Tag: Brent Crude

When OPEC+ ministers meet this weekend, they confront the unpalatable choice: continue to curb oil-supplies well into 2025, or risk a renewed price slump.

With oil demand slowing in China and supplies swelling across the Americas, delegates say the group led by Saudi Arabia and Russia is once again discussing delaying their plans to increase production — potentially for several months.

But if OPEC+ wants to prevent a glut, it may need to do much more. A surplus looms next year even if the cartel cancels the supply hikes entirely, the International Energy Agency forecasts. Citigroup Inc. and JPMorgan Chase & Co. warn that prices are already set for a slump from $73 a barrel toward $60 — and lower if the group opens the taps.

Another selloff would spell financial pain for the Saudis, who have already been forced to cut spending on lavish economic transformation plans. And that’s before the oil market reckons with the return of President Donald Trump, who promises to bolster US crude production and threatens punitive tariffs for China.

“I think that there’s no room for them to increase and the market will remind them of that when necessary,” Gunvor Group Co-founder and Chief Executive Officer Torbjörn Törnqvist said at the Energy Intelligence Forum in London on Tuesday. 

Earlier that day, Saudi Arabian Energy Minister Prince Abdulaziz bin Salman met with Russian Deputy Prime Minister Alexander Novak and Iraqi Prime Minister Mohammed Shia Al-Sudani in Baghdad. They discussed the importance of keeping markets balanced and fulfilling commitments to cut production, according to statements from the countries. The whole 23-nation coalition will convene online on Sunday. 

When the Organization of Petroleum Exporting Countries and its partners last gathered almost six months ago, the picture was very different. Confident that the post-pandemic surge in world oil consumption would continue, the group unveiled a road map to restore production halted since 2022, outlining the return of 2.2 million barrels a day in monthly installments from October. 

But things have shifted since then. 

Brent crude futures have slumped about 17% since early July — shrugging off conflict in the Middle East — while demand in China contracted for six months in a row as it grapples with an array of economic challenges. Chinese consumption — which has powered oil markets for the past two decades — may have already peaked, according to the IEA.

Next year, global oil demand will grow by roughly 1 million barrels a day next year — less than half the rate seen in 2023 — as the shift from fossil fuels to electric vehicles gathers pace, the Paris-based agency predicts. 

This will be eclipsed by a tide of new supply from the US, Brazil, Canada and Guyana, leaving an excess of more than 1 million barrels a day, it says.

“The oil market appears to be heading for a sizable surplus in 2025,” said Martijn Rats, an analyst at Morgan Stanley.

The fraught outlook for OPEC+ comes even before oil markets absorb the impact of a second term for Trump, who has promised the US oil industry will “drill, baby, drill,” and warned of brutal trade tariffs on a number of countries, including China. 

Iran and China

Still, forecasts can often go astray, and if oil markets defy bearish predictions it will make OPEC+’s task easier.

Global oil demand continues to surprise to the upside and looks set for strong growth in the next five to 10 years, BP Chief Executive Officer Murray Auchincloss said at a conference in London on Monday.

Oil prices are currently “trying to price in a future supply glut that has yet to arrive,” said Jeff Currie, chief strategy officer for energy pathways at Carlyle Group. The pullback in prices is already eroding the outlook for supply growth, reducing the probability the glut will materialize.

“Nearly all bear markets are demand-driven, and with China front-footed with stimulus, the odds of an unexpected demand shock are limited,” said Currie.

There’s also the possibility that Trump renews the campaign of “maximum pressure” used to choke crude exports from Iran during his first term, in a bid to limit the country’s nuclear program. 

“If Present Trump really goes whole hog, and they take down 1 million to 1.2 million barrels of Iranian oil exports, that would remove oversupply next year,” said Bob McNally, founder of Rapidan Energy Group and a former White House official. “That makes it much easier for OPEC+ to return those barrels.”

But absent a crackdown on Tehran, OPEC+ nations may need to persevere with their cuts. That would be a challenge for several members — notably Iraq, Russia, Kazakhstan and the United Arab Emirates, which have struggled to implement the supply curbs they were supposed to make at the start of this year.

The United Arab Emirates is being allowed to gradually phase in a further 300,000 barrels a day of extra output in recognition of recent increases to its production capacity. There’s no such allowance for Kazakhstan, where the start of a major expansion to the Tengiz oil field may further test its commitment to the OPEC+ deal next year. 

The longer the surplus persists, the greater the possibility that OPEC+ members will eventually tire of quotas and revert to pursuing individual market share, as they did during the policy “resets” of 2014 and 2020, said Natasha Kaneva, head of global commodities research at JPMorgan. 

“Increasing oil production might become a key consideration for some OPEC members in 2026,” when “there is an elevated risk of another market reset,” she said.

by Grant Smith,  Bloomberg / Wednesday, November 27, 2024

John Donigian, Senior Director of Market Strategy at Moody’s, discusses how energy companies can thrive in an increasingly unpredictable global market

Global complexities are presenting unprecedented challenges for energy and utility companies, creating a perfect storm of obstacles.

Regulations are evolving rapidly, environmental risks are escalating and supply chain vulnerabilities have never been more apparent.

Energy companies once again came under scrutiny for their role in the green transition during COP29. However, against this backdrop, supply chains for both renewable and fossil fuel sources are facing extraordinary pressure.

Moody’s, a global leader in credit ratings and integrated risk assessment, offers KYC and AML solutions to help firms identify threats from illicit actors while ensuring regulatory compliance.

When it comes to the energy sector, Moody’s risk assessments enable organisations to navigate complex regulations, manage environmental risks and make informed investment decisions that align with their operational and strategic objectives.

Leveraging comprehensive risk management capabilities, Moody’s enhances supply chain resilience across both traditional and renewable energy sectors.

Here, John Donigian, Senior Director of Market Strategy at Moody’s, discusses how modern energy companies can not only survive but thrive in an increasingly unpredictable global market.

What’s the current regulatory landscape for energy, oil and gas firms? How does it differ for those operating in renewables?

The regulatory landscape for energy, oil and gas firms has become increasingly stringent with the arrival of mandates on emissions, transparency and environmental standards. These sectors face complex compliance demands and heightened third-party risk, given the intricate nature of their supply chains that often function across regulatory jurisdictions.

A key example is the EU’s new Methane Regulation, which came into force in August 2024. The directive seeks to significantly reduce methane emissions from fossil energy production and applies to oil, gas and liquified natural gas (LNG) importers within the EU. It mandates operators establish firm monitoring and reporting procedures on methane emissions.

Firms operating within EU member states are obliged to fulfil these compliance responsibilities — if they fail to meet reporting requirements they face fines of up to 20% of their annual turnover.

Renewable energy firms are subject to a less intense regulatory environment, even potentially benefiting from tax incentives and streamlined permitting processes, such as with the EU’s Renewable Energy Directive. 

However, the sector is still subject to reporting requirements that focus on responsible sourcing and supply chain transparency, which aim to combat greenwashing.

For both sectors, integrated platforms that support compliance and comprehensive third-party risk management are becoming essential, enabling smoother regulatory adherence and mitigating supplier risk across global supply chains.

How can firms, particularly those operating in energy/utilities, best identify and measure risk in their supply chains?

Technological solutions are key to staying on top of supply chain risk. Energy companies can manage their compliance processes much more effectively with the help of advanced data tools, which help map out dependencies in the supply chain and model potential disruptions before they happen. 

Automated solutions also make it easier to create detailed risk profiles that are continuously updated with factors such as jurisdictional anomalies, shell companies and sanctions risk exposure.

Similarly, advanced analytics platforms, which centralise the data compliance professionals need to conduct risk assessments, provide a unified view of risk. 

This means companies can keep a close eye on suppliers and identify risks early on to act swiftly, ensuring they remain aligned with regulations, meet contract terms and build better resilience. 

How can these risks be avoided?

Energy and utility companies can avoid supply chain risks by diversifying their supplier base, maintaining strategic inventory buffers and investing in real-time monitoring to detect potential disruptions at early stages. 

Each step provides a barrier against supply-chain failures, from reducing reliance on any single entity and their associated risks, introducing safeguards against supply-chain interruptions and making supply chains more adaptable before disruptions can impact operations.

This proactive foundation enables companies to adapt swiftly and avoid costly operational setbacks.

Firms can also avoid supply chain risks by adopting a thorough approach to third-party risk management. 

De-risking begins with asking the right questions, particularly when onboarding new suppliers, such as who they are and who they’re doing business with, as well as understanding material risk factors like financial stability and business practices. 

Compliance teams should return to this practice regularly at each potential change in risk level, so should a supplier’s risk status change, they can act upon the information. 

Without consistent oversight, a singular incident of poor practice can impact an entire supply chain, potentially resulting in costly operational delays, regulatory breaches and financial penalties. 

How can firms prepare for less predictable risks like natural disasters?

The risks posed by catastrophic environmental events are increasing significantly in cost, frequency and severity.

A report on the impact of climate-related disasters in the US by the National Centers for Environmental Information revealed that in 2023 major weather and climate events in the US resulted in US$92.9bn in damages. 

The financial damage posed by these increasingly frequent natural disasters underscores the need for businesses to build resilience against such risks, particularly to protect their supply chains. 

Building resilience begins with using climate data and predictive analytics, which allows companies to pinpoint high-risk areas and adjust sourcing and logistics strategies. 

Firms may also consider relocating operations from vulnerable zones, establishing relationships with alternative suppliers and enhancing overall supply chain flexibility to improve adaptability in the face of evolving environmental risks.

By combining environmental data analysis with proactive supplier monitoring, organisations are better equipped to anticipate, adapt to and withstand emerging threats to their supply chains.

By: Tom Chapman /November 24, 2024

The merger could create the world’s second-largest oil producer after Saudi Arabian oil giant Aramco.

Russia is considering a merger of state-backed giant Rosneft Oil with Gazprom Neft, a subsidiary of majority state-owned Gazprom, and Lukoil, a private petroleum company, reported the Wall Street Journal.

Rosneft would absorb both Gazprom Neft and Lukoil in the proposed merger, indicated sources familiar with the negotiation.

This move would create the world’s second-largest crude oil producer, trailing only behind Saudi Arabia’s Aramco, and potentially pump approximately three-times the output of US oil giant Exxon.

The merger could also enable Russia to secure higher prices for Russian oil from key customers in India and China.

The Wall Street Journal reported that discussions between executives and government officials have been ongoing over the past few months, citing anonymous sources. However, the outcome remains uncertain, with a deal being possible but not guaranteed.

Despite the potential for such a significant consolidation, there are notable hurdles including resistance from certain executives at Rosneft and Lukoil, as well as the challenge of securing funds to compensate Lukoil shareholders.

Igor Sechin, the head of Rosneft and a close associate of Russian President Vladimir Putin, is a central figure in the ongoing discussions.

There is no clarity on whether Sechin will lead any potential merged entity, as representatives from the government, Gazprom Neft, Lukoil and Rosneft have denied involvement in merger talks.

The Kremlin has expressed no knowledge of such a deal, and last month it could not confirm reports of a proposal to nationalise the energy sector.

Gazprom has faced significant revenue losses since Russia’s large-scale invasion in 2022, largely due to reduced energy sales, reported the Institute for the Study of War, a US-based non-profit research group.

Additionally, long-time Gazprom CEO Alexey Miller failed to secure an agreement with China in early 2024 over the proposed Power of Siberia-2 gas pipeline due to unresolved disputes.

By: Offshore-technology / November 12, 2024

Fast forward five years, and all seems to have gone the wrong way. The mojo is certainly gone. Exxon is not only again the largest US oil company, but its market value nearly doubles its competitor. Worse, Exxon has entangled Chevron in a long arbitration battle that could derail a make-or-break $60-billion-plus deal. Wirth, long admired, is now questioned. Rivals whisper his job may be on the line.

Mike Wirth became the king of Big Oil on Oct. 7, 2020. That was the day the chief executive officer of Chevron Corp. elbowed out archival Exxon Mobil Corp. to become America’s largest oil corporation by market value.

Fast forward five years, and all seems to have gone the wrong way. The mojo is certainly gone. Exxon is not only again the largest US oil company, but its market value nearly doubles its competitor. Worse, Exxon has entangled Chevron in a long arbitration battle that could derail a make-or-break $60-billion-plus deal. Wirth, long admired, is now questioned. Rivals whisper his job may be on the line.

The 64-year-old American chemical engineer is on a charm offensive to prove naysayers wrong. “The portfolio is stronger than it’s been,” he tells me in an hour-long interview. “This is the comeback.”

The path to redemption isn’t easy, but having listened to Wirth’s arguments, as well as spoken to multiple shareholders, bankers and analysts over the last few weeks.

To be fair to Wirth, his company is far from suffering the existential crisis its critics claim. In the third quarter, it returned to shareholders a record high $7.7 billion via dividends and share buybacks. Its stock has recovered too: At close to $160 per share, Chevron is up more than 10 per cent over the last year. Speaking from his office on the outskirts of San Francisco, days before Chevron relocates its headquarters to Houston, Wirth painted a rosy outlook because, as he puts it, Chevron has promised investors to increase its free cash flow by 10 per cent each year. The target seems achievable; if it delivers, the mojo will return.

Speaking from his office on the outskirts of San Francisco, days before Chevron relocates its headquarters to Houston, Wirth painted a rosy outlook because, as he puts it, Chevron’s cash generation compared to its spending is at an “inflection” point… If oil prices stay above $70 a barrel, it should enjoy a cash bonanza from 2025 as several projects start pumping, allowing the company to move into harvest mode. Chevron has promised investors to increase its free cash flow by 10 per cent each year….The target seems achievable; if it delivers, the mojo will return.

Yet, the challenges abound. Wirth inherited a troubled legacy when he became CEO in 2018. Under his predecessor, John S. Watson, Chevron had become a byword for late and over-budget mega-projects. Capital spending jumped from less than $20 billion annually before 2010 to about $40 billion in 2013, 2014 and 2015. Watson famously justified the splurge with a new vision: $100-a-barrel was the new $20-a-barrel.

Wirth inherited a troubled legacy when he became CEO in 2018. Under his predecessor, John S. Watson, Chevron had become a byword for late and over-budget mega-projects. Capital spending jumped from less than $20 billion annually before 2010 to about $40 billion in 2013, 2014 and 2015. Watson famously justified the splurge with a new vision: $100-a-barrel was the new $20-a-barrel.

Saudi Arabia had other plans, however. In late 2014, the kingdom launched a price war to halt the expansion of the US shale industry. Oil prices cratered to less than $30 a barrel. Chevron was left hanging out to dry. Wirth slashed spending and told investors the old days wouldn’t come back. Some were skeptical, but he delivered. Little by little, shareholders regained confidence. Then, in 2019, Wirth attempted to buy rival Anadarko in a deal valued at $50 billion, including debt. But Occidental Petroleum Corp. counterbid at $57 billion with the help of Warren Buffett. Rather than start a bidding war, Wirth walked away, pocketing a $1 billion breakup fee. It was the move that consolidated his appeal on Wall Street: He put financial common sense above ego.

All that Wirth needed to do to remain Wall Street’s favorite was rinse and repeat: keep costs under control, deliver projects on time and meet oil production targets. “Repetition is reputation,” as veteran oil analyst Paul Sankey likes to put it.

But Chevron didn’t, and Wall Street was merciless. The first setback was the expansion of the Tengiz project in Kazakhstan, the company’s crown jewel. When announced in 2016, it was meant to cost $37 billion and see its first oil in 2022; now, now, the crude won’t flow until next year, and the cost has ballooned to over $45 billion. Wirth admits he dropped the ball, allowing a culture of “optimism” that overlook the challenges.

“We were not — and I was not — asking the right questions,” he says. “I was not in contact with the field team as frequently as I should have been.” For Wall Street, it was déjà vu of the years when spending went unchecked.

The second setback was in Chevron’s backyard — the Permian region that’s the epicenter of the US shale revolution. Wirth had set a lofty target of pumping one million barrels a day by 2027, but in 2022 and 2023, the company struggled. With hindsight, it was a minor wobble as production is now again on track. But, Chevron didn’t explain itself at the time, putting off some investors.

Yet these setbacks pale in comparison with the third: the ongoing acquisition of Hess Corp. for $60 billion, including debt. The deal, announced in 2023, is the boldest that Wirth has attempted and would give Chevron a stake in a prized series of oil fields off the coast of Guyana, the Latin American nation bordering Venezuela and Brazil. The problem? Exxon owns a large chunk of the very same oilfields and claims it has the right to bid for them first.

Exxon, Chevron and Hess tried to resolve their differences in private, but the case is now going into arbitration in June, with a ruling likely in July or August. For many in the industry, Exxon, by delaying the Chevron-Hess deal at least one year, has already won — even if it ultimately losses the arbitration.

Still, everyone faces risks, even Exxon, and as the arbitration approaches, I believe the incentive to reach an out-of-the-court deal increases. Wirth disagrees: “Why would you do something now that you shouldn’t get done earlier?” He may be ultimately right, but that’s of little help for shareholders now. Today, investors don’t know what they are buying in Chevron. Are they purchasing shares in a future Chevron-Hess? Are they buying into a Chevron that fails to buy Hess and rushes into a standalone Chevron that carries on without further deals?

All those options have pros and cons — but above all, they have uncertainty. If one believes that Wirth will prevail in arbitration, buying Chevron today is a no-brainer. But if he doesn’t, one must put a lot of faith that the CEO wouldn’t rush into an expensive M&A deal to offset the loss of Hess.

“The standalone Chevron story is very, very strong,” Wirth says. “So even in the case where the transaction doesn’t close, which we don’t believe is going to happen, I think our track record says we wouldn’t go out and just throw money at something.”
But it’s hard to see how Chevron wouldn’t search for an acquisition if it doesn’t get Hess, although Wirth can probably do it on his own terms and time, without overpaying. Without that extra something, investors would question the growth of Chevron beyond the next few years. The Permian is a great story, but production there is expected to plateau in 2027; Tengiz is now a superb narrative for 2025, 2026 and 2027, but as time goes, shareholders will start asking questions about the renewal of thof the oilfield’s contract, set for 2033. Buying Hess solves these questions, hence why it’s so important.

Wirth has a point when he insists that Chevron is a better company than naysayers portray. Above all, it’s a cash machine. Between 2011 and 2014, Chevron generated, on average, $3.9 billion in free cash flow per year with Brent crude averaging nearly $110 a barrel. Last year, Chevron produced five times more free cash flow — nearly $20 billion — despite Brent crude trading at $80 a barrel. With a leverage ratio around 12 per cent, which is likely to drop into the single digits in the fourth quarter thanks to asset sales, Chevron can take on debt to sustain dividends and buybacks if oil prices sag. In the past, the company has boosted iits leverage to 20 per cent to 25 per cent during down cycles. Funding payouts with debt is risky, however, so Chevron should consider lowering its buybacks if oil prices fall below $70 a barrel. The company is currently buying back its shares atat a pace of $17 billion annually, near the upper end of its $10 billion to $20 billion annual guidance.

That financial firepower, alongside Wirth’s reputation as an executive who would walk from a deal rather than overpay, is the best antidote to skeptical investors. Chevron is owning its mistakes, and that’s a first good step. Now, it needs to show it’s learned the lessons.

By: Javier Blas ,Bloomberg / 12 November, 2024.

Oil prices lost further ground in early trade on a stronger dollar and pessimism over Chinese demand growth.

Brent crude traded 1.4% lower to $72.86 a barrel, while WTI fell 1.6% to $69.26 a barrel.

The dollar was up 0.4% against a basket of major currencies ahead of key inflation data later this week, making oil cheaper. Prices are also pressured by growing concerns over demand trends in China after the top crude importer didn’t announce new stimulus measures, as well as easing supply risks in the U.S.

Meanwhile, “a Trump presidency is seen as relatively more bearish for energy markets,” ING analysts said in a note. “However, the key risk to this view is if President Trump chooses to strictly enforce sanctions against Iran.”

By Giulia Petroni, Dow Jones Newswires / Nov 11, 2024

Weak demand in China will lead to lower supply from the world’s top crude exporter, Saudi Arabia, to the world’s largest crude importer in December, trading sources told Reuters on Monday.

The drop in Saudi supply would come despite the fact that the Kingdom has reduced its official selling prices (OSPs) for crude loading in December for Asia.

December will see a second consecutive month of lower Saudi deliveries to China, estimated at a total of 36.5 million barrels. This would be down from 37.5 million barrels expected this month, and 46 million barrels in October, according to trade data compiled by Reuters.

The Saudi crude oil supply to China next month would also be the lowest monthly volume since July, as Chinese state-owned giants PetroChina, Sinopec, and Sinochem are expected to lift fewer cargoes from the Kingdom.

Aramco, the Saudi state giant, last week reduced the price of its crude that will be loading for Asia in December.

Saudi Arabia’s flagship crude grade, Arab Light, saw its OSP cut by $0.50 per barrel, to $1.70 a barrel above the Dubai/Oman benchmarks, from which Middle Eastern exporters price their crude for the Asian markets.

The Kingdom also slashed the OSPs of all its grades loading for Asia—Arab Extra Light, Super Light, Arab Medium, and Arab Heavy, although the reductions in the heavier grades were lower than those for the lighter crudes.

Chinese crude oil imports have been underwhelming this year, with October marking the sixth consecutive month in which cargo arrivals have lagged behind the imports in the same months of 2023, official Chinese data showed last week.

Reduced capacity at a PetroChina refinery and continued weak demand from China’s independent refiners, the so-called teapots, weighed on the imports into the world’s top crude importer in October.

Weaker-than-expected Chinese demand may have been the reason why the OPEC+ group delayed the beginning of the easing of its production cuts to January 2025, from December 2024, although the cartel and its allies did not give a specific reason for the decision.

By Tsvetana Paraskova for Oilprice.com / Nov 11, 2024

U.S. energy company Glenfarne Group LLC said on Monday it had selected construction contractor Kiewit to build its proposed Texas LNG export terminal in Brownsville, Texas.

The proposed terminal has the capacity to turn about 0.5 billion cubic feet per day (Bcf/d) of natural gas into 4 million tonnes per annum of liquefied natural gas.

Glenfarne said it would work with Kiewit to meet the requirements needed to achieve a final investment decision (FID).

The company was expected to begin construction by November 2024 and commercial operations by 2028. However, in May it asked federal energy regulators to give it until 2029 to put its plant into service.

Earlier this month, Glenfarne said it had already secured enough supply agreements in a volume sufficient for achieving an FID, including agreements with EQT Corp., Gunvor Group, and Macquarie Group.

By: Reuters , 11/4/2024

Global Partners LP is strengthening its operational capabilities and supply options in the Northeast with the acquisition of a liquid energy terminal in East Providence, R.I., from the ExxonMobil Oil Corp.

The terminal — which features 10 product tanks with 959,730-barrel shell capacity — serves as a strategic storage facility for various products, including gasoline, additives, distillates and ethanol. It includes a six-bay truck rack servicing the Rhode Island, northern Connecticut and southern Massachusetts markets, as well as a large dock with capabilities to accommodate long-range vessels.

The addition of gasoline infrastructure through the transaction will enable the partnership to optimize its large, active marketing and retail presence in the area. In addition to the terminal, Global Partners will acquire surplus vacant real estate parcels providing long-term opportunities for alternative uses as market dynamics evolve, the company stated.

“The additional operational capabilities and supply optionality, along with the potential for real estate development, further deliver our commitment to strategic growth by diversifying our portfolio and capitalizing on assets that leverage our integrated network,” Slifka added.

The latest acquisition builds upon the partnership’s strategy to enhance its assets of liquid energy terminals. Over the last year, Global Partners has invested more than $500 million to significantly expand its wholesale segment through the strategic acquisition of a combined 29 terminals from Motiva Enterprises and Gulf Oil, more than doubling the partnership’s storage capacity to 21.4 million barrels.

The terminals expanded the partnership’s geographic reach within New England, along the Eastern Seaboard and into Florida, the Gulf Coast and Texas, as Convenience Store News previously reported.

Waltham-based Global Partners operates or maintains dedicated storage at 54 liquid energy terminals — with connectivity to strategic rail, pipeline and marine assets — spanning from Maine to Florida and into the U.S. Gulf States. Through this extensive network, the company distributes gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers. In addition, Global Partners owns, operates and/or supplies more than 1,700 retail locations across the Northeast states, the Mid-Atlantic and Texas.

By: Danielle Romano , csnews / 11/4/2024 .

Global tank storage operator Vopak has committed just a fraction of the $1 billion it allocated for energy transition projects by 2030 but expects investments to accelerate towards the end of the decade, CEO Dick Richelle said. 

The company has spent a little less than $100 million on the projects in the two years since it made the spending pledge, Richelle told Reuters in an interview.

“Although developments have slowed down, we still see that it kind of moved away from a big hype and dream to much more realism in building these new supply chains going forward,” he said.

Some of the factors that have slowed projects include a lack of government mandates and incentives, higher production costs for alternative fuels and rising construction capital expenditure, he added.

For example, Norway’s Equinor scrapped plans to export hydrogen to Germany because it is too expensive and there is insufficient demand and Repsol put on hold hydrogen projects in Spain due to an unfavourable regulatory environment.

“You need all of those parties at the same time to hold hands and basically jump to make sure that you can establish a whole supply chain,” Richelle said.

“I think that has been slow simply because of the fact that it’s either not clear what incentive you’re going to get at production, or it’s not clear what the mandate is and where you want to sell your product, or the incentive over there in order to import the product.”

Looking ahead, Vopak is focusing on infrastructure projects in four areas of energy transition: biofuels and feedstocks such as sustainable aviation fuel and renewable diesel; hydrogen and hydrogen carriers such as ammonia; carbon dioxide (CO2) value and supply chains; and battery storage.

Vopak plans to capture a bigger share of the biofuels market by converting existing storage tanks for bio-bunker fuel blending in Rotterdam and Singapore, and in the use of biofuels as raw material for fuel and petrochemical production in India, Brazil and Los Angeles, Richelle said.

For ammonia, Vopak is targeting big production centres such as the Middle East and the U.S., and end-markets like Antwerp, Rotterdam, Singapore and South Korea where it operates terminals, he added. The company said in July it had opened an office in Japan to explore opportunities there.

Vopak also has a strong presence in China, a competitive producer of green methanol, where it can facilitate the production and distribution of the alternative fuel, Richelle said.

In carbon storage, the company is working on a project in Rotterdam and has an initial agreement with Australia’s Northern Territory to develop a CO2 import terminal.

Vopak is also making early steps in battery storage investments, having announced a project in Texas earlier this year, Richelle said.

“We see that there’s potentially an important role for Vopak to play as the world moves from the storage of molecules to electrons,” he said.

Story by Florence Tan and Jeslyn Lerh, November 4, 2024

Exxon Mobil (XOM.N), opens new tab on Friday edged past Wall Street’s third quarter profit estimate, boosted by strong oil output in its first full quarter that includes volumes from U.S. shale producer Pioneer Natural Resources.

Oil industry earnings have been squeezed this year by slowing demand and weak margins on gasoline and diesel. But Exxon’s year-over-year profit fell 5%, a much smaller drop than at rivals BP (BP.L), opens new tab and TotalEnergies (TTEF.PA), opens new tab, which posted sharply lower quarterly results.

The top U.S. oil producer reported income of $8.61 billion, down from $9.07 billion a year ago. Its $1.92 per share profit topped Wall Street’s outlook of $1.88 per share, on higher oil and gas production and spending constraints.

“We had a number of production records” in the quarter, said finance chief Kathryn Mikells, citing an increase of about 25% year-on-year in oil and gas output to 4.6 million barrels of oil equivalent per day (boepd).

Exxon earlier this month flagged operating profit had likely decreased, leading Wall Street analysts to shave their quarterly per share earnings forecast by nearly a dime.

RECORD PRODUCTION

Exxon’s results reflected the first full quarter of production following its acquisition in May of Pioneer Natural Resources. The acquisition has already boosted the company’s cash flow, Mikells told analysts on a post-earnings call.

The $60 billion deal drove production in Permian basin, the top U.S. shale field, to nearly 1.4 million boepd, helping overcome a 17% decline in average oil prices in the quarter ended Sept. 30.

Volume growth from the Pioneer acquisition and its lucrative Guyana consortium added almost $3 billion to earnings in the first nine months of this year, Mikells said on a post-earnings conference call. Compared with the second-quarter, Pioneer output averaged slightly lower, she noted.

Despite the record, output from the Permian was still below Barclays’ estimate of 1.5 million boepd, and Exxon’s earnings from U.S. oil and gas production were also softer than forecast, the bank’s analyst Betty Jiang said.

No. 2 U.S. oil producer Chevron (CVX.N), opens new tab, whose plans to acquire Hess Corp have locked the two rivals in a bitter arbitration battle over Guyana, beat Wall Street estimates by a nine-cent margin compared with Exxon’s four-cent beat.

That helped Chevron shares gain more than 3% on Friday, while Exxon gave up more than 2% of premarket gains to trade about flat by noon ET (1600 GMT).

Exxon expects full year output to average about 4.3 million boepd, including eight months of Pioneer’s contributions.

The company plans to issue a revised production forecast next month. It noted that scheduled well maintenance will lower output by about 30,000 boepd in the fourth quarter.

The market is worried about oil supply outrunning demand next year, with exporter group OPEC reviewing plans to add 180,000 barrels per day (bpd) of additional oil supply from December. Oil prices slumped over the summer and remain about 12% below June’s average.

REFINING SLUMPS, CHEMICALS GROW

Exxon disclosed it raised its quarterly dividend by 4% after generating free cash flow of $11.3 billion, well above analysts’ estimates. Rivals Saudi Aramco (2223.SE), opens new tab and Chevron have had to borrow this year to cover shareholder returns after boosting dividends and buybacks to attract investors.

Exxon’s earnings from producing gasoline and diesel in the quarter were $1.31 billion, down from $2.44 billion year-on-year as weak margins and a nearly month-long outage at its 251,800-bpd Illinois refinery hit segment results.

Lower planned maintenance at other plants, along with gains on derivatives, helped offset weak industry-wide refining margins and the impact of the Illinois outage, Exxon said.

“Refining margins definitely came down in the quarter. If you look at overall results for the refining business, we feel pretty good,” said CFO Mikells. Per unit refining margins since 2019 have about doubled on a constant margin basis, she said.

Profits from Exxon’s chemical business, which has been pressured by industry overcapacity for two years, rose in the quarter to $893 million, compared with $249 million a year ago, on a slight increase in margins.

By Shariq Khan and Gary Mcwilliams / November 4, 2024