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.
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
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
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
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.
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