Easwaran Kanason

Co - founder of PetroEdge
Last Updated: October 5, 2018
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Business Trends
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In landmark deal, ConocoPhillips has agreed to sell its 30% stake in the Greater Sunrise natural gas and condensate fields in the East Timor Sea to the government of East Timor for US$350 million. For the first major company to enter the fledgling nation back in 2006, ConocoPhillips has spearheaded much of the upstream developments in Timor-Leste, as the country is also known, which still form the backbone of its economy. With the great prizes waiting in Greater Sunrise, why this sale and why now?

Because the tectonic plates powering Timorese upstream has shifted. After years of disagreements – including a spying scandal that was taken to the international court – Timor-Leste and Australia signed a historic treaty this year in March. The deal settled the dispute over the maritime boundary between the two countries, delineating the sea and the position of the Greater Sunrise fields officially for the first time. Estimates suggest that up to US$65 billion in potential reserves lie within Greater Sunrise, and for East Timor, developing this is necessary to replace its maturing Bayu Undan condensate field. Though the issue of whether the gas should be piped to East Timor or Australia for processing remains yet resolved, the sale by ConocoPhillips can be seen as a move to bolster the position of the government in the development of the field.

With Asia’s appetite for LNG unabating, the government of East Timor wants to push for an onshore LNG liquefaction plant in the country, included associated pipelines and an FPSO. In a statement following the sale, ConocoPhillips notes that it ‘differed with the government on its proposed development plan for Sunrise but we recognise the importance of the field to the nation’ – perhaps a veiled reference that ConocoPhillips would prefer the option of piping the gas to Australia, seen as the more viable and economic action but that its hand was forced. The Sunrise and Trobadour fields that form Greater Sunrise are geographically closer to East Timor, but building a debut LNG project of a scale required of Greater Sunrise is seen as a major risk, but also a matter of grave national importance. It certainly gives an opportunity for Timor GAP – the state oil firm – more say in the development of the field, bringing it to the table with other partners in the Greater Sunrise project including Woodside, Shell and Osaka Gas. As operator, Woodside has a preference for an FLNG processing plant, similar to Shell’s Prelude, but as the second-largest partner in the joint venture, the government may now dictate otherwise.

More squabbles will follow, but this move changes up the dynamics of the project in favour of the tiny nation. The next step is to create a viable development plan that will appease all project partners, and that is the harder part. But one thing is for certain; the commercialisation of Greater Sunrise has now closer to reality, more than four decades after it was discovered.

About The Greater Sunrise Fields

  • Discovered in 1974
  • Resources estimated to include 5.1 tcf of LNG and 226 million barrels of condensate
  • Partners: Woodside Petroleum (33.44%), Government of Timor-Leste (30%), Royal Dutch Shell (26.56%), Osaka Gas (10%)
  • Location: 150km southeast of East Timor, 450km northwest of Darwin

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OPEC+ Prevails, For Now

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

  • OPEC – 800,000 b/d cut from Oct 2018 levels, Saudi Arabia to cut 500,000 b/d
  • Non-OPEC – 400,000 b/d cut from Oct 2018, Russia to cut 228,000 b/d
  • Total – 1.2 mmb/d cut from Oct 2018, Saudi Arabia and Russia to cut 728,000 b/d
December, 15 2018
Your Weekly Update: 10 - 14 December 2018

Market Watch

Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b

  • Crude prices strengthened at the start of this week, with OPEC delivering an agreement that will see production across the OPEC+ alliance decline by 1.2 mmb/d beginning January 2019
  • Two-thirds or 800,000 b/d of the cut will be borne by OPEC – with most of it taken up by Saudi Arabia – while the non-OPEC group will take up a cut of 400,000 b/d, most of which will be taken up by Russia
  • Skepticism has reigned before the supply deal was reached, as the first day of the OPEC meeting in Vienna closed without consensus and the threads holding OPEC together showed some stress when Qatar decided to quit the group
  • Crude prices were also boosted by Libya declaring force majeure at its largest oil field at El Sharara over arm protests, while Canada’s Alberta province announced plans to pare back some 325,000 b/d of output to ease a huge glut
  • The coordinated supply deal by OPEC ‘was not easy’ according to UAE Minister of Energy and Industry, with Iran in particular balking at being asked to sign up to a symbolic cut; this might not augur well for future supply deals that might be necessary given current trends
  • However, the supply cut will only last until April 2019, when the terms are due for a review, which would give OPEC+ enough time to consider and deal with the expiration of American waivers for eight countries over continued import of Iranian crude in May
  • Meanwhile, America became a net oil exporter for the first time in almost 75 years, as the unprecedented boom in US crude oil fuelled by the shale revolution powers on, a development that could dilute OPEC+’s attempt to support global crude prices
  • The recent weakening of WTI prices saw the US lose 10 active oil rigs last week, however, the addition of 9 new gas rigs led to a net loss of only 1 in the Baker Hughes active US rig count
  • Crude price outlook: OPEC+’s decision might have provided some relief, but may not be enough to keep crude oil prices trending upwards. Expect prices to moderate to US$60-61/b for Brent and US$50-51/b for WTI

Headlines of the week

Upstream

  • ExxonMobil’s winning streak in Guyana continues, as it announces its 10th offshore discovery at the Pluma-1 well, boosting estimated recoverable resources in the Stabroek block by almost 1 mmb/d to over 5 mmb/d
  • Apache has initiated production at the Garten field in the UK North Sea, with an output rate of 13,700 b/d and 15.7 bcf/d of natural gas
  • Chevron has raised its capital expenditure for the first time since 2014 into US$20 billion, with a major focus on expanding operations in the Permian Basin as well as on the Tengiz megaproject in Kazakhstan
  • Canada’s Alberta province, weighed down by a supply glut caused by pipeline bottlenecks, has announced moves to reduce the region’s output by 325,000 b/d
  • Equinor and Faroe Petroleum have agreed to trade a number of assets in the Norwegian Sea and the Norwegian Continental Shelf North Sea, encompassing the Njord, Bauge Hyme, Vilje Ringhome, Marulk and Alve fields, with the deal described as a ‘balanced swap’ in terms of value with no cash consideration

Downstream

  • CNPC’s US$9.53 billion joint venture integrated 400 kb/d petrochemicals/refinery project with PDVSA in Jieyang, China has been reactivated, and is now expected to begin operations in late 2021
  • French president Emmanuel Macron has backtracked and suspended a planned fuel-tax hike, after weeks of violent riots by the so-called Yellow Vests grassroot groups of up to 300,000 protestors
  • Limetree Bay Ventures has secured US$1.25 billion in financing that paves the way for the Limetree Bay refinery in the US Virgin Islands to restart after being idled for years, partnering with BP Products North America on the project

Natural Gas/LNG

  • Equinor has received permission from the Norwegian government to proceed with the development of Troll Phase 3, delivering an additional 2.2 billion boe/d of natural gas with a planned start-up timeframe of 1H2021
  • Shell has completed the construction of Gibraltar’s first LNG regasification facility, a small-scale project that will feed a new power plant in the territory
  • Trinidad and Tobago has agreed to allow BP and Shell to extend the operational life of the Atlantic LNG Train 1 in Point Fortin by five years, with the country receiving the ability to sell LNG cargoes through its state gas firm
  • Tokyo Gas and the Philippines’ First Gen Corporation have signed a joint development agreement to build and operate an LNG receiving terminal, as the three-horse race narrows over the country’s first LNG import facility
  • American LNG player Tellurian has agreed to supply trader Vitol with some 1.5 mtpa of LNG over 15 years from its 27.6 mtpa Driftwood LNG export terminal currently being developed in Calcasiue River, Louisiana
  • Tanzania is opening talks with Equinor and ExxonMobil to launch the East African nation’s first LNG project, likely to derive gas from the Equinor-operated offshore Block 2
  • Shell is expecting to produce its first cargo of LNG from its Prelude FLNG facility in Australia before the end of 2018
December, 14 2018
Permian’s Pipeline Lifeline

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

  • September 2018 – EPIC Midstream Holdings – 675,000 b/d, 1125km, 24-30’ diameter, 4Q19 target opening
  • November 2018, Wolf Midstream Partners – 500,000 b/d, 65km, 16’ diameter, 2H2019 target opening
  • November 2018, Jupiter Energy – 1 mmb/d, 1050km, 36’ diameter, 2020 target opening
  • December 2018, Plains All American Pipeline – 575,000 b/d, 830km, 26’ diameter, 3Q19 target opening
December, 04 2018