Countdown to 2020, part IV: How California is both boosting and undermining its solar + storage future
California has a vision for a widespread residential solar + storage market that would ultimately supplant PV-only systems in both effectiveness and return on investment and is currently assembling all of the pieces to bring it to life. Those pieces include:
- Revisions to Title 24 of the California Code of Regulations. In addition to the solar mandate, the new building standards include a credit for solar to be combined with on-site energy storage as an energy efficiency measure. In fact, speakers at the California Solar Power Expo at the Marriott Marquis San Diego Marina in April said they expect homebuilders to skip solar-only systems to comply with the Title 24 mandate and go straight to solar + storage systems. This makes sense given the pricing and design advantages in the new build sector we’ve already discussed earlier in this series, plus the very real need for home backup power in California (more on that later).
- The passing of SB 700. This bill reauthorized the state’s Self-Generation Incentive Program (SGIP), with the potential to provide $800 million in funding for storage and other emerging clean energy technologies.
- New time of use (TOU) rates. The large investor-owned utilities (IOUs) in the state — Pacific Gas & Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) — now have new rate schedules available that shift on-peak times from midday to evening (4 p.m. to 9 p.m.). This will hurt the economics of residential solar-only projects, but creates a stronger economic opportunity for pairing storage with solar. SDG&E started defaulting all customers to TOU rates in March, and SCE and PG&E are scheduled to default customers in October next year.
Combine all of that with lower cost, quality batteries and — voila! — residential solar + storage can actually pencil out with a shorter payback period than PV-only does today. No, really, it can. Energy Toolbase calculated just that possibility here in 2019 after SCE implemented its new TOU rate structure in March. Consider the following:
- SCE’s TOU-D-PRIME rate has a wide TOU price differential in both the winter and summer seasons (24 cents/kWh in the summer and 21 cents/kWh in the winter).
- The PRIME rate offers a wide price differential all seven days of the week, rather than only Monday through Friday, effectively offering a lucrative price signal all 365 days of the year.
- The TOU windows align perfectly for charging batteries from PV off-peak during the day and discharging them on-peak in the evening.
Adam Gerza, COO of Energy Toolbase, modeled a typical solar + storage project factoring in everything above versus a PV-only project under the same rate schedule for a typical homeowner in the SCE service territory. The result showed a PV-only payback of nine years. The PV + storage system showed a payback of eight and a half years.
There you have it: a vision realized. Seemed exciting. With all of the new TOU rate schedules moving from voluntary to mandatory next year, and with that SGIP funding extended for five more years, we were ready to blare the trumpets in part IV of our Countdown to 2020 that a new solar + storage age was dawning and all solar contractors should prepare to capitalize. But after assessing the current reality a bit more, I found good news and bad news. And the good news is I didn’t waste time on trumpet lessons.
Before you head into installment IV of our Countdown to 2020, here are the previous three installments if you need to catch up:
- Installment I: The role solar plays in California’s new building efficiency standards
- Installment II: Constructing a new solar pathway
- Installment III: Would you like solar with that?
The rate debate
The controversy of these TOU rates is certainly not news to California solar installers, who have been against these sweeping rate schedule changes since they surfaced because moving the peak effectively erodes the value of solar. The perception is the utilities wanted to do this for their own financial savings (there is certainly truth to that), but there are also grid management issues the state needs to stay ahead of, especially with its super aggressive renewable goals. So, a shift in price signals was inevitable and a shift in priorities likely necessary.
The California Solar Energy Industries Association understood this when it refocused and rebranded as the California Solar + Storage Association (CALSSA) last year. The organization now has the semi-impossible task of negotiating rate schedules that can keep the solar-only residential market vibrant while also incentivizing this transition to solar + storage.
“Our strategy the last few years has been to take a two-pronged approach in rate cases to make sure there are a set of rates that will enable solar-only to be financially viable,” says Scott Murtishaw, senior advisor, regulatory affairs at CALSSA.
He believes the solar-only residential market is still viable in the short-term, especially in SDG&E territory where rates are so high, but also knows it will not continue. TOU rates are going to become increasingly differentiated as more solar comes online and depresses the daytime wholesale rates increasingly toward zero or into negative pricing territory. The underlying economics are likely to be reflected more and more in the retail rate.
“And that’s getting harder,” Murtishaw says. “Over the next few years, those daytime, off-peak rates, for eight months of the year, are going to be increasingly declining, and like we’re seeing in SCE territory now, solar-only will be really tough. At the same time, we want a structure available on an opt-in basis that is highly differentiated between peak and off-peak rates with more differentiation in the winter than other rate schedules so that storage cycling is incentivized during the summer months at the very least, and some cases in the winter, but especially in the spring when the grid operator is already curtailing solar output to prevent overgeneration.”
These are all important long-term moves, but in the short-term, TOU arbitrage is still an ineffective use case on its own if the goal of a customer is a financial return with a reasonable payback period.
“On every residential rate schedule that we have modeled, adding energy storage to a solar project and operating the battery in TOU arbitrage mode erodes the economics of the project,” Gerza says. “In many cases adding storage weakens the financial return significantly.”
SGIP or SOL?
Gerza’s insight is why CALSSA has been so adamant about SGIP funding. It is a crucial incentive for getting solar + storage projects to pencil.
On a per project basis, an SGIP rebate, coupled with the 30 percent Investment Tax Credit (ITC), can cover up to 60 percent of the installed system cost. These incentives are the main factors in the eight-and-half-year payback that Energy Toolbase estimated.
The SGIP program was set to expire at the end of next year, but SB 700 passed with broad bipartisan support to reauthorize the $800 million program until 2026. During that time, CALSSA estimates SGIP funding will result in nearly 3 GW of energy storage systems, launching the market similar to how the state’s Million Solar Roofs Initiative sent residential solar soaring to its current status. Thus, when the rebate phases out in 2026, the storage market would be stabilized and stand on its own.
The only hurdle still remaining is the actual SGIP funding. Turns out, passing the bill to reauthorize SGIP funds only passed the ultimate funding decision to the California Public Utilities Commission. The CPUC can now reauthorize the full $800 million, it could fund a partial amount, or it could fund zero. The direction it’s leaning is unclear, and despite how crucial the reauthorization is for this new energy vision, the CPUC has concerns.
Why wouldn’t they re-up on SGIP funding? The commission is questioning how useful the most recent SGIP funding round has been. The residential allotment is mostly gone and has been for quite a while, but the commercial portion, which is 85 percent of the money, has stalled out. PG&E, for example, is only on Step 2 of 5 at this point. None of the IOUs are in Step 4.
“Our concern is that the commission could look at these budgets, with the non-residential being 85 percent of the total budget, and say ‘well you’re not spending the money you have so why should we authorize more?’” Murtishaw says.
That’s a good question, especially for C&I solar + storage projects, which have a much stronger price signal than residential storage. What gives? Murtishaw believes a big reason is self-inflicted at the commission level. There were changes in commercial rates under negotiation at PG&E and SCE during last year. Those new pro storage rates came out in August 2018 and October 2018 respectively, but most of them haven’t been implemented yet. Murtishaw’s argument is the market hasn’t had time to respond. Further, the commission has delayed issuing a decision concerning greenhouse gas reductions, the result of which is tied to these incentives. An initial staff proposal was unfavorable for storage, with “extreme clawbacks from systems installed before new rules were adopted.” That was nixed. Commissioner Cliff Rechtschaffen issued a proposed decision on May 31, and while it still contains elements that CALSSA opposes, it rejects most of the particularly onerous aspects of the staff proposal.
“We’re hoping the commission finalizes the decision soon to provide that clarity because in the interim it is scaring off some would-be customers,” Murtishaw says.
Another factor is the continuation of the demand response auction mechanism. Traditional demand response companies are showing more interest in using storage to provide that demand response to customers, and the program was set to expire this year, causing more uncertainty. The CPUC has issued a proposed decision to extend it for another four years.
“We hope in the next two to three years we overcome some of these artificial barriers preventing storage from providing more value to the grid and generating more revenue as a result,” Murtishaw says.
Bottom line from CALSSA’s POV is it’s difficult to assess the merits of a program that wasn’t able to function properly, especially given how crucial it is for bridging the gap to California’s new energy future.
“Over the next few years, there’s probably no customer-sited storage market without SGIP,” Murtishaw says. “The costs are too high relative to the revenue streams available, so SGIP is going to be essential in the near term.”
If SGIP doesn’t get funded, then not only does this solar + storage future take a hit, but PV-only will remain stuck under the new “storage-friendly” TOU rates. The final decision on SGIP funding likely won’t emerge until the end of the year.
The useful case
To put a bow on this, we chatted with Jenise Granvold, partner and director of sales operations and policy for SolarCraft, an employee-owned solar installation company. SolarCraft has been around for 35 years, getting its start in solar thermal, eventually expanding into residential PV, small commercial and now storage.
SolarCraft is installing a slow but steady stream of residential storage systems by just having the option and presenting it to customers. I was curious how they were making deals happen. Was it SGIP?
“We have decided not to apply for SGIP funding,” she says. “We give clients information to do so, but we haven’t had any of our clients get it yet. It’s an ornery process to get the funds. Tons of paperwork, the way the structure is set up is extremely rigid.”
This anecdote illustrates another problem with the SGIP rebate system to this point. As mentioned earlier, most of the residential funds in the current funding round are gone and have been gone. The vast majority of these funds were claimed by large national solar and storage companies that were more well equipped to handle the headaches and provide the rebate to solid leads.
OK, no SGIP for SolarCraft. Maybe it’s the new rate structure? As luck would have it, they are in PG&E territory, which, according to Energy Toolbase, has the most lucrative rate schedule among the IOUs in terms of storage payback right now: EV (A). This is an experimental EV rate with a wide TOU price differential year-round (seven days a week), with a 35 cents per kWh price delta in the summer and 21 cents per kWh in the winter.
So, is that getting the market going?
“Frankly, there is no ROI,” she says. “These take 20 years to pencil out. … When we did the math on the EV rate structure, it would save about $1.50 per day.”
And this is the lucrative rate schedule (which is going to be replaced by a simpler, but similar rate called EV2).
So, what then?
No matter what regulators decide or how the market reacts, SolarCraft serves affluent customers in a more rural area in PG&E territory, which is now shutting off power lines when there is a reasonable threat of a wildfire outbreak. Risks include low humidity levels, sustained winds of moderate speeds or gusts of high-speed winds, with some areas marked as higher-threat areas than others. PG&E spokeswoman Andrea Menniti warns PG&E customers to prepare for periods of sustained power loss during times when the threat of fires is high and that customers can expect to lose power a few times per year.
“There’s a lot of value to it, which is why we’re seeing people pull the trigger already,” she says. “We anticipate it will happen more, once the price comes down, given the lack of reliable energy out here. We were all so used to it and spoiled by it, but now in our market because of the PG&E fires and bankruptcy, we’ve deployed many more battery systems than we’ve expected, and a lot of them are the [expensive batteries], which we didn’t expect either. But if you’re a rural property and your energy goes down, you also don’t have water and septic.”
We started this article and Countdown to 2020 series with the same hope and bold vision that California has, but the status quo and competing interests curbed our enthusiasm. In our next installment, we will explore these complications as well as the potential opportunities that lay ahead for California’s DER-heavy grid.