Large Loads May Get New Grid Hookup Rules
In October, Department of Energy (DOE) Secretary Chris Wright issued a proposed Advance Notice of Proposed Rulemaking (ANOPR) to the Federal Energy Regulatory Commission (FERC) about hooking up new large customers to the country’s transmission system. While technically underneath the DOE umbrella for administrative purposes, FERC is an independent agency that is not ordinarily obligated to follow directions from the DOE. However, Sec. Wright’s new grid hookup rules were submitted under a rarely used provision of law that requires FERC to consider and act on a DOE proposal within a reasonable amount of time. While FERC merely has to act on the proposal without necessarily adopting it, Sec. Wright requested that final action be taken by April 30, 2026.
As the independent regulator of interstate energy transactions, FERC recently received a full complement of commissioners. Two new commissioners joined the ranks within the past few weeks, both Republicans appointed by President Donald J. Trump. One of them, industry veteran and former FERC advisor Laura Swett, was named chair the day after the agency received Sec. Wright’s ANOPR. Given the truncated timeline, both new commissioners must consider the rule while setting up their offices and getting up to speed on other pressing matters.
While many FERC rulemakings take years to finalize—especially those dealing with contentious or complicated jurisdictional issues—the agency has about six months to take final action on the DOE’s proposal. This explains why FERC wants interested parties to comment on the proposal within the first few weeks of receiving it. Though other major undertakings are eventually finalized in a rule hundreds of pages long, reflecting a record created over a significant process, this effort starts with a two-page letter and a 14-page proposal as support.
History
The United States is currently experiencing load growth after a decade of stagnant or declining customer demand for electricity; however, most of that growth is confined to distinct geographic areas. Instead of the slow, broad growth in electricity demand experienced during the mass adoption of electric equipment during the 20th century (or that expected by electrification of transportation and heat in the near future), today’s load growth—both real and expected—is chiefly represented by very large new customers, many in overlapping geographic areas. These customers are stressing the grid systems of defined areas and contributing toward resource adequacy concerns over entire regions.
Many of these new customers are data centers seeking to interconnect to the grid to support today’s digital economy and in response to growing interest in and demand for artificial intelligence (AI). While there are skeptics and detractors, policymakers at the local, state, and national levels seem overwhelmingly interested in attracting and accommodating these new customers. The reasons for these accommodations vary, but the national security aspect of “winning the AI race,” incentivizing economic growth, and driving an expanded tax base alongside additional jobs and investment are the most common. Regardless, the knock-on effect of the increased demand for data centers is the increased demand for electricity to power their facilities. In order to access power, those facilities also want to connect to the grid. While investors note just how frothy the data center and AI buildout has become, developers are still trying to attract prospective data center customers. Thus, it is unclear what number of developers and prospective customers seeking grid connections will attract an end-use customer and consume power.
Today, incumbent utilities run the process of connecting customers to the grid, which is subject to state public utility commission (PUC) oversight. However, these processes are opaque and differ significantly between utilities, and PUCs do not actively monitor interconnection requests. This lack of transparency and supervision has led to claims of preferential and discriminatory conduct by utilities, thereby increasing the time it takes to connect new customers and conducting infrastructure planning and investment in ways that unnecessarily increase costs. These critiques often cite utilities’ inherent bias to overinvest, given their rate-regulated nature. The highest profile complaint about utility action in this vein occurred in Ohio, where American Electric Power (AEP) imposed a moratorium on connecting new customers to the grid without PUC approval, largely in anticipation of proposing new grid hookup rules. Consumer groups argued that the utility “unilaterally imposed this discriminatory, unnecessary, unjustified, and unlawful moratorium on connecting these new customers based solely on their business function and use of electricity,” and that AEP’s planning processes could lead to “billions of dollars in additional and unneeded electricity costs.” These potential cost increases can result from unreasonable demand forecasts that drive up region-wide power prices or from investing in unnecessary grid upgrades.
The Proposal
The DOE’s ANOPR may be short on explaining today’s issues with large load interconnections, but the principles laid out within it confirm that current processes run the risk of utilities acting discriminatorily and feed into utilities’ bias to maximize capital investments. Much of the ANOPR focuses on the principles FERC should adopt to create rules for interconnecting large loads of 20 megawatts or more. It also directs FERC to take over processes currently overseen by state regulators “to ensure the timely and orderly interconnection of large loads to the transmission system.” The proposal seeks to create standardized processes and agreements for interconnecting large loads to the grid, citing demand growth, the Federal Power Act (FPA) grant of authority to FERC “over the transmission of electric energy in interstate commerce,” and an interest in ensuring large loads can receive “open access and nondiscriminatory access to the transmission system.”
In addition to setting best practices in transmission interconnection planning, the ANOPR notes 14 principles FERC should consider in its rulemaking. These principles implicitly exhibit the reality that most utilities fail to plan in ways that can speed up new grid connections, reduce unnecessary grid investments, and even incentivize the development of new power plants to serve new demand. For instance, the fifth principle notes that in studying the interconnection of load and generation at a single point of interconnection, the prospective large-load customer can seek transmission service for the net difference between the demand and generation only, “ensur[ing] efficient buildout of the transmission system” relative to studying the load and generation independently. In addition to noting the need for standardized rules for load and generation located together, the ANOPR supports the need for studies that consider the flexibility of load in planning, including the degree to which these flexible loads can be interconnected on an expedited basis. Today’s processes are clearly too slow for the DOE’s liking.
Conclusion and Takeaway
While the ANOPR mentions the use of FERC processes and agreements to connect generation to the transmission grid as a reason why federalizing load interconnection is acceptable, such a comparison is not as helpful as the drafters may have intended. First, generation interconnection queues in regions across the country are such a mess—with multi-year waits to be studied, much less connected, as the norm—that they require extensive FERC intervention. These long waits exist largely in wholesale markets, or regional transmission organizations (RTOs), where interconnection is overseen independently, whereas even federally regulated generation interconnection is completed at the utility level in non-RTO areas. While this disparity results from a robust market for non-utility generation, it is nevertheless a reality. Thus, federalizing load interconnection like the generation interconnection process will look very different inside and outside RTOs. Furthermore, load and generation connecting at transmission implicate different jurisdictional considerations. Generation seeks connection to transmission to provide a FERC-jurisdictional service (selling electricity at wholesale), while load interconnects to receive a service (buying power for end use) beyond the scope of the FPA.
Former FERC commissioners and state utility commissioners alike have flagged the latter jurisdictional question. While FERC may set rules for connecting to the interstate transmission grid under its jurisdiction within the FPA, related issues—like building and siting the generation needed to ultimately serve customers and whether (and to what extent) customers engage in load flexibility for which they can be compensated—are within state jurisdiction. Understandably, the DOE’s proposal does not directly address either issue. If states do not allow these new large loads to take flexible end-use service or delay building power plants to meet the demand of the interconnected large loads, all of this effort could be for naught. Whether FERC’s application of the DOE’s principles to a federal large load interconnection process is successful will require coordination with states and their utility regulators. FERC must determine whether adopting the DOE’s proposal as written will actually accomplish its stated goals.
Finally, the efficacy and sustainability of any FERC action made within the DOE’s prescribed timeframe will depend on the level of support (including evidence) gathered during the comment and response process. FERC has limited time to gather a record to craft and support any action, thereby raising the prospect that detractors could argue the final action is legally infirm. If FERC does not consider and address their interests, then the states may be first in line to challenge the agency’s rulemaking.