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Last Updated: March 8, 2017
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Last week in World Oil:

Prices

  • Global crude prices remain firmly in their existing range, with Brent starting the week around US$56/b and WTI at US$53/b. Rising US production and signs that buyers are seeking alternate supplies have capped any gains made from the OPEC production cut, with the Iraqi oil minister publicly stating that he believes the cuts may have to be extended to the end of the year to support the current price environment.

Upstream & Midstream

  • Iran’s northern city of Kirkuk continues to be an incendiary environment. After four bombs hit a pipeline connecting the Bai Hassan oilfield to the degassing station – thought to be the world of Islamic State militants – additional disruption came when Kurdish forces seized a processing site, threatening to hold it hostage until the national Iraqi government to building a refinery in a region that wants additional autonomy.
  • Another week and another rise, though the rate of expansion is slowing down. This is the seventh consecutive rise in the weekly US active site count, with seven new gains in oil outweighing a loss of five gas rigs.

Downstream

  • South American nation Guyana has struck oil. With ExxonMobil and its partners discovering between 800 million to 1.4 billion barrels of oil offshore Guyana and production expected in 2020, the next question is what to do with the oil. Guyana does not currently have any refinery facilities, and the government is now mulling striking an agreement with neighbours Trinidad and Tobago, a Caribbean refinery centre, to ship its crude there for third-party processing. Suriname, which also has an underperforming refinery, has also been approached.
  • Two separate American lobbies behind the rise of Donald Trump are clashing, over the nation’s biofuels program. In the fossil fuel corner, billionaire Carl Icahn wants to shift the responsibility of the ethanol blending mandate from oil refiners (where it currently lies) to fuel blenders, who oppose the regulation change that has the potential to effect the entire ethanol chain, including farmers that supported Trump.

Natural Gas and LNG

  • That Canada is an LNG powerhouse is not in doubt, but it has not actually exported a single parcel of LNG yet, waiting for its export facilities along the British Columbia to approach completion. In a roundabout way, however, the very first Canadian LNG parcel may be sold overseas this year…. from Louisiana. American LNG player Cheniere has been quietly building a portfolio of natural gas suppliers to support its Sabine Pass export terminal, and has now begun sourcing gas from as far as the Montney shale play, straddling Canada’s Alberta and BC provinces.

Corporate

  • Total and Brazilian state player Petrobras have sealed a ‘strategic alliance’ that will see both companies collaborate closely. Petrobras will be transferring rights to some of its domestic fields to Total, maintaining ownership of key assets while balancing its severe debt situation. Total is a strategic choice in this case with its open attitude to investment.


Last week in Asian oil:

Upstream & Midstream

  • Attempting to fulfil its ambitious forecast of tripling its crude production, Pertamina has been looking overseas for assets. Shut out of sites in Africa and Asia over competitive forces, Iran has been the main target on its radar. The state player has submitted official proposals to Iran’s NIOC to develop the Ab-Teymour and Mansouri fields, containing up to 1.5 billions of oil each, meeting the deadline set back in August 2016 when Pertamina and NIOC agreed to a MoU to evaluate the development of the fields.

Downstream & Shipping

  • China’s Sinopec has announced a US$29 billion plan to upgrade four refineries over the next four years, envisioning a literal brighter future by siphoning out the pollution responsible for the perpetual smog in China’s cities. The four sites – in Shanghai, Nanjing, Zhenhai and Zhanjiang – will have their collective capacity raised to 2.6 mmb/d (and ethylene capacity up to 9 million tons per year), representing 45% of Sinopec’s refining capacity. The fuel specifications will be based on the so-called National VI standard, up from the current Euro V, which is being implemented in Beijing this year and rolled out across China over the next four years.
  • China’s largest independent refiner is teaming up with CEFC China Energy and the Rizhao port authority to construct what is believed to be the first ‘teapot’-owned crude oil terminal in Shandong. Long restricted from importing crude until last year, China’s refined products output from independent refineries exploded last year, but also revealed a weakness – the complete lack of crude terminal facilities to serve the teapots. The logistical bottleneck has prevented the teapots from expanding further, so a move into storage and terminals is natural. Dongming Petrochemical, the largest such teapot, is planning to build a 300,000 deadweight tonnage (DWT) crude terminal, two 150,000 DWT crude berths and a 9.8 million barrel storage farm in Rizhao, south of Qingdao, China’s largest oil port by volume that is almost completely saturated.
  • Indonesia’s Pertamina expects to finalise its partner for the US$10 billion Bontang refinery by April. Unusually offering a majority stake in the 300 kb/d refinery – up to 95% – the move seems an admission that Pertamina simply does not have the capacity to develop its expansion plans alone. Rosneft and Saudi Aramco are names that have been linked as possible partners, but interest seems to have petered out, a chronic problem in Indonesia as ambition clashes with practical reality. This also casts doubt on Pertamina’s ability to develop the Balongan refinery expansion project on its own, after Saudi Aramco pulled out of the project last year.

Natural Gas & LNG

  • India’s state gas player GAIL has inked a deal with Swiss trader Gunvor for LNG cargo swaps. A glut in Asia has caused Asian spot LNG prices to fall sharply over the past six months, making it unfeasible economically to bring GAIL’s US LNG cargoes over. Gunvor will supply 800,000 tons of LNG to India’s west coast from its portfolio at more feasible prices, receiving 600,000 tons of Sabine Pass LNG in return.  GAIL went on a spending spree in the US, buying into natural gas assets during a period when prices kept rising, and now that the market has upended, is stuck with an overhang of expensive (and distant) gas.

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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