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Recovering from a disaster like the Palisades or Eaton fire can take years. Here’s what they can expect.

Two weeks after two of California’s most destructive wildfires on record sparked on the same day in Los Angeles, tens of thousands of displaced residents are taking the first steps of their recovery processes. Officials have started lifting evacuation orders for both the Eaton and Palisades fires, allowing families to return to their properties for the first time. For those whose houses survived, that means suiting up in personal protective equipment and cautiously wiping away ash, throwing out spoiled food, and assessing the damage from smoke, heat, and flames. For those whose houses were lost, it means sorting through wreckage to see what, if anything, can be salvaged.
This moment marks the first of many milestones fire survivors will encounter in the weeks, months, and years to come. Urban wildfires launch complicated timelines that involve a braiding of bureaucratic checklists and personal choices. The volume of decisions can be daunting in both volume and scope, stretched over the course of months, if not years.
It took about 15 months for the first house to be rebuilt and occupied following the 2023 Lahaina Fire in Maui. Five years after the 2018 Camp Fire — which is currently the only California wildfire more devastating than the Eaton Fire — the hard-hit town of Paradise had still rebuilt only about a third of its lost structures. The recovery from the 2021 Marshall Fire in Colorado has notably outpaced many others. There, about two-thirds of the lost homes were rebuilt within the first three years, but that still leaves hundreds wading through their next steps with waning support.
Jennifer Gray Thompson, founder and CEO of the nonprofit group After the Fire U.S.A., told me it’s important to understand that every disaster — and therefore every recovery — is different. Her organization helps communities through this process, building on the knowledge of survivors from previous wildfires, and she said each community tends to make some adaptations and improvements. But the experiences of other wildfire-impacted areas can offer L.A.’s fire survivors an idea of the steps and potential concerns they can expect to encounter next.
Take the re-entry process. As Los Angeles Mayor Karen Bass explained in a press conference on Monday, “Re-entry is based on safety.” And just because the fire has passed doesn’t mean the danger has: “Firefighters are still at work to prevent fires, to prevent flare-ups; there are hazardous materials being dealt with; utility repairs are underway; or there is other emergency work that makes it unsafe to be in the area,” Bass said. So far, officials doing this work have identified more than 16,000 destroyed structures and 28 fatalities from the two fires.
This waiting phase can be particularly challenging for those who evacuated, said Thompson. The adrenaline that helped impacted families make it through the fire might be waning under the weight of time, and the road ahead can start to feel overwhelming as various government agencies come to town and task forces pop up. It can take weeks for some evacuees to get the go-ahead to return home, particularly if they choose to wait for hazardous materials to get cleared, as L.A. County Department of Public Health Director Barbara Ferrer has recommended.
That brings us to the two phases of cleanup: removing hazardous materials and disposing of debris. Since the L.A. wildfires are a federally declared disaster, the Federal Emergency Management Agency is able to direct resources toward these tasks, with more than 500 Environmental Protection Agency employees currently surveying the burned areas to identify and collect of things like propane tanks, batteries, and other contaminants, which are packaged up and then disposed of off-site. This reduces the risks for residents returning to their properties, removing some obvious sources of chemicals and toxins like heavy metals and asbestos.
Once residents do make it back, they’ll have the opportunity to both survey and sift through their homes and choose whether they would like the government to remove the remains or contract out to a private company. This part of the process traditionally takes months, if not longer, depending on the scope of the damage, volume of the debris, and cooperation of the residents. For perspective, one year after the Lahaina Fire, debris removal was still ongoing and had racked up a more than $1 billion bill. The Army Corps of Engineers, which led this effort in Lahaina, will take charge again in L.A., with the L.A. Department of Public Works overseeing both phases from the local level.
While these are the larger hurdles residents will need to cross on the property level in order to rebuild, there will also be a number of government and utility-led efforts to make their homes habitable. That includes addressing issues with electric and water systems, from downed lines to blocked or broken sewers. These efforts are now underway in both burned areas, with utility trucks becoming a common sight across the county.
All of this can clear the way for construction to begin on the impacted properties, which comes with its own set of timelines, costs, and players. California Governor Gavin Newsom and Los Angeles Mayor Karen Bass have issued executive orders to reduce some of the bureaucracy that often accompanies permitting and building in L.A. These include suspending environmental reviews, expediting permitting, and clearing the way to “rebuild homes as they were.”
Still, residents will have to get those permits approved and source labor and materials for the project in what’s become a crowded national market. Other disasters, such as last year’s one-two punch of Hurricanes Helene and Milton, have created unusually high competition, with one development firm executive telling the Wall Street Journal he foresees a “Hunger Games-style competition for materials and labor.”
Fire survivors will also need to find the funds to put towards these projects, whether that’s through government aid, insurance, fundraising campaigns, or digging deep into their own pockets. Robert Fenton, Jr., a FEMA regional administrator, said that as of Wednesday, the agency has registered nearly 100,000 fire survivors to receive aid so far, including money to cover immediate needs for evacuees and to provide personal property and displacement assistance. But many previous disaster survivors will attest that navigating FEMA’s system can be challenging, particularly if you are also insured. Insurance claims need to be filed first — so that FEMA avoids duplicating aid homeowners are already receiving — another process that is known to be both slow and time-consuming, requiring a litany of paperwork and receipts.
And all of this is assuming no additional disasters occur during the recovery process. Wildfire-scorched areas are vulnerable to debris flows when it rains, as it is forecasted to do for the first time in months this weekend. Speaking at a county press conference Wednesday, Mark Pestrella, director of the L.A. Department of Public Works, said his office will be conducting 24/7 storm patrols, making assessments of burned properties and deploying sediment traps and sandbags in at-risk areas. Other weather conditions, like extreme heat or high winds, can also suspend operations and further delay residents from returning.
Overall, Thompson referred to rebuilding after a wildfire as “the biggest group project most people will have ever done in their lives.” Individuals, government officials, non-profits, attorneys, insurers, utilities, developers, and all sorts of laborers will be a part of the process, each bringing their own perspectives, needs, and costs to the table — some complementary and some competing.
Already, there is tension between the desire to rebuild for displaced residents and the desire to make the impacted area more resilient in the face of future hazards. In her newsletter, Susan Crawford, a climate adaptation expert and senior fellow at the Carnegie Endowment for International Peace, described the urge to quickly restore what was lost in L.A. as “both understandable and unthinkable” given the county’s ongoing housing crisis and wildfire risk. (Crawford is also a Heatmap contributor.)
“It’s obvious we should be taking a step back and thinking how and where we are rethinking how and where we live, but it may be too much to contemplate in this thickly populated area,” Crawford told me.
For those in L.A. trying to find their own way forward through these agencies and agendas, Thompson recommends turning to others who understand what you’re going through, like your neighbors. Establishing ways to share information, support, and organize can help ensure your community’s concerns and priorities are taken into account in the recovery process.
“You can actually do this,” she said. “It feels right now like it can’t, and it’s going to take time and it comes in stages. But you’re not alone.”
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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.