INDIA’S GAS INFRASTRUCTURE CHALLENGE

Insight and analysis for the global LNG industr y

Gas – and especially LNG imports – are central to Indian energy policy, but their future level and market share remain unclear, in large part due to uncertainty over how the country’s gas infrastructure will be built out. While the government is pushing its city gas programme hard, protracted delay is the norm rather than the exception, casting doubt on the rapidity with which Indian LNG demand can grow.

INDIA’S GAS INFRASTRUCTURE CHALLENGE

Feature:LNG and the methane emissions challenge

Country Focus:Argentina - Hanging in the balance

Project Spotlight:Mozambique LNG

Feature:Egypt ramps up its LNG exports

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Managing Director: Rick Gill [email protected]

Events/Advertising: Joao Salviano [email protected]

Editorial: Ross McCracken [email protected]

William Powell [email protected]

Design: Jeremy Seeman [email protected]

Editorial ................................................. 4Fuel cost competition

Events and Conferences ......... 31

LNG News .......................................................... 33Global LNG .................... 33 Supply ............................. 37Demand ......................... 43

In Transport ................. 49Corporate ..................... 53Shipping .......................... 57

COUNTRY FOCUS:Argentina - Hanging inthe balance

21PROJECT SPOTLIGHT:Mozambique LNG

25TECHNOLOGY:Korean Competition for GGT

28

INDEX

FEATURE:India's gasinfrastructure challenge

6FEATURE:Egypt ramps up its LNG exports

12FEATURE:LNG and the methane emissions challenge

17Project Spotlight:Mozambique LNG

L N G C O N D E N S E D | N AT U R A L G A S W O R L D . C O M 3






profi t margins. No longer; US LNG and reformed carbon pricing are putting European gas-fi red spark spreads back in the money just as nuclear plants are being phased out in countries like Germany and regulation limits the operation of older coal plant.

Low prices will also encourage new market entrants, such as Germany and Sri Lanka, as well as market broadening. Rapid adoption of LNG in transport needs a supportive regulatory framework to foster low carbon transportation, but also a solid economic case in terms of LNG versus diesel or fuel oil costs to encourage fl eet owners to take the plunge. With gas prices increasingly decoupled from oil and supply having overtaken immediate demand, gas’ share of the transportation market can be expected to rise more quickly.

How long this period of low pricing lasts depends heavily on one large and unpredictable factor: the weather. Q4 2018 and Q1 2019 spot LNG prices are substantially higher than those for summer delivery at around $6.8-8.0/mn Btu, a level which puts US LNG back into profi t. If the northern hemisphere winter is cold, returns should be good, but, if it proves moderate, LNG producers may face a prolonged period of production-cost sales as Asian and European storage inventories remain high into summer 2020 and more liquefaction capacity comes on-stream.

This would give project developers, and the utilities that provide those all-important supply and purchase agreements, pause for thought, potentially promoting a re-evaluation of the forecast supply tightness in the mid-2020s. This fear of a closing window of opportunity may be driving the current rush to fi nal investment decisions. The LNG industry appears doomed to boom and bust on the construction side because when the market looks good for one it looks good for all, and is equally fated on the demand side to suffer the vagaries of the weather. However, the bottom line is that while cheap LNG may hurt producers now, it will sustain long-term market expansion.

— NGW

S LNG fl ooding into Europe pushing spot LNG prices to multi-year lows close to $4/mn Btu demonstrates that regional gas markets have

become truly globalized. Competition between pipeline gas and LNG is intensifying as buyers put into operation all the contractual and operational fl exibility at their disposal to access the cheapest possible source of gas.

LNG is currently priced both in Europe and Asia-Pacifi c at the cost of delivered US LNG into these markets, leaving next to nothing on the table for the US exporters who continue to ramp up their liquefaction capacities.

Refl ecting the abundance of gas in the US, prices there have fallen, despite the increase in exports, both as LNG and by pipeline to Mexico. This will sustain the strong rise in natural gas demand in the country coming from the power sector, promoting accelerated coal-to-gas switching, and higher gas use in petrochemicals and refi ning among other sectors. It will also sustain, despite the current lack of profi t margin on LNG exports, the belief that the US will provide low-priced feedstock gas for the next generation of LNG plants targeting a forecast tighter LNG market in the mid-2020s.

The wave of cheap LNG is also having benefi cial effects for gas demand in Europe which spells good news for greenhouse gas emissions reductions. First, in a region plagued by gas supply insecurity, owing to its dependence on a few larger external pipeline suppliers and falling domestic production, it is clear demonstration of LNG’s ability to diversify countries’ import options. Large affordable volumes of gas can reach Europe from multiple production points around the world far beyond the reach of pipeline construction.

Second, the fall in gas prices is rejuvenating the prospects for gas-fi red power generation. This is being reinforced by the recent sharp rise in carbon prices under the EU Emissions Trading Scheme, which penalises carbon-heavy coal-fi red generation to the benefi t of gas. Gas-fi red power has always been seen as complementary to renewables because of its operational fl exibility, but has for many years suffered from low and often negative

FUEL COST COMPETITIONU

EDITORIAL

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MARTIN DANIEL

After graduating from Oxford, Martin Daniel worked in the Economics Unit of the British Coal Corporation and then the Supply, Transport and Markets team at IEA Coal Research. He later founded the publication Global Private Power and worked for FT Energy and then for S&P Global Platts as editor of Power in Asia and International Gas Report. He is currently a freelance energy consultant.

ROSS MCCR ACKEN

Ross McCracken was managing editor of S&P Global’s fl agship analytical newsletter Energy Economist for 13 years. He was formerly Platts crude oil manager EMEA. Ross has written extensively on oil, gas and power markets, with a particular interest in long-term energy forecasts, new technologies and China. He graduated with an MSc from the London School of Economics in 1993.

DR. NEIL ALEX ANDER FORD

Dr. Neil Alexander Ford is a freelance consultant, journalist and expert witness on African affairs, specialising in international relations, the energy sector and political risk. Most of his work focuses on Sub-Saharan Africa, but he also writes on other emerging markets.

Neil has a PhD in African international relations from the University of Edinburgh and 20 years of experience as a writer and analyst for magazines, newspapers and websites, including as associate editor of African Business magazine.

WILLIAM POWELL

William has been reporting and commenting on Europe’s gas markets for 20 years. He started in journalism at PH Energy Analysis (now ICIS Heren) in 1995, shortly before the UK devised the National Balancing Point -- Europe’s fi rst gas hub. His subsequent career has included senior management and editorial positions at FT Energy, Petroleum Economist, Argus Media and Platts, where he latterly edited International Gas Report. His focus has been on regional markets and how they function. William also speaks Russian and has had several literary/academic translations published.

CONTRIBUTORS


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ndia is steadily becoming more important in determining the future shape of the global energy market. Oil major BP

forecasts that Indian primary energy demand will balloon more than two and a half times, compared with 2017, to 1,928 million tonnes of oil equivalent in 2040, at which point India will account for 11% of global energy demand up from 6% now.

The BP Energy Outlook 2019 provides a succinct assessment of Indian energy and gas prospects. “India accounts for more than a quarter of net global primary energy demand growth between 2017-2040” it projects, adding that “gas production grows, but fails to keep pace with demand, implying signifi cant growth in gas imports.”

BP forecasts that Indian gas production will rise from 29bn m3 in 2017 to 74bn m3 in 2040. Gas use is projected to increase from 54bn m3 to 185bn m3

over the same period, implying that imports will rise four-fold from 25bn m3 to 111bn m3.

INDIA’S GAS INFRASTRUCTURE CHALLENGEMartin Daniel

IGas – and especially LNG imports – are central to Indian energy policy, but their future level and market share remain unclear, in large part due to uncertainty over how the country’s gas infrastructure will be built out. While the government is pushing its city gas programme hard, protracted delay is the norm rather than the exception, casting doubt on the rapidity with which Indian LNG demand can grow.


GAIL Existing Pipelines

GAIL Proposed Pipelines

RGTL East-West Pipelines

RGTL Proposed Pipelines

GSPL Existing Pipelines

GSPL Proposed Pipelines

PNGRB EOI Proposed Pipelines

PNGRB Future Proposed Pipelines

IOCL Existing Pipelines

Existing LNG Terminal

Proposed LNG Terminal

Mundra

Dahej

Hazira

Dabhol

Kochi

Ennore

Kakinada

Few analysts would regard BP’s forecast of Indian gas production as unduly pessimistic, given the travails of KG D6 and other fields. Gas production fell sharply in the first half of the 2010s and has been treading water since. Output in the financial year ending March 2019 was a third down on FY2011-12.

On the import front, India plans to bring in substantial amounts of piped gas from Turkmenistan, Iran and elsewhere. However, all the projects involve significant delivery and other risks, not least seemingly-intractable geopolitical problems. They are proceeding extremely slowly.

LNG ON THE FRONT FOOT

In contrast, LNG imports have been actively pursued. Six regasification terminals with nearly 40mn mt/yr of capacity in total are operational, two under construction and several others approved. It is planned that, by 2025, 11 terminals with 56.5mn mt/yr of capacity will be in use.

LNG imports could continue growing at a substantial rate thereafter, given the constraints

Operating Indian LNG terminalsOwner Capacity (mn

mt/yr)Capacity utilisation factor 2018-19, %

Dahej Petronet LNG 17.5 106.5*

Hazira Shell Enegry India 5 79.9

Dabhol RGPPL 1.7 24.4

Kochi Petronet LNG 5 9.3

Ennore IOC 5 n/a

Mundra Adani/Gujurat State Petroleum Co. 5 n/a

S O U R C E : P E T R O L E U M P L A N N I N G & A N A L Y S I S C E L L , M A Y 2 0 1 9

*Based on then capacity of 15mn mt/yr; 17.5mn mt/yr capacity achieved in June 2019

India’s Gas Pipeline Infrastructure


to 2030 – a target reiterated by Prime Minister Narendra Modi in December 2018.

There are several reasons for the scaling back of targets. India’s legal, regulatory and pricing framework remains unfavourable to gas developments. In particular, the mandated sale of much gas to generators and fertiliser plants at low prices -- in some cases below cost -- has deterred investment in supply, both domestic and imported.

Inadequate transmission infrastructure has also played a major role in stymieing the targets. In 2013, PNGRB saw the stock of operational gas pipelines rising from 13,000 km to 28,000 km over the following “5-6 years, putting in place most of the National Gas Grid that would connect all major demand and supply centre(s) in India.”

But, by May 2019, only 16,226 km of pipelines were operational, according to the government’s Petroleum Planning and Analysis Cell (PPAC). A further 11,216 km was approved or under construction. Operational lines are concentrated in the west, north and southeast of India.

Lack of fi nance has delayed many gas infrastructure projects, often refl ecting regulatory and pricing issues. Access to land and political or social opposition are also vexed problems. Projects can be delayed for years as cases grind through the courts, while intervening political changes can be equally problematic.

DELAYS THE NORM

Protracted delays are thus the norm rather than the exception. Petronet LNG’s 5mn mt/yr

facing domestic gas production and piped imports, and given India’s projected growth in energy demand.

LNG seems an obvious choice to meet much of the country’s additional energy demand. Output from renewables is forecast to surge, but from a low base, while questions hang over expectations that coal use will at least double, owing both to local and global environmental concerns, as well as technical and other constraints, such as land permitting.

Given these factors, it is perhaps surprising that future LNG imports are not forecast to be higher. The muted projections mean gas’ share of Indian primary energy rises relatively modestly, in the case of BP from 6% in 2017 to 8% in 2040, while the International Energy Agency sees gas’ share below 10% in 2040.

Government projections have been much higher. In 2013, India’s Petroleum and Natural Gas Regulatory Board (PNGRB) issued Vision 2030, which forecast LNG import capacity of 83mn mt/yr in 2029-30. At 113bn m3, this was already more than the import level projected for 2040 by BP.

MISSED TARGETS

But therein lies the rub. While India has prioritised gas use for years and mandated a growing market share for the fuel, successive government targets have been revised downwards.

In 2000, the India Hydrocarbon Vision-2025 projected that gas would account for 20% of total energy supply by 2025. The target for 2025 was subsequently pared to 15%. Then the date for achieving that reduced share was pushed back

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Indian LNG imports and gas production by fi nancial year (bn m3)

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2012-13 2013-14 2014-15 2015-16 2016-17 2017-18 2018-192011-12


terminal at Kochi was commissioned in 2013, but a 400-km pipeline from the facility remains to be completed. The terminal’s capacity utilisation factor was thus only 9.3% in FY2018-19, according to PPAC.

Ratnagiri Gas and Power Private Ltd’s 1.7mn mt/yr Dabhol terminal, also built in 2013, is equally hamstrung by infrastructure constraints. It operated at under a third of nameplate capacity in 2018-19 as it awaits construction of a breakwater to allow operation during the monsoon.

Also delayed is the pipeline to deliver gas from the latest LNG terminal to start up, Indian Oil’s 5mn mt/yr project at Ennore, which began commissioning in early 2019. It will supply 2mn mt/yr of gas to three nearby consumers, but a 1,240-km pipeline to deliver the remaining gas to further-flung consumers is unlikely to be completed for at least two years.

These factors largely explain why Indian LNG terminals are not operating at full capacity. In 2018, the four terminals then operational had 26.7mn mt/yr of nameplate capacity, but only 22mn mt/yr of LNG was imported. With Kochi and Dabhol operating well below capacity, the level of imports would have been lower still had Petronet LNG’s Dahej facility not operated at 106.5% of its then 15mn mt/yr capacity. The terminal’s capacity was raised to 17.5mn mt/yr in June 2019.

It could be argued that while the national gas transmission grid may have been delayed, most of its sections are now finished or under construction. Once the final trunk lines are completed, slotting in additional delivery points and building city gas distribution networks can proceed more quickly.

But that is not necessarily the case since distribution networks face the same issues – financial, regulatory, land access and so on – as transmission lines. This is a problem because city gas is seen as a key driver of future Indian gas demand. Grid power and fertiliser pricing means these markets remain problematic for gas, while its use in transportation, although still a priority, could decline as a result of the government’s policy to switch to electric vehicles from 2030.

CITY GAS PLANS

There is no question the government is pushing the city gas programme. PNGRB has now awarded licenses covering 402 districts hosting 70% of the population. Most recently, in March,

Indian piped gas domestic customers in April 2018 (mn)

Indian gas use by sector (bn m3)

S O U R C E : P E T R O L E U M P L A N N I N G & A N A L Y S I S C E L L

Gujarat1.84

Maharashtra1.21

TOTAL: 1.21

Delhi0.89

Uttar Pradesh0.1

Other0.23

Note: domestic only, excludes commercial (26,131) and industrial

(7,601) city gas customers

2017-182011-12

Fertiliser

Power Generation

City Gas Distribution

Refinery

Petrochemicals

Other

14.68

12.03

8.58

3.894.02

9.63

14

22.63

5.6

4.261.86

12.33

Total: 60.68

Total: 52.83


the cash flow necessary to make initial loan repayments while city gas networks are built out.

UNCERTAIN OUTLOOK

Given the importance of the city gas sector for future Indian gas use, the likelihood of infrastructure delays means gas use and LNG imports are likely to grow relatively modestly in line with BP’s and other recent projections.

Much stronger growth could only occur if gas-fired electricity generation is promoted. Well over half of India’s 24,867 MW of existing gas-fired plant is unused or under-utilised, with gas use in generation little more than half the 2011 level, although this may increase while spot LNG prices are low at around $4.5/mn Btu.

A sustained increase in Indian gas-for-power generation would require a shift to cost-reflective power pricing, probably together with significant carbon pricing to penalise coal use. If these conditions were met, gas use could soar within months compared with the years needed to build hundreds of city gas networks. However, market-based retail power prices remain a distant prospect.

it issued letters of intent for 124 districts under the tenth city gas distribution (CGD) tender. The licensees must install 20.3 million piped gas connections by March 2029.

The preceding round covered 174 districts with commitments to connect 22.1 million customers. But while there has been a marked uptick in licensing, PPAC data shows that in April 2018 operating city gas networks served only 4.3 million domestic consumers, mostly in Gujarat, Maharashtra and Delhi.

Completing the national grid is key to expanding city gas use, with construction of the eastern pipeline a key element in this process. But even with the grid in place, implementing all or even most of the city gas networks by 2029 is a tall order.

By 2029 city gas is likely to account for more than its 16% of current Indian gas sales. However, given the likelihood of delays in implementing many networks, it is uncertain how much gas CGD consumers will buy, meaning the location and number of new LNG terminals is also uncertain.

The key factor determining which LNG import projects are successful is likely to be the presence, as at Kochi and elsewhere, of big industrial gas users or captive power plants nearby to act as anchor customers. These will provide

Indian electricity generation by fuel in 2018

India’s installed generation capacity by fuel, May 2019

TWh % of total Coal 1176.3 75.4 Oil 10.1 0.1 Natural gas 74.3 4.8 Nuclear 39.1 2.5 Hydro 139.7 8.9 Other renewables 121.7 7.8 Total 1561.1 100

MW % of total Coal 200,075 56.1 Diesel 638 0.2 Natural gas 24,937 7 Nuclear 6,780 1.9 Hydro 45,399 12.7 Other renewable 78,359 21.9 Total 356,818 100

S O U R C E : B P S T A T I S T I C A L R E V I E W O F W O R L D E N E R G Y 2 0 1 9 S O U R C E : C E N T R A L E L E C T R I C I T Y A U T H O R I T Y

L N G C O N D E N S E D | N AT U R A L G A S W O R L D . C O M 1 0

2019 EDITION (13TH MAY 2019)

THE GLOBAL GAS MARKET BY CEDIGAZ

DOWNLOAD THE REPORT AND DATA

TOP-10 NATURAL GAS IMPORTERS (BCM)

CHINA JAPAN GERMANY ITALY SOUTH KOREA

MEXICO TURKEY FRANCE UNITED KINGDOM

SPAIN

TOP-10

CHINA

150150150

100100100

505050

000

NATURAL GAS IMPORTERS (BCM)

201820182018 201720172017

2018 HAS BEEN A REMARKABLE YEARFOR THE GLOBAL GAS MARKET

+4.7%Global Demand

+11.5%US production

+32%Chinese imports

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https://www.cedigaz.org/shop-with-selector/?type=publications&search=Global%20gas%20market

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RSPB

gypt was the world’s eighth biggest LNG exporter in 2009 with three trains on two separate projects. However,

population growth and energy subsidies fuelled domestic consumption over many years, while a relatively unattractive investment regime deterred exploration investment. As a result, gas production fell from 6.1bn ft3/d in 2009 to 4.3bn ft3/d in 2015, according to fi gures from the state owned Egyptian Natural Gas Holding Company (EGAS).

There were gas shortages in 2013 and 2014. Successive governments prioritised domestic needs over gas exports, with the result that LNG exports nosedived from 2014. One of the country’s two LNG schemes, Idku, exported just fi ve cargoes in 2014, down from 50 in 2013. The country began importing LNG via two fl oating storage and regasifi cation units (FSRUs) in 2014 and an import pipeline from Iraq was even suggested.

EGYPT RAMPS UP ITS LNG EXP ORTSNeil Ford

EThe Egyptian gas industry has come full circle over the past decade, swinging from signifi cant net gas exporter to importer and back again. The country has phased out its own LNG imports and is in the process of bringing its mothballed LNG export capacity back on stream. Given the huge fi nds that have been made in recent years and the potential for regional gas cooperation, new liquefaction trains could be developed in the longer term.


RAPID TURNAROUND

However, the situation has been turned around in a remarkably short time, principally because of a string of new discoveries which have been brought quickly on-stream, including the huge Zohr field. Discovered by Eni in 2016, Zohr is located 155km offshore on the Shorouk Block and is thought to be the biggest gas field in the Eastern Mediterranean with estimated reserves of 30 trillion ft3.

Eni and partners Rosneft and BP are in the process of investing $12bn in the field. Production reached 2bn ft3/d last September and the government expects output to reach 3bn ft3/d by the end of this year, slightly ahead of Eni’s original development plan. While the domestic market is likely to absorb much of the gas, Rosneft has said that it expects to export gas from the field.

In addition to Zohr, BP is increasing output on its North Alexandria West Nile Delta project from 400mn ft3/d to 700mn ft3/d over the course of this year. The third phase of the development,

the Raven field, will add more production also by year’s end.

BP has brought 1.5bn ft3/d of new production on stream since the start of 2015, while Eni began producing gas on the 883mn ft3/d Nooros project last January. Additional gas will come from the Atul and Salamat fields. Eni’s Nour prospect has also been widely heralded by the media, but the Italian firm is still appraising the size of the find.

Egyptian gas production averaged 6.5bn ft3/d last year, the highest level since 2012. The ministry of petroleum and mineral resources expects national output to reach 7.5bn ft3/d in 2020.

LNG EXPORTS RESUMED

The government was able to cancel an option for a third FSRU in December 2017 once it became clear that the planned imports would not all be needed. The number of import cargoes was much lower in 2017 and 2018 than expected and it appears that the final LNG cargo arrived in Egypt in September 2018.

E G Y P T

J O R D A N

S Y R I A

T U R K E Y

C Y P R U S

L E B A N O N

I S R A E L

Port Said

Arish

Taba Aqaba

Ashkelon

Damascus

Amman

Homs

Tripoli

Baniyas

West Nile Delta Field

Nooros FieldAtoll Field

Zohr Field

Idku LNGplant

DiamettaLNG plant

East Mediterranean Gas Infrastructure


DOMESTIC CONSUMPTION

Efforts to maximise exports will rest on how fast domestic gas demand increases, how much new gas is discovered and how quickly new fi nds are brought on stream.

Domestic demand should be constrained by rising prices. Egypt’s economic diffi culties forced Cairo to turn to the International Monetary Fund for help in November 2016 and the Fund agreed a $12bn loan to be paid in tranches in return for a succession of economic reforms.

The money has now all been sanctioned and the enacted reforms have included cuts to energy subsidies. However, while upstream gas prices have now been partly deregulated, the price paid for gas used in power generation remains regulated at a low level.

The power sector accounts for about 65% of total domestic gas consumption, and the price mechanism remains a disincentive to gas producers. The government has promised to create a commercial gas market without any subsidies, but for the moment EGAS’ retains an automatic allocation of a proportion of national gas production at sub-commercial rates.

Moreover, the world’s three biggest combined cycle gas fi red plants – Beni Suef, New Capital and Burullus – were completed by Siemens last July for the Egyptian Electricity

Petroleum and mineral resources minister Tarek El Molla said the FSRU at the port of Sokhna will remain in place, but only for “strategic” reasons. This will allow the country to import gas during the period of peak consumption in the summer, if required.

Higher domestic production has also allowed LNG production to resume at the Idku plant, with the number of export cargoes rising from three a month at the start of the year to six in June. Idku exported 800mn ft3/d in February, twice as much as it exported in the whole of last year. This is the equivalent of 6mn mt/yr, not far off the plant’s 7.2mn mt/yr nameplate capacity.

Idku, which is located about 50km east of Alexandria, is owned by the Egyptian LNG (ELNG) consortium of Shell, Petronas, Engie, Egyptian General Petroleum Corporation (EGPC) and EGAS.

The government has announced the imminent resumption of production at the country’s second LNG plant several times this year, but it appears that ongoing legal disputes between the operating company and the government, relating to the failure to supply suffi cient gas feedstock over the past few years, have still not been resolved.

SEGAS, which operates the Damietta facility, is 40% owned by Eni, 40% by Union Fenosa of Spain, 10% by EGAS and 10% by EGPC. It is located 60km west of Port Said and has production capacity of 5mn mt/yr.

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Egypt eradicates its gas defi cit (bn m3)

Production Consumption


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El Molla has also said that the country will cooperate with Saudi Arabia on exploring for oil and gas in the Red Sea, after Riyadh announced gas fi nds there in March.

FUTURE GAS HUB

Government offi cials and the World Bank have talked about turning Egypt into an international gas hub, with the country importing and exporting large volumes of gas, perhaps backed up with substantial gas storage capacity. This vision should be strengthened by the government’s decision to end its monopoly on gas imports and distribution last year. The keys to Egypt’s gas hub ambitions are further market deregulation and cooperation with other countries in the region.

Despite the big jump in domestic production, Egypt is to continue importing gas, but via pipeline rather than in the form of LNG. Under an agreement signed in February 2018, Noble Energy and Delek are to pipe gas from Israel’s Leviathan and Tamar fi elds to Egypt over ten years via the East Mediterranean Gas (EMG) pipeline, which connects Ashkelon in Israel to El Arish in Egypt. The 90km line is owned by Noble, Delek and Egyptian fi rm Sphinx; tests are already underway, with commercial supplies due to start later this year.

Holding Company and have combined generating capacity of 14.4 GW. In addition, Cairo has set a target of increasing the number of residential gas customers from 4mn in 2017 to 10mn by 2025.

The ministry of electricity and energy expects power demand to grow at more than 6% a year for the foreseeable future, although the government intends to lift all power subsidies by 2022. In addition, planned new construction projects and the government’s plans for agricultural expansion suggest that gas demand from cement and fertiliser plants will increase.

Power trading with Saudi Arabia could also affect Egypt’s ability – positively or negatively – to export LNG, as the two governments hope to oversee construction of a cross-border interconnector with up to 3 GW of capacity.

On the production side, Zohr and the other recent fi nds have generated interest in securing new Egyptian acreage and the ministry of petroleum is regarded as being more fl exible now in the deals it strikes with upstream investors. BP, Eni, ExxonMobil and Shell were all awarded blocks in February. More blocks were offered in the Red Sea in March, while eleven blocks are expected to be included in a licensing round covering the western part of Egypt’s Mediterranean territory in late 2019 or early 2020.

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Egyptian LNG demand drops (bn m3)

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Delek to pipe gas from Aphrodite to the Idku plant in Egypt. The government had wanted an LNG plant to be built at Vasilikos on Cyprus.

POTENTIAL NEW LNG CAPACITY

While the turnaround in Egypt’s gas fortunes should ensure that the country’s existing LNG production capacity comes fully back on stream, it seems less likely that any new LNG trains will be developed in Egypt in the short term. The International Energy Agency expects Cairo to continue favouring domestic gas needs over exports. In addition, it has become a lot more expensive to import components since the Egyptian pound lost a lot of its value after it was allowed to fl oat freely from November 2016.

However, investment conditions are improving. Cairo is close to clearing its long standing debts to international oil and gas companies, so confi dence in the government may be higher than for several years. A combination of regional cooperation and further substantial discoveries could see new trains built in the longer term. The Idku plant was developed with six trains in mind, so there is plenty of scope for expansion, but investors here and on any other project are likely to want guarantees from the government that feedstock supplies will be sustained for at least 20 years.

The way for Israeli imports was paved by Cairo’s agreement in mid-June to pay $500mn to Israel Electric Corporation for breaking a contract to supply Egyptian gas in 2012. The payment is a big reduction on the fi ne of $1.7bn that was imposed by the International Chamber of Commerce in 2015 and the money will be paid over eight and a half years. The EMG was repeatedly bombed by Islamist militants in Egypt and supplies were halted entirely in 2012 at a time when Egypt was experiencing its own gas shortages.

Noble says that it expects to export at least 350mn ft3/d through the line, under its contract to supply 689bn ft3 to Dolphinus Holdings in Egypt over ten years. Some of this gas may be used to produce LNG, which could be exported to states that would not accept Israeli gas.

At the very least, it will be used to satisfy domestic demand and free up Egyptian production capacity that can be used to supply the country’s two LNG plants.

Despite continued political diffi culties, there could be further cooperation between Egypt, Israel and also Cyprus in developing the spate of discoveries that have been made in the Eastern Mediterranean. In May, the Cypriot government agreed to take a smaller share of the revenues from the development of its undeveloped Aphrodite fi eld to allow Noble Energy, Shell and

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ecent studies on LNG use in transport have questioned the contribution LNG can make to lowering greenhouse gas

emissions (GHG). These studies highlighted, amongst other issues, emissions of unburned methane, which although relatively short-lived in the atmosphere, are just over 30 times more potent as a GHG than carbon dioxide (CO2).

Last year a report, Assessment of methane emissions from the US oil and gas supply chain, published in the journal Science, concluded that methane emissions from the US oil and natural gas supply chain were about 60% higher than those estimated by the US Environmental Protection Agency’s Greenhouse Gas Inventory. The large-scale study, which covered about 30% of US gas production, used ground-based measurements validated by aircraft observations.

The study argued that the difference in measurement arose from better observation of equipment operating in abnormal conditions, with emissions from liquid storage hatches and vents playing a particularly signifi cant role. One of its key conclusions was that signifi cant emissions reductions can be achieved by deploying improved emissions detection and repair

LNG AND THE METHANE EMISSIONS CHALLENGERoss McCracken

The LNG industry needs to up its game on both CO2 and methane emissions, if it is to gain social acceptance that LNG is part of the climate change solution as opposed to part of the problem. Recent studies suggest methane emissions from oil and gas operations are under-reported and that full life-cycle analysis in some cases shows limited greenhouse gas benefi ts from LNG use. Oil and gas companies are beginning to adopt emissions reductions targets, but have barely scratched the surface of what is possible.

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systems that rapidly identify equipment operating abnormally.

The study found that 20% of oil and natural gas supply chain methane emissions came from gas gathering and a further 20% from processing, transmission and storage. It said, “methane emissions of this magnitude, per unit of natural gas consumed, produce radiative forcing over a 20-year time horizon comparable to the CO2 from natural gas combustion.”

The findings have global indications because if methane emissions from the full LNG production chain are heavily under-reported – as the study suggests – then arguments put forward for example by the Australian Petroleum Production and Exploration Association, that “for every tonne of carbon dioxide equivalent emitted in LNG

production within Australia, between 5.5 and 9.5 tonnes of emissions from the coal alternative can be avoided globally,” become somewhat questionable.

Environmental non-governmental organisations in Australia increasingly blame the country’s poor performance on GHG emissions reductions on the rapid growth of its LNG industry.

The study also notes that methane leaks, like gas flaring, are in nobody’s interest. They represent a waste of a valuable resource which could otherwise be monetised. However, in the absence of any safety concerns, a gas producer or gatherer will tend to look at LDAR (leak detection and repair) on an economic basis, i.e. whether the value of the saved gas is worth the cost of detection and repair.

That narrow but rational calculation in a business sense is changing as a result of studies like the one published in Science. Greater visibility of life-cycle emissions, not just CO2, will bring greater public and regulatory scrutiny. Gas producers are under pressure to demonstrate the validity of their environmental claims in order to support LNG’s social acceptance as part of the solution to climate change

“ Gas producers are under pressure to demonstrate the validity of their environmental claims.”

Liquefaction

• Fuel

• Fugitives

Storage and Transport

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• Fugitives

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• Pneumatic controllers

• Liquids removal

• Dehydration

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• Liquid storage tanks

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• Pneumatic Controllers

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Distribution

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Emission points from the gas/LNG supply chain


into the Dupuy Formation under Barrow Island via nine injection wells at three drill centres.

However, to date the project has still not come on line. Chevron last year said it would be up and running in March 2019, but a subsequent announcement in March said it would take another nine months, owing to technical difficulties identified during commissioning.

LIQUEFACTION POWER

A second project keen to highlight its environmental profile is LNG Canada, which targets a different area of GHG emissions. The plant will be powered by a combination of gas-fired turbines and electricity generated by BC Hydro, with the use of renewable electricity reducing the plant’s carbon footprint.

The plant will be located at Kitimat at the head of the Douglas Channel about 650 km northwest of Vancouver. Each of the two trains will have capacity of at least 6.5mn mt/year, with an option to expand to four trains in a second phase. Construction of the first two trains is expected to take about five years, bringing the plant online in 2023/24.

Liquefaction requires powerful compressors which need lots of energy. This is usually provided by gas turbines, either heavy-duty gas turbines or more efficient aero-derivative turbines, making use of the natural availability of gas at an LNG plant and providing a reliable source of electricity generation on site.

However, some plants employ electric drive, which requires less energy per ton of LNG. Electricity has to be sourced from the grid, which is not always an option for remote LNG projects. The carbon profile of the liquefaction process reflects that of the grid electricity. In the case of LNG Canada this will be hydro power.

While LNG Canada and Chevron’s Gorgon CCS projects are laudable in their intentions, neither are world firsts, although Gorgon CCS will be the largest of its kind. Carbon has been sequestered from CO2 heavy gas streams at the Sleipner gas field in Norway since 1996 and from BP’s In Salah project in Algeria between 2004 and 2011.

In addition, Equinor’s Snohvit LNG plant on Melkoya island near Hammerfest stores up to 0.7mn mt/yr of CO2 from its liquefaction operations and employs electric drive, powered by an electricity system dominated by Norway’s abundant hydro power resources.

CLOUDY DEBATE

Warnings that methane emissions from the LNG supply chain could undermine the environmental case for gas are not new, but it seems to remain a blind spot for the industry, which has moved only slowly to address them.

In July 2017, a report by the Oxford Institute for Energy Studies, Methane Emissions: from blind spot to spotlight, found that most data and studies supported the view that “the increase in global atmospheric methane in the last ten years was not a result of the increase in global gas production over this period.”

However, it argued a “lack of consistent and transparent data and a failure from industry players to articulate a coherent message on methane emissions has resulted in a data vacuum that has been filled by less rigorous, and in some cases self-serving, alternative conclusions.”

“ To date the project – Gorgon CCS – has still not come on line.”

CCS DELAY

Improvements in LDAR are only one area in which LNG’s emissions profile can be improved. Two current projects have adopted different strategies for promoting low carbon production.

The first is Chevron’s Carbon Capture and Storage (CCS) project at the Gorgon LNG facility in Australia. Substantial delays to this project have resulted in criticism by environmental groups that the CCS component of the project has not been prioritised.

Gorgon is a three-train plant with capacity of 15.6mn mt/yr, which came on-stream in 2016 and 2017. Part of the development deal with the Western Australian provincial government was that it would limit the project’s emissions by 40% by capturing and storing underground up to 4mn mt/yr of CO2. The project is billed as the world’s largest commercial-scale CO2 injection project.

Gas for Gorgon comes from the Gorgon and Jansz-lo gas fields. Gorgon field gas contains 14% CO2, which has to be removed before liquefaction. Rather than vent the CO2, the aim is to inject it


maintaining this target. The company in April reported a 1.7mn mt reduction in CO2 emissions in the previous 12 months, alongside 3% growth in upstream oil and gas production. At the same time, the company announced $100mn in new funding to support new upstream projects delivering additional GHG emission reductions.

The adoption of carbon targets is an important step in putting environmental objectives at the heart of business strategy, but there remains a signifi cant gap between stated ambitions and project implementation on the ground. Given the greater scrutiny which methane emissions are attracting, LNG producers need to adopt emissions abatement plans which address the full supply chain rather than piecemeal showcase projects. If delivered late, these projects will inevitably attract criticism that commitment to them is less than whole-hearted.

Given this experience, a future plant in the 2020s with partially renewable electricity supply and a heavily delayed CCS project do not add up to much.

CARBON OFFSETS

A further option in addressing oil and gas emissions is offsets. Oil and gas majors Shell and Eni have both adopted emission reductions targets and carbon offsets will play a key role in meeting them.

Shell has a three-year program to reduce its net carbon footprint by 2-3%, which includes plans to plant more than 5mn trees in the Netherlands over 12 years and around 300,000 trees in Spain’s Castilla y Leon region this year, in addition to sponsoring ecosystem regeneration projects in Australian and Malaysia.

Eni announced in March a net zero carbon emissions target by 2030, which also involves carbon offsets. Plans include growing its renewable power capacity from 0.2 GW to 10 GW by 2030 and 81,000 km2 of new forest spread across a number of projects in Africa. The net zero target applies to the company’s operations rather than from the end-use emissions of the oil and gas it sells. It includes a target to reduce methane emissions by 80%.

BP has specifi cally adopted a methane intensity target of 0.2% between 2018-2025, which it already met in 2018. The aim appears to be to grow oil and gas production while

“A future plant in the 2020s with partially renewable electricity supply and a heavily delayed CCS project do not add up to much.”


here is no question that Argentina reached a milestone in June as Exmar’s Tango LNG came into

operation for state oil and gas company YPF. Operating in the deep water port of Bahia Blanca, it is the first floating LNG plant in the Americas and still one of only a handful around the world. It marks Argentina’s transition from LNG importer to LNG exporter. However, in practice, Argentina will, for the moment, be both LNG importer and exporter.

Tango LNG’s capacity is small at 0.5mn mt/yr and Argentina’s gas demand spikes during the southern hemisphere winter, when, despite rising domestic gas production, it will still look for LNG imports. Nonetheless, the downward trend in the country’s LNG requirements is clear. As its domestic gas balance has improved, Argentina’s LNG imports have fallen, reaching a peak at 4.6mn tons in 2013, but declining steadily each year since, reaching just 2.7mn mt in 2018.

COUNTRY FOCUS:

ARGENTINA – HANGINGIN THE BALANCE

Argentina’s future role in the world LNG market is highly uncertain. In one scenario, in which domestic shale gas development proceeds as planned, it could be exporting 32mn mt/yr of LNG by 2030. In another, adverse investment conditions would imperil the development of the country’s shale gas resources and the infrastructure required to get them to market, leaving not just Argentina but also Chile with a gas defi cit to be fi lled by LNG imports and growing renewables generation.

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SHALE GAS

The cause of this transition is shale gas. Argentina sits on some of the largest shale oil and gas resources in the world. The most promising field, the giant Vaca Muerta in Neuquen province, has and is receiving serious investment attention from major oil and gas companies.

Vaca Muerta is regularly compared with the prolific US Eagle Ford and is three times the size of the US Permian basin. According to Rystad Energy, YPF in the El Orejano area, TecPetrol in Forting De Piedra and BP and Total in Aguada Pichana are all achieving gas well productivity at a similar level to the US Utica, Haynesville and Marcellus shale basins. Moreover, decline rates are reported to be ‘shallow’ – i.e. the gas wells produce more for longer than many US shale plays.

According to the US Energy Information Administration, Argentina boasts 801.5 trillion ft3 (22.7 trillion m3) of technically recoverable wet shale gas and 27bn barrels of tight oil. In terms of wet shale gas resources, it outstrips the US (622.5 trillion ft3) and comes second only to China (1,115.2 trillion ft3). Following an exploratory period, companies like YPF, Chevron, ExxonMobil, Shell, Total and BP started to move towards full production mode on Vaca Muerta

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last year. Argentina appears to be the only country in the world on a path to replicating the US shale experience.

However, it is by no means all plain sailing. It is taking time to build the infrastructure and supply-side services required for a competitive and dynamic shale gas sector. While the rampup in shale gas production is promising, it has hit major constraints.

Supply-side services, for example hydraulic pumping capacity and fracking sand and proppant provision, are insuffi cient to support a fast rate of expansion. In addition, there is only a limited ability to export gas from the Neuquen basin. YPF announced in May that it would limit new natural gas investment as a result of local production oversupply. Consultants Wood Mackenzie say that a planned 1,000-km pipeline from Neuquen to San Nicolas will be needed by 2022, in addition to increased export capacity to Chile and Brazil, in order to support higher shale gas production.

The development of LNG plants is an obvious way to create additional demand and the government has announced plans for its fi rst large LNG export plant, also, as with Tango LNG, likely to be sited at Bahia Blanca. Offi cials hope preparatory work will begin on the plant this year, but no fi nal investment decision

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and Chile – while the suspension of pipeline exports to Brazil contributed to the development of a third.

The situation changed with the election of Mauricio Macri as president in 2015. Macri has gradually rolled back and reversed the incentive structures which saw runaway consumption and falling investment in production. He has removed capital controls and improved the operating environment for investors in co-operation with the Neuquen regional government.

Subsidies for end-users have been reduced and, in 2017, the ministry of energy introduced price incentives for shale and tight gas production. Regulations have been enacted allowing the free export of gas to Chile and for thermal power plants to buy their gas from producers rather than from electricity system operator Cammesa. In February this year, auctions for gas contracts between producers and distributors were held. In sum, Macri has sought to reintroduce market pricing for gas.

ELECTION UNCERTAINTY

These reforms narrowed the annual gas defi cit in 2018 to 9.28bn m3 from a peak of 11.67bn m3

in 2014, but whether they stay in place hinges on the October elections. Macri’s re-election prospects currently look dim. He was forced to call in the IMF last year to stabilise the country’s fi nances. The economy is in the second year of recession and this has hit Macri hard in the opinion polls. According to World Bank data, Argentina’s economy contracted by 2.8% in 2018 and will decline a further 1.7% this year before returning to growth in 2020.

Opinion polls in May put presidential hopeful Alberto Fernandez 10 points ahead of Macri. Fernandez’ running mate is Cristina Fernandez de Kirchner, who was president from 2007-2015, and who, along with family and former associates, faces a number of court cases, which may dent her current popularity. The prospect of a Fernandez-Kirchner victory brings with it the risk of the reintroduction of popular subsidies for gas consumption, capital controls, and a deterioration of relations with the IMF. It could impact investment in Vaca Muerta production capacity, the pipelines necessary to evacuate the gas and LNG export plants. As a result, Argentina’s future as an LNG importer or exporter hangs delicately in the political bala nce.

is likely until after the October presidential elections. Capacity is estimated at an initial 40mn mt/yr, comprising six trains, with the aim, somewhat optimistically, being to start operations in 2023. Gas would be supplied via a dedicated pipeline, ensuring secure fl ows even during winter.

Average demand for gas in Argentina was 140mn m3/d in 2018, while gas production was about 132mn m3/d. The energy ministry forecasts that gas output will rise to 400mn m3/d by 2030, allowing for 180mn m3/d of exports, with one-third dedicated to exports to Chile and Brazil and the remainder – the equivalent of about 32mn mt/yr – exported as LNG.

POLITICAL THREAT

The development of Argentina’s gas industry has been bumpy to say the least and heavily influenced by long periods of political populism, which saw consumption heavily subsidised to the detriment of returns on production. From a surplus of gas which allowed exports by pipeline to neighbouring countries between 1998-2007, Argentina moved into deficit in 2008. To meet its own demand, it became a gas importer first of pipeline gas from Bolivia and then LNG. The end of gas exports to Chile meant Argentina’s gas sector mismanagement created two new LNG markets – Argentina

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t has taken almost 12 years to get to the FID from the start of the company’s exploration contract in December 2007.

Two years later, in 2009, the fi rst drillship arrived and a string of major gas discoveries followed. Offshore Area 1, which will feed the planned LNG plant, contains an estimated 75 trillion ft3 of recoverable reserves.

Some of Area 1’s reserves straddle Offshore Area 4, which is operated by Italy’s Eni, but the two-train, 12.88mn mt/yr Mozambique LNG project is centred on the Golfi nho/Atum fi elds located entirely within offshore Area 1.

US company Anadarko announced June 18, as fl agged earlier in the year, a positive fi nal investment decision (FID) for its Mozambique LNG project. It will be Mozambique’s and east Africa’s fi rst onshore LNG plant.

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The project is backed by 11.1mn mt/yr of long-term LNG sales with buyers in Asia and Europe, and will also provide gas for domestic use. Agreeing sale and purchase agreements (SPAs) has taken time and flexibility, but their arrangement is crucial to raising project finance. The total project cost is estimated at $20bn, two-thirds of which will be project financed.

The SPAs have durations ranging from 13-20 years and volumes of between 0.28mn mt/yr to

2.6mn mt/yr. The cargoes have been priced on an ex-ship DES basis, which means the project consortium is responsible for shipping.

Anadarko holds a 26.5% working interest in Area 1. Co-venturers include state company ENH Rovuma (15%), Japan’s Mitsui (20%), India’s ONGC (10%), Beas Rovuma Energy Mozambique Limited (10%), India’s BPRL (10%), and Thailand’s PTTEP (8.5%)

However, even as Anadarko embarks on what is a major international project for the

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and requirements of development include local content commitments and development of the local economy and training for local employment.

However, there are other challenges. Mozambique was hit by Cyclone Kenneth in April, causing huge devastation as high winds and torrential rain led to flooding. The storm followed Cyclone Idai in March, which led to an estimated 1,000 deaths and millions of displaced people. The storms did the worst damage to the south of the country.

Mozambique LNG is situated in an area in the north on the Tanzanian border where insurgency is reported to have resulted in the deaths of over 100 people and destroyed hundreds of homes. Islamist militants launched an insurgency campaign in the country late in 2017. The militants have mainly concentrated on civilian and government targets, but in February four people were injured in an attack on a convoy working on Mozambique LNG on the road from Mocimboa da Praia to Afungi. The convey was reported to have been attacked by 15 unidentified gunmen.

Meanwhile, a report by consultancy AKap Energy, “Economic Analysis of Mozambique’s LNG projects”, published in April, said that ENH may struggle to meet its debt and equity obligations. The report calculated that ENH’s total required investment in the country’s LNG projects is around half of Mozambique’s current GDP, with possible further funding required for other blocks and developing domestic gas.

This means the Mozambique government will have to borrow, but it is currently in talks to restructure over $2bn of loans, which were defaulted on in 2016 amid a corruption scandal that still rumbles on. Some of the government’s future gas revenues have already been allocated to the restructuring of a $727mn eurobond loan, according to an agreement in principal made in November last year.

That said, the size of Mozambique LNG alone could prove transformational for Mozambique’s state finances and the government has been successful in agreeing local development plans with the various consortia. The country’s location on the east coast of Africa also makes it well suited to supply LNG to Asia, which is expected to be the primary source of new LNG demand over the coming decades.

company, it looks likely to end up in the growing LNG portfolio of French company Total. US independent Occidental is buying Anadarko, but will sell the company’s sub-Saharan Africa upstream assets to Total in a deal worth $8.8bn. The transaction, which is contingent upon Occidental completing its acquisition of Anadarko, is expected to close in 2020.

The engineering, procurement and construction contract has been awarded to a joint venture comprising Italy’s Saipem, US company McDermott International and Japan’s Chiyoda Corp. Saipem takes the lion’s share of the contract, with $6bn, while McDermott will initially book $2bn. Chiyoda will provide advisory services. Saipem will lead the joint-venture, known as CCS JV.

FURTHER GROWTH

Mozambique LNG will be the second of three LNG projects designed to monetise the country’s huge offshore gas reserves.

The first is a floating LNG project called Coral LNG, which will have capacity of 3.4mn mt/yr. This is being developed by Eni to operate in Offshore Area 4. Construction started earlier this year and the vessel is expected to be complete by the end of 2021, going into production in 2022. An agreement was reached in 2016 for BP to take all of the output over 20 years and its offshore location meant it could race ahead of the onshore projects.

The third project is onshore and being developed by ExxonMobil and Eni. This will also be a two-train facility, but with capacity of 15mn mt/yr, fed with gas from the Mamba complex, which contains fields overlapping Offshore Areas 1 and 4. ExxonMobil and Eni are expected to take all of the output from the project into their own portfolios, with start-up targeted for 2024. A final investment decision is expected later this year. The government approved the project’s development plan in May.

COUNTRY RISK

The announcement of FID on Mozambique LNG indicates the companies involved are prepared to take on the challenges of opening up Mozambique to LNG development. The country lacks the supply-side resources for such a large project, although part of the remit


t present, the big three Korean shipyards – Daewoo Shipbuilding & Marine Engineering (DSME), Hyundai

Heavy Industries and Samsung Heavy Industries (SHI) – have to pay GTT royalties on each vessel that uses the French company’s technology. However, DSME’s Solidus technology is now the third Korean LNG containment system to be developed, following Samsung Heavy Industries’ KCS and Kogas’ KC-1

Kogas developed the KC-1 membrane tank system in cooperation with SHI, Hyundai Heavy Industries and DSME. The system uses 1.5mm stainless steel plates in both the primary and secondary barriers, which are corrugated to cope with thermal expansion and contraction. The two layers are backed by panels of polyurethane foam, with inter-barrier spacers used to prevent any damage to the primary barrier affecting the secondary barrier. KC-1 was fi rst used on the 174,000 cu m SK Serenity and SK Spica, which were completed for SK Shipping in the fi rst quarter of 2018.

French fi rm GTT has long provided most of the containment systems used in LNG vessels, but now faces new competition from South Korea. The main rivals to GTT’s membrane technology have traditionally been the self-supporting tanks produced by its Norwegian and Japanese rivals that are structurally independent of the vessel hull. However, South Korean shipyards have now developed their own containment systems and are starting to use them for the fi rst time.

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year for a decade, with its containment systems ordered for 50 new vessels.

Over the past decade, GTT has reduced the boil-off rate (BOR) from 0.15% of volume per day to 0.07% in its new Mark III Flex+. The reduced BOR has been achieved through increased insulation thickness and the lower fuel requirements of more effi cient propulsion systems. This contrasts with a rate of 0.12% of the cargo volume per day on Kogas’ KC-1 system.

GTT has adapted the insulation provided on its two systems: Mark III and NO96. The insulation on the Mark III Flex+ is now 480mm thick, while a layer for rigid triplex has been added to the secondary barrier to increase strength. The NO96GW uses glass wool in the boxes backing the two metallic barriers, while in the LO3 version of the NO96 a box insulated with glass wool is attached to a plywood and polyurethane foam panel.

GTT technical director Karim Chapot said: “The thermal performance of LNG cargo containment systems is one of the chief concerns in the LNG sector. It has a direct impact on transport costs and CO2 emissions. Technological advances have made it possible to continuously improve this performance over recent years, halving LNG emissions in the space of a decade.”

In mid-June, classifi cation society DNV GL approved DSME’s own Solidus LNG containment system for use. The insulation material used in Solidus, which is surrounded by metallic layers on both sides, has been developed by DSME and BASF of Germany to reduce LNG boil-off rates. It has also been approved by Lloyd’s Register. Securing general approval for ship application (GASA) encourages carrier owners to adopt particular technologies.

DSME chief executive and president Sung-Geun Lee said: “The Solidus design improves the new-building productivity and signifi cantly reduces costs, making it a big step forward in developing the LNG carrier industry for shipbuilders and suppliers.”

GTT LOWERS BOR

Despite the emerging Korean competition, French engineering fi rm GTT’s membrane technology is used on about three-quarters of the 520 conventional LNG carriers currently in use and it seems to be maintaining market share, in part because it has improved the thermal performance of its cargo containment systems to cut carbon emissions and transport costs. The company says that 2018 was its best

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for Saga LNG Shipping of Singapore, has 45,000 cu m capacity.

Saga Dawn’s gas trials were completed over the first half of June, testing the gas combustion unit, cargo handling equipment and the Wärtsilä dual fuel main and auxiliary engines. All three cargo tanks completed global tightness testing to confirm the integrity of the secondary barrier system. The CEO of Saga LNG Shipping, David Wu, said that his company would order further similar vessels “in the near future to meet evolving market demands”. Saga LNG Shipping says that the self supporting prismatic tanks make better use of the hull space and are simpler to construct.

It will be interesting to see which containment systems are chosen for new fl eets, particularly as the size of LNG carriers is increasing. A string of new orders are expected in the near future, including from Qatar Petroleum to service its North Field expansion and from Anadarko Petroleum, which is expected to order 15 new vessels in the second half of this year for its Mozambique LNG project. A similar number of vessels will be required by ExxonMobil and Eni if, as expected, they also take the fi nal investment decision on their LNG scheme in Mozambique this year.

The Mark III Flex+ system is being used on two big carriers currently under construction by Samsung Heavy Industries for Gaslog, each with 180,000 cu m capacity. The solution obtained general approval from several classifi cation societies, including DNV GL and Lloyds Register, in the second half of 2017.

GTT’s NO96 Flex cargo containment system, which was approved by class society Bureau Veritas last September, offers the same 0.07% BOR. Insulating polyurethane foam panels are attached to the inner hull, while the primary membrane is now corrugated stainless steel. Work will start on building a prototype of the NO96 Flex system next year.

NEW DESIGN FROM LNT

Singapore-based LNT Marine has developed an A-Box design that uses an International Maritime Organisation independent type A tank as the main barrier, plus a conventional cargo tank support system and liquid-tight thermal insulation as a full secondary barrier to make maximum use of the hull space. The fi rst vessel incorporating the technology , the Saga Dawn, was launched at China Merchants Heavy Industry’s Jiangsu shipyard in March, making it the fi rst LNG carrier to be built at the yard. The vessel, which was built PH

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LNG Western AfricaJuly 8-9Accra, Ghanaszwgroup.com/lng-western-africa- conference-2019

LNG & Natural Gas Markets AsiaAugust 29-30Singaporespglobal.com/platts/en/events/apac/ lng-natural-gas/summary

World Energy CongressSeptember 9-12Abu Dhabi, United Arab Emirateswec24.org

South America Energy WeekSeptember 10-11Buenos Aires, Argentinaenergycouncil.com/event-events/ south-america-assembly-southern-edition/

6th London Gas & LNG Forum 2019September 11-12London, UKenergystreamcmg.com/forums/forums- seminars/6th-london-gas-lng-forum-2019

Gastech Exhibiton & Conference 2019September 17-19Houston, USAgastechevent.com

CWC World LNG & Gas Series Morocco SummitOctober 2-3Marrakesh, Moroccocwcmoroccogas.com

Tanzania Oil & Gas ConferenceOctober 2-3Dar es Salaam, Tanzaniacwctog.com

LNGgcOctober 8-10London, UKenergy.knect365.com/lnggc-london

China LNG & GasOctober 16-17Beijing, Chinachinalngsummit.com

North America Gas ForumOctober 21-23Washington DC, USAenergy-dialogues.com/nagf

CWC World LNG Bunkering SummitNovember 5-6Hamburg, Germanycwclngbunkeringsummit.com


http://www.szwgroup.com/lng-western-africa-conference-2019

https://www.spglobal.com/platts/en/events/apac/lng-natural-gas/summary

https://www.wec24.org/

https://www.energycouncil.com/event-events/south-america-assembly-southern-edition/

https://www.energystreamcmg.com/forums/forums-seminars/6th-london-gas-lng-forum-2019.aspx

https://www.gastechevent.com/

https://www.cwcmoroccogas.com/

https://www.cwctog.com/

https://energy.knect365.com/lnggc-london/

https://www.chinalngsummit.com/

https://energy-dialogues.com/nagf/

https://www.cwclngbunkeringsummit.com/

C O N F E R E N C E S & E V E N T S

LNG Bunkering Summit 2020January 29-30, 2020Amsterdam, Netherlandsoilandgasiq.com/events-lngbunkering

6th International LNG CongressMarch 2-3, 2020Brussels, Belgiumlngcongress.com

6th CWC China LNG & Gas International Summit & ExhibitionMarch 4-6, 2020Shanghai, Chinachinalnggas.com

Oil & Gas Vietnam (OGAV 2019)November 13-15Vung Tau Cityoilgasvietnam.com

Mozambique Gas Summit & ExhibitionNovember 20-21Maputo, Mozambiquemozambique-gas-summit.com

CWC 20th Annual World LNG Summit & Awards EveningDecember 3-6Rome, Italyworld.cwclng.com

Frankfurt Gas ForumDecember 11-12Frankfurt, Germanyenergystreamcmg.com/forums/forums-seminars/7th-frankfurt-gas-forum-2019

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http://oilgasvietnam.com/

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https://world.cwclng.com/

https://www.energystreamcmg.com/forums/forums-seminars/7th-frankfurt-gas-forum-2019.aspx

https://www.oilandgasiq.com/events-lngbunkering

https://lngcongress.com/

https://www.chinalnggas.com/

US EXPORTS TO EUROPE RISE TENFOLDExports of US LNG to Europe have gone up sharply since October 2018, averaging 1.9bn ft³/day in the winter of 2018–19, compared with 0.1bn ft³/d in the winter of 2017–18, the US Energy Information Administration (EIA) said in its weekly report June 6.

That was mainly due to “tepid” demand in Asia because of the warm winter and additional LNG supply that came online in the fourth quarter of 2018, increasing global spot LNG supply, the EIA said. China, a major gas buyer, has also slapped retaliatory tariffs on US LNG.

The narrowing price difference between the UK National Balancing Point (NBP) and the equivalent spot price in Japan affected the flow of flexible exports from the US.

Transportation costs from the US Gulf Coast to Europe are about $1.50/mn Btu less than those to Asian markets (for a round trip) and the price difference between Japan spot LNG and NBP prices was less than $1.00/mn Btu in December and January 2019. With the price difference reaching a low of $0.60/mn Btu in April, US exports to Europe rose again.

In March and April US LNG exports to Europe averaged 1.7bn ft³/d, ten times higher than in the same months of last year, and accounted for more than one-third of all US LNG exports in those months. Most were sent from Cheniere Energy’s Sabine Pass terminal in Louisiana.

Europe’s LNG imports in the winter months of 2018–19 averaged 10.2bn ft³/d, 60% higher than in the previous two winters and the highest winter average since at least 2013, according to data from French consultancy Cedigaz. Russia, Nigeria and the US were the three largest suppliers to Europe from January through April 2019 (based on a four-month average).

With even more US LNG capacity coming on stream and Russian and Norwegian exports also strong, European storage facilities are expected to be filled by August, a few months earlier than normal. There has been talk of some US production facilities being shut this summer as the liquefaction and shipping costs from the US might exceed market prices.

US GAS PRICES FALL

The price of gas for July delivery at the US Henry Hub hit a three-year low of $2.324/mn Btu June 6, the lowest price for front-month delivery since May 31, 2016. This was despite low gas storage stocks and rising gas exports, the EIA said. There had been concerns before the LNG export terminals were built that US exports would push US hub prices up as demand for gas rose.

LNG exports for the first three months of 2019 averaged 4bn ft³/d, 1bn ft³/d more than the annual average in 2018. Natural gas exports by pipeline from January to March 2019 averaged 8.3bn ft³/d, an increase of 7% from the 2018 annual average. EIA forecasts growth in natural gas exports to continue, with total natural gas gross exports in 2019 averaging 12.4bn ft³/d, up a quarter on 2018.

BANGLADESH LIBERALISES LNG MARKETBangladesh has opened up the LNG segment to the private sector as the government eyes a supply crunch in the facing of mounting gas demand.

The ministry of power, energy and mineral resources has adopted a policy allowing private entrepreneurs to import LNG, regasify it and sell the gas onwards. Under the “LNG Import Policy for Private Sector 2019” the government will not interfere in pricing.

State-owned Petrobangla is the monopoly LNG importer currently, having received its first LNG shipments from Qatar in April 2018. Around 600mn ft3/day of regasified LNG feeds into the national grid through two import terminals.

However, by 2041, Bangladesh will need to import around 30mn mt/yr of LNG to meet demand, according to forecasts by Copenhagen-based research firm Ramboll. The country’s existing gas reserves of around 12tn ft3 are likely to run dry by 2038.

Permitted private sector companies will now be allowed to sell gas imported as LNG to fuel power plants and industrial units and for other commercial purposes. Operators of power plants and industry will also be able to arrange imports directly.

NEWS: GLOBAL LNG


N E W S : G L O B A L L N G

However, private traders will be limited in the amount of regasified LNG they can sell to Petrobangla. Sales of surplus gas cannot exceed 25% of a private trader’s total import volumes.

The policy also opens the way for the private sector to build LNG import infrastructure. Companies will have the opportunity to construct jetties, platforms, storage tanks, re-gasification plants and pipeline networks. Importers will also have access to Bangladesh’s gas network, which is operated by Petrobangla.

To receive an import permit, private operators must have experience in heavy industries or the power and energy sector. In the case of a consortium, third parties must have a minimum of five years’ experience in LNG project construction or maintenance.

Importers seeking a licence must provide necessary documents about potential buyers and planned volumes. No-objection certificates from the government will be required each year of operation.

TECHNIP TO PAY $300MN OVER BRIBERYUK-based oil and gas services group TechnipFMC said June 25 that it will pay over $300mn in fines to settle bribery cases brought by the US.

The New York-listed company released the statement shortly after the US Justice Department announced TechnipFMC had admitted violating the Foreign Corrupt Practices Act by bribing energy officials in Brazil and Iraq.

“TechnipFMC has agreed to resolutions with the US Department of Justice, the US Securities and Exchange Commission Staff and the Brazilian authorities … to resolve anti-corruption investigations in Brazil and relating to the intermediary, Unaoil,” the statement reads. “The company has agreed to pay a total of $301.3mn to these authorities to resolve investigations into conduct dating back over a decade ago.”

US authorities said that in 2003-2013 Technip had paid over $70mn in bribes to officials from Brazilian state-owned oil and gas company Petrobras. Iraqi officials were bribed from 2008 to 2013, according to US prosecutors.

Technip said in its statement that it remains under investigation by French authorities related to historical projects in Equatorial Guinea and Ghana, and maintains a $70mn provision related to the case.

The corrupt practices continued despite Technip agreeing in 2010 to pay a $240mn settlement over bribes paid in Nigeria.

The Brazilian bribery scheme was linked to a case against Singaporean shipyard operator Keppel Offshore & Marine, which agreed with US, Brazilian and Singaporean authorities in 2017 to pay a $422mn settlement.

CEO Doug Pferdehirt stated that the “conduct dating back over a decade ago, taken by former employees, does not reflect the core values of our company today,” and said that Technip plans to enhance its anti-corruption programme.

AUSTRALIAN STATE TAX COUNTERPRODUCTIVE: E&P INDUSTRYThe Queensland government’s announcement that it will hike the petroleum royalty rate by a quarter threatens ongoing investment in one of the very sectors which can underpin the state budget over the coming decades, upstream lobby group Australian Petroleum Production & Exploration Association (Appea) said June 11.

Treasurer Jackie Trad announced an across the board retrospective increase in the petroleum royalty rate from 10% to 12.5%, effective July 1, on all gas produced in Queensland, home to three LNG plants fed by coalbed methane fields. The gas is sold mostly to Asian markets and exports last year from Queensland reached a record 21mn metric tons.

Appea CEO Andrew McConville said there was “no justification for the arbitrary decision to penalise an industry that had invested over A$70bn ($48bn) in Queensland, employs thousands of Queenslanders and has underpinned the state’s domestic gas needs.”

The budget papers forecast that the industry will deliver at least A$2.5bn in royalties to the people of Queensland over the next four years. While the industry welcomes the decision to conduct a review of the operation of the present royalty regime, the announcement of a significant increase in the royalty was made without any consultation with industry, Appea said.

“Increases in royalty rates, however structured, increase the cost of gas production and undermine



the long-term stability that is needed to continue to attract investment in Queensland,” McConville said. “An announcement with no consultation, as we have seen today, will be very carefully reviewed by current and prospective investors.”

Raising the rates will limit the gas available to the domestic gas market, at a time when that market is already under pressure from falling output from the Bass Strait and political barriers to resource development in southern states, he said. Victoria, for example, has imposed a moratorium on hydraulic fracturing.

McConville said the industry would seek to work with the government “in what must be a genuinely independent policy and operational review of the existing royalty provisions.”

POLAND DEVELOPS NON-RUSSIAN GAS STRATEGY

Plaquemines terminal will increase from 1mn to 2.5mn metric tons/year.

Deliveries are expected to start in 2023. This new amendment raises PGNiG’s total commitment with Venture Global LNG projects to 3.5mn mt/yr, from Calcasieu Pass (1mn mt/yr) and Plaquemines (2.5mn mt/yr), it said. All the contracts are for 20 years and free on board, meaning that PGNiG can decide where to sell the gas.

The US Federal Energy Regulatory Commission (Ferc) issued May 3 a Final Environmental Impact Statement for both the Plaquemines LNG facility and the associated Gator Express Pipeline.

Meanwhile, PGNiG agreed to buy a 22.2% stake in two licences in the King Lear field in the North Sea, it said June 7. The stake is being sold by Total.

The Polish company says the PL146 and PL333 licences could see it reap up to 0.25bn m3/yr once production starts. The BP-operated King Lear field contains recoverable resources of 98.6mn boe, including 9.2bn m3 of natural gas, and is scheduled to launch in 2025.

Norway’s Equinor sold its 77.8% stake in King Lear to BP last year. At the same time, PGNiG bought it out of the nearby Tommeliten discovery, which should launch production in 2024. Partners on the project are operator ConocoPhilips (28.26%), Total (20.23%) and Eni (9.13%).

Poland is racing to secure upstream resources to supply gas to the Baltic Pipe project, which will complement its LNG imports. Once the latest deal is finalised, PGNiG will hold shares in 25 licenses on the Norwegian continental shelf, on four of which it acts as operator.

PGNiG’s Aerfugl field is due start production on time in June 2020, the company said June 4. Operator Aker BP estimates that the development phase 1 is 40% complete. PGNiG Upstream Norway and its license partners hope to reach the execution stage for phase 2 in November.

Meanwhile, the 10bn m³/yr Baltic Pipe project secured a second permit in June, Polish TSO Gaz-System said, relating to its construction location in the province of West Pomerania, Poland’s most north westerly region. The project secured its first permit, from the region of Wielkopolska to the south east of West Pomerania, May 15.

The permit expands the permissions for the Polish onshore section of Baltic Pipe, which will ship gas to Poland from the Norwegian shelf via Denmark. Polish officials have said they hope to launch construction in mid-2020 and have the pipeline fully operational by 2022.

Poland’s strategy to wean itself off Russian gas entirely by the time its current take-or-pay contract with Russia’s Gazprom expires in 2023 is evolving rapidly.

State-owned gas company PGNiG has signed up for another 1.5mn metric tons/year of US LNG with US LNG developer Venture Global, it said June 12. Under this agreement, the volume of LNG to be supplied from the

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POLITICAL SETBACK FOR US LNG DELIVERY BY TRAINLegislators in the US House of Representative approved an appropriations bill amendment June 24, setting back the prospects for supplying LNG by rail tank cars. Citing safety issues, the bill would stop the secretary of transportation from issuing a special permit for transportation to a subsidiary of New Fortress Energy, Energy Transport Solutions, to move 100-car unit trains of LNG, which would serve both the domestic and export markets. A comment period on an environmental assessment of the company’s plans is set to expire on July 8.

The bill would also stop the general movement of LNG in rail tank cars and potentially goes against an executive order issued by US President Donald Trump in April which called for LNG to be allowed to move in rail tank cars within 13 months. Currently, LNG can only be moved by pipeline or in portable IMO cargo tank containers, which can be loaded on trains.

While saying that moving LNG by rail used less fuel and was therefore better for the environment, the Pipeline and Hazardous Materials Safety Administration earlier warned that releases of LNG, owing to a breach of the inner tank of a tank car “could pose pool fi re, vapor fi re and explosion hazards, which pose the highest potential impacts when compared to localized cryogenic hazards.”

GS ENERGY, TOKYO GAS TO BUY CARBON NEUTRAL LNG FROM SHELLSouth Korean GS Energy and Tokyo Gas have signed an agreement with Shell Eastern Trading for delivery of one cargo each of carbon neutral LNG, Shell said June 18.

Nature based carbon credits will be used to compensate the full carbon dioxide (CO2) emissions generated – from exploring for and producing the natural gas, to use by the fi nal consumer. The cargoes, which will be delivered by July 2019, will provide enough carbon neutral energy to power nearly 300,000 homes for a full year, Shell added.

According to Shell, nature-based projects protect, transform or restore land and enable nature to add oxygen and absorb more CO2 emissions from the atmosphere. Each carbon credit is subject to a third-party verifi cation process and represents the avoidance or removal of 1 metric ton of CO2.

Credits used for this deal are bought from Shell’s global portfolio of nature-based projects, including Katingan Peatland Restoration and Conservation Project in Indonesia and Cordillera Azul National Park Project in Peru, Shell said.

These projects also have extra benefi ts such as offering alternative sources of income to local communities, improving soil productivity, cleaning air and water, and maintaining biodiversity, it said.

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NOVATEK SELLS ARCTIC 2 STAKE, READY TO TAKE FIDRussian independent gas producer Novatek is selling 10% of the shares in its Arctic LNG 2 project to a Dutch-registered Japanese consortium consisting of Mitsui & Co (25%) and Japan Oil, Gas and Metals National Corporation (Jogmec, 75%). The agreement leaves Novatek with 60% and paves the way for a final investment decision (FID) in the third quarter.

Novatek said it had signed the sales and purchase agreement, which includes long-term LNG offtake of about 2mn mt/yr, after the G20 summit in Osaka. The agreement will close in the nearest future subject to regulatory approvals, the company said.

Mitsui said Novatek's estimate of the total development cost is around $ 21-23bn, adding that following FID with partners, LNG production was due to start around 2023. Other partners are subsidiaries of France’s Total; China National Petroleum Corporation and China National Offshore Oil Corporation, all with 10% each.

Arctic LNG 2 will comprise three LNG trains with capacity of 6.6mn mt/yr each, using gravity-based structure (GBS) platforms, saving a third of the cost of Yamal LNG where the trains were built on thermally-insulated piles sunk deep into the permafrost. Feedstock gas will come from the Utrenneye field, on the Gydan Peninsula.

VENTURE GLOBAL SECURES ADDITIONAL LNG FINANCINGUS LNG developer Venture Global said June 27 it has raised $675mn of additional investment from institutional investors that will be used primarily to further the development of the company’s 20mn mt/yr Plaquemines LNG export project in Louisiana.

Together with the $855mn raised earlier and May’s equity investment of $1.3bn from Stonepeak Infrastructure Partners, Venture Global has now raised total committed capital of $2.8bn to support the development of its LNG export facilities.

“With the expansion of our Plaquemines LNG sales and purchase agreement (SPA) with PGNiG to 2.5mn mt/yr and in anticipation of additional near-term commercialisation, we are excited to add significant new resources as we prepare to commence early works at Plaquemines later this year,” the company said.

The Plaquemines LNG export facility will use highly-efficient midscale, modular, factory-fabricated liquefaction trains in an identical configuration to Venture Global’s Calcasieu Pass LNG project, currently under construction in Cameron Parish, Louisiana, the company said.

A final order concerning Plaquemines from the US Federal Energy Regulatory Commission is expected no later than August 1, after which Venture Global will be in a position to take a positive final investment decision. Construction on Phase 1 – nine liquefaction blocks with capacity of 10mn mt/yr – is expected to begin late this year, with Phase 2 set to begin construction in late 2020.

WOODFIBRE LNG SECURES BP ANCHORPacific Oil & Gas (PO&G) announced June 26 that it has signed up BP as a foundation buyer for its Canadian Woodfibre LNG project.

The pair have signed a binding LNG sales and purchase agreement (SPA) that will see the UK-based major purchase 0.75mn metric tons (mt)/yr from the export facility in British Columbia. The contract will run for 15 years on a free-on-board (FOB) basis, with first delivery expected in 2023.

“We are honoured to have BP as a foundation customer of our Woodfibre LNG project,” said PO&G president Ratnesh Bedi. “We look forward to providing BP with a consistent supply of flexible Canadian LNG that can displace more carbon intensive fuels.”

“This SPA further broadens our supplier base and adds to BP’s ability to offer cleaner energy to our customers around the world,” said COO of BP’s LNG global business Jonty Shepard.

PO&G also noted that it is in talks with BP Canada regarding transportation and balancing services for gas supplies to the planned LNG export facility, which is planned to have a capacity of 250,000m3/yr, or 2.1mn mt/yr.

NEWS: LNG SUPPLY


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INPEX SUBMITS REVISED ABADI LNG PLANJapan’s Inpex Corporation announced June 20 that it had submitted a revised plan of development (POD) for the Abadi LNG project to the Indonesian authorities.

The revised POD, issued via subsidiary Inpex Masela, is based on an onshore LNG development scheme with an annual LNG production capacity of 9.5mn mt/year. The project involves developing the Abadi gas field in the Masela Block, located in the Arafura Sea in Indonesia.

“Inpex anticipates that the revised POD will be approved at an early stage, after which the company will work in partnership with Shell toward reaching FID and ultimately commencing production, with the cooperation of the government of Indonesia,” said Shunichiro Sugaya, president of Inpex Masela.

Inpex earlier in June signed a heads of agreement (HOA) with the Indonesian government regarding a revised POD for the project. The revised POD incorporates the results of pre-front end engineering design (Pre-feed) work conducted between March and October 2018.

In addition, Inpex, in partnership with Shell, filed an application to amend the production sharing agreement for the Masela Block. This amendment accommodates the additional seven years’ time allocation to the production sharing contract term due to the time spent studying the previously proposed development scheme, it said.

In March 2016, the country’s president Joko Widodo said the production facilities should be built onshore, instead of offshore as Inpex had proposed, causing the Japanese company to review its plans.

The Masela block contract was signed in 1998. Inpex is operator with a 65% share in the block while Shell owns 35%. The project is the first large-scale integrated LNG development project operated by Inpex in Indonesia.

CHENIERE TAKES FID ON SABINE PASS TRAIN 6US LNG developer Cheniere Energy said June 3 that it has finalised a new capital allocation plan, a key feature of which is the final investment decision (FID) on Train 6 at its Sabine Pass LNG export terminal in Louisiana.

The capital allocation plan prioritises the reinvestment of cash flows to grow Cheniere’s LNG complex, targets improved credit metrics and promises a return of excess capital to shareholders. The company expects to generate some $9bn of available cash through the first half of 2024, and the new capital allocation plan covers the period until then.

“The capital allocation framework we announced today prioritises continued investment in our LNG platform through new high-return growth projects, beginning with Sabine Pass Train 6, on which we have made a positive FID and have issued full notice to proceed to Bechtel,” Cheniere CEO Jack Fusco said.

To fund the 4.5mn mt/yr Train 6 and construction of a third berth at Sabine Pass, Cheniere Energy Partners entered into 5-year, $1.5bn senior secured credit facilities with 29 banks and financial institutions in a transaction that closed May 29.

In a separate announcement June 3, Cheniere said it had entered into a long-term gas supply agreement with US producer Apache for 140,000 mn Btu/day of natural gas to Cheniere’s Corpus Christi Stage 3 project in Texas. The LNG associated with this supply – about 0.85mn mt/yr – will be marketed by Cheniere.

Under the terms of the gas sales agreement, Apache will receive an LNG price, net of a fixed liquefaction fee and certain costs incurred by Cheniere, for the natural gas delivered to Corpus Christi. The LNG price is based on international LNG indices.

Corpus Christi Stage 3 is being developed to include up to seven mid-scale liquefaction trains with a total nominal production capacity of about 9.5mn mt/yr. It received its final environmental assessment from the US Federal Energy Regulatory Commission in March 2019 and expects to receive all other regulatory approvals by the end of this year.

PRELUDE FLNG SHIPS ITS FIRST CARGOThe Shell-operated Prelude FLNG facility, located 475 km northeast of Broome in Western Australia, has shipped its first LNG cargo, Shell Australia said June 11.

The shipment will be delivered to customers inAsia, Shell Australia added. “Today’s first shipment of LNG departed from Prelude FLNG, safely. Everyone involved should be very proud of the work taken to reach this important milestone,” Shell’s integrated gas



and new energies director, Maarten Wetselaar, said in a statement.

Prelude is expected to produce 3.6mn mt/yr of LNG; 1.3mn mt/yr of condensate and 0.4mn mt/yr of LPG. “Prelude forms an integral part of our global portfolio and plays an important role in meeting growing demand for more and cleaner energy for our customers around the world,” Wetselaar added.

The project involves developing the Prelude and Concerto gas fields and separating and liquefying the produced gas at the FLNG facility.

Shell is the operator of the project with a 67.5% interest, Japan’s Inpex has 17.5%, Taiwan’s CPC 5% and South Korea’s Kogas 10%. Shell never committed itself to a start-up date or commented on the cost of the project, but it was expected by many in the industry to have come on stream some years ago. The final investment decision (FID) was more than eight years ago and the facility arrived in Australia almost two years ago.

Consultancy Wood Mackenzie said a key indicator of success will be how fast Prelude delivers its second and third cargo, and ramps up to plateau output. “Shell will be keen to ramp up to full production quickly to counteract any reserves impact from the already producing and connected Ichthys field,” it said. Japanese Inpex is the operator of the much larger Ichthys LNG project.

BACKFILL PHASE

“The Prelude facility will be backfilled by Crux, which entered front-end engineering and design this year. We expect a final investment decision late next year with first production in 2025. In addition, later this year Shell will spud the Bratwurst exploration well. If a significant gas resource is discovered it is likely these volumes will be developed via the Prelude facility, WoodMac said.

“With Prelude onstream, Australia is on track to export more than 80mn mt/year of LNG, which surpasses Qatar [78mn mt/yr] as the largest LNG producer in the world.

“The completion of Prelude marks the end of the Australian greenfield LNG boom. The next investment cycle is already in sight, with backfill projects – Scarborough, Barossa, Browse, Arrow and Crux – vying for FID,” it concluded.

Australia’s Santos announced June 27 that the Barossa joint venture had entered into exclusive negotiations with the Darwin LNG joint venture for the supply of backfill gas.

WOODSIDE RESTARTS PRODUCTION AT PLUTOAustralia’s Woodside said June 24 that it had restarted production at its Pluto LNG plant. Earlier in the month, the company extended its planned maintenance schedule, owing to technical issues during the restart. Woodside had made arrangements to meet obligations to its customers, including the purchase of third-party cargoes.

As a result of the turnaround extension, the company expects its 2019 production to be at the lower end of its 88–94mn boe guidance range. The extension comes at a time of depressed spot LNG prices.

AUSTRALIAN EXPORTS DROP IN MAYAustralian LNG exports in May stood at 6.4mn metric tons (94 cargoes), down from a record 6.7mn mt (98 cargoes) in April, advisory firm EnergyQuest said in its June LNG report.

Australia’s May shipments were 75mn mt/year on an annualised basis, just behind Qatar nameplate’s capacity of 77mn mt/yr, the report said.

Australian projects delivered 38 cargoes to China in May, up from 36 in March, more than delivered to Japan. West coast shipments decreased to 68 cargoes in May compared with 70 in April while East coast LNG shipments declined to 26 cargoes compared with 28 in April.

OREGON LNG PROJECT SECURES 82% LANDOWNER SUPPORTThe Jordan Cove LNG project said June 24 it has secured voluntary easement agreements with 82% of the private landowners along the route of the Pacific Trail pipeline, which will deliver feed gas to the proposed 7.8mn mt/yr liquefaction plant in Coos Bay, Oregon from the Malin trading hub in southern Oregon.



“This 82% is more than just a number,” said Harry Andersen, senior vice president for Jordan Cove’s Canadian parent, Pembina Pipeline. “It represents a tremendous measure of progress forward for Jordan Cove.”

When Jordan Cove was first turned down by the US Federal Energy Regulatory Commission (Ferc) in 2016, one of the reasons cited was lack of landowner support for the 229-mile Pacific Trail pipeline. When Pembina acquired the project with its 2017 acquisition of Verasen, voluntary easement agreements had reached only 20% of affected landowners.

The LNG project, which has faced stiff state, local and indigenous opposition since it was first introduced by Verasen, was the subject of scoping meetings across Oregon in June designed to give Ferc staff public input as they prepare the project’s final environmental impact statement (EIS), which is expected to be completed in October. Ferc’s final order on the project is anticipated in early January 2020.

The fact that 82% of affected landowners have reached voluntary easement agreements, the company said, shows that despite apparent public objections to the project, a “quiet majority of citizens in southern Oregon” support the project.

However, despite positive landowner support, the project still faces headwinds at the state level: a key water quality certification was denied in May and decisions on other key state permits won’t be made until later this year. In light of that, Pembina has slowed work on the project, and now does not anticipate a final investment decision until 1H 2020, with completion delayed a year, to 2025.

TRANSBORDERS, KYUSHU PLAN FLNG OFF AUSTRALIAAustralia’s Transborders Energy has entered into a joint study agreement with Japan’s Kyushu Electric Power and its affiliate Kyushu Electric Australia to develop an FLNG plant that will be deployed on a range of stranded gas fields offshore Australia, it said June 17.

“Transborders’ goal is to unlock stranded gas resources, develop a new LNG supply source, and offer alternative LNG solutions. Participation by major Japanese utilities as strategic partners, such as Kyushu, in the joint study endorse and add significant value to our FLNG solution,” Transborders chairman Jack Sato said.

The two companies will conduct technical pre-front-end engineering and design (pre-Feed) with Transborders’ strategic partners TechnipFMC and Norway’s Add Energy; pre-negotiate key commercial terms of the FLNG plant; and pursue its deployment on stranded gas resource opportunities.

Based on this joint study agreement, Transborders has executed relevant agreements with TechnipFMC and Add Energy to commence the technical pre-Feed work. MODEC Management Services plans to give support to the pre-Feed work as operational advisor, Transborders said.

Upon completion of the FLNG development work in 2019, Transborders will be in a position to convert a range of stranded gas resources into a ‘project sanction ready’ state within 24 months after FLNG deployment, while also allowing LNG buyers access to competitive LNG supply sources, it said.

EDGE CAPTURES STRANDED GASUS Edge has produced and delivered its first LNG in the US, using stranded natural gas as the source. It sees a gap in the market for monetising gas which would otherwise be flared.

In an announcement June 18, it said Edge is “the first viable route to market for stranded gas reserves, and a revenue generating alternative to flaring or venting associated gas from oil production.” According to the World Bank, last year 145bn m³ of gas was flared, with the Bakken, Permian and Eagle Ford the biggest growth areas.

Edge began on-well-site LNG production in the US May 7, accessing Marcellus gas in Pennsylvania, and making truck-delivered LNG sales to its first customers. To date, it said, Edge has delivered over 30,000 gallons of LNG (114 m³) to a delivery point at a New England gas utility over 300 miles away from the Marcellus production site.

Edge uses Galileo Global Technologies’ transportable Cryobox LNG production and liquefaction equipment at the wellhead and takes it by truck directly to its customers› doorsteps. Edge Cryobox units are designed to be quickly and easily connected and disconnected from feedstock gas wells. Units are also self-powered using produced gas, removing the need for a grid connection.



Edge uses technology developed and proven in Argentina, and is successfully producing and delivering LNG in the US. However, it is suitable for use anywhere in the world where stranded, flared or vented gas is an issue, it said.

Edge CEO Mark Casaday said: “It is estimated that stranded wells account for up to 60% of global reserves, and up to 20% of those drilled in Marcellus, showing the scale of this untapped resource.”

CANADIAN LNG DEVELOPER BUYS MORE GAS ASSETSCanadian LNG developer Pieridae Energy said June 26 it has reached a C$190mn (US$145mn) agreement to acquire all of Shell Canada’s natural gas assets in the Foothills region of Alberta, more than doubling its production and reserves base and bringing closer a final investment decision (FID) on its C$10bn ($7.5bn) Goldboro LNG project in Nova Scotia.

The acquisition, expected to close in 3Q 2019, includes average production of 119mn ft3/day of conventional natural gas, 5,646 barrels/day of natural gas liquids and 3,161 b/d of condensate and light oil. Pieridae will also acquire three deep cut sour gas processing plants at Jumping Pound, Caroline and Waterton with a combined processing capacity of 750mn ft3/d, of which 420mn ft3/d is available.

“We said we would acquire additional gas supplies for the LNG facility and we have done that,” Pieridae CEO Alfred Sorensen said. “Not only does this deal help us secure the remaining conventional natural gas supply needed for the first train of the Goldboro LNG project, it makes Pieridae a major player in the Alberta midstream and upstream industry.”

Sorensen suggested to NGW that a new supply deal for the first 5mn mt/yr train at Goldboro was close to being concluded.

With the added natural gas supply, Pieridae now expects to access up to US$1.5bn in credit support from the German government to develop the upstream assets as part of its Goldboro LNG project. All of the output from the first train was committed to German utility Uniper in 2013 under a 20-year purchase and sale agreement.

In 2018, Swiss utility Axpo signed a term sheet for what some sources said could be as much as 2.5mn mt/yr of Train 2 output, while Sorensen told NGW that virtually all of the second train’s remaining capacity

has been committed to parties which he was not in a position to identify.

The acquisition includes an estimated 257,400 net developed and undeveloped acres of land, proved developed and producing (PDP) reserves of 82.78mn barrels of oil equivalent (boe) and proved reserves of about 89.3mn boe, giving the company plenty of running room to develop additional production to meet the expected 900mn ft³/day of demand from Train 1. Pieridae’s existing reserves total about 60.1mn boe on a PDP basis and nearly 84mn boe on a proved basis.

“Existing production and new drilling inventory will provide significant new gas supply along with an extensive, well maintained, underutilised and sophisticated gas midstream system,” the company said. “The associated liquids will provide accretive net operating income and the associated gas will provide a large contribution to the 800mn ft3/day of conventional gas supply that is required for Train 1 of the Goldboro LNG facility.”

Pieridae’s Ikkuma Resources, acquired in December 2018, will supply the remaining 100mn ft3/day to Train 1.

Pieridae continues to work with Kellogg Brown & Root (KBR) to review an amended version of the previously prepared front-end engineering and design (Feed) study for the project, and to conduct an open-book estimate necessary to finalise a lump-sum, turnkey engineering, procurement and construction contract with KBR. Pending that contract, the company expects to take a positive FID on Goldboro LNG by the end of this year.

TOKYO GAS, SUMITOMO INK LNG AGREEMENTTokyo Gas has signed a preliminary agreement with Sumitomo Joint Electric Power regarding the supply of LNG, it said June 19. Under the agreement, Tokyo Gas will supply about 170,000 mt/yr of LNG to Sumitomo for a period of five years extending from fiscal 2021 to fiscal 2025. The agreement has an ex-ship delivery condition.

“The two companies will build connections with the community and contribute to the development of the Shikoku area, through promoting the use of the environmentally friendly natural gas and the stable and efficient use of energy, by providing a stable supply of LNG under this agreement,” Tokyo Gas said.

Supplies will come from multiple LNG projects with which Tokyo Gas has entered into contracts, the company said.



MAJOR UPSTREAM INVESTMENT OPPORTUNITY IN MALAYSIA: WOODMACMalaysia offers some of the most material and attractive upstream investment opportunities in Southeast Asia, primarily due to the need for additional gas supply, Wood Mackenzie said in a research report published June 24.

The multiple breakdowns in the Sabah-Sarawak gas pipeline and a delayed fi nal investment decision (FID) on the large Kasawari gas project have resulted in a supply crunch to the Bintulu MLNG plant. WoodMac sees this supply shortage persisting until at least 2025, when major new fi elds - Jerun, Timi, Rosmari, Marjoram and Kasawari - are likely to be brought onstream.

“This is a golden opportunity for upstream players to swiftly bring gas onstream and jump ahead of the queue: either in the form of increasing existing production, or by developing smaller discoveries to tie into existing infrastructure. But speed is the key,” said upstream research director Angus Rodger at the AOGC conference in Kuala Lumpur.

The most prospective basins for new discoveries and undeveloped gas resources in Malaysia are in offshore Sarawak. In this region, WoodMac estimates there is already 17 trillion ft3 of discovered and undeveloped gas that is commercially viable. However, as many of the easiest fi elds have already been commercialised, those that remain will be more diffi cult and costly to develop, WoodMac said. For example, half of the 17 trillion ft3 requires investment in technology to process higher levels of carbon dioxide and/or other contaminants, it said.

All this means that for explorers there are additional benefi ts in drilling for new sources of cleaner gas. Any such discoveries stand a good chance of leap-frogging the queue of existing resources and getting fast-tracked for development, WoodMac added.

“We expect Petronas to ramp up its own exploration efforts, particularly in deepwater Sarawak, to prove up easier-to-develop resources. It will also invest in new technology to develop some of the more challenging accumulations,” stated Rodger.

“The national oil company (NOC) has already proven itself as a global technology leader through its deployment of the PFLNG1 vessel and development of the RAPID project. We expect this investment in innovation to continue, which sets Petronas apart from many of its NOC peer group,” said Rodger.

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INDIA’S LNG DEMAND RUNNING AHEAD OF DOMESTIC OUTPUTIndia’s LNG imports in May increased year-on-year for the second month in a row, according to latest data published by Indian oil and gas ministry’s Petroleum Planning and Analysis Cell (PPAC).

India imported LNG equivalent to 2.52 m3 of pipeline gas (about 1.85mn mt), up 4.4%, compared with May 2018. During the first two months of the present financial year, cumulative imports were 5.15 m3, up 5.62% year-on-year. India’s financial year runs from April to March.

During the last financial year, India imported 27bn m3 of LNG, up 2.6% compared with the year before. This was the highest ever imports during a fiscal year.

Meanwhile, India’s gross production of natural gas in May was 2.73bn m3, up only 0.4% over May 2018. Natural gas available for sale during May was 4.56bn m3, down 0.4% year-on-year. Regasified LNG accounted for about half of total gas consumption. Cumulative natural gas production during the last financial year was 32.65bn m3, up 0.7% year-on-year.

H-ENERGY’S WEST INDIA TERMINAL TO START BY YEAR-END: REPORTMumbai-based H-Energy is expected to start operations at its Jaigarh floating LNG import terminal by the fourth quarter of this year, Financial Express reported June 18, citing a company official.

The floating storage and regasification unit GDF Suez Cape Ann arrived at Jaigarh Port in the western Indian state of Maharashtra last May. It is owned by Hoegh, LNG but was on charter to France’s Engie, which had sub-chartered it to China’s Cnnoc for the previous two winters for use at the Chinese port of Tianjin.

Financial Express reported that with the start of the terminal imminent, H-Energy is looking to source 1mn mt/year of LNG. The terminal will start with a capacity of 1.5mn mt/yr and will be ramped up to 2.5mn mt/yr later, the official told the newspaper.

H-Energy is also planning a land-based receiving terminal in the eastern Indian state of West Bengal. Earlier this year, company CEO Darshan Hiranandani said during an event in Kolkata that work on the proposed LNG receiving terminal will likely start in the middle of this year.

The terminal will supply regasified LNG to West Bengal as well as to neighbouring Bangladesh. The initial capacity of the terminal would be 3mn mt/yr, which can be expanded to 5mn mt/yr.

INDIA’S PETRONET EXPANDS DAHEJ TERMINAL CAPACITYIndia’s biggest LNG importer, Petronet LNG, has expanded the capacity of its Dahej LNG import terminal, it said June 10 in a regulatory filing. Dahej import terminal’s capacity has increased to 17.5mn mt/year from 15mn mt/yr. The terminal is located in the western Indian state of Gujarat.

Petronet said that facilities related to the expansion of Dahej LNG terminal has been commissioned and were undergoing a stabilisation phase. “As such the additional gas send-out from Dahej LNG terminal has commenced. The performance guarantee test shall be performed once the system is stabilized,” it said.

In addition to the Dahej terminal, Petronet also operates the 5mn mt/yr Kochi import terminal in the southern Indian state of Kerala.

PAKISTAN TENDERS FOR 240 LNG CARGOESState-owned Pakistan LNG is seeking to contract supply of 240 LNG cargoes over the next ten years, according to tender documentation. The company is seeking two cargoes of 140,000 m3 every month, according to the documents, which were posted on the company›s website June 4. The cargoes are to be delivered on an ex-ship basis to Port Qasim, Karachi.


NEWS: LNG DEMAND

Pakistan has two import terminals located at Port Qasim. Pakistan LNG did not say to which terminal the cargoes would be delivered. Last date for the submission of bids is July 18. The bids will be opened on the same day.

CHINA MAY LNG IMPORTS RISE 7.6% YOYChina imported 4.43mn metric tons of LNG in May, up 7.6% year-on-year, customs department’s data published June 23 showed. This was slightly lower than in April, which saw imports of 4.54mn mt. During the first five months of the year, LNG imports were 23.87mn mt, up 20.3% year on year.

Meanwhile, China’s pipeline imports in May were 3.13mn mt, down 4.3% yearon year. Overall, Asia’s biggest economy imported 7.56mn mt of gas in May, compared with 7.65mn mt in April, the customs department data showed.

Cumulative imports during the first five months of the year were 39.4mn mt, up 13.4% compared with the same period of previous year, according to the data.

JAPAN’S MOL FINALISES HONG KONG FSRU DEALThe partners behind the Hong Kong LNG Terminal project announced June 21 that they have agreed to charter a floating storage and regasification unit (FSRU) from Japan’s Mitsui OSK Lines (MOL), which will be used for the Hong Kong offshore LNG terminal project.

The project is a joint venture of Castle Peak Power Company (Capco) and Hongkong Electric Co. (HK Electric). The companies said they have entered into a time charter agreement with the Japanese company for the FSRU.

The FSRU will be used for receiving, storing, and regasifying LNG for the supply of natural gas to Capco and HK Electric for power generation through two separate subsea gas pipelines. MOL will be responsible for providing operations and maintenance services for the vessel and the offshore LNG terminal.

Last year, MOL entered into a preliminary agreement to supply the Challenger FSRU to the Hong Kong

project. Built in 2017 with a storage capacity of 263,000 m3 it is the world’s largest. The LNG terminal will distribute gas to two destinations in Hong Kong, the Black Point power station located at New Territories and Lamma power station on Lamma Island.

The Hong Kong offshore LNG terminal project is being developed to support the Hong Kong Special Administrative Region (HKSAR) government’s target of generating about half of Hong Kong’s electricity from natural gas from 2020 onward to improve air quality.

“HK Electric is taking steps to substantially increase the use of natural gas for power generation, from currently over 30% of total output to around 70% by 2023, as we support the government’s policy and targets to combat climate change and improve air quality while transforming Hong Kong into a low-carbon city,” HK Electric’s managing director Wan Chi-tin said.

Capco and HK Electric also announced an agreement with Shell Eastern Trading for long-term LNG supplies for the Hong Kong offshore LNG terminal.

Shell will supply LNG to both Capco and HK Electric from its worldwide LNG portfolio, the two utilities said without offering details. Capco is a 70:30 joint venture of CLP Power Hong Kong and China Southern Power Grid International, a wholly owned subsidiary of China Southern Power Grid Co. Last year, CLP Power received environmental approval for its offshore LNG terminal.

ADB TO FUND SRI LANKA LNG TERMINAL FEASIBILITY STUDYThe Asian Development Bank (ADB) will fund a study to assess the feasibility of developing an LNG import terminal in Sri Lanka, it said in June.

The feasibility study will look to identify the optimal LNG facility for Sri Lanka and the most suitable location for the development of new gas-fired power plants and associated facilities. This will include a detailed study considering the demand for natural gas in Sri Lanka, the global LNG market, LNG pricing and contracts, the possibility of supplying LNG to regional markets, and other social and environmental aspects, the ADB said.

According to the ADB, an LNG facility in Sri Lanka could also serve the Maldivian market. “Maldives is considering importing LNG for power generation and other uses. An LNG terminal in Sri Lanka with sufficient storage and adequate supply will benefit from lowering the energy cost of both countries,” the ADB said.


N E W S : L N G D E M A N D

Ceylon Electricity Board (CEB), a state-owned electricity utility, has already carried out a preliminary feasibility study with support from the ADB exploring the possibility of LNG for Colombo-based power plants. The study recommended setting up an LNG terminal and other infrastructure on an expeditious basis for supplying LNG for power generation, the ADB said.

Last year, the Sri Lankan government said India›s Petronet LNG would partner with Japan’s Mitsubishi and Sojitz Corporation to set up Sri Lanka’s first LNG terminal near Colombo. The government issued a letter of intent with the Indian government regarding the plan during the visit of Indian foreign minister Sushma Swaraj to Colombo in September 2017.

SAMSUNG C&T TO BUILD VIETNAMESE LNG TERMINALSouth Korea’s Samsung C&T announced June 25 it has been awarded the contract to build Vietnam’s first LNG import terminal.

Samsung C&T will carry out the $180mn LNG import terminal project in a joint venture with PetroVietnam Technical Services Work. Work was slated to start later in June and take about 40 months to complete, the company said in a statement.

The terminal will have a 180,000m3 tank, a vapour transmission facility and a docking station. It will be located 70km southeast of Ho Chi Minh City. Once operational, the terminal will supply gas to the Nhon Trach power plant.

JAPAN’S LNG IMPORTS DROP IN MAYJapan’s LNG imports in May stood at 5.56mn metric tons, down 13.1% year-on-year, according to provisional data released by the country’s finance ministry June 19. In April, Japan, the world’s biggest LNG importer, imported 5.62mn mt of LNG.

The average price of spot LNG imports into Japan contracted in May 2019 was $5.4/mn Btu, down from $8.2/mn Btu in the same month a year ago, the

country’s trade ministry (Meti) said June 11. Compared with April, the price was up 3.9%.

Meti prices are ‘delivered ex ship’ in Japan, or else are converted into such a ‘DES’ equivalent. Meti also published June 11 official average arrivals-based price. The latest figures show that May arrivals’ average value was $5.3/mn Btu, down from $7.9/mn Btu for May 2018.

AGL PUSHES BACK LNG IMPORT TERMINAL START UPAustralia’s AGL Energy has pushed back the start date of its Crib Point LNG import terminal near Melbourne, it said June 28. The company said that it expects first gas to be delivered from the proposed facility at Crib Point in Victoria in the second half of fiscal 2022. AGL had previously indicated first gas could potentially be delivered during fiscal 2021.

“Confirmation of this timetable follows AGL’s decision to select the Hoegh Esperanza as the floating storage and regasification unit (FSRU) for the Crib Point project, as opposed to the Hoegh Giant as communicated in December 2018,” the company said.

AGL believes the Esperanza better fits timing and operational requirements arising from the Environment Effects Statement (EES) process currently being undertaken by the Victorian government. The Hoegh Esperanza has a later delivery window than the Hoegh Giant.

AGL expects the outcome of the EES to occur no earlier than late fiscal 2020, subject to and following which AGL expects to reach a final investment decision on the Crib Point project, which is planned to have a capacity of 100 petajoules/year (2.67bn m3/yr).

NOVATEK SIGNS UP FOR VIETNAMESE LNG-FIRED POWER PROJECTNovatek announced June 7 that it has signed a memorandum of understanding (MOU) to co-operate in the development of a gas-fired power plant in Vietnam that will use LNG.



The Russian gas producer will work alongside France’s Total, Russia’s Zarubezhneft and Germany’s Siemens on an “integrated energy-generating project with the use of liquefied natural gas (LNG) within the Socialist Republic of Vietnam,” it said in a statement.

“The Vietnamese market is of great interest to us as the country’s economy and demand for electricity is forecast to grow at a fast pace creating favourable conditions for gas-fired power generation and LNG supplies,” noted Novatek chairman Leonid Mikhelson.

State-owned PetroVietnam signed off on a 30-year production sharing agreement with Zarubezhneft on the offshore Block 16-1/15 in May. The project has the same partners as another Vietnamese MoU signed for Ninh Thuan province late in May.

There has been a flurry of interest among foreign investors in LNG-fired power projects in Vietnam, which has fallen behind in developing its energy sector as coal and oil projects have lagged. Several projects to develop LNG terminals are in the planning stages.

Russia’s Gazprom signed MOUs in 2016 over exploring the possibility of using gas from joint projects offshore Vietnam, as well as Gazprom’s LNG, for power generation. More recently, The US Trade and Development Agency and Vietnam Electricity signed a grant agreement for technical assistance for an LNG terminal and gas-to-power project for Vietnam’s southern region.

PNOC, LLOYDS SIGN LNG MOU: REPORTState-run Philippine National Oil Co. (PNOC) and Lloyds Energy have signed a memorandum of understanding to explore the possibility of developing LNG facilities in the Philippines, Philstar reported June 26.

PNOC said it signed an MoU with Lloyds Energy to “explore cooperative ways for the development of LNG facilities and natural gas generation plants and other related activities” in government properties in Limay, Bataan, Bauan, Batangas, and Mabini, Batangas, the newspaper reported.

The MoU also explores the viability of oil import and storage, the state-run firm said. PNOC CEO Reuben Lista said the team-up with Lloyds Energy would not affect its prospective partnership with Phoenix Petroleum Philippines and China’s Cnooc.

“Both are exploratory and without exclusivity

clauses. These steps will encourage also the private sector to consider these directions,” he said.

In March this year, Phoenix Petroelum and Cnoon signd an MoU with PNOC to allow PNOC to be part of the LNG project being developed by Tanglawan Philippine LNG —a joint venture between Phoenix and Cnooc.

The MoU with Lloyds will also allow PNOC to provide a strategic alliance in further developing the Tanglawan LNG project, with the government-run corporation’s involvement in the areas of pipeline infrastructure and franchise, banked gas, equity, and other marketing opportunities, Philstar reported.

GERMAN LNG TERMINAL TENDERS FOR EPCGerman LNG Terminal will start the engineering, procurement and construction prequalification (EPC) process for its planned 8bn m³/yr (6mn metric tons/yr) LNG terminal in northern Germany “this month,” it said June 19.

Potential EPC contractors will receive a prequalification package and can submit lump-sum offers between August and October. The winning bidder(s) will be announced in the first quarter of 2020, followed by the release of an early (or limited) notice to proceed to start scheduled early activities.

German LNG Terminal is a joint venture of Dutch companies Vopak and Gasunie as well as German company Oiltanking, part of Marquard & Bahls. They share a “firm commitment to build Germany’s first LNG terminal.”

Vopak and Gasunie have already successfully joined forces to build and operate the Gate terminal in Rotterdam, where capacity was all sold on long-term reservation contracts, meaning that the shippers bore the financial risk of underutilisation.

German LNG Terminal said Brunsbuettel offers easy access to markets in northwest Europe, Scandinavia and the Baltics and is close to Hamburg with LNG bunkering potential. It is also in the ChemCoast Park, which has industrial customers with high energy needs. It enjoys strong support from both local and federal government as it would contribute to gas supply diversification and provides efficient supply chains for LNG as an alternative fuel.

The market’s reaction to the Brunsbuettel terminal project has been positive, the JV said. with interest from future customers reflected in the execution of several heads of agreements – including one with Swiss Axpo, which is considering Canadian LNG from the planned



Goldboro project, due to take final investment decision this year.

There are also plans for another LNG terminal on the German coast, which was being promoted by Uniper. However, in recent months its senior staff have all left or given notice to quit, as Finnish Fortum seeks more control of the company and blamed management for being obstructive. Uniper’s new CEO and CFO only began work this month, while the commercial and technical officers leave later this year.

FINLAND INAUGURATES TORNIO LNG TERMINALFinnish state utility Gasum formally opened its €100mn ($112mn) LNG regasification terminal in Tornio June 11. The port lies in an industrial region near the border with Sweden.

The terminal will supply natural gas to Outokumpu’s Tornio steel mill and LNG to local industries, mines and other consumers. LNG from the terminal will also be supplied to the LNG storage facility, also supplied by Wartsila, at the SSAB Raahe steel mill.

The terminal supplies LNG as fuel to ships, such as the new icebreaker Polaris, operating in the Gulf of Bothnia. Truck access to the terminal allows fast and efficient deliveries of the LNG, Gasum said. The terminal will be able to process some 40 metric tons/hour, Gasum said.

The new terminal significantly enhances the area’s competitiveness by ensuring the availability of energy that is affordable, has low emissions and can be used by local industry, as well as maritime and heavy-duty traffic, Gasum said.

The terminal was built by joint venture Manga LNG, comprising the Outokumpu and SSAB steel companies, EPV Energy and Gasum. Manga LNG CEO Mika Kolehmainen said: “Previously, the only LNG terminal in Finland was in Pori – some 600 km to the south. The Tornio terminal is equipped with bunkering stations for LNG vessels, regasification equipment for LNG, as well as a storage unit that is 50,000 m³.”

Gasum’s LNG boss Kimmo Rahkamo told NGW that the plant had some additional funding from the state, but nothing from the EU. The LNG will come from the owners’ portfolio, which includes some of Gasum’s own production near Stavanger in Norway, he said. Capacity is open for third parties, but for the owners, for whom the plant is a sunk cost, it will be cheap to

operate. Rahkamo said that the LNG would displace propane, in the case of the steel mills.

Wartsila will serve the Tornio Manga LNG terminal under a 10-year maintenance agreement. This agreement ensures reliable gas send-out and maximises uptime of the LNG terminal, it said, without disclosing the value of the contract.

TURKISH LNG IMPORTS CLIMBTurkey’s LNG imports continued to increase in early 2019, despite a sharp drop in overall imports, a report released June 27 showed.

Gas imports dropped by 10.3% year on year in the first four months of 2019 to 17.93bn m3, Turkey’s Energy Market Regulatory Authority (Emra) reported. However, LNG imports increased by 16% to 5.18bn m3 over the same period. Imports from the US soared from 191mn m3 to 804mn m3 during the four-month period.

In contrast, pipeline imports fell by 19.6% to 11.918bn m3. Purchases from Russia were hit hardest, as they dropped 39%. Imports from Iran declined 2.5%. However, Azeri gas purchases grew by 48%, driven by the start up of the Trans-Anatolian gas pipeline (Tanap) from the middle of last year.

Despite the sharp decline of imports, Turkish consumption dropped by no more than 1% to 20.115bn m3. That saw stored gas used to make up the difference, with the 1.47bn m3 volume in underground facilities and LNG terminals at the end of the period around half the level recorded in April 2018. Turkey’s gas exports to Greece also increased in January-April, by 22% year-on-year to 227mn m3.

NEW FORTRESS AGREES TO BUILD ANGOLAN LNG TERMINALUS-based New Fortress Energy (NFE) announced June 5 that it had signed a memorandum of understanding (MOU) to develop an LNG terminal in Angola.

Under the MOU, signed with a trio of Angolan ministries, New Fortress would fund, build, and operate an LNG import and regasification terminal that will



be used to supply gas for power generation and to industrial facilities across Angola, New-York-based NFE said in a statement. The company offered no details regarding the capacity, timescale or cost of the potential project. Angola is presently an LNG exporter.

NFE added that as part of the agreement, it will also work with the ministry of mineral resources and petroleum to explore the development of additional indigenous natural gas resources and a domestic liquefaction facility.

“The signing of this MOU is the first step in moving Angola to become a gas economy,” Angola’s minister of mineral resources and petroleum, Diamantino Azeved, said.

“This partnership will provide cleaner, affordable natural gas to Angola, creating significant economic and environmental benefits,” said New Fortress CEO Wes Edens. “With Angola’s transition to a gas economy, significantly lower fuel costs will encourage further investment and directly benefit Angolans.”

The Angolan government announced the same day that it has launched a six-year licensing cycle which includes 10 high-potential blocks in the Namibe and Benguela Basins.

EVOL LNG, ADAMAN RESOURCES SIGN LNG AGREEMENTAustralian LNG distributor Evol LNG has signed a long-term LNG supply agreement with resources company Adaman Resources, it said June 17.

Evol LNG will supply LNG to Adaman Resources’ wholly-owned subsidiary Kirkalocka Gold SPV located in Western Australia. Kirkalocka gold mine is set to restart operations after more than a decade. The mine will use LNG to fuel Zenith Energy’s 14.5 MW power station, with supply planned to commence from September, Evol LNG said June 17.

Evol LNG and Wholesale manager, Nick Rea, said the use of LNG as an alternative to diesel will help minimise the mine’s carbon emissions. “LNG produces 25% less CO2 emissions than diesel, and during the initial six years of operation, the mine will avoid 50,000 metric tons of greenhouse gas emissions by fuelling its power station with LNG instead of diesel. This is the equivalent of keeping around 3,000 cars off the road,” said Rea.

Evol will build, own, operate and maintain the on-site LNG storage and vaporisation facility at the mine. “Utilising LNG as an alternative to diesel-fired generation will significantly reduce our energy costs and exposure to volatile diesel prices. Based on the current diesel price, we estimate our energy costs to be reduced by more than A$13mn (US$9mn) during the first six years of operation,” Adaman Resources CEO, Craig Bradshaw, said.

Rea said Kirkalocka was their third major contract in the mid-west in recent years, and sees huge potential for growth in this region. “The scarcity of gas pipelines and absence of grid power would otherwise force off-grid mines to use diesel for power generation, but we are able to provide a much better solution with LNG. It’s clean, safe, reliable and lower cost than diesel,” Rea said.

DNV APPROVES KAWASAKI’S LNG FLOATING POWER PLANT CONCEPTClassification society DNV GL has awarded Kawasaki Heavy Industries (KHI) an approval in principle (AIP) for their LNG floating power plant, it said June 11.

The LNG floating power plant is a decentralised energy generation solution that enables locations to tap into natural gas as part of their power mix. The concept is designed for installation in areas where energy demand is rapidly increasing, but onshore infrastructure is not feasible or commercially viable, DNV said.

As per the LNG floating power plant concept, the LNG would be offloaded from a carrier, stored onboard in two cylindrical (IMO type C) tanks, and then regasified for power generation and exported to the onshore grid. Regasification takes place in the fuel gas supply space facility located on the deck with the gas then fed into the gas engine power generation system, which is comprised of four gas-fuelled KHI engines.

The LNG floating power plant concept has been de-veloped based on KHI’s experience with onshore LNG receiving terminals and LNG containment systems, DNV added.

“After carrying out both a hazard identification study and a review of the design according to its rules, DNV GL has been able to issue an approval in principle for the concept. The AIP finds that the design complies with the DNV GL rules for Gas Power Plants in Part 6, Chapter 5, Section 20, that were introduced in 2018,” it said.



US SENATORS SEEK TO LEVELISE LNG FUEL TAXThree US senators said June 11 they had reintroduced bi-partisan legislation that would ensure excise taxes levied on LNG used as fuel in marine transportation on inland waterways were consistent with taxes applied to gasoline and diesel fuel.

The Waterway LNG Parity Act, reintroduced by Republican senators Bill Cassidy of Louisiana and Todd Young of Indiana and Democrat senator Michael Bennet of Colorado would account for the lower energy density of LNG relative to diesel.

About 1.7 gallons of LNG are needed to provide the same amount of energy as one gallon of diesel, but because fuel is taxed on volume and not energy content, a gallon of LNG attracts an excise tax of $0.50 while a gallon of diesel is taxed at $0.29.

Although LNG is a cleaner fuel than diesel or gasoline, the senators say the current application of the excise tax disincentivises its use.

“Natural gas is a clean, domestic energy source that should be treated equally to gasoline and diesel,” Cassidy said. “We should be encouraging the use and production of LNG.”

The LNG fuel and natural gas vehicle industries applaud-ed the move, saying LNG in marine, rail and road transpor-tation applications represents a “win” for the environment and is more economical than diesel or gasoline.

“LNG is domestic, clean, and abundant, ensuring that marine operators have decades of affordable fuel that produces near zero sulfur oxide emissions and significantly reduces particulate matter and nitrogen oxides,” NGVAmerica president Dan Gage said.

REDEXIS AND CEPSA TO CREATE LARGEST GAS REFUELLING NETWORK IN SPAINSpanish companies Redexis, an integrated energy infrastructure company, and Cepsa, an energy company, are to create the largest network of natural

gas refuelling stations in Spain, providing Compressed Natural Gas (CNG) for light vehicles and LNG for heavy vehicles.

Redexis will invest €30mn ($33.6mn) between 2019 and 2021 in the construction and maintenance of 50 gas refuelling points located at Cepsa service stations. Cepsa will handle the supply and sale of the gas. The alliance aims to have 80 service stations in operation by end-2023 on a total investment spend of €60mn.

The stations are to be built in urban areas and along key transport corridors. During the agreement signing ceremony, Fernando Bergasa, chairman at Redexis said, “this agreement … will enable … a huge step forward in both qualitative and quantitative terms in the provision of natural gas refuelling infrastructure in Spain.”

Natural gas vehicle (NGV) registrations in Spain were up 145% at 5,745 last year, according to the two companies, which said more conversions and new models were being offered on the market. They said manufacturers predict there will be around 80,000 light NGVs on Spanish roads in 2021.

NGVs in Spain attract less road tax than conventional internal combustion engine vehicles and are allowed to drive in emissions restricted areas. Cepsa and Redexis estimate that using gas as a fuel generates a 30% cost saving per kilometre, when compared with diesel and a 50% saving compared with gasoline. Some models can travel up to 1,300 km without refuelling thanks to bi-fuel gas/gasoline tanks.

ITALY’S SNAM BORROWS TO BUILD MORE NATGAS STATIONSItalian transmission system operator Snam has signed a €25mn ($28mn) loan agreement with the European Investment Bank (EIB) to build 110 filling stations for natural gas vehicles, it said June 11. Italy has more vehicles that run on natural gas than any other European country.

It wants to build 101 compressed natural gas (CNG) and 9 LNG/CNG refuelling stations for a total cost of €50mn. The loan, which as per EIB practice will amount to a maximum of half the cost of the investment, will


NEWS: LNG IN TRANSPORT

have a fixed rate of 0.547%. This is the first EIB loan obtained by Snam for its wholly-owned subsidiary, Snam4Mobility, which operates in the sustainable mobility sector.

These refuelling stations will be built as part of the company’s investment to strengthen Italy’s distribution network of natural and renewable gas (biomethane), which is one of the best technologies for sustainable mobility, both in terms of the economy and the environment.

Snam4Mobility has launched six stations in Italy with 60 more under construction, and Snam expects to build a total of 300 in the coming years. Snam’s commitment to sustainable mobility is part of the Snamtec project, launched with the company’s 2018-2022 strategic plan and supported by an €850mn investment in sustainability, technological innovation and new activities relating to the energy transition.

The loan will complement the European Union’s €1.3mn contribution provided through the CEF (Connecting Europe Facility) programme, obtained by Snam4Mobility last December for the construction of 9 L-CNG refuelling stations.

CANADA INTRODUCES NEW NGV ROADMAPThe Canadian Natural Gas Vehicle Alliance (CNGVA) released June 5 a new roadmap supporting the growing deployment of natural gas vehicles (NGVs) in the highway transport sector and highlighting the emergence of renewable natural gas that can magnify the emissions-reduction benefits of NGVs.

The report, Natural Gas Use in the Medium and Heavy-Duty Transportation Sector, or Roadmap 2.0 for ease, builds on a 2010 report by Natural Resources Canada that first examined gas use in transportation – Roadmap 1.0 – and found the medium and heavy-duty sector the most optimal target for development of natural gas options.

“This roadmap is an important tool for Canadians and industry to have more choices when it comes to transportation,” Canadian energy minister Amarjeet Sohi said. “Our government is working with partners to provide more options to get products and people where they need to go, while reducing pollution and growing our economy.”

Natural gas is already widely used by municipal refuse collection and public transit fleets, and is

gaining support in the over-the-highway trucking industry, as refuelling infrastructure continues to be developed along major highway corridors. And it is beginning to penetrate the marine transport sector: the Canadian LNG-fuelled ferry fleet is second in size only to that of Norway’s, and ferry operators in British Columbia and Quebec are continuing to grow their LNG fleets.

“At FortisBC, we are well-positioned to help our provincial government achieve its GHG emissions reductions goals in transportation by utilising abundant, low cost, cleaner burning BC natural gas,” said Roger Dall’Antonia, CEO of BC distributor FortisBC. “By converting vehicles and marine vessels to natural gas, we can cut GHG emissions while helping operators save on fuel costs.”

The report notes the existence of a strong business case for NGVs in Canada: the resource is plentiful, costs remain stable and high fuel-use fleets can benefit from costs savings compared with price-volatile diesel. Regulatory measures that favour the emissions reductions associated with a switch to NGVs only serve to accentuate the business case, noted Bruce Winchester, executive director of the CNGVA.

Adding renewable natural gas (RNG) to the mix can accelerate the reduction of emissions associated with more carbon-intense fuels. Using LNG as a fuel can reduce greenhouse gas (GHG) emissions by more than 25%; RNG can increase that reduction by nearly 82%, CNGVA said.

“Canada’s natural gas and biogas industries have taken a lead in exploring and outlining opportunities for RNG in Canada,” the report says. “The natural gas industry has outlined aspirational targets to blend 5% and 10% RNG content into their systems over the next two decades.”

CORALIUS COMPLETES FIRST ROTTERDAM BUNKERINGThe LNG bunker vessel Coralius, operated by Finland’s Gasum, completed its first bunkering operation at the port of Rotterdam in June, suppling fuel to the vessel Bit Viking, which was converted to run on LNG in 2011 and is owned by Tarbit Shipping. Anders Hermansson, technical manager for Tarbit Shipping said the ship runs on LNG about 97% of the time.


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“Being able to bunker our clients in the Amsterdam-Rotterdam-Antwerp area increases LNG availability and security for the LNG-fuelled fleet. The amount of LNG-driven vessels is growing rapidly globally, and we will definitely be part of the growth in being present where LNG is needed,” said Kimmo Rahkamo, Vice President, natural gas and LNG for Gasum.

Coralius will operate predominantly in the North Sea and Skagerrak area and has completed more than a 100 bunkering operations over the past 22 months. The vessel delivers LNG through ship-to-ship bunkering both in port and at sea, making LNG available to vessels unable to visit an LNG terminal.

Gasum expects the size of bunkering options to grow as more and larger ships adopt LNG as a fuel. The company said bunkering operations speed had also increased and was now almost as quick as oil bunkering.

INLAND BUNKER BARGE OPERATIONAL FOR TITAN LNGTitan LNG announced in June that its FlexFueler001 had performed its first official bunkering June 14 at the port of Rotterdam, supplying LNG to Norlines. Titan LNG is the first accredited LNG bunker supplier able to deliver by inland water barge. The LNG bunker permit for Rotterdam and the overall LNG bunkering accreditation were granted in May.

The FlexFueler001 is part of a series of vessels. Titan LNG will deploy the FlexFueler002, which is currently under construction, in mid-2020 in the port of Antwerp. The company expects to announce a third barge in coming months.

Samskip, operator of the LNG-powered Norlines Vessels, the Kvitnos and the Kvitbjørn, runs a weekly service into Rotterdam. Paul Wielaars, Trade Manager West Coast Norway said, “We are no longer dependent on truck-to-ship operations. Bunkering at the same time as cargo operations take place, can save us up to 8 hours.”

Titan LNG said the business case for LNG-powered vessels remains very compelling, adding that the economics have worked out well for early adopters of LNG as a marine fuel. The company said that LNG was currently priced at the same level as heavy fuel oil, but was compliant with emissions regulations for the North Sea Emissions Control Area and International Maritime Organisation.

GTT RECEIVES CHINESE ORDER FOR FIVE CONTAINER SHIP LNG FUEL TANKSFrench engineering company GTT has received an order from the Chinese shipyard Jiangnan Shipyard (Group) Co., Ltd. for the tank design of five new LNG-fuelled container ships of 15,000 TEU capacity each. The ships will be built on behalf of a European ship-owner and delivery will be staggered between the second half of 2021 and the first half of 2022.

GTT will design the LNG fuel tanks, with a capacity of 14,000 m3 per ship. The Mark III Flex membrane containment system, developed by GTT, has been chosen for its space optimisation allowing maximum usage of cargo capacity.

Philippe Berterottière, Chairman and CEO of GTT, said: “Less than 18 months after the first order for LNG-fuelled container ships, we are delighted to confirm, with this new order, the interest and effectiveness of our solutions to address the emerging environmental challenges for shipping.”

CONTAINERSHIPS TAKES DELIVERY OF 2ND LNG-FUELLED CONTAINER SHIPContainerships, a subsidiary of the CMA CGM Group, took delivery in June of its second container ship powered by LNG, the Containerships Polar.

The vessel will be phased into a redesigned BALT 2 service in the Port of Rotterdam from June 23. At the beginning of May, the 1,380-TEU vessel started its voyage from Guangzhou Wenchong Shipyard in China to Northern Europe, where it will operate alongside its sister ship Containerships Nord. The ship is ice-class and will operate in Northern Europe and the Baltics.

Its first LNG fuelling operation was expected at the end of June, via ship-to-ship bunkering in Rotterdam. Two more containerships, Containerships Arctic and Aurora, are expected to join the fleet by the end of 2019. CMA CGM Group expects to be operating 20 LNG-powered vessels by 2022.



FIRST CHINESE LNG BUNKER VESSEL BUILD ON TRACKChina’s fi rst seagoing LNG bunker vessel is expected to be delivered in early 2020 and go into operation shortly thereafter. It is being built by Dalian Shipbuilding Industry Corporation (DSIC) for an affi liate of ENN Energy holdings, one of the largest users of LNG in China. The vessel was designed by China Ship Design & Research Center Co. Ltd.

Finland’s Wärtsilä will provide the vessel’s cargo handling system, the Wärtsilä 34DF dual-fuel main engine, the gearbox, controlled pitch propeller, shaft generator and two Wärtsilä 20DF dual-fuel auxillary engines, as well as the ship’s sewage treatment plant. The integrated gas, propulsion, and waste treatment systems are designed to deliver high effi ciency with stable and clean operations.

“This project is China’s first LNG bunkering vessel with a C type tank and is another milestone for DSIC in the gas carrier market. It follows the successful delivery of a Very Large Ethane Carrier with a capacity of 85,000 m3 -- the world’s largest C type tank,” said Richard Hu, Marketing Director, DSIC.

The 8,500 m3 capacity bunkering vessel isthe first newbuild LNG vessel for ENN Energy Holdings and is part of the group’s ambition toplay an active role in the international marine LNG fuel supplier market. With this bunker vessel, ENN will be able to supply fuel to the world’s biggest LNG-fuelled vessels.

The new vessel will be based at the newly-opened ENN Zhoushan LNG receiving & bunkering terminal in China’s eastern Zhejiang province. In addition to providing bunkering supply operations, it will also carry out gas testing services for LNG carriers and other LNG-fuelled vessels.

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CHINESE GIANTS BUY INTO RUSSIAN LNGRussian independent Novatek reported in June that it has signed off on the sale of stakes in its Arctic LNG 2 project to two Chinese state giants. Share purchase agreements for 10% stakes were signed with China National Petroleum Corporation (CNPC) and China National Offshore Oil Corporation (CNOOC). The agreements will close “in the nearest future” pending approval by Russian and Chinese regulatory authorities, Novatek said in a statement.

The announcement came shortly after Novatek had announced it will team up with a Chinese state fund to develop shipping services to export LNG from its projects. Chinese gas demand continues to grow dramatically. The country is now the world’s second-largest importer of LNG, and is expected to overtake Japan to take the top spot in the coming years.

The deals with the Chinese buyers were first announced in April. In March, France’s Total took a 10% stake, leaving Novatek with 70%. Novatek CFO Mark Gyetvay said in May that the company was in talks to sell a further 10 % stake in Arctic LNG 2 – which will have three LNG trains of 6.6mn mt/yr each, liquefying gas from the Utrennee field in Russia’s far north – in order to raise funds to pursue its ambitious development plans.

Novatek wants to hold 60% in Arctic LNG 2, so another 10% stake is about to be sold, the company official told a conference. “In a relatively short time we will announce a fourth partner,” he said.

AUSTRALIA’S LNG LTD UPDATES MAGNOLIA COSTAustralia’s Liquefied Natural Gas Limited (LNGL) said June 24 it had agreed an updated lump-sum turnkey engineering, procurement and construction (EPC) contract with the KBR-SKE&C joint venture (KSJV) that will direct construction of the 8.8mn mt/yr Magnolia LNG project in Louisiana.

The updated agreement reflects the entire scope of the original EPC contract, amended to include updated

subcontractor pricing, costs associated with increasing liquefaction capacity by 800,000 mt/yr and additional scope of work by the KSJV that was previously the responsibility of LNGL.

LNGL CEO Greg Vesey said the agreement provides for an EPC cost of $4.623bn, providing an installed capacity cost of $525/mt/yr of liquefaction capacity.

GLX GETS FIRST LNG BID ON EUROPEAN PLATFORMCommodity trader Trafigura June 20 placed the first bid on LNG trading marketplace GLX’s Europe LNG bid-offer platform a day after its launch, GLX said June 21.

The firm bid was placed by Trafigura directly into the marketplace in real-time, following the platform’s launch. “Trafigura’s participation underpins the company’s strategy to bring greater transparency and liquidity to the LNG market,” GLX said.

Marc Howson, GLX’s managing director LNG Market Development, said the launch of the Europe bid-offer platform comes at an important time in the evolution of the LNG market.

GLX was launched in 2016 and its LNG trading platform became operational the following year. Woodside became a foundation member of GLX in July 2017.

PAVILION ENERGY BUYS IBERDROLA’S LNG ASSETSSingapore’s Pavilion Energy has entered into an agreement to purchase the portfolio of LNG assets of Spanish Iberdrola, it said June 20, without naming the price.

The portfolio comprises about 4mn mt/yr of Iberdrola’s long-term sale and supply LNG contracts. It also includes long-term regasification of some 2mn mt/yr at the Grain LNG terminal (UK), regasification access in Spain and Spanish-France border pipeline capacity, as well as the time-charter of a newbuild MEGI LNG vessel, Pavilion said.


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The two parties have also concluded a gas sales agreement for Pavilion Energy to supply natural gas in Spain to Iberdrola Generacion Espana.

The acquisition was entered into by Pavilion Energy Trading & Supply, a wholly-owned subsidiary of Pavilion Energy. The closing of this transaction will take place on January 1, 2020.

MALAYSIA’S SERBA SECURES MULTIPLE CONTRACTSMalaysian engineering services provider Serba Dinamik Holdings said June 18 that its subsidiaries have won seven contracts.

Serba Dinamik International, Serba Dinamik Holdings’ wholly-owned subsidiary, has won a three-year ringgit 250.62mn ($60mn) operations and maintenance (O&M) contract from Pavilion Qatar Engineering, the company said in a stock exchange filing.

Another wholly owned subsidiary, Serba Dinamik, has secured one engineering, procurement, construction and commissioning (EPCC) contract and five O&M contracts.

The five O&M contracts have been awarded by Petronas Chemicals Fertiliser Sabah, Malaysian Refining Company, Malaysia LNG, Kebabangan Petroleum Operating Company and PC Myanmar (Hong Kong). Serba Dinamik won the EPPC contract from Petronas.

The O&M contracts have no specific value as the contracts are on a ‘call-out’ basis whereby the work orders will be awarded at the discretion of the clients based on its activities schedules and rates throughout the duration of the contracts, Serba Dinamik Holdings said.

“The contracts secured are expected to contribute positively to the SDHB Group’s earnings for the financial year ending 31 December 2019,” it said.

SINGAPORE’S AEI, CHINA’S ZHONGNENG TO COLLABORATE IN LNG BUSINESSSingaporean aluminium producer AEI Corporation and China’s Zhongneng International Gas June 13 entered

into a framework agreement to work together in the LNG business, AEI said June 17.

The two parties plan to jointly procure at least 6mn metric tons/year of LNG from the international market and purchase LNG ISO containers to be used on the Yangtze River Basin. They also plan to incorporate a joint venture entity in Shanghai to undertake LNG trading and logistic activities. The joint venture firm will supply LNG for power generation to Zhongneng, AEI said.

In addition, Zhongneng has agreed to AEI’s participation in the investment and construction of port facilities, and the operation of LNG ISO containers projects located along the Yangtze River. AEI is also expected to participate in the establishment of structured funds for the related LNG logistics facilities and trade investment, it said.

Zhongneng is in the business of import and purchase of LNG, domestic sales and warehousing logistics and distribution, logistics facilities construction and equipment manufacturing. Zhongneng International Petrochemical, a China state-owned enterprise, holds 51% equity in Zhongneng International Gas.

TOTAL TO PICK UP 30% STAKE IN INDIA’S ADANI GAS: REPORTFrench major Total is expected to buy a 30% stake in Indian city gas distribution (CGD) firm Adani Gas for over $800mn, Times of India reported June 14.

The deal, if confirmed, is expected to trigger an open offer to public shareholders. After that, promoter Gautam Adani and Total might hold equal stakes in the company. The deal size could be well above $1bn, the newspaper reported. Adani owns a 75% stake in Adani Gas which was listed recently.

The company, a part of Adani Group, won additional geographical areas (GA) in the ninth and tenth rounds of CGD bidding. With these wins, Adani Gas is now authorised for 19 GAs and its joint venture with Indian Oil is also authorized for 19 GAs for natural gas network development and distribution, making it one of the leading CGD players in the country.

Adani Gas currently operates CGD networks in five locations: Ahmedabad, Baroda, Faridabad, Khurja and Palwal. Its joint venture with Indian Oil is currently running CGD networks at Prayagraj, Chandigarh,


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Panipat, Udham Singh Nagar, Daman, Dharwad, Ernakulam and Bulandshahr.

Last year, Total and Adani Group announced they will jointly develop LNG terminals and fuel retail outlets in India.

TOTAL TO BUY TOSHIBA’S US LNG ASSETSFrance’s Total has signed an agreement with Japan’s Toshiba Corporation to take over its portfolio of US LNG business, the French firm said June 1.

The deal includes a 20-year tolling agreement for 2.2mn mt/year of LNG from Freeport LNG train 3 in Texas and the corresponding gas transportation agreements on the pipelines feeding the terminal. Train 3 of the Freeport LNG plant is expected to start commercial operations by Q2 2020.

Under the transaction, Total will acquire all the shares of Toshiba America LNG (TAL) for $15mn to be paid by Total to Toshiba and will be assigned all contracts related to their LNG business by Toshiba Energy Systems and Solutions for a consideration of $815mn to be paid by Toshiba to Total, the French company said. Total will therefore receive from Toshiba a net cash consideration of $800mn payable at the closing date. The proposed transaction is subject to required approvals and is expected to close by the end of 2019.

“The takeover of Toshiba’s LNG portfolio is in line with Total’s strategy to become a major LNG portfolio player. Adding 2.2mn mt/yr of LNG to our existing positions in the US, in particular Cameron LNG, will enable optimisations of the supply and operations of these LNG sources,” commented Philippe Sauquet, president Gas, Renewables and Power at Total. “Already an integrated player in the US gas market, Total is set to become one of the leading US LNG exporters by 2020 with a 7mn mt/yr portfolio.”

Toshiba in a separate statement said that with the close of the transfer, TAL will be deconsolidated from Toshiba Group, and it expects to record a loss, including related expenses, of some yen 93bn ($860mn) in its consolidated business financials.

The Japanese firm last year agreed to sell the US LNG business to China’s ENN Group. However, the deal was scrapped by ENN in April this year.

TRAFIGURA PROFITS DOUBLE, US LNG HELPSTrading house Trafigura Group delivered a strong performance during the first half of the company’s financial year to March 31. US crude and LNG exports were among the causes, it said June 11.

Group revenues were flat at $86.297bn compared with $86.935bn in the first half of 2018, as trading volumes and average commodity price levels were broadly in line with last year. But profit for the period rose by 92% to $426mn from $222mn.

The company’s restructured oil trading operation was able to quickly adapt to increased price volatility caused by geopolitical events during the period, as well as to benefit from its market-leading position in strategic commodity flows, notably the increase in exports of crude oil and LNG from the US, the company said, without providing details.

Gross profit was $1.472bn, up by half from $979mn in the first half of 2018. Gross profit margin was 1.70%, up from 1.13% a year ago. Earnings before interest, tax, depreciation and amortisation were close to a record at $1.112bn, compared with $658mn a year ago.

Gross profit in oil and petroleum products trading was $1.035bn, nearly three and a half times higher than in H1 2018. While all of the division’s books performed well during the period, the crude oil, gasoline, LNG and wet freight desks were the stand-out contributors, although the volume traded was down 7%. Gross profit in metals and minerals fell by about a third to $437mn, despite 3% more volume traded compared with this time last year, reflecting a slow start for the non-ferrous concentrates and refined metal books.

GAZPROM, OMV INK LNG AGREEMENTThe CEO of Russian pipeline gas export monopoly Gazprom Alexei Miller and his counterpart at Austria’s OMV Rainer Seele have agreed to co-operate further in LNG.

The two companies had previously agreed that Gazprom will supply 1.2bn m³ of gas as LNG in 2020,



but under an agreement signed June 7 they have now agreed to extend this beyond 2020 and to include the sale and purchase of conventional and small-scale LNG cargos, Gazprom said.

In addition, both companies intend to explore options for the joint development of small-scale LNG infrastructure projects.

Seele said: “We have been receiving reliable gas supplies from Russia for more than 50 years. Now we are extending our co-operation to LNG. This will contribute to the diversification of sources of supply and help us safeguard security of supply in Europe.” OMV has LNG regasification capacity in the Netherlands.

From January 1, 2020, the flow of Russian gas across Ukraine – Austria’s principal import route – will be regulated by European network access rules, according to Naftogaz Ukrainy, as the present 10-year contract expires December 31. But, so far, no terms have been agreed between Russia and Ukraine for even a short-term contract and there are fears of supply disruptions. Gazprom’s 55bn m³/yr Nord Stream 2 subsea pipeline is not expected to be running by the end of the year.

CHART INDUSTRIES SECURES $1.1BN IN FINANCING COMMITMENTSUS LNG and industrial gases equipment provider Chart Industries announced June 5 that it has secured $1.1bn in financing commitments from banks.

The funds will power Chart’s $592mn acquisition of Harsco Corporation’s Industrial Air-X-Changers business (Harsco AXC). Chart has called the purchase a significant step towards executing its strategy to focus on cryogenic expertise for the industrial gas and energy spaces. The deal, which Chart reports has received accelerated antitrust clearance, was expected to close July 1.

The new financing commitments consist of a revolving credit facility that will replace and extend Chart’s existing $550m revolver, and a new term loan, both of which were oversubscribed.

Harsco AXC is projected to generate net sales of some $260mn in full year 2019 and 23% Ebitda margin as a percentage of sales. “With over $20mn of cost

synergies expected in the first 12 months of ownership, we expect further margin expansion in the business,” Chart said in a statement.

“We are very pleased with the overwhelming support from existing and new banks to offer committed funding to Chart,” said Chart Industries’ CEO Jill Evanko. “Their support further affirms the strategic direction of this acquisition and our plan for profitable future growth.”

The company also reiterated its full year 2019 sales guidance of $1.41bn-$1.46bn. The guidance assumes LNG project revenue in 2019 from the Venture Global Calcasieu Pass and Golar Gimi projects of $28m-$30m. Capital expenditures for 2019 are expected at $35mn-$40mn, “which includes the build out of an LNG fuel systems production line in Europe,” the statement added.

AIE AWARDS CONSTRUCTION CONTRACT FOR OZ IMPORT TERMINALAustralian Industrial Energy (AIE) June 3 said it has awarded the wharf facility and pipeline construction contract for its LNG import terminal Port Kembla near Sydney.

The contract has been awarded to SCSB joint venture, which comprises Spiecapag and Soletanche Bachy. Late in May, AIE reached a preliminary agreement with energy retailer EnergyAustralia to supply gas from the proposed LNG import terminal.

Planning design is underway for the terminal and construction will commence immediately after the AIE joint venture partners complete their final investment decision (FID), which is expected later this year, AIE said. In April, the A$250mn (US$176mn) Port Kembla terminal received developmental consent from the New South Wales government.

Construction work will include dredging, a new wharf within the existing Port Kembla dock and the pipeline to connect the new facility to the east coast gas network at Cringila. AIE plans to import up to 100 petajoules/yr (2.67bn m3/yr) starting from 2020 at Port Kembla.



RUSSIA’S VEB TO FUND LNG-FUELLED TANKERSState-owned Sovcomflot secured June 7 financing from Russia’s state development bank VEB for the construction of three new LNG-fuelled tankers. Russia’s largest shipping company initially placed an order for the vessels with the Zvezda Shipyard at the end of December. They are scheduled for delivery in 2022-2023, Sovcomflot said.

Each tanker will have a deadweight of 51,000 metric tons and they are intended to transport petroleum products and gas condensate, operating under 20-year time charter agreements with Novatek, which produces and markets condensate as well as gas.

The vessels will have an Ice Class 1B classification, enabling them to provide safe and reliable year-round transportation for hydrocarbons in challenging ice conditions, in particular within the Baltic Sea. The company has identified LNG as a core segment of its long term strategy.

“The company already successfully operates six new-generation Aframax tankers, which are powered by LNG fuel. Five more LNG-powered vessels have been ordered by Sovcomflot from the Zvezda shipyard and will be built over the next few years,” said Sovcomflot CEO Sergey Frank.

VEB Leasing specialises in funding transportation. It previously participated in financing the Sovcomflot’s Aframax tankers.

NOVATEK, SOVCOMFLOT AND CHINA TEAM UP ON LNG SHIPPINGRussia’s Novatek announced June 7 that it has agreed with Russian shipper Sovcomflot and China’s Silk Road Fund and Cosco Shipping to establish a joint venture to carry LNG exports from its Arctic projects.

Under the agreement, the quartet will establish a long-term partnership: Maritime Arctic Transport (Mart). The new company will allow joint development,

financing and implementing of year-round logistics arrangements for shipping hydrocarbons from Russia’s Arctic zone, a statement from Novatek said.

Mart will work on shipping Russian gas to the Asia-Pacific region, as well as organising transit cargo traffic along the Northern Sea Route between Asia and Western Europe.

The Silk Road Fund was launched by Beijing in 2014, and is the leading finance provider to projects under the Belt and Road Initiative – the state strategy to run Chinese-owned infrastructure across Asia and into Western Europe.

“The agreement represents an important milestone in developing the transportation of LNG produced by our Arctic projects along the Northern Sea Route,” noted Novatek chairman Leonid Mikhelson.

“The development of Mart will facilitate the rapid transformation of the Northern Sea Route into a global and commercially effective transportation corridor between the Pacific and Atlantic basins, as well as in the implementation of the decision made by the leadership of the Russian Federation to increase Northern Sea Route annual cargo traffic to 80mn mt in 2024.”

GASLOG ENDS COOL POOL ARRANGEMENTMonaco-based vessel operator GasLog has decided to assume commercial control of its vessels operating in the LNG carrier spot market through The Cool Pool, it said June 6.

The Cool Pool, set up a few years ago when the market was long, is an LNG carrier pooling agreement between GasLog and Golar LNG focusing exclusively on spot fixtures of up to 12 months in duration.

“Golar’s declared intention to spin off its spot LNG vessels, coupled with the Group’s belief that robust LNG commodity supply and demand fundamentals will lead to a tightening LNG shipping market and increased multi-year charter opportunities, have led it to decide to withdraw its vessels from The Cool Pool,” the company said.

“Assuming commercial control of these vessels will allow the Group greater flexibility and agility in pursuing longer-term time charter opportunities. This will


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enhance the Group’s ability to deliver on its strategic objective of optimizing fleet employment across spot and term markets and maximising vessel utilisation, earnings and value,” GasLog said.

The five vessels owned by GasLog and the one vessel owned by GasLog Partners now operating in the spot market will withdraw from The Cool Pool over coming months as contracts expire, GasLog said. GasLog CEO Paul Wogan said that the tightening market was a good time to place more of them on longer-term charters to optimise earnings. Customers had expressed more interest in multi-month and multi-year charters, he said.

First up is the GasLog Shanghai, which will now be able to secure an attractive term charter, said GasLog.

SAMSUNG HEAVY WINS ORDER FOR TWO LNG CARRIERS

South Korean shipbuilder Samsung Heavy Industries (SHI) has received a $380mn order for two LNG carriers from a Bermuda-based entity, it said June 7 without disclosing the identity of the customer.

These vessels will be delivered by the end of June 2022, SHI added. With this order, the company has received orders for 10 LNG carrier so far this year. SHI has also received an order for one FPSO, it said. SHI’s order for 11 vessels is valued at $3bn, 38% of the full year target of $7.8bn. The company said it is continuing to win orders “despite shrinking shipbuilding orders worldwide.”

MOL, GAIL SIGN LNG CHARTER AGREEMENTJapan’s Mitsui OSK Line (MOL) has signed a short-term LNG carrier charter agreement with India’s biggest gas marketing firm Gail, it said June 20.

Gail holds a portfolio of about 14mn mt/year of LNG from various long and short-term contracts. In addition to its main supplier, Qatar’s RasGas, Gail also has long-term contracts with Gazprom and ExxonMobil (Gorgon LNG). The company also two US LNG contracts: one is with Cheniere and one with Dominion. Both are indexed to the most liquid US gas hub, the Henry Hub.

MOL said it has been participating in the Indian market since the beginning of LNG imports into the country, having brought the first gas from Qatar. MOL is participating not only in LNG transportation, but also projects in India for floating LNG receiving terminals and ethane transportation by the world’s first Very Large Ethane Carrier.

DAEWOO SHIPBUILDING, DNV INK FRAMEWORK AGREEMENTDaewoo Shipbuilding & Marine Engineering (DSME) and DNV GL have signed a framework agreement which will see them cooperate on joint development projects for future technologies in the shipbuilding and offshore plant industries, DNV said June 13.

DSME and DNV plan to develop technologies to maximise the safety and efficiency of ships and offshore units. Planned joint studies include 3D model hull approval, the estimation of allowable wave heights for a 174,000 LNG floating storage and regasification unit, and a structural safety assessment for Solidus which is an LNG cargo containment system developed by DSME, DNV said.

DNV presented DSME with a general approval for ship application (Gasa) for the Solidus LNG cargo containment system. “Solidus uses a high-performance and environmentally friendly insulation material developed with BASF, to lower LNG boil-off rates. In addition, to optimise the safety of the system and prevent LNG leakage, DSME has incorporated two metallic barriers into Solidus,” DNV said.

“DNV GL’s approval of Solidus is a great milestone for DSME, marking our leadership in LNG technology,” DSME CEO Sung-Geun Lee said. “The Solidus design improves the newbuilding productivity and significantly reduces costs, making it a big step forward in developing the LNG carrier industry for shipbuilders and suppliers.”

N-KOM ACHIEVES OPERATIONAL MILESTONENakilat-Keppel Offshore & Marine (N-KOM) recently completed its 200th LNG vessel repair at the Erhama bin Jaber Al Jalahma Shipyard, Nakilat said June 11.


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Chartered by Qatargas and operated by NYK LNG Shipmanagement, the 135,295 m3 vessel, Al Khor, completed general drydocking maintenance repairs and upgrades at the shipyard.

This is third time the moss-type LNG carrier Al Khor is calling for repairs at the facility, having previously been drydocked in 2014 and 2016, Nakilat said. In addition to regular maintenance, the vessel also underwent water ballast steel renewal and tank treatment, hull treatment, as well as several surveys and endurance tests during the drydocking period.

Earlier this year, N-KOM successfully completed its fi rst fl oating storage regasifi cation unit (FSRU) project for the 138,000 m3 FSRU Excelerate owned by Excelerate Energy. During its period at the Erhama Bin Jaber Al Jalahma Shipyard, the FSRU underwent routine drydocking and repairs, in addition to modifi cations and retrofi tting of several new systems, including the installation of a ballast water treatment system.

QATARGAS DELIVERS BIGGEST LNG CARGO TO TURKEYQatargas June 23 said it has delivered the largest single cargo of LNG to the Marmara LNG terminal in Turkey. The cargo was delivered on board the Q-Flex vessel Al Sheehaniya, which became the fi rst ever Q-Flex vessel to call at the recently expanded Marmara LNG terminal, Qatargas said.

The Marmara terminal is owned by Turkish state Botas and was originally designed to accommodate conventional size vessels, and recently went through upgrades to accommodate both Q-Flex and Q-Max vessels.

Al Sheehaniya is a Q-Flex class LNG vessel with an overall cargo carrying capacity of 210,000 m³. It loaded a cargo of about 207,000 m3 of LNG at the Ras Laffan terminal in Qatar May 30 before heading to Turkey.

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