The crash in oil prices from $115 per barrel to under $35 at its lowest point was one of the most significant macroeconomic developments in recent years. Although oil prices have started improving, climbing over $80 in October, the downturn tested and proved the resilience of international oil majors.
One primary concern has been whether oil majors have been underinvesting following huge capex cuts made in 2014. We have not seen this be the case. Despite cutting investments by nearly 50% and postponing investment decisions on major developments, activity levels did not drop as much as dollar capex. Instead, we have witnessed an increase in actual and projected aggregate production.
Production through downturn
Between 2013 and 2017, oil production profiles had modest changes, with the liquid and gas production mix remaining relatively stable across the supermajors. We expect aggregate production to continue to grow.
We generally consider liquid production to be more profitable than gas production. Across all majors, about 55% of the production profile consisted of liquids, on average.
Low prices hit proved reserves
A key measure for oil companies is their reserve life index (RLI), or the years it would take to use up their reserves, assuming a constant production rate and no portfolio changes. Since 2013, the average RLI on a one-year production basis reduced by one year to 13 years, which is sufficient on a proved reserve basis.
In 2016, when lower prices affected ExxonMobil’s project in Canada, it removed 3.5bn barrels of bitumen from its proved reserves. Meanwhile, Shell’s proved reserves declined in 2015, but its acquisition of BG helped increase proved reserves to above 13bn barrels of oil equivalent (BOE) in 2016.
Cost cutting softened the blow
As oil prices fell, all major energy companies saw combined oil and gas revenue per BOE fall by more than half. Cost cutting initiatives helped soften the impact of this plunge. Gas sales acted as a hedge, but their mitigating effect was reduced because some gas and LNG contracts were linked to oil prices. Also, the difference between the highest and lowest revenue per BOE among the majors narrowed; in 2017 it was $5, down from $20 in 2013.
Total remains the most efficient major in terms of operating costs. In part, this indicates that it operates in emerging markets. But other oil majors have also cut costs—Royal Dutch Shell slashed its unit costs by more than 50%. Even at affiliates, costs have reduced, stemming from cuts, operating efficiencies and improvements in logistics. Foreign currency movements also favoured subsidiaries not operating in US dollars.
Leverage increased through the downturn, exacerbated by a fall in dividends from equity-accounted joint ventures and affiliates. An upsurge in the level of fixed-asset disposals compared with 2013 provided companies with cash to help meet financial obligations and prevent an aggressive rise in leverage to fund capex and dividends. Funds from operations (FFO) to debt was roughly 35% on average at the end of 2017, compared with almost 85% in 2013.
Looking forward, we expect average FFO to debt for majors to rise above 50% by 2020. We also expect big players will continue to maintain rigorous cost controls amidst improving upstream market conditions. Depending on companies’ financial policy choices, some might be better prepared than others to weather another future period of low oil prices.