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The story of natural gas taxes and bans this election cycle is far more nuanced than that.

Berkeley, California and Washington State put the transition to all-electric buildings on the ballot last week, and in both cases, it seemed to fail the test. Voters in Berkeley overwhelmingly rejected a proposed tax on natural gas that would raise money for electrification projects. In one fell swoop, voters in Washington State repealed several of their nation-leading policies that encourage electric over gas appliances and barred cities and towns from passing similar policies in the future.
On the face of things, the results appear to show voters retreating from ambitious climate action and rejecting electrification — a concerning signal at a time when federal support for decarbonization is about to evaporate and state and local leadership to cut emissions will become paramount. But the specific circumstances behind each vote suggest that’s not the whole story.
The Berkeley proposal was submitted by a small group of activists who knew it was more ideologically driven than politically feasible, and it proved to be controversial even among diehard climate advocates in the city. The Washington State initiative slid onto the ballot just three months before the election and ultimately passed on a razor thin margin. The two cases offer distinct lessons and takeaways, but to climate advocates, a budding backlash to electrification is not one of them.
The Berkeley proposal, otherwise known as Measure GG, was largely written by one person. Daniel Tahara is a software engineer at Tesla by day, and a climate activist by night with 350 Bay Area, a local chapter of the national climate advocacy group 350.org. For the past few years, he’s been animated by a question that I, too, am frequently asking: How are most people going to afford the steep cost of retrofitting their homes to use electric appliances?
To Tahara, finding an answer became more pressing last year when the Bay Area Air Quality Management District, a regional authority that regulates pollution, approved rules to phase out the sale of gas appliances. Starting in 2027, Berkeley residents will no longer be able to purchase a new gas-fired water heater if their old one fails — they’ll have to go electric. The rule applies to gas-fired furnaces and boilers in 2029. “We've got a lot of old buildings,” Tahara told me. “They would need a lot of electrical work to support new appliances, and people just don't have the money for it.”
His solution was Measure GG, an ordinance that would have imposed a tax of $2.96 per therm of natural gas used by buildings larger than 15,000 square feet. The estimated $26.7 million per year raised by the tax would go into a fund to help everyone else in town pay for electrification retrofits.
Tahara rallied a number of local environmental and community groups around the idea, but he did not have the support of the bigger non-profits and advocacy orgs that work on electrification policy in California, including the Building Decarbonization Coalition, Rewiring America, RMI, the Sierra Club, or the Natural Resources Defense Council.
"Any large blanket tax hike without input from those it would impact, no plans for a managed transition to the new fees, and no analysis on who is most likely to benefit or be burdened is likely to face real challenges with voters,” Alejandra Mejia Cunningham, the senior manager of building decarbonization for the NRDC, told me via email. “It is very important for tax-based policy proposals to be robust and thoroughly socialized."
I also talked to several Berkeley-based electrification supporters who voted no on Measure GG. Tom Graly, who chairs a local electrification working group, told me part of the reason the policy proved so controversial is that it singled out some of the city’s most beloved institutions, such as the Berkeley Bowl supermarket, a local chain, and the Berkeley Repertory Theater. The theater estimated the tax would cost it up to $69,000 per year, while converting off of gas would cost millions. “This well-intentioned ballot measure with its immediate implementation would be very harmful to our struggling organization,” Tom Parrish, the theater’s managing director said in a statement for the “No on GG” campaign.
Tahara based the tax on estimates for what’s called the “social cost of carbon,” or the projected economic damage that every additional ton of carbon dioxide put into the atmosphere will cause. But the number Tahara chose was on the high end — more than double the number the Biden administration uses when it weighs the costs and benefits of new regulations on carbon. If passed, the tax would more than double the cost of using natural gas in large buildings. He said some national groups gave him feedback on the proposal, like phasing in the tax over time and building in more exemptions, which he might consider for a future version. But he and his partners on the measure wanted to preserve their core thesis, which was that climate damages are already happening and are unaccounted for.
“I think part of our responsibility as local activists is to put out new ideas, to push the status quo,” he said. “I don’t think there’s been a lot of that that’s been happening in the last couple years.”
In Tahara’s view, the measure failed because the opposition campaign had a lot more money, and because even though Berkeley is often called the birthplace of the electrify everything movement, there’s still a lot of people in town who are completely unaware of the harm natural gas causes to the climate and to public health. On that, Graly agreed. “There's a huge education gap,” he said. “People just don't think about hot water. They turn on the faucet and the water is hot, and they're happy.”
Initiative 2066 in Washington State was a wide-ranging proposal to both roll back existing policies and preempt future ones. It was so wide-ranging, in fact, that its opponents believe it’s illegal under the state’s “single subject” rule for ballot measures, and they plan to fight it in court.
If the measure stands, it will invalidate the state’s nation-leading residential and commercial energy codes that strongly incentivize builders to forego gas hookups. It will remove a provision in state statute that requires Washington’s energy codes to gradually tighten toward zero-emissions new construction by 2031. It will repeal key parts of a law the state legislature passed earlier this year that require Washington’s biggest utility, Puget Sound Energy, to consider alternatives to replacing aging gas infrastructure or building new gas pipelines. And it will ban cities and towns from passing any local ordinances that “prohibit, penalize, or discourage” the use of gas in buildings.
The initiative was one of four put on the ballot by Let’s Go Washington, a group bankrolled by hedge fund manager and multimillionaire Brian Heywood, and had the Building Industry Association of Washington as its primary sponsor, alongside a number of other pro-gas, pro-business, and realty groups.
There’s no doubt 2066 is a significant setback in the state’s progress toward cutting carbon emissions. But when I asked climate advocates in Washington how they were interpreting the outcome, they pointed to a handful of reasons why they weren’t too concerned about public sentiment around decarbonization.
First, the vote was incredibly close, with just over 51% of voters checking “yes.” Second, another initiative Let’s Go Washington put on the ballot — 2117, which would have repealed the state’s big umbrella climate law that puts a declining cap on emissions — unambiguously failed, with 62% voting “no.” Third, they argue the split reflects confusion about what 2066 would do.
The “yes on 2066” campaign sold it as a measure to “protect energy choice” and “stop the gas ban,” warning that otherwise utility rates would increase and the state would force homeowners to pay tens of thousands of dollars to retrofit their homes. There are kernels of truth to the messaging — the state’s building codes seriously limit developers’ ability to put gas hookups in new construction without outright banning them. The new law affecting Puget Sound Energy is primarily a planning policy that requires the utility to consider alternatives to gas infrastructure, but it doesn’t force anyone to get off gas, and regulators are likely to approve only those alternatives that save ratepayers money.
“I think voters were responding to a lot of misinformation and fear-mongering,” said Leah Missik, the Washington deputy policy director for Climate Solutions, a regional nonprofit that helped spearhead the “no on 2066” campaign. She emphasized that it was put on the ballot in July, giving groups like hers only a few months to drum up their response to it, whereas they knew about 2117 for over a year, and thus had a lot more time to educate voters on what that initiative would do.
The confusion probably also wasn’t helped by the fact that the policies 2066 repealed were incredibly wonky, dealing with building codes and utility planning.
“I think that given all of those headwinds, the fact that about half of Washingtonians still voted against initiative 2066 is a testament to how popular climate action is in the state,” Emily Moore, the director of the climate and energy program at the Sightline Institute, a Seattle-based think tank, told me.
Sightline didn’t campaign for or against the measure, but Moore had some takeaways from the vote. She said environmental groups spent a lot of their energy countering the narrative that there was a gas ban, which may have inadvertently reinforced the idea. One lesson for the future might be to put more emphasis on the benefits of electrification, like the fact that heat pumps provide both heating and cooling and half of the state doesn’t currently have air conditioning. The other anti-climate measure, 2117, may have failed so decisively because Washington’s emission cap policy has raised more then $2 billion in funding for projects that people are already seeing the benefits of, like free transit passes.
“Likely a no vote on that one felt like getting to keep good things,” she told me. “I think we have more to do to show that getting off of gas means getting good things too.”
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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.