We expect 2016 exploration spend to be around half the 2014 peak, and it could fall even further next year.
Quarterly losses, dividends cut, budgets slashed – oil companies are in survival mode. Protecting cash flow is a top priority, so why continue to spend on exploration? The primary long-term organic growth engine of the upstream industry now looks like a dispensable luxury. Investment in exploration grew at a dizzying pace for over a decade, but falling returns – even at $80/bbl planning prices – caused many to question the role of exploration in their business.
Spend on exploration and appraisal (E&A), outside of the shale plays, tripled between 2005 and 2014 to a peak of $95 billion. During that time, the number of E&A wells drilled actually fell. The entire industry was subject to spiraling cost escalation throughout this period, reflecting the rise in oil prices. What changed in exploration was not only the cost base, but also the nature of the wells. Fewer cheap wells were drilled onshore (excluding US shales), while more wells were drilled in expensive deep waters. Over the decade, explorers moved to ever-deeper waters, and targeted more deeply buried and complex reservoirs. These increasingly challenging wells required newer drilling rigs with greater capabilities – which came at a cost.
To secure a new-build rig, oil companies had to sign multi-year contracts, typically at day rates of $600,000 or more, triple the average day rate in early 2005. The wells took longer to drill (because of the greater depth), pushing up total well cost. And, of course, these higher drilling costs not only applied to exploration, but also to any potential development of the discoveries.
Exploration spend was buoyed by higher oil prices, but was also success-driven. The years 2009 to 2012 were outstanding for finding giant fields off Brazil, West Africa, East Africa and elsewhere, and successful exploration companies were the darlings of the stock market. Total annual discovered volumes averaged over 35 billion barrels of oil equivalent (boe) during these years.
The last three years have been much less prolific. Once drilling activity shifted from exploration to appraisal in the two mega-regions of Brazil and East Africa, total discovered volumes fell away to average less than half the volumes of the previous four years – despite continuing high levels of spend. That said, the technical risks remained largely unchanged, even with the increasing complexity. Across the decade, a little more than one in three wells found hydrocarbons.
More worrying than the fall in overall volumes is that proportionally fewer discoveries were considered commercially viable. Wood Mackenzie analyses each discovery on its individual merits to decide whether it is likely to be developed and commercialized. Before 2013, around half the discoveries (and the resources discovered) were considered commercial. Of the 2014 finds, only 20% are currently thought to be commercially viable. Mostly this drop was because the costs of developing the oil and gas were too high. But our team of exploration analysts determined that there were other factors exacerbating the trend:
The proportion of gas increased; finding a market for gas is harder and the price received is much lower than oil on an energy-equivalent basis.
The increasing complexity of the environment – deeper waters and reservoirs, harsh conditions, difficult geology, to name a few – made commercialization much more challenging.
A small but increasing share of activity was in under-explored, remote areas with little or no infrastructure. Discoveries here needed to be much bigger than average to merit high up-front investment and, more often than not, they did not quite make the grade.
The result: across the industry, full-cycle returns fell. Our in-depth work analysing the full extent of exploration activity, from initial geophysical studies through to appraisal, and including all dry holes, showed that full-cycle returns dropped from an average of 12% (IRR) in the five years to 2012, to below 5% in 2014, even at $80/bbl long-term. This metric is hopelessly short of the typical cost of capital for an E&P business of say 10%. Our analysis of the top explorers shows that individual company results varied markedly during this period, but falling commodity prices that weren’t matched by falling costs meant that almost everybody’s results slid compared to prior years.
A few companies – Marathon and ConocoPhillips among them – decided that the investment opportunities in their Lower 48 portfolio were better than the exploration prospects in their international deepwater acreage portfolio. Exiting high-impact deepwater exploration – where material new discoveries are made that can drive a company’s long-term growth – would have been unthinkable for these firms a few years ago. Companies that are maintaining exploration activity for long-term growth are slashing budgets. We expect 2016 exploration spend to be around half the 2014 peak, and it could fall even further next year. Even where a company has budget to drill a prospect, its partners in that prospect may not, resulting in an exploration investment gridlock.
Deepwater fields already in production are cash-generating assets for many companies. They are generally low cost, requiring little reinvestment and declining at a relatively low rate, especially compared to shale plays. Operators are delaying multi-billion-dollar final investment decisions (FID) on the next generation of deepwater projects while oil prices are low and costs remain high. Given the development lead times, the impact of these delays on production will be felt in three to six years. The grindingly slow pace of exploration over the next couple of years will hurt production levels in 10 to 15 years. But the impact will be felt much sooner in the industry in many ways. If it is to continue as a key growth mechanism, exploration needs to get back on track – and quickly.