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Before a large data centre requests grid service, ask the utility and transmission organizations to define the connection process, required studies, available capacity, upgrade obligations, tariff, contract commitments and curtailment rules in writing. Bring a phased, technically detailed load forecast rather than a single headline megawatt number, and treat every early capacity or date estimate as conditional until the responsible utility, RTO/ISO and regulator approve it.
The Federal Energy Regulatory Commission (FERC) generally describes a large load in its RM26-4 proceeding as demand above 20 megawatts (MW), but that is the docket’s framing, not a universal threshold. A project’s actual process depends on its location, voltage, utility territory, transmission owner, RTO/ISO and state rules.
Prepare a utility-ready load package first
Your first meeting will be more productive if the utility receives a consistent technical package. State the requested peak MW for each development phase, expected energization date, ramp rate, confidence in each milestone and the consequences of delay. Separate the facility’s demand into IT/server equipment, cooling, electrical distribution losses and other building loads.
Include seasonal and day/night load shapes, expected power factor and any material changes during commissioning. NERC’s March 2026 large-load questionnaire asks for rated total MW including IT, distribution and cooling, component shares, power factor, time-varying demand, cooling configuration and motor-drive details. Use the same definitions in every application, forecast and presentation.
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- Site location, voltage level and evidence of site control.
- Phase-by-phase MW, MVA, ramp and in-service dates.
- Cooling technology, motor drives, power-electronic equipment and backup systems.
- Expected response to voltage or frequency disturbances, load drop and reconnection.
- Permitting, financing, equipment-order and construction milestones, with confidence levels.
Ask the utility to identify any missing data before it starts a formal study. A changed peak, ramp, location or in-service date can trigger a restudy, so maintain a version-controlled forecast.
1. Who owns the process and who can approve each step?
Ask for the named utility account lead, the distribution and transmission contacts, the transmission owner, the applicable RTO/ISO and the state regulator. Confirm whether the project enters a distribution load-review process, a transmission-level large-load process or both.
Request the sequence of applications
Obtain a written checklist showing which application, study agreement, service agreement, special contract, interconnection request or transmission-service request comes first. Ask who accepts each filing, who performs the study, who can change its assumptions and which decisions require regulator or RTO/ISO approval.
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Define escalation and communication
Get meeting frequency, response-time expectations, document portals and an escalation path for unresolved technical or commercial issues. Do not assume the person coordinating a feasibility screen has authority to approve a tariff, network upgrade or final service date.
2. What information and model data must we provide?
Ask for the utility’s required data template and modeling format. Confirm whether it needs hourly or sub-hourly profiles, minimum load, ramp-rate limits, harmonic or power-quality information, fault-current data, protection settings and equipment models.
Describe the load’s physical behavior
Explain cooling equipment, variable-speed drives, UPS systems, power-conversion equipment and automatic controls. Ask how the utility will represent motor starting, power factor correction, voltage sensitivity, frequency response and simultaneous load changes.
Describe abnormal events
Provide the expected behavior during a disturbance: which loads trip, how much demand drops, whether backup systems start, and how the facility reconnects. State the reconnection ramp and whether staged restoration is possible. NERC’s March 2026 questionnaire specifically seeks disturbance response, disconnection, reconnection and backup-system information because transmission-planning simulations use those behaviors to identify reliability problems and mitigation measures.
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3. Which studies will be performed, and what exactly will they decide?
Ask whether the project requires a screening or feasibility review, system-impact study, facilities study, transmission-service study, contingency analysis, reliability assessment or several studies in sequence. Request the scope, assumptions, data inputs, deliverables, responsible party, milestones, dependencies and payment schedule for each one.
Ask about restudy triggers
Have the utility list changes that invalidate the study: a higher peak, faster ramp, different power factor, changed voltage, new location, altered in-service date, a revised generation plan or a material change in queued projects. Ask whether a phase can be studied separately and how a later phase affects earlier findings.
Separate study results from approvals
A study may identify a technically feasible design without granting service rights or regulatory approval. Ask which conclusions are preliminary, which are binding, and what filings or agreements remain before construction can proceed. FERC’s 2026 proceedings discuss improving transmission-service applications and studies, but they do not guarantee a uniform process or a particular study duration.
4. How much capacity is available, and on what date?
Ask what physical or contractual constraint limits service: local transformer capacity, transmission capability, stability, short-circuit duty, generation adequacy, voltage performance or another limitation. Ask whether the quoted capacity is firm, conditional, deliverable only after upgrades or dependent on another customer’s project.
Demand a schedule with dependencies
Request milestone dates for engineering, permitting, procurement, construction, outages, testing and energization. Identify dependencies on long-lead transformers, transmission corridors, environmental approvals and other queued projects. Ask for a range of credible dates and the assumptions behind each date rather than treating an early estimate as a guarantee.
FERC staff reported that the average data-centre size increased from 25 MW in 2020 to almost 80 MW for facilities entering service in 2025, based on staff analysis of Yes Energy data in the 2026 2025 State of the Markets report. That average does not predict your project, but it explains why a large facility may require new generation or transmission infrastructure and why accurate entry forecasts matter.
5. Which upgrades are required, and who pays?
Request an itemized estimate covering customer-owned facilities, direct connection work, network upgrades, protection and metering, study deposits, security and ongoing transmission or distribution charges. Ask which costs are assigned solely to your project and which are shared with other customers.
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Clarify credits and cost shifting
Ask whether payments for network upgrades can be credited or refunded as later customers use the facilities, what conditions apply and when credits are paid. Ask what safeguards prevent your project from shifting costs to existing customers, and whether you could be charged for facilities built for a larger future load than you ultimately take.
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6. What tariff and contract commitments apply if the project changes?
Obtain the current tariff and any proposed special contract. Ask for contract demand, minimum bills, minimum term, collateral, milestone deadlines, ramp commitments, security-posting rules and adjustment mechanisms.
Model delay, downsizing and cancellation
Ask what happens if a phase is delayed, reduced, mothballed or canceled. Identify termination charges, minimum-payment exposure, unrecovered study or construction costs and obligations that survive termination. Ask whether the utility can reserve capacity before you reach a milestone and what happens if that reservation expires.
Check approval status
Mark every clause that requires state commission, FERC, RTO/ISO or other approval. Request notice of proposed tariff changes and a written explanation of which commercial terms are still negotiable.
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Ask the utility to describe every available service class and the operational consequences of choosing it. For each option, obtain curtailment triggers, advance notice, expected duration, frequency limits, restoration priority, testing requirements and compensation.
Test whether flexibility changes the study
Ask whether a controllable load, staged energization or an agreed curtailment level can qualify for different service treatment or reduce an identified constraint. FERC’s proceedings consider whether flexible loads might move through studies faster and address new transmission services for flexible large loads, but those are regulatory issues, not promises of a 60-day study or guaranteed accelerated service.
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Translate curtailment into operations
Map each interruption scenario to the data centre’s uptime design, backup generation, battery duration, maintenance plan and service-level commitments. A lower-cost or earlier service option is not equivalent to firm capacity if curtailment can occur without enough notice for an orderly workload transfer.
8. What reliability behavior must the data centre disclose?
Ask how the utility will model power factor, cooling motors, voltage response, frequency response, load shedding and reconnection. Provide validated equipment information where available and identify assumptions where final equipment has not been selected.
Agree on disturbance and reconnection rules
Confirm the voltage and frequency thresholds that cause automatic disconnection, the minimum reconnection delay, the maximum restoration ramp and whether the utility can block reconnection during a system emergency. Ask who controls each setting and how changes are approved.
Coordinate backup systems
Describe batteries, generators, automatic transfer schemes and black-start or islanding functions. Ask how generator trips, failed starts, testing and simultaneous transfers affect the grid model and the facility’s service obligations.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.9. How will onsite generation or co-location change the arrangement?
If the site will use behind-the-meter generation or share a campus with a power plant, ask whether the arrangement changes the interconnection process, transmission service, tariff, metering or cost allocation.
Cover imports, exports and outages
Ask how the utility treats imports when onsite generation is unavailable, exports when generation exceeds load, generator trips, planned maintenance, fuel interruptions and protection during islanding. Confirm whether an electrically proximate generator is considered part of the same load, a separate interconnection or a resource serving the grid.
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FERC’s RM26-4 docket raises reliability questions when a plant partially serves a large customer, while June 2026 regional actions address co-location and behind-the-meter generation. Obtain written responsibility for dispatch, telemetry, outage notification, testing and emergency separation; do not assume co-location eliminates transmission or distribution obligations.
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10. When will the project appear in load forecasts and resource plans?
Ask what evidence the utility needs before counting the project in its demand forecast or resource plan. Possible evidence may include site control, financing, permits, equipment orders and a credible construction schedule, but the utility should state its own thresholds.
Understand forecast updates
Ask how forecast treatment changes as milestones are achieved or missed, how the utility communicates revisions to the RTO/ISO and whether your load is modeled as a single block or phased demand. FERC’s market report describes utility and RTO/ISO forecast adjustments and emphasizes accurate estimates of when—and whether—large facilities enter service.
11. Which supply alternatives should we compare?
Evaluate alternatives against the same criteria rather than comparing headline connection dates or energy prices alone.
| Option | Service date and dependencies | Firmness and curtailment | Upgrades and recurring exposure | Reliability and clean-energy considerations |
|---|---|---|---|---|
| Grid-only service | Depends on available network capacity, studies, equipment, permits and queued projects. | Defined by the selected tariff; firm service may require upgrades and commitments. | Customer, direct-connection and network costs plus transmission or distribution charges. | Depends on the regional resource mix and grid contingencies. |
| Flexible or interruptible service | May alter study assumptions or timing if the utility accepts enforceable flexibility. | Subject to specified triggers, notice, duration, frequency and compensation. | May reduce or change upgrade requirements, but minimum commitments and collateral still apply. | Requires operational controls, backup capability and workload-curtailment planning. |
| Onsite generation | Depends on generator procurement, fuel, permits, interconnection and testing. | Reduces grid dependence but introduces generator-trip and fuel-availability risks. | Includes generation, controls, interconnection, backup import and possible export arrangements. | Emissions, fuel and clean-energy matching must be assessed with grid service. |
| Co-location with generation | Depends on the plant, electrical topology, interconnection and regulatory treatment. | Must define supply during plant outages and whether grid service is firm or conditional. | Clarify shared facilities, metering, transmission service, upgrade allocation and exit costs. | Requires coordinated protection, dispatch, outage and islanding procedures. |
DOE’s January 2025 brief frames these choices through cost allocation, resource adequacy, technology risk-sharing, stranded-investment risk and clean-energy or onsite-supply options. FERC notes that regional grid operators have different structures, so a single national solution should not be assumed.
12. Which decisions are final, and what could still change?
End every major meeting with a written decision log. For each capacity figure, cost, date and operating rule, record whether it is preliminary, study-dependent, tariff-based, contractually committed or subject to regulator approval.
Ask for change-control rules
Request the assumptions that could change the answer and the notice process if they do. Include changes in peak demand, ramp, phase dates, equipment, generation, queue conditions, reliability criteria or law. Ask how pending requests will be treated if FERC, an RTO/ISO or a state regulator changes the rules; FERC’s RM26-4 docket expressly raises that issue.
Keep a decision register
- Question asked and utility response.
- Document version, date and responsible organization.
- Assumptions and data supplied by each party.
- Open item, owner and due date.
- Approval still required and consequence if it is denied.
Warning signs that require clarification
- A capacity number is presented without a voltage level, study basis, firmness definition or date.
- A service date omits permitting, procurement, outage or queued-project dependencies.
- A cost estimate combines customer facilities and network upgrades without allocation.
- A tariff discussion ignores minimum bills, collateral, exit charges or delayed phases.
- A load model does not include cooling, distribution losses, power factor or reconnection behavior.
- Onsite generation is described as eliminating grid obligations without addressing imports, exports, outages or protection.
- Different utility, RTO/ISO and regulator contacts provide incompatible assumptions.
Use the utility’s current tariff, application forms and regional filings for the project location. Available capacity, queue position, study duration, upgrade amount, contract terms and environmental approvals cannot be inferred from national FERC, NERC or DOE material alone.
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