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How Team Biden learned to stop worrying and love carbon removal.

What does the new American climate policy look like?
Last week, we got a better sense. On Friday, the Biden administration unveiled a massive investment — more than $1.2 billion — that aims to create a new industry in the United States out of whole cloth that will specialize in removing carbon from the atmosphere.
As President Joe Biden’s climate law hits its one-year anniversary, the investment shows the audacity, the potential, and — ultimately — the risks of his approach to climate and economic policy.
If successful, the investment will establish a new sector of the American economy and remake another one, while providing the world with an important tool to fight climate change. If unsuccessful, then the investment could set back an important climate technology and forever link it to the fossil-fuel industry.
The investment’s centerpiece is two large industrial facilities in Louisiana and Texas that will remove more than 1 million tons of carbon from the atmosphere every year. But the program is much broader than those hubs, encompassing more advanced and experimental approaches to carbon removal, or CDR, than the government has previously funded. The government has unleashed old industrial policy tools, such as advanced market guarantees, toward the nascent field.
Although Biden is implementing this policy, the approach will almost certainly outlive his administration. America’s support for carbon removal is strongly, perhaps surprisingly, bipartisan. The new hubs and the other policies announced last week were funded by the bipartisan infrastructure law or by other bipartisan legislation.
Given all that, it’s worth it to spend some time on these investments to better understand how they work and what they might mean for the future of the American economy.
Let’s start here: Yes, we will probably need carbon dioxide removal, or CDR, to meet the world’s and the country’s climate goals.
This wasn’t always clear. When I started as a climate reporter in 2015, carbon removal was taboo, something that only climate deniers and other folks who wanted to delay decarbonization brought up. An influential Princeton study from earlier in the decade had concluded that carbon removal — especially capturing carbon in the ambient air, a strategy called direct air capture, or DAC — would never pencil out financially and that it would always be cheaper to reduce fossil-fuel use rather than suck carbon out of the sky.
But in 2018, the Intergovernmental Panel on Climate Change made a startling announcement: So much carbon dioxide had accumulated in the atmosphere that it would be virtually impossible to keep global warming below 1.5 degrees Celsius without carbon removal.
The IPCC studied global energy models and found that even in optimistic scenarios, humanity would release too much carbon by the middle of the century to keep temperatures from briefly rising by more than 1.5 degrees Celsius. But if we began removing carbon from the atmosphere, then we could avoid locking in that spike in temperatures for the long term. That is, in order to hit the 1.5-degree goal by 2100, humanity must spend much of the 21st century removing carbon from the atmosphere and sequestering it for thousands of years.
We need carbon removal, in other words, not so we can keep burning fossil fuels, but to deal with the fossil-fuel pollution that is already in the atmosphere.
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This change was only possible because CDR’s costs were falling. A few months earlier, a company called Carbon Engineering had announced that it would soon cut direct air capture’s cost to $230 a ton. (DAC was once thought to cost $600 a ton.) This suggested that in a handful of cases — a small handful — it might make financial sense to use DAC instead of decarbonizing a particular activity.
Even so, the numbers involved in this effort are mind-boggling. This year, several thousands tons of carbon will be removed from the atmosphere worldwide, at a cost of $200 to $2,000 a ton, according to one industry expert. Perhaps 100,000 tons of carbon have ever been removed from the atmosphere by a human-run process, according to CDR.fyi, a community-run database.
But by 2050, in order to hit the IPCC’s targets, humanity must remove about 5 billion tons a year at a cost of roughly $100 a ton.
For context, the global shipping industry moves about 11 billion tons of material each year.
In other words, in the next three decades, humanity must perfect the technology of CDR, find a way to pay for it, and massively scale it up to the degree that it captures roughly half of the amount of material that travels via oceanborne trade today. And it must do this while decarbonizing the rest of the energy system — because if we fail to bring fossil-fuel use nearly to zero during this period, then all of this will be for naught.
Q: Well, if we have to store all this carbon for a very long time, why don’t we plant a lot of trees?
A: For a few years in the mid 2010s, trees did seem like the cheapest way to pull carbon out of the atmosphere.
But the scale of the carbon problem exceeds what biology alone can fix. Since 1850, humanity has pumped 2.5 trillion tons of carbon dioxide into the atmosphere. This is nearly twice the total biomass of all life on Earth. Only geology can deal with such a massive (literally) problem. To truly undo climate change, we must put carbon back into geological storage. Plus, even if you sopped up a lot of carbon with trees, they might burn down. Then you’d be back where you started.
Yet CDR isn’t just a logistical problem.
Fossil fuel companies have long used the rhetoric of carbon removal — and its relative, carbon capture and storage, which sucks up climate pollution from a smokestack or industrial process — as an excuse to keep drilling for oil and gas. At the same time, they’ve resisted any federal regulation that would require them to actually capture carbon when they burn fossil fuels.
What’s more, the infrastructure and the expertise best-suited for carbon removal is largely in the same places that have fossil-fuel industries today. (Think of the Gulf Coast or North Dakota.) Some people who live in those places want to see decarbonization end the fossil-fuel industry forever — not transform it into something different, like a carbon management industry.
And although the technology to inject captured carbon dioxide into the ground is decades-old, concentrated CO2 can be dangerous if mishandled.
It’s not hard to imagine a world where the promise of CDR allows oil and gas companies to keep drilling and polluting, but where a lack of any binding regulation — and local pushback whenever a CDR facility is announced — means that very little carbon actually gets removed from the atmosphere. In that world, no matter how powerful CDR is technologically, the politics of CDR would make climate change worse.
Which brings us to the Biden administration’s strategy for scaling up the CDR industry. It has three components:
1. Build massive direct air capture facilities around the country.
2. A slew of new programs to boost alternative (and maybe less energy-intensive) approaches to CDR.
3. A new “Responsible Carbon Management” guideline.
In short, the administration is seeking to scale up the most straightforward carbon-removal technology, financially support other promising approaches, and then ensure it all happens in an above-board way.
The marquee announcement here are the carbon capture hubs, which were widely covered last week. The Energy Department will spend $1.2 billion on large-scale facilities in Louisiana and Texas that will use industrial processes to cleanse carbon from the ambient air. Each will remove about one million tons of carbon a year when complete.
Project Cypress, the Louisiana hub, will be run by the federal contractor Battelle in conjunction with Climeworks, a Swiss DAC company, and Heirloom, which stores carbon dioxide in concrete.
The boringly named South Texas DAC Hub will be run by Occidental Petroleum, an oil company, in conjunction with the DAC company Carbon Engineering and Worley, an engineering firm.
These are going to be the charismatic megaprojects of the CDR industry. They are meant to create clusters of expertise and infrastructure, concentrated in a geographic core, that will give rise to more innovation. You can think of them as little Silicon Valleys — or, more pointedly, little Shenzens — of carbon removal.
As goes these hubs, so goes CDR. If the hubs have an accident, or take too long to build, then the industry will struggle; if they succeed, it will have a running start. Therefore, the Energy Department has made a big fuss about how these projects should help local residents: When selecting these projects, it took the unusual step of ranking these projects’ “community benefits” as highly as their more technical aspects.
Last week, an Energy Department official was quick to point out to me that these projects have merely been selected and that neither has received any money yet. Next, the department and these hubs will negotiate binding contracts that will seek to lock in community benefits for locals. Only then will the funds flow.
What’s more interesting, though, is what’s not here. In the infrastructure law, Congress required that the Energy Department establish four DAC hubs. Only two have been announced. That’s because officials realized last year that fewer than four places nationwide had the expertise and understanding of DAC necessary to erect a massive million-ton facility on demand.
So the department set up a kind of starter DAC hub program — a series of grants that will allow cities, nonprofits, universities and companies to study the feasibility of establishing a DAC hub in their town. It gave out more than a dozen of these grants last week to companies and universities in Utah, California, Illinois, Kentucky, and more.
Officials clearly hope that these starter grants may produce more than two full-fledged DAC hub projects, which Congress can then fund at the same level as the Texas and Louisiana facilities.
Even those starter projects will specialize in DAC, though, which means that each approach will use industrial machinery to capture carbon from the ambient air and inject it underground.
But removing carbon doesn’t necessarily require DAC. It may be possible to remove carbon passively by using certain kinds of rock, for instance, or by growing lots and lots of algae. These approaches will probably use less energy than DAC, and they may even remove more carbon than DAC, but they will be harder to measure and verify, and there will be more uncertainty about exactly how much carbon you’re taking out of the atmosphere.
But federal policy has a strong pro-DAC bias. That’s not only because of the DAC hubs, but also because of the Inflation Reduction Act: Biden’s climate law pays companies $180 for each ton of carbon that they remove from the atmosphere, but it is written such that it can essentially only be used for DAC.
The department is trying to diversify away from DAC within the bounds that Congress has given. Last week, it announced that it would soon sponsor small pilot programs that use alternative technologies, including rock mineralization, biomass, and ocean-based processes. It will also fund efforts to measure and verify those techniques so as to make sure they remove a dependable amount of carbon from the atmosphere.
The Energy Department also announced that it will create a new pilot purchase program for carbon removal efforts, providing an “early market commitment” to carbon-removal companies in the same way that it provided one to COVID vaccine makers. This program, which will have an initial budget of $35 million, will use federal expertise to identify which CDR techniques are the most viable and promising, allowing a DOE purchase contract to function as a de facto stamp of approval. (Heatmap first covered the existence of this program earlier this month.)
Finally, the department will launch a separate prize for commercial DAC providers with the goal of cutting its costs down to $100 a ton.
These programs have the unfortunate name “Carbon Negative Shot,” which is meant to evoke a “moonshot” but sounds more like an overpriced product for deer hunters. We will not dwell on it any longer.
All these efforts will turn the Department of Energy into the world’s biggest public buyer and supporter of carbon removal. That lays the groundwork for the final aspect of its strategy that launched last week: a “Responsible Carbon Management Initiative.”
This is a nonbinding list of principles that any carbon-management project will have to follow: These include engaging respectfully with communities before setting up a project, consulting with local tribes, developing the local workforce and ensuring good jobs, and monitoring local air and water quality. (The department is seeking public comment on what, exactly, these principles should be.)
Eventually, the Energy Department hopes to use these principles to provide “technical assistance” to projects that meet the guidelines. It will also recognize developers that have demonstrated they meet the principles.
In other words, the initiative could, over time, become a kind of soft standards-setting body for the industry — a way to distinguish good carbon-removal projects from the bad (and hopefully eliminate the bad in the first place). It will help that the same department publishing these guidelines will also be where all the funding is coming from.
Will all this work? I don’t know. But the scale of the effort is meaningful in itself, because it shows how the Biden administration approaches the task of erecting an industry de novo. If there’s such a thing as Bidenomics, this is what it looks like: a place-based development strategy that admires industrial clustering, supports domestic supply and demand, and applies an optimistic approach to regulation.
You can also see the risk of Biden’s approach. Decarbonization requires technical expertise and real-world know-how; in America, most of that expertise resides in the private sector. Occidental, an oil company that describes itself (optimistically) as a carbon management company, will operate one of the DAC hubs. Although it is prohibited by law from doing anything really egregious — like using the carbon that it’s capturing to drill for more oil — the Biden team cannot ensure that its heart or actions will remain pure. Occidental will be a good carbon-removal team player only so long as it benefits its bottom line.
Yet I don’t want to overstate the importance of this investment either. The vast majority of the Biden administration’s climate investment is going to cutting emissions: If anything, the Biden administration is spending too little on carbon removal, not too much. By my estimate, these programs, including the DAC hubs, will amount for 2% of the roughly $173 billion that the bipartisan infrastructure law devotes to climate or environmental projects. And when you include the Inflation Reduction Act’s climate spending — which is where most federal climate spending is in the first place — the programs discussed here drop to perhaps one percent of total climate spending, although that will depend on how many facilities use the DAC tax credit.
That is a small price for a big prize. If this funding “works,” then these investments will represent the beginning of a new industry — a carbon management industry capable of pulling millions of tons of pollution out of the sky. But even if they fail, then we’ll have learned something too: that carbon removal — and especially DAC — may in fact be unworkable, and that we should not comfort ourselves in the years to come with the hope of cleaning up the atmosphere.
“Our responsibility is to do what we can, learn what we can, improve the solutions, and pass them on. It is our responsibility to leave the people of the future a free hand,” the physicist Richard Feynman once wrote. A couple billion seems a worthy price for learning if that hand is free or not.
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Members of the nation’s largest grid couldn’t agree on a recommendation for how to deal with the surge of incoming demand.
The members of PJM Interconnection, the country’s largest electricity market, held an advisory vote Wednesday to help decide how the grid operator should handle the tidal wave of incoming demand from data centers. Twelve proposals were put forward by data center companies, transmission companies, power companies, utilities, state legislators, advocates, PJM’s market monitor, and PJM itself.
None of them passed.
“There was no winner here,” PJM chief executive Manu Asthana told the meeting following the announcement of the vote tallies. There was, however, “a lot of information in these votes,” he added. “We’re going to study them closely.”
The PJM board was always going to make the final decision on what it would submit to federal regulators, and will try to get something to the Federal Energy Regulatory Commission by the end of the year, Asthana said — just before he plans to step down as CEO.
“PJM opened this conversation about the integration of large loads and greatly appreciates our stakeholders for their contributions to this effort. The stakeholder process produced many thoughtful proposals, some of which were introduced late in the process and require additional development,” a PJM spokesperson said in a statement. “This vote is advisory to PJM’s independent Board. The Board can and does expect to act on large load additions to the system and will make its decision known in the next few weeks.”
The surge in data center development — actual and planned — has thrown the 13-state PJM Interconnection into a crisis, with utility bills rising across the network due to the billions of dollars in payments required to cover the additional costs.
Those rising bills have led to cries of frustration from across the PJM member states — and from inside the house.
“The current supply of capacity in PJM is not adequate to meet the demand from large data center loads and will not be adequate in the foreseeable future,” PJM’s independent market monitor wrote in a memo earlier this month. “Customers are already bearing billions of dollars in higher costs as a direct result of existing and forecast data center load,” it said in a quarterly report released just a few days letter, pegging the added charges to ensure that generators will be available in times of grid stress due to data center development at over $16 billion.
PJM’s initial proposal to deal with the data center swell would have created a category for new large sources of demand on the system to interconnect without the backing of capacity; in return, they’d agree to have their power supply curtailed when demand got too high. The proposal provoked outrage from just about everyone involved in PJM, including data center developers and analysts who were open to flexibility in general, who said that the grid operator was overstepping its responsibilities.
PJM’s subsequent proposal would allow for voluntary participation in a curtailment program, but was lambasted by environmental groups like Evergreen Collaborative for not having “any semblance of ambition.” PJM’s own market monitor said that voluntary schemes to curtail power “are not equivalent to new generation,” and that instead data centers should “be required to bring their own new generation” — essentially to match their own demand with new supply.
A coalition of environmental groups, including the Natural Resources Defence Council and state legislators in PJM, said in their proposal that data centers should be required to bring their own capacity — crucially counting demand response (being paid to curtail power) as a source of capacity.
“The growth of data centers is colliding with the reality of the power grid,” Tom Rutigliano, who works on grid issues for the Natural Resources Defense Council, said in a statement. “PJM members weren’t able to see past their commercial interests and solve a critical reliability threat. Now the board will need to stand up and make some hard decisions.”
Those decisions will come without any consensus from members about what to do next.
“Just because none of these passed doesn’t mean that the board will not act,” David Mills, the chairman of PJM’s board of managers, said at the conclusion of the meeting. “We will make our best efforts to put something together that will address the issues.”
California energy companies are asking for permission to take in more revenue. Consumer advocates are having none of it.
There’s a seemingly obvious solution to expensive electricity bills: Cut utility profits.
Investor-owned utilities have to deliver profits to their shareholders to be able to raise capital for grid projects. That profit comes in the form of a markup you and I pay on our electricity bills. State regulators decide how much that mark-up is. What if they made it lower?
A growing body of evidence suggests they should at least consider it. In principle, the rate of return on equity, or ROE, that regulators allow utilities to charge should reflect the risk that equity investors are taking by putting their money in those utilities, but that relationship seems to have gotten out of whack. Among the first to draw attention to the issue was a 2019 paper by Carnegie Mellon researchers which found that since the 1990s, the average “risk premium” exhibited by utility ROEs as compared to relatively risk-free U.S. Treasury bonds has grown from 3% to nearly 8%.
“An error or bias of merely one percentage point in the allowed return would imply tens of billions of dollars in additional cost for ratepayers in the form of higher retail power prices,” the authors wrote.
Subsequent research reproduced and built on those findings, showing that a generous ROE creates a perverse incentive for utilities to increase their capital investments, leading to excess costs for consumers of $3 billion to $11 billion per year. Now, the ex-chief economist of a major U.S. utility company, Mark Ellis, is putting his own analysis out there, arguing that unreasonably high ROEs are costing U.S. energy customers $50 billion per year, or over $300 per household.
Not only does this hurt consumers, it also makes the energy transition more expensive and less politically palatable.
That’s what environmental and consumer advocates are worried about in California, where the Public Utility Commission is currently considering requests by the state’s four largest energy companies to raise each of their ROE. Utilities in the state have reported record profits amid a worsening affordability crisis. On Friday, the commission signaled that it would instead lower the companies’ ROE — although not nearly as much as advocates have recommended. A final decision is expected in December.
“It’s a joke,” Ellis, the former utility executive, told me of the commission proceedings. “If you read the proposed decision, they don’t address any of the facts or evidence in the case at all.” His own analysis, which he submitted to the California commission on behalf of the Sierra Club, proposes that an average ROE of 6%, down from about 10%, would be justified and has the potential to save California energy customers more than $6 billion per year.
Utilities, of course, disagree, and have brought their own analysis and warnings about the risks of lowering their ROE. Regulators are left to sort through it all to figure out the magic number — one large enough to appeal to investors, but not so large as to throw ratepayers under the bus.
How does the ROE work its way into your bill? Let’s say your local utility, The Electric Company, has a regulated return on equity of 10%, and it plans to spend $100 million to build new substations. Utilities typically finance these kinds of capital projects with a mix of debt (loans they will have to pay interest on) and equity (shares sold to investors). Then they recover that money from ratepayers over the course of decades. If The Electric Company raises half of the capital, or $50 million, via equity, an ROE of 10% means it will be able to charge ratepayers $5 million on top of the cost of the project. That additional $5 million is factored into the per-killowatt-hour rates that customers pay. The profit can then be reinvested into future projects, issued to shareholders as dividends, paid out to executives as bonuses — the list goes on.
The energy research group RMI, which agrees that the average utility ROE is much too high, estimates the surcharge currently makes up between 15% and 20%% of the average customer’s utility bill. “Setting ROEs at the right level is necessary to bring forward a rapid, just, and equitable transition,” RMI wrote.
Utilities, however, say the “right level” is likely higher, not lower. They warn that in reality, lowering their ROE would trigger a cascade of negative effects — credit downgrades, higher borrowing costs, lower stock prices, investors taking their money elsewhere — that would push energy rates up, not down. These effects would also make it more difficult for utilities to invest in projects to clean up and expand the electric grid.
Timothy Winter, the portfolio manager of a utility-focused fund at the investment firm Gabelli, told me this “virtuous cycle” runs in both directions. Higher ROEs lead to a lower cost of capital, which leads to more investment, better reliability, and lower rates, he argued. Winter said that if California regulators reduced utility ROEs to 6%, investors would flee the state.
Between growing wildfire risk and the bankruptcy of California’s largest utility, PG&E, California energy providers are too exposed to warrant such low returns, he said. As a comparison, he noted that U.S. Treasury bonds, which are generally viewed as risk-free, yield about 4%. “If it’s a 6% return with an equity risk, they’re not going to do it,” he said of investors.
I probed Winter a bit more on this. Is that really true given that utilities are still, in many ways, the opposite of risky investments? They have captive customers, stable income, and are seeing skyrocketing growth in demand for their product.
This caused him to spiral down into an investor’s worst nightmare scenario. “Yes, there is a risk,” he said. “If a regulator is willing to give a 6% return and they used to give 11%, how do I know they’re not going to decide, okay, rates keep going up, next rate case it’s going to be 4%?” After that, he said, how can investors be sure the government won’t end up taking over the utility altogether?
Travis Miller, a senior equity analyst at Morningstar, was more measured. He hesitated to tell me whether a 6% ROE would hurt utilities’ ability to raise capital. “What usually happens” when regulators lower the ROE, he said, “is the utilities just decide not to invest very much, so then they don’t have to raise capital.” He would expect the California utilities to “invest to maintain reliability and that’s about it,” meaning that “a lot of new data center build that is planned in California would have to go elsewhere.”
Return on equity also isn’t the only thing investors look at, Miller added. They consider the overall regulatory environment. Is it predictable? Is it transparent? He said there have been cases where regulators cut a utility’s ROE but the overall regulatory environment remained strong, and other instances where the cut to ROE was “another sign of a deteriorating relationship” — a phrase that brings to mind Winter’s panic about government takeovers. (I should note, advocates for public takeovers of utilities cite this whole dynamic around the need to woo investors and the perverse incentives it creates as a key justification for their cause. Publicly-owned utilities — which serve about 1 in 7 electricity customers in the U.S., including in large cities like Sacramento, Los Angeles, and Seattle — don’t charge an ROE.)
When I spoke to Ellis about his proposal, I fired off all of the utility arguments I could think of. Won’t utilities stop building stuff and making the investments we need them to make if they can’t earn as much? “They have a legal obligation to continue to invest,” he said. But will they be able to raise equity? They don’t necessarily need to raise new equity, he responded, suggesting that utilities could reinvest more of their profits rather than distributing the money as dividends. This is not how utilities traditionally operate, he admitted, but it’s an option.
Prior to taking up the consumer cause, Ellis spent 15 years in leadership and executive roles at Sempra Energy, the parent company of San Diego Gas and Electric and SoCal Gas — two of the companies that petitioned for higher ROE. “I know how they think about this issue,” he told me, asserting that the arguments the companies make to regulators do not match how they think about ROE internally.
During our interview, Ellis described the current state of utility regulation of ROE in California as “reprehensible,” “egregious,” “heartbreaking,” and “a huge injustice.”
In the analysis he submitted to the utility commission, Ellis not only makes the case that the average U.S. utility’s ROE is much higher than is necessary to attract capital, but also that the potential impacts to consumers of lowering it — i.e. the potential to hurt a utility’s credit rating and increase its cost of debt — would be outweighed by customer savings.
He argues that to justify their requests for higher ROEs, the utilities use forecasts from biased sources, cherry-pick and manipulate data, and make economically impossible assumptions, like that earnings will grow faster than GDP.
Stephen Jarvis, an assistant professor at the London School of Economics who has conducted research on ROE rates, has reached similar conclusions about them being excessively high. Nonetheless, he told me he sympathized with the challenge regulators face. He said there was no “right” answer for how to calculate the appropriate ROE. “Depending on the assumptions that you use, you can come up with quite different numbers for what a fair rate of return should be,” he said.
The sentiment echoes the preliminary decision the California Public Utilities Commission issued last week, when it observed that all of the proposals submitted in the proceeding were “dependent on subjective inputs and assumptions.”
Ellis said the decision contained a “smoking gun,” however, proving that the commission didn’t really do its job. Changes in ROE are supposed to reflect changes to a company’s risk profile, he said. The risk profile for Southern California Edison, which is facing lawsuits related to the Eaton Fire and already paying out hundreds of millions of dollars to survivors, has certainly changed in a different way than its peers. Regardless, the commission made the exact same recommendation for each utility to reduce ROE by 0.35%. “The Commission clearly is not looking at the evidence.”
There is likely some truth to that. “It’s more art than science,” Cliff Rechtschaffen, who served for six years on the California Public Utilities Commission, told me when I asked how the people in those seats attempt to calibrate ROE. He acknowledged there was a self-reinforcing element to the process — regulators look at where investors might go if the rate of return is too low, and use that to determine what the rate should be. “But the rates of return that are set in other jurisdictions are, in turn, influenced by the national utility market, which includes your own utility market,” he said.
Similarly, regulators rely on market analysts, investment advisors, investment bankers, and so on, who have an inherent interest in building up the market and ensuring healthy rates of return, he said. “That makes it harder to discern and do true price discovery.”
Rechtschaffen said he was glad that environmental and consumer advocates were bringing greater scrutiny to ROE, adding that it was the “right time” to do so. “Particularly in this environment where utilities have forecast that they’re going to be spending tens of billions of dollars on capital upgrades, do we need the same rates of return that we’ve seen?”
On ravenous data centers, treasured aluminum trash, and the drilling slump
Current conditions: The West Coast’s parade of storms continues with downpours along the California shoreline, threatening mudslides • Up to 10 inches of rain is headed for the Ozarks • Temperatures climbed beyond 50 degrees Fahrenheit in Greenland this week before beginning a downward slide.
The Department of Energy’s Loan Programs Office just announced a $1 billion loan to finance Microsoft’s restart of the functional Unit 1 reactor at the Three Mile Island nuclear plant. The funding will go to Constellation, the station’s owner, and cover the majority of the estimated $1.6 billion restart cost. If successful, it’ll likely be the nation’s second-ever reactor restart, assuming Holtec International’s revival of the Palisades nuclear plant goes as planned in the next few months. While the Trump administration has rebranded several loans brokered under its predecessor, this marks the first completely new deal sanctioned by the Trump-era LPO, a sign of Energy Secretary Chris Wright’s recent pledge to focus funding on nuclear projects. It’s also the first-ever LPO loan to reach conditional commitment and financial close on the same day.
“Constellation’s restart of a nuclear power plant in Pennsylvania will provide affordable, reliable, and secure energy to Americans across the Mid-Atlantic region,” Wright said in a statement. “It will also help ensure America has the energy it needs to grow its domestic manufacturing base and win the AI race.” Constellation’s stock soared in after-hours trading in response to the news. Holtec’s historic first restart in Michigan got the green light from regulators to come back online in July, as I reported in this newsletter at the time. But already another company is lining up to turn its defunct reactor back on: As I reported here in August, utility giant NextEra wants to revive its Duane Arnold nuclear station in Iowa. The push to restart older reactors reflects a growing need for electricity long before new reactors can come online. Meanwhile, next-generation reactors are plowing ahead. The nuclear startup Valar Atomics claimed this week to achieve criticality long before the July 4 deadline set in an Energy Department competition.
Over the next five years, American demand for electricity is set to grow by the equivalent of 15 times the peak demand of the entirety of New York City. That’s according to the latest annual forecast from the consultancy Grid Strategies. The growth — roughly sixfold what was forecast in 2022 — comes overwhelmingly from data centers, as shown by which regions expect the largest growth:

“The fact that these facilities are city-sized is a huge deal,” John Wilson, Grid Strategies’ vice president and the report’s lead author, told Canary Media. “That has huge implications if these facilities get canceled, or they get built and don’t have long service lives.” Mounting political opposition to data centers could make deals less certain. A Heatmap Pro survey in September found just 44% of Americans would welcome a data center opening nearby. And last week I wrote about how progressives in Congress are rallying around a crackdown on data centers.
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The contrast couldn’t be starker. In Washington, President Donald Trump rolled out the red carpet for Saudi Crown Prince Mohammed bin Salman, offering an opulent welcome to the White House and lashing out at reporters who asked about September 11 or the killing of journalist Jamal Khashoggi. In Belém, Brazil, meanwhile, former Vice President Al Gore tore into the team of delegates Saudi Arabia sent to the United Nations climate summit for “flexing its muscles” in negotiations about how to shift away from oil and gas. “Saudi Arabia appears to be determined to veto the effort to solve the climate crisis, only to protect their lavish income from selling the fossil fuels that are the principal cause of the climate crisis,” Gore told the Financial Times. “I hope that the rest of the world will stand up to this obscene greed and recklessness on the part of the kingdom.”
But the Trump meeting could yield some progress on clean energy. Among the top issues the White House listed in its read-out of the summit was the push to export American atomic energy technology to Saudi Arabia as the country looks to follow the United Arab Emirates in embracing nuclear power.
Facing growing needs for domestic sources of metal for the energy transition, the European Union is seeing its trash as treasure. On Tuesday, the European Commission proposed restricting exports of aluminum scrap amid what The Wall Street Journal called “concerns that rising outflows of the resource could leave Europe short of a critical input for its decarbonization efforts.” Speaking at the European Aluminum Summit, EU trade chief Maros Sefcovic referred to the exports as “leakage.” The proposal wouldn’t fully block sales of aluminum scrap overseas, but would adopt a “balanced” measure that ensures sufficient supplies and competitive prices in the single market. “Scrap is a strategic commodity given its important contribution to circularity and decarbonization, as production from secondary materials releases less emissions and is less energy intensive, as well as to our strategic autonomy,” Sefcovic said. The measure is set to be adopted by spring 2026.
In the U.S., the Biden administration made what Heatmap’s Matthew Zeitlin last year called a “big bet” on aluminum. The Trump administration slapped steep new tariffs on imported aluminum, though as our colleague Katie Brigham wrote, “aluminum producers rely on imports of these same materials to build their own plants. Tariffs on these vital construction materials — plus exorbitant levies on all goods from China — will make building new production facilities significantly costlier.”

The average number of active rigs per month that are drilling for oil and natural gas in the continental United States fell steadily over the past year. As of last month, the U.S. had 517 rigs in operation, down from a peak of 750 in the end of 2022. The number of oil-pumping rigs dropped 33% to 397 rigs, while gas-pumping rigs slid 23% to 120 rigs over the same period from December 2022 to October 2025. While the Energy Information Administration said the declining rig count “reflects operators’ responses to declining crude oil and natural gas prices,” the federal research agency said it’s also “improvement in drilling efficiencies,” meaning companies are getting more fuel out of existing wells.
It’s been a pattern in recent research on sustainability. Scientists look at methods that Indigenous groups have maintained as traditions only to find that approaches that have sustained throughout centuries or millennia are finding new value now. A study by the University of Hawaiʻi at Mānoa’s Hawaiʻi Institute of Marine Biology found that Native Hawaiian aquaculture systems — essentially fish ponds known as loko iʻa — effectively shielded fish populations from the negative impacts of climate change, demonstrating resilience and bolstering local food security. “Our study is one of the first in academic literature to compare the temperatures between loko iʻa and the surrounding bay and how these temperature differences may be reflected in potential fish productivity,” lead author Annie Innes-Gold, a recent PhD graduate from the university, said in a press release. “We found that although rising water temperature may lead to declines in fish populations, loko iʻa fish populations were more resilient.”