Last week in the world oil:
- With news filtering out that major OPEC members were preparing to enforce the new supply quotas, crude oil prices are marching upwards to the mid-US$50/b level, raising hopes that the trajectory was on the mend and US$60/b levels could be seen in the first half of 2017
Upstream & Midstream
- Libya’s National Oil Corporation has confirmed that the Sharara and El Feel oil field pipelines have re-opened after two years, adding 175 kb/d to national production in January and up to 270 kb/d by May 2017. Production in Libya has been hampered by political conflict, with output languishing at 600 kb/d, far off average figures of 1.6 mmb/d in 2011.
- Faced with a stubborn Saudi Arabia refusing to resume shipments of oil products, Egypt is looking for alternatives to solve it energy deficiency. It is now speaking with Iraq to directly import crude amounting to 1-2 million barrels per month, hoping to finalise the details by Q12017.
- Another 16 rigs came online in the US, 13 of which were oil rigs, as American shale producers happily respond to the positive price signals.
- Mexico has set a timetable for fuel price liberalisation, beginning in March to roll out on a staggered basis over the rest of the year. Gasoline and diesel prices have been set by the government for decades and the move is part of a larger energy reform movement that began in 2013. The rollout begin in the northwestern Baja California and Sonora states, then move south to the main consumption areas and finally to the Yucatan.
- Shell continues its divestment at a rapid pace, last week agreeing to sell its 20% stake in Vivo Energy to Vitol Africa for US$250 million. Vivo Energy will retain the rights to marketing and distributing fuels in 16 African nations under the Shell brand.
Natural Gas & LNG
- BP seems to be aggressively expanding on the natural gas front. After purchasing a stake in the Zohr field in Egypt and sanctioning an expansion in Indonesia’s Tangguh LNG last month, BP has now purchased stakes in West African licences held by US player Kosmos Energy. In a deal worth US$916 million, BP has acquired interest in offshore blocks in Mauritania and Senegal, as it tries to play catch-up with rival Shell.
- France’s Total is also pushing ahead, acquiring a stake in Houston-based Tellurian share, that will see it partner with Tellurian to develop the Driftwood LNG terminal in Lousiana due to start up in 2022.
- Phillips 66 has started up its Freeport LPG Export Terminal, loading its first cargo on a VLGC last week. The startup is part of a wider expansion of the US natural gas liquids infrastructure, including ethane and LPG (propane and butane), which much of the volumes destined for Asia.
- BP has agreed to take a 10% stake in the Adco onshore oil concession for 40 years, with Abu Dhabi government gaining a 2% stake in the supermajor. The deal is part of Adnoc’s aim to secure 40% foreign funding in the Adco concession, with stakes already held by France’s Total (10%), Japan’s Inpex (5%) and South Korea’s GS Caltex (3%).
Last week in Asian oil:
Upstream & Midstream
- The shine seems to be coming off Australian upstream. The results of the country’s latest licensing round are out, and only nine of the 29 offshore oil and gas exploration permits have been taken up. With some of sites in the prodigious Bonaparte, Browse, Carnarvon and Roebuck basins, the low take up is symptomatic of the recent more cautious approach in E&P.
Downstream & Shipping
- A major Chinese independent refiner is opening up a trading office in Singapore next year, as the teapots leverage the opportunity granted to them by crude import quotas this year to go global. A Singapore trading desk would make it easier for Sinochem Hongrun Petrochemical to acquire crude on the open market, and could also have allowed it to trade refined products, although the Chinese government has clamped down on that by rescinding export quotas for the teapots next year. Another teapot, Shandong Hengyuan Petrochemical, acquired a 51% stake in Shell’s 156 kb/d Port Dickson refinery in Malaysia for US$66.3 million.
- Mongolia is seeking funds from India to build an oil refinery and associated pipeline infrastructure, hoping to garner US$1 billion from the Import-Export Bank of India in an infrastructure funding pact sealed by Prime Minister Narendra Modi last year. Of the number, US$700 million is earmarked for building the refinery and US$264 million for oil pipelines.
- Vietnam has allowed retail prices of gasoline, diesel and other products to rise for a second time in less than a month, hiking controlled prices by 6.7% last week due to increases in crude prices. Retail fuel prices are controlled by the government in Vietnam, implemented by state distributor Petrolimex, though prices are still relatively lower than the global average, with diesel and gasoline at 12,670 and 17,590 dong (US$0.56 and US$0.77) per litre with the latest hike.
Gas & LNG
- ExxonMobil’s bid to take over InterOil as part of its grand plans for Papua New Guinea LNG has hit more road blocks. Although most InterOil shareholders approved the deal, founder Phil Mulacek is not happy and has launched (successful) legal bids to scupper the deal, with the Court of Appeal in Yukon, Canada halting the deal. ExxonMobil’s offer to raise its bid to as high as US$3.9 billion does not seem to have satisfied Mulacek and the parties now have until March 31, 2017 to rescue the deal.
- Idemitsu has completed it purchase of a stake in rival refiner Showa Shell Sekiyu. However, due to opposition from the founding family of Idemitsu, the purchase was trimmed to just under a third of the shares, and places the longer-term goal of a merger as less possible given the obstruction.
- Chevron is divesting its geothermal assets in Southeast Asia. Once a promising area of investment, low oil prices have removed some of the shine from geothermal energy. The Ayala Corporation of the Philippines has agreed to acquire Chevron’s geothermal assets in Indonesia and the Philippines, valued at US$3 billion. Ayala is in the power generation business in the Philippines, and this would also represent its first investment in Indonesia.
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It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.
This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.
The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.
It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.
The Abadi LNG Project:
Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b
Headlines of the week
Midstream & Downstream
A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.
That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.
That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.
Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.
Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?
Expectations at the 176th OPEC Conference