Across California, the companies that are trying to build charging stations for electric trucks are being told that it will take years — or even up to a decade — for them to get the electricity they need. That’s because utilities are failing to build out the grid fast enough to meet that demand.

This poses a major problem for a state that’s aiming to clean up its trucking industry. California has the most aggressive set of truck electrification goals in the country, and compliance deadlines are coming up fast.

State legislators did pass two laws last year — SB 410 and AB 50 — ordering regulators to find ways to speed up the process of getting utility customers the grid power they need, and last week the California Public Utilities Commission issued a decision meant to set timeframes for this work.

But charging companies, electric truck manufacturers, and environmental advocates are not happy with the result. They say the decision does next to nothing to get utilities to move faster or work harder to serve the massive charging hubs being planned across the state.

“It’s shocking how little the commission did here. They basically adopted status quo timelines across the board,” said Sky Stanfield, an attorney working with the Interstate Renewable Energy Council, a nonprofit clean energy advocacy group.

California’s struggle to deal with this issue is raising doubts about not only whether the state can meet its own climate goals but also whether truck electrification targets are achievable at all. States in the U.S. Northeast and Pacific Northwest with transportation-electrification targets will also need to build megawatt-scale charging along highways. Those projects will likewise require grid capacity upgrades that take a much longer time to plan and build than charging sites for passenger vehicles.

Stanfield and IREC believe that the CPUC’s decision both is inadequate and runs counter to clear instruction from California law. SB 410 orders the CPUC to craft regulations that ​“improve the speed at which energization and service upgrades are performed” and push the state’s big utilities to upgrade their grids ​“in time to achieve the state’s decarbonization goals.”

But the state’s electric truck targets simply won’t be met if charging stations aren’t built more rapidly, Stanfield said. ​“No one’s going to buy a fancy EV truck that costs well over $100,000 if they can’t charge it.”

IREC isn’t alone in this perspective. Powering America’s Commercial Transportation, a consortium of major EV charging and manufacturing companies, wrote in its comments to the CPUC that the decision ​“does not comply with either the requirements or legislative intent” of the law.

PACT asked the CPUC to set a two-year maximum timeline for utilities to build new substations and complete the more complex grid upgrades required by large EV charging depots.

But instead, the CPUC simply had Pacific Gas and Electric, Southern California Edison , and San Diego Gas & Electric report how long these major ​“upstream capacity” grid projects are taking today and then used the lower average of that historical data to set maximum timelines that utilities should meet in the future.

Those timelines are much, much too long, electric truck manufacturers, charging-project developers, and clean transportation advocates say. They stretch from nearly two years for upgrading distribution circuits and nearly three years for upgrading substations to nearly nine years for building the new substations that utilities say they’ll need to power truck-charging depots currently being built. 

“We’ve put in millions of dollars in the facilities we’ve already upgraded, and more that are in motion,” said Paul Rosa, a PACT board member.

As senior vice president of procurement and fleet planning at truck leasing company Penske, he is responsible for the company’s transport projects, including truck-charging projects in Southern and Central California.

But those projects represent just a fraction of the 114,500 chargers required to support the 157,000 medium- and heavy-duty vehicles that the California Energy Commission forecasts the state will need by 2030. 

“If we can’t get the power, this all comes to a screeching halt,” Rosa said.

The big problem with the grid and trucks

The slow and burdensome process of getting new customers connected to the grid — ​“energization” in CPUC parlance — isn’t a problem for just EV trucks.

PG&E has been under fire for years for failing to deliver timely grid hookups to everyday commercial and residential projects — a result, critics say, of poor planning and resource management.

The CPUC’s new decision does set a 125-business-day maximum timeline for these less complicated energizations. If those targets are met by utilities, ​“maximum timelines for grid connections could be reduced up to 49 percent compared to current operations,” the CPUC noted in a fact sheet accompanying the decision.

“I think the commission got it right” on these less complicated energization targets, said Tom Ashley, vice president of government and utility relations at Voltera, a company building EV charging projects across the state.

But how the commission handled the larger-scale grid upgrades — the kind needed to get EV truck-charging stations up and running — is a different story, he said. ​“That is where the industry is really frustrated that we didn’t get the help, and the utilities didn’t get the direction.”

The state’s Advanced Clean Trucks rule requires truck manufacturers to hit minimum targets for zero-emissions trucks as a percentage of total sales over the coming years, ratcheting from 30% of all medium- and heavy-duty vehicles by 2028 to 50% by 2030.

And California’s Advanced Clean Fleets rule requires the state’s biggest trucking and freight companies to convert hundreds of thousands of diesel trucks to zero-emissions models over the next 12 years, with earlier targets for certain classes of vehicles, including the heavy trucks carrying cargo containers from California’s busy and polluted ports.

Right now, many of the plans to build charging hubs for those trucks are stuck in grid-upgrade limbo — and the CPUC decision offers little indication it will get them unstuck.

“We’ve submitted for well over 50 projects in the past two years, looking for the right property to acquire,” said Jason Berry, director of energy and utilities at Terawatt Infrastructure. The startup has more than $1 billion in equity and project finance lined up to build large-scale charging hubs, including a network that will stretch from California to Texas along the I-10 highway, a major trucking corridor.

But of the sites Terawatt has scouted in California, ​“about 95% of those do not have the power we’re trying to request,” Berry said. To serve proposed charging hubs in California’s Inland Empire, utility SCE has said that it will need to expand existing substations, which takes four to five years, or build a new substation, which takes at least eight years, Terawatt said in May comments to the CPUC.

Terawatt is far from the only company facing delays. In testimony to the CPUC, Berry pointed out that Tesla has told the agency that 12 Supercharger sites with 522 charging stalls are facing delays because of capacity issues in SCE territory. A state-funded electric truck-charging project in the Inland Empire is also held up due to similar constraints.

The main problem is that large-scale charging sites can be built much faster than utilities are used to moving, Berry said. ​“We’re building projects, maybe ideally starting at 10 megawatts and then going to 20 megawatts,” Berry said. That’s about the same load on the grid as would be caused by an entirely new residential neighborhood or big commercial or industrial site.

But while those sites typically take years to plan and build, a new truck-charging site can go from planning to completion in less than a year.

“They have to have a mechanism to start on those things, or every single project is going to be four to five years out — which is what we’re being told on so many of these today,” he said.

The same point was made by Diego Quevedo, utilities lead and senior charging-infrastructure engineer at Daimler Truck North America, which joined fellow electric truck manufacturers Volvo Group North America and Navistar to weigh in on the CPUC proceeding.

“Trucks can be manufactured by OEMs and delivered approximately six months after receiving an order,” Quevedo said in testimony before the CPUC. But fleets won’t order trucks if they lack the confidence the utility grid infrastructure will be built and energized when the trucks are delivered.”

Utilities’ grid-capacity additions are taking from seven to 10 years to ​“plan, design, budget, construct, and energize,” he said. Unless those capacity expansions can be sped up significantly, ​“electric trucks become expensive stranded assets that are unable to charge,” he said.

Why it’s so hard to speed up expensive grid upgrades 

California’s major utilities have a different perspective. They’ve argued in comments to the CPUC that it may be difficult or impossible to move more quickly on such complicated work.

First, as utilities have pointed out, many of the things that can slow down major grid projects are beyond their control. In a filing with the CPUC, PG&E noted that ​“one capacity upgrade project may face an extended timeline due to lengthy environmental assessments and permitting processes, and another may encounter challenges in acquiring materials in a timely manner due to manufacturer issues.”

IREC’s Stanfield conceded that equipment backlogs and environmental and permitting reviews are barriers to moving more quickly. ​“But we have to make it go faster if we want to hit our climate goals, if we want manufacturers to build clean trucks.”

And there’s an even bigger challenge to making major changes to the grid in anticipation of booming demand from EV charging: the cost involved. 

“Lack of funding is the big block to meet the anticipated load growth,” Terawatt’s Berry said.

California’s utilities are already spending more than they ever have on their power grids, for myriad reasons. They are passing the costs of grid-hardening investments and integrating new clean energy into the power system on to customers in the form of electricity rates that are now the highest in the continental U.S.

Electricity rate increases are an economic and political crisis in California. Keeping them from rising any further has become the chief focus of lawmakers and regulators in the past several years. Any proposals that could raise customer bills even more face a tough battle — including plans to build grid infrastructure for electric truck-charging hubs.

SB 410 does give the CPUC permission to allow utilities to increase their spending in order to meet tighter EV-charger energization timelines. But the bill also calls on regulators to subject these requests to​“extremely strict accounting.”

PG&E was the first utility to submit a ratemaking mechanism under SB 410 earlier this year. The Utility Reform Network, a ratepayer advocacy group, quickly filed comments protesting the utility’s plan to create a ​“balancing account” that would enable it to recover as much as $4 billion in additional energization-related spending from customers — a structure that falls outside the standard three-year ​“rate case” process for California utilities.

“PG&E’s electric rates and bills are now so high that they threaten both access to the essential energy services that PG&E provides and the achievement of the state’s decarbonization goals, which rely in part on customers choosing to electrify buildings and vehicles,” TURN wrote in its comments.

TURN wants the CPUC to limit the scope of SB 410’s extra cost-recovery provisions to ​“specific work needed to complete an individual customer connection request,” rather than the kind of proactive upstream grid investments that truck-charging advocates are calling for. TURN would prefer that those projects remain part of general rate cases, the sprawling proceedings that determine how much utilities spend on their grids.

But those general rate cases can take up to five years to move from identifying the broader, systemwide analyses of how much electricity demand is set to rise to winning regulatory approval in order to build the expensive grid infrastructure needed to actually meet those growing needs. That’s too long to wait to fix the problem, charging advocates say.

At the same time, ratepayer advocates are challenging utility efforts to expand the scope of their larger-scale plans to meet looming EV charging needs. In SCE’s current general rate case, TURN and the CPUC’s Public Advocates Office, which is tasked with protecting consumers, are protesting that the utility is overestimating how much money it needs to spend to prepare its grid from growing EV-charging needs.

Terawatt and other charging developers and electric truck manufacturers argue just the opposite — that the utility isn’t planning to spend enough over the next three years. In his testimony in the rate case, Terawatt’s Berry complained that TURN and PAO are challenging utility and state forecasts of future charging needs based on outdated data, and that failing to approve the utility’s funding request will ​“ensure that California fails to achieve its zero-emission vehicle goals.”

Charging advocates have also asked the CPUC to create a separate regulatory process to consider the grid buildout needs spurred by large-scale charging projects. But the CPUC rejected that concept in its decision last week, stating that ​“preferential treatment based on project type is prohibited by California law.”

Finding a way to plan the grid ahead of big charging needs

All these conflicting imperatives leave the CPUC with tough choices to resolve the gap between charging needs and grid buildout plans, said Cole Jermyn, an attorney at the Environmental Defense Fund.

The CPUC ​“can and should do more here. I don’t think the timelines they set here are as strong as they could have been,” Jermyn said. 

At the same time, ​“the commission had an incredibly difficult job here. The targets are not easy to set, and they had a very short timeline to do it.” 

That’s why multiple groups have asked the CPUC to focus its next phase of work on implementing SB 410 and AB 50 on a key issue: aligning grid planning and EV charging needs.

“Part of the work here is figuring out what that proactive planning looks like,” Jermyn said. ​“The utility cannot wait around for customers to come to them and say, ​‘We need 5 megawatts of capacity.’ They need to be looking out into the future to start proactively preparing their distribution grids for all this electrification.”

At the same time, ​“how do you balance that need for proactive planning and investment with ratepayer investments along the way to make sure this isn’t building assets that won’t be used and end up on someone’s bills?” Jermyn asked. That will be complicated, but, he added, ​“I think it’s doable — especially for a state that has such clear goals.”

SB 410 also specifically called on the CPUC to take California’s decarbonization goals into account in tackling energization delays — but last week’s decision ​“was relatively silent on that issue,” Jermyn said.

“This is something we think is incredibly important to be in the next phase of this proceeding, because it wasn’t in this one,” he said. ​“We don’t know if the timelines they set are meeting that goal or not. We should figure out if they are.”

EDF has advocated for years for utilities and regulators to approve grid spending in advance of EV charging needs, noting that such spending will end up reducing costs for utility customers in the long run.

That’s because California’s utilities don’t earn profits directly through electricity sales. Instead, their rates are structured to repay their costs of doing business. More customers buying more electricity can spread out the costs of collecting the money that utilities need to operate and invest in infrastructure, which can reduce the rates per kilowatt-hour that utilities must collect in future years.

This isn’t just a California issue. Nearly a dozen states — including Massachusetts, New Jersey, New York, Oregon, Vermont, and Washington — have adopted advanced clean truck rules. They’re not as aggressive as California’s rules, but meeting them will still require grappling with the same challenges around proactive grid planning.

Voltera’s Ashley worried that the CPUC’s decision may set a bad precedent for other state regulators on this front. ​“The commission has a really hard job. They’re tasked with a lot of complicated policy and execution,” he said. ​“And at the end of the day, they have some overarching mandates, including affordability for ratepayers,” that complicate the task.

But California also has ​“the most aggressive targets, goals, and statutory requirements around not just electrification of transportation but electrification of other segments” of the economy, he said. ​“If California doesn’t get this right, who will?”

California’s backlogged grid is holding up its electric truck dreams is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

California policymakers are searching for ways to rein in the cost of expanding the state’s power grid, which is necessary to combat climate change. Experts warn they’re missing an opportunity that’s right in front of them — taking advantage of the growing number of clean energy technologies owned by utility customers.

California ended its legislative session last month unable to pass a proposed legislative package to address rising electricity rates for customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, which serve about three-quarters of the state’s residents.

Lawmakers also failed to pass several bills aimed at boosting the role battery-backed rooftop solar systems, electric vehicles, and electric heat pumps and water heaters can play in balancing the power that’s available on the grid.

Replacing fossil-fueled vehicles with EVs, and gas heating systems with heat pumps, will increase statewide electricity demand, requiring utilities to invest billions of dollars to upgrade their grids. But those same technologies can shift when they use power to avoid the handful of hours per year when demand spikes. That’s important, because the cost of building power grids is largely determined by the size of those spikes — and in turn is a core driver of California’s energy affordability crisis.

If the state can use distributed energy resources to shave a bit of demand from grid peaks, it stands to save big. One example: In an April report, consultancy Brattle Group projected that virtual power plants, which can shift when EVs and electric appliances draw from the grid or tap into customer solar and battery systems, could provide more than 15 percent of the state’s peak grid demand by 2035. That would amount to around $550 million per year in consumer savings. 

About $500 million of that would flow directly to the customers who own the devices, which could help defray the cost of buying EVs and heat pumps, two technologies that need to be rapidly adopted to meet climate goals. But because tapping into those devices would cost less than making large-scale investments, utilities — and by extension all of their customers — would save about $50 million per year by 2035, Brattle found.

“California’s affordability challenges are years in the making and are worsened by climate-driven impacts like heat waves and wildfires,” said Edson Perez, who leads trade group Advanced Energy United’s legislative and political engagement in California. ​“However, there are critical steps we can take now: optimizing our existing grid, maximizing the cost-effectiveness of essential grid upgrades, and fully leveraging available technologies like distributed energy resources.”

But as it stands, California isn’t putting the full weight of policy support behind these types of distributed energy programs.

Pilot programs have petered out, seen their budgets clawed back, or have been outright canceled. The scale of demand-side resources operating in the state has actually declined over the past decade, even as the state’s grid stresses have increased. And efforts to create statewide targets for distributed energy — like those that helped spur California’s rooftop-solar and home-battery leadership — have failed to gain traction, including a proposed bill in the state’s just-concluded legislative session.

Advocates say it’s time for the state to change that — especially since there’s an expiration date for capturing the value of DERs. Without policies to encourage utilities and customers to work together to realize the grid benefits of these technologies, utilities will simply build expensive, centralized infrastructure to meet rising electricity demand. Once that money is spent, potential savings can’t be realized, undermining the economic case for VPPs.

Unfortunately, utilities have clear incentives to discount the potential of VPPs as a money-saving tool, because they earn guaranteed rates of profit on capital investments like grid buildouts, but don’t for alternatives like VPPs. Plus, they’re held responsible for failing to keep pace with growing power demand — and are loath to rely on decentralized assets owned by customers in place of tried-and-true grid investments.

California’s VPP policy landscape

This utility reluctance may well explain why a roster of bills aimed at enlisting DERs to combat rising grid costs stalled in this year’s regular legislative session.

SB 1305 proposed requiring the California Public Utilities Commission to determine targets for utilities to ​“procure generation from cost-effective virtual power plants,” and then mandate that the utilities meet them.

Similar targets for rooftop solar and batteries have been valuable for boosting early-stage deployments in California, said Cliff Staton, head of government affairs and community relations at Renew Home, the company formed by the merger of Google Nest’s smart-thermostat energy-shifting service Nest Renew and California-based residential demand-response aggregator Ohmconnect.

“If you set the targets, you begin to provide the certainty to the industry that if you invest, there will be a return for your investment over time,” Staton said.

An early version of SB 1305 set hard percentage targets for VPP procurements by 2028 and by 2035. Those percentages were stripped from the bill later in the session, leaving the final targets up to CPUC discretion. The bill failed to clear a key legislative committee anyway.

Another bill that died in committee, AB 2891, would have expanded options for VPPs to capture the value of the peak load reductions they can provide. The legislation would have ordered the California Energy Commission to create methods for VPPs to reduce how much generation capacity each utility in the state must secure to meet peak grid demands in future years.

Only a handful of California’s community choice aggregators — the public entities that supply power to an increasing number of customers of the state’s major utilities — are using this approach today. But those CCAs have been able to start paying customers with solar and batteries for the value they can provide by reducing reliance on increasingly expensive contracts with centralized grid resources — mostly fossil-gas-fired power plants.

For more than a decade, state laws have called on the CPUC to create programs that reward customers for the energy and grid values provided by their solar panels, backup batteries, electric vehicles, and remote-controllable devices like smart thermostats and water heaters.

But these efforts have been plagued by an on-again, off-again approach from regulators and utilities. The California Energy Commission set a goal in 2023 of achieving 7 gigawatts of load flexibility from VPPs and other customer-owned resources by 2030; two of the CEC’s key contributions to that effort saw their budgets slashed this year.

Meanwhile, many of the programs launched by the CPUC over the past decade have stalled out due to overly complicated structures, or had their budgets reduced or canceled due to concerns over their cost-effectiveness.

The CPUC and the California Independent System Operator (CAISO), the entity responsible for managing California’s transmission grid and energy markets, argue that these programs have failed to perform as promised. Relying on them more would run the risk of eroding rather than improving grid reliability, they say.

But the companies engaging in these VPP programs — smart-thermostat providers like Renew Home and ecobee; solar and battery installers like sonnen, Sunrun, Sunnova, and Tesla; and demand-response providers like AutoGrid, CPower, Enel X, and Voltus — argue that overly complex and restrictive rules and compensation structures are to blame.

Adding to these challenges for would-be VPP providers is the declining value of rooftop solar. Major changes in California’s net-metering policies over the past two years have slashed the value of customer-owned solar systems, slowing the growth of the state’s leading rooftop solar market.

That’s a problem for VPP providers and advocates who see rooftop solar as an important way to help meet demand from households and businesses with EVs and heat pumps — and to charge up batteries with clean electricity that VPP programs can tap into later.

A host of bills were proposed to reset state policy to restore more value to customer-owned solar during this year’s legislative session. But only one — SB 1374, which restores compensation for schools that install solar — made it through.

California’s new rooftop solar regime does reward customers for adding batteries to store surplus solar power during the day and discharge it in evenings, when the grid faces its greatest and most costly stresses.

But solar and battery advocacy groups argue that those rewards haven’t counterbalanced the broader erosion of rooftop solar values — and that the VPP opportunities that have emerged in the state can’t yet be trusted to make up the remaining difference.

“It’s important for customers to find value in the investment they’ve made, and to help the grid and lower cost for all consumers,” said Meghan Nutting, executive vice president of government and regulatory affairs at Sunnova. ​“One of the problems with VPP programs so far is that it’s really tough to talk about that value proposition up front because programs are so short, you can’t count on them, or the funding isn’t there.”

Why grid costs and VPPs are intertwined 

At the same time, California policies that encourage people to buy other distributed energy resources — namely EVs and heat pumps — are under threat from rising electricity rates, which are eroding the benefits of switching from fossil fuels.

A controversial policy enacted this year to reduce the per-kilowatt-hour rates paid by customers of the state’s big three utilities in exchange for higher fixed costs may or may not ease that pressure. But both opponents and supporters of the policy agree that shifting the balance of fixed and variable electricity costs does little to address the underlying problems.

Programs that enlist those exact same distributed energy resources to ease grid stresses have a much clearer value proposition, on the other hand.

About half of the electricity bills of customers of California’s three big utilities is made up of fixed costs like grid investments. A majority of those investments are tied to building a grid robust enough to supply power not just for average needs, but during the few hours per year when electricity use peaks.

Those peaks are getting bigger as California’s climate goals encourage more EVs and heat pumps to come online, and the costs of dealing with that have only just begun to be built into utilities’ broader grid investment plans. A series of studies ordered by the CPUC found that adding demand from EVs and heat pumps to the grid could increase ratepayer costs by more than $50 billion by 2035 — or, depending on the approach taken, costs could be contained to less than half of that over the same timespan.

One key variable in those distinct cost forecasts is whether EVs can be programmed or incentivized to avoid charging all at once and overwhelming the grid. ​“Smart charging” programs that encourage EV owners to shift when they charge their cars could save California ratepayers tens of billions of dollars over the coming decade.

With the right policies and technologies in place, big new grid demands like EVs could actually become valuable resources for energy in their own right. SB 59, a bill that passed in this year’s legislative session after failing to make it last year, orders state agencies to study the proper role for regulation that could require automakers to enable their EVs to support ​“vehicle-to-grid” charging — sending power from EV batteries back to homes, buildings, or the grid at large.

The challenge for utilities and regulators is finding the right mix of approaches that can allow them to take advantage of EVs, heat pumps, residential solar and batteries, and other distributed resources such that they avoid either overbuilding or underbuilding the grid, said Merrian Borgeson, policy director for California climate and energy at the environmental nonprofit Natural Resources Defense Council.

“We have to be really careful with any new investment — but we do need to make new investments,” she said. ​“If we pull back too far on energizing loads like electric homes or EV trucks, we miss out on getting those loads connected.” 

California could cut utility bills with distributed energy. Why isn’t it? is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

A bill introduced in the California legislature proposes to slash hundreds of millions of dollars from programs that help schools replace worn-out HVAC systems, low-income households install batteries, and affordable housing projects deploy solar panels — all for what would amount to a one-time rebate of no more than $50 for customers of the state’s three major utilities.

Lawmakers and Governor Gavin Newsom’s office have crafted the legislation, which they are calling the ​“affordability project,” in response to fast-rising utility rates at the state’s three large investor-owned utilities: Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric.

But community groups, environmental advocates, and clean energy industry groups say the cuts will cause immediate and severe harms to those relying on them while doing next to nothing to fulfill their purported goal of reining in the state’s sky-high electricity rates.

“It’s not a way to solve the problem, and you’re hurting programs that are working,” said 

Merrian Borgeson, policy director for California climate and energy at the nonprofit environmental group Natural Resources Defense Council, told Canary Media in an interview.

AB 3121 emerged late Wednesday evening after weeks of backroom negotiations over how best to control rate increases for customers. But the reforms proposed by the bill do little to address the primary drivers of those increases, which come down to the investments utilities are making in their power grids to meet rapidly rising electricity demand, and also to harden them against the risk of sparking deadly wildfires.

Another bill introduced late Wednesday, SB 1003, would call on state agencies to increase oversight over utilities’ wildfire-mitigation spending, which could lead to cost reductions. And another bill, AB 3264, would require the California Public Utilities Commission (CPUC) to assess and analyze total annual energy costs for residential customers, with the goal of finding ways to shift some costs from ratepayers.

“California’s high electricity prices are a decade in the making,” Borgeson said in a Thursday statement. ​“We need an overhaul that targets the root causes of this surge: wildfire spending, capacity constraints, insufficient regulatory oversight, and the need for funding sources beyond consumer-paid utility rates to address the climate crisis. This policy proposal will move the needle on some of these challenges, but it also includes damaging cuts to important programs that benefit vulnerable communities.”

NRDC has estimated that the cuts being proposed would yield only about a $50 one-time rebate for the average residential customer of the state’s three major investor-owned utilities. A report from Politico this week cited an unnamed California lawmaker who estimated the cuts would provide customers as little as $30 each in one-time rebates.

A Wednesday letter signed by NRDC and more than two dozen other groups warned Newsom, California Senate President Pro Tempore Mike McGuire, and Speaker of the Assembly Robert Rivas against cuts to ​“critical programs that advance energy affordability, reliability, and climate resilience for vulnerable communities.”

“Focusing on short-term tactics will not resolve California’s affordability crisis,” the groups wrote. ​“Instead, it will exacerbate it, making our energy system more expensive, polluted, and dangerous — especially for our most vulnerable communities.”

The pushback comes as lawmakers are scrambling to address unfinished business before this year’s legislative session ends at midnight on Saturday — including a June pledge from California Assembly Utilities and Energy Chair Cottie Petrie-Norris, sponsor of AB 3121, to cut the bills of customers of the state’s three big utilities by $10 per month. (Petrie-Norris’s office did not immediately respond to a request for comment on Thursday.)

The high cost of electricity has become a pressing problem for low-income Californians struggling to pay their utility bills, and is threatening to derail the state’s broader electrification efforts by dramatically increasing the costs to consumers of switching from fossil fuels to electricity to power their cars and provide household heating.

In the past 10 years, average electrical rates have risen by 110 percent for residential customers of PG&E, 90 percent for those served by Southern California Edison, and 82 percent for customers of SDG&E, according to data compiled by state regulators. The past three years alone have seen average residential rates jump by 51 percent for PG&E and SCE and 20 percent for SDG&E.

And more rate hikes are looming at PG&E, the state’s biggest utility, which serves about 16 million people in Northern and Central California. In November, the California Public Utilities Commission approved a rate case adding about $32.50 per month to customers’ bills, followed by a further rate hike in March of about $5 to $6 per month starting this spring.

In a July report, the CPUC forecasted average annual electric rate increases of 10.8 percent for PG&E, 6.8 percent for SCE, and 5.6 percent for SDG&E, compared with an assumed inflation rate of 2.6 percent.

This chart from the CPUC’s July report breaks out the proportion of the state’s three big utilities’ ​“revenue requirement,” or how much money they must bring in from ratepayers to cover their costs. The biggest increases are coming from distribution-grid investments, primarily driven by PG&E’s program aimed at burying power lines, clearing vegetation, and installing technology to reduce wildfire risks.

According to reporting from The Sacramento Bee citing anonymous sources familiar with the negotiations, earlier versions of the affordability package included proposals to reduce broader grid expansion costs via ​“securitization” — financing some portion of utility spending through debt, rather than by passing them on to ratepayers.

But those components, which could reduce the profits that utilities earn for investments in their capital infrastructure, were dropped from the bill, the Bee reported last week.

With the potential savings from the wildfire-mitigation cost controls and broader energy cost analysis as yet unclear, the only immediate savings from the legislative package would come from cuts to programs that serve ​“people who don’t have political power,” said Beckie Menten, senior regulatory and policy specialist at the nonprofit Building Decarbonization Coalition.

“We’re really supportive of solutions that address affordability,” she said. But ​“what we’re seeing on the table for the most part are pretty reactive and not very comprehensive of our systemic solutions.”

On the chopping block: School HVAC retrofits and solar and batteries for low-income residents 

AB 3121 proposes to provide utility customers with rebates by clawing back unspent and ​“unencumbered” funds from three programs: California Schools Healthy Air, Plumbing, and Efficiency (CalSHAPE); the Self-Generation Incentive Program (SGIP); and Solar on Multifamily Affordable Housing (SOMAH).

The CalSHAPE program, administered by the California Energy Commission, was created by a law passed during the Covid pandemic to help schools repair HVAC systems to improve health, and it has disbursed 646 grants totaling $421 million in funding for the ventilation upgrades.

Roughly $250 million remains in the program, and many schools were in the process of applying for funding, said Stephanie Seidmon, program director of nonprofit advocacy group Undaunted K12. But AB 3121 would retroactively set the deadline for those applications at July 1, 2024, and return any funds not disbursed to utility ratepayers.

But the one-time rebates per customer that would result aren’t worth the loss of funding for schools that need the money to improve air-conditioning and ventilation systems, Seidmon contended. ​“It’s really important for low-income schools that can’t raise a bond measure to upgrade their HVAC systems, or schools facing these wildfire and heat risks,” she said.

Much of CalSHAPE’s remaining $250 million in funding ​“is for schools that are replacing their HVAC as we’re going to be facing wildfires this fall,” said NRDC’s Bergeson. ​“It’s crazy to me we’d be taking away that money, especially when many of these schools are in disadvantaged communities and were depending on this.”

The SGIP program provides incentives for low-income customers to purchase batteries to provide backup power during power outages. In a March decision, the CPUC allocated $280 million to the program’s current grant cycle, and lawmakers pledged in a 2022 budget and climate law, AB 209, to provide $350 million to the program over the next several years.

Returning unspent portions of those funds to utilities would provide a minimal one-off rebate to individual customers at the cost of undermining a program that ​“helps both rural and disadvantaged communities” obtain batteries that are increasingly valuable in a state experiencing heat- and wildfire-driven grid emergencies, said Edson Perez, California policy lead for clean energy industry trade group Advanced Energy United.

The batteries installed through the program also help store solar power for use in evenings, when grid power tends to be dirtier and more expensive, which ​“helps the grid as a whole,” he said. A May report to the CPUC found that batteries installed through SGIP have reduced utility costs by roughly $27 million, primarily during a September 2022 heat wave that threatened to overwhelm California’s grid.

The SOMAH program has a budget of $100 million and a legislatively mandated goal of installing 300 megawatts of solar by 2032, and is ​“California’s landmark program for multifamily affordable housing access to affordable solar and affordable storage,” said Steve Campbell, western regulatory director for nonprofit Vote Solar.

AB 3121 doesn’t call for reclaiming the entirety of that funding stream. But it would require the CPUC to credit ​“no more than 1/2 of the program funds that are unencumbered as of January 1, 2025,” back to utilities to return to customers as rebates.

SOMAH was created in 2019 and saw a significant slowdown during the Covid pandemic, Campbell said. In the past year, however, applications and projects have picked up steam. 

“When a low-income program starts to work again is the worst time to pull the rug out from underneath it,” he said. 

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California has given America a glimpse at what running one of the world’s largest economies on renewable energy might look like.

The state recently hit a milestone: 100 days this year with 100% carbon-free, renewable electricity for at least a part of each day, as tracked by Stanford University engineering Professor Mark Z. Jacobson.

The state notched the milestone while — so far — avoiding blackouts and emergency power reductions this year, even with the hottest July on record.

That progress is largely due to the substantial public and private investments in renewable energy — particularly batteries storing solar power to use when the sun isn’t shining, according to energy experts.

“California has made unprecedented investments in our power grid in recent years — and we’re seeing them pay off in real time,” Gov. Gavin Newsom said in a statement to CalMatters. “Not only is our grid more reliable and resilient, it’s also increasingly running on 100% clean electricity.”

The state faces a huge challenge in coming years: A series of mandates will require carbon-free energy while also putting more electric cars on roads and electric appliances in homes. California, under state law, must run on 60% renewable energy by 2030, ramping up to 100% by 2045.

Signs of progress are emerging. From January to mid-July of this year, zero-carbon, renewable energy exceeded demand in California for 945 hours during 146 days — equivalent to a month-and-a-half of 100% fossil-fuel-free electricity, according to the California Energy Commission, the state agency tasked with carrying out the clean energy mandates.

But California still has a long way to go to stop burning fossil fuels for electricity. Natural gas, which emits greenhouse gases and air pollutants, remains its single largest source of electricity.

Just over half of power generated for Californians in 2022 came from solar, wind, other renewables and nuclear power, while 36% came from natural gas plants.

Reliability of the power grid is a top concern as the state switches to solar and wind energy. Unpredictable events like wildfires and winter storms also cause outages, while hot summer months, with air conditioners whirring, strain the supply.

In August of 2020 California experienced its first non-wildfire blackouts in nearly 20 years, and in late August and September of 2022, a severe heatwave forced regulators to ask consumers to voluntarily reduce power for 10 days.

Since September 2022 — when California teetered on the edge of those blackouts and the governor pleaded for conservation — nearly 11,600 new megawatts of clean energy have been added to the state’s grid, said Elliot Mainzer, chief executive of the California Independent System Operator, which manages the grid. (That’s enough to power around 9 to 12 million homes although it’s not available all at one time.)

California also now has more than 10,000 megawatts of battery capacity, making it the largest supply outside of China. Battery power from large commercial facilities proved its worth during last month’s heat wave, Mainzer said.

Batteries “were a major difference-maker,” Mainzer said. “The batteries charged during the day, when solar energy is abundant, and then they put that energy back onto the grid in the afternoon and evening, when solar production is rolling off the system.”

California relies heavily on four-hour duration lithium-ion batteries, which come in large, centralized facilities and hybrid facilities paired with solar energy projects. More homes also are installing batteries with their rooftop solar installations, but they supply a small amount of power.

Planning and practicing various emergency scenarios has also helped immensely, Mainzer said.

“Our grid operators are now increasingly experienced at managing these extreme heat events,” Mainzer said. “Our forecasters also did an excellent job of reviewing the next day’s conditions so that the market could respond effectively.”

‘The table is set’ for clean energy

California may need to more than double its energy generation capacity by 2045 to meet the 100% clean energy target while adding electric cars, appliances and other technologies, said Siva Gunda, who sits on the California Energy Commission. 

To do that, California aims to build about 6,000 to 8,000 megawatts of new energy resources each year. The state hit a record last year, adding more than 6,000 megawatts, Gunda said. Each megawatt is enough to serve between 750 and 1,000 homes. 

“The table is set,” Gunda said. “The pieces are there for success, and it’s about executing it, together with a common vision and collaboration.”

The commission is closely monitoring a new concern: Artificial intelligence technology, which uses large data centers that consume power. “We’re carefully watching where the loads are going to grow,” Gunda said.

Stanford’s Jacobson said running on 100% renewable energy is becoming more common.

Over the July 28 weekend, California marked the 100th nonconsecutive day within a 144-day stretch in which 100% of electricity came from renewable sources for periods ranging from five minutes to more than 10 hours, he said.

On April 8, a solar eclipse reduced solar power generation and increased demand on the grid, which was met by batteries. On May 5, wind, hydroelectric and solar energy reached more than 160% of demand for a significant portion of the day.

California continues to waffle about ending its reliance on natural gas and nuclear power.

Fearing emergency rolling blackouts like the one in 2020, Newsom and the Legislature in 2022 allowed some natural gas plants that were supposed to go offline to keep operating. 

And the Diablo Canyon nuclear power plant will continue operating while Pacific Gas & Electric pursues federal permission to stay open past 2025. Nuclear power is considered renewable and carbon-free but it creates radioactive waste.

State officials and private investors aim to create an entirely new industry — giant floating ocean wind platforms — to produce 13% of California’s power, enough to power 25 million homes, by 2045. The massive projects will cost billions of dollars. 

Some Democratic legislators are hoping to make it easier to build wind and solar projects, since sometimes local obstacles and permitting take years. They are negotiating an end-of-session package of proposed laws that could streamline construction, CalMatters reported earlier this month. California’s legislative session ends Aug. 31.

Jacobson said the cost of large-scale solar power projects has “dropped substantially” in recent decades largely because of “economies of scale — just the huge growth of solar on a worldwide scale.”

“There’s no miracle technology that was developed,” he said. “It’s just subtle improvements in existing technologies and deployment, deployment, deployment.”

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The need to prioritize the installation of heat pumps in California’s low-income households is clear.

California’s Fourth Climate Change Assessment devoted a separate report on the challenges for low-income residents in the San Joaquin Valley and the resulting health implications. Affordable air conditioning is likely at the top of the list of health needs for the vulnerable in the San Joaquin Valley, where weather regularly exceeds over 100 Fahrenheit in the summer and fall.

“Some residents living in these homes are disabled, need regular medical attention, and are unable to work,” a program implementer noted in a pilot report update on San Joaquin Valley, reporting on the conditions that program recipients had endured prior to the heat pump installations. “Ethically, these customers need HVAC systems to live comfortably and cannot be overlooked.”

Yet ensuring that these same communities benefit from rebate programs to encourage heat pump installations is more complex.

It turns out that for low-income residents, participation in a rebate program can require thousands of dollars of additional out-of-pocket costs, relative to richer households, because the homes tend to be older, the electricity is more likely to need upgrades, and there are often additional modifications or infrastructure improvements required — such as replacing water damaged flooring or walls from leaks — to provide the power. These costs, for additional wiring and other critical work, are typically either only partially or not covered by most rebate programs.

TECH Clean California, a statewide initiative to accelerate the adoption of clean space and water heating technology and put California on a path to carbon-free homes by 2045, has identified these additional costs as a key barrier to introducing heat pumps into lower-income homes.

“If you are a lower-income or harder-to-reach person, you’re probably not going to participate in a program that requires you to do a $20,000 HVAC replacement that you can’t afford,” said Sandy Laube, an energy efficiency policy researcher at Energy Solutions, the program administrator of TECH Clean California.

To address this roadblock, TECH Clean California provided funding for an already existing program, the San Joaquin Valley Disadvantaged Community Pilot Project. The pilot is part of California’s broader effort to assess the economic feasibility of helping these residents reduce their energy costs by replacing certain appliances with electric ones. The findings will be used to determine how best to meet the State’s broader goals for addressing climate change and reducing the disproportionate climate burden these communities bear.

TECH Clean California, which has committed 40 percent of its incentive funding to income-qualified customers, has learned that working with other partners in equity work helps leverage that commitment even further.

For this effort, TECH Clean California experimented with encouraging greater participation from interested households, many of which were budget-constrained.

The San Joaquin Valley Disadvantaged Community Pilot program had funded the installation of heat pump systems into roughly 279 qualifying low-income homes in the San Joaquin Valley, but due to restrictions in how funding can be used, there is a $5,000 minor home repair remediation cost maximum. This put some of the needed repairs out of reach for would-be program participants.

TECH Clean California was able to provide enough additional incentive funding to expand the San Joaquin Valley Pilot, so that it could reach more residents. In fact, TECH Clean California successfully helped fund remediation work in 89 additional homes. “We saw that many of these lower-income households were not going to be able to participate and get the broader benefits of renewable power in their home,” Laube said. “We wanted to be equitable in how we are spending the incentive money, which has meant finding ways to include groups that would normally not participate.”

This additional TECH Clean California funding covered home repair expenses, trenching, and other infrastructure costs, bridging the gap between what the utility was able to fund through its program and what the end customers needed to install the new electrification equipment. As a result, eligible customers had no additional out-of-pocket expenses.

“The additional TECH Clean California funding ended up being very important,” said Jose Landeros, the Director of Energy Programs for Proteus. “If it had not been for those additional funds for the remediation, many of these customers would not have participated.”

The needed work which TECH Clean California funded were a subset of homes that PG&E’s Building Electrification program had identified as needing heat pump water heaters. For these homes in San Joaquin Valley, the preparatory work for installation in a 2022 pilot project revealed a broad range of preliminary repair issues that first needed to be addressed.

Many of these homes needed to relocate the new heat pump systems water heater to the exterior of the home, requiring the installation of a metal enclosure for protection from weather or other damage.

Several residences in the San Joaquin Valley also required panel upgrades to support the added load of the new electrical equipment.

“It costs more money to electrify low-income households,” said Rachel Etherington, an energy transition strategist with the Ortiz Group, who worked with the San Joaquin Valley community in facilitating heat pump installations. “You only know how bad it is when you’re on the ground. “There’s no pavement for example. You can’t put machinery on dirt. You must revert to manual trenching, so that’s a significant labor cost. And every single home needed an electrical panel upgrade. It gives you an understanding of why it’s such an interesting project, like the pioneer of low-income implementation.” However, these kinds of upgrades will have further benefits for customers down the road, providing the basis for further electrification.

“A 200-amp panel gives low-income customers a better availability of power for the future, meaning that if they do have to get an electric car, they now have the capacity to be able to put an EV charger on their house,” said Lyal Ray, a quality production manager for Synergy Energy who was actively involved in many of the installations for San Joaquin Valley. “They have the capacity to put battery storage that is provided for low-income housing.”

It’s these kinds of hidden costs that are proving to be a barrier for lower-income families to access the benefits that electrification technology such as heat pump water heater HVACs can provide. 

“Without TECH Clean California funds, 89 of these households would not have been able to participate, elderly residents who require electricity all day, residents on dialysis machines,” Etherington said. “They required a significant amount of infrastructure upgrades. But at the end of the day, these are people’s homes, and those TECH Clean California funds created a huge quality of life improvement for those households.”

Written by Emily Pickrell. For more information about this and other projects, please visit TECH Clean California’s Annual Report at techcleanca.com. The report highlights learnings and accomplishments through the initiative’s statewide focus and collaboration. The guiding principle of TECH Clean California puts the state on a pathway to six million heat pumps by 2030 and carbon-free homes by 2045.

Commentary: Encouraging heat pump technology for San Joaquin Valley residents is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.