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It’s been a dry year so far for industry mergers and acquisitions – or A&D (acquisitions and divestitures) as the activity is known in the upstream world. But what little activity there is makes for some interesting reading. Particularly because it provides some idea for what the future could look like post-2020. Occidental Petroleum, for example, looks shaky as it furiously attempts to shed its debt load. Chevron, on the other hand, has had the last laugh, acquiring Noble Energy and finally managing to stitch together its disparate Permian assets into a more comprehensive tapestry. The latest of these intriguing moves also centres upon US shale, specifically the Permian golden goose. Malaysia’s national oil company Petronas is reportedly looking into buying its way into US shale, with driller DoublePoint Energy the target.
While neither firm has commented and reports suggest that talks are still at a preliminary stage, the possibilities are interesting. DoublePoint Energy has a 100,000 acre tranche of drilling rights smack in the prolific heart of the Permian, currently producing some 55,000 b/d of shale oil. Backed by private equity including the Blackstone Group, Apollo Global Management, Quantum Energy Partners and Magnetar Capital, DoublePoint is headed up by Cody Campbell and John Sellers – who made a name for themselves for patching together separate Permian drilling leases into a more cohesive whole, then selling that on to interested buyers for a tidy profit. Their previous largest sale (to Parsley Energy in 2017) amounted to US$2.8 billion.
Given the current climate, Campbell and Sellers might not be able to hit those same highs. After all, the industry is reticent to splash out wantonly in the Permian, given the history of steep production drops and the tricky oil price situation going forward. Chevron’s acquisition of Noble Energy, for example, was a relative steal at US$5 billion. DoublePoint Energy’s assets have already been previously assessed – a push by its private equity owners – with a 2019 valuation pegged at US$5 billion. It might fetch half of that today, making it a relatively safe bet for Petronas and still a decent sum for DoublePoint.
But what is more interesting is not this sale itself, but how it fits into the wider strategy of Petronas. Known as one of the most well-run of the national oil companies that emerged since the 1970s, Petronas leveraged its massive (at the time) asset base in Malaysia to go international. It moved into Central Asia, the Middle East and Africa early, opening out new upstream horizons there. It bet big on natural gas – specifically LNG – and remains one of the largest producers in the world and operates one of the largest LNG fleets through subsidiary MISC. It has recently expanded its downstream portfolio with the massive RAPID refinery in Johor, significantly expanding its footprint in high-value fuels and petrochemicals. And now, it seems, it has its sights set on a new frontier: the Americas.
Petronas and the Americas are no stranger to each other, but arguably the relationship kicked off in earnest when Petronas began exploring options to establish an LNG export facility in Canada’s British Columbia coast. That attempt hit several snags, its own Pacific Northwest project was derailed due to environmental sensitivity, with Petronas eventually buying a 25% stake in the Kitimat project led by Shell. But over the past two years, the pace has picked up. Petronas snapped up 10 blocks in Mexico, including some in the offshore Salinas Basin and Mexican Ridges. It bought a 50% stake in the Tartaruga Verde and Espadarte fields in Brazil’s offshore Campos Basin. It has an ongoing, and very promising drilling campaign in Suriname. It is aiming to have its first shale oil success through Argentina’s Vaca Muerta formation, through a US$2.3 billion joint venture with Argentine state oil firm YPF. And it is already in the USA, jointly announcing an ultra-deepwater discovery in the US Gulf of Mexico’s Monument well in January 2020 with its partners Equinor and Repsol.
Given this context, a Petronas presence in the Permian is not a possibility but an eventuality. If not DoublePoint Energy, then someone else. But the time seems ripe for the hunt, as the red hot-valuations of Permian players cool down to something more realistic and less risky since 2018. For the path that Petronas’ Americas expansion has taken – a stated focus for the company – this is a logical progression. And by the sounds of it, there might be more to come.
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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.