After months of skepticism, traders seem to have finally realized that OPEC+ is serious about keeping crude oil supply constrained.

Per the latest weekly data from Reuters, as reported by market analyst John Kemp, traders are buying oil at the fastest rate since 2020. And oil prices are on the rise.

Of course, OPEC is not the only factor behind the change in sentiment among traders. Refinery disruptions in Russia resulting from Ukrainian drone attacks have also had a lot to do with the growing bullishness on oil markets. Recent reports that the U.S. had urged the Ukrainians to stop targeting Russian refineries and the Ukrainians’ refusal to do so probably reinforced the effect, too.

There is also the improvement in analysts’ outlooks for the global economy. The picture seems to no longer be as bleak as it was last year, so oil demand projections are improving. A month ago, the International Monetary Fund revised upwards its forecast for the global economy, and so did S&P Global Market Intelligence. So traders are once again buying oil in significant volumes.

According to the Reuters numbers, in the week ending March 19, traders bought the equivalent of 140 million barrels across the six most traded crude and fuel contracts. Crude was the most bought, with 57 million barrels in West Texas Intermediate changing hands during that week along with 55 million barrels of Brent crude.

Escalating geopolitical tension, coupled with a rise in attacks on energy facilities in Russia and Ukraine, alongside receding ceasefire hopes in the Middle East, raised concern over global oil supply,” Nissan Securities analyst Hiroyuki Kikukawa told Reuters in comments on the latest movements in prices.

Yet while geopolitical factors play a big role in day-to-day price swings, the OPEC+ cuts normally have a longer-term effect-once it kicks in, and this time, it took a while.

Saudi Arabia first announced in July that it would reduce the amount of oil it supplies to global markets. Some saw it as insignificant, while others dismissed it as a desperate attempt to prop up the unproppable as prices remained stubbornly stuck within a narrow range below $80 per barrel.

Yet later, the rest of OPEC and its Russia-led partners also joined the Saudis-and prices still remained locked in their range. The factors that kept them there were the same that are now fueling the rally: a pessimistic outlook for the global economy, geopolitical tensions that weren’t affecting oil supply, and general skepticism about demand in the era of the energy transition.

The tide only began to turn this year as the outlook for global GDP began to change, with the first data about 2023 starting to come in. In some places, things were as bad as they seemed, such as the eurozone. In other parts of the world, however, such as the United States, the economy performed better than most expected, sparking hope that this year could be better still. And that shifted traders’ attention from demand to supply.

There had been warnings about shrinking oil inventories amid the OPEC+ cuts but those got little attention until the change in economic outlook. Now, there’s suddenly concern about a deficit that even the IEA acknowledged, after a month ago confidently stating that the oil market was comfortably supplied.

So now prices are on the rise again and Morgan Stanley has already forecast that Brent will hit $90 per barrel later in the year. “Every month that OPEC discipline remains in-place, Brent flat price will likely continue to catch up with where inventories and time spreads already are,” the bank said. It’s safe to say that OPEC discipline will remain in place for quite a while yet.

By Oilprice / Irina Slav – Mar 26, 2024

This is the first of a three-part series on emerging energy sources and Texas’ role in developing them. You can read part two, on geothermal energy, here, and part three, on nuclear energy, here.

JEFFERSON COUNTY — A concrete platform with fading blue paint marks the birthplace of the modern oil and gas industry in southeast Texas. Weather-beaten signs describe how drillers tapped the Spindletop oil well in 1901, a discovery that launched petroleum giants Texaco, Mobil and Gulf Oil.

Nearby, a red pipeline traces a neat path above flat, gravel-covered earth. French company Air Liquide started building this unassuming facility, with a wellhead and other machinery, on the iconic site in 2014 to store what it believes will be key to an energy revolution: hydrogen.

The ground that once released millions of barrels of oil now holds some 4.5 billion cubic feet of highly pressurized hydrogen. The gas is contained in a skyscraper-shaped cavern that reaches about a mile below ground within a subterranean salt dome.

Hydrogen promoters see the gas as a crucial part of addressing climate change. If it’s produced in a way that creates few or no greenhouse gas emissions, it could provide an eco-friendly fuel for cars, planes, 18-wheelers and ships, and could power energy-intensive industries such as steel manufacturing. Hydrogen emits only water when used as fuel in fuel cells; burning it directly can create nitrogen oxides, which can create haze and acid rain..

If companies can produce clean hydrogen at a price that’s competitive with gasoline or diesel, supporters say it would revolutionize the fuel industry.

That’s a big if.

Hydrogen is among the most common elements in the universe, but on Earth it’s typically found bonded with something else, such as carbon. Today, hydrogen is often obtained by isolating it from methane, a mix of carbon and hydrogen that is the main component of natural gas. This process leaves behind carbon dioxide, which worsens climate change if released into the air.

Engineers say it’s possible to clean up that process by catching the extra carbon dioxide and reusing it — to get more oil out of a well, for example — or injecting it into the earth to store it. Another less polluting method is to split hydrogen from water, which is made up of hydrogen and oxygen, using electricity generated by wind, solar or nuclear power.

Texas has emerged as a leader in producing hydrogen the cheaper way using abundant supplies of natural gas without capturing the carbon dioxide. Air Liquide makes hydrogen at facilities along the state’s coast, from Beaumont to Corpus Christi. More than 100 miles of pipelines move that hydrogen to companies that buy it for processes such as removing sulfur from crude oil.

Little hydrogen is made from gas with carbon capture or from water in the state — or the rest of the country.

Some academics, policy advisers and companies that make hydrogen say Texas and the Gulf Coast should be where hydrogen created with fewer emissions takes off. A majority of the country’s hydrogen pipelines are already here, Texas’ petrochemical workers have skills that easily transfer to hydrogen production — which involves chemical reactions — and the state has the natural gas and renewable energy needed to produce it.

“We can be the breadbasket for not only the U.S. but for the world in providing hydrogen,” said Bryan Fisher, a managing director with RMI, a nonprofit that supports the clean energy transition.

But producing enough hydrogen cheaply, building the pipelines to move it and the subterranean caverns to store it and finding the customers to buy it requires companies to take some financial risk.

That effort is getting a boost from the federal government, which is offering billions of dollars’ worth of tax credits to kick-start production of hydrogen from gas with carbon capture or water. The government also plans to divide as much as $7 billion among seven regional clusters of projects to build hydrogen infrastructure, including up to $1.2 billion for projects in Texas and Louisiana that plan to make hydrogen largely from natural gas.

Competing to break into the industry are traditional fossil fuel companies, including Chevron and ExxonMobil. Hydrogen advocates say interest by the oil giants is good because they have the money and expertise to tackle such an ambitious project.

But environmental groups doubt that fossil fuel companies can make hydrogen from natural gas as cleanly as they say they can. They worry the federal funding will prop up oil and gas companies, when the emphasis should be on making hydrogen from water or creating clean power another way.

“Producing hydrogen from natural gas is not clean, not low-carbon and cannot and should not be considered a solution in our efforts to solve the world’s worsening climate change crisis,” David Schlissel, the co-author of a report from the Institute for Energy, Economics and Financial Analysis, said in a webinar.

Sitting in a mobile office at the Spindletop site, Katie Ellet, president of hydrogen energy and mobility for Air Liquide, urged critics not to be so puritanical about hydrogen production. She described hydrogen as part of a centuries-long evolution toward progressively cleaner fuels: coal replaced wood, then oil replaced coal.

Ellet believes now is hydrogen’s Spindletop moment. She believes the technology, economics and interest are in place to allow the industry to boom.

“We transition through these different energy cycles,” Ellet said. “And we’ve gotten better. We’ve learned, and we’ve gotten better. This is us … evolving into that next generation.”

Hydrogen hype grows in Texas

One weekday in October, Brian Weeks, senior director of business development at GTI Energy, walked onto a Houston hotel’s conference room stage to discuss hydrogen. GTI Energy used to be known as the Gas Technology Institute and researched natural gas. Now it promotes low-carbon energy.

Weeks faced a standing-room-only crowd at the Hydrogen North America event. He remembered when, maybe a decade earlier, only seven people at a conference showed up to hear him speak on the topic.

People have predicted hydrogen was about to take off before. Weeks worked on the idea off and on since the late 1990s, when he was at Texaco and the company believed hydrogen could power cars. At the time, they worried energy prices would keep rising. Weeks recalled it as a heady time for hydrogen, with actors from the hit TV series Baywatch starring in promotional videos.

But hydrogen didn’t catch. Technology for producing it remained expensive, while oil production instead got a giant boost. Hydraulic fracturing technology allowed the United States to rapidly increase how much oil it produced.

Still, Weeks wouldn’t have spent so much of his life on hydrogen if he didn’t believe it had a future, he said. Like Ellet, he said the circumstances feel different now. That’s in large part because of the federal government’s big investment: By 2030, the Biden administration wants America to produce 10 million metric tons per year of hydrogen made from water using renewable energy or from gas using carbon storage — about how much is produced now largely from gas without carbon capture.

“It’s been a roller coaster, really, for the last at least 20 years,” Weeks said in an interview.

Over the past few years, Weeks has helped a coalition of businesses, researchers and others apply for the federal funding earmarked in the 2021 Infrastructure Investment and Jobs Act for regional hydrogen projects, called “hydrogen hubs.”

Nine projects centered in Houston sought money as a single hub, and on Oct. 13, the Department of Energy announced that they and six other applicants from across the country won. As part of the Houston group, Chevron wants to make low-carbon hydrogen and ammonia, which is used in fertilizer. ExxonMobil wants to build hydrogen pipelines and fueling stations for trucks.

The Gulf Coast projects aimed to produce more than 1.8 million metric tons of hydrogen per year, more than any of the other winning hubs. Some 80% would be made from natural gas.

Local and state leaders are cheering on the industry’s growth. Brett Perlman, CEO of the nonprofit Center for Houston’s Future, supported the hydrogen hub effort. Perlman’s job is to consider Houston’s economy and what will happen to it as the world works to address climate change and wean itself off fossil fuels.

Perlman wrestles with how to make Houston the low-carbon energy capital of the world. He speaks at conferences, too, to build the case that hydrogen should be part of maintaining the city’s success.

“The energy transition is going to happen, and Houston will have a role,” Perlman said at his office. “The real question is can Houston be, continue to be, a leader?”

Back at the same conference where Weeks spoke, Texas Public Utility Commissioner Lori Cobos, whose agency regulates the electricity industry, explained that because it has huge natural gas reserves and is a top producer of wind and solar energy, Texas is “uniquely positioned to be a national and global leader in hydrogen.”

The easy path to selling hydrogen made in these new ways would be to start by converting places already using hydrogen for purposes such as making fertilizer, refining petroleum and treating metals. But even more environmental benefits would come if it could also be used in new applications, said John Hensley, vice president of markets and policy analysis for the industry advocacy group American Clean Power Association.

Hydrogen believers envision the fuel could decarbonize industries that are considered hard to electrify. Hydrogen would power planes and trucks that heavy electric batteries would slow down. It would supply the high heat needed to make cement that electricity could not provide.

The new federal tax incentives get hydrogen close, if not all the way, to being able to compete with fossil fuels on price, said Fisher of RMI. The government plans to pay up to $3 per kilogram of what it defines as clean hydrogen, such as that made from water, or up to $85 per metric ton of stored carbon dioxide that’s captured after making hydrogen from natural gas.

With the subsidies, producing hydrogen from water would cost generally from $4 to $6 per kilogram, and producing it from natural gas would cost generally from $2 to $4, Fisher said. He stressed that it would depend on the specifics of the project. The government’s goal is to get the cost to $1 per kilogram for both types.

Environmental groups and critics raise concerns 

The hydrogen solution does not sound so promising to environmental groups, especially when it comes to making it from natural gas using carbon capture. A number of critics came together in a windowless Houston conference room of their own later in October to build the case to journalists that carbon capture in hydrogen production shouldn’t be seen as a way to address climate change but instead as a boost to the oil and gas industry.

“This is not a transfer off of fossil fuel dependency,” said Jane Patton, campaign manager for U.S. fossil economy at the Center for International Environmental Law. “This is a perpetuation of fossil fuel dependency.”

With money from the Rockefeller Family Fund, which has an initiative focused on slowing oil and gas production because it drives climate change, organizers brought in the big guns to tell the other side of the story. The day began with a speech from Bob Bullard, founding director of the Bullard Center for Environmental and Climate Justice at Texas Southern University, known by many as the father of environmental justice.

Bullard has passionately told many versions of the same narrative. He pioneered his environmental justice work decades ago when he highlighted that the city of Houston primarily built its trash incinerators and landfills in Black neighborhoods. And he brought attention to one example after another of companies polluting poor communities of color rather than wealthy, white ones.

Now a member of the White House Environmental Justice Advisory Council, Bullard said he’s seen no proof that a build-out of hydrogen and carbon storage will be any better for local communities than the expansion of the petrochemical industry was over the past century, bringing more pollution than benefits to surrounding communities. He continued to call for a federal study to find out whether hydrogen production with carbon capture is safe for the people who live around it.

“You’re asking the same people to sacrifice in the same way,” Bullard said at the event. “Can we trust the oil and gas industry to be truthful? I don’t have to write a book on that. We know the answer.”

Schlissel, the director of resource planning analysis for the Institute for Energy, Economics and Financial Analysis, believes the government is using a badly built model to judge how clean hydrogen projects are when they’re evaluated for federal support.

One problem is that the model inappropriately leaves out the fact that hydrogen pipelines could leak, Schlissel says. Hydrogen can react with the molecule that breaks down harmful methane in the atmosphere and make the methane last longer, contributing to climate change.

Schlissel also says the model assumes companies can catch a lot of carbon dioxide — which he believes is totally unrealistic. While companies using carbon capture technology don’t typically publicize their capture rates, Schlissel and his colleagues dug up what they could and concluded that the technology was far short of where it needs to be.

Speakers at the event also expressed little confidence in the Railroad Commission of Texas, which regulates the state’s oil and gas industry, to regulate hydrogen pipelines and underground storage. Commission Shift, a watchdog group that calls for reforming the Railroad Commission, says the agency has a poor track record when it comes to protecting Texans from explosions, leaks and other problems with wells and pipelines.

In a statement, commission spokesperson Patty Ramon said the agency has “protected public safety and the environment for more than a century.” The agency does pipeline inspections regularly and has exceeded Legislative performance goals, Ramon added.

These advocates are up against wealthy, politically powerful companies that say making hydrogen from natural gas with carbon capture is a ready solution to start lowering how much carbon dioxide escapes into the atmosphere — even if it’s imperfect.

“I find this polarization of seeking perfect at the expense of very good is problematic,” Chris Greig, a senior research scientist with the Andlinger Center for Energy and the Environment at Princeton University, said in an interview.

“And, to be clear, the distrust (of oil and gas companies) is not unwarranted, right? There’s been some wrongs done,” Greig added. “But somehow we have to set that aside and find some sort of middle ground.”

BY texastribune / Emily Foxhall, MARCH 25, 2024

Carbon capture and storage (CCS) could become a vital solution to hlping reduce carbon emissions. This means it has the potential to be a massive commercial opportunity.

ExxonMobil (NYSE: XOM) sees CCS growing into a $4 trillion global market by 2050, while Occidental Petroleum (NYSE: OXY) believes it could become a $3 trillion to $5 trillion global industry. That’s leading those oil giants to invest heavily to capture this emerging and potentially very lucrative opportunity.

Fellow oil giant Chevron (NYSE: CVX) also wants to capture a slice of the global CCS market. It recently signed an agreement to evaluate a potential CCS solution for Japan. Here’s a look at some of the projects these oil stocks have under development.

Another step toward its lower carbon ambitions

Chevron signed a memorandum of understanding with Japan’s JX Nippon Oil & Gas Exploration to evaluate exporting carbon dioxide from Japan to storage projects in the Asia-Pacific region. The companies will study the feasibility of building a CCS value chain, including capturing the greenhouse gas from industrial sources in Japan, including affiliates of JX, and transporting it by ship to storage sites operated by Chevron in Australia. The partners would also evaluate other potential storage sites throughout the Asia-Pacific region.

CCS represents a potential win-win solution for Chevron and other energy and industrial companies. It could enable them to continue operating their legacy businesses for decades to come while reducing the impact fossil fuel usage has on the environment.

Chevron has committed to spending $10 billion on lower-carbon investments and projects by 2028, including CCS, hydrogen, and renewable fuels. The company is developing several potential CCS projects across the Americas and Asia-Pacific region. For example, it’s part of a joint venture aiming to develop Bayou Bend, one of the large carbon storage projects in the U.S. It’s also part of joint ventures evaluating massive offshore greenhouse gas storage projects in Australia that encompass subsurface areas the size of Denmark.

A step behind the leaders

Most of Chevron’s projects are still in the evaluation stages. That puts it at risk of falling behind rivals Exxon and Occidental Petroleum, which have projects under construction secured by commercial contracts.

Occidental is currently building the world’s largest direct air capture project in Texas, which will be capable of capturing 500,000 tons of carbon dioxide per year from the air. The company formed a joint venture with a fund managed by BlackRock, which will invest $550 million into the project. The Stratos project is already under construction and should begin commercial operations next year. Occidental is commercializing the facility by selling carbon credits to several customers.

Exxon is taking a different approach. It focuses on transporting and storing carbon dioxide captured directly at the emissions source.

In 2022, Exxon signed a landmark commercial agreement with CF Industries to capture and permanently store 2 million metric tons of carbon dioxide annually from its manufacturing complex in Louisiana starting next year. Exxon will transport the gas via pipelines operated by EnLink Midstream to a sequestration site the oil giant is developing. Exxon has gone on to sign several additional commercial agreements with large industrial customers.

In addition, it paid nearly $5 billion to buy Denbury Resources, primarily for its carbon dioxide pipeline infrastructure. Exxon now has the largest owned and operated carbon dioxide pipeline network in the country. It also has access to 15 strategically located onshore storage sites in the country.

Exxon and Occidental Petroleum believe their CCS businesses could be huge moneymakers. Occidental thinks it could eventually generate as much earnings and cash flow from these operations as it currently does from producing oil and gas. Meanwhile, Exxon believes CCS could be a multibillion-dollar annual revenue stream. Further, long-term contracts will serve as the commercial foundation of the business, which will supply Exxon with more predictable cash flow than it produces from oil and gas.

Looking for ways to capture a slice of this enormous opportunity

Chevron continues to evaluate potential CCS projects. The oil giant wants to find commercially viable opportunities that would benefit the environment and its business. While it currently lags behind leaders Exxon and Occidental, the opportunity is so potentially vast that there’s plenty of room for Chevron to secure needle-moving opportunities. That upside adds to its long-term investment appeal.

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By: The Motley Fool, Wednesday March 20, 2024 

Oil prices likely will trade at about $85-$90 a barrel in the third quarter even if OPEC+ producers and allies decide not to extend current supply cuts, said Gunvor Group Ltd.’s global head of research and analysis.

If Saudi Arabia and allies extend cuts beyond the second quarter, that could send prices even higher, Frederic Lasserre said during the CERAWeek by S&P Global conference in Houston. Cuts beyond the second quarter currently are not planned.

Ample supplies largely have kept international oil prices in the range of $80 a barrel this year even as conflict in the Middle East disrupts regional shipping and Russia’s war with Ukraine escalates.

Read More: Gunvor Says Drones Shut 600,000 Barrels of Russian Refining

“The Saudis have no choice but to switch back into this swing-producer kind of role and try to manage supply at very short term if they want to stabilize prices around $80,” Lasserre said.

Prices remain vulnerable to spikes, especially as geopolitical risks are elevated with two wars and disruptions at vital trade routes at the Panama Canal and Red Sea, Lasserre and Trafigura Group’s global head of oil Ben Luckock warned. 

Meanwhile, oil demand from China is expected to increase by about 700,000 barrels a day this year, representing about 50% of total global demand growth this year, Lasserre said. 

By: Bloomberg News / Devika Krishna Kumar, Mar 19, 2024

Slower-than-expected power sales growth hits net carbon intensity target

Targets 15%-20% Scope 3 emissions cut by 2030 from oil products vs 2021

Comes amid focus on growth of low-carbon fuel sales such as SAF, hydrogen

Shell weakened its main 2030 carbon reduction target March 14 but said it remains focused on net-zero emissions by 2050, despite a slower pace of power sales growth amid an ongoing shift away from traditional oil-based fuels.

In the first update to its main energy transition targets since 2021, Shell said it will target a 15%-20% cut in the net carbon intensity of its energy products by 2030 compared with 2016 levels. It had previously aimed for a 20% cut by 2030. The company said it now plans to reduce the net carbon intensity of the energy products it sells by 9-12% by 2024, 9-13% by 2025, 15-20% by 2030, and 100% by 2050.

In line with our shift to prioritizing value over volume in power, we are concentrating on select markets and segments,” Shell said. “One example is our focus on commercial customers more than retail customers. Given this focus on value, we expect growth in total power sales to 2030 will be lower than previously planned.”

Europe’s biggest integrated energy major also scrapped a 2035 target of a 45% reduction in net carbon intensity, citing “uncertainty in the pace of change in the energy transition.”

But Shell set itself a new target to cut the carbon emissions from the use of its oil products by 2030 as it sells less gasoline and diesel and ramps up production of low-carbon products such as biofuels and hydrogen.

Shell said it plans to reduce customer, or Scope 3, emissions from the use of its oil products by 15%-20% by 2030 compared with 2021 levels. The cut would mean a fall of more than 40% in Scope 3 emissions from its oil products compared with 2016 levels, Shell said.

“Achieving this ambition will mean reducing sales of oil products, such as petrol and diesel, as we support customers as they move to electric mobility and lower-carbon fuels, including natural gas, LNG and biofuels,” Shell said in its latest energy transition strategy.

Operating emissions

Under its previous energy transition targets, Shell was planning to reduce its production of traditional fuels by 55% by 2030 as it provides more low-carbon fuels such as biofuels for road transport and aviation, and hydrogen. Shell is also shrinking its global refining footprint to four core, integrated energy and chemicals sites by repurposing its remaining refineries.

Like many of its energy major peers, Shell plans to grow its production and sales of biofuels in the coming years, including premium biofuels such as sustainable aviation fuel, renewable diesel and renewable natural gas. Shell is already one of the world’s largest energy traders and blenders of biofuels, selling more low-carbon fuels than it produces. In 2023, around 9.7 billion liters of biofuels went into Shell’s road fuels worldwide, compared with 9.5 billion liters in 2022, according to the company.

Shell estimates that some 15%-20% of its total oil products are used for non-energy products such as lubricants and chemical products, which do not generate Scope 3 emissions.

On its central emission targets, Shell said it continues a drive to halve emissions from its operations (Scope 1 and 2) by 2030, compared with 2016 on a net basis. By the end of 2023, Shell said it had achieved more than 60% of this target and reduced the net carbon intensity of the energy products it sells by 6.3% compared with 2016, the third consecutive year it hit the target.

However, Shell maintained its overall target of achieving net-zero emissions by 2050 across all its operations and energy products to help support the Paris Climate Agreement goals.

“Today the world must meet growing demand for energy while tackling the urgent challenge of climate change,” CEO Wael Sawan said in a statement. “I am encouraged by the rapid progress in the energy transition in recent years in many countries and technologies, which reinforces my deep conviction in the direction of our strategy.”

Shell also confirmed it will invest $10 billion-$15 billion between 2023 and the end of 2025 in low-carbon energy solutions, which include spending on business lines such as electric vehicle charging, biofuels, renewable power, hydrogen and carbon capture and storage.

LNG, carbon credits

The energy major’s net carbon intensity in 2023 fell to 74 grams of CO2e/Megajoules, down by 2.6% and 6.3% from 2022 and 2016, respectively.

This fall was mainly achieved through a reduction in the average intensity of power sold and the use of carbon credits.

Most oil companies do not have Scope 3 emissions targets but instead have set net carbon intensity metrics.

Carbon intensity is seen as a less ambitious measure as net emissions can simply be lowered by selling more clean energy alternatives such as wind or solar power.

As it looks to expand its LNG business by 20%-30% by 2030 it will focus on reducing the carbon intensity of these operations, it added.

In its LNG joint venture in Canada, it plans to use use natural gas and renewable electricity while in the North Field Expansion project in Qatar it hopes to use CCS.

“We expect LNG will play a critical role in the transition,” said Sawan. “It continues to provide a secure supply of energy in many European countries. It also offers flexibility to electricity grids as wind and solar power grow, and opportunities to lower carbon emissions from industries such as cement and steel by replacing coal.”

Shell is an active participant in the voluntary carbon markets and in 2023, its net carbon intensity accounted for 20 million carbon credits, of which 4 million were linked to the sale of energy products, it said.

By: spglobal / Robert Perkins, 14 Mar 2024.

Investments in new oil production have been stalling since about 2014. This has led many to suggest that higher prices for longer are on the cards, supported by anti-oil industry energy policies in key jurisdictions that are home to the largest private producers.

Yet a case might be made that although lower, the oil industry’s investments over the past decade have become better targeted at prospects with a good chance of a discovery. Either that, or they have become luckier than usual. Nowhere is this clearer than in Africa.

Earlier this month, French TotalEnergies said that it would buy a 33% stake in an exploration block offshore South Africa. Its partner QatarEnergy was also taking part in the acquisition in Block 3B/4B, with a 24% interest. The acquisition is part of the French supermajor’s exploration campaign in South Africa’s neighbor Namibia, which shares the Orange Basin with South Africa.

The Orange Basin has recently become something of a hot spot rivaling Guyana. The last couple of years have seen a string of discoveries revealing reserves estimated at around 5 billion barrels so far. And the rate of success has been unusually high, with 15 confirmed discoveries of commercial volumes of hydrocarbons in 17 exploration wells drilled since February 2022, per the Financial Times.

The largest discovery so far was made by TotalEnergies in the Venus field offshore Namibia, with estimated reserves of 3 billion barrels. No wonder the company is expanding in the area—even as forecasts for peak oil demand persist.

“Following the Venus success in Namibia, TotalEnergies is continuing to progress its Exploration effort in the Orange Basin,” the senior vice president for exploration at the French company, Kevin McLachlan, said last week, following the news of the South Africa investment.

“South Africa’s side of the Orange Basin resembles those of Namibia, it is highly prospective with at least two prospects in the northern region of the basin potentially containing millions of barrels of oil and associated gas,” according to Jonathan Salomo, who is the lead geologist for the West coast of South Africa at the country’s Petroleum Agency.

TotalEnergies and QatarEnergy are not alone in their pursuit of Africa’s hitherto untapped oil and gas riches. In January this year, a Canadian company specifically focused on Africa and named accordingly—Africa Oil Corp—completed the  purchase purcha of additional acreage in the same Orange Basin block that TotalEnergies and the Qatari state oil company are planning to expand into.

The block is estimated to contain prospective resources equal to some 4 billion barrels of oil equivalent, Offshore Energy reported back in January, with success probability ranging between 11% and 39% for the 24 prospects in the block.

Southern Africa is a hotspot, then, but it is not the only one in Africa. Offshore Energy again reported this month that a Houston-based energy company had struck a deal struck a deal to buy a Swedish exploration player to gain access to an offshore block in the Ivory Coast.

The target company, Svenska Petroleum Exploration, holds a 27% stake in the Baobab field offshore the Western African country that is most famous for its cocoa. The Baobab field is a producing one, yielding some 4,500 gross barrels of oil equivalent daily, with plans to expand this and extend the productive life of the field.

Oil is not the sole focus of international investors, either. Liquefied natural gas has become a priority for many as Europe joined the big buyers’ club two years ago, providing a huge boost to exploration, including in Africa, which already produces some LNG but could produce a lot more.

The Greater Tortue Ahmeyim LNG project, for instance, is about to enter operation in the third quarter of this year. Located on the border between Senegal and Mauritania, the project is led by BP in partnership with Kosmos Energy and the state energy companies of the two countries. GTA LNG will have an annual capacity of 2.3 million tons initially, to be expanded to 10 million tons over three phases.

Next year could also see the pre-final investment decision on the Tanzania LNG terminal, which aims to tap the country’s offshore gas resources. The price tag of the project is $42 billion and it is being developed by an all-star cast including Equinor, Shell, and Exxon. The capacity of the project is seen at a minimum of 10 million tons annually, potentially turning Tanzania into a sizeable player in the LNG market.

Oil and gas exploration in Africa is booming, in part because the continent contains a lot of the hitherto undiscovered global hydrocarbon reserves and in part because local governments appear to be a lot more open to the idea than the governments in Big Oil’s home countries and nearby jurisdictions.

Wood Mackenzie calculated last year that the energy industry is investing a total $800 billion in African oil and gas. The investment cycle began in 2010, the firm’s upstream research director said at an industry event in October, and will end with Africa emerging as a leading producer of LNG from floating terminals and a growing source of deepwater oil.

By Oilprice.com / Irina Slav, March 12, 2024

Hydrogen is traditionally used to produce methanol and refine petroleum. Currently, around 51% of hydrogen used in the economy goes to refineries, and 43% is used as an input for ammonia synthesis, primarily for production of fertilizers.1 The most common process for producing hydrogen is steam methane reforming. Fossil fuel-based, it consumes around 6% of the world’s natural gas and 2% of its coal.

However, this is changing as the production of green hydrogen (see sidebar) becomes a more viable option, and to some extent, an essential one as fossil fuels become more expensive, more unacceptable due to climate change and a bargaining tool in geopolitical conflicts. The world is looking to more sustainable energy production and ways to reach net zero emissions by the year 2050,2 and using hydrogen as fuel for heavy transport applications like trucks, buses and cars is an increasingly popular topic of conversation. However, using green hydrogen comes with its own challenges, including how to store and transport it and how to test and validate it where no standard testing and

Green hydrogen is used to describe hydrogen gas that is completely carbon-neutral and produced using renewable energy sources in a process called electrolysis. Here are its key characteristics:

1. Renewable energy source: Green hydrogen is produced using electricity generated only from renewable energy sources, such as wind, solar, hydroelectric or geothermal power.

2. Electrolysis: Green hydrogen is produced in an electrolyzer, which uses renewable energy to split water (H2O) into hydrogen (H2) and oxygen (O2) using an electric current.

3. Zero greenhouse gas emissions: Because the electricity used in the electrolysis process comes from renewable sources, the overall carbon footprint of green hydrogen production is minimal or even zero.

4. Versatile applications: Green hydrogen can be used in a wide range of applications, including fuel cell vehicles, industrial processes, electricity generation and energy storage. It can serve as an energy carrier, helping to store and transport renewable energy efficiently.

Sealing & Storage

Achieving a reliable seal involves using advanced materials and engineering techniques that can withstand the challenges posed by hydrogen’s small molecular size, which makes it difficult to seal and store as it can permeate through many materials. For certain applications, sealing materials must demonstrate a high level of compatibility and permeation resistance to prevent loss.

Another related issue is rapid gas decompression (RGD). In a high-pressure system, the small hydrogen molecules can be absorbed into a seal material. If the pressure in the system is suddenly relieved, gas trapped in the seal material can expand to match the new ambient pressure, potentially causing the seal to blister and crack as the gas tries to escape.

Finally, seals for different hydrogen systems need to withstand seriously tough environments, including high pressures of up to 14,504 pounds per square inch (psi) (e.g., in high-pressure valves) and extreme low temperatures down to -418 F (e.g., in liquid hydrogen storage and transportation).

Hydrogen: The Facts (Sidebar)

Hydrogen is a gas with an average atomic mass of 1.00794.

It is the first and most abundant element on the periodic table.

It is a constituent of most organic compounds, making up about 75% of the universe’s overall mass.

Hydrogen is colorless, odorless and tasteless.

The lightest of all elements, hydrogen consists of the smallest of all molecules, which means it can permeate through many materials.

Hydrogen is rarely available in its pure form on Earth, so it requires extraction from compounds containing hydrogen. Any compound with ‘H’ in its chemical formula has hydrogen as one of its constituents.

It is in hydrocarbons, methane (CH4) and water (H2O).

Setting the Standard

The evolving nature of the hydrogen market and value chain creates a demand for fuel storage standards. Experts are looking to existing standards for similar storage applications such as those used for oil and gas, which define acceptable characteristics for polymers in arduous conditions relative to permeation, RGD and general media compatibility. However, no existing standards provide a perfect fit, because they do not account for the conditions seen in typical applications throughout the hydrogen value chain.

Hydrogen is an explosive gas, and it must be tested with great care. Many seal manufacturers use third-party testing facilities. Helium is often used as a proxy for safer testing, and results are converted to hydrogen values. However, helium is not a perfect substitute, and some companies are investing in their own rigs that are approved to test hydrogen. These facilities offer comprehensive, hydrogen-specific standards and validation processes, and their experts can create custom solutions for whatever the user needs.

Seals are tested to International Organization for Standardization (ISO) 17268 for RGD, EC79 for components intended for hydrogen-powered vehicles, SAE J2600 for fueling connectors, nozzles and receptacles of compressed hydrogen surface vehicles, along with some permeation testing. Other tests include verification for a wide range of static sealing cross sections, including cyclic pressure, with pressure ranges from 101 to 10,877 psi and temperature ranges
from -65 F to 266 F.   

The current and future market needs for hydrogen sealing across the entire value chain production, transportation, storage and end use are broad, ranging from standard components to highly engineered solutions. Few OEMs have extensive experience in these areas, making a hydrogen component and sealing partner essential.

 By: pumpsandsystems / James Simpson, 03/12/2024.

Europe is pivoting away from Russian natural gas to hydrogen. Germany’s role will be key.

In Ancient Rome, roads converged on Italy. In 21st-century Europe, new hydrogen pipelines to ensure European energy security will lead to Germany.

The corridors represent a grand endeavor designed to facilitate the production, importation, and transportation across Europe of hydrogen. They will form the backbone of a revolutionary pivot away from dependence on Russian gas. Hydrogen can complement intermittent renewable sources such as wind and solar power, providing a reliable energy supply.

The goal is ambitious: to enable the transportation of a total of 20 million tons of this gas per year by 2030. Six supply corridors that would be directly or indirectly connected to Germany. These corridors consist of pipelines, production and storage facilities, port terminals, and shipping lanes across seas, rivers, and land. Initially, the corridors will connect local supply and demand in different parts of Europe, before expanding and connecting Europe with neighboring regions. One of them, the Central European Hydrogen Corridor (CEHC), would pump this gas from Ukraine.

Germany needs an alternative to gas, given its large energy-intensive industries and its plans to phase out coal and lignite plants. H2 MOBILITY Germany is building a nationwide network of hydrogen filling stations. Gasunie and Thyssengas are setting up this gas’s transportation infrastructure connecting Germany’s North Sea coast with the industrial Ruhr Valley. This “hydrogen core network” aims to repurpose existing gas infrastructure and is meant to be completed by 2032.

Despite this progress, Germany’s ambitious energy plans still must overcome serious obstacles. Hydrogen can cause embrittlement in certain materials such as steel and cast iron out of which natural gas pipelines are typically made, leading to safety risks and pipeline degradation. Careful selection of pipeline materials, coatings, and design are required to mitigate this risk.

Another challenge is building out Europe’s hydrogen production capacity – while avoiding being undercut by China. Electrolyzers use electricity to split water into hydrogen and oxygen. Europe has traditionally held a strong position in the electrolyzer manufacturing industry, home to six out of the ten largest electrolyzer manufacturers. But Europe also used to be the world’s leader in solar power manufacturing, until cheap Chinese panels swept the market. Europe’s hydrogen strategy aims to maintain the region’s competitive strengths in electrolyzer manufacturing.

Investment and innovation also are required to boost hydrogen storage. New solutions such as underground caverns or innovative hydrogen carriers are needed.

If these challenges are met, demand for hydrogen will skyrocket. Germany alone will need to import around 50% – 70% of the energy it needs, forecast at 95 – 130 TWh in 2030. Denmark is eyeing production of 6GW, with most of the production exported to Germany via a hydrogen pipeline that will be operational in 2028. The UK’s leading electrolyzer manufacturer ITM Power, has set up a production site in Germany to bypass post-Brexit regulatory hurdles. Other countries might follow suit. Germany’s growing demand for hydrogen could incentivize hydrogen producers and exporters in my homeland, Poland.

Germany’s ambitious hopes could suck in imports from friendlier countries such as Namibia, Oman, or Kazakhstan, for which some of Europe’s hydrogen corridors are designed. By leading the way in hydrogen innovation and deployment, Germany can influence international standards and regulations.

Hydrogen is destined to play a pivotal role in Europe’s green transition. If Germany dominates, Berlin will gain great sway over the continent’s energy policy, worrying some neighbors But Germany’s central location makes it fit to serve as a hydrogen hub. It has the political will and economic strength to drive a European hydrogen revolution. Success will foster an interconnected, resilient European energy system, free of Russian influence.

Maciej Filip Bukowski is a 2022 CEPA James S. Denton fellow, a 2023 International Republican Institute Transatlantic Security Initiative fellow, and currently a senior international analysis expert at BGK, a Polish development bank. A graduate of Sorbonne and Cornell law schools, he is completing a Ph.D. thesis at the Jagiellonian University on the geopolitics of climate change.

Bandwidth is CEPA’s online journal dedicated to advancing transatlantic cooperation on tech policy. All opinions are those of the author and do not necessarily represent the position or views of the institutions they represent or the Center for European Policy Analysis.

By Maciej Bukowski, March 12, 2024

Hydrogen is a gas with an average atomic mass of 1.00794.

It is the first and most abundant element on the periodic table.

It is a constituent of most organic compounds, making up about 75% of the universe’s overall mass.

Hydrogen is colorless, odorless and tasteless.

The lightest of all elements, hydrogen consists of the smallest of all molecules, which means it can permeate through many materials.

Hydrogen is rarely available in its pure form on Earth, so it requires extraction from compounds containing hydrogen. Any compound with ‘H’ in its chemical formula has hydrogen as one of its constituents.

It is in hydrocarbons, methane (CH4) and water (H2O) has been a key driver in my portfolio and allowed me to outperform the market since 2020.

During the pandemic, I bought the stock dirt cheap close to $30, when the entire world was buying tech, growth, and alternative investments like crypto and pictures of rocks.

However, I sold Exxon Mobil and shifted my money to peers, like Canadian Natural Resources (CNQ), as I realized I had bet on the wrong horse.

Don’t get me wrong! This article is not going to be a hit job on Exxon or a promotion of my holdings.

After having received countless questions from readers who asked me why I don’t own Exxon anymore, I will use this article to explain why I believe that Exxon is not the right place to be if investors want to bet on higher oil prices.

Nonetheless, I will also explain why I keep a Buy rating on the stock, as it’s not a bad company.

So, let’s get right to it!

When Oil Rises, Exxon Underperforms

While the company may have massive reserves and growth opportunities in markets like Guyana, on top of consistent dividend growth and a credit rating of AA-, it is somewhat stuck in the middle.

The company is not the best place to be for dividend income. Other companies have much more favorable distribution policies.
It’s not as undervalued as other oil companies, in case investors are looking for opportunities with potentially more capital appreciation.
The chart below confirms my case (I’ll give you more details in this article).

Below, we are looking at the ratio between the XOM stock price and the Energy Select Sector ETF (XLE). That’s the black line. The red line shows the price of oil – except that it’s inverted!

In other words, the fact that the XOM/XLE ratio tends to follow the red line over time shows that when oil prices fall, investors prefer XOM. That makes sense, as it comes with a lot of safety, including a balance sheet with an AA- rating.

However, when oil prices rise (the red line drops), XOM performs poorly compared to the XLE ETF.

Also, please bear in mind that Exxon accounts for roughly a quarter of the XLE ETF.

Exxon and Chevron (CVX) combined account for almost 40% of the entire ETF.

Including dividends, XOM has returned 76% over the past ten years, beating the XLE by roughly 28 points.
However, as the lower part of the chart above shows (it’s the XOM/XLE ratio again), outperformance has entirely vanished over the past five years.

The last time XOM was the “best place” to be in energy was between 2014 and 2021.

This period of subdued oil prices put pressure on US shale producers, benefiting XOM as a safe haven in a troubled industry compared to XLE.

Exxon Is Good, But Not Good Enough
With all of this in mind, Exxon isn’t a bad stock. If you have owned Exxon for many years and want to avoid taxes by not selling, I don’t think it hurts to stick around.

After all, Exxon is making progress.

For example, the company is rapidly investing in growth projects.

As we can see above, major projects, totaling $30 billion, were completed on time or ahead of schedule and within budget.

These projects included the Beaumont refinery expansion, the only major refinery expansion in the United States in recent years.

The EIA posted the chart below last year, which shows the significance of this project, especially in light of higher post-pandemic demand and prolonged underinvestment in the industry.

top 10 U.S. refineries by operable crude oil distillation capacity
Energy Information Administration

On top of expanding its downstream (refining) footprint, the company is improving its upstream capabilities (producing oil and gas).

The company has an emphasis on two major basins:

The Permian. This is America’s most attractive basin, with deep reserves and attractive breakeven prices.
Guyana. This country has massive offshore reserves. S&P Global (SPGI) estimates that this nation has more than 11 billion barrels of oil in reserves.
Image
S&P Global

For Exxon, these two projects boast a competitive cost of supply, positioned below $35 per barrel. This ensures profitability even in challenging market conditions.

In these two areas, Exxon is producing more than it initially expected.

So in the Permian, we had guided to 600,000 kind of oil equivalent barrels. We came in at 620,000. In Guyana, we had said 380,000, we came in at 390,000, right? And you think about where we’re at in Guyana today, and we’ve got prosperity, the third boat, which is in the Payara development already up to nameplate capacity as we stand here today. And that’s because we made the decision to drill more wells to ensure that we could get that boat up to capacity as quickly as possible in our organization absolutely delivered on that. – XOM 4Q23 Earnings Call

The company is also working on completing the acquisition of Pioneer Natural Resources (PXD), a deal I discussed in this article.

Exxon expects significant synergies from the acquisition, particularly in terms of increased resource recovery and capital efficiency. By combining resources and expertise, Exxon Mobil aims to unlock additional value and drive sustainable growth in the Permian Basin.

Essentially, the deal is all about resource recovery in the Permian Basin, an area where PXD has some of the best assets in the Midland.

XOM believes that by applying its development strategy and “operational excellence” to Pioneer’s assets, it can maximize the production of oil and gas from existing reservoirs.

This is very important, as the Permian is slowly moving toward peak production growth, a development that could be very bullish for oil prices, as the shale revolution was the reason why prices were often very subdued.

The Permian is expected to produce a record high 5.974 million barrels per day in February, though that will be the smallest month-over-month growth since July, EIA data showed. – Reuters

On top of that, Exxon is now going after Chevron. Exxon recently filed for arbitration in the International Chamber of Commerce in Paris, as it believes it has a right of first refusal over the Chevron/Hess (HES) deal.

Chevron’s deal to buy Hess amounts to a circumvention of Exxon’s pre-emption rights, Chapman said. While the joint-operating agreement with Hess and other partners in Guyana is confidential, Exxon is “very, very confident” in its position, he said. – Bloomberg

While Exxon will try to buy Hess, it is likely that Chevron will terminate the deal before it comes to that.

Once that happens, it needs to be seen what Exxon will do.

For now, however, the key takeaway is that Exxon is becoming increasingly aggressive in both the Permian and Guyana, as it seems to capitalize on its ability to increase output in an industry that is increasingly focused on capital preservation.

So, what about its dividend?

Exxon has 41 years of consecutive annual dividend increases, making it one of the few Dividend Aristocrats in the industry.

After hiking its dividend by 4.4% on October 27, it now pays $0.95 per share per quarter. That’s a yield of 3.5%.

The five-year dividend CAGR is 2.6%, which is extremely low.
While the company did not cut its dividend during the pandemic, it seems to follow a strategy based on safety.

It knows that if it were to aggressively hike its dividend, it might have to cut once oil prices implode again.

However, instead of using special dividends, Exxon – like its major peers – is using buybacks to distribute cash. While that may benefit the per-share value of its business, it’s not necessarily what income-focused investors are looking for.

Especially in the energy sector, investors tend to be income-focused. I’m one of them.

Over the past three years, XOM bought back 6% of its shares.
This year, the company is expected to generate $32 billion in free cash flow. While this is highly dependent on oil prices, it indicates a free cash flow yield of 7%.

In other words, we can expect total distributions to be close to that number, potentially consisting of 50/50 dividends and buybacks.

Needless to say, that’s also dependent on future M&A and potential investments in growth.

Personally, I am not a fan of the buyback strategy and doubt we’ll see a shift to special dividends.

What I Prefer Instead Of Exxon
Buybacks make sense when a company is very cheap. This applies to a company like Cenovus (CVE), the Canadian integrated oil and gas player that has vowed to distribute all excess cash flow through buybacks in the future. I discuss CVE in this article.

CVE trades at less than 6x operating cash flow (“OCF”).

Exxon trades at a blended OCF ratio of 7.8x. Generally speaking, XOM has enjoyed a higher multiple, as it is simply a more stable business than most oil companies.

Its normalized OCF multiple is 9x, as we can see in the chart below (the blue line).

However, at current prices, I prefer a range of other companies:

Undervalued plays like Cenovus.
U.S. shale producers with a focus on special dividends and a very attractive valuation. In this segment, I like Devon Energy (DVN), which I discuss in this article.
Super-majors like EOG Resources (EOG). I often think of it as an on-shore version of Exxon. EOG uses special dividends to reward investors. I discussed EOG in this article. Especially premium drilling has allowed this company to boost shareholder returns. It now has a base dividend of 3%, a double-digit OCF yield, and a stock price that, I believe, is easily up to 30% undervalued in the current environment. The data in the chart below supports my thesis.
Image

I also prefer plays like Canadian Natural Resources, which just hit its leverage target and has pledged to return 100% of its free cash flow to shareholders.

CNQ is my largest upstream investment.

I also preferred Diamondback Energy (FANG), as it uses special dividends to distribute most of its cash to shareholders.

However, after the recent M&A announcement, the stock is not very cheap anymore, and we may see a focus on debt reduction.

Nonetheless, if FANG comes down, I will buy this one for a number of family accounts, likely also my personal dividend growth portfolio.
Over the next few years, I expect all of these stocks to beat XOM and deliver substantially more dividends – and buybacks.

However, these companies are more volatile than Exxon. Moreover, while CNQ has a somewhat similar volatility profile and a Dividend Aristocrat profile, it has CAD/USD currency risks and tax implications for some investors.

So, all things considered, I like Exxon. However, I do not like it enough to recommend it to the “average” investor looking for oil exposure.

While it certainly has benefits like consistent dividend growth, growth potential in Guyana and the Permian, and diversification through downstream operations, dividend growth is too slow, it’s not extremely cheap to warrant buybacks, and I expect the company to continue underperforming its average peers during oil price rallies.

Takeaway
While Exxon has historically been a stalwart in the energy sector, recent trends suggest it may not be the best bet for investors seeking exposure to higher oil prices.

Despite its solid fundamentals, including substantial reserves and growth projects, Exxon’s performance tends to lag behind during oil price upswings.

Moreover, the company’s cautious approach to dividend growth and reliance on buybacks may not appeal to income-focused investors.

Instead, alternatives like undervalued plays such as Cenovus or U.S. shale producers like Devon Energy offer more attractive prospects for dividend growth and capital appreciation.

While Exxon remains a viable option for some, it may not be the optimal choice for investors seeking elevated returns in the current energy environment.

However, I am giving the stock a Buy rating, as it’s still a good company that will benefit from potentially higher oil prices and measures to improve the business.

Pros & Cons
Reasons to like Exxon:

Historically stable investment in the energy sector.
Massive reserves and growth opportunities in Guyana and the Permian Basin.
Consistent dividend growth for 41 consecutive years.
Diversification through downstream operations.
Reasons to dislike Exxon:

Underperformance during oil price rallies compared to peers.
Slow dividend growth may not appeal to income-focused investors.
Reliance on buybacks instead of special dividends.
XOM is not as undervalued as some alternatives like Cenovus or Devon Energy.
I see a high likelihood of continued underperformance in the current energy environment.

By: seekingalpha / Leo Nelissen ,Mar. 11, 2024

Shell is presently exploring the potential application of Bloom Energy’s solid oxide electrolyser (SOEC) technology to produce hydrogen within its operations.

This endeavor involves a collaborative effort with Bloom Energy to develop scalable and large-scale SOEC systems aimed at generating hydrogen for potential deployment across Shell’s assets. The adoption of these systems is perceived as a crucial advancement that could significantly contribute to decarbonizing various challenging-to-abate sectors.

Hydrogen plays a crucial role in refining processes, serving to enhance the quality of petroleum products and facilitate the processing of diverse crude oils. Currently, the predominant method for hydrogen production in refining relies on unabated fossil fuel processes. Acknowledging the urgent need to mitigate carbon emissions, Shell has been actively exploring electrolyser technology as a means to decarbonize its existing refineries. As part of these efforts, Shell Deutschland secured a 100MW capacity reservation with ITM Power in December 2023 for its proton exchange membrane (PEM) electrolyser stacks, designed for hydrogen production at the Rhineland facility.

The SOEC technology is distinguished by high-temperature electrolysis for hydrogen production. This innovative approach utilizes a solid ceramic material as the electrolyte, enabling water splitting at temperatures of up to 800°C. The elevated temperature significantly reduces the electrical energy input required for the process, rendering it more efficient compared to conventional low-temperature electrolysis methods.

In May 2023, Bloom Energy achieved a noteworthy milestone by commissioning a 4MW SOEC system at a NASA research center in California, United States. During this deployment, Bloom Energy reported that the SOEC system demonstrated the capability to generate 20-25% more hydrogen per megawatt compared to commercially demonstrated low-temperature electrolyser technologies.

Shell plc, headquartered in London, is a British multinational oil and gas corporation. As a significant player in the Big Oil sector, Shell ranks as the second-largest investor-owned oil and gas company globally and stands among the world’s largest corporations across all industries. Shell operates across the entire oil and gas value chain, engaging in exploration, production, refining, transportation, distribution, marketing, petrochemicals, power generation, and trading.

Bloom Energy, headquartered in San Jose, California, is a publicly traded American company. Specializing in solid oxide fuel cells, it manufactures and markets systems capable of onsite electricity generation. Established in 2001, Bloom Energy emerged from stealth mode in 2010. The company’s flagship product is the Bloom Energy Server, a solid oxide fuel cell power generator that operates using either natural gas or biogas as its fuel source.

By: Chem Analyst News/ Motoki Sasaki , March 8, 2024