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Last Updated: April 24, 2020
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Headline crude prices for the week beginning 20 April 2020 – Brent: US$26/b; WTI: -US$4/b

  • This week has been a wild ride for crude oil prices, exposing the intricate nature of futures contracts and highlighting technicalities in trading that could, bizarrely, cause crude oil prices – or any futures contracts – to turn negative
  • That is exactly what happened with WTI at the start of the week, where pessimism over steep demand declines that would not be offset by OPEC+’s new landmark supply deal, drove front-month prices into the red
  • The action was focused on the expiring contract for May delivery, with traders scrambling to offload contracts to avoid having to receive the oil physically amid a severe shortage of onshore storage space; at one point, the May contract plunged as low as -US$37/b, but recovered to -USS4/b
  • With the expiry of the May WTI contract, the US crude benchmark has returned to a more normal level; while the May contract was active, the June contract was trading in the US$20/b range and with the expiry of the May contract, the June contract remains firmly in the black as traders still have time to ascertain the situation until storage becomes an issue once again on 20 May
  • WTI prices still remain weak, trading at US$17/b since the changeover, with Brent also falling below the US$20/b level to a 22-year low, but has since recovered slightly to some US$22/b
  • Although the new OPEC+ supply deal only kicks in on May 1, Kuwait has already started reducing its crude oil supply to the new quota levels; Saudi Arabia, however, is reportedly still pumping at full volume, loading a large amount of cargoes to the US Gulf that exacerbated the WTI price meltdown
  • Within OPEC+, Saudi Arabia and Russia are also hinting at further output cuts; unlike the market-based players like the US, Canada, Brazil and Norway – where the expected production cuts will come ‘automatically’ from market conditions – the OPEC+ group must coordinate any new supply restrictions
  • Russia will be distributing its 2.5 mmb/d cut proportionally across its oil companies, with Rosneft taking up 40% of the total reduction
  • OPEC announced that it expects global demand for OPEC crude to fall to its lowest level in three decades over Q2 2020, at just under 20 mmb/d, or roughly half of its normal production levels
  • Meanwhile, the Covid-19 pandemic is hitting projects in development; hundreds of workers at Novatek’s Arctic LNG 2 export project in Russia have tested positive, while work at Total’s Afungi LNG site in Mozambique’s Cabo Delgado was halted and closed off as two-thirds of the country’s confirmed Covid-19 cases were detected at the site
  • Amid the catastrophic price environment for US crude, the active rig count fell by another 73 rigs (66 oil, 7 gas) to 529 sites, its lowest level since July 2016
  • In the aftermath of the WTI price meltdown, oil prices have recovered somewhat but still remain weak, although traders also seem confident that market forces will trigger faster-than-expected declines in output; with that, Brent should be trading in the US$20-22/b range, with WTI recovering to the US$15-17/b range


Headlines of the week

Upstream

  • Petrobras has begun hibernating 62 of its platforms operating in offshore shallow water fields in Brazil, affecting the Campos, Sergipe, Potiguar and Ceara basins, and collectively removing some 23,000 b/d of crude output
  • In addition to Petrobras, Equinor is also halting production at its Peregrino field in Brazil’s Campos basin, though this seems to be linked to safety issues
  • Shell and ExxonMobil have halted output at two offshore assets in the US Gulf of Mexico – the 100,000 b/d Perdido hub and the Hoover platform – following the discovery of a leak on the Hoover Offshore Oil Pipeline System (HOOPS) that connects the fields to the Quintana Terminal in Freeport, Texas
  • More details have emerged from the US government’s negotiations to rent out storage capacity in the federal Strategic Petroleum Reserve, with nine companies in the running to rent an initial 23 million barrels of space
  • Oklahoma is formerly contemplating implementing crude output curbs, joining Texas as the state claims its crude is ‘wasted at current prices’
  • Shell has lifted force majeure on exports of Forcados crude in Nigeria as the Trans Forcados pipeline was re-opened after a two-week shutdown, the second time in a year that the pipeline’s closure has affected Forcados exports
  • ExxonMobil is conducting field trials of 8 new methane detection technologies – including satellite and aerial surveillance monitoring – at some 1000 sites in Texas in an attempt to reduce methane emissions
  • TC Energy’s Keystone XL oil pipeline connecting Canada to the US has hit yet another setback as a US court rules against a permit to allow the pipeline to cross bodies of water in the US without sufficient environmental review

Midstream/Downstream

  • Refineries and petchem plants worldwide – from Russia to the US – have recalibrated their operations to switch away from conventional production to focus on producing raw materials for critical Personal Protective Equipment (PPE) like sanitisers, antiseptics, medical masks and gowns
  • Shell has restarted its heavy oil hydrocracker at the 211,270 b/d Convent refinery in Louisiana after several days of outage following a malfunction

Natural Gas/LNG

  • Qatar Petroleum has begun its drilling campaign at the giant offshore North Field East gas project, spudding the first of 80 planned wells that is expected to boost Qatar’s LNG capacity from 77 mtpa to 110 mtpa
  • BP has signed an agreement with China’s Foran Energy to supply some 600,000 tons per annum of LNG to the industrial Guangdong province
  • Canada’s Pieridae has delayed FID on the Goldboro LNG export project in Nova Scotia to an unspecified period beyond the initial date of 30 September
  • Israel’s Energean Oil and Gas has increased estimated recoverable reserves at its Karish North field by 32% to some 1.2 tcf of gas and 39 mmboe of liquids
  • Russia’s Parliament has passed amendments to the country’s Law on Gas Exports that would ease restrictions on LNG exports that could encourage the development of more LNG exporters and export projects
  • ADNOC has cancelled two EPC contracts awarded to Petrofac related to its giant Dalma Gas Development Project in an apparent attempt to reduce spending against the backdrop of the Covid-19 pandemic
  • Singapore’s LNG-9 has reportedly withdrawn from a planned acquisition of Australia’s LNG Ltd, which is planning the Magnolia LNG project in Louisiana

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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