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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In the U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO), EIA forecasts that the Lower 48 states’ working natural gas in storage will end the 2019–20 winter heating season (November 1–March 31) at 1,935 billion cubic feet (Bcf), with 12% more inventory than the previous five-year average. This increase is the result of mild winter temperatures and continuing strong production. EIA forecasts that net injections during the refill season (April 1–October 31) will bring the total working gas in storage to 4,029 Bcf, which, if realized, would be the largest monthly inventory level on record.
Mild winter temperatures for the current winter have put downward pressure on natural gas prices and led to smaller withdrawals from natural gas into storage. Year-over-year growth in dry natural gas production and natural gas exports—especially liquefied natural gas (LNG)—throughout 2019 also affected natural gas storage levels. On October 11, 2019, the total natural gas in storage surpassed the previous five-year average—an indicator of typical storage levels—for the first time since mid-2017.
The total natural gas in storage at the start of this heating season was 3,725 Bcf on October 31, 2019. EIA expects withdrawals from working natural gas storage to total 1,790 Bcf at the end of March 2020. If realized, this would be the least natural gas withdrawn during a heating season since the winter of 2015–16, when temperatures were also mild.
Injections into and withdrawals from natural gas storage balance seasonal and other fluctuations in consumption. Natural gas demand is greatest in the winter months, when residential and commercial demand for natural gas for space heating increases. Natural gas consumption in the power sector is greatest in summer months, when overall electricity demand is relatively high because of air conditioning.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In the latest STEO, EIA expects the total working natural gas in storage will exceed the previous five-year average for the remainder of 2020, despite declines in dry natural gas production, increases in natural gas consumption in the electric power sector, and increases in natural gas exports. EIA expects monthly natural gas production to decline from last year’s record levels in 2020 as lower natural gas prices reduce incentives for natural gas-directed drilling and as lower crude oil prices reduce incentives for oil-directed drilling and associated gas production.
At the start of February, a major new find was jointly announced by the two largest emirates within the UAE: the oil-rich Abu Dhabi and the ambitious Dubai. Between them, they literally made the world’s largest natural gas discovery since 2005. Located at the border between the two sheikdoms, the Jebel Ali field is estimated to contain some 80 trillion scf of natural gas, the largest global find since the Galkynysh field in Turkmenistan.
Stretching over 5,000 square km, an exploration campaign by Abu Dhabi involving over 10 wells confirmed the enormous discovery in early January 2020. The shallow nature of the onshore reserves should make it easier to extract gas at lower costs, hastening the time-to-market. At current estimated figures, Jebel Ali would be the fourth-largest gas field in the Middle East, behind Qatar’s North Field, Iran’s South Pars and Abu Dhabi’s own Bab field.
The politics of the UAE can be complicated; each emirate is essentially self-governing with federal oversight, which is dominated by Abu Dhabi and Dubai (which always hold the President and Prime Minister roles, according to convention). This essentially means that each emirate has grew quite independently. Fujairah, for example, developed into a bunkering port, while Sharjah went into industry and manufacturing. Dubai is globally famous for its titanic real estate projects, pursued finance, services and media, while Abu Dhabi, the largest and most blessed of all with hydrocarbon resources, turned into an energy powerhouse. Oil & gas wealth in the UAE is mainly in Abu Dhabi; so while the Jebel Ali discovery is a welcome addition for Abu Dhabi, it is a game changer for Dubai, which imports most of its energy needs.
Speculation has raised that possibility that the Jebel Ali field could vault the UAE into gas self-sufficiency, because even Abu Dhabi imports gas. The UAE has a stated goal to be gas independent by 2030. On paper, that’s possible. Abu Dhabi’s ADNOC has agreed to develop the field with Dubai’s gas supplier, the Dubai Supply Authority (DUSUP), with the entire supply will be channel to DUSUP for use in Dubai. Jebel Ali could begin producing gas by 2023, and will likely be distributed domestically through pipeline. The enormous reserves could supply the entire UAE’s gas demand for nearly 30 years, assuming optimal recovery conditions. However, in practice, self-sufficiency might take longer to achieve.
Dubai and indeed, Abu Dhabi are currently reliant on Qatar for their gas supply. An existing sales agreement that expires in 2032 sees Qatar pipe 2 bcf/d of gas to the UAE through Abu Dhabi. The problem is that these neighbours are erstwhile friends. A division in the Middle East between the pro-Saudi Arabia and pro-Iran blocs has caused a rift. Led by Saudi Arabia, several Persian Gulf states including the UAE implemented a diplomatic and trade blockade on Qatar, isolating it. The blockade, slightly weakened, still continues today. Even now, planes flying into Qatar have to make strange manoeuvres when approaching to avoid encroaching on Saudi and UAE airspace. However, the gas supply arrangement remains in place.
And this is where the Jebel Ali discovery could come in handy. Qatar is already on track to be self-sufficient in gas terms by 2025, but will probably honour the Qatar deal until expiration. Dubai has been increasingly reliant on LNG through an FSRU for power generation, but has attempted over the years to kick-start a number of coal or solar-power projects. Jebel Ali won’t kick the addiction, but it could definitely reduce Dubai’s reliance on Qatari gas.
Jebel Ali wasn’t the only recent gas discovery made in the UAE. Further north, the Sharjah National Oil Corp and Italy’s Eni announced a new onshore gas and condensate discovery. Though tiny in comparison to Jebel Ali, some 50 mscf/d of lean gas and condensate. The cumulative effects of these discoveries could make gas self-sufficiency a reality sooner. At this point, the UAE consumes some 7.4 bcf gas per day, while marketed production is some 6.2 bcf/d. An ambitious plan to develop Abu Dhabi’s large gas fields was the rationale behind naming the 2030 self-sufficiency deadline. With the discovery of Jebel Ali, that can now be brought forward by a couple of years at least. And there might even be some left over to be exported as LNG
The UAE Major Gas Projects:
Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b
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