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.