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.
End of Article
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International expansions for Saudi Aramco – the largest oil company in the world – are not uncommon. But up to this point, those expansions have followed a certain logic: to create entrenched demand for Saudi crude in the world’s largest consuming markets. But Saudi champion’s latest expansion move defies, or perhaps, changes that logic, as Aramco returns to Europe. And not just any part of Europe, but Eastern Europe – an area of the world dominated by Russia – as Saudi Aramco acquires downstream assets from Poland’s PKN Orlen and signs quite a significant crude supply deal. How is this important? Let us examine.
First, the deal itself and its history. As part of the current Polish government’s plan to strengthen its national ‘crown jewels’ in line with its more nationalistic stance, state energy firm PKN Orlen announced plans to purchase its fellow Polish rival (and also state-owned) Grupa Lotos. The outright purchase fell afoul of EU anti-competition rules, which meant that PKN Orlen had to divest some Lotos assets in order to win approval of the deal. Some of the Lotos assets – including 417 fuel stations – are being sold to Hungary’s MOL, which will also sign a long-term fuel supply agreement with PKN Orlen for the newly-acquired sites, while PKN Orlen will gain fuel retail assets in Hungary and Slovakia as part of the deal. But, more interestingly, PKN Orlen has chosen to sell a 30% stake in the Lotos Gdansk refinery in Poland (with a crude processing capacity of 210,000 bd) to Saudi Aramco, alongside a stake in a fuel logistic subsidiary and jet fuel joint venture supply arrangement between Lotos and BP. In return, PKN Orlen will also sign a long-term contract to purchase between 200,000-337,000 b/d of crude from Aramco, which is an addition to the current contract for 100,000 b/d of Saudi crude that already exists. At a maximum, that figure will cover more than half of Poland’s crude oil requirements, but PKN Orlen has also said that it plans to direct some of that new supply to several of its other refineries elsewhere in Lithuania and the Czech Republic.
For Saudi Aramco, this is very interesting. While Aramco has always been a presence in Europe as a major crude supplier, its expansion plans over the past decade have been focused elsewhere. In the US, where it acquired full ownership of the Motiva joint venture from Shell in 2017. In doing so, it acquired control of Port Arthur, the largest refinery in North America, and has been on a petrochemicals-focused expansion since. In Asia, where Aramco has been busy creating significant nodes for its crude – in China, in India and in Malaysia (to serve the Southeast Asia and facilitate trade). And at home, where the focus has on expanding refining and petrochemical capacity, and strengthen its natural gas position. So this expansion in Europe – a mature market with a low ceiling for growth, even in Eastern Europe, is interesting. Why Poland, and not East or southern Africa? The answer seems fairly obvious: Russia.
The current era of relatively peaceful cooperation between Saudi Arabia and Russia in the oil sphere is recent. Very recent. It was not too long ago that Saudi Arabia and Russia were locked in a crude price war, which had devastating consequences, and ultimately led to the détente through OPEC+ that presaged an unprecedented supply control deal. That was through necessity, as the world faced the far ranging impact of the Covid-19 pandemic. But remove that lens of cooperation, and Saudi Arabia and Russia are actual rivals. With the current supply easing strategy through OPEC+ gradually coming to an end, this could remove the need for the that club (by say 2H 2022). And with Russia not being part of OPEC itself – where Saudi Arabia is the kingpin – cooperation is no longer necessary once the world returns to normality.
So the Polish deal is canny. In a statement, Aramco stated that ‘the investments will widen (our) presence in the European downstream sector and further expand (our) crude imports into Poland, which aligns with PKN Orlen’s strategy of diversifying its energy supplies’. Which hints at the other geopolitical aspect in play. Europe’s major reliance on Russia for its crude and natural gas has been a minefield – see the recent price chaos in the European natural gas markets – and countries that were formally under the Soviet sphere of influence have been trying to wean themselves off reliance from a politically unpredictable neighbour. Poland’s current disillusion with EU membership (at least from the ruling party) are well-documented, but its entanglement with Russia is existential. The Cold War is not more than 30 years gone.
For Saudi Aramco, the move aligns with its desire to optimise export sales from its Red Sea-facing terminals Yanbu, Jeddah, Shuqaiq and Rabigh, which have closer access to Europe through the Suez Canal. It is for the same reason that Aramco’s trading subsidiary ATC recently signed a deal with German refiner/trader Klesch Group for a 3-year supply of 110,000 b/d crude. It would seem that Saudi Arabia is anticipating an eventual end to the OPEC+ era of cooperative and a return to rivalry. And in a rivalry, that means having to make power moves. The PKN Orlen deal is a power move, since it brings Aramco squarely in Russia’s backyard, directly displacing Russian market share. Not just in Poland, but in other markets as well. And with a geopolitical situation that is fragile – see the recent tensions about Russian military build-up at the Ukrainian borders – that plays into Aramco’s hands. European sales make up only a fraction of the daily flotilla of Saudi crude to enters international markets, but even though European consumption is in structural decline, there are still volumes required.
How will Russia react? Politically, it is on the backfoot, but its entrenched positions in Europe allows it to hold plenty of sway. European reservations about the Putin administration and climate change goals do not detract from commercial reality that Europe needs energy now. The debate of the Nord Stream 2 pipeline is proof of that. Russian crude freed up from being directed to Eastern Europe means a surplus to sell elsewhere. Which means that Russia will be looking at deals with other countries and refiners, possibly in markets with Aramco is dominant. That level of tension won’t be seen for a while – these deals takes months and years to complete – but we can certainly expect that agitation to be reflected in upcoming OPEC+ discussions. The club recently endorsed another expected 400,000 b/d of supply easing for January. Reading the tea leaves – of which the PKN Orlen is one – makes it sound like there will not be much more cooperation beyond April, once the supply deal is anticipated to end.
End of Article
- Crude price trading range: Brent – US$86-88/b, WTI – US$84-86/b
- Crude oil benchmarks globally continue their gain streak for a fifth week, as the market bounces back from the lows seen in early December as the threat of the Omicron virus variant fades and signs point to tightening balances on strong consumption
- This could set the stage for US$100/b oil by midyear – as predicted by several key analysts – as consumption rebounds ahead of summer travel and OPEC+ remains locked into its gradual consumption easing schedule
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