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.