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Market Watch

Headline crude prices for the week beginning 28 January 2019 – Brent: US$61/b; WTI: US$53/b

  • Oil prices continue to tread water in a tight range, with the market weighing the effectiveness of OPEC’s new supply deal with the looming spectre of growing American shale output
  • In an effort to shore up prices and prove its commitment, Saudi Arabia said it would reduce its oil output again in February and pump oil ‘well below’ its production limit for six months; January output was 10.2 mmb/d while February output is likely to be 10.1 mmb/d
  • The pledge comes as Saudi Arabia and Russia called off talks at the World Economic Forum in Davos, spurring rumours of a growing rift between the two oil giants
  • On the Iranian front, the EU is looking at ways of circumventing American sanctions on Iranian crude while Japanese refiners loaded their first Iranian crude cargo since October, following the footsteps of China, India, Turkey and South Korea
  • In another front opening on the American trade warpath, new US sanctions on Venezuelan crude look set to hurt American Gulf refiners – who depend on heavy crude from PDVSA – to the benefit of China and India
  • After a sharp drop the previous week, the active American drill count bounced back, gaining 10 oil rigs while losing one gas rig for a net gain of 9 sites to 1,059.
  • Crude price outlook: Crude oil will continue to hover in their present levels – Brent at US$60-62/b and WTI at US$52-54/b – with little on the horizon that could shake the benchmarks out of their current entrenched ranges

Headlines of the week


  • Eni has started up production at a new well in the Vandumbu field offshore Angola, with the VAN-102 well achieving initial performance of 13,000 b/d; coupled with the recent start-up of the Mpungi field, Eni’s Block 15/06 should reach a new production level of some 170,000 boe/d
  • Even as Saudi Aramco plans to embark on an IPO and the Kingdom open up to foreign investment, Saudi Arabia will keep exclusive rights to develop its vast oil reserves with Aramco, with no plans to chip away as its monopoly
  • Total is looking to take FID on its Ikike and deepwater Preowei oil projects in Nigeria in the first half of 2019, bringing onstream assets with projected output of 60,000 b/d and 70,000 b/d respectively
  • Turkey’s Genel Energy has acquired stakes in the Sarta and Qara Dagh blocks in the Kurdistan region of Iraq, with Chevron retaining operating stakes
  • Ineos remains committed to developing a solution for the challenging high-pressure, high-temperature Hejre oil and gas field in the Danish North Sea
  • BHP has struck oil at the deepwater Trion field in the Gulf of Mexico, after becoming the first non-Pemex deepwater driller in the country last year
  • Chevron has sold its 51.74% stake in Brazil’s Frade field in the offshore Ceara basin to independent PetroRio for an undisclosed amount

Midstream & Downstream

  • The port of Fujairah in the UAE has joined other major ports like Shanghai and Singapore in banning open-loop scrubbers, forcing ships in the East of Suez to comply with IMO’s new 2020 regulations requiring ships to burn fuels with a sulfur content of less than 500ppm, down from 3500ppm
  • President Donald Trump’s administration is taking steps to limit the ability of American states to block interstate oil and gas pipeline, targeted at boosting limited pipeline capacity in the US Northeast
  • Tallgrass Energy Partners and Kinder Morgan have agreed to expand transport capacity from Wyoming and Colorado to Cushing, combining the Pony Express, Wyoming Interstate and Cheyenne Plains Gas pipelines to boost delivery to 800,000 b/d of light crude and 150,000 b/d of heavy crude
  • ExxonMobil has joined forces with Plains All American Pipeline and Lotus Midstream in a 1 mmb/d crude pipeline project meant to deliver Permian shale crude to Houston by 2021
  • Citgo has idled its small gasoline producing unit at the 157,500 bd Corpus Christi refinery, in a sign of a growing global gasoline glut

Natural Gas/LNG

  • Saudi Aramco has announced its intention to spend ‘billions of dollars’ to acquire natural gas assets in the US in its ambitions to diversify away from crude to become a global natural gas/LNG player
  • Lithuania’s Klaipeda LNG terminal will double its LNG capacity by 2021 when pipelines to Poland and Finland are completed, delivering Norwegian gas to the Baltic countries in an effort to reduce Russia’s dominance over gas supplies
  • CNOOC and Total have announced a new natural gas discovery in the Glengorm prospect in the UK Central North Sea; at 250 million boe of recoverable resources, it is the largest UK gas find in more than a decade
  • Shell’s Kitimat LNG project in Canada’s British Columbia is gaining steam, with contracts and subcontracts worth almost US$1 billion already handed out
  • Anadarko and PTTEP will take FID on the Mozambique Area 1 natural gas project in the Rovuma basin in 1H2019, targeting eventual LNG production

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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

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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