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Last week in world oil


-International crude prices started the year off a bit weaker than in its ended in December, with prices hovering around the US$52-53/b on the New Year, as the US dollar rallied to its highest levels against major currencies since 2002. January is when OPEC members are expected to make major cuts to their collective supply, and the oil markets will be hoping that the quotas will stick to lift prices.

Upstream & Midstream

-BP and Azerbaijans Socar have agreed to terms governing the developing of the giant Azeri-Chirag-Gunashi (ACG) field in the Caspian Sea through 2050. BP is the lead in the AIOC consortium that comprises international presence in ACG, with other partners being Chevron, Inpex, Statoil, Itochu, ONGC Videsh and ExxonMobil. The super-giant ACG currently produces 620 kb/d of oil equivalent, beginning in 1997 with estimated recoverable reserves of 5-6 billion, with more gas reserves yet untapped.

-Peruvian President Pedro Pablo Kuczynski is threatening to terminate the US$5 billion Southern Peruvian Natural Gas Pipeline if evidence of bribery surfaced. News that Brazilian builder Odebrecht had admitted to bribing officials in Peru from 2005 to 2014 triggered the investigation, with some US$29 million allegedly distributed to gain access to Peruvian energy projects. Under the graft investigation, Odebrecht is required to divest its 55% stake inproject, with Brookfield Asset Management a likely buyer. Chinas CNPC has also been named as a possible contender.

-The US rig count might have ended just under the year-end rig count for 2015, but it is up significantly since mid-2016, with signs that the count will improve further over the first half of 2017. The final week of 2016 saw only 2 new rigs being added both oil during the quietest period of the year, bringing the total to 525, just under 536 on December 30, 2015. Since May 2016, American drillers have started/restarted over 209 oil and gas rigs domestically as prices improved over the second half of 2016.


-After being idled in 2012 by Valero, the 225 kb/d refinery in Aruba will be restarted in 2017. The process will take over 18 months, with Citgo appointing a consortium of Frances Technip, Venezuelas Tecnoconsult and Y&V Group to refurbish the site in a US$700 million project. The would give Venezuelas PDVSA a continued presence in the Caribbean through its US subsidiaryCitgo,after the Curacao refinery now appears to be in Chinese hands.

Natural Gas & LNG

-Malaysias Petronas is aiming to move ahead with its US$27 billion LNG project in western Canada by identifying a new site that would reduce cost and quell local opposition, which had dogged the Pacific Northwest LNG project previously. The processing site will remain on Lelu Island, but the docking facilities moved to theneighbouringRidley Island, eliminating the need for an expensive suspension bridge that was part of the original plan that cut through an environmentally sensitive area.

Last week in Asian oil:

Upstream & Midstream

-Iran has named 29 companies from over a dozen countries that will be allowed to bid for oil and gas projects under its new Iran Petroleum Contract (IPC) model. Though not exhaustive, the pre-qualification list includes Shell, Total, Eni, Petronas,Gazpromand Lukoil, but not BP, which opted out of participating out of fears of renewed American hostility when Donald Trump enters the White House.

-In a move that acknowledges that domestic Chinese upstream production is hitting a wall,Petrochinawill slash capital spending at the Daqing field the countrys largest by 20% in 2017. The aim is to now keep output steady instead of boosting production, keeping output steady at 40 million tons of oil and gas by 2019, in line with 2015 figures.

Downstream & Shipping

-Australian grocery retailer Woolsworth is selling its national fuel station network to BP for A$1.8 billion, claiming that it didnt understand the fuel business. The deal marks BPs second major foray back into downstream in the last two months, after agreeing to partner with Reliance in India.Woolworthsfuel stations are currently being supplied by CaltexAustralia,and will be transitioned to be part of the BP network gradually.

-Chinas Sinopec has begun supplying Beijing Six grade gasoline and diesel to the capital, as the city battles the persistent smog that blankets Beijing. Beijing Six is a stricter standard than even the National Five (equivalent to Euro V) that will be rolled out across China over 2017, with the same 10ppmsulphurlimit and a lower nitrogen oxide and olefins spec. All 562 of Sinopec fuel stations in Beijing will sell the new standard, supplied mainly by SinopecsCangzhou, Yangshan and Qilu refineries.

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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