The longest streak of consecutive declines in WTI crude futures ended Tuesday at 12 straight days, leaving the oil market wondering: what just happened?
Talk of $100 oil was on the lips of some analysts in early autumn. Then came October. WTI crude fell 10.8%, its biggest monthly percentage drop since July 2016. Nor did the losses end there.
On Tuesday, US oil futures settled at $55.69 a barrel, a year-to-date low, down a whopping 7.1% from Monday.
Fingers have been pointed at OPEC and President Trump. The quest by Washington to drive Iranian exports to zero through sanctions pressured Saudi Arabia to increase exports.
Yet oil prices climbed higher. Growing nervous, the White House decided to grant temporary waivers to eight countries allowing them to keep purchasing some amounts of Iranian crude.
In an instant, a lynchpin of the higher oil price scenario was removed. Even an OPEC meeting in the middle of the price collapse couldn’t stop the slide. Promises of future production cuts and a Saudi unilateral pledge to reduce exports went unheeded.
The other key contributor is doubts about the ability of global demand to absorb supply from outside OPEC (i.e. US shale).
Growth in key shale plays, like the Permian Basin, remains a major factor influencing the global supply-demand balance, on par with OPEC decisions.
Satellite imagery courtesy of Planet Labs Inc.
In its latest report, the International Energy Agency said non-OPEC production was 3.5 million barrels per day higher in August than a year ago, of which the US contributed 3 million bpd.
US production averaged 11.3 million bpd in August, an all-time high, the Energy Information Administration said this month. The EIA expects US production will average 12.1 million bpd in 2019.
Unlike an OPEC meeting, the action unfolding in the Permian Basin occurs far from the cameras and microphones of the media.
Even if reporters showed in Midland, what would they find? No single voice can speak for all producers. And tracking activity is daunting given the size of the Permian Basin.
Instead, the market relies heavily on EIA and IEA monthly reports for updates on US production and forecasts. Those figures are only as good as the underlying public data and when you dig deeper the room for improvement is obvious.
Let’s take a quick look.
The drilling phase is easily followed as rigs move from site to site where permits have been granted. Baker Hughes releases a North American rig count every Friday broken down by various categories, such as state, basin, oil vs gas and trajectory (horizontal, vertical or directional).
The next phase is well completion, and this is where things get messy. An oil company can wait up to nine months in some cases to notify state regulators that a well has been completed. And then another 45 days can pass before the state makes that information public.
Then there is production, the last phase, which can also involve lengthy delays. Companies are required to file paperwork 30-60 days after production begins and the state has another 45 days to post.
None of this would matter much if the time from drilling to production followed a consistent pattern.
That was the case until recently. Then operators began to pause after drilling a well to finish it. This led to the introduction of “DUCs” (drilled, but uncompleted wells) into the oil market vocabulary.
The reasons for DUCs include difficulties finding crews, equipment and materials, lack of pipeline space and unattractive oil prices.
Whatever the cause, the inventory of DUCs is important because this represents future supply. But relying on publicly available sources to track the different phases is hardly ideal considering those delays.
In Part 2 of this blog series, we’ll look at the innovative methods Ursa has developed to monitor well completions and the start of production.
Here’s a hint: satellite imagery and machine learning. More to come!