Rooftop solar PV, behind-the-meter batteries, smart thermostats and appliances, and energy-aware home automation are all sources of energy, capacity and reliability for the power grid. So say the engineers who’ve built them -- and so say the customers buying them. Now if only the regulators would move as fast as the engineers and customers.
That's how two top executives from SolarCity and Nest Labs described the current state of play in California for distributed energy resources (DER). Speaking at the More Than Smart conference in Sacramento on Wednesday, Peter Rive, CTO and co-founder of SolarCity, and Scott McGaraghan, director of business development for Nest Labs, laid out ways each company is ready to serve grid needs beyond what they're doing today -- and gave some specific advice to the state's regulators on how to fix what's not working.
“Listen to the engineers” was the top piece of advice from SolarCity's Rive. As one of the leading third-party solar developers in the state (and the country), SolarCity has had its disputes with utilities over net metering and rate reform. Last year, it joined solar developers and energy storage providers in pressing the California Public Utilities Commission (CPUC) to affirm their right to connect battery-backed solar systems to the grid, against utility objections.
SolarCity has broadband-connected servers at every home and business it has equipped with solar, and Rive has spoken before about how the company can use that data analysis and control capability to offer grid services beyond the kilowatt-hours of net-metered green energy they provide. Smart inverters are able to provide voltage support and reactive power today, he noted, and they are furthest along in being put to use on the grid, although California still has two years of testing to complete.
But energy storage, which Rive said will come “by default” with each SolarCity PV installation by 2020, will open up huge new realms, he said. That could include storing hours' worth of solar energy for use later in the day, helping to solve the “duck-curve” grid disruptions facing California and other solar-rich states like Hawaii.
It could also include injecting energy back into the grid from the battery, he noted. But SolarCity and other behind-the-meter battery players can’t do that under today’s rules, despite the engineers' assurances that it’s safe and reliable at scale, he said.
McGaraghan, director of business development for Nest, named “listen to the customers” as his core plea to regulators in the audience. Since being bought by Google for $3.2 billion last year, Nest has added smart smoke detectors and internet cameras from its $555 million acquisition of Dropcam to its portfolio. The long-term goal is a “conscious home,” he said, with Nest’s internet-connected, smartphone-controllable thermostats connecting with cloud-based analytics that can verify, predict and optimize energy efficiency based on each homeowner’s behavior.
Nest has also participated in demand response programs with utilities including Austin Energy, Green Mountain Energy, Southern California Edison and NRG Energy’s Reliant Energy. Those have been almost exclusively traditional mass-market, behind-the-meter deployments, with customers agreeing to let temperatures rise on hot days. Typical programs tap these thermostats about 20 hours a year, he said. But Nest can offer more fine-tuned energy adjustments across its customer base of something like 400 hours a year -- that is, if regulations allow it to participate in the markets for grid-balancing services, or to earn money as a capacity resource for grid operators.
Nest has even demonstrated home-by-home energy adjustment that’s connected to utility SCADA systems, to help manage localized grid disruptions, he noted. That could allow demand response capacity to play a role in the distribution grid investment planning models that California’s investor-owned utilities are developing for next year, to meet mandates put in place by AB 327, a far-reaching energy law enacted last year. Instead of building new power lines or upgrading substations to meet peaks that only come a few times a year, they could simply turn down air conditioners and pool pumps to lower the peak.
In some ways, distributed energy is “erasing the line between the grid and customers” in ways like these, said Susan Kennedy, CEO of Advanced Microgrid Solutions. A former CPUC commissioner and chief of staff for Gov. Arnold Schwarzenegger, Kennedy founded Advanced Microgrid Solutions last year to integrate multiple demand-side technologies, centered around energy storage, in order to allow buildings, campuses or portfolios to participate in a variety of grid-facing programs or markets.
Distributed energy management offers much more flexibility than traditional natural-gas-fired power plants, since it can be built in building-by-building increments, she noted. It also opens up buildings to the “application economy,” with a much broader world of software and business development talent than has existed before, she said.
But the market potential for distributed energy is still being stymied by some recent regulatory decisions in California, she observed. For example, state grid operator CAISO is developing plans for a “resource adequacy” product that could call on centralized or distributed assets to help the grid manage the steep afternoon ramp that comes on solar-rich grids.
It’s currently asking any participating resource to be available for four hours, which is too long to discharge most lithium-ion batteries. They’re much better suited to a two-hour duration, which is something CAISO and utilities could use to manage ramp, she said. By keeping a four-hour limit, CAISO has “literally doubled the cost of lithium-ion batteries,” she said, by requiring a project to have two batteries where one would have served just as well.
But Kennedy reserved her bluntest criticism for the massive, long-term procurement proceeding underway in Southern California to replace the San Onofre nuclear power plant with wind and solar, demand response, energy efficiency and energy storage. In that decision is a rule requiring utilities to prove that any distributed resources they tap for these RFPs must be “incremental” in proportion to the amount that would have come onto the grid, more or less naturally, through customer growth.
That vague, yet prescriptive, bit of language has put utilities in a bind, she said. It’s not clear how incremental capacity will be measured, for instance, or how utility spending in existing energy efficiency and Self-Generation Incentive Program funds will relate to that calculation. That uncertainty is making it hard for distributed resources to get traction with utilities developing RFPs that will give out billions of dollars to meet grid needs through 2022, she said -- and solving it will require the state’s regulators to work quickly, lest the opportunity for bidding be lost.