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.

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.

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

Background

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

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

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

The Court’s Analysis

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

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

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

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

Significance

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

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

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

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

Background

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

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

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

The Tenth Circuit’s Analysis

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

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

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

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

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

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

Significance

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

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

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

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

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

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

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

Wyoming: The Regulatory Framework

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

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

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

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

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

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

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

The Landlord-Tenant Structure in Wyoming

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

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

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

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

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

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

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

SPP’s Expansion into Wyoming

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

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

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

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

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

Incumbent Utility Considerations in Wyoming

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

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

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

Utah: Pragmatic Regulation

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

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

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

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

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

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

Municipal Utility Alternatives

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

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

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

Rocky Mountain Power and Western Market Evolution

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

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

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

Integrated Resource Planning and Data Center Load

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

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

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

The Investment Thesis for Wyoming and Utah

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

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

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

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

Practical Considerations

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

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

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

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

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

What to Watch in Wyoming and Utah

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

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

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

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

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

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

This alert is intended to provide a general overview of the regulatory frameworks for data center power in Wyoming and Utah. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

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

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

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

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

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

The Colorado Public Utilities Commission’s Regulatory Philosophy

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

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

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

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

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

The LLT Filing includes three primary components.

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

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

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

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

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

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

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

The Generation Cap and Its Implications

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

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

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

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

Climate Policy Framework

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

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

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

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

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

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

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

Environmental Justice

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

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

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

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

Self-Generation and Behind-the-Meter Rights

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

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

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

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

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

Utility Certification and Territorial Considerations

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

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

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

Transmission Access and Constraints

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

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

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

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

Electric Resource Planning and Data Center Load

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

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

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

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

Optimal Structures for Colorado

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

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

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

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

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

The Colorado Investment Thesis

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

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

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

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

What to Watch in Colorado

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

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

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

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

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

This alert is intended to provide a general overview of the regulatory framework for data center power in Colorado. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.

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