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.

The patchwork of carbon pricing regimes across the U.S. and globally has become one of the most consequential – and least discussed – variables in AI data center siting decisions. But the compliance cost differential is only part of the picture. The federal Clean Air Act’s permitting framework, which is triggered primarily by nitrogen oxide emissions rather than carbon dioxide for most projects, creates a parallel set of regulatory considerations that directly affect project timelines, technology selection, and deal structuring. This alert explains both frameworks, identifies key areas of legal uncertainty, and outlines the structuring steps that developers, lenders, and investors should consider.

Introduction

The rapid buildout of AI data center infrastructure has surfaced a regulatory dynamic that is quietly reshaping how developers, investors, and lenders evaluate project sites. A large-scale natural gas power fleet supporting a data center campus – say, 700 megawatts of on-site generation – faces dramatically different compliance costs depending on where it is built. In Texas, which imposes no carbon price, the carbon compliance cost is zero. In California, where the Cap-and-Invest program prices carbon at roughly $29 per ton today and rising, the same fleet would face tens of millions of dollars in annual compliance costs. In the European Union, where Emissions Trading System (ETS) allowances currently trade at approximately $78–79 per ton and are projected to exceed $150 per ton by 2030, the annual compliance burden can reach well into nine figures. Over the 20-year useful life of a generation fleet, these differentials compound into sums that can rival or exceed the capital cost of the generation assets themselves.

That concentration of cost goes a long way toward explaining why hyperscale AI data center investment has gravitated toward Texas and a handful of other states with favorable regulatory frameworks. But the compliance cost differential, striking as it is, tells only part of the story. For the clients we advise – developers selecting sites, general counsel negotiating construction contracts, lenders underwriting project finance, investors evaluating risk – the more important question is: What do we need to structure, permit, and document to capture this advantage, and what legal risks should we be aware of along the way?

This alert addresses those questions.

The Federal Permitting Framework: Why the Conversation Starts with Nitrogen Oxides, Not Carbon

Most observers of the data center space assume that carbon pricing is the primary regulatory variable in siting decisions. It is an understandable assumption, given the attention that carbon policy receives in the press. But it is incomplete – and, for the majority of U.S. projects, it puts the emphasis in the wrong place.

The federal Clean Air Act (CAA) establishes a permitting framework for large industrial sources of air pollution. Two programs are particularly relevant here: Prevention of Significant Deterioration (PSD), which applies to the construction of new major sources of pollution in areas that meet federal air quality standards, and Title V, which imposes ongoing operating permit requirements on major sources. Both programs are triggered when a facility’s emissions of certain regulated pollutants – known as “criteria pollutants” – exceed specified thresholds.

For on-site power generation at data centers, the criteria pollutant that matters most is nitrogen oxides, commonly abbreviated as NOx. NOx is a byproduct of fossil fuel combustion and a precursor to smog and particulate matter. The federal PSD major source threshold for NOx is 250 tons per year for most data center generation configurations, including simple-cycle combustion turbines and reciprocating engines, which are not listed source categories under Section 169(1) of the Clean Air Act. Combined-cycle configurations with heat recovery steam generators may qualify as fossil-fuel fired steam electric plants, a listed category subject to a lower 100 ton per year threshold – a classification that should be evaluated on a project-specific basis.

Greenhouse gas emissions – including carbon dioxide – are regulated under a separate and narrower framework. The so-called GHG Tailoring Rule sets a Title V threshold at 100,000 tons of carbon dioxide equivalent per year, a figure so high that most data center power configurations do not approach it on greenhouse gas emissions alone. More importantly, the Supreme Court’s 2014 decision in Utility Air Regulatory Group v. EPA established that greenhouse gas Best Available Control Technology (BACT) requirements apply only to facilities that already qualify as major sources under criteria pollutants – the “anyway source” doctrine. In practical terms, this means that if a data center’s on-site generation stays below the NOx major source threshold, there is no federal obligation to undergo greenhouse gas BACT review.

The implication for project planning is significant. Technology selection for on-site power generation is not merely an engineering decision; it is a permitting strategy decision. The choice among generation technologies – reciprocating engines, simple-cycle combustion turbines, combined-cycle gas turbines, solid oxide fuel cells – determines whether a facility’s NOx emissions will exceed the major source threshold and, consequently, whether it will be subject to full PSD review (a process that typically adds 18 to 36 months to the project timeline) or can proceed through a faster, more streamlined permitting pathway.

The numbers illustrate the point. An uncontrolled simple-cycle combustion turbine operating at 100 megawatts of capacity can produce 219 to 438 tons of NOx per year – above the applicable 250 ton per year PSD major source threshold at the upper end of the range, and approaching it even at the lower end. The same turbine, equipped with selective catalytic reduction (SCR), a widely used emissions control technology, drops to 22 to 88 tons per year. A solid oxide fuel cell, which generates electricity through an electrochemical process rather than combustion, produces roughly 1.3 tons of NOx per year at the same capacity – effectively invisible to the PSD framework at any realistic campus scale.

An additional layer of complexity arises from the source aggregation rules. Under the Environmental Protection Agency’s (EPA) adjacency standard, multiple emission units located on contiguous property, under common control, and sharing the same industrial classification code are treated as a single stationary source for purposes of the threshold calculation. For a data center campus with dozens or hundreds of individual generators, the entire fleet’s NOx output is summed. This aggregation calculation – how the campus is designed, how ownership is structured, how phases are sequenced – is a critical variable that must be analyzed before engineering, procurement, and construction contracts are executed.

In December 2025, the EPA launched a dedicated Clean Air Act Resources for Data Centers webpage, that consolidates guidance on emissions thresholds, aggregation rules, and permitting pathways. A companion report from the Congressional Research Service documented the source aggregation framework in detail. Together, these resources confirm that the federal government recognizes data centers as a distinct and significant category of air emissions source – and that the permitting framework will be applied with increasing specificity. Two additional dimensions of this framework warrant particular attention: the treatment of facility modifications and expansions, and the distinction among state-level permitting pathways.

A related but distinct issue arises when a facility that was originally permitted below the major source threshold later expands or modifies its operations in a way that increases emissions. The Clean Air Act’s New Source Review modification rules apply when a physical or operational change at an existing major source results in a significant net emissions increase. For a data center campus that is designed for phased buildout over several years, the modification analysis must be considered at the outset – not only for the initial phase, but for the cumulative impact of subsequent phases. A campus that is permitted as a minor source in Phase 1 but crosses the major source threshold in Phase 2 may trigger full PSD review for the expansion, with significant implications for the project timeline and for contractual commitments made on the basis of the original permitting assumptions. A phased buildout over several years may also trigger the Clean Air Act’s anti-circumvention principle that prevents regulated entities from structuring operations in a way that may cause EPA to view the buildout as an attempt to avoid PSD permitting requirements. 

It is also important to distinguish among the permitting pathways available in key jurisdictions. In Texas, TCEQ administers several distinct pathways for air quality permits: emissions registration (available for facilities that meet certain low-emission criteria), standard permits (pre-established permits for facilities that meet prescribed conditions), and case-by-case New Source Review. These pathways involve different timelines, different levels of agency review, and different operational constraints. The choice among them is a function of the generation technology selected, the campus configuration, and the emissions profile – and it should be made in consultation with environmental counsel before engineering and procurement decisions are finalized.

For practitioners, the state-level overlay adds further complexity. States like Colorado, where air quality regulators have been among the most active in the country on emissions from energy operations, impose their own standards that may be more stringent than federal requirements. In nonattainment areas – regions that do not meet federal air quality standards for one or more criteria pollutants – NOx compliance costs alone can add $25 million to $50 million annually. The interplay between federal PSD requirements and state-level standards creates a layered regulatory environment that demands jurisdiction-specific analysis.

The Domestic Carbon Pricing Landscape

Layered on top of the federal permitting framework is a patchwork of state and regional carbon pricing regimes that creates a compliance cost spectrum ranging from zero to nearly $30 per ton within the U.S.

Texas imposes no carbon price – no cap-and-trade program, no carbon tax, no emissions fee. The TCEQ holds greenhouse gas permitting authority and applies it only to facilities that are already major sources under criteria pollutants. The TCEQ standard permit pathway, which has been used by several of the largest data center generation deployments in the state, offers a substantially faster route to operation than full New Source Review. For developers who prioritize speed to power, this pathway represents a material competitive advantage.

California operates the Cap-and-Invest program (renamed under 2025 legislation from Cap-and-Trade and extended through 2045), which covers on-site fossil fuel combustion above 25,000 metric tons of carbon dioxide equivalent per year. The current allowance price is approximately $29 per ton, with a statutory price floor that escalates at 5% plus the consumer price index annually. Data centers are not classified as trade-exposed industries and receive no free allocation of allowances – they pay for every ton emitted. For a 500-megawatt combined-cycle gas facility operating at 85% capacity factor, the annual compliance cost at current prices is roughly $43.5 million. At projected escalation rates, that figure approaches $120 million per year by 2040. Over a 20-year project life, the present-value differential between a California siting decision and a Texas siting decision can run into the billions of dollars.

The Regional Greenhouse Gas Initiative (RGGI) covers ten states in the Northeast at a price of $22 to $27 per ton. RGGI applies to fossil-fuel-fired electric power generators with a capacity of 25 megawatts or above. For data center developers, RGGI presents what may be the most interesting open legal question in this space: Does on-site generation that is consumed entirely by the data center – never exported to the grid – qualify as an “electric power plant” under RGGI’s definitions? The question is genuinely unresolved and is state-specific within the RGGI region. A facility generating exclusively for its own consumption has a reasonable legal argument that it falls outside RGGI’s coverage. Developers are currently taking different positions on this question across RGGI jurisdictions, and the answer carries significant financial consequences. For a multi-hundred-megawatt behind-the-meter deployment, the difference between covered and exempt is tens of millions of dollars annually. Any developer treating this question as clearly settled – in either direction – is accepting legal risk that should be identified and evaluated.

We raise this question not to advocate for a particular position but to identify a genuine area of legal uncertainty that developers and their counsel should evaluate on a project-specific and state-specific basis. The resolution of this question will likely vary across RGGI member states and may evolve as regulators respond to the growth of behind-the-meter data center generation.

Washington State operates the Climate Commitment Act at approximately $26 per ton, with the same 25,000-ton applicability threshold as California. Washington’s legislature has been actively considering provisions that would specifically target data center fossil fuel generation, making it the jurisdiction with the highest near-term political risk for behind-the-meter gas deployment in the Pacific Northwest.

Taken together, this patchwork of state and regional programs produces compliance cost differentials that are large enough to reshape project economics. A brief example illustrates the magnitude of the siting decision. Consider a 500-megawatt combined-cycle natural gas facility operating at 85% capacity factor, producing approximately 1.5 million metric tons of carbon dioxide per year. In Texas, the annual carbon compliance cost is zero. In California, at current Cap-and-Invest prices of approximately $29 per ton, the annual cost is roughly $43.5 million. In the European Union, at current ETS prices of approximately $78 per ton, the annual cost is approximately $117 million. Over 20 years, even before accounting for projected price escalation, the cumulative differential between the Texas and California scenarios alone exceeds $800 million in nominal terms. These figures are necessarily approximate – they will vary with actual capacity factors, emission rates, allowance prices, and applicable exemptions – but they convey the order of magnitude that makes regulatory cost modeling a first-order siting variable.

Structuring the Deal to Match the Regulatory Reality

The regulatory landscape creates the opportunity. The deal documentation – the contracts, the permits, the financing agreements – determines whether a particular client captures that opportunity or is exposed to risks that erode it.

Several structuring considerations deserve attention.

Siting criteria should formally incorporate regulatory cost modeling. The 20-year net present value of the carbon and NOx compliance cost differential across candidate sites can exceed $1 billion for large-scale deployments. That figure belongs in the siting analysis alongside land cost, power availability, and fiber connectivity – not in a footnote to the environmental section of the feasibility study.

The NOx aggregation analysis should be completed before construction contracts are executed. Ownership structures, campus layout, phasing strategies, and adjacency determinations all affect whether separate buildings or project phases will be aggregated into a single stationary source for purposes of the emissions threshold calculation. A post-signing determination that previously separate phases aggregate into a single source can fundamentally alter the permitting pathway, adding 18 months or more to the timeline and triggering cascading contractual defaults. This analysis requires counsel experienced in Clean Air Act source determinations who understand how the EPA and state agencies evaluate these questions in practice.

Construction contracts should allocate permitting risk with specificity. The EPC contract should distinguish between permitting delays caused by regulatory determinations (such as a change in the aggregation analysis or an unexpected nonattainment area designation) and delays caused by contractor performance. Business interruption and delay-in-start-up insurance should be structured to match these contractual allocations – a point that requires coordination among deal counsel, environmental counsel, and the insurance placement team.

Lender representations and warranties should address the permitting pathway. Project finance lenders are increasingly requiring borrowers to represent that the facility will not trigger major source thresholds and to covenant that operations will maintain the emissions profile assumed in the permitting strategy. Borrower’s counsel should ensure that the technology specifications, operational parameters, and aggregation analysis support those representations before they are made.

Escalation and optionality provisions warrant careful attention. Carbon prices in high-cost jurisdictions are projected to rise substantially over the next decade. Contracts with 20-year terms should include escalation mechanisms that reflect this trajectory, and the project design should preserve flexibility for future hybrid configurations – incorporating renewables, battery storage, or alternative generation technologies – that can reduce carbon exposure as compliance costs increase.

A related consideration involves the interaction between carbon compliance costs and federal tax incentives. The Inflation Reduction Act’s clean electricity production credit (Section 45Y) and clean electricity investment credit (Section 48E) provide substantial incentives for qualifying generation technologies, including certain renewable and zero-emission sources. For a developer evaluating the total cost of power across jurisdictions, the analysis is not limited to the carbon compliance differential; it also includes the tax credit value of alternative generation technologies that may reduce or eliminate carbon exposure. The interplay among carbon pricing, tax incentives, and generation technology selection is complex, and the optimal configuration will depend on the specific project economics, the applicable jurisdiction, and the developer’s tax position. These are determinations that require coordination among energy counsel, tax counsel, and the project’s financial advisors.

Community engagement should be incorporated into the legal and permitting strategy from the outset. Building at a massive scale – whether in rural Texas counties, suburban corridors in Colorado, or fast-growing communities anywhere in the country – brings economic benefits, but it also invites scrutiny on water use, noise, emissions, and land use. The environmental enforcement and community engagement landscape across multiple states has taught us that regulators and communities alike are paying closer attention to cumulative impacts than ever before. Proactive engagement, transparent environmental data, and well-structured community benefit agreements can meaningfully reduce both litigation risk and permitting timelines. Developers who treat community relations as an afterthought are the ones most likely to encounter delays that cost more than the engagement would have.

Conclusion

The multi-gigawatt commitments flowing into Texas, the rapid deployment of behind-the-meter generation fleets, and the broader migration of capital toward jurisdictions with favorable regulatory frameworks reflect a rational response to a complex regulatory landscape. The opportunity is real – but so is the legal and regulatory complexity involved in capturing it.

The clients who are navigating this landscape most effectively are the ones who bring energy and environmental counsel into the siting conversation at the beginning of the process – not after the letter of intent is signed and the permitting questions have already become expensive surprises.

This alert is intended to provide a general overview of the regulatory and structuring considerations relevant to AI data center siting and on-site power generation. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

R.J. Colwell is a senior associate at Davis Graham & Stubbs LLP who advises data center developers, power generation companies, and their investors and lenders on the regulatory, contractual, and permitting dimensions of AI infrastructure projects. R.J. can be reached at rj.colwell@davisgraham.com. Randy Dann is a partner at Davis Graham & Stubbs LLP whose practice focuses on Clean Air Act compliance, air quality enforcement, and environmental regulatory matters for energy and natural resources clients. He serves as vice chair of the American Bar Association’s Air Quality Committee. Randy can be reached at randy.dann@davisgraham.com.

In Davis Graham’s January 2026 alert, we discussed the significant changes introduced by the Holding Foreign Insiders Accountable Act, which extended Section 16 reporting obligations to directors and certain officers of foreign private issuers. In a welcome development for many FPIs, the Securities and Exchange Commission has now exercised its exemptive authority to provide relief for issuers incorporated in certain qualifying jurisdictions.

Background

As detailed in Davis Graham’s prior alert, the Holding Foreign Insiders Accountable Act (“HFIAA”), signed into law on December 18, 2025 as part of the National Defense Authorization Act for Fiscal Year 2026, amended Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), to extend insider reporting obligations to directors and officers (as defined in Section 3(a)(7) of the Exchange Act and Rule 16a-1(f) of the Exchange Act, respectively) of foreign private issuers (“FPIs”). The HFIAA also authorized the Securities and Exchange Commission (“SEC”)to exempt any person, security, or transaction from Section 16(a) reporting requirements if the SEC determines that the laws of a foreign jurisdiction impose “substantially similar” requirements.

On March 5, 2026, just days before the March 18, 2026 compliance deadline, the SEC issued an exemptive order (Release No. 34-104931)^[1] providing conditional relief from Section 16(a) reporting obligations for directors and officers of certain FPIs.

Scope of Exemption

Under the SEC’s order, the exemption is available to directors and officers of any FPI that is both (1) incorporated or organized in a “qualifying jurisdiction” and (2) subject to a “qualifying regulation.”

Qualifying Jurisdictions

The SEC has identified six qualifying jurisdictions:

• Canada;
• Chile;
• the European Economic Area^[2];
• the Republic of Korea;
• Switzerland; and
• the United Kingdom.

Qualifying Regulations

The SEC determined that each of the following regulations imposes requirements “substantially similar” to Section 16(a) based on five key criteria: (i) persons covered, (ii) securities covered, (iii) transactions covered, (iv) the content and timeliness of required reports, and (v) public availability of reports in English.

Jurisdiction	Qualifying Regulation
Canada	National Instrument 55-104 – Insider Reporting Requirements and Exemptions (supported by National Instrument 55-102 – System for Electronic Disclosure by Insiders (SEDI) and companion policies)
Chile	Articles 12, 17, and 20 of the Chilean Securities Market Law (Ley de Mercado de Valores, Ley No. 18,045) and General Rule (Norma de Carácter General) No. 269
European Economic Area	Article 19 of the European Market Abuse Regulation (Regulation (EU) No. 596/2014, as amended by Regulation (EU) No. 2024/2809) and as incorporated into the domestic law of each European Economic Area state (“EU MAR”)
Republic of Korea	Article 173 of the Republic of Korea Financial Investment Services and Capital Markets Act and Article 200 of the Enforcement Decree of the Financial Investment Services and Capital Markets Act
Switzerland	Article 56 of the Listing Rules and implementing directives of SIX Swiss Exchange as approved by the Swiss Financial Market Supervisory Authority
United Kingdom	Article 19 of the United Kingdom Market Abuse Regulation (Regulation (EU) No. 596/2014), as it forms part of UK domestic law pursuant to the European Union (Withdrawal) Act 2018

Key Conditions for Reliance on the Exemption

The exemption is subject to two important conditions that FPIs and their insiders must satisfy:

1. Reporting Under the Qualifying Regulation. Each director or officer relying on the exemption must report their transactions in the issuer’s securities as required under the applicable qualifying regulation. Importantly, this condition applies on an individual basis. If a director or officer qualifies as such under SEC rules but falls outside the defined category of reporting persons under the qualifying regulation, that individual will still be required to file Section 16(a) reports with the SEC.
2. English-Language Availability. Any report filed under a qualifying regulation must be made available in English to the general public within two business days. If an English version cannot be filed through the regulator’s or listing venue’s database, it may be posted on the company’s website.

Both the incorporation/organization requirement and the qualifying regulation requirement must be satisfied, although they need not involve the same jurisdiction. For example, directors and officers of an FPI incorporated in Canada with securities listed in Germany (which is subject to Article 19 of EU MAR) would qualify for the exemption because (i) Canada is a qualifying jurisdiction and (ii) EU MAR is a qualifying regulation, even though these arise from different jurisdictions.

However, satisfying only one prong is insufficient. An FPI incorporated in a non-qualifying jurisdiction but listed on an exchange in a qualifying jurisdiction would not qualify, even if subject to a qualifying regulation, due to not meeting the incorporation/organization requirement. Directors and officers of such FPIs must still file Section 16(a) reports in addition to any foreign reporting obligations.

Practical Implications and Immediate Action Items

For FPIs in qualifying jurisdictions:

• Assess exemption eligibility immediately. Confirm whether the FPI is subject to a qualifying regulation and conduct an analysis to identify which directors and officers would be covered by the exemption.
• Identify potential gaps. Determine if any Section 16 directors or officers are not currently reporting under any qualifying regulation and evaluate whether to align home-country reporting obligations or prepare for parallel SEC filings.
• Establish English-language reporting processes. If reports under the qualifying regulation are not already filed in English, establish a process for preparing and publishing English versions within the two-business-day window, whether through the foreign regulator’s database or on the company’s website.

For FPIs NOT in qualifying jurisdictions:

Directors and officers of FPIs incorporated outside the qualifying jurisdictions or not subject to qualifying regulations remain subject to the Section 16(a) reporting framework. These FPIs should follow the action items outlined in Davis Graham’s January 2026 alert:

• Identify covered personnel. Identify covered personnel and ensure that they are enrolled in EDGAR Next and have obtained the necessary filing credentials before March 18, 2026.
• Prepare for initial EDGAR filings. Prepare for initial Form 3 filings, which must be submitted by 10:00 p.m., Eastern Time, on March 18, 2026.
• Update related policies and procedures. Review and update internal policies to address Section 16 reporting and workflows.
• Train and communicate. Educate directors and officers on Section 16 reporting obligations, beneficial ownership concepts, and filing procedures.

Next Steps

For questions about the SEC’s exemptive order, the scope of coverage, or how to structure Section 16 compliance, contact a member of our Public Companies & Capital Markets team to help you navigate these new requirements.

• ^[1] See https://www.sec.gov/rules-regulations/2026/03/34-104931 for the full text of the exemptive order.
• ^[2] As of the date of the exemptive order, the European Economic Area consists of the 27 member states of the European Union (Austria, Belgium, Bulgaria, Croatia, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands, Poland, Portugal, Romania, Slovakia, Slovenia, Spain, and Sweden) as well as Iceland, Liechtenstein, and Norway. Any country that joins the EEA would also be required to adopt EU MAR (and therefore this exemptive relief would apply to directors and officers of its FPIs), while a country that leaves the EEA may no longer be subject to EU MAR (and directors and officers of its FPIs would no longer be eligible for this exemptive relief to the extent the country is no longer subject to the EU MAR).

On March 5, 2026, in In the Matter of Fred L. Maxwell, deceased, No. 25CA0323, a division of the Colorado Court of Appeals addressed the extent to which restrictions on the sale and use of a charitable gift of real property can be modified under the cy pres doctrine as articulated in section 15-1-1106(c), C.R.S. (2025). The division held that CSU STRATA, the donee of 9,733 acres of ranchland, could not void the sale and use restrictions on its real property, but under the cy pres doctrine it was allowed to reform the will devising the property so that it could either (1) sell the property free of sale and use restrictions with the proceeds to be used consistent with the donor’s intent, or (2) encumber the property consistent with the donor’s intent.

Through his last will and testament, executed in 1945 (“Will”), Fred L. Maxwell conveyed 9,733 acres of ranchland, the Maxwell Ranch, to the Colorado Agricultural Research Foundation, now known as CSU STRATA.

The Will imposed both use and alienation restrictions on the ranch. The ranch was to be used “exclusively for experimental purposes in connection with the Colorado State College of Agricultural and Mechanic Arts [now Colorado State University],” specifically “for a study of the nutritive value of mountain meadows and grasses and include experimentation with means of renovating and improving meadows and pastures, and a study of animal nutrition and diseases under range conditions, and also to be set up a practical course in range and ranch management, including experimental work in breeding livestock.” The text of the Will acknowledged, however, that these purposes were “not in the way of limitation, but merely as a suggestion” and permitted the ranch to “be used for such other experimental purposes as said Foundation may deem advisable.” In addition, the Will provided “the real estate shall never be alienated, sold, or disposed of by said beneficiary or its successors or assigns.”

In 2024, CSU STRATA petitioned the Larimer County District Court to void both the sale and the use restrictions in the Will. In the alternative, CSU STRATA sought reformation of the Will such that it could sell the land and use the proceeds for research related to the use restriction. CSU STRATA also sought a declaration that a lease for wind energy production was consistent with the use restriction. The district court denied CSU’s petition in its entirety.

On appeal, the division affirmed in part and reversed in part. First, the division held that the donee of a charitable gift of real property is not entitled to a declaration that restrictions on alienation and use of that property are void, because, as an exception to the general rule prohibiting unreasonable restraints on alienation, restraints on alienation in charitable gifts are generally enforceable. Second, applying the cy pres doctrine as articulated in section 15-1-1106(c), C.R.S. (2025), which allows a court to modify a restriction contained in a gift instrument if the restriction has become unlawful, impracticable, impossible to achieve, or wasteful, the division held a donee may reform the will under which the gift was made to allow the property to be sold, with the proceeds to go toward activities consistent with the donor’s purpose in making the gift or encumbered in a way consistent with that purpose.

The division’s analysis made three key determinations.

First, the division held that restraints on alienation in charitable gifts—whether direct, as in the sale restriction, or indirect, as in the use restriction—are enforceable, as an exception to the general rule prohibiting unreasonable restraints on alienation. As a result, the division determined that there were no grounds upon which to void those restrictions.

Second, the division reviewed the record de novo and found that the undisputed evidence presented by CSU STRATA showed that it had tried for decades to support agricultural and ranch management programming on the Maxwell Ranch, but that the organization had concluded that continuing to do so had become practically and financially unfeasible. Based on an affidavit to this effect from the president and CEO of CSU STRATA, the division determined that the Maxwell Ranch restrictions had become impracticable under sections 15-1-1106(c) and 15-5-413(1)(c)) (concerning cy pres as applied to charitable gifts). Consequently, CSU STRATA could sell the property free of the sale and use restrictions contained within the Will, with any resulting proceeds used to fund CSU’s experimental research operations at other locations. The division also determined that CSU STRATA could encumber the land consistent with Maxwell’s intent that the ranch be used for experimental research, although the court noted that there was not enough evidence in the record for it to declare that a conservation easement would be consistent with that intent.

Third, the division determined that CSU STRATA was entitled to declaratory judgment that a wind energy production lease would further the donor’s intent that the ranch be used for experimental research, based on a prior 2007 court determination to that effect.

The division remanded the case to the district court with instructions to effectuate its holding. The decision was authored by Judge Jones with Judges Lum and Meirink concurring.

Read the full opinion here.

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