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Last Updated: January 10, 2020
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Headline crude prices for the week beginning 6 January 2020 – Brent: US$70/b; WTI: US$64/b

  • As tensions in the Middle East spill over into violent escalation, crude oil prices spiked as the US initiated the assassination of one of Iran’s most powerful general, incurring the wrath of both Iran and Iraq, where the fateful drone strike took place
  • The death of Qaseem Soleimani was called a ‘major strike against Iran’ and ‘bigger than (the death of) bin Laden’; Iran has vowed revenge and withdrew from its nuclear deal commitments, while Iraq has voted to expel all American military in retaliation
  • In response, Iran initiated missile strikes against US military bases in northern Iraq – and may have downed an Ukrainian commercial plane in the process – but both the US and Iran have walked back from the brink, providing some calm to the market
  • However, tensions will still be high and any spark could result in all-out war, which may not just affect Iran but also Iraq and its output of some 4 mmb/d; Chevron has already evacuated its workers from the Kurdistan Region of Iraq, which is near the strike zones targeted by Iran
  • The US active rig count fell below 800 sites once again, wiping out two weeks of gains, with the loss of 9 rigs (7 oil, 2 gas) that coincided with a period of weakness in US oil prices
  • After the volley of attacks that drove prices higher, the risk of imminent war between the US and Iran has receded (slightly), causing crude prices to fall back as well; global crude benchmarks have now returned to their previous ranges, with Brent at US$64-66/b and WTI at US$59-61/b

Headlines of the week

Upstream

  • The first three crude oil cargoes from Guyana have been snapped up by Shell, which won the rights to market the Liza crude cargoes through a government auction, with the first cargo expected to be lifted in February
  • While ExxonMobil and Hess reap the rewards from Guyana, others exploring in the area have not been so lucky; Tullow Oil and Repsol announced that they would plug and abandon the Carapa-1 well in the Kanuku license after encountering less crude oil flow than expected
  • ExxonMobil has secured a significant amount of new acreage in Egypt, with over 1.7 million offshore acres acquired, including the 1.2 million-acre North Marakia block in the Herodotus Basin and the North East El Amriya block in the Nile Delta; ExxonMobil will hold 100% interest in both blocks
  • The latest UK offshore licensing round attracted 104 applications for 245 blocks or part-blocks from 71 companies, focusing on acreage near and around the main producing areas of the UK Continental Shelf
  • Petronas continues to dip its toes into South America, acquiring 50% of the Tartaruga Verde producing field and Module III of the Espadarte field from Petrobras, to go along with the 3 Brazilian exploration blocks it won recently
  • Chevron and PDVSA’s joint venture Petropiar facility will once again produce Hamaca-grade synthetic crude for export after the crude upgrader site was forced to switch to blending heavier Merey crude since July 2019
  • Iraq has resumed production at the Nasiriya oil field after output was halted by domestic protests over government corruption, although operations at the Nasiriya oil refinery remained curtailed after protestors blocked plant access

Midstream/Downstream

  • The government of Curacao has ended its contract with PDVSA to operate the 335,000 b/d Isla refinery at the end of 2019, despite both parties reaching an earlier deal to extend PDVSA’s operatorship by a year
  • After six months of trial runs, Hengyi Petrochemicals’ 160,000 b/d Pulau Muara Besar refinery in Brunei has reached full commercial production, running at near 100% utilisation rates, with much of its LPG exported to the Philippines, gasoline to Indonesia and other fuels, that will add an additional 5.7 bcm of gas and 700,000 tons of condensate ad across the region
  • Zhejiang Petroleum & Chemical has started up the remaining units at its Zhoushan refinery, which began initial production in May 2019, which will double crude processing capacity to 400,000 b/d and add a 1 mtpa ethylene unit
  • China Sinochem expects to start up a new 60,000 b/d crude processing unit at its Quanzhou refinery in Fujian in mid-2020, alongside a new petrochemicals plant fed by a naphtha cracker with capacity for 1 million tpa of ethylene

Natural Gas/LNG

  • Natural gas has begun to flow from the Leviathan field in Israel, some 10 years after the field was discovered and 3 years after development was sanctioned; Leviathan will be producing at some 1.2 bcf/d during its first project phase
  • The leaders of Cyprus, Greece and Israel have officially signed the accord to begin work on the Eastern Mediterranean gas pipeline, with the 1900 km link connecting gas fields in the East Mediterranean to Europe through Greece
  • Novatek has brought first gas online from its North Russkoye field in West Siberia’s Yamal-Nenet that will yield an additional 5.7 bcm of gas and 700,000 tons of condensate, as the first launch of the North Russkiy block of fields – which include the Dorogovskoye, East Tazovskoye and Kharbeyskoye fields

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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

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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