In the past 18 months, the federal regulatory posture toward data center power has moved from outright rejection to active rulemaking. Between November 2024 and April 2026, the Federal Energy Regulatory Commission (FERC or the Commission), the U.S. Department of Energy (DOE), the White House, and Congress have each intervened in the regulatory landscape governing how data centers obtain dedicated power supply. The core concept is behind-the-meter generation and co-located load, arrangements in which a developer builds or contracts for dedicated power generation at or adjacent to the data center site and delivers electricity directly to the facility rather than drawing it from the grid through a traditional utility (collectively, BTM). Regional transmission organizations (RTOs), the entities that coordinate wholesale electricity markets and manage the transmission grid across multi-state regions, have proposed their own frameworks in parallel. The result is a regulatory environment that, while still taking shape, is far more defined than it was six months ago and warrants careful attention from developers, sponsors, lenders, and their counsel in how transactions are structured, financed, and sited.
American data centers consumed approximately 4% of total U.S. electricity in 2023, a figure projected to reach between 6.7% and 12% by 2028 as artificial intelligence and machine learning workloads proliferate. Traditional grid interconnection processes cannot satisfy this demand on the timelines that developers require. Interconnection queues in major organized markets now exceed five years in many cases, with study deposits, readiness requirements, and network upgrade obligations that can reach into the hundreds of millions of dollars. These delays impose real costs: each month of delay represents millions in lost revenue and stranded investment. BTM generation has emerged as a practical response to these constraints.
This alert surveys the principal federal developments reshaping BTM generation strategy for data centers. It is the first in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions.
The Talen Order: Rejection and Its Limits
FERC’s November 1, 2024, rejection of the amended interconnection service agreement (ISA) at the Susquehanna Steam Electric Station remains the foundational decision in this space to date. The Susquehanna station is a 2,520 MW nuclear generating facility in Luzerne County, Pennsylvania, operated by a subsidiary of Talen Energy and interconnected to the grid through PJM Interconnection (PJM), the RTO that administers the nation’s largest wholesale electricity market, covering 13 states and the District of Columbia. In March 2024, Talen announced the sale of its adjacent Cumulus data center campus to Amazon Web Services for approximately $650 million. The amended ISA filed in June 2024 would have increased the permitted co-located load from 300 MW to 480 MW, reduced Susquehanna’s capacity interconnection rights correspondingly, and added substantial non-conforming provisions addressing reliability, capacity market obligations, and operational coordination.
FERC issued an order (the Talen Order) rejecting the amended ISA because PJM failed to meet its “high burden” of demonstrating that the proposed non-conforming provisions were necessary deviations from PJM’s pro forma interconnection service agreement. The record and concurring statements highlighted broader concerns. On cost allocation, intervenors contended that the cost shift arising from the arrangement could reach as much as $140 million per year. On reliability, PJM’s Independent Market Monitor (IMM), the independent entity responsible for monitoring competitive conditions and market performance within PJM’s wholesale markets, argued that the filing rested on the “illusion” that co-located load at a nuclear plant could be fully isolated from the grid. On precedent, former FERC Commissioner Mark C. Christie warned that approval could trigger widespread load migration from the transmission system, undermining the cooperative cost structure that supports grid infrastructure.
Former FERC Chairman Willie J. Phillips issued a sharp dissent in the Talen Order, arguing that the decision was “a step backward for both electric reliability and national security.” Former Chairman Phillips contended that PJM had comprehensively addressed reliability issues, that the amended ISA represented a first-of-its-kind configuration justifying non-conforming provisions, and that the decision created unnecessary roadblocks to an industry necessary for national security.
The Talen Order did not categorically prohibit BTM arrangements. The decision addressed a specific ISA amendment for an existing grid-connected generator. It also did not address new-build dedicated generation, fully BTM arrangements without transmission interconnection, or co-location in markets outside PJM. Talen and Amazon subsequently expanded their commercial relationship, with Talen announcing a 1.9 GW supply arrangement in June 2025. That the parties most directly affected by the Talen Order found a path forward through restructured commercial terms suggests that its practical impact on deal flow may prove narrower than its headline initially suggested.
For developers and their advisors, the Talen Order nonetheless established several principles that have carried through every subsequent FERC order. First, FERC will scrutinize the cost allocation implications of BTM arrangements, and intervenors will quantify the alleged cost shift to existing ratepayers. Second, FERC expects a thorough analytical record demonstrating that the BTM arrangement will not compromise reliability. Third, the Commission is sensitive to precedential effects and will consider the system-wide implications of approving any individual arrangement. These concerns have animated everything that has followed from FERC since.
The PJM Order: From Rejection to Regulation
FERC’s December 18, 2025, order on PJM co-location (the PJM Order) confirmed what former Chairman Phillips’s dissent in the Talen Order had argued: co-located load is permissible, but it requires a regulatory structure. The PJM Order arose from a February 2025 proceeding in which FERC directed PJM and its transmission owners to demonstrate that PJM’s existing tariff, the set of FERC-approved rules governing rates, terms, and conditions for transmission service in the PJM market, remained just and reasonable in the absence of clear provisions governing co-location arrangements. The PJM Order was approved 5-0, a rare unanimous outcome that suggests consensus on the core principles even among FERC Commissioners who may differ on implementation details.
FERC found PJM’s existing tariff “unjust and unreasonable” because it lacked sufficient clarity on the rates, terms, and conditions applicable to generators serving co-located load. The absence of standardized rules had left generators and large loads unable to determine the steps necessary to implement co-location arrangements, leading to disparate treatment across the PJM footprint and introducing a risk that large-load projects could receive grid services without contributing to the recovery of associated costs.
FERC directed PJM to establish four transmission service options for eligible customers serving co-located load: (1) traditional Network Integration Transmission Service (NITS) on a gross demand basis, a full-requirements service with corresponding cost allocation obligations; (2) Interim Non-Firm Transmission Service, a bridge for facilities that need to begin operations before network upgrades are complete, subject to curtailment during system emergencies; (3) Firm Contract Demand Transmission Service, a new firm service allowing co-located loads to secure guaranteed transmission capacity at a specified contract demand level; and (4) Non-Firm Contract Demand Transmission Service, an interruptible option at a lower cost point for loads with greater operational flexibility.
The Firm and Non-Firm Contract Demand services are particularly significant for BTM strategies. They recognize that co-located loads with on-site generation can limit their energy withdrawals from the transmission system, and they allow those loads to pay transmission charges commensurate with their actual grid reliance rather than their total consumption. For a 500 MW data center with 450 MW of dedicated on-site generation, the difference between gross-demand NITS billing (on the full 500 MW) and Firm Contract Demand billing (on the 50 MW of grid reliance) could amount to tens of millions of dollars annually in transmission charges alone.
The PJM Order also mandated gross demand billing for ancillary services, ensuring that co-located loads contribute to frequency regulation, voltage support, and reserves regardless of their transmission service election. FERC also directed PJM to establish a new megawatt threshold for BTM generation netting (with a three-year transition period for existing network customers and grandfathering for certain contracts entered into before December 18, 2025). Critically for transaction structuring, existing generators seeking to modify their interconnection agreements to add co-located load must follow PJM’s full study process and bear complete cost responsibility for any network upgrades.
That last requirement creates a potentially meaningful asymmetry between existing and new generation. Acquiring an operating plant with existing interconnection rights and modifying its ISA to serve co-located load now triggers the full regulatory apparatus: study process, mandatory upgrade costs, capacity market adjustments, and the scrutiny that comes with a non-conforming ISA amendment (the precise posture that produced the Talen Order rejection). New-build generation dedicated to co-located load from inception may face a lighter path, particularly where the developer can demonstrate minimal reliance on the transmission system through the Firm or Non-Firm Contract Demand services. Sponsors evaluating acquisition strategies may wish to model this regulatory cost differential alongside conventional transaction economics before executing a letter of intent.
Utilities and their regulatory counsel view the PJM Order from a different vantage point. For transmission owners, the PJM Order addresses a legitimate concern about load defection and cost recovery. When large loads co-locate with generation and reduce their transmission withdrawals, the fixed costs of maintaining the transmission system are recovered from a smaller base of remaining customers. The gross demand billing requirement for ancillary services and the mandatory upgrade cost responsibility for existing generators are designed to ensure that co-located loads continue to contribute to the system they rely upon for backup. Standby and backup service rates, which compensate utilities for maintaining capacity availability for loads that primarily self-supply, will be a critical component of the economics for any co-located arrangement in PJM. Developers should expect utilities to seek cost-of-service rates for standby and backup service rather than offering subsidized rates, and project economics should be modeled accordingly.
PJM submitted its principal compliance filing on February 23, 2026, with a requested effective date of July 31, 2026. The filing establishes a 50 MW cumulative nameplate threshold for retail BTM generation that can be netted against load for NITS purposes. Below that threshold, the existing netting rules continue to apply. Above it, loads must take one of the four transmission services described above and be studied for reliability impacts. The filing details the three new transmission services and incorporates grandfathering mechanics for existing contracts.
PJM followed on February 27, 2026, with a separate filing proposing an Expedited Interconnection Track (EIT). The EIT would process up to 10 interconnection requests per year for generating facilities with committed commercial in-service dates and state siting authority support, targeting executed generator interconnection agreements within approximately 10 months. If approved and effective by July 31, 2026 as PJM has requested, the EIT could materially accelerate the timeline for new-build generation serving BTM data center load in PJM territory.
In parallel, PJM’s Critical Issue Fast Path (CIFP) stakeholder process on Large Load Additions produced a January 2026 Board Decisional Letter establishing key principles: a “Bring Your Own Generation” expedited track, a 50 MW large-load threshold, improved load forecasting, and a holistic market review in 2026. A bipartisan coalition of all 13 PJM state governors and the White House National Energy Dominance Council also issued a joint Statement of Principles on January 15, 2026, calling for data centers to bear the infrastructure costs of their own load growth and proposing a potential emergency “backstop” auction to incentivize new generation with 15-year terms for price certainty. The political pressure from both the state and federal levels is pushing in the same direction as FERC’s orders: cost internalization.
For lenders and project finance teams, the PJM compliance filings are the documents that will define the practical economics of co-located load in the nation’s largest wholesale market. The 50 MW netting threshold, the specific rate structures for the three new transmission services, and the EIT eligibility criteria are pending FERC review. Until these provisions are finalized, the transmission cost component of project economics in PJM carries uncertainty that credit committees may wish to address through material adverse regulatory change provisions, debt-service coverage ratio cushions, or reserve account mechanics in financing documents.
SPP’s HILL Framework: An Alternative Model
On January 14, 2026, FERC issued an order (the SPP Order) accepting a framework proposed by the Southwest Power Pool (SPP), the RTO that administers the wholesale electricity market and manages the transmission grid across portions of 14 states in the central United States, including portions of Wyoming. SPP’s High Impact Large Load (HILL) framework provides the first RTO-specific pathway designed from the outset for expedited data center interconnection. The SPP framework took a fundamentally different approach from PJM’s. Where PJM focused on the generator side (regulating how existing and new generators can serve co-located load), SPP focused on the load itself.
SPP defines a HILL as a new commercial or industrial load, or an increase in commercial or industrial load, of 75 MW or greater at a single site connected through one or more shared points of interconnection or delivery points to the SPP transmission system. The associated High Impact Large Load Generation Assessment (HILLGA) process offers dedicated generation an expedited study path outside the standard Definitive Interconnection System Impact Study (DISIS) queue. HILLGA requests can be submitted on a rolling basis rather than during defined request windows, providing a meaningful speed advantage.
That speed, however, comes with some important constraints. HILLGA applications require fees and security deposits that are double those in the DISIS process. Geographic proximity requirements limit HILLGA generation to no more than two substations from the associated HILL, and a generating facility supporting multiple HILLs may involve no more than five substations with no more than two existing transmission line segments between each substation. These geographic constraints prevent HILLGA from functioning as a general queue-bypass mechanism while accommodating reasonable campus-style data center developments. HILLGA interconnection agreements carry a five-year term, after which the generator must either enter SPP’s standard interconnection process or terminate. Separately, HILLGA requests do not receive queue priority over standard interconnection requests, and the network upgrades identified through the HILLGA study process are assigned to the HILLGA customer rather than allocated to other interconnection customers in the standard queue.
SPP also imposed ongoing operational requirements on HILLs: hourly load forecast data provided in real time, remote disconnect capability for the transmission operator, ramp rate limitations not exceeding 20 MW per minute, and ride-through requirements. These operational constraints reflect reliability concerns about sudden large-load changes and may prove challenging for data center operators accustomed to flexible operations, though they may also signal the kind of operational requirements FERC could adopt more broadly.
The SPP framework is immediately relevant for the Mountain West. The western portion of PacifiCorp’s transmission system, including areas in central and eastern Wyoming, came under SPP RTO administration effective April 1, 2026. Projects previously subject only to the Western Area Power Administration (WAPA) – the federal power marketing administration that manages transmission assets across the western United States – or to PacifiCorp’s bilateral interconnection processes now face SPP’s standardized procedures, including FERC Order 2023 requirements and the HILL framework. Projects sited in areas outside SPP’s footprint may face different interconnection requirements depending on the transmission provider. WAPA’s own interconnection procedures, for example, are subject to FERC jurisdiction and may impose obligations independent of SPP membership.
For developers evaluating the Mountain West, the practical question is whether the generation-to-load configuration can be structured to avoid triggering SPP’s procedures. A fully islanded arrangement (radial connection from generation to load, no grid synchronization) should fall outside SPP’s interconnection framework because there is no interconnection to study. The HILLGA pathway becomes relevant only for projects that require grid interconnection, whether for backup, surplus sales, or reliability. Developers with sites that can support an islanded configuration may wish to evaluate a phased approach: begin operations on an islanded basis while pursuing HILLGA or standard interconnection in parallel, and transition to grid-connected service once interconnection rights are secured. The regulatory analysis for each phase differs and should be structured from the outset to accommodate the transition. Alert 3 in this series addresses the phased approach in detail.
Rocky Mountain Power’s anticipated entry into the Extended Day-Ahead Market administered by the California Independent System Operator (CAISO) in May 2026 adds a further dimension, deepening wholesale market access across Utah, Wyoming, and portions of Idaho and Oregon, and expanding both the opportunities and the potential jurisdictional triggers for BTM generation in those states. State-specific considerations are addressed in Alerts 5 (Colorado) and 6 (Wyoming and Utah).
Stepping Back: The Progression from Rejection to Regulation
These developments taken together (the Talen Order, the PJM Order, PJM’s compliance filings, and the SPP Order) reveal a Commission that has moved rapidly from rejection to regulation. In November 2024, FERC rejected a specific co-location arrangement. By December 2025, FERC had directed the creation of a comprehensive regulatory framework for co-located load in the nation’s largest wholesale market. By January 2026, FERC had accepted a complementary framework in SPP. By February 2026, PJM had filed detailed tariff revisions and an expedited interconnection track. In approximately 15 months, the regulatory landscape went from “no clear rules” to “detailed rules pending final approval.”
Understanding why FERC moved this quickly, and in this particular sequence, is important for anticipating what comes next. The Commission’s approach reflects a deliberate institutional strategy. Rather than asserting a national rule of general applicability over co-located load or large-load interconnections (a step FERC has not yet taken), the Commission built the framework incrementally, through individual proceedings involving specific RTOs. Each order established principles (cost causation, reliability study requirements, transmission service options) that the next order could build upon. Together, they create a body of precedent that a national rulemaking can draw upon.
DOE’s Proposed National Rulemaking: Moving Toward a Standardized Framework
In October 2025, Secretary of Energy Wright directed FERC to initiate a rulemaking proceeding (FERC Docket No. RM26-4-000) (the DOE Rulemaking Proposal) that would assert federal jurisdiction over the interconnection of large loads greater than 20 MW directly to FERC-jurisdictional transmission facilities. FERC responded by issuing an Advance Notice of Proposed Rulemaking, the first formal step in the federal rulemaking process, which solicits public comment on whether and how to proceed before proposing specific rules. The DOE Rulemaking Proposal sets out 14 guiding principles for a national framework that would establish standardized interconnection procedures for large loads, analogous to the existing generator interconnection framework under FERC Orders 2003 and 2023.
The DOE Rulemaking Proposal’s jurisdictional claim is significant, contested, and, from an institutional perspective, a departure from FERC’s preferred approach. As described above, the Commission had been building co-location frameworks region by region, through RTO-specific proceedings. The DOE Rulemaking Proposal asks FERC to leapfrog that incremental approach and assert jurisdiction over load interconnections nationally. This is authority FERC has never before claimed. Secretary Wright acknowledged as much in the directive, noting that FERC “has not exerted jurisdiction over load interconnections,” while arguing that doing so “falls squarely within the Commission’s jurisdiction.”
The tension between DOE’s push for a national framework and FERC’s institutional preference for building the record through RTO-specific proceedings is the central dynamic shaping the timeline. DOE initially directed FERC to take “final action” by April 30, 2026. At its April 17, 2026 open meeting, FERC announced that it will act on the DOE Rulemaking Proposal by the end of June 2026, two months later than DOE had requested. FERC Chairman Laura V. Swett stated that the Commission has been working “full speed, around the clock” on the proposal, reviewing approximately 3,500 public comments and consulting with regional grid operators and states developing their own data center policies. Chairman Swett acknowledged that the jurisdictional question is “very important,” noting that “[j]urisdiction is the first question that I, as a FERC litigator, ask.” Given that the rulemaking is still at the advance notice stage (typically followed by a Notice of Proposed Rulemaking (NOPR) and then a final rule), and given the significant jurisdictional objections filed by state commissions, utilities, and consumer advocates, the June 2026 timeline appears more likely to produce a NOPR or a policy statement than a final rule.
The DOE Rulemaking Proposal proposes 100% participant funding, meaning large-load customers would pay the full cost of network upgrades their projects trigger. This marks a significant departure from the traditional socialized model in which transmission upgrades are treated as shared infrastructure and recovered through regional transmission rates. The DOE Rulemaking Proposal asks whether a crediting mechanism could offset those costs over time if the upgrades deliver system-wide benefits. Stakeholder comments have split predictably: developers and technology companies favor a stronger federal role to reduce friction and shorten timelines, while states and many utilities view the proposal as a threat to their traditional authority over retail service, distribution, and resource planning.
The DOE Rulemaking Proposal’s scope is limited to interconnections “directly to transmission facilities,” consistent with FERC’s seven-factor test for distinguishing transmission from distribution. Fully BTM arrangements with no direct transmission interconnection, and facilities operating entirely off-grid, appear to fall outside the DOE Rulemaking Proposal’s proposed reach. The degree of jurisdictional exposure turns on the physical configuration: whether the line connecting generation to load is electrically islanded from the grid or synchronized with it, whether it is BTM, and what entity holds title to the electricity and the interconnecting facilities. A dedicated islanded line presents the strongest case for avoiding FERC jurisdiction. A radial line synchronized with the grid, even serving only one load, could be treated as a transmission facility within FERC’s reach. That distinction is critical and should be evaluated based on site-specific engineering.
An open question for developers with projects already in development is whether a final rule could reach facilities that were structured to avoid FERC jurisdiction at the time of development. The DOE Rulemaking Proposal’s proposed principles address “new” loads and hybrid facilities, and the comment request asks how to treat interconnections “already being studied” during any transition, but it does not expressly carve out facilities with no transmission interconnection at all. Developers with projects in the structuring phase should consider incorporating regulatory change provisions into interconnection and offtake agreements, including representations regarding regulatory status and renegotiation triggers tied to material changes in the applicable jurisdictional framework, to preserve optionality if the regulatory landscape continues to evolve. Lenders may wish to address the same risk through material adverse regulatory change triggers in financing documents.
Separately, the North American Electric Reliability Corporation (NERC), the entity responsible for developing and enforcing mandatory reliability standards for the bulk power system across the United States and Canada, has convened a Large Loads Task Force to develop reliability guidelines for large loads, with a potential mandatory Reliability Standard to follow. A mandatory standard could impose operational requirements on large-load operators regardless of their interconnection status or FERC jurisdictional classification. Developers structuring off-grid or islanded facilities should not assume that avoiding FERC transmission jurisdiction necessarily eliminates all federal regulatory exposure. This is an area that warrants close monitoring.
What This Means for Developers, Sponsors, and Lenders
For developers making near-term siting and procurement decisions, the federal landscape now presents a rough hierarchy. The Electric Reliability Council of Texas (ERCOT), which manages the vast majority of the Texas electric grid independently from the two major U.S. interconnections and largely outside FERC’s wholesale jurisdiction, remains the fastest and least regulated path to co-located or BTM generation at scale, though Texas Senate Bill (SB) 6 (which imposed new large-load interconnection requirements) and the ERCOT batch study transition add complexity that did not exist 18 months ago.
Islanded off-grid facilities in states with permissive regulatory frameworks offer the next-clearest path, avoiding both FERC jurisdiction and RTO interconnection requirements, though at the cost of overbuilding generation to cover reliability without grid backup. SPP’s HILL framework provides an expedited interconnection option with defined timelines but imposes geographic constraints, five-year term limits, and operational monitoring. PJM’s new co-location services are the most structured and potentially the most costly, but they provide regulatory certainty and access to the nation’s largest wholesale market. The optimal path will depend on the developer’s timeline, risk tolerance, capital structure, and whether grid backup or surplus sales are part of the operating model and investment thesis.
For sponsors and their advisors, the regulatory trajectory appears to create a meaningful distinction between new-build and acquisition strategies for co-located generation. The PJM Order’s requirements for existing generators modifying their interconnection agreements impose regulatory costs on acquisition-and-retrofit strategies that new-build dedicated generation may avoid. The tax analysis may compound this: new-build generation using qualifying clean energy technologies may be eligible for credits under Section 45Y or Section 48E of the Inflation Reduction Act of 2022 (IRA) that could materially alter project economics relative to acquisition of existing fossil-fuel generation. Sponsors may wish to model the full regulatory and tax differential before committing to an acquisition thesis.
For lenders and project finance teams, regulatory uncertainty around the DOE Rulemaking Proposal and pending PJM compliance filings introduces a period of elevated risk that may warrant specific attention in credit documentation. Until the framework stabilizes (likely no earlier than late 2026), financing documents for BTM generation projects should address regulatory change risk, including representations regarding the project’s current FERC jurisdictional status, material adverse regulatory change triggers tied to final action on the DOE Rulemaking Proposal or material modifications to the applicable RTO’s co-location tariff, and step-in or restructuring rights if the project’s interconnection or transmission service arrangements require modification. On the other side of the ledger, the regulatory barriers now emerging (upfront deposits, mandatory transmission charges, study timelines, self-funded generation expectations) may function as barriers to entry that favor well-capitalized sponsors with the balance sheet and regulatory sophistication to navigate the current environment.
For utilities and their regulatory counsel, the PJM Order and the Ratepayer Protection Pledge (discussed in the next alert) address legitimate cost recovery concerns. Standby and backup service rates remain the utility’s primary mechanism for recovering fixed costs from self-supplying customers, and the PJM Order’s gross demand billing and mandatory upgrade cost provisions are designed to prevent the cost shifts that concerned the Commission in the Talen Order. Developers who engage constructively with these concerns, through voluntary demand response commitments, emergency generation availability, standby service agreements that reflect actual backup usage, and cost-share arrangements for transmission infrastructure, may find themselves better positioned in regulatory proceedings than those who optimize for cost avoidance.
FERC’s announcement that it will act on the DOE Rulemaking Proposal by the end of June 2026 extends the timeline but does not change the direction. The Commission has signaled through the Talen Order, the PJM Order, and the SPP Order that BTM arrangements will be regulated, not prohibited. The remaining question is the scope and pace of that regulation. Stakeholders with active or planned projects should monitor FERC’s action on the DOE Rulemaking Proposal and the pending PJM compliance filings, and should consider how potential outcomes could affect existing or planned arrangements.
This is the first in a series of seven alerts on the regulatory frameworks for data center BTM generation. The next alert examines the Ratepayer Protection Pledge, the DATA Act, and the emerging political economy of data center power.
This alert is intended to provide a general overview of the federal regulatory developments applicable to behind-the-meter generation and co-located load arrangements serving data centers. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.
RJ Colwell is a Senior Associate at Davis Graham & Stubbs LLP in the Energy & Mining Group. His practice focuses on the regulatory, transactional, and structuring dimensions of data center power, advising data center developers, power generation companies, and their investors and lenders on FERC regulatory matters, behind-the-meter generation, co-located load arrangements, and energy infrastructure transactions. RJ can be reached at rj.colwell@davisgraham.com.