On April 30, 2026, the United States Court of Appeals for the Tenth Circuit issued an opinion affirming summary judgment in favor of Defendants Netflix, Inc. and Royal Goode Productions, LLC and holding that the use of short clips from copyrighted videos in the hit documentary series Tiger King: Murder, Mayhem and Madness (“Tiger King”) did not constitute copyright infringement.

Background

Timothy Sepi was hired in 2015 to work at the Gerald Wayne Interactive Zoological Park (the “Park”), which was operated by Joseph Maldonado-Passage (also known as Joe Exotic). The Park housed exotic animals and had a web series called Joe Exotic TV. Part of Mr. Sepi’s job was to photograph and film park tours.  Mr. Sepi also performed filming and editing for Joe Exotic TV. Mr. Sepi terminated his employment relationship with the Park in 2016.

In 2020, Netflix and Royal Goode released the Tiger King series, which included seven videos that Mr. Sepi filmed while employed by the Park. Tiger King also included an eighth video documenting the funeral of Joe Exotic’s husband that Mr. Sepi filmed after leaving the Park. After Tiger King was released, Mr. Sepi filed for and received copyright registrations for all eight videos and then sued Netflix and Royal Goode for copyright infringement.

The district court granted summary judgment for the defendants, holding that Mr. Sepi did not own the copyright for seven of the videos because they were works made for hire. It further held that the defendants’ use of the funeral footage was fair use and did not infringe upon Mr. Sepi’s copyright.

On appeal, the Tenth Circuit panel addressed two issues: (i) whether the seven videos filmed during Mr. Sepi’s employment were “works made for hire” under the Copyright Act, and (ii) whether the use of the funeral video qualified as fair use. The panel ruled against the plaintiffs on both issues.

Analysis

On the first issue, the Tenth Circuit held that the plaintiffs had waived their challenge to the district court’s work-made-for-hire determination because they were advancing a new argument on appeal. For the first time, plaintiffs argued that Mr. Sepi’s scope of employment as a tour videographer did not extend to cinematography or film editing conducted on his own time. The panel found the new theory incompatible with the argument presented below and held plaintiffs waived the argument. Accordingly, the court affirmed the district court’s grant of summary judgment as to the first seven videos.

On the second issue, the panel conducted an extensive fair use analysis of the Funeral Video and concluded that all four statutory factors under 17 U.S.C. § 107 favored Netflix.

As to the first fair use factor—purpose and character of the use—the panel found that Netflix’s use of approximately sixty-six seconds of the nearly twenty-four-minute Funeral Video was significantly transformative. While Mr. Sepi created the Funeral Video as a remembrance of Mr. Maldonado, Netflix used excerpted clips to illustrate Joe Exotic’s purported megalomania and showmanship. The panel emphasized that this was “classic documentary-style borrowing.” While acknowledging that Tiger King had an undeniable commercial purpose, the panel cautioned that this is not dispositive and the focus is on the “commercial exploitation of the copyrighted work itself, not the commercial nature of the secondary work as a whole.” The panel found that the commercialism of the use did not “loom large” given the insubstantial nature of the borrowing because it could not be said that the success of the Tiger King was due to its use of the Funeral Video—the clip comprised only 2.58% of Episode Five and 0.35% of the entire series.

On the second factor—the nature of the copyrighted work—the panel found the Funeral Video to be factual rather than creative, noting that Mr. Sepi simply placed a camera on a tripod and left it running without directing or arranging the events depicted. The panel also rejected the plaintiffs’ argument that the video was “unpublished,” reasoning that the relevant inquiry focuses on whether a work has been disclosed or disseminated—which it had, through livestreaming and posting on YouTube—and not on the statutory definition of “publication.”

On the third factor—the amount and substantiality of the portion used—the panel found that defendants used a quantitatively insubstantial amount of the Funeral Video and took no more than was necessary for their transformative purpose.

On the fourth factor—market impact—the panel concluded that the plaintiffs failed to identify any protectible derivative market that could be harmed by defendants’ use. The panel further noted that Mr. Sepi had never licensed, sold, or otherwise commercially exploited any of his work, and the significantly transformative nature of defendants’ copying attenuated the likelihood of any cognizable market harm.

The panel ultimately affirmed summary judgment for the defendants on both issues.

This decision is notable for its thorough analysis of fair use in the documentary context following the Supreme Court’s decision in Andy Warhol Foundation for the Visual Arts, Inc. v. Goldsmith, 598 U.S. 508 (2023). The panel reinforced that documentary-style borrowing of short clips for purposes of education, social commentary, and criticism frequently qualifies as fair use—particularly when the use is insubstantial and serves a distinctly different purpose from the original.

The case is Whyte Monkee Productions, LLC v. Netflix, Inc., No. 22-6086. The opinion was authored by Chief Judge Holmes, with Judges Hartz and Carson concurring.

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For questions about this legal alert, please contact a member of the Davis Graham Appellate Group.

On May 4, 2026, the Colorado Supreme Court held in Northern Integrated Supply Project Water Activity Enterprise v. VIMA Partners, LLC, 2026 CO 29, that a water activity enterprise—a special purpose business entity formed under sections 37-45.1-101 to -107, C.R.S. (2025) to carry out water projects—may condemn private property when exercising its parent water conservancy district’s legal authority in relation to “water activities,” which by statute includes infrastructure related to the distribution of wholesale or retail water.

Background

The case arose from the Northern Integrated Supply Project Water Activity Enterprise’s condemnation petition seeking permanent and temporary construction easements over land owned by VIMA Partners, LLC. NISP Enterprise stated that it needed the easements to survey, build, and maintain water delivery pipelines and related infrastructure for the Northern Integrated Supply Project, a regional water supply and distribution project intended to provide 40,000 acre-feet annually of new water supply to fifteen municipalities and water districts within Northern Water’s boundaries. VIMA moved for judgment on the pleadings, arguing that no statute cited by NISP Enterprise gave it the power of eminent domain. The district court denied that motion, and VIMA then sought relief under C.A.R. 21.

The Court’s Analysis

The Supreme Court began by acknowledging that eminent domain statutes are construed narrowly, ambiguities are resolved in favor of the landowner, and condemnation authority cannot be implied from doubtful or vague statutory language. But those principles did not help VIMA because the Court concluded that the governing statutes expressly supplied the necessary authority.

To reach this conclusion, the Court looked at the plain language of Colorado’s statutes to answer two questions: who is allowed to condemn property under section 37-45-118(1)(c), and what they are allowed to condemn property for.

The Court answered the first question by reading two statutes together. The first, section 37-45-118(1)(c), allows a “water conservancy district board” to take private property when needed to carry out its powers under the Water Conservancy Act. The second, section 37-45.1-103(4), provides that the governing body of a “water activity enterprise” “may exercise the district’s legal authority relating to water activities.” While not a “water conservancy district board,” the Court held that NISP Enterprise could nevertheless condemn property under section 37-45-118(1)(c) because it had the same legal authority to condemn as its parent district, Northern Water Conservancy District, as long as the condemnation is tied to “water activities.”

The Court answered the second question by looking at the plain and unambiguous language of section 37-45.1-102(3).  That section defines “water activity” to include “the diversion, storage, carriage, delivery, distribution, collection, treatment, use, reuse, augmentation, exchange, or discharge of water,” as well as wholesale or retail water, wastewater, or stormwater services and the acquisition of water or water rights. Because NISP Enterprise sought easements for pipelines and related infrastructure for a water delivery and distribution project, the Court concluded that the work was directly related to the acquisition, carriage, delivery, and distribution of water.

Finally, the Court also noted that section 38-1-202(1)(f)(XXX) separately identifies a water activity enterprise as an entity that may exercise the eminent domain authority of the district that owns it in relation to a water activity.

While the Court acknowledged VIMA’s emphasis on Colorado’s strict-construction canon that courts should not stretch statutory language to find condemnation power where there is none, the Court was ultimately unwilling to construe the statutes so strictly so as to ignore the plain language of the statutes at issue. In doing so, it distinguished cases where parties tried to locate condemnation power in other vague or broad statutory language that never actually mentioned eminent domain or that failed to specifically identify who could exercise it or for what purpose. Here, the Court held that the statutes clearly did both: section 37-45-118(1)(c) names eminent domain expressly, and section 37-45.1-103(4) authorizes water activity enterprises to exercise their parent district’s legal authority for water activities. Strict construction, the Court emphasized, does not permit courts to ignore what the legislature actually wrote.

Consistency with Prior Eminent Domian Caselaw

The decision fits squarely within a line of reasoning the Court established two decades ago in Department of Transportation v. Stapleton, 97 P.3d 938 (Colo. 2004), a case the Court expressly cited in rejecting VIMA’s narrow-construction argument. In Stapleton, a landowner argued that CDOT could not condemn her property near State Highway 82 for a parking and transit facility because it was not a “highway.” 97 P.3d at 941. The Court disagreed. It held that “state highway purposes” were broad enough to encompass a transit facility that was an integral component of a broader highway improvement project. Id. at 941, 945. The Court acknowledged the narrow-construction rule but applied what amounts to a common-sense test: read the grant of authority in light of the statutory scheme as a whole and ask whether the proposed taking has a functional relationship to the entity’s authorized public purpose. Id.

That same framework drove the result in NISP Enterprise. VIMA urged the Court to treat “water activities” as an exhaustive checklist and to exclude pipelines because the word “pipeline” appeared only in a separate statutory definition. The Court refused to read the statute that rigidly, holding instead that “relating to water activities” covers actions functionally connected with water delivery and distribution, which is exactly the purpose that NISP Enterprise’s proposed water delivery pipelines would serve.

The through-line from Stapleton to NISP Enterprise is clear: strict construction of eminent domain statutes is still required, but it does not defeat condemnation authority where the plain language of the statute identifies the power, identifies the entity or source of delegated authority, and the proposed taking bears a direct, practical relationship to the public function the legislature authorized.

Practical Implications

This decision matters beyond the parties involved. Water activity enterprises have become the vehicle for pursuing water projects across Colorado, largely because they allow districts to operate outside TABOR’s taxing, revenue, and spending limitations. The General Assembly created them for precisely that purpose: to let water conservancy districts, water conservation districts, and other governmental entities keep building water infrastructure without running afoul of TABOR’s fiscal constraints. Until now, there was no Colorado appellate authority squarely addressing whether those enterprises could exercise eminent domain. Now there is, and the answer is yes, provided the taking relates to water activities. For project sponsors, the takeaway is practical: tie every proposed taking to the condemning entity’s statutory powers, and document clearly how the property interest sought relates to the authorized public activity.

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For questions about this legal alert, please contact a member of the Davis Graham Appellate Group.

The first six alerts in this series addressed how data centers can navigate regulatory frameworks to secure behind-the-meter generation and co-located load arrangements (collectively, BTM) across multiple jurisdictions. This final alert addresses a different set of questions: What does the emergence of data center BTM generation at gigawatt scale mean for the electric grid? What responsibilities should large loads accept, even where regulation does not compel them? And what does the regulatory landscape described throughout this series look like when viewed as a whole?

The distinction between what a developer can do and what a developer should do runs throughout this series, but it is sharpest here. The structuring techniques described in Alert 3, the jurisdictional advantages described in Alerts 4 and 6, and the regulatory frameworks described in Alerts 1, 2, and 5 collectively provide developers with the tools to minimize their regulatory burden and, in some configurations, to avoid Federal Energy Regulatory Commission (FERC) and state utility regulation almost entirely. The question this alert poses is whether minimizing the regulatory burden should be the end of the analysis, or whether there are strategic, economic, and policy reasons to engage the grid and its stakeholders more constructively than the minimum the law requires.

There is a reasonable case that the developers and sponsors who build the most durable competitive positions may be those who treat regulatory frameworks not as obstacles to circumvent but as expressions of societal priorities to engage with. The regulatory trajectory described in the preceding alerts, the political developments described in Alert 2, and the practical reality that data centers depend on the grid and the communities around them in ways that a purely regulatory analysis does not fully capture, all suggest that constructive engagement may produce better long-term outcomes than optimization for regulatory avoidance, though reasonable minds can and do differ on where to draw that line for any given project.

The Cooperative Bargain and Its Limits

The American electric grid is critical infrastructure built over nearly a century through a combination of private investment, public subsidy, and regulatory compacts. The regulatory frameworks that govern it, from the Federal Power Act’s (FPA) jurisdictional division to state utility certification requirements to regional transmission organization (RTO) tariff structures, reflect a foundational premise: that the costs and benefits of the grid should be shared among its participants in a manner that is just, reasonable, and non-discriminatory.

BTM generation, at the scale the data center industry is now pursuing, challenges that premise. When a 500 MW load islands itself through dedicated on-site generation, it exits the cooperative cost structure that supports the transmission network, the distribution system, backup generation capacity, frequency regulation, voltage support, and the administrative infrastructure of grid management. The remaining ratepayers, predominantly residential and small commercial customers, bear a proportionally larger share of those fixed costs.

This is the concern that has animated every major regulatory development described in this series. The Talen Order’s cost allocation analysis (described in Alert 1). The PJM Order’s gross demand billing and mandatory upgrade cost provisions (described in Alert 1). The Ratepayer Protection Pledge’s five commitments (described in Alert 2). The DOE Rulemaking Proposal’s proposed 100% participant funding (described in Alert 1). State large-load tariffs from Colorado to Virginia to Georgia. The 13-governor Statement of Principles (described in Alert 1) demanding that data centers bear their own infrastructure costs. Each of these actions, taken by different institutions at different levels of government, reflects the same underlying concern: that large loads should not defect from the cooperative bargain without accounting for the costs of that defection.

The concern is not unique to data centers. Industrial self-generation has existed for decades, and the tension between self-supply and grid cost recovery is a longstanding feature of utility regulation. What distinguishes the current moment is scale. A single hyperscale data center campus can consume more electricity than many American cities. The aggregate load growth from data centers is projected to account for the majority of U.S. electricity demand growth over the next decade. At that scale, the cost allocation consequences of load defection are not marginal adjustments; they are structural changes to the economics of the grid.

The Sustainability Paradox

A fundamental tension pervades data center BTM generation that deserves direct acknowledgment. The same developers pursuing aggressive carbon-neutrality commitments often contemplate natural gas BTM generation to bypass interconnection queues and regulatory complexity. The same sponsors marketing infrastructure funds aligned with environmental, social, and governance (ESG) criteria are underwriting gas plants because they deliver power faster and cheaper than renewables with storage at the scale data centers require.

This tension does not lend itself to easy resolution, and this alert does not pretend to resolve it. Renewable BTM generation faces intermittency challenges that require oversizing, battery storage, or fossil backup, all of which increase cost and complexity. Nuclear generation promises the optimal combination of baseload reliability and carbon-free operation, but commercial deployment of small modular reactors (SMRs) remains years away. Natural gas generation delivers reliable power on timeline and on budget, but at a carbon cost that increasingly conflicts with corporate sustainability commitments, investor ESG screening, and the regulatory environment in states like Colorado (described in Alert 5).

The market appears to be resolving this tension through hybrid configurations that combine multiple generation technologies. Solar or wind provides daytime or baseload renewable generation and the associated clean energy attributes. Battery storage firms the renewable resource, provides grid services revenue potential, and addresses short-duration intermittency. Natural gas provides backup for extended weather events, nighttime demand, and unplanned outages. The clean electricity production credit (Section 45Y) and investment credit (Section 48E) under the Inflation Reduction Act of 2022 (IRA) improve the economics of the renewable and storage components. Battery storage costs continue to decline. The optimal configuration varies by jurisdiction, resource availability, interconnection constraints, and the developer’s tolerance for intermittency risk.

For sponsors evaluating the sustainability dimension, the key insight is that the tension is not going away and that the market’s tolerance for gas-only BTM generation may narrow over time. Corporate procurement officers at hyperscalers are under increasing pressure from their own sustainability teams and from investor ESG reporting requirements. State regulatory frameworks, particularly in Colorado, are beginning to channel data center generation toward clean energy technologies. The Ratepayer Protection Pledge’s community investment and grid reliability commitments create a public expectation of responsible energy practices that goes beyond emissions alone. Developers who build hybrid or renewable BTM generation today may be better positioned for a regulatory and commercial environment that is trending toward decarbonization than developers who optimize for the lowest-cost generation technology without considering the trajectory.

The SMR Pipeline

Advanced nuclear technology may ultimately resolve the sustainability paradox by providing carbon-free, baseload, high-capacity-factor generation that can be purpose-built for data center loads. Several SMR developers have announced partnerships or strategic plans targeting data center applications at multi-gigawatt scale by the late 2030s or early 2040s, combining near-zero carbon emissions, small physical footprints, and long operating lives with the baseload reliability that data center loads require.

Wyoming and Utah are among the most favorable jurisdictions for early SMR deployment. Wyoming has adopted a nuclear-supportive legislative environment, including statutory provisions facilitating nuclear development and institutional support through the Wyoming Energy Authority. Utah’s pragmatic regulatory framework and Utah Senate Bill 132’s large-load safe harbor provide a pathway for nuclear-powered data centers that does not exist in states with more restrictive regulatory environments. Both states have retiring coal plant sites with existing transmission interconnections, water rights, cooling infrastructure, and trained workforce, all of which reduce the cost and timeline for new generation development and make those sites attractive candidates for SMR siting.

The regulatory pathway for SMR deployment remains complex. Nuclear Regulatory Commission (NRC) licensing is a multi-year process addressing safety, security, and environmental impacts. FERC jurisdiction applies outside ERCOT for any SMR interconnected to the transmission system, though radially connected SMRs serving dedicated loads may be able to avoid FERC jurisdiction under the same analysis described in Alert 3. State siting authority applies in every jurisdiction and could prove controversial in some. The fuel supply question, particularly for designs requiring high-assay low-enriched uranium, involves supply chain and regulatory considerations that are still being resolved at the federal level. And foreign entity of concern (FEOC) compliance considerations apply for any reactor components sourced from certain countries under the IRA’s foreign entity restrictions.

Spent fuel management presents a further consideration that developers should not overlook. The U.S. has no permanent repository for commercial nuclear waste, and SMR operators will be responsible for on-site storage of spent fuel assemblies for an indefinite period, with the associated costs, security obligations, and long-term site liability that on-site storage entails. Developers evaluating the SMR pathway should account for spent fuel storage in their site planning, decommissioning reserves, and ground lease or land acquisition documents from the outset.

For developers with seven-to-ten-year horizons, the SMR pathway may warrant serious evaluation, and Wyoming and Utah are among the most favorable jurisdictions for early deployment. For developers operating on two-to-four-year timelines, SMR deployment is not yet a near-term planning assumption. The optimal near-term strategy may be to secure sites with characteristics that support both conventional generation today and potential SMR deployment in the future, including adequate land, water, transmission access (or the ability to island), and community support for energy development.

For lenders and sponsors, the SMR investment thesis is currently a venture-stage proposition rather than a project-finance-stage proposition. The capital intensity of first-of-a-kind nuclear deployment, the regulatory timeline, and the technology risk are not well-suited to traditional project finance structures with fixed repayment schedules and limited-recourse credit. As SMR technology matures and the first commercial units demonstrate operational performance, the financing structures will likely evolve toward more conventional project finance models. In the interim, early-stage capital (equity investment in SMR developers, site optioning, development-stage financing for NRC licensing and permitting) may represent the appropriate risk-return profile.

Coal Plant Site Conversion

A related opportunity involves the acquisition and conversion of retiring coal plant sites for data center use. Multiple coal plants across Wyoming and Utah face retirement in the coming years as utilities execute their clean energy transition plans. These sites offer existing transmission interconnections (which may be available for data center service without a new interconnection queue position), existing water rights and cooling infrastructure, permitted land with established industrial use, existing environmental compliance history, and trained workforce familiar with power generation operations.

For sponsors evaluating acquisition strategies, coal plant conversion represents a distinct transaction type. The acquisition target is a retiring or recently retired generation facility, and the development thesis involves converting the site to data center use with new or repurposed generation. The regulatory analysis for the conversion depends on whether the new generation will be grid-connected (triggering the applicable interconnection procedures and, in SPP territory, the HILL framework) or islanded (avoiding the federal overlay). The existing transmission interconnection may be a significant asset, potentially reducing or eliminating the queue delay and study costs that a greenfield project would face, but the interconnection rights associated with the retiring plant may need to be restructured or replaced to accommodate the new use.

From a project finance perspective, coal plant conversion projects present a distinctive risk profile. The existing infrastructure reduces capital expenditure relative to a greenfield development, but the condition of the existing assets (particularly the transmission interconnection, the water rights, and any environmental remediation obligations) requires thorough diligence. Lenders should evaluate the transferability and adequacy of the existing permits, the status and remaining term of any water rights, the environmental condition of the site (including potential remediation obligations under state and federal environmental law), and the regulatory status of the existing interconnection. Coal plant sites in both Wyoming and Utah may also qualify for the energy community bonus credit under the IRA, a 10% adder available for projects sited in census tracts with retiring coal facilities or significant fossil fuel employment. For new-build renewable or clean energy generation at converted coal sites, the bonus credit can materially improve project economics and may help offset the remediation and infrastructure costs associated with the conversion.

Transmission Cost Allocation Reform

The transmission cost allocation question cuts across every jurisdiction in this series and is likely to remain the most contested policy issue in data center energy regulation for the foreseeable future.

Current transmission cost allocation methodologies in most organized markets socialize network upgrade costs across load-serving entities on a regional or zonal basis. This approach reflects the historical assumption that the transmission network serves all users and that its costs should be shared broadly. That assumption becomes strained when individual loads reach the scale of small cities and when those loads have the option to exit the grid through BTM generation.

The approaches to this problem that have emerged across the jurisdictions in this series are varied but directionally consistent. The PJM Order (described in Alert 1) requires existing generators modifying their interconnection agreements to bear full cost responsibility for network upgrades, and mandates gross demand billing for ancillary services across all co-located loads. The DOE Rulemaking Proposal (described in Alert 1) proposes 100% participant funding, under which large-load customers would pay the full cost of the network upgrades their interconnection triggers. The Southwest Power Pool’s (SPP) High Impact Large Load (HILL) framework (described in Alert 1) caps capacity accreditation and requires geographic proximity to prevent the HILL Generation Assessment (HILLGA) process from becoming a mechanism for socializing upgrade costs across the broader system. The Ratepayer Protection Pledge’s second commitment (full infrastructure cost absorption) codifies the same principle at the executive level. And state large-load tariffs across more than 30 states are implementing jurisdiction-specific versions of the same concept.

FERC’s stakeholder comment process on the DOE Rulemaking Proposal has surfaced a potential middle ground. Multiple state commissions, utilities, and technology companies have proposed that large loads would fund upgrades upfront but receive partial refunds or credits over time if those upgrades deliver system-wide reliability or congestion benefits. This approach preserves the cost-causation principle (the developer who triggers the upgrade pays for it) while acknowledging that transmission upgrades, once built, often benefit users beyond the specific customer who funded them.

The cost allocation framework that FERC ultimately adopts, whether through the DOE Rulemaking Proposal proceeding, through RTO-specific compliance proceedings, or through a combination of both, will be one of the most consequential determinants of BTM generation economics nationwide. Developers, sponsors, and lenders should monitor the DOE Rulemaking Proposal proceeding (with FERC having announced at its April 17, 2026 open meeting that it expects to act by the end of June 2026), the PJM Interconnection (PJM) paper hearing (with PJM’s initial brief filed in February 2026, responses due March 2026, and replies due April 2026), and state-level tariff proceedings for developments that could materially affect project economics.

NERC Reliability Standards and the Registration Question

The North American Electric Reliability Corporation’s (NERC) Large Loads Task Force is developing reliability guidelines for the management of large loads, with a potential mandatory Reliability Standard to follow. NERC is the entity responsible for developing and enforcing mandatory reliability standards for the bulk power system across the U.S. and Canada. This workstream has received less public attention than the FERC orders and the DOE Rulemaking Proposal, but its implications could be significant for developers who have structured their projects to avoid FERC transmission jurisdiction.

A reliability guideline, if adopted, would establish voluntary best practices for how large-load operators interact with the bulk electric system. A mandatory Reliability Standard, if subsequently adopted and approved by FERC, could require large-load operators to register as NERC-registered entities, comply with specific operational and procedural requirements, submit to NERC audit authority, and face penalties for non-compliance.

The registration question is particularly important for developers of islanded or off-grid facilities. As described in Alerts 1 and 3, an islanded facility with no grid interconnection presents the strongest case for avoiding FERC transmission jurisdiction. But NERC’s reliability jurisdiction is not coextensive with FERC’s transmission jurisdiction. NERC’s authority extends to users, owners, and operators of the bulk electric system, and the question of whether a large load that affects the bulk electric system (even indirectly, through its effect on system frequency, voltage, or resource adequacy) is a “user” subject to NERC registration is not settled.

Consumer group Public Citizen has called on FERC to declare that data centers are subject to federal grid reliability standards, which would effectively resolve this question in favor of mandatory registration. FERC has not acted on that request, and FERC’s institutional preference for incremental action (described in Alert 1) suggests that a sweeping declaration is less likely than a targeted approach through the NERC standards development process. But the direction of travel is worth noting: the same political and regulatory dynamics that produced the Talen Order, the PJM Order, the Ratepayer Protection Pledge, and the DOE Rulemaking Proposal are also producing pressure to bring large loads within the reliability standards framework.

Developers of islanded and off-grid facilities should not assume that avoiding FERC transmission jurisdiction eliminates all federal regulatory exposure. The NERC dimension represents a separate analytical track that may converge with the jurisdictional framework described in earlier alerts. The reliability guideline development process, and any subsequent Reliability Standard proposal, warrant careful monitoring.

Voluntary Grid Support: The Strategic Case

Regardless of what the regulatory framework ultimately requires, there are strategic reasons for data center developers to make voluntary commitments to grid support. These commitments can take several forms.

Demand response participation, in which the data center reduces its load during peak demand events in response to grid operator requests or price signals, directly addresses the resource adequacy concern that underlies much of the regulatory activity described in this series. For data centers with operational flexibility to shift or defer certain workloads, demand response can provide a meaningful contribution to grid reliability while generating revenue through demand response programs or avoided peak-demand charges.

Emergency generation commitments, in which the data center makes its on-site generation available to the grid during system emergencies, address the reliability concern from the generation side. In ERCOT, emergency exports during scarcity events can capture pricing up to $5,000/MWh, providing a direct financial incentive. In PJM and SPP, the value may be realized through capacity market participation or bilateral reliability contracts.

Voluntary reliability contributions, such as reactive power support and voltage regulation, address technical reliability needs that the grid operator may struggle to meet as large loads concentrate in specific areas. These services are typically compensated through ancillary service markets or bilateral arrangements.

Cost-share agreements for transmission infrastructure benefit the broader community by ensuring that grid improvements funded in connection with a data center project are available to serve other users. These agreements can take the form of direct financial contributions, infrastructure donations, or negotiated arrangements with the serving utility and the state commission.

The strategic case for these commitments is straightforward. Regulators are more likely to approve interconnection agreements, special contracts, and tariff arrangements for developers who demonstrate grid responsibility. Utilities are more cooperative counterparties when the developer addresses their cost recovery and reliability concerns proactively. Communities are more receptive to large-scale development when the developer invests in local infrastructure and services. And lenders may view voluntary grid commitments as a form of regulatory risk mitigation that strengthens the credit profile.

The developers who are navigating the regulatory environment described in this series most effectively are those who approach grid responsibility as a strategic asset rather than a compliance burden. The voluntary commitments described above cost money and create operational obligations. But they also build the kind of relationships with regulators, utilities, and communities that produce better outcomes across the full range of regulatory interactions that a large-scale energy project entails over its operating life.

Series Synthesis

Across the seven alerts in this series, several principal themes have emerged from the regulatory frameworks surveyed:

The cost-internalization consensus appears to be the new baseline. Whether through FERC orders, state large-load tariffs, the Ratepayer Protection Pledge, or the 13-governor Statement of Principles (each described in Alerts 1 and 2), the expectation that data center load will fund its own generation, transmission, and grid services is becoming the regulatory and political baseline across the country. Developers should generally expect to internalize the full cost of service in their project economics. The structuring question is not whether to bear these costs but how to allocate them efficiently across the project’s contractual architecture while preserving jurisdictional advantages.

Structure determines jurisdiction. The physical configuration of the generation-to-load connection and the ownership architecture of the parties are the highest-leverage variables in the regulatory analysis. A single-entity islanded facility avoids FERC jurisdiction entirely. A third-party power purchase agreement with grid interconnection in an organized market triggers the full co-location framework. Every other configuration falls between these poles. The structuring choices described in Alert 3, and the jurisdictional advantages they produce or forfeit, are the foundation on which everything else rests.

The regulatory hierarchy among jurisdictions has become clearer. ERCOT offers the fastest and least regulated path, with structural FERC avoidance and the established Private Use Network framework, though Texas Senate Bill 6 and the batch study transition add real compliance requirements (Alert 4). Wyoming offers minimalist state regulation and extraordinary resource endowments, but the SPP expansion introduces a new federal layer for grid-connected projects (Alert 6). Utah offers a pragmatic regulatory environment with Utah Senate Bill 132’s statutory safe harbor, municipal utility alternatives, and flexible utility partnerships (Alert 6). Colorado demands renewable alignment and imposes the most complex regulatory framework in this series, but offers strong renewable resources and a utility in Xcel Energy that is actively building the framework for large-load service (Alert 5). PJM and SPP offer the most structured co-location frameworks with the highest associated costs, but provide regulatory certainty and access to organized wholesale markets (Alert 1). The optimal jurisdiction depends on the project’s specific characteristics, and the collected edition of this series is designed to provide the analytical framework for that decision in the surveyed jurisdictions. Water availability adds a further dimension to the jurisdictional comparison that this series has addressed in the context of individual states but that warrants cross-jurisdictional analysis in its own right, particularly for projects involving thermal generation in the arid West.

The window for structuring around undefined rules is narrowing. In January 2026, the PJM co-location framework was a single order with compliance filings pending. The SPP HILL framework had just been accepted. The DOE Rulemaking Proposal was in the comment period. The Ratepayer Protection Pledge had not yet been issued. PJM’s compliance filings are now docketed with a July 31, 2026 effective date. SPP’s framework is operational. FERC has announced that it expects to act on the DOE Rulemaking Proposal by the end of June 2026. State large-load tariffs are proliferating across the country. Arrangements that depend on the absence of clear rules, that exploit undefined tariff provisions or unresolved jurisdictional questions, are increasingly exposed. The framework is being built now. The developers who participate in building it will have a hand in shaping it. Those who wait may find themselves shaped by the outcomes.

Engagement appears more productive than avoidance. Regulators, utilities, and communities are more likely to accommodate developers whose proposals demonstrate that BTM generation and grid responsibility are compatible than those who optimize for regulatory exit. The constructive engagement principle applies across every jurisdiction in this series, from ERCOT (where proactive participation in Public Utility Commission of Texas (PUCT) proceedings and voluntary grid support build goodwill) to Colorado (where alignment with the state’s clean energy framework may determine whether the regulatory process supports or impedes the project) to Wyoming (where engagement with the incumbent utility may reduce the risk of adversarial proceedings even in a permissive regulatory environment) to Utah (where early engagement with Rocky Mountain Power or municipal utilities on special contract terms and integrated resource planning can position the developer as a constructive partner rather than an unanticipated load).

The regulatory landscape will continue to evolve. The DOE Rulemaking Proposal, the PJM compliance filings, the Xcel Energy large-load tariff proceeding, the pending Wyoming Public Service Commission declaratory proceeding, the ERCOT batch study transition, Rocky Mountain Power’s EDAM entry, NERC’s Large Loads Task Force, and the competing legislative proposals at the federal and state levels will each produce developments in the coming months that refine the frameworks described in this series. Developers, sponsors, and lenders with active or planned projects should monitor these proceedings closely and evaluate how potential outcomes could affect existing or contemplated arrangements.

A Note on What Comes Next

The data center industry’s demand for electricity is not a temporary phenomenon. Artificial intelligence workloads are growing, cloud computing is expanding, and the digitization of the economy continues to accelerate. The regulatory frameworks described in this series are early attempts to accommodate that demand within structures designed for a different era. The FPA’s 1935 jurisdictional division, state utility regulatory models developed for vertically integrated monopolies, and RTO market designs built around traditional generation and load patterns are all being stretched to accommodate power arrangements that their architects did not anticipate.

The regulatory structures that ultimately emerge will reflect the balance that regulators, legislators, utilities, and developers collectively strike between competing objectives: speed versus deliberation, cost optimization versus cost sharing, federal uniformity versus state flexibility, innovation versus reliability. The developers and sponsors who approach that process with sophistication, humility, and a genuine commitment to constructive engagement are the ones most likely to build projects that succeed not only commercially but also in the broader sense of contributing to a grid that serves everyone.

The collected edition of this series, incorporating all seven alerts with updated analysis reflecting developments since Alert 1 was published, is available from the author upon request.

This is the seventh and final alert in a series examining the regulatory frameworks applicable to data center power across multiple jurisdictions.

This alert is intended to provide a general overview of the grid responsibility, sustainability, and policy considerations applicable to data center 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.

On April 30, 2026, the Colorado Court of Appeals issued its opinion in Carroll Partners LLC v. Board of Commissioners of Pitkin County, 2026 COA 34, affirming summary judgment in favor of Pitkin County on a challenge to an employee housing impact fee of nearly one million dollars assessed for the demolition and replacement of a single-family residence. The decision addresses the scope of a local government’s authority to impose impact fees on new development under the Local Government Land Use Control Enabling Act of 1974 (the “Act”). In a case of first impression, the court concluded that the Act authorizes a local government to impose impact fees as a condition of issuing a development permit, and that such authority is not limited to the development of raw land or projects that substantially change the use of previously developed property.

Background

Under the Act, local governments are authorized to regulate the use of land within their jurisdictions based on “the impact of the use on the community or surrounding areas.” §§ 29-20-101, -104(1)(g)(I), C.R.S. (2025). One mechanism for exercising this authority is the impact fee statute, section 29-20-104.5(1), which permits a local government to “impose an impact fee or other similar development charge to fund expenditures by such local government on capital facilities needed to serve new development” as a condition of issuing a development permit. Governments that choose to assess such fees must do so pursuant to a legislatively adopted schedule that is generally applicable to a broad class of property and intended to defray the projected impacts of proposed development on capital facilities. § 29-20-104.5(1)(a)–(c).

Pitkin County imposes an employee housing impact fee (“EHIF”) on certain construction projects under its land use code. The EHIF is designed to generate funds to offset demand for employee housing caused by employment generated from new development, and the county uses the fees it collects to create additional dwelling units to be added to its employee housing inventory.

Carroll Partners LLC (“Carroll”) purchased a 6.5-acre lot in the Starwood Seven subdivision on which a 14,807-square-foot house, built in 1983, was located. Carroll applied for a development permit to demolish the existing structure and replace it with a new single-family residence generally within the same footprint. Pitkin County conditionally approved the application as a “replacement” project and informed Carroll that it would be required to pay an EHIF of $948,544.18 before a building permit could be issued. Carroll’s request for an exemption was denied, and Carroll appealed to the district court, which granted summary judgment in favor of Pitkin County.

The Court’s Analysis

On appeal, Carroll raised two primary arguments: (1) that Pitkin County exceeded its statutory authority under the impact fee statute, and (2) that the imposition of the EHIF violated Carroll’s substantive due process rights.

Carroll argued that the impact fee statute only authorizes local governments to assess impact fees on “new development,” which Carroll argued should be construed narrowly as the development “of a raw parcel of land for a specific and/or different use.” Under Carroll’s reading, because its project involved the demolition and reconstruction of an existing house without a material change in use or expected occupancy, the EHIF could not be imposed because the project did not involve “growth” and would not appreciably increase the county’s infrastructure needs.

The court rejected this interpretation, agreeing with Pitkin County that a local government’s authority to impose impact fees is linked to the issuance of a “development permit,” such that if a project is extensive enough to require such a permit, the local government may charge an impact fee as a condition of its issuance. See § 29-20-103(1) (defining “development permit”). The court found that the county’s interpretation properly accounted for all the words and phrases in the impact fee statute, whereas Carroll’s interpretation would render the statute’s reference to development permits superfluous. The court further concluded that the phrase “new development” encompasses more than the development of raw land, holding that nothing in the Act suggests that a reconstruction project extensive enough to require a development permit falls outside the scope of a local government’s authority to impose an impact fee.

Regarding Carroll’s substantive due process challenge, the court applied rational basis review and found that Pitkin County’s assessment of the EHIF easily satisfied the test. The court observed that “employee generation” occurs whether construction takes place on raw land or on land with an existing residence, and that Pitkin County’s formula, which assesses a fee based on projected construction impacts and use and maintenance impacts, is reasonably tailored to quantify those impacts.

Significance

This decision significantly broadens the scope of local government impact fee authority in Colorado. Property owners and developers should be aware that impact fees may lawfully be imposed not only on greenfield development but also on demolition-and-replacement projects, and potentially any construction project substantial enough to require a development permit. The decision also reinforces that employee housing impact fees, which address the workforce housing demands generated by construction activity itself, bear a rational relationship to legitimate governmental interests and will survive constitutional challenge under rational basis review. In high-cost markets like Pitkin County, where such fees can approach $1 million for a single-family residence, the financial implications for developers and property owners undertaking replacement construction are substantial.

The decision was authored by Judge Grove with Judges Yun and Taubman concurring.

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For questions about this legal alert, please contact a member of the Davis Graham Appellate Group.

On April 27, 2026, the United States Court of Appeals for the Tenth Circuit reversed the district court in Devon Energy Production Co., L.P. v. United States Department of the Interior, No. 24-6132. A majority of the panel held that the Office of Natural Resources Revenue (“ONRR”) acted arbitrarily and capriciously when it disallowed certain gas treatment deductions without considering a prior settlement agreement between Devon Energy Production Co., L.P. (“Devon”) and the federal government. The panel held that the settlement agreement constituted “an important legal and factual part of the problem” because it legally controlled over otherwise applicable regulations and factually affected over 80% of the disputed royalties.

Background

Devon held federal leases to produce natural gas from two units in New Mexico. The gas formations beneath these units presented distinct treatment challenges. For example, coalbed methane from one gas formation typically contains excessive carbon dioxide that must be removed before the gas is marketable, a cost that is generally non-deductible from royalty calculations under federal regulations. The companies that treated Devon’s gas bundled deductible charges (such as transportation) with non-deductible charges (such as carbon dioxide removal), making it difficult for Devon to segregate costs.

One of Devon’s predecessors encountered this same bundled-cost problem during an audit in the 1990s. That entity entered into a settlement agreement with the government, which established specific rates for transportation and treatment of coalbed gas. When state officials audited Devon’s production for the 2004–2008 period and disallowed approximately $2.84 million in deductions, Devon responded that it had calculated its treatment costs using the formula set out in that settlement agreement.

The ONRR’s decision, which omitted any mention of the settlement agreement, ordered Devon to either separate its bundled charges or identify the deductible costs through another method. Devon sought judicial review and the district court affirmed, reasoning that the settlement agreement would not have covered all of the disputed royalties.

The Tenth Circuit’s Analysis

Applying de novo review, a Tenth Circuit panel reversed, holding that an agency acts arbitrarily and capriciously when it “fail[s] to consider an important aspect of the problem,” and that the settlement agreement was precisely such an aspect. The panel identified two dimensions of significance: legally, the settlement agreement “controlled over regulations that would otherwise conflict” pursuant to 30 C.F.R. § 206.150(b); and factually, the agreement bore on a substantial portion of the disputed royalties.

The government advanced three arguments, each of which the panel rejected. First, it contended that the settlement agreement involved a different Devon entity than the party in this case. The panel found the administrative record insufficient to resolve whether a merger had united the two entities and declined to affirm on a ground that the agency never considered.

Second, the government argued that even if a merger occurred, the surviving entity might not have assumed the settlement agreement. Again, the incomplete record precluded reliance on this argument.

Third, the government argued the settlement agreement’s treatment rate expired before the audit period. The panel engaged in a detailed textual analysis of the settlement agreement. The agreement’s body provided that rates “for transporting coalbed gas” would continue until the expiration of Devon’s underlying contract. Meanwhile, Exhibit B to the settlement agreement separately identified a treatment rate of 7.78 cents per thousand cubic feet. The panel found the agreement ambiguous as to whether the expiration provision encompassed only transportation rates or also the treatment rate. Because the government itself had previously characterized the 7.78-cent figure as “the agreed cost of CO2 removal under the . . . Settlement Agreement,” the panel concluded that all parties understood the agreement to have established a treatment rate—leaving the sole question as when that rate terminated. Given this ambiguity, the panel held the expiration issue was neither “clear” nor “indisputable,” and thus could not sustain an alternative affirmance.

The panel ultimately reversed and remanded to the district court with instructions to determine the appropriate remedy under a two-factor test which considers (1) the seriousness of the agency’s deficiencies and (2) the disruptive consequences of an interim change.

Judge Tymkovich dissented, finding that the settlement agreement’s treatment rates had indisputably expired before the audit period. In his view, the agreement’s rate-setting provision and its expiration clause were inextricably intertwined: whatever rates the agreement fixed were subject to defined termination triggers that had already occurred. Judge Tymkovich would have affirmed the agency’s decision on harmless error grounds.

Significance

The panel’s holding carries two significant implications. First, the decision reinforces that a prior settlement agreement between a lessee and the federal government can supersede otherwise applicable regulatory provisions governing royalty deductions. Under 30 C.F.R. § 206.150(b) (2004), which now appears at 30 C.F.R. § 1206.140(c), such agreements control over conflicting regulations. In addition, and although this dispute involved New Mexico leases and the specific deductions concerned New Mexico gas production, the panel’s reasoning rests squarely on federal regulatory law, suggesting the holding would extend to federal leases throughout the circuit.

Second, the decision underscores the principle that agencies must grapple with all material aspects of a regulated party’s objections during the administrative process. Where a lessee points to a settlement agreement as the basis for its deduction methodology, the agency cannot simply ignore it and demand alternative substantiation. Failure to engage with such arguments renders the agency’s order vulnerable to reversal as arbitrary and capricious. Lessees with existing settlement agreements governing royalty calculations should ensure those agreements are prominently invoked during any audit or administrative proceeding.

The case is Devon Energy Production Co., L.P. v. United States Department of the Interior, No. 24-6132, __ F.4th __ (10th Cir. 2026). The decision was authored by Judge Bacharach, joined by Judge Hartz, with Judge Tymkovich dissenting.

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For questions about this legal alert, please contact a member of the Davis Graham Appellate Group.

Wyoming and Utah occupy a distinctive position in the regulatory landscape described throughout this series. Both offer regulatory environments meaningfully more permissive than Colorado’s climate-driven framework or the Federal Energy Regulatory Commission (FERC) jurisdictional organized markets for behind-the-meter generation and co-located load arrangements serving data centers (collectively, BTM), but through different mechanisms and with different constraints. Wyoming’s minimalist approach offers speed, simplicity, and extraordinary natural resource endowments. Utah’s pragmatic regulation offers flexibility, partnership opportunities, and a statutory framework purpose-built for large-load service. Both states are attracting data center capital at a pace that would have been difficult to anticipate even two years ago.

These states also share a characteristic that distinguishes them from Texas: they are not structurally isolated from FERC in the way that the Electric Reliability Council of Texas (ERCOT) is. Wyoming’s transmission system includes FERC-jurisdictional facilities operated by PacifiCorp (Rocky Mountain Power), the Western Area Power Administration (WAPA), and, as of April 1, 2026, the Southwest Power Pool (SPP). Utah’s dominant utility, Rocky Mountain Power, operates under FERC wholesale jurisdiction and is entering the California Independent System Operator’s (CAISO) Extended Day-Ahead Market (EDAM). The federal overlay described in Alerts 1 through 3 applies in both states whenever a BTM generation arrangement touches the grid. The state-level advantages described in this alert are most fully realized when the project can be structured to avoid that federal overlay, which in practice means an islanded or radial configuration with no grid synchronization.

This alert examines the regulatory frameworks in both states, the structural options available to developers, and the practical considerations that determine whether a given project can succeed in these jurisdictions.

Wyoming: The Regulatory Framework

Wyoming represents nearly the opposite regulatory philosophy from Colorado. The Wyoming Public Service Commission (WPSC) exercises utility regulation under a statutory framework that is deliberately narrow in scope, reflecting the state’s longstanding commitment to limited government intervention in commercial energy arrangements.

The threshold question for any BTM generation project in Wyoming is whether the arrangement causes the generator to become a “public utility” subject to WPSC regulation. Wyoming law defines a public utility as any person owning or operating equipment to provide utility service “to or for the public.” That limiting phrase is the key to Wyoming’s regulatory environment for data center power, because it excludes from utility regulation any arrangement that serves a defined, limited class of customers rather than the general public.

Wyoming case law has interpreted this limitation consistently and favorably for dedicated industrial generation. The established precedent provides that sales to a single purchaser, or to a small number of identified industrial customers, do not constitute service “to or for the public” and therefore do not render the seller a public utility. The analysis focuses on several factors: the number and character of the customers served, whether the entity holds itself out as available to serve the general public, and whether the operation is clothed with a public interest. A dedicated generation facility built to serve one or two data centers, with no public offering of service, should satisfy these criteria.

This framework creates a regulatory environment in which a 300 MW natural gas plant built to serve a single data center customer, with no grid interconnection and no offering of service to the public, would not be subject to WPSC rate regulation, certification requirements, or territorial restrictions. The simplicity of this outcome, relative to the multi-layered regulatory analysis required in PJM Interconnection (PJM), SPP, or even Colorado, is Wyoming’s principal competitive advantage for data center power development.

The WPSC has a pending proceeding that may provide additional clarity on the viability of third-party sales structures in this context. A petition for declaratory order filed in 2025 asks the WPSC to confirm that selling electricity to one or two industrial customers co-located with generation facilities would not cause the seller to become a public utility or violate incumbent utility territorial rights. If granted, the petition would provide significant comfort for developers pursuing third-party sales arrangements. The petition has not yet been acted upon as of this writing, and developers considering Wyoming should monitor the proceedings for developments.

A separate WPSC rulemaking is examining a potential framework for retail sales by non-utility generators. The rulemaking has not produced final rules, and its timeline and scope remain uncertain. Developers should be cautious about structuring projects around anticipated regulatory relief that has not yet materialized, whether in the form of a favorable declaratory ruling or new administrative rules.

The Wyoming legislature’s efforts to facilitate data center development through statutory clarification have likewise not yet produced enacted legislation. During the 2025 interim, the Joint Corporations, Elections and Political Subdivisions Committee’s working group discussed exemptions for third-party generation serving large loads, and draft language was circulated that included a potential 100 MW threshold. However, the working group did not reach consensus, no bill was introduced, and the 2026 budget session produced no data-center-specific legislation. Wyoming’s existing statutory framework is favorable, but developers should rely on the law as it exists rather than on anticipated legislative action.

The Landlord-Tenant Structure in Wyoming

Wyoming’s statutory framework includes an exemption for the generation and distribution of electricity “for the use of tenants of a producer.” This landlord-tenant exemption provides a structural option that may offer advantages over both self-supply and third-party sales arrangements, particularly for sponsors who wish to retain ownership and tax benefits associated with the generation assets.

Under this structure, the generation owner holds both the generation facility and the real property on which the data center operates. The data center operator leases the site from the generation owner and receives power as a bundled component of the lease. If the electricity is delivered as part of the lease arrangement, without separate metering or billing as a standalone commodity, the landlord should not be classified as a public utility under Wyoming law.

Wyoming courts have addressed the boundary between landlord-provided utility service and regulated retail sales. The controlling distinction turns on billing structure: when utility costs are included in rent and passed through as part of the lease, the landlord is not a utility; when the landlord separately meters and bills tenants for the utility commodity, the landlord crosses into regulated territory. This distinction has been applied consistently by both the courts and the WPSC in administrative proceedings.

The landlord-tenant structure has meaningful advantages for sponsors. The generation owner retains outright ownership of both the generation assets and the land, preserving depreciation, bonus depreciation, and eligibility for energy tax credits (including credits under Section 45Y and Section 48E of the Inflation Reduction Act of 2022 (IRA), where the generation technology qualifies). The data center operator holds a lease interest in the real property, not an ownership or leasehold interest in the generation assets, which simplifies the tenant’s balance sheet treatment and avoids the complexities of generation asset lease classification. The lease can potentially be structured with a fixed capacity component (reflecting the capital cost of dedicated generation) and a variable operating cost pass-through (covering fuel and maintenance), provided the overall arrangement is embedded in a bona fide real property lease with meaningful non-electricity terms.

The principal risk is that the WPSC could look through the form of the arrangement and conclude that electricity delivery is the dominant economic purpose, effectively treating the lease as a disguised retail electricity sale. That risk appears manageable with appropriate structuring. The lease should include meaningful non-electricity terms (site access, infrastructure, maintenance obligations, shared facilities). The rent structure should avoid a pure per-kWh volumetric charge that functions as an electricity rate. Lease provisions should be consistent with commercial real property practice, including term, renewal, and default provisions that read as a real property lease rather than a power purchase agreement. And the arrangement should not involve separate metering or billing of electricity as a standalone commodity, which is the line that Wyoming courts and the WPSC have consistently identified as the boundary of the exemption.

From a FERC perspective, the landlord-tenant structure is most effective when combined with an islanded configuration, as described in Alert 3. If there is no sale for resale (because the transaction is a lease service rather than an electricity sale) and no transmission in interstate commerce (because the facility is islanded from the grid), both federal jurisdictional triggers are likely avoided.

For lenders evaluating the landlord-tenant structure, the novelty of the arrangement in the data center context is a factor that may require additional diligence. The legal framework is established (the relevant Wyoming statutory provisions, court decisions, and WPSC administrative precedent are consistent and well-developed), but the specific application to a large-scale, single-tenant data center with dedicated generation has not been tested in a contested proceeding. Lenders may wish to obtain legal opinions addressing the structure’s compliance with Wyoming law and, if the project is islanded, its position outside FERC jurisdiction. The regulatory change provisions discussed in Alert 3 (representations regarding regulatory status, renegotiation triggers tied to material changes in the jurisdictional framework) are particularly relevant for landlord-tenant structures, where the risk of reclassification, while manageable, is not zero.

SPP’s Expansion into Wyoming

The regulatory landscape in Wyoming shifted on April 1, 2026, when the western portion of PacifiCorp’s transmission system, including areas in central and eastern Wyoming, came under SPP regional transmission organization (RTO) administration. This development introduces a new federal regulatory overlay in portions of Wyoming that previously operated outside any RTO framework.

The practical effect depends on the project’s physical configuration. The SPP overlay does not eliminate Wyoming’s state-law advantages. Self-supply arrangements, landlord-tenant structures, and third-party sales to limited customers remain exempt from Wyoming utility regulation regardless of RTO jurisdiction, because the WPSC’s “to or for the public” analysis is a state-law question that is independent of federal RTO administration. However, any grid interconnection for backup or surplus sales in SPP territory triggers the federal overlay described in Alert 1, including SPP’s standardized interconnection procedures, FERC Order 2023 requirements, and the High Impact Large Load (HILL) and HILL Generation Assessment (HILLGA) framework (each described in Alert 1).

Developers who can keep the arrangement fully islanded (a radial connection from generation to load with no grid synchronization) should be able to avoid SPP’s procedures entirely, because there is no interconnection to the transmission system and therefore no event that triggers SPP’s jurisdiction. Developers who need grid backup or wish to sell surplus generation into the market would need to navigate both the Wyoming state framework and the SPP federal framework. The phased approach described in Alert 3, beginning operations on an islanded basis while pursuing grid interconnection in parallel, may be particularly relevant in Wyoming given the recent SPP expansion.

The geographic question matters. Not all of Wyoming is within SPP’s footprint. Projects sited in areas served by municipal utilities, rural electric cooperatives, or WAPA facilities outside SPP’s administrative boundaries may avoid RTO-level interconnection requirements, though WAPA’s own FERC-jurisdictional interconnection procedures would still apply. Developers should confirm which transmission provider administers the specific area where the project is sited and evaluate the applicable interconnection procedures accordingly.

Wyoming’s geography often permits islanded configurations. The state’s vast land area, relatively sparse development, and abundant energy resources (natural gas, wind, and coal-to-gas conversion opportunities) make it feasible to site generation and load in close proximity without requiring grid interconnection for reliability. Projects of extraordinary scale are already moving forward. In January 2026, Laramie County commissioners unanimously approved a multi-gigawatt AI data center campus developed by a partnership between a leading AI computing company and a major midstream operator, illustrating both the scale of development that Wyoming can accommodate and the level of capital that is flowing into the state.

Incumbent Utility Considerations in Wyoming

Wyoming’s investor-owned utilities, primarily Rocky Mountain Power and Black Hills Energy, operate under territorial service obligations. Territorial exclusivity could theoretically be invoked to challenge BTM generation arrangements that serve load within the utility’s certificated territory. However, Wyoming law contains several important limitations on this concern.

Self-generation is expressly permitted regardless of territorial assignments. A utility’s franchise does not create a mandatory purchase obligation, and Wyoming law explicitly excludes self-generators from the utility regulatory framework. The landlord-tenant exemption appears in the same statutory subsection as the self-generation exclusion, suggesting that the legislature intended both to operate as exceptions to territorial exclusivity. And the WPSC’s jurisdiction over certificated territory disputes is limited to entities classified as public utilities under the statutory definition; if the generator falls within one of the statutory exemptions, the territorial exclusivity framework should not apply.

That said, incumbent utilities have an economic interest in serving large loads and may challenge arrangements that they view as encroaching on their service territory or reducing their revenue base. A utility complaint before the WPSC, even if ultimately unsuccessful on the merits, takes time and money to litigate and can delay project timelines. Developers should evaluate the enforcement posture of the incumbent utility in their target area and consider whether proactive engagement (including negotiated standby service arrangements and cost-share commitments for shared infrastructure) may reduce the risk of an adversarial proceeding. The constructive engagement principle described in Alerts 2 and 5 applies in Wyoming as well, even though the regulatory environment is more permissive.

Utah: Pragmatic Regulation

Utah’s regulatory framework occupies a middle ground between Wyoming’s minimalism and Colorado’s policy-driven approach. The Utah Public Service Commission (Utah PSC) operates under statutory authority to regulate “public utilities” providing service in the state, and its authority is limited to powers expressly granted by the legislature. Utah defines “public utility” to include entities providing electric service “for public use,” a formulation similar to Wyoming’s “to or for the public” but interpreted somewhat more broadly.

The critical distinction for data center developers is that Utah, like Wyoming, draws a line between service to the general public (which triggers utility regulation) and service to defined, limited customers (which may not). Self-generation is permitted. The Utah PSC has approved special contracts outside standard tariffs for large industrial loads, including arrangements involving dedicated generation resources, custom rate structures, unique interconnection terms, and economic development incentives. The Utah PSC’s pragmatic approach makes individually negotiated arrangements viable for large projects that standard tariffs cannot accommodate.

Senate Bill 132: A Statutory Framework for Large-Load Service

In March 2025, Utah Governor Spencer Cox signed Senate Bill 132 (SB 132), establishing a statutory framework for electric service to customers with large electrical loads, defined as a cumulative demand of 100 MW or more at a single point of delivery. SB 132 is significant because it provides a defined statutory safe harbor for large-load service arrangements that might otherwise face uncertainty under the general “public use” standard.

SB 132 authorizes closed private generation systems, in which a generator provides electricity to a defined set of large-load customers without becoming a public utility, and special contracts between utilities and large-load customers that can include bespoke terms for generation, delivery, pricing, and cost allocation. The statute provides a level of regulatory certainty for large-load service arrangements in Utah that exceeds what Wyoming’s case-law framework currently offers, because the framework is statutory rather than dependent on favorable case outcomes or declaratory rulings.

For developers, SB 132 simplifies the regulatory analysis for Utah projects at the 100 MW threshold and above. Rather than arguing from general “public use” principles that a given arrangement falls outside utility regulation (as is necessary in Wyoming), a developer in Utah can point to a specific statutory authorization for the arrangement. This distinction may matter for lenders and sponsors who are more comfortable relying on a statutory safe harbor than on judicial precedent or an administrative declaratory ruling.

Municipal Utility Alternatives

Utah has a significant municipal utility presence that creates an alternative pathway for data center development. Provo, St. George, Murray, Logan, Bountiful, and numerous other communities operate municipal electric systems, and two joint action agencies (the Utah Associated Municipal Power Systems and the Utah Municipal Power Agency) provide wholesale power and shared services.

Municipal utilities offer several advantages for data center developers. They answer to city councils rather than state regulators, enabling faster decision-making and customized service arrangements. They operate on a cost-of-service basis without investor profit margins, potentially offering lower rates. They are not subject to Utah PSC tariff requirements, which means they can negotiate bespoke power arrangements directly with large customers. And many municipal utilities view large loads as beneficial to their systems’ load factors and local economies, creating an economic development orientation that investor-owned utilities may not share to the same degree.

For developers whose siting analysis can accommodate a location in municipal utility territory, the municipal pathway may offer meaningful advantages in terms of speed, flexibility, rate levels, and the ability to negotiate terms that would require Utah PSC approval in Rocky Mountain Power territory. The tradeoff is that municipal utility territories are generally smaller and may not offer the same land availability, fiber connectivity, or water resources as locations in investor-owned utility territory or outside any utility territory.

Rocky Mountain Power and Western Market Evolution

Rocky Mountain Power, the dominant investor-owned utility in Utah, is entering CAISO’s EDAM with participation expected to begin in May 2026. EDAM will deepen wholesale market access across Rocky Mountain Power’s six-state service territory (Utah, Wyoming, Oregon, Washington, Idaho, and California) by adding a day-ahead energy market optimization to the existing real-time Western Energy Imbalance Market in which Rocky Mountain Power has participated since 2014.

For BTM generation in Utah, EDAM creates both opportunities and potential jurisdictional complications. On the opportunity side, deeper wholesale market access means that surplus generation from BTM facilities (to the extent the developer structures the arrangement to permit grid sales) can be monetized at day-ahead market prices rather than only through real-time imbalance transactions or bilateral contracts. On the jurisdictional side, participation in EDAM may expand the FERC jurisdictional touchpoints for arrangements that interact with the wholesale market. The Talen Order’s concerns (described in Alert 1) about cost allocation and resource adequacy impacts apply in Utah through Rocky Mountain Power’s FERC-jurisdictional transmission system, and developers should evaluate whether their arrangements implicate wholesale market participation and plan accordingly.

The FERC jurisdictional analysis for Utah projects is similar to the analysis for Wyoming projects described above and in Alert 3: an islanded facility with no grid interconnection avoids FERC jurisdiction entirely, while any grid connection triggers the federal overlay. The key difference is that Utah’s transmission system is currently administered by Rocky Mountain Power under FERC-approved open access transmission tariff (OATT) provisions (not by an RTO), which means the interconnection process follows Rocky Mountain Power’s OATT rather than an RTO’s standardized procedures. This may change as Western market integration evolves, and developers with long-dated projects should monitor whether Rocky Mountain Power’s transmission ultimately comes under RTO administration.

Integrated Resource Planning and Data Center Load

Rocky Mountain Power files an integrated resource plan (IRP) on a biennial schedule covering its six-state service territory, subject to review by the utility commissions in each state. The IRP process has direct implications for data center power availability in Utah.

Large data center loads should be represented in the IRP load forecast to ensure adequate resource planning. Loads that are anticipated in the IRP are more likely to be served on the developer’s timeline, because the utility will have planned and procured generation to meet them. Unanticipated load can create resource adequacy challenges and delay service. Conversely, if data centers increasingly pursue BTM generation, the utility’s load forecast must adjust downward to avoid overbuilding.

Rocky Mountain Power’s IRP includes a near-term action plan identifying specific resources for procurement. Data centers seeking utility-backed power arrangements should engage the IRP process to ensure their load is reflected in the planning horizon and that the utility’s proposed resource portfolio can accommodate the incremental demand. The IRP process also reveals the utility’s resource preferences and timing, which can inform a developer’s decision about whether to pursue utility service, BTM generation, or a hybrid approach.

The Investment Thesis for Wyoming and Utah

For sponsors evaluating Wyoming and Utah, the investment thesis is fundamentally different from the Colorado thesis described in Alert 5 and the Texas thesis described in Alert 4.

Wyoming offers the lowest regulatory burden of any state in this series. The state-level framework imposes minimal requirements on dedicated generation serving limited customers. The resource base (natural gas, wind, large-scale solar potential, and retiring coal plant sites with existing infrastructure) is abundant. Coal plant conversion and small modular reactor (SMR) deployment opportunities are addressed in Alert 7. Land is available and inexpensive. The political environment is favorable to energy development. The risk factors are the novelty of the legal framework as applied to data center-scale projects (the relevant legal principles are established but have not been tested at this scale in a contested proceeding), the SPP expansion (which adds a federal overlay for grid-connected projects in portions of the state), and the infrastructure constraints (fiber, water, workforce) that come with developing in a rural state in the West. For sponsors willing to accept the novelty risk and invest in infrastructure, Wyoming may offer the best risk-adjusted returns of any jurisdiction in this series for large-scale, islanded BTM generation.

Utah offers a more structured but still favorable environment. SB 132 provides a statutory safe harbor for large-load arrangements at the 100 MW threshold and above. The municipal utility alternative provides a flexible pathway that can move faster than investor-owned utility service. Rocky Mountain Power’s pragmatic approach to special contracts and the Utah PSC’s willingness to approve bespoke arrangements for large industrial loads create a regulatory environment that, while more involved than Wyoming’s, is substantially less burdensome than Colorado’s. The state’s proximity to fiber and transportation infrastructure (particularly along the Wasatch Front), its growing technology sector, and its relatively affordable cost of living make it an attractive location for data center development from a workforce and operational perspective. The risk factors are Rocky Mountain Power’s evolving market participation (including EDAM entry, which could expand FERC jurisdictional touchpoints), the absence of ERCOT-style structural FERC avoidance, and the fact that the resource base, while strong in solar and natural gas, is not as diverse as Texas’s.

For lenders, Wyoming and Utah projects present credit profiles that differ from both the ERCOT model (described in Alert 4) and the Colorado model (described in Alert 5). Wyoming’s regulatory simplicity reduces the compliance diligence burden, but the novelty of the landlord-tenant and third-party sales structures at data center scale may require more extensive legal opinions and regulatory representations than a Private Use Network structure in ERCOT. Utah’s SB 132 framework provides a stronger statutory foundation, which may simplify the regulatory risk analysis. In both states, the choice between islanded and grid-connected configurations has a significant effect on the credit profile: islanded projects avoid federal regulatory risk but require overbuilding and lack grid backup, while grid-connected projects introduce federal regulatory complexity but offer reliability advantages and surplus sales potential.

Practical Considerations

Developers evaluating Wyoming and Utah should consider several practical factors alongside the regulatory analysis.

Water availability is a threshold issue for any generation project involving thermal cooling. Natural gas generation requires water for cooling, emissions controls, and plant operations. Solar and wind generation require minimal water, but battery storage manufacturing and data center cooling (even with advanced air-cooling technologies) still involve meaningful water consumption. Wyoming and Utah are both arid states, and water rights are regulated under state appropriation systems that require permits for the beneficial use of public water. Developers should conduct water availability and stress assessments as part of site due diligence and should evaluate whether produced water, recycled water, or dry cooling alternatives may be viable for their specific location.

Fiber connectivity is often cited as a constraint for data center development in rural Wyoming, though the situation is improving with new fiber builds targeting energy development corridors. Utah’s Wasatch Front offers significantly better fiber infrastructure. Developers whose operations require high-bandwidth, low-latency connectivity should evaluate fiber availability as a siting criterion alongside regulatory and resource considerations.

Community engagement matters in both states, even though the regulatory environments are more permissive than Colorado’s. Data center development at the scale now contemplated (measured in gigawatts rather than megawatts) brings economic benefits but also raises questions about water use, visual impact, noise, and the long-term economic effects on rural communities. Developers who invest in community relationships, local hiring, and transparent communication about the project’s impacts may encounter less friction than those who rely solely on the permissive regulatory framework.

The national political environment also bears consideration. The Ratepayer Protection Pledge (described in Alert 2) establishes cost-internalization as the baseline expectation for data center power at the federal level, and state large-load tariff proceedings across the country are moving in the same direction. Wyoming’s permissive framework is unlikely to face the same political pressure in the near term, given the state’s strong orientation toward energy development and limited government. But developers with 20-year investment horizons should recognize that the national consensus on cost-internalization could eventually produce pressure on states that are perceived as allowing large loads to avoid contributing to grid infrastructure, whether through federal legislation, FERC rulemaking, or simply through the political dynamics that attend the next grid emergency.

What to Watch in Wyoming and Utah

WPSC action on the pending petition for declaratory order regarding non-utility status for third-party electricity sales to limited industrial customers: A ruling either way could materially affect the viability analysis for third-party sales structures.

WPSC rulemaking on the framework for retail sales by non-utility generators: If rules are adopted, they could simplify or complicate the existing case-law framework.

SPP interconnection activity in the newly administered portions of Wyoming: Early HILLGA applications and interconnection study results will provide data on how the SPP framework operates in practice in Wyoming.

Rocky Mountain Power EDAM entry (anticipated May 2026): The effective date and the initial operating experience will clarify how EDAM participation affects wholesale market access and FERC jurisdictional exposure for BTM generation in Utah and Wyoming.

Utah PSC proceedings involving large-load service under SB 132: Early applications and Utah PSC decisions will establish how the statutory framework operates in practice.

This is the sixth in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions. The final alert in this series examines the grid’s future, large-load responsibility, the SMR and coal plant conversion pipeline, and the synthesis of themes across all seven installments.

This alert is intended to provide a general overview of the regulatory frameworks for data center power in Wyoming and Utah. 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.

Colorado is the most complex jurisdiction in this series. It is also, for Davis Graham’s clients and for the growing number of developers evaluating the Front Range and eastern plains, one of the most important.

Unlike Texas, which offers structural avoidance of Federal Energy Regulatory Commission (FERC) jurisdiction and an energy-only market, or Wyoming and Utah, which offer comparatively minimalist state regulation, Colorado layers binding climate mandates, environmental justice requirements, utility resource planning obligations, and an active public utilities commission on top of the cost-internalization framework for behind-the-meter generation and co-located load arrangements serving data centers (collectively, BTM) that is becoming the national baseline. That cost-internalization principle, formalized at the federal level through the Ratepayer Protection Pledge (described in Alert 2), has been a feature of Colorado’s regulatory approach for longer than most other jurisdictions.

The result is a regulatory environment that is demanding but not prohibitive. Colorado offers exceptional renewable resources (particularly wind on the eastern plains and solar across much of the state), proximity to major demand centers along the Front Range, a sophisticated and engaged regulatory commission, and a utility in Xcel Energy, Colorado’s dominant investor-owned utility with approximately 1.6 million customers, that is actively working to accommodate large-load growth within the constraints of its climate obligations. For developers willing to align BTM generation with Colorado’s policy framework, the state offers a viable and potentially attractive pathway. For developers pursuing gas-fired BTM generation without a meaningful clean energy component, Colorado is likely the most difficult jurisdiction in this series to navigate.

This alert examines Colorado’s regulatory framework in detail, including the Xcel Energy large-load tariff filing, the climate policy overlay, the environmental justice dimension, and the practical structuring considerations that determine whether a given project can succeed in this state.

The Colorado Public Utilities Commission’s Regulatory Philosophy

The Colorado Public Utilities Commission (CPUC) operates with a fundamentally different philosophy from Wyoming’s minimalist approach or Utah’s pragmatic flexibility. Colorado statute directs the CPUC to ensure that utility service is adequate, just, and reasonable, but recent legislation has transformed the CPUC from a traditional economic regulator into an active agent of energy transition. The CPUC now considers greenhouse gas emissions, renewable energy deployment, environmental justice impacts, and the state’s broader climate goals in virtually every major proceeding, from electric resource plans to rate cases to interconnection applications.

This regulatory philosophy has practical consequences for data center power. A developer seeking CPUC approval for a special contract, a large-load tariff arrangement, or an interconnection that involves fossil-fuel generation should expect the CPUC to evaluate the proposal not only on traditional cost-of-service grounds but also on its consistency with the state’s climate trajectory. The CPUC is not hostile to data center development. To the contrary, the CPUC recognizes that data centers bring jobs, tax revenue, and economic diversification. But the CPUC expects large energy consumers to be part of the state’s clean energy transition, not an exception to it.

For developers and their counsel, this means that Colorado regulatory proceedings are substantively different from those in Texas or Wyoming. The CPUC will ask questions that no Texas regulator would ask: What is the carbon profile of the proposed generation? How does it align with the state’s emissions reduction targets? What are the environmental justice implications of siting the facility in the proposed community? What community benefits has the developer committed to? Developers who prepare for these questions and build their answers into the project design from the outset will navigate the regulatory process more efficiently than those who treat the climate and environmental justice overlay as an afterthought.

Xcel Energy’s Schedule TL and the Large-Load Framework

On April 2, 2026, Xcel Energy’s Colorado subsidiary, Public Service Company of Colorado (Xcel Energy or Xcel), filed Advice No. 2018 – Electric with the CPUC in Proceeding No. 26AL-0137E, proposing a comprehensive framework for serving new large-load customers (the LLT Filing). The LLT Filing followed a November 2025 CPUC order (Decision No. C25-0747) adopting guiding principles for large-load service and directing Xcel to file a detailed proposal by January 31, 2026. Xcel subsequently obtained a variance extending the deadline to April 2, 2026 (Proceeding No. 26V-0048E). Xcel has requested that the proposed tariffs become effective May 3, 2026, though the CPUC proceeding (including stakeholder intervention, public comment hearings, and evidentiary proceedings) will continue through 2026, and the final approved tariff may differ from the filed version.

The LLT Filing includes three primary components.

Schedule Transmission Large Service (Schedule TL) establishes a new transmission-level rate class for customers with 50 MW or more of new or new incremental (expanded) load. The overarching design principle is that large-load customers are responsible for at least the incremental costs associated with serving their load and that such costs are not unreasonably borne by non-large-load customers. Schedule TL creates a new customer class with its own terms, conditions, and cost allocation mechanisms, separate from existing residential, commercial, and industrial rate classes. The LLT Filing states that current classes of service and current customers will not be adversely affected by the proposal, because the new class will bear the incremental costs it causes.

The Transmission Line Extension Policy is updated to reflect the scale and characteristics of large-load interconnections. The revised policy provides for direct assignment of customer-specific interconnection costs through an upfront payment and allocation of shared transmission investments consistent with Schedule TL’s cost allocation framework. As reported in public commentary on the LLT Filing, total upfront study and deposit commitments may reach approximately $600,000 before construction begins, and the customer would be responsible for all new generation, transmission, substation, and interconnection costs attributable to its load.

Schedule Clean Transition Tariff (Schedule CTT) is an optional tariff available to Schedule TL customers. It enables participation in the development of new advanced technology resources through coordinated resource planning processes, while ensuring that costs and risks are not shifted to non-participating customers. Schedule CTT is designed to channel large-load demand toward emerging carbon-free technologies (the LLT Filing identifies geothermal and long-duration energy storage among the targeted technologies) and reflects the CPUC’s interest in aligning data center growth with the state’s clean energy transition.

The LLT Filing contemplates two pathways for serving large-load customers. The first is the standard tariff-based approach under Schedule TL and Schedule CTT, which provides a defined cost structure and regulatory process. The second is a “Speed-to-Market” pathway that maintains Xcel’s core large-load cost allocation and customer protection principles while allowing tailored contractual arrangements subject to CPUC approval. The Speed-to-Market pathway is significant for developers who need to move faster than the standard tariff proceeding may allow or whose projects require bespoke terms that the standardized tariff cannot accommodate. Both pathways share the same foundational principle: the large-load customer bears the incremental cost of service.

The LLT Filing is supported by pre-filed direct testimony of five witnesses addressing rate design, cost allocation, transmission planning, resource planning, and the clean transition framework. The scope and detail of the LLT Filing reflect Xcel’s recognition that large-load service is not a minor tariff adjustment but a structural change in how the utility plans, builds, and recovers costs for a new category of customer demand.

The CPUC must approve the tariffs before they take effect. Consumer advocates, including the Colorado Office of the Utility Consumer Advocate, CoPIRG, and AARP Colorado, have indicated initial support for the framework’s cost-protection principles. The proceeding will include stakeholder intervention, public comment, and evidentiary hearings. Developers considering service in Xcel territory should monitor Proceeding No. 26AL-0137E for intervention deadlines, the scope of stakeholder objections, and any CPUC modifications to the filed tariff.

Several aspects of the LLT Filing deserve particular attention as the proceeding unfolds. The 50 MW threshold for Schedule TL applicability may be contested by stakeholders who believe a lower threshold (such as 20 MW, consistent with the DOE Rulemaking Proposal’s proposed national threshold for large-load interconnection, described in Alert 1) is more appropriate. The cost allocation methodology, specifically how shared transmission investments are allocated between large-load customers and the existing customer base, is likely to be a contested issue. The scope and terms of the Speed-to-Market pathway, including what contractual flexibility the CPUC is willing to permit and what customer protection conditions it will impose, will be important for developers whose timelines cannot accommodate the standard tariff proceeding. And Schedule CTT’s eligibility criteria and pricing structure will determine whether it provides a meaningful incentive for developers to invest in emerging clean energy technologies or functions primarily as a policy signal.

The Generation Cap and Its Implications

In February 2026, the CPUC approved up to 4,100 MW of new generation for Xcel Energy, down dramatically from the approximately 14,000 MW that Xcel had requested in its electric resource plan (ERP). Xcel’s own LLT Filing acknowledges that the long-term effect of Schedule TL on Xcel’s rates and revenues cannot be determined at this time, and that revenue impacts will become known only as customers enroll and incremental costs are identified, underscoring the forecasting uncertainty that the generation cap was designed to address. The CPUC expressed concern that Xcel might overbuild generation capacity given the uncertainty surrounding data center demand, and it chose a more conservative approach that could be expanded if demand materializes with greater certainty.

This cap has direct implications for data center developers considering grid-supplied power in Xcel’s Colorado territory. With Xcel projecting that large-load customers will account for approximately two-thirds of its new electricity demand, and with the CPUC having approved less than a third of the requested generation capacity, the available grid-supplied power for new large-load customers is constrained. Developers who plan to rely entirely on Xcel for utility-supplied power should understand that the generation capacity to serve their load may not yet be committed to the utility’s resource plan, which could affect the timeline for receiving service. The cap also creates a first-mover dynamic: developers who secure commitments under the LLT framework before the approved generation capacity is fully allocated may be better positioned than those who arrive later in the cycle and must wait for additional generation to be procured and approved.

This constraint may make BTM generation, where the developer controls the generation resource and does not depend on utility procurement timelines, a more attractive pathway for some projects. However, BTM generation in Colorado carries its own regulatory and policy considerations, described below, that do not apply in the same way in Texas or Wyoming.

For sponsors and lenders evaluating Colorado projects, the generation cap introduces a form of regulatory supply risk that is distinct from the FERC jurisdictional risks described in earlier alerts. A developer planning to take service under the LLT framework should confirm that Xcel has sufficient generation in its approved resource plan to serve the proposed load, or that the developer is prepared to wait for additional generation to be procured and approved in a future resource plan cycle. The CPUC’s four-year resource planning process creates a defined cadence for these decisions, but the timeline may not align with the developer’s commercial requirements.

Climate Policy Framework

Colorado’s climate mandates are not merely background context or aspirational policy goals. They are binding statutory requirements that shape generation technology selection, utility resource planning, and regulatory proceedings in ways that directly affect BTM generation strategy.

House Bill 19-1261 mandates a 50% reduction in economy-wide greenhouse gas emissions by 2030 and a 90% reduction by 2050, in each case from 2005 levels. These economy-wide targets flow down to the electricity sector through CPUC implementation, and the CPUC has interpreted its mandate to require that utility resource plans achieve roughly 80% carbon reduction from the electricity sector by 2030.

Senate Bill 19-236, codified principally at Colorado Revised Statutes § 40-2-125.5, requires qualifying retail investor-owned utilities to achieve an 80% reduction in carbon dioxide emissions from 2005 levels by 2030, with alignment toward the state’s goal of 100% clean electricity by 2040. Rural electric cooperatives are also subject to renewable energy standards requiring at least 20% generation from eligible renewable sources.

Xcel Energy has committed to at least 80% carbon reduction by 2030 and 100% carbon-free electricity by 2050. Its resource plan contemplates retirement of remaining coal generation by the end of 2030, approximately 6,100 MW of new generation (predominantly renewable), substantial battery storage deployment, and 630 MW of strategically located natural gas resources retained for reliability.

Natural gas BTM generation does not directly violate these mandates. The emissions reduction targets flow through the CPUC to utility resource plans rather than imposing facility-level emissions caps on self-generators. A developer who builds a gas-fired BTM plant is not, strictly speaking, in violation of Colorado law. However, the practical environment for gas-fired BTM generation in Colorado is challenging from several directions.

Corporate sustainability commitments that most major data center operators have adopted may conflict with gas-fired generation. Environmental, social, and governance (ESG) screening by institutional investors may affect the bankability of gas-fired BTM projects in Colorado specifically, even if the same investors would finance identical projects in Texas. The CPUC will evaluate any special contract, interconnection application, or tariff proceeding involving a large load with attention to the load’s generation profile and its consistency with the state’s climate goals. And community opposition to fossil-fuel generation siting, particularly in Front Range communities where air quality is already a concern, can delay or defeat permitting.

For sponsors evaluating the Colorado investment thesis, the climate overlay creates both a constraint and an opportunity. The constraint is obvious: gas-fired BTM generation faces headwinds that do not exist in Texas, Wyoming, or Utah. The opportunity is more nuanced. Developers who bring renewable or hybrid BTM generation that aligns with Colorado’s climate trajectory may find a receptive regulatory environment, community support, and a utility partner in Xcel that is actively seeking clean energy resources. Colorado’s renewable energy standards, its net metering and community solar frameworks, and Schedule CTT all create pathways for BTM generation that meets the state’s climate test. The question for each project is whether the economics of renewable or hybrid BTM generation can compete with gas-fired generation on a total-cost-of-ownership basis, including the regulatory and political costs of misalignment with state policy.

Environmental Justice

Colorado’s climate legislation includes environmental justice provisions that the CPUC takes seriously. The CPUC is required to consider disproportionate impacts on low-income communities and communities of color, to prioritize benefits in disproportionately impacted communities, and to evaluate whether proposed projects would add to the cumulative environmental burden in communities that already bear a disproportionate share of pollution and environmental degradation.

For data center development, the environmental justice framework creates several practical considerations. Siting gas-fired generation in or near communities designated as disproportionately impacted could draw heightened regulatory scrutiny, intervenor opposition, and potential permitting delay. Data centers’ cumulative water and electricity consumption may raise environmental justice concerns in water-stressed areas, particularly along the Front Range, where competition for water resources is intensifying. The CPUC increasingly expects large energy projects to demonstrate community benefits, and developers should anticipate requests for community benefit agreements, local hiring commitments, and environmental mitigation measures as part of the regulatory approval process.

These considerations are not theoretical. A data center project in the Elyria-Swansea neighborhood of Denver has drawn sustained community criticism over air quality impacts, and the project has become a reference point in Colorado’s policy debate about data center siting. Developers who engage with environmental justice concerns proactively, through early community outreach, transparent environmental data, and well-structured community benefit commitments, may experience materially different regulatory outcomes than developers who treat these concerns as an obstacle to be managed at the permitting stage.

For the CPUC’s perspective, the environmental justice framework is not an add-on to the regulatory process; it is an integral component of the CPUC’s statutory mandate. CPUC commissioners and staff evaluate large-load proposals with environmental justice in mind, and a project that fails to address these concerns, or that addresses them only after intervenors have raised them, may face a more difficult path to approval than one that demonstrates genuine engagement from the outset.

Self-Generation and Behind-the-Meter Rights

Despite the climate mandates and regulatory complexity, Colorado maintains relatively robust protections for customer-owned generation that provide a foundation for BTM strategies.

Colorado law expressly provides that retail electric utility customers are entitled to generate, consume, and store electricity on their premises. Self-generation does not violate utility territorial rights. A customer who installs generation at its facility and consumes the output is exercising a statutory right, not encroaching on the utility’s franchise. This protection applies regardless of the generation technology, though the practical and regulatory environment for gas-fired self-generation differs from renewable self-generation in the ways described above.

Net metering is available for customer-owned renewable generation, with minimum system size thresholds of 10 kilowatts for residential and 25 kilowatts for commercial customers and no statutory maximum. Credits are provided at a one-to-one ratio against the customer-generator’s energy consumption. Net metering applies only to “eligible energy resources,” which include solar, wind, and hydroelectric, but not natural gas. This limitation means that net metering is available for renewable BTM generation but not for gas-fired BTM generation, creating an additional economic incentive to align BTM strategies with the state’s renewable energy framework.

Community solar gardens, authorized under Colorado’s Community Solar Gardens Act, allow multiple customers to subscribe to shares in solar facilities and receive credit for their proportional production. The program was designed primarily for residential and small commercial customers, and individual solar garden capacity is capped at 2 MW under current rules, which is orders of magnitude below the power requirements of a typical hyperscale data center. As a result, community solar gardens are unlikely to serve as a meaningful component of a data center’s primary power supply. They could, however, supplement a data center’s renewable energy procurement strategy at the margin by providing credits against grid consumption for the portion of the load served by the utility, particularly where the developer subscribes to multiple gardens as part of a broader renewable energy compliance or voluntary sustainability commitment.

For BTM generation that exceeds net metering limits or uses non-renewable fuel, standby service tariffs apply. Colorado utilities file standby tariffs with the CPUC covering demand charges based on maximum grid draw, reservation fees for backup capacity, and non-bypassable transmission and distribution charges. The CPUC reviews standby rates for cost-basis and reasonableness, ensuring they do not discriminate against customers who engage in self-generation. However, standby costs in Colorado can be material, particularly for large facilities that maintain a grid connection for backup during generation outages or maintenance. These costs should be modeled into project economics from the outset, and developers who believe that a utility’s proposed standby rates are unreasonably high or discriminatory can challenge them before the CPUC.

Utility Certification and Territorial Considerations

Colorado utilities operate under certificates of public convenience and necessity (CPCNs) that grant exclusive service territories. The CPUC may approve special contracts between utilities and large industrial customers outside standard tariffs, which provides a mechanism for bespoke power arrangements.

The self-generation exception described above protects the developer’s right to generate and consume on-site power without CPCN implications. However, third-party BTM generation arrangements, in which a separate entity generates and sells power to the data center, may raise territorial and certification questions similar to those described in the Texas context in Alert 4 (regarding Retail Electric Provider certification) and in the structural analysis in Alert 3 (regarding the sale-for-resale trigger under the Federal Power Act). Whether such an arrangement constitutes retail electric service within the utility’s certificated territory is a fact-specific analysis under Colorado law, and the CPUC has not squarely addressed the question in the data center context. Developers pursuing third-party arrangements should evaluate the territorial implications and consider whether a special contract with the serving utility (rather than a third-party bypass) may be the more pragmatic path.

Municipal utilities in Colorado, including Colorado Springs Utilities and a number of smaller municipal systems, operate outside the CPUC’s jurisdiction and may offer more flexible terms for large-load service. The Colorado Constitution grants municipalities the authority to operate utility systems and grant franchises, and municipal utilities can negotiate service arrangements directly with large customers without CPUC approval. For data center developers whose siting analysis can accommodate a location in municipal utility territory, the municipal pathway may offer advantages in terms of speed, flexibility, and the ability to negotiate bespoke terms. Colorado Springs Utilities, in particular, has been actively pursuing data center load and may represent a competitive alternative to Xcel service territory for developers who do not require a Front Range Denver-area location. Rural electric cooperatives, which serve significant portions of eastern Colorado through member distribution systems, are regulated by the CPUC for some purposes but operate under different rate-setting and resource planning frameworks than investor-owned utilities. Developers evaluating sites in cooperative territory should confirm the applicable tariff structure, any large-load service limitations, and the cooperative’s resource planning obligations before committing to a site.

Transmission Access and Constraints

Colorado’s transmission system faces growing constraints that affect BTM generation strategy. Transmission congestion between renewable-rich eastern Colorado and Front Range load centers limits the ability to deliver renewable energy to where it is consumed. Transmission investment is accelerating, driving rising transmission charges embedded in retail rates. Interconnection queue delays contribute to extended timelines for grid-connected projects.

These constraints create a strategic tension for data center developers. Siting near Front Range demand centers (Denver, Colorado Springs, Boulder) provides proximity to fiber, labor, and commercial infrastructure but subjects the project to transmission congestion, higher grid service costs, and potentially longer interconnection timelines. Siting in generation-rich areas (eastern Colorado’s wind corridor, or locations with strong solar resources) may offer better grid access and lower congestion costs but requires the developer to address fiber connectivity, workforce, and the practical challenges of operating in less developed areas.

BTM generation can partially resolve this tension by reducing the data center’s reliance on the congested transmission system. A hybrid BTM arrangement (solar plus storage plus gas backup) sited in an area with strong renewable resources can serve the data center’s load directly, with grid service limited to backup and supplemental power. This approach reduces the transmission charges embedded in the utility bill, avoids the interconnection queue for the BTM generation component, and aligns with Colorado’s renewable energy framework.

For project finance teams, Colorado’s transmission constraints represent a form of infrastructure risk. Projects that depend on utility-supplied power may face rising transmission charges over the project’s life as Colorado invests in transmission upgrades to accommodate its renewable energy transition. The CPUC has projected that average residential electricity rates could increase by as much as 55% by 2029 compared to 2024 levels, driven in part by renewable energy transition costs and infrastructure investment. BTM generation provides a partial hedge for data center developers against this rate trajectory, though the standby and backup service charges that apply to grid-connected BTM facilities are themselves tied to the utility’s cost of maintaining transmission and distribution infrastructure. For sponsors modeling project economics over a 20-year horizon, the rate trajectory analysis may favor BTM generation structures that reduce grid dependence, particularly where the BTM generation resource is renewable and aligns with Colorado’s policy framework.

Electric Resource Planning and Data Center Load

Colorado law requires regulated utilities to file electric resource plans (ERPs) every four years for CPUC review and approval. The ERP process has direct implications for data center power availability and planning.

Utility ERPs must forecast load growth and propose generation resources to meet projected demand. Large data center loads, which can represent 200 to 500 MW increments and may appear or disappear on timelines shorter than the ERP cycle, create significant forecasting uncertainty. The CPUC’s decision to approve only 4,100 MW of the 14,000 MW Xcel requested reflects this concern: the CPUC was unwilling to commit ratepayer capital to generation that might not be needed if data center demand does not materialize as projected.

Data center developers planning to take utility-supplied power should engage the ERP process proactively. Large loads that are represented in the utility’s load forecast are more likely to be served on the developer’s timeline, because the utility will have planned and procured generation to meet them. Loads that are not anticipated in the ERP may face delays while the utility procures additional resources, a process that is subject to the CPUC’s approval and can take years.

Conversely, if data centers increasingly pursue BTM generation, utility load forecasts must adjust downward. Overestimating grid-connected load leads to excess generation procurement, higher rates for remaining customers, and potential stranded cost disputes. The CPUC is aware of this dynamic and is likely to scrutinize any ERP filing that relies heavily on anticipated data center load without firm commitments.

Optimal Structures for Colorado

Colorado’s regulatory framework may reward developers who align with the state’s clean energy trajectory and complicate the path for those who do not. Several structural approaches appear viable given the current regulatory environment.

A utility partnership on renewables, structured as a special contract with Xcel for dedicated renewable generation subject to the LLT Filing’s commercial terms and CPUC approval, provides regulatory certainty and sustainability alignment. The developer relies on Xcel to procure and deliver clean energy, pays for the generation and infrastructure through the LLT framework, and benefits from the utility’s expertise in managing renewable intermittency and grid integration. The tradeoff is limited developer control over the generation resource and dependence on the utility’s procurement timeline and cost structure.

A hybrid BTM system combining solar generation, battery storage, and natural gas backup may offer the best balance of Colorado’s competing considerations. Solar and storage handle daytime baseload and provide the renewable profile that the regulatory environment rewards. Battery storage firms the solar resource, provides grid services revenue potential, and addresses intermittency. Natural gas backup covers extended weather events, nighttime demand, and unplanned outages, providing the reliability that data center operations require. This structure aligns with the state’s renewable energy framework while acknowledging the practical reliability constraints of renewable-only generation at scale. The gas component should be sized as backup rather than baseload, both for operational reasons and to reduce the regulatory and political exposure associated with gas-fired generation in Colorado. New-build renewable and storage generation may also be eligible for credits under Section 45Y or Section 48E of the Inflation Reduction Act of 2022 (IRA), and projects sited in qualifying census tracts (including portions of eastern Colorado’s wind corridor and former coal communities) may qualify for the energy community bonus credit, which can materially improve project economics.

A wind PPA with grid backup leverages eastern Colorado’s exceptional wind resources through a dedicated generation contract, with Xcel grid service for reliability and supplemental power. This approach provides renewable procurement at scale, aligns with the state’s renewable energy standards, and may qualify for favorable treatment under Schedule CTT. The grid backup component would be subject to the LLT framework, including the upfront deposits, study costs, and developer-funded infrastructure requirements.

Each of these structures requires engagement with the CPUC’s regulatory process. Proactive engagement, transparent environmental data, community benefit commitments, and demonstrated alignment with the state’s resource planning priorities can make a meaningful difference in how the regulatory process unfolds. Developers who bring renewable or clean energy proposals and who demonstrate community engagement may find the CPUC to be a constructive partner in facilitating responsible data center growth. Developers who seek to circumvent the climate framework or who treat regulatory proceedings as obstacles to be overcome may find a less accommodating reception.

The Colorado Investment Thesis

For sponsors evaluating Colorado, the investment thesis is more complex than in Texas, Wyoming, or Utah, but it is not necessarily less attractive.

The regulatory burden is higher. The climate mandates, the LLT Filing’s upfront financial requirements, the ERP process, and the environmental justice framework all impose costs and timelines that do not exist in ERCOT or in the comparatively streamlined regulatory environments in Wyoming and Utah. The generation cap constrains utility-supplied power availability and may force developers toward BTM generation, which carries its own set of regulatory considerations.

But Colorado also offers competitive advantages. The renewable resource base is among the strongest in the country. The Front Range provides access to fiber, labor, water (though increasingly constrained), and commercial infrastructure. The regulatory environment, while demanding, is transparent and predictable: the CPUC’s processes are well-established, intervenor participation is organized, and the rules of engagement are defined. Developers who invest in understanding and working within the framework can achieve outcomes on timelines that are reasonable.

For lenders, Colorado projects present a credit profile that differs from the ERCOT projects described in Alert 4. The regulatory complexity introduces compliance risk that requires more extensive diligence and documentation. Climate mandate exposure (the risk that future tightening of emissions standards could affect generation technology choices or impose additional costs) is a factor that does not arise in Texas. But the LLT framework, once approved, provides a defined cost structure that may actually simplify the revenue analysis: the developer knows what it will pay for generation, transmission, and interconnection, and the take-or-pay structure of the dedicated rate schedule provides revenue certainty for the utility counterparty. That certainty may be attractive to lenders even if the absolute cost level is higher than in ERCOT.

What to Watch in Colorado

CPUC review of Xcel’s LLT Filing (Proceeding No. 26AL-0137E, Advice No. 2018 – Electric): Xcel has requested a May 3, 2026, effective date, but the proceeding will include stakeholder intervention, public comment hearings, and evidentiary hearings that will extend through 2026. The final approved tariff may differ materially from the filed version. Developers considering Xcel territory should monitor intervention deadlines, the scope of contested issues (particularly the 50 MW threshold, cost allocation methodology, and Speed-to-Market pathway terms), and any CPUC modifications to the proposed framework.

Xcel Energy rate case (Proceeding No. 25AL-0494E): Xcel has filed for a $356 million increase in annual revenue, with a CPUC decision expected in Q3 2026 and proposed rate implementation in August 2026. The rate case will affect the economics of grid-supplied power relative to BTM generation.

CPUC resource planning proceedings: The 4,100 MW generation cap and the biennial ERP cycle will determine how much additional generation Xcel can procure and on what timeline. Data center developers should engage these proceedings to ensure their load is reflected in the utility’s planning.

2026 Colorado legislative session: Competing data center bills in the state legislature offer different visions for data center development, with one bill requiring data centers to pay for clean energy generation and another offering sales tax incentives. The legislative outcome could affect project economics and siting decisions.

This is the fifth in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions. The next alert examines Wyoming and Utah, two states at the opposite end of the regulatory spectrum from Colorado, each offering distinct advantages and, in Wyoming’s case, a regulatory framework that has recently become more complex with the expansion of SPP’s footprint.

This alert is intended to provide a general overview of the regulatory framework for data center power in Colorado. 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.

Every federal development described in the first three alerts of this series – the PJM Interconnection (PJM) co-location orders, the Southwest Power Pool (SPP) High Impact Large Load (HILL) framework, the DOE Rulemaking Proposal’s proposed assertion of jurisdiction over large-load interconnections, and the new transmission service requirements and gross demand billing mandates – reinforces the same observation: the structural advantages of the Electric Reliability Council of Texas (ERCOT) for data center behind-the-meter generation and co-located load arrangements (collectively, BTM) have widened with each new federal regulatory action.

Texas is not a regulatory vacuum. Senate Bill 6, the ERCOT batch study transition, weatherization mandates, and multiple active rulemakings before the Public Utility Commission of Texas (PUCT) add genuine compliance complexity. But the starting position, complete avoidance of Federal Energy Regulatory Commission (FERC) jurisdiction over wholesale sales, transmission service, and interconnection, eliminates the entire federal regulatory overlay that defines the cost and timeline for BTM generation in every other organized market in the United States. For developers, sponsors, and lenders evaluating where to deploy capital for data center power infrastructure, that structural advantage deserves careful analysis.

This alert examines the Texas/ERCOT regulatory framework, the recent legislative and regulatory changes that add new requirements, and the practical considerations that determine whether the structural advantage translates into a project-level economic advantage for a given development.

The ERCOT Anomaly

Approximately 90% of Texas electricity load operates within ERCOT, which is intentionally isolated from the interstate grid through limited, asynchronous DC ties. ERCOT operates as an independent system operator but does not function as a regional transmission organization (RTO) under FERC oversight. Electricity generated, transmitted, and consumed entirely within ERCOT falls outside FERC’s jurisdiction over “the sale of electric energy at wholesale in interstate commerce” and “the transmission of electric energy in interstate commerce” under Section 201(b)(1) of the Federal Power Act (FPA).

The jurisdictional consequences are significant and pervasive. Electricity sales within ERCOT, including sales from a third-party generator to a data center operator, do not require FERC market-based rate (MBR) authorization. They do not trigger the co-location transmission service frameworks imposed in PJM, which administers the nation’s largest wholesale electricity market across 13 states, and SPP, which manages the wholesale market and transmission grid across portions of 14 states in the central United States. They are not subject to the DOE Rulemaking Proposal’s proposed standardized interconnection procedures for large loads. They are not subject to FERC-mandated gross demand billing for ancillary services. And they are not subject to the interconnection queue backlogs and multi-year study timelines that characterize FERC-jurisdictional markets.

The jurisdictional analysis that occupies substantial transactional attention in PJM territory (described in detail in Alert 3) is largely inapplicable in ERCOT. The sale-for-resale trigger under the FPA does not apply because the sale does not occur in interstate commerce. The transmission nexus does not apply because the electricity does not move on the interstate grid. The structuring questions about islanded versus synchronized configurations, about affiliate versus arm’s-length arrangements, about prophylactic MBR filings and declaratory orders, are questions that ERCOT developers generally do not need to answer.

For FERC practitioners and counsel accustomed to navigating the federal overlay, the simplicity of the ERCOT framework can be disorienting. The regulatory environment is not unregulated; it is differently regulated, with state-level oversight through the PUCT and ERCOT’s own protocols substituting for the federal framework. Understanding what those state-level requirements are, and how they have changed since 2025, is essential for developers who plan to capture the structural advantage rather than merely assume it.

Private Use Networks: The Established Pathway

ERCOT’s protocols establish Private Use Networks (PUNs) as the primary regulatory mechanism for BTM generation serving dedicated loads. A PUN is defined as an electric network connected to the ERCOT transmission system at a single point that serves only the owner’s load without third-party sales.

PUNs offer several advantages for data center BTM projects. They avoid FERC jurisdiction entirely because the arrangement operates within a non-FERC-jurisdictional market. The primary power flow occurs within the private network, with the ERCOT grid interconnection used only for backup or supplemental service, which simplifies the interconnection process relative to a front-of-meter generator seeking full transmission access. PUN operators control the dispatch of generation to serve their load without ERCOT market participation requirements, though voluntary participation is permitted and may enhance project economics (discussed below). To qualify as a PUN, the arrangement must satisfy ERCOT’s single-entity ownership requirement: the generation, the load, and the interconnecting facilities must be owned or controlled by the same entity. Developers pursuing a third-party structure (in which GenCo and DataCo are separate entities) cannot use the PUN pathway without consolidating ownership, whether through a single-purpose entity that owns both the generation and the data center, a master lease structure in which one entity holds operational control of both, or another arrangement that satisfies the single-entity requirement. The structuring choice has implications for tax ownership, financing, and the REP certification analysis discussed below, and should be evaluated with tax counsel and the project’s financing parties before the ownership structure is finalized. Establishing a PUN also requires notification to ERCOT and verification of single-entity ownership, not PUCT certification or extensive regulatory proceedings.

The PUN structure directly addresses the cost allocation and reliability concerns that animated the Talen Order and the PJM Order (each described in Alert 1). Because the arrangement operates entirely within ERCOT, there is no federal transmission cost allocation to dispute, no capacity market impact to study, no interstate cost shift to litigate, and no intervenor standing to challenge the arrangement before FERC. The developer’s regulatory burden is limited to state-level requirements, which, while meaningful, are substantially less complex and less costly than the federal overlay applicable in PJM, SPP, and other organized markets.

For sponsors evaluating the ERCOT opportunity, the PUN structure has a particular advantage for project finance. The absence of federal regulatory risk simplifies the credit analysis: there is no FERC reclassification risk, no risk of unanticipated transmission charges from RTO tariff changes, and no regulatory change trigger tied to the DOE Rulemaking Proposal or PJM compliance proceedings. Lenders can underwrite the project against ERCOT market risk, Texas regulatory risk, and operational risk without layering federal regulatory uncertainty on top. That simplification may translate into more favorable financing terms, tighter spreads, and fewer regulatory representations and covenants in credit documentation relative to comparable projects in FERC-jurisdictional markets.

Senate Bill 6: The New Legislative Framework

The 89th Texas Legislature enacted Senate Bill 6 (SB 6), signed by Governor Greg Abbott on June 20, 2025, establishing a comprehensive regulatory framework for large-load interconnection within ERCOT. SB 6 represents the most significant legislative development for data center power in Texas since the deregulation of the retail market, and developers should understand its requirements in detail.

SB 6 imposes several requirements directly relevant to BTM data center generation. Entities interconnecting after December 31, 2025, must develop curtailment protocols and install equipment enabling remote disconnection by ERCOT during grid emergencies. Load forecasting requirements apply, obligating large-load customers to provide ERCOT with detailed demand projections that feed into ERCOT’s system planning. Ramp rate limitations may apply to large loads whose sudden changes in consumption could affect grid frequency and stability.

SB 6 also directs the PUCT to implement the legislation through multiple active rulemakings. The PUCT assigns each rulemaking a numbered “Project” docket, which functions similarly to a FERC docket number as the official proceeding identifier. Project 58481 addresses interconnection standards for large loads. Project 58479 addresses net-metering rules for co-located generation and load. Additional proceedings address large-load forecasting criteria, reliability contributions, and coordination between ERCOT and serving utilities. These rulemakings are ongoing, and the implementing rules will define the practical compliance requirements for BTM generation going forward. The final rules may differ from the statutory framework in ways that affect project design and economics.

For developers, SB 6 represents both a compliance burden and a political signal. The compliance burden is real: curtailment protocols, remote disconnect, load forecasting, and potential ramp rate limitations add operational requirements and equipment costs that did not exist before 2026. But the political signal may be equally important. SB 6 reflects the Texas legislature’s decision to accommodate data center load growth within ERCOT rather than restrict it. The legislature chose to impose operating conditions on large loads rather than to block or penalize them. That legislative posture, combined with ERCOT’s structural FERC avoidance, suggests that Texas intends to remain a preferred jurisdiction for data center development, subject to requirements designed to protect grid reliability and existing ratepayers.

For sponsors and lenders, SB 6’s requirements should be modeled into project economics from the outset. Curtailment obligations affect revenue projections: if the facility is required to reduce load during grid emergencies, the data center’s availability (and therefore its revenue) may be reduced during the highest-value periods. Remote disconnect equipment adds capital cost. Load forecasting compliance requires dedicated personnel or systems. These costs are modest relative to the federal regulatory burden in PJM or SPP, but they are not zero, and they should not be ignored.

The curtailment obligation also has implications for the offtake or service level agreement between the generation provider and the data center customer. If ERCOT orders load curtailment during a grid emergency, the resulting reduction in data center availability may constitute an event under the service level agreement (SLA) unless the agreement expressly carves out grid-emergency curtailment as an excused event. Developers and their counsel should ensure that the offtake agreement, the SLA, and the force majeure provisions are drafted to allocate curtailment risk consistently, and that the data center customer understands the frequency and duration of curtailment events that SB 6 may produce.

Congressional staff monitoring data center energy policy should note SB 6 as a potential model for federal approaches. The legislation’s framework of accommodating large loads while imposing reliability and cost-sharing conditions reflects a policy balance that may inform the DOE Rulemaking Proposal and future federal legislation. To the extent that the DATA Act (described in Alert 2) proposes a complete exemption from federal regulation for off-grid facilities, SB 6 represents an alternative approach: regulation that is calibrated to the risks rather than eliminated entirely.

The ERCOT Batch Study Transition

ERCOT’s large-load interconnection process is undergoing fundamental reform. The historical process was serial: interconnection requests were studied individually in the order received. That process functioned adequately when ERCOT received fewer than 20 requests per quarter. It cannot function at current volumes, which have reached close to 100 requests per quarter, driven overwhelmingly by data center and industrial load growth.

ERCOT is transitioning to a batch study process in which interconnection requests are grouped and studied together, analogous (though not identical) to the cluster study process that FERC Order 2023 imposed on FERC-jurisdictional transmission providers. A “Batch Zero” mechanism addresses the backlog of existing requests submitted under the serial process. ERCOT has indicated a target effective date of August 1, 2026, following anticipated ERCOT Board approval.

The transition creates near-term scheduling uncertainty for developers with projects in the queue. Projects submitted under the serial process may be rolled into Batch Zero or studied under transitional procedures that differ from both the old serial process and the new batch process. Developers should confirm the status of their interconnection requests and understand how the transition affects their study timeline, cost obligations, and queue position.

For developers who have not yet submitted interconnection requests, the batch study framework may offer advantages over the serial process: studies conducted in clusters can identify shared infrastructure needs and allocate costs more efficiently, and the batch process may ultimately produce faster study completion for projects that enter the queue together. But the transition period itself may be slower than either the old or new steady-state process, because ERCOT is simultaneously processing legacy serial requests, Batch Zero transitional requests, and early batches under the new framework.

REP Certification and Third-Party Arrangements

Texas’s deregulated retail electricity market allows customers in competitive service areas to choose their electricity provider. However, entities providing retail electric service must obtain Retail Electric Provider (REP) certification from the PUCT. The certification requirement applies to entities that sell electricity at retail to end-use customers, with certain exemptions.

The critical question for third-party BTM generation in Texas is whether GenCo providing power to DataCo constitutes retail electric service requiring REP certification. If GenCo and DataCo are the same entity (single-entity self-supply through a PUN), the question does not arise, because no retail sale occurs. If GenCo and DataCo are separate entities with arm’s-length contracts, the PUCT could potentially characterize the arrangement as a retail sale requiring REP certification.

The PUCT has not required REP certification for certain single-customer or integrated arrangements. Texas law provides a streamlined certification path for providers serving large individual customers, and the PUCT has generally taken a permissive approach to industrial arrangements that do not involve service to the general public. However, the regulatory analysis is fact-specific, and the PUCT’s approach may evolve as data center power arrangements become more common and more closely scrutinized.

Developers pursuing third-party BTM generation in ERCOT should evaluate whether REP certification is required for their specific arrangement, whether an existing exemption applies, or whether obtaining a streamlined certification as a precautionary measure may be advisable. The REP certification process is not particularly burdensome (compared to, for example, obtaining MBR authorization from FERC), and the compliance obligations are manageable for a sophisticated operator. The risk of operating without certification when it is required, which could result in enforcement action and potential unwinding of the arrangement, is likely not worth the cost savings of avoiding the certification process.

Weatherization and Resilience Requirements

The February 2021 winter storm that caused widespread blackouts in Texas, known as Winter Storm Uri, prompted significant regulatory reforms that apply to BTM generation as well as grid-connected facilities.

Generation facilities and associated fuel supply infrastructure must implement weatherization measures to operate during extreme weather. Requirements include cold weather preparedness (insulation, freeze protection equipment, windbreaks, auxiliary fuels), freeze protection for natural gas production and delivery infrastructure serving electric generation in ERCOT, heat preparedness for summer peak conditions, and annual weatherization inspections, declarations of preparedness, and certifications. ERCOT is tasked with inspecting for compliance and reporting violations to the PUCT.

BTM natural gas generation must demonstrate reliable fuel access through firm supply contracts, on-site storage, or both. Fuel assurance has become a critical regulatory and operational requirement since Uri, and developers should expect scrutiny of their fuel supply arrangements during the interconnection and registration process.

These requirements add cost and operational complexity. Cold and heat weatherization, fuel assurance, annual compliance certifications, and ERCOT inspections represent ongoing obligations that must be budgeted and managed. For lenders, weatherization compliance is a diligence item: the financing documents should include representations regarding compliance with applicable weatherization standards, covenants requiring ongoing compliance, and notice requirements if the facility is found noncompliant or faces enforcement action.

For data centers requiring high reliability (which is effectively all of them), the investment in weatherization is prudent regardless of the regulatory mandate. Winter Storm Uri demonstrated that Texas weather can produce extreme conditions that overwhelm unprepared facilities. A data center that loses power during a winter storm faces not only the direct cost of the outage but also the reputational and contractual consequences of failing to meet uptime commitments. Weatherization should be designed into the facility from the outset, not treated as a compliance afterthought.

Resource Adequacy: The Energy-Only Market

ERCOT operates an energy-only market without a capacity market, a structural distinction from PJM, ISO New England (ISO-NE), and other organized markets where capacity obligations play a significant role in the economics and regulation of generation.

In an energy-only market, generators are compensated only for the energy and ancillary services they actually provide, not for maintaining available capacity. There are no must-offer obligations requiring generators to bid into a capacity auction, no capacity performance penalties for failing to deliver during peak conditions, and no obligation to commit BTM generation resources to a capacity market. ERCOT relies instead on scarcity pricing, allowing energy prices to reach $5,000/MWh during tight supply conditions, to incentivize adequate generation investment and availability.

For BTM generation in ERCOT, the energy-only structure has several implications. There are no capacity market obligations to navigate, which eliminates a significant source of regulatory complexity and cost that applies in PJM and other organized markets with mandatory capacity obligations, including ISO-NE and the New York Independent System Operator (NYISO). BTM generators can participate voluntarily in ERCOT’s real-time energy market to monetize surplus generation, and can provide ancillary services (regulation, responsive reserves, non-spinning reserves) for additional revenue, but participation is entirely optional. During tight supply conditions, PUN operators capable of exporting surplus generation to the grid can capture substantial scarcity pricing revenue, though this opportunity is intermittent and should not be the primary basis for project economics.

The energy-only structure is itself evolving. The Texas legislature has authorized the PUCT to establish reliability mechanisms under Texas Utilities Code § 39.1594, and the Performance Credit Mechanism (PCM) or similar constructs may introduce capacity-like obligations that could affect BTM generation economics. The PCM, as currently contemplated, would credit generators for providing capacity during critical periods, potentially creating a revenue stream for BTM generators willing to offer excess capacity to the market. It could also create an obligation or incentive structure that reduces the operational flexibility that PUN operators currently enjoy. Developers with long-dated investments in ERCOT should monitor the PUCT’s implementation of these reliability mechanisms and consider how potential changes to the energy-only structure could affect project economics over the facility’s operating life.

ERCOT Market Participation: The Revenue Opportunity

While PUNs can operate independently of ERCOT’s markets, voluntary market participation may meaningfully enhance project economics for facilities with surplus generation capacity or operational flexibility.

Energy market sales provide a straightforward revenue stream when the data center’s load is below the generation facility’s output. For a facility sized with a 15 to 30 percent reserve margin (as described in Alert 3 for islanded configurations), the surplus capacity during normal operations represents potential energy market revenue. ERCOT’s real-time market clears at marginal cost, with prices that can be highly volatile, ranging from near-zero during low-demand periods to $5,000/MWh during scarcity events.

Ancillary services represent a potentially higher-value revenue stream for generation capable of rapid response. Responsive reserves, regulation services, and non-spinning reserves are procured by ERCOT through competitive markets. BTM generation that can modulate output or redirect generation between the data center and the grid may be well-positioned to provide these services, though doing so requires operational coordination between the generation facility and the data center’s power management systems.

During grid emergencies, ERCOT’s Reliability Deployment Price Adder (RDPA) can produce scarcity pricing that makes emergency exports extremely valuable. A PUN capable of reducing its grid draw or exporting surplus generation during these events can capture significant revenue in a short period.

Market participation requires registration as a Qualified Scheduling Entity (QSE) and compliance with ERCOT protocols. For sophisticated operators with the systems and personnel to manage the complexity, the revenue opportunity may be meaningful. For operators whose primary focus is data center uptime rather than power market optimization, the complexity may not be justified. The decision should be evaluated as part of the project’s overall financial model, with realistic assumptions about market price frequency, dispatch flexibility, and the operational burden of QSE compliance.

For sponsors and lenders, ERCOT market revenue adds an upside component to the project’s cash flow projections but introduces commodity price exposure that complicates the credit analysis. Lenders may wish to structure market revenue as an equity upside rather than a base-case debt service assumption, or may require hedging arrangements or revenue reserves to mitigate the volatility.

The Cost Differential: Quantifying the Structural Advantage

For sponsors and lenders evaluating the ERCOT opportunity relative to FERC-jurisdictional markets, the cost differential is the central analytical question. The structural advantage described throughout this alert translates into project-level economics through several channels.

In PJM, a 500 MW data center with dedicated co-located generation would face mandatory transmission service charges under one of the four service options established by the PJM Order (described in Alert 1), gross demand billing for ancillary services regardless of the transmission service election, interconnection study costs and potential network upgrade obligations (which can reach into the hundreds of millions of dollars for large projects in constrained areas), and the administrative and legal costs of navigating the co-location tariff framework, the compliance filings, and potential intervenor challenges. The aggregate annual cost of these federal regulatory obligations could amount to tens of millions of dollars for a facility of this scale.

In ERCOT, the same facility would face PUCT registration (straightforward), ERCOT interconnection (under the batch study process), SB 6 compliance (curtailment protocols, remote disconnect, load forecasting), weatherization, and standby/backup utility tariffs. These costs are real but materially lower than the PJM regulatory burden. A reasonable estimate of the annual cost differential, accounting for transmission charges, ancillary service billing, and regulatory compliance, could range from $20 million to $50 million or more, depending on the specific PJM zone, the transmission service election, and the extent of network upgrade obligations.

That differential compounds over a 20-year project life. At a 500 MW scale, the present value of the regulatory cost savings from ERCOT versus PJM could represent hundreds of millions of dollars. This is a significant factor in the current capital migration to Texas, and the structural advantage is likely to persist even as SB 6 and the batch study transition add new compliance requirements.

The cost differential is not the only factor in siting decisions. Fiber connectivity, water availability, labor markets, tax incentives, land costs, community receptivity, and the developer’s existing infrastructure and relationships all play a role. But for developers whose siting analysis can accommodate Texas, the regulatory cost advantage is large enough to be dispositive for many projects.

The tax analysis reinforces rather than offsets the structural advantage. Credits under Section 45Y and Section 48E of the Inflation Reduction Act of 2022 (IRA) are technology-based, not geography-based, and are equally available for qualifying generation in ERCOT as in FERC-jurisdictional markets. Texas locations may also qualify for the energy community bonus credit, a 10% adder available for projects sited in qualifying census tracts, many of which are concentrated in the Permian Basin, along the Gulf Coast, and in former coal communities. Sponsors evaluating ERCOT against other jurisdictions should incorporate the energy community designation into their siting analysis, as the bonus credit can materially affect project economics for qualifying locations.

The tax analysis summarized in this section is intended to identify structural considerations relevant to siting decisions, not to provide tax advice. The specific application of IRA credits, the energy community bonus, and any state-level incentives to a particular project should be confirmed by tax counsel and the sponsor’s accountants. The availability and value of these credits depend on the specific technology, ownership structure, and tax position of the sponsor, and should not be incorporated into project economics or financing assumptions without that confirmation.

Standby and Backup Service: The Utility Variable

Data centers operating PUNs typically maintain a backup connection to the local distribution utility for supplemental power, maintenance outages, and emergencies. This backup service implicates utility tariffs that vary significantly among ERCOT utilities.

Standby and backup tariffs typically include demand charges based on maximum coincident peak usage from the grid, energy charges for actual kWh consumed, backup reservation charges for maintaining capacity availability, and non-bypassable delivery charges for transmission and distribution infrastructure. The specific rate levels and structures differ materially among Texas utilities. For a large data center, the difference in annual standby costs between the most favorable and least favorable utility territory in ERCOT can amount to millions of dollars.

Texas law provides an important protection: utilities cannot prevent self-generation through prohibitive standby rates. All utility rates, including standby charges for backup service to self-generators, must be just and reasonable, and the PUCT reviews standby tariffs for cost-basis and non-discrimination. Developers who believe that a utility’s standby rates are unreasonably high or discriminatory can challenge them before the PUCT.

Utility territory selection should be a component of the siting analysis, not an afterthought. Developers should obtain and compare standby tariff schedules from the utilities serving their candidate sites, model the standby cost over the project life, and factor the result into the siting decision alongside land cost, interconnection timeline, fiber availability, and other variables.

Practical Considerations

ERCOT offers what appears to be the fastest and most cost-effective path to operational BTM generation at scale in the United States. The structural FERC avoidance, the established PUN framework, the competitive energy markets, the resource diversity (wind, solar, and natural gas), and the state’s scale and growth trajectory create a combination of advantages that no other jurisdiction currently matches.

But the advantage is structural, not absolute. SB 6 adds real compliance requirements. The batch study transition creates near-term interconnection uncertainty. Weatherization is a capital and operational cost. Standby rate differentials among utility territories can materially affect economics. The PUCT’s ongoing rulemakings will define compliance requirements that are not yet finalized. And the political environment, while currently favorable, is subject to change: the Ratepayer Protection Pledge’s “national policy” language (discussed in Alert 2) and the growing public attention to data center energy consumption create political pressures that could produce additional requirements over time.

The developers who are most likely to capture the ERCOT advantage are those who approach Texas with the same diligence they would apply to any complex regulatory environment: engaging the active PUCT proceedings, modeling SB 6 compliance costs, evaluating utility territory as a siting variable, designing weatherization into the facility, and building the project for long-term regulatory resilience rather than optimizing for the current moment.

This is the fourth in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions. The next alert examines Colorado’s large-load tariff and the clean energy overlay that makes Colorado the most complex jurisdiction in this series and the one most different from Texas.

This alert is intended to provide a general overview of the regulatory framework for data center power in Texas and ERCOT. 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.

The first two alerts in this series traced the Federal Energy Regulatory Commission’s (FERC or the Commission) regulatory trajectory and the political economy now shaping data center power. This alert turns to the structuring question that sits at the center of every behind-the-meter generation and co-located load transaction serving data centers (collectively, BTM): how to design an arrangement that achieves the developer’s commercial objectives while managing, or, where the project configuration permits, avoiding FERC jurisdiction.

Structure determines jurisdiction. That is the single most important proposition in this area of practice. The physical configuration of the generation-to-load connection, the ownership architecture, the contractual relationship between the generator and the data center, and the presence or absence of a grid interconnection collectively determine whether the arrangement falls within FERC’s regulatory reach or outside it. A transaction that is structured carefully can avoid federal wholesale jurisdiction entirely. A transaction that inadvertently triggers FERC jurisdiction can expose the generator to market-based rate (MBR) authorization requirements, ongoing compliance and reporting obligations, potential refund liability, and, in PJM Interconnection (PJM) and the Southwest Power Pool (SPP), the full weight of the co-location frameworks described in Alert 1. Those consequences are retroactive, costly, and difficult to unwind.

This alert examines the principal structural choices, identifies the jurisdictional triggers associated with each, and provides practical guidance for developers, sponsors, lenders, and their counsel.

The Two Jurisdictional Triggers

FERC jurisdiction over electricity transactions attaches through two independent pathways under Section 201(b)(1) of the Federal Power Act (FPA). Either trigger, standing alone, is sufficient to bring the arrangement within FERC’s regulatory reach.

The first is the sale-for-resale trigger. The FPA grants FERC jurisdiction over “the sale of electric energy at wholesale in interstate commerce,” and defines a wholesale sale as “a sale of electric energy to any person for resale.” The critical distinction lies between sales (which trigger jurisdiction when they are for resale) and consumption (which does not). If the data center is the end consumer of the electricity and does not resell it, the transaction is a retail sale reserved to state jurisdiction under FPA Section 201(b)(1). Self-supply by a single entity that generates and consumes its own power is the clearest case: no sale occurs at all, and FERC jurisdiction does not attach.

This distinction proves more complex in practice than in theory. Three increasingly common data center power arrangements illustrate the spectrum. This alert discusses each in turn below.

The second trigger is the transmission nexus. The FPA grants FERC authority over “the transmission of electric energy in interstate commerce” and “all facilities for such transmission or sale.” This transmission jurisdiction extends broadly. If generation facilities connect to the grid, even through a backup or supplemental interconnection, that connection may bring the arrangement within FERC’s reach regardless of whether the underlying sale is retail or wholesale. Courts and FERC have recognized limited exceptions for “radial” interconnections that are sole-use, limited and discrete, radial in nature, and not part of an integrated transmission network. But the exception is narrow, fact-specific, and cannot be assumed without careful engineering and legal analysis.

Three Structures, Three Risk Profiles

Consider three increasingly common arrangements for a 200 MW natural gas plant adjacent to a data center facility.

Structure 1: Single-Entity Self-Supply. DataCo owns and operates both the data center and the 200 MW plant. The plant’s output flows entirely to the data center via a dedicated interconnection with no path to the grid. No electricity crosses the boundary of a single legal entity, and no sale occurs. FERC jurisdiction does not attach under either the sale-for-resale trigger or the transmission nexus (assuming no grid interconnection). This is the cleanest structure from a jurisdictional perspective. Its limitation is that it requires the data center operator to be in the power generation business, including managing fuel procurement, environmental permitting, plant operations, and maintenance, functions that many data center companies prefer to outsource.

Structure 2: Third-Party PPA. GenCo builds and operates the 200 MW plant. GenCo sells 100% of the plant’s output to DataCo under a 20-year power purchase agreement (PPA). The power flows through a dedicated interconnection with no grid connection. DataCo consumes all of the electricity and does not resell any portion. This arrangement should constitute a retail sale outside FERC’s wholesale jurisdiction, because DataCo is the end consumer and does not purchase for resale. However, FERC has long maintained that corporate separateness alone does not determine jurisdictional questions. The Commission looks to the substance of an arrangement, not merely its form, and considers whether the overall structure and purpose of the arrangement constitute a wholesale transaction regardless of the label applied by the parties. If DataCo were to resell any portion of the output, or if surplus generation were to flow to the grid through an interconnection, the sale-for-resale trigger could be implicated. And if the dedicated interconnection between GenCo’s plant and DataCo’s facility were synchronized with the grid, the transmission nexus could be triggered independently.

Structure 3: Affiliate Wholesale. GenCo and DataCo are corporate affiliates. GenCo sells the plant’s output into the wholesale market, while DataCo purchases power from the grid at retail rates through the local utility. This structure clearly involves wholesale sales requiring FERC MBR authorization and, in organized markets administered by regional transmission organizations (RTOs), full participation in the applicable RTO’s capacity, energy, and ancillary service frameworks. It provides no BTM benefit and no queue avoidance. It is included here to mark the outer boundary of the jurisdictional spectrum.

Structure 1 avoids FERC jurisdiction entirely. Structure 3 is fully within it. Structure 2 occupies the gray zone where most live transactions sit and where structuring precision determines the outcome.

Managing the Gray Zone: Structural Choices That Reduce Jurisdictional Exposure

For developers pursuing Structure 2 arrangements (or variations of it), several structural choices may reduce the risk of FERC jurisdictional exposure. None of these choices provides certainty in the absence of a FERC declaratory order or MBR filing, but each shifts the analysis in a favorable direction.

Ownership Integration. The strongest defense against the sale-for-resale trigger is eliminating the “sale” altogether. If GenCo and DataCo form a single-purpose limited liability company (LLC) that owns both the generation facility and the data center, the transfer of electricity from the plant to the load is an internal allocation within a single entity, not a sale between separate parties. The LLC structure should have genuine economic substance: shared capital contributions, integrated governance, common operational control, and a business purpose beyond jurisdictional avoidance. FERC’s substance-over-form analysis means that a structure that is formally integrated but functionally operates as a bilateral PPA between two independent parties may not withstand scrutiny. The more genuine the integration, the stronger the jurisdictional position.

For sponsors and their counsel, the ownership integration approach raises practical considerations that deserve attention at the term sheet stage. An integrated LLC typically means the sponsor and the data center customer (or their respective affiliates) are co-owners of the generation asset. That affects the capital stack, the allocation of development risk, the tax treatment (including whether the sponsor can claim depreciation and energy tax credits), and the exit mechanics. If the sponsor’s investment thesis contemplates selling the generation asset independently of the data center, or if the data center customer’s business model does not include co-ownership of generation, the integrated LLC may not be commercially feasible, and the parties may need to rely on one of the alternative structural approaches described below.

Deep Operational Integration. Where separate legal entities are required (for tax, financing, liability, or commercial reasons), the arrangement should demonstrate operational integration sufficient for FERC to treat the electricity transfer as an internal allocation rather than a wholesale sale. Indicators that FERC has considered in evaluating whether arrangements between affiliated entities constitute wholesale sales include common control of dispatch and operations, shared planning and investment decisions, integrated fuel procurement, absence of arm’s-length price negotiation, and whether the entities function as a single economic enterprise even though they are legally separate. The line between “deep operational integration” (which may support a characterization as internal transfer) and “separate entities with a PPA” (which constitutes a sale requiring jurisdictional analysis) is not bright, and FERC has provided limited guidance on where it falls. Developers pursuing this approach should document the operational integration comprehensively, because the analytical record will be important if FERC or an intervenor challenges the arrangement.

Prophylactic MBR Authorization. Where any material jurisdictional ambiguity exists, obtaining MBR authorization from FERC as a precautionary measure may be the most prudent path. MBR authorization requires demonstrating a lack of horizontal market power (the seller does not have the ability to raise prices above competitive levels) and vertical market power (the seller does not have the ability to erect barriers to entry through control of transmission). It also imposes ongoing compliance obligations, including quarterly transaction reporting, change-in-status filings, and triennial market power updates. These obligations are not trivial. But the alternative, operating without authorization and facing potential refund liability and enforcement action if FERC later determines that the arrangement constitutes a wholesale sale, presents a significantly less attractive risk profile. For lenders and equity sponsors, the existence of MBR authorization (even if never used operationally) may provide a level of regulatory comfort that facilitates financing on more favorable terms.

FERC Declaratory Orders. FERC’s declaratory order process under Rule 207 of the Commission’s Rules of Practice and Procedure allows developers to obtain jurisdictional clarity before commencing operations. The process typically takes six to 12 months and requires a detailed factual submission describing the arrangement, the parties, the physical configuration, and the basis for the requested jurisdictional determination. Declaratory orders are not binding on future Commissions in the same way that a rulemaking would be, but they provide significant comfort and reliance protection for the specific arrangement described. For large-capital projects where jurisdictional uncertainty affects financing terms, insurance requirements, or counterparty willingness to commit, the investment in a declaratory order proceeding may be justified.

The Physical Configuration: Islanded vs. Grid-Connected

The contractual structure and the physical configuration of the generation-to-load connection operate as independent jurisdictional variables. Even a contractually clean self-supply arrangement can trigger FERC transmission jurisdiction if the facilities are interconnected with the grid.

A facility that is electrically islanded from the grid, with no synchronization, no backup interconnection, and no path for power to flow to or from the interstate transmission system, presents the strongest case for avoiding FERC transmission jurisdiction. The generation facility delivers power to the data center through a dedicated line that does not touch the grid. No transmission of electric energy in interstate commerce occurs, and neither the generation facility nor the interconnecting line constitutes a facility used for such transmission.

The tradeoff for islanding is reliability. An islanded facility must be sized to meet the data center’s full load requirement plus sufficient reserve margin to cover maintenance outages and unplanned trips, which typically means overbuilding generation capacity by 15 to 30 percent relative to expected average consumption. That excess capacity represents significant capital investment that sits idle during normal operations. For a 500 MW data center, the incremental cost of 75 to 150 MW of reserve generation capacity can amount to hundreds of millions of dollars in additional capital expenditure. Sponsors and their financial advisors may wish to model this overbuilding cost against the regulatory cost savings from FERC avoidance to determine whether the islanded configuration produces a net economic advantage for the specific project.

Grid interconnection eliminates the overbuilding requirement by providing access to utility backup power during outages and maintenance. It may also enable the monetization of surplus generation through grid sales rather than curtailment. But any grid interconnection in a FERC-jurisdictional market subjects the facility to the applicable RTO’s interconnection procedures, study requirements, and, under the PJM Order (described in Alert 1), the new transmission service framework for co-located load. The choice between islanding and grid connection is therefore both an engineering decision and a regulatory decision, and it has direct implications for the project’s capital structure, operating economics, and bankability.

For lenders evaluating BTM generation projects, the islanded configuration presents a distinctive risk profile. The facility has no grid backup, meaning that any generation outage directly affects the data center’s operations and revenue. Lenders may require higher debt-service coverage ratios, larger reserve accounts, or more comprehensive insurance coverage for islanded projects than for grid-connected projects. The generation technology, the fuel supply arrangements (including firm gas transportation and on-site storage), and the maintenance program become critical credit considerations in the absence of grid backup. Conversely, the islanded facility carries no risk of unanticipated transmission charges, regulatory reclassification, or RTO tariff changes, which may simplify the regulatory risk analysis in the credit memorandum.

The Phased Approach

For developers who need both speed to market and eventual grid access, a phased strategy may offer the best path to both objectives. The concept is straightforward: begin operations on a fully islanded basis under a self-supply or integrated LLC structure, which allows the data center to reach commercial operation and begin generating revenue without waiting for interconnection queue processing. Pursue grid interconnection studies and approvals in parallel. Transition to a grid-connected configuration, with the attendant transmission service and cost-sharing obligations, once interconnection rights are secured.

The phased approach has meaningful practical advantages. It compresses the time to revenue, which can be critical for sponsor internal rate of return and for meeting contractual delivery commitments to the data center customer. It provides a period of operational experience during the islanded phase that can inform the design of the grid-connected phase. And it allows the developer to observe how the regulatory framework (including the DOE Rulemaking Proposal, the PJM compliance filings, and the SPP High Impact Large Load (HILL) framework, each described in Alert 1) develops before committing to a specific transmission service election.

The execution is more complex than the concept. The regulatory analysis for the islanded phase differs from the grid-connected phase in several material respects, and both phases must be structured from the outset to accommodate the transition. The PPA or LLC agreement should contemplate the shift from islanded to grid-connected service, including triggers for when the transition occurs, allocation of the incremental transmission charges and study costs associated with grid connection, adjustment of the capacity commitment and pricing structure to reflect the availability of grid backup, and modification of the risk allocation (including force majeure, curtailment, and regulatory change provisions) to account for the RTO framework that takes effect upon interconnection. The interconnection application should be filed early enough in the islanded phase to allow the queue position and study process to mature by the time the developer is ready to transition. And the financing documents should address the transition as a planned event with defined conditions, not as a material change that triggers covenant defaults or renegotiation.

Lenders may view the phased approach favorably if the transition mechanics are well-defined, because it combines the regulatory simplicity of the islanded phase with the reliability and revenue advantages of grid connection. But the transition introduces its own risks: the grid connection may be delayed by queue backlogs, study costs may exceed initial estimates, and the RTO tariff provisions that apply at the time of interconnection may differ from those in effect when the project was initially structured. These risks should be addressed in the financing documents through conditions to the transition, cost caps or allocation mechanisms for interconnection study costs, and regulatory change provisions tied to the specific RTO framework. The data center customer’s service level agreement or offtake arrangement should also address the transition explicitly, including any planned outage window during the switchover from islanded to grid-connected service, the allocation of curtailment risk during the transition period, and whether the availability guarantee and liquidated damages framework changes upon grid connection to reflect the improved reliability profile.

The Landlord-Tenant Alternative

In certain states, a landlord-tenant utility exemption provides an additional structural pathway. Under this model, the generation owner holds both the generation facility and the real property, leases the site to the data center operator, and delivers power as a bundled component of the lease rather than as a separately metered and billed commodity. If structured properly, no “sale” of electricity occurs under applicable state utility law, the power delivery is a lease service, and the landlord is not classified as a utility.

The landlord-tenant structure has notable advantages for sponsors. The generation owner retains tax and GAAP ownership of the generation assets, preserving depreciation, bonus depreciation, and eligibility for energy tax credits (including credits under Section 45Y and Section 48E of the Inflation Reduction Act of 2022 (IRA), where the generation technology qualifies). The data center customer holds a lease interest rather than an ownership or leasehold interest in the generation assets, which simplifies the customer’s balance sheet treatment and avoids the complexities of asset lease classification for accounting purposes (specifically ASC 842).

The structure requires careful attention to several elements. The lease should include meaningful non-electricity terms (site access, infrastructure, maintenance obligations, shared facilities) so that it reads as a real property lease with bundled services rather than a power purchase agreement with a lease wrapper. The rent structure should avoid pure per-kWh volumetric charges that function as an electricity rate. A two-part structure consisting of a fixed capacity component and a variable operating cost pass-through may be more defensible, though the precise boundary between permissible cost recovery and impermissible retail sale will depend on the applicable state’s statutory framework and regulatory precedent. The lease term and renewal provisions should be consistent with commercial real property practice. And the arrangement should not involve separate metering or billing of electricity as a standalone commodity, which in several states has been identified by courts or regulatory commissions as the line between a bundled lease service and a regulated retail sale.

The landlord-tenant exemption is not available or has not been tested in every jurisdiction. The states where it has the strongest statutory or judicial support (and where it is most relevant for data center development at the scale contemplated in this series) are addressed in Alert 6.

From a FERC perspective, the landlord-tenant structure is most effective when combined with an islanded configuration. If there is no sale for resale (because the transaction is a lease service, not a wholesale sale) and no transmission in interstate commerce (because the facility is islanded), both jurisdictional triggers are avoided.

The Utility’s Likely Response

Developers should expect that incumbent utilities may challenge BTM generation arrangements, regardless of the structure chosen. Utilities have legitimate concerns about lost revenue, stranded cost recovery, and the impact of load departure on the remaining customer base. They also have an economic incentive to serve large loads rather than lose them to self-supply.

The most common challenges take several forms. A utility may file a complaint before the state public utility commission alleging that the arrangement constitutes an unauthorized retail sale or violates the utility’s certificated service territory. A utility may seek to impose prohibitive standby or backup rates on self-generating customers, effectively rendering BTM generation uneconomic. A utility may intervene in FERC proceedings or interconnection processes to raise cost allocation, reliability, or jurisdictional objections. And a utility may engage the state legislature or regulatory commission to seek changes in the statutory or regulatory framework that would restrict or increase the cost of BTM generation.

None of these challenges is necessarily fatal to a well-structured arrangement. State law in most jurisdictions protects the right of customers to self-generate, and standby rates are subject to regulatory review for reasonableness. But each challenge takes time and money to litigate, and the risk of an adverse outcome, even if the legal merits ultimately favor the developer, should be factored into the project timeline and budget. Developers who engage with the incumbent utility early in the process, who structure standby and backup service arrangements that address the utility’s cost recovery concerns, and who demonstrate willingness to participate in grid support (demand response, emergency generation, reliability coordination) may find less adversarial regulatory proceedings. The constructive engagement principle described in Alert 2 applies here with particular force.

PURPA: Limited Utility at Scale

The Public Utility Regulatory Policies Act of 1978 (PURPA) offers certain exemptions from FPA regulation for qualifying facilities (QFs), including exemption from FPA utility registration requirements, exemption from state utility rate regulation in certain circumstances, and mandatory purchase obligations from utilities at avoided cost rates. For data center BTM generation, QF status offers potential regulatory shelter.

However, PURPA’s constraints make it generally impractical for large-scale data center generation. The small power production facility pathway (covering renewables) caps at 80 MW, well below the 200 to 500 MW scale most developers contemplate. The cogeneration pathway has no size cap, which is its principal advantage, but it requires the facility to meet FERC’s operating and efficiency standards under 18 C.F.R. Part 292, including meaningful, useful thermal output in addition to electricity. Most data center loads are electricity-only. Using waste heat from generation for data center cooling is a plausible path to qualification, but the thermal output must be “useful” under FERC’s standards, not merely dissipated, and the facility must meet minimum efficiency thresholds. Whether waste heat used for cooling satisfies FERC’s useful thermal output requirement involves technical and regulatory uncertainties that are difficult to resolve as a planning assumption.

PURPA’s QF exemptions are most valuable when paired with third-party power sales structures, where federal and state utility regulation would otherwise apply most directly. Under self-supply or landlord-tenant structures, the state statutory exemptions typically do most of the regulatory work, and the incremental value of QF certification is limited to the mandatory purchase obligation (providing a floor for surplus output sales) and the Public Utility Holding Company Act (PUHCA) exemption (relevant only if the ownership structure involves a holding company with utility affiliates). These benefits should be weighed against the ongoing compliance burden of maintaining QF status.

For most large-scale data center BTM generation projects, PURPA exemptions are unlikely to serve as the primary regulatory strategy. They may assist smaller distributed generation projects, specialized cogeneration configurations where the data center’s cooling load can satisfy the thermal output requirements, or projects where the mandatory purchase obligation provides meaningful surplus sales revenue. But at the 200 MW and above scale, the structuring approaches described earlier in this alert provide a more reliable regulatory foundation.

Observations

Three principles emerge from this analysis.

First, the jurisdictional outcome is determined by the interaction of the contractual structure and the physical configuration. A self-supply or integrated LLC structure combined with an islanded configuration avoids both FERC jurisdictional triggers. A third-party PPA combined with grid interconnection potentially triggers both. Every other combination falls somewhere between these poles, and the regulatory risk profile of each must be evaluated on its specific facts.

Second, the optimal structure is not the one that minimizes regulatory exposure in isolation, but the one that best balances regulatory considerations against commercial, tax, financing, and operational objectives. A fully islanded self-supply arrangement is jurisdictionally clean but commercially restrictive. A third-party PPA with grid backup is jurisdictionally complex but commercially flexible. The right answer for a given project depends on the sponsor’s investment thesis, the data center customer’s operating requirements, the availability of financing for the chosen structure, and the state-specific regulatory framework.

Third, the regulatory landscape described in Alerts 1 and 2 is actively tightening the gray zone. The PJM Order, the SPP HILL framework, and the DOE Rulemaking Proposal (each described in Alert 1) are designed to bring co-located and BTM arrangements within a defined regulatory framework. Arrangements that rely on jurisdictional ambiguity, that depend on the absence of clear rules to avoid compliance, are increasingly exposed. The window for structuring around undefined tariff provisions is narrowing. Developers may wish to structure transactions on the assumption that the framework will be more defined, not less, by the time the project reaches commercial operation.

This is the third in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions. The next alert examines the Texas/ERCOT framework, the jurisdiction where these structuring choices are most straightforward, and the regulatory advantages relative to FERC-jurisdictional markets are most pronounced.

This alert is intended to provide a general overview of the structuring considerations applicable to behind-the-meter generation serving data center loads. 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.

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.