Much has been made of the recent confidence tumble in America’s Permian Basin, the low cost and prodigious shale play that straddles Texas and New Mexico. It began when Pioneer Natural Resources announced its second-quarter financial results – reporting net income of US$233 million, compared to a net loss of US$268 million the same quarter last year. But the positive results weren’t what investors focused on – it was expected, given the recovery in crude prices this year. Instead, they zoomed in on Pioneer’s decision to slash US$100 million from its 2017 capital budget, as well as anomalies within its production data – an unexpected drop in oil production that was somewhat offset by higher natural gas output (though from new wells, unusually), accompanied by higher costs. Pioneer’s stock took a tumble, down by 16% at one point, and it dragged all other Permian-related stocks with it – spooking investors that held shares of EOG Resources and RSP. Editorials and analytical notes were written furiously, warning that enthusiasm in the Permian was waning.
Meanwhile, the weekly rig count data released by Baker Hughes-GE fell by one the week Pioneer released its results. Within the topline number, active rigs in the Permian basin were flat week on week, having been the main source of rig count growth over the past year together with the Eagle Ford basin. The week after, active rig counts fell by 5, with the Permian and Eagle Ford losing 2 and 3 sites, respectively. On a macro scale, the market would cheer this as a sign that US oil production is finding a new plateau at the current level of crude prices, stuck around US$50/b. On a micro level, it is causing some jitters among Permian producers – many of whom have trimmed their spending targets for 2017 and 2018, including heavyweights Diamondback Energy and Devon Energy, in anticipation of a slowdown.
Are we about to see a collapse in the Permian? Absolutely not. After a period of rapid growth in early 2017, in response to crude prices jumping on the OPEC supply freeze pact, the Permian is merely hitting a wall of marginal gains. Permian producers raised production rapidly earlier this year, anticipating that prices would maintain at US$60/b, thereby unleashing supply that moderated prices again. With the outlook now pointing towards prices stubbornly sticking to the US$50/b level, producers are now adjusting their approach. The Petroleum Economist reports that "oil bulls and OPEC ministers who are looking for cracks in the shale recovery due to recent announcements by Anadarko, Hess and Whiting Petroleum are cutting their 2017 budgets, will be disappointed. It may just be too soon claim any victory that US shale is shutting down. EIA reports that DUCs (Drilled but Uncompleted Wells) have nearly doubled from this time last year to around 2,250. If oil remains at sub-$50, companies could start pulling rigs, and start shifting to cheaper and quicker options of completing their DUCs. This will power production growth for at least several months."
Growth in the Permian will continue through 2017 and 2018, but at a slower pace. The Permian region is projected to represent about 30 percent of total U.S. crude oil production in the coming year. Wood Mackenzie is predicting the Permain output will rise by 300,000 b/d by the end of 2017, pushing past the 2.7 mmb/d level. Meanwhile, supermajors ExxonMobil and Chevron are both increasing their presence in the Permian attracted by lower costs – the average wellhead breakeven presence in the Permian hovers around US$35/b – aiming to raise production there by 20% and 35%, respectively, from low bases. Meanwhile, Falcon Seaboard Resources just announced a US$145 million Permian fund.
Interest in the Permian isn’t waning. The ride is just slowing down, because the industry in the Permian has moved past the short, sweet period when prices rise faster than costs, and is now adjusting to that. And even the furore around Pioneer is misplaced; the company has said that the unexpected drop in oil production was short term and would be fixed in the next quarter. Pumping more natural gas isn’t a huge problem either – Permian player Parsley boosted its gas production forecast for the year in fact – since it diversifies output and total resources are still expanding. Now, in fact, might be a good time to cherry pick Permian stocks – the valuations remain good, while the stock prices have taken a beating. With OPEC, mainly Saudi Arabia attempt manoeuvring again to support prices, the Permian basin phenomenon is far from over.
P.S. for continuity of investments in the energy industry, making the right choices are key for future success. Read more about Scenario planning and the so what question a recent blog post by Henk Krijnen. Henk Krijnen will be in Kuala Lumpur this October 2017, presenting a very timely "Masterclass on Scenario Planning for Decision Making in the Energy Industry". Find out more https://goo.gl/tauq5x. If you are too busy during this period, check out our training series on “Training to Navigate Uncertainty in Oil & Gas”
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The week started off ominously. Qatar, a member of OPEC since 1960, quit the organisation. Its reasoning made logical sense – Qatar produces very little crude, so to have a say in a cartel focused on crude was not in its interests, which lie in LNG – but it hinted at deep-seated tensions in OPEC that could undermine Saudi Arabia’s attempts to corral members. Qatar, under a Saudi-led blockade, was allied with Iran – and Saudi Arabia and Iran were not friends, to say the least. This, and other simmering divisions, coloured the picture as OPEC went into its last meeting for the year in Vienna.
Against all odds, OPEC and its NOPEC allies managed to come to an agreement. After a nervy start to the conference – where it looked like no consensus could be reached – OPEC+ announced that they would cut 1.2 mmb/d of crude oil production beginning January. Split between 800,000 b/d from OPEC members and 400,000 b/d from NOPEC, the supply deal contained a little bit of everything. It was sizable enough to placate the market (market analysts had predicted only a 800,000 b/d cut). It was not country-specific (beyond a casual mention by the Saudi Oil Minister that the Kingdom was aiming for a 500,000 b/d cut), a sly way of building in Iran’s natural decline in crude exports from American sanctions into the deal without having individual member commitments. And since the baseline for the output was October production levels, it represents pre-sanction Iranian volumes, which were 3.3 mmb/d according to OPEC – making the mathematics of the deal simpler.
Crude oil markets rallied in response. Brent climbed by 5%, breaking a long losing streak, as the market reacted to the move. But the deal doesn’t so much as solve the problem as it does kick the can further down the road. A review is scheduled for April; coincidentally (or not), American waivers granted to eight countries on the import of Iranian crude expire in May. By April, it should be clear whether those will continue, allowing OPEC+ to monitor the situation and the direction of Washington’s policy against Iran in a new American political environment post-midterm elections. If the waivers continue, then the deal might stick. If they don’t, then OPEC+ has time to react.
There are caveats as well. OPEC members, who are shouldering the bigger part of the burden, said there would be ‘special considerations’ for its members. Libya and Venezuela - both facing challenging production environments – received official exemptions from the new group-level quota. Nigeria, exempted in the last round, did not. Iran claims to have been given an exemption but OPEC says that Iran had agreed to a ‘symbolic cut’ – a situation of splitting hairs over language that ultimately have the same result. But more important will be adherence. The supply deals of the last 18 months have been unusual in the high adherence by OPEC members. Can it happen again this time? Russia – which is rumoured to be targeting a 228,000 b/d cut – has already said that it would take the country ‘months’ to get its production level down to the requested level. There might be similar inertia in other members of OPEC+. Meanwhile, American crude output is surging and there is a risk to OPEC+ that they will be displaced out of their established markets. For now, OPEC remains powerful enough to sway the market. How long it will remain that way?
Infographic: OPEC+ December Supply Deal
Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b
Headlines of the week
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