Battery Metals Outlook
Bloomberg special report
Just a few short years ago, cellphone sales figures had the power to send jitters though battery metal markets. Today, with annual electric vehicle (EV) sales expected to reach 28 times their current magnitude by 2040 — and each vehicle using more than 10,000 times the lithium of a handheld device — the markets are finding themselves sitting atop very different tectonics.
The booming EV sector has turned battery technology into one of the fastest-growing arenas of modern innovation. The race is on for the most efficient cathode chemistries, and much of the industry is focusing on high-nickel approaches as a way to increase battery density. By 2030, this quest for economy is set to drive a thirteen-fold increase in battery-nickel demand, with an interim deficit through 2024.
Still, with clear leaders yet to stand out in the nascent EV marketplace, the advantages of near-term battery production capacity may trump emphasis on optimally energy-efficient or space-saving chemistry. Getting a brand on the road, after all, is crucial for EV manufacturers looking to claim market share. The battery technologies used by the biggest players are likely to dictate standards for the rest of the industry.
For battery makers, availability and price of raw materials are chief considerations. Maintaining the balance between cost, competitiveness and creativity will affect which metals they are able and willing to build into their products. In the coming years, a key variable in this area will be the disparity between metal supplier nameplate capacity and actual ability to deliver.
Geopolitical uncertainty in Africa is affecting global cobalt availability, as lithium faces technical challenges and the supply of battery-grade nickel hinges on the success of new projects in Indonesia. Meanwhile, storage technologies in the green energy sphere are driving an increase in the use of vanadium — a metal with 10,000 times the abundance of lithium. Although currently too costly to be a threat to the Li-ion paradigm, it may not stay that way for long.
Drawing on insights from our Bloomberg Intelligence and BloombergNEF (BNEF) teams, this report covers the most important issues affecting battery metals markets — today and in the future. Read on to find out more.
Lithium producers need volume and new technology to get ahead
By Yi Zhu and Anthony Cham Fung Yau, Bloomberg Intelligence
Lithium producers could increase production volume or apply new technology to maintain revenue and margins as prices fall.
Signing long-term supply contracts with downstream users at set prices will help hedge against the price declines and keep revenue stable. Applying new technology in the extraction process will save production time and reduce unit costs, cushioning price falls and reserving margins. The lithium carbonate price has corrected 40% as of end-April from a peak at the end of October 2017, after jumping threefold since the beginning of 2015.
Major lithium producers such as Albemarle, SQM, Tianqi Lithium, Ganfeng Lithium and Livent are all vying for a bigger market share by acquiring lithium mine assets, developing new extraction methods and engaging in long-term offtake agreements with downstream customers.
Lithium producers lock in long-term supply to stabilize revenue
Lithium producers with rising output including Ganfeng Lithium are seeking long-term supply contracts with downstream clients to ensure stable demand, and setting periodic contract prices to hedge against short-term volatility. Boosting sales volume has helped counter falling prices since last year, stabilizing revenue.
Growing sales volumes to cushion price falls
Lithium producers are likely to increase sales volumes amid falling prices to keep revenue stable. With rising supply pressuring prices, signing long-term contracts with downstream users could help producers maintain or increase market share, boosting sales volume. Downstream users, in turn, would prefer a secure supply of raw materials, which are in strong demand due to the booming battery industry.
Major lithium users have signed long-term agreements for raw materials, such as LG Chem's five-year contracts with Nemaska Lithium and Ganfeng Lithium, and Posco's life-of-mine agreement with Pilbara Minerals.
Ganfeng likely to hunt more offtake agreements
Ganfeng Lithium will likely continue to seek more long-term sales contracts with downstream clients as it ramps up production, with output jumping 114% in the past four years. It has signed long-term supply contracts with major battery producer LG Chem and automakers such as Tesla, BMW and Volkswagen. Ganfeng produced 42,298 tons of LCE (lithium carbonate equivalent) in 2018, up 16% from a year earlier. As its joint venture with Pilbara Minerals ramps up at Pilgangoora, Western Australia, which was commissioned in 2H18, Ganfeng's output will continue to climb, allowing it to sign new contracts with more clients.
Ganfeng is the second-largest lithium producer in China in terms of revenue, following Tianqi Lithium. The company signed a 10-year contract in early April with Volkswagen to supply lithium products.
Lithium all about volume amid price fall
It will be a volume game for lithium producers going forward, as the metal's price weakness will likely continue. Revenue of lithium producers that fail to ramp up production could be hurt, as lithium prices have corrected since early 2018 due to rising industry supply. Booming demand from the battery industry drove up lithium prices in 2015-17. That spurred lithium miners to quickly increase output through commissioning new mines or expanding brownfield production. Lithium output will continue to rise in 2019 as new capacity comes online, pressuring prices. Producers with flat output growth will lose market share and see revenue fall.
Average prices of lithium carbonate and hydroxide fell 35% and 23%, respectively, in 1Q from a year earlier.
Tianqi, Ganfeng can gain lithium share with new technologies
Chinese lithium producers such as Tianqi and Ganfeng can gain market share by buying extraction technologies to reduce unit costs. New methods to extract lithium ore shortens the processing time from brine to concentrate and increase efficiency. Posco's technology can reduce production time by 12 times.
New technology may shake up global market
New extraction technology, if applied by Chinese lithium producers, could boost output and shake up the global market. China's major lithium producers Tianqi Lithium and Ganfeng Lithium only manufacture lithium vs. global peers such as Albemarle and SQM which are chemical producers and are more aggressive using new technology to increase output and reduce costs due to their 100% exposure to a single metal.
Assuming Chinese players increase their output by 3 times by purchasing technical know-how from third-parties such as Posco, they could lift their global market share to 43%, from the current 20%.
Posco's PosLX technology could cut production time to between 8 hours and 1 month from 12-18 months. Rincon's Direct Xtraction Process technology can process lithium carbonate within 24 hours.
Advanced technology owners gain market share
The most-efficient lithium producers, who can process brine to concentrate fastest, can increase production volume and reduce unit costs, preserving margin amid falling lithium prices. Extraction technologies such as Posco Lithium Extraction (PosLX) developed by the Korea's largest steelmaker would shorten processing time significantly, by 12 times. Producers with advanced technology can gain market share, and ensure operating stability vs. miners who rely on third-party technical expertise.
Posco is an integrated lithium producer from mining to battery cathode manufacturing. It owns brine pools in Argentina and has signed offtake purchase agreements with Australian lithium miners.
Chinese lithium share to rise in 2020 as supplies normalize
By Sophie Lu, BloombergNEF
Lithium miners put brakes on 2019 capacity expansion.
The previously anticipated 'tsunami' of lithium supply may not materialize as miners pullback on new capacity additions in the face of mounting technical and regulatory challenges, as well as shortfalls in financing.
Lithium production capacity can reach 424,000 metric tons lithium carbonate equivalent (LCE) this year, according to BloombergNEF forecasts. That is only a 5 percent increase over 2018, and significantly lower than the estimated 227,000 metric tons LCE of new nameplate capacity that was to be commissioned, as per the announcements of lithium producers. BNEF forecasts global lithium demand to reach 430,000 metric tons LCE by 2020. The global lithium market will be comfortably supplied through 2020. After 2021, producers have significant flexibility to accelerate or delay new capacity additions to support lithium prices.
BloombergNEF global lithium supply and demand forecast
Chinese lithium miners target doubling of capacity by 2020.
Tianqi Lithium Corp. and Ganfeng Lithium Co. are the most visible Chinese lithium producers, controlling 4.6 percent and 7.4 percent of the global mined lithium market respectively in 2018. However, most of their lithium resource holdings are overseas, not in China.
China is the third largest producer of mined lithium, according to the U.S. Geological Survey. Producers whose lithium resources are primarily located in China include Qinghai Salt Lake Lanke, partially owned by BYD Co., Western Mining Group and CITIC Guoan Co. Ltd., which controls the largest lithium mine already in production in China. Driven by government backed research and development, and cheap capital, producers in China target a doubling of capacity by 2020. If successful, they could increase China's share of global lithium mine capacity to 15 percent.
Producer controlled lithium mine nameplate capacity by 2020
Vanadium batteries to ride price spike, fight lithium
By Iain Wilson, BloombergNEF
Vanadium pentoxide surged from January 2016-December 2018.
Flow batteries based on vanadium will increasingly challenge lithium-ion technology as developers look for storage systems to back up wind and solar projects and support the grid –- despite a 10-fold spike in the cost of the silvery-gray transition metal late last year.
So said Stefan Schauss, president of Canada-based CellCube Energy Storage Systems Inc., in an interview with BloombergNEF. CellCube, capitalized at $11 million, is one of a number of companies manufacturing vanadium flow batteries. Supporters argue these have safety, recycling and scalability advantages over lithium-based storage systems.
However, vanadium batteries face market skepticism. BNEF’s latest storage market outlook, published in January, predicted that lithium-ion accounted for 85 percent of storage project capacity commissioned in 2018, and would “remain the preferred technology”. It added: “The majority of providers of alternative technologies remain too early-stage, unable to deliver at the scale required by major developers and utilities, and unbankable.”
The cost issue for vanadium batteries has been in the spotlight recently, with a 10-fold surge in the price of European-traded vanadium pentoxide from June 2016 to December 2018, when it hit a high of $28.75 a pound (see chart below). Prices have since returned to about $17 a pound. Steelmaking currently accounts for the great bulk of industrial demand for vanadium, and the price spike happened after China mandated more of the metal be used in steel rebar.
Schauss told BNEF that vanadium supply issues would not stand in the way of the growth of flow batteries: “Vanadium is abundant in the Earth’s crust. It’s 10,000 times more available than lithium as a prime element for batteries.” He added: “Any price development or long-term anticipated shortage will probably be leveled out by other sources of vanadium coming online.”
In January, CellCube announced a partnership with Immersa Ltd. to deliver large-scale vanadium redox flow battery systems for the U.K. Also in January, the company announced energy storage sales to Germany and the Czech Republic -- a combined 250kW/1.1MWh for the two systems valued at more than $1 million.
BNEF spoke to CellCube’s Schauss about the outlook for the battery technology. The following is an edited transcript.
Q: Can you describe what a vanadium redox flow battery is and how it differs from a lithium-ion battery?
A: A flow battery works by storing electrical charges in a large reservoir of fluids. In order to do so, you’re using a charge conversion cell stack that is equivalent to battery poles. The conversion cells convert the energy from electricity into a chemical-bound energy and vice versa. Pumping all fluid through the conversion cells allows the fluid to charge or discharge the battery entirely.
Q: What are the advantages to this approach?
A: There are two key advantages. The first is that you can basically scale the rated power of the battery versus its energy capacity, which is unlike a lithium battery where you always have a pre-determined ratio between power and electricity. The advantage is that the fluid is the energy capacity. When you think of that, it’s really a physical capacity. When you extend the battery or you scale a long-duration battery as you add electrolyte or the fluid, it’s just in a tank so you pump more in. This way you can expand the system or determine the system right from the very start on a very large body on a very long-duration storage. The fluid is a fraction of the cost of what additional cells would cost.
The other advantage is that because you have two fluids physically separated in two tanks, you never have a cell discharge phenomenon and you never have a degradation of usage. In a lithium cell you have anodes and cathodes and through the liquid travelling between the anode and the cathode you are always chemically binding and ripping apart the binding based on the charge and discharge level. In that case, you have an entropic behavior that over time kills the capability of separating and recombining. In flow batteries, you don’t have that because you always have the same fluid. You don’t have a physical change in the fluid. You just add charges directly to whatever the carrier medium is.
Q: So you’re saying there is no degradation and there is an infinite number of charging cycles?
A: The pure substance never degrades. It’s just vanadium salts in water so it can’t decay in itself and it still has the same properties. We’re never changing the physical substance in the charge and discharge cycle and that is unlike other battery technology.
Q: Can you talk about the safety aspect?
A: We have to distinguish between the different lithium-ion technologies. The dominant model right now is anything with a nickel-manganese-cobalt type of cell. While this has an advantage on one hand, the chemistry has a certain property to incinerate when it is not treated right. Because of the way cells are built and the way overall the elements are working together, you have a certain danger you need to safeguard against.
With flow batteries, there’s primarily an advantage on a large scale because it does not display any thermal runaway behavior due to its water-soluble base.
Q: If vanadium flow batteries are to be accepted more in the market, do densities need to be improved?
A: The question is where you want to apply storage solutions. Applying it in a mobile environment like electric vehicles, then weight and density are major aspects in terms of the design. We see flow batteries for multiple-hour storage solutions in a stationary storage environment in very large scale. We’re only interested in applications where we’re talking a megawatt or above and most interested parties we’re talking with are working on schemes of 100 megawatts or more.
When you look at the footprint density you will see that vanadium redox flow batteries are pretty much in line with what lithium has.
Q: What is the ideal application then for this type of battery?
A: We see flow batteries in general for large-scale renewable generation co-location. That means large solar plants, large wind farms in the multi-megawatt range either mandated or as a desire to deliver a higher-quality power output to grid systems -- being on the distribution or transmission grid level, and providing additional capacity to the grid. The other aspect is to provide reserve or reserve capacity for grid operators in large scale. Again, we’re talking 10 megawatts up to 500 megawatts. Third, we see it in microgrid environments where there is no decentralized storage application.
This past summer we closed a deal for a system in Sweden, a 1.6 megawatt-hour system. It is a test bed for how a community microgrid might run. One hundred and fifty single-family homes that have pulled together to be powered out of renewables but also out of a central battery system.
Q: In terms of technology, lithium-ion seems to be favored at the moment. Flow hasn’t seen much pickup for the past couple of years. How does CellCube see this changing?
A: There is a common consensus building that lithium might be limited by its cost structure to solve the transition to a fully renewable power grid on the stationary energy storage side.
Pair that with some of the safety problems we are currently experiencing on global deployments of large-scale lithium cell-based installations as well as the recycling question, which remains unsolved to a large extent.
Flow batteries, for example, do not present any of these threats since they are inherently nonflammable or explosive and don’t have the recycling necessity. In flow batteries, the chemistry is undegradable and has an almost infinite life. Even when an end-of-life scenario for an individual deployed energy storage system is envisioned, the medium can be re-used.
Q: What geographies are you looking at?
A: We see North America, we see Europe coming up with a few exceptions. The Middle East is up and coming. We see Africa being developed and leaping a classical, conventional grid build out. We see Australia as a very strong market.
There are several jurisdictions or regions where large-scale energy storage is today. We’re getting inundated with requests for large-scale projects. Every week we get three more coming in.
Flow batteries, based on the chemistry and the economics and the sizing, work best for storage supplies of three hours or plus. The three- to four-hour mark is typically where we are butting heads in the market with lithium. Alternative technology always has to argue against the better economics or the better performances that you can achieve for the customer, but everything beyond four hours, a flow battery, and in particular our flow battery, we’re at a price point where we can definitely provide a cost advantage to any kind of project developer. We get a ton of requests and the project sizes are typically between 10 and 100 megawatts.
Q: At what price point do flow batteries become really attractive?
A: You see the need for storage not so much for the sake of storage but you see the need for storage either because there’s a higher demand at a point in time when wind is not available or there needs to be excess wind energy distributed because the demand side is requiring higher capacity on the grid. Typically, it’s a combination of how cheap the generated energy can be bought versus how expensive I can sell it for or what I can achieve on the market offtaking my stored energy. When you have an energy storage system that can reliably dispatch into the market at any given time, this is a higher quality of electricity than when it’s unpredictable or only partially predictable.
So the question is at what level it makes sense. We have storage solutions from four hours onwards that, because of our long life and non-degradation in capacity, we’re getting resulting LCOS [levelized cost of storage] 3 cents to 6 cents per kilowatt hour or $30 to $60 per megawatt hour on stored energy when delivering power to the grid. Adding the combination of low-cost generated power and the combination of energy delivery rivals competitive power pricing at peak times, and hence displays a valid business case for putting storage in the mix.
Q: The price of vanadium pentoxide flake saw a huge spike in October and November last year. What drove the spike and does it concern you?
Europe-traded vanadium pentoxide (98% V205)
A: The peak we saw last year was primarily driven by the mandate that the Chinese government put in to increase the content of vanadium in rebar. With a slightly slowing economy, it has already been indicated that the consumption is not that much higher. The vanadium producers [have coped], and an increase in production has taken place. Vanadium is abundant in the Earth’s crust. It’s 10,000 times more available than lithium as a prime element for batteries. Any price
development or long-term anticipated shortage will probably be leveled out by other sources of vanadium coming online.
In the short term, we’re buying vanadium from producers on the open market. However, we have long-term agreements that we had even before the spike so that we see a subdued rate on vanadium going forward.
Battery-grade nickel may face deficit by 2024
By Kwasi Ampofo, BloombergNEF
Batteries currently consume 54,000 metric tons of nickel.
Five percent of demand for the very pure so-called class-1 nickel comes from batteries, but BloombergNEF forecasts this will increase to over 40 percent by 2025. Some class-1 demand from the stainless-steel industry can be switched to less pure class-2 as new ferronickel production comes on-line. This potential switch helps to alleviate short-term supply constraints. However, even with this flexibility, class-1 nickel supply is likely to run into a deficit by 2024.
Supply is currently dominated by the top ten players, including Vale SA, Jinchuan Group Co., Glencore Plc, BHP Group, Sumitomo Metal Mining Co., Anglo American Plc, MMC Norilsk Nickel PJSC and Eramet. Their combined supply in 2018 totaled over 900,000 metric tons of class-1 nickel, with potential to expand supply by an additional 150,000 tons by 2025.
Class 1 nickel supply and demand forecast
Tesla to switch
battery tech
By Kwasi Ampofo and James Frith, BloombergNEF
Future of Tesla batteries lies in Indonesia's nickel mines.
EV battery industry leaders including Tesla Inc., LG Chem Ltd., and BMW AG are shifting to high-nickel cathodes in order to increase battery density. As a result, BloombergNEF forecasts battery demand for nickel may increase ninefold by 2030.
Increasingly, the nickel needed to drive EV batteries will come from Indonesia, particularly through the application of high-pressure acid leaching (HPAL) technology, meant to produce battery-grade nickel sulfates from lower-grade laterite ores. Among the eight HPAL projects in operation around the world, half of the best performing Tier 1 and Tier 2 assets, are in Indonesia. Producers are developing six new HPAL projects that collectively can produce 220,000 metric tons of battery-grade refined nickel, and 70 percent of this capacity is being developed in Indonesia.
Upcoming battery-grade refined nickel capacity development
Tesla-CATL tie-up won't force switch in battery chemistry.
Chinese battery manufacturer Contemporary Amperex Technology Co. has been negotiating with Tesla Inc. to supply batteries for the automaker’s Chinese gigafactory. This has fueled debate over whether Tesla will switch to using lithium nickel-manganese-cobalt oxide, or so-called NMC, batteries instead of the lithium-nickel-cobalt-aluminum oxide, or NCA, cells for which it is known. A switch would have implications for metals demand.
The primary reason for this speculation is that CATL already produces NMC cells and does not produce NCA cells. Elon Musk confirmed that Tesla would have multiple cell suppliers for its Shanghai plant on the company’s first-quarter earnings call. Such a shift, however, is not a given, according to BloombergNEF’s analysis.
It is true that CATL already produces batteries of different chemistry types. It uses lithium-iron phosphate, or LFP, batteries for stationary storage and electric buses, but NMC for passenger EVs. Adding a new line to produce NCA for Tesla’s EVs would be relatively simple.
In addition, CATL has recently started producing NMC (811) cells, with eight parts nickel for every one part manganese and one part cobalt. These are as technically challenging to produce as NCA cells. This is because both cathode active materials are sensitive to moisture.
CATL therefore already has the required knowledge and technology to manufacture NCA cells.
Tesla also uses a form of NCA with a lower-than-normal cobalt content – five percent versus 14 percent, which BNEF refers to as NCA+. This is much lower than what its peers have been able to achieve and is the result of more than seven years of research and development. BNEF estimates that its cells also contain 50 percent less cobalt than NMC (811) cells. This reduces Tesla’s exposure to cobalt price volatility and it is unlikely that Tesla would be eager to abandon what is currently an important differentiator for the company.
A lower dependence on metal sourced from the Democratic Republic of Congo would also be beneficial from the perspective of sustainability. A heavy reliance on the D.R.C. continues to trouble automakers. German automaker Bayerische Motoren Werke AG, for example, has said it will source its cobalt from Australia and Morocco. If all automakers were to follow this path, especially if Tesla switched to NMC, the market would soon run out of non-D.R.C. supply.
Indeed, Tesla recently provided evidence of a credible route to going cobalt free in NCA, a goal Elon Musk has explicitly stated. This is something that hasn’t been achieved in the NMC family of cathodes.
As things stand, Tesla produces performance vehicles – even its cheapest EV, the standard range Model 3, can do 0-60 miles per hour in 5.6 seconds. NCA is better at providing high power, needed for this high performance, than NMC. If it were to make the switch it could sacrifice this performance.
And there is more to the supply chain. Panasonic doesn’t manufacture the NCA active material, this comes from a third-party material producer like BASF SE or Umicore SA. It is the relationship with the material producer that will truly determine what chemistry Tesla uses.
Global cobalt deficit risk rises with Glencore, ERG cuts
By Sophie Lu, BloombergNEF
Cuts announced in mines in Congo, world's largest producer.
Cobalt is increasingly at risk of supply deficit in 2019. Recently announced capacity cuts by Eurasian Resources Group Sarl (ERG) and Glencore in the Democratic Republic of Congo -- the world's largest producer -- could impact about 9,000 tons of mined output. BloombergNEF originally forecast global mined cobalt supply to be sufficient to meet demand of 156,000 tons this year. That looks unlikely now, unless new capacity comes up outside of Congo.
ERG announced on Feb. 19 plans to halt production at the Boss mine, as it assesses feasibility of new processing lines. Glencore also announced labor cuts (not yet production halts) at its Mutanda mine. Its Kamoto mine was suspended in a dispute with the Congolese government last month. Capable of producing up to 15,000 tons of cobalt, Kamoto had planned only 6,000 tons of output this year.
Democratic Republic of Congo's cobalt output by mine, 2019
