People's Republic of Bangladesh: Preparing the Gas Sector Development Program (Financed by the Japan Special Fund)

Transcription

1 Technical Assistance Consultant s Report Project Number: April 2009 People's Republic of Bangladesh: Preparing the Gas Sector Development Program (Financed by the Japan Special Fund) Prepared by: Technoconsult International Limited Dhaka, Bangaldesh For Petrobangla This consultant s report does not necessarily reflect the views of ADB or the Government concerned, and ADB and the Government cannot be held liable for its contents. (For project preparatory technical assistance: All the views expressed herein may not be incorporated into the proposed project s design.

2 Final Report Volume 2: Main Report People s Republic of Bangladesh: Preparing the Clean Fuel Sector Development Program TA 4952-BAN Technoconsult International Limited Sena Kalyan Bhaban (7 th Floor), 195 Motijheel C/A, Dhaka Tel: , Fax: , info@tcil-bd.com, Web: Project Number: March 2009

3 CURRENCY EQUIVALENTS (as of 1 March 2009) Currency Unit Taka (Tk) Tk1.00 = $ $1.00 = Tk68.95 In this report, a rate of $1 = Tk70.00 has been used ABBREVIATIONS ADB Asian Development Bank ADP annual development program BAPEX Bangladesh Petroleum Exploration Company Limited BCF billion cubic feet BERC Bangladesh Energy Regulatory Commission BGFCL Bangladesh Gas Fields Company Limited BGSL Bakhrabad Gas Systems Limited cm cubic meter DCFP Dhaka Clean Fuel Project DEGTP Dhanua-Elenga Gas Transmission Pipeline DM distribution margin DPP development project proforma EA executing agency EIA environmental impact assessment EIRR Economic internal rate of return EMRD Energy and Mineral Resources Division EPZ export processing zone FIRR financial internal rate of return FY financial year GDP gross domestic product GHG greenhouse gas GSMP Gas Sector Master Plan GSRR Gas Sector Reform Roadmap GTCL Gas Transmission Company Limited GTDP Gas Transmission and Development Project GWh gigawatt-hour HCU Hydrocarbon Unit HSFO high sulphur fuel oil IEE initial environmental examination IOC international oil company IPO initial public offering IPP independent power producer JGTDSL Jalalabad Gas Transmission and Distribution Systems Limited JNGTP Jamuna Bridge (West)-Nalka Gas Transmission Pipeline kgoe kilogram of oil equivalent kiloton thousand ton (metric) km Kilometer kwh kilowatt-hour LRMC long run marginal cost MCF millennium (thousand) cubic feet MCM millennium (thousand) cubic meters

4 ABBREVIATIONS (Continued) MDG millennium development goals MMCF million cubic feet MMCFD million cubic feet per day MMCM million cubic meter MW Megawatt NEP National Energy Policy NPV net present value O&M operation and maintenance BPDB Bangladesh Power Development Board PDF price deficit fund Petrobangla Bangladesh Oil, Gas and Minerals Corporation PGCL Paschimanchal Gas Company Limited PRS poverty reduction strategy PSC production sharing contract psig pounds per square inch gauge PSMP Power System Master Plan BREB Bangladesh Rural Electrification Board ROR rate of return SCF standard conversion factor SD supplementary duty SGCL Sundarban Gas Company Limited SER shadow exchange rate SFR self-financing ratio SGC state-owned gas companies SGFL Sylhet Gas Fields Limited SWR shadow wage rate SWRGDN South West Region Gas Distribution Network T ton (metric) TA technical assistance TABGTP Titas-Ashuganj-Bakhrabad Gas Transmission Pipeline TCF trillion cubic feet TGTDCL Titas Gas Transmission and Distribution Company Limited TM transmission margin TNGDP Third Natural Gas Development Project toe ton of oil equivalent TOR terms of reference UNDP United Nations Development Programme VAT value-added tax WACC weighted average cost of capital NOTES (i) (ii) The fiscal year (FY) of the Government and its agencies ends on 30 June. In this report, "$" refers to US dollars.

5 CONTENTS Maps 1 Natural Gas Fields and Pipelines i 2 Gas Fields and Transmission Network ii 3 Gas Transmission Flow Diagram iii 4 Natural Gas Based Power Plants and Fertilizer Factories iv 5 Rehabilitation and Development of Titas Gas Field v 6 South Western Region Gas Distribution vi I. PURPOSE AND SCOPE 1 A. Introduction 1 B. Project Objectives and Output 1 C. Work Accomplished 2 D. Organization of the Report 2 II. THE SECTOR: PERFORMANCE, PROBLEMS AND OPPORTUNITIES 3 A. Performance Indicators and Analysis 3 B. Analysis of Key Problems and Opportunities 6 C. Gas Demand Assessment 15 D. Gas Supply 24 E. Gas Pricing 28 F. Government Policies and Plans 36 G. Policy Framework 39 H. Gas Sector Reform Roadmap 46 III. CLEAN FUEL SECTOR DEVELOPMENT PROGRAM 51 A. Issues 51 B. Impact and Outcome 51 C. Important Features 51 D. The Program 52 E. The Project 59 F. Project Cost Estimates and Financing Plan 71 G. Detailed Project Costs 72 H. Implementation Arrangements 79 I. Financial Review of Gas Sector Operations 83 J. Financial Projections of Executing Agencies 92 K. Social Assessment and Resettlement 105 L. Environmental Aspects 108 IV. PROGRAM BENEFITS, IMPACTS, ASSUMPTIONS AND RISKS 111 A. Expected Benefits 111 B. Economic Analysis 112 C. Financial Evaluation Of The Project 124 D. Risks and Safeguards 131 APPENDIXES 133

6 1 I. PURPOSE AND SCOPE A. Introduction 1. In the face of impending gas shortages as well as continued growth of Bangladesh s energy and natural gas requirements in recent years, the Government has requested ADB financing for several priority projects in the gas sector that would help implement its Poverty Reduction Strategy (PRS). 1 In January 2008, ADB engaged Technoconsult International Limited (TCIL, Consultant) to undertake the TA study. This Final Report presents the findings and analysis undertaken since February 2008 under the project preparatory technical assistance (TA) for the Clean Fuel Sector Development Program (the Program). 2 B. Project Objectives and Output 2. The sector goal is to facilitate economic growth, poverty reduction and environmental improvement through natural gas sector development. The purpose of the TA is to help the Government prepare a new gas sector development program to build on the progress from the ongoing Gas Transmission and Development Project (GTDP). 3 The Program will include (i) a policy agenda for improving the governance of the natural gas sector, and to improve sector institutions, and (ii) priority investments to support implementation of the Gas Sector Master Plan (GSMP) 4, and (iii) creating facilities for distribution of gas in new areas for which transmission system is being constructed under GTDP. 3. The TA is assisting the Government prepare the Program. Key activities include the following: (i) Adopting measures to ensure adequate gas supply in the eastern parts of the country. (ii) Analyzing the potential for economic growth and social development in less developed areas, particularly with reference to expanding natural gas supply and distribution in the western and southwestern regions of the country with the construction of the pipeline to Khulna under GTDP. (iii) Developing an investment package that identifies gas sector infrastructure development components. (iv) Reviewing the Program s investment components including cost estimates, financing plan, and procurement packages. (v) Performing detailed financial, economic, environmental, social, poverty reduction, and institutional analyses of the identified project components. (vi) Estimating the levels that greenhouse gas emissions will be reduced by the subcomponents. 1 Government of Bangladesh Unlocking the Potential: National Strategy for Accelerated Poverty Reduction. Dhaka. The PRSP is being updated for the period ADB Technical Assistance to the People s Republic of Bangladesh for Preparing the Gas Sector Development Program. Manila. The title of the project has been changed by ADB to the Clean Fuel Sector Development Program in the Country Operations Business Plan. 3 ADB Report and Recommendation of the President to the Board of Directors on a Proposed Loan to the People s Republic of Bangladesh for the Gas Transmission and Development Project. Manila 4 The GSMP was prepared by Wood Mckenzie in 2006 with financial assistance from the World Bank, and approved by the Government in 2007.

7 2 4. The terms of reference of the TA are in Appendix 1. The outputs of the TA comprise the following: (i) A sector development plan containing an analysis of opportunities for the sector s growth and development. (ii) A policy reform agenda for the development of the gas sector including promotion of public and private investments. (iii) Identification of priority investment projects with technical, social, economic and financial justification in accordance with relevant ADB guidelines. (iv) Assessment of institutional development and restructuring requirements to implement proposed policies and investment components. 5. Bangladesh Oil, Gas and Minerals Corporation (Petrobangla) was the Executing Agency (EA) of the TA and responsible for coordinating with its companies and for providing necessary support to the Consultant including access to information and project sites and facilities. The Energy and Mineral Resources Division (EMRD) of the Ministry of Power, Energy and Mineral Resources coordinated with other ministries and agencies on policy related aspects. C. Work Accomplished 6. The study commenced on 15 February 2008 and was scheduled for completion by the end of February As part of the TA study, the Consultant submitted the Inception Report on 31 March An Interim Report was submitted in August 2008 following the stakeholder workshop on Gas Sector Reform Roadmap and Demand Supply Balance that was held on 31 July The main aspects of the revised roadmap for the gas sector and a tentative policy reform matrix were included in the Interim Report. The Draft Final Report was submitted in January 2009 covering the entire TOR including preliminary assessments of environmental and resettlement issues. The Final Report incorporates, as appropriate, comments from ADB and the Government agencies including the tripartite review from February D. Organization of the Report 7. This Report is presented in four volumes. The first volume contains the executive summary in accordance with the ADB format for the Report and Recommendation of the President. The second volume comprises the main report, which addresses the TOR in a sequential manner. The sector problems are analyzed followed by an assessment of the role of the gas sector in meeting the Government s poverty reduction strategies and objectives, followed by resource assessment, demand supply assessment, gas network analysis, and policy and institutional review and analysis. 8. The Report sets out background on tariffs and financial performance of all Petrobangla companies in the sector. The Report also presents the draft revised Gas Sector Reform Roadmap (GSRR) recently adopted by the Government. A tentative time-bound policy reform matrix developed in consultation with the Government outlining conditions for the release of the two tranches of the Program loan is included. The scope of the investment component of the Program is then defined, and a comprehensive analysis of the technical, financial and economic aspects is presented. The environmental, social and poverty reduction impacts are discussed in accordance with the relevant ADB procedures and guidelines. 9. The third volume provides the related data and appendixes. The fourth volume contains the presentations made in the stakeholders workshop conducted during the project. The decision of the Bangladesh Energy Regulatory Commission (BERC) on Petrobangla s proposal for tariff adjustments is also included.

8 3 II. THE SECTOR: PERFORMANCE, PROBLEMS AND OPPORTUNITIES A. Performance Indicators and Analysis 1. Poverty Reduction Strategy 10. The Government s overarching goal and development vision, as articulated in the PRS adopted in November 2005, is to substantially reduce poverty and invigorate social development in the shortest possible time. The PRS has been replaced by an updated Medium Term Macroeconomic Framework and Policy Matrix. The PRS stresses the links between investment, growth, job creation, and poverty reduction, and identifies key areas where reforms are needed, public investments are required, and public policies merit improvement. The lack of specificity on sectoral governance reforms suggested the need for broad ownership for governance reforms within the government. The authorities are planning to address these issues in the second PRS, now under preparation. 11. In addition to specifying social targets in line with the country s millennium development goals (MDG), 5 the PRS commits the Government to halve the proportion of population living below the poverty line by the year To attain this target, Bangladesh needs to accelerate the pace of poverty reduction from 1.5% per year observed in the 1990s to 3.3% for the period The PRS stresses the links between investment, growth and job creation, and poverty reduction, and identifies key areas where reforms are needed, public investments are required, and public policies merit improvement. The strategy recognizes the need for acceleration of economic growth as the main vehicle for reducing poverty. If the past trends of income inequality persist in the next decade, Bangladesh will have to raise the economy s growth from about 5% per annum in recent years to 6-7% and sustain this growth rate over the next 15 years for reaching the MDG poverty reduction targets. In parallel, the strategy lays emphasis on improvements in governance, investment in human resource development, women s advancement and social protection. 12. Infrastructure, particularly energy, will play a very significant role in achieving the envisaged economic growth and poverty reduction. Infrastructural deficiencies continue to act as a major impediment to Bangladesh s developmental efforts. Reliable access to energy is essential for economic development and poverty reduction in Bangladesh. However, the energy sector has recently been afflicted by shortages of gas and electricity, stifling economic growth and social welfare. In addition to inadequate infrastructure coverage, poor management and inefficiency of publicly managed energy enterprises have created a huge fiscal burden and constrained the much-needed expansion of energy services to the growing needs of the economy. The Government will adopt a new approach to infrastructure development involving reorientation of sectoral priorities and increased private participation to alleviate infrastructure bottlenecks. To this end, the Government is implementing comprehensive sector reforms in energy development and management through a carefully sequenced approach to ensure reduced physical distribution costs and improve service delivery to the poor and poorer areas. Within this macroeconomic framework, a greater focus was needed on improving governance especially in sectors such as gas that is the prime indigenous source of energy in the country. 13. The natural gas sector, with its enormous potential in contributing to the development of the economy, has to be managed effectively to maximize its role in poverty reduction and generation of equitable benefits. However, in recent years the sector has to meet rapid demand increase while grappling with unsatisfactory management of sector infrastructure, inadequate 5 World Bank Poverty in Bangladesh: Building on Progress, joint poverty assessment by the World Bank and the Asian Development Bank. Washington.

9 4 tariff and price settings, poor operational performance and poor financial positions of sector institutions, energy security and inefficient use of gas caused by unmetered domestic consumption. The gas infrastructure is in a poor condition because of weak governance, lack of commercial orientation and inadequate funding for maintenance and expansion. The financial and technical capacity of the state-owned gas companies (SGCs) including Petrobangla is less than satisfactory. Poor financial performance and limited financial autonomy of the SGCs is largely due to the Government s inadequate pricing policies as well as operational inefficiencies. The operational performance in the gas sector has been affected mainly by high system loss and to some extent by infrastructure constraints and lack of investment resources. Various measures need to be undertaken to improve the performance of the gas sector. The PRS underscores the need for working out action plans for improving sector governance and the agencies operational efficiency and financial performance. The PRS also emphasizes implementation of policies directed towards expanding the national natural gas grid to cover western, north-western and south-western regions of the country to promote extensive industrialization and accelerate balanced regional development. 14. The strategic goals for the second PRS that is under formulation are to (i) ensure conservation measures for economic and efficient use of energy, and (ii) institutional restructuring of the gas sector entities for improved performance. The key targets are to (i) commercialize the gas sector, (ii) increase oil and gas reserves through extended exploration and development programs, (iii) attract private investment, (iv) expand national grid to cover western, northwestern and southwestern regions, (v) increase usage of compressed natural gas (CNG) as environment friendly clean fuel, and (vi) reform Petrobangla and restructure its companies to improve management capacity. The proposed Program conforms to the approaches outlined in the Government s strategy for the development of the gas sector to support its poverty reduction initiatives. 2. Role of Energy in Poverty Reduction 15. Commercial energy meets 47% of the total energy consumption of the country. Commercial energy is available to about 42% of the population as electricity, and to about 8% of the population as hydrocarbons, liquid fuels, natural gas, or liquefied petroleum gas. Natural gas accounts for almost 75% of the commercial energy and about 90% of electricity generation. In 2005/06, the country consumed 18.5 million ton of oil equivalent (toe) of commercial energy. Bangladesh s per capita consumption of commercial energy in various forms has improved rather slowly, from 82 kilograms of oil equivalent (kgoe) in FY1996 to 130 kgoe in FY The total consumption of natural gas increased from 332 billion cubic feet (BCF) or 2.63 million cubic feet (MMCF) per capita in FY2000 to 527 BCF or 3.71 MCF per capita in FY2006. The total consumption of electricity in FY2006 was about 23,430 gigawatt-hour (GWh) or 165 kilowatthour (kwh) per capita. 16. In the energy sector, the two largest greenhouse gas (GHG) emitting sources are electricity generation and non-energy use (urea fertilizer production) amounting to almost half of all the GHGs. The other significant GHG emitting sources are traditional biomass for energy, diesel for transport, kerosene for rural lighting, and coal for manufacturing bricks. In 1990, emission from energy sector was 21,186 kilotons including carbon dioxide and non-carbon dioxide emissions, which was approximately 30% of total GHG emission of Bangladesh. The GHG emission from the projected commercial energy requirements would increase from 10,100 kilotons in 2000 to 64,900 kilotons by In addition to expanded use of natural gas, rigorous 6 The per capita commercial energy consumption in 2006 was: 437 kgoe in Sri Lanka, 463 kgoe in Pakistan, 494 kgoe in India, 554 in the Philippines, 706 in Indonesia, 905 in the People s Republic of China, 1212 kgoe in Thailand and 2126 kgoe in Malaysia.

10 5 demand and supply side management, and development of renewable energy resources could help substantially reduce this emission (Appendix 2). 3. Resource Assessment 17. An assessment of the natural gas resources, the production from existing gas fields and the potential availability is in Appendix 3. The opening up of natural gas exploration and production to the international oil companies (IOCs) in the 1990s through production sharing contracts (PSCs) has contributed to improved gas supply in recent years. A study by the Hydrocarbon Unit (HCU) estimates Bangladesh s remaining recoverable proven and probable gas reserves at just over 16 TCF. 7 In earlier estimations, government agencies used recovery factors in the range of 52-72% for various fields. However, for fields recently discovered by the IOCs, the assumed recovery factors are in the range of 76-82%. The study reveals that with present day technology and good reservoir management practice, at least 70% recovery of gas could be achieved. As such recovery factors in the range of 70%-75% have been used depending on reservoir characteristics. This resource assessment also considered the option of lowering the abandonment pressure from 1100 pounds per square inch gauge (psig) to 500 psig by using compressor. There is a further possibility of 8 TCF in addition to these reserves (3P), while resource estimates for undiscovered fields are estimated to be 42 TCF at the 50% level (2P) and 64 TCF at the 10% level (3P). There is a 90% probability that undiscovered resources will be at least 19 TCF (1P) and could go up to 64 TCF with a mean of 42 TCF. Taking the discovered and undiscovered reserves together, there is a 90% probability that Bangladesh s gas resource will exceed 30 TCF. Some estimates indicate an undiscovered potential of up to 88 TCF, 8 about 5.5 times the reserves of 15.9 TCF proved and probable recoverable gas discovered to date that have been put on production. 18. Total proven recoverable gas reserves in Bangladesh from 23 fields (19 in the public sector and 4 in the private sector) are estimated at 20.6 trillion cubic feet (TCF), of which 7.68 TCF has so far been consumed. The current net recoverable reserve stands at TCF. Out of 23 gas fields, 17 gas fields have so far been brought under production (Map 1); 14 of these fields are currently under production. 9 Production from the remaining three fields was suspended due to various technical reasons. However, these three fields, namely Chhatak, Kamta and Feni, appear to have the potential to produce further with added efforts and IOC participation is in progress to redevelop these two fields. The total proved and probable recoverable reserves not on production at this time amounts to more than 4.0 TCF, of which 3 TCF was discovered in post PSC areas, the largest field being Bibiyana, with estimated recoverable reserves of more than 2.4 TCF. The gas transmission network and flow diagram are in Maps 2 and 3, while the location of the major power plants is in Map Natural gas would provide most of the current and future energy requirements, and the gas market needs to be expanded to optimize the use of natural gas resources and support economic development. Although Bangladesh is producing natural gas for over three decades, all of its major fields are underdeveloped and have not been properly delineated yet, and there are widely varying assessment of the country s natural gas resource potential. Resources are divided into discovered and undiscovered. The discovered resources are those that have been confirmed by drilling and reliable geological mapping. Undiscovered resources are yet to be confirmed by drilling and therefore have an increased level of uncertainty and risk attached to 7 Hydrocarbon Unit. Bangladesh Petroleum and Resource Assessment Hydrocarbon Unit. Bangladesh Gas Optimal Utilization Study BAPEX recently discovered a gas field at Srikail, which is under investigation.

11 6 them, depending on the assumed recovery factor that reflects the probability of the resources becoming at least equal to the estimated level The HCU study further elaborates that the combined play and prospect probability is only 12%. But according to the report similar geological settings in other parts of the world have proven successful and more and better information can help to reduce the risk, hence, increase the probability. However, in the Surma Petroleum System of Eastern Petroleum Province apart from Block 11, all other blocks have been extensively surveyed by Unocal (Currently Chevron) and Tullow and the only discovery made was 200 BCF Bangora gas field. Similarly in Eastern Delta-Hill Tract Petroleum System of the province, blocks 7, 9, 10, 15, 16, 17, 18, and 22 have been extensively surveyed by, Cairn, Chevron, Tullow in their respective blocks. The only unsurveyed block is part of block 6 in the system. So far there had not been any discovery in the blocks after the studies were made. However, two new structures, one in block 7 by Chevron and the other in block 10 by Cairn were delineated through seismic survey. B. Analysis of Key Problems and Opportunities 1. Natural Gas Resource Availability 21. As most of the attractive on-shore blocks have been surveyed using state-of-the-art seismic technology, it can be confidently said that the undiscovered gas resource potential of the country with 50% probability is neither 32 TCF nor 42.1 TCF as suggested by Petrobangla- United States Geological Survey study and HCU study respectively. Similarly, the undiscovered gas resource potential of the country with 90% probability is neither 8.4 TCF nor 19 TCF as suggested by the two studies. After the studies carried out by the two groups, seismic surveys conducted over the potential onshore blocks could only delineate two new structures one in Block 7 and the other in Block 10. However, the offshore blocks 19, 20, and 21 have not yet been surveyed or tested. Blocks 17 and 18 have been surveyed by Total-Tullow joint venture but results are not yet known. The study did not consider the offshore area to be at all prospective. Thus from the resource potential of 32 TCF to 42 TCF as pointed out by the Petrobangla-USGS and HCU studies, no specific reserve should be considered for future planning or any business opportunities, since the failure of delineating any significant structures or gas fields by the recent surveys conducted in the potential blocks has highly downgraded the prospects of the whole area. 22. A major concern in the gas sector is the security of adequate gas supply. Petrobangla's estimates show that there will be shortfall in gas supply from the year The problem is not only that reserves and infrastructure to supply gas are insufficient, but that, absent better policy mechanisms for allocating gas to different projects and sectors, there is a risk that Bangladesh is over-committing its scarce gas reserves. If the present demand-supply scenario persists, Bangladesh will be unable to meet its commercial energy demand from indigenous sources. There was a move a few years ago among the Governments of Myanmar, Bangladesh, and India on a private sector inter-country investment proposal that would enable the import of about million cubic feet per day (MMCFD) of natural gas from Myanmar to India across Bangladesh. However, these discussions have remained inconclusive for various political and economic considerations. Recent Bangladesh initiatives for the import of natural gas from Myanmar have also not led to any successful understanding beyond a general indication that the Bangladesh proposal may be considered against future discoveries of gas reserves as most of the current production has been committed for exports to other countries including People s Republic of China and India. 10 When using probabilistic methods in resource estimation, the terms proven, probable and possible are used. Proved (1P) represents 90% probability, proved and probable (2P) represent 50% probability, and proved, probable and possible (3P) together represent 10% probability.

12 7 23. Bangladesh has an on-shore area of 144,000 square kilometers (sq km) and an offshore area of 63,000 sq km with only 68 exploration wells drilled countrywide and 22 discoveries. The Bengal Basin is unexplored when compared to other significant hydrocarbon province on a worldwide basis with a relatively high rate of exploration success. As such, intensive hydrocarbon exploration is needed in unexplored frontier and virgin areas. Foreign and local enterprises are to be encouraged to invest for hydrocarbon exploration in the country. 24. Although IOC production has already reached about 50%, Petrobangla predicts that over the next 12 years, IOC production will comprise 30 to 45% of supply with the balance from SGCs. The SGCs will drill 43 wells during the next 12 years at a total cost of $266 million and require an additional $84 million for gas treatment plants. The producing companies are generating sufficient cash resources at the well-head margin of Tk0.75 per cubic meter (cm) that should enable them to make these investments. The IOCs will be required to invest $275 million, most of this from Chevron. Definitive contractual gas supply and investment commitments have been made and its international financial resources are sufficient to fulfill these commitments. 25. Recognizing the acute gas supply situation, the Government has emphasized further exploration and development of onshore and offshore gas fields. The third round of bidding for offshore exploration is underway since March Although the response has not been highly encouraging, PSCs with successful IOCs may be finalized in FY The potentially substantial natural gas reserves have remained under-exploited. Domestic gas use is under priced considerably, leading to a high opportunity cost in terms of foregone resources that could have been mobilized to support investment within and outside the sector, especially given the country s massive development financing needs. Performance in the gas sector has been limited well below the potential because of the low gas exploitation, limited use of the domestic market, significant under pricing of gas sales and high system loss. There may still be a large quantity of gas to be discovered under suitable economic and policy conditions. 2. Gas Transmission Issues 27. Petrobangla has moved progressively from separate isolated systems to an integrated transmission network delivering gas to the four distribution companies serving distinct franchise areas. The Jalalabad Gas Transmission and Distribution Systems Limited (JGTDSL) for the Sylhet area, Titas Gas Transmission and Distribution Company Limited (TGTDCL) for greater Dhaka and Mymensingh areas, Bakhrabad Gas Systems Limited (BGSL) for the Chittagong area, and Paschimanchal Gas Company Limited (PGCL) for the Rajshahi division. JGTDCL, TGTDCL, and BGSL used to own dedicated transmission lines to meet their gas demand. 28. The first step towards integration was the implementation of a 20-inch pipeline linking Bakhrabad gas field to Demra, at the inlet of the greater Dhaka distribution network. This line was constructed for supplying gas from Bakhrabad gas field to TGTDCL franchise area. The line remained underutilized for a long time as production from Bakhrabad gas field, which was developed primarily to meet Chittagong gas demand, depleted fast. The 14-inch and 16-inch lines from Titas gas field to TGTDCL franchise area passing through Narsingdi were also saturated and created bottlenecks in supplying required gas to greater Dhaka area. The second step towards an integrated system was the completion of a north-south pipeline allowing gas transfer from Kailastila in the north to Ashuganj. The completion of Ashuganj -Bakhrabad the AB pipeline (59 km of 30 inch pipeline) effected the physical integration of three separate systems.

13 8 29. The AB pipeline removed two major bottlenecks. Firstly, the gas flowing from Ashuganj to Bakhrabad supplemented the short supply from the Bakhrabad gas field to the Chittagong area. Secondly, it allowed the creation of a loop feeding Demra from Titas through the AB line and then through the currently idle 20 inch pipeline from Bakhrabad to Demra. 30. The main gas transmission grid in Bangladesh is operated and managed by the Gas Transmission Company Limited (GTCL). Most of the gas fields supply points are in the northeast and central regions of the country, while delivery points are located in the west, greater Dhaka and Chittagong areas, and for the past few years to the region west of the Jamuna River. Pipe lengths and diameters of the current system are shown in Table 1 and the estimated throughput capacities of the major parts of the system are shown in Table 2. Table 1: Existing Gas Transmission Network Pipeline Segment Diameter (inch) Length (km) Kailastila Muchai Muchai - Ashuganj Ashuganj-Bakhrabad Bakhrabad-Meghnaghat Meghnaghat-GTCL Demra Bakhrabad- Chittagong Ashuganj-Manohardi Manohardi-Dhanua Dhanua-Elenga Elenga-Jamuna Bridge (East) Jamuna Bridge (East) Jamuna 30 9 bridge (West) Jamuna Bridge (West)-Nalka Km = kilometer Source: GTCL Table 2: Gas Transmission Capacity System Pipeline Segment Capacity (MMCFD) Inlet/Outlet Pressure (psig) North South Kailastila - Ashuganj /850 Ashuganj- Bakhrabad- Meghnaghat Ashuganj- Meghnaghat Ashuganj Nalka Ashuganj-Nalka with Manohardi loop MMCFD = million cubic feet per day, psig = pounds per square inch gauge Source: GTCL / /550

14 9 31. The major bottlenecks in the transmission network are from Ashuganj to Ghorasal and also from Ashuganj to Chittagong. Further, saturation of North-South pipeline reduced available gas pressure at Ashuganj and thus the capacity of the downstream network to a great extent. To meet gas demand in the Ghorasal and Dhaka areas, the 24-inch Ashuganj-Manohardi- Dhanua-Elenga pipeline was tapped at Dhanua and Elenga, and two 20-inch lines were constructed from Manohardi to Narsingdi and Dhanua to Aminbazar. Installation of compressors at Muchai and Ashuganj will help in transmitting additional gas through the North-South pipeline and raising pressure at Ashuganj to the design levels of the downstream systems. Looping of the 20-inch Bakhrabad-Demra pipeline with a proposed 30-inch pipeline under the Siddhirganj Peaking Power Project funded by the World Bank will ease the supply situation in GTDCL franchise area. However, since the Chittagong area will largely depend on gas supply from the North-Eastern fields because of the depletion of the Bakhrabad and Sangu gas fields, capacity enhancement of the Ashuganj-Bakhrabad-Chittagong pipelines will be required to meet the fast growing demand in the Chittagong area. 32. The pressure gradient of a pipeline gives an indication of the optimum use of the available pipe cross sectional area. The ideal pressure gradient for design and operation is 3-7 psi per mile. Pressure gradients of less than 2 psi per mile imply an oversized pipe, meaning that any expansion will likely require compression. Pressure gradients greater than 8 psi per mile imply higher operation costs and high velocities and any expansion will likely require looping of pipelines. The pressure gradients on the existing system are shown in Table 3. With the exception of the Rashidpur Habiganj segment, any expansion of the indicated subsystems of the GTCL grid will likely require compression first. The current system has no compression, although compressor projects at Ashuganj and Elenga funded through GTDP are under implementation and are expected to be commissioned around Table 3: Gas Transmission Pressure Gradients Pipeline Segment Pressure Gradient (psi per mile) Habiganj Ashuganj 1.8 Rashidpur Habiganj 6.7 Bakhrabad Chittagong 1.2 Ashuganj Bakhrabad 1.4 Bakhrabad Meghnaghat 4.6 Manohardi Elenga 1.3 psi = pounds per square inch Source: Consultant estimates a. North-South System 33. Compressor facilities at Muchai will enhance the deliverability of gas from northeast gas fields into the Ashuganj hub. The flow capacity of the compressor has been liberally sized up to 1,735 MMCFD. Based on the current assessment, the gas production in the catchment area of Muchai compressor station could be around 1,450 to 1,500 MMCFD. After meeting the demand of JGTDSL (250 MMCFD), about 1,200 to 1,250 MMCFD of gas would be available for compression at Muchai by The existing pipelines between Muchai and Ashuganj have transmission capacity of about 1,350 MMCFD with Muchai discharge pressure of 1,050 psig and Ashuganj suction pressure of 680 psig (when the compressor stations at the both ends are commissioned). In the event more than 1,350 MMCFD of gas would be available from

15 10 upstream of Muchai in future for transmission to Ashuganj, looping of the Muchai-Ashuganj section may be required. b. West System 34. Under already planned projects, a total compression facility of about 2,267 MMCFD is being installed at Ashuganj hub out of which 1,502 MMCFD is earmarked for the west of Ashuganj demand centers (i.e. TGTDCL, PGCL and SGCL). To make the best use of the compression facilities, the planned downstream pipelines must be completed in parallel. A compressor station is under implementation at Elenga. The flow capacity of the compressor is stipulated to be 500 MMCFD at a discharge pressure of 1000 psig and suction pressure of 600 psig. The proposed addition of a 30-inch pipeline between Dhanua and Elenga is primarily meant to address the transmission capacity limitation between the Ashuganj and the Elenga compressor stations. c. Central-South System 35. The central-south transmission network consists of the Ashuganj-Bakhrabad-Chittagong section plus some spur lines connecting the Bakhrabad hub to the greater Dhaka region. Of the projects already approved for implementation, the installation of reciprocating compressors at Bakhrabad will facilitate the evacuation of medium pressure gas to the Bakhrabad - Chittagong line from the gas fields in the vicinity. For this system, a flow of 795 MMCFD has been earmarked from the Ashuganj compressor station once it has been completed. Until the compressors are installed, deliverability of gas to Chittagong will remain problematic. The erratic and fast-depleting Sangu gas field that feeds directly to the Chittagong ring main further aggravates the problem. 36. The basic difficulties in upgrading the existing gas transmission system arise from the fact that the network has been laid in a piecemeal fashion over a long period and it is only very recently that a serious thought has been given under GTDP to a mix of compressor and pipeline extension to augment transmission capacity. Consideration of existing gas demand and expected future demand growth patterns on a geographical basis is a prerequisite for any planning and analysis for future transmission network expansion and capacity augmentation. The imbalance in demand and supply, in the nine load centers, shown schematically in Appendix 3 underscores the requirement for, and importance of, augmenting and reinforcing gas transmission in Bangladesh System Loss 37. The operational performance in the gas sector has been affected by high system loss. The efficiency of gas distribution to non-bulk consumers has been quite unsatisfactory (Appendix 4). The overall gas system loss or unaccounted for gas ranged from 4.5% to 6.5% during FY2000-FY2005 (Table 4). These system losses were much higher than the 2% covenanted for the different gas distribution companies under ADB s Third Natural Gas Development (TNGDP) Project that closed on 23 October 2003, 12 and the experience in most countries in the region. The distribution losses were very high, ranging from 13 to 21%, while the transmission loses were within reasonable levels, less than 1-2%. The system losses for TGTDCL have been very high ranging from 7 to 24%, while that for the other three distribution companies BGSL, JGTDSL and PGCL are much less. For instance, BGSL maintained 11 ADB Technical Assistance to the People s Republic of Bangladesh for Gas System Development Plan. Manila. 12 ADB Report and Recommendation of the President to the Board of Directors on a Proposed Loan and Technical Assistance Grants to the People s Republic of Bangladesh for the Third Natural Gas Development Project. Manila

16 11 system losses less than 2% up to FY1999. The losses went up to 4.1% in FY2002 but have come down to about 1% in the past two years. JGTDSL maintained system losses at less than 2% throughout since FY1993, and in recent years the losses came down to less than 1%. PGCL has maintained a system loss at less than 1% since its inception in FY2000. Since then some improvement has been achieved with the average losses falling to 2.8% and non-bulk supply to 5.8% reflecting the impact of the measures undertaken in recent years across all gas distribution companies. 38. Gas losses result from commercial activities or the physical components of the gas production, delivery and marketing system. The losses from the physical components, referred to as fugitive or technical losses, result from small leaks at compressor and pump shaft seals, metering stations, gas meters, pipelines, household appliances, and operating procedures involving flaring, venting, purging, etc. Commercial losses arise during the transfer of gas ownership activities and result from incorrect or no meter readings, nonpayment for billed gas, theft, etc. Table 4: Summary of Gas System Loss (%) Year (ending June) TGTDCL BGSL JGTDSL PGCL OVERALL (AVERAGE) Total Distribution Total Distribution Total Distribution Total Distribution Total Distribution (-) (-) (-) 3.23 (-) (-) 2.44 (-) (-) 1.88 (-) (-)0.29 (-) 1.05 (-) 0.45 (-) (-)0.60 (-) 2.15 (-) 0.40 (-) (-)0.01 (-) (-)0.06 (-0.42) BGSL = Bakhrabad Gas Systems Limited; JGTDSL = Jalalabad Gas Transmission and Distribution Systems Limited; PGCL = Paschimanchal Gas Company Limited; TGTDCL = Titas Gas Transmission and Distribution Limited Source: Petrobangla 39. A combination of factors accounts for the high distribution loss resulting in a high overall system loss. These include meter inaccuracy, leakage, or loss due to flat rate domestic use, and theft or fraud, which account for 70% of the system loss. Sales of gas to domestic gas consumers are not metered. The norm for 2 burners per customer, which most customer have, is 87 cm per month but sample tests show that consumption of 110 cm per month is not unusual. The flat charge unrelated to consumption undoubtedly results in burners being left on unnecessarily because of convenience, such as having hot water readily available at all times. 40. The gas system loss of between 5 and 6% that occurred until recently effectively represents a 24% loss on non-bulk distribution (e.g. to industrial, commercial and domestic consumers), rather high compared to levels in other countries. 13 Allowing 2% transmission and distribution loss as acceptable norm in the gas industry, the cost of gas system loss is 13 In India, Mahanagar Gas Limited in Mumbai and Indraprastha Gas Limited in Delhi, both privately owned companies, incurred about 5-6% system loss in the beginning, this is now below 1%. This was possible due to the introduction of modern metering system, regular calibration and improved monitoring system.

17 12 substantial, estimated at about Tk2.4 billion per year. In addition, the cost of collection inefficiency is also sizable. Assuming a norm of 98% collection-billing ratio, the cost of collection shortfall is estimated at Tk1.8 billion per year. 41. Recently, the TGTDCL has initiated several measures to contain the system losses. These include installation of meters, privatization of meter reading and billing and adoption of measures recommended under an ADB TA provided in conjunction with the TNGDP. 14 The TA made several recommendations and developed a plan for reducing system loss that includes installation of meters, and privatization of meter reading and billing. These include increased vigilance, severance of unauthorized connections, legal proceedings to recover outstanding and delinquent payments. The plan was revised into a comprehensive efficiency improvement and system loss reduction plan for the entire gas sector and adopted for implementation under the GTDP (footnote 3). Steps are being taken to install meters for domestic consumption that could bring down consumption considerably, and very likely from the current level of 110 cm to 87 cm per month. Although about 45% of the gas tariff is government taxes, the economic savings from metered sale will still provide a very attractive return. Since the distribution companies are natural monopolies providing a service, all of their costs are to be recovered from the customers in due course. Gas theft by the commercial and industrial consumers could be reduced by more rigid monitoring, and enforcement of relevant regulations. The enactment of the proposed gas act will empower the distribution companies to take legal actions against fraud, theft, malpractices, and delinquent customers. 4. Sector Governance 42. The institutional framework for the energy sector particularly that for the gas sector and Petrobangla including the SGCs, is summarized in Appendix 5. Petrobangla coordinates the gas sector activities in the country while the EMRD provides the overall policy direction. Petrobangla carries out its gas business through nine operating companies. The gas sector companies are: Bangladesh Petroleum Exploration Company Limited (BAPEX), engaged in exploration and production; Bangladesh Gas Fields Company Limited (BGFCL) and Sylhet Gas Fields Limited (SGFL), involved in gas field development and production; GTCL, involved in transmission; TGTDCL, BGSL, JGTDSL and PGCL involved in transmission and/or distribution; and Rupantarita Prakritik Gas Company Limited (RPGCL) involved in liquefied petroleum gas (LPG) and compressed natural gas (CNG) marketing. TGTDCL, being the oldest and largest, operates in the franchise area of Dhaka division (excluding greater Faridpur district) and Brahmanbaria district. BGSL serves the market in Chittagong division excluding Brahmanbaria district. JGTDSL serves the market in Sylhet division while PGCL operates in the franchise area in Rajshahi division. A new company Sundarban Gas Company Limited (SGCL) is being established for the distribution of gas in the Southwestern region. 43. Private sector interest and foreign direct investment in the gas sector has increased significantly since the mid-1990s, when the Government extended opportunities to foreign companies to explore, extract and produce gas under PSCs. The involvement of the IOCs has contributed to improved gas supply in recent years. The situation could have been better if more gas exploration activities could be undertaken. However, 43% of the total energy needs of the country continue to be met by biomass, particularly in rural areas. The situation reflects infrastructural constraints in the supply of gas, including inadequate production and lack of an efficient transmission and distribution system. The country s natural gas reserves are under exploited, while bulk and domestic gas use is significantly under priced. This results in high opportunity cost with respect to unutilized resources that would have supported investment 14 ADB Technical Assistance to the People s Republic of Bangladesh for Safety and Efficiency Improvements in the Gas Sector. Manila provided in conjunction with the Third Natural Gas Development Project.

18 13 within and outside the sector. The SGCs in practice do not have the governance attributes of a fully corporatized entity. Approval of organizational set up, compensation policy, budget and development projects are still subject to scrutiny and approval by Petrobangla and/or the Government. 44. The gas sector is regulated and administered by the Government, although there have been initiatives for limited private sector involvement during the last few years particularly for retail sale of compressed natural gas to the transport sector and of liquefied petroleum gas to households or commercial establishments. The Government, through the EMRD manages the authority for policy formulation, appointment and transfer of officials, investment decision and regulation. Petrobangla was created under the Presidential Order 27 of 1972, and subsequently incorporated through a series of ordinances as a state corporation for oil and gas exploration, production, transmission and distribution. Since 1994, when the first round of PSCs was entered with the IOCs responsible for drilling, Petrobangla has served as supervisor and sole purchaser of IOC outputs. 45. Petrobangla no longer has a direct operational role and conducts its sector oversight and management activities through nine operating companies. These SGCs are incorporated as public limited companies under the Companies Act of 1994 and governed by separate boards of directors. Petrobangla and EMRD have authority to override major board decisions on matters of pricing, operating and development budgets, operational structure and staffing. The directors of the operating companies are either directors of Petrobangla, or government officials and individuals appointed by EMRD, including representatives from different chambers of commerce and industries, and technical universities. 46. The financial performance of Petrobangla and its subsidiary entities has been affected largely by pricing and taxation policies but also by operational efficiencies and default by consumers. Petrobangla earns an overall modest profit despite significant under pricing of gas sales from its fields and despite purchasing gas from IOCs at a price that is linked to world price of alternative fuels heavy fuel oil. This is largely because production from its entities that account for half the total supply is valued at a very low price, reflecting very low costs of production from fields developed on average years ago. This has left very little margin for exploration and production companies. Petrobangla s low cost of production from fields developed many years ago is significantly less than the current opportunity cost of gas, as reflected by its cost of commercial purchases from IOCs under PSCs for recently developed fields. In addition, gas has been underpriced significantly, with about 80% of its gas supply to power, fertilizer and household sectors being subsidized heavily, with no budgetary transfer to compensate Petrobangla. The deficiencies in the supply of gas in relation to the demand experienced in recent years have underscored the need for augmenting gas exploration and production. 47. However, all SGCs are making net profit. As of 30 June 2007, cumulative retained earnings of SGCs except BAPEX stood at Tk27,112.4 million ($ million equivalent). However, on the same date Petrobangla and BAPEX s cumulative losses stood at Tk28,726 million ($420 million equivalent) and Tk1,794 million ($26.2 million equivalent), respectively. During FY cumulative profit of Petrobangla and SGCs was Tk3,724 million. Though BAPEX is making operational profit, net losses were due to relatively smaller gas production share compared to asset base and servicing of past liabilities transferred from Petrobangla to BAPEX. Petrobangla losses were due to irrational pricing of IOC gas that allowed SGCs to make substantial profit. Following completion of cost recovery period of Bibiyana and Moulavibazar gas field development by Chevron, Petrobangla is likely to make substantial profit from FY

19 The public sector gas companies including Petrobangla are supposed to operate as commercially viable entities but they neither have the desired operational autonomy, nor are allowed market-based well-head prices to fund exploration and gas field development. Consequently, they have not been able to finance investment to expand, upgrade and maintain the infrastructure network adequately. Petrobangla has not undertaken any significant geophysical survey or drilled any exploration well for many years. Its transmission and distribution investments, funded entirely by the Government under the annual development program (ADP), have been inadequate. As a result of the present policy of practically operating as a government department, Petrobangla is indifferent to market signals and has no incentive to improve its efficiency; capital expenditures are incommensurate with the size of its operations, and it has been depleting its gas reserves without replacing these. Recently, the Government brought about major changes in the management of the sector entities by associating nongovernmental individuals and by delegating more authority. The Government has also allowed full autonomy to the gas sector entities, but that is yet to be fully practiced. 49. Another area of inefficiency relates to the unsatisfactory management of gas infrastructure. This is partly due to delayed or inadequate investment in expansion of the gas transmission and distribution network and its operation and maintenance (O&M). This has limited the market and constrained Petrobangla s gas production, causing supply shortages and disrupting economic activities in fertilizer production and power generation. Progress toward institutional reform and improved management in the gas sector has been slow. The main issue appears to be the varying receptiveness to reform among concerned senior officials in the executing agencies, Petrobangla and EMRD. The increasing supply of gas since 1997 through PSCs is believed to have resulted in less pressure on authorities to adopt reforms promoted by ADB and other development partners. 50. Public sector resources are limited to providing adequate support to meet the gas sector s essential investments such as increasing gas exploration, further expanding gas transmission pipelines, and reactivating abandoned gas fields. The scale of the required investments in exploration implies a significant role for the private sector in this area, provided that right incentives are made available. Private sector participation in gas transmission and distribution could help improve operational efficiency in these areas. In this context, an ADB TA executed during outlined measures for promoting private sector participation and ensuring sustainable development. 15 The detailed examination of sector structure, unbundling of companies, and investment planning was undertaken to meet the reform objectives and to facilitate greater private sector participation in the gas sector. 51. Despite the resource constraints, little effort has been made in creating an enabling environment for mobilizing private sector resources to finance required investments in these areas. Some limited private sector involvement in marketing and distribution of oil, LPG and CNG has, however, been initiated. Proposals for restructuring and offloading the shares of two gas companies (BGSL and TGTDCL) have been under consideration for quite some time, but progress in implementing them could be expedited. Future sectoral governance strategies should place emphasis on improving efficiency, mobilizing private sector resources to support demand side of gas development, production and supply, and in assisting the Government to reflect its role in ensuring efficient regulation and oversight and responsiveness to stakeholder interests, expectations, and inputs. Losses in the gas sector largely occur in the distribution phase. 15 ADB Technical Assistance for Promoting Private Sector Participation in the Energy Sector. Manila

20 The legal framework for the establishment of BERC was enacted on 13 March 2003 and the BERC was made effective from 27 April After several years, BERC is now composed of a full complement of members since mid Measures are now being taken for making the BERC fully operational through approved service rules, licensing regulations and operating procedures. The Government will need to empower BERC in an active way, to provide not just the legal mandate but also the moral authority to carry out its work. BERC has received considerable TA supports from the United States Agency for International Development and the World Bank to help with its work. Such supports cover a range of institutional strengthening and training activities, specific studies of immediate interest, and provision of resident advisory support from experienced consultants with professional experience working within a regulatory agency. However, without adequate funds independent of government budgetary resources and competent staff, BERC will not be able to operate as a true regulatory body as it evolves, and the Government will carry out the regulatory role, as it has done in the past. Furthermore, the BERC Act limits its role to only downstream activities, leaving the upstream operations to direct government control and intervention through Petrobangla. C. Gas Demand Assessment 53. Petrobangla has recently revised its forecast of gas demand through to the year This forecast supersedes that prepared by Wood Mackenzie in 2006 as part of the GSMP, and is now its official forecast. This section discusses Petrobangla s demand forecasting methodology, compares it with the GSMP forecast, and identifies the forecast adopted for the purposes of analysis in this report. 1. Historic Consumption 54. Gas consumption rose from a total of 365 BCF in FY2001 to 557 BCF in FY2008, a compound average annual growth rate of 7.3% (Appendix 6). Sector-wise, the highest consumption growth rate was in the non-bulk category with an average growth rate over the period of 23%. The non-bulk category comprises the industrial sector, the commercial sector, domestic sector, tea, seasonal, and CNG. In FY2006, industrial and household consumers accounted for approximately 49% and 40% respectively in the non-bulk category. Between FY1999 and FY2007, average annual growth rates in consumption by industry and domestic sectors have been recorded as 12.4% and 16.3% respectively. The high rate of growth in domestic consumption can be attributed to rapid growth in the construction sector (real estate s), large scale rural-urban migration of population and scarcity of alternative cheaper fuel for domestic use. CNG recorded phenomenal growth during FY2003 to FY2007, going from BCF in FY2003 to 24.2 BCF in FY2008. Government initiatives for arresting air pollution through encouraging use of indigenous natural gas, increase in prices of alternative fuels for use in the automobiles, increase in the number of CNG run vehicles, and expansion of multi-use of indigenous natural gas have been identified as some of the major contributors to such high increase in the consumption of CNG. Growth in gas consumption in the electricity and fertilizer sectors was 1.5% and -6.5% respectively over the period. Table 5 summarizes historic growth in gas consumption for the country and for each of the four distribution companies. 2. Revised Demand Projections a. General Approach 55. Petrobangla has prepared its forecast under four broad sectors: power, captive power, fertilizer and non-bulk. The power sector gas forecast is driven by gas requirements for existing and planned gas-fired power stations. A similar approach was adopted for the fertilizer sector.

21 16 For other sectors a growth rate was determined and applied to the most recent full-year consumption data to arrive at a forecast consumption figure. 56. Petrobangla adopted an iterative approach in finalizing its demand forecast, matching available supply to estimated demand to ensure a reasonable balance. For this reason, Petrobangla s forecast does not reflect true demand, as growth rates have been adjusted downwards by Petrobangla to reflect increasingly tight constraints on supply. This is particularly true of the power sector. As such, Petrobangla s forecast is best described as a constrained demand forecast as it does not include demand that Petrobangla does not intend to or is unable to supply. Table 5: Historical Gas Sales (BCF) Company Sector Gas Sales FY2002 FY2003 FY2004 FY2005 FY2006 FY2007 FY2008 CAGR (%) TGTDCL Electricity Fertilizer Non Bulk Total BGSL Electricity Fertilizer Non Bulk Total JGTDSL Electricity Fertilizer Non Bulk Total PGCL Electricity Fertilizer Non Bulk Total All Bangladesh Electricity Fertilizer Non Bulk Total BGSL = Bakhrabad Gas Systems Limited; CAGR = compound average growth rate; JGTDSL =Jalalabad Gas Transmission and Distribution Limited; PGCL = Paschimanchal Gas Company Limited; TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla b. Power Sector 57. The Bangladesh Power Development Board (BPDB), the Bangladesh Rural Electrification Board (BREB) and the independent power producers (IPPs) are the major players who generate and supply electricity to the national power grid. Off-grid captive power generation located in industrial and commercial centers serve electricity for self-consumption and for consumption in adjoining areas. Total installed generation capacity was 5,245 megawatt (MW) as at 31 December 2006, with 3,985 MW owned and operated by PDB and 1,260 MW owned and operated by the private sector. 58. In the period FY2006-FY2008, peak power supply was 4,130 MW. Shortage of gas supply meant that actual peak demand could not be supplied, and an estimated 800MW of load shedding was required to balance demand and supply. During the same period, 22,743 gigawatt-hour (GWh) of generation was dispatched according to BPDB, 87% of which was gas-

22 17 fired while the rest was generated from oil, hydro, and coal. Generation of electricity by the public and the private sectors are approximately 65% and 35% respectively. 59. BPDB uses the electricity demand forecast that was prepared as part of the 2005 Power System Master Plan (PSMP) as its base forecast for system planning purposes. The forecast was econometric in nature, and used population growth and a series of assumptions regarding income and power price to derive a base electrical energy demand forecast, from which a peak demand forecast was generated. Network losses were then added to determine generating plant capacity requirements and energy requirements. BPDB s base case generation expansion plan relies heavily on gas as a fuel. An alternative generation expansion scenario was also developed that assumed constraints on gas supply resulting in heavier use of coalfired plant in the generation mix. 60. On the basis of its base case expansion plan, BPDB has proposed 17 new gas-fuelled power plants in the public sector and five new gas-fuelled private sector power plants for commissioning by the year The capacity of the 17 public sector plants total 3775 MW and would require 744 MMCFD of gas. The 1,840 MW of private sector plant would require 315 MMCFD of gas. The proposed plants are a mix of peaking gas turbines and combined cycle plant (gas turbine and steam turbine) for base and mid-load duties. Supply of gas to 660MW of proposed rented power generating plant and 220MW of proposed small IPPS was also requested by BPDB. Gas requirements were stated as 202 MMCFD and 103 MMCFD respectively. 61. Petrobangla has assessed its ability to supply the new power plants based on expected gas availability and, through negotiations with BPDB, has committed to supplying 12 of the 17 public sector power plants and four of the five private sector plants. However, Petrobangla has said that gas supply to three of the public sector power plants will be possible only after June 2011 and will depend on the progress with the construction of new transmission pipelines and installation of compressors at certain points in the network. Table 6 and Appendix 7 list the power generating facilities that will be supplied with gas by Petrobangla, and Table 7 shows the corresponding gas demand forecast for the power sector. In total, Petrobangla has informed BPDB that it will not be able to provide gas for 1,950 MW of proposed new generation. In the context of a system with total installed generating capacity of 5,245 MW currently, 1,950 MW is a significant block of generating capacity. 62. The base case GDP growth forecast adopted in the GSMP forecast assumes constant real growth of 5.5%. Average GDP growth rates of 6.8% and 7.9% were also tested. Demand growth was assumed moderated downwards by percentage points by an anticipated move to economic cost-reflective gas and electricity tariffs over the period In converting from electricity demand to gas demand, a theoretically ideal generating plant mix was assumed, and an expected gradual increase in generating plant efficiencies was taken into account. The GSMP electricity demand forecast was similar to the forecast in the PSMP. BPDB commented, however, that the plant efficiency improvement assumed in the GSMP electricity forecast is unlikely to be achieved in practice. The implication of this is that the GSMP forecast for gas demand in the electricity sector is likely to slightly low, especially if tariff rationalization does not occur or is delayed significantly.

23 18 Table 6: New Gas-Fired Power Generating Facilities BGSL = Bakhrabad Gas Systems Limited, JGTDSL = Jalalabad Gas Transmission and Distribution Systems Limited, PGCL = Paschimanchal Gas Company Limited, SGCL = Sundarban Gas Company Limited, TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla

24 BPDB commented that it is now in a situation where neither of its generation expansion scenarios is realistic, given much tighter than expected gas supply and the absence of any commercial development of Bangladesh s coalfields. BPDB will need to substantially update its master plan to account for the fuel resource constraint that it is facing. The general constraint on gas supply to other sectors of the economy also has an implication for the electricity demand forecast in the PSMP in that some fuel substitution away from gas to electricity would be expected. Fuel substitution towards electricity was not incorporated in the PSMP demand forecast. On the other hand, PDB s base electricity demand forecast assumed reasonably constant growth in Bangladesh s GDP. Given the increasing energy intensity of Bangladesh s economy in recent years, the implication of a substantial gas shortage is that a slowdown in economic growth is very likely. This, in turn, will have an impact on demand for electricity and gas both directly and indirectly. Table 7: Power Sector Gas Demand Forecast (MMCFD) Distribution Company FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 BGSL JGTDSL PGCL TGTDCL SGCL Total 1,117 1,263 1,742 1,906 2,084 2,101 2,192 Annual Growth Rate 13% 38% 9% 9% 1% 4% Average Growth Rate (11 years): 7.4% BGSL = Bakhrabad Gas Systems Limited, JGTDSL = Jalalabad Gas Transmission and Distribution Systems Limited, PGCL = Paschimanchal Gas Company Limited, SGCL = Sundarban Gas Company Limited, TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla c. Captive Power Sector 64. The use of gas by captive power generators has increased significantly in the past decade, reflecting the low quality and reliability of grid electricity in some parts of Bangladesh. In the absence of significant investment in electricity infrastructure and construction of new generating plant, strong growth in captive power would be expected to continue. As discussed above, the inability of Petrobangla to commit to new gas supplies for 1,950MW of planned grid power generation would suggest unabated growth in captive power. This is not expected to be the case; gas supply for captive power will also be constrained, meaning that other, more expensive fuels will need to be used to fire captive plant, or demand will remain unserved. This, in turn, will reduce the amount of electricity generated from captive power plants, placing further pressure on grid supply. 65. Petrobangla has assumed near constant growth of % for captive power in its gas demand forecast, as shown in Table 8. The GSMP forecast used captive power growth rates in the range 5-7%, but with higher growth during the first few years and significantly lower growth thereafter. Two issues are important when comparing these two forecasts. Firstly, the GSMP forecast noted the impact of consumers switching from captive power to grid power as supply quality improves. For the sake of simplicity, this switching was ignored in the modeling on the basis that this switching effect is neutral from viewpoint of total regional demand for gas. The implication of this is that some gas that might actually be consumed by grid-based electricity generators (assuming that the captive power to grid power switching does actually occur) was included in the GSMP captive power forecast. Secondly, it assumed an increase in gas tariffs to

25 20 economic levels during the first few years of the forecast period, resulting in dampening of demand for gas. 66. Petrobangla s forecast does not explicitly take captive-to-grid switching or gas tariff increases into account. Given the expected shortage of grid-based generation after 2011, an increase in gas demand for captive generation would be expected. However, the anticipated tariff increase would be expected to soften demand in the near term. On balance, Petrobangla s forecast rate of demand growth in the captive power sector is considered reasonable on average but may disguise price-driven softening of demand in the near term. Table 8: Captive Power Sector Gas Demand Forecast (MMCFD) Distribution Company FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 BGSL JGTDSL PGCL TGTDCL SGCL Total Annual Growth Rate 8% 8% 8% 8% 8% 8% Average Growth Rate (11 years): 8.3% BGSL = Bakhrabad Gas Systems Limited, JGTDSL = Jalalabad Gas Transmission and Distribution Systems Limited, PGCL = Paschimanchal Gas Company Limited, SGCL = Sundarban Gas Company Limited, TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla d. Fertilizer Sector 67. Currently seven fertilizer plants six owned by Bangladesh Chemical Industries Corporation 16 and one in the joint venture named Karnaphuli Fertilizer Company are in operation in the country as major source for meeting the demand for fertilizer. All these companies are producing mostly Urea fertilizer and are using natural gas as their major raw material. TGTDCL has been the largest supplier of natural gas to the fertilizer sector meeting the maximum demand of the four BCIC plants, namely Jamuna Fertilizer Company Limited, Urea Fertilizer Factory Limited, Polash Urea Fertilizer Factory and Zia Fertilizer Company Limited, having daily gas demands of 45, 45, 14 and 52 MMCF respectively. CUFL (52 MMCFD) and KAFCO (63 MMCFD) are getting their natural gas supply from BGSL while JGTDSL is meeting the maximum possible demand of NGFF (18 MMCFD). These companies together are currently meeting only 60-70% of the total domestic demand for nitrogenous fertilizer (which accounts for more than 80% of the total nutrient consumption) which is estimated to be about 3 million metric ton per annum. Therefore, to reduce the demand-supply gap Bangladesh Chemical Industries Corporation plans to install two fertilizer plants in the country by 2016 namely Shahjalal Fertilizer Company Ltd in Fenchuganj (already in the tendering process) and Northwest Fertilizer Company Ltd in Sirajganj with production capacity of 1750 metric ton of Urea fertilizer each. However, these two new plants will require 45 MMCFD each of natural gas when commissioned. 16 The plants under BCIC are: Jamuna Fertilizer Company Ltd (JFCL) in Jamalpur, Urea Fertilizer Company Ltd (UFFL) in Ghorasal, Narsingdi; Polash Urea Fertilizer Company Ltd (PUFFL) in Polash, Narsingdi; Zia Fertilizer Company Ltd (ZFCL) in Ashuganj, Brahmanbaria, Chittagong Fertilizer Company Ltd (CUFL) in Rangadia, Chittagong; and Natural Gas Fertilizer Company Ltd (NGFF) in Fenchuganj, Sylhet.

26 Petrobangla has assumed flat demand for gas in the fertilizer sector through to 2015, with no new fertilizer plant being commissioned between now and then. A new plant to be owned by Shahjalal Fertilizer Company Ltd is assumed to be commissioned by 2016, increasing gas demand in the fertilizer sector by approximately 23 MMCFD. Demand is forecast to be flat for the remainder of the forecast period. The forecast is summarized in Table 9. With the exception of the steep increase in demand in 2016, Petrobangla s forecast of gas demand in the fertilizer sector matches that in GSMP. Table 9: Fertilizer Sector Gas Demand Forecast (MMCFD) Distribution Company FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 BGSL JGTDSL PGCL TGTDCL SGCL Total Annual Growth Rate 0% 3% 0% 0% 0% 0% Average Growth Rate (11 years): 2.2% BGSL = Bakhrabad Gas Systems Limited, JGTDSL = Jalalabad Gas Transmission and Distribution Systems Limited, PGCL = Paschimanchal Gas Company Limited, SGCL = Sundarban Gas Company Limited, TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla e. Non-Bulk Sector 69. Petrobangla has adopted a macro-level approach to its forecasting of gas demand in the non-bulk sector; it has assumed a flat 8% annual growth rate in non-bulk demand for all distribution companies with the exception of PGCL, for which it has assumed a non-bulk growth rate of 20%. The forecast is shown in Table 10. These growth rates are broadly aligned with growth rates in the GSMP. 70. Regression analysis on GDP and gas demand was used in the GSMP to estimate growth rates for each gas distribution company and for each of the non-bulk subsectors i.e. industrial, residential, commercial, captive power, and CNG. Typically, nine years of historical data was used, and a reliable link between the GDP and gas demand was identified in most cases, yielding sector-wise income elasticities of demand. These elasticities were then modified downwards by 2-3%age points during the first few years of the forecast to take account of the anticipated move to economic cost-reflective tariffs. 17 Based on the results of the regression analysis and after adjustments for tariff increases, income elasticities in the range were used in the industrial sector and in the residential sector. Elasticities were lower in the commercial sector, reflecting the relatively unimportance of gas in this sector. 71. Due to lack of good historical data and the recent rapid uptake rates for CNG, an ad hoc approach was used for CNG demand forecasts in the GSMP. An average growth rate of approximately 10% was assumed. It was noted, however, that CNG uptake depends on the number of vehicle owners who view it as economic to switch to this alternative fuel, and that this, in turn, depends on the degree of support that the Government is willing to provide to incentivize 17 It is not clear from the GSMP whether a price elasticity of demand was explicitly used, or whether the income elasticity of demand figure was adjusted downwards. However, the overall impact on demand should be the same whichever approach was used.

27 22 CNG use. In the PGCL area, a single non-bulk demand growth rate of 16% was assumed because of lack of historic data, and simple exponential growth was applied to current demand to arrive at a demand forecast. A similar approach was used for the south and southwest regions. Table 10: Non-Bulk Sector Gas Demand Forecast (MMCFD) Distribution Company FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 BGSL JGTDSL PGCL TGTDCL SGCL Total Annual Growth Rate 8% 10% 8% 8% 8% 8% Average Growth Rate (11 years): 8.5% BGSL = Bakhrabad Gas Systems Limited, JGTDSL = Jalalabad Gas Transmission and Distribution Systems Limited, PGCL = Paschimanchal Gas Company Limited, SGCL = Sundarban Gas Company Limited, TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla f. Impact of Tariff Increases 72. The GSMP forecast used the experiences in other countries to estimate the extent to which tariff increases would dampen demand, with an adjustment of 2-3%age points applied to growth for during the first three years of the forecast (i.e. growth rates determined by applying estimated income elasticities of demand were reduced by 2-3%age points). In the absence of regular historic increase in energy tariffs, it is difficult to evaluate the likely impact of significant increases in tariffs on demand and therefore the reasonableness of the adjustment made in the GSMP. However, given the relatively low per capita energy consumption and low incomes in Bangladesh, price elasticity of demand would be high, meaning that demand would respond strongly downwards to price increases. The GSMP adjustment of 2-3%age points per annum over four years implies elasticity of approximately -0.2, which is possibly on the low side. 73. The expected tariff increases have not yet happened and tariffs now need to be increased by more than 50% to reflect economic cost. In June 2008, Petrobangla submitted a tariff petition to BERC under the new draft tariff regulations proposing about 66% increase in consumer level tariff. BERC held public hearings in September-October, and issued its decision in November 2008 that maintains status quo. In its decision, BERC concluded that Petrobangla failed to prove its proposal, which was based on financial considerations, as just and reasonable. However, a 10-15% increase may be considered from July 2009 provided Petrobangla could provide a strategic plan for increasing the supply of gas by its exploration and production companies. 74. Exactly how this tariff increase if and when effected will translate to end-use tariffs remains unclear; the draft regulations do not appear to place any constraints on the way in which Petrobangla balances the tariff between various consumer groups and Petrobangla has traditionally used heavy cross subsidies in favor of the power and residential sectors. Moreover, the extent to which the Government will directly subsidize consumers, if at all, is unknown. In this context, the validity of the price-related demand softening in the GSMP forecast is yet to be demonstrated. The implication of the GSMP forecasting approach is that: (i) in the absence of the introduction of economic cost-reflective tariffs, the GSMP will underestimate the demand for

28 23 gas; and (ii) if cost-reflective tariffs are introduced, the GSMP might overestimate the demand for gas. g. System Losses 75. Petrobangla did not explicitly treat losses in its demand forecast. Implicitly, it assumed only minor further reduction in losses, and distributed these among the utilities taking into consideration that TGTDCL, being the oldest and largest distributor, currently accounts for approximately 95% of losses. h. Summary of Demand Forecast 76. The sector-wise demand forecast up to 2020 is summarized in Table 11. The forecast does not appear to consider the impact of significant tariff increases, which would be expected to soften demand in the non-bulk sector considerably. On the other hand, there is considerable suppressed demand implicit in the forecasting methodology, particularly in the power sector. On balance therefore, the forecast is considered reasonable and will be adopted for planning purposes. Customer Category FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018 FY2019 FY2020 Total Power 1,117 1,263 1,742 1,906 2,084 2,101 2,192 2,210 2,253 2,278 2,415 2,445 Growth Total Captive Power Growth Total Fertilizer Growth Total Non-Bulk ,002 1,085 1,175 1,273 1,379 1,495 1,622 1,760 Growth Total Demand 2,412 2,609 3,225 3,450 3,728 3,846 4,060 4,297 4,459 4,637 4,946 5,153 Source: Petrobangla Table 11: Gas Demand Forecast ( ) Figures in MMCFD 77. The gas demand forecast revised by Petrobangla reflects supply constraints. The overall growth rate assumed in the forecast is 7.3%, the same as the historic growth rate for the periods. The projected gas demand by distribution companies is summarized in Table 12 and detailed in Appendix 8. Table 12: Total Gas Demand Forecast (MMCFD) Distribution Company FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 BGSL JGTDSL PGCL SGCL TGTDCL 1,662 1,827 2,011 2,246 2,337 2,435 2,614 Total 2,363 2,587 3,175 3,432 3,711 3,837 4,047 Annual Growth Rate 9% 23% 8% 8% 3% 5% Average Growth Rate (11 years): 7.3% BGSL = Bakhrabad Gas Systems Limited, JGTDSL = Jalalabad Gas Transmission and Distributions Systems Limited, PGCL = Paschimanchal Gas Company Limited, SGCL = Sundarban Gas Company Limited, TGTDCL = Titas Gas Transmission and Distribution Company Limited Source: Petrobangla

29 Petrobangla s demand forecast is compared to the GSMP forecast in Figure 1. The GSMP Case A forecast assumed constant GDP growth of 5.5% and the GSMP Case B assumed average GDP growth of 6.8%. The Case A forecast estimated average gas demand growth of 5.3% for the period , whereas the Case B forecast estimated average demand growth of 7.5% for the same period. Both GSMP forecasts estimated significantly lower consumption in the base year than Petrobangla has used. This appears to be a consequence of the GSMP assumption of the introduction of cost-reflective tariffs over the period The Petrobangla forecast also shows a step increase in 2011 as series of new gas-fired power plants are commissioned. Beyond 2011, the Petrobangla forecast average growth rate reduces to 5.2%, which is the same as the overall growth rate in GSMP Case A and is significantly lower than the Case B growth rate. This reflects the supply constraints imposed by the shortage of gas, particularly in the important power sector. Figure 1: Comparison of Gas Demand Forecasts D. Gas Supply 1. Production Scenario 79. There are presently 17 gas fields operational in Bangladesh. They are operated by BGFCL, SGFL, BAPEX, Niko, Unocal and Shell/Cairns. The first three are SGCs owned by Petrobangla and the latter three IOCs are working under PSCs and joint venture agreements. Field-wise production is summarized in Table 13 and Appendix 9. Figure 2 compares the gas reserves with production. 80. Petrobangla revised its gas production forecast in July 2008 in conjunction with its reforecasting of demand growth. The production forecast assumes net recoverable resources as at May 2008 of 12,954 BCF, as summarized in Table 14 and detailed in Appendix 10. This is considered to be a conservative estimate. The 2003 Reserve Estimation Report from the HCU indicated that an additional 9,120 BCF was available in possible recoverable reserves and from utilization of wellhead compression to 500 psi. Adding this to Petrobangla estimate of recoverable reserve gives an available reserve from discovered fields of 22,594 BCF. Even at current level of consumption the remaining recoverable reserve will exhaust in 20 years, and,

30 25 with 6% growth rate, the remaining recoverable reserve will not last beyond 13 years. Given the current reserve status and anticipated shortfall in meeting growing demand, restriction should be imposed in committing new gas usage. Table 13: Production Capacity and Current Production from Existing Gas Fields (2008) Company Field Total Wells Flowing Wells Production Capacity Average Production MMCFD MMCFD BGFCL Titas Bakhrabad Habiganj Narsingdi Meghna SGCL Sylhet Kailastila Rashidpur Beanibazar BAPEX Saldanadi Fenchuganj Cairn Sangu Chevron Jalalabad Moulavibazar Bibiyana Tullow Bangora Niko/BAPEX Feni Total ,838 1,770 Total SGCs: 923 MMCFD IOCs: 915 MMCFD BGFCL = Bangladesh Gas Fields Company Limited; BAPEX = Bangladesh Petroleum Exploration Company Limited; SGCL = Sylhet Gas Company Limited Source: Petrobangla Figure 2: Gas Reserve Vs Production As of May 2008 Reserves Recoverable (P3) Recoverable (P3) Possible Possible (P3) (P3) Remaining Remaining Reserve Reserve CumulativeProduction Proven Recoverable (2P) Proven Recoverable (2P) Proven (GIIP) Proven (GIIP) Series3 Series2 Gas in trillion Series1 cubic feet (TCF) Source: Petrobangla

31 26 Table 14: Summary of Production Forecast Field Recoverable Reserve Cumulative Production Remaining Reserve Production Forecast (MMCFD) (BCF) (BCF) (BCF) (BCF) Existing SGCs 15,889 6,415 9,473 1,015 1,089 1,229 1,376 1,540 1,577 1,689 7,157 IOCs 4,743 1,261 3,481 1, ,354 New Discoveries and Offshore Bidding SGCs IOCs ,172 Total 20,632 7,676 12,954 2,040 2,024 2,169 2,511 2,835 2,942 3,299 13,272 BCF = billion cubic feet; IOCs = international oil companies; MMCFD = million cubic feet per day; SGCs = State Gas Companies Source: Petrobangla 81. There is every possibility to increase the reserve volume from the discovered gas fields provided the following time bound program is implemented on a priority basis: i) Initiate reservoir pressure data gathering program on major gas fields. ii) Drill additional production wells, particularly in Titas, Habiganj and Kailastila. iii) Appraise the already discovered gas fields to prove up current probable and possible reserve estimate. iv) Re-complete all the wells that are currently watered up or are executing sand production problems. v) Re organize the production companies to create an experience field development team for each field. vi) Ensure each field has a depletion plan a long-term production forecast and field development program. 2. Demand and Supply Balance 82. Even though Petrobangla has developed a demand forecast that assumes significant supply constraints particularly in the power sector, there is a sustained and growing gap between forecast gas demand and forecast gas production. Table 15 shows the supply shortfall reaches 895 MMCFD by 2014, and totals 3,726 BCF over the period (Figure 3).This is a significant shortfall, representing 22% of the already constrained forecast demand over the period. In the absence of new gas discoveries or extreme demand side management measures including large tariff increase, this forecast gas shortfall is likely to have a profound impact on the economy in the coming years. Table 15: Forecast Demand versus Forecast Production (MMCFD) FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 Total FY2009- FY2020 (BCF) Forecast Demand 2,363 2,587 3,175 3,432 3,711 3,837 4,047 16,998 Forecast Production 2,040 2,024 2,169 2,511 2,835 2,942 3,299 13,272 Supply Shortfall , ,726 BCF = billion cubic feet; MMCFD = million cubic feet per day Source: Petrobangla

32 27 Figure 3: Gas Production Projection vs Demand Figures in MMCFD Petrobangla Petrobangla-New Discovery IOC-1 New Discovery: IOC-2 New Discovery: IOC-3 Demand To meet growing demand and overcome production and transmission deficiencies, large scale investment in exploration, field development, and transmission and distribution segments has to be made. Petrobangla estimates that gas demand will go up to 5,144 MMCFD in FY2020. Probable gas production from existing gas fields is expected to peak to 2,475 MMCFD in FY2017 and then gradually going down to 2,288 MMCFD in FY2020. Petrobangla also projects production to peak to 1,080 MMCFD in FY2017 from new discoveries by the IOCs in both onshore and offshore. Overall peak production by SGCs and IOCs is estimated to reach a level of 3,555 MMCFD in FY To augment gas production, Petrobangla has drawn a program for further exploration; work over of wells in producing gas fields; drilling of new wells in producing and non-producing gas fields with self and government financing. Petrobangla estimates production enhancement up to 400 MMCFD by FY2012, which appears to be optimistic. Production augmentation is likely to be around MMCFD. 85. Major production enhancement is estimated to come from IOC operation in both onshore and offshore blocks. Petrobangla has recently divided the country into 54 smaller blocks and gone for a fresh bidding round for 28 offshore blocks. Eleven IOCs participated and proposals are under evaluation. Apparently lack of seismic data and stricter terms and conditions of PSC failed to attract major IOCs. Petrobangla expects to award few undisputed blocks to successful bidders by mid India and Myanmar have raised objections for some tendered blocks, claiming their jurisdiction of those blocks.

33 28 E. Gas Pricing 1. Current Gas Tariffs and Operating Margins a. Gas Price Philosophy 86. Gas pricing remains a sensitive issue in Bangladesh. Currently, end-use gas tariffs do not reflect the economic cost of delivering gas to consumers. Pricing gas at less than economic cost encourages inefficient and unsustainable end use of gas. The Government maintains that the low gas prices play an important role in contributing to industrialization, agricultural output and general improvement of quality of life and evidence suggests that this is at least partially true. However, Bangladesh is now faced with the real possibility of exhaustion of its gas reserves and cannot afford to implicitly encourage inefficient consumption of gas through prices that do not reflect true economic costs. b. Current Gas Tariffs 87. The current retail price for gas is set by the Government through a non-transparent process based on different socio-economic considerations in accordance with the pricing framework outlined in 2003, summarized in Appendix 11. The Government also sets the level of supplementary duty (SD) payable by Petrobangla on gas sales, and determines the margins to be paid for gas transmission and distribution companies. Gas production companies receive a fixed wellhead price estimated by the Government to be adequate to meet their needs. End user prices range from TK2.19/cm ($0.89/MCF) for fertilizer to TK8.07/cm ($3.26/MCF) for commercial, with domestic at Tk4.45/cm ($1.80/MCF). The wellhead price paid to Petrobangla subsidiaries amounts to TK0.25/cm ($0.10/MCF). The spread between the end user price and wellhead prices provides the margin for GTCL transportation, Government taxes, BAPEX, PDF, and gas distribution. The revenue allocation between the nine tariff categories is arbitrary and not cost reflective. Gas tariffs and the notional distribution of revenue under each of tariff classification are shown in Table 16. The Government s margin on gas sales is made up of VAT at 15% of the component of the end user price attributable to gas supplied from state companies, and the SD levy of 96% on all transmission and network costs and on gas supplied by state companies. 88. The end user price to the unmetered residential consumers is based on an estimate of consumption per burner, hot water heater, and other gas appliances likely to be used by consumers. Charges for gas are based on a gas burning unit count and a flat monthly charge per gas burning unit. In the absence of a cost signal, actual household gas consumption is likely to be higher than the assumed level.

34 29 Table 16: Gas Price Distribution between Government and Petrobangla (Effective from 1 January 2005, Tk/cm) Customer Category End Users Price Government VAT SD Total PDF BAPEX Margin Petrobangla s on End Users Price Well head Margin Transmission Margin Distribution Margin Total 1 Power Fertilizer Industry Commercial Seasonal Tea-Estate Domestic Captive Power Feed Gas for CNG a BAPEX = Bangladesh Petroleum Exploration and Production Company; CNG = compressed natural gas; PDF = price deficit fund; SD = Supplementary duty; VAT = value-added tax a CNG tariff was increased on 18 April 2008 Source: Petrobangla c. Gas Purchased from IOCs 89. IOC-operated fields presently provide approximately 50% of the total gas supply. Petrobangla buys gas from the IOCs under PSCs at contractual prices linked to international fuel oil prices and sells it to the distribution companies at prices fixed by the Government. Gas purchase prices under the PSCs are set at 75% of the Singapore high sulfur fuel oil (HSFO) price, but in a range with a $70 per metric ton floor and a $120 per metric ton cap, which translates to a minimum gas price of $1.40 and a maximum gas price of $2.90/MCF. Under the PSCs, gas from IOCs is characterized as either cost recovery gas or profit gas. Cost recovery gas is the component of extracted gas that is sold by IOCs to Petrobangla to recover IOCs costs incurred in putting wells into production and keeping them in production. No more than 60% (55% in some PSCs) of gas can be deemed as cost recovery gas in any given year. Profit gas is any gas in excess of cost recovery gas, and is shared between IOCs and Petrobangla on the basis of a formulae prescribed in the PSCs. d. Gas Purchased from SGCs 90. At around Tk170 per MCF, IOC wellhead gas is priced generally in accordance with economic principles in that it reflects world oil prices. Conversely, the price paid for SGC gas is apparently arbitrarily set at Tk7.1 per MCF, well below its economic (opportunity) cost. In the Consultant s view, this price does not provide sufficient incentive for SGCs to manage their reservoirs and to optimize gas production. If the SGCs are to compete with IOCs and are to have an incentive to improve their reservoir management, they need to have similar gas sales contracts and rights as the IOCs.

35 30 e. Transmission and Distribution Margins 91. The transmission and distribution companies receive margins for the volume of gas transmitted and sold to consumers. GTCL, the transmission company, receives a margin for the volume of gas transmitted through its system, which barely covers its operating costs and does not provide any return on capital invested, BAPEX, the exploration company receives Tk0.05 per cm (Tk1.41 per MCF) from the end-user price in the form of a levy. The residual margin that arises as a result of the sale of gas from state gas producers (SGCs) to end-use customers is pooled together as the price deficit fund (PDF), and is used to meet the difference between the cost of gas bought by Petrobangla from IOCs and end-use tariffs. However, the PDF has not been sufficient to cover the costs of IOC gas and penalty interest has been paid because of delays in remittances for gas. The distribution companies sell the gas to consumers on behalf of Petrobangla and remit the proceeds to Petrobangla after keeping their margins. Petrobangla pays the transmission and production companies their margins, and remits supplementary duties and VAT on SGC gas to the Government. f. Past Gas Tariffs and Recent Increases 92. Gas tariffs have not been adjusted adequately for many years. The average yearly nominal increase in gas has been limited, varying in the main consumption categories around 4.0% annually over the last 10 years. In addition, the nominal tariff adjustment in Tkterms has been largely offset by the depreciation of the Tk, averaging 4.4% annually since FY In addition gas prices have not reflected changes in international oil prices. As a result, gas prices have not increased in dollar terms since the early 1990s. This has adversely affected the viability of Petrobangla s operations, because its payment obligations to IOCs under the PSCs, debt servicing of foreign loans and foreign exchange component of the needed investments for transmission and distribution are linked to fluctuations in the exchange rate. This limits the ability of the sector to finance the future investment necessary for expansion and improving performance. 93. The build-up of the current average tariff and the distribution of the average tariff across the value chain are shown in Figure 3. The figure shows that the notional components in the build-up of tariff are not necessarily matched by revenue distribution, reflecting the fact that the tariffs have not had adequate adjustment in the past and have not been increased since In particular, the proportion of IOC-sourced gas in the consumer mix has increased from around 27% at the time of the last tariff adjustment in 2005 to approximately 50% in This means that the weighted cost of gas has increased by around 60% since Figure 3 shows the total value of IOC gas before netting off Petrobangla s share of profit gas. Because total revenue distribution is greater than total revenue, a subsidy is required. This is shown in the figure as implicit state subsidy, as is currently approximately Tk12 per MCF.

36 31 Figure 3: Current Average Tariff Build-Up and Revenue Distribution (FY 2008) Source: Consultant estimates. g. Subsidies in Tariffs 94. The current tariff structure includes both general subsidy and cross subsidy, both of which are undesirable and encourage economically inefficient consumption of energy (gas and electricity). Using the recent tariff petition filed by Petrobangla as representative of the financial cost of supply, the general financial subsidy is currently of the order of 30% (i.e. the tariff is only 70% of the financial cost of supply and the rest is subsidized). 18 The industrial, commercial and tea estate sectors are the only three sectors that currently face a tariff above the financial cost of supply as estimated by Petrobangla. Collectively these three sectors provide approximately Tk3.3 per MCF of financial subsidy to the other sectors. 2. Price Regulation and Policy a. Draft Tariff Regulations 95. BERC is expected to provide increasingly transparent and consistent economic regulation to the energy sector pricing. Amongst other activities, BERC has recently circulated gas transmission tariff and gas distribution tariff regulations for public consultation. These regulations, which apply to current government-owned licensees plus any future privatelyowned licensees, build on an economic cost-plus basis for transmission and distribution tariff setting, with licensees able to recover efficient costs and to make a reasonable return on capital invested. The draft distribution regulation, for example, states that [the tariff] determined by this 18 In general, the average incremental financial cost (AIFC) is compared to the average tariff to determine the level of financial subsidy. AIFC is likely to be greater than the average tariff estimated by Petrobangla since the tariff methodology is backward looking whereas AIFC is forward looking. Therefore, the true level of financial subsidy is likely to be greater than the level indicated.