Global LNG · © ArgusMedia Ltd MONTHLY Global LNG LNG MARKETS, PROJECTS AND INFRASTRUCTURE VOLUME...

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M O N T H L Y

Global LNGLNG MARKETS, PROJECTS AND INFRASTRUCTURE VOLUME X, ISSUE 4, APRIL 2014

Tokyo treads tricky path to security 3

Japan’s gas retailers bank on growth 4

Producers split on Europe’s demand 5

Shell cements pole position 6-7

India’s Gail sticks to US strategy 8

Woodside seeks buyer clarity 10-11

Battle for PNG fields intensifies 12

Market markers

Spain: LNG vs electricity $/mn Btu

Jul 12 Oct Jan 14 Apr Jul Oct Jan 145

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Month-ahead electricityLNG

Spanish LNG vs electricity $/mn Btu

US LNG vs Henry Hub $/mn Btu


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10Henry Hub

LNG

US LNG vs Henry Hub $/mn Btu

Chevron is already marketing LNG from a proposed fourth train despite giving no firm date for its completion

Chevron is marketing LNG from a possi-ble expansion of its three-train 15.6mn t/yr Gorgon LNG development in Western Australia, it says.

The company did not say when a new train at the $54bn Gorgon project would come on line. It is evaluating a fourth train and has 11 trillion ft³ (308bn m³) of gas resources to underpin the expansion, Chevron upstream senior vice-president Jay Johnson said last month.

Chevron is marketing additional LNG associated with the fourth train, but does not indicate to whom. The company has a 47.33pc stake in Gorgon and has sold through binding agreements 65pc of its share of output from the project’s first three trains. Gorgon is 78pc complete and plans first shipments in 2015.

But the timing of Gorgon’s start-up, which has already been pushed back from an original launch of late 2014, was put in doubt when partner Shell said on 13 March that the first three trains will come on line between 2016 and 2018. Shell owns 25pc of the project.

Chevron had been quiet on a pos-sible expansion at Gorgon in the past 18 months (AGL, February, p11). The project has been hit by two cost increases, rising to $54bn in December last year, or 46pc above the original estimate of $37bn (AGL, January, p14).

The Australian government’s com-modity forecaster, Bree, agrees with Chevron’s timing of the Gorgon start-up. The three Gorgon trains are likely to come on line in the first half of 2015, second half of 2015 and first half of 2016, it says.

Bree’s latest five-year outlook, released on 26 March, puts Australian LNG exports at 79mn t in the financial year to 30 June 2019, which compares with its prediction a year earlier for 88mn t of exports in 2017-18. Bree expects later start-ups at some of the seven LNG projects under construction, which have combined capacity of 61.8mn t/yr. Its higher forecast last year was based on assumptions of further expansions at these projects.

Revision, revision, revisionBree revised the timing of the other pro-ject that Chevron is building in Australia — the 8.9mn t/yr Wheatstone venture. It now expects the first train to start ship-ments in the second half of 2016, with the second train following in the first half of 2017, compared with its prediction last year that both trains would start in 2016.

It pushed back the expected start-up of the second train at UK firm BG’s 8.5mn t/yr Queensland Curtis LNG (QCLNG) venture to the second half of 2015. The first train will start later this year. Bree last year forecast that both QCLNG trains would start this year.

Bree expects Shell’s 3.6mn t/yr Prelude floating LNG project in the Browse basin offshore Western Australia to start up in the second half of 2017, compared with its previous forecast of a 2016 start-up. Shell said on 13 March that Prelude was 50pc complete, but gave no specific date on its first ship-ments, except to say that it would come on line between 2016 and 2018.

‘Non-price elements of oil-linked contracts are an important part of the value to the buyer, and not really captured by just doing a Henry Hub comparison’ — Shell Q&A (see pp6-7)

Gorgon expansion output on offer

Japan: JCC vs LNG $/mn Btu


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22Japanese Crude CocktailLNG

Japanese LNG vs crude $/mn Btu

Key price points $/mn BtuJan Feb

Zeebrugge gas month-ahead 10.62 9.62

US Nymex month 1, Henry Hub 4.41 5.58

US LNG import price 6.75 na

Japanese Crude Cocktail 19.57 19.12

Japanese LNG import price 16.80 16.61

— Markets and data pp16-28

April 2014

© 2014 Argus Media Ltd www.argusmedia.com

Argus Global LNG —

ContentsAsia-PacificTokyo on delicate path to energy security 3Japan gas sales to grow despite tax hike 4India’s Gail sticks to US LNG strategy 8Oil Search to stymie Total’s PNG deal 12Debate rages over Australian LNG viability 12Gladstone LNG boosts gas supply 13

Middle East and AfricaCameroon LNG may start as early as 2019 4

AmericasEndesa signs supply deal with Cheniere 3US Pacific coast export prospects improve 9

Europe and FSUProducers split on demand outlook 5

GlobalDevelopers push for pricing certainty 8Bree sees 50pc rise in global demand 13

CorporateQ&A: Shell cements position at the top 6-7Q&A: Woodside identifies upside 10-11

BriefsIndia’s gas price reforms face delay 14Lithuania asks for Nato US LNG exports 14

Kogas slows investment on debt plan 14PetroChina makes loss on gas and LNG 14Gail and Chubu combine on LNG buying 14Mozambique LNG signs initial deals 15PNG LNG to export 9-13 cargoes this year 15Gazprom discusses LNG sales to Kuwait 15BofA Merrill Lynch signs Dubai LNG deal 15Bulgaria and Greece mull joint FSRU 15

MarketsMarket overview 16European pipeline markets 19US pipeline markets 20Competing fuels market 21-22LNG fleet news 23Shipping netbacks 24Global LNG import volumes 25-26Spark spreads 27LNG movements 28

Data and pricesGlobal LNG import prices 17-18European pipeline prices 19Pipeline spot markets 20Oil, products, coal and power prices 21Shipping order book 24LNG netbacks 25International spark spreads 27Latest estimated imports and exports 28

Issue highlightsl�Tokyo pursues energy securityGreater dependence on Russia is a risk for Japan’s long-term LNG procurement plans amid increased tensions between Moscow and Washington (see p3).

l�Japan sees growth despite taxJapan’s major gas retailers expect mod-erate gas sales growth amid a sustained economic revival, despite a consump-tion tax increase (see p4).

l�Shell cements top positionShell’s acquisition of Spanish firm Repsol’s Latin America LNG assets strengthens its position as the world’s largest LNG supplier (see pp6-7).

l�Woodside seeks buyer clarityWoodside Petroleum faces surging costs at its LNG projects in Western Australia and a dispute over its Sunrise venture in East Timor, as it seeks a deal with Israel over the country’s Leviathan LNG export plans (see pp10-11).

Contents

Argus Global LNG is published by Argus Media Ltd

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April 2014


Argus Global LNG — Japan/US

The Ukraine crisis is a reminder for Tokyo that greater depend-ence on Russia may pose risks for Japan’s long-term LNG procurement plans. This would leave the fate of its post-Fuku-shima-Daiichi energy security hanging in the balance amid increased tensions between Russia and the US, the two future key LNG suppliers for the country.

Premier Shinzo Abe’s active energy diplomacy has taken centre stage in Tokyo’s continuing quest for answers to the country’s post-Fukushima-Daiichi fuel mix (AGL, May, p1). Abe had hopes of agreeing LNG supplies from Russia to reinforce Japan’s long-term energy security. And Tokyo envisioned that progress in bilateral relations could expedite talks to resolve the dispute over the Kuril islands and lead to a peace treaty to formally end World War 2 hostilities during President Vladimir Putin’s expected visit to Japan later this year.

Russia has taken advantage of its close proximity to Japan and boosted LNG exports to help Japan meet increased demand after the Fukushima-Daiichi crisis resulted in nuclear power plant closures. Imports of Russian LNG rose by 42pc in three years to a record 8.6mn t in 2013, accounting for 10pc of Japan’s total. The country’s total LNG imports increased by 25pc to 87.5mn t over the same period. Japanese firms have contracts to import 5mn t/yr, plus optional supply, from Russia’s 10.6mn t/yr Sakhalin 2 LNG project (AGL, July, p3).

Japanese firms, with backing from Tokyo, have stepped up co-operation and investment in upstream and LNG develop-ment in Russia’s far east, aiming to double LNG exports from Russia to Japan by 2020. Japan’s Inpex and Japex, as well as trading firm Itochu, are co-operating with Russia’s state-con-trolled Gazprom to develop the 10mn t/yr Vladivostok LNG pro-ject and jointly market the LNG in Japan (AGL, July 2012, p5).

Russian state-controlled energy firm Rosneft has teamed

up with Japanese trading firm Marubeni to develop a 5mn t/yr LNG project in Sakhalin and is committed to deliver 1mn t/yr of LNG to the Sodeco consortium and 1.25mn t/yr to Marubeni — both Sakhalin 1 investors — from 2019 (AGL, January, p7). Japan’s economy, industry and trade ministry holds 50pc in Sodeco, with Japex, Marubeni and Itochu owning the rest. Sakhalin 2, in which trading firms Mitsubishi and Mitsui are investors, plans to add a third 5mn t/yr train as early as 2019.

“Developing relations with Russia is in the best interests of our country,” Abe said last month. But Russia’s incursion into Ukraine has complicated efforts by Tokyo to forge ties with Moscow. Tokyo may be forced to consider turning away from Russia as its G7 allies threaten a new round of sanctions targeting Russia’s energy sector. Japan’s investment in Russia has been led by state-run energy agency Jogmec and Inpex and Japex, in which Tokyo holds 18.9pc and 34pc, respectively.

International relationsTokyo remains wary of a fresh policy intervention by its US and European allies after suffering a major diplomatic defeat over implementing tougher sanctions against Iran. Inpex in 2010 exited Iran’s giant Azadegan oil development project under US pressure as sanctions intensified against Tehran’s nuclear pro-gramme (AGL, July 2011, p4). Japan’s oil imports from Iran last year dropped to their lowest in more than 30 years, with refin-ers cutting imports in return for a waiver from US sanctions.

But Tokyo’s insistence on engaging Russia may dent its alliance with Washington at a time when US-Japan relations had already cooled over Abe’s visit to a controversial war shrine in December last year. Japan is committed to take 17mn t/yr of LNG from new US projects as it bids to cut fuel costs and relieve the burden on its reviving economy (AGL, March, p5).

Tokyo treads delicate path to energy security

US independent Cheniere Energy has signed a 20-year contract to sell 1.5mn t/yr of LNG, equivalent to 2.1bn m³/yr of dry gas, from its planned Corpus Christi terminal in Texas to Spanish utility Endesa. Deliveries would start when the first liquefaction train begins commercial operations, potentially as early as 2018.

It is the second long-term sales con-tract that Cheniere has signed for its Corpus Christi export facility, which is being developed to have three liquefac-tion trains with a combined capacity of 13.5mn t/yr. The liquefaction fee that Cheniere will charge for Corpus Christi

is higher than what it charges for the Sabine Pass LNG export plant it is build-ing in Louisiana, the company says.

Endesa will not have to buy LNG if it is uneconomic to do so, as is the case for other US LNG export contracts. But it will have to pay a liquefaction charge of $3.50/mn Btu for all its capacity of 78 trillion Btu/yr, whether it takes any LNG or not. This means that it will pay Cheniere about $274mn/yr for its capacity.

If Endesa takes LNG, it will pay an additional 115pc of the Nymex Henry Hub natural gas futures contract for the month in which a delivery is scheduled.

If Endesa does not want a cargo in a particular month, it must notify Cheniere by the 20th day of the month, two months before the cargo is due to load. Endesa will be charged a relatively small suspension fee for the supply that it does not take.

Cheniere will charge its initial cus-tomer at Sabine Pass, the UK’s BG, $2.25/mn Btu for capacity plus 115pc of the Nymex price for LNG supply. It will charge its later customers at Sabine Pass $3/mn Btu for capacity. Sabine Pass is expected to start commercial operations in early 2016 (AGL, September, p15).

Endesa signs supply deal with Cheniere

April 2014


Argus Global LNG — Japan/West Africa

Japan’s four major gas retailers — Tokyo Gas, Osaka Gas, Toho Gas and Saibu Gas — all forecast moderate growth in their gas sales in the fiscal year to March 2015. The four firms, which account for 72pc of Japan’s gas sales, expect a sus-tained economic revival despite a consumption tax increase.

Tokyo Gas is expected to raise its LNG consumption by 5pc on the year to 11.3mn t in fiscal year 2014-15, which runs from April to March, with gas sales expected to hit 15bn m³, also up by 5pc from a year earlier (see table). Sales to indus-trial customers are expected to increase by 10pc on the year to 6.8bn m³, accounting for 45pc of Tokyo Gas’ total gas sales. The utility aims to boost industrial sales to 7.8bn m³ by fiscal year 2018-19 as it plans to further extend pipeline networks to promote a fuel shift to piped gas.

The government expects a moderate economic recovery to be sustained despite the 1 April consumption tax rise to 8pc from 5pc, with real GDP forecast to grow by 1.4pc in fiscal year 2014-15. This contrasts with the last consumption tax increase in 1997 to 5pc from 3pc, which immediately sent the country’s economy into recession.

Network expansionTokyo Gas and Osaka Gas are banking on growing gas demand from the power sector, which will be fully deregulated by 2018-20 to prompt investments in new power generation projects using piped gas. Tokyo Gas is scheduled to com-plete the new 1mn t/yr Hitachi LNG import terminal, located 100km north of Tokyo on the Pacific coast, which targets nearby manufacturing areas by extending the firm’s pipeline network from Hitachi. Tokyo Gas is also committed to supply piped gas from Hitachi to steelmaker Kobe Steel’s 1.4GW combined-cycle gas turbine (CCGT) power plant project planned for a 2019 start-up in Moka (AGL, March 2013, p19).

Osaka Gas will start supplying piped gas to regional power utility Kansai Electric Power’s Aioi thermal power plant in Hyogo prefecture under a new deal beginning in April 2016. Kansai will convert two 375MW oil-fired power units to gas-fired units at Aioi. Osaka Gas has expanded wholesale LNG supply to regional power and gas companies and is scheduled to begin delivering 300,000 t/yr of imported LNG to Shizuoka Gas from this month.

Hub linkageOsaka Gas is also in talks with Fukuoka-based Saibu Gas to join Saibu’s planned 1.6GW CCGT project at Hibiki for a 2020-21 start-up, a deal that may allow Osaka Gas to supply Saibu with LNG imports. Saibu’s 700,000 t/yr Hibiki LNG import terminal is scheduled to begin commissioning in November (AGL, July, p3). Saibu Gas expects gas sales to rise by 4pc on the year to 960mn m³ this fiscal year. The company aims to boost total gas sales to 1bn m³ by fiscal year 2016-17.

Nagoya-based Toho Gas plans to raise its LNG procure-ment by 0.4pc on the year to 3mn t, because it expects a 1pc increase in its gas sales to 4bn m³. The company in January signed an agreement for 300,000 t/yr of LNG from the Cameron LNG project in the US for 20 years beginning in late 2017, and is planning to seek additional supplies from new projects including those in North America and Africa. Toho is considering using Henry Hub and UK NBP-linked prices for its future LNG imports in addition to the oil-linked price.

Gas sales to grow despite tax hikeLNG consumption forecast mn tFiscal year 2013-14 2014-15 2015-16 2016-17 2017-18 2018-19

Tokyo Gas 10.8 11.3 11.3 11.5 12.0 12.2

Osaka Gas 7.0 7.0 7.1 7.2 7.4 7.5

The Cameroon LNG project in west Africa is targeting its first LNG cargo in 2019-20, London-listed upstream inde-pendent Bowleven said on 31 March.

The project is based on an initial single onshore train of up to 3.5mn t/yr operated by French utility GDF Suez. Gas supplies for the project would include output from Bowleven’s Etinde field development. The LNG facility would be built 30km south of Kribi on the Atlantic coast, from where Cameroon exports domestic crude as well as crude from Chad.

GDF Suez and the Cameroon gov-ernment signed an initial agreement in 2008 to advance the LNG scheme to use associated and non-associated gas. Cameroon would join Nigeria, Angola and Equatorial Guinea as west African LNG exporters if a final investment deci-sion on the project is approved.

Mozambique and Tanzania are plan-ning LNG developments after significant gas discoveries. US upstream independ-ent Anadarko Petroleum has targeted first LNG exports from Mozambique in 2018. Both projects will mainly target

Asia-Pacific markets (AGL, July, p12).Talks are under way with GDF Suez

on the quantities of gas to be supplied to the Cameroon LNG project, Bowleven says. A provisional allocation of gas to the scheme from Etinde is expected to be agreed in the second half of this year.

“Momentum is building behind the proposed Cameroon LNG scheme and this represents a significant opportunity to monetise the considerable upside poten-tial identified on Etinde, both in block MLHP-7 and into our Sapele discoveries in block MLHP-5,” Bowleven says.

Cameroon LNG may start as early as 2019

April 2014


Argus Global LNG — Europe

The LNG demand outlook is uncertain, as shipments to Asia-Pacific continue to rise steadily and the shale boom in the US all but ends imports to the country (AGL, February 2013, p12).

Natural gas exporters looking to Europe — where the financial crisis and the unintended consequences of renew-able energy policies led to a 30pc fall in net LNG imports to 33.7mn t last year — may find this picture even less clear. What happens next will have a significant impact on the overall strength of the global LNG industry. A continuing fall in European consumption would push more exports from the Middle East and Africa to Asia-Pacific, where new suppliers in North America and Australia will be competing to meet rising demand.

Part of the issue is that surging North American gas pro-duction displaced coal in US power generation, with the coal then exported cheaply to Europe. This confounded expecta-tions that Europe would reduce coal use as wind and solar power capacity expanded and governments pushed to meet emissions reduction targets. Power generators opted to use cheap coal imports rather than much more expensive gas.

EU coal consumption was expected to fall by 45pc in 2012-20, according to the IEA. Demand for the fuel is instead expanding as European utilities use coal-fired generation, rather than gas-fired output, to balance out the intermittency of wind and solar power.

This means that CO2 emissions are rising even as European governments invest $30bn/yr to subsidise renew-able energy supplies. It will be “all but impossible for Europe to meet its climate targets”, Shell acting upstream vice-president Maarten Wetselaar says. Gas-fired power plants are being shut down and, in some cases, dismantled. French utility GDF Suez alone idled around 10GW of gas-fired capacity and wrote off more than $2bn in gas-fired generation assets last year, which suggests that the prospects for a gas demand recovery in the region are bleak.

Slow growthBut some big gas producers are hopeful that European demand will start to rise again. Total expects demand to rise by 1.3pc/yr up to 2030, a third as fast as Asia-Pacific growth.

Europe could support global markets by taking more cargoes when prices fall or by selling supply when they spike, Shell says. European importers last year re-exported more than 4.3mn t of LNG. “We do see European demand coming back,” Shell global LNG vice-president Roger Bounds says. “Maybe it becomes the flex market.”

UK energy firm BG expects European LNG imports to continue to fall over the next several years before recovering in the 2020s. Imports have dropped by more than 30mn t/yr since 2010. State-controlled Qatargas predicts a faster rebound, eventually to record highs over the next 10 years.

Demand in Europe will rise sharply over the next decade as the economy recovers from the financial crisis and emissions reduction goals necessitate more use of gas for power gen-eration, Qatargas says.

More LNG will be needed as European gas production declines, pushing imports in the region to around 150mn t/yr by 2025, Qatargas chief operating officer for commercial and shipping Alaa Abujbara says. “Demand was hurt by the recession. But in the longer term, Europe has a clear need for more natural gas,” he says. “Europe does not realise what is coming up.”

Qatargas is the world’s largest LNG producer with 42mn t/yr of production capacity from seven trains, and has much at stake in Europe’s energy choices. The company’s massive investments in LNG export projects over the past decade was based on European customers buying about 35pc of its out-put. But just 22pc of Qatargas’ LNG shipments were sent to Europe last year. Asia-Pacific markets, which were projected to account for 40pc of Qatargas supply, took 71pc.

Europe’s economic recovery will probably remain lack-lustre, with the European Commission predicting growth of around 1.1pc this year. Unemployment in the region remained unchanged at 11.9pc in February, equivalent to around 19mn people without work.

Mixed messagesHopes for gas demand growth would probably require changes in energy policy. European countries would be better off from an emissions perspective replacing coal-fired genera-tion with gas than replacing gas with renewables, Total gas and power president Philippe Sauquet says. And they would save $150bn in subsidy costs over five years. But given con-cerns over European power prices — German energy minister Sigmar Gabriel says rising energy costs could undermine the country’s industrial competitiveness — even a cut in renew-able subsidies would not necessarily equate to a surge in gas use. Gas will still compete with coal, and the Ukraine crisis could lead to higher gas prices in the region.

Qatargas sees gas winning out, even at higher prices. European LNG pricing must change, becoming more on a par with Asia-Pacific, as competition for LNG cargoes rises, Abujbara says. “Demand is going to pick up very soon,” he says. “I think Europe needs to start thinking about where that 150mn t/yr is going to come from. I think it is mainly going to come from the US.”

Fellow Qatari gas exporter Rasgas expects LNG to be the fuel of choice to fill the supply gap as more nuclear power generation plants are decommissioned. “This is the era of LNG,” Rasgas chief executive Hamad Rashid al-Mohannadi says. “The share of coal and nuclear will decline in favour of gas and renewables.”

LNG producers split on demand outlook

April 2014


Argus Global LNG — Interview

Shell in January completed its $4.1bn acquisition of Spanish firm Repsol’s LNG assets, primarily in Latin America. The deal helped fill one of the few geographic supply gaps in Shell’s gas export portfolio and strengthened its position as the world’s largest LNG supplier. Argus interviewed Shell global LNG vice-president Roger Bounds after the Gastech conference on 24-27 March in Seoul, South Korea. Edited highlights follow:

What is the status of the Sakhalin 2 expansion and Shell’s plans for a third LNG liquefaction train?Sakhalin [in Russia] is a fantastic project. Our company has a real success story in the region, along with our joint-venture partners, [Japanese trading firms] Mitsui and Mitsubishi and [Russian state-controlled] Gazprom. We are proud that we have delivered a highly efficient project that has performed and delivered for the energy business here in Asia. We have always been open with our plans for project expansion over its lifetime — to be able to do more with that project and fulfil its promise. We have agreed with Gazprom to begin an initial engineering and design study, and signed a roadmap outlin-ing steps towards the construction of the third train.

How might US and EU sanctions against Russia as a result of the Ukraine crisis affect Sakhalin 2’s prospects?My first concern is for the people and Shell’s staff in particular. We have been reassured that our staff will not encounter any security concerns. Other than that, we are trying to take a long-term view on Russia to see how this [current crisis] fits into what has been a long-term, stable relationship. It is too soon to tell how it will impact energy choices from buy-ers, but we expect that they will also take into account the long-term supply stability argument. There was discussion at Gastech concerning how Russia continued to supply Europe’s energy needs throughout the Cold War period, through quite a range of political cycles. We would probably look past the current situation to focus on the long term.

Could US LNG export projects benefit from the political uncertainty?The US process for approving export projects has been remarkably consistent. It is being done on a very methodical basis and has led to a high degree of certainty in the industry and we expect that is going to continue.

Will Shell’s project expansion plans be affected by recently appointed chief executive Ben van Beurden’s strategic outlook for the company?The new chief executive has made a very strong commit-

ment to operational performance and capital discipline. That is not a step away from [former chief executive] Peter Voser, but it is a recognition of last year’s results and the desire to address that.

At the same time, van Beurden made strong statements in support of the integrated gas portfolio and what he expects from those assets. That is the overarching stand, and I think it is entirely consistent. It is a re-affirmation of what we have always felt and have told the market, which is to deliver good projects on time, on budget and to meet customers’ needs. This has sent a clear market signal that we are engaging in sensible energy projects, where decisions are made in a timely fashion, where we pick the right configuration of mar-ket demand and supply fundamentals and the right support that we are looking for.

As a consequence, we can make choices to exit smaller projects that are not a good fit — such as the 8.9mn t/yr Wheatstone LNG in Western Australia and our delayed commitments on coal-bed methane in Queensland — until conditions are positive or we see that there is a better way to monetise that gas (AGL, February, p8).

What are your thoughts on industry co-operation in Canada to ensure LNG projects are more

economical?Shell already has a number of strong part-nerships in our projects. Our partners have different upstream interests and typically work with us on pipeline and midstream investment. More broadly, the need for co-

operation on infrastructure and the desire to avoid unnecessary competition for scarce

resources is an industry-wide problem and is some-times surprisingly difficult to deliver. We have a track record

of pushing people to try and work together as an industry. This method has allowed us to increase government confi-dence in the ability of industry to deliver, improve our returns to shareholders and deliver gas to customers more competi-tively (AGL, December, p7).

Is the buyer interest there?We do see Asia-Pacific demand for Canadian gas. Having said that, the absence of long-term contracts — the sort of assured relationship between the offtakers and the produc-ers — can act as an impediment for the industry. We have to weigh that tension. Shell is comfortable that there is enough demand out there and that we will see the support materialise.

We also recognise that unless the industry as a whole is able to step up and make the commitments to consume the gas — build the infrastructure, commission the gas-fired power plants and be prepared to take the gas at

Shell cements its position at the top

p7

‘We are trying to

take a long-term view on Russia to see

how this current crisis fits into what has been a

long-term, stable relationship’

April 2014



prices that are enough to sustain a reasonable return on these sorts of projects — the sector could easily slow down, and we could fail to meet our demand aspirations.

What is the outlook for buyer-seller tension — where buyers want less oil indexation, more flexibility and lower prices, while sellers face challenging project economics?In the traditional power markets in Asia-Pacific, if long-term, life-cycle costs are taken into account, then the relative price of gas is quite competitive, and over time, these arguments will come forward. As a consequence, on the basis of the competi-tiveness of gas integration, the demand for continued electri-fication and the demand from the utilities’ forecasts and LNG going into new uses, we see enough demand and at prices that will sustain investment criteria for new projects.

In contrast, it is incumbent on all of us to manage the costs of our projects. That is why we are doing things like working on modulisation, replication, good contract management. It is necessary to deliver projects that will really be able to pitch themselves into the marketplace competitively.

What are the most compelling strategic benefits of the Repsol asset purchase?The deal allows us entry into a part of the world where we did not have existing operations. We now have full global breadth across both hemi-spheres, and will be able to offer a range of supply points in a way which adds diversity to our portfolio.

Where do you see China’s future gas demand outlook?Gas penetration into China is still remarkably low, even by the preferred predictions. We see gas coming in from 3-4 different sources. We are working closely with [Chinese state-owned oil company] CNPC to develop their own gas resources. China also imports pipeline gas from its neighbours, while we anticipate continued offshore exploration in the country in due course.

There is a significant number of LNG terminals under con-struction or being commissioned, which will meet the burgeon-ing gas demand in coastal areas of China. Filling those termi-nals will mean that China must contract more energy supply. It is not clear where that supply will be sourced — whether from government investments, the country’s upstream off-shore, or from more diversified sources. We do see China being long in the market for LNG.

Is China’s first private-sector receiving terminal, Guanghui Xinjiang, still moving forward?We are working with a few Chinese players to facilitate mar-ket-entry opportunities, particularly around LNG as a trans-port fuel. Our focus is not to position gas into the pipeline but to bring our equity LNG into the marketplace, where local

partners can then retail it as a road fuel. We forecast LNG for the transportation sector to grow in China at an extraordinary rate — the fastest in the world really — much faster than even in North America. In order to source LNG as a road fuel, they can take it out of existing terminals or through small-scale liquefaction of indigenous gas — in particular from coal-bed methane or tight gas. The policy focus and commitment to make this happen is inevitable, and Shell wants to be part of that growth. Our terminal developments are part of that journey (AGL, January 2012, p9).

How big a game changer will Chinese shale gas be for LNG markets?It is not so much a game changer, but a continuation. We would love China to have success in developing domestic gas resources because the more gas they have, the more comfortable they are going to be as gas consumers. The more comfort they have as gas consumers, the more infra-structure they will put in place. That is better for the quality of life of the Chinese consumer and it is better for us as an industry because it adds a big, stable demand source (AGL, April 2012, p10).

There is a lot of debate about US Henry Hub-linked LNG pricing. But given the freight

costs, can it really be assumed that the delivered cost will be lower than what buyers are paying now?There has been a lot of analysis on the issue. What was found is that depend-ing on your expectations of Henry Hub

and oil prices — as well as assumptions regarding processing, transport costs and

the pricing relationship to oil — you can end up in about the same zone. Will it fundamentally

be a different price? Probably not. But it will most prob-ably be framed differently. The traditional oil-linked contracts are not responsible for the high short-term prices you are seeing in the market.

Short-term prices are laterally negotiated without neces-sarily having any reference to oil prices. Second, long-term LNG prices which have been oil indexed include the ability to renegotiate prices and a degree of flexibility for the buyer. Those non-price elements are an important part of the value contribution to the buyer, which is understated and is not really captured just by doing a Henry Hub compared with oil comparison. It is up to people to make their own assumptions about what they think is going to happen to oil and what they think is going to happen to Henry Hub.

But what we really emphasise is that the traditional long-term contracts we have been using over the past 40 years have stood the test of time and give flexibility to buyers. We look forward to continuing talks over the issue with buyers for the next 40 years (AGL, March, p6).

Interview

‘The Repsol asset

purchase allows us entry into a part of the

world where we did not have existing operations. We now have full global

breadth across both hemispheres’

April 2014


Argus Global LNG — Corporate/Global

Indian state-controlled LNG importer Gail has no plans to allocate more than 1mn t/yr of the 5.8mn t/yr of LNG that it has contracted from US projects to buyers outside India. This is despite perceptions that the company may be struggling to secure sales agreements with domestic consumers.

Gail has an agreement with US LNG infrastructure firm Cheniere Energy to buy 3.5mn t/yr from the Sabine Pass project, which is authorised to export 16mn t/yr of LNG (AGL, June, p1). It has a 2.3mn t/yr liquefaction capacity agreement with US energy company Dominion Resources’ 5.75mn t/yr Cove Point project. Sabine Pass is due to begin first deliveries in 2016, with Cove Point following in 2017.

Economic and rupee weakness have given rise to doubts over Indian consumers’ ability to purchase LNG, despite forecasts for strong consumption growth. LNG imports are forecast to reach 31.7mn t/yr by 2020, from 12.1mn t last year, as a result of increasing gas demand from the fertiliser and power sector, US firm Bernstein Research says.

Comfortable for nowGail has been marketing its US LNG in and outside India, but is comfortable about not having any supply agreements because first deliveries will begin only in 2-3 years. It expects domestic demand to grow strongly and is preparing for this by seeking additional long-term supplies from countries such as Canada, Qatar, Algeria, Mozambique and Nigeria.

Some 2mn t/yr of Gail’s US LNG will supply its LPG and petrochemical plants. This leaves about 2.8mn t/yr to be sold

within India and 1mn t/yr to be marketed on a long-term basis, rather than spot, to other consumers outside the country. Gail expects 80pc of domestic demand to come from the power and fertiliser sectors, which use gas as a feedstock. It has received expressions of interest from domestic consumers and expects to sign some deals later this year.

Competition threatMarket participants note that interest in purchasing LNG from Sabine Pass has reduced compared with a year ago, as more US projects seek customers. And Gail is not alone in offering its US LNG to a secondary market. It could face competition from companies such as French utility GDF Suez, which is looking at Asia-Pacific as a potential market for its US sup-plies. GDF Suez has a 20-year deal for 4mn t/yr of liquefac-tion capacity at the 12mn t/yr Cameron LNG export project in Louisiana, which is scheduled to start exports in late 2017.

Gail’s deals are for 20 years and are indexed to the US Henry Hub benchmark price, but Indian consumers have no experience of such long-term supply agreements. They are tak-ing their time to assess their needs and how much they should pay, given uncertainty over Henry Hub price movements. Gail is expected to pay Cheniere 115pc of the Nymex Henry Hub final settlement price in the month in which a cargo is loaded.

“As long as Henry Hub prices stay around $5/mn Btu, that should be fine for consumers,” a trader in India says. “But there is no guarantee that Henry Hub prices will not go up. So there is uncertainty in the market.”

India’s Gail sticks to US LNG strategy

Executives from Chevron and Japanese upstream company Inpex have warned that a rational pricing mechanism for LNG needs to be agreed for future Asia-Pacific LNG production projects to be approved.

“Projects will not go ahead without agreement on rational pricing mech-anisms to underpin these projects,” Chevron Australia managing director Roy Krzywosinski told Australian indus-try group Appea’s conference in Perth this month.

Asia-Pacific LNG buyers are mov-ing away from traditional long-term, oil-linked pricing and are leaning towards US Henry Hub and European NBP pric-ing. Suppliers are aware that mecha-nisms are evolving in Asia-Pacific and

that buyers want to diversify their pric-ing. But they warn that the high capital requirements of LNG projects mean that they need to find a way to reduce the risk associated with pricing over time.

Many of Australia’s LNG projects have been developed in joint ventures with Asia-Pacific LNG buyers and this has allowed for long-term offtake agree-ments that have underpinned financing for major projects. But this model is now under threat from differences in opinion over pricing and the market outlook.

“I am concerned that there exists a substantial gap between the sup-pliers and the buyers with regard to their understanding on the future supply-demand balance and what future pric-ing mechanism they envision,” Inpex

chief executive Toshiaki Kitamura told the conference. “Unless this gap can be narrowed, the worst-case scenario would be a delay in the development of a healthy global LNG market resulting in a lose-lose situation for all concerned.”

Kitamura and Krzywosinski called on buyers and sellers to work together to find a plan that works for both sides. They insisted that suppliers would work to reduce costs to make LNG a more attractive energy supply option in return for pricing mechanism clarity.

“If we collaborate, I am confident we can find common ground to achieve the necessary pricing to underpin future projects while supporting Asia’s eco-nomic expansion and development,” Krzywosinski said.

Developers push for pricing certainty

April 2014


Argus Global LNG — US

The US Department of Energy (DOE) on 24 March condition-ally authorised the Jordan Cove LNG export project in Coos Bay, Oregon, to send up to 6mn t/yr of LNG, equivalent to 8.2bn m³/yr of dry gas, for 20 years to countries that do not have free trade agreements (FTAs) with the US.

The licence is contingent on Jordan Cove receiving con-struction approval from US energy regulator Ferc. Most of the world’s largest LNG consuming countries by volume, including Japan, which is by far the largest, do not have FTAs with the US (AGL, June, p11).

Jordan Cove, which is owned by Canada-based Veresen, says it has non-exclusive, non-binding agreements with Asian buyers for liquefaction tolling capacity that exceed planned output, and that it is likely to finalise contracts totalling 6mn t/yr this year. The project aims to come on line in early 2019.

The second proposed LNG project in the state, Oregon LNG, is next in line to be considered by the DOE for non-FTA export approval. The agency has been issuing such licences at a rate of about one every two months, but it has no timeline to make a decision (AGL, October, p1). Oregon LNG aims to start operations in 2019.

Houston-based energy consultancy Galway gave the Jordan Cove project about a 25pc chance of being built 18 months ago, managing director Robert Stibolt says. Galway now gives Jordan Cove about a 50pc probability of materialis-ing, based on its non-FTA licence and the preliminary tolling deals. But the difficulty of building major infrastructure projects in the US northwest because of strong opposition from envi-ronmental groups means it is possible that Jordan Cove could be delayed or even blocked, Stibolt says, stressing that he is not aware of any particular issue.

Environmental challengesVeresen expects Ferc to issue a final environmental impact statement for Jordan Cove late this year, and approve the project in time for the company to make a final investment decision by early 2015. But US bank Goldman Sachs did not include Jordan Cove in a list of likely US LNG export projects in a 10-year outlook released last month, citing the lack of firm tolling deals with customers.

The environmental challenges faced by the Oregon pro-jects are exacerbated by their need to build long pipelines to connect to regional hubs that would bring feedgas from western Canada or the US Rockies region.

Opponents of the Oregon LNG project say a decision by the Clatsop county regulators in October last year to deny a local zoning permit for a 41-mile (66km) section of the planned 86-mile bi-directional Oregon Pipeline will prevent the terminal and associated pipeline from being constructed. Oregon LNG contends that it will receive the permit because Ferc’s exclusive authority to site LNG terminals supersedes

the county’s ruling, among other reasons. Oregon LNG and the state’s Department of Land Conservation and Development have twice extended the review period for the coastal zone management act permit, with a decision now expected by 2 July.

Jordan Cove has an influential ally in US Senator Ron Wyden. The Oregon democrat has often urged caution in US export approvals, but has pressed the DOE to approve Jordan Cove’s non-FTA licence without delay.

A number of analysts expect the greenfield Oregon projects to be more expensive, based on equivalent units of production, than brownfield export schemes being devel-oped at existing LNG import terminals on the US Gulf and east coasts.

Cost considerationsJordan Cove and the adjoining 420MW South Dunes power plant have an estimated combined cost of $5.3bn. The planned 232-mile Pacific Connector pipeline, which would bring feedgas from the natural gas hub at Malin, Oregon, near the California border, has an estimated cost of $1.5bn. That would be a total cost of $6.8bn for 6mn t/yr of capacity, or $1,133/t of annual capacity.

Oregon LNG, which would be located at the mouth of the Columbia river in Warrenton, has an estimated cost of $5.8bn. The proposed Oregon Pipeline, which would deliver as much as 1.25bn ft³/d (12.9bn m³/yr) of gas by connecting it to midstream operator Williams Partners’ Northwest pipeline near Woodland, Washington, would cost $664mn. This would be a total cost of $6.5bn for 9.6mn t/yr of capacity, or $722/t of annual capacity.

US LNG firm Cheniere Energy expects to spend $12bn-13bn to build four liquefaction trains with a combined name-plate capacity of 18mn t/yr at the Sabine Pass terminal in Louisiana. This equates to $667-722/t of annual capacity, comparable with Oregon LNG’s estimated cost.

But the costs of the Oregon projects could increase because they have not completed detailed engineering stud-ies and their figures do not include financing costs, which could be significant.

Jordan Cove and Oregon LNG say the delivered cost from their projects to Asia-Pacific would be comparable with shipments from US brownfield projects, even after the expansion of the Panama Canal is completed, which would significantly reduce the travel time from the US Gulf and east coasts to Asian markets. Jordan Cove estimates that the delivered cost from its project to Japan would be $11-12/mn Btu. Oregon LNG says its potential customers could save about $1bn/yr in shipping costs compared with customers of similar-sized projects on the US Gulf and east coasts (AGL, January, p13).

Pacific coast export prospects improve

April 2014


Argus Global LNG — Interview

Australia’s largest LNG operator Woodside Petroleum faces surging development costs at its new projects in Western Australia and a dispute with East Timor’s government that has stalled its Sunrise LNG project. Chief executive Peter Coleman delayed a decision late last month to buy into the Leviathan LNG export project off the coast of Israel, which requires agreement on fiscal terms with the Israeli government. And just as a wave of new LNG supply sources come onto Asia-Pacific markets, the region’s largest buyers are reconsidering their demand targets. Argus interviewed Coleman in Seoul last month after the Gastech conference, where LNG buyer-seller tensions took centre stage. Edited highlights follow:

South Korea warns that the gas revolution in Asia-Pacific is threatened by high regional LNG prices. Yet even with current pricing sellers are strained by chal-lenging project economics as development costs rise. How do you see that dynamic playing out, and how might the pace of new project approvals be affected?What we are seeing here is not unusual and certainly not something the industry has not seen historically. It is becom-ing a little more public because industry policies are being reviewed by a number of Asian nations after the issues that nuclear power has had. Buying nations are adjusting energy policy at the same time as trying to adjust their elasticity or flexibility with respect to prices. This is understandable.

Suppliers owe a duty to ourselves and to buyers to keep our cost structures as low as possible to remain competitive, to ensure that we do not destroy demand or the opportunity of demand through our own inefficiencies. Buyers can help by giving better pre-dictability of demand. We wait for price signals in the market, and we wait for buyers to tell us when demand is going to be there. The reality is, if buyers are unable to give those signals early enough, then you have this pent-up supply sitting there waiting to go and you have a lot of competition to supply.

That is what we are seeing at the moment, as a huge number of projects in Australia are all coming on line, compet-ing now with gas from the US. There is a lot of supply coming onto the market in a short period of time. This is not an effi-cient way to develop the industry because that same supply is competing for resources at a point in time where our cost basis is being driven up by the cost of services and equip-ment. And the cost of services and equipment is being driven up by the increase in demand in Asia, which is being driven up by greater access to affordable energy, as Asia becomes more developed and more urbanisation takes place. The success of Asia itself is driving up the cost base because it is pulling on limited resources globally.

The oil and gas industry needs to take stock of the way we have been developing and the cost structures that have been established, the technology that we are using, and determine if there are things we can do to help break this cycle.

Are east Asian governments hurting their own cause by not sending clear demand signals to the industry?It could help the industry a lot if they were able to send clearer signals. The malaise we are in at the moment is not sustain-able in the long term, and we need governments to give clearer energy policy and direction. It would be helpful for the buyers of those nations so they could go into the market with certainty, and they would look at new projects because they would be able to engage with sellers with certainty. Sellers always prefer certainty over chasing margin.

Where do things stand on talks with Israel to reach fis-cal terms on eastern Mediterranean LNG development? Developers have a risk, particularly in tax-royalty regimes, where host governments have the right to change those regimes. Israel is reviewing its oil and gas laws as it prepares

itself for gas production in the country. We are in discussions with them around finalisation to

changes to some of those tax laws. Israel final-ised its export policy in the past 12 months, so it is now very clear on how much volume it can export. It is also undertaking a review of the tax regime, particularly with respect to

the tax base for exports. We have had input into that. We are encouraging them to publish it

quickly so we have some certainty around develop-ment, but they have given us no timeline (AGL, March, p13).

The eastern Mediterranean will be a mixture of pipeline gas and LNG, and so the best development concept is to have multiple-destination flexibility for the gas. The ultimate destination flexibility comes with LNG, but there will be multiple pipelines going to different customers and different countries.

What are the prospects for the proposed floating LNG (FLNG) development at Australia’s Browse project, and will there be a staggered approach or will all three trains come on line at once?It will be a phased approach, so there will be three sequential facilities developed. It is most likely to be FLNG — that is what the joint venture is evaluating at the moment. We will know more in the second half of this year when we make a decision on whether to move forward. We are in the basis-of-design stage, working through the development, and we will make a decision in the second half on whether we move to the front-end engineering and design stage — the final step before making an investment decision.

Woodside identifies upside amid buyer-seller tension

‘The success

of Asia itself is driving up the cost base because it is pulling on

limited resources globally’

p11

April 2014



We would prefer to use the FLNG technology being devel-oped by Shell. Although we are still in the evaluation stage. There are lots of advantages, we just need to make sure it delivers the right cost structure (AGL, March, p11).

China is giving conflicting signals on its LNG demand growth. How do you see the Chinese market developing?I see it as very strong. China’s demand is currently under-stated in the marketplace. It is still constrained by state-owned enterprises. Look at the difference between the demand and usage profile in South Korea and China — although both have very similar climatic conditions and are very similar in their aspirations for development. I see a lot of opportunity in China that is yet to be built into forecasts. China has gas-to-gas competition with pipeline gas. The Chinese government’s cur-rent forecast is for the use of gas in conventional ways, such as for power generation. It does not touch on the penetration of gas into transportation, or shipping. These are difficult to forecast but provide upside.

How close are you to reaching a resolution over the stalled development of the Sunrise field in East Timor?The arbitration outcome has a defined reso-lution path, and the arbiters have been appointed. It is not something that Woodside is party to, so it is not something that is in our hands. It is a government-to-government issue that is being resolved through the proper process, which is arbitration.

There is a governing body that was jointly estab-lished between the governments of East Timor and Australia to oversee the development of the Sunrise field. That body disagrees over the best development concept. The key is to go through the process for agreeing the sharing of revenues, make sure that all parties are very clear on that, and then sit down and talk in a meaningful way about development with the governments of East Timor and Australia.

Woodside is ready to start development. But there is no use in talking about it now because the two governments are in dispute — they have a completely different view of the right development plan. Woodside has put forward a proposal as the operator. That proposal has been backed by the Australian gov-ernment. The East Timor government has a different view. They do not have a way of resolving that, so they need to resolve the first part, which is revenue sharing (AGL, January, p1).

How many spot cargoes will Woodside’s new trading operation in Singapore handle this year, and how many will be third-party cargoes?The trading vessel in Singapore is designed for international trading. We brought two additional vessels into our fleet in the past 12 months, both from South Korean shipyards. The first

vessel went into our Pluto development. It is doing trade from Australia, moving cargoes back and forth to Asia. The vessel in Singapore is a Singapore-flagged vessel doing international trade. It moves between Asian markets and Atlantic markets depending on where we can get the best charter rates. It is a combination of using the ship for sub-chartering to others or using it ourselves to trade. We do not have a target on cargoes — we want it to be profitable.

The key for Woodside is that we are developing our knowl-edge and flexibility to ensure we can protect the value of our upstream investment. We want to make sure that we are in the trading space so we can place our cargoes into the best buying opportunity. If we are not, we become subject to the whims of buyers, and I have got a $20bn investment waiting for somebody to turn up and take my product. I cannot keep stor-ing LNG in the warehouse because the tanks are only so big.

Will your Pluto LNG export plant in Western Australia produce over nameplate capacity?We are working hard on Pluto to continue to boost it up. We

are focused on reliability first, and then we will focus on capacity. We are still working on reliability.

The plant is running very well, but we still have some opportunity in reliability. We will shut the plant for a scheduled turnaround next year, and we will work to increase capacity then. It is too early to say what that might

be, but that is the first time we will look at the plan to increase capacity (AGL, February, p13).

Are there any implications for Woodside LNG developments from the Ukraine crisis?There are a number of possible scenarios around the Ukraine crisis. One is that the status quo remains, Russia continues to supply Ukraine with natural gas, and the sanctions that both sides have put in place will remain for a period of time but will not escalate. In another scenario sanctions continue to esca-late, which may have a direct impact on both US investments in Russia and Russian investments in the US and elsewhere. It is difficult to predict what that might mean, but in the energy sector, there are some very significant investments across both sides. In another scenario Moscow plays hardball with Kiev over the price of Russian gas going into Ukraine, which has an impact on Ukraine’s ability to pay those prices. I do not know if there is a scenario in which Russia cuts off the gas, and whether Europe can supply enough gas coming the other way.

It is a reminder to buyers that diversity of supply is the best way to ensure supply security. That has always been the case — to have diverse and reliable supply sources. Do not rely on just one supply source. When we talk to buyers about our portfolio, we are always very clear that the cost structure is such that we will not be the cheapest, but we will be that part of your supply portfolio that you can rely on.

Interview

‘South Korea and

China have very simi-lar aspirations for devel-opment. There is a lot of opportunity in China that

is yet to be built into forecasts’

April 2014


Argus Global LNG — Asia-Pacific

The battle for control of the Elk and Antelope gas fields in Papua New Guinea (PNG) is intensifying with the partners in the PNG LNG project, including ExxonMobil and PNG-focused upstream group Oil Search, looking to block Total’s purchase of a stake in petroleum retention licence (PRL) 15, which cov-ers the fields.

Total and US independent InterOil hold a combined 76.65pc in the Elk and Antelope gas fields, which contain estimated resources of 5.4 trillion-9 trillion ft³ (153bn-255bn m³), and want to develop a stand-alone LNG production plant. But Oil Search, which bought a 22.835pc interest in PRL 15 through the $900mn purchase of Switzerland-based invest-ment group Pac LNG on 27 February, is opposing Total’s plans. Oil Search on 28 March issued a notice of dispute to InterOil over the sale of a 40.1pc stake in PRL 15 to Total two days before (AGL, March, p1).

Oil Search says that after it bought its stake in PRL 15, InterOil transferred a 40.1pc holding in the licence to a new entity called SPI 208 from an entity called SPI 200, which origi-nally held InterOil’s entire PRL 15 stake. The purchase gave Oil Search pre-emptive rights over any stake sold by the other joint-venture partners in PRL 15.

InterOil held a 75.611pc share of PRL 15 and was planning to sell a substantial part of its stake to Total under an agree-

ment struck in December last year (AGL, February, p1). But Oil Search says the transfer to a different entity means that it no longer has a pre-emptive right over the 40.1pc stake.

Oil Search is expected to take its case to arbitration, possibly in London. But it is unlikely that the company could afford to buy the 40.1pc stake on its own — it had to finance its purchase of PRL 15 through a $1.1bn equity share placement to the PNG government, which gave Port Moresby a 10pc share of Oil Search. Oil Search could instead exercise its pre-emptive right in PRL 15 through a deal with ExxonMobil, which last year held exclusive talks with InterOil about buying into the Elk and Antelope fields (AGL, September, p5).

Open ambitionExxonMobil, which operates the two-train 6.9mn t/yr PNG LNG project that is scheduled to start first shipments in the second half of this year, has made no secret about its desire to add a third liquefaction train. Oil Search argues that an additional train at PNG LNG would be more cost-effective than building a stand-alone LNG project.

Total revised its agreement with InterOil by taking a 40.1pc stake in PRL 15 for $401mn instead of 61.3pc under the origi-nal deal struck in December.

Oil Search moves to stymie Total’s PNG deal

New LNG supply is unlikely to be devel-oped in Australia because of high devel-opment costs and a desire on the part of buyers to spread geographical risk, according to the Paris-based IEA.

“At current costs, I do not know who is going to invest in new LNG plants in Australia,” IEA senior gas analyst Anne-Sophie Corbeau told the Argus Australian Gas and Energy Markets con-ference in Sydney on 20 March.

Australia has seven LNG projects under construction with a total of 61.7mn t/yr of new liquefaction capacity. A num-ber of other projects are planned but have not reached a final investment decision.

Corbeau played down the chances of cheaper brownfield LNG expansions, say-ing buyers would prefer to diversify geo-graphical risk in a market that will soon be dominated by supply from Australia and Qatar. But brownfield expansion is always cheaper than new developments,

no matter which country they are located in, the managing director of Australian independent Santos’ Gladstone LNG (GLNG) project, Rod Duke, said.

The end of Australia’s mining boom has cut costs, with a 15pc fall in contract service fees over the past year, Duke said. And coal-bed methane (CBM) to LNG development costs on Australia’s east coast are likely to fall further as the three projects at Gladstone are commissioned. UK firm BG’s 8.5mn t/yr Queensland Curtis LNG project will come on line at the end of this year, followed by the 7.8mn t/yr GLNG plant and the 9mn t/yr Australia Pacific LNG venture of US independent ConocoPhillips, Australia’s Origin Energy and Chinese state-controlled Sinopec. The three projects each have two trains, with the potential to add a third.

Concerns that CBM supply will be insufficient to support the LNG industry at Gladstone are overblown, according

to Jamie Summons of consultancy IES Advisory Service, which compiled the federal government’s domestic gas mar-ket study. There are sufficient proven and probable reserves on the east coast to meet demand until 2022, the study found (AGL, March, p4).

But this includes gas owned by Shell and state-controlled PetroChina’s pro-posed Arrow LNG project at Gladstone. It is unlikely that the plant will go ahead, particularly after it reduced its staff by a third earlier this year. The way in which Arrow feeds its gas to the east coast market will have a major impact on supply for the other three LNG plants at Gladstone and the possibility of addi-tional trains (AGL, February, p8).

A pricing standoff means suppliers will not agree to the type of long-term con-tracts that buyers have become accus-tomed to, despite there being enough gas on the east coast, Summons said.

Debate rages over viability of Australia’s LNG industry

April 2014


Argus Global LNG — Australia

The partners in Australia’s 7.8mn t/yr Gladstone LNG (GLNG) project signed an agreement on 27 March to buy gas from Queensland’s Meridian Seamgas joint venture for 20 years at a price linked to oil. The deal, which will start in 2015, is the latest by the GLNG partners to secure sufficient gas before the project’s start-up next year.

The $18.5bn GLNG project requires 243.4bn m³ of gas over 20 years of operation or about 12.2bn m³/yr, govern-ment commodity forecaster Bree says. The project does not have enough of its own gas, having proven and probable gas reserves of 140.6bn m³ last year, up by 0.6pc from the end of 2012. This equates to a little more than 11.5 years of supply at full production. Under the deal, Meridian Seamgas will provide about 11.8bn m³ of gas over the 20 years or about 11.5pc of GLNG’s shortfall of 102.8bn m³.

GLNG also has deals to buy 19.5bn m³ of gas from Australian independent Santos, operator and 30pc owner of GLNG, for five years from 2015, 9.5bn m³ from Australian inde-pendent Origin Energy for 10 years from 2015, and 2.6bn m³ from Origin for five years from 2016 with an option for an extra 2.5bn m³ over the five-year period (AGL, March, p4).

But this means that GLNG has secured 184bn m³ or about three-quarters of the supply that it needs for the 20-year project and requires a further 59.4bn m³. Origin has limited proven and probable gas reserves in eastern Australia beyond gas that it has allocated to its 37.5pc stake in the 9mn t/yr Australian Pacific LNG (APLNG) project as well as deals with

GLNG and Santos and UK firm BG’s 8.5mn t/yr Queensland Curtis LNG (QCLNG) venture.

All three LNG projects under construction at Queensland’s Gladstone port — GLNG, QCLNG and APLNG — will experi-ence gas shortfalls in the year from the fourth quarter of 2015, when all six liquefaction trains are due on line, US bank Citi says in a report. The two-train QCLNG is expected to start up in October-December, with GLNG following in mid-2015. The three projects, which will be supplied from Queensland’s coal-bed methane (CBM) fields, are expected to seek third-party gas in the long term, boosting domestic prices, Citi says.

Arrow potentialThe only project able to provide GLNG with the gas that it needs is Shell and state-controlled PetroChina’s 9mn t/yr Arrow LNG venture. Arrow has not ruled out becoming a third-party supplier to the three LNG projects because it could sell the gas at oil-linked prices rather than spend $20bn on devel-oping a new liquefaction plant (AGL, February, p8).

CBM from the Meridian field will be delivered to GLNG’s gas transmission pipeline, which is adjacent to the field. Meridian is owned by Australian independent Westside with 51pc and Japanese trading firm Mitsui with 49pc. The Meridian field has proved and probable reserves of 17.7bn m³, Westside says.

The other GLNG shareholders are Total and Malaysia’s state-owned Petronas with 27.5pc each and South Korean state-controlled Kogas with 15pc.

Gladstone LNG boosts gas supply

Global LNG demand will rise by 50pc to 350mn t in 2019 from 2013, Australian commodity forecaster Bree said on 26 March. It expects new supplies from Australia, the US, Canada, Russia and Africa to meet much of this growth.

It predicts that global gas demand will rise by 12pc to about 3.93 trillion m³/yr over the period, driven by growth in China, India, Africa and the Middle East. Demand growth will coincide with a shift in output, as new Australian supplies offset lower European production, and the US becomes an exporter. “[There is] a signifi-cant shift to the east in gas demand, and [we will see] major realignments in world gas trade flows,” Bree says.

Recent global LNG trade has been muted, staying at about 235mn t/yr in 2011-13, amid tight supply. Bree

expects this to last until 2015, when new supply will begin from Australia, then other Asia-Pacific countries and the US, Canada, Russia, and Africa, releasing pent-up demand.

Japan will be the key importer up to 2019. Its imports are expected to dip to 86mn t in 2019, because of energy efficiency measures and govern-ment reforms, from 87.5mn t last year. Nuclear power restarts in the next two years will hit generators’ oil demand, not gas, Bree says. The Middle East is Japan’s biggest LNG supplier, but Australia and the US will become more prominent by 2019.

China’s gas demand rose by 20pc/yr in 2005-13 and will increase to 287bn m³ by 2019, mainly because of power sector demand. But domestic gas output

will meet only 55pc of demand in 2019, down from 75pc in 2012. The gap will be met by pipeline and LNG imports, with Bree uncertain about China’s shale gas plans. Imports will reach 51mn t/yr by 2019, up from 18mn t last year.

Southeast Asian imports are expected to rise to about 18mn t/yr by 2019, with most of this growth com-ing from Indonesia and Malaysia, which imported a combined 1mn t last year. Indonesia, Malaysia and Brunei make up the world’s second-largest LNG export-ing region after the Middle East, and the transition to a more domestic focus will affect world LNG trade. This tension has prompted Indonesia’s proposed 2mn t/yr Donggi-Senoro liquefaction plant to set aside a third of production for local needs, Bree says (AGL, December, p13).

Bree sees 50pc rise in global demand by 2019

April 2014



Lithuania asks for Nato US LNG exportsLithuania has asked the US to consider supplying LNG to Nato members along-side countries with which the US has free trade agreements (FTAs), none of which are in Europe. Russia’s state-controlled Gazprom is Lithuania’s only pipeline gas supplier and Vilnius pays 30pc more for gas than other European countries. It wants LNG imports to diversify supply. The US has approved LNG exports to non-FTA states for some projects, includ-ing Cheniere Energy’s 18mn t/yr Sabine Pass facility. But US president Barack Obama says European importers must still compete for US LNG even with a trade deal. US export licences are “going into the open market”, he says. “It is not targeted.” Lithuania’s first LNG import terminal, a 2.2mn t/yr floating storage and regasification unit, is due to begin opera-tions in December (AGL, January, p4).

Kogas slows investment on debt planSouth Korea’s state-controlled Kogas is slowing upstream investment to cut debt, delaying a push to trim LNG import costs. “We invested too much over the past 4-5 years,” Kogas vice-president Kwon Young-sik says. “We have to con-trol the speed of project investment. We will look to invest again when we get to a very sound financial position.” Kogas may sell part of its stakes in Australia’s 7.8mn t/yr Gladstone LNG (GLNG) pro-ject and the Shell-led 12mn t/yr LNG Canada project. The Canadian sale is unlikely to occur before next year, Kwon says. Kogas may wait until GLNG starts production next year to attract a buyer for part of that stake. Kogas plans to remain a stakeholder in LNG developments, partly to make import prices more reflec-tive of development costs.

PetroChina makes loss on gas and LNGChinese state-controlled PetroChina made a loss of 41.9bn yuan ($6.8bn) from LNG and pipeline gas imports last year as demand increased and domestic prices fell below high international levels. PetroChina’s natural gas and pipeline segment sustained losses of Yn28.3bn from the sale of 27.5bn m³ of gas sourced

from central Asia, while sales of 7.3bn m³ equivalent of LNG imports incurred losses of Yn20.3bn. The loss from gas sales in 2013 is similar to the estimated Yn41.9bn in losses for the same seg-ment in 2012. Chinese domestic gas prices have long languished below inter-national levels because of government price controls, resulting in losses for the country’s two main suppliers, PetroChina and state-owned CNOOC. Beijing issued domestic gas price reforms in July last year in a bid to soften the impact of rising international prices on Chinese importers. But strong LNG demand in northeast Asia along with surges in sea-sonal demand from China have kept a significant price differential between import and domestic prices.

Gail and Chubu combine on LNG buyingIndia’s state-controlled gas distributor Gail and Japanese utility Chubu Electric Power have signed a deal to collabo-rate on LNG procurement. The firms will pursue possible joint purchases of LNG and optimise shipping to buy LNG at lower prices. They are looking to bet-ter balance demand fluctuations with contractual commitments by diversifying supply and increasing contract flexibility. This may reduce expensive spot buying. The deal follows an initial agreement reached between the two companies in January. It is part of a wider strategy to co-ordinate LNG purchases between

Asia-Pacific buyers to cut the cost of imports. Gail is seeking to establish the Asia LNG forum, a group of LNG buyers, and is actively working towards estab-lishing a regional gas trading hub for Asia-Pacific and an Asian gas index. And Japan’s economy, industry and trade ministry announced plans last year to set up a study group of LNG buyers.

Japanese utility secures Cameron LNGJapanese utility Kansai Electric Power on 31 March agreed to buy around 400,000 t/yr of LNG from the planned 12mn t/yr Cameron LNG export project in the US through Japanese trading firm Mitsui. The deal will cover 20 years from the second half of 2017, when the plant is due on line. Prices will be linked to US Henry Hub indexes, and supplied on a delivered basis. Mitsui has 16.6pc in Cameron LNG, with 50.2pc owned by US firm Sempra Energy. Japan’s Mitsubishi and France’s GDF Suez each hold 16.6pc. Mitsui, Mitsubishi and GDF Suez have bought the full capacity of the terminal’s three 4mn t/yr liquefaction trains. Kansai used 7.6mn t of LNG last year, up by 1.7pc from 2012 and by 31.1pc com-pared with 2011 (AGL, February, p14).

US Exim bank to finance Philippines LNGThe US Export-Import Bank (Exim) has signed an initial deal with the Philippines’ Department of Energy for $1bn of financ-ing guarantees to develop LNG import

In brief

India’s Election Commission has told the government to stop a planned increase in gas prices in a blow to attempts to boost struggling domestic output.

The decision will delay the intro-duction of a new gas price formula that would have doubled wellhead gas prices to around $8.40/mn Btu from April. The price increase would poten-tially make higher-priced LNG imports more competitive in the domestic mar-ket (AGL, July, p13).

But a delay could further hit Indian gas output, while uncertainty over pric-

ing policies will hurt investment, forcing industries to turn to imported LNG in the absence of reliable domestic supplies.

India’s Aam Aadmi Party, led by anti-corruption activist Arvind Kejriwal, had asked the commission to intervene to stop the gas price hike. It argued that election laws bar the implementa-tion of new policies after the poll dates are announced. India will hold general elections in April and May, and the new government that takes office in June is likely to review the gas pricing policy of the current Congress-led administration.

India’s gas price reforms face delay

April 2014



facilities and renewable energy generat-ing capacity in the Philippines. The bank will finance medium and long-term loan guarantees and may also provide direct dollar loans up to a combined value of $1bn. The funds are intended to sup-port the development of LNG infrastruc-ture including ports, receiving terminals, regasification facilities and pipelines, and the bank hopes that it will help support US energy-related exports to the country. The Philippines does not import LNG, but plans to boost LNG consumption in order to diversify its energy mix and reduce emissions. Domestic power generation firm First Gen is developing a 4mn t/yr land-based import terminal at Batangas, which could come on line in 2018. And Hong-Kong based Energy World is devel-oping a 3mn t/yr LNG import terminal in Pagbilao, southeast of the capital Manila. The Philippines development bank has underwritten the Pagbilao project’s $550mn of debt (AGL, March, p14).

Mozambique LNG signs preliminary dealsUS upstream independent Anadarko Petroleum has signed non-binding pre-liminary deals with Asian buyers for 3.3mn t/yr of LNG from its planned Mozambique LNG export project. Deals will contain some hybrid pricing with oil linkage and spot gas indexation, such as the UK NBP or the US Henry Hub. This would allow east African projects to compete against planned US export pro-jects based on US spot prices, and more easily sell to relatively close European markets. A deal with Thailand’s PTT has already been signed. First cargoes are due in 2018. Offshore area 1 has 1.3 tril-lion-2 trillion m³ in recoverable reserves Anadarko says. Anadarko projects that Mozambique will become the world’s third-largest LNG producer with a capac-ity of about 50mn t/yr, behind Qatar and Australia (AGL, October, p8).

PNG LNG to export 9-13 cargoes in 2014Papua New Guinea (PNG) LNG is likely to export between nine and 13 LNG car-goes this year, according to stakeholder upstream independent Oil Search. The ExxonMobil-operated 6.9mn t/yr LNG

facility is due to deliver its first cargo by mid-2014, up to a month earlier than pre-vious estimates. The plant’s gas output will be 730mn-1bn m³ this year, or about 9-13 LNG cargoes, Oil Search says. The firm plans to continue exploration of the P’nyang and Hides areas this year, with a view to using the gas to underpin a possible PNG LNG expansion. Almost 95pc of the two-train, $19bn plant’s supplies have been contracted to four customers — Chinese state-controlled Sinopec with 2mn t/yr, Japanese utilities state-controlled Tepco and Osaka Gas with 1.8mn t/yr and 1.5mn t/yr, respec-tively and Taiwanese state-owned CPC with 1.2mn t/yr. Plans for the remaining 400,000 t/yr are unclear (see p12).

Gazprom discusses LNG sales to KuwaitRussia’s state-controlled Gazprom wants to sell more LNG to Kuwait to underpin its liquefaction expansion plans. Kuwait imports LNG in the summer when power demand for air-conditioning is highest. The issue was on the agenda at a March meeting between Gazprom chief execu-tive Alexei Miller and Kuwait’s ambas-sador to Russia Abdulaziz al-Adwani. Gazprom’s LNG projects include the first 5mn t/yr Vladivostok LNG train, due for commissioning in 2018, with a second train in 2020. Gazprom is also consider-ing expanding the 10.6mn t/yr Sakhalin 2 plant. Both projects are in Russia’s far east. Gazprom has sold two LNG car-goes to Kuwait from the Sakhalin 2 pro-ject since 2011, through Gazprom-led Sakhalin Energy. Kuwait’s state-owned KNPC recently agreed a five-year charter with LNG tanker operator Golar LNG Partners for the 170,000m³ Golar Igloo floating storage and regasification unit, with the charter due to begin this month (AGL, December, p23).

BofA Merrill Lynch signs Dubai LNG dealBank of America Merrill Lynch has signed a short-term deal to supply LNG to Dubai from this summer. The deal is with the Dubai Supply Authority and is for under five years. Standard-sized LNG shipments will arrive at the 3mn t/yr Jebel Ali import terminal, and the gas will be used for elec-tricity generation. The bank declines to comment on whether the price is oil-linked or where the LNG will come from. This is the bank’s first major supply deal with a buyer in the Middle East. Its previous activities have included importing cargoes into the Netherlands’ Gate LNG terminal and trading European reloads. The bank is continuing small-scale operations from Gate. It signed a deal last year to supply LNG to industrial and marine transporta-tion customers in the Baltic region. The deliveries started in summer last year.

Bulgaria and Greece mull joint FSRUBulgaria is in discussions with Greece about a joint LNG import deal to diversify its energy supply. Bulgarian energy minis-ter Dragomir Stoynev said last month that the governments are considering a col-laborative floating storage and regasifica-tion unit (FSRU) for LNG imports at the city of Kavala in northern Greece. The terminal would enable Bulgaria to import LNG through Greece and sell it on to Romania and Serbia. Talks are expected to be final-ised by the end of this year. Bulgaria has no LNG import infrastructure. Greece has one LNG import terminal at Revithoussa in the south, near Athens. The 1.6mn t/yr terminal operated by state-controlled Depa has 130,000m³ of storage capacity — enough for a week’s sendout at peak capacity (AGL, November, p13). The two countries discussed potential LNG sup-ply during a recent working visit to Qatar, Stoynev says.

In brief

Global Markets

Cushing struggles with persistent constraintsCFTC will be key to market reformFTC may soften anti-manipulation ruleUrals goes eastAdnoc deepens April export cuts

OIL PRICE REPORTING, DERIVATIVES AND ANALYSIS VOLUME XXXIX, 9, 2 MARCH 2009

C O N T E N T S

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Crude sold from floating storageNew Nigerian projects to offset output lossesFSU product exports riseOpec cuts start to biteCrude loadings fall

Elections have consequences. US president Barack Obamahas been given a clear mandate for change. The new admin-istration is determined to tighten financial regulation. Reck-less accumulation of risk by banks in financial derivativestriggered the credit freeze and has saddled the US and theworld with a deep recession that threatens to become a full-blown depression. The danger now is that moves to regulatefinancial markets will spill into energy markets.Gary Gensler is likely to be confirmed as chairman ofUS commodities regulator the CFTC, and therefore on thefront line of the Obama administration’s efforts to overseeoil derivatives. Gensler came under close scrutiny during hisconfirmation because of his background as a treasury offi-cial in the Clinton administration. Opposition to his nomina-tion came principally from Senate agricultural committeechairman Tom Harkin, who was concerned about Gensler’srole, along with that of Obama’s treasury secretary TimothyGeithner, in deregulating financial markets in the late 1990s.

Gensler’s career in Wall Street bank Goldman Sachstroubles some observers. But he has assuaged the commit-tee’s doubts. Gensler proposes that all standardised over-the-counter (OTC) derivatives, such as swaps, be clearedthough exchanges. The credit freeze has already led to manymore crude and product swaps moving to Ice and Nymex’sClearport exchange for clearing, as financial institutionsseek to minimise counterparty risk in OTC deals.Gensler’s replies to senator Carl Levin addressed USpoliticians’ concerns head on. “I believe that excessive spec-ulation in commodity futures can cause sudden or unreason-able fluctuations or unwarranted changes in commodityprices,” Gensler wrote. “Excessive speculation” is a phrasewritten into the Commodities Exchange Act that hasbecome a buzz term among supporters of tighter market reg-ulation. Obama’s energy plan promises a “crackdown onexcessive energy speculation”. Excessive speculation is bad.But then “nothing in excess” is an ancient classical saying.

The term excessive speculation carries political weightbut little practical meaning. The CFTC has repeatedly dis-proved the theory that speculation distorts oil futures mar-

kets. Yet Congress and the Bush administration passed anenergy law that enables US antitrust regulator the FTC towrite a rule to prevent manipulation in wholesale oil mar-kets. “Frankly, the best intentioned and most brilliantlycrafted legislation will be only as effective as the regulatorswho will implement the law,” Harkin says. Manipulation isclearly wrong. The issue is defining it. If the FTC makes arule, it is likely to use a broad definition of “recklessness”,rather than “specific intent” to manipulate the oil markets.The FTC takes its cue from securities market legislation.But financial markets have collapsed, whereas oil marketsas currently regulated are efficient and competitive. Impos-ing a recklessness definition is likely to discourage oil firmsfrom doing more than the minimum of trading to deal withsupply imbalances. Price discovery, risk management andliquidity would all suffer. Oil prices would become morevolatile, lurching from one opaque level to another, as theydid in the 1970s before liquid oil markets fully developed.Financial markets march to the beat of different drumsthan oil markets do. Rules that have evolved to prevent themanipulation of the price of slips of paper in equity or bondmarkets will have unintended consequences when applied tothe buying and selling of physical oil through real infrastruc-ture, subject to the vagaries of weather and geopolitics.Needlessly creating regulatory uncertainty, or allowing twosystems, one principles-based the other rules-based, wouldharm the efficient functioning of oil markets. Politiciansshould bear in mind that new rules have consequences too.

Excessive regulation

Market markersNorth Sea Dated up by almost $5/bl to $45.40/blApril WTI gains just over $5/bl to $45.22/blUS gasoline crack spreads rise by $3.50-6.25/blGlobal diesel margins down by up to $2.50/bl

Argus Global Markets

Argus Global Markets frequently sparks debate within the oil industry with its topical and insightful editorials on key issues driving the global oil markets. Each week the publication features intelligent analysis of the latest market trends, and draws on Argus’ daily oil price reporting resources to survey regional crude and products markets. Contact us on Tel:+44 20 7780 4200, email: [email protected]

April 2014



Global LNG prices at a glance $/mn Btu

US

Dec Jan ±

Everett 8.17 10.21 2.04

US average 8.17 6.75 -1.42

Europe

Dec Jan ±

France 11.74 11.57 -0.17

UK (Qatar) 10.49 9.67 -0.82

Spain 10.30 10.23 -0.07

Asia-Pacific

Jan Feb ±

Japan 16.80 16.61 -0.19

China 13.37 11.67 -1.70

S.Korea 14.57 14.57 0.00

Taiwan 14.02 13.98 -0.04

Northeast Asian importers may expose themselves to higher political risk and price volatility by stalling the growth of tradi-tional suppliers and shifting needs to US and Russian sources.

Australia’s Woodside Petroleum, the UK’s BG and other major LNG developers say mixed signals on energy policies in Japan, South Korea and China are contributing to delays in approving the next wave of export projects. Only one of the 10 final investment decisions (FIDs) due in 2013 actually occurred, as sanctioning was pushed back on Nigeria’s Brass LNG venture, a fourth train at the Gorgon project in Australia and Eni’s proposed development offshore Mozambique.

The one FID taken last year was for the Yamal LNG development in northwest Siberia. Russia is advancing plans to boost exports to Asia-Pacific and reduce its reliance on European customers. Shell and state-controlled Gazprom are considering an expansion of the Sakhalin 2 export project.

Meanwhile, the shale gas boom in North America has positioned the US to become a major LNG exporter, with over 290mn t/yr of liquefaction projects proposed.

Asia-Pacific buyers are pursuing new supply as they push for lower prices and more flexibility, including less oil indexa-tion. LNG costs in Asia have jumped by 170pc in the past five years, eroding countries’ economic competitiveness, accord-ing to Taiwan’s CPC. “Ensuring a stable supply at a reasonable price is a critical concern,” chairman Sheng-Chung Lin says.

Japan may even look to import Russian pipeline gas, at an infrastructure cost of $5bn-5.5bn, despite current geopolitical tension, utility Tokyo Gas vice-president Shigeru Muraki says.

But US and Russian supplies are not without problems. Only 18mn t/yr of US export capacity has been sanctioned, and exports are controversial. Linking prices to the US Henry

Hub means diversification is volatile, but LNG priced off Henry Hub could become more expensive than oil-linked imports, South Korean Kogas chief executive Jang Seok-hyo says. Kogas and Tokyo Gas plan to limit exposure to US gas.

Russia has a geopolitical struggle with the US over Ukraine. US and EU sanctions against Moscow threaten to cut investment and push up costs just as Russian firms take on key projects such as Yamal. Pursuing lower fuel costs comes with a higher risk of supply disruption, UK consultancy Wood Mackenzie says. But the US-Russia row may lead to faster approvals for US LNG export projects. “The political use of gas as a foreign policy tool is gaining momentum,” the firm says.

Gas producers see little risk of disruptions to Russian sup-ply. Russia supplied gas to Europe through the Cold War, Shell global LNG vice-president Roger Bounds says. And fears over escalating sanctions will probably prove moot by the time new projects such as Eni’s LNG development in Mozambique start up, Eni vice-president Steve Ratcliffe says (AGL, October, p7).

But usual Asia-Pacific suppliers, such as Woodside and Qatar’s state-owned Rasgas, are reminding buyers of their reliability. Ukraine is a “reminder to buyers that diversity of sup-ply is the best way to ensure supply security”, Woodside chief executive Peter Coleman says (see pp10-11).

And exporters say they need more clarity from custom-ers. Japan has delayed nuclear restart decisions, clouding its demand outlook. Kogas is reluctant to agree new contracts until Seoul issues new gas supply targets, due late this year. And China has sent mixed demand signals. “Clear and imme-diate decisions need to be made against an ambiguous back-drop to ensure adequate supply where and when required,” Rasgas chief executive Hamad Rashid al-Mohannadi says.

Asian LNG shift could carry higher risk

Market overview

April 2014


Argus Global LNG — Market overview

LNG prices $/mn BtuImporter/source Feb 13 Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 FebJapan

Abu Dhabi 17.06 17.31 16.39 16.95 17.55 16.70 16.58 15.99 15.94 16.15 16.65 17.66 17.12

Algeria 16.62 15.80 15.75 15.37 15.15 15.46 19.03 18.74

Australia 15.80 14.43 14.67 15.69 14.95 15.96 14.95 13.62 14.23 14.02 14.45 15.13 15.83

Belgium 18.85

Brunei 17.13 17.49 16.57 17.19 15.11 16.21 16.16 16.11 15.80 16.07 16.75 17.49 17.15

Egypt 15.96 17.01 17.74 17.54 18.10 16.30

Equatorial Guinea 16.49 18.93 17.40 17.47 17.01 17.56 17.19 16.68 17.31 16.97 18.36 18.44

France 16.72

Indonesia 17.66 18.41 17.17 16.95 17.07 16.76 16.96 17.08 16.29 16.89 17.21 17.89 17.79

Malaysia 17.39 17.65 16.57 17.33 17.54 16.75 16.90 16.46 16.16 15.56 16.98 17.87 17.49

Norway 14.96 16.15 17.35 19.28 18.92

Nigeria 16.04 17.02 16.01 16.25 16.54 16.10 15.33 15.89 15.75 15.97 16.34 17.37 17.40

Oman 9.18 10.64 11.65 13.09 13.35 9.47 10.48 9.70 11.05 11.46 11.46 16.01 11.87

Peru 19.02 17.27 15.86 15.94 19.08 19.51

Qatar 16.77 17.25 16.56 17.12 16.87 16.70 16.34 16.00 15.99 16.24 16.35 17.55 17.16

Russia 14.85 14.06 13.90 13.68 13.84 14.19 13.23 14.56 12.02 13.82 16.08 14.51 14.26

Spain 16.07 16.39 18.85

Trinidad 14.59 15.48 15.09 16.63

Yemen 17.21 18.36 16.47 16.06 14.29 16.05 16.90 17.93

Average 16.41 16.35 15.70 16.23 16.03 15.96 15.57 15.02 15.04 15.57 15.91 16.80 16.61

China

Algeria 16.77

Australia 3.25 3.25 3.32 3.56 3.95 3.49 3.22 3.37 3.24 3.24 3.64 3.43 3.33

Egypt 18.77 16.09 15.90 17.88

Equatorial Guinea 16.00 15.84 16.39 18.38 19.04

Indonesia 4.00 4.03 3.89 3.91 4.02 3.89 3.90 3.88 3.80 3.76 3.86 3.79

Malaysia 7.70 8.23 8.17 8.02 7.96 8.02 7.92 9.81 8.83 7.76 7.58 8.60 7.46

Nigeria 16.98 13.97 14.87 17.43 16.54 17.03 16.86

Qatar 18.06 17.94 18.62 18.87 18.76 17.19 17.92 17.58 17.50 16.68 17.41 17.92 17.43

Russia 17.60

Trinidad 16.30 18.66 15.94

Yemen 18.83 19.74 10.13 14.35 13.94 14.50 15.80 9.50 12.26 16.97 18.72

Average 13.37 10.60 10.96 9.11 11.09 10.77 11.57 11.86 9.44 9.47 13.87 13.37 11.67

South Korea

Algeria 16.01 15.70 15.79

Australia 14.99 13.51 13.50 14.13 15.00 13.72

Belgium 15.85 16.72 17.51

Brunei 19.55 19.61 17.22 16.61 16.61 17.31 15.77 20.82 16.44 16.90 17.17

Egypt 15.96 15.13 16.47 16.29 13.54 18.75

Equatorial Guinea 17.03 17.02 16.49 18.92

Indonesia 13.33 14.78 15.09 12.79 13.85 12.71 12.94 13.25 11.88 12.92 14.01 14.00 13.93

Malaysia 12.17 10.69 8.95 13.14 12.72 8.50 15.90 11.15 15.88 12.54 14.93 16.73 17.05

Nigeria 15.08 13.98 16.26 13.77 14.76 16.11 14.39 15.44 11.16 14.91 16.66 16.79

Norway 17.91 8.78

Oman 18.50 18.32 18.24 18.40 18.11 18.16 17.25 19.25 16.95 18.60 17.35 18.11 18.17

Peru 16.17 15.50 15.51

Qatar 17.00 17.14 17.82 18.25 17.79 18.32 17.88 20.06 16.69 18.74 16.76 17.37 17.66

Russia 6.94 3.73 4.30 3.91 7.85 15.25 8.78 7.09 4.37 8.88 3.91 7.54 11.24

Trinidad 12.98 11.83 12.43 13.32 12.62 12.45 13.90

Yemen 10.67 7.94 8.34 6.55 6.10 8.15 3.96 8.65 8.94 8.54 6.29 15.48

Average 14.98 15.19 14.28 14.55 14.89 14.91 14.73 14.75 14.42 13.54 14.60 14.59 14.57

Taiwan

Australia 18.26

Brunei 17.39

Egypt 15.98 17.36 16.00

Equatorial Guinea 14.86 16.23 16.19 17.69 16.92

Indonesia 17.65 18.83 20.12 16.88 16.70 17.12 17.60 17.96 18.84 18.31 17.37 18.06 17.75

Malaysia 17.46 18.39 17.38 18.14 17.25 16.31 16.48 16.57 17.11 17.07 17.09 17.24 17.10

Nigeria 17.63 15.71 15.65 21.08 17.30 16.55 17.56

Qatar 13.04 11.33 12.78 10.90 12.62 11.84 11.74 11.89 10.98 11.76 10.53 11.79 11.07

Russia 19.17 19.17 16.93 18.43

Trinidad 16.00

Yemen 14.68

Average 14.49 14.62 15.35 14.42 14.89 15.34 14.41 14.71 14.64 15.39 13.67 14.02 13.98

Thailand

Nigeria 16.37 16.31 17.91

Qatar 17.29 15.02 14.58 14.76 16.32 16.71 17.75

Russia 17.28

Average 17.29 16.19 15.29 15.34 16.31 17.91 16.71 16.71 17.75

April 2014


Argus Global LNG — Market overview

LNG prices $/mn BtuImporter/source Feb 13 Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 FebIndia

Algeria 11.62

Egypt 15.91 15.34 12.24 12.49

France

Nigeria 13.60 13.02 13.66 13.64 11.71 13.36 14.12 13.66

Qatar 11.68 10.48 11.05 10.97 10.61 11.47 11.67 12.78 12.74 12.21

Yemen 15.25 14.25 11.03 13.13 13.54 14.40 11.84

Average 12.14 11.09 11.80 11.11 10.93 11.47 11.94 12.94 12.88 12.19

Belgium

Egypt 10.55

Qatar 10.30 10.62 10.81 10.08 9.95 9.90 10.29 10.29 10.59 11.16 10.43

France

Algeria 12.50 11.56 11.61 11.59 11.70 11.56 11.59 11.31 11.61 11.53 11.54 11.50

Belgium 3.25 10.35 10.06 16.53 9.07 11.21 9.95 10.04

Egypt 11.57

Nigeria 12.78 11.77 11.69 11.80 11.26 11.70 11.76 11.66 11.60

Norway 11.71

Qatar 13.78 13.82 13.48 12.87 13.20 12.98 13.33 13.01 13.54

Yemen 8.24

Average 12.93 9.75 12.01 11.81 11.09 11.93 11.62 11.82 11.81 12.08 11.74 11.57

Greece

Algeria 12.79 12.58 12.97 12.43 12.42 11.72 12.10

Equatorial Guinea 33.99

Nigeria 14.10

Italy

Algeria

Qatar 12.76 12.39 12.98 12.85 13.11 11.84 9.80 9.75 10.02 9.83 9.61

Portugal

Algeria 11.07

Egypt 12.10

Nigeria 8.48 7.84 9.01 7.91 8.51 10.70 7.81 10.05

Norway 8.83 7.56

Other 15.54 10.24 11.64 8.69 8.87 8.75 8.68

Qatar 10.10 11.05 11.27 11.19

US 15.47

Spain

Algeria 11.36 10.21 11.21 10.67 11.23 10.45 10.38 10.30 10.65 10.14 10.80 10.98

Egypt 8.82 11.10

Nigeria 8.77 10.02 9.25 7.91 10.03 9.06 9.84 10.06 9.35 8.09 9.80

Norway 8.73 10.89 10.23 13.46 10.92 12.57 10.93 10.93 11.25 10.16 15.78

Oman 8.53 8.70

Peru 10.30 4.21 2.18 7.74 6.21 7.04 10.22 10.05 11.03 10.06 7.87

Qatar 11.80 9.91 10.14 11.11 10.05 9.54 9.51 9.97 9.68 10.05 10.37 10.14

Trinidad 7.28 7.54 10.91 10.04 10.31 12.76 11.43 8.13 6.51 7.16 10.22 10.49

Average 9.93 9.45 9.86 9.70 10.18 9.84 9.79 9.96 9.69 9.64 10.30 10.23

UK

Algeria 9.39 11.41 9.53 9.64 9.99

Egypt

Norway 7.87 8.62 11.82 9.96 9.13 9.18 10.42 10.53 9.95 10.24 10.55

Qatar 7.94 9.63 9.39 9.55 9.49 8.88 8.14 7.54 9.41 10.07 10.49 9.67

Trinidad 17.48 3.48 1.34

US 2.14

Average 7.94 10.13 9.45 9.83 9.17 8.93 8.99 8.47 8.85 10.05 10.43 9.75

Canada

Trinidad 6.18 3.31

Chile

Mejillones

Quintero

US

Cove Point

Nigeria 14.18

Trinidad

Elba Island

Qatar 2.97 3.17

Trinidad 2.97 3.31 4.15

Everett

Trinidad 5.73 5.89 4.67 4.29 5.03 4.27 3.71 3.89 3.28 4.05 10.21

Yemen 7.19 7.29 8.17

Sabine Pass

Trinidad 14.00 13.40

US average 4.18 4.69 4.67 4.29 8.23 4.27 6.84 9.26 5.33 4.05 8.17 6.75

Puerto Rico 4.10 12.84 13.03 3.67 13.74 13.57 8.27 8.05 5.82 12.65 9.30 8.77

April 2014



l NBP day-ahead and near-curve prices tumbled in March as mild weather curbed demand and imports from Norway rose. Norwegian output was boosted after successful repairs to a faulty Troll compressor that had limited production since January last year. The combination of steady imports from Norway and weak heating demand resulted in a low draw on storage reserves, which were considerably higher than a year earlier by the end of March. The storage overhang, fore-casts for a warm start to April and weak power sector gas demand weighed on contracts delivering through summer.

l Zeebrugge’s LNG terminal received three cargoes and reloaded two to leave net LNG deliveries at 132,000m³ in March. The two re-exports totalled 310,000m³, judging by tanker size, compared with 138,000m³ exported in March last year. The higher reloads occurred during mild weather and low demand, which weighed on sendout into the Belgian system. Weak demand and mild weather saw day-ahead prices at Zeebrugge beach fall by 9p/th in March.

l Low demand in France for much of March saw prices slide, exacerbated by persistent storage withdrawals. Lower storage capacity uptake for the next year meant shippers had to withdraw gas that could not be rolled over into the new storage season starting on 1 April. Day-ahead prices at the Peg Nord fell by €3.50/MWh in March, and at the Peg Sud they declined by €6.90/MWh over the month.

Weak demand weighs on prices

European pipeline markets

Argus European long-term contract prices (pipeline) €/MWhDelivery month Jun 13 Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar Apr* May* Jun*

Oil index 32.93 32.56 32.38 32.19 31.85 31.74 31.75 31.70 31.70 31.44 31.26 31.06 30.98

+5pc discount 31.28 30.93 30.76 30.58 30.26 30.15 30.17 30.11 30.11 29.86 29.69 29.51 29.43

+7.5pc discount 30.46 30.11 29.95 29.78 29.46 29.36 29.37 29.32 29.32 29.08 28.91 28.73 28.66

+10pc discount 29.64 29.30 29.14 28.97 28.66 28.56 28.58 28.53 28.53 28.29 28.13 27.96 27.88

+12.5pc discount 28.81 28.49 28.33 28.17 27.87 27.77 27.78 27.74 27.74 27.51 27.35 27.18 27.11

+15pc discount 27.99 27.67 27.52 27.36 27.07 26.98 26.99 26.94 26.94 26.72 26.57 26.40 26.33

+20pc discount 26.34 26.04 25.90 25.76 25.48 25.39 25.40 25.36 25.36 25.15 25.00 24.85 24.79

Oil/TTF

Oil index 90pc + 10pc TTF 32.28 31.90 31.76 31.54 31.32 31.26 31.35 31.32 31.18 30.69 30.54 30.38 30.31





Oil/NCG

Oil index 90pc + 10pc NCG 32.31 31.92 31.78 31.57 31.34 31.28 31.36 31.33 31.19 30.72 30.56 30.40 30.33





Oil/VTP

Oil index 90pc + 10pc VTP 32.37 31.98 31.84 31.64 31.38 31.29 31.36 31.33 31.20 30.74 30.60 30.43





*provisional

Argus European long-term contract prices, Mar 14€/MWh $/’000m³

Oil index 31.44 461.46

+ 5pc discount 29.86 438.39

+ 7.5pc discount 29.08 426.85

+ 10pc discount 28.29 415.31

+ 12.5pc discount 27.51 403.78

+ 15pc discount 26.72 392.24

+ 20pc discount 25.15 369.17

Oil/TTF

Oil index 90pc + 10pc TTF 30.69 450.53





Oil/NCG

Oil index 90pc + 10pc NCG 30.72 450.88





Oil/VTP

Oil index 90pc + 10pc VTP 30.74 451.23





April 2014



l US gas futures fell in March amid expectations that milder seasonal weather will trim demand, despite the colder-than-normal finish to the 2013-14 winter heating season.

l Nymex prompt-month prices fell by 23.8¢/mn Btu, or 5.2pc, since 28 February to settle at $4.371/mn Btu on 31 March. Prices reached a settlement peak of $4.667/mn Btu on 4 March amid forecasts for cold weather and dwindling stocks. But they retreated from that high with the approach-ing spring shoulder season, when weather-related gas demand typically goes slack and storage injections resume.

l The injection season, which usually begins on 1 April, should result in record additions to US stockpiles owing to growing US gas output, the EIA says. US gross gas produc-tion in January rebounded to more than 75bn ft³/d (772.5bn m³/yr) as output from Texas and New Mexico rose, more than offsetting a weather-related production decline from the Marcellus shale in Pennsylvania and West Virginia.

l US gas stocks continued to fall sharply amid demand-boosting cold. Draws from storage in the four weeks ended 28 March totalled 374bn ft³ (10.6bn m³). That decline was more than double the five-year average draw for the period of 140bn ft³ but was 7pc below the year-earlier level. The bigger-than-average fall in March left US inventories at 822bn ft³, the lowest in more than a decade. US stockpiles at the end of the month were 52pc lower than a year earlier and 55pc below the five-year average, EIA data show.

US gas futures dip with onset of springHenry Hub vs Zeebrugge $/mn Btu


4

6

8

10

12

Zeebrugge

Henry Hub

Henry Hub vs Zeebrugge $/mn Btu

Jul 12 Oct Jan 13 Apr Jul Oct Jan 14 Apr-3

-2

-1

0

1

2

Zeebrugge 1st full-month vs NBP (p/therm)

NBP = 0

Zeebrugge front-month differential to NBP p/therm

US

Spot market natural gas prices (pipeline)Mar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

Europe p/th

UK NBP, 1st month 69.93 66.93 64.80 63.45 65.70 64.49 65.96 68.81 70.82 70.83 66.07 59.02 56.77

UK NBP, 2nd month 66.59 65.94 64.92 64.83 65.15 65.82 68.70 70.91 71.97 71.36 65.15 58.70 56.56

UK NBP, 3rd month 64.96 65.93 65.70 64.49 67.14 69.52 70.90 72.23 72.17 69.76 64.03 58.36 56.02

Ice, 1st month 69.46 66.89 64.75 63.54 65.68 64.57 66.08 68.94 70.78 70.89 66.06 58.97 56.78

Ice, 2nd month 66.45 65.95 64.91 64.82 65.22 66.02 68.80 70.95 71.93 71.31 65.13 58.65 56.55

Ice, 3rd month 64.98 65.95 65.65 64.62 67.27 69.68 70.98 72.23 72.04 69.66 64.00 58.28 56.06

Europe €/MWh

Zeebrugge, 1st month 27.12 26.88 26.54 25.85 26.17 25.73 26.55 27.08 28.07 28.17 26.61 24.01 23.11

Zeebrugge, 2nd month 26.40 26.80 26.31 26.21 26.03 26.05 27.28 27.87 28.42 28.38 26.37 24.12 23.23

Zeebrugge, 3rd month 26.05 26.57 26.53 26.04 26.41 27.01 27.98 28.22 28.54 27.81 26.30 24.20 23.29

TTF 1st month 26.91 26.83 26.46 25.97 26.14 25.68 26.55 26.93 27.75 27.96 26.52 23.99 23.11

TTF 2nd month 26.44 26.86 26.37 26.22 26.13 26.05 27.18 27.47 27.97 28.21 26.39 24.14 23.23

TTF 3rd month 26.34 26.69 26.48 26.20 26.48 26.90 27.62 27.61 28.00 27.89 26.15 24.15 23.32

US $/mn Btu

Henry Hub, 1st month 3.44 3.98 4.16 4.15 3.71 3.46 3.57 3.50 3.49 3.82 4.41 5.58 4.86

NY (Transco Zone 6) 4.28 4.72 4.23 3.94 4.06 3.50 3.74 3.67 3.77 5.95 30.41 12.96 7.88

Columbia TCO 3.88 4.22 4.10 3.79 3.59 3.43 3.65 3.67 3.57 4.10 4.77 6.03 4.89

SoCal border 3.86 4.12 4.04 3.82 3.78 3.57 3.74 3.76 3.69 4.65 4.73 6.93 4.97

Nymex, 1st month 3.77 4.16 4.07 3.81 3.64 3.41 3.62 3.66 3.62 4.28 4.55 5.16 4.49

Nymex, 2nd month 3.81 4.20 4.11 3.83 3.64 3.45 3.71 3.79 3.68 4.28 4.43 4.63 4.46

US gas in underground storage bn ft³Region 28 Mar 28 Feb ± Year ago Five-year

average±% 5-yr average

East 310 525 -215 669 758 -59.1

West 160 190 -30 331 294 -45.6

Producing 352 481 -129 701 762 -53.8

Total lower 48 822 1,196 -374 1,700 1,814 -54.7

— EIA

April 2014


Argus Global LNG — Competing fuels

Crude $/blMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

Japanese Crude Cocktail 115.62 111.29 106.55 104.66 104.67 107.15 111.05 113.48 112.76 112.10 113.51 110.89 -

Tapis 115.05 108.85 108.76 108.52 113.81 118.46 119.91 117.54 113.91 117.12 114.89 115.19 112.55

Dubai (1st month) London close 105.26 100.92 100.40 100.40 103.78 107.29 108.11 106.56 106.07 107.86 103.88 105.12 104.32

North Sea Dated 108.45 101.92 102.50 102.95 107.91 111.32 111.91 109.15 108.00 110.80 108.17 108.84 107.55

WTI (1st month) 92.91 92.02 94.76 95.79 104.69 106.54 106.25 100.50 93.94 97.85 94.86 100.72 100.57

International fuel oil prices $/tMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

HSFO 180 fob South Korea 647.53 627.40 623.39 632.16 616.36 617.88 621.27 627.44 616.15 625.57 623.65 623.16 614.80

HSFO 180 fob Singapore 636.53 616.40 612.39 621.16 605.36 606.88 610.27 616.44 605.15 614.57 612.65 612.16 603.80

LSWR Indon. (V-500 fr. 1 Oct 10) 711.91 678.19 666.48 668.35 655.86 668.07 673.38 671.28 702.95 699.55 691.72 695.11 689.16

1pc fuel oil fob NWE 621.55 591.92 600.99 607.16 603.96 610.64 611.29 595.39 592.05 606.70 580.75 619.45 621.20

1pc fuel oil fob W Med 633.29 599.10 609.89 615.31 612.08 619.96 619.15 603.68 600.57 615.90 597.09 637.53 629.87

New York 1pc 627.59 610.31 610.76 603.02 596.75 610.38 620.75 614.35 608.91 613.51 615.11 663.95 656.01

International gasoil prices $/tMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

C+F Japan 930.11 878.04 871.10 892.96 925.79 939.06 935.33 937.20 933.99 955.78 919.89 929.59 915.72

Fob South Korea 916.61 863.35 860.81 877.22 908.40 923.47 917.65 915.42 910.94 935.63 903.11 915.57 904.45

German heating oil 923.34 874.13 871.85 885.89 923.55 945.82 950.60 941.72 928.02 950.19 926.36 933.70 913.70

Heating oil fob W Med 900.96 857.46 862.38 878.48 911.04 930.79 939.23 932.38 914.21 934.44 909.49 914.56 895.92

No 2 oil New York 910.73 838.92 829.81 850.13 891.47 913.79 915.71 909.89 902.24 938.04 945.35 949.28 907.29

International electricity prices €/MWhMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

France month ahead 46.22 35.12 29.87 28.33 31.71 36.98 48.30 52.38 52.35 56.75 52.62 42.17 34.40

Spain pool weighted average 25.14 19.48 34.26 41.27 51.16 43.26 50.62 51.62 41.96 61.47 32.97 16.26 27.06

Spain month ahead 40.39 41.40 49.29 48.10 50.86 50.20 47.91 50.62 48.06 58.92 44.57 29.11 28.92

PJM West day ahead $/MWh 37.39 32.19 29.53 27.39 28.93 24.97 26.39 28.69 32.68 36.98 131.50 67.71 66.02

Entergy day ahead $/MWh 27.86 27.84 24.55 22.00 21.88 21.68 21.34 24.14 26.12 30.85 40.93 48.37 39.67

International coal prices $/tMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

Japan 107.19 102.72 101.55 96.79 90.80 90.77 93.98 98.46 99.23 113.53 107.77 93.22 90.65

South Korea 101.02 96.85 95.49 91.28 85.23 84.74 86.16 89.60 90.66 94.76 92.29 89.31 87.73

Indonesia 92.73 88.99 88.28 84.71 78.16 77.83 78.04 80.08 82.21 83.85 83.32 80.35 78.35

ARA 84.49 82.76 81.84 74.51 75.22 75.43 78.41 84.72 83.86 84.59 83.32 77.16 75.25

Nymex spec. (short tons) 57.28 57.32 60.41 57.38 54.55 52.86 52.03 54.79 53.41 56.54 57.64 59.29 60.30

International shipping fuel prices $/tMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb Mar

New York 180cst 655.45 631.57 620.91 615.30 629.18 666.11 684.73 665.46 643.95 655.14 639.67 663.13 650.64

New York 380cst 625.45 601.57 590.91 585.30 596.00 607.70 611.73 605.24 592.89 604.90 589.67 617.87 605.64

Houston 180cst 649.33 629.77 622.34 615.43 623.82 664.64 693.53 656.65 632.79 650.05 629.26 635.03 635.95

Houston 380cst 609.33 589.77 582.34 575.43 580.64 591.91 612.03 596.43 582.53 597.67 579.26 589.76 585.24

Antwerp 180cst 632.06 612.45 609.07 606.53 623.26 623.96 619.81 614.20 603.60 611.66 593.52 607.35 609.06

Antwerp 380cst 603.46 585.25 583.56 580.38 595.63 600.37 591.75 584.89 573.36 580.26 564.05 577.38 575.62

Singapore 180cst 638.75 624.77 615.71 617.70 608.70 609.05 604.86 617.93 610.45 615.74 618.60 626.00 611.33

Singapore 380cst 631.80 614.14 606.67 600.95 598.22 601.90 600.26 608.28 598.71 602.38 603.69 606.88 592.45

South Korea 180cst 676.35 667.36 651.76 642.80 638.96 646.00 649.90 656.75 664.17 677.68 675.52 665.45 651.62

South Korea 380cst 654.25 645.41 627.38 619.00 614.65 620.35 625.48 631.70 641.86 651.74 647.69 635.60 622.24

Fujaira 180cst 674.80 672.23 668.76 669.85 656.52 655.08 646.48 641.95 645.43 621.55 638.29 628.20 629.55

Fujaira 380cst 633.60 618.32 611.62 611.45 593.26 596.45 596.81 607.36 614.07 604.36 610.29 605.63 598.57

April 2014



Crude prices fell in March as Libyan output looked likely to return to the market and as weak Chinese and European manufacturing data hit the global oil demand outlook. Tripoli appeared close to an agreement with armed groups in Libya to lift a blockade on major oil export ports. Libyan output is around 130,000 b/d, but capacity is 1.6mn b/d. Atlantic basin benchmark North Sea Dated fell sharply in March, by $5.36/bl to $106.04/bl. US marker WTI fell by a smaller amount — $3.34/bl to $101.58/bl — because of a more robust economic outlook compared with Europe and a fall in US crude stocks.

European diesel prices firmed in late March as more than a month of Mediterranean maintenance closed arbitrages to Europe and Turkish buying tightened availability. Gasoline rose with the switch to more expensive summer grades, but a lack of arbitrage opportunities weighed on European val-ues. Jet fuel prices remain under pressure as the arbitrage from Asia-Pacific and the Mideast Gulf to Europe opened. High-sulphur fuel oil gained ground against crude as the barge market tightened. Vacuum gasoil premiums to crude futures fell sharply on strengthening refining margins.

European coal prices were weak in March, as demand fell with rising temperatures and renewables output. Delivered prices sank to a monthly low of $72.83/t on 10 March, but rebounded to end the month at $78.58/t. Seaborne oversup-ply worsened at the end of March, as Colombia’s Drummond restarted shipments after an 11-week loading suspension from 13 January. Exports from South Africa’s Richard’s Bay surged, rising to 6.9mn t from 4.5mn t in February. Fob prices fell by $2.55/t to an eight-month low of $72.14/t on 27 March, before edging up to close the month at $73.75/t.

Higher solar and wind power generation weighed on con-tinental European spot prices in March with the German day-ahead contract averaging €31.04/MWh, down from €33.49/MWh in February and €39.36/MWh in March 2013. High hydropower and renewables output weighed on Italian spot prices but Spanish prices rose to €26.67/MWh in March from €17.12/MWh in February, with coal and nuclear plants covering demand amid limited gas-fired generation. UK spot prices fell to £44.42/MWh in March from £45.10/MWh in February as higher temperatures trimmed demand.

Libyan deal prompts crude slide

Product prices firm on maintenance

Coal eases as renewables step higher

Solar and wind power crimp spot values

Competing fuels

Jul 12 Oct Jan 13 Apr Jul Oct Jan 14 Apr90

100

110

120

130North Sea Dated

Tapis

North Sea Dated and Tapis $/blNorth Sea Dated vs Tapis $/bl

180cst fuel oil fob Singapore $/t


600

650

700

750

180cst fuel oil fob Singapore $/t

Coal: cif South Korea $/t


85

90

95

100

105

Coal cif South Korea $/t

p y

Apr 12 Jul Oct Jan 13 Apr Jul Oct Jan 145

10

15

20

25

Month-ahead

LNG

Spain: Month-ahead electricity vs LNG $/mn Btu

April 2014



l Shell is cautious on LNG bunkering, but expects 18.7mn t/yr (330,000 b/d) of demand for low-sulphur fuel oil to shift to marine gasoil next year as sulphur emissions controls are tightened. Current gasoil supplies will be sufficient to meet the increase in demand as sulphur limits are lowered to 0.1pc in emissions control areas in Europe and North America, Shell general manager of oil markets analysis Chris Midgley says (AGL, September, p16). But suppliers may struggle to meet distillate demand as a global 0.5pc sulphur cap is introduced in 2020-25, depending on the uptake of alternative technologies such as scrubbers and LNG bunker-ing. LNG is “not even close to ready” for bunkering, Midgley says, citing natural gas price volatility and the high cost of retrofitting vessels to use the fuel.

l The European Parliament has announced a preliminary timeframe for developing infrastructure to facilitate the use of alternative fuels in the transport sector, but with a delay for the introduction of LNG. The guidelines, which are set out in an informal agreement released on 20 March and must be approved by the transport committee and EU Council, specify that LNG refuelling stations for road vehicles must be widely available by the end of 2025, a delay of five years from draft guidelines released in November. The agreement stipu-lates that EU countries must ensure that sufficient refuelling and recharging stations are available to enable cars, trucks and ships that use natural gas and electricity to move freely on EU roads and waterways, with a staged introduction.

Shipping news

Shipping

LNG vessel time-charter rates $/dDuration: spot/short term

West of Suez 55,000

East of Suez 56,000

LNG vessel fleet Mar Owner No. Age of fleet

Av. Min. Max.Total capacity

m³Average

capacity m³

MISC 29 12 3 30 3,660,181 126,213

Nakilat (QGTC) 25 2 1 3 6,001,009 240,040

Teekay Shipping 15 6 12 18 2,369,984 157,999

NYK Line 15 3 1 8 2,043,660 145,976

BW Gas 14 5 2 8 2,047,348 146,239

Bonny Gas Transport 14 18 5 35 1,862,187 133,013

Mitsui OSK Line 8 11 3 26 1,077,705 134,713

BG 12 4 1 7 1,835,491 152,958

K Line 10 4 2 11 1,488,533 148,853

Shell 11 29 7 39 1,064,145 96,740

Exmar 10 4 1 9 1,445,496 144,500

J4 (MOL/NYK/K Line/Lino) 10 13 11 15 1,363,616 136,362

J5 Consortium 8 3 3 3 1,697,900 212,238

AP Moller 8 3 1 7 1,275,770 159,471

Knutsen 8 4 1 7 1,246,446 155,806

National Gas Shipping 8 16 14 17 1,094,046 136,756

Burmah Gas Transport 8 33 32 34 1,010,700 126,388

BP Shipping 7 5 3 9 1,021,980 145,997

Hyundai Merchant Marine 7 11 3 17 935,182 133,597

Australia LNG 7 18 7 22 903,830 129,119

SNTM-Hyproc 7 24 3 35 788,054 112,579

China LNG Ship 5 3 2 3 735,417 147,083

Maran Maritime Gas 5 5 4 6 727,100 145,420

SK Shipping 5 12 11 17 680,075 136,015

OSG/QGTC 4 7 7 7 864,800 210,100

Pronav Ship Management 4 4 3 4 840,800 216,200

Tokyo LNG Tanker 4 5 2 8 590,599 147,650

Sovcomflot-NYK 4 3 3 4 585,800 146,450

Oman Shipping 6 7 5 10 872,620 145,437

Dynacom Tankers 4 11 3 34 578,399 144,600

Korea Line 4 7 3 11 570,773 142,693

Golar LNG 13 19 5 36 1,740,645 133,896

Hanjin Shipping 4 13 11 16 545,347 136,337

GDF Suez 4 12 4 32 507,640 126,910

J3 (NYK/MOL/K Line)/Nakilat 5 25 22 28 631,065 126,213

Hoegh LNG 3 17 2 38 377,730 125,910

Awilco LNG 3 28 27 28 375,542 125,181

PT Humpuss 3 14 2 21 283,260 94,420

Elcano 2 5 1 8 311,673 155,837

Gaslog 2 1 1 1 309,600 154,800

STX Pan Ocean 2 2 1 3 299,300 149,650

Hoegh LNG/MOL 2 5 5 5 294,400 147,200

Petronet 2 7 7 7 272,052 136,026

J3 (NYK/MOL/K Line) 2 28 27 28 250,767 125,384

Sovcomflot 2 42 42 42 143,000 71,500

Eni 2 28 13 42 212,000 53,000

Chemikalien Seetrans 2 36 36 36 38,500 71,000

Trinity LNG Carrier 1 1 1 1 154,200 154,200

Algeria Nippon Gas 1 7 7 7 145,000 145,000

Stena Bulk 3 2 1 4 492,311 164,104

Cygnus LNG Shipping 1 2 2 2 145,400 145,400

IS Carriers 1 8 8 8 138,306 138,306

Brunei Gas 1 9 9 9 135,000 135,000

Distrigas 1 33 33 33 131,235 131,235

Messigaz 1 37 37 37 40,081 40,081

Maple LNG Transport 1 4 4 4 19,100 19,100

Camartina (QSC) 1 7 7 7 138000 138000

Peninsular LNG (J4/Nakilat) 1 4 4 4 145000 145000

Qatar LNG Transport 1 7 7 7 135000 135000

Tokyo Gas Consortium 1 17 17 17 127547 127547

Sea Optima (Tsakos) 1 4 4 4 150000 150000

Total 355 13 1 42 51,968,347 146,390

LNG vessel orderbook Mar Owner Number of vessels m³

Alpha Tankers 1 159,700

Awilco 2 311,800

BW Maritime 2 310,000

Cardiff Marine 4 639,200

Chevron 4 1,420,700

CNOOC/CLNG/Shenergy 1 147,200

Dynacom 4 620,000

Excelerate 1 173,400

GasLog 8 1,240,000

Golar LNG 9 1,450,000

Hoegh LNG 4 340,000

Maran Gas Maritime 7 1,127,000

Mitsui 1 160,400

Hudong 4 688,000

Shell 1 320,000

Sonangol 3 481,500

Sovcomflot 2 340,000

Themaris 3 480,000

Total 61 10,408,900

April 2014


Argus Global LNG — Shipping

Model assumes a 138,000m³ LNG carrier at 98pc utilisa-tion travelling at 19 knots. One day in port for loading and two for discharge. Boil-off rates of 0.15pc/d when loaded, 0.1pc/d in ballast. 5pc of cargo returned as cargo heel on ballast leg. Bunker and MDO prices from Argus, assuming consumption of 160 t/d bunkers at sea plus 3 t/d MDO in port. Cost of capital assumed at 5.5pc. Ship assumed to have 15 days/yr downtime.

Shipping data derived from Argus databasesand Argus market reports

Saili

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$/

mn

Btu

Deliv

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pric

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mn

Btu

Netb

ack

$/m

n Bt

u

1970 1975 1980 1985 1990 1995 2000 2005 20100

10

20

30

40

50

LNG vessels fleet deliveriesLNG fleet deliveries No. of vessels

Over 40 35-40 30-35 25-30 20-25 15-20 10-15 5-10* Up to 50

20

40

60

80

100

120

140

160

180

Fleet age in yearsLNG fleet age in years

Netbacks for 138,000m³ tanker Mar

Qatar-Japan 14.0 2,759,704 129,115 72,261 10,602 24,955 803,786 3,800,423 125,321 46,880,895 1.42 17.16 15.74

Qatar-S Korea 14.7 2,897,254 134,946 75,524 11,081 26,082 840,086 3,984,973 125,174 48,190,498 1.49 17.66 16.17

Qatar-Spain 11.2 2,209,507 105,791 59,207 8,687 20,447 658,586 3,062,225 125,906 27,831,862 1.14 10.14 9.00

Abu Dhabi-Japan 14.0 2,759,704 129,115 72,261 10,602 24,955 803,786 3,800,423 125,321 46,771,616 1.42 17.12 15.70

Algeria-Belgium 3.4 652,835 40,817 22,844 3,352 7,889 254,100 981,837 127,539 28,998,950 0.36 10.43 10.07

Algeria-France 1.1 216,873 21,658 12,121 1,778 4,186 134,829 391,445 128,020 32,094,570 0.14 11.50 11.36

Algeria-S Korea 20.0 3,799,346 179,095 100,233 14,706 34,615 1,114,929 5,242,923 124,065 42,705,902 1.97 15.79 13.82

Algeria-Spain 0.8 160,009 19,159 10,723 1,573 3,703 119,271 314,438 128,083 30,658,363 0.11 10.98 10.87

Algeria-US 10.9 2,074,451 103,292 57,809 8,482 19,964 643,029 2,907,026 125,969 22,435,866 1.08 8.17 7.09

Australia-Japan 7.9 1,529,614 78,302 43,823 6,430 15,134 487,457 2,160,759 126,597 43,687,839 0.80 15.83 15.03

Australia-S Korea 8.5 1,645,177 83,300 46,620 6,840 16,100 518,571 2,316,608 126,471 37,827,082 0.86 13.72 12.86

Brunei-Japan 4.9 951,799 53,312 29,837 4,378 10,304 331,886 1,381,516 127,225 47,565,489 0.51 17.15 16.64

Brunei-S Korea 5.7 1,105,883 59,976 33,566 4,925 11,592 373,371 1,589,314 127,057 47,558,300 0.58 17.17 16.59

Indonesia-Japan 7.2 1,394,790 72,471 40,559 5,951 14,007 451,157 1,978,936 126,743 49,153,879 0.73 17.79 17.06

Indonesia-S Korea 6.9 1,337,009 69,972 39,161 5,746 13,524 435,600 1,901,011 126,806 38,507,738 0.70 13.93 13.23

Libya-Spain 2.3 444,332 31,654 17,716 2,599 6,118 197,057 699,476 127,769 28,494,214 0.26 10.23 9.97

Malaysia-S Korea 4.7 913,278 51,646 28,904 4,241 9,982 321,514 1,329,566 127,267 47,303,695 0.49 17.05 16.56

Nigeria-France 8.8 1,676,399 85,799 48,019 7,045 16,583 534,129 2,367,973 126,409 31,966,207 0.88 11.60 10.72

Nigeria-Spain 8.4 1,600,579 82,467 46,154 6,772 15,939 513,386 2,265,297 126,492 27,023,815 0.84 9.80 8.96

Nigeria-US 13.4 2,548,323 124,117 69,464 10,192 23,989 772,671 3,548,756 125,446 22,342,694 1.32 8.17 6.85

Oman-Japan 13.0 2,563,205 120,785 67,599 9,918 23,345 751,929 3,536,781 125,530 32,482,831 1.32 11.87 10.55

Oman-S Korea 12.5 2,464,956 116,620 65,268 9,576 22,540 726,000 3,404,960 125,634 49,764,530 1.27 18.17 16.90

Oman-Spain 12.3 2,425,656 114,954 64,336 9,439 22,218 715,629 3,352,231 125,676 28,027,558 1.25 10.23 8.98

Oman-US 9.3 1,836,158 89,964 50,350 7,387 17,388 560,057 2,561,304 126,304 22,495,496 0.95 8.17 7.22

Trinidad-US 4.8 946,243 52,479 29,371 4,309 10,143 326,700 1,369,245 127,246 22,663,205 0.50 8.17 7.67

Alaska-Japan 7.4 1,454,258 74,137 41,492 6,088 14,329 461,529 2,051,832 126,702 36,735,847 0.76 13.30 12.54

Algeria-UK 4.0 766,565 45,815 25,641 3,762 8,855 285,214 1,135,852 127,413 27,748,258 0.42 9.99 9.57

April 2014


Argus Global LNG — LNG movements

Import volumes ’000tMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb

Importer/sourceJapanAbu Dhabi 481.10 479.20 476.70 416.40 537.70 488.40 421.40 540.10 361.80 240.50 426.50 417.20Algeria 61.50 121.10 58.60 61.60 60.40 56.90 63.20Australia 1,535.70 1,463.90 1,252.70 1,444.70 1,499.00 1,635.90 1,645.00 1,570.70 1,318.70 1,759.80 1,725.00 1,428.70Belgium 58.00Brunei 548.60 363.30 458.90 389.70 517.20 423.80 233.60 425.10 362.60 397.00 359.00 419.30Egypt 58.70 63.90 71.90 63.30 59.80 Equatorial Guinea 305.10 337.20 201.20 260.80 125.40 17.70 276.40 133.90 124.60 132.20 186.60France 43.00 Indonesia 484.90 495.00 488.40 483.80 550.50 488.90 373.30 595.10 606.20 657.30 563.30 631.00Malaysia 1,439.60 1,021.60 1,126.00 1,174.40 1,281.90 1,309.50 1,057.60 1,183.10 1,359.30 1,303.70 1,303.70 1,459.00Nigeria 428.30 227.50 368.10 117.40 189.70 237.00 320.00 232.10 425.40 407.70 495.40 301.40Norway 384.50 64.10 58.00 186.80 54.60 123.90Oman 318.10 350.90 254.20 382.80 319.10 318.60 449.20 190.40 441.30 383.50 384.90Peru 72.70 145.60 74.10 74.00 74.30Qatar 1,286.90 1,579.40 1,016.80 1,212.90 1,297.70 1,399.00 1,156.20 1,328.10 1,178.40 1,585.10 1,723.50 1,272.60Russia 714.70 731.80 708.40 563.80 700.00 643.20 853.40 642.00 723.60 780.00 769.40 687.60Spain 58.70 78.90 14.60Trinidad 54.50 55.60 50.30 61.80 Yemen 65.00 65.80 55.20 68.30 119.30 65.70 128.10Total 7,739.40 7,049.80 6,421.20 6,441.60 7,412.40 7,249.40 6,582.30 7,478.30 7.217.10 8,085.20 8,179.10 7,464.30South Korea Abu Dhabi 325.36Algeria 61.90 65.11 61.02Australia 170.95 70.33 174.68 81.87 56.30Belgium 63.83 63.00 61.99Brunei 53.81 101.86 217.65 82.49 64.43 64.45 55.03 178.79 125.11 54.61Egypt 124.72 57.73 59.62 67.20 67.33Equatorial Guinea 61.19 122.32 71.42Indonesia 584.00 439.80 582.84 298.71 344.80 630.92 441.65 603.64 577.50 502.57 514.23Malaysia 324.04 462.68 230.21 348.08 170.17 471.56 476.21 458.53 283.15 532.41 479.76 226.29Nigeria 55.34 254.64 61.21 181.82 60.76 360.34 304.60 180.82 354.02 557.17 301.30Norway 57.58 Oman 427.43 305.84 303.90 374.27 363.29 309.29 303.72 307.45 181.68 364.40 490.31 309.05Peru 148.55 70.82 70.67 76.94 72.24 Qatar 1,823.23 1,183.93 897.77 937.60 784.30 811.82 867.84 1,212.55 444.76 1,115.97 1,429.68 1,857.97Russia 127.26 191.44 127.12 191.85 63.85 119.81 248.41 191.23 250.74 192.15 256.99 256.38Trinidad 100.80 49.42 170.59 48.21 59.26 102.31 52.92 Yemen 324.60 383.99 323.70 193.38 239.94 312.85 167.17 317.35 129.76 320.72 309.31 425.26Total 4,155.68 3,513.92 2,915.35 2,787.91 2,332.46 3,271.30 2,793.97 3,189.31 2,301.64 3,956.90 4,342.25 4,134.80ChinaAlgeria 56.7Australia 260.01 324.69 325.80 323.70 256.56 253.39 323.97 258.98 323.47 323.74 323.87 258.28Egypt 60.64 188.53 61.95 63.10 Equatorial Guinea 59.00 63.36 209.09 73.64Indonesia 241.54 303.29 364.00 121.15 181.88 242.27 181.34 303.54 248.15 124.90 249.75 187.32Malaysia 199.36 191.90 253.24 200.21 250.96 249.62 178.40 283.58 144.16 257.27 413.17 243.92Nigeria 58.20 61.95 58.12 121.74 61.05 59.54Qatar 430.14 613.44 409.08 409.68 522.89 504.16 591.28 379.47 313.47 1,091.88 1,275.14 748.20Russia 66.05Trinidad 57.80 56.67 61.09Yemen 68.19 65.38 133.62 134.74 193.63 60.32 68.90 198.43 129.45 128.48Total 1,257.44 1,559.34 1,352.12 1,250.31 1,347.03 1,689.40 1,452.43 1,356.42 1,347.74 2,377.84 2,652.24 1,497.26TaiwanAustralia 60.39 Brunei 65.10Egypt 57.60 62.99 63.81 Equatorial Guinea 63.59 58.93 127.85 73.90 63.02 Indonesia 183.93 61.31 122.62 183.93 122.62 183.93 183.93 189.93 183.93 183.93 122.62 183.93Malaysia 115.65 298.59 300.91 300.45 306.82 353.02 302.89 185.55 303.06 179.06 118.72 181.82Nigeria 124.49 62.38 125.25 62.98 66.87 60.84 68.50 Qatar 571.23 442.34 505.33 628.71 603.03 567.29 566.29 439.36 379.77 506.82 493.28 434.43Russia 63.96 63.96 Spain 64.74 62.00Trinidad 55.10Yemen 61.60 Total 1,059.26 1,046.57 1,178.70 1,239.66 1,163.15 1,218.27 1,241.80 953.48 998.28 931.81 799.72 800.18ThailandNigeria 58.97 57.55 119.45Qatar 452.16 89.99 89.82 89.86 89.82 91.48 182.35Russia 17.36Yemen 63.29 Total 452.16 153.28 148.80 148.66 57.55 119.45 107.18 91.48 182.35

April 2014


Argus Global LNG — LNG movements

Import volumes ’000tMar 13 Apr May Jun Jul Aug Sep Oct Nov Dec Jan 14 Feb

IndiaAlgeria 66.84 Egypt 62.85 65.72 67.41Nigeria 61.53 61.58 61.17 60.95 122.58 61.07 60.70Qatar 750.98 921.54 1,118.80 920.92 927.51 1,042.30 711.76 1,050.60 1,070.61Yemen 70.28 60.06 70.24 65.12 63.76 69.99Total 942.20 1,119.12 1,240.03 1,119.52 927.51 1,230.00 831.74 1,175.06 1,140.60Belgium Algeria 8.96Qatar 123.16 184.87 194.35 176.39 307.63 185.14 184.75 184.75 125.51 185.28Total 123.16 184.87 194.35 185.35 307.63 185.14 184.75 184.75 125.51 185.28FranceAlgeria 331.36 368.40 618.46 390.98 339.60 431.67 315.16 154.19 157.33 306.58 356.77Belgium 92.15 2.94 1.42 0.99 1.07 0.59 2.90 10.04Egypt 64.97Nigeria 54.47 123.32 59.08 62.51 127.56 72.65 116.95 114.16Norway 61.79 Qatar 92.75 89.92 93.11 92.79 180.31 93.11 90.12 92.62Yemen 69.80Total 423.51 518.56 833.12 520.85 433.78 589.43 557.98 375.45 381.89 519.05 480.97GreeceAlgeria 87.43 32.63 32.85 64.16 33.97 33.80 108.28 Eguatorial Guinea 33.99Nigeria Total 87.43 32.63 32.85 64.16 33.99 108.28ItalyQatar 187.80 251.64 248.12 311.40 309.48 124.28 189.97 126.72 120.18 121.36 Total 187.80 251.64 248.12 311.40 309.48 124.28 189.97 126.72 120.18 121.36Portugal Algeria 33.80 Egypt 62.88Nigeria 55.66 60.95 117.03 127.24 134.14 53.97 162.45Norway 61.53 60.51Other 24.17 0.16 53.00 0.27 0.27 0.25 0.35 Qatar 56.3 60.06 61.53 59.47US 47.60 Total 161.23 180.29 238.62 127.24 194.65 168.50 221.92 0.27 0.27 0.25 0.35Spain Algeria 228.96 305.07 335.47 287.82 547.09 122.40 222.33 299.75 244.47 266.40 209.96Egypt 56.72Nigeria 100.02 309.92 101.65 126.24 116.81 59.49 112.69 402.32 111.05 333.22Norway 103.04 21.45 5.87 128.07 62.66 171.98 117.66 116.92 61.82 61.73Oman 63.98 62.63 Peru 70.35 62.17 141.98 140.65 132.75 141.18 77.85 198.71 70.71 154.75Qatar 236.41 214.50 172.92 260.52 180.48 295.41 209.04 271.44 117.18 302.33 175.87Trinidad 227.35 171.80 166.05 56.27 53.35 110.26 167.66 114.48 110.59 113.35 114.40Total 959.76 1,155.72 844.13 1,000.90 1,101.04 892.29 1,027.28 1,282.76 782.00 814.61 1,049.93UKAlgeria 32.41 54.13 32.20 32.30 26.78Norway 90.70 62.20 136.83 79.35 118.78 73.25 136.59 39.13 45.09 32.93Qatar 114.21 938.07 956.73 889.04 457.35 407.45 285.84 601.04 114.27 318.70Trinidad 50.04 62.20 55.47 US 2.17 Total 287.36 1,054.40 1,093.56 1,062.79 576.13 513.00 422.43 724.59 159.36 351.63CanadaQatar 114.06Trinidad (long term) 57.99 Total 57.99 114.06USCove Point Nigeria 50.50Elba Island Trinidad 71.40 52.00 59.78Qatar EverettTrinidad 90.30 100.80 109.70 100.90 156.50 116.20 58.40 52.10 50.40 61.25Yemen 53.90 54.70 53.20 45.41 Sabine PassTrinidad 56.00 56.10Total 161.70 100.80 109.70 156.90 156.50 116.20 270.90 106.80 50.40 53.20 166.44

Puerto RicoTrinidad 62.43 89.50 74.90 0.70 97.70 123.60 90.52 110.50 110.10 134.40 56.90

Trinidadian to US 100.80

April 2014


Argus Global LNG — Spark spreads

Note: Spark spreads compare the cost of generating power at various heating efficiencies with the cost of buying power from the grid. A positive spread indicates it is economical to buy fuel, while a negative spread indicates it is economical to buy power off the grid. Prices are taken from Argus oil, gas, coal and electricity daily market reports, the IEA, company sources and national statistical bodies.The model does not take account of local taxes or transport costs.

International spark spreads Mar

Region/fuel Price $ Fuel$/MWh

Electricity, industrial price

$/MWh

Spark spreads at varying conversion rates $/MWh

30pc 34pc 38pc 49.13pc 55pc

Asia-Pacific

Japan

LNG $/mn Btu 16.61 56.47 106.70 -81.36 -59.39 -41.92 -8.25 4.02

Coal, cif Japan $/t 90.65 12.99 106.70 63.44 68.49 72.51 80.26 83.08

HSFO 180, cif Japan $/t 615.33 51.40 106.70 -64.45 -44.46 -28.56 2.09 13.25

South Korea

LNG $/mn Btu 14.57 49.54 78.86 -86.10 -66.83 -51.51 -21.97 -11.21

Coal, cif Korea $/t 87.726 12.57 78.86 36.99 41.88 45.77 53.27 56.00

HSFO 180, fob Korea $/t 623.16 52.05 78.86 -94.47 -74.22 -58.12 -27.09 -15.78

Europe

Belgium

LNG $/mn Btu 10.43 35.46 62.15 -55.94 -42.15 -31.17 -10.03 -2.33

Zeebrugge Pipeline natural gas $/mn Btu 9.37 31.86 62.15 -43.94 -31.55 -21.69 -2.70 4.22

Coal $/t 75.253 10.78 62.15 26.24 30.43 33.77 40.20 42.54

Fuel oil 1pc fob NWE $/t 621.202 51.89 62.15 -110.64 -90.45 -74.40 -43.46 -32.19

France

LNG $/mn btu 12.48 42.43 58.30 -83.00 -66.49 -53.36 -28.06 -18.85

Pipeline natural gas, Russia $/mn Btu 12.90 43.86 58.30 -87.75 -70.69 -57.12 -30.97 -21.44

Coal $/t 75.25 10.78 58.30 22.39 26.59 29.92 36.35 38.70

Fuel oil 1pc fob w Med $/t 629.869 52.61 58.30 -116.89 -96.43 -80.15 -48.78 -37.35

Italy

LNG $/mn Btu 10.23 34.78 70.99 -44.83 -31.30 -20.54 0.19 7.75

Pipeline natural gas, Russia $/mn Btu 12.90 43.86 70.99 -75.06 -58.00 -44.43 -18.28 -8.76

Coal $/t 75.25 10.78 70.99 35.08 39.27 42.61 49.04 51.38


Spain

LNG $/mn Btu 10.23 34.90 40.26 -75.98 -62.40 -51.60 -30.79 -23.21

Pipeline natural gas, Algeria $/mn Btu 12.65 43.01 40.26 -102.97 -86.24 -72.93 -47.29 -37.95

Coal $/t 75.25 10.78 40.26 4.34 8.54 11.87 18.30 20.65


Americas

US Gulf coast

LNG $/mn Btu 6.75 23.03 48.37 -28.32 -19.36 -12.24 1.49 6.50

Natural gas, Henry Hub Nymex $/mn Btu 4.860 16.52 48.37 -6.65 -0.23 4.89 14.74 18.33

Coal Central Appalachia $/t 60.30 8.64 48.37 19.59 22.96 25.63 30.78 32.66

HSFO 3pc fob USGC $/t 576.44 48.15 48.37 -111.96 -93.23 -78.34 -49.63 -39.17

US Northeast

LNG $/mn btu 6.75 23.03 63.33 -13.36 -4.40 2.72 16.46 21.46

Natural gas, Transco Z6 NY $/mn Btu 7.879 26.79 63.33 -25.87 -15.45 -7.16 8.81 14.63

Coal Central Appalachia $/t 60.30 8.64 63.33 34.56 37.92 40.59 45.74 47.62

HSFO 3pc fob NYH $/t 589.34 49.23 63.33 -100.59 -81.44 -66.21 -36.86 -26.17

Conversion factors (left-hand column units are multiplied by the factor shown to convert to units in the top row)

Equals million British thermal units

barrels of oil equivalent

tonnes of oil equivalent

cubic feet (ft³) gas

cubic metres (m³) gas m³ LNG

tonnes LNG (specific gravity

0.425)

tonnes LNG (specific gravity

0.475)

1 million Btu (1mn Btu) 1 0.172 0.0235 1000 28.3 0.0459 0.0195 0.0218

1 barrel of oil equivalent (boe) 5.8 1 0.136 5800 164.2 0.266 0.113 0.126

1 tonne of oil equivalent (toe) 42.5 7.33 1 42.5 1200 1.95 0.828 0.925

1 ft³ gas 0.001 0.000172 0.0000235 1 0.0283 0.0000458 0.0000195 0.0000218

1 m³ gas 0.0353 0.0061 0.00083 35.3 1 0.00162 0.000688 0.000769

1 m³ LNG 21.8 3.76 0.513 21,824 618 1 0.425 0.475

1 tonne LNG (specific gravity 0.425) 51.3 8.85 1.207 51,350 1,450 2.353 1

1 tonne LNG (specific gravity 0.475) 45.9 7.91 1.081 45,950 1,300 2.105 1

April 2014



l Japan cut LNG imports from its regular suppliers in the Middle East in February, sending overall imports for the month to 7.5mn t, lower by 0.2pc on the year. Imports from Qatar fell by 21.8pc to 1.3mn t, while UAE supply dropped by 13.4pc to 417,166t. Japan took no cargoes from Yemen compared with 62,459t in February 2013. The declines out-stripped a 54.9pc rise in Omani supply to 384,921t.

l Japanese buyers reduced imports from Brunei and Russia by a respective 7.9pc to 419,346t and by 4pc to 687,586t. But Australian supply rose by 16.1pc to 1.4mn t, while imports from Malaysia and Indonesia increased by a respec-tive 9.3pc to 1.5mn t and by 15.4pc to 631,016t. Imports from Nigeria and Equatorial Guinea rose by a respective 4.8pc to 301,420t and by 40.7pc to 186,621t, while Algerian supply rose by 4.9pc to 63,181t. Japan took a respective 14,584t and 46,210t of reload cargoes from Spain and the Netherlands, after taking no cargoes in February 2013.

l LNG deliveries to Chinese state-run importers PetroChina and CNOOC totalled 1.5mn t in February, an increase of 6.1pc compared with the same month a year earlier. While February imports strengthened on the year, volumes were significantly lower than a month earlier. Imports in January reached a record 2.65mn t to meet peak winter demand.

l China’s imports were all sourced from term and portfolio suppliers, with cargoes originating from Australia, Indonesia, Malaysia, Qatar and Nigeria. The highest-priced imports were sourced from Qatar at an average $17.43/mn Btu on a delivered basis for 748,199t of LNG. Qatar accounted for the largest share of exports to China in February. Reliance on term contracted supplies kept China’s average import price at $11.67/mn Btu des, 12.7pc lower than in February 2013.

US imports mn t

Jan 13 Apr Jul Oct Jan 140.0

0.5

1.0

1.5

2.0

Total US imports

from Trinidad

US imports mn t

Brunei 5.58

Russia 9.15Oman 5.13

Australia 19.02Malaysia 19.43

Qatar 16.94

Nigeria 4.01

Indonesia 8.40

Eq Guinea 2.48

Netherlands 0.62

Norway 1.65

Abu Dhabi 5.55

Peru 0.99Algeria 0.84

Spain 0.19

Japan LNG import sources, Feb %

Japan reduces Middle East importsJapanese imports

Jan 13 Apr Jul Oct Jan 140.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6IndonesiaMalaysia

mn tJapanese imports mn t

’000tMalaysia 1,459.0Australia 1,428.7Qatar 1,272.6Russia 687.6Indonesia 631.0Brunei 419.3Abu Dhabi 417.2Oman 384.9Nigeria 301.4Eq Guinea 186.6Norway 123.9Peru 74.3Algeria 63.2Netherlands 46.2Spain 14.6Total 7,510.5

Latest estimated gas import and export

Australia -1,743.3

+ Imports - Exports

Indonesia -1,516.5

South Korea +4,322.3

Japan +7,510.5

Turkey 0.0

Qatar -6,156.1

from US (Alaska)

Nigeria -1,237.1

Libya 0.0

Brunei -419.3

Puerto Rico +110.1

Malaysia -2,111.0

US 0.0

’000 t

Abu Dhabi -417.2

UK +351.6

China +1,625.7

Oman -694.0

Egypt -67.3

Norway -218.6

Italy +121.4

Portugal +0.4

France +474.7/0.0

USCameronCove PointElba IslandEverettLake CharlesGolden PassGulf GatewayNortheast GatewayFreeportSabine PassNeptune DeepwaterTotal

0.00.0

+59.8+50.4

0.00.00.00.00.00.00.0

+110.2Yemen -666.2

Russia (Sakhalin) -944.0

Peru -229.1

Trinidad -293.0

Algeria -799.2

Eq Guinea -258.0

Greece +108.3

Canada +57.6

India +1,053.8

Taiwan +800.2Mexico 0.0

Brazil -54.6

Thailand +182.4

Angola 0.0

Belgium +185.3/-65.8

Spain +1,049.9/-74.1

Latest estimated gas imports and exports ’000 t/month

LNG movements

Global LNG · © ArgusMedia Ltd MONTHLY Global LNG LNG MARKETS, PROJECTS AND INFRASTRUCTURE VOLUME...

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