Crude prices are heading lower again, rounding out a downbeat week, as the expectation of an OPEC production cut extension is more than outweighed by an ongoing lopsided market. As oversupply fears enter the fray once more, hark, here are five things to consider in oil markets today:
1) OPEC crude exports so far this month are down compared to March, led by a drop from Saudi Arabia and Iran. Nonetheless, total global crude loadings continue to tick higher, holding above 50 million barrels per day.
As our ClipperData illustrate below, global loadings continue to grow - and strongly - on a year-over-year basis, as global producers have ratcheted up output, and more recently, on signs of crude potentially shifting out of onshore storage.
2) While there has been considerable focus of late on the elevated nature of OECD inventories, there has also been the suggestion that crude is instead being drawn down from areas where there is less transparancy and visibility, such as the Caribbean.
Six locations in the Carribbean export crude (not including Curacao, as it is a stepping stone for Venezuelan exports): Trinidad & Tobago, St. Lucia, St. Croix, Cayman Islands, the Bahamas and Aruba. Loadings from these six averaged 400,000 bpd last year. Year-to-date, this number is slightly lower, at 380,000 bpd - but this is due to a slow start to the year; March and April loadings are picking up. There has been one particularly interesting development of late.
Arclight Capital / Freepoint took over the Hovensa refinery complex in St. Croix in early 2016 after a period of inactivity, and is transforming it into a storage hub. We can see from our ClipperData that it started pulling in crude for storage in mid-last year, receiving regular deliveries each month of mostly heavier grades - such as Castilla Blend and Maya.
Its appetite changed this year, pulling in lighter crude instead such as Ekofisk from the North Sea, and WTI in recent months. This makes sense, given that lighter grades are more readily available this year, as heavier and sour crude gets bid up amid the OPEC production cut deal.
In terms of exports from St. Croix, we saw a loading bound for Portugal in November, then a three-month absence. Since the start of March, however, we have seen three loadings. Combine this with a tick higher in loadings from Aruba and St Lucia, and a trend may be potentially emerging.
3) Since the start of the year, non-Canadian companies have sold more than $20 billion of Canadian oil sands assets, as companies switch their focus to short-cycle oil projects instead, such as U.S. shale.
This drying up of international investment has been offset by Canadian companies such as Cenovus Energy, Suncor and Canadian Natural Resources stepping up instead, with the expectation that their local knowledge, relationships and sharing of proprietary technologies will make the oil sands a much more viable option going forward.
Oil sands accounted for 2.4 million barrels per day of production in 2015 (hark, below), accounting for nearly two-thirds of Canadian output.
According to OPEC, total Canadian production rose a further 80,000 bpd last year to average 4.5mn bpd. Ongoing production growth is expected this year, with an increase of 210,000 bpd to average 4.71mn bpd - driven by production ramp ups for both bitumen and synthetic oil projects.
4) Yesterday we looked at drilled but uncompleted wells (DUCs, quack) in the Permian basin. The chart below adds a bit more color, showing both drilled and completed wells. As a reader rightly commented on yesterday's blog, this rise in DUCs is likely due to operators ensuring they maintain their land leases.
The rise in the drilled wells is likely a response to improving confidence in the oil sector, while the rising DUCs point to higher production ahead when market conditions become more favorable (think: services costs and/or oil prices).
The graphic below is also from the Dallas Fed's latest energy indicators, showing the change in the Texas rig count by county from May 2016 to March 2017. The Permian Basin, not surprisingly, has been the biggest beneficiary, accounting for the three counties with the biggest rig count increases: Reeves (+31), Martin (+15) and Howard (+14).
5) Finally, stat of the day comes from this WSJ article, which highlights that Chinese refining capacity has tripled this century, now accounting for 15 percent of the global total (at the end of 2015). This is ~20 percent higher than Chinese domestic demand. CNPC, China's largest oil company, project that refining capacity will increase by 5 percent in 2017, leading to higher product exports going forward.
Countering this view is the implementation of a consumption tax in China on mixed aromatics, light cycle oil and bitumen blend, which could ultimately hit exports of oil products.
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The vast Shah Deniz field in Azerbaijan’s portion of the South Caspian Sea marked several milestones in 2018. It has now produced a cumulative total of 100 billion cubic metres of natural gas since the field started up in 2006, with daily output reaching a new peak, growing by 12.5% y-o-y. At a cost of US$28 billion, Shah Deniz – with its estimated 1.2 trillion cubic metres of gas resources – has proven to be an unparalleled success, being a founding link of Europe’s Southern Gas Corridor and coming in relatively on budget and on time. And now BP, along with its partners, is hoping to replicate that success with an ambitious exploration schedule over the next two years.
Four new exploration wells in three blocks, along with a seismic survey of a fourth, are planned for 2019 and an additional three wells in 2020. The aggressive programme is aimed at confirming a long-held belief by BP and SOCAR there are more significant pockets of gas swirling around the area. The first exploratory well is targeting the Shafag-Asiman block, where initial seismic surveys suggest natural gas reserves of some 500 billion cubic metres; if confirmed, that would make it the second-largest gas field ever discovered in the Caspian, behind only Shah Deniz. BP also suspects that Shah Deniz itself could be bigger than expected – the company has long predicted the existence of a second, deeper reservoir below the existing field, and a ‘further assessment’ is planned for 2020 to get to the bottom of the case, so to speak.
Two wells are planned to be drilled in the Shallow Water Absheron Peninsula (SWAP) block, some 30km southeast of Baku, where BP operates in equal partnership with SOCAR, with an additional well planned for 2020. The goal at SWAP is light crude oil, as is a seismic survey in the deepwater Caspian Sea Block D230 where a ‘significant amount’ of oil is expected. Exploration in the onshore Gobustan block, an inland field 50km north of Baku, rounds up BP’s upstream programme and the company expects that at least one seven wells of these will yield a bonanza that will take Azerbaijan’s reserves well into the middle of the century.
Developments in the Caspian are key, as it is the starting node of the Southern Gas Corridor – meant to deliver gas to Europe. Shah Deniz gas currently makes its way to Turkey via the South Caucasus Gas pipeline and exports onwards to Europe should begin when the US$8.5 billion, 32 bcm/y Trans-Anatolian Pipeline (TANAP) starts service in 2020. Planned output from Azerbaijan currently only fills half of the TANAP capacity, meaning there is room for plenty more gas, if BP can find it. From Turkey, Azeri gas will link up to the Trans-Adriatic Pipeline in Greece and connect into Turkey, potentially joined by other pipelines projects that are planned to link up with gas production in Israel. This alternate source of natural gas for Europe is crucial, particularly since political will to push through the Nordstream-2 pipeline connecting Russian gas to Germany is slackening. The demand is there and so is the infrastructure. And now BP will be spending the next two years trying to prove that the supply exists underneath Azerbaijan.
BP’s upcoming planned exploration in the Caspian:
When it was first announced in 2012, there was scepticism about whether or not Petronas’ RAPID refinery in Johor was destined for reality or cancellation. It came at a time when the refining industry saw multiple ambitious, sometimes unpractical, projects announced. At that point, Petronas – though one of the most respected state oil firms – was still seen as more of an upstream player internationally. Its downstream forays were largely confined to its home base Malaysia and specialty chemicals, as well as a surprising venture into South African through Engen. Its refineries, too, were relatively small. So the announcement that Petronas was planning essentially, its own Jamnagar, promoted some pessimism. Could it succeed?
It has. The RAPID refinery – part of a larger plan to turn the Pengerang district in southern Johor into an oil refining and storage hub capitalising on linkages with Singapore – received its first cargo of crude oil for testing in September 2018. Mechanical completion was achieved on November 29 and all critical units have begun commissioning ahead of the expected firing up of RAPID’s 300 kb/d CDU later this month. A second cargo of 2 million barrels of Saudi crude arrived at RAPID last week. It seems like it’s all systems go for RAPID. But it wasn’t always so clear cut. Financing difficulties – and the 2015 crude oil price crash – put the US$27 billion project on shaky ground for a while, and it was only when Saudi Aramco swooped in to purchase a US$7 billion stake in the project that it started coalescing. Petronas had been courting Aramco since the start of the project, mainly as a crude provider, but having the Saudi giant on board was the final step towards FID. It guaranteed a stable supply of crude for Petronas; and for Aramco, RAPID gave it a foothold in a major global refining hub area as part of its strategy to expand downstream.
But RAPID will be entering into a market quite different than when it was first announced. In 2012, demand for fuel products was concentrated on light distillates; in 2019, that focus has changed. Impending new International Maritime Organisation (IMO) regulations are requiring shippers to switch from burning cheap (and dirty) fuel oil to using cleaner middle distillate gasoils. This plays well into complex refineries like RAPID, specialising in cracking heavy and medium Arabian crude into valuable products. But the issue is that Asia and the rest of the world is currently swamped with gasoline. A whole host of new Asian refineries – the latest being the 200 kb/d Nghi Son in Vietnam – have contributed to growing volumes of gasoline with no home in Asia. Gasoline refining margins in Singapore have taken a hit, falling into negative territory for the first time in seven years. Adding RAPID to the equation places more pressure on gasoline margins, even though margins for middle distillates are still very healthy. And with three other large Asian refinery projects scheduled to come online in 2019 – one in Brunei and two in China – that glut will only grow.
The safety valve for RAPID (and indeed the other refineries due this year) is that they have been planned with deep petrochemicals integration, using naphtha produced from the refinery portion. RAPID itself is planned to have capacity of 3 million tpa of ethylene, propylene and other olefins – still a lucrative market that justifies the mega-investment. But it will be at least two years before RAPID’s petrochemicals portion will be ready to start up, and when it does, it’ll face the same set of challenging circumstances as refineries like Hengli’s 400 kb/d Dalian Changxing plant also bring online their petchem operations. But that is a problem for the future and for now, RAPID is first out of the gate into reality. It won’t be entering in a bonanza fuels market as predicted in 2012, but there is still space in the market for RAPID – and a few other like in – at least for now.
RAPID Refinery Factsheet:
Tyre market in Bangladesh is forecasted to grow at over 9% until 2020 on the back of growth in automobile sales, advancements in public infrastructure, and development-seeking government policies.
The government has emphasized on the road infrastructure of the country, which has been instrumental in driving vehicle sales in the country.
The tyre market reached Tk 4,750 crore last year, up from about Tk 4,000 crore in 2017, according to market insiders.
The commercial vehicle tyre segment dominates this industry with around 80% of the market share. At least 1.5 lakh pieces of tyres in the segment were sold in 2018.
In the commercial vehicle tyre segment, the MRF's market share is 30%. Apollo controls 5% of the segment, Birla 10%, CEAT 3%, and Hankook 1%. The rest 51% is controlled by non-branded Chinese tyres.
However, Bangladesh mostly lacks in tyre manufacturing setups, which leads to tyre imports from other countries as the only feasible option to meet the demand. The company largely imports tyre from China, India, Indonesia, Thailand and Japan.
Automobile and tyre sales in Bangladesh are expected to grow with the rising in purchasing power of people as well as growing investments and joint ventures of foreign market players. The country might become the exporting destination for global tyre manufacturers.
Several global tyre giants have also expressed interest in making significant investments by setting up their manufacturing units in the country.
This reflects an opportunity for local companies to set up an indigenous manufacturing base in Bangladesh and also enables foreign players to set up their localized production facilities to capture a significant market.
It can be said that, the rise in automobile sales, improvement in public infrastructure, and growth in purchasing power to drive the tyre market over the next five years.