Last week, Tesla Motors CEO Elon Musk answered a lot of questions about how the electric-vehicle-turned-energy-storage company was going to lower the cost of and expand the market for home battery systems.
Now Peter Rive, Musk’s cousin and co-founder and CTO of SolarCity, has filled in some important missing details by explaining how Tesla’s sister company is going to turn those backup batteries into grid resources — and share the resulting revenues with its customers.
Unlike its commercial-government and microgrid lines of business, which will use Tesla batteries for demand charge management and always-on power, respectively, SolarCity’s initial offering for residential customers is centered on emergency backup power. But in a Friday interview, Rive said that its residential solar-battery customers will eventually be able to make money by opening their systems to a number of future grid uses.
“All of the contracts that customers are signing, and all of the batteries we’ll be deploying, are grid-services-ready,” he said. SolarCity has been installing in-home controllers and broadband connections at its residential solar sites for years now. While they’ve mainly been used to track solar system performance, SolarCity has also tapped them in storage pilot projects, to show how it can alter charge-discharge cycles to help meet utility and grid needs.
Now, SolarCity’s financed battery-solar residential system offerings will include a standard customer contract that “essentially splits revenues that grid services provide,” he said. “This is something that we’ve contemplated for quite some time.”
Rive didn’t provide precise details on how this revenue-sharing model would work. That makes sense, given the lack of clarity on just how aggregated solar-storage systems will be able to earn money for grid services in the future.
But he did provide one metric for the value it could capture for SolarCity and its customers — the rough estimate of $10 per kilowatt-month that California utilities pay for resources and investments to maintain grid capacity.
“In their case, they procure capital equipment and then depreciate it,” he said. “With solar and a battery, you can provide what is a firm capacity resource.”
That’s why the value is presented as a “per-month” figure, by the way. That’s not an amount of energy to be sold to the system hour by hour and day by day. Instead, it’s a payment in exchange for a firm commitment to turn its fleet of battery-backed solar systems into a reliable source of power at moments of peak energy demand, when utilities and grid operators need it the most.
Breaking price barriers to drive solar-battery resources to grid scale
Hitting the right price point for grid-connected batteries is important for this equation to work out, and “the thing that excites us the most about this new product is the reduction in cost,” he said. SolarCity will install Tesla’s 10-kilowatt-hour batteries for about $5,000, he said — a figure that clarifies just how much markup it plans to add to the $3,500 pre-inverter and installation price Tesla quoted in last week’s unveiling.
That equates to $500 per kilowatt-hour for an all-in system cost — a price point that truly does push the lower boundary of what we’ve seen in the residential energy storage field. It also allows SolarCity to include Tesla’s batteries as a part of its typical solar installation financing.
That’s not just in markets that offer lucrative incentives for behind-the-meter energy storage, he said. While Tesla and SolarCity have received tens of millions of dollars from California’s Self-Generation Incentive Program (SGIP), for example, “for this product, we are not counting on any SGIP incentives whatsoever,” he said. That’s not to say that SolarCity will stop tapping the SGIP or other incentives when appropriate, he said, adding, “I don’t see it as the long-term solution.”
“Plus, we’re offering this product in many states,” he said. In fact, “pretty much all the states we’re in.”
That’s a lot more states than the limited number that are actively working on ways to allow third parties like SolarCity to make money on networked solar-storage systems as grid assets. But in a handful of key states, those changes are coming fast.
“Right now, there’s a lot of work going on in New York, California and Hawaii that contemplates a market for distributed energy resources,” he said. “Even though those markets don’t exist yet, we’re pretty sure they will” in the near future.
Take California, the state where Rive says utilities pay roughly $10 per kilowatt-month for grid capacity services. California has mandated that its three big investor-owned utilities procure a combined 1.3 gigawatts of energy storage by 2022 — and it has set aside customer-sited storage systems as being eligible for meeting that mandate.
New models for merging utility and customer assets
Southern California Edison opened the door for distributed energy resources (DERs) to serve capacity needs last year, when it signed contracts for hundreds of megawatts of distributed solar, behind-the-meter batteries, automated demand response and targeted energy efficiency as part of its 2,200-megawatt Local Capacity Requirement (LCR) procurement for its grid-stressed West Los Angeles Basin region.
Another place where aggregated solar-battery systems could get paid for their service is to meet the need for flexible capacity resources — energy assets that can be called upon to help the grid manage steep ramp-ups in demand for electricity in late afternoons and early evenings. While California doesn’t see that kind of need today, it’s going to during cool, sunny days in the years ahead if rooftop solar keeps growing, according to the California Independent System Operator load forecast that’s become known as the “duck curve.”
Distributed, customer-owned resources could help flatten these potentially disruptive grid-wide imbalances without building new natural gas-fired peaker plants or transmission lines, if they’re set up to do so — and if they can be compensated for the service. Here’s a chart from California energy policy nonprofit The Clean Coalition (PDF) that shows how that could play out.
But long-term capacity is just one of the grid services that distributed solar-battery systems could provide, Rive noted. “Solar and batteries are just incredibly flexible resources.”
Another way they could help the grid is by providing voltage management and reactive power support, when linked with the capabilities of smart inverters. That could allow them to help mitigate the unusual grid conditions that can arise on circuits experiencing voltage fluctuations and two-way power flows from distributed solar.
SolarCity has already shown this capability in partnership with the Department of Energy’s National Renewable Energy Laboratory and utility Hawaii Electric (HECO), in a project that has led to HECO agreeing to unblock a backlog of rooftop solar interconnections it feared could further destabilize its island distribution circuits.
Finding a win-win way out of grid defection
Distributed solar companies have long argued that the positive impacts of rooftop solar outweigh the negative effects for utilities — an important counterweight to proposals from utilities in states such as Arizona to impose hefty fixed charges on solar-equipped customers, or by HECO to halt new interconnections while it studies the potential destabilizing effects of more and more rooftop solar.
But “if HECO is preventing someone from going solar, there are other options,” Rive said. One option is taking customers off-grid with battery-solar systems that can provide all their electricity needs. As part of SolarCity’s Friday announcement, “we’re expecting to have a zero-down lease product in Hawaii some time next year that will be sub-HECO prices,” he said.
Grid defection isn’t economically viable outside of atypical markets like Hawaii, which generates most of its electricity with expensive imported oil. But if studies from the Rocky Mountain Institute are to be believed, ever-cheaper solar and battery technologies will drive more and more markets to reach similar tipping points over the coming decade.
These are the same economic factors that have driven down revenues and credit ratings of utilities in solar-rich Germany, and have pushed California, New York and Hawaii to rework regulations to forestall a similar collapse within their borders. New York’s Reforming the Energy Vision program, California proceedings mandated by state law AB 327, and Hawaii’s “DG 2.0” initiative are all laying the groundwork for customer-owned energy assets to be considered an integral part of utility infrastructure.
“In the past, people have been describing those services in the abstract,” said Rive, who contributed an article to Greentech Media in February to explain how it could work. “But this is available for purchase for utilities now” — or if not now, certainly by 2020, with batteries as part of every new solar installation SolarCity intends to install by then.
At the same time, SolarCity’s installations will still comply with California rules that limit how much grid power can be used to charge up solar-battery systems that are allowed to earn net-metering credits, he said.
“The battery gets 100 percent of its energy from the solar system — structurally, we are guaranteeing that,” he said. “There should be no misunderstanding around any potential to circumvent the terms of the net-metering agreement.”
Of course, as California reworks its net metering regulations, rules for how solar-battery systems earn their keep could change — another uncertainty to add to how the business model for solar-storage systems could play out in the years to come.
Source: Greentech Media. Reproduced with permission.