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 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.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b
Headlines of the week
The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects
Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b
Headlines of the week