Easwaran Kanason

Co - founder of NrgEdge
Last Updated: May 9, 2020
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Business Trends
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Consensus estimates indicate that the full extent of the Covid-19 pandemic will wipe out at least 18.5 mmb/d of oil demand in 2020 alone. Some analysts have gone even further, suggesting that the number could go as high as 30 mmb/d. As supply reacts to demand, there is no doubt that producers must throttle back production to avoid a destructive oversupply that has already decimated crude oil prices. OPEC+’s new two-year supply deal promises to take 9.7 mmb/d off the market through June 2020, then declining gently. At its best, this will only account for half of the demand shortfall, leaving an excess of at least another 9 mmb/d. In the extraordinary OPEC+ and G20 meetings that surrounded the coordinated deal, it was stated that the free market producers – mainly the US, Canada, Brazil and Norway – would make up a further cut of 5 mmb/d through natural ‘market adjustments’. The question, then, is how?

For the OPEC nations, this is relatively easy. Most are oligarchies, controlled environments where difficult decisions can be implemented swiftly. In many cases, there is only a single firm controlling its vast oil wealth. Thus, Saudi Arabia, though it may have joint ventures with foreign firms, has full control over the entire Saudi crude oil production mechanism. The dictate to reduce production by 2.5 mmb/d is a (relatively) straight forward matter of recalibrating the Kingdom’s integrated production infrastructure. This applies to OPEC states as well, such as Kuwait, the UAE and Angola, where Kuwait Petroleum, ADNOC or Sonangol have tightly integrated crude production infrastructure where control of national output levels is centralised.

Even in countries within OPEC or OPEC+ where the industry is more competitive, this holds true. In Russia, Rosneft, Gazprom and Lukoil may all compete with each other, but they will not ignore an order from the Kremlin to reduce output proportionately in accordance to the supply deal. In OPEC countries such as Iran and Iraq, the small number of national producers makes collusion easier. This even applies in countries within OPEC+ where free market ideals hold more strongly. Petronas may not be able to dictate the output levels of PTTEP, Shell or ConocoPhillips’ Malaysian assets, but it owns enough control in key assets to influence the national output level. Ditto for Azerbaijan, Kazakhstan and Oman, even if the state oil firms there have extensive partnerships with supermajors such as BP, Chevron and Shell.

Adherence aside, it should be relatively easy for the OPEC+ club to meet their target of 9.7 mmb/d if the temptation to cheat doesn’t take hold. But what about the large free market producers? The pact between these countries and OPEC+ calls for the former to reduce production ‘naturally’ according to market pressure. That, again, is relatively easier for Norway and Brazil, where the reins of production are concentrated in the hands of Equinor and Petrobras. But what about the thorn in the oil industry’s side, the USA? There is no American state oil firm, and neither is there a federal body tasked to coordinate national output levels. It can happen on a state-level, like the Alberta state government in Canada or the Texas Railroad Commission – but players in these markets still cannot be compelled to follow through. The US oil industry is a matrix of many, many private players large, medium and small, each driven by a capitalist drive for profit, which is counter intuitive to controlling output.

So, in the absence of top-level control, each player in the US is left to their own devices to control their own output, in hope that each of its rivals will do the same to allow an optimal level of national output. A true expression of game theory. So what is going to happen?

Well, the first – and quickest – way to reduce output is to target onshore wells, particularly in the shale patch. This can happen voluntarily, or enforced through the growing number of bankruptcies. In North Dakota, where the shale revolution took root early, some 6200 wells have been shut, almost a third of all wells. Stopping wells temporarily is easy, but halting them forever is considerably tougher. So the question facing these producers is: which wells to shut, and for how long? For most, the target will be painted on newer wells, where the marginal cost to extract abundant oil is lower, essentially saving the crude for a better price. And running older, less productive wells, with the idea of closing those fully once the resources expire, rather than going through the expensive stop-and-restart process in newer wells. It is a strategy that supermajors ExxonMobil and Chevron have taken in the US shale patch, who announced that they would be slashing rigs in the prolific Permian Basin by 75% (to 15 sites) and 71% (to 5 sites) over 2020. Closures will be on the newer, more prolific wells – a testament to shale’s steep production drop-off curve and, as ExxonMobil put it, ‘better off deferring higher production rates into a period with better pricing.’ This strategy seems to be replicated across the American club of producers, from the giants to regional players such as Continental Resources. And once again, the American shale patch’s flexibility can run both ways, as easy as it is to close down an onshore shale rig (compared to a vast offshore rig), it is equally easy to restart them once market conditions change.

In April alone, estimates from the IEA show that the US, Canada and Brazil accounted for most of the month’s 2.2 mmb/d decline in production. That’s nearly half of what was requested of the free market oil producers. With the OPEC+ deal entering force in May and US oil prices in the doldrums, it would seem that there is enough political will and market pressure to enforce nearly 15 mmb/d of output cuts across the industry. That will go a long way to supporting prices in their current weak state. The hope is that this bitter pill won’t have to last long, and once demand improves and economies re-open, oil producers from across the spectrum will be able to return to business as usual. Or, at least, business as usual in the new normal.

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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