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Last Updated: May 11, 2020
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Headline crude prices for the week beginning 4 May 2020 – Brent: US$27/b; WTI: US$20/b

  • Crude oil prices have rallied to levels last seen before the oil price meltdown in mid-April, as OPEC+ begins the largest supply cut deal in its history and signs that global oil demand is slowly recovering
  • The start of OPEC+ 9.7 mmb/d supply reduction has also been accompanied by a huge ‘voluntary’ reduction by private players in the US, with ExxonMobil, Chevron and ConocoPhillips alone shutting some as much as 660,000 b/d of their US capacity through June
  • The combination of the OPEC+ cuts and the market-enforced reductions on international players should halve the global oil glut in May, but the overhang will still be a considerable 6 mmb/d, generating concern over the pressure on storage capacity globally
  • In the US, inventory builds at the key hub of Cushing, Oklahoma rose by 1.8 million barrels, the smallest rise in 6 weeks, and triggering a recovery in WTI prices since this could see the storage crunch and oversupply situation easing
  • However, the storage situation is not equal worldwide: while Petrobras has ample space in Brazil to store crude, reports suggest that South Korea has run out of commercial storage space, with the 38 million barrels of capacity held by Korea National Oil Corp and Oilhub Korea Yeosu completely tapped out in one of Asia’s largest refining markets
  • Crude and refined product storage space in India and Singapore are also reportedly filling up fast, which will force buyers to look into offshore storage
  • The US active rig count, according to Baker Hughes, has lost another 57 rigs over the week, shaving off 53 oil rigs and 4 gas rigs to a new total of 408 sites, the lowest count since May 2016
  • Crude oil prices have roughly doubled over the past two weeks, buoyed by optimism that demand will gradually return and OPEC+ will keep adherence high to hold back a supply flood; this might be premature, since a supply glut still exists, particularly ahead of the expiry of the June WTI contract May 20, but should be enough to keep Brent and WTI in the US$$-26-30/b and US$20-24/b range for now


Headlines of the week

Upstream

  • Lebanon’s ambition of joining the ranks of the Eastern Mediterranean’s oil and gas bonanza have come up empty for now, with Total’s maiden test drilling campaign in the offshore Block 4 having come up dry
  • Jadestone Energy will be delaying its Australian drilling campaign planned for the Stag and Montara oil fields offshore northwest Australia until 2021, having already deferred planned upstream development campaigns in Vietnam
  • Neptune Energy is reporting that it has made two ‘important’ hydrocarbon discoveries in northwestern Germany – with the Ringe 6 well striking oil while the Adorf Z15 well in Emlichheim struck gas flows
  • Neptune Energy has also kicked off its drilling campaign on the offshore Fenja field in Norway, estimated to deliver some 40,000 b/d at peak production
  • Despite major uncertainty in the market, BP has reaffirmed its commitment to complete the sale of its Alaskan upstream business to Hilcorp, with the initial consideration of US$5.6 billion having been renegotiated
  • Mubadala Petroleum has reduced capex for its Manora offshore oil development project in Thailand by some US$14 million
  • UK independent Coro Energy has bailed out of a plan to acquire a 42.5% stake in the Bulu production sharing contract in Indonesia that encompasses the Lengo gas field, citing ‘increasing concerns’ over operator KrisEnergy

Midstream/Downstream

  • China will issue its first ever export quotas for very low sulfur fuel oil (VLSFO) later this year, with the first batch expected for 10 million tonnes of the marine fuel as Chinese refiners aims to capture a huge slice of the new market
  • As crashing oil prices and the Covid-19 pandemic impacting production and promotimg nationalism, Lukoil is reporting that its 3 refineries in Europe (Italy, Romania and Bulgaria) are now processing only Russian crude
  • Thailand’s IRPC has officially delayed a planned US$1 billion petrochemicals project that would add 1.3 million tonnes per year of paraxylene and 400,000 tons of benzene production capacity to the country’s third-largest refiner

Natural Gas/LNG

  • ExxonMobil is now looking to sanction FID for its US$25 billion Rovuma LNG project in Mozambique in 2021, which will now be the hub for all future trains
  • France’s Total and Japan’s Mitsui have individually signed up for long-term LNG purchases for Sempra’s Energia Costa Azul project in Baja California, Mexico, which will total some 2.5 million tons per annum
  • Aker BPs’s Ærfugl Phase 2 development plans kicks off in grand style, with the first well drilled three years ahead of schedule, tapping into a reservoir containing some 300 million boe of natural gas
  • Sempra has postponed FID on its Port Arthur LNG export project from 2020 to 2021, citing ‘weakened global demand’ due to the Covid-19 pandemic
  • Arrow Energy has kicked off the first phase of its Surat Gas Project in Australia’s southern Queensland area, which is expected to deliver some 5 tcf of natural gas for Arrow and its partners Shell and PetroChina

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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