Natural Gas World Magazine

NEWS. ANALYSIS. THE INSIDE TRACK. Vol 3, Issue 7 | April 18, 2018

CARVING UP THE ARCTIC:

drilling and shipping

LNG PROJECTS NEED CREATIVE THOUGHT RUSSIA AND THE WEST: NS2 and TPA

INTERVIEW: STATOIL TALKS ABOUT THE IMPORTANCE OF GAS

86

YEARS OF BRINGING THE GAS INDUSTRY TOGETHER

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Editorial: Financing the Future of LNG

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Feature articles

05 Mastery of the Arctic

10 Yamal to Asia, the Faster Way

The undecided legal possession of the Arctic means that different countries are able to assert their rights to it with little fear of redress. So far Russia is making most of the running in terms of business deals, while Norway is busy issuing licences.

The start of LNG exports from Yamal is a decisive shift in Russia’s Far East development strategy, bringing it closer to China and set to improve the economy of the region.

14 Norway's Gassier Future

17 Gazprom Wards off TPA at Home

NGW met Tor Martin Anfinnsen, Statoil’s marketing and trading chief, during the IP Week 2018 conference in London in February, where he spoke about the importance of gas to Norway and Statoil.

The long-standing agreement between Gazprom and the government is holding up, despite the pressure to open up the export pipelines to third-party access: Gazprom's interests are safe for now.

20 Nord Stream 2: Russia Plays with Fire

23 China's Laws Favour Gas

The first few months of the year have not seen any softening in Russia's foreign policy, but this is precisely the time that its actions in one sphere could adversely damage it in another, as it seeks approvals for a key new pipeline.

China's latest addition to its legal armoury for environmental protection should help the growth of its gas industry, as the soil pollution law is intended to complement other normative acts and regulations aimed at cutting emissions.

Vol 3, Iss 7 | April 18, 2018

Table of Contents

25 Vietnam Caves in to China

27 Bunkering in the US

Vietnam has its back against the wall once again, and just like many times before, it comes amid growing pressure from its long-time rival, largest trading partner, and giant neighbour to the north: China.

With the Jacksonville Port Authority leading the way, LNG as a marine fuel is gaining ground in the US.

29 LNG Projects Need Plan B

33 Ecuador Opens Bidding Round

Final investment decisions for the second wave of US LNG development await resolution of several contract controversies, relating to length, volume and creditworthiness. Keeping costs down, meanwhile, is easier said than done.

Ecuador has launched a new bidding round, which includes the country’s only gas producing field, as Quito tries to drum up interest in the slow-moving natural gas sector. But it faces competition from other countries seeking investors.

36 Turkey's Tempting, Onshore Gas Tight gas prospects deep under European Turkey (Thrace) could produce 1bn ft³/d (10bn m³/yr) by 2025 if the capital is available to develop them, according to TransAtlantic Petroleum, a US independent active in the region for over a decade. Vol 3, Iss 7 | April 18, 2018

4

EDITORIAL: FINANCING THE FUTURE OF LNG In the last year or so, much importance has been attached to new LNG export projects to fill an expected 150mn metric tons/ year (mt/yr) of anticipated demand after 2025. New demand has been left pretty much to Australia and the US to fill, with varying degrees of financial success. Australian projects, for example, have suffered from massive cost over-runs, while demand in key Asian markets softened in the wake of the 2008 recession. China’s recent surge in demand helped the Australian projects to a certain extent, and signalled that those projects, and others in the US that are close to being complete, could fare quite well. But what comes next? The 16th Americas Summit of the CWC World LNG & Gas Series in March set out to answer a few key questions: How will new North American projects impact the global industry over the next two years? In the longer term, how will new LNG sales contracts evolve? How will new projects be financed? How will new technologies impact the LNG business? Will LNG as a transportation fuel ever become a relevant demand source? Finally, how will a developing spot market for LNG impact prices and pricing hubs? The first of those is pretty obvious. Cheniere Energy’s new export terminal at Sabine Pass, Louisiana, only began delivering fuel to global markets in 2016, but already it has delivered more than 300 cargoes to 25 countries. By 2020, with a fifth train at Sabine Pass and the 2019 commissioning of the first two trains at its Corpus Christi terminal in Texas, Cheniere expects to be delivering 70 LNG cargoes every month to about 24 FOB customers – meaning many of those cargoes can be delivered to virtually any market in the world, from Europe and the Middle East to Asia or South America. Dominion Energy’s Cove Point terminal is also expected to begin making global deliveries this year, along with Kinder Morgan’s Elba Island terminal in Georgia and Sempra’s Cameron LNG terminal in Louisiana. Freeport LNG in Texas is expected to join the market in 2019. Beyond 2020, however, the supply picture is murkier, even though as much as 1bn mt/yr of new capacity has been proposed, in the US, in Canada, in Russia and in Africa. Whether all of those projects will ever be built, and which, remain open questions, in part because there are no clear answers to any of the other questions the Houston conference addressed. Tomorrow’s LNG sales and purchase agreement (SPA) contract, for example, is likely to look vastly different than yesterday’s long-term, oil-indexed agreement between one seller and one buyer. Buyers with long-term contracts that will begin to expire in 2020 are not interested in rolling over those longterm arrangements – instead, they want shorter terms, smaller volumes and flexible pricing. New buyers, many of whom lack

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the credit resources of the first tranche of LNG buyers a decade ago, are not in a position to accept the risks associated with a 20-year sales and purchase agreement – they will want to purchase largely on the short-term or spot market. That, of course, raises the next question: Who will finance new LNG export projects? In the past, long-term SPAs based on remarkably high global gas prices linked to soaring oil prices made it easy for banks to extend project financing. In the new LNG world, 10-15 years is the new long-term and more and more contracts are for even shorter periods, in some cases only five to seven years. And many of those contracts are with buyers considerably less credit-worthy than state-owned gas or power utilities. Few banks are willing to offer project financing under those conditions, leaving developers and traders to take on more of the financial risks associated with greenfield export projects. Some of today’s pre-FID projects, in the US, in Canada or elsewhere, may never see shovels in the ground. And new technologies? What will be the impact of floating LNG, for either liquefaction or re-gasification? Floating liquefaction technologies offer flexibility in siting and the potential for reduced EPC costs. Mid-scale, land-based liquefaction trains are also gaining traction, suggesting that future export projects will be more closely tied to market need, with new, smaller trains added as demand warrants. And what of LNG as a fuel? The existing global LNG market is based primarily on LNG as natural gas, providing heating fuel for residential, commercial and industrial customers or fuel to generate electrical power. In today’s carbon-constrained world, it would seem obvious that LNG as a transportation fuel would offer limitless future demand, but there appears to be little prospect that LNG will make any meaningful penetration into land or marine fuel markets for at least the next decade or more. Last, but certainly not least, is the development of a spot market for LNG. Projections suggest that up to half the 400mn mt/yr of global LNG trade could be done on the spot market by 2020. But without the liquidity offered by a single, globally-traded marker price – like Brent in the oil business – there is some question whether a viable spot market, with cargoes bought and sold with the touch of a button on a computer, will ever come to pass. There is no doubt that tomorrow’s LNG business will not look much like yesterday’s. But the biggest question – what exactly will it look like – remains unanswered. NGW

5 MASTERY OF THE ARCTIC The undecided legal possession of the Arctic means that different countries are able to assert their rights to it with little fear of redress. So far Russia is making most of the running in terms of business deals, while Norway is busy issuing licences. Advances in liquefaction technology and prospects of opening up much shorter transport routes that link North America and Eurasia have enhanced the prospects of Arctic gas exploration and production. The 40% shorter distance, compared with the Suez or Panama canals, still faces problems in winter but global warming could even solve that problem too by 2040. As a result, the Arctic has become a strategic region for governments and the gas industry but views on how to manage it range from militarisation to regional co-operation and trade. Norway, Canada, US, Russia, Denmark (Greenland) and Iceland want sovereignty over Arctic areas and hence exclusive rights to its resources and some have applied to the United Nations’ Commission on the Limits of the Continental Shelf (CLCS). However the status of the Arctic is undefined in international law, with some bodies arguing that it should remain a no-man’s land. Iceland claimed its right to the Aegir Basin area and the western and southern parts of Reykjanes Ridge (2009).

Countries with no Arctic territory are also keen to have a say in its future: China, Japan and the South Korea are interested in transportation routes and energy resources. And the EU presented an integrated European Union policy for the Arctic in April 2016 and appointed its first ambassador at large for Arctic Affairs, Marie-Anne Coninsx, then the EU ambassador to Canada. The keen interest for this region is well understandable: there is a lot at stake above latitude 66°30' N. The gas deposits in the Arctic are abundant and account for about 22-30% of the world’s undiscovered natural gas resources.

Arctic Mean Estimated Undiscovered Technically Recoverable, Conventional Oil and Natural Gas Resources

Denmark has filed five submissions, and these were made in respect of the north of the Faroe Islands (2009), the FaroeRockall Plateau Region (2010), as well as the Northern (2014), North-Eastern (2013) and Southern Continental Shelf of Greenland (2012). The Norwegian submission covered the North East Atlantic and the Arctic (2006) - some of these claims were regulated independently by Norway and Russia in the Treaty concerning Maritime Delimitation and Co-operation in the Barents Sea and the Arctic Ocean in 2010. Although the treaty is unique in the Arctic context, it does omit a sensitive topic, namely future gas and oil exploration and production around the Svalbard archipelago. Canada has so far only made one submission, in respect of the Atlantic Ocean (2013). However, it is expected to file its second, the so-called “North Pole” final submission, concerning the Lomonosov and Alpha-Mendeleev Ridges somewhere in 2018. Russia’s submission of 2015 is under review by the CLCS which met February 12-23 this year and its decision will have a substantial impact on Arctic exploration and the shape of future transportation routes in the far north.

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U.S. Energy Information Administration

6 The Arctic Ocean covers 14mn km² and is mostly less than 500 metres deep. Digital technology for seismic and other prospecting methods is moving forward, saving time in both exploitation and remediation if things should go wrong. However, environmentalists have put forward radical arguments for a total ban of Arctic exploration for oil and gas, arguing for example that it is incompatible with the Paris Agreement of 2016. These claims have yet to be tested in the courts. For the gas industry the signal is clear however: corporate directives and social responsibility strategies should improve the overall standardisation and harmonisation of technical and operational business practices in areas such as health, environment and safety. Transparency and exchange of the best practices in these areas between enterprises is therefore advisable. As for today, it is fair to say that Arctic, covering an area of roughly 20mn km², remains an unsolved puzzle and poses a challenge in political, economic and environmental terms, as Norway demonstrates. Norway, known for its welfare policies, is an energy nation and a petroleum giant. Besides, Norway is a polar champion, with polar heroes – such as Fridtjof Nansen and Roald Amundsen – and also a well-established Arctic strategy thanks to the work of Stoltenberg’s two consecutive cabinets. Their work has defined the northern regions as Norway's most important foreign policy area. Norwegians have long developed their competence in Arctic oil and gas exploration and parliament opened up parts of the Barents Sea as early as 1989. On the other hand, most of the country’s electricity comes from hydropower: clean energy accounts for 69% of Norway’s total energy use. Its energy policy emphasises sustainable development and assigns Enova organisation a main responsibility for Norway’s conversion towards being a lowemission society. And a previous prime minister, Gro Harlem Brundtland, chaired the World Commission on Environment and Development (WCED) and coined the concept of sustainable development - first introduced to the public in 1987 by WCDE’s report Our Common Future. The minister of petroleum and energy, Terje Soviknes (Progress Party) replaced Tord Andre Lien at a time when environmental groups brought the case against the Norwegian government claiming that the king’s resolution of June 10, 2016, which permitted the 23rd round of licensing, violated section 112 of the constitution. Section 122 says that every person has the right to a clean and diverse environment and furthermore natural

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Credit: MCT

resources should be managed by comprehensive long-term considerations whereby this right will be safeguarded for future generations. On January 4 this year, the Oslo District Court dismissed the case; but environmentalists were ready for that, announcing a month later their plans to appeal to the Supreme Court. Also, in the 23rd round three licences in the northeastern part of the Barents Sea were awarded to Statoil and Cairn’s subsidiary Capricorn. Russia claimed this violated the Svalbard Treaty (1920) but Lien explained to the Russian government that Svalbard was a part of the Norwegian continental shelf and hence the awards were valid. The 1920 Treaty of Svalbard recognises Norway’s sovereignty over the archipelago but gives all countries the right to exercise maritime, industrial, mining and commercial activity where the Norwegian rule of law applies. American, Russian and Norwegian companies began drilling for oil and gas on Svalbard as long ago as 1960, the first commercial drilling taking place in Kongsfjorden (Kvadehuksletta 19621966). But it took until the late 1980s to find commercial gas on Svalbard. Soon after, Russian Trust Arktikugol made a significant oil discovery in Billefjorden (1992). In 2004, Russia announced it would proceed with oil and gas exploration around the Svalbardarchipelago, and it remains determined to keep this promise.

7 Announced Announcedblocks blocksininthe the

24 Licensing Round 24 Licencing Round th

The Norwegian Sea

th

The Barents Sea

Credit: Government of Norway

On August 29, 2016, Norway invited companies to nominate blocks for the 24th licensing round in the frontier areas of the Norwegian Sea and the Barents Sea. In total, 11 companies took part: Anglo-Dutch Shell, AkerBP, UK Centrica Resources, Russian-owned DEA, Japanese Idemitsu Petroleum; Kuwaiti Kufpec, Swedish Lundin, Austrian OMV, RN Nordic Oil, Statoil Petroleum; and German Wintershall. On June 21, 2017, the 24th licensing round was announced, and 102 blocks were offered: 93 in the Barents Sea and 9 in the Norwegian Sea.

of the committee underlined the importance of the petroleum industry for Norway and proposed that the parliament ask the Norwegian government to submit a new petroleum report on Norwegian oil and gas policy – in view of the climate challenge and the new market situation.

The 24th round’s awards are to be announced in the first half of 2018.

Neither of the proposals were adopted. On February 27 this year, the parliament rejected the joint GP and SLP proposal as well as the Bastholm’s proposal by a vote of 93 to 8.

Soon after the 24th round was announced, on October 10, 2017, the parliamentary commissioner Une Aina Bastholm (The Green Party) submitted a proposal asking parliament to suspend the planned allocation of new exploration permits. On February 15 the parliamentary committee on energy and environment issued an official response to this proposal. Most

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In addition, the parliament was asked by the Green Party (GP) and the Socialist Left Party (SLP) to stop the APA awards as well.

Recently, it was also proposed in the parliament to ask the Norwegian government to submit a new petroleum report on Norwegian oil and gas policy in view of climate challenges and the new market situation. The results of the parliament’s votes (52 to 48) that day were only marginally in favour of dismissing this proposal.

Offered awards in predefined areas in North Sea

Offered rewards in predeďŹ ned areas of North Sea PL 554D: 34/5,6 Total Aker BP Point

40% 30% 30%

PL 927: 35/7,10 Wintershall Capricorn

50% 50%

PL 926: 33/9,12, 34/10 Faroe DNO Concedo

40% 30% 30%

PL 922: 30/3 Spirit VNG DNO Maersk

40% 20% 20% 20%

PL 043ES: 29/6, 30/4 Total Statoil Petoro

51% 19% 30%

PL 918S: 24/6 Statoil Lotos

PL 932: 34/3,6, 35/1,4 Aker BP MOL

60% 40%

PL 914S (Ivar Aasen Unit): 16/1 Aker BP 34,7862% Statoil 41,473% Spirit 12,3173% OKEA 0,554% Wintershall 6,4615% Lundin 1,385% VNG 3,023%

50% 50%

PL 777D: 15/5 Aker BP Point Wintershall Petoro

40% 20% 20% 20%

PL 818B : 15/3 Aker BP Statoil Lime

40% 30% 30%

PL 912: 16/4,5,7 ConocoPhillips Point Pandion

40% 30% 30%

PL 907: 7/7,8,10,11 Aker BP Maersk Wellesley Petoro

40% 20% 20% 20%

PL 906: 7/11,12 Aker BP Faroe Maersk Statoil

40% 20% 20% 20%

PL 810B: 2/1, 8/10 Faroe Spirit Aker BP

40% 30% 30%

Credit: Norwegian Petroleum Directorate

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PL931: 34/6,9, 35/4,7 Wellesley DNO

60% 40%

PL 929: 35/6, 36/4 ENGIE DNO DEA Pandion

40% 20% 20% 20%

PL 928: 35/9 Spirit Capricorn

50% 50%

PL 924: 31/2,3, 32/1, 35/12 Statoil 70% DNO 30%

75% 25%

PL 913: 15/3, 24/12 OMV Repsol

APA 2017

PL 923: 31/1,2 Statoil DNO Wellesley Petoro

40% 20% 20% 20%

PL 740C: 31/4 Faroe Point

50% 50%

PL 875B: 30/10 Suncor Capricorn

60% 40%

PL 917: 25/7,10 ConocoPhillips Suncor Lundin Point

40% 20% 20% 20%

PL 915: 16/1, 25/10 Aker BP Statoil Spirit

35% 50% 15%

PL 167C: 16/1 Statoil Lundin

80% 20%

8

PL 930: 35/6 Statoil Wellesley Spirit Point

40% 20% 20% 20%

PL 153C: 35/6,9 ENGIE DEA Shell Wintershall Petoro

30% 8% 12% 20% 30%

PL 925: 35/9,12 Wellesley Concedo

90% 10%

PL090I: 31/2 Statoil ExxonMobil Idemitsu ENGIE

45% 25% 15% 15%

PL 921: 32/4,7 Statoil DNO Petoro

50% 30% 20%

PL 920: 30/5,8 OMV VNG

60% 40%

PL 919: 25/4 Aker BP ConocoPhillips Lundin

65% 20% 15%

PL 956: 25/8 Point Suncor

70% 30%

PL 916: 16/2, 25/11 Aker BP Lundin Statoil Petoro

40% 20% 20% 20%

PL 775B: 16/4,5 ConocoPhillips Concedo Point Petoro

40% 20% 20% 20%

PL 911: 16/8 Point ConocoPhillips

60% 40%

PL 910: 9/2,3 Repsol OKEA LOTOS

61,111% 16,667% 22,222%

PL 909: 9/3,6, 10/4 Repsol Skagen 44

70% 30%

PL 908: 9/11,12, 10/10,11 Statoil 70% Faroe 30%

PL 065B: 1/3 Aker BP Faroe PL 006E: 2/5 Faroe Aker BP

55% 45% 85% 15%

PL 019E: 7/12 Aker BP Faroe PL 905: 2/2,5 MOL OMV

80% 20% 50% 50%

PL 863B: 7/9, 8/7 Shell Aker BP

60% 40%

PL 904: 2/9, 3/7 MOL Statoil Lundin Petoro

30% 20% 20% 30%

9 The aim of the Norwegian government is clear. As Soviknes himself said at the Oslo Energy Forum February 10, “Gas is part of the solution – not the problem.” Norway will drill. And gas will be needed. This is especially true for the European Union where gas, known for its environmental benefits relative to other fossil fuels, has been identified as the main solution to the problem of oil, coal and carbon emissions. Norway’s prime minster, Erna Solberg, said that allocating attractive exploration areas was a key element of Norway’s petroleum policy. These intentions are also reflected in the recent Award in PreDefined Areas (APA 2017) licencing round. In mid-January the ministry awarded 75 exploration licences to 34 companies to carry out exploration work in Norwegian fields in mature areas of: the North Sea (45), the Norwegian Sea (22) and the Barents Sea (8). As such, the APA 2017 resulted in a record high number of awards, 19 more than the previous APA round in 2016. So far however, the greatest records in the Arctic have been set by Russia. Aware that it accounts for half the Arctic population and owns more than a half of all the Arctic coastline, Moscow has taken the opportunities that arise in the High North with determination. President Vladimir Putin has kept the Arctic high on his political agenda. In 2014, the government issued its Principles of the Arctic State Policy of the Russian Federation to 2020 and Beyond. This country has the largest fleet of nuclear icebreakers in the world. One of them is even accessible to the public. For a fee of $28,000 an individual can take a 14-day cruise in the High North on board the 50 Let Pobedy – which dates the vessel’s naming ceremony to 1995, 50 years after Russia's victory in the Second World War. In August 2017, this icebreaker set a record for a voyage from Murmansk to the North Pole in just 79 hours. Also, last summer the Russian icebreaking LNG carrier Christophe

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Credit: Total

de Margerie made its first transit through the Northern Sea Route. The vessel carried LNG from Snohvit offshore Norway to Boryeong in South Korea and delivered a cargo for Total Gas & Power. The Christophe de Margerie took 15 days, half the time a transit through Suez Canal would normally take. It is perhaps not too early to say that while some Arctic fronts are forming, the centre of gravity of the global gas market is moving towards the Asian-Pacific region where the Arctic component plays a strong, if not a pivotal, role. However, the territorial claims to the Arctic can complicate the safety of the region until they are solved by agreements between the involved countries and with respect to the UN CLCS’ technical recommendations. The final shape of the Arctic is yet to be decided. Paulina Landry

10 YAMAL TO ASIA, THE FASTER WAY The start of LNG exports from Yamal is a decisive shift in Russia’s Far East development strategy, bringing it closer to China and set to improve the economy of the region. With the start-up of the first 5.5mn metric tons (mt)/yr train at Yamal LNG late last year, Russia is ready to expand its share of the Asian gas market and to gain access to China in particular. Chinese entities have a 29.9% stake in Yamal LNG, with CNPC on 20% and Silk Road Fund the rest. The new source of supply will increasingly affect the global LNG market, although its confinement in winter to mainly European markets will reduce its ability to arbitrage without further investment in storage capacity near Asia. If Sakhalin Energy is expanded and Arctic LNG-2 goes ahead, by 2025 total Russian pipeline and LNG exports capable of reaching Asia could amount to 106.5bn m³/yr, equivalent to Nord Stream 1 and 2 – although this would not be only Gazprom’s equity gas, unlike its Europe-pointing pipelines.

Yamal LNG (Credit: Total)

Nevertheless all these projects are very important to Russia, as it has often talked about the need to diversify its gas market and the ‘Asian pivot’. It is too heavily reliant on EU countries that while they pay more per unit than the domestic markets do, now are becoming less lucrative: the European Union is doing all it can to limit the economic rent Gazprom may derive from these sales. And Asian gas demand growth seems limitless.

Projects under way When complete, Yamal LNG’s output will be either 16.5mn mt/ yr or 17.4mn mt/yr, depending on whether the operator adds a small fourth train; and it is Russia’s second, following the 9.6mn mt/yr Gazprom-led Sakhalin Energy project, whose expansion, with the help of Anglo-Dutch major Shell, is still in doubt. It comes just before the Power of Siberia pipeline (38bn m³/yr), a direct onshore line to China, comes onstream which is due in 2020, starting off slowly.

Yamal LNG Project (Credit: Yamal LNG)

The Power of Siberia’s Russian section is already substantially completed (75.5% as of late March) and uses only Russianforged steel, as part of the national drive towards cost-savings and self-sufficiency in high-grade technology. As with Sakhalin Energy, Yamal LNG is just over half-owned by a Russian entity with 50.1% – although this time it is a private company, Novatek, which is partly owned by French Total, that

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ARC7 tanker (Credit: Yamal LNG)

11 is in the driving-seat. A few years after Power of Siberia, Arctic LNG-2 could be launched, coming on in three stages between 2022 and 2025, and also using Russian technology. That is to be another three-train project of 18.3mn mt/yr capacity and it will depend on a different resource base from Yamal LNG, although geographically close to it: the Gydan Peninsula is just across the Gulf of Ob from Yamal. Both Yamal LNG and Sakhalin have been producing above nameplate so far: Sakhalin Energy produced “upwards of 10.9mn mt” in 2016 compared with the projected 9.6mn mt/yr, Gazprom said; while the freezing Yamal winter also helped liquefaction at Novatek’s plant. Output was 9% higher than planned, at least for the first few months of operation.

Benefits of the NSR LNG cannot be shipped eastwards to Asia through the Northern Sea Route (NSR) at present between November and June without icebreakers. But a trans-shipment depot at Kamchatka would allow for storage in summer and onward shipment from conventional tankers in winter, depending on the size of the storage.

A storage facility for 20mn mt of LNG is under consideration. However, Russia’s state-owned nuclear icebreaker operator Atomflot is planning to make more such vessels in order to keep the eastern part of NSR open throughout the year. Taking a cargo from Sabetta to China, South Korea, or Japan takes two weeks using the NSR but over a month going through the Suez Canal, MOL Europe & Africa commercial manager for LNG and offshore, Kota Okada, told NGW in an interview in March; and Asia is less than a week’s sailing from Kamchatka. The NSR is strategically very important to Russia as it leads to the Far East; a logistics base at Kamchatka could support the transport of other goods from Russia to Asia as well. But the focus for now is on LNG: Russia wants to increase LNG exports as fast as possible, as it is strategically important, MOL says. In February 2018, MOL signed an MoU with the Far East Investment and Export Agency, part of the ministry for the development of the far east, obliging the two sides to cooperate with each other in the development of the NSR and the Russian Far East.

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Northern Sea Route (Credit: MOL)

This explains Moscow’s immediate and substantial support for the Yamal LNG project when sanctions were imposed – mobilising state Sberbank funds and investing in Sabetta port construction – allowing the project to remain on time and budget.

MOL already has a relationship with a Chinese operator: it shares the Yamal LNG fleet, which will have three Arc-7 icebreakers and four conventional tankers, with Cosco Shipping. Arc-7s break the ice by going stern-first, which is where most of the vessel’s weight is. The tankers go through ice up to 1.5m thick at over 5 knots, but can still move through it even when the ice is 2.1 While other projects in the world are focused on a certain rate metres thick. of return and conventional economics of gas production costs and netbacks, for Russia the overriding aim is relationships – MOL’s first MOL Arc-7 tanker Vladimir Rusanov was built at a especially with China, South Korea and Japan – and the strong cost of $350mn, Okada said, and has completed ice testing in strategic position these relationships may bring. the Kara Sea in March. After the hull was inspected for signs of stress in the Sea of Murmansk, it sailed to Sabetta to collect the MOL is also thinking about the hydrocarbon resources under the first cargo. Arctic, some of which arguably belong to Russia although there is no convention yet on dividing up the spoils under the ice (see Mastery of the Arctic). Experience and relationships gained from shipping would stand MOL in good stead if these resources are ever to be developed. Russia’s own upstream activities in the Arctic need foreign technology which is now prohibited by sanctions. US major ExxonMobil decided last year to abandon its Kara Sea project, where it partnered with Rosneft, leaving the latter without the means to produce oil and gas from the one well they drilled. Ice Trials of “Vladimir Rusanov” – MOL/CS’s First Arc-7 (Credit: MOL)

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13

The LNG carrier "Christophe de Margerie" (Source: Total)

MOL is to receive another vessel in September 2018 and the third Arc-7 a year later, all from the DSME yard in Korea. Fluxys’ 180,000 m³ LNG storage and trans-shipment tank at Zeebrugge will be complete and on schedule next year, a year after Yamal LNG started although it is not apparently being delivered late. In the meantime Yamal LNG tankers can use Gate in the Netherlands, Montoir on the French Atlantic coast or Grain LNG in southeast UK, for trans-shipping or for injection and withdrawal from land-based facilities. Sovcomflot was to have built a number of tankers but sanctions hit the project, so in the event, it built only the Christophe de Margerie, named after Total’s previous CEO who drove the French company’s Russia strategy. Conventional LNG tankers have four engines; Arc-7s have six, giving them 50% more power when needed – for ice-breaking, not in open water, when they are not used – plus azipods. Designed by ABB, they allow the propeller shafts to be swung round: the heavy stern is what breaks the ice so they need to turn round. That also means two bridges and more officers: there is a crew of 35 for ice-class, normally it is less than 20. The tough operating regime – temperatures are often below -30C and sometimes reach -50C – means more equipment; and therefore more engineers are needed to service it. There is also a lot of redundancy as equipment cannot easily be dispatched from shore when the tanker is cutting through ice, and so also needs to be carried around. MOL works with port operator Rosmorport, which controls the majority of Russia’s harbours and has experienced ice pilots for ice navigation and MOL contributes to the cost of training its crew, who are MOL employees, Okada said.

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Before Yamal LNG there was not much demand envisaged for Arctic vessels, although nuclear vessel operator Atomflot has helped train crews in ice navigation. MOL is also required to help the development of Polar Water Operations Manual, which is one of the requirements under the Polar Code, he said. If Arctic LNG 2 goes ahead, that will need new vessels. The 18.3mn mt/yr plant, yet to be approved, is to come on line in stages, from 2022-2025. By that point, the hope is the eastern sea route will be open for longer but also there will be more nuclear icebreakers. As things are, less and less ice forms each year – this has been noticeable even over the last decade – so this could be feasible, he said. Vessels that service output from Norway's Snohvit LNG plant are not designed for ice as it does not form in the Barents Sea along Norway's northern coast, but Yamal LNG could sublet its own tankers to them if needed for using the NSR; or conventional tankers for Snohvit could pay Atomflot an escort fee. Arc-7 tankers, being icebreakers, do not require an escort, he said. Traders at London's IP Week gas panel last month took the view that the start of Yamal trade into China this summer could herald a new dynamic in summer supply fundamentals, with Vitol's head of LNG Pablo Galante Escobar suggesting it could lead to weaker summer prices once shipments start arriving in the Asia-Pacific market 14 days after leaving the Yamal LNG complex (NGW Magazine, Vol.3, Issue 5, p20-22). William Powell

14 NORWAY'S GASSIER FUTURE NGW met Tor Martin Anfinnsen, Statoil’s marketing and trading chief, during the IP Week 2018 conference in London in February, where he spoke about the importance of gas to Norway and Statoil.

Troll A Platfrom (Credit: Statoil)

Norway reached record gas sales in 2017, despite the fact that past forecasts predicted decline. How was this achieved and what was Statoil's contribution?

In the mature areas of the North Sea and the Norwegian Sea we can develop smaller discoveries because they can be easily tied into the existing infrastructure.

Several factors contribute to these figures. First, the production permit for Troll has been increased in two steps, from 30 to 33bn m³ for gas year 2016 and then to 36bn m³ for gas year 2017. Second, some volumes from new fields add to the total volume. And third, the regularity both at both producing platforms in the pipeline system and at the three processing plants – Karsto, Kollsnes and Nyhamna – has been very high.

In the Barents Sea, which the NPD believes contains most of the undiscovered resources, discoveries will need to be larger to support construction of new pipeline infrastructure or new LNG trains.

According to the Norwegian Petroleum Directorate (NPD) the future looks even brighter. How is this going to be achieved and is it sustainable? The NPD recently published its revised outlook regarding reserves and production and their report shows there is a potential for the NCS to maintain a high production level in the medium term, ie into the next decade. As one would assume, there is more uncertainty regarding the longer term. By the mid-2030s, the NPD projects that one third of the production is from fields not yet discovered. In other words, exploration and new discoveries will be key in the longer term. In addition, geography and size of discoveries will be important.

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There is also potential in improving the recovery rate and from depleting oil reservoirs that will be phased out, hence no longer needing gas for reinjection to support oil recovery. Europe depends on Norwegian gas supplies into the future as a balance to the ever-growing Russian gas supplies. And yet Europe is not giving consistent signals about what these needs will be in future, to ensure certainty so that oil and gas companies can invest in long term projects. How is this affecting Statoil? Any company needs to be certain that there is a market for its products before making large investments. This is especially important for the gas industry because of the long lead time from investment decision to start-up of production. It is very important that framework conditions are in place in the EU that encourage both exploration and investments in new production

15 What are the key drivers in Statoil's gas strategy? The NCS naturally remains our main engine and key source of supply, with the EU, especially northwest Europe and UK, being the key markets for our pipeline gas. Our fields are literally at the EU’s doorstep and our production is for all practical purposes part of the EU’s indigenous supply. Put simply, we produce what we can and react to price signals so that we sell as much as possible where we get the best return. We have a lot of flexibility in transportation, with five different delivery points in the key markets. When it comes to LNG, we have Europe’s only large liquefaction plant. We sell our LNG partly on long term contracts and partly on a spot basis. Where the spot volumes end up will depend on price signals and arbitrage opportunities. On top of our equity production we add third party volumes to our portfolio and utilise the flexibility that we have in shipping and contracts to maximise value. We also have significant gas production in the US, and our model is to reach premium markets such as Manhattan and Toronto

We have come a long way with our existing production, and in Norway we have developed both technological and operational measures that make the NCS stand out. The government has played a crucial role in this, both with a stick in terms of CO2 taxation and with carrots in terms of incentives. Statoil-operated installations on the NCS have an average CO2 intensity of 9 kg/barrel of produced oil. The global average is 17 kg of CO2/barrel. Statoil’s target for 2030 is a carbon intensity of 8 kg/produced barrel for our global operations. When it comes to new production, from exploration or acquisitions, we target prospects that are low on carbon footprint and high in value. We believe this position will be a competitive edge in the long term. Our second main direction is our own renewables business. We have a separate business area, New Energy Solutions (NES), which is building a significant portfolio of assets. So far offshore wind has had priority, as this is an area where we can utilise our expertise from offshore development and operations. But we are also working on solar projects.

Statoil coined the phrase 'high value – low carbon'. What do you mean by this and how do you reconcile the two with your natural gas plans?

The third direction is making natural gas green, with CCS as a key element.

We believe natural gas is an enabler for both. It is the fossil fuel with the smallest carbon footprint and contributes to reducing carbon emissions, especially when replacing coal. Natural gas is also flexible in power generation and can solve the intermittency challenge that still comes with renewables.

While doing this, and in order to meet the world’s energy demand, we will continue investing in exploration for oil and gas, and we will invest in projects that can bring more barrels and more gas to our portfolio. We firmly believe that the world will need both oil and gas as well as renewables also towards 2050.

We believe that gas remains a destination fuel and not only a transition fuel. It is difficult to foresee that electrification will be the solution for all segments, especially if it is supposed to be 100% based on renewables. There will be a need for gas.

What is your technology strategy and how does this contribute to achieving cost competitiveness in a low gas price environment?

There are also ways to remove CO2 emissions from gas altogether. We are looking into models where we make hydrogen from natural gas by removing CO2 and reinjecting it into the seabed to be safely stored there. This pre-combustion technology is proven and tested, so the job is to do it at scale and in a way that is sustainable also from a commercial perspective. This is exciting, and we are optimistic. Statoil is proud of its Climate Roadmap. Can you explain this and what you are doing to ensure that Statoil continues to be a serious player in the hydrocarbons industry while driving this? Our low-carbon efforts take three main directions. The first one is constantly reducing emissions from our own production.

On production and transmission, we focus on technology that strengthens safety and reliability as those are the two most important issues for our people and for consumers. We have also taken large steps on automation and digitalisation of our offshore activities, and we are reaping effects from implementing the LEAN methodology. When it comes to marketing and trading we have modernized our contracts and made them simpler to follow up, reducing costs for both seller and buyer. We are also moving forward on digitalisation, where we have started with algorithmic trading and we are part of an industry initiative in blockchain technology for post-transaction deal handling, which we believe will make completion of trades more secure and quicker while also reducing costs.

16 NPD says Norway's future gas reserves depend greatly on developing the Barents Sea and Arctic regions. Yet there is increasing resistance within the country against this. How is Statoil pursuing this? We understand that there are concerns. Our job is to demonstrate every day that we can develop and operate installations without harm to the environment, people or communities. We do not deny the fact that there is risk involved in our industry. But we believe our track record shows that we are able to manage risk in a good way. We have a dialogue with relevant authorities, political parties, local communities and organisations to find solutions that can work for all parties. Public opposition to oil and gas drilling is increasing. For the first time, an opinion poll last year showed a majority of Norwegians favouring leaving some oil in the ground. Is this a threat to future gas production in Norway? Any oil and gas company needs a licence to operate and ultimately it is the public, though governments, that decide the terms. Again, we as an industry need to demonstrate that environmental risks can be managed. At the same time, we need to show what the oil and gas industry means to society and local communities in terms of welfare and jobs, directly and through ripple effects. Our CEO (Eldar Saetre) has also stated that some oil will have to be left in the ground. But we believe that this is not a threat to our gas production.

Many of the Energy Outlooks, including Statoil's Energy Perspectives, forecast a bright future for natural gas well into the future and identify the need for continued investments in new production. Do you share this and how sustainable is this in a competitive low gas price and climate change environment? Yes, we share this view. It is easy to get the wrong perspective if you look at the world through a pair of European lenses. Gas has been under pressure from policy makers in Europe for a period but now we see that gas has had a comeback the last years and that there seems to be increasing recognition for what gas brings to the table also in a low carbon future. Economic growth and a growing population, particularly in Asia, means that the world will need more energy. Gas will be a key enabler both to ensure energy security but also to reduce carbon emissions and to improve air quality in major cities. We already see that gas is called upon as a solution to health problems caused by particles and soot in major cities in Asia. Asia will need a lot of imports and will remain the number one destination for LNG in the foreseeable future.

There is also the apparent contradiction of the Norwegian Sovereign Wealth Fund that was on the back of Norway's oil and gas industry, but now it is about to divest of its fossil fuel stocks. What is your view on this and on the risk that it may lead to wider divestments by international institutions?

Credit: Statoil

I think most will agree that it is best not to keep too many eggs in one basket. The fund’s suggestion to divest from fossil fuel stocks is based on risk management considerations and nothing else. Since its main revenue stream comes from the State’s income from oil and gas, it makes perfect sense to reduce that exposure by not investing the fund’s money in oil and gas companies. Other funds do not have the same risk management concern to consider.

“‘Equi’ is the starting point for words like equal, equality and equilibrium. ‘Nor’ signals a company proud of its origin. Together, Equinor is a powerful expression of who we are, where we come from and what we aspire to be. We are a values-based company, and the name describes how we want to approach people and the societies where we operate.

In your presentation at the IP Week conference you talked about LNG. How do you see the future of LNG? Could this be a way to monetise north Barents Sea gas discoveries? We see a strong market for LNG with Asia, especially China as a main engine. The market is becoming increasingly commoditised and we see that the LNG market also has an effect on European gas prices. We already have cargoes going into Asia Pacific. If we make further discoveries in the Barents Sea, LNG is clearly an attractive alternative.

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Statoil plans to change its name to Equinor. What has led to this and what is the message in this. Why Equinor?

We will by no means stop being an oil and gas company, but we want to be more than that. As a major player we want to take part in shaping the future of energy. There is no doubt that output from renewables will grow tremendously in the coming years. We want to take part in this growing business, utilizing our experience from offshore development and operations, and from marketing and trading of energy commodities, to create value for shareholders and societies. Charles Ellinas

17 GAZPROM WARDS OFF TPA AT HOME The long-standing agreement between Gazprom and the government is holding up, despite the pressure to open up the export pipelines to thirdparty access; Gazprom's interests are safe for now. The question of whether to liberalise Russia’s gas system so that independent producers can access export markets has cropped up with particular frequency in the context of Nord Stream 2. If the government allowed Rosneft and others to access the 55mn m³/yr pipeline to Germany then the problem of Gazprom’s monopoly would be solved, and the European Commission would have one less problem to overcome. But so far the idea has been rejected as not being best for Gazprom – and hence not best for Russia either. In the oil market, competition between traders is growing. Although a potential new trader is not likely to enter the market because of the well-established connections between the other players, anyone can theoretically take part. Transneft is the monopolist transporter but it does not produce or buy oil for trading on its own account. This is not the case with the gas sector. Gazprom, the biggest gas producer and supplier in Russia, is also the operator of the pipeline network and it has denied other producers third party access (TPA). Even if the grounds for doing so are tenuous, the last few years have shown that there is little chance of wider reform, as it is not in line with Russian gas policy.

The unified gas supply system (UGSS) is the main component of the Russian transmission system and – with its 171,400 km of pipelines and other infrastructure – is viewed by many Russians as the eighth wonder of the world. It is a unique engineering complex, encompassing gas production, processing, transmission, storage and distribution facilities. These ensure continuous gas supplies from the wellhead to the burner tip in the world’s largest country. For Russians, unbundling would be a step too far. Gazprom in various forms has co-ordinated the network since 1961 as its sole owner and it dominates all the other segments of the domestic gas value chain too, and it has worked. All legal issues concerning UGSS and the relationship between Gazprom and other gas market players have been regulated since 1999 by the federal law on gas supply (FLGS). Russia’s domestic gas transportation rules have been liberalising since mid-2000s and, bowing to regulatory and anti-monopoly acts, there is non-discriminatory access to the UGSS. Reforms have raised the share of other parties since the late 2000s but there is no law giving access to export pipelines or to those that are not part of the UGSS.

The Unified Gas Supply System of Russia (UGSS) is controlled by Gazprom’s Central Operations and Dispatch Department (CODD) (Credit: Gazprom)

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18

Testing the rights

Total gas production in Russia 2016

Total gas production in Russia 2016 700

In 2015 a court confirmed Rosneft's right to access the transSakhalin gas pipeline but Sakhalin Energy did not allow it. Rosneft went to appeal; and in February 2017 it applied to the federal anti-monopoly service (FAS) for a ruling. A year later (March 12, 2018) the FAS closed the case as the court had proved Rosneft's right to use it and found that Gazprom had violated antimonopoly law. Rosneft has also sought access to Power of Siberia, and in theory it has it for purely domestic gas sales; but according to experts, Rosneft wanted access in order to export gas to China. Experts argue that Power of Siberia is an international gas pipeline. According to the law on gas exports of 2006 the only owner of access to export pipelines is Gazprom. The relationship between TPA and national energy security makes it difficult to gather comments from Russian experts. Generally, they prefer to say that non-discriminatory access to the Russian UGSS already exists. For example one said that every major gas company is a tool that exists to assist and support national policy, and that wider access to UGSS would be against Russia’s commercial interests. Gazprom’s official position is that it provides independent companies with non-discriminatory access to UGSS and if access is blocked, it is only because of technical reasons, a typical one being that there is no spare capacity for non-Gazprom gas. However, Gazprom believes that Russia's position on TPA needs to be explained to the public. Russian newspapers such as Kommersant have said that Gazprom has ordered a number of articles to promote the Russian viewpoint in Europe, and to explain the threats resulting from export market liberalisation – especially in the gas export context. Europeans are keen for the pipes to be separated from supply and trading, as their market works on the TPA principle whereby one business cannot cross-subsidise the other, charging a lot for transport and so undercut the competition for supply. By contrast, in 2016 Gazprom’s grid pumped gas for 24 independent companies, totalling 129bn m³, just a fifth of all the gas distributed in Russia. That leaves four-fifths in Gazprom’s

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600 500 400 300 200

Gazprom Total

Rosneft

Novatek

Company

Others

Source: Gazprom, Interfax

Inflow of gas via Gazprom’s GTS in Russia

Inflow of gas via Gazprom's GTS in Russia 700 600 500 BCM

A long-standing dispute between the Sakhalin 1 owners – Russian Rosneft, US ExxonMobil, Japanese Sodeco and India’s ONGC – and Gazprom concerning the access to the Sakhalin– Khabarovsk–Vladivostok pipeline ended in December 2017. The energy minister Alexander Novak announced that gas from Sakhalin 1 would be sold by Gazprom's Sakhalin Energy consortium on condition that Gazprom supplied 2.3bn m³/yr to Rosneft's petrochemical company in the east. The pipeline, according to Gazprom’s website, is part of the UGSS, and so open to all.

400 300 200 100 0 2014 Total

2015

Independent producers

2016 Source: Gazprom

hands; whereas in Europe this percentage is lower in almost every case. For example, in Poland, generally held to be one of the least competitive markets, state-majority-owned PGNiG in 2017 had 73.7 % of the market. It is therefore understandable that independent companies in Russia should want a bigger share, and from their point of view the situation is not that great especially given the fact that despite long-standing laws, independent producers have only in the last decade begun to get more access to Gazprom's domestic pipelines. For example, between 2008 and 2011, the FAS brought 28 cases against Gazprom, accusing it of hampering access to the UGSS. Perhaps for this reason from 2015 FAS has regulated the fees. However, Gazprom is trying to increase shipping fees for its competitors. In June 2017 it wanted to raise them by about 3.9% from rubles 65,1/’000m³/’00 km, but the ministry of economic development and the ministry of energy blocked the idea. Gazprom’s argument was that transit fees have not gone up since 2015, and according to company data, the cost of pumping gas belonging to independent gas producers in 2017 was rubles

29

69.2/’000 m³/’00 km, which was more than the tariff. Another argument was that independent producers do not share fairly in the burden of maintaining the UGSS. Gazprom invested more than $16bn in the years 2012-17, although some of this might have been for export-related infrastructure. There is another argument saying that a 3.6% increase in transit fees will not reduce the pre-tax profits of independent producers dramatically, while on the other hand it would bring Gazprom only $177mn-$355mn – depending on the weather and so on – and this is small beer compared with how much Gazprom has already invested in the system. According to Vygon Consulting project manager Dmitry Akishin, the optimal tariff increase should be around 10%. According to the economic development ministry’s forecast for 2017-19, tariffs for shipping gas for independents should not rise faster than wholesale gas prices for industry. And the ministry proposed an increase of 1.9% while his counterpart in energy proposed 1.7%. The position of independent producers is clear: they want 0% tariff indexation and deputy prime minister Arkady Dvorkovich is in support of this position. Further, at last year’s St Petersburg International Economic Forum, Novatek's CEO Leonid Mikhelson said: “Unjustified decisions to hike pipeline tariffs for independent companies can lead to a gas deficit in Russia.” He also underlined that the first prority was to set up a methodology for tariffs. He also said that the current tariff was too high, an opinion shared by many independent producers.

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Tariff dispute A representative of Rosneft said: “The indexation of the tariff for gas transportation, proposed by the FAS, is not justified. The company understands that tariffs should not be raised, but it should be calculated using a new methodology, taking into account a reasonable level of costs which is set by the regulator.” He added also that Gazprom was investing more than necessary in the gas transportation system. In addition, it mainly invested in the export-oriented gas transportation capacities, which are hardly used by independent participants. Moreover, according to open-access government information, the capital expenditure on domestic gas pipelines is falling, which should mean lower tariffs. In 2017, the issue of tariffs has not been resolved. The head of FAS Igor Artemyev predicted this as long ago as August and said that that the decision would be taken this year. The existing legal and regulatory frameworks of UGSS and nonUGS systems and transportation tariffs do not adequately meet today’s changes in the Russian gas market, least of all in the rapidly growing LNG sector and the role it could play in the liberalisation of the Russian domestic market and export routes.

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NEWS. ANALYSIS. THE INSIDE TRACK.

20 However, the Russian LNG sector is still a work in progress and there is no regulation of small scale LNG market (SSLNG) and the niche markets in this sector. The position of the administration is crucial but first it has to compare opportunities and risks. On one hand LNG can increase the efficiency of the UGSS. But on the other, in the long term, companies may want to create alternatives to the UGSS SSLNG value chain, and so weaken the government’s position.

to gas exports. Pipeline export is dominated by Gazprom. And independent producers hope that LNG exports are not under strong government control especially in the context of ambitious plans to increase Russia’s share of the global gas market through LNG. It brings hope that liberalisation of the access to LNG export routes will become more open. Only three companies meet the criteria set by the Law on Gas Exports, allowing these companies to export LNG: Gazprom, Rosneft and Novatek.

This is especially likely to happen if the independent producers cannot grab more of the market which will drive them naturally to SSLNG, bypassing the pipelines. This situation is a paradox because Gazprom is already the main player in SSLNG market. It might try to defend its position there in order to avoid weakening its pipeline business.

The expansion of LNG exports will be keenly watched, since producers of SSLNG will be able to export LNG up to 400 km from the Russian border to the first refuelling points built, according to a European Union directive 2014/94/EU, along the existing TEN-T Core Network.

In addition, experts think the SSLNG sector is seen as a complementary part of the gas sector in Russia, used – as in China – to gasify regions far from gas pipelines; and in the transport sector. But what if companies start trying to create demand for SSLNG in gasified regions? The main obstacle is economic: in general it is not thought to be profitable for an independent operator to develop its own LNG value chain without using UGSS. Moreover, Russia’s president, Vladimir Putin during the Yamal LNG launching ceremony in Sabetta last December, said that LNG projects and gas pipeline projects were not competitors: LNG cannot affect gas pipelines. The assessment of the situation becomes even more complicated because government programmes concerning SSLNG have just started and most independent producers are waiting to see how they are implemented. This is probably why the LNG sector will develop slowly and remain under state control. A similar question applies

Regardless of the policy and security risks, the option that access to the gas system would be similar to the Italian one, where Eni has 54% market share, does not seem probable. In addition, the general director of NIIgazeconomika – Gazprom’s leading research centre which forecasts gas industry development – Nikolal Kislenko told a conference last year that in the summer months of 2017, independent gas producers produced about 2.5bn m³ more than Gazprom and added that it was not correct to describe Gazprom as a monopoly. The most probable scenario is that Gazprom will carry more and more gas for third parties but without any detriment to itself. And SSLNG will be developed under strong governmental regulations; and no project that could jeopardise government policy will be introduced. These considerations all make it unlikely that there will be a Transneft for Russia’s gas sector. Kamil Sobczak

NORD STREAM 2: RUSSIA PLAYS WITH FIRE The first few months of the year have not seen any softening in Russia's foreign policy, but this is precisely the time that its actions in one sphere could adversely damage it in another, as it seeks approvals for a key new pipeline. By the end of February 2018, Russia’s relationship with Ukraine had deteriorated sharply after the Stockholm court demanded that Gazprom/Moscow pay more than $2bn to Kiev and in early March, Gazprom announced it would not sell gas to Ukraine on the new, disadvantageous terms the court demanded.

of Russia’s relationship with the West. In reply, Kiev pointed out that Russia was not a reliable partner and said not for the first time that Nord Stream 2 should be scrapped. All of this renewed doubts that Nord Stream 2 pipeline will be built, but these problems will not necessarily kill the project.

In addition, the Kremlin’s alleged attempt on the life of a Russian ex-spy and his daughter in the UK led to further deterioration

Tensions between Ukraine and Russia erupted almost immediately after the collapse of the Victor Yanukovich regime

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21 and the tensions in Donbas in 2014. In the increasingly bitter conflict, gas lines and gas supplies started to play an important role in the confrontation between the two countries. Most of the gas lines had been built during the Soviet era and this led to a peculiar love/hate relationship between Kiev and Moscow. On one hand, Kiev wanted to free itself from dependence on Russian gas, but it could not afford the luxury of diversification. In addition, Ukraine was loath to lose its role as the major transit state. For this reason, it bitterly opposed Nord Stream 2 while Moscow clearly regarded Nord Stream 2 as one of its major priorities. In response to the attempted assassination, the US imposed sanctions on several oligarchs connected with Russia's newlyre-elected president, Vladimir Putin, including Gazprom CEO Alexei Miller. And since then, there has been the April 7 suspected chemicals attack on Douma, Syria, which would appear to be the final nail in the coffin for Moscow's plans. Still, the Nord Stream 2 project continues, with first Germany and then Finland consenting to the offshore route crossing their territory, the latter’s final approval coming April 12, leaving Denmark and Sweden yet to decide whether to approve or not.

Moscow’s chances for success While it seems to be a reckless move, Moscow is not in immediate danger of losing its access to western customers. Kiev has made it clear that it has no intention of taking Russian gas while it moves through Ukrainian territory, demonstrating that it is a law-abiding country. More important, Russia already has Nord Stream I and permission to use the Opal gas line almost at full capacity, enabling it to send most of the gas to Europe anyway. One should also remember that the heating season for this year is approaching its end. More importantly, Moscow’s actions emphasise the difference between Western Europe – mostly Germany, with which Moscow has no issues – and eastern Europeans, who could create problems for Germany and other central European countries in the future; and here, Moscow has exploited an increasing rift inside the European community. The increasing tension between the US and “old Europe,” as Donald Rumsfeld, George W Bush’s Secretary of Defence, has been re-emerging for a long time. It started soon after the end of the Cold War, when Berlin became doubtful that it needed the US' nuclear umbrella; and Washington saw Germany not so much as an ally but as a competitor. The conflict became an open one upon Donald Trump’s victory and led to growing economic and hence geopolitical distancing between the two countries. The conflict between Washington and Berlin intensified the conflict inside the EU. To understand the process, one should

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Nord Stream 2 (Credit: Nord Stream)

remember recent history. Most eastern Europeans ran headlong to the EU with the notion, deeply ingrained in their historical memory, that what they regarded as their low-level standard of living was due to their control by Russia. Still, their entrance into their European family was often deeply disappointing, and quite similar to the feelings of the Soviets and eastern Europeans of the Cold War era, who found political and intellectual liberty but not necessarily employment, affordable housing or health care – which they had taken for granted in their socialist, totalitarian societies. The situation with eastern European states became structurally similar. It is true that the Soviet empire had brought totalitarian socialism and controlled eastern European satellites’ foreign policy, but it also brought the almost-free flow of natural resources, including gas and oil. The USSR was also a bottomless market for anything that these eastern European countries had produced. With the EU, they entered an absolutely different arrangement. The dominant powers of Europe, Germany first of all, were capitalist countries. The results were clear: while official statistics provided a rosy picture of eastern European economies and rising living standards, the reality for many eastern Europeans was quite different. Their economies and living standards collapsed, and this explained the rise of “populism,” with its often latent “national-socialist” tinge. If eastern Europeans are unhappy with the US, their dislike of Germany is much stronger. And, as in the case with Russia/the USSR in the past, this hostility is easily anchored in the not-so-distant past. In this particular circumstance, some eastern Europeans look at the US as a natural geopolitical and economic counterbalance, not just of Russia, but also of Germany. This is, for example, the case with Poland, which wants to increase its reliance on American LNG. The increasing tension between Washington, Brussels and Berlin has provided additional impetus to the

22 Prologue to the drama In the beginning of the post-Soviet era, Moscow continued to sell gas to Ukraine, and charged it less than to Western customers. This arrangement ended with Putin’s advent. For the Russian business community and the Kremlin tightly connected with it, it was just another foreign customer. Any discount had to be explicitly linked to economic and/or geopolitical benefits. Gas delivery was also used as a weapon to deal with recalcitrant leaders. Ukraine could serve here as a good example. Victor Yushchenko, Ukraine’s president from 2005 to 2010, was the first victim of Moscow’s use of gas as a weapon. Yushchenko was clearly anti-Russian, and suffered from the “gas war” in 2005/2006, when Moscow cut supplies to Ukraine, on the basis that Ukraine had taken gas intended for western European customers. Pro-Russian Yanukovich, who ran Ukraine from 2010 to 2014, had limited relief from Moscow. But his demise in 2014 and the beginning of the Russo-Ukrainian conflict created new gas problems. Moscow proclaimed plans to build gas lines which would bypass Ukraine completely, to deliver gas directly to Turkey and northern Germany. Ukraine and several eastern European countries were strongly against the project, which would deprive them of revenue. This conflict between Moscow and Kiev was especially acrimonious, and the two countries were enmeshed in conflict over gas supply. Both sides appealed to international courts, and when the Stockholm court of arbitration decided in favour of Ukraine, Russia took a decisive step: it actually called for the severing of all gas-related ties with Ukraine, and called for the cancellation of the gas supply and the gas transit agreements that the Stockholm tribunal had spent so long redrafting. The decision appeared to be an impulsive, high-stakes gamble, which could cut Russia off from the western European market just when the construction of the second string of TurkStream and Nord Stream 2 are still up in the air. Only later will it be clear whether it has done more harm than good.

simmering conflict between Berlin and some Eastern European capitals, such as Warsaw.

E Europe and Germany: different approaches

build facilities for accepting LNG, and this prevents geopolitical blackmail. At the same time, Berlin insists that the existing LNG terminals do not prevent Germany from receiving gas from Nord Stream 2.

EU countries have been divided in their approaches to Nord Stream 2. While eastern Europeans strongly oppose the project, Germany is on Russia’s side. The conflict became clear as long ago as last year. In addition, German support of Nord Stream 2 was solidified by Gerhard Schroder, the former German chancellor, in managing the project.

But Warsaw knows that Germany is unlikely to shift to LNG as Moscow is unlikely to stop supplying gas to Germany: German LNG terminals are more insurance against dramatic worsening of the Russo-German relationship, rather than a true alternative to Russian gas.

One could also add that Germany’s increasing support of Nord Stream – much to US annoyance – provided Gazprom with the sense of optimism and the feeling that Nord Stream II would be built, regardless of US sanctions.

By providing permission for Nord Stream’s construction in its territorial waters, during the time of mass expulsion of Russian diplomats and tensions not seen since the coldest part of the Cold War, Berlin showed that it has little interest in supporting eastern Europeans, even those who belong to the EU, and paid no attention to Washington’s admonitions and threats.

The major argument against Nord Stream 2 is that the project is geopolitical, not commercial, in nature. In this reading, it was just an outfit of the Russian government, and Moscow could cut the supply at any given moment. Consequently, only US LNG could be geopolitically safe. Berlin pretends that it understands these concerns, and is ready to

Vol 3, Iss 7 | April 18, 2018

All of these indicate that Nord Stream has good chance of survival regardless of the complications in Russia’s relationship with the West and Ukraine. Dmitry Shlapentokh

23 CHINA'S LAWS FAVOUR GAS China's latest addition to its legal armoury for environmental protection should help the growth of its gas industry, as the soil pollution law is intended to complement other normative acts and regulations aimed at cutting emissions. China’s coal-to-gas transition has taken its first historic steps with the introduction of emission trading systems and taxation, with layers of environmental policy governance looking set to stay. The latest such, the planned soil pollution law, while seemingly unrelated to coal or gas, is a long-term measure which is expected to reap benefits when other measures are

will receive fines ranging from yuan 500,000 ($79,000) to 2mn when the new law is approved.

also in place.

of polluted land, and penalties for violations. The tax on soil pollution also contains components intended to fill in the gaps in the law on environmental protection whose earlier drafts date back to 2004.

At the 13th National People’s Congress in March 2018, the country’s lawmakers said that six pieces of legislation concerning environmental protection, air pollution, water pollution, the marine environment, an environment tax and wildlife protection – as well as the Paris Agreement – have been enacted or modified. The committee is expected to focus on reviewing a draft law on soil pollution as well as a law on solid waste pollution in 2018. With the comprehensive legal framework gradually taking shape to protect the environment, emissions monitoring is anticipated to be strengthened, thus enabling other industries such as agriculture to facilitate the coal-to-gas transition in China’s quest for an environmentally aware economy. The strength of the commitment has become clearer since two laws – the environmental protection law and water pollution laws – took effect on the first day of 2018.

What’s Missing & What’s Taxed The new soil pollution tax will encompass some of the other pollutants which are not covered by the environmental protection law. This includes those specifically emitted from agricultural production and its waste treatment facilities. Companies and individuals who are found discharging sewage, sludge or other waste containing heavy metals or other pollutants into farmland

The draft has 94 articles covering nine chapters and clarifies the responsibilities of governments, companies and the public. It also covers standards, monitoring, risk assessments, restoration

According to Wang Jinnan, head of the Chinese academy for environmental planning under the ministry of environmental protection, the environmental protection tax law is a first and is expected to kick-start a “green” financial and taxation system. Coming into force January 1, it replaced the existing “pollutant discharge fee” which had been in place for several decades. Nonetheless, according to some tax experts, the environmental protection tax law only targets enterprises and other entities that directly emit a taxable pollutant and does not tax indirectly discharged pollutants. Significantly while China’s National Bureau of Statistics is collating data such as volume of wastewater and taxable pollutants, carbon dioxide is excluded. Also, enterprises that emit taxable pollutants in legitimate centralised sewage and domestic waste treatment facilities, are exempted from the tax. This varies between local governments too. They are allowed to adjust their pollutant limits, subject to the National People’s Congress Standing Committee. Heavily polluted cities will have more stringent pollutant-free targets to meet. Implementation is a contributing factor as well.

24 The law requires co-ordination between the tax authority, the environmental protection authority and the local governments who – while not environmental experts – are tasked with establishing pollutant-tracking mechanisms.

China's Carbon Emissions & GDP

And local agencies have been working hard on inspections and surveys aimed at finding the current levels of pollutants in order to establish the baseline and so establish achievable targets for reduction..

What this means for Coal-to-Gas While the primary aim of the impending tax is to cut soil pollution, it has huge implications for cutting emissions. According to IEA’s report on Carbon Dioxide Emissions From Fuel Combustion, while global energy use contributes to the largest source of carbon emissions at 68% in 2014, the next major singular contribution comes from the agricultural sector at 12% which produces mainly methane and nitrous oxides from domestic livestock, crop cultivation as well as crop production processes which consume energy. In 2015, global carbon dioxide emissions reached 32.3 Gt CO2 which is within the 0.1% range of 2014 levels according to IEA. Carbon emissions from fuel combustion have remained comparatively constant in 2015, the first year since carbon emissions became a global issue. This suggests that the global emphasis will now turn towards emissions from non-fuel combustion sources. According to the National Bureau of Statistics, China produced yuan 107bn of gross output value from its agricultural industry in 2015, which depends on good quality soil and water for sustainability. With the underlying transformation of China’s coal-to-gas economy, timely and accurate data on carbon dioxide emissions will be a necessary part of the process of informing law-makers and local governments on whether or not the local, regional and international targets are being achieved. This includes collating and standardising carbon emissions from gas, and from non-traditional fuel combustion sources such as agriculture. The impending tax on soil pollution is just the first step towards establishing accountability and creating the required governing structures to enable the tracking of carbon emissions from the agricultural sector. Nonetheless, while measuring carbon emissions is costly and is a norm for which a requirement has only recently emerged, this necessarily implies the transition or a reset to a lowcarbon economy whether globally or regionally. And it has developed over the years in China. In May 2017 according to a Carbon Market Readiness Training Report published by the International Emissions Trading Association, an energy company spokesperson said that current emissions data determined by historical data may cause a shortfall in measurements. Vol 3, Iss 7 | April 18, 2018

Source: Statistics from International Energy Agency, CO2 Emissions from Fuel Combustion (2017).

He says that emissions will decline as the economy becomes more energy efficient; overlapping policies and incentives, as well as a dip in economic activity could also affect emissions. This will be more pronounced in China since its gross domestic product has leapt ahead in the last decade. Also, it will take time and money for the vast country to produce acceptable accuracy for its emissions and their reductions. As the diagram shows, as China’s gas demand goes up, actual emissions also increase. Standardised emission tracking mechanisms will need to be built into district energy and distribution systems, which brings important implications such as urban service costs, gas bills and industrial costs. Another contributing factor is the existing level of environmental consciousness of the agricultural communities, which may explain why China has taken the next step while its coal-to-gas economy is still a work in progress. Lastly, China’s simultaneous race in developing green bonds to fund its environmentally conscious economy may have added to the pressure forward to improve existing carbon measuring systems. China’s impending soil taxation is in many ways a beginning to another layer of environmental governance which is a critical step towards a coal-to-gas future. While the laws initially serve to deter pollution, they do not immediately change business practices or the perceptions of how pollutants affect people’s lives. Relying on gas for energy consumption also does not necessarily mean a completely clean environment or cleaner soil. Nonetheless with common measurables and the environmental consciousness in place, China will have internally consistent norms and structures to ensure a clear cut-off from the old coal and polluting economy. It also enables a foundation on which future layers of governance may build continually evolving, environmentally conscious business practices. Staff

25 VIETNAM CAVES IN TO CHINA Vietnam has its back against the wall once again, and just like many times before, it comes amid growing pressure from its long-time rival, largest trading partner, and giant neighbour to the north: China. According to a March 29 BBC report, which cited an industry source, state-owned Petro Vietnam ordered Spanish energy firm Repsol to suspend an oil and gas project, which was in its final stages, off the country’s southeast coast. The pull-out could cost Repsol some $200mn in lost investment, the report said. Repsol did not respond to NGW requests for comments on the matter.

covers nearly 90% of the South China Sea. A drilling rig, the Ensco 8504, was scheduled to depart from Singapore for the drill site on March 22, the BBC report added. Repsol has already contracted Yinson, a Malaysian owned company, to provide a floating production storage and offloading (FPSO) vessel at the site for 10 years at an estimated cost of more than $1bn.

The site in question is called Ca Rong Do (Red Emperor) and lies in block 07/03 in the South China Sea. Repsol's local subsidiary estimates that it contains 45mn barrels of oil and 172bn ft³ of gas. The area is also clearly within Vietnam’s UN-mandated 200-nautical mile exclusive economic zone (EEZ), but is also claimed by China as part of its U-shaped, nine-dash line which

It is the second time in less than a year that Hanoi has bowed to Chinese pressure in its own waters. In July, Vietnam also ordered Repsol to stop oil drilling operations at an adjacent location, Block 136/3, in response to what media at the time called “threats from China.”

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The geopolitical squabble last year came just days after Repsol reportedly made a major gas discovery in the area. In late November, US president Donald Trump offered to mediate territorial maritime disputes between the two parties. His offer was ignored. Repsol has a global footprint with both upstream and downstream activities in 37 countries. In the Asia-Pacific region, the Madrid-based company has operations in China, Singapore, Indonesia, Malaysia and Vietnam where it holds mineral rights to seven exploration and production (E&P) blocks.

Possible geopolitical triangle

Repsol's activities in Vietnam (Credit: Repsol)

The Red Emperor cancellation comes as Vietnam goes long on gas, striking a number of deals in the past year that are projected to at least triple the country’s gas output within eight years. One of these recent deals, however, could also up the geopolitical ante not only between Beijing and Hanoi but between Beijing and Washington as well. Vietnam and US major ExxonMobil recently agreed to develop the Ca Voi Xanh, or so-called Blue Whale offshore gas project, the country’s largest gas project.

“Vietnamese sources intimate that both sides have reached an informal understanding that they will not interfere in activities by the other party if it falls on their side of a hypothetical median line. Both sides are free to make public protest but the understanding is that both sides will exercise restraint and not interfere. This understanding should reduce the risk to Exxon Mobil in its present operations,” he said.

Blue Whale is a game-changer for not only US-Vietnamese bilateral relations and energy company partnerships but economically as well. Vietnam has previously said that revenues from the field could be as much as $20bn for the national budget over the life of the project.

However, Vietnam’s most recent kowtow to Chinese pressure over its Red Emperor project comes just weeks after the USS Carl Vinson anchored off the coast of the southeast Asian country at the port city of Danang, the first visit by an American aircraft carrier since the end of the Vietnam War in 1975.

The Blue Whale project is in deep-water block 118, about 55 miles (88 km) off the Vietnamese coast, in an area only 10 miles outside China’s nine-dash line. It remains to be seen if an American oil company, especially an oil major with ExxonMobil’s clout, would also bow to Chinese pressure to stop any future drilling activities.

Most analysts concede that by allowing an American super carrier to dock near Danang, the government in Hanoi is playing all of its geopolitical cards, in essence balancing the US and China off each other as it jockeys for influence, and in some aspects survival, in the region.

Carl Thayer, Emeritus Professor at The University of New South Wales and an expert in Vietnamese relations, sees stark differences between Repsol’s recent project cancellation and Exxon’s Blue Whale project. “Oil exploration by Repsol in the waters around Vanguard Bank to the south of the Spratly islands and oil exploration by ExxonMobil in the waters off central Vietnam are two separate issues, he told NGW. Moreover, China claims that it reached an agreement with Vietnam to maintain the status quo in the Vanguard Bank area, according to Thayer. “When Vietnam resumed oil exploration in this area last year China put enormous pressure on Vietnam reportedly even threating armed force. Vietnam backed down,” he said.

Thayer added that since Exxon is US listed, American commercial interests are directly involved. “It is a relatively minor matter for China to put pressure on Repsol, a Spanish company; but it would be a major matter if China took action against a US company,” he said. “Both the North Korean nuclear proliferation issue and the tariff contretemps between Washington and Beijing militate against China taking direct action against ExxonMobil.” Beijing, however, could seek to disrupt growing US-Vietnamese ties. “Beijing is more likely to press Hanoi to stop Exxon’s Blue Whale project and thus drive a wedge between Hanoi and Washington. Beijing will play the long game in the South China Sea while the US is focused on North Korea and its trade imbalance with China,” Thayer said. Tim Daiss

However, since ExxonMobil’s project is near but does not cross China’s unilaterally defined nine-dash line it is a different situation.

Vol 3, Iss 7 | April 18, 2018

27 BUNKERING IN THE US With the Jacksonville Port Authority leading the way, LNG as a marine fuel is gaining ground in the US. Demand in the US for LNG as a bunker fuel in the shipping industry is relatively low, but with stricter low-sulphur fuel regulations set to come into effect in 2020, LNG bunkering is expected to expand to most major ports, according to the panellists at a recent LNG conference in Houston. Under new International Maritime Organization (IMO) rules that take effect January 1, 2020, sulphur content in bunker fuels will be limited to 0.5%, down from the current limit of 3.5%. Aziz Bamik, general manager of GTT North America, a whollyowned subsidiary of France’s GTT, which designs and engineers LNG shipping and storage facilities, told the 16th Americas Summit of the CWC World LNG & Gas Series that with those regulations less than two years out, the global shipping industry is at a “tipping point” for reducing emissions from its bunker fuels. “By 2020, ship owners globally will have to limit sulphur in fuel to 0.5%, which opens opportunities for LNG,” he said. “That means that if they want to be compliant, they will either have to install scrubbers to clean the exhaust, or they will have to use LNG.” Converting to LNG as a bunker fuel, Bamik said, is

the best long-run solution for most ship operators: it’s clean – SOX emissions are eliminated, NOX emissions are reduced by 85% and CO2 emissions are reduced by more than 25% – it’s cost-effective and it’s readily available. There are now 120 ships in the global fleet running on LNG, he said, and another 124 on order that are capable of using LNG as a fuel. Around the world, there are 46 LNG bunkering stations, and six vessels capable of providing LNG bunkering services. The global cruise industry, meanwhile, will put 13 LNG-powered vessels into service between now and 2026, according to Cruise Industry News. Carnival Corporation will operate seven of those, three under its US-based Carnival Cruise Lines flag, while the rest will be operated by Royal Caribbean Cruises and France’s MSC Cruises. “We are now, in 2018, at the tipping point because we have seen some key decisions in the last year that will trigger the growth of LNG as a marine fuel,” Bamik added. Among those decisions was the late-2017 contract awarded to GTT by China State Shipbuilding to provide LNG fuel tanks for nine of the largest container ships – 22,000 20-foot-equivalent units (TEU) capacity – ever built. Each of those ships will have LNG fuel

The Clean Jacksonville bunker barge, under construction at the Conrad Ship Yard in Orange, Texas (Credit: Conrad Industries/GTT)

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capacity of about 18,600 m³, and together, they will consume about 300,000 metric tons of LNG each year. By 2028, he said, at least 10 US ports will have LNG capabilities, expanding the fuel’s maritime fuel presence in the US that began about four years ago at the Jacksonville Port Authority (Jaxport), on the northeast coast of Florida. Supported by a proactive US Coast Guard presence, Jaxport has become the centre of US LNG bunkering. Encompassing three marine cargo terminals and a cruise terminal, the port will soon have two small-scale liquefaction facilities capable of producing 320,000 gallons/day of LNG, and North America’s first LNG bunker barge, the Clean Jacksonville, designed by GTT North America and nearing completion at the Conrad Shipyard in Orange, Texas. It’s already home to the world’s first LNG-powered containerships, Tote Maritime’s Isla Bella and Perla del Caribe (which will be bunkered by the Clean Jacksonville) and will soon welcome two combination container-roll-on/roll-off ships. Crowley Maritime’s El Coqui and Taino will each have 2,400 TEU capacity, with additional space for nearly 400 vehicles. Crowley also operates a shore-side bunkering facility, designed and built by Eagle LNG, which is currently building one of the two small-scale liquefaction facilities at Jaxport. The other is being built by JAX LNG – a partnership of Pivotal LNG and NorthStar Midstream – which will also own and operate the Clean Jacksonville. “We haven’t really had a lot of stumbling blocks in getting LNG into the Jacksonville market,” David Stubbs, director, properties and environmental compliance at Jaxport, told the Houston conference. “Jacksonville and Jaxport started the move to LNG in the state of Florida and Florida will be a real hotbed of LNG in the maritime industry through not only the container industry but also the cruise industry, which is converting their ships.” None of Jaxport’s LNG successes, Stubbs said, would have been possible without the active support of the US Coast Guard (USCG), which oversees water-side operations at every port in the US. Lieutenant Commander Dallas Smith, detachment chief at the USCG’s Liquefied Gas Carrier National Center of Expertise in Port Arthur, Texas, said it is the Coast Guard’s mission, through the Center, to be as proactive as it can with the development of policy and guidance for LNG as a marine fuel. “We still don’t have any Coast Guard regulations for LNG as fuel but we have several policies and guidelines regarding operating and designing,” he told conference delegates. “We have had great partnerships with some of the different facilities like Jaxport, GTT, Tote and Crowley. We have looked at their facilities and they’ve helped us raise awareness.”

Vol 3, Iss 7 | April 18, 2018

The launch of the Isla Bella, the world's first LNG-fueled containership. It is now homeported at Jaxport in Florida (Credit: Tote Maritime)

Four years ago, when Tote Maritime first approached Jaxport with the idea of home-porting the Isla Bella and the Perla del Caribe in Jacksonville, port authorities had no knowledge of LNG or its potential use as a bunker fuel, Stubbs said. “What we did know, however, was that if we didn’t get out in front of this and get it in front of the public, it likely wasn’t going to be very well-received by the public,” he said. Tote Maritime, Jaxport and the USCG hosted numerous public meetings and hearings explaining the environmental and cost advantages of LNG bunkering, and by the time Eagle LNG brought forward its plans for a liquefaction facility, pretty much all the questions had been answered. “A public hearing into the Eagle LNG project was convened, the company gave an overview of the project, two members of the public spoke favourably about the project, and the hearing adjourned after just 24 minutes,” Stubbs said. “I doubt major LNG terminals can get things done quite that quickly.” Dale Lunan

29 LNG PROJECTS NEED PLAN B Final investment decisions for the second wave of US LNG development await resolution of several contract controversies, relating to length, volume and creditworthiness. Keeping costs down, meanwhile, is easier said than done. In the last couple of years, final investment decisions (FIDs) for new LNG export projects to go into service around 2025 have dried up. This is largely because the old rules governing the structure of the contracts have been torn up and there is no consensus about how to replace them, according to numerous panelists at the 16th Americas Summit of the CWC World LNG & Gas Series in Houston last month.

If buyers blink first, and accept long-term contracts, many major US projects with off-take agreements in place will move quickly to FID. If sellers blink first and accept the ongoing trend to shorter contract terms that has become evident in the last few years, they will need to come up with new business models and creative and unconventional financing arrangements. The move to shorter contracts has been gaining strength over the last four years, according to Jason Feer, head of business intelligence at ship and energy brokerage Poten & Partners. In 2014, two-thirds – 20 out of 30 – new supply and purchase agreements (SPAs) were for 10 or more years; by 2017, the trend had reversed, with 20 of 30 SPAs for five years or less. "And the number of deals for 20 or more years has plummeted – 10- or 15- year SPAs are now considered to be long-term,” Feer said.

LNG Americas 2018 (Credit: CWC Group)

A senior research associate at Columbia University’s Center on Global Energy Policy, Akos Losz, said FIDs covering only about 10mn metric tons/year (mt/yr) of export capacity were taken in 2016 and 2017, primarily because of a disconnect between buyers who are reluctant to sign long-term contracts and sellers who are unable to sanction new projects without those longterm contracts. By 2025 there will be a need for about 150mn mt/yr of new export capacity, according to data presented by Patrick Hughes, vice president, corporate strategy and investor relations at NextDecade. But while Losz said more than enough export capacity has been proposed – about 1bn mt/yr – and better than 300mn mt/yr of that could be considered at a pre-FID stage, little of it will actually go to FID without a resolution of the contract stalemate. “It will be very interesting over the next two years to watch how this impasse will resolve itself,” Losz said. “There are really only a couple of ways it can resolve itself – the question is, who will blink first?”

The shorter-term contracts are replacing longer-term legacy contracts that are expiring, he said, and the trend is expected to continue, with 200mn mt/yr of legacy contracts set to expire between now and 2030. Buyers want to replace those longterm, single source contracts with a portfolio of contracts with different terms, lengths and degrees of flexibility, and their old suppliers have found a certain degree of flexibility to meet those new demands, primarily because they’ve paid off the project financing that was supported by the original contracts. "This represents a fundamental restructuring of the global LNG market,” Feer said, noting that as contract terms shorten, average volumes per deal are falling, to less than 0.70mn mt/yr last year from 0.90mn mt/yr the year before. These new market realities, he said, are forcing developers and aggregators to sign more contracts – quite possibly with less credit-worthy counterparties – in order to take FID or clear unsold volumes, which just adds to the challenges faced by sponsors and increases the complexity of financing. In a later session, Carlos Wheelock, head of LNG Americas for global trading house Vitol, said LNG traders can help bridge that contractual gap between sellers and buyers. “The role of the traders will be to facilitate FID for some of these facilities and absorb some of the risks that are required and bridge

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some of the mismatches between producers, lenders and other stakeholders who require very precise and rigid terms to be able to FID facilities and buyers who demand flexibility and less volume and who perhaps don’t have the required credit,” he said. “That’s what we do for a living – we step between dreams and reality and try to figure it out.”

Other speakers in Houston were less certain of Henry Hub’s future as a key index for global LNG trade, suggesting the Gulf Coast LNG market still lacks the liquidity to support Henry Hub as a global index and insisting few European buyers have much of an appetite for Henry Hub, even if those in Latin America or Asia are open to the concept.

Indexing options The first wave of LNG development in the US was financed largely on the strength of global crude oil prices, which were linked to natural gas prices in Asia, and the price of natural gas in North America. Banks were willing to extend project financing to LNG developers based on that spread – which peaked at around $16/mn Btu in 2012.

The CEO of CFEnergia & CFE International (units of Mexico’s state-owned electric utility Comision Federal de Electricidad), Guillermo Turrent said Henry Hub was a natural fit in Mexico, given its pipeline connections to US supply. But Alejandro Alle, executive director of Energia del Pacifico in El Salvador, said power markets in central and south America would likely remain tied to Brent pricing, simply because LNG for power competes directly against fuel oil for dispatch.

But when crude prices collapsed in 2014, that spread disappeared, NextDecade’s Hughes said, falling to only about $3 in 2016 and stalling the global LNG market and most of the commercial activity that was associated with LNG projects.

Ernesto Parilla, head of LNG trading at Spanish utility Iberdrola, was also sceptical about Henry Hub as an index. “Sellers and traders, I think, are open to it, but I don’t see buyers too interested right now.”

“The spreads are now showing signs of moderate widening and we have witnessed substantially more interest in the US second wave as a result,” Hughes said, pointing to Cheniere Energy’s 15year SPA with commodities trader Trafigura in January and its 20-plus year SPAs with China National Petroleum Corporation in February as proof that there is global interest in long-term LNG contracts with US developers. “We think Cheniere’s recent success is probably just the beginning of what will be a pivotal year for the US LNG sector.”

The president of Cnooc Gas & Power Trading & Marketing Ye Yishu was also somewhat sceptical about Henry Hub’s global future, although he did suggest Chinese buyers, while still very tightly tied to oil prices via the NBP index, could accept Henry Hub pricing. “At Cnooc our preference is to have oil indexation, but because of the size of our market we can accommodate Henry Hub if it can provide us some flexibility in contract terms so we can manage demand volatility.”

What is decidedly less certain, however, is whether global LNG customers will be willing to abandon more traditional LNG pricing links – NBP in Europe or JKM (Japan-Korea Marker) in Asia – for prices linked to the Henry Hub natural gas price in North America. Cheniere’s SPAs with Trafigura and CNPC were based on the Henry Hub price plus a fixed component for liquefaction of just over $3.00/mn Btu in later deals. Not surprisingly, Cheniere is convinced that Henry Hub is the index of the future for the global LNG industry, largely because few forecasts suggest Henry Hub will increase much beyond its current $3/mn Btu level in the near-to-medium term. Combined with EPC costs for new liquefaction in the US that are falling rapidly towards $500/mt/yr, that Henry Hub price can land US LNG in virtually any market in the world at between $7/mn Btu and $8/mn Btu, Anatol Feygin, Cheniere Energy’s executive vice president and chief commercial officer, told the conference. “We are in the camp that believes Henry Hub will continue to grow in importance as a pricing index for global LNG trade,” he said. “I believe the first year on the forward strips that Henry Hub is above $3 is 2023, so that is a very nice tailwind for the US export business model.”

Vol 3, Iss 7 | April 18, 2018

Vitol’s Wheelock, however, said the question about what index gains prominence is not of burning importance now, compared with the length of contracts – buyers want shorter contracts, sellers want longer contracts. “It’s not necessarily a lack of appetite for Henry Hub, it is a lack of appetite for any long-term contract, regardless of the price indexation.” Dale Lunan

Costing LNG projects In today’s competitive landscape with new LNG projects struggling to find buyers and project financing, there is increased focus on being the “low-cost” LNG project. Numerous projects, especially those in the second wave of proposed US LNG export projects, are promising low $/metric ton (mt) engineering, procurement and construction (EPC) costs, with about $500/ mt/yr capacity viewed as the magic number to lure buyers. LNG project developers are promising cheap feed gas, smaller trains, shorter contracts, and just about anything else that might appeal to the new breed of LNG buyers that generally want smaller volumes and shorter contracts. As buyers struggle to

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(Credit: Susan Sakmar) CWC's LNG & Gas Americas Summit panel 'Driving LNG Use through Infrastructure and Technological Innovation: How are New Technologies Impacting the LNG Business?' From L to R: Susan Sakmar, author and attorney; Christopher Caswell of KBR; Mona Setoodeh of CH-IV; Robert M Shivers of LoneStar – LNG; Martin Rosetta of Chiyoda International

evaluate the onslaught of “low-cost” projects out there, it can be hard to evaluate which projects are merely aspirational and which projects might actually go the distance to final investment decision (FID). For this reason, some EPC contractors like Mitsubishi are still focused on LNG projects sponsored by the large integrated energy companies and national oil companies (NOCs) that were instrumental in developing the LNG industry. On the sidelines of CERAWeek in Houston in March, NGW sat down with Mike Sicker, VP of business development at Mitsubishi Heavy Industries America’s (MHIA) Oil & Gas Division to get his views on the global LNG market overall and where a traditional EPC contractor like Mitsubishi sees opportunities. Mitsubishi has partnered with ExxonMobil on some of the biggest and most successful LNG projects in the world including Qatar and Papua New Guinea. Not surprising, Sicker indicated that Mitsubishi is focused on several planned expansion projects and sees these projects as having the best likelihood of moving forward in this competitive environment. While plant expansions are usually the lowest cost of incremental supply, the consensus view seems to be that by the mid-2020s, new greenfield LNG projects will be needed to meet growing demand. Since these projects will need to be sanctioned soon to avoid a supply shortfall, there is increased focus on costs with the view that the recent high capital expenditure and schedule trends cannot be the norm for the next wave of new LNG projects. At a recent panel on LNG technology at CWC’s LNG Americas event, a group of industry experts discussed the various technological and cost issues facing the LNG industry

Vol 3, Iss 7 | April 18, 2018

and even challenged the conventional wisdom on $/mt as a measure. According to Christopher Caswell, director of global LNG and FLNG technology and development for engineering giant KBR, it is often misleading to use $/mt as a means to judge past LNG projects as well as the feasibility of future LNG projects since the site-specific elements of every project are the biggest drivers of project capex and schedule. Projects at their earliest stage of development are not likely to know their site-specific impacts to capex and schedule, which makes the estimate of $/ mt merely an estimate. It is often very difficult to determine what exactly is included or excluded in reported costs and at the end of the day, there is very little certainty that what was previously included as reported costs at the time of sanction actually reflects the owner’s final cost when EPC is completed. This leads to a wide range of $/mt for completed projects. Nevertheless, projects seeking investors, offtakers, or project financing typically use $/mt as a way to benchmark their project against all others. For example, Tellurian has characterised its proposed Driftwood LNG project as one of the lowest cost projects in the world at an estimated $550/mt EPC costs, with equity stakes being sold at $1,500/mt/yr output. At the CWC event, a potential LNG buyer from China expressed some frustration at the range of costs and asked how buyers should evaluate the various claims being made. While no specific feedback was given at the event, it is evident that the devil is in the details with LNG projects and buyers would be well advised to do extensive due diligence to determine whether

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Key terms of EPC agreements with Bechtel

Source:Tellurian Corporate Presentation, March 2018, www.tellurianinc.com

Driftwood vs. competitors – cost per tonne

Source: :Tellurian Corporate Presentation, March 2018, www.tellurianinc.com Note: (1) The World Bank bases the Logistics Performance Index (LPI) on surveys of operators to measure logistics “friendliness� in respective countries which is supplemented by quantitative data on the performance of components of the logistics chain.

there is enough data to make the estimate reliable. This task is made difficult since the $/mt cost metric only captures capital expenditure and the LNG production rate and does not take into account the scope and site-specific differences in each project.

reality as project financiers have continued to insist they still require long-term contracts with creditworthy offtakers. Project lenders also typically require proven technology with a track record of success.

These include the size of facility (large or small); whether or not it is modular; the size of the trains; and the availability of manpower. In recent years, rising costs for raw material, equipment and skilled labour have all contributed to rising LNG project costs. In the end, it will likely be the bankers that help sort out the aspirational projects from the ones grounded in

Unless the bankers relax their standards and accept more risk, existing LNG projects and projects backed by large integrated energy companies or NOCs will continue to have an advantage.

Vol 3, Iss 7 | April 18, 2018

Susan Sakmar

33 ECUADOR OPENS BIDDING ROUND Ecuador has launched a new bidding round, which includes the country’s only gas producing field, as Quito tries to drum up interest in the slowmoving natural gas sector. But it faces competition from other countries seeking investors. Ecuador launched an auction March 13 for a 10-year service contract for the Amistad (‘friendship’) gas field in the coastal south of the country, as well as contracts for several oil fields. Officials reportedly said that payments would be linked to global oil prices. The results of the auction are due to be released in June. Under the contracts, companies will carry out activities that include drilling, well completion, the reactivation of plugged wells and the construction of required facilities. Oil and gas minister Carlos Perez has said four companies – Chile’s GeoPark, a unit of Russia’s Rosneft, China’s CCDC Petroleum and Hilong Group – have expressed an interest in the bidding so far.

50mn ft³/d – the peak level it was at a few years ago before production began declining. The government “just needs to do something to get solid investment in the field. There are not a lot of other gas fields in Ecuador – that’s the main gas source for them at moment,” Marco Baltazar, a senior consultant at energy advisory firm Wood Mackenzie, told NGW. Despite its discovery as long ago as 1970, the field has remained underdeveloped for many years as there is no market for the gas, the consultancy said in a report last year.

The Amistad field, which supplies the 130-MW Machala power plant, is around 60 km offshore in Block 6 in the Gulf of Guayaquil, and has seen prolonged developmental delays over its long history.

It did not start producing until 2002, operated by a unit of US independent Noble Energy, Energy Development Company. In 2010, Petroamazonas assumed operatorship of the field when the US firm refused to switch from a production-sharing contract to a service agreement.

Today it produces about 39mn ft³/day, but Ecuador’s state-run Petroamazonas has said it wants production to rise again to

The field has been operated by the state for the last eight years. Production was boosted in 2012 when three satellite platforms

Vol 3, Iss 7 | April 18, 2018

34

"From a government perspective, having your own supply of gas is a matter of national energy security – and sometimes economics interferes with national policy."

Historically, the field has been underdeveloped, however that is now changing because there is greater gas demand, Baltazar told NGW. Drawing investment to the field in future could however still pose a problem, he noted. “There was an investment between around 2012 and 2016 – they [the government] drew up a couple of wells and they did some workovers but more needs to be done if they want to increase the output from the field,” he cautioned. In addition, it will be difficult for the government to make changes to the kind of contracts it uses for gas fields, something which it has already done in the oil sector, he noted. Starting in 2010, the government of the former president, Rafael Correa, began to revamp Ecuador’s oil field production sharing contracts by enabling joint-venture partners to become service contractors. The introduction of fee-for-service contracts meant that contractors receive a payment for each additional barrel of production. After the global oil price crashed in 2014, the government changed some of the original service contracts because they had very high oil prices, said Baltazar.

Petroamazonas offshore activities (Credit: Petroamazonas)

were installed – two of which are producing. A seven-well drilling programme was also embarked upon that year. Reprocessing of seismic data has taken place for the second phase of development of the field, which Petroamazonas said has boosted gas reserves to a total of around 1.7 trillion ft³. The second development phase includes a seven-well drilling programme as well as the installation of connecting platforms between three platforms. It will also involve the construction of a large trunk pipeline leading to the onshore processing facility. However the ministry of hydrocarbons said at the end of February that no wells have been drilled at the field for the past two years, which could deter potential investors. In addition, there are several big auctions scheduled to take place across Latin America this year, meaning Ecuador will have to compete quite hard to attract foreign investors to its auction. Colombia said in March that is planning a major oil auction in April, while new bid rounds are also already due to take place in Brazil, Argentina, Mexico – for the onshore shale gas acreage in the north – and Uruguay.

Vol 3, Iss 7 | April 18, 2018

They were adjusted – to take account of new oil prices as low as around $30/barrel – and tied to West Texas Intermediate crude prices. Nonetheless, the same cannot be done for gas contracts because prices are very low at the moment, he added. Coupled with that, there is oversupply in the market, partly owing to shale gas in the US. Further to these challenges, Baltazar said that there is a lack of regulation in the gas market including over the price that the government will pay to companies for their gas. “They can import gas from Peru at low prices so that would also be competing – why would you develop a field if it costs 3 or 4 dollars per cubic metre to get that gas when you can get that same gas imported from Peru,” he asked. It “remains to be seen what price and if it makes better sense to just pay for LNG imports from Peru or Trinidad,” he added. From a government perspective, having your own supply of gas is a matter of national energy security – and sometimes economics interferes with national policy,” he pointed out. Overall it may be more expensive to develop the field but it would of course guarantee the country’s energy supply in the long-term, and it is in the best interests of the Ecuadorian people that they develop this gas, he added. Sophie Davies

33 Mexico seeks to cut imports Mexico is also looking to attract more investors upstream, with gas next on the horizon. While it does not have the obvious resources of Brazil, which drummed up a lot of interest upstream in March, Mexico has the advantage of a transparent licensing system and a corporate regulatory framework that follow international standards. The downside is the heavy burden of compliance, the amount of paperwork that needs filing and the rising level of corporation tax – which should fall, to attract investors. There is also a major problem that dates back to the energy reform process, whereby 90% of the acreage was retained by state monopoly Pemex before outsiders were allowed to bid. The head of upstream regulator CNH (the national hydrocarbons commission) Juan Carlos Zepeda told a conference in London March 21 that it needs to be transformed into a joint stock company so it can raise cash through shares. Mexico is holding its shale licencing round later this year, pinning hopes on the extension of the Eagle Ford shale from Texas into northern Mexico. But also state producer Pemex is sitting on some of the country's acreage, lacking the resources to develop all the blocks it was given when it lost its monopoly. Only Pemex can take decisions on what acreage to farm out. Pemex does not have the capital it needs in order to produce the oil and gas it needs to double national oil production to 3mn b/d and to stop importing gas, said Zepeda. Zepeda told delegates at a conference that only when Pemex has shares will it be able to raise funds on capital markets, although he told NGW in an interview that the state could keep 50% plus one share, to ensure it retained control. The country goes to the polls in the summer, and a populist candidate, the left-wing Andres Manuel Lopez Obrador (Amlo for short), is doing well so far.

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However, turning Pemex into a 'proper company' was not a strategy intended to pre-empt government interference in a key part of the national economy should Amlo win: it is rather a priority in its own right, CNH's Zepeda told NGW. The country is also working on improving financing projects, including guidelines on reserves-based lending, where a percentage of the cashflow from a field would be used as collateral, he said. Delegates at the conference however also said that the government was pushing through what reforms that it could, before the elections, to make it harder for Amlo to return to the old days if he became president. Chris Sladen, who runs the UK major BP's Mexico business, told the conference that Mexico's goal would require the launch of some ten big fields annually for several years but there was no sign of that happening. "Big problems need big solutions," he said. BP has exploration acreage but no production yet in Mexico and he also said he was lucky to have such patient managers. Zepeda said that diversifying gas supplies meant more domestic production. US gas is the cheapest there is, but the country needs to build more pipelines to gasify more regions in order to satisfy latent demand. The Burgos basin in the north is an extension of the gas-prone US Eagle Ford play, he said, but bids for acreage there will not be awarded until September. "It is very good that we can import US gas but we need to diversify; we should be able to diversify. It is not easy to compete with the US until the Burgos Basin comes on," he told NGW. Mexico now imports about 5bn ft³/d of its 6bn ft³/d consumption, mostly through two pipelines from the US, along with a smattering of LNG, but it could consume 8bn ft³ by 2020 given the lifting of capacity constraints, he said. "We want to keep importing US gas," he said, "but it should be complementary. If we had all the pipelines we wish, we could easily use another 2bn ft³/d in the short term." William Powell

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36 TURKEY'S TEMPTING, ONSHORE GAS Tight gas prospects deep under European Turkey (Thrace) could produce 1bn ft³/d (10bn m³/yr) by 2025 if the capital is available to develop them, according to TransAtlantic Petroleum, a US independent active in the region for over a decade. TransAtlantic chairman Malone Mitchell told NGW Magazine March 23 that his company in 2010 acquired Turkey’s largest privately-owned gas producer, selling off much of the shallowlevel rights last year to Valeura Energy.

Big assets need a big asset sheet

Canada’s Valeura made a significant tight gas/condensate discovery in late 2017 on acreage adjacent to, but never owned by, TransAtlantic. In early 2017 Norwegian Statoil farmed into two of Valeura’s Banarli licences onshore Thrace for a 50% stake in the deep rights only, below 2,500 metres.

and early next.

Valeura ran four production tests in late 2017 from eight fracturing stages at its 4,196-metre deep Yamalik-1 natural gascondensate discovery on Banarli, which flowed 2.9mn ft³/d over 24 hours. In February, its net 50% interest in the Thrace acreage was independently audited as having 5.2 trillion ft³ of risked mean prospective resources of natural gas, and 165mn barrels of condensate.

“We are looking for a whole company solution to the entire portfolio. We want to sell or merge. We want a stronger financial owner that is less constrained,” he adds. It is difficult to raise debt financing in the US where banks do not understand the low political risk in Turkey, he said.

TransAtlantic’s gas mainly in Thrace New York and Toronto-listed TransAtlantic Petroleum’s largest (40%) shareholder is US family-owned Riata corporate group which also has interests in US drilling contracting, real estate, plus the US producer Longfellow Energy. The latter spun off its Nemaha subsidiary, which owns shale oil and gas tracts in Oklahoma, to South Korean’s SK Energy for an undisclosed sum, in a deal announced March 21. TransAtlantic has all the non-US upstream interests, now all in Turkey, plus one Bulgarian licence.

TransAtlantic has some 50,000 net acres in the core of the onshore Thrace basin and, subject to financing, it is looking to drill up to three wells on its Temrez licence there, late this year

“We’re a very small company,” Mitchell told NGW while in London: “We have big company assets, but we need a bigger company asset sheet to develop them.

Mitchell argues that, under US Securities & Exchange Commission rules, TransAtlantic must list zero 1P to 3P gas reserves in Thrace out to end-2018 – and so a valuation per net acre will be the most appropriate metric for judging TransAtlantic’s value until 2019 by when it may demonstrate to SEC standards any reserves. But TransAtlantic’s March 22 presentation to analysts argues that its acreage is worth as much as Valeura’s, which it puts at $6,196/acre net to Valeura, based on an estimate of the latter’s roughly C$417mn (US$310mn) market capitalisation. TransAtlantic provided a best estimate recoverable figure of some 3 trillion ft³ gas and 70mn b condensate for its own Temrez licence in Thrace, in its 2017 annual results on March 21.

Oil produced in southeast Turkey accounted for 97% of TransAtlantic’s net 2017 production of 2,799 barrels of oil equivalent/day, while 3% was made up of 1.03mn ft³/d gas produced in Thrace. It made a net 2017 loss from continuing operations of $23.9mn, roughly the same as the year before.

Of the planned three-well drilling programme, two would be drilled in 4Q 2018 with the third probably in early 2019. The initial deep-level Thrace wells are expected to cost $6mn completed but, post-2019, could get cheaper over time: down to "about $4.5mn apiece.”

All the gas production is in Thrace (European Turkey) except for a small gas field near the Syrian border on TransAtlantic’s [Turkish] Bakuk licence that was shut in as a precaution, but the firm plans to start it up again to meet local demand. Once a pipe has been built to bring Iraqi gas into the national transmission system (NTS), a full-field development at Bakuk can begin.

“These are not new rocks,” says Mitchell: “There are 900 wells that have produced in these same rocks on the rims of the basin. You just go down into the centre of the basin where it’s under extremely high pressure and high temperature. We have wells on our Temrez block that have penetrated the entire section,

Vol 3, Iss 7 | April 18, 2018

37 so uniquely in that area we know the total thickness of sand.” When it first built pipe and tapped into the NTS back in 2010, the approvals process “took a while,” sighs Mitchell. Now TransAtlantic is at home with the Turkish regulatory environment: “I have drilled hundreds of wells in Turkey, and in Oklahoma, and thousands in Texas. I will tell you: Turkey is better than either Texas and Oklahoma and has been for the decade I’ve been in Turkey. We have bid against the state oil company [TPAO], against large family conglomerates. We have never felt we were treated unfairly over licence awards or the legal system.” Most staff are locals and its country manager since 2006 previously was Arco’s country manager.

How big could a development get and cost? If the planned three-well drilling campaign at the turn of this year succeeds, TransAtlantic expects late 2019 to move to a “continuous production programme” – with as much development from wellpads as possible, to keep costs and environmental impact down. By end-2020 with this slow start, TransAtlantic expects production may still only be 1mn m³/d (35mn ft³/d). “Very quickly then, after we’ve established the spacing of wells, and optimal drill pads, we would expect that the company would want to ramp up – based on our experience in the US – to ten drilling rigs. Over a number of years, we believe you could ultimately deliver from our acreage as much as 1bn ft³/d. But that takes a company that has the capital able to deploy ten rigs.” As well as rig costs, Mitchell notes that that wells would require workover, plus compression facilities, requiring hundreds of

Drilling in Thrace, northwest Turkey (Photo credit: TransAtlantic Petroleum)

millions of dollars of investment in infrastructure. He says that 1bn ft³/d production level would not be achieved until the late 2020s. But he sees a ready market, given TransAtlantic acreage is just 20 km from the largest gas-fired power plant in Turkey and the NTS and that there is an existing 10-12 inch gas pipe system across the assets (one that may need expanding to 18-in, at a cost of $6mn). Valeura concurs, having earned C$6.61/’000 ft³ (US$5.30/mn Btu) in 4Q 2017 in Thrace. As gas production potentially grows beyond the limit of its owned infrastructure, the Calgary firm sees several options: it could tie into a regular Botas pipeline, another Botas pipe that also connects to Greece, or sell directly to a local gas distributor that currently offtakes from Botas. Mark Smedley

Turkey’s Gas Market Turkey consumed 53.5bn m³ of natural gas in 2017, up 16% on the previous year, and well over 99% of that was net imports. Domestic production is believed to be less than 0.4bn m³. The country’s overall energy import bill, which includes gas, reached $37.19bn last year, up 37%, and is expected to top $40bn in 2018, according to Turkish Statistical Institute chief Volkan Ozdemir. Turkey wants to boost indigenous energy production so that it is less reliant on imports. One aspect of that policy is that domestic coal’s share of Turkish electricity generation has risen steeply in recent years, according to an OIES study. The government’s Vision 2023 policy aims to increase the share of renewables in the electricity mix to 30%, raise coal to 30%, raise nuclear to 10%, but reduce gas’s share to 30%. But the more domestic gas, the merrier.

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