East Timor and Australia are friends again. But a grudging friendship for mutual benefit that replaces the outright animosity that existed before. And like most fallouts, it revolved around money.
In 1974, the collective Greater Sunrise fields were discovered in the Timor Gap, an area of the Timor Sea that lies between Australia and then-Portuguese colony East Timor. With estimated reserves of some 5.13 tcf of natural gas – equivalent to about a third of current global LNG consumption – it is a jewel that is begging to be developed. However, Indonesia invaded East Timor – which had only enjoyed independence from Portugal for 9 days – and administered it until 2002; among the many things it conducted on ‘behalf’ of the Timorese was to agree on a maritime border with Australia.
As it finally became independent in 2002, the new East Timor (Democratic Republic of Timor-Leste) needed new friends. Indonesia wasn’t the best option, so it turned to Australia, its largest international supporter. But the riches in the Timor Sea proved too vast. Although the young and naïve East Timor did agree on treaties governing joint development of the Timor Gap and Greater Sunrise, it also asserted that it did not recognise the maritime border agreed by Indonesia with Australia. Rather, it argued for a border that is equi-distance between East Timor and Australia; a move that would put Greater Sunrise within Timorese waters. Alarmed by this, Australia’s government sanctioned placing bugs within the Timorese cabinets to monitor discussions. And just as Greater Sunrise was on the verge of finally being developed, the scandal broke… followed by years of argument and accusations.
That has been put aside for now. East Timor dropped its suit against Australia at the Permanent Court of Arbitration last year, and last week signed a new treaty that redraws their maritime boundary*. This formally ends the dispute over the border. It, however, does not set out terms of the actual field development, preferring to leave that up to the Greater Sunrise consortium of Woodside, ConocoPhillips, Shell and Osaka Gas – East Timor will receive at least 70% of Greater Sunrise revenues, up to 80% depending on where the gas is processed. The decision is particularly pertinent for East Timor, as its Bayu Undan field – the only major gas production field in operation – is set to be depleted by 2022. From friends to enemies to friends again, Australia has sought to re-assure all parties that no clandestine shenanigans were involved this time.
*On 6 March 2018, Australia’s Minister for Foreign Affairs, the Hon Julie Bishop MP, and Timor-Leste’s Minister in the Office of the Prime Minister for the Delimitation of Borders and the Agent in the Conciliation, His Excellency Mr Hermenegildo Pereira, signed the Treaty Between Australia and the Democratic Republic of Timor-Leste Establishing Their Maritime Boundaries in the Timor Sea [PDF 592 KB]. The treaty was signed in New York at the United Nations Headquarters in the presence of the United Nations Secretary-General and the Chair of the Conciliation Commission.
"Frenemy" (less commonly spelled "frienemy") is an oxymoron and a portmanteau of "friend" and "enemy" that refers to "a person with whom one is friendly, despite a fundamental dislike or rivalry" or "a person who combines the characteristics of a friend and an enemy". https://en.wikipedia.org/wiki/Frenemy
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The week started off ominously. Qatar, a member of OPEC since 1960, quit the organisation. Its reasoning made logical sense – Qatar produces very little crude, so to have a say in a cartel focused on crude was not in its interests, which lie in LNG – but it hinted at deep-seated tensions in OPEC that could undermine Saudi Arabia’s attempts to corral members. Qatar, under a Saudi-led blockade, was allied with Iran – and Saudi Arabia and Iran were not friends, to say the least. This, and other simmering divisions, coloured the picture as OPEC went into its last meeting for the year in Vienna.
Against all odds, OPEC and its NOPEC allies managed to come to an agreement. After a nervy start to the conference – where it looked like no consensus could be reached – OPEC+ announced that they would cut 1.2 mmb/d of crude oil production beginning January. Split between 800,000 b/d from OPEC members and 400,000 b/d from NOPEC, the supply deal contained a little bit of everything. It was sizable enough to placate the market (market analysts had predicted only a 800,000 b/d cut). It was not country-specific (beyond a casual mention by the Saudi Oil Minister that the Kingdom was aiming for a 500,000 b/d cut), a sly way of building in Iran’s natural decline in crude exports from American sanctions into the deal without having individual member commitments. And since the baseline for the output was October production levels, it represents pre-sanction Iranian volumes, which were 3.3 mmb/d according to OPEC – making the mathematics of the deal simpler.
Crude oil markets rallied in response. Brent climbed by 5%, breaking a long losing streak, as the market reacted to the move. But the deal doesn’t so much as solve the problem as it does kick the can further down the road. A review is scheduled for April; coincidentally (or not), American waivers granted to eight countries on the import of Iranian crude expire in May. By April, it should be clear whether those will continue, allowing OPEC+ to monitor the situation and the direction of Washington’s policy against Iran in a new American political environment post-midterm elections. If the waivers continue, then the deal might stick. If they don’t, then OPEC+ has time to react.
There are caveats as well. OPEC members, who are shouldering the bigger part of the burden, said there would be ‘special considerations’ for its members. Libya and Venezuela - both facing challenging production environments – received official exemptions from the new group-level quota. Nigeria, exempted in the last round, did not. Iran claims to have been given an exemption but OPEC says that Iran had agreed to a ‘symbolic cut’ – a situation of splitting hairs over language that ultimately have the same result. But more important will be adherence. The supply deals of the last 18 months have been unusual in the high adherence by OPEC members. Can it happen again this time? Russia – which is rumoured to be targeting a 228,000 b/d cut – has already said that it would take the country ‘months’ to get its production level down to the requested level. There might be similar inertia in other members of OPEC+. Meanwhile, American crude output is surging and there is a risk to OPEC+ that they will be displaced out of their established markets. For now, OPEC remains powerful enough to sway the market. How long it will remain that way?
Infographic: OPEC+ December Supply Deal
Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b
Headlines of the week
The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects