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.

In the past 18 months, the federal regulatory posture toward data center power has moved from outright rejection to active rulemaking. Between November 2024 and April 2026, the Federal Energy Regulatory Commission (FERC or the Commission), the U.S. Department of Energy (DOE), the White House, and Congress have each intervened in the regulatory landscape governing how data centers obtain dedicated power supply. The core concept is behind-the-meter generation and co-located load, arrangements in which a developer builds or contracts for dedicated power generation at or adjacent to the data center site and delivers electricity directly to the facility rather than drawing it from the grid through a traditional utility (collectively, BTM). Regional transmission organizations (RTOs), the entities that coordinate wholesale electricity markets and manage the transmission grid across multi-state regions, have proposed their own frameworks in parallel. The result is a regulatory environment that, while still taking shape, is far more defined than it was six months ago and warrants careful attention from developers, sponsors, lenders, and their counsel in how transactions are structured, financed, and sited.

American data centers consumed approximately 4% of total U.S. electricity in 2023, a figure projected to reach between 6.7% and 12% by 2028 as artificial intelligence and machine learning workloads proliferate. Traditional grid interconnection processes cannot satisfy this demand on the timelines that developers require. Interconnection queues in major organized markets now exceed five years in many cases, with study deposits, readiness requirements, and network upgrade obligations that can reach into the hundreds of millions of dollars. These delays impose real costs: each month of delay represents millions in lost revenue and stranded investment. BTM generation has emerged as a practical response to these constraints.

This alert surveys the principal federal developments reshaping BTM generation strategy for data centers. It is the first in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions.

The Talen Order: Rejection and Its Limits

FERC’s November 1, 2024, rejection of the amended interconnection service agreement (ISA) at the Susquehanna Steam Electric Station remains the foundational decision in this space to date. The Susquehanna station is a 2,520 MW nuclear generating facility in Luzerne County, Pennsylvania, operated by a subsidiary of Talen Energy and interconnected to the grid through PJM Interconnection (PJM), the RTO that administers the nation’s largest wholesale electricity market, covering 13 states and the District of Columbia. In March 2024, Talen announced the sale of its adjacent Cumulus data center campus to Amazon Web Services for approximately $650 million. The amended ISA filed in June 2024 would have increased the permitted co-located load from 300 MW to 480 MW, reduced Susquehanna’s capacity interconnection rights correspondingly, and added substantial non-conforming provisions addressing reliability, capacity market obligations, and operational coordination.

FERC issued an order (the Talen Order) rejecting the amended ISA because PJM failed to meet its “high burden” of demonstrating that the proposed non-conforming provisions were necessary deviations from PJM’s pro forma interconnection service agreement. The record and concurring statements highlighted broader concerns. On cost allocation, intervenors contended that the cost shift arising from the arrangement could reach as much as $140 million per year. On reliability, PJM’s Independent Market Monitor (IMM), the independent entity responsible for monitoring competitive conditions and market performance within PJM’s wholesale markets, argued that the filing rested on the “illusion” that co-located load at a nuclear plant could be fully isolated from the grid. On precedent, former FERC Commissioner Mark C. Christie warned that approval could trigger widespread load migration from the transmission system, undermining the cooperative cost structure that supports grid infrastructure.

Former FERC Chairman Willie J. Phillips issued a sharp dissent in the Talen Order, arguing that the decision was “a step backward for both electric reliability and national security.” Former Chairman Phillips contended that PJM had comprehensively addressed reliability issues, that the amended ISA represented a first-of-its-kind configuration justifying non-conforming provisions, and that the decision created unnecessary roadblocks to an industry necessary for national security.

The Talen Order did not categorically prohibit BTM arrangements. The decision addressed a specific ISA amendment for an existing grid-connected generator. It also did not address new-build dedicated generation, fully BTM arrangements without transmission interconnection, or co-location in markets outside PJM. Talen and Amazon subsequently expanded their commercial relationship, with Talen announcing a 1.9 GW supply arrangement in June 2025. That the parties most directly affected by the Talen Order found a path forward through restructured commercial terms suggests that its practical impact on deal flow may prove narrower than its headline initially suggested.

For developers and their advisors, the Talen Order nonetheless established several principles that have carried through every subsequent FERC order. First, FERC will scrutinize the cost allocation implications of BTM arrangements, and intervenors will quantify the alleged cost shift to existing ratepayers. Second, FERC expects a thorough analytical record demonstrating that the BTM arrangement will not compromise reliability. Third, the Commission is sensitive to precedential effects and will consider the system-wide implications of approving any individual arrangement. These concerns have animated everything that has followed from FERC since.

The PJM Order: From Rejection to Regulation

FERC’s December 18, 2025, order on PJM co-location (the PJM Order) confirmed what former Chairman Phillips’s dissent in the Talen Order had argued: co-located load is permissible, but it requires a regulatory structure. The PJM Order arose from a February 2025 proceeding in which FERC directed PJM and its transmission owners to demonstrate that PJM’s existing tariff, the set of FERC-approved rules governing rates, terms, and conditions for transmission service in the PJM market, remained just and reasonable in the absence of clear provisions governing co-location arrangements. The PJM Order was approved 5-0, a rare unanimous outcome that suggests consensus on the core principles even among FERC Commissioners who may differ on implementation details.

FERC found PJM’s existing tariff “unjust and unreasonable” because it lacked sufficient clarity on the rates, terms, and conditions applicable to generators serving co-located load. The absence of standardized rules had left generators and large loads unable to determine the steps necessary to implement co-location arrangements, leading to disparate treatment across the PJM footprint and introducing a risk that large-load projects could receive grid services without contributing to the recovery of associated costs.

FERC directed PJM to establish four transmission service options for eligible customers serving co-located load: (1) traditional Network Integration Transmission Service (NITS) on a gross demand basis, a full-requirements service with corresponding cost allocation obligations; (2) Interim Non-Firm Transmission Service, a bridge for facilities that need to begin operations before network upgrades are complete, subject to curtailment during system emergencies; (3) Firm Contract Demand Transmission Service, a new firm service allowing co-located loads to secure guaranteed transmission capacity at a specified contract demand level; and (4) Non-Firm Contract Demand Transmission Service, an interruptible option at a lower cost point for loads with greater operational flexibility.

The Firm and Non-Firm Contract Demand services are particularly significant for BTM strategies. They recognize that co-located loads with on-site generation can limit their energy withdrawals from the transmission system, and they allow those loads to pay transmission charges commensurate with their actual grid reliance rather than their total consumption. For a 500 MW data center with 450 MW of dedicated on-site generation, the difference between gross-demand NITS billing (on the full 500 MW) and Firm Contract Demand billing (on the 50 MW of grid reliance) could amount to tens of millions of dollars annually in transmission charges alone.

The PJM Order also mandated gross demand billing for ancillary services, ensuring that co-located loads contribute to frequency regulation, voltage support, and reserves regardless of their transmission service election. FERC also directed PJM to establish a new megawatt threshold for BTM generation netting (with a three-year transition period for existing network customers and grandfathering for certain contracts entered into before December 18, 2025). Critically for transaction structuring, existing generators seeking to modify their interconnection agreements to add co-located load must follow PJM’s full study process and bear complete cost responsibility for any network upgrades.

That last requirement creates a potentially meaningful asymmetry between existing and new generation. Acquiring an operating plant with existing interconnection rights and modifying its ISA to serve co-located load now triggers the full regulatory apparatus: study process, mandatory upgrade costs, capacity market adjustments, and the scrutiny that comes with a non-conforming ISA amendment (the precise posture that produced the Talen Order rejection). New-build generation dedicated to co-located load from inception may face a lighter path, particularly where the developer can demonstrate minimal reliance on the transmission system through the Firm or Non-Firm Contract Demand services. Sponsors evaluating acquisition strategies may wish to model this regulatory cost differential alongside conventional transaction economics before executing a letter of intent.

Utilities and their regulatory counsel view the PJM Order from a different vantage point. For transmission owners, the PJM Order addresses a legitimate concern about load defection and cost recovery. When large loads co-locate with generation and reduce their transmission withdrawals, the fixed costs of maintaining the transmission system are recovered from a smaller base of remaining customers. The gross demand billing requirement for ancillary services and the mandatory upgrade cost responsibility for existing generators are designed to ensure that co-located loads continue to contribute to the system they rely upon for backup. Standby and backup service rates, which compensate utilities for maintaining capacity availability for loads that primarily self-supply, will be a critical component of the economics for any co-located arrangement in PJM. Developers should expect utilities to seek cost-of-service rates for standby and backup service rather than offering subsidized rates, and project economics should be modeled accordingly.

PJM submitted its principal compliance filing on February 23, 2026, with a requested effective date of July 31, 2026. The filing establishes a 50 MW cumulative nameplate threshold for retail BTM generation that can be netted against load for NITS purposes. Below that threshold, the existing netting rules continue to apply. Above it, loads must take one of the four transmission services described above and be studied for reliability impacts. The filing details the three new transmission services and incorporates grandfathering mechanics for existing contracts.

PJM followed on February 27, 2026, with a separate filing proposing an Expedited Interconnection Track (EIT). The EIT would process up to 10 interconnection requests per year for generating facilities with committed commercial in-service dates and state siting authority support, targeting executed generator interconnection agreements within approximately 10 months. If approved and effective by July 31, 2026 as PJM has requested, the EIT could materially accelerate the timeline for new-build generation serving BTM data center load in PJM territory.

In parallel, PJM’s Critical Issue Fast Path (CIFP) stakeholder process on Large Load Additions produced a January 2026 Board Decisional Letter establishing key principles: a “Bring Your Own Generation” expedited track, a 50 MW large-load threshold, improved load forecasting, and a holistic market review in 2026. A bipartisan coalition of all 13 PJM state governors and the White House National Energy Dominance Council also issued a joint Statement of Principles on January 15, 2026, calling for data centers to bear the infrastructure costs of their own load growth and proposing a potential emergency “backstop” auction to incentivize new generation with 15-year terms for price certainty. The political pressure from both the state and federal levels is pushing in the same direction as FERC’s orders: cost internalization.

For lenders and project finance teams, the PJM compliance filings are the documents that will define the practical economics of co-located load in the nation’s largest wholesale market. The 50 MW netting threshold, the specific rate structures for the three new transmission services, and the EIT eligibility criteria are pending FERC review. Until these provisions are finalized, the transmission cost component of project economics in PJM carries uncertainty that credit committees may wish to address through material adverse regulatory change provisions, debt-service coverage ratio cushions, or reserve account mechanics in financing documents.

SPP’s HILL Framework: An Alternative Model

On January 14, 2026, FERC issued an order (the SPP Order) accepting a framework proposed by the Southwest Power Pool (SPP), the RTO that administers the wholesale electricity market and manages the transmission grid across portions of 14 states in the central United States, including portions of Wyoming. SPP’s High Impact Large Load (HILL) framework provides the first RTO-specific pathway designed from the outset for expedited data center interconnection. The SPP framework took a fundamentally different approach from PJM’s. Where PJM focused on the generator side (regulating how existing and new generators can serve co-located load), SPP focused on the load itself.

SPP defines a HILL as a new commercial or industrial load, or an increase in commercial or industrial load, of 75 MW or greater at a single site connected through one or more shared points of interconnection or delivery points to the SPP transmission system. The associated High Impact Large Load Generation Assessment (HILLGA) process offers dedicated generation an expedited study path outside the standard Definitive Interconnection System Impact Study (DISIS) queue. HILLGA requests can be submitted on a rolling basis rather than during defined request windows, providing a meaningful speed advantage.

That speed, however, comes with some important constraints. HILLGA applications require fees and security deposits that are double those in the DISIS process. Geographic proximity requirements limit HILLGA generation to no more than two substations from the associated HILL, and a generating facility supporting multiple HILLs may involve no more than five substations with no more than two existing transmission line segments between each substation. These geographic constraints prevent HILLGA from functioning as a general queue-bypass mechanism while accommodating reasonable campus-style data center developments. HILLGA interconnection agreements carry a five-year term, after which the generator must either enter SPP’s standard interconnection process or terminate. Separately, HILLGA requests do not receive queue priority over standard interconnection requests, and the network upgrades identified through the HILLGA study process are assigned to the HILLGA customer rather than allocated to other interconnection customers in the standard queue.

SPP also imposed ongoing operational requirements on HILLs: hourly load forecast data provided in real time, remote disconnect capability for the transmission operator, ramp rate limitations not exceeding 20 MW per minute, and ride-through requirements. These operational constraints reflect reliability concerns about sudden large-load changes and may prove challenging for data center operators accustomed to flexible operations, though they may also signal the kind of operational requirements FERC could adopt more broadly.

The SPP framework is immediately relevant for the Mountain West. The western portion of PacifiCorp’s transmission system, including areas in central and eastern Wyoming, came under SPP RTO administration effective April 1, 2026. Projects previously subject only to the Western Area Power Administration (WAPA) – the federal power marketing administration that manages transmission assets across the western United States – or to PacifiCorp’s bilateral interconnection processes now face SPP’s standardized procedures, including FERC Order 2023 requirements and the HILL framework. Projects sited in areas outside SPP’s footprint may face different interconnection requirements depending on the transmission provider. WAPA’s own interconnection procedures, for example, are subject to FERC jurisdiction and may impose obligations independent of SPP membership.

For developers evaluating the Mountain West, the practical question is whether the generation-to-load configuration can be structured to avoid triggering SPP’s procedures. A fully islanded arrangement (radial connection from generation to load, no grid synchronization) should fall outside SPP’s interconnection framework because there is no interconnection to study. The HILLGA pathway becomes relevant only for projects that require grid interconnection, whether for backup, surplus sales, or reliability. Developers with sites that can support an islanded configuration may wish to evaluate a phased approach: begin operations on an islanded basis while pursuing HILLGA or standard interconnection in parallel, and transition to grid-connected service once interconnection rights are secured. The regulatory analysis for each phase differs and should be structured from the outset to accommodate the transition. Alert 3 in this series addresses the phased approach in detail.

Rocky Mountain Power’s anticipated entry into the Extended Day-Ahead Market administered by the California Independent System Operator (CAISO) in May 2026 adds a further dimension, deepening wholesale market access across Utah, Wyoming, and portions of Idaho and Oregon, and expanding both the opportunities and the potential jurisdictional triggers for BTM generation in those states. State-specific considerations are addressed in Alerts 5 (Colorado) and 6 (Wyoming and Utah).

Stepping Back: The Progression from Rejection to Regulation

These developments taken together (the Talen Order, the PJM Order, PJM’s compliance filings, and the SPP Order) reveal a Commission that has moved rapidly from rejection to regulation. In November 2024, FERC rejected a specific co-location arrangement. By December 2025, FERC had directed the creation of a comprehensive regulatory framework for co-located load in the nation’s largest wholesale market. By January 2026, FERC had accepted a complementary framework in SPP. By February 2026, PJM had filed detailed tariff revisions and an expedited interconnection track. In approximately 15 months, the regulatory landscape went from “no clear rules” to “detailed rules pending final approval.”

Understanding why FERC moved this quickly, and in this particular sequence, is important for anticipating what comes next. The Commission’s approach reflects a deliberate institutional strategy. Rather than asserting a national rule of general applicability over co-located load or large-load interconnections (a step FERC has not yet taken), the Commission built the framework incrementally, through individual proceedings involving specific RTOs. Each order established principles (cost causation, reliability study requirements, transmission service options) that the next order could build upon. Together, they create a body of precedent that a national rulemaking can draw upon.

DOE’s Proposed National Rulemaking: Moving Toward a Standardized Framework

In October 2025, Secretary of Energy Wright directed FERC to initiate a rulemaking proceeding (FERC Docket No. RM26-4-000) (the DOE Rulemaking Proposal) that would assert federal jurisdiction over the interconnection of large loads greater than 20 MW directly to FERC-jurisdictional transmission facilities. FERC responded by issuing an Advance Notice of Proposed Rulemaking, the first formal step in the federal rulemaking process, which solicits public comment on whether and how to proceed before proposing specific rules. The DOE Rulemaking Proposal sets out 14 guiding principles for a national framework that would establish standardized interconnection procedures for large loads, analogous to the existing generator interconnection framework under FERC Orders 2003 and 2023.

The DOE Rulemaking Proposal’s jurisdictional claim is significant, contested, and, from an institutional perspective, a departure from FERC’s preferred approach. As described above, the Commission had been building co-location frameworks region by region, through RTO-specific proceedings. The DOE Rulemaking Proposal asks FERC to leapfrog that incremental approach and assert jurisdiction over load interconnections nationally. This is authority FERC has never before claimed. Secretary Wright acknowledged as much in the directive, noting that FERC “has not exerted jurisdiction over load interconnections,” while arguing that doing so “falls squarely within the Commission’s jurisdiction.”

The tension between DOE’s push for a national framework and FERC’s institutional preference for building the record through RTO-specific proceedings is the central dynamic shaping the timeline. DOE initially directed FERC to take “final action” by April 30, 2026. At its April 17, 2026 open meeting, FERC announced that it will act on the DOE Rulemaking Proposal by the end of June 2026, two months later than DOE had requested. FERC Chairman Laura V. Swett stated that the Commission has been working “full speed, around the clock” on the proposal, reviewing approximately 3,500 public comments and consulting with regional grid operators and states developing their own data center policies. Chairman Swett acknowledged that the jurisdictional question is “very important,” noting that “[j]urisdiction is the first question that I, as a FERC litigator, ask.” Given that the rulemaking is still at the advance notice stage (typically followed by a Notice of Proposed Rulemaking (NOPR) and then a final rule), and given the significant jurisdictional objections filed by state commissions, utilities, and consumer advocates, the June 2026 timeline appears more likely to produce a NOPR or a policy statement than a final rule.

The DOE Rulemaking Proposal proposes 100% participant funding, meaning large-load customers would pay the full cost of network upgrades their projects trigger. This marks a significant departure from the traditional socialized model in which transmission upgrades are treated as shared infrastructure and recovered through regional transmission rates. The DOE Rulemaking Proposal asks whether a crediting mechanism could offset those costs over time if the upgrades deliver system-wide benefits. Stakeholder comments have split predictably: developers and technology companies favor a stronger federal role to reduce friction and shorten timelines, while states and many utilities view the proposal as a threat to their traditional authority over retail service, distribution, and resource planning.

The DOE Rulemaking Proposal’s scope is limited to interconnections “directly to transmission facilities,” consistent with FERC’s seven-factor test for distinguishing transmission from distribution. Fully BTM arrangements with no direct transmission interconnection, and facilities operating entirely off-grid, appear to fall outside the DOE Rulemaking Proposal’s proposed reach. The degree of jurisdictional exposure turns on the physical configuration: whether the line connecting generation to load is electrically islanded from the grid or synchronized with it, whether it is BTM, and what entity holds title to the electricity and the interconnecting facilities. A dedicated islanded line presents the strongest case for avoiding FERC jurisdiction. A radial line synchronized with the grid, even serving only one load, could be treated as a transmission facility within FERC’s reach. That distinction is critical and should be evaluated based on site-specific engineering.

An open question for developers with projects already in development is whether a final rule could reach facilities that were structured to avoid FERC jurisdiction at the time of development. The DOE Rulemaking Proposal’s proposed principles address “new” loads and hybrid facilities, and the comment request asks how to treat interconnections “already being studied” during any transition, but it does not expressly carve out facilities with no transmission interconnection at all. Developers with projects in the structuring phase should consider incorporating regulatory change provisions into interconnection and offtake agreements, including representations regarding regulatory status and renegotiation triggers tied to material changes in the applicable jurisdictional framework, to preserve optionality if the regulatory landscape continues to evolve. Lenders may wish to address the same risk through material adverse regulatory change triggers in financing documents.

Separately, the North American Electric Reliability Corporation (NERC), the entity responsible for developing and enforcing mandatory reliability standards for the bulk power system across the United States and Canada, has convened a Large Loads Task Force to develop reliability guidelines for large loads, with a potential mandatory Reliability Standard to follow. A mandatory standard could impose operational requirements on large-load operators regardless of their interconnection status or FERC jurisdictional classification. Developers structuring off-grid or islanded facilities should not assume that avoiding FERC transmission jurisdiction necessarily eliminates all federal regulatory exposure. This is an area that warrants close monitoring.

What This Means for Developers, Sponsors, and Lenders

For developers making near-term siting and procurement decisions, the federal landscape now presents a rough hierarchy. The Electric Reliability Council of Texas (ERCOT), which manages the vast majority of the Texas electric grid independently from the two major U.S. interconnections and largely outside FERC’s wholesale jurisdiction, remains the fastest and least regulated path to co-located or BTM generation at scale, though Texas Senate Bill (SB) 6 (which imposed new large-load interconnection requirements) and the ERCOT batch study transition add complexity that did not exist 18 months ago.

Islanded off-grid facilities in states with permissive regulatory frameworks offer the next-clearest path, avoiding both FERC jurisdiction and RTO interconnection requirements, though at the cost of overbuilding generation to cover reliability without grid backup. SPP’s HILL framework provides an expedited interconnection option with defined timelines but imposes geographic constraints, five-year term limits, and operational monitoring. PJM’s new co-location services are the most structured and potentially the most costly, but they provide regulatory certainty and access to the nation’s largest wholesale market. The optimal path will depend on the developer’s timeline, risk tolerance, capital structure, and whether grid backup or surplus sales are part of the operating model and investment thesis.

For sponsors and their advisors, the regulatory trajectory appears to create a meaningful distinction between new-build and acquisition strategies for co-located generation. The PJM Order’s requirements for existing generators modifying their interconnection agreements impose regulatory costs on acquisition-and-retrofit strategies that new-build dedicated generation may avoid. The tax analysis may compound this: new-build generation using qualifying clean energy technologies may be eligible for credits under Section 45Y or Section 48E of the Inflation Reduction Act of 2022 (IRA) that could materially alter project economics relative to acquisition of existing fossil-fuel generation. Sponsors may wish to model the full regulatory and tax differential before committing to an acquisition thesis.

For lenders and project finance teams, regulatory uncertainty around the DOE Rulemaking Proposal and pending PJM compliance filings introduces a period of elevated risk that may warrant specific attention in credit documentation. Until the framework stabilizes (likely no earlier than late 2026), financing documents for BTM generation projects should address regulatory change risk, including representations regarding the project’s current FERC jurisdictional status, material adverse regulatory change triggers tied to final action on the DOE Rulemaking Proposal or material modifications to the applicable RTO’s co-location tariff, and step-in or restructuring rights if the project’s interconnection or transmission service arrangements require modification. On the other side of the ledger, the regulatory barriers now emerging (upfront deposits, mandatory transmission charges, study timelines, self-funded generation expectations) may function as barriers to entry that favor well-capitalized sponsors with the balance sheet and regulatory sophistication to navigate the current environment.

For utilities and their regulatory counsel, the PJM Order and the Ratepayer Protection Pledge (discussed in the next alert) address legitimate cost recovery concerns. Standby and backup service rates remain the utility’s primary mechanism for recovering fixed costs from self-supplying customers, and the PJM Order’s gross demand billing and mandatory upgrade cost provisions are designed to prevent the cost shifts that concerned the Commission in the Talen Order. Developers who engage constructively with these concerns, through voluntary demand response commitments, emergency generation availability, standby service agreements that reflect actual backup usage, and cost-share arrangements for transmission infrastructure, may find themselves better positioned in regulatory proceedings than those who optimize for cost avoidance.

FERC’s announcement that it will act on the DOE Rulemaking Proposal by the end of June 2026 extends the timeline but does not change the direction. The Commission has signaled through the Talen Order, the PJM Order, and the SPP Order that BTM arrangements will be regulated, not prohibited. The remaining question is the scope and pace of that regulation. Stakeholders with active or planned projects should monitor FERC’s action on the DOE Rulemaking Proposal and the pending PJM compliance filings, and should consider how potential outcomes could affect existing or planned arrangements.

This is the first in a series of seven alerts on the regulatory frameworks for data center BTM generation. The next alert examines the Ratepayer Protection Pledge, the DATA Act, and the emerging political economy of data center power.

This alert is intended to provide a general overview of the federal regulatory developments applicable to behind-the-meter generation and co-located load arrangements serving data centers. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

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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 16, 2026, a division of the Colorado Court of Appeals issued a published opinion in English v. Thorpe, 2026 COA 29, addressing a question of first impression: which rule of civil procedure applies when a party seeks to amend a pleading by dismissing some, but not all, of its claims against a defending party. The division concluded that C.R.C.P. 15(a), governing amendments to pleadings, controls, and not C.R.C.P. 41(a)(2), which addresses voluntary dismissal of an action.

Background

This dispute arose between the estate of Joseph English and Shirley Thorpe over a jointly occupied home. English’s estate sued Thorpe for unjust enrichment and conversion. Thorpe filed an answer and three counterclaims, including two claims premised on the existence of a business partnership between Thorpe and English. Thorpe later sought to amend her answer to drop the two partnership counterclaims while maintaining her unjust enrichment counterclaim. The district court denied the motion, reasoning that because Thorpe sought to dismiss claims, C.R.C.P. 41(a)(2) rather than Rule 15(a) governed, and that permitting dismissal would alter the nature of the case and prejudice the estate.

The Court of Appeals’ Analysis

The division concluded that the district court erred by applying Rule 41(a)(2) instead of Rule 15(a) to Thorpe’s motion, and that this error was not harmless because Rule 15(a)’s more liberal standard favors the moving party.

Rule 15 Versus Rule 41

The division observed that no reported Colorado appellate decision had previously addressed whether Rule 15(a) or Rule 41(a) controls when a party seeks to dismiss some, but not all, of its claims against an opposing party. Turning to the federal rules for guidance, the division noted that federal authority is largely consistent: Rule 41 governs dismissal of an “action”—meaning the whole case, i.e., all claims against a party—while Rule 15 governs the elimination of some, but not all, individual claims from a multi-claim pleading.

The division found particularly instructive the decision in Campbell v. Hoffman, 151 F.R.D. 682, 684 (D. Kan. 1993), which explained that “Rule 41(a)(2) authorizes a plaintiff to dismiss voluntarily an ‘action,’ but does not apply when a plaintiff seeks to dismiss some, but not all, of his or her claims.” The division also cited the Ninth Circuit’s decision in Hells Canyon Preservation Council v. U.S. Forest Service, 403 F.3d 683, 688 (9th Cir. 2005), which held that Rule 15(a) is the appropriate mechanism when a party desires to eliminate one or more but less than all claims without dismissing as to any defendant, and the Seventh Circuit’s decision in Taylor v. Brown, 787 F.3d 851, 857 (7th Cir. 2015), which reaffirmed that Rule 41(a) “does not speak of dismissing one claim in a suit; it speaks of dismissing ‘an action.’”

Applying these authorities, the division held that, because Thorpe did not seek to dismiss all of her counterclaims, the district court applied the incorrect legal standard by treating her Rule 15(a) motion as a Rule 41(a)(2) motion.

The Error Was Not Harmless

The division emphasized that this misapplication was not harmless because the standards differ in a meaningful way. Rule 15(a) requires that leave to amend “shall be freely given when justice so requires,” and the court must deny amendment only upon a showing of “undue delay, bad faith, undue prejudice, [or] futility of amendment.” By contrast, Rule 41(a)(2) does not contain this liberal standard. The division found that the district court’s stated reasons for denial—that the amendment would alter the case’s nature and potentially require new discovery—were insufficient under Rule 15(a)’s more permissive framework, particularly given that discovery had not yet closed, depositions had not occurred, and trial was months away.

The division further noted that even if Rule 41(a)(2) had been properly applied, the motion should still have been granted because voluntary dismissal “generally should be granted unless a dismissal would result in legal prejudice” to the other party. In this case, any prejudice could be ameliorated, including by treating Thorpe’s prior counterclaims as evidentiary admissions, but not as judicial admissions, noting that “[j]udicial admissions are conclusive, whereas evidentiary admissions may always be contradicted or explained.”

The division reversed the district court’s judgment and remanded for a new trial.

Significance

English v. Thorpe resolves a previously open question in Colorado procedure and establishes a clear rule: when a party seeks to eliminate some but not all claims against an opposing party, the motion is properly brought and evaluated under C.R.C.P. 15(a)’s liberal amendment standard, not C.R.C.P. 41(a)(2)’s dismissal framework. Practitioners should be aware that this holding applies to both claims and counterclaims; the division rejected the argument that counterclaims should be treated differently from claims under Rule 41. The decision underscores that Rule 15(a)’s policy of freely granting amendments applies with full force when a party seeks to narrow, rather than expand, the issues in a case.

The case is English v. Thorpe, 2026 COA 29, ___ P.3d ___. The decision was authored by Judge Schutz with Judges Freyre and Brown concurring.

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

On April 6, 2026, the Colorado Supreme Court unanimously ruled that an attorney does not violate Colorado Rule of Civil Procedure (“C.R.C.P.”) 11(a) merely by copying information, including allegations, from complaints in lawsuits involving some of the same defendants, as long as the attorney conducts “a sufficient investigation to support the allegations contained in the complaint, at least on information and belief.” The court cautioned, however, that the sufficiency of that investigation is highly fact dependent.

Accordingly, a plaintiff’s incorporation of allegations from related actions does not alone violate Rule11(a) and must instead be evaluated in the context of each case.

Background

In 2018, plaintiff Dean Houser filed a securities class action against CenturyLink, Inc. and several of its current and former officers and directors. Houser alleged that CenturyLink’s offering documents issued in connection with its merger with another company were false and misleading because they contained material omissions regarding systemic and ongoing illegal “cramming” practices—the unauthorized addition of services to customer accounts. Hauser later filed a notice of supplemental authority, citing a parallel securities fraud class action lawsuit pending in federal court in Minnesota.

The district court initially dismissed Houser’s complaint, but a division of the court of appeals reversed in part, granting Houser leave to amend his complaint. The division cautioned that if Houser desired to use allegations made by a party in a separate lawsuit, he must plead borrowed allegations “as facts, not as allegations by someone else, and must do so only after reasonable inquiry as required by C.R.C.P. 11.”

Houser filed an amended complaint incorporating additional allegations from several related proceedings, including a Minnesota Attorney General lawsuit and a whistleblower action.

Defendants moved to dismiss, arguing that Houser had “simply plagiarized” complaints without speaking to confidential witnesses or independently verifying the underlying allegations. The district court agreed and dismissed the amended complaint. A division of the court of appeals again reversed, concluding that Rule 11(a) does not require counsel to speak directly with confidential witnesses whose allegations are incorporated from related complaints.

The Supreme Court’s Analysis

The Supreme Court affirmed, rejecting defendants’ contention that counsel must personally interview witnesses before incorporating their allegations from related proceedings.

Reviewing the civil rules, the Court noted that a complaint need only provide “a short and plain statement of the claim showing that the pleader is entitled to relief,” C.R.C.P. 8(a)(2), and that allegations may be made “upon information and belief” when a pleader lacks direct knowledge, C.R.C.P. 8(e)(1).

Under C.R.C.P. 11(a), an attorney’s signature certifies that, after reasonable inquiry, the pleading is well grounded in fact and warranted by existing law. An attorney may violate the rule by failing to conduct an objectively reasonable inquiry before signing (bad faith is not a prerequisite for a violation). The Court observed that C.R.C.P. 11(a) “personalizes the responsibility of the attorney who certified the pleading” and “safeguards the judicial process by compelling attorneys to submit pleadings which are truthful and advance meritorious legal arguments.”

Surveying federal case law interpreting the analogous Fed. R. Civ. P. 11, the Court observed that courts have reached varying fact-specific conclusions. The Court declined to adopt a bright-line rule requiring counsel to speak with confidential witnesses before copying their allegations from related litigation, reasoning that it “simply may not be possible for counsel to do so” and that such a requirement would dramatically raise the pleading standard.

Applying these principles, the Court agreed that Houser’s counsel had conducted a sufficient inquiry. Specifically, Houser’s counsel had spoken with plaintiffs’ counsel in related cases; reviewed publicly available filings, state attorneys general investigations, SEC filings, press releases, earnings calls, and analyst and media reports; and attached affidavits from four named customers. These efforts, the Court found satisfied C.R.C.P. 11(a)’s reasonable inquiry requirement.

Implications

The Court emphasized that its holding does not permit plaintiffs to “wholesale copy complaints from other lawsuits without personally investigating the facts alleged in them,” reiterating that the civil rules mandate a reasonable investigation. The Court also rejected the suggestion that its decision would cause securities class actions to skyrocket in state courts, expressing confidence that trial courts will continue to serve as appropriate gatekeepers.

The opinion was authored by Justice Richard L. Gabriel.

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

On April 6, 2026, the Colorado Supreme Court held in Ralph L. Wadsworth Construction Co., LLC v. Regional Rail Partners, 2026 CO 19, that subcontractors on public projects may seek recovery of disputed or unliquidated amounts—including delay and disruption damages—in verified statements of claim under the Public Works Act. The Court also clarified that the penalty for filing an excessive claim is forfeiture of statutory remedies only, leaving common law claims available.

The Colorado Public Works Act

Because government property cannot be subjected to mechanics’ liens (the security interest contractors typically use on private projects), Colorado enacted the Public Works Act to give contractors and subcontractors analogous protections on public projects. Under section 38-26-107(1), C.R.S. (2025), a party that has furnished labor, materials, or equipment for a public project may file a “verified statement of claim”—i.e., a statutory lien—against retained contract funds held by the public entity. The public entity must then withhold sufficient funds until the claim is resolved. As a safeguard against abuse, section 38-26-110(1) provides that a claimant who files an “excessive” claim—one for more than the amount due, with no reasonable possibility it was due, and with knowledge of that fact—forfeits certain rights and remedies.

A central question in Wadsworth was whether “disputed or unliquidated amounts”—sums whose value has not been finally determined or that are subject to genuine dispute—may be included in such a claim.

Background

In 2013, the Regional Transportation District (“RTD”) contracted with Regional Rail Partners to build the North Metro Rail Line, a $343-million public works project. Regional Rail Partners, in turn, subcontracted with Wadsworth for rail work. After the project experienced delays and disruptions, Wadsworth filed a verified statement of claim with RTD—the public contracting body required to receive such claims under the Act—for about $12.8 million it believed Regional Rail Partners owed it for labor, materials, and other project costs. Wadsworth then sued Regional Rail Partners and others; after a ten-day bench trial, the court found the claim was not excessive and awarded Wadsworth over $3.7 million, including delay and disruption damages, and over $1.9 million in unpaid construction funds.

A division of the Court of Appeals reversed, holding that that Wadsworth’s claim was excessive as a matter of law because it included disputed delay and disruption damages—amounts that, in the division’s view, a subcontractor may not include in a verified statement of claim because they had not yet been proven or agreed upon. As a consequence, the division concluded that Wadsworth had forfeited its entire claim—not just statutory remedies—including all legal avenues of recovery.

On appeal, the Colorado Supreme Court addressed two questions: (1) whether disputed or unliquidated amounts—including delay and disruption damages—may be included in a verified statement of claim, and (2) whether the penalty for filing an excessive claim forfeits all legal remedies or only statutory remedies under the Act.

The Colorado Supreme Court’s Holdings

The Court answered both questions in favor of the subcontractor.

First, the Court held that disputed and unliquidated amounts are permissible because the plain language of sections 38-26-107 and 38-26-110 does not prohibit claimants from including disputed or unliquidated amounts in a verified statement of claim. An amount may be disputed yet still have a “reasonable possibility” of being due, and reading the statute to bar all disputed amounts would undermine the Act’s protective purpose.

The Court further held that delay and disruption damages—the added costs for labor, materials, and equipment incurred because of project delays or lost productivity—are permissible so long as they fall within the statute’s categories. However, purely consequential damages, such as lost profits or idle equipment time, may not be included.

Second, the Court held that forfeiture is limited to statutory remedies only and does not extend to common law claims (e.g., breach of contract). Finding section 38-26-110’s forfeiture language ambiguous, the Court looked to the parallel provision in the Mechanics’ Lien Act, § 38-22-128, C.R.S. (2025), and its legislative history. Both confirmed that the legislature intended to limit forfeiture to statutory rights and remedies only—not all legal remedies.The Court reasoned that stripping contractors of all avenues of relief would deter claimants from exercising statutory remedies at all, contrary to the Act’s purpose.

The Court remanded the case to the Court of Appeals for further proceedings on issues raised in Wadsworth’s cross-appeal.

Key Takeaways

This decision provides important guidance for participants in Colorado public works projects. Contractors and subcontractors may include disputed and unliquidated amounts—including delay and disruption damages—in a verified statement of claim, provided the amounts represent costs for labor, materials, or other supplies used in performing the work. Purely consequential damages, such as lost profits, may not be included. And even if a claim is later found excessive, the claimant forfeits only its statutory remedies under the Act. Common law claims, such as breach of contract, remain available.

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

Battery energy storage systems, or BESS, have become essential infrastructure for data center development. The data center industry’s global electricity consumption is set to surge by more than 300 percent by the end of this decade, according to several industry forecasts, and the grid cannot absorb that demand without dispatchable, flexible capacity at scale. Battery storage is no longer simply backup equipment at the edge of a data center’s power strategy. It is instead a primary tool for securing grid connections, managing the extreme power demands of artificial intelligence (AI) workloads, providing resilience, and meeting the clean energy commitments that operators have made to their boards, their customers, and their investors.

The numbers reflect the urgency. The U.S. Energy Information Administration projects that developers will add 24 GW of utility-scale battery capacity to the grid in 2026, up from the record 15 GW installed in 2025, with more than 40 GW deployed over the past five years. That growth is heavily concentrated: Texas, California, and Arizona together account for roughly 80 percent of planned 2026 additions. Texas leads with approximately 12.9 GW (over half the national total), driven by wind and solar balancing needs on the ERCOT grid and surging data center demand near Dallas and Houston. California, which has used batteries for years to manage peak evening loads and reduce reliance on natural gas peakers, is expected to add 3.4 GW.  Arizona is projected to add 3.2 GW.

While this alert focuses primarily on federal regulatory developments and the ERCOT market, where recent project activity provides a useful illustration, the financing, compliance, and structuring considerations discussed here apply across all major interconnection markets, including PJM, where data center load concentration is highest, and a December 2025 capacity auction revealed a 6,623 MW deficit at a record clearing price.

The legal and commercial landscape governing these assets has grown to match their strategic importance, and it shifted materially in 2025 and is shifting again in 2026. New federal rules under the One Big Beautiful Bill Act (OBBBA) have made supply chain compliance a condition of tax credit eligibility. A live FERC proceeding is poised to reshape the economics of co-located storage. Import tariffs have raised equipment costs by more than 50 percent since January 2025. Each of these developments creates obligations, opportunities, and risks that data center developers and operators, battery storage companies, project lenders, and energy transition investors will want to understand before their next transaction.

I. What BESS Does for a Data Center

The function a BESS performs in a data center context determines its contract structure, its financing treatment, and its regulatory classification. That function matters enormously, and establishing it clearly at the outset of a project is not a technicality. It determines which revenue streams are monetizable, what performance warranties are commercially appropriate, and how the asset is underwritten by lenders and equity investors.

Battery storage now performs four distinct functions for data centers: (1) regulating the massive power shifts common in AI training loads by enabling facilities to ramp from 10 percent to 90 percent capacity in milliseconds; (2) securing faster grid connections for data centers that install storage to guarantee demand response when requested by utilities; (3) providing resilience coverage for shorter grid outages; and (4) supporting long-term 24/7 carbon-free energy commitments for operators with clean energy goals. The fourth function, supporting 24/7 carbon-free energy commitments, has particular structural implications. Operators pursuing hourly matching rather than annual matching require storage sized and dispatched to cover every hour of load with verified clean energy, which produces fundamentally different cycling profiles, capacity requirements, and verification protocols from those of an annual renewable energy credit retirement. Agreements for hourly-matched storage need to address time-granular delivery obligations, measurement and verification standards, and the interaction between the BESS dispatch schedule and grid services revenue. An asset dispatched to fill hourly gaps in renewable generation may not be available for the ancillary services markets that support its merchant revenue, and agreements that do not account for that tension will underperform on one side or the other.

A BESS procured primarily to accelerate interconnection is a different asset legally, commercially, and financially from one procured for resilience, and both differ from one procured to monetize revenue for grid services. Lenders underwriting these assets benefit from that clarity before pricing the deal, and operators are well-served by establishing it before entering procurement.

The interconnection use case deserves particular attention, given where the market is moving. Aligned Data Centers recently agreed to pay to build a 31-megawatt battery as an explicit strategy to accelerate grid interconnection, making it one of the first data center operators to use storage as an interconnection tool rather than a power backup. That model is replicable across constrained markets nationally, and operators facing long interconnection queues may find it worth evaluating seriously before accepting delay as the only option.

A fifth configuration is emerging among operators that pair data centers with dedicated on-site generation rather than relying primarily on grid interconnection. In that model, storage stabilizes the output of co-located generation assets, manages load variability without grid dispatch, and provides ride-through capability during fuel supply or generation interruptions. The contract structures for these configurations differ materially from grid-connected models: the BESS is typically integrated into the generation facility’s operating agreement rather than procured separately, and the performance guarantees are tied to generation availability rather than grid service metrics. As more operators explore on-site power solutions to avoid interconnection delays, this configuration is likely to grow in commercial significance. Developers deploying behind-the-meter generation to power data centers while waiting two to four years for grid connections are finding that battery storage is not optional: without it, the mix of solar, gas, and diesel generation cannot deliver the power quality that data center loads require. Regardless of configuration, co-located BESS installations raise fire safety and thermal management considerations, including compliance with NFPA 855 and local fire code requirements, that affect siting, insurance, and the physical separation requirements between storage and computing infrastructure. These requirements are increasingly finding their way into offtake and site lease agreements as conditions of operation.

II. The Financing Environment

Energy storage remains central to grid reliability, renewable integration, and data center growth, and while capital deployment became more selective in 2025, investor interest in battery storage assets remained strong, particularly for late-stage and operational projects positioned for near-term execution. The market has matured in a healthy direction: it now rewards well-structured, de-risked transactions and prices speculative ones accordingly.

Three financing dynamics define the current environment and warrant attention from every party to a BESS transaction.

The first is that storage benefits materially from documentation as a distinct asset rather than an afterthought to a larger financing arrangement. Storage investment is increasingly embedded within broader energy and infrastructure transactions, and publicly reported M&A and financing data often does not distinguish between projects that include storage and those that do not. In practice, BESS assets are frequently under-documented: collateral descriptions are vague, insurance requirements do not specifically address storage risks, and lender consent provisions treat storage as ancillary equipment rather than a material project component. Transactions structured with storage explicitly identified, valued, and ring-fenced within the financing arrangement close with fewer surprises at the table.

That documentation challenge extends to the revenue structure. Lenders and equity sponsors increasingly distinguish between contracted and merchant revenue when sizing debt and pricing equity. A BESS with a tolling agreement or capacity contract supporting 60 to 70 percent of projected revenue is a fundamentally different financing proposition from one relying primarily on energy arbitrage and ancillary services. Where a project stacks multiple revenue streams, the complexity compounds: dispatch optimization must balance competing obligations across energy arbitrage, ancillary services, and capacity commitments, and the financing documents must define priority among those streams, allocate dispatch authority between the operator and the offtaker, and address the risk that regulatory changes to one market product may affect the economics of the others.

The second dynamic is that project-level acquisitions have roughly doubled. Approximately 45 reported energy storage project M&A transactions occurred during the first nine months of 2025, compared to roughly 22 during the same period in 2024, driven by buyers’ preference for de-risked assets with confirmed interconnection, permitting, and offtake. The exit market for storage platforms is liquid, and the debt markets are following. In January 2026, BlackRock’s Jupiter Power closed a $500 million senior secured green revolving loan to accelerate a 12,000 MW U.S. development pipeline. Construction began in March 2026 on a 203 MW project in the high-demand corridor between Dallas and Houston, with completion targeted for May 2027. Separately, in 2025, Lydian Energy closed a $233 million tax credit bridge facility backed by ING and KeyBank to support three battery projects, including two 200 MW / 400 MWh systems in Texas, representing a combined investment of approximately $139 million. Battery companies building data center market presence may wish to structure for eventual monetization from the first project, because institutional buyers have historically paid full value for confirmed interconnection, documented Foreign Entity of Concern (FEOC) compliance, and contracted revenue.

The third is that tariffs have raised costs materially and created potential contract exposure that parties to existing agreements may not have anticipated. Since January 2025, battery storage costs have risen an estimated 56 to 69 percent due to the Trump administration’s tariff policies, depending on configuration and sourcing. Those cost increases compound the capital intensity of an already infrastructure-heavy segment: Enbridge’s 600 MW Clear Fork Creek Solar and BESS project in Wilson, Texas, for example, represents an estimated $800 million combined capital investment for the full facility, and several standalone battery projects now under development in ERCOT exceed 400 MW apiece. Fixed-price supply agreements executed before this escalation may no longer reflect current economics, and force majeure, material adverse change, and price-adjustment provisions in those contracts are worth reviewing. New agreements that include explicit tariff pass-through mechanisms with defined limits are designed to address this exposure prospectively.

III. The FERC Large-Load Interconnection Proceeding

The most consequential active regulatory proceeding for everyone in this space warrants close attention, not because it is abstract policy, but because its outcome will directly affect the economics of BESS assets that are being procured and financed right now.

In October 2025, the U.S. Department of Energy (DOE) formally requested that the Federal Energy Regulatory Commission (FERC) assert jurisdiction over the interconnection of large electrical loads to the U.S. bulk electric transmission grid and to establish standardized interconnection procedures. DOE proposed April 30, 2026, as the target date for FERC’s final action. This proceeding builds on a series of FERC orders, including FERC’s conditional treatment of the Talen Energy-Amazon co-location structure and subsequent directives to PJM and SPP to develop formal frameworks for co-located loads, which have progressively defined how federal regulators approach the intersection of large load growth and transmission system access. DOE’s April 30 deadline is approaching, and its outcome will be operative for projects whose agreements are being negotiated today.

The central contested question is how transmission costs are allocated when generation or storage is co-located with a large load. Several hyperscalers have described co-location as a bridge solution until regulatory certainty improves. The specific positions vary: some have focused on willingness to pay for transmission services conditioned on unused capacity being excluded from cost allocations, while others have emphasized broader grid investment commitments tied to their clean energy procurement frameworks. How FERC reconciles these positions will determine the economics of BESS assets co-located with data center facilities, because transmission cost allocation directly affects grid services revenue, a primary component of return on invested capital for many storage projects. Agreements currently being negotiated with commercial operation dates in 2026 through 2028 will be operative under whatever rules FERC issues, and parties to those agreements may wish to consider provisions that contemplate a range of transmission cost allocation outcomes rather than assuming today’s rules will continue to persist.

IV. FEOC Compliance: The Issue That Now Governs Tax Credit Eligibility

The Prohibited Foreign Entity (PFE) rules under the OBBBA, operationalized by Internal Revenue Service (IRS) Notice 2026-15, issued February 12, 2026, are the single most consequential legal development in battery storage in 2026. They are in effect now, and every BESS beginning construction this year is subject to them.

The framework. A Prohibited Foreign Entity is generally an individual or entity with significant ties to China, Russia, North Korea, or Iran, or listed on certain U.S. government watch lists. A PFE cannot claim, sell, or purchase certain clean energy tax credits, and an energy storage facility that contains an excessive proportion of components produced by PFEs is ineligible for the Section 48E Investment Tax Credit (ITC) or Section 45Y Production Tax Credit (PTC).

The MACR test. Developers must calculate a Material Assistance Cost Ratio (MACR) for each energy storage technology for which they seek the ITC. For storage facilities beginning construction in 2026, the minimum threshold is 55 percent, meaning at least 55 percent of direct equipment costs must come from non-PFE sources. That threshold increases five percentage points annually, reaching 75 percent by 2030, which means that a supply chain configuration that clears the threshold in 2026 may fall short by 2028 without active management. The trajectory matters as much as the current number.

The cell problem. IRS safe harbor tables assign 52 percent of total direct cost to battery cells in certain grid-scale BESS configurations, and Chinese manufacturers control over 80 percent of the global battery cell and module supply chain. Most cells currently come from covered foreign nations, making MACR compliance the central procurement challenge for any developer seeking federal tax credits on a new BESS beginning construction in 2026. This is the commercial reality for every BESS transaction, and it requires an active supply chain strategy rather than passive compliance.

The recapture exposure. If disqualifying payments to a specified foreign entity are made within 10 years after a facility is placed into service, the taxpayer must repay the entire value of the previously claimed tax credit. On a large BESS project claiming a 30 percent ITC with bonus adders, that can be a nine-figure contingent liability sitting in the capital structure for a decade. Lenders will want to model it as a contingent obligation, and some are already requiring reserves, escrows, or insurance wraps as conditions of financing. On the commercial side, offtake and supply agreements benefit from explicit allocation of this exposure between parties, with indemnification provisions that reflect the full recapture risk rather than just the incremental cost of a future supply chain swap.

The monetization path for the ITC itself also warrants attention. Internal Revenue Code (IRC) Section 6418 transfer elections allow project owners to sell tax credits directly to unrelated buyers, which has become a preferred structure for many sponsors. Where the project owner retains the credits instead, the combination of the ITC with Modified Accelerated Cost Recovery System (MACRS) depreciation remains a central component of the equity return. The PFE recapture framework applies directly to the tax credits, but a recapture event can also disrupt the broader tax structure in ways that affect the depreciation assumptions underlying the equity model. Transferability, moreover, does not eliminate recapture risk for the transferee, and credit purchase agreements that do not allocate PFE-related recapture exposure with the same specificity as the underlying supply agreements may leave the credit buyer holding a contingent liability that it did not price at closing.

What compliance involves in practice. Each containerized BESS combines battery modules, enclosures, thermal systems, inverter assemblies, and electronic controls, each of which can introduce PFE exposure at different points in the supply chain, and top-level entity certifications from manufacturers are generally not sufficient to establish compliance. Supply agreements that require component-level sourcing disclosure, per-product MACR calculations tied to the cost tables in IRS Notice 2026-15, and manufacturer certification obligations that survive ownership changes and supply chain restructurings provide meaningfully stronger protection. Until the safe harbor tables promised by the OBBBA are published (due December 31, 2026), taxpayers may rely on IRS Notice 2025-08 tables and supplier certifications, provided they do not have actual knowledge that a certification is inaccurate. That carve-out requires active supply chain management and real traceability protocols, not passive reliance on a folder of manufacturer paperwork that no one has verified against the actual component list. The market’s response to these rules has been telling: industry analysts tracked at least 10 GW of storage projects that began construction before year-end 2025 specifically to safe-harbor under the prior regime and avoid FEOC compliance entirely. That volume underscores both the difficulty of meeting the new thresholds and the competitive advantage available to developers who can.

V. The Data Center Market: What Battery Companies Should Consider

Most battery storage companies have built their businesses around utility-scale grid applications. The data center segment is structurally different and presents both genuine opportunity for companies willing to develop the right capabilities and real commercial risk for those that apply utility-market assumptions without adjustment.

A threshold point is worth stating clearly: the utility-scale BESS projects now proliferating across ERCOT and other markets are grid assets, not data center assets. They are dispatched into wholesale energy and ancillary services markets, and the data centers driving regional load growth are, for now, indirect beneficiaries rather than direct offtakers. But the trajectory is toward convergence. Battery storage has emerged as a critical tool for managing congestion and reliability challenges associated with data center development and rapid load growth, particularly in constrained interconnection markets. Several of the largest standalone battery projects advancing toward commercial operation in 2026 and 2027 are sited in ERCOT, where proximity to rapidly expanding data center clusters near Dallas and Houston creates both merchant revenue opportunities and potential behind-the-meter offtake structures for co-located facilities. The revenue dynamics differ by market: ERCOT’s energy-only design rewards price volatility; California’s Resource Adequacy framework provides a contracted capacity floor that can represent 30 to 40 percent of a storage project’s annual revenue; and PJM’s recent capacity price spike signals an acute need for new dispatchable resources. As interconnection constraints intensify and co-location frameworks take shape under the FERC proceeding discussed in Section III above, the line between grid-serving and load-serving storage is likely to blur, and battery companies positioned on the utility-scale side of that line today will want to be ready when it does.

That said, data center customers are not utility procurement teams. The largest AI infrastructure operators are sophisticated counterparties with experienced in-house counsel and procurement staff who have structured large, complex infrastructure transactions before. Standard utility offtake agreements will not serve either party well in that context, and battery companies that arrive at the table with utility-market templates will find themselves renegotiating from the start.

What this market rewards, and what utility storage does not, includes discharge profiles and cycling tolerances tuned to AI training load ramps, performance guarantees expressed in terms that align with data center uptime standards rather than grid dispatch metrics, FEOC-compliant supply chain documentation ready at signing (because tax credit eligibility is a closing condition, not a post-closing diligence item), and financing structures that treat storage as long-term infrastructure rather than commodity equipment with a short replacement cycle. New battery cell chemistries resilient to the cycling demands of AI training loads are being developed specifically to target this use case, and companies developing or deploying those chemistries with clean supply chains to match are well-positioned to establish preferred vendor relationships before the segment consolidates around a smaller number of proven counterparties.

Companies with proven unit economics and operational track records are accessing debt markets and specialized industrial financing, marking the transition from startup funding to heavy industry capital structures. Battery companies entering the data center segment with a view toward eventual monetization are well-served by building institutional financing track records beginning with their first deal in this market. The buyers who pay full value for storage platforms want operating history, documented compliance, and contracted revenue. The time to build that foundation is at the beginning of the platform, not after several transactions have closed without it.

VII. Technology Trends That Affect Agreement Structure

The battery technology stack is evolving fast enough that agreements drafted without flexibility may be commercially disadvantaged well before their expiration dates, and the technology choices being made today have direct implications for FEOC compliance and long-term contract performance.

The industry is moving toward greater technology diversity, with longer-duration storage shifting from a niche solution to a strategic necessity as AI-driven load growth continues. Two developments in particular deserve attention from parties structuring BESS agreements for data center applications.

Silicon-anode batteries are emerging as the performance answer to AI’s specific power demand profile. The near-instantaneous power response required by AI-enabled servers overwhelms traditional lithium-ion technology, and silicon-anode cells’ extreme fast-discharge capability directly addresses this constraint. Supply agreements that lock operators into lithium-ion specifications for 10- to 15-year terms may benefit from technology substitution rights: explicit provisions allowing migration to superior chemistries as they reach commercial scale, without requiring full renegotiation of the underlying agreement. Regardless of chemistry, all BESS assets degrade over time, and agreements with long-term capacity guarantees should include augmentation provisions that specify the timing, cost allocation, and performance testing protocols for capacity replenishment, particularly where the BESS supports uptime commitments that do not tolerate degradation-driven shortfalls.

Sodium-ion alternatives address both the performance question and the FEOC compliance problem simultaneously. FEOC regulations and global mineral pressures are driving renewed interest in non-lithium, FEOC-safe chemistries, and sodium-ion batteries avoid the Chinese-dominated lithium and cobalt supply chains that make MACR compliance difficult. Chemistry-agnostic procurement specifications (rather than lithium-specific technical requirements) reduce FEOC risk, preserve access to a broader and improving supplier base, and give operators the flexibility to benefit from cost declines in alternative chemistries as they mature.

VII. Considerations for Developers, Operators, Lenders & Battery Companies

Several issues are worth addressing actively rather than allowing to accumulate.

• Existing BESS supply agreements merit review for tariff pass-through provisions, force majeure coverage, and PFE representations, particularly those executed before July 2025 when the OBBBA took effect;
• Modeling MACR exposure before signing new procurement contracts is advisable, given that the 55 percent threshold for 2026 facilities is the floor and the path to 75 percent by 2030 means today’s sourcing decisions carry consequences through the decade;
• The FERC large-load interconnection rulemaking appears to be moving forward, with final action expected as early as April 30, 2026, and agreements now being negotiated may benefit from provisions that contemplate a range of transmission cost allocation outcomes;
• Requiring component-level supply chain disclosure in procurement agreements, rather than entity-level certifications alone, provides substantially more durable FEOC compliance protection;
• Credit purchase agreements under IRC Section 6418 transfer elections warrant the same PFE-related recapture allocation as the underlying supply agreements, particularly where the credit buyer has not independently verified the project’s MACR compliance;
• BESS agreements supporting hourly carbon-free energy commitments should address the tension between time-granular delivery obligations and ancillary services availability, because dispatch profiles for hourly matching differ materially from those optimized for merchant revenue;
• Operators pairing data centers with dedicated on-site generation should expect BESS contract structures that integrate storage into the generation facility’s operating agreement rather than treating it as a standalone procurement, with performance guarantees tied to generation availability; and
• Battery companies building data center market presence are well-served by investing early in the commercial infrastructure this customer segment requires, including tailored offtake structures, AI-workload performance guarantees, and FEOC documentation protocols ready at signing, rather than adapting utility-market contracts after the customer conversation has already begun.

VIII. Conclusion

Battery storage for data centers has become a project finance, regulatory compliance, and supply chain management challenge as much as it is a procurement decision, and the FEOC rules, the FERC interconnection rulemaking, the tariff-driven cost increases, and the shifting technology stack have made this a more complex environment than it was 18 months ago. With 24 GW of new capacity expected in 2026 alone and major project financings closing at a pace that would have been difficult to imagine even two years ago, the opportunity for well-positioned developers, operators, and their advisors to establish durable competitive advantages in this segment has never been larger, or more time-sensitive.

This alert is intended to provide a general overview of the financing, regulatory, and structuring considerations relevant to battery storage for data center applications. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

RJ Colwellis a senior associate at Davis Graham & Stubbs LLP in the Energy & Mining Group. His practice focuses on the intersection of battery storage, data center infrastructure, and energy regulatory compliance, advising data center developers, power generation companies, battery storage companies, and their investors and lenders on transaction structuring and regulatory matters. For questions about the above article or data center considerations, please contact RJ Colwell or a member of the Davis Graham Data Center Group .

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On March 26, 2026, a unanimous division of the Colorado Court of Appeals ruled that a state or local government does not violate Colorado’s Taxpayer Bill of Rights (“TABOR”) by imposing a regulatory fee on short-term rentals.

In Dorotik v. Town of Breckenridge, 2026 COA 20, the division considered whether a charge on short-term rental owners enacted by the Town of Breckenridge violated TABOR. The division concluded that it did not.

In 1992, voters amended the Colorado Constitution to add TABOR, which requires state and local governments to receive voter approval prior to implementing a new tax. Taxes enacted without the requisite approval are invalid.

In 2021, Breckenridge passed Ordinance No. 35, which charged owners a fee to obtain or renew a short-term rental license. The ordinance’s purpose was to “defray the costs of housing policies and programs for the local workforce essential to the [t]ourism economy that benefits the short-term rental licensees.” After hiring a consultant and considering the data regarding guest spending and demand for affordable housing for the local workforce, Breckenridge landed on a license fee of $756 per short-term rental bedroom.

A short-term rental owner in Breckenridge sued the town to challenge the fee. He argued that the fee constituted an impermissible tax that generated excess revenue for the town and which had not been properly approved by voters pursuant to TABOR, as laid out in article X, section 20(4)(a) of the Colorado Constitution.

The trial court dismissed the suit, reasoning that Ordinance No. 35 was not a tax because its purpose “is to protect the public’s health, safety, and welfare and it labels the charge as a fee.” Additionally, the primary purpose of the charge is to defray the costs of “administering [Breckenridge’s] regulatory scheme,” not to raise revenue for general government expenses.

On appeal, the division affirmed the trial court’s dismissal.

Reviewing Breckenridge’s Ordinance No. 35, the division considered whether the town was exercising its legislative taxation power or its regulatory police power. The Colorado Supreme Court has defined taxes as charges “that raise revenues for general municipal purpose.” But municipalities can also regulate activities pursuant to their inherent police powers “to promote the health, safety, and welfare of its citizens” without taxpayer approval under TABOR. The key inquiry is whether the regulatory charge “is imposed as part of a comprehensive regulatory scheme and its primary purpose is to defray the reasonable direct and indirect costs of providing a service or regulating an activity under that scheme.” (Alterations omitted.)

First, Ordinance No. 35’s stated purpose, the division held, clearly outlined its intent to defray the costs of its programs to support the local workforce and to address the secondary impacts of the short-term rental industry. And while its label doesn’t necessarily make it “regulatory fee,” the municipality’s intent cannot be ignored.

Second, in considering the practical realities of the charge’s operation, the division analyzed “how the charge operates to determine if [it] is in fact imposed to defray the direct or indirect costs of regulation and if the amount of the fee is reasonable in light of those costs, or if the charge’s primary purpose is to raise revenue for general governmental use.” Here, the charge was fixed in the Town’s annual budget process and is separately accounted. The ordinance also restricts funds from being used for “general municipal or governmental purposes of spending.” Ordinance No. 35 also requires that the funds be spent on Breckenridge’s “housing policies and programs,” the “secondary impacts caused by the [short term rental] industry,” and to defray the costs of administrating the program. These practical realities indicate, the division held, that the charge is a fee, not a tax.

Third, the division rejected the argument that the charge must be a tax because it generates additional revenue from short-term rental guest spending on hospitality and recreation. It pointed to the Town’s consultant, who concluded that Breckenridge would have to charge $2,161 per short-term rental bedroom to defray the short-term rental impact on local housing, and that the Town set the fee at a fraction of that—$756. The division analogized to regulatory fees imposed on the sales of plastic bags and marijuana while separately taxing the products. Further, the “touchstone” of the fee analysis is whether “the charge b[ears] a reasonable relationship to the direct or indirect costs of the government providing the service of regulating the activity.” So, the division concluded, the revenue positive activity of the short-term rental charge did not violate TABOR.

The opinion was authored by Judge Kuhn, Judges Dunn and Lipinsky concurring.

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

By RJ Colwell and James Rees

Texas is the epicenter of AI data center development in the U.S. – and water is emerging as a critical variable in project siting, permitting, and long-term operational resilience. This alert examines the scale of data center water demand in Texas, the regulatory developments bringing new transparency to the issue, the legal framework governing water rights and supply, the water stewardship commitments redefining social license for large industrial users, and the technology and investment landscape positioning Texas to lead in water-efficient infrastructure.

The Convergence

Texas has always been where big things get built. The state’s pro-business regulatory environment, abundant land, deep energy expertise, and world-class research institutions made it the capital of the global oil and gas industry. Those same attributes are now making it the default destination for what may be the largest infrastructure buildout of the next decade: artificial intelligence data centers.

But data centers need more than land and power. They need water – large quantities of it – primarily to cool the servers that process AI workloads. A single gigawatt of data center capacity, together with its co-located power generation, requires 10-21 million gallons of water per day. Multi-gigawatt campuses – the scale that hyperscalers like Google, Microsoft, Amazon AWS, and Meta are now planning across Dallas-Fort Worth, San Antonio, and West Texas – multiply that demand. And Texas, for all its advantages, is a state where water has never been taken for granted. The companies and investors who will build most successfully here will treat water not as a constraint to work around but as a strategic asset to plan for from the outset.

The Numbers

The scale of the water question is now well documented. In January 2026, the Houston Advanced Research Center (HARC) published a white paper titled Thirsty Data and the Lone Star State: The Impact of Data Center Growth on Texas’ Water Supply. HARC found that existing data centers in Texas consume an estimated 25 billion gallons of water annually through both direct use (primarily cooling) and indirect use (primarily the water consumed by the power plants that supply their electricity). By 2030, depending on the pace of construction and the cooling technologies adopted, that figure could rise to between 29 billion and 161 billion gallons per year – potentially representing up to 2.7% of total statewide water use.

Those numbers deserve context. At the state level, data center water consumption remains a small fraction of total use. Agriculture, municipal supply, and oil and gas operations are far larger consumers. But data center water use is geographically concentrated – clustered in the Dallas-Fort Worth metroplex, Houston, San Antonio, Austin, and West Texas – and it is growing rapidly in regions that already face competing demands on limited water resources.

Texas faces a projected 290 billion-gallon annual water deficit by 2050, and industrial water demand is expanding roughly three times faster than municipal demand. Against that backdrop, a rapidly growing new category of industrial water user – one that operates around the clock and requires high-reliability supply – demands serious planning.

The Regulatory Landscape

Texas regulators are paying attention, and they are approaching the issue in a pragmatic fashion. In February 2026, the Texas Public Utility Commission (PUC) announced that it would survey data centers and cryptocurrency mining facilities statewide on their water usage this spring. The survey – authorized through a budget rider authored by State Representative Armando Walle – will collect information on direct water use, cooling technology, and indirect water consumption through power generation. Facilities will have six weeks to respond, and the results will be shared with the Texas Water Development Board (TWDB) and the Texas Commission on Environmental Quality (TCEQ) to inform future planning.

Representative Walle described the survey as a “softer approach” – gathering data before legislating. That framing reflects a broader opportunity: Texas can shape how data center water use is managed proactively, rather than reactively. The companies that are already prepared with transparent water data and efficient operations will be best positioned as planning translates into policy.

Separately, TCEQ is drafting permits for commercial-scale produced water treatment and discharge – a regulatory milestone that, if finalized, would unlock one of the largest alternative water supply sources in the state for beneficial reuse in data center cooling, power generation, and agriculture.

For developers and investors, the legal landscape adds complexity that rewards early engagement. Texas water law operates under a bifurcated system. Surface water is governed by the prior appropriation doctrine – essentially, first in time, first in right – and is administered by TCEQ through a permitting process. Groundwater, by contrast, is governed by the Rule of Capture, as modified by local groundwater conservation districts that set their own production limits and permitting requirements.

The specific rules governing groundwater production vary significantly from district to district. Some have adopted regulations that effectively cap large-scale industrial withdrawals; others are more permissive. The landmark Texas Supreme Court decision in Edwards Aquifer Authority v. Day (2012) confirmed that landowners have a constitutionally protected ownership interest in groundwater beneath their property – but also affirmed the state’s authority to regulate production through conservation districts. For a developer evaluating multiple candidate sites, the practical consequence is that water availability is not merely a hydrological question; it is a legal question that turns on the specific rules of the district where the site is located.

Community dynamics matter too. Data centers bring construction jobs, tax revenue, and technology investment. But when a community perceives that a new facility will strain its water supply, support can erode quickly. Proactive engagement and transparent water planning are not just good corporate citizenship; they are a practical component of permitting strategy.

Social License Requires Investment: The Hyperscaler Water Positive Playbook

The world’s largest hyperscalers – Google, Meta, Amazon AWS, and Microsoft – are facing mounting public scrutiny over how much water their data centers and business operations consume. Each has made commitments to become “water positive” by 2030, promising to return more water to local basins than it consumes. Water stewardship is moving quickly from voluntary commitment to operating requirement, and the emerging hyperscaler playbook is likely to set the benchmark against which all large industrial water users in Texas will be measured.

Microsoft has already invested in more than 76 water replenishment projects globally. Google has committed to replenishing 120% of the water it consumes, on average, across its offices and data centers. Amazon AWS prioritizes exhausting on-site efficiency first and then achieving water positivity by returning more water to communities than it uses in direct operations. Meta has committed to restoring 200% of its water consumption in regions where water scarcity is highest.

Each of these programs is designed not just to offset internal consumption, but to build social license – demonstrating to regulators, groundwater conservation districts, and host communities that data center operations will improve, not degrade, local water security.

Those investments are already showing up in Texas watersheds. Google is contributing $2.6 million to Texas Water Trade to create and enhance up to 1,000 acres of wetlands along the Trinity-San Jacinto Estuary, a project expected to return 300 million gallons of freshwater annually to the watershed.

Beyond replenishing water through nature-based projects, the hyperscalers are investing in a parallel portfolio of technology-driven efficiency solutions: data-driven pressure management to reduce non-revenue water losses at utilities (an issue that costs Texas an estimated 88 billion gallons in a single year from aging infrastructure), advanced leak detection, smart irrigation, and real-time pipe network monitoring. Together, these form a replicable blueprint for closing Texas’ water gap at scale.

The common thread is that the investments are not charitable donations. They are strategic, verified, and bankable. Water saved or returned is independently verified against each company’s consumption footprint and credentialed under industry frameworks. Collectively, these commitments are setting a market expectation that any large industrial water user in Texas demonstrate minimal environmental and community impact. Those developers and investors who align early with this expectation will find a smoother path to permitting, financing, and long-term operational stability.

The Solutions Are Here – and They Are Centered in Texas

This is where the story turns from challenge to competitive advantage. Texas is not only consuming water at an industrial scale; it is also home to a growing ecosystem of institutions and companies developing the technologies and strategies to use water more efficiently – and, increasingly, to reduce dependence on freshwater altogether.

Rice University’s WaTER Institute, launched in 2024, leads cutting-edge research at the intersection of water technology, public health, and energy infrastructure. The institute’s work spans destruction of per- and polyfluoroalkyl substances (PFAS, the persistent “forever chemicals” found in many water supplies), advanced membrane technologies for desalination and wastewater reuse, and decentralized water treatment systems that can be deployed at the facility level. These are not theoretical capabilities. They are technologies moving from the laboratory to commercial deployment, with direct applicability to data center and power generation operations.

In September 2025, Rice’s WaTER Institute and Noverram co-hosted the Water Nexus Conference during Houston Energy and Climate Week, bringing together researchers, entrepreneurs, investors, end users, and policymakers. One of the key themes of that gathering was the scale of the infrastructure investment opportunity. McKinsey & Company’s Sarah Brody, who delivered the keynote, pointed to a growing water infrastructure funding gap – projected to reach $195 billion by 2030 – but stressed that nearly half of it could be closed through innovative technologies, capital structuring, and operational efficiency.

The technology options available to data center developers today are real and commercially proven. Closed-loop cooling systems can reduce freshwater consumption by up to 70%. Direct-to-chip cooling – a method that circulates coolant directly across server processors rather than cooling the ambient air – can reduce water use by 20% to 90%, depending on system design and climate, while also lowering facility power requirements. Immersion cooling, which submerges servers in non-conductive fluid, eliminates evaporative water use entirely. And brackish water desalination and treated wastewater reuse can provide alternative supply sources that do not compete with municipal freshwater.

Produced Water: Texas’ Unconventional Competitive Advantage

For oil and gas companies, there is an additional and underappreciated angle: produced water. The Permian Basin alone produces roughly 840 million gallons of water per day – a volume that dwarfs the cooling demand of even the most ambitious data center campuses. That water, historically a waste stream requiring expensive saltwater disposal, is becoming a feedstock. Operators already face rising disposal costs and, in some areas, over-pressured injection capacity that may run out of room entirely by the late 2020s. The economics of treatment and disposal are converging: as disposal costs rise and desalination technology costs decline, the business case for treating produced water to beneficial-reuse specifications is approaching parity – and in some configurations may already pencil out.

The treatment pathway is well understood. Multistage processes – pre-treatment to remove oils, greases, iron, and suspended solids; membrane-based desalination (including osmotically assisted reverse osmosis and vacuum membrane distillation); and post-treatment polishing for residual contaminants like ammonia and boron – can take raw produced water from salinity levels of 130,000 to 150,000 milligrams per liter down to less than 200 milligrams per liter, a specification clean enough for data center cooling, power generation, and agricultural irrigation.

The infrastructure to aggregate that water already exists. Midstream companies have built thousands of miles of gathering pipelines across the Delaware and Midland basins to collect produced water from multiple operators and deliver it to centralized locations – infrastructure originally built for disposal that can be repurposed to feed commercial-scale treatment plants.

If several gigawatts of data center capacity are sited in the Permian, the combined cooling and power generation demand could reach 42 million to 84 million gallons per day – a meaningful fraction of the basin’s produced water output, but well within the available supply. For operators, this transforms a disposal liability into a revenue-generating resource. For data center developers, it provides a non-freshwater supply source with the volume and reliability that large-scale operations require. For the communities and agricultural users that share these basins, it reduces the pressure on limited freshwater aquifers.

Pilot projects are already underway, and early results from agricultural growth studies using treated produced water show that soils and crops respond favorably – opening a pathway to beneficial reuse that extends beyond data centers to food production and environmental restoration. The companies and investors positioned at this intersection of oil and gas water management, desalination technology, and data center infrastructure are sitting on the most compelling convergence opportunity in Texas today.

For developers evaluating alternative water sources – whether produced water, treated municipal wastewater, or brackish groundwater – the regulatory pathway involves additional permitting considerations. The use of reclaimed water for industrial cooling is generally permissible under Texas law, but it requires coordination with the wastewater treatment provider, compliance with TCEQ’s reclaimed water quality standards, and, in some cases, additional discharge permits for blowdown water or other process streams. These requirements are well understood and manageable, but they must be incorporated into the project timeline from the outset rather than addressed as an afterthought.

What Smart Capital Is Doing Now

Understanding the technology is important, but technology alone does not make a project water-resilient. The developers and investors who are getting this right treat water as a planning discipline – integrated into project design, legal structuring, and due diligence from the earliest stages. The goal is not to check an environmental, social, and governance (ESG) box. It is to manage an operational and financial variable that affects site selection, construction timeline, operating cost, and community relations.

In practice, that means conducting water availability and stress assessments as part of site due diligence and structuring water supply agreements with long-term security provisions that account for competing demands. It means evaluating cooling technology choices through a total-cost-of-ownership lens that includes water, not just energy efficiency; engaging with groundwater conservation districts and local water authorities before announcing a project; and building water efficiency commitments into project finance documents and tenant agreements. It also means evaluating produced water supply agreements and desalination partnerships in site selection in basins where that option is available – particularly in West Texas, where the convergence of natural gas supply, produced water volume, land availability, and workforce creates a uniquely favorable development profile.

For investors evaluating data center projects or portfolios, water risk is increasingly a factor in both asset-level underwriting and portfolio-level risk assessment. Projects sited in water-stressed regions without robust supply agreements or efficient cooling technology may face operational constraints, higher long-term costs, or community opposition that delays development. Conversely, projects that demonstrate water resilience – through technology selection, supply diversification, water positive commitments, and proactive community engagement – may command a premium in an increasingly risk-aware capital market.

Scaling water technology solutions comes down to three interdependent factors: the strength of the team, the viability of the technology, and a clear understanding of the market need. All three are present in Texas today – in Houston’s energy corridor, in Rice’s research labs, in the Permian Basin’s produced water infrastructure, and in the growing ecosystem of water technology startups and the investors backing them.

Texas built the modern energy economy. It is now building the AI infrastructure economy. The companies and investors who ensure it also leads in water resilience hold the most durable competitive position – and the legal, strategic, and technological tools to achieve that are available right now. The window to build that advantage is open. It will not stay open indefinitely.

This alert is intended to provide a general overview of the legal, regulatory, and strategic considerations relevant to water management in Texas data center and energy infrastructure projects. 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. He advises energy companies, data center developers, and investors on transactions, regulatory compliance, and project structuring across Texas and beyond. His practice spans energy and water infrastructure transactions, produced and recycled water, and the regulatory pathway for alternative water sources in large-scale energy and data center projects. RJ can be reached at rj.colwell@davisgraham.com.

James Rees is a Director of Noverram, a consulting firm providing strategy and capital advice for water and sustainability-focused companies, and a collaborator with Rice University’s WaTER Institute. Bridging management consulting and financial markets, he advises corporations, investors, and technology companies on strategy, impact projects, and capital structures that turn water resilience into competitive advantage. James can be reached at james@noverram.com.