Someday, grid batteries will come in standard packages, ready to be plugged in as fast as utilities can find places and use cases for them. At least, that’s how utility Southern California Edison would like its next round of energystoragesystems to be delivered.

Under a groundbreaking request for proposals (RFP) issued this week, SCE is calling for battery vendors to build “pre-engineered” storage systems, between 1 megawatt-hours and 16 megawatt-hours in size, that can be built, shipped, installed and up and running within 7 months of being contracted.

SCE says it needs this standardized packaging and quick turnaround to allow storage systems to fit into fast-changing distribution grid project-planning cycles. This is the same way that utilities order transformers and other standard grid gear today.

But for a grid storage industry that’s still moving from the pilot-project phase of development to broader commercial markets, it’s a novel concept. In fact, SCE’s new RFP may be the first time a utility has asked for this kind of arrangement for batteries, Mark Irwin, a director in SCE's advanced technology department, said in a Wednesday interview.

“I think it’s the first time anyone has done what you’d call a framework agreement for energy storage purchasing,” he said. Under a framework agreement, a utility will ask vendors to compete for the role of serving as equipment provider for a less well-defined set of future projects, and then call upon the winning vendors to deliver the equipment as those plans solidify.

In other words, “It’s a faster move toward catalog or off-the-shelf” purchasing for energy storage systems, Irwin said. “When utilities decide to buy multiple products, this is how they decide to buy them.”

SCE’s definition of "pre-engineered" includes combinations of batteries, power converters and control systems that have been proven in field tests, and are capable of communicating with utility control systems via standard protocols, he said.

That’s likely to limit the scope of competitors to this RFP to well-funded and established battery vendors or system integrators -- some names that come to mind include Tesla, NEC Energy Solutions, S&C Electric, General Electric, and other energy storage providers with business models that allow for direct sales to utilities, rather than owning the projects themselves.

Irwin didn’t provide any specifics as to what vendors it expected to compete for the new RFP. But he noted that SCE expected to pick only one or two vendors for this procurement, which would add up to five to 10 systems in total, most likely in the smaller 2- to 8-megawatt-hour range.

That’s not such a big procurement compared to the massive 250 megawatts of distributed storage that SCE contracted for last year, or the 580 megawatts of storage it is mandated to procure by 2020 under California state law AB 2514. That mandate calls on SCE and the state’s other two big investor-owned utilities, Pacific Gas & Electric and San Diego Gas & Electric, to procure 1.3 gigawatts of storage by decade’s end. Each utility has issued RFPs to meet its first biannual procurement targets.

But all of these projects to date have been targeted for specific sites and preplanned to meet specific grid needs, with lead times that stretch into multiple years. This new RFP is meant to collapse all of these constraints, Irwin said.

First of all, it has much more flexibility built into where its new batteries will end up, ranging from coastal Ventura and Orange Counties to the deserts of Palm Springs and the Central Valley farmlands of Tulare. “We’re trying to get people to price the cost of transportation to places that encompass our entire service territory,” he said.

As for how SCE will make use of these batteries, “We’re doing distribution deferral,” he said -- charging batteries at off-peak hours, then discharging them to bolster grid circuits that would otherwise require expensive upgrades to wires and transformers to manage peak loading conditions. But the utility also wants to keep the options open to use those batteries for other purposes, like selling their excess energy into grid markets, as new regulations open up that possibility, he said.

SCE has already done one distribution deferral battery project in Orange, Calif., but that demonstration project took a lot of advance planning. For this next round, the utility wants to be able to identify projects, procure batteries, and put them in place much faster, he said.   

“Everything downstream of the substation is very flexible,” he added. Utilities may identify distribution grid projects that seem like a good fit for energy storage two to three years in advance, but “some of those projects can get canceled, because the distribution planning team ended up finding better, lower-cost solutions.”

“What we were thinking is, if we moved to projects that are closer to deployment -- one to two years away or even one year away -- we will get to projects that are a lot further along” in the planning process, he said. That’s important, because the closer that SCE gets to pulling the trigger on a distribution upgrade project, the more clarity it has on how much its different options will cost.

“From a price standpoint, energy storage can only compete with some of the more expensive distribution system upgrades that tend to take 18 to 24 months,” he said. On the other hand, “if we had unexpected load growth, or derating of the current system, and we’d like to solve that problem before our next summer peak, but the non-storage upgrade takes until the following summer peak -- we could solve that problem with a storage upgrade,” he said.

These are the kinds of less-than-sexy yet critical concerns that could have a profound effect on just how quickly grid-scale batteries can become cost-competitive alternatives for distribution grid projects. And California could see a lot more call for storage to serve these needs, under the new distribution resource plans (DRPs) that the state’s big three utilities have just submitted.  

Each of California’s big utilities, including SCE, have analyzed how much distributed energy resources (DERs), including storage, could be added to its distribution circuits under these DRPs. They’re also seeking regulator permission to test a combination of batteries and rooftop solar, on-site generators, demand response, building energy management and microgrid control systems to prove out how third-party DERs should be valued as grid assets.

These are part of the ongoing debates about how much grid storage should be owned by utilities versus third parties, how different classes of systems should be allowed to earn revenues for the services they provide, and other issues that are coming to the fore as grid-scale storage. But amidst all these policy issues, there’s little doubt that the industry would be well served by moving to a business model that can see products quickly deployed and easily integrated into a variety of grid configurations.