FirstEnergy, AEP detail process, timelines and risks for connecting large data‑center loads in West Virginia

Jim Myers, president of West Virginia and Maryland operations for FirstEnergy, and Robert Bradish, senior vice president for regulated infrastructure investment planning at American Electric Power, told the West Virginia Public Energy Authority that utilities are prepared to work with very large electricity customers — notably hyperscale data centers — but that connecting them requires time, coordination and contractual protections.

Myers said FirstEnergy is working on five large data‑center projects in West Virginia “which represents about 1,650 megawatts, of load that they're looking for.” He and his colleagues described a staged interconnection process that begins with early engagement and conceptual studies and can move through detailed engineering and a signed construction agreement.

The utilities laid out the typical steps a prospective large customer will face: an initial conceptual or “connectability” assessment; a detailed engineering study that includes cost and timing; a formal interconnection study with PJM; and, if the customer proceeds, a construction agreement obligating the customer to pay long‑lead equipment and construction milestones. Greg Hussing, FirstEnergy’s director for FERC and RTO technical services, summarized the customer interaction: “I want to call it a customer engagement or customer partnership when we're working with a large customer, large load.”

Why it matters

Large, continuous loads change how utilities plan and operate the grid. Utilities said these customers typically have high load factors (often 90% or higher) and can require high‑voltage transmission connections, new substations and long‑lead equipment such as extra‑large transformers. That combination affects project schedules, cost allocation and risk for existing customers.

Timelines, phasing and temporary service

FirstEnergy and AEP officials gave timing examples based on recent projects and supply‑chain realities. Hussing said the detailed interconnection study step takes “a hundred and 80 days to do this very detailed study.” For a greenfield, 1‑gigawatt facility that requires a high‑voltage substation and new transmission taps, the presenters estimated several years to complete siting, order and receive long‑lead equipment and build the substation. Myers and Bradish both noted that a realistic schedule for substantial transmission work and substation construction is commonly in the 3–5 year range; several speakers said 5 years is a reasonable order of magnitude for full build‑out in many greenfield cases.

Both utilities stressed that developers frequently use phased approaches: utilities can provide large temporary service or staged connections so a customer can begin limited operations while major transmission work proceeds. Myers said temporary taps and phased on‑ramps are common, and Bradish described cases where fuel cells or other local generation served as interim solutions while transmission upgrades were planned.

Contract terms, financial commitments and customer protections

AEP and Appalachian Power said they use contractual and tariff tools to reduce risk to other customers. John Scalzo, vice president of regulatory finance at Appalachian Power, said, “we filed with the Public Service Commission what we call a large load tariff,” describing a tariff under which very large new customers accept enhanced minimum bills, multi‑year ramp schedules and contractual terms designed to place development and exit risk with the customer rather than general ratepayers.

Myers and Hussing described the standard practice of requiring a customer to enter a construction agreement that makes the customer responsible for long‑lead equipment orders and construction milestones so that costs are not stranded if a project stops in midstream.

Operational and engineering constraints

Bradish highlighted the engineering scale of the installations: “these things are bigger than most of our generating units,” a point he used to explain why studies must include regional stability, protection coordination and voltage control. Both AEP and FirstEnergy described how a single large load can change power flows across a broad area and require studies that examine impacts on neighboring utilities. Utilities said they do not publish detailed transmission heat maps because transmission configuration is considered critical infrastructure; instead they work with developers in confidence to identify suitable connection locations.

Supply‑chain and equipment lead times

Presenters repeatedly flagged long lead times for large transformers, breakers and other station equipment as a primary schedule driver. Myers and Bradish said utilities now often order equipment internationally and that lead times remain a constraint on how fast a full high‑voltage interconnection can be completed.

Quotes from the meeting

“Myers (FirstEnergy): ‘we have 5 large data centers ... which represents about 1,650 megawatts, of load that they're looking for.’

Hussing (FirstEnergy): ‘I want to call it a customer engagement or customer partnership when we're working with a large customer, large load.’

Hussing (on study length): ‘we take in our process a hundred and 80 days to do this very detailed study.’

Bradish (AEP): ‘these things are bigger than most of our generating units.’

Scalzo (Appalachian Power): ‘we filed with the Public Service Commission what we call a large load tariff.’

What remains unsettled

Utilities emphasized that every large‑load project is site‑specific. Developers’ desired timelines and willingness to contract for construction risk determine whether a connection can be delivered quickly. Utilities also warned that protection settings, coordination with PJM rules and regional transmission limits can force multi‑year transmission projects when multiple large loads cluster in one region.

Ending

FirstEnergy and AEP told the authority that West Virginia’s low retail rates and existing heavy infrastructure make it attractive for large energy users, but cautioned that speed‑to‑market depends on where a customer locates, how much of the build is already in place, and whether the developer will accept contractual obligations for construction and long‑lead equipment. Both utilities said they prefer early, coordinated engagement with state and local officials, developers and PJM to reduce schedule risk and avoid unexpected impacts on other customers.