Last week in the world oil:
-News of a strong recovery in US oil drilling offset optimism that OPEC and its non-OPEC allies were on track to meet their output reduction goals, leading oil prices to start the week slightly lower after gains last week. Saudi Arabia notched up its highest exports in 13 years in November, but numbers are expected to fall by nearly 400 kb/d in January as the supply cuts kick in. The push-pull relationship between OPEC and free market producers in the US highlights the difficulties in the race to raise prices.
Upstream & Midstream
-In a move that could potentially revolutionise oil trading, Mercurialis testing out an oil cargo contract sale based on the digital blockchain technology. Working together with banks ING and Societe Generale, the cargo of African crude sold to ChemChina is based on the technology that powers bitcoins a permanent digital ledger of all transaction history known as a blockchain that could replace the current complex system of clearing and settlement that require massive amounts of paperwork.
-The US oil rig count leapt by 35 last week, the largest rise since 2011, as US drillers responded to price signals, potentially hampering OPECs attempt to strengthen prices. Some 29 new oil rigs and 6 new gas rigs were restarted, and more additions are expected.
-A fire has halted output at Adnocs Ruwais refinery in Abu Dhabi, shutting down half of the sites 800 kb/d capacity. The outage at the newer section, is expected to be short, with production resuming next week.
Natural Gas & LNG
-In an attempt to reduce heavy reliance on Russian natural gas, Serbia and Bulgaria are cooperating on a natural gas pipeline project. The 150km pipeline is scheduled to begin construction in May 2019 and operational by the end of 2020, linking Sofia with the Serbian city of Nis. This could draw supplies from pipelines in Greece and Turkey, and possibly volumes from Israels Leviathan field. Poland, too, is plotting reducing dependence on Russia, aiming to have a gas pipeline to Norway in place by 2022.
-Brazil's Odebrecht group, embroiled in the country's largest ever graft scandal, has missed a financing deadline that will see it exit a US$5 billion natural gas pipeline in Peru, potentially derailing the entire project. The bribery scandal has brought the once powerhouse to its knees, which will now see it focus on divesting assets in all but two sectors to survive, retaining only its construction arm and petrochemical producer Braskem.
-Frances Technip and FMC Technologies have completed their merger, now operating as unified service provider TechnipFMC. The merger comes partially due to the slump in upstream investment, but also to consolidate developing technology to access hard-to-reach assets.
-Shell will have a new Head of Exploration next month, with current upstream strategy vice president Marc Gerrits taking over the role from Ceri Powell, who moves on to become the managing director of Brunei Shell Petroleum. The move is part of a broader reshuffle of executives following the acquisition of the BG Group, with upstream moving away from risky frontier areas like Alaska to existing production sites like Brunei and Malaysia.
Last week in Asian oil:
Upstream & Midstream
-Indonesia's Pertamina has unveiled an ambitious plan to invest US$54 billion in upstream production through 2025, aiming to raise its oil, gas and geothermal output by 185% to 1.91 million barrels. Pertamina's upstream output has slumped over the last decade, hitting its lowest point of 670 kb/d in November 2016, with the company struggling to acquire even domestic fields. The goals are at odds with OPECs wider objectives, leading Indonesia to withdraw temporarily from the organisation in November to focus on an upstream spending spree.
-A week after extending a storage deal with Saudi Aramco, Japan has done the same with the UAEs Adnoc. The two-year extension will allow Adnoc to continue storing up to 6.29 million barrels of crude oil in theKiireterminal in Kagoshima until 2019 at no cost in return for first dibs on the supplies in the case of emergencies. Adnoc uses the storage facilities as a convenient way to distribute crude across East Asia.
Downstream & Shipping
-Iran and China have agreed to a US$3 billion deal that will see China support Iran financially as its moves to upgrade its ailing oil refining infrastructure. The agreement will focus on the 430 kb/d Abadan refinery, Irans largest, that is in dire need of upgrades after years of sanctions prevented access to parts and new technology. It is an indication that the rest of the world is still prepared to deal with Iran, even as the new American administration is prepared to be more hostile.
-Bangladesh has reversed its decision to slash fuel prices as global crude prices rise. The phased prices cuts which would reduce the controlled prices of gasoline, diesel and LPG began in April 2015, after a two-year freeze to help state-owned player Bangladesh Petroleum Corp recover losses and were meant to be extended over 2017. However, the government has now decided that raising oil prices pose too much of a risk to move ahead with another 10% cut, freezing gasoline prices at around 86 taka (US$1.10) per litre.
-Singapore's struggling Jurong Aromatic Corp (JAC) might have found a buyer in South Koreas Lotte Chemical Corp. After going into receivership in September 2015 due to debt issues as global commodity prices were routed, JAC also had to deal with an 18-month outage as its petrochemical complex to fix issues and has been searching for a possible suitor. Lotte, which currently operates two naphtha crackers in Daesan and Yeosu along with a condensate splitter shared with Hyundai Oilbank, has been looking at potential overseas assets and JAC would be a suitable target to establish itself as one of Asia's largest condensate buyers.
Natural Gas & LNG
-Pakistan is in need of natural gas, a reason why Asian LNG prices have spiked over the last two weeks. While there is no short-term solution, it has secured some long-term security with a Gunvor deal to receive 60 LNG cargoes over the next five years and an Eni deal for 180 cargoes over the next 15 years. More tenders are expected, as Pakistan works towards bringing two more LNG terminals online over the next two years.
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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)|
*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)
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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.
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