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Last Updated: July 4, 2019
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Market Watch 

Headline crude prices for the week beginning 1 July 2019 – Brent: US$66/b; WTI: US$59/b

  • As the members of OPEC and the wider OPEC+ group sat down in Vienna for a delayed meeting, oil prices surged to a five-week high on optimism that a supply deal would be reached and positive developments out of the G20 Summit
  • OPEC+ was widely expected to extend the current supply deal to the end of 2019, but there was optimism that more could be expected; OPEC delivered by agreeing to extend the production cuts to March 2020
  • At the recently concluded G20 Summit in Osaka, all eyes were on US and China interactions, with President Donald Trump and Premier Xi Jinping agreeing to restart trade talks that could end a period of uncertainty of the global economy
  • Reaction to the events was mixed; the extension of the supply deal was widely expected, and the additional three months was not enough to shake up the status quo, while the US-China thaw was a mere truce but held no promise of a concrete deal being reached
  • US drillers snapped a declining streak, adding four oil rigs but dropping four gas rigs to leave the active US rig count unchanged at 967, 80 sites down from the count a year ago
  • After initial optimism, the extent of the OPEC+ supply deal extension is unlikely to be comprehensive enough to please the market and we expect crude prices will pare back gains to trade US$63-65/b for Brent and US$56-58 for WTI


Headlines of the week

Upstream

  • The Kenya government has officially signed an agreement with Tullow Oil, Total and Africa Oil Corp for a 60-80 kb/d crude oil processing facility to cover crude discoveries in Blocks 10BB and 3T in the Lokichar Basin
  • ExxonMobil is reportedly looking to put its Norwegian upstream portfolio up for sale, covering some 150,000 boe/d of production, following in the footsteps of other American firms pulling back from the North Sea
  • South Africa is working on a new oil and gas policy to clearly define regulation for oil and gas resources in light of Total’s massive Brulpadda discovery

Midstream/Downstream

  • Saudi Aramco has announced plans to spend US$6 billion to build additional petrochemical capabilities at its South Korean refining joint venture with S-Oil, adding a steam cracker and olefins unit to the 669 kb/d site by 2024
  • Philadelphia Energy Solutions has confirmed that it will shut down its 335 kb/d US refinery that was crippled by a massive fire last month
  • Chevron Phillips Chemical and Qatar Petroleum have signed an agreement to build a 1.9 mtpa ethane cracker and two polyethylene units at the Ras Laffan Industrial City complex in Qatar
  • Vitol has started construction of a 30 kb/d small oil refinery at its Malaysian storage terminal in Tanjung Bin aimed at providing low-sulfur fuel oil for ships
  • Petronas Chemicals has announced plans to invest US$6 billion over the next 20 years to expand its specialty chemicals portfolio, primarily through acquisitions like its US$186 million takeover of the Da Vinci Group in May
  • In synergy with ExxonMobil’s planned expansion of its Singapore refining complex, industrial gas player Linde is spending US$1.4 billion to expand its facilities to supply hydrogen and synthesis gas to the ExxonMobil site
  • Turkmenistan has inaugurated the world’s first gas-to-gasoline plant in Ashgabat, with the capacity for 15,500 b/d of gasoline from natural gas
  • Petrobras has reaffirmed its intent to depart completely from fuels distribution in Brazil, aiming to sell off at least one of its 8 refineries this year and strike a deal for its LPG unit as soon as August

Natural Gas/LNG

  • BP’s gas marketing arm has signed an LNG sales and purchase agreement with Woodfibre LNG in Canada’s British Columbia, taking on 750,000 tons per annum of LNG over 15 years beginning 2024
  • Cheniere has produced first LNG from its Corpus Christi Train 2 site in Texas
  • Kufpec, the international upstream arm of Kuwait Petroleum Corp, is aiming to boost production from its gas assets in Canada and Australia, targeting a boost at its Canadian shale gas to 20,000 boe/d by end-2019 and gaining right to three new gas blocks in Australia where currently production is almost 40,000 boe/d
  • Australia’s Evol LNG has agreed to supply LNG to the Adaman Resources’ Western Australian Kirkalocka Gold mine beginning September 2019
  • American liquefaction player Venture Global has raised an additional US$675 million to fund the ongoing development of its 20 mtpa Plaquemines LNG export terminal in Louisiana
  • Sempra LNG has applied for permission to expand its Port Arthur LNG plant with two additional trains (Train 3 and Train 4) that would double production capacity to 27 million tons per annum

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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