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As part of the BGG Tianjin Nangang LNG terminal, China Huanqiu Contracting & Engineering Co. Ltd (HQCEC) has completed the construction of two Liquefied Natural Gas (LNG) onshore storage tanks, each with a capacity of 220,000 m3.

They are the world’s largest onshore LNG storage tanks incorporating the GST® membrane containment technology.

These very large onshore LNG tanks are part of the agreement signed in November 2019 between GTT and the Chinese state-owned company Beijing Enterprises Group (BEG), relating to the construction of eight onshore tanks[3] using GST® technology, at the BGG Tianjin Nangang LNG terminal.

The construction schedule remained on track, despite the constraints imposed by the COVID-19 pandemic. The two onshore tanks are now entering the commissioning phase and will be operational in the first half of 2023.

The GST® technology developed by GTT offers many advantages compared to a traditional onshore LNG tank: safer storage management through integrated monitoring, greater storage capacity for the same footprint and greater respect for the environment[5].

BGG, HQCEC and GTT organized a delivery ceremony in the presence of Mr. Laurent Bili, Ambassador of France in China, Mr. Jean-Marc Fenet, Minister Counselor, representatives of the governments of Beijing & Tianjin, Mrs. Yalan Li, Chairwoman of BGG, Mr. Shaoguang Song, Chairman of HQCEC, and Mr. Adnan Ezzarhouni, General Manager of GTT China.

Philippe Berterottière, Chairman and CEO of the GTT Group, stated: “The construction of these first two onshore tanks marks an important milestone for BGG’s LNG terminal in Tianjin.

These tanks are the first of eight planned for the site and are already the largest onshore tanks in the world equipped with our GST® technology. We thank BGG and the Chinese government for their trust and wish HQCEC every success of this new terminal.”

Mr. Laurent Bili, Ambassador of France in China, said at this occasion: “These tanks are an industrial success story, a very concrete example of a fruitful Franco-Chinese partnership, a technological innovation and part of the response to the challenges of climate change”

Mrs. Yalan Li, Chairwoman of BGG and President of IGU, declared: “This milestone is the reward of five years of assessment, preparation, engineering and actual construction.

The City of Beijing and Beijing Entreprises Group are proud to have evolved this emerging technology into a promising solution for many projects around the world.

Thanks to this world first, these containment membrane tanks are on their way to becoming the state-of-the-art in LNG storage.

We have been impressed by the dedication and passion of GTT and HQCEC to make this world first a success, and we thank the French and Chinese authorities for supporting such an important technology partnership between our two countries.”

Mr. Shaoguang Song, Chairman of HQCEC, declared: “We are proud to have successfully completed these two world largest onshore membrane tanks with the strong support of GTT, thanks to the precious opportunity provided by BGG.

With the advantages of higher efficiency and lower carbon footprint, membrane system has been proved to be a good choice for upcoming LNG projects, both onshore and offshore.

Committed to continuous technology innovation and process optimization, HQCEC will continue to promote membrane technology to domestic and international markets and bring value to our clients.”

By Marine Insight, January 20, 2023

OPEC+ is facing “volatile prospects” in oil markets both in supply and demand, UAE energy minister Suhail al-Mazrouei told Asharq TV on Saturday.

He said this was due to European sanctions on Russian crude taking effect in addition to China lifting its “zero-COVID” policy.

OPEC+ production capacity was down 3.7 mln bpd due to fewer investments in the oil sector, Al-Mazrouei said.

He also said UAE is taking preemptive steps to compensate for the reduced oil production capacity in some countries by bringing forward its five million barrel per day oil production capacity expansion to 2027 from a previous target of 2030.

Regarding gas, Al-Mazrouei told the Atlantic Council Global Energy Summit earlier that the world would need natural gas for a long time and more investment was required to ensure supply security and affordable prices during the global energy transition.

Reuters by Ahmed Tolba, January 20, 2023

Established by the U.S. government nearly fifty years ago, the Strategic Petroleum Reserve (SPR) is intended to protect the economy and strengthen national security during major oil supply disruptions. Presidents have tapped the reserve, which is one of several U.S. strategic stockpiles, in response to various crises, including natural disasters, military conflicts, and ship-channel closings.

Supporters say that the reserve safeguards the independence of U.S. foreign policy and remains a critical energy security tool. Others level various criticisms, including that the SPR is ineffective, unnecessary, and prone to exploitation for political gain.

The Joe Biden administration’s massive withdrawals from the SPR in response to the war in Ukraine and oil price inflation in 2022 have rekindled debate over the reserve. 

Where is the Strategic Petroleum Reserve?

The SPR is the world’s largest stockpile of emergency crude oil, owned and operated by the U.S. federal government to alleviate significant oil supply disruptions or price inflation.

The oil is kept across a network of underground salt caverns in Texas and Louisiana, which can hold a total of more than seven hundred million barrels of oil. Up to 4.4 million barrels can be withdrawn per day—about a quarter of daily U.S. consumption—and the oil takes about two weeks to reach the market. 

When was the Strategic Petroleum Reserve created?

The SPR was conceived in response to the 1973 oil embargo by the Organization of Petroleum Exporting Countries (OPEC), imposed in retaliation for the United States’ support of Israel during the Fourth Arab-Israeli War.

The Energy Policy and Conservation Act (EPCA), signed into law by President Gerald R. Ford in 1975, authorized the creation of a strategic oil reserve to shield the U.S. economy from future supply shocks, including those engineered by oil-producing countries attempting to coerce U.S. leaders or gain foreign policy concessions. 

Ford signed the EPCA, a compromise with the then Democrat-controlled Congress, after having originally proposed energy independence legislation that would have created an even larger reserve and expanded his powers to impose tariffs on underpriced imported oil.

The slimmer EPCA created a smaller reserve and introduced fuel economy standards for vehicles, but it did not include the oil price controls and energy efficiency standards for appliances that Ford had sought. 

Who controls the Strategic Petroleum Reserve?

The president and Congress each exert degrees of control over the SPR, with the executive taking the lead on withdrawals and legislators having approval power over restocking.

The president can independently authorize an emergency drawdown from the reserve in response to a “severe energy supply interruption,” or if the United States has been obligated to by the International Energy Program [PDF], a framework for cooperation among members of the International Energy Agency (IEA). For instance, in 2011, member countries of the IEA collectively released sixty million barrels in response to shortages resulting from the conflict in Libya.

To respond to more modest disruptions, the president can order a limited withdrawal of up to thirty million barrels without declaring an emergency drawdown. In both cases, the Department of Energy auctions the oil to the highest bidder among companies registered with the SPR.

The secretary of energy is responsible for oil purchases to refill the SPR, but Congress must approve any new spending required to do so. For instance, President Donald Trump ordered that the reserve be filled to maximum capacity to help struggling U.S. producers at the start of the COVID-19 pandemic, but Congress did not approve the purchase.

The Department of Energy also leads exchange agreements, or short-term loans of oil that are repaid with interest, thereby increasing the size of the SPR. Since the 1990s, the president and Congress have occasionally mandated the sale of oil from the reserve to raise revenue.

When has it been tapped?

There have been three dozen releases from the SPR since its inception, including twenty-two sales and fourteen exchanges (loans). Five of the sales have been emergency drawdowns: in 1991, during the Gulf War; in 2005, in response to Hurricane Katrina; in 2011, during the conflict in Libya; and twice in 2022, both in response to Russia’s invasion of Ukraine. 

The most recent releases before the war were due to the COVID-19 pandemic and the subsequent rebound in oil demand, as rising gasoline prices contributed to record inflation in the United States.

In November 2021, President Biden announced a release of thirty-two million barrels in exchange agreements and eighteen million barrels in sales, seen as an effort to pressure OPEC to increase production; some experts said it was a novel use of the SPR, given there was no supply disruption. 

In March 2022, as Russia’s war in Ukraine caused turmoil in global energy markets, Biden authorized an emergency release of thirty million barrels, as part of a coordinated action led by the IEA.

Later that month, he approved the emergency release of up to one million barrels per day for six months, or a total of about 180 million barrels—the largest release in the reserve’s history. Biden said the move was a “wartime bridge” that would allow domestic oil production time to ramp up.

By October of that year, the Department of Energy had completed its emergency sale from the stockpile, bringing the reserve down to fewer than four hundred million barrels, a four-decade low. The administration said it will use the revenue to replenish the reserve by purchasing oil when the price of West Texas Intermediate (a U.S. benchmark) is $72 per barrel or less.

What is the debate over the Strategic Petroleum Reserve?

The war in Ukraine and the consequent SPR drawdowns have renewed debate over the reserve’s purpose and operation. Some analysts say that Biden ordered the emergency drawdowns to lower gas prices and win votes for Democratic candidates in the 2022 midterm elections. They argue that these political gains come at the cost of harming SPR infrastructure and increasing U.S. dependency on large oil producers.

For instance, they argue that the Biden administration has made some unsavory concessions to Venezuela and Saudi Arabia. Meanwhile, some critics have called for an end to the SPR entirely, contending that market forces and private stockpiles are sufficient to shield the United States from a negative supply shock. 

However, many analysts agree that the SPR serves an integral purpose in mitigating short-term supply shocks.

“As long as there’s a potential for war, hurricanes, and other disruptions, you have to have the SPR,” says Sarah Emerson, president of consulting firm ESAI Energy. Without the SPR, Emerson says, the government would likely have to ask companies to hold more reserves, which would increase their costs and thus prove unpopular.

Furthermore, private stockpiles would likely have to be kept in above-ground tanks, where the oil would have a shorter shelf life than in the salt caverns of the SPR, and thus a shorter window within which it could be sold. Oil companies generally prefer to hold only the number of barrels they are confident that they can sell. 

“Companies run pretty lean, as lean as they can,” says Bruce Beaubouef, an energy journalist and author of a reference book on the SPR. “History has shown that private stockpiles are not sufficient to respond to an emergency.”

Additionally, there are concerns about the state of the country’s oil infrastructure and the implications for the SPR.

A 2016 review by the Department of Energy warned that aging surface infrastructure, including storage tanks and pumps, will begin to compromise the SPR’s capabilities.

Also, record U.S. energy production in each of the past eight years, and the resulting congestion in pipelines, could leave the SPR unable to effectively deliver oil without shutting off domestic suppliers, the department said. In November 2022, Biden asked Congress for $500 million to modernize the SPR, though Congress is yet to approve the funding.

Council on Foreign Relations by Noah Berman, January 20, 2023

Europe is set to ban imports of Russian oil products on Feb. 5 in a move that is already causing massive shifts in global diesel trading.

Buyers are rushing to fill European oil storage tanks with Russian diesel, with flows this month on track to hit a one-year high.

The European Union banned seaborne Russian crude imports from Dec. 5 and will ban Russian oil products from Feb. 5, in a move aimed at depriving Moscow of revenue.

The Group of Seven nations (G7), Australia and the 27 European Union countries also implemented on Dec. 5 a price cap on Russian crude.

This allowed non-EU countries to continue importing seaborne Russian crude oil, but it will prohibit shipping, insurance and re-insurance companies from handling cargoes of Russian crude around the globe, unless it is sold for less than $60.

Russian Urals crude prices fell in December. Russian crude was sold to countries such as India well below the $60 per barrel price cap, according to trading sources, despite Russia saying it would not abide by the cap even if it has to cut production.

Vessels carrying Russian crude loaded before Dec. 5 and unloaded at their destination before Jan. 19 will not be subject to the price cap, according to the U.S. Treasury Department.

The G7 including the United States, Australia and the EU, are designing a similar price cap mechanism for Russia’s refined fuels such as diesel, kerosene and fuel oil, from Feb. 5.

There will be on products trading at a premium to crude oil as well as those trading at a discount, according to a G7 official.

But experts have struggled to see how the price cap will work for refined fuels. Capping oil product prices is more complicated than setting a price limit on crude, because there are many oil products and their price often depends on where they are bought, rather than where they are produced.

DIESEL PRICES

Since Europe is heavily reliant on Russian diesel imports, the Feb. 5 ban is expected to support profit margins for the fuel, analysts say.

WoodMac expects European diesel margins, the profit that a refiner theoretically makes from refining crude into diesel, to average $38 a barrel in the first half of the year, more than double the 2018-22 average based on Reuters calculations.

DIESEL FLOWS

European diesel imports have averaged 700,000 barrels per day (bpd) so far this year, their highest since March 2021, according to oil analytics firm Vortexa, as traders rush to fill tanks ahead of the ban.

At the same time, Europe has been raising its diesel imports from Asia and the Middle East, the two regions expected to shoulder most of its exports after the ban comes into place.

The longer voyages, however, and higher demand for tankers shipping the fuel into Europe, has meant that freight rates are rising, adding to the cost for consumers.

NEW REFINERIES

New refinery projects are expected to raise global diesel production, boosting flows to Europe later in the year and helping to ease the crunch, analysts say.

New additions include expansion of the 400,000 bpd Jizan refinery in Saudi Arabia, Dangote’s 650,000 bpd oil refinery in Nigeria which is expected to come on stream in the first quarter, the new 615,000 bpd al-Zour refinery in Kuwait and a number of sites in China.

Reuters by Ahmad Ghaddar, January 20, 2023

Minister of Energy Csaba Lantos called the strengthening of energy sovereignty a priority task in a program on Radio Kossuth, where he also said that the mild winter had resulted in low gas consumption, which is why the levels of gas storage facilities in Europe and Hungary are very high.

Csaba Lantos said that although Russian gas is still arriving in Europe, it cannot be ruled out that the war will last for a long time, nor that gas prices will rise.

Asked about Ursula von der Leyen, the President of the European Commission’s prediction in December, when she said that there could be a shortage of up to 30 billion cubic meters of gas on the market, the minister said that there are about 25 major LNG terminals under construction in the EU, which could ease the energy crisis and replace natural gas from Russia.

He added that: when the terminals are completed, it will be possible to say that Europe is truly independent from Russian gas. Construction of the terminals has started, but 2023-2024 will be a tough year for Europe.

The minister pointed out that Hungary’s situation is a little different, as it has a relatively large number of gas storage facilities.

As long as the Serbian pipeline is in operation, these storage facilities will be filled, he noted. He also spoke of strengthening Hungary’s energy sovereignty, saying that “we are very dependent on foreign countries for energy, and we need to decrease this dependence.”

As an example, he said that: In 2021, Hungary consumed around 10 billion cubic meters of natural, while 1.5 billion cubic meters could be extracted from Hungarian soil.

The government’s ambition is to reach two billion cubic meters per year. In addition, they will continue to exploit weather-dependent renewable energy sources, such as solar energy and, as a complement, wind energy.

Lantos added that financial resources will be available to achieve these goals. He pointed out that the Hungarian recovery plan was considered one of the best by the European Union, so they hope that “this EU money will come in.”

If for some reason it does not, then other sources will have to be found to implement the program to strengthen energy sovereignty.

Meanwhile, despite the energy crisis, Hungarian households’ energy bills are still among the lowest in Europe.

According to the Hungarian Energy and Public Utility Regulatory Authority, Hungarian households paid the second cheapest price (9.02 euro cents per kilowatt-hour) for electricity in the last month of the year for average consumption in the protected price category (2,523 kilowatt-hours per year) among European capitals.

Households consuming 20 percent more than the average annual consumption were able to access electricity at 10.40 euro cents, also the second cheapest price in Europe, they said.

Regarding natural gas, it was the cheapest in Hungary in December at a reduced price of 2.48 euro cents per kilowatt hour (up to 63,645 megajoules per year). Hungarian households had access to gas at 5.04 euro cents per kilowatt-hour, the second cheapest price in Europe when consumption was 20 percent above the capped amount.

By Hungary Today, January 19, 2023

Global monthly oil production peaked on a monthly basis in November 2018, and there are now real questions as to whether oil output will ever hit those heights again.

A combination of spending discipline and regulatory hurdles appears to have ended the shale boom, but shale production growth may well have slowed anyway.

There have been plenty of ‘peak oil’ predictions in the past, but with growing regulatory resistance, the death of U.S. shale, and less tier-one acreage, this really could be it.

Prior to the pandemic-induced downturn in world oil production, U.S. oil production growth was responsible for 98 percent of the increase in world production in 2018 (as reported in 2019).

Almost all of that growth resulted from rapid increases in shale oil production which accounted for 64 percent of U.S. production (as of 2021).

Fast forward to today when Oilprice.com has declared that “The U.S. Shale Boom Is Officially Over.”

The reasons cited mostly have to do with management “discipline” regarding capital expenditure in favor of shareholder payouts and complaints about “anti-oil rhetoric” and “regulatory uncertainty.”

But there might just be another reason for the slowdown in shale oil production in the United States: There isn’t as much accessible and economical shale oil underground as advertised.

Earth scientist David Hughes laid out his case for this view in his “Shale Reality Check 2021.” (For a summary of Hughes’ report, see my piece from December 2021 entitled, “U.S. shale oil and gas forecast: Too good to be true?”)

There may be other sources of oil worldwide that will somehow make up for the significantly lower growth in U.S. shale oil production.

But no other source seems set to provide the kind of growth U.S. shale oil provided, that is, 73.2 percent of the global increase in oil production from 2008 through 2018.

The world has actually been getting along with less oil for some time now. World oil production proper (crude oil including lease condensate) peaked on a monthly basis in November 2018 at 84.58 million barrels per day (mbpd).

In August 2022 production was 81.44 mbpd. That’s after a pandemic-induced shock that saw production fall to 70.28 mbpd in June 2020.

Neither the U.S. shale oil companies nor OPEC seem ready to increase production significantly (assuming that they can). Russia, among the world’s top three producers, is under heavy sanction and may not be able to produce more oil for export anytime soon.

(Again, it is not certain that Russia can significantly increase production. Except for the pandemic-induced drop Russia has long been on a production plateau of between 10 and 11 mbpd.)

No doubt some new oil savior will be announced soon whether credible or not. In the meantime, the world economy will be faced with limited oil supplies that do not simply grow to meet our fantasies of what we want. The result will be high prices, that is, higher than has been historically the case.

A recession won’t change this dynamic and, in fact, may reinforce it as oil companies are likely to reduce drilling activity when demand for oil slumps. That will make it doubly difficult for those companies to supply growing demand coming out of the next recession.

This is the way things might very well be for a long time if not indefinitely. Many of us who foresaw this day said that we would only see peak world oil production in the rearview mirror. It may take a few more years to determine if November 2018 marked the all-time peak.

OilPrice.com by Kurt Cobb, January 19, 2023

Both ExxonMobil and Chevron have sold off non-core assets in other parts of the world in recent years.

Exxon and Chevron are betting big on oil and gas assets in the Americas as they seek to capitalize on abundant resources with good returns closer to home.

Both U.S. supermajors have said in their releases about the 2023 capital budget allocation that they would focus on the Permian and a handful of oil and gas projects in North and South America.

Over the past year, Exxon quit Russia after the Russian invasion of Ukraine, and Chevron saw its concession agreements in Indonesia and Thailand expire.

In the past few years, Chevron has sold assets in the UK, Denmark, and Brazil, among others, according to The Wall Street Journal. Exxon, for its part, has either sold or is trying to sell assets in Nigeria, Egypt, and Chad, among others.

In its corporate plan through 2027, Exxon said last month that its investments in 2023 were expected to be in the range of $23 billion to $25 billion “to help increase supply to meet global demand.”

More than 70% of Exxon’s capital investments will be deployed in strategic developments in the U.S. Permian Basin, as well as in Guyana, Brazil, and LNG projects around the world.

By 2027, upstream production is expected to grow by 500,000 oil-equivalent barrels per day to 4.2 million oil-equivalent barrels per day, with more than 50% of the total coming from these key growth areas.

Some 90% of the upstream investments that bring on new oil and flowing gas production are expected to have returns greater than 10% at prices less than or equal to $35 per barrel, Exxon said.

Chevron continues to bet on the Permian, too. Its upstream capex—out of organic capex of $14 billion for 2023—includes more than $4 billion for Permian Basin development and roughly $2 billion for other shale and tight assets.

More than 20% of upstream capex is for projects in the Gulf of Mexico, Chevron said last month.

Oilprice.com by Tsvetana Paraskova, January 19, 2023

The supermajors’ record quarterly earnings have drawn repeated criticism from President Joe Biden and officials from his Administration.

The surge in oil and gas prices will translate into record-high 2022 earnings for the two U.S. supermajors, Exxon and Chevron, with their combined yearly profits hitting nearly $100 billion, analysts say.   

The two oil and gas giants benefited from the soaring price of oil and gas following the Russian invasion of Ukraine.

Although oil prices traded below $90 per barrel in the last weeks of 2022 and prices increased on an annual basis by only around 10% last year compared to 2021, extreme volatility and the frequent surges above $100 per barrel helped all oil firms, including the biggest American integrated companies, generate record or near-record quarterly profits and cash flows.    

The yearly earnings for Exxon and Chevron are also expected to be at record highs. Exxon is set to report a record of as much as $56 billion in profit for 2022, while Chevron’s earnings are projected to exceed $37 billion, also a record-high, per estimates compiled by S&P Capital IQ cited by the Financial Times.

The supermajors’ record quarterly earnings have drawn repeated criticism from President Joe Biden and officials from his Administration, who have slammed company strategies to boost share buybacks and raise dividends instead of “passing on the savings” to “lower the prices at the pump” for American consumers.  

Exxon and Chevron’s quarterly earnings after the Russian invasion of Ukraine were already an indication that the yearly profits for 2022 would be at record highs. 

Chevron posted its highest-ever quarterly profits for the second quarter, thanks to high oil and gas prices and tight fuel markets driving multi-year high refining margins.

For Q3, Chevron recorded its second-highest quarterly profit ever on the back of increased oil and gas demand and increased U.S. production. Exxon booked a record $19.66 billion profit for the third quarter, beating the previous record of $17.9 billion it booked for the previous quarter. 

Chevron is “on track to beat” in 2022 its free cash flow record from 2021, chief financial officer Pierre Breber said on the Q3 earnings call in October. 

Chevron said last month its 2023 organic capex would be $14 billion for 2023, consistent with its “long-term plans to safely deliver higher returns and lower carbon,” according to chairman and CEO Mike Wirth. 

“Our capex budgets remain in line with prior guidance despite inflation,” Wirth said. “We’re winning back investors with capital efficient growth, a strong balance sheet, and more cash returned to shareholders.” 

Exxon’s corporate plan through 2027, also unveiled in December, maintains annual capital expenditures at $20-$25 billion, while growing lower-emissions investments to around $17 billion. Investments in 2023 are expected to be in the range of $23 billion to $25 billion to help increase supply to meet global demand.

“We view our success as an ‘and’ equation, one in which we can produce the energy and products society needs – and – be a leader in reducing greenhouse gas emissions from our own operations and also those from other companies,” said chairman and CEO Darren Woods. 

Even if they raise investments in clean energy solutions, both supermajors say that they would continue to deliver oil and gas as the world will still run on fossil fuels for years, and decades, to come. 

The strategy, however, has been slammed by both environmentalists and the White House. Campaigners accuse oil majors of greenwashing, while the Biden Administration is accusing the companies of “war profiteering” and of not investing in American supply, threatening windfall taxes for those who don’t. 

If oil firms don’t invest in increasing production and refining capacity, “they’re going to pay a higher tax on their excess profits and face other restrictions,” President Biden said in October.  

With the decline in U.S. gasoline prices in recent weeks, the rhetoric of blaming the oil industry has subsided at the expense of the Administration taking credit for the falling prices at the pump. 

On several occasions, the American Petroleum Institute (API) has issued statements after criticism from the Biden Administration. In one of the most recent from end-October, API President and CEO Mike Sommers said, “Rather than taking credit for price declines and shifting blame for price increases, the Biden administration should get serious about addressing the supply and demand imbalance that has caused higher gas prices and created long-term energy challenges.” 

“Oil companies do not set prices—global commodities markets do. Increasing taxes on American energy discourages investment in new production, which is the exact opposite of what is needed.”  

Oilprice.com by Tsvetana Paraskova, January 19, 2023

Demand for renewable ethanol in the EU will increase by 13% from now until 2030, according to a new report from the European Commission.

The EU Agricultural Outlook for Markets, Income and Environment 2022-2032, published by the Commission’s DG for Agriculture and Rural Development, forecasts that demand for renewable ethanol will increase to 7.7 billion litres per year in 2030 before levelling out and decreasing slightly to 7.4 billion litres per year in 2032.

According to ePURE, the outlook compiles both recent statistics and projections for the EU27 production, consumption, and trade of agricultural products.

For biofuels, the report notes that while petrol and diesel consumption are expected to decrease by 18% and 21% respectively in 2032 compared to the 2020-2022 average, increasing biofuel blending rates will hold up demand for biofuels during this period.

To achieve this, more EU countries could introduce E10 (with up to 10% renewable ethanol) as the standard petrol grade. Already 15 EU countries plus the UK have adopted the standard.

According to the Commission figures, corn will remain the main feedstock used in the EU for ethanol production by 2032, followed by wheat and sugar beet, while the share of waste and residues in the feedstock mix will grow from 7% to 15% between 2022 and 2032.

The outlook also foresees a decrease in EU protein demand of 4.7%, but the demand for medium-protein feed, feed with an average protein content of 27% (such as ethanol co-product DDGS) will remain stable and even slightly increase.

The report also expects EU imports of ethanol to remain stable while exports will grow at 3.3% annually.

With petrol and hybrid cars continuing to make up an important part of the EU automobile fleet, it’s clear renewable ethanol has a vital role to play in transport decarbonisation – an immediate, cost-effective, sustainable and socially inclusive emissions reduction solution.

By biofuels international, January 19, 2023