FERC Proposes Major Reforms and Commences a Multi-Pronged Approach to Tackle Transmission Planning and Cost Allocation

FERC’s efforts represent the first time in a decade that the agency has considered large-scale changes to regional transmission planning and cost allocation processes. Given the timing of the NOPR, FERC could issue a final rule by the end of the year.

FERC believes that the current regional transmission planning process is not optimized to coordinate the interconnection and transmission of energy from renewable generation that is anticipated to be connected to the grid at an increasing rate over the coming years. Due to the lack of regional transmission planning and cost allocation, the grid is currently being expanded on a more localized level through interconnection-related network upgrades resulting from one-off generator interconnection requests. The status quo of localized, incremental expansion does not efficiently or cost‑effectively address transmission needs on a regional scale, thereby failing to achieve the economies of scale needed to integrate and bring online a significant amount of new renewable generation resources that will likely require additional transmission facilities due to their distance from load centers. This in turn creates issues in maintaining Commission-jurisdictional rates that FERC believes are just and reasonable and not unduly discriminatory or preferential. The NOPR aims to address these concerns by proposing reforms to encourage long-term, regional transmission planning and cost allocation. The NOPR would require public utility transmission providers to identify transmission needs driven by the changing mix of energy resources and demand and to work more closely with states in long-term regional transmission planning and in developing cost allocation methodologies.

What the NOPR Includes

The major proposed reforms in the NOPR fall into two buckets: (1) proposed changes to regional transmission planning and (2) proposed changes to regional transmission cost allocation. In addition, there are a number of related reform proposals of note which are discussed below.

Proposed Changes to Regional Transmission Planning

Public utility transmission providers conduct regional transmission planning to satisfy (1) reliability needs that meet minimum performance requirements; (2) economic needs to plan congestion alleviation and the integration of new resources in a cost-justified manner; and (3) public policy requirements established by local, state or federal laws or regulations. Long-term assessments may range from ten to twenty years depending on the process. FERC is concerned that the existing regional transmission planning process may not be forward-looking enough to meet transmission needs driven by changes in the resource mix and demand, which may lead to a piece-meal and inefficient transmission planning approach. The NOPR contains a number of proposed reforms accordingly, including:

• Requiring public utility transmission providers to participate in regional transmission planning processes that include a “Long-Term Regional Transmission Plan.” FERC proposes that these long-term plans must include (1) an evaluation of transmission facilities’ needs over a 20-year planning horizon, to be reassessed every three years; (2) a set of Commission-identified categories of factors that may drive transmission needs driven by changes in the resource mix and demand, including (a) federal, state, and local laws and regulations that may affect the future resource mix as well as decarbonization and electrification, (b) state-approved utility integrated resource plans and expected supply obligations for load-serving entities, (c) trends in technology and fuel costs, (d) resource retirements, (e) generator interconnection requests and withdrawals, and (f) utility and corporate commitments and federal, state, and local goals that affect the future resource mix and demand; (3) at least four long-term scenarios (multiple scenarios that incorporate different assumptions about the future electric power system over a sufficiently long-term, forward-looking planning horizon); (4) “best available data” in developing the long-term scenarios; and (5) a consideration of whether to identify geographic zones with the potential for development of large amounts of new generation.
• Requiring public utility transmission providers to consider in their Long-Term Regional Transmission Plan, regional transmission facilities that would address interconnection-related needs which have been identified in the generator interconnection process as requiring network upgrades and where (1) the public utility transmission provider identified such upgrades in interconnection studies in at least two interconnection queue cycles during the last five years; (2) the interconnection-related upgrade identified has a voltage of at least 200 kV and/or an estimated cost of at least $30 million; (3) the upgrades have not been developed and are not currently planned to be developed because the interconnection requests have been withdrawn; and (4) the public utility transmission provider has not identified an interconnection-related network upgrade to address the relevant need in a final generator interconnection agreement. FERC proposes to insert this requirement and the enumerated criteria in a new Section 3.10 of the pro forma Standard Large Generator Interconnection Agreement. This reform stems from FERC’s concern that numerous generators request interconnection to the grid but withdraw the request as a result of sticker-shock related to the required network upgrade costs. For example, FERC states that 245 generation projects withdrew from the queue in MISO between January 2016 and July 2020 as a result of the high interconnection-related network upgrade costs. The proposed reform in the NOPR would ensure that the most necessary interconnection-related needs are incorporated into the utility’s long-term regional transmission planning, thereby allocating the costs of such facilities more broadly in recognition of their widespread benefit.
• Requiring public utility transmission providers to identify the set of benefits they will use in evaluating transmission facilities for selection in the Long-Term Regional Transmission plan for purposes of cost allocation as the more efficient or cost-effective solution to a regional transmission need, explain how the benefits will meet identified transmission needs driven by changes in the resource mix and demand, and evaluate the benefits over a 20-year horizon from the estimated in-service date of the facilities. FERC’s proposal would also allow, but not require, public utility transmission providers to evaluate the benefits of a portfolio of regional transmission facilities instead of on a facility-by-facility basis. Rather than adopt a particular definition of “benefits” or “beneficiaries,” FERC proposes a list of benefits in the NOPR to consider, including (1) avoided or deferred reliability transmission projects 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 contingencies; (7) mitigation of weather and load uncertainty; (8) capacity cost benefits from reduced peak energy losses; (9) deferred generation capacity investments; (10) access to lower-cost generation; (11) increased competition; and (12) increased market liquidity.
• Requiring public utility transmission providers to include in their open access transmission tariffs (“OATTs”) (1) transparent and not unduly discriminatory criteria, which seeks to maximize benefits to consumers over time without over-building, to identify and evaluate transmission facilities for potential selection in the regional transmission plan for purposes of cost allocation that address the needs driven by changes in the resource mix and demand; and (2) a process to coordinate with the relevant state entities in developing such criteria. FERC believes that its proposal provides sufficient flexibility to allow public utility transmission providers in each region to develop selection criteria that could balance individual state interests within each transmission planning region.
• Requiring public utility transmission providers to include in their regional transmission planning and cost allocation processes the incorporation into transmission facilities of (1) dynamic line ratings and (2) advanced power flow control devices.

Proposed Changes to Regional Transmission Cost Allocation

FERC states in the NOPR that reforms to public utility transmission providers’ regional cost allocation methods are necessary to ensure that Commission-jurisdictional rates are just and reasonable and not unduly discriminatory or preferential. However, the most readily recognizable impediment to the build out of regional transmission facilities is identifying and implementing a cost allocation methodology that is recognized as just and reasonable and may encompass several states. As a result, the NOPR contains proposed cost allocation reforms, including:

• Requiring public utility transmission providers in each transmission planning region to revise their OATTs to include either (1) a long-term regional transmission cost allocation method, i.e., an ex ante cost allocation method that would be included in the OATT and utilized by the developer of a long-term regional transmission facility; (2) a State Agreement Process, which FERC proposes to define as an ex post cost allocation process that would be included in the OATT which could be followed to establish a cost allocation method for a particular facility, if agreement can be reached; or (3) a combination of the two. Either cost allocation methodology is required to comply with the six existing Order No. 1000 cost allocation principles.¹
• Requiring public utility transmission providers in each transmission planning region to establish a process detailed in their OATTs to add a time period for states to negotiate an alternate cost allocation method for a transmission facility selected in the regional transmission plan for purposes of cost allocation that is different from any ex ante regional cost allocation method that would otherwise apply. If the state(s) can agree upon an alternate cost allocation methodology during the relevant time period (e.g., 90 days), then the public utility transmission provider may elect to file the agreement with the Commission for consideration under Section 205 of the Federal Power Act (“FPA”).
• Requiring public utility transmission providers to identify the benefits they will use in any ex ante cost allocation method associated with long-term regional transmission planning, how they will calculate those benefits, and how the benefits will reasonably reflect the benefits of regional transmission facilities to meet the identified needs driving by changes in the resource mix and demand.

Additional Proposed Changes

The NOPR includes a number of additional reform proposals that could have a major impact on regional transmission planning and project development, including:

• The removal of the construction work in progress (“CWIP”) incentive, which was promulgated under the Energy Policy Act of 2005 and Order No. 679 to allow a public utility to recover 100% of its CWIP costs in rate base prior to a project’s commercial operation. FERC believes that with 20-year horizons for long-term regional transmission planning, the CWIP incentive puts undue risk on ratepayers who may directly finance construction under the CWIP incentive but ultimately receive no benefits from such facilities if the projects are never placed into service. However, pre-construction and construction costs can still be booked as Allowance for Funds Used During Construction and recovered after the project is placed into service.
• Amending Order No. 1000 to allow for the exercise of a federal right of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, so long as the incumbent transmission provider with the federal right of first refusal for such regional transmission facilities establishes joint ownership of the facilities. Order No. 1000 had previously prohibited any exercise of a federal right of first refusal by an incumbent utility for entirely new transmission facilities selected in a regional transmission plan because such a right would create an unjust barrier to entry; however, the NOPR provides that, since issuing Order No. 1000, investment in transmission facilities appears to be concentrated in transmission facilities not subject to Order No. 1000’s competitive transmission development processes and investment in regionally planned transmission has declined, suggesting that the blanket prohibition on a federal right of first refusal could ultimately be discouraging development. Therefore, FERC believes that conditioning the federal right of first refusal on joint-ownership with the nonincumbent transmission developer or another unaffiliated entity will facilitate an open planning process, decrease potential financing and siting risks, and increase the likelihood that transmission facilities will be cost-effectively developed.
• Requiring public utility transmission providers to revise their OATTs with additional provisions to increase transparency in the local transmission planning process by including (1) the criteria, models, and assumptions that they use in their local transmission planning process; (2) the local transmission needs that they identify through that process; and (3) the potential local or regional transmission facilities that they will evaluate to address those local transmission needs.
• Requiring public utility transmission providers in neighboring transmission planning regions to revise their existing interregional coordination procedures to provide for (1) information sharing regarding the respective transmission needs identified in their Long-Term Regional Transmission Plans as well as the potential transmission facilities to meet those needs; (2) the identification and joint evaluation of interregional transmission facilities that may be more efficient or cost-effective transmission facilities to address transmission needs identified through their Long-Term Regional Transmission Plans; and (3) an entity to propose an interregional transmission facility in the regional transmission planning process as a potential solution to transmission needs identified through long-term regional transmission planning.

What the NOPR Does Not Include

The ANOPR sought comments on reforms related to cost allocation methodologies for interconnection-related network upgrades, interconnection queue processes, interregional transmission coordination and planning, and oversight of transmission planning and costs. The NOPR did not propose reforms directly related to these topics. Instead, the Commission issued a notice of technical conference on transmission planning and cost management, scheduled for fall of this year.

This means that FERC left one of the major issues—reforming the interconnection process—on the table. This is a key point of contention for many renewable generation project developers that have increasingly complained of delayed waits in the interconnection queue and rising costs of system upgrades. Although FERC’s proposed reforms in the NOPR address issues indirectly related to the system upgrade costs, there will likely be sustained pressure on FERC to address the underlying issues in a future rulemaking after the technical conference this fall.

Commissioner Danly’s Dissent

Commissioner Danly, drafting the lone dissent to the NOPR, chastised FERC for using Section 206 of the FPA to implement its proposed reforms rather than allowing public utilities to file their own transmission planning reforms under Section 205. Danly argues the NOPR’s proposed reforms are based on narrow environmental policy objectives as opposed to legitimate FPA issues such as ensuring just and reasonable rates or reliability. Commissioner Danly goes on to accuse the NOPR of “socalizing the costs of [] transmission across as broad a population of ratepayers as possible” and summarizes the NOPR as “a boondoggle.” One of Commissioner Danly’s primary concerns is that consumers in some states will be forced to bear the cost of policy choices made by other states.

The Next Steps

Comments on the NOPR are due 75 days after it is published in the Federal Register, with reply comments due 30 days thereafter. Should the Commission issue any final rule in the NOPR proceeding, then FERC proposes to require that each public utility transmission provider submit a compliance filing within 8 months of the effective date of that final rule to revise its OATT and other documents necessary to demonstrate that the utility meets the requirements in the final rule. Transmission providers that are not public utilities would have to adopt the requirements as a condition of maintaining the status of their safe harbor tariff or otherwise satisfy the reciprocity requirement in Order No. 888.

Chairman Glick has been publicly vocal about his efforts to implement transmission planning and cost allocations reforms. With reply comments on the NOPR due in August, it is reasonable to expect a final rule by the end of the year.

The technical conference on transmission planning and cost management is scheduled for Thursday, October 6, 2022. Interested panelists are required to self-nominate by June 16, 2022.

¹ The Order No. 1000 cost allocation principles are: (1) the cost of transmission facilities selected in a regional transmission plan for purposes of cost allocation must be allocated to those within the transmission planning region that benefit from those facilities in a manner that is at least roughly commensurate with estimated benefits; (2) those that receive no benefit from transmission facilities, either at present or in a likely future scenario, must not be involuntarily allocated any of the costs of those transmission facilities; (3) a benefit to cost threshold ration, if adopted, cannot exceed 1.25 to 1; (4) costs must be allocated solely within the transmission region unless another entity outside the region voluntarily assumes a portion of those costs; (5) the method for determining benefits and identifying beneficiaries must be transparent; and (6) there may be different regional cost allocation methods for different types of transmission facilities, such as those needed for reliability, congestion relief, or to achieve public policy requirements.