It does not seem that long ago when Saudi Arabia’s crown jewel, Saudi Aramco was about to make a huge splash by listing (a tiny portion of itself) publicly for the first time. Although that was less than a year ago, many of the details then have now been glazed over. Over the final quarter of 2019, the IPO timeline was in considerable flux, reportedly because the Saudi Crown Prince was determined to engineer a US$2 trillion debut valuation. It did not. At least not immediately, starting at US$1.88 trillion before briefly hitting target after. Several months later, a global pandemic has significantly reduced that valuation. Not only that, Saudi Aramco no longer has claim to the title of the world’s most valued company. That belongs to Apple.
But that’s besides the point now. What matters is Aramco’s commitments in the lead-up to its valuation. In order to generate the maximum amount of interest, mainly from the ruling and connected Saudi families, Aramco promised to hand out over US$75 billion in annual dividends through 2025. Even in better times, that’s a huge promise. But now that the oil price situation has upended, it seems unsustainable.
For another company, public-listed or private, the solution would be simple. Scale back announced dividend payouts, or stop them completely. That’s what companies like Shell, BP and Total have done. In an economic crisis, most investors would understand. But what if the major shareholder is a government? Aramco is still 98% owned by the Saudi government, and the federal coffers, which run everything from the national airline to plans to open up for official tourism are dependent on the dividends that Aramco pays. Adjusting the dividend payouts is not an option, particularly since the government is already far from balancing its budget even with the current fiscal structure. The blurred line between Saudi Arabia and Saudi Aramco is a double-edged sword; and it is now a liability for a company that finds its hands shackled and its flexibility to manoeuvre cemented down due to its commitments.
This need to prioritise dividends means that Saudi Aramco has a reckoning to face. Its valuation and, indeed, business plan was driven by a diversification strategy that was meant to move Aramco from an upstream-focused titan to an integrated behemoth. Aramco had invested in key refining nodes throughout Asia and the world that ensure captive demand for its crude in key markets. It bought SABIC in a pricey deal that was part of a petrochemicals-heavy downstream dive. It set up an LNG trading desk in Singapore before it even produced a single drop of liquefied natural gas. With dry season in the oil and gas world setting in, some of these projects must now wither so that the rest of Saudi Aramco can survive.
A spate of cancellations and deferments have been announced. The planned US$20 billion crude-to-chemicals plan in Yanbu is likely to be cancelled outright. The decision to purchase 25% of Sempra Energy’s Port Arthur LNG project in Texas is being reviewed. A US$6.6 billion plan to add new petrochemicals capacity at the Motiva refinery on the US Gulf Coast is on pause. Downstream plans linked to greenfield refinery investments in Pakistan, India and China have been delayed. CEO Amin Nasser has slashed CAPEX for 2020 from US$40 billion to US$25 billion, and the March 2020 plans to boost crude output capacity within the Kingdom (to 13 mmb/d from a current 12 mmb/d) have been deferred by a year.
But, as dire as this sounds, this is more of a refocusing rather than a reckoning. There is a certain trend here, where outright cancellations are linked to eliminating risk of excess capacity, while delays are linked to new projects and expansions. In petrochemicals, for example, Aramco’s SABIC purchase means it already has a large surplus of production capacity. Adding to that right now, with the global economy expected to be weak for years, is not good business. But Aramco is also committed to expanding its natural gas/LNG offerings and securing long-term demand nodes through refining for its crude. It is just admitting that now is not the best time to focus on those.
It is then instructive to look at what projects have not been affected by the slash in funding. It remains in talks to acquire a stake in India’s Reliance and an integrated downstream site in China’s Zhoushan. The Yanbu plans are expected to be repackaged as incremental upgrades to existing sites, a move to focus on upgraded brownfield sites over building greenfield ones. And drilling still continues, with Aramco announcing the discovery of two new oil and gas assets near the Kingdom’s border with Iraq, with the Hadabat Al-Hajara and Abraq at-Tulul fields offering a mixture of light crude, condensates and natural gas to the market.
Saudi Aramco is not retreating because it wants to. It is retreating because it has to. All indications now appear to show that Aramco is committed to following the strategy roadmap it has outlined previously. At least in the future, Aramco will become more diversified and in line with industry expectations. The current dividend situation has made Aramco less nimble. Admitting its challenges maybe out of character for Saudi Aramco. But the one thing that all can admit right now is that a pause is necessary in order to figure out the best way forward.
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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.