Reassembling Production Networks and Small-Scale LNG Demand in Southeast Asia

Reassembling Production Networks and Small-Scale LNG Demand in Southeast Asia Alexander Dodge Department of Geography Norwegian University of Science and Technology In this paper, I review literature on energy transitions in developing countries and present a geographer s argument for unpacking the role of spatiality. I go further to argue that spatial outcomes regarding energy transitions are not simply an outcome of regional disparities in income growth, but are also a result of relational processes by which production and consumption is organized and embedded across geographical locations. I find synergies with an analytical framework derived from Global Production Networks in order to identify the inter-organizational relationships between economic and non-economic actors in the energy industry. I ask how such arrangements evolve and how they influence energy transition outcomes. This paper focuses on the role of LNG in order to meet energy needs in Southeast Asia. In particular, the paper calls for a new focus on the evolving organization of LNG production networks in order to meet energy demands. The world of LNG is fundamentally shifting. Whereas LNG production was dominated by LNG operators (super-majors and national oil companies) new players, particularly in the United States have proved formidable in bringing LNG into the market from unconventional sources such as shale gas and coal bed methane. Meanwhile conventional LNG markets, particularly in East Asia, have matured, and LNG demand has slowed. New market imperatives in Southeast Asia have developed, but meeting energy demands requires new capabilities and a re-organization of inter-firm and intra-firm relationships. Policy makers and national utility firms play a significant role as they negotiate outcomes for LNG development by developing the regulatory conditions, incentives, and tenders in order to push energy transitions forward. This paper uses a Global Production Network Framework in order to identify the competitive dynamics that are driving large shifts in the LNG industry. Global Production Networks is a conceptual framework used to explain how production and consumption in the global economy is distributed. The framework seeks to explain on how firms organize their products and services through different organizational strategies such as inter-firm partnerships or inter-firm control of supplier and customers. The framework also places particular attention on non-firm actors such as nation-states, in regards to their influence on how inter-organizational relationships are organized. I seek to apply a Global Production Network Framework in order to understand the development of Small-Scale LNG in Southeast Asia and Indonesia. This paper lays the groundwork for further research into the development of inter-organizational relationships in the

Small-Scale LNG industry. In my research, I seek to identify the drivers and enablers that influence firm and non-firm organizational strategies. Energy Transitions The global energy system is shifting its center of gravity to Asia. In 2035, energy demand in ASEAN is expected to increase 80% (International Energy Agency, 2013). With a high rate of economic growth and development, questions on how to supply portions of the population who have yet to access main energy grids is a significant issue. While the region has various energy recourse endowments, a decline in oil production calls for a shift in the current energy mix. The annual average rate of growth over 2016 to 2020 in ASEAN is expected to be 5.2% (OECD, 2015). The economic growth in Southeast Asia has significant implications for energy demand in the region. However, providing electricity proves to be a large challenge in Southeast Asia. Sections of the population cannot access centralized electricity networks or local (distributed) power supply systems (DNV Clean Technology Centre, 2012). Populations in eastern Indonesia, parts of the Philippines, Vietnam and Myanmar, Laos and Cambodia lack access due to geographical challenges such as mountains, islands, forests, etc. Grid extension is therefore expensive, as is establishing local off-grid power supply systems. In addition, off-grid systems are difficult to operate, and the technical skills required may not be readily available. The rise in GDP growth and the increasing demand for energy in Southeast Asia will imply significant energy transitions. The nature of transitions in the developing countries often imply the development of affordable and available modern energy services, but at the same time an increase in carbon intensity (Bradshaw, 2010). Researchers have previously assessed energy transitions with major historical shifts, such as the shift from wood and waterpower to coal in the 19 th century, or the shift from coal to oil in the 20 th century. Such energy shifts have pointed to complementary developments and broad social changes in infrastructure, transportation, industry and urbanization. Energy Transitions in developing countries has therefore been associated with the transition from primary fuels to modern energy services. Energy Poverty is a concept used to characterize the problems of inadequate energy access in developing countries and the economic, equity, education and health concerns as a result (Bouzarovski & Petrova, 2015). Energy poverty results from low levels of electrification and other networked energy provisions and well as lack of access of adequate facilities for cooking, lighting and electric appliances. The Energy Ladder concept correlates income rise with the transition from biomass fuels, to liquid and solid fuels, to modern energy forms such as natural gas or electricity (Van Ruijve 2008 in Bradshaw, 2010). The problem with the energy ladder concepts is that it fashions a linear, stage-based path for progress. The main drivers and outcomes of this path is economic growth. However, understanding energy transitions in terms of economic growth has been notoriously deterministic, often correlating GDP growth with energy intensity and efficiency, as developing countries shift to more modern energy fuels as incomes grow.

Bridge, Bouzarovski, Bradshaw, and Eyre (2013) argues that the challenge with energy transitions, is that while they provide some clarity to temporal processes behind transitions in a given geographic unit, the conceptualization to how energy systems and economic activity are organized across space is over looked. Therefore, an understanding on the spatial dynamics of energy systems is needed. The geography of energy transitions, therefore, are related to the distribution of energy related activities across space and the underlying processes that have given rise to these patterns (Bridge et al., 2013, p. 333). Energy Systems in this sense include networked geographies of connection, dependency and control. I argue that understanding energy transitions requires an understanding of the relational processes by which energy production and consumption is organized. A Global Production Network Framework Global Production Networks, or GPN, is an analytical framework used to understand flows, places and the changing international distribution of production and consumption (Henderson, Dicken, Hess, Coe, & Yeung, 2002, p. 5). Whereas as other approaches such as value chains focus on linear processes of activities which result in the final commodity, GPN seeks to understand how flows of materials, design, knowledge, services, etc. are organized horizontally, vertically and diagonally through inter-organizational networks across geographical locations. The Global Production Network framework arguably provides a broader and more comprehensive framework than value chains. The challenge with value chains is they often overfocus on the order of relationships between firms and steps within the production chain. Often firms are then arranged in a hierarchical ordering between supply, distribution and customers. However, the setup by which firms organize their products and services either within the firm itself, or through customer-supplier relationships or partnerships, is overlooked. I argue that such a perspective is useful for understanding energy transitions. As pointed out before, energy transition literature focuses on temporal processes within given geographic units. Bridge however argues that we should instead look at the dispersion, density, and connectivity of energy networks and how they are organized distinctly within and between territories. Territoriality is a concept invoked in the geographic perspective on the organization of economic activities in energy markets. In a relational perspective, territoriality is used as a way of thinking about how energy production networks are organized geographically in order to generate and capture value. Territoriality is observed through the spatiality of relationships across geographic location, and the processes and scales by which actors exercise power. According to Coe, Dicken, and Hess (2008) networks form across a multiplicity of geographical and organizational scales, and are manifested through territorial embeddedness. The GPN framework is a relational approach, which argues that markets are organized via inter-dependent decision making processes of agents within and external to production networks. By identifying and understanding the dynamics of strategies, such a perspective can bridge the gap between economic actors and structural dynamics.

In the GPN 2.0 Framework, Coe and Yeung (2015) seek to identify several casual drivers of competitive dynamics in global production networks including cost-capability ratios, market imperatives, financial disciplines and risk environments. Identifying competitive dynamics are useful in understanding actor-specific strategies for organizing GPN. Such a framework is useful as it allows GPN research to account for the emergence and evolution of production networks. Cost-Capability Ratio Firms seek to reduce costs, but at the same time achieve greater firm-specific capabilities in order to capture and hold market share. Firms in the LNG industry will need to develop new capabilities, but at the same time, lower costs in order to capture market share in emerging markets. Market Imperative Both producers and customers will be involved in and negotiate energy transition outcomes. Energy producers will seek new revenue streams and profit, while customers will demand better and more affordable products and services. Financial Discipline Firms with high financial discipline are able fulfill financial objectives of their investors and therefore have the ability to reinvest more in finance driven growth. Risk Management Firms are subject to different risks, particularly in different territories with different regulatory regimes. These risks include Economic Risk, Product Risk and Regulatory Risk. Economic Risk is the ability to hold a position in the market and product risk is the negative views of consumers and customers, and a demand for corporate social responsibility. Regulatory risk is the political, public to private governance and changes in standards and norms. Environmental Risk is the potential of environmental hazards. These competitive dynamics act as the casual drivers for how different actors in global production networks organize their production networks. Different strategies are available to firms that determine how they engage with relationships both within their own firm, with other firms, and with institutional actors. Intrafirm coordination The firm s strategy regarding the internalization and consolidation of production and services within the lead-firms, strategic partners, and suppliers. Interfirm Control The firm s strategy for outsourcing its value activity to independent suppliers and contractors, while at the same time retaining strong control over production processes. Interfirm Partnership The firm s strategy for collaborating and jointly developing solutions between the firm and strategic partners or key suppliers in order to compete with other lead firms. Extra firm Bargaining The bargaining relationships between firms and state institutions for market access regarding regulatory and fiscal frameworks. This paper will look at the case of a Global Production Network in Liquid Natural Gas in order to explain how energy development is related to the inter-organizational relationships by which natural gas is produced, exchanged, distributed and stored. As the LNG industry evolves in light

of structural changes in the industry, new organizational forms appear where new market imperatives in developing countries emerge. In order to meet these market changes firms must redefine costs and capabilities, reallocate risk, and develop financial discipline by reassembling global production networks. The Cost of a Cleaner Fossil Fuel Energy development literature tends to prioritize the role of economic development in the shift towards greater energy affordability, access and sustainability. I argue that how energy commodities are produced, stored and exchanged play an important role in development. The affordability of energy across geographic locations plays an important role in determining access. However, the means by which cost and value are added to energy commodities are black-boxed. A question arises on how value-adding activities are organized and how energy commodities are made accessible for global trade. Not all energy fuels are created equal. Natural Gas is an energy commodity with low energy density compared to liquid and solid fuels. Natural Gas has an energy density of.0364 Megajoules per Liter (MJ/L). In comparison, diesel has an energy density of 35.8 MJ/L and coal ranges between 26 to 49 MJ/L (Alternative Fuels Data Center, 2013). Natural Gas is mainly composed of methane, a lighter hydrocarbon than those found in diesel or coal. Natural Gas has lower levels of Sulfur and Nitrogen emissions, and therefore is a cleaner burning fuel than coal or diesel. However, as a gas at stable temperatures it is harder and more expensive to handle then diesel or coal. Natural Gas is nevertheless abundant; the EIA estimated that in 2015 there are 6793 Trillion Cubic Feet of proved reserves in the world. Production prices for natural gas are low, however it is the physicality of natural gas, and the feats of engineering required to rework natural gas into an exchangeable commodity, which defines its distribution in the space economy. Gas can be transported through transmission pipelines that links gas suppliers to demand centers and distribution networks. However, there are often significant geographical challenges to building pipelines, in addition to environmental and political barriers such as terms of access and right of way. Transporting small volumes to smaller and marginal gas markets make long distance pipeline transmission usually un-economical. As Bridge argues Natural gas is an uncooperative commodity: It may have use-value and be in plentiful supply, but producing exchange value requires the labors, of science, capital and law (Bridge, 2004, p. 364). By cryogenically cooling natural gas into a liquid at -162C, it can be transported via seaways on carriers or on land by road or railways. The liquefaction processes reduces density to 1/600 th of its original size. The process provides a liquid fuel with an energy density (22.2 MJ/L) that is competitive with other liquid fuels. However, while liquefying natural gas increases its exchange value, the infrastructure required for liquefaction, transport and receiving natural gas requires large capital expenditures. In order to reduce costs of Liquid Natural Gas (LNG) per unit, the LNG industry has trended over the last decades towards both increasing the size of

liquefaction facilities, and delivering LNG in larger quantities. Liquefaction Plant sizes have generally grown in size over the past decades as shown in the chart below. Figure 1 - Liquefaction Train Size Growth (Songhurst, 2014, p. 5) Today liquid natural gas (LNG) is usually received in large quantities and through longterm contracts. The conventional large-scale LNG system therefore relies on economies of scale and the promise of long-term returns, despite substantial infrastructure costs. LNG producers and customers have traditionally been tightly controlled, with back-to-back, take-or-pay contracts between producers, suppliers and customers. Take-or-pay contracts bind the customer to take and pay for a product or risk paying a penalty. These contracts provided security for producers who would invest in liquefaction facilities. Such take-or-pay arrangements however meant that generally producers made agreements primarily with large utility off-takers. By managing economic risk through long-term contracts, LNG plant owners and operators were able to develop financial discipline by ensuring long-term offtake of production. LNG production plant operators and owners were thus able to demonstrate financial discipline and mitigate economic risk by demonstrating tight inter-firm control. Typically, these operators and owners included a few number of super majors such as Exxon Mobile, Shell, ConocoPhillips, BP, etc. sometimes in cooperation with National Oil Companies such as Qatar Petroleum, Gazprom, Nigeria National Petroleum Company, etc. These companies often externalized activities to FEED and EPC contractors or shipyards for floating LNG plants. However in 2014, LNG trade reached historic highs of 241 MT (Mega Tons) (International Gas Union, 2015b). LNG trade has grown 3.4 MT in 2012-2014. 19 countries exported LNG, up from 17 in 2012. LNG production is likely to grow as well, with over 750 MTPA in proposed liquefaction capacity in new LNG frontiers. The rise of unconventional methods for natural gas extraction has led to the rise of new LNG plant producers, particularly from the United States and Australia. 58.2 MPTA of LNG Production will be online in Australia

and 9 MPTA in the United States. Meanwhile LNG demand is lowering, particularly in East Asia. LNG demand, particularly among conventional buyers, has been slowing down. Japan, the largest LNG importer with 88.9 MPTA (next largest is South Korea at 38 MPTA), is starting to restart its nuclear reactors after the Fukushima disaster in 2011. South Korea is also building new nuclear reactors and is expecting to lower the demand for LNG. The economic turmoil in China, in addition to the shift to less energy intensive industries, has slowed down the demand for LNG in china. The result of the large increase in LNG production combined with the slowing of LNG demand has created a gap that has lowered LNG prices significantly. With an oversupply of LNG, new players have come onto the market in order to find new homes for LNG. However, since large off-takers are reducing their demand, there is a need to enter new, smaller markets. The conventional large-scale LNG system benefited from economies of scale, despite substantial infrastructure costs. Therefore, delivering to small markets faces a huge hurdle, as developing a production network to access remote areas will be relatively expensive unless there is a high user demand. Changes in the LNG industry also show a shift in power from LNG producers to buyers. Whereas producers previously maintained tight control over the value chain. Often buyers would sign destination clauses in LNG contracts that restricted the trade of fuel. However, buyers like Tokyo Electric Power Co. and Chubu Electric power have refused to sign destination clauses. In addition, the ratio of long-term contracts compared to short term contracts are falling. Contract lengths have fallen 8.5% in the last few years (Poten and Partners, 2016). The result is a growth in portfolio suppliers and aggregators who purchase LNG on long-term contracts and sell LNG to the spot market (contracts below 5 years). Spot market prices have dropped, allowing more room for flexible contracts. LNG producers nevertheless continue to sign long-term contracts with large utility off takers. However, as the amount of LNG on the spot market grows and new players come into the market, and buyers will begin to require more flexible solutions. Increasing demand will require new capabilities and a different organization regarding the exchange and distribution of LNG. New Capabilities Three-quarters of the primary energy mix in Southeast Asia consists of fossil fuels. Oil remains the dominant fuel at 37% of the primary energy mix in 201l. Natural gas comes in second at 21% of the primary energy mix. Renewable energies represent 12% of the primary energy mix. Although Southeast Asia is facing a decline in oil production, it also has significant gas reserves. Countries like Thailand and Malaysia, for example, use gas for 60% of the power generation (Shirdhar, 2009). Southeast Asia has 7.5 trillion cubic meters of proven gas reserves, the majority of which are in Indonesia and Malaysia. Total gas production in the region is expected to grow by 30%, from 203 billion cubic meters (bcm) in 2011 to 260 bcm in in 2035 (International Energy Agency, 2013). As energy demand in domestic markets grow, there is a new market imperative to increase the domestic consumption of natural gas. As explained before

however, geographical challenges and dispersed populations, make it difficult for distributing natural gas through conventional supply chains. Small-Scale LNG (SSLNG) supply chains are a means of delivering LNG to end users (power plants, fertilizer producers, industry, transport, etc.) in areas that cannot be reached through conventional natural gas production networks. SSLNG however, would not replace conventional value chains, but in most cases would offtake LNG from large import terminals in conventional production networks. The exception, however, is the development of small liquefaction plants that would extract natural gas from stranded gas reserves, such as coal bed methane. SSLNG plants can be located closer to markets then conventional large-scale plants and therefore reduce transport time and costs. The International Gas Union (2015) defines SSLNG as liquefaction and regasification facilities at a capacity of less than 1 MTPA. SSLNG carriers are defined as having a storage capacity of 30,000 cubic meters or less. Although the technology and solutions are readily available, the market is slow to develop due to the expense of establishing small-scale LNG facilities, mainly due to the lack of scale. There also is a need to coordinate actors across the production network in order to ensure a stable supply and end user value. However coordinating actors remains a challenge when the demand for SSLNG is not yet prevalent. Such actors would include LNG producers, Ship Owners, Terminal Owners/Operators, End Users (Industry, Maritime, Power companies), etc. The following graph is an example of a Small-Scale LNG value chain. Figure 2 Potential Configuration of a Small Scale LNG value Chain. Infrastructure projects for SSLNG are often simpler and require less capital expenditures than conventional LNG plants (International Gas Union, 2015a). Modular designs for SSLNG plants can reduce capital expenditures and provide flexibility through off-site fabrication. There is less of a need for specialized equipment, and the time between project concept and turnkey plant delivery is short. However, on $/tonne per annum basis, the expenses for SSLNG is higher than large-scale LNG business.

In order for SSLNG to be less costly, then several challenges along the supply chain need to be solved such as standardization, unmanned facilities (in order to reduce operating expenditures), boil off gas solutions, storage tank and containments solutions, etc. SSLNG therefore is an example of optimizing cost-capability ratios. A number of firms have entered the market offering solutions for small-scale distribution challenges. These firms prove to be an important link between a changing LNG industry and developing demand in Southeast Asia. These firms, however, have chosen different inter-organizational strategies in order to enter the market. Small-scale LNG is a niche and young market in Southeast Asia, with few projects online; these markets have proved to be highly competitive. Firms in this market have arguably chosen different organizational strategies, mostly related to their size and their product portfolios. On one side, there are firms that have chosen to develop their capabilities in order to offer a broad range of solutions that span across the entire value chain. Other firms, however, have chosen to specialize and optimize a specific solution, and engage in partnerships with other firms across the value chain. Firms that choose the intrafirm control find themselves Risk Management Risk arguable plays an important role in determining how production networks are organized. Generally, firms choose different inter-organizational strategies in order to allocate risk or reduce risk uncertainty. Inter-firm control reduced uncertainty for LNG producers by allocating risk to the buyers through take-or-pay clauses in long-term contracts. Developing Small-Scale LNG in emerging countries inherently faces uncertainty and entails risk. Uncertainty differs from risk, in the sense that risk may be calculated, but uncertainty refers to unknown and random outcomes that are not predictable. A main challenge for small-scale LNG will be the nature of long-term contracts for infrastructure such as LNG carriers or receiving terminals. The challenge is that in order to develop demand for small-scale LNG, small-scale LNG will need to compete in markets usually dominated by other energy fuels such as diesel or coal. Diesel is more expensive than LNG (although less so after the oil crisis), but requires less infrastructure. Coal plants are expensive and polluting, but again require less distribution infrastructure and coal is the cheapest fossil fuel. However, coal faces a degree of product risk, as negative views over emissions and pollutants from coal-fired power plants have lead to local opposition. Landowners may refuse land for planned construction sites. A project led by Bhimasena power, with support from the Indonesian government, was stalled as 50 landowners refused to sell 40 hectares to the project (The Japan Times, 2013). Small-Scale LNG generally faces lower product risk, particularly offshore or near-shore facilities that do not require land rights. With floating solutions, LNG does not require exclusions zones and is less likely to have challenges with local land owners over land-rights. Small-Scale LNG nevertheless represents a development in new capabilities in the LNG industry and a reorganization of power relationships in production networks. The question becomes what is the new market imperative for small-scale LNG in emerging markets. Building onshore receiving terminals for LNG would require bringing in expertise and manpower and would require land space. However, several firms have been offering near-shore solutions such as

small floating regasification and storage units (FSRU) or even barges with regasification and storage capabilities. Such solutions prove more flexible, but have other challenges such as operating in rough waters and other environmental risks. New Market Imperatives in Indonesia With a population of 250 Million, Indonesia is the largest country in Southeast Asia and the fourth largest country in the world. However, 1/5 th of the population does not have access to electricity (as of 2014). Energy use per capita is low at 0.8 TOE/cap in 2013. In comparison, Singapore has energy use per capita of 6.4 TOE (DEN National Energy Council). Indonesia is an archipelago nation with over 17,000 islands. The lack of infrastructure and capability to build transmission grids across these islands present formidable geographical challenges to providing universal electrification. There are large regional disparities in electrification rates in Indonesia. Jakarta has the highest electrification rates of 95.39% as of 2013 (PLN, 2013). Jakarta is located on the central island of Java, which has an electrification rate of 82.88%. However, the region of Papua only has an electrification rate of 36.1%, and east Nusa Tenggara has an electrification rate of 48.3%. A large challenge for Indonesia will be to bridge the gap between central and peripheral regions, particularly when revenue streams are also disperse. Gross Domestic Regional Product is 58,87% in The Bali/Java Region and 23.77% in Sumatera. However, gross domestic regional product is only 1.8% in Papua, 4.74% in Sulawesi, and.27% in Maluku. PLN, the state-owned utilities company, shows that Jakarta represents energy sales of 37 trillion idr, and the island of Java accounts for 74% of total sales in Indonesia for PLN (PLN, 2013). Papua only accounts for 876 billion idr in sales, and Maluku only 570 billion idr in sales. The rates of energy consumption and energy sales will provide a large challenge for the country to reach universal electrification. Many of the eastern regions rely on diesel for electrification. The average generation cost per kwh for diesel is high at 3,286 idr per kw, compared to coal at 719 rp/kw. Combined cycle gas fired plants are more expensive than coal-fired steam power plants at 1,159 Rp/kwh. Outside of Java, oil fuels account for 62% of energy production. In Java, coal accounts for 60% of power production, and 35% is accounted for by natural gas, while oil fuels account only for 3%. Presently, Natural Gas outside of Java is only used for power generation in Sumatera/Riau, South Kalimantan, and Sulawesi (ibid.). Indonesia has considerable economic growth, and energy demand is expected to increase substantially. Electricity demand is expected to increase from 219 Twh to 464 Twh (National Energy Council DEN). The government will need to put in place measures to ensure that installed capacity can meet demand without running into shortages or black outs. The Indonesian Government led by President Widodo has planned to increase its installed capacity for power generation from 52 GW in 2013 to 115 GW to 2025, and energy consumption per capita to 1.4 TOE/cap in 2025. These plans represent an ambitious strategy by the Indonesian government to achieve universal electrification.

The need for energy and the plans by the Indonesian government arguably creates the market imperative for the domestic consumption of LNG. 15 GW should be generated through Natural Gas according to the energy master plan in Indonesia. Given the nature of Indonesia s archipelago islands, the government will play a large role in creating demand by investing and tendering infrastructure projects for small-scale LNG. However, the main challenge will justify the use of LNG compared to other energy fuels. There are clear barriers to achieving electrification in Indonesia, including removing fuel subsidies that eat up infrastructure budget, in addition to balancing energy cost differentials between the west and east sides of the country. The reason why cutting fuel subsidies helps natural gas is that they interfere with market mechanisms and divert government recourses from investing in infrastructure (Seah, 2014). Fuel subsides benefit mostly wealthier urban citizens who enjoy a high rate of energy usage and already have access to electricity. However, for portions of the population whom do not have access, which is a potential market for SSLNG, fuel subsidies are of little help. Since natural gas enjoys fewer subsidies compared to oil products, then the cut in fuel subsidies helps the business case for natural gas. Another main challenge is Indonesia s reliance on fuel oils for power generation and transport. While these fuel oils represent 38% of energy consumption, they represent 50% of energy costs. Fuel subsidies cost the government 7% to 27% of public expenditures between 2005 and 2015. In 2014, the government spent 20 billion on fuel subsidies. In 2008, the government increased the prices 30%, which had then prompted a series of riots, although the government tried to ease the impact through handouts. Removing subsidies therefore has faced major political opposition. However, in 2015, due to the fall in oil prices, President Widodo reduced the subsidies on diesel fuels without facing major political backlash. However, it will challenging for the government to maintain the cuts in subsidies if oil prices increase. Therefore, the government has an imperative to increase energy efficiency and switch to other, more affordable fuels, such as natural gas (Seah, 2014) Indonesia has large reserves of natural gas, 103.4 trillion cubic feet in 2014 (EIA). Indonesia has traditionally been and is one of the oldest gas exporters, with the largest exports shipped to Japan. The first liquefaction plant was built in Botang in 1977 and in Arun in 1978 (International Gas Union, 2015b). Until 2012, Indonesia exported more natural gas than it consumed and in 2016, 53% of gas production was allocated for domestic consumption, with 47% or export. Indonesia procured its first receiving terminal (floating) in Nusantara in 2012. Project gas demand in 2025 is expected to be 1649 MBOEPD, a 252% growth from 654 MBOEPD in 2013. A large challenge will be to increase national gas production in order to meet growing domestic demand and export obligations. Although the government has intentions to increase the amount of gas allocated for domestic consumption. However, this will be challenging, particularly for regional economic development. In 2014 the Arun liquification terminal in North Aceh on Sumatera ceased exports and was converted to a receiving terminal in 2015. The Gross Regional Domestic Product for North Aceh declined from IDR 7.86 Trillion in 2006 to 4.32 trillion in 2012 mainly due to fall in LNG exports from Arun. One of the main challenges, particularly for LNG producing regions, is to shift their economies from hydrocarbon-based exports, to manufacturing or services.

The reduction in exports is not only a challenge for North Aceh, but generally in Indonesia as it switches from a resource and agriculture based economy, to a manufacturing based economy. However, these changes require a reliable, affordable and accessible flow of energy fuels. Indonesia has large reserves of natural gas, and as LNG prices drop and the government loses revenue from LNG exports, then increasing the domestic use of gas becomes a market imperative that needs to be created by the government. Further Research: Small-Scale LNG Distribution in Indonesia Indonesia is a country that is experiencing economic growth, but faces large economic disparities between western and eastern parts of the country. While Sumatera and Java is connected to energy infrastructure through gas pipelines and coal-fired power generation, the eastern part of the country relies on diesel power generation that is often expensive and highly polluting. Nevertheless, Indonesia has several LNG production plants, and as LNG prices on export markets are low, and imperative to increase LNG for domestic project. The case in Indonesia arguably shows a market imperative, where both customers (national energy companies) and suppliers in small-scale LNG seek to create a market for small-scale LNG. In goal of my research is to understand the different strategies firms use to organize their product within LNG production networks. As outlined before I argue that firms may choose different strategies such as intrafirm coordination, interfirm control, interfirm partnerships and extra-firm bargaining. While the conventional LNG industry developed a degree of interfirm control by tightly organizing their value chains, I argue that the small-scale LNG industry will need to develop new organizational strategies in order to provide buyers with cost-effective and flexible solution. In my further research, I plan to interview several firms interested in the Indonesian market in order to understand their strategies and barriers towards developing new organizational arrangements, particularly in a high uncertainty and economic risk enviroment within developing small-scale LNG. In addition, I will focus on the role of the Indonesian government and national energy companies in regards to developing the initial regulatory framework and enabling conditions in order to develop a small-scale LNG industry. I will ask what the bargaining processes are between international suppliers and national energy firms, and how they plan to organize tender processes and initial conditions in order to acquire the financing and infrastructure necessary to build up small-scale LNG in Indonesia.

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