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. 

California electric bill relief plan would gut low-income energy programs 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.

This story was originally published by Canary Media.

Over the past three years, an unusually broad coalition has come together to champion a new way to finance and build community-solar-and-battery projects in California. It includes solar companies, environmental justice activists, consumer advocates, labor unions, farmers, homebuilder industry groups, and both Democratic and Republican state lawmakers — a rare instance of concord in a state riven by conflicts over rooftop solar and utility policy. 

Supporters say the plan, known as the Net Value Billing Tariff, could enable the building of up to 8 gigawatts of community-solar-battery projects over the coming decades, all of which would be connected to low-voltage power grids that sell low-cost power to subscribing households, businesses, and organizations.

But on Thursday, the California Public Utilities Commission voted 3–1 to reject the coalition’s plan. Instead, it ordered the state’s major utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — to restructure a number of long-running distributed solar programs that have failed to spur almost any projects in the decade or more they’ve been in place. 

Critics warn that these utility-backed plans won’t create a workable pathway to expanding a class of solar power that has become a major driver of clean energy growth in other states and a key focus of the Biden administration’s energy equity policy.

They also fear that the CPUC’s reliance on state and federal subsidies to boost the economic competitiveness of these existing failed community-solar models might jeopardize the state’s ability to even qualify for the $250 million in community-solar funding that the Biden administration has provisionally offered it. 

“We are cheating ourselves out of the benefits of community solar and storage with this decision,” said Derek Chernow, western regional director for the Coalition for Community Solar Access (CCSA), which represents companies and nonprofits that advocate for community solar. 

Since CCSA devised the NVBT in 2021, it has won ​“unprecedented bipartisan broad-based support from stakeholders that don’t typically come together and see eye to eye on clean energy issues,” Chernow said. 

The plan the CPUC cobbled together from utility proposals, by contrast, lacks ​“any support — broad-based or otherwise,” he said. 

An outpouring of rage from community-solar supporters

CPUC President Alice Busching Reynolds defended the decision to reject the NVBT at Thursday’s meeting. She pointed to other existing California programs that assist low-income households and multifamily buildings in obtaining solar, and noted that the CPUC’s plan will expand an existing community-solar program that offers low-income customers a 20 percent reduction on their bills. 

She said that the NVBT program was too costly a way to bring new solar-and-battery resources to the state, compared to the large-scale energy projects being contracted by utilities and community energy providers. 

“California is really at an inflection point where we must use the most cost-effective clean energy resources that provide reliability value to the system,” Reynolds said. 

Backers of the NVBT hold a very different view. Since March, when the CPUC unveiled its proposed decision to reject the NVBT, there has been broad public outcry. Letters protesting its proposal have flooded into the CPUC from community-solar advocacy groups, environmental organizations, commercial real estate companies, farmworker advocacy groups, farming industry associations, and Republican and Democratic state lawmakers. 

The CPUC issued a revised proposed decision on Tuesday, ahead of Thursday’s vote, which differed little from the initial March proposal. The only major change was the removal of a legal argument claiming that the NVBT violates federal law — a theory that was met with widespread incredulity and was rebutted by three former chairs of the Federal Energy Regulatory Commission in letters to the CPUC. 

The Utility Reform Network (TURN), a nonprofit that advocates for utility customers, has warned that the CPUC’s community-solar plan will ​“favor large utility companies by ensuring solar program development costs are incurred by home builders, renters, and other solar community participants,” while failing to offer lower-income customers a chance to reduce their fast-rising electric bills by subscribing to lower-cost solar power. 

And 20 lawmakers who supported AB 2316, the 2022 state law that ordered the CPUC to create an equitable and affordable community-solar program, have told the CPUC that its failure to support the NVBT could mean the state falls short on its clean energy and climate goals. 

“Transmission-scale renewables face significant siting, interconnection, and transmission challenges,” creating the risk that utilities won’t be able to hit the aggressive clean energy procurement targets set by the CPUC, the lawmakers wrote in a September letter. ​“Small, distribution-sited community solar and storage projects have incredible potential as we modernize and expand our transmission system.”

Speaking at Thursday’s CPUC meeting, Assemblymember Chris Ward, the San Diego Democrat who authored AB 2316, called the CPUC’s pending decision ​“a dismissal of California’s need for clean, reliable, and affordable energy.” 

“After agreeing with nearly all stakeholders that the state’s existing community renewables programs are not workable, the proposed decision has opted to repeat these mistakes by creating an outdated, commercially unworkable program that will result in no new renewable energy projects or energy storage,” he told the CPUC commissioners, all of whom were appointed by Governor Gavin Newsom (D).

Why California lags on community solar 

California leads the country in rooftop solar and stands behind only Texas in utility-scale solar-and-battery farms. But its community-solar projects make up less than 1 percent of the 6.2 gigawatts of community solar that have been built in the 22 states with policies that support this form of solar development. That’s largely because the community-solar programs that have existed in California for more than a decade have been unattractive to solar developers, financiers, and would-be subscribers. 

The earliest programs, which targeted commercial and industrial customers, charged a premium over standard utility rates, making them undesirable. Later programs created for lower-income and disadvantaged communities have been stymied by limits on how many megawatts’ worth of projects can be built and the size of individual projects, as well as onerous rules that require projects serving disadvantaged communities to be located within five miles of those customers. 

Designed to remove those barriers, the NVBT was modeled on a community-solar program created by New York that has led to more than 2 gigawatts of projects in that state. That structure allows community-solar projects to earn steady revenues from the power they produce based on a complex calculation of benefits. Those benefits include helping to meet state climate goals, bringing clean power to underserved customers, and, importantly, helping to support utility grids by, for example, avoiding the cost of securing power during the rare hours of the year when utility grids face the greatest stress. 

Unlike California’s existing community-solar programs, the NVBT would incentivize projects to add batteries to store and shift solar power from when it’s in surplus to when it’s most needed on the grid. 

And under AB 2316, any new community-solar-and-battery projects in California must provide at least 51 percent of their capacity to serve low-income residential customers at prices that reduce their electricity bills — a valuable option for low-income households, renters, and other utility customers that can’t access rooftop solar. 

“We’re very interested in seeing renters have access to community-solar projects,” said Matt Freedman, a staff attorney at TURN. ​“And we’re excited that the California statute requires at least 51 percent of the benefits go to low-income customers. We think that’s revolutionary — that we’re putting low-income customers first in line to receive the benefits of these projects.” 

To date, California’s community-solar programs have subsidized lower-income customers through funds drawn from utility ratepayers at large or from the state’s greenhouse gas cap-and-trade program. NVBT backers hoped the structure they proposed would allow projects to earn enough money in their own right to support reduced rates for lower-income customers. 

Why the CPUC rejected the NVBT

But all the revenues and benefits of community-solar-battery projects under the NVBT rely on a common factor, Freedman said: being able to tap into the same value structure that dictates what rooftop-solar-equipped customers served by California’s three major utilities earn for their solar power. That structure is called the avoided-cost calculator, and AB 2316 explicitly cited it as the metric that the CPUC should use to determine the value of community solar, he said. 

The CPUC’s decision rejected that reading of the law, however. Instead, it agreed with the state’s big utilities that the solar-and-battery projects that the NVBT would finance could increase costs on some of the state’s utility customers in excess of the value those projects would provide to customers at large. 

To reach that conclusion, the CPUC didn’t compare the cost and value of community-solar-and-battery projects against the value assigned to rooftop solar systems and other distribution-grid-connected clean energy resources. Instead, it compared their value against wholesale ​“avoided-cost” rates of electricity generated by power plants, utility-scale solar-and-battery farms, and other large-scale resources. 

Those resources provide power that’s much cheaper on a per-kilowatt-hour basis than power from community-solar-battery projects, which face higher land and construction costs connected to building in more populous areas, and which can’t match the economies of scale achieved by solar-and-battery farms in the hundreds of megawatts apiece. 

But by choosing that comparison point, the CPUC also dismissed the value that distributed community-solar projects can provide by delivering power much closer to customers than far-off power plants and solar farms connected by expensive high-voltage transmission lines, Freedman said. 

A better comparison, he suggested, would be against a form of solar-and-battery power that community projects could actually supplant to significant economic benefit — the solar systems all new homes and many new commercial and multifamily buildings must include under California building codes. 

That’s why the California Building Industries Association trade group has been a strong supporter of the NVBT. CBIA estimates that the state’s building codes will require the addition of 250 to 400 megawatts of new solar per year over the coming decade to keep up with the pace of residential construction. Community solar and batteries under the NVBT could be a much cheaper way to meet those requirements — but only if developers have a program that makes building those projects economically viable. 

A problematic replacement plan 

It’s hard to see how the CPUC’s newly enacted Community Renewable Energy Program (CREP) structure will make that possible. 

In essence, the CPUC has ordered utilities to restructure two existing tariffs that allow distributed energy projects to sell their power to utilities at wholesale avoided-cost rates: the Renewable Market Adjusting Tariff (ReMAT) program, which allows projects of up to 3 megawatts, and the Public Utility Regulatory Policies Act (PURPA) Standard Offer Contract, which allows projects of up to 20 megawatts.

But the low prices and short contract terms for these structures have been extremely unattractive to clean energy developers. No project has been completed under the ​“standard offer contract” structure since 1995, and only one 3-megawatt solar-only project has been built under ReMAT since 2021, Freedman said. 

It’s hard to envision lenders or investors backing a solar project with such an unclear pathway to profitability, CCSA’s Chernow said. What’s more, neither of those tariffs reward projects that invest in batteries to store solar power when it’s not as valuable for the grid and discharge it during times of grid stress, he said. 

“You don’t get the scalability, you don’t get the growth, you don’t get the storage — you don’t get all of the avoided-cost benefits that were originally set up with the Net Value Billing Tariff,” he said. 

To make matters worse, both of those programs are meant to supply lower-income customers with solar power that can reduce their electricity bills, Freedman said. But retail electricity rates in California are five to six times higher than the wholesale rates that the CPUC would allow these projects to earn. 

To make up for that discrepancy, the CPUC has ordered utilities to use ​“external funding or incentives” to offer credits to subscribing customers that are structured in a way that doesn’t increase their utility energy costs. Low-income customers, which must make up at least half of all subscribers, ​“will receive no less than 20 percent” bill credits. 

But at present, the only money the CPUC has identified for these external sources is $33 million in state-approved funding available for community-solar usage and storage-backed renewable-generation programs. Beyond that, Thursday’s decision orders utilities to look to federal investment tax credits and a set of programs created by the Inflation Reduction Act to spur investment and lending in underserved communities, including the U.S. Environmental Protection Agency’s $7 billion Solar for All program.

Last month, EPA announced 60 provisional recipients of that funding. California is set to receive $249 million, pending approval of how it plans to spend the money — including a commitment to ensure that low-income customers who participate will be able to lower their electricity bills by at least 20 percent compared to what they were paying before. 

CPUC President Reynolds noted at Thursday’s meeting that ​“while we’re still waiting for guidance from U.S. EPA, we hope to use a significant portion of this funding to support projects and subscribers in this new program.” 

But NVBT advocates say it’s far from clear that the programs that will evolve from the CPUC’s decision will provide the underlying utility tariff structures that could allow that federal funding to jump-start a commercially viable community-solar market. In fact, CCSA has calculated that the $249 million in federal funding would allow only about 50 megawatts of community-solar-and-battery projects to achieve economic viability under the CPUC’s proposal and still achieve the Solar for All program’s low-income energy-cost reduction targets, Chernow said. 

That’s a far cry from the gigawatts of solar-and-battery projects financed and built by independent developers on a cost-effective basis that the NVBT could have incentivized to be built. But Freedman pointed out that even that relatively small-scale expansion might not be possible if developers decline to participate due to lack of clear long-term economics. 

“Even if the state gets the commitment from the money, will we be able to spend it? If you design a program that developers don’t subscribe to, and there are no resources under the program, there’s no draw on the program,” he said. 

CPUC Commissioner Darcie Houck, who voted against the decision, echoed some of these concerns at Thursday’s meeting. ​“The reliance on funding that may or may not be available in the future puts the program either at risk of failing or potentially having to have ratepayers cover the full cost of the program going forward,” she said. Houck was outvoted by commissioners John Reynolds and Karen Douglas and CPUC President Reynolds, with commissioner Matt Baker recusing himself.

Chernow said the CCSA planned to ​“work within the CPUC’s process to try to fix this as much as we can.” But without significant changes, he warned that the structure set by Thursday’s order stood little chance of spurring the kind of community-solar growth happening in other states. 

The U.S. Department of Energy has set a goal of building 25 gigawatts of community solar by 2025, a fivefold increase from today. But Chernow fears the country as a whole ​“can’t get to these federal goals without California — and California can’t get there with this proposed decision.”

California regulators reject plan that would’ve boosted community solar 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.

Utilities across the U.S. Southeast are claiming that a massive buildout of data centers and factories will force them to construct gigawatts of new fossil gas-fired power plants over the coming decade — a fleet large enough and dirty enough to potentially put U.S. climate goals out of reach.

However, critics of these plans say that utilities have cleaner and cheaper alternatives to reliably manage surging new power demand, and that state utility regulators in Georgia, the Carolinas and Tennessee need to require them to explore those options.

For the moment, though, these utilities, which serve tens of millions of customers, appear set on a fossil-fueled power expansion that also promises them additional profits for years to come — profits that environmentalists and consumer advocates argue will be reaped at the expense of the climate and their customers.

“The problem we face now is that everyone is searching for power,” said Simon Mahan, executive director of the Southern Renewable Energy Association. ​“Utilities across the Southeast are scrambling to find every last megawatt they can get…. They are trying desperately to get these new large-load customers, because they make more money when they sell more power.”

In some regions, these potential new customers are big data centers to serve the skyrocketing demand for enterprise computing power, artificial intelligence and cryptocurrency mining. In others, they’re factories for electric vehicles, lithium-ion batteries and solar panels supported by billions of dollars of federal incentives from the Inflation Reduction Act.

The exact figures vary from region to region, but most of the utilities are now forecasting high single-digit percentage growth rates every year through the end of the decade. Demand for electricity over the past decade and a half has stayed flat or even declined, so growth on that order would be a sea change for utilities.

Whether this new electricity demand will emerge at the speed and scale these utilities are predicting is unclear; utilities have overestimated demand growth before. Some critics have accused utilities of seizing on hype around the rapid expansion of energy-intensive artificial intelligence technology to win approval for gas plants that are not really necessary.

But even if these projections are accurate, critics say new fossil gas plants aren’t the answer. They argue that gas plants are polluting, unreliable and likely to become stranded assets in the near future, as climate imperatives and cheaper clean-energy resources force them to close before utilities have recouped their costs.

“Are we facing a ​‘grid crisis’ in the U.S. due to data center and factory expansion? No,” Tyler Norris, former vice president of development at independent power producer Cypress Creek Renewables and now a doctoral student at Duke University, wrote in a recent social media post. ​“But doomsday thinking appears to be spreading and increasing the risk of poor decision-making.”

There are more reliable and cost-effective ways to deal with an increase in electricity demand that must be explored further, Norris and others point out, like building solar and wind power — paired with batteries — or enlisting power-hungry corporate customers to use less electricity when demand is at its highest. These options also help achieve climate goals, rather than threaten them.

Experts say the only way to course correct is for state utility commissions to intervene — something each one has an opportunity to do in the coming months. 

What the utilities want — and what it would cost the climate

The Southeast utilities’ current plans, if approved, could have a disastrous climate impact.

These utilities are also planning to add gigawatts of solar power, batteries and other carbon-free resources and to close down gigawatts of coal-fired power plants. But taken together, the carbon impacts of a large gas expansion would eclipse the gains of these projects, according to an analysis from the Southern Environmental Law Center.

Last month, Georgia Power, a business unit of multi-state utility holding company Southern Company, secured a preliminary settlement plan with Georgia regulators that would allow the utility to fast-track 1,400 megawatts of new gas-fired power plants in the next three years. Georgia Power sought permission last year to rush the plan through regulatory approval to meet what it now forecasts will be 17 times more power demand growth than it had predicted it would need just 18 months earlier, due to new data centers and factories being planned in the state. The settlement plan still requires the vote of the Georgia Public Service Commission, expected to be held on April 16.

Duke Energy, one of the country’s biggest utilities with operations in six states, recently added significantly more fossil gas plants to its plan for supplying North Carolina and South Carolina, boosting its request to a total of 9,000 megawatts. That’s nearly three times the amount it requested to build in a 2022 proposal, and would delay its ability to meet a commitment under North Carolina law to cut its carbon emissions by 70 percent from 2005 levels by 2030. Duke says the buildout is needed to meet a forecasted 12-percent increase in electricity demand by 2038, driven largely by dozens of economic development projects in both states.

In South Carolina, state lawmakers are advancing legislation backed by utilities Dominion Energy and Santee Cooper to fast-track construction of a 2,000-megawatt fossil gas-fired power plant. The bill’s sponsor, Speaker of the House Murrell Smith (R), has cited a looming ​“crisis point” for the state’s grid as a result of rising demand from factories and growing population.

And Tennessee Valley Authority, the federal entity that generates power for 10 million people across seven Southeastern states, is developing a plan that could include 6,600 megawatts of new gas-fired power plants to replace coal plants and serve growing power demand. TVA delayed the release of its official plan last month, leaving uncertain just how much new gas-fired power it will propose.

“If all of these gas proposals across the Southeast do come to fruition, I think we’re going to have a huge confluence of issues between climate and reliability and affordability,” said Maggie Shober, research director of the Southern Alliance for Clean Energy.

What’s frustrating, Shober said, is that these utilities ​“were already proposing new gas before this load growth showed up. Duke and TVA have each flip-flopped on who has the largest gas buildout in the country, but they remain first and second by a pretty large margin.”

Gudrun Thompson, senior attorney and energy program leader at the Southern Environmental Law Center, agreed that ​“gas has been the answer to multiple problems” for Southeastern utilities.

“A couple of years ago it was the bridge fuel they needed to accommodate renewables. After Winter Storms Uri and Elliott” — major storms that led to catastrophic power outages in Texas and rolling blackouts in the Southeast, respectively — ​“it was what they needed for reliability. Now it’s what they need to meet data center load,” she said. ​“Whatever the problem is, it seems the reflexive solution is to build a new gas plant.”

The nonprofit environmental advocacy law firm estimates that utilities in Alabama, Georgia, North Carolina, South Carolina, Tennessee and Virginia are planning to retire about 25,000 megawatts of coal by 2038, while simultaneously rushing to build 33,000 megawatts of new gas plants over the next decade. At the same time, utilities across the country need to cut power-sector emissions 80 percent by 2030 compared to a 2005 baseline to meet U.S. Paris Agreement commitments — any new fossil-fueled power plants are likely to put those targets out of reach, Thompson said.

Why fossil gas plants are not the most reliable choice

Clean energy and consumer advocates in the Southeast are also worried that new gas plants wouldn’t even solve the problem utilities are citing to justify them: making the grid more reliable in the face of rapid demand growth.

That’s because of the nature of the power shortfalls Southeastern utilities face. Day-to-day, the utilities have few problems meeting the electricity needs of their customers. But they do struggle to meet demand during grid ​“peaks” — the handful of hours during the hottest summer afternoons and coldest winter mornings when customers need the most power.

However, gas-fired power plants failed to perform that critical task during Winter Storm Elliot in December 2022. Supply fell short by more than 70,000 megawatts of generation capacity across the U.S. Southeast at the time, forcing Duke Energy and the Tennessee Valley Authority to institute rolling blackouts. Much of the failures occurred at gas-fired power plants that were forced offline because equipment froze or pipelines couldn’t deliver, calling into question the assumption that building yet more gas infrastructure will solve future problems.

“We’ve been trying to make the argument that gas plants not only didn’t save the day during these winter storm events, they were a big part of the problem — whereas renewables pretty much performed as expected,” Thompson said.

What performed ​“really well was demand response,” she said, referring to programs that pay households and businesses to turn down power use or switch to backup power during grid emergencies. Many of the customers driving the boom in demand — primarily data centers, which can shift electricity usage and tap backup power to ride through outages — ​“could really participate in demand response programs, and deliver a lot of peak load reduction,” she noted.

That view was echoed by Norris in a presentation to South Carolina regulators last September. Norris highlighted the cascade of problems — power plant failures and an inability to import power over transmission lines from neighboring regions — that forced Duke Energy to institute rolling blackouts on the morning of Christmas Eve during Winter Storm Elliot.

But the presentation also showed that the duration of the demand spike that triggered the grid emergency was a relatively brief three to four hours, he said in an interview. That’s a gap that can mostly be met by lithium-ion batteries, at a cost that’s competitive with gas-fired power, or by commercial facilities like data centers agreeing to reduce their power demand.

But Duke Energy’s most recently updated plan, released in January, doesn’t take that potential flexibility into account, he said. Instead, it assumes that ​“new industrial and commercial load is 24/7/365 — zero flexibility. And they’re taking the total draw of the new load and putting it right on top of their winter peaking load forecast. It’s a maximalist, worst-case scenario.”

Peakers versus baseload gas plants: A big difference in carbon and cost

At the very least, utilities struggling to meet peak demand could focus on building the type of gas power plant built for that specific purpose, Norris said. But that’s not what’s happening.

Instead, utilities are proposing to build huge numbers of power plants that are designed to run regularly. It’s a ​“solution” that’s not matched to the problem of managing infrequent, hours-long grid peaks — and the impact of such a decision could reverberate for decades.

There are two types of gas-fired power plants: single-cycle combustion turbines (CTs) that can be ​“ramped up” to meet unexpected surges in power demand within minutes, and combined-cycle gas turbines (CCGTs) that make up the majority of gas-fired generation capacity in the U.S. today.

CTs operate at lower efficiency than CCCTs, but they usually run between 10 and 20 percent of the year — a stark difference from CCGTs, which on average run over 50 percent of the time in the U.S.

Duke Energy’s most recent proposal to regulators is heavily weighted toward CCGTs. In between the 2022 version and its January update, Duke has doubled the amount of CTs it is asking regulators to let it build by 2035 — but nearly tripled the amount of CCGTs it wants to build by then.

The fear is that because these power plants are designed to run far more often than CT plants, they will crowd out lower-emissions resources — and delay the shift to a carbon-free grid. 

“Once these large combined cycle units are on the system, it will be very tempting to use them long into the future,” Norris said.

Why gas plants force extra costs onto customers 

A rash of new gas plants could actually increase costs for customers. Electricity from newly built wind and solar farms is already cheaper than power from newly built gas plants. And lithium-ion batteries have fallen in cost to the point where using them to store clean power and discharge it later is competitive with building new gas-fired peaker plants.

In other words, ​“gas plants are no longer the cheapest option,” Shober said. But for utilities, they may still be the most convenient — and, crucially, the most profitable — route.

Regulated utilities like Duke Energy and Georgia Power pass the cost of building power plants and other capital expenses on to their customers in the form of higher rates on their utility bills, meaning it’s customers, not utilities, who pay for new gas plants.

Gas prices can also spike unexpectedly, whether due to seasonal shortages during cold winter months or global supply shocks such as Russia’s invasion of Ukraine. But under current regulatory structures, utilities can pass the cost of those spikes on to customers as well.

These disconnects are rooted in what’s known as ​“cost-of-service” regulation, under which investor-owned utilities are allowed to make a guaranteed rate of return, typically set in the 8 to 10 percent range, on investments in capital assets like power plants and power lines. The aim is to encourage utilities to build the infrastructure they need to deliver energy to everyone they serve.

But that also means that ​“investor-owned utilities under cost-of-service ratemaking have incentives to maximize capital expenses and little to no incentive to improve efficiency,” Norris said.

In some cases, that can lead to utilities taking actions that run counter to their customers’ interests — including the large customers utilities are trying to attract.

That’s certainly true of the data center developers that are part of the Clean Energy Buyers Association (CEBA), a trade group representing more than 400 companies with clean energy goals, such as Google and Microsoft, that have pledged to attain round-the-clock carbon-free energy by 2030.

For years, CEBA has pushed Southeastern utilities to expand clean energy to help large corporate customers meet their goals. In a recent Georgia Power public hearing, Priya Barua, CEBA’s director of market and policy innovation, noted that overbuilding fossil fuel capacity in Georgia ​“would result in higher costs for existing customers and make it more difficult for existing customers to meet their sustainability targets.”

“If you don’t have solutions to empower customers to bring clean energy to the system, there’s no guarantee that those customers are going to site there,” Barua told Canary Media. ​“I think that is something that Georgia Power and regulators have to factor in when making decisions.”

What can regulators do?

While other utilities across the country are also seeking permission to build new gas-fired power plants, the largest buildout is slated for the Southeast. The confluence of climate, cost and reliability concerns over these utilities’ plans puts a burden on utility regulators to carefully examine them, said Mike O’Boyle, senior director for electricity policy at think tank Energy Innovation.

Under the regulatory compact that allows utilities to operate as monopolies in the territories they serve, ​“utilities only recover costs that are prudently incurred,” he said. ​“That prudency standard is rooted in whether the utility fully examined alternatives.”

In a March report, O’Boyle and Energy Innovation colleagues laid out several reasons why the plans of Southeastern utilities may not meet that standard. While demand for electricity is almost certain to grow over the coming decade, ​“the exact pace of the growth in the short term remains uncertain, particularly with the addition of factories and data centers,” it noted. ​“Therefore, short-term investments by utilities should prioritize low-regrets, flexible options that avoid locking in expensive and potentially stranded assets.”

The report highlighted that utilities in the regions with the largest projected growth by percentage — the Northwest, Southwest, and California — are ​“markedly not moving to add gas to their resource plans.”

Environmentalists’ fight against new gas plants has been complicated by the shift in power demand growth patterns, however. Grid reliability is an increasing concern among regulators and industry groups, as coal retirements accelerate and it becomes clear that — whatever the magnitude and speed — electricity demand is set to rise in the years to come. This uncertainty presents utilities and regulators with a conundrum, said Danny Freeman, senior partner, energy and utilities with consultancy West Monroe.

“They have to pull together a credible projection of what the load is going to look like,” he said. Data center developers ​“are looking across the country and trying to find the cheapest possible energy supplier across any number of states. When these deals will be done, and when they’ll kick in is a huge question mark.”

At the same time, ​“there are realities to serving this growing load that have to be dealt with,” he said. Data centers may not be willing to commit to shutting off their power during hours of peak grid demand as a precondition of being able to connect to utility grids, he said. And renewable energy, with its variability tied to weather, ​“presents a challenge to grid operators,” he said.

But just because cleaner and cheaper options are more complicated than building new gas-fired power plants doesn’t absolve utilities and regulators of the responsibility of examining them, O’Boyle said.

“Regulators have to start by asking the right questions,” he said. ​“Are there viable projects that can use your existing interconnection points from retiring coal plants? Are there bids in prior RFPs that are still viable, and have you considered them as alternatives to your new gas plant? Have you considered energy efficiency or flexible load?”

Public utility commissions must insist that utilities examine these options more thoroughly as an alternative to new fossil gas-fueled power plants, and compel them to share their assumptions and methods for assessing their relative merits, he said. If they don’t, it’s very hard for all parties involved to find a mutually acceptable path forward.

“I don’t know if there’s a smoking gun here for utilities acting in bad faith,” he said. ​“I think they were caught off guard, as many analysts were, by this load growth — and they’re looking for solutions that can work. Their number one incentive is that the lights don’t go out. And it’s a lot easier to say ​‘one plant solves my problem.’”

“But the stakes are really high,” he said. ​“You can’t just jump into a billion-dollar expenditure — whatever it costs to build a gigawatt of new gas — especially when these large consumers are coming to the table and saying, ​‘We want something else, and we can help.’ It’s worth taking a breath and working collaboratively on solutions that are lower risk and lower cost, and actually meet customers’ needs.”

Southeast utilities want to meet surging power demand with gas, not renewables 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.