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It’s hard to make assumptions about cost more than a decade out. Just ask the nuclear startup NuScale.
Every company is, in a certain light, a kind of time machine, and every new product is a missive from the past. When a group of people get together to launch a startup, they’re making a bet that in a few months or years, people are going to want what they’re selling.
In the software industry, the past isn’t too long ago. Because it is possible to code and distribute an app somewhat quickly, a new software product might have only been conceived earlier that year or a year or two earlier.
In a mature consumer-product field — like, say, the car industry — the timeline is longer. A model year 2024 car might have first been conceived of in 2022, and it probably relies on a deeper engineering structure — a “platform” — that might date back to 2018 or earlier. Every new car contains, in essence, two-year-old technology.
But in the “hard tech” industry, the delay can be even longer. It can take more than a decade to get a new type of airplane or power plant to market. These types of technology are the biggest bet of all — because by the time the missive reaches its destination, the world may have changed.
So it was with NuScale, an Oregon-based company developing a small, modular nuclear reactor. Last week, NuScale announced that it was pulling out of a Department of Energy-backed, first-of-a-kind project in Utah.
The company had once planned to build six small, modular nuclear reactors in Utah in conjunction with the Idaho National Laboratory. But despite receiving more than $1 billion in Department of Energy subsidies, NuScale could not make the economics of its project work.
The main problem was that NuScale’s electricity was too expensive. Over the past two years, the estimated price of its project surged, rising by more than 75%. Because electricity projects have to recoup their costs from selling power, those high construction costs helped increase the estimated cost of the project’s electricity by 53%.
By the end, NuScale estimated that power from the project would cost $89 per megawatt-hour. (The average cost of residential electricity in Utah is about $20 per megawatt hour.) Of course, nuclear energy can provide benefits beyond what is captured by price — it is one of the few energy sources that can provide 24/7, zero-carbon electricity — but some costs are too high. NuScale struggled to sell its electrons to nearby towns: It simply could not compete with cheaper electricity from natural gas, solar, or other fuels.
It wasn’t supposed to be like this: NuScale’s smaller size and modular design were supposed to result in lower costs. In essence, NuScale hoped that cost savings would emerge from learning-by-doing and economies of scale — as it got better at making small, modular reactors, it would figure out how to bring down their costs.
That wasn’t a ludicrous idea. Economies of scale have brought down the cost of solar, wind, batteries, and electric vehicles over the past decade. And that idea — that as people do something more, they figure out how to do it more cheaply and efficiently — underpins American and Chinese climate policy.
But the Utah project was the first project of its kind, so NuScale hadn’t yet had the opportunity to take advantage of those economies of scale.
NuScale “shows how much customer matters for a first-of-a-kind deployment. NuScale went down a road that would have proven to be a really interesting model if successful, but it was a lot of legwork,” Ryan Norman, a nuclear analyst at the think tank Third Way, told me. Other advanced nuclear startups have more reliable customer relationships, he added.
Even worse for NuScale, the company found itself building the project amid the worst inflation in a generation. What might have once seemed like a “boring” part of a reactor’s design could create new and spiraling costs.
For instance, NuScale’s design required a lot of concrete, Farah Benahmed, a nuclear policy analyst at Breakthrough Energy, a set of climate investment and advocacy organizations founded by Bill Gates, told me. But concrete costs have risen dramatically, increasing by more than 9% over the past two years and helping to drive the company’s spiraling costs. Other advanced reactor designs don’t rely on concrete to the same degree as NuScale, Benahmed said. (Gates has invested in Terrapower, an advanced nuclear company that competes with NuScale.)
Other key inputs into NuScale’s reactors have also surged in price. From 2021 to 2023, the cost of carbon steel piping more than doubled, according to producer price index data. The cost of fabricated steel plates rose by more than 50%, and the cost of copper wiring rose by 30%.
More broadly, NuScale was founded in 2007 — which means, almost inevitably, that the company was responding to a very different energy moment than the one we have now. At the time, the world was undergoing the first wave of widespread public concern about climate change, driven by Hurricane Katrina, An Inconvenient Truth, and the Intergovernmental Panel on Climate Change’s fourth assessment report. It seemed plausible that Congress might pass a bipartisan cap-and-trade law, which would benefit zero-carbon nuclear power.
Most importantly, U.S. electricity costs were rising, and experts feared they would continue to increase in the 2010s. America’s natural gas supplies seemed to be running out, and the country was preparing to import liquified natural gas in large quantities.
Then came the fracking boom. Cheap natural gas flooded the market, reshaping the domestic energy system and moderating the rise in power prices. The United States never passed a carbon price or a cap-and-trade law. And the economics of building lots of NuScale reactors to provide zero-carbon, 24/7 electricity now look seriously different.
NuScale is not the only clean energy company to run into inflation-driven problems. The offshore-wind company Orsted recently canceled two projects on the Jersey shore due to cost and supply-chain problems. Other offshore projects are also at risk.
Nuclear advocates said that despite its issues, NuScale has accomplished something that no other nuclear startup has. It is the sole nuclear startup to receive approval from the Nuclear Regulatory Commission, the federal agency that must approve nuclear reactors before they can be used. “NuScale has paved the way for how to move through the NRC process. They’re a great example and paved the way for the industry,” Benahmed, the Breakthrough analyst, said.
That approval process took more than four years. It shows another way that it can take years or even decades for “hard tech” companies to get to market — to send their missive from the past to the present.
But despite that long timeline, advocates remain upbeat about the larger industry. “The investor base will do its due diligence to assess what business decisions went wrong with NuScale, but ultimately I think this development is less detrimental to the wave of support we've seen for advanced nuclear from that group,” Norman, the Third Way analyst, said. Because NuScale uses a small version of a light-water reactor — a conventional reactor technology that other advanced-nuclear startups have eschewed — investors probably won’t lose faith in the sector itself.
But they agreed that the make-or-break moment for nuclear is coming up. “The key decision point we need to wrestle with as we continue along the innovation path is: Who is going to lead?” Norma said. “Our allies are waiting. Our competitors are watching. Like it or not, now is the time for the U.S. and industry to prove itself. We've gotta have moxy.”
Editor's note: The original version of this article misidentified one of NuScale’s investors. We regret the error.
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On Trump’s metal nationalization spree, Tesla’s big pitch, and fusion’s challenges
Current conditions: King tides are raising ocean levels near Charleston, South Carolina, as much as eight feet above low water averages • A blizzard on Mount Everest has trapped hundreds of hikers and killed at least one • A depression that could form into Tropical Storm Jerry is strengthening in the Atlantic as it barrels northward with an unclear path.
Solar and wind outpaced the growth of global electricity demand in the first half of 2025, vaulting renewables toward overtaking coal worldwide for the first time on record, according to analysis published Tuesday by the research outfit Ember. This year’s growth resulted in a small overall decline in both coal and gas-fired power generation, with India and China seeing the most notable reductions, despite the United States and Europe ratcheting up fossil fuel usage. “We are seeing the first signs of a crucial turning point,” Malgorzata Wiatros-Motyka, a senior electricity analyst at Ember, said in a statement. “Solar and wind are now growing fast enough to meet the world’s growing appetite for electricity. This marks the beginning of a shift where clean power is keeping pace with demand growth.”
Wind and solar installations matched 109% of new global demand for power in the first half of 2025.Ember
That growth is projected to continue. Later on Tuesday morning, the International Energy Agency released its own report forecasting that renewable capacity will double over the next five years. Solar is predicted to make up 80% of that growth. But, factoring in the Trump administration’s policies, the forecast roughly cut in half previous projections for U.S. growth. Domestic opposition to renewables runs beyond the White House, too. Exclusive data gathered by Heatmap Pro and published in July showed that a fifth of U.S. counties now restrict development of renewables.
President Donald Trump signed an executive order Monday directing federal agencies to push forward with a controversial 211-mile mining road in Alaska designed to facilitate production of copper, zinc, gallium, and other critical minerals. The project, which the Biden administration halted last year over concerns for permafrost in the fast-warming region, has been at the center of a decadeslong legal battle. As part of the deal, the U.S. government will invest $35.6 million in Alaska’s Ambler Mining District, including taking a 10% stake in the main developer, Trilogy Metals, that includes warrants to buy an additional 7.5% of the company. The road itself will be jointly owned by the state, the federal government, and Alaska Native villages. “It’s a very, very big deal from the standpoint of minerals and energy,” Trump said in the Oval Office.
It’s just the latest stake the Trump administration has taken in a mineral company. In July, the Department of Defense became the largest shareholder of MP Materials, the company producing rare earths in the U.S. at its Mountain Pass mine in California. The move, The Economist noted at the time, marked the biggest American experiment in direct government ownership since the nationalization of the railroads in World War I. Last week, the Department of Energy renegotiated a loan to Lithium Americas’ Thacker Pass project in Nevada to take a stake in what’s set to become the largest lithium mine in the Western Hemisphere when it comes online in the next few years. The White House’s mineral shopping spree isn’t over. On Friday, Reuters reported that the administration is considering buying shares in Critical Metals, the company looking to develop rare earths production in Greenland. In response to the news, shares in the Nasdaq-traded miner surged 62% on Monday. Partial nationalization isn’t the only approach the administration is taking to challenging China’s grip over global mineral supplies. Last month, as I reported for Heatmap, the Defense Logistics Agency awarded money to Xerion, an Ohio startup devising a novel way to process cobalt and gallium.
Tesla looks poised to unveil a cheaper, stripped-down version of its Model Y as early as today. In one of two short videos posted to CEO Elon Musk’s X social media site, the electric automaker showed the midsize SUV’s signature lights beaming through the dark. The design matches what InsideEVs noted were likely images of the prototype spotted on a test drive in Texas. The second teaser video showed what appears to be a fast-spinning, Tesla-branded fan. “Your guess is as good as ours as to what will be revealed,” InsideEVs’ Andrei Nedelea wrote Monday. “Our money is on the Roadster or a new vacuum cleaner design to take on Dyson.”
The new products come amid an historic slump for Tesla. As Heatmap’s Matthew Zeitlin reported, the company’s share of the U.S. electric vehicle sales sank to their lowest-ever level in August despite the surge in purchases as Americans rushed to use the federal tax credits before they expired thanks to Trump’s landmark One Big Beautiful Bill Act law. Yet Musk has managed to steer the automaker’s financial fate through an attention-grabbing maneuver. Last month, the world’s richest man bought $1 billion in Tesla shares in a show of self confidence that managed to rebound the company’s stock price. But Andrew Moseman argued in Heatmap that “the bullish stock market performance is divorced not only from the reality of the company’s electric car sales, but also from, well, everything else that’s happened lately.”
On Monday, Trump warned that medium and heavy-duty trucks imported to the U.S. will face a 25% tariff starting on November 1. The president announced the trade levies in a post on Truth Social on the eve of a White House visit by Canadian Prime Minister Mark Carney, whose country would feel the pinch of tariffs on imported trucks. As the Financial Times noted, Trump had threatened to impose 25% tariffs on some trucks in late September but “failed to implement them, raising questions about his commitment to the policy.”
Fusion startups make a lot of bold claims about how soon a technology long dismissed as the energy source of tomorrow will be able to produce commercial electrons. Though investors are betting that, as Heatmap’s Katie Brigham wrote last year, “it is finally, possibly, almost time for fusion,” a new report from the University of Pennsylvania’s Kleinman Center for Energy Policy shows that supply chain challenges threaten to hold back the nascent industry even if it can bring laboratory breakthroughs to market. Tritium, one of two main fusion fuels, has a half life of just 12.3 years, meaning it does not exist in significant quantities in nature. Today, tritium is primarily produced by 30 pressurized heavy water fission reactors globally, but only at a total of 4 kilograms per year. As a result, “tritium availability could throttle fusion development,” the report found. That’s not the only bottleneck. “The fusion industry will require specialized components that don’t yet have well-established supply chains, like superconducting cables and the aforementioned advanced materials, and shortages of these components would delay development and inflate costs.”
Scientists mapped the RNA — the molecules that carry out DNA’s instructions — of wheat and, for the first time, identified when certain genes are active. The discovery promises to accelerate plant breeders’ efforts to develop more resilient varieties of the world’s most widely cultivated crop that use less fertilizer, resist higher temperatures, and survive with less water as the climate changes. “We discovered how groups of genes work together as regulatory networks to control gene expression,” Rachel Rusholme-Pilcher, the study’s lead author and a researcher at Britain’s Earlham Institute, said in a statement. “Our research allowed us to look at how these network connections differ between wheat varieties, revealing new sources of genetic diversity that could be critical in boosting the resilience of wheat.”
Shine Technologies is getting close to breakeven — on operations, at least — by selling neutrons and isotopes.
Amidst the frenzied investment in fusion and the race to get a commercial reactor on the grid by the 2030s, one under-the-radar fusion company has been making money for years. That’s Shine Technologies, which has been operating in some form or another since 2005, making neutrons for materials testing and nuclear isotopes for medical imaging, all while working toward an eventual energy-generating reactor of its own.
“I think we can moonshot ourselves to net energy,” Greg Piefer, founder and CEO of Shine, told me, referring to the point at which the energy produced from a fusion reaction exceeds the energy required to sustain it. “But I don’t think we can moonshot ourselves to break even costwise.”
Rather than trying to build a full-scale reactor that can produce net energy via a self-sustaining fusion reaction right off the bat, Shine uses a particle accelerator to drive a series of small-scale fusion reactions. When high-energy ions connect with fuels, such as tritium or deuterium, they undergo a fusion reaction that produces high-energy neutrons and specialized isotopes more often generated for use in industry via fission.
Piefer, who has a PhD in nuclear engineering from the University of Wisconsin-Madison, started up his company by making neutrons for materials testing in the aerospace and defense industries. Unlike other forms of radiation, such as X-rays, neutrons can penetrate dense materials such as metals, hydrogen-containing fuels, or ceramics, making it possible to spot hidden flaws. An otherwise invisible crack in a turbine blade, for example, could still block or scatter neutrons, while contamination from water or oil would absorb neutrons — making these faults clear in a radiographic image.
Scientists also use neutrons to test nuclear fission fuel by identifying contamination and verifying uranium enrichment levels. According to Piefer, Shine produces the neutrons used to test half of all fission fuel today. “Fusion actually already enables the production of 50% of the fission fuel in this country,” he told me.
My mind was blown. I didn’t understand how fusion — a famously expensive endeavor — could be an economically viable option for these applications.
Piefer understood. “I’ll sit here in one breath and I’ll tell you fusion is way too expensive to compete making electricity, and in another breath that it’s much cheaper than fission for making isotopes and doing testing,” he said. As Piefer went on to explain, if the goal isn’t net energy, you can strip the fusion reactor of a good deal of complexity — no superconducting magnets, complicated structures to produce tritium fuel, or control systems to keep the burning fusion plasma contained.
With a simplified system, Piefer told me, it’s much easier to produce a fusion reaction than a fission reaction. The latter, he explained, “operates on the razor’s edge of something called criticality” — a self-sustaining reaction that must be precisely balanced. If a fission reaction accelerates too quickly, power surges dangerously and you get a disaster like Chernobyl. If it slows, there’s simply no reaction at all. Plus, even after a fission reactor shuts down, it keeps producing heat, and thus must be actively cooled. But when it comes to fusion, there’s no danger of an out of control power surge, because, unlike fission, it’s not a chain reaction — if the input conditions change, fusion stops immediately. Furthermore, fusion produces no heat after the reaction stops.
Some of Shine’s customers include manufacturers of turbine blades and explosives such as the U.S. Army and GE Hitachi, as well as the biopharmaceutical companies Blue Earth Therapeutics and Telix Pharmaceuticals. Piefer told me that the company is now “on the verge of essentially breakeven” — no fusion pun intended — when it comes to its operating expenses. These days, it’s reinvesting much of its revenue to build out what Piefer says will be the largest isotope production facility in the world in Wisconsin. Isotopes are created when high energy neutrons strike stable elements, causing the nuclei to absorb the neutron and become radioactive. The isotope’s radioactive properties make them useful for targeting particular tissues, cells, or organs in medical imaging or focused therapies..
Shine’s in-progress facility will primarily produce molybdenum‑99, the most commonly used isotope for medical imaging. The company already operates one smaller isotope facility producing lutetium-177, which features in cutting-edge cancer therapies.
Compared to materials testing, producing medical isotopes has required Shine to increase the temperature and thus the efficiency of its fusion target. Subsequent applications will require greater efficiency still. The idea is that as Shine applies its tech to increasingly challenging and energy-intensive tasks, it will also move step by step toward a commercially viable, net-energy-generating fusion reactor. Piefer just doesn’t know what exactly those incremental improvements will look like.
The company hasn’t committed to any specific reactor design for its fusion energy device yet, and Piefer told me that at this stage, he doesn’t think it’s necessary to pick winners. “We don’t have to, and don’t want to,” he said. “We’ve got this flexible manufacturing platform that’s doing all the things you need to do to get really good at making fusion systems, regardless of technology.”
Fusion energy aside, the company doesn’t even know how it’s going to reach the heat and efficiency requirements needed to achieve its next target — recycling spent fission fuel. But Piefer told me that if Shine can get there, scientists do already understand the chemistry. First, Shine would separate out the long-lived, highly radioactive waste products from the spent fuel using much the same approach it uses for isolating medical isotopes, no fusion reaction needed. Then, Piefer told me, “fusion can turn those long-lived wastes into short-lived waste” by using high-energy fusion neutrons to alter the radioactive nuclei in ways that make them decay faster.
If the company pulls that off — a big if indeed — it would then move on to building an energy-generating reactor. Overall, Piefer guesses this final stage will wind up taking the fusion industry “more time and money than most people predict.” Perhaps, he said, investors will prove willing to bankroll buzzy fusion startups far longer than their ambitious timelines currently imply. But perhaps not. And in the meantime, he thinks many companies will end up turning to the very markets that Shine has been exploring for decades now.
“So we’re well positioned to work with them, well positioned to help create mutual success, or well positioned to use our position to move ourselves forward,” Piefer told me, hinting that the company would be interested in making acquisitions.
Indeed, some fusion companies are already following Shine’s lead, eyeing isotopes as an early — or primary — revenue generating opportunity. Microreactor company Avalanche Energy eventually wants to replace diesel generators, but in the meantime plans to produce radioisotopes for medical and energy applications. U.K.-based fusion company Astral Systems is also making desktop-sized reactors, but with the central aim of selling medical isotopes.
If too many companies break their promises or extend their timelines interminably, as Piefer thinks is likely, more and more will come around to the pragmatism of Shine’s approach, he said. “Near term applications are increasingly talked about,” Piefer told me. “They’re not the highlight of the show yet, but I’d say the voice is getting louder.”
So while he still doesn’t have any idea what the final form for Shine’s hypothetical fusion power plant will take, in his mind the company is leading the race. “I believe we’re actually on the fastest path to fusion commercialization for energy of anybody out there,” Piefer told me. “Because commercial is important to us, and it always has been.”
The state quietly refreshed its cap and trade program, revamped how it funds wildfire cleanup, and reorganized its grid governance — plus offered some relief on gas prices.
California is in the trenches. The state has pioneered ambitious climate policy in the United States for more than two decades, and each time the legislature takes up the issue, the question is not whether to expand and refine its strategy, but how to do so in a politically and economically sustainable way.
With cost of living on everyone’s minds — California has some of the highest energy costs in the country — affordability drove this year’s policy negotiations. After a bruising legislative session, however, California emerged in late September with six climate bills signed into law that attempt to balance decarbonization with cost-reduction measures — an outcome that caught many climate advocates off guard.
“It was definitely touch and go whether this was all going to come together,” Victoria Rome, the director of California government affairs for the Natural Resources Defense Council, told me. “It was a lot of complicated policy to put forward in a relatively short time frame.”
The package reauthorizes California’s signature cap and trade program, rebranded as “cap and invest,” with a slight tweak that will help lower electricity bills. It clears a major hurdle to creating a more integrated Western electricity market that has the potential to deliver cleaner energy throughout the region at lower cost. It replenishes a rapidly diminishing wildfire fund that ensures utilities don’t go belly-up when they’re found liable for wildfires — and offsets the cost to customers by limiting how much of the cost of transmission upgrades utilities are allowed to pass on. And lastly — and most controversially — in an attempt to stabilize gasoline prices, it streamlines approval of new oil wells in Kern County, California.
Not everyone was happy with the compromise. The Center for Biological Diversity condemned the oil and gas bill, while environmental justice advocates were angry that lawmakers did not do more to protect low-income communities in the reform of cap and trade. It also remains to be seen how much the cost containment measures will help. Some of them, like the new Western electricity market, likely won’t pay off for many years. The cap and trade extension could ultimately exacerbate costs.
A few other groundbreaking climate-related bills are still sitting on Newsom’s desk, such as one that would set a safe maximum indoor temperature, requiring landlords to provide cooling to tenants, and another that would override local zoning rules to allow taller, denser housing to be built near public transit. He has until next Monday to sign them. But even without those, the package illustrates how California Democrats are at least trying to leverage the new politics of affordability to advance their climate goals, and the ways in which the two are difficult to align.
Here’s a breakdown of the major changes.
California’s cap and trade program is the state’s centerpiece climate policy. It puts a price on pollution by requiring dirty industries to buy and retire state-auctioned “allowances” for every ton of carbon they emit, with a declining amount of allowances released into the market each year. Funds raised through allowance sales are funneled into utility bill credits for consumers as well as climate-friendly projects throughout the state.
Prior to last month’s legislation, the program was only authorized to continue through 2030, and the closer that date got, the greater the uncertainty became about whether it would continue. According to one analysis, that uncertainty cost the state $3.6 billion in revenues over the year ending in May 2025 as companies relied on allowances they’d stocked up on in previous years, when they were cheaper and more plentiful. If the program was going to expire in 2030, there was less incentive to collect more — or to invest in emission-reducing solutions like replacing their boilers with industrial heat pumps.
The legislature extended cap and trade through 2045, rebranding as “cap and invest” — a more politically resonant title originating in Washington State that highlights the revenue-raising aspect of the program. It also introduced several key reforms. By 2031, earnings from the program reserved for utility credits will go exclusively toward electric bill savings, i.e. it will no longer subsidize residential gas. “The general idea was that almost every gas customer is an electric customer,” Danny Cullenward, a California-based climate economist and lawyer, told me. “And so if you shift the same total dollars from gas and electric to just electric, you concentrate the benefits on the electric side, which supports building decarbonization, but you don’t take any dollars away from the customer.”
California has the highest electric rates in the continental U.S., and so right now, switching from using natural gas to all-electric appliances is not in everyone’s best interest. Providing more relief on the electric side will help with that — especially as the price of allowances increases in the coming years, translating into more revenue to fund bill credits. The legislation also directs electric utilities to apply the credits over the summer, when bills are highest, rather than on the twice-a-year schedule they used previously.
The other major reform has to do with the way carbon offsets are integrated into the program. Previously, companies could purchase offsets instead of allowances to account for a certain amount of their emissions, giving them a cheaper way to comply. Now, every time a company retires an offset instead of an allowance, the state will also retire an allowance. This is an implicit recognition by lawmakers that carbon offsets haven’t been effective at reducing emissions, Cullenward told me.
While he called the extension of cap and invest a “profound and important accomplishment,” Cullenward also raised major concerns about its future impacts on affordability. The program literally puts a price on carbon, after all, and that price is now set to rise, pervading much of California’s economy, from the pump to the cost of goods and services. “Outside of my hope that this will be a net benefit for electric utility ratepayers, which I think is a very good and positive thing, this is not an affordability bill,” he told me.
Lawmakers have done nothing to mitigate the program’s effect on gasoline and diesel costs, he pointed out. They also haven’t addressed the elephant in the room — a $95 price ceiling on allowances that, if they ever get there, may be politically untenable. (Right now prices are around $30.) State regulators now have a chance to revise the price ceiling, Cullenward said, ideally with an eye toward balancing ambition with consumer cost impacts. “That’s the main part of the work that is completely not yet done,” he said.
Energy nerds throughout the West have been scheming to unite its disparate grids for years. Unlike the entire eastern half of the country, where utilities buy and sell energy across state lines in competitive markets on both a daily and realtime basis, and work together to plan transmission upgrades throughout their territories, most Western states do all of their energy trading through longer-term bilateral contracts.
After years of failed efforts to change that, lawmakers have finally given California’s grid operator their blessing to work with other states in the region on creating such a market. Proponents argue that more competition and coordination between utilities in the West will create efficiencies that save money, improve reliability, and accelerate decarbonization. For example, California, which often produces more solar energy than it can use during the day, would be able to sell more of that power to other states. When there’s a heat wave coming, it’ll have more supply to draw from.
To be clear, California was already working on all this prior to last month’s legislation. The state’s grid operator launched a realtime electricity trading market in 2014, which now has 21 utility participants throughout the West. Next year it will launch an extended day-ahead market, enabling utilities to buy power about a week in advance of when they’ll need it. That will initially have just two participants, PacifiCorp and Portland General Electric, with five others planning to join in later years.
But seven companies does not a competitive market make. To grow to its fullest potential, the day-ahead market will need many more participants. That was always going to be a tough sell so long as California was in charge, Vijay Satyal, the deputy director of regional markets at the nonprofit Western Resource Advocates, told me. CAISO, California’s grid operator, is overseen by a governor-appointed board, “which is one reason why the larger West never wanted to be part of CAISO, if the governance and decision making would be controlled by the governor of one state,” he said.
An effort is already underway between state officials, utilities, and other stakeholders, including those from California, to create an independently-governed Western Energy Market called the West-Wide Governance Pathways Initiative. The new legislation grants CAISO permission to transition governance of its realtime and day-ahead markets to the organization that comes out of that effort — as long as the group meets certain requirements around transparency and engagement with state leadership.
“Now there’s opportunity for all the utilities across the West to come together and for clean energy developers to be part of a larger market and be transparent, independent, and not controlled by one state’s policies,” Satyal told me. The other advantage of having this regional organization is that it can engage in more coordinated transmission planning — another potential cost-saving measure.
Wildfires have been a huge part of California’s electricity affordability crisis. Case in point: Since 2019, Californians have had to pay an extra fee on top of their electric bills that goes into a state Wildfire Fund to help utilities cover post-wildfire loss and damage claims — a sort of insurance mechanism to prevent utility insolvency.
This year, lawmakers were under pressure to add more money to the pot. Experts worried that without another infusion, payments related to January’s Eaton Fire in Los Angeles, which the U.S. Department of Justice alleges was caused by faulty utility equipment, would deplete much of what’s left.
The legislature extended the fee, adding $18 billion to the Wildfire Fund that will be split evenly between ratepayers and utility shareholders over the next decade. But it also passed several measures that will help offset that cost by minimizing future rate increases. First, utilities will be prohibited from earning a profit on the first $6 billion they spend on wildfire mitigation projects, such as burying power lines, starting next year. Companies will be required to finance this spending more cheaply through ratepayer-backed bonds rather than through equity, which commands a higher rate of return.
On top of that, the legislature directed the governor’s office to create a “Transmission Infrastructure Accelerator,” a program that will develop public financing options for new transmission lines, such as low-cost loans, revenue bonds, or even partial public ownership of the projects. The program will have a dedicated “Revolving Fund” that will be replenished each year with a portion of cap and invest revenue.
“It is the largest electricity affordability measure in the whole package,” Sam Uden, the co-founder and managing director for the nonprofit policy shop Net Zero California, told me — to the tune of $3 billion in savings per year once the new lines are constructed, according to an analysis his group commissioned.
Gavin Newsom has not necessarily been a friend to the oil industry. He’s instituted distance requirements for new oil wells barring drilling near homes and schools, and given local jurisdictions more authority over drilling. But gasoline prices — ever a political issue in California — have tested his resolve. The price at the pump in California has averaged around a dollar higher than the rest of the U.S. for the past several years, and that margin has crept up closer to $1.30 this year. After two of the state’s refineries announced they would close this year and next, threatening to drive prices higher, Newsom backed a bill this session to increase oil production in Kern County.
Uden of Net Zero California justified the bill as a “short term measure.” The provisions that streamline drilling permits only apply through 2036. “We are really trying to grapple with what is a very difficult transition,” he told me. “We’ve got to phase down oil, but we can’t do it in a way that just spikes gas prices.”
It’s unclear, however, whether more drilling in Kern County will do much to address the problem — especially if the cap and invest program continues to drive up prices, as Cullenward fears. At least to date, the state’s high gasoline prices have not been caused by a lack of gasoline supply, according to University of California, Berkeley, economist Severin Borenstein. The bigger factors driving price increases are taxes and environmental fees and the special blend of gasoline required by the state’s air quality regulators.
What will drive prices up are refinery closures. Lawmakers are making a bet that increased in-state oil production will prevent further closures by giving refineries access to cheaper crude. But Borenstein notes that the state will continue to rely on crude imports, meaning the price of gasoline will still be tied to the global market. His preferred solution to keep prices in check is to remove barriers to importing more refined gasoline.
“The longer run challenge is to balance refining supply and demand, which oil production doesn’t address,” Borenstein wrote.
Michael Wara, a senior research scholar at Stanford University’s Woods Institute for the Environment, agreed on the urgency of opening a new import terminal. He told me he saw the Kern County bill as a way to buy time. “We’ve done the kind of stopgap measure. The increased permits will help stabilize Northern California refineries for probably a couple years,” he said. “But if we don’t use that couple of years in the right way, then we will be in big trouble.”
Wara also wasn’t too worried about the measure creating some kind of oil Renaissance. “Permits are one thing. The decision to actually drill a well is an economic decision that’s going to be driven by oil prices, which are pretty low right now. I don’t think anybody thinks that handing out more permits is going to stem the decline in that industry.”