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Forget a peak – falling production from existing fields should be the market’s immediate focus.
Peak oil demand has swiftly moved from concept to potential to symbolic talisman— and it means different things to different people. Most often, the debate centres on the year when this peak may occur. Is it 2025? 2035? And these days the discussion never fails to mention electric vehicles, which—runs the argument—will eat away at oil’s market presence.
For oil markets, even that number takes some unpacking—we analysts tend to spend too much time focusing on the increment (in this case the 1.6m) and too little time looking at the base number. In our defence, that bias makes some sense. The size the growth in supply or demand (or the size of the contraction of either) is of paramount importance in plotting how the price path may develop. So our assumption often starts from zero—looking at the net change from the period before. So, in turn, once we know, based on forecast oil-demand growth, that the world will need 1m or 1.6m b/d of more supply next year, we can give a guide to producers about how much new oil is needed to keep things in balance.
Within this framework, the potential for peak demand, therefore, matters a great deal: it tells the market that no more new oil is needed, and that as demand falls oil will need to be removed from the system. If you are focused on the positive benefits of energy transitions and waning oil demand, this would be a moment of celebration.
But there’s a problem with this framework. It’s simple—but it ignores a crucial part of the equation: the scale of the decline rate. And these days that’s even more significant, because the decline rate has become more dynamic. Companies shouldn’t ignore this shift in 2018 or beyond. It will matter a lot more than the (most likely) distant and hard-to-pin down arrival of an absolute peak in consumption.
That producing wells and fields decline isn’t exactly news—we know they do. But the global rate of this decline is more difficult to put a number to. The rule of thumb offers up a range from 3-6% a year, with offshore rates higher than onshore, older fields higher than younger, and shale higher than all of them.
But it seems that the decline rate has changed during the course of the oil market’s downturn since mid-2014. Decline rates shrank in the initial phases of the price slump, as companies sought to keep existing production as high as possible by streamlining maintenance and focusing capital. Offsetting a field’s or well’s decline is, after all, often the cheapest barrel a company can bring to market. It was a way producers battened down the hatches to try to last out what was at first thought likely to be short-lived price weakness.
As the notion that prices would stay “lower for longer” took hold, these temporary efforts were undercut by the sharp drop in capex. The result was an increase in the decline rate. Rystad estimated that 2016 had the highest decline rate of the past 25 years. It’s likely to get worse, too, as the recent deep spending cuts steepen the decline curve for the next two years. Furthermore, we can expect a long-term structural increase in the decline rate, simply because—in the absence of many new fields being developed—the average age of the producing ones is now trending upwards. In 2017, we assessed the decline rate at 9+%, equating to about 8.8m b/d. That’s five times greater than the demand increment for 2017.
The growth of shale production has been breathtaking (and well documented), with output rising from just 1.4m b/d in 2007 to 6m b/d in 2017. Yet even this greater-than-threefold absolute increase in production pales in comparison to the growth in the resource’s decline rate. In 2007, shale’s decline rate was estimated at 300,000 b/d. A decade later, the decline rate is nearly 4.3m b/d, a 15-fold increase.
To put this in context, before shale started to cover some of the 1.6m b/d of global demand growth in 2017, it first had to produce the equivalent of non-Opec Latin America’s output. Or put it another way: the volume shale producers needed to produce just to reach par output again in 2017 would make it Opec‘s second-biggest producer.
These high decline rates are themselves partly caused by the underlying fast pace of growth, because new wells are the ones that decline most in their first year. Still, even when growth (in net output terms) has been absent, it takes a while for the decline rate to come down. For example, non-Permian production fell by about 0.8m b/d in 2016 as the industry cut activity in the face of low prices. The pace of decline over the same period fell by about 0.6m b/d—a rapid contraction, for sure, but in aggregate it still remained in excess of 3.7m b/d.
Shale’s ability to manage a potential supply shortage and keep prices relatively low and steady has been a major theme of discussions among analysts. My view is that shale has over-delivered what even the most positive assessments expected. Its growth in 2011-2014 period and its resilience in the face of lower prices can cause a cognitive bias that this course will continue. But shale offers a relatively small portion of the global supply stack. And its high decline rate actually increases the risks of a supply shortage, particularly if its growth continues. From a volume standpoint, this is a bigger matter than the incremental demand growth.
For companies in 2018, it all means this. In an era of oversupply—which already seems to be receding—they need to pay attention to the long-term implications of changing decline rates, even more so given the context of multiple years of declining or insufficient investment. As firms focus their strategies on energy-transition plans and how they can compete, they would also benefit from focusing on their decline rate—and divulging it—while keeping production costs low to offset this decline. Being able to compare performance with their peers will allow for a fuller and more complete picture of the role of demand growth for the industry.
Jamie Webster is Senior Director at The Boston Consulting Group’s Center for Energy Impact
This article is part of Outlook 2018, our annual book looking at energy market trends for the year ahead. To purchase a copy, click here