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Last Updated: November 15, 2018
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Market Watch

Headline crude prices for the week beginning 12 November 2018 – Brent: US$71/b; WTI: US$60/b

  • Crude prices continue their retreat from recent highs, as a bear market engulfed sentiment last week over fears of oversupply from frantic OPEC+ pumping offsetting the loss of Iranian crude volumes, which itself was mitigated by the US handing out waivers to eight key crude importers
  • After stating that OPEC was in a ‘pump as much as you can’ mode, the quick fall in prices has caused alarm across the cartel, with Saudi Arabia reversing gear to curb its exports by 500,000 b/d in December to shore up prices
  • With the OPEC meeting in Vienna imminent, it is possible that a new output cut agreement could be reached within OPEC+, to counter an oversupply situation stemming from declining demand, as well as surging US shale production – which will rise to a record 7.94 mmb/d across seven major shale basins in December, according to the EIA
  • However, beyond Saudi Arabia, there is not much appetite within the OPEC+ alliance to reduce output, with Iraq happy with its record production and Russia dismissing the oversupply situation as a ‘seasonal glitch’
  • Saudi Arabia’s plan to cut its oil production was criticised by US President Donald Trump, stung by losses in midterm elections that Trump chalks up to, in part, high fuel prices
  • News that Saudi Arabia was researching the topic of breaking up OPEC rattled the markets, but the Kingdom moved to quash rumours as Aramco raised the pricing for its medium and heavy crudes sold to Asia
  • Despite this, trends have turned bearish for crude prices over this week, propelled by large jumps in US crude output and worries over a global economic slowdown, particularly in China; Brent and WTI fell by over US$4/b on Tuesday alone, falling below the US$70/b and US$60/b levels again
  • After several weeks of caution, US drillers added 14 new rigs this week – up by 12 oil rigs and 2 gas rigs to 1,081 in total – with the most gains once again coming from the prolific Permian Basin
  • Crude price outlook: After the large drop on Tuesday, crude prices appear to have stabilised somewhat around the US$65-66/b level for Brent and the US$55-56/b level for WTI


Headlines of the week

Upstream

  • Another setback for TransCanada’s beleaguered Keystone XL pipeline, as a judge in Montana halted the project over two lawsuits filed asserting that its environmental impact assessment required further review
  • Phillips 66 and Bridger Pipeline are launching two new crude pipelines connecting Rockies and Bakken oil to the Texas Gulf Coast; the Liberty Pipeline will carry 350 kb/d from Bakken/Rockies to Corpus Christi, while the 400 kb/d Red Oak Pipeline connects Corpus Christi to Houston
  • Magellan Midstream Partners is looking to build a new pipeline connecting Cushing to Houston, with the 250 kb/d Voyager pipeline targeted at end-2020
  • The Kurdistan Regional Government in Iraq has increased capacity of its oil pipeline from Kirkuk to Ceyhan, Turkey, from 700,000 b/d to 1 mmb/d
  • After previously fleeing from Canadian oil sands, ExxonMobil is investing again, with its Imperial Oil unit earmarking some US$2 billion for the new Aspen project in northern Alberta
  • Senrica Energy continues its buying spree in the North Sea, acquiring Marubeni Oil & Gas’ 3.75% and 8.33% interest in the Bruce and Keith fields
  • ADNOC is implementing a comprehensive hydrocarbons strategy that will increase its crude output capacity to 4 mmb/d by 2020 and 5 mmb/d by 2030
  • Croatia has launched the country’s second onshore licensing round, offering seven blocks in the prolific Pannonian basin
  • Eni and Lukoil have signed a farm-out deal, transferring participating interests in three shallow-water offshore Mexican licenses, including Area 10, 12 and 14
  • Buoyed by recent gas successes, Israel has announced its second offshore licensing round, offering up 19 blocks in its southern waters
  • Senegal is overhauling its own code, with plans to raise royalties and have the state take a bigger stake in projects after a string of major discoveries
  • CNOOC is kickstarting a development drive aimed at eking out additional volumes from several marginal fields in Bohai Bay and the South China Sea

Downstream

  • Nigeria’s ambitious overhaul of its state-owned refineries has been pushed back to end-2019 over slow progress in NNPC’s attempt to seek joint financing
  • NNPC is looking to sign crude-for-product swap deals with Shell and ExxonMobil, after signing one with BP, to acquire crude for its refineries
  • France is pushing ahead with its attempt to introduce a new fuel tax, despite a series of major blockades and protests planned to oppose the measure

Natural Gas/LNG

  • Total and Sempra Energy have signed a new MoU on LNG cooperation, covering the Cameron LNG in Louisiana, USA and Energía Costa Azul in Baja California, Mexico, with Total potentially taking up to 9 mtpa of LNG for its global portfolio from both projects
  • Cuadrilla has had first shale gas flow at its exploration well in the UK’s Preston New Road site, sparking optimism for the commercialisation of Bowland Shale
  • Croatia has picked Golar Power to deliver an FSRU for a planned floating LNG terminal in the northern Adriatic Sea
  • Tellurian confirms that construction on its Driftwood LNG terminal Louisiana will begin in 2H2019, which operations planned to begin in 2023
  • Japan’s Toshiba Corp is exiting the US LNG business, selling off its assets to China’s ENN Ecological Holdings for over US$800 million

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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