What “powered land” means

For Soare, the definition starts with contracts. “To us, powered land is a contractual right to deliverable megawatts on a known date, not just land near a substation,” he says. “There’s the interconnection agreement, the infrastructure to connect to the grid, and there’s also the power supply, the generation or energy from the grid... Either way, you need both of these components.”

Each agreement covers a different risk. The grid connection agreement provides the right to connect and a timeline to capacity, but it doesn’t guarantee supply or price stability. The power purchase agreement locks in supply and economics, but only applies once power is received.

Transferability matters too. According to Soare, whether those agreements can move to a new owner often depends on the counterparty’s credit requirements and any approvals needed from a public utility commission or the utility itself, and Blue Owl makes transferability a condition of closing. Power alone also doesn’t justify a premium. The firm needs line of sight into state and local support, zoning and entitlements, local infrastructure, and whether the location will appeal to its hyperscale tenants.

Chambers adds that the definition has broadened. A powered site today is defined by its full power system, including onsite generation, battery storage, and the power ramp, along with the grid connection.

Why timelines matter as much as capacity

According to Chambers, many interconnection queues can now be a decade long. On one Aston Power project in Arizona, the local utility estimated seven to ten years to deliver a grid connection and the generation needed to support the load request.

The demand behind those queues is enormous, though not all of it is real. ERCOT’s 2025 queue includes around 230 gigawatts of large load requests, more than double the grid’s entire 103 gigawatt generation fleet, and well above its all-time peak of 85 gigawatts. Only about 7.5 gigawatts has actually connected.

Figure 4: ERCOT’s large-load queue is now bigger than the grid

Source: ERCOT System Planning update, Dec 2025 board materials (Via Utility Dive, Latitude Media)

Soare expects much of that to fall away. “There’s double counting, and there’s triple counting,” he says. “It’s very similar to what happened in the renewables industry, where developers flooded the interconnection queue with many projects, but in reality, not all of these projects were built.” As states and grids make large load interconnection more expensive, he expects the projects that advance to be those with the right locations, entitlements, and community support, backed by experienced, well-capitalized developers.

The studies are where timelines tend to slip. “When you put in a large load request, typically what happens first is a system impact study,” Chambers explains, “and even those system impact studies over the last couple of years have been delayed for months, if not years.” A facility study follows, telling the developer what grid upgrades will cost, how long they’ll take, and whether they’re possible at all. Batch reviews, part of SB6 in ERCOT and being adopted elsewhere, aim to speed up the process, but the volume of requests remains significant.

Hybrid power is becoming the default

With grid timelines this long, Chambers says most large sites now need a hybrid approach. “You likely need onsite generation plus a grid connection to actually make things work in a timeframe that makes any sense,” he says.

On the Arizona project, Aston combined significant onsite generation with a direct connection to federal transmission infrastructure operated by Western Area Power Administration (WAPA). “We can purchase power and port those electrons to the site, combine those electrons with the electrons that we will generate onsite, and effectively provide a utility-like service to the end user,” Chambers says.

Regulation is pushing in the same direction. Chambers points to SB6 in Texas, which he describes as still somewhat in flux, under which large loads are effectively expected to build onsite generation, and the amount of onsite capacity they build is the amount they can be curtailed from the grid during emergencies. “More and more we’re seeing utilities that will effectively demand that you have onsite generation because they will curtail you,” he says. “We expect to see that sort of all over the place.”

Soare sees the grid as the long-term path. “Our priority is grid connected projects. The grid is the most resilient and cost-effective path to serve these large load projects, and it provides the best access to clean energy,” he says. Blue Owl invests in behind-the-meter generation when benefits like a faster ramp or protection against curtailment outweigh the added cost, with the expectation that it will eventually be grid connected.

The underwriting reset

For investors, power now sits at the center of site selection. “Understanding the timelines, the power ramp, the costs, the risk, what infrastructure is needed on the grid, both from a transmission and generation perspective, what the contractual terms look like,” Soare says. “All of these are essential to understand the power piece of the equation.” Blue Owl dedicates 12 months or more to pre-development, structuring utility agreements and community partnerships and planning a multi-phase approach, so it isn’t simply holding land and waiting for power.

Underwriting powered land now means accounting for study delays, queue positioning, regulatory change, and the cost and timeline of hybrid power, alongside the fundamentals that have always mattered. Site selection has become as much an infrastructure negotiation as a land deal. A $28,000-per-acre parcel in a power-constrained market may be inexpensive land, but it won’t become an investable opportunity until the power story is solved.

Watch the full webinar to hear Soare and Chambers walk through grid connection agreements, system impact studies, transferability, and how to assess power certainty in deal underwriting.

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