Easwaran Kanason

Co - founder of NrgEdge
Last Updated: May 16, 2020
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Business Trends

Qatar, in size, is only 0.5% the land/ocean mass of Saudi Arabia. Yet, despite its size, it punches well above its weight in the international arena, just like its neighbour. Most of this is down to one thing: liquefied natural gas. Qatar is the world’s leading LNG producer and exporter in the world, and that vast wealth has fuelled the dramatic transformation of its economy since 1996 when the first shipment of Qatari LNG set sail for Japan.

But uneasy lies the crown. There are usurpers to the throne. Australia, after over a decade of overstuffed budgets and overextended deadlines, is hot on Qatar’s heels. In some months of 2019, Australian LNG production and exports actually exceeded Qatar’s. And coming up both Australia and Qatar’s back rapidly is the US. The shale revolution not only transformed US oil industry; it did the same for the US natural gas industry as well. The abundance of onshore natural gas liquids has fuelled an LNG export boom in the US, with some two dozen projects in various states of completion and development. In 2019, the US accounted for more than half of new liquefaction capacity added worldwide. In the same year, the US leapfrogged Malaysia as the third largest LNG exporter in the world, and by 2025, its LNG production capacity could reach almost 15 bcf/d – eclipsing both Qatar and Australia.

The competition may be heating up, but that will not diminish Qatar’s importance. With its recent moves to tap into the vast natural gas resources in its offshore North Field and securing infrastructure though new deals for LNG ships, Qatar is prepared to defend its market share, which props up its riches. It is, after all, the Saudi Arabia of the gas world.

However, the similarities end there. While Saudi Arabia is the largest swing oil producer and the de facto leader of the OPEC and OPEC+ oil clubs, no such co-operation platform exists for natural gas/LNG. There have been attempts in the past to create one, but they have all failed. Which means that while market control and supply deals will always be an option in the oil world, the natural gas/LNG world is a cut throat business. Producers compete by offering long-term contracts for 10 or more years, locking buyers into a fixed sales cycle. Qatar was a great benefactor of this, sealing ultra-long deals with key buyers in Japan and South Korea over the 90s and 2000s, tying the price of LNG to crude oil…. a mechanism that sent its revenues into the stratosphere when crude prices breached the US$100/b level in 2011.

That advantage is disappearing from Qatar, as the riches its reaped attracted a whole new generation of LNG producers – from Mozambique to Mexico. These additional supplies shifted the LNG world from a seller’s market to a buyer’s one. When Shell completed its Prelude project (though it was massively delayed) and Inpex finished its Ichthys site, Australia became a true rival to Qatar, with the US waiting in the wings. The abundance of new suppliers has had loyal old clients pressing for more flexibility in LNG contracts, with Japan leading the fray by demanding renegotiation of contractual terms as the world’s largest buyer. The entrance of US LNG exporters has also changed the nature of the game, shifting LNG buying from ultra-long contracts to shorter-term ones in the 2-5 year range, as well as offering a more liquid spot market.

That would be have been fine, as global LNG demand was growing rapidly, fuelled by China and India. A rising tide lifts all. But then the Covid-19 pandemic occurred. And just as it has done for oil, the pandemic shifted the LNG market from oversupply to supply glut. With very little visibility on the timeframe for improvement, global natural gas/LNG prices have more than halved. Qatar is especially vulnerable to this development, since many of its ultra-long contracts are near expiry. If this was OPEC, it could convince its fellow exporters to curb output to support prices. But there is no OGEC. And Qatar,  the vulnerable LNG king,  has only two options: voluntarily curb its output to prevent the glut from getting greate or initiate a battle for market share by lowering prices. Sound familiar? That’s exactly what Saudi Arabia and Russia did in March, destroying confidence in the crude market and briefly sending WTI prices into negative territory. There is a legitimate worry that this could happen in LNG as well.

Caught between and rock and a hard place, Qatar’s next move will determine the immediate future of LNG. It already has some of the world’s cheapest LNG production, but even it will not be immune from low prices if it decides to push for market share. Sure, initiating a price war could wipe up the US’ developing LNG export industry, but just as we saw with shale oil in 2014 and even today, the US shale patch will always bounce back through flexible entrepreneurship. It will likely have to throttle output. But that risks rivals overtaking it sooner than expected, and its vast North Field Expansion project is already underway, increasing its LNG capacity by 45% by 2025. At stake is not just Qatar’s grip on the throne, but the entire global LNG complex. Hot gas brings hot rewards, but is intensely flammable as well.

Statistics: World’s Largest LNG Producers (2019)

  • Qatar
  • Australia
  • USA
  • Malaysia
  • Nigeria

Market Outlook:

  • Crude price trading range: Brent – US$30-33/b, WTI – US$26-28/b
  • Saudi Arabia to slash production by an additional 1 mmb/d after talks with US
  • IEA report suggest the ‘beginning of a fragile recovery’
  • Reports from the US suggest shale producers are restarting rigs, as prices near US$30/b


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)

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



Latin America









Middle East












*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