January 12, 2026
There has been a recent flurry of regulatory activity in both Washington, DC, and Colorado as federal and state regulators work to establish new frameworks for data center interconnection and co-located generation. The Secretary of Energy directed FERC to consider an Advanced Notice of Proposed Rulemaking on large load interconnection procedures, FERC issued an order requiring PJM to develop co-location tariff provisions, the Colorado Public Utilities Commission directed Xcel Energy to file large-load tariff principles by January 2026, and FERC rejected Tri-State’s proposed large load tariff on jurisdictional grounds. These developments underscore ongoing efforts to adapt existing frameworks to how utilities and regulators approach data center interconnection, cost allocation, and co-located generation.
DOE’s Direction to FERC
On October 23, 2025, Secretary of Energy Chris Wright directed the Federal Energy Regulatory Commission (FERC or Commission) to consider an Advanced Notice of Proposed Rulemaking (ANOPR) addressing interconnection procedures for large loads (defined as those exceeding 20 megawatts (MW)), and requesting that FERC issue a final rule by April 30, 2026. Secretary Wright issued the ANOPR pursuant to Section 403 of the Department of Energy Organization Act, which empowers the Secretary of Energy to propose rules to FERC, but does not require FERC to implement them. Additionally, FERC issued a notice inviting comments regarding the ANOPR on October 27, 2025, in Docket No. RM26-4-000.
DOE’s proposed ANOPR advances the position that FERC has jurisdiction over large load interconnections through FERC Order No. 888, based on four legal theories:
- large load interconnections are a critical component of open access transmission service analogous to generator interconnections under FERC Order No. 2003;
- such interconnections directly affect jurisdictional wholesale rates;
- the proposal does not intrude on states’ retail electricity jurisdiction; and
- FERC’s exclusive jurisdiction over transmission of electric energy in interstate commerce encompasses interconnection service.
The ANOPR enumerates 14 guiding principles, including limiting FERC’s authority to interconnections directly to transmission facilities, applying reforms only to new loads greater than 20 MW, studying load and hybrid facilities alongside generation projects, implementing standardized deposits and withdrawal penalties, and allocating 100% of network upgrade costs to the load.
Whether FERC has statutory authority to regulate large load interconnections remains uncertain. Any rules promulgated will face scrutiny under the major questions doctrine (West Virginia v. EPA) and review under Loper Bright Enterprises v. Raimondo, which held that courts should not apply Chevron deference to agency interpretations of ambiguous statutes. FERC’s notice inviting comments on the ANOPR was procedural only and did not discuss or endorse the four legal theories noted above. FERC’s own precedent also highlights this ambiguity: in rejecting Tri-State’s large load tariff (discussed below), FERC stated that the proposal may regulate ‘terms and conditions of a Customer’s retail service in ways that are beyond the Commission’s authority.’ Additionally, the National Association of Regulatory Utility Commissioners (NARUC) has urged FERC to substantially modify the ANOPR, asserting it infringes on states’ retail electricity jurisdiction. These challenges create substantial uncertainty as to whether FERC will adopt the ANOPR in whole, in part, or at all.
FERC’s PJM Co-Location Order
On December 18, 2025, FERC unanimously issued an order directing PJM Interconnection (PJM) to revise its tariff to address co-located loads at generating facilities. The order arose from FERC’s show cause proceeding following high-profile co-location arrangements, including Amazon’s data center at Talen Energy’s Susquehanna nuclear plant located in Pennsylvania and Microsoft’s Three Mile Island restart agreement.
FERC found PJM’s existing tariff unjust and unreasonable due to lack of clarity regarding co-located loads. The order requires PJM to offer four transmission service options:
- traditional Network Integration Transmission Service for entire nameplate load;
- interim non-firm service permitting expedited construction before grid upgrades are completed, with acceptance of curtailment risk;
- firm contract demand service for only the portion of load expected to be served by the grid; and
- non-firm contract demand service (which carries curtailment risk).
The order directs PJM to propose mechanisms, such as minimum monthly charges, to ensure that costs of maintaining grid reliability and backup capability are appropriately allocated, even for facilities with limited grid usage or rarely used backup service. Final tariff details remain pending PJM’s compliance filings (due in January 2026) and further FERC review.
While Colorado is not within PJM’s footprint, FERC’s order signals potential federal regulatory approaches to co-location and may inform or influence Colorado’s frameworks. For example, Xcel Energy’s large-load tariff filing due in January 2026 could potentially incorporate concepts from the PJM order.
Colorado PUC Directive to Xcel Energy
In late October 2025 (with a written decision issued in December 2025), the Colorado Public Utilities Commission (PUC) adopted guiding principles for service to large-load customers and directed Xcel Energy to file a more detailed large-load tariff proposal in January 2026 as part of Xcel’s Electric Resource Plan proceeding (Proceeding No. 24A-0442E). The PUC-adopted guiding principles include measures such as upfront fees and security deposits, minimum 15-year service contracts, minimum bill requirements for reserved capacity, and early exit fees if the developer terminates service before the contract term.
Xcel’s forthcoming large-load tariff proposal is expected to address how co-located generation affects cost allocation. This may include differentiated transmission charges that reflect actual grid usage rather than full nameplate capacity for data centers with onsite generation, though minimum charges for maintaining backup grid service could also apply, similar to concepts in FERC’s PJM order.
Xcel’s formal tariff filing could inform approaches by other Colorado utilities and cooperatives addressing large loads, though structural and governance differences among utilities may limit direct applicability, and the tariff’s terms are expected to materially affect project economics and feasibility for data centers requiring grid-supplied power or backup service.
Tri-State’s Rejected Large Load Tariff
In August 2025, Tri-State proposed a High-Impact Load Tariff at FERC (Docket No. ER25-3316) for loads exceeding 45 megawatts. On October 27, 2025, FERC rejected the tariff, determining that provisions requiring member cooperatives’ retail customers to execute agreements and related security deposit requirements exceeded FERC’s jurisdiction over wholesale transactions under Federal Power Act sections 205 and 206. As of this writing, no revised tariff has been proposed.
FERC’s rejection underscores the jurisdictional tensions evident in DOE’s ANOPR. Developers considering sites in Tri-State member cooperative territories (which include 15 Colorado cooperatives) may want to consider engaging early with both the local distribution cooperative and Tri-State to understand capacity availability and study timelines. Until a revised framework is in place, large load interconnection in Tri-State territories will follow existing procedures.
Potential Colorado Implications
These federal and state actions signal several key themes:
Cost Allocation Based on Actual Use. Both FERC’s PJM order and Colorado’s emerging frameworks signal emerging interest in charging data centers based more closely on grid usage, rather than full nameplate capacity, though minimum charges for backup service could still apply.
Developer Financial Commitments. Utilities and regulators are requiring upfront security deposits, long-term contracts, and early exit fees to ensure speculative projects do not force infrastructure investments that other ratepayers ultimately bear. These measures aim to protect existing ratepayers from bearing the costs of speculative or withdrawn projects, while FERC’s PJM order also creates pathways for developers willing to accept curtailment risk to potentially expedite timelines.
Co-Location Frameworks. FERC’s PJM order and DOE’s ANOPR signal that co-located generation can be a viable model when structured to protect ratepayers. However, the requirement that generators and co-located loads fund transmission upgrades to maintain service for existing customers means co-location does not eliminate grid-related costs.
Federal-State Jurisdictional Tensions. The DOE ANOPR and Tri-State’s rejected tariff filing at FERC highlight ongoing tensions between federal and state authority. FERC’s own statement in the Tri-State rejection regarding the limits of its authority, combined with NARUC’s opposition to the ANOPR, suggests that any expansion of federal jurisdiction will be contested.
Interconnection Timelines. Despite efforts to clarify rules, physical interconnection timelines (driven by studies, network upgrade design, and construction) remain lengthy (currently estimated at anywhere from 24 to 48 months).
Considerations for Colorado Stakeholders
Companies considering data center investments in Colorado may wish to consider the following:
- Xcel’s January 2026, tariff filing will establish initial service terms, cost allocation, and co-location treatment for the state’s largest utility. Interested stakeholders should review the filing (Docket No. 24A-0442E).
- Early engagement with Xcel, Tri-State, or other serving utilities during site selection can provide clarity on capacity availability, interconnection study timelines, and how emerging tariff frameworks may affect project economics.
- With regulatory clarity increasing and cost allocation frameworks becoming more defined, co-located generation should be evaluated. However, financial models should account for network upgrade obligations that may be required when generators “leave the grid.”
- Stakeholders may wish to monitor FERC Docket No. RM26-4-000 and consider filing comments to ensure any federal framework accommodates Colorado’s regulatory structures, particularly given ongoing jurisdictional contests and active comment proceedings. Additionally, monitoring PJM’s January 19, 2026 report to FERC and subsequent tariff implementation may provide insights into frameworks that could be adopted in other regions.
- Power supply strategy – whether traditional utility service, co-located generation, hybrid models, or acceptance of curtailment risk through non-firm arrangements – should be determined early and integrated with cooling design, air permitting, water rights strategy, and land use review.
The convergence of federal action by DOE and FERC, Colorado PUC directives, and Tri-State’s jurisdictional challenges creates a dynamic regulatory environment for data centers and large loads in Colorado. While some clarity is emerging, significant questions remain regarding implementation, cost allocation details, and the interplay between federal and state authority.
For questions about energy regulatory developments impacting data centers, please contact RJ Colwell.