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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In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

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The Impact of COVID 19 In The Downstream Oil & Gas Sector

Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.

Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.

Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and  power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.

Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.

But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.

Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.

Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)

Region
Consumption (mmb/d)*
Refining Capacity (mmb/d)
North America

22.71

22.33

Latin America

6.5

5.98

Europe

14.27

15.68

CIS

4.0

8.16

Middle East

9.0

9.7

Africa

3.96

3.4

Asia-Pacific

35

34.75

Total

95.44

100.05

*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Crude oil prices hold their recent gains, staying rangebound with demand gradually improving as lockdown slowly ease
  • Worries that global oil supply would increase after June - when the OPEC+ supply deal eases and higher prices bring back some free-market production - kept prices in check
  • Russia has signalled that it intends to ease back immediately in line with the supply deal, but Saudi Arabia and its allies are pushing for the 9.7 mmb/d cut to be extended to end-2020, putting the two oil producers on another collision course that previously resulted in a price war
  • Morgan Stanley expects Brent prices to rise to US$40/b by 4Q 2020, but cautioned that a full recovery was only likely to materialise in 2021

End of Article

In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

May, 31 2020
North American crude oil prices are closely, but not perfectly, connected

selected North American crude oil prices

Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.

The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.

Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.

pricing locations of selected North American crudes

Source: U.S. Energy Information Administration

First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.

Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.

Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.

Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.

Principal contributor: Jesse Barnett

May, 28 2020
Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020