After three years of oversupply and significant inventory builds, the oil market has begun to rebalance. Demand has been robust, bolstered by a sustained period of low prices. US supply, responding to those same low prices, levelled out in 2016, while global investment underwent a striking decline across consecutive years. While a gradual rebalancing of the global oil market was already underway, last year’s agreement by key producers to limit production has accelerated matters. We project that liquids1 demand will outpace supply later this year and then global inventory levels will normalise.
Looking ahead to the 2020s, we see compelling market fundamentals.
Global demand for liquids is expected to rise by around one per cent per annum over the next decade. Rising global population, increasing living standards, greater car ownership in the developing world and ongoing urbanisation will all contribute to demand.
This growth is solid – but it is not as strong as the experience of the century to date. One reason for this is that substitution and efficiency improvements have and will continue to displace the use of crude oil as fuel. Some demand sectors, such as passenger vehicles and power generation, are susceptible to these advances in technology. We have shared our views on the electrification of the passenger vehicle fleet in an earlier edition of Prospects (Electric vehicles - why all the noise?).
The supply side narrative is at least as important, if not more so. The yields from producing fields decline at an average rate of around three to four per cent per annum. Therefore, even in the absence of growing demand, significant ongoing investment is required just to stand still. On our estimates, by 2025 the world will need approximately 30 MMbbl/d of new supply to come online. This is a staggering one third of current annual global demand and excludes projects already under development.
In recent years, investment has been extraordinarily weak by historical standards. This phase creates the clear potential for the world to again be short of oil - as it periodically was prior to the US shale revolution. A significant portion of the new supply that we estimate will be required to meet future demand will have to come from regions with relatively high ‘above ground’ risk. In the past some of the supply risk was mitigated by the availability of spare capacity within the OPEC countries. However, that buffer has been eroded substantially in recent years. When we consider the other available options and aggregate them into an estimated cost curve, one point becomes very clear: cheap sources of oil are becoming increasingly more difficult to find. Traditional resource developers tend to pick the low hanging fruit first. And that means our estimated industry cost curve has a tendency to steepen over time; with the slope getting closer to 90 degrees than 45 degrees around the intersection with demand.
US shale plays are no different to conventional resources in this regard. Not all shale plays, and not even all wells within those plays, are created equal.The US shale industry has performed admirably in terms of reducing costs and improving productivity, surprising most observers with its resilience in the face of sustained low prices. That performance, impressive as it has been, is not evidence that there is an infinite volume of onshore core areas that are economic at or below US$50/bbl. It is important to understand that geology will remain a limiting factor. It is geology that ultimately determines relative cost curve positioning. Non-core areas will therefore continue to require higher inducement prices than core areas, industry wide learning curve or no. And our analysis strongly suggests that non-core areas will eventually be induced, due to the combination of rising demand and the tyranny of field depletion in the existing resource base.
Though the history of US shale is relatively brief, we have seen enough to know how responsive producers can be to shifting prices – both up and down. Total US production reached 9.6 MMbbl/d in April of 2015. US output then declined by approximately one MMbbl/d; but with prices recovering mildly in the first half of 2017, positive momentum has returned. Rig activity over the past few years reflects this elevated elasticity of supply and we expect the US to stem the decline and expand output again in 2017. In other words, the marginal producer during the current cyclical phase is most likely to be a US shale operator.
More than half of the new rigs put in place since the end of 2016 have been in the Permian. The remainder have been distributed across multiple areas. We expect this distribution of activity to continue, as beyond the Permian, there are limited sweet spots available where we see the potential for a viable return at current prices. Eagle Ford, which has been the focus of much activity in recent years, is a case in point. It has captured only around 10 per cent of the rig growth over the past six months.
Finally, it is notable that oil was the last pillar commodity in our portfolio to move into surplus during the relatively synchronised global downturn in prices; and it appears that it is going to be among the first to move back into fundamental balance on the far side of the early 2016 trough.2 Where commodity downturns are concerned, having a claim to being “Last In and First Out” is a strong advertisement for resilience.
1 The majority of petroleum liquids are crude oil, but the definition also includes condensates, natural gas liquids and biofuels.
2 Whether oil is classified as first, or not, depends upon how one defines developments in the met coal market in CY2016, when policy and weather disruptions pushed the market steeply into deficit basically overnight.