Sharply weaker oil prices and the COVID-19 pandemic are weighing heavily on the outlook for crude oil. It is not only U.S. shale oil and gas which will experience a wave of stranded assets because of the poor outlook for crude oil, such an event is also looming in Latin America. The latest oil rally, spurred on by hopes of a coronavirus vaccine, has seen Brent climb more than 33% since the start of June 2020 to around $49 per barrel, but that still may not be enough. The global push to reduce emissions, decarbonize the world economy and slow climate change are only adding to the pressure on oil markets. A key threat for the future of oil in Latin America is the emergence of peak oil, which is expected to arrive in 2030 or even sooner. When that occurs, demand for fossil fuels will stop growing and will start to steadily weaken - causing oil prices to enter a period of sustained decline. Fossil fuel consumption will gradually wane as the adoption of electric vehicles swells and the push to decarbonize the world economy accelerates. Carbon emission targets established by the Paris Agreement and increasingly stricter emission regulations for fuels, including a concerted effort to sharply reduce sulfur content, are impacting demand for some crude oil grades. Those developments pose a direct threat to Latin America’s hydrocarbon sector and the viability of the region’s oil resources. Some of the most vulnerable oil assets in Latin America are those with high breakeven costs operating in less politically stable jurisdictions such as Argentina. The Vaca Muerta shale formation in Patagonia, long viewed by Buenos Aires as an economic silver bullet, is at risk of becoming a stranded asset. The shale play has some of the highest breakeven costs in Latin America. New projects need Brent at over $50 per barrel to breakeven and existing operations require the international benchmark to be trading at $45 to $50 a barrel to be cashflow positive. In an operating environment where Brent is trading at less than $50 per barrel, international energy companies will look elsewhere to invest. According to the Argentine Energy Institute, a domestic think tank, international energy majors already operating in the Vaca Muerta, like Chevron, Shell, and ExxonMobil, will redirect capital to lower cost oilfields outside of Argentina.
Related: Large Oil Trader Trafigura Books Strongest Trading Year Ever The risk of the Vaca Muerta and its hydrocarbon resources, estimated by the U.S. EIA to be 16 billion barrels of oil and 308 trillion cubic feet of natural gas, becoming a stranded asset is amplified by heightened political and economic risks in Argentina. The risk associated with the country increased last year due to the victory of a Peronist candidate, Alberto Fernández, in the presidential election and the appointment of Cristina Fernández de Kirchner, the architect of the 2012 nationalization of YPF, as vice-president. Those risks are further amplified by the economic and political fallout from the COVID-19 pandemic which the IMF predicts will see Argentina’s 2020 GDP contract by almost 12%. This magnifies the hazards posed by Argentina’s latest economic crisis and could prevent Buenos Aires from successfully funding various subsidies aimed at promoting investment in the Vaca Muerta.
Low oil prices and the threat of diminished demand means many other high-cost operations in Latin America are facing a similar hazard. According to the Natural Resource Governance Institute, up to 40% of producing oil assets in offshore Atlantic Brazil, Colombia’s Caribbean, Peru’s Amazon, and Venezuela are not economically viable with Brent at $50 per barrel or less. Predictions that oil will average less than $50 per barrel during 2021 increases the risk of some of those operations becoming stranded assets. That risk is even greater for those oilfields which are producing heavier sour grades of crude oil. The ongoing implementation of regulations aimed at reducing emissions, notably sulfur dioxide and particulates, are making high sulfur content crude oil grades less popular among refiners. They are more difficult and costly to refine into high-quality low sulfur content gasoline, diesel, bunker oil, and other fuels. According to the International Council On Clean Transportation, low sulfur fuels make vehicles cleaner and those with near-zero sulfur content have virtually no particulate or nitrogen oxide emissions. This demonstrates the considerable benefit created by pushing to eliminate sulfur from fuels. Lighter sweeter grades of crude oil are cheaper and less complex to refine, requiring less refinery upgrading than heavier higher sulfur content oil. The introduction of IMO2020, which places stringent restrictions on the sulfur content of marine bunker fuels, caused a significant leap in demand for sweeter grades of crude oil from Asian refiners. The production of marine bunker fuel is one of the single largest consumers of heavy higher sulfur content crude oil. Given that the global shipping market is one of the world’s largest fuel consumers, IMO2020 is having a profound effect on demand for lighter sweet crude oils.
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This could cause demand for the heavy crude oil produced by Venezuela, Colombia, Ecuador, and Peru to fall significantly. Many of Venezuela’s crude oil blends have an API gravity of 11º to 24º and sulfur content of 2% or greater, making them highly unattractive in a low emission world. Venezuela’s high breakeven costs, estimated to average $42 to $56 per barrel, coupled with its crumbling domestic oil infrastructure, strict U.S. sanctions, and the pressing need for regime change means a large proportion of its 303 billion barrels of oil reserves will become uneconomic to exploit in a low carbon world. Colombia, which also predominantly produces heavier sour crude oil varieties is experiencing similar headwinds. The Andean country’s key Castilla and Vasconia heavy oil blends have API gravities of 17.7º and 23º while their sulfur content is 1.83% and 1.09% respectively, making them unattractive to refiners seeking to cost-effectively meet emission requirements. The idea of investing in Colombia’s oil industry is even less attractive due to the after-tax breakeven costs of $40 to $45 per barrel and domestic security issues. Peru principal Loreto crude oil has an API gravity of 19.1º and sulfur of 1.05% which, with a breakeven of $37.72 per barrel, reduces the appeal of investing in Peru to foreign energy companies. This is heightened by the ongoing conflict in Peru’s Amazon, where most of its onshore oil industry is located. A distinct lack of social license and community resentment towards Lima are fomenting significant and ongoing civil conflict with protestors blockading and even seizing oilfields and crucial pipeline infrastructure forcing production to cease.
Ecuador is facing similar headwinds as its Napo and Oriente crudes have API gravities of 16.8º and 23.6º and sulfur content of 2.33% and 1.61% respectively and both have high breakeven costs. The Andean country’s Esmeraldas refinery, which is owned by state-controlled PetroEcuador and has only run sporadically for years, is incapable of producing IMO2020 compliant marine bunker fuel unless the end product is blended down with imported lighter sweeter crude oil. This, along with aging domestic energy infrastructure, pipeline outages, and growing community dissent in Ecuador’s Amazon toward the oil industry, considerably reduces the attractiveness of investing in the South American country. Without a significant injection of capital in Ecuador’s failing energy infrastructure, it will become increasingly difficult to exploit its oil reserves of over 8 billion barrels.
The growing momentum to decarbonize the global economy, the accelerating adoption of electric vehicles, and the ever-stricter emission regulations are all weighing heavily on the outlook for fossil fuels. Those factors, coupled with high breakeven costs and elevated geopolitical risk, increase the likelihood of a considerable portion of South America’s oil reserves becoming stranded assets. That can be blamed in some jurisdictions on the poor management of natural resources, a lack of investment in supporting infrastructure, and major political hurdles. As those oil reserves become uneconomic it will have a sharp impact on oil-dependent economies, particularly Venezuela, Colombia, and Ecuador, causing growth to slow.
By Matthew Smith for Oilprice.com
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Those who have been prematurely and flippantly saying that the pandemic has brought peak oil demand closer should think again and accept that this is a myth promoted by militant environmental activists and hydrocarbon asset divestment campaigners and also vested interests. There will neither be a post-oil era nor a peak oil demand either throughout the 21st century and probably far beyond.
As for the Brent crude oil price, it is projected to hit $60 in the first quarter of 2021 rising to $70-$80 by the third quarter invigorated by the strengthening global oil market fundamentals and also by the start of anti-COVID vaccination around the world with the promise that the global economy will soon be back in business.
Prices at $60-$70 will be higher than the average breakeven prices of the major producers in South America. Therefore, no oil assets will be left stranded once prices continue their upward surge (and surge they will).
Argentine’s shale oil industry isn’t going to fare better than the US shale oil industry. It shares with its sister in the United States exceptionally high breakeven prices and depletion rates ranging from 70%-90% in the first year of production. I dare say it will end up bankrupt like its sister in America unless it operates economically and produce sensibly.
Dr Mamdouh G Salameh
International Oil Economist
Visiting Professor of Energy Economics at ESCP Europe Business School, London
Beyond that is the usual Gulf of Mexico which despite the Hurricane risks remains a lot more stable than anything coming out of the Middle East or Russia at the moment.
Brazil off shore and Argentina shale still have yet to be even put to the test.