Easwaran Kanason

Co - founder of NrgEdge
Last Updated: November 23, 2016
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Business Trends

Last week in world oil

Optimism that OPEC and Russia could agree on a supply freeze lifted oil prices near the US$50/b level, as traders bet that supply/demand fundamentals had a eroded to a point that would necessitate action on the part of the producers. This optimism is hopefully not misplaced, but at some point, OPEC members will be hurting enough to agree on something. 

Kuwait has stepped in after Saudi Arabia cut off crude deliveries to Egypt. Although the Kuwaiti government says the shipments, renewed from an existing contract for three more years, are not intended to replace the Saudi source, it provides a measure of relief for Egypt, forced to issue emergency spot tenders after Saudi Arabia cut off supplies in October. Under the new agreement, Egypt will receive 2 million barrels of Kuwaiti crude a month, an amount insufficient to meet total domestic needs.

In response to higher prices, the US oil rig count jumped by double digits last week. Nineteen new oil rigs were added last week, with a single additional gas site bringing the total number of oil and gas rigs drilling in the US to 588, with most of the increases coming from the Permian Basin. 

US refiner Tesoro has agreed to buy independent US refiner Western Refining for US$4.1 billion, creating a new company that will represent 6% of the American crude processing capacity and the fifth-largest in the country. Western Refining’s speciality is gathering oil in remote fields, pooling it together and bringing it to a hub, with its pipeline infrastructure in the Texan and New Mexico Permian shale basin filling a huge gap in Tesoro’s midstream business. 

Argentina has removed subsidies for crude purchases by state-run YPF, a move aimed at freeing up cash for the beleaguered Argentine government. YPF had previously accessed crude at a subsidised cost of about US$62/b, but will now be required to pay market price as President Mauricio Macri slashes subsidies to prevent a ballooning fiscal deficit. This applies to domestic crude oil, where subsidies were put in place by Cristina Fernandez de Kirchner to promote drilling. YPF controls some 60% of the refinery and oil products market in Argentina. 

ExxonMobil is exiting the western South America retail business, passing over its fuel and lubricants businesses in Colombia, Ecuador and Peru to Chile’s Empresas Copec. Copec will retain the licence to produce and distribute fuel and lubricants in the markets under the ExxonMobil brands, while taking ownership of the existing distribution network. 

Italy’s Eni has finalised its plans to develop the Coral South offshore gas project in Mozambique. In an investment of up to US$50 billion, the huge gas reserves in Eni’s Area 4 concession could produce up to 3.3 mtpa of LNG per year, requiring six subsea wells and a floating production facility. Coral South contains some 16 tcf of gas, and Eni has already signed a deal to provide BP with LNG from the project over 20 years. 

The giant Kashagan oil field in Kazakhstan has finally started commercial production. Halted in 2013, when a pipeline cracked open causing the entire field to shut down, Kashagan is now back on track to reach output of 630 million barrels by 2017 and 760 million barrels by 2020, from a reserve estimated at 16 billion barrels. 

This is why an OPEC deal in the next week is highly unlikely. In October, Iran overtook Saudi Arabia as the chief supplier of crude oil to India, underscoring a trend that has seen Iran ramp up its exports to Asian nations, often at the expense of Saudi Arabia, regaining market share lost during the years of the sanctions. In October, Iran delivered some 798 kb/d of crude to India, compared to Saudi Arabia’s 697 kb/d. On a YTD basis, Saudi Arabia is still India’s top supplier, followed by Iraq, but Iranian exports to India have generally tripled over the course of 2016. 

Japan’s Idemitsu Kosan has been forced to delay its planned purchase of Showa Shell Sekiyu from Royal Dutch Shell again, as a review by the Japan Fair Trade Commission is still underway. The deal is now expected to be closed by January from its already delayed timeframe of November, as Idemitsu seeks to acquire 33% of Showa Shell after a full takeover was shelved indefinitely with stiff opposition from the founding family members of Idemitsu Kosan. 

Japan’s Tokyo Gas has signed an MoU with the UK’s Centrica for location swaps of LNG, benefitting both parties by slashing transportation costs. Tokyo Gas will supply Centrica with 700-800 ktpa of LNG from the Cove Point project in Maryland, while Centrica will oblige with an equivalent amount from its Asia Pacific LNG network. Swap deals are still uncommon in the LNG space, but will become more common as European and Asian utilities – with their LNG assets and contracts in far-flung places – seek to optimise their supply and transportation network. 

Petronas has achieved first gas for the floating LNG facility from the Kanowit field in Sarawak, a sign that its floating production unit is ready to enter commercial operations and deliver cargos.  It will be a world’s first, with the PFLNG Satu operating as the world’s first FLNG facility as Petronas seeks to unlock gas reserves in remote and stranded fields. 

After a 96% drop in Q216 profits, Petronas’ financial performance has bounced back, with Q316 profits tripling to RM6.1 billion over lower net impairment on assets and higher average prices for most of its products. Sales volumes, however, remain a concern, with shipments of almost all major products lower across the quarter.  The outlook for Q416 is a bit rockier, given the weakening of the Malaysian ringgit since November. 

Have a productive week ahead!

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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)

Consumption (mmb/d)*
Refining Capacity (mmb/d)
North America



Latin America









Middle East












*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