Oil prices have increased 60% since late January. Is this an oil-price recovery?
Two previous price rallies ended badly because they had little basis in market-balance fundamentals. The current rally will probably fail for the same reason.
The Oil Glut Worsens But Prices Reach 2016 Highs
Although oil prices reached the highest levels so far in 2016 during the past few days, the global over-supply of oil worsened in March.
EIA data released this week shows that the net surplus (supply minus consumption) increased to 1.45 million barrels per day. Compared to February, the surplus increased 270,000 barrels per day. That’s a bad sign for the durable price recovery that some believe is already underway.
The production freeze that OPEC plus Russia will discuss this weekend has already arrived. Supply increased only 20,000 barrels per day in March. Consumption, however, decreased by 250,000 barrels per day. That’s not good news for the world economy although first quarter consumption is commonly lower than levels during the second half of the year.
The April IEA Oil Market Report was also released this week and it largely corroborates EIA data. First quarter 2016 liquids supply surplus was 1.53 million barrels per day compared to EIA’s 1.71 million barrels per day for the quarter.
The first quarter 2016 surplus fell 220,000 barrels per day from the fourth quarter 2015. Overall supply declined 660,000 barrels per day but demand fell by 880,000 barrels per day.
IEA’s demand growth forecast for 2016 remains 1.2 million barrels per day. 2015 demand growth was a very high 1.8 million barrels per day because of low oil prices. 1.2 million barrels per day is, however, consistent with average growth from 2011 through 2014.
Oil prices have increased from $26 to $45 per barrel during the current January – April price rally. This is based partly on hope for an OPEC-plus-Russia production freeze that almost everyone agrees will do nothing to balance global oil markets.
There were two major price cycles in 2015. During the first cycle, WTI prices increased from about $44 in mid-March to more than $60 by early May over a period of about 50 days. This was based on plunging U.S. rig counts and withdrawals from storage. Prices remained around $60 per barrel for 25 days and then fell to about $38 by mid- to late August over a period of 72 days. The total trough-to-trough period of the cycle was 157 days.
During the second cycle, prices increased from $38 to more than $49 per barrel in only 7 days in late August 2015 based on good economic news about China and U.S. storage withdrawals. Prices fluctuated between $39 and $49 with an average price of almost $45 per barrel for 93 days. After falling below $40 per barrel in early December, prices dropped to $26.55 on January 20, 2016, a period of 46 days.The total trough-to-trough period of the cycle was 146 days.
At the beginning of the present cycle, prices increased from $26.55 to $33.62 in late January and then dropped to $26.21 on February 11. This “double-bottom” pattern probably tested the low-price threshold for the greater oil-price collapse that began in June 2014.
That does not mean that a price recovery is in progress. It suggests that because $26 per barrel is so far below the marginal cost of production that prices are more likely to increase going forward than to discover a lower bottom.
Following the double-bottom, prices increased to $41.45 on March 22 over a period of 40 days. Prices fell to $35.70 over the next 12 days before increasing to $42.17 on April 13. Yesterday, prices fell to $41.52. The total duration of this cycle is 63 days so far.
Aside from the global production surplus, the huge amount of oil in storage is the other key factor working against a price recovery right now.
Last week, a larger-than-anticipated 4.94 million barrel withdrawal from U.S. storage re-ignited the price rally that had stalled during the previous week. A 6.6 million barrel addition this week was largely ignored by the market as futures prices fell only $0.44 yesterday.
U.S. stocks are near record high levels of 78 million barrels more than at this time in 2015 and 138 million barrels more than the 5-year average.
OECD stocks are also at record levels of 3.13 billion barrels of liquids. That is 359 million barrels more than the 5-year average but 54% of those volumes are U.S. stocks.
Comparative inventory patterns have been mixed and unclear for the past few weeks. Cushing stocks have been decreasing but Cushing-plus-Gulf Coast and overal U.S. crude oil inventories have been alternating between decrease and increase. It is, therefore, too early to tell whether comparative inventory data supports a price increase or not.
Posted in The Petroleum Truth Report on April 14, 2016
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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.