California may be the country’s key emerging market for battery-backed distributed solar. But that promise is made up of equal parts opportunity and uncertainty.
On the opportunity side, there are the state’s groundbreaking energystoragemandates, its revamping of demand response programs, and its push to reconfigure the way utilities include distributed energy resources (DERs) into their grid investment plans.
On the uncertainty side, there are coming changes to California’s net metering regulations to consider, as well as a broader rate restructuring that could reduce the return of rooftop solar that doesn't include some ability to manage energy generation and consumption on a day-by-day and hour-by-hour basis.
This is a short summary of the thoughts from companies working in the solar-storage space at last week’s Intersolar conference in San Francisco. Over the past three years, this solar showcase has seen the interest in energy storage grow from a single workshop session back in 2013, to almost a full floor of battery-focused exhibitors at this year’s event.
In part, this expanded interest is being driven by California’s vanguard efforts to expand energy storage as a viable part of the grid landscape. A 2013 mandate requiring the state’s big three utilities to procure 1.3 gigawatts of energy storage by 2022 requires that third parties own at least half this amount, and it has pushed massive numbers of project proposals into the pipeline.
A large part of this growth is being driven by the state’s push to rely on far more distributed renewable energy as a replacement for central power stations. Southern California Edison’s procurement of hundreds of megawatts' worth of distributed storage contracts last year was part of a groundbreaking effort to bolster a grid that’s facing both system-wide and localized impacts from the loss of the San Onofre nuclear power plant and future natural-gas-fired power plant retirements.
At the same time, state law AB 327 has also required Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric to create distributed resource plans (DRPs). These could give battery-backed solar systems a coequal role alongside billion-dollar utility capital investment plans for expanding and maintaining these utilities’ low-voltage distribution grids.
These DRPs include proposed pilot projects that “are pushing the boundaries on what storage and other DERs [distributed energy resources] can do on the distribution grid,” Ted Ko, policy director at behind-the-meter battery startup Stem, said in a Wednesday interview. In simple terms, each utility wants to determine whether batteries can support congested and stressed grid circuits in ways that could defer costly utility upgrades, in ways that solar alone might not.
In particular, SDG&E’s proposal to create a unique storage tariff, one that would reward battery-equipped customers willing to give the utility control over their batteries, is “a really interesting approach to how we can defer distribution grid investments with assets that customers can own,” he said.
Finally, California’s grid operator CAISO has proposed a new model for how distributed energy resource providers (DERPs) could bid their aggregated resources into grid energy and ancillary services markets, one that could come into play as early as next year.
Hitting today’s needs, preparing for future opportunities
These grid-facing opportunities are, however, not really a part of the equation for today’s behind-the-meter energy storage players. Today’s biggest money-making opportunity in California lies in helping commercial customers reduce spikes in energy usage that drive the demand charges that can make up to half of a commercial customer’s electricity bill.
“We’ve decided to focus on commercial and industrial peak-clipping applications,” Kirk Stokes, director of sales for Sharp Electronics’ energy systems and services group, said of Sharp’s energy storage business in a Wednesday interview at Intersolar. “We can sell today against existing rate schedules -- we can quantify the economics today.”
For commercial customers that see rooftop solar as a valuable way to reduce energy costs, adding storage is simply a way to address the demand side of the bill, he added. That’s the premise that’s driving solar-storage partnerships like those between Stem and SunPower, Green Charge and SunEdison, and Tesla and SolarCity.
As for the emerging opportunities to provide grid support, “When it becomes a quantifiable revenue stream, we’ll be ready,” Stokes said. “That’s why our product comes into the market with a 10-year asset management service and a 10-year guarantee.” And “because it’s software, if I’ve got an asset deployed at a commercial site, I can deliver a different feature set tomorrow by downloading a different software set.”
Stem, for its part, is already participating in an 85-megawatt contract with Southern California Edison, which calls on it to provide local and system-wide capacity for the utility. “We’re installing those systems by the end of next year, and we need to make sure all the settlement agreements and capacity agreements work,” Ko said.
One of the big questions overshadowing all of California’s policy innovations creating grid-facing opportunities for energy storage is whether they’ll maintain a role for third parties as developers and aggregators. The idea of utilities owning distributed storage assets, which could make sense in some cases, directly undercuts this opportunity for third parties, and is emerging as a critical area of contention.
SDG&E’s concept of a tariff that directly links utilities to customers might also become a way to circumvent third parties like Stem. But Ko predicted that “in the future, even if they use that same model as a rate tariff for customers, it’s going to end up being third-party providers like us managing those boxes for them, and they’re going to send signals to us.”
Bundling energy storage and demand response, grid resources
“The tricky part is what we do -- balancing the behavior of the battery to manage what the customer needs, as well as what the grid needs,” he said. “Utilities aren’t used to managing distributed resources at that level anyway, let alone managing it for optimization of multiple customers.”
That leads to another arena where customer-focused storage systems could play a new role, he said -- demand response, or the business of reducing energy use at homes and businesses in response to utility and grid needs.
California is in the midst of rewriting its demand response regulations to open new opportunities for smaller-scale participants to play a role, and has been running pilot projects to ensure that aggregating lots of sites at scale is technically possible. Stem was the first company to use behind-the-meter batteries to bid its customers into one of these early pilots, and “those systems are still operating today,” he said.
While it’s certainly possible for customers to cut energy use for demand response without relying on batteries, “with storage, you have a lot more visibility, and a lot more dependability,” he said. What’s more, “if we can cover the cost of the battery providing demand-charge management value to the customer, as well as demand-response benefits to the California ISO markets, we don’t necessarily need incentives.”
But as Sharp’s Stokes noted, batteries require a significant revenue stream to pay off their cost, and today’s demand-response opportunities don’t necessarily hit those marks.
“We’re selling a product right now that needs, at a minimum, $18 to $20 per kilowatt per month,” he said. “If we find a utility rate schedule that, on annual average, costs a customer $18 or more per kilowatt per month, that’s a target for us. If it’s less than that, we’ll walk. Demand response programs, they’re talking about $5 to $6 per kilowatt per month. You can’t sell storage on that.”
Of course, demand response programs that offer more money for faster-acting or more reliable service could help improve those figures, Ko said. But stacking those revenues on top of demand-charge management creates its own challenges in turn, he noted.
One is that California grid operator CAISO takes a 10-day rolling baseline of a building’s energy consumption to calculate how much extra reduction should receive demand-response payments. If a battery is regularly clipping peak consumption, it’s going to affect that baseline and force the battery to discharge beyond that standard daily amount to reap a demand-response payment -- and that could over-stress the battery and reduce its operating life.
Various demand-response programs calculate baselines in different ways, and the rules for how this is all done are open to change, Ko noted. Certainly any storage systems that want to play a role in demand response will have to carefully monitor, record and analyze a wide range of data to ensure they’re able to play into new markets, he said.
Similar considerations are no doubt driving demand response giant EnerNOC’s work with battery provider Tesla as it pilots storage-backed demand response in California. EnerNOC is also working with SunPower to merge on-site solar generation and energy management and efficiency, providing additional insight into how the daily patterns of solar generation play into this complex set of calculations.
Hedging against net metering changes, time-of-use rates
Amidst all these policy developments, it’s important not to forget that California’s solar net energy metering (NEM) regulations are about to change, and in ways that leave the future value of distributed solar very much in question. Later this year, the California Public Utilities Commission is set to hear the first proposals for how the state might revamp the net metering regime that now pays customers retail rates for the energy generated by their rooftop solar and other distributed energy systems.
Utilities are eager to reduce the compensation paid to customers under net metering, and solar companies and advocates want to retain it. But it’s likely that any future regime will include a lot of new components that seek to value distributed energy’s role for the grid at large in a more nuanced manner -- and that could include new rules for solar that come with the flexibility and dispatchability that storage can provide, Ko said.
“How should the new NEM successor tariff account for storage, or value storage? That’s obviously a very hot topic right now,” he said. One of the key concepts to keep in mind is that storage-backed solar could allow for more complex rate structures “that are better for the grid and for utilities, without confusing the customer that much more, because intermediaries like us will manage that for them.” There’s a possibility that concepts like SDG&E’s storage tariff could be expanded to a much broader class of customers under net metering reform, although it’s still quite unclear how that might happen.
In the meantime, a major reworking of California’s residential utility rate structure is opening up further uncertainties for net-metered solar economics. Earlier this month, the CPUC approved a plan that will replace a decade-old monthly tiered rate structure with a much less steeply rising rate structure, meaning that people who consume a lot more electricity over the course of a month will pay less in rates. That’s generally considered to be a bad thing for solar economics, since those high-cost customers stood to save a lot more money by installing rooftop PV that kept them from hitting those top tiers.
But in the long run, the CPUC’s new plan will shift to a daily time-of-use regime that charges higher prices at times of the day when electricity is in greatest demand and most expensive to generate. That, in turn, could open up significant opportunities for solar that’s backed with a certain amount of energy storage to smooth out daily energy consumption patterns, Ko noted.
That’s going to be an important driver for residential solar-storage economics. So far, the companies targeting this market such as Tesla and SolarCity, Sungevity and Sonnenbatterie, SunPower and Sunverge, Sunrun and Outback Power, Enphase and Eliiy, and many others, are promoting emergency backup power as their initial value, and the potential to reduce peak-power costs as a future benefit.