Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems.
This is part one of a three-part Down to the Wire series this week digging into a new rooftop-solar policy expected to be adopted by the California Public Utilities Commission on December 15, 2022. [UPDATE: The policy was adopted by the CPUC as anticipated.]
Vincent Battaglia, CEO and founder of Renova Energy, isn’t shy about expressing his feelings on California’s looming decision to end the net-metering regime that’s driven a nation-leading 12 gigawatts of rooftop-solar installations in the state and helped his company grow from a sole proprietorship in 2006 to more than 300 employees and $65 million in annual revenue today.
“Bullshit” is how Battaglia characterizes the “cost-shift” argument made by California utilities and consumer advocates contending that existing net-metering policy has unfairly shifted the costs of maintaining the state’s grid from people rich enough to buy or finance rooftop-solar systems to those who can’t afford them. He blames utilities for the lion’s share of rising electricity costs instead.
And he thinks the new structure proposed by the California Public Utilities Commission, which would reduce compensation for exported rooftop solar power based on hourly measurements of its value to the grid, is ridiculous for being based on an “asinine set of incremental adjustments of every frickin’ hour of every day.” He fears the structure will make the cost-effectiveness of every new solar system a mystery for homeowners, installers and financiers alike.
But no matter how Battaglia feels — and his point of view is far from unique among California rooftop-solar industry players, even if it is more colorfully expressed than most — he’s still planning for how to keep his business growing once net metering goes away in California next year, as it will if the CPUC approves its proposed structure at its meeting this Thursday. And there’s more to his plan than expanding into neighboring states like Nevada and Arizona, he said.
First, “we’ll be adjusting our pricing so that our customers are not looking at a nine-year payback,” he said. Under the current net-metering structure, a homeowner who installs a new rooftop solar system can expect to recoup the cost in five to seven years through reduced electricity bills and credits for exporting their excess power to the grid.
The CPUC’s new structure has set a target of nine years for customer payback, but Battaglia wants to get that number closer to seven for his customers.
“In 18 months, when the utility does another double-digit rate increase” — an offhand reference to California’s spiraling retail electricity rates, which have risen between 15 and 33 percent since January 2020 — “that pricing will look even better,” he said.
Second, Renova will double down on selling batteries alongside new solar systems, he said. Those batteries can store solar power generated at midday, when it’s worth little to customers or to California’s grid, and save it for the evening “peak” hours after the sun goes down, when the state faces increasing threats of power demand exceeding supply.
Renova is sourcing batteries from SunPower, a minority investor in Battaglia’s company. “Those batteries are very clever with their software,” he said, capable of forecasting when they should store power and when they should discharge to lower a home’s grid draw or export power back to the grid. And because the CPUC’s proposed new structure would offer extra-high value during a relative handful of hours of the year, being able to predict that is vital to make up for the big drop in compensation they’ll face almost every other hour of the year.
Those are also the hours when the CPUC and other state agencies hope that solar and batteries can support all the other grid-powered devices — electric vehicles are a big one, as are heat pumps for space and water heating — that Californians must adopt to reduce carbon emissions and meet the state’s mandate to achieve net-zero carbon by 2045.
In this respect, Battaglia’s plan largely aligns with broader state policy. The CPUC’s stated goal with its net-metering replacement plan is to shift a largely solar-only market to one dominated by solar panels plus batteries — plus EVs, plus electric heating and appliances — all responding to and being rewarded for acting in ways that shift and shape their generation and consumption of power to support the grid at large.
Renova’s roadmap also mirrors the strategies being developed by a host of other companies whose businesses will be affected by the coming policy change, including nationwide solar installers Sunrun, Sunnova and SunPower, solar-inverter providers Enphase and SolarEdge, and battery vendors such as Tesla, LG Energy Solutions, Panasonic, sonnen and Generac. They’re all looking at the still-uncertain details of how California’s new regime will work, both in isolation and in conjunction with multiple other policy shifts underway in the state.
“We’re kind of in the Wild West of this new form of customer adoption,” said Walker Wright, vice president of public policy at Sunrun, the country’s leading residential solar installer. “How can we get ratepayer value, resiliency value, out of a solar-plus-storage future in California?”
Moving beyond net metering
To understand why batteries will be so important as the rooftop-solar market changes under the CPUC’s expected decision, it’s important to know how rooftop solar makes money for homeowners. In simple terms, that happens in two ways: by reducing how much electricity customers buy from utilities and by allowing customers to sell excess solar power back to utilities.
Today, both of those values are based on the retail rates that customers pay for utility power. Customers avoid paying those retail rates for every kilowatt-hour of rooftop-solar power that replaces a kilowatt-hour they would have used from the grid. They also get paid the retail rates for every kilowatt-hour of solar generated in excess of their usage that feeds back to the grid. (In the end, they pay for their “net” usage of electricity, hence the term net metering.) According to the California Solar and Storage Association (CALSSA), the payback on most net-metered solar systems in the state is split pretty evenly between those two value streams.
Retail electricity rates are much higher in California than in other parts of the country, due to a number of factors. And, like everywhere in the country, they’re also much higher than the prices for power on wholesale power markets. That’s because retail rates encompass costs for lots of things beyond electricity, like the expenses of building transmission lines and other grid assets, hardening the grid against the threat of sparking wildfires, investing in energy-efficiency programs and offering subsidies to low-income customers.
It's that gap between the portion of rates that pays for the cost of generating electricity and the portion that pays for all those other things that causes so much strife and confusion over net metering.
Utilities in California and across the country — and some consumer advocates and environmental groups — argue that net metering at full retail rates allows people with rooftop solar to avoid paying their fair share of all the costs for things that they still benefit from, starting with the grid that provides them power when their solar systems don’t. That, critics of net metering say, forces an unfair and unsustainable share of those costs onto people who don’t have solar.
Rooftop-solar advocates and their environmental and community allies argue that those costs are outweighed by the benefits of widespread rooftop solar. Those include tapping private-sector investment to replace fossil-fueled power faster than utilities would do on their own, reducing the need for new grid infrastructure by generating more power closer to where it’s used, and giving customers who want to switch to electric vehicles and heating a resource that can help cover the higher costs of making that switch, among others. They also argue that utilities are overestimating the so-called “cost shift” from solar to non-solar customers in the service of a more fundamental interest: protecting their monopoly over the generation and provision of power.
We’ve written multiple articles and hosted a debate on the fractious arguments over these “cost-shift” calculations, and won’t spend more time on them here. Suffice it to say that the CPUC has agreed with utilities and their allies that full retail-rate net metering is causing a cost shift, and its proposed decision aims to correct it. The CPUC’s solution, which will apply to new solar customers starting as early as April 2023 (existing customers are exempted), is to change both the rates that solar-equipped customers pay for power and the rates they earn for exporting power, to more accurately reflect the costs and benefits of each. And both of these changes make energy storage an integral part of a moneymaking rooftop-solar proposition.
Why batteries are central to navigating California’s rooftop-solar future
For the power that new rooftop-solar owners buy from the grid, the CPUC’s plan would require them to pay “electrification rates,” dubbed as such because they’re intended to help homeowners move away from fossil gas and electrify their homes. In general, those are rate structures that charge more for power during peak hours (evenings from about 5 p.m. to 9 p.m.) and less during off-peak hours (the rest of the time). The aim is to encourage customers to use less energy during peak hours and then, during non-peak hours, store up solar power in batteries so it can be released during peak hours to lessen demand and strain on the grid.
Here’s a chart of current electrification rates for California’s big three investor-owned utilities — Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.
Most of the customers of these utilities are already on “time-of-use” rates that charge more during peak hours. But electrification rates have higher on-peak and lower off-peak prices, which reward customers who can control their consumption and generation to maximize value, but punish customers who can’t.
For the power that new solar owners export and sell to the grid, the CPUC would replace retail-rate compensation with compensation on an “avoided-cost” basis — a complicated structure meant to reflect the value of exported power from hour to hour across different months of the year and different climate zones across the state. The following charts show how those values will shift over months of the year and hours of the day in a temperate climate zone within PG&E’s service territory, indicating the wide variation in values that exported solar power can expect to receive over time. (The items listed in the legends are “costs” that the state can avoid by tapping into rooftop solar power.)
The problem with both of these changes, solar advocates say, is that they replace stable and predictable values with changing and unpredictable ones.
That’s less of a problem for the power that rooftop-solar owners buy from the grid. The three utilities’ electrification rates are fairly comprehensible and predictable for homeowners and solar companies looking to game out their potential savings. Still, each utility’s electrification rate is different, so there’s a lack of consistency across the state.
What’s more, an ongoing CPUC proceeding to “advance demand flexibility through electric rates” could well alter those rates in future years by changing the hour-by-hour structures on offer to solar customers or by adding new monthly charges in an attempt to spread fixed utility costs more evenly across all customers.
But those concerns pale in comparison to solar advocates’ anger over the changes proposed on the export side of the equation. First, the avoided-cost rates the CPUC would have solar-equipped customers earn for their exported power are far lower on average than today’s retail rates — about 75 percent lower, according to CALSSA — which cuts deeply into roughly half of a rooftop-solar system’s total economic value.
Second, they’re based on a highly complex and much-disputed set of calculations of the value that exported energy plays across multiple realms, including reducing the need for large-scale utility resources to meet grid peaks, reducing grid-upgrade costs and supplanting the use of climate-polluting fossil gas. Those values change from hour to hour and month to month, and as the charts above indicate, they’re much higher during a handful of hours in the summer months than at any other time. That forces solar-plus-battery systems to target a small number of high-value hours per year to export as much energy as possible to make up for the majority of hours when that energy will be worth much less. The avoided-cost calculations will also be rerun by the CPUC every two years, adding even more uncertainty to the system.
Solar advocates have been arguing for a gentler “glide path” for making the shift from exported solar earning full retail rates to it earning these avoided-cost rates, one that would slowly cut compensation over the course of multiple years. The CPUC’s proposal does offer some customers a higher rate for exported solar during the first nine years of a system’s operation, several cents per kilowatt-hour above the avoided-cost rate. But solar groups argue that’s not enough to soften a steep dropoff in compensation that could undercut rooftop-solar economics and crash the state’s rooftop-solar industry.
Absent any last-minute changes, however, it appears that solar companies will need to find a way to make their businesses work within the structure the CPUC has proposed. Sam Jammal, vice president and chief of staff for major residential solar lender Mosaic, highlighted the increased uncertainty that these changes could force on parties trying to predict payback periods and rates of return on portfolios of net-metered solar-system assets.
“We can still finance the products and ensure we can structure affordable monthly payments,” he said. At the same time, “we have some concerns about how complicated the state policy may be becoming.”
In a world where solar power’s natural daily generation patterns will earn far less money, batteries become an increasingly important — perhaps central — piece of the rooftop-solar proposition. But when you add in the uncertainty and unpredictability of the underlying rate structures and avoided-cost crediting metrics that will determine that total value, batteries take on an additional role — that of an insurance policy against unexpected change.
That’s because batteries are the most controllable part of the “load shape” — the combination of solar generation, energy storage and electricity consumption at every home with a rooftop array. This graphic from Sunrun shows how a battery (represented in green) can store excess solar power and discharge it later in the day to convert a home’s “net load” — the amount of energy a home draws from the grid — to nearly nothing throughout most of the day, including what would normally be the time of peak household usage in the evening, when the grid is likely to be under the most stress and electricity costs are highest.
Managing that load shape will spell the difference between earning a reasonable payback on your investment in a solar array or not. While Jammal hopes that the CPUC will alter its proposal to enable standalone rooftop solar to achieve reasonable economic rewards, “ultimately we think solar-plus-batteries will be the direction the market will go,” he said. “What we are going to see — and we’re all going to learn this — is how our partners on the installation side start combining batteries and start combining these electrification products that have their own incentives and their own impacts on whole-home energy use.”
Is the industry ready for a boom in demand for batteries?
All of these changes add up to huge opportunities for battery vendors and the host of companies that are integrating batteries into residential solar.
Sunrun was ahead of most installers in marketing batteries alongside solar systems. It’s had particular success in California, where existing rate structures have already been encouraging home storage, and the risks of wildfire-prevention blackouts have made many customers seek out batteries to serve as backup power sources. The company says batteries are added to about 20 percent of the residential solar systems they install in California, compared to an industry average of about 14 percent in the state.
The CPUC’s forthcoming decision, meant to supercharge adoption of batteries with solar systems, could quickly drive those adoption rates far higher, said Sunrun’s Wright. But it’s unclear whether the state’s utilities, regulators and permitting agencies are ready to efficiently support the shift to a far greater number of solar-battery systems than the state has seen before — and whether the broader battery industry and supply chain is geared up to support it.
California has deployed more than 530 megawatts of residential battery systems over the past five years, and demand is growing, Wright said. In fact, “there’s far more demand for batteries than the industry can deliver right now, due to well-known battery shortages,” he said.
Solving those supply bottlenecks will be the first challenge for a post-net-metering California market. Recent market signals do indicate that a long-running shortage of batteries for grid energy storage, caused by Covid-related supply-chain disruptions and booming demand for lithium-ion batteries for EVs, may be easing, said James West, senior managing director and head of sustainable technologies and clean energy research at Evercore ISI.
“We had a time there where the companies that were financing a lot of this, like Sunrun and Sunnova, and the technology providers like Enphase and SunPower, were short on batteries,” he said. “Now they’re able to provide the batteries, at least in a reasonable amount of time.”
Once they can get the batteries, the next question for solar companies is whether they can get them permitted and interconnected in a timely fashion, Wright said. “How quickly can you ramp up what is a profound change in the types and…volumes of applications that are coming in?”
Industry data indicates that it takes about 50 percent longer to permit and interconnect battery-solar systems than it does for solar systems alone, he noted. Many city and county permitting offices are still learning how to process these requests, although efforts to standardize solar permitting processes, including the Department of Energy’s SolarApp, could be adapted to support solar-plus-battery installations.
Another challenge is that adding batteries is more likely to trigger the need to upgrade a home’s main electrical panel, a process that can add months of additional permitting and interconnection time, Wright said. And customers who install rooftop solar are likely also to be “in the front of the pack in terms of electrifying their homes and having EVs in their garages,” which will add complications to interconnection and permitting.
EVs and electric heating could add significant new loads to the utility grid — and rooftop solar panels could offer significant relief to those stresses, he said. But “how can we get there, and can the system digest that change, and at what speed?”
Making solar-battery systems make economic sense
It’s also important to remember that batteries cost thousands of dollars on top of the cost of a typical home solar installation. Earning back the cost of a battery is far more complicated than plugging it in, programming it to store power at midday and discharge when peak prices begin, and walking away.
That’s why almost every solar-plus-battery system now being sold in California comes with a variety of options for actively controlling and adjusting the interplay of solar generation, energy storage and home electricity use to maximize the overall value of that “load shape.” Just what that optimization will look like depends, of course, on a number of factors.
Some of them are starting to become clear — the need to limit exports during off-peak hours and save up energy to discharge when the value of energy exports spike, for example. But others will only emerge in the future, which means that these systems have to be ready to react to change.
That’s the idea behind sonnenConnect, the new “grid-interactive” solar-battery program from sonnen, the German battery vendor owned by Shell, and Baker Electric Home Energy, a subsidiary of electrical contractor Baker Electric. It’s one of a growing number of “virtual power plant” offerings that are promising customers increased value for their solar-plus-battery systems, in exchange for letting the installing company control how those batteries operate on a moment-by-moment basis.
“This is about harnessing solar and harmonizing it into grid operations in order to enable the energy transition,” said Blake Richetta, CEO of sonnen’s U.S. business. “To become a firm grid asset, you have to develop this kind of mechanism. Otherwise, you have tens of thousands of batteries doing nothing, sitting in backup-power mode.”
Sonnen has been operating these kinds of residential solar-battery virtual power plants in Germany since 2015, and it has structured similar arrangements in Utah with utility Rocky Mountain Power and in California for some apartment complexes.
SonnenConnect’s value proposition for homeowners and the grid at large is only partly defined at present, Richetta said. The most obvious value will come from balancing a home’s load shape against time-of-use rates and electrification rates, which is a relatively simple matter of scheduling when batteries charge up and discharge against known daily cycles.
But those daily schedules can change unexpectedly, he said. One major example of that is when California’s grid is on the verge of collapse, as happened in the summer of 2020 and again in September of this year, when grid operator CAISO had to institute emergency measures to reduce electricity consumption to prevent heat-wave-driven electricity demand from outstripping available supply.
During these emergencies, stored battery power is far more valuable to the grid at the tail end of a 5–9 p.m. peak period, after the sun goes down, than at the beginning, when the grid hasn’t yet reached its highest point of stress, he noted. But battery systems that aren’t programmed with this fact in mind might start discharging power at 5 p.m., leaving them depleted later on when they’re really needed.
Companies including sonnen, Sunnova, Sunrun and Tesla are already signing up customers willing to let those companies actively control their batteries to manage these later-evening demand spikes. The avoided-cost rates for energy exports would offer more money for those key hours, which could make it worthwhile to save up as much energy as possible and inject it into the grid at those precise times, he said. That’s just one of a growing number of ways that centrally controlled and orchestrated solar-battery systems can boost their value for their owners and the grid, Richetta said.
There’s clear value in a future of rooftop-solar-and-battery systems that can deliver that power when the grid needs it most, he said. That value shows up in modeling that indicates that the right combination of distributed solar-plus-storage systems can reduce the costs of getting to a 100 percent carbon-free grid by tens of billions or even hundreds of billions of dollars, compared to relying solely on utility-scale clean energy and batteries and high-voltage transmission grids.
“If there are aggregations of future solar-plus-storage systems across the state, the system should be able to find value from them during peak times,” Sunrun’s Wright said — “and they should be able to compete on the market for the value they provide the grid.”
How can solar-battery systems compete for that value? That will be the subject of part two in our three-part series on California’s post-net-metering future.
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