Why the pause is new
Your utility contact used to answer capacity questions in a phone call. Now there is a pause. The pause has a regulatory origin.
NERC's 2025 Long-Term Reliability Assessment, published January 2026, identified 13 of 23 North American assessment areas facing resource adequacy challenges over the 2026–2035 window. MISO moves from normal risk in 2026 to high risk by 2028. PJM is elevated now, high by 2029. ERCOT is elevated through 2028, high by 2029. WECC-Basin, WECC-Northwest, SERC-East, SPP, New York, New England, Maritimes, Manitoba Hydro, SaskPower, and Québec all carry elevated or high designations within the assessment period. The stress profiles differ by region: PJM faces winter early-morning and evening risk from generator availability and fuel supply constraints; ERCOT's exposure is winter demand variability with significant summer risk; MISO's is summer late-afternoon as solar output declines. If your utility territory falls within any of these assessment areas, the planning team is operating under a reliability outlook that has materially tightened since 2023.
Then FERC acted. On June 18, 2026, the Commission issued six Section 206 show-cause orders to every RTO/ISO and their transmission owners: PJM (EL26-67-000), SPP (EL26-68-000), NYISO (EL26-69-000), MISO (EL26-70-000), CAISO (EL26-71-000), and ISO-NE (EL26-72-000). Each has 60 days to justify why existing tariffs remain just and reasonable without large-load provisions, or to propose tariff changes. Informational reports on generation adequacy for existing and new large loads are due in 30 days. FERC's five reform categories cover study processes, cost-shift protection and transmission-cost transparency, co-location and behind-the-meter generation, flexible large-load transmission services, and study processes for generation serving co-located loads.
The orders do not impose an immediate uniform interconnection rule. They do not disrupt existing agreements or agreements nearing completion. They do create a compliance environment where every RTO/ISO is simultaneously reviewing how it handles large-load requests. The utilities operating within those RTOs know the rules governing capacity commitments may change within months. That is what your utility contact is weighing when they pause.
What the utility actually hears
In an earlier piece, I built a four-tier utility commitment ladder: screening-level capacity statement, study commitment and timeline, upgrade path with cost and equipment reality, and contract terms with energization schedule. That framework describes what the EDO needs from the utility. This piece describes what the utility has to do to produce each tier. Most miscommunication between EDOs and utility planning teams lives in the gap between those two perspectives.
"How much capacity is available at this site?" sounds like a lookup. It is an engineering workflow with regulatory constraints, cost-allocation implications, and reliability obligations that attach the moment the utility puts a number in writing.
The utility hears a question that cannot be answered without knowing: available to whom, at what voltage, at what load factor, at what power factor, on what timeline, with what redundancy requirement, and under what cost-allocation structure. A 10 MW load at 95% load factor requesting 138 kV service is a fundamentally different engineering problem than a 10 MW load at 40% load factor at 69 kV, even at the same substation. Every variable changes the answer. The utility is not being evasive. It is being precise about a question that has no single answer until those variables are specified.
Two utilities, two structures
Utilities do not organize the study process identically. AEP Ohio and Portland General Electric illustrate the structural range, and why the commitment ladder maps differently depending on which utility serves your site.
AEP Ohio runs a single formal study. The published Data Center Tariff process applies to all new data centers or expansions and to projects of 25,000 kW or greater. At intake, the customer must control the property by ownership, lease, or option and must provide a specific location, load ramp, and final load.
Study fees are due within 45 days:
| Load size | Study fee |
|---|---|
| 25,000–49,999 kW | $10,000 |
| 50,000–99,999 kW | $50,000 |
| ≥100,000 kW | $100,000 |
Unpaid fees mean the service request is withdrawn.
The information AEP Ohio needs from the customer goes well beyond initial intake. Projects moving forward must submit the NERC Load Dynamic questionnaire and AEP Transmission's Appendix B.2 End-User Connection form. That form asks for GPS coordinates, requested voltage class, requested AEP asset, site plan, one-line drawing, industrial load type, onsite generation details, load ramp schedule, normal and anticipated peak demand, power factor, load factor, UPS information, power-electronic load data, and motor-load information.
AEP Ohio produces a load study and service plan. The regional-upgrade analysis uses NERC TPL standards: N-1 thermal analysis, N-1-1 thermal analysis, N-1-1 voltage magnitude analysis, N-1-1 voltage drop analysis. AEP Ohio targets 60 days if regional transmission upgrades are needed, 45 days otherwise. The output is estimated in-service dates, required non-regional transmission upgrades, and a local service plan identifying specific upgrades to connect the load. After the study, the customer receives a Letter of Agreement and an Electric Service Agreement. The LOA requires 100% reimbursement of buildout costs if the customer cancels or delays by more than 12 months before the target energization date.
The commitment is binary. You are in the study or you are not. AEP Ohio does not present a separate pre-feasibility, system-impact, and facilities-study ladder in its public materials. Mapped against the four-tier commitment ladder, AEP Ohio's architecture collapses tiers two and three into a single study that simultaneously establishes the upgrade path and its costs. The LOA and ESA cover tier four. There is no formal mechanism corresponding to tier one. The EDO has to build the screening-level capacity statement from other sources.
PGE structures its large-load process as four explicit phases for loads of 1 MW or greater:
| Phase | Timeline (serial) | Cost | What it produces |
|---|---|---|---|
| Pre-feasibility | 7–14 days | Free | Informal high-level review; identifies required follow-on studies |
| Feasibility | 14–45 days (1–5 MW); 30–45 days (5–30 MW); skipped for >30 MW | Study agreement + deposit (amounts not published) | Feasibility determination |
| System impact | 45 days (1–5 MW); 60 days (5–30 MW); 180 days for cluster studies ≥5 MW | Study agreement + deposit | Engineering assessment of interconnection effects on safety and reliability; preliminary upgrade costs |
| Facilities study | 90 days (serial); 120 days (cluster) | Study agreement + deposit | Equipment, engineering, procurement, and construction cost estimates |
Pre-feasibility requires a request through Power Partner with a specific load amount and location but carries no cost, no binding timeline, and no capacity allotment. On the commitment ladder, it sits at the boundary between tier one and tier two.
PGE's publicly accessible process page states that a nonrefundable application fee and a study deposit, reconciled to actual costs at the end of the study process, are required for all studies beyond pre-feasibility. PGE does not publish specific dollar amounts for either the application fee or the study deposit on that page. If you are in PGE territory, you need to ask. The absence of published fee schedules is itself a data point: it tells you how much of the process is handled through direct engagement rather than public documentation.
Two operational details matter. First, PGE's study reports include "growing levels of commitment to capacity allotment, costs, and schedule" as the customer progresses through stages. Each stage narrows the uncertainty band for both sides. Second, load studies expire 60–90 days after completion unless PGE approves an extension. A study completed in January may not be valid by April. Completing all required studies does not guarantee the requested load on the requested timeline. Transmission project timelines, long-lead equipment availability, and flexible-load constraints can all affect allotment or timing.
The structural difference between AEP Ohio and PGE is architecture, not quality. AEP Ohio's single-study model requires more customer commitment upfront. PGE's phased model allows incremental commitment but takes longer to reach the same endpoint. An EDO working in AEP Ohio territory faces a different conversation with prospects than one in PGE territory. Knowing which structure governs your sites determines how you prepare for that conversation.
The pre-prospect ceiling
The question that matters most for EDOs is what the utility can produce before a prospect exists.
The answer is narrower than what most EDOs want and wider than what most EDOs currently have.
AEP Ohio publishes a hosting capacity map showing distribution-level capacity by station and circuit: station name, circuit voltage class, total circuit capacity, total transformer capacity, total station capacity. The map is designed for DER interconnection, covers loads between 150 kW and 7,500 kW, and carries explicit disclaimers: preliminary review only, uses data from a previous point in time, does not replace interconnection applications. For an industrial prospect drawing 5 MW or more, the hosting capacity map indicates something about the distribution system's baseline condition. It indicates nothing about transmission-level service availability.
PGE's pre-feasibility phase is free and takes 7–14 days, but it requires a request through Power Partner with a specific load amount and location. It is not a general-purpose capacity inventory tool. PGE states that all requests of 1 MW or greater must be reviewed by System Planning before PGE can answer site-development and construction questions.
Neither utility publishes a pre-prospect capacity letter template for economic development partners. Neither publishes site-specific substation headroom on an economic development page. AEP's public economic development page says AEP Ohio provides transmission and distribution services that can accommodate large industrial users. That is a marketing statement. It is not a capacity statement. The distance between those two categories is the distance between surviving a screen and not appearing in one.
A site selector at screening needs bounded uncertainty: a dated statement of current conditions with caveats. What the utility can produce without a named load is general system data. What the utility can produce with a named load is a specific engineering study. The EDO operates in the space between those two categories.
The boundary exists because every capacity statement the utility makes has reliability implications for every other customer on the system. The NERC reliability assessment and the FERC show-cause orders are tightening that discipline, not loosening it.
The request the planning team will recognize
A utility planning team will recognize and respond to a request framed in their operational vocabulary. They will stall on "tell us what capacity you have."
What is logically available before a formal study, and how to frame the request:
Substation-level data. Named substations serving or adjacent to target sites. Nameplate MVA ratings. Number of transformer banks. Service voltage. Feeder positions, total and available. This is system-level data that exists in the utility's GIS and planning databases. It does not require a study to produce. The request that works: "We are building site profiles for economic development screening. We need substation nameplate ratings, service voltage, and feeder configuration for substations serving [named sites or corridors]. We understand this is point-in-time data and does not constitute a capacity commitment."
That last sentence matters. It tells the utility you understand the boundary. It removes the reason for the pause.
Historical peak loading. Substations have historical peak demand data. The ratio of peak demand to nameplate capacity gives a rough headroom estimate, but the ratio overstates available capacity. It does not account for contingency reserves the utility must maintain, committed loads in the interconnection queue that have not yet materialized, or thermal derating under summer conditions. Present the ratio as a screening indicator, not as available megawatts, and say so explicitly in the site profile. A site selector who sees "38% headroom" based on nameplate-minus-peak will ask about contingency, queue, and derating immediately. The EDO that presents the number with the right caveat keeps credibility. The one that gets corrected loses it.
The utility may or may not share historical loading data, depending on whether it considers loading data competitively sensitive or operationally provisional. Ask. If the answer is no, ask what they can share that indicates relative loading.
Planned capital upgrades. A substation expansion, new feeder, or transmission reinforcement in the utility's capital plan changes the site's competitive position materially. The structural asymmetry between municipal utilities and IOUs is sharpest here. A municipal utility can treat its capital plan as a public-facing recruitment tool, publishing named substations with MVA ratings and energization quarters on a public page. An IOU-served city typically cannot produce equivalent documentation without the utility's explicit cooperation, because IOUs file capital plans with state PUCs, not on city project pages. The EDO in IOU territory experiencing difficulty getting capital-plan specifics is not facing a relationship problem. It is facing a regulatory-model problem. The documentation gap is structural. Closing it requires either formal partnership with the utility that produces equivalent public commitments, or the EDO's own work extracting what is available from PUC filings. Neither path is fast. But knowing the source of the gap is what separates a productive conversation from a frustrating one.
What the utility cannot provide before a prospect triggers a formal study:
- A will-serve letter without a named customer
- A capacity guarantee without a load profile
- A cost estimate for service without a facilities study
- An energization date without a signed service agreement
These are engineering and regulatory requirements rooted in the utility's reliability obligations to every other customer on the system. Requesting commitments the utility cannot make does not demonstrate urgency. It signals a misunderstanding of the utility's operating constraints, and it makes the next request harder.
What survives the screen
A site profile built on bounded, verifiable data survives screening. One built on marketing language does not.
"Substation X, 150 MVA nameplate, two transformer banks, 138/13.8 kV, six feeder positions with two available, historical peak at approximately 62% of nameplate (note: does not reflect contingency reserves or queued commitments), planned third transformer bank in utility capital plan for Q3 2028."
That gives a site selector enough to keep the site in the set. It does not answer the prospect's specific question. It answers the screening question: does this site have a plausible path to the power this prospect needs?
Screening requires that and nothing more. The formal study answers the rest, and it is triggered by the prospect, not by the EDO.
- FERC's 60-day responses: Each RTO/ISO must justify or reform its large-load tariff provisions by mid-August 2026, and the resulting filings in dockets like PJM's EL26-67-000 will determine whether study processes, cost-allocation rules, or capacity-reservation mechanics change for industrial loads in your territory.
- Data center demand pressure: Lawrence Berkeley National Laboratory's June 2026 update estimates data centers could reach 11.8% of total U.S. electricity use by 2030, which means the interconnection queue congestion and substation capacity competition EDOs face is not temporary.
- Alabama SEEDS Round 4: Applications are open through August 31 for approximately $11.7 million in site-assessment grants requiring at least 50 acres and site ownership or purchase option, with awards expected in late October.
- Wastewater as the other screen: The 2026 Guild/DCI Pulse Check put utility and infrastructure capacity at 61% as the top site-elimination factor, but for wet-process manufacturing the binding constraint is often discharge chemistry, not megawatts.