Metals Tech

Scientists have found a way of using alternative metals in lithium-based batteries that might not only help relieve the issues associated with conflict materials, but also offer more storage capacity in future devices.

The research team, led by professors at the University of California, Berkeley, managed to build lithium cathodes with 50 per cent more storage capacity than conventional materials – potentially enabling batteries to be made that can last considerably longer between recharges than current battery technology.

This could change how we use technology in the future as these batteries are used in phones, laptops, tablets and even some cars.

It’s also a potentially important step environmentally as lithium-based batteries currently use more than 50 per cent of all cobalt produced in the world, of which around half comes from the Democratic Republic of the Congo, where it’s largely mined by hand – in some instances by children.

For the first time we have a really cheap element that can do a lot of electron exchange in batteries

“We’ve opened up a new chemical space for battery technology,” said the University’s professor in the Department of Materials Science and Engineering, and senior author of the report, Gerbrand Ceder.

“For the first time we have a really cheap element that can do a lot of electron exchange in batteries.”

The study has been published in the April edition of the journal Nature and is a collaboration between scientists at UC Berkeley, Berkeley Lab, Argonne National Lab, MIT and UC Santa Cruz.

“To deal with the resource issue of cobalt, you have to do away from this layeredness in cathodes,” Ceder added. “Disordering cathodes has allowed us to play with a lot more of the periodic table.”

In the new study, Ceder’s lab shows how new technologies can be used to get a lot of capacity from a cathode.

In the world of batteries, this is a huge improvement over conventional cathodes

Using a process called ‘fluorine doping’, the scientists incorporated a large amount of manganese in the cathode. Having more manganese ions with the proper charge enables the cathodes to hold more lithium ions, thus increasing the battery’s capacity.

“In the world of batteries, this is a huge improvement over conventional cathodes,” said lead author Jinhyuk Lee, who was a postdoctoral fellow at Ceder’s lab during the study.

The new lithium alternative technology needs to be scaled up and tested more to see if it can be used in applications like laptops or electric vehicles, however.

But Ceder says whether or not this technology actually makes it inside a battery is beside the point as the researchers have opened new possibilities for the design of cathodes, an even bigger feat, apparently.

In the battery industry, records seem set to be broken almost as soon as they are hit. This is what may be about to happen with the largest battery storage system to date, if a California company gets all the permits it needs to build a 350-MW installation in the desert near Palm Springs.

When Tesla completed its 100 MW/129 MWh last year, it became a hallmark in the evolution of renewable power, signaling that the race for bigger and better storage systems was just beginning. Now, Recurrent Battery has staked its own claim in this race.

The San Francisco-based company is the U.S. unit of Canadian Solar and it has plans to build a 350-MW solar farm in the California desert along with a battery storage system of the same size. The Crimson project will span 2,500 acres. However, it is far from certain it will be completed.

The idea is certainly great. Tesla’s battery can power several tens of thousands of households. This one—if built—would power three times that, reducing this part of California’s dependence on natural gas power plants. These are now used after sunset for lack of enough solar energy storage installations. But the key is to find a buyer for the energy that will be produced by the solar farm—and this client needs to be large enough to justify the investment.

In other words, for now, the battery that will have triple the size of Tesla’s jewel is still just a possibility. Another project, however, is not: A British billionaire is building a 120 MW/140 MWh installation not far from Tesla’s installation in Australia.

Sanjeev Gupta, owner of Australian steelworks Whyalla, is building the battery to use both as storage for electricity produced by a solar farm, and in construction at the steelworks site. What we’re seeing there is likely just the beginning of ever-bigger battery storage systems that will accompany every large-scale solar or wind project.

A recent Moody’s report on energy storage supports this forecast. It found that investors are getting more and more interested in energy storage projects as their commercial viability improves. Moody’s calculated that a kWh of electricity from a battery storage installation currently costs around US$0.133. That’s based on a price of US$400 per kWh of storage (a high-price estimate) for a fully installed system divided by 3,000 charge/recharge cycles per battery over a lifetime of 10 years.

Now, Moody’s notes that this cost per kWh is still higher than conventional electricity, but adds that things are changing fast as batteries become cheaper and cheaper, so soon we may actually have renewable electricity that costs less than the output of fossil fuels power plants.

There is the question of battery life spans, of course, when compared to the life span of the average gas-fired power plant. Also, there are some unique challenges, Moody’s vice president and senior credit officer Rick Donner said in the report, especially with regard to operating risks. Still Donner said, on the whole, battery storage projects carry the same risks as conventional power generation projects.

Costs are falling, in the meantime. Moody’s estimates that by 2020-2022, the cost per kWh of storage will drop to US$100. This will make even bigger projects than Crimson viable. If things continue moving in the same direction as they have been for the last decade, it won’t be long before a 100 MW storage system becomes the lower end of renewable storage capacity.

CASTING doubt on wind power, Geoff Moore (Letters, April 12) seems to be denying the evidence of climate change. He suggests that historical recordings of Scottish weather indicate that the country is afflicted by “bad wind years” as well as “good wind years”. Unfortunately, with the inexorable advance of global warming the past weather record becomes meaningless. This warming means that the atmosphere will become increasingly energetic, potentially resulting in “good wind years” which are wilder than in the past, and “bad wind years”where the wind becomes incessant, particularly in northerly latitudes. If this is so, then the need for storage to “fill in” the wind power deficits for “bad years” becomes arguably much less critical.

Mr Moore wrongly dismisses the rapid developments which are occurring in battery technology, but batteries are not the only route to massive energy storage. Scotland is already well served by high altitude hydro-electric storage systems, while at the global level growing numbers of energy projects are increasingly being directed toward expanding pumped hydro-electric storage facilities. There are, at the last count, 64 fully developed pumped storage schemes world-wide and 10 more are under construction. In fact, even in the UK, there now exists four such schemes which are capable of providing more power than will be available from Hinkley Point nuclear power station.

The mining cycle has reached a sweet spot with booming commodity prices, lower costs and strong global growth fuelling healthy bottom lines. Yet cautious firms, burned by high spending levels ahead of the 2015/ 2016 downturn are determined not to repeat old mistakes. Heidi Vella finds out how miners are doing things differently this time around.

After four years of weak commodity prices and oversupply to the market, the last 18 months has finally seen growth return to the mining sector. Cue a collective sigh of relief.

Commodity prices are up across the board, supported by a lack of investment in new capacity, and mining firms are finally returning to profit.

In February, Anglo American  reported a 45% increase in annual earnings, as well as free cashflow of £3.5bn. Other major companies, including as BHP Billiton, Rio Tinto and Glencore, have released similarly compelling results.

According to a new Deloitte Touche Tohmatsu report, the mining industry now stands in ‘the middle of what appears to be another bull run for some commodities’.

During the last mining boom which played out in the early to mid-2000s, many commodities reached record prices. Firms reacted by investing full-throttle into new projects, but failed to pause to tackle increasingly expensive operating costs.

“Mining companies carried on expanding, and in their rush to maximise those high prices, they incurred costs,” says Deloitte Australia consulting mining leader David Cormack.

“However, when the cycle turned, much of that expenditure was hard wired into their operations, and even their mind-sets,” he adds. “It took a long time for them to respond and when they did, it had to be in a dramatic style.”

That response involved mass jobs losses, divesting assets and parking up exploration drill rigs indefinitely. This time around, have miners learned from the crash and burn?

Caution trumps miners’ risk appetite

Firms have learned “valuable lessons” from what was a once-in-a-lifetime super-cycle, says Cormack. Today they are far more cautious.

“Mining companies are being more prudent about what they do and some of the growth options available to them now are from assets they already have in their portfolio,” says Cormack.

“They are looking to expand those projects first, though mergers and acquisitions are definitely starting to come more into the conversation.”

Furthermore, rather than spending money on ambitious new projects or deals, companies are returning dividends to shareholders. BHP Billiton recently gave shareholders a dividend of 55 cents a share, up from 40 cents a year earlier. And in February, Rio Tinto, which has declared a 70% increase in annual profits, awarded its biggest dividend yet of $1.80 a share, taking its payout for 2017 to $2.90, beating its previous record of $2.15.

This is in stark contrast to the peak of the previous boom when the industry invested more than $900bn of shareholder money into new projects and deals, according to The Financial Times.

James Stevenson, senior director, global coal at IHS Markit, says the strong prices of the last 18 months would previously have seen heavy investment and possibly over production, with prices coming off slightly.

“We haven’t seen that this time because there is a behavioural change; producers are more risk-averse, only making investments when it is more justified. They have much less interest in being speculative,” he explains.

Furthermore, due to the sector’s inherent volatility, access to capital has become difficult and more expensive, especially for coal projects. As Cormack said, mining firms are looking inward instead at how they can maximise the potential of their current assets.

Mark Cutifani, chief executive of Anglo American, told the FT Commodities Global Summit in Lausanne in March that the company has to improve its existing assets first.

“We’re allergic to those types of risks today,” he said, “but at the same time we’ve got to be careful we don’t become gun shy either. We’re just trying to get the balance right.”

This is a good strategy, Stevenson agrees, as “it reduces the risk of over investment, as the best cure for hire prices is high prices”.

New-age commodities

Now, investments are increasingly being made in so-called ‘new-age minerals’: cobalt, copper, nickel and lithium.

“Big miners are putting their capex against commodities, projects and portfolios that are showing good long-term prospects but, more specifically, we are seeing the emergence of the ‘battery minerals’ and the ‘new-age minerals’ needed for the technology of the future,” says Cormack. “Some exploration companies have completely switched from more traditional commodities to these newer ones.”

Lithium, for example, is now one of the world’s fastest growing commodities due to the demand for Li-ion batteries. According to Chile’s largest lithium producer, SQM, the mineral’s growth rate is at 20%. In March, the company said its net income had reached $428m, an increase of more than 50% of the $278m  the year before.

Cobalt is also garnering a lot of interest due to its scarcity but necessity in batteries for electric vehicles. According to figures from the London Metal Exchange, the price of cobalt has made a 22% gain already this year and a 250% gain since early 2017.

Furthermore, data from Mining Intelligence shows that worldwide cobalt drilling activity quadrupled in Q4 2017, accounting for 50% of total activity of battery materials worldwide.

Industry culture change

As time goes on and prices remain buoyant, as they are broadly expected to, could miners suffer a memory lapse and fall back into bad habits?

“They might,” says Cormack, “but probably not to the same extent.” This is because beyond fiscal prudence there are other factors at play in the mining sector today.

“The sustainability agenda has advanced in leaps and bounds,” he continues, “companies are now being sincere about how they carry out their operations.

“I think this is a very exciting time to be in the industry, there are some lessons learned from the past and mining firms have taken this on board and not only restructured their operations but the way they approach things.”

This is as far reaching, he says, as mining firms working towards greater diversity of their boards for better scrutiny and delivery of shareholder value, investments in innovation, automation and technology, as well as looking to learn lessons from other sectors, including the automotive and agriculture.

“We are seeing a huge interest and traction on how to use technology to optimise more effectively and efficiently and to future-proof companies against potential commodity downturns,” he adds.

Though this is less prevalent in coal mining, according to Stevenson. “We haven’t seen a lot of remote operations and AI in the coal space for varied reasons,” he says, “but the biggest being that we are still coming out of a time where there was no money to spend and technology still requires an upfront cost”.

This new interest in doing things differently has also extended to local community engagement and environmental responsibility, says McCormack, with companies looking at options such as in-situ excavation to minimise their impact.

It seems that, after a tumultuous period of low commodity prices and high public scrutiny, many mining firms are focused on understanding how to manage their key risks – commodity prices, permitting, access to capital and social licence to operate – in a more sustainable way to avoid, among other things, reputational damage and financial loss.

An even bigger light-bulb moment is happening for utilities and automakers, who want to use the batteries in electric cars as storage for the entire public power grid. The idea, known as “vehicle-to-grid,” is to someday have millions of drivers become mini electricity traders, charging up when rates are cheap and pumping energy back into the grid during peak hours or when the sun simply isn’t shining. If it works – and it’s a big if – renewable energy could get much cheaper and more widely used.

“We really, really need storage in order to make better use of wind and solar power, and electric cars could provide it,’’ said Daniel Brenden, an analyst who studies the electricity market at BMI Research in London. “The potential is so huge.’’

Future

Today, fewer than one per cent of the world’s vehicles are electric, but by 2040 more than half of all new cars will run on the same juice as televisions, computers and hair dryers, according to estimates by Bloomberg New Energy Finance. Once cars and everything else are fed from the same source, they can share the same plumbing.

As it stands, energy generated by wind and solar farms often goes to waste because there’s nowhere to store it. South Australia solved the problem by investing an estimated $80 million to $90 million to build the world’s biggest lithium ion battery on the edge of the Outback. The result is a massive cluster of white boxes that is essentially a huge reservoir for electricity. Inside are the same batteries Tesla Inc. uses in its cars.

But what if that reservoir was divided between millions of cars already on the road? That’s the vehicle-to-grid concept.

It’s promising because the newest electric vehicles can hold enough energy to power the average US home for several days. For most drivers, whose cars sit idle 90 per cent of the time, sharing their batteries would make good use of a very under-utilised resource. (It’s like Airbnb, but with car parts instead of seldom-used apartments.) For the utilities, borrowing people’s batteries would mean not having to build or buy them.

Sounds awesome.

In the real world, though, there’s a tangle of complications. Elaborate new computer networks would have to be built, carmakers and power companies would have to collaborate, and people would have to stop thinking of their cars as a private bubble. The main practical problem is getting drivers to charge up when there’s a power surplus, and getting them to give back when the public grid has a deficit, all the while making sure people’s cars never run out of juice.

To get a sense of the difficulties, consider the struggle the world’s No 1 seller of electric cars, Nissan Motor Co, has had convincing customers in Japan to try a simple system like the one Maguire jerry-rigged for himself at his home in the Irish countryside.

Cut utility bills

By allowing car batteries to serve as a residential power source, Nissan says its vehicle-to-home service cuts utility bills by about $40 per month. Still, only about 7,000 car owners have adopted the system in the six years since it started, a tiny number compared with the 81,500 Leaf EVs that Nissan has sold so far in the country. Declining to discuss any travails, a spokesman said the company is “very pleased” with its sales and sees growing consumer interest in the technology.

For Maguire, the rural inventor, one thing that’s become clear is that car batteries can be a lot more useful than most people think. His latest challenge is seeing whether he can convert his diesel-guzzling BMW sedan into an electric car on a shoestring budget of less than €1,000, or about $1,250.

“I joke that one day I’m going to finish up these projects and take up golf,” he said. “But the more I learn about these batteries, the more I try and the more I get out of them.’’