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ExxonMobil (XOM) plans to slash 2020 capital spending and cash operating expenses to make up for the massive shortfall in cash flows, while managing to avoid any write-down so far.
The U.S. oil giant is working hard to ensure it survives the current industry downturn. It's showing just how strong it is along the way.
The exploration and production names got a shot in the arm today as investors took a positive view of the economic future.
The Zacks Analyst Blog Highlights: Visa, JPMorgan Chase, Bank of America, Chevron and Eli Lilly
With the Dow and the S&P 500 booking their best quarterly performance since 1987, one could consider stepping into the markets again with an investment perspective.
(Bloomberg) -- America’s biggest oil companies are coming under increasing pressure from climate-conscious investors to disclose their long-term forecasts for crude prices as the Covid-19 pandemic injects fresh uncertainty into the demand outlook for fossil fuels.Exxon Mobil Corp. and Chevron Corp. don’t publish such estimates, meaning that shareholders are less able to scrutinize how the companies’ investment plans square with expectations for a global transition to clean energy. That needs to change, according to the New York State Common Retirement Fund, California State Teachers’ Retirement System, and Ceres, a Boston-based coalition of investors with $30 trillion of assets.In Europe, major oil companies are sharing their long-term forecasts, with dramatic results. Two weeks ago, BP Plc said it had radically reduced its long-term price assumption for Brent crude, causing a writedown of as much as $17.5 billion. Royal Dutch Shell Plc warned Tuesday that it would write down as much as $22 billion in the second quarter as the pandemic hammers demand for everything from oil to liquefied natural gas.Long-term price assumptions are critical because they’re used by Big Oil to determine whether or not a resource will be economically viable and at what value it’s held on a company’s books. Activists and some investors say companies are at risk of being overly optimistic in their assessment of future crude prices. That could lead to them to build expensive projects that effectively become worthless — so-called stranded assets — in a world transitioning toward low-carbon fuel sources.“Exxon and Chevron should be more transparent and disclose long-term price forecasts and other information that investors need to assess their companies’ low-carbon transition plans,” said Mark Johnson, a spokesman for the Office of the New York State Comptroller, which oversees the New York State Common Retirement Fund. “Without this information, investors cannot assess whether Exxon and Chevron are serious, or just paying lip service to the threat of climate change.”Chevron compiles “multiple forecast scenarios” informed by third-party information and its own analysis, spokesman Sean Comey said in an emailed statement. “We continue to view this data as proprietary since it contains sensitive business information that would be of interest to our competitors.”Exxon evaluates annual plans and major investments across a range of price scenarios, and it discloses guidance on the impact of price fluctuations in annual regulatory filings, spokesman Casey Norton said in an emailed response to questions. The company supports the goals of the Paris Agreement on climate change, Norton said.“The world will continue to require significant investment in liquids and natural gas,” he said.Covid-19 has brought the issue of future pricing into sharp relief. Before the pandemic, peak crude demand was thought to be at least a decade away. But the virus has caused such a savage drop-off in oil consumption that some, including BP CEO Bernard Looney, are questioning if global usage of fossil fuels will ever return to pre-pandemic levels.“At the heart of investor concern is that they’re planning for a future that’s not likely to come to pass -- a future of high demand and high prices,” said Andrew Logan, senior director of oil and gas at Ceres.Speaking to investors in March, Exxon and Chevron both gave their long-term cash flow projections at $60 a barrel, roughly the average of the past five years. But the projections aren’t a long-term price forecast and don’t provide insights into climate planning or potential writedowns. Meanwhile, crude is currently trading around $40 a barrel, with lingering uncertainty over the recovery in global demand or whether OPEC can maintain supply cuts.Both companies regularly tout their new projects as having low break-even costs that make them more competitive than those of their rivals. For example, Exxon has said its projects in Guyana and the Permian Basin on West Texas and New Mexico will make “double-digit returns” at $40 a barrel. But it may be a different story for other parts of its portfolio. If oil was at $30, Exxon would own 60% of the oil majors’ 30 lowest-margin assets by production, according to researcher Wood Mackenzie Ltd.“There’s a bit of opaqueness to the disclosure” from American oil companies without the long-term price assumptions, said Brian Rice, a fund manager at California State Teachers’ Retirement System, also known as Calstrs. “From an engagement perspective, it can be frustrating,” he said, adding that it could be a data point that more investors push for in the future. Calstrs and the New York State Common Retirement Fund manage about $453 billion between them including shares of Exxon and Chevron.While there’s no specific regulation than prevents U.S. companies from publishing long-term price forecasts, many are reluctant to do so for fear of exposing themselves to lawsuits accusing the companies of trying to influence oil prices, according to Ed Hirs, an energy fellow at the University of Houston.For investors, the risk they face is that price assumptions are too rosy. But it’s also a critical issue for the environment. Much of Canada’s oil sands, among the most carbon-intensive parts of the industry, were developed with the expectation of prices above $80 a barrel, according to Kathy Mulvey, a campaign director at the Union of Concerned Scientists.“We need more scrutiny at the front end of these projects,” she said in an interview. “They pose systemic risks to the environment if they get it wrong.”For more articles like this, please visit us at bloomberg.comSubscribe now to stay ahead with the most trusted business news source.©2020 Bloomberg L.P.
Chevron Australia Downstream Pty Ltd., a wholly-owned subsidiary of Chevron Corporation, today announced that it has completed the acquisition from Puma Energy Asia Pacific B.V. of all shares and equity interests of Puma Energy (Australia) Holdings Pty Ltd for the amount of AU$425 million.
In the latest trading session, Chevron (CVX) closed at $89.23, marking a +1.78% move from the previous day.
The long struggling shale pioneer Chesapeake Energy (CHK) filed for Chapter 11 bankruptcy protection, while Italy's Eni SpA (E) acquired three wind farm projects.
(Bloomberg Opinion) -- BHP Group’s future can do without hydrocarbons.The world’s largest digger is among the last heavyweights to mix mines with a significant presence in oil, a combination that is becoming harder to justify over the long term. Crude demand will be slow to recover after a pandemic that has kept workers home and jets grounded, and some of that appetite will never come back. Meanwhile, pressure to cut carbon emissions is only increasing. Oil giant BP Plc is the latest to take a hit, warning it expects impairments and write-offs worth as much as $17.5 billion due to a more gloomy view of what lies ahead. The Big Australian could benefit from a dose of that realism.There is little question that the petroleum division, with assets from Western Australia to the Gulf of Mexico, has generated impressive cash over the years — if you exclude the ill-considered foray into U.S. shale, a $20 billion investment (excluding capital expenditure) much criticized by activist fund Elliott Management Corp. and eventually sold off in 2018. In the six months to December 2019, the unit accounted for about 13% of BHP’s total earnings before interest, tax, depreciation and amortization, notching up an impressive 65% margin. Only iron ore, the group’s top earner, was higher, at 69%. Add in low production costs that cushion the blow of 2020’s lackluster oil prices, and it’s easy to see why putting in more cash is tempting when, as analyst Glyn Lawcock of UBS Group AG points out, the miner has few readily available alternative investments.It’s also true that while the medium-term global appetite for oil looks far less certain than it did, there’s a more appealing argument to be made around fading supply. Indeed, the $115 billion miner’s central expectation last year of demand hitting a high point in the mid-2030s now looks bullish, compared to comments from the likes of Royal Dutch Shell Plc and BP. A peak even in the middle of this decade, BHP’s low-demand scenario, may prove optimistic. On the production side, though, the miner is right to point out that the industry has been investing less, a trend that will only accelerate after a disastrous 2020 and squeeze future production. BHP has estimated ongoing natural field decline at a rate of 3% to 5% per year.None of this means boss Mike Henry and his team can afford to ignore the signs that this year will prove to be a turning point for oil.Diversification has benefits, but operating synergies between oil and mining are debatable — it’s not an accident that while majors sold out of one or the other, none have returned. As a standalone business, the petroleum division might arguably have ventured less enthusiastically into shale. And the risk today is clear: Staying on can turn into overstaying.Here, Henry can reflect on the experience in thermal coal, where BHP woke up too late. Rival Rio Tinto Group offloaded its last coal mine in 2018, wrapping up a process that began in 2013. BHP held on to decent assets, using up tax losses. It’s now trying to retreat just as Anglo American Plc prepares to hive off its South African coal mines, and interest in the dirty fuel has dwindled. Oil has fewer easy substitutes, but it's conceivable that, with significant changes in policy, crude could be left similarly stranded. Accepting the need for an exit from a business that BHP has been in since the 1960s is only the first step, of course. For one, a carve-out in the mold of coal-to-aluminium producer South32 Ltd., which BHP spun off successfully in 2015, is harder to advocate for oil. The move then was about getting more out of sub-scale operations. In petroleum, BHP is not the operator for many of the assets, making such efficiencies harder to accomplish.BHP can begin by reviewing its portfolio, starting with mature assets in Australia. Partner Exxon Mobil Corp. has said that it’s seeking a buyer for its share of the Gippsland Basin oil and gas development in the Bass Strait; a joint sale with BHP has been considered before. Chevron Corp., meanwhile, has put its stake in the giant North West Shelf liquefied natural gas venture on the block. That operation, Australia’s largest LNG project, is shifting from processing its own gas to opening services to new suppliers, a business known as tolling — less suited to either Chevron or BHP. The mining giant has in any event been less enthusiastic about gas than oil.Granted, even that won’t be easy. Australia churns up a decent amount of revenue, and BHP can argue it is better to continue taking cash now, at the risk of selling for less later. Some investors may agree. A similarly short-term view in the Gulf of Mexico could see it adding to the portfolio as distressed rivals are forced out.For newish boss Henry, though, none of those would look like the decisions of a company preparing for a greener future. He has an opportunity to outline the path to net zero emissions when BHP announces full-year results in August. An exit plan for oil would be one decisive step toward that goal.This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.Clara Ferreira Marques is a Bloomberg Opinion columnist covering commodities and environmental, social and governance issues. Previously, she was an associate editor for Reuters Breakingviews, and editor and correspondent for Reuters in Singapore, India, the U.K., Italy and Russia.For more articles like this, please visit us at bloomberg.com/opinionSubscribe now to stay ahead with the most trusted business news source.©2020 Bloomberg L.P.
Chevron (CVX)-run Gorgon and Wheatstone natural gas facilities are expected to churn out 500 terajoules of domestic gas daily for the Western Australian market.
(Bloomberg Opinion) -- It’s the mother of all payouts.The $75 billion that Saudi Aramco doles out in dividends every year dwarfs what any other listed company gives to shareholders. It’s roughly equivalent to the payouts from Exxon Mobil Corp., Royal Dutch Shell Plc, Chevron Corp., BP Plc, Total SA, PetroChina Co., Eni SpA, Petroleo Brasiliero SA and China Petroleum & Chemical Corp. or Sinopec — put together.That makes Chief Executive Officer Amin Nasser’s promise to continue that level of returns for the next five years an extraordinary vote of confidence in an oil market awash with uncertainties. Saudi Aramco will be prepared to borrow money to ensure that it meets its commitment this year despite oil prices heading into negative territory, he said this month.Running up debts to keep the dividend on track is standard practice for energy companies amid the carnage of 2020’s oil market — except for those, like Shell, which plan to cut payouts altogether. You only want to fund dividends out of borrowings, though, if you’re certain it’ll be a strictly temporary measure. The risk for Aramco is that upholding such a long-term promise to shareholders will bend its entire business out of shape, just when it needs to be especially nimble as crude demand slows and goes into reverse. The core of Aramco’s profitability is its astonishingly low production costs, with operating expenses amounting to not much more than $8 a barrel of oil and equivalent products last year. It’s remarkable how quickly the spending adds up, though. Royalties paid to the Saudi state alone added another $10 a barrel or so, while corporate income tax came to around $19 a barrel and dividends swallowed a further $15. Once all those tolls were paid, Aramco didn’t have a lot of spare change left out of $60-a-barrel oil, let alone the stuff in the $40-a-barrel range it’s selling at the moment.A firm dividend policy is an unusually inflexible cost. Unlike the royalties and income taxes levied as a percentage of Aramco’s revenues and profits, payouts don’t automatically shrink if the price of crude declines. If anything, the burden per barrel rises further when prices and output fall. Perhaps in recognition of this, the Saudi state has from the start agreed to forgo its portion of any payouts to the extent that receiving them would get in the way of Umm-and-Abu investors getting their share(1). That may help maintain a theoretical $75 billion-a-year payout but it makes a nonsense of the idea that all shareholders are equal, not to mention the principle that a dividend policy is some sort of a commitment to future earnings. It’s not clear, either, why a company with this get-out clause would want to take on debt to meet its promised payments, although Aramco’s borrowing costs are essentially identical to those of the Saudi state.Dividends aren’t the end of Aramco’s committed spending. Its purchase of a majority stake in chemicals company Saudi Basic Industries Corp., or Sabic, was completed this month, committing it to about $69 billion of payments over the next six years — even after a restructured plan pushed the bulk of the cash outflow toward the middle of the decade.Then there’s a potential $15 billion investment in Reliance Industries Ltd.’s Jamnagar refinery in India, $20 billion on a separate planned chemicals venture with Sabic, plus Sabic’s own $5 billion a year or so of capital spending which will now sit on Aramco’s balance sheet.Add it all up and the picture is troubling. It’s likely to be several years before operating cash flows rise above $100 billion a year again, even with Sabic’s business consolidated. If Aramco wants to spend three-quarters of that sum on its dividend while laying out $10 billion to $15 billion annually for Sabic’s finance and investment costs, then capex on its core operations will have to fall to a third or less of the $35 billion-odd that the company was spending until recently. For all that executives are confident of their ability to increase production at very low costs, that sort of belt-tightening would make the easiest route to higher profits — lifting crude output from its pre-Covid 10 million daily barrels to around 13 million — extraordinarily difficult to achieve.That path is likely to be constrained, anyway, by several years of weak demand growth as the world recovers from Covid-19. Not to mention the fact that Aramco’s importance to the oil market rests on the proposition that increases in its output, coordinated via OPEC+, should make prices move in the opposite direction, resulting in little by way of net revenue gains for the company.Unlike most of its competitors, Saudi Aramco doesn’t really need to be so focused on dividends. All but 1.5% of its shares are held by the same state that’s hoovering up royalty and tax payments further up the income statement. Riyadh shouldn’t really care how it’s getting paid, as long as it’s getting paid.That dividend policy looks more like a swaggering attempt to hold back the tide of an oil market on the edge of terminal decline. The quicker Aramco acknowledges that, the better equipped it will be to handle the coming turmoil.(1) Americans would call them "Mom-and-Pop shareholders."This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.David Fickling is a Bloomberg Opinion columnist covering commodities, as well as industrial and consumer companies. He has been a reporter for Bloomberg News, Dow Jones, the Wall Street Journal, the Financial Times and the Guardian.For more articles like this, please visit us at bloomberg.com/opinionSubscribe now to stay ahead with the most trusted business news source.©2020 Bloomberg L.P.
Per Wood Mackenzie analysis, Chevron (CVX) and Royal Dutch Shell's (RDS.A) upstream portfolios are the most resilient at $30/barrel crude while ExxonMobil (XOM) is least resilient.
In the latest trading session, Chevron (CVX) closed at $91.44, marking a -0.16% move from the previous day.
(Bloomberg) -- After more than three decades, the project that kick-started Australia’s push to become a liquefied natural gas powerhouse faces a shakeup.Woodside Petroleum Ltd. on Tuesday reiterated that it would consider buying Chevron Corp.’s stake in North West Shelf and indicated that other joint venture partners could be looking to exit. That may mark the end of a delicate balance at Australia’s biggest LNG project, where six international partners have equal stakes, as the plant needs to find new gas supplies to keep on humming.As operator Woodside is viewed by many in the industry as the logical buyer for Chevron’s stake. The U.S. oil major announced last week it would start a formal marketing process after receiving unsolicited approaches from potential buyers, though the other five stakeholders have pre-emptive rights.“This has been the jewel in Woodside’s crown for a long period of time, so you don’t want your neighbors to put up the ‘For Sale’ sign and then get the wrong people move in next door,” Chief Executive Officer Peter Coleman, said at a Credit Suisse Group AG energy conference Tuesday. “We have a right, we’ll look at it. Whether we participate or not is really going to depend on price.”The stake could be worth as much as $3.7 billion, according to Saul Kavonic, a resources analyst at Credit Suisse. Chevron said that the time was right to consider a sale as NWS moves to becoming a third-party tolling facility.That transition means the asset is more likely to appeal to infrastructure investors rather than oil and gas industry players, Coleman said. Plenty of “tire-kickers” were likely to show interest, but he expected Chevron to be selective in who it invites into the data room.First In Queue“Maybe Chevron formed the view that there were other joint venturers that were starting to position themselves to sell assets globally, of which North West Shelf may have been one of those,” Coleman said when asked about the U.S. company’s motivation. “Maybe they formed the view that they would rather be the first in the queue, rather than follow someone else.”A Chevron spokesman declined to comment on Coleman’s statement. The other participants in NWS are BP Plc, Royal Dutch Shell Plc, BHP Group and Japan Australia LNG.“It increasingly appears Woodside may double down on its existing footprint alongside new partners, and take advantage of majors’ exits to become the ‘basin master’ in the region,” Kavonic said in an email.North West Shelf, which has loaded more than 5,000 LNG cargoes since 1989, has been considering options to sustain output as its foundational gas fields begin to run dry. Woodside wants gas from its Browse project to feed into NWS, but has struggled to get the partners to align on that strategy.Chevron has been seen as an obstacle to Woodside’s plans because, unlike most of the other NWS partners, it has no stake in Browse and has competing gas resources in the region that could also use the infrastructure.Senegal DelaysSeparately, Coleman played down a report that Senegal had been forced to delay its first oil and gas projects by as much as two years due to coronavirus. The timetable for the Woodside-operated Sangomar development was only likely to be pushed back by a few months, he said. The company approved the first phase in January and is targeting first oil in early 2023.Still, delays to the group’s major projects meant Woodside’s long-term production growth target of more than 6% was likely now unachievable, RBC Capital Markets analyst Gordon Ramsay said in a note.Read: Australia LNG Stalwarts Delay Flagship Projects on Virus Hit“We see Woodside’s medium- to long-term growth outlook as challenged, considering an outlook of project delays, a relatively weak LNG, oil and broader market environment and ever-decreasing oil-indexed LNG contractual slopes,” Ramsay said.Woodside shares were down 0.5% at A$21.97 at 2:38 p.m. Sydney time. They have fallen about 36% this year amid a broad decline in oil and gas prices.For more articles like this, please visit us at bloomberg.comSubscribe now to stay ahead with the most trusted business news source.©2020 Bloomberg L.P.
Chevron's (CVX) share in the North West Shelf project is estimated between $3 billion and $4 billion, lower than the pre-pandemic price of $6 billion due to a dramatic plunge in LNG prices this year.
The Zacks Analyst Blog Highlights: ExxonMobil, Chevron, Occidental Petroleum, National Oilwell Varco and Apache
The three stocks that I think will have to reevaluate their dividends soon are ExxonMobil (NYSE: XOM), Chevron (NYSE: CVX), and Simon Property Group (NYSE: SPG). At first glance, it may seem that dividends from big oil companies are about as safe as it gets in investing. Oil companies have been profitable for decades, they are a huge part of the economy, and there's no way they're not making gobs of money...right?
(Bloomberg) -- Oil production in Venezuela, the country with the world’s largest reserves of crude, has fallen to a 75-year low with U.S. sanctions continuing to cripple the country’s exports.Venezuela’s state-run oil company Petroleos de Venezuela SA lowered its production estimates to 374,000 barrels a day as of Wednesday, according to a document seen by Bloomberg, a level not seen since 1945. Its slide is a result of U.S. sanctions that have scared most of the world’s oil buyers away from Venezuelan crude, resulting in a storage glut that forced it to shut fields across the nation.PDVSA’s production estimate is 57% lower than planned output, according to the document. The projection -- which takes into account oil wells performance registries -- is also a stark contrast with the 550,000 barrels a day production reported by secondary sources to OPEC in May.A PDVSA press official declined to comment.The drop comes amid increased pressure from the U.S. government, with the Treasury Department threatening to sanction 50 vessels on top of previous banned companies operating ships lifting crude from Venezuela, including those belonging to PDVSA trading with Cuba.The once-prolific Orinoco Belt has been hit the hardest, with an expected 79% drop in output, according to the document. Production in the light crude fields of the Maracaibo basin has dropped 45%.The impact has affected PDVSA’s joint ventures, such as Petrozamora with GBP Global Resources NV in the Maracaibo basin, according to people familiar with the matter who asked not to be identified because the information isn’t public. PDVSA shut joint venture oil fields in Bachaquero and Lagunillas this week, due to the lack of vessels lifting crude in the area, they said.Petrozamora, one of Venezuela‘s most productive fields in the country, was down to 28,000 barrels a day on Wednesday, compared to 94,700 barrels a day a year ago, the people said. Boscan, run by PDVSA and Chevron Corp., halted production in early May, one person said.Output at the Chevron-PDVSA joint venture Petropiar in the Orinoco Belt has fallen 70% since January to 30,000 barrels a day, one person said.Chevron defers questions on its Venezuela joint ventures to PDVSA, spokesperson Ray Fohr said in an email.The situation isn’t likely to resolve soon. Two incoming vessels due to lift crude recently canceled plans, according to one of the people.For more articles like this, please visit us at bloomberg.comSubscribe now to stay ahead with the most trusted business news source.©2020 Bloomberg L.P.