Australia’s LNG producers face the risk of massive write-downs on the fundamental value of their multi-billion dollar investments as the COVID-19 crisis raises questions about the longer-term role of gas in a low-carbon world.
Shell’s stunning advice this week of write-downs of up to $US22 billion ($31.6 billion), much of it driven by Australian LNG, sent shivers down the collective spine of the local industry.
Oil Search added to the gloom, advising it would cut its workforce by almost a third by the end of the year, putting paid to lingering hopes of a revival in the fortunes of its stalled LNG expansion in Papua New Guinea.
In the US, the 15th anniversary of the shale boom looks set to be marked by as much as $US300 billion of impairments this June quarter, estimates Deloitte, warning of a potential chain reaction of insolvencies and restructuring. US shale pioneer Chesapeake Energy filed for bankruptcy protection last weekend.
The Shell news strengthened the view that took hold after BP’s similar impairment advice in June that heavy write-downs must only be a matter of time for Australia’s home-grown LNG players, Woodside Petroleum, Santos, Origin Energy and Papua New Guinea’s Oil Search.
The cut in oil price assumptions by Shell and BP that sits behind the write-downs gives added traction to a theory that COVID-19 is not just a cyclical shock to the sector but represents a fundamental shift that means that valued assets are worth less in a post-pandemic world than they were before.
Shell’s global chief executive, Ben van Beurden, startled investors in late April when he suggested oil demand may have peaked last year, while BP boss Bernard Looney has pointed to a likely step-up in efforts towards “a Paris-consistent world” that also have ramifications for gas demand.
BP’s revised long-term assumptions have oil sitting at $US55 a barrel in 2020 terms, while Shell is now assuming $US60 a barrel, although only $US35 this year. That leaves a big gap to the $US70-$US75 a barrel real prices for Brent crude that analysts say are being used typically across the Australian industry for asset impairment testing.
“Following some high profile impairments in the global energy sector recently, we expect the Australian energy sector to face heightened impairment risk this half,” Macquarie Equities advised clients.
Still, while Credit Suisse energy analyst Saul Kavonic points to a risk of local write-downs, he says there are still doubts that the Australian producers will follow the lead of the European majors.
The European players are widely regarded as moving more purposefully down the path of a transition to low-carbon energy than their US peers, with Australian producers somewhere in between.
“In Australia, writedowns are now a higher risk, but far from a foregone conclusion,” Mr Kavonic said, adding that companies can use an oil price downturn to announce write-downs that are driven by project execution problems under the cover of lower oil prices.
Indeed, the only two assets singled out in the $US8 billion-$US9 billion of write-downs in Shell’s integrated gas business were the QCLNG venture in Queensland, acquired through the bullish $US50 billion takeover of BG Group in 2016, and the highly ambitious Prelude floating project. Prelude has yet to reach full production and has been offline since early March.
Shell acknowledged in its announcement that “a changed view on the development attractiveness” was a factor in the revised asset values, in addition to lower prices.
Still, sources say the write-downs by Shell and others put in stark relief the impact of sustained low prices and cast further uncertainty on the appetite for their continued investment in Australia and in projects such as the Woodside-led high-carbon Browse LNG venture.
The debate comes as the short-term gas market remains under huge pressure after spot LNG prices tumbled to a record low below $US2 per million British thermal units in April. More than 40 Australian LNG cargoes have faced lengthy delays, or been anchored offshore, with the odd shipment diverted as far afield as Mexico, according to consultancy EnergyQuest.
The firm suggests the market may only deteriorate this northern summer, with European spot prices potentially following US crude oil into negative territory.
Wall Street energy analyst Paul Sankey of Mizuho Securities calculates that based on some shipments, prices in the “disastrous” LNG market have already effectively fallen as deeply into negative territory as West Texas Intermediate did in April.
Mr Sankey pointed to an LNG cargo that was being redirected back from Belgium to the US from where it originated in the first place. All up, including liquefaction, shipping, loading, reloading and unloading, he put the cost at $US10/MMBTU delivered, well above the US benchmark spot price at Henry Hub of $US1.85. That delivers a “netback” of negative $US8.15/MMTBU, equivalent to negative $US49 a barrel of oil.
“What a mess the market is in, with many of the characteristics of heavy oil, namely high fixed/sunk capital, low storage relative to production scale, distressed low marginal cost production,” Mr Sankey told clients.
The impact of the dire market on US LNG cargoes also has a local angle. With the further slump in contract LNG prices in Europe and Asia due to the collapse in oil prices, the expected gap in prices between cheap shale in the US and overseas gas markets has disappeared.
That has ruined the business case behind deals struck by Woodside and others several years ago to purchase US cargoes.
“The global gas market today looks vastly different to when these contracts were signed,” Wood Mackenzie Asia Pacific vice chairman Gavin Thompson said in a blog.
“The economic chaos wrought by the coronavirus lockdown has cratered demand and worsened the LNG oversupply, pushing global gas prices even lower.”
Sydney-based Citigroup analyst James Byrne has told clients that Woodside is “likely to be out of the money…for 20 years” on a deal it struck in 2014 and which started up in May to purchase cargoes from the Corpus Christi LNG export terminal in Texas.
Mr Byrne puts the hit to Woodside’s 2020 profit at $US46 million as the company elects to pay a $US3.50/MMBTU “take-or-pay” toll fee rather than taking delivery of the gas. Total losses over 20 years could amount to $US1.5 billion, Citi estimates, noting the deal would only break even at an oil price of $US72 a barrel, assuming a long-term Henry Hub price of $US2.50/MMBTU.
Woodside has yet to give formal guidance on its US LNG cargoes, amid expectations of an update in its June quarter report on July 16. However chief executive Peter Coleman said in early May that the industry in general “is not taking cargoes out of any of those plants for on-sale into Europe”.
While Woodside, like Santos and Oil Search, remain confident in the long-term outlook for LNG, Mr Coleman has acknowledged the risk that companies “drink our own cordial” and over-invest in new LNG capacity once the market stabilises and billions of dollars of stalled potential investments come back onto the table.
Extracted from AFR