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.

On March 12, 2026, a division of the Colorado Court of Appeals issued a significant opinion concerning federal preemption, aviation law, and environmental nuisance. In Town of Superior v. Board of County Commissioners of Jefferson County, 2026 COA 14, the division held that federal law preempts a state court from ordering an airport proprietor to ban certain aircraft operations as a noise abatement measure, even though the proprietor itself retains the authority to impose such restrictions voluntarily. The division remanded the case for further consideration regarding whether the federal Clean Air Act separately preempts the plaintiffs’ claim for injunctive relief to abate lead emissions from aircraft.

Background

The Town of Superior and the Board of County Commissioners of Boulder County (together, the “Plaintiffs”) sued the Board of County Commissioners of Jefferson County and the Airport Director of the Rocky Mountain Metropolitan Airport (the “Airport”), alleging that certain aircraft operations at the Airport caused excessive noise and hazardous lead exposure for their residents. Specifically, Plaintiffs challenged nearby “touch-and-go” operations—a common flight training maneuver in which an aircraft lands and immediately takes off again without stopping—performed by piston-engine aircraft, a type of small plane that typically uses leaded fuel. As alleged by Plaintiffs, these touch-and-go maneuvers result in excessive noise and hazardous lead exposure because the aircraft, when performing such maneuvers, fly at lower altitudes and at lower speeds than they otherwise would.

Plaintiffs brought a public nuisance claim and sought an injunction requiring Jefferson County to prohibit touch-and-go operations by piston engine aircraft at the Airport. Jefferson County moved to dismiss under C.R.C.P. 12(b)(5), arguing that federal law preempts state and local regulation of aircraft operations, noise levels, and emissions. The district court granted the motion, concluding that federal law preempts any local or state limitation on aircraft flight operations, including limitations on noise abatement or lead pollution.

The Division’s Federal Preemption Analysis

On appeal, a division of the Colorado Court of Appeals reaffirmed the well-established principle that federal law preempts state and local regulation of aircraft noise. Under City of Burbank v. Lockheed Air Terminal Inc., 411 U.S. 624 (1973), the U.S. Supreme Court held that the Federal Aviation Act and related statutes create a “comprehensive scheme of federal control of the aircraft noise problem” that preempts state and local control. Here, the Plaintiffs did not seriously contest this premise and acknowledged that state and local governments cannot regulate aircraft noise via their police powers.

The division next addressed the “proprietor’s exception,” under which a governmental entity that owns and operates an airport may, in its role as airport proprietor, impose certain noise restrictions that it could not impose through the exercise of its police powers. This exception originates from a footnote in City of Burbank and was previously recognized by the Colorado Supreme Court in Arapahoe County Public Airport Authority v. Centennial Express Airlines, Inc., 956 P.2d 587 (Colo. 1998). The division assumed, without deciding, that Jefferson County had the authority as airport proprietor to prohibit touch-and-go operations if it chose to do so.

The critical question—and the one on which the case turned—was whether a state court could order an airport proprietor to exercise its proprietary authority and impose noise restrictions. The division concluded it could not.

The division drew a clear distinction between a restriction voluntarily adopted by an airport proprietor and a restriction imposed on the proprietor by a court. An injunction, the division reasoned, is not a restriction imposed by the airport proprietor; it is a restriction imposed on the proprietor by a court. A state court has no greater authority to impose such a restriction in an area of federal preemption than does a state or local legislative body. To hold otherwise would authorize state governmental control over aircraft noise, a result that City of Burbank forbids.

In reaching this conclusion, the division relied heavily on Northeast Phoenix Homeowners’ Ass’n v. Scottsdale Municipal Airport, 636 P.2d 1269 (Ariz. Ct. App. 1981), in which the Arizona Court of Appeals rejected an analogous argument and held that “rules mandated by a court through its injunctive powers would in no sense emanate from the airport proprietor.” The division rejected Plaintiffs’ attempts to distinguish Scottsdale Municipal Airport, finding that none of their arguments undermined the case’s fundamental holding that a state court cannot do through an injunction what a state legislative body could not do through legislation.

The Colorado Court of Appeals also noted that Plaintiffs failed to cite a single case in which a state court had enjoined aircraft flight operations—or required an airport proprietor to do so—to abate aviation noise. Rather, the cases on which Plaintiffs relied generally involved one of three distinguishable scenarios: (1) a restriction imposed by the airport proprietor itself, (2) a claim for damages, or (3) a land use regulation prohibiting the use of property as an airport.

Remand on the Clean Air Act Issue

As to the lead emissions component of Plaintiffs’ claim, the division reversed the district court’s dismissal and remanded for further proceedings. The division noted that City of Burbank is limited to federal preemption of state and local aviation noise control and says nothing about federal preemption of state and local aviation pollution control. However, Jefferson County had argued before the district court that a provision of the Clean Air Act, 42 U.S.C. § 7573, expressly preempts state or local authority to “adopt or enforce any standard respecting emissions of any air pollutant from any aircraft or engine thereof” that differs from a federal standard. Because the district court had not addressed this argument, and because the controlling question—whether an emissions-based restriction on aircraft operations is a “standard respecting emissions”—is a novel one with no on-point authority in Colorado or elsewhere, the division declined to resolve it in the first instance and remanded for further proceedings.

The case is Town of Superior v. Board of County Commissioners of Jefferson County, 2026 COA 14, ___ P.3d ___. The decision was authored by Judge Schock with Judges Grove and Yun concurring.

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

On March 19, 2026, the US District Court for the Eastern District of Texas in Flowers Title Companies LLC v. Bessent[1] ruled that the U.S. Financial Crimes Enforcement Network (“FinCEN”) exceeded its statutory authority under the Bank Secrecy Act by adopting the “Anti-Money Laundering Regulations for Residential Real Estate Transfers” (the “Rule”), and vacated the Rule effective immediately[2]. The Rule would have required certain individuals, such as title insurance agents, escrow agents, and attorneys, to report information about certain residential real estate conveyances when the buyer is a business entity or trust. FinCEN argued that the rule was needed to combat money laundering in real estate, but the court found that the agency did not have the legal authority to impose it.

The court held that the Rule exceeded FinCEN’s statutory authority under the Bank Secrecy Act on two independent grounds. First, the court found that the Bank Secrecy Act allows FinCEN to require reports of “any suspicious transaction”, but the Rule treated all non-financed residential real estate as suspicious, and FinCEN failed to adequately explain how that blanket assumption was justified. Second, the court concluded that the Bank Secrecy Act only authorizes FinCEN to require financial institutions to maintain reporting procedures, not to impose independent substantive reporting obligations.  Because the Rule conflicted with the unambiguous terms of the statute, the court vacated it under the Administrative Procedure Act as the default remedy, finding vacatur appropriate given both the seriousness of the Rule’s deficiencies and the minimal disruption of restoring the pre-Rule status quo.

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[1] FLOWERS TITLE COMPANIES, LLC, v. SCOTT BESSENT, in his official capacity as U.S. Secretary of Treasury, et al., Memorandum Opinion and Order

[2] FLOWERS TITLE COMPANIES, LLC, v. SCOTT BESSENT, in his official capacity as U.S. Secretary of Treasury, et al., Final Judgement

On March 9, 2026, the Colorado Supreme Court reversed the Title Board’s approval of Proposed Initiative 2025–2026 #158, a ballot initiative that sought to amend the Colorado Taxpayer’s Bill of Rights (“TABOR”) to require voter approval for any “fee” expected to create more than $100 million in revenue in its first five fiscal years and defined “fee” as “a voluntarily incurred governmental charge in exchange for a specific benefit conferred on the payer.” In the Matter of the Title, Ballot Title, and Submission Clause for Proposed Initiative 2025–2026 #158, 2026 CO 13 (Colo. Mar. 9, 2026) (hereinafter, “In re Title”). The Court held Initiative #158 violated the Colorado Constitution’s single subject requirement by combining two distinct objectives: (1) requiring statewide voter approval of certain fees and (2) substantively redefining the term “fee” throughout Colorado law. This ruling effectively removes Initiative #158 from consideration for the 2026 general election ballot.

TABOR and the Tax/Fee Distinction

TABOR limits the spending and taxing powers of state and local government, requiring voter approval of any new tax, tax rate increase, extension of an expiring tax, or tax policy change causing a net tax revenue gain.  Importantly, TABOR does not define the term “tax,” and Colorado courts have developed the distinction between taxes and fees through case law.

The Court explained, under existing precedent, “a charge is a ‘tax’ if its primary purpose is to defray general governmental expenses,” but “a charge is a ‘fee’ if its primary purpose is to defray the cost of services provided to those charged.”  The Court recognized this distinction is consequential because fees are not currently subject to TABOR’s voter approval requirements.

Initiative #158

Initiative #158 sought to amend TABOR by adding a new subsection (4.5) titled “Voter approval of fees.”  The proposal contained two central components:

• The Initiative would require statewide voter approval for any fee established or increased with projected or actual revenue totaling over $100 million in the first five fiscal years, except for fees charged by institutions of higher education (“Voter Approval Requirement”); and

• The Initiative would define “fee” “as used in Colorado law” to mean “a voluntarily incurred governmental charge in exchange for a specific benefit conferred on the payer, which fee should reasonably approximate the payer’s fair share of the costs incurred by the government in providing said specific benefit.” 

The Court’s Single Subject Analysis

The Court explained, in Colorado, “every constitutional amendment or law proposed by initiative” must be “limited to a single subject, which shall be clearly expressed in its title.” § 1-40-106.5(1)(a); see also Colo. Const. art. V, § 1(5.5). This requirement serves two purposes: (1) it “ensures that each proposal depends on its own merits for passage,” thereby preventing “log rolling” tactics, the combining of multiple subjects to attract support from various factions; and (2) it prevents surprise and fraud upon voters by stopping the inadvertent passage of a surreptitious provision “coiled up in the folds” of a complex initiative.

“An initiative satisfies the single subject requirement when it tends to effect or carry out one general objective or purpose,” and its subject matter is “necessarily and properly connected rather than disconnected or incongruous.”

Proponents of Initiative #158 argued it contains only one subject: its central purpose is to require voter approval of certain fees and a definition of “fee” is necessary to effectuate that purpose. Without that definition, Proponents contended, the Initiative “would be unenforceable and meaningless.”

The Petitioner challenging Initiative #158 argued its definition of “fee” is a surreptitious second subject “coiled in the folds” of Initiative #158. Petitioner contended the definition of “fee” is significantly narrower than that established by existing case law and it would be used not only in TABOR but throughout Colorado law.

The Court agreed with the Petitioner that the redefinition of “fee” in Initiative #158 was neither necessarily nor properly connected to its stated purpose of requiring voter approval of certain fees. The Court found that the Initiative proposed a significant—and retroactive—change to the definition of all fees under Colorado law, separate and apart from any voter approval requirement. 

The Court rejected the Proponents’ argument that changing the definition of “fee” was necessary for the voter approval requirement to be enforceable, reasoning that, if the definition were removed, the current judicially developed understanding of “fee” would still give full effect to the voter approval provision.

Critically, the Court noted that, in 2014, it held an identical definition of “fee” proposed in Initiative #129 was a single subject for purposes of the single-subject requirement. Initiative #129 proposed the same definition of “fee” that appears in Initiative #158 as a standalone provision, and it was challenged as containing more than one subject. Milo v. Coulter (In re Title, Ballot Title & Submission Clause for 2013-2014 #129), 2014 CO 53, ¶ 2, 333 P.3d 101, 103. Milo held Initiative #129 “contain[ed] a single subject: the definition of a ‘fee.’”  Id. 

In light of Milo, the Court reasoned, because “Initiative #158 is Initiative #129 plus a new voter approval requirement,” it necessarily contains two subjects.

Additionally, the Court noted the log rolling danger: Initiative #158 could attract a “yes” vote from voters who support statewide voter approval of fees but would not support narrowing the definition of existing and new fees under Colorado law.  Conversely, it could attract support from voters who favor changing the existing definition of “fee” but would not support the voter approval requirement. The Court also expressed concern that the proposed new constitutional definition significantly narrows the types of charges that currently qualify as a “fee,” potentially triggering the reclassification of countless existing fees under Colorado law and rendering some no longer exempt from TABOR. These significant changes were not necessarily connected to the stated central purpose of prospectively requiring voter approval of fees exceeding a certain revenue threshold.

The Court’s reversal of the Title Board’s action on Initiative #158 removes this measure from the 2026 ballot cycle. The initiative has been remanded to the Title Board with instructions to strike the title, ballot title, and submission clause, and to return the Initiative to its Proponents. This decision underscores the Court’s continued vigilance in enforcing the single subject requirement for ballot initiatives. Proponents seeking similar reforms will need to pursue separate initiatives addressing voter approval requirements for fees and the redefinition of “fee” under Colorado law.

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