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Last Updated: January 16, 2017
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Last week in world oil:


Prices

Oil prices steadied this week, with a weaker dollar supporting prices amid signs that OPEC’s output cut might hold despite some niggles. Brent crude edged above US$55/b, while WTI was at US$52/b. The focus this week is on the dollar, with Donald Trump being inaugurated as President. 


Upstream & Midstream

True to their word, Saudi Arabia has slashed its output to less than 10 million barrels, the lowest level in two years as it prepares to lead OPEC’s efforts to enforce a supply cut. Under the OPEC agreement, Saudi Arabia was to cut 486 kb/d off production to 10.058 mmb/d, but has gone even further to offset inertia in other OPEC members like Iraq. Saudi Energy Minister Khalid Al-Falih has stated that he will consider renewing the supply freeze in six months when the next OPEC meeting is scheduled. Fellow OPEC member Algeria has also pledged to reduce its output by more than its quota.


Halliburton and Petrobras have announced a technology cooperation partnership that will focus on complex reservoirs. The multi-year pact is aimed at assisting Petrobras in its deepwater presalt and mature fields over the long-term. The project portfolio will have three main objectives: reducing well construction investment, long-term reservoir monitoring and increasing well productivity.


Unusually, the US oil rig count fell last week, shedding seven sites to finish at 522. Offsetting a single gain in gas rigs, the total operating rig count in the US is now 659, perhaps a sign that producers are pausing in their zeal to monitor the oil price situation and OPEC’s commitment to it. 


Downstream

Kinder Morgan’s attempt to expand an oil pipeline in western Canada has cleared its final regulatory hurdle, with the British Columbia province giving environmental approval for part of the project’s profit. Some 37 conditions were attached to the approval of the Trans Mountain project, with Kinder Morgan agreeing to pay B.C as much as C$1 billion over 20 years in revenue sharing that will go towards environmental protection.


Russia’s Rosneft has agreed to supply up to 55 million tons of crude over a five year period to QHG Trading, a trading company linked to commodities giant Rosneft and Qatar. The deal follows the acquisition of a 19.5% stake in Rosneft by Qatar Investment Authority and Glencore last month for US$11.8 billion, with both companies now getting crude in return. Glencore, specifically, will receive an additional 220 kb/d to trade.

 

Natural Gas & LNG

A bitter, freezing winter is sweeping across Europe, boosting LNG demand and triggering the highest spot LNG prices in France’s southern gas hub since December 2013. The cold winter has boosted Europe’s requirements of natural gas, which has benefitted Russia’s Gazprom, recording its highest ever piped gas volumes to Western Europe on January 6, at some 615.5 million cubic metres.

 

 

Last week in Asian oil:

Upstream & Midstream

Thailand national upstream company PTTEP, part of the PTT empire, has slashed its capex spending this year. Plans for 2017 will involve investment of US$2.903 billion, more than 50% than envisioned two years ago, as its acknowledges the difficulties of securing overseas upstream assets. The primary focus going forward will be on natural gas, and the company has also slashed its production forecasts, leaving Thailand increasingly reliant on imports for its crude requirements.


In a rare bright spot, Chinese upstream giant CNOOC has started production at its Penglai 19-9 field. Located in the Bohai Bay, the new field is small, with peak production of some 13 kb/d expected in 2019. The joint venture between CNOOC and ConocoPhillips China will not be enough to halt the steady decline in Chinese crude production, but will help meet the country’s new objective of stabilising output. 


Downstream & Shipping

Indian fuel demand grew by its fastest pace in 16 years in 2016, as a low price environment kicked off growth in passenger car and flights, supporting gasoline and aviation fuels. Total fuel consumption grew by 10.7%, but the demonetisation drive impacted demand in December and will hold growth back in 2017, as consumers defer large purchases. State giant Indian Oil Corp (IOC) intends to support the demand growth by purchasing upstream assets, with the aim of ensuring that at least a tenth of its refining capacity be fed by crude from fields that it owns outright or has a partial state in, requiring a tenfold boost in crude production to 210 kb/d over the next eight year. 


Natural Gas & LNG

Thailand’s PTT continues its march to secure natural gas supplies, choosing a Marubeni-Itochu joint venture to fed its Chavalit Punthong pipeline. The pipeline, PTT’s fifth, stretches 430km from coastal Rayong to Nonthaburi near Bangkok, supplying the Thai capital with natural gas for power generation.


Vietnam has moved a step closer to realising its Blue Whale natural gas project, with PetroVietnam signing an agreement with ExxonMobil to develop the project. With an estimated 150 billion cubic metres of reserves, Blue Whale is Vietnam’s largest natural gas project, with the volumes aimed at powering the country’s electricity grid. First gas is expected by 2023, contributing US$20 billion to the national budget.

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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