Archives for posts with tag: demand

One of the major drivers behind the challenges currently facing many of the shipping markets has been slower demand growth. World seaborne trade grew by less than 2% in 2015, the slowest pace since 2009, with trends in China pivotal. After the emergence of plenty of disappointing demand-side data last year, what do the indicators of Chinese trade so far in 2016 reveal?

A Surprising Start?

It’s a vital question. Chinese seaborne imports reached a massive 2.1 billion tonnes last year, accounting for 20% of global imports. But in 2015, growth in Chinese imports eased to just 1%, from an average of 9% p.a. in 2011-14. However, data for the first quarter of 2016 provides some pleasant surprises. After slowing for four consecutive years, growth in Chinese seaborne imports in tonnes appears to have picked up pace in Q1 2016, increasing by 6% y-o-y.

Picking Up Speed

Iron ore trade, which last year accounted for 45% of total Chinese imports, has driven much of this growth. Iron ore imports had a strong Q1 2016, rising by 7% y-o-y to 239mt. This was supported by restocking of iron ore inventories in line with improved steel demand and prices in recent months, following government support for infrastructure projects. This has been despite total steel production continuing to contract y-o-y, by 4% in Q1. Meanwhile, Chinese coal imports appear to have stabilised recently, following a sharp fall in 1H 2015, and the pace of decline in imports in Q1 2016 eased to 6% y-o-y. Growth in China’s minor bulk imports also improved marginally in Q1.

Some improvements have also been apparent outside of the dry bulk sector. Expansion in China’s crude oil imports has accelerated, with imports up 14% y-o-y in Q1 to 84mt, following robust growth of 9% in 2015. Imports have been boosted further this year by the liberalisation of the crude oil import market, opening up imports to independent refiners. And although Chinese gas demand came under pressure in 2015 from weaker industrial use, recent cuts to domestic gas prices have supported demand and LNG imports grew 17% y-o-y in Q1 2016 to 6mt.

Mixed Results

Meanwhile, indicators of Chinese exports remain mixed. Container trade on the key Far East-Europe route grew slightly in Q1, after falling 4% in 2015; the impact of adjustments to European inventories and falling Russian demand is likely to moderate this year. However, growth in China’s steel products exports has slowed, partly reflecting greater domestic steel demand.

A Question Of Endurance?

Overall, it would still be fair to say that the seaborne demand environment is still highly challenging, and that volatility clouds the picture in China and elsewhere. Moreover, questions remain over the sustainability of recent developments in some of China’s industrial sectors, and major obstacles to trade volume growth clearly remain. Nevertheless, there are some areas where improved Chinese volume growth has provided a nice surprise so far this year. Against a troubled background, shipping market players will hope these trends at least have a little mileage. Have a nice day.



It’s now more than a year since the tanker market took off. In mid-2014 tanker earnings picked up and since then have been in the $30-$40,000/day range. But the market remains nervous. This tanker pick-up coincided with a slump in dry bulk earnings, which is interesting because on paper bulkers and tankers both seem to have surplus capacity. So why are tankers doing so much better than bulkers?

Long-Term Premium

On an “all sizes average” basis tanker earnings generally exceed bulker earnings (the tanker “basket” contains a greater share of larger ships). For example, between 1990 and 2015 to date tanker earnings averaged $24,996/day, whilst bulkers earned $13,933/day. That gives tankers a 79% premium over bulkers. During the seven years since the Credit Crisis, the premium has remained. Tankers have earned $18,281/day, compared to bulkers’ $12,427/day, a 47% premium. So the “premium” relationship held, even during a period of deep recession.

Earnings Distribution

However, during the period of recession tanker earnings have swung from below to above “average premium levels”. To illustrate this point we have estimated what tanker earnings “should have been” over the last seven years if they had followed the “average premium” relationship with bulker earnings over the full period back to 1990. This relationship was estimated using a regression equation as a “rule of thumb”, using monthly data for the period 1990 to 2015, and then used to estimate tanker earnings since 2009 from bulker earnings, shown by the red line on the graph.

For the first five years tankers underperformed compared to the long-term “average premium” versus bulkers, with the blue line, showing actual earnings, below the red line. But in 2014 they started to exceed the expected premium as bulker earnings dropped and tanker earnings increased. Currently tanker earnings offer a significant “bonus” above the estimated “norm”, at levels about six times higher than bulker earnings.

More Than One Answer

So what’s going on? The first answer is that tankers are playing “catch up” for the bad run early in the recession. But there are other answers to the question. One is that in 2015 oil trade has grown much faster than expected, increasing by 4% compared with only 2% expected earlier in the year. Another is the oil price collapse from over $100/bbl to close to $40/bbl, creating an opportunity for arbitrage by holding oil in ships, in anticipation of a price increase. Additionally, of course, bulkers have suffered from an absence of demand growth this year.

The Usual Suspects?

So there you have it. The tanker boom has gone on longer than many might have anticipated and tanker earnings are outperforming their long-run relationship with bulker earnings. But a “fundamental” surplus remains and investors might be right to be cautious. Scrapping has almost stopped, ordering has picked up and supply growth is set to increase. So, enjoy it while you can, and remember that it’s partly a game of catch up. Have a nice day.


Idle capacity has been a feature of the containership sector since the economic downturn in 2008-09. Prior to that, box freight rates tended to vary according to fairly macro factors, and liner companies appeared less inclined to resort to micro supply management to address imbalances. But in recent years, there have been clear phases of containership ‘idling’, each highly reflective of conditions in the sector.

The Worst Of Times

Global box trade dropped by 9% in 2009, and liner companies were left with little option but to idle significant levels of capacity to resurrect freight levels from rock bottom levels (Phase 1 on the graph). By the end of 2009, 1.5m TEU, or 11% of total fleet capacity stood idle. This did at least help push freight rates back up.

Not The Best Of Times

It did of course have a negative impact on the charter market, leaving owners, with an easy supply of laid up ships lurking in the background for charterers to access, unable to bid up rates. But, with some believing the world economy to be recovering quickly, substantial amounts of idle capacity were soon reactivated and by the end of September 2010, there was only 1.6% of the fleet idle (Phase 2). However, with freight levels having dropped again, further lay-up followed, and by end March 2012, the position had been reversed and 5.9% of the fleet was idle (Phase 3). Charter owner tonnage accounted for around 70% of the total by the summer of 2012, and most of the idle capacity was in classic charter market sizes, with only 3% above 5,000 TEU, putting pressure back on charter rates.

Better Times?

In the next phase, market conditions very slowly appeared to become more helpful, and idle capacity gradually fell, with the winter peak receding each year (Phase 4); idle capacity peaked at 6% of the fleet in early 2012, 5% in 2013 and 4% in 2014. But the charter owners’ share stayed high, keeping pressure on the charter market. It took until well into 2014 for rates to see much positive traction. By the end of 2014, idle capacity was finally more limited, at 1.3% of the fleet, reflective of the improved environment.

Time For A Change (Again)?

Today, despite severe freight rate pressure, idle capacity is still fairly limited at 2.5% of the fleet, but it is on the rise and the charter market is softening, ceding some of its gains. Larger ships had begun to account for a greater share of the idle pool (24% over 5,000 TEU in May) but recent weeks have seen a return to increased smaller ship idling.

So how will Phase 5 play out? There are a range of scenarios. Liner companies might continue to compete aggressively on the mainlanes with an apparent surplus of big ship capacity, and endure freight rate pain without idling too much more capacity. Or to protect freight rates they might start to idle a greater number of larger ships. Alternatively, they might once again pass down the pressure to the smaller ship arena, leaving more significant levels of capacity there to impact on the charter market. Much might depend on the flexibility of tonnage. Either way, once again, the development of idle boxship capacity will be a sign of the times. Have a nice day.


On July 14th 2015, after 20 months of negotiations, Iran and the so-called “P5+1” signed the “Joint Comprehensive Plan of Action”: in return for US, EU and UN-mandated sanctions against the country being gradually lifted, Iran has agreed to roll back its nuclear capabilities. Should the deal stick, the door will open to foreign investment once more. What, then, are the possible implications for Iranian offshore oil? Should this deal stick, IOCs will soon be able to operate in Iran once more. What, then, are the possible implications for Iran’s offshore sector?

Political Locks

On the eve of the Islamic Revolution in 1979, total Iranian oil production stood at 6.0m bpd, of which around 12% (0.72m bpd) was from 13 offshore fields producing oil, all located in shallow waters and exploited via fixed platforms. The turmoil of the Revolution saw oil production drop to 1.70m bpd in 1980, and in the ensuing Iran-Iraq War, offshore fields like Salman were shut in due to military action. As a result, actual offshore oil production was less than 50% of capacity for most of the 1980s; after the War, production began to recover, peaking at 88% of capacity (0.60m bpd) in 1997. However, as US and then EU economic sanctions on Iran tightened, IOCs were forced to exit the country, depriving Iran’s offshore sector of key investment and technology. Development work slowed and much of Iran’s offshore 2P reserves (30.3bn bbl of oil; 707 tcf of gas) were locked away. At the same time, Iran lacked the resources to implement EOR at brownfields. As a result, the gap between actual and nameplate offshore production was 1.38m bpd by 2014, with production at 0.54m bpd.

Rusty Hinges

Now that sanctions are to be lifted, indications suggest Iran aims to get as much oil production as possible back onstream in 2015/16. Restoring offshore production is likely to require more than just turning the taps though. Iran’s ability to halt decline at brownfields has been curbed, in contrast to other mature producers like the U.A.E. Half of Iran’s active offshore oil fields predate the Revolution (the oldest started up in 1961). Extensive EOR work is likely to be required at such fields – one opportunity for IOCs. Thus, while offshore production is forecast to grow by 7.3% in 2015, this is mostly due to South Pars condensate production ramping up, rather than utilisation of older capacity.

An Alternative Entrance?

Iran is planning an “oil contract roadshow” in London in 2H 2015, with the stated aim of attracting foreign investment in E&P of $185 billion by 2020. However, it is likely that much of the investment will be directed towards stalled onshore projects such as Yadavaran, and to restoring production at mature onshore fields like Azadegan. A spate of onshore discoveries made from 2006 to 2008 may also be prioritised by cash-hungry Iran, particularly those in the Khuzestan province spanning the Iraq border. Some of Iran’s 7 undeveloped offshore fields like Esfandiar (532m bbl) may warrant priority, and the South Pars Oil Layer is scheduled to come onstream in 2018. But even taking into account the Caspian (home to the 2011 Sardar-e Jangal 500m bbl find), offshore oil opportunities for IOCs (and so vessel owners) may be limited at first.

It seems, then, that the offshore oil capacity gap could widen before it narrows. Certainly given its reserves Iran has long-term offshore potential, notwithstanding its troubled history. But observers expecting a quick and big uptick in oil-related offshore activity might need to be patient.


For many of the markets covered by Shipping Intelligence Weekly, the first part of 2015 was relatively kind. Rates for crude and product tankers were riding high, boxship charter rates picked up for the first time in years and VLGC rates have hit levels above 2014 averages. Even Capesizes have recently shown signs of life. But spare a thought for the offshore sector, the hardest hit by the oil price decline.

Price Drop

Back in the downturn of 2008/09, most commodity and shipping markets felt the negative impact and the offshore markets were no exception, with dayrates dropping by an average of around 35% (see graph).  Moving forward to the current time, however, the 50% decline in oil prices since mid-2014 has brought some relief for merchant vessels, in the form of cheaper bunkers, and stimulated oil demand, helping trade. But cheaper oil has meanwhile put heavy pressure on the offshore sector, where field operators already faced cashflow problems as field developments ran late and over-budget. The response has been sharp cuts in exploration and production (E&P) budgets. It is estimated that spending on offshore E&P will fall by 19% this year.

Investment Cuts

This means investment decisions on new projects have been deferred, whilst expenditure to enhance recovery from existing fields has also slipped. Accordingly, drilling demand has fallen, just as deliveries of new jack-up and floating drilling rigs have accelerated. Rates for ultra-deepwater floaters are now almost 50% below their late 2013 peak, at around $300,000/day. This reflects the reduced demand in frontier areas for exploration and appraisal drilling, not helped by the corruption investigations in Brazil. Meanwhile, jack-up drilling rig rates have been equally hard hit, with shale gas production killing demand in one of their traditional major markets, the shallow water Gulf of Mexico. Utilisation of jack-ups is below 80%, and rates have fallen more than 35% to around $100,000/day.

Less Support For Vessels

This has had rapid knock-on consequences. The 5,365 vessels and 1,133 owners in the OSV market are also exposed to the downturn in exploration drilling and operational field maintenance. Fewer active rigs harms the AHTS market for rig towage and positioning, whilst PSVs rely on the growth in active offshore installations (drilling rigs, plus mobile and fixed production platforms) to add to demand. Rates for OSVs are down in all regions, by over 35% on average in terms of the index on the graph. PSVs have a further problem of a robust supply growth to contend with (and close to 40% of the fleet on order for the largest units over 4,000 dwt).

Of course, markets are cyclical, and the offshore sector had its moment in the sun during 2012/13, at a time when several of the merchant shipping markets were in the doldrums. Although the current oversupply in world oil markets of around 1.5m bpd is a clear short-term hurdle, projected demand trends suggest that higher oil prices remain a likely prospect in the long-term, and the improvement in other sectors suggests that there will eventually be light at the end of the tunnel for offshore too. It’s just that it could be a little way off yet. Have a nice day.

On 14th August 1948, Don Bradman, Australia’s greatest cricketer of all, walked out for his last test match innings, at the Oval in London. Over 52 test matches, his average score was an astonishing 99.9 runs. All he needed was 4 runs for a test match average of 100 (sorry non-cricketers, you’ll have to check it out on Wikipedia). But he was bowled out second ball by leg spinner Eric Hollies.

Two Simple Rules

The moral of this sad story is that however experienced you are, two basic rules apply. Keep your eye on the ball and watch out for spinners that behave erratically. That seems to apply pretty well to today’s tanker market. The fantastic revival of tanker earnings started in October 2013, was interrupted by the summer dip in 2014, then picked up in October 2014. Since then it has not looked back, with crude tanker earnings generally averaging $40-$50,000/day. There is a little weakening right now, but sentiment appears to be confident for the winter.

Demanding Wicket

Against the background of a 2% fall in seaborne crude oil trade in 2014, US fracking and a lacklustre world economy, this earnings surge was a surprise. But there were some mitigating factors. Low oil prices are boosting demand and the IEA has revised up its forecast for growth in global oil demand in 2015 to 1.6m bpd.

Growth on long-haul trades has also helped. Between 2011 and 2014 Caribbean tonne-mile exports increased by 36%, largely due to increased shipments to China and India. That sounds good, but many VLCCs repositioned with a backhaul e.g. West African crude for Europe, and maybe a Transatlantic fuel oil cargo. Although handling fuel oil is time consuming, especially when it involves STS (ship to ship), this undermined some of the “tonne-mile” effect. And so did cargo-leg speeds, which appear to have edged upwards over the last year. But while the part played by demand may not seem entirely clear, there has still been a notable improvement in crude trade volumes this year, with seaborne shipments to major importers estimated to have increased by 4% year-on-year in 1H 2015.

It’s Supply, Stupid?

When we turn to supply, the picture becomes clearer. Until the summer of 2013, the crude tanker fleet was growing at 15-20m dwt pa. That’s about 5-6% per annum growth, well above demand growth. But by October 2013 growth had fallen to 2%, producing a nice year-end spike. The tanker supply slowdown kept on going and by July 2014 the crude tanker fleet was declining. Admittedly the growth has
edged up so far in 2015, but only to around 1-2% per annum.

Nasty Spinner In Sixteen?

So there you have it. Tanker investors have scored well in the last year, but, like Don Bradman, they must remember rule two and watch out for the spinners. Although fleet growth is sluggish, the crude tanker orderbook for 2016 could produce a “googly” as it pushes fleet growth back up to 6% (depending on demolition). Even with positive demand, tanker investors are going to have to keep their eye on that ball and hope it breaks the right way. Have a nice day.


E&P offshore India can be divided into two very distinct species of activity: the one species is typified by shallow water exploration using jack-up drilling rigs, and by multi-phase fixed platform developments; the other species by ultra-deepwater exploration using floaters. The first is concentrated off the west coast, the second off the east coast. But when it comes to CAPEX, which species of activity sits at the top of the food chain in these lean times?

Shallow Water Ancestry

Mumbai High is the ancestor and primordial archetype of the vast majority of field developments offshore India today. Discovered in 1974 in the Mumbai Basin off the country’s west coast, the field was brought onstream in 1976 and was initially exploited via 4 fixed platforms in water depths of around 85m. Subsequent expansions have seen this number rise to 159, with 8 more platforms being fabricated for the Ph.3 redevelopment projects at the field. For the first 30 years of Indian offshore E&P, exploration was focused in the Mumbai Basin while development followed the pattern at Mumbai High. Hence, as of July 2015, 94 fields had been discovered off India’s west coast, all in shallow waters, accounting for 48% of Indian offshore discoveries. Of these 94 fields, 39 are active and 11 are under development. The basin also accounts for 301 active fixed platforms, as well as 13% (18 units) of the jack-up fleet in the Middle East/ISC region. With EOR and redevelopment work underway, the Mumbai Basin remains an important area of offshore activity.

Deepwater Diversification

However, since 2002 the Indian offshore sector has bifurcated to produce a very different species of offshore activity. Exploration campaigns in the east coast Krishna Godavari Basin resulted in 50 new discoveries in water depths >500m (and 51 shallow water finds). Amongst these was KG-DWN-2005/1-A, a field in a water depth of 3,166m, making it the deepest find (in terms of water depth) to date globally. At the height of KG Basin exploration, 12 floaters were active in the country. All this being said, Indian deepwater activity is much less advanced than shallow water E&P: just two deepwater fields are in production and none are currently under development. As a corollary, there are almost no subsea installations offshore India and just one active MOPU.

An Evolutionary Hiatus?

There are, however, 25 ‘probable’ deepwater field developments, including some potentially prolific fields. However, development seems to have been inhibited by the example of KG-D6 (Dhirubhai 1&3), a deepwater (850m) gas field which has shown precipitous production decline. India’s offshore sector is also dominated by indigenous companies like the government-controlled ONGC, who seemingly lack the deepwater technological or operational expertise of many IOCs. At the same time, there are still 88 potential shallow water fields, as well as plenty of scope for EOR at older fields – the sort of projects where Indian oil companies have substantial experience.

Opening up of the upstream sector, as is being attempted in Mexico, might be one means to adapt to the challenges of the “P” of deepwater E&P in India. However, this does not appear to be on the cards for the immediate future. So for the time being, given the hostile conditions of the weaker oil price environment, shallow water activity seems set to thrive best.