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Oil prices

  • Crude oil benchmarks had a poor week, dropping to two month lows to the mid-US$40s level, as traders fretted over a growing stockpile of oil globally, with the EIA reporting a smaller-than-expected decrease in US oil stockpiles. Not even falling US production could lift the market, as dips in US output were matched by increases in OPEC, mainly Iranian crude. 

Last week in Asian oil:

  • All eyes will be squarely on the South China Sea this week, as the United Nations Permanent Court of Arbitration rules on the legality of China’s claims – the so-called nine-dashed line that crosses over with territorial claims from Vietnam, Malaysia, Brunei and the Philippines, which initiated the arbitration. The ruling is expected to be unfavourable to China, with the country already pre-empting the decision by announcing it would ‘ignore the court’s judgement’. The ruling is expected July 12, and the quandary of oil rights in the resource-rich sea will drag on for longer.

  • Indian Oil’s refining chief, Sanjiy Singh, has warned that at the current rate of consumption growth, Indian may become a net importer of oil products in 15 years, even at the current planned rate of expansion. Strong growth will eat into the country’s current exports of products, unless Indian refiners push ahead with plans to increase capacity, such as the mammoth planned joint venture refinery between IOC, BPCL and HPCL. Indian Oil itself announced plans to spend US$6 billion over the next six years to boost refining capacity.

  • Indonesia’s Pertamina is aiming to build a strategic crude petroleum reserve of 25 million barrels within the next two years to ensure domestic energy security. Roughly 60% of the crude earmarked for the SPR will come from domestic production from private companies, and the remainder imported in. Expansions in oil product storage capacity are also planned, equivalent to 30 days of consumption.

  • BP finally signed off on its planned US8 billion expansion of the Tangguh LNG project in Indonesia, clearing the way for the third train to begin operations in 2020. The expansion will increase capacity at the West Papua site by 50%, to 11.4 million tons, all of which will be split between domestic power utility firm PLN and Japan’s Kansai Electric Power.

  • In a sign that Japan’s ambition to establish an LNG trading hub is gaining pace, the Jera Co joint venture between Tokyo Electric Power and Chubu Electric Power is reportedly on the verge of a second deal in as many months to resell LNG to a European client. Another deal, by Shizuoka Gas and Shell Eastern Trading, has been established to utilise the export capacity recently added to the Shimizu LNG terminal. 
  • Tokyo Gas is establishing a joint venture with PetroVietnam Gas to build an LNG plant and distribution pipelines to feed Vietnam’s rapidly growing appetite for natural gas-powered electricity.

  • Thailand’s PTTEP, the upstream arm of PTT, has signed an MoU with Oman Oil Company Exploration and Production (OOCEP) to collaborate on E&P projects in Oman, extending PTT’s presence in Omani upstream in line with its ambitions to expand overseas upstream production in lieu of declining Thai output.

Last week in the world oil:

  • ExxonMobil announced the discovery of a potentially giant oil field in Guyana, a new deepwater find in South America. The Liza-2 production test indicates a recoverable resource of between 800 million to 14 billion oil-equivalent barrels, in a reservoir structure similar to the already-operating Liza-1 field.

  • After a corruption scandal involving Petrobras’ monopoly over exploiting Brazil’s massive pre-salt oil deposits, a new bill advanced in Congress will potentially allow other companies to run projects in the pre-salt region, in hopes that it will revived stalled development in the region.

  • Chevron has given the go-ahead to a US$37 billion expansion of the Tengiz field in Kazakhstan, a giant field that currently represents 45% of total Kazakh production. The plan to expand output to 260 kb/d by 2022 is the industry’s largest investment since crude prices tumbled two years ago, a sign that oil giants are sensing that it is safe to start spending again.

  • The US oil rig count jumped again last week, rising by 10 to a total of 351, a proxy for increasing activity in the sector. All the increases last week, and over the last few months, have been from onshore rigs, with offshore rigs remaining static at 19. Gas rigs fell by one to 88.

  • The persistent glut of gasoline supplies in the US is having two effects on the wider market – first, driving crude prices lower and second, slashing American refining margins, which is likely to push oil majors further away from downstream into the recovering embrace of upstream.

  • Iran is exploring the possibility of opening an oil refinery in Bulgaria, as part of a plan to expand the country’s trade with the East European nation. If the project goes ahead, it would challenge Bulgaria’s sole refinery, Lukoil’s Neftochim Burgas site, currently the largest refining site in southeastern Europe.

  • ExxonMobil and Qatar Petroleum are teaming up to purchase energy assets in Mozambique, home to some of the largest natural gas discoveries in the last decade. On the target list for the collaborators are gas fields owned by Anadarko and Eni, in the bountiful Rovuma Basin.

  • Total named Philippe Sauquet, former head of its refining and chemicals division, as boss of its new gas, renewables and power unit, a sign that the French company is getting serious about expanding its ambitions in clean energy.

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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