Archives for category: LNG

Energy is shipping’s biggest single market, accounting for 43% of the cargo moved in 2013 – 4.3 billion tonnes. Oil is still the big dog, with 2.8 billion tonnes of cargo and the coal trade has now reached 1.2 billion tonnes. Which leaves gas as the junior partner in the energy triangle with 307 million tonnes of trade in 2013, of which 244 million tonnes was LNG and an estimated 63 million tonnes was LPG.

The Crown Prince Of Energy

LNG may still be the junior partner in tonnage, but it is widely seen as a future “seed corn” trade for the maritime business. This positive perception rests on two foundations. Firstly there are enormous reserves of “stranded” natural gas located so far from the world’s major consumer zones that sea transport is the only way to bring the product to market. Secondly natural gas is a clean fuel, in an era which is becoming increasingly preoccupied with reducing emissions of carbon and other pollutants into the atmosphere.

Fight For The Title

But it’s not all plain sailing and LNG is up against some tough competition – coal and oil – and in the three way fight for market share which lies ahead it has a few strategic disadvantages. Oil, the ultimate portable energy source, has the land and air transport fuel market nailed down. In this market the need to maintain LNG at a temperature of -162°C makes competition extremely difficult, and creates limitations to the wider use of LNG as a transport fuel.

The other major market is power generation and here LNG is on firmer ground. Once the storage and re-gasification facilities have been installed, LNG is the ideal clean fuel. The problem is that in this market coal is a long established and devastating competitor. Coal is generally much cheaper than gas and more widely available. In contrast gas supplies are more limited, requiring major investment, and are often located in “difficult” geopolitical areas.

Speedy Growth

Despite these disadvantages, the LNG trade has turned in a spritely growth performance. Since 1984 imports by countries east of Suez have grown by a CAGR of 5.8%, and by 6.5% west of Suez (despite a slowdown in 2012-13). Compared with the growth of the oil trade when it developed more than a century ago, this is super-fast. 44 years since the first LNG shipment by sea to Asia, global trade in 2013 reached 532m cbm, or 244m tonnes, with a fleet of 31m dwt. For comparison, after 44 years seaborne oil trade only reached 55m tonnes and the tanker fleet was just 9.5m dwt (in 1928). This is a reminder that although LNG has not been an easy ride, things take time and LNG’s growth path is pretty dynamic (though not without its problems – in the 1980s one third of the fleet was laid up).

Trending But Tricky

If current growth trends continue, LNG trade could reach one billion tonnes in the 2030s. It is easy to believe that there will be demand in an energy hungry world for this clean fuel, despite its limitations. But in the meantime LNG is a niche player, trading luxury fuel to price sensitive markets. Which makes it tricky, even for the big boys. Have a nice day.


While the expanding role of Asia (especially China, see SIW 1132) in seaborne trade has grabbed headlines in recent years, developments in the US, still the world’s largest economy, have also had a significant impact. In a short space of time, changes in the US energy sector have dramatically altered global trading patterns in a number of commodities, significantly impacting the pattern of volume growth.

Putting On A Spurt Of Energy

For much of the last three decades, US oil production has been in decline, falling on average by 1% a year since 1980 to a low of 6.8m bpd in 2008. Yet technological advances have since led to huge gains in exploitation of ‘unconventional’ oil and gas shale reserves. In the space of just six years, the US managed to raise oil output alone by an astonishing 60% to almost 11m bpd, a new record.

Making An Oil Change

This has led to huge changes in US energy usage and import requirements. Crude oil imports have almost halved since 2005, and since 2010 have fallen on average by 11% p.a. to 260mt last year. Exports of crude oil from West Africa in particular have had to find a home elsewhere (unsurprisingly, many shipments now go East). Since US crude exports are still banned, US refiners have taken advantage of greater domestic crude supply to produce high volumes of oil products, especially for shipment to Latin America and Europe. Lower US oil demand since the economic downturn has also contributed, and seaborne product exports reached 120mt in 2013, up from 70mt in 2009. Alongside global shifts in the location of refinery capacity and oil demand growth, these trends have transformed seaborne oil trade patterns.

The impact could be similarly profound in the gas sector. As US imports of gas, mostly LNG, have dropped (on average by 34% per year since 2010), plans to add up to nearly 100mtpa of liquefaction capacity by 2020 could mean the US eventually emerges as a major LNG exporter, potentially accounting for 15% of global capacity (from 0.5% currently). Meanwhile, LPG shipments are continuing to accelerate strongly, rising by more than 60% y-o-y so far in 2014 to 6mt.

Miners Under Pressure

There has also been an impact in the dry bulk sector. Lower domestic gas prices have pushed the share of coal in US energy use to below 20%, leaving miners with excess coal supplies. US steam coal exports jumped to 48mt in 2012 from 11mt in 2009, contributing to lower global coal prices (cutting mining margins) and higher Asian import demand.

So What Next?

So the effects of the changing balance in the US energy sector have been far-reaching, and there remains scope for more shifts to occur as trade patterns continue to adjust to changes in commodity supply and prices. While the firm pace of expansion in US oil and gas output may start to slow, any change to existing export policies could have further impact. What is clear already, in terms of seaborne trade growth, is that the focus has shifted away from US imports, for decades a key driver of the expansion of global volumes, towards the country’s developing role as an energy exporter.


Natural gas demand and onshore and offshore production data is now available in Offshore Intelligence Monthly, split out by region and country on pages 3, 6-7 and 20-25. Analysing this data, it is apparent that the offshore hydrocarbons cake just keeps on getting bigger.

Since 1993, world combined offshore oil and gas production has increased by 58%, to 43.7m boepd in 2013; and between 2013 and 2023, it is forecast to increase by a further 35%, to 58.9m barrels oil equivalent per day (boepd). While oil is playing its part in this, gas is proving an even more potent rising agent in the offshore mix, of which it is taking an increasing share.

Measuring the Ingredients

As the Graph of the Month shows, growth rates for offshore oil and gas production have moved more or less in line y-o-y, with gas consistently ahead of oil as hitherto undeveloped historical offshore gas discoveries are brought onstream. While offshore gas production grew with a 3.8% CAGR from 1993 to 2013, oil exhibited a 1.4% CAGR. The spread between gas and oil production is forecast to continue 2013-23, with gas and oil production CAGRs of 4.2% and 2.0% respectively. It is thus expected that offshore gas production will almost achieve parity in volume terms with offshore oil by 2023, accounting for over 49% of offshore hydrocarbons output (versus 32% in 1993).

Energy Hunger

The strength of gas in the offshore production mix in part reflects faster historical and anticipated growth in gas demand. Since 2009, oil demand growth has stagnated in OECD countries whereas gas demand growth has remained firm, averaging 3.0% p.a. 2010-13 with a rate of 2.1% projected for 2014. In non-OECD countries, gas demand growth averaged 4.7% over the 2010-13 period, compared to 3.9% for oil demand. Similarly, 2014 demand growth is forecast at 3.7% for gas and 2.7% for oil. As non-OECD countries continue to industrialise, demand growth for natural gas is likely to remain firm.

Let Them Eat Cake

Given this scenario, it is likely shale gas will meet only a portion of future demand. Conventional gas will still have a role in feeding world energy hunger, and the offshore gas element of this increasingly so. In 2013, 30% of world natural gas production was offshore; in 2023 this is forecast to reach 36%. Accordingly, the offshore gas field investment outlook is positive. Offshore field operators are initiating schemes to utilise associated gas at mature oilfields. Moreover, development of offshore gas fields is increasingly perceived as economic. Gas fields account for 51% of fields under development and 48% of undeveloped offshore discoveries.

More so than oil, offshore gas growth is driven by mega-projects. Current examples include nine South Pars phases off Iran, Leviathan off Israel and Shah Deniz II in the Caspian, due onstream in 2015-17, 2017 and 2019. Major LNG projects planned offshore East Africa and Australia, entailing extensive subsea production systems and deployment of the world’s first floating liquefied natural gas (FLNG) vessels (like Shell’s “Prelude”), are also responsible much of the forecast growth in offshore gas. All in all then, gas looks to be quite a tasty slice of the offshore cake. Bon appétit!


OIMT201405Russia is forecast to account for 13% of world crude oil production and 18% of world natural gas production in 2014. While its prodigious Siberian flows tend to receive most of the credit for this feat, fields located off the country’s 16 million km of coastline are nonetheless projected to produce 390,000 bpd oil and 2.64 bcfd gas in 2014. So where exactly is Russian offshore production to be found? And what is the outlook?

Mastering the Arctic

As the Graph of the Month shows, offshore oil and gas production in Baltic & Arctic Russia stagnated after the break-up of the USSR, declining to 0.03m boepd in 2013, when it accounted for 4% of Russian offshore production. This trend was thrown into reverse when the Prirazlomnoye field came onstream in December 2013. Located 23km from shore in the Pechora Sea, the field is exploited via a ice-class platform and production is scheduled to reach 120,000 bpd by 2019. New technologies and robust oil prices are thus unlocking reserves hitherto stranded, and by 2023 Arctic oil and gas is forecast to constitute 11% of Russia’s offshore production.

Caspian and Crimean Conquests

Russia’s southern offshore fields, mainly in the Caspian, accounted for 9% of Russian offshore production in 2013. In the Caspian, as in the Arctic, harsh conditions have limited field development and disincentivised efforts to halt production decline. However, as in the Arctic, decline is now forecast to be arrested. Lukoil, for example, are planning substantial investment over the next four years at fields like Khvalynskoye and Yuri S. Kuvykin, where ice-class jack-up production units are likely to make development feasible. By 2023, the area is forecast to account for 24% of Russian offshore oil and gas production (excluding gas produced by fields off the Crimea, over which Russia now has de facto control, and which produced 410m cfd in 2013).

Expanding Eastwards

The Russian Far East is a relatively new area of offshore E&P. The Sakhalin-2 project started up in 1996 but offshore activity is still geographically limited, even if production volumes, at 0.78m boepd, are significant. The area accounted for 88% of Russian offshore production in 2013. Moreover, the Far East is Russia’s window on the developing economies of the Asia Pacific region, so companies are seeking to increase activity there, particularly with regards to LNG. In October 2013, the first Sakhalin-3 field, Kirinskoye, a subsea-to-shore development, began ramping up to 580m cfd. Further such field developments are planned out to 2023, when the area is projected to produce 0.95m boepd, its share falling to 65% despite new Capex due to faster Arctic and Caspian growth.

Thus production is forecast to grow in each of Russia’s offshore areas, driven largely by investment in high-spec jack-up, fixed platform and subsea field solutions. Total offshore oil production is projected to grow with a CAGR of 8.9% from 2014 to reach 890,000 bpd in 2023, and gas production likewise at 2.5% to reach 3.36 bcfd. Offshore would then account for 6.7% of the country’s oil and gas production, a far cry from the 2% nadir of post-Soviet decay.

OIMT02The floating LNG or “FLNG” concept has existed for decades; however it was not until 2011 that a long term solution was officially cemented with the signing of the $3bn build contract for ‘PRELUDE FLNG’. Following this, the FLNG sector has seen a new wave of activity, and contracts for 2 further units were placed in early February. Early estimates suggest as much as $85bn could be invested in FLNG technology by 2020, making it an exciting growth area.

A Demand Story

The Graph of the Month displays the cumulative potential FLNG requirement of 36 mooted FLNG projects with targeted delivery dates up to 2020. Of course, it is highly unlikely that all of these projects will actually come to fruition, with those rated ‘possible’ significantly more speculative than the more ‘probable’ units. However, if all those FLNG projects currently deemed ‘probable’ are ordered, then the number of operational units could be as many as 10 units by 2018 and 16 by 2020.

The major reason for the interest in FLNG is the desire to exploit ‘stranded’ gas fields far from existing infrastructure, given the strength of future gas demand expectations (BP’s Energy Outlook puts gas demand growth at 2.2% p.a. in the period to 2025). Accordingly, offshore gas output is expected to grow at a compound rate of 4.5% per year to 140bn cfd by 2020. FLNG could become a key part of this.

The major focus of growth in projects which could utilise FLNG will be Asia Pacific, notably off Australia. Close to half of potential FLNG locations are in the region, many in the Browse, Carnarvon and Bonaparte basins off north west Australia. While the Asia Pacific region remains a key area of growth, the Americas and Africa also hold opportunities for the positioning of potential units, with 17% apiece.
At the start of February, 2 further FLNG orders were placed. Petronas took the final investment decision (FID) for Rotan gas field off Malaysia, and awarded the contract for the hull to Samsung H.I. Meanwhile, Exmar have added a second moored barge unit to the order already under construction for use on Colombia’s Caribbean coast.

Not Yet Tried and Tested

Although this demonstrates the continued positivity surrounding the FLNG sector, it remains untested, with FLNG technology yet to enter operation. The first FLNG unit is slated for delivery in 2014, and will be the first of the Exmar barge-shaped units for Colombia. However, until the first LNG cargo is loaded (2015), it is unclear what technical challenges may be faced. Furthermore, the FLNG sector also faces risk from commodity prices. Should the US start to export shale gas on a large scale, this may produce downward pressure on gas prices, potentially making FLNG solutions less attractive to investors.

Fuelling the Future

So, the FLNG sector is still in its infancy and the outcome of the first projects could have a big impact on future investment. Ultimately, such a nascent sector faces technological and economic challenges. However, with offshore gas output set to increase substantially, it is likely that requirements for FLNG vessels will continue to progress.