SPECIAL ARTICLEEconomic & Political Weekly EPW september 13, 200857The Economics of Iran-Pakistan-India Natural Gas Pipeline Anoop SinghThis paper examines the economics of the landed price of natural gas in India through the Iran-Pakistan-India pipeline in comparison with the existing agreements for the import of liquefied natural gas. It reviews the natural gas demand and supply scenario in India, and assesses the efficacy of the pipeline in the context of energy security. The paper analyses the economics of natural gas supply fromIPI pipeline in terms of cost of power generation and the cost of delivered power to consumers. It also briefly discusses the process of negotiations for the IPI pipeline.Anoop Singh (anoops@iitk.ac.in) is with the Indian Institute of Technology, Kanpur.The growth of the Indian economy would significantly depend on the availability of energy. Given the resource mix available in the country, the country’s dependence on imported fuel – oil, natural gas, coal and nuclear fuel – is expected to grow in the future. Diversification of the sources of fuel supply, regional level energy sector planning investment in infrastruc-ture to support regional cooperation in the energy sector are identified as some of the key steps to help improve the energy security scenario in south Asia [Sankar et al2005]. In order to secure the long-term energy requirements of the country, the idea of importing natural gas through pipelines has been gaining shape for quite some time.1 Among three such proposals that have been put forward in the past, the negotiations over the Iran- Pakistan-India (IPI) natural gas pipeline have yielded positive results. Concerns have been raised regarding the success of the overland IPI pipeline due to non-congruence of politico-economic and strategic objectives of the three countries [Pandian 2005]. There has largely been a positive outlook for such cooperation among the three countries [Tongia and Arunachalam 1999; Sen 2000; Verma 2007; Srivastava and Misra 2007]. Amidst the exist-ing geopolitical equations, the concern for long-term security of supplies through theIPI pipeline has grabbed a lot of attention [Tongia and Arunachalam 1999; Sen 2000; Pandian 2005; Verma 2007; Srivastava and Misra 2007]. However, little has been dis-cussed about the economics of the pipeline.The 1,850-2,135 km (depending on the route)IPI natural gas pipeline is to be used to initially import about 60MMscmd2 of natural gas from the South Pars gas field in Iran. The energy requirement of India and Pakistan requires substantial energy import. Iran has about 15 per cent of the world’s proven gas reserves. While both India and Pakistan need long-term energy supplies, Iran finds a large market for its gas in the neighbour-hood. The project, which was initiated as a gas pipeline between Iran and Pakistan, was later joined by India. This not only improves the economics of the project for Pakistan but also pro-vides access to a larger market in India. For India, it is an option to expand energy supplies for an energy starved economy. In spite of favourable economics for the parties involved, the project has also been overshadowed by the geopolitical equations between India and Pakistan and between Iran and theUS [Pandian 2005; Verma 2007].As per a pricing arrangement under negotiation, the price of natural gas has been benchmarked to Japanese custom cleared crude (JCC). This paper examines the economics of the landed price of natural gas in India in comparison with the existing

SPECIAL ARTICLEseptember 13, 2008 EPW Economic & Political Weekly58agreements for liquid natural gas (LNG) import. The paper reviews the natural gas demand and supply scenario in India and examines the efficacy of the pipeline in the context of energy security. Further, we also examine the economics of natural gas supply from theIPI pipeline in terms of the cost of power genera-tion and delivered power to consumers. The paper also briefly reviews the process of negotiations of the IPI pipeline. 1 Demand and Supply of Natural Gas in IndiaEconomic growth in developing countries like India is dependent on the availability of energy inputs. During 1980-81 to 2003-04 (1990-91 to 2003-04), India recorded a energy-to-GDP ratio for total primary commercial energy supply as 1.08 (0.82). The elasticity for electricity generated to GDP during the same period is estimated to be 1.30 (1.06) [GOI 2006a]. To attain a GDP growth of 9-10 per cent in the near future, the country needs to expand its electricity generation at approximately 9.5-10.5 per cent per annum.Coal continues to dominate the primary energy supply in the country (Table 1). While India is endowed with significant coal reserves, a large quantity of oil is imported. In spite of a vast quantity of coal reserves in the country, there are concerns for coal quality as well as environmental concerns associated with coal mining and its utilisation. In contrast, natural gas is a cleaner source of energy. Due to limited domestic resources, its contribu-tion to the primary energy supply in the country remains limited. Natural gas reserves in the country have grown from 686 BCM in 1990 to 1,075 BCM in 2006 [GOI 2007]. Recent discoveries in the Krishna Godavari (KG) basin have given a fillip to gas exploration in the country.As per the India Hydrocarbon Vision-2025, the demand for natural gas is projected to reach 313 MMscmd by 2011-12 and 391 MMscmd by 2024-25. Against this, domestic production, riding on new discoveries, is expected to reach a peak of 200 MMscmd leav-ing a gap of 191 MMscmd [GOI 2000]. More recently, a sub-group on natural gas for the Eleventh Five-Year Plan projected a mar-ginally lower demand for natural gas. This is expected to reach about 281 MMscmd by the year 2011-12 (Table 2). However, the projections for gas availability3 take into account the recent dis-coveries in theKG basin and the projected increase in import of LNG (Table 3). The power sector is expected to remain the largest consumer of natural gas, followed by the fertiliser sector. Given the poten-tial for addition to gas-based generation capacity,4 a higher quan-tity of natural gas can be utilised in the country. This would, however, be guided by the economics of natural gas utilisation in the power sector. This is examined later in Section 7.The above demand and supply projections of natural gas present a marginal demand-supply gap of about 5 MMscmd by 2011-12. Advancement of production from the KG basin would help early induction of gas-based power generation capacity. This would not, however, affect the supply scenario from 2011-12 onwards.5 Long-term projections as per the Hydrocarbon Vision-2025 place the demand for natural gas to be about 391 MMscmd by 2024-25. The supply of natural gas can be supplemented with higher domestic exploration as well as through its import in the form ofLNG and piped natural gas. It is clear that additional import of natural gas over and above the existing supply con-tracts cannot be ruled out.6 The piped natural gas import from Iran, under a favourable security scenario, could supplement India’s energy security in future.Improved availability of natural gas would not only help improve generation in gas-based generation plants but also help conversion of dual-fuel liquid based plants to gas. Due to the nature of the supplies and associated contracts, improved availa-bility of natural gas would get translated into additional capacity additions by various user sectors like power, fertiliser, city gas, etc. Table 1: Sources of Primary Energy Supply in IndiaSource 1990-91 2000-01 2001-02 2002-03 2003-04 2004-05 2005-06 (P)Petroleum products (MMT) 57.75 106.97 107.71 111.78 115.99 120.17 121.05Natural gas (net) (BCM) 12.77 27.86 28.04 29.96 30.91 30.78 31.33Coal (MMT) 211.73 309.63 327.79 341.29 361.25 382.61 405.2Lignite (MMT) 13.77 22.95 24.81 26.02 27.96 30.34 32.53Electricity (BnkWh) 289.4 554.5 579.1 596.5 633.3 680 730.32Source: GOI (2007).Table 2: Projected Demand for Natural Gas (2007-08 to 2011-12) ActualProjected(MMscmd) 2005-06 (P) 2007-08 2008-09 2009-10 2010-11 2011-12Power 32.548088100 112 125Fertiliser 21.27 40.82 42.65 52.24 79.36 79.36City gas 0.21 12.08 12.93 13.83 14.8 15.83Industrial 10.361516.0517.1718.3819.66Petrochem/refineries/inter cons 20.22 25.37 27.15 29.05 31.08 33.25Sponge iron/steel 6 6.42 6.87 7.35 7.86Total demand for natural gas 84.59 179.27 193.19 219.16 262.96 280.98Source: GOI (2006b, 2007).Table 3: Projected Availability of Natural Gas(2007-08 to 2011-12)Natural Gas Supply Actual Projected(MMscmd) 2005-06 (P) 2007-08 2008-09 2009-10 2010-11 2011-12ONGC Prod not avail 68.07 47.28 48.42 45.69 44.67 41.08Private/joint ventures (as per DGH) 20.16 23.26 61.56 60.28 58.42 57.22Projected domestic 88.22 70.54 109.98 105.97 103.09 98.3Additional gas anticipated D6 (RIL) – 20 30 40GSPC (10 TCF) – 54 54 54Total projected domestic supply 88.22 70.54 109.98 179.97 187.09 192.3 (75) LNG supply (MMTPA) 2007-08 2008-09 2009-10 2010-11 2011-12Dahej 5 5 7.5 1010Hazira (Shell) 2.5 2.5 2.5 2.5 2.5Dhabol 1.2 2.1 5 5 5Kochi 2.5 5Mangalore 1.25Total LNG supply (MMTPA) 8.7 9.6 15 20 23.75Total LNG supply (MMscmd) 18.55 30.45 33.6 52.7 70 83.12Total natural gas supply (domestic and LNG) (MMscmd) (93.55) 100.99 143.58 232.67 257.09275.42Advancement of gas production from Reliance Industries Limited D-6 blockD6 (RIL) (revised production schedule) – 40 40 40 40Updated total natural gas supply (domestic and LNG) (MMscmd) (93.55) 100.99 183.58 252.67 267.09275.42The projections for updated availability of natural gas take into account advancement in production programme from RIL’s KG-DWN-98/3 (known as D-6) block in the KG basin.Source: GOI (2006b, 2007).

SPECIAL ARTICLEEconomic & Political Weekly EPW september 13, 200859The improved availability of natural gas can help alleviate the power supply position in the country. Due to the lower gestation period of gas-based power plants, one could expect faster addi-tion to the generation capacity in the country. The import of nat-ural gas is expected to partially fill the emerging gap in demand and supply. 3 Import of Natural Gas and LNGIndia’s dependence on energy import has historically been related to a significant import of crude oil and petroleum products. The new exploration licensing policy (NELP), formulated in 1997 and implemented in 1999, is aimed to enhance private participation in oil and gas exploration. The policy provides a level playing field to private investors by giving the same fiscal and contract terms as applicable to national oil companies. However, to sup-plement resources for the increasing demand for natural gas and limited resources in the country, places an emphasis on the import of natural gas as well asLNG. The natural gas resources in the country’s neighbourhood motivated proposals for natural gas import via pipelines. Three such proposals, to import gas from Bangladesh, Myanmar and Iran, have been examined in the past.8 India is positioned as a large market for export of gas from these countries. There are a number of technical options to transport energy trapped in natural gas reserves. These include piped natural gas, LNG, gas to liquid and gas to electricity. Thomas and Dawe (2003) discuss various technical options to transport energy in gas reserves. Although, these pipelines have associated concerns like inflexibility in delivery points and risk of sabotage, the econom-ics of overland gas pipelines have justified their presence in almost all continents [Thomas and Dawe 2003]. While natural gas pipelines are economical, very large distances tend to favour theLNG option. For distances under about 2,000 miles, pipelines are less expensive thanLNG [Tongia and Arunachalam 1999]. The network characteristics of pipelines also ensure added relia-bility and economies of scale for gas pipeline transportation.The first proposal for export of gas from Bangladesh to India was to be undertaken from Unocal Corporation’s Bibiyana fields in north-east Bangladesh. This field is estimated to hold in place reserves of about 6.6 trillion cubic feet (tcf). The proposed pipe-line was to link up with the Hazira-Vijaipur-Jagdishpur pipeline in India. Negotiations with Bangladesh could not move further partially due to political overshadows. Later, Bangladesh cited that increasing domestic demand for gas does not make it availa-ble for export purposes. Commercial gas discoveries of about 5 tcf Rakhine offshore gas block in Myanmar in January 2004 raised hopes for gas import from there. Two Indian companies, Oil and Natural Gas Corpora-tion (ONGC) Videsh Nigam (OVL) and Gas Authority of India (GAIL), hold a 20 and 10 per cent stake respectively in the A-1 Rakhine offshore gas block in Myanmar. The block provides a prospect of producing 20-25 MMscmd of gas for a period of 20 years. Three options were considered to import gas from Myan-mar – a deep sea pipeline, an overland route through Bangladesh and a overland route through north-east India [Infraline undated a]. The first one is adjudged to be uneconomical. In June 2004, 2 Natural Gas and Indian Power SectorThe shortage of natural gas in the country is affecting power generation as well as fertiliser production. The gas-based power plants, which can record availability up to 90 per cent are operating at a plant load factor (PLF) of about 65 per cent (Table 4). The unavailability of gas is also leading to use of expen-sive naphtha. The generation loss7 due to natural gas shortage is estimated to be 6,582 GWh in April-June 2007. The estimated generation loss for gas-based power plants during April-June 2007 by ownership is presented in Table 4. During the same period, energy shortage in the country is estimated to be 15,758 GWh [CEA 2007a].As on June 2007, the installed gas-based power genera-tion capacity in the country is estimated to be 13,077MW, about 10.5 per cent of the total generation capacity of 1,24,857 MW. Natural gas- based electricity gen-eration possess special attributes like shorter gestation periods and are specifically suited for peak power generation. Concerns for coal quality, inability to get coal linkages and large distance from coal mines favour the economics of natural gas for electri-city generation, if it is available at an appropriate price. However, use of importedLNG to generate electricity has been questioned on the merit of cost and supply security [Phadke 2001].The Parikh Committee’s report on integrated energy policy projects that the Indian power sector may require about 119 BCM (326MMscmd) natural gas by 2031-32 [GOI 2006a] (Table 5). The estimate of demand projections for 2011-12 is lower that at pre-sented by the sub-group on natural gas for the Eleventh Five-Year Plan (2007-2012).The sub-group has identified only 1,889 MW addition of gas-based generation capacity during 2007-12. Under an optimistic view about natural gas availability, an additional capacity of 31,766 MW is also identified to be developed during the Eleventh Plan [GOI 2006b]. Based on these projections for capacity addi-tion, the natural gas requirement for the power sector is esti-mated to go up to about 197 MMscmd by the end of the Eleventh Five-Year Plan (Table 6, p 60).Table 4: Plant Load Factor of Liquid Fuel/Gas Based Gas Turbines(April-June 2007) Capacity PLF (%) Generation Generation (MW) Loss (GWh) Loss (GWh) @ PLF = 90% @ PLF = 80%Central sector 5,159 79.08 1149.38 96.95State sector 3,825 47.53 3314.26 2533.94Private utility 280 80.81 52.47 –Private independent power providers 3,903 63.49 2111.07 1314.86All gas turbines combined cycle gas turbines 13,077 65.33 6581.89 3918.81Thermal 86,12781.7––Overall capacity 1,24,857 – – –Capacity as on March 31, 2007.Source: Estimated from data available in CEA (2007b).Table 5: Demand for Natural Gas for Power Sector as per Parikh Committee’s ReportYear Demand for Natural Demand for Natural Gas (BCM) Gas (MMscmd) 8% pa 9% pa 8% pa 9% pa GrowthGrowthGrowthGrowth2011-12 19 21 52 582016-17 33 37 90 1012021-22 52 59 142 1622026-27 77 87 211 2382031-32 119 134 326 367Source: GOI (2006a).

SPECIAL ARTICLEseptember 13, 2008 EPW Economic & Political Weekly60the government of Bangladesh expressed its willingness to con-sider an Indian proposal of laying the overland gas pipeline from Myanmar to India through its territory. In November 2004, Bang-ladesh agreed “in principle” to the proposed 290 km pipeline tran-siting through its territory. Bangladesh could earn $ 125 million as transit charges per year. In January 2005, a trilateral ministerial meeting led the three countries to an understanding to build the pipeline at an estimated cost of $ 1 billion. Subsequently, a techno-commercial working committee (TCWC) was constituted. The TCWC prepared a draft memorandum of understanding (MoU), which could not be approved due to differences between India and Bangladesh over a preambular paragraph that included bilateral issues in such a trilateral agreement. The vacillations in negotiation of a transit route through Bangladesh and the security concerns for the north-eastern route led to delay in negotiations with Myanmar. The feasibility of an overland pipeline through the north- eastern part of the country is being re-examined. GAIL has com-pleted a detailed feasibility report (DFR) for the proposed pipeline route through the north-eastern part of the country. As per the DFR, the proposed pipeline will pass near Aizwal (Mizoram), Silchar and Guwahati (Assam) and Siliguri (West Bengal). It would finally be injected at Gaya (Bihar) in the proposed Jagdishpur-Haldia pipeline to cater to the gas demand of north-ern as well as eastern part of the country. The proposed pipeline would have a design capacity of 18MMscmd and would traverse a distance of 1,573 km from the Myanmar-India border to Gaya (Bihar). However, the fate of this pipeline hangs in balance as Myanmar indicated that out of the presently available gas of 4.8 tcf from the A-1 block, 2.0 tcf is to be earmarked for domestic consumption. This leaves only 2.8 tcf of gas for export. As the quantity is not adjudged to be sufficient to derive economies of its export, Myanmar is to explore additional availability of gas though further exploration work in the A-3 block. Amid these negotiations, Myanmar and China reportedly signed anMoU on March 14, 2007, wherein Myanmar would export gas from A-1 andA-3 blocks at a rate marginally over$ 4 per MMBtu [Infraline undated b]. Myanmar has recently informed that it is considering export of gas discovered from A-1 and A-3 blocks to China through a 1,000 km on-land pipeline [Lok Sabha 2007]. The uncertainties associated with gas import through pipe-lines also led to acceleration of port developments in western states to import gas in the form of LNG. Petronet LNG, a joint venture promoted byGAIL, Indian Oil Corporation, Bharat Petroleum Corporation and ONGC was formed for the import of LNG to meet the growing demand of natural gas. It operates a 5 MMTPA capacityLNG terminal at Dahej in Gujarat. The capacity of this terminal is planned to be increased to 10MMTPA by 2009-10. India imports 5 MMTPALNG at Dahej from Qatar under a 25-year contract that commenced in 2003. AnotherLNG supply contract with Iran for the same quantity is to begin gas supplies for 25 years beginning 2009. Shell also operates 2.5 MMTPA LNG terminal at Hazira. Though commissioned in April 2005, it is not able to source requisite supplies on a long-term contract and has been operating much below its capacity. The existing LNG terminal at Dhabol, with a capacity of 1.2 MMTPA in 2007-08, is planned to be expanded to 5 MMTPA by 2009-10. AnLNG terminal is being set up at Kochi to import 2.5 MMTPALNG by the year 2010-11. The capacity of this terminal is also planned to be increased to 5MMTPA by 2011-12. A smallerLNG terminal of 1.25 MMTPA capacity is planned to come up at Mangalore by 2011-12 [GOI 2006c].4 NegotiationsforIPI PipelineIran’s proven natural gas reserves are estimated to be 26,850 billion scm, representing 14.84 per cent of the world’s natural gas reserves in 2006, second only to the former Union of Soviet Socialist Republics (USSR) nations [OPEC 2007]. However, its gross natural gas production remains low (1,64,200 million scm in 2006) with a reserve to production ratio of 163.52 years. Iran has not exploited its domestic natural gas resources in proportion to the resources available. Iran’s share in the world’s export mar-ket for natural gas remains low. In 2006, Iran exported only 5,727 million scm of natural gas, a meagre 0.76 per cent of world trade in natural gas. Interestingly, Iran remains a net importer of natural gas. In 2006, it imported 6,263 million scm natural gas while exported only 5,727 million scm (ibid).Iran together with other west Asian countries, is home to about 40 per cent of the world’s proven natural gas reserves. For such a large resource of natural gas, growing economies like India pro-vide a significant market within close reach. The growing energy deficit in south Asia led to a proposal for exporting natural gas from west Asian countries [Kubota 1996; Aithuis et al 1995]. India explored a number of options including building deep-sea pipe-lines from Oman and Qatar. However, these did not materialise due to high cost,9 difficult terrain and political hiccups.The genesis of the natural gas import from Iran can be traced back to 1993. The government of India and the government of the Islamic Republic of Iran inked bilateral agreements in June and November 1993. These agreements led to commissioning of a pre-feasibility study in early 1995 for a shallow water offshore gas pipeline from Iran to India outside the territorial waters of Pakistan. However, the study was terminated in 1997 as the government of Pakistan refused to grant permission to conduct survey to identify a suitable pipeline corridor. The prospects to explore energy cooperation were revived during the Eleventh Indo-Iran Joint Commission meeting in Tehran in May 2000. This agreement provided that for developing gas sector cooperation between the two countries, three options would be Table 6: Projected Natural Gas Based Capacity and Natural Gas Requirement during the Eleventh PlanGas Based Capacity Capacity Natural Gas Natural Gas (MW)RequirementRequirement (BCM)#(MMscmd)#Existing 13,077 20,077 55Projected addition during Eleventh Plan 1,889 2,900 8Addition during Eleventh Plan (subject to gas availability) 31,766 48,771 134Total by the end of Eleventh Plan 46,732 71,748 197# - At 90% PLF; (Heat rate = 1850 Kcal/KWh); gross calorific value (GCV) of natural gas = 9500 Kcal/cu m. Some of the best performing existing gas-based plants reported following heat rate in 2003-04: Lanco’s Kondapalli -1969, Pragati (PPCL) – 1802, Dadri Gas (NTPC) – 1998, Anta (NTPC) – 1772 and Faridabad Gas (NTPC) – 1923 [CEA 2005]. New plants are assumed to have a better heat rate.Source: Estimated from capacity addition projections by GoI (2006b).

SPECIAL ARTICLEEconomic & Political Weekly EPW september 13, 200861examined: (i) LNG supply; (ii) deep water gas pipeline; and (iii) on-land gas pipeline via Pakistan [Infraline undated c].The negotiations for the three-nation IPI pipeline have primarily been concentrated on capacity, pricing and route of the pipeline. Pakistan and India have been discussing the IPI gas pipeline project with the government of Iran. A tripartite joint working group (JWG) of Iran, Pakistan and India has been formed. Four meetings of the trilateral JWG have been held; the last meeting being held in Tehran on January 24-25, 2007. During this meeting, Iran and Pakistan agreed to a pricing formula, subject to approval by their respective authorities. India conveyed that it would respond to the pricing formula within four weeks. Apart from this, two separate secretary level JWGs, viz, India-Pakistan JWG and India-Iran spe-cial JWG (SJWG) have been constituted. Three meetings of India-Iran SJWG have been held, the last one was held on December 28-29, 2005. Four meetings of India-Pakistan JWG have been held, the last one being held in Islamabad on February 22-23, 2007. The issues related to transportation tariff and transit fees for passage of pipeline through Pakistan were discussed in the last meeting. A technical sub-group meeting between Pakistan and India was held on March 22-23, 2007 at New Delhi to discuss technical issues, transit fee and transportation cost [Rajya Sabha 2007a].The negotiations over the IPI pipeline have also been overshad-owed byUS-Iran relations. This primarily stems from the Iran- Libya Sanctions Act of 1996 that provides for the imposition of sanctions against foreign companies, which invest more than $20 million in a year in Iran’s energy sector. To mitigate this, it is proposed that the pipeline project be developed individually by each country in their respective country. Iran would lay a pipeline up to the Iran-Pakistan border, the take-off point for the gas. The Indian side emphasises contract for delivery of gas at the Indian border, whereas Iran insists for the delivery point to be at the Iran-Pakistan border, thus transferring the transit risk to India.The finalised route of the pipeline provides an off-take at Hyderabad in Pakistan and would extend up to Barmer, the off-take point in India. The pipeline would be of 56 inches in diameter up to a length of 795 km from the Iran-Pakistan border up to Hyderabad. Thereafter, the remaining length of the pipeline up to Barmer, a length of 241 km would be of 42 inches in diameter. The total length of the pipeline through Pakistan would be approxi-mately 1,035 km. The total length of the pipeline from the South Pars field in Iran to Barmer in India is 2,775 km [Infraline 2007a].5 NegotiationsoverPriceThe pricing for natural gas supply from Iran, apart from security concerns, has been a major sticking point in the IPI pipeline nego-tiations. While the Iranian point of view was to align the natural gas price to the price of LNG, India and Pakistan proposed a more realistic approach that would keep the piped gas economical for investment in the pipeline infrastructure. The volatility in the crude oil price, which has scaled new peaks over the last couple of years, took the leverage away from the buyers. From the Indian point of view, transportation charge and transit fee are the addi-tional issues to be negotiated bilaterally with Pakistan.The commercial interests from the three countries in the IPI pipeline are being extended through three representative agencies – the National Iranian Gas Export Company (NIGEC), Interstate Gas Systems Private and GAIL. Iran, India, Pakistan have jointly appointed Gaffney, Cline and Associates (GCA), aUK based consultant, to provide an independent professional view on the appropriate price to be charged for the natural gas at the point where the pipeline crosses the border between Iran and Pakistan. A pricing methodology based on the netback from price of LNG at Japan has been agreed upon by the three countries. The GCA is to arrive at a price for natural gas after taking into account transportation up to Iran-Pakistan border.The GCA based its netback calculations on the following: (a) costofLNG in Japan; (b)LNG shipping cost from the Persian gulf to Japan; (c) cost of gas liquefaction in Iran; (d) cost of gas processing for LNG mode and pipeline mode; and (e) estimated pipeline transportation cost from Assaluyeh to the Iran-Pakistan border [Infraline 2007b].During the fourth trilateralJWG meeting held at Tehran on January 24-25, 2007, net back calculations and price derivation done byGCA were discussed. In response to reservations by India and Pakistan, Iran suggested a formula for gas price up to Pakistan-Iran border during theJWG meeting on February 22-23, 2007 in Islamabad. The agreed formula links the price of deliv-ered gas to the price of JCC. While Iran and Pakistan agreed to the proposed formula subject to approval by the respective gov-ernments, India agreed to respond to pricing formula with in four weeks. The formula for the gas delivered at the Iran-Pakistan border is as follows (ibid):ForJCC price less than$ 30/bblP = 1.54 + 0.05* JCC;stJCC < 30 ForJCC price in the range $ 30 – $ 70/bblP = 1.15 + 0.0633* JCC;st 30≤JCC≤ 70ForJCC price greater than$ 70/bblP = 2.06 + 0.05* JCC;stJCC > 70where p denotes the price of delivered gas at Iran-Pakistan bor-der (in $ perMMBtu) and JCC – price of Japan custom cleared crude (in $ per barrel).At the prevailingJCC price of about $ 70/bbl, the natural gas supplies at the Iran-Pakistan border would be$ 5.04/MMBtu. Adding a normative transportation and tariff charge, the cost insurance and freight price of the gas at the Indian border would be approximately $ 5.84/MMBtu. The associated assumptions and their reasonableness are further discussed in Section 7. This is lower than the $ 7.17/MMBtu which Tehran sought in mid-2006 but higher than the Indian plan to peg the gas at $ 4.25/MMBtu. The merits of the landed price of natural gas for India are exam-ined later in Section 7. The other two important issues, namely, the transportation charges and transit fee to be paid to Pakistan are discussed below.6 Transportation Tariff and Transit Fee The transportation charges are essentially a commercial mean of compensating the pipeline investor for investment in the pipeline and a reasonable return on the same.10 The transportation

SPECIAL ARTICLEseptember 13, 2008 EPW Economic & Political Weekly62charges can be worked out on the basis of [Energy Charter Secre-tariat 2006]: (i) distance-based capacity tariffs; (ii) distance-based commodity charges; and (iii) entry-exist tariffs. The gov-ernment charges, often known as transit fee is discussed later in the section.Pakistan has been seeking a transportation tariff of $ 0.70-0.75 per MMBtu, while India was willing to pay $ 0.55 perMMBtu [Businessline 2007].GCA has estimated the gas transportation charges to be$ 0.73/MMBtu for a 1,100 kmIPI pipeline with 60 MMscmd flow transiting through Pakistan. For a pipeline with 90MMscmd flow, the transportation charges could be worked out to approximately $ 0.60/mmbtu [Infraline 2007b].The transportation tariff charged for natural gas transportation across transiting countries is estimated to range between $ 0.01 and $ 0.08 per MMBtu per 100 km (Table 7). For an equivalent length of 1,035 km of IPI pipeline transiting through Pakistan, this works out to $ 0.13 and 0.80 per MMBtu. The Energy Charter Secretariat (2006) also worked out transportation tariff for a model11 1,500 km high pressure 56 inch pipeline. This is estimated to be $ 1.6 per 1000m3/100 km (equivalent to $ 0.04 per MMBtu per 100 km). For an equivalent length of 1,035 km of IPI pipeline transiting through Pakistan, this works out to $ 0.44 per MMBtu (Table 7). In this context, the proposed transportation tariff of $ 0.6 per MMBtu seems on higher side. A softening of the steel prices would justify further reduction in the tariff. Further about 291 km length of the pipeline, from Hyderabad in Pakistan to Barmer in India is to be constructed using a 42 inch pipeline. While this may reduce revenue requirement for this segment, loss of economies of scale and lower volume handled would marginally increase the tariff in MMBtu terms.The transportation tariff of $ 0.44 per MMBtu for a model pipeline assumes that the transiting country does not utilise the pipeline for domestic gas utilisation. If one factors in the utilisation of the pipe-line for the consumption of gas in Pakistan, the associated transportation tariff may work out be on the lower side. The 795 km out of the total length of about 1,035 km would be utilised for serving the domestic requirements in Pakistan. The proposed allocation of gas volume between India and Pakistan is 30 MMscmd each. The 795 km segment would be utilised for transporting 60MMscmd gas (including 30MMscmd each for India and Pakistan). Taking into account the parameters associ-ated with theIPI pipeline, a model tariff for a high pressure tran-sit line to be paid by India is estimated to be$ 0.41/MMBtu. The estimated model tariff would provide tariff revenue over$ 226 million per annum to Pakistan. This is for compensating the investment in construct-ing pipeline including cost of right of way and pipeline’s operation and maintenance.Apart from “commercial” transportation tariff for use of a transiting pipeline the host government also needs to provide for safety and associated guarantees, if any. This is known as government charges or transit fee. The transit fees levied by the host state are uncommon in energy charter treaty coun-tries. Such fees are usually charged from pipeline investors for providing right of way, security of assets as well as various legisla-tive and administrative state guarantees from host governments. These are often fro-zen at a level at the time of initial agreement and could be taken in cash or in kind. The Energy Charter Secretariat (2006) reports that a minimum in-kind transit fee of 5 per cent of the gas transported is levied by Georgia.12 Similarly, Tunisia and Morocco levy a transit fee of 5 to 7 per cent of gas transported. Belarus also levies a transit fee equivalent to about 5 per cent of gas volumes transited. In the case of theIPI pipeline, Pakistan is seeking a transit fee of $ 0.49 per MMBtu while New Delhi offered $ 0.20 perMMBtu [Businessline 2007]. A transit fee of $ 0.20 perMMBtu corresponds to an in-kind fee of 5 per cent of the gas transported at a long-termJCC price of about $ 45 per bbl. Given the long-term nature of the pipeline, this may seem to be reasonable. Again, one must consider that about 77 per cent of the pipeline length is co-shared by India and Pakistan and, hence,a significant part of expendi-ture to be incurred by Pakistan for the security of the pipeline provides security benefit to Pakistan itself.Given the associated security risk and the overcast of geopoliti-cal relations between the two neighbours, the pipeline transit economics should also include energy security concerns. A sce-nario for supply disruption due to the geopolitical situation in the region has remained a major concern [Tongia and Arunachalam 1999; Sen 2000; Pandian 2005; Verma 2007; Srivastava and Misra 2007]. It is suggested that the pipeline be subjected to the principle of national treatment by Pakistan by providing a level of security to the transiting pipeline as it would have provided to a domestic pipeline and that the pipelines be explicitly covered under the articleV of the General Agreement on Table 7: Natural Gas Transportation Tariff in Energy Charter Treaty CountriesYear of Country Distance Distance-Based Equivalent Share of Pipeline Agreement/ (kms) Commodity Charges Tariff for Domestic DiameterCost Basis $/1000m3/ $/MMBtu/ IPI PipelineConsumption (Inches) 100 km 100 km ($/ MMBtu) (%)2005 Belarus(Yamal) 575 0.46 0.01 0.13 34.78 >362005 Belarus(Ukraine) 0.75 0.02 0.21 – >361998 CzechRepublic 350 2.9 0.08 0.80 18.37 na2003 Poland 680 2.74 0.07 0.75 39.39>36(56)2004 Russia 1,100 0.71 0.02 0.19 – >362004 Ukraine 1.09 0.03 0.30 37.16 >362004 Interconnector (UK to Belgium) 235 2.12 0.06 0.58 0.00 >36 (40)2005 Model high pressure transit line 56 inches 1,500 1.6 0.04 0.44 0.00 562005 Model high pressure transit line 36 inches 1,500 3.3 0.09 0.91 0.00 362005 Model high pressure transit line (IPI) # 1,035 1.995 0.053 0.408 50.00 56, 36*# - For transit supplies to India though the proposed IPI pipeline.* We assume that the pipeline used for onward transportation from Hyderabad in Pakistan to Barmer in India to be of 36 inches diameter rather than the proposed 42 inches.This would increase the model tariff only marginally as the difference it is applicable over a smaller distance and for half the gas volume transported.Although, tariff can be worked out for a 42 inches pipeline, we have not attempted to do so.Source: Estimated using data from Energy Charter Secretariat (2006).Table 8: Current Gas Price in India ($/MMBtu) APM PMT RLNG– Spot Gas*LongTerm#RLNGBase price (land fall/CIF) 1.78 4.75 2.79 8.0-9.5Delivered price at power plant 2.8-2.90 5.25& 4.5-4.6 10.5-13* Present production is 10.8 MMscmd. Out of this, 6.0 MMscmd is allocated through APM and 4.8 MMscmd is marketed directly to consumers); # Price valid till 2008; & - Including transportation charge and marketing margin @ 0.5/MMBtu.Source: NTPC (2007).

SPECIAL ARTICLEEconomic & Political Weekly EPW september 13, 200863transportation cost and transit fee to be paid to Pakistan, import duty, transportation charges in India and applicable taxes. The assumptions associated with these aspects are reported in Table 9. Further, we also estimate the cost of producing elec-tricity using importedLNG under a set of assumptions outlined in Table 10.At aJCC price of $ 70 per bbl, the cost of electricity generated using natural gas from IPI pipeline at the generation plant bus-bar is estimated to be Rs 3.31 per kWh (Table 9). At the same benchmark price of JCC, the estimated cost of electricity genera-tion at the generation plant bus-bar using re-gassified-LNG from Qatar and Iran are Rs 4.7 per kWh and Rs 3.59 per kWh respec-tively (Table 10). Clearly, the economics favours the IPI gas sup-plies at the suggested price in comparison to the existing LNG options. The LNG import from Iran provides the next economical natural gas supplies. The verdict would favour the IPI pipeline, till it is utilised in north India requiring less investment in its transportation. For the western and southern states, the LNG option may prove to be economical. If we factor in the added security risk associated with theIPI pipeline, the LNG contracts from west Asian countries would strengthen India’s energy security interests in a better way than the IPI pipeline.Imported natural gas for base load plants in the Indian power sector does not provide an economic alternative. This is specially true from the recent experience in the bidding for the Tariff and Trade [Verma 2007]. It is proposed that the project developers would cover the risk of the project for the Pakistan segment of the pipeline by securing adequate financial and sover-eign guarantees and insurance cover. The responsibility for this will rest with the Iranian side and the project developers. The Indian side proposes that there would be adequate “supply or pay” conditions for ensuring security of natural gas supply. Gas storage facilities in India as well as short-termLNG supplies are proposed to provide additional security as an integral part of the project structure [Rajya Sabha 2005].7 Economics of Power Generation Using Natural Gas from IPI PipelineThe power sector is the largest consumer of natural gas in the country and is expected to retain this position in near future as well (see Section 1). In this context, we examine the economics of the IPI pipeline in terms of its impact on the cost of power produced and delivered to consumers. We also examine the proposed deal with the existing contracts to importLNG from Qatar and Iran.An expert committee set up by the Central Electricity Authority (CEA) ranked piped natural gas from the exist-ing sources at time to be the cheapest fuel for power generation in the country [CEA 2004]. The cost of power genera-tion from natural gas was estimated to be Rs 1.49 per kWh. However, this assumed that the subsidised natural gas would be available at a price of Rs 4,000/scm along the Hazira-Bijapur-Jagdishpur pipeline. A port based gen-eration plant using importedLNG13 were found to be less economical and the associated cost of power generation was estimated to be Rs 2.29 per kWh, the same price at which a port based plant would produce electricity using imported coal. In the present scenario, neither the gas availability nor the price holds true.The price of the natural gas basket in the country has undergone significant change due to increasing share of gas supplies from joint venture fields and the availability of regassified LNG (Table 8, p 62). The new power plants may not be able to derive the benefit of subsidised prices under the administrative price mechanism (APM). Hence, it would not be appropriate to compare the cost of generation from APM linked natural gas supplies with that to be supplied through the IPI pipe-line. Hence, we examine the economics of the later with respect to the alternate imported source of gas in the form of LNG.The economics of power generation is examined by taking intoaccount the landed cost of natural gas after inclusion of Table 9: Economics of Power Generation Using Natural Imported through IPI PipelinePrice of JCC Price of Gas Price at Price in India Price Including Cost of Variable Cost Cost of Power Cost of Cost of at Iran-India- after Transport Delivered of Power Generation Delivered Delivered Pakistan Pakistan Custom Duty Charges and Gas at Generation (Including Power Power Border Border# @ 5% Marketing Consumer Fixed Cost)! (Including (Including Margin & End* T&D Cost)## T&D Loss)## ($/Bbl) ($/MMBtu)($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (Rs/kWh)(Rs/kWh)(Rs/kWh) (Rs/kWh)40 3.684.4824.715.416.081.832.833.134.1750 4.325.115 5.376.07 6.832.06 3.063.364.4760 4.955.7486.046.747.582.283.283.584.7770 5.586.3816.707.408.332.513.513.815.0780 6.066.867.207.908.892.683.683.985.30# Transportation charge in Pakistan @ $ 0.6/MMBtu, Transit fee in Pakistan @ $ 0.2/MMBtu; & Transportation charge in India @ $ 0.2/MMBtu and marketing margin @ $ 0.1/MMBtu; * State level tax @ 12.5 %; ** Exchange rate @ Rs 41/$, Heat rate for power generation @ 1850 kcal/kWh; ! Fixed Cost @ Rs 1/kWh; ## Including T & D Cost @ Rs 0.30 per kWh and T & D loss @ 25%.Source: Author’s calculations.Table 10: Economics of Power Generation from LNG Imported from Qatar and IranPrice of JCC LNG FOB CIF Price Landed Cost Post Price Including Cost of Variable Cost Cost of Power Cost of Cost of Price * (Including of LNG in India Regasification Transport Delivered of Power Generation Delivered Delivered Shipping and (Including Cost $$ Charges and Gas at Generation (Including Power Power Insurence)&& Customs Marketing Consumer Fixed Cost)! (Including (Including Duty @ 5%) Margin & End* T&D Cost)## T&D Loss)## ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) (Rs/kWh) (Rs/kWh) (Rs/kWh) (Rs/kWh)LNG from Qatar 40 5.07 5.365.62 6.026.727.572.28 3.28 3.584.7750 6.336.626.957.358.059.062.733.734.035.3760 7.607.898.288.689.3810.563.184.184.485.9770 8.879.169.6110.0110.7112.053.634.634.936.5780 10.1310.4210.9411.3412.0413.554.085.085.387.17LNG from Iran 40 3.804.094.294.695.396.071.832.833.134.1750 4.454.744.985.386.086.842.063.063.364.4860 5.105.39 5.666.066.767.602.293.293.594.7970 5.756.046.346.747.448.372.523.523.825.0980 6.406.697.027.428.129.142.753.754.055.40Notes to Table 9; && Shipping and insurance @ $ 0.29/MMBtu; $$ Regasification cost @ $ 0.6/MMBtu; * Infraline (undated d) and author’s calculations.

SPECIAL ARTICLEseptember 13, 2008 EPW Economic & Political Weekly64ultra mega power plants (UMPPs) of a capacity of 4,000MW each. The UMPPs at Sasan (based on domestic coal) and Mundra (based on imported coal) have been bid at 25-year levelised tariff of Rs 1.196 and Rs 2.26 per kWh for the two projects respectively.Undoubtedly, the cost of generating power from imported piped or LNG is higher than traditional coal. Further, given the present state of the distribution segment in the Indian power sec-tor, there would be few buyers for such power. The consumers may have to pay as high as Rs 5.75 per kWh for the incremental power supply from the gas supplied by the IPI pipeline (Table 9). ImportedLNG fares worse as the consumer impact of the power generated for the Qatar and IranLNG would be Rs 7.59 per kWh and Rs 6.12 per kWh respectively (Table 10). To improve grid discipline under the prevailing power short-ages scenario, the Central Electricity Regulatory Commission (CERC) revised the peak rate for unscheduled interchange (UI) rate under the terms and conditions of tariff to Rs 7.45 per kWh corresponding to a grid frequency of 49.02 Hz and below. This has subsequently been revised to Rs 10 per kWh, highlighting the value of peak power shortage in the country. Given the prevailing UI rate, the economics of natural gas-based power does seem attractive for peak hours especially by the industrial and commercial consumers. One can also note that the prevailing tariff for natural gas-based generation for the central sector generating stations is only Rs 1.67 (Table 11). Hence, economics ofimported gas seems to be justified to replace naphtha and for meeting peak energy requirements in the Indian power sector. Given the perennial shortage of power, there is also a scope for reliable baseload electricity especially by large industrial consumers.However, such a comparison cannot be done in isolation from the market-based pricing of gas produced by private/JV fields. The promise of cheap domestic gas is get-ting faded. In response to a internationally competitive bids invited by the NTPC in 2003, Reliance Industries (RIL) won the bid to supply natural gas the central sector gen-erating company at $ 2.97 per Mmbtu. The contract is under dispute on various counts including a cap on seller’s liability. Gas from the same field, at similarprice,wasalsotofeed8,000MW power plant of Reliance Energy in north India.RIL has recently tested the market by inviting bids to price the discovered gas. The process led to “discovery” of a price of $ 4.79 perMMBtu excluding transportation charges, taxes, etc. The price was later reworked to $ 4.33 per MMBtu. The idea of feeding the Indian power sector with cheap domestic gas does not seem promising anymore. Given that the government has accepted a “market” determined price of $ 4.75 perMMBtu for the Panna- Mukta-Tapti fields, any softening of natural gas prices for new discoveries would be welcomed by natural gas consumers in the country.The gas pipelines could help reduce the cost of delivered gas compared withLNG but at the cost of an increased risk of supply disruption. The diplomatic gains are argued to overweight the modest risks associated with supply disruptions [Verma 2007]. The pipeline negotiations seem to be regaining the lost momentum with the political change in Pakistan, albeit the growing enmity between Iran and the US. The pipeline, touted to be a step towards the Asian energy security grid, holds promise for increased energy cooperation in the region. The proposed gas utilisation policy proposes the following order of priority – fertiliser plants, LPG extraction, existing power plants, city gas distribution, replacement of liquid fuel in refineries, industrial users and greenfield plants in that order. Conse-quently, the availability of domestic natural gas for expansion of gas based capacity in the power sector would be very limited. The availability of the IPI pipeline can feed new power plants near the load centres in the northern region, which has a loca-tional disadvantage both with respect to the availability of coal as well as natural gas.8 ConclusionsThe natural gas supply from IPI gas is not expected to be cheap but it is expected to supplement natural gas availability in India. The “real” economic benefits of the IPI pipeline are to be found beyond the offered price of gas. Although security concerns are real, the project structuring and supply contract must envision the potential for disruption of supplies. The pipeline may serve as a “peace pipeline” and may serve to strengthen economic ties between India and Pakistan. This would also help open up access to large natural gas resources in Turkmenistan though the pro-posed Turkmenistan-Afghanistan-Pakistan (TAP) pipeline. The Asian Development Bank undertook a study for feasibility assessment of the TAPpipeline to export natural gas from theDaulatabad area of Turkmenistan. India has also been invited to participate in the project. While the Turkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline may derive little physical synergies from theIPI pipeline, the experience in forging the cross-border cooperation for theIPI pipeline provides a template for such efforts in future. In spite of the absence of significant regional cooperation in the electricity and oil and gas sector in the past, there is renewed enthusiasm towards strengthening such cooperation in the south Asian region.Changes in the geopolitical equations seem to have influenced the progress towards energy cooperation in the region. Improve-ment in availability of domestic natural gas at a “reasonable” price and favourable outcome of the civilian nuclear cooperation between India and the US may not significantly alter the energy security scenario for India in the short run. While, the supply concerns may obliterate the reasonableness of the natural gas supplies fromIPI pipeline, the efficacy of the IPI pipeline may stem from a thaw in the economic ties between the two neighbours and a scope for energy cooperation beyond the project itself. Table 11: Cost of Generation (Tariff) for Central Sector Generating Stations for 2005-06S No Type of Generating Station Cost of Generation (Tariff) 2005-06(Rs/kWh)1 Coal stations -pit-head 1232 Coal stations-non pit head 1943 Average cost of coal stations 1474 Lignite based thermal station 1715 Natural gas fuel 1676 Liquid fuel (naphtha/HSD) 700Ex-bus price as per the CERC’s revised Terms & Conditions of Tariff with improved norms and at 80% PLF.Figures are as on April 1, 2004.Source: Lok Sabha (2006).