US oil growth set to decline says the EIA
The price plunge is testing the resilience of the world’s biggest oil producer
Even for an industry used to booms and busts, the US experience over the past few years stands out. As drillers piled into North Dakota and Texas’ shale plays crude flowed out at an unprecedented rate. From 2011 to 2014 the US became the first country ever to add more than 1m barrels per day (b/d) of production for three straight years. In the process, it overtook Russia and Saudi Arabia as the world’s largest oil producer, a feat that was unthinkable just a few years ago.
The widespread adoption of directional drilling and fracking were critical to the US’ oil renaissance. But high oil prices and cheap financing were vital too, and the fall in the oil price has stalled the US oil production juggernaut.
The Energy Information Administration (EIA), the statistical arm of the Department of Energy, thinks US crude output has peaked, for now, and 2016 will see a year-on-year decline, led lower by falling shale output.
US crude output likely hit a multi-decade high of 9.59m b/d in May, but the second half of this year should see the number shrink.
The EIA expects production to fall by 300,000 b/d from the May high and average about 9.2m b/d in the first quarter of next year.
The low oil price is not hitting all sectors of the oil patch equally. Shale projects, which are relatively high up the cost curve and can quickly be curtailed by financially strained drillers, are feeling the pain first. Shale output could fall by 0.5m b/d over the next few months, according to the EIA.
A slew of deep-water Gulf of Mexico (GoM) projects, however, are largely going ahead regardless of the oil price – much of the investment needed to get them on line has already been spent.
An extra 150,000 b/d of new GoM output in the coming months will help to partially offset falling shale production. In Alaska, which is producing around 500,000 b/d, lower oil prices are likely to accelerate the long-term downward trend in production.
The WTI price benchmark has fallen by more than 40% from $105 a barrel (/b) last June to $60/b, though the price has recovered from a low of $43/b in March. The price decline was even harsher in some prolific shale plays such as the Bakken, where local crude grades sell at a steep discount to WTI because of infrastructure and other logistical constraints. In March, for instance, Williston Basin sweet crude averaged just $34/b.
The price rout prompted a swift response from shale drillers who saw the economics of their projects undercut by low prices. Capital spending has been slashed by around a third across the shale patch as companies rein in drilling plans – focusing on completing wells that have already been drilled and only drilling on their most productive land. The result has been a plunging rig count, starting from a high base.
The pace of the post-2009 recession build up in the rig numbers was unprecedented. In June 2009, the oil-directed rig count in the US was just 180. By June last year it had topped 1,500. But the fall has been equally unprecedented. Since the start of the year, when spending cuts started taking hold, the number of active rigs has fallen by nearly 60%, to around 640.
The biggest question for the market when oil prices started falling was how long it would take before shale production started to decline to follow the rig count numbers off the cliff.
Because of the rapid decline rates at shale wells, sustained and intense drilling is needed to keep output growing. It appears to have taken around six months for the spending cuts and falling rig count to make their mark on output. Two factors helped production remain elevated for longer than many thought it would. For one, many companies had a deep backlog of wells that had been drilled but were still waiting to be fracked and put into production.
Drillers went after these wells first and it took some time to work through the inventory. Second, shale drillers are getting a lot more bang for their buck. Wells are being drilled at the best acreage using the best crews and kit. As a result, the average Bakken well is producing 60% more oil today than a year ago. Similar efficiency gains have been seen across the US shale patch.
Now, the questions are different ones: how much US shale does the market need and at what price will output start to creep up again?
For now, the low oil price is taking shale barrels out of an oversupplied market. But that surplus won’t last long. From late 2016, analysts at Deutsche Bank reckon there will be a “call on US shale” as the country emerges as a key swing supplier.
The latter half of the decade should make things even more interesting for America’s drillers. Shale has been a casualty of the oil-price decline, but so too have early-stage deep-water, oil sands and other relatively high-cost projects. This year has been one of the worst in decades for final investment decisions on new projects that would be expected to start producing around 2017 or 2018. That could leave a huge supply gap to fill in a few years time. Shale producers that can quickly ramp up production could find themselves well positioned to grab this slice of the market.
The analysts at Deutsche Bank say shale production will need to grow by around 0.5m b/d from 2016 to 2017, another 0.7m b/d in 2018 and a return to 1m b/d growth in 2019 and 2020. By the end of the decade, demand for US crude – simply to replace the oil output lost by decisions that aren’t being taken now – will be more than 10m b/d.
If that dynamic plays out, the US shale industry might initially be the hardest hit by the oil downturn, but ultimately its biggest winner down the line.
The oil price needed to fuel a new spurt of growth, though, is less certain. While the best wells can be profitable at prices well beneath $50/b, that is a relatively small segment of the shale sector. Bernstein, a Wall Street research firm, found that the marginal barrel cost in the US rose to $118/b in 2014, up from $110/b in 2012 and 2013.
Those eye-watering numbers have come down sharply in the first months of 2015, though, thanks to rapid deflation in costs for drilling services and equipment. Bernstein reckons the marginal cost, the price needed for sustained growth, has come down to around $80/b.
A Deutsche Bank analysis of shale company cash flow, meanwhile, found that a range between $65/b to $80/b was needed to restart the US shale “growth machine”.
This echoes statements from the companies themselves, which have been much more vocal in recent months about wanting to return to growth after months of austerity.
EOG Resources, among the top tier shale producers, said it could return to double-digit growth if oil prices went back above $65/b.
Whiting Petroleum’s chief executive James Volker said his company would likely start adding rigs again if the oil price rose to $70/b. Over the short-run, it seems likely that a rise to $65/b would at least see shale output stabilise, while a return to $70/b plus could see drillers once again start to ramp up activity.
That price level would almost certainly rise sharply again, however, if the kind of demand for shale envisaged by Deutsche Bank – up to 1m b/d of extra oil – materialised. In that scenario, demand for drilling services, and their cost, would rise again and companies would have to drill in more marginal areas requiring higher oil prices to deliver returns.
Bernstein says the US would need an oil price of more than $110/b to sustain 1m b/d of growth.
While US shale production has been quick to respond to lower oil prices, the GoM’s deep waters are enjoying the fruits of exploration investments made during the oil-price boom years.
In 2015, a host of new projects should deliver around 250,000 b/d of production – the second highest yearly production growth rate ever for the deep-water GoM.
Output is likely to hit an all-time high of close to 1.7m b/d in late 2016, a remarkable reversal for a sector that saw its future thrown into doubt just five years ago following the Macondo oil spill.
Growth will come primarily from the Lower Tertiary section of the Gulf, which has yielded some of the largest offshore discoveries in the world in recent years. Anadarko’s Lucius field will add around 60,000 b/d of production over the next two years. An expansion of BP’s Thunderhorse field is expected to add a further 60,000 b/d by the end of 2016.
LLOG’s Delta House field should deliver 75,000 b/d and Chevron’s Jack and St Malo complex is expected to add nearly 80,000 b/d of new production as it ramps up over the next two years.
Because their upfront costs have been sunk, these projects will be profitable even at today’s lower oil price. But the outlook for projects that haven’t yet been sanctioned is less certain.
This poses a major risk for output growth after 2018. Deutsche Bank says that discoveries still in the early stages of development such as Shell’s Appomattox, BP’s Tiber and Anadarko’s Shenandoah fields would be unprofitable at an oil price of $60/b.
The US has emerged from the latest oil price boom as an energy superpower. It is being tested by the bust, but those hoping US producers and their oil would fade away quietly will be disappointed.