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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Headline crude prices for the week beginning 20 May 2019 – Brent: US$73/b; WTI: US$63/b
Headlines of the week
Midstream & Downstream
At first, it seemed like a done deal. Chevron made a US$33 billion offer to take over US-based upstream independent Anadarko Petroleum. It was a 39% premium to Anadarko’s last traded price at the time and would have been the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. The deal would have given Chevron significant and synergistic acreage in the Permian Basin along with new potential in US midstream, as well as Anadarko’s high potential projects in Africa. Then Occidental Petroleum swooped in at the eleventh hour, making the delicious new bid and pulling the carpet out from under Chevron.
We can thank Warren Buffet for this. Occidental Petroleum, or Oxy, had previously made several quiet approaches to purchase Anadarko. These were rebuffed in favour of Chevron’s. Then Oxy’s CEO Vicki Hollub took the company jet to meet with Buffet. Playing to his reported desire to buy into shale, Hollub returned with a US$10 billion cash infusion from Buffet’s Berkshire Hathaway – which was contingent on Oxy’s successful purchase of Anadarko. Hollub also secured a US$8.8 billion commitment from France’s Total to sell off Anadarko’s African assets. With these aces, she then re-approached Anadarko with a new deal – for US$38 billion.
This could have sparked off a price war. After all, the Chevron-Anadarko deal made a lot of sense – securing premium spots in the prolific Permian, creating a 120 sq.km corridor in the sweet spot of the shale basin, the Delaware. But the risk-adverse appetite of Chevron’s CEO Michael Wirth returned, and Chevron declined to increase its offer. By bowing out of the bid, Wirth said ‘Cost and capital discipline always matters…. winning in any environment doesn’t mean winning at any cost… for the sake for doing a deal.” Chevron walks away with a termination fee of US$1 billion and the scuppered dreams of matching ExxonMobil in size.
And so Oxy was victorious, capping off a two-year pursuit by Hollub for Anadarko – which only went public after the Chevron bid. This new ‘global energy leader’ has a combined 1.3 mmb/d boe production, but instead of leveraging Anadarko’s more international spread of operations, Oxy is looking for a future that is significantly more domestic.
The Oxy-Anadarko marriage will make Occidental the undisputed top producer in the Permian Basin, the hottest of all current oil and gas hotspots. Oxy was once a more international player, under former CEO Armand Hammer, who took Occidental to Libya, Peru, Venezuela, Bolivia, the Congo and other developing markets. A downturn in the 1990s led to a refocusing of operations on the US, with Oxy being one of the first companies to research extracting shale oil. And so, as the deal was done, Anadarko’s promising projects in Africa – Area 1 and the Mozambique LNG project, as well as interest in Ghana, Algeria and South Africa – go to Total, which has plenty of synergies to exploit. The retreat back to the US makes sense; Anadarko’s 600,000 acres in the Permian are reportedly the most ‘potentially profitable’ and it also has a major presence in Gulf of Mexico deepwater. Occidental has already identified 10,000 drilling locations in Anadarko areas that are near existing Oxy operations.
While Chevron licks its wounds, it can comfort itself with the fact that it is still the largest current supermajor presence in the Permian, with output there surging 70% in 2018 y-o-y. There could be other targets for acquisitions – Pioneer Natural Resources, Concho Resources or Diamondback Energy – but Chevron’s hunger for takeover seems to have diminished. And with it, the promises of an M&A bonanza in the Permian over 2019.
The Occidental-Anadarko deal:
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.