It has been a big few months for transmission. On the heels of FERC Order No 1920, which overhauled regional transmission planning, Senators Joe Manchin (I-WV) and John Barrasso (R-WY) released the text of their permitting reform legislation, the Energy Permitting Reform Act of 2024 (EPR), in mid-July. (See the detailed and one-page summaries, as well as the bill text.)
Most discussion of the EPR so far has focused on its permitting provisions, particularly the merits of putting renewable energy projects on a more level playing field with fossil fuel projects with respect to permitting, siting, and environmental review—weighed against the bill’s potential to lock in continued fossil fuel development. Far less attention has been paid to how the EPR changes national transmission planning processes for the better, particularly for renewable energy resources.
The EPR establishes a reformed planning process that not only backstops interregional transmission planning in ways congruent with FERC’s actions on regional planning, but supports better project selection and cost allocation. Crucially, although less broadly appreciated, it also facilitates public transmission financing for critical projects. While the EPR does not address interconnection, a better transmission planning process should ameliorate local interconnection frictions.
In this blog post, I will examine these main transmission-related elements of the EPR. For more detail, see the schematic on EPR’s planning processes created by Grid Strategies at the end of this post.
Planning reforms
EPR amends the Federal Power Act to require neighboring transmission regions to regularly and jointly plan transmission with one another. The plans must (1) establish a common set of inputs, assumptions, and consistent timelines; (2) consider advanced conductors or reconductoring; and (3) ensure they provide from a list of reliability and affordability benefits, specified by EPR, for those served by any new transmission capacity (see the list below). If regions fail to come to timely agreement on a plan, FERC can provide an extension to the planning process—or require compliance with a plan approved by the Commission based on a record of the planning process and in accordance with the cost allocation process (described below).
Permitting backstop authority
EPR creates two pathways to permitting transmission projects. First, projects can be approved as part of the new interregional planning process described above. Second, EPR tasks FERC with establishing a process through which utilities or independent developers can seek approval for projects that they believe to be in the “national interest.” Applicants demonstrate their claim to FERC based on seven criteria (see Figure 2). To support FERC’s assessment of applicants, the EPR also requires the Department of Energy to conduct studies of national and regional transmission constraints every three years.
In the event that the interregional process fails to provide approval for projects, those developers can use this permitting backstop (an alternative pathway to approval) to make the case that their projects are vital to the grid.
This applicant-driven process replaces a pre-existing process whereby the Secretary of Energy designates National Interest Electric Transmission Corridors (NIETCs) based on time consuming studies. In May 2024, as required by the Bipartisan Infrastructure Law, the DOE released a preliminary list of NIETCs, projects within which are supposed to get access to fast-tracked permitting. However, these proposed NIETCs must still go through a comment period and an environmental review process, the latter of which is not even scheduled to begin until the fall. Moreover, the proposed NIETCs are limited in geographic scope—almost certainly denying vital corridors an alternative route to approval.
The new applicant-driven process is streamlined, applies to all parts of the country, doesn’t require environmental review, and lets projects go straight to FERC rather than wait for the Secretary of Energy to issue an NIETC designation. It represents a parallel and (seemingly) co-equal process to interregional planning, allowing projects to use FERC to bypass transmission planning regions or interregional disagreements.
Cost allocation reforms
Both the interregional planning and applicant-driven processes require developers to file with FERC for cost allocations for their respective projects. FERC must ensure that the allocation of costs to entities using the power grid are just and reasonable and in accordance with the cost causation principle (i.e., customers that do not receive benefits from projects should not help pay to develop them). EPR specifies a list of affordability and reliability benefits that FERC must take into account when determining cost allocation (see the list of benefits above).
This is one of the biggest changes introduced by EPR. Without these reforms, the cost burden of new transmission would fall on renewable energy developers, resulting in many failed projects. Instituting cost allocation provisions for the interregional planning and applicant-driven process is therefore a big step forward to expanding carbon free energy sources.
However, there are some caveats:
The framework of cost causation demarcates who is required to contribute financially to a major project. Both FERC Order No. 1920 and EPR retain it. Doing so was likely necessary due to the bill’s bipartisan nature, given that alternatives would involve socializing the costs of large fixed infrastructure projects beyond those who are direct financial beneficiaries by considering broader systemic benefits or policy preferences (such as an outright preference for zero-emission resources) as criteria by which to allocate cost. EPR’s specification of benefits that FERC may use to determine cost allocation is a huge improvement over the current system, and includes criteria beneficial to clean energy. However, the interpretation of benefits is not an exact science; it remains fraught with controversy. Even with EPR’s improved framework, relying on cost causation to limit financial contributors to new transmission projects may render negotiations on certain projects more difficult depending on how narrowly the affordability and reliability benefit criteria are interpreted. Political opponents of clean energy are keen to ensure that costs of infrastructure are not socialized in ways that would have consumers in their jurisdictions supporting development that they see as detrimental to fossil fuel power sources.
Finally, FERC Order No. 1920 allows states and interconnecting customers to fund all or a portion of a facility that did not meet their transmission providers’ affordability/reliability criteria. In addition, the Order allows for a six-month voluntary cost allocation process after project approval in which states and participants can come to agreement on allocating costs. If the parties do not come to a conclusion, the regional transmission authority can impose a default formula. The future of this provision is unclear under EPR, nor is EPR clear about how FERC could break deadlocks in any potential process.
Transmission financing
The slow pace of NIETC designations severely limited the use of a major IRA program for financing and reducing the cost of new transmission: the Transmission Financing Facility (TFF) program. TFF provides concessionary rate, senior loans for up to 80 percent of the total cost of a transmission project in a NIETC. The applicant must be a non-federal borrower, must be constructing or modifying transmission lines, must address congestion or capacity constraints identified as part of the area’s NIETC designation.
The length and geographic limitations of the NIETC process means that the TFF program has gone largely untapped. The Department of Energy is currently seeking comments on the scope of eligible projects and financing criteria for TFF in the wake of preliminary NIETCs being released in May. EPR would allow projects to secure a national interest designation directly through the applicant-driven process, rather than forcing projects to wait for the federal NIETC designation process. This will dramatically speed up the takeup of TFF loans, which are only available through 2031, and expand the geographic areas in which TFF loans can be applicable. Spreading TFF over a wider geographic area reduces some of the challenges imposed by the cost causation framework by reducing the upfront financing costs of new transmission.
Compensation and interconnection
EPR allows FERC to approve payments to communities that host transmission lines but do not directly benefit from doing so. This provision may facilitate more payments from regions that consume renewable power to those that generate and transmit it. That geographic skew is already reflected, to some degree, in wholesale market pricing incentives as well as ratepayer-backed projects. But this would step up that transfer. Depending on how FERC administers the planning and cost allocation processes (especially the benefits assessment), this allowance could, on one hand, ease local acquiescence to transmission lines while, on the other hand, increase utility opposition to large capital investments into transmission due to the added costs of compensating host communities.
EPR does not contain provisions addressing interconnection—the process by which generation and storage resources connect to the grid. Projects are studied as part of this process to determine if network upgrades are required in order for them to reliably interconnect; if that study process deems upgrades are necessary, projects must pay for the upgrades their application triggered (cost causation). This is a key mechanism for investing in transmission capacity, but it creates a host of uncertainties for projects: lengthening wait times, upgrade costs, and exposure to other projects’ problems via grouping or clustering of projects for analysis. Because interconnection proceeds on a first-come, first-studied basis, developers are incentivized to game the system by holding projects in the interconnection queue that they know will never see completion. The result has been lengthening interconnection queues across the US, primarily affecting renewable and storage resources.
EPR does not address these problems, though it does come on the heels of FERC Order No. 2023, which provided a start (see here for more). However, it is worth noting that building out new transmission capacity through the EPR’s interregional and applicant-driven processes should ease interconnection constraints. New transmission capacity would also grease the pursuit of interconnection reforms allowing projects to access the grid with fewer associated system-wide grid upgrades, counterbalanced by a risk of curtailment—known as the “connect and manage” approach.
Conclusion
Transmission is vital to decarbonization. Large scale renewable and storage investment and increasing electrification will require new transmission capacity to facilitate reliability, provide demand for projects, and rapidly interconnect new resources. The bipartisan permitting reform takes a big swing at uncertainties holding back investment by private and public developers alike. It creates two permitting processes for interregional transmission, including a backstop authority that dramatically simplifies the existing NIETC process and gives the federal government new flexibility to facilitate rapid approval of strategic lines and unclog paralyzed planning. It establishes and specifies cost allocation to interregional projects based on a series of affordability and reliability benefits. It expands the potential eligibility and geographic scope of the TFF facility to derisk investment in new lines. Of course, there is more the federal government could and must do. But the EPR provisions are a vital start and represent a vital template for further legislative effort.
