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How Republicans and Democrats came together to seed new industries in specific places

The Biden administration announced on Friday that it would spend up to $7 billion to create seven new “hydrogen hubs” across the country. These hubs will house large-scale industrial facilities specializing in producing, moving, and using hydrogen, a potent gas that could play a range of roles in a climate-friendly economy. Hydrogen, which does not emit carbon pollution when burned, could decarbonize long-distance trucking, energy storage, chemical making, and heavy industry.
These hubs will, as my colleague Emily Pontecorvo writes, become important public-private laboratories for the use of clean hydrogen. They will complement tens of billions of dollars in tax credits that could soon support a clean hydrogen industry.
Although these hubs are a key part of the president’s climate strategy, they are not created by his signature climate law, the Inflation Reduction Act. They were funded, instead, by the bipartisan infrastructure law, which passed in December 2021.
That same legislation also spent $3.5 billion to create new direct air capture hubs, big regional facilities that will deploy technology capable of sucking carbon dioxide from the ambient air. In August, the Energy Department awarded the first of those hubs to Texas and Louisiana.
It matters that these two “hub”-based programs command some measure of bipartisan support. It signals, first, that these programs are likely to endure even if the GOP takes the White House next year. It shows, too, that Republicans in Congress — and especially in the Senate, where 19 Republicans voted for the infrastructure law — can back climate policy under some conditions. (Even if those conditions might involve having to negotiate with a Democratic president.)
It certainly helps, too, that hydrogen and direct air capture are two potentially climate-friendly industries where the fossil fuel industry could play the largest role. The chief executive of Occidental Petroleum, a fossil-fuel company that is building one of the first air-capture hubs, has even argued that carbon removal technology could allow the oil and gas industry to operate for decades to come.
But the bipartisan support for these programs reveal something else, too — a deeper change in how America’s leaders think about governing and growing the economy. Most coverage of the hubs has elided the fact that they’re called “hubs,” almost treating the word “hub” as a synonym for “big new economic thing.” But the hubs are called “hubs” for a reason; don’t snub the hubness of the hubs. The hubs are meant to do more than create new experimental industrial facilities at taxpayer expense. They are meant to seed specific industries in specific places, creating new centers of gravity that will allow new regional economies to form.
The idea behind the hubs goes back more than a decade. In 2010, a team of researchers at the Massachusetts Institute of Technology looked around the U.S. economy and realized something strange: Although many of the world’s most innovative and profitable companies did their R&D, design, and distribution in America, very few of them made their products here. Think of Apple, for instance, whose iPhones then bore the inscription: “Designed in California. Assembled in China.”
Why was that?, the team asked. That arrangement distorted the economy, depriving working-class people of the benefits of new industries. It also seemed unsustainable. “Without production capabilities in the U.S., can we generate new growth and jobs?” asked Suzanne Berger, a political science professor who led the project. “Can we even sustain innovation without manufacturing capabilities in the U.S.?”
The U.S. could not go on like this forever, they concluded, because innovation in design was inseparable from innovation in production. Many industries — including biotech, material science, and clean energy — required engineers to constantly flit back and forth from the factory floor to the lab, bringing problems encountered by assembly technicians back to the design engineers.
But this tight circuit of design, production, and design again didn’t just happen within influential companies, like Ford, AT&T, and 3M. One takeaway from their report, Making in America, is that innovation emerges from skilled communities of practice located in specific places. When a big company opens a factory or R&D lab somewhere, an ecosystem grows up around it. Small- and medium-sized manufacturers with their own expertise cluster around that big firm, because they can make a living by selling their own goods and services to that firm (or its competitors).
Speaking to a Senate committee in 2013, Berger described what happened when her team visited the laboratory of Tonio Buonassisi, a mechanical engineer then building a new type of solar cell. Buonassisi’s lab in Cambridge, Massachusetts, was full of cutting-edge equipment that had been made by an instrument company located only a couple hours away.
“Much of [that] machinery had been made in close collaboration between the lab and the instrument companies as they handed ideas and components and prototypes back and forth,” Berger said. “Used for the first time in the lab, these tools were now being marketed to commercial solar companies.”
At the time, the domestic solar industry was collapsing, and it worried Buonassisi. If American solar-cell makers went out of business, then it would put his specialty toolmaker out of business, too — and slow down or possibly end his own research agenda. “Even in a fragmented global economy with instant connection over the Internet to anywhere in the world,” Berger said, the close geographic ties “that connect research in its earliest stages to production in its final phases remain vital.”
When you start looking, you see endless evidence of these ecologies of production, these skilled communities of practice, everywhere. Silicon Valley once earned its name because it housed a booming semiconductor manufacturing industry nurtured by the Defense Department. A chip conductor at Intel could access a specialty lens maker, or metallurgist, or chemicals maker only a short drive away; even outside of work, these people met at bars and socialized in the same places. Soon, that semiconductor ecosystem gave rise to other adjacent businesses: a software industry that could write code for those semiconductors, and a personal computing industry that could make semiconductors useful to mass-market consumers; those industries gave rise to today’s tech industry.
Nor was that region’s power solely rooted in its technicians. The banks near Silicon Valley grew so familiar with the hardware and software industries that they could finance companies there more easily and cheaply than other financial institutions. One of those institutions even named itself after Silicon Valley.
Today, America has relatively few of these innovative clusters left. The point of the hub-based strategy is to build them back. The idea of the hubs isn’t only that America will get seven new large-scale facilities that produce or process hydrogen, or four new facilities that suck carbon out of the air. The object is that these big facilities will anchor new skilled communities of practice, the same way that, say, a deep-sea volcanic vent gives rise to an entire colorful food chain. President Biden might be announcing a new Philadelphia-based hydrogen hub today, but we won’t know if that hub will be a success until it’s scuttling with metallurgists and chemists and financiers and specialty electricians in 10 years.
The hydrogen and direct air capture facilities, in other words, are meant to grow into true hubs — hubs of engineering, hubs of finance, hubs of innovation. The government, having recognized that new industries and industrial centers will not form naturally, is now trying to seed them intentionally.
That is far from the laissez faire approach to innovation once embraced by policymakers. And it matters that Democrats and Republicans alike have embraced it in the infrastructure law: It reveals the growing belief that free markets alone will not keep America at the top of the global economy. Today’s announcement might be the first time you hear about a new federally supported “hub.” It probably won’t be the last.
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In practice, direct lithium extraction doesn’t quite make sense, but 2026 could its critical year.
Lithium isn’t like most minerals.
Unlike other battery metals such as nickel, cobalt, and manganese, which are mined from hard-rock ores using drills and explosives, the majority of the world’s lithium resources are found in underground reservoirs of extremely salty water, known as brine. And while hard-rock mining does play a major role in lithium extraction — the majority of the world’s actual production still comes from rocks — brine mining is usually significantly cheaper, and is thus highly attractive wherever it’s geographically feasible.
Reaching that brine and extracting that lithium — so integral to grid-scale energy storage and electric vehicles alike — is typically slow, inefficient, and environmentally taxing. This year, however, could represent a critical juncture for a novel process known as Direct Lithium Extraction, or DLE, which promises to be faster, cleaner, and capable of unlocking lithium across a wider range of geographies.
The traditional method of separating lithium from brine is straightforward but time-consuming. Essentially, the liquid is pumped through a series of vast, vividly colored solar evaporation ponds that gradually concentrate the mineral over the course of more than a year.
It works, but by the time the lithium is extracted, refined, and ready for market, both the demand and the price may have shifted significantly, as evidenced by the dramatic rise and collapse of lithium prices over the past five years. And while evaporation ponds are well-suited to the arid deserts of Chile and Argentina where they’re most common, the geology, brine chemistry, and climate of the U.S. regions with the best reserves are generally not amenable to this approach. Not to mention the ponds require a humongous land footprint, raising questions about land use and ecological degradation.
DLE forgoes these expansive pools, instead pulling lithium-rich brine into a processing unit, where some combination of chemicals, sorbents, or membranes isolate and extricate the lithium before the remaining brine gets injected back underground. This process can produce battery-grade lithium in a matter of hours or days, without the need to transport concentrated brine to separate processing facilities.
This tech has been studied for decades, but aside from a few Chinese producers using it in combination with evaporation ponds, it’s largely remained stuck in the research and development stage. Now, several DLE companies are looking to build their first commercial plants in 2026, aiming to prove that their methods can work at scale, no evaporation ponds needed.
“I do think this is the year where DLE starts getting more and more relevant,” Federico Gay, a principal lithium analyst at Benchmark Mineral Intelligence, told me.
Standard Lithium, in partnership with oil and gas major Equinor, aims to break ground this year on its first commercial facility in Arkansas’s lithium-rich Smackover Formation, while the startup Lilac Solution also plans to commence construction on a commercial plant at Utah’s Great Salt Lake. Mining giant Rio Tinto is progressing with plans to build a commercial DLE facility in Argentina, which is already home to one commercial DLE plant — the first outside of China. That facility is run by the French mining company Eramet, which plans to ramp production to full capacity this year.
If “prices are positive” for lithium, Gay said, he expects that the industry will also start to see mergers and acquisitions this year among technology providers and larger corporations such as mining giants or oil and gas majors, as “some of the big players will try locking in or buying technology to potentially produce from the resources they own.” Indeed, ExxonMobil and Occidental Petroleum are already developing DLE projects, while major automakers have invested, too.
But that looming question of lithium prices — and what it means for DLE’s viability — is no small thing. When EV and battery storage demand boomed at the start of the decade, lithium prices climbed roughly 10-fold through 2022 before plunging as producers aggressively ramped output, flooding the market just as EV demand cooled. And while prices have lately started to tick upward again, there’s no telling whether the trend will continue.
“Everyone seems to have settled on a consensus view that $20,000 a tonne is where the market’s really going to be unleashed,” Joe Arencibia, president of the DLE startup Summit Nanotech, told me, referring to the lithium extraction market in all of its forms — hard rock mining, traditional brine, and DLE. “As far as we’re concerned, a market with $14,000, $15,000 a tonne is fine and dandy for us.”
Lilac Solutions, the most prominent startup in the DLE space, expects that its initial Utah project — which will produce a relatively humble 5,000 metric tons of lithium per year — will be profitable even if lithium prices hit last year’s low of $8,300 per metric ton. That’s according to the company’s CEO Raef Sully, who also told me that because Utah’s reserves are much lower grade than South America’s, Lilac could produce lithium for a mere $3,000 to $3,500 in Chile if it scaled production to 15,000 or 20,000 metric tons per year.
What sets Lilac apart from other DLE projects is its approach to separating lithium from brine. Most companies are pursuing adsorption-based processes, in which lithium ions bind to an aluminum-based sorbent, which removes them from surrounding impurities. But stripping the lithium from the sorbent generally requires a good deal of freshwater, which is not ideal given that many lithium-rich regions are parched deserts.
Lilac’s tech relies on an ion-exchange process in which small ceramic beads selectively capture lithium ions from the brine in their crystalline structure, swapping them for hydrogen ions. “The crystal structure seems to have a really strong attraction to lithium and nothing else,” Sully told me. Acid then releases the concentrated lithium. When compared with adsorption-based tech, he explained, this method demands far fewer materials and is “much more selective for lithium ions versus other ions,” making the result purer and thus cheaper to process into a battery-grade material.
Because adsorption-based DLE is already operating commercially and ion-exchange isn’t, Lilac has much to prove with its first commercial facility, which is expected to finalize funding and begin construction by the middle of this year.
Sully estimates that Lilac will need to raise around $250 million to build its first commercial facility, which has already been delayed due to the price slump. The company’s former CEO and current CTO Dave Snydacker told me in 2023 that he expected to commence commercial operations by the end of 2024, whereas now the company plans to bring its Utah plant online at the end of 2027 or early 2028.
“Two years ago, with where the market was, nobody was going to look at that investment,” Sully explained, referring to its commercial plant. Investors, he said, were waiting to see what remained after the market bottomed out, which it now seems to have done. Lilac is still standing, and while there haven’t yet been any public announcements regarding project funding, Sully told me he’s confident that the money will come together in time to break ground in mid-2026.
It also doesn’t hurt that lithium prices have been on the rise for a few months, currently hovering around $20,000 per tonne. Gay thinks prices are likely to stabilize somewhere in this range, as stakeholders who have weathered the volatility now have a better understanding of the market.
At that price, hard rock mining would be a feasible option, though still more expensive than traditional evaporation ponds and far above what DLE producers are forecasting. And while some mines operated at a loss or mothballed their operations during the past few years, Gay thinks that even if prices stabilize, hard-rock mines will continue to be the dominant source of lithium for the foreseeable future due to sustained global investment across Africa, Brazil, Australia, and parts of Asia. The price may be steeper, but the infrastructure is also well-established and the economics are well-understood.
“I’m optimistic and bullish about DLE, but probably it won’t have the impact that it was thought about two or three years ago,” Gay told me, as the hype has died down and prices have cooled from their record high of around $80,000 per tonne. By 2040, Benchmark forecasts that DLE will make up 15% to 20% of the lithium market, with evaporation ponds continuing to be a larger contributor for the next decade or so, primarily due to the high upfront costs of DLE projects and the time required for them to reach economies of scale.
On average, Benchmark predicts that this tech will wind up in “the high end of the second quartile” of the cost curve, making DLE projects a lower mid-cost option. “So it’s good — not great, good. But we’ll have some DLE projects in the first quartile as well, so competing with very good evaporation assets,” Gay told me.
Unsurprisingly, the technology companies themselves are more bullish on their approach. Even though Arencibia predicts that evaporation ponds will continue to be about 25% cheaper, he thinks that “the majority of future brine projects will be DLE,” and that DLE will represent 25% or more of the future lithium market.
That forecast comes in large part because Chile — the world’s largest producer of lithium from brine — has stated in its National Lithium Strategy that all new projects should have an “obligatory requirement” to use novel, less ecologically disruptive production methods. Other nations with significant but yet-to-be exploited lithium brine resources, such as Bolivia, could follow suit.
Sully is even more optimistic, predicting that as lithium demand grows from about 1.5 million metric tons per year to around 3.5 million metric tons by 2035, the majority of that growth will come from DLE. “I honestly believe that there will be no more hard rock mines built in Australia or the U.S.,” he said, telling me that in ten years time, half of our lithium supply could “easily” come from DLE.
As a number of major projects break ground this year and the big players start consolidating, we’ll begin to get a sense of whose projections are most realistic. But it won’t be until some of these projects ramp up commercial production in the 2028 to 2030 timeframe that DLE’s market potential will really crystalize.
“If you’re not a very large player at the moment, I think it’s very difficult for you to proceed,” Sully told me, reflecting on how lithium’s price shocks have rocked the industry. Even with lithium prices ticking precariously upwards now, the industry is preparing for at least some level of continued volatility and uncertainty.
“Long term, who knows what [prices are] going to be,” Sully said. “I’ve given up trying to predict.”
A chat with CleanCapital founder Jon Powers.
This week’s conversation is with Jon Powers, founder of the investment firm CleanCapital. I reached out to Powers because I wanted to get a better understanding of how renewable energy investments were shifting one year into the Trump administration. What followed was a candid, detailed look inside the thinking of how the big money in cleantech actually views Trump’s war on renewable energy permitting.
The following conversation was lightly edited for clarity.
Alright, so let’s start off with a big question: How do investors in clean energy view Trump’s permitting freeze?
So, let’s take a step back. Look at the trend over the last decade. The industry’s boomed, manufacturing jobs are happening, the labor force has grown, investments are coming.
We [Clean Capital] are backed by infrastructure life insurance money. It’s money that wasn’t in this market 10 years ago. It’s there because these are long-term infrastructure assets. They see the opportunity. What are they looking for? Certainty. If somebody takes your life insurance money, and they invest it, they want to know it’s going to be there in 20 years in case they need to pay it out. These are really great assets – they’re paying for electricity, the panels hold up, etcetera.
With investors, the more you can manage that risk, the more capital there is out there and the better cost of capital there is for the project. If I was taking high cost private equity money to fund a project, you have to pay for the equipment and the cost of the financing. The more you can bring down the cost of financing – which has happened over the last decade – the cheaper the power can be on the back-end. You can use cheaper money to build.
Once you get that type of capital, you need certainty. That certainty had developed. The election of President Trump threw that into a little bit of disarray. We’re seeing that being implemented today, and they’re doing everything they can to throw wrenches into the growth of what we’ve been doing. They passed the bill affecting the tax credits, and the work they’re doing on permitting to slow roll projects, all of that uncertainty is damaging the projects and more importantly costs everyone down the road by raising the cost of electricity, in turn making projects more expensive in the first place. It’s not a nice recipe for people buying electricity.
But in September, I went to the RE+ conference in California – I thought that was going to be a funeral march but it wasn’t. People were saying, Now we have to shift and adjust. This is a huge industry. How do we get those adjustments and move forward?
Investors looked at it the same way. Yes, how will things like permitting affect the timeline of getting to build? But the fundamentals of supply and demand haven’t changed and in fact are working more in favor of us than before, so we’re figuring out where to invest on that potential. Also, yes federal is key, but state permitting is crucial. When you’re talking about distributed generation going out of a facility next to a data center, or a Wal-Mart, or an Amazon warehouse, that demand very much still exists and projects are being built in that middle market today.
What you’re seeing is a recalibration of risk among investors to understand where we put our money today. And we’re seeing some international money pulling back, and it all comes back to that concept of certainty.
To what extent does the international money moving out of the U.S. have to do with what Trump has done to offshore wind? Is that trade policy? Help us understand why that is happening.
I think it’s not trade policy, per se. Maybe that’s happening on the technology side. But what I’m talking about is money going into infrastructure and assets – for a couple of years, we were one of the hottest places to invest.
Think about a European pension fund who is taking money from a country in Europe and wanting to invest it somewhere they’ll get their money back. That type of capital has definitely been re-evaluating where they’ll put their money, and parallel, some of the larger utility players are starting to re-evaluate or even back out of projects because they’re concerned about questions around large-scale utility solar development, specifically.
Taking a step back to something else you said about federal permitting not being as crucial as state permitting–
That’s about the size of the project. Huge utility projects may still need federal approvals for transmission.
Okay. But when it comes to the trendline on community relations and social conflict, are we seeing renewable energy permitting risk increase in the U.S.? Decrease? Stay the same?
That has less to do with the administration but more of a well-structured fossil fuel campaign. Anti-climate, very dark money. I am not an expert on where the money comes from, but folks have tried to map that out. Now you’re even seeing local communities pass stuff like no energy storage [ordinances].
What’s interesting is that in those communities, we as an industry are not really present providing facts to counter this. That’s very frustrating for folks. We’re seeing these pass and honestly asking, Who was there?
Is the federal permitting freeze impacting investment too?
Definitely.
It’s not like you put money into a project all at once, right? It happens in these chunks. Let’s say there’s 10 steps for investing in a project. A little bit of money at step one, more money at step two, and it gradually gets more until you build the project. The middle area – permitting, getting approval from utilities – is really critical to the investments. So you’re seeing a little bit of a pause in when and how we make investments, because we sometimes don’t know if we’ll make it to, say, step six.
I actually think we’ll see the most impact from this in data center costs.
Can you explain that a bit more for me?
Look at northern Virginia for a second. There wasn’t a lot of new electricity added to that market but you all of the sudden upped demand for electricity by 20 percent. We’re literally seeing today all these utilities putting in rate hikes for consumers because it is literally a supply-demand question. If you can’t build new supply, it's going to be consumers paying for it, and even if you could build a new natural gas plant – at minimum that will happen four-to-six years from now. So over the next four years, we’ll see costs go up.
We’re building projects today that we invested in two years ago. That policy landscape we invested in two years ago hasn’t changed from what we invested into. But the policy landscape then changed dramatically.
If you wipe out half of what was coming in, there’s nothing backfilling that.
Plus more on the week’s biggest renewables fights.
Shelby County, Indiana – A large data center was rejected late Wednesday southeast of Indianapolis, as the takedown of a major Google campus last year continues to reverberate in the area.
Dane County, Wisconsin – Heading northwest, the QTS data center in DeForest we’ve been tracking is broiling into a major conflict, after activists uncovered controversial emails between the village’s president and the company.
White Pine County, Nevada – The Trump administration is finally moving a little bit of renewable energy infrastructure through the permitting process. Or at least, that’s what it looks like.
Mineral County, Nevada – Meanwhile, the BLM actually did approve a solar project on federal lands while we were gone: the Libra energy facility in southwest Nevada.
Hancock County, Ohio – Ohio’s legal system appears friendly for solar development right now, as another utility-scale project’s permits were upheld by the state Supreme Court.