On May 13, 2024, the Federal Energy Regulatory Commission (FERC) issued its long-awaited final rule on regional transmission planning and cost allocation, Order No. 1920. The final rule’s release follows a notice-and-comment period that drew over 600 comments from interested parties, amounting to over 30,000 pages from nearly 200 stakeholders—the largest record considered in any FERC proceeding, according to FERC staff.[1]
The rule is a hefty 1,300 pages, so this alert highlights select issues of particular importance to market participants and notes the flashpoints of disagreements amongst the commissioners.
Long-Term Regional Transmission Planning
The final rule establishes a long-term planning horizon timeline of 20 years. Transmission providers must conduct this planning at least every five years. This longer planning horizon would be required of all RTOs.
The NOPR noted the differing timeframes currently in place, including CAISO’s use of a 10-year transmission planning horizon for the selection of facilities in its regional transmission plan for cost allocation purposes, NYISO’s use of a 10-year or shorter horizon for its regional transmission planning process for reliability and economic needs, and PJM’s use of a 15-year horizon for its long-term analysis as part of its regional transmission planning process.[2] Other non-RTO planning regions use a 10-year transmission planning horizon for their regional transmission planning processes.[3]
Critically, the final rule also requires all transmission providers to incorporate at least seven categories of factors into the development of long-term scenarios:
(1) federal, federally recognized Tribal, state, and local laws and regulations that affect the future resource mix and demand;
(2) federal, federally recognized Tribal, state, and local laws and regulations on decarbonization and electrification;
(3) state-approved utility integrated resource plans and expected supply obligations for load-serving entities;
(4) trends in fuel costs and in the cost, performance, and availability of generation and electric storage resources, as well as the building and transportation of electrification technologies;
(5) resource retirements;
(6) generator interconnection requests and withdrawals; and
(7) utility and corporate commitments and federal, federally recognized Tribal, state, and local goals that affect the future resource mix and demand.[4]
Order No. 1920 also prescribes the evaluation of long-term regional transmission facilities over the 20-year time horizon through the mandatory use and measurement of at least seven benefits. This is another break from the flexible approach of the NOPR, which proposed a list of twelve potential benefits that were “not mandatory or exhaustive.”[5]
As to this newly mandated benefit requirement, the final rule explains that the record shows that, in order to ensure just and reasonable commission-jurisdictional transmission rates, “it is necessary to require transmission providers to measure and use in Long-Term Regional Transmission Planning a set of particular benefits so that they may identify, evaluate, and select regional transmission facilities that are more efficient or cost-effective transmission solutions to Long-Term Transmission Needs.”[6] Mandating the measurement and use of a floor of benefits ensures that providers will consider a sufficiently broad range of benefits when determining whether to select a long-term regional transmission facility as a more efficient or cost-effective solution.
Cost Allocation
How transmission providers engage with state regulators on long-term regional transmission projects represents one of the most significant reforms in Order No. 1920. At a high level, the final rule provides for engagement with state regulators, but does not require transmission providers to seek the regulators’ consent on cost allocation.
The NOPR proposed a requirement that transmission providers in each region revise their open-access tariffs to include either a long-term regional transmission cost allocation method to allocate the costs of long-term regional transmission facilities, a “state agreement process” by which one or more relevant state entities may voluntarily agree to a cost allocation method, or a combination of these two methods. The commission also proposed that any such cost allocation method must still comply with the regional cost allocation principles set forth in Order No. 1000, including that the costs of selected facilities must be “roughly commensurate” with estimated benefits.[7]
The final rule reins in this flexible proposal by requiring, not just permitting, all providers to have at least one default ex ante cost allocation method that applies to long-term regional transmission facilities that are selected through the long-term regional planning process. Providers are permitted—though not required—to adopt a state agreement approach to determine the cost allocation method for specific long-term regional transmission facilities, either before project selection or up to six months after. Order No. 1920 emphasizes that sole reliance on a state agreement process to determine a cost allocation method for selected long-term regional transmission facilities “will not achieve the objectives of this final rule.”[8] Moreover, any cost allocation method that transmission providers propose, whether the result of a state agreement process or a long-term regional transmission cost allocation method, must allocate costs in a manner that is at least roughly commensurate with estimated benefits.
At least from the dissenting commissioner’s perspective, the most significant change from the NOPR relates to seeking agreement from the relevant state regulators. The NOPR proposed to require that transmission providers seek agreement from the relevant state entities on the proposed cost allocation method, whether a default long-term regional transmission cost allocation method or one derived from the state agreement approach: “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.”[9] —
But as described above, the final rule declines to adopt the NOPR proposal to require providers to seek state regulators’ agreement on cost allocation. In Commissioner Mark Christie’s view, this is a fundamental change and subverts the compromise approach of the NOPR.
Right of First Refusal
Order No. 1000 required each public utility transmission provider to remove provisions in commission-jurisdictional tariffs and agreements that establish a federal right of first refusal for “incumbent” transmission providers—those entities developing a transmission facility within their own retail distribution service territory or footprint—as to new transmission facilities selected in a regional transmission plan for purposes of cost allocation.
The NOPR proposed amending Order No. 1000 to allow the exercise of federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent establishing a joint ownership structure with unaffiliated nonincumbent developers for the transmission facilities.
The final rule declines to adopt the NOPR proposal to establish a conditional federal right of first refusal based on joint ownership.[10] The commission explained that this proposal is better considered along with other future transmission reforms including, for example, as part of its ongoing generic proceeding on transmission planning and cost management.[11]
Construction Work In Progress Incentive
The NOPR proposed to prohibit transmission providers from using the ratemaking protocol that allows for inclusion of 100% of construction work in progress (CWIP) costs in rate base for long-term regional transmission facilities. The final rule, however, does not adopt the proposal to limit the availability of the CWIP incentive.
The Commissioners’ Views
Chairman Willie Phillips and Commissioner Allison Clements both voted for the final rule and offered, in their joint concurring statement, a rallying cry in favor of the commission’s efforts on reforming regional transmission planning. “[A] strong electric transmission grid is the foundation for how this Commission meets its most important statutory responsibilities under the Federal Power Act (FPA).”[12] They defended the final rule’s reforms as both reliability and affordability imperatives, emphasizing that “[f]ailure to act now would hamper the reliability and resilience of our electric grid while leaving customers holding the bag for the inevitably more costly upgrades in the future.”[13]
Commissioner Christie dissented on the final rule and gave a lengthy statement at the meeting on the reasons for his dissent. Commissioner Christie expressed his view that while the NOPR was a bipartisan compromise, the final rule was not. In his written statement, Commissioner Christie expressed his fundamental complaint: that the majority’s final rule broke the explicit “compromise” of the NOPR that states must consent for their consumers to bear the costs of long-term regional transmission facilities.[14] He also characterized the final rule as a “shell game” driven by lobbying and special interest groups and designed to conceal the socialization of trillions of dollars in costs, and alleged that the final rule was rushed out to avoid being overturned under the Congressional Review Act, which allows Congress to void certain executive branch and agency rules within a certain period after they are finalized and could come into play next winter depending on the results of the upcoming election.[15]
Commissioner Christie also predicted there would be numerous legal challenges to the final rule, because:
(1) it violates the Administrative Procedure Act by substantially deviating from the proposed rule without sufficient notice to the public;
(2) it exceeds FERC’s authority under the Federal Power Act by transforming FERC into a national integrated resource planner, infringing on the authority over electric generation that Congress reserved for the states;
(3) it violates the major questions doctrine;
(4) it violates both prongs of Section 206 of the Federal Power Act by failing to show that every transmission provider’s regional transmission planning and cost allocation processes are no longer just and reasonable, and that the replacement rate is just and reasonable; and
(5) it transgresses the Commission’s duty to protect consumers under the FPA.
Commissioner Clements, for her part, noted at the meeting that the dissent “misrepresents the final rule and strains in its legal rationale.” The joint concurrence also claimed that Commissioner Christie’s preferred approach would violate the cost causation principle and harm reliability. “[P]assing around a hat” is no way to develop needed transmission infrastructure for the world’s largest economy, in their view.[16] Chairman Phillips and Commissioner Clements even analogized Commissioner Christie’s “wholly voluntary approach” on paying for infrastructure to the ill-fated Articles of Confederation experiment.[17]
Compliance timelines
The final rule is effective 60 days from date of publication in the Federal Register. Transmission providers must submit a compliance filing within 10 months of the effective date of the draft final rule for most of the final rule’s requirements (with the exception of interregional transmission coordination requirements, which get 12 months for compliance).
Next Steps
We expect to see many requests for rehearing. In addition to rehearing, parties may also seek extensions of Order No. 1920's compliance deadlines, consistent with motions filed last fall seeking such extensions in FERC's Order No. 2023 proceeding on generator interconnection reform. FERC ultimately granted compliance deadline extensions in the Order No. 2023 proceeding.
Footnotes
[1] Staff Presentation | Building for the Future Through Electric Regional Transmission Planning and Cost Allocation, FERC (May 13, 2024), https://ferc.gov/news-events/news/staff-presentation-building-future-through-electric-regional-transmission-planning.
[2] See NOPR, 179 FERC ¶ 61,028 at P 94 (2022).
[3] Id.
[4] Final Rule, 187 FERC ¶ 61,068 at P 409 (2024).
[5] NOPR, 179 FERC ¶ 61,028 at P 184.
[6] Final Rule, 187 FERC ¶ 61,068 at P 722.
[7] NOPR, 179 FERC ¶ 61,028 at P 228.
[8] Final Rule, 187 FERC ¶ 61,068 at P 1292.
[9] NOPR, 179 FERC ¶ 61,028 at P 304.
[10] Final Rule, 187 FERC ¶ 61,068 at P 1563.
[11] Id. at P 1564 & n.3346.
[12] Final Rule, 187 FERC ¶ 61,068 (Phillips, Chairman & Clements, Comm’r, concurring at P 1) (“Final Rule Concurrence”).
[13] Id. at P 4.
[14] Final Rule, 187 FERC ¶ 61,068 (Christie, Comm’r, dissenting at P 10).
[15] Id. at P 7.
[16] Final Rule Concurrence at P 10.
[17] Id. at P 11.
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