The Fuse

End of an Era? Oil and Gas Megaprojects Pushed to the Back Burner

by Nick Cunningham | March 10, 2016

On March 7, Chevron announced that its colossal liquefied natural gas (LNG) export terminal on the northwest coast of Australia had finally begun operations.

The cost for the Gorgon LNG project will top $54 billion, up from an original estimate of just $37 billion. LNG prices have collapsed by more than half since 2014, raising risks for LNG exporters at a time when low oil prices are also cutting into revenues. Chevron says that with customers signed up for 20-year contracts, plus the 40-year lifespan, the project will offer stable returns. The California-based oil major reiterated that they are in it for the long haul.

“We expect legacy assets such as Gorgon will drive long-term growth and create shareholder value for decades to come,” Chairman and CEO John Watson said in a statement.

Even if Gorgon LNG turns out to be a big winner for Chevron—which remains an open question given the enormous price tag—it may still end up being one of the last mega-sized energy projects for quite a long time. Oil majors are cancelling or delaying megaprojects at a massive scale, and pivoting towards shale.

The era of the megaproject

It was only a few short years ago that gargantuan oil and gas projects were in vogue. During the historic run up in commodity prices from around 2003 to 2014, the scope of the largest oil and gas projects swelled in size, complexity, and cost. The industry hoped to capitalize on what seemed to be an era of permanently high prices.

High oil prices enticed companies to go where they had not gone before: Arctic drilling, ultra-deep water, oil sands, and even monstrously complex projects such as Kashagan in Kazakhstan, and yes, even a $54 billion LNG project in northwest Australia.

During the historic run up in commodity prices from around 2003 to 2014, the scope of the largest oil and gas projects swelled in size, complexity, and cost.

The era of megaprojects was characterized by cost inflation and setbacks. A 2014 EY report (formerly Ernst & Young) surveyed 365 oil and gas megaprojects from around the world, finding that 64 percent of them suffered from cost overruns and 73 percent had delays. Their research also showed that the trend had worsened with time: In 2011, 78 percent of upstream oil and gas projects had cost overruns or delays, while only 50 percent suffered from the same problems in 2003.

It didn’t matter. While ballooning costs were a headache for the oil majors and their shareholders, the future revenues from triple-digit oil prices still justified the expense.

From megaprojects to “short-cycle” shale

Megaprojects no longer look so attractive with oil at $40 per barrel or lower. Even if oil prices rebound, few analysts expect a return to $100 oil anytime soon, spelling the end of the megaproject for now.

Take Chevron, for example. While the oil major was relieved to finally see its Gorgon LNG project reach completion on March 7, a day later it announced a scaling-down of its ambitions. On March 8, Chevron cut its spending plans for 2017 and 2018 by more than a third, from a previous plan of $20-$24 billion each year down to just $17-$22 billion. “We’re completing major projects that have been under construction for several years. This enables us to grow production and reduce spending at the same time, which should improve our net cash flow significantly,” CEO John Watson said in a statement.

But the more revealing comment came from Jay Johnson, Chevron’s executive vice president for upstream operations:

“We’re transitioning our spending to more short-cycle, higher-return activity that utilizes existing infrastructure.”

“We’re focused on safe, reliable operations and effective project start-ups and ramp-ups. At Gorgon, we’re producing LNG and the first cargo is expected to ship next week. With an advantaged position in the Permian and a deep portfolio of operating assets, we’re transitioning our spending to more short-cycle, higher-return activity that utilizes existing infrastructure.”

In a presentation to analysts, Watson reiterated the company’s decision to back away from any future megaprojects. Aside from the Tengiz project in Kazakstan, which Chevron is still mulling over, the company won’t greenlight any more large-scale investments. “We need better prices for more long-cycle time projects,” he said, according to Bloomberg. “Ultimately, prices have to support investments.”

Instead, Chevron will look at shale drilling in the Permian Basin in West Texas. A well drilled in the Permian will cost Chevron $7 million apiece, which sounds much more attractive than shelling out billions of dollars for a project that will take years to develop.

To be sure, shale wells produce a fraction of the oil and gas that a large-scale project would, but a company like Chevron can drill hundreds or thousands of them, ramping up activity as market conditions warrant. Bloomberg reported that Chevron already has identified 1,300 Permian wells that can offer a 10 percent return with oil at $40 per barrel, and the list of profitable wells climbs dramatically as prices rise.

It is hard to overstate how substantially different the business model is compared to the recent past. In 2014, for example, Gorgon LNG and Wheatstone, another massive LNG project in Australia, swallowed up about half of Chevron’s spending for the year. In contrast, Chevron will shift much of these resources to focus on shale. “Don’t be surprised if by the middle of the next decade 20 to 25 percent of our production is in this short-cycle shale and tight activity,” Watson said on March 8.

A January 2016 report from Wood Mackenzie estimated that $380 billion worth of oil and gas investment in 68 major projects have been cancelled since 2014.

Chevron is not the only company employing this strategy. Royal Dutch Shell cancelled its Arctic drilling program last year, as well as a major oil sands projects in Canada (although Shell still has its sights set on expensive offshore oil in Brazil). In October, ConocoPhillips said that by 2017, it would cease exploration for oil and gas in deep-water. “It’s a strategic decision to exit deep-water exploration,” ConocoPhillips’ executive vice president Matt Fox said. A few months earlier ConocoPhillips outlined a plan to obtain more than half of its production from shale over the next three years. ExxonMobil also announced plans in 2015 to double shale production in the next few years while it limits its spending on megaprojects.

A January 2016 report from Wood Mackenzie estimated that $380 billion worth of oil and gas investment in 68 major projects have been cancelled since 2014. The companies involved largely had no choice but to cancel such ambitious levels of spending, but the end result will be an estimated 2.9 million barrels of oil per day that will not come online this decade.

A temporary or permanent shift?

The big question is whether large-scale single-project investments will ever come back. A sharp rise in oil prices could bring many of the suspended projects back to the forefront.

However, that seems to be a remote prospect. In the IEA’s World Energy Outlook 2015, the Paris-based energy agency does not forecast a return to $100 oil before the end of the decade. In a few of its scenarios the IEA predicts that oil will stay below that threshold through 2040. If that holds true, it could be a long time before the oil majors move forward with any more megaprojects. Fear of betting big on a project just to see oil prices continue to languish will prevent major investments for years to come.