You’re out of free articles.
Log in
To continue reading, log in to your account.
Create a Free Account
To unlock more free articles, please create a free account.
Sign In or Create an Account.
By continuing, you agree to the Terms of Service and acknowledge our Privacy Policy
Welcome to Heatmap
Thank you for registering with Heatmap. Climate change is one of the greatest challenges of our lives, a force reshaping our economy, our politics, and our culture. We hope to be your trusted, friendly, and insightful guide to that transformation. Please enjoy your free articles. You can check your profile here .
subscribe to get Unlimited access
Offer for a Heatmap News Unlimited Access subscription; please note that your subscription will renew automatically unless you cancel prior to renewal. Cancellation takes effect at the end of your current billing period. We will let you know in advance of any price changes. Taxes may apply. Offer terms are subject to change.
Subscribe to get unlimited Access
Hey, you are out of free articles but you are only a few clicks away from full access. Subscribe below and take advantage of our introductory offer.
subscribe to get Unlimited access
Offer for a Heatmap News Unlimited Access subscription; please note that your subscription will renew automatically unless you cancel prior to renewal. Cancellation takes effect at the end of your current billing period. We will let you know in advance of any price changes. Taxes may apply. Offer terms are subject to change.
Create Your Account
Please Enter Your Password
Forgot your password?
Please enter the email address you use for your account so we can send you a link to reset your password:

For more than a decade, Americans have been sold inferior furnaces to heat their homes that raise their energy bills and dump carbon into the atmosphere when much more efficient options were available. That’s finally going to change … five years from now.
On Friday, the Department of Energy finalized new, long-awaited standards for gas furnaces that have not meaningfully changed since they were first enacted in 1987. So long as the rule does not get held up in court, or by a future administration, it will require that by 2029, all gas furnaces on the market are 95% efficient. When it was first enacted, the standard was 78%. The current standard, which went into effect in 2015, is 80%.
It’s a bit of an awkward win for the climate movement. On the one hand, it’s a rule that assumes that fossil fuel-fired furnaces will still be on the market through at least 2058, far past the 2050 date by which the U.S. has committed to reduce its emissions to net-zero. Every new gas furnace installed could lock in carbon emissions and local pollution for the 15 to 20 years it operates.
On the other, clean energy and environmental advocates have been pushing for this kind of update to the standards since at least 2007, only to be stymied by lobbying and lawsuits from the gas industry, equipment manufacturers, and other industry groups. Though some states, like New York and California, are starting to phase out the sale of gas furnaces, there’s not yet any plan to do so on the national level. As long as people keep buying them, this rule will go a long way to make sure they emit as little as possible.
“Furnace technology advanced a long time ago, but the standards didn’t keep up,” said Andrew deLaski, the executive director of the Appliance Standards Awareness Project, in a press release. “This is going to guarantee that all new models use proven energy-saving technologies. We won’t keep wasting so much heat for decades more.”
The DOE estimates the updated standard will cumulatively save consumers $24.8 billion on their energy bills between 2029 and 2058. Individual households could save $350 over the lifetime of the equipment, and those living in mobile homes could save more than $600. The agency also says the rule will cut carbon emissions by 332 million metric tons over that period, roughly equivalent to the annual emissions from a third of American homes. It will also cut methane emissions by 4.3 million tons, which is slightly more than all U.S. municipal landfills emit in a year.
Jumping from 80% to 95% might sound like a big leap, but the technology to achieve it has been on the market for decades. A number of states and efficiency advocacy groups tried to sue the DOE when it last changed the standard in 2007 because they claimed that 80% was already too low back then. The vast majority of the products for sale were performing at that level or higher, so the change wasn’t going to do anything to reduce energy consumption or save households and businesses money.
The DOE made several attempts to update the standard under the Obama administration. The big sticking point was a technological quirk. Systems that achieve efficiency higher than 80% use something called a condenser to capture waste heat from the exhaust stream and send it into the building instead. Switching from a non-condensing furnace to a condensing furnace may come with some additional expenses, like the need to move the furnace to a different part of the building and install an exhaust pipe. Opponents argued that any rule that effectively banned non-condensing furnaces was unfair to consumers who couldn’t afford those changes. Under the Trump administration, they argued that condensing furnaces should be regulated as an entirely different product class.
But advocates counter that consumers will save money in the long run with a more efficient system. The updated standard could especially benefit renters, who won’t necessarily be burdened with any potential increase in upfront costs to install a condensing boiler, but will see lower heating bills. The DOE also estimates that when the standard kicks in, about 4.2% of building owners will forgo a new gas furnace altogether and get an electric heat pump, with the help of tax credits and rebates in the Inflation Reduction Act that incentivize this shift. That estimate does not even take into account the fact that furnaces may soon no longer qualify for Energy Star certification, which could push even more consumers to heat pumps.
Though on paper, the standard is expected to make a significant dent in emissions, the fact that it won’t go into effect for five more years — nearly 40 years after the last significant change — will have lasting consequences. Millions of gas-guzzling furnaces have been installed that didn’t have to be, and millions more could be before the standard kicks in. All the carbon emitted as a result will warm the planet for thousands of years.
Log in
To continue reading, log in to your account.
Create a Free Account
To unlock more free articles, please create a free account.
A climate scientist goes back to the numbers to argue that we’re overestimating the cost of the energy transition.
I’ve long been struck by how hard it is to predict the evolution of our energy system even a few years in advance, never mind 25 or 30 years. I still remember the “peak oil” craze in the mid-2000s, when people were telling me the end of oil was nigh. It sounded convincing right up until it turned out to be wrong.
Let me show you how bad previous predictions have been for the electricity sector.
Each plot below shows predictions of how a particular source of electricity will evolve, as well as what actually happened. The data comes from the Energy Information Administration and covers the U.S. electricity sector.
We’ll start with coal. In the first plot, the black line shows actual U.S. coal-fired electricity generation. The blue lines are predictions made each year since 2008.
In 2008, coal was expected to produce increasing amounts of electricity into the future. Instead, it immediately started to decline. It took until 2023 for the EIA to begin predicting a long-term decline in coal, despite the fact that coal had been declining for 15 years.
Natural gas, by contrast, has generated an increasing share of U.S. electricity. This is largely due to the tidal wave of cheap natural gas from hydraulic fracturing. The predictions, on the other hand, did not anticipate this.
The takeaway here is that predicting the evolution of our energy system is not just difficult in the long run, e.g., 30 years from now, but also that it’s difficult even in the short run.
If we combine coal and gas, the forecasts look better. This reflects the fact that natural gas has largely replaced coal over the years, so that the underestimate for gas helps cancel out the overestimate for coal.
But even for the combined category, the forecasts vary widely.
Moving on to renewables, here’s solar, including both utility and residential solar:
And here’s wind:
For both energy sources, predictions before 2015 were really bad. What changed after that I can’t say — my guess is they got sick of being so wrong.
Across all energy sources, the 2023 and 2025 forecasts differ sharply from the 2026 forecast. The predictions made for those years assume the persistence of Biden’s Inflation Reduction Act, while 2026 predictions assume the reversal of those policies.
The difference between 2025 and 2026 is an estimate of the role that politics plays in the future evolution of our electricity sector. That we cannot confidently predict who will win future elections or what their policies will be is another very good reason why it’s so hard to predict the future of our energy system.
Why is it so hard to predict the energy mix in our electricity system? One big reason is that it is hard to predict the future rate of innovation. We can see this in a plot of the cost of energy:
I’m using levelized cost of energy as my measure of the cost to produce power from each source. I understand the limitations of LCOE, but for an energy developer, LCOE is the number that counts. Yes, wind and solar are intermittent, but that’s a grid problem. All that matters to the developer is which low-LCOE energy source they can build.
You can see that the price of wind and solar plummeted in the early 2010s, reflecting enormous innovation in the production of renewable energy. That was not predicted by most mainstream forecasts, as confirmed by predictions of wind and solar above.
There has also been a lot of innovation in fossil fuel production, most importantly fracking and horizontal drilling. These technologies drove down the cost of natural gas in the late 2000s and changed the economics of electricity generation almost overnight. Coal plants that had looked like safe long-term investments suddenly faced a cheaper competitor.
Yet this, too, was largely missed. In the late 2000s, many utilities were still trying to build coal plants, unable to see that coal was entering a precipitous decline. TXU Corp., for instance, tried to build 11 new coal plants in Texas in the mid-aughts. Though it was the state’s largest utility at the time, it ultimately got bought out by private equity, who compromised with environmental groups and agreed to build just three of the original 11 proposed plants, two of which are still in operation.
Meanwhile, the restructured TXU declared bankruptcy in 2014, after natural gas prices collapsed.
All of this goes to show that coal was not beaten by a single technology. It was beaten by a sequence of technologies that forecasters failed to anticipate.
Based on economics, coal is now a stone-cold loser. Its remaining advantage is not cost, nor is it speed of construction or flexibility. It is politics. The Trump Administration is forcing coal-fired plants to stay open, and recent reporting suggests these interventions are raising costs for consumers.
In the competition between solar, wind, and natural gas, solar and wind are the cheapest. The combination of low costs and short construction times with the price volatility of natural gas gives wind and solar a huge market advantage, explaining their exponential growth.
Yes, solar and wind are coming for natural gas.
The LCOE plot also shows the profound disadvantage nuclear faces. Nuclear energy costs nearly $200 per megawatt-hour, around four times the cost of wind and solar. And it takes a decade or two to get it online. Without government mandates or heavy policy support, I would say there is little likelihood we will see a nuclear renaissance.
Much of the debate in climate policy centers on the cost, difficulty, and timeline for phasing out fossil fuels in order to achieve net zero. You constantly hear pundits and analysts throwing around eye-popping numbers, confidently claiming, e.g., that “it will cost XXX trillions of dollars to reach net zero in our economy by 2050.”

But if the forecasting failures of the past 20 years have taught us anything, it’s this: We simply have no idea how much decarbonization will cost.
You should treat numbers like McKinsey’s estimate above as guesses. They could be right, but historically speaking, they probably aren’t.
To summarize, here are the reasons why the true cost of reaching net zero remains so uncertain:
Overall, the uncertainty in these long-term forecasts is enormous. And if history is any guide, the errors are not random. They usually point in the same direction — they overestimate the cost of the energy transition.
One reason is that traditional forecasting models tend to assume slow, steady technological progress. But energy technologies do not always improve that way. Solar, wind, batteries, and fracking all show that costs can change fast when conditions line up. Most models, which assume gradual change, will miss these breaks.
Another problem is that fossil fuels are often treated as stable, low-risk alternatives. They are not. Their prices can swing wildly, and their supply chains are exposed to wars, political instability, and global market shocks. Those costs are real and hard to predict, so they are left out of these estimates.
That is the central point: Estimates of the cost of the energy transition should be treated as conditional guesses built on assumptions about technology, fuel prices, politics, and geopolitics, all of which have repeatedly surprised us.
The lesson of the past 20 years is not that the energy transition will be easy or hard — we really don’t know. Anyone claiming to know the cost decades in advance should be treated with skepticism.
Editor’s note: A version of this article originally appeared in the author’s newsletter, The Climate Brink, and has been repurposed for Heatmap.
Current conditions: The Atlantic hurricane season officially began today, in what’s expected to be a relatively mild year • A powerful storm with winds of up to 80 miles per hour is walloping broad swaths of millions of Australians • Temperatures in Oman are approaching 120 degrees Fahrenheit.

The United States’ offshore wind industry is, at this very moment, booming — at least in terms of the turbine arrays finally coming online in recent weeks. But there are no new projects underway as President Donald Trump pulls out all the stops to kill the industry in what I have previously called a death by a thousand cuts. That’s despite the fact that demand for electricity is soaring in the U.S. Luckily for Americans, our nation’s aging network of power grids overlaps with our northern neighbor’s. And Canada is now looking at a potential offshore wind boom. Last summer, Nova Scotia started laying the groundwork for offshore wind projects. Now Ming Yang, the world’s third-largest manufacturer of wind turbines, is considering investing in a project off Canada’s Pacific coast. The proposed project in the Hecate Strait off British Columbia would add up to 2 gigawatts of offshore wind capacity to Canada’s portfolio, according to Renewables Now. It’s part of Ming Yang’s broader push into Western markets, as my colleague Matthew Zeitlin reported last October.
Just days after New York State delayed its carbon-cutting plan and loosened the rules on how it counts greenhouse gases, California mounted its own retreat on climate goals. On Friday, Bloomberg reported that the California Air Resources Board had voted to give as much as $4 billion of free allowances to oil refiners and other industrial polluters to make compliance with the state’s 13-year-old carbon market easier. At least New York Governor Kathy Hochul “had the decency” to signal publicly that she intended to roll back the state’s climate law, said Danny Cullenward, an economist and lawyer who wrote a book on climate policy. “Here in California we do the same in private and call it climate leadership,” Cullenward wrote of California Governor Gavin Newsom and CARB Chair Lauren Sanchez in a post on Bluesky.
Kudos to the Trump administration, then, for being so open about its plans to render the SEC something that might more appropriately serve as an acronym for Salting the Earth of Climate disclosures. Last month, I told you that the Securities and Exchange Commission was reviewing a Biden-era rule requiring companies to disclose the risk climate change posed to their businesses. On Friday, the agency formally proposed eliminating the regulation. “SEC disclosure obligations should comply with the Commission’s statutory authority, be guided by materiality as the North Star, avoid the practical effect of dictating corporate behavior, and be imposed only when the expected benefits justify the likely costs and burdens,” SEC Chairman Paul S. Atkins said in a statement.
Rehlko isn’t a household name, but it used to be: The 106-year-old firm was previously called Kohler Energy. But since spinning out from the titan of American manufacturing of kitchen sinks and bathroom toilets, Rehlko has honed its business as a leading producer and installer of generators and the infrastructure to house the diesel-, gas-, or hydrogen-fired power sources. Now, I can report exclusively for this newsletter, the company is preparing to expand its factory in Wisconsin as its backlog of orders for generators to power data centers stretches beyond 13 months. In an interview on Friday, Rehlko CEO Brian Melka told me that this facility is part of a plan “to increase the size and the output of the business about four to five times, or 400% to 500%, over the next five or six years.” The Wisconsin plant is specifically designed to assemble the company’s “e-frame” product, a generator enclosure that looks like a shipping container and includes the wiring and fire suppression tools needed to safely house one of Rehlko’s proprietary generators, which provide off-grid back-up power to data centers, hospitals, and other large power users. In addition to beefing up its capacity to manufacture more generators and enclosures, the company is expanding its engineering team for larger projects in which Rehlko uses another firm’s gas turbines for full-time power generation.
“We want to maintain that competitive edge, not only to be able to deliver the product faster but also to deliver the entire solution faster,” Melka said. “This is going to significantly increase our capacity as we go into 2027 with this new facility to be able to build many more fully enclosed units. The demand keeps pushing out. We essentially sold out the capacity for that building for 2027 and 2028 before we even signed the lease.”
Sign up to receive Heatmap AM in your inbox every morning:
Unlike Russia, France, Japan, and China, the U.S. doesn’t recycle its nuclear waste. That is, until now. Roughly half a dozen companies are competing to be the first to create a beachhead for a new recycling industry in the U.S. Now one of those startups, Curio, has kicked off the pre-application process for a Nuclear Regulatory Commission permit. It’s just an inaugural step: Submitting a letter of intent to the agency to establish a docket and start providing documents to the regulator. But Curio plans to build a plant that could process up to 4,000 metric tons of used commercial light water reactor fuel per year. “The initiation of this application process marks a key and decisive moment for Curio and our nation as we commercially deploy what will be the world’s most advanced and capable used nuclear fuel recycling facility based on our game-changing NuCycle technology,” Curio CEO Ed McGinnis said in a statement, referring to the brand of the company’s reprocessing technology that was recently validated by four of the Department of Energy’s national laboratories.
South Korea, meanwhile, wants to start enriching and reprocessing its own fuel, and has garnered support from the Trump administration to do so. In the meantime, the democratic world’s most competent builder of civilian nuclear plants is doing what it does best and starting construction on a new reactor. On Friday, World Nuclear News reported that crews had poured the first concrete for Shin Hanul nuclear plant’s fourth reactor.
In January, I told you when Century Aluminum overhauled its plans to build the first new aluminum smelter in the U.S. to include an investment from an Emirati company. At the time, the Energy Department hailed the deal as a sign that Trump’s tariffs were working. On Friday, Mining.com published a feature building off a report from the advocacy group Industrious Labs that examined the recent push for new aluminum smelting in the U.S. The analysis concluded that, while 50% tariffs bolstered the sector, “access to industrial-scale electricity — and increasingly industrial-scale clean electricity — is the pain point,” said Annie Sartor, senior campaigns director at Industrious Labs. “Aluminum producers are being scooped by data centers and hyperscalers. They can simply pay more for the power.”
Among the more exciting concepts for supplying the market with cheap, clean, and affordable hydrogen is finding the stuff in naturally-formed underground reservoirs, allowing oil and gas drillers to do their thing for a green fuel. Now Oman, the Arab world’s diplomatic equivalent of Switzerland, is making progress in drilling the first wells for natural hydrogen. HyTerra, the Australian startup exploring for hydrogen in the country, told the Oman Observer that the successful pilot well boded well for tapping “one of the best source rock systems” for natural hydrogen yet discovered in the world. Given the latest heat wave in the country, the value of a fossil fuel replacement is likely becoming more obvious.
A group of energy researchers have a three-part prescription for Washington, D.C.’s exploding energy costs.
Washington, D.C. has earned an unwelcome distinction: the largest one-year electricity price increase of any state (or equivalent geographic distinction) in the U.S. Prices there are up 87% over the past five years and 26% in the past year alone, according to new data from MIT and Heatmap News’ Electricity Price Hub. The average D.C. household is now paying $55 more for power each month than it did five years ago.
In the face of this crisis, local officials have done little but blame regional markets, emphasizing the parts of recent rate increases they don’t fully control — generation charges — rather than any proactive measures they could take to offer relief to D.C. households. Meanwhile Exelon, the parent company for Pepco, D.C.’s local utility, has used the crisis to lobby state policymakers across the region for something worse — a return to utility-owned generation, which could leave consumers holding the bag for projects that run over budget or that are built for demand that never materializes.
As residents of Washington, D.C. and energy researchers who helped put together the Electricity Price Hub, we are well aware that the District cannot remake the regional electricity market on its own. But it has meaningful tools to protect ratepayers now.
To be sure, the problems D.C. faces are not entirely of its own making. Rising demand and constrained supply across the Mid-Atlantic have created a wholesale market pressure cooker.
Capacity market prices in the Pepco region, which are set through a regional auction scheme designed to ensure the grid can reliably deliver power when demand peaks, increased more than fivefold in 2025. Those costs are passing through to retail bills. As capacity has come under increasing strain, generation charges in Pepco’s standard supply service have gone up 119% — 33% in the past year alone, with yet another rate increase set to kick in on June 1.
That regional dynamic is real. But it does not absolve local officials.
Roughly 30% of Pepco’s average residential bill is made up of charges that fall squarely under D.C. jurisdiction. Distribution charges, the largest of those local components, have risen 57% over five years, and account for 20% of the total rate increase. The D.C. Public Service Commission regulates utilities in the District and must approve Pepco’s rates before they take effect. The commission, in turn, answers to the D.C. Council, the District’s legislature, which confirms its commissioners and oversees its work. These bodies should be examining every dollar of Pepco’s proposed increases. Instead, a D.C. court recently struck down the commission’s most recent rate-hike approval, finding that it had failed to sufficiently scrutinize Pepco’s request.
When a regulator is doing such a poor job that judges have to step in, that is a five-alarm signal. Yet there is a workable action plan for the Council and the PSC to rein in costs and ease the burden on D.C. households.
First, scrutinize distribution charges aggressively — that is squarely within their jurisdiction. As Pennsylvania Governor Josh Shapiro argued in his public letter to utility leaders last month, the PSC should require Pepco to justify every additional dollar of revenue requested in plain language. That means using transparent, replicable data and analysis to show why it’s needed, the alternatives considered, and how the proposed spending will concretely benefit consumers. To support this, the D.C. Council should ensure that the PSC, the Office of the People’s Council, and relevant state agencies are adequately resourced and positioned to engage with and probe Pepco’s arguments in rate proceedings.
Second, force transparency into how Pepco procures power. The public has remarkably little visibility into what makes up generation charges for the utility. For example, how much of the total cost is attributable to capacity prices, energy procurement, administrative costs, and compliance with the District’s Renewable Energy Portfolio standard? And what changes could D.C. consider to the competitive procurement process or RPS eligibility requirements to mitigate costs? Officials can’t manage what they can’t measure.
Third, attack demand by making it easier for customers to generate their own supply. High and unpredictable interconnection fees, process delays, and other administrative hurdles add unnecessary costs and contribute to the above-average cost of solar in D.C.. The D.C. Council and PSC can incentivize distribution-level solar battery deployment by cutting permitting and interconnection costs and improve cost transparency and streamline interconnection reviews to speed up the process of installing solar and storage.
None of these moves alone will reverse five years of rate increases. But together they would put real downward pressure on bills and signal that the city is serious.
What officials should reject — across the region — is Exelon’s push for utility-owned generation. In practice, it could create a generation subsidiary tomorrow. The reason it wants its rate-regulated distribution utility to do so instead is that this would let it earn a guaranteed return on costs it currently just passes through, while shifting the risk of cost overruns, schedule slips, and overbuilt capacity from shareholders to ratepayers. It would also hand the utility an information advantage over independent power producers, suppressing the competition the market relies on to keep prices honest. More profit, less risk, less competition. A great deal — for the utility.
The D.C. Council recently passed emergency legislation pausing utility disconnections for residents with unpaid balances under $1,000. That is a humane stopgap as we head into summer, but it is not a strategy. Neither is anything that has been proposed during the current mayoral race, in which leading candidates have attacked each other’s records instead of offering a plan to lower bills.
D.C. residents do not need more blame-shifting. The choice in front of the council and the PSC is concrete: Scrutinize what is in their jurisdiction, force the transparency they have the authority to require, accelerate the cheapest sources of new supply, and refuse to subsidize a Pepco business model that turns ratepayers into the underwriters of utility risk. That is the test of whether they meet this moment seriously.