China's apparent oil demand contracted by 1.3% in April 2016 from a year earlier to 11.36 million barrels per day (b/d), according to a just-released analysis of Chinese government data by S&P Global Platts, the leading independent provider of information and benchmark prices for the commodities and energy markets.
Refinery throughput in April averaged 10.93 million b/d, data from the China's National Bureau of Statistics (NBS) showed May 14. This was a 2.3% increase year over year and a 3% rise month over month.
Net imports of key oil products however slumped 48.1% from a year earlier to an average 430,000 b/d in April, driven by sustained exports of transport fuels, according to data from China's General Administration of Customs.
The contraction in oil demand in April represented the third consecutive month of negative growth and was largely attributable to a considerable decline in gasoil and fuel oil demand, amid a slowed Chinese economy.
Over the first four months of 2016, apparent oil demand averaged 11.15 million b/d, down 0.3%. This compared with 8.4% expansion during January-April 2015.
China's oil demand growth is expected to moderate significantly in 2016 as gross domestic product growth slows on the back of economic rebalancing. China's government data shows the economy expanded by 6.7% in the first quarter of this year, a decline from 6.8% in the fourth quarter of 2015.
China's 2016 apparent oil demand is forecast to grow by less than 2%, according to Platts China Oil Analytics, an on-line platform for supply/demand and trade data, of S&P Global Platts.
Gasoil exports hit record high volumes in March and April as refineries grappled with domestic oversupply and muted consumption.
The fuel is used in the industrial and heavy transport sectors. Demand has taken a hit in recent years, given stagnation in the manufacturing sector amid China's transition towards more service-sector-led economic growth.'Despite the fact that refineries have reduced domestic gasoil production by 2% on a year over year basis in 2016, exports have more than quadrupled during the same period, at the same time refiners have reported sluggish domestic sales of gasoil,' said Song Yen Ling, senior analyst with Platts China Oil Analytics.
In April alone, gasoil apparent demand tumbled 8.8% from a year ago, signaling the eighth consecutive month of decline.
Apparent demand for gasoline climbed to a record high of 2.89 million b/d in April, up 7% from a year earlier, according to S&P Global Platts calculations. The growth in the apparent demand figure was due to an 8.8% boost in domestic production, which more than offset a 35.5% rise in exports.
So far this year, gasoline apparent demand in China has increased by 7.9% to an average 2.83 million b/d.
Passenger vehicle sales rose 6.1% from January to April this year, with SUV sales surging 46.3%. New tax incentives introduced late last year to encourage small car ownership likely contributed to higher growth. In contrast, passenger vehicle sales rose just 2.8% in the first four months of 2015.
Platts China Oil Analytics forecasts a gasoline apparent demand rise of 6.4% in 2016, but notes that rising oil prices could limit growth in gasoline consumption this year.
China's fuel oil apparent demand in April shrank by 35.4% on a year-over-year basis to 672,000 b/d. The country's fuel oil consumption has fallen since late 2015, following the government's move to allow more independent refiners to import crude oil. Prior to this, such refiners had limited access to crude oil and therefore tended to import fuel oil as their main processing feedstock. However, since the second half of 2015, Beijing has approved more than 1 million b/d of crude oil import quotas for independent refiners.
With fuel oil not as popular with refiners as processing feedstock, consumption is mainly focused on the bunker market. Fuel oil apparent demand this year has dived 19% year on year to 705,000 b/d.
In contrast, independent refiners' appetite for crude oil has surged significantly in 2016.
China's crude oil imports over the first three months of this year have increased 10.9% to an average 7.49 million b/d, with at least three-quarters of the growth attributed to independent refiners. Consequently, fuel oil imports into China have fallen 40% over January to April to 286,000 b/d.
Month-to-month demand in China is generally viewed to be subjected to short-term anomalies which are of interest and important to note, but often fail to reveal the country's underlying demand trends. Year-to-year comparisons are viewed by the marketplace to be more indicative of the country's energy profile.
*S&P Global Platts calculates China's apparent or implied oil demand on the basis of crude throughput volumes at the domestic refineries and net oil product imports, as reported by the NBS and Chinese customs. Platts also takes into account undeclared revisions in NBS historical data.
The government releases data on imports, exports, domestic crude production and refinery throughput data, but does not give official data on the country's actual oil consumption figure and oil stockpiles. Official statistics on oil storage are released intermittently.
In view of some significant shifts in Chinese consumption and trade patterns in recent years, S&P Global Platts has revised its methodology starting July 2015 to include production and net imports of liquefied petroleum gas (LPG), as well as imports of petroleum bitumen blend, a popular imported feedstock for China's teapot refineries.
S&P Global Platts has also refined its calculation of exports of jet fuel and fuel oil to exclude international marine bunker sales and aviation fuel delivered to international flights. This also impacts net imports, and hence apparent demand calculations.
All historical figures used for comparison have also been calculated using the new methodology to ensure consistency.
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
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Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline