Politics, suspense, discord and drama — OPEC’s June 22 meeting in Vienna had all the ingredients of a thriller. Then, it ended in an anticlimax.
The formal agreements signed by OPEC’s 14 ministers on Friday and by OPEC and its 10 non-OPEC collaborators on Saturday were general and vague. The OPEC communiques simply said the countries agreed to “strive to adhere” to their target production levels to correct cuts that had swung deeper than intended.
Without specifics, OPEC’s decision Friday barely qualified as a “deal.” It was a guiding principle at best and a smokescreen at worst, saving face for Iran and others opposed to a proposed 1 million b/d hike. But as it turned out, it gave Saudi Arabia and Russia the leeway they needed.
Though the highly anticipated decision from Vienna on Friday left observers nonplussed, it preserved the image that as a group, OPEC remained cohesive and in control of the market. That was important after the emergence of major rifts within the organization and suggestions that it was doing the US’ bidding by deciding to raise supply.
The real deal, which was sealed during the OPEC/non-OPEC meeting in Vienna on Saturday, is that several producers will start putting more oil — up to 1 million b/d — into the market starting in July. The Saudi and Russian energy ministers didn’t mince their words while articulating the agreement and their supply boost plans to the media. Iranian oil minister Bĳan Zanganeh had departed Vienna by then and his starkly different interpretation of Friday’s deal was pushed aside.
Which countries will now starting pumping more is relatively easier to guess. How much more they will produce is trickier to say, though estimates of actual addition of barrels point to around 600,000 b/d.
Individual country quotas agreed in November 2016 will need to be formally adjusted to ensure that the supply shortfall from Venezuela and potentially Iran in the coming months is offset by members with spare capacity. Curiously, that important job of rejigging quotas has been left to the OPEC/non-OPEC Joint Ministerial Monitoring Committee.
The fact that Saudi Arabia and Russia co-chair the committee should smooth the way. But renewed friction with the “no-hike” camp, especially Iran, which insists that producers with spare capacity should not be allowed to compensate for those falling short, is likely. In the coming months, Iran will have to either fall in line or risk becoming a pariah.
Crude’s 3-5% spike Friday was a knee-jerk reaction to a confusing picture. As Monday dawned in Asia, Brent futures had hit the skids.
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The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects
Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b
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