Energy storage has inspired many metaphors to convey the versatility of its uses. Some call it the bacon of the grid, making other resources taste better. But the image of the Swiss Army knife better captures the sheer number of different roles this technology can play.
Storage Plus is examining the major storage use cases to understand the history and future of each tool on the Swiss Army knife of storage. Last week covered non-wires alternatives, which use batteries in place of more expensive grid upgrades. We also explored the capacity use case, which analysts believe will drive 80 to 90 percent of deployments in the coming decade. Before that, we told the story of frequency regulation, the tool in the toolkit that launched the modern grid storage industry.
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Developers have used batteries to save customers money for years, but the style and strategy continue to shift.
The use case goes by various names. There’s demand-charge management, which tackles the time-based charges that can make up half of a commercial property’s monthly power bill. Time-of-use arbitrage helps customers avoid more expensive hours, usually with the help of solar power. Sometimes the batteries operate as a traditional demand-response asset, generating value by dropping load at crucial times.
What unites the various business models for customer savings via battery storage is that they rarely stand on their own. The “Swiss Army knife of storage” framing foregrounds each major use of storage as a freestanding entity, but bill savings is one that typically relies on other applications to make deals happen.
“In every geography where grid services are possible today through commercially available means, our systems are participating in those alongside more typical bill management approaches,” said Phil Martin, vice president of energy storage at Enel X.
It’s also a use case that is still hitting its stride. Old strategies and players have fallen by the wayside, new ones are rising, and the future is still unwritten.
Defining the opportunity
Customer bill savings require a customer. The search for customers willing to invest in batteries for bill savings almost always leads to commercial or industrial entities.
Commercial and industrial customers have had more exposure to time-based rates and charges than do residential customers. They’re also more likely to task an employee with managing the company's energy costs — someone who could be persuaded to adopt a new grid technology if the payoff looks good.
That’s what a handful of California-based startups tried to do in the early part of this decade. In 2013, the state mandated that its utilities make an unprecedented investment in batteries. Venture-backed companies including AMS, Green Charge Networks and Stem figured the right software could turn small batteries located across many different sites into useful assets for the grid at large and for the batteries’ hosts.
These startups put their theory to the test when utility Southern California Edison decided to shut down the San Onofre nuclear plant, situated on the shore between Los Angeles and San Diego.
“San Onofre’s retirement created a moment in time when there was an enormous gap between local generation capacity and demand,” said Alan Russo, chief revenue officer at Stem. “That was a pretty big deal.”
The 2014 Local Capacity Requirement procurement awarded 85 megawatts of capacity to Stem and 50 megawatts to AMS. They would go out and sign up commercial customers to host batteries. Then the startups would operate the batteries in such a way as to save the customers money on their bills and deliver local capacity when the utility needed it. The early demand-charge management business model was predicated upon revenue from a capacity contract to make the whole thing viable.
Struggle to survive
The problem with that model was that there was only one San Onofre. Other nuclear plants shut down around the country, but none of them prompted a massive distributed storage contracting extravaganza.
Even those one-of-a-kind contracts proved insufficient to sustain some of the business models. AMS ran into difficulty funding a multiyear infrastructure build-out with the working capital of a young startup; it eventually pivoted to market dispatch software, handing off its Southern California fleet to Stem to operate on the utility’s behalf. That pivot had a happy ending: Leading storage integrator Fluence bought AMS in October 2020, attracted by its ability to make more money for power plant owners through algorithmic dispatch.
Green Charge sold to French energy giant Engie in 2016, later transforming into Engie Storage. The reconstituted company shifted focus from California to New England, where solar developers could add batteries, seize incentives and bid into wholesale markets. It started offering front-of-the-meter batteries, veering from the small commercial customer base it had cultivated.
Stem stayed closer to its original roots but largely moved away from self-developing, instead supplying developer partners with software and storage expertise. And instead of primarily installing small standalone batteries (Stem’s initial projects clocked in at 18 kilowatts but grew from there), Stem deals with solar-paired storage in California.
As the Local Capacity Requirement installations wrapped up, California utilities enforced time-of-use rates that paid customers less for solar generation in midday hours and charged them more for power in evening peak hours. Adding batteries to commercial storage allowed customers to mitigate demand charges, shift solar production to more valuable hours and capture the federal Investment Tax Credit on the whole bundle.
“Today, the majority of the market is solar attached, by far,” Russo said of Stem’s California operations. “The magic is determining what’s the most economically appropriate thing to do with the energy storage system at any given moment.”
This may be different from the original view on the value of standalone commercial-scale batteries. But it seems to be working. Stem’s bookings grew 33 percent from 2018 to 2019, Russo said. 2020 bookings have already surpassed the full year of 2019, with most of the historically bustling fourth quarter still left to go.
Portfolio-based approach
A different flavor of commercial storage sees batteries not as the ultimate goal but as one of a range of tools harnessed to serve customers.
Enel, the Italian utility turned global renewables superpower, forged its Enel X business by acquiring behind-the-meter storage developer Demand Energy, as well as commercial demand response leader EnerNOC. The combined company dispatches battery storage as one tool in a multifarious portfolio of demand response assets.
Plenty of policy and regulatory work needs to be carried out to allow batteries to earn money on the full range of services they can provide. Indeed, slower-than-expected regulatory developments for distributed storage have hindered the growth of that market. But demand-response frameworks have clear mechanisms for compensation, Enel X's Martin said.
That’s not to say balancing grid services with customer needs is always simple or straightforward.
“Value-stacking is not inherently accretive,” Martin said. “The secret sauce around value-stacking is around minimizing opportunity costs.”
A newcomer to the segment is bringing ample amounts of capital to invest in storage alongside other customer-sited equipment, such ass solar, miniature wind turbines, electric vehicle charging and more. In just a single year, Catalyze has invested $40 million to acquire and develop distributed energy, and it has plenty more cash to spend from backer EnCap, an oil and gas investor.
Catalyze differs from its peers in that it says it can keep costs so low that it does not need to stack grid services to make projects pencil out economically. It designs projects around standard equipment configurations rather than customized designs and uses a proprietary software platform to scout customers and manage projects.
Frozen in Ontario
After California’s Local Capacity Requirement moment, developers found the best traction for standalone demand-charge-management batteries in Ontario, Canada.
The province funds its clean energy programs in part through a Global Adjustment Charge, which hits large commercial and industrial facilities with charges based on their usage during the five highest peak hours on the system. If those customers install batteries and drop their usage during those five system peaks, they can significantly reduce power bills.
The value of this driver is evident in the scale of batteries it supports.
“The use case can allow you to have a very large battery relative to the [customer's] site load,” Martin said.
The biggest known customer-sited batteries are all in Ontario. Currently, Convergent Energy + Power holds the record, with two 10-megawatt/20-megawatt-hour systems. Enel X is also building two of that size as part of a 10-project portfolio in partnership with Ardian Infrastructure.
But that bustling market hit a wall in June: The province froze the demand charge for the coming year as a response to the economic disruptions of COVID-19. This move provides more predictable power bills for companies recovering from the slowdown. But it also means investments in storage won’t matter, for the time being; customers will pay charges based on the past year’s peaks.
That sudden shift revealed the risks in building a long-term business model on a tariff structure that is vulnerable to change. It could trigger flashbacks to the PJM frequency regulation market's sudden decline; if there’s any lesson to extrapolate from there, it’s the importance of making your money back soon, before rule changes scuttle the business model.
Demand-charge models are particularly susceptible to this risk. Utilities and their regulators set rates in order to recoup necessary investments in grid infrastructure. Demand charges are one way to make that money back. But if every customer that had to pay demand charges successfully avoided them with clever battery investments, the charge would lose its ability to collect money for the grid, forcing a change in the rate design.
In any case, the changes in Ontario are just temporary, Martin noted.
“The long-term value proposition is unchanged, and we continue to see Ontario as a strategic growth market for battery storage,” he said.
Next moves
The nonresidential storage segment has never managed to sustain long-term growth, according to data from Wood Mackenzie.
Quarterly deployments jumped up and down over the years, with seemingly promising growth runs ending after two consecutive quarters. That’s markedly different from the residential market, which is on a six-quarter growth streak.
Efforts to standardize products and shorten the sales cycle could help fuel sustainable growth. In the near term, teaming up with the distributed solar industry serves that goal, said Stem’s Russo.
“The solar industry has a great track record and has continued to project growth,” he explained. “As a [chief revenue officer], I’d much rather attach to a large, robust, growing market than have to carve out my own market.”
Developers also flag electric vehicle fleet charging and backup power as services that are becoming more attractive to corporate customers. The business models there are less proven, though.
Engie staked out a model for this in a deal for the Santa Barbara Unified School District. It will install onsite solar across the school portfolio, with battery backup at the larger facilities. Savings from solar and battery operations mean this deal will deliver cheaper electricity over its lifetime while providing backup power to protect against fires or earthquakes.
Demand-management batteries historically were too small to offer meaningful backup because making them larger would throw off project economics. Santa Barbara shows that the calculus is changing, and the architects of the deal insist the model could work in other outage-prone regions.
The biggest question mark hanging over the future of storage for bill management is the recent Federal Energy Regulatory Commission Order 2222. The decision asks the organized power markets to make rules to allow distributed resources to compete. Actual implementation remains months, if not years, away.
But the potential is high, Russo said. It could extend the sorts of opportunities Stem pursues in California into other geographies. “This is just creating an environment where developers will be able to proceed with greater confidence."
The state-by-state implementation is still unfolding, but developers can chase land rights and interconnection positions knowing that something is in the works.
