Back
Michael Gillogly, manager of the Pepperwood Preserve, understands the wildfire risk that power lines pose firsthand. The 3,200-acre nature reserve in Sonoma County, California, burned in 2017 when a privately owned electrical system sparked a fire. It burned again in 2019 during a conflagration started by power lines operated by utility Pacific Gas & Electric.
So when PG&E approached Gillogly about installing a solar- and battery-powered microgrid to replace the single power line serving a guest house on the property, he was relieved. “We do a lot of wildfire research here,” he noted. Getting rid of “the line up to the Bechtel House is part of PG&E’s work on eliminating the risk of fire.”
PG&E covered the costs of building the microgrid, and so far, the solar and batteries have kept the light and heat on at the guest house, even when a dozen or so researchers spent several cloudy days there, Gillogly said.
Over the past few years, PG&E has increasingly opted for these “remote grids” as the costs of maintaining long power lines in wildfire-prone terrain skyrocket and the price of solar panels, batteries, and backup generators continues to decline. The utility has installed about a dozen systems in the Sierra Nevada high country, with the Pepperwood Preserve microgrid the first to be powered 100% by solar and batteries. The utility plans to complete more than 30 remote grids by the end of 2027.
Until recently, utilities have rarely promoted solar-and-battery alternatives to power lines, particularly if they don’t own the solar and batteries in question. After all, utilities earn guaranteed profits on the money they spend on their grids.
But PG&E’s remote-grid initiative, launched with regulator approval in 2023, allows it to earn a rate of return on these projects that’s similar to what it would earn on the grid upgrades required to provide those customers with reliable power. The catch is that the costs of installing and operating the solar panels and batteries and maintaining and fueling the generators must be lower than what the utility would have spent on power lines.
“It all depends on what the alternative is,” said Abigail Tinker, senior manager of grid innovation delivery at PG&E. For the communities the utility has targeted, power lines can be quite expensive, largely due to the cost of ensuring that they won’t cause wildfires.
PG&E was forced into bankruptcy in 2019 after its power lines sparked California’s deadliest-ever wildfire, and the company is under state mandate to prevent more such disasters. PG&E and California’s other major utilities are spending tens of billions of dollars on burying key power lines, clearing trees and underbrush, and protecting overhead lines with hardened coverings, hair-trigger shutoff switches, and other equipment.
But these wildfire-prevention investments are driving up utility expenditures and customer rates. Solar and batteries are an increasingly cost-effective alternative, Tinker said, with the benefits outweighing the price tag of having to harden as little as a mile of power lines.
PG&E saves money either by getting rid of grid connections altogether or by delaying the construction of new lines. Microgrids can also improve reliability for customers when utilities must intentionally de-energize the lines that serve them during windstorms and other times of high wildfire risk — an increasingly common contingency in fire-prone areas.
Angelo Campus, CEO of BoxPower, which built most of PG&E’s remote microgrids, sees the strategy penciling out for more and more utilities for these same reasons.
“We’re working with about a dozen utilities across the country on similar but distinct flavors of this,” he said. “Wildfire mitigation is a huge issue across the West,” and climate change is increasing the frequency and severity of the threat.
Utilities are responsible for about 10% of wildfires. But they’re bearing outsized financial risks from those they do cause. Portland, Oregon-based PacifiCorp is facing billions of dollars in costs and $30 billion in claims for wildfires sparked by its grid in 2020, and potentially more for another fire in 2022. Hawaiian Electric paid a $2 billion settlement to cover damages from the deadly 2023 Maui fires caused by its grid.
Microgrids can’t replace the majority of a utility’s system, of course. But they are being considered for increasingly large communities, Campus said.
Nevada utility NV Energy has proposed a solar and battery microgrid to replace a diesel generator system now providing backup power to customers in the mountain town of Mt. Charleston. Combining solar and batteries with “ruggedized” overhead lines should save about $21 million compared to burying power lines underground, while limiting impacts of wildfire-prevention power outages, according to the utility.
Some larger projects have already been built. San Diego Gas & Electric has been running a microgrid for the rural California town of Borrego Springs since 2013, offering about 3,000 residents backup solar, battery, and generator power to bolster the single line that connects them to the larger grid, which is susceptible to being shut off due to wildfire risk. Duke Energy built a microgrid in Hot Springs, North Carolina, a town of about 535 residents served by a single 10-mile power line prone to outages, on the grounds that it was cheaper than building a second line to improve reliability.
In each of these cases, utilities must weigh the costs of the alternatives, Tinker said. “It’s complicated and nuanced in terms of dollars per mile, because you have to be able to do the evaluation of individual circuits, and what can be done to mitigate the risk for each circuit,” she said.
Whether microgrids are connected to the larger grid or not, utilities need to maintain communications links with them to ensure the systems are operating reliably and safely. PG&E is working with New Sun Road, a company that provides remote monitoring and control technology, to keep its far-flung grids in working order.
It’s important to distinguish remote microgrids built and operated by utilities from other types of microgrids. Solar, batteries, backup generators, and on-site power controls are also being used by electric-truck-charging depots and industrial facilities that don’t want to wait for utilities to expand their grids to serve them. Microgrids are also providing college campuses, military bases, municipal buildings, and churches and community centers with backup power when the grid goes down and with self-supplied power to offset utility bills when the grid is up and running.
Utilities have been far less friendly to customer-owned microgrids in general, however, seeing them as a threat to their core business model. Since 2018, California law has required the state Public Utilities Commission to develop rules to allow customers to build their own microgrids. But progress has been painfully slow, and only a handful of grant-funded projects have been completed.
Microgrid developers and advocates complain that the commission has put too many restrictions on how customers who own microgrids can earn money for the energy they generate when the grid remains up and running. Utilities contend that they need to maintain control over the portions of their grid that connect to microgrids to avoid creating more hazards.
“It is a very difficult balance that PG&E is constantly trying to strike, with the oversight of [utility regulators] and other stakeholders, between safety and reliability and affordability,” Tinker said. “That’s something we’re trying to thread the needle on.”
But as the costs of expanding and maintaining utility grids continue to climb, and solar and batteries become more affordable, utilities and their customers are likely to see more opportunities to make microgrids work, Campus said.
“The cost of building poles and wires and maintaining distribution infrastructure has grown substantially over the past 20 years,” he said. “Look at the cost of distributed generation and battery — it’s an inverse cost curve.”
A correction was made on Sept. 11, 2025: This story originally misstated PG&E’s timeline for installing more than 30 remote grids. The utility expects to install that number of systems by the end of 2027, not 2026.
Two of the leading startups working on advanced geothermal energy just struck deals with established industrial giants — moves that will help the companies accelerate their efforts to harness the potentially abundant source of carbon-free energy from underground.
Last week, Fervo Energy said it had picked oilfield services giant Baker Hughes to provide crucial equipment for the startup’s Cape Station geothermal plant in Utah, a selection that brings the 500-megawatt project closer to its 2028 completion goal. Baker Hughes will design and deliver equipment for five power-generating units totaling 300 MW in capacity, which will operate with Fervo’s fracking-based “enhanced geothermal system.”
The news followed an Aug. 28 announcement that startup Sage Geosystems is partnering with Ormat Technologies, a major global developer of conventional geothermal plants. The agreement will enable Sage to deploy its next-generation technology at one of Ormat’s existing sites in Nevada or Utah.
Teaming up with Ormat accelerates Sage’s timeline to build its first commercial power-generation facility by about two years. It’s now targeting to bring the plant online by late 2026 or early 2027, said Cindy Taff, CEO of Sage.
“For us, the ability to scale faster with Ormat is huge,” Taff told Canary Media. “But it’s also a great opportunity for Ormat to reach a deeper [geothermal] resource than what they’re targeting now.”
Geothermal energy represents only about 0.4% of total U.S. electricity generation — largely because existing technology is constrained by geography. Today’s geothermal plants rely on naturally occurring reservoirs of hot water and steam, found only in places like Northern California and Nevada, to spin their turbines and generate power.
Technological advances are making it possible to deploy geothermal in less obvious areas, breathing fresh life into the decades-old industry. In recent years, the carbon-free energy source has seen a surge of investment and bipartisan policy support amid soaring demand for electricity from data centers, factories, and electric vehicles.
Fervo and Sage, both based in Houston, have previously inked deals to supply the tech giants Google and Meta, respectively, with hundreds of megawatts of clean, around-the-clock power for their sprawling U.S. operations.
Next-generation geothermal also benefits from the fact that it shares the same workforce and supply chain as oil and gas companies, an industry now heavily favored in Washington, D.C. The sweeping budget law that President Donald Trump signed in July largely preserves key tax credits for geothermal power plants — despite slashing incentives for wind and solar — and the Trump administration is pushing to fast-track environmental reviews for all types of geothermal projects.
“Geothermal has always enjoyed support from both sides of the aisle,” said Taff, who was previously a vice president at fossil fuel company Shell. “But now there’s a lot of momentum for the industry.”
Sage’s approach to geothermal energy involves tapping into both heat and pressure from hot, dry rocks found deep underground. To start, the company drills wells and fractures rocks to create artificial reservoirs that it pumps full of water. Sage cycles the water in and out of the fracture — like inflating and deflating a balloon — and can jettison the liquid to the surface to drive turbines and produce electricity.
The startup’s partnership with Reno, Nevada-based Ormat will allow Sage to access land and power-plant equipment and to connect to the grid far more quickly than if the startup set up a new site on its own. The companies are looking to install the next-generation system at a facility where Ormat’s older conventional wells are declining in capacity.
“In general, plants may operate below capacity due to a combination of factors, such as changes in the geothermal resource over time,” said Smadar Lavi, Ormat’s vice president and head of investor relations and ESG planning and reporting. “These sites are well-suited for piloting Sage’s technology, as it offers the potential to unlock additional production from existing assets.”
Terra Rogers of the nonprofit Clean Air Task Force said that Ormat’s decision to expand beyond its traditional hydrothermal resources and into next-generation tech represents “an important step, and we’ve all been waiting for it.” Rogers, who leads the advocacy group’s superhot rock geothermal program, called Ormat the “grandparents of geothermal,” given that the company has been around for 60 years and operates more than 190 geothermal plants globally.
As part of the agreement, Ormat can license Sage’s technologies for power generation as well as energy storage. The startup uses a similar setup to store excess grid energy. But instead of drilling deep into high-temperature rocks, Sage pumps water into shallower formations that aren’t as hot, since heat isn’t needed for storage. Pressure builds up underground and can be released later, when power demand spikes, to spin a pinwheel-like Pelton turbine and send electricity back to the grid.
“The idea that [Ormat] chose Sage specifically, with their storage technology, is also very telling for the needs of the grid in the West,” Rogers said, adding that it “complements existing or intermittent forms of renewables” like wind and solar.
Sage recently finished building its first commercial storage project on the site of a coal plant owned by San Miguel Electric Cooperative in Christine, Texas. The facility, which is expected to connect to the Texas grid in December, will be able to discharge 3 MW for four to six hours at a time, according to Taff.
The startup plans to perform a demonstration of its electricity-generating tech in the first quarter of 2026 in Starr County, Texas, in partnership with the U.S. Air Force. Sage is also evaluating potential sites east of the Rocky Mountains to develop its 150-MW project with Meta.
Fervo, meanwhile, continues drilling away at its Cape Station project in Beaver County, Utah, which has been under construction for almost two years.
The eight-year-old company said an initial 100-MW installation is poised to start delivering power to the grid in 2026. An additional 400 MW is slated to come online in 2028, a portion of which will use the new equipment from Baker Hughes. The startup’s recent supply deal comes just months after Fervo said it secured $206 million in new financing for the Cape Station project.
“Fervo designed Cape Station to be a flagship development that’s scalable, repeatable, and a proof point that geothermal is ready to become a major source of reliable, carbon-free power in the U.S.,” Tim Latimer, Fervo’s CEO and cofounder, said in a Sept. 2 statement.
Three bills have advanced through the California Legislature that are meant to increase the use of virtual power plants as a way to rein in energy costs. While good news for utility customers, that welcomed progress comes with its own dose of bad news: The most ambitious proposals were stripped out of one of the bills in a secretive process inaccessible even to the bill’s author.
Two of the bills, AB 44 and AB 740, cleared a key legislative hurdle with only minor alterations that will not significantly reduce their impact, according to Edson Perez, who leads California legislative and political engagement for clean-energy trade group Advanced Energy United.
But SB 541, the most pioneering of the three bills in question, was “gutted” last week via an opaque legislative maneuver, Perez said. Those amendments stripped the bill of important provisions that would have required the state’s biggest utilities to provide data to enable them to build virtual power plants into their grid investment plans.
Those provisions “would have helped California get the most out of its existing grid while saving ratepayers billions,” Perez said. “At a time of skyrocketing electricity bills and reliability challenges, California can’t afford to sideline tools that make the grid cleaner, more resilient, and more affordable.”
California has the highest electricity rates in the nation outside of Hawaii. Virtual power plants, which stitch together distributed energy like rooftop solar, home batteries, and EVs, can’t solve that problem on their own. But they can certainly help: A new report from think tank GridLab and Kevala, a grid-data analytics startup found that California could cut energy costs for consumers by $3.7 billion to $13.7 billion in 2030, compared to a base case, by using home batteries, EV chargers, and smart thermostats to avoid or defer costly upgrades to power lines and other infrastructure.
The changes made to SB 541 will dramatically reduce the savings it could offer, according to Sen. Josh Becker, the Democrat who authored the bill and chair of the Senate energy committee.
“We’re very disappointed,” he said.
The bill still includes measures to spur utilities to expand their use of VPPs, “so we can avoid overbuilding to meet the highest peaks in demand,” he said. “But we’ve missed an opportunity to do so much more by focusing on the other half of the problem — all this spending on upgrading poles and wires that can be avoided if we take better advantage of distributed energy resources.”
Becker said he didn’t know who was responsible for excising that portion of the bill or why they did it. The amendments were introduced during a process known as “suspense,” during which the Legislature’s appropriations committees can amend or shelve bills with no debate or transparency into how changes are made or by whom. Last Friday’s process ended up culling more than a quarter of the 686 bills under consideration, including high-profile ones like a proposal to streamline permitting for high-speed rail.
“We’re pursuing every avenue to keep that language alive,” Becker said of the removed text. But there’s little time for lawmakers to secure revisions before Sept. 12, the last day for the Legislature to pass bills this year.
For a handful of hours every year in California, often on the hottest days, electricity use soars beyond the usual day-to-day level and hits what’s known as peak demand. To meet these peaks, utilities have historically opted to build more power plants and power lines than they need on a daily basis — an expensive choice that is responsible for a large portion of utility bills.
But California can reduce demand peaks and make a big dent in those costs by taking advantage of solar-charged batteries, smart thermostats, EV chargers, and other devices scattered across homes and businesses. Individual customers are compensated for allowing the rest of the grid to use their energy resources, but if done right, a VPP’s benefits outweigh those payments.
A 2024 analysis from The Brattle Group found that VPPs could shave about 15% of California’s peak demand by 2035, saving utility customers about $550 million each year. Most of those savings would flow to those whose clean energy assets are enrolled in the programs, but customers at large would also see costs decline because utilities wouldn’t have to build as much infrastructure.
California badly needs to cut those costs. Average residential electricity rates in the state increased 47% from 2019 to 2023 and now stand at nearly twice the national average, largely driven by the effort to prevent power lines from sparking deadly wildfires. Pressure to expand power grids to serve data centers, EV charging, and home electrification is set to push rates higher still.
In the face of these rising costs, “making better use of what’s already on the grid rather than building something from scratch is a pretty important consideration,” said Ryan Hledik, a principal at Brattle and lead author of the study.
But California is not on track to meet its VPP targets. In 2023, the California Energy Commission (CEC), acting to comply with a law passed the previous year, set a “load-shift” goal of 7 gigawatts by 2030 for the state. But the CEC’s June progress report found that California’s demand-flexibility capacity barely grew over the past two years and remains at just over 3.5 gigawatts, or about half the 2030 goal.
The state isn’t likely to reach its 7-GW target under “business-as-usual” conditions, the CEC report found. That’s especially true if the policymakers decide to eliminate programs created after grid emergencies in 2020 and 2022, which have grown fastest in recent years compared to utility-managed VPPs. The report concludes that California needs “additional near-term strategies” to close the gap.
SB 541 was designed to help fill that gap.
In particular, the bill was meant to do two main things to incorporate load flexibility into how California manages its grid costs, Becker explained: Track progress toward state goals and embed VPPs into how the state’s major utilities invest in their power grids.
The amended bill still requires the California Energy Commission to create regulations to track the progress toward the 7-GW goal by utilities, community energy providers, and other “load-serving entities” supplying power to customers. “We need to know which load-serving entities are doing a good job of it, and learn from the best practices,” Becker said.
But the original version of SB 541 also called on the California Public Utilities Commission to create regulations to require the state’s three major utilities to share data on their low-voltage distribution grids, and use that data to discover how VPPs can reduce the cost of managing that infrastructure. Last week’s amendments entirely cut this portion of the bill.
Brad Heavner, executive director of the California Solar and Storage Association trade group, said that’s a missed opportunity. Today’s VPPs and demand-response programs are triggered to reduce pressure on the state’s transmission grid and generator fleets when energy demand exceeds supply, he said. In other words, they’re “focused on times when we may not have enough energy statewide,” which is “obviously important.”
But as originally written, SB 541 would have required a more proactive approach that integrates VPPs into grid planning.
“From an affordability perspective, most of the reason our rates have increased is due to utility overspending on the distribution grid,” he said. “VPP programs should be equally focused on using networked batteries to avoid the cost of expanding substations and other big infrastructure.”
Getting utilities to do this has been a longtime challenge. For more than a decade, California regulators have been under state mandate to press utilities to integrate rooftop solar, batteries, and other distributed energy resources — DERs in industry parlance — into how they invest in and manage their grids.
But as Hledik told a California Assembly committee in July in testimony supporting SB 541, “attempts to use load flexibility as a distribution system resource have had limited success.” Existing programs aimed at requiring utilities to seek out DERs that can replace or defer grid investments have failed to result in any significant projects.
SB 541 was designed to overcome those previous pitfalls, Hledik said, by requiring that “load flexibility opportunities be considered earlier and more comprehensively in distribution planning.”
The other VPP bills don’t take on distribution grid costs. AB 740 would require the CEC to adopt a virtual power plant deployment plan by November 2026, in collaboration with state grid operator CAISO, the utilities commission, and an advisory group representing disadvantaged communities.
”It doesn’t require them to implement anything specifically,” said Perez of Advanced Energy United. “But it does require that cross-agency deep dive that is just not happening right now.”
AB 44, which Advanced Energy United also supports, is “more surgical,” Perez said. It would order the CEC to adopt a method to value VPPs as a means of reducing “resource adequacy” requirements — the calculation of the grid resources needed to meet peak demand in future years.
Resource adequacy costs are rising across California. A handful of community choice aggregators (CCAs), the city- and county-level entities that procure clean energy for a growing number of the customers of California’s big three utilities, have worked with CEC to prove that their VPPs function well enough to count toward resource adequacy. The CEC has then reduced their requirements accordingly, which has allowed CCAs to cut their customers’ energy bills.
That’s a useful route to capturing the value of VPPs, Perez said. But it’s largely been done on an ad-hoc basis to date, and “there’s no clear process” for other CCAs to follow suit, he explained. “AB 44 tries to make that process more transparent.”
None of the bills have passed yet. If they can clear the Legislature by mid-September, Gov. Gavin Newsom (D) will have until Oct. 12 to sign the legislation into law.
This isn’t state lawmakers’ first attempt to pass VPP bills.
Similar efforts failed to advance in last year’s legislative session, as did bills aimed at restricting utility spending. Utilities earn guaranteed profits for every dollar they spend on power grids and other capital infrastructure, which incentivizes them to resist VPP policies that might reduce those expenses — and California’s utilities have political heft in state government.
But Becker, who is also pushing legislation to offset utility spending through public financing in this year’s legislative session, said the state’s utilities are already struggling to expand their grids quickly enough to serve large new customers like EV charging depots and data centers.
In other words, they can’t spend money fast enough to build the grid that’s needed right now. “We’re just trying to align the rules of the game to reward good behavior,” he said.
State legislatures saw a torrent of anti-clean energy bills introduced this year — and little more than a trickle of measures that would benefit renewables. Fortunately, most of the legislation was not signed into law.
As of June, with most states’ legislative sessions wrapped up for the year, 305 bills related to the siting of new clean energy developments had been introduced across 47 states, according to a new report from Clean Tomorrow, a policy-focused nonprofit. Of those, 148 would likely have made it harder to build renewables, while just 68 would have helped wind, solar, or battery storage projects move forward. The remaining 89 would have had a neutral or unclear impact.
The vast majority of these bills stalled out, and of the few that were signed into law, slightly more were favorable to clean energy than hostile to it. Ten pro-renewables siting laws passed versus seven that are expected to restrict clean energy.
Still, the flood of new anti-renewables legislation underscores the increasingly hostile policy environment for clean energy.
Already, 16 states have significant restrictions on new solar, wind, and battery projects, and 459 counties and municipalities across 44 states have restrictions of their own, per a June 2025 report from the Sabin Center for Climate Change Law at Columbia University. These restrictive policies range from giving local officials more authority over permitting decisions to imposing onerous setback requirements on projects, which prevent solar or wind from being built within a certain distance of, say, a road or a property line.
Such policies are becoming more common around the U.S., the Sabin Center finds, a fact that is not surprising given shrinking public approval for large clean energy projects. Support for expanding solar farms fell from 66% to 52% between September 2022 and this past June, per an AP/NORC poll; pro-solar sentiment declined most among independents and Democrats over that period.
Still, some Democrat-led states are boosting policy support for clean energy deployment — most notably Colorado. Even in deep-red Ohio, the governor signed into law a bipartisan, tech-neutral bill that is expected to make it modestly easier to build clean energy.
States and municipalities have significant power to advance clean energy, even without the federal government. They also have the ability to stifle it, making state and local government a crucial arena for the energy transition. Right now, with Trump’s all-out campaign against clean energy at their back, opponents of renewables have the momentum.
If you didn’t think President Donald Trump’s attacks on offshore wind could get worse, think again. In just the last week, the administration targeted more already-permitted wind projects, slashed funding for projects tied to offshore wind, and enlisted a wide array of federal departments to go after the industry.
Trump vowed on the first day of his term that “we aren’t going to do the wind thing,” and it’s been blow after blow to the sector since. But in the last two weeks, the Trump administration has doubled down on its commitment to crushing offshore wind in particular — and what was already an aggressive campaign has now become an all-out war.
In late August, the Interior Department sent a stop-work order to the Revolution Wind project off the coast of Rhode Island, even though the development is just months away from completion. It echoed a similar — failed — attempt to halt construction of the Empire Wind project off the coast of New York back in April.
New England’s grid operator has since warned that delays will jeopardize power reliability and raise electricity prices, and even fishermen who voted for Trump are urging the administration to let work resume. Developer Ørsted and the states of Rhode Island and Connecticut are now suing the Trump administration to get Revolution Wind construction up and running.
The halt turned out to be just the start of a new wave of attacks. Late last week, the Transportation Department said it would pull $679 million from projects to support offshore wind. That includes about $426 million granted to turn a California port into the country’s first hub for floating offshore wind construction.
Recent federal court filings reveal the administration is also looking to revoke and reconsider permits for three already-approved projects: Maryland Offshore Wind, as well as the SouthCoast Wind and New England Wind projects off Massachusetts.
And now, Trump is expanding his full-court press by calling on federal departments that typically have nothing to do with offshore wind, The New York Times reports. The Health and Human Services Department is apparently researching whether turbines emit harmful electromagnetic waves — a claim multiple studies have debunked. And the Defense Department is looking into whether offshore wind farms pose national security risks, the dubious reason the administration cited when halting Revolution Wind last month.
If it wasn’t clear before, it is now: The Trump administration is going to leave no stone unturned in its attempt to stop offshore wind in America.
Court OKs green bank termination
The Trump administration scored a significant, but potentially temporary, win in its efforts to claw back billions of dollars meant to bring clean energy to communities nationwide. A federal appeals court decided on Tuesday that the U.S. EPA has the authority to cancel awards under the $20 billion Greenhouse Gas Reduction Fund.
The “green bank” program, created by the Inflation Reduction Act, is supposed to provide low-interest loans for emissions-reducing projects in low-income and disadvantaged communities. The EPA moved early in Trump’s presidency to revoke the funds, which had already been awarded to the nonprofits administering the program, and the money has been frozen in Citibank accounts ever since. Still, it’s not the end of the line: The nonprofits indicate they’ll appeal the decision further.
What utilities can learn from the data center capital of the world
As tech giants continue to build data centers, utilities will have to figure out how to meet growing electricity demand without raising power prices and carbon emissions. And in Virginia, Dominion Energy might be showing them what not to do, experts and advocates tell Canary Media’s Elizabeth Ouzts. The utility has already gotten regulators to approve its plan to build a raft of new fossil-fueled plants over the next 15 years, despite a state law requiring the total phaseout of fossil fuel power by 2045.
Dominion isn’t in an enviable position, to be sure, as no utility can be sure of whether the data center power boom will fully come to fruition. But utilities can still turn to efficiency measures, battery storage, and grid-enhancing technologies to cut their need to add more power, and data centers can be flexible with their power usage to avoid overwhelming the grid.
Stretching EV incentives: The IRS clarifies that consumers can still receive EV tax incentives if they sign a contract and make a payment by Sept. 30; they don’t necessarily have to take possession of their vehicle by then. (CNBC)
Use it or lose it: Rewiring America is working with elected officials, manufacturers, utilities, and other groups to encourage consumers to tap federal incentives for efficient home upgrades and appliances before the tax credits expire. (Canary Media)
Nuclear interference: Nuclear Regulatory Commission Chair David Wright confirms a Trump administration official told him the agency would be expected to “rubber-stamp” reactors approved by the Energy or Defense departments, and says he pushed back. (E&E News)
Curbing carbon capture: A peer-reviewed study finds the Earth can store far less captured carbon than previously thought after accounting for earthquake-prone areas and other risk factors. (Grist)
Solar still surges: Global solar deployment hit 380 gigawatts in the first half of this year, a 64% increase from the same period in 2024, a new Ember report finds. (Utility Dive)
Wind’s lesson: As state and local leaders defend offshore wind against the federal government, solar developers should take note and double down on state and local engagement, a clean energy advocate says. (Latitude Media)
Gassing up EVs: The Trump administration will prioritize EV charging stations at gas stations and truck stops for funding as it reopens the $5 billion National Electric Vehicle Infrastructure program. (E&E News)
Colorado is pushing hard to quickly approve a massive amount of renewable energy while the projects are still eligible for federal incentives.
The Republican tax and spending law that passed this summer drastically shortened the timeline for wind and solar projects to qualify for federal tax credits. Under the 2022 Inflation Reduction Act, developers had until at least 2033 to start construction; now they must begin before July 4 of 2026, or meet the abrupt deadline of commencing operations by the end of 2027.
This sudden change puts states in a tight spot: If wind or solar projects can’t get started within a year, they’ll be considerably more expensive. And power demand and utility bills are already rising nationwide.
All of these factors are putting pressure on state energy regulators, who typically move at an exceedingly deliberative pace, which is to say, very slowly. The usual months of back and forth and obscure bureaucratic wrangling could force customers to pay billions of dollars more, based on the new deadlines from the Republican majority in Congress.
In recent weeks, Colorado became one of the first states to try getting ahead of that damaging outcome, creating a playbook others could learn from. Gov. Jared Polis, a Democrat, kicked off the effort with an Aug. 1 letter urging state authorities to “eliminate administrative barriers and bottlenecks for renewable projects.” Polis, who campaigned on a strong clean energy platform, identified the immense financial stakes of the moment.
“Getting this right is of critical importance to Colorado ratepayers; by maximizing the utilization of tax credits while they’re available and reducing future tariff uncertainty, the State can avoid billions of dollars in additional energy costs for decades to come,” he wrote.
Taking up that call, key players in the Colorado energy establishment filed an official request with the state’s Public Utilities Commission on Aug. 22 to speed up decision-making for a “near-term procurement.” This effort would enable final approvals before mid-2026 for 4 gigawatts of renewables (which could include batteries), 200 megawatts of thermal power (like gas), and 300 megawatts that could be gas or energy storage. That’s a considerable amount for the state, which currently has around 5 gigawatts of wind and 4.5 gigawatts of solar installed.
On Aug. 27, the utilities commission approved an expedited timeline to decide on the joint proposal. Prospects seem favorable for its passage in the coming days, as it was put forward by the commission’s own staff, the Colorado Energy Office, the Office of the Utility Consumer Advocate, and the state’s largest utility, Xcel Energy.
Delivering on the faster schedule could save Xcel’s Colorado customers $5 billion over 20 years, said Michelle Aguayo, a spokesperson for the utility.
For several years running, solar, wind, and batteries have accounted for over 90% of new additions to the U.S. power grid. New turbines for gas-fired plants are more or less sold out until 2030. And all around the country, electricity demand is rising faster than it has in decades. For those reasons, experts still expect lots of renewable energy to be built even once subsidies expire.
But expediting projects now is still worthwhile. Federal tax credits can cut project costs by more than 30% — a fact that’s helping forge some unlikely coalitions.
“We are seeing, in states like Colorado, a coming-together of forces to try to execute on taking advantage of these incentives as quickly as possible,” said Sam Ricketts, a longtime climate policy advocate who recently cofounded S2 Strategies, a clean energy advisory firm. “Many of [these projects] are going to get built. It’s a matter of when: Will it be lower cost or higher cost?”
Indeed, it’s rare to find enthusiastic agreement between a monopoly utility and a ratepayer advocate, whose job is to contest utility spending that could raise bills for customers. In this case, the clear threat of higher energy prices from Trump administration policies has created an unusual alignment of interests. Ricketts refers to this catalyst as “the fierce urgency of commence construction,” the technical term for when developers can lock in the favorable tax credit rates.
Speeding up regulatory approvals is valuable on a number of levels. The typical pace of states’ energy infrastructure deliberations has been out of step both with the urgency of the climate crisis and the more recent spike in electricity demand. Faster approvals of cheap clean energy projects could push down prices compared to further reliance on expensive, aging coal and gas plants. But the exigencies of climate change, demand growth, or customer wellbeing haven’t prompted the kind of speed-up that Trump’s reworking of federal energy policy achieved.
That said, the acceleration will be limited in its scope. States will have to allocate time and effort to salvage just some of the energy benefits that had been promised for a decade to come. Aguayo, from Xcel, described this as a “one-time process in response to the current policy environment,” not a long-term change to the state’s “robust competitive resource planning process.”
Other states can learn from Polis’ timely response to the about-face in Washington. And, indeed, some are already taking action of their own. Maine fast-tracked its renewable procurement a few weeks after President Donald Trump signed his signature policy bill. California Gov. Gavin Newsom, a Democrat, signed an executive order Aug. 29 directing state agencies to do what they can to help clean energy projects meet the new federal deadlines.
As it stands, though, the list of states taking prompt action pales in comparison to those facing cost hikes on their wind and solar projects, which is to say, all 50. Eventually, state leaders across the country will have to grapple with a dire outlook: Trump came to office declaring an energy emergency, and then took one action after another to reduce the supply and raise the cost of American electricity production.
“Clean energy really is the lowest-cost, fastest to deploy resource now,” Ricketts noted. “We need more generation, and everyone knows it. … [But] the federal government is doing all it can to go in the wrong direction.”
Hundreds of business people, policy analysts, and conservative advocates filled a downtown Cleveland conference hall last week for the National Conservative Energy Summit. One major theme: the need for both the federal and local governments to remove increasingly high hurdles to building renewable energy.
“Conservatives can and should lead on energy,” said John Szoka, CEO of the Conservative Energy Network, in his opening remarks.
The group, which cohosted the program with the Ohio Conservative Energy Forum, has a mission “to champion secure, reliable, affordable, clean American energy.” Its goal of achieving American energy independence includes support for a range of technologies, including solar, wind, battery storage, hydrogen, biomass, and small modular nuclear reactors.
The Trump administration has taken a more single-minded approach to energy.
Since January, it has promoted more fossil-fuel use and stalled the retirement of aging power plants. At the same time, it has rescinded grants and loans for clean energy projects; eliminated tax credits for wind, solar, EVs, and home-energy upgrades; and even halted construction on some offshore wind projects.
“While it’s easy to view this as a roadblock, … it’s a signal that we have more work to do,” Szoka said. He encouraged attendees to use what they learned during the conference in their grassroots efforts to build support for clean energy, especially when faced with extremism and misinformation. “If we don’t explain what’s going on clearly, we risk losing the argument before it even starts.”
As President Donald Trump attacks clean energy at the federal level, some states like Colorado and Maine are pushing to speed up deployment. But in general, state and local laws that restrict renewable energy development are gaining steam nationwide. A June report by the Sabin Center for Climate Change Law at Columbia University notes 16 states with laws limiting solar or wind, with over 450 counties and municipalities across more than 40 states imposing other restrictions.
Speaking at the conference, Jenifer French, chair of Ohio’s Power Siting Board and its Public Utilities Commission, noted that approximately 30 counties in the state ban solar or wind energy in all or parts of their territories, an authority granted to them by a 2021 law known as Senate Bill 52. The board or its staff have also determined solar and wind projects are not in the public interest in several cases where bans didn’t apply but where local governments unanimously opposed the proposals.
Asked for her advice to developers, French said, “I just think communicating with the local officials around the project is so helpful, and being part of that community and earning their trust is very effective.”
Companies often hear such suggestions, but “frankly, I think that’s used as a cop-out sometimes,” said Drew Christensen, senior director of public engagement at utility-scale developer Apex Clean Energy, during a later panel about how policies shape companies’ decisions.
No matter how many community meetings are held, some people will still fight projects, putting pressure on local officials who may not have expertise in energy issues, he noted.
The deference to local governments creates a slippery slope, said Amanda Stallings, senior policy manager for clean-energy developer Geronimo Power, who also spoke on the panel. In her view, the states that pile on restrictive policies will not only see less investment from solar and wind developers, but will also discourage other industries from moving in.
Constraints on renewables also tread on landowners’ property rights, Stallings said, pointing out that in some cases a local government tells farmers not to use their land for solar but would have no problem with a housing development.
“What country do we live in when our government tells us what we can and can’t do?” Stallings said. The point resonated with various attendees from state chapters of the Land and Liberty Coalition, who made comments during networking breaks that property owners should be free to make their own economic decisions about their land.
Meanwhile, “this idea of behind-the-scenes picking winners and losers, that’s what’s going to create a reliability problem,” Stallings said. That risk is already visible: Late last month, the grid operator ISO New England warned of potential reliability issues from delaying Revolution Wind, a nearly finished offshore project that the Trump administration has halted for now.
This past spring, Ohio managed to pass bipartisan legislation that is expected to help the state build more energy — both renewable and fossil-fueled — in large part because the law doesn’t pick winners, according to state Rep. Tristan Rader, D-Lakewood. House Bill 15 passed with unanimous support in the Ohio Senate and just two dissenting Republican votes in the House.
Speaking on a panel about the new law, Rader called it a big step but emphasized that the state still has barriers to getting additional renewable energy on the grid.
“We don’t need to incentivize it. In Ohio, we just need a level playing field,” he said.
For one thing, the Ohio Senate removed provisions from HB 15 that would have created a community solar pilot program. Two Republicans in the House have introduced a separate bill to revive a version of that measure.
Beyond that, the law left SB 52’s extra hurdles for solar and wind in place, along with property line setbacks for wind that were tripled by a last-minute addition to a 2014 budget law.
“We have put up a lot of barriers to different forms of power over the years,” said state Rep. Tex Fischer, R-Boardman, who noted that added levels of government review compound uncertainty for developers. “I think the solution is removing those barriers.”
The Trump administration’s latest attack on an in-progress offshore wind project is now being challenged in court. Two lawsuits announced Thursday — one brought by the wind farm’s developers, the other by Rhode Island and Connecticut — seek immediate relief from a federal stop-work order that froze construction of Revolution Wind two weeks ago.
The developers, Danish energy giant Ørsted and investment firm Global Infrastructure Partners, filed a complaint Thursday morning in the U.S. District Court for the District of Columbia, requesting a preliminary injunction that would allow Revolution Wind’s offshore construction to resume. The 65-turbine project being built 15 miles from Rhode Island’s coastline is 80% completed.
Hours later, attorneys general from both Rhode Island and Connecticut announced a separate lawsuit against the Trump administration, asking the court to declare the construction halt unlawful — and overturn it.
If allowed to proceed, the project would generate enough carbon-free electricity to power more than 350,000 households across the two states. Should President Donald Trump tank the development, it would be a disaster for New England’s grid.
The project was set to come online next year, and New England’s grid operator had already factored its 704 megawatts into its plans. Delaying delivery of that power on such short notice “will increase risks to reliability,” ISO New England warned in a statement last week, adding that the hold-up could also increase utility bills and discourage future investment. New England governors, labor representatives, and even local fishermen have also demanded Trump overturn his decision.
“Does this sound like a federal government that is prioritizing the American people? This is bizarre, this is unlawful, this is potentially devastating, and we won’t stand by and watch it happen,” said Rhode Island Attorney General Peter F. Neronha in a statement.
The lawsuit comes as the Trump administration steps up its already hostile campaign against offshore wind. There’s new chaos almost daily.
Since ordering Revolution Wind to stop construction in late August, the administration has filed documents with federal courts signaling it intends to revoke permits for projects near Maryland and Massachusetts. The Transportation Department clawed back $679 million in federal funding for infrastructure supporting offshore wind. And White House officials are reportedly directing a wide range of agencies — including unrelated departments like Health and Human Services — to seek out reasons to cancel projects already underway.
In choosing litigation over negotiation, the moves made on Thursday mark a shift in how the wind industry is responding to the U.S. government’s new war on the energy resource.
When the Interior Department stopped New York’s Empire Wind project in April, developer Equinor opted not to take the Trump administration to court — even as its losses rose to nearly $1 billion. Instead, the firm and diplomats from its home country and majority shareholder Norway lobbied the government to overturn its decision. In May, the Trump administration reversed course, claiming that it had struck a deal with New York Gov. Kathy Hochul (D) to allow gas pipelines in the state. Hochul’s office denies any such deal was made.
In both instances, the Trump administration used vague and dubious justifications for the stop-work orders. For Revolution Wind, the Interior Department cited “national security” concerns that a retired Navy commander called “specious.” For Empire Wind, it pointed to a mysterious report that officials blacked out entirely on a federal website and still refuse to share with the public.
Ørsted and others are now embarking on a legal battle that could determine not only the fate of Revolution Wind, but whether a more aggressive response is a cheaper and better way to push back on Trump’s always-escalating crusade against “windmills.”
Just over a year ago, the world’s first commercial hydrogen ferry officially set sail in the San Francisco Bay, offering a clean, quiet rebuttal to the noisy, polluting ferries that many coastal cities depend on.
Now, the vessel’s owner is working to build a bigger, faster version in New York.
Switch Maritime was recently awarded $2 million from New York state to develop a 150-passenger ferry powered by hydrogen fuel cells — a technology that doesn’t directly emit carbon dioxide or toxic air pollution, just a little heat and water vapor. The company says it aims to launch the vessel around early 2028 in New York City waterways as part of a 12-month demonstration period, before potentially transitioning to longer-term service.
“Ferry operators have aging fleets that need to be replaced,” said Pace Ralli, CEO and cofounder of Switch. “We’re trying to give these operators a viable alternative to rebuilding and renewing their fleet with diesel.”
More than 600 ferries ply the country’s waterways. The vast majority of them still burn diesel fuel, leaving smoggy trails of planet-warming gases and health-harming pollutants in their wake.
Some of the nation’s biggest ferry operators — including those in New York City, San Francisco, and Washington state — are starting to test and deploy cleaner marine technologies to meet their climate goals and improve air quality in waterfront communities.
Last month, New York City launched a $33 million hybrid-electric ferry that uses batteries and diesel generators. A handful of other hybrid and fully battery-powered vessels are operating or under construction nationwide, and hundreds more have hit the water in China and Europe.
For now, Switch’s San Francisco ferry is the only fully hydrogen-powered vessel in the U.S.
The boat, called Sea Change, launched in July 2024 after more than six years in development. The 75-passenger ferry includes 360 kilowatts of fuel cells, a 600-kW electric propulsion system, lithium-ion batteries, and 10 tanks that can store a total of 246 kilograms of hydrogen. The vessel uses the most readily available type of hydrogen — the kind produced using fossil gas — which is sourced from existing automotive fueling stations in the San Francisco area.
The New York ferry will be twice the size and operate twice as fast as Sea Change, said Seamus Nolan, Switch’s director of commercial and government affairs. He said the $2 million grant from the New York State Energy Research and Development Authority will help fund the company’s initial work to develop the larger vessel and cover some operational costs during the yearlong demonstration period.
Just as crucial as launching the ferry will be establishing a hydrogen supply chain for this specific project, given that no such networks exist today in the U.S. maritime industry. Nolan said that Switch has identified three potential suppliers of green hydrogen — made from renewable energy sources — that could initially serve the new vessel’s operations, though future supplies could include hydrogen made from nuclear or methane pyrolysis as those production methods scale.
A lack of cheap, clean hydrogen remains one of the biggest barriers to taking fuel-cell ferries mainstream. It’s also a key reason why ferry operators are primarily turning to battery-powered boats to begin greening their fleets. Hydrogen fuel is substantially more expensive to make and transport than diesel fuel, and producers remain reluctant to ramp up supplies — and thus drive down prices — given the uncertainty around customer demand.
This was already true under the Biden administration. Now the second Trump administration is moving to scrap federal policies meant to accelerate production of clean hydrogen, including by potentially canceling awards for four projects under the $7 billion Regional Clean Hydrogen Hubs program. The budget law passed by congressional Republicans in July also hastens the phaseout of the 45V tax credit for clean hydrogen production.
“If done safely, green hydrogen is a viable alternative fuel for maritime … but there’s a lot of concerns around, how do we scale up green hydrogen production so that it’s affordable for maritime use and that there’s enough supply?” said Teresa Bui, senior climate campaign director at the nonprofit group Pacific Environment.
During the Sea Change trial in San Francisco, the vessel experienced “minor disruptions due to fuel sourcing at times,” though routine maintenance work and occasional mechanical issues were bigger causes of interrupted service, said Thomas Hall, director of operations and customer experience for San Francisco Bay Ferry, which ran the hydrogen ferry during the demonstration period.
From July 2024 to January 2025, Sea Change zipped along a short tourist route between the historic Ferry Building and Fisherman’s Wharf. The temporary pilot service was sponsored by a group of private partners, including Chevron New Energies, United Airlines, and the Golden Gate Bridge, Highway, and Transportation District.
Hall said the ferry operator is evaluating the demonstration’s results, which will help inform its longer-term plans. The Water Emergency Transportation Authority, which oversees San Francisco Bay Ferry, has secured more than $150 million in local, state, and federal funding to deploy zero-emissions vessels. Plans are well underway to build three small battery-electric ferries and two large battery ferries for the service. Hall said that, down the road, hydrogen ferries could potentially operate on routes that cover longer distances or for extended periods of time.
“Being part of a first-in-the-world, groundbreaking project is something we value a lot here in the Bay Area,” Hall said. “It was a huge achievement that will make future implementations easier.”
Since the pilot ended earlier this year, Switch and its vessel operator partner Blue & Gold Fleet have been running tests to see how Sea Change performs on critical commuter routes in the San Francisco Bay Area. The plan is to bring the vessel back into passenger service in the coming months, either in San Francisco or in a new city that is looking to test the technology.
“Sea Change is one proof-of-concept to show that it can be done, that it can be operated commercially,” Nolan said of the hydrogen fuel-cell ferry. The New York demonstration will be Switch’s chance to prove the technology can operate at twice the scale.
The Trump administration’s latest attack on an offshore wind project could make New England’s electricity less reliable and more expensive.
Late last month, the administration halted work on the nearly complete Revolution Wind project off the coast of Rhode Island and Massachusetts, citing dubious “national security” reasons. State governors, labor leaders, and even New England fishermen who voted for Donald Trump oppose the move, which is part of the president’s monthslong assault on an energy source central to the Northeast’s grid and decarbonization plans.
Should Trump tank the project, it would leave a gaping hole in New England’s energy mix, driving up the region’s already-high electricity prices and leaving its grid more vulnerable to collapse during winter storms. New England’s grid operator has already factored the 704-megawatt wind farm into its plans starting next year. Delaying delivery of that power “will increase risks to reliability,” ISO New England warned in a statement last week.
That’s not to mention the longer-term disruptions that could stem from killing a project that’s followed all the rules and is already about 80% built.
“Unpredictable risks and threats to resources—regardless of technology—that have made significant capital investments, secured necessary permits, and are close to completion will stifle future investments, increase costs to consumers, and undermine the power grid’s reliability and the region’s economy now and in the future,” ISO New England said in the statement.
In the measured world of grid operators, warnings like these are “unprecedented,” said Abe Silverman, an attorney, energy consultant, and research scholar at Johns Hopkins University. But so is the threat of the federal government smashing a cornerstone of a region’s energy mix, he said.
“We’re talking about a really significant hit to consumers, at a time we’re all hyper-concerned about inflation and energy prices generally,” Silverman said. Losing Revolution Wind’s electricity could cost New England consumers about $500 million a year, he estimated, based on the value the project has secured in ISO New England’s forward capacity market and its potential to supplant costlier power plants used during grid emergencies.
And “we don’t need a bunch of fancy studies to tell us that these units are needed for reliability,” he said. New England has long struggled to meet electricity demand during winter cold snaps and summer heat waves. When temperatures surpassed 100 degrees Fahrenheit for several days in June, “they had every single generator on,” he said. “Here we have a unit that should be operating as of next summer that is now in doubt.”
But it’s during the winter months that the loss of Revolution Wind could be most keenly felt, said Susan Muller, a senior energy analyst at the Union of Concerned Scientists. That’s when the region’s limited supply of fossil gas is stretched even thinner, since the fuel is used both for building heating and power generation. ISO New England is banking on offshore wind — which blows most strongly in the winter — to meet energy needs as temperatures plummet.
But as the move to shut down Revolution Wind shows, the Trump administration’s relentless attacks on the offshore wind industry are making the energy source harder to plan around.
In the winter, “we essentially run out of pipeline gas” for the gas-fired power plants that make up New England’s largest single source of power, Muller said. The region is forced to rely on power plants fueled by oil and costly liquefied natural gas to cover the gap.
That’s an expensive way to keep the lights on. Wholesale power costs from December to February spiked to $4 billion, up from $1.6 billion the previous winter, according to ISO New England data, largely driven by increasing gas costs and a bump in coal- and oil-fired generation. ISO New England reported that total energy costs this spring rose 67% compared to last year, driven primarily by a 112% year-over-year increase in gas prices.
Luckily, strong winter winds make offshore wind farms a great solution to these problems, Muller said — and she has the fancy studies to prove it.
Muller consulted on a new report from Daymark Energy Advisors that found New England could have saved $400 million in energy costs this past winter if 3.5 gigawatts of offshore wind capacity had been online. That’s roughly the total combined capacity of Revolution, the in-progress Vineyard Wind, and two other yet-to-be-built projects, New England Wind 1 and the first phase of the SouthCoast Wind project.
A similar analysis Muller worked on last year found that Revolution Wind and Vineyard Wind would have slashed blackout risk had they been available in recent decades. Vineyard Wind is already sending power to the grid from 17 of its 62 turbines, and the entire project is expected to be complete by year’s end.
The money-saving mechanism is pretty simple, Muller explained. Offshore wind farms are costly to build, and the utilities in Connecticut and Rhode Island that signed long-term contracts with Revolution Wind will be paying prices for that power that are higher than the average prices on ISO New England’s wholesale energy market. But the price is steady and not susceptible to huge swings like that of fossil gas. During wintertime peaks, it costs the same to generate power from offshore wind as it does on a mild day — the same is not true for gas.
Because of this dynamic, the Daymark Energy Advisors analysis found that Revolution Wind’s power would still save consumers money even if the utilities pay twice as much as wholesale prices, Muller said.
Revolution Wind is also meant to supply power to ISO New England’s forward capacity market, which is designed to secure the resources the region needs to ensure its grid can keep running during times of peak demand in future years.
The project would make it less expensive for the region to meet those peaks, Silverman said, putting New England in a better position than other areas of the country. Grid operator PJM Interconnection, which covers 13 states and D.C., has seen capacity prices skyrocket in the past year because it has not built new generation fast enough, he noted.
Perhaps even more valuable is that offshore wind can be a buffer against fuel shortages, Muller said. “In other words, we might have enough power plants, but they might not have enough fuel to get us through,” she said.
This summer, ISO New England unveiled the initial findings of an assessment on the grid’s ability to deliver energy during extreme weather events. That’s an incredibly complicated evaluation with a lot of variables, ranging from the future of large-scale transmission lines that can deliver more power from outside the region to the capacity of the Everett Marine Terminal, a major LNG import and storage facility near Boston.
But out of all those variables, the study’s base case assumes that ISO New England will have about 1.6 gigawatts of offshore wind power in 2027, including 704 megawatts from Revolution Wind. “If you take it out of the model, the risk will go up,” Muller said.
Fossil fuels can’t replace the power that would be lost if Revolution Wind isn’t brought online, Muller and Silverman said — even if the Trump administration is touting more gas pipelines as a solution.
Last month, U.S. Environmental Protection Agency Administrator Lee Zeldin published an op-ed in The Boston Globe claiming that a proposed pipeline originating in Pennsylvania would bring down energy costs in New England by enabling the region to access more gas from the line’s terminus in New York.
The piece came after the Trump administration lifted a stop-work order on New York’s Empire Wind offshore wind project in May, claiming it had struck a deal with Gov. Kathy Hochul to allow two major gas pipelines to be built in the state. Hochul, a Democrat, has denied any quid pro quo but has said the state will “work with the administration and private entities on new energy projects that meet the legal requirements under New York law.”
Energy experts have pointed out many flaws in the administration’s push for more pipelines, including a lack of capacity to move gas from New York to New England and poor long-term economics for expanding that capacity. Every state in New England except New Hampshire has set clean energy and decarbonization mandates that call for using less fossil gas, not more, in the years to come.
“We know that pipelines cost billions of dollars to build,” Muller said. But while Revolution Wind will generate energy throughout the year, “a pipeline would only change things for a handful of days, a few weeks of the year. The rest of the time, it wouldn’t be needed. … There would be cheaper options.”
The Trump administration has insisted that fossil-fueled power plants must stay open to ensure grid reliability, going so far as to use emergency powers to force coal-, gas-, and oil-burning plants to keep running past their planned retirements. Those orders will force customers to bear tens of millions of dollars or more in unnecessary costs while doing nothing to improve reliability, according to energy analysts as well as the state attorneys general and environmental groups challenging the extensions in court.
Fossil-fueled power plants also pose reliability challenges in cold weather. Gas plants made up the majority of generator failures during widespread winter blackouts in Texas in 2021, across the U.S. Southeast in 2022, and during the 2014 “polar vortex” in the U.S. Northeast.
The cold can cause malfunctions at gas plants themselves, or it can limit fuel supply by spurring breakdowns at the wellheads and compression stations that feed pipeline networks. ISO New England’s most recent winter outlook assumed that 3.9 gigawatts to 4.8 gigawatts of gas-fired power “may be at risk due to constrained natural gas pipelines.”
All of these factors were considered in the years-long decision-making processes that New England states went through to decide that offshore wind is their best choice, said Larry Chretien, executive director of the nonprofit Green Energy Consumers Alliance.
“We’re buying 30 years of power at a fixed price, and it’s a good price,” he said. “The states have decided they want to buy this stuff.” By blocking completion of Revolution Wind, the Trump administration is “forcing fossil fuels down our throats.”
.svg)
