In late 2024, Harold Patterson, CEO of renewables developer Patterson Enterprises, was looking to finance two standalone energy storage systems that his company was planning to install in eastern Virginia. Initially, the two 10 megawatt projects were supposed to be financed through the U.S. Department of Agriculture’s rural energy loan program, but President Trump’s win that November and his promise to walk back renewables investment prompted Patterson to look for other options.
“The bank [that specialized in USDA lending] that we were working with told us that they had over two gigawatts of projects that got dumped, and had to shut the project down,” Patterson told Latitude Media. So he instead turned to a connection with Climate First Bank, a community bank founded in 2021.
Climate First was immediately interested in the projects, which were well-aligned with its focus on financing climate solutions. But, according to Hana Freymiller, Climate First’s director of energy project finance, the bank had never financed standalone energy storage systems before — much less one relying on arbitrage, meaning buying electricity when prices are low and selling when they’re high, for a revenue stream. While increasingly popular for energy storage systems, arbitrage doesn’t immediately translate into the long-term contracts banks require for project finance, which for power projects usually come in the form of power purchase agreements.
“One of the big challenges with battery stand-alone is arbitrage,” Freymiller said. “Banks and other financial institutions aren’t yet as comfortable with financing projects that are going to buy low and sell high, particularly at this scale.”
So, in the ensuing weeks, Climate First and Patterson collaborated to ensure the projects met the specific criteria the bank needed to approve the financing: certainty in the revenue stream, and assurance that the projects would be operational even if they took years to go through the interconnection queue.
The work led to a $32 million, seven-year, construction-to-term loan for the two systems, which broke ground in April of last year and came online in late 2025. As of now, they’re waiting in the interconnection queue, even as they provide storage for a local modular data center.
Despite being the first standalone storage project for both Climate First and Patterson, which had up until then only developed storage paired with solar, the deal came together remarkably quickly, with less than one year in between a first contact between the firms and the projects coming online.
The structure exemplifies how developers and traditional lenders like community banks, which have historically refused to touch merchant storage, are finding novel ways to get deals done. Such creative financing is becoming essential as the market grapples with policy headwinds and a Trump administration leery of funding renewables, a situation that risks leaving mid-market projects such as Patterson’s one without funding.
Now, Freymiller says, Climate First can use it as a template for the financing of other mid-market standalone storage projects.
“There’s a huge benefit for lenders from a project finance perspective to this structure,” she said. “On the other hand, the downside of the structure is that developers don’t get to take the upside on the arbitrage market. There are different players out there trying to help with the ‘buy low, sell high’ aspect of it. And as we see this market evolve and we get more comfortable with arbitrage, we may see the [structure] evolve.”
The ‘contract in the middle’
For Climate First to get comfortable with the revenue stream, it required the security of a long-term contract to ensure loan repayment, even during market downturns. Patterson addressed this by bringing in a tenant with a 20-year lease.
“That tenant has agreed to pay a fixed revenue stream to [Patterson], the owner of the system,” Freymiller said. “Once the system clears the interconnection queue, the tenant will get to take advantage of the arbitrage market, but they’re the ones taking on its risk. For Patterson and the bank, the contract with that tenant provides certainty in the revenue stream.” (The company has not publicly named the tenant.)
This “contract in the middle,” as Freymiller calls it, is an increasingly popular way of involving skittish financial institutions in volatile markets. In the REC market, for example, a state might guarantee a REC contract for a period of time, in lieu of long-term contracted revenue.
“Another way is an insurance payment,” Freymiller added. “They’ll come in if you hit a loss, and then you’ll pay them an upside. It’s the same idea: it insures you against the downside of the market, and gives the lender comfort that the revenue will always be there.”
To add additional layers of lender protection, Patterson and Climate First also said they put some insurance coverage in place, though the companies declined to provide more details.
‘The timeline risk’
For Climate First, another element of uncertainty came from the lack of a clear timeline for when the storage projects would be able to be interconnected and thus start engaging in arbitrage. The projects are located in PJM, which is the largest grid operator in North America and receives thousands of interconnection requests annually. As of last April, it had 200 GW of renewable power waiting in the queue, with some projects taking years to go through it.
“You have a timeline risk, which can be uncomfortable for a bank like ours,” Freymiller said of the PJM queue.
Patterson decided to bridge the gap by going ahead and building the projects regardless of the queue, collaborating with the local utility A&N Electric Cooperative to place them on two of its distribution substations.
“Our approach was to get the project built and operational, and then worry about the queue,” Patterson said. “And actually, this way the queue will move forward more quickly, because a lot of its delays come from having to prove that the construction will hit certain milestones by certain dates.”
As a result, while the systems await final PJM approval for market-wide arbitrage, they are already operational locally, charging from the grid and providing backup power to the tenant’s modular data center.
Meanwhile, federal reforms approved in December 2025, which will take effect this April, will allow mid-sized projects like Patterson’s to bypass the PJM backlog entirely, defaulting instead to Virginia’s faster, state-level interconnection process. “We’re skipping through a lot of what we had mapped out, and I think we can have them interconnected by the middle of this year,” Patterson said.
