The Baker Hughes US oil rig count – a proxy for health and optimism in the overall upstream sector – has just reached a 31-month high to 1067 rigs, though nowhere near the all-time high of 1609 back in July 2014. This recent development is not surprising; crude prices have been trending upwards and reached a new 24-month peak last week as well.
Looking at the breakout data, it is possible that some of the gains could be from re-started sites shut down in the wake of Hurricane Michael bypassing the Gulf Coast, but the main additions are still coming from onshore Texas. The home to the mammoth Permian and the Eagle Ford shale basins, the Permian alone has 490 active oil and gas rigs. While infrastructural bottlenecks – mainly restrained pipeline capacity – have caused drilling activities to slow down since June, there are still gains to be made. Meanwhile, the lower prices caused by shale liquids being trapped in the Permian has led drillers to look elsewhere, where prices are stronger and infrastructure less clogged up – including re-looking at the Bakken and promising areas like Austin Chalk and Niobrabra. Recent auctions have seen record-high prices for acreage in Louisiana and Alabama; even in the Permian, interest remains high, with a recent sale in the New Mexican side of the basin setting a new record of more than double the previous high.
This could be key to navigating the coming global supply crunch, triggered by new American sanctions on Iran, and exacerbated by continuing problems in key OPEC producers such as Venezuela and Libya. Although Russia has raised its production and Saudi Arabia has pledged to fill the hole that Iranian crude will be leaving, the assassination of Jamal Khashoggi places the Kingdom in a position of belligerence with the rest of the world. So the US may find itself in a position to have to provide extra volumes on its own – which may be why active rigs have been increasing, and new areas being sought. There is a bit of a spanner in the works, though. The trade spat between the USA and China has led Chinese importers to slam the brakes on importing US crude, even though American crude is not yet on the list of products tariffed by China. LNG and even NGLs – propane and ethane imported to produce petrochemicals – have also seen significant slowdown.
How high can the American rig count get? If prices continue to march up – and there are many that believe the US$100/b mark will be reached soon – then the number of oil rigs drilling in the US could rise past 1200 again. But to reach the dizzying heights above 1500, which was the average over most of 2014, is unlikely. Not because there are lesser volumes of liquid underground – although studies are now showing that the decline rate in mature shale fields is alarmingly high – but because of consolidation. From a collection of many, many small players in the early 2010s, the shale landscape now is consolidating into a collection of medium and large players, with behemoths like ExxonMobil, Chevron and BP also muscling in. A rising tide of crude prices is lifting American drilling activity, but the magnitude of gains in 2018 will be different – due to a combination of infrastructure bottlenecks, fragile geopolitics and sector structural changes.
The main danger is short memories – the zeal of cashing in on high oil prices is what caused the 2015 crash and high corporate debt, and the enthusiasm brewing in American shale again could lead to history repeating itself.
Baker Hughes US Active Rig Count:
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Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.
Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.
When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.
This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.
In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.
The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.
By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)
Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b
Headlines of the week
Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership: