Oil is on the defensive again, retracing from resistance in recent days amid bearish U.S.-centric data of rampant production increases. Despite the Good Friday holiday, we get the EIA inventory report at the usual time tomorrow, but for now, hark, here are six things to consider in oil markets today:
1) As oil prices based on the Dubai-Oman benchmark remain more expensive than U.S.-based WTI, Latin American crude continues to be pulled towards Asia. This is displacing other flows, translating into lower U.S. imports. We are over halfway through the month, and imports from Central and South America are at the slowest monthly pace on our records.
Our ClipperData show that imports this month continue to drop from Brazil and Colombia, while Ecuadorian grades, Napo and Oriente, are completely absent. Only Venezuelan grades are showing strength versus the month prior:
2) The latest monthly IEA report has been interpreted as somewhat downbeat, despite the prognostication that 'the market is already very close to balance'. This is because demand growth has been adjusted lower by 200,000 bpd in Q1, and by 100,000 bpd for 2017 on the whole, to +1.3mn bpd.
While Asian fuel demand has been the backbone of oil demand growth for many a year, signs of stuttering from various parts of the region - including South Korea, Japan and India - means demand growth may not be as robust as we have come to expect.
The second piece of the puzzle is inventories. The agency reported that OECD oil and product stocks fell by a mere 8.1 million barrels in February after January's rise. This leaves them at 3.055 billion (beeelion) barrels, some 330 million barrels above the 5-year average (aka, the normalized level that is the goal of the OPEC production cuts).
Including the IEA's estimate for March, it projects that inventories still climbed on the aggregate through the first quarter of the year, up by 38.5 million barrels:
3) Yesterday's feature on NPR's Texas Standard addressed the issue of fracking sand, and how it is in a bull market. The interview can be found here, while here are some of the sand stats quoted:
--Fracking sand is used as a proppant in hydraulic fracturing, to hold open tiny fissures for oil and gas to pass through
--A total of 54 million tons of fracking sand were used in the U.S. in 2014. Demand is projected to rise to 80 million tons this year, and to 120 million tons in 2018
--Typically the fracking sector has been dominated by silica sand from Wisconsin and Minnesota, as well as from Illinois, Iowa and Indiana. But as more fracking sand is needed in Texas, more mines are starting up
--Nearly 20 times more sand is used per well compared to the peak of the last energy boom
--The largest wells now consume up to 25,000 tons, compared to from 1,500 tons in 2014
--It can take up to 1,000 truck loads to haul enough sand to frack a single large well
4) While so much focus remains on the oil boom in the Permian basin, it is important to note that according to the latest EIA drilling productivity report, natural gas production in the basin is set to reach a new milestone, clambering over 8 Bcf/d. This has prompted Blackstone Group LP to takeover EagleClaw Midstream Ventures for $2 billion. As crude production rises in the basin, more 'associated gas' is produced as a biproduct. With demand for natural gas set to continue on its upward trajectory due to a number of factors - power generation, industrial demand, pipeline and LNG exports - the future is looking bright for the Permian, for both oil and gas.
5) While on the topic of the Permian, the chart below is part of a study of 37 U.S. E&P companies by Bloomberg, showing that 32 of the 37 companies have hedged part of their production for 2017. As for Permian-focused companies, they have hedged 64 percent of their expected oil production for this year...and at a weighted average price of $49.43/bbl to boot. As efficiencies improve in the basin, a hedged price of around $50/bbl appears an attractive option. Only 21 of 37 have hedged anticipated production for 2018.
6) Finally, this piece out on RBN Energy references ClipperData, and how we are counting cargoes and using port agents to identify the quantity, type and quality of crude that is being imported into the U.S. on an almost real-time basis.
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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