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.

For years, utilities have grappled with how to handle the ever-growing number of solar and battery systems trying to connect to the lower-voltage grids that deliver power to customers. That’s especially true for midsize projects like, say, a solar array that might adorn the roof of a multiunit apartment complex or a community-solar project that generates power shared by hundreds of dispersed customers.

On the one hand, utilities have eyed such projects warily, fearing that if the solar panels or batteries inject too much power onto local circuits at moments when electricity demand is low, it might cause grid instability or safety problems. As a result, utilities have thrown up barriers that have delayed or halted grid connections.

But as advocates have been pointing out for over a decade, these distributed solar and battery resources can also be enormous assets: By holding back power when the grid doesn’t need it, and then sharing their extra power during periods of high demand, they can help alleviate grid strains and lower the cost of keeping the grid running for everyone.

It’s taken California regulators, utilities and clean-energy advocates nearly four years to hash out these conflicting ideas. But in mid-March, the California Public Utilities Commission approved new interconnection rules that take into account how, with the right structures in place, solar and solar-plus-battery systems can be more help than hazard to California’s overworked grid.

“This will open up opportunities for distributed energy resources to be designed in a way that aligns with grid needs,” said Sky Stanfield, an attorney who works with the Interstate Renewable Energy Council, the nonprofit group that’s been the main proponent of the new rules. ​“It’s a long time coming to recognize that distributed energy resources are a whole lot more helpful than they’re allowed to be — and that we don’t have to spend as much to upgrade the grid as a result.”

The ​“Limited Generation Profile option” just approved by the CPUC is a complicated set of regulations that determine how solar and solar-battery systems interact with the lower-voltage grids operated by California’s CPUC-regulated utilities Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.

Today, those utilities make a simplistic set of assumptions when they consider the potential impacts of a project on the lower-voltage grid systems that carry power from substations to homes and businesses, Stanfield said — basically, that each project is producing its peak output at the time of least electricity demand from customers.

That’s pretty much how all U.S. utilities calculate the risks of new generation connecting to their grids, she noted. But this assumption is likely to yield findings that exaggerate how likely a project is to inject too much power onto local grid circuits.

To eliminate those perceived risks, utilities have demanded that project developers pay for grid upgrades themselves or have prevented the projects from connecting at all. Since those grid upgrades can cost hundreds of thousands to millions of dollars and take years to complete, the result either way tends to stop projects in their tracks.

Allowing new solar and battery projects to support the grid

The CPUC’s new policy takes a different tack, one well suited to larger-scale projects that are more likely to trigger grid upgrades. It will allow solar and battery projects to modulate how much power they send to the grid with the help of either solar inverters whose power-control systems can reduce power output from moment to moment or batteries that can soak up excess solar power and inject it back into the grid later.

Limited Generation Profile projects would be able to use these capabilities to alter their grid injections during different periods of the day, based on a set of schedules they can choose from. Those scheduling options are derived from the grid data available in the maps of hosting capacity from Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. (Here’s a snapshot of PG&E’s hosting-capacity map for a downtown section of the central California city of Bakersfield, with circuit capacity represented in red, orange, yellow and green.)

Most utilities in the U.S. haven’t been ordered by regulators to collect the detailed and accurate local grid data needed to create these kinds of maps, Stanfield noted. In fact, the Interstate Renewable Energy Council has played a key watchdog role in alerting the CPUC to problems with these maps as they’ve been developed over the past decade, as well as in making them more useful for customers and project developers looking for good spots to connect to the grid.

Thanks to those improvements, California’s maps now contain accurate information on the hour-by-hour capacity of individual circuits.

With this data in hand, California’s three largest utilities and clean-energy project developers can finally agree on just how much power solar and battery projects can safely inject onto the grid during different periods of the day and night across each month of the year.

That amount may be close to zero during some stretches — say, on a circuit with many homes with rooftop solar systems during sunny and mild spring daylight hours, when self-generated solar power can exceed customer demand for electricity. Within those hours, Limited Generation Profile projects may export little or no energy at all.

But these ​“minimum-loading” conditions are relatively rare — and at other moments, that same grid circuit may be hungry for all the power it can get. That’s typically during hot summer and autumn evenings, when the state’s ample solar resources are fading away, yet electricity demand for air conditioning remains high — the same conditions that have caused statewide grid emergencies in recent years.

California’s power grid is struggling to deal with the wide swings between times when it has too much solar and times when all available resources still don’t provide enough electricity. In fact, the CPUC and state policymakers have made significant efforts to address this imbalance via state rooftop solar policy — which has reduced the value of solar delivered to the grid while promoting the value of batteries that can store power for when it’s needed — and with utility-scale power procurement policies, which have put gigawatts of batteries into operation over the past few years to store solar power for those evening hours when demand exceeds supply.

But until now, utility interconnection policy ​“has not taken into account, or enabled, distributed energy resources to differentiate when they produce power and when they don’t,” Stanfield said. That’s left interconnection policy misaligned with broader state policy imperatives for how best to use solar systems and batteries, she added.

It’s also put interconnection policy at odds with policy efforts to better manage growing distribution-grid costs, Stanfield noted. Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric are facing tens of billions of dollars of additional grid investment in the coming decades to supply the millions of electric vehicles, heat pumps and electric appliances that the state is asking consumers to adopt in order to reduce carbon emissions.

“Grid upgrades are expensive,” Stanfield said, ​“and we want to avoid them where we don’t need them” — particularly in cases where new solar and battery systems could actually help reduce grid strains.

Even more fundamentally, rules that bar more solar and battery power from reaching the grid based on outdated and inaccurate methods of determining their grid impacts will rob customers at large of the value those projects could provide.

That’s the conclusion reached by Amin Younes, an electric distribution planning and policy engineer with CPUC’s Public Advocates Office, which represents utility customers’ interests. Younes studied the potential for the Limited Generation Profile option to add more clean energy to California’s grids during hours when energy is in short supply.

This graphic from a presentation of his work indicates how widely the capacity of a typical distribution grid circuit can vary from hour to hour. In this case, limiting a solar or battery project to the minimum loading condition — the red line on the chart — would have forced a project to be sized to deliver no more than 1.5 megawatts of power of maximum capacity. But during many more hours of the year, that circuit could accept far more than that — often more than twice that minimum limit, or more than 3 megawatts of power.

According to his analysis, factoring in that extra capacity across the distribution circuits of all three utilities could add up to tens of billions of dollars per year in additional clean energy that could be delivered. And because that power would supply the grid at hours when electricity costs and threats of grid emergencies are the highest, that ​“could lower costs and increase grid reliability,” he said in an interview.

Finally, implementing the Limited Generation Profile option should allow solar and battery developers to avoid having to pay for grid upgrades and give them a much faster interconnection process, Stanfield said. And, if it works as planned, it could be a useful model for other states to follow.

Solving grid-interconnection challenges across the country

In a 2021 blog post, the Electric Power Research Institute, a nonprofit power-sector research group involved in a wide variety of utility technology projects, highlighted the need for more flexible interconnection policies across the U.S. to prevent the tens of billions of dollars of forecasted investment in EV charging, distributed solar and battery backup systems from being stalled out by grid constraints.

The conservative, expect-the-worst approach that most utilities take with interconnection processes may be a way to maintain grid reliability, the institute noted. But it can also ​“lower customer satisfaction and slow progress toward renewable energy targets.”

It’s important to distinguish the problems plaguing this class of clean energy from the similar but distinct issues blocking hundreds of gigawatts of utility-scale wind and solar farms from connecting to transmission grids across the country. The Interstate Renewable Energy Council’s work in California and other states has focused mainly on distribution grid interconnection policies, which cover everything from rooftop solar systems and home battery and EV charging installations to multi-megawatt solar and battery projects.

While these types of interconnection problems can stymie even smaller-scale home rooftop solar systems, the bigger challenges tend to arise with larger-scale installations like community-solar systems that generate power for many different customers (in California, for example, most projects under 1 megawatt in generation capacity aren’t responsible for paying for grid upgrades). In many states, growing grid-upgrade costs and maddeningly slow interconnection timelines have become increasingly significant roadblocks to connecting these mid-sized projects.

In Minnesota, solar and consumer groups are fighting a utility policy that can assign hundreds of thousands of dollars in grid-upgrade costs to relatively small rooftop solar and community ​“solar garden” projects. In the community-solar-rich state of Massachusetts, some developers are stuck waiting for years for grid studies to allow projects to move forward. 

States including New York, Minnesota and Massachusetts have begun to explore flexible interconnection policies — the more general term for the approach California is taking, according to Stanfield — but only through pilot projects or laborious ​“non-wires solutions” programs run by utilities. They have yet to embrace a standard way for clean energy developers to work with utilities.

Most other U.S. utilities haven’t been compelled by state law and regulatory mandates to produce the detailed distribution-grid-level data collection and hosting capacity analyses that enable the CPUC’s Limited Generation Profile approach, Stanfield noted. But these kinds of tools are starting to be developed in other states. That’s an important precursor to enable flexible interconnection, she said.

Can ​“flexible interconnection” expand community solar and batteries? 

To be fair, utilities have very good reasons to take a conservative, safety-first approach to interconnection. After all, they’re responsible for keeping grids safe and reliable — and distributed energy resources represent potential disruptions to those grids that utilities can’t directly control.

That’s why California’s Limited Generation Profile option won’t go into effect until nine months after certain power-system control technologies are certified by the Underwriters Laboratory standards organization as being able to reliably perform according to schedule. That’s expected to happen sometime within the coming year, Stanfield said.

Utilities have also been concerned that changes on their grids could leave circuits susceptible to dangerous conditions. CPUC’s new policy does allow utilities to curtail a project during emergencies or request a change to the project’s schedule in the highly unlikely circumstance of a ​“sustained load reduction” on a grid circuit — namely, if a major customer using that circuit closes down and permanently reduces electricity demand.

But under the new rules, utilities are largely required to honor the schedules they’ve agreed to with solar and battery projects, and to take on reasonable costs of grid upgrades to manage them. That’s a vital feature for any successful flexible-interconnection process, Stanfield said, because project developers secure investment for projects based on some level of certainty about how much power they’ll be able to sell over the project’s lifetimes.

Any utility program that injects too much uncertainty into that prospect — by, for example, retaining the right to unilaterally curtail a project’s grid exports without a clear and provable grid problem to justify it — won’t work for developers, she said.

“A flexible interconnection solution, if it’s modeled and can show what the impacts are going to be, might give developers a lot more certainty and more comfort,” said David Gahl, executive director of the Solar and Storage Industries Institute, during a November event held by the Interstate Renewable Energy Council. That nonprofit is leading a flexible-interconnection pilot project in New York state that’s funded by The U.S. Department of Energy’s Interconnection Innovation e-Xchange program.

Utopia Hill, CEO of Reactivate, a joint venture developing community-solar projects for disadvantaged communities, also noted at the November event that the key to future flexible-interconnection processes is increasing their predictability. ​“If we can’t get financing parties comfortable with that, we can’t get the funding to build the projects,” she said.

It’s still not clear if the CPUC’s Limited Generation Profile rules will meet that need for California solar and battery developers, said Kevin Luo, interconnection policy advisor for the California Solar & Storage Association trade group. One big question is whether the scheduling options approved by the CPUC will actually allow developers to design moneymaking projects.

“That’s one of the reasons why we pushed so hard for customers to be able to pick their own schedules,” he said — an option that the CPUC denied. ​“Nobody has done the forecasting work necessary to have the confidence in any one schedule.”

Nor are California’s solar policies and market dynamics aligned to support the 1-megawatt-and-up projects that the Limited Generation Profile option would be best suited to, Stanfield said. California lacks effective policies to promote the development of multi-megawatt, distribution-grid-connected community-solar projects or large-scale rooftop solar projects on warehouses or apartment complexes that would be eligible for the new interconnection treatment — although solar and environmental-justice groups are pushing regulators and lawmakers to change that.

Even so, Stanfield said, starting with a schedule-based approach at least begins to align utilities’ grid needs with the imperative to add far more solar and batteries to California’s grid. That way, ​“you can start to get some of the benefits now — and then we can build on that further.” 

California’s new rules allow solar and batteries to help out the grid 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.

One of California’s marquee programs for cleaning up transportation emissions is at a crossroads. Decisions made in the next few months could set the decade-and-a-half-old Low Carbon Fuel Standard on one of two very different paths.

One path, favored by fossil fuel and renewable natural gas interests, would lock in a market scheme that currently extracts billions of dollars per year from Californians at the pump and subsidizes crop-based and cow-manure-derived biofuels.

That would be a disaster, according to environmental advocates, who point to a growing body of scientific evidence showing that this approach, if extended until 2045 as proposed, would cause these biofuels to grow at a scale that would harm the climate and the environment.

The other path, proposed by environmental groups, transportation-decarbonization analysts and climate and energy researchers, would limit the scope of unsustainable biofuels in the program, and instead reorient it to support what experts agree should be California’s primary clean transportation pathway: electric vehicles.

To date, roughly 80 percent of LCFS funding has gone to combustion biofuels rather than electric vehicles. That’s simply incompatible with the state’s EV ambitions and needs, said Adrian Martinez, deputy managing attorney of nonprofit advocacy group Earthjustice — and the imperative to reduce emissions from transportation, which account for nearly 40 percent of the state’s greenhouse gas emissions.

“We’ve got to eliminate our reliance on combustion,” he said, but ​“the program as designed will continue to provide lucrative incentives for combustible fuels well into the future.”

The regulator in charge of the LCFS program — and this high-stakes decision — is the California Air Resources Board. CARB’s board, which comprises 14 voting members, 12 appointed by the governor and two by the state legislature, holds a host of responsibilities around California’s energy transition. Those include shaping the state’s nation-leading EV policy, as well as determining its broad plans for achieving long-term greenhouse-gas reduction goals.

Critics say the LCFS program’s increasing support for biofuels is in direct contrast to both the EV targets and the climate goals also overseen by CARB — and that the program has been captured by deep-pocketed industries trying to greenwash the continued use of combustion fuels.

CARB has a chance to reform the program with an upcoming vote, initially set for this month, but now postponed to an undetermined future date. But its pathway to fixing the problems that plague LCFS is murky and messy at best.

Right now, the staff managing the LCFS program hasn’t given CARB board members an opportunity to pick a climate- and EV-friendly alternative. Instead, a December staff proposal provides only one option for the board to vote on later this year: a set of policies that Earthjustice forecasts would direct $27 billion over the coming decade toward biofuels and worsen effects on the climate, the environment and the prices that Californians pay at the pump.

CARB does have another option, however — an alternative proposal laid out by CARB’s Environmental Justice Advisory Committee, created to advise the board on environmental-justice issues.

That proposal would cap the fast-growing share of crop-based renewable diesel flooding the state. It would also end the unusual structure that now allows biogas produced by dairy farm manure to offset a much higher amount of carbon emissions than any other source of alternative fuels.

And, importantly, it would make the core of the program — its carbon-offset marketplace — function in a much healthier way, proponents say. A torrent of cheap, polluting renewable diesel and dairy farm biogas credits have dragged down the price that LCFS credits can fetch for avoiding emissions, diluting the incentive to deploy new climate technologies and sapping what could be a key funding source for EV infrastructure in the state.

“The stakes are very, very high,” Martinez said. ​“That’s why you see so much attention focused on this — and a very broad and diverse coalition that is pushing for more systemic change to the program, versus more modest tweaks that will really just keep this market owned and dominated by fossil fuel interests.”

A history of the LCFS program

California’s Low Carbon Fuel Standard was born out of AB 32, the 2006 law that created the state’s carbon cap-and-trade market. Much like carbon markets, LCFS is meant to make companies pay for their carbon emissions by buying credits from technologies that reduce carbon emissions.

The program requires all fossil fuels refined and sold in California to meet increasingly stringent carbon-intensity targets. In practice, fossil fuel producers have to buy a bunch of LCFS credits from low-carbon transit sources operating in the state in order to comply. The goal is to create a system that taxes planet-warming fossil fuels to fund cleaner transportation alternatives.

But the LCFS has strayed from its initial focus on vehicle electrification and ​“advanced” non-crop-based biofuels to become ​“a swag bag for venture capitalists, big oil, big agriculture, and big gas, increasingly coming at the expense of low- and moderate-income Californians.” That’s how Jim Duffy, a 13-year veteran of the agency who served as branch chief of the LCFS program from 2019 to 2020 and retired in 2022, described the evolution of the program in comments filed with CARB.

Under the LCFS regulation adopted in 2009, dairy-manure-to-biogas projects did not receive special treatment compared to other sources of methane such as landfills and sewage treatment plants, Duffy wrote. Similarly, diesel fuels made from crops like soybeans were considered ​“only marginally better than fossil diesel.”

But in the years since, ​“the LCFS was revised to provide additional and unnecessary support to landfills and first-generation crop-based biofuels” and ​“to mitigate the methane problem created by the dairy industry itself,” Duffy wrote — despite the fact that evidence increasingly suggests that both sources harm the planet far more than they benefit it.

The result has been an increasing share of LCFS credits being supplied by renewable diesel and dairy-generated biogas. 

CARB has justified these shifts with analysis indicating they will yield net positive climate impacts.

“The proposed amendments now under consideration will directly increase the program benefits in the most burdened communities, by reducing the carbon across the supply chain for fuels sold in California, as well as improving public health for fuels sold in California,” CARB spokesperson Dave Clegern said in an email to Canary Media. He cited data from CARB staff’s analysis of its proposal indicating that, by 2045, its plan will reduce nitrogen oxide emissions by 25,586 tons, cut greenhouse gas emissions by 560 million metric tons and yield public-health cost savings of nearly $5 billion. 

But critics say the agency is failing to account for the full scope of climate harms that will be caused by its continued emphasis on biofuels.

They warn that the sheer scale of California’s program — totaling some $4 billion per year — is driving investment in the wrong transportation alternatives. The consequences are dire, they say — not just within the state, but across the country and around the world.

Why renewable diesel is threatening CARB’s climate and credit goals

Take renewable diesel, a fuel made from fats and oils processed to be identical to fossil diesel fuel. The U.S. increased production of the fuel by 400% between 2019 and 2022, and it is set to double it again this year, according to Jeremy Martin, senior scientist and director of fuels policy for the Union of Concerned Scientists.

Unlike ethanol and biodiesel, which can only partially replace gasoline and diesel, renewable diesel has ​“no limit on how much can be blended,” Martin said. It could theoretically completely replace diesel fuel for trucks, buses and other vehicles. And California’s LCFS offers credits on top of the federal incentives the fuel receives, making the state the primary target of renewable diesel producers across the country.

As a result, the share of renewable diesel as a percentage of total diesel fuel use has skyrocketed in California compared to the rest of the U.S., as the chart below shows.

In a September meeting, Steven Cliff, CARB’s executive officer, highlighted a milestone for the LCFS program: As of mid-2023, California had ​“more than half of our diesel demand being met by non-petroleum-based diesel alternatives. This is a direct result of the LCFS program, and it’s bringing real climate and air-quality benefits to the state.”

In Martin’s view, that milestone is not a win, but a warning. It indicates that renewable diesel is ​“flooding the LCFS, drowning the policy — and it doesn’t make sense” on climate or environmental terms.

Once the demand for renewable diesel outgrows the supply of waste oils and other non-crop feedstocks that can be used to make the fuel in genuinely climate-friendly ways, it becomes highly likely that it will cause more greenhouse gas emissions than it will displace. Critics like Martin argue that demand has now reached this point, though it’s a contested question.

This additional demand for crop oils could mostly serve ​“to expand the cultivation of palm oil to replace the soybean and other oils made into fuel,” the Union of Concerned Scientists argued in comments to CARB. That, in turn, is likely to lead to more rapid deforestation in nations that produce large amounts of these crops, such as Brazil and Indonesia — an outcome that would cause far greater climate harms than whatever emissions reductions result from replacing fossil diesel.

To stop this, the Union of Concerned Scientists and other groups want CARB to set a limit on how much renewable diesel can receive LCFS credits. CARB staff’s proposal declines to set such a cap, citing renewable diesel’s climate and health benefits.

But CARB’s methodology is out of step with the latest science, according to multiple groups studying these issues. The Union of Concerned Scientists, for its part, says CARB’s analysis is ​“based on inaccurate claims of climate and air-quality benefits and associated health outcomes.”

In a recent comparison of five different models for evaluating the climate impacts of crop-based biofuels, the U.S. Environmental Protection Agency found that only CARB’s own model shows a positive carbon-reduction impact.

And while the agency has a proposal to limit deforestation harms by setting ​“sustainability guidelines” for crops being used for renewable diesel, it applies only to feedstocks grown in the U.S., Martin noted. That’s a problem: California is on pace to consume 10 percent of global soybean oil supplies for renewable diesel, meaning a significant amount of the crop oil produced for the program will be grown under conditions CARB cannot police, he said.

Given that reality, Martin said, ​“If California declines to act — if they say, ​‘This is evidence of success; look how little fossil diesel we’re using’” by replacing it with renewable diesel, ​“then, in fact, California is giving its support to a fuel that we know is unsustainable at these volumes.”

California’s biofuel bias is hampering its EV future. Can that change? 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.

Last month, utilities in New York state submitted plans for 13 pilot projects meant to replace fossil-gas pipelines with infrastructure that can power clean, carbon-free heat pumps.

These underground thermal networks range from dense midtown Manhattan commercial centers to low-income housing, and from neighborhoods in the Hudson Valley to the upstate town of Ithaca.

But the projects, spurred by a 2022 state law that puts New York on the cutting edge of a decarbonization strategy now being explored by a growing number of states, share a common goal: to cut fossil fuels and carbon emissions out of the gas utility business, while still carving out a role for those utilities in the decades to come.

That work will still involve digging trenches, laying pipelines and installing equipment — the same kind of capital investments that earn gas utilities long and stable rates of return today. But instead of flammable and planet-warming gas, those pipes will carry water or other liquids that transfer heat from underground — or from other buildings and sources in the network — that can be used by heat pumps to keep buildings warm.

Heat pumps, which operate like reversible air conditioners, are much more energy-efficient than fossil-fired furnaces or boilers. They’re even more efficient when they can exchange heat and cold with fluid at a stable temperature, rather than from cold outside air, as the more common air-source heat pumps do.

The U.S. Department of Energy estimates that ground-source heat pumps reduce energy consumption and emissions by up to 44 percent compared to air-source heat pumps and 72 percent compared to standard air-conditioning equipment.

Capturing and sharing waste heat from thermal energy networks can increase efficiency even further. That, in turn, can cut the electricity bills of customers, which will rise as they switch from gas to electric heating.

But most building owners would struggle to afford the cost of drilling boreholes and installing pipes for their own geothermal heat pump systems, or to craft contracts with their neighbors to build and share underground networks. That’s why New York’s approach to adapting the gas utility infrastructure holds so much promise. Doing so will help all those individual homeowners and businesses share in the costs and reap the rewards, said Lisa Dix, New York director for the nonprofit Building Decarbonization Coalition.

Her team led an effort to rally utility labor unions, environmental groups and community organizations behind the 2022 law, called the Utility Thermal Energy Network and Jobs Act. These groups have since coalesced into a coalition called UpgradeNY that hopes to see these pilot projects serve as a model for a statewide conversion.

The newly proposed projects in New York are meant to offer a ​“clear understanding of neighborhood scale thermal energy networks,” she said, ​“so that as the transition happens, we can get to the scale we need to get to.”

The projects could also help serve as an early blueprint for the other half dozen or so states pursuing or exploring this method of decarbonization, she said. ​“We’re going to have to stop digging the hole, stop subsidizing the expansion of the fossil fuel system.”

New York’s pilot projects 

By design, the 13 pilot projects in New York cover a variety of different neighborhoods.

UpgradeNY has endorsed 11 of the projects but is asking the New York Public Service Commission to review the remaining two, one on Long Island and another in the city of Buffalo, that would continue to use fossil-gas-fired boilers for high-temperature heat.

Con Edison, the utility serving New York City and Westchester County, has proposed three projects taking on some of the most challenging urban settings, including the landmark Rockefeller Center.

For that project, Con Ed plans to convert three large commercial buildings from the utility’s district steam-heating network to heat pumps. These heat pumps would draw on water that’s warmed up by waste heat from sources including the sewers, data centers and adjoining buildings’ cooling systems. 

“There are some misconceptions out there — people think you have to drill a million boreholes” to capture underground heat, Dix said. ​“But you can get your heat from different [underground sources]. You can get it from the subway. You can get it from the sewer. And it’s going to help decarbonize Con Ed’s steam system if we do it right.”

Real estate company Tishman Speyer, the owner of 30 Rockefeller Center, is a key partner in the project, she noted. The firm has a strong incentive to participate because the project could lower the cost of complying with New York City’s Local Law 97, which requires all large buildings to reduce their carbon emissions by 40 percent from 2019 levels by 2030.

Hitting those targets will require an estimated $18.2 billion in investment in alternatives to fossil-gas-fired boilers and furnaces. Shared networks could significantly reduce the cost to individual buildings, but property owners ​“don’t want to deal privately with all that permitting — they want the utility to deal with all that,” Dix said.

Another Con Ed project in Manhattan’s Chelsea neighborhood plans to get 100 % of heating, cooling and hot-water needs for a low-income multifamily residential building from a nearby data center. ​“We can have a data center literally heating an entire multifamily building or a big skyscraper,” Dix said.

Other projects on the list will test how thermal energy networks can link residential and commercial buildings in less dense environments. Those include a project by utility NYSEG in the city of Norwich that will connect homes and buildings to underground networks and waste heat from a grocery store’s refrigeration system, and a project by utility Orange & Rockland in the town of Haverstraw that will build two networks — one serving new waterfront construction, and the other municipal and school district buildings — that are close enough to be linked together in future expansions.

Dix highlighted a project that utility NYSEG has proposed in Ithaca, which in 2021 became the first U.S. city to pledge to completely decarbonize its buildings by 2030. It’s also the home of Cornell University, which has a district heating, cooling and cogeneration system that now uses fossil gas, but which the university hopes to convert to geothermal power. 

How thermal energy networks could transform the gas utility business

New York is an early leader on this front, but thermal energy networks are gaining ground across the country.

Today, three other states — Colorado, Massachusetts and Minnesota — have passed laws that allow or mandate gas utilities to undertake thermal energy network pilot projects. In Massachusetts, the first utility-built network, covering 32 residential and five commercial buildings and 140 customers in the city of Framingham, is expected to be complete in the next few months.

Other states including Illinois, Maine, Vermont and Washington are exploring similar laws. And 13 gas utilities have created a Utility Networked Geothermal Collaborative to explore options.

To be clear, thermal energy networks, also called geothermal networks or geo-districts, aren’t a new idea. A number of cities, colleges and corporate campuses in Europe, Asia and North America use district energy systems — shared steam or hot water exchange networks — for heating and cooling needs, and many of them aim to switch from fossil fuels to zero-carbon electricity. In the U.S., geothermal networks that tap into underground heat, cool water from nearby lakes or waste heat from sewers and other buildings are proving the efficiency and cost benefits of the concept.

But gas utilities are an ideal party to carry out thermal energy networks at scale, said Audrey Schulman, co-executive director of the Home Energy Efficiency Team (HEET), a Cambridge, Massachusetts–based group that helped spur the state’s first such pilot projects by utilities Eversource and National Grid, including the project in Framingham.

First, gas utilities have the workforce, expertise and access to capital needed to build the sprawling and interconnected underground networks required, she said. Second, they’re already spending billions of dollars per year on fossil-gas pipeline expansions and repairs that will inevitably become ​“stranded assets” long before their costs are paid back by customers.

In Massachusetts, the state’s six investor-owned gas utilities plan to spend more than $40 billion on a Gas System Enhancement Program to replace the roughly 22 percent of gas lines in the state that are prone to leaks, she said. Customers pay the cost of those investments via increases on their bills that can persist for decades — far past the state’s deadline to reduce greenhouse gas emissions by 85 percent from 1990 levels by 2050.

The state’s push toward thermal energy networks will likely be accelerated by a December decision from the Massachusetts Department of Public Utilities to reject gas-utility decarbonization plans that relied too heavily on alternative fuels like hydrogen and renewable natural gas. Beyond that, the department’s ​“beyond gas” order calls for ​“minimizing additional investment in pipeline and distribution mains” and specifically calls out thermal energy networks as an alternative.

“The whole thing is about setting up the regulatory structure by which we get off gas and onto something else,” Schulman said.

New York faces similar choices as it works to implement its 2019 climate law that calls for cutting fossil gas use by at least one-third by 2030 and converting the ​“vast majority” of customers to electric heating by 2050, Dix said. Despite these imperatives, gas utilities in the state have spent $5 billion on infrastructure investments and identified $28 billion in pipeline replacement plans since the law’s passage.

This disconnect between climate imperatives isn’t limited to Massachusetts and New York. Consultancy Brattle Group found in a 2021 report that U.S. gas utilities may face $150 billion to $180 billion of ​“unrecovered” investment in pipelines over the coming decade. States including California and Colorado have set policies to limit expanding gas lines and to push gas utilities to transition customers to less-polluting alternatives.

Gas utilities across the country have largely fought such mandates or pushed proposals that rely on continuing to use their pipelines to carry carbon-neutral fuels such as biomethane or hydrogen. But a growing body of research indicates that these plans will likely falter due to the high cost and low availability of those alternative fuels.

At the same time, when looking for large-scale conversion of entire neighborhoods to low-carbon alternatives, ​“utilities make the most sense to do this,” Dix said. ​“They’ve got rights of way, they have the permitting authority, they have access to capital, and they have the workforce, which is already unionized.”

Like many other states with decarbonization mandates, New York has offered hundreds of millions of dollars in incentives for heat pumps and building electrification, and has imposed regulations limiting the expansion of fossil gas to new buildings.

But according to a 2023 report from the Building Decarbonization Coalition, this ​“house-by-house” approach could end up leaving gas utilities and regulators in a bind — being forced to maintain expensive gas distribution networks to supply fuel to a dwindling number of customers.

The customers that remain, meanwhile, will bear a greater and greater proportion of the cost of paying off those gas investments, leading to a vicious cycle of cost increases being imposed on people who can’t afford to make the switch to heat pumps on their own. These left-behind customers are more likely to be lower-income earners already struggling to afford increasingly expensive utility bills.

Thermal energy networks, by contrast, can be planned on a neighborhood-by-neighborhood basis, she said. That gives utilities and regulators an opportunity to target disadvantaged communities, areas with the most aged or leak-prone infrastructure, or other strategic approaches to shifting people from gas to electric heating and appliances en masse.

The efficiency benefits of these networks can also provide significant relief to power grids that will experience massive growth in demand from building heating and electric vehicles. Department of Energy research has found that installing geothermal heat pumps in nearly 80 percent of U.S. homes could reduce the costs of decarbonizing the grid by 30 percent and avoid the need for 24,500 miles of new transmission lines by 2050.

From pilot projects to statewide transformation 

Many steps remain for New York to bring these on-paper pilots into the real world, however.

First, each utility will have to negotiate with the customers involved in the pilots on how to share the costs of installing heat pumps and other new equipment. Then they’ll need to build the projects and get them up and running, track the performance of the equipment and underlying networks, and assess the cost-effectiveness of the projects.

Bringing down the cost of these projects will be an important first test. Heat pumps are more expensive than gas furnaces, and designing and constructing the pipes, boreholes and networked heat-exchange technologies involved will be more costly than standard gas infrastructure projects.

“There will be a marginal cost increase compared to business as usual,” said Matt Rusteika, Building Decarbonization Coalition’s director of market transformation. ​“But because you’re not buying the gas, and the gas is like half the bill, the cost for consumers would come down.”

Altering laws now on the books in New York, Massachusetts and other states to allow utilities to switch customers from gas to thermal energy network service without triggering ​“obligation to serve” objections will also be important, he said. Under those laws, ​“if the customer says ​‘I want gas,’ the utility has to give gas to them,” he said. That obligation is a core part of a utility’s mission, but its strict application could allow a single customer in a neighborhood slated for a thermal energy network to stymie the entire project.

In New York, the Utility Thermal Energy Network and Jobs Act suspends that law for the pilot projects now being considered, Dix said. But another law would need to be passed to extend that shift to the state at large. In Massachusetts, the Home Energy Efficiency Team and other environmental and community groups are endorsing a ​“Future of Clean Heat” bill that would make similar changes.

More complexities will emerge as utilities and regulators start to consider the methods for some members of a thermal energy network to exchange their waste heat with others, Rusteika said. ​“How you compensate people who provide it and those who use it is a more complicated question.”

For now, backers of thermal energy networks are waiting for the first pilot projects in Massachusetts and New York to provide the real-world testing grounds for answering these kinds of questions. Eversource’s first project in Framingham, Massachusetts is set to come online later this spring, he said. ​“We’re going to learn a lot about efficiency and functionality and comfort and cost from that pilot.” 

New York will replace gas pipelines to pump clean heat into buildings 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.