FERC’s Regional Path for Large-Load Integration: Prudent Avoidance, Not Abstention

FERC’s June 18, 2026 show-cause orders issued in response to DOE’s request are best understood as the next step in the Commission’s long-running open-access transmission and transmission-planning project. Since Order No. 888, FERC has used open-access transmission tariffs to prevent undue discrimination in transmission service. Order No. 890 brought coordinated, open, and transparent planning to the center of that framework. Order No. 1000 added regional and interregional planning, public-policy planning, and tariffed cost-allocation methods. Order No.

1920 then pushed transmission providers toward long-term regional planning, improved coordination with generator interconnection, advanced transmission technologies, and greater transparency between local and regional planning.

When the Department of Energy asked FERC in October 2025 to develop standardized procedures for interconnecting large loads to the transmission system, the request posed a problem in its hardest legal form. Data centers, industrial electrification, advanced manufacturing, artificial-intelligence infrastructure, crypto mining, and other large-load additions are moving faster than most utilities can absorb using their traditional forms of planning to ensure reliability. But a national federal rule governing large-load interconnection also risked serious Constitutional and statutory headwinds by inviting FERC to cross the line between Federal authority over interstate transmission and wholesale power supply arrangements and into legally protected state authority over supply adequacy, retail service, siting, and retail cost allocation.

The Commission did not take the single nationwide rulemaking path sketched by DOE’s ANOPR. It instead opened regional proceedings under Section 206 of the Federal Power Act directed to the several regional grid organizations: PJM, SPP, MISO, NYISO, CAISO, and ISO-NE. Each organized market must now show that its tariff remains just and reasonable or explain what tariff changes would be needed to address large-load study procedures, cost-shift protections, flexible-load service, co-location, behind-the-meter generation, and generator interconnection for resources serving nearby or co-located load.

This approach does not avoid federal action. Rather, it channels federal action into the transmission-tariff, transmission-planning, generator-interconnection, cost-allocation, and transparency tools where FERC’s authority is most established.. The result is prudent avoidance of jurisdictional confusion and associated litigation--not abstention.

What Problem Did the DOE Identify?

DOE’s Section 403 letter and accompanying advance notice of proposed rulemaking reflected a legitimate reliability and economic development concern. Large loads are no longer ordinary incremental additions to the utility forecast. A single data-center campus can look like a mid-sized city. At the upper end of the current development trend, a single campus can approach the load profile of a small or mid-sized city.  Several such campuses in the same electrical area can change local transmission needs, resource adequacy assumptions, voltage support requirements, and the economics of generator development. In some situations, the power consumption or “load” can be roughly comparable to a large city, such as Pittsburgh, Pennsylvania or San Antonio, Texas. 

The speed of the development cycle makes the problem harder. Cities and towns grow fairly methodically and not all at once. Large data-center campuses can arrive in large blocks, on commercial development timelines that are much shorter than the timelines required for reasonable evaluation, transmission upgrades or new generation additions. They can be planned, financed, and constructed on timelines that are shorter than the timelines required for traditional transmission upgrades or new generation additions. The result is a planning mismatch:

• Load developers need speed to power. 
• Transmission owners need reliable study results. 
• Existing customers need protection from stranded or socialized costs. 
• State regulators need enough information to protect retail customers. 
• RTOs and ISOs need operational visibility and resource adequacy assurance.

DOE’s proposal sought to solve the problem by asking FERC to standardize large-load interconnection procedures nationwide. It proposed a relatively low 20 MW threshold and suggested direct assignment of upgrade costs to the large-load customer. That approach promised a uniform process, clear cost responsibility, and faster integration of nationally important load. It also raised the question that has defined electric regulation since the Federal Power Act was enacted: where does federal transmission jurisdiction end and well-established state authority over retail supply and local utilities begin?

Why was a Single National Rule Hard?

Section 201(b) of the Federal Power Act gives FERC jurisdiction over transmission in interstate commerce and wholesale sales of electric energy. It reserves the states’ authority over retail sales, local distribution, generation facilities, and matters not otherwise subject to federal jurisdiction. That division is not always easy to administer in a modern grid, but it remains central to the statute.

Relatively recent U.S. Supreme Court decisions, such as New York v. FERC and FERC v. EPSA, teach two related lessons. First, FERC’s authority over interstate transmission is broad, including unbundled retail transmission service where transmission service is separated from the retail sale. Second, FERC’s “affecting” jurisdiction has limits. A federal rule must directly affect jurisdictional rates or service, and it cannot be used to regulate retail sales or state-jurisdictional matters simply because those matters influence wholesale markets or transmission planning.

That distinction matters most outside organized markets. In non-RTO, vertically integrated regions, large loads commonly take bundled retail service under state-approved tariffs. Transmission, generation, and retail service are not separated in the same way they are in an RTO tariff structure. A national FERC rule prescribing cost responsibility for bundled retail load would invite  the argument that FERC was using the vocabulary of transmission interconnection to indirectly regulate the economics of retail service. 

FERC’s June 18 orders appear to recognize that problem. The Commission did not federalize large retail load interconnection. It focused on transmission service to Eligible Customers, the study processes needed to determine whether that service can be provided reliably, Network Upgrade costs that may enter jurisdictional transmission rates, generator interconnection procedures, and ancillary-service or transmission-service charges for load that remains able to rely on the grid. It also repeatedly preserved state authority over retail sales, retail service terms, siting, construction, resource planning, and retail cost allocation.

What did FERC do Instead?

The June 18 orders share a common architecture. Each order directs the relevant RTO or ISO, and in several cases the relevant transmission owners, to respond within 60 days. Each order also directs an informational report on generation or resource adequacy for large-load growth. FERC encourages Section 205 filings and allows the possibility of a limited abeyance if the region is developing concrete tariff changes.

The orders create a federal large-load tariff project, but not a single national pro forma. FERC is using regional Section 206 records to test whether existing tariff structures are adequate and, if not, what region-specific reforms are needed. FERC is not asking each region to copy a single national pro forma. It is asking each region to explain whether its current tariff is adequate and, if not, to propose revisions suited to that region’s market design and transmission structure.

In the June 18, 2026 orders, FERC focuses on several common elements:

• A clear large-load definition, generally centered on new commercial or industrial load of significant size, with regional variations around that threshold, voltage level, site configuration, and co-location status; 
• Application and study procedures for Eligible Customers seeking transmission service on behalf of large loads;
• Readiness requirements, deposits, milestones, and disclosure of duplicative or overlapping requests;
• Operational requirements such as hourly forecasts, telemetry, communications, remote disconnect, ramp-rate limits, ride-through obligations, and controls or protection systems;
• Evaluation of alternative transmission technologies such as STATCOMs, static VAR compensators, advanced power-flow control, advanced conductors, tower lifting, and dynamic line ratings;
• Public transparency around Network Upgrades and their estimated costs;
• Cost-recovery agreements, minimum contributions, credit support, and revenue-requirement crediting to protect other transmission customers;
• Transmission services for flexible large loads that can limit withdrawals;
• Rules for co-located load and load with behind-the-meter generation; an
• Generator interconnection services for generation serving electrically proximate large load or large co-located load.

What are the Regional Differences?

The most important feature of the June 18 orders is that they are regional. That is not a compromise in the weak sense. It is the legal and operational premises of the orders.

PJM is the co-location template region. 
The PJM co-location orders already produced the most developed service design, including Interim Network Integration Transmission Service, Firm Contract Demand service, and Non-Firm Contract Demand service. Those orders also address controls, penalties, behind-the-meter generation netting, anti-toggling protections, and ancillary-service charges. The new PJM show-cause order extends the inquiry beyond co-location to ordinary large loads, flexible large loads, cost-recovery protections, and generation serving electrically proximate load.

SPP is the large-load process proof-of-concept region. 
FERC has already accepted SPP’s High Impact Large Load (“HILL”) process, High Impact Large Load Generation Assessment (“HILLGA”) process, and Conditional High Impact Large Load Service (“CHILLS”). HILL provides a tariff-based study framework for large loads. HILLGA provides a path for generation specifically identified for and limited to serving a nearby HILL. CHILLS provides conditional service while firm transmission service, designated resources, or upgrades are being developed. SPP is not done, but it is the region that shows the model can be built.

MISO is the full conventional-OATT buildout region.
MISO has a traditional Regional Transmission Organization (“RTO”) framework, including network and point-to-point service, transmission planning, generator interconnection, and formula-rate cost recovery. But it does not have the SPP-style HILL/HILLGA/CHILLS architecture or the PJM co-location service architecture. FERC’s MISO order presses for the full set of reforms in a conventional organized-market setting.

NYISO is the existing-process-but-incomplete-tariff region.
NYISO already has load interconnection procedures and a distinctive financial-reservation transmission model. It also has BTM:NG Resource rules and significant transmission-owner involvement in facilities studies and local processes. FERC’s concern is not that nothing exists. It is that key elements may not be sufficiently tariffed, transparent, consistent, or tailored to large-load dynamics and risks.

CAISO is the adaptation region.
CAISO does not fit neatly into the traditional network-service model. It operates with Scheduling Coordinators, Participating Transmission Owners, daily transmission-service concepts, and Access Charges. FERC is asking CAISO to adapt the same large-load principles to that structure rather than import PJM’s tariff language wholesale.

ISO-NE is the preventive region.
FERC acknowledges that New England has not yet seen the same level of data-center and large-load pressure as some other regions. But ISO-NE’s order shows that FERC is not waiting for saturation before asking for tariff clarity. ISO-NE has Regional Network Service, Local Network Service, Local Point-to-Point Service, generator-interconnection, provisional-service, and surplus-service structures. FERC’s question is whether those existing mechanisms provide adequate rules of the road for large loads, co-location, BTMG, flexible service, and generation serving nearby load.

Cost-Shifting Protection Replaces One-Size-Fits-All Direct Assignment

DOE’s ANOPR put substantial attention on direct assignment of upgrade costs to the large-load customers. FERC’s orders take a more nuanced path. They focus on protecting transmission customers from cost shifts without adopting a one-size-fits-all national direct-assignment rule.

The problem is straightforward. A large-load request may cause an RTO, ISO, or transmission owner to plan new facilities. If those facilities are built and included in transmission revenue requirements, other transmission customers may pay if the load does not materialize, ramps more slowly than expected, takes less service than requested, or later curtails operations. That risk is not hypothetical. Large-load projects can be speculative, duplicative, or sensitive to changing power prices and project economics.

FERC’s preferred tool appears to be a tariffed cost-recovery and credit-support framework, often implemented through agreements among the RTO or ISO, the relevant transmission owner, and the Eligible Customer taking service for the large load. The orders ask whether tariffs should include pro forma agreements among the RTO/ISO, the relevant transmission owner, and the Eligible Customer taking service on behalf of the large load. Those agreements may require minimum contributions, credit support, or other financial security, with payments credited to transmission-owner revenue requirements so other customers are protected.

That approach is important because it is tied to jurisdictional transmission rates. It does not purport to dictate how a state commission allocates retail costs. Instead, it creates federal transparency and revenue-requirement protections that state commissions can use when they decide how wholesale transmission costs should be recovered at retail.

Co-Location Is Becoming a Tariff Category

Before the recent orders, co-location was often discussed as a creative project structure. After the PJM orders and the June 18 show-cause orders, it is becoming a tariff category. FERC is no longer asking only whether a generator and a data center can share facilities. It is now asking who takes transmission service for the load, what rights that customer reserves, what charges apply when the load remains synchronized with the grid, how behind-the-meter generation is netted, what controls prevent unauthorized withdrawals, and how the arrangement affects resource adequacy.

This is especially important for load with behind-the-meter generation. PJM, CAISO, ISO-NE, and NYISO each face some version of the gross-load versus net-load issue. A large load may ordinarily be served by onsite generation and show little net withdrawal. If the grid must stand ready to serve the load when the onsite generation is unavailable, FERC is concerned that netting may understate the load’s use of, or reliance on, the transmission system. That concern drives FERC’s interest in materiality thresholds, gross-demand charges for certain ancillary services, and service products based on reserved withdrawal rights.

The same logic applies to generation serving electrically proximate load. FERC is interested in ways to bring new generation online faster when it is intended to serve nearby load and has limited grid impact. However, the generator-interconnection service must be defined carefully. The generator’s output may need to be limited to the load’s hourly forecast, or controls may need to ensure that net injection does not exceed existing interconnection rights. FERC is encouraging innovation, but it is not treating proximity as a substitute for reliability studies or enforceable operating limits.

How does this affect Non-RTOs?

The June 18 orders leave the hardest jurisdictional question largely unresolved because the country’s transmission structures remain regionally distinct from one another. Order No. 2000 encouraged voluntary RTO formation, and the result is the system we have today: organized markets across much of the country, but large non-RTO regions where transmission service, generation planning, and retail service remain more tightly bundled inside vertically integrated utility structures. They apply to organized markets with filed tariffs and separated transmission-service constructs. They do not directly apply to the Southeast or large portions of the West that are not in RTOs. In those regions, large-load customers often take bundled retail service from vertically integrated utilities under state regulation.

That matters. In RTO regions, FERC can anchor reform in OATT transmission service, RTO-administered study procedures, Network Upgrade cost recovery, formula rates, ancillary-service charges, and generator interconnection. In non-RTO regions, the same physical load may be served under a bundled retail tariff through a state-regulated integrated utility. The transmission facilities may be part of a broader integrated resource plan, and the state commission may control line-extension policy, contribution-in-aid-of-construction treatment, retail-class cost allocation, and utility resource obligations.

FERC commissioners have encouraged non-RTO utilities and states to consider approaches that reflect, as appropriate, emerging principles in the organized-market orders, but any such approach will need to be adapted to bundled retail service, state integrated-resource planning, and state retail cost-allocation frameworks. 

What Comes Next?

The orders are only the beginning. Each RTO or ISO must now build a record. Transmission owners will need to address facilities studies, local planning, construction responsibility, operational controls, protection systems, cost estimates, cost-recovery agreements, and formula-rate crediting. State commissions and consumer advocates will need to decide what information they need from RTO-level transparency to protect retail customers. Large-load developers will need to show that their projects are real, financeable, technically controllable, and capable of being studied based on enforceable operating parameters.

The most difficult implementation questions are practical, not abstract. 

• Can a meaningful large-load study be completed in 60 to 90 days, and if so, what level of detail does that study provide? 
• How should speculative or duplicative requests be screened without blocking viable projects?
• How should flexible load be charged when it wants limited firm rights and conditional service above that level? 
• How should a cost-recovery agreement account for phased load ramp, broader system benefits, and pre-existing state agreements? 
• How should behind-the-meter generation be treated when it reduces normal withdrawals but does not eliminate the grid’s obligation to stand ready? 
• How should a generator serving nearby load participate in energy, ancillary-service, or capacity markets?
• These questions will not be answered by slogans about speed to power or cost causation. They require tariff work, engineering discipline, and a careful record.

Conclusion: Clarity, Not Uniformity

The June 18 orders are best understood as prudent avoidance, not abstention: FERC acted, but it acted through the open-access transmission and transmission-planning framework that has carried much of electric policy since Order No. 888. FERC accepted DOE’s premise that large-load growth is now a national reliability, affordability, and economic-development issue. It declined to solve that problem through a uniform federal rule that would have invited a direct collision with state retail authority. The Commission instead chose a more durable path: regional Section 206 proceedings tied to transmission service, transmission rates, cost causation, generator interconnection, and tariff transparency.

That choice leaves hard questions for each region. It does not tell every data center how fast it can connect. It does not tell every transmission owner who will pay for every upgrade. It does not resolve the non-RTO bundled-retail question. But it does preserve the Federal Power Act’s basic “cooperative federalism” design. Federal authority is strongest where the issue is transmission service, transmission rates, tariffed transmission planning, generator interconnection, operational reliability, and protection against cost shifts in jurisdictional transmission rates. State authority remains central where retail service, siting, integrated resource planning, and retail cost allocation are an issue.

The next phase will test whether cooperative federalism can move as quickly as the large loads now seeking service. The answer should be clarity, not uniformity.