U.S. Shale Challenges OPEC With Record Production In 2023
Last year, oil prices hit multi-decade highs shortly after Russia invaded Ukraine, prompting the Biden administration to urge U.S. producers and OPEC to ramp up production at a faster clip so as to rein in spiraling oil prices. However, Saudi Arabia and its allies responded by doing the exact opposite, cutting production when oil prices started plummeting. Predictably, the United States and Europe were irked by the cartel’s defiance, with President Joe Biden’s administration accusing Saudi Arabia of colluding with Russia and supporting its war in Ukraine. Well, President Biden can at least thank his lucky stars that the U.S. Shale Patch paid heed to his clarion call: the Energy Information Administration (EIA) has forecast total U.S. output will hit 12.61M bbl/day in the current year, eclipsing the previous record of 12.32M bbl/day set in 2019’s and easily beating last year’s 11.89M bbl/day. U.S. crude oil output is up 9% Y/Y blunting OPEC’s efforts to keep supplies low in a bid to goose prices. There is little doubt the U.S. Shale Patch is largely responsible for keeping oil markets well supplied and oil prices low: Rystad Energy has estimated that whereas OPEC and its allies have announced cuts amounting to ~6% of 2022’s production, non-OPEC supply has made up for two-thirds of those cuts, with the U.S. accounting for half of that. Energy experts have generally been bearish about U.S. crude supply with many arguing it has already peaked, “The projection suggests the pace of US shale growth, one of the few sources of major new supply in recent year, is slowing despite oil prices hovering at around $90 a barrel, about double most domestic producers’ breakeven costs. If the trend continues, it would deprive the global market of additional barrels to help make up for OPEC+ production cuts and disruption to Russian supplies amid its invasion of Ukraine,” Bloomberg said, Bloomberg cited comments by ConocoPhillips (NYSE: COP) CEO Ryan Lance that rising costs as well as limited supplies of labor and equipment were some of the problems that were hamstringing efforts by U.S. shale producers to quickly ramp up production. However, Bloomberg also noted that the biggest factor behind the slowdown is a change of the playbook by the majority of U.S. shale companies from focussing on growth and expansion to more capital discipline and returning more cash to shareholders. Improved Efficiency Luckily for the Shale Patch, improving drilling and cost efficiency not only means they are able to squeeze more for less but they are also able to eke out a profit at much lower oil prices. According to J.P. Morgan, U.S. drilling and fracking costs have declined 36% since 2014, significantly lowering the breakeven points of many producers. For instance JPM points out that increased efficiency means EOG Resources (NYSE:EOG), for example, can earn as much from oil priced at $42/bbl today as it would have from $86/bbl oil in 2014; in contrast, Saudi Arabia reportedly requires ~$81/bbl oil to balance its books. The U.S. shale revolution dramatically reshaped the world energy markets. The shale boom was one of the most impressive growth stories, from take off in 2008 to the Permian stealing the mantle from Saudi Arabia’s Ghawar as the world’s highest producing oilfield in a little over a decade. Overall, Reuters has estimated that, “U.S. petroleum production is at least 10-11 million bpd higher than it would have been without horizontal drilling and hydraulic fracturing.’’ Unfortunately, the Shale Patch has lately been struggling to ramp up production due to a litany of challenges including pressure from investors to boost returns, limited equipment and workers as well as a lack of capital. But shale giant ExxonMobil Corp. (NYSE:XOM) is now betting that shale producers can double crude output from their existing wells by employing novel fracking technologies. “There’s just a lot of oil being left in the ground. Fracking’s been around for a really long time, but the science of fracking is not well understood,” Exxon Chief Executive Officer Darren Woods said Thursday at the Bernstein Strategic Decisions conference. Woods has revealed that Exxon is currently working on two specific areas to improve fracking. First off, the company is trying to frack more precisely along the well so that more oil-soaked rock gets drained. It’s also looking for ways to keep the fracked cracks open longer so as to boost the flow of oil. Shale Refracs Luckily, the U.S. Shale Patch won’t have to wait for Exxon to perfect its new fracking technologies. There’s already a proven technology for oil producers to return to existing wells and give them a second, high-pressure blast to increase output for a fraction of the cost of finishing a new well: shale well refracturing. Refracturing is an operation designed to restimulate a well after an initial period of production, and can restore well productivity to near original or even higher rates of production as well as extend the productive life of a well. Re-fracking can be something of a booster shot for producers–a quick increase in output for a fraction of the cost of developing a new well. While refracturing has never really gone mainstream, the technique is seeing higher adoption as drilling technology improves, aging oilfields erode output, and companies try to do more with less. According to a report published in the Journal of Petroleum Technology, new research from the Eagle Ford Shale in south Texas shows that refractured wells using liners are even capable of outperforming new wells despite the latter benefiting from more modern completion designs. JPT also estimates that North Dakota’s Bakken Shale straddles some 400 openhole wells capable of generating an excess of $2 billion if refractured. Mind you, that estimate is derived from oil prices at $60/bbl vs. this year’s average oil price of almost $90/bbl. According to Garrett Fowler, chief operating officer for ResFrac, a refrac can be up to 40% cheaper than a new well and double or triple oil flows from aging wells. How Refracs Work Fowler says the
Russia’s Urals Oil Breaches $60 Price Cap For The First Time
Russia’s flagship crude grade, which has been trading consistently below the price cap set by the G7 and the European Union, climbed above $60 per barrel on Wednesday. That’s supported by Argus Media data, cited by Bloomberg. It is now, for the first time, that observers can judge if the price cap is actually working. Before, with Urals trading below it anyway, it could hardly be argued that the cap was doing anything to deliberately squeeze Russia’s oil export income. In fact, because another Russian grade, ESPO, has been consistently trading above the price cap, it could be argued that the cap was not the most effective of tools, mostly creating a headache for Western insurers and shipowners. But now that Urals has jumped above the cap, even temporarily, things could get interesting—and unpleasant for buyers. According to energy analyst Vandana Hari from Vanda Insights, when it comes to India “It’s problematic.” “Indian banks have been extra cautious in the last few months for fear of sanctions, requiring the refiners to show that the free-on-board price of their cargo was below $60 in order to put the payment through,” Hari told Bloomberg. If Urals jumps above $60 again, it means Russia and its oil buyers would have to increase the use of non-Western insurers and tanker operators to avoid punitive action from the G7 and the EU. “We are monitoring the market closely for potential violations of the price cap,” the U.S. Treasury said in a statement cited by Bloomberg. “It is worth noting that trades above $60 that do not use Coalition services are not in violation of the price cap and a substantial proportion of Russian oil trades, though, still use Coalition service providers.”
Petroleum Ministry lowers domestic content criteria, purchase preference advantage for homegrown firms in oil & gas PSUs LSTK, EPC projects
Prime Minister Narendra Modi’s push for Make in India suffered a setback on Tuesday with Petroleum Ministry lowering the domestic content criteria as well as purchase preference advantage for homegrown firms in lumpsum turnkey (LSTK) or engineering, procurement and construction (EPC) projects floated by oil and gas public sector undertakings (PSUs To give preference to local suppliers and to promote domestic manufacturing and production of goods and services, India in 2017 classified a Class-I local supplier, with local content ‘equal to or more than 50 per cent’, as the winner in all PSU global contracts provided the Class-I supplier sourced 50 per cent of its content locally and matched the lowest bid, even if it had quoted 20 per cent higher than the lowest bid. These thresholds were greatly reduced on Tuesday through a Ministry order whereby the domestic content contribution was lowered to 30 per cent — gradually escalating to 50 per cent — and the purchase preference price differential reduced to 10 per cent across the board and for all years to come. That, in essence, means that any foreign firm stands a chance to win LSTK and EPC contracts even if it domestically sources 30 per cent of the project value (instead earlier 50 per cent) and majorly, that domestic Class-I firms would have to be well within 10 per cent price range (instead of the earlier 20 per cent) quoted by a foreign firm to bag the purchase preference advantage. “…to increase competition and to incentivize progressive increase in Minimum Local Content (MLC) in high value oil and gas LSTK/EPC contracts/projects, it has been decided under para 14 of the Public Procurement (Preference to Make in India) Order 2017 to revise the MLC for getting the purchase preference and Margin of PP for such contracts/projects on progressive basis with predictable trajectory,” says the Ministry’s July 11 order.
Demand for term LNG contracts firms amid supply security concerns
LNG term contract volumes have leapt this year, as energy security becomes paramount worldwide, with markets — most notably among them China — snapping up deals to head off potential shortages, industry sources and analysts have told S&P Global Commodity Insights. While long-term deals have become increasingly appealing to buyers, short and medium-term arrangements have remained important, due to the flexibility they provide, industry observers said. The LNG supply response takes a minimum of around four years to come through and 2022-27 represents a period of “reshuffle”, according to Michael Stoppard, global gas strategy lead and special adviser with S&P Global Commodity Insights. Most of the recent term deals have been for volumes from either projects yet to reach final investment decision, or from part of capacity expansions at existing developments.