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.