Archives for category: LNG

The development of the global merchant fleet is affected by a very broad range of interwoven supply and demand factors, including shipping and commodity cycles, investor sentiment, regulatory concerns, yard capacity and so on. Another factor is shore-side infrastructure projects, which can be tricky to disentangle from the wider web, though this influence is a little clearer on, for example, the LNG carrier sector…

For the full version of this article, please go to Shipping Intelligence Network.

The introduction of new environmental regulations is leading the shipping industry to look for ways of reducing its emissions of harmful gases. This week we focus on two separate but related issues: the way in which vessels are powered, and the type of fuel that they use. New technologies are being adopted, with certain ship types leading the way…

Electric Therapy

The majority (96%) of active merchant vessels are powered by mechanical systems in which a form of fuel oil powers a main engine (usually a 2 or 4-stroke diesel) which is connected to the propeller. Most other vessels are “diesel-electric”, in which the power generated by the (4-stroke) main engine(s) is converted to electricity before being transferred to propeller(s) or thruster(s) via electric motors.

By optimising the loading of the engines, diesel-electric systems can lower fuel consumption and emissions. These systems are well established in sectors such as offshore, tugs and passenger, where manoeuvrability, variation in power demand and engine noise are important considerations. For larger cargo vessels, where demand for power is generally higher and more consistent, conventional mechanical systems remain more efficient and cost-effective. Our Graph of the Week shows that against a backdrop of reduced contracting in the larger cargo sectors, electrically-driven ships have assumed a greater share of the newbuilding market, accounting for 22% of reported newbuilding contracts so far this year.

Battery Charged

The next step for electric power may be more widespread adoption of batteries in main propulsion systems. There are 22 vessels in service and 14 on order that use batteries, mostly alongside either conventional diesel or dual-fuel generating sets. As well as reducing emissions when using battery power, these can enhance efficiency by optimising engine loads and transferring surplus power to or from the batteries as required. For smaller ferries intended for short routes, all-electric propulsion systems are feasible.

Gas Treatment

LNG has been identified as a cleaner fuel capable of reducing vessel emissions in line with new regulations. Clarksons Research’s World Fleet Register currently identifies 542 merchant ships in the fleet and on order capable of using LNG fuel. 351 of these are LNG carriers, which can use cargo boil-off to fuel a choice of turbine, dual-fuel diesel electric or dual-fuel 2-stroke main engines. In other sectors LNG fuel has taken longer to gain market share, but there are signs that where ship designs and the supply of bunkers allow, it is becoming more popular. Out of the 130 contracts recorded so far in 2017, 21 are for vessels capable of using LNG fuel. These include 4 Aframax tankers, the largest vessels other than LNG carriers to adopt dual-fuel 2-stroke engines.

More efficient power systems and cleaner fuels are two examples of how the shipping industry is responding to the challenges set by new environmental regulations. Alongside other developments in vessel design and operating practices, shipping is steering towards a more efficient and cleaner future. Have a nice day!

SIW1266:Graph of the Week

Natural gas is set to account for an increasing share of the global energy mix in coming years, with gas consumption growing by an average of around 1.5%-2% a year out to 2040, according to energy forecasting agencies such as the IEA. And based on recent trends, if the consensus views on natural gas prove accurate, the implications for the offshore and LNG carrier fleets are likely to be significant.

Stepping On The Pedal

In 2016, global natural gas demand stood at an estimated 347bn cfd, up by 24% on the 280bn cfd consumed in 2006. Demand for natural gas in recent years has been driven by industrialisation in developing economies (Chinese gas demand, for example, grew at a CAGR of 13% in 2006-16) and environmental concerns the world over. Historically, the majority of trade in natural gas has been by pipeline, for instance from Eurasia to Europe. In 2015, pipelines still accounted for 68% of natural gas volumes moved globally.

However, liquefied natural gas (LNG) has become an increasingly important form in which gas is traded, even given the costs of complex liquefaction and regasification facilities. Over 50% of existing nameplate liquefaction capacity at LNG export terminals (349mtpa globally) has come online since 2005. As a corollary, from start 2006 to start March 2017, the LNG carrier fleet increased from 193 to 479 vessels and tripled in total capacity to 70.2m cubic metres of LNG.

Shifting It Up A Gear

Growth in the seaborne LNG trade is in turn closely linked with growth in offshore gas production, as major LNG exporters such as Qatar and more recently Australia use offshore gas fields to provide feedstock to LNG trains. Qatar accounted for 30% of LNG exports and 22% of existing liquefaction capacity in 2016, all fed via offshore gas, mostly from the giant North Field. In 2006, offshore fields accounted for 28% of global gas production and by 2016, 31%. This is set to rise to 32% (119bn cfd) in 2017, mainly due to field start-ups off Australia that are to feed LNG projects like Wheatstone. Finding, developing and supporting offshore gas fields on Australia’s NW Shelf has created demand for a range of vessels from the offshore fleet of over 13,500 units.

More Gas In The Tank

The exploitation of these remote reserves has also spawned the FLNG concept – vessels that can be used to exploit otherwise stranded gas. The LNG markets are clearly challenged at present but in the long term, planned FLNG projects in Australia, Mozambique, Tanzania, Mauritania and other areas could potentially sustain offshore gas production growth. Another major source of gas production growth has been the US shale gas sector, where production rose from 4bn cfd in 2007 to 48bn cfd in 2016. The US accounts for over 50% of liquefaction capacity under construction (while some planned projects entail liquefaction of shale gas on near-shore FLNGs) and is set to become a major LNG exporter in coming years.

So offshore gas production has grown as a share of total global gas production, as has US shale gas. Both trends can create opportunities for LNG and offshore vessels. And if, in line with consensus expectations, gas continues to grow as a share of the energy mix, then these trends may have a long and interesting road ahead.

SIW1265:Global Natural Gas Production And LNG Export Capacity

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

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.

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Plagued by constant blackouts and power shortages, Egypt appears to be facing its worst energy crisis in decades. However, following the historic discovery of the giant gas field Zohr offshore Egypt in August this year and revived interest from IOCs, it seems that the tables are set to turn. Indeed, after a period of gas production decline, Egypt’s energy outlook is getting increasingly bright.

Slide Down The Gas Pyramid

Until recently, Egypt’s gas production story had been one of growth: production climbed from 1.68 to 5.76 bn cfd between 2000-2009 and in 2003, it was sufficient to kick-start LNG exports. However, a combination of political unrest (notably the Arab Spring of 2011) and rising population has resulted in natural gas supply shortages over the last 5 years. Domestic gas demand has on average grown by 8% y-o-y, eventually outstripping supply. As a result, Egypt has been forced to re-route LNG destined for exports to domestic consumption. Indeed, at the start of 2014, BG announced it was breaking its contracts because it was unable to export enough gas. This year, Egypt resorted to importing LNG from Qatar – a bitter moment for the previous exporter.

Enter Zohr

They say that when you hit bottom, the only way is up and for Egypt, this seems to be the case. Earlier this year, ENI made what is believed to be the largest ever gas discovery in the Mediterranean, named Zohr. The field is part of the Levantine Basin, home to other prolific gas finds such as the Israeli Leviathan field. ENI puts the find down to different use of sequencing models, concentrating on carbonate rather than classical sand reservoirs. The gas giant (estimated to hold 30 tcf of lean gas) is located in water depths of 1,450m, providing an exciting departure from typical shallow exploration of mature basins in the region. Additionally, BP announced a $12 billion investment in Egypt’s West Nile Delta project: another deepwater discovery with 5 tcf of gas resources. A move to deeper waters creates opportunity for subsea development, the current production solution of choice in all of the country’s active deepwater fields. Out of the 68 active subsea units in Egypt, 40 are operated by ENI and 8 by BP. It is likely that these operators will continue to implement subsea development in their future projects.

Clash Of The Giants

Elsewhere, the discovery of Zohr was not such welcome news. There were plans to import gas via a pipeline from the Tamar field and (once in production) the competing gas giant, Leviathan, in Israel. Plans for the Leviathan field will now have to be redrawn and potentially accelerated if Israel wants a claim of the region’s LNG exports. However, following extensive regulatory and anti-trust objections, its start-up date remains uncertain.

Nevertheless, it is clear that Egypt’s fortunes are turning. The Zohr discovery, alongside other scheduled start-ups, will strengthen Egypt’s energy balance in the long-term. And the story does not end here: it has been reported that there are 7 other deepwater blocks with similar lithology to ENI’s. There is evidently a revived interest in the Levantine basin, as IOCs begin to wonder where the next giant could be hiding.

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Since 1970, 179 offshore gas fields have been discovered in the Browse and Carnarvon Basins of Australia’s Northwest Shelf. From around 2005, as offshore technology advanced and Asian gas demand rose, operators hatched plans of monstrous magnitudes for these fields. However, in an environment of low oil prices and E&P spending cuts, some of these offshore behemoths now look more endangered.

Taming The Seas

The Australian NW Shelf accounts for about 15% of offshore projects globally with CAPEX of over $5bn. NW Shelf projects tend to be capital intensive, in part because they are remote, with an average distance to shore of 161km. Development thus entails long export pipelines (889km for Ichthys, for example) to onshore LNG plants, or as yet unproven FLNG technology. CAPEX in turn contributes to high project breakeven prices, as does OPEX: for example, OSVs make longer trips for far-from-shore projects. Until recently, high project breakevens stymied final investment decisions (FIDs). However, due in part to cost-saving subsea and cryo-technology, in 2007, Chevron approved Greater Gorgon, a $37bn multi-field project with reserves of 40 tcf. Subsequently, 11 more projects received positive FIDS, including Prelude ($12bn), Pluto ($16bn) and Wheatstone ($29bn).

Teething Problems

Since 2007, 4 of these projects have come onstream and the other 8 are due to begin ramping up 2015-17. However, these 12 projects have not been without their problems. Greater Gorgon, for instance, was first scheduled to start up in 2H 2014, rather than 2H 2015; CAPEX has risen by 49% to $55bn. Meanwhile projects yet to be sanctioned have seen FIDs delayed by operators trying to cut costs. Scarborough, a mooted $19bn FLNG development 286km from shore (which has now been delayed again due to the fall in the oil price) underwent multiple FEED studies following the 2010 pre-FEED. Before circumstances changed, a 2019 start-up briefly looked likely.

Monsters Have Feelings Too

NW Shelf gas projects are thought to be some of the more sensitive globally to the change in the oil price since mid-2014. Greater Gorgon’s breakeven is relatively low for the area, but still stands at $67/boe. Projects further from shore are thought to have higher breakevens, in the $80-100/boe range. No Australian project more than 250km from shore has passed FID, though 50% of those yet to reach EPC exceed this distance, casting doubts on their viability. Since the fall in the oil price, Scarborough’s FID has been postponed to 2017/18; start-up before 2023 is considered unlikely. Other projects facing fresh feasibility concerns include Equus, Browse, Greater Sunrise, Crux and Cash Maple. Indeed, the average slippage for such projects already stands at 40 months. Many may not now come onstream before 2023 and a paucity of start-ups is anticipated in the mid-term, 2018-22, due to delayed FIDs 2014-17.

Clearly, then, remote Australian mega-projects are subject to high costs and breakevens, which increases slippage risk. That being said, the long-term fundamentals of energy-hungry non-OECD economies still suggest remaining NW Shelf gas will be viable eventually. These mammoth projects are not extinct yet.

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