The countries of OPEC, once all-powerful in determining oil prices, besieged by infighting – have agreed to their first production freeze in eight years. After many aborted attempts to implement a supply cut, many were skeptical that this latest attempt would succeed. It certainly was a rocky road getting here; the cut was informally agreed in September, and very public outcries by Iran, Iraq, Libya and Nigeria cast doubt on OPEC’s ability to whip its members in line.
After the classic display of Game Theory over the past two yeas, OPEC will reduce its output by 1.2 mb/d by January, confirming OPEC’s intention to stick to the 32.5 mb/d level agreed in Algiers two months ago. More importantly, the agreement extends beyond OPEC, with non-OPEC nations also agreeing to implement cuts, including Russia.
The test of this will be actually implementing it, which is the harder portion of the equation. Nigeria and Libya are exempted from the cuts as they recover from infrastructure damage inflicted earlier this year, but Saudi Arabia, Iran and Iraq have all been given quotas. In particular, Iran has put aside its squabbling with Saudi Arabia to agree to capping its output at 3.8 mb/d, while Saudi Arabia will reduce its production by almost 500 kb/d, the UAE by 140 kb/d and Kuwait by 130 kb/d. Indonesia has requested a suspension of its OPEC membership (only two years after being re-admitted) as production cuts conflict with the country’s urgent need to raise its crude production. Saudi Arabia and its Gulf allies have generally stuck to their quotas in the past, but many other OPEC members haven’t. This will be a constant problem, which may undermine the whole integrity of the agreement.
But thus far the market seems to think OPEC will stick to the plan, sending Brent and WTI crude above the US$50/b mark, the highest since the OPEC Algiers plan was first announced.
Crucially, the plan also includes participation from non-OPEC members. Exactly what this entails is unknown beyond a vague statement that non-OPEC members are expected to reduce production by some 600 kb/d, with Russia decreasing by 300 kb/d (‘conditional to technical ability’, of course). These cuts are non-binding, and again, the harder part after herding the cats together to agree is actually implementing the plan. OPEC’s talks with non-OPEC producers continues on December 9, and meeting again next May to monitor progress. Analysts at Deutsche Bank said the deal isn’t enough to change the oil market outlook. The bank is skeptical that the full reduction will be realized, especially from non-OPEC countries. Analysts said oil traders would watch the agreement warily in the coming weeks.
Rising oil prices in the wake of OPEC’s production cut could hit demand from Asia’s emerging energy consumers, where weakening currencies have already led to higher prices. Since oil is priced in dollars, it makes crude more expensive in local currencies that have weakened against the greenback. China and India, the world’s second- and third-largest oil consumers after the U.S., have each seen declines in their currencies versus the U.S. dollar in recent weeks. However the beleaguered Asian oil industry could benefit from OPEC’s decision to cut production
But we are certainly in more positive territory than we were yesterday. OPEC has agreed to a supply freeze. Most would have dismissed this as a Yeti sighting, but it actually has happened. The nuts and bolts of enforcing it will now begin, and there are plenty of ways this house of cards could tumble down, but as it stands now, 2017 looks to be a better year for oil than 2016. Which can only be a good thing for you and me.
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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
Headlines of the week
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