The (New) Force Behind Upstream Asset Buys

In times of crisis, oil and gas company default to two things: staff layoffs and asset sales. The idea is to preserve cash and to focus on core operations, forgoing ambitious potential built up during the good times. It happened in 2002/2003, after 9/11 and the invasion of Iraq, and it happened again in 2015, as crude prices more than halved from over US$100/b. And it will happen once more in 2020-2021, as the industry reacts to what is being called the greatest challenge to the global economy since the Great Depression.

Which, itself, makes the notion of buying and selling oil and gas assets considerably difficult. The Covid-19 crisis has thrown up too many uncertainties in too short a time, and there are some in the industry that are openly wondering whether global oil demand will ever return to its pre-crisis level. Factor in the strengthening climate change argument that is changing the core strategies of energy supermajors, the idea of buying a (potentially distressed) oil or gas asset is now quite unappealing, not matter how strategic that asset could be. Consultant Rystad Energy recently reported that the global industry as a whole was planning to divest over 12 million barrels of oil equivalent in assets. That’s great and all, but is anyone going to buy?

The crisis has already affected deals struck pre-Covid. BP recently slashed the value of its North Sea assets set to be sold to Premier Oil by half to US$210 million (including some oil-price linked payments) and also revised the terms of its Alaska asset sale to Hilcorp Energy. The announcement came with the reason that it was ‘being adjusted to reflect developments in global commodity markets’ – which is a broad understatement indeed. Elsewhere, Total walked out of two deals to acquire the African assets of Occidental Petroleum, forgoing the deals in Ghana and Algeria that were originally done as part of Oxy’s debt-laden acquisition of Anadarko last year – a deal that at the time was considered controversial, but it now looks foolhardy. Total was to use the deal, valued at US$8 billion for Anadarko’s African assets, to deepen its footprint in Africa. It was considerably more candid, citing ‘extraordinary market environment and the lack of visibility the group faces’ and a need to be ‘financially flexible’. In Australia, Eni is going ahead with its planned sale of natural gas assets, effectively exiting the market and disposing of high-quality assets that are a critical part of Australian domestic gas network. Why sell then? The answer is to raise cash.

Asset sales are a normal part of life in the industry. But any sale requires a seller and a buyer. In these cash-strapped, challenging times, are there even any buyers in the market? In the case of BP, Total and Eni, the sales were already planned and buyers already courted. What about now? Reports suggest that finding buyers is going to challenging. In 2015, the last time the industry went on a major selling spree, private equity-backed companies started taking over assets, buying into acreage in the North Sea and other mature basins as the supermajors evolved to be leaner and meaner. This could happen again. But what won’t happen is the trend of majors and supermajors acquiring from each other. Not because they can’t afford to, but because they don’t want to. The conversation around climate change has pushed almost all supermajors and global majors to work towards being carbon neutral by 2050 with net-zero emissions. That means moving away from conventional assets towards renewables; and the reason why although Total walked away from the Occidental Petroleum deals, it is still snapping up solar and wind assets.

If private equity doesn’t deploy its capital this time round, then there will be other interests. Either from local players, British independents in the case of the North Sea, tempted by opportunities deemed non-core by the majors, or by Asian energy players. The latter trend has already been apparent for a while.

Malaysia’s Petronas had a decades-long head-start in this area, recently expanding into Latin America for the first time through Mexico and Suriname. China’s CNOOC has also been on a decade-long spending spree, while Thailand’s PTTEP was one of the very few energy companies not to slash its upstream capex budget for 2020-2021. These players, with captive domestic markets from their roles as (de facto) state oil firms, have a stronger base to work on than supermajors, while shareholder pressure (especially on issues such as climate change) lesser. In March, South Korea’s SK E&S bought a 25% stake in the Darwin LNG and the Bayu-Udan gas condensate field. In May, ExxonMobil put up its 6.8% stake in the Azeri-Chirag-Guneshli field in Azerbaijan for sale again, citing renewed interest from Asian companies.

More high-quality assets will be coming on the market at bargain prices, and there should be plenty of interest to sustain sales from established behemoths like CNOOC to less-expected players like Pertamina or ONGC. Asia has been the driving force behind oil demand growth over the past two decades. And now, it could be the driving force behind upstream growth for the next decade.

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Market Outlook:

• Crude price trading range: Brent – US$38-42/b, WTI – US$33-36/b
• Oil prices jumped up as OPEC+ confirmed a one-month extension of the current 9.7 mmb/d level of supply cuts until end-July, with promises of improved compliance by errant members such as Nigeria and Iraq
• Iraq has reportedly asked some buyers to forgo June and July cargoes, indicating it is taking concrete steps to meet its quota
• Saudi Arabia will stop its voluntary production cuts of an additional 1 mmb/d in June, and raised its Official Selling Price for crude considerably after the OPEC+ decision
• US crude oil inventories showed a surprise jump, indicating that demand recovery is still quite fragile, prompting a slide in Brent prices back below US$40/b

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