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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According to the Nigeria National Petroleum Corporation (NNPC), Nigeria has the world’s 9th largest natural gas reserves (192 TCF of gas reserves). As at 2018, Nigeria exported over 1tcf of gas as Liquefied Natural Gas (LNG) to several countries. However domestically, we produce less than 4,000MW of power for over 180million people.
Think about this – imagine every Nigerian holding a 20W light bulb, that’s how much power we generate in Nigeria. In comparison, South Africa generates 42,000MW of power for a population of 57 million. We have the capacity to produce over 2 million Metric Tonnes of fertilizer (primarily urea) per year but we still import fertilizer. The Federal Government’s initiative to rejuvenate the agriculture sector is definitely the right thing to do for our economy, but fertilizer must be readily available to support the industry. Why do we import fertilizer when we have so much gas?
I could go on and on with these statistics, but you can see where I’m going with this so I won’t belabor the point. I will leave you with this mental image: imagine a man that lives with his family on the banks of a river that has fresh, clean water. Rather than collect and use this water directly from the river, he treks over 20km each day to buy bottled water from a company that collects the same water, bottles it and sells to him at a profit. This is the tragedy on Nigeria and it should make us all very sad.
Several indigenous companies like Nestoil were born and grown by the opportunities created by the local and international oil majors – NNPC and its subsidiaries – NGC, NAPIMS, Shell, Mobil, Agip, NDPHC. Nestoil’s main focus is the Engineering Procurement Construction and Commissioning of oil and gas pipelines and flowstations, essentially, infrastructure that supports upstream companies to produce and transport oil and natural gas, as well as and downstream companies to store and move their product. In our 28 years of doing business, we have built over 300km of pipelines of various sizes through the harshest terrain, ranging from dry land to seasonal swamp, to pure swamps, as well as some of the toughest and most volatile and hostile communities in Nigeria. I would be remiss if I do not use this opportunity to say a big thank you to those companies that gave us the opportunity to serve you. The over 2,000 direct staff and over 50,000 indirect staff we employ thank you. We are very grateful for the past opportunities given to us, and look forward to future opportunities that we can get.
Headline crude prices for the week beginning 15 July 2019 – Brent: US$66/b; WTI: US$59/b
Headlines of the week
Unplanned crude oil production outages for the Organization of the Petroleum Exporting Countries (OPEC) averaged 2.5 million barrels per day (b/d) in the first half of 2019, the highest six-month average since the end of 2015. EIA estimates that in June, Iran alone accounted for more than 60% (1.7 million b/d) of all OPEC unplanned outages.
EIA differentiates among declines in production resulting from unplanned production outages, permanent losses of production capacity, and voluntary production cutbacks for OPEC members. Only the first of those categories is included in the historical unplanned production outage estimates that EIA publishes in its monthly Short-Term Energy Outlook (STEO).
Unplanned production outages include, but are not limited to, sanctions, armed conflicts, political disputes, labor actions, natural disasters, and unplanned maintenance. Unplanned outages can be short-lived or last for a number of years, but as long as the production capacity is not lost, EIA tracks these disruptions as outages rather than lost capacity.
Loss of production capacity includes natural capacity declines and declines resulting from irreparable damage that are unlikely to return within one year. This lost capacity cannot contribute to global supply without significant investment and lead time.
Voluntary cutbacks are associated with OPEC production agreements and only apply to OPEC members. Voluntary cutbacks count toward the country’s spare capacity but are not counted as unplanned production outages.
EIA defines spare crude oil production capacity—which only applies to OPEC members adhering to OPEC production agreements—as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices. EIA does not include unplanned crude oil production outages in its assessment of spare production capacity.
As an example, EIA considers Iranian production declines that result from U.S. sanctions to be unplanned production outages, making Iran a significant contributor to the total OPEC unplanned crude oil production outages. During the fourth quarter of 2015, before the Joint Comprehensive Plan of Action became effective in January 2016, EIA estimated that an average 800,000 b/d of Iranian production was disrupted. In the first quarter of 2019, the first full quarter since U.S. sanctions on Iran were re-imposed in November 2018, Iranian disruptions averaged 1.2 million b/d.
Another long-term contributor to EIA’s estimate of OPEC unplanned crude oil production outages is the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. Production halted there in 2014 because of a political dispute between the two countries. EIA attributes half of the PNZ’s estimated 500,000 b/d production capacity to each country.
In the July 2019 STEO, EIA only considered about 100,000 b/d of Venezuela’s 130,000 b/d production decline from January to February as an unplanned crude oil production outage. After a series of ongoing nationwide power outages in Venezuela that began on March 7 and cut electricity to the country's oil-producing areas, EIA estimates that PdVSA, Venezuela’s national oil company, could not restart the disrupted production because of deteriorating infrastructure, and the previously disrupted 100,000 b/d became lost capacity.