Interconnection costs for utility-scale energy storage in California are significantly lower than in other major US markets, with developers also benefiting from network upgrade cost reimbursements unavailable elsewhere, according to a senior executive at Rev Renewables.
The remarks were made during the 2026 US Solar & Storage Finance event in Garden Grove, California, in a discussion between Kevin Imboden, global director of market research & intelligence at data centre developer EdgeconneX, and Sandeep Arora, senior vice president & head of transmission & markets at LS Power-owned Rev Renewables.
Arora explained that for a 250MW, 4-hour battery energy storage system (BESS) project in California, developers face approximately US$750,000 in initial costs to enter the California Independent System Operator’s (CAISO) Cluster 16 interconnection queue, which opens 1 October and closes 15 October 2026.
He noted that CAISO has changed its approach to queue management. “Gone are the days when CAISO would take every single project that enters their queue process and study that. Now it’s: ‘how much room do I have at each location?’ and up to 150% of that is what they study.”
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California offers cost reimbursement advantage
The key financial advantage for California developers emerges after projects progress through the interconnection cycle. Using the example of a 250MW project with US$20 million in total interconnection costs—split evenly between network upgrades and interconnection customer facilities—Arora explained that California developers receive reimbursement for network upgrade costs.
“In California, once you build the project, you get your money back. You get reimbursement of that US$10 million network upgrade,” he said. “You don’t get that in PJM. You don’t get that in MISO for the most part.”
By contrast, similar-sized projects in other markets face substantially higher upfront costs and greater financial risk. “A similar-size project in MISO would be upwards of US$1.5 million, and you could quickly lose a million dollars if you go through phase one studies,” Arora said.
The Electric Reliability Council of Texas (ERCOT) operates differently, with costs largely socialised, though it lacks a capacity market. “ERCOT basically is all socialised. You get almost all of the cost back. But ERCOT is also a different market construct. You’re not selling any capacity in ERCOT,” Arora explained.
AI deployment accelerating across interconnection processes
AI is already being deployed across multiple aspects of project development and interconnection processes, Arora revealed, with tangible cost and time savings emerging.
“My team uses AI. Stuff that we used to do modelling-type work for—a lot of ISOs, RTOs are coming in with new requirements: ‘Deliver to me this PSAT model.’ We’re actually using AI in-house to develop those models much quicker, much cheaper. We used to pay US$50,000 per model to consultants, and some of that stuff is being done in-house now using AI,” he said.
ISOs and regional transmission organisations are also adopting AI tools. At the interconnection request intake stage, AI is being deployed to test whether applications will pass or fail deficiency reviews—a critical checkpoint with limited time for corrections.
“Even on the load flow, the power flow side, stuff that would take several days, weeks to get built—AI is being used to build those models much quicker,” Arora said, though he emphasised the continued need for human oversight.
Beyond individual project development, Arora noted that ISOs are considering grid-enhancing technologies and automation in their transmission planning. “I would rather see more interconnection capacity become available in the next couple of years versus having to wait for a large transmission line that takes 10-plus years to get built,” he said.
However, he acknowledged the limitations given the scale of demand, with Imboden noting that ERCOT currently faces 500GW of interconnection requests.
