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Last Updated: April 17, 2020
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Headline crude prices for the week beginning 13 April 2020 – Brent: US$31/b; WTI: US$22/b

  • In the face of a landmark OPEC+ deal to slash production by nearly 10 million barrels a day, crude oil prices did not stage a recovery, but instead lost ground as the size of the supply deal failed to impress a market concerned about the scale of demand destruction from the Covid-19 pandemic
  • Despite a last-minute threat by Mexico to scupper the deal, the OPEC+ club agreed to cut 9.7 mmb/d of output through June 2020; an additional 5 mmb/d of cuts would come as an ‘automatic’ process of low crude prices for non-OPEC+ countries including the US, Norway, Canada and Brazil, but this still pales in comparison to a fall of 18.5 mmb/d of oil demand expected for the year
  • The unprecedented situation has led to a curious situation of many free-market economics supporting supply controls, as the G20 group of countries met virtually to support the OPEC+ deal; the US even offered to ‘pick up some of Mexico’s slack’ to save the OPEC+ deal
  • Adherence to the OPEC+ supply deal, which will last for two years until June 2022, is also up in the air; there is already evidence that both Saudi Arabia and Russia are still pumping oil at full volume in a bid to secure market share before the new deal kicks in May 1
  • However large the deal, it failed to impress the trading market; at a minimum, oil demand is expected to decline by 18.5 mmb/d in 2020, with some models predicting a loss of up to 35 mmb/d in a worst-case scenario, which would leave a huge oversupply in the market
  • While countries and companies are scrambling to fill up reserves and infrastructure – from train cars to pipelines to cargo ships – with spare crude, this will not be enough to absorb the huge amount of excess oil expected
  • Dynamics have also widened the spread between the two global oil benchmarks, with WTI sinking to a near-US$10/b discount to Brent as shale producers are caught in an existential crisis of continuing to pump or ceasing to exist
  • The depressed price environment is still wreaking havoc with the US rig count, which lost another 62 sites (58 oil, 4 gas) to sink to a 3-year low of 602 active sites according to Baker Hughes
  • After OPEC+ did all it could to enforce a new supply deal, crude oil prices are still reeling from the Covid-19 pandemic and the damage done by the Saudi-Russia oil price war; expect crude oil prices to remain soft, with Brent in the US$28-30/b range and WTI at US$24-26/b


Headlines of the week

Upstream

  • The US Department of Energy will made 77 million barrels of storage space in the federal Strategic Petroleum Reserve available to US producers in two tranches of 30 million barrels and 47 million barrels, respectively
  • Total has divested some US$400 million of non-core assets from its portfolio, with the main upstream portion being the sale of its Brunei E&P subsidiary (and 86.95% interest in Block CA1) to Shell
  • India is looking to purchase 15 million barrels of crude to fill up its three strategic reserves to take advantage of low prices, aiming at 5.5 million barrels of the UAE’s Upper Zakum grade for Mangalore, 9.2 million barrels of Saudi grades for Padur, and Iraqi Basrah Light grades for Visakhapatnam
  • Despite the global oil route and countries racing the cut production, Pemex is going to opposite route, continuing on its path to double drilling to 423 wells in 2020 and accelerate development of 15 recent upstream developments
  • Equinor has announced a new oil discovery in the US Gulf of Mexico, with the Monument well striking ‘good’ flows of crude oil
  • Wintershall DEA has made a new oil discovery at Well 6406/3-110 in the Bergknapp prospect’s Garn and Tilje formations in the Norwegian Sea
  • The Covid-19 devastation of global oil demand has forced the Middle East’s largest crude terminal in Fujairah to stop accepting storage requests by traders and refiners, having reached its capacity ceiling of 14 million barrels
  • INEOS will postpone planned summer shutdown for the UK’s Forties Pipeline system to spring 2021 in response to the ongoing Covid-19 lockdown
  • Norway has approved plans to build the Hywind Tampen floating wind farm that will power five oil and gas production platforms in the North Sea, with 11 wind turbines supporting the Snorre A and B, and Gullfaks A, B and C sites
  • Saudi Arabia has delayed the kick-off to develop its US$10 billion offshore Zuluf field until 2H 2020 amid major uncertainty in the industry

Midstream/Downstream

  • Nigeria’s NNPC will shut down its entire refining infrastructure in the country, in a bid to complete a comprehensive upgrade plan while avoid haemorrhaging money from the current low crude and refined price environment
  • As part of Total’s US$400 million non-core asset divestment, the French supermajor has sold its fuels import, distribution and marketing businesses in Liberia and Sierra Leone to Conex Oil & Gas, including 63 service stations
  • Marathon Petroleum has idled its 26,000 b/d refinery in Gallup, New Mexico – becoming the second North American refinery to shut down amid the pandemic
  • The Belarus-Russia oil supply spat seems to be ending, with Russian pipeline operator Transneft resuming supplies of Russian crude to Belarusian refineries

Natural Gas/LNG

  • Total has chartered its first LNG-powered VLCCs, while each of the two vessels owned by Malaysia’s AET aiming to enter service in 2022; the LNG for the vessels will be provided by Total’s own marine bunkering fuels arm
  • BP has declared force majeure on receiving the Gimi 2.5 million tpa FLNG facility from Golar LNG in 2022, after delaying its Greater Tortue Ahmeyim LNG project offshore Mauritania and Senegal
  • SDX has announced a new commercial gas discovery at its Sobhi well in Egypt, with some 24 bcf of recoverable gas and condensate that is expected to be tied back to the Yunus-1X pipeline tied back to the South Disouq processing facility

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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