Chevron upgrades pasadena refinery to increase capacity, feedstock and product flexibility

Chevron U.S.A., Inc. (CUSA), a wholly owned subsidiary of Chevron Corporation (NYSE: CVX), has completed a retrofit of its refinery in Pasadena, Texas, which is expected to increase product flexibility and expand the processing capacity of lighter crudes by nearly 15 percent to 125,000 barrels per day.

Chevron acquired the Pasadena Refinery in 2019 with the strategic intent to expand its Gulf Coast refining system. This project is expected to allow the company to process more equity crude from the Permian Basin, supply more products to customers in the U.S. Gulf Coast and realize synergies with the company’s Pascagoula refinery.

The Light Tight Oil (LTO) Project aims to enhance facility reliability and safety and will ultimately result in an increase in the supply of refined products domestically. The refinery will also begin producing jet fuel and exporting gas oil.

“The Pasadena Refinery is on a journey to maximize value for Chevron and the community it serves by driving progress in safety and reliability,” said Chevron Manufacturing President Chris Cavote. “This refinery now firmly integrates our upstream and downstream businesses as we aim to optimize the value chain.”

Planning for the LTO Project began in 2019 with work beginning in early 2020.

“I’m extremely proud of our employee and contractor workforce, which logged over 4 million hours to complete this complex project in an operating refinery. Our safety program reinforced the focus on working safely throughout the project,” said Refinery General Manager Tifanie Steele. “We are investing in the refinery to help it be successful in the long-term, which we hope will support continuing positive economic impact to our community.”

The phased start-up of the asset is expected to last through Q1 of 2025 as project team members work to confirm all plants are operating as planned and products are developed to specification.

About Chevron

Chevron (NYSE: CVX) is one of the world’s leading integrated energy companies. We believe affordable, reliable and ever-cleaner energy is essential to enabling human progress. Chevron produces crude oil and natural gas; manufactures transportation fuels, lubricants, petrochemicals and additives; and develops technologies that enhance our business and the industry. We aim to grow our oil and gas business, lower the carbon intensity of our operations and grow lower carbon businesses in renewable fuels, carbon capture and offsets, hydrogen and other emerging technologies. 

By: Chevron / Dec. 10, 2024.

ENOC, JPUT Complete New Inter-Terminal Pipeline in Singapore

Horizon Terminals Ltd. (HTL), an Emirates National Oil Co. (ENOC) unit, has completed the Horizon JPUT Pipeline Connectivity Project in Singapore.

The project was undertaken by Horizon Singapore Terminals Pte. Ltd. (HSTPL) and Jurong Port Universal Terminal Pte. Ltd. (JPUT). ENOC said in a media release the project is a major milestone in HTL’s international expansion.

For Singapore, this means a major step toward petroleum infrastructure development, operational efficiency, and cost reduction, it said.

ENOC said the project involved the construction of a new pipe rack connecting both terminals, equipped with a 24-inch pipeline for Fuel Oil and a 20-inch pipeline for Clean Petroleum Products. The infrastructure, according to ENOC, will also mitigate operational risk, reducing transfer times between the two terminals and reducing costs for customers of both facilities.

HSTPL and JPUT have formed a partnership on Jurong Island, with the two terminals being built in 2006 and 2007, respectively. ENOC added that over the years, the partnership expanded with a mutual aid understanding and the construction of a firewater line in 2009, progressing to the current pipeline connectivity project, benefiting customers of both terminals.

“The successful completion of the Horizon JPUT Pipeline marks a pivotal moment not only for Singapore’s energy infrastructure but also for the region. This project strengthens our global footprint and reinforces ENOC’s position as a global energy leader”, Saif Humaid Al Falasi, Group CEO of ENOC and Chairman of HSTPL, said.

“This new infrastructure strengthens our partnership with Horizon Singapore Terminals, expands service offerings for our customers, and enhances the collaborative ecosystem between our terminals”, Loh Wei, CEO of JPUT, said.

The new pipeline reduces the reliance on short-range shipping operations, decreasing marine traffic at the port and increasing the safety of essential long-range vessel movements, ENOC said. Additionally, this development lowers carbon emissions, supporting more sustainable operations, it said.

By Paul Anderson, Rigzone Staff / Monday, December 09, 2024

BP’s Chairman Needs to Put the Company Up for Sale

The UK oil company’s future as a standalone entity is bleak. 

In the spring of 1998, with oil hovering near $10 a barrel, BP Plc reached a dismal conclusion: Its future as a standalone company was grim. So John Browne, its chief executive officer at the time, rang the chairman of US rival Amoco and proposed a merger. The deal, announced in August of that year, triggered a flurry of M&A activity that created the current Big Oil mob.

Today, BP is at a similar juncture. Its future alone is bleak. Investors have lost faith in its strategy, its management and its board. Even sell-side analysts, typically deferential to the companies they cover, are out for blood: Take the headline of a recent report by veteran analyst Paul Sankey that read “BP Results: Beat? Miss? Who Cares, Fire the Board.”

History doesn’t repeat, but it rhymes. BP Chairman Helge Lund needs to pick up the phone and seek a deal — effectively putting the company up for sale. If he plays it well, the oil major may get to call the resulting transaction a “merger of equals.” So who can he phone? Shell Plc, of course. Moreover, the UK government should encourage such a deal with the aim of keeping a Shell-BP company British and still listed in London.

BP executives may be pinning their hopes that a strategic update, scheduled for February, will revive the company’s fortunes. Lund was in the US last month sounding out institutional investors; my understanding is that they denounced the current strategy. In 2020, BP made a bet: oil demand had peaked, and the future was about reducing fossil fuel output and investing an ever-larger share of its budget in green electricity, primarily wind and solar power. Since then, the company has rowed back on its green strategy, but investors are demanding it refocus on its traditional strengths — oil and gas.

The damage to BP in recent years has been enormous. At about $75 billion, BP’s market valuation is a shadow of its previous might. In 2006, the company was worth $250 billion; even in 1998, before the merger with Amoco, it was worth $80 billion. Its stock-market performance has been horrid. BP is among the top-10 worst performers on the FTSE 100 blue chip index in the past 12 months. It doesn’t look prettier if one looks further afield — in the past five years, its shares are down 20%, compared with gains for its rivals of 10% to 70%. BP’s stock would be even lower if investors weren’t anticipating either an activist emerging or an M&A deal. But those opportunistic hedge fund bets won’t last for ever.

To be sure, the company is far from a basket case. Its Gulf of Mexico business is second to none and its trading capabilities are legendary. But it’s also carrying a lot of underperforming divisions, while its Russian business is so toxic that it’s impossible to value.

Importantly, BP is probably worth more as the sum of its parts than as a whole, offering an opportunity for any buyer to hang on to the assets it wants, and sell the rest: Private equity firms and sovereign wealth funds would be eager buyers of whatever a potential purchaser was willing to dispose of.

If the BP chairman did make the call, Shell CEO Wael Sawan should pick up the phone. The numbers would stack up even after paying a typical 30% premium. Synergies alone would generate billions of dollars of savings; when analysts at Barclays Plc did the sums on a fantasy BP-Shell merger, they came up with $7.5 billion in annual operating cost savings and a $5 billion reduction in capital expenditure, suggesting the transaction would pay for itself in a few short years.

Moreover, buying BP would resolve key problems for Shell; how to sustain growth after 2030, and how to add exposure to the US. Shell executives have made some very good decisions in recent years; abandoning the American shale sector wasn’t one of them. The main obstacle to a deal? Shell is currently focusing on a business revamp that won’t be completed until mid-2026, so a transaction with BP now would be earlier than the company would wish. The thing about M&A, though is that it happens when it’s possible, not when the time is ideal.

While some are willing to give the board the benefit of the doubt for the next few months, I doubt BP can change direction to their satisfaction. My skepticism is compounded by the board’s selection of Murray Auchincloss, one of the architects of the current strategy, as its chief executive. If the board wanted a U-turn, it should have chosen a different leader in January.

There are other options. BP could try to entice TotalEnergies SE into a merger of equals of sorts, but the idea of a French-British — with emphasis on that particular order of nationalities — oil company seems farfetched. The UK government might not be so keen on a foreign takeover. I also worry that buying BP would burden Total’s balance sheet too much, particularly if oil and gas prices remain at current levels.

In the absence of a European deal, BP might be attractive to US oil giant-in-waiting ConocoPhillips. Conoco has a market value of $135 billion, making it almost double the size of BP. It’s expanding in liquefied natural gas, and BP could turbocharge that business; it would also deliver a fantastic trading business to Conoco, along with production in the Gulf of Mexico, where the US-based company isn’t currently present. But Conoco would have to dispose of way too many other assets, starting with the downstream operations; the company has spent more than a decade focusing entirely on pumping oil and gas, rather than refining it and selling it to costumers.

There’s another US option: tapping Warren Buffett’s riches via a deal with Occidental Petroleum Corp. Adding Occidental’s shale operations to BP’s best assets could work; though, here again, the British government might object to BP relocating to America.

Finally, BP could seek a Middle Eastern strategic investor – the state-owned oil companies of Abu Dhabi and Kuwait come to mind. In the late 1980s the Kuwaitis bought more than a fifth of BP, although later London intervened and forced the Middle Eastern nation to sell a chunk. With that history, a deal may be complicated — but state-controlled firms are keen to expand into trading and LNG. Moreover, if new shareholders force a change of strategic direction, they’ll benefit from any resulting rally in BP shares.

Considering BP’s disastrous performance in recent years, the board should be considering all options. To my mind, putting itself up for sale would be a sensible move — and the sooner the better.

By: Javier Blas, Bloomberg / December 8, 2024

Why Oil Markets Are Trading With Zero Conviction

Oil markets are hesitant to trade with conviction as they await the start of Trump’s second term.

OPEC+ has delayed unwinding production cuts until the end of Q1 2025 due to pessimistic market sentiment.

Natural gas prices have dipped due to forecasts of milder weather.

With nearly a month since U.S. President-elect Donald Trump won a second term in the Oval Office, oil markets have been struggling to find direction despite event risk remaining high, particularly in the Middle East. According to commodity analysts at Standard Chartered, the market’s apparent hesitation to trade a view with any conviction has intensified the notion that oil markets seem content to wait for Trump to take office. Volatility has fallen sharply, with the 30-day front-month Brent realized annualized volatility sinking to a1 6-week low of 25.1% at settlement on 2 December. This volatility reading falls in the lower 30% tail of the distribution of volatility over the past 10 years.

The ongoing ceasefire in Lebanon appears fragile, while the rekindling of the Syrian civil war indicates that the balance of power in the region has been disturbed. On Monday, Hezbollah fired into a disputed border zone held by Israel, with Lebanon’s parliament speaker claiming that Israel has committed 54 breaches of the ceasefire.

StanChart has reiterated its earlier prediction that OPEC+ tapering mechanism is likely to play the biggest role in dictating the oil price trajectory. The analysts note that the OPEC+ Joint Ministerial Monitoring Committee (JMMC) and the broader OPEC+ Ministerial meeting originally scheduled for 1 December was moved to today, with the more administrative OPEC meeting set for 10 December.

According to StanChart, the key discussions were those between Saudi Arabia, Russia, Iraq, Kuwait, the UAE, Kazakhstan, Algeria, and Oman, the eight OPEC+ nations that announced additional voluntary output cuts in April and November 2023. StanChart correctly predicted that, given current negative market sentiment and an overly pessimistic market view of 2025 balances, tactically the best choice for ministers was to delay any unwinding of voluntary cuts to the end of Q1 and perhaps even further out. StanChart notes that much of the recent burst of oil diplomacy has centered on Iraq and its commitment to both reduce output to target and to pay back past overproduction.

Bloomberg estimates that Iraqi crude oil output fell to a three-year low of 4.06 million barrels per day (mb/d) in November; good for a 70 thousand barrels per day (kb/d) m/m decline;, 260 kb/d below August and 420 kb/d lower y/y, but still 60 kb/d above target (including voluntary cuts).

According to StanChart, much of the negative sentiment that has dominated oil markets over the past couple of months can be chalked up to misapprehensions about the tapering mechanism for the voluntary cuts made by eight OPEC+ countries. Many traders are worried that the balance of oil demand growth and non-OPEC+ supply growth might not offset the scale of restored OPEC+output, leaving oil markets oversupplied. However, the experts have pointed out that this assumption flies in the face of continued reassurances from OPEC+ members that the tapering would be fully dependent on market conditions rather than being automatic. 

Trader focus has been on the question of how many barrels could be returned before a surplus emerged; however, positioning and price dynamics imply that the answer to that question is zero. 

In a November 3 press release, OPEC announced that output increases would be postponed by a month until the start of 2025. StanChart says the delayed return of more barrels to the market does not necessarily mean that OPEC felt the physical market could not absorb the oil, but rather reflects its awareness that extremely pessimistic 2025 oil balance predictions have viewed the tapering through that lens. StanChart says the latest announcement by OPEC strengthens the case that the pace of tapering will be market-dependent and not automatic as traders fear. This realization is likely to have driven the latest oil price rally.

Gas Rally Hits Pause

U.S. natural gas futures dropped to $3.00/MMBtu on Tuesday, their lowest in over a week, after surging 20% in November. Gas prices have declined amid forecasts of milder weather in mid-December, following a brief cold spell that had driven earlier gains. Utilities have stopped drawing heavily from storage, despite colder-than-usual weather recently boosting consumption. Meanwhile, U.S. gas production clocked in at a robust 101.5 billion cubic feet per day in November, but below last year’s peak of 105.3 bcfd. 

Meanwhile, European natural gas futures slipped to €47.6 per megawatt-hour, retreating from a 13-month high of €49 earlier this week, as forecasts pointed to warmer weather while withdrawals slowed down. EU gas inventory draws have moderated over the past week: According to Gas Infrastructure Europe (GIE) data, inventories stood at 100.06 billion cubic metres (bcm) on 1 December; the w/w draw clocking in at 2.96 bcm, a significant deceleration from the previous week’s draw of 3.58 bcm. Last week’s withdrawal clip was also less than both last year’s draw of 3.65 bcm and the five-year average of 3.09 bcm.

Gas inventories are at 85.2% of capacity, 10.54 bcm lower y/y but just 0.36 bcm below the five-year average.

By Alex Kimani, Oilprice.com  – Dec 06, 2024

4 critical moments for North American oil and gas trading

To stay ahead of the energy commodities market in North America in 2024, you had to be on top of these events as they happened

In an uncertain world, global commodities markets are increasingly sensitive to a wide range of factors that can impact supply, demand and prices. As we come to the end of an eventful year for North American oil and gas, we highlight some of the ways Wood Mackenzie’s real-time data and analytics have helped our clients stay ahead of events that shaped the market in 2024. 

 1. January 2024: New WoodMac model forecasts US natural gas freeze-offs 

Freeze-offs can be a serious problem at all stages of the gas supply chain, from the production wellhead through to the last point in the customer delivery system. Whether the gas is a byproduct from a crude oil well, or ‘dry gas’ from a gas-only well, the potential for water or hydrates to freeze and block the flow is a constant threat as temperatures fall. Our research shows that new natural gas production added over the past decade is more vulnerable to freeze-offs than legacy wells, making the forecasting of these events more important than ever. 

As the cold weather surge hit at the beginning of the year, we launched an all-new freeze-off forecasting model to accurately forecast the impact by region of low temperatures two weeks ahead. During the extreme weather, freeze-offs actualised close to our ‘most likely’ scenario, underlining the accuracy of the new forecasting approach.  

2. February 2024: WoodMac flyover shows Matterhorn Express Pipeline progress 

The 580-mile Matterhorn Express Pipeline (MXP) is designed to provide an added 2.5 billion cubic feet per day (bcfd) of takeaway capacity out of the Permian basin to Katy, near Houston, Texas. In mid-February, we chartered an aircraft to overfly the route of the pipeline, which was still under construction.  

With the benefit of over 3,000 photographs taken on the reconnaissance flight we were able to confirm significant progress both on the pipeline itself and on its associated compressor stations. Subscribers to our Natural Gas Infrastructure Intelligence product were able to access the photos and draw their own conclusions via our NatGas Portal.  

Initial flows along the MXP followed in September 2024. While the pipeline won’t initially unlock new production, it will provide much-needed additional capacity to address constraints on sending gas eastwards from the Permian and out of the region. That should strengthen cash prices for gas at the central Waha Hub in Pecos County, Texas – particularly during disruption due to events such as pipeline outages and maintenance that can drive Waha cash prices below zero. 

3. April 2024: WoodMac crude storage levels data shows TMX oil pipeline nearing completion

The Trans Mountain Expansion (TMX) project involves the construction of an additional pipeline roughly parallel to the existing one between Edmonton and Burnaby in Vancouver, Canada. In April we registered a sharp drop in crude inventories at the storage hub in Edmonton where the pipeline originates. This indicated that significant system line fill had started – the final pre-operation step before the pipeline was ready for commercial shipments.

TMX went on to deliver its first barrels of oil on 20 May. By subscribing to our North American Crude Markets Service, WoodMac clients were able to stay ahead of the market impact of TMX going into commercial operation. They also enjoyed access to our in-depth views on how the pipeline will reconfigure trade flows across the North American crude value chain.

4. August 2024: Wood Mac Production by Producer models capture Marcellus gas curtailment

On 2 August 2024, Coterra Energy announced it had decided to cut 325 million cubic feet per day (mmcfd) of gross production (275 mmcfd net) from its Marcellus shale gas play in Pennsylvania. The firm’s decision, made in response to low market prices, was one of a string of similar decisions made that quarter by companies including Chesapeake Energy, EQT Corporation and National Fuel Gas.

Clients of WoodMac’s Equity Production Insight Service, which uses proprietary data and analytics to monitor daily production levels for more than 30 oil and gas exploration firms, were informed of the curtailment almost as it happened. Our data showed estimated net production for Coterra down around 270 mmcfd from the first of the month, in line with the figure given in the company’s announcement the following day.

By :Jim Mitchell , Woodmac / 06 December 2024

Oil and Gas Industry Enters New Investment Cycle with Focus on Sustainability

The oil and gas industry is shifting towards a new investment cycle that prioritizes decarbonization and sustainability alongside financial performance.

Emission-reduction targets are now a critical part of project development and decision-making processes.

Oil and gas companies must navigate uncertainty while delivering on their commitments to decarbonization, resilience, and diversification.

The upstream oil and gas sector stands on the cusp of entering a new investment cycle — one that Rystad Energy has dubbed the ‘deliver in uncertainty’ cycle — where there is set to be an increased focus among players to deliver on sustainability targets while remaining financially robust.

The previous cycle, which started amid the Covid-19 pandemic in 2020 and is now ending, threw energy markets into turmoil. However, it accelerated the pace of energy transition as oil and gas companies were forced to re-invent themselves, figuring out their value proposition amid an increasing push from investors and governments to do more to lower emissions.

With Russia’s invasion of Ukraine in February 2022, high energy prices, OPEC+ production cuts and a realization that transition may take longer, the pendulum swung towards resilient supply, with the stock prices of major oil players rising, market capitalization surging, and companies paying dividends and undertaking share buybacks like never before.

Oil price cycles typically affect investment levels and force some exploration and production (E&P) players to adopt new strategies and reset priorities to remain competitive and investable in a new market reality. The market is nearing the end of the current investment cycle where, to protect their balance sheets and stabilize returns, E&P players have revised and reshaped their portfolios, prioritizing decarbonization and portfolio resilience. As a result, a wide range of new key-performance indicators and targets were adopted as part of the decision-making process. Emission-reduction targets, emission intensity and carbon prices are no longer a novelty in decision-making and portfolio valuation; they are essential parts of a company’s strategy.

Digitalization has been under the spotlight of the industry and companies for several years, but eventually it became a part of ‘business as usual’. Now, digital initiatives are an essential component of project development as they are beneficial in terms of optimizing cost and time. Decarbonization can be considered in the same way: steadily, it is becoming a part of business strategy, and abatement plans must be included in each project development as, even if a company has an objective of increasing supply, its emission-reduction targets make it accountable for keeping emissions under control.

Decarbonization as a new digitalization strategy is now an essential part of business, with companies, the financial sector and governments sharing accountability for reducing emissions to meet global emissions targets.

For the upcoming ‘deliver in uncertainty’ investment cycle, oil and gas companies must deliver on commitments, targets and goals acquired in the previous cycle associated with decarbonization, resilience and diversification while performing their fiduciary responsibilities. Even under the most conservative energy transition scenario, where hydrocarbon demand aligns with a 2.2 degrees Celsius temperature increase – referring to average global temperature rises above pre-industrial levels – upstream investments are expected to plateau at around $620 billion per year.

By Olga Savenkova,  Rystad Energy / Dec 06, 2024.

The Energy Report: Getting It Together

Is OPEC Plus getting its acts together? Brent Oil Futures prices are rising on reports that suggest that OPEC-plus will extend of its production cuts until the end of the first quarter of next year. If agreed it would allow the trend of dwindling supply. And unless it falls apart, it will establish what we have seen and that is to the lower the end of the trading rage for the rest of this year and into the new one.

This comes as China reacts to the Biden administration putting export controls on computer chip-making equipment, software and high-bandwidth memory chips to China. China struck back by banning some exports of gallium and germanium, that can be used for military purposes.

Gallium and Germanium are rare metals that are essential in producing semiconductors and other high-tech products like semiconductor wafers for solar cells, LEDs, fiber optics, dentistry, Integrated circuits, airport security scanners, infrared optics, Infrared sensors. China is the world’s largest producer of gallium and germanium, and it would be hard to replace those supplies.

Reuters reported that on Saturday Iraq halted all operations at the Shuaiba refinery in Basra following the overloading of fuel oil storage tanks, according to three refinery officials. The disruption occurred after no ships arrived at the Khor al-Zubair port to load exported fuel oil since mid-last week. The officials, who spoke on condition of anonymity, said the backlog of fuel oil at the refinery led to the suspension of operations.

Natural Gas Futures has pulled back hopes for a December warm up but in Europe an energy crisis is developing. Javier Blass from Bloomberg pointed out that, “European natural gas storage withdrawals in November were the 2nd largest since at least 2011 (and about double the long-term average). The reason? Strong gas-fired electricity generation to offset low wind, plus a cold start of the winter season.

In the US cold was the natural gas story last week but hopes for a warmup is pressuring us. Fox Weather reported that, “Winter weather is making its presence known across the U.S. as millions of people deal with the onslaught of a long-duration, lake-effect snowstorm that has paralyzed communities downwind of the Great Lakes. And to make matters worse, rounds of arctic air will continue to invade the country and send temperatures tumbling below freezing in cities as far as the Southeast.

The FOX Forecast Center said the arctic blast from Canada has been sweeping across the central and eastern U.S.. Temperatures in cities in the northern Plains plummeted below zero over the weekend, and wind chills made it feel even colder.

Cheap corn, more Ethanol. DTN reports that US Ethanol production is hot and at an all-time high! DTN Energy says that overall ethanol production in the United States averaged 1.119 million barrels per day (bpd) in the week ended Nov. 22, a fresh record high, up 9,000 bpd week-on-week, the Energy Information Administration reports. Domestic ethanol production for the week was 108,000 bpd, or 9.7%, higher than in the same week last year while four-week average output at 1.112 million bpd was 81,000 bpd above the same four weeks last year. Midwest ethanol production averaged 1.048 million bpd, up 10,000 bpd week-on-week and 98,000 bpd, or 9.4%, higher than in the same week last year.

The fundamental outlook for oil is looking pretty solid here as we get into winter demand. We should start hitting on all cylinders now we’re going to really test the thesis that the market is oversupplied. We’re probably going to find out very shortly whether that’s the case.

By Phil Flynn, Investing / 12. 03. 2024.

Linde Awarded $10 million by US DOE

Linde has been awarded $10 million (€9 million) by the US Department of Energy (DOE) to lead the demonstration of cost-effective, standardised, and replicable advanced hydrogen fuelling infrastructure for heavy-duty trucks in La Porte, Texas.

The hydrogen refuelling station (HRS) will offer high fuelling throughput with convenient and accessible fuelling options to businesses and transportation fleets in the region, as well as tube trailer filling to enable supply chain development in the Gulf Coast region.

The HRS will be located in the heart of Linde’s robust hydrogen pipeline complex that supplies over 1 billion cubic feet (28 million m3) per day of hydrogen to the area, enabling access to reliable and low-cost feedstock.

The funding is part of DOE’s efforts to advance the National Clean Hydrogen Strategy to accelerate the research, development, demonstration, and deployment of next-generation clean hydrogen technologies.

By: Anamika Talwaria , Tankstorage / December 3, 2024.

ExxonMobil profits dip as it gives back almost $10 bn to investors

ExxonMobil reported a dip in third-quarter profits Friday on lower earnings from its refining business, but the results were strong enough to enable nearly $10 billion in shareholder distributions.

The big US oil company, which saw upstream oil production rise following its acquisition of Pioneer Natural Resources, pointed to the benefits of $11.3 billion in “structural cost savings” as a driver of the results. 

The oil giant returned $9.8 billion to investors in the three-month period, up from $9.5 billion in the second quarter. ExxonMobil lifted the dividend by four percent, in addition to making share repurchases.

Net profits in the third quarter were $8.6 billion, down 5.1 percent from the year-ago period.

While earnings were higher in upstream and chemical products, ExxonMobil saw a big drop in energy products results due to weakened refinery margins.

The company pointed to record oil and natural gas output in Guyana and strong results in the Permian Basin, a shale region in Texas and New Mexico.

Crude oil prices have fallen about 15 percent since the end of the second quarter, a dynamic that Chief Executive Darren Woods said reflected a market imbalance.

“We’re seeing record levels of demand for oil, record levels for demand for products coming out of refinery, petroleum products,” Woods told CNBC.

“But we also see a lot of supply in the world right now, and a lot of that supply is coming out of the US, and the unconventional developments that we have here in the US, and so it’s basically a supply-driven price environment right now.”

At Chevron, profits came in at $4.5 billion, down 31 percent from the year-ago level.

Chevron’s earnings were also dented by lower refining margins, although it also enjoyed record oil and natural gas production from the Permian Basin.

Chevron returned $7.7 billion to shareholders during the quarter, which the company said was a record.

By: Easternprogress / December 03, 2024 

Brazil’s Ultra plans $200 million LPG terminal with Supergasbras

Brazil’s fuel retailer Ultra UGPA3.SA has asked the country’s antitrust body for approval to build and operate a liquefied petroleum gas (LPG) terminal in the Port of Pecem, in the state of Ceara, together with Supergasbras, it said on Friday.

The facility, with storage capacity of some 62,000 tons, would cost a total of 1.2 billion reais ($200.90 million) to be split between Ultra’s subsidiary Ultragaz and Supergasbras, Ultra said in the filing, adding that building works are expected to be completed in 2028.

($1 = 5.9730 reais)

By: Isabel Teles, Reuters / Dic 3, 2024.