CANADIAN ENERGY RESEARCH INSTITUTE

LNG LIQUEFACTION FOR THE ASIA-PACIFIC MARKET: CANADA’S PLACE IN A GLOBAL GAME

Study No. 148 June 2015

Canadian Energy Research Institute | Relevant • Independent • Objective

Canaport LNG Terminal

LNG LIQUEFACTION FOR THE ASIA-PACIFIC MARKET: CANADA’S PLACE IN A GLOBAL GAME

LNG Liquefaction in the Asia-Pacific Market: Canada’s Place in a Global Game

Author: Jon Rozhon Allan Fogwill ISBN 1-927037-33-1 Copyright © Canadian Energy Research Institute, 2015 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute

June 2015 Printed in Canada Front Photo Courtesy of Atlantic Canada Opportunities Agency, http://www.acoa-apeca.gc.ca/eng/publications/FactSheetsAndBrochures/Pages/B_ProfitablePlace.aspx

Acknowledgements: The author of this report would like to extend his thanks to Jim Jensen of Jensen Associates, Peter Howard, Jeanne Liendo, and Megan Murphy for their valuable insight and contributions to this report.

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objective economic research in energy and environmental issues to benefit business, government, academia and the public. We strive to build bridges between scholarship and policy, combining the insights of scientific research, economic analysis, and practical experience. For more information about CERI, visit www.ceri.ca

CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: info@ceri.ca Phone: 403-282-1231

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Table of Contents LIST OF FIGURES ............................................................................................................. v

LIST OF TABLES ............................................................................................................... vii

EXECUTIVE SUMMARY .................................................................................................... ix

INTRODUCTION .............................................................................................................. xi

CHAPTER 1 LNG IN THE ASIA-PACIFIC REGION ............................................................. 1

Importing Nations .............................................................................................................. 2 Japan ............................................................................................................................ 2 South Korea .................................................................................................................. 4 China ............................................................................................................................ 7 India ............................................................................................................................. 10 Taiwan .......................................................................................................................... 12 Exporting Nations and Regions .......................................................................................... 14 Australia ....................................................................................................................... 15 Canada ......................................................................................................................... 16 Eastern Canada ............................................................................................................ 21 United States ................................................................................................................ 24 Oceania (except Australia) ........................................................................................... 28

CHAPTER 2 LNG IN AFRICA ......................................................................................... 31

Nigeria ................................................................................................................................ 31 Mozambique ...................................................................................................................... 31 Tanzania and Cameroon .................................................................................................... 32

CHAPTER 3 LNG IN EUROPE AND ASIA (RUSSIA) .......................................................... 35

Russia ................................................................................................................................. 35 Norway ............................................................................................................................... 36

CHAPTER 4 LNG IN THE MIDDLE EAST ......................................................................... 39

Iran ..................................................................................................................................... 39 Israel ................................................................................................................................... 39 Iraq ..................................................................................................................................... 40

CHAPTER 5 LNG IN SOUTH AMERICA .......................................................................... 43

CHAPTER 6 NATURAL GAS PIPELINE MOVEMENTS ...................................................... 45

Russia ................................................................................................................................. 45 Alternatives to Europe for Russia ...................................................................................... 45 Alternatives to Russia for Europe ...................................................................................... 46

CHAPTER 7 FUTURE ASIA LNG SUPPLY AND DEMAND ................................................. 49

CHAPTER 8 CONCLUSIONS .......................................................................................... 53

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List of Figures E.1 Asia-Pacific LNG Supply and Natural Gas Import Demand: 2012-2030 ...................... ix

E.2 BC LNG as Part of Global Gas Supply to Asia, 2013 ..................................................... x

1.1 Asia-Pacific LNG Import Levels in the Decade 2004-2013 ........................................... 1

1.2 Asia-Pacific LNG Export Levels in the Decade 2004-2013 ........................................... 2

1.3 Change in Japan’s Energy Mix: Pre- and Post-Fukushima .......................................... 3

1.4 Japan’s LNG Imports and Import Capacity Utilization Rate, 2009-2013 ..................... 4

1.5 Change in South Korea’s Energy Mix: 2004 and 2013 ................................................ 5

1.6 South Korea’s LNG Imports and Import Capacity Utilization Rate, 2009-2013 ........... 6

1.7 South Korea Offshore Basins ....................................................................................... 7

1.8 Change in China’s Energy Mix: 2004 and 2013 ........................................................... 8

1.9 China’s LNG Imports and Import Capacity Utilization Rate, 2009-2013 ..................... 10

1.10 Change in India’s Energy Mix: 2004 and 2013 ............................................................ 10

1.11 India’s LNG Imports and Import Capacity Utilization Rate, 2009-2013 ....................... 12

1.12 Change in Taiwan’s Energy Mix: 2004 and 2013 ........................................................ 13

1.13 Taiwan’s LNG Imports and Import Capacity Utilization Rate, 2009-2013 ................... 13

1.14 Australia LNG Projects – Proposed, Under Construction, Operating – 2015 .............. 16

1.15 Proposed British Columbia LNG Liquefaction Projects ................................................ 18

1.16 Proposed Eastern Canada LNG Liquefaction Projects ................................................. 22

1.17 Planned US LNG Liquefaction Projects ........................................................................ 25

1.18 Operating and Planned Oceania (except Australia) LNG Liquefaction Projects .......... 29

2.1 Operating and Planned Africa LNG Liquefaction Projects ........................................... 33

3.1 Operating, Under Construction and Planned Europe and Asia (Russia) LNG Liquefaction Projects ............................................................................................ 37

4.1 Operating, Planned and Unknown Middle East LNG Liquefaction Projects ................ 41

5.1 Operating South America LNG Liquefaction Projects .................................................. 43

6.1 Proposed Russian Natural Gas Pipelines to China ....................................................... 46

6.2 Southern European Pipeline Routes ............................................................................ 47

7.1 Asia-Pacific LNG Supply and Natural Gas Import Demand: 2012 to 2030 .................. 49

8.1 BC LNG Liquefaction Supply Cost Estimate .................................................................. 53

8.2 Cost of LNG Facilities, 1969-2014 ................................................................................ 54

8.3 Oil Price Required to Make British Columbia LNG Liquefaction Projects Viable ......... 55

8.4 BC LNG as Part of Global Gas Supply to Asia, 2013 ..................................................... 56

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List of Tables 1.1 Proposed Pipelines to Supply British Columbia LNG Liquefaction Projects ................ 18

1.2 Capital Costs per Tonne of Capacity, US and Australia................................................ 28

8.1 Delivered LNG to Asian Market Supply Cost Estimate ................................................ 54

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Executive Summary This study examines the global LNG liquefaction industry to determine Canada’s potential to sell its gas to the fast-developing Asian market. Future Asian LNG demand is forecast and potential global supply to the region is estimated. The general supply/demand situation is summarized in Figure E.1.

Figure E.1: Asia-Pacific LNG Supply and Natural Gas Import Demand: 2012 to 2030

Sources: CERI, IEA

The demand curve on the chart is from the International Energy Agency’s (IEA) World Energy Outlook 2014 “New Policies Scenario”, which the agency states is their “central scenario”.1 The line represents total Asian natural gas demand to be met by imported gas. Key points from this figure include:

Most major liquefaction facilities will come online in the post-2015 timeframe, and as numerous players attempt to access Asian markets, there will be a constraint around 2019.

Some of this natural gas demand is being met by existing pipeline capacity (in excess of 2 bcfd).

The IEA assumes that the two Russian pipelines, Altai and Power of Siberia will go ahead, which will supply China with natural gas volumes in excess of 6 bcfd. If one or both pipelines are cancelled – a possibility as financing for the projects is in question – the

1 Birol et al. World Energy Outlook 2014. International Energy Agency (IEA). Paris. P. 687

Asian Natural Gas Demand

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demand line will shift upwards with increased demand in Asia for LNG from Canada, the US, and elsewhere.

To gauge the cost competitiveness of Canadian liquefaction, a generic British Columbia project was estimated.

Capital costs were calculated to be $865/tonne of capacity, which falls into the “normal cost” range of global liquefaction projects.

The total delivered supply cost to Japan (including a 12 percent profit margin) for this LNG is $11.20/mcf.

Using Asian LNG pricing, the Japan Crude Cocktail price required to make the generic BC project viable is approximately $70 bbl.

The above calculations are in line with other research that finds Canadian LNG projects to be cost competitive with Sabine Pass, a Gulf Coast liquefaction facility, and other gas supply projects (see Figure E.2).

Figure E.2: BC LNG as Part of Global Gas Supply to Asia, 2013

Source: OIES, CERI.

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Introduction In the early summer of 2012, when spot natural gas prices reached $18/MMbtu in Japan and gas at the Henry Hub in Louisiana was priced less than $2/MMbtu, “Arbitrage” was a word often heard in industry circles. If producers could get their gas on LNG tankers and send it to Asia, there was plenty of money to be made. Three years later, in mid-2015, Japan is not publishing monthly spot price data because of a lack of trades, what Reuters calls “the latest sign of tepid global demand for the fuel.2” Arbitrage opportunities have disappeared.

That is not to say these sorts of opportunities could not arise again. Even though natural gas prices are in the doldrums now, the global industry is still pulsing with activity – contracts are being negotiated, pipelines are being built, and LNG liquefaction and regasification facilities are

under construction. With European natural gas demand in a prolonged slump and Asian demand showing promise over the long run, the focus of the industry is largely on the Pacific Rim where everyone is looking for the next opportunity.

This study will analyze the global LNG liquefaction situation to determine what prospects may arise for Canadian natural gas to be exported to Asia. Though there are no LNG liquefaction terminals under construction at present, more facilities are planned for Canada than for any other country. Much of this has to do with Canada holding abundant volumes of natural gas proved reserves, a great deal of it presently stranded in a region of the country near the Pacific Ocean. But besides that, Canada is a nation with established democratic institutions, rule of law, and a history of permitting foreign companies access to hydrocarbon resources. National oil and gas companies and other interested parties know that if they sign contracts to extract and export

resources from Canada, chances are excellent that those contracts will be honoured.

In June 2015, Petronas of Malaysia decided to make a conditional Final Investment Decision (FID) to proceed with the Pacific Northwest LNG project near Prince Rupert, British Columbia. It is the first project in British Columbia to reach a conditional FID. Once running, this liquefaction facility will send natural gas to Asia for 25 years – not an arbitrage exercise at all but instead a long-term commitment to its customers and to the Canadian natural gas industry. The Petronas deal, assuming it passes muster with both the BC provincial government and the federal government of Canada, marks Canada’s first entry into the global LNG game.

2 “Japan skips LNG spot price data due to lack of trades”. Reuters. June 9, 2015. http://www.reuters.com/article/2015/06/09/lng-japan-spot-idUSL3N0YV1OY20150609 Accessed June 25, 2015.

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Chapter 1: LNG in the Asia-Pacific Region LNG imports in 2013 reached record highs in the five Asia-Pacific nations that have major regasification terminals: Japan, South Korea, China, India, and Taiwan. In fact, over the decade 2004 to 2013, LNG imports rose every year except for the recessionary year 2009 (see Figure 1.1). South Korea and China witnessed growth largely as a result of industrial demand. Japan’s growth came not only from industrial demand but also from major changes in the nation’s energy mix since the March 2011 Fukushima nuclear crisis. Taiwan LNG imports have risen gradually over the decade as the country has not built as much major regasification infrastructure as its neighbours in the region. India, similarly, had not invested regularly in infrastructure in the past but is poised to import more LNG as several new regasification facilities come online.

Figure 1.1: Asia-Pacific LNG Import Levels in the Decade 2004-2013

Source: BP Statistical Review of World Energy, CERI

The region’s traditional LNG exporting countries – Australia, Brunei, Malaysia, and Indonesia – have also seen growth but at a modest pace. Importing nations in the region still bring in far

greater volumes than the regional exporting nations send out, and of those exports almost all remain within the region. Currently, the difference in demand is being met by suppliers from the Middle East. Australia, as a result of its massive spending on natural gas infrastructure, has more than doubled its LNG export capacity over the years 2004 to 2013, while Malaysia and Brunei have maintained stable export levels. Indonesia is now producing more natural gas than ever but has exported less LNG in recent years because of domestic natural gas demand that has

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doubled since 2005.3 In fact, both Indonesia and Malaysia with their island geography, have

begun regional LNG imports although they remain net exporters.

Figure 1.2: Asia-Pacific LNG Export Levels in the Decade 2004-2013

Source: BP Statistical Review of World Energy, CERI

Importing Nations

Japan

The combination of a weak national economy and vigorous efforts to conserve energy in the wake of the Fukushima disaster saw Japan’s total energy use decline by 13.5 percent in only 3 years. Nuclear energy was affected severely, with the industry completely shut down for a time.

Nuclear’s steep decline was offset by modest increases in oil, coal, and renewables. The place of natural gas in the national energy mix, however, grew 5.2 percent, the most of any energy source, to represent 22.2 percent of the total energy consumed in Japan in 2013 (see Figure 1.3).

3 EIA. Indonesia Country Analysis Brief. www.eia.gov/countries/cab.cfm?fips=id Accessed April 24, 2015.

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Figure 1.3: Change in Japan’s Energy Mix: Pre- and Post-Fukushima

Source: BP Statistical Review of World Energy, CERI

There is presently a tug-of-war between the Liberal Democratic Party government of Prime Minister Shinzo Abe and anti-nuclear advocates. Abe announced in April 2015 a new energy policy direction with nuclear playing a central role, representing 20 percent of the energy mix by 2030. Environmentalists, with the backing of a majority of the citizenry, have taken on the

government in court with varied results.4 The battle over nuclear power in Japan promises to be ongoing and long.

Japan’s natural gas industry is poised to benefit by the nuclear debate, at least over the medium- to long-term. Gas demand is likely to suffer in the short term as some nuclear facilities restart and Japan’s economic growth remains sluggish. Natural gas represents a proven substitute for nuclear and produces fewer GHG emissions than the two other main alternatives: oil and coal. Already the world’s largest importer of LNG, Japan has continued to build up its regasification infrastructure to exceed by far the current levels of demand.5 As Figure 1.4 shows, only about 40 percent of Japan’s LNG capacity was utilized in 2013, a trend that is rising but at a slow pace. Japan also has a diversity of supply, with LNG shipments being sourced from 18 different countries.6

4 Hamada, Kentaro. “Japan court approves restart of reactors in boost for Abe’s nuclear policy”. Reuters. April 22, 2015. http://www.reuters.com/article/2015/04/22/us-japan-nuclear-courts-idUSKBN0NC1QD20150422 Accessed April 22, 2015. 5 EIA. Japan Country Analysis Brief. http://www.eia.gov/countries/cab.cfm?fips=ja Accessed April 22, 2015. 6 BP Statistical Review of World Energy, 2014.

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Figure 1.4: Japan’s LNG Imports and Import Capacity Utilization Rate, 2009-2013

Source: BP Statistical Review of World Energy, CERI

For a number of years, there have been quiet discussions between the governments of Japan and Russia about building an undersea pipeline between Sakhalin and Hokkaido. If constructed, this would be the first pipeline link established between Japan and the Asian continent. Before any pipeline could be seriously considered, however, ongoing trade sanctions over Russia would need to be lifted and perhaps also a resolution found to a territorial dispute in the north of the Japanese archipelago.7 Japan’s imported natural gas will continue to arrive in the form of LNG over the foreseeable future.

The domestic natural gas industry remains small, with fields in Hokkaido and northern Honshu producing less than 500 MMcf. However, there have been efforts for many years to extract natural gas from the abundant methane hydrates present in the Sea of Japan and in the Nankai Trough on the Pacific coast. Extraction is still prohibitively expensive, but the Energy Information

Administration (EIA) notes that commercial production in Japan could start as early as 2018.8 Commercial, economic production of natural gas from methane hydrates could revolutionize the natural gas industry in Japan and elsewhere, simply because of the vast quantities of hydrates present in many areas of the world.

South Korea

In many ways, South Korea’s energy situation resembles that of Japan. Like Japan, South Korea

has few indigenous energy resources. Both countries are denied direct land access to hydrocarbons – Japan because of its geographical isolation as an island nation, and South Korea

7 Reuters. “Russia proposes building natural gas pipeline to Japan – Nikkei”. http://www.reuters.com/article/2014/10/15/russia-japan-pipeline-idUSL3N0SA0ZE20141015 Accessed April 22, 2015. 8 EIA. Japan Country Analysis Brief. http://www.eia.gov/countries/cab.cfm?fips=ja Accessed April 22, 2015.

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because of its separation from continental Asia by its geopolitical rival, North Korea. South Korea

has also diversified its LNG supply similarly to Japan – mitigating geopolitical risk – receiving no more than 33 percent from one source nation (Qatar) and the rest of its gas from more than 10 other countries.

Figure 1.5: Change in South Korea’s Energy Mix: 2004 and 2013

Source: BP Statistical Review of World Energy, CERI

South Korea’s economic miracle has been well-documented. Much of the growth has been built on access to LNG imports, which have more than doubled over the past decade and have made

South Korea the world’s second largest importer of LNG after Japan.9 South Korea has been careful to build regasification capacity to keep pace with natural gas demand, as Figure 1.5 shows. In 2015-16 alone, more than 500 bcf of new regasification capacity is slated to be built.

The South Korean Ministry of Trade, Industry, and Energy is seeking to curtail the growth of the country’s oil and gas sector, at least over the short run, by implementing energy efficiency

measures. This is being done in large part to reduce greenhouse gas emissions. “The government will require all new large, energy-dependent facilities to be equipped with a power management system, such as an energy storage system”, according to the Ministry.10 These measures are expected to decrease natural gas demand by 1.8 percent by 2017.

A recovery in the nation’s nuclear industry should also serve to decrease natural gas demand

over the next few years. Similar to Japan, South Korea has built up a major nuclear industry, with

9 EIA South Korea Country Analysis Brief. http://www.eia.gov/countries/cab.cfm?fips=ks Accessed April 23, 2015. 10 Platts. “South Korea plans to reduce natural gas, oil demand, cut GHG emissions by 2017”. December 2, 2014. http://www.platts.com/latest-news/natural-gas/seoul/south-korea-plans-to-reduce-natural-gas-oil-demand-27891482 Accessed April 23, 2015.

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reactors providing about one-third of the nation’s electricity.11 Also, similar to Japan, South

Korea shut down several of its reactors in recent years because of safety concerns. The country is seeing some of those reactors come back on stream, lessening demand for LNG to help drive that nation’s highly-industrialized economy.

Figure 1.6: South Korea’s LNG Imports and Import Capacity Utilization Rate, 2009-2013

Source: BP Statistical Review of World Energy, CERI

Plans have been tabled in the past to build a gas pipeline from China through North Korea, but the almost constant state of geopolitical tension on the Korean peninsula will need to be resolved

before such a project can go ahead. Another expensive possibility is a Russia-China-South Korea pipeline, with a section of the pipeline lain on top of the sea bed, from the Chinese port of Weihai, stretching to Seoul, some 200 km to the east. For the time being, however, South Korea will be required to import gas through its LNG ports, which is the most economical option.

South Korea’s gas monopoly, KOGAS, has extensively explored the ocean surrounding the peninsula. At present, the only producing gas field is the Donghae field, which is located offshore in the Sea of Japan, south and east of Seoul (see Figure 1.7). This is not a large find, however, producing only about 2 percent of the gas volume the nation requires.12

11 “Nuclear Power in South Korea”. World Nuclear Association. June 17, 2015. http://www.world-nuclear.org/info/Country-Profiles/Countries-O-S/South-Korea/ Accessed June 21, 2015. 12 EIA South Korea Country Analysis Brief.

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Figure 1.7: South Korea Offshore Basins

Source: EIA

China

China imports natural gas for the same reasons as the other countries in the region. But more

than the other nations, China has a severe air pollution problem – a result of burning low quality crude-based fuels and more coal than the rest of the world combined. Pollution has become such a challenge that the central government has been forced to address the concerns of the people – Premier Li Keqiang has declared a “war on pollution13” taking a degree of ownership of the issue and promising sweeping changes to improve air quality. Bringing to industry more natural gas – which emits far less carbon monoxide, nitrogen oxide, sulfur dioxide, and particulates than coal – is one choice to maintain and grow current levels of economic activity in China while reducing air pollution levels.

There is room for a larger role for natural gas in China’s energy mix. In 2013 natural gas held only a 5 percent segment, though that represented double the share natural gas held a decade earlier (see Figure 1.8). China has been busy building both pipeline and LNG regasification infrastructure

in recent years. The nation’s oil and gas companies (ostensibly controlled by the state) have been purchasing overseas natural gas assets, developing in-house upstream expertise, and offering financial loans to other nations in exchange for hydrocarbon supplies. As of 2013, China was the

13 Blanchard, B. et al. “China to ‘declare war’ on pollution, premier says”. Reuters. March 4, 2014. http://www.reuters.com/article/2014/03/05/us-china-parliament-pollution-idUSBREA2405W20140305 Accessed May 9, 2015.

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world’s third largest LNG importer, behind Japan and South Korea, and the ninth largest importer

of pipeline gas.14

Figure 1.8: Change in China’s Energy Mix: 2004 and 2013

Source: BP Statistical Review of World Energy, CERI

Unlike Japan, South Korea, and Taiwan, China has a notable domestic natural gas resource. Most of the gas is located in the central part of the country in areas like Sichuan, Xinjiang and Inner Mongolia, so pipeline infrastructure has been and is continuing to be built to move that gas to the major industrial centres in the south and along the east coast. Unique challenges face the

Chinese natural gas industry, though. Unlike the mostly flat prairie of mid-continent North America, where much of the natural gas is found and from which it is transported, central China is mountainous, and much of the gas is found in complex geological formations. This is not to say it cannot be extracted. It can be, but it cannot be done easily or cheaply. Moreover, the construction and operation of pipelines to these remote and rocky regions is challenging and expensive.

The central government regularly sets ambitious coalbed methane (CBM) and shale gas production targets to access an estimated 134 Tcm of gas-in-place.15 However, these goals are not regularly met. For example, at the beginning of 2015, the government stated that China will be producing 2.9 bcf/day of CBM by 2020, and then only three months later increased that forecast to 3.9 bcf/day, “prompting criticism that it is unrealistic in view of currently depressed

oil prices…”16 The government is also optimistic about shale gas, expecting over 600 MMcfd in production for 2015, whereas industry experts feel somewhere in the range of 400 to 450 MMcfd

14 BP Statistical Review of World Energy, 2014. 15 “Oil & Gas Security: Emergency Response of IEA Countries”. IEA. 2012. P. 14. https://www.iea.org/publications/freepublications/publication/China_2012.pdf Accessed May 9, 2015. 16 “China’s CBM Target Upgrade Draws Skepticism”. Natural Gas Week. Vol XXI, No.9, March 2, 2015. Page 17.

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is more realistic.17 These are not large volumes – nowhere near being able to meet all of China’s

burgeoning natural gas demand. Clearly a number of factors, including infrastructure and cost constraints, are coalescing to keep China’s CBM and shale gas industry small for the time being.

Much greater volumes may be received by international pipelines. China’s pipeline gas imports are presently being received from Turkmenistan (80 percent), Uzbekistan (12 percent), Burma (5.5 percent), and Kazakhstan (1.5 percent) and volumes rose to record highs in 2013, to 27.4 Bcm (2.65 Bcfd), up from 21.4 Bcm (2.07 Bcfd) in 2012.18 However, there is a big game changer on the horizon in the form of two proposed 56” gas pipelines from Russia – the Altai pipeline and the Power of Siberia pipeline – that could move natural gas volumes in excess of 90 Bcm per year (8.7 Bcfd) into China if constructed and if operated at capacity. The question that remains to be answered is whether or not Russia can afford the investment now that their economy has slowed, and if they cannot afford it, are they willing to take money from China in exchange for more

control of the upstream assets? As of this writing, Gazprom, which is constructing Power of Siberia, has announced that work has begun on the pipeline and it is still on course to be transporting first gas by 2019.19 Ground has not yet been broken on Altai.

Though China’s LNG imports have increased in recent years, the import capacity utilization rate has not risen to the same degree, as Figure 1.9 shows. This has to do with the upsurge in pipeline imports from central Asia, expanded domestic natural gas production, and a rise in LNG regasification capacity. As a result, China is well-prepared to handle the expected, continued increase in LNG shipments from abroad.

17 Ibid. 18 “China’s December gas pipeline imports hit record high 3.41 Bcm”. Platts. January 26, 2015. http://www.platts.com/latest-news/natural-gas/singapore/chinas-december-gas-pipeline-imports-hit-record-26991967 Accessed May 9, 2015; BP Statistical Review of World Energy, 2013, 2014. 19 http://www.gazprom.com/press/news/2015/march/article220536/ Accessed May 9, 2015.

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Figure 1.9: China’s LNG Imports and Import Capacity Utilization Rate, 2009-2013

Source: BP Statistical Review of World Energy, CERI

India

As with its LNG importing neighbours in the Asia-Pacific region, India has seen LNG imports rise over the past decade, though not to the same degree as those nations (see Figure 1.10).

Figure 1.10: Change in India’s Energy Mix: 2004 and 2013

Source: BP Statistical Review of World Energy, CERI

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India is still in many ways a developing country, despite its renowned Information Technology

and Manufacturing sectors. 77 million households in India were without electricity in 2011,20 and if the federal government’s goal of universal electrification by 2019 is to be approached or met, it will probably be done through inexpensive and available coal, rather than by extensive use of natural gas.21 It is a challenge to forecast the role that natural gas will play in the Indian economy in the future, as the price is controlled by the government and the government has not announced any clear policy direction. As one expert puts it,

In India, although the government has pledged to review the [natural gas] pricing formula every 6 months – which is significant given long periods of inactivity in the past, it is as yet unclear what the long-term or medium-term goal of reform is – for instance, to make gas competitive with coal for environmental reasons, to replace other fuels (such as oil) with gas for fiscal and budgetary reasons, or to retain a proportion of gas as backup generation in the pursuit of renewable energy.22

In short, the future of natural gas in India depends greatly on the vagaries of politics and government and is therefore difficult to predict.

That being said, India has begun to build up its regasification capacity, and it also appears that the oft-delayed Turkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline, India’s first major gas import line, will be under construction in 2015.23 TAPI, if it can finally get moving, will initially provide India with 1.2 bcfd of natural gas to supplement domestic production and LNG imports.

LNG import capacity utilization exceeded 90 percent in 2007, only three years after India commenced its first natural gas imports (from Qatar), and again in 2011, when infrastructure

construction could not outpace domestic demand. Recently-built, large regasification facilities in Kerala and Maharashtra brought that rate down to 47 percent in 2013 (see Figure 1.11). This could decrease further if all of India’s planned regasification projects become operational within the next few years. As of 2013, India is the fourth largest LNG importer in the world, with 86 percent of supply from Qatar and the rest of the gas originating from a handful of other countries.24

20 Palit, D. et al. “Indian Approaches to Energy Access” in Energy Poverty: Global Challenges and Local Solutions. Oxford University Press, 2014. P 237. 21 Sen, Anupama. “Gas Pricing Reform in India: Implications for the Indian gas landscape.” Oxford Institute for Energy Studies. April 2015. P. 58. http://www.oxfordenergy.org/wpcms/wp-content/uploads/2015/04/NG-96.pdf Accessed April 23, 2015. 22 Sen, P. 59. 23 Tanchum, Micha’el, “A breakthrough on the TAPI pipeline?” The Diplomat. March 20, 2015. http://thediplomat.com/2015/03/a-breakthrough-on-the-tapi-pipeline/ Accessed April 23, 2015. 24 BP Statistical Review of World Energy, 2014.

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Figure 1.11: India’s LNG Imports and Import Capacity Utilization Rate, 2009-2013

Source: BP Statistical Review of World Energy, CERI

The domestic natural gas industry supplied all of the country’s needs until a decade ago. Though India holds 47 Tcf of proved natural gas reserves, recent production has been around 1.5 Tcf per year and appears to be on the decline, according to the EIA.25

Taiwan

With few indigenous hydrocarbon resources, Taiwan has been importing oil and gas for years. The country’s LNG infrastructure is well established, and as of 2013, Taiwan was the 5th largest

importer of LNG in the world. The lion’s share of Taiwan’s energy mix comes from oil and coal, but natural gas has been growing, up 4 percent over the decade 2004-2013 (see Figure 1.12). The country receives most of its gas from Malaysia, Indonesia, and Qatar, but according to the EIA, Taiwan is now mitigating its import risk by negotiating new deals with Australia, the US, and Papua New Guinea.26 Though there has been talk in the past about building natural gas pipelines across the Taiwan Strait to access supply from mainline China, no infrastructure has been built yet;27 all of Taiwan’s gas imports arrive by LNG tanker.

25 EIA. India Country Analysis Brief. http://www.eia.gov/countries/cab.cfm?fips=in Accessed April 23, 2015. 26 EIA Taiwan Country Analysis Brief. http://www.eia.gov/countries/country-data.cfm?fips=tw Accessed May 9, 2015. 27 “China, Taiwan Urged to Explore Possibility of Undersea Gas Pipeline”. Natural Gas Asia. http://www.naturalgasasia.com/china-taiwan-urged-to-explore-possibility-of-undersea-gas-pipeline-10894 Accessed May 9, 2015.

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Figure 1.12: Change in Taiwan’s Energy Mix: 2004 and 2013

Source: BP Statistical Review of World Energy, CERI

Only two regasification terminals are in operation in Taiwan, the Yung-An facility (1.3 Bcfd), which has been operational since 1990, and the smaller Taichung facility (0.4 Bcfd), which came online in 2009. A third facility is needed as the utilization rate has neared 100 percent in recent years (see Figure 1.13). That facility, Taipei LNG, is presently under construction and should be online in 2018. Taiwan is planning to decommission its nuclear plants beginning in 2019, another reason why the new regasification facility will be welcomed.28

Figure 1.13: Taiwan’s LNG Imports and Import Capacity Utilization Rate, 2009-2013

Source: BP Statistical Review of World Energy, CERI

28 “Taiwan’s CPC finalizes location of third LNG terminal, says chairman.” Platts. http://www.platts.com/latest-news/natural-gas/tokyo/taiwans-cpc-finalizes-location-of-third-lng-terminal-7079593 Accessed May 9, 2015.

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Natural gas imports will continue for the foreseeable future in Taiwan. One area of potential for

domestic production is the East China Sea, which is a promising region for natural gas. However, much of the area is under territorial dispute, with China, South Korea, and Japan all making claims. As of this writing, no negotiated settlement is on the horizon.

Taiwan, as mentioned earlier, is mitigating risk by sourcing its natural gas from various countries throughout the world. It is also investing in upstream projects in these countries. Taiwan’s energy monopoly, CPC Corporation, according to its website has “twin goals…of locking in stable supplies over the long-term through ownership or control of the resources [thereby reducing import costs]. As of the end of 2013, CPC was engaged in cooperative exploration and production in 25 fields spread over 10 countries.29” Taiwan, like the other Asian importing nations, is not content simply to rely on LNG contracts and the spot market to obtain natural gas supplies; it has become directly involved in upstream projects across the globe to ensure control from wellhead

to burner-tip.

All five of Asia’s LNG importers are seeing increased volumes of LNG and a greater place in the energy mix for natural gas. All of these countries either have a diversity of supply sources or are taking measures to diversify. Japan, Korea, Taiwan, and to a lesser degree China, have for many years been gradually building up regasification capacity in order to accept far greater volumes of LNG in the future. India did not plan its infrastructure as carefully and has seen a high regasification utilization factor over the past decade, approaching 100 percent in some years. But even in India, new regasification facilities are now being planned and built as that nation embraces LNG imports to supplement domestic natural gas production.

Exporting Nations and Regions In the world today LNG liquefaction capacity is fast approaching 300 MTPA, and should surpass that number later this year when facilities in the United States and Australia come online. Though there is much talk of new projects throughout the world, with over 800 MTPA having been proposed, the fact of the matter is that only 130 MTPA of new capacity is presently under construction. And 90 percent of that construction is happening in the United States and Australia. These facilities are expensive to build, far more so than regasification facilities, so it stands to reason that liquefaction is mostly being proposed and built in natural gas-rich nations that do not present high levels of country risk and can attract financial backing. The US, especially the Gulf Coast, is active now because companies can build tolling plants and tap into Henry Hub-priced supply. Furthermore, Australia is building up supply because companies there have made numerous potentially profitable natural gas discoveries and wish to monetize them.

29 http://en.cpc.com.tw/global_content.aspx?ID=1 Accessed May 9, 2015

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Australia

But it appears the bloom has fallen off the rose of the Australian natural gas LNG export industry. Analysts have likened the present situation to a “slow train crash”30 with tens of billions having been spent already, over $170 billion being spent on under-construction liquefaction infrastructure, and not enough gas production to fulfill natural gas contracts that stretch out 20 years into the future. Some state governments have restricted gas drilling, which is a controversial practice in Australia, and until those restrictions are lifted, gas flow in many locations will be limited.

These limitations may well be short-lived, but other predicaments face Australia as it looks to move the world’s third largest LNG export industry into a global leadership position. The nation has four operating LNG liquefaction facilities and six more under construction (see Figure 1.14), and this extensive activity has led to mounting labour shortages and costs. Furthermore,

escalating material costs, land rights issues, and the long distance of natural gas fields from markets and export facilities are all contributing additionally to rising costs. Though projects that are under construction in 2015 will almost certainly be finished, it is improbable that proposed expansions and greenfield projects with a capacity approaching 40 MTPA – Fisherman’s Landing, Tassie Shoal, Sunrise, Scarborough, Browse, Cash Maple, and the Gorgon expansion – will go ahead until oil and gas prices rise and settle for a period of time at significantly higher levels than in 2015. Already, Shell has cancelled the Arrow project in Queensland, which would have brought proposed greenfield capacity up to beyond 50 MTPA.31

30 Macdonald-Smith, Angela. “Australia’s LNG market a ‘slow train crash’ says Credit Suisse analyst”. Sidney Morning Herald. February 17, 2015. http://www.smh.com.au/business/australias-lng-market-a-slow-train-crash-says-credit-suisse-analyst-20150217-13gnh8.html Accessed May 26, 2015. 31 Wilkinson, Rick. “Shell cancels Arrow LNG project”. Oil and Gas Journal. January 30, 2015. http://www.ogj.com/articles/2015/01/shell-cancels-arrow-lng-project.html Accessed May 26, 2015.

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Figure 1.14: Australia LNG Projects – Proposed, Under Construction, Operating – 2015 Spring

Source: CERI, EIA, Company websites

There will be a deep impact on world LNG supply from the 56.85 MTPA of new capacity Australia plans to build by year-end 2017.32 That volume represents a 21 percent increase from the world 2013 capacity of 270 MT. Approximately 90 percent of gas from these new projects is covered

under long-term supply contracts to Korean, Japanese, and Chinese companies and utilities, providing a secure source of natural gas to these markets for years to come and reducing the need to look elsewhere in the world for supply. Countries aspiring to compete with Australia for the Asia-Pacific market, but are not yet building new liquefaction capacity, may find themselves at a disadvantage over the next few years. Though natural gas demand promises to be robust over the long haul, such a rapid and large addition to LNG capacity will soften demand in the short term.

Canada

British Columbia

When CERI published its first LNG study in January 2013, there were six natural gas liquefaction projects planned for the Pacific coast of Canada. As of June 2015, there are twenty announced

projects, and most of the major players are present: Shell, Exxon Mobil, CNOOC, PetroChina, Mitsubishi, and KOGAS, among others. Of those twenty projects, ten have received export licenses from the NEB, and are awaiting a Final Investment Decision (FID). No FID’s have been taken on any of the projects as of this writing, though one project, Pacific Northwest LNG, has

32 BP Statistical Review of World Energy, 2014.

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announced a provisional FID, which is contingent on the British Columbia provincial legislature

approving the project in July and a further federal regulatory decision to be taken sometime in the fall of 2015.33

If the announcement of so many projects is not indication enough of strong industry interest in British Columbia LNG, certainly the active presence of many of these companies further upstream in British Columbia and Alberta provides additional evidence of commitment to develop the resource. So, what is holding up the start of work? It boils down to cost and a market supply glut. All of the proposed British Columbia LNG liquefaction developments are greenfield projects, located for the most part in a remote corner of the province without access to gas unless upstream and midstream infrastructure could be built. Only recently many of these schemes began to appear feasible if oil-indexed supply contracts could be secured. But over the past year both crude-linked contract LNG prices and spot market LNG prices have fallen precipitously.

Unlike Australian projects that have the vast majority of their output covered under long term supply contracts, not all of the Canadian projects have found customers. And the Canadian projects are at a cost disadvantage to the US projects under development, as the US Gulf Coast facilities are all brownfield projects; originally planned for LNG import, with much of the capital cost sunk years ago, they are now being converted to liquefaction facilities instead. And the US projects do not have to invest in a dedicated source of supply.

Most analysts predict that at most, anywhere from one to five of the British Columbia projects will receive an FID, with the other projects being postponed or cancelled outright. Indeed, if all twenty were to go ahead on schedule, British Columbia liquefaction capacity would reach 300 MTPA within a decade (see Figure 1.5). By way of comparison, world LNG shipments in 2013 totaled only 270 MTPA,34 and in British Columbia and Alberta – the two provinces from which

natural gas would be sourced – total natural gas production in 2013 was only 119 MTPA.35 Alberta and British Columbia natural gas production would need to increase by 152 percent to supply all twenty projects. Natural gas reserves are vast in these two provinces, but it would be an undertaking of unprecedented size and scope to develop them in the next five to ten years.

33 Cattaneo, Claudia. “Why the go-ahead for Pacific NorthWest LNG is a big shot in the arm for Canada’s energy industry.” Financial Post. June 13, 2015. http://business.financialpost.com/news/energy/petronas-lng-launch-a-big-deal-for-b-c-industry?__lsa=64c9-9d40 Accessed June 21, 2015. 34 BP Statistical Review of World Energy, 2014; CERI 35 Canadian Association of Petroleum Producers (CAPP)

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Figure 1.15: Proposed British Columbia LNG Liquefaction Projects

Sources: CERI, NEB, Province of British Columbia, Company websites

There remains the additional issue of pipeline infrastructure. For all of the Western Canadian gas to reach the British Columbia coast, a commensurate increase in pipeline capacity would be necessary, upwards of 30 bcfd. However, there is only a total pipeline capacity of 14.6 Bcfd being

proposed (see Table 1.1). And even then, can volumes of such size be sustained over the lifespan of these projects?

Table 1.1: Proposed Pipelines to Supply British Columbia LNG Liquefaction Projects

Sources: CERI, Government of British Columbia, company websites

At a time when there is a worldwide glut of LNG, and several large liquefaction projects on the verge of completion, there is no reason for Canada on its own to attempt to double the world LNG supply.

The projects that are likely to go ahead in the coming few years require companies and partnerships that are in the business for the long term and are not unduly concerned over recent

NameCapacity

(BCFD)From To

Associated LNG

Facility

Pacific Northern Gas Transmission Pipeline Expansion 0.61 Summit Lake Kitimat multiple; Kitimat LNG

Pacific Trail Pipeline 1.4 Summit Lake Kitimat Kitimat LNG

Coastal GasLink Pipeline 2 Dawson Creek Kitimat LNG Canada

Prince Rupert Gas Transmission 2 Ft. St. John Prince Rupert Pacific Northwest LNG

Westcoast Connector Gas Transmission 8.4 NE BC Prince Rupert Prince Rupert LNG

Eagle Mountain -- Woodfibre Gas Pipeline 0.228 Coquitlam Squamish Woodfibre

Total 14.638

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fluctuations in the price of natural gas and LNG. Three of the larger projects in particular hold

potential: Pacific Northwest LNG, LNG Canada, and to a lesser extent Kitimat LNG. Of the smaller facilities, Douglas Channel and Woodfibre are good possibilities.

Pacific Northwest LNG

Pacific Northwest LNG is a partnership between Petronas of Malaysia (62 percent), Sinopec (15 percent), the Japan Petroleum Exploration Company (15 percent), the Indian Oil Corporation, Ltd. (10 percent), and PetroleumBRUNEI (3 percent).36 It has strong potential to go ahead (as mentioned earlier, Petronas and its partners have made a provisional FID), but unlike Kitimat LNG, Pacific Northwest has run into problems in its dealings with First Nations. The partnership was offered to the Prince Rupert Lax Kw’alaams First Nation, a $1.15 billion deal paid over 40 years, for approval to build the project. However, the First Nation rejected the deal unanimously,

not because the sum was considered too low, but because certain environmental concerns had not been addressed to their satisfaction. In particular, the Lax Kw’alaams cited a proposed bridge that could affect salmon spawning habitat.37 Recent rulings by the Supreme Court of Canada have underlined the necessity of consulting and receiving approvals from First Nations on major infrastructure projects that impact their territories. The company will be working towards solving this issue over the coming months in order to win approval for their project from both the British Columbia provincial government and the Canadian federal government. If this issue is resolved eventually, and the requisite approvals are in place, Pacific Northwest shows solid promise – there is an approved pipeline proposal in place, the 2 bcfd Prince Rupert Gas Transmission line, to be built by TransCanada – and offtake agreements have been signed with several Asian buyers.

LNG Canada

LNG Canada in Kitimat is being proposed by Shell Canada, KOGAS, Mitsubishi, and PetroChina, with Shell possessing a 50 percent share, PetroChina, holding 20 percent, and KOGAS and Mitsubishi taking 15 percent each. LNG Canada’s partners are all big players in natural gas and looking to grow their assets. At a time when many companies are pulling back from LNG, Shell is investing in three major projects in various parts of the globe; PetroChina is also expanding its LNG business and has three new LNG import facilities in China to supply with gas; Mitsubishi has been involved in the industry since the first project in Alaska was commissioned in 1969; and KOGAS is the world’s largest regasifier today.38 LNG Canada has “Asian customers lined up to take delivery”, according to the Globe and Mail.39 This project also has its own pipeline system in the works, the Coastal GasLink pipeline, which would bring 2 bcfd of gas from the Dawson

36 http://pacificnorthwestlng.com/learn-about-pacific-northwest-lng/ Accessed May 18, 2015. 37 “B.C. First Nation says No to $1.15-billion deal, says it’s ‘not a money issue’”. The Canadian Press. May 14, 2015. http://www.vancouverobserver.com/news/bc-first-nation-says-no-115-billion-deal-says-its-not-money-issue Accessed May 18, 2015. 38 http://lngcanada.ca/the-project/the-companies-behind-lng-canada Accessed May 18, 2015. 39 Jang, Brent. “Shell-BG Group merger a game changer for B.C.’s LNG industry”. Globe and Mail. April 8, 2015. http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/shell-bg-group-merger-a-game-changer-for-bcs-lng-industry/article23853965/ accessed May 18, 2015.

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Creek area, close by Shell’s northeastern BC natural gas assets. The partners estimate the project

could cost between $25 billion and $40 billion, depending on the degree to which there is cost escalation.40

Kitimat LNG

Kitimat LNG received a boost when Woodside Canada replaced Apache as Chevron’s partner. Prior to the announcement, the project was in a state of limbo because Apache had decided in August 2014 that it wished to exit the partnership.41 Perth-based Woodside has been a central participant in Australia’s burgeoning LNG industry, involved in Australia’s first LNG project – Northwest Shelf – and in four others – Pluto, Wheatstone, Browse, and Sunrise. In fact, Chevron has a history with Woodside as participants in the Northwest Shelf JV and two other Australian LNG projects. The companies are also working together on some upstream projects in British

Columbia’s Liard and Horn River basins in order to feed gas to Kitimat. The $1.5 billion Pacific Trail Pipeline, with a capacity of 1.4 bcfd, is proposed to bring that upstream gas to the coast from northeast British Columbia. Benefits agreements have been signed with all of the First Nations along the pipeline route, and the liquefaction project enjoys the support of the Haisla nation, whose land at Bish Cove is being leased. The challenge facing Kitimat LNG is getting commitments from Asian customers to buy the LNG. Certainties are required for a project of this size and scope; financing would be impossible to secure for a project relying on spot LNG when complete.

Douglas Channel LNG

Of the smaller LNG facilities, two that are most likely to go ahead are Woodfibre LNG in Squamish

– which is approximately 60 km north of Vancouver – and Douglas Channel LNG near Kitimat. Douglas Channel was in receivership when it was bought by a consortium including AltaGas, Idemitsu (Japan), Électricité de France, and EXMAR NV (Belgium).42 This facility will be constructed on leased Haisla First Nation land and gas will be supplied via existing pipelines in the area. The Douglas Channel business model is based on building from a small starting point. Overnight costs for the project, estimated at $500 million,43 will not approach those of the Shell, Chevron/Woodside, and Petronas projects, providing Douglas Channel with opportunity to

40 Jang, Brent. “Shell says B.C. LNG export terminal to cost $40-billion.” Globe & Mail. November 7, 2014. http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/shell-says-bc-lng-export-terminal-to-cost-40-billion/article21509629/ Accessed May 18, 2015. 41 “Apache sells stake in Kitimat LNG project to Woodside Petroleum”. CBC News. December 15, 2014. http://www.cbc.ca/news/business/apache-sells-stake-in-kitimat-lng-project-to-woodside-petroleum-1.2873884, Accessed May 18, 2015. 42 Press release. “Fresh Start for Douglas Channel LNG Project as New Owners Take Control”. January 29, 2015. Exmar. http://www.exmar.be/file.aspx?id=1078 Accessed May 18, 2015. 43 Lewis, Jeff. “AltaGas poised to help save Douglas Channel LNG project”. Financial Post. March 12, 2014. http://business.financialpost.com/news/energy/altagas-poised-to-help-save-douglas-channel-lng-project?__lsa=2801-ea85 Accessed May 19, 2015.

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succeed on a modest scale. If that success is reached, the consortium has plans to construct the

similarly modest Triton facility within a few years (see Figure 1.15).

Woodfibre LNG

Woodfibre, like Douglas Channel, sees an opportunity to succeed simply because it is nowhere near the size of the other proposed facilities on the Pacific coast – it is expected to cost in the area of $1.7 billion, a fraction of the $25 billion + costs of the larger projects. With a deepwater port, access to an import facility in China (which may or may not be used), and natural gas supply being fed by the modest (0.23 Bcfd) Eagle Mountain – Woodfibre Gas Pipeline, Woodfibre should be able to find a niche in the global LNG market. Woodfibre claim that their project “doesn’t need the really high prices of last year to be successful”.44 $10 to $12 LNG is enough to make the undertaking feasible.

Eastern Canada

There has been recent interest arising in sending Canadian LNG to export markets via deep water ports in Eastern Canada. East Asian markets could be accessed via the Panama Canal or possibly, in a number of years, the much larger canal planned for Nicaragua. But Europe and India are the markets most discussed. Germany and other European nations appear eager to secure alternative gas sources to Russia, which has never been an entirely reliable supplier. With civil war raging in Ukraine, an important transit point for much of the Russian natural gas, European energy security is tenuous. Opportunity exists also in India, which is already a major importer of LNG, is building more regasification infrastructure, and may be requiring greater volumes of natural gas if the TAPI import pipeline is further delayed. The various proponents of the Eastern Canadian projects voice optimism but a number of obstacles remain in the way, including lack of

pipeline infrastructure and no final word of approval yet from the NEB on export licenses. And these projects will require US supply, raising significant sovereign risks that the pipelines will be approved and if approved, allowed to operate over the life of the plants. Assuming that pipelines can be built, supply can be found, approvals can be earned, money can be raised, and markets can be secured, the potential exists for a Canadian East Coast export industry approaching 50 MTPA (see Figure 1.16).

44 Pablo, Carlito. “Woodfibre LNG plant in Squamish likely won’t be up and running by 2017”. The Georgia Straight. April 16, 2015. http://www.straight.com/news/433031/woodfibre-lng-plant-squamish-likely-wont-be-and-running-2017 Accessed May 19, 2015.

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Figure 1.16: Proposed Eastern Canada LNG Liquefaction Projects

Sources: CERI, NEB, Company websites

Goldboro LNG

The project garnering the most attention is the Goldboro facility, which is planned for Nova Scotia. Already, Goldboro (owned by energy infrastructure company Pieridae) has found a European buyer for 5 MTPA of its 10 MTPA capacity – the German utility E.ON. Moreover, Goldboro is at the end point of the Maritime & Northeast Pipeline that now ships Nova Scotia natural gas (which is in decline) to the United States but could be reversed to bring in natural gas from the Marcellus shale. Estimated capital costs for Goldboro range between $5 and $10 billion; Pieridae has received loan guarantees from the German government, so funding is available if an FID is taken.45 Goldboro received approval from the Province of Nova Scotia without meeting any additional environmental or stakeholder-related criteria beyond what was required for the NEB application. This contrasts with the Bear Head facility, which has been asked to meet

numerous provincially-set criteria.

45 McCarthy, Shawn. “Canada’s LNG marathon man: pioneering the dream from coast to coast.” Globe & Mail. February 27, 2015. http://www.theglobeandmail.com/report-on-business/careers/careers-leadership/pieridae-energy-boss-pioneered-bcs-lng-dream/article23234989/ Accessed May 19, 2015.

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Bear Head LNG

An Australian company, Liquefied Natural Gas Ltd., is behind the Bear Head LNG product slated for construction in Point Tupper on Cape Breton Island. This facility was approved in May 2015 at the provincial level (though NEB approval is still pending) but the company must meet 32 conditions. These conditions include monitoring and making contingencies for “air emissions, greenhouse gases, noise, birds, wildlife (especially species at risk), traffic, and water sources”.46 Furthermore, the Bear Head operators will be required to consult with “municipal, Mi’kmaq and citizen representatives47” and if any archeological discoveries are found, the developers must halt all work on the project. Nevertheless, Liquefied Natural Gas has indicated it intends to comply with all of the conditions. If the project goes ahead according to the company’s timeline, an FID will be taken in 2016 and the facility could be operational in 2019 – liquefying 8 MTPA for export to Europe and India.

Canaport LNG

Canada’s sole brownfield proposal is the Canaport facility that has been importing LNG in St. John, New Brunswick since 2009. Converting the facility to export is not yet a fait accompli, but one of the owners, Spanish major Repsol, has decided to apply for an export license anyway. The conversion to a liquefaction facility with capacity of 5 MTPA could cost as much as $4 billion,48 but because the storage and other infrastructure is already in place, this is less than the cost of a greenfield facility of the same size.

H-Energy

The H-Energy liquefaction facility, if built, would be the largest of all the proposed Eastern

Canadian projects, with an annual export capacity of 13.5 MT. It is planned for Melford on Cape Breton Island, with an estimated cost of $3 billion. As of this writing, the National Energy Board (NEB) does not list H-Energy among facilities applying for an export license, so this project is still in the early stages of development. The developer is the Hiranandai Group of Mumbai, which states that it has MoU’s with clients in Europe and India for 50 percent of the plant’s capacity.49

Energie Saguenay (GNL Quebec)

The Energie Saguenay facility, planned to a capacity of 11 MTPA, is slated to be built in Grande-Anse, La Baie, Quebec, on the shores of the St. Lawrence Seaway. This project is proposed by

46 Gunn, Andrea. “N.S. approves Bear Head LNG plant”. Halifax Chronicle Herald. May 19, 2015. http://thechronicleherald.ca/business/1287711-n.s.-approves-bear-head-lng-plant Accessed May 21, 2015. 47 Ibid. 48 Jones, Robert. “Repsol applies to export LNG from Canaport”. CBC News. February 12, 2015. http://www.cbc.ca/news/canada/new-brunswick/repsol-applies-to-export-lng-from-canaport-1.2954857 Accessed May 21, 2015. 49 Alberstat, Joann. “H-Energy’s planned LNG plant for Melford garners global clients”. Halifax Chronicle Herald. July 18, 2014. http://thechronicleherald.ca/business/1223795-h-energy-s-planned-lng-plant-for-melford-garners-global-clients Accessed May 21, 2015.

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Ruby River Capital of the US, will cost $7.5 billion, and is expected to be operational by 2021.

Because Energie Saguenay is located on the Quebec grid, it will have access to 550 MW of electricity, which the developers claim will result in “significantly lower GHG emissions and lower operating costs than other major LNG plants today”.50 Unlike the Stolt LNGaz project (see below), which is being developed partly to meet domestic natural gas demand, Energie Saguenay will export all of its LNG, with its deep-water port servicing 160 Q-Flex class vessels per year. The Nova Scotia projects hinge on a reversal of the Maritimes & Northeast Pipeline, but Energy Saguenay plans on sourcing its natural gas from a new 650 km pipeline to be built by TransCanada Pipelines to tap into the mainline gas system in Ontario.51

Stolt LNGaz

A facility is planned for Becancour Quebec, which is on the South Shore of the St. Lawrence,

directly across from Trois-Rivieres. The Stolt LNGaz project is owned by a Norwegian company, Stolt-Nielsen Gas, with experience in shipping and storing LNG and Liquefied Petroleum Gas (LPG) in Europe and Asia. The facility itself will be small in comparison with the other LNG liquefaction projects planned for Eastern Canada, and its mandate will be different. Not only will Stolt LNGaz serve the international LNG market, with exports of approximately 0.5 MTPA, it will also ship LNG to industrial regasification facilities along the St. Lawrence; some of the LNG will be offloaded to trucks for shipment to remote areas in northern Quebec. Stolt-Nielsen plan to invest $600 million into the project and hope to capture niche markets in Europe, Asia, South America and the Caribbean.52

United States

More LNG liquefaction capacity is being planned for Canada than for the United States, but while

most Canadian projects await an FID, five projects are already under construction in the US (see Figure 1.17). Four of those liquefaction projects are brownfield; they hold a significant capital cost advantage over the greenfield projects because many engineering and infrastructure costs were sunk in years past when these sites were being built for regasification purposes. Beyond these facilities, what gets developed depends on market demand; an ability to keep capital costs low; an uncongested Panama Canal (for Asia-bound exports originating on the Gulf and Atlantic coasts); and perhaps taking advantage of niche opportunities that arise.53 The US projects are entering a world LNG market that is still relatively small at around 270 MTPA and are competing for market share, not only with the Canadian and Australian facilities, but also with large East African projects, possible ventures in Nigeria, and various pipeline developments. The once large arbitrage opportunities that were present in the global LNG market as recently as a year ago have

50 http://energiesaguenay.com/en/project/project-summary/ 51 Application to the NEB, GNL Quebec, Inc. https://docs.neb-one.gc.ca/ll-eng/llisapi.dll/fetch/2000/90466/94153/552726/2540979/2541293/2540639/Export_Application_%28English%29_-_A4D7G7.pdf?nodeid=2541185&vernum=-2 Page 3. Accessed May 21, 2015. 52 http://www.slngaz.com/en/home 53 For example, small scale LNG to serve corporate customers on a coastline – similar to the Stolt LNGaz project that will serve small markets along the St. Lawrence and northern Quebec

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all but disappeared with a highly competitive market landscape taking its place – at least for the

time being. As matters stand now, if all US projects are completed on schedule, 68.9 MTPA will be added to world LNG supply by 2019.

US Regulation

Exporting natural gas from the United States can only happen if certain regulatory conditions are met. First, developers must gain permission from the US Department of Energy (DoE) for export to countries that have a free-trade agreement with the US; in order to satisfy the DoE, the developer must show that the project would not harm the US economy, US energy security, or the local environment. Then there must be approval from the Federal Energy Regulatory Commission (FERC), which can take over a year to grant. Finally, if a developer wishes to export to countries that do not have a free-trade agreement, they must make another application to the DoE. Few projects make it this far. However, all five of the projects under discussion in this

report have been granted the necessary approvals at every level.

Figure 1.17: Planned US LNG Liquefaction Projects

Source: CERI, Company websites

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Sabine Pass LNG

Getting a jump on the Gulf Coast competition, Cheniere Energy’s Sabine Pass is the first of all of the US projects that will be operational – sometime in 2015. 4.5 MTPA of capacity will be online at that point with two more trains of 4.5 MTPA becoming operational in 2016, and a fourth train of the same capacity operating in 2017. Sabine Pass represents something of a miracle for Cheniere, which built the massive facility in 2008, strictly for regasification of imported gas. The facility’s 6 massive storage tanks, with a capacity of 17 Bcf, sat empty for seven years. But with the quick development of an export market, Cheniere was in a serendipitous position to turn much of the facility into a liquefaction terminal. As the Cheniere CEO Charif Souki stated: “it’s a revolutionary thing, absolutely astonishing, that America will be an exporter of hydrocarbons”.54 When all is said and done, Sabine Pass will be bi-directional, operating both regasification and liquefaction facilities. As mentioned earlier, Cheniere is functioning under an LNG tolling business

model, taking delivery of gas (priced at Henry Hub) from a number of upstream sources and delivering LNG to multiple clients. These clients include Chevron (US), Total (France), BG Group (Shell), Gas Natural Fenosa (Spain), KOGAS (Korea), and GAIL (India), all of whom signed 20-year contracts. When Cheniere finishes the Sabine Pass, Sabine Pass extension (not yet under construction), and the Corpus Christi projects, the company could be exporting approximately 10 percent of total global LNG.55

Cove Point LNG

Dominion Resources’ Cove Point LNG in Maryland is the only one of the five projects now under construction located outside of the Gulf of Mexico region. Originally a regasification facility, now it is being converted to export LNG as well. Cove Point is situated in the Chesapeake Bay, an area

that has not seen nearly as much oil and gas infrastructure development as the Gulf Coast. As a result, there has been public opposition to the changed facility, with concerns being voiced about issues such as hydraulic fracturing and the plant’s proximity to a nuclear reactor.56

Dominion has carried on with the project, however, with a commitment to spend upwards of $3.8 billion on liquefaction facilities. In May 2015, Dominion received permission from the DoE to export domestic natural gas from Cove Point to countries without a Free Trade Agreement with the US.57 The government “considered the economic, energy security, and environmental

54 Helman, Christopher. “How Cheniere Energy Got First IN Line To Export America’s Natural Gas.” Forbes. May 6, 2013. http://www.forbes.com/sites/christopherhelman/2013/04/17/first-mover-how-cheniere-energy-is-leading-americas-lng-revolution/ Accessed May 26, 2015. 55 “Will the U.S. Shale Boom Fuel Asia’s Economic Future and Europe’s Energy Security?” Market Wired. March 4, 2015. http://www.marketwired.com/press-release/will-the-us-shale-boom-fuel-asias-economic-future-and-europes-energy-security-nyse-lng-1997598.htm Accessed May 26, 2015. 56 Selle, Caroline. “Maryland Residents Fight Cove Point LNG Export Plans That Threaten to Turn Area Into ‘Industrial Site’”. Desmog. January 29, 2014. http://www.desmogblog.com/2014/01/28/maryland-residents-fight-lng-export-plans-threaten-turn-area-industrial-site Accessed May 26, 2015. 57 ”Energy Department Authorizes Dominion Cove Point LNG to Export Liquefied Natural Gas”. Energy.gov. May 7, 2015. http://energy.gov/articles/energy-department-authorizes-dominion-cove-point-lng-export-liquefied-natural-gas Accessed May 26, 2015.

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impacts and determined that exports at a rate of up to 0.77 Bcf/d for a period of 20 years was

[sic] not inconsistent with the public interest”.58 Thus, the determination has been made at the federal government level that the project is not of a size and scale that would jeopardize US corporate and energy security interests or, more important to the concerned local citizenry, create undue harm to the nearby environment.

Cameron LNG

Cameron LNG, now being constructed in Hackberry, Louisiana, is backed by a number of companies from across the globe: Sempra Energy (US), Engie, formerly known as GDF Suez, (France), Mitsubishi (Japan) and Mitsui (Japan). In fact, central to the FID taken in August 2014 was the commitment by the Japan Bank for International Cooperation (JBIC), Nippon Export and Investment Insurance (NEXI) and other foreign banks to offer $7.4 billion of financing towards

the $10 billion + project. Additionally, 20-year tolling agreements with Engie, Mitsubishi, and Mitsui – 4 MTPA each – were signed. Whether or not natural gas is needed, Cameron can bank on the tolls being paid well into the future.

Freeport LNG

Second in size to Sabine Pass, at 13.2 MTPA capacity, Freeport is an $11 billion project scheduled to have 4.4 MTPA online in 2018 and the rest of the capacity ready by 2019. Freeport is another regasification site that is being reorganized for exports, though it will retain some regasification capacity “if it is needed for the domestic market.59” All 13.2 MTPA of production capacity has been contracted under tolling agreements with Osaka Gas (Japan), Chubu Electric (Japan), BP (UK), Toshiba (Japan), and SK E&S (South Korea).

Corpus Christi LNG

Corpus Christi LNG is the only greenfield facility under construction in the US at present. Though this will be an expensive project to build ($11 billion), project owners Cheniere had already sold out their long-term contracts by 2014, making the FID decision easier.60 Furthermore, in terms of cost/ton of capacity, Cheniere plans to keep expenses down to $815. This is similar to US brownfield projects, as Table 1.2 indicates.

58 Ibid. 59 Freeport LNG. http://www.freeportlng.com/Liquefaction_Project.asp Accessed May 26, 2015. 60 Corpus Christi LNG ‘sold out’, says Cheniere’s Charif Souki”. Gastech News. July 16, 2015. http://www.gastechnews.com/lng/corpus-christi-lng-sold-out-says-chenieres-charif-souki/ Accessed May 26, 2015.

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Table 1.2: Capital Costs per Tonne of Capacity, US and Australia

Name In Service Date Cap Cost/Tonne Greenfield or

Brownfield

Typical Australian Project61 ~ $ 3,400 greenfield

Nikiski LNG62 2025 $ 2,500 greenfield

Cameron LNG 2018 $ 833 brownfield

Freeport LNG 2018 $ 833 brownfield

Corpus Christi LNG 2018 $ 815 greenfield

Cove Point LNG 2017 $ 724 brownfield

Sabine Pass LNG 2015 $ 667 brownfield

Source: CERI; Moody’s

Cheniere has locked in numerous buyers at modest volumes of LNG, to be taken for at least 20 years. For example, the Portuguese utility Energias de Portugal S.A. (EDP) has agreed to 0.77 MTPA from Corpus Christi at a purchase price indexed to the Henry Hub natural gas price. The Sales and Purchase Agreement (SPA) will be in effect for a 20-year term with an option of up to 10 more years.63 Cheniere has signed SPA’s with six other companies, mostly European, but also with Woodside Energy Trading Singapore and also Pertamina (Indonesia). Thus, the facility will be sending shipments both to Europe and to Asia.

Oceania (except Australia)

Unlike North America and Australia, there is little in the way of additional liquefaction capacity being built in the Oceania region (see Figure 1.18). Most of the capacity, in the region of 70

MTPA, is now operational. The biggest potential players in the area are Indonesia and Malaysia, but they have rapidly growing domestic demand to meet and are now getting into the business of building regasification facilities.64 Still, some of the smaller countries have become involved in the liquefaction side of the business. Papua New Guinea, for example, commissioned the PNG LNG Project in 2014, a large facility that is now shipping 6.9 MTPA to Asian Pacific markets.65 Brunei’s Lumut facility has been running smoothly since the 1970s. Both of these nations have 61 Moody’s 2015 estimate of Australian greenfield project costs. See: https://www.moodys.com/research/Moodys-Liquefied-natural-gas-projects-nixed-amid-lower-oil-prices--PR_322439 Accessed May 26, 2015. http://www.naturalgasintel.com/articles/101902-moodys-forecasts-cancellation-of-many-us-lng-export-projects 62 The Nikiski LNG project, planned for Alaska, is not approved and will probably not be constructed until at least 2025. It is included in the chart for comparison purposes as it reflects the upper end of the cost range in the US. 63 “Cheniere and EDP Sign 20-year LNG Sale and Purchase Agreement”. PR Newswire. December 18, 2014. http://www.prnewswire.com/news-releases/cheniere-and-edp-sign-20-year-lng-sale-and-purchase-agreement-300011855.html Accessed May 26, 2015. 64 Malaysia has 1.6 bcfd of regasification facilities that are either operational now or will be by 2016; Indonesia is building small receiving terminals throughout the archipelago in an effort to have small communities switch from oil to gas-fired electrical generation. 65 ”PNG LNG Marks One Year since the Start of Production.” April 29, 2015. http://pnglng.com/news/png_lng_marks_one_year_of_production Accessed June 2, 2015.

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long-term plans for more liquefaction, but these projects probably will not get underway until

the post-2020 period.

Figure 1.18: Operating and Planned Oceania (except Australia) LNG Liquefaction Projects

Source: CERI, Various company websites

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Chapter 2: LNG in Africa Nigeria, Angola, Algeria, Egypt, and Equatorial Guinea all have liquefaction projects running, with volumes approaching 60 MTPA being contributed to world supply. North African volumes have been serving the European market for a number of years; the new projects slated for East Africa would be suited to delivering gas to India, being able to sail directly to the Subcontinent without passing through any of the world’s major shipping bottlenecks. European and East Asian markets also hold potential, though the most direct routes to these regions would require passage through the Suez Canal or Malacca Strait. A number of projects are in the planning stage and nearing FID’s, including facilities that would open up rich, new fields in Mozambique and Tanzania.

Nigeria Nigeria, with the largest natural gas reserves in all of Africa at 180 Tcf,1 holds solid potential as an LNG supplier, mostly to Europe. But the same problems that plague the oil industry in that nation – corruption, banditry, and piracy – are being faced by natural gas producers. Furthermore, there is at present a shortage of infrastructure, resulting in much gas being flared rather than monetized. Despite these problems, Chevron and Shell have made final investment decisions on four natural gas production projects for the 2016-2017 timeframe. And four other projects are being planned by Shell and ExxonMobil for the post-2020 period.2 This could be a boon for the oft-delayed Brass LNG project, which has been in search of a secure source of supply,3 and it would be beneficial for the larger Olokola LNG, proposed for 2018, that will be located close to supply sources on the West Delta. Expansion of Nigeria LNG is also being proposed, but this project is not approaching an FID and would not come online for five more

years at least.

Mozambique The Mozambique LNG project at Palma Bay, which anticipates an initial four trains totaling 20 MTPA online in 2018, is causing a stir. If the project goes ahead, it will create an entirely new natural gas industry where none existed before. The proposed liquefaction plant will be constructed in the northern part of the country to access the untapped offshore Rovuma Basin, which is rich in gas, and in drilling to date has produced almost no dry wells.4 The project is backed by companies from North America, Europe, India, and East Asia including Anadarko (US), Eni (Italy), Mitsui (Japan), PTTEP (Thailand), ONGC Videsh (India), and Oil India. Plans for this project include eventual expansion totaling 50 MTPA at some point beyond 2020. This is well

1 “Nigeria Country Brief” EIA. February 2015. http://www.eia.gov/beta/international/analysis_includes/countries_long/Nigeria/nigeria.pdf Accessed June 3, 2015. 2 Ibid. 3 “Brass LNG: Looking into the Horizon”. This Day Live. January 1, 2013. http://www.thisdaylive.com/articles/brass-lng-looking-into-the-horizon/135035/ Accessed June 3, 2015. 4 Fruehauf, Anne. Mozambique’s LNG revolution: A political risk outlook for the Rovuma LNG ventures. Oxford Institute for Energy Studies. OIES Paper: NG 86. April 2014. Page 4.

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within Mozambique’s potential productive capacity, as the nation’s proved natural gas reserves

were assessed in 2014 at 100 Tcf, up from 4.5 Tcf in 2013.5 Optimism abounds. The chairman of Anadarko, Al Walker has stated “We believe, as we go into the next decade, Mozambique will emerge as the third-largest exporter of LNG in the world.”6

That being said, the FID has not yet been taken by Anadarko and Eni, the two largest players in the venture, though the decision is expected in 2015. The initial four trains will cost upwards of $16 billion, will see some 10,000 people employed, and over 3,000 local residents relocated.7 For a country with a GDP of approximately $US 15 billion,8 it will be the largest industrial project in national history. An influx of foreign workers is expected since few of the local residents are trained for the construction and operational work that the project will require. Time will tell whether Mozambique can avoid the symptoms of Resource Curse – graft, environmental degradation, social trauma, to name but three – that have beset other developing nations

attempting to build a hydrocarbon industry out of nothing.

Tanzania and Cameroon In many respects Tanzania is similar to Mozambique, with only a small natural gas industry that meets the country’s domestic needs and much work to do to build export capacity. However, the deepwater offshore has been explored in recent years by BG Group, Statoil, and ExxonMobil and in excess of 25 Tcf of recoverable gas resources have been booked.9 The Government of Tanzania has announced that it is buying up land in the south of the country in order to pave the way for a liquefaction facility to be built there. It is expected that BG Group, Statoil, Exxon Mobil, and Ophir Energy will be partners in the export terminal, with an FID expected sometime in 201610.

Africa’s first Floating LNG liquefaction facility is slated to be completed and shipping gas from Cameroon by 2018 (see Figure 2.1). The facility will produce 1.2 MTPA for an 8-year period and will be operated by the Cameroon national oil company, La Société Nationale des Hydrocarbures (SNH) and Perenco Cameroon. According to the Petroleum Economist, this facility is presently under construction.11

The French firm Engie (formerly GDF Suez) is working with SNH to develop Cameroon LNG in the south of the country. Initial plans are to build a first train of 3.5 MTPA. The partners note the

5 “Mozambique Country Brief”. EIA. July 2014. http://www.eia.gov/beta/international/analysis.cfm?iso=MOZ Accessed June 21, 2015. 6 Fruehauf Ibid. Page 1 7 Maylie, Devon and Daniel Gilbert. “Anadarko’s Controversial Mozambique Project Shows Appetite for Natural Gas.” Wall Street Journal. August 11, 2014. http://www.wsj.com/articles/anadarkos-controversial-mozambique-project-shows-appetite-for-natural-gas-1407810602 Accessed June 21, 2015. 8 http://data.worldbank.org/country/mozambique Accessed June 21, 2015. 9 “Tanzania Country Brief”. EIA. April 2014. http://www.eia.gov/beta/international/analysis.cfm?iso=TZA Accessed June 21, 2015. 10 “Tanzania to finalise land acquisition for LNG project”. Reuters. May 9, 2015. http://www.reuters.com/article/2015/05/09/tanzania-gas-idUSL1N0Y009220150509 Accessed June 21, 2015. 11 “World LNG Map: 2015 edition.” Petroleum Economist.

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project will co-produce Liquefied Petroleum Gas (LPG) and will also reduce local flaring of

associated natural gas.12 As Cameroon is on the West Coast of Africa, Cameroon LNG is ideally situated to ship to Europe without cargo passing through chokepoints, though piracy throughout the Gulf of Guinea is a growing concern.

Figure 2.1: Operating and Planned Africa LNG Liquefaction Projects

Source: CERI, Various company websites

12 http://www.gdfsuez.com/wp-content/uploads/2012/05/cameroun-uk.pdf

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Chapter 3: LNG in Europe and Asia (Russia) Russia Russia has an LNG liquefaction facility (Sakhalin 2) running in its far eastern region and proposes further facilities on the other side of the world, but still inside Russia, on the Gulf of Finland (Baltic LNG) (see Figure 3.1). In between these sites, but further north, are some projects either under construction or under consideration (Yamal LNG, Shtokman LNG, Pechora LNG) that will ship out of ports on the Arctic Ocean. Yamal will operate year-round with shipments to Asia via the Northern Sea Route in the summer in ice breaking ARC7 specially-designed tankers.1 During the winter months, the tankers will deliver to a reshipment terminal in Spain. Russia often finds itself embroiled in pipeline issues, such as its ongoing confrontation with Ukraine, but by becoming involved in LNG liquefaction projects, Russia is ensuring market access to places where

its pipelines may not go.

Japan is one such place, and the Sakhalin 2 project, commissioned in 2009, has been serving Japan and neighbouring South Korea since then. The Japanese Prime Minister at the time, Taro Aso, underscored his nation’s need for energy security by saying “It is a long-standing dream of Japan to have energy supplies so near.”2 Those energy supplies could be increased by upwards of 570 MMcfd if the Sakhalin 2 third train comes online as scheduled in 2018.

These are modest volumes considering the size of the East Asian market and its historical eagerness to obtain regional supply. In fact, the proposed Russian LNG projects that are expected to compete on the international market are the far larger Vladivostok LNG and Yamal LNG, offering 15 MTPA (2 bcfd) and 16.5 MTPA (2.2 bcfd) of production respectively. These

developments are estimated to cost a total of $45 billion, perhaps more, with financing a concern in a recession-and-sanctions-hit Russian economy. There has been recent talk that Gazprom could scrap the Vladivostok plan entirely, because of financing issues, and send gas to China via pipeline instead.3 Yamal is more promising to go ahead, as construction has been ongoing since 2013,4 though it too has financing difficulties. According to Reuters, Yamal is 40 percent backed by international energy companies (Total of France holds a 20 percent share of the project as does China’s CNPC) and its majority shareholder Novatek has strong support from the Kremlin: “While dozens of Russian energy ventures are in jeopardy due to the sanctions, the Kremlin is

1 “DSME to Build 1st ARC7 Icd-Class Tanker for Yamal”. World Maritime News. http://worldmaritimenews.com/archives/106699/dsme-to-build-1st-arc7-ice-class-tanker-for-yamal/ Accessed June 25, 2015. 2 Mosolova, Tanya and Denis Dyomkin. “RPT-UPDATE 5-Russian LNG plant extends Kremlin’s energy reach.” Reuters. February 18, 2009. http://uk.reuters.com/article/2009/02/18/sakhalin-lng-idUKLI71733420090218 Accessed June 21, 2015. 3 Indeed, Vladivostok can wait since the plan is for it to receive gas from the Power of Siberia pipeline, which, in turn will be partly filled with gas from the Kovytka field not expected to be online until 2022. “Gazprom could scrap Vladivostok LNG for pipeline”. ICIS. October 15, 2014. http://www.icis.com/resources/news/2014/10/15/9829141/gazprom-could-scrap-vladivostok-lng-for-pipeline/ Accessed June 21, 2015. 4 “International Gas Union World LNG Report – 2015 edition. Page 21.

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bent on saving Yamal no matter what. If it stays on track, it will also show the West that the

world’s largest energy industry is not cracking under sanctions.”5

It appears that despite the size and cost of Yamal, it could compete with international LNG projects looking to gain Asian market share. The Oxford Institute of Energy Studies (OIES) believe the Yamal LNG breakeven price to be in the $US 10 range,6 which is competitive with British Columbia projects that have supply costs (costs + profit margin) closer to $12, and with US Gulf Coast LNG, too, which has a much longer distance to market. It should also be noted that Sakhalin 2 expansion, though more modest in scale, can break even at under $7, making that project one of the most competitive in the world today.

Baltic LNG (10 MTPA) announced an FID in April 2015, but that does not ensure it will be built. In fact, a similar project was proposed in 2008 but abandoned because of unfavourable market

conditions.7 An argument can be made that market conditions are no better in 2015, but this project may offer geopolitical advantages. First, it would permit gas to be delivered to the Russian exclave of Kaliningrad, an important Baltic port, which now relies on gas pipelined through Lithuania or Poland. Secondly, it would offer extra supply in close proximity to European clients if such supply were needed. Finally, it could ship LNG to the South American Atlantic coast, serving markets in Brazil and Argentina.

Norway The Snohvit LNG terminal has been operational since 2007, with a capacity of 4.2 MTPA. There are no present plans for expansion.

5 “CORRECTED – Total’s CEO to visit Russia’s Yamal LNG project.” Reuters. April 8, 2015. http://www.reuters.com/article/2015/04/08/yamal-total-ceo-idUSL5N0X53PN20150408 Accessed June 21, 2015. 6 Henderson, James and Jonathan Stern. The Potential Impact on Asia Gas Markets of Russia’s Eastern Gas Strategy. The Oxford Institute for Energy Studies. Oxford Energy Comment. February 2014. Page 6. 7 “Uncertainty lingers over Baltic LNG despite FID.” Interfax. April 21, 2015. http://interfaxenergy.com/gasdaily/article/15899/uncertainty-lingers-over-baltic-lng-despite-fid Accessed June 21, 2015.

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Figure 3.1: Operating, Under Construction and Planned Europe and Asia (Russia) LNG Liquefaction Projects

Source: CERI, EIA, company websites

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Chapter 4: LNG in the Middle East The Middle East holds the most operating LNG liquefaction infrastructure anywhere in the world, 34 percent of the global total. Figure 4.1 shows that there are few immediate plans to expand, with Qatar, Yemen, and Oman standing pat with the facilities they have built to date.1 In fact, the region could see some contraction since the Yemen facilities came under the control of a rebel force in April 20152 – the plant has shut and exports have ceased, reducing regional output by 6.7 MTPA. This shutdown, declared force majeure by the plant’s operators, will persist until some stability can be found in the country’s domestic political situation, and that could be years away.

Iran Iran LNG was announced years ago but little in the way of development has occurred recently.

However, the Islamic Republic has more than doubled its gas reserves over the past thirty years, and at the beginning of 2015 held 1,201 Tcf3 of proved reserves – second only to Russia. Most Iranian gas fields (only 1/3 of the nation’s gas is associated with oil) are in close proximity to the Persian Gulf, so developing an LNG export industry is a distinct possibility. Geopolitics and a global gas glut may determine a limited role for Iran in world gas markets today, but with the recent thaw in relations between western powers and Iran, progress appears on the horizon in this 35 year-old geopolitical stalemate. A renaissance in Iranian gas could be reasonably expected within the next decade.

Israel Israel has the potential to export LNG now that the country has discovered natural gas in offshore

fields. These recent discoveries were big: the 10 Tcf Tamar field, discovered in 2009, and the 19 Tcf Leviathan field, discovered in 2010, were the world’s largest deep-water natural gas finds in those years4 and development of those fields coupled with modest domestic natural gas demand should put Israel in a position to export a good portion – the Israeli government has decided that up to 40 percent of proven reserves may be exported.5 Pipeline exports could go to Egypt, Jordan, the West Bank, Gaza, Greece, or Turkey (the latter two options would be via underwater pipelines) but each of these options is fraught with problems – not only from the Mideast region’s Arab states, but also from Greece and Turkey whose long- standing disputes still simmer. LNG

1 The UAE is making plans for expansion, but details are unavailable as of this writing. See http://www.thenational.ae/business/energy/dubai-considers-lng-import-terminal-expansion Accessed June 3, 2015. 2 Kerr, Simeon and Peter Salisbury. “UN sanctions Houthis as Yemen LNG halts production.” Financial Times. April 14, 2015. http://www.ft.com/cms/s/0/f774c16c-e26f-11e4-ba33-00144feab7de.html#axzz3dhg1v2ly Accessed June 21, 2015. 3 “Table 3. Top 10 countries with proved natural gas reserves, Jan. 2015.” EIA. http://www.eia.gov/beta/international/analysis.cfm?iso=ARE Accessed June 3, 2015. 4 Henderson, Simon. “Natural Gas Export Options for Israel and Cyprus. “Mediterranean Paper Series. The German Marshall Fund of the United States.” September 2013. Page 3. 5 Henderson, ibid. Page 3.

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exports could enable Israel to reach foreign markets with less geopolitical risk taken than if

pipelines were built.

US-based Noble energy is working with Daewoo of Korea toward building a Floating LNG plant based off Israel’s Mediterranean coast. This project could send gas from Tamar at a rate of 3.4 MTPA by 2018. Other projects are under consideration for the port at Eilat in the southernmost tip of the country (bypassing the Suez Canal), a land-based LNG plant on the Mediterranean coast, and another land-based plant in the Jordanian Red Sea port of Aqaba.6

Iraq Centre to a deadly civil and regional war over the past decade, Iraq offers little in the way of stability for LNG liquefaction projects. Presently, over half of the country’s natural gas production is flared, a total of 423 Bcfd.7 In an effort to reduce the flaring and put the gas to better use, the

state-run South Gas Company has created a joint venture with Mitsubishi and Shell. The JV will look to upgrade existing facilities and build new ones, including an LNG project in the southern city of Basra. Ongoing fighting in the country has disrupted operations at three major non-associated gas fields, so even if the Basra LNG project goes ahead and is operational within the next few years, supplying the plant with gas will probably be a difficult task.

6 Henderson, ibid. Pp 9-12. 7 “Iraq Country Brief”. EIA. January 30, 2015. http://www.eia.gov/beta/international/analysis_includes/countries_long/Iraq/iraq.pdf Accessed June 21, 2015.

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Figure 4.1: Operating, Planned and Unknown Middle East LNG Liquefaction Projects

Source: CERI, EIA

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Chapter 5: LNG in South America Most South American LNG facilities are either regasification terminals or small scale LNG (SSLNG) to serve local markets. The major liquefaction facilities are located in Trinidad and Tobago and Peru and have been running for a number of years (see Figure 5.1). Though expansion may not be in the offing for any of the currently operating facilities, the upcoming completion of the expanded Panama Canal is promising greater efficiencies for all cargoes moving to Asia, and in the case of Peru, moving to Europe. Previously, only about a dozen of the world’s smallest LNG carriers were able to negotiate the canal, but the bigger waterway will be able to accommodate 80 percent of the global LNG fleet. According to energy industry consultant Timera Energy, voyage times from Trinidad to Japan will be reduced by 30 percent.1 This is significant because the shorter distance will mean lower fuel consumption and less LNG boil off. It is also notable

that the canal will reduce voyage times between Trinidad (or the Gulf Coast) and the operational and proposed regasification units along The North American and South American Pacific coast; this could permit previously marginal LNG trading routes to become profitable.

Figure 5.1: Operating South America LNG Liquefaction Projects

Source: CERI, EIA

1 “Panama Canal upgrade impact on the LNG Market”.

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This study concentrates on LNG movements into Asia with a view to determining the place that

Canadian LNG could have in that region. That being said, the Asian market does not operate in isolation, and natural gas flows elsewhere in the world affect Asian supply and demand. With that in mind, the following chapter considers major movements of natural gas in other world regions.

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Chapter 6: Natural Gas Pipeline Movements Russia “Russia is doomed to live with the European market,” says the head of the Energy Institute at the state-run Russian Academy of Sciences.1 And the Europeans also appear resigned to take Russian gas. Despite the uneasy relationship between the sides – borne of geopolitical conflict and disagreement on the value of the commodity that flows from east to west – both Europe and Russia have recently invested in infrastructure to increase natural gas volumes. Over the past five years, the Nord Stream pipeline system came online, bringing Russian gas underneath the Baltic Sea into northern Europe at a rate of 55 Bcm per annum.2 Two more pipeline strings could be added at some future point to double the capacity again. This has rendered superfluous the long-planned South Stream pipeline, which would have carried gas from Russia beneath the Black

Sea (bypassing geopolitical chokepoint Ukraine) into Bulgaria and up into Western Europe. That

project was cancelled in December 2014.3 Now Russia has by far the most reach into European gas markets, and Europe is better connected to Russia than to any other natural gas supplier. Though there is a massive natural gas market in Asia that Russia could turn to, so far it has only built the Sakhalin 2 LNG facility to serve customers there; Russia is simply not involved anywhere else the way it is involved in Europe. Whether either party likes it or not, at least over the short- to medium-term, Europe and Russia are joined in a marriage of gas.

Alternatives to Europe for Russia Both partners have a roving eye, however. Russia has been looking to Asia and has found a friend in China. As noted earlier, after years of talks, the two nations signed agreements worth as much as $400 billion to build two pipelines to ship Russian gas to China – the Altai pipeline to transport

Central Siberian gas into Western China, and the Power of Siberia pipeline which would carry Eastern Siberian gas into China from the northeast (see Figure 6.1). These pipelines could move as much as 8.7 bcfd of gas into China, a dramatic shift to the east for Russia.

1 Mazneva, Erina and Misha Savic. “Russia Sees Bleak Outlook for Gazprom Gains in Europe”. Bloomberg Business. May 28, 2015. http://www.bloomberg.com/news/articles/2015-05-28/russia-sees-bleak-outlook-for-gazprom-sales-in-eu-on-price-drop Accessed June 1, 2015. 2 https://www.nord-stream.com/the-project/pipeline/ Accessed June 1, 2015. 3 Ostensibly the project was halted because the parties could not secure land-use licenses from Bulgaria, but the prolonged slump in natural gas prices also played a part.

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Figure 6.1: Proposed Russian Natural Gas Pipelines to China

Source: Singapore Straits Times

Alternatives to Russia for Europe Europe has been acquiring supply from North Africa. It is also now looking to the former Soviet republic – but now independent state – Azerbaijan. A new pipeline, the Trans-Anatolian, has been under construction since the spring of 2015 (see Figure 6.2), and it will bring 1.5 Bcfd out of Azerbaijan.4 But this alone does not displace much Russian gas to Europe. Turkmenistan, Azerbaijan’s neighbour across the Caspian Sea, and owner of the fourth largest gas reserves in the world, could certainly boost those volumes if it could build a pipeline across the Caspian. The legal status of the Caspian is ambiguous and the law of the sea does not apply to it. Prior to the breakup of the Soviet Union, jurisdiction was governed by a treaty between Iran and the USSR. They now argue that no pipeline can be built without approval of the littoral states – Russia, Iran, Kazakhstan, Azerbaijan and Turkmenistan. Turkmenistan to date has not challenged this legal

interpretation, unwilling to antagonize Moscow. However, now that the South Stream Gas Pipeline has been cancelled by Russia, Southern Europe perceives the need to develop

4 “Linking the Caspian to Europe: Repercussions of the Trans-Anatolian Pipeline Agreement.” Rethink Institute. November 2012. http://www.rethinkinstitute.org//wp-content/uploads/2013/09/Linking-the-Caspian-to-Europe.pdf Page 1. Accessed June 24, 2015.

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alternatives, and further infrastructure linking the Central Asian region with Europe, the Southern

Gas Corridor, is being planned.5

Figure 6.2: Southern European Pipeline Routes

Source: Rethink Institute

5 Tcherneva, Vessela et al. “Europe’s alternatives to Russian gas”. European Council on Foreign Relations. April 9, 2015. http://www.ecfr.eu/article/commentary_europes_alternatives_to_russian_gas311666 Accessed June 24, 2015.

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Chapter 7: Future Asia LNG Supply and Demand The overall LNG supply and demand picture for the Asia-Pacific region is abounding with variables. LNG demand in this report is based on the IEA’s New Policies scenario. More positive or pessimistic scenarios are possible, depending on numerous factors, including: the degree to which the global economy recovers; the extent that environmentally-sensitive energy policies are developed (such as GHG emissions reductions in China, for example); the strength of nuclear energy’s resurgence in Japan and Korea; the level of protectionism that enters the market, or the number of pipelines constructed to bring natural gas into the region. This last variable, pipelines, is one to watch simply because if planned pipelines bringing gas in from the north and west are

not constructed, potential LNG projects in East Africa, Eurasia, and the US become more apt to be built. Figure 7.1 indicates Asian natural gas imports demand, some of which is being met by existing pipelines (in excess of 2 bcfd). Though in 2015 Asian natural gas demand is sluggish, it is expected to grow over the next 15 years. Without new pipelines like the Power of Siberia and Altai, which together would bring a minimum of 6 Bcfd into China and a maximum in excess of 8 bcfd, demand for LNG would increase.

Figure 7.1: Asia-Pacific LNG Supply and Natural Gas Import Demand: 2012 to 2030

Sources: CERI, IEA, Various

Asian Natural Gas Demand

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What is feasible? Let us examine by region the liquefaction capacity being constructed as of 2015

and the most economically-likely projects to follow.

Middle East liquefaction is expected neither to grow nor to shrink as facilities throughout the region are fully operational and Qatar, at present the largest LNG producer in the world, has announced a moratorium on further liquefaction plant construction. Israel, Iraq, and Iran are all possible LNG producers at some future point but the geopolitical situations in these areas must be settled first. One question mark going forward is Yemen, which is engulfed in civil war and in April 2015 declared force majeure on its liquefaction facility. How long it takes for the facility to restart production is an open question, but this study assumes Yemeni supplies back online by 2017. Close examination of Figure 7.1 reveals that the loss of Yemeni supply does not make a material difference in volumes exported from the Middle East in 2015 and 2016.

Australia is assuming global LNG liquefaction leadership with numerous projects under construction and coming online over the next three years. Beyond that, however, most analysts do not foresee further projects being undertaken in that country. Some projects have been outright cancelled, such as Shell’s massive Arrow project, and the current supply glut must be resolved and natural gas prices must rise significantly in order to see any of these costly projects going ahead. As a result, Australian liquefaction looks to plateau in the years after the Shell Prelude drops anchor in the Browse Basin in 2017.

Other supply sources in the region are mostly from Malaysia and Indonesia. However, these countries are moving away from an LNG export model to using the natural gas for domestic purposes. As Figure 7.1 indicates, supply from these countries is set to decline over the next half dozen years.

The US is the other country besides Australia seeing significant LNG liquefaction construction activity at present. US projects benefit by being almost exclusively brownfield developments with costs much lower than the greenfield projects planned or under construction elsewhere in the world. With most liquefaction centered on the Gulf Coast, and with the Panama Canal expansion due to be complete by 2016, US LNG shippers are poised to take advantage of closer proximity to Asian markets. The US is also in position to see several proposed liquefaction projects go ahead because some of them (such as Gulf LNG and Golden Pass) are brownfield and since the country has a mature natural gas industry, most of the pipeline infrastructure is already in place to get the gas to port. Even in an area where capital costs are likely to be high and pipeline infrastructure is not in place – namely, the Nikiski project in Alaska – there is considerable public and political support for eventual LNG development.

The odds are very good that two potential LNG liquefaction projects will also be completed in Eurasia. These are Yamal LNG, a favourite of the Kremlin, and the Sakhalin 2 expansion, which appears to be economically feasible even with sustained low LNG prices. Sakhalin 2 will ship 100 percent of its gas to Asia. Some Yamal gas could go to Europe, but it is being built primarily to serve Asia.

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Finally, East Africa is an exciting future LNG producer simply because there are rich offshore

basins. Development will start from zero, however, so capital costs will be high and only companies with a high tolerance for project risk will be players. The two projects with the most potential are the two-phase Mozambique LNG at Palma Bay and Tanzania LNG. If the projects go ahead, we assume both will be brought online over a number of years, with full capacity being reached by 2026.

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Chapter 8: Conclusions This report centres on the British Columbia liquefaction projects, with the assumption that Canada’s East Coast projects will serve markets in Europe. The most probable East Coast facility to go ahead, Goldboro in Nova Scotia, already has a contract in place to provide a German utility with half of the facility’s output. India is a possibility over the long term for some of the Atlantic projects, especially the H-Energy LNG project in Nova Scotia, which is backed by the Hiranandani Group of India. But because H-Energy had not yet applied to the NEB for the necessary export approvals, this facility is not on a fast track to becoming operational.

CERI has researched the capital costs of various West Coast LNG projects, both in the US and in Canada, with the results showing that the average capital cost per tonne for West Coast projects

works out to $865. For a BC LNG liquefaction project, that $865 breaks down as shown in Figure 8.1.

Figure 8.1: BC LNG Liquefaction Supply Cost Estimate

Source: CERI

Compared to the capital costs incurred for other projects in the world, this BC generic project is cost competitive. In a February 2014 report published by the Oxford Institute for Energy Studies, author Brian Songhurst compares the cost on a tonne per annum basis for all LNG plants that came online between 1969 and 2014.1 The projects deemed “high cost” include the majority of

the Australian projects, Papua New Guinea, and Norway’s Snohvit. Sabine Pass, a US Gulf Coast

1 Songhurst, Brian. “LNG Plant Cost Escalation”. Oxford Institute for Energy Studies. February, 2014. http://www.oxfordenergy.org/wpcms/wp-content/uploads/2014/02/NG-83.pdf Accessed June 24, 2015.

61%17%

11%

8%

1% 2% Capital Costs

LNG Facility FixedOperating Expenses

LNG Facility VariableOperating Expenses

Corporate Taxes

LNG Income Taxes

Carbon Taxes

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project, falls into the “normal cost” range, as would our generic BC LNG Liquefaction plant, as

shown in Figure 8.2.

Figure 8.2: Cost of LNG Facilities, 1969-2014

Source: OIES, CERI

The total supply cost, with a 12 percent profit margin, for this generic BC facility works out to approximately $6.50/mcf. This is but one piece of the puzzle to come to a delivered supply cost

estimate with delivery to Japan. The other elements of the puzzle are shown in Table 8.1. It should be noted that these values are specific to British Columbia and should not be used as proxy data for other projects.

Table 8.1: Delivered LNG to Asian Market Supply Cost Estimate.

Northeast British Columbia Field Supply Cost $2.25/mcf

Pipeline transportation toll $1.25/mcf

Prince Rupert Liquefaction Cost $6.50/mcf

Prince Rupert Loading and Transport to market $1.20/mcf

Total Delivered Supply Cost (Japan) $11.20/mcf

Sources: CERI, PSAC, Company reports

Pricing this LNG using Asian LNG pricing, what is the oil price (Japan Crude Cocktail price) needed to make the generic BC project viable? The following formula is used in our calculations:

LNG Price ($/MMBTU) = A*(JCC) + B

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A is a constant that is indexed to oil, usually between 70 to 90 percent of the oil equivalent in

$/MMBTU. B is another constant used in this pricing formula and is usually around $.7 to $.9/MMBTU.2 Using the $11.20 total delivered supply cost to Japan as the Landed LNG price, the oil price required to make BC projects viable is approximately $70/bbl as shown in Figure 8.3.

Figure 8.3: Oil Price Required to Make British Columbia LNG Liquefaction Projects Viable

Source: CERI

This puts Canada in the running with the various other options to get natural gas to Asia, including the Russian pipelines. Figure 8.4 compares Russian gas exports with other gas supply to Asia, indicating where Western Canadian projects stand.

2 For these calculations, it is assumed that A is fixed at .1485 and B is fixed at $.8. In reality, these constants could be different values.

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Figure 8.4: BC LNG as Part of Global Gas Supply to Asia, 2013

Source: OIES, CERI3

There has been much talk about the Henry Hub-linked contracts in the United States and how they will permit gas to be sold out of Gulf Coast terminals at rock-bottom prices. This would have

been a distinct advantage for Asian buyers as recently as a year ago when oil prices were much higher than they are today.4 But now that oil prices have fallen, oil-based contracts are competitive with Henry-Hub pricing. As Figure 8.4 shows, Sabine Pass gas reaches the boat more cheaply than BC gas, but the extra shipping costs more than make up for the difference. However, the expanded Panama Canal will shorten trips from the Gulf Coast to Asia, something the Gulf Coast projects are banking on.

As of this writing, the price of Brent Crude is in the $60-$65 range, and spot LNG for July delivery to Asia is $7.60/MMBTU.5 Clearly, at these prices, few suppliers in the world can break even, and the generic West Coast Canada project featured in Figure 8.4 is not among them. That being said, spot LNG prices were 41.3 percent higher at the same time last year, and in July 2012 spot prices were over $18, which would have made profitable every project listed. The price of LNG has

3 Free on Board (FOB) refers to the price to get the product to port. Transport refers to the costs incurred in shipping from the port of origin to the destination 4 Of course, a year ago, none of the Gulf Coast terminals were operating. 5 ‘’Platts: July spot LNG prices to Asia plummet” LNG World News. https://www.lngworldnews.com/platts-july-spot-lng-prices-to-asia-plummet/ Accessed June 24, 2015.

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been variable and will in all likelihood continue to be so.6 For any of these large-scale projects,

profitability cannot and should not be gauged from quarter-to-quarter; it must be considered over the long run. And over the long run, as Figure 7.1 demonstrates, Asian natural gas demand appears almost certain to rise, providing opportunity for any cost-effective project, Canadian or not, to find its place in Asia.

For all players in the Asia market, what happens between Russia and China will determine just how much a piece of the LNG pie can be taken and by whom. If the Altai and Power of Siberia pipelines are built, approximately 7 bcfd of central Siberian gas and undeveloped gas in Eastern Siberia find a market at a price of around $10. China will then either buy spot supply for natural gas or enter into medium-term contracts to meet any natural gas demand beyond what Russia supplies. If one of the pipeline projects does not proceed, there will be greater opportunities for all LNG players.

As stated earlier in this report, the two major Canadian LNG liquefaction projects most likely to go ahead are Petronas-backed Pacific Northwest LNG and the Shell-backed LNG Canada. Petronas is as close to a fait accompli as can be imagined now that it has announced its conditional FID and has several contracts in place for its gas; in fact, the Malaysian company has been keeping up a steady drilling pace in its upstream BC natural gas assets, spending $2.5 billion on those assets in 2014.7

LNG Canada is but one portion of a Shell global gas portfolio that includes 25 percent of the world’s LNG vessels, eight LNG projects in seven countries, and three more projects under construction.8 With KOGAS, Mitsubishi, and PetroChina as partners, Shell should have no difficulty in finding Asian or other markets for the gas. Shell may be reviewing its portfolio

following the purchase of BG group in April, but it has the presence and the backing to go ahead with LNG Canada. Like Petronas, Shell is working on its upstream assets in BC and an FID is expected sometime in 2016.

A third major LNG project, Kitimat LNG, is also worth mentioning because it is being proposed by two companies, Chevron and Woodside, with expertise in LNG and a history of working together on these projects. They have a feeder pipeline proposed and have support of First Nations groups along the pipeline route and at the plant location. However, the litmus test for this project is getting Asian customers to commit. No contracts mean no shovels in the ground.

Two projects smaller in size, Douglas Channel LNG and Woodfibre LNG, also have potential because their business models require less financing, receive their gas from existing pipelines,

6 “Japan Liquefied Natural Gas Import Price.” YCharts. https://ycharts.com/indicators/japan_liquefied_natural_gas_import_price Accessed June 24, 2014. 7 Penty, Rebecca. “Canada-US LNG rivalry draws focus as Petronas delays decision.” BNN. December 5, 2014. http://www.bnn.ca/News/2014/12/5/Canada-US-LNG-rivalry-draws-focus-as-Petronas-delays-decision.aspx Accessed June 24, 2015. 8 http://lngcanada.ca/the-project/the-companies-behind-lng-canada Accessed June 24, 2015.

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and require prices in the $10 to $12 range. Either one of these, or perhaps both, can find their

niche.

Numerous issues are on the horizon for LNG exporters to Asia:

increased Russian and Central Asian pipelined gas to India and China;

potential increased Russian LNG destined for Asia;

a possible nuclear energy renaissance in Korea and Japan;

Australian gas coming online, 90 percent of which is covered under long-term supply contracts;

an expanded Panama Canal (and a potential Canal in Nicaragua), lowering shipping costs for Gulf Coast LNG; increasingly probable East African FID’s;

more willingness among Asian buyers to test the spot market; and

shifting contractual terms based on commodities other than oil, such as Henry Hub gas.

Yet, in the face of all of these variables and an atmosphere of general uncertainty, Pacific Northwest LNG is almost certain to go ahead. Will it be the first and last BC LNG project or the first of many? Either way, Canada is poised to finally join the game.