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"It is getting harder and harder for everybody to get access to power" The US energy market has a problem that predates the current surge in electricity prices, and it is one that CEA operators in North America need to plan around now. Getting power to a new or expanding facility is taking longer and costing more, not because natural gas is expensive, but because the queue for grid access is backed up by a structural demand shift that has little to do with agriculture. That was the core message delivered by Aubrey Skalak, Director of Energy Engineering, and Seth Bay, Senior Energy Analyst at 5, an Irving, Texas-based energy procurement and advisory firm serving around 4,600 commercial, industrial, and government clients across the US and Mexico, during their session at the CEA and Indoor Farming conference. "It is getting harder and harder for everybody to get access to power. Anything like indoor agriculture or any other manufacturing sector is running into the same roadblock," Skalak said. Aubrey Skalak (left) and Seth Bay (right) The queue is four times longer than it was ten years ago The numbers are specific. For a five to 25-megawatt connection, the average interconnection timeline in 2015 was around 13 months. Today it is around 50 months. That shift reflects not just rising demand, but a grid infrastructure that has not been substantially updated in four or five decades and was not designed to support the flat, constant load profile of large-scale data centres now competing for the same capacity. "These data centres, these gigawatt-and-above data centres, their load shape is flat," Skalak said. "The grids are struggling to support that." The problem is concentrated in the deregulated markets but is spreading. In ERCOT, the Texas grid, demand was 87 gigawatts in 2025 and is forecast to reach 95 gigawatts this summer, stair-stepping to 145 gigawatts by 2031, which 5 described as nearly doubling the grid in five years. Data centres account for the largest projected new load segment in ERCOT. PJM, covering Pennsylvania, New Jersey, Illinois, Virginia, and much of the northeastern US, is on the same hockey-stick trajectory, with demand expected to shoot up significantly from 2026 through 2030. Every industrial sector connected to the same infrastructure is competing for the same finite capacity. "If we were to suddenly get that demand expected in 2030 today, we could not handle it," Skalak said. "Our grid capacity, when everything is running well, is, I believe, around 120 gigawatts, in that ballpark." Power prices rising as natural gas demand falls A related shift is undermining a long-standing assumption in energy procurement. Historically, natural gas prices and power prices moved in lockstep. That correlation is breaking down. The US natural gas supply is currently healthy. Storage levels are above the five-year average, and the country is averaging around 19 billion cubic feet a day of LNG feed gas year to date, near all-time highs. On the forward curve, gas prices across calendar years 2027 through 2030 are sitting around $4 per MMBtu. Despite that, power prices in major US markets are rising. "We have an increase in power prices despite the decrease in natural gas demand," Bay said. "What that should make you think about is your procurement strategy. A simple fixed price may not be the way to go. Buying in tranches and having some index exposure may be the most optimal approach." Site selection, bridge power, and following the process For operators planning new builds or expansions, 5 has identified three areas where early decisions carry the most weight: site selection, bridge power, and following the utility's own process correctly. On site selection, the most actionable advice is to check the substation capacity before committing to a location. Many utilities offer an informal pre-application step, sometimes called Step Zero, where an operator can ask whether local infrastructure can support a given load without formally entering the queue. If the answer is no, move to the next candidate site. Where possible, prioritising locations with existing service connections, transformers, or substations already in place can take months or years off commissioning timelines. Bridge power has become a planning assumption while waiting for utility interconnection. Fuel cells are a common solution, though lead times on those are also extending. On the procedural side, funding an additional feasibility study from the utility creates a deadline the provider is obligated to meet. "If you can put the ball in the utility's court, having done everything correctly, then it's on them to ensure you get your power," Skalak said. "It could speak to the need for some on-site resiliency as well, so you can leverage that optionality," Bay said. The geothermal payback problem The session closed with a question on deep geothermal, a technology with genuine appeal that rarely moves past the planning stage in the US market. The 5 assessment was direct: the economics do not typically fit within the payback windows that US project finance requires. "In the US, where the economics are tightly managed on a lot of these projects, they'll abandon them if it's more than a four to five-year payback," Skalak said. "The initial investment to dig that deep could be a ten-year payback. Any energy project will pay for itself. The question is whether you can stomach waiting ten years." For more information: 5 Aubrey Skalak, Director of Energy Engineering Seth Bay, Senior Energy Analyst [email protected] www.energyby5.com

The Energy Advisory Firm 5 Acquires BidURenergy and NRG Advisory Services to Significantly Expand Its Presence in the Northeast . Press Release. •