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Energy transition fears drive short-term focus

The world will still need oil and gas for the foreseeable future. But concerns over how much and for how long are stifling investment

Peak oil used to be a term relevant to the supply side. That it is now applicable on the demand side instead is testament to two of the energy industry's biggest game-changers of the past decadethe US shale oil boom and the emergence of renewables as an affordable, scalable future source.

The pace of the so-called energy transition to a low or zero carbon emissions future is highly uncertain. At Petroleum Economist's GCC Strategy Forum in February, Andy Brogan, global oil and gas transaction advisory services leader at consultancy EY, illustrated six different forecasts for oil demand out to 2040, from ExxonMobil, Opec and two each from BP and the International Energy Agency (IEA).

The 2040 predictions ranged from over 120mn bl/d in the IEA's "current policies" scenario, around 110mn bl/d in the ExxonMobil, Opec and BP base-case projections, but dramatically lower at sub-80mn bl/d in BP's "extra-fast transition" and only just above 70mn bl/d, or a full 50mn bl/d lower than its "current policies" figure, for the IEA's "sustainable development" scenario.

The timing for peak oil demand varies similarly, from right now in the IEA's more aggressive energy transition and around the end of the decade for BP's extra-fast model, through a 2020s projection from Shell, to the start of the 2030s for BP's base case and actually beyond 2040 for Opec and ExxonMobil.

This uncertainty over the future is understandable, but also makes for an uncomfortable present. Because, while 2040 may at first glance seem far away, the investment required to produce at least some of the oil and gas we will still need even under the most aggressive energy transition projections must be made now.

EY calculates 2040 production from existing assets at around 40mn bl/d, applying a decline rate of 4pc from a 2018 global oil and liquids production figure of just shy of 100mn bl/d, well shy of 70-80mn bl/d under the lower range of the estimates and 70mn bl/d below the 110mn-bl/d figures of the ExxonMobil/Opec/BP base-case scenarios.

Undercapitalised industry

In short, the industry needs more investment, but it cannot be sure how much. Brogan estimates the current industry investment commitments are only enough to meet the production required in the most aggressive, lowest-oil-demand scenarios, yet current policy evolution does not yet support a future where this is currently the likeliest scenario, suggesting that the industry is undercapitalised.

This view is supported by Rob West, founder and CEO of research firm Thunder Said Energy and previously a partner at analyst Redburn. A Redburn survey of institutional investors in late 2018 found that the average base-case internal rate of return (IIR) for investment in greenfield oil and gas projects, as opposed to dividend growth and buybacks, rose from 14pc for LNG, through 15pc for US shale oil and 18pc for US deep water to 21pc for large projects outside safe geographies.

The results surprised Redburn, given that it had been assuming a cost of capital more like 10pc, based on supporting factors such as the US securities and exchange commission (SEC) demanding that oil companies must use a 10pc discount rate when reporting net present value (NPV) of their reserves and information service Bloomberg putting mean working average cost of capital (Wacc) across 12 major oil firms at 9pc. Applying a 20pc IIR to the average project requires, in Redburn's view, $70/bl oil to break even, compared to $40/bl at 10pc.

"The leading reason for higher hurdle rates is growing investor fear over the energy transition" is the frank conclusion of Redburn's report into its findings, authored by West. "And the further investors are looking out into the future, the more concerned many seem to be."

Shale's advantage

LNG's position at the bottom of the rangeeven though LNG very often requires significant upfront investment and patience for a returnreinforces the view that perception of future risk is key, with gas seen as a safer long-term bet than oil. While shale oil may offer lower absolute returns than conventional, the fact that you can get your money back quicker is a key factor in its lower IIR. "It is not yet appreciated how relatively well advantaged shale is going to be at attracting capital, in a world of increasing investor caution to funding longer-cycle projects," West argues.

In contrast, according to his estimates, long-life projects will take 10-12 years before paying off their discounted upfront investment costs and 20 years to repay those costs undiscounted. "An investor is implicitly being asked to look out to 2028-38 and decide whether these projects are rational investments," say West.

"In the North Sea in the 1980s, if it would take until year 15 or 20 to get your money back, no one batted an eyelid. But the world has changed, there is a genuine substitution effect on demand, the outlook for the product itself is unclear," agrees Carol Bell, whose CV boasts non-executive directorships of a string of non-OECD-focused oil firms including Hardy Oil and Gas, Caracal Energy, Salamander Energy and most recently Ophir Energy and TransGlobe Energy, as well as North Sea independents Revus and Det Norske.

But, while acknowledging that the energy transition has a significant impact on investment appetite, Bell does not absolve oil companies themselves of all blame. "With few exceptions, the return on capital in the E&P sector has been poor," she says. "For too many companies, the return on capital has not exceeded the cost of capital and investors have got tired of it. Investors have a choice to invest in other sectors that generate consistent returns and the oil and gas sector has seen a lot of outflows."

Debt financing difficulties

Bell is similarly unimpressed with the return on capital achieved by the majors over the past 10 years, but they have at least rewarded shareholders by paying substantial dividends. Smaller E&P companies, without major cashflows, cannot go down the dividend route to attract and retain equity investment. Equally, debt financing can be difficult to secure in some parts of the world outside the OECD, given higher governance and regulatory risks, and often greater timescales to bring discoveries into production and to start generating revenues.

Bell sees this reflected in the capital allocation behaviour of the majors, who have established key positions in US shale plays. There, investment can be switched on and off quickly in response to oil market conditions. Meanwhile deep-water wildcats have almost become a thing of the past.

In his Redburn report, West acknowledges the appetite for return, but argues that "conversely, pushing companies to maximise free cash flow and 'run down their assets' amidst the energy transition is unlikely to create long-run value for shareholders". The fear engendered by peak demand has led, in West's view, to listed oil firms concentrating too much on existing production, where little value is created as each year's free cash flow depletes the asset, and less on discovery, appraisal and development, where value is created.

Bell and West both proffer a similar solution to the conundrum of investing now into a future for oil where the uncertainty is no longer just price-related but involves existential threat: namely "advantaged" projects. "Investors will be rewarded for taking 'fossil fuel risk', allocating capital to companies, creating value and long-term growth from advantaged projects at the bottom end of the global cost curve," says West.

"New oil will have to be advantaged," concurs Bell, "either very big or close to infrastructure, and it will need to pay out relatively quickly."

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