Optimization of Revenues from Trading LNG in Different...

The IMRE Journal Volume 2 (1) 2008 2008. TU Bergakademie Freiberg

http://www.wiwi.tu-freiberg.de/~urm/imre/journal/index.htm

Optimization of Revenues from Trading LNG in Different Geographical Spot Markets - A Case Study on Exporting LNG from Indonesia to Japan, or, Alternatively, the UK or the USA

Yessiva, Jan C. Bongaerts

Technische Universität Bergakademie Freiberg Correspondence: Professor Dr. Jan C. Bongaerts TU Bergakademie Freiberg Lessingstraße 45, 09596 Freiberg, Germany e-mail: [email protected] Revised: 09.05.2008 Online Publication Date: 29.05.2008

Abstract

Indonesia is one of the main exporters of Liquefied Natural Gas (LNG). Traditionally, Japan has been the main customer and the infrastructure for LNG in Indonesia was custom designed for importers in Japan. Since 2001, a new law was passed in Indonesia with the intention to increase domestic consumption of natural gas. This is due to the increase of demand for energy in the country. Moreover, the government plans to replace domestic consumption of oil with gas, in order to regain the status of net oil exporter and strengthen its position as a member of OPEC. Meanwhile, the costs of LNG infrastructure are falling rapidly and the regional LNG markets are merging into a global market. This opens up new opportunities for LNG market participants. With increasing prices of oil and gas, there is tendency to change over from traditional long-term contracts to short-term contracts and even spot markets. The paper analyses these changes in the LNG market with respect to the opportunities for Indonesian LNG exporters. A case study is developed to present some potential outcomes of alternative marketing strategies. Keywords: LNG, globalisation, pricing of oil and gas, market mechanisms for LNG

Introduction

The high oil price has encouraged an increasing use of natural gas to produce energy. Another reason for this increase relates to the fact that natural gas is considered as a cleaner energy resource compared to oil. Before 1964, pipeline systems were the main means of transporting natural gas, but with systems the gas cannot be traded over long distances. In 1964 the situation changed with the start-up of the Liquefied Natural Gas (LNG) trade between Algeria and France (Hashimoto et al. 2004). Since then, gas is traded over long distances as LNG using special cryogenic vessels. Even so, there is no global market for LNG and LNG is mainly being traded within two Basins, i.e. the Atlantic Basin and the Pacific Basin. Currently, both Basins have different pricing systems and different contractual terms, but this is changing, since LNG buyers are searching for more flexibility in their LNG contracts, e.g. by opening up possibilities to divert LNG ships and signing short-term contracts. Similarly, LNG exporters are investigating opportunities of more flexibility for the benefit of shaping their energy policies or/and better market conditions. One exporting country where this development takes place is Indonesia.

Traditionally, Indonesia exports LNG mainly to Japan, but, with the adoption of its new Oil and Gas Law No. 22/2001, the intention is to reduce these exports in order to allow more inland consumption as of 2010. Given this intention, the fact is that the infrastructure for gas storage and distribution in the country is not sufficient and its construction will take time. Hence, until this infrastructure is in place and since Indonesia plans to export only 258 million Mmbtu (Million British Thermal Units) instead of 620 million Mmbtu per year to Japan, there will be increasing amounts of so-called uncommitted LNG in the country. This LNG can be sold, in particular in spot markets. This paper explores some opportunities for doing so. It is structured as follows: Part one presents some information about the LNG trade in general with some current and future trends. Part 2 focuses on Indonesia as a Regional player in the LNG markets. Part 3 presents the case study and, in part 4, a discussion about the implications for Indonesia are discussed

The LNG markets

LNG is being traded in the Atlantic Basin and the Pacific Basin. The main exporting counties are the following:

• Pacific Basin: Australia, Brunei Darussalam, Indonesia, Malaysia, the United States, and Russia

• Atlantic Basin: Algeria, Egypt, Libya, Nigeria and Norway and Trinidad

• Middle East: Oman, Qatar and the United Arab Emirates.

The main LNG importing countries are the following:

• Pacific Basin: China, India, Japan, South Korea and Taiwan

• Atlantic Basin: Belgium, the Dominican Republic, France, Greece, Italy, Portugal, Puerto Rico, Spain, Turkey, the UK and the USA

Figure 1 shows some trends in exports of LNG by country. With the growing importance of the Middle East exporters as so-called swing producers, there is a possibility that the LNG trade becomes global, since these swing producers can balance supply and demand

Figure 1 shows some trends in exports of LNG by country.

Figure 1: LNG Exports Trend by Country. Source: Smaal, Shell Global Solutions, 2003 – Mtpa = million tonnes per annum. in both Basins by performing appropriate short-term trades. This development may have an effect upon the traditional practice of signing long-term contracts with a duration of 20 years and more in the sense that the share of LNG traded through short-term contracts will increase. The duration of short-term contracts is only one year or a few years. In spot markets, the duration is one year. Short term contracts and, in particular, the spot market trade, also grow due to reductions in the investment costs for new LNG projects. With decreasing costs for the construction of liquefaction plants, there is no need to trade the entire LNG production of planned capacity at once under long-term contracts. Producers of LNG can, therefore, declare a specific volume as non-committed. Hence, since the mid 1990s, a new LNG spot trade developed, in particular in the USA, where 70 percent of LNG imported in 2004 was mainly based on short-term trades (Jensen Associates 2007). Similar developments took place in other countries such as Spain and South Korea, which rely on spot cargoes to cover their seasonal demand during the winter peaks. Currently, LNG spot trading is estimated to amount to 15 - 30 percent of world LNG trade (International Gas Union 2006). This implies that short-term contracts are important, but, nevertheless, long-term contracts will dominate in the future as they are needed for financing LNG projects. One factor which is stimulating short term trades relates to the capacity availability of the infrastructure.

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Page 37 Exporting LNG from Indonesia to Japan Yessiva, Jan C. Bongaerts

Indeed, if no liquefaction and regasification capacity is available, there cannot be any uncommitted volumes. Since new projects are under way, such capacity is available. Similarly, currently, new LNG ships are being built without dedicated trade. Hence, they are available for seizing spot trading opportunities.

The LNG supply chain

Establishing a market for LNG implies operating of a reliable supply chain. Technically, the chains consists of four stages (excluding pipe line systems within the stages), as shown in Figure 2. Upstream refers to the exploration and production of natural gas, which is then liquefied, transported in cryonic vessels to a port of destination and regasified for distribution.

Figure 2: LNG Supply Chain. Source: Self-prepared. Liquefaction plants consist of processing trains and the economic size of one train now is about 3 to 3.5 million tons (IEA 2005). Qatar is considering building a train that could reach 7.8 million tons (Jensen, J.T. 2004). The cost of a single train plant is around US $1 billion but adding a second train in a Greenfield Facility can reduce the investment cost of this train by 20-30 percent. According to the Gas Technology Institute (GTI), the construction of a liquefaction plant that annually produces 8.2 million tons of LNG could cost $1.5 to $2.0 billion (IEA 2003). Clearly, this cost can vary because of land costs, environmental and safety regulations, labour costs, and other conditions (IEA 2005). Technological progress has helped to reduce the investment and the operational costs of a liquefaction plant. LNG ships are called cryogenic tankers. The typical size of an LNG tanker is 135,000 to 140,000 cubic meters of cargo (IEA 2005) and, currently, tanker designs up to 250,000 cubic meters are under study. The cost of building a typical size tanker is around $160-170 millions (IEA 2005).

Transportation costs are largely a function of the distance between the liquefaction plant and regasification terminal. The cost of constructing a regasification terminal depends on capacity and location. At present the largest storage tank capacity is about 200,000 cm (IEA 2005). Table 1 presents a comparison of estimated costs for setting up an LNG chain in the early 1990s and the early 2000s, including the achieved decrease per Mmbtu.

Early 1990s (US$/Mmbtu)

Early 2000s (US$/Mmbtu)

Upstream development cost

0.5 - 0.8 0.5 – 0.8

Liquefaction 1.3 – 1.4 1.0 – 1.1 Shipping (LNG tanker)

1.2 – 1.3 0.9 – 1.0

Regasification 0.5 – 0.6 0.4 – 0.5 Total 3.5 – 4.1 2.8 – 3.4

Table 1: Investment Costs for an LNG Chain in the early 1990s and the early 2000s (for a Middle East to Far East Project). Source: IEA (2005).

A global LNG market?

At the 23rd International Gas Union Conference, held in Amsterdam in 2006, the report of Working Group D3 dealing with the future of the spot market was presented. The report contained two world maps represented here as Figures 3 and 4 which illustrate the potential transition from a set of Regional markets to one global market for LNG in the future. Figure 3: Current Gas Flows. Source: Report of Programme Committee D3: 2006, page 140.

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Figure 4: Global Gas Trade in the Future. Source: Report of Programme Committee D3: 2006, Page 141.

Clearly, the difference between the two figures is striking but the factors explaining the transition to a global market must be identified. An attempt is made in this section.

(1) Increase of spot/short-term trading. This leads to more flexibility for LNG sellers who can be more responsive to changes in the market, in particular to changes in demand.

(2) In combination with (1) more flexible Supply and Purchase Agreements (SPA). Obstacles to such flexibility consist in bilateral SPA between one seller and one buyer, obligatory delivery by an LNG vessel to one specific buyer, exclusive use of a vessel only for LNG explicitly mentioned in the SPA and Take-or-pay clauses which oblige the buyer to guarantee a minimum payment level, regardless of the actual receipt of the contracted LNG volume. Clearly, these instruments were installed to enable serving particular customers for long terms of 20 to 25 years. If a seller would wish to serve a new customer, he has to invest in new capacity. If these instruments are no longer written in SPA, both sellers and buyers become more flexible.

(3) In combination with (1) contracts covering smaller volumes with increased flexibility, for example designed as Free on Board (FOB),2 which allows buyers to divert cargoes to specific markets at short notice.

(4) Setting up so-called swap arrangements covering exchanges of LNG volumes without price considerations. Swap arrangements can take place for geographical and logistical reasons. Hence, in 2000, Trinidad and Tobago had an SPA with Spain and Algeria had an SPA with the USA. In consequence, Spain resold its LNG to the USA, Algeria delivered its LNG to Spain and Trinidad and Tobago shipped its LNG to the USA. This arrangement decreased shipping costs for all parties. Swap arrangements can also be used to balance out regional differences in seasonal demand. Hence, in 2003, Japan, with its peak demand in the summer season (for cooling and air conditioning) received a certain volume of LNG from South Korea and shipped an equivalent volume of LNG to South Korea in the winter of 2004 in order to balance out the peak demand there. This arrangement allows for a better joint management of peak demands.

(5) Physical LNG arbitrage transactions between Basins. As an example, during the winter of 2000–2001, in the USA regasification terminals had spare capacity. At the time, with the existence of spot markets, the USA was very attractive for LNG sellers because of the high price for LNG. [The Henry Hub price reached US $ 10 / Mmbtu.] Given their location and their role as swing producers, this situation benefitted Middle East exporters. Hence, European buyers negotiated with their Middle East suppliers to redirect LNG cargoes, originally designated for Europe, to the USA in order to capture the economic benefit of the high USA LNG price. The LNG supplies for Europe were covered by spot purchases of UK gas at lower prices.

(6) Liberalisation of gas markets in the European Union and the USA through so-called Third Party Access. This implies that sellers (Third Parties) have access to pipelines and grid systems owned and operated by others. Clearly, TPA is a necessary condition for creating competitive markets but not necessarily a sufficient condition for globalization.

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In the case of natural gas and LNG, however, it leads to a growing importance of so-called hubs, and, indirectly, to an increase of markets traders with a potential towards globalisation. A hub can be defined as a physical transfer point where several pipelines connect to a facility that redirects properly metered gas volumes from one pipeline to another. Examples of local hubs are Henry Hub in the USA, NBP in the UK, Title Transfer Facility (TTF) in the Netherlands and the BEB hub in Germany. Trading at a hub forms spot markets and, hence, creates more flexibility.

(7) Price indexation for natural gas and LNG moving away from an oil index towards a multiple index, including oil but also natural gas itself (gas-on-gas pricing) as an instrument to keep gas prices lower that oil prices. Currently, there is no clear trend towards an oil independent gas price indexation, but the growing importance of short term contracts may contribute to this trend. In a typical long-term contract, the contracting parties agree on a base price which is continuously escalated according to the price of competing fuels, in particular, gas oil, heavy fuel oil and crude. In short-term contracts, there is no need for this escalation.

Push factors for a global LNG trade

Given the fact that the spot trade in the Atlantic Basin has been rapidly developing, the Pacific Basin still trades LNG based on long-term contracts. This situation is, however changing and, to a certain extent, one can identify push factors (under control of sellers) acting globally in the direction of global LNG trade: These push factors are the following:

Pull factors for a global LNG trade

1. Economic growth is related to higher energy consumption leading to higher demand in the future.

2. Trends towards liberalization of the energy markets, already implemented in the USA and the European Union starting in the Asia Pacific Basin. Liberalization increases competition among energy utilities and may imply a preferences for more flexible contracts, including shorter durations

3. Persistent trend to depend on energy imports, with a growing tendency in the Asia Pacific Basin, in combination with policies or energy security, implying a diversification of energy suppliers and fuels, and a reduction of oil imports from the Middle East.

4. Clean fuel policies. With environmental policies for the reduction of greenhouse gas emissions in place or under development, natural gas is expected to increasingly replace coal and petroleum.

5. Development of “downstream” gas infrastructure on the distribution side as an important factor driving future demand for gas.

Taken together, these factors may lead to a global market for LNG in the sense that they can be taken as parameters for scenario building. This, however, is not the purpose of the paper. Its intention is rather to take this development as likely and investigate to what extent a particular country, in our case, Indonesia, can benefit from it through appropriate efforts towards globalising its LNG business. This issue is dealt with in the following sections.

Indonesia as a regional LNG player in the Pacific Basin

Indonesia’s shares of consumption of energy are presented in Figure 5.

Figure 5: Use of energy in Indonesia for 2004. Source: Self-prepared based on reference Bappenas 2006. The largest share consists of oil (53 %) followed by natural gas (30 %) and coal (12 %). Total per capita energy consumption stood at 19.7 Mmbtu in 2004. In terms of natural gas, at the end of 2006, an estimated amount of 2.63 trillion cubic meters (equivalent to 87x109 Mmbtu) of proven gas reserves was reported.

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In the same year, Indonesia exported 0.62x109 Mmbtu of LNG to Japan, 0.22x109 Mmbtu to South Korea and 0.14x109 Mmbtu to Taiwan. Indonesia owns two LNG facilities at Arun and Bontang, respectively. The plants are dedicated for long-term contracts for exports to Japan, Korea, and Taiwan. The Bontang plant has a total capacity of 1.16x109 Mmbtu and the Tangguh LNG has a total capacity of 0.39x109 Mmbtu. A third plant at Tangguh is under construction at a total capital cost of US $ 5 Billion and will become operational in 2008 (BP 2007). In 2003, 58 percent of the natural gas was exported, mostly as LNG, with only a small portion exported via pipelines to Singapore. In the consecutive years, domestic consumption increased rapidly and Indonesia is in the process of changing the objectives of its energy exports policy. Already in 2006, it was moved to second position as an LNG exporter with Qatar taking first position due to the diversion of exports to meet soaring domestic needs. Iin Arifin Takhyan, Vice President of PT Pertamina’s, the state oil company, said in October 2007 that his company was to lower supplies to a Japanese buying group by 75 percent after the current contract expires in 2010 (International Herald Tribune of 10 March 2008). Since exports to Japan will change, it is important to have a look at the bilateral market for LNG between Indonesia and Japan.

The bilateral market between Indonesia and Japan

Japan has twelve LNG suppliers, which are Algeria, Australia, Brunei Darussalam, Egypt, Indonesia, Malaysia, Nigeria, Oman, Qatar, Trinidad and Tobago, the United Arab Emirates and the USA, but Indonesia is a big player. In 2006, Japan purchased 62.2 million tons of LNG from abroad, up 7.2 percent, or 4.2 million tons, from 2005, to supply 96.4 percent of its LNG needs. Indonesia was the largest supplier to Japan in 2006, exporting 13.99 million tons, followed by Australia, Malaysia, Qatar, Brunei and the United Arab Emirates, which shipped 12.16 million tons, 12.02 million tons, 7.48 million tons, 6.50 million tons, and 5.31 million tons. The typical trading instrument is a long-term contract, because Japanese buyers prefer a security of 20 or more years of LNG supplies. Trade between Indonesia and Japan started in 1977.

In Japan, LNG prices include Cost, Freight, and Insurance (CIF)2 and they were based upon the so-called Japan Crude Cocktail (JCC) index. JCC is the average CIF value of all crude and raw oils imported in Japan in a specific period (Tetsuo, M. and Tsuzuki A. 2006). The prices of Dubai crude oil and Oman crude oil are used as references for setting the spot price for oil in Japan (Tetsuo, M. and Tsuzuki A. 2006). The crude oil price was used as a reference for setting the LNG price in Japan, because light crude oil was the main competitor of gas. However, as the oil price increased, a new formula for setting the LNG price, known as the S-Curve formula, was introduced. The S-curve formula can be stated as:

With:

P (LNG): the price of LNG in US $ / Mmbtu P (Oil): the average price of imported crude oil in

US $ / Barrel A: a slope showing the linkage to crude oil B: the transportation cost in US $ / Mmbtu

This formula is used to protect sellers when the oil price crashes and protect buyers in the case of high oil prices. Before the S-Curve formula was used in Asia, the crude oil parity formula was used to determine the LNG price in the Basin. Figure 6 shows both LNG pricing curves, the crude oil parity line and the S-Curve price. Figure 6: Crude oil parity line and S-Curve price Source: Hawaii Energy Policy Forum The oil parity curve is calculated as follows:

P LNG = 17.2 x P(Oil)

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The constant 17.2 is the quotient of 100/5,8, where 5,8 is the conversion factor of 1 Mmbtu to 1 barrel of oil. The gray line in Figure 6 is the S–Curve Formula. It is calculated as follows:

1. Range 1: covering the upper range 1 of JCC (US $ 23.50 – US $ 29 per barrel of oil), with S-Curve formula:

BPCrudeBPCrudePLNG ×⎟⎠⎞

⎜⎝⎛

−−

++×=115.16

5.1685.14

2. Range 2: covering the middle range of JCC (US $16.50 – US $23.50 per barrel of oil), with the S-Curve formula:

BPCrudePLNG +×= 85.14

3. Range 3 covering the lower range of JCC (US

$ 11- US $ 16.50 per barrel of oil), with S-Curve formula:

BPCrudeBPCrudePLNG ×⎟⎠⎞

⎜⎝⎛

−−

++×=5.2329

5.2385.14

Since the LNG trade between Indonesia and Japan is based on long term contracts, the contracted LNG prices change little over time. The transportation cost, which is written as constant (B) in the S-Curve formula, is negotiable. This cost can be adjusted when oil prices change, but the increase is usually still below US $ 4.00 / Mmbtu. With this type of contract, Indonesia's exporters are obliged to deliver the contracted volumes without benefits from any price changes which might occur in the LNG spot markets. If Indonesia changes its energy policy and if exporters are interested in trading in spot markets, such benefits might become available. The important spot markets are in Europe and the USA and, hence, geographically far away. In order to explore the consequences of this geographical disadvantage, a case study was made. It is presented in the next section.

A case study on exporting LNG from Indonesia to Japan, or, alternatively, the UK or the USA

The objective of the case study is to find out if there is a possibility for Indonesian LNG to enter the spot

markets of the USA or the UK, which can be considered as a step to be a partner in a global market. To assess the possibility, gross profit from trading in those spot markets is compared with gross profit from trading LNG with Japan. The case study is described best by considering a seller X trading LNG over a one year time period. The main asset for the seller to conduct the trade is an LNG tanker. Revenue is calculated as the product of the LNG volume sold and the LNG price in the respective market. Gross profit is calculated by subtracting transportation costs, regasification costs, and the costs for buying the LNG in Indonesia from revenues. The case study assumes that, from Indonesia, the vessel can sail either to Japan or the UK or the USA to deliver the LNG. In Japan and in the UK, seller X can only sell LNG. In the USA, seller X can sell and buy LNG as a new cargo. The price of LNG in Indonesia is calculated from an S-curve formula and it is based on the Indonesia crude oil price. Transportation costs are not included. Table 2 presents the monthly LNG price in Indonesia for 1 year.

Months Indonesian Crude Oil Price

in 2006 (US$/Barrels)

LNG Price in Indonesia

(US$/Mmbtu)

January 62.26 5.70 February 61.19 5.63 March 61.72 5.66 April 68.92 6.14 May 70.01 6.21 June 67.85 6.07 July 71.95 6.34 August 72.82 6.40 September 62.49 5.72 October 55.98 5.28 November 55.90 5.28 December 60.15 5.56

Table 2: LNG Price in Indonesia. Source: Self-prepared based on Bappenas, 2006 The LNG spot prices in Japan were calculated on the basis of the S-curve formula and linked with the spot Dubai crude oil price in 2006. The spot prices in the USA were calculated on the basis of the Henry Hub spot price in 2006.

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For the calculation of the spot prices in the UK the NBP spot prices in 2006 were used. Forward prices, i.e. the price of selling LNG at ti for delivery at ti+1, were derived from the spot prices. The time period is divided as follows:

• t1 represents the time period from 1 January until 31 March

• t2 represents the second quarter from 1 April until 30 June

• t3 stands for the third quarter from 1 July until 31 September

• t4 stands for the period of time from 1 October until 31 December

Table 3: LNG Spot prices and forward prices in Japan, the UK and the USA.

The terms of the contracts can be defined a follows:

• At t1, seller X signs a contract to deliver LNG to a buyer at t2 (end of June), t3 (end of September), and t4 (end of December) based on forward prices fixed at t1.

After 3 months, at t2, the forward prices for delivery at t3 and t4 might change (in this case study, it is assumed that the prices change). Seller X can compare the revenues from signing a contract at t1 and sell LNG at fixed forward prices agreed at t1 revenues from signing contracts at both dates t1 and t2 respectively. Depending on the outcome of this comparison, the seller will either sign a contract only at t1 or sing contracts at t1 and t2.

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Figure 7 shows the potential plans for Seller X.

Figure 7: Business plan. Source: Self-prepared. The capacity of the LNG tanker for the spot trade is set at 150,000 m3 and, hence, it can enter the LNG to South Hook Terminal in the UK, Everett Terminal in the USA and to LNG terminals in Japan. It is assumed that the cost for a new vessel with a size of 150,000 m3 is US $ 320,000,000, while the daily charter rate of the vessel is around US $ 65,000. In terms of the ship charter, there are two elements of cost to consider. The first element is the capital costs of the ship, which is reflected in the daily charter rate charged to pay off the loans taken for financing the ship. The second element is the variable cost of operation of the ship, including the cost of the crew, the cost of fuel for the ship, and the provision of spares and operational support. The variable cost is around US $ 30,000 per day. The transportation cost of a chartered ship is around 0.049 US $ / Mmbtu per day and the cost for investing in a new vessel is 0.04 US $ / Mmbtu per day. The other cost to consider is the regasification cost. In the case study it is assumed that the regasification cost for one Mmbtu per day is US $ 0.0007 in either in Japan, or, the USA, or the UK. After identifying all costs, the shipping route is developed. Since there are three markets where the LNG can be sold, three fixed routes and a mixed route can be defined. The fixed routes are the following:

1. Buy LNG in Indonesia – sell (forward) only in Japan

2. Buy LNG in Indonesia – sell (forward) only in the USA

3. Buy LNG in Indonesia – sell (forward) only in the UK

The mixed route can be described as follow:

4. Buy LNG in Indonesia – fulfill contracts to sell LNG in the agreed market(s) and use the vessel during times without signed contracts to sell to other markets.

Outcomes of the case study

The details of some of the calculations are contained in Appendices 1, 2 and 3 respectively. The outcomes of these calculations show that, taken the NBP price of the UK spot market may give a higher revenue to the seller than selling to Japan. Table 4 shows the summary outcomes of the case study. The larger gross revenue which can be obtained from the UK spot market is explained by the difference in the NBP price in the UK spot market and the LNG price in Japan. It should also be taken into account that sailing time to and from the UK is much higher than traveling time to Japan. This is also the case for the sailing time to and from the USA. To the UK, it takes 41 days to sail from Indonesia and it takes only16 days to sail to Japan. The sailing time to the USA is 47 days.

Markets Fixed Route Mixed Route Japan US$

1,827,345.39 US$ 2,001,296.08

The UK US$ 41,986,149.20

US$ 36,969,585.66

The USA -US$ 22,006,908.17

-US$ 3,709,169.78

Table 4: Gross revenue from selling in spot markets in the three markets. Source: Self-prepared. Table 4 also shows that selling LNG to the USA results in a negative revenue. This is explained by the level of the Henry Hub price which, on the basis of the data used, is lower than the LNG price in Japan. Moreover, sailing time to the USA takes much more time. As explained above, the results of Table 4 also reflect the various routes available to the vessel. In opting for the mixed route, the seller can benefit form the short

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sailing time to Japan.

Sailing to the USA implies a longer traveling time and selling LNG at a relatively low price. However, this also offers an opportunity to buy at this price and sell in the LNG cargo in UK at a high price or, as shown in Appendix 3, return to Japan. In that sense, the vessel is performing an arbitrage among geographically distinct markets. This advantage is missing if the vessel sails between Indonesia and Japan all year round. In analysing these outcomes, one should, however, take into account that the case study is based upon 2006 prices.

Implications for Indonesia as a regional player in the (global) LNG market

Globalisation and opportunities to enter the globalizing LNG market

Indonesia's strategy to reduce LNG exports to Japan as a consequence of the Oil and Gas Law No. 22/2001 leads to a liquefaction capacity which is not committed under long-term contracts. The uncommitted capacity is intended to be available to domestic buyers, such as fertilizer plants, petrochemical plants, electricity generation plants, the state gas company, cement plants, the steel industry, etc. However, since the gas infrastructure in the country is still underdeveloped, gas cannot be stored for a long time. One possible way to overcome this situation is by selling the uncommitted capacity in the spot markets, in particular in the USA and the UK. This was illustrated in the case study with fixed routes and mixed routes scenarios. In order to benefit from the effects of arbitrage through entering spot markets, Indonesia needs to dispose of uncommitted LNG and spare capacities in LNG infrastructure such as liquefaction and LNG tankers. The uncommitted capacity is available when the LNG exports to Japan are reduced and domestic demand is not fully absorbing LNG volumes no longer sold to Japan. In addition, there are other, more technical conditions which need to be fulfilled. These relate to technical quality specifications for LNG gas and the compatibility of LNG tankers with loading terminals and receiving terminals. Moreover, it should be taken into account that the spot market is also characterized by seasonalities which differ in the various geographical areas of a globalising market.

In terms of quality specifications, it is known that Japan requires LNG with High Heating Value (HHV). In the UK, LNG must meet a maximum Wobbe Index in normal operation of 51.41 MJ/m3. Such technical specifications are missing in the USA. Since Indonesia traditionally exports most of its LNG to Japan, its LNG quality specification meets the Japanese requirements. If exports are diverse to the UK, an adjustment needs to be made. This implies additional investments in LNG liquefaction plants. When considering uncommitted capacity of LNG tankers, it should be taken into account that tanker sizes might fit to installations in ports of charge but may not be compatible with receiving terminals. Often, tankers are built to the terms of well-defined long-term contracts. As a result, their lifetimes are determined and limited by the duration of these contracts. In such cases, since tankers are built to the specification of receiving terminals, they cannot be used for shipping LNG to buyers making use of non-compatible terminals. Hence, exporters from Indonesia traditionally serving dedicated terminals in Japan may have to charter different LNG tankers which are suited for use in the spot trades they envisage to enter. Since the growth of the LNG spot trade is partly driven by seasonality, sellers must be keen to identify demand, in particular the peak demand, during certain time periods of the year within geographical areas of the potentially globalising LNG market. This might be seen as a risk or an opportunity, depending upon the availability of demand and it may set a boundary for reliability on the spot trade. When considering the opportunities of arbitrage across the LNG spot markets, one should not leave out the fact that Asia has by far the world's largest share regasification capacitiy. Figure 8 shows that this share amounts to 69 % with North America covering 10 % and Europe accounting for 20 %. If a closer look is taken at this situation, one should know that, within Asia Japan is the dominating country with just over 40 % of the world’s capacity (PLATTS 2008). Similarly, South Korea accounts for 12.6% of the world’s regasification capacity, and, hence, together, Japan and South Korea make up just over half of the world's total regasification capacity. However, if forecasts of new construction around the world, is taken into account, Japan and South Korea will face

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Figure 8: The World’s LNG regasification capacities in 2007. Source: Self-prepared based on CERA’s Global Regasification Capacities. more competition and their combined share of regasification capacity is expected to shrink dramati-cally from 53.5% now to just 18.1% by 2013. In the coming years, investments in regasification terminals are rising at a faster pace than the associated liquefaction. According to CERA 2007, this does not come as a surprise, since the costs of operating regasification plants represent only 10 to 15 percent of the total LNG supply chain costs. Hence, for a smooth operation of global LNG markets, regasification plants should always be in excess over liquefaction terminals. For producers, surplus regasification capacity is essential if they have an interest in moving shipments between Basins as wanted or intended. Figure 9: Estimates of the development of global liquiefaction capacity in LNG producing countries. Source: SAIC’s World LNG Trade Model (2007).

For buyers, excess regasification capacity is the prime condition to enter markets in a global procurement “game”. If all capacity is committed, no other trade than the one covered by the standing (long term) contracts is possible. Interestingly enough, with excess regasification capacities, powerful buyers may have an interest to strive for even more such excess capacity since it will be relatively cheap to acquire. In this way, they speculate on increases of the value of these assets when demand is picking up Hence, in essence, with time passing, control of regasification plants will increasingly cease to be a competitive advantage in key growth markets, such as the U.S.A. and Europe. This also means that operators of such regasification plants will meet with difficulties in finding customers with an interest in long-term supply contracts. Moreover, since the expanding number of countries considering building LNG import facilities ranges from Brazil and the Netherlands to Pakistan and New Zealand, and, in that sense also contributes indirectly to the globalisation of the LNG trade. The expansion of regasification capacity is not the only factor implying the globalization of the LNG trade. As already mentioned at the beginning of this paper, producers in the Middle East are seen as crucial given their growing so-called swing position. Figure 9 illustrates this development.

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The trend for globalization is confirmed by other developments as well. Next to increases in liquefaction capacity, shipping capacity is to increase by more than 50 % until 2010. Much of that capacity will be non-committed and, hence, it can be used for “novel” market solutions, such as using ships not only to transport LNG, but also as floating regasification and storage vessels. With alls these developments taking place at the same time, the new LNG trade will be much more market flexible than the traditional LNG trade structure which was characterized by long-term contracts between specific sellers and specific users in specific countries with fixed points of dispatch and delivery. These rigid terms were commonly believed necessary to finance the large capital requirements of LNG producers and importers, but as already explained above, the recent years have seen dramatic changes in these contracts. Many newer contracts are not dedicated to specific buyers in specific markets but to aggregator or merchant buyers who will seek to move the LNG to the market of highest value, as with most other commodities.

Indonesia’s opportunities

For Indonesia, as a regional player in this globalisation process, the situation is rather complex. The country is currently facing a serious energy crisis. This is indicated by long queues for kerosene, LPG shortages, and power supply interruptions. Moreover, the government has been supporting energy consumption with huge subsidies. Power generators and manufacturers are protesting about the shortage of gas. At the same time, the country is still the third largest exporter of LNG (and coal). It is now a net importer of oil because the consumption infrastructure in the country is designed for oil. Taken the subsidies into account, the upsurge in oil prices is worrying the government and parliament, who have had to make adjustments to the 2008 fiscal budget. Similar fears exist with respect to the 2009 budget. In that context, the government has to solve conflicting problems. One the one hand, it is tempted to reduce exports of LNG on long-term contracts, in particular to Japan and allow for more consumption within the country. In December 2006 it was decided that 25% of the production from all future gas-field discoveries should go to the domestic Indonesian market.

Clearly, this will adversely affect Indonesia’s trade balance, but this move also raises the issue of pricing gas for domestic consumers. With the restructuring of its energy policy in 2001 the government, with the support of Parliament, also started to liberalize the domestic markets for oil and gas under the supervision of new regulatory authorities. Clearly, producers of gas intended for export through liquefaction plants are not willing to sell this gas to domestic consumers for less – except that these insist on lower prices. Operators of fertilizer plants and of power have been raising fierce opposition to such price increases which must be approved by the regulator. In some cases price increases can be obtained, particularly for sales to industrial users, but these deals must also be approved by mid/downstream domestic regulator BPH Migas. Hence, domestic consumers are supposed to take into account that the days of cheap energy are over but are not all of them willing to learn this lesson fast enough. For explorers and producers, the far-from-clear domestic gas utilization policy and its resulting price risk are creating enormous uncertainty in the economics of developing known and to-be-found Indonesian gas fields. In addition, the need to develop an extensive pipeline network to transfer the gas from prospective basins to demand centres in Java, is far from complete and will add additional costs. The biggest of these pipelines would be to transfer gas from East Kalimantan – near the site of Bontang - to central Java. The tender for the pipeline has been issued, along with tenders for gas pipelines linking east and west Java. Interest has been reported from Chevron and CNOOC, as well as domestic gas distributor and pipeline operator PGN, but the economics are uncertain. The tariff is estimated at around 90cts/Mcf, and with wholesale prices in Java currently near $3/MMbtu, this represents a far less attractive option than LNG sales. Higher prices in the domestic markets would also set incentives to (foreign) investors to increase their efforts in the energy sectors. Indeed, the government is keen to reverse the decline in overseas investment in its electricity, oil and gas sectors, in order to meet domestic power and gas needs. Its intention is also to re-establish the country as a net oil exporter, and, as a result, revalidate its OPEC status. On the other hand, the government wants to benefit

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from the high prices for oil and gas – in particular LNG – in the international markets in combination with the increased flexibility and globalisation of the LNG market, as described in the paper. This has implied new agreements on long-term contracts, in particular with Japan. Indonesia and Japan have come to an agreement over the extension of liquefied natural gas (LNG) contracts due to expire in 2010 and 2011. Having been negotiating for years, both parties have settled on a price for the LNG Indonesia exports to Japan, but have also agreed that volumes will be significantly reduced. The resolution has cleared the way for US $6.5 bn worth of deals between three major Japanese companies and Indonesia's state-controlled PT Pertamina. In sum, much less LNG will be sold at much higher prices. According data from LNG Japan Corp, Indonesia sold LNG to Japan at an average of US $ 8.46 per Mmbtu in 2007, but in January of 2008, the price rose to US $ 10.56 per Mmbtu. This was the month when crude futures broke the US $ 100 a barrel mark for the first time since trading began in 1983. In terms of quantities, Indonesia will cut LNG supply to Japan by 75% to 3 million tonnes a year for the first five years after current contracts expire. The supply will be reduced to 2 million tonnes annually in the five years after that. In conclusion, managing the gas resources in Indonesia in order to create wealth seems to be a complex issue with incompatible objectives. Meeting domestic demand with domestic energy sources at prices below this obtainable in export markets sets negative incentives to investors. Reducing exports of LNG may lead to reduced oil imports and improve Indonesia’s status as an OPEC member. Reducing exports sold under long-term contracts may increase economic opportunities but not necessarily at a global level. It seems that difficult choices need to be made among such conflicting objectives.

Notes 1. FOB means the buyer lifts the LNG from the

liquefaction plant and is responsible for transporting the LNG to the receiving terminal.” (IEA 2002).

2. A CIF price means that the cost of cargo, insurance and travel/freight to a given destination are all included in the price. (IEA 2002)

References

BP (2007) “Statistical Review Full Report Workbook

2007”. Retrieved on 28.12.2007 from, www.bp.com

Jensen, J.T. (2004). The Development of a Global LNG Market Oxford Institute for Energy Studies

Jensen Associates. (2007). The Outlook for Global Trade in Liquefied Natural Gas Projections to the Year 2020. Retrieved on 14.03.2008 from, www.energy.ca.gov

Platts. (2008). Retrieved on 01.12.2007 from, www.platts.com

SAIC’s World LNG Trade Model (2007). Retrieved on 14.03.2008 from www.stanford.edu

Tetsuo M. and Tsuzuki A. (2006). Natural Gas and LNG Supply and Demand Trends in Asia Pacific and Atlantic Markets

The Global Liquefied Natural Gas Market: Status and Outlook, Report: DOE/EIA-0637, release date: December 2003

Union Gas. (2006). Retrieved from CERA. (2007). Global Regasification Inventory.

Retrieved on 25.03.2008 from, www.cera.com Hashimoto, K., Elass J. and Eller S. (2004): Liquefied

Natural Gas from Qatar: The Qatargas Project. Geopolitics of Natural Gas Study, Houston: James A. Baker III Institute for Public Policy Energy Forum and Rice University

IEA (2002) “Flexibility in Natural Gas Supply and Demand”, France: OECD/IEA.

IEA. (2005). Energy Price and Taxes, 1st Quarter 2005 – xxix. Retrieved on 26.10.2007 from, www.data.iea.org

IEA (2003). The Global Liquified Natural Gas Market: Status and Outlook. Report DOE/EIA-0637. Retrieved on 26.10.2007 from www.eia.doe.gov

International Gas Union. (2006). Report of Programme Committee D 3, Algeria. Retrieved on 14.12.2007 from, www.igu.org

International Herald Tribune. Retrieved on 10.03.2008 from, www.iht.com/


Appendix 1

Transportation cost and regasification cost calculation

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Appendix 2

Gross profit calculation for Japan at period t1 – fixed route

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Appendix 3

Gross profit calculation for Japan at Period t1 – mixed route


Appendix 3

Gross profit calculation for Japan at period t1 – mixed route

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