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California has given America a glimpse at what running one of the world’s largest economies on renewable energy might look like.

The state recently hit a milestone: 100 days this year with 100% carbon-free, renewable electricity for at least a part of each day, as tracked by Stanford University engineering Professor Mark Z. Jacobson.

The state notched the milestone while — so far — avoiding blackouts and emergency power reductions this year, even with the hottest July on record.

That progress is largely due to the substantial public and private investments in renewable energy — particularly batteries storing solar power to use when the sun isn’t shining, according to energy experts.

“California has made unprecedented investments in our power grid in recent years — and we’re seeing them pay off in real time,” Gov. Gavin Newsom said in a statement to CalMatters. “Not only is our grid more reliable and resilient, it’s also increasingly running on 100% clean electricity.”

The state faces a huge challenge in coming years: A series of mandates will require carbon-free energy while also putting more electric cars on roads and electric appliances in homes. California, under state law, must run on 60% renewable energy by 2030, ramping up to 100% by 2045.

Signs of progress are emerging. From January to mid-July of this year, zero-carbon, renewable energy exceeded demand in California for 945 hours during 146 days — equivalent to a month-and-a-half of 100% fossil-fuel-free electricity, according to the California Energy Commission, the state agency tasked with carrying out the clean energy mandates.

But California still has a long way to go to stop burning fossil fuels for electricity. Natural gas, which emits greenhouse gases and air pollutants, remains its single largest source of electricity.

Just over half of power generated for Californians in 2022 came from solar, wind, other renewables and nuclear power, while 36% came from natural gas plants.

Reliability of the power grid is a top concern as the state switches to solar and wind energy. Unpredictable events like wildfires and winter storms also cause outages, while hot summer months, with air conditioners whirring, strain the supply.

In August of 2020 California experienced its first non-wildfire blackouts in nearly 20 years, and in late August and September of 2022, a severe heatwave forced regulators to ask consumers to voluntarily reduce power for 10 days.

Since September 2022 — when California teetered on the edge of those blackouts and the governor pleaded for conservation — nearly 11,600 new megawatts of clean energy have been added to the state’s grid, said Elliot Mainzer, chief executive of the California Independent System Operator, which manages the grid. (That’s enough to power around 9 to 12 million homes although it’s not available all at one time.)

California also now has more than 10,000 megawatts of battery capacity, making it the largest supply outside of China. Battery power from large commercial facilities proved its worth during last month’s heat wave, Mainzer said.

Batteries “were a major difference-maker,” Mainzer said. “The batteries charged during the day, when solar energy is abundant, and then they put that energy back onto the grid in the afternoon and evening, when solar production is rolling off the system.”

California relies heavily on four-hour duration lithium-ion batteries, which come in large, centralized facilities and hybrid facilities paired with solar energy projects. More homes also are installing batteries with their rooftop solar installations, but they supply a small amount of power.

Planning and practicing various emergency scenarios has also helped immensely, Mainzer said.

“Our grid operators are now increasingly experienced at managing these extreme heat events,” Mainzer said. “Our forecasters also did an excellent job of reviewing the next day’s conditions so that the market could respond effectively.”

‘The table is set’ for clean energy

California may need to more than double its energy generation capacity by 2045 to meet the 100% clean energy target while adding electric cars, appliances and other technologies, said Siva Gunda, who sits on the California Energy Commission. 

To do that, California aims to build about 6,000 to 8,000 megawatts of new energy resources each year. The state hit a record last year, adding more than 6,000 megawatts, Gunda said. Each megawatt is enough to serve between 750 and 1,000 homes. 

“The table is set,” Gunda said. “The pieces are there for success, and it’s about executing it, together with a common vision and collaboration.”

The commission is closely monitoring a new concern: Artificial intelligence technology, which uses large data centers that consume power. “We’re carefully watching where the loads are going to grow,” Gunda said.

Stanford’s Jacobson said running on 100% renewable energy is becoming more common.

Over the July 28 weekend, California marked the 100th nonconsecutive day within a 144-day stretch in which 100% of electricity came from renewable sources for periods ranging from five minutes to more than 10 hours, he said.

On April 8, a solar eclipse reduced solar power generation and increased demand on the grid, which was met by batteries. On May 5, wind, hydroelectric and solar energy reached more than 160% of demand for a significant portion of the day.

California continues to waffle about ending its reliance on natural gas and nuclear power.

Fearing emergency rolling blackouts like the one in 2020, Newsom and the Legislature in 2022 allowed some natural gas plants that were supposed to go offline to keep operating. 

And the Diablo Canyon nuclear power plant will continue operating while Pacific Gas & Electric pursues federal permission to stay open past 2025. Nuclear power is considered renewable and carbon-free but it creates radioactive waste.

State officials and private investors aim to create an entirely new industry — giant floating ocean wind platforms — to produce 13% of California’s power, enough to power 25 million homes, by 2045. The massive projects will cost billions of dollars. 

Some Democratic legislators are hoping to make it easier to build wind and solar projects, since sometimes local obstacles and permitting take years. They are negotiating an end-of-session package of proposed laws that could streamline construction, CalMatters reported earlier this month. California’s legislative session ends Aug. 31.

Jacobson said the cost of large-scale solar power projects has “dropped substantially” in recent decades largely because of “economies of scale — just the huge growth of solar on a worldwide scale.”

“There’s no miracle technology that was developed,” he said. “It’s just subtle improvements in existing technologies and deployment, deployment, deployment.”

California hits milestones toward 100% clean energy — but has a long way to go is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

This article was originally published by Colorado Newsline.

The state commission that regulates Colorado’s oil and gas industry this week adopted its first set of rules governing geothermal drilling, taking another step towards fulfilling the broader mandate it was given as part of a legislative makeover of the agency last year. But regulators and experts say not to expect a “boom” in the new technology just yet.

The Energy and Carbon Management Commission was formerly known as the Colorado Oil and Gas Conservation Commission until lawmakers rebranded it in 2023. The name change that came with new authority to regulate emerging industries like carbon capture and so-called deep geothermal energy.

ECMC adopted its Deep Geothermal Operations rules on a unanimous 5-0 vote Monday. The 59-page addition to the agency’s rulebook outlines permitting and enforcement procedures broadly similar to those already in place for oil and gas operations, giving the commission the power to approve or deny permits to protect health and safety and ensuring that local governments have a say in the process.

While existing technologies like heat pumps involve drilling geothermal wells hundreds of feet into the ground to heat and cool homes and even entire neighborhoods, the deep geothermal industry aims to help power the electric grid by drilling thousands of feet down into much hotter pockets of the Earth’s crust. To date, the application of deep geothermal technology has been limited by a variety of factors, but some experts point to its potential to serve as a “baseload” source of clean energy to help offset the intermittency of renewables like wind and solar.

Gov. Jared Polis, who has touted geothermal energy’s potential in his “Heat Beneath Our Feet” initiative, said in a statement Monday that with the ECMC’s new rules, the state is “poised to leverage this clean, renewable energy resource.”

“Colorado has incredible low-cost renewable energy resources like geothermal that can help reduce emissions and save Coloradans money,” Polis said. “Geothermal energy can play an integral role in powering the way Coloradans live, work and play, and will help future generations.”

The feasibility of tapping into deep geothermal resources can vary widely according to local geology. A study released last month by the ECMC, the Colorado Geological Survey and Atlanta-based energy firm Teverra analyzed “geothermal utilization opportunities” and found that the Piceance Basin north of Grand Junction, the Raton Basin near Trinidad and a “localized hot spot” along the Colorado-Kansas border rank as the state’s most promising locations.

Colorado Communities for Climate Action, a coalition of 43 local governments supportive of clean energy policies, said the rules adopted by the ECMC struck an “impressive balance.”

“Local governments are optimistic about the role of deep geothermal electricity in efficiently decarbonizing Colorado’s power grid,” Emma Pinter, an Adams County commissioner and vice president of Colorado Communities for Climate Action, said in a statement. “But we have to make sure this new technology benefits all Coloradans and their environment while avoiding the damage we have seen from oil and gas development and other extractive industries.”

“Despite its promise as a clean energy source, (deep geothermal operations) will have some adverse impacts, although we don’t yet know the scope of them, and it’s important to recognize that,” Kate Burke, an assistant county attorney for Boulder County, told commissioners in a rulemaking hearing last week. “The net impacts … should be less than oil and gas, and in some instances, the scale may be smaller, but that doesn’t mean there won’t be impacts to the people, plants and animals living near the facilities.”

Geothermal Rising, a trade group representing geothermal energy companies, was “very satisfied with where the draft rules have landed,” an attorney for the group, Matt Lepore, told commissioners Monday. Lepore is a former chair of the agency who departed in 2018 and has gone on to represent the oil and gas industry in commission proceedings.

Environmental groups have urged the ECMC to follow up with a second geothermal rulemaking process to flesh out its regulations before operations ramp up. Commissioner Brett Ackerman, a former Colorado Parks and Wildlife official, said prior to Monday’s vote that it was important not to “hamper industry” at an early stage, but the agency should “appropriately address future concerns and opportunities as they arise.”

“I agree that it’s highly unlikely that there’s any pending boom of deep geothermal development,” Ackerman said. “We’re rather more at a pilot stage.”

Colorado oil and gas regulators adopt ‘deep geothermal’ drilling rules is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

This article was originally published by Canary Media.

A hefty chunk of U.S. emissions comes from the energy used to heat buildings. That means millions of homes must be converted to electric heating in order to meet climate targets. 

In Colorado, a 2021 law spurred the state’s largest investor-owned utility to produce a plan that could transition a lot of homes to clean heating — and fast.

Xcel Energy’s Clean Heat Plan was approved this May. It directs more than $440 million over the next three years mainly to electrification and energy-efficiency measures that are meant to reduce reliance on the gas system and cut annual emissions by 725,000 tons.

The utility, which provides both gas and electricity to its customers, filed an initial plan that included proposals to spend heavily on hydrogen blending, biomethane, and certified natural gas. But after strong opposition from clean energy advocates who say these routes do not represent viable pathways to decarbonization, those proposals were reevaluated. Following a motion filed by the Sierra Club, Natural Resources Defense Council, and others last November, Xcel amended its original plan filed with the Colorado Public Utilities Commission.

Now the majority of funds will go toward building electrification and energy efficiency, which the commission found to be the ​“most cost effective and scalable ways to reduce emissions from burning gas and buildings, both in the short run as well as in the long term,” said Meera Fickling, building decarbonization manager at Western Resource Advocates.

Electrification efforts will primarily take the form of incentives that make it cheaper for customers to switch gas heating appliances to electric heat pumps. The incentives can be combined with federal electrification tax credits and extend to all-electric new construction as well. One-fifth of the program’s funding is earmarked for low-income customers. The plan’s funding is roughly three times the $140 million that the Inflation Reduction Act allocated to Colorado for similar measures.

The utility forecasts gas sales to decline by 14 percent between this year and 2028, The Colorado Sun reports.

While many states have incentives and rebates available for upgrading to energy-efficient appliances and heating solutions, Colorado specifically directs its gas utilities to lead those programs — and holds them accountable for contributing to the state’s climate goals.

That’s why Xcel’s new clean heat program will be ​“a test case of a utility-led model towards decarbonizing the gas distribution system,” Fickling said. ​“It really serves as a model — a nationwide model — for how gas utilities can allocate resources to decarbonize their system in the long term.”

From state laws to utility plans 

Colorado’s push to clean up home heating started three years ago with the Clean Heat Law, which requires gas distribution utilities to create concrete plans to reduce their greenhouse gas emissions 4 percent below 2015 levels by 2025 and 22 percent by 2030. Xcel’s recently approved Clean Heat Plan will carry the utility through 2027, and the utility must propose a new plan in the coming years to meet the next target.

“I expect the next plan to really take a close look at the 2030 target and the trajectory to achieve it,” said Jack Ihle, regional vice president of regulatory policy at Xcel.

The Clean Heat Law was the first of its kind in any state, Fickling said, though others have since taken steps to curtail the climate impact of heating.

Following Colorado’s 2021 law, in 2023 Vermont passed the Affordable Heat Act to reduce emissions from home heating, and Massachusetts drafted similar legislation. This year, Illinois and New Jersey have both introduced bills with clean heating and decarbonization standards.

In Minnesota, the state’s largest gas utility just received approval for a five-year, $106 million plan to reduce its emissions following the state’s 2021 Natural Gas Innovation Act. The utility, CenterPoint Energy, says the plan would ​“reduce or avoid an estimated 1.2 million tons of carbon emissions over the lifetime of the projects,” though advocates have criticized the approach.

But utilities in Colorado ​“have a lot more flexibility in terms of the portfolio that they propose,” said Joe Dammel, manager of carbon-free buildings at RMI. While Xcel can prioritize energy efficiency and electrification in Colorado, Minnesota’s Natural Gas Innovation Act requires gas utilities to produce emissions-reduction plans that spend at least half of their budgets on alternative fuels like renewable natural gas, which can still heavily pollute. In Colorado, a much smaller amount is dedicated to alternative fuels; only around $10 million out of the $440 million can be spent on renewable natural gas and recovered methane, and all projects must specifically be approved by the commission.

Another difference between the two recently approved plans is that Xcel delivers gas and electricity to about 1.5 million customers in Colorado, which gives it an opportunity to counterbalance lost gas revenue with increased sales from its electricity business. 

Meanwhile, CenterPoint serves gas to about 910,000 customers but has no electricity customers. That gives it fewer opportunities to make up for losses from its gas business driven by electrification mandates, and more incentive to prioritize the use of alternative fuels delivered through the pipelines it owns — and not electrification.

Investing in 100,000 heat pumps 

Now that the funds have been approved, Xcel is waiting on a final written order from regulators, which should arrive later this month. From there, it will start implementing the plan and work on defining rebate levels and informing customers on how to access incentives.

The details are still being decided, but customers will likely need to pay first and then get reimbursed later, as is the case for many current rebate programs, said Emmett Romine, vice president of energy and transportation solutions at Xcel. Customers would also get higher rebates if they choose more advanced technologies, like high-efficiency cold-climate heat pumps.

Beyond educating customers, the company is putting workforce-training plans together to ensure there are enough heat-pump installers ready to help customers convert. Xcel is also working with distributors and manufacturers ​“to make sure that there’s a supply chain that will come to Colorado when we stimulate demand,” Romine said.

The plan represents a significant step up from Xcel’s current pace of upgrades. ​“The goals are really aggressive,” Romine said. ​“When you look at the number of heat pumps and the number of water heaters we’ve got to contemplate getting into homes, it’s an enormous amount of work.” Currently, Xcel does around 10,000 rebates a year for traditional gas furnaces. Now, it’s aiming to do 20,000 heat-pump conversions this year and just under 100,000 total by the end of 2026, Romine said.

That supercharged effort won’t come without costs. Ratepayers will see electricity rates go up by 1.1 percent and gas rates rise by 7 percent over the next four years due to the plan. But advocates say it’s worth it to avoid pouring money into a gas system that must be phased out — and that the climate benefits outweigh the upfront costs. Even without the Clean Heat Plan, Xcel projected it would need to increase base rate revenue by 32 percent between 2023 and 2030, The Colorado Sun reported.

Colorado’s plan ​“is a very good example of needing to pursue both sides of the equation at the same time — decarbonization, electrification — but at the same time ensuring that we’re starting to shrink and eliminate unnecessary investments in the gas system,” said Alejandra Mejia Cunningham, senior manager of state buildings policy at the Natural Resources Defense Council.

The Public Utilities Commission has encouraged Xcel to report its progress by 2026, ahead of the legally mandated schedule, Ihle said. Advocates will be watching closely to see how it all plays out.

“We’re gonna have to make sure that we’re seeing the results of that in terms of participation, customer satisfaction, and ultimately emissions and cost reductions,” Dammel said. ​“There’s going to be a lot of utilities across the country following this.” 

Xcel Colorado’s new clean heat plan is a big deal. Here’s why. is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Oregon’s plan to regulate fossil fuel companies and reduce greenhouse gases is ready for public comment after being derailed seven months ago by a lawsuit brought by natural gas companies. 

Draft regulations for the state’s redo of the 2021 Climate Protection Program were published Tuesday by the Oregon Department of Environmental Quality. The agency gave the public until Friday, Aug. 30 to comment on them. The state’s Environmental Quality Commission, which oversees rulemaking for DEQ, is expected to vote on final rules by the end of the year, once again putting the state’s landmark climate change laws into action.

Little has changed from the original program standards, which were passed three years ago by the commission. The targets for reducing greenhouse gas pollution would remain the same. Under the proposed rules, Oregon would attempt to reach a 50% reduction in greenhouse gas pollution by 2035 and a 90% reduction by 2050 to confront the growing threat of climate change. 

Fossil fuel companies would have to gradually decarbonize their energy supply, largely by shifting away from petroleum and natural gas and instead incorporating renewable energy sources such as wind, solar and so-called biofuels – made from captured gas and decomposing matter – into their energy offerings. 

Natural gas is almost entirely methane gas, among the most potent climate-warming greenhouse gases that trap heat in the atmosphere. One-third of global warming is due to human-caused emissions of methane, according to the U.S. Environmental Protection Agency. 

Under the newly proposed rules, some heavy energy users in the state would need to meet emissions reduction targets and companies would need to show compliance with the program every two years, as opposed to every three years in the original plan.

“We did build off of the work that we already did in the prior Climate Protection Program,” Nicole Singh, senior climate change policy advisor for DEQ, told the Capital Chronicle on Tuesday. “We didn’t throw that out the window. We’re using that information to help inform this.”

To give companies a little flexibility, they would be able meet some pollution reduction targets by purchasing credits sold by the state. Money from those credits are invested in projects that reduce greenhouse gas emissions. 

Expanding the program

Besides the three-year compliance schedule, the largest change to the newly proposed rules is who has to follow them. 

The state, for the first time, would regulate the emissions of companies that are heavy natural gas users, not just the suppliers of their gas. These include some cement, fertilizer and gypsum producers. Gypsum is in plaster, drywall and some cement. Companies operating in Oregon, including cement maker Ash Grove and Georgia Pacific, which works with gypsum, would need to meet new emissions standards, Singh said.

The agency included other changes in the investment portion of the Climate Protection Program. This section covers what is ostensibly Oregon’s carbon crediting market, where polluters can offset some of their greenhouse gas emissions by investing in projects that reduce overall emissions. One credit would be equal to one metric ton of carbon dioxide released into the atmosphere, and companies could buy them for $129 per credit. This market, which would have begun operating this year, was previously projected to bring in $150 million a year for community decarbonization and renewable energy projects, according to the Portland-based nonprofit Seeding Justice, which had previously been tasked with overseeing the investments.

Credit recipients, largely nonprofits working on community-based projects, could use the grants to help people and businesses buy and install solar panels and heat pumps, purchase electric vehicles and chargers and help weatherize homes and buildings.

Under the proposed rules, Oregon’s nine federally recognized tribes would play a bigger role in determining grants and would receive more funding, according to Singh. It’s unclear yet what role Seeding Justice could play in distributing grants in the future, she said, because such details would follow final rulemaking.

The state would also take a fraction of the funding – about 4.5% – to pay for its oversight of the grants and to undertake internal and external auditing to ensure money is being spent appropriately and that projects are, in fact, reducing the amount of greenhouse gas emissions required. 

Under the new rules, companies could offset 15% of their emissions through the purchase of these credits during the first two years of the Climate Protection Program and 20% during each two-year compliance period thereafter. Previously, companies could only offset 10% of their emissions through the credits in the first two years.

DEQ also proposes to work more closely with the Oregon Public Utilities Commission to understand how the Climate Protection Program will affect natural gas rates for Oregonians and to ensure companies aren’t passing all the costs of decarbonization on to their customers. 

Lawsuit triggers redo

The Climate Protection Program was approved in 2021 by the Environmental Quality Commission after more than a year of meetings, presentations from the environmental quality department and public comment. 

But in December, Oregon Court of Appeals judges agreed with lawyers representing NW Natural, Avista Corporation and Cascade Natural Gas Corporation, who argued that in the process of imposing state regulations to cap and reduce emissions, the commission failed to submit required disclosures to the companies and to other entities that hold federal industrial air pollution permits. The department was required to issue a written statement about why the state was adopting emission limits that exceeded federal rules, disclose a list of alternatives that were considered and explain why they were not adopted. 

The judges ruled the program invalid on those technicalities.

Rather than appealing the decision to the Oregon Supreme Court, which would likely not hear the case until mid-2025, state environmental regulators announced in January that they would start over.

Redo of Oregon program to cap greenhouse gas pollution ready for public review is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Add lithium to water in a chemistry lab, and you’ll get an incendiary reaction. The same might be said of opening new lithium mines: The prospect can spark conflicts when it comes to water.

Mining companies and the U.S. government are investing in increased extraction for lithium, which is a critical component in some renewable energy technology, especially electric vehicle batteries and large grid-scale storage batteries.

The IRA injected the Department of Energy (DOE) Loan Programs Office with about $11.7 billion to support new loans for energy projects, including mines for needed metals like lithium. This builds on earlier Bipartisan Infrastructure Law (BIL) grants for battery material supply chains. The IRA also offers tax credits of up to $7,500 on eligible electric vehicles, creating additional demand for lithium by the auto industry.

With funding from the IRA, DOE and BIL, lithium miners have gained new financial vigor and governmental votes of confidence. Yet some worry what impact this newfound funding will have on the environment.

Domestic mining is still primarily governed by the outdated 1872 Mining Law, which didn’t enshrine environmental protections, but “declared all valuable mineral deposits in land belonging to the United States to be free and open to exploration and purchase,” according to the Bureau of Land Management (BLM) website.

Through the National Environmental Policy Act, environmental impact statements are required ahead of major projects like mines, although some statements have been criticized as rushed or insufficient. But ultimately, it’s up to companies to choose and monitor their own environmental protections and community agreements, even if they’re collecting federal subsidies.

Lithium mining poses a range of risks to biodiversity and groundwater supplies, depending on the methods used. There are three main types of lithium extraction: brine evaporation, hard rock mining and clay mining.

In brine evaporation, groundwater is first pumped to the surface. There, 90% of it is evaporated away to concentrate the lithium brine, with additional freshwater needed to complete extraction.

Hard rock and clay mining often begin with “dewatering,” or removing groundwater to reach the ore, in addition to needing more water to process the ore. These methods also require chemicals such as sulfuric acid for processing, which in cobalt and copper mining has led to contamination of local water systems.

Concerned about the risks, local residents and environmentalists have resisted new mines with tactics from protests to litigation — but a government-supported lithium boom appears to be underway regardless.

New mines emerge

A Center for Biological Diversity map lists more than 125 lithium extraction projects in the western U.S. alone. Seven are inactive, and the majority are in various stages from exploration to development. Most of the proposed mines are in Nevada, predicted as a future “Silicon Valley of lithium.”

Albemarle’s Silver Peak mine in Nevada, a brine evaporation mine that has come under scrutiny for depleting groundwater aquifers in an increasingly-arid region, is the only currently active U.S. lithium mine. That’s likely to soon change, since the IRA has incentivized metal and mineral extraction in the United States and in countries with a U.S. free trade agreement.

Through its loan support and EV sales incentives, the IRA has made lithium mines more profitable, and less financially risky for companies opening new ones. Several lithium companies, including ioneer, Allkem and Albemarle, lobbied for the IRA’s passage or for provisions within it. A 2023 IRA impact report from S&P Global noted “aggressive mine capacity additions” for lithium planned in countries including the United States, Chile and Australia.

Domestically, most lithium deposits are in the West, where water supplies are already stressed.

“There’s a critical minerals and specifically a lithium rush unfolding, especially, but not exclusively, across the western U.S.,” says Providence College political scientist Thea Riofrancos, who specializes in studying the impact of resource extraction on communities. She adds that some of the mining interest predates the IRA, “but it’s picked up a lot since the IRA, because that sent such clear signals.”

Yet new mines pose risks to the region’s biodiversity. In a lawsuit against a Rover Metals exploration project, the Center for Biological Diversity and Amargosa Conservancy alleged that even exploratory drilling near springs in the Ash Meadows National Wildlife Refuge in Nevada would threaten endangered and endemic species. Active mines can have even bigger impacts.

“We need lithium as a part of our transition off of fossil fuels, but it can’t come at the expense of biodiversity or our most precious protected areas,” Patrick Donnelly of the Center for Biological Diversity, said in announcing the lawsuit. “Some places have to be off-limits to resource extraction, and Ash Meadows National Wildlife Refuge is at the top of the list.”

Thacker Pass on track

The Thacker Pass mine run by Lithium Americas is on track to become the second active lithium mine in the United States. The project in far northern Nevada may be indicative of what’s to come as more government-fueled mines pop up.

The lithium clay mine is under construction, with most Phase 1 construction costs covered by IRA support: General Motors is investing $650 million in exchange for the mine’s lithium. The U.S. Department of Energy provided a conditional $2.26 billion low-interest loan. Permitting came earlier, from President Trump’s administration. In 2028, the Thacker Pass mine is expected to reach full capacity production.

The DOE said the loan will provide General Motors with enough lithium for 800,000 electric vehicles a year and “reinforces the Biden-Harris Administration’s whole-of-government approach to strengthening America’s critical materials supply chain, which is essential to building America’s clean transportation future and enhancing our national and energy security.”

Questions about ‘voluntary’ mitigation

Lithium Americas plans to recycle and reuse withdrawn water an average of seven times. Its Phase 1 water consumption is estimated to be about 929 million gallons per year, equal to “around five alfalfa irrigation pivots,” according to the company’s blog.

Lithium Americas purchased existing agricultural water rights, so the operation won’t increase groundwater withdrawal, although existing groundwater withdrawal may still be unsustainable. It has also outlined plans for nearby habitat restoration. A post-mining reclamation plan is intended to reduce long-lived environmental impacts by refilling pits and restoring the surface.

But implementing and tracking mitigation strategies like these is left up to the companies. 

“What I think is concerning is the proliferation of lots of voluntary governance mechanisms that companies don’t have to do,” says Riofrancos. “What’s important — and it sounds old-fashioned, maybe — is regulation that’s binding; that’s enforceable; that carries sanctions, fees, punishments, fines, whatever, if the regulations are not obeyed.”

Riofrancos believes such regulations, plus sustained protests against irresponsible mines, could get the mining industry to “do better.” She says the IRA-supported DOE loan program represents a missed opportunity to tie robust regulations to mining projects: “It’s very light on guardrails and requirements for loan recipients.”

It’s also unclear how much mitigation is realistically possible.

“There’s ways to tinker around the edges, but ultimately, there’s no mitigating an open-pit mine,” Donnelly, the Great Basin director of the Center for Biological Diversity, said in an interview. “(These mines) cause impacts to the water table, impacts to wildlife, impacts to local and Indigenous communities.”

He believes IRA loans and other federal subsidies help new mines get permitted in spite of environmental risks: “The DOE’s kind of waving a magic wand and saying, ‘This mine is okay to permit.’ ”

But the exact risks of each new lithium mine are tricky to measure. The three different types of mines can have different effects, depending on variables including location, says David Boutt, a hydrogeology researcher and professor at the University of Massachusetts-Amherst. Companies are often reluctant to share data that would help scientists evaluate impacts, he says.

“It’s hard to establish a number, like, ‘This one has like a 30% less environmental impact than the others,’ ” Boutt says. “We don’t see these numbers, because a lot of the impacts are local and hard to quantify.”

Sacred site to become lithium mine

Yet for people living near mining sites, the risks can feel tangible. Dean Barlese, an elder from the Pyramid Lake Paiute Tribe, says he’s opposed to the Thacker Pass mine both because it’s at an Indigenous sacred site, and because his people’s lives are intertwined with the local ecosystem.

“A lot of people think it’s just a desert wasteland,” he says. “But the medicines we use are still out there. As Native people, we still gather our food, roots, berries — we’ve survived here for thousands of years.”

Barlese says he’d rather not see mining projects near Indigenous communities at all, regardless of community benefits agreements and environmental mitigation plans. “I would encourage the public to really look into the devastation that getting a bit of lithium does.”

Lithium demand could be reduced if investments were made in public transit and walkable communities, so fewer people were buying cars, Riofrancos says. Although the IRA includes investments in battery recycling, it doesn’t incentivize efforts to reduce surging lithium demand. Instead, it supports extraction to meet the demand, and helps ensure that the extracting companies can profit.

“ ‘Green energy’ is not green energy,” says Barlese. “Money speaks louder than anything else.”

Another possible solution to the mining debate would be an energy transition that uses less lithium.

“One way to reduce demand for lithium (or any battery metals) would be to make smaller batteries, or batteries that are more resource-efficient,” says Riofrancos. Two-thirds of current EV models are SUVs or large vehicles; small- and medium-sized EVs account for only a quarter of EV sales in the United States. Incentivizing smaller vehicles, which can use smaller batteries, could ultimately lead to fewer lithium mines.

Other battery chemistries are another option.

“Given the complexity of getting a permit, of getting the social license, of having everything in place, it’s going to take a long time (to open new mines),” says Boutt, the hydrogeologist. “And perhaps by the time we get to the point where we are developing those resources, we’ll have different battery technology where we’re not as reliant on lithium.”

Floodlight is a nonprofit newsroom that investigates the powerful interests stalling climate action.

Billions in US funding boosts lithium mining, stressing water supplies is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.