The discovery of the potential for thousands of tons of lithium to be extracted annually from wastewater generated by fracking in the Marcellus Shale leaves proponents of a green energy future at a crossroads, Republicans said Thursday.
A University of Pittsburgh study suggested processing byproducts from natural gas production in Pennsylvania’s Marcellus Shale basin could potentially meet nearly half of U.S. lithium needs. The typical electric vehicle (EV) requires nearly 18 pounds of lithium to power its battery. That figure grows exponentially for Teslas, according to reports.
Rep. Guy Reschenthaler, R-Pa., who represents much of the Marcellus territory, told Fox News he wants to see those on the left change their tune.
“Now nearly 40% of our nation’s domestic need for lithium can be found right here as a byproduct of fracking,” he said. “I fully expect every single Democrat to join Republicans in supporting domestic natural gas development.”
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“Fracking may provide the cleanest, most environmentally friendly way to produce natural gas energy and harvest the domestic lithium we need for the green future endorsed by my colleagues on the extreme left.”
Could this possibly get any funnier? If greens want to alleviate the Lithium crisis, to provide for their EV revolution, they need to support fracking natural gas in Pennsylvania’s Marcellus Shale region.
A slowdown in the growth of electric vehicle (EV) demand has led to entire mines being shut down as the supply of rare earth minerals essential for EV components exceeds demand, according to The Wall Street Journal.
Mines around the world are ceasing operations or halting construction projects in response to the falling demand, such as a $1.3 billion plant in North Carolina operated by Albemarle. which announced that it was deferring spending on the project amid the market turmoil, according to the WSJ The total market share of EVs rose from 3.1% in January 2023 to 3.6% in December 2023, while the share of U.S. vehicle inventory grew from 2.8% to 5.7% in that same time frame as demand fails to keep up with supply. (RELATED: California EV Sales Decline For First Time In A Decade As State Continues Green Push)
Over the last few years, global mineral producers have ramped up mining operations in an attempt to capitalize on the emerging EV market, but consumers have declined to adopt EVs at the rate producers were expecting, leading to rare minerals flooding the market and driving down prices, according to the WSJ. The market for metals is often subject to boom-and-bust cycles due to unpredictable demand and the slow speed at which mines can be brought into operation.
The price of lithium is down around 90% since the beginning of last year, and the price of nickel has been cut in half in that same time frame, according to the WSJ. A mine on the French Pacific island of New Caledonia recently suspended operations, despite providing more than 6% of the world’s nickel supply.
A scramble to secure strategic minerals such as copper, cobalt, lithium, and nickel could increase price pressures and raise the cost of the climate transition, IMF economists write in the latest issue of F&D. https://t.co/X72oppqbAepic.twitter.com/hoqLoenEdb
The decline in mineral demand is particularly dire to the Australian mining industry and economy in general, with the country’s government recently designating nickel as a critical mineral to give corporations access to government grants in order to provide some stimulus to struggling companies, according to the WSJ. The collapse of mineral prices has led to a loss of more than one-fifth of Australia’s mine supply.
China controls around 87% of the world’s rare earth mineral refining capacity, leading the U.S. to attempt to subsidize projects outside of China to secure access to the resources. The Biden administration has included provisions in EV tax credits that require a certain percentage of minerals not to be from a foreign entity of concern like China to be eligible.
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The riddle of unhinged EU support for the Zelensky regime in Kyiv is now solved. Anyone inclined can unravel why the Germans, in particular, backstabbed Russia in the Minsk peace boondoggle. Lithium.
Energy Monitor’s parent company, GlobalData, recently released a report showing that Europe’s biggest lithium reserves lie in the Donbass region of Russia. The former Ukrainian Shevchenkivske field in the Donetsk region and the Kruta Balka block in the Zaporizhzhia region are now part of Russia. These reserves add tremendously to Russia’s humongous Lithium deposits (now 1.5M metric tons) and solidify the country’s top ten position globally. If we consider other BRICS nations’ reserves, including China (2M metric tons), EU industry is at a leverage point.
What’s most significant about this is that the EU, and Germany in particular, desperately need the rare mineral to manufacture green energy technologies such as wind turbines, electric vehicles, and a wide variety of electronic devices. This text from the Critical Minerals Thematic Intelligence Report overview is telling:
“Critical minerals are key to transitioning to a low-carbon world. There are over 70 countries globally that have set net-zero targets and pledged to lower their emissions. However, these widespread measures for a greener future are straining natural resources, especially the minerals required to produce energy transition technologies such as electric vehicles (EVs) and solar panels…”
The report goes on to reveal how these rare minerals are monopolized by just a few regions and how supply chain problems affect their recovery and distribution. In short, if Europe does not procure more Lithium, the energy transition EU President Ursula von der Leyen toots her horn about every other day will either be delayed or made unfeasible because of demand shortages.
While the United States, Australia, and a few Latin American countries hold the lion’s share of Lithium reserves, EU access to these supplies will be expensive. In addition, the U.S. and these emerging nations will surely use the biggest part of their reserves for domestic needs.
The demand (need) for European Lithium supply is so intense, German CDU MP Roderich Kiesewetter came right out and admitted the Russia-Ukraine conflict is all about the 500,000 tons or more of the mineral under the ground of the Donbass region. Kiesewetter said, “The European Union supports Ukraine because of lithium deposits in the Donbass.” The politician also took note of the Donbass being part of Russia now, means Berlin’s dependence on Moscow.
Kiesewetter, a retired colonel, is also suggesting that Germany provide Zelensky’s regime with the highly accurate Taurus cruise missiles, which have a 500km range. The Swedish/German air-launched missile carries a 1,100-pound warhead and is essentially a bunker-buster type weapon. The missiles would be far more useful for Zelensky’s remaining Nazi battalions than a few rusty old Leopard tanks. What the MP’s statements mean, however, is that Germany and the EU intend on taking Ukraine’s vast resources by force now. The Euromaidan Coup only got the Western elites’ feet in the door, and now the singular order has few options left since the failed Ukraine offensive.
The EU commissars are in the process of slitting their own throats. Just the other day, the commission passed another round of sanctions aimed at Russia’s luxury diamond exports to the bloc. This will not affect the average EU citizen, but the upper-middle class and the wealthy will have to fork over more Euros to get pretty round diamonds. The Americans (or British) blowing up the gas pipelines, the potential for grain shortages in the EU, and other key minerals Russia and nations friendly to her export begin to take their toll on an already shaky confederation of member states.
Consider what EU member states manufacture and export to elevate their GNP. In the lists here, you’ll click on two vital exports. Cars and/or refined petroleum are vital to every country. Cars are, by far, the biggest import and export commodities. So, when these autos finally go electric, just imagine how desperate EU industry and consumers will be for Lithium! The Europeans will flounder if forced to import quantities of this strategic mineral from distant sources that have their own batteries to make. If there is a WWIII over the Russia/Ukraine situation, I am sure we’ll be able to name it “The Great Lithium War.”
Phil Butler, is a policy investigator and analyst, a political scientist and expert on Eastern Europe, he’s an author of the recent bestseller “Putin’s Praetorians” and other books. He writes exclusively for the online magazine “New Eastern Outlook”.
Lithium prices are down lately, and EV manufacturers, the major users of Lithium, have recently announced substantial cuts to production. So why are Lithium miners so optimistic?
Electric Vehicles Are Stuck In A Lull. What That Means For Tesla, Other EV Stocks And EV Battery Manufacturing.
The transition from internal combustion engines to electric vehicles was never going to be easy. But the gradual arrival of battery-powered cars drove sprawling plans to make EVs and EV batteries in the U.S., with companies like Tesla (TSLA), Ford Motor (F) and General Motors (GM) leading the charge.
Federal funding combined with geopolitical and climate concerns to expand the promise of industry growth for EV stocks and the so-called battery belt taking shape across the U.S. and beyond. The hope was to strengthen the Achilles’ heel of the nation’s electric vehicles boom: its reliance on batteries and critical minerals from abroad, especially China.
But consumer enthusiasm for electric cars has recently lost some of its charge, with Tesla, Ford, GM and Rivian Automotive (RIVN) among those turning cautious and scaling back, among other things, their battery manufacturing plans. Now analysts and executives are reading the data and the tea leaves, trying to determine whether the vibrant outlook for EVs and battery manufacturing is paused, broken or evolving into something new entirely.
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“Automakers are losing tens of thousands of dollars for each electric vehicle sold,” said CFRA equity analyst Garrett Nelson. “Something had to give, and it has given.”
Lithium prices crashed in 2023, but these figures show white gold is still the market’s biggest bet
Lithium prices have tumbled in 2023, but new data shows the money men continue to bet on the battery metal
BDO’s Sherif Andrawes says financiers and punters are looking at long term demand for lithium by backing equity and debt raisings in the metal ahead of traditional stayers like gold
Weak IPO market and falling cash balances should see even more lithium and gold M&A in 2024
As gold prices picked up steam and lithium prices began to crash, the flow of money into ASX explorers ran the opposite direction in a sign investors continue to view lithium as the commodity of the future.
Oversupply in China and the consequences of a small, volatile market have seen spodumene concentrate prices fall to a little over US$1000/t, just 12 months after rising to upwards of US$8000/t in an unprecedented bull run.
Chemical prices have fallen from around US$80,000/t to a little over US$15,000/t in the same time.
The fall has revived memories of the bear market from 2018 to early 2020, when against many industry projections, but inline with the warnings of some investment banks like Morgan Stanley, spodumene prices fell to around US$500/t and only the strong survived.
…
BDO’s head of global natural resources Sherif Andrawes said investors continued to punt on a massive uptick in electric vehicle demand going forward.
“There is a long term view that even despite the short term prices coming down and a lot of volatility in the lithium price, the long term demand for lithium will be there,” he told Stockhead.
It might be because they think politicians are still in their corner.
But the politicians have been slow to inflict promised EV mandates on voters, in what promises to be a difficult election cycle for Net Zero aligned politicians – so slow that EV manufacturers are starting to complain.
Ford UK says any delay on government petrol car ban risks EV transition
Reuters
September 20, 20239:30 PM GMT+10 Updated 3 days ago
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Ford said dropping the [British] 2030 deadline would be a mistake, and hinted it could put further investments at risk.
“The UK 2030 target is a vital catalyst to accelerate Ford into a cleaner future,” Ford UK chair Lisa Brankin said in a statement on Wednesday.
“Our business needs three things from the UK government: ambition, commitment and consistency. A relaxation of 2030 would undermine all three.”
For starters I don’t think Lithium is going away forever. Even if current generation EVs turn out to be a bust, as seems increasingly likely, there really is no substitute for Lithium when it comes to batteries. The nearest relative to Lithium (atomic weight 7) is Sodium (atomic weight 23). But Sodium on an atom for atom basis is 23 / 7 = 3x heavier than Lithium. So in any application where weight is important, Sodium has a huge disadvantage compared to Lithium.
Having said this there are alternatives to batteries, which might one day supplant Lithium batteries – so there is no absolute guarantee Lithium batteries are the future.
For vehicles, the distress of EV manufacturers is creating an opportunity for hydrogen and ammonia fuel proponents. Even laptops may one day be powered by fuel cells rather than batteries. And there is the ever present possibility of a supercapacitor nanotech breakthrough which could upset everyone’s apple cart.
Frankly I find the green alternatives to EVs scarier than EVs. When an EV catches fire you usually have a chance to get out, a few seconds between smoke and deadly fire. But ammonia can kill you on contact, it chemically attacks and burns any flesh it touches. And hydrogen is horrifyingly explosive and flammable – as residents of Bakersfield discovered in July this year.
As for supercapacitors – anyone who has seen an old style TV fail with a bang has witnessed a small scale capacitor dielectric failure. Imagine that scaled up million times, and you get the idea of why I’m going to let someone else drive the first supercapacitor EVs.
Given I think “green” alternatives to EVs are even worse, am I saying EVs are the future?
The answer, for now at least, is no.
Consumers are clearly voting with their wallets, rejecting EVs, leaving them on the dealer lots. And politicians are caving in to demands from voters to extend the deadline for phasing out gasoline vehicles.
Barring an unexpected range, price and reliability breakthrough, I can’t help thinking the Lithium bulls could be in for a long wait, to realise a return on their investments.
Update (EW): Added a quote from the first article “Automakers are losing tens of thousands of dollars for each electric vehicle sold…”
Greenpeace International activists paint the word ‘RISK!’ on the starboard side of Normand Energy, a vessel chartered by the Belgian company Global Sea Mineral Resources (GSR).
The Rainbow Warrior is bearing witness to equipment tests carried out by GSR using the Patania II nodule collector, at approximately 4500 metres deep in the Clarion Clipperton Zone. The mining company is aiming to commercially extract minerals from the seabed in the future.
The Greenpeace ship is in the Clarion Clipperton Zone in the Pacific to bear witness to the deep sea mining industry. Part of the ongoing ‘Protect the Oceans’ campaign.
Environmentalists have warned deep sea mining could be “catastrophic” for the vast and little understood habitat, which holds minerals needed for green technologies.
The UK has for the first time come out in support of a pause in highly controversial mining of the deep sea bed, having previously supported it, reports Sky News.
On Monday, the government added its name to a group of countries seeking a moratorium on new licences to exploit minerals such as lithium, copper and cobalt – vital for green energy – from the deep sea.
The environment department said the precautionary pause is designed to protect the world’s ocean from such projects, which involve heavy machinery scraping deposits from the world’s largest habitat, until more evidence on the impact is available.
It said it would establish a new UK-based network of experts to collect further scientific data.
Components of a subsea mining machine pictured in 2014
Environment Secretary Therese Coffey said the UK will use “our scientific expertise to fully understand the impact of deep sea mining on precious ecosystems; and in the meantime, we will not support or sponsor any exploitation licences”.
The announcement comes as negotiations at the United Nations regulator, the International Seabed Authority, start on Monday, and take place one month before the COP28 climate talks commence in Dubai in December.
Previously, Prime Minister Rishi Sunak’s government had been in favour of exploratory licences, a position criticised by Labour and dozens of scientists.
Other than from a few small tests, no commercial mining has happened at scale yet, and campaigners say it will be extremely destructive, with full environmental impacts hard to predict.
But deep sea mining is regarded as a potential solution to the expected global shortage of raw materials considered critical to a greener energy future, and used in things like batteries and renewable power.
It is also seen as a way to reduce dependence on the relatively few countries that hold deposits on land, including China, Australia, Russia, South Africa and Zimbabwe.
Ronald Stein is an engineer, senior policy advisor on energy literacy for the Heartland Institute and CFACT, and co-author of the Pulitzer Prize nominated book “Clean Energy Exploitations.”
Global cobalt demand soared with the advent of cell phones and laptop computers. Cobalt improves battery performance, extends driving range and reduces fire risks. Now, cobalt, lithium, and other materials are exploding with the arrival of electric vehicles in tandem with government EV mandates and subsidies.
All that electrical transformation equipment will require billions of tons of cobalt, lithium, copper, nickel, graphite, iron, aluminum, rare earths, and other raw materials at scales unprecedented in human history. That will necessitate mining, ore processing, manufacturing, land disruption and pollution at equally unprecedented levels.
The Administration is laser-focused on ending the “climate crisis” by switching to “clean” electricity. It has few qualms about importing the critically needed materials from foreign countries, primarily China – regardless of economic, defense, national security, ecological or human rights implications. It just wants the dirty aspects of “clean” electricity far away and out of sight.
Cobalt mining involves unimaginable horrors that are never discussed by environmentalists nor by government leaders. However, the Biden Administration opposes mining in the United States even under stringent US pollution, workplace safety and mined-land reclamation regulations.
An educational and entertaining 45-minute discussion between Stu Turley of Sandstone Media’s Energy News Beat and Ronald Stein about “Clean Energy Exploitations” brings transparency to the humanity exploitations and environmental degradation in the developing countries that are mining for the exotic minerals and metals required to create the batteries needed to store “green electricity”. Just a few minutes into the video I provide an explanation of the exploitations that should be considered in the buying process for an EV that should be viewed by all environmentalists and government leaders.
We hear much about reparations for descendants of American slaves, but little about reparations for Native Americans, and zilch about compensating these modern-day slaves in developing countries like those in the Democratic Republic of Congo in Africa that holds 72 percent of the world’s known supplies of cobalt.
With demographics of EV owners predominantly middle-aged white men earning more than $100,000 per year, Social Security shows that the national average wage index for 2021 is only $60,575 ($40,000 less than the average EV owner). US News recently reported that more than 60 percent of adults are living from paycheck to paycheck and that 48 percent of Americans with annual incomes over $100,000 are also living paycheck to paycheck. As U.S. consumers struggle to afford their day-to-day lifestyle, many are relying on credit cards or dipping into savings, making them financially vulnerable.
Besides the affordability of ANY new car, ICE or EV, is it ethical and morally responsible to purchase an EV knowing where the supply chain of EV battery materials originates?
Those that are less fortunate in poorer developing countries are the ones mining for exotic minerals and metals to support the movement in wealthy countries to EV’s and intermittent electricity from wind and solar.
The wealthy country elites continue to demonstrate their lack of ethical, moral, and social responsibilities, by using subsidies that encourage the continued exploitations of people with yellow, brown, and black skin and the environmental degradation occurring “elsewhere”, out of view of those living in wealthy countries.
No one can really say whether widespread adoption of EVs will cut carbon emissions.
A dozen states have joined California and many countries in passing legislation to ban the sale of conventional cars and push everyone into electric vehicles (EVs), many within the decade. Similarly, in a feat of regulatory legerdemain, the U.S. Environmental Protection Agency has proposed emissions rules that would effectively require automakers to sell mostly EVs. And of course, the ill-named Inflation Reduction Act, a.k.a. the Green New Deal, gushes subsidies across the EV ecosystem.
The rush to subsidize and mandate EVs is animated by a fatal conceit: the assumption that they will radically reduce CO2 emissions. That assumption is embedded orthodoxy not just among green pundits and administrators of the regulatory state but also among EV critics, who take issue with a forced transition mainly on grounds of lost freedoms, costs, and market distortions.
But the truth is, because of the nature of uncertainties in global industrial ecosystems, no one really knows how much widespread adoption of EVs could reduce emissions, or whether they might even increase them. (And no, this has nothing to do with the truth / joke that Teslas are coal-fired when fueled at night in many places.) While grid realities will indeed matter more than most realize, the relevant and surprising emissions wildcard comes from the gargantuan, energy-hungry processes needed to make EV batteries. This is one of those technical issues that tends to attract slogans, simplifications, and illusions of accuracy; a better understanding requires some patience.
EV emissions realities start with physics. To match the energy stored in one pound of oil requires 15 pounds of lithium battery, which in turn entails digging up about 7,000 pounds of rock and dirt to get the minerals needed—lithium, graphite, copper, nickel, aluminum, zinc, neodymium, manganese, and so on. Thus, fabricating a typical, single half-ton EV battery requires mining and processing about 250 tons of materials. (These figures hold roughly true for all lithium chemistries.) For the carbon-counters tracking such things, the global mining and minerals sector uses 40 percent of all industrial energy—dominated by oil, coal, and natural gas—and that’s before we take into consideration the massive expansion that would be required to supply all the battery factories planned for widespread EV adoption.
The inherent uncertainties about calculating real-world EV emissions arise from myriad “known unknowns” about mining and refining activities. Those all happen elsewhere, upstream, before assembly at a battery or EV factory—that is, before the first mile driven on a grid-supplied kilowatt-hour. Of course, a conventional car also has upstream emissions, though these derive mainly from steel and iron, which account for 85 percent of its weight. For conventional cars, those upstream emissions are a minor factor; burning gasoline dominates the CO2 footprint. But the need for far more materials, and different types, dominates an EV’s total footprint. Production of those metals, such as copper, nickel, and aluminum, uses on average three to ten times more energy per pound than does steel production. All the other EV minerals are similarly energy-intense.
The International Energy Agency (IEA) flagged these realities in a 2021 report. While that report focused on the inadequacy of the supplies of “energy minerals” (something that has since, finally, become widely known), the researchers noted that upstream CO2 emissions from fabricating an EV can “vary considerably across companies and regions.” Indeed. Changing the source of copper or nickel, for example, can lead to doubling or more than tripling those metals’ emissions intensities, depending on a facility’s age, process types, and locations. Building an EV requires several hundred more pounds of copper than building an internal-combustion car.
Assumptions about aluminum matter too, because EVs also typically require several hundred pounds more of that material, and two-thirds of global aluminum production comes from coal-fired grids in China, Russia, and India. (The U.S. produces just 2 percent.) In general, refineries in China, which account for 50 percent to 80 percent of global “energy minerals” supply, have emissions 1.5 times greater than those in the European Union or U.S.
A review of dozens of studies of upstream emissions revealed that the bottom-line estimates of EV lifecycle emissions varied by fivefold. It gets worse. That same review found that, across those studies, the median size of the battery assumed for the analyses was 30 kilowatt-hours. But the overwhelming majority of U.S. EVs bought last year sported batteries two to three times bigger. Tripling battery size triples the upstream emissions.
None of these variabilities appears in government forecasts for “zero emissions” cars. In fact, the range of upstream emissions is so wide that it renders meaningless any use of an average number to calculate an EV’s overall carbon footprint. But that’s what analysts do, whether at the IEA or EPA.
There has been some new thinking from the anti-CO2 religionists. The fact that the world is desperately short of lithium and
for electric vehicle batteries, at the scale they want to force, is dawning on them. There isn’t enough and likely will not be enough in the coming decades to meet the electric batteries demand. Certainly not enough for grid scale electric batteries too.
The climate alarmists haven’t let the facts get in the way of their unrealistic green fantasy of averting climate doom with part-time wind and solar. That it could somehow replace all the coal, oil, and natural gas we use, which provide us with 80% of our energy.
Except one huge, huge problem. Wind and solar produce little or no energy 70% of the time.
Reliable, full-time, on demand electricity keeps the heat going and the lights on when it is dark, and the wind is not blowing. The new expensive, impractical, and impossible federal $9.5 billion hydrogen subsidies talking point is wasted spending.
Green hydrogen made from wind and solar is not practical and is a very expensive form of energy storage and transport.
Hydrogen is not a fuel. Hydrogen must be created; it must be made from another energy source, just as electricity must be made from other energy.
No one is making green hydrogen at scale because it is difficult, expensive and requires major factories. Spoiler alert, there isn’t excess “green” energy – wind and solar – to make hydrogen with.
Green hydrogen requires 13 times more water than hydrogen produced. Sea water must be desalinated first for an added cost. More water is needed for cooling. So, it is a good idea to locate hydrogen facilities near abundant water, not in the chronically short of water western U.S.
Then the water must be heated to 2,000 degrees and electrocuted. Then the hydrogen must be super chilled to near absolute zero. Then it’s compressed to 10,000 psi, three times the psi of an average scuba tank. Then you have usable hydrogen- liquid, super- cold, compressed hydrogen. This is an expensive energy-intensive process.
The insurmountable problem with this process is that it cannot be turned on an hour after sunrise and an hour before sunset when solar panels provide the electricity. Or turned on when the wind blows and turned off when the wind stops.
Without some other energy storage device to store the “over-produced” wind and solar electricity, making green hydrogen is impossible. The costs of over-building wind and solar, then adding batteries to provide a steady stream of 24/7 electricity to make “green” hydrogen is astronomical. And in 25 years when the wind towers and solar panels wear out, or when the batteries need to be replaced every 10 years, you need to essentially start over.
Green hydrogen sounds good. And there is a well-funded industry of selling it and obscuring the truth. They have to cover up the facts and mislead people in order for the government and investor gravy train to keep them in business.
Don’t fall for the green or the pink hydrogen hype. It just doesn’t make sense. Apply a little common sense and critical thinking and you will join me in opposing this waste of money.
The hydrogen lobby duped congress to provide $9.5 billion for hydrogen hubs. Even red states who know this is a boondoggle are attempting to land this federal largesse.
Because it will create jobs with borrowed taxpayer money. I remind you that the US is $31 trillion in debt, with estimates it will balloon to over $50 trillion over the next decade.
These hydrogen jobs will last only as long as the subsidies do. Then like the Obama U.S. solar revolution, they will go bankrupt.
Frank Lasee is a former Wisconsin state senator and former member of Governor Scott Walker’s administration. The district he represented had two nuclear power plants, a biomass plant and numerous wind towers. He has experience with energy, the environment, and the climate. You can read more energy and climate information at www.truthinenergyandclimate.com which Frank leads.
The energy industry lobbyists are out with their begging bowls demanding more subsidies to deliver more “investment” in renewables in general and offshore wind in particular. It looks like the developers cannot deliver the wind farms they promised at “record low” strike prices of £37.35/MWh and claims of wind being nine times cheaper than gas were just so much hot air.
The Government’s predictions of decreasing costs of offshore wind were based on continued low commodity prices, the availability of cheap money and unrealistic assumptions about improved operational performance. It’s not looking likely that any of their operational improvement targets will be met.
In addition, the costs of raw materials and energy have gone up dramatically and interest rates have risen sharply pushing up the costs of capital. These factors have had a dramatic effect on the price of offshore wind.
Sensitivity of Offshore Wind Prices to Various Factors
Who would have guessed that a highly mineral intensive and capital intensive source of energy would be very susceptible to commodity and energy price inflation and rising interest rates?
The work of Professor Simon Michaux has shown that the prices of critical minerals are going to continue to rise as demand increases and ore grades for new discoveries fall leading to higher processing costs.
It is beginning to look like the offshore wind power bubble has burst and the fantasy of ever cheaper renewables has come to an end.
Introduction
This week, Energy UK and RenewableUK ran campaigns to lobby the Government for more subsidies for renewables in general and offshore wind in particular. Essentially, Energy UK admits that the bids of £37.35/MWh made during Allocation Round 4 (AR4) in mid-2022 were far too low and now the operators need more money to make their projects viable. This is a far cry from the claims made at the time by Carbon Brief and others that offshore wind power is nine times cheaper than gas.
The Government forecast a cost of £100/MWh for new offshore wind farms coming on stream in 2025, in their 2016 energy costs report . Their 2020 report showed the cost falling to £57/MWh for offshore wind farms coming on stream in 2025.
There are many cost drivers that govern the eventual price that needs to be charged for wind power. This article looks at initial capital costs for construction and infrastructure, cost of capital, build time, load factor the expected life of the asset. The actual performance of four wind farms from their published accounts is compared to the Government forecasts and industry publications.
We then take a look at the sensitivity of Government forecasts to changes in these cost factors to explain why Government forecasts and the AR4 bids were unrealistic.
Finally, we take a brief look a the work of Professor Simon Michaux who shows that the prices required to deliver increased supply of key minerals required to deliver wind farms are only going to get more expensive as new discoveries have lower ore grades and are thus more expensive to produce.
Demands from Energy UK and RenewableUK
The results of the Contracts for Difference Round 4 (AR4) auction were announced in July 2022. The winning bids for Offshore wind were set at a strike price of £37.35/MWh at 2012 prices. Now Energy UK says:
“The investment climate has changed dramatically since these contracts were awarded at record low prices. There are now serious concerns that many AR4 projects may not be deliverable at current strike prices.”
They also explain that supply chain and financing costs have risen, raising questions about the deliverability of projects. They also say that developers were relying on the windfall of high electricity prices to justify their projects, by delaying their commitment to Contract for Difference (CfD) prices:
“There are immediate concerns whether CfD Allocation Round 4 (AR4) projects will go ahead. Generators who secured AR4 contracts did so during a period of high prices. As such, many AR4 projects had low strike prices that took account of the ability of generators to factor in a period of merchant exposure before implementing the CfD.”
They also state that the expected prices for AR5 are too low, jeopardizing new projects coming forward. Their solutions are higher prices in the CfD auctions, and tax breaks so renewables providers escape much the Electricity Generation Levy (EGL). In other words, the begging bowl is out for even more subsidies.
RenewableUK used more flowery language to describe the problem and solutions, but also called for higher CfD prices, more tax incentives for renewables and less expensive grid charges. In other words, they demand that others pay for the very long copper cables through hostile terrain that are required to connect up new offshore wind farms. So again, the demand is for ever more subsidies for what is supposed to be a cheap source of energy.
Let’s look at why it has all gone wrong for the offshore wind industry.
Actual Costs of Offshore Wind Farm Electricity
First of all, offshore wind has been far from cheap so far. Modern wind farms receive a subsidy in the form of a CfD contract that guarantees index-linked prices for 15 years.
I have taken an in depth look at four offshore wind farms that provide sufficiently detailed information. Links to the relevant pages at Companies House are provided in the list below.
Figure 1 shows the revenue per MWh of electricity generated (£/MWh) for the most recent two financial years. For Beatrice this is the years up to 31 March 2021 and 2022. For the others it is for the two years ending 31 December 2020 and 2021. The horizontal dashed lines show the BEIS forecasts of the Levelised Cost of Energy for Offshore wind farms. The red line shows their estimate (£100/MWh) for new farms coming on stream in 2025, taken from the 2016 report. The 2016 estimate for new capacity in 2020 was £106/MWh. The green line shows the estimated cost for offshore wind farms coming on stream in 2025 (£57/MWh) taken from the 2020 report. In each case, the actual prices achieved are far higher than the estimates for new farms in 2020.
Figure 1 – Revenue per MWh generated by Year for Selected Offshore Windfarms
To some extent, this is to be expected because the Government is anticipating improvements in technology to bring costs down in the future. Sheringham Shoal came on stream in September 2012, Dudgeon in February 2017, Beatrice in July 2018 and East Anglia One in July 2020. Looking at Dudgeon, Beatrice and East Anglia One, it does look like there is a general trend downwards in the price of electricity sold for the more recent wind farms. However, East Anglia One that came into operation in 2020, received prices for its electricity 18.8% more expensive than the Government forecast in 2016 for new wind farms in 2020. Moreover, because the CfD contracts are index linked, the prices per MWh rise year on year.
Aficionados of the UK offshore wind sector may ask why Hornsea One and Hornsea Two have not been included in the analysis above. The answer is that these wind farms are operated by Ørsted and their published accounts do not disclose the amount of power generated, so it is not possible to determine their actual performance. Hornsea One was fully commissioned on 28 December 2019 and has a CfD for £140/MWh recorded in its favour, some 32% above the Government’s forecast for 2020. Hornsea 2 began operation at the end of August 2022 and had signed an CfD with a strike price of £57.50/MWh. Similarly, Triton Knoll and Moray East agreed CfDs with strike prices of £74.75/MWh and £57.50/MWh respectively at 2012 prices. However, it has been reported that these farms have not taken up their CfDs and are instead selling power at much higher prices. Of course, these CfDs are index-linked, so by the time they take them up, the strike prices will have risen.
Given that new windfarms coming on stream around 2020 are nowhere near meeting the Government’s forecast for 2020 and lobbyists are already bleating about AR4 agreed prices, it’s not looking good for the 2025 forecasts made in 2020. Let’s dig a bit deeper into the factors that make up the price of offshore wind energy.
Factors Governing Wind Farm Costs
There are a number of factors governing offshore wind farm costs. They include initial capital costs for construction and infrastructure, cost of capital, build time, load factor the expected life of the asset. Between the 2016 and 2020 reports, the Government has made some important changes to its assumptions for wind farms coming on stream in 2025. These are shown in Figure 2.
Figure 2 – Changes to Offshore Wind Cost Factors
The reference size has increased from 844MW to 1,000GW. This is probably justified given that windfarms that have come on stream recently have been larger than 1GW. The load factor has increased from 47.67% to 51%. The construction time has been reduced by 33% from three years to two years. The expected lifetime of the wind farm has increased 36% from 22 years to 30 years. Construction costs have fallen 28% from £2,100/kW of capacity to £1,500/kW. The fixed operation and maintenance costs have decreased 20% from £45,400/MW/yr to £36,300/MW/yr and very importantly, the hurdle rate cost of capital has fallen from 8.9% to 6.3%.
Let’s take a look at each of these factors and judge how realistic they are.
Capital Costs
The capital costs for the turbines, installation and infrastructure are a key driver of the price of wind power. Clearly, the higher the costs, the higher electricity prices have to be to recoup those costs. The 2020 Government report assumes that construction costs of wind farms deployed in 2025 will fall 28% compared to what they assumed in their 2016 report. Some of this reduction is driven by the increase in wind turbine size. The larger the turbine, fewer machines are required to deliver the same output. However, each turbine is larger and so contains more materials and requires even larger concrete foundations.
In essence, the construction costs represent the costs of the materials required to manufacture the turbines and secure them on the ocean floor, plus the costs of the energy and labour to transform the raw inputs into the finished article. Figure 3 shows how the prices of key commodities have changed over the past 10 years (all taken from Trading Economics).
Figure 3 – Changes in Energy and Commodity Prices
The Brent oil price has roughly doubled from ~$40/bbl in 2016 and 2020 to over $80/bbl today. Oil is the feedstock to make the fuel used to extract minerals from the ground and transport materials around. UK gas prices have gone up roughly six-fold from ~20p/therm in 2016 and 2020 to 128p/therm today. Looked at another way, gas prices are still 3 times higher than what might have been regarded as a long-term average of 40p/therm. Coal prices have increased 3-fold from $60-70/t in 2016 and 2020 to $209/t today. Gas and coal are used as fuel to generate the electricity to make steel and concrete and power factories. Iron ore prices have gone up from around $60/tonne in 2016 to over $127/tonne today. Coal and iron ore are the raw materials used to make steel for the turbine towers. Copper prices have roughly doubled from ~$2/lb in 2016 and 2020 to over $4/lb today. Copper is used in the rotors of the turbine generators and in the cables to connect them to the shore. Neodymium prices have more than doubled from ~CNY40K/t to over ~CNY93K/t. Neodymium is a rare earth metal used as a key ingredient in the permanent magnets used in the generators.
It seems unlikely that the massive increase in commodity costs will have been offset by the economies of scale derived from the larger turbines. This is borne out in the recent investor presentations from Vestas and Siemens Gamesa and of course by the reports from Energy UK and RenewableUK described above.
Vestas is loss-making and its overall order intake is shrinking. Offshore order intake has risen overall, but for Europe was very small at just 60MW, or four of their very large turbines. Figure 4 shows the average selling price of its offshore wind turbines increased 34% from Q4 2021 to Q4 2022.
Figure 4 – Vestas Order Intake and average selling price per MW
Siemens is also loss-making and its order intake is also shrinking. Siemens doesn’t disclose the selling price per MW of its offshore turbines, probably because it didn’t sell much in Q1 2023, but its onshore prices increased 25% from Q1 2022 to Q1 2023 and by over 50% since Q1 2020.
The costs of the raw commodities have risen substantially since the Government’s reports were put together, the two main turbine providers are losing money and need to increase prices further to become profitable. It looks highly unlikely that the costs of turbines and installation are going to fall by the predicted 28% between now and 2025 and instead will rise substantially.
Cost of Capital
The cost of capital, or discount rate is a crucial determinant of offshore wind farm costs. The cost of capital is used to discount future cash flows to current values. The higher the discount rate, the lower the current value of future cash flows. The Government changed its hurdle rate assumption for wind farms delivered in 2025 from 8.9% in its 2016 report to 6.3% in its 2020 report.
The hurdle or discount rate required is related to the “risk-free” rate represented by the yield on UK Government gilts. In 2016, the yield on the 10-year gilt was around 1.25% and about 0.35% in 2020. The 30-year gilt yielded around 1.85% and 0.85% respectively in the same two years. Averaging these yields, the 2016 report assumed a 7.35% premium to gilt yields and the 2020 report assumed a 5.7% premium, the average of those two premia is 6.53%.
10-year and 30-year gilts are currently yielding 3.5% and 3.9% respectively. Taking the average of those two figures and applying the 6.53% average premium gives a more realistic hurdle rate for 2025 of 10.23%.
We will look at the dramatic impact this has on the prices of wind electricity in the section on sensitivity.
Build Time
The build time is an important driver of the costs of offshore wind. If it takes longer to build out, the operator has to wait longer before it is generating revenue to repay the money borrowed to build the wind farm. The Government has reduced its assumed construction time by 50% from 3 years to 2 years between the 2016 report and the 2020 report.
The various different wind farms in the comparison shown in Figure 5 below have websites that describe the timeline for construction. The times shown are the time from construction start to full commissioning.
Figure 5 – Total Construction Time for Selected Offshore Wind Farms (Years)
In practice, the wind farms go into partial production part way through construction as some of the early turbines are brought onstream. Therefore, the build times are probably exaggerated a little, but probably not enough to make a significant difference to the overall picture. Most of the offshore windfarms took longer than 3 years to construct, none of them took two years and there’s no apparent downward trend in the overall build time.
It doesn’t look likely that total construction times are going to fall by a whole year by 2025, especially when one considers that windfarms are getting larger and being located further out to sea, complicating logistics.
Offshore Wind Farm Load Factors
Load factors (also known as capacity factors) measure how much electricity will be generated compared to the theoretical maximum if the wind blew at the correct speed all year. The higher the load factor, the more electricity is produced which should lead to lower costs per MWh as the capital expenditure is spread across more units of electricity.
Of course, there are times when the wind doesn’t blow fast enough, or even at all and the turbines produce nothing. There are also times when the wind blows too hard and the turbines have to be turned off to avoid damage and so they produce nothing then either. Figure 6 shows the performance of actual wind farms compared to the Government assumptions for 2020 and 2025.
Figure 6 – Load Factor by Year for Selected Offshore Windfarms
In 2016, the Government assumed a load factor of 47.67% for new wind farms commissioned in 2020 and 2025. The 2020 report assumes a load factor of 51% for turbines commissioned in 2025. These assumptions are averages for every year of the life of the wind farm, not a maximum. In its first full year of operation East Anglia One failed to hit the 2020 target by over three percentage points. Even the performance of Dudgeon in 2020 should be viewed as a one-off performance as it had much lower load factors in its other years of operation as shown in Figure 7.
Figure 7 – Dudgeon Wind Farm Load Factor by Year
The load factor of a wind farm is driven by a number of elements including the turbine technology, the layout of the turbines in the sea, the sophistication of the control system and the operation and maintenance regime. To help with its forecasts, the Government commissioned a report from DNV GL to examine the improvements in technology that might improve load factors in the future. The results are shown in Figure 8 below.
Their baseline estimate is for load factors for new wind farms of 49.7% in 2022, rising to 51% in 2025 and 52.9% in 2030. The improvements to 2030 are driven by moving to larger turbines (15MW compared to 7MW typical today), more advanced control systems and more optimal layouts. We might expect Hornsea One to have a similar performance to East Anglia One as they both use the same model of Siemens 7 MW turbines. Hornsea Two was built using 8MW turbines. Moray East and Triton Knoll, both fully commissioned in 2022, were built using Vestas 9.5MW turbines. However, we won’t know the actual performance of these sites for quite some time.
Vestas is now marketing a 15MW turbine with an implied load factor of over 60% in ideal conditions. Siemens is also marketing a 14MW turbine, but doesn’t make a specific claim for its capacity factor.
We shall have to wait and see how the newer wind farms perform before coming to a complete judgement on the accuracy of the load factor forecasts. However, the first year of operation of East Anglia One shows that hitting the 2020 target even once is challenging, let alone as an average over the life of the wind farm. In its 2020 report, the Government assumes load factors rising to 57% by 2030 (in line with DNV’s upper case) and 63% by 2040 (DNV had a maximum of 60% in 2035). It seems very optimistic to assume the upper case as an average over the whole life of the asset.
Asset Lifetime
The Government changed its assumption on the lifetime of offshore windfarms between its 2016 and 2020 reports. The 2016 report assumed a life of 22 years and the 2020 report increased the life by 36% to 30 years.
Figure 9 sets out the depreciation policies in the accounts of many wind farm companies. The expected life falls well short of 30 years and averages around 24 years.
Figure 9 – Expected Asset Life of Selected Offshore Wind Farms
In addition, the expected life of the new 14MW Siemens turbine is 25 years, although Vestas is claiming 30 years for its 15MW turbine. Putting all the data together, it seems very optimistic to assume a 30-year average lifetime for all new offshore wind farms.
Sensitivity of Offshore Wind Prices
A Discounted Cashflow model has been constructed using the parameters set out in the Government’s 2020 report. This gives a zero NPV using £56.94/MWh strike price so is giving results very close to the Government model; close enough to be a rounding error. Then the various cost drivers were varied to test the sensitivity of prices to the different parameters. The results are shown in Figure 10.
Figure 10 – Sensitivity of Offshore Wind Power Prices to Various Factors
The prices for offshore wind are most sensitive to increased costs of construction and infrastructure and the cost of finance. A 35% increase in the costs of construction (note some projects reporting a 50% increase according to Energy UK) results in an 18.8% increase in the price of electricity. A few percentage points increase in the cost of capital push the electricity prices up 26.5%. Shortfalls in the load factor, asset life and extending the build time have relatively little effect. If all of the changes in the cost drivers come to pass, then offshore wind farm prices rise by 74% to £99.10, almost back to the figures assumed by the Government back in 2016.
Who would have guessed that a highly mineral and capital-intensive source of energy would be very susceptible to commodity and energy price inflation and rising interest rates?
Implications
If scientists such as Professor Simon Michaux are correct, the era of cheap minerals is over. Technologies such as wind and solar power and associated battery storage will demand more and more critical minerals such as copper, nickel, cobalt and lithium. New discoveries of these minerals are required and new discoveries tend to have lower ore grades and so are more energy intensive and expensive to transform into useful metals. This means that these minerals are going to continue to get more expensive for some time to come. This will lead to structurally higher inflation which will mean higher interest rates, so the era of cheap credit is coming to an end.
Therefore, the most important cost drivers for wind power are going to get more expensive, pushing up the price of wind power, which itself will further increase inflation. More subsidies will not fix these problems. In fact, they will make them worse. It is starting to look like offshore wind bubble has popped.
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