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Developer Cypress Creek has broken ground on the project, which will eventually deliver 2.5 gigawatts of solar production and 2.9 gigawatt-hours of battery storage.
Longtime solar developer Cypress Creek Energy has not only broken ground on what could be the largest solar-plus-storage plant in the country, but also secured a blue-chip customer to pay for the clean power.
Google will buy all the electricity from the first two phases of the forthcoming Steel River Energy Center in Mississippi County, Arkansas, just upriver from Memphis, Tennessee — totaling 1.6 gigawatts of solar capacity and 1.9 gigawatt-hours of battery storage. Once fully online in 2029, its power won’t flow directly to the tech giant but instead onto the grid managed by Entergy Arkansas, which supplies one of the company’s data centers and will serve a future data center planned for West Memphis, a Google spokesperson told Canary Media.
This marks the latest and largest effort by the tech giant to generate clean power for its rapidly expanding data center fleet, and it comes as the AI boom drives a growth spurt in carbon emissions from Google and other tech companies that have adopted voluntary decarbonization targets.
“As one of the nation’s most significant new solar plus storage projects, Steel River helps address growing electricity demand with reliable, cost-effective power, utilizing battery storage systems to strengthen grid dependability while also unlocking new clean capacity,” the Google spokesperson said in an email.
A planned third phase will bring the total capacity on-site to 2.45 gigawatts of solar production and 2.9 gigawatt-hours of battery storage by the end of 2029. Google is not contracted to purchase that power.
This scale places Steel River at the forefront of U.S. solar facilities. While several operating projects have broken the gigawatt barrier in other parts of the world, U.S. developers have only crept up to that threshold. The Edwards & Sanborn plant came online in California’s Mojave Desert in early 2024 with a national-best 875 megawatts of solar and nearly 3.3 gigawatt-hours of storage. Steel River would blast past that solar capacity level, though it won’t store quite as much in its batteries.
“In my view, that’s where we’re headed as a country,” Cypress Creek CEO Kevin Smith said. “Solar right now is the most affordable electricity supply. It’s also fastest to market.”
Cypress Creek secured $3.5 billion in project financing in June to cover the costs of building and operating the first two phases. Lenders for the project include Barclays, BNP Paribas, Santander, and Wells Fargo. The developer and its financiers can move forward knowing that a cash-rich anchor customer will pay an agreed-upon rate for every unit of power the project generates.
The solar industry has endured a series of withering policy blows during the second Trump administration. President Donald Trump’s fluctuating tariff policies raised the costs of key materials unpredictably. Then, just over a year ago, the president’s budget law revoked a lucrative tax credit for solar, and subsequent executive-branch actions stymied development on public lands. (Cypress Creek managed to lock in the project’s tax credits before their July 4 expiration.) Despite all that, solar is still the single largest source of new electricity getting built in the U.S. this year, as it has been for many years running.
The AI surge has stimulated a historic level of demand for electricity, and though solar can’t power data centers 24/7, it can typically deliver the cheapest and quickest new electricity production. Steel River stands as a testament to those qualities. It will generate more instantaneous power than the state’s two nuclear reactors (1.8 gigawatts, taken together), but at a far lower price tag and with a manageable three-year construction effort, instead of the yearslong drift of recent U.S. nuclear construction.
Arkansas has a lot to offer solar developers, Smith said. The state provided good access to transmission and allows power producers to sell into the 15-state wholesale market managed by the Midcontinent Independent System Operator. And Cypress was able to lease 11,000 acres, largely from the Lawrence Group, a major private farm owner based in Nashville, Tennessee.
Notably, Arkansas has no state-level renewable incentives or mandates, said Lauren Waldrip, executive director of the Arkansas Advanced Energy Association, who attended the Steel River groundbreaking Tuesday. Solar projects have to succeed there on a competitive market basis.
“Coal used to hang its hat on being the cheapest. That’s just not the case anymore,” Waldrip said. “We’re seeing that solar is one of the best options, especially when you couple storage with it. We can store this power and dispatch it on demand in a very reliable and affordable way. Those are just the facts.”
Agriculture has long led the state’s economy, but the sector faces a historically turbulent time; indeed, Arkansas led the nation in farm bankruptcies last year. For smaller family farms, solar lease payments can help keep the rest of the farm financially viable; for large landowners like the Lawrence Group, it offers a diversified revenue stream.
“People are realizing the generational impact that these projects can have in these rural communities that so desperately need a shot in the arm,” Waldrip said. The Steel River plant is expected to inject $300 million into the local tax base over its lifetime.
The project also showcases how far the solar industry has come in onshoring its supply chain. In fact, Cypress Creek will source much of its construction materials from the project’s own backyard.
The power plant’s moniker references how Mississippi County produces more steel than any other county in the nation. Cypress Creek will buy an estimated 400,000 piles from Paco Steel, about 30 miles north, in Blytheville, Arkansas. Those piles will be sourced from steel coils produced at U.S. Steel’s Big River Steel in Osceola, Arkansas, roughly 10 miles from the new solar project; and the piles will hold up steel trackers from Nextpower, which has a network of domestic steel factories from Pittsburgh to Memphis to Las Vegas to supply its equipment.
Cypress is buying 3 million domestic panels for the first two phases from First Solar, which opened a 3.5-gigawatt solar factory in Lawrence County, Alabama, in 2024. And the batteries will come from LG Energy Solution Vertech, which has led the charge to onshore grid battery cell production in the U.S. and Canada. That effort is going so well that the U.S. is on track to become self-sufficient in grid battery supply by the end of this year.
In the 1950s, former General Motors CEO Charles Wilson told Congress that “what was good for our country was good for General Motors, and vice versa.” The Steel River project makes an implicit case that the success of the nation’s largest solar project is good for the nation, too.
The Trump administration has a year to issue updated energy conservation standards for the homes, a move that would especially help the rural South.
A sweeping federal housing bill that became law last Saturday contains some big benefits for Americans poised to buy or rent new manufactured homes — the same families who often struggle to make ends meet and can least afford the rising cost of heating fuel and electricity.
The 21st Century ROAD to Housing Act — a rare feat of bipartisanship in Washington, D.C. — gives the Trump administration one year to issue updated minimum energy-efficiency standards for the construction of manufactured homes, which account for about one in 10 new houses across the country and are especially prevalent in the U.S. South.
The provisions on prefabricated housing mark a surprising turnaround on energy policy.
In January, the Republican-led U.S. House of Representatives, with the support of dozens of Democrats, passed a bill to rescind new efficiency codes for manufactured homes — and instead lock in place 30-year-old standards for insulation, window and door sealing, ventilation, and other features. But during months of negotiations on the housing package, the Senate, also controlled by Republicans, fought to preserve the new codes. The final legislation passed the House last month with just 32 “no” votes.
The forthcoming standards — if they’re as strong as energy-efficiency advocates hope — will be crucial for Southern households.
Of the 4.7 million prefab homes delivered nationwide in recent decades, more than half are in 10 Southern states. Texas leads the country, with nearly 600,000 units, and North Carolina is second, with over 330,000, the U.S. Census shows. The “East South Central” region, which spans from Kentucky to Alabama, has the highest concentration of manufactured homes in the country, at 9.3%.
The dwellings are exempt from state and local energy codes, and older models are notoriously energy inefficient, with thin insulation, drafty windows and doors, and often outdated modes of heating and cooling.
“It’s easy to see, with an older … home, a $300 or $400 heating bill in the wintertime,” said Brad Rouse, executive director of the Asheville, North Carolina–based Energy Savers Network, which works to install energy-savings measures for modest-income households in the region.
High monthly costs tend to be especially difficult for manufactured home residents to handle: Their median income is $40,000, less than half that of families living in site-built houses. The Southeast, meanwhile, is the most energy-burdened region in the country, with one in three households struggling to pay their energy bills.
Residents of modular homes often “don’t have money left over,” Rouse said. “To have high winter heating and cooling bills can really hit them pretty hard in the pocketbook.”
The recently passed law includes two major provisions to unleash more manufactured housing across the country, said Mark Kresowik, senior policy director at the American Council for an Energy-Efficient Economy.
One is the reauthorization of a grant program to help families replace older non–site-built houses, including those constructed before the U.S. Department of Housing and Urban Development had any efficiency standards whatsoever.
“If you go from a pre–HUD Code home,” Kresowik said, to a gold-standard version like those being built in Vermont, “you’re talking about potentially a 50% reduction in the energy use inside that home. That’s huge.”
The law also removes a mandate that manufactured houses, once widely called “trailers,” be built on a permanent steel chassis that allows them to be transported. Some 90% of such homes never move after their initial setup.
As housing manufacturers retool their facilities according to the new chassis rule, they also have an opportunity to make adjustments to account for upcoming efficiency requirements, Kresowik said.
“This is the perfect time to also update those factories to deliver lower-cost homes to live in,” he said.
The U.S. Department of Housing and Urban Development last updated standards for manufactured homes in 1994. In 2007, a bipartisan law required the Department of Energy to issue more protective rules, aligned with model standards for site-built homes. In 2022, the Biden administration finally complied, but those criteria never went into effect, and Trump paused them indefinitely last summer.
Last week’s housing law doesn’t repeal the DOE requirement adopted in 2007. But it does specify that only HUD can promulgate and enforce efficiency rules, and says the agency must do so in a year’s time. It also mandates new standards every three years.
Under the 2022 proposal, the average double-wide home was expected to cost $4,222 more up front, a figure that would be offset in less than five years in the form of lower energy bills. For single-wide units, the additional up-front costs were pegged at $660, which households would recoup within one year.
Some half of all manufactured homes are already built well above the minimum code. Yet the industry has long resisted new rules, and the second Trump administration has been hostile to energy efficiency efforts. So advocates like Kresowik have their work cut out for them to push HUD to devise standards that are at least as strong as those proposed four years ago.
“In this moment where voters have clearly communicated that lowering their costs is a top priority, this would be a thing that HUD can do,” Kresowik said. “[Updated standards] should deliver tremendous energy savings and cost savings. They should lower the cost to live inside a manufactured home.”
The region has added dozens of turbines off the East Coast since last summer. They and other clean energy sources cut the need for oil power amid recent hot weather.
America’s offshore wind farms have already shown their ability to keep electricity flowing during brutal winter storms. Now, the clean energy resource has proved it can also bolster the grid during major heat waves.
Earlier this month, as dangerously hot and humid temperatures settled over the eastern United States, two wind projects near New England consistently delivered hundreds of megawatts to the grid as residents cranked up their air conditioners. The influx of wind reduced utilities’ reliance on dirty, expensive oil-burning peaker plants, which operate only when electricity demand is through the roof, according to the data firm Grid Status.
Analysts compared how the regional system performed during the July heat wave and a sweltering stretch in June 2025, before much of the current offshore wind capacity came online. Oil provided nearly 10% of the region’s total power supply during peak-demand conditions on July 2, 2026 — that period’s hottest day — down from nearly 15% at the highest point on June 24, 2025. That’s a drop of more than a gigawatt in oil-fueled generation between those two days.
Part of the decline was due to slightly weaker overall demand during the July 2 peak than during last year’s event. But Grid Status said that stronger generation from the region’s utility-scale offshore wind farms was a key factor. The projects are coming online despite repeated attempts by the Trump administration to block them.
The surge of hydropower delivered via the New England Clean Energy Connect power line, which started carrying electricity from Canada to Maine in January, also reduced peak oil use. Meanwhile, an abundance of rooftop solar installations significantly eased overall electricity demand during the heat wave.
“Even if total demand was in line with last year, we would still be hundreds of megawatts below what the total [peak oil] burn would’ve been,” said Tim Ennis, a Grid Status analyst in Boston. “We didn’t have to turn the oil on as hard at lunchtime because we had the wind and [hydropower line] online as well.”
Ennis noted that offshore wind is often touted by experts for its ability to bolster grid reliability during winter. New England’s power system is becoming increasingly constrained in colder months, owing to the shift to electric space and water heating systems. Ocean winds in the region are at their strongest and steadiest during the season, meaning offshore turbines can help meet some of that growing electricity demand and reduce stress on gas-fueled power plants.
While wind speeds are generally lower during summer, the recent heat wave confirms that the projects still play a meaningful role on the hottest days — more of which are headed for the region this week.
The 806-MW Vineyard Wind, off the coast of Massachusetts, finished construction in March, and its developer had activated 49 of its 62 turbines as of early May. The 704-MW Revolution Wind, near Rhode Island, started sending power to the grid in March and is set to reach full commercial operations by the second half of 2026.
Ennis said data shows that the commissioned offshore turbines relieved grid stress from July 1 to 4, during periods when air-conditioning use was at its peak, offsetting some of utilities’ need to turn on oil plants, a step that adds to customers’ already high utility bills. All told, New England operators produced 42.2 gigawatt-hours of oil-fired power during that four-day heat wave, down 37% from the total oil burned from June 23 to 25, 2025.
Outside New England, the already completed 132-MW South Fork Wind farm had a strong showing off the coast of New York. The project, which came online in 2024, operated at nearly full capacity on July 2, sending electricity into the heat-stressed grid on Long Island, Mikkel Mæhlisen of Ørsted, which jointly owns South Fork Wind with Skyborn Renewables, recently wrote on LinkedIn.
The Independent System Operator New England has previously stressed the role that offshore wind can play in supporting the grid during extreme heat events. The regional grid operator spoke out last August after the Trump administration halted construction of Revolution Wind, which was then 80% complete.
“Recent heatwaves in New England drove demand for electricity to very high levels and demonstrated that our region needs all generation resources with market obligations to be available to meet demand and maintain required reserves,” ISO New England said in an Aug. 25, 2025, statement, noting that delaying Revolution Wind “will increase risks to reliability.”
A federal judge overturned the stop-work order in September. But its developer Ørsted was forced to hit the brakes again in December after Trump’s Bureau of Ocean Energy Management paused the leases for all five large-scale U.S. offshore wind projects under construction. Though judges later lifted those orders as well, the delays still cost some developers millions of dollars and threatened projects’ viability.
The Trump administration has since adopted a new tactic for kneecapping America’s fledgling offshore wind industry: paying developers to abandon plans for future wind farms, using billions of dollars in taxpayer funding. The strategy makes it highly unlikely that any new projects will be built in the next few years.
However, when all five wind farms are fully up and running, they will add nearly 6 GW in clean capacity to help the East Coast navigate days of bone-chilling cold or life-threatening heat.
“The potential costs and benefits of offshore wind have been debated for decades,” said Fara Courtney, who consults on offshore wind policies and research projects for Outer Harbor Consulting, in Gloucester, Massachusetts. “Now we have the first projects up and producing, [and] the data is clear: Offshore wind is a new American energy sector with a big role to play in meeting this region’s skyrocketing energy demand.”
A new program from startup Every Electric and utility Con Edison lets New Yorkers power their window ACs with home batteries to take stress off the grid.
Earlier this month, as a historic heat dome smothered the U.S. Midwest and Atlantic Coast, New York City Mayor Zohran Mamdani asked residents to set their air conditioners to 78 degrees Fahrenheit to protect the city’s severely strained grid. “Let’s ease demand — and get through the heat — together,” he posted on X ahead of the sweltering July 4 weekend.
Previous NYC leaders and elected officials nationwide have given the same advice ahead of extreme weather events. But Mamdani’s suggestion that everyone pitch in sparked backlash from conservative figures and prompted the Trump administration to remove its thermostat-level recommendations from the Department of Energy’s website.
All the while, in apartments across New York City, hundreds of residents were supporting the electric grid without needing to adjust their AC at all.
The local startup Every Electric launched a novel pilot program earlier this year with the utility Con Edison that allows participants to plug their window air-conditioning units into a battery pack, which itself is plugged into the wall. The Wi-Fi–connected batteries draw electricity from the grid when conditions are calm, then power ACs with the stored-up energy when demand on the grid is highest.
“The air conditioner can stay on, but we can still reduce load on the grid,” Andrew Wang, the company’s CEO, told me a few days after the heat wave and a subsequent major storm passed over the metropolis.
“And the big thing is, you don’t impact someone’s preferred settings,” he said. In an outage, the batteries can power a typical window unit for about four hours, he added.
Millions of New Yorkers live in older apartment buildings without central air conditioning. Many residents instead use two or more window AC units to keep their homes cool. On blistering, humid days — like July 2, when temperatures hit 104℉ — these appliances can represent about 20% of the entire city’s electricity demand, Wang said. On a household level, it’s more like 75% of total peak energy use.
Every Electric, which ran a small internal pilot last year, has so far delivered over 1,000 batteries to roughly 600 apartments, including mine. It’s free to participate, though I had to pay a $50 refundable deposit for the power bank, which is now shoved against the wall between the window and my bed. (Every Electric’s lithium-iron phosphate devices are different from the beat-up lithium-ion batteries linked to e-bike fires in my Brooklyn neighborhood and citywide.)
Wang said that heading into the heat wave, New York’s grid operator forecasted a 45% jump in NYC-wide peak demand for July 2. The window ACs in Every Electric’s program used 130% more electricity at their peak that day than they do in a typical week. Yet the company’s batteries met much of that demand, mitigating a source of grid stress and allowing renters to keep cool, even as Con Edison reduced voltages in certain areas to prevent widespread outages.
Collectively, Every Electric’s battery fleet can provide about 2.5 megawatt-hours of distributed energy storage. That’s a teeny sliver of the total power draw from window ACs. But experts say that such programs, when scaled, can play a crucial role in boosting grid reliability, reducing utility costs — and making the overall system more resilient to climate change.
On brutally hot days, utilities often fire up expensive, old fossil-fuel-burning peaker plants to meet the extra demand. Then there are the added maintenance costs and infrastructure upgrades. In May, Con Edison said it was investing a record $3.9 billion to lay more cables and build new transformers and substations to maintain reliable service “as extreme heat becomes more frequent and severe.”
“Distributed energy storage is a resource that [utilities] can leverage to avoid these peak demand spikes, and there’s a clear benefit for them, in terms of deferring their capacity investments,” said Bryan Bollinger, a professor of marketing and economic policy at the Tuck School of Business at Dartmouth, who studies how consumers make energy decisions.
A growing number of states, led by California, are increasingly adopting programs that call upon networks of customer-owned energy devices — like Tesla Powerwalls charged by rooftop solar panels — to support the grid when needed. But these initiatives, also called virtual power plants, primarily serve homeowners who are able to outfit their homes with clean technologies.
Every Electric’s renter-friendly approach “targets a different population completely,” Bollinger said. “You’re getting a bunch of consumers who also want to feel like they’re doing their part, but who don’t have the ability to do things like install solar panels.”
The company’s program also skirts the challenges facing large-scale battery storage systems in New York City. Big batteries can provide even greater relief to the grid, but local developers are ensnared in a regulatory battle with Con Edison related to the cost and effort of connecting to the system. Every Electric’s microwave-sized batteries face no such issues: As the utility sees it, the power bank in my bedroom is no different from a computer or TV.
Participants will be rewarded for our goodwill to the grid, with a payment that reflects each household’s peak summer monthly utility bill, up to $150 per power bank pairing.
The money comes from Con Edison’s Smart Usage Rewards program, under which the utility pays its customers to actively reduce energy use during specific blocks of time, in specific neighborhoods, on the hottest days of the year. Every Electric is enrolled as an “aggregator” that virtually manages all the power banks in its network. Wang’s team distributes a portion of the rewards it receives to its own participants, while keeping the rest to cover its costs and expand the program.
The ability to earn money while staying cool has an obvious appeal: The owners of some 10,000 window ACs units have requested batteries. Every Electric said it’s working to fulfill as many of those orders as possible over the summer.
Con Edison, which serves 3.7 million customers, said over 50,000 electricity users representing 500 megawatts in capacity are enrolled in the utility’s demand-response initiatives. During the past heat wave, the company called on customers to curb energy use 27 times across its networks in NYC and neighboring Westchester County.
A spokesperson said Con Edison doesn’t yet have specific data on how Every Electric’s pilot and other programs performed during the record-breaking heat. But in general, such efforts, combined with infrastructure investments and technological upgrades, have helped limit strain on the grid when it’s needed the most.
Beyond the Con Edison program, Wang declined to get specific about Every Electric’s financials, though he said the six-person startup is supported by a blend of sources. That includes private investors, debt financing from social-impact funds, and grants from the New York State Research and Development Authority.
“We’re excited by how scalable this can be,” Wang said, adding that the utility and state regulators “are telling everyone to look under every rock to find ways to make the grid run a little bit cheaper and more reliable.”
Bollinger, who until recently was a New York City renter himself, said he hopes that programs like Every Electric’s can catch on nationwide — because they can both bolster the grid and benefit more consumers. “It provides access to this kind of technology to non-homeowners as well, which we just haven’t seen with a lot of renewable energy technologies,” he said.
Plug-in panels can lower your bills. To boost the American market for the tech, nonprofit Bright Saver is selling kits with no markup, starting at around $300.
Do you live in the U.S. and want balcony solar? A new initiative could help you get a deal on one of these small but mighty systems that plug into a standard outlet and push clean power into your home.
Today, California-based nonprofit Bright Saver announced it’s selling zero-markup DIY solar kits starting at about $300. The move is intended to kick-start the U.S. market for the tech, which is already cheap and widespread in Germany. Residents in 47 states can now pre-order, with shipping expected in August.
“Only a nonprofit like ours will ever give up our margins completely to pass along to consumers the savings from clean energy,” said Cora Stryker, co-founder of Bright Saver. “Someone’s got to do it, or we are up the creek in terms of energy affordability and climate.” The nonprofit has sold balcony solar kits before, but not at cost.
Plug-and-play solar can go in virtually any sunny outdoor spot. That flexibility opens up solar access to the four in 10 U.S. households who can’t, for financial or logistical reasons, put an array on their roof. With every watt generated, the tech lowers household electricity bills and reduces planet-warming emissions.
As spiking energy prices squeeze Americans, balcony solar is becoming wildly popular. Legislatures in more than half of U.S. states have introduced measures to encourage and regulate plug-in solar, and so far eight governors have signed such bills into law. Bright Saver estimates deployed systems number in the thousands nationwide.
But balcony solar in the U.S. has a long way to go to reach the scale seen in Germany. There, plug-in solar installations grew from roughly 40,000 systems in 2017 to as many as 4 million in 2025.
Bright Saver wants the tech to take off faster stateside.
That’s why the nonprofit is selling systems for “what it costs us to purchase in bulk from the manufacturers,” Stryker said. She declined to name those manufacturers, noting that the organization is brand-agnostic and could switch at any time.
Bright Saver sells a 180-watt kit for about $285 and a 360-watt kit for $414. To access these prices, you first have to become a member, which costs $29 annually (with renewal optional). Otherwise, a 180-watt kit is $499, and a 360-watt kit is $699.
The organization aims to be the Costco of clean energy; only members can access the deep discounts. And more product deals are coming. Bright Saver plans to offer plug-in home batteries that work with balcony solar kits as soon as next year.
With the membership, the 180-watt kit works out to $1.74 per watt. The 360-watt system, which is just 5% the size of a typical 7,200-watt rooftop array, is significantly better priced at $1.23 per watt.
That’s a good deal in the U.S. Nationally, the average rooftop system costs $2.60 per watt before local and state incentives, largely because of the high “soft costs” of marketing, permitting, and installation. Balcony solar kits sold domestically by companies such as CraftStrom, APsystems, and EcoFlow hover around $1.50 to $2.50 per watt, although it’s possible to find systems on sale for less.
But even Bright Saver’s 360-watt-kit price is more than three times what Germans can pay. There, balcony solar through Ikea is a stupefying $0.35 per watt. Clean energy really is cheap energy, especially outside the U.S.
A lower up-front price means a faster payback from energy savings. Bright Saver says that if you live in an area with high electricity rates and your home uses all the power as the panels produce it, its kits would save enough on electricity bills to pay for themselves in as little as 2.5 years.
Bentham Paulos, senior research associate for the national nonprofit Clean Energy States Alliance, calculates that with California’s average electricity price at 32 cents per kilowatt-hour, Bright Saver’s 360-watt kit would save a household in the state about $150 per year; that translates to a payback of about three years. The timeline can stretch from seven to 10 years in places like North Dakota, where electricity rates are lower.
You can run the numbers for your situation with Paulos’ payback calculator. Bright Saver also has a tool, which accounts for potential increases in utility rates.
Households could reap savings for decades. Solar panels and inverters can last 25 to 30 years, quietly producing power from sunlight that falls free on everyone on earth.
“The solar revolution is the great sunny hope of our time,” said Bill McKibben, longtime environmental journalist and co-founder of nonprofit advocacy group Third Act. With plug-in systems, “now everyone can participate.”
Bright Saver’s annual membership fee covers some of the nonprofit’s overhead; the group runs mainly on donor funding and says it can keep the discounted sales going for up to six months without more cash. But membership is also a way to rally balcony solar supporters.
“We’re building a constituency,” said Kevin Chou, co-founder of Bright Saver. “Joining a movement that’s actually winning is its own kind of power. Every Bright Saver member makes the case for saving money and fighting climate change a little harder for lawmakers to ignore.”
Regulations to ensure the consumer safety of balcony solar are still evolving in the U.S. But Bright Saver states that its kits are safe to use, as the individual components — the panels and inverters — have been certified by a nationally recognized testing laboratory, even though the system as a whole has not. (No system yet has.)
That limitation impacts where the nonprofit sells its kits. Some states are requiring complete-system certification. Bright Saver said it will block shipping to Maine, New York, and Vermont, which have passed bills with that mandate, according to the nonprofit. Other states, like Utah, which in 2025 became the first to legalize balcony solar, require only that the kits’ individual components are certified.
Still, component-level standards have been a concern to some because balcony solar injects power into a home’s wiring. In a worse-case scenario, a portable solar device could overheat a section of a home circuit if other appliances are drawing power from the system at the same time. If the circuit breaker — the safety mechanism — fails to detect what’s going on, then a fire could break out.
But a technical amendment that experts have proposed adding to the National Electrical Code, rules that all states use to safeguard people from electricity hazards, points out that the electrical wires in U.S. homes have some buffer built in. This margin isn’t enough for a larger 1,200-watt balcony solar setup, but it is sufficient to accommodate Bright Saver’s system.
Plugging 360 watts into a typical 15-amp circuit “can never damage” the 14-gauge copper wires commonly used, per the amendment’s explanatory notes. While the proposal hasn’t been adopted yet, Stryker expects it will be by September 2028, before the next scheduled update to the code is released.
“We designed our systems to be 360 watts because of what the NEC amendment tells us is safe,” Stryker said.
Balcony solar is still a new technology in the U.S., and not everyone is going to feel comfortable with it yet, Stryker said. But sentiment could shift “once we have tens of thousands of these [deployed], demonstrating that there are no house fires, even with the component-level certified systems,” Stryker said.
“And let’s not forget, Utah has had up to 1,200-watt systems in the wild for more than a year now,” she added. “We have no major safety incidents.”
Sodium-ion batteries promise cheaper, more durable energy storage. Peak Energy seeks to kick-start the next-gen battery market by building the first big U.S. plant.
Startup Peak Energy launched in 2023 with a promise to bring the up-and-coming sodium-ion battery chemistry to American shores. Now, it’s building a gigafactory in Sacramento, California, that will be the country’s first to produce sodium-ion battery storage plants for the grid.
If Peak Energy succeeds in its broader mission, it will introduce a new generation of batteries better suited for grid storage than the dominant lithium-ion chemistries, which are effectively hand-me-downs from electric vehicles. These sodium-ion batteries can run safely at a broad range of temperatures, company leaders say, meaning they can operate more cheaply and durably than the lithium-ion phosphate (LFP) cells that have become the go-to for stationary storage.
“We’ve gone from proving the technology out and having really great interest to having contracted business with customers that we have to go deliver on,” said Peak’s CEO and co-founder Landon Mossburg. Chinese battery companies have begun scaling sodium-ion production in recent years, but the technology hasn’t broken into the Western power sector yet. Peak is at the forefront of startups trying to make that happen.
Peak assembled a cohort of interested developers to observe the design and piloting of its storage technology, which it installed at a Colorado testing facility last year. Several power producers signed up for small pilot installations this year, with much bigger orders teed up for 2027. So far, the company has worked with manufacturers in China to supply cells to its specifications and then assembled them into containers at its existing facility in Burlingame, California. That site can produce only 100 megawatt-hours per year — roughly 32 units at 3.1 megawatt-hours each — as a function of its size and reliance on some manual work rather than full automation.
That output won’t suffice in an era when a single battery project may need several times the Burlingame site’s annual production. The Sacramento factory will produce 40 times more, 4 gigawatt-hours per year, when it starts its highly automated production, planned for the first quarter of 2027. Once assembled, the 100,000-pound containers can slip right onto the highway for shipment to customers.
It’s a quick turnaround as far as factory buildouts go, made possible because Peak found a newly built shell to lease in an industrial park near the Sacramento airport, said Mossburg. The site already had power supply from the Sacramento Municipal Utility District, so Peak can drop in its manufacturing equipment with only minor upgrades to the structure and electrical service, he added. It also helps that the factory won’t be doing the highly technical cell fabrication, which takes longer to install.
Peak chose Sacramento after a competitive search around the country, and ended up bucking the conventional wisdom that you can’t build things in California anymore. Mossburg said he wanted to prioritize access to talent, rather than chase the richest state and local incentives or the lowest cost of labor or energy. Operating in California involves spending more in taxes and electricity costs than, say, in Texas, but Sacramento is accessible to the Bay Area and all the electrical engineering expertise of Silicon Valley and the Tesla diaspora. It’s also close to the Burlingame site where Peak has built its first enclosures.
Peak also won $10.5 million in tax credits from the California Competes program, which are tied to hiring milestones, Mossburg said.
Down the road, Peak leadership hopes to find onshore sources for its battery cells, and formed a partnership in June with GM to co-develop that product with the automaker’s Michigan battery labs.
All told, Peak’s strategy could allow for a relatively low-cost and rapid path to large-scale manufacturing. That would be a welcome contrast to the billion-dollar factory expansion pursued by Swedish startup Northvolt, which tried to forge a European battery empire before collapsing into bankruptcy. (Mossburg worked there for a time as president for North America.) But Peak still needs to prove there’s a market for a chemistry that has never been widely deployed in the U.S. grid storage market, which has been notoriously unwelcoming to anything that isn’t lithium-ion.
Peak’s chief strategy officer, Geoff Brown, got in early on the current LFP trend about a decade ago, when he was running pioneering grid-battery firm Powin Energy. His company scoured the Chinese market for the best cells to put into grid storage enclosures, and ultimately picked a form factor that had been designed for electric buses, he recalled. At that point, sodium-ion cells hadn’t made the jump to mass production.
Unlike the chemistries that ruled the grid storage market thus far, sodium-ion was “the first battery really purposely designed” for stationary storage, Brown said.
“You sacrifice some energy density for massive improvements in safety but also very significant economic benefits,” he noted.
A vast global factory base now produces LFP cells, but sodium-ion is already within striking distance of the per-cell manufacturing cost given its cheaper bill of materials, Mossburg said. Peak is pricing its enclosures to match Tesla’s LFP-fueled Megapack, but argues that they cost less on a lifetime basis because the cells are so durable and don’t need energy-sucking temperature-control and fire-suppression equipment.
Still, scale matters, and the Sacramento site is a necessary step for taking on the U.S. storage market with this new battery.
Last week’s high temperatures pushed the U.S. grid to its limits, and showcased how new wind and solar additions are essential to keeping the lights on.
Last week brought soaring temperatures to much of the U.S., forcing Americans to switch on their air conditioners — or, in many cases, flex their heat pumps’ cooling capabilities. And to cope with it all, the U.S. power grid delivered more electricity than ever — a feat that wouldn’t have been possible without clean energy’s massive growth over the past few years.
Temperatures in the triple digits prompted grid operators across the U.S. to prepare for potential emergencies. PJM Interconnection, which covers parts of the Midwest and East Coast, was granted federal authorization to direct data centers and other large power users to tap diesel generators and battery backup systems as a “last resort” to prevent power shutoffs. But the grid region didn’t end up needing those emergency resources, even as its power demand reached its highest level on record.
Texas, meanwhile, set a record for peak demand in any July — 83 gigawatts on the evening of July 6. Solar power, which Texas has recently added in spades, covered more than 30% of that demand, Texas energy expert Doug Lewin noted. Solar also helped Texas’ grid operator avoid the need to push customers to conserve power.
In New England, it was wind power that proved to be a hero as temperatures soared. The region burned less oil this time around than it did during a similar heat wave last year, per Grid Status, thanks in large part to offshore wind farms that have recently come online. The New England Clean Energy Connect power line, which started delivering electricity earlier this year, also brought in tons of hydropower from Canada.
Wind similarly played a strong role in keeping the lights on in the Southwest Power Pool, which spans the central U.S. from North Dakota down to northern Texas.
New York City’s sparkling new transmission line, which was supposed to bolster the city’s grid during heat waves like this one, was unfortunately a letdown. The Champlain Hudson Power Express, or CHPE (pronounced “chippy”), has been bringing clean hydropower from Canada into the city for the last month, but an issue in Quebec forced the line to shut down on July Fourth. The heat wave was luckily on its last legs by that time, and CHPE isn’t essential to New York grid operations just yet. But it’s set to become a vital power source as aging natural gas plants begin to retire.
Aside from a few short-lived outages scattered across the eastern half of the U.S., the grid weathered its first test of the summer pretty darn well. Still, with climate change making summer heat more extreme, and with more and more data centers and other large power users coming online, we’re far from out of the woods yet.
Hawaiʻi is retreating from its clean energy ambitions
Back in 2015, Hawaiʻi set the first statewide clean electricity goal in the country, aiming for a system run completely on renewable electricity by 2045. But as that deadline creeps closer, the state is considering retreating toward fossil fuels, reports Canary Media’s Julian Spector in partnership with Savannah Harriman-Pote of Hawaiʻi Public Radio.
As it stands, Hawaiʻi relies heavily on imported oil to generate electricity, and its residents pay the highest power prices in the nation as a result. But the state’s ambitious plans to build out tons of solar power and battery storage to replace its oil imports have been slowed down by the COVID-19 pandemic, the war in Ukraine, and a catastrophic fire on Maui.
Now, Gov. Josh Green (D) is pursuing a different solution: a natural gas terminal that would again depend on an imported fossil fuel. Julian and Savannah have all the details and explore what Hawaiʻi’s clean energy challenges can teach other states.
Another step forward for nuclear power
America’s nuclear renaissance just keeps getting more credible. Last week, Holtec International — a company usually known for shutting down nuclear plants — announced a big milestone in its quest to reopen Michigan’s Palisades reactor. All major renovations to the plant are done, and the company’s next and final steps are essentially what would be done to restart the plant after a routine outage, reports Alexander C. Kaufman.
The Palisades restart — and the nation’s atomic ambitions — are just one small piece of the world’s nuclear power redux. A BloombergNEF study out this week predicts global nuclear capacity will climb 44% over the next decade. That means as much as 535 gigawatts of nuclear capacity could be on the grid by 2036, up from 372 GW as of last year.
Glass half full: A new MIT report predicts the Inflation Reduction Act’s clean energy legacy will continue despite President Donald Trump and Congress repealing many of its incentives, as tons of renewable power is still on track to get built through 2035. (report, Heatmap)
Demolishing clean jobs: More than 200 clean energy generation and manufacturing projects have been canceled or downsized since Trump took office last year, costing the U.S. hundreds of thousands of jobs, a new report finds. (Canary Media)
Union blowback: Union workers and leaders call out the Trump administration’s buyouts of offshore wind leases, saying the deals are destroying good-paying union jobs. (The Guardian)
Cuba in crisis: Cuba suffered an island-wide blackout early this week amid a U.S.-led blockade on oil imports to the country. (Associated Press)
Cooking up batteries: Brooklyn startup Electra Research is building induction stoves equipped with small backup batteries that can also be leveraged as a grid resource. (Canary Media)
RGGI, set, go: The 11 East Coast states participating in the Regional Greenhouse Gas Initiative will share a massive $1.3 billion for climate programs raised so far this year in auctions of allowances for carbon pollution. (E&E News)
After a few missed targets, Holtec says the remaining tasks to bring Michigan’s Palisades plant back online are equal to restoring service after a routine outage.
Up until recently, the U.S. was in a yearslong dry spell in the construction of new nuclear power plants. The hiatus finally ended in April, when two next-generation nuclear developers broke ground on their debut plants.
Though those facilities will take years to finish, the next reactor set to patch onto the U.S. grid could be mere months away.
That’s because Holtec International, long known for its work decommissioning shuttered nuclear plants, is seeking to restart a defunct power station in Michigan — a first for the U.S.
Last week, the nuclear industry’s undertaker-turned-doula announced that it had reached a “watershed moment” by completing all major renovations for its reconstruction of the Palisades plant’s single 800-megawatt reactor, on Michigan’s western coast. While the checklist of 5,000 remaining maintenance issues sounds long, Holtec compared the outstanding workload to that for a routine refueling outage at an operational plant.
“At this point, what we’re doing is typical of a routine outage,” said Nick Culp, a longtime worker at the Palisades plant who now serves as Holtec’s senior manager of government affairs and communications.
The average length of a planned maintenance or refueling outage at a U.S. nuclear plant was 34 days as of 2024, according to the U.S. Energy Information Administration. The longest planned outage in 2024 lasted roughly two months, though recent years have seen reactors idled for as long as three or four months.
It’s possible, of course, that Palisades’ timeline could drag on longer. Florida-headquartered Holtec has already missed two stated target dates for the restart, which it initially said would happen last year. After the firm failed to meet that deadline due to unexpected repair work, a spokesperson told Engineering News-Record that Holtec was aiming for early 2026 — which has now come and gone. Culp declined to comment on multiple questions about exactly when the company expects the reactor to come online.
But once Palisades does return to service, it could generate enough clean electricity to single-handedly power every household in Detroit twice over — and could also serve as a model for reviving other nuclear plants nationwide.
Previously owned by the utility giant Entergy, Palisades’ pressurized-water reactor was shut down in 2022, the last in a wave of nuclear plant closures brought on by the costs of repairing and relicensing facilities amid competition from relatively cheap natural gas and renewables.
In the 2010s, following decades of mostly flat electricity demand, debates over the future of American energy mirrored those seen in other Western democracies, primarily revolving around the strategic value of renewables versus fossil fuels. On the political right, which traditionally supported atomic power, enthusiasm for natural gas appeared to crowd out backing for reactors. On the left, which historically opposed nuclear energy, the falling prices of wind and solar seemed to make reconsidering atomic power unnecessary. Despite repeated warnings from federal researchers that growing industry and electrification would drive up power demand, policy discussions on both sides focused on promoting their preferred energy sources rather than preserving existing nuclear capacity.
So the U.S. allowed for 13 reactors to go out of business between 2013 and 2022 as the country prioritized natural gas. Those reactors represented roughly 10 gigawatts of output, roughly enough power to supply every household in Pennsylvania and New Jersey combined.
When Holtec bought the site in 2018, the plan was to demolish the facility and make money on the decommissioning fund. But in 2024, the company — which was already planning to expand into building and operating live reactors — proposed something that had never been tried in the U.S. before: restarting a shuttered plant. At that point, skyrocketing energy demand from the AI boom was beginning to foster renewed support for nuclear energy across the political spectrum.
Under the Biden administration, the Department of Energy’s Loan Programs Office awarded Holtec a $1.52 billion loan to finance the renovations needed to relicense Palisades’ 54-year-old reactor, previously the oldest in operation in the U.S. fleet. While the Trump administration froze all clean energy spending after taking office, the loan to Holtec was among the first the DOE allowed to move forward.
Holtec took on the project in two parts. The first involved overhauling the reactor side of the plant, where atom-splitting reactions produce enormous amounts of heat that are used to turn water into steam. The second — the milestone completed last week — focused on repairing the generator side of the plant, where the steam spins turbine blades and generates electricity.
The work was significant. Holtec conducted the only deep cleaning of the station’s generator in more than half a century, including replacing all the degraded metal tubes in the steam and condenser systems, recoating all the metal in the electrical system to prevent corrosion, and disassembling the entire machine for its first full refurbishment. The company also saved the fuel left in the reactor after its final shutdown, and received a shipment of fresh fuel — currently stored on-site — to be loaded right before the plant starts back up.
Holtec went on a hiring and training spree, too. The company said it requalified 26 former plant operators to maintain their Nuclear Regulatory Commission licenses in addition to graduating a new class of specialists. A second class of newly hired operators is set to undergo final NRC licensing exams this month.
“We’re down to what we characterize as bulk work: routine maintenance activities,” Culp said. “At this point, if you’re out on the turbine deck, it looks fully assembled. We’re now going through the process to tighten everything up.”
Among the items on the to-do list: finishing up some of the pneumatic air controls, removing scaffolding, and carrying out inspections. Installation of a new instrument air-compression system just wrapped up on Monday, Culp said.
“It’s like cleaning up our work,” he said. “What we’re saying is we’re progressing toward the end of the process.”
If Holtec is successful in restarting the first nuclear plant, it would make it easier for other defunct reactors to come online.
The first of those is Constellation Energy Generation’s Crane nuclear plant, formerly Three Mile Island. The station infamously lost one of its reactors in 1979 in the nation’s only major civilian nuclear accident. But the other unit stayed in service until 2019. Two years ago, Microsoft pledged $16 billion to reopen the plant’s operable reactor to supply its data centers with clean electricity. Just last month, the Federal Energy Regulatory Commission cleared the way for the plant to patch back onto the grid as early as next year. The second is NextEra’s Duane Arnold nuclear plant. Last October, Google inked a deal with the utility to fund the restart of Iowa’s only atomic power station, which shut down in 2020. The plant could begin pumping out electricity by early 2029. It’s unclear whether either project would move forward if something happened to thwart Palisades’ progress.
At least five other nuclear stations could be rebuilt if not restarted. Experts widely agree that the demolition at California’s San Onofre, New York’s Indian Point, New Jersey’s Oyster Creek, Massachusetts’ Pilgrim, and the geographically eponymous Vermont Yankee is already too far along for the reactors themselves to be revived. But certain elements — the containment domes over the reactor chambers, for example — could be reused. Last fall, Holtec floated the idea of rebuilding a new reactor inside the existing facilities at Indian Point, which supplied much of New York City’s power until its final reactor closed in 2021. But Gov. Kathy Hochul, a Democrat, has rejected the idea, citing opposition from local officials in Westchester County.
Palisades’ completion would also pave the path for Holtec’s budding initiative to construct reactors from scratch. The company plans to build two of its SMR-300s, 300-megawatt pressurized-water reactors at Palisades. If successful, Holtec wants to build the units across the country, including at other sites it owns, such as Oyster Creek. In December, the Energy Department gave Holtec $400 million to support the SMR construction, although questions remain about the timelines and economic viability of the technology.
If nothing else, the Palisades restart serves as “an object lesson in the power and necessity” of the DOE’s Office of Energy Dominance Financing (the new name for the Loan Programs Office), said Emmet Penney, a historian of the nuclear industry and the director of energy and infrastructure at the Foundation for American Innovation, a right-leaning think tank that advocates for building more reactors in the U.S. Palisades’ rebirth also demonstrates that long-horizon nuclear projects can maintain government support even as the partisan pendulum swings in Washington, he said.
“It is proof positive of the bipartisan consensus around nuclear,” Penney said.
Over 200 major clean energy projects were canceled over the first year and a half of Trump’s term. A report says that’s left nearly half a million jobs on the table.
President Donald Trump’s attacks on clean energy haven’t spelled disaster for the energy transition — but they have definitely hurt job prospects for Americans.
Between January 2025, when Trump took office for his second term, and May 2026, a total of 216 major clean energy generation and manufacturing projects were scrapped, closed, or downsized, according to a new report from the business-focused advocacy group E2.
Those cancellations, driven in large part by the Trump administration’s hostility toward clean energy, have resulted in the loss of nearly half a million potential jobs, E2 found. Just over a tenth of those would have been permanent roles at clean energy facilities, while the rest would have been either temporary construction jobs or steady work in roles supporting the sector, from selling building materials to serving food at restaurants near a new factory.
Trump took office amid an unprecedented surge in the clean energy economy. The 2022 Inflation Reduction Act spurred the rapid construction of both renewable power projects and domestic factories intended to build solar panels, electric vehicles, batteries, and other crucial cleantech.
But the boom went bust pretty much as soon as Trump won the election in late 2024. Even before Trump and congressional Republicans gutted the Inflation Reduction Act one year ago, companies began reevaluating and stepping away from investments given Trump’s favoritism for fossil fuels and opposition to renewables, particularly wind.
When it comes to jobs, most of the damage to date is in the EV sector, which in the U.S. was already plagued by high costs and weak demand prior to the Trump administration ripping away key discounts for car buyers.
Still, new clean energy continues to be built in America, and while EV sales have taken a hit, they haven’t ground to a halt. The country’s solar manufacturing industry is notching new milestones, and EV makers are pivoting their battery-making factories to serve the red-hot storage sector.
The clean economy has had some real setbacks since Trump took office last year — but it’s still poised to grow even without support from the federal government.
Gov. Josh Green, a Democrat, wants to import LNG to slash energy bills. But the move might not lead to savings — and it could trip up the state’s climate goals.
On June 8, 2015, Gov. David Ige sat under the great seal of the state of Hawaiʻi and signed the nation’s first legal commitment to run an entire state’s grid system on 100% renewable electricity.
Ige, a Democrat, lamented that Hawaiʻi was “the most oil-dependent state” in the U.S.; unlike others, it relied on oil to produce nearly all of its electricity.
“Making the transition to renewable, indigenous resources for power generation will allow us to keep more of that money at home, thereby improving our economy, environment and energy security,” he said at the time.
Two months later, he shot down a pricey proposal to use another imported fossil fuel — natural gas — to reduce the islands’ dependence on oil imports. Ige’s reasoning was clear: “It’s time to focus all of our efforts on renewables,” he said.
Now, Ige’s successor, Gov. Josh Green, is abandoning that all-out focus on renewables — and throwing his support behind a natural gas import scheme that critics contend would threaten the state’s climate targets while delivering marginal savings, at best, to residents.
Green, also a Democrat, is backing a $2 billion bid by Japan’s largest energy company, JERA, to construct a floating liquefied-natural-gas import terminal called Longboard LNG. In May, the Federal Energy Regulatory Commission granted JERA’s request to begin the review process for the project.
This vessel would ride the surf near Barbers Point, an industrial zone in west Oʻahu that’s home to several power plants. LNG tankers would pull up every three to four weeks to unload the gas, which would flow via undersea pipeline to shore and then fuel a new 500-megawatt power plant to serve Oʻahu, the state’s most densely populated island.
The proposed plant could comfortably meet about 40% of the island’s highest recorded electricity demand and has a target commercial operations date of 2030. Green contends that natural gas can help the state wean off costly and polluting oil without undermining its legal mandate to fully decarbonize its electricity system by 2045. In June, he told Hawaiʻi Public Radio that while the state needs solar and other renewables, it also should have pursued natural gas a decade ago.
“We made a mistake not having a more balanced energy plan,” he said.
The state’s renewables buildout has been buffeted by a once-in-a-century pandemic, multiple global conflicts, and a catastrophic fire. A decade into the transition, utility customers in Hawaiʻi remain mercilessly exposed to the whims of the global oil market, which saw prices spike this spring after Iran cut off most shipping through the Strait of Hormuz.
To date, the energy transition has not sufficiently addressed the primary concern of many of Green’s constituents: Their energy rates are the highest in the nation. JERA, meanwhile, claims it can cut Oʻahu households’ electric bills by $500 a year on average.
But critics say that it makes no sense to tether the state to yet another internationally traded fossil fuel — one whose price also shot up thanks to the war in Iran.
“You can’t solve this problem of a reliance on imported oil by moving to another import that we don’t control,” said Chris Lee, a Democratic state senator who authored the 100% clean energy law and stood beside Ige as he signed it. “And that’s just very painfully obvious.”
This isn’t just a problem for the 50th state. Hawaiʻi started a trend with its 100% clean energy law; nearly half of all states followed with similar measures, and many of them have struggled to build renewables as fast as they hoped, too. Now, elected leaders of these states are also grappling with rising energy costs and, in many cases, a slower-than-expected buildout of renewables.
In New York, long a self-styled leader in the fight against climate change, Gov. Kathy Hochul (D) just eliminated binding interim carbon-reduction targets due to concerns about affordability. Several other Northeastern states considered weakening or undoing their own climate policies in spring legislative sessions, signaling a broader shift toward a less hopeful era of the clean energy transition.
While Hawaiʻi has not yet touched its marquee climate laws, the politics of affordability are clearly having an impact: The biggest energy conversation over the last year in one of the nation’s bluest states has revolved around a massive fossil fuel investment. If Hawaiʻi locks in this natural gas infrastructure, it would mark a significant change from the path it first laid out when it bet on the clean energy transformation.
Lee, who represents part of Oʻahu’s eastern coast, spent three years arguing on behalf of the 2015 climate legislation before skeptical colleagues, hesitant state agencies, and a reluctant utility. When it finally passed, Lee recalled it signaled a “paradigm shift.”
“We realized this is very possible, and not only possible, but inevitable,” he said recently from his office at the Hawaiʻi State Capitol.
Ultimately, advances in renewable energy technologies, like wind and solar, helped make the case for decarbonization, Lee said. The goal also tapped into a broad desire to make Hawaiʻi more self-sufficient.
“For a long time here in Hawaiʻi, we’ve been dependent on imports — food, energy, pretty much everything we consume — and that’s been one of our Achilles’ heels,” Lee said. “We spend billions of dollars that we send overseas every single year to import these things that we rely on, bare necessities.”
In 2018, Hawaiian Electric, the investor-owned utility that supplies power to 95% of customers in the state, awarded bids to four new large-scale solar projects to move Oʻahu toward the 2045 target. The utility mandated the projects come online by the end of 2022.
Only one of those projects, Clearway Energy’s Mililani I Solar, hit that deadline. The others stumbled amid COVID supply chain disruptions and the state’s notoriously slow permitting process. The last of the batch, Hoʻohana Solar, came online last year.
The utility was just beginning to move on from the challenges of the pandemic when a deadly blaze burned through the town of Lahaina on Maui on Aug. 8, 2023, killing 102 people and damaging or destroying thousands of buildings. A local and federal investigation implicated Hawaiian Electric’s equipment; the utility subsequently confirmed that broken power lines had ignited dry vegetation and started a fire, which later rekindled and spread out of control.
In the wake of the fire, Hawaiian Electric’s credit rating dropped to junk status, leading Clearway to cancel three major solar projects and other developers to raise their electricity prices.
Despite the sluggish large-scale solar buildout, Hawaiʻi is technically on track to meet its interim targets under the clean energy law. Hawaiian Electric hit 37% qualifying renewable generation in 2025, mostly due to broad adoption of rooftop solar. Hawaiʻi has the highest rooftop solar penetration of any state in the U.S.; around half of single-family homes on Oʻahu boast panels.
Rooftop solar delivers substantial savings for those with the means to install it, and has reduced the overall volume of oil the state needs to burn to meet electricity demand. But that progress isn’t translating into savings for most customers: Families without solar on their homes are still paying the highest electricity rates in the nation and remain susceptible to dramatic shocks in the global oil market. When Russia invaded Ukraine in 2022, for instance, power prices for average Hawaiʻi households jumped by more than 20%.
In May 2015, an Oʻahu residential customer who used 500 kilowatt-hours of energy in a month paid $140.48. In May 2026, that same customer using the same amount of energy paid $256.27, according to Hawaiian Electric’s estimates. In a state that also has some of the nation’s highest food and housing costs, Hawaiʻi’s most vulnerable residents are often burdened with more bills than they can reasonably pay.
At a local energy conference in May 2024, Green suggested publicly that LNG could reduce the state’s reliance on oil — and thus energy bills — while it worked toward the 2045 clean energy mandate. Last October, the governor’s office announced a strategic partnership with JERA.
“On the table, I have the offer of over $2 billion of private investment,” Green told Hawaiʻi Public Radio in March. “We have an opportunity, if I’m constructive and pragmatic, to help our next generation have a lower cost of energy.”
Aside from the governor, the loudest local champion of the JERA project has been the Hawaiʻi State Energy Office, led by Chief Energy Officer Mark Glick.
In March, Glick appeared before the state’s House energy committee to discuss a study his office conducted on alternative energy pathways for the state. The study, which came out in January 2025, concluded that switching to imported gas power could save residents hundreds of dollars a year on energy costs, or a total of $700 million in net present value compared to sticking with oil.
He was followed at the podium by Matthias Fripp, an electrical engineer who taught at the University of Hawaiʻi at Mānoa for a decade and now conducts energy policy analysis at Energy Innovation, a San Francisco–based think tank that advocates for decarbonization.
“It’s an honor to be here — it’s my first time speaking in front of a legislature, so I’m a little bit nervous, but thank you for having me,” said Fripp, sporting dark-frame glasses and an aloha shirt adorned with green leaves and orange flowers.
Fripp had pored over the spreadsheets the Energy Office had shared with him, and in doing so, he told the committee, he had uncovered a series of errors that collectively inflated the supposed benefits of LNG by $1.2 billion. Most glaringly, a spreadsheet formula left out the fuel cost of LNG in comparison to fuel oil, such that the projected benefits would only accrue if Hawaiʻi miraculously got LNG delivered for free. Removing those errors, Fripp said, reversed the administration’s top-line finding: Instead of saving money, LNG would actually cost consumers around $300 million.
Rep. Nicole Lowen (D), the committee chair, pressed Glick to acknowledge these errors. He initially called out “the way that this is transpiring,” adding that “we received no ability to even look and understand what the differences are, because we’re being delivered this in real time.”
Fripp then testified that he had emailed Glick’s team about the errors some three weeks prior, and never heard a response. Glick challenged that assessment, but under subsequent questioning, his colleague Monique Zanfes confirmed receipt of the email in question and acknowledged that the team had not followed up on it.
The next day, March 13, the Energy Office posted a defensive Instagram message calling Fripp’s assertions “INCORRECT” and stating “HSEO unequivocally stands by its work on the study.” Six days later, the office officially acknowledged an “unintentional algebraic syntax error” and retracted the scenario that had shown the greatest net benefits, to the tune of $700 million.
The Green administration and the Hawaiʻi State Energy Office continued to push for natural gas despite the collapse of their official case.
Within days of the committee hearing, administration officials coordinated the release of a sleek slide deck laying out JERA’s project proposal. Emails obtained by the environmental groups Earthjustice and Life of the Land through public records requests show that throughout that time, the governor’s office and the Energy Office collaborated on a media campaign to promote the LNG proposal with iQ 360, a public relations firm contracted by JERA.
One email chain from March 16 shows state press officers working alongside a rep from iQ 360 to craft responses to questions from a journalist with Bloomberg News.
“I think we do need to add something to the effect that this program aligns with our 2045 aspirations. Both Mark and Erik spoke to it tonight and national story must carry this aspiration,” wrote the Energy Office’s Strategy and Marketing Officer Yvonne Hunter, referring to an event in which Glick appeared alongside JERA Americas Vice President of Development Erik Montague.
Life of the Land, founded in 1970, regularly intervenes in regulatory proceedings involving new energy projects. Executive Director Henry Curtis said that with the JERA LNG project, the Energy Office has stepped well outside its usual role.
“We’ve never seen the State Energy Office handpick a specific technology and a specific company and throw their weight behind it,” he told Hawaiʻi Public Radio.
The Energy Office has since revised its non-retracted scenarios, which currently show more substantial benefits from LNG. In the scenario the state is leaning on now, net present values jumped from $150 million to $651 million in the republished study.
While that may sound impressive, experts at Hawaiʻi Natural Energy Institute, the state’s primary academic body researching and modeling the energy transition, say those savings are negligible. HNEI Director Rick Rocheleau said that after spreading $651 million out over the proposed 15-year timeline for burning gas and then breaking it down by the energy Hawaiian Electric sells, it boils down to less than a penny per kilowatt-hour in savings.
“We would effectively be breaking even,” Rocheleau said.
JERA has run its own calculations on what LNG could save customers and produced a figure higher than that in the Energy Office’s study: It claims that by burning gas instead of oil, it can lower energy costs by 20% and provide Oʻahu households with an average of $500 off their bills each year.
Rocheleau called those numbers a “mirage.” He said that JERA is calculating its savings per meter, not per household, and neglected to distinguish between commercial and residential meters. Large commercial customers will see higher savings, whereas residents would get a much lower return — closer to 2 cents per kilowatt-hour, or 5% of the average customer’s bill, according to Rocheleau’s calculations based on JERA’s assumptions.
“To put it in perspective, total fuel cost is only about 20% of our electricity costs now, so LNG and the infrastructure would have to be free for us to save 20%,” Rocheleau said.
Even if the case for savings was airtight, the JERA proposal makes other questionable assumptions. It has little margin for error in its projected timeline, especially if the LNG facilities will indeed comply with the 2045 clean energy deadline, as Green insists is the case.
JERA is offering to front roughly $2 billion to build the gas infrastructure, and plans to profit from this investment by charging Oʻahu residents for the gas-fired electricity. JERA hopes to have its LNG terminal and power plant fully constructed in 2030, an extremely optimistic timeline that would still allow only 15 years to make money burning gas before that becomes illegal.
But gas power plants are hefty investments, so developers or utilities typically run them for decades to recoup what they spent; JERA’s calculation for the supposed household savings assumes a 40-year power plant operating life, which would stretch into the 2070s.
“Once you build the infrastructure, unless you’re going to keep it for a very long time, anything you do to amortize it quickly is going to drive up the cost,” said Jay Griffin, who chaired the state utility regulatory commission from 2019 to 2022. “If you’re really intent on saying ‘We’ll only do this for 15 years,’ now it’s a 15-year mortgage on a $2 billion loan, versus 30 or 50 years.”
To hit that 2030 target date for commercial operations, JERA would have to make quick work of permitting this complex and multifaceted project, and shepherd the controversial plan swiftly through approvals at the Public Utilities Commission.
“That alone can take years because the PUC takes its job very seriously. These are very technical issues,” said Isaac Moriwake, the environmental attorney who leads Earthjustice’s Mid-Pacific Office.
Navigating PUC approval will also require some degree of buy-in from Hawaiian Electric, the electric monopoly that actually runs the Oʻahu grid. JERA needs the utility to either solicit bids for the project or request a waiver from the competitive bidding process on JERA’s behalf. Thus far, the utility has played no formal role in JERA’s proposal, and one of its press statements about LNG exuded a rare degree of saltiness for the typically bland genre of utility communications, noting how the state has zigzagged in its approach to LNG over the past quarter century. Hawaiian Electric confirmed to Canary Media and Hawai’i Public Radio that it has not formed a partnership with JERA.
Even after the PUC rules on the proposal, community members have a right to appeal up to the state Supreme Court, an eventuality Moriwake said was “almost guaranteed.”
And even if the project wins all the necessary approvals and deflects legal incursions, it still wouldn’t be out of the woods.
“We have an extensive track record of projects going over budget and taking too long,” Griffin said of construction efforts in Hawaiʻi. “After all the infrastructure, the build, and any delays, who’s going to guarantee those savings?”
JERA’s Montague acknowledged in an email that 2030 completion would be “an aggressive timeline,” but added that “we fully believe it can be accomplished.” The company’s slide deck stressed that it still expects savings for customers if the project is delayed by three years or its cost grows by 20%.
Crucially, though, its expected savings depend on “assuming thermal plants switch to renewable fuel at 2045.” JERA asserts that the power plant’s turbines could burn renewable natural gas, clean hydrogen, or clean ammonia with limited upgrades to comply with the clean energy law.
When asked to name power plants burning green hydrogen, Montague said that JERA upgraded a turbine in New Jersey to be capable of burning a 40% blend of hydrogen with natural gas, and noted that GE Vernova sells turbines it says can handle a 100% hydrogen fuel.
Testing is one thing, but power plants have not yet adopted hydrogen as a sole fuel for regular operations. Staking Oʻahu’s grid on clean fuels entails betting on specialized generator equipment not yet in widespread production and an uninterrupted supply of fuels that remain niche and expensive.
Renewable natural gas does exist — it can be siphoned off landfills and manure ponds so it doesn’t hit the atmosphere as unabated methane. But the Energy Office study, for instance, made clear that “RNG is not scalable or widely available enough to meet Hawai‘i’s energy demands.”
Should Oʻahu find itself in a position where the LNG plant eventually gets approved, but comes online years late due to the predictable community challenges or construction delays, or both, and then cannot actually deliver a quick and easy switch to burning hypothetical clean fuels by 2045, JERA would have to make its money back in that compressed timeframe, with the captive customers on Oʻahu footing the bill.
“This project’s a loser, and for it to make any kind of sense, they’re going to have to sprinkle some fairy dust on it,” Moriwake said. “If you sign up for this long-term fossil-fuel commitment, you’re going to be pushing back cleaner and cheaper renewable resources and forfeiting our clean energy and climate goals.”
JERA and the Green administration counter those unresolved questions with a sense of urgency. They paint a binary picture: the expensive, polluting, oil-burning status quo versus a cheaper, cleaner future powered by natural gas. On April 16, the 48th day of the Iran war, Green told listeners of Hawaiʻi Public Radio that the state’s dependence on oil had to change.
“Right now, the idea of continuing to rely on oil from places like Libya or worry about what happens in the Middle East when you have a war with Iran, it’s just insanity,” Green said. “And I’m just not going to be a governor that sits on my butt and doesn’t do something when I can try to make things more affordable.”
Of course, Iran’s blockade of the Strait of Hormuz didn’t just stop oil flows; it cut off shipping access for about one-fifth of global LNG supply, too. Iranian missiles damaged Qatar’s primary gas facility so badly it will take years to repair, creating a long-term constraint on gas markets in Europe and Asia.
Even if Green wasn’t pursuing gas import dependence at a historically volatile time for the commodity, his oil-versus-gas dichotomy overlooks another option: solar.
Clean energy advocates argue that the state should instead fast-track investment in solar and batteries to drastically reduce Oʻahu’s need for imported fuel. If anyone wanted to see receipts from a natural experiment that tested this exact strategy, all they’d have to do is hop on a 40-minute flight from Honolulu to Līhuʻe, Kauaʻi.
Neighboring Kauaʻi is the only island in the state served by an electric utility outside of Hawaiian Electric’s purview. Member-owned Kauaʻi Island Utility Cooperative (KIUC) built enough solar and batteries that it routinely runs solely on renewable power for portions of sunny days. Its leaders aren’t worried about hitting the 2045 deadline — they expect to entirely forgo fossil fuels by 2033, 12 years ahead of schedule.
When KIUC formed in 2002, electricity rates on Kauaʻi were 70% higher than on Oʻahu, according to KIUC president and CEO David Bissell. Today, the island has the lowest rates statewide, and Bissell said customers are far more insulated from the vagaries of the oil market.
Solar investments have been key to KIUC’s success. One-fifth of KIUC’s members have rooftop solar on their homes. Utility-scale solar currently accounts for roughly a quarter of Kauaʻi’s annual generation. Two recently approved solar and battery farms will bring that up to around 60%, each providing electricity at a rate of about 15 cents per kilowatt-hour, a steep discount compared to oil-fired generation.
These projects, together with KIUC’s other renewable facilities, will help Kauaʻi avoid more than 300 million gallons of fossil fuel use over the next 25 years.
“It’s helped our greenhouse gas emissions get radically reduced, and it uses Kauaʻi’s abundant resources to produce energy and benefit the island,” Bissell told state lawmakers in April.
Oʻahu has a much higher energy demand and more land constraints than Kauaʻi, but some experts say the island can overcome those hurdles. In that same April meeting, Fripp appeared alongside Michael Roberts, an economist and fellow at the University of Hawaiʻi Economic Research Organization, to discuss how Oʻahu might achieve comparable results to Kauaʻi.
Roberts and a Ph.D. student updated a model originally designed by Fripp and ran more than 100 scenarios comparing energy project and fuel costs to determine the most affordable path forward for Oʻahu utility customers. This analysis concluded that investments in solar, not natural gas, presented Oʻahu’s best bet at mitigating electricity costs. In late June, Roberts published a report on the Economic Research Organization’s website that built on the initial analysis.
That case for solar became muddied on July 7, when Roberts withdrew his study, noting errors made in the rush to publish, including one in a correction that relied on data points hallucinated by an AI assistant.
Roberts is conducting an internal audit of the report, which he plans to reissue soon. So far, his top-line takeaway stands: “Building no new fossil-fuel plant remains the least-cost path for Oʻahu in every corrected case,” he said in a statement.
Gov. Green, in an emailed statement, commended the Economic Research Organization for recognizing the “flaws and bias” in the research. “The faulty study and analysis, deeply compromised by vested interests, threatens to set back our collective opportunity to build a sane bridge to a fully renewable future.”
Prior to the retraction, the Energy Office had contested Roberts’ expectation that solar will maintain its cost advantage over other sources. The Energy Office had pointed out that Hawaiian Electric recently submitted power purchase agreements to the Public Utilities Commission for two new Oʻahu solar and battery farms, Puʻuloa Solar and Mahi Solar, at price points of about 21 cents and 23 cents per kilowatt-hour, respectively.
That’s double what grid-scale solar has cost in Hawaiʻi in the past. In the contract document, Mahi Solar developer Longroad Energy noted concerns about Hawaiian Electric’s tenuous financial position since the Maui fires and the rollback of federal incentives for solar projects. That price jump, though, is anomalous in the broader trend of solar costs, which have a long track record of declining over time, while the cost to build gas power plants has been rising amid roiling demand.
Griffin, who as a regulator sparred with Hawaiian Electric to pick up the pace of clean energy to avoid surging oil costs when the state’s last coal plant closed, maintains that much of the delay in Hawaiʻi’s renewables buildout “is self-inflicted.”
“Can we do things better here? One hundred percent,” he said. “Do we have more potential to improve the clean energy pathway? Absolutely.”
Amid these conflicting reports on Oʻahu’s energy pathways, state lawmakers have called on the Public Utilities Commission to step in. Lee, in the state Senate, and Lowen, in the House, introduced resolutions that their respective chambers approved requesting that the commission conduct its own analysis on how to cut costs for residents.
The commission has until the end of the year to return its preliminary findings to lawmakers. In the meantime, Lee said the state shouldn’t tether itself to yet another imported fossil fuel.
“Unless somebody can guarantee the price of an imported fuel at a rate that is far lower, or at least comparable to investing in local renewables, … then I don’t see how the math maths,” Lee said.
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