‘Big Oil’ fights back

Andrew Ward
Barrels are filled with oil at a Royal Dutch Shell lubricants blending plant in Torzhok, Russia.
Andrey Rudakov | Bloomberg | Getty Images

Conventional oil and gas producers are approving new projects at the fastest rate since the oil price crash three years ago in a sign of "big oil" fighting back against competition from US shale producers amid low crude prices.

More new oil and gasfields were given the go-ahead in the first half of this year than in the whole of 2016 as companies such as ExxonMobil, Royal Dutch Shell and BP re-engineer projects to lower costs and accelerate speed of development.

Average development costs have fallen 40 per cent since 2014, according to Wood Mackenzie, the energy consultancy, encouraging companies to revive investment despite continued weakness in the oil market. But they are doing so on a highly selective basis, with only the most attractive projects going ahead.

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"It has taken almost three years to reach this stage because back in 2015 quite a lot of people thought the oil price drop was just a blip," says Readul Islam, analyst at Rystad Energy, the Norwegian research company.

"The industry took a while to get its collective mind around the idea of 'lower for longer' and now people are getting used to lower for even longer."

The first six months of this year saw 15 large conventional upstream oil and gas projects given the green light, with reserves of about 8bn barrels of oil and oil equivalent, according to WoodMac. This compared with 12 projects approved in the whole of 2016, containing about 8.8bn barrels.

However, activity remains far below the average 40 new developments approved annually between 2007 and 2013 and, with crude prices yo-yoing around $50 per barrel, analysts say the economics of conventional projects remain precarious.

Conventional producers know that they need to sharpen operations to remain competitive in the face of surging supplies of US shale resources, which can be brought on stream more quickly and at lower cost.

Longer term threats from the rise of renewable energy, and electric vehicles in particular, are raising further questions about the commercial viability of much of the undeveloped oil and gas in companies' portfolios.

In this environment, the most risky or economically marginal projects are being cancelled, leaving billions of barrels of untapped resources "stranded" as long as weak prices persist. Producers are instead trying to mimic the "short cycle" model of US shale companies by focusing on resources that can be developed at the lowest cost in the shortest time.

Almost three-quarters of conventional projects approved this year have been "brownfield" expansions of existing fields, or satellite developments connected to existing platforms and pipelines through so-called tie-backs.

"Not only are these projects less risky than greenfield developments, they also tend to be less capital-intensive and are quicker to bring on stream, offering a quicker payback and better returns on development dollars," says Angus Rodger, research director at WoodMac.

Examples include Shell going ahead in February with its Kaikias project in the Gulf of Mexico. The field's output will be fed into the group's nearby Ursa production hub, limiting the amount of new infrastructure required. Development costs were cut by half from original estimates, allowing Kaikias to break even at below $40 per barrel.

Much of the savings have come from a squeeze on the oilfield service companies that provide equipment and build infrastructure. Mr Islam says ExxonMobil's go-ahead last month for its Liza project off the coast of Guyana was timed by the US group to benefit from "rock-bottom rates" for drilling rigs and other services.

Malcolm Dickson, research director at WoodMac, says service costs have fallen "as low as they will go" but he does not expect them to rebound because demand remains sluggish and the market is still saddled with excess capacity. This sets conventional oil and gas apart from the US shale industry, which is beginning to experience cost inflation due to resurgent drilling.

Conventional producers are trying to narrow shale's cost advantage further by adopting a "no frills" approach to development. The "big is better" mentality of the $100-oil era has given way to smaller, simplified projects, often involving fewer wells than originally planned and advanced in phases rather than all at once.

Mr Dickson cites the Buckskin project in the Gulf of Mexico, which originally involved development of 350m barrels of oil at a break-even price of $90 per barrel. It is now being pushed forward by LLOG, a privately owned US company, with an aim to develop 140m barrels with a break-even of $50 per barrel.

Project execution is also showing signs of improvement in an industry notorious for delays and budget overruns. Increased cost discipline combined with easy access to over-supplied equipment, services and labour helped BP's West Nile Delta field in Egypt come on stream in May eight months early and under budget.

Iain Reid, analyst at Macquarie, predicts that "enormous efforts" to reduce costs will be reflected in improved year-on-year earnings when the "supermajors" report second-quarter results in coming days, starting with Shell and Total on Thursday.

However, balance sheets are expected to remain under pressure from weak prices and hefty dividend commitments. This guarantees that capital expenditure will stay under tight control. More than 100 projects ready for development have been delayed since 2014, according to Rystad, and this year's upturn has barely made a dent in the backlog.

WoodMac says that half of all greenfield conventional projects awaiting a green light would not achieve a 15 per cent return on investment at long-term oil prices of $60 per barrel, raising "serious doubt" over their prospects for development. By this measure, there is twice as much undeveloped US shale oil capable of making money at $60 per barrel than there is conventional resources.

This explains why ExxonMobil and Chevron have been skewing investment towards shale, and highlights the challenge for the more traditional European majors such as Shell, BP and Total to keep driving costs lower in future.

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