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(Bloomberg Opinion) -- As oil companies flesh out plans to cut carbon emissions, their peers in the mining sector risk being left behind. BHP Group, Rio Tinto Group and Vale SA are already among the world’s largest emitters, thanks to the vast amounts of carbon spewed out turning their key product of iron ore into steel. Among producers with listings on major developed exchanges, only Royal Dutch Shell Plc sits higher than the big three miners in terms of so-called Scope 3 emissions. (This describes pollution generated when a company’s products are used, such as when gasoline is burned in a car or steel is produced in a mill. It comprises the vast majority of total emissions in the resources sector.(1))Oil companies are already working to address that issue. Eni SpA, Shell, Total SE and Repsol SA all have plans to reduce the emissions intensity of their products by about a third by the 2030s, with sharper cuts to 2050. BP Plc has signed up to a more ambitious target, reducing oil production 40% by 2030.The big iron miners, on the other hand, have made do with only the vaguest of promises. Fortescue Metals Group Ltd. refuses to even disclose its easily calculated Scope 3 total. BHP’s announcement of its plans Sept. 10 is likely to set a benchmark for other companies. New Chief Executive Officer Mike Henry has good reason to be bold.To see why, it’s worth considering what makes BHP unique among big miners. Unlike its peers, the company also has a significant petroleum business, with gas comprising about 55% of its 109 million barrels of annual oil-equivalent output. Producing another fossil fuel might not seem the most obvious way for BHP to decarbonize — but its expertise in the industry could go a long way toward reducing emissions from its steel mill customers.To make more than a marginal reduction in the 7% to 8% of global emissions that come from steelmaking will involve either a breakthrough in capturing carbon emissions and storing them underground, or a switch from making metal in blast furnaces to using electric arc furnaces. Understanding petroleum geology and engineering will be a major advantage in both cases.Carbon storage has never lived up to the hype. But to the extent that it’s viable anywhere in the world, it’s where CO2 is injected into underground petroleum reservoirs, usually to drive more oil and gas to the surface. If BHP’s customers are to go down that route, it’s the only major miner that could make money from being part of such a solution.As we’ve argued, the more likely approach is a switch to arc furnaces, which use electricity rather than coal to melt their metal. A growing mountain of steel scrap in China, combined with likely prices on carbon emissions and greater ability to match output to demand, should see them replacing an increasing number of blast furnaces over the coming decades. BHP itself sees the share of blast furnaces declining from 70% of global steelmaking capacity to between 55% and 60% by 2050.Mining companies genuinely motivated to halt rather than advance climate change should see a great opportunity in this shift. The key commodity for a world making steel without blast furnaces would be direct reduced iron, which can be produced by burning off the oxygen in iron ore using natural gas or hydrogen — probably in the easily transported form of hot briquetted iron, or HBI. BHP had bad experiences with this product two decades ago, but the technology hasn’t stood still and demand is forecast to rise rapidly. If the four miners that account for more than two-thirds of iron ore in the seaborne market committed to converting a rising share of their output to HBI, then they’d be nudging customers to decarbonize their steel mills, while selling a product that changes hands for about three times the price of iron ore. So far, though, only Vale has shown much interest.As a petroleum producer in the North West Shelf off the coast of the iron-rich Pilbara region, BHP is well-placed to provide the power an Australian HBI industry would need — first via “blue hydrogen” made from methane with carbon capture, but ultimately with “green hydrogen” made by splitting water molecules with renewable power and transported via legacy natural gas infrastructure.Such a switch wouldn’t be good news for BHP’s coking coal business, which is heavily dependent on blast furnaces retaining their market share. Becoming part of the solution, though, would allow the company to manage the decline of coking coal while making money from the technology that will disrupt it, rather than crossing its fingers that the world will fail to address climate change.The mining industry has played its cards well convincing environmentally minded investors that there’s no alternative to blast furnaces. That’s helped miners avoid the opprobrium, divestment and capital drought that's hit thermal coal of late — but with the world's fossil fuel-free steel mill starting operations this week, it’s becoming an increasingly untenable position.BHP’s reluctance to accept what was going to happen to the coal power industry in the 2010s cost its shareholders dearly. Is it going to make the same mistake again with steel?(1) Some oil companies, including Exxon Mobil Corp. and Chevron Corp., don't declare their Scope 3 emissions. BP would have comparable figures to Shell if it equity-accounted the emissions from its stake in Rosneft Oil Co.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.
(Bloomberg Opinion) -- Trading saved European Big Oil from the full impact of this year’s oil crisis. It’s not the first time that massive profits from in-house trading desks ameliorated poor operating results from the core business of finding and producing hydrocarbons — and it won’t be the last. But the companies may struggle to carry this safety net into the era of decarbonization.As my Bloomberg Opinion colleague Chris Hughes wrote this week, Royal Dutch Shell Plc proved it could make a profit even amid the carnage of the oil market in the April-June quarter. The slump in oil and gas production — down 7% year on year and 11% quarter on quarter — and collapse in prices was offset by aggressive cost and capital-expenditure reductions, plus a “very strong” trading result.The company’s American peers, Exxon Mobil Corp. and Chevron Corp., largely avoid pure trading, sticking instead to marketing their own production. That deprived them of the safety net enjoyed by Shell and Italy’s Eni SpA (and presumably also BP Plc, which reports earnings on Tuesday).It showed in their second-quarter results. On Friday Chevron reported its worst quarterly loss in at least three decades and warned that the global Covid-19 pandemic may continue to drag on earnings. With the recovery in oil demand running out of steam, that’s not a big surprise. Exxon followed hard on its heels with its biggest-ever loss, as the collapse in crude prices hit upstream earnings, while the slump in demand hit its refining and chemical businesses. Exxon was probably glad to not have a big trading operation, as it managed to lose money there too.As Bloomberg News’s Javier Blas explains here, Shell profited from the sharp drop in the price of crude for prompt delivery relative to that for future supplies, allowing it to lock in a profit by buying and storing oil, while selling forward in the derivatives market. With low borrowing costs and plentiful cheap storage capacity throughout its supply chain, the company enjoyed advantages over the independent trading companies.But the gap in prices has narrowed since the end of April. Now the profit that can be locked in, less than $2 a barrel, probably won’t even cover Shell’s storage and financing costs. Will the gap widen again? Almost certainly, at some point. Will it get as wide as it was at the end of March or late April? Maybe not, as that was the widest it’s been in the data going back to October 2007. The last big blow-out was during the great oil disruption in January 2009, which was triggered by the financial crisis.Of course, trading profits don’t just rely on extreme and rare events. They have made significant contributions to the incomes of European oil majors in what might be termed “more normal” times too. And that raises a longer-term question for these companies as they become less reliant on oil.Although oil trading is well established, with a vast array of derivative contracts that can be utilized to generate profits, trading in natural gas is much less mature and may never develop in the same way as oil markets. Despite the growing volume of gas transported around the world in super-chilled liquid form, most supplies are still delivered through pipelines that tie buyers and sellers into long-term relationships and multi-year contracts. Trading instruments in electricity and renewable energy sources are even less well developed.Over the past decade, the “oil” companies, whose profits were mostly derived from pumping crude out of the oil fields they discovered, transformed themselves into “oil and gas” companies. Now they are evolving once again to become “energy” companies. Shell’s latest report shows that almost half of its production was natural gas, compared with less than 40% in 2005.The swing is likely to become even more pronounced. Companies like Shell aren’t going to stop producing oil, but it will become less important as the world increasingly embraces less carbon-intensive forms of energy. As they become more focused on natural gas, electricity and, very likely, hydrogen, their ability to offset any weaknesses in their core activities through trading profits are likely to be severely curtailed.This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.Julian Lee is an oil strategist for Bloomberg. Previously he worked as a senior analyst at the Centre for Global Energy Studies.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.
(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.