Easwaran Kanason

Co - founder of NrgEdge
Last Updated: May 16, 2020
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Business Trends
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As the Covid-19 slowly but surely eases, the oil and gas industry has released its financial results for Q1 2020. And, as expected, the results are rather grim.                  

The year 2020 started off on a relatively decent note, with oil prices in the mid-US$60/b range. It wasn’t record-breaking, but it was sustainable, with hope that the supply glut anticipated for the year would gradually ease. At US$60/b, there’s profit to be made, even for expensive projects aimed at tapping into risky-resources, from Canada’s oil sands complex in Alberta to Total’s difficult deepwater Brulpadda project in the turbulent seas off South Africa. It is enough for the US shale patch to continue drilling to save its life, and it more than covers the estimated production costs in Saudi Arabia that is thought to be near US$10/b.

What a change a few months have made. The rumblings of the Covid-19 outbreak moved from isolated in China to a full-blown global pandemic, causing a swift but sure attack on energy demand. Demand reacts to supply, but supply in the oil world is slow to react. Very slow to react. Then, as country after country initiated lockdowns, the two titans of the OPEC+ pact decided to initiate something else: an oil price war following a disagreement over extending and deepening the club’s supply deal. Oil prices halved to US$30/b. That lasted for over a month, resolved only in April, by which time, untold damage had been done and US oil prices briefly, fell into negative territory. The global Brent benchmark fell to US$15/b.

The cut-off for financial results was March 31, before the worst of the price route occurred. But it was enough to cause alarming results for the world’s largest publicly-traded oil companies. Years of fiscal restraint had slowly been giving way to ambitious spending. That has been cut short, but the previous cost-cutting measures did put the supermajors in a better position to weather a storm. The only question now is: how long will this storm last?

As it were, the Q1 2020 financial results from the five oil supermajors paint a mixed picture. Traditionally, BP and Shell are the first to release. First to bear the bad news was UK’s BP, which declared a net profit of US$800 million, down from US$2.4 billion reported in Q1 2019. It was, according to CEO Bernard Looney, ‘a good quarter but, undoubtedly, a very brutal environment’, but BP still declared a (reduced) dividend for its shareholders. Reducing dividends were a common denominator across the board in the industry, with Norway’s Equinor being the first to announce and Shell following BP by cutting its shareholder rewards for the first time since World War II and suspending its share buyback programme. Shell’s results did manage to meet market expectations, though, with net profit down by almost half to some US$2.9 billion. Total, the last of the European supermajors to report, also had similar results, net profits sliding down to US$1.8 billion, beating consensus forecasts.

It was in the US, though, that the worst financial results were reported. This was already expected, with service giants Schlumberger and Halliburton reporting massive impairments on the destruction of the US shale patch; and of the supermajors, none bet more heavily on the golden egg of shale than Chevron and ExxonMobil. Against that backdrop, Chevron actually performed very well. Having lagged behind its rivals since 2017, Chevron actually reported a 14% rise in profits to US$3.6 billion despite a 13% fall in revenue. But that was largely because Chevron had already taken a US$10 billion impairment on Permian shale assets in Q4 2020, and must be relieved that its attempted takeover of Anadarko last year was sniped by Occidental Petroleum. In contrast, ExxonMobil took it on its chin in Q1 2020, declaring a US$2.9 billion impairment on the value of its inventory and assets due to the crude plunge, leading to a quarterly net loss of US$610 million.

Across the board, dividends were slashed, as was capital expenditure, which all supermajors slashing their upstream budgets by an average of 30% for 2020 and 2021. Most are predicting an annual loss of some 16-20 mmb/d of oil demand for the year, coinciding with the higher end of predictions, reflecting a mood that a recovery will come soon. But before that recovery can come, the entire industry still has to weather the current storm. If the conditions in Q1 2020 were bad, then the conditions in Q2 2020 will be worst. Grim as they as, the Q1 2020 financial results are no anomaly, but a sign of worst things to come. The only hope that the industry is clinging on to is that the storm will pass soon. That can’t come soon enough.

Q1 2020 Supermajor Results:

- ExxonMobil: Revenue (US$56.1 billion, down 11.1% y-o-y); Net Profit (-US$610 million, down 120% y-o-y)

- Chevron: Revenue (US$29.7 billion, down 13.1% y-o-y); Net Profit (US$3.6 billion, up 13.8% y-o-y)

- Shell: Revenue (US$60 billion, down 28.3% y-o-y); Net Profit (US$2.9 billion, down 46% y-o-y)

- BP: Revenue (US$59.7 billion, down 10% y-o-y); Net Profit (US$800 million, down 67% y-o-y)

- Total: Revenue (US$43.8 billion, down 14.4% y-o-y); Net Profit (US$1.8 billion, down 35% y-o-y)

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Renewables became the second-most prevalent U.S. electricity source in 2020

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.

monthly U.S electricity generation from all sectors, selected sources

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.

July, 29 2021
PRODUCTION DATA ANALYSIS AND NODAL ANALYSIS

Kindly join this webinar on production data and nodal analysis on the 4yh of August 2021 via the link below

https://www.linkedin.com/events/productiondataanalysis-nodalana6810976295401467904/

July, 28 2021
Abu Dhabi Lifts The Tide For OPEC+

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.

End of Article 

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Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Worries about new Covid-19 infections worldwide dragging down demand just as OPEC+ announced that it would be raising production by 400,000 b/d a month from August onward triggered a slide in Brent and WTI crude prices below US$70/b
  • However, that slide was short lived as near-term demand indications showed the consumption remained relatively resilient, which lifted crude prices back to their previous range in the low US$70/b level, although the longer-term effects of the Covid-19 delta variants are still unknown at this moment
  • Clarity over supply and demand will continue to be lacking given the fragility of the situation, which suggests that crude prices will remain broadly rangebound for now

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July, 26 2021