California regulators cut incentives for rooftop solar even further

The California Public Utilities Commission has insisted that its decision last year to slash the compensation that households can receive from rooftop solar systems comes with a silver lining — a financial incentive for households to add batteries to their solar systems.

The CPUC has also stressed that this policy can help supply the state with far more batteries that can store excess solar power generated at midday and then discharge it after the sun goes down, when the grid faces severe shortfalls in electricity supply.

But on Thursday, the CPUC approved changes to the state’s current rooftop solar regime, proposed by two of the state’s biggest utilities, that solar groups say will undercut that policy imperative by preventing owners of solar-plus-battery systems from getting paid the full value for the grid assistance they can provide.

For an industry that’s laying off thousands of employees in the face of steep dropoffs in customer demand for rooftop solar, the CPUC’s latest decision adds insult to injury, said Brad Heavner, policy director for the California Solar and Storage Association trade group.

“This is a bait-and-switch, through and through,” he said. Since the CPUC’s new rooftop solar compensation regime went into effect in mid-April, solar installers have been promising customers that the extra costs of adding a battery to a new rooftop solar installation will pay off under the new net-billing system, he said.

“And now they’re saying, ​“No, we were just kidding. We’re not really going to let you do that.’”

Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association trade group, echoed those concerns in a Friday press release. ​“This change extends the payback period for solar and storage customers far beyond what the CPUC used to justify the new net billing structure, and it weakens the grid by disincentivizing energy storage additions,” she said.

The change won’t entirely eliminate the value of solar-plus-battery systems. But analysis from Tom Beach, principal consultant at Crossborder Energy and a consultant to the Solar Energy Industries Association, estimates that it will reduce solar-battery system owners’ compensation value by 10 to 15 percent, or about $230 per year, compared to what they could have expected to earn before the CPUC made this change.

That’s not a huge amount, compared to the average $2,000 per year in compensation that a typical solar-battery system owner could expect after last April’s rule changes from reducing their purchases of utility power and exporting power to the grid. But in the tight economics of today’s California solar market, every dollar adds up.

The CPUC’s new rooftop solar compensation structure has already lengthened the ​“payback” period for a solar installation — the time it takes for the system’s owner to earn back its costs — from an average of four to seven years before the rule change to nine years or longer under the new regime. Now, ​“if you’re losing 10 to 15 percent of your bill savings, your payback will be 10 to 15 percent longer,” Beach said.

Getting into the guts of a complicated solar-storage controversy

The CPUC’s decision rests on a highly technical distinction between different measurements of the value of energy that customers with solar-plus-battery systems can export back to the grid, and the complicated method that the CPUC adopted to calculate them.

Under the state’s former net-metering regime, customers earned the same retail rates they paid for electricity for any energy they exported to the grid — a structure that remains in place for existing net-metering customers.

Under the tariff changes approved by the CPUC for systems installed after April 2023, however, those exports earn only a fraction of that retail value during a majority of hours of the year — about 75 percent less on average.

But during key late afternoon and evening hours in summer and fall months, when the state’s grid faces its most severe supply shortfalls, those grid exports are worth much more. This is meant to reflect their value in helping the state avoid paying for expensive peak power or having to build expensive new generation resources to supply it.

In fact, exporting as much energy as possible between 4 to 9 p.m. during the months of August and September could potentially earn customers enough money to pay off the extra costs of installing a battery with a solar system within eight to nine years.

“The average across the year of those exports are horrible, but at least there are those few hours when we have batteries, and we can help the grid,” Heavner said. 

How much a utility customer earns for exported energy is set by the avoided-cost calculator, the CPUC’s complex set of metrics meant to determine the values to utilities and society at large of the power that a customer contributes to the grid. Those values include the cost of building and maintaining the transmission and distribution grids that carry power to customers, the value of the customer’s carbon-free energy in reducing greenhouse gas emissions, and other factors.

But by far the biggest share of value during those peak hours in August and September comes from helping utilities avoid having to build and buy power from the generation assets, like gas-fired ​“peaker” power plants and utility-scale solar farms paired with batteries, that are needed to supply power during those infrequent but critical moments when demand for electricity exceeds supply.

Those are known as ​“generation” costs, and during those important hours, they make up about 80 percent of the credits that customers can earn from pushing power back to the grid, Beach said.

But the typical California utility customer’s bill is structured in almost the opposite way. Only about a third of the per-kilowatt-hour charge that customers pay is made up of these ​“generation-related charges” tied to the cost of generating the power itself. The other two-thirds of their charges are paying for other things — primarily, the utility’s investments into their transmission and distribution grids, which are known as ​“delivery-related” charges.

In the past, that’s never been a problem, since net metering simply paid customers the same retail rate for exports. But the CPUC’s new net-billing tariff opened up a whole new realm of complications around how to measure and compensate customers for the power they export — and the CPUC didn’t finalize how it would value those exports when it approved its broader net-metering change last December.

Instead, that rulemaking process has been playing out over the course of 2023 — and that opened the door for the state’s three big investor-owned utilities, which serve most of the state’s residents, to propose alterations to how those exports are valued, and how customers are compensated for them in once-yearly billing statements known as ​“true-up” bills.

Specifically, utilities Pacific Gas & Electric and San Diego Gas & Electric asked the CPUC to draw a distinction between generation-related charges and delivery-related charges in these true-up bills. Instead of bundling both of them together, they asked the CPUC to ​“limit delivery-related retail export compensation credits to offsetting delivery-related charges and to limit generation-related credits to offsetting generation-related charges.”

But that creates a huge gap for solar-plus-battery-equipped customers, Heavner said. Those customers need to earn the full avoided-cost value from discharging power back to the grid during those evening hours in August and September to make their investment pencil out financially — and most of the value of those credits is tied into the generation-related costs.

But only about one-third of their utility bill is tied to those generation-related costs — which means that they can only use the export credits they generate during those hours to offset that one-third of their monthly billing cost.

“You can see the problem,” Heavner said. ​“You get all these generation-related credits, but you don’t have that many generation-related costs on your bill.” Instead, those credits will accumulate as credits that show up on a customer’s annual true-up bill, but that they won’t be able to recover in the form of payments from the utility.

Credits for helping the grid that utility customers can’t recover

The CPUC’s decision on Thursday acknowledged that approving PG&E and SDG&E’s proposal ​“could result in the unintended consequence of slightly dampening the retail export compensation price signal during key hours when the grid is most strained and is emitting the most greenhouse gases.” But the CPUC approved the utilities’ proposal nonetheless — and as Heavner pointed out, it provided no evidence for its assertion that the change would only ​“slightly” dampen the financial incentive for customers with solar-battery systems to help the grid.

What’s worse, Beach said, is that the CPUC’s idea for giving customers a chance to recoup the credits they’ll now be barred from actually getting paid every year — allowing customers to carry forward those credits for recovery in future years — won’t actually end up delivering them the credits they’re unable to recover.

That’s because if customers keep operating their batteries in the way the CPUC wants them to — exporting power during those peak August and September afternoon and evening hours — they’ll never end up altering the mismatch between their utility bills and their export crediting that would allow them to reclaim the banked credits.

“So customers are going to get a statement from their utility every year that says, ​‘you’ve earned another $230 in credits that we’re not going to pay you,’” he said. ​“And the next year it will be $460, and then $690 — and then in 10 years, $2,300.”

In his view, that runs the risk of undermining the CPUC’s goal of using price signals to encourage battery-equipped solar customers to support the state’s power grid.

“If you operate your storage to discharge from 4 to 9 p.m. in August and September, and all of the sudden you find out they’re taking away all that money and not paying it to you, one response would be to say, ​‘I’m going to operate my storage system differently,’” he said. Instead, customers may decide, ​‘I’m not going to export power in the summer evenings when it’s most valuable — I’ll just offset my usage at other times of the day. I won’t make as much money, but at least it’s not going to be taken away from me.’”

Unfortunately, the CPUC’s decision may end up incentivizing customers to do just that, he said. ​“I don’t think the customer can completely mitigate this loss in bill savings by doing that. But they can partially mitigate it — and it’s worse for the system.”

The simpler road not taken 

What Beach and Heavner find most maddening about this CPUC decision is that it would have been so simple to fix the problem it was trying to address.

PG&E and SDG&E said that this change was needed to avoid complicating the accounting of credits for generation-related versus delivery-related bill components. Specifically, they noted that utilities combine both of these costs to their customers on their bills, but that community choice aggregators (CCAs) — the public entities that have taken over the responsibility of procuring electricity for a growing number of utility customers across the state — do not.

That’s because CCAs don’t have the authority to mitigate the delivery-related costs on the bills that they send their customers, since CCAs are using the power grids that utilities own and maintain. Those grid-related costs are borne by the utility and are simply pass-throughs on CCA customers’ bills.

But there’s an easy solution to that problem, Beach said: Let the CCAs work it out. ​“The CCAs could provide these generation credits to net-billing customers. They could send the customers a check every year. Or they could send the check to PG&E.”

As for those customers who aren’t part of a CCA, the course for utilities is simple, Beach said. ​“If you’re a PG&E customer, then PG&E just offsets the generation credits against the delivery charges — it’s just an accounting thing on their books.”

Heavner dismissed the arguments from PG&E and SDG&E that the CPUC lacks the authority to order CCAs to manage their billing structures this way, and that CCAs would be likely to avoid paying customers for the share of their generation-related credits that they earn from feeding power back to the grid when it’s most valuable.

“If you’re a CCA customer and you’re really helping with these high-value hours, you’ll have more credits than you’ll have charges on your bill,” he said. And the CCAs will ​“treat it like credits for everything else — they’ll send you a check.” But that’s no longer an option for CCAs under the rule change that the CPUC affirmed on Thursday.

Heavner did, however, highlight that both PG&E and SDG&E asserted in their arguments that if CCAs did end up not paying their customers the full share of credits they earned, customers with solar-plus-battery systems might end up choosing to opt out of being a CCA customer and return to the utility to gain the full measure of their credits — which, again, is no longer an option, since the CPUC’s decision will now restrict customers from earning credits whether or not they make that choice.

“PG&E is concerned that if the CCA doesn’t give you the credit that you’re owed, then it would be a better deal to go back to PG&E,” he said. ​“And PG&E doesn’t want solar customers.”