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Headline crude prices for the week beginning 27 April 2020 – Brent: US$16/b; WTI: US$14/b

  • Crude oil prices remain in the doldrums after a week of see-saw prices, with traders attempted to ascertain the extent of demand destruction while also shifting their focus to the new OPEC+ supply deal
  • Signs that major economies were slowly emerging from the Covid-19 pandemic – ahead of crucial summer demand season – were adding drops of optimism to the sentiment pool; China is now almost back to full operation, while fatality and case rates in the US, Europe and Asia were also on the decline
  • The major concern is storage: there is already too much oil – crude and refined – sloshing around the world, and storage capacity worldwide is already hitting its limit, as players seek new, novel ways to hoard oil
  • Saudi Arabia has begun throttling its production down to 8.5 mmb/d, while Kuwait, Algeria and the UAE had already begun reducing production earlier; but all eyes will be on Russia, as well as overall adherence to the quotas
  • WTI prices also took a tumble as the United State Oil Fund LP – the largest oil exchange-traded funds (ETF) – announced it would sell out its June WTI contracts, adding to the glut in the market and highlighting the risk of another bloodbath when the WTI June contract expires on May 20
  • The Covid-19 pandemic is also affecting major upstream projects; cases are on the risk in Novatek’s Arctic LNG 2 project in Russia and Total’s Afungi LNG site in Mozambique, while clusters have been reported in the UK North Sea, which could jeopardise the industry there amid the Brexit uncertainty
  • The US active rig count continues to chart new recent lows, losing 64 rigs (60 oil, 4 gas) to bring the total number of operating rigs to 465, with the main losses predictably being in the onshore sector as offshore rigs remained flat
  • Oil prices are slowly recovering on the market’s twin hopes of the Covid-19 pandemic easing and the OPEC+ supply deal biting off a major portion of disappeared demand; expect Brent to trade in the US$22-26/b range, with WTI further back at US$15-18/b range

  

Headlines of the week

Upstream

  • After almost a year of regular renewals, the US government has decided not to renew Chevron’s waiver to operate in Venezuela despite sanctions, in an effort to place more pressure on Nicolas Maduro; the decision also affects four service providers: Halliburton, Schlumberger, Baker Hughes and Weatherford
  • Despite postponing drilling campaigns elsewhere, Thailand’s PTTEP is moving ahead with its plans to on two wildcat explorations in Peninsular Malaysia’s Block 415 and PM407, which it picked up in March 2019
  • Total is to purchase Tullow Oil’s whole interest in the Uganda Lake Albert development – including the East African Crude Pipeline – for US$575 million
  • Indonesia has announced that the PB-1 oil discovery in Central Sumatra’s onshore Mahato permit contains some 61.8 billion barrels of oil in place
  • Despite a hedging strategy that proved to be canny in the face of an oil price collapse, Mexico’s Pemex is now looking to halt production at new oilfields – some 20 fields with output estimated at 50,000 b/d at peak – and refine more
  • Pertamina has officially cut its 2020 target for new drilling and upstream output, aiming to cut output by 3% to 894,000 b/d from the previous 923,000 b/d
  • Consolidation continues in the US shale patch, as Oklahoma-based Empire Petroleum Corp acquired upstream and midstream assets in the Eagle Ford basin’s Ft. Trinidad field from Pardus Oil & Gas
  • Chevron has sold its non-operating interest in the Azeri-Chirag-Deepwater Gunashli (ACG) oil fields to Hungary’s MOL for some US$1.57 billion

Midstream/Downstream

  • Fujairah, the Middle East’s oil storage hub, may be getting new storage capacity, as Brooge Petroleum and Gas Investment announced plans to advance its Phase III facilities to add 2.1-3.5 cbm of space for crude and refined products; the Phase III plans also include a possible associated refinery
  • After the dramatic downfall of Singapore’s Hin Leong Trading, Sinopec is now reportedly in talks with the trader to purchase the 2.33 million cbm Universal Terminal in Singapore, which could fetch some US$1.5 billion
  • Portugal’s Galp Energia will be suspending operation at its 220 kb/d Sines refinery on a lack of storage space for a fuels glut; Galp had already shut its smaller Matosinhos refinery in early April, bringing all refining to a halt
  • South African petchems giant Sasol is looking to sell a large stake in its US$13 billion Lake Charles chemicals complex, aiming for a possible joint venture
  • Indonesia will be shutting down the 260 kb/d Balikpapan refinery in East Kalimantan in early May as domestic demand for fuels shrivels up; the shutdown will also affect the 120 kb/d upgrade project planned for the site

Natural Gas/LNG

  • Sempra Energy’s Cameron LNG has entered the final commissioning stage for Cameron LNG Phase 1 project in Louisiana, introducing pipeline gas to the final of three liquefaction trains with a total capacity of 12 million tpa
  • Woodside and its partners have begun offshore surveys in Myanmar’s offshore ultra-deep Block A-6, which is expected to strike natural gas
  • Qatar Petroleum has struck a deal with China’s Hudong-Zhonghua Shipbuilding Group to reserve the latter’s upcoming shipbuilding capacity to expand its LNG carrier fleet, in preparation for the ongoing North Field expansion projects
  • Indonesia’s Medco Energi has announced a new offshore gas discovery, at the offshore South Natuna Sea Block B

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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