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Headline crude prices for the week beginning 2 April 2017 – Brent: US$67/b; WTI: US$63/b

  • After the Easter break, oil prices started the week on a weaker note as geopolitical development exacerbated operational concerns.
  • Chatter in the market suggests that Saudi Arabia will be cutting the price for the crude grades it sells to Asia, sparking off speculation that Aramco will aiming to recapture lost market share and signalling an end to the production freeze.
  • Russian crude output also rose in March, from 10.95 mmbpd to 10,97 mmbpd, in spite of the OPEC/NOPEC supply cut agreement still in place.
  • The trade spat between the US and China has also been escalating, with China replying with tariffs on some US$50 billions of US imports after the White House announced more tariffs on Chinese products last week; the potential trade war has been rattling financial markets, especially in Asia.
  • Bahrain’s announcement that it has made its largest oil discovery in decades also caused traders to take stock of the major upstream projects in the pipeline that will raise supply in the long run.
  • With US crude production still rising and crude inventories also building, the host of bearish factors is likely to weigh on traders’ minds; however, the API reported that overall crude inventories declined by 3.28 million barrels last week, which has lifted prices slightly.
  • Despite their numbers, Russia and Saudi Arabia say they will set up a joint mechanism to govern OPEC and NOPEC cooperation will be set up by the end of the year, with talk at an energy conference in Baghdad suggesting that the supply freeze may have to be extended, instead of cut short.
  • The active US rig count unexpectedly declined by 2 last week, with a 7 site drop in oil rigs, bringing the overall total to 979 sites.
  • Crude price outlook: Although concerns over geopolitical and trade spats will cap gains, a more optimistic sentiment this week should see Brent trade at US$68/b and WTI at US$64/b. The new Shanghai crude contract will be in line with WTI prices.


Headlines of the week

Upstream

  • The new Shanghai crude futures contract is attaining benchmark status faster than expected, as Unipec – Sinopec’s trading arm – inked a one-year deal to purchase Middle Eastern crude from a ‘western oil major’ based on the Shanghai crude contract, displacing the Dubai and Oman markers.
  • Just as its fuel retail business is attracting foreign investment, almost half of 35 shallow water blocks offered by Mexico have been awarded, with European majors like Total, Eni and Repsol being the major winners.
  • Repsol has officially declared force majeure over the US$2 billion Ca Rong Do development, as Vietnam capitulates to Chinese pressure.
  • Reliance’s exit from US shale plays continues as its sold shale assets to Sundance Energy for US$100 million, including some Eagle Ford sites.
  • ExxonMobil emerged with eight blocks from Brazil’s recent offshore block auction – either alone or in partnership – with interest in the pre-salt concessions more than doubling the government’s estimates.
  • Iraq will be holding an oil and gas field auction for 11 sites on April 15, attracting major interest from ExxonMobil, Total and Lukoil.
  • Apache has made a ‘significant’ new discovery in Block 9/18a Area-W in the UK North Sea, with Graten possibly have 10 million barrels of light oil.


Downstream

  • India’s BPCL has announced plans to build a US$3 billion petrochemical plant in Mumbai, having purchased 202 hectares of land in March. The petchem complex will be integrated with its 240 kb/d Mumbai refinery.
  • The RAPID refinery in Johor is finally getting off the ground, as Saudi Aramco finalised its deal to buy a US$7 billion stake in the project and supply an initial 50% of its crude, with an option to rise to 70%.
  • The Trump administration is moving to reverse Obama-era fuel efficiency regulations for cars and light trucks, arguing that the Environmental Protection Agency targets were ‘too aggressive’.
  • Iraq is looking into building crude oil storage facilities in Japan and South Korea to increase sales to East Asia, following the example of Aramco.
  • Adnoc has signed two 3-year deals with Japan’s Idemitsu Kosan and Thailand’s SCG Chemicals to deliver up to 1.5 mtpa of naphtha per year.


Natural Gas/LNG

  • Petronas is reviving its K5 sour gas project in Sarawak, which will serve as a pilot project to test its carbon capture and storage technology.
  • China’s Sinopec has set out a plan to increase its natural gas supply capacity to some 60 bcm/y across its domestic output and imported volumes over the next 6 years, up from a current 27 bcm/y. Sinopec will also be doubling its LNG handling capacity to 26 mtpa.
  • Thailand’s PTTEP is now looking at a gas-to-power concept for the Aung Sinkha gas condensate field in Myanmar, part of the M3 gas block.
  • Iraq has officially enlisted Baker Hughes and General Electric to process natural gas extracted from the Nassiriya and Al Gharraf oilfields, which are currently being flared due to lack of gas capture facilities.

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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