Oil majors wrestle with reserves as industry health measure

As oil majors and investors grapple with the upheaval of the energy transition, some traditional metrics for producers' long-term growth potential are up for debate.

Climate change, the renewable energy boom and electrification are throwing demand scenarios for oil and gas wide open and casting a shadow over future returns in the sector.

Where a company's production-to-reserve ratio, or reserves life, was once a proxy for business sustainability, many now see exposure to stranded assets in reserves either too expensive or polluting to extract.

Shell, which has only replaced its annual production with new reserves twice since 2011, faced analyst scrutiny this month after reporting its reserves slumped to fresh lows due to divestments and the writedown of a troubled Dutch gas field.

The Anglo-Dutch supermajor is now able to maintain just 8.4 years of current production with its proved reserves, the lowest reserves life ratio of its oil major peers.

Fielding questions over its upstream growth potential, Shell said it is pursuing a “value before volume” rationale, happy to ditch reserves in lower value projects in favor of higher margin developments such as North America and Brazil.

"I do want to stress that not all barrels are created equally, and that we will not chase production volumes on reserves, but we will continue to focus on cash generation and returns," CFO Jessica Uhl told analysts on an earnings call.

One challenge is the reliance on US Securities and Exchange Commission’s proved reserves reporting to analyze true exploration performance.

Shell claims it is being penalized by the US SEC reporting rules which don't allow reserves from LNG projects to be booked without a third-party sales contract. As the world's biggest integrated gas player, Shell markets a lot of its own gas, which keeps some proven reserves off its books.

Booking US shale reserves is also problematic. SEC rules allow proved status for shale that can be profitably tapped in the next five years. With economic recoverability tied to short-term well costs, efficiency gains and prices, shale bookings can be more fickle than conventional projects.

Different strokes

Shell 's approach to reserves is by no means unique.

Quality, not quantity, of proved reserves has become the new mantra for oil company executives, particularly as higher-cost projects such as Canadian oil sands and remote, deepwater fields were shelved in the wake of the 2014 oil price slump.

The cost curve for resource development is now the battleground being fought over, with oil majors promising ever tougher discipline and efficiency to approve projects that can turn a profit at below $40/b.

Total's CEO Patrick Pouyanne told analysts this month he is confident that the company's 20 years of proven and probable reserves life — a much wider measure than just proved — is more than enough to feed its longer-term growth as they can all be developed profitably at $50/b.

Like most of its peers, the French major has seen its proven reserves slip in recent years. At the start of 2018, however, its proved reserves could still meet over 12 years of production, broadly the historic benchmark for most oil majors.

Others take a more traditional view of growing their reserves.

In the US, ExxonMobil prides itself on consistently growing its reserves, which were able to cover 14 years of production at the start of 2018. The oil giant is not slowing down either. Last year it made the biggest haul in the industry, discovering close to 2 billion barrels in gross resources off Guyana.

Italy's Eni also takes a more traditional view of reserves as a marker of business sustainability, but only because it sees organic growth as a more reliable source of low-cost resources to future proof its reserve base.

Fresh pastures?

Keeping upstream costs in check by passing over harder-to-pump, lower-margin reserves, known as "portfolio high-grading", is also being fueled by the growing clamor for energy companies to walk in step with the Paris climate goals. The potential for a much faster than expected, policy-driven shift to low-carbon energy also makes guessing the future market for oil and gas more tricky.

But oil majors believe concerns over peak oil demand, at least, are premature given the ample resources in the ground and the difficulty of displacing oil in key sectors such as aviation and plastics.

BP's chief economist Spencer Dale, for example, is sanguine about the impact on IOCs of even the most pessimistic scenarios for oil demand in the coming decades.

Under a “Rapid Transition” scenario of radical switching to cleaner fuels compatible with meeting the Paris climate goals, oil demand would be slashed by around 28 million b/d in 2040 to 80 million b/d, BP estimates.

Even under this scenario, however, oil and gas would still provide half of the world's energy needs in 2040, Dale points out, providing plenty of growth room for hydrocarbon producers.

“If we can produce amongst the cheapest oil of the 80 million b/d demand in 2040, then we can carry on producing that oil,” he said, presenting BP's latest long-term energy outlook.

For that reason, Dale believes simple market forces will generate the returns for the “trillions of dollars” needed to develop existing and future oil and gas resources in the years ahead.

With the world's five top oil supermajors producing less than 10% of the world's oil, Dale notes, a company like BP would only need to take a "tiny fraction" of market share to carry on growing its oil production for decades.

But that's still a big “if”. Barring major economic and political reforms, access to the world’s cheapest oil and gas is largely off-limits to IOCs in places like Saudi Arabia, Iran, Kuwait, Russia, and Iraq.

Still, if BP's optimism over future demand proves correct, success through the drill bit may remain a key sector performance marker for the foreseeable future.