DENVER – July 7, 2026 – Davis Graham & Stubbs LLP is pleased to announce that Maria Y. Luna will join Kathleen Schroder as Co-Chair of the Davis Graham Clean Energy & Sustainability Group.

“Maria has long been an important contributor to the firm’s clean energy and renewable energy work,” said Zachary D. Detra, Head of the firm’s Transactions Department. “Her experience advising clients on large-scale renewable energy projects, combined with her practical approach to real estate and project development matters, will further strengthen the group’s ability to serve clients across the clean energy sector.”

Maria has extensive experience representing clients across the United States in large-scale real estate matters, with a particular focus on renewable energy and complex, multi-site acquisitions spanning industrial, retail, and office properties nationwide. Her practice encompasses utility-scale renewable energy projects, leasing, acquisitions, and dispositions. She regularly represents clients developing utility-scale wind and solar projects, guiding them through the full range of issues these developments present, including title, access, easements, and leasing. 

Davis Graham’s Clean Energy & Sustainability Group advises clients on clean energy projects from start to finish, including project siting and permitting, and contractual agreements. The group’s work spans wind, solar, geothermal, green hydrogen, biomass, renewable natural gas, hydrogen, renewable energy storage, and carbon capture, use, and sequestration.

BLM Issues Curative NEPA Analysis for Wyoming Leases Subject to WildEarth Guardians and Western Watersheds Project Litigation

On June 5, 2026, the Bureau of Land Management (BLM) Wyoming State Office released a long-awaited environmental assessment (EA) intended to cure National Environmental Policy Act (NEPA) deficiencies affecting hundreds of federal oil and gas leases in Wyoming sold between 2015 and 2020. The EA supplements the NEPA analysis for the May 2015, August 2015, November 2015, February/May 2016, August 2016, November 2016, February 2017, June 2017, September 2017, September 2018, March 2019, and March 2020 Wyoming lease sales.

Environmental groups challenged these lease sales in WildEarth Guardians v. Haaland, No. 1:16-cv-01724 (D.D.C.) (“WEG I”), WildEarth Guardians v. Haaland, No. 1:20-cv-00056 (D.D.C.) (“WEG II”), WildEarth Guardians v. Haaland, No. 1:21-cv-00175 (D.D.C.) (“WEG III”), and Western Watersheds Project v. Haaland, No. 1:18-cv-00187 (D. Idaho). The supplemental NEPA analysis was required either because a court found error in BLM’s original analysis or through settlement agreements. The EA provides additional analysis on the effects of leasing on greenhouse gas emissions and greater sage-grouse, among other resources.

The EA has two significant consequences for federal oil and gas lessees in Wyoming. First, it allows BLM to resume approving applications for permit to drill (APDs) on leases covered by the EA. Second, it may cause lease suspensions to terminate. BLM had suspended leases subject to the WEG and Western Watersheds Project cases upon lessees’ request. Lessees should review their suspension terms carefully to determine whether the EA’s issuance caused suspensions to terminate automatically and primary terms to resume running.

Notably, the EA does not address lease sales challenged in Montana Wildlife Federation v. Burgum, No. 4:18-cv-00069-BMM (D. Mont.), which include the December 2017, March 2018, June 2018, February 2019, September 2019, December 2019, and December 2020 Wyoming lease sales. The Montana Wildlife Federation court has canceled most of these leases, rendering them ineligible for curative NEPA analysis.

District of Montana Vacates Oil and Gas Leases in Phase III of Montana Wildlife Federation

On June 12, 2026, the U.S. District Court for the District of Montana adjudicated the third phase of challenges to federal oil and gas lease sales in Montana Wildlife Federation v. Burgum, No. 18-cv-0069 (D. Mont.). The court found that, when deciding to lease, BLM did not properly apply a directive in its resource management plans (RMPs) requiring it to prioritize oil and gas leasing and development outside of sage-grouse habitat. As a result, the court vacated all nonproducing leases sold at the March and December 2019 Montana/Dakota lease sales and the February, September, and December 2019 Wyoming lease sales. The court declined to vacate nine producing leases from these sales and did not vacate BLM’s offering of parcels at the December 2020 Wyoming lease sale.

This decision aligns with prior rulings in the case. In Phase I (2020) and Phase II (2022), the court similarly vacated oil and gas leases after finding BLM failed to comply with the prioritization directive. The Ninth Circuit affirmed the Phase I decision, and an appeal of the Phase II decision is pending.

The Phase III decision is notable not only for vacating a broad swath of oil and gas leases but for sparing nine producing oil and gas leases. The court declined to vacate only those leases on which actual production, i.e., drilling, occurred. Leases held by communitized or unitized production, but on which drilling had not occurred, were vacated.

The court also declined to vacate BLM’s decision to offer leases at the December 2020 Wyoming lease sale. The court reasoned that, because BLM had not issued these leases, no final agency action existed that the court could vacate. The court expressly allowed BLM to complete further NEPA analysis to determine whether to issue these leases.

For the vacated leases, BLM will not immediately return monies to leaseholders. The court stayed the effectiveness of its decision to allow for appeals. As of July 15, 2026, no appeals have been filed.

Although the decision invalidates thousands of acres of existing leases, it may have a limited effect on future leasing. The prioritization directive was contained in BLM’s 2015 RMPs for greater sage-grouse management. BLM has since revised these RMPs, and the revised RMPs lack a prioritization directive. Moreover, Public Law 119-21 (2025), colloquially known as the One Big Beautiful Bill Act, requires BLM to offer for lease any lands designated as open for leasing in an RMP that received a nomination.

For questions about this legal alert, please contact a member of the Davis Graham Environmental & Public Lands Group.

On June 23, 2026, the United States Court of Appeals for the Federal Circuit affirmed a district court decision that an Enanta Pharmaceuticals patent was invalid as anticipated by Pfizer’s public disclosure. The court held that Enanta’s provisional patent application did not sufficiently support the subject matter later claimed in the eventual patent and rejected patentee’s argument that the missing disclosure was a simple typographical error.

Provisional applications are often filed shortly before a public disclosure, such as a presentation at a conference, a big meeting with investors, or a publication in a journal.  At times, the decision to file a patent application is a last-minute consideration and rushed. However, this case provides a pointed lesson in how such hastiness can have dire consequences, particularly in competitive areas of technology where multiple companies are striving to reach the same goals.

Here, Enanta filed a provisional patent application on July 20, 2020, disclosing a chemical composition where one of the substituents was identified as NHC(O)-C₂-C_12, whereas the later granted patent claims a composition where that substituent is identified as NHC(O)-C₁-C₁₂. Enanta first introduced the C₁ substituent in its first non-provisional patent application one year after the provisional filing on July 19, 2021, which is perfectly permissible.

However, in the meantime at Pfizer, work was being carried out on the C₁-substituent compound, and during the time between Enanta’s provisional and non-provisional patent application filings, Pfizer presented the C₁-substituent compound at a presentation on April 6, 2021.  This presentation created an intervening public disclosure. Pfizer went on to commercialize a compound identical to the claims, including the C₁ substituent. Enanta sued Pfizer for infringement of that claim in its granted patent.

The issue in the case was whether the compound having the C₁ substituent was sufficiently disclosed in the provisional application to support the later granted claims, which included the C₁ compound. Enanta argued that the difference between NHC(O)-C₂-C₁₂ and NHC(O)-C₁-C₁₂ was a typographical error. Pfizer argued that “2” is expressly different from “1” and that “2” expressly excludes “1.”

Certain mistakes in patent claims can be corrected either through the U.S. Patent Office reissue process or by a court. In Novo Indus. L.P. v. Micro Molds Corp, 350 F.3d 1348, 1354 (Fed. Cir. 2003), the court set forth a two-part test for when it is appropriate for a court to make a correction in the claims. First, the correction must not be subject to reasonable debate based on consideration of the claim language and the specification, and second, the prosecution history must not suggest a different interpretation of the claims. In other words, the error must be evident from the face of the patent taken from the viewpoint of a person in the technical field of the invention. Here, the court held that this error was clearly subject to reasonable debate and therefore was not the type of error that could be corrected by a court. To explain its position, the court likened the distinction between a C₁ compound and a C₂ compound to the difference between methanol (a C₁ compound, highly toxic to human ingestion) and ethanol (a C₂ compound, commonly consumed alcohol). This example, according to the court, “illustrates why a disclosure of one chemical compound, or integer in this case, cannot necessarily be a disclosure of another, even one close by structurally.” Id. at 10.

Pfizer was particularly suited to attack the Enanta claim on the basis of a claim drafting error, because years earlier Pfizer itself was on the other end of such an error.  Pfizer, Inc. v. Ranbaxy Labs, 457 F.3d 1284, 1292 (Fed. Cir. 2006). In the Pfizer case, Pfizer had asserted a patent against a generic drug maker alleging infringement, only to find that the asserted claim depended from a non-overlapping claim (i.e., the claim depended from claim 2 but should have depended from claim 1). Again, a “2” was mistakenly recited where the claim should have stated “1” and there too, the claim was held invalid. Although the statutory basis for invalidity was different, the coincidence is remarkable.

Patent applications are important company assets. It is critical that both a competent patent attorney and the inventor(s) work carefully to prepare and prosecute patent applications. Errors which may seem easily correctable may lead to patent invalidity if not addressed before litigation is initiated, and preferably during prosecution.

The case is Enanta Pharmaceuticals, Inc. v. Pfizer Inc. C.A. No. 2025-1427 __ F.4^th__ (Fed. Cir., June 23, 2026). The case was before Circuit Judges Lourie, Bryson, and Chen, with the opinion authored by Circuit Judge Lourie.

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For questions about this legal alert, please contact a member of the Davis Graham Intellectual Property & Transactions Group.

On May 5, 2026, the United States Court of Appeals for the Tenth Circuit reversed the district court in Rider v. OXY USA, Inc., Case No. 25-3142. The panel held that the United States District Court for the District of Kansas erred in denying class certification of royalty interest owners who alleged that Merit Energy Company, LLC and Merit Hugoton, L.P. (“Merit”) and Oxy USA, Inc. (“Oxy,” and together with Merit, “Defendants”) breached a 2008 class action settlement agreement governing royalty deductions in the Kansas Hugoton Gas Field. Applying its recently clarified ascertainability standard from Cline v. Sunoco, Inc., 159 F.4th 1171 (10th Cir. 2025), the panel found the proposed class plainly ascertainable and reversed with instructions to certify the class.

Background

In 1998, a group of plaintiffs filed the Littell v. OXY USA, Inc. class action in Kansas state court, alleging that Oxy was underpaying royalties on lease agreements in the Kansas Hugoton Gas Field. The court certified the class, and in January 2008, the parties entered into a settlement. Under the settlement, Oxy agreed to provide $16.7 million to a settlement fund and to limit gathering charges on future royalty payments to $0.15 per mmbtu. The settlement stated that it would be binding on the parties’ successors, assigns, and any entity into which a party may merge or consolidate.

Merit acquired Oxy’s assets in the Kansas Hugoton Gas Field in May 2014. At that time, Oxy informed Merit about the identity of royalty owners it had been paying under the Littell settlement and its methodology for calculating royalty payments. Merit, however, determined that it was not bound by the settlement’s future royalty provisions and began taking deductions that Plaintiffs allege violate the settlement.

Plaintiffs filed a putative class action in December 2023, asserting breach of contract claims against Defendants. After the district court denied Defendants’ motions to dismiss, the court denied class certification, finding the class was not ascertainable because determining which payees owned mineral interests in land burdened by leases acquired from Oxy was not “administratively feasible.” The court then concluded that Plaintiffs could not satisfy any other Rule 23 requirement.

The Tenth Circuit’s Analysis

A panel of the Tenth Circuit reversed, applying its intervening decision in Cline v. Sunoco, which rejected the “administrative feasibility” requirement for ascertainability. Under Cline, a class definition need only be (1) clearly defined and not vague, and (2) defined by objective criteria. The court found both requirements satisfied: Merit can identify each person or entity it has paid from its own records, and when Merit acquired Oxy’s assets, Oxy provided Merit with the identities of settlement payees.

The panel rejected Defendants’ arguments that individualized title searches would be required to connect payees to the Littell settlement. Citing Cline, the panel held that a defendant cannot defeat class certification by pointing to deficiencies in its own records or by arguing that it must individually review a large number of records. The panel observed that if Merit’s records are adequate for it to rely on to make regular payments, they are adequate for it to rely on to make additional payments should Plaintiffs have a meritorious claim.

Turning to the remaining Rule 23 requirements, the panel found the district court’s ascertainability error “tainted” the rest of its analysis. The panel held that commonality was satisfied because the central issue, i.e., whether Merit breached the settlement by deducting more than the permitted limit, applied to all leases and all wells under the settlement. Typicality and adequacy of representation were likewise met because the named plaintiffs’ claims were based on the same legal theory as the class. On predominance, the panel found that Defendants’ alleged systematic breach was the predominant issue, and that individualized damages questions do not defeat predominance as a matter of law. Finally, the panel concluded that superiority was satisfied, noting that a class action is the ideal method to litigate breach of a class action settlement.

The case is Rider v. OXY USA, Inc., No. 25-3142, __F.4th__ (10th Cir. 2026). The decision was authored by Judge Kelly, joined by Judges Bacharach and Federico.

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

By RJ Colwell, Patrick Datz, and Rachel Nixon

Data center projects increasingly include on-site power generation that transforms their risk profile from a technology asset into a hybrid energy-and-technology facility. Standard insurance products were not designed for this configuration, and the legal documents that govern these projects frequently allocate risks in ways that do not align with the insurance actually in place. This alert illustrates those gaps through four scenarios drawn from transactions we are seeing in the market and outlines the coordination that sponsors, lenders, and operators need to close them.

The Scale of What Is Being Built

The artificial intelligence boom is driving one of the largest infrastructure buildouts in American history. U.S. data center construction spending reached $41 billion in 2025 – up 344% from 2020 – with more than 565 large-scale facilities operating and nearly as many in the planning or construction pipeline. Five major technology companies alone have announced roughly $700 billion in combined capital expenditure plans for 2026, the vast majority directed toward AI-related infrastructure. Private equity and infrastructure funds are deploying capital at comparable scale, with firms such as Blackstone, KKR, and Brookfield building or acquiring multi-gigawatt data center platforms that carry project-finance-style risk profiles regardless of how they are capitalized.

For developers, operators, investors, and lenders, those numbers signal enormous opportunity. They also signal a shift in the risk profile of these projects that deserves careful attention – and, in our experience, is not yet receiving it in many deal rooms.

A New Kind of Asset, a New Kind of Risk

Until recently, most data centers drew their power from the electrical grid. Their risk profile was largely that of a technology asset: expensive equipment, high uptime requirements, and exposure to outages and cyberattacks. Standard commercial property, business interruption, and cyber insurance policies, while imperfect, were reasonably well suited to those risks.

That picture has changed. Grid interconnection delays – now commonly exceeding three to five years in many ISO/RTO queue regions – have driven developers to build their own on-site power generation, often structured as behind-the-meter (BTM) facilities to avoid triggering FERC jurisdictional obligations under the Federal Power Act. These BTM installations can include fleets of reciprocating engines, combustion turbines, or fuel cells running on natural gas, sometimes generating hundreds of megawatts on a single campus.

The result is that a modern data center campus is no longer just a technology asset. It is a hybrid energy-and-technology facility, with a risk profile that straddles both industries. On-site power generation introduces exposures that are familiar in the oil and gas and power generation sectors but new to many data center developers: air quality permitting requirements, fuel supply and commodity price volatility, thermal and mechanical risks from generation equipment, and environmental liabilities related to emissions, noise, and cooling water discharge. These are risks that standard technology-sector insurance programs were never designed to address.

From an underwriting standpoint – and this is a point that developers and their counsel frequently underestimate – this shift moves the risk from a single-class technology occupancy into a combined energy-and-technology classification. Property carriers writing pure data center risk often will not accept the on-site generation exposure, and power generation underwriters are not equipped to evaluate the IT load. The result is that the program frequently needs to be placed across multiple carriers or through a specialty facility that can accommodate both classes on one form. Equipment breakdown coverage (sometimes still referenced by its legacy name, boiler and machinery) becomes a central rather than incidental coverage element, since reciprocating engines, combustion turbines, transformers, switchgear, and chillers are all rotating or pressure-containing equipment with breakdown exposure that the all-risk property form does not respond to.

The valuation basis matters as well: data center hardware depreciates aggressively under tax accounting but is almost always replaced new, so replacement cost coverage with appropriate margin clauses and obsolete-equipment endorsements should be confirmed line by line. For lenders, this is not an academic exercise: inadequate valuation language in the insurance program can create a gap between the collateral value assumed in the credit agreement and the recovery available after a loss, which is precisely the scenario that triggers covenant defaults and impairs recovery.

It is worth noting that these exposures vary depending on the commercial model. A developer building a single-tenant, build-to-suit campus faces a different risk allocation than a colocation operator hosting multiple tenants, each of whom may carry its own insurance program. In the colocation context, the gaps are frequently found not in the operator’s own policies but in the interplay between the operator’s coverage, the tenant’s coverage, and the lease provisions that allocate responsibility between them. Developers and operators at sufficient scale may also evaluate self-insurance or captive insurance structures as part of their overall risk management strategy. The threshold question in every case is the same: Have the legal documents and the insurance program been designed together, or have they been assembled independently?

The question has a regulatory dimension as well. In states where the public utility commission asserts jurisdiction over entities that sell electricity to third parties, a colocation operator that provides power to tenants under a bundled services model may face rate regulation arguments that the operator’s insurance program was never designed to address. Understanding the interaction between the commercial structure, the regulatory classification, and the insurance program is essential.

Captive and self-insurance structures merit a closer look in this context, particularly for developers operating at platform scale. A single-parent captive domiciled in Vermont, Bermuda, or the Cayman Islands can sit in the middle of the program to retain the predictable layers of risk (deductible buy-down, equipment breakdown frequency layers, cyber retention), with a fronting carrier issuing the policy of record to satisfy lender and lease requirements. The critical caution is that lender credit agreements often specify minimum carrier ratings (typically A- or better by AM Best) and prohibit deductibles above stated thresholds; a captive structure that has not been pre-approved by the lender can trip the same covenants the program is meant to support. Tax treatment under IRC 831(b) and the related material risk provisions should be confirmed with counsel before the structure is finalized.

The good news is that the insurance market is evolving to meet the moment. Specialized programs now offer integrated coverage spanning construction, operations, cyber, cargo, and delay-in-start-up – bringing together risk classes that were traditionally placed separately. These programs represent a meaningful step forward for developers who know to ask for them and who engage their insurance advisors early enough in the project timeline to structure coverage properly.

The challenge is one of coordination. The legal documents that govern the project – the engineering, procurement, and construction contract (commonly called the EPC contract), the lease, the generation services agreement, the power purchase arrangement – allocate risk among the parties. The insurance program is supposed to backstop those allocations. When the two are built in parallel, the result is a well-integrated structure. When they are built in sequence – or in isolation – gaps emerge. Those gaps are where the nine-figure surprises live.

Where the Gaps Are: Four Practical Scenarios

The most effective way to understand the emerging risk gap is to walk through the scenarios where legal structuring and insurance placement either reinforce each other or leave the project exposed.

Fire and thermal runaway. Lithium-ion batteries are increasingly used in server racks and on-site energy storage systems. These batteries carry a well-documented risk of thermal runaway – a self-reinforcing overheating cycle that can cause fire and explosion.

If a thermal event destroys server racks and causes an extended outage, the insurance and legal questions arise simultaneously. On the insurance side: Does the property policy cover the full replacement value of the specialized equipment, or do sublimits apply? Does it cover the loss of electronic data stored on the destroyed servers? Many standard property policies exclude data loss entirely, which is a critical gap for facilities whose core function is storing and processing data. Does the business interruption coverage reflect the actual revenue at stake when tenants are running high-value AI training workloads?

On the legal side, the questions are equally urgent. Who bears liability under the lease, the services agreement, or the EPC contract – the operator, the equipment vendor, or the general contractor? These questions need to be answered in concert, before the loss occurs, not after.

The insurance market’s response to this exposure is evolving rapidly, and several specifics are worth flagging for developers and their counsel. Property carriers have been narrowing their appetite for battery energy storage systems and high-density lithium-ion server rack deployments throughout the 2025 and 2026 renewal cycles, and many programs now carry sublimits in the $10 million to $25 million range for BESS losses on facilities where the total insured value is in the hundreds of millions or billions. Some carriers have introduced outright exclusions tied to non-compliance with NFPA 855 (the standard for the installation of stationary energy storage systems), UL 9540 (the safety standard for energy storage systems), and UL 9540A (the cell-level propagation test). Underwriters increasingly want to see fire detection and suppression that meets or exceeds these standards, spacing and compartmentalization of battery enclosures, and documented commissioning records.

On the data side, electronic data and media coverage is almost always sublimited on a standard property form, and the cost of recreating training datasets or model weights after a destructive event can be orders of magnitude larger than the sublimit. The obsolescence dimension compounds the problem: AI accelerator hardware may cycle through multiple generations during a single policy period, and a replacement cost provision that reimburses the cost of like-kind-and-quality equipment may not deliver equivalent compute capacity if the destroyed hardware is no longer manufactured. A separate technology errors and omissions or cyber policy may pick up some of this exposure, but only if the coverage trigger and the property trigger are deliberately coordinated. Cause-of-loss disputes between the property and cyber markets are the most common reason a covered loss ends up partially paid. For in-house counsel managing a claim in the aftermath of a thermal event, the time to resolve this coordination question is at placement, not at the point of loss.

Permitting delays. A developer plans a multi-phase campus expansion. Local residents raise concerns about noise, water consumption, or air emissions. The permitting process stalls. Construction slips by six months or more, and the developer misses contractual deadlines with anchor tenants. Delay-in-start-up exposure – the financial cost of the delay itself, measured in lost revenue and contractual penalties (often abbreviated “DSU” in insurance terminology) – can exceed a billion dollars on a single large campus. The question for the development team is whether the builders risk policy (a specialized form of property insurance that covers loss or damage during the construction phase) includes DSU coverage and whether the sublimit is adequate. In most cases, it is not – unless the coverage has been specifically negotiated at the outset. On the contract side, the allocation of permitting delay risk between the developer and the EPC contractor must be addressed with precision. Generic force majeure provisions rarely suffice.

The distinction matters for lenders as well. Credit agreements for data center projects typically require the borrower to maintain insurance at specified levels and to provide evidence that the permitting timeline assumed in the financing model remains on track. When a permitting delay arises and the insurance coverage does not respond – because the DSU sublimit is exhausted, or because the cause of the delay falls within a policy exclusion – the borrower may find itself in technical default of its insurance covenants at the same moment it most needs its lender’s flexibility.

Several distinctions inside the delay coverages are worth making explicit, because they interact directly with the credit agreement provisions that lenders and their counsel negotiate. Builders risk DSU and operating-phase business interruption are not the same coverage; they sit on different policies, are triggered by different events, and use different valuation methodologies. The builders risk DSU indemnity period typically runs from the originally scheduled commercial operation date to the actual commercial operation date, capped at a stated number of months. The operating-phase business interruption indemnity period runs from the date of the physical damage event to the date the facility is restored to operating condition, also capped. Between the two policies, there is often a gap at the handover from construction to operations that needs to be specifically negotiated.

Soft costs coverage (interest carry, additional financing costs, real estate taxes, leasing commissions) is a separate line that lenders increasingly require, and it is typically sublimited well below the DSU limit. Lender-required endorsements that should be confirmed on every placement include the lender’s loss payable endorsement (438 BFU or equivalent), waiver of subrogation in favor of the lender, severability of interests, primary and non-contributory language, and at least 30 days’ notice of cancellation or material change (often 60 to 90 days’ notice on syndicated facilities). Developers should also be aware that permitting delays tied to air quality or environmental review under state implementation plans may implicate federal regulatory timelines that cannot be accelerated by commercial negotiation alone, a dimension that the force majeure analysis in the EPC contract and the DSU coverage in the insurance program must both account for.

Equipment loss in transit. A critical shipment of servers or power generation equipment is damaged during transport. With multiple developers competing for the same specialized equipment, replacement lead times are growing – and so is the DSU exposure triggered by the delay. A single cargo loss on a hyperscale project can produce a DSU claim that far exceeds the replacement value of the equipment itself. The relevant insurance policies – cargo, builders risk, and DSU – often overlap in theory but leave gaps in practice. The generation services agreement may allocate the risk differently than the insurance program assumes. Identifying and closing these gaps requires coordination between legal counsel and the insurance placement team.

Marine cargo placement for hyperscale projects has its own discipline, and the details matter for lenders and sponsors who are relying on equipment delivery timelines to support their financial models. Coverage should be written on Institute Cargo Clauses A (the broadest all-risk form available in the London market) with extensions for war and strikes, general average and salvage, and contingent and seller’s interest where the project takes title at different stages of the supply chain. The accumulation limit, which caps the carrier’s exposure at any single location at any single time, is often the binding constraint on a large project rather than the per-conveyance limit; equipment staged at a port of discharge or at an intermediate warehouse can sit there in quantities that exceed standard accumulation terms. Delay-in-start-up triggered by a cargo loss is a separate coverage decision: many marine cargo policies exclude delay as a covered cause, and the DSU section of the builders risk policy may not respond unless the cargo loss is also a covered cause under the builders risk form. A difference-in-conditions endorsement or a marine DSU extension may be needed to close that seam. Project cargo and stock throughput placements written by specialty marine markets handle these issues more cleanly than a transactional cargo policy bought on a per-shipment basis.

Fuel supply disruption. A behind-the-meter gas fleet depends on a reliable natural gas supply. A pipeline constraint, a severe weather event, or a spike in commodity prices disrupts fuel delivery or makes continued operation uneconomic. Who bears this risk? Under the generation services agreement or the power purchase arrangement, the answer depends on how the fuel supply provisions and force majeure definitions are drafted. Whether business interruption insurance responds to a fuel supply disruption – as distinct from a mechanical failure of the generation equipment itself – depends on the specific policy language. This scenario sits at the intersection of energy law and insurance placement, and it is one where clients with experience structuring oil and gas transactions have a meaningful advantage.

This scenario exposes one of the most consequential limitations in standard business interruption forms, and it is where the data center sector’s relative unfamiliarity with energy-sector risk allocation is most visible. A pipeline constraint, a regulatory curtailment, or a commodity price spike that interrupts fuel delivery without any physical damage to insured property will not trigger standard business interruption coverage. The coverages that respond to this exposure sit in different parts of the program: contingent business interruption (covering income loss from physical damage to a named supplier’s property), supply chain or trade disruption coverage (a non-damage business interruption form that pays on a defined trigger such as a denial of access, supplier insolvency, or regulatory action), and weather or parametric coverage that pays on a measured index rather than on demonstrated damage. Each has its own trigger, exclusions, and valuation methodology, and each must be sized against the specific fuel supply structure in the generation services agreement. The pricing for these coverages has firmed considerably as carriers have absorbed losses from supply chain disruptions, but capacity is generally available for well-engineered risks. Commodity price risk itself is typically hedged in the financial markets rather than insured. Water supply risk presents a parallel exposure in water-stressed jurisdictions, particularly in Western states governed by prior appropriation doctrines, groundwater management areas, or active management frameworks such as Arizona’s, where cooling water demand may be subject to curtailment or reallocation. Standard property and business interruption forms do not address this exposure, and whether standalone or parametric coverage is available for water curtailment risk remains an evolving question. At a minimum, the site lease and generation services agreement should address water supply continuity, curtailment allocation, and the right to secure alternative sources.

For developers and sponsors who have structured oil and gas midstream or downstream transactions, the analytical framework here will be familiar: the generation services agreement is functionally a gas processing or tolling agreement, and the insurance and hedging program should be designed with the same rigor. For those coming from a pure technology or real estate background, this is an area where experienced energy counsel and insurance advisors add the most value.

Practical Considerations

The core insight is structural. Every risk allocation decision in the project documents has an insurance counterpart. A force majeure clause that shifts permitting delay risk to the developer is typically matched by adequate DSU coverage in the builders risk policy. An environmental indemnity in the lease is often backstopped by environmental impairment liability coverage. A fuel supply agreement that is silent on commodity price escalation creates an exposure that will surface in the business interruption analysis if the risk materializes.

From a placement standpoint, a coordinated program for a hyperscale or BTM-powered project will typically include the following coverage lines, each with project-specific endorsements that should be reviewed alongside the transaction documents. Builders risk should be placed on an all-risk form with LEG 3 defects coverage, testing and commissioning extensions, soft costs, and DSU sized to the financing model. Operational property and equipment breakdown should sit on a combined form covering both IT and generation equipment, with data restoration and dependent property extensions. General liability with completed operations coverage should be extended to match the statute of repose in the project jurisdiction, supported by an excess and umbrella tower commonly in the $200 million to $500 million range for hyperscale risks. Environmental impairment liability should address emissions, cooling water discharge, and historical site conditions, with coverage periods extending past the policy term to address long-tail claims. Cyber and technology errors and omissions coverage should include operational technology and industrial control system extensions, contingent business interruption, and the broadest available silent-cyber and war exclusion language. Project-specific professional liability should ideally be carried by the architects, engineers, and design-build contractors, with completed operations tail extending past project delivery. Marine cargo and stock throughput should be placed as discussed above. Finally, in most cases workers compensation and the contractor’s liability program should be structured either as separate placements or, on larger projects, through an owner-controlled or contractor-controlled insurance program (OCIP or CCIP) that consolidates coverage across the entire job site. The common thread across all of these lines is that the coverage in well-structured programs must be designed against the specific risk allocations in the project documents, not layered on after the documents are signed. The most expensive insurance failures we see are not coverage gaps in the abstract; they are mismatches between what the contract says and what the policy actually covers.

The developers and operators who are navigating this landscape most effectively are the ones who bring their legal counsel and their insurance advisors into alignment early – before the letter of intent is signed, not after construction is underway and the gaps have already been baked into the deal structure. For sponsors, lenders, and in-house teams evaluating new platforms or expanding existing ones, the threshold question remains: Have the legal documents and the insurance program been designed together?

This alert is intended to provide a general overview of the risk management considerations relevant to data center development and on-site power generation. It does not constitute legal or insurance advice, and the appropriate coverage structure and contractual approach will depend on the specific facts, commercial model, jurisdiction, and risk profile applicable to each project.

RJ Colwell is a senior associate in the Energy & Mining Group at Davis Graham & Stubbs LLP, where he advises data center developers, power generation companies, private equity and infrastructure sponsors, and their lenders on the regulatory, transactional, and permitting dimensions of AI power infrastructure. His practice spans energy M&A, FERC regulatory compliance, behind-the-meter generation structuring, and data center power supply arrangements. RJ can be reached at rj.colwell@davisgraham.com.

Patrick Datz is an Executive Vice President at IMA Financial Group, where he specializes in insurance program design for energy, power generation, and large-scale infrastructure assets. He advises developers, sponsors, and lenders on property and equipment breakdown placement, builders risk and delay-in-start-up structuring, and the use of captive and self-insurance strategies for capital-intensive projects. Patrick can be reached at patrick.datz@imacorp.com.

Rachel Nixon is a Senior Vice President at IMA Financial Group, where she advises technology, data center, and hybrid energy-technology companies on risk architecture and insurance strategy. Her work focuses on AI-driven and emerging exposures, including cyber and technology errors and omissions, supply chain and cargo risk, and the coordination of coverage across complex, multi-carrier programs. Rachel can be reached at rachel.nixon@imacorp.com.

On April 28, 2026, the Securities and Exchange Commission (the “SEC” or the “Commission”) issued Release No. IA-6961, approving an adjustment to the dollar amount thresholds used to determine “qualified client” status under Rule 205-3[1] of the Investment Advisers Act of 1940, as amended (the “Advisers Act”). The new thresholds take effect on June 29, 2026, and will affect how Colorado state-licensed and SEC-registered investment advisers charge performance-based fees to clients and private fund investors.

Background

Under Section 205(a)(1) of the Advisers Act, registered investment advisers (“RIAs”) are generally prohibited from entering into or performing any investment advisory contract that provides for compensation based on a share of capital gains or appreciation in the value of a client’s funds—commonly referred to as “performance fees,” “carried interests,” or “incentive allocations.”  However, RIAs are exempt from this prohibition if the client is considered a “qualified client” under Rule 205-3 under the Advisers Act. “Qualified clients” include, among others, clients meeting an assets-under-management test or a net worth test. The Dodd-Frank Act requires the Commission to adjust the dollar thresholds for these two tests for inflation every five years, rounded to the nearest $100,000.

New Thresholds

Beginning June 29, 2026, to be deemed a qualified client, a client or private fund investor must have:

• Assets-Under-Management: At least $1,400,000 (adjusted from $1,100,000) under the management of the RIA immediately after entering into the advisory arrangement; or
• Net Worth: A household net worth (excluding the value of a primary residence and related debt) of more than $2,700,000 (adjusted from $2,200,000) at the time of entering into the advisory agreement.

The adjusted thresholds will not apply retroactively or to contractual relationships entered into prior to the effective date.

Key Takeaways and Recommended Next Steps

1. Update Fund Offering Documentation. Private fund advisers who oversee Section 3(c)(1) funds should review their investor questionnaires, subscription agreements, and transfer documentation to incorporate the updated dollar thresholds for qualified client eligibility.
2. Update Compliance Programs. Advisers should review compliance policies and procedures, private placement guidelines, marketing materials, and training materials for references to the dollar-based qualified client thresholds and make any necessary updates.
3. Review Indirect Basis Application. For RIAs advising a Section 3(c)(1) fund[2], mutual fund, or business development company under Rule 205-3(d), performance fee limitations also apply on an indirect basis. To the extent that an investor in any of these products is being charged a performance fee, review investor materials to ensure that the fund is not charging such fees to non-qualified client investors.
4. Application of Indirect Basis for Colorado RIAs. The regulations adopted under the Colorado Securities Act impose additional conditions on exempt reporting advisers (“ERAs”) that advise a Section 3(c)(1) fund. For these ERAs, interests in the Section 3(c)(1) fund may be offered only to qualified clients.[3] ERAs should therefore review subscription documents to seek to ensure they do not inadvertently create a compliance gap.
5. Assess Timing of Upcoming Closings. As fund sponsors prepare for upcoming initial or additional closings involving investors who will be charged a performance fee, those sponsors should account for the higher thresholds when obtaining confirmations from such investors.

For additional guidance or support, please reach out to a member of our Asset Management Group or another member of the Davis Graham Team.

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[1] 17 C.F.R. §275.205-3.

[2] Note that under Rule 205-3, the fund is not required to “look through” to the investor level to determine qualified client status for Section 3(c)(5), 3(c)(7), or 3(c)(9) funds.

[3] Colorado Rule 51-4.11(c)(1)(IA).

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

Background

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

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

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

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

Analysis

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

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

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

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

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

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

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

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

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

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

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

Background

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

The Court’s Analysis

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

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

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

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

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

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

Consistency with Prior Eminent Domian Caselaw

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

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

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

Practical Implications

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

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

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

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

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

The Cooperative Bargain and Its Limits

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

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

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

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

The Sustainability Paradox

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

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

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

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

The SMR Pipeline

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

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

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

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

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

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

Coal Plant Site Conversion

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

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

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

Transmission Cost Allocation Reform

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

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

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

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

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

NERC Reliability Standards and the Registration Question

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

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

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

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

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

Voluntary Grid Support: The Strategic Case

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

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

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

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

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

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

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

Series Synthesis

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

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

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

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

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

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

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

A Note on What Comes Next

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

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

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

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

This alert is intended to provide a general overview of the grid responsibility, sustainability, and policy considerations applicable to data center behind-the-meter generation. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

RJ Colwell is a Senior Associate at Davis Graham & Stubbs LLP in the Energy & Mining Group. His practice focuses on the regulatory, transactional, and structuring dimensions of data center power, advising data center developers, power generation companies, and their investors and lenders on FERC regulatory matters, behind-the-meter generation, co-located load arrangements, and energy infrastructure transactions. RJ can be reached at rj.colwell@davisgraham.com.