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Market Watch

Headline crude prices for the week beginning 12 March 2017 – Brent: US$64/b; WTI: US$61/b

  • Crude prices started on a weaker note, after a see-saw week of trading last week, as indications pointed to American shale output swelling.
  • With OPEC’s efforts already in place and the beginnings of a pullback in June expected by the market, attention has been focused on the current swing factor – American crude production.
  • Output from major US shale regions is expected to continue strong gains. This would help stabilise, perhaps increase, crude stockpiles in Cushing, Oklahoma, which have declined consistently since the start of 2018.
  • The EIA expects output from American shale regions to reach 6.95 mmb/d in April, a gain of 131,000 b/d, with the Permian alone contributing a gain of 80,000 b/d.
  • US jobs data showed a healthy increase in oil and gas sector employment, up 1,100 in February, an acceleration after steady gains last year.
  • Oil rigs in the US fell for the first time in six weeks, dropping four sites in response to the recent sapping of crude price strength. Gains of seven gas sites still led to an overall gain, with the total active rig count at 984.
  • All this points to American crude output exceeding expectations in output terms; within OPEC, Iran is lobbying to keep oil prices at US$60, fearing that a US$70/b target will only encourage additional US shale output.
  • Crude price outlook: The continued ascent of American shale production will keep price momentum depressed, with Brent likely to trend towards US$63-64/b and WTI at US$60-61/b.

Headlines of the week

Upstream

  • Eni has acquired a 40-year stake in the two major offshore concessions in Abu Dhabi for US$875 million. In return, Eni receives a 5% stake in the Lower Zakum oil fields and a 10% in the oil, condensate and gas fields of Umm Shaif and Nasr. ADNOC will continue to hold a 60% stake in both.
  • Saudi Arabia is scheduled to join the shale revolution by end March, as shale production at the North Arabia basin, said to rival Eagle Ford in Texas, begins. Drilling at the South Ghawar and Jafurah basins is also underway, as Aramco plans a US$300 billion ten-year spending spree.
  • Encouraged by recent discoveries in Guyana, the Dominican Republic will be offering two onshore oil and two offshore gas blocks by the end of March, attracting the attention of BP and ExxonMobil.
  • Petronas has struck oil at the Boudji-1 well in Gabon’s offshore Block F14, an ultra-deepwater field with encouraging ‘high quality’ deposits.
  • Premier Oil’s Catcher field – the most recent field to start up in the North Sea – will reach its projected 60,000 b/d target ahead of plan, by 1H18.
  • Shell will be selling out of the ageing Draugen field in Norway, along with stakes in smaller fields, including Gjoa, Kvitebjorn, Valeman and Sindre.

Downstream

  • Petronas will be upgrading its ageing Kerteh refinery by 2022, to expand its crude diet beyond the local light sweet Tapis crude, as well expand capacity to meet Euro V standards and deepen petrochemical linkages.
  • Petrobras will be investing some US$42 million to upgrade its Presidente Bernardes refinery near Sao Paulo to improve efficiency.
  • Vietnam has pulled the plug on the planned US$3.2 billion 160 kb/d Phu Yen refinery, revoking the investment licence granted to UK-based Technostar Management and Russia’s Telloil Group.
  • Sinopec appears to have prevailed over Glencore in pursuit of Chevron’s downstream assets in South Africa and Botswana, as South Africa’s Competition Tribunal approved its US$900 million purchase, subject to an additional investment of US$504 million over the next five years.
  • Saudi Aramco and SABIC have appointed Wood to develop its planned crude-to-chemicals complex in Saudi Arabia, which would be the world’s largest with a capacity of 400 kb/d and 9 mtpa of petrochemicals.
  • Not to be outdone, ADNOC announced plans to build the world’s largest integrated refining and chemicals site in Ruwais, doubling its crude capacity and tripling its petrochemicals capacity, rivalling Jamnagar.

Natural Gas/LNG

  • Petronas has inked a 13-year contract with Tokyo Gas, supplying some 500,000 tons of LNG per year to its long-term customer beginning April 2018, which could rise to 900,000 tons per year after seven years.
  • In another blow to Canadian Pacific coast LNG, Australia’s Woodside has dropped plans to develop its Grassy Point project, choosing instead to focus on the Kitimat LNG project with partner Chevron.
  • Ophir Energy expects first gas from its Fortuna project in Equatorial Guinea by 2022, with FID expected by the end of 2018.
  • Trial operations have begun at Ichthys in Australia, with Inpex sticking to its end-March target date despite rumours of more delays.

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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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Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

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