LNG Condensed

VOLUME 02 | ISSUE 03 | MARCH 2020

Insight and analysis for the global LNG industry Feature: Covid-19 could boost Central Asian plans to access South Asian gas markets

Feature: Improving fortunes for Indonesian gas?

oil price spells The collapse in the for the LNG even more trouble ffering from industry. Already su ergy demand has surplus capacity, en e easures to retard th been hard hit by m virus (Covid-19). spread of the corona and long-term LNG l oi le hi w , er ev ow H likely to remain contract prices look 21 could be a major low, spot LNG in 20 evitable rebound. beneficiary of the in

Country focus: Turkey: LNG intake rises

Project Spotlight: PFLNG DUA

Technology: Liquefaction tech – a key decision

INDEX

05 FEATURE: Volume Wars

09 FEATURE: Covid-19 could boost Central Asian plans to access South Asian gas markets

20 COUNTRY FOCUS: Turkey: LNG intake rises

PROJECT SPOTLIGHT: PFLNG DUA

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

27 TECHNOLOGY: Liquefaction tech – a key decision

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LNG News ..........................................................

30

Global LNG .................... 31 Supply ............................. 35 Demand ......................... 40

Copyright 2020 Minoils Media: LNG Condensed Managing Director: Rick Gill rick.gill@naturalgasworld.com Events/Advertising: Joao Salviano joao.salviano@naturalgasworld.com

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FEATURE: Improving fortunes for Indonesian gas?

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Editorial .............................................

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Corporate ..................... 44 In Transport ................. 51 Shipping .......................... 54

Editorial: Ross McCracken ross.mccracken@naturalgasworld.com William Powell william.powell@naturalgasworld.com Design: Jeremy Seeman contact@jeremyseeman.com

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EDITORIAL

M

easures taken to contain the spread of the coronavirus (Covid-19) are hitting the world hard.

Energy demand, particularly from transportation, is falling sharply, while the curtailment of industrial activity is widespread and sufficient to send the global economy into recession. Governments around the world are responding with fiscal and monetary stimuli, but they are unlikely to have much impact while countries effectively lock down economic and social activity.

For the oil and gas industry the effects look calamitous.

The sharp reduction in demand in a situation in which global oil and gas supply was already in surplus prompted calls for deeper production cuts from the Opec+ group of producers. These failed over a lack of agreement between Russia and Saudi Arabia. The result has been a decision

by Riyadh to open the taps and let the market decide where the price of oil should lie. The result has been an unprecedented collapse to less than $25/barrel for US benchmark West Texas Intermediate.

LNG producers and project developers thus face two sudden radical changes to the investment outlook: the impact on global growth of Covid-19 and thus of future demand for gas and LNG; and a new pricing environment in which there is no output restraint to stabilise the price of oil on which the majority of long-term LNG contracts still depend.

The first impact is almost certain to be a sharp curtailment in upstream spending. The North Sea oil and gas industry has already said it expects upstream investment to slump by a third. The short-term effects could also be severe as the nature of rig and supply chain work means staff do not have the home work option.

While many observers have focused on the price collapse, Covid-19 restrictions could have an immediate impact on many oil and gas companies’ operational capacities.

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At $25/barrel, almost all US shale drilling is uneconomic as is new investment in the Canadian oil and gas sector. US gas production has proven very resilient to low gas prices in the past, but is inextricably linked to the fortunes of shale oil, which can be expected to see a sharp contraction, if such low oil prices prove prolonged.

This raises a huge level of uncertainty for the next wave of hopeful US LNG developers: will cheap feedstock gas be available and will foreign demand for LNG rebound postCovid-19?

Three other groups will be assessing the new uncertainties – the big portfolio players, financiers and LNG buyers.

The big portfolio players have shown a willingness to fund LNG plants via their own balance sheets and by taking offtake into their own portfolios. How viable is this strategy now? Buyers will be re-evaluating their long-term LNG requirements and the terms on which they contract supplies. Financiers will be assessing the risks of lending into an already over-supplied market in the light of a sudden and unexpected demand-side shock.

The result is likely to be a phase of paralysis and emergency cutbacks. The oil and gas services sector, will be hit very hard. Few if any new LNG projects are likely to be sanctioned until the dust has settled.

Maybe Saudi Arabia’s aggressive production strategy will eventually force other producers back to the negotiating table and a new agreement on output cuts will be reached.

Maybe Covid-19 is contained and economic activity returns to normality.

Right now, it is impossible to know. The oil and gas industry is thus faced with a huge drop in expected revenues which upends all current plans and introduces massive uncertainty into the economic outlook for the next six to 12 months at least. The industry has little choice but to hunker down and ride out the storm: extensive losses can be expected before it is over.

— NGW

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PHOTO: FLICKR.COM/KEES TORN

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PRICE COLLAPSE

CONTRIBUTORS ROSS MCCR ACKEN Ross McCracken was managing editor of S&P Global’s flagship 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.

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.

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 first 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.

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Ross McCracken

The collapse in the oil price spells even more trouble for the LNG industry.

Already suffering from surplus capacity, energy demand has been hard hit by measures to retard the spread of the coronavirus (Covid-19). However, while oil and long-term LNG contract prices look likely to remain low, spot LNG in 2021 could be a major beneficiary of the inevitable rebound.

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lthough new pricing formulas have proliferated in recent years, the majority of LNG is still sold on long-term contract indexed to oil, usually with a lag of about six months. The fall in the oil price will serve to even out the large disparity between spot LNG prices and long-term contract prices linked to oil, but only by bringing both to very low levels -- in some cases below the combined cost of producing or acquiring feedstock gas, liquefaction and transportation.

A massive hit to LNG producers’ incomes appears inevitable, threatening both existing production and future plans for expansion.

Take for example Qatar’s huge planned enlargement of LNG production from its North Field, which would be sustained largely on the back of revenues accruing from the co-production of condensate. In the space of a month, those projected revenues have been cut by more than half.

In the US, oil prices hovering around $30/barrel for Brent and below for the US marker crude West Texas Intermediate herald a major contraction in shale production.

05

Financial crisis rebound - global oil and gas demand Gas (% increase)

Oil (mn toe)

Oil (% increase)

6,000

8

5,000

6

4,000

4

3,000

2

2,000

0

1,000

-2

0

2005

2006

2007

2008

2009

2010

2011

% increase

bn m 3 and mn toe

Gas (bn m3)

-4

Source: BP Statistical Review of World Energy

Break-even levels vary between shale plays, but only a very small minority of producers will be able to cope with sub-$40/b prices let alone sub-$30/b. Forward price hedging will protect some producers in the short term, but not if low oil prices are sustained.

US gas production’s near constant expansion over the last decade reflects the upstream connection with oil as almost all shale wells produce a combination of liquids and gas. There have been few periods like today, when US shale has been tested by both low oil and gas prices.

From 2015, when Saudi Arabia also embarked on a strategy of maximum output, US gas production plateaued and then fell before recovering when the Opec+ group was formed, throwing a life line to US shale producers by cutting production.

“ There have been few periods like today, when US shale has been tested by both low oil and gas prices.”

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However, with the US shale sector again likely to experience severe contraction, the outlook for final investment decisions on new LNG plants is poor. Not only do the export economics look very weak, despite cheap domestic feedstock, but the continuing domestic output expansion on which they are predicated may now simply not occur in the time span developers had previously expected.

OIL DYNAMICS A key question is how long will the oil price remain low?

Oil prices were already falling as the implications of measures taken to contain Covid-19 became clearer. This reversed a period of optimism at the beginning of the year in which the US and China approved phase one of a trade deal and a hard Brexit was avoided.

China’s ability to honour its side of the trade agreement, in terms of purchases of US energy and other goods, now seems hugely constrained, particularly given that the commitments looked over ambitious in the first place.

With demand falling due to Covid-19, Saudi Arabia pushed for deeper and longer cuts in

06

105,000

10,500

100,000

10,000

95,000

9,500

90,000

9,000

85,000

8,500

80,000

8,000

75,000

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

US field production of crude oil ( ‘000 b/d)

US gross gas withdrawals (mn ft 3 /d)

Saudi Arabia’s earlier volume war - impact on shale

7,500 Source: EIA

production both from its own members and from the other oil producers which make up the Opec+ group, of which Russia is by far the most important. However, Moscow refused and Saudi Arabia responded by turning on the taps, presenting oil producers with a stark choice – either pull together and limit output or face all out competition. Russia has chosen all out competition.

It is a battle which Saudi Arabia can win, but only at great cost. The kingdom’s 2019 budget was expansionary and based on an unrealised oil price of around $80/b. Its 2020 budget is much more modest, but still assumes an oil price in the low $60s/b and incorporates some heavy cuts in government spending. Even though Saudi Arabia can offset the fall in price with greater output, an oil price in the low $30s for Brent means it will have to cut spending more and fall back on its substantial foreign currency reserves.

Saudi Aramco officials have been briefing the media that is it comfortable with oil around $30/b and that it can sustain output of 12mn b/d for a year without the need for further spending. Not only that, but it intends to launch a new program to expand its capacity to 13mn b/d.

This is fighting talk, but does not reflect the Saudi government’s spending commitments,

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owing to its involvement in the Yemeni civil war and its plans for economic transformation.

Riyadh’s strategy could have one of three outcomes: it drives higher-cost oil supply out of the market, mainly via the contraction of US shale oil production; it forces Russia back to the negotiating table and a new agreement on output restraint is reached amongst the Opec+ group; or Opec – for which read Riyadh -- buckles and takes on the burden of price stabilisation alone.

If current policy positions are maintained, oil prices are likely to remain in the doldrums well into 2021, if not longer.

RECESSION However, the unprecedented nature of the current situation stems from both the demand and the supply sides – Saudi Arabia’s volume war and the demand destruction of Covid-19.

Responses to the spread of the virus have caused a near cessation in non-essential travel with analysts now suggesting that the loss to oil demand could be as much as 10mn b/d.

Oil tanker rates have rocketed not just because of the volumes of oil pushed out by Saudi Arabia, but by the pressing need to find storage; putting oil on a tanker and letting it sit around is one option, albeit an expensive one.

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This is also a more immediate concern; oil and gas supply chains cannot cope with such a rapid and unexpected drop in demand. As storage options are exhausted, refineries will stop refining and, further upstream, production will be shut in because there will be nowhere for the oil and gas to go.

The downturn in the oil and gas industry will add significantly to the recessionary forces swirling around the global economy.

“ Assuming Covid-19 is defanged this year and the world economy avoids a recessionary spiral as a result of major government interventions, 2021 could start to look a lot better for LNG.”

CRISES EXPERIENCE Although too early to assess the full impact, the situation is comparable in magnitude with the 2008/09 financial crisis. This effectively reset former notions of both short and long-term energy demand, shifting the whole energy demand curve downwards. For the second time in just over a decade, GDP growth will be lower for a period and start again from a lower base before returning to its long-run potential.

In 2007, the International Energy Agency, in its World Energy Outlook (WEO) reference case, envisaged oil demand growing from 84.7mn b/d in 2006 to 116.3mn b/d in 2030. Gas consumption would rise from 2,854bn m3 to 4,779bn m3, and global primary energy consumption from 11,429mn tons of oil equivalent to 17,721mn toe.

Two years later, in November 2009, in the wake of the financial crisis, expected oil demand in 2030 had been curbed to 105.2mn b/d, gas consumption would reach 4,310bn m3 and global primary energy consumption would be 16,790mn toe, a downward revision of 5.3%.

While the financial crisis was not the only factor at play in these revisions, (and the 2007 WEO itself was somewhat exuberant in terms of

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expected growth), it did reset long-term forecasts on a lower footing.

It even had a silver lining. At the International Association for Energy Economics conference in Vienna in September 2009, Fatih Birol, then IAE chief economist and now the agency’s executive director, declared that the climate change targets of the time “were no longer a fantasy.”

REBOUND PROSPECTS At the time of writing many countries around the world, including major economies, have declared emergency measures and even states of emergency in an effort to contain Covid-19, but there are also signs that infection rates in China have peaked. Pandemics do not last forever and a return to ‘normality’ will eventually occur, probably towards the end of the year or in 2021.

There should then be a substantial rebound in oil and gas demand, as there was after the 2008/2009 financial crisis. It is here that the oil and gas markets could potentially diverge.

Gas is harder than oil to store and there is less storage capacity overall as a ratio to normal demand than for oil and refined products. As a result, excess gas inventories should be drawn down quicker than oil and refined product stocks, which, in the most likely scenario, will continue to be bolstered by Saudi Arabia’s maximum output strategy.

In the 2008/2009 financial crisis, global gas demand, then much less dependent on China, continued to rise in 2008, falling in 2009 by 2%, but then rebounding sharply into a period of rapid growth. Gas demand in 2010 was a healthy 7.8% above 2007 levels.

In contrast, oil demand contracted in both 2008 and 2009, when it was down 1.6% on 2007 levels, but rebounded more slowly to be 1.8% above 2007 levels in 2010.

Assuming Covid-19 is defanged this year and the world economy avoids a recessionary spiral as a result of major government interventions, 2021 could start to look a lot better for LNG. Long-term oil-indexed contract prices will remain low, but spot LNG prices could make a comeback if some production is shut in this year and new planned trains in the US delay commissioning.

A further boost might come if major new LNG projects, the economics of which are dependent on the co-production of condensates, are also shelved for the time being.

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COVID-19 COULD BOOST CENTRAL ASIAN PLANS TO ACCESS SOUTH ASIAN GAS MARKETS Martin Daniel

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he future level of Asian LNG imports will be determined by many factors, among them the growth and composition of economic activity, the fortunes of coal, renewable energy, nuclear power and indigenous gas production. But for several key importers one of the main factors will be how much piped gas they buy from Central Asia.

These importers include China, India and Pakistan, which together accounted for less than 7% of global LNG imports in 2008, but more than 26% in 2018, according to BP data. The figure was higher still in 2019. Shell’s LNG Outlook 2020 noted that Chinese LNG imports jumped 14% year on year in 2019, while South Asian LNG imports rose 19%, both above the global increase of 12.5%.

Central Asian pipeline exports effectively mean gas from Turkmenistan, which had 19.5 trillion m3 of proven gas reserves at the end of 2018. This represents about a tenth of the world’s total proved reserves with a reserve to production ratio of 316.8 years. Uzbekistan with 1.2 trillion m3 and

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Turkmenistan holds around a tenth of the world’s proven gas reserves. Its options for export are limited and the coronavirus (Covid-19) pandemic has underlined its problematic reliance on pipeline exports to China. As a result, the TAPI pipeline project looks increasingly attractive, despite major political and security risks. LNG suppliers to South Asia could find that competition from Central Asian piped gas proves one of the long-term consequences of the Covid-19 pandemic.

The TAPI pipeline project faces major political and security risks

UZBEKISTAN

TURKMENISTAN Ashgabat

Galkynysh

Kabul

CHINA

Islamabad

Herat

AFGHANISTAN IRAN

PAKISTAN INDIA

Kandahar

Multan Quetta

Fazilka New Delhi

NEPAL Source: EIA

“ The main reason for TAPI’s limited progress is its security and political risks, which have ruled out any recourse to commercial financing.”

Kazakhstan with 1 trillion m3 are among the other Central Asian countries with significant reserves.

TAPI’S POTENTIAL Central Asia already exports large volumes of piped gas and could potentially supply much more, but uncertainty surrounds most of the new projects that could carry this gas to market. This is particularly true of the Turkmenistan-AfghanistanPakistan-India (TAPI) pipeline, which would export gas from Turkmenistan’s giant Galkynysh field to Afghanistan, Pakistan and India.

First mooted in 1995, the $10bn project is being developed by the TAPI Pipeline Company Ltd (TPCL), which is 85% owned and largely bankrolled by the state energy company Turkmengaz. The other sponsors are Afghan Gas

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Enterprise, Pakistan’s Inter State Gas Systems (Pvt) Ltd and Gail India Ltd, each with 5% stakes.

The pipeline would run 214km through Turkmenistan then 816km through Afghanistan, passing the cities of Herat and Kandahar. An 819km section through Pakistan would pass the cities of Quetta and Multan, before the line terminates at Fazilka in India.

Following completion, the capacity of the pipeline would ramp up to 33bn m3/yr, with the gas being supplied over a 30-year period to Afghanistan (5bn m3/yr), Pakistan (14bn m3/yr) and India (14bn m3/yr). However, the completion date for TAPI remains very unclear.

An official presentation about the project was made at a Turkmenistan oil and gas roadshow held in Dubai in February. The event provided little new information, merely repeating previous assertions that construction of the Turkmen and Afghan sections of the line had begun in December 2015 and February 2018, respectively. It added that work on the Pakistan section was due to begin this year.

Separately, Pakistan’s Petroleum Division said in early 2020 that project completion was scheduled for December 2023. This is significantly later than previous timetables for a pipeline until recently slated for completion in 2020. It is also unclear how much progress has been made on

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Key LNG growth markets (bn m3/yr) LNG imports

CHINA

Piped imports

300

300

INDIA

250

250

200

200

200

150

150

100

100

2008

2013

2008

9.4

43.6 34.2

35.6 35.6

58.1 27.5 30.6

18

49 31.1 2013

2018

0

2008

0

0

2018

50

0

0

40 29.4 11.3

50

4.6 0

25.1 27.4

50

47.9

73.5

81.9 80.9

100

121.8

150

161.5

171.9

250

PAKISTAN

34.6 34.6

300

Production 283

Demand

2013

2018

33.3

Source: BP Statistical Review of World Energy, 2019

China’s pipeline gas imports (bn m3/yr) 2018

24.4

2013

the various national pipeline segments, and thus how realistic the 2023 deadline is.

For instance, in January, a spokesman for the Afghan Mines and Petroleum Ministry was reported by local media as saying that legislation was still needed to acquire land for the Afghan section of the pipeline. He added that only then could construction start on a section of the line that has supposedly been under way since early 2018.

Turkmenistan

2.9 0

0.1

2.9

5.4

6.3

RISK CONCERNS

Kazakhstan

Uzbekistan

Myanmar

Source: BP Statistical Review of World Energy, 2019

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The delays and opaque status of TAPI have often been attributed to Turkmenistan’s quixotic president, Gurbanguly Berdymukhamedov, and his country’s labyrinthine bureaucracy. However, the main reason for the limited progress on the project is its security and political risks, which have ruled out any recourse to commercial financing.

The security risks relate to the vulnerability of the pipeline to attack, primarily but not exclusively in Afghanistan. The political risks centre on the longstanding tensions between Pakistan and India.

Some mitigation of the security risks was secured in 2018 when the Taliban expressed support for the project. The project got a further boost in late 2019 when TPCL agreed to pay for insurance to cover non-delivery of gas as a result of problems in Afghanistan. And it got another boost at the end of February with the signing of the US-Taliban peace deal.

However, the US-Taliban agreement is only the first step towards a wider peace deal needed to underpin the project’s

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82 73.5

Key markets, LNG imports 2018-2019

Share of projected additional LNG imports by region, 2019-2040 (%)

(bn m3/yr)

2019

31.32

Asia 74

29.51

2018

9.4

10.3

Europe 9

China

Pakistan

India Source: Various

“ PetroChina’s move has highlighted Turkmenistan’s considerable reliance on China, and is likely to result in the urgent pursuit of sales elsewhere.”

security. Moreover, political risks related to the mutual distrust between Pakistan and India could prove an even more intractable problem, especially given the current heightened tensions between the two countries over Kashmir and religious issues.

Terminating the project in Pakistan rather than India has been toyed with over the years, but the importance of the 14bn m3/yr of planned sales to India for the overall viability of the project would make this problematic.

Moreover, while the differences between Pakistan and India are profound, they agree on one issue; both believe the price of gas initially agreed with TPCL is too high given the recent fall in LNG prices.

Pakistan officials said in January that the price agreed for TAPI gas was up to 10% higher

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Source: Shell LNG Outlook 2020 (February 2020)

than the prevailing price of LNG, according to local press reports. As a result, the country’s Economic Coordination Committee decided to delay construction work on the Pakistan section of the project until the price had been renegotiated with TPCL. TAPI’S ATTRACTIONS While TAPI faces severe obstacles and its completion in 2023 appears highly improbable, it still remains attractive to all the participants. It would provide substantial transit revenues plus gas for Afghanistan; diversify Turkmenistan’s sales portfolio; and help Pakistan and India meet their burgeoning gas demand, while providing a counterbalance to LNG imports.

Reaching new markets is a key concern for Turkmenistan since its prospects for exporting gas to Europe through a trans-Caspian pipeline appear increasingly remote, at least in the medium term.

Ashgabat is also determined to limit its reliance on exports to Russia and Iran, so TAPI is the only sure way of avoiding over-reliance on China.

This is an issue since China now seems a less staunch partner than appeared the case when the first three pipelines comprising the 1,833km

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Existing and planned Chinese pipeline gas supplies (bn m3/yr) Line

Capacity

Central Asia A to C

55

Central Asia A to C upgrade

5

Status Operational Planned for 2020

Myanmar

10

Operational but with actual sales of 3bn m3/ yr or less

Central Asia D

30

Planned for 2022, but currently stalled

Power of Siberia-1

38

Operational Dec 2019, 5bn m3 supply planned in 2020

Power of Siberia-2

30

Timing to be decided

Power of Siberia-3

n/a

Initial proposal only Source: Various

China-Central Asia Gas Pipeline System were commissioned between 2009 and 2014.

The three lines can deliver 55bn m3/yr of gas from Uzbekistan (10bn m3), Kazakhstan (10bn m3) and Turkmenistan (35bn m3). By February 2020, the pipeline system had delivered more than 300bn m3 of gas, with its deliveries outrunning China’s LNG imports each year from 2012 to 2016.

CHINA’S OPTIONS China’s LNG imports overtook piped imports in 2017. Moreover, the latest Chinese gas import pipeline to be commissioned was not the 30bn m3/yr fourth Central Asian pipeline (line D), but the 30bn m3/yr Power of Siberia-1 pipeline from Russia, which entered service in December 2019.

Line D would deliver gas from eastern Turkmenistan to China along a route passing through Uzbekistan, Tajikistan and Kyrgyzstan. But Line D is heavily delayed. Originally scheduled to enter operation in 2016, completion is now slated for 2022 at the earliest.

Work on the Tajik section of the line has begun, according to local press reports. However, in 2017, Uzbekistan said it was suspending construction of its section, and has yet to resume work. It also appears that Kyrgyzstan, which postponed the start of construction on its section in late 2019, has yet to begin work.

It has been claimed that one of the main reasons for Line D’s travails is that China wanted

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to delay receiving additional Central Asian gas.

While firm evidence for this claim is lacking, there is no question that China is currently seeking to cut back or defer its existing commitments.

On March 5, China’s biggest single gas importer, PetroChina, issued force majeure notices to its suppliers. Unusually mild winter weather combined with the impact of the Covid-19 outbreak on economic activity had left the listed subsidiary of the state-run China National Petroleum Corporation with overflowing stocks, and a cliff edge approaching in the form of the end of the winter heating season.

PetroChina’s move followed CNOOC’s declaration of force majeure on February 6.

However, whereas CNOOC declared force majeure on purchases from three LNG suppliers, PetroChina -- which sources two-fifths of its gas requirements from imports -- sent notices to only one LNG supplier, but all its suppliers of piped gas.

This is not surprising since over two-thirds of PetroChina’s imports are delivered by pipeline. These include a small amount from Myanmar and will in future include gas from the newly-commissioned Power of Siberia-1 pipeline. But most is delivered through the China-Central Asia Gas Pipeline System, which supplied 47.9bn m3 in 2019.

Few recipients of the force majeure notices were prepared to comment. However, Kazakh gas exporter KazTransGas, which had planned to supply 10bn m3 of gas to China this year, said on March 6 that it was discussing future supplies with PetroChina.

ASHGABAT’S QUANDARY None of this suggests that contracted Central Asian exports will not resume once the pandemic ends, nor that Line D will not proceed in the medium term. However, PetroChina’s move has highlighted Turkmenistan’s considerable reliance on China, and is likely to result in the urgent pursuit of sales elsewhere.

With trans-Caspian sales to Europe looking increasingly unlikely, at least in the medium term, and sales to both Russia and Iran increasingly unattractive, that means pressing for sales to South Asia through TAPI. The project may not be done quickly, but the pressure to implement it has ratcheted up several notches.

For LNG suppliers to the burgeoning South Asian market, competition from Central Asian piped gas sales could thus be one of the main long-term consequences of the Covid-19 outbreak.

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IMPROVING FORTUNES FOR INDONESIAN GAS? Neil Ford

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n a significant turnaround, the government of Indonesia says that plans to import LNG have been cancelled.

The minister for energy and mines, Ignasius Jonan, says the country will now “never” need to import gas, owing to several big projects being developed after many years of delay.

However, domestic demand is set to grow rapidly as the government seeks to increase the share of natural gas in the energy mix to maximise oil exports, so the gas industry is

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coming under demand pressure from both sides.

At the same time, the crash in oil and gas prices threatens the economic viability and timing of Indonesia’s new upstream projects.

DECLINING EXPORTS Indonesia’s position as a global LNG power has been steadily eroded since it controlled 40% of the global market in 1988. It now accounts for just 6% of global supply. Falling export volumes are not just a function of failings in the oil and gas sector, but the result of economic growth over the past 20 years, resulting in higher domestic energy consumption, with gas demand increasing in particular from gas-fired power plants and industrial companies.

The country has three operational LNG plants. The biggest is state-operated Badak LNG in Bontang, which has production capacity of 11.5mn metric tons a year from four trains, followed by Tangguh with 7.6mn mt/yr from two trains; and the single-train Donggi-Senoro, which was completed in 2015, with 2mn m/yr capacity. However, exports have declined as more gas output and also LNG production has been funnelled into domestic use.

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PHOTO: ISTOCK.COM/SAKKMESTERKE

Indonesia’s plans to reverse the long decline in its LNG exports could be derailed or at least severely delayed by the collapse of oil and gas prices.

The government has set ambitious new production targets for both oil and gas, but has also to meet rising domestic demand at a time when project economics have become very challenging.

Indonesian LNG plants and regasification terminals

Arun Regas 3.0mn mt/yr

Bontang 11.5mn mt/yr Donggi-Senore 2mn mt/yr

Lampung 1.8mn mt/yr

Nusantara 3mn mt/yr Regasification Terminals

Sengkang under construction 5mn mt/yr

Tangguh 7.6mn mt/yr

Abadi planned late 2020s 9.5mn mt/yr

Benoa 0.3mn mt/yr

LNG plants

Source: IGU

LNG exports fell from 23.6mn mt/yr in 2010 to 13.4mn mt/yr in 2018. Declining production on the Arun field in North Sumatra led to the Arun LNG plant being converted into a regasification terminal in 2014. Many of the country’s long-term supply contracts expired over this period.

Indonesia also began to eat into its own LNG production, joining the select but growing band of countries with both LNG liquefaction and regasification terminals. In 2012, the Nusantara floating, storage, regasification unit (FSRU) was completed with capacity of 3mn mt/yr. The Lampung (1.8mn mt/yr), Arun Regas (3mn mt/yr) and Benoa (300,000 mt/yr) projects have since followed.

ABADI LNG AT LAST Indonesia’s President Joko Widodo announced plans in early 2019 to introduce new oil and gas sector legislation to encourage greater investment, after years of criticism over the level of red tape. Foreign firms have also complained about unattractive investment terms, with the result that planned projects have been repeatedly delayed or cancelled.

As a result, Indonesia has failed to make the most of its 98 trillion ft3 of proven natural gas reserves,

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while oil production had also dropped steadily. Yet the planned new law has still not materialised.

Nonetheless, after years of decline, the government is now confident there will be sufficient gas to support the development of new LNG production capacity and increase the use of existing plants.

The biggest boost to the industry looks set to come from Inpex’s Abadi LNG scheme on its Masela block, south of the Tanimbar Islands and right on the maritime boundary with Australia. The Japanese company, which began exploration work on the block in 1998, originally planned to develop the field as a floating LNG (FLNG) project, but this was blocked by the government in 2016, forcing it to investigate onshore options.

Inpex now holds a 65% stake in the venture, with Shell owning the remaining 35%. Their project development plan for a 9.5mn mt/yr onshore plant, including the timetable, level of investment, financial terms and local supply, was sanctioned by the government last year.

In return for agreeing to an onshore development, the government has granted a 27year operating licence rather than 20 years.

Yet no final investment decision (FID) has been taken, with Inpex saying, prior to the current

15

Indonesia gas production, consumption and LNG exports (bn m3) Production

Consumption

LNG exports

100

80

60

40

20

0

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Source: BP Statistical Review of World Energy

drop in oil prices, that it hoped to take FID in the early 2020s, which implies first gas sometime after 2027. Project capital costs are estimated at 2 trillion yen ($18.4bn).

This would be the second big LNG project developed by Inpex, after it brought the Ichthys scheme on stream in Australia in 2018.

Inpex has already awarded a contract to Fugro to undertake a geophysical and geotechnical marine survey to support front-end engineering design (FEED) work on the offshore production infrastructure and pipeline.

There are believed to be a variety of engineering challenges on the project, including regional seismicity, subsea faulting and slope stability. The partners are also in talks over concluding long-term sales and purchase agreements for LNG from the onshore plant.

However, a significant proportion of the development’s output will go to meet domestic demand rather than exports. In February, the Japanese firm’s local subsidiary, Inpex Masela, signed memoranda of understanding with stateowned power company PT Perusahaan Listrik Negara (PLN) and PT Pupuk Indonesia concerning the supply of both LNG and natural gas to the domestic market.

This includes 150mn ft3/d of natural gas to a fertiliser and petrochemical project owned by

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Pupuk Indoneisa; and 2-3mn mt/yr of LNG to a gas-fired power plant operated by PLN. In a statement, Inpex said: “The long term supply of LNG and natural gas from the project is consistent with the Indonesian government’s focus on optimizing domestic natural resource utilization.”

UPSTREAM PROSPECTS BP is currently developing the Tangguh LNG Train 3 in West Papua with annual production capacity of 3.8mn mt/yr. This will increase total production capacity on Tangguh to 11.4mn mt/yr.

The field, which had proven reserves of 18 trillion ft3, was discovered in the 1990s and brought into production in 2009. Train 3 was due for completion this year, but engineering and procurement problems have been reported and it is now likely to be the second half of 2021 before it is completed.

The government’s Upstream Oil and Gas Regulatory Special Task Force (SKK Migas) has attributed the delay to a contractor’s financial problems and the impact of natural disasters on the production of construction materials.

The Bontang LNG plant could benefit too, if the Gendalo-Gehem project, which is the second phase of the Chevron-operated Indonesia Deepwater Development (IDD), were developed. Until

16

5

50

4

40

3

30

2

20

1

10

0

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Reserves (trillion m3)

Reserves to production ratio (yrs)

Indonesian gas reserves (trillion m3) and reserves to production ratio (yrs)

0

Source: BP Statistical Review of World Energy

recently it looked like it would be, as talks were underway between Chevron (62%), Eni (20%), a variety of smaller investors (18%) and SKK Migas over developing the project, with first gas targeted from the new development phase for 2025.

The first phase, named Bangka, came on stream in 2016, with an estimated 1 trillion ft3 believed to be in place, while Gendalo-Gehem holds an estimated 1.5 trillion ft3.

However, Chevron announced in January that it was considering selling its stake in IDD. In a statement, it said: “IDD Stage 2 was not able to compete for capital in Chevron’s global portfolio.”

Analysts GlobalData said in February that production from gas fields that supply existing LNG plants will decline over the next six years, but that gas supplies to LNG production could recover sometime after 2026 if the Abadi and GendaloGehem LNG projects were developed as planned.

In addition, more gas could be fed into the domestic market from the Kali Berau Dalam discovery that was made on the Sakakemang Block in South Sumatra last February. The Spanish company Repsol, which has a 45% stake in the licence, estimates reserves at 2 trillion ft3, making it the largest gas discovery in Indonesia in 18 years. Petronas holds 45% and Mitsui Oil Exploration 10%.

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If sanctioned, it could come on stream within five years.

Meanwhile, Badak LNG should have a new source of supply when the Merakes deepwater gas field comes on stream next year. Located just 170km from the plant, it is operated by Eni with an 85% stake, alongside Pertamina (15%). In addition, Pertamina’s Jambaran Tiung Biru project in East Java is scheduled to come on stream in the second half of next year. It will supply 170mn ft3/d to power plants from 2.5 trillion ft3 of reserves, helping to ensure domestic supply so that more LNG can be exported.

GOVERNMENT AMBITIONS Enthusiasm surrounding the various projects has prompted the government into setting a target of doubling natural gas production to 12.3bn ft3/d by 2030. This sounds like a very ambitious target, particularly as government officials have said that domestic demand would continue to take priority over LNG exports, with the domestic market taking 70% of total output by 2024, up from 35% at present. A separate target of boosting oil production from an average of 746,000 b/d last year to 1mn b/d by 2030 has also been set.

17

Indonesia: gas meets new power demand but displaces little oil (TWh) Oil-fired generation

Gas-fired generation

100

80

60

40

20

0 2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Source: BP Statistical Review of World Energy

Djakarta has begun talks with upstream companies and industry bodies over how the goals can be met. The executive director of the Indonesian Petroleum Association, Marjolijn Wajong told journalists: “Basically, we welcome the plan to increase production as long as we can figure out how to ensure good project economics.”

The government is particularly keen to boost hydrocarbon production to reduce the country’s growing deficit in oil and gas. The country had a $1.18bn deficit in oil and gas trade in January, almost three times as much as in the same month last year. Without it, the country would have had a surplus in overall trade, rather than the $864mn deficit it recorded for the month.

Total oil and gas revenues were $805.9mn this January, 34.7% lower than in the same month in 2019. The collapse in oil and gas prices in March will therefore serve to improve Indonesia’s overall trade balance, but limit funds for upstream development while making project economics highly uncertain.

DOMESTIC GAS DEMAND Djakarta has set a target of increasing the proportion of gas in the energy mix from 18.1% in 2018 to 22% by 2025. Given that SKK Migas forecasts a rise in total energy consumption from 185.5mn mt/yr of oil

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equivalent to 248.4mn mtoe over the same period, this would require a big absolute rise in gas demand and supply over the same period.

The government wants more gas-fired generation capacity and more power from renewable energy projects to reduce the share of oil in the energy mix from 45% in 2018 to 25% by 2025. A big increase in biofuels and using LNG as a fuel for trucks is planned to help achieve this highly ambitious target. The strategy is designed to prolong the life of the Indonesian oil industry; some reports suggest that existing fields could be exhausted by 2030 at current rates of recovery.

The state-owned gas transmission and distribution firm Perusahaan Gas Negara (PGN) has been given the task of ensuring that more gas-fired plants are developed. The government restructured the energy sector in 2018 to give Pertamina a 57% stake in PGN to ensure the smooth development of gas projects from field development, through pipeline construction and on to distribution.

PLN will convert some of its power plants from oil and diesel to gas, starting with 52 very small diesel-fired plants with combined capacity of 1,870 MW. PLN plans to reduce its diesel consumption from 2.6mn kilolitres last year to 1.6mn kilolitres in 2021.

18

Indonesia’s oil and biofuel production (1,000 b/d oil equivalent) Biofuels

Oil

1,400

1,200

1,000

800

600

400

200

0 2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Source: BP Statistical Review of World Energy

In early March, PGN announced that it would invest $2.5bn in regasification capacity and associated infrastructure in Nusa Tenggara, West Kalimantan, North Papua, Sulawesi and Maluku to supply gas to its power plants.

This policy of displacing oil with gas in the power sector could have a big impact on the country’s ability to export LNG. However, much will depend on the impact of Covid-19 on long-term economic growth and therefore energy demand.

At present, it appears that it could have a dramatic effect on growth over the forecast period. Shipments of LNG from Indonesia’s Tangguh plant to China’s Fujian province were already being postponed in February because of the outbreak. At this stage, cargoes have just been delayed by several months, but it seems likely that some will be cancelled entirely.

FUTURE PROSPECTS In a price environment capable of supporting upstream investment, a turnaround in Indonesian LNG exports looks possible, but current plans are almost certain to be held in abeyance until there is at least some stabilisation in the oil price.

The government had previously expected to start importing LNG by 2025, but the planned

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contract for Cheniere Energy to ship cargoes from its plant on the US Gulf coast to the Nusantara FLNG plant may now be cancelled. However, it remains to be seen if the rise in exports will be quite as dramatic as the government hopes because of the rapidly growing demands of the power sector.

Producing 1mn b/d oil and 12.3bn ft3/d of gas by 2030 is a very testing target, particularly as just two years ago the General National Energy Planning road map for the country’s energy future forecast falls in oil and gas production over the next decade, to 667,000 b/d and 5.8bn ft3/d by 2030 respectively. Further gas discoveries need to be made, if LNG exports are to be sustained, as demand from the power and petrochemical sectors is continuing to grow.

Indonesia should have the LNG capacity needed to boost exports if the feedstock is available. If Masela and Tangguh Train 3 are developed as planned, they would boost national production capacity to 33.1mn mt/yr.

Post Covid-19, there is likely to be plenty of appetite for Indonesian LNG, if output rebounds as much as the government hopes. Given its geographical location, almost all of Indonesia’s exports go to the huge LNG markets in East Asia: Japan, South Korea, Taiwan and China.

19

Country Focus:

TURKEY: LNG INTAKE RISES

Despite an overall fall in gas consumption, Turkey’s LNG imports rose in both 2018 and 2019, pushing it into the top rank of European LNG importers.

Keen both to diversify its import sources and reduce its dependence on Russian pipeline gas, the country was an enthusiastic buyer of US LNG last year.

Yet the country has also boosted its use of coal. If more ambitious decarbonisation policies are adopted, gas-for-coal displacement will be an obvious pathway to reduce carbon emissions.

T

urkey’s LNG imports reached a record 11.3bn m3 in 2018, according to official data, up from 5.9bn m3 in 2013. In 2019, a new record was set with imports of 12.69bn m3.

This was despite an overall drop in gas consumption of 9.0% to 44.89bn m3 last year and a fall in total gas imports of 10.2% to 45.21bn m3.

Imports were particularly strong in the first half of the year, reaching a record high of 7.14bn m3, according to the country’s Energy Market Regulatory Authority, with LNG surpassing for the first time a 30% share in total first-half imports of 23.29bn m3. LNG imports were up 14% on the same period a year earlier even though total gas imports were down 10%.

In particular, Turkish imports of US LNG leapt 463% in the first half of 2019 from 191mn m3 in the same period of 2018 to 884mn m3. By contrast, Russian pipeline imports slumped 35.7%.

DIVERSIFICATION STRATEGY Two main factors have allowed Turkey to favour LNG over Russian pipeline supplies: the availability of low-priced volumes, and

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20

Turkish gas consumption and LNG imports (bn m3) Imports — LNG

Consumption 60 50 40 30 20 10 0 2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Source: BP Statistical Review of World Energy

Turkish gas imports 2018/2019 (bn m3)

Russia

A zerbaijan

2018

Iran

2019

Algeria LNG

Nigeria LNG

Other LNG Source: EPDK

the leverage and uncertainty created by Russia’s attempts to circumvent the Ukrainian gas system as a means of getting its gas to European markets.

At the same time, however, Ankara has sought to limit gas use for power generation, depending instead on the cheaper alternative of coal and lignite. Gas use for power generation fell last year by 38.3%, according to official data, from 18.2bn m3 to 11.25bn m3. Having played second fiddle to gas in the power generation sector for years, coal became the largest source of electricity generation for Turkey in 2016 and then by an even greater margin in 2018 and 2019.

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This lowest-cost strategy reflects the travails of the Turkish economy, which, having grown by 7.5% in 2017, saw its economic expansion slow to 2.8% in 2018 and zero in 2019. The slowdown has been accompanied by a deterioration in the country’s balance of trade, highlighting its dependence on imported energy. The reduction in power sector gas use in 2018 was a major contributory factor to the improvement in the country’s balance of payments.

Prior to the outbreak of the coronavirus (Covid-19), the World Bank expected a return to growth of about 3% in 2020, but that, as with other GDP forecasts in the current environment, is unlikely now to be realised.

21

Turkey: electricity generation by fuel (TWh) Coal

Gas

Hydro

Other renewables

Oil

350 300 250 200 150 100 50 0 2000

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Source: BP Statistical Review of World Energy

500

4,000

400

3,800

300

3,600

200

EU

4,200

3,400

3,200 2009

Turkey

Turkey out of step on carbon emissions (mn mt of CO2)

100

2010

2011

2012

2013

2014

2015

2016

2017

0 2018

Source: BP Statistical Review of World Energy

LIMITED CLIMATE AMBITIONS Turkey has stepped up its deployment of renewable energy sources such as solar and wind to take advantage of their low costs, so that, in 2018, renewables, not including hydropower, generated about 12.5% of the country’s electricity, up from 4.8% in 2014.

However, the growth in coal use means that if Turkey adopts a more aggressive decarbonisation strategy, gas-for-coal displacement would be an obvious pathway to large, short-term gains in greenhouse gas emissions, which should benefit LNG.

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Turkey is out of line with the rest of Europe when it comes to carbon emissions.

The country’s carbon emissions have been rising fairly steadily over the last decade from 276mn mt of CO2 in 2009 to 390mn in 2018, in contrast to the EU’s downward trend.

Slow economic growth and sharp hikes in the price of gas supplied by Botas to gas-fired generators have left many of the country’s gas plants idle.

RUSSIAN ANGLE Turkey imports gas by pipeline from Russia via the BlueStream pipeline, which has capacity of 16bn m3 a year and delivers gas under the Black Sea to make landfall in Samsun. In contrast, the Trans Balkan gas pipeline brings gas through Ukraine, Moldova, Romania and Bulgaria before reaching Turkey in the west. Gas coming via the Trans Balkan pipeline is being displaced by gas through the new Turkstream pipeline, which also runs under the Black Sea. Turkey also imports pipeline gas from Azerbaijan and Iran. Turkey has been taking more Azeri gas as volumes increase through the recently commissioned TransAnatolian Pipeline, but, for Russian gas, Ankara’s purchases have been falling well below contracted volumes with the shortfall made up for by LNG purchases.

22

Turkey: net trade in goods and services (BoP, current US $bn)

2016

2020

2021

-25.6 -39.0

-36.9

-23.9

2022

Source: World Bank

Russia’s Gazprom has been unable or unwilling to take a hard line with Turkish state-owned gas importer Botas because of its desire to commission two strings, each with capacity of 15.75nm m3, of Turkstream, which it did in January. Turkstream is the centre piece of Russia’s efforts to circumvent Ukrainian gas transits to south European markets.

Ankara appears to be using LNG and gas from its other pipeline suppliers to pressure Russia into more flexible supply arrangements. If an accommodation can be reached, some restoration of Russian pipeline import volumes is a clear threat to Turkey’s current enthusiasm for LNG, but equally could also be absorbed by an increase in gas use in the power sector.

LNG INFRASTRUCTURE Turkey has four regasification terminals, the first, Marmara Ereglisi, came on-stream in 1994. It is 100% owned and operated by Botas.

The second, Izmir Aliaga, was commissioned in 2006 and is owned and operated by the privatelyheld Egegaz, which is part of the Colakoglu Group.

Both are onshore terminals.

The country’s first floating, storage and regasification unit (FSRU) was added in 2017 at Etki with the FSRU Neptune and the second in 2018 at Dortyol with the FSRU Challenger. Etki is operated by Etki Liman Isletmeleri Dolgalgaz Ithalat ve Ticaret and Dortyol by Botas. Challenger is the largest FSRU in the world, but is slated to be relocated to Hong Kong in 2021.

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-68.9

-56.3

-42.8

-39.6

-34.0

-32.7

-27.0

-16.1

-6.0

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

-17.1 2019

+4%

+0%

2018

+4%

+2.8%

2017

+3%

+7.5%

Turkish economy under strain, GDP growth (%)

Source: World Bank

According to International Gas Union data, regasification capacities based on nameplate totalled 25mn mt/yr (34bn m3) at end-2018 -- Marmara Ereglisi 7.6, Aliaga 8.0, Etki 5.3 and Dortyol 4.1.

GIGNL, the International Group of Natural Gas Importers, puts total nominal capacity at 16.8mn mt/yr (Marmara Ereglisi 4.6, Aliaga 4.4, Etki 3.7 and Dortyol 4.1).

Gas Infrastructure Europe comes in at about 18mn mt/yr, with expansion plans of 2mn mt/yr at Aliaga and 2.7mn mt/yr at Marmara Ereglisi.

A third FSRU is planned for the Gulf of Saros in the Aegean with capacity of 3.8-7.6mn mt/yr.

Botas has a long-term contract with Algeria’s Sonatrach for 3.02 mn mt/yr, which was raised in 2018 to 3.21 mn mt/yr, with the expiry date pushed back to 2024. Botas also receives 0.91 mn mt/yr from Nigeria LNG, a contract which expires in 2021.

Turkey’s gas storage capacity is expected to rise from about 3.4bn m3 now to over 11bn m3 by 2023, constituting more than 20% of the country’s annual demand.

As a result, the infrastructure to import more LNG and consume more gas in the power sector is all in place, as, increasingly, are the major pipelines for Turkey to take up its longstanding ambition to be a major gas transit country. This all points to the emergence of an increasingly competitive market for gas imports into the country, one in which LNG will have a long-term role, even if future volumes depend heavily on Russian imports and Turkish power sector policy.

23

Project Spotlight:

PFLNG DUA

R

otan was the first gas field discovered on block H in 2007. The field is owned by Petronas and Thailand’s PTTEP (56%), which bought out US company Murphy Oil’s Malaysian assets last year.

Petronas’s foray into floating LNG (FLNG) technology is designed to arrest the country’s stalling LNG exports by exploiting gas fields too far from shore and/or too small to justify a subsea pipeline. The country’s gas production fell from 74.5bn m3 in 2017 to 72.5bn m3 in 2018, while consumption was broadly stable, falling 0.5bn m3

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to 41.3bn m3. LNG exports amounted to 33bn m3, the lowest level since 2012.

Although Petronas mooted the possibility of a third such vessel in December, no decision is likely at present, given the prevailing uncertainties regarding gas demand and oil and gas company revenues as a result of the coronavirus (Covid-19) and the ending of the Opec+ agreement from April. Commercial production from the PFLNG Dua is expected to start in November amid market uncertainties which could not have been predicted when the final investment decision to go ahead was taken in February 2014.

Such vessels, however, are long-term investments – PFLNG Dua is designed to operate for 20 years before dry docking and it thus likely to see a number of gas market highs and lows.

FLNG DEVELOPMENT Whether the FLNG sector continues to grow or not, the deployment of a number of bespoke and converted vessels in the last four years has been a significant development for the gas industry,

24

PHOTO: PETRONAS

Malaysia’s Petronas saw its second floating LNG vessel, PFLNG Dua, leave port under tow in February. The vessel will be moored through an external turret on the deepwater Rotan gas field, 140 km offshore Kota Kinabalu in block H, Sabah, Malaysia.

Malaysia’s Block H off Sabah, containing the Rotan gas field

MALAYSIA Buluh

Rotan

Hanks

Tembusu N & S

Bemba Rotan W

PHILLIPPINES

Saraca

Bates

Dolfin

CA-2

Bunga Lili

Bunga Lili South

Blk. H

Blk. P CA-1

Bunga Lili North

Sabah

SK Area

BRUNEI INDONESIA

• 2 Discoveries for 2012 - Buluh-1 - Bunga Lili-1 • 4 Discoveries/4 Wells

• Multiple low risk lookalike prospects remain • Total Resource: 1.5 - 2 TCF

Source: Murphy Oil

demonstrating its ability to monetise previously inaccessible reserves. This has extended the gas resource, both in terms of volume and location.

Although not the first to start construction of a bespoke FLNG vessel, Petronas was the first to finish, deploying the world’s first FLNG facility, PFLNG Satu, on the Kanowit gas field off Sarawak in 2016. Its sister ship PFLNG Dua is bigger with liquefaction capacity of 1.5mn mt/yr, compared with PFLNG Satu’s 1.2mn mt/yr. Both process lean gas.

DEVELOPMENT COSTS PFLNG Dua is also cheaper than Satu. A study of liquefaction plant costs by the Oxford Institute for Energy Studies in 2018, LNG Plant Cost Reduction 2014-18, put the project cost at $1,100/metric ton of annual capacity (mt/yr) and the onboard liquefaction plant at $825/mt/yr, in comparison

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with PFLNG Satu’s $1,290/mt/yr and $968/mt/ yr respectively. The lower costs reflected the increase in scale and experience, but also that the contract was awarded as an extension of the PFLNG Satu project and was able to take advantage of a weak fabrication market.

The costs compare very favourably with Shell’s first-of-a-kind Prelude project, the second bespoke FLNG vessel to be deployed, but Prelude is much larger at 3.6mn mt/yr LNG capacity and also produces condensates (1.3mn mt/yr) and LPG (0.4mn mt/yr). Satu and Dua do not have any liquids production.

One of the attractions of FLNG, in comparison with onshore LNG plants, is that shipyard construction provides a higher level of confidence in terms of both delivery schedule and costs.

Shipyards provide a controlled environment with high productivity. An IGU report, FLNG

25

FLNG extends Malaysia’s gas development reach (bn m3) Production

Consumption

LNG exports

Proved gas reserves (trillion m3)

80

70

60

50

40

30

20

10

0

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Source: BP Statistical Review of World Energy

Concepts: Facts and Differentiators, estimated that for an FLNG vessel 90% of commissioning can be completed within the shipyard prior to open water deployment.

However, the PFLNG vessels both come in at higher cost than for FLNG vessels constructed via conversion of an LNG tanker, the project costs of which the Oxford study estimated at $600/mt/yr.

Choosing newbuild over a conversion has both pros and cons. Newbuilds can be designed for a specific field application, while conversions suffer from some design limitations as a result of the existing carrier design. Newbuilds have higher capex and take longer to construct, but are also expected to have longer lives, therefore reducing the total cost of ownership.

CONTRACTORS Although led by Petronas, the project has involved a host of contractors bringing different elements of technology to the project. Swiss engineering company ABB designed, manufactured and installed the vessel’s electrical systems for Japan’s JCG Corporation, which was awarded

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the engineering and procurement contract.

ABB developed the world’s tallest single-lift prefabricated electrical structures, known as e-houses, for the facility.

Hull construction was undertaken by South Korea’s Samsung Heavy Industries at its Geoje shipyard. Air Products, via JCG, manufactured and supplied its proprietary AP-NTM LNG Process and Equipment, including coil-wound heat-exchangers, compressor-expanders and the economiser cold boxes. The AP-NTM LNG is an efficient nitrogencycle process, well suited to small-scale single train LNG developments and was also used for PFLNG Satu.

As part of a global frame agreement for equipment supply between Petronas and GE, GE Oil & Gas supplied four of its PGT25+G4 gas turbine generator systems and two nitrogen trains featuring two LM6000-PF+ 2BCL907 aeroderivative gas turbines in mechanical-drive mode.

PFLNG2 was classified by ABS. PACC Offshore Services Holdings was awarded contracts for four offshore support vessels, which by now should have delivered the pioneering vessel to its intended destination on the Rotan gas field.

26

Technology:

LIQUEFACTION TECH – A KEY DECISION

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S

electing liquefaction technology is one of the biggest choices facing any LNG project developer. Air Products & Chemicals (APCI) almost entirely dominated the sector in its early years, but although the company still holds a considerable lead, it is facing a growing number of competitors as projects become increasingly varied.

Before gas can be liquefied, condensates have to be removed and impurities, such as water, sulphur, mercury and carbon dioxide, taken out in case they cause blockages. The remaining dry gas is more than 90% methane and it is usually cooled to about -161°C, methane’s boiling point.

Liquefaction is achieved through a succession of refrigeration cycles using different refrigerants, but the process is complicated by the flammability of the gas.

Trains generally consist of a compression process, propane condenser process, a methane area and an ethane/ethylene area. The gas is cooled by a compressed refrigerant as it passes

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The market for liquefaction technology is dominated by two main players, but small-scale and floating LNG projects are driving innovation in the area, while newer companies, like Russia’s Novatek, are keen to develop their own processes.

Liquefaction technology providers are focused not just on increasing efficiency, safety and reliability, but also increasingly on greenhouse gas emission reductions.

Efficiency Driven Solution Mixed refrigerants enhance LNG technology by matching the composite cooling curves of natural gas liquefaction. Dual mixed refrigerant systems allow for higher capacity design. Black and Veatch’s PRICO-DMR® technology captures these advantages in one LNG solution.

Turbine/ Motor

WMR Compressor Gas Treating

Feed Gas

Heavies Recovery

Turbine/ Motor

NGL/Condenasate

CMR Compressor

LNG Storage CMR Expander

through aluminium coils before being transferred to storage tanks. There is most variation in the different technologies in the type of heating cycles and refrigerants employed.

Two main options exist, for large LNG production at least: a cascade process using several refrigeration cycles, with each refrigerant vaporising at different temperatures; and mixed refrigerant technology. The latter is more complicated, but is generally regarded as producing a more efficient plant design.

Developers have to make a decision on which technology to use at an early stage in project development, but the choice is often far from straightforward. Michael Scrivens, vice president and managing director of LNG export solutions

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for Black & Veatch’s oil and gas business, told LNG Condensed that each technology has merits based on project size and capacity, project location, and efficiency and utility requirements.

TWO BIG RIVALS The sector is dominated by two companies: APCI and ConocoPhillips. The former’s APC3MR liquefaction process is the market leader and it also offers its AP-X, SP Single Mixed Refrigerant and AP Dual Mixed Refrigerant technologies among other options.

ConocoPhillips focuses on one main technology, Optimized Cascade, which is the second most used option in operation today, licensed for

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use on 26 trains with production capacity of 106.3mn metric tons a year.

Four trains use APCI technology for every one licensed to use Cascade, according to the US Department of Energy (DoE), but this is partly a function of APCI’s early start in the industry.

For capacity built after 1995, the DoE says that the ratio falls to two-to-one, still in APCI’s favour.

Of the other competitors, Black & Veatch has developed more than 30 operational plants, but they generally have smaller capacities.

The AP C3MR process uses a mixed refrigerant of nitrogen, ethane/ethylene, methane and propane. The gas is cooled to about -35°C in the propane cycle, then to -90°C in the ethane/ ethylene cycle and to -155°C in the methane cycle. The process employs the company’s proprietary spiral-wound heat exchanger.

DoE analysts say the technology has “high efficiency, ease of operation and reliability, with the use of readily available refrigerant streams” but warns that the use of propane as a key refrigerant requires some risk mitigation because it is highly explosive and accumulates in low-lying areas because it is heavier than air. This requires the refrigerant storage tanks to be located well away from the main plant processes.

The AP-X process builds on the AP-C3MR technology, adding an additional driver for nitrogen refrigeration compression, which provides subcooling refrigeration for the liquefaction process. The size of the spiral-wound heat exchanger is maintained, but the additional driver takes some of the subcooling strain, giving production capacity of up to 7.8mn mt/yr on a single train. Six AP-X trains on this scale have been developed in Qatar, although some sources suggest that 10mn mt/yr would be possible.

OPTIMIZED CASCADE ConocoPhillips’ Optimized Cascade technology was first used by the Kenai LNG plant in 1969 and the company says the process has been licensed for use on a further 25 trains. The process is based on three multi-staged, cascaded refrigerant circuits using pure refrigerants. In a statement, the company said that it had “optimized the heat integration to closely approach the natural gas and refrigerant cooling curves, resulting in a highly efficient process.”

Optimized Cascade incorporates brazed aluminium heat exchangers and cold box

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modules for efficiency and use across a range of LNG train sizes. The treated gas is chilled and condensed to about -162°C in successively colder heat exchangers, using pure propane, ethane and methane as refrigerants to support heat integration because they are predictable.

In order to increase plant availability, one train of heat exchangers can be served by two parallel refrigeration turbine and compressor trains. ConocoPhillips trains often have production capacity of about 5mn mt/ yr, but the company believes that 6.5mn mt/yr would be possible.

Black & Veatch’s PRICO technology uses a dual mixed refrigerant to match “the composite cooling curves of natural gas liquefaction”, the company says. It argues that its technology needs a smaller plot size, requires lower capital investment and offers a simpler control system than competing technologies. Its standard PRICO technology can be used on trains with production capacity of up to 1.5mn mt/yr, but this increases to 3.5mn mt/yr with its PRICODMR design, which is based on EMR Technology licensed from ExxonMobil Upstream Research Company. It also markets PRICO for use on peak shaving, in vehicle fuel supply and for gas distribution systems TECHNOLOGY DEVELOPMENT Rather than seeking a technological step change from one model to another over the past few years, technology licensors have continually worked to increase efficiency for their various technologies with the aim of providing increased production for similar power requirements.

They have also sought to improve safety, particularly through the use of more advanced forms of data analysis. Scrivens of Black & Veatch said: “Advancements in predictive maintenance and analyzing continuous monitoring data has increased the reliability of equipment, thereby reducing maintenance intervals of some equipment and lowering the risk to workers.”

Looking ahead, two factors look likely to drive technological change. First, there is already substantial pressure on LNG producers to reduce their greenhouse gas emissions – of both carbon and methane. Second, the growing appetite for very small-scale and floating LNG projects may yield breakthroughs in liquefaction technology that could be replicated across the wider industry.

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CONFERENCES & EVENTS

6th International LNG Congress

Canadian Gas Dialogues

March 2-3 Brussels, Belgium lngcongress.com

April 1

stocexpo.com/en

LNG & Natural Gas Markets Asia

AOG Australian Oi & Gas Exhibition & Conference

April 16-17 Singapore, Singapore platts.com

March 11-13 Perth, Australia aogexpo.com.au

3rd CWC Japan LNG & Gas Summit

7th Annual International LNG Congress Russia

2nd CEE Small-Scale LNG Forum

Mar 23-27 Geneva, Switzerland unece.org/index.php?id=52506

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MAY

March 18-19 Moscow, Russia lngrussiacongress.com/en

Global Methane Forum 2020

April 23-24 Tokyo, Japan cwcjapanlng.com

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APR

Calgary, Canada The spread of the coronavirus naturalgasworld.com/gas-dialogues-events 6th CWC China LNG(Covid-19) & Gas has resulted in the International Summit & Exhibition Green Gasof Mobility Summit March 4-6 widespread cancellation Apr 1-2 Shanghai, China Madrid, Spain chinalnggas.com conferences and events and a greengasmobilitysummit.com/en CERAWeek severe curtailment of travel.

LNG 5th East and Southern Africa March 9-13 Gas & LNG Conference 2020 Houston, USA Condensed’s conferences and April 2-3 ceraweek.com Maputo, Mozambique events listings will return once StocExpo Europe 2020 szwgroup.com/east-southern-africa-gas-lng-conMarch 10-12 ference the situation has normalised.

Rotterdam, Netherlands

May 5-6 Warsaw, Poland ceesslng.com

Floating LNG Global May 11-12 Amsterdam, Netherlands informaconnect.com/flng

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news: GLOBAL LNG LOW CRUDE PRICE TO DELAY LNG INVESTMENT: TIMERA The almost halving of the Brent crude oil price has brought long-term oil-indexed contracts for LNG closer to spot market prices. This will keep LNG prices lower for longer, say energy market analysis company Timera.

The gap that had opened up between long-term oil indexed contracts and gas hub prices will now narrow substantially. That translates into further resistance to gas price recovery, at least across the Covid-19 demand shock horizon in 2020, it said in a research paper March 23.

This means cost relief for LNG buyers. Before crude fell, buyers of oil-indexed contracts faced contract prices well above current hub prices, but now with time they will see something closer to hubs assuming crude prices remain at or below $30/mn Btu and that hub prices do not fall any lower.

“For example, a $30/barrel crude price and 10% slope mean a contract gas price around $3/mn Btu. But “lower crude will typically take some time to feed into settled LNG contract prices due to averaging and lagging,” Timera said.

PIPELINE SUPPLIES LOW AS LNG RISES IN NW EUROPE: MAREX Europe’s imports of pipeline gas remain low, down by 22% in northwest Europe and by 17% in eastern Europe, according to analysis by Marex Spectron published March 19. Any deficit “is clearly balanced by steady rates of LNG imports, which have however declined on a weekly basis,” the report said.

It says the oversupply is now small, as storage destocking rates are around the norm after several weeks of lower than normal withdrawals. And “for the first time during the 2019/20 winter season, high pressure cells will build up over northern Europe and Scandinavia, pushing the jet-stream away from continental Europe and the UK. This will significantly decrease the wind output, supporting indirect demand. Temperatures are also set to dip.”

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But the positive impact on gas demand will be offset by economic stagnation, it warns. “Locally, Europe has been showing a decent pick-up in activity.... However, domestic demand will likely shrink due to the total or partial lockdown of many countries – this will certainly have a negative impact on all of the indicators that we monitor, and will influence the performance of gas demand for the weeks and months to come.”

RUSSIA ROLLS OUT ARCTIC TAX RELIEF Russia has introduced more tax relief for Arctic LNG export projects due to start operations from 2022, under a law signed by Russian president Vladimir Putin and published by the Kremlin on March 18.

A zero rate of mineral extraction tax (MET) will apply to fields that supply gas to liquefaction trains as well as petrochemical enterprises, during their first 12 years of commercial operation or until their cumulative output reaches 250bn m3. Rates of MET vary from project to project, although Fitch Ratings estimates that Gazprom paid on average $17/’000 m3 of gas extracted in MET last year, equal to 25-30% of the domestic sales price.

Only projects north of the Arctic Circle will be able to benefit from the new support.

The tax break will be a major boon for Novatek, which is preparing to launch its next major LNG export terminal, the 19.8mn mt/yr Arctic LNG 2, in 2023. The private gas producer secured significant tax breaks for its first terminal Yamal LNG, which entered production in December 2017.

During its first 12 years of operation, the project will pay no export tax, MET or property tax, while the profit tax it pays will be 13.5% lower than the usual rate. What is more, the Russian government helped fund some of the project’s infrastructure, including an airport, seaport and a fleet of icebreaking LNG carriers.

The zero rate for Arctic petrochemical ventures will primarily benefit Gazprom, which is understood to be planning a $14bn petrochemical hub on Russia’s northern Yamal peninsula. The hub will use ethane derived from gas fields in the area as its feedstock.

MET rates of 1% and 5% will also be set for offshore Arctic gas and oil projects during their first 15 years of

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production. Gazprom stands to gain here as well, as it operates a number of large fields containing trillions of m3 of gas in the Pechora and Barents seas. The first of these projects expected to enter production is Kamennomysskoye-more, located near land in shallow waters of the Gulf of Ob. It is due on stream in 2025.

Russia’s state oil producer Rosneft will also get extra relief for the Vankor oilfield and its satellites, which the company has suggested will form part of an Arctic megaproject that could one day yield 2mn b/d – equivalent to around a sixth of Russia’s total production.

The latest package of support measures were drawn up long before the sharp decline in oil and gas prices over recent months, as a result of Covid-19’s impact on demand and the breakdown of Opec+ talks. As long as current prices persist, the tax measures are unlikely to motivate producers to sanction any new projects in the high-cost Arctic region. But they may help entice investment if market conditions improve over the coming years.

AUSTRALIAN GAS EXPORT VALUE FALLS: GOVT Australia’s LNG export volumes are to rise to 81mn mt in the fiscal year ending March 31 2020, up from 75mn mt in the previous 12-month period, but prices and overall revenues are expected to decline, according to government statistics published March 18.

The real value of Australia’s LNG exports is forecast to decline from A$51bn ($29.9bn) in 2018-19 to A$49bn in 2019-20 and to just A$44bn in 2020-21, and remain in the A$44bn-47bn range to 2024–25.

Global LNG capacity has rapidly expanded over the last two years, with projects ramping up in Australia, the US and Russia. At the same time, demand growth has been slowing from the traditional Asian buyers. Weak demand has been further exacerbated by a warmer-than usual northern hemisphere winter, and the impact of Covid-19 in China, the report says.

While Asian LNG spot prices are forecast to recover from the current record lows, ongoing overcapacity in global LNG markets is expected to constrain the extent of any price recovery over the next two years.

After 2021, rising demand is expected gradually to close the gap on expanding global production capacity and support a rise in the Asian LNG spot price, the report says.

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Upstream lobby group Australian Petroleum Production & Exploration Association CEO Andrew McConville said the data reminded Australians of the critical contribution of our oil and gas industry. “At a time of great economic uncertainty arising from the current pandemic, Australia’s resources and energy exports are helping ensure that Australia has the financial ability to respond effectively and strongly,” he said.

ASIA PACIFIC MAY SEE $1BN CUT IN EXPLORATION SPEND: WOODMAC The oil price crash and the Covid-19 outbreak will lead to a cut in exploration spend in the Asia Pacific (Apac) of up to $1bn from an expected level of $4.5bn this year, Wood Mackenzie Asia Pacific vice-chair, Gavin Thompson said in a note March 17.

“Our Apac exploration team had been expecting around 200 exploration wells in the region in 2020. This could now fall by up to 30%. Most explorers will delay campaigns where a rig has not yet been committed or if the well economics at $35/b fail company thresholds,” Thompson said.

Only around one in seven prospects in Apac breakeven below $35/b, and most of those are smaller near-field prospects. With fewer wells drilled, Asia can expect a rising import requirement in future years, he said.

A sustained period of low prices will delay most upstream final investment decisions (FID) in the region. The biggest blow will be felt in Australia where companies are aiming to sanction large, strategically important backfill LNG investments in 2020. Significant projects in southeast Asia will also be pushed back, Thompson said.

Among those projects targeting FID in 2020, Australia’s Scarborough, operated by Woodside, and Barossa, operated by Santos, account for 52% of unsanctioned spend and 48% of reserves.

“Prior to the oil price crash, Santos and Woodside were already looking to farm-down their respective equity exposures to ease capital requirements. This will be challenging in the near-term as companies roll out capital management plans to control or delay discretionary expenditure. All projects vying for FID, but requiring a farm-down in equity exposure, will be challenged,” he said. “Looking across the Apac, close

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to $35bn of pre-FID and development spend is at risk in 2020-2022, and that’s before we consider potential cuts to existing spend on producing assets.”

The demand risk comes mainly from weaker demand outside China now that coronavirus is a pandemic.

Historically, low oil prices stimulate oil demand, but the extent to which low oil prices will help demand to recover this time is limited by obvious coronavirus containment measures, Thompson said.

According to Thompson, “Low oil prices are a mixed blessing for LNG markets. Sustained lower oil prices will bring down LNG contract prices in Asia, which have been at a premium recently, but also create greater competition from oil itself,” he said.

In Japan and South Korea, lower prices for oilindexed purchases should support coal-to-gas switching economics in the power sector. South Korea has seen some switching in recent months. High oil-indexed contract volumes dominate the weighted average cost of gas, resulting in strong 2019 prices around $10-12/ mn btu. But with the oil price fall, prices are set to halve over the next three to six months, bolstering the case for gas, Thompson said.

For China, at $35/b oil, contracted LNG arrives at a lower cost than domestic wholesale price benchmarks.

“While there is a strong incentive for NOCs to retain the benefits, the import cost reduction will be partially passed through and allow the government to push lower gas prices to end-users. This will help coronavirusaffected business resume operations but stimulating new coal-to-gas switching will still require further policy support,” Thompson said.

In other markets such as India, lower oil prices could slow the shift from oil to gas in the industrial sector, as heating oil, LPG and naphtha compete with contracted and spot LNG, he said.

UPSTREAM GROUP WELCOMES EU CLIMATE LAW The International Association of Oil & Gas Producers (IOGP) said March 4 that it supports the EU’s objective to reach climate neutrality by 2050, embodied in the draft European Union Climate Law. “We call on policy-makers to follow up on the Climate Law with an inclusive approach that promotes all available technologies and solutions equally, and encourage the EU to step up its engagement with its global partners to

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combine decarbonisation efforts,” it said.

“With the Climate Law, the EU sets a clear objective on the horizon. Reaching climate neutrality by 2050 will be an immense challenge for the EU as a whole.

We simply cannot afford to try and take shortcuts or to cherry pick solutions anymore. We need policy-makers to help deploy all large-scale alternatives: carbon capture use and storage and clean hydrogen from natural gas will be key,” said IOGP. The group’s members plan to minimise emissions linked to the production, processing and transport of its products, including methane leakage and flaring, as well as the electrification of platforms.

It sees natural gas as a cost-effective alternative to coal and enabler of renewable energy integration, but the group’s members will also invest more in other lowcarbon and renewable energies and services including wind, solar, batteries and biofuels. “We also pursue nature-based solutions essential to tackle emissions which are too difficult or technically impossible to avoid,” IOGP said.

“Oil and gas account for nearly 60% of EU energy demand today, therefore the involvement of our sector will be instrumental to making Europe’s transition to a cleaner energy system a success,” IOGP concluded.

However, the draft law does have shortcomings, according to researcher Andrei Belyi, who told NGW March 5 that all laws have a chapter of definitions of the terms used. This needs one in order to avoid conflicting interpretations, he said. Carbon neutrality, low-carbon and zero-carbon technologies in particular need to be defined, including the measurement of the carbon – different gases have different global warming potential over different time horizons.

This further implies a differentiation between various greenhouse gases, such as carbon dioxide, methane, and water vapours. “It is clear that the EU Climate Law doesn’t go into detailed distinction between different emissions and their uneven effect on the atmosphere,” he said.

AUSTRALIA TO SET UP NEW LNG, H2 RESEARCH CENTRE The Australian federal government along with industry, Western Australian state government and research partners will establish the Future Energy Exports Cooperative Research Centre (FEnEx CRC) in an

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forward “to working with the FEnEx CRC to investigate ways of shaping the Australian energy market into one that is even more efficient and contributes to a cleaner future energy mix at home and abroad.”

A foundation project of the FEnEx CRC will be establishing the LNG Futures Facility, a 10 metric tons/ day research and teaching plant to be based at Kwinana.

The project was announced by Western Australia premier Mark McGowan at the LNG19 conference in Shanghai almost a year ago. The state government committed A$10mn towards the plant as part of its LNG jobs taskforce commitments; UWA committed up to A$15mn. About A$16mn of the Commonwealth funding announced today will be allocated to the LNG Futures Facility, the UWA said.

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attempt to develop and test new LNG and hydrogen technologies, the University of Western Australia (UWA), which will lead the project, said March 13.

The federal minister for industry, science and technology, Karen Andrews, said the federal government will contribute a total of A$40mn (US$25mn) in cofunding to the CRC, which builds upon a further A$122mn in support from industry, state governments, and research organisations.

“The CRC’s mission is to ensure Australia’s vital LNG industry remains competitive, reduces its environmental footprint, and helps to grow hydrogen exports for new emerging markets,” the UWA said.

Upstream lobby group Australian Petroleum Production & Exploration Association said it looked

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news: LNG SUPPLY WOODSIDE DEFERS FID ON KEY PROJECTS

CANADIAN WOODFIBRE LNG FACES DELAY: PRESS

Australia’s Woodside Petroleum has deferred targeted final investment decisions (FID) on Scarborough, Pluto Train 2 and Browse and slashed approximately 50% in forecast 2020 total expenditure in response to uncertain market conditions created by low oil prices and the coronavirus (Covid-19) outbreak, it said March 27.

Total expenditure in 2020 is expected to reduce to approximately US$2.4bn. This includes an approximately US$100mn reduction in operating expenditure and a 60% reduction in investment expenditure to US$1.7 – 1.9bn, Woodside said.

Woodside will change the planned schedule at the Karratha gas plant, with Train 3’s turnaround deferred to September 2020 and Train 4 to August 2021. It will delay target FID for the US$11bn Scarborough project, which it owns with BHP, and Pluto Train 2 to 2021. The FID on Scarborough was expected in the first half of this year.

The FID on US$20bn Browse has been deferred to an unspecified date. The Browse joint venture partners are Woodside (30.6%), European majors Shell (27%) and BP (17.33%); a MitsuiMitsubishi joint venture (14.4%); and PetroChina (10.67%).

Both Scarborough and Browse projects are key to Woodside’s plan to triple its oil and gas reserves in less than a decade.

Woodside’s has, however, kept its 2020 production guidance unchanged at 97–103mn boe. It said that LNG and oil production have not fallen, and deliveries to customers continue.

The full impact of the lower oil price will not be realised until late Q2 2020 due to the lag between the oil price and realised LNG price, the company said. To reduce exposure to potential further downside and increase revenue certainty, Woodside has hedged 11.85mn barrels of oil between April and December 2020 at an average price of US$33.47/barrel.

Woodside has also agreed with a customer to fix the price of approximately 2.4mn boe of LNG production over the same period, to further increase revenue certainty.

Canada’s Woodfibre LNG project, a 2.1mn mt/yr liquefaction and export project on the shores of Howe Sound north of Vancouver, is reportedly facing a one-year delay due, in part, to the global Covid-19 pandemic and financial difficulties with its preferred EPC partner.

A final investment decision (FID) was expected earlier this year, with construction to start this summer. But now, the report from the local Squamish Chief newspaper said, construction won’t start until the summer of 2021.

FID has not yet been announced, and the company has applied to the BC Environmental Assessment Office (EAO) for a five-year extension of its environmental assessment permit, which expires in October.

The media report cited the Covid-19 related shut-down of a fabrication yard in China as one reason for the delay, and also suggested that the financial difficulties of Woodfibre’s preferred EPC contractor played a role.

“Last fall, Woodfibre LNG was nearing finalisation of an [engineering, procurement and construction] contract and announcement of a final investment decision when our preferred contractor for engineering, procurement and module fabrication, encountered financial challenges,” Woodfibre LNG CEO David Keane said in an email copied to the Chief. “In January 2020, our preferred contractor filed for Chapter 11 bankruptcy protection in the US and is now undergoing proceedings which are expected to continue until July 2020 at the earliest.”

Although Keane did not identify the EPC contractor, it is thought to be McDermott International, which filed for Chapter 11 protection in January and subsequently reached an agreement to sell its technology business Lummus as part of its reorganization plan. That reorganization plan received approval earlier in March.

Other amendments to environmental approvals that Woodfibre had sought, including a switch to air cooling from water cooling and permission to provide floating workforce accommodation, were also cited as reasons for the delay.

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JAPAN’S INPEX TO REVIEW INVESTMENT PLANS Japan’s Inpex Corporation is looking to optimise operations, review investment plans and cut costs amid sliding oil

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prices and the Covid-19 outbreak, it said March 25 in a statement.

“While it remains a challenge at this stage to forecast how long these conditions will last, it is Inpex’s policy to minimise the impact of oil prices maintaining their current level for a certain amount of time by optimising operations, reviewing investment plans group-wide and pursuing further cost-reduction measures, in order to sustain stable business operations,” it said without giving any details.

The company said it will disclose the impact to the forecasted consolidated operating results for the year ending December 31 announced in February in a timely manner once the impact is determined.

Inpex operates oil and gas projects in Japan, the Americas, Asia, Australia, the Middle East and north Africa. It operates the Ichthys LNG export project offshore northern Australia. The company is also preparing to start front-end engineering design work at the Abadi LNG project in Indonesia.

SOUND GETS APPROVALS FOR MOROCCO PROJECT Morocco-focused gas company Sound Energy has secured an additional environmental impact assessment (EIA) approval and land rights for its Tendrara gas project, it said in a March 20 statement.

The company received the EIA approval from the Moroccan ministry of energy, mines and environment for the construction of a gas treatment and compression complex, including a micro LNG production facility.

In February, Sound announced its plan to pursue the first phase of the TE-5 Horst development at the Tendrara concession, which would involve liquefying its gas. Negotiations are ongoing with equipment providers for the LNG facility, as well as industrial customers and distributors on a gas offtake agreement, the company said.

Sound also obtained land access approvals from the country’s interior ministry for the 120km Tendrara gas export pipeline (TGEP), which will be built under the second phase of the TE-5 Horst development. Sound said these approvals covered 99.9% of the pipeline’s length. The remaining approvals relate to three key roads and five river crossings along the TGEP route and are to be sought after a final investment decision is taken.

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The latest approvals come after Sound received EIA approval from the Moroccan government to build and operate the pipeline.

GASUM TO DELIVER LIQUIFIED BIOGAS TO FINNISH REFINERY Finnish gas firm Gasum said March 20 it had reached an agreement with cleantech firm Forchem to supply liquefied biogas (LBG) to the latter’s oil biorefinery in Rauma, Finland.

The LBG is received at a terminal and then vaporised and used in the refinery’s production processes. The plant switched to using LNG last year.

“This is the first time we delivered liquefied biogas, or LBG, to Forchem. LBG is an environmentally friendly fuel and we offer it for a variety of industrial needs.

LNG and LBG can both be delivered using the same equipment, and the switch to LBG can be made without any additional investments,” Gasum sales director Tommy Mattila said in a statement.

“At Gasum we’re strongly expanding our LNG and LBG distribution network to meet our customers’ needs relating to their efforts to meet their emission reduction requirements,” he continued. “The construction of the LNG infrastructure also enables the introduction of LBG in the future.”

Gasum noted that industrial operators could significantly lower their emissions through the use of LNG and LBG. The latter can be produced from feedstocks including biodegradable side streams from industrial and other enterprises, as well as from consumer biowaste.

US REGULATOR APPROVES JORDON COVE LNG PROJECT The US Federal Energy Regulatory Commission (Ferc) has approved Pembina Pipeline’s controversial Jordan Cove LNG project and the accompanying Pacific Connector natural gas pipeline.

It is the first ever approval by the commission of a US west coast LNG export project, and comes despite significant environmental opposition and difficulties acquiring critical state permits.

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“We appreciate Ferc’s science-based approach to their review,” Harry Andersen, Pembina’s senior vice president and chief legal officer, said in a statement.

“The approval emphasises yet again that Jordan Cove is environmentally responsible and is a project that should be permitted given a prudent regulatory and legal process was undertaken.”

The project includes a 7.5mn mt/yr liquefaction and export terminal on the shores of Oregon’s Coos Bay and the 229-mile Pacific Connector pipeline, which would deliver feed gas – sourced from Canada or the US Rockies region – to the terminal from the Malin Hub in southern Oregon.

Calgary-based Pembina Pipeline acquired Jordan Cove in 2017 as part of its acquisition of Veresen, and since then has been working to obtain extensive local, state and federal regulatory approvals. All 14 required permits from local counties and cities have been received, but the project has not yet received a critical water quality certification from the state of Oregon.

Pembina has yet to make a final investment decision on the estimated $10bn project, and said in May 2019 it would slow work on Jordan Cove while it sought federal and state approvals.

LNG CANADA SLOWING KITIMAT WORK Canada’s only active new liquefaction project, the AngloDutch Shell-led LNG Canada project at Kitimat, on BC’s northern coast, is slowing work at the site in light of the global Covid-19 pandemic.

“Exercising an abundance of caution that prioritises the safety of our workers and the community, LNG Canada, JGC Fluor (JFJV) and our subcontractors have reviewed the staffing level at our site in Kitimat,” LNG Canada said in a statement posted to its website and updated on March 17. “Demobilisation of staff in non-business critical positions has already commenced with personnel leaving Kitimat, with some following our work from home policy.”

Essential work that will continue at the site, the company said, includes seasonal activities that must take place within regulatory windows, work that has already begun and needs to be completed to ensure the area is safely secured, and the unloading of material delivery vessels at the Kitimat port.

“This work will be conducted with additional safety, health and hygiene precautions that follow

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recommended social distancing protocols and all other current recommendations for best practices.”

The number of staff actually on the ground in Kitimat will gradually be reduced to half of current levels over the coming weeks, LNG Canada said, primarily by reducing the number of workers flying in on rotation. If necessary, LNG Canada, the JGC Fluor joint venture and site contractors will implement a final reduction of staff on site to critical levels required to maintain site security and environmental controls.

“Business travel between our construction sites in Kitimat and all other regional and international locations continues to be heavily restricted.”

Coastal GasLink, which is in the early stages of construction on the 670-km pipeline that will feed the LNG Canada plant, is also restricting on-site staff, in the field and in the office, to those in critical operations, including construction. All workers associated with the project, whether employed by CGL or its prime contractors, are subject to the suspension of business travel, and all meetings will be conducted via technology options to avoid personal contact.

With pending spring break-up conditions reducing access due to soft ground conditions, CGL is working primarily with local workers and prioritising critical and essential work paths, such as erosion and sediment control, and clearing the right-of-way in sections to ensure river and wildlife safety. Non-critical work will be delayed, CGL said.

AUSTRALIA’S LNG EXPORTS UP IN FEB: ENERGYQUEST Australian LNG exports in February were up year-on-year but saw a sharp drop in comparison to January, energy consultancy EnergyQuest said in its February report.

Australian LNG shipments totalled 6.1mn metric tons (90 cargoes) in February, significantly lower than the 7mn mt (103 cargoes) in January, although higher than the 5.6mn mt (82 cargoes) in February 2019.

Australia’s February shipments were 76.2mn mt/yr on an annualised basis, just below Qatar’s nameplate capacity of 77mn mt/yr, EnergyQuest said.

“The disruption to trade with China and Japan from the coronavirus is starting to become evident in cargoes, not yet substantial but most pronounced in shipments from Gladstone, which supplies Chinese customers CNOOC and Sinopec,” the report said.

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In total Australian projects delivered 29 cargoes to China in February, well down on 40 in January although more than the 26 delivered in February 2019.

However, cargoes delivered from Gladstone fell from 17 a year ago to 14 this February, when 12 Australian cargoes destined for China were delayed or diverted, EnergyQuest said. Shipments from Gladstone bound for China amounted to only 1.05mn mt in February, down from 1.24mn mt a year earlier and marking the lowest level since September 2018.

31 deliveries were made to Japan in February, compared with 45 delivered in January and 40 in February 2019.

According to EnergyQuest, the slump in the oil price will take two or three months to feed through into LNG price realisations but will have a significant impact. At a 12% slope to the oil price, the LNG price is $7.80/mn Btu at an oil price of $65/b, but only $4.20/ mn Btu at $35/b.

MEXICAN LNG PROJECT AWARDS FEED CONTRACT Mexico Pacific Limited (MPL), which is proposing to build a 12mn mt/yr natural gas liquefaction and export terminal on Mexico’s Pacific Coast near Sonora, said March 9 it had awarded a front-end engineering and design (Feed) contract to Technip USA. The west coast location offers relatively short shipping distances to key Asian markets and access to low-cost US natural gas. According to current project timelines, it would place its first trains in service about a year ahead of the larger 14mn mt/yr LNG Canada project, currently under construction on BC’s northern coast near Kitimat.

“With major permits in hand and the Feed award completed, MPL is on track to take FID (final investment decision) and establish a world-class North American LNG export facility on the west coast of Mexico,” MPL CEO Douglas Shanda said.

Shanda said the company is targeting early 2021 for a final investment decision on the project, with the first 4mn mt/yr module expected in-service in 2024. MPL is controlled by New York-based Avaio Capital, which has more than $50bn worth of infrastructure development underway in the energy, water, transportation and digital sectors.

The project, on a 1,100-acre brownfield site originally permitted as an import and regasification terminal in

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Puerto Libertad, Sonora, received US Department of Energy export authorisations for free-trade and non-freetrade countries in March 2019.

OZ EAST COAST GAS OUTPUT UP 5.5% IN 2019 Australian east coast gas production in 2019 reached a record 1,914.2 petajoules (PJ) (51.11bn m3), up 5.5% yr/yr, despite plummeting prices, energy consultancy EnergyQuest said in its March 2020 quarterly report.

The simple average of short-term east coast gas prices was A$7.49 (US$4.98)/gigajoule (GJ) in Q4, down by 25.9% from an average A$10.11/GJ in Q4 2018 and down by 9% from the Q3 2019 average of A$8.23/GJ, EnergyQuest said. Export prices linked to crude oil were also trending downwards from 2018 onwards, according to an Australian government report late December.

On the west coast, Western Australia domestic gas production grew strongly to a record 415.8 PJ in 2019, up 6.4% yr/yr. Production exceeded total state demand of 383.1 PJ, with an estimated 40.1 PJ of gas in storage at the end of 2019. The LNG projects (NWS, Gorgon, Wheatstone and Pluto) supplied 223.7 PJ, 9.3% of LNG production.

Australian LNG exports reached a record 77.3mn metric tons in 2019, sealing Australia’s claim as the world’s largest LNG producer, EnergyQuest said. The Queensland LNG projects shipped a record 22.4mn mt in 2019, up 9.1% yr/yr.

BERKSHIRE HATHAWAY EXITS $7BN CANADIAN LNG PROJECT: PRESS Warren Buffett’s Berkshire Hathaway group has dropped plans to invest C$4bn (US$3bn) in the C$9bn development of an LNG terminal at the port of Saguenay in Quebec, Canada, local press reported March 5.

The US group’s withdrawal was first reported by Montreal-based La Presse. A spokesperson for the project’s developer GNL Quebec said a major investor

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had walked away after months of talks because of protests against energy investments in Canada and the “general political context” in the country. Sources told the newspaper that this investor was Berkshire.

The project, known as Energie Saguenay, aims to export 11mn mt/yr of LNG from fields in western Canada starting in 2025. In addition to liquefaction facilities, it will involve the construction of a 780-km pipeline to transport gas from Ontario to Saguenay.

Discussions on Energie Saguenay have been going on for six years, but the project has been held back by opposition from environmentalists and indigenous peoples. The project “is not yet compromised,” the GNL Quebec spokesperson said. “It is expected that final decisions, whether to go ahead or not, will be made in 2021.”

In addition to the national problems of hydrocarbon development projects, now is not an encouraging time for major new LNG export capacity. Spot LNG prices are at long-term lows and show little sign of rising. Asian and European prices for April were both a few cents adrift of $3/mn Btu March 5, leaving little margin after liquefaction and shipping from the $1.77/mn Btu Henry Hub market.

FORTISBC PUSHES AHEAD WITH TILBURY EXPANSION BC natural gas distributor FortisBC is pushing ahead with a C$3bn Phase 2 expansion of its Tilbury Island liquefaction terminal in BC’s Lower Mainland that would increase LNG production capacity to about 4.5mn mt/yr.

According to an initial project description approved by BC’s Environmental Assessment Office (EAO) February 27, the new facilities at Tilbury Island will add 11,000 mt/ day of liquefaction capacity and 162,000 m3 of storage capacity.

Phase 2 would be the third expansion of Tilbury Island in the last six years. Phase 1A, completed in 2018, added 700 mt/day of liquefaction capacity and 46,000 m3 of tank storage. Phase 1B, which is currently in the design and engineering stages with a planned in-service date in 2023, will add 2,000 mt/day of liquefaction capacity.

Liquefaction trains at both Phase 1 expansions will use all-electric compressors, with power drawn from the provincial grid, as would the Phase 2 liquefaction trains. Some expansion on an Enbridge

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gas pipeline serving Tilbury Island would also likely be needed to meet the gas supply requirements of the expanded facility.

The original Tilbury Island facility has operated since 1971 as a storage and peak-shaving facility, with 60 mt/ day of liquefaction capacity and 28,000 m3 of storage capacity. Some or all of the base plant liquefaction and storage capacity may be decommissioned following completion of the Phase 2 project.

The Phase 2 project is now in the 90-day early engagement stage of the province’s environmental assessment process, which allows for the early identification of interests, issues and concerns of indigenous First Nations, stakeholders and the public that can inform project design, siting and any alternative approaches to development.

The project may also be subjected to a federal review under the Impact Assessment Act – the infamous Bill C-69. The EAO and the Impact Assessment Agency of Canada (IAAC) are working together for the initial phase of the project’s review, and a 30-day comment period jointly held by the two agencies is expected to be announced soon.

Assuming receipt of all provincial and any federal approvals, additional storage in Phase 2 would be in-service in 2024, while staged completion of the additional liquefaction trains would take place between 2024 and 2028.

CAMERON LNG T2 STARTS COMMERCIAL OPS The second 4mn mt/yr train of the Cameron LNG export project in Louisiana has started commercial operations, its operator Sempra Energy said on March 2.

The train started production in December and is now operating commercially under Cameron LNG›s tolling agreements, Sempra said in a statement. The third and final train sanctioned as part of the project›s first phase is still on track to launch production in the second quarter and begin commercial operations in the third, it said, bringing the plant›s total capacity to 12mn mt/yr.

Sempra has a 50.2% stake in Cameron LNG. Its partners are France’s Total and Japan’s Mitsui & Co, Mitsubishi and Nippon Yusen Kabushiki Kaisha.

The group plan to take a final investment decision on the project’s second phase, which will add another two trains, by mid-2021.

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The floating LNG terminal in Alexandroupolis, northern Greece, has received long-term capacity bids totalling 2.6bn m³/yr, its operator Gastrade said March 26. The project’s planned regasification capacity is 5.5bn m3/yr.

The process was completed March 24, with bids from Greek and foreign gas companies; Bulgaria said it would be bidding for capacity earlier in March, as the deadline was pushed back.

Gastrade said the response had been “very satisfactory and far surpassed the one experienced in similar cases of new gas projects recently.” It marks a “critical step towards the materialisation of the project,” it said, without saying if it was sufficient to get the project over the line.

Gastrade CEO Konstantinos Spyropoulos said the terminal would enhance the energy diversification and security of supply in Greece, the Balkans and the wider south east European area. This part of Europe is heavily reliant on Russian pipeline gas.

The company said the market test process was conducted under the supervision of the Greek Regulatory Authority for Energy (RAE) and in line with the guidelines for the management and the allocation of capacity on the project under EU rules.

In emailed comments, the project manager Kostis Sifnaios told NGW that the market test «absolutely supported a final investment decision (FID). To this extent, we will proceed swiftly in this direction with an objective to take FID before the end of this year,» he said.

He said that selling half the technical capacity on a long-term basis was “an extremely successful result.” He said that terminal utilisation has been historically much lower than half, and having half of the capacity booked 2.5 years before the start of commercial operations is “great.” There is nothing stopping other companies now booking capacity, and he said that short-term bookings would “boost further their results and commercial viability.”

UK piped gas imports slumped 28% in 2019 to 318 TWh (28.9bn m3), statistics published by the Department of Business, Energy and Industrial Strategy (Beis) on March 26 show, while LNG imports more than doubled to 200 TWh (18.5bn m3).

Norway remained the country’s top supplier, but its market share shrunk to 57% last year from 72% in 2018. Imports from Belgium and the Netherlands also declined, by 89% and 42% respectively.

LNG shipments climbed to their highest level since 2011, when deliveries surged because of low temperatures and a disruption in Norwegian supplies. Beis attributed the growth last year to weak demand in Asia and new liquefaction capacity coming on stream in Qatar, the US and Russia – the same trends that led to many other European countries significantly increasing their LNG intake.

Qatari supplies tripled in 2019, accounting for 49% of the UK’s total LNG imports, while deliveries from the US and Russia doubled. There were also increases from Algeria, Equatorial Guinea, Nigeria and Peru. The UK imported LNG from Angola and Cameroon for the first time.

Overall gas imports were unchanged at 518 TWh (47.3bn m3). Demand fell by 0.5% to 876 TWh, while production was down 2.2% at 440 TWh. Exports grew by 5.6% to 87.5 TWh.

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PETRONET ISSUES FORCE MAJEURE NOTICE TO QATARGAS: PRESS Petronet LNG, India’s biggest LNG importer, has issued a force majeure notice to Qatargas seeking to delay loading of LNG cargoes under long-term deals as India announced a 21-day lockdown to combat the spread of coronavirus (Covid-19), Reuters reported March 25 citing two sources familiar with the matter.

“It seems demand will fall drastically as industrial production is curtailed to a great extent and demand for gas will fall further,” said one of the sources.

On the evening of March 24, India’s prime minister Narendra Modi imposed a nationwide lockdown in an

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attempt to slow the spread of Covid-19. The lockdown came into effect on March 25 and will last till April 14.

Qatar is India’s biggest supplier of LNG. In 1999, Petronet LNG signed a long-term deal to import 7.5mn metric tons/year of LNG from RasGas (merged with Qatargas in January 2018). In late 2015, the two companies agreed on a new deal under which Petronet LNG would import an additional 1mn mt/yr of LNG, taking the total annual long-term commitment to 8.5mn mt/yr.

India’s LNG imports had spiked in the last couple of months as prices have been trading at multi-year lows.

In January, India’s imports grew by 25% yr/yr and in February they spiked by a whopping 68% yr/yr. The decision by Petronet LNG is expected to impact imports in March and April.

CHINA’S LNG IMPORTS IN JAN-FEB UP 2.3%

The south Asian country imported 3.45bn m3 (about 2.6mn metric tons) of LNG in February, compared with 2.05bn m3 in the same month of last year. India’s imports were sharply up on January as well when the country took in 2.77bn m3 of LNG. The cumulative imports of 30.81bn m3 during the 11 months of the current financial year (2019-2020), were higher by 16.9% compared with the corresponding period of the previous year, the data showed. This year’s imports have already surpassed the previous financial year’s imports of 27bn m³ of LNG. Anglo-Dutch major Shell said in February that India had taken a lot of the cargoes of LNG that China was declining in the wake of reduced demand following the Covid-19 outbreak.

GAS MALAYSIA UNIT GETS LNG IMPORT LICENCE

China’s LNG imports during January-February totalled 11.13mn metric tons, up 2.3% yr/yr, according to customs data published March 23. The customs department did not provide data for January and February separately. Meanwhile, China’s pipeline gas imports were 6.67mn mt, up 3.6% yr/yr, the data showed.

Chinese gas imports have taken a hit this year because of the Covid-19 outbreak, with yr/yr growth slowing down significantly. In January last year, Chinese LNG imports grew 27.8% yr/yr and in February 2019 they grew 9.7% yr/yr.

China’s natural gas imports, both via pipeline and in the form of LNG, totalled 17.8mn mt (24.2bn m3) in the first two months of this year, up 2.8% yr/yr.

Malaysian gas retailer Gas Malaysia March 18 said its subsidiary has been granted a 10-year licence by the Energy Commission to import LNG into the country.

Gas Malaysia said the licence allows its whollyowned subsidiary, Gas Malaysia Energy and Services, to import the LNG into Malaysia by any means other than by transshipment.

“The issuance of the licence will have no material effect on the earnings and financial position of Gas Malaysia group for the financial year ending 31 December 2020,” the company said.

Gas Malaysia supplies natural gas and LPG to homes, commercial businesses and industries in Malaysia. Apart from the general public, its shareholders include MMC Corporation, Tokyo Gas, and Petronas Gas.

INDIA’S LNG IMPORTS IN FEB SPIKE 68%

JAPAN’S FEB LNG IMPORTS DROP BY A TENTH

India’s LNG imports in February jumped almost 68% yr/yr to a monthly record, owing to new regasification capacity being onstream and as global prices remain at multi-year lows, according to data published by the Indian oil and gas ministry’s Petroleum Planning and Analysis Cell March 20.

Japan’s LNG imports in February stood at 6.64mn metric tons, down 9.6% yr/yr according to the provisional data released by the country’s finance ministry March 18.

Imports were down month-on-month as well from 7.51mn mt in January. Japan remains the world’s

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biggest LNG importer. Last year, the country’s LNG imports were 77.32mn mt, down 6.7% on 2018.

The average price of spot LNG imports into Japan contracted in February was $3.4/mn Btu, sharply down from $7.5/mn Btu in the same month a year earlier, the country’s trade ministry (Meti) said March 10.

Compared with January, the price was down 42%.

Meti prices are delivered ex ship (DES) in Japan, or else are converted into a DES equivalent.

Meti also published March 10 official average arrivalsbased prices. The latest figures show that February arrivals’ average value was $5.5/mn Btu, down from $8.3/mn Btu for same month of last year.

GOLAR LNG TO ESTABLISH BRAZILIAN LNG HUB Golar Power, a joint venture between Norway’s Golar LNG and US-based Stonepeak Infrastructure Partners, has signed a protocol of intentions with Brazil’s Pernambuco state government on developing an LNG import terminal in the Brazilian port of Suape, it said March 16.

Golar Power’s plan envisages establishing Suape as a hub for LNG distribution in northeast Brazil. Access to gas will benefit the economies of Pernambuco’s interior cities that lack pipeline access, it said.

Work will commence in the second half of 2020 on the project, which will include infrastructure for the supply of gas and LNG for electricity generation and to meet the demands of industries, commerce, LNG stations and households. Golar Power said it would work with local gas distributor Companhia Pernambucana de Gas Natural (Copergas) to bring gas to areas of the state that are not currently served by the pipeline network.

The terminal will employ an existing LNG carrier, permanently docked at the port. LNG will be distributed to cities within a radius of up to 1,000 km in truckmounted LNG ISO containers, at an initial rate of 800 m3/day, equivalent to 480,000 m3/day of natural gas.

LNG will also be transported to other Brazilian states using small-scale LNG carriers.

The project’s development will depend on regulatory approvals being secured and commercial agreements concluded. Golar Power will cover its capital cost.

In November Avenir LNG, a partnership between Golar LNG and fellow Norwegian firms Hoegh LNG and Stolt-Nielsen, announced it would collaborate with

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Golar Power on developing Brazil›s small-scale LNG market. Stonepeak is an investor in Venture Global’s US liquefaction projects.

SANTOS’ NARRABRI PROJECT GOES TO PLANNING COMMISSION Santos March 12 announced that the New South Wales (NSW) minister for planning has referred the Narrabri gas project to the Independent Planning Commission (IPC) for determination.

“This is a key milestone in the independent approvals process. The next step is for the NSW department of planning to complete its assessment report and provide the report to the IPC for its consideration,” the company said.

The minister has requested that the IPC hold public hearings and make a determination regarding the Narrabri gas project within 12 weeks of receiving the department’s assessment report, Santos said.

Santos CEO Kevin Gallagher welcomed the referral, noting that a decision on whether or not the Narrabri coalbed methane project can proceed is vital for Santos to determine where it will invest in new natural gas developments to supply the east coast gas market over the coming decade.

“We have applied the best science to the environmental impact statement for Narrabri. We are confident that it will stand on its merits and that the project could be safely and sustainably developed to protect water resources and the environment. Santos will participate openly and transparently in the IPC process,” Gallagher said.

Santos said the Narrabri gas project has the potential to supply enough natural gas to meet up to half of NSW’s natural gas demand. The company has committed 100% of Narrabri gas to the domestic market. The project, however, has been mired in controversy as many activists say it poses a risk to the local environment. Santos has always denied these claims.

“If we can develop Narrabri gas, it will be the most competitively-priced gas for NSW customers, and it will always be cheaper than LNG imports, especially when gas prices are high in Asia. Ours is a cyclical business and we must not lose sight of the fact that the current

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low price and market conditions are not permanent.

Demand, and with it, prices, will ultimately recover, and therefore, we must continue to focus on how and when we need to develop future gas sources at the lowest possible cost of supply to increase competition,” Gallagher said.

WORK ON FIRST GEN’S PHILIPPINES TERMINAL MIGHT START IN MAY Manila-listed First Gen Corporation has submitted an application to the Philippines’ energy department to start work on the Batangas LNG terminal project in Batangas City by May this year, it said in a stock exchange notice March 5.

Its wholly-owned subsidiary, Fgen LNG, has filed the application for a permit to construct, expand, rehabilitate and modify (PCERM) its existing jetty with the department of energy. A PCERM is required by the Philippine Downstream Natural Gas Regulation (PDNGR).

Once work on the jetty is complete, it will be able to receive large and small-scale LNG vessels as well as the present traffic of liquid fuel tankers, and build an onshore gas receiving facility.

“Once completed, the project will allow First Gen to be able to bring in a floating storage and regasification unit (FSRU) on an interim basis and thus accelerate FGEN LNG’s ability to introduce LNG to the Philippines,” it said.

FGEN LNG hopes to be able to start work as early as May, with first LNG arriving as early as Q3 of 2022, First Gen said. Ultimately it hopes to have a $1bn onshore regasification terminal operating, but it is not planning a final investment decision until 2024.

In December 2018, Japanese utility, Tokyo Gas, signed an agreement with First Gen to develop an LNG receiving terminal in the country. Tokyo Gas has a 20% stake in FGEN LNG. In September last year, First Gen picked Japan’s JGC Corporation for the engineering, procurement and construction (EPC) work for the project.

The company stated that the project, and the early entry of LNG, will play a critical role in ensuring the energy security of the Luzon grid and the Philippines.

The offshore Malampaya gas field is declining and gas supplies for the country’s power plants are looking ever less reliable.

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First Gen has about 2 GW generating capacity from four operating gas assets – the 1-GW Santa Rita plant, the 500-MW San Lorenzo plant, the 414-MW San Gabriel plant and the 97-MW Avion plant – all of which depend on Malampaya’s gas, whose gas sales contract expires in 2024. They are all at Batangas City.

Also needing a gas supply is the 1.2-GW Ilijan gasfired power plant, operated by Korea Electric Power Corporation, but due to be turned over to Philippine conglomerate San Miguel Corporation in July 2022. The facility’s gas sales and purchase agreement is set to expire early that year.

FERUS IN NORTHERN CANADA LNG SUPPLY DEAL Ferus Natural Gas Fuels (Ferus NGF) said March 2 it has entered into a four-year contract with Yukon Energy for the supply and delivery of LNG for power generation in Whitehorse, the capital of Canada’s northern Yukon Territory.

“Ferus NGF is committed to developing Canada’s domestic LNG market and partnering with local businesses and indigenous groups to create long-term economic, social and environmental benefits,” said Travis Balaski, business unit vice president of Ferus NGF. “We’re confident in the longterm viability of LNG as a clean, affordable fuel and we believe this contract enhances Yukon’s energy security while bringing many additional benefits to the territory.”

The LNG to supply the contract will come from two micro-LNG production facilities, one in Elmworth, in northwestern Alberta, owned and operated by Ferus NGF, and the second, a third-party facility in Dawson Creek, BC. Drawing on two production facilities will ensure Yukon Energy’s requirements are met, as will a trailer fleet capable of delivering 2,400 GJ/day, enough LNG to heat over 7,500 average Canadian homes for a day.

Ferus NGF has contracted with Chieftain Energy, based in Whitehorse and majority owned by First Nations interests, as its “first call” LNG transportation carrier.

The LNG fuel will be used by Yukon Energy to supplement its hydroelectric and other renewable sources. When hydro resources are low, and/or when demand spikes – as it did in Whitehorse in January 2020 – LNG is a reliable back-up to generate electricity for heating and powering homes and businesses.

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news: LNG CORPORATE TOTAL FOLLOWS OTHER MAJORS IN SLASHING CAPEX France’s Total said March 23 it would shave more than $3bn off its planned investments in 2020, lowering the total to under $15bn, in order to weather the oil market downturn.

The savings mainly amount to short-term flexible capex, Total said. The company aims to bring down its operating costs by $800mn yr/yr in 2020, instead of the previous target of $300mn.

Total had announced a plan to buy back $2bn of shares in 2020, assuming a $60 oil price environment. It bought back $550mn of stock in January and February alone. With Brent now trading at around $25/b, it has suspended the buyback programme, just as fellow European majors Shell and Equinor have done.

In a presentation, Total said it was more prepared for the current crisis than prior to the 2015-2016 downturn.

Its cash breakeven point was less than $25/b in 2019, versus more than $100/b in 2014. Its upstream operating expenditure averaged $5.4/boe last year, compared with $9.9/boe five years earlier, while its organic capex came to $13.4bn, down from $26.4bn in 2014.

Total fared better than some of its competitors in the fourth quarter, posting adjusted net income of $3.17bn, unchanged from the same period in 2018. It was supported by higher output and increased LNG sales, which countered the impact of weaker prices. However, the LNG price will be drifting downwards through the oil indexation clauses in its term contracts, and demand for oil products is sharply down as aviation and other transport fuel needs fall as a result of coronavirus (Covid-19) containment measures.

FLUXYS GAINS ON LNG BUSINESS Belgian transmission system operator Fluxys Belgium saw revenues and profit rise last year compared with 2018, thanks in part to much heavier use of its LNG facilities, it reported March 25.

Its turnover was up about 5% at €531.0mn ($578mn) in 2019 and net profit rose by over a third, from €54.5mn

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in 2018 to €69.5mn in 2019. Pretax earnings before depreciation and amortisation (Ebitda) were up €19mn at €297.34mn and pretax earnings (Ebit) were up €14mn, at €134.8mn.

LNG activities broke records, as 130 vessels docked at the Zeebrugge terminal, over half as many again as the previous high point of 82 in 2009. Compared with 2018, more than twice as many carriers came to unload LNG, and the amount of natural gas injected by the terminal into the network was almost three times higher.

The number of LNG transshipment operations doubled.

Demand for loading small LNG carriers in 2019 was unchanged year on year, while almost 1,200 more LNG trailers were loaded.

Investments in property, plant and equipment were up €91.3mn, compared with €78.1mn in 2018. Most of the money was spent on the fifth tank at Zeebrugge, which will be used for Novatek’s transshipments of LNG from Russia’s far north. That allows 8mn metric tons/ year to be handled, with effect from last December.

ITALY’S SNAM SEES HEALTHY DEMAND Italian gas transmission system operator Snam reported adjusted profit of €1.1bn ($1.2bn) for 2019, up 8.2%, thanks to better operations, lower financing costs and higher income from shares in subsidiaries, chiefly the Greek TSO Desfa. It had free cash flow of €482mn, it said March 19.

Adjusted pre-tax earnings (Ebitda) for 2019 were €2.17bn, up 3.5% 2018. Revenues were €2.6bn, up 3% thanks to higher tariffs and a 3.5% rise in volumes injected into the system to 75.37bn m³. National demand of 74.6bn m³ was higher, mainly the result of 2.45bn m³ more going into the power sector, a tenth more than in 2018.

Cheaper LNG meant more regasification: last year 2.4bn m³ were injected from the Panigaglia terminal, compared with 0.91bn m³ in 2018.

Storage volumes were down 8.3% compared with 2018, as 19.33bn m³ moved through the system. There were high injections earlier in the year in readiness for a possible problem with Russian gas transit through Ukraine at the start of 2020, but low withdrawals, owing to mild weather.

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DUTCH ENECO SALE COMPLETES Japan’s Mitsubish Corp (MC) and Chubu have now acquired all the shares of Dutch utility Eneco through their special purpose vehicle Diamond Chubu Europe, paying €4.1bn ($4.8bn) in total, they said March 25.

Both companies have LNG trading businesses which will now be able to add value through the retail network: Chubu owns half of energy trader Jera, which has a tolling agreement with US Freeport LNG; while Mitsubishi is an offtaker and investor in LNG Canada.

Another part of the business empire is gas turbine manufacturing, and its customers include Jera.

TOKYO GAS MULLS LNG TRADING BUSINESS Japanese utility Tokyo Gas plans to establish a new entity to boost LNG trading activity and make it a mainstay for the company, it said March 25 in its 202022 medium-term management plan.

“With regard to LNG, one of the group’s strengths, we will shift from viewing LNG as a raw material of gas and electricity delivered to our clients to viewing it also as “product.” Increasing the flexibility and competitiveness of our procurement portfolio, we will work to expand our LNG operations through asset-backed trading, and through terminal operations that are integrated with overseas LNG demand,” the company said.

Tokyo Gas, one of the biggest buyers of LNG, plans to collaborate with other companies to pursue transaction opportunities. “Co-operation with Centrica, RWE and other business partners will provide flexibility with respect to procurement and sales contracts and expand LNG swap transactions that utilise ships, LNG terminals, thermal power plants and other assets,” it said.

Tokyo Gas is focusing on building LNG infrastructure in Asia where the demand for gas is increasing.

The company already has a significant presence in southeast Asia.

In the Philippines, Tokyo Gas has formed a joint venture with Manila-listed First Gen to build an LNG import terminal, work on which is expected to start

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in May. In Taiwan, Tokyo Gas Engineering Solutions Corporation (TGES), a unit of Tokyo Gas, has got the front end engineering design (Feed) work from CPC Corporation for an expansion project of its LNG receiving terminal at Yung An. In Vietnam, Petrovietnam Gas (PV Gas), Bitexco and Tokyo Gas have established a joint venture entity, LNG Vietnam.

PETRONET LNG CEO UNDER CORRUPTION SCANNER India’s petroleum and natural gas ministry has received several corruption allegations against the CEO and other officials of Petronet LNG (PLL), petroleum and natural gas minister Dharmendra Pradhan said March 23 in a written reply to a question in Lok Sabha, the lower house of the Indian parliament.

“Several complaints have been received in the ministry of petroleum and natural gas against MD and CEO, PLL and other officers of PLL regarding alleged corruption/irregularities which were forwarded to chairperson, audit committee, PLL for taking appropriate action,” Pradhan said without disclosing the nature of the allegations.

Prabhat Singh has led Petronet LNG, since September 2015. The company is India’s biggest LNG importer and operates two import and regasification terminals.

Four state-run companies – Bharat Petroleum Corp, Gail, Indian Oil Corp and ONGC – hold 12.5% each in Petronet LNG while the other half is held by the public and institutions. Last year, it signed a provisional agreement to buy a stake in Driftwood LNG, the US Permian gas-LNG project operated by Tellurian, but it has not made a firm commitment.

OZ SANTOS CUTS 2020 CAPEX BY 38% Australia’s Santos March 23 announced a 38%, or $550mn, reduction in 2020 capital expenditure in response to the Covid-19 outbreak and collapse in oil prices. The company is aiming for a 2020 free cash flow breakeven oil price of $25/barrel.

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Santos has deferred the investment decision on the Barossa project just days after awarding contracts for the supply and installation of subsea infrastructure. The award was the last major facilities commitments ahead of a final investment decision (FID).

“Given the uncertain economic impact of Covid-19 combined with the lower oil price, we expect to defer FID on Barossa until business conditions improve.

Barossa remains an important project for Santos due to its brownfield nature and its low cost of supply,” Santos CEO Kevin Gallagher said.

The company has joined a slew of producers of all sizes who have announced radical cost-cutting plans as the Brent crude oil price declined sharply in March.

Commenting on its takeover of ConocoPhillips› northern Australia business, Santos said the acquisition is expected to complete in the first half of 2020.

ConocoPhillips is offloading its 56.9% position at the 3.24mn mt/yr Darwin LNG export terminal and the Bayu-Undan gas field that supplies it. In addition, the company is offloading its 37.5% share in the Barossa and Caldita gas fields.

Santos has also announced an agreement to sell a 25% interest in Bayu-Undan and Darwin LNG to South Korean SK E&S for $390mn. The deal is conditional on Santos completing the ConocoPhillips deal. SK E&S already has a 37.5% position at Barossa, and the two companies view its development as a “key priority,” Santos said. Santos’ transaction with SK E&S will be backdated to October 1 2019.

INOX INDIA, SHELL PARTNER ON LNG DISTRIBUTION IN INDIA Indian cryogenic liquid storage, distribution, and regasification solutions provider Inox India has signed a memorandum of understanding (MoU) with AngloDutch major Shell to develop a market for LNG supply by road from the Shell-operated Hazira terminal in Gujarat, it said March 18.

The company plans to deploy infrastructure including logistics and receiving facilities, as well as offer LNG access to the customers not connected to the supply chain.

“This will help in increasing the penetration and consumption of clean, reliable and cost-efficient LNG to commercial and industrial users all over the country.

The MoU also covers the cooperation in developing a larger market for LNG as a transport fuel for long haul

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heavy-duty trucks and buses,” Inox said. Shell Energy India is building a truck loading facility at its 5mn metric tons/year Hazira terminal.

India is promoting greater use of gas in the economy in order to tackle air pollution. The government wants to increase its share in the energy mix from 6% at present to 15% by 2030. It expects the city gas sector to be a major demand driver.

NOVATEK APPLIES FOR CHINESE GAS JV The European Commission (EC) said on March 17 it had received an application from Russian firms Novatek and Gazprombank, as well as China’s Sinopec, to form a gas trading joint venture (JV) in China. According to the EC, “the notified transaction could fall within the scope of the Merger Regulation.”

The JV, known as Sinova Natural Gas, will engage in “the import and export, as well as purchase and sale, of natural gas (including pipeline gas and LNG) and investment in natural gas-related projects in China,” an EC notice read.

Novatek sells LNG to China from its Yamal LNG project in the Russian Arctic, and is due to ramp up shipments after launching its second export terminal Arctic LNG 2 in 2023. It is looking to make its LNG business more robust by expanding across the supply chain, all the way to end-users, in China and other key Asia-Pacific markets.

The gas producer signed a heads of agreement with Gazprombank and Sinopec on establishing the new JV in June last year. It has also reached preliminary deals with Indian LNG developers H-Energy and Petronet LNG on the joint marketing of LNG in India, as well as an agreement with Japan›s Saibu Gas on marketing LNG and developing gas-fired power generation and bunkering operations.

OIL SEARCH CUTS CAPEX BY 38% AMID MARKET TURMOIL Papua New Guinea-focused Oil Search has cut its investments in 2020 by 38% in response to the steep

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decline in oil prices and the continuing spread of the Covid-19 pandemic.

“Apart from work programmes required to ensure ongoing reliable and safe operations, all discretionary activities within the Company’s control that have not yet commenced are being suspended or deferred,” the company said in a statement on March 18. “Where possible, some projects that have commenced have also been suspended safely.”

As a result of these steps, Oil Search expects its investment expenditure in 2020 to fall to $440-530mn, down from a previous guidance of $710-845mn. Capital spending for the year from April is forecast to drop to $200-300mn, from $400-500mn.

Oil Search has a 29% stake in the $13bn PNG LNG expansion project operated by ExxonMobil and also involving France’s Total.

“At present, we have assumed that activity on the LNG expansion are minimal,” Oil Search said, adding that ExxonMobil had informed it that it was also taking steps to reduce discretionary spending. The US major recently said it too planned to “significantly” cut its spending in response to the market downturn.

“While Oil Search is fortunate to have world-class assets, these unprecedented times require us to take immediate and decisive steps to position us for a potentially extended period of lower oil prices and business uncertainty,” Oil Search’s managing director Keiran Wuff explained.

The Sydney-listed operator has also decided to suspend the sale of a 15% interest in its Alaskan assets, although discussions continue with several potential buyers.

KOSMOS EYES 30% CUT IN 2020 CAPEX Texan oil and gas producer Kosmos Energy aims to slash its capital expenditure for this year by around 30% to $250mn, in response to current market volatility.

In a statement March 17, the company said it had identified more than $100mn of discretionary planned spending, mostly relating to exploration activities in the Gulf of Mexico and its basin-opening exploration portfolio, that could be cut. Production is expected to be flat, in line with Kosmos’ previous guidance, and only a minimal impact is expected on output in 2021.

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“The company also has significant flexibility in its 2021 capital programme should current market conditions persist,” it said.

Kosmos is a partner in the Greater Tortue Ahmeyim (GTA) LNG development off the coast of Mauritania and Senegal. The company said it was working with GTA’s operator BP on deferring planned capital spending in 2020 relating to the project’s first phase, sanctioned in December 2018. The phase is set to produce 2.5mn mt/ yr of LNG starting in 2022.

Kosmos said its priority remained selling down its interests in Mauritania and Senegal to support its growing gas business. Spending on GTA’s second and third phases should be minimal until final investment decisions (FIDs) on them are taken, expected in mid2022 and mid-2023 respectively.

The company also said it would trim forecast operating expenditure and general and administrative costs in 2020 by $60mn. It aims to slash opex by $1/boe, without affecting near-term production. The reduction in general and administrative costs will be achieved by cutting staff and scrapping all bonuses, Kosmos said. It will also cancel dividends announced in the fourth quarter of 2019 until market conditions improve, saving a further $75mn annually.

Kosmos expects to be free cash flow neutral starting in the second quarter, and believes it can fund all its obligations if Brent is at $35/barrel.

SIEMENS TO SUPPLY TURBINES FOR RUSSION LNG PROJECT: PRESS German’s Siemens has won a joint contract worth €130mn ($145mn) to supply equipment for Novatek’s Obsk LNG project, the Moscow-based Kommersant newspaper reported on March 16, citing sources.

The contract was awarded jointly to Siemens and Kazancompressormash, part of Russian engineering group HMS. Siemens will provide seven SGT-700 turbines, while Kazancompressormash will supply 10 compressors. An engineering plant owned by Russian nuclear firm Rosatom has also been selected to deliver the project’s cryogenic heat exchangers.

Novatek aims to take a final investment decision on Obsk LNG later this year, and bring the plant into

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operation in late 2022 or early 2023. It will consist of three liquefaction trains each capable of producing 1.6mn mt/yr of LNG.

AIR PRODUCTS PICKED FOR MOZAMBIQUE LNG EQUIPMENT Air Products has been selected to provide its proprietary LNG technology, equipment and related process licence and advisory services for the Total-operated Mozambique LNG export plant, it said in a statement March 12.

The Pennsylvania-based firm received a contract for the work from a joint venture between Italy’s Saipem, the US’ McDermott and Japan’s Chiyoda that is serving as Mozambique LNG’s lead contractor. It is due to supply two of its proprietary coil wound main cryogenic heat exchangers, which will be manufactured at Air Products’ facility in Florida. They will then be shipped to the project site on the Afungi Peninsula in Cabo Delgado, Mozambique.

Mozambique LNG is designed to produce 13mn mt/ yr of LNG, using gas from the Golfinho and Atum gas fields in the offshore Rovuma basin. The $20bn project is due on stream by 2024.

Total operates Mozambique LNG with a 26.5% stake, while its partners are Japan’s Mitsui E&P (20%), India’s ONGC Videsh (10%) and BPRL Ventures Mozambique (10%), local players state-owned ENH Rovuma (15%) and Beas Rovuma Energy Mozambique (10%) and Thailand’s PTTEP (8.5%).

US COURT CONFIRMS MCDERMOTT REORGANISATION PLANS US Bankruptcy Court for the Southern District of Texas has confirmed McDermott International’s reorganisation plan and approved the $2.7bn sale of Lummus Technology to a joint partnership between Chatterjee Group and Rhone Capital, the engineering, construction and procurement company said late March 12.

“With the support of our creditors, employees, customers and suppliers, we have been able to confirm

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our plan of reorganisation less than two months after we initially filed for Chapter 11,” said McDermott CEO David Dickson. “This is a significant achievement and allows us to emerge in the near-term as a stronger, more competitive player, with a sustainable capital structure that matches the strength of our operating business.”

Under the terms of the plan, McDermott will complete a comprehensive restructuring transaction to de-lever its balance sheet by eliminating almost $5bn of debt, leaving it in the black. It hopes to achieve this in Q2, following regulatory approval for the sale of Lummus Technology.

McDermott acquired Lummus in 2018 as part of its CB&I takeover. It is a licensor of gas processing, refining, petrochemical and coal gasification technologies, as well as a supplier of proprietary catalysts, equipment, and related engineering services.

Proceeds from the divestment of Lummus will be used to settle McDermott’s debtor-in-possession financing, fund emergence costs and provide cash for its balance sheet, the company said. Among its current high-profile gas projects are the Qatar North Field expansion and Mozambique LNG.

POLAND’S PGNIG PROFITS SLUMP ON LOWER PRICES, HIGHER COSTS Profits at Poland’s PGNiG plunged 57% in 2019, as a growth in gas sales revenues was outweighed by a rise in the cost of its gas purchases, according to a company report published March 12.

Net income totalled zlotys 1.37bn ($357mn) for the year, down from zlotys 3.21bn in 2018. Core earnings (Ebitda) came to zlotys 5.5bn, versus zlotys 7.1bn in the year before.

PGNiG spent zlotys 26.7bn on gas purchases in 2019, constituting around 67% of its total operating expenses, down from zlotys 24.9bn in the year before.

The company got around 60% of its gas from Russia last year under a long-term contract, with costs indexed to the price of crude. It expects a favourable Stockholm arbitration ruling soon, which could result in changes in the way its Russian gas is priced.

PGNiG also received around 23% of its gas in the form of LNG, up from 20% in the previous year, while its remaining purchases are made from its southern and western neighbours.

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The company increased its gas sales volumes by 6% in 2019 to 30.7bn m3, but its revenues rose by only 2% to zlotys 42bn, as European gas prices were lower because of higher LNG imports. According to PGNiG CEO Jerzy Kwiecinski, the average price of gas traded at the Polish power exchange was down 35% last year.

Revenues from PGNiG’s trade and storage segment rose 5% to zlotys 33.25bn, but revenues from exploration and production fell 32% to zlotys 3.18bn.

Turnover at its distribution services business was also down 5% at zlotys 4.21bn, while revenues from heat sales were up 1% at zlotys 1.33bn.

PGNiG also booked impairment losses in the fourth quarter, including a zlotys 212mn charge on its upstream operations, a zlotys 339mn charge on its trade and storage segment and a zlotys 272mn charge relating to its stake in the Polska Grupa Gornicza coal mining concern.

“All participants of the global gas market are currently facing the challenge of low prices. We should bear in mind, though, that demand for gas has been growing at a significant rate, as confirmed by forecasts from all around the world,” Kwiecinski said in a statement.

“Against this backdrop, we are consistently and actively diversifying our sources of natural gas imports with a view to ensuring Poland’s energy security.”

PAVILION, SLNG RENEW LNG STORAGE PACT Pavilion Energy and Singapore LNG Corporation (SLNG) have signed a new five-year agreement for LNG storage and reload services at the SLNG terminal on Jurong Island, the companies said March 10 in a joint statement. Pavilion and SLNG first signed a two-year deal in August 2017.

“Pavilion Energy is pleased to renew the partnership with SLNG. Tank capacity in Singapore presents greater opportunities for LNG optimisation and trading in the Asia-Pacific Basin,” said Frederic H. Barnaud, CEO of Pavilion Energy, adding “Pavilion Energy has held true to our commitment to facilitate wide access to the SLNG terminal, contributing to the vibrancy of Singapore’s LNG market.”

Under the agreement, Pavilion Energy will have access to a tank capacity of 180,000 m3 on a segregated basis at the SLNG terminal over the next five years.

The companies expect such capacity will support a

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higher volume of LNG trading activities, including LNG breakbulk and vessel cool-down services.

“SLNG is happy to extend our cooperation with Pavilion Energy through this longer-term storage and reload services agreement. SLNG has taken bold steps to develop infrastructure and create new service offerings to meet the needs of the industry, and we will continue to do so,” Tan Soo Koong, CEO of SLNG said.

“We are primed to play our part in helping Singapore achieve its ambition of becoming an LNG hub, through catalysing LNG-related businesses such as LNG Trading, small-scale LNG distribution, LNG bunkering, and more.”

Pavilion also has a multi-year agreement with German Uniper to use each other›s storage capacity. The agreement, signed in 2017, allows Uniper, which also trades coal, to access Singapore storage and reload facility, while Pavilion benefits from the access to LNG regas capacities in Gate LNG terminal and Grain LNG terminal.

TELLURIAN CUTS WORKFORCE, NAMES NEW CFO US LNG developer Tellurian has appointed Kian Granmayehas CFO, replacing Antoine Lafargue who will join the marketing group, it said March 9. Amos Hochstein, formerly senior vice-president of LNG marketing, now leads the marketing of LNG and partnership interests from Driftwood LNG. CEO Meg Gentle said: “We are reducing our costs and reorganising the company to make Tellurian resilient in the face of current challenges in financial and energy markets. We are redirecting resources to complete the marketing of the Driftwood LNG project, which is fully permitted and ready to begin construction.”

The day before, Bloomberg reported sources saying that Tellurian had laid off 70 staff, or 40% of its workforce, as part of a major restructuring effort. It also said that Tellurian could delay a final investment decision (FID) at its Driftwood LNG project by 12-18 months. In October last year, Tellurian told NGW that an FID on the venture would be taken in early 2020, itself a delay from earlier plans.

At full capacity Driftwood LNG is due to export 27.6mn mt/yr of LNG, the gas coming from the Permian basin where it trades at a hefty discount to Henry Hub. Tellurian announced March 2 it would slow corporate spending and reorganise financing for a 2019 term

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loan because of the uncertain outlook for gas demand.

A long-awaited deal with importer Petronet failed to materialise during the US president Donald Trump’s visit to India in February.

SEMPRA SELECTS BECHTEL FOR PORT ARTHUR EPC WORK

PHOTO: FLICKR.COM/ANTÓN OSOLEV

Sempra Energy and Bechtel have signed a fixedprice engineering, procurement and construction (EPC) contract for the Port Arthur LNG liquefaction project under development in Port Arthur, Texas, the companies said March 3 in a joint statement.

As part of the EPC contract, Bechtel Oil, Gas, and Chemicals, a unit of Bechtel, will perform the detailed engineering, procurement, construction, commissioning, start-up, performance testing and operator training activities for the project. The scope of the agreement

also includes continuing pre-final investment decision engineering to better assure project cost and schedule certainty, the companies said.

The Port Arthur LNG development project is expected to initially include two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services, with a nameplate capacity of approximately 13.5mn metric tons/year of LNG. In January, Sempra and Saudi Aramco signed an interim provisional agreement for transferring equity in the Port Arthur project. The two signed a heads of agreement in May last year for the purchase of 5mn mt/yr of LNG and a 25% equity investment in the project. In December 2018, Port Arthur LNG entered into an agreement with Polish Oil and Gas Company for the sale and purchase of 2mn mt/yr.

The Port Arthur LNG project received authorisation from the US Department of Energy to export domestically produced LNG to countries that do not have a free trade agreement with the US in May 2019.

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news: LNG IN TRANSPORT NGVS ON THE RISE While electric vehicles have stolen the limelight in recent times, the number of new registrations for passenger cars powered by compressed natural gas (CNG) rose nearly 6% from 2018 to 69,900 last year, just over half of which were in Italy.

There were also 1,980 new gas buses and 8,910 new light commercial gas vehicles in Europe. 2,120 new CNG trucks also started on the roads. The number of new LNG powered heavy-duty trucks (4,510) has almost tripled compared with 2018, according to National Gas Vehicle Association Europe (NGVA Europe). The number of CNG filling stations in Europe reached 3,732, while the number of LNG stations rose 50% to 249.

“These numbers confirm the ever-growing attraction of natural gas mobility for European consumers. This is the result of a mature gas vehicle technology with high engine efficiency and performance, widespread infrastructure and low total cost of ownership, but also great environmental benefits of gas in transport,” NGVA Europe’s secretary-general Andrea Gerini said.

PETRONET SEEKS BUILDERS FOR INDIAN LNG/CNG STATIONS India’s Petronet LNG has invited companies to bid for turnkey contracts to design, build and commission LNG/ LCNG fuelling stations. It uploaded tender documents to its website March 19.

Petronet wants five stations built on major highways: Bichhiwara in Rajasthan (on the Delhi-Mumbai route); Palej in Gujarat (on the Delhi-Mumbai route); Palghar in Maharashtra (on the Delhi-Mumbai route); Khakhrechi in Gujarat (on Ahmedabad-Mundra route); and Baldana, also in Gujarat, but on the Ahmedabad-Rajkot route. The company expects work to be completed 270 days after the contract is signed.

The bidder’s annual turnover must exceed rupees 175mn ($2.3mn) if it is an Indian entity, or $2.5mn if a foreign bidder, for the last three years. The last date of submission of bids is May 4.

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Petronet, India’s biggest LNG importer, operates two receiving terminals in the country: one at Dahej in west India and one at Kochi in south India.

BELGIAN NGV NUMBERS UP 40% As part of its financial results released March 25, Belgian transmission system operator Fluxys Belgium revealed a substantial increase of the use of natural gas in road transport in the country.

The number of vehicles powered by compressed natural gas (CNG) in Belgium rose by almost 40% in 2019, from 14,000 to just over 19,000. Around 30 CNG filling stations were opened, bringing the total number in Belgium to 134.

Another 30 or so are at the planning stage and should materialise in 2020. At the end of 2019, Belgium had 12 LNG filling stations for LNG-fuelled trucks, with another six at the planning stage, the company said.

NOVATEK, NAUTICOR TEAM UP FOR BALTIC LNG SUPPLY Russia’s Novatek has signed a letter of intent (LoI) with German LNG bunkerer Nauticor to co-operate in developing LNG supply infrastructure in the Baltic Sea area, the latter said in a statement March 25.

The pair aim to develop the LNG bunkering market through the use of refuelling vessels and trucks. The main focus will be on developing infrastructure along Germany’s Baltic Sea coast.

Novatek is a major LNG supplier to Europe, delivering shipments from its Yamal and Vysotsk liquefaction terminals in northern Russia, while Nauticor has established LNG bunkering supply chains in northwest Europe.

“The commitment of a strong player like Novatek, to support the development of small-scale LNG infrastructure in the Baltic Sea and beyond, underlines Nauticor’s efforts to develop the last mile of the LNG

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supply chain from the terminal to the end-customer,” the Hamburg-based firm’s senior business development manager Gregoire Hartig commented.

Nauticor, which is being bought by Finnish state utility Gasum, is already a customer of Novatek’s Vysotsk LNG terminal. Gasum operates the LNG regasification terminal at Tornio.

LBM/LSM CAN SERVE AS LOWCOST MARINE FUELS: STUDY LNG bunkering association SEA/LNG published a study March 25 on how liquefied biomethane (LBM) and liquefied synthetic methane (LSM) can serve as lowcost and readily available marine fuels while helping to decarbonise the shipping industry.

LBM is derived from four main biomass streams: energy crops, agricultural residues, forestry products and residues and aquatic biomass. There is enough sustainable biomass supply to produce the biomethane necessary for the shipping industry’s needs, especially as power and industry sectors reduce their use of methane as part of a move away from fossil fuels, the report stated.

However, current renewable energy generation is insufficient to produce enough LSM to power a significant share of the global shipping fleet, it continued. To decarbonise the entire sector using LSM, clean electricity generation would need to rise by 2530% by 2050.

Both LBM and LSM are likely to be commercially competitive versus other green fuels, the report stated. The production costs for LBM and other renewable fuels such as green hydrogen and green ammonia are broadly comparable. Liquefaction, storage and transport costs for ammonia are lower than for LBM, but these costs for liquid hydrogen are much higher. Transportation costs for LBM are relatively low, thanks to its global availability.

Green hydrogen and green ammonia are also expected to have a higher bunker price cost mark-up than LBM or LSM, as the infrastructure needed for the latter fuels is already there, being used for LNG, but this is not the case for hydrogen or ammonia.

“The shipping industry faces unprecedented challenges if they are to meet the IMO’s decarbonisation targets and the even more demanding goals being discussed by the EU,” the report stated. “Confusing

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claims and counter claims are being made for different zero-emissions technologies, all of which have decades of research and development before they are proven for safe marine operations, globally available and commercially viable.”

By adopting LNG as a fuel, shipowners are futureproofing their investments against increasingly stringent environmental regulations, as LNG produces considerably less greenhouse gas emissions than the present alternatives, the report stated. And these LNGfuelled vessels can use non-fossil fuel methane such as LBM and LSM in the future with little or no modification, once they become available on scale.

“If we are to make effective, meaningful progress with emissions reductions, waiting for utopia and the ‘perfect’ solution is not an option,” the report concluded.

“We must act today and LNG is the only option that moves us forward on all fronts, now.”

UK LOGISTICS FIRMS ADDS TO LNG TRUCK FLEET UK haulage firm Reynolds Logistics has put two new Volvo FM LNG 6x2 tractor units into operation for a contract with Gasrec, the latter company said March 10. “Replacing two dual-fuel Volvo trucks, the new vehicles will deliver to Gasrec sites around the country – including Sittingbourne, Swindon, Tamworth and the company’s flagship refuelling site next to the Daventry International Rail Freight Terminal,” it said.

Gasrec, which supplies filling stations, projects that one-third of the UK’s 44 metric ton heavy goods vehicles will be running on gas in the next seven years, with about 39,000 gas-fuelled trucks on the road. Gasrec said that “delivering all of our LNG using the latest technology gas-powered trucks is an important landmark.”

The two new FMs – which have a range of around 450 miles when pulling a fully-loaded tri-axle gas tanker – are based at Reynolds’ site in Grays, Essex, and will load daily at the Grain LNG terminal. They are each powered by Volvo’s G13C LNG engines, which operate at a par with a regular diesel model with the same power rating, while reducing CO2 emissions by as much as 95% when fuelled with biomethane.

Reynolds Logistics said it had received “excellent driver feedback on the latest trucks in the company’s fleet.... These LNG-powered trucks have very clear

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environmental benefits and we believe it’s our responsibility to play our part in helping to reduce air pollution as much as we can.”

CANADIAN, JAPANESE PORTS TO PROMOTE LNG AS FUEL

WARTSILA TO EQUIP KOREAN LNG BUNKERING SHIP Finland’s Wartsila has won an order for a cargo handling system for a new 18,000-m3 LNG bunkering vessel, it said March 3.

The ship is being built at the Hyundai Mipo shipyard in Korea, for shipping corporation Korea Line, and will be chartered by Shell.

Wartsila’s contract covers engineering, design, procurement and commissioning of the cargo handling system, including cargo tank design. The company will start supplying the equipment at the end of 2020, ahead of the ship’s delivery in early 2022. The contract includes an option for a second vessel.

PHOTO: FLICKR.COM/EX 22218 - ON/OFF

The Vancouver Fraser Port Authority and Japan’s Tomakomai Port Authority March 5 signed a memorandum of understanding to promote the use of LNG as a marine fuel and work on LNG bunkering services at the Port of Vancouver and Port of Tomakomai, Port of Vancouver said March 13.

“The provision of LNG fuel for ships transiting between the ports of Vancouver and Tomakomai will reduce air emissions from shipping, protecting air quality in port communities, while also reducing contributions to global climate change,” it said.

The Port of Vancouver and the Port of Tomakomai will exchange information and expertise on LNG bunkering, including technical procedures and best practices, and where feasible, coordinate port requirements and

guidelines for LNG bunkering to facilitate the use of LNG marine fuel in both ports.

The development of LNG bunkering services in the Port of Vancouver and Port of Tomakomai will enable the adoption of LNG as a marine fuel by ships engaged in trans-Pacific trade, Port of Vancouver said.

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news: LNG SHIPPING JAPAN’S MOL TO BOOK EXTRAORDINARY LOSS OF $146MN Japanese shipping firm Mitsui OSK Line (MOL) said March 24 that it expects to record an extraordinary loss of $146mn on the consolidated basis for the 12-months ending March 31 on account of losses at its subsidiaries.

MOL Bridge Finance, a unit of MOL, expects to take a hit of $71mn on a loan to dry bulk owner and operator Gearbulk Holding. According to MOL, the loss is expected as it will not be able to recover a part of the loan due to a sluggish market, which is expected to be further exacerbated by the coronavirus (Covid-19) outbreak.

On the charter-out contracts of containerships to its subsidiary Ocean Network Express, MOL said it expects to record a loss of $75mn related to business restructuring for the 12-months that ended in March 2018.

MOL also plans to record a provision for loss on guarantees of $71mn as an extraordinary loss on its non-consolidated financial statements, because the joint guaranty is included in the liabilities of the subsidiary.

However, the provision for loss on guarantees will be eliminated from the consolidated financial results.

Tokyo-based MOL is one of the largest shipping companies in the world. Its fleet includes dry cargo ships, LNG carriers, tankers, container ships, and container terminals. Its LNG tanker fleet includes the Arc-7 winterised tankers used for the Yamal LNG project in Russia’s far north.

FRENCH GTT, EXCELERATE SIGN TERM SUPPORT DEAL French LNG technology firm GTT has signed a five-year global technical services agreement with the ship-owner Excelerate Energy on the maintenance and operation of nine floating, storage and regasification units (FSRUs) equipped with GTT technology. This agreement includes GTT on-site technical assistance for inspection, maintenance, repairs, operations and engineering, GTT said March 11.

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GTT CEO Philippe Berterottiere said he was “pleased to have the opportunity to support a long-term partner like Excelerate Energy in the efficient operations of their FSRUs. This agreement is pivotal to develop customised services, ensuring the performance and safety of each FSRU in operation.”

Excelerate Energy COO Edward Scott said the company looked forward to continuing a nearly two decades long relationship with GTT.

FLEX LNG LAUNCHES LNGC IN KOREA LNG shipping company Flex LNG February 29 launched its newbuild LNG carrier Flex Freedom at the Daewoo Shipbuilding and Marine Engineering yard in Geoje, South Korea, it said in a statement through its Linkedin account the same day.

The 173,400 m3 LNG carrier is fitted with slow speed two-stroke high-pressure MEGI propulsion and reliquefaction system which brings the boil-off down to 0.035%, Flex LNG said.

Once fully refurbished and tested Flex Freedom will be available in the market in Q3 2020, the company added.

MOL, DSME GET APPROVAL FOR NEW REGAS SYSTEM DESIGN Japanese shipowner Mitsui OSK Lines (MOL) and South Korean Daewoo Shipbuilding & Marine Engineering (DSME) have jointly obtained approval in principle (AIP) from Bureau Veritas for the design of a new cold energy use regasification system, CryoPowered Regas, for floating storage and regasification units, MOL said in March.

“The Cryo-Powered Regas system, which MOL and DSME obtained the AIP for this time, will enable to utilise the LNG cold energy as power generation by adopting the Organic Rankine Cycle in the FSRU regasification process. The system is targeted to

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technology in a small-scale pilot facility within 2020 and provide the technology to customers in future FSRU projects.

“Organic Rankine Cycle system itself is a proven technology that has been utilised in multiple onshore LNG terminals for around 40 years. This will be however the world’s first case to adopt the system for FSRU,” MOL said.

PHOTO: FLICKR.COM/LENS ENV Y

reduce the fuel gas consumption and CO2 emission for FSRU by approximately 50% by recovering approximately 70% of the power consumption in the regasification process at maximum rated regas flow rate,” MOL said.

In February, the two companies entered into an agreement to jointly develop the Cryo-Powered Regas technology. MOL and DSME plan to test the

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