In April 2018, the Northern Territories of Australia lifted a ban on fracking that has been in place since 2016. It is a move that has had energy companies salivating, tempted by sky-high estimates of shale gas and oil trapped deep underneath the Outback. It is also one few of the Australian territories to embrace fracking after massive opposition on environmental and social grounds, which has already seen fracking banned by legislation in most places in Australia.
Why is this happening? With a massive onshore area, Australia is known to be onshore gas-rich. Tapping into this has long been the ambition of the country’s energy players, but they have had to face an organised grassroots and political opposition that has campaigned to prevent fracking from taking place, citing issues over water pollution, geological stability and environmental impact. Add to this conundrum of Australia’s internal supply/demand balance – where the country as a whole is a major exporter of LNG through the giant offshore projects in Western Australia, while the more industrialised and populous East and Southeast face a domestic gas crunch.
Origin Energy is hoping that it will be able to solve these issues, while proving that responsible fracking can assuage citizenry concerns and showcase it as a ‘good energy player’. It has announced plans to drill two new wells in the Beetaloo Basin this year; named after a cattle ranch the size of Hawai’i, Beetaloo has been called the ‘best immediate prospect’ the replacing dwindling gas from the Bass Strait in Victoria state. An estimate suggests that Beetaloo holds some 500 trillion cubic feet of gas, a size that would put it on par with pioneering US shale basins like Marcellus and Barnett. Drilling that occurred prior to 2016 suggested a recoverable resource of 6.6 tcf, which alone would be enough to supply an LNG export train for 20 years. The new round of drilling – at the liquids-rich Kyalla and Velkerri shale plays – is aimed to looking for liquids, the sort of shale oil that has been found in onshore USA and that truly revolutionised the industry there.
Origin Energy (and its partner Falcon Oil & Gas) isn’t the only player in Northern Territories shale. Fellow Australian player Santos is also looking to start drilling in the NT McArthur basin this year, having already submitted its environmental management plan to the NT government after calling it the ‘largest and most promising shale gas opportunity in Australia.’ If any of this gas (that is yet-to-be-explored) makes it to commercialisation, it will come to market around 2024-2025 at the earliest – just in time to stave off the chronic shortage of natural gas on the east coast.
But it won’t be easy. Even if the shale gas and shale liquids are commercially viable, the Beetaloo and McArthur basins are – to put it simply – in the middle of nowhere. Origin Energy’s permit area is roughly three times the size of Singapore in area with little human activity beyond farming. It is also some 2,500 kilometres away from Sydney and the closest industrial applications that would require that gas, necessitating a massive expansion of cross-state gas transmission networks and pipelines. Connection to Darwin and its port facilities is also possible, sending the gas overseas or within Australia as LNG, but that too will require significant investment of at least A$1.5 billion. In that sense, the issues facing Australian shale are not different from that faced by US shale: there is plenty of gas. Getting it out of the ground is the easier part; getting it to market is the far harder part.
The Beetaloo and McArthur Shale Basins:
- 600km southeast of Darwin, ~30,000 square kilometres
- Holds an estimated 70% of total shale gas resources in the Northern Territories
- Origin Energy/Falcon Oil & Gas hold exploration permits for EP76, EP98 and EP 117 (covering 4.6 million acres)
- 500km southeast of Darwin, ~180,000 square kilometres
- Very high unconventional oil and gas potential’, particularly in the Barney Creek Formation
- Santos holds exploration permits for EP161, EP162, EP189 and EP(A)288
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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: