In June, a major milestone was hit. Argentina exported its first-ever cargo of liquefied natural gas through its state oil firm YPF with the assistance of Cheniere. A light oil cargo, from Vista Oil & Gas, soon followed. But not only is it the first ever LNG sale for the country, it is also the first commercial output from the Vaca Muerta shale play – one of the world’s largest shale formations and a potential game changer for the hobbling Argentine economy.
Known as the ‘Argentine Permian’, Vaca Muerta was discovered as long ago as 1918, when it was recognised as the source of petroleum for formations in the prolific Neuquén Basin. In 2010, YPF (which was then Repsol-YPF) made a significant shale oil discovery and is now currently producing 45,000 b/d of light oil. Several other discoveries have since been made, with its potential labelled as ‘vast’. The Argentine government estimates that, if development proceeds smoothly, Vaca Muerta could double the country’s oil production to 1 mmb/d by 2023 and lift natural gas production to 260 cbm/d. The US EIA goes even further, estimating that the Vaca Muerta formation holds recoverable resources of up to 16.2 billion barrels of oil and 308 trillion cubic feet of natural gas, which would make it the largest hydrocarbon basin in Argentina, surpassing the Neuquén Basin.
But despite this potential, exploiting Vaca Muerta has proved challenging. Since the initial discoveries around 2010, drilling and development has commenced but the first tangible results are only starting to emerge. In the wider context, Argentina has been battling government changes and an economic malaise which has led to high costs, regulatory uncertainty and insufficient infrastructure despite billions in investment from supermajors. A currency crisis from last year is still impacting the economy, and with elections due in October, a U-turn in policy is a possibility. This has so far hampered efforts to build pipelines to connect Vaca Muerta – a 30,000 sq km formation about 600km from the nearest coastline – to necessary LNG facilities. But despite these hurdles, international oil firms such as ExxonMobil, Chevron, Shell and Total are still holding on to acreage positions in Vaca Muerta.
In Vaca Muerta, YPF is currently the leading producer, with output of 71,000 boe/d in Q119 from three projects – Loma Campana, La Amarga Chica and Bandurria Sur. Not far behind are its international rivals. Shell has announced that it is moving on to the development phase of the Sierra Blances, Cruz Lorena and Coiron Amargo Sur Oeste blocks with a projected output of 70,000 boe/d by the mid-2020s. ExxonMobil has announced plans to drill 90 wells, with first production of 55,000 b/d expected by 2024. Total is working on its Aguada Pichana Este licence while Chevron has plans to drill up to 2,000 wells in the El Trapial, Loma de Molle Norte and Narambuana deposits. Unlike the Permian, which was powered by small, nimble independents, the supermajors got into Vaca Muerta early and hold a significant position. But commercial interest also extends beyond these giants; private equity firms Riverstone and Southern Cross Group have invested in creating a midstream Vaca Muerta player called Aleph to boost pipeline infrastructure that will be necessary if Argentina is to continue growing its light oil exports from a projected 70,000 b/d in 2020 and boost LNG sales.
The potential is there, particularly since peak output in the southern hemisphere’s summer coincides with deep winter in northeast Asia, during which spot demand from China, Korea and Japan has spiked in recent seasons. Shipping costs would be lowered as well, since Argentine shipments could avoid tolls at the Panama Canal to provide a competitive alternative to US exports. Vaca Muerta might mean dead cow in Spanish, but it is giving new life to Argentina’s upstream industry. The wait has been long and it will just take a little longer
The Vaca Muerta Shale Basin:
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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