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 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.
In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.
Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.
We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.
Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.
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The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.
How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.
The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.
The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.
On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.
But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.
For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.
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