Events that happen today don’t always show their impact until later. Sometimes much, much later. Tsunamis can occur several hours after the initial earthquake. And, as much as markets have access to an over-abundance of information, the impacts of trends currently happening on the ground (or rather, under the ground) aren’t always obvious until they hit.
Take US crude production, for example. The story over 2018 and 2019 was the quick acceleration of American crude output, powered by the shale revolution. The US has now overtaken Saudi Arabia and Russia as the world’s number 1 oil producer. Total production blasted past the 12 mmb/d level in 2018, and heady forecasts predicted that output could comfortably reach 14 mmb/d by the end of 2020. The amount of US crude flowing – onshore and offshore – has upended world crude price dynamics, and also bestowed cheap fuel on the US, powering its economy. The trends have also spilled over in the gas markets, where the US is currently enjoying historically low natural gas prices domestically and in the process of transforming itself a major LNG exporter.
To assume this will continue is a fallacy. The scenario occurring today is happening because of what happened several years ago. Looking at the data of active US oil rigs available from Baker Hughes – which is taken as a proxy for the level of upstream activity in the country – and the US crude production numbers from the EIA shows an evident lag between the two indicators. There appears to be a two-year lag between activities in the drilling sector with impact on output. Between December 2016 and December 2017, when the active oil rig count increased by 272, crude oil production only increased by 1.18 mmb/d; but between December 2017 and December 2018, crude oil production jumped by 2.06 mmb/d. Between December 2017 and December 2018, when the active oil rig count growth slowed down to 128, crude oil production growth also slowed down to only 800,000 b/d between December 2018 and estimates for November 2019.
To be fair, there are many other factors that impact production. But the active oil rig count is a significant indicator, and indeed predictor, of future output. Which is why current trends in the US active rig count are worrying. Between December 2018 and November 2018, Baker Hughes reports that the active oil rig count in the US declined by 206 – a 31-month low. And the decline seems chronic. Within that data, much of that decline comes from onshore rigs, particularly in the Permian and Eagle Ford basins. At current trends, the oil rig count could fall below 600 by early 2020. Given that shale fields have a prolific initial production period, followed by a sharp decline, this is worrying. US oil production could actually decline in late 2020, early 2021.
Of course, there are other things to consider. Consolidation is ongoing in the Permian, which may be reducing rig count but increasing productivity. With the investment community has turned against shale, drying up capital, some small- and medium-scale drillers are going bust. These assets, sometimes in high-opportunity areas, are being plucked off, as the big guys – the ExxonMobils, the Chevrons and the BPs – move in. There are many reasons why the active rig count might be dropping, but the main reasons remains that drilling just isn’t as attractive anymore. That itself will never translate 1-to-1 to production trends, but it will have a definite material impact. A reversal in US oil production growth is unlikely; what’s more likely is that the explosive growth will slow down. In fact, it already is. An average production level of 13 mmb/d is still achievable within six months, but the 14 mmb/d level looks very far off. Don’t be fooled by the surface image of current US oil output. Trying times are coming, and if you paid attention to the indicators, you would have known it is coming… and can prepare for it.
US Active Oil Rig Count vs US Crude Production
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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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