How a Quebec Lithium Mine May Help Make Electric Cars Affordable

The project also illustrates how difficult it is to get lithium out of the ground and break China’s dominance in processing the metal and turning it into batteries.

Source: New York Times | By Jack Ewing

Jack Ewing, who covers the global auto industry, reported from La Corne, Quebec.

• Sept. 20, 2022

About 350 miles northwest of Montreal, amid a vast pine forest, is a deep mining pit with walls of mottled rock. The pit has changed hands repeatedly and been mired in bankruptcy, but now it could help determine the future of electric vehicles.

The mine contains lithium, an indispensable ingredient in electric car batteries that is in short supply. If it opens on schedule early next year, it will be the second North American source of that metal, offering hope that badly needed raw materials can be extracted and refined close to Canadian, U.S. and Mexican auto factories, in line with Biden administration policies that aim to break China’s dominance of the battery supply chain.

Having more mines will also help contain the price of lithium, which has soared fivefold since mid-2021, pushing the cost of electric vehicles so high that they are out of reach for many drivers. The average new electric car in the United States costs about $66,000, just a few thousand dollars short of the median household income last year.

But the mine outside La Corne, operated by Sayona Mining, an Australian company, also illustrates the many hurdles that must be overcome to produce and process the materials needed to wean automobiles from fossil fuels. The mine has had several owners, and some of them filed for bankruptcy. As a result, some analysts and investors warn that many mines being developed now may never be viable.

Dozens of lithium mines are in various stages of development in Canada and the United States. Canada has made it a mission to become a major source of raw materials and components for electric vehicles. But most of these projects are years away from production. Even if they are able to raise the billions of dollars needed to get going, there is no guarantee they will yield enough lithium to meet the continent’s needs.

Amid a vast pine forest in Quebec sits a deep mining pit with walls of mottled rock. The rock contains lithium, an indispensable ingredient in electric car batteries that is in short supply.

Elon Musk, Tesla’s chief executive, said in July that being a lithium supplier was a “license to print money.” But it is also a risky, volatile business. Ore buried deep in the earth may have insufficient concentrations of lithium to be profitable. Opposition from environmental groups or nearby residents can delay or kill projects.

Mines tend to be in remote locations. By industry standards, Sayona’s mine, which is at the end of a 12-mile gravel road, is just around the corner. Many other projects are far more inaccessible.

After the price of lithium fell by half from 2017 to 2020, the mine’s previous owner, the Chinese battery maker CATL, shut down operations and sought protection from creditors for the subsidiary that owned the property. Sayona, working with Piedmont Lithium, a lithium mining and processing company based in Belmont, N.C., bought the operation last year.

Sayona site sits at the end of a 12-mile gravel road about 350 miles northwest of Montreal.

Some investors believe the hype around lithium is overblown and have been betting against mining companies. They believe that some of the companies lack the expertise to blast ore, haul it out of the earth and separate the lithium from the surrounding rock. Lithium projects often suffer delays and cost overruns.

The risk is reflected in the gyrations of Sayona shares traded on the Australian Securities Exchange in Sydney. They peaked at 36 Australian cents (24 U.S. cents) in April, plunged to 13 cents in June and have recently traded at around 28 cents.

“Those of us in the industry are quite confident that lithium will be in short supply for the next decade,” said Keith Phillips, chief executive of Piedmont Lithium, which owns 25 percent of the Sayona’s Quebec project. He added, “Others are taking a contrarian view.”

For many people in government and the auto industry, the main concern is whether there will be enough lithium to meet soaring demand for electric vehicles.

The Inflation Reduction Act, which President Biden signed in August, has raised the stakes for the auto industry. To qualify for several incentives and subsidies in the law, which go to car buyers and automakers and are worth a total of $10,000 or more per electric vehicle, battery makers must use raw materials from North America or a country with which the United States has a trade agreement.

Lithium is the lightest known metal; its ability to store energy makes it attractive for batteries.

The world will also need more refineries, the plants where raw lithium is processed into a concentrated form of the metal that goes into batteries. Most lithium is processed in China, and Piedmont and other companies plan to build refineries in the United States. But lithium processing requires expertise that is in short supply, said Eric Norris, president of lithium at Albemarle, a mining and processing company in Charlotte, N.C.

Lithium is the lightest known metal, and its ability to store energy makes it attractive for batteries. But lithium deposits come embedded in other metals and minerals. That is why extracting lithium can be incredibly difficult.

The mining industry “has not honed its ability, broadly speaking, to build conversion capacity repeatedly and consistently,” Mr. Norris said, noting that even his company, which has extensive experience, has suffered delays building processing plants.

Albemarle operates the only active lithium mine in the United States, in Silver Peak, Nev., where the metal is extracted from brine, a liquid found beneath the ground. Some Tesla batteries contain lithium from Nevada, but the site’s total annual output is enough for about 80,000 vehicles. Americans bought 370,000 battery-powered cars in the first six months of 2022, according to Kelley Blue Book, and sales are rising fast.

The mine outside La Corne has traded hands several times; some of the businesses that had owned it filed for bankruptcy.

Albemarle also produces lithium in Chile and Australia. The company is working to reopen a lithium mine in Kings Mountain, N.C., and plans to build a refinery in the Southeast.

Even those large projects will not be enough to satisfy demand as California and other states move to ban internal combustion engines. “It’s going to take everything we can do and our competitors can do over the next five years to keep up,” Mr. Norris said.

One of the first things that Sayona had to do when it took over the La Corne mine was pump out water that had filled the pit, exposing terraced walls of dark and pale stone from previous excavations. Lighter rock contains lithium.

After being blasted loose and crushed, the rock is processed in several stages to remove waste material. A short drive from the mine, inside a large building with walls of corrugated blue metal, a laser scanner uses jets of compressed air to separate light-colored lithium ore. The ore is then refined in vats filled with detergent and water, where the lithium floats to the surface and is skimmed away.

The end product looks like fine white sand but it is still only about 6 percent lithium. The rest includes aluminum, silicon and other substances. The material is sent to refineries, most of them in China, to be further purified.

Yves Desrosiers, an engineer and a senior adviser at Sayona, began working at the La Corne mine in 2012. During a tour, he expressed satisfaction at what he said were improvements made by Sayona and Piedmont. Those include better control of dust, and a plan to restore the site once the lithium runs out in a few decades.

“The productivity will be a lot better because we are correcting everything,” Mr. Desrosiers said. In a few years, the company plans to upgrade the facility to produce lithium carbonate, which contains a much higher concentration of lithium than the raw metal extracted from the ground.

The operation will get its electricity from Quebec’s abundant hydropower plants, and will use only recycled water in the separation process, Mr. Desrosiers said. Still, environmental activists are watching the project warily.

Long Point First Nation, an Indigenous group, wants to do its own environmental impact study of lithium mines that it says are on its ancestral territory.

Mining is a pillar of the Quebec economy, and the area around La Corne is populated with people whose livelihoods depend on extraction of iron, nickel, copper, zinc and other metals. There is an active gold mine near the largest city in the area, Val-d’Or, or Valley of Gold.

Mining “is our life,” said Sébastien D’Astous, a metallurgist turned politician who is the mayor of Amos, a small city north of La Corne. “Everybody knows, or has in the near family, people who work in mining or for contractors.”

Most people support the lithium mine, but a significant minority oppose it, Mr. D’Astous said. Opponents fear that another lithium mine being developed by Sayona in nearby La Motte, Quebec, could contaminate an underground river.

Rodrigue Turgeon, a local lawyer and program co-leader for MiningWatch Canada, a watchdog group, has pushed to make sure the Sayona mines undergo rigorous environmental reviews. Long Point First Nation, an Indigenous group that says the mines are on its ancestral territory, wants to conduct its own environmental impact study.

Sébastien Lemire, who represents the region around La Corne in the Canadian Parliament, said he wanted to make sure that the wealth created by lithium mining flowed to the people of Quebec rather than to outside investors.

Mr. Lemire praised activists for being “vigilant” about environmental standards, but he favors the mine and drives an electric car, a Chevrolet Bolt.

“If we don’t do it,” he said at a cafe in La Corne, “we’re missing the opportunity of the electrification of transport.”

Jack Ewing writes about business from New York, focusing on the auto industry and the transition to electric cars. He spent much of his career in Europe and is the author of “Faster, Higher, Farther," about the Volkswagen emissions scandal. @JackEwingNYT • Facebook

A version of this article appears in print on Sept. 20, 2022, Section A, Page 1 of the New York edition with the headline: Canadian Mine May Hold a Key To Electric Cars. Order Reprints | Today’s Paper | Subscribe

Hydrogen tax credit details: USA

Source: Recharge News | by Leigh Collins

The $433bn Inflation Reduction Act of 2022 creates a tax credit that would pay clean hydrogen producers up to $3 per kilogram (adjusted for inflation).

The size of the tax credits available to US clean hydrogen producers depends on the lifecycle greenhouse gas (GHG) emissions of each project — and more importantly, on how much staff are paid.

So the basic tax credit rate for “qualified clean hydrogen” is set at $0.60/kg, with a sliding scale depending on lifecycle emissions — measured in carbon dioxide-equivalent (CO2e) — of the H2 produced.

Hydrogen manufactured with less than 0.45kg of lifecycle CO2e emissions per kg of H2 would receive 100% of the credit, followed by 33.4% for 0.45-1.5kgCO2e/kgH2, 25% for 1.5-2.5kg and 20% for 2.5-4kg.

The lifecycle emissions would have to be verified “by an unrelated third party”, and only projects that start construction before 2033 would qualify.

However, the wage requirement in the new bill seems to be the most important part of the deal — multiplying the size of the tax credit by a factor of five.

Producers would be eligible for this boost if they ensure “that any laborers and mechanics employed by contractors and subcontractors in the construction of such facility… shall be paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which such facility is located as most recently determined by the Secretary of Labor”.

Importantly, these lifecycle emissions are calculated from “well to gate” — in other words, they would include upstream methane emissions in the production of blue hydrogen (which is made from natural gas with incomplete carbon capture and storage).

Also, the IRA states that blue hydrogen projects would be ineligible for H2 tax credits if they already receive federal tax credits for carbon capture and storage — but green hydrogen projects would also be allowed to receive renewable energy tax credits valued at $30/MWh in addition to the hydrogen ones.

'This will set the bar' | All eyes on California for historic first US floating wind auction

ANALYSIS | As bumper 43 applicants line up, experts say milestone round is test for industry's risk appetite while industrialisation holds key to long term success

5 December 2022 16:28 GMT UPDATED  5 December 2022 17:05 GMT

Source: Recharge News | By Tim Ferry

The US’ flagship west coast deepwater wind auction set to kick off tomorrow (6 December) is the nation’s most eagerly anticipated seabed leasing round since the New York Bight spurred a $4bn-plus bidding bonanza, and marks the opening of a whole new frontier for the global floating sector.

The US government and the state of California will spur at least 4.6GW – and likely far more – of new capacity and a multibillion dollar investment wave, playing a huge role in the state’s massive climate and renewable energy ambitions that include a near term target of 2-5GW by 2030 and 25GW by 2045.

Five lease zones spread across two separate wind energy areas (WEA) off Morro Bay in central California and Humboldt County in the north are to come under the hammer (see graphic at foot). The WEAs sprawl over some 373,000 acres of Pacific deepwater and hold a wind resource expected by the Bureau of Ocean Energy (BOEM), the lead regulator of energy development in federal waters, to generate enough clean power for 1.6 million homes.

The auction has attracted a bumper 43 applicants that includes international stalwarts, American newbies, and joint ventures across technology and project developers.

The leasing round begins 6 December at 0700 Pacific Standard Time (1000 Eastern Standard Time), with BOEM anticipating it may extend over several days. Bids start at $6m and provisional winners will be announced at its conclusion, but the results may take several weeks before being certified.

But will that huge demand lead to a feeding frenzy such as was seen for fixed-bottom capacity in the New York Bight, where bids totalled $4.37bn in February this year? Not necessarily, according to some expert commentators.

“Prices tend to be higher in states that have actual offshore wind mandates than in states where they're just supporting it,” Walt Musial, National Renewable Energy Laboratory (NREL)’s head of offshore wind energy research, told Recharge.

New York and New Jersey, the two US states facing the New York Bight, have some of the nation’s most aggressive legal targets. “In California, we don’t see that mandate,” said Musial.

California’s mid-century floating goal leads the nation but is not legally mandated. The state does have aggressive decarbonisation mandates of 40% reduction in greenhouse gas emissions off 1990 baselines by 2030, and economy-wide carbon neutrality by 2045, but is technologically agnostic.

The state leads the US with 27GW of utility and residential solar, but this poses grid balancing challenges.

Musial said California understands that floating wind is going to be needed, “but to what degree is still in question.”

The state also lacks a clear pathway to market, as it doesn’t have a central authority capable of organising procurement.

“These first few leases will set a bar for where things go,” said Musial.

Diverse range of bidders

California’s floating auction has seen an unprecedented range of bidders, from industry stalwarts Orsted and Avangrid to oil supermajors TotalEnergies and BP and local energy consortiums new to the sector, such as Redwood Coast Energy Authority (see panel).

This “reflects both confidence in the direction of national and state energy goals [and] the knowledge that offshore wind has to be a significant part of the solution,” said Theodore Paradise, chief policy and legal officer in the US for Swedish floating wind developer Hexicon, which is also a qualified bidder.

Floating wind “is the perfect complement to solar to generate clean, reliable baseload power”, Jonah Margulis, senior vice president for offshore wind at Mainstream Renewables, told Recharge.

Scott Urquhart, CEO of research consultancy Aegir Insights, told Recharge: “Getting one of the first leases gives you a good foothold and positions you for many future options that might come your way.”

The auction is heavily focused on delivering local economic benefits, with 10% of the bid value available as community benefit agreements and 20% towards supply chain and workforce development, and those successful in obtaining lease options will need to invest in significant supply chain plans as well as bonuses directly to affected communities.

Port, transmission, and supply chain bottlenecks

California needs substantial supply chain and port investment, without which successful leaseholders will face myriad challenges advancing their projects.

Marshalling ports are “absolutely necessary for projects to get built,” said Musial, but Morro Bay has no readily available port nearby, with the only harbour actively developing a floating wind programme at Humboldt Bay, nearly 500 miles (800km) away.

Joshua Singer, lead on offshore wind ports for engineering consultancy Moffat & Nichol, told a recent conference, “There are no other ports on southern California that can be readied in time.”

Morro Bay’s three leases hold around a gigawatt each, and any port capacity built in the vicinity would need to be shared, adding to the risk, said Musial.

CALIFORNIA FLOATING WIND AUCTION QUALIFIED BIDDERS

547 Energy

AEUG Offshore

Algonquin Power Fund (America)

Arevia Power

Avangrid Renewables

BP US Offshore Wind Energy

California North Floating

California Offshore Wind Development

California South Floating

Castle Wind

Central California Offshore Wind

Cademo Corporation

Cierco Project Corporation

Clearway Renew

Corio OSW Investments

CPV Offshore Wind

EDF Renewables Development

EDPR Offshore North America

Equinor Wind US

Ferrovial Energy US

GW Offshore Wind

Hexicon USA

Ideol USA

Invenergy California Offshore

JERA Renewables NA

Marubeni Power International

Mission Floating Wind

Northcoast Floating Wind

Northland Power America

Orsted North America

Pacific Moon Offshore Wind

Pacific Offshore Wind

Redwood Coast Energy Authority (RCEA)

Redwood Coast Offshore Wind

RWE Renewables Development

RWE Offshore Wind Holdings

Seaglass Offshore Wind I

Seaglass Offshore Wind II

Shell New Energies US

SSE Renewable North America Offshore Wind

TotalEnergies Renewables USA

US Mainstream Renewable Power

Humboldt WEA, conversely, has existing transmission infrastructure to handle only some 150MW of offshore wind power, a tenth of its 1.5GW capacity potential.

Floating wind plant in northern California would require $5.3bn-$8bn in high-voltage transmission lines, according to the California independent system operator (Caiso), compared to only a single, 500kV substation for around $110m for the central coast.

“They're probably going to need more lease areas” to drive investment in the grid, Musial noted.

Supply chain investment is another question for the industry. The state has large-scale industrial ports at Long Beach and Los Angeles, but these are already bursting at the seams with logistics activity.

Building supply chain capacity instead of shipping components in from Asia or the US east coast could drive mass investment and jobs creation.

American Job Project sees GDP impacts from construction alone driving $16.2bn to $39.7bn in California, while the University of Southern California’s Schwarzenegger Institute estimates job gains from developing 10GW by 2040 totalling up to 195,000 job-years.

'Global epicentre'

Jason Folsom, vice president for renewables at Aker Solutions, told the Recharge Summit event in Washington, DC in November that California could become “the global epicentre for floating wind”.

Still, the industry’s success will depend on cost reductions that are being challenged by surging inflation, rising interest rates, and relentless supply chain disruptions.

The Biden administration’s Floating Wind shot aims to not only see 15GW of capacity in deep waters off US coastlines but the levelised cost of energy (LCOE) slashed by 70% in that same time frame.

Musial said cost reductions depend on large-scale industrialisation on the same turbine platform.

“The industry needs to mature the platform that they’ve developed at the 15MW scale and optimise and industrialise around that point,” he said.

“We can gain huge cost reductions just through the industrialisation of one specific platform, the standardisation of those parts in serial production, and the learning that goes on at those levels,” he said.

European electricity market: "We need a reform to stimulate low-carbon investments and guarantee supply"

Source: LeMonde, The world | by some french dudes? and translated by Google

Posted january 6, 2023 at 06:00, updated at 06:00

Due to soaring electricity prices, several opposition representatives, from the Rassemblement national to La France insoumise, including the Republicans, are calling for an exit from the European electricity market to lower consumer bills. , citing the example of Spain and Portugal. While qualifying this market as "badly done for a very long time" , Emmanuel Macron promised, Thursday, January 5, for the second half of 2023 "a reform of the electricity market so that it depends [on] production costs" .

How does this market work? As electricity cannot be stored, the principle of the European system consists in guaranteeing the balance between supply and demand for electricity on a European scale, by calling on the least expensive means of production as a priority. When it is no longer enough, other means are brought in, always favoring the least expensive. But the market price depends on the cost of production of the last plant to come into operation, which is often gas-fired. The more the gas plants are in demand, the higher the market price. This is the case this winter, due to the shutdown of many French nuclear reactors and the war in Ukraine, which has caused gas prices to soar.

Several European countries using a lot of gas to produce electricity, such as Germany and Italy, the European electricity market, which sets a single price regardless of the means of production, may therefore seem unfair for a country like France which has a large nuclear fleet .

But is the European market solely responsible for the current price spike? Are Spain and Portugal really out of it? Would France have an interest in following their example? Interviewed by Le Monde , Nicolas Goldberg, expert at Colombus Consulting, delivers his analysis.

What is wrong with the European market?

Many of the reproaches made to the European market are in fact the result of a misunderstanding. What some politicians are saying is that electricity prices are pegged to gas prices because of the Germans and that's why their prices are high, but that's not true. This system has one virtue, which is that the balance between supply and demand is achieved at the lowest possible cost. Each producer has an interest in offering the lowest price in order to receive the marginal tariff [the difference between the cost of production and the tariff for the last kilowatt-hour produced]. This can, of course, generate excess profits, but they are currently taxed and this taxation feeds the tariff shields. The reproaches of political leaders are therefore unjustified and the Germans have nothing to do with it.

On the other hand, what can be criticized for this system is that it encourages the sizing of production capacities as accurately as possible. Today, France sometimes imports electricity when it could produce it, quite simply because it is cheaper. The European market guarantees this ability to import at the best price, which is a good thing for consumers. But that does not encourage us to invest in production capacities, which reduces our room for manoeuvre. When you encounter a problem such as corrosion of nuclear facilities or gas supply difficulties, there is a risk of a shortage, as we can see today. This is the reason why opposition leaders who do not understand this functioning or want to use it for political ends are asking for a way out, citing, wrongly, the example of Spain and Portugal.

Precisely, have these countries really left the European electricity market?

No, that's completely wrong. They remain fully integrated into it, but have obtained a temporary exemption which allows them to cap the wholesale price of gas and reduce consumer bills by only 10% to 15% because the cost of the device is re-invoiced to consumers. But this is also what other Member States of the European Union [EU] do indirectly with tariff shields financed by taxing excess profits . The French government tells us of a saving of 20%. It is therefore more effective than what Spain is doing, without the perverse effects .

One country has indeed left the European market, it is the United Kingdom. It is still connected to the European network and continues to import electricity, but negotiates it over the counter and the tariffs are necessarily higher than if it had remained there and decoupled from the rest of the EU. Strangely, the political leaders who want to get out of it do not cite this example...

So France would have no interest in leaving it?

The answer is clearly no, for two reasons. The first is that it lacks electricity today, which has not escaped anyone. However, the European market makes it possible to import massively at the best price, a price harmonized at European level. When France is an exporter, on the other hand, he guarantees us that there will always be outlets, even when our nuclear power stations are producing at full capacity, because this electricity is cheaper than fossil fuels and France can use these interconnections to export. In this case, we don't hear anyone saying that we have to get out of it.

This European market therefore has a double benefit: when we have overcapacity, it allows us to export at very good prices and bring in foreign currency; when we are short of capacity, which is rather the case at the moment, our supply remains guaranteed at the best price. The interconnections have also shown their good functioning this winter.

Should it, despite everything, be reformed?

I think it is necessary. The market was developed in a logic of great liberalisation, at a time – the 1990s – when the fight against climate change was not the primary concern and when the European electricity system was very overcapacity. It contributed to the closure of means of production, in particular coal-fired power stations, but did not encourage investment. This system is myopic. It does not encourage looking at things in the long term.

We need a reform to stimulate investment in low-carbon production and guarantee security of supply, which would also limit the effects of speculation. In normal times, the European market protects us from it, because there is no reason to speculate when security is guaranteed; this was not the case this summer, when the risk of a shortage emerged, which opened the way to speculation. Among the avenues for reform, there is therefore that of imposing prudential rules on electricity suppliers so that they hedge themselves in the long term and are less subject to the ups and downs of the market.

Ice or Molten Salt, Not Batteries, to Store Energy

Source: New York Times | By Matthew L. Wald

• April 21, 2014

WASHINGTON — ENERGY storage is crucial to transforming the electric grid into a clean, sustainable, low-emissions system, the experts say. And it’s happening already, just not the way most consumers would expect.

The simplest idea for storage — charging up batteries at night when there is a lot of wind energy and not much demand for it, or at midday when the sun is bright — is years from being feasible, according to the experts.

The reason? It costs hundreds of dollars to store a kilowatt-hour of energy in a battery, while nationally the average retail price of a kilowatt-hour is about 11 cents. On the wholesale market, even buying low at off-peak periods and selling high could earn a battery owner perhaps 25 or 30 cents for each $400 or so invested. For that kind of transaction, “storage is not profitable,” said Jay Apt, executive director of the Carnegie Mellon Electricity Industry Center.

Prices would have to fall by 90 percent, from the current range of $300 to $500 per kilowatt-hour of capacity down to $30 to $50, he said. Instead, electric companies and some users of commercial power are adopting storage in forms that many people would not recognize as batteries — big containers of ice in building basements, or vast tanks of molten salt,  for example. And where plain old batteries that store actual electricity are being used on the power grid, they do very subtle, high-value jobs, like keeping the alternating current system in the proper rhythm, or smoothing out the flow of energy from wind farms that are prone to start and stop suddenly.

On the horizon is an exotic future of battery installations in places with plenty of conventional and renewable capacity that will need a bridge from daytime solar power. California anticipates that need in a few years, when solar power wanes at sunset, but natural gas plants are unable to awake fast enough from their afternoon nap, a problem the utility industry calls “ramping.”  Batteries will be needed to let the natural gas system start up early and supplement electricity supplies at twilight.

The storage field is so new that even executives in the energy business have trouble knowing how to think about it.

Take, for example, the strange tale of Dauren Kilish, an executive of AES Energy Storage, a company in Northern Virginia. Mr. Kilish’s firm set out to build a 40-megawatt battery in Texas, comprising several truck trailers. That amount of power would run about 4,000 window air-conditioners on a hot day or absorb about half the output of a small power plant running on natural gas.

Mr. Kilish called the grid operator to register the battery as an asset on the grid, since the battery was designed to be charged or discharged at the operator’s command. The grid keeps track of each generator as a resource, but also keeps track of businesses and can absorb extra energy when the system has a surplus.

So in which category  should it be registered? asked Mr. Kilish. Both, said the system operator, as a 40-megawatt source of supply and as a 40-megawatt source of load. AES said the system operator told the company to list the battery as an 80-megawatt resource.

AES also operates a big battery bank at the center of a wind farm in West Virginia. But it does not do what a consumer might expect; that is, storing energy from wind that blows mostly at night to meet heavier demand during the day when market prices are higher. Instead, on days when the wind is variable, it absorbs extra energy when a gust comes through, and pushes the energy back into the grid when the wind machines are suddenly calmed, to smooth out the variation in the farm’s output. It is far too small to store meaningful amounts from nighttime until daytime.

The value of storage, according to AES, is to add flexibility to the system.

But the way to store bulk amounts of energy for the grid lately is with cold or heat, as ice or molten salt. Hundreds of buildings now use their air-conditioning systems to freeze water into ice in the middle of the night,  taking advantage of low outdoor temperatures to help do the job. During the day, they melt the ice to cool the air.

In the Arizona desert, a major new solar plant uses the sun’s heat to warm sodium into a hot liquid. When the sun goes down, the sodium is piped into a steam generator, giving off its heat to boil water, which is used to spin a turbine and make electricity. The builders say using batteries would have made the costs many times higher.

A Houston company, TAS Energy, stores energy as cold. It chills water at night, and during the hot Texas summer, uses the cold water in a device like a radiator, to cool incoming air that is sent to a plant burning natural gas. When the incoming air is cooler, it is denser, so more of it fits into the combustion chamber, and power output is higher. The effect is to use nighttime energy to increase capacity in the hot afternoon.

Nearly all of these technologies lose energy on the way; that is, their round-trip efficiency, the ratio of energy put in to energy taken out, is well under 100 percent. But Darrell Hayslip, the chairman of the Energy Storage Association, said energy efficiency was not the point: dollar efficiency was. “You can’t really measure round-trip efficiency; it’s a function of economics,” he said. “If the charging electricity costs $2 vs. $20 for the electricity discharged, then it’s got greater round-trip efficiency.”

Mr. Hayslip’s trade group is 20 years old, but recently changed its name to “energy storage” from “electricity storage,” to better account for the variety of forms in which energy is being stored.

A version of this article appears in print on April 22, 2014, Section F, Page 7 of the New York edition with the headline: Ice or Molten Salt, Not Batteries, to Store Energy. Order Reprints | Today’s Paper | Subscribe