XOM - Exxon Mobil Corporation

NYSE - Nasdaq Real-time price. Currency in USD
+1.17 (+1.71%)
As of 2:27PM EDT. Market open.
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Previous close68.30
Bid69.37 x 1300
Ask69.38 x 1800
Day's range68.87 - 69.53
52-week range64.65 - 87.36
Avg. volume10,799,341
Market cap293.935B
Beta (3Y monthly)1.17
PE ratio (TTM)16.74
EPS (TTM)4.15
Earnings date31 Oct 2019 - 4 Nov 2019
Forward dividend & yield3.48 (5.10%)
Ex-dividend date2019-08-12
1y target est82.74
Trade prices are not sourced from all markets
  • Here's Why 1 Analyst Prefers Chevron Stock Over ExxonMobil
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  • The Texas Power Casino Pays Off (for Now)

    The Texas Power Casino Pays Off (for Now)

    (Bloomberg Opinion) -- There’s a Vegas-like quality to the Texas electricity market. Whereas other regions use factors like capacity payments to encourage new power plants, Texas relies on the spin of the wheel. If temperatures are hot enough, and the wind is calm enough, and enough power generators go offline unexpectedly, a scramble for power spurs prices from the usual range of $20 to $30 per megawatt-hour up to $9,000.And that’s what happened last week:Merchant generators in Texas play this slot machine, hoping for a handful of these windfalls. BloombergNEF estimates the state’s generators reaped $1.5 billion across just two days last week, equivalent to more than 10% of the money paid in the wholesale electricity market last year.The Electric Reliability Council of Texas, or Ercot, banks on such jackpots tempting developers to build more capacity. The mechanism works, more or less, but the inevitable lag between market signals and new construction can leave the power market dangerously close to shortages — and consequently the spikes. This is shown clearly in the reports Ercot publishes twice a year providing a forecast of the state’s “reserve margin,” or spare capacity. The target level is 13.75% of peak demand. Here are the forecasts for 2020 through 2023 taken from the May report over the past seven years:The latest forecasts suggest expectations are beginning to turn again. While the expected reserve margin for 2020 has shrunk further, it has expanded further out, moving back above the target level in 2021. That may prove optimistic.NRG Energy Inc., one of the biggest power generators and retailers in Texas, said on its recent earnings call that Ercot most likely overestimates new capacity and underestimates closings. As warnings go, this one is less a call to arms and more a pitch to buy; NRG’s plants should profit in a tighter, more volatile market. That said, it is safe to assume that much of the  roughly 112 gigawatts of proposed projects — substantially bigger than the state’s total existing capacity — will not materialize. Less than a quarter of it had an agreement to hook plants into the grid signed at the end of July. Wind and solar projects dominate Texas’ pipeline and Greg Gordon, an analyst at Evercore ISI, typically discounts these by 35% and 75% respectively. He forecasts much tighter conditions in the medium term:In theory, this alternative view should spur new projects, especially solar farms. Hot, muggy days can mean air conditioners crank up just as the state’s formidable fleet of wind turbines slow for want of a breeze. Solar power, on the other hand, is tailor-made for those dog-day afternoons. But the state’s solar capacity of 1.9 gigawatts is low, and while there is a nominal 62 gigawatts in the works, most of it will never see the light of day. Tara Narayanan, a solar analyst for BloombergNEF, points to the impending roll-off of the investment tax credit for renewable projects as well as President Donald Trump’s tariffs on imported solar modules. Taken together, these mean the optimal window for building solar capacity approved before the end of 2019 is actually in 2022-2023, when developers can still utilize the highest tax credit while also purchasing equipment unburdened by the tariffs.(1) Ercot’s pipeline suggests perhaps 3.4 gigawatts of new solar capacity entering service by the end of next summer. Using that as a conservative estimate and plugging it into BloombergNEF’s U.S. “Power Mixer” tool, the result implies a cut to average peak summer prices in 2021 of almost $4 per megawatt-hour, knocking perhaps $270 million off fleet revenue. That’s unhelpful for merchant generators but hardly a game changer.Yet the game is changing at a broader level. Texas, like so many other power markets, is undergoing a transition. In addition to wind power, cheap shale gas pushes down on power prices while rising demand and the retirement of older thermal power plants offer support. Even if solar power has been slow to take hold, and reserve margins remain low, the Texas power market represents a gamble. After all, last week’s spike came after a months-long slump in power futures as expectations of a lucrative heat wave had declined. Similarly, while 2018’s summer was a hot one, there were no big price spikes that year. This is one reason, even with near-term reserve margins looking tight, investors have been reluctant to price that fully into generator stocks. It is also why, even with the prospect of markets remaining tight, there will be no wave of construction in big conventional plants. Solar’s quick lead times and the ability to scale up alongside demand is a structural advantage.The price volatility, and expectation of more, is spurring one important part of the market to take matters into its own hands: commercial and industrial customers. As even the likes of Exxon Mobil Corp. have discovered, a long-term renewable supply contract can deliver energy at stable prices, and the cost of such power continues to drop. Corporate power-purchase agreements signed in Texas this year are likely to surpass those for the entire U.S. just two years ago, according to BloombergNEF. Power producers in Texas should enjoy decent odds of more jackpots in the next few years, but the house is moving against them. (1) This assumes, of course, that neither the tax credit nor the tariffs are extended.To contact the author of this story: Liam Denning at ldenning1@bloomberg.netTo contact the editor responsible for this story: Daniel Niemi at dniemi1@bloomberg.netThis column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.Liam Denning is a Bloomberg Opinion columnist covering energy, mining and commodities. He previously was editor of the Wall Street Journal's Heard on the Street column and wrote for the Financial Times' Lex column. He was also an investment banker.For more articles like this, please visit us at bloomberg.com/opinion©2019 Bloomberg L.P.

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    Oil and gas giant Exxon is getting hit again. Has the story changed, or is the recent drop just par for the course?

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    Exxon Mobil Falls 3%

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    Exclusive: After 50 years in UK North Sea, Exxon eyes the exit - sources

    Exxon Mobil is considering a sale of its assets in the British North Sea after more than 50 years in the oil and gas basin as it focuses on U.S. shale production and new projects. The world's largest publicly traded energy company has held talks with a number of North Sea operators in recent weeks to gauge interest in some or all of its assets, which could fetch up to $2 billion, according to three industry sources with knowledge of the matter. Exxon declined to comment.

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  • The World’s Newest Petrostate Isn’t Ready for a Tsunami of Cash

    The World’s Newest Petrostate Isn’t Ready for a Tsunami of Cash

    (Bloomberg Markets) -- The Caribbean beats of reggae and soca ease into American hip-hop at a roadside bar in Georgetown, Guyana. Outside, teenagers hoot as they whiz past palm trees on mopeds. But for Gavin Singh, a 36-year-old investment banker, this is no time for play or relaxation. “People out there don’t really get it,” he says, pushing aside his mojito to emphasize his point. “We have a tsunami coming.”A tsunami of what?“Of cash. Of opportunity.”This tiny nation on the north coast of South America is about to become the world’s newest petrostate—and potentially the richest. In 2015, Exxon Mobil Corp. made what one of its executives described as a “fairy tale” discovery in the vast Stabroek exploration block off the Guyanese coast. Since then, it’s found so much oil that by the mid-2020s Guyana, with a population of about 778,000, will probably produce more crude per citizen than any other country.Crucially, however, Guyana—a poor former colony, first of the Dutch, then of the British—is unprepared for what’s coming. Its petroleum laws were written in the 1980s. The Department of Energy has an annual budget of $2 million. Five years after Exxon’s discovery, the country still hasn’t finished crafting relevant new laws or even established a regulatory body to oversee exploration and production. Last year the government set up a sovereign wealth fund to soak up as much as $5 billion in oil revenue per year by 2025, but there are no plans for how to spend it.Even as the windfall approaches, more and more questions are being raised about how the country sold exploration rights off its coast—not just to Exxon, but also to other outfits that followed in the supermajor’s wake. The State Assets Recovery Agency (SARA), an anticorruption unit looking into the leases, hasn’t named any targets. It’s too early for that, says its director, Clive Thomas. “We’re building up a case,” he says. Guyana’s oil age is dawning at a rocky political moment in this still-evolving democracy. The current president, David Granger, who heads a coalition government, lost a no-confidence ballot by a single vote in Parliament last December, triggering an election that as of late July hadn’t been scheduled. The parliamentary rebuff was a stinging reversal for Granger, who took office in May 2015, and the election could pave the way for the return of the People’s Progressive Party (PPP), which had held power for 23 years, including when Guyana first sold off its oil rights.Then there’s the specter of Venezuela, which borders Guyana to the northwest and has historically laid claim to part of its rich offshore fields. Last year, Venezuelan gunboats sailed in to hinder Exxon’s activities, but drilling carried on to the south in the Stabroek block. So far Guyana has managed to weather its neighbor’s interference—no doubt aided by the cratering economy and widespread unrest that’s preoccupied Nicolás Maduro’s regime in Caracas.The whiff of oil can be intoxicating, especially in a nation where the average income is $385 a month. “It’s really a matter of how wealthy you’re going to be, rather than whether you’re going to be wealthy at all,” says Minister of Natural Resources Raphael Trotman.But oil can sometimes be a curse. For every Norway or Qatar, there’s likely to be a grim counternarrative: an Angola or, for that matter, a Venezuela, which is a wreck even though it has the world’s largest oil reserves. “I keep hearing about how wealthy we will be as a country,” says Bharrat Jagdeo, a former president who’s now leader of the PPP. “People don’t realize the timelines. It requires hard work over an extended period of time to really get wealthy. That sense of caution is not there in this euphoria.”When Mark Bynoe, the director of Guyana’s Department of Energy, was a boy, he used to play cricket barefoot with friends in his village outside Georgetown. At the end of the day, his feet “would be shiny at the bottom,” he remembers. “We knew oil was around.”Bordered by Venezuela, Brazil, and Suriname—all producers—Guyana always held the promise of oil. But for decades after independence from Britain in 1966, explorers drilled nothing but dry holes. “We were practically begging people to take a block offshore,” says Jagdeo. “Nobody wanted to come.”Then along came Exxon. It was 1999, and Jagdeo was heading the government. Guyana and Exxon signed a production-sharing agreement that covered a 26,800-square-kilometer (10,348-square-mile) deep-water area spanning virtually the entire width of the country’s maritime borders. Given all the unsuccessful exploration, Exxon secured the rights to Stabroek under terms so generous that they would come back to haunt the country.The early years were frustrating for Exxon. Border disputes with Venezuela and Suriname impeded exploration. After the Suriname quarrel was settled in 2007, Exxon began gathering data and conducting seismic imaging along the eastern reaches of Stabroek. Then, in 2013, the Venezuelan navy boarded and for four days detained an exploration vessel contracted by Anadarko Petroleum Corp., another U.S. producer that was surveying in the area. Exxon plowed on. In 2014 oil prices crashed, and its partner in Stabroek, Royal Dutch Shell Plc, pulled out. Unwilling to shoulder the financial risks on its own, Exxon remained the operator responsible for exploration but brought in New York-based Hess Corp. and China’s state-backed Cnooc Ltd., handing them 30% and 25% stakes, respectively, in exchange for sharing drilling costs.When Exxon began drilling the wildcat well Liza-1 in March 2015, Guyana was just a couple months away from a general election. On May 20, four days after Granger emerged as the surprise winner, Exxon announced it had struck oil.The timeline would later prove controversial and become a focus of the SARA investigation. But one thing was clear: Oil was coming.When Liza-1 struck oil, Lars Mangal, one of Guyana’s foremost petroleum professionals, knew exactly what to do. He’d spent two decades working in oilfield services around the world for Houston-based Schlumberger Ltd. before ending up in the U.K. Now he needed to pack up his belongings, get back to Georgetown, lease a dockyard, and bid for the Exxon services contract. “This is the big one,” Mangal, who turns 54 in August, recalls thinking.He was right. His company is now one of the lead local investors in Guyana Shore Base Inc., which acts as Exxon’s main service hub in Georgetown. He has no doubt that Guyana needs to embrace Exxon’s plans for Stabroek oil. “Damn it,” he says. “Get it out of the ground.”Somebody has written a message on a whiteboard at Guyana Shore Base that reflects Mangal’s attitude. It reads, “Don’t obsess over who’s baking the cake. Figure out how to get a slice.”Lars’s younger brother, Jan, would almost certainly take issue with that. Jan Mangal, who also has a long track record in the oil industry, has become a leading critic of exploration deals that Exxon and other companies cut with the government.Jan, 49, worked at Chevron Corp. for 13 years after earning a doctorate in engineering at the University of Oxford. He became Granger’s energy adviser in 2017. From the start, he clashed with ministers who unsuccessfully resisted his call to have all of the country’s oil contracts published and open to public scrutiny. He didn’t last long in the role, leaving after a year when his contract wasn’t renewed. He’s now a consultant.“Corruption is the main reason why countries like Guyana fail with oil and gas,” Jan says. “It undermines everything.” He says that Guyana didn’t get a fair deal from Exxon—he calls it a dated, “colonial contract”—and that other leases have been awarded without due process, potentially costing the country billions of dollars in lost revenue and exposing vulnerable Guyana to the so-called resource curse.Exxon’s manager in Guyana, Rod Henson, disagrees. He says the contract reflects the high risk of drilling the first well. In any case, he says, “the revenues that are going to be generated from that give Guyana the flexibility and the opportunity to be anything they want to be.” The months before Exxon struck oil in 2015 were an unsettled time in Guyana. Then-President Donald Ramotar had clashed with Parliament over government spending. Fearing a no-confidence vote and the end of his party’s 23-year rule, he dissolved the legislative body and called a general election for May.At the same time, unbeknownst to the wider world, Exxon was getting ready to drill Liza-1. Other companies, smelling oil, were circling Guyana’s waters.On March 4, Ramotar signed an exploration lease for the 6,100-square-kilometer Canje block with Mid-Atlantic Oil & Gas, a little-known company run by Guyanese businessman Edris Dookie. The next day, Exxon, whose Stabroek block abuts Canje, began drilling.On April 28, Ramotar signed over another exploration lease, this time with the partnership of Tel Aviv-based Ratio Petroleum Energy Ltd. and Toronto-based Cataleya Energy Ltd. It covered the 13,535-square-kilometer Kaieteur block, also adjacent to Stabroek.On May 7, then-Minister of Natural Resources Robert Persaud announced that Exxon had struck oil. The general election was four days later, and on May 16, Granger, leader of the then-opposition, was sworn in as president. Four days after that, Exxon confirmed the discovery to the stock market.The award of oil leases in developing countries is one of the most secretive, competitive, and contested corners of the industry. Before oil is discovered, governments typically offer royalty rates and tax incentives that are favorable to exploration companies. As soon as a discovery is made, unsold leases nearby become extremely valuable overnight, allowing governments to set higher rates for them. This binary before-and-after phenomenon opens the door to abuse by people acting on inside information.As Bloomberg News first reported in May, SARA is now probing the deals Guyana cut with oil companies over the years. “We’re investigating the issuance of the licenses, for example, and the various blocks,” says SARA chief Thomas. He stresses that the postmortem is in the very early stages, so he can’t disclose much except to say the investigation is focused on the runup to the 2015 election.“There are so many red flags,” Jan Mangal says, looking back at that period. He says the government could have commanded much more favorable tax and royalty rates if the Canje and Kaieteur leases had been sold after Exxon’s Stabroek discovery was announced and not before. “The country could have got 10 or 100 times what it got for these massive, massive blocks,” he says.Ramotar says he didn’t know about the Exxon find when the Canje and Kaieteur deals were signed, adding, however, “I was told that the indications were good.” He says that the SARA investigation is “politically motivated” and that contracts signed under the current government should be looked at as well. He says he welcomes “any impartial international inquiry.”Persaud, the natural resources minister at the time, says focusing on the election timeline suggests “a wrong narrative.” He says the Canje and Kaieteur leases had been all but signed, sealed, and delivered in 2013. But then the Venezuelan navy boarded the Anadarko-contracted exploration vessel, spooking Guyanese authorities. Not wanting to provoke Venezuela further, Persaud says, the government put the contracts on hold. The Canje lease, which was published on government websites, could be interpreted as backing this version of events: “2013” has been crossed out and replaced with a handwritten “2015.”Representatives from Mid-Atlantic, Cataleya, and Ratio Petroleum concur with Persaud’s timeline. “We were working away steadily in good faith for many, many years,” Cataleya Chief Executive Officer Michael Cawood says. “This wasn’t something that popped up all of a sudden.”About a year after the leases were signed, Exxon took a 50% stake in Kaieteur and a 35% stake in Canje and became the operator of both blocks. Cawood says his group took “no cash consideration” from Exxon for the stake in Kaieteur. Dookie says there were “terms” agreed to with Exxon for its Canje stake but declined to say what there were. Exxon wasn’t the recipient of the Canje and Kaieteur blocks initially and had nothing to do with the talks at the time. Exxon declined to comment on terms. All the companies involved say they have acted entirely properly.In 2016, Exxon had a problem. Its deal with Guyana was 17 years old, and under the complex terms of the agreement, the supermajor was running out of time to find more oil. This was an opportunity for Guyana’s new government, now led by Granger, to update the 1999 contract and extract better terms. Such negotiations are a fine balancing act for governments: Push too little, and you get too little; push too hard, and the company might walk away.Natural Resources Minister Trotman took a different route: no negotiation at all. He says Guyana was worried, once again, about Venezuela, fearing Exxon’s discovery would rile its prickly neighbor; neither Exxon nor the government wanted to get into a protracted negotiation.Instead, in October 2016, the government and Exxon modified the terms of the existing 1999 deal.This was a missed opportunity of epic proportions, says the PPP’s Jagdeo, the opposition leader and former president. “They had 3 billion barrels of proven reserves,” he says. “One would have thought you would have gotten a better contract.”Trotman counters that the government’s overriding concern in the Exxon talks was finding “security in what it had.” That included getting an $18 million signing bonus that, Trotman says, “we believed we should use for … the prosecution of our case” against Venezuela to settle territorial claims.There was one hitch—a big one. The bonus was kept secret from the public for what Trotman describes as “national security” reasons. The 2016 contract that modified the terms of the original wouldn’t be made public until 2017 (following the intercession of Jan Mangal), but in the small world of Guyana, it wasn’t long before word leaked out and caused an uproar. “If this is what they do with $18 million, what will they do with all the billions to come?” says Charles Ramson, 35, a PPP politician.Bynoe, the current energy director, says it was a mistake not to be more open about the $18 million. In retrospect, Trotman agrees. “We should have confided in the people much earlier,” he says. In addition to the signing bonus, according to Exxon’s Henson, the government got more “rental type payments,” royalties, and commitments of local content as part of the deal. But, crucially, the modified terms also allowed Exxon more time to explore and develop Liza. Henson says that without the 2016 modifications he’s “absolutely certain we would not be producing oil in 2020.”The controversy surrounding the 2016 contract doesn’t end there. According to an analysis of the agreement by Rystad Energy AS, an Oslo-based consultancy, Guyana will take about 60% of the oil’s profits, with the remainder going to Exxon, Hess, and Cnooc.That’s considerably lower than the global average of 75% for offshore projects, Rystad said in a 2018 report. However, it also pointed out that countries in the early stages of oil and gas development, such as Mozambique and Mauritania, are often forced to “sweeten the pot” for the exploration companies. “Clearly we have to make a profit,” Henson says. “We understand there are benefits to us and our partners, but we truly want this to benefit the country.”Bynoe takes a Goldilocks view of the whole affair. “Is it the greatest contract for government? I would say no,” he says. “Is it the worst contract? I would still say no.” Over time, he says, Guyana can “incrementally improve the conditions.”With that in mind, he says, it’s time to look forward. “We have been looking back about the contract,” he says. “There’s been too little attention in how will we treat these resources when they begin to flow to us.” At Exxon’s Investor Day meeting at the New York Stock Exchange in March, Guyana took center stage. It’s not hard to see why. Senior Vice President Neil Chapman—the exec who’d once described the Stabroek find as a “fairy tale”—pointed to a chart featuring estimates from Wood Mackenzie Ltd., an Edinburgh-based energy consulting firm. It showed that Exxon’s Guyana wells will be the most profitable of all new deep-water projects by major oil companies.Exxon expects the first Stabroek oil to flow to the Liza Destiny, a storage and offloading vessel, in early 2020, with production quickly ramping up to 120,000 barrels a day and rising by 2025 to 750,000 a day (roughly on a par with last year’s daily output in Indonesia, which has a population of 264 million).As for Guyana, the government estimates the Exxon deal will bring in $300 million in 2020, or about a third of the country’s entire tax revenue, and surge to $5 billion by 2025.“They say Guyana will be one of the richest countries in the world,” says Melissa Garrett, a waitress who supplements her income by selling potatoes, eggplant, and plantains at a stall at Georgetown’s century-old Bourda market. “People are in the mood for change. They want it now.”They also need to come to terms with the massive transformation coming their way, says Singh, the investment banker lingering over his mojito at the roadside bar. “Sitting back and doing nothing can be the worst mistake they can make,” he says.Georgetown—its crumbling colonial buildings set amid canals built by the Dutch in the 18th century—resembles a developing-world Amsterdam that’s faded in the harsh sunlight. On its bustling narrow streets, Guyanese descendants of Indian indentured laborers and African slaves live and work side by side, shop at the same markets, and dream the same dreams of wonders coming their way thanks to oil.Guyana’s political elite is torn over how to spend the money. The Granger government has said it wants to use the windfall to reshape the economy, pumping money into health and education, into the country’s vast natural resources, and into rail, road, and port projects that could provide an important pathway to the Atlantic for northern Brazil. Thomas, the head of SARA, favors bypassing government altogether in favor of a universal basic income-like stipend of $5,000 per family.First things first, says Jan Mangal. “Guyana really needs to fix all of its existing problems now before the oil money flows,” he says. “If it doesn’t, the oil money will exacerbate the existing problems and make them worse.”Chris Ram, a lawyer and former newspaper columnist (he broke the news about the $18 million signing bonus), worries that, rather than taking a leap forward propelled by oil, Guyana could slip backward. In the 1980s, under left-wing strongman Forbes Burnham, Guyana shared many traits with today’s Venezuela. Although democracy took root in the 1990s, Ram fears for its fragility.“We don’t have a culture of democracy,” he says over a meal in one of Georgetown’s many Indian curry houses. “The constitution is weak and open to abuse. Problems are swept under the carpet. It’s frightening. All the elements of a resource curse are there.”Crowley covers oil for Bloomberg in Houston.  To contact the author of this story: Kevin Crowley in Houston at kcrowley1@bloomberg.netTo contact the editor responsible for this story: Stryker McGuire at smcguire12@bloomberg.netFor more articles like this, please visit us at bloomberg.com©2019 Bloomberg L.P.

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  • Bloomberg

    Saudi Aramco Puts the ‘Brief’ in ‘Briefing’

    (Bloomberg Opinion) -- Great thirty minutes, guys.Monday morning’s much-ballyhooed earnings call from Saudi Arabian Oil Co., or Saudi Aramco, was remarkable chiefly for its brevity. About 25 minutes in, the host was reminding people to get their questions into the queue. Just after 9:30 a.m. in New York, it was time for closing remarks.Aramco, the biggest oil major in the world, is owned by the government of Saudi Arabia, so the fact it was putting anyone on the line to talk about a published set of accounts is noteworthy. And, to be fair, they had blocked out an hour. Yet the call yielded little new information. That partly reflected the caliber of the questions, with the first amounting to “please explain why your company is so awesome.” But it was also a function of the usual reticence of major companies, compounded by the fact that this one is, after all, not merely unlisted but a virtual state within a famously secretive state.It was, therefore, entirely understandable that Aramco didn’t offer up much detail on plans to buy a 20% stake in the refining and chemicals business of India’s Reliance Industries Ltd., only made public a few hours before the call got underway.On the other hand, it was unfortunate that CFO Khalid Al-Dabbagh effectively dodged a decent question on Aramco’s capital expenditure and dividend policy. If, as recent reports suggest, Aramco still intends to go through with its IPO and this was a dry run for that, then questions about cash flow and dividends will be the ones that really matter.In a world where energy stocks have fallen out of favor because of a legacy of excess spending and concern about faltering demand growth, the majors are valued chiefly for their dividends. A public Aramco would be no different in this respect (see this).The first-half numbers just published confirmed Aramco is a cash-flow juggernaut, generating free cash flow after capex of almost $38 billion and paying its sole shareholder a dividend of more than $46 billion. The details beneath such numbers matter, though. After all, it’s immediately obvious that, despite generating more free cash flow in the first half than BP Plc, Chevron Corp., Exxon Mobil Corp., Royal Dutch Shell Plc, and Total SA combined, Aramco borrowed to pay that dividend to the government. While net debt is just 2% of capital employed, there was a $28 billion swing in net indebtedness in the space of 12 months. And Aramco’s capex in the first half looked low – which is why it was questioned – and Al-Dabbagh did allow that “timing” was one reason for that, suggesting it would rise in the second half of 2019.Roughly 40% of the first-half dividend was an outsize special payment predicated on 2018’s “exceptionally strong financial performance,” yet sitting oddly with a year-over-year decline in first-half profit. Coming alongside Aramco’s acquisition of the government’s majority stake in Saudi Basic Industries, or Sabic, this reinforces the sense that the company chiefly represents a financing channel for a government facing chronic deficits at current oil prices. To which one might respond: Duh, like, it’s a national oil company, what exactly did you think it was for?This is the central issue when it comes to Aramco’s valuation, however, because the closeness of that relationship with the government affects the risk premium on the company’s earnings. Taking the 12 months through June as a whole, Aramco’s capex of about $35 billion left it with free cash flow of about $88 billion, more than enough to fund $72 billion of dividend payments. Putting those on an Exxon-like yield of 5% implies a value of $1.45 trillion.Yet, assuming ordinary dividends are running at $52 billion a year – as the accounts suggest – about $20 billion of that payout is akin to the more discretionary buybacks oil majors use to distribute exceptional income. Aramco’s payout was 99% of earnings in the first half of 2019 versus just 52% a year earlier. That cyclical element should be priced at a discount to ordinary dividends, especially in light of Aramco’s role in Saudi Arabia’s public finances. Price the dividend at 6%, and the value drops to $1.21 trillion; at 7%, a shade higher than the yield for BP and Shell, it falls to $1.03 trillion.These are still very big numbers (and in line with the valuation I put together last year). They remain, however, far short of the $2 trillion valuation bragged about by Prince Mohammed bin Salman; and this despite those numbers reflecting, in part, an “exceptionally” strong year for the company.If Aramco’s owner still wants to get even close to a two in front of those twelve zeroes on the trading screen some day, then the company needs either a fundamental shift in the outlook for the oil market or a fundamental reappraisal of its ability to squeeze even more dividends out of that market. It has only some influence over the first option. The second would require at least a bit more time on the phone. Update: A typographical error in an earlier version of this story put Aramco’s implied valuation with a 6% dividend at $1.21 billion instead of $1.21 trillion.To contact the author of this story: Liam Denning at ldenning1@bloomberg.netTo contact the editor responsible for this story: Mark Gongloff at mgongloff1@bloomberg.netThis column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.Liam Denning is a Bloomberg Opinion columnist covering energy, mining and commodities. He previously was editor of the Wall Street Journal's Heard on the Street column and wrote for the Financial Times' Lex column. He was also an investment banker.For more articles like this, please visit us at bloomberg.com/opinion©2019 Bloomberg L.P.

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