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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In a few days, the bi-annual OPEC meeting will take place on November 30, leading into a wider OPEC+ meeting on December 30. This is what all the political jostling and negotiations currently taking place is leading up to, as the coalition of major oil producers under the OPEC+ banner decide on the next step of its historic and ambitious supply control plan. Designed to prop up global oil prices by managing supply, a postponement of the next phase in the supply deal is widely expected. But there are many cracks appearing beneath the headline.
A quick recap. After Saudi Arabia and Russia triggered a price war in March 2020 that led to a collapse in oil prices (with US crude prices briefly falling into negative territory due to the technical quirk), OPEC and its non-OPEC allies (known collectively as OPEC+) agreed to a massive supply quota deal that would throttle their production for 2 years. The initial figure was 10 mmb/d, until Mexico’s reticence brought that down to 9.7 mmb/d. This was due to fall to 7.7 mmb/d by July 2020, but soft demand forced a delay, while Saudi Arabia led the charge to ensure full compliance from laggards, which included Iraq, Nigeria and (unusually) the UAE. The next tranche will bring the supply control ceiling down to 5.7 mmb/d. But given that Covid-19 is still raging globally (despite promising vaccine results), this might be too much too soon. Yes, prices have recovered, but at US$40/b crude, this is still not sufficient to cover the oil-dependent budgets of many OPEC+ nations. So a delay is very likely.
But for how long? The OPEC+ Joint Technical Committee panel has suggested that the next step of the plan (which will effectively boost global supply by 2 mmb/d) be postponed by 3-6 months. This move, if adopted, will have been presaged by several public statements by OPEC+ leaders, including a pointed comment from OPEC Secretary General Mohammad Barkindo that producers must be ready to respond to ‘shifts in market fundamentals’.
On the surface, this is a necessary move. Crude prices have rallied recently – to as high as US$45/b – on positive news of Covid-19 vaccines. Treatments from Pfizer, Moderna and the Oxford University/AstraZeneca have touted 90%+ effectiveness in various forms, with countries such as the US, Germany and the UK ordering billions of doses and setting the stage for mass vaccinations beginning December. Life returning to a semblance of normality would lift demand, particularly in key products such as gasoline (as driving rates increase) and jet fuel (allowing a crippled aviation sector to return to life). Underpinning the rally is the understanding that OPEC+ will always act in the market’s favour, carefully supporting the price recovery. But there are already grouses among OPEC members that they are doing ‘too much’. Led by Saudi Arabia, the draconian dictates of meeting full compliance to previous quotas have ruffled feathers, although most members have reluctantly attempt to abide by them. But there is a wider existential issue that OPEC+ is merely allowing its rivals to resuscitate and leapfrog them once again; the US active oil rig count by Baker Hughes has reversed a chronic decline trend, as WTI prices are at levels above breakeven for US shale.
Complaints from Iran, Iraq and Nigeria are to be expected, as is from Libya as it seeks continued exemption from quotas due to the legacy of civil war even though it has recently returned to almost full production following a truce. But grievance is also coming from an unexpected quarter: the UAE. A major supporter in the Saudi Arabia faction of OPEC, reports suggest that the UAE (led by the largest emirate, Abu Dhabi) are privately questioning the benefit of remaining in OPEC. Beset by shrivelling oil revenue, the Emiratis have been grumbling about the fairness of their allocated quota as they seek to rebuild their trade-dependent economy. There has been suggestion that the Emiratis could even leave OPEC if decisions led to a net negative outcome for them. Unlike the Qatar exit, this will not just be a blow to OPEC as a whole, questioning its market relevance but to Saudi Arabia’s lead position, as it loses one of its main allies, reducing its negotiation power. And if the UAE leaves, Kuwait could follow, which would leave the Saudis even more isolated.
This could be a tactic to increase the volume of the UAE’s voice in OPEC+, which has been dominated by Saudi Arabia and Russia. But it could also be a genuine policy shift. Either way, it throws even more conundrums onto a delicate situation that could undermine an already fragile market. Despite the positive market news led by Covid-19 vaccines and demand recovery in Asia, American crude oil inventories in Cushing are now approaching similar high levels last seen in April (just before the WTI crash) while OPEC itself has lowered its global demand forecast for 2020 by 300,000 b/d. That’s dangerous territory to be treading in, especially if members of the OPEC+ club are threatening to exit and undermine the pack. A postponement of the plan seems inevitable on December 1 at this point, but it is what lies beyond the immediate horizon that is the true threat to OPEC+.
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In the U.S. Energy Information Administration’s (EIA) November Short-Term Energy Outlook (STEO), EIA forecasts that U.S. crude oil production will remain near its current level through the end of 2021.
A record 12.9 million barrels per day (b/d) of crude oil was produced in the United States in November 2019 and was at 12.7 million b/d in March 2020, when the President declared a national emergency concerning the COVID-19 outbreak. Crude oil production then fell to 10.0 million b/d in May 2020, the lowest level since January 2018.
By August, the latest monthly data available in EIA’s series, production of crude oil had risen to 10.6 million b/d in the United States, and the U.S. benchmark price of West Texas Intermediate (WTI) crude oil had increased from a monthly average of $17 per barrel (b) in April to $42/b in August. EIA forecasts that the WTI price will average $43/b in the first half of 2021, up from our forecast of $40/b during the second half of 2020.
The U.S. crude oil production forecast reflects EIA’s expectations that annual global petroleum demand will not recover to pre-pandemic levels (101.5 million b/d in 2019) through at least 2021. EIA forecasts that global consumption of petroleum will average 92.9 million b/d in 2020 and 98.8 million b/d in 2021.
The gradual recovery in global demand for petroleum contributes to EIA’s forecast of higher crude oil prices in 2021. EIA expects that the Brent crude oil price will increase from its 2020 average of $41/b to $47/b in 2021.
EIA’s crude oil price forecast depends on many factors, especially changes in global production of crude oil. As of early November, members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) were considering plans to keep production at current levels, which could result in higher crude oil prices. OPEC+ had previously planned to ease production cuts in January 2021.
Other factors could result in lower-than-forecast prices, especially a slower recovery in global petroleum demand. As COVID-19 cases continue to increase, some parts of the United States are adding restrictions such as curfews and limitations on gatherings and some European countries are re-instituting lockdown measures.
EIA recently published a more detailed discussion of U.S. crude oil production in This Week in Petroleum.
The U.S. Energy Information Administration (EIA) forecasts that members of the Organization of the Petroleum Exporting Countries (OPEC) will earn about $323 billion in net oil export revenues in 2020. If realized, this forecast revenue would be the lowest in 18 years. Lower crude oil prices and lower export volumes drive this expected decrease in export revenues.
Crude oil prices have fallen as a result of lower global demand for petroleum products because of responses to COVID-19. Export volumes have also decreased under OPEC agreements limiting crude oil output that were made in response to low crude oil prices and record-high production disruptions in Libya, Iran, and to a lesser extent, Venezuela.
OPEC earned an estimated $595 billion in net oil export revenues in 2019, less than half of the estimated record high of $1.2 trillion, which was earned in 2012. Continued declines in revenue in 2020 could be detrimental to member countries’ fiscal budgets, which rely heavily on revenues from oil sales to import goods, fund social programs, and support public services. EIA expects a decline in net oil export revenue for OPEC in 2020 because of continued voluntary curtailments and low crude oil prices.
The benchmark Brent crude oil spot price fell from an annual average of $71 per barrel (b) in 2018 to $64/b in 2019. EIA expects Brent to average $41/b in 2020, based on forecasts in EIA’s October 2020 Short-Term Energy Outlook (STEO). OPEC petroleum production averaged 36.6 million barrels per day (b/d) in 2018 and fell to 34.5 million b/d in 2019; EIA expects OPEC production to decline a further 3.9 million b/d to average 30.7 million b/d in 2020.
EIA based its OPEC revenues estimate on forecast petroleum liquids production—including crude oil, condensate, and natural gas plant liquids—and forecast values of OPEC petroleum consumption and crude oil prices.
EIA recently published a more detailed discussion of OPEC revenue in This Week in Petroleum.