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For more than four years, California has had a law on the books meant to protect homes and buildings during an urban firestorm like the Palisade and Eaton fires. But it’s never gone into effect.
In theory, the policy was simple. It directed state officials to develop new rules for buildings in areas with high fire risk, which would govern what people were allowed to put within the five-foot perimeter immediately surrounding their homes. A large body of evidence shows that clearing this area, known in the fire mitigation world as “zone zero,” of combustible materials can be the difference between a building that alights during a wildfire and one that can weather the blaze.
The new rules — essentially just a list of items allowed in that five-foot zone — were due two years ago, by January 1, 2023. But the State Board of Forestry and Fire Protection has yet to begin a formal rulemaking process. Ask anyone who’s been following this thread what’s taking so long, and they’ll almost certainly point to one thing: politics.
“There’s a ton of science about what to do, but the science has run into challenges with social acceptance, and therefore political acceptance,” Michael Wara, director of Stanford University’s Climate and Energy Policy Program, told me. People do not want to be told how they can or can’t landscape or furnish or otherwise adorn the outside of their homes. Inevitably, when the rules do come out, you’ll hear about Gavin Newsom coming to take away people’s decks and policing gardens.
No one thinks that zone zero rules, if enacted and adhered to, could have prevented fires in the Pacific Palisades or Altadena or saved every structure in the recent fires’ path. But alongside other fire mitigation strategies, zone zero design can significantly lower the chances of a given building burning, and therefore the chances that a fire will spread to neighboring buildings, and ultimately reduce the risk of fires becoming compounding, devastating disasters. Wara likened it to car safety rules like seatbelts and airbags — people still die in car accidents, but far fewer than would otherwise.
The question now is whether the record-breaking destruction in Los Angeles will be enough to convince people that zone zero rules are effective and worthwhile. Past experience shows the answer is not an obvious yes.
Why homes burn
There are three ways buildings ignite during a wildfire, Yana Valachovic, a forest scientist with the University of California Agriculture and Natural Resources Fire Network who specializes in community resilience and the built environment, told me. They are either exposed to burning embers, direct flames, or radiant heat, though most often a combination.
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Embers — hot, hard debris of burned material from a fire — can be carried miles away from their origin by the wind and create new spot fires next to homes. “What happens with those embers is they get thrown at the building, they hit the walls, the siding, and then drop to the base and collect at the base,” Valachovic said, “so you can have not just one, but thousands of embers at the base of our structures.”
Embers can also penetrate buildings through open windows and ventilation systems. If radiant heat from nearby burning structures causes windows to shatter or fall out, that can also create new vectors for embers to enter the home. “Embers find their way,” Valachovic said.
Fire mitigation experts promote two strategies for reducing vulnerability, and they go hand in hand. The first is
home hardening, which could mean building with fire-resistant materials but also includes smaller but effective actions like covering air vents with fine mesh screens and sealing gaps to try to block embers. The second is creating so-called “defensible space,” or a buffer around the building, where any vegetation is carefully selected and managed to slow the spread of fire to and from the building. California divides defensible space into three different zones: Zone one extends from 5 feet away from the structure to 30 feet, and zone two goes out to 100 feet away. Then, of course, there’s zone zero.
The state has had regulations on the books to require at least 30 feet of defensible space in high-risk areas since 1965, and it updated the standards to establish a two-zone system in 2006. In both cases, the rules were “really framed around, how do you interrupt flames running at the building?” said Valachovic. The regulations included thinning trees and removing lower branches, clearing some trees that were closer to homes, clearing dead wood and litter, and pruning branches that hang over buildings. But they still allowed for vegetation right up against the house.
Since then, wildfire post-mortems have found that this scenario of flames burning a path to a building is not a primary driver of structure loss. “It was missing the point,” Valachovic told me of the previous rule structure. “What we’ve seen now for the last decade is that embers are really driving our home loss issue, and so we’re basically allowing all this vegetation and combustible material to be present in the zone that is really very vulnerable.”
In August 2020, after Governor Gavin Newsom declared a state of emergency in California due to an explosion of wildfires, the state legislature passed AB 3074, which finally sought to bridge the gap by creating a new, “ember-resistant zone” — zone zero. Had the rules been implemented under the timeline mandated by the law, new homes would have had to comply beginning in 2023, and existing homes would have had to comply beginning in 2024. Like the earlier defensible space rules, they would have applied to homes located in parts of the state designated as Fire Hazard Severity Zones. These are generally areas that you might think of as the “wildland-urban interface,” where homes abut wildland vegetation like forests or scrublands, but others extend into more urban areas. Almost all of the burned area in the Pacific Palisades, for instance, would have been
subject to the rules, while only a small portion of the homes in Altadena are in the zone.
Why “zone zero” is political
When I reached out to the California Natural Resources Agency, the umbrella group for both the Board of Forestry and Fire Protection and CalFire, to ask if there was an updated timeline for the regulations, one of the first things that Tony Andersen, the Deputy Secretary for Communications, told me, was not about the timeline but about the ultimate cost of compliance.
“We recognize there are costs associated with doing this work around homes and structures,” Andersen told me via email, “and we are focused on identifying options for financial assistance as well as education and outreach to help owners prepare and prioritize mitigations.” He then noted that the rulemaking was a “complex process” that the agency wanted to get right, and said it aimed to present a draft proposal to the Board “as soon as is feasible, most likely in the coming months.”
Andersen’s response illustrates one of several tensions that have made it difficult to write the zone zero rules — and will ultimately make them difficult to implement. If the rules say you can’t have a wooden deck, for example, or you can’t have a fence that touches the building, homeowners could face costly retrofits. And despite witnessing the horror of destructive wildfires, many homeowners don’t want to switch their wooden fence for a metal one, or replace their bushes with gravel.
Five feet might sound like a negligible amount of space, but people are attached to the aesthetics of this zone. Homeowners have become used to “softening” the line where the walls meet the ground by filling it in with vegetation, Valachovic told me. “We really developed this idea that we don’t visually want to see our foundations,” she said. “From a fire defense perspective, this idea that we have combustible material basically ringing our houses and our structures, that is problematic.”
Several people I interviewed for this story asked if I had seen a documentary about the aftermath of the 2018 Camp Fire in Paradise, California called
Bring Your Own Brigade. The film captures a series of city council meetings in 2019, when officials were considering updating local building standards. They weigh a number of ideas that would reduce the risk of embers collecting on top of, inside, or next to homes, including eliminating gutters and requiring roof overhangs and a five-foot setback for any combustible material.
At the time, the Camp Fire was the deadliest and most destructive wildfire in state history, killing 85 people, displacing more than 50,000, and destroying more than 18,000 structures. But during a public hearing, community members lashed out at the potential cost, warned that new standards would prevent displaced residents from moving back, and decried the aesthetic implications.
“Paradise is an individualistic town,” one person says. “That’s part of the charm and the quirkiness. We don’t need consistency and uniformity.”
In another scene, a city councilmember asks Paradise Fire Chief John Messina to narrow down the list to just one rule that would make the community more fire resistant. “That five-foot barrier around your house is extremely important,” he replies. “That would be the No. 1 thing out of all of this that I would say would defend your home the best and have the most impact.” Shortly after, the council votes down the measure.
Michael Wara, who recalled the scene to me over the phone, said a similar thing happened when the fire chief in his community in Mill Valley tried to get the city council to adopt zone zero rules. “The word got out in the community that this crazy fire chief was going to make us rip up our front yards,” he said. When the council convened for a vote, more than a thousand people showed up to oppose it. The council ended up passing it as a voluntary measure.
To Wara, part of the problem is the language used to communicate these ideas with the public. “Zone zero” and “hardening” conjure a bunker mentality, he said. “I do not want my family to live in a bunker that is hardened to attack. I want my family to live in a home that is welcoming.”
He also thinks the state can reach a compromise, like allowing succulents and other fire-resistant greenery in zone zero. The rules don’t have to turn these areas into gravel and concrete wastelands to be effective.
Courtesy of the Los Angeles County Fire Department
The Los Angeles County Fire Department recently included photos in a
notice to homeowners about defensible space rules and the upcoming zone zero regulations that illustrate how landscapes might strike that balance. The images feature stone walkways immediately next to homes, followed by raised beds made of metal and concrete containing attractive landscaping. Not quite “quirky” and “charming,” but far from a barren dystopia.
Where insurance fits in
Despite the delay in implementing zone zero, California has tried to pitch it as part of a strategy to solve the state’s
insurance crisis. In 2022, Insurance Commissioner Ricardo Lara enacted new rules requiring insurance companies to provide discounts to homeowners who do home hardening retrofits and create defensible space.
“That’s terrific,” Dave Jones, the director of the Climate Risk Initiative at the University of California, Berkeley, and Lara’s predecessor as insurance commissioner, told me. “But you don’t get the discount if they won’t write you the insurance.”
Jones said the bigger issue is that the models insurance companies use to decide whether or not to write a policy do not account for fire mitigation efforts. A homeowner could take every action on the list for home hardening, create a zone zero, live in a community that’s investing in aggressive fuels reduction, and so on, and insurance companies could still deny them coverage. Last year, Jones wrote a bill that would have required companies to change the models they use to determine coverage to account for mitigation. Several insurance industry trade groups opposed the bill,
arguing that it was “premature and impossible to implement given the real-world data constraints,” and that it was “inconsistent” with the state’s efforts to “restore a healthy and competitive insurance market.” It didn’t pass.
If following zone zero guidelines meant having a shot at getting insurance, maybe people would be more open to doing it, Jones argued to me. But as things stand, that’s not the case. “I don’t think the failure is so much in the state developing the standards as it is in the lack of political courage to stand up to the insurance industry and say, hey, look, enough is enough. We’re going to pass a law to require your models to account for this.”
This past year, the California legislature passed a law giving existing homes three years, instead of just one, to comply with zone zero rules once they are finalized, whenever that is. And if the regulations are finalized this year, it’s possible that some of the rebuilt structures in the Pacific Palisades and Altadena will have to meet them.
Ultimately, Valachovic sees hope in fire mitigation work. The narrative that climate change is driving these destructive wildfires can make people feel helpless. But there are so many low-cost, simple things people can do to reduce their exposure. “I just feel like we have a moral imperative to share practical, reasonable actions that people can take to make a difference, and to know that with that, the odds improve substantially.”
Editor’s note: This story has been updated to clarify the role of the California Natural Resources Agency in the rulemaking process.
Heatmap Illustration/Getty Images, Standard Lithium
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 majorautomakers 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.”
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.
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.
Real estate firm Prologis was the loser at the end of a five-hour hearing last night before the planning commission in Shelbyville, a city whose municipal council earlier this week approved a nearly 500-acre land annexation for new data center construction. After hearing from countless Shelbyville residents, the planning commission gave the Prologis data center proposal an “unfavorable” recommendation, meaning it wants the city to ultimately reject the project. (Simpsons fans: maybe they could build the data center in Springfield instead.)
This is at least the third data center to be rejected by local officials in four months in Indiana. It comes after Indianapolis’ headline-grabbing decision to turn down a massive Google complex and commissioners in St. Joseph County – in the town of New Carlisle, outside of South Bend – also voted down a data center project.
Not all data centers are failing in Indiana, though. In the northwest border community of Hobart, just outside of Chicago, the mayor and city council unanimously approved an $11 billion Amazon data center complex in spite of a similar uproar against development. Hobart Mayor Josh Huddlestun defended the decision in a Facebook post, declaring the deal with Amazon “the largest publicly known upfront cash payment ever for a private development on private land” in the United States.
“This comes at a critical time,” Huddlestun wrote, pointing to future lost tax revenue due to a state law cutting property taxes. “Those cuts will significantly reduce revenue for cities across Indiana. We prepared early because we did not want to lay off employees or cut the services you depend on.”
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.
At a village board meeting on Wednesday, a member of activist group No Data Center in DeForest said they obtained conversations between village president Jane Cahill Wolfgram and QTS in which Wolfgram counseled the company on how to sell the project to the community.
Wolfgram apparently told QTS its descriptions of potential water use were inconsistent and that “lots of these folks are college educated and smart and looking to question.” Those comments were subsequently reported early this morning by regional TV news station WKOW, which confirmed the emails were authentic. Now they are beginning to make the rounds on local social media pages.
Wolfgram defended her comments to WKOW in a statement: “It is typical for staff and elected officials to have conversations with individuals or organizations seeking to make local investments to better understand potential impacts, challenges and benefits.”
Earlier this week, residents apparently also submitted a petition to village leadership requesting a referendum on the data center project that was reportedly signed by more than a thousand residents of the 12,000 person village. The village board rejected the petition, citing advice from its attorneys.
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.
The Bureau of Land Management this week updated the permitting timetable to say it’ll publish an updated analysis for the Greenlink North transmission line next month, taking into account impacts on sage grouse populations. If constructed, Greenlink North is expected to connect to solar projects across northern Nevada and attach to a substation in Ely, a town in White Pine County.
Conservationists consider sage grouse to be a keystone species for climate impacts and require unabated swathes of land in order to find mates. The Center for Biological Diversity has opposed Greenlink North on multiple grounds, but a primary point of contention has been that that new infrastructure could likely hinder sage grouse migration patterns and mating rituals, and the Center celebrated this decision. The solar industry has never really addressed sage grouse impacts in a comprehensive manner as they are somewhat unavoidable, though energy companies do generally monitor for the birds in compliance with any conditions for permits.
I’m not sure where this will go as Trump has certainly sought to hurt renewable infrastructure but also is paring back species protection efforts. It’s also worth noting that the timing here is liable to slip. The Trump 2.0 BLM has updated their permitting timetables for other renewable energy-related projects before, only to miss their deadlines or cancel the project (that’s what happened to Esmeralda 7).
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.
Developer SB Energy is now expected to begin construction on the 700-megawatt project this year. Libra was nearly finished with the permitting process and had been given a preliminary go-ahead at the end of the Biden administration, but SB Energy apparently required an amendment to its environmental approval taking into account new plans for its gen-tie transmission line, stormwater drainage, and other considerations.
This is not evidence of a broader thaw in renewable energy permitting, as none of the timelines for other active solar projects listed on BLM’s website have been updated since November at the latest.
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.
The high court cleared the way for the South Branch project in Hancock County in late December after residents opposed to the project challenged the final greenlight from the Ohio Power Siting Board, which was issued in 2023. The court found the OPSB decisions were “not unlawful or unreasonable,” that the residents’ challenge to the board was contradicted by evidence, and that the final approvals were justified.
I expect the next shoe to drop in the state’s solar legal challenges will be the Circleville solar project in Pickaway County. The Supreme Court this week heard arguments in a challenge against the OPSB decision to reject Circleville’s construction permit.
Courtesy of the Los Angeles County Fire Department
