved integrated resource plans and load-serving obligations;

• Trends in fuel costs;

• Resource retirements;

• Generator interconnection requests and withdrawals; and

• Utility and corporate commitments.

Each public utility transmission provider would be required to develop at least four distinct Long-Term Scenarios based on the factors described above (as well as any additional factors adopted by the region).  At a minimum, each Long-Term Scenario would need to be consistent with federal, state, and local laws and state-approved integrated resource plans.  However, each Long-Term Scenario could employ different assumptions regarding the remaining factors as well as other characteristics of the power grid subject to certain conditions.

The NOPR also proposes to require the regional transmission planning process to identify specific geographic zones within the transmission planning region that have the potential for the development of large amounts of generation and to incorporate these designated zones, and commercial interest in these zones, into its Long-Term Scenarios.  FERC explains that identifying such zones would promote the development of facilities that have the potential to serve large concentrations of new generation in a more efficient and cost-effective manner.

2. Coordination With The Generator Interconnection Process

While the Commission has deferred pursuing holistic reforms to the generator interconnection process, the Commission is proposing to require transmission providers to account for certain needs identified through the interconnection process in their Long-Term Scenario Planning.  The Commission expresses concern regarding the tendency for interconnection-related needs to be identified repeatedly in interconnection studies, only for these needs to go unresolved due to the withdrawal of generation resources from the process.  To address this issue, the NOPR proposes to require that transmission providers evaluate for possible selection in the regional transmission plan and corresponding cost allocation, regional transmission facilities to address interconnection-related needs that: have been identified in at least two interconnection queue cycles during the preceding five years; have a voltage of at least 200 kV and/or an estimated cost of at least $30 million; and have not been developed due to the withdrawal of interconnection customers.

3. Evaluation Of The Benefits Of Regional Transmission Facilities

The NOPR proposes to give each region flexibility to determine what benefits would be considered in Long-Term Regional Transmission Planning and how to calculate those benefits, rejecting calls for the Commission to mandate that transmission providers evaluate regional transmission facilities using a set list of benefits.  Recognizing the strong support for adopting a common set of minimum benefits, however, the Commission identified a proposed list of transmission benefits that transmission service providers may consider in their Long-Term Regional Planning and cost allocation processes:

• avoided or deferred reliability transmission projects and aging infrastructure replacement;

• reduced loss of load probability or reduced planning reserve margin;

• production cost savings;

• reduced transmission energy losses;

• reduced congestion due to transmission outages;

• mitigation of extreme events and system contingencies;

• mitigation of weather and load uncertainty;

• capacity cost benefits from reduced peak energy losses;

• deferred generation capacity investments;

• access to lower-cost generation;

• increased competition; and

• increased market liquidity. 

Under the Commission’s proposal, the benefits of a facility would be evaluated over a 20-year time horizon, and could be evaluated individually or as part of a broader portfolio of transmission facilities.

4. Selection Of Regional Transmission Facilities

Consistent with the Commission’s approach in Order No. 1000, the Commission proposes to give regions flexibility to determine the criteria that will be used to determine whether to select, in the regional transmission plan for purposes of regional cost allocation, a transmission facility that addresses transmission needs driven by changes in the resource mix and demand. However, given the increasingly important role of state policies in shaping the resource mix, the Commission proposes to require transmission providers to consult with and seek support and agreement from relevant state entities within their transmission planning region’s footprint to develop the selection criteria. Such state involvement will provide states with the opportunity to influence regional planning and cost allocation, thus, promoting consumer interests and reducing the potential for contentious disputes over transmission planning and cost allocation. 

5. Consideration Of Grid-Enhancing Technologies

Building on FERC’s recent dynamic line ratings initiatives, the NOPR proposes to require transmission providers in each transmission planning region to consider in regional transmission planning and cost allocation processes the incorporation of dynamic line ratings and advanced power flow control devices into transmission facilities.

Regional Transmission Cost Allocation

The Commission proposes to require transmission providers in each region to modify their tariffs to include either (1) a Long-Term Regional Transmission Cost Allocation Method to apportion the costs of the long-term regional transmission facilities, (2) a State Agreement Process where one or more state entities can agree to a cost allocation method, or (3) some combination of the two.  Either method must comply with the cost allocation principles articulated by the Commission in Order No. 1000.  Public utility transmission providers in each transmission planning region would be required to obtain the agreement of relevant state entities⁵ on the cost allocation method and explain how the cost method reflects the agreement of the relevant state entities or explains the good faith efforts made to seek agreement.

In addition, public utility transmission providers would be required to detail in their open access transmission tariffs the process of providing a state or states the time period for negotiating a cost allocation method that is different than any ex ante regional cost allocation method that would otherwise apply.  If an agreement is not met within a specified timeframe, then the transmission developer may use any ex ante regional cost allocation method that would otherwise apply.  

Federal Right of First Refusal

One particularly notable aspect of the NOPR is the Commission’s proposal to modify the requirement adopted in Order No. 1000 that, with certain exceptions, regional transmission facilities selected in a regional transmission plan for purposes of cost allocation not be subject to a federal right of first refusal (“ROFR”).  The elimination of a federal ROFR for new regional facilities selected for the purpose of cost allocation was a key element of Order No. 1000’s nonincumbent transmission developer reforms.  In the NOPR, the Commission expresses concern that the ROFR requirements of Order No. 1000 may be discouraging incumbent transmission developers from pursuing development of regional transmission facilities.  At the same time, the Commission emphasizes that it continues to believe that competition can promote efficient and cost-effective transmission development.

For these reasons, the Commission proposes to allow incumbent transmission providers to retain a federal ROFR conditioned on a demonstration that the incumbent has established a qualifying joint ownership arrangement with an unaffiliated nonincumbent transmission developer or other unaffiliated entity.  As contemplated, these arrangements could include joint ownership with unaffiliated public power entities, load-serving entities, or other non-affiliates.  In effect, under the Commission’s conditional ROFR proposal, an incumbent transmission provider would be given a right to submit a jointly-owned regional transmission facility proposal in partnership with one or more qualifying entities before the opportunity to develop the project would be made available to nonincumbents.

Other Reforms

In addition to the transmission planning and cost allocation proposals described above, the Commission also proposes to:

• Prohibit the use of the Construction Work-in-Progress incentive for Long-Term Regional  Transmission Facilities;

• Require transmission providers to provide additional transparency into the local transmission planning process with the goal of helping to identify opportunities to “right size” local transmission facilities to meet regional transmission goals; and

• Promote the exchange of information regarding Long-Term Regional Transmission Planning in interregional transmission planning processes.

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1. Transmission Planning & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g and 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).

2. NOPR at P 10.

3. Concurrently with the NOPR, the Commission issued a notice of a staff-led technical conference on transmission costs to be held in October 2022.  Transmission Planning and Cost Management, Notice of Technical Conference, Docket No. AD22-8-000 (April 21, 2022). 

4. The NOPR has not yet been published in the Federal Register.  However, we anticipate the comment deadline will likely be in mid-July. 

5. The NOPR defines relevant state entities as “any state entity responsible for utility regulation or siting electric transmission facilities within the state or portion of a state located in the transmission planning region, including any state entity as may be designated for that purpose by the law of such state.”  NOPR at P 304.