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The all-American EV startup is cutting costs to survive.

America’s most interesting electric-vehicle company is about to have the defining year of its life.
On Wednesday, the company reported that it lost $1.58 billion in the fourth quarter of last year, bringing its net annual losses to $5.4 billion. It announced that it is laying off about 10% of its salaried employees, but — at the same time — promised that it has a plan to achieve a small profit by the end of this year.
Rivian does not seem to be in trouble — not quite yet, at least. But the earnings made clear what electric-vehicle observers have known for a long time: Either the company will emerge from this year poised to be a winner in the EV transition, or it will find itself up against the wall.
That’s partially because Rivian has a stomach-turning number of corporate milestones coming up. Over the next 11 months, it plans to unveil an entirely new line of vehicles, shut down its factory for several weeks for cost-saving upgrades, break ground on a new $5 billion facility in Georgia, and — most importantly — turn a profit for the first time. It also expects to manufacture and deliver roughly another 60,000 vehicles to customers.
Any one of these goals would be difficult to achieve in any environment. But Rivian is going to have to execute all of them during a time defined by “economic and geopolitical uncertainties” and especially high interest rates, its CEO R.J. Scaringe told investors on Wednesday. Since 2021, Rivian’s once robust stockpile of cash has been cut in half to about $7 billion; at its current burn rate, the company will run out of money in a little more than two years.
Although Rivian’s situation is dire, it’s not experiencing anything out of the ordinary. As I’ve written before, the electric truck maker is crossing what commentators sometimes call “the EV valley of death.” This is the challenging point in a company’s life cycle where it has developed a product and scaled it up to production — thereby raising its operating expenses to eye-watering levels — but where its revenue has not yet increased too.
During this vulnerable period, a company essentially burns through its cash on hand in the hope that more customers and serious revenue will soon show up. If those customers don’t arrive, then it either needs to raise more cash … or it runs out of money and goes bankrupt.
It’s a frightening time, but once a company crosses the valley of death, it can reach an idyll. Not so long ago, Tesla found itself in something like Rivian’s position as it prepared to launch the Model 3. Seven years later, it is the most valuable automaker in the world.
Once Rivian’s revenue exceeds its costs, its problems will get easier, or at least more straightforward: Instead of fighting for its survival and watching its cash reserves dwindle, Scaringe will be able to make more strategic trade-offs. Should the company cut costs to expand its profit margin and reward investors, or should it pass the savings along to customers in the form of lower prices, thus growing its market share? Scaringe can’t make these types of decisions until his firm is safely out of the valley.
Claire McDonough, Rivian’s chief financial officer and a former J.P. Morgan director, has a plan for crossing that canyon — an aptly if strangely named “bridge to profitability” that it will attempt to build this year. Rivian’s survival, she said, will depend above all on cutting the unit costs of producing its vehicles, including by using fewer materials to make every car. Other savings will come from making more vehicles faster. That’s what makes the shutdown plan, though it might seem extreme, worth it; McDonough said those improvements alone will get the company about 80% of the way to profitability.
Another 15% will come from marketing more “software-enabled products” to Rivian drivers and by selling air-pollution credits to other carmakers, whose vehicles are not as climate-friendly. This is a tried-and-true technique; Tesla first turned a profit in 2021 by selling regulatory credits needed to comply with federal and California state-level rules to other, dirtier automakers. But that same year, Tesla also debuted an entirely new vehicle: the Model Y crossover, which quickly became its top seller in the United States. Tesla, in other words, finally started to make money by cutting costs, finding new revenue sources, and releasing new products.
New products, however, are becoming a weak point for Rivian. The company says that high interest rates will keep demand for its vehicles flat this year. It expects to make about 60,000 of them, about 20,000 fewer than what it had once anticipated. The Rivian R1S, a three-row S.U.V., has become the company’s flagship; it is selling better and is cheaper to manufacture than Rivian’s pickup, the R1T. It also costs at least $75,000, or nearly $600 a month to lease. The highest-tier models can cost $99,000. Turns out, it’s difficult to sell a lot of $70,000 trucks when even the cheapest new-car loans hover around 6%.
Rivian once had a first-to-market advantage in the electric three-row SUV market, but that may be fizzling out, too. Kia is now selling its own all-electric three-row SUV, the EV9, for $18,000 less than the R1S; in fact, the Kia EV9’s most expensive trim costs $76,000, which is only slightly more than the cheapest R1S. The Kia SUV can also charge faster than the Rivian under ideal conditions. It remains an open question how many rich suburbanites are still interested in buying Rivians, especially now that the Tesla Cybertruck and Ford F-150 Lightning are competing directly with Rivian’s pickup truck.
The company’s hopes, in other words, rest on its next product line: the R2, which it will launch on March 7. We know almost nothing about the R2 line, except that it will probably include an SUV, that it will go on sale in 2026, and that it will fall somewhere in the $45,000 to $55,000 price range. (The median new car transaction in the United States now costs $48,200.) Last year, Scaringe told me that the R2’s timing was perfect because it would fit “beautifully with what we see as this big shift” in the American EV market. In today’s market, he said, “a lot of people ask themselves, Am I gonna get an electric car? Well maybe the next one.” He better hope they’ll start buying that next one in 2026.
Even if they do, Rivian may still have to confront the problem that Tesla has changed the EV market before Rivian could get there. When the first Tesla Model 3s were delivered in 2017, the sedan was instantly one of the best EVs on the market — because it was one of the only EVs on the market. Now every automaker in the world has plans to compete at the Model 3’s price point.
Rivian’s fortunes don’t rest entirely on American consumers; it also sells vans to commercial fleet operators, as well as delivery trucks to Amazon. (Amazon owns about 17% of Rivian.) But that business can be lumpy. Rivian’s vehicle growth slowed down last quarter, for instance, almost entirely because of a near pause in sales to Amazon, which sets up fewer new vehicles in the fourth quarter. If Amazon is willing to bail out Rivian, in other words, it’s not yet clear in the data.
None of this is to say that the company’s outlook is dire. Rivian was always going to find itself at a moment like this, when its expenses exceeded its revenue by such a large amount. The automaker already has devoted fans, and many people — myself included — are interested in the R2 as a potential first EV purchase.
And the company has shown that it can make strides in a single year. Twelve months ago, I had never seen a Rivian on the road before; today, one is regularly parked on my block. The company rocketed from a standing start to become the No. 5 best-selling electric car brand in America last year. What the company has done so far is impressive. But now it must prove that it can be great.
Editor's note: This story has been updated to correctly reflect Rivian's cash burn rate.
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The problem isn’t just affordability, two researchers from Heatmap and MIT’s Electricity Price Hub argue. Bill volatility also creates pain for electricity consumers.
Americans have come to expect shocking electricity bills, especially in the summer months. The latest data from the Electricity Price Hub makes clear: Households in every region of the country are seeing not just record high July bills, but also bills that are sharply higher than even just a few months before.
Some may see these trends and argue that utilities and regulators set rates, but bills are ultimately the result of consumer choices about how much electricity to use. But that narrative misses the mark for a simple reason: How utilities and regulators design rates influence both summer bill swings and how much electricity consumers use. Seasonal rates and other features of electricity pricing can exacerbate summer bill swings and inform customers’ decisions about whether certain electricity uses — even running the air conditioner on an extremely hot day — are worth it.
The scale of this summer’s electricity bill increases is striking. Nationwide, the average household electricity bill was $90 per month, or 71% higher in July than it was in April of this year. Not only are bills up, they are up from a high base. The national average bill in April 2026 was higher than any previous April average in the Electricity Price Hub data, and 37% higher than the national average in April five years ago.
These trends are not just driven by a few states. There are households in every corner of the country experiencing sharp increases in their power bills this summer.
At the state level, average household bills have increased the most in New Jersey (up 163%), Nevada (157%), and Oklahoma (133%), but bills have at least doubled in 11 states and are up 1.5 times in 24 more.
In 19 different states, average household bills from major utilities at least doubled from April to July, adding between $72 and $214 per month to their average customers’ bills. In 12 of those states — including some in the Northeast, Mountain West, South, and Southeast — more than 40% of all households are served by utilities whose average bills have at least doubled this summer.
Greater electricity use is a big part of what’s at play in these trends, but it’s not the whole story. Higher summer rates also contribute, in many cases. Rate design, market conditions, and regulatory processes can all cause electricity prices to change throughout the year.
Some utilities, for instance, have rates that vary seasonally, automatically adjusting in the summer months. Seasonal rates contribute to summer bill increases for eight of the 10 utilities whose average bill increased most from April to July. For three of those utilities, over half of the April-to-July increase was driven by seasonal rates. For another five, seasonal rates play a meaningful role, compounding usage-driven increases. For only two does the increase come back to usage alone.
Taken together, these findings suggest that summer bill shocks are not simply a function of warmer weather. In many cases, they also reflect deliberate choices about how utilities price electricity during the summer months.
Even where higher usage is the primary driver of rising summer bills, the way utilities structure rates influences how much customers can save by using less electricity or shifting when they consume power.
Across the utilities with the largest April-to-July bill increases, there is considerable variation in how they calculate a customer’s monthly bill. All include a mix of fixed monthly fees and charges based on usage, measured in dollars per kilowatt-hour. But the balance between these components differs significantly, with fixed charges contributing from 4% to 23% of average bills over the past 12 months. Some utilities apply the same per kilowatt-hour rate year-round, while others increase rates in the summer. For some, the same rate applies to the total amount of electricity customers use in a month, while others have rates that increase for higher tiers of usage.
That means the design of residential rates also determines how much households actually benefit from using less electricity. Two households may receive similar-sized bills, but depending on how their utilities structure their rates, customers can see very different savings from cutting back.
The three New Jersey utilities in the top 10 illustrate one approach: They all have relatively small fixed customer charges, along with per-kilowatt-hour rates that vary both seasonally and by usage tier. For example, Jersey Central Power & Light’s distribution charge shifts from a single volumetric charge in the winter to a tiered structure in the summer, with usage above 600 kilowatt-hours priced at a higher rate. This structure contributes to sizable seasonal bill swings, but it also creates a strong financial incentive to limit summer usage.
The average household in JCP&L’s service area used more than 1,000 kilowatt-hours in July 2025. Had that household used 15% less electricity, it would have saved roughly $50 that month; a 25% reduction would have saved $82. At current rates, a 25% reduction in usage would cut the average bill by 28%, and every 4 kilowatt-hour reduction in usage over 600 kilowatt-hours saves a dollar.
Nevada Power takes a different approach. Its residential rate consists of a larger fixed customer charge — contributing 14% of total average bills over the last year — and a set of volumetric rates that do not vary by season or usage level. As a result, consumers have less of a financial incentive to reduce consumption. A household would need to reduce usage by roughly 8.4 kilowatt-hours to save a dollar, and cutting electricity use by 25% would reduce the bill by about 23% — meaningfully less than under JCP&L's structure.
While seasonal variability in bills is expected and not on its face problematic, it is important to recognize that unpredictability and month-to-month volatility in power bills can compound energy affordability challenges. And although regulators cannot control the weather, the choices they make about rates influence the agency households have in managing their bills each month.
This then raises the question: Should utilities and regulators consider bill stability and its impact on affordability in setting rates? Staff for the Arizona Corporation Commission, which is currently considering requests from the state’s two investor-owned utilities to raise average household bills by around 15%, recently testified that “affordability and energy burden are not pertinent to ratemaking” — that they are, instead, “societal issues.” But that is exactly the wrong sentiment.
Affordability and bill stability both deserve to be explicit considerations in ratemaking, carefully weighed against other objectives and not dismissed or treated as an afterthought. Doing so may look different in different places and does not require prioritizing bill stability over all else. But where households are struggling to manage unpredictable power bills, regulators should be sensitive to those trends and lend greater weight to measures that boost households’ ability to manage usage and limit bills, should they choose to.
That may mean more effective and targeted energy efficiency and demand response programs and incentives for utilities to promote uptake. In some cases, it may call for better customer education on available rate schedules and ways to manage bills, and ultimately it may require more modern rate design. Whatever the response, stability is part of affordability. Wild bill swings add to the burden of record-high bills — a fact that utilities and regulators cannot afford to ignore.
On Trump’s mineral deals, the gas turbine backlog, and Turkic offshore wind
Current conditions: Tropical Storm Lala could strengthen into a hurricane before hitting Hawaii’s Big Island, becoming the first such storm to make landfall there since 1900 • A glacial outburst at Suicide Basin near Juneau, Alaska, is raising the Mendenhall River • Temperatures surpassed 107 degrees Fahrenheit in Zaragoza, the inland capital of Spain’s Aragon region.

The United States is rapidly approaching a two-decade streak as the world’s No. 1 producer of natural gas. The country held the top spot between 2009 and 2024, the latest year for which the U.S. Energy Information Administration has data. But America pumped record volumes of natural gas last year. And now the federal energy research agency forecasts 2026 will be another record year. Marketed natural gas production — the total volume that actually makes it to market, minus what’s burned off or leaks as waste — is set to reach an average of 122.5 billion cubic feet per day in 2026, up from 2025’s record of 118.5 billion cubic feet per day. The new milestone is the result of expanded drilling in the Permian region that straddles Texas and New Mexico, and in the Haynesville area, between Texas and Louisiana.
When the Trump administration first started buying up equity stakes in mining companies, former officials from the Biden administration told my colleague Matthew Zeitlin they were “jealous” that the Republican White House had the guts to try something novel to compete with China on the metals needed for defense and energy technologies. Now, however, top Democrats are asking federal watchdogs to probe whether the American taxpayer is actually getting good deals. New Mexico Senator Martin Heinrich, the ranking member of the Senate Energy and Natural Resources Committee, and Representative Jared Huffman, the top Democrat on the House Natural Resources Committee, called on the Government Accountability Office to open an investigation into potential conflicts of interest. In a letter sent last week to Acting U.S. Comptroller General Orice Williams Brown and published Thursday on E&E News, the lawmakers accused the White House of violating rules to assess the financial risk of federal purchases. “These equity acquisitions also create potential conflicts of interest for federal agencies because a significant portion of the planned mining operations are located on federal lands,” they wrote. “With the executive branch now holding direct financial equity in these private mining operations, the federal government is required to act simultaneously as a mining investor and land-use regulator, an inherent conflict of interest.”
Mitsubishi’s backlog of orders for large-frame gas turbines is now more than twice its output from last year. In the 2025 fiscal year, the Japanese industrial giant delivered 16 gigawatts of gas turbines and had a backlog of 23 gigawatts. Just halfway through 2026, that backlog has ballooned to 35 gigawatts, executives told investors on the latest quarterly earnings call. The update, announced in Japan last week and covered in English by Utility Dive on Thursday, shows that “demand for large-frame gas turbines remains broadly in line with, or slightly above, the strong level we had anticipated,” Hiroshi Nishio,the chief financial officer of Mitsubishi Heavy Industries.
Power electronics maker Heron Power, meanwhile, unveiled plans for a $100 million factory in Morgan Hill, California. The startup, led by a former Tesla executive, aims to produce next-generation transformers that can patch more solar panels and batteries on the grid and help ease some of the issues that arise from the direct current-based electricity sources. The first factory is designed to churn out 40 gigawatts of Heron Links, the transformer product, per year. “America's grid has to grow faster than it has in decades. We’re seeing new demand from AI and EVs, and at the same time new supply from solar and storage,” Drew Baglino, Heron Power’s chief executive and founder, said in a statement. “The equipment running the grid hasn’t changed in 50 years. Heron Factory One in Morgan Hill is how we fix that. We’re manufacturing the leapfrog technology our grid needs, at scale, in America first.”
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Offshore wind is in retreat in the U.S., where, as my colleague Robinson Meyer wrote this week, the Trump administration is paying billions to kill projects that were already dead or dying. The industry’s tide is also ebbing in Japan, where the new right-wing government of Sanae Takaichi is putting a heightened focus on nuclear power. Elsewhere, however, offshore wind is booming. Europe is only expanding its plans. China is steadily dominating the industry. And East Asian countries such as South Korea and Taiwan are expanding their sectors.
Now two of the richest countries in the Turkic world are laying plans for more offshore turbines. Turkey announced plans this week for its first offshore wind tender in the first quarter of 2027, Renewables Now reported. Azerbaijan, meanwhile, this week formally designated a 275-square-mile section of water in the Caspian Sea for offshore wind development, per offshoreWIND.biz. The moves highlight the extent to which the U.S. government stands alone in its view that offshore wind has no role in a modern electricity mix. Turkey, after all, is doubling its domestic production of gas and completing its first nuclear plant. Azerbaijan is famously rich in natural gas and produces a decent amount of hydropower. Yet both countries are still charging ahead on offshore wind.
Deep-sea mining isn’t yet technically legal in international waters. But the Trump administration isn’t waiting, creating the regulatory frameworks for domestic approvals and opening the area around one of America’s Pacific territories to exploration. Japan has been eager to follow suit. Now Washington and Tokyo are planning to meet “centuries’ worth of industrial demand” by establishing what Mining.com called the world’s deepest undersea mine in a bid to take on China’s mineral dominance. The mineral extraction would take place more than 1,000 miles southeast of Tokyo on an uninhabited speck of land called Minamitorishima, where Japanese scientists carried out tests pulling rare earths out of mineral-rich mud.
China is actively building more reactors at home than all other countries combined and singlehandedly restarted the race for novel technologies after hooking the world’s only commercial high-temperature gas-cooled reactors up to the grid in 2023. So far, Beijing’s two state-owned nuclear companies have remained focused on building light water reactors. Just one new high-temperature gas-cooled unit, designed to have more than twice the output of the first version, is currently underway at a facility where the fourth-generation, helium-cooled technology will be paired with third-generation, water-cooled reactors. Now the developer, the China National Nuclear Corporation, has made plans to procure a contract for the reactor for the first time, laying the groundwork for future deals to purchase units specifically designed to reach high temperatures. The “first concrete” for the plant is expected to be poured by the end of 2026, World Nuclear News reported.
Investment in zero-carbon energy and transportation surged this spring, driven by consumer EV and battery buying.
This is an edition of Heatmap Daily, an evening review of the day’s news written by our executive editor. Sign up for it here.
Ready to be surprised? Clean energy and transportation investment surged in the second quarter of this year, rising to more than $75 billion in total, according to new data released earlier this week.
In fact, this spring was the second biggest quarter for U.S. clean investment in nominal terms since at least 2018, when data started to be kept. More than 5% of overall investment in the United States went into a clean energy or transportation industry.
That’s according to the Clean Investment Monitor, a joint project of the MIT Center for Energy and Environmental Policy Research and the Rhodium Group, a private research firm. The monitor tracks nationwide investment across a number of sectors that make up the new electricity economy, including critical mineral refining, battery manufacturing, solar and wind installation, and electric vehicle and heat pump purchases by consumers (among other variables).
Outside of a promising headline number, the story is a mixed one. Investment in America’s clean manufacturing sector started growing again last quarter after falling for 18 months; it remains about 24% below where it was a year earlier, according to the project. The new growth came overwhelmingly from investment in the EV supply chain — defined as “critical minerals, batteries, vehicle assembly, and charging equipment” — driving a staggering 88% of all clean manufacturing investment. That subsector alone made up more than 9% of all U.S. clean investment.
The more interesting story — and what leaps out from the chart — is that retail activity drove the spring resurgence. High gasoline prices helped here, pushing consumers to buy all-electric and plug-in hybrid vehicles in larger numbers. (Rivian, Tesla, and other automakers started to see an EV rebound last quarter, too, after Republicans ended EV incentives in 2025.) But the real boom came in residential batteries, which surged to an all-time high of $11 billion in quarterly sales. Consumer activity hasn’t made up such a large share of national clean investment since 2023.
This trend wasn’t just happening in the United States. We’ve talked a lot at Heatmap about whether the Strait of Hormuz crisis will drive a clean energy boom. But it's now clear the oil price shock really did encourage global EV adoption. Some 50 countries set new EV sales records in 2026’s second quarter, according to Kelley Blue Book. India, Brazil, and Australia all set record highs. That's a lot of demand destruction.