Archives for category: Gas

Once upon a time, before the Chinese economic boom captured so much of the attention of the world of shipping, the US was a more important demand source for seaborne trade. Its share of global imports is lower today, but the US still plays a key part in world seaborne trade. What’s the detail behind this backdrop and how might the big changes in US politics impact the trends?

In A Chinese Theatre

Looking back, in 2006, North American container imports accounted for 18% of world box trade, whilst 22% of global seaborne crude oil trade went to the US. In 2016, these figures were 13% and 12% respectively. Some of this change is relative: rapid growth in China and developing Asia has clearly reduced the US share of global trade. Nevertheless, US imports have actually fallen in many of the major categories of seaborne trade. The volume, however, is still highly significant, so changes in US trade patterns are of major importance. The import trades shown on the graph alone account for around 6% of global seaborne trade.

A Mexican Stand-Off

Looking forward, one key aspect is the clear scenario in which US policy under the new administration becomes more protectionist. The US is withdrawing from the mooted Trans-Pacific Partnership and there is the possibility of punitive tariffs. The focus is manufacturing: attempts to ‘re-shore’ production which once upon a time would have taken place in the West. This could have a negative impact on certain import trades. The US accounted for 23% of all car imports by sea in 2016. Tariffs could harm this trade, as could a more aggressive approach against alleged dumping of cheap Asian steel products (the US imported more than 30mt of steel in 2016, 8% of the global seaborne trade). Meanwhile, efforts to promote US products could imperil the c.4% pa compound growth rate of eastbound transpacific container trade since 2010, although more jobs in manufacturing might also support increased US consumer activity.

Spaghetti Western

Another key aspect relates to energy. The US economy was once driven by cowboys; more recently shale oil has taken a key role. This has reduced energy imports, the US’s largest import category. Crude and products imports fell 45% in the last decade, whilst LNG imports dropped by 86%. Pro-energy industry policies of the new administration may have some further negative effects on hydrocarbon imports, though the set-up of US refineries means that some heavy crude imports are needed to ensure a balanced refinery slate. Conversely, oil industry-friendly policies could encourage exports, although additional LNG exports will partly depend on continued expansion of high-CAPEX liquefaction capacity.


Coming Up Next?

So, the backdrop is that seaborne trade is less dependent on the US than it once was, with some volumes that used to “Go West” increasingly heading to Asia. But, US seaborne trade does remain highly significant, and key elements appear potentially exposed to shifts in aspects of US policy. Though there may be pros as well as cons, looking ahead it’s clearly going to be important to watch closely for the impact of the big change in the US.


Back in the past the gas shipping sectors may have been considered relatively niche within the world of global shipping. However, in the last two decades they have been amongst the faster growing parts of the industry. This week’s Analysis takes a look at how shipping’s ‘coolest’ sector has grown in prominence to become part of the mainstream, and some of the ups and downs along the way.

Keeping Cool

Gas (LNG and LPG) shipping may once have been considered by some as a relatively niche part of global shipping, with the fleet and trade volumes dwarfed by other sectors. Even today, LNG and LPG carriers account for just 5% of total world fleet GT, and LNG and LPG trade accounted for just 3% of global seaborne volumes in 2015. However, following phases of rapid fleet growth, the combined gas carrier fleet now stands poised to top 100 million cbm of gas carrying capacity next year, more than double the size of the fleet at the end of 2007.

Gas Expands

Following expansion in LNG trade in the late 1990s, in the mid-2000s a glut of new export terminal sanctioning led to a surge in LNG carrier contracting, peaking at 10.9m cbm in 2004. This supported average fleet growth of 15% p.a. in the period 2000-08, to 40.3m cbm at the end of 2008. In comparison the LPG carrier fleet grew more steadily, though trade growth was supported by increased export volumes from the Middle East and Europe. Between 2000 and 2008, LPG carrier capacity increased from 13m cbm to 18m cbm, at an average rate of growth of 4% p.a. Across this period combined gas carrier capacity grew by an average of 10% p.a. to total 58.2m cbm by the end of 2008. However, after the economic downturn, sanctioning of liquefaction projects slowed, which limited LNG fleet growth, and growth in the LPG sector slowed too. Between 2008 and 2014, combined gas carrier fleet capacity grew by a much less rapid 6% p.a. on average, with even slower growth in 2011-12.

Powering On

Nevertheless, since the start of 2015 it has been full steam ahead for the gas carrier fleet. With LNG carrier ordering backed by the return to liquefaction terminal sanctioning in the 2010s and the vision of a cleaner energy future, and LPG carrier demand supported by the advent of fracking in the US and refinery capacity expansion elsewhere, 26.1m cbm of combined gas carrier capacity was ordered in 2013-15. This has supported rapid fleet growth in recent years and since the end of 2014, LPG carrier fleet capacity has grown by 32% and LNG carrier fleet capacity by 12%.

Mainstream Profile

So, the gas sector’s profile is fully in the mainstream today, and despite it’s relatively limited share of the world’s tonnage and global seaborne trade, in other ways it accounts for rather more weight. Gas carriers are complex, high value units; they account for 15% of the shipyard orderbook in CGT (shipyard work) terms today, and for an estimated value of $78bn, 9% of the world fleet total. And with a 20-year compound annual growth rate of 8% in combined capacity, and the 100 million cbm mark just around the corner, surely that’s one of modern shipping’s success stories? Have a nice day.

SIW1241 Graph of the Week

The Indonesian government has been trying to reinvigorate investment in the country’s upstream oil and gas industry in the last few years. However, tough market conditions persist and political uncertainty remains a challenge. With oil companies seemingly losing interest in acreage offshore Indonesia, could offshore drilling demand in the country be running out of steam?

Ageing Problems

Indonesia is an OPEC member state and accounted for 16% (0.25m bpd) and 23% (3.67bn cfd) of offshore oil and gas production in SE Asia in 2015. However, oil and gas production off Indonesia declined by 4.7% from 2010 to 2015. In part this decline is because there have been few major discoveries to offset dwindling reserves at the country’s mature fields. Recently, operators have also been less willing to conduct additional development drilling on these depleting fields. As the Graph of the Month illustrates, offshore development drilling fell by 27% y-o-y between 2014 and 2015 and exploration drilling has also been subdued, with just two wells drilled in 2015, compared to 24 in 2014. Moreover, exploration has yielded only seven offshore discoveries since 2014, indicating that future development drilling demand could suffer as well.

Losing Interest

Problematic energy market fundamentals aside, political uncertainty has exacerbated the situation. The implementation of controversial Regulation 79/2010 in 2010 ended previous “assume and discharge” rules, meaning that new Production Sharing Contracts (PSCs) could be subject to varying and arbitrary levels of tax previously “dischargeable”. Operators recoiled strongly, denting interest in PSCs, as demonstrated by lacklustre participation in the 2013 Licensing Round. Corrective actions have since been taken, but it created crippling uncertainty in Indonesia’s upstream sector. Looking ahead, low oil prices and a 30% downwards revision to the level of tax oil companies can offset with costs, operators could become even less willing to commit to offshore acreage. Only 6 out of 11 offshore PSCs were awarded in the 2014 tender round. Moreover, Total and Chevron intend to relinquish the Mahakam and East Kalimantan blocks, which will expire in 2017 and 2018 respectively. Of 115 offshore PSCs held as of end 2015, 39 are undergoing termination, and operators might opt to reduce or end drilling activity if they intend not to renew these PSCs.

Under Pressure

It appears operators are losing interest in acreage off Indonesia, which could translate into weaker drilling demand, though the government has been exploring ways to stimulate investment and may eventually broker deals to keep operators committed to major offshore PSCs and capital outlay. Additionally, the country’s NOC, Pertamina, reportedly could assume operatorship of over 50% of upstream acreage. These factors might improve drilling demand in the longer term.

At present however, Indonesia’s offshore sector is clearly challenged: against the backdrop of globally reduced offshore E&P, the country has its own regulatory uncertainties. These factors have led to reduced interest in offshore acreage and subdued drilling activity. Unless the government can intervene to revive operator confidence, the near future also does not look encouraging for drilling demand.


In recent years, Australia has been a major growth area for offshore gas production and a key driver of offshore CAPEX. However, the prospects for Australian gas projects that have yet to be sanctioned are looking increasingly uncertain due to weaker LNG prices and cost overruns at existing projects. The outlook for Australian offshore projects may also be complicated by the recent Australian general election.

Gas Powered

Historically, the majority of offshore oil and gas production in Australia has been produced from Southern Australia, particularly from the Gippsland Basin. However, E&P activity in recent years has moved offshore North West Australia, where the emphasis is on large, deepwater gas projects. As a result, Australian offshore gas production increased with a robust CAGR of 7.9% from 2010 to 2015, reaching 5.88bn cfd last year and making Australia the fifth largest offshore natural gas producer globally.

Ample Supplies

This trend is expected to continue with the start-up of Phase One of the Gorgon gas project earlier in the year, increasing Australia’s 2016 estimated offshore gas production to 6.44bn cfd. This is probably just the beginning as Australia is projected to become an even bigger offshore gas producer. The country currently accounts for 10 projects that are undergoing EPC or Installation & Commissioning. Foremost amongst these are gas mega-projects such as Chevron’s Wheatstone, Shell’s Prelude and Inpex’s Ichthys LNG developments, which are scheduled to start-up in 2017. This is anticipated to accelerate Australia’s projected offshore gas production to 9.10bn cfd in 2017, before levelling off at 10.9bn cfd in 2020.

Moreover, onshore projects like Gladstone LNG and Australia Pacific LNG, which are now online, have begun to ramp up production. This is likely to lead to a rapid growth in available supply, arguably pressuring market fundamentals and so weakening spot LNG prices. Consequently, the combination of low spot prices, abundant supply and the development of associated gas reserves off Australia could hit the commercial prospects of many potential gas projects off Australia. Additionally, spot gas purchases could also gain favour against term contracts, possibly pressuring gas project feasibility.

Taking On Water

Currently, 41 projects representing an estimated $158bn in CAPEX have not entered EPC and 97% of the reserves from these projects are gas. Given the current challenging outlook for gas project economics, these projects might not receive an FID as operators could delay sanctioning until conditions improve, possibly abandoning some projects altogether. The situation could be exacerbated by Australia’s general election, which (at the time of writing) looks likely to produce a hung parliament, muddying energy policy waters and possibly putting a domestic gas reservation policy on future projects on the political agenda. That being said, the drive for environmentally friendly fuels could boost gas demand and improve the viability of gas projects in the longer term.

Political issues aside though, oversupply and low gas prices are key. Due to these factors, the near term investment outlook is very uncertain. However, with a project backlog of $158bn, offshore Australia still retains massive long term potential.


Generally, shipping industry watchers spend much of their time monitoring events out to sea: how fleets are evolving, trade volumes growing and freight rates performing. But occasionally it can be worth pointing the telescope in the other direction, and spending time considering how events on land can affect the industry. One such major land-based change has been the development of US shale oil and gas.

What No-One Saw Coming

Back in 2009, few would have dared predict that new fracking technologies would allow the US to add 10m boepd of unconventional output across a five year period. This is roughly the same net volume as was added to global offshore output between 2000 and 2015. The offshore markets have been amongst the hardest hit by the oversupply, and cuts in investment will make it harder to add to the 46.9m boepd set to be produced offshore globally in 2016. Since the oil price slump, rig rates have dropped by more than 50%, OSV rates by more than 35%, and today more than 300 rigs and 1,400 OSVs are laid up.

Shale In The Sights

One of the main factors which helped shale fracking to become widespread was the rapid recovery of the oil price after the 2009 downturn. This, of course, also helped the offshore sector have its day in the sun, before the downturn. But shale’s growth also had an impact on other shipping segments. US LPG exports grew at a CAGR of 71% in 2010-15. The growth of shale gas even led to proposals for the first transatlantic exports of ethane derived from it, and orders for ‘VLECs’ vessels followed.

The rise of shale gas also changed the LNG trade fundamentally. In 2010, US LNG imports were expected to be a major growth area. Today, the US has 117mt of under-utilised LNG import infrastructure (imports were just 1.86mt in 2015). Some projects have been converted to liquefaction, and up to 250mt of export capacity was mooted. One new project, Sabine Pass, is now exporting.

Telescoping Tank Capacity

Growth of US shale substantially reduced US import demand for light crudes. This primarily affected imports from West Africa. The transatlantic trade on Suezmaxes and Aframaxes fell from 1.8m bpd in 2010 to 0.3m bpd in 2014. But a 1975 ban on US crude exports prevented tanker exports of surplus oil, much of which is light grades for which US refineries were not ideally configured. US Jones Act tankers and tank barges benefited, as limited fleet supply for upcoast voyages sent coastal timecharter rates as high as $140,000/day in mid-2015, but there was no similar effect on international trade.

The US government has now eased the export restrictions, but this has come as lower oil prices have hit the rig count and output onshore. The lower oil price has caused shale to go into decline. Yet it has provided a nice boost for tanker trades, as low oil prices have stimulated oil demand from transportation and industry.

So, developments in the mid-west of America have had major ramifications for energy shipping and offshore markets globally. This is set to continue as the industry waits to see how shale responds to the slight oil price gain over Q2 2016. This only goes to demonstrate the need to keep this related land-based industry under surveillance. Have a nice day.


Historically, a prime characteristic of the shipping industry has been that when one sector is performing weakly there is generally another that is strong, and that even when most of the markets are down there is often one which provides at least some counterbalance by performing more robustly. Today’s market climate suggest that it’s worth taking a look at this interesting element of the industry’s make-up.

Interesting Indices

One way to examine this is simply to look at the performance of the key sectors over time. The graph shows six-month moving averages of indices representing earnings in the four major volume sectors, with each index based on the 100 mark being equivalent to the historical average. This allows a quick view of the relative health of each sector in historical terms compared to the other key sectors at any point in time. Today, the bulker and containership earnings indices are at a low ebb. Yet, though not quite at last year’s heights, the tanker market continues to perform robustly with the index above 100, and gas earnings, though sliding, still look strong in historical terms.

Looking back, this type of landscape is not new. In the 1990s, for 60 months in a row, the containership index stood above 100 whilst the other market indices lingered below the 100 mark. For over half of the period between May 2001 and March 2003, the tanker market index stood above 100 whilst the other sectors experienced earnings below historical averages. In the aftermath of the credit crunch, in 17 of the 18 months between May 2009 and October 2010 the bulker market index stood above 100 whilst the other indices remained below that level.

Different Drivers

This behaviour should not be unexpected. Only some market drivers are common across sectors. On the demand side, although macroeconomic factors can prove general, commodity-specific trends are often key. On the supply side, whilst shipbuilding, finance and steel industry developments can have a common impact, sector-specific building and demolition trends are very important too.

Clear Coefficients

To some extent this can be measured in statistical terms. The ‘correlation coefficient’ measures the strength of the relationship between two series (+1 represents the most positive correlation, 0 no correlation and -1 the most negative correlation). The average coefficient between the pairs of indices here is just 0.26, implying little correlation. Removing the more ‘niche’ gas sector index from the comparison, the average coefficient between the remaining three series is 0.52, still not really indicative of a particularly significant positive correlation.

Helpfully Out Of Sync?

So, shipping markets are highly cyclical but the cycles are not always in sync. In less than 20% of the period here were earnings in all four sectors concurrently below historical averages. With some sectors today looking fragile and demand growth sluggish overall, history might offer some reassurance if the brighter spots start to fade, by suggesting that something else might eventually have its time in the sun. Have a nice day.


Over the course of the last 20 years, oil and gas companies have cultivated a vast metallic forest beneath the world’s oceans, consisting now of some 5,800 installed subsea trees. The growth of this artificial arboretum has supported an array of related offshore fabrication, installation and IMR industries. But how to assess the outlook for this complex sector? Well, one key metric is the subsea tree backlog…

Into The Woods

The tree ‘backlog’ is the ‘orderbook’ of subsea trees. It is constituted by trees ordered by oil companies from subsea fabricators that have not yet been installed. A tree itself is the tall array of valves that caps a well; unlike ‘dry’ trees, subsea or ‘wet’ trees are located on the seabed, rather than on fixed platforms or MOPUs. While fields can host various subsea structure types, trees are at the core of nearly all subsea developments. Hence, the backlog is a key proxy for subsea CAPEX and subsea construction vessel demand. The real boom for the subsea sector came in period of high oil prices after 2009, as innovation in the subsea sector facilitated deepwater frontier projects in West Africa, Brazil and the US GoM. The backlog grew from 647 units in Q3 2009 to a peak of 1,158 at start Q4 2014 – an increase of 79%. At this point a number of large projects utilising subsea trees had recently reached the EPC stage, including TEN (Ghana, $4.9bn, 36 trees), Egina (Nigeria, $15bn, 44 trees) and Buzios (Brazil, $2.6bn, 20 trees). The charter rate for a large (250t crane) MSV in the North Sea, meanwhile, stood at around $52-59,000/day.

Cut Down To Size

However, like other offshore sectors, the subsea sector has been adversely affected by weaker oil prices (and the paralysis at Petrobras). Initially the backlog provided a degree of insulation for fabricators and installation contractors. The backlog is eroding though, having fallen y-o-y in each of the last nine quarters by between 1% and 14%. As at start Q2 2016, it stood at 876 units, down 24% on the Q4 2013 peak. Installers have been working through the backlog while new awards have dwindled (only 59 trees have been contracted in 2016 as at start May) due to a dearth of project FIDs. True, the subsea sector has held up better than the rig or OSV sectors (in part due to IMR demand, not captured by the backlog size) but North Sea dayrates for a 250t MSV have fallen by 34% since Q2 2014, to $32-43,000/day at start May 2016.

New Spring?

Could things in subsea get as challenging as in the rig and OSV sectors? Perhaps, but that depends on the timing of the recovery in offshore project FIDs. Besides, the downturn is not all bad for subsea – in the long run. In order to reduce field development costs, companies are increasingly relying on subsea efficiency gains – Statoil’s subsea standardisation drive is a notable example of this. As costs at subsea projects fall, more such projects are likely to receive FIDs. New tree awards are expected to recover to around 300 per annum by the end of the decade.

So subsea seems to be becoming more challenged, as reflected in the falling subsea tree backlog. But subsea is likely to play a key part in the recovery too. The arrival of new awards, followed by a sustained increase in backlog, will be a good indicator of when the offshore market is out of the woods.