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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Headline crude prices for the week beginning 7 January 2019 – Brent: US$57/b; WTI: US$49/b
Headlines of the week
At some point in 2019, crude production in Venezuela will dip below the 1 mmb/d level. It might already have occurred; estimated output was 1.15 mmb/d in November and the country’s downward trajectory for 2018 would put December numbers at about 1.06 mmb/d. Financial sanctions imposed on the country by the US, coupled with years of fiscal mismanagement have triggered an economic and humanitarian meltdown, where inflation has at times hit 1,400,000% and forced an abandonment of the ‘old’ bolivar for a ‘new bolivar’. PDVSA – once an oil industry crown jewel – has been hammered, from its cargoes being seized by ConocoPhillips for debts owed to the loss of the Curacao refinery and its prized Citgo refineries in the US.
The year 2019 will not see a repair of this chronic issue. Crude production in Venezuela will continue to slide. Once Latin America’s largest oil exporter – with peak production of 3.3 mmb/d and exports of 2.3 mmb/d in 1999 – it has now been eclipsed by Brazil and eventually tiny Guyana, where ExxonMobil has made massive discoveries. Even more pain is on the way, as the Trump administration prepares new sanctions as Nicolas Maduro begins his second term after a widely-derided election. But what is pain for Venezuela is gain for OPEC; the slack that its declining volumes provides makes it easier to maintain aggregate supply levels aimed at shoring up global oil prices.
It isn’t that Venezuela doesn’t want to increase – or at least maintain its production levels. It is that PDVSA isn’t capable of doing so alone, and has lost many deep-pocketed international ‘friends’ that were once instrumental to its success. The nationalisation of the oil industry in 2007 alienated supermajors like Chevron, Total and BP, and led to ConocoPhillips and ExxonMobil suing the Venezuelan government. Arbitration in 2014 saw that amount reduced, but even that has not been paid; ConocoPhillips took the extraordinary step of seizing PDVSA cargoes at sea and its Caribbean assets in lieu of the US$2 billion arbitration award. Burnt by the legacies of Hugo Chavez and now Nicolas Maduro, these majors won’t be coming back – forcing Venezuela to turn to second-tier companies and foreign aid to extract more volumes. Last week, Venezuela signed an agreement with the newly-formed US-based Erepla Services to boost production at the Tia Juana, Rosa Mediano and Ayacucho 5 fields. In return, Erepla will receive half the oil produced – generous terms that still weren’t enough to entice service giants like Schlumberger and Halliburton.
Venezuela is also tapping into Russian, Chinese and Indian aid to boost output, essentially selling off key assets for necessary cash and expertise. This could be a temporary band-aid, but nothing more. Most of Venezuela’s oil reserves come from the extra-heavy reserves in the Orinoco Belt, where an estimated 1.2 trillion barrels lies. Extracting this will be extremely expensive and possibly commercially uneconomical – given the refining industry’s move away from heavy grades to middle distillates. There are also very few refineries in the world that can process such heavy crude, and Venezuela is in no position to make additional demands from them. In a world where PDVSA has fewer and fewer friends, recovery will be extremely tough and extremely far-off.
Infographic: Venezuelan crude production:
Headline crude prices for the week beginning 31 December 2018 – Brent: US$54/b; WTI: US$46/b
Headlines of the week