States took on the mantle of combating climate change during the first Trump administration. Now they need to redouble the work during the second. 

That’s the message that Caroline Spears, executive director of Climate Cabinet, has for state lawmakers following Trump’s victory on Tuesday. 

As an advocacy organization that helps state and local leaders ​“run, win, and legislate on climate change,” Climate Cabinet supported more than 170 candidates in Tuesday’s election. As of midday Wednesday, when Spears spoke to Canary Media, she was feeling cautiously optimistic about the races her group had focused on: ​“About a third of them we won, about a third of them we lost, and about a third of them are still too close to call.” 

Getting climate-committed candidates into state offices can make the difference between a state enacting or preserving climate policies and it blocking or rolling back such policies, she said. For example, the 2022 midterms saw Maryland, Massachusetts, Michigan, and Minnesota secure Democratic ​“trifectas” — control of the governor’s office and both houses of the state legislature — leading to significant climate legislation being passed and signed into law in those states. 

States have ​“always been key to climate policy,” Spears said, and now, with a Trump administration expected to attempt to unravel the Biden administration’s climate policies and unleash fossil fuels, it’s ​“up to state leaders to hold the line.”

How states can keep the energy transition moving

State lawmakers and regulators have the ability to order local utilities to shut down or reduce emissions from fossil-fueled power plants and expand the share of electricity they generate from zero-carbon resources like wind, solar, geothermal, and nuclear power. 

States can also require large polluters — like fossil-gas utilities — to reduce the amount of greenhouse gas they spew into the air and set emissions and energy-efficiency requirements for buildings. At present, states have the authority to adopt vehicle emissions standards that are more strict than those set by the federal government — although Trump sought to rescind that authority during his first term and may attempt to do so again. 

States also play a key role in distributing funds from the federal Inflation Reduction Act and Infrastructure Investment and Jobs Act — at least while the full laws remain on the books. 

During the first Trump administration, ​“we saw states really taking charge,” said Jeff Deyette, deputy director of clean energy at the Union of Concerned Scientists, an advocacy group. ​“I think that momentum has been maintained over the past eight years. This could be another boost to continue to push those state leaders … to protect what they have.” 

There’s a lot to protect. The roster of states with aggressive decarbonization targets has expanded under the Biden administration: Colorado, Illinois, Maryland, Massachusetts, North Carolina, Oregon, Rhode Island, and Washington state all adopted strong emissions goals in 2021 or 2022. 

All told, 25 states and Washington, D.C., have now instituted some form of target for achieving either economywide net-zero carbon emissions, 100 percent renewable or carbon-free electricity, or both. This chart, compiled in mid-2024, includes all of these states except Vermont, which in June 2024 passed a law mandating 100 percent renewable energy by 2035 for all utilities and by 2030 for its largest utility, Green Mountain Power. 

How the 2024 election changed the state policy landscape

Clean energy and climate policies aren’t necessarily partisan issues, said Heather O’Neill, CEO of trade group Advanced Energy United. ​“We see the potential for broad agreement in states of all political stripes and persuasions,” as utilities grapple with rising electricity demand from data centers, factories, electric vehicles, and broader economic growth. ​“Advanced energy technologies are a low-cost solution to all of these challenges,” she said.

She cited the example of Texas, a red state that’s deployed more wind and utility-scale solar power than any other state and is set to pass California for having the most grid-connected batteries by year’s end. Those resources are ​“working to keep the grid reliable,” O’Neill said, as shown by the role that solar and batteries played in averting grid emergencies this summer. 

But to date, Democratic control has been a prerequisite for passing aggressive climate or clean-energy legislation in almost every state that has done so. The exception is North Carolina, where the GOP-controlled legislature passed a law in 2021 mandating that Duke Energy, the state’s biggest utility, cut carbon emissions 70 percent below 2005 levels by 2030 and reach net-zero emissions by 2050. 

Heading into the election, 17 states had Democratic trifectas and 23 states had Republican trifectas. No state appears to be on a path to form a new Democratic trifecta as a result of the election; rather, Democrats have lost full control in Michigan and might do the same in Minnesota. 

“We were in defense mode in Minnesota and Michigan,” Spears said. 

In Michigan, Republicans gained a majority in the state House of Representatives, while Democrats retained a majority in the state Senate and Democratic Gov. Gretchen Whitmer still has two more years in her term. That means the state is likely to protect a slate of climate bills passed in 2023, including a mandate for the state’s two big utilities to reach 80 percent carbon-free electricity by 2035 and 100 percent by 2040. 

The situation in Minnesota is still up in the air. As of Thursday evening, the state House was evenly split between parties, with two remaining races set for automatic recounts due to razor-thin vote differences. But Democrats retained their majority in the state Senate, and Democratic Gov. Tim Walz remains in office. Even if Republicans end up narrowly controlling the House, they likely won’t be able to overturn the state’s 2023 law requiring power utilities to use 100 percent clean electricity by 2040 or a slate of bills creating incentives for electric vehicles and converting homes and buildings to more efficient electric heating. 

In Pennsylvania, a state where Democrats were thought to have a chance at forming a new trifecta, Republicans appear set to retain their majority in the state Senate. Democrats could maintain their thin majority in the state House, but the outcome depends on three races that have yet to be called. Democratic Gov. Josh Shapiro has proposed a carbon cap-and-invest program that would collect funds from power plants and use them to lower electric bills and support clean energy projects, but it’s unlikely to pass without Democratic majorities in both houses of the state legislature. 

The clearest victories for candidates backed by Climate Cabinet in this election cycle have been in North Carolina and Wisconsin, Spears said — though their wins did not give Democrats legislative majorities.

In Wisconsin, gains by Democrats eliminated a Republican supermajority in the Senate, giving Democratic Gov. Tony Evers the ability to veto legislation out of line with his climate agenda, she said. 

In North Carolina, Democrat Josh Stein, the state attorney general who won his race to succeed Democratic Gov. Roy Cooper, will, ​“unlike his predecessor, have a veto pen that works, because we broke the supermajority” in the state House, she said. Republicans used that supermajority to override Cooper’s veto of a bill that weakened the efficiency requirements in building codes for new homes in the state. 

Voters also chalked up some climate wins with state ballot measures in Tuesday’s election. Californians passed a $10 billion climate bond that included $850 million for clean energy infrastructure — the largest of a number of local and state climate and environmental bonds passed across the country, which together will invest $18 billion. And Washington state voters rejected a ballot initiative that would have rolled back its landmark 2021 climate law. 

Turning pledges into action 

For the states that have already managed to get climate goals on the books, living up to those commitments is now even more urgent. 

State climate mandates must be followed up with continuous action from regulators, utilities, and private-sector actors to translate into actual emissions reductions. Right now, it’s far from clear that the states with decarbonization goals are on track to achieve their targets. 

A 2023 report from the Environmental Defense Fund found that the 24 states with ambitious targets were on track to cut emissions only 27 to 39 percent by 2030, well below the 50 percent reductions they’re aiming for. Since then, more states have found themselves falling behind on their climate targets, including the two most populous — the Democratic strongholds of California and New York.

California is lagging on its goal of reducing carbon emissions 48 percent below 1990 levels by 2030, according to a June report. Meanwhile, New York state has yet to finalize a cap-and-invest strategy to hit its target of 100 percent carbon-free energy by 2040 and is off track to hit its utility-scale solar and wind targets, although it has achieved its goals for distributed and community solar projects. 

For the energy transition to continue despite the headwinds of a second Trump administration, these two leading states — and the others that have enshrined decarbonization goals in law — need to do all they can to deliver on their climate commitments. 

Should Trump gut the Inflation Reduction Act, the task at hand for these states will become more difficult. Some analysts doubt this will happen because the law has funneled billions into red states and thereby earned some Republican defenders.

The law’s litany of clean energy tax credits make solar, wind, and storage projects into no-brainers; they were already cost-competitive with fossil fuels before the subsidies. The EV incentives help bring the cost of electric models in line with gas cars. Its bevy of grant programs — from money for bolstering the grid to funding for home electrification and low-income solar — are helping states transition away from fossil fuels. 

All of this makes it far cheaper and easier for states to achieve their clean energy targets and emissions-reduction goals. 

It’s unclear which of the Biden administration’s climate accomplishments will remain intact — but what is clear is the ever more urgent need for states to push forward on their climate goals, however difficult that may become.

After Trump win, it’s up to states to lead on climate action 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.

The Biden administration has enacted the most consequential federal clean energy and climate policy in U.S. history, giving the nation a fighting chance at reducing greenhouse gas emissions fast enough to deal with the climate crisis. Former President Donald Trump, who has won the 2024 presidential election, has pledged to undo that work.

Though Trump’s executive powers will allow him to slow the energy transition in a number of ways, the extent to which he rolls back Biden’s clean energy accomplishments will be dictated in part by whether Republicans retain control of the House of Representatives. The GOP flipped the U.S. Senate, but votes are still being counted in key House races as of Wednesday morning.

Here’s what clean energy and climate experts say is most likely to be lost under a second Trump administration — and what might survive.

What Trump has said about energy

Trump’s rhetoric presages a worst-case future. He has called climate change a hoax and the Biden administration’s climate policies a ​“green new scam.” He has said he wants to repeal the landmark Inflation Reduction Act and halt the law’s hundreds of billions of dollars of tax credits, grants, and other federal incentives for clean energy, electric vehicles, and other low-carbon technologies.

Trump has also made ​“drill, baby, drill” a call-and-response line at his rallies, pledging to undo any restraints on production and use of the fossil fuels driving climate change. U.S. oil and gas production is already at a record high under the Biden administration.

“He has pledged to do the bidding for Big Oil on day one,” Andrew Reagan, executive director of Clean Energy for America, said during a recent webinar.

“Oil and gas lobbyists are drafting executive orders for him to sign on day one,” Reagan added, citing news reports of plans from oil industry groups to roll back key Biden administration regulations and executive orders.

A Trump administration would be all but certain to reverse key Environmental Protection Agency regulations limiting greenhouse gas emissions from power plants, light-duty and heavy-duty vehicles, and the oil and gas industry, all of which analysts say are necessary to meet the country’s climate commitments. It’s also almost sure to lift the Biden administration’s pause on federal permitting of fossil-gas export facilities.

Trump has also promised to withdraw the U.S. from international climate agreements (again), including the Paris agreement aimed at limiting global warming to no more than 2 degrees Celsius above pre-industrial levels.

“We know that Trump would take us out of the Paris agreement, and that would be the last time his administration uttered the word ​‘climate,’” Catherine Wolfram, an economist at the MIT Sloan School of Management and former deputy assistant secretary for climate and energy economics in the Biden administration’s Treasury Department, told Canary Media. ​“Losing that global leadership would be one of the greatest losses of a Trump presidency.”

What will happen to the Inflation Reduction Act? 

Trump won’t have the power to enact all of his promises on his own. Some of the decisions must be made by Congress, including any effort to repeal the Inflation Reduction Act or to claw back unspent funds from that law or the 2021 bipartisan infrastructure law.

Complete repeal of the Inflation Reduction Act would be highly disruptive to a clean energy sector that has seen planned investment grow to roughly $500 billion since the law was passed in mid-2022.

It would also undermine clean energy job growth, which has increased at roughly twice the pace of U.S. employment overall. A recent survey of clean energy companies found that a repeal of the law would be expected to lead to half of them losing business or revenue, roughly one-quarter losing projects or contracts, about one-fifth laying off workers, and about one in 10 going out of business. 

“We found that especially rural areas and smaller rural communities would experience the largest negative impacts of repeal of the Inflation Reduction Act,” Shara Mohtadi, co-founder of S2 Strategies, said in an October webinar presenting the survey data. ​“These are the regions of the country that have seen the biggest uptake in the economic benefits and the manufacturing jobs coming from other countries into the United States.”

Indeed, most of the investment and job growth the IRA has spurred has taken place in states and congressional districts represented by Republicans.

These on-the-ground realities have driven expectations that large swaths of the law’s tax credits would be likely to survive even with Republican control of the White House and both houses of Congress. Trump would face pushback within his own party to undoing the law entirely.

In an August letter to current Speaker of the House Mike Johnson (R-Louisiana), 18 House Republicans warned against repealing the clean energy and manufacturing tax credits created by the Inflation Reduction Act, which have ​“spurred innovation, incentivized investment, and created good jobs in many parts of the country — including many districts represented by members of our conference.”

“Prematurely repealing energy tax credits, particularly those which were used to justify investments that already broke ground, would undermine private investments and stop development that is already ongoing,” the 18 House Republicans wrote. ​“A full repeal would create a worst-case scenario where we would have spent billions of taxpayer dollars and received next to nothing in return.”

Republicans would need a roughly 20-seat majority to overcome opposition from these party members opposed to a full repeal, said Harry Godfrey, head of the federal investment and manufacturing working group of trade group Advanced Energy United.

“I don’t envision Republicans holding the House with 20-plus seats,” he said.

Godfrey also doubted that a Trump administration would be eager to undermine the domestic manufacturing boom that the law’s tax credits have spurred. He noted that at the October 1 vice-presidential debate, J.D. Vance, the Republican Ohio senator and Trump’s running mate, emphasized the need for the U.S. to ​“consolidate American dominance” in key energy sectors and industries now dominated by China.

While Vance went on to falsely accuse the Biden administration of failing to bolster U.S. industries against China, the goal of emphasizing domestic competitiveness could lead Republicans to avoid undermining progress in that direction, he suggested.

How Trump’s second term could derail the clean energy transition 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 year ago, the U.S. announced ambitious plans to build large-scale clean hydrogen hubs. Now, 12 months later, those plans have advanced little and are still shrouded in uncertainty.

Last October, the U.S. Department of Energy picked seven consortiums across the country to receive up to $7 billion in federal grants. The goal of this startup money? To help the hubs attract tens of billions more in private-sector investment to pay for construction costs. These projects, located around the country, aim to bring together a wide array of organizations to scale up the production, storage, and transport of low- and zero-carbon hydrogen, which some experts view as a way to replace fossil fuels in industries such as steelmaking and aviation.

There’s still little publicly available information to indicate whether these ​“clean hydrogen hubs” are likely to attract the needed private sector investment, however. Just as opaque are their potential community and climate impacts.

Environmental groups, community advocates, and energy experts have grown concerned that the projects are off track — and increasingly dismayed that the DOE and the hub projects are not giving them the transparency needed to confirm or deny these worries.

This puts the DOE’s Office of Clean Energy Demonstrations, the agency responsible for the H2Hubs program, in a tricky position.

The $7 billion in H2Hub awards is being doled out in phases, over the course of many years. It’s OCED’s job to make sure the hubs are hitting the technical, financial, and community-benefit milestones needed to earn these disbursements.

The hydrogen hubs are a cornerstone of not only the Biden administration’s clean hydrogen strategy, but its overall approach to clean energy. Without the hubs, the U.S. may not be able to supply the tens of millions of tons per year of clean hydrogen needed to decarbonize key industries in the decades to come.

“We know that jump-starting a new clean energy economy in the U.S. is going to take time and public and private sector investment,” Kelly Cummins, OCED’s acting director, told Canary Media in an October interview. ​“To do that right and make sure it’s sustainable, we need to engage communities in a new way.”

However, community and environmental groups hounding the hydrogen hubs and DOE for information over the past year say that engagement isn’t happening. The Natural Resources Defense Council reported in May that ​“environmental justice advocates and frontline communities have largely been kept in the dark on key details and basic information about many of these projects.”

Since then, relatively little additional information has emerged. ​“We’re still struggling at this point to understand what’s really going on with the hubs,” said Morgan Rote, director of U.S. climate at the Environmental Defense Fund (EDF), another nonprofit group that’s been tracking the disconnect between hydrogen hubs and communities.

“I don’t think DOE is sitting on a whole wealth of information they’re not sharing,” Rote said. ​“But that makes it even more challenging — and it’s no wonder communities feel like they don’t have information, if the DOE doesn’t have information.”

Cummins acknowledged these frustrations.“The tension here is that we’re still in early days,” she said. ​“We’ve been working to engage communities and special interest groups. But we’re just at the start of this learning process.”

The initial planning grants are just the first step in what OCED expects to be an eight- to 12-year pathway to full-scale ramp-up and operations. Each stage will involve its own series of ​“go/no-go” decisions, with a ​“long list of deliverables and criteria,” Cummins said.

To date, only three hubs have been awarded first-phase planning grants of about $30 million each: the ARCHES hub in California; the Pacific Northwest Hydrogen Association(PNWH2), which includes Oregon, Washington, and Montana; and the Appalachian Regional Clean Hydrogen Hub (ARCH2), which includes Ohio, Pennsylvania, and West Virginia. The remainder are still in the process of negotiating final approval for their first-phase funding.

“We’ll go through a review of all that — the financing, the technology, the community benefits — and then make a decision if they’re ready to move from Phase One to Phase Two,” she said. ​“And there are some instances where we might decide they are not moving to Phase Two.”

Measuring progress on first-of-a-kind hydrogen hubs

Less than 1 percent of global hydrogen production today is low-carbon. Of the roughly 90 million tons per year produced globally and 10 million tons per year in the U.S., almost all is derived from fossil gas.

Right now, the two main methods for making low- or zero-carbon hydrogen are far more expensive than dirty hydrogen — and also untested at scale. Those include so-called ​“blue hydrogen,” which is made from fossil gas combined with carbon capture, and ​“green hydrogen,” which is made by splitting water in electrolyzers powered by zero-carbon electricity.

The hydrogen hubs need about $40 billion in private-sector investment to match DOE’s $7 billion. That’s a tough sell for investors, given the uncertain economics involved both for would-be clean hydrogen producers and for the industries that must invest in retrofitting facilities, building new infrastructure, and reconfiguring how they do business in order to use it.

What’s more, the rules for a subsidy that could make clean hydrogen cost-competitive with dirty hydrogen — the 45V production tax credits created by the Inflation Reduction Act — have yet to be finalized.

Last December, the U.S. Treasury Department proposed rules that would require green-hydrogen producers to source newly built and consistently deliverable clean electricity — restrictions that energy analysts say are vital to ensure hydrogen production doesn’t end up increasing carbon emissions.

But those proposed rules are being challenged by a number of industry groups and politicians who say they’ll stifle the nascent industry — including the seven hydrogen hubs themselves. The Treasury Department aims to finalize the rules by January.

The regulations for blue hydrogen remain another point of contention. Only the California and Pacific Northwest hubs have pledged to not make hydrogen from fossil gas. Some hubs, such as the Appalachian hub, have made blue hydrogen a focus. But blue hydrogen has yet to be proven to be cost-effective at scale, and in some cases could lead to more carbon emissions than simply using fossil gas.

The unresolved nature of these regulations — and the projects themselves — makes it impossible to tell at this point whether the hubs will actually help fight climate change.

In a May letter to DOE, U.S. Representatives Jamie Raskin (D-Maryland) and Donald S. Beyer Jr. (D-Virginia) complained that the agency has touted the potential for hydrogen made by the hubs to reduce carbon emissions by 25 million metric tons per year, but has ​“yet to publish the projected lifecycle emissions linked to the production of hydrogen.”

That information is ​“overdue and critical for us to fully understand the precise climate and public health impacts of the H2Hubs program,” the lawmakers wrote. ​“Scientists have warned that high levels of lifecycle emissions from hydrogen production could entirely cancel out any climate benefits from replacing fossil fuels with hydrogen.”

Cummins noted that DOE has responded to this request for information. ​“But the response was focused on the fact that we are evaluating every aspect of the production and use of hydrogen so that we can understand the impact on the environment,” she said — and much of that work remains to be done.

Are the hydrogen hubs living up to their community commitments? 

Though it may be early days for the hubs, advocates say the projects could be operating in a much more transparent way.

OCED released summaries of each hub’s commitment to community benefits immediately after the hubs were selected last October. Since then, OCED has held more than 70 meetings with more than 900 individuals and groups participating, Cummins said. The office has also briefed about 4,000 individuals and groups, including community members, environmental justice organizations, labor and workforce organizations, first responders, local businesses, energy professionals, elected tribal leaders, and local, state, and federal government officials.

The feedback from those meetings has led OCED to add new requirements for the hubs. The projects now must create public data reporting portals to share information as it’s finalized. They must develop community advisory structures that allow groups to provide feedback on plans as they’re developed. And they must ​“jointly evaluate or pursue negotiated agreements” on labor, workforce, health and safety, and community benefits plans.

“We’re really focused on three-way communication” between OCED, hub participants, and affected communities and other groups ​“to make sure anything we’re hearing back from the community is adequately addressed,” Cummins said. ​“That will determine whether we move forward to the next phase of the process.”

Environmental and community groups worry these requirements may still not prevent hub participants from running roughshod over communities, however.

In particular, many fear that participants — including oil and gas giants such as bp America, Chevron, Enbridge, EQT, ExxonMobil, Sempra Energy, and TC Energy — will subject communities already burdened with fossil fuel pollution to further harms from hydrogen production.

Communities have ​“questions around the transparency for the selection and planning process, how to monitor and evaluate community benefits plans, and to ensure there are sustained community benefits after the duration of the grants,” said Cihang Yuan, a senior program officer at the environmental nonprofit World Wildlife Fund. Other concerns include ​“more local impacts, such as hydrogen leakage or chemical disasters,” she said. ​“It’s definitely important for these hubs to have a solid plan for safety of operations.”

The secretive approach that hubs have taken to sharing information with potentially affected communities has added to these concerns. In California, the ARCHES hub requires meeting participants to sign non-disclosure agreements barring them from sharing information about the hub’s activities under threat of legal penalties.

“That’s something we can’t do,” said Theo Caretto, associate attorney at California-based environmental justice group Communities for a Better Environment (CBE), since it would bar community groups from sharing information with their constituents.

Those non-disclosure rules have remained in place at ARCHES and other hubs despite continual protests, forcing groups like CBE to wait for public information to dribble out. But one year in, ​“we’re having difficulty getting specifics on which projects are being funded,” Caretto said. ​“They’ve given out fact sheets and publications,” such as the map and chart below in a May report from ARCHES to DOE. ​“But those are still quite general and don’t give specifics about what each project is.”

The Ohio River Valley Institute has raised similar concerns about the ARCH2 project in Appalachia. In a May letter to DOE signed by 54 nonprofit and community groups, Tom Torres, the institute’s hydrogen campaign coordinator, said communities have had ​“no substantive opportunity to shape this proposal while negotiations continue behind closed doors.”

The saving grace, he wrote, is that ​“nothing so grievous has been done that cannot be undone. Money has yet to flow to these projects and ground has not been broken.” 

Giving communities authority over how major energy infrastructure is planned and built would be a departure from how large industrial projects have historically been pursued.

“There is this dichotomy, this tension, between the project development deadlines and long-term robust engagement processes that will be needed to meet these community benefits plans obligations and gain community trust,” said Mona Dajani, global co-chair of energy, infrastructure and hydrogen at law firm Baker Botts and lead counsel for the HyVelocity hub in Texas.

DOE’s commitment to ensuring that hubs will meet the Biden administration’s Justice40 Initiative — its pledge to direct at least 40 percent of climate-related federal spending to communities ​“historically impacted by energy development and burdened with policies of exclusion and disinvestment,” as Dajani put it — heightens the importance of community involvement.

This will ​“add a lot of complexity to development processes. But they’re doing their best. 

It’s definitely going to be challenging to be transparent when it’s not all finished,” Dajani said.

Will private-sector players commit to spending the money? 

Amidst questions around community benefits and lifecycle carbon emissions, much of the hype that fueled oversized clean-hydrogen projections in the past few years has started to deflate. Major project announcements have been delayed or put in limbo, leading analysts to question whether ambitious government clean-hydrogen production targets can be reached in the coming decade.

This retrenchment is also a threat to U.S. hydrogen hubs, which must convince companies and their financial backers to commit to the tens of billions of dollars of investment needed to scale up clean hydrogen to compete against the fossil fuels it is meant to displace.

That challenge is already rearing its head at the Appalachian ARCH2 hub, a pet project of a lawmaker key to getting the hydrogen hub program passed as part of the 2022 Bipartisan Infrastructure Bill — retiring Democratic U.S. Senator Joe Manchin of West Virginia.

Manchin praised the ARCH2 hub’s potential to revitalize the economy of his home state and the greater Appalachian region at an August event marking DOE’s approval of its first-phase grant. ​“I’m happy to know that I was able to play a part in this to be able to have a future for my children and grandchildren,” he said. 

But, as is true for all of the hub projects at this point, it’s far from clear that ARCH2 will deliver on its promise of becoming a clean energy economic engine for the region.

In a report released this week, the Ohio River Valley Institute noted that several projects initially identified as part of the ARCH2 plan have since dropped out. Those include Canadian gas producer and pipeline owner TC Energy and industrial chemicals giant Chemours, which canceled plans to develop two green hydrogen production sites in West Virginia.

“The various hydrogen hubs and their individual projects are much more tenuous than many people imagine,” Sean O’Leary, senior researcher at the Ohio River Valley Institute and the author of the report, told Canary Media. ​“These projects are still heavily dependent on private markets to come up with the funds.”

In an attempt to fill the gap left by those departures, ARCH2 recently issued a call for companies to propose projects, which could receive up to $110 million if selected. ​“Originally you could argue that we had projects that were seeking federal funds,” O’Leary said. ​“Now, we have federal funds seeking projects.”

Cummins said that OCED has anticipated that hub participants may drop out or be added throughout the early stages. ​“That’s OK. We don’t want a company that for any reason doesn’t want to participate to be stuck in something they don’t see as economically viable.”

At the same time, OCED will vet new entrants on the same criteria applied to those that initially applied: ​“Are they technically feasible? Do we see a path to financial viability? What does their workforce plan look like? And finally, what do their community benefits look like?”

In an email to Canary Media, T.R. Massey, spokesperson for Battelle, the research organization managing the ARCH2 hub, echoed a key refrain about the projects: ​“The important context to remember is these new hydrogen hubs, including ARCH2, have just entered the first phase.” 

One year in, U.S. clean hydrogen hubs face questions — and have few answers 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.

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.