Last winter, Southern California Edison (SCE) sent the U.S. energy storage sector into a frenzy with a single announcement: It would purchase over 250 MW of energy storage in one fell swoop — more than five times the amount California regulators required it to do at the time, and easily the biggest single storage procurement to date.

That purchase was brought on by a landmark mandate from the California Public Utilities Commission (CPUC). Passed in 2013, the order requires the state’s three big investor-owned utilities (IOUs) to put 1.3 GW of storage on the grid by the end of the decade.

As a first step in that process, the regulators stipulated that the IOUs had to contract for 50 MW of storage by the end of 2014. But as a part of a larger request for proposals, SCE elected to contract for 264 MW of diverse energy storage technologies, including utility-scale batteries, behind-the-meter resources, and non-battery storage alternatives.

That giant storage procurement puts company in uncharted territory for an American utility, forcing it to grapple with valuation and operational issues involving storage that other power companies have only imagined.

Nearly one year on from that historic proposal, what has SCE learned about storage—and what is its outlook for the future? Utility Dive spoke with SCE President Pedro Pizarro to find out.

Evaluating storage alongside other resources

SCE’s storage buy last year wasn’t only a first in terms of its scale, it was also the first time that the utility compared storage side-by-side with traditional generation resources like natural gas, according to Pizarro.

Typically, SCE and other utilities would purchase demand-side resources in one RFP, storage in another, and traditional generation in another, Pizarro said. But this time, the utility took a different approach under the umbrella of a broader solicitation for resources they called the Local Capacity Requirements Request for Offers (LCR-RFO).

“We looked at natural gas, we looked at demand-side resources like demand response, we looked at various types of storage — not just batteries,” Pizarro said. “We considered all these technologies side-by-side and made decisions simultaneously across that mix of technologies.”

To the best of SCE’s knowledge, that was the first time a utility has planned for generation resources in such a holistic way, Pizarro said. While the process wasn’t exactly like comparing apples-to-apples, it did allow the utility to understand better how different technologies stack up against each other.

“This LCR-RFO picked up some solar, picked up storage from batteries, picked up ice storage, it picked up some demand response resources, and some natural gas-fired resources,” Pizarro said. “So, it was an umbrella that allowed us to compare and contrast and make decisions across all the technologies.”

Storage in the LCR-RFO

The 264 MW storage procurement remains SCE’s last big storage buy to date, but there will be more to come in the future, Pizarro said. As a part of that Oct. 2013 mandate, the PUC set a target of 1325 MW to be procured by the state’s IOUs by 2020. Utilities can own and rate base half of that capacity, but must purchase the other half from third party providers.

In determining how much storage it would buy in its LCR-RFO last year, Pizarro said SCE used a “least-cost, best-fit methodology” balanced with a consideration of what regulators and the public want the utility to invest in.

“We also take into account some of the policy preferences that the state has,” he said. “There’s a set of preferred resources — whether that be demand side, renewables or storage — so ultimately we made these judgement calls in the procurement process around what’s the balance, what's the mix, that we end up procuring.”

In this case, he said, the utility felt the 264 MW of storage met its local capacity needs and “also helped stimulate support for these preferred resources like storage.”

“We recognize that this is early days for the industry,” Pizarro said, “so we understand the value that our contracts backed by our strong balance sheet, the value that has in terms of supporting innovation and giving these technologies a foothold.”

Placing storage on the grid

It’s important to note, Pizarro said, that not all the storage SCE procured is the same.

“Of the 264 MW, about 100 MW is large and in front of the meter, and 164 MW is small, aggregated, and behind the meter on the customer side,” he said. “That was another innovation that we appreciated — the ability to contract for utility-scale, grid-scale resources as well as smaller, customer-side-of-the-meter resources, and look at the interplay between them.”

Just where to situate those resources, both utility-scale and behind-the-meter, is an issue SCE is still working through, Pizarro said. It’s an issue the utility has been mulling over for a while.

Back in February, Utility Dive spoke with Doug Kim, SCE’s director of advanced technology, at the ARPA-E conference in Washington, DC. He outlined why it’s so difficult to monetize the distribution grid — utilities haven’t yet come up with methodologies for identifying locational values for distributed resources like energy storage.

If a utility puts a battery on a feeder with high peak demand for a short period of time, Kim said, storage has a huge value in decreasing demand during those peak times. But put that same battery on more robust feeder, with bigger wires and transformers, and the battery’s value would likely differ.

“The granularity of the information that you need for that grid — especially a distribution grid that is very dynamic and can be reconfigured — could be very different, very complex,” Kim said at the time. “So, how do you have a value that’s assigned to a specific resource? That’s the problem that we have to think about and figure out how to do it.”

Pizarro said that determining the locational value of storage is still an “evolving area,” one that will “continue to get a lot of focus over the years ahead.” SCE’s Distribution Resource Plan — a framework for how the company plans to modernize its grid — that the utility filed with regulators in July was a big step forward in that process, he said.

“[The DRP] includes a lot of commentary around how we can provide greater transparency in terms of the value of distributed resources at different points in the grid,” Pizarro said.

For instance, SCE has begun putting up online maps that show the available capacity for distributed resources on different points of the grid, Pizarro said, “and there are more tools being developed as a part of the DRP process in the years ahead.”

Learning to value storage

In addition to the initiatives proposed under the umbrella of the utility’s Distribution Resource Plan, Pizarro said SCE took a wide variety of storage attributes into account during its LCR-RFO solicitation.

“There’s a variety of things that storage can do for us,” Pizarro said, such as storing excess generation and saving it to be released later during higher load events.

“As we get more renewables and solar PV on the grid, that’s going to increase the periods of overgeneration on the system,” he said. “Well, one value of storage is being able to take that and store it for when it’s more valuable later on.”

SCE also considered grid functions of storage like its ability to assist with grid congestion, balance voltage and frequency, and smooth the integration of renewables.

“Our valuation process tries to take all these attributes into account along with a sense of the locational value,” Pizarro said. “Then you put it all together and that yields a set of metrics that our team uses to determine what offers are the most viable, which ones are the most attractive to customers.”

Because SCE was considering a wide range of storage’s benefits, some of the storage resources procured in the LCR-RFO came in at higher per-kWh price than the gas-fired generation SCE bought at the same time. Pizarro said that’s a wrinkle the media didn’t catch the first time around.

“I saw a lot written saying clearly this is storage now fully, head-to-head competitive against natural gas-fired resources,” he said. “I think there’s a little misunderstanding, because we have storage mandates, and we were procuring to meet them.”

The SCE president said that while they saw some offers that were “very competitive” on price with gas-fired power, it ended up buying other storage resources that were more expensive as well.

“We still picked them up because they had other attributes we wanted to capture for customers,” he said.

Being able to capture those multiple value streams that storage offers is crucial for utilities looking to accelerate the deployment of the resources on their systems.

Texas utility Oncor, for instance, announced last year that it thought more than 5 GW of storage could be cost-effective on the ERCOT grid. Its plans for large-scale deployment had to be curtailed, Utility Dive recently reported, because Texas electricity market rules don’t allow T&D utilities to own resources that function like generation. That means Oncor can only deploy storage to use it for grid functions, like enhancing reliability, but not for anything that involves it getting into competitive energy markets like a generation resource would.

Not being able to realize all of the benefits that storage has to offer significantly reduces the technology’s value to Texas utilities, Oncor and Brattle Group officials told Utility Dive. But there are no such market barriers in California, and Pizarro said that taking all of storage’s attributes into account in the LCR-RFO is a main reason they found it beneficial to buy so much, even when it was nominally more expensive than gas.

‘A little science experiment’

SCE hasn’t made any major storage purchases since the LCR-RFO, and its vendors are currently busy at work to deploy the resources on its system. In the meantime, Pizarro said that SCE is focused on continuing to study the functions of storage it already has on the grid, like the the 2.5 MW Orange County system and an 8 MW transmission-connected project at the Tehachapi wind farm.

“We have our Tehachapi energy storage project, that’s testing an 8 MW system at the transmission level, and is one of the largest of its kind in the world,” Pizarro said. “That one is providing grid services in an area, part of the Tehachapi project that’s bringing in a lot of renewable power, so a great way to test transmission level integration.”

In many ways, SCE is learning lessons about storage not only for itself, but for the entire industry. Pizarro hopes that its experience can provide helpful lessons for other companies as well.

“We had a sense of different use cases for storage early on, even going back to some white papers going back 4 to 5 years ago,” he said. “So we’re testing and demonstrating those different storage uses, whether it’s for storing excess energy and shifting it to higher value periods, smoothing out fluctuations in the grid system at the distribution level, or supplying demand out at the transmission level, we’re getting learnings on that.

Pizarro sees SCE’s role in energy storage not only as self-serving. The utility can play a proactive role in figuring out how to better place, value and operate a variety of energy storage technologies, stimulating the growth of the industry far beyond the borders of its service area.

“It’s early days in the technology,” he said. “My view is that we’re still on the flat part of the S curve here, and I think it’s important that there’s value we can capture for customers today, but there’s also a broader societal value that we’re capturing by being able to have these demonstrations — frankly not only see what’s working, but where the bumps are and provide that feedback to the broader market.

“There’s a lot value in that part of this,” he continued. “Some of this [experience] is commercial products, and some of it is still a little science experiment, but it’s an important one for society and we’re just very pleased to be able to play a central role in that.”