Of all the energy and environmental legislation coming out of California’s expiring legislative session, none has gotten as much attention as SB 100 — the mandate to boost the state’s renewable portfolio standard targets from 50 to 60 percent by 2030, and more ambitiously, to reach 100 percent carbon-free energy by 2045.
So far, most of the debate over the 100 percent target has centered on how to replace the natural-gas-fired power plants that provide roughly one-third of the state’s energy, as well as its most reliable and flexible peak capacity, without disrupting the grid or driving energy costs sky-high. Most of the suggestions for solving this gigantic supply-side problem have also concentrated on large-scale, supply-side solutions — gigawatts of batteries, or big increases in geothermal power, or integrating resources and markets from across the Western United States, for example.
But on the demand side of the equation, SB 100 is largely silent.
The bill, now on Governor Jerry Brown's desk, makes only one mention of distributed energy resources, as one of a long list of items that utilities will have to prove they’ve sought out to hit their new 60-percent-by-2030 interim targets. Its language on renewable portfolio standard (RPS) procurements presumes that utilities will seek out power-purchase agreements similar to those they have secured in the past, indicating a focus on utility-scale versus distributed projects. And it offers no guidance on how rooftop solar or other forms of distributed energy resources (DERs) could someday be counted as solutions in their own right.
To be fair, California energy policy watchers weren’t expecting these kinds of demand-side policies from SB 100. First of all, it’s always been crafted as an RPS bill — and the RPS construct largely excludes the positive contributions of rooftop solar, which is by far the largest category of DER out there today.
Second, California is still creating the rules for how net-metered solar, behind-the-meter batteries, advanced inverters, smart homes and buildings, grid-responsive electric vehicles, and other DERs will play a role in managing the state’s ever-rising share of intermittent solar and wind power.
But there’s no doubt that DERs and their integration with grid planning and operations will play a major role in whether or not California can meet SB 100’s mandates. As Greentech Media’s Julian Spector wrote in his exhaustive SB 100 overview this week, the demand side is the “X-factor” for any prediction of what the California energy system will look like in 2045.
And, as state energy policy watchers noted in interviews this week, the groundwork for tapping the potential of California’s grid edge resources is being laid today, and will be coming of age well before its 100 percent targets are reached. That means that the various policies being developed for DER-grid integration will have a significant impact on the way the bill eventually meets its goals.
Rooftop solar as nothing but lost load: The limits of the RPS construct for valuing DER
The first, and most obvious, point about SB 100 is that its plan through 2030 sticks with a construct — the renewable portfolio standard — that excludes net-metered solar power, and DERs more broadly, from playing an active role in meeting the state’s renewable energy targets.
“The 100 percent [by 2045] target is good, and it will influence long-term planning decisions. But really, to my view, this is a 60 percent RPS,” Brad Heavner, policy director for the California Solar & Storage Association (CSSA, formerly CalSEIA), said of SB 100. And that means a “whole infrastructure that has been built around 100 percent utility procurement.”
SB 100’s RPS targets for California’s utilities are 44 percent by the end of 2024, 52 percent by the end of 2027, and 60 percent by the end of 2030. As with previous RPS targets, they will be measured as “a specified percentage of total kilowatt-hours sold to the utility’s retail end-use customers.”
Under current regulations, the only way that distributed, net-metered solar really helps utilities in meeting their RPS goals is by reducing total utility retail sales — spinning customers’ meters backward, in other words — and thus reducing the percentage share they need to procure in renewables for each target. Utilities bake in some assumption of distributed solar growth into their retail sales growth forecasts when procuring utility-scale renewables and revise it with each procurement cycle, said Wade Schauer, director of Americas research at Wood Mackenzie Power and Renewables.
But this treats rooftop solar as if it’s no different than energy efficiency or other demand reduction, which masks its true nature and role on the grid, said Bernadette Del Chiaro, CSSA’s executive director. “Rooftop solar, which is almost the cleanest of clean, by most standards, is relegated to this mishmash status,” she said.
While this issue did come up for debate in crafting the state’s 2030 RPS goals as part of the 2015 omnibus energy bill SB 350, it was eventually left unresolved in that legislation, she said, adding, “It’s a conflict that California lawmakers have not yet addressed."
“All of these state agencies now are going to be directed to point all of their focus on this 100 percent of retail sales goal,” she said. “What does that mean for DERs? How do we make sure that DERs are part of this whole zero-carbon plan?”
Chad Singleton, senior manager at Wood Mackenzie Power & Renewables, agreed that, while “technically speaking, rooftop solar and DG [distributed generation] can count toward the RPS, there are just a bunch of roadblocks” in the way.
California is working on a transition from its current “Net Energy Metering 2.0” structure that’s expected to see solar-equipped customers, along with all other customers, moving to time-of-use rates by the early part of the next decade. Under TOU rates, the value of solar — as well as of energy storage, load-shifting, EV charging, and fast-responding and automated demand response — will largely be driven by a push to solve the very problems that solar power is causing, and will continue to cause, in California.
Aggregated, responsive, flexible: DERs as a solution to an all-green grid
SB 100’s glide path toward a renewable-powered grid does underscore another opportunity for distributed energy resources, however. That’s their role in helping to stabilize a system that’s losing its most flexible resources, and needs to find a cost-effective alternative to replace them.
“One of the biggest considerations with a total decarbonization goal is, how does resource adequacy happen?” Singleton asked. Resource adequacy (RA) is California’s term for the year-ahead capacity that California utilities have to secure for systemwide, local and “flexible” needs, including their 15 percent reserve margins.
RA has traditionally been filled largely by natural-gas plants, along with a declining share of legacy C&I demand response, and “the fastest-reacting, most reliable generators we have are peaker plants,” he said. Batteries are the most oft-cited replacement for peaker plants, and not just for power plants that aren’t built yet. PG&E’s proposal to build what would be the world’s largest battery, a combined 482 megawatts and 1,930 megawatt-hours of lithium-ion, would replace the need for three peaker plants that are up and running, but deemed too expensive to operate without “must-run” orders from state grid operator CAISO.
“But I do think with a total decarbonization goal, that resource adequacy will be pushed more toward the distributed side,” he said, since demand-side resources may well be more cost-effective than the alternative. “That’s when you start looking at demand response, electric vehicles” and other resources that can be relied on as much as peaker plants.
Peter Miller, Western energy project director for the Natural Resources Defense Council, agreed that “DERs are complementary to the goals of SB 100, by helping us to meet our clean energy targets at lowest possible cost. They can help by reducing the need for wholesale resources, and by reducing the costs of integrating those resources.”
California has been trying to revamp its demand response regulations to allow aggregated DERs to play a greater role. The Demand Response Auction Mechanism (DRAM) pilot program has allowed a host of third-party vendors to provide the state’s investor-owned utilities with a total of 700 megawatts so far of RA made up of aggregated residential and commercial and industrial demand response, batteries, EV chargers, and other behind-the-meter assets.
At the same time, California’s big investor-owned utilities have already contracted for hundreds of megawatts of DERs as capacity to help replace the San Onofre nuclear power plant, and more than 100 megawatts of energy storage and demand response to help manage potential energy shortfalls caused by the Aliso Canyon crisis.
They’re also in the midst of DER pilots meant to test whether distributed resources can replace new power plants and transmission lines — or allow existing power plants and transmission lines to be replaced with lower-carbon alternatives. Southern California Edison’s Preferred Resources Pilot in Orange County, which has contracted for 125 megawatts of DERs including batteries, demand response, energy efficiency and rooftop solar, is one of the largest. Others, such as PG&E’s distributed energy resource management system pilots in San Jose, are tapping the capabilities of advanced inverters and solar-storage systems used in tandem with the latest distribution grid technologies.
These pilots are also feeding data to CPUC’s distributed resources plan (DRP) proceeding — California’s version of New York’s work on enabling DERs to serve as non-wires alternatives for distribution grid investments. The goal of the DRP is to make DERs an integral part of utilities’ multibillion-dollar annual distribution grid investment plans, both by developing an integrated capacity analysis to collect and share data on the capacity limits for new DERs on the system, and a locational net benefit analysis that establishes the positive values of DERs in lieu of traditional grid upgrades.
The past month has seen several important filings on the DRP proceeding, including the latest grid needs assessments from the utilities, as well as upcoming distribution deferral opportunity reports to identify how DERs could be enlisted to defer — or perhaps even obviate entirely — the need for more expensive capacity upgrades.
Just how data is collected, shared and analyzed to come to these various conclusions has been a sticking point between utilities and would-be DER providers, CSSA’s Heavner noted. Still, “they’ve all been inching forward in the same direction. There are important questions, but there are answers to them, and they’re being worked out now. Once we’ve pushed through those, it’s just a question of when we can go big.”