The previous alert in this series traced the Federal Energy Regulatory Commission’s (FERC or the Commission) regulatory trajectory from the Talen Order through the pending Advance Notice of Proposed Rulemaking on large-load interconnection (the DOE Rulemaking Proposal), a progression from rejection to structured accommodation in just 18 months. This alert examines the political and policy developments that are converging with that regulatory framework and that may prove equally consequential for how behind-the-meter generation and co-located load arrangements serving data centers (collectively, BTM) are structured, financed, and approved.
The regulatory orders described in Alert 1 established the legal architecture. The developments described here establish the political environment in which that architecture will be applied. For developers, sponsors, and their counsel, the practical implications of these political developments may be as significant as the tariff provisions themselves, because they shape how state regulators, utility counterparties, community intervenors, and lenders will evaluate any proposed data center power arrangement going forward.
The Ratepayer Protection Pledge
On March 4, 2026, President Donald J. Trump issued a proclamation establishing the Ratepayer Protection Pledge (the Pledge). The Pledge marks a notable shift in federal posture toward data center energy consumption, from an earlier emphasis on accelerating AI infrastructure buildout to a policy that is explicitly conscious of consumer energy costs. Seven leading hyperscalers and AI companies accepted the terms of the Pledge.
The Pledge contains five core commitments. First, signatories agreed to fund all new electricity generation required by their facilities, whether by constructing their own power plants, entering into long-term commitments to purchase power from new generation facilities, or acquiring output from newly developed generation assets, rather than drawing incremental power from the existing grid. Second, signatories committed to bearing the full cost of transmission and distribution upgrades necessary to interconnect and serve their facilities. Third, signatories agreed to negotiate dedicated rate schedules with their serving utilities and state regulators, accepting minimum payment obligations regardless of actual consumption, effectively functioning as take-or-pay arrangements for electricity service. Fourth, signatories pledged to make local investments in the communities where they operate, including through local hiring commitments and workforce development initiatives. Fifth, signatories committed to coordinating with regional grid operators on reliability planning and, where feasible, making on-site backup generation available to the grid during emergency conditions.
The Pledge is not legally binding on its signatories. It contains no enforcement mechanism, penalty provisions, or private right of action. However, the accompanying presidential proclamation declares that the Pledge’s commitments “effectuate the national policy of the United States.” That language, while not creating independent legal obligations, provides a reference point that regulators and intervenors are likely to cite in a variety of proceedings.
How the Pledge May Be Used
The Pledge’s significance lies less in what it requires of its seven signatories than in the baseline it may establish for the broader market. Several practical applications are foreseeable.
In state rate proceedings, intervenors and consumer advocates may cite the Pledge as evidence of industry-accepted cost allocation principles when challenging proposed interconnection arrangements or rate treatments that would shift data center costs to other customer classes. The Pledge’s self-funded generation and full infrastructure cost absorption commitments align closely with the cost-internalization principles that state commissions in Colorado, Utah, Virginia, and other states have been developing through large-load tariff proceedings. A state public utilities commission evaluating whether a proposed data center rate arrangement is just and reasonable may look to the Pledge’s commitments as a benchmark, even if the developer before the commission is not a signatory.
At FERC, the Pledge could be referenced in evaluating whether proposed co-location arrangements adequately protect existing ratepayers. The cost allocation requirements (gross demand billing, mandatory upgrade costs, transmission service elections) set forth in the PJM Order (described in Alert 1) are conceptually aligned with the Pledge’s principles. Future co-location filings that fall short of those principles may face a more skeptical reception.
In siting disputes and local permitting proceedings, communities opposing new data center projects may argue that developers who have not adopted the Pledge’s commitments are failing to meet the national policy standard the proclamation establishes. The Pledge’s community investment commitment provides a template that local officials and community groups may reference when negotiating community benefit agreements, tax incentive packages, or conditional use permits.
Non-signatory developers, including independent power producers and infrastructure-focused operators building dedicated generation for data center load, should expect to be measured against the Pledge’s commitments whether they signed or not. The Pledge did not create new legal obligations, but it may have established a new set of political and regulatory expectations.
The Utility Perspective on Cost Internalization
The Pledge, and the broader cost-internalization consensus it reflects, addresses a concern that utilities and consumer advocates have raised with increasing urgency: load defection and stranded cost recovery.
The electric grid’s cost structure is built on the assumption that large industrial and commercial loads will contribute to the fixed costs of transmission, distribution, and generation infrastructure through their utility rates. When a large load exits the grid through BTM generation, it reduces the revenue base over which those fixed costs are recovered, potentially increasing rates for remaining customers. If the same large load later returns to the grid for backup service during outages or maintenance, it imposes costs on a system it did not help maintain during the islanded period.
This dynamic is not unique to data centers, but the scale of data center load makes it particularly consequential. A single hyperscale data center campus can consume 500 MW or more, equivalent to the residential load of a mid-sized city. When that load exits the grid, the revenue impact on the utility and remaining ratepayers can be substantial.
Utilities address this concern through several mechanisms. Standby service tariffs impose demand charges, reservation fees, and non-bypassable delivery charges on self-generating customers who maintain a grid connection for backup. These tariffs are designed to ensure that self-generators contribute to the fixed costs of maintaining grid capacity and infrastructure even when they are not drawing significant energy from the system. Standby rates vary significantly among utilities and jurisdictions, and these variations can materially affect the economics of BTM generation projects. In some jurisdictions, standby charges alone can represent millions of dollars annually for a large data center, a cost that must be incorporated into the project’s financial model from the outset.
Beyond standby rates, utilities are increasingly seeking (and state commissions are increasingly approving) large-load tariffs that require upfront security deposits, commitment to minimum contract terms, and developer-funded infrastructure upgrades. Colorado’s Xcel Energy large-load tariff filing (filed April 2, 2026, and proposing approximately $600,000 in upfront commitments, developer-funded generation and transmission, and an optional clean transition component) is one example. Similar proceedings are underway or recently completed in Virginia, Georgia, Indiana, and other states experiencing significant data center load growth. According to the Smart Electric Power Alliance, state regulators approved 29 large-load tariffs in 2025 alone, with 77 more pending across 36 states. The pace of these filings suggests that large-load tariff design is becoming a distinct regulatory practice area, and developers should expect that utility counsel will arrive at interconnection negotiations with increasingly standardized frameworks for cost allocation, minimum commitment terms, and standby service design.
Developers who understand the utility’s position, and who structure their arrangements to address cost recovery and reliability concerns proactively, may find regulatory proceedings less adversarial and more productive. Voluntary demand response participation, emergency generation commitments, standby service agreements that reflect actual backup usage rather than attempting to minimize charges, and cost-share arrangements for transmission infrastructure serving the broader community are all mechanisms that can demonstrate to regulators and utilities that BTM generation and grid participation are not mutually exclusive.
The DATA Act and Competing Legislative Proposals
The Pledge represents the executive branch’s approach to data center energy policy: voluntary commitments by the largest companies, framed as national policy, with regulatory and political enforcement through downstream proceedings. Congress is exploring two fundamentally different legislative approaches.
In January 2026, Senator Cotton introduced the Decentralized Access to Technology Alternatives Act (the DATA Act), which would exempt fully off-grid power suppliers from the Federal Power Act and U.S. Department of Energy (DOE) regulation entirely. The bill has been referred to the Senate Energy and Natural Resources Committee but has not been scheduled for a hearing or markup as of this writing. If enacted, the legislation would create a statutory pathway for the complete FERC avoidance that 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, achieves structurally through geographic isolation from the interstate grid, but available nationwide regardless of geography.
The DATA Act reflects a fundamentally different theory of data center power than the Pledge. Where the Pledge assumes data centers will remain connected to the grid and focuses on ensuring they pay their fair share, the DATA Act would create a pathway for facilities to disconnect from the grid entirely, avoiding interconnection queues, transmission charges, and capacity market obligations altogether. For developers willing to invest in fully self-sufficient power infrastructure, this could accelerate project timelines and reduce regulatory complexity. However, fully off-grid facilities would still be subject to state and local environmental permitting requirements, including Clean Air Act compliance for on-site generation, and would need to address reliability concerns without the backstop of grid access, potentially requiring significant investment in redundant generation and storage capacity.
At the other end of the legislative spectrum, Senator Bernie Sanders and Representative Alexandria Ocasio-Cortez have introduced legislation calling for a federal moratorium on new data center construction, reflecting growing concern among some members of Congress about data center energy consumption, electricity affordability, and environmental impacts. Several state and local governments are considering or have enacted their own moratoriums or restrictions on data center development, driven by concerns about water usage, noise, air quality, and the strain on local power infrastructure.
Neither bill appears to have a clear path to enactment in the current Congress. The DATA Act would face opposition from utilities, consumer advocates, and state regulators who view it as undermining the cost-sharing framework that the PJM Order, the Pledge, and state large-load tariffs are designed to establish. The moratorium bill would face opposition from the technology industry, the administration, and economic development interests. But both bills signal that data center energy policy has become a contested issue on Capitol Hill, and both could influence the political environment in which the DOE Rulemaking Proposal, FERC co-location proceedings, and state regulatory proceedings unfold. Congressional staff on the Senate Energy and Natural Resources Committee are likely watching whether FERC’s action on the DOE Rulemaking Proposal reduces or increases legislative appetite for statutory intervention.
The MISO/SPP Transmission Complaint
On April 7, 2026, a coalition of transmission owners in the Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP) footprints, the regional transmission organizations (RTOs) that administer wholesale electricity markets across the central United States, filed a complaint at FERC requesting that the Commission either suspend competitive bidding for transmission projects for up to five years or exempt transmission projects needed to ensure timely construction of power generation and facilities with large electricity demands, such as data centers. The coalition argued that the competitive solicitation processes used by MISO and SPP to select transmission developers unreasonably delay projects that are needed to support data center and AI infrastructure. The complaint urged FERC to act by July 16, 2026.
Consumer advocates immediately opposed the complaint. The Electricity Transmission Competition Coalition described it as “tone-deaf to the electricity affordability crisis facing Americans” and warned that suspending competition would “expose consumers in these regions to unchecked cost escalation for years, guaranteeing higher utility bills.”
Former FERC officials have noted that the complaint appears to recast longstanding arguments against FERC Order 1000’s competitive transmission development framework (which eliminated a federal right of first refusal for incumbent utilities for regional transmission projects) in the language of AI infrastructure urgency. Former FERC Chairman Neil J. Chatterjee cautioned against “throwing the baby out with the bathwater” in response to what he characterized as old arguments in new packaging.
The complaint is significant for this series because it directly implicates the SPP High Impact Large Load (HILL) framework described in Alert 1 and the broader tension between accelerating transmission development and maintaining competitive processes that protect consumer interests. It also highlights a dynamic that runs throughout the data center power landscape: incumbents and new entrants are using the urgency of data center demand to advance pre-existing policy positions, and FERC must sort genuine data-center-driven concerns from opportunistic re-litigation of settled policy disputes.
MISO and SPP have indicated they are reviewing the complaint. FERC’s response, if it comes by the requested July 16, 2026 date, could affect transmission development timelines in a footprint that encompasses significant portions of the Mountain West, the Great Plains, and the upper Midwest. It will also test whether FERC can maintain the incremental, RTO-by-RTO approach to co-location policy described in this series, or whether the pressure for faster transmission development forces a more centralized response.
The NERC Reliability Dimension
Separately from the FERC proceedings and the legislative proposals, the North American Electric Reliability Corporation’s (NERC) Large Loads Task Force is developing reliability guidelines for the management of large loads. NERC is the entity responsible for developing and enforcing mandatory reliability standards for the bulk power system across the United States and Canada. A reliability guideline would leverage NERC’s technical analysis and establish best practices for how large-load operators manage their interaction with the bulk electric system. If NERC subsequently adopts a mandatory Reliability Standard (which would require FERC approval), it could impose registration, compliance, and audit obligations on large-load operators, potentially including operators of facilities that have structured to avoid FERC transmission jurisdiction.
Consumer group Public Citizen has separately called on FERC to declare that data centers and other large loads are subject to federal grid reliability standards. If FERC or NERC were to adopt this position, it could introduce a layer of federal regulatory exposure for off-grid and islanded facilities that is independent of the jurisdictional analysis described in Alert 1. Developers structuring off-grid or islanded facilities should not assume that avoiding FERC transmission jurisdiction necessarily eliminates all federal regulatory exposure. The NERC dimension is an area that warrants careful monitoring as the reliability guideline development process advances.
A Decision Framework for Near-Term Siting and Procurement
For developers making near-term siting and procurement decisions, the combined effect of the regulatory orders described in Alert 1 and the political developments described here produces a landscape with several distinct pathways, each carrying different tradeoffs in terms of speed, cost, regulatory certainty, and risk.
ERCOT remains the fastest and least regulated path to BTM generation at scale. ERCOT’s intentional isolation from the interstate grid eliminates FERC jurisdiction entirely, and the Private Use Network structure (a mechanism under ERCOT’s protocols that allows an electric network connected to the grid at a single point to serve only the owner’s load) provides a proven regulatory vehicle for self-supply. Texas Senate Bill (SB) 6’s new requirements (curtailment protocols, remote disconnect, load forecasting) and the ERCOT batch study transition add compliance complexity, but the absence of mandatory transmission service charges, capacity market obligations, and the federal co-location framework that applies in PJM Interconnection (PJM) and SPP preserves a significant structural cost advantage. For a 500 MW BTM facility, the annual cost differential between ERCOT and PJM could amount to tens of millions of dollars in avoided transmission and ancillary service charges. Alert 4 in this series examines the Texas/ERCOT framework in detail.
Islanded off-grid facilities in states with permissive regulatory frameworks (Wyoming and portions of Utah being the most relevant for this series) offer the next-clearest path. These arrangements avoid both FERC jurisdiction and RTO interconnection requirements, provided the facility has no synchronization with the grid. The tradeoff is reliability: an islanded facility must be sized to meet the data center’s full load plus reserve margin for maintenance and unplanned outages, typically requiring 15 to 30 percent excess generation capacity. The overbuilt capacity represents stranded investment during normal operations but is essential for operational continuity. Developers pursuing this path should also consider whether portions of their project area have recently come under RTO administration (as occurred with portions of Wyoming on April 1, 2026, when SPP assumed administration of part of PacifiCorp’s transmission system), which could affect the regulatory analysis for any future grid interconnection. Alert 6 addresses Wyoming and Utah in detail.
SPP’s HILL framework provides an expedited interconnection option with defined timelines. The High Impact Large Load Generation Assessment (HILLGA) process accepts rolling submissions (unlike PJM’s cluster-based study process), and SPP has indicated studies could be completed in approximately 150 days. But the framework imposes geographic proximity requirements, doubled fees and deposits, five-year interconnection term limits, operational monitoring (including remote disconnect and ramp rate limitations not exceeding 20 MW per minute), and a capacity accreditation cap tied to actual load. The five-year term limit means the HILLGA interconnection is a bridge, not a permanent solution; developers who intend to operate beyond five years must transition to SPP’s standard interconnection process.
PJM’s new co-location services are the most structured and potentially the most costly. Gross demand billing, mandatory transmission service elections, full study processes for existing generators, and network upgrade cost responsibility create a regulatory compliance burden that does not exist in ERCOT or in islanded arrangements. However, PJM offers regulatory certainty (the co-location tariff revisions are pending FERC review with a requested effective date of July 31, 2026), access to the nation’s largest wholesale market, and the ability to monetize surplus generation through PJM’s energy, capacity, and ancillary service markets. For developers with the capital to absorb the upfront costs and the sophistication to navigate the regulatory framework, PJM may offer a more predictable long-term operating environment than less regulated jurisdictions where the rules are still emerging.
The optimal path will depend on the developer’s timeline, risk tolerance, capital structure, generation technology, and whether grid backup or surplus sales are part of the operating model and investment thesis. State-level frameworks add a further dimension that varies significantly by jurisdiction. In Colorado, cost-internalization and binding emissions reduction mandates shape not only economics but the range of permissible generation technologies for BTM arrangements. In Utah, pragmatic regulation, a statutory framework for large-load service (Utah SB 132), and municipal utility alternatives create a different set of opportunities. Wyoming’s minimalist regulatory framework offers speed but now carries an SPP overlay in portions of the state. These state-specific frameworks reflect affirmative policy choices, not incidental regulatory friction, and they are examined in subsequent alerts in this series.
Implications for Financing and Deal Structuring
The political developments described in this alert have several implications for how data center power projects are financed and structured.
The cost-internalization consensus appears to be hardening at every level of government. Whether through FERC orders, state large-load tariffs, the Pledge, or the 13-governor Statement of Principles described in Alert 1, the expectation that data center load will fund its own generation and infrastructure is becoming the regulatory and political baseline. Developers should generally expect to internalize the full cost of generation, transmission upgrades, and grid services in their project economics. The structuring question, how to allocate these costs across power purchase agreements, tolling agreements, lease arrangements, and partnership structures while preserving jurisdictional advantages, is the subject of the next alert in this series.
The regulatory trajectory may favor new-build over acquisition. As discussed in Alert 1, the PJM Order’s requirements for existing generators modifying their interconnection agreements (full study process, full upgrade cost responsibility, capacity market adjustments) impose regulatory costs on acquisition-and-retrofit strategies that new-build dedicated generation may be able to avoid. Acquisition strategies do, however, offer advantages that new-build cannot replicate: proven generation performance, existing fuel supply and water arrangements, established community relationships, and immediate operational capacity without construction risk. The regulatory cost differential is one input into the build-vs-buy analysis, not a dispositive one. The tax analysis may compound this distinction: 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, particularly where the sponsor’s ownership and operating structure is designed to capture or transfer those credits under Internal Revenue Code Section 6418 transfer elections. The interplay among the regulatory cost differential, tax credit eligibility, and generation technology selection is complex and will depend on the specific project economics, the applicable jurisdiction, and the developer’s tax position. These are determinations that require coordination among energy counsel, tax counsel, and the project’s financial advisors.
Financing documents should address regulatory change risk with specificity. The period between now and the stabilization of the co-location framework (likely no earlier than late 2026) presents elevated uncertainty for lenders underwriting long-tenor debt against BTM generation assets. Credit committees may wish to consider material adverse regulatory change triggers tied to final action on the DOE Rulemaking Proposal or material modifications to applicable RTO co-location tariffs. Step-in or restructuring rights that allow the lender to require modifications to the project’s interconnection or transmission service arrangements if the regulatory framework changes materially during the loan term may be appropriate. Cash sweep or reserve account mechanics tied to the imposition of previously unanticipated transmission service charges warrant consideration as well. Representations regarding the project’s current FERC jurisdictional status, and covenants requiring notice if that status is challenged or changes, provide a threshold level of protection.
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. The capital required to meet these requirements (front-loaded study costs, infrastructure funding obligations, take-or-pay rate commitments) is substantial, and developers who lack the resources to absorb the upfront investment may be unable to compete effectively. For sponsors already positioned in this space, the hardening regulatory and political consensus could prove to be a competitive advantage as much as a cost, concentrating market opportunity among firms that can navigate the multi-jurisdictional framework.
What to Watch
End of June 2026: FERC’s announced timeline for action on the DOE Rulemaking Proposal. At its April 17, 2026 open meeting, 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. 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.
July 16, 2026: Requested action date on the MISO/SPP transmission owner complaint.
July 31, 2026: PJM’s requested effective date for co-location tariff revisions and the Expedited Interconnection Track.
Ongoing: NERC Large Loads Task Force reliability guideline development, with a potential mandatory Reliability Standard to follow.
Ongoing: State large-load tariff proceedings across multiple jurisdictions, including the Colorado Public Utilities Commission’s review of Xcel Energy’s April 2, 2026 filing.
Stakeholders with active or planned projects should monitor these proceedings and consider how potential outcomes could affect existing or planned arrangements. Positioning interconnection and structuring strategies in anticipation of regulatory clarity, rather than waiting for outcomes to be finalized, may reduce the risk of stranded structuring decisions.
This is the second in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions. The next alert addresses transactional structuring to manage FERC jurisdiction.
This alert is intended to provide a general overview of the political, policy, and strategic developments applicable to data center power procurement and behind-the-meter generation. 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.