Texas proposes new interconnection standards for large electric loads: Regulatory implications for large energy users

Large electricity users – particularly data centers and other energy intensive facilities – are reshaping how regulators, utilities, and grid operators think about system planning and interconnection. In multiple regions across the United States, proposed projects contemplate single site demand measured in the hundreds of megawatts (MW), in some cases on development timelines that outpace planned generation and transmission infrastructure development. As a result, policymakers are increasingly focused on how to accommodate rapid load growth without undermining reliability or shifting costs to other system users.

Against this backdrop, the Public Utility Commission of Texas (PUCT) proposed a new rule – 16 Texas Administrative Code (TAC) §25.194 – on March 12, 2026 that would establish detailed interconnection standards for new and expanding electric loads of 75 MW or greater in the region where electric power flow is managed by the Electric Reliability Council of Texas (ERCOT). The proposed rule is intended to implement Senate Bill 6 – signed into law on June 20, 2025 – which directed the Commission to develop a framework for large load interconnections that both supports economic development and addresses concerns around system reliability and stranded infrastructure costs.

Texas is among the first states to translate these dual priorities into a comprehensive regulatory proposal, and the proposed rule offers an early look at how jurisdictions may seek to allocate risk, require upfront commitments, and manage uncertainty associated with large scale load growth. While the proposed rule is specific to Texas and ERCOT, it reflects challenges that are emerging nationwide and is likely to inform policy discussions well beyond the state.

Overview of the proposed Texas rule

Proposed 16 TAC §25.194 may reflect a policy shift toward requiring earlier certainty and financial commitments from large load customers seeking to interconnect in ERCOT. Under the proposed rule, the interconnection process would place greater emphasis on project readiness, transparency, and risk allocation at the outset.

Taken together, the proposed requirements would establish conditions to discourage speculative or duplicative interconnection requests and protect transmission planning from projects that may later be delayed, downsized, or abandoned. For data centers and other energy intensive projects, this means aligning interconnection strategy, site control, permitting progress, and capital planning before projects can advance in the queue.

Draft Rule §25.194 would apply to any large load customer in ERCOT that seeks:

• A new interconnection that is equal to or exceeds 75 MW,
• An expanded interconnection that equals or exceeds 75 MW for the first time, or
• An expanded interconnection that exceeds 75 MW by 75 MW or more.

Key requirements are as follows: 

• Front loaded project readiness requirements. The proposed rule establishes a two‑step structure requiring large‑load customers to first execute an intermediate agreement demonstrating site control, permitting progress, and development readiness. Following execution of the intermediate agreement, the interconnecting utility must coordinate with ERCOT to initiate the interconnection study within 60 days.  
  
  
• Upfront fees and financial security. The proposed rule requires large-load customers to pay minimum interconnection study fees of $100,000 for projects with requested peak demand of 75–249 MW and $300,000 for projects with a requested peak demand of 250 MW or more – with customers responsible for actual costs if those amounts are exceeded. Beginning in 2027, these thresholds would be adjusted every five years based on the Consumer Price Index. Customers would also be required to post financial security of $50,000 per MW of requested peak demand upon execution of the intermediate agreement, as well as additional financial security for significant equipment or services (with lead times of six months or more before such items may be procured). A non refundable interconnection fee of $50,000 per MW of contracted peak demand would apply once studies are complete.
  
  
• Compressed post study execution timelines. Following completion of ERCOT’s interconnection studies, customers would have 30 days to execute an interconnection agreement or face cancellation. They would be required at that stage to fund 100 percent of direct interconnection costs and provide security for certain system upgrades.
  
  
• Defined financial consequences for delay or withdrawal. If a project is delayed, downsized, or withdrawn, the proposed rule generally limits refunds of posted financial security to 20 percent, with the remaining 80 percent applied to the transmission provider’s rate base after outstanding costs are covered; for projects that successfully energize, refunds are staged over time, with final balances released only after five years of sustained operation at contracted demand. Notably, contribution in aid of construction payments for direct interconnection costs are not refundable under any circumstances, including voluntary withdrawal or failure to meet energization milestones.

In practical terms, these requirements could result in significant upfront capital commitments. These financial thresholds would be higher than those imposed by other major US grid operators, where study deposits and interconnection fees for load customers are typically measured in the tens of thousands of dollars rather than millions.

Implications for developers and large power users

If adopted largely as proposed, the proposed rule would represent a change in the framework governing large load development in Texas. Projects would be required to demonstrate a higher degree of certainty earlier in the interconnection process, which could affect site selection, permitting strategy, and financing timelines.

The proposed framework also addresses the timing and structure of capital commitments during the interconnection process. Upfront financial commitments would be required earlier in project development, and the proposed rule specifies how posted funds would be treated if projects are delayed, modified, or withdrawn. In addition, disclosure obligations relating to “substantially similar” interconnection requests may factor into how developers coordinate timing and prioritization across multiple sites or jurisdictions.

From a system planning perspective, the proposed rule establishes parameters governing the assumptions used in transmission planning and interconnection studies, including how interconnection requests that do not ultimately move forward are treated.

Broader regulatory context

Although the proposed rule would apply only within ERCOT, similar issues are being considered in other jurisdictions. Across the country, regulators, utilities, and regional transmission organizations are examining how to address unprecedented large load growth while maintaining system reliability and factoring in cost considerations.

Texas’s proposed rule provides an example of how a state may approach these issues – including by establishing requirements related to proof of project readiness, financial commitments, and risk allocation to large load customers. Other jurisdictions are exploring different approaches, resulting in regulatory frameworks that vary by state and region.

For companies developing energy intensive projects in multiple markets, these differences underscore the importance of understanding varying interconnection requirements and regulatory approaches across jurisdictions.

Next steps

As the PUCT’s rulemaking process moves forward, stakeholders may wish to monitor the following key milestones: 

1. April 17, 2026 is the deadline to file initial written comments on the proposed rule and to request a public hearing in PUCT Project No. 58481 
   
   
2. Later in 2026, the Commission is expected to review stakeholder input and determine whether to adopt the rule as proposed or with modifications

The regulatory treatment of large electric loads is evolving rapidly as state commissions, regional grid operators, and federal regulators respond to unprecedented growth in energy intensive development. As these developments implicate regulatory, interconnection, and project finance considerations across jurisdictions, DLA Piper’s Energy and Natural Resources and Regulatory and Government Affairs teams continue to monitor these laws and analyze their potential implications across industries. 

If you have questions about the proposed Texas rule or how similar developments may affect current or planned projects across the United States, please contact any of the authors.