The Baker Hughes US oil rig count – a proxy for health and optimism in the overall upstream sector – has just reached a 31-month high to 1067 rigs, though nowhere near the all-time high of 1609 back in July 2014. This recent development is not surprising; crude prices have been trending upwards and reached a new 24-month peak last week as well.
Looking at the breakout data, it is possible that some of the gains could be from re-started sites shut down in the wake of Hurricane Michael bypassing the Gulf Coast, but the main additions are still coming from onshore Texas. The home to the mammoth Permian and the Eagle Ford shale basins, the Permian alone has 490 active oil and gas rigs. While infrastructural bottlenecks – mainly restrained pipeline capacity – have caused drilling activities to slow down since June, there are still gains to be made. Meanwhile, the lower prices caused by shale liquids being trapped in the Permian has led drillers to look elsewhere, where prices are stronger and infrastructure less clogged up – including re-looking at the Bakken and promising areas like Austin Chalk and Niobrabra. Recent auctions have seen record-high prices for acreage in Louisiana and Alabama; even in the Permian, interest remains high, with a recent sale in the New Mexican side of the basin setting a new record of more than double the previous high.
This could be key to navigating the coming global supply crunch, triggered by new American sanctions on Iran, and exacerbated by continuing problems in key OPEC producers such as Venezuela and Libya. Although Russia has raised its production and Saudi Arabia has pledged to fill the hole that Iranian crude will be leaving, the assassination of Jamal Khashoggi places the Kingdom in a position of belligerence with the rest of the world. So the US may find itself in a position to have to provide extra volumes on its own – which may be why active rigs have been increasing, and new areas being sought. There is a bit of a spanner in the works, though. The trade spat between the USA and China has led Chinese importers to slam the brakes on importing US crude, even though American crude is not yet on the list of products tariffed by China. LNG and even NGLs – propane and ethane imported to produce petrochemicals – have also seen significant slowdown.
How high can the American rig count get? If prices continue to march up – and there are many that believe the US$100/b mark will be reached soon – then the number of oil rigs drilling in the US could rise past 1200 again. But to reach the dizzying heights above 1500, which was the average over most of 2014, is unlikely. Not because there are lesser volumes of liquid underground – although studies are now showing that the decline rate in mature shale fields is alarmingly high – but because of consolidation. From a collection of many, many small players in the early 2010s, the shale landscape now is consolidating into a collection of medium and large players, with behemoths like ExxonMobil, Chevron and BP also muscling in. A rising tide of crude prices is lifting American drilling activity, but the magnitude of gains in 2018 will be different – due to a combination of infrastructure bottlenecks, fragile geopolitics and sector structural changes.
The main danger is short memories – the zeal of cashing in on high oil prices is what caused the 2015 crash and high corporate debt, and the enthusiasm brewing in American shale again could lead to history repeating itself.
Baker Hughes US Active Rig Count:
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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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