i 4a69 Departmental Papers Series, No. 10 SOUTH ASIA GAS TRADE by Jaap Aithuis Pulligarnai Venugopal Anil Malhotra Hossein Razavi Asia Technical Department April 1995 World Bank LE £.S...diioduj SutZuLe2jo S ..................... .................................1 U0¢ U JO S3UOUIMj3 S ............................................................s.. x. duq slp ui s2nssi syoadwi u 6aueul pue BuiziueBio O... £su Iw=N SuuzodUl jo sJoJ . aSpJ)s 6Z . siod jo isOc gL ......................................................... uo-n- se.Dj Jo ° S seg lenBlN 5upjodwi 9z................................ ......... -- - - - ure SP F 8N Er............................. iguio .ioj PULuU1(J zz=- ......................................... 6ana IMeMunumoO ioi pueuuaau iz................................. .............. 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Because natural gas as a fuel has properties which are advantageous in terms of efficiency and environmental impact compared to such other fuels as oil and coal, the Governments of India and Pakism have explored the possibilities to import natual gas in addition to their domestic gas production. Various Memoranda of UTnderstanding have been signed recendy between thc Govenments of India and Pakistan and several pnvate sector consortia on the development of ambitious LNG or gas peline import schemes, based upon the gas reserves in the Middle East. Countries like Qatar, Iran, Oman, the UAE and Yemen have substantial reserves of natual gas and are in principle candidates to supply India and/or Pakistan. Bangladesh is a potential gas supplier for India Several feasibility studies for gas import projects have been completed or are underway, all of them based on a specific set of as ptions that makes mutu comparsons difficult. The need was felt to have a broad overview of possible gas tade projects, based on a consistent set of assumptions, and of other issues relevant for successful implementation of such projects The paper is meant to provide an overall understanding of gas trade issues for India, Pakistan and Bangladesh. The views and interraions set forth in the paper are those of the authors. However, it is hoped that dissemng this information among the Bank staff advising borrower governmens on gas trade issues will lead them to bring this analysis and recommendations to the attention of Asian decision makers, and thus to bolster the effectiveness of the Bank's opertions in the region. Harold W. Messenger Director Asia Technical Department , x ACKNOWLEDGEMENTS This report was prepared jointly by staff in the Asia Technical Department and the Oil and Gas Division of the Industry and Energy Department. The Country Departments provided yeoman cooperation in the analysis and their contributions are greatfully acknowledged. The authors are grateful to the staff members of Asia Region, IFC and CVP who were gracious enough to comment on the earlier draft ABBREVIATIONS AND ACRONYMS mmcfd million cubic feet per day bcf billion (=1000 million) cubic feet tcf trillion (=1000 billion) cubic feet LNG Liquefied Natural Gas LPG Liquefied Petroleum Gas kWh kilowatt hours TWh terawatt (=billion kilowatt) hours MW megawatt nutoe million tonnes of oil equivalent mI.ce million tonnes of coal equivalent Btu British thermal unit imBtu million British thermal units bcm billion cubic meters GDP Gross Domestic Product CIF Costs, Insurance and Freight (included) ESMAP Energy Sector Management Assistance Program p.a. per annum Executive Summary Gas Trade in South Asia The world recognizes natural gas as a premium fuel, both for environmental and economic reasons. In Bangladesh, natural gas is in abundance (estimated reserves of 12 tcf) and is almost ffie only domestic fuel, supplying 74 percent of the demand for conmercial energy. While it has potential for gas exports, the extent would depend on the new discoveries to be made. India has substantial gas reserves (26 tcf) but has been importing petroleum and petroleum products in ever rising quantities as the demand/supply gap for commercial energy keeps widening. Pakistan's gas reserves are estimated at 23 tcf, but its oil and coal reserves are limited and the hydropower resources are difficuk to develop. Pakistan too has been importing petroleum and petroleum in rising volumes as the demand for commercial energy has been running ahead of a slower paced but growing domestic supply including new gas. A number of studies' have been carried out to analyze the issues involved in meetng the growing gap between commercial energy supply and demand in the subcontinent. The objective of this note is to review the existing data, develop a framework for the analysis of the various options and to recommend a course of action for the future. Based on commercial energy demand projections for India, it is expeted that the total commercial energy demand would be about 375 miMlion tonnes of oil equivalent (mmtoe) by the year 2003 from the 1994 level of 246 mmtoe, an increase of 52 percent.2 Based on the present plans of the domestic agencies, the domestic supply of commercial energy is projected to grow at an average of 4.2 percent p.a., leaving a sizable energy deficit of nearly 70 mmtoe - against today prices valued at about US$7.0 billion - in 2003, as shown in the table below: 1Two studies, one an ESMAP assessment of Pakistan's natural gas potential with a rcommended strategy for import of gas, and the other a review of the ndian natural gas market undertaken by consultants contain a wealth of data which is drawn on for this paper. A report under prepaation in ASTDR titled Engy Pespectives aned Power investments in the Next Ten Years" is also relied on for additional data, as well as petroleum intelligence reports. 2These projections are based on a GDP growth rate of 5 percent p.a. during this period. Energy demand and supply In India 1999-2003 Total Domestic supply Total Dcmandf merg~y Coal Oil Hydro Nanural Cow mergy suPPly demand supply gap Year mntoe mmce* mmtoe mmtoe TWH mmioe'* bef mnuoe mmtoe numoe 1993 246 191 134 30 102 36 517 13 214 32 1999 318 253 177 41 98 34 955 24 276 42 2000 332 266 186 40 102 36 955 24 285 47 2001 346 276 193 38 106 37 955 24 292 54 2002 365 287 201 36 110 38 955 24 299 66 2003 374 299 209 33 113 39 955 24 305 69 nuntce:=0.7 mmtoe * Esfinmae based on a 25 percent efficiency of equivalent oil fired plant. A similar evaluation in Pakistan leads to a projection of total comrial energy demand of 61 mmtoe in 2003 from the 1994 level of 34 mmtoe. For Pakistan fte GDP growth rate is estimated at 6.5 percent, an energy elasticity of 1.03 and a population growth rate of 3.1 percent p.a. during the next decade. Paldstan will, in the year 2003, need to import a 24 mmtoe at a cost of US$2.4 billion when today energy prices are taken into account. Energy demand and supply in PakLstan 1999-2003 Tota Domestic supply Total Demand enerCgy coal Oil Hydro iNaul Gas suprpy suppy demandsupy a Year umtoe "mce mm!oe mmoe TWH mmtoe* bc4 * mmtoe vmtoe mntoe 1993 34.0 4.0 1.9 3.1 20.3 5.1 560 13.1 23.2 10.8 1999 47.0 5.1 2.4 3.2 29.5 7.4 898 21.0 34.0 13.0 2000 50.2 5.3 2.5 3.2 31.5 7.9 954 22.3 35.9 14.3 2001 53.6 5.5 2.6 3.2 33.5 8.4 968 22.6 36.8 16.8 2002 57.1 5.7 2.7 3.2 33.5 8.4 979 22.6 36.9 20.2 2003 61.0 5.9 2.8 3.2 33.5 8.4 993 22.6 37.0 24.0 * Estimate based on a 36 pcnt effciency of equivakt oil fired planL 943-977 B/cf Thus, there will be a need for energy imports to Pakistan and India together of 61.3 mmtoe in 2000 which will rise to 93.0 xmntoe by the year 2003, imports which 2 will impose a considerable burden on the two economies. The annual energy import bill of the two countries will rise from the present US$4.5 billion to US$9.3 billion in 2003. The composition of energy imports - oil, natual gas, or coal - will clearly depend on the price of supply of the various fuels, the demand pattem, the technology and the geographical location of the demand in the two countries. At present, the energy deficits in the two countries are being met almost entirely through import of crude oil or petroleum products. Based on a comparison of fuel costs at the plant gate, a netback value analysis for both countries reveals that natural gas, whether landed as pipelined gas or as LNG and subsequently regassified, can compete with kerosene and LPG in the domestic and commercial sector, with naphtha in existing ferilizer production, with fuel oil or diesel in combined cycle power generation and with coal in non-pithead base-load power production as long as the landed price for the natural gas does not exceed a US$3.5/mmBtu level; at that price it will not compete with heavy fuel oil or coal in industrial heat and steam raising, with naphtha in new greenfield fertilizer production or with coal-based pithead power production. It seems therefore that natural gas can play an important role in meeting the commercial energy deficits in the two countries. A market analysis carimed out sector-wise by consultants has estimated the total demand for gas at 4,000 mmcfd in 2000 and 6,400 mmcfd in 2003 in India. Taking into account the projected domestic gas production, the demand for imported gas is estmated at about 1,450 mmcfd in 2000 which rises to about 3,800 mmcfd in 20033. Beyond 2004 there will be need for even greater imports of gas as the domestic production declines. In the case of Paldstan, it is estimated that demand for gas will be 3,000 mmcfd by the end of the decade and will rise to 3,650 mnmcfd by 2003. Since indigenous supply (allowing for expected new discoveries) is expected to grow from 2,650 muncfd in 2000 to 2,950 mmcfd in 2003, the inference is that the demand for imported gas will be about 350 mmcfd in 2000, but would rise to over 700 mmcfd in 2003. Barring any major new oil or gas discoveries in the inteimn period, demand for imported gas is expected to keep inreasing threnafter. Thus, at a minimum the need for import of gas to the subcontinent may be estimated at about 1,800 mmcfd in 2000 but which will rises rapidly to 4,500 mmcfd in 2003. Six countries, namely Iran, Oman, Qatar, Turkmenistan, U.A.E. and Yemen have exportable gas reserves. Ian, with reserves of 730 tcf, has entered into agreements for feasibility studies for onshore pipelines to India and Pakistan, as also to Europe. But its gas fields, while containing vast reserves, are far from being developed. Given the political climate and financing constraints to develop the gas fields, no immediate development of the gas fields in Iran, Turkmenistan (reserves of 80 tcf) and Yemen (unassessed) can be foreseen. Oman, with reserves in the range of 20 tcf, has studied transporting gas to India by both a shallow offshore pipeline along the Iran and Palistan coasts and by a 3,000 meter deep sea line. Simultaneously, it has also been actively promoting a project for export of LNG by a consortium of the Oman Liquid Natual Gas company, Shell, Total, Partex of Portugal and a number of Japanese companies. But it 3 The deficit of 3,800 mmcfd in 2003 is split at 1.000 mmcfd in die southem region and the balance in tbe north and the we. 3 appears that there may not be enough gas reserves to sustain both the pipeline and the LNG projects. U.A.E. is a waditional exporter of LNG to the far east, particularly Japan, and could export an additional 2 million tons of LNG since it is planning on extending the Das Island LNG facility from the current 4.8 million tons. Qatar has 160 tcf of gas reserves and has four LNG projects for selling 26 million tons of LNG in different stages of evolution. Qatar is also examining gas pipeline and LNG export projects to India and Pakistan. It is not unthinkable that the recendy revived Natuna LNG project, with recoverable hydrocarbon reserves estimated at 45 tcf, could also become a potential supply source for the subcontinent in the early part of the next cenury. There are a number of options for the import of gas to India and Pakistan which need to be evaluated: onshore pipelines from Iran and Turlmenistan; offshore pipelines from Qatar, Iran and Oman; combination of offshore and inland pipelines; and LNG from existing plants or from new constructions in the mid east. Preliminary evaluations by the various consultants indicated that cost of delivered gas through onshore pipelines could range from US$1.43 to 1.85 /mmBtu, for offshore pipelines from US$1.9 to 2.2 /mmBtu, while LNG costs would be in the range of US$2.62 to 4.62/mmBtu. These estimates, however, were based on assumptions that lacked consistency, in particular on the yearly volumes. There is, therefore, some concern that the LNG transportation costs may have been overstated in the consultant reports. Our own calculations show that it should be possible to deliver a 1,500 Tncfd based volume of LNG (after regassification) from the mid-east to the subcontinent at a transportation cost just below US$3/mmBtu. Prima facie, it seems that natural gas transported through pipelines should have a delivered cost of less than that for LNG, the difference depending on whether the pipeline is onshore or offshore, the location of the market, and also any transit charges that may be levied by the countries over whose land the line traverses. But, given the recently reported tendency of decreasing costs for large-scale LNG projects, the difference in costs may be much less than are presendy being estimated. This is particularly true if a major market is located further than has been recognized by the consultant reports, for example, the south east of India which would need an additional 1,000 mile onshore pipeline from the landfall point in western India. In analyzing and interpreting these cost figures it must be kept in mind, however, that the underlying traditional economic analysis is not the ultimate decisive factor in final decisions on major private sector infrastructure projects. What matters ultimately is the finanlcia viability of the project, the strength of its sponsors and its risk structure. Therefore, in the evaluation of the optimmn alternive modes of gas transport, a number of factors, in addition to the delivered price of gas, will need to be taken into account in reaching a decision. These include: * Political risk * Market risk * Commercial and project risk * Coordination of downstream investments with import volumes * ;Fnancial resource mobilization mechanisms * Security packages. 4 Mechanisms for Financing The most important challenge in gas import projects is the arrangement of a viable financing scheme. Most common is the "build-own-nd-operate" (BOO) scheme, in which private investors mobilize the required capital, build the transmission infrastructure (LNG or pipeline), and operate the system under a take-or-pay contract with a gas company in the importing country. The success of such a scheme would require that: (i) The pIivate investor has the financial capacity to provide the equity funds of about 25-30 percent of the project cosL In many gas export projects the project cost, excluding the downstream market development, is in the order of US$4-5 billion, implying equity investments of US$1-1.5 billion. Many of the proponents of BOO schemes do not have a financial capacity close to this level. (ii) An instrumnent is developed to cope with political risk Private investors do not enter easily into situations where there is significant political risk This clearly becomes a more serious consideration when large investments with long gestation periods are at stake. Under these circumstances, a guarantee instrument would economize private sector participation considerably. This kind of instument can be developed in conjunction with private insurance programs or with multilateral institutions. Potential finanmciers of intemational gas projects will also be greatly encouraged to participate, when most or all of the following conditions are fulfilled as well: (iii) The project has full political support of the exporting and importing governments, as well as of the govemments through whose jurisdictions the gas will be transited. (iv) The consortium that is launching the project may have to include one or several major intemational oil or gas companies. (v) The implementation of the project must be in reputable and experienced hands. (vi) Long tam contacts with unconditional commitments, including take-or-pay clauses, must be signed. Recommended Strategy for Gas Trade Based on an analysis of the above factors, the tentative recommended strategy for import of gas should incorporate the following: * Multiple vs. sigle gas sources. A multi-source approach is possible in view of the size of the need for imports of gas of 4,500 mmcfd and would alleviate political risk perceptions. * Total investnent needs. The total investment needed for natural gas import should include also the downshtam infrastucture necessary to deliver the gas to the consumer. * Coordination ofsupply and demand. In view of the large investment requirements, both upsteam and downstream, graduated market development in phase with the upstream construction is highly desirable. The economies of scale that may be 5 possible through larger upstream systems need to be balanced with the possibilities of asynchrony in the completion of the downstream markets. * Allocation and management of risks. The political, market, commercial and project risks will have to be shared between the govermments, the developers and the international financial institutions. * Intemational fiancial institions participation. Since both the investment requirements, political and market risks of these projects are so great, the participation of the intemational financial institutions seems essential. The role of these institutions could bc to provide technical assistance, help in the financial structuring of the projects, development of appropriate security packages, and use of guarantee instruments. * Lead institutions for project development. There is a need for clarity in the responsibility and the process for development of a project which is complex. involves a large number of domestic agencies, and is international in scope. bhe countries could nominate specific agencies to develop specific projects as outlined above, but with an oversight committee for final decisions, within a specified time frame. It is important to stipulate that, before any gas is imported, the energy pricing system in the gas receiving countries has been reformed in such a way that it is based upon sound economic principles. This implies that existing pricing policies should be revised and subsidies on specific energy products be abolished. It also entails the abolition of the existing gas allocation policy of the government Taking into account the above considerations, it seems clear that one way to a successful implementation of gas import projects for Pakistan and India is to have them set up as joint ventures, in which the private sector has a major share in and responsibility for the construction and operation of the gas import schemes, while governments of exporting and importing countries hold an effective share in the projects. Given the perception of political and market risks, these projects are unlikely to come to fruition without some participation - in the form of loans and/or guarantees - of one or more international financial institutions. In addition, such participation seems necessary because: (i) major oil and gas companies (and other foreign investors) do not want to form project companies which are perceived by the govermments of the exporting and importing countries as total foreign entities. The oil and gas conpanies are very much eager to create a project company which has at least some Igal ownership. (ii) the private investors, while happy to see that govermnents are not running the gas export/import business, definitely seek minor shareholding by the governments to ensure that they procure cooperation, partnership and an accommodating business environment (iii) the major oil companies have separated their operations into independent profit centers. They therfore cannot cross-subsidize some activities or regions with the hope of very long tenn rewards from these activities or regions. This means the oil companies' ability to take certain types of risk is much more limited than in the past. 6 (iv) the large investments, the long gestation of the projets and the political risks involved necessitate some measures for risk mitigation. These could be made available through some form of explicit guarantees -such as the guarantee instrument, developed by the World Bank, or private insurance programs- or through direct financial participation of intewational financial institutions. (v) there is a need for an agency to facilitat cooperation among the investors, the involved governments and other major players. Such role can be most effectively played by international financial institutions. Gas import projects, whether by pipeline or as LNG, will require a stuctwue that pennits the mi vilization of finance from domestic and international sources. In the case of pipelines, three se,arate modules are possible: gas production in the exporting country, pipeline transportation, and gas sale in the inporting country. For LNG projects, the additional modules would be for liquefaction of gas in the exporting countty, ransportation by LNG tankers instead of by pipeline, and regassification in the importing country. The financing and operation of each of these modules can be assigned to separate agencies, both domestic and foreign, but always as part of the overall gas project It is also important to note that, in the World Bank's new oil and gas lending strategy, transnational gas trade projects are recognized as an area of highest priority for Bank assistance. For India, a possible mix of projects for satisfying gas demand till 2003 would be: e A 600 - 1,000 mmcfd LNG scheme for south cast India. * A 2,800-3,200 mmcfd onshore/offshore gas pipeline system from Oman and/or Qatar. It is less probable, but not to be excluded, that Iran and/or Turkmenistan could supply part of these volumes in the timefme mentioned. For the longer term they are important potential suppliers of substantial quantties of gas for the South-Asian region. For Pakistan, the approach would be for the following projects till 2003: * An onshore pipeline from Qatar with a capacity of at least 700 mmcfd. Because the gas demand will grow very rapidly after the year 2003, it probably makes economic sense to build a pipeline with a higher capacity. Because the suggested gas import projects for Pakistan and India have a substantial part of the pipeline routing in conmnon, it seems that coordination in the construction of pipelies that bring gas to both countries has some merits. Taking into account the big quantities of gas that each of the countries will need in 2003 and thereafter, a transportation system with at least two pipelines and in the long term probably more seems necessary if the gas is to come friom the QatarOman region. For Bangladesh, the only country on the subcontinent with some export potential, the key policy decision is to invite inteional oil companies for oil and gas exploration, but with clearance for export of gas beyond that required for domestic market. This could be achieved by the govemment offering the private sector the altenatives of, (i) 7 purchase of reserves after discovery at a detemnned pnce, (ii) purchase of natual gas earmarkedfor domestic market up to a level determined atcontract stage with the baance to be disposed by the company, or (iii) export of gas to any country depending on the price. 8 1 Regional Energy Sector Overview Introduction Bangladesh, India and Pakistan demonstrated strong economic growth rates during the 1980s. The 1990s opened with a deceleration of the growth, which, however, did not last long. During 1980-92, GDP grew on an average at 4.2 percent in Bangladesh, 5.2 percent in India and 6.1 percent in Pakistan. The propostications for future growth are even better. Economic growth and incrase in use of commercial energy go hand-in-hand and result in reduction in use of non-commercial energy (most of which is fuelwood). Although all three countries possess substantial energy resources in one form or another, they all are net importers of energy, mostly oil and oil products. Energy Reserves and Supply Historically, coal, oil and natural gas have been the most important contributors in satisfying the region's overall demand for conmercial energy. There is, however, substantial variation in the mix of used commercial energy in India on the one hand and in Pakistan and Bangladesh on the other, due to the difference in available natural energy resources in thetbree countres. In Bgadesh natural gas is in abundance. It is almost the only domestic fuel, supplying 74 percent of the demand for commercial energy. The issue there is if that country should consider exporting natural gas and, if so, when and how. In&j has vast coal reserves, some substantial oil and gas reserves, and hydropower; nevertheless, it has been importing crude oil and oil products in ever rising quantities, as the demand-supply gap for conmenial energy keeps widening. Pakistan has substantial gas reserves, with new discoveries continuing to be made. Its oil and coal reserves are, however, limited and the hydropower resources are difficult to develop. Pakistan too has been importing oil and oil prducts in rising volumes, as the demand for commercial energy has been running ahead of a slower paced but growing domestic supply, including new gas. In the following a brief overview of the recent commercial energy supply situation is given. India: In 1992, India's primary energy supply (including imports) was about 205 mmtoe, comprising 174 mmtoe of domestic production and 31 mmtoe of imported energy. Of the suppply, coal and lignite accounted for 54 percent, oil (about one- half of which was imported) 27 percent, hydropower for about 13 percent and natural gas for about 6 percent. Although domestic production of crude oil increased sharply after the discovery of Bombay High in the mid 70s, India has continued to import oil. Coal is the main primay resource, not only for direct use in industry, but also in indirect uses of energy through power generation. Coal's share in the supply has maintained a proportion around 54 percent for the last twenty years. Oil too maintained over these years its proportion in the supply at around 30 percent, but with 'swing' in the share of imported oil in total oil consumption. Natural gas, being the main altemative to coal and oil in the Indian energy scene with a domestic production of 560 bcf in 1992, is likely to play an increasing important role in the coming years, thereby displacing the traditional fuels in the market and supplying incremental energy demands: the forecast gas production for the year 2000 is 940 bcf. The reason for this is that natural gas is environmentally far more benign, also it has economic advantages when used as a fuel for power generation. Natural gas recorded a 6 percent share in primary energy consumption in 1992, against I percent only in 1973. There has been a growing appreciation of the value of natural gas and its attractiveness as a substitute for oil and coal, so much dtat flaring of gas which was around 50 percent of production in the early 1970s has declined steadily and would be almost zero by the mid 1990s. Pakistan: Natural gas has been the most important contributor to the energy supply in Pakistan, constituting 42 percent (13.0 mmtoe) in 1992. Oil followed with 38 percent, hydropower with 13 percent and coal with a modest 7 percent. Energy imported almost wholly consisted of oil and oil products, domestic oil meeting only a quarter of the oil rqiiremnts. Consumption of commercial energy has been growing at about 8.5 percent p.a. over the last decade and with energy conservation measures in place is expected to show a future growth of 6 to 7 percent p.a. Natural gas is foreseen to remain a very important contnbutor to the energy supply when more gas fields are discovered as expected. Pakistan is gas prone and gas reserves account for 90 percent of the discovered hydrocarbon reserves. Natural gas production has increased 4-fold since 1973 with ultilization in power and ferdlizers. Indications are that domestic gas production would reach a level of about 1,050 bcf per year in the early years of the next century (600 bcf in 1992) and stay at that level for a few years before declining. Bangladesh: In 1992, primary conmercial energy consumption in Bangladesh was 6.8 mmtoe, of which nawral gas accounted for 60 percent, oil for 32 percent, hydropower for 4 percent and (imported) coal for 4 percent The bulk of the gas consumption was in power generation and ferdlizer production, together accounting for 83 percent of the 1992 gas usage in the country. With increased gas availability and the government's policy of substituting natural gas for imported petroleum products, the county's dependence on imported energy was significantly reduced in the 1980s. Natural gas is forecast to play an inmcreasing role in satisfying the projected energy demand growth, specifically in the power generation sector. 10 Economics of Using Gas vis-a-vis Alternative Fuels Natural gas competes with altemative fuels in nearly all its applications. Ihe economic value (or netback value) of natural gas in its various applications is that price of the gas, at which the unit cost of production of the final product (electricity, ferdlizer, heat) will be the same as the unit cost of production, based on the alternative fuel/feedstock in those applications. In economic terms, the netback value of gas gives an indication of the price, at which the consumer of the gas is indifferent whether he uses gas or the altemative fuel/feedstock in his specific application. Within each category of consumers, however, gas will have a range of netback values which will be dependent on the characteistics of individual consumners in terms of their location, mix of alternative fiuels/feedstock, pattern of fuel use, etc. In the following, therefore, we have estimated bench or representative netback values for each consumer class. Gas In competiton with oil In Pakistan as wel as in India, producer and consumer prices of oil products and natural gas are adminiswred by the federal government. Annex 1.1 gives an overview of the January 1993 consumer prices of some oil products and naural gas, as in force in India and Pakistan, together with the prices for OECD Europe. As long as such regimes of admiistered energy prices with implicit subsidies for certain products and/or consumer categories exist, it is impossible to assess the long term degree of price competiion between (subsidized) natural gas on the one hand and its (subsidized) copetitors, i.e., oil products, on the other. In addition, a tariff structure that does not fully reflect the cost of the various energy resources is not conducive to an efficient use of energy and an optimal inter-fuel substitution. For the purpose of assessing the economic value of gas in relation to its oil competitors, therefore, the international (non-subsidized) crude oil and product prices are the appropnate variables. To avoid the difficulties in assessing the rather varying inland transportation cost of oil products, gas and coal, depending on which specific location and which specific type of end-consumer in the vast south Asian region is chosen, a certain simplification has been adopted in that the oil prices CIF Bombay/Karachi have been assumed to be the yardstick for assessing the economic value of natral gas at these coastal delivery points. In Table 1.1 the most relevant CF Bombay/Karachi product prices are listed, based on a price of crude oil of US$18Jbbl, FOB Arab Gulf. Product prices would increase USS7-8/tonne for a US$1/bbl increase of the FOB crude oil price, except for LPG, which would increase US$1 1-12/tonne. 11 Table 1.1 product prices, CIF Bombay/lKrachl, at crude price of US$18/bbi, FOB, Arab Gulf CIFprice Product US$/ionne LPG 185 Naphta 180 Kerosene 215 Gasoil 190 Fuel oil (low sulphur) 120. Fuel oil (high sulphur) 90 Gas in competition with coal Natural gas competes mainly with coal in the industrial and power generation sector. As already was mentioned above, India is well endowed with coal reserves, while Pakistan currently has hardly any substantial coal production. A large proportion of the coal reserves in India is of low quality with a high ash content; this prohibits from an economic point of view its long distance transport from the generally remote coal mines, mainly in central-east India, to the main consumption areas in the western and southern parts of the country. Pithead prices of coal are fixed by the centl govemment and are, at a level of around US$0.5/mmBtu for average quality (16 mmnBtu/ ton) power station-destined coal, just below or at par with the cost of production, but well below intemational prices. When royalties and transport fees, however, are added to the pithead price, the average power station delivered price for coal in western India is in the same order of magnitude (US$I.6-I.8/mmBtu) as the price for imported steam coal (26 nunBtulton) at the Indian west coast or Karachi. As a yardstick for coal prices for power generation we assume, therefore, the prices as specified in Table 1.2: Table 1.2 Prices of coal for power generation Coal destnation $/tonne $/mmBtu Pithead 7.5 0.5 Westcoast 25.0 1.6 - 1.8 Southern region 25.0 1.6 - 1.8 Although the domestic coal reserves are substantial, the growth in coal production is limited, due to financial, environmental and social restrictions. Based on the realized growth rates of 5.4% for coking coal and 6.7% for non-coking coal during the 1980's, and 12 takdng into account that railway tansportation capacity in the country is curntly nmre than strated, it is foreseen that the growti in coal production will not exceed 5% p.a. Annex 1.2. gives an overview of realized coal production over the past 10 years. In the Southern region, comprising Andhra Pradesh, Karnataka, Kerala and Tamil Nadu there is a certain amount of coal and lignite production within the region. But this is well below the overall prnmry energy r uirmes for power generation, cemnt production and other industrial uses. Coal from outside the region from mines beyond 1,000 kms, is regularly transported by rail. More and more of such coal, subject to availablity, has to be transported in as the energy demand grows in the region. In order to assess the economic viability of gas use in existing and fubture applications, benchmark netback values for gas in the main consuming sectors have been estimated. These netback values are calculated based on the prices of the fudelsfeedstock displaced, as represented in Table 1.1 and Table 1.2 above, and taking into acount de different efficiencies in end use between natural gas and its alternatives, together with differential capital and operating costs of the gas and non-gas applications. Because Tables 1.1 and 1.2 represent oil and coal prices for both India and Pakistan, the estimated benchmark netback values for gas, which are based on these prices, hold for both countries. The benchmark netback values of natr gas for various applications are esimated to be as in Table 1.3. 13 Table 1.3. Benchmark notback values of gas Netback vwue End use (US$/mmBtu) Residential/commercial * new conmercial consumer 6.7 * new residential consumer 3.5 - 7.0 Combined cycle power generation * fuel oil replacement 4.3 * diesel replacement 6.4 Base-load power generation * coal replacement * - pithead 2.3 - westcoast-area 3.7 - southern region 3.7 Industrial heat and steam raising 3.0 Fertilizer production * future geenfield 2.2 * existing piants 5.0 *Cost for flue gas desulfuzation (estimated at US$O.5/mnBtu) and for additional coal infiastctumre have not been taken into account Annex 1.3 gives an overview of the assurmtions and the procedure used to calculate the netback values and shows some of the calcuations supportive of the conclusions in Table 1.3. It must be noted that the above benchmaik netback values for gas have an indicative cfaracter only and should not be used to make final investment decisions. The netback values for power generation, for instance, do not include any envirnmental premium. Only an in-depth economic and environmental analysis of the power sector could in the end determine the advantage of using gas vis-a-vis domestic coal. The results in Table 1.3. show that residential/commercial use of naural gas would have the highest netback values, for new residential consumers depending on the stage of development of the gas distribution grid: the higher value of US$7.0/mmBtu represents the marginal customer in a well-developed distribution system, the lower value of US$3.5lmmBtu is applicable in areas where gas is available, but a grid has yet to be developed. The high values are due to the replacement of high value liquids, large end use efficiencies for natural gas applications and - in case of an existing distnbution grid - relatively low incremental investments. The high residential/commial netbacks are directly followed by the netbacks, based upon gas use in combined cycle power generation, where gas is substituting diesel or fuel oil. Use of nrabral gas instead of coal in power 14 production would be economically feasible only in non-pithead generation, assuming a gas import price level of US$3.5/mmBtu. Pithead generation of electricity has economic advantages over gas fired power generation; this holds, however, only when the power is consumed within a distance less than about 400 miles from the location where the power is generated. Beyond that distance the transportation cost of electricity becomes prohibitive to compete with locally gas generated electicity; in other words, when the distance between coal mines and the coastal consumption areas of power is greater than about 400 miles, gas generated power can compete with power generated at the coal mine mouth. With the above gas import price of US$3.5/mmBtu, gas use in fertilizer production seems feasible only in existing plants, where the capital investments are considered to be sunk costs; taling into account the currently low world market prices for urea, new greenfield urea plants would be no viable option for usage of gas with the above import price level. 15 2 Commercial Energy Demand and Supply By Country Bangladesh Proven remaining recoverable naura gas reserves in Bangladesh are estimated at 12 tcf (or 340 bcm). The current yearly consumption of gas is about 200 bcf, giving a reserve to production ratio of 60 years. Even with a forecast gas consumption of about 480 bcf in the year 2003 , this ratio remains at a comfortable 25 years. Bangladesh has a very low energy consumption per capita, at about 60 kgoe per year, and as its economy grows, gas consumption would grow even faster. Table 2.0 gives a forecast of the supply of natural gas in the country, together with the forecast supply of oil and coal, which are inmpoted, and of hydropower. Table 2.0 Commercial energy supply In Bangladesh 1999-2003 (mmtoe) Year Oif Natural Gas Coal Hydro Total 1993 1.6 4.9 0.5 0.2 7.2 1999 1.4 8.7 0.5 0.2 10.8 2000 1.3 9.4 0.5 0.2 11.4 2001 1.3 9.8 0.6 0.2 11.9 2002 1.2 10.6 0.6 0.2 12.6 2003 1.1 11.5 0.6 0.2 13.4 Allowing for this growing gas consumption, there may be a rationale in the government's reported wish to preserve the existing gas reserves as "national reserve". But, the exploration for hydrocarbons in the country, which is considered gas prone, is far from complete. Internaional oil companies have been higbly interested m exploration, onshore as wel as offshore. Their enthusiasm apparently gets a set back, however, when the Govemment of Bangladesh (GOB) shows disinclination to commit to export of new gas, which should be possible for at least the new discoveries. India is a "natural" market for the gas, unless the new finds are so large that LNG exports to Thailand or other countries in the Far East become feasible. For the time being, it is a change of policy that is required from the GOB before any meaningful study of gas trade, involving that country, can be undertaken. India Energy resources India's energy resources and their 1992 production, with the resulting reserveslproduction ratio, are shown in Table 2.1 below: Table 2.1 Energy reserves in India (as of 1992) Production Reserves/production Reserves Recoverable in 1992 ratio (years) Coal, million tonnes 70,000 255 280 Crude oil, million tonnes 806 31 26 Natural gas, billion cu.ft. 26,000 660 40 Although the cozl reserves are vast, logistics and economics have limited the growth in the annual output of coal to about 5 percenL Crude oil and natual gas reserves seem to have peaked, at least for now; as a result, when annual production increases, specially that of natural gas, the reserves stand to be depleted in less time than shown under the reservescproduction ratio. India has a hydropower potential of 84,000 MW, of which 14 percent has been developed so far. Practical problems have prevented further significant hydropower development. Demand for commercial energy Projections of total commercial energy consumption and the domestic energy supply in the years 1999-2003 are represented in Table 2.2. These are the first years when import of natural gas may happen, if action to do so is initiated over the next few months. Total energy demand is prognosticated on the basis of an energy consumption growth rate of 6.5 percent per year until the year 2000, and 4.5 percent per year therafter. The domestic supply of energy is assumed at the maximum likely figures; imports of oil, gas and coal would make up the remaining demand/supply gap. 17 Table 2.2 Energy demand and supply In India 1999-2003 Total Domestic supply Toal Deana' enery Coal Oil Hydro Natural Gas mera supply Year dnand mnuce* mmtoe mmtoe TWX mmwoe** b1f mmoe supply gqp mmtoe mmntoe mmtoe 1993 246 191 134 30 102 36 517 13 214 32 1999 318 253 177 41 98 34 955 24 276 42 2000 332 266 186 40 102 36 955 24 285 47 2001 346 276 193 38 106 37 955 24 292 54 2002 365 287 201 36 110 38 955 24 299 66 2003 374 299 209 33 113 39 955 24 305 69 mrntce=0.7 mmtoe * Estimate based on a 25 percent efficiency of equivalent oil fired planL As can be seen from the table above, the demand/supply gap is substantial, corsponding with 13.2 percent of total energy demand in 1999, rising to 18.4 percent in 2003. Which fuels must be used to fll the gap and how much of each is subject to stratgic, economic and political considerations. It is clear that natmal gas can play an important ole in satisfying the unfulfilled demand for commercial energy. To put that in perspective: the estted gap of 42 mmtoe in 1999 corresponds with 49 bcm or 1,750 bcf of natural gas on a yearly basis, this is 4,775 mmcfd. Demand for natural gas In 1992 total conswnption of natural gas in India reached 510.3 bcf, of which 55 percent was used for energy purposes and 45 percent for non-energy usage. Table 2.3 specifies the various usages of the gas. Table 2.3 Natural gas consumption In FY 1991-92 Conswmption Consumer (bcf) Energy purposes: * power generation 168.7 * industri fuel 27.1 * teaplantation 3.8 * domestic fuel 2.5 * LPG production 76.5 Subtotal 278.6 Non-energ purposes: * fertilizer production 194.7 * perohemical feedstock 18.8 * other 18.2 Subtotal 231.7 Grand total 510.3 Source Indian Petroleum&Natral Ga Statisics 1991-92 18 At present, natural gas supplies are allocated to end-use consuners according to a policy, determined by the govermment. As can be seen from the table above, allocafion for fertilizer production and power generation are pred t over other usage of gas. Gas use policy has been a subject of considerable debate in India during the second half of last decennium, but there seems to be a consensus now of how to allocate the available gas to the various consumer categories. It must be noted that a gas allocation policy is aimed to achieve not only an economic objective, but also objectives of social and strategic nature. The preferential supply of gas for ferhlizer production in the last decnnium (46 percent of total gas consumption) reflects the paramount importance of India's agnculture sector and the Gors desire to achieve a high degree of strategic independence for the production of ferdlizers. The supply of natral gas for power generation, raked second during the 1980s with 29 percent of total gas offtake, becomes a more and more important allocation of the available gas; the power sector will become the most important consumer category for natural gas in India in the mid 1990s. This is due to the fact that India7s demand for electricity is still increasing at a higher rate than the increase in capacity of the power system; that system grew from 30,000 MW in 1980-81 to 72,000 MW (public sector) in 1992-93, with corresponding increase in electicity availability from 110,000 GWh to 284,000 GWh over the same period. Based on the gas demand and supply data of recent intemnal Bank reports4 and exwmal studies, we eirated the gas demand for a high and a medium demand scenario, and the future donesc gas supply as in Fig. 2.1. Annex 2.1 specifies the data. Fig. 2.1. Future gas demand and suRpOy 8000 7000- iOOO ~~Domsestic so-. m 5000 U c 4000 f d 3000 -- 2000 _ --- 1000.. 1992 1994 1996 1998 2000 2002 2003 4Soue Gas Flig Reduction Project 19 Comparing the natural gas demand/supply gap for the medium demand case in the above Figure 2.1 with the total energy demandlsupply gap, as represented in Table 2.2, yields the following data for both gaps and the percentage of the gas gap in relation to the energy gap: Table 2.4 Energy gap vs. natural gas gap (mmtoe) Year Energy gap Namwl gas gap Rado(%) 1999 42 8.0 19.0 2000 47 12.7 27.0 2001 54 18.2 33.7 2002 66 25.1 38.0 20D3 69 33.5 48.6 It can be seen from the above table and Figure 2.2 below that, based on the projected demand for total energy and for natural gas, the gas gap constitutes about one- fifth of the total energy gap in the year 1999 and about one-half in 2003. FI.2.2. Energy demand and domestic suRply In IndimImmtoe) 400 350 300 25 0 - domestic hydro 200 150 100 50 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 E it is assumed that the natual gas gap is fully made up in 2003, the implication is that 33.5 nmmtoe or about 3,800 mmcfd of natual gas is being imported in tlat year. It seems more reaistic to assume that any future ixport scheme for natural gas in about 10 years from now will allow for a maximum of 2000 nmmcfd gas import per year. In that event, the ratio of nattual gas gap in the energy gap will stand to be reduced to about 33 percent in 2003, leaving a considerable unfilfilled potential demand for natural gas. 20 Natural ga Infastructre India does not have an integrated national gas transmission system. A part of India in the west around Bombay and Ahmedabad, and in the west-north-west in Gujarat, Rajasthan, Madhya Pradesh and Uttar Pradesh receive gas from onshore fields in the region as well as from the offshore fields of Bombay High, Bassein and several other, smaller fields in the Arabian Sea off the western coast. Small coastal areas in Andra Pradesh and Tamil Nadu are similarly linked to proximate onshore and offshore gas fields, holding limited gas reserves. Assam and Tripura also get gas supplies from small onshore fields in the respective states. These independent networks presently carry about 1,600 mmcfd of gas and would be developed to carry about twice as much in due course. The capacity of the western offshore lines and of the HBJ pipeline serving the west-north-west region is under expansion to accomodate the associated domestic supply, which is moving towards peak production (from 1,000 mmncfd in 1993 to 2,000 mmcfd, to be achieved in 1998). The Govemment of India has recently approved in principle a proposal for a trunk pipeline from the Bombay area to the south of India (distance around 1,800 miles) for the supply of indigenous western offshore gas. If that line is laid and the gas reserves in the western offshore areas are shared with the south, it would seem that the supply to the south could only be made through widening the demand/supply gap for natural gas in the Bombay and HBJ region. If, on the other hand, natural gas is to be imported from the Middle East, the proposed trunk line to the south could become an essential piece fitting into a national grid. Regional gas demand Expanding on the observations above concening the proposed gas transmission line to the south, the fir fact to note is that of the 'gas gap' of 33.5 mmtoe or 3,800 mmcfd in 2003 in the medium demand case (see para 2.6), about 2,150 nmcfd will be in the west and the north (Bombay, Gujarat, HBJ line and vicinity), about 775 mmcfd in the southem region and the balance in the other regions (but with easier access to coal). Given these large quantities of deficits, also that the demand-supply gap will tend to further widen after 2003, a multi-faceted import strategy of a series of economic packages for import, of varying sources, of different modes of transportation if necessary, of different destinations etc., should be followed. Any package for import, obviously, should be economic; namely, gas should be the optimum fuel to import at the time and place it is needed. Pakistan Energy resources Pakistan's energy resources and their 1992 production, with the resulting reserves/production ratio, are shown in Table 2.5 below: 21 Table 25 Energy reserves In Paistan (as of 1992) Reserves Recoverable 1992 Production RIP Rado (years) Coal, million tonnes 432 3.6 120 Crude oil, million tonnes 27 3.1 9 Naturl gas, billion cu.A 22,800 551 41 Pakistan's natural gas reserves are about the one resource which is notable. The Government of Pakistan has been liberalizing the petroleum exploration policy from time to time, which has attracted some renewed interest from international oil companies to explore for gas as such. Pakistan has hydropower potential of about 27,000 MW of which some 18 percent has been developed so far. Schemes in progress to harness more hydropower should double the hydel output by the year 2000. The production of coal and gas is expected not to grow substantially in the near future. Demand for commercial energy Projections of total commcial energy consumption and the domestic energy supply in the years 1999-2003 are represented in Table 2.6. These are the first years when imports of natural gas may happen, if action to do so is initiated over the next few montis. Total energy demand is prognosticated on the basis of an energy consumption growth rate of 6.5 percent per year until 2000, and 6.7 percent per year thereafter. The domestic supply of energy is assumed at the maximun likely figures; imports of oil, gas and coal would make up the remaining demand/supply gap. Table 2.6 Energy demand and supply In Pakifsan 1999-2003 Total Domestic supply Total D&mnd' enffv Coal Oil Hydro Natural Gas enCrD supply dana wad supply gap Ycor mmtoe mitce nwloc mmtoe T'WW mnoeJ W * b4 mMtoe mmtoe mmtoe 1993 34.0 4.0 1.9 3.1 20.3 5.1 560 13.1 23.2 10.8 1999 47.0 5.1 2.4 3.2 29.5 7.4 898 21.0 34.0 13.0 2000 50.2 5.3 2.5 3.2 31.5 7.9 954 22.3 35.9 14.3 2001 53.6 5.5 2.6 3.2 33.5 8.4 968 22.6 36.8 16.8 2002 57.1 5.7 2.7 3.2 33.5 8.4 979 22.6 36.9 20.2 2003 61.0 5.9 2.8 3.2 33.5 8.4 993 22.6 37.0 24.0 * Estimate based on a 36 percent efficiency of equivalent ol fired planL 8.48.7 mega calories per cu.meter As can be seen from the table abowv, the demand/supply gap is substantial, corresponding with 28 percent of tal energy demand in i999, rising to 39 perent in the 22 year 2003. For satisfying its cnergy needs, Pakistan will tius become more and more import dependant. To illustrate, the energy demandlsupply gap for the year 2003 of 24 rnmtoe corresponds with 1,050 bcf of natural gas on a yearly basis, this is 2,900 mmcfd. Demand for natural gas In 1991, total consumption of natural gas in Pakistan reached 481 bcf, of which 40 percent was used for power generation, 22 percent for industrial usages, 20 percent for fertilizer feedstock and fuel, and 17 percent for residential and conumncial use. Table 2.7 gives details of the 1991 gas consumption, as mealized by the two gas transmission and distribution companies, Sui Northeem Gas Pipelines Limited (SNGPL) and Sui South Gas Company (SSGC), and the Mari gas tansmission company which delivers Mari gas directly to power and fertilizer plants. Table 2.7 Gas consumption In 1991 (bcf) Consumer SSGC SNGPL Mai Total Power 66 33 96 196 Ferilizer - 33 66 99 Industrial 50 56 - 106 Residential 24 43 - 67 Commercial 4 9 - 13 Total 144 175 162 481 Source: SSGC, SNGPL. Ministry of Petroleum and Natural Resources Natural gas supplies are allocated to end-use consumers according to a policy that is determined by goverment. In descending priority, these allocations are fon (i) fertilizer production; (ii) diesel replacement for power generating turbines; (iii) kersene replacement in the residential and commercial sectors; (iv) fuel oil displacemet in the industrial sector; (v) fuel oil displacement in steam turbine power plants, and (vi) fuel oil displacement in cement and steel production. The preferential supply of gas for existing (and planned) urea production reflects the paramount importance of Pakistan's agricultural sector and the Govermment's desire to achieve a high degree of straegic independence for ferftlizer production. The high priority afforded to to residential and commercial users reduces the need for imports of expensive fuels such as kerosene and LPG, and eases the demand for fuelwood which has resulted in serious soil degadation problems in the country. Since in coming years the competition for available gas supplies becomes more intense, an important element of the future allocation policy is the provision of suppLies to uses which provide the highest economic benefit to the economy. Based on what was recently (early 1994) reported in the Bank's ESMAP study on Natural Gas Reserve Assessment and Import Strategy for Pakista in Figure 2.2 23 a high and medium demand scenario, together with a most likely scao for future dgm& pgas supply is given. Annex 2.2 specifies fte underlying data for this figure. Fig.2j. Future gem deM-nd and supply (Mnmctd 4500 4000 3500 3000 m m 2500- .. C 1500 -Mediumndemand 1000- _& Hihdemd 5oo - ---Domesic supply 1992 1994 1996 1998 2000 2002 2003 Comparing the naural gas demand/supply gap for the medium scenario in the above Figure 2.2 with the totl enery gap, as represented in Table 2.6, gives the following for both gaps, together with the ratio gas gap/total energy gap: Table 2.8 Energy gap and natural gas gap (mmtoe) Year Eeg gap Gasgap Rato (%) 1999 13.0 2.0 15 2000 14.3 2.5 17 2001 16.8 3.2 19 2002 20.2 3.9 19 2003 24.0 4.8 20 Frm dte above Table 2.8 and Figue 2.3 below it follows, that the portion of the gas deficit in the totl energy gap is steadly rising, although its portion raher moderate: in 2003 the gas gap consfitutes "only" one-fifth of the total energy gap. 24 Fg. 2.4. Energy demand and dommtlc supply In Paldsten (mmtse) 70 T 60- 50 40 30 20 - . 1 0 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 It must be noted, however, that the referred Bank study indicates, that the demand/supply gap for natural gas is sharply rising after 2003, resulting in a gas supply shortfall in the year 2010 of 2,500-3,000 mmcfd or 21.4-25.7 mnmtoe per year. Its share in the total energy gap at that time is expected to be in the order of 25 percent5. It is noted here that GOP has been negotiating a project for inport of gas by pipeline from Qatar which may deliver 1,100 mmcfd (=9.4 mmtoe) to 1,600 mmcfd (=13.7 mmtoe) commencing- from late 1998. From Table 2.8 it would appear that most of the energy gap between 1999-2001 would then be filled by imported gas. An aggressive penetration of the market by natural gas, so that almost all incremental demand for commeal energy is met by gas, would be required if Qatr would deliver the above gas volumes and the data from Table 2.8 are taken into account. s The pesentation to the Bank made recently by one of the involved gas supply consortia shows that in August 1993, 'GOP agreed firm gas import qantities and ake-or-pay commitment'. The Principles of Gas Sales are stated as: 'Fust Gas: late 1998; Daily Qty.: 1,600 mmcfd Minimum Bill: 70 peAcei.., 1st year, 75 percent, 2nd year; 80 percent, 3rd year and subsequent' These quantities corspond to 9.6 mmtoe in 1999, 103 mmtoe in 2000 and 11.0 mmtoe from 2001. They far eceed the 'gas gap' in Table 2.5 and woud also far e ceed the 'gas gap' under the high scenario also. In fact, during 1999-2001, almost the whole of the energy gap will be met if gas of the volumes indicated am imported. It is noticed that the uconstained demand is placed at 4,180 mmcfd in 199899 and 4,480 mmcfd in 1999/2000. The high demand scenario in the ESMAP study is about 1,000 nmmcfd lower. Therein lies the major difference. 25 Natural gas Inftstructure Pakistan has developed an extensive gas transmission and distribution system with a total length of more than 2,200 miles major cities, including Karachi, Hyderabad, Sukkur and Queta in the Sindh and Baluchistan provinces in the south, and Faisalabad, Lahore, Islamabad and Peshawar in the Punjab and North Western Frontier provinces in the north are covered. The two tansmission and distribution companies SSGC and SNGPL, operating the southem and northern systems respectively, have embarked on major investment programs to accomodate the additional domestic gas from new fields. There is also a snall independent pipeline system for evacuation of gas from some of the fields, in particular the Mari field, and transporting it direct to some big gas consumers. If gas is imported, it is likely to be landed at Gadani, close to Karachi, and then transported to Karachi at the southern end of the pipeline grid. Other options for landing the imported gas exist, but the Gadani option represents a magnitude of costs which appear optimal. The estimated investments and the average incremental cost of trnsmission, related to absorbing imported gas of a volume of 2,000 mmcfd or 20.7 bcm per year for that option, are US$2,900 million and US$0.81/mmBtu respectively. Like India, Pakistan would also be well advised to diversify its energy imports by importing natnral gas in addition to the traditional import of oil and oil products. Coal is a candidate for import as well, but it is unlikely to compete with natural gas in power generation, if the landed price of gas does not exceed US$3/mmBtu. 26 3 Importing Natural Gas Sources of Gas India and Pakistan are located in proximity to the gas prone areas of the Middle East and the substantial landlocked gas deposits of Turkmenistan. Six countries, namely Iran, Oman, Qatar, Turkmenistan, U.A.E. and Yemen have exportable gas reserves. In Annex 3.1 an outline is given on the extent of the reserves, the status of their development and the state of readiness to sell gas to India and Pakistan. Iran is interested in supplying gas and has entered into agrements for feasibility studies for gas pipelines to Paldstan and India. Its gas reserves, however, which are estimated to be as huge as 730 tcf, are far from being developed. In the long ran, an is indeed a good source for import of gas by India and Pakistan. Given the current political climate and the financing constraints to develop the gas fields, "the long run" could mean a wait of ten or more years before Iranian gas exports to Pakistan and India would Oman is anxious to sell gas to India. A MOU appears to have been signed with India for transmission of gas by pipeline. The possibilities of transporting gas by either a shallow offshore pipeline along the coast of Iran and Pakistan or a direct deep sea pipeline have been under study. Because the latter had economic and political advantages over the shallow route, the Oman Oil Company (OOC), whose shares are held by the Ministy of Petroleum and Minerals and that of Fmance and Economic Affairs of Oman, had even a proposal before it for the laying of the deep sea line. Simultaneously, Oman was actively promoting a LNG export project by a consortium of Shell, Total and two Japanese companies in joint venture with OOC It is very likely, however, that the gas reserves of Oman are not sufficient until more are proven (beyond 7 tcf for the LNG project) to sustain both the India pipeline and the LNG export project The India project may not take off for afew years. In any case, the first priority is being given to the LNG export project targeted to export LNG in 2000 and attention for the present is focussed on it The U. A.E. is a traditional exporter of LNG to the Far East, particularly Japan. It could export an additional 2 million tonnes of LNG, equivalent to 100 bcf of gas, yearly since it is planning to extend the Das Island LNG facility from the current 4.8 mmtpy. It is unealistic to assume that this additional LNG capacity will be available for the gas markets in Pakistan or India, because (i) the volumes involved are rather small and (ii) they will have been contracted long befc.re a decision by the Indian or Pakistan govemnment whether to import gas by pipeline or by ship in the form of LNG would have been taken. Turkmenistan and Yemen are currently not considered as serious candidates for supplying natural gas to India and Pakistan, since no immediate development of the gas fields in Turknenistan and Yemen is foreseen, mainly due to the political instability and lack of funds in these countries. In the long run, Turkmenistan might become a reliable source of gas supply for the Indian subcontinent when it could share its huge gas production potential with Iran, with the purpose to jointly supply the region with substantial volumes of gas. This could be accomplished by delivering gas from Turkmenistan to the northem gas consuming areas in Iran; corresponding volumes gas from the south Iranian fields are thus available for export through overland pipelines to Pakistan and/or India. Qatar is - in a time frame of the late 1990s - a firm source to import gas from. The country has about 160 tcf of natural gas resc.rves, which, for intemational standards, are enormous. Qatar has four LNG projects for selling 26 nmmtpy of LNG, corresponding to just under 1,300 bcf of gas per year, in different stages of evolution, and it is considering to pipeline gas to Pakistan. TransCanada, Brown & Root and Crescent Petroleum are the sponsors of this project; but, as discussed in para 2.12, the madret capacity (and the internal infrastructre) to absorb the imported gas in the volumes planned should be developed aggressively. Recently, Exxon announced that the Indonesian Natuna natural gas project will be revived again. This would entail that a gas platea-volume of 2.4 bcf per day, in the forrn of LNG, becomes available. The most likely markets include Japan, South Korea and Taiwan, but it is not unrealistic to assume that the Indian subcontinent could also become a potential destination for this gas. Mode of Transportation Based on the availability of of gas reserves as dicussed above, the following choices for pipeline routes or LNG schemes seem theoretically obtainable: 28 Pipelines (i) Qatar/lran -India/Pakistan Overland (ii) Qatar/Iran -India Overland Iran/shallow offshore Palistan (iii) Qatar/Iran -India Shallow water (iv) Oman -India Shallow water (v) Oman -India Deep sea (vi) Turkmenistan -Pakistan/India Overland LNG (vii) QatarfIan(Oman/UAE -India Grassroot plant (viii) Qatar/Oman/UAE -India Plant extension (ix) Qatar -Pakistan Grassroot plant Cost of Imports Costs for transportation for the above altematives have been developed on assumptions as explained below. Annex 3.2 gives examples of the transport cost calculations for LNG schemes, while Annex 3.3 specifies examples for pipeline transport calculations. A sunmnary table, Table 3.1, follows on the next page. The calculations have been developed in the case of the pipelines for tansportation of 1,500 mrmcfd to one destination in India and one in Pakistan. For LNG, transportation of LNG purchased out of a 11 mmtpy (or 1,500 mrncfd) exporting scheme is considered to one destination in Pakistan and three destinations in India; also for LNG from a 4 nupy (600 mmcfd) exporting scheme. A typical grass-root LNG scheme involves in the overall transportation tariff a component of 60-65 percent towards liquefaction, 20-25 percent towards shipping and 10-15 percent towards regassification. The LNG tariffs shown thus include regassification costs. The discount rate is taken at 15 percent, which is what private investors would normaly take into reckoning. All costs are in 1994 US dollars. To arrive at the delivered cost of gas, the cost of the gas produced and transported to the liquefaction plant (in the case of LNG) or to the export tenninal has to be added. It may be in the range of US$1.00mm.Btu or more. For our analysis we have taken the US$1.00/mmBtu figure. 29 Table 3.1 Transportation Costs Tarff Source Route Destination Distance US$/mmBtu (lams) (15% DCF) Pipelines 1.500_ruf 1. QatarIan Cverland Karachi 1,600 1.83 Ahmnedabad 2,200 2.44 2. Qatar/Iran Overland/) Karachi 1,600 2.01 shalow) Ahmedabad 2,200 2.68 3. Qatar/Ian Shallow Karachi 1,600 2.20 Ahmedabad 2,200 2.92 4. Oman Shallow Ahmedabad 1,300 2.53 5. Oman* Deep-sea Ahmedabad 1,200 2.30 6. Turkemenistan Overland Karachi 1,650 1.86 Abnielabad 2,250 2.51 LNG-grass root** .500 nmmfd 7a. hran/Qatar Karachi 2.70 ,'Cnan Bombay 2.85 Cochin 3.10 Madras 3.22 7b. hran/Qatar Bombay 3.23 /Oman Cochin 3.52 Madras 3.57 *The cost figures used to calculate this tariff are rather speculative becawse the technology for 3,000m deep subsea pipelines is not proven yet *Tariffs for plant extension are less by about $O.50lmmBtu Strategies for Importing Natural Gas The strategy for Pakistan is simple. A pipeine (or a LNG tanker) would deliver the gas near Karachi and inteal costs thereafter become common for either mode of exenal transportation. As the figures, represented in Table 3.2 below, show, it is obvious that the pipline overland mode of transportation from an extenal source is the most cost effective for Pakistan. In that case, the delivered cost of the gas (cost of produced gas of US$ 1.00 plus transportation) at Karachi is US$2.83/mmBtu against US$ 3.701mmBtu for delivered LNG. Talkng into account the netback values of US$3.0 /mmBtu for gas in industnial heat and steam raising and US$ 3.7/mmBtu for gas in coal fired power generation (see Table 1.3), it follows that gas, imported by pipeline, would be 30 the fuel to be preferred over oil and oil products in industrial applications, as well as over coal in power generation. The LNG option would only be viable when the gas is used in higher netback value applications such as residential and commercial use and combined cycle power generation. Because of its higher cost compared with the pipelined gas, such LNG option should -in the longer term- only be considered as complementary to a pipeline import scheme, when diversification of supply is of vital importance for the gas importing country. Table 3.2 Transportation cost for Pakistan (Karachi) Source Route Tariff Qatar/Iran Overland 1.83 Qatar/Iran Overland/shallow water 2.01 Qatar/Iran Shallow water 2.20 Turkmenistan Overland 1.86 Iran/Qatar/Oman LNG 2.70 For India, no simple conclusion is possible. Developing some more components of costs, namely for interna transporation (see Annex 3.4 for details of calculations), the following emerges, vide Table 3.3. Ahmedabad is taken as the entry terninal for all imported gas. From Alunedabad, inland pipelines would transport the gas to Bombay, Cochin or Madras, to choose some representative geographically dispersed destinations in the south. LNG, if imported, would move directly to these ports. Table 3.3 Inland transportation costs Listnce Tariff Route kms US$/mmBtu Ahmedabad-Bombay 500 0.36 Ahliedabad-Cochin 1,560 1.14 Ahmedabad-Madras 1,350 0.98 First, looldng at the Bombay-Ahmedabad sector which would also feed gas to the HBJ pipeline, the least cost choices come out as follows: 31 Table 3.4 Import costs of gas- Ahmedabad/Bombay Transmission Gas cost at Gas cost at Source Mode Destinton cost source destinaon $/mmBtu $/mmrBu $SmmBtu Oman Deep-sea Ahmedabad/ 2.30/ 3.30/ Bombay 2.66 1.00 3.66 Qatar/Iran Overland Ahniedabad/ 2.44/ 3.44/ Bombay 2.80 1.00 3.80 Qatar/Iran Overland/ Ahmedabad/ 2.68/ 3.68/ shallow Bombay 3.04 1.00 4.04 Qatar/Oman LNG Kandla/ Bombay 2.85 1.00 3.85 In all these choices, natural gas will compete with altemative fuels in a variety of applications including power generation with oil firing or, depending on the location, with domestic coal or imported coal as a fuel (see Table 1.3). Nevertheless, the Oman deep-sea option, it would seem, will take several years to get off the ground since first priority will be given by Oman to its ongoing LNG export project. In addition, it seems to date that the gas reserve position in Oman is not sufficient to allow for both the LNG project and a pipeline export project to India. Another complicating factor is that the technology for deep sea pipelines (2,500-3,000 meter of water depth), although considered to be feasible, is unproven, which makes the time and cost estimates for such a project somewhat uncertain. The Qatar/fIran overland pipeline option also will take time to materialize, particularly if the export is sought from Iran. From Qatar, the pipeline could be laid faster if the Qatar-Pakistan pipeline being sponsored by the currently active consortium of Crescent, TransCanada and Brown and Root is extended to India. There are political overtones to a pipeline through a third country. Further, there are also additional costs as third countries do charge transit fees. The fourth option, that of LNG from Qatar/Oman, is also worth consideration, specially considering that major oil companies are already involved in the projects to liquefy natural gas in both countries and are looking for markets to export LNG. In addition, the cost estimates for the LNG options for the Indian market are not very out of line with those for the pipeline options. Import of LNG does not pre- empt such pipeline transmission projects as could be developed in course of time. Taking the southern region in India, covering the four southern states, it is necessary to note that an efficient southern electricity transmission grid is in operation. It is being strengdtened and modernized under an ongoing Bank project, due to be completed in 1997. The south has a large unmet power demand. A combined cycle power plant to be located anywhere in the region with a capacity of about 2,500 MW to 5,000 MW would but partially meet the demand. The following table, Table 3.5, shows the economic cost of delivered gas at Madras and Cochin. These levels of cost make that the netback value for gas, when it is replacing coal in power generation (US $3.7/mmBtu, see Table 1.3), plus its environmental premium (US$0.5/mmBtu, see footnote of Table 1.3), is about break-even 32 with the cost of delivered LNG. It must be noted, however, that a more in-depth cost analysis is needed to assess the feasibility of gas fired power geneation for the Madras and Cochin regions. Table 3.5 Import costs of gas - Madrsl Cochin Gas cost at Transmission Gas cost at Source Mode source cost Destinaon destinion $/nmmBtru $mmBtu $/mmBtu Oman Deep-sea 1.00 3.28 Madras 4.28 Qatar/Iran Overl/shall. 1.00 3.66 Madras 4.66 Qatar/Oman LNG 1.0(' 3.22 Madras 4.22 Oman Deep-sea 1.00 3.44 Cochin 4.44 Qatar/Iran Overland 1.00 3.82 Cochin 4.82 Qatar/Oman LNG 1.00 3.10 Cochin 4.10 It will be seen that for the southem region, the LNG option appears the most attractive: Although LNG costs at Cochin could be a little lower than at Madras, the overall merits may lie in importing LNG at or near Madras. It is more centrally situated in the southern electricity grid. Further, from there radial gas lines of small diameters could supply industrial clusters in Hyderabad (Andhra Pradesh), Bangalore (Karnataka), Cochin (Kerala) and Madurai (Tamil Nadu). The prfce of LNG A caveat has to be entered here. As already mentioned earlier, the cost figures used in this report are only best estimates. Reality check is actually to negotiate contracts, all options being kept open, several of which have been indicated above. In this context it will also be pertinent to mention some well known facts about how LNG is normaly priced in world trade. LNG is priced either on a CIF basis (delivered at the quay of the receiving regassification teminal) or on a FOB basis (on board of the LNG tanker after liquefaction). Most pricing clauses in LNG sales contracts contain a pnce adjustment clause, that allows the price of LNG to be adjusted periodically to reflect changes in the price of the commodities, to which the LNG price is pegged. Most price indexation mechanisms refer to a 9 or 12 month averaged price of a basket of crude oils or to such averaged prices of crude, fuel oil and gas oil as parameters that determine the price of the LNG. Prices in the Asian market are usually on a CEF basis and have been rather flat over the last 7-8 years, in line with the rather stable (depressed) oil and oil product prices over the same time after the collapse of the oil prices in 1986. In Annex 3.5 an overviev; is given of CIF prices of LNG, imported by Japan fom the Middle East (Abu Dhabi) and of the average Japar -se CIF import prices of LNG, both over the period 1981-1991. Recent average import prices of LNG for Japan are in the US$3.1-3.3JmmBtu range, reflecting the somewhat lower oil prices compared with those of the early 1990s. When freight 33 differentials as between Japan and India ae considered, ndia should be able to secure a lower price than Jpan and so too, Pakistan. 34 4 Organizing and Financing Imports Issues In Gas Imports Elwnnts of a contract Large scale gas import projects, in which the gas is to be transportd over a distance of 1,000 km and more, require huge investments, not only in the upsream phase of such projects ( which includes the gas production and transmission facilities), but also in the downstream phase where an infrastructe for distribution to industrial and domesicJ commrcial gas users is essential. Large gas projects, therefore, require sophisticated contractual aanments to ensure that the involved parties have a balanced agreement and are able to live up to their comnitments over a long time period. The main elemets dt define the balance of an agrement may be divided into two types: (i) the cmmercial or ma.erud elements, which include mauers of deliveiy points, requured investments, and quality, quantity and pricing of the gas; (ii) the tedmica or praccal elements, which relate to handling of the gas stram, metering, testing, and so on. A ful overview is provided in Annex 4.1, where the left hand column shows the commerckl points that should be covered by the contract, and the right hand column shows the more 1dvacal considerations. In respect with quantities, it should be noted dtat in intemnational pipeine contracts a yearly as well as a daily or hourly maxmm and nimum quantity are stipated, with the purpose to define an steady load of the pipeline systeom A typical figurc for this load is dt it can fluctae between 80 pe.cent and 120 percent of the averaged yearly load. In addition, economic quantities for lovt distance pipeline tansmission woultd typicly require transporting about 1,500 mmcfd of gas; economic pawlges for LNG requie processing of about 2 milLon tons LNG per year (in one tran of about 300 mmcfd), which in power generation could provide the fuel to a 2,500 MW combined cycle plant. It may be a good idea to deal with many of hie tbchnical or practica elements of a contract in a separate, supplementay document, which can be chnged more 6Baed upoO: RDickel: Long team gas conact, Pdnciples and Applications and uon: BEaaso et aL: Intemaiona Gas Tnde, Potnti maor projects. Boih awe World Bank publicadons. easily than a contract. These supplementary documents may reflect new technical developments, new means of communication, or more advanced metering devices. Experience indicates that amendments to such supplementary agreements are often seen as reasonable and necessary and that they generally do not change the commercial balance of the overall contract. Risks Contrary to the marketing of oil, the marketing of gas requires investrnent in a long-term marketing infrastructure, consisting of a costly transmission and distribution system. The gas producer is thus bound to the customers down the pipeline and vice versa; this implies that in a gas chain, apart from the hydrocarbon jreserve risk and the price risk which are also present in the oil chain, there is a potential marketing risk for the producer of the gas. To cope with this additional risk, most intemational gas contracts contain a take-or- pay clause, which stipulates that the buyer conmits itself to pay for a substantial part (mostly 80 percent) of the yearly contacted quantity of gas, whether these quantities have been taken or not. Only in cases of force majeure the buyer will be exempted from this obligation. Other risks that govem international gas contracts are political risks and exchange risks, in case the gas is not paid for in hard currency. The political risks may influence the way gas business is conducted. For example, rates of return between 25 percent and 35 percent, and sometimes higher, are common criteria for interational companies operating in politically volatile areas; such rates may be double the level, acceptable for gas projects in more secure areas of the world. All risks, including the political, marketing, exchange and project risks, will have to be shared betweer. the project participants, such as the govemments, the project developers, the commercial lenders and the international financial institutions. More specifically, private sponsors are certainly looking for a firm commit in the form of a Government guaranteed take-or-pay contract. Commercial lenders will also look at such Government's guarantee to protect the stream of revenues of the project. This is understandable when one realizes that a large portion of the imported gas is to be used in power generation which is not viable today without a substantial change in the electricity pricing system. The role of one or more multilateral intemational institutions would be to mininize the political risk (performtance of the gas utilities) and the market risk (back-up of the take-or-pay contract). They are also well-equipped to provide technical assistance and help in the financial structuring of the projects. Since the investment reqirements as well as the political and marketing risks in gas import projects are considerable, participation of international financial institutions in those projects seem essential. They can provide for the development of appropriate secunty packages and the use of guarantee instruments, such as recently developed by the World Bank. They can also play a major role in facilitating the necsary cooperation among project developers, commercial investors, govemments and other major players in the projects. 36 Organizing Imports The following discussion takes the case of India as an example. However, the same observations apply equally to Pakistan and the corresponding institutions in dtat country, such as Pakistan State Oil Limited, Sui Northern Gas Pipelines Limited and Sui Southem Gas Company, and Oil and Gas Development Corporation. India has an established system for importing crude oil and oil products. This is primarily the responsibility of the Indian Oil Corporation (IOC), a state owned corporation, which is under pardal privatization. Having been in the import business for several years, IOC has acquired expertise in international negotiations and tading. IOC has maintained close contacts with the oil exporting countries, the international commercial banks, the domestic financial market and a whole lot of other players in inteational business. Its own status as a succesful company and a financial giant, with 'Fortune'- listing, gives it a prestige which should be put to use when India launches projects for import of natural gas, which is but an extension of IOC's role as the main importer of oil. The Gas Authorty of India Ltd. (GAIL), also a wholly owned state corporation, has been engaged in marketing domestic gas and operating the HBJ pipeline. In recent times, GOI has called on GAIL and Engineers India Ltd., a state owned corporation for engineering and construction supervision of state projects in the oil and gas sector, to advise it on gas imports. In major policy shifts, GOI and the State govemments have been encouraging the private sector to invest in energy infrastructure projects, both on grounds of speedier execution of such pmjects and providing investments fnances. The ENRON project for power generation in Maharashtra, which is designed to use imported gas in due course, is a major break-through in this respect. Ineia's own private sector is dynamic in the new economic climate of a near free market. There is a thirst for foreign capitaL which too is eager to come to India in its different forms, namely portfolio equity, direct investment, private loans and bonds. In organizing import of natural gas, each of the advantages as outlined in the preceding paragraphs should be pressed into service. GOI should prepare an indicative plan for import of gas and probably issue a paper. One of the important issues that should be adressed by the Government in preparing the gas import plan is the notion that any gas import scheme cannot easily be implemented without a (dramatic) change in the current energy pricing policies of the country. The system of subsidizing certain energy products should be abolished and a pricing policy, based on sound economic principles, should be put in place7. Without undertaking the necessary pricing reforms the market risks of embarking in any gas import scheme are simply too high. For the same reason, the gas allocation policy of the Govermnent should be eliminated. Continuation to allocate gas to uneconomic uses (e.g. as a feedstock for new fertlizer plants) implies continuation of subsidies. In addition, it would be difficult to mobilize resources for the construction of 7 It is perhaps useful to notice here that a non-subsidized system of international prices of competing fuels was the basis for assessment of the netback values for gas in its various applications. 37 transmission and distribution networks if the concerned gas utilities were obliged to supply gas to uneconomic consumers, and if they were not protected by a sound pricing policy. The gas importing country, in addition, should be aware that it is strategically in a vulnerable position when it becomes overly dependent on a single energy source. For the case of India, it can be seen from Fig. 2.2. that, at least up to the year 2003, the 'energy-mix" for the country is not unbalanced and there exists no excessive dependency on imported e,iergy8. Especially for the longer term, when domestic energy sources are becoming more and more depleted, it is important for any energy importing country to have in place an import strategy which assures that there is an adequate diversification of energy supply from foreign sources. Taking into account what has been stated above, IOC should then move to 'bring into being' the several projects, availing itself of technical assistence from GAIL and EEL. The phrase 'bring into being' is deliberately chosen. IOC should invoke private interest- it is likely to be foreign interest by and large- and limit its own direct implementation of any component of a project to the minimum required for all other pieces to fall into place. Gas import projects are of two kinds: import by pipelines and import as LNG, and may be arranged in the following modules: w inworts (i) Gas production in the exporting country Cii) Pipeline transportation (iii) Gas sale in India Module (i) is the responsability of the exporting country, most likely in a joint venture with one or more intemational oil companies; the joint venture will raise the finaces necessary to develop the gas fields and make the gas available at the pipeline inlet Module (ii) should be executed by a consortium of mainly foreign companiesfmvestors. Module (iii) will be the responsibility of IOC9 with the active involvement of GAIL. IOC will negoiae the terms and conditions of the contract to buy stated quantities of natural gas at stated times. Receiving terminals, storage etc., should be provided by IOC. If the supply is to power plants, IOC/GAIL will negotiate the sale in due time, far in advance of contacting for purchase of gas, and ensure that the power plants are installed or ready in time to use the gas. If the supply is to industries or other consumers, IOC/GAIL will ensure that the sale contracts are signed in sufficient advance ime and the internal distribution infrasucture is in place. It may be that the consumers will finance the infrastructure, particulady long dedicated pipelines to industrial centers and agree to open access for other consumers to make use of the pipelines at later dates. 8Fig.2.4. shows that the same, though to a lesser extent becaue its relatively higher import dependency, is true for the case of Pakistan up to the year 2003. 9 IOC will include GAIL and EIL as necessary. 38 LIVG b=utr Under this mode, the modules are the following: (i) Gas production in the exporting country (ii) Liquefaction of gas (iii) Transportation by LNG tankers (iv) Regassification (v) Gas sale in India Modules (i), (ii) and (iii) are likely to go together and lie in the domain of a foreign consortium of companies. Or, one consortium may handle modules (i) and (ii) and another module (iii). IOC would negotiate for purchase of LNG, either on FOB or on CIF basis; in the fonner case it would also negotiate for transportation. But regassification would be with IOC as also the further sale in India. This would correspond to module (iii) considered under the Pipeline transportation mode. It may be necessary to develop cross country trunk pipelines, e.g. connecting the existing western system to the southern region of India; this work will fall to GAIL to execute. Procedures as presently obtain for strengthening the HBJ pipeline would apply. Financing the Projects The most important challenge in gas import projects is the arrangement of a viable financing scheme. Most common is the "build-own-and-operate" (BOO) scheme, in which pnvate investors mobilize the required capital, build the transmssion infiastructure (LNG or pipeline), and operate the system under a take-or-pay contract with a gas company in the importing country. The success of such a scheme would require that (i) The private investor has the finanmcial capacity to provide the equity funds of about 25-30 percent of the project cost. In many gas export projects the project cost, excluding the downsweam market development, is in the order of US$4-5 billion, implying equity investments of US$1-1.5 billion. Many of the proponents of BOO schemes do not have a financial capacity close to this level. (ii) An instrnent is developed to cope with political rislk Private investors do not enter easily into situations where there is significant political risk. This clearly becomes a more serious consideration when large invesments with long gestation periods are at stake. Under these circumstances, a guarantee insument would economize private sector participation considerably. This kind of instrument can be developed in conjunction with private insurance programs or with ltilateral institutions. Potential financiers of intermional gas projects will also be greatly encouraged to participate, when most or all of the following conditions are fiulfilled as well: (iii) The project has full political support of the exporting and importing governments, as well as of the governments through whose jurisdictions the gas will be transited. 39 (iv) The consortium that is launching the project may have to include one or several major international oil or gas companies. (v) The implementation of the project must be in reputable and experienced hands. (vi) Long term contracts with unconditional conunitrnents, including take-or-pay clauses, must be signed. Recommended Strategy Based on an analysis of the above factors, the tentative recornmended strategy for import of gas should incorporate the following: * Multiple vs. single gas sources. A multi-source approach is possible in view of the size of the need for imports of gas of 4,500 mmcfd and would alleviate political risk perceptions. * Total investment needs. The total investment needed for natural gas import should include also the downstream infrastructure necessary to deliver the gas to the consumer. * Coordintion of supply and demand In view of the large investment requirements, both upstream and downstream, graduated market development in phase with the upsteam construction is highly desirable. The economies of scale that may be possible through larger upstream systems need to be balarnced with the possibilities of asynchrony in the completion of the downstream markets. * Allocation and management of risks. The political, market, commercial and project risks will have to be shared between the govemments, the developers and the international financial institutions. * international fiancial institutions partic4mitio7L Since both the investment requirements, political and market risks of these projects are so great, the participation of the international financial institutions seems essential. The role of these institutions could be to provide technical assistance, help in the financial structuring of the projects, development of appropriate security packages, and use of guarantee instruments. Lead instutions for project development. There is a need for clarity in the responsibility and the process for development of a project which is complex, involves a large number of domestic agencies, and is intemational in scope. The countries could nominate specific agencies to develop specific projects as oudined above, but with an oversight committee for final decisions, within a specified fime frame. 40 Annex 1.1 Prices of oil products and natural gas in India. Pakistan and OECD-Europe as Rer l/11993 OECD ILmdk* Pukdstm"* Europe Automotive: regular gasoline (US ctsAlitre) 64.5 45.2 n.a. diesel (US ctsAitre) 21.9 19.6 57.9 Household: kerosene (US cts/litre) 9.4 19.3 363 LPG (US cts/kg) 18.2 20.4 n.a. Natural gas (US$1mmBtu) 1.80 1.41 12.33 Indushid: Fuel oil, general ind. (US$Itor) 185.4 91.4 130.9 Fuel oiL fertilizer ind. (US$Iton) 110.1 91.4 n.a Naural gas, general ind. (US$ImmBtu) 1.80 (coast) 2.12 4.22 2.73 (HBJ) Naturalgas,ferdlizerind.(USSImmBtu) 1.80 (coast) 0.92 n.a 2.73 (HBJ) Bombay-area **Islamabad-area Sources: Ihe World Bank: -A survey of Asia's Energy Pices lEk IEA Statistics. 2nd quater 1994 Annex 1.2 INDIA Coal Production 1980.1992 Year Production (mmtoe) Yearly growth(%) 1980-81 55.82 - 1981-82 60.87 9.0 1982-83 63.95 5.1 1983-84 67.73 5.9 1984-85 72.23 6.6 1985-86 75.56 4.6 1986-87 81.23 7.5 1987-88 88.08 8.4 1988-89 95.35 8.3 1989-90 98.44 3.2 1990-91 103.75 5.4 1991-92 112.35 8.3 1992-93 116.72 3.9 Soot= CME. CmuE Suac m India, May 1993 Annex 1.3 page I Netback value for gas in Dpw i on For the calculation of the netback value of gas in power generation the following assumptions have been used: O fmied pant Coal firedplant CC Gas fired pant Capacity (MW 600 60 600 Unit invesment cost (US$/kW) 900 1,000 600 Costcontgency(%) 15 15 15 Operatonal cost (% of investmernt cost) 2 2.5 4 Fuel dfciency (%) 37 37 45 Cost of coal (USShmmBtu) - 1.70 Cost of fuel oil (USSfton) 105 _ Constuction period of plant 4 years 4 yeasu 4 yam Stt of power production in 4th year in 4th year in 4th year Discount facto (%) 15 15 15 The netback value for gas is calculad as follows: (1) Calculate the net present value of the total cost (capex, opex and fuel) for oil fired resp. coal fird plant (2) Calculate the net present value of the cost, excluding fuel (=gas) cost, for the combned cycle plant (3) Calculate the difference of these two net present values (4) Divide that difference by the net present value of the quantity of gas that is required in the gas fired plant to generate the same power as the coal fired or oil fired plants (5) The quotient is the netback value for gas. I _________ ____ ~~~~~~GAG VALUE IN POWER ____ ________ 00GMW COAL PLANT,WESTCOAST ____600 MW 0.0. PLANT __ Gfdscnoy 37% __ _ _ _ __ _ _ _ _ EfficIency 45% _ _ _ _ _ AP fM W 600 __ _ __ _ _ _ _ __ _ _ _ __ _ _ __ _ __ _ 600 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ GW/y 3993 _________W_ ____ Whyr.... 3993 _______________ (at_ _ __ __ __6655 _ __ _ __ __ _ __ _ (at 66 5 H) _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ Jni Iny.coutl1 $1150/kW ______________________nit -vcost, I *6901kW _____ _____ ___ ____ 5% contIngem ____________________________15% contlnagn _____ _____ _____ ____ -- Oo 2.5% of kwvestm. ______- .- ____ pe!_4% of lnvestm. __ ________ _______ 60 MW COAL, WTOCAST ___MW_COMBINED_CYCLE CAPEX FO CONS9'N FO COST - u- CAPE)X. CAPEX OPEX -CAPEX, GAS CO-NsN GAS CONSN GAS CONSN ___________ InoI.aont. net b ails plant gate _ __ _ _ OPEX __ _ _ __ _ _ __ _ _ __ _ _ _ __ __ _ _ _ __ _ (mm USOL (mm MMB ~iu (mtn USSINI (mln US*IN (mln tIS$L -mln US$) 3:1Aff-A!1U! ( rn!).~nrSI)m MtI t9994 104 0 0.00 0 _ 104.00 82 0 1 2- _ .0 0- 0 1995$ 345 0 0.00345.00 166 0 166 0 0 0 l996 172 0 0.00 0 172.00 104 0 104 _000 t99? 69 36.62 62.60 17.3 148.90 62 16.6 78.8 841 _ 2.30 30.30 1999 0 38.82 62.60 73 7.0 0186__ 16. 6 - i.84 2i.-30 - -30.'30 tee.ss 0 36.82 62.00 17. 99501, 8. 4 .3-03 5000 0 36.62 62.60 17.3 79~~~~~~~~-i.90 0 - 6616.6 841 .0 03 5001 0 36.82 62.60 17.3 799 16.6 168812.30 30.30 t005 0 36.82 62.60 17.3 _ 79.90 0 1 6.6F' 16.6 _ 841 _ 2.30 30.30 5008 0 36.82 62.60 iT i3 79.90 0 16.6- 16.6- 84 1- - 2-.30' -30.30 5003 0 36.82 62.60 1 7.3 79.90 ___ 66_ 1. 4 .0 30.30 5005 0 36.82 62.60 17.3 79.90 0 1. 666123 03 R009 0 36.82 62.60 17.3 79.90 0 - 16-.6 -16.6 841 2.30 30.30 200? 0 36.82 62.60 17.3 79.00 0 16.6 16.6 841 __ 2.30 .30,.30. 5009 0 36.82 62.60 17.3 179.90 0 16.6-. 16.6 _81_ _2.0 30.30 5009 0 36.82 62.60 17.3 79.90 0 16.6 16.6 841 2.30 _ 30.30 50ot 0 36.82 62.60 17.3 79.900 0- 16.6a 16.6 84.3 0-.30 5019 0 36.82 62.60 17.3 -~79.90 0 16.6 16.6 841 2.30 30.30 R012 0 36.82 62.60 17.3 79.90 0 16.8 16.6 8123 03 5018 0 36.82 626 73 79.90 01.186 _ 841 2.30 30.30 *014 0 36.82 62.60 17.3 79.90 0 16.616. 8412.3-0- 30i.30-- 5095 0 36.82 62.60 17.3 79.90 0 16.6 16.6 841 -~2.30 30.30 TOTAL 190 699.62 1169.3 387_ 2208.05 414 -1542 4i97436 NPV0S1% 103.05 110.07 255.11- 705329400.61 6763662 425.94 9.39- 12.4 _ _ _ _ _ _ _ _ _ _ _ ________ __ ________ __ _______ ___ ___ _______ ___ _______N etback vers s al3 7w _________ ~~~~~~~~~~GAS VALUE IN POVWER _ _ _ _ __ _ _ _ _ _ _ _ _________ 600~O MW OIL PLAN4T ON__ _ _ _ _ _ MW 0.0. PLANT_ _ _ __ _ _ _ _ Efficiency 37% _____________ Effiency 45%-_ _ OW v 3993 __ _ __ _ WIVyr 3993 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ (at 6855H1) I _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ at 6655 H) I_ _ _ _ _ _ _ _ _ _ nit lnv.oest,nl $1 035/kW ______ _____ _____Uni Inv-cosl Incl 690/kW ________ ______ 5% contInue c __ _ _ _ _ _ _ __ _ _ _ _ _ __ _ _ _ _ _15% contlnpenc __ _ _ _ _ _ _ _ __ __ _ _ _ _ _ _ _ _ Opo 2 of Investm. _ _ _ _ _ _ _ _ _ _ _-_ _ _ Oc 4% of Investm. _____ __ _______ ~~~~600 MW OIL GM__ __ ____ ___ ___'0 MW COMBINED CYCLE _______ _______ ~CAP'EX FO CONSN FO COST OPEX CAPEX+ CAPEX OPEX -- CAPEX+ GAS CONSIN GACS CO-NSN MAM CONSN ___________Incf.cont. "et basis elant gate OPEX _____ PE _ ___ _________(mm US$1 mm MMBtw,(mm USSIv (mln USOMy (mln US$) (min US$ (mmn UMI (min US$) (mlm m3tl) (mn3ld) min MMBtU 1994 14000 - 012.00 820 82 0__00 1995 373 0 0.00 0 373.00 166 0 166 0 __ I99e 03 0 0.00 0 93.00 104 - 0 -104 0 0- 0 #997 31 36.82 92.27 12.4 135.67 62 16.6 78.6 641 _ _ 2.30 30.30 1998 0 36.82 92.27 12.4 104.67 0 16.6 16. __ 41 -2.30 30.30 1999 0 36.82 92.27 12.4- 104.67 0I16.6 16.6 6.41 _ 2.30 .30.30 1000 0 36.82 92.27 12.4 104.67 0 16.6 16.6 A 41 -2.30- 30.30 2001 0 36.82 92.27 12.4 104.67 0 --16.6 18.6 841 2.30 30.30 200* 0 36.82 02.27 12.4 104.67 0 16.6 16.6 841 2.30i 30.30 2008 68 22 24 14 0 0 1.6 6. 84 _ 2.30 _ 03 1004 0 8~~~~~6.82 92.27 12i.4 104.87 0 16.6 6. 812.030.30 5005 0 368 2.27 _124 104.67 0 1661. 4 .30 30.30 2006 0 36.82 92.27 12.4 104.67 0 166 6.842.030.30 *007 0 36.82 92.27- -1.4 104.67 0 16.6 16.6 841 2.30 30.30 agar 0 36.82 92.27 12.4 104.87 0 '16.6 1_16.6 841 2.30 30.30 S00 0 36.82 92.27 12.4 104.67 0 16.6 __ 1.6. 841 2.3-0 - -30.30 logo 0 36.82 92.27 12.4 104.67 0 16.6 16.6 841 2.30 30.30 g01a 0 36.82 92.27 12.4 104.67 - 0 16.6 16. 841 2.30 30.30 201* 0 ~~~~~36.82 92.27 _12.4 104.67 0 __ 16.8 . 16.6 __ _841 2.30 -- 30.30 _ g2018 0 36.82 92.27 1 2.4 104.67 0 16.6 16.6 841 2.30 30.30 1014 0 ~~~~~~36.82 92.27 1-2.4 104.7 6_ 16.6 8§! 41 - 2.30 30.30 1015 0 36.82 ~~~~~ ~~92.27 12.4 104.67 0 1 16.6 16.6 8 41 _9.30 30.30 TOTAL 621 699.62 1753.2 235.6 2609.82 414 315.4 729.4 15072 43.76 _ 575.6324 NPVO1I% 463.74 150.07 -376.06 50.54 695.24 300.61 67.65 368.31 3425.94 9.29 123.47 _______ _______ _______ _______ _______ ~~~~~~~~~~~~~~~~~~~~Nstbek verus off 4.27 Annex 2.1 INDIA GAS DEMANDISUPPLY (numemd) 1992 1994 1996 1998 2000 2002 2003 DemnandIigh 43.3 62.3 85.0 112.4 148.6 193.3 223.2 DemandMedium 43.3 52.6 65.7 85.5 113.8 153.4 180.3 Sipply 43.3 52.6 60.7 67.7 73.1 73.1 73.1 Swn mmIU Gcfa e aloe Asccia.. WONd BU Annex 2.2 PAKISTAN GAS DEMANDISUPPLY (mmefd) 1992 1994 1996 1998 2000 2002 2003 Demand High 1550 1954 2445 2885 3322 3780 4020 DemandMedium. 1550 1914 2275 2645 3016 3420 3635 Supply 1550 1824 2110 2410 2650 2850 2940 Sources: Refuenced World Bank Study EXPORT POTENTIAL FOR GAS & STATUS OF EXPORTS Annex 3.1 Reserves Prominent fields for Country proved and export to Asia LNG Pipeline for export to _probable -_Asia hun 700Tcf S. Pars and N. Pars No developinent IGAT lines to FSU have country as a offshore undeveloped. ceased carrying gas; a study whole Basic designs for for a pipeline to India is to developing S. Pars to be be taken up, jointly sponsor- prpared by an ed by India and an; also, a international engineering feasibility study for a pipe- company being selected. line to Pakistan has been For N. Pars, desultory agreed upon between the two negotiations with Shell governments in progress Oman 20 Tcf Barik, Mabruk, Saih LNG export of 6 mint to far Pipeline to India was under in various Nhayada and Saih Rawl cast planned by a consortium: consideration-: a shallow fildds and of fields onshore being Government, Shell, Total and water route along Iran & variable dcveloped for 6.3 Tcf. Japanese companies; target Pakistan continental shelf quality year, 2000; 7 Tcf dedicated. (one 35" 2000 km) or a direct deep sea route (two 24" 1440 kn).The LNG consortium (Oman, Shell, Total and Japanese) apparently feel that the reserves are not adequate for both LNG and the pipe- line to India.Tbe latter seems to be on indefinite hold. Qatar 160Tcf Dome field, extension of Eoject I: QGPC, Total, Mobil Brown & Root of USA, Iran's S. Pars Marubeni in a consortium com- TransCanada Pipelines and mitted to supplying Japanese Crescent Petroleum of the power utilities 4 m-t p.a. Emiates are sponsoring a starting 1997; a further 2 mmt pipeline to Pakdstan, 1600 p.a. available. Ikm along offshore Ian and Eject 2: QGPC, Mobil close Pakistan. Linkage with India to agreeing to sell Korea Gas envisaged by the sponsors. 2.4 mmt p.a. in 1998; Enron Capacity 2 bcfd, diameter 40" in India likely to take 2.5 mmt or more p.a in phases froi-r 098; a further 5.2 mmt p.a. available for negotiation. Riect 3: Eurogas Project, 6 mnut p.a. failed due to non- agreement on price with Italy. Er:iet4 Under discussion with Elf-Sumitomo for 4 mint p.a. TurkeI enistan 80 Tcf Sovetabad in the south Landlcked Pipeline via Iran and country as a near hun Pakistan possible-onland. whole UAE. Substantial Das Island ficility-4.6 m-t No pipeline considered. p.a exports done. Further expansior. by 2 nmt p.a. prcticable, would be economical too. Yemen Substantial Hunt & Exxon have a feasibiity study for 5 mmt p.a. But all on hold now. IRANIQATAROMAN -BOMBAY LNG O | 600 MMCFD _ ____MMEXPENXD USS OPERAlING COST. I US$ Year Gassales Prolect tariff Gmss revenue Uwuefac S ReaassicatxL Uquefac .i R Net revenue (2 shIps) _ MMT p.a. US$/ MMBtu MM USS MU US 1 0 3.23 0 120 38 34 0 0 0 -192 2 0 3.23 0 320 100 90 0 0 0 -510 3 0 3.23 0 480 150 135 0 0 0 -765 4 0 3.23 0 400 125 112 0 0 0 -637 5 1 3.23 162 280 87 79 0 0 0 -285 6 3 3.23 485 0 0 0 75 37 24 349 7 4 3.23 646 0 0 0 75 37 24 510 8 4 3.23 646 0 0 0 75 37 24 510 9 4 3.23 646 0 0 0 75 37 24 510 0 9 4 3.23 646 0 0 0 75 37 24 510 11 4 3.23 646 0 0 0 75 37 24 510 11 24 3.23 648 0 0 0 75 37 24 510 13 4 3.23 646 0 0 0 75 37 24 510 14 4 3.23 646 0 0 0 75 37 24 510 15 4 3.23 646 0 0 0 75 37 24 510 16 4 3.23 646 0 0 0 75 37 24 510 17 4 3.23 646 0 0 0 75 37 24 510 17 4 3.23 646 0 0 0 75 37 24 510 19 4 3.23 646 0 0 0 75 37 24 510 20 4 3.23 646 0 0 0 75 37 24 510 21 4 3.23 646 0 0 0 75 37 24 510 22 4 3.23 646 0 0 0 75 37 24 510 23 4 3.23 646 0 0 0 75 37 24 510 24 4 3.23 646 0 0 0 75 37 24 510 25 4 3.23 646 0 0 0 75 37 24 510 26 4 3.23 646 0 0 0 75 37 24 510 27 4 3.23 646 0 0 0 75 37 24 510 28 4 3.23 646 0 0 0 75 37 24 510 29 4 3.23 646 0 0 0 75 37 24 510 1,600 500 450 1,800 8s8 576 9,690 At overall tadf _________ _________ of 3.23/MMbtu I RR 15.00 Lbq 1.08 61% _ _ _ Ship .69 21% _ __ 9Regas .56 18% _ w If liquefaction lnvestm.=3/4 *then tadrff US$2.83 MM Btu at Irra.15 ___________ ___________ If liquefaction Investm.m1/2 ,then tarff - US$2.43/ MM *tu at Irr=.15 _ ~IRAATAa - *KARACHI LNG100 UF _~~~~~~~~~~ms . E E T LZ 0," Ut$ Vat Gsaed Pftwet kt af uvnue Uetao S R LIquefac hP R _ NOt NeVenue _ l (4 * 1~~~~~~~~~~~~25.000) _ MMTPQ US$ / MMIu MMUSS (1 a 00.000) 1US$ 1 0 2.70 0 300 91 80 _ 0 0 0 _451 2 0 2.70 0 800 240 160 o o o -1,200 3 0 2.70 0 1,200 360 240 0 0 o - 1,800 4 0 - 2.70 0 1000 300 200 O O O -t,S00 5 4 2.70 540 700 209 140 0 0 0 -509 6 8 2.70 1,080 0 0 0 180 88 40 772 7 11 2.70 1,4865 0 0 0 180 s8 40 1,177 8 11 Z.70 1,485 0 0 0 180 88 40 1,177 9 11 2.70 1,485 0 0 0 180 88 40 1.177 10 11 2.70 1,485 0 0 0 ISO as 40 1,177 12 11 2.70 1,485 o o 0 180 as 40 1,177 13 . 11 2.70 1,485 0 0 0 ISO as 40 _1,177 14 11 2.70 1,486 0 0 0 1,8 as 40 1_177 15 11 2.70 1,485 a a 0 180 88 40 1,177 1l8 11 2.70 1,485 0 0 0 160 88 40 1,177 17 11 2.70 1,485 0 0 0 40 1,177 16 11 2.70 1,486 0 0 0 180 88 40 1,177 19 11 2.70 1.4865 0 0 0 180 88 40 1,177 20 11 2.70 1,485 0 0 0 180 88 40 1,177 21 I 1 2.70 1,485 0 0 0 180 88 40 1,177 22 11 2.70 1,485 0 0 0 180 88 40 1,177 23 11 2.70 1,485 0 0 0 ISO as 40 1,177 24 11 2.70 1,485 0 0 0 ISO as 40 1_177 25 11 2.70 1,485 0 0 0 ISO8as 40 1 177 26 II 2.70 1485 0 0 0 ISO as 40 1_177 27 11 2.70 1,485 0 0 0 180 _ a88 40 1,177 28 11 2.70 1,485 0 0 0 180 88 40 1,177 29 11 2.70 1,485 0 0 0 ISO so 40 1,177 TOTALS 265 35,775 4,000 1,200 Boo 4,320 2,112 - 960 22,383 At overall tarHt t of 2.701MMbtu [RR1 _ _ I R R L_q 1.76 06% _ _o _ Ship .5_ 22% _ _ _ R_ .3ff 13% _ _ _________ _____ If_ I Iuefaction Investm.n3/4 ,then tarilf = US$2.34/ MM Btu at Irr=.15 _ If liuefction Investm..1/2 Ithen tadifl = US$1.98U MM Btu at Irr=.15 Annex 3.3 Page I TURKMEN_MED0ABAD_N_P iPELINEENA E ANALYSIS Year Gasvolume Pipeline-tariff Gross revenue Investment Opeiat. cost Net revenue _B_ dcf p.a. $/MMBtu MM USS MM US$ SM US$ mm USS 1 0 2.51 0 576 0 -576 2 0 2.51 0 1,388 0 -1,388 3 0 2.51 0 1,759 0 -1,759 4 0 2.51 0 1,062 0 -1,062 5 132 2.51 338 294 47 -3 6 265 2.51 678 294 65 319 7 397 2.51 1,016 147 110 759 8 529 2.51 1,354 0 143 1,211 9 529 2.51 1,354 0 143 1,211 10 529 2.51 1,354 0 143 1,211 1 1 529 2.51 1.354 0 143 1,211 12 529 2.51 1,354 0 143 1,211 13 529 2.51 1,354 0 143 1,211 14 529 2.51 1,354 0 143 1,211 15 529 2.51 1,354 0 143 1,211 16 529 2.51 1,354 0 143 1,211 17 529 2.51 1,354 0 143 1,211 1 8 529 2.51 1,354 0 143 1,211 19 529 2.51 1,354 0 143 1,211 20 529 2.51 1,354 0 143 1,211 21 529 2.51 1,354 0 143 1,211 22 529 2.51 1,354 0 143 1,211 23 529 2.51 1,354 0 143 1,211 24 529 2.51 1,354 0 143 1,211 25 529 2.51 1,354 0 143 1,211 26 529 2.51 1,354 0 143 1,211 27 529 2.51 1,354 0 143 1,211 28 529 2.51 1,354 0 143 1,211 29 529 2.51 1,354 0 143 1,211 Total 12,432 31,828 5,520 3,368 22,940 NPV @ 15% 1,594 _ 4,081 3,643 435 _________ _________ IRR 15.01 Annex 3.3 Page 2 CIATAR-AHMED BAD(I )ODSHORE PPEUNE ECONOMIC ANALYSIS Year Gasvoiume Pipeline-tariff Gross revenue Investment OperaL cost Net revenue Bcf p.a. $IMMBtu MM US$ Mm USS MM USS LMM US$ 1 0 2.44 0 618 0 -618 2 0 2.44 0 1,236 0 -1,236 3 0 2.44 0 1,590 0 -1,590 4 0 2.44 0 1,114 45 -1,159 5 132 2.44 329 290 70 -31 6 265 2.44 660 290 110 260 7 397 2.44 988 142 136 710 8 529 2.44 1,317 0 136 1,181 9 529 2.44 1,317 0 136 1,181 10 529 2.44 1,317 0 136 1,181 11 529 2.44 1,317 0 136 1,181 12 529 2.44 1,317 0 136 1,181 13 529 2.44 1,317 0 136 1,181 14 529 2.44 1,317 0 136 1,181 15 529 2.44 1,317 0 136 1,181 16 529 2.44 1,317 0 136 1,181 17 529 2.44 1,317 0 136 1,181 18 529 2.44 1,317 0 136 1,181 19 529 2.44 1,317 0 136 _ 1,181 20 529 2.44 1,317 0 136 1,181 21 529 2.44 1,317 0 136 1,181 22 529 2.44 1,317 0 136 1,181 23 529 2.44 1,317 0 136 1,181 24 529 2.44 1,317 0 136 1,181 25 529 2.44 1,317 0 136 1,181 26 529 2.44 1,317 0 136 1,181 27 529 2.44 1,317 0 136 1,181 28 529 2.44 1,317 0 136 1,181 29 529 2.44 1,317 0 136 1,181 Total 12,432 30,941 5,280 3,353 22,308 NPV 0 15% 1,594 3,967 3,477 484 _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ IR R 15.02 INDIA: AHMEDABAD-COCHIN TRANSPORT OF NATURAL GAS (1560 KM.) YEAR INVESTMENT MAINTENANCE GASVOLUME GASVOLUME GASVOLUME TARIFF F_VENUES NET BENErr $ million $ millon mmcfd bom mln mmBtu $US /mmBtu $ million $ million 1 300 -300.00 2 600 -600.00 3 1550 -1550.00 4 625 -625.00 5 65 1500 15.49 553 1.14 630.84 565.84 6 6________ 85 1500 15.49 5C.~.r 1.14 630.84 565.84 7 _ 65 1500 15.49 553 1.14 630.84 565.84 8 65 1500 15.49 553 1.14 630.84 565.84 9 65 1500 15.49 553 1.14 630.84 565.84 10 _ 65 1500 15.49 553 1.14 630.84 565.84 11 65 1500 15.49 553 1.14 630.84 565.84 12 6 5 1500 15.49 553 1.14 630.84 565.84 13 _ 6 5 1500 15.49 553 1.14 630.84 565.84 14 65 1500 15.49 553 1.14 630.84 565.84 15 6_ 85 1500 15.49 553 1.14 630.84 565.84 16 65 1500 15.49 553 1.14 630.84 565.84 17 65 1500 15.49 553 1.14 630.84 565.84 18 _7_ 65 1500 15.49 553 1.14 630.84 565.84 19 65 1500 15.49 553 1.14 630.84 565.84 20 65 1500 15.49 553 1.14 630.84 565.84 21 65 1500 15.49 553 1.14 630.84 565.84 221 -- 65 1500 15.49 553 1.14 630.84 565.84 23 65 1500 15.49 553 1.14 630.84 565.84 24 65 1500 15.49 553 1.14 630.84 565.84 25 65 1500 15.49 553 1.14 630.84 565.84 26 65 1500 15.49 553 1.14 630.84 565.84 27 65 1500 15.49 553 1.14 630.84 565.84 28 65 1500 15.49 553 1.14 630.84 565.84 28 65 1500 16.49 553 1.14 630.84 565.84 29 65 1500 15.49 553 1.14 630.84 565.84 Total 3075 1625 37500 _ 387.36 _ 13834 _ 15770.93 11070.93 ___ _ _ _ _ _ __ _ __ IRR 15.00 Annex 3.5 Prices of LNG for Japa Year Average LNG prce Abu Dhabi LNG price 1981 5.83 6.61 1982 5.74 6.27 1983 5.16 5.47 1984 4.90 5.21 1985 4.99 4.89 1986 3.98 4.37 1987 3.29 3.29 1988 3.22 3.19 1989 3.26 3.09 1990 3.60 3.29 1991 3.98 3.90 Fffst half of 3.09 3.11 1994 Soure: Cedigaz World LNG trade Annex 4.1 Commercial versus lElementsof a Contract Delineadon of spheres Define delivery point(s) Handling of gas strms Investmnt to realize the project Define investment obligation of both sides Quantity Comnitments Metring, operang mles, Sharing of risks Iformaion flow Exceptions (force majeure) Penaltyfmcentive schemes Quality Specification Specification definition Consequences, if offspec Applicable test information on quality Price Detrmination of prce formula Billing and payment rules Due date of payment Minimum pay prioe, default rebates Taxes Currency Review of the price formula Information Scope of information to be given to the Means of omion other side