Liquefied natural gas in China : options for markets, institutions, and finance

WORLD BANK DISCUSSION PAPER NO. 414 WDP414 Work In progress May 2000 for public discussion Liquefied Natural Gas in C]hina 6tuions fortlarkets, Institutions, ati/ Finanme LDean Girdis tratos vo u/areas RaY Tornkinis  Recent World Bank Discussion Papers No. 345 On the Road to EU Accession: Financial Sector Development in Central Europe. Michael S. Borish, Wei Ding, and Michel Noel No. 346 Structural Aspects of Manufacturing in Sub-Saharan Africa: Findings from a Seven Country Enterprise Survey. Tyler Biggs and Pradeep Srivastava No. 347 Health Reform in Africa: Lessonsfrom Sierra Leone. Bruce Siegel, David Peters, and Sheku Kamara No. 348 Did External Barriers Cause the Marginalization of Sub-Saharan Africa in World Trade? Azita Amjadi Ulrich Reincke, and Alexander J. Yeats No. 349 Surveillance of Agricultural Price and Trade Policy in Latin America during Major Policy Reforms. Alberto Valdes No. 350 Who Benefitsfrom Public Education Spending in Malawi: Resultsfrom the Recent Education Reform. Florencia Castro-Leal No. 351 From Universal Food Subsidies to a Self-Targeted Program: A Case Study in Tunisian Reform. Laura Tuck and Kathy Lindert No. 352 China's Urban Transport Development Strategy: Proceedings of a Symposium in Beijing, November 8-10,1995. Edited by Stephen Stares and Liu Zhi No. 353 Telecommunications Policiesfor Sub-Saharan Africa. Mohanmmad A. Mustafa, Bruce Laidlaw, and Mark Brand No. 354 Saving across the World: Puzzles and Policies. Klaus Schmidt-Hebbel and Luis Serven No. 355 Agriculture and German Reunification. Ulrich E. Koester and Karen M. Brooks No. 356 Evaluating Health Projects: Lessons from the Literature. Susan Stout, Alison Evans, Janet Nassim, and Laura Raney, with substantial contributions from Rudolpho Bulatao, Varun Gauri, and Timothy Johnston No. 357 Innovations and Risk Taking: The Engine of Reform in Local Government in Latin America and the Caribbean. Tim Campbell No. 358 China's Non-Bank Financial Institutions:Trust and Investment Companies. Anjali Kumar, Nicholas Lardy, William Albrecht, Terry Chuppe, Susan Selwyn, Paula Perttunen, and Tao Zhang No. 359 The Demandfor Oil Products in Developing Countries. Dermot Gately and Shane S. Streifel No. 360 Preventing Banking Sector Distress and Crises in Latin America: Proceedings of a Conference held in Washington, D.C., April 15-16,1996. Edited by Suman K. Bery and Valeriano F. Garcia No. 361 China: Power Sector Regulation in a Socialist Market Economy. Edited by Shao Shiwei, Lu Zhengyong, Norreddine Berrah, Bernard Tenenbaum, and Zhao Jianping No. 362 The Regulation of Non-Bank Financial institutions: The United States, the European Union, and Other Countries. Edited by Anjali Kumar with contributions by Terry Chuppe and Paula Perttunen No. 363 Fostering Sustainable Development: The Sector Investment Program. Nwanze Okidegbe No. 364 Intensified Systems of Farming in the Tropics and Subtropics. J.A. Nicholas Wallis No. 365 Innovations in Health Care Financing: Proceedings of a World Bank Conference, March 10-11, 1997. Edited by George J. Schieber No. 366 Poverty Reduction and Human Development in the Caribbean: A Cross-Country Study. Judy L. Baker No. 367 Easing Barriers to Movement of Plant Varieties for Agricultural Development. Edited by David Gisselquist and Jitendra Srivastava No. 368 Sri Lanka's Tea Industry: Succeeding in the Global Market. Ridwan Ali, Yusuf A. Choudhry, and Douglas W. Lister No. 369 A Commercial Bank's Microfinance Program: The Case of Hatton National Bank in Sri Lanka. Joselito S. Gallardo, Bikki K. Randhawa, and Orlando J. Sacay No. 370 Sri Lanka's Rubber Industry: Succeeding in the Global Market. Ridwan Ali, Yusuf A. Choudhry, and Douglas W. Lister No. 371 Land Reform in Ukraine: The First Five Years. Csaba Csaki and Zvi Lerman No. 373 A Poverty Profile of Cambodia. Nicholas Prescott and Menno Pradhan No. 374 Macroeconomic Reform in China: Laying the Foundation for a Socialist Economy. Jiwei Lou No. 375 Design of Social Funds: Participation, Demand Orientation, and Local Organizational Capacity. Deepa Narayan and Katrinka Ebbe No. 376 Poverty, Social Services, and Safety Nets in Vietnam. Nicholas Prescott No. 377 Mobilizing Domestic Capital Markets for Infrastructure Financing: International Experience and Lessons for China. Anjali Kumar, R. David Gray, Mangesh Hoskote, Stephan von Klaudy, and Jeff Ruster No. 378 Trends in Financing Regional Expenditures in Transition Economies: The Case of Ukraine. Nina Bubnova and Lucan Way (Continued on the inside back cover)  WORLD BANK DISCUSSION-PAPER NO. 414 Liquefied Natural Gas in China Optionsfor Markets, Institutions, and Finance Dean Girdis Stratos Tavoulareas Ray Tomkins The World Bank Washington, D.C.  Copyright K 2000 The International Bank for Reconstruction and Development/THE WORLD BANK 1818 H Street, N.W. Washington, D.C. 20433, U.S.A. All rights reserved Manufactured in the United States of America First printing May 2000 Discussion Papers present results of country analysis or research that are circulated to encourage discussion and comment within the development community. The typescript of this paper therefore has not been prepared in accordance with the procedures appropriate to formal printed texts, and the World Bank accepts no responsibility for errors. Some sources cited in this paper may be informal documents that are not readily available. The findings, interpretations, and conclusions expressed in this paper are entirely those of the author(s) and should not be attributed in any manner to the World Bank, to its affiliated organizations, or to members of its Board of Executive Directors or the countries they represent. The World Bank does not guarantee the accuracy of the data included in this publication and accepts no responsibility for any consequence of their use. The boundaries, colors, denominations, and other information shown on any map in this volume do not imply on the part of the World Bank Group any judgment on the legal status of any territory or the endorsement or acceptance of such boundaries. The material in this publication is copyrighted. The World Bank encourages dissemination of its work and will normally grant permission promptly. Permission to photocopy items for intemal or personal use, for the internal or personal use of specific clients, or for educational classroom use, is granted by the World Bank, provided that the appropriate fee is paid directly to Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, U.S.A., telephone 978-750-8400, fax 978-750-4470. Please contact the Copyright Clearance Center before photocopying items. For permission to reprint individual articles or chapters, please fax your request with complete information to the Republication Department, Copyright Clearance Center, fax 978-750-4470. All other queries on rights and licenses should be addressed to the World Bank at the address above or faxed to 202-522-2422. ISBN: 0-8213-4734-9 ISSN: 0259-210X The cover photo was provided by Shell Photo Services. It shows a shipment of liquefied natural gas (LNG) that will be re-gasified and distributed by pipeline. Dean Girdis, Stratos Tavoulareas, and Ray Tomkins were consultants to EPDC International, Ltd. (EPDCI) and Tokyo Electric Power Co. (Tepco) for this project and work frequently with the World Bank on energy sector issues. Library of Congress Cataloging-in-Publication Data has been applied for.  Contents Foreword ........................................................................ vii Abstract ........................................................................ viii Preface ........................................................................ ix Objectives of the Report ......................................................................... ix Structure of the Report ........................................................................ x Acknowledgments ........................................................................ xi Abbreviations and Acronyms ........................................................................ xii Glossary ........................................................................ xiv Units of Measure ........................................................................ xviii Natural Gas ........................................................................ xviii Town Gas ........................................................................ xviii Energy and Power ........................................................................ xviii Currency Units ........................................................................ xviii 1. Energy Demand Growth in China .......................... ............................................... 1 Power Demand ..........................................................................2 Energy Supply Options .........................................................................3 Energy-Induced Environmental Damage .........................................................................3 2. An Energy Profile of the East China Region ......................................................................... 5 Profile of the Study Area ......................................................................... 5 Energy Demand Growth in Coastal China .........................................................................6 Energy Demand in the Yangtze Delta .........................................................................7 Power Sector Demand .........................................................................7 Nonpower Sector Demand .........................................................................9 Coal's Dominance Continues .........................................................................9 Role of Hydro ........................................................................ 11 Key Energy and Environmental Issues in the Yangtze Delta .................... ................................ 12 3. Projected Demand for Gas and Influence of Benefits of Gas Use ............................................. 15 Demand for Gas ......................................................................... 15 Characteristics of Demand ......................................................................... 15 Yangtze Delta Case Study ........................................................................ 16 Power Sector Demand and Load Forecast ........................................................................ 17 Approach .................... 17 Gas Demand .................... 17 Nonpower Demand Forecast .................... 19 Approach .................... 19 Gas Demand .................... 20 Key Factors for Establishment of a Gas Market .................................. 21 Environmental Benefits of Gas .................................. 23 Hii  Nonenvironmental Benefits of Gas ................................................................. 23 Interfuel Substitution and Reduced Dependence on Coal .................................................... 23 Fuel Diversification ................................................................. 24 More Efficient and Flexible Operation of Power Systems ............................ ........................ 24 4. Gas Supply Options ................................................................. 25 Domestic Gas .................................................................. 25 Reserves ................................................................. 25 Domestic Production ................................................................. 26 Consumption ................................................................. 26 Cost of Supply .................................................................. 27 Supply Infrastructure ................................................................. 27 Imported Piped Gas ................................................................. 27 LNG Supply Sources ................................................................. 28 Forecast LNG Demand .................................................................. 29 Comparing Natural Gas Options for the Yangtze Delta . .......................................................... 29 International Piped Gas versus LNG ......................... ........................................ 30 LNG Prices and Competitiveness ................................................................. 30 Integrated Gas Development Strategy ................................................................. 31 5. Key Issues for LNG Development ................................................................. 33 Development of LNG Project ................................................................. 34 Overview of Downstream LNG Finance ............................. ..................................... 35 Factors Influencing Economics ................................................................. 35 Gas Pricing Issues ................................................................. 37 Creating an Appropriate Institutional Framework .................................................................. 37 Infrastructure Development Objectives ......................... ........................................ 38 Balancing Short- and Long-term Development Goals ........................................................... 38 Balancing Strategic and Social Aims ...................... ........................................... 39 Risk Analysis ................................................................. 39 Role of Government Agencies ................................................................. 40 Financing Issues and Requirements for Proposed Project ........................................................ 41 6. Ownership Structure and Trading Arrangemrents ................................................................. 43 Ownership Structure ................................................................. 43 Key Elements .............................................................. . . 43 Control and Ownership ................................................................. 44 Impact of Power Sector Reform and Single Buyer Model ..................................................... 44 Alternative Models of Ownership Structure .................................................................. 45 Model 1: Two Variants of the Integrated Company .............................................................. 45 Model 2: The Gas Development Company ................................................................. 46 Model 3: Separation of Gas Buyer from Terminal and Pipeline Owner / Operator .............. 47 Model 4: Power Sector as LNG Buyer ........................... ...................................... 47 Assessment of Alternative Models ................................................................. 48 Contracts ................................................................. 50 Trading Arrangements ................................................................. 51 7. Regulation and the Role of Government ............................... ................................... 53 What Needs to be Regulated? .................................................................. 53 iv Liquefied Natural Gas in China  Gas Pricing Issues ............................................................................. 53 LNG Pricing ............................................................................. 54 Terminal and Transportation Charges ............................................................................. 54 Uniform Pricing and Transportation Charges . ..................................................................... 54 Cross-Subsidies ............................................................................. 55 Regulatory and Legal Framework ............................................................................. 55 W ho Should Carry Out the Regulatory Functions? .............................................................. 56 Role of Government Agencies ............................................................................. 57 8. Financing LNG in China ............................................................................. 59 Key Financing Issues ............................................................................. 59 Components for Successful Financing .............................................................................. 60 Proposed Financing Structure ............................................................................. 60 Risk Mitigation for Financing ............................................................................. 61 9. Project Financial Analysis ............................................................................. 63 Approach and Methodology ............................................................................. 63 Gas Pricing Analysis ............................................................................. 64 Base Case ............................................................................. 64 Sensitivity of Key Variables ............................................................................. 66 10. Conclusions ............................................................................. 71 References ............................................................................. 75 Tables Table 1.1 Power Capacity and Generation in China, 1980-97 ........................................................................ 2 Table 1.2 Electricity Forecast (1997-2010) ....................................................................................3 Table 2.1 Projected Energy Demand in China's Coastal Provinces (million TCE) .......................................... 7 Table 2.2 Projected Power Balance, 1998 (MW) ................................ .............................................. 7 Table 2.3 Installed Capacity (MW) and Generation (GWh) in Yangtze Delta, 1996 ............. ......................... 8 Table 2.4 Power from Three Gorges Allocated to Jiangsu, Shanghai and Zhejiang ............. .......................... 11 Table 2.5 Seasonal Variation of Average Power from Three Gorges Allocated to the Study Area (TWh) ............................................................................. 11 Table 3.1 Required LNG-based Power Generation Capacity .......................................................................... 19 Table 4.1 Major Chinese Gas Fields ............................................................................. 26 Table 4.2 Potential Sources of LNG Supply ........................ ..................................................... 28 Table 4.3 Forecast LNG Demand in Asia Pacific (BCM) ............................................................................. 29 Table 6.1 Key Advantages and Disadvantages of Proposed Models ............................................................... 49 Table 7.1 Proposed Scope of Regulation ............................................................................. 56 Table 7.2 Current Responsibility for Regulation ............................................................................. 57 Table 9.1 Notes for Figure 9.3 and Figure 9.4 ............................................................................. 66 Table 9.2 Sensitivity of Power and Gas Tariffs Based on Project ROR, (2007 in Current Yuan) .................... 69 Figures Figure 2.1 Energy Resources and Target Areas for Use of Natural Gas in China ........................................... 6 Figure 2.2 Major Coal Transport Corridors to Yangtze Delta ..................................................................... .... 10 Contents v  Figure 3.1 Total Projected Demand for Gas ............................ .................................................... 16 Figure 3.2 Cumulative Installed Capacity Additions of Gas-Fired Power Plants .............. ............................. 18 Figure 3.3 Gas Demand from the Power Sector, 2003-20 ............................................................................... 18 Figure 3.4 Base Case: Nonpower Demand for Gas ......................................................................... ....... 20 Figure 3.5 Nonpower Demand for Gas ................................................................................ 20 Figure 3.6 Impact of Gas Use on Power Sector Emissions in Shanghai, Jiangsu, and Zhejiang 1999-2021 ....................................................................... 23 Figure 4.1 LNG Supply Price Compared with Netback Value of Gas ........................ .................................... 31 Figure 5.1 Profile of an LNG Project ................................................................................ 34 Figure 6.1 Model 1: Integrated Company-Single Buyer ................................................................................ 46 Figure 6.2 Model la: Integrated Company-Multiple Buyers .......................................................................... 46 Figure 6.3 Model 2: Gas Development Company ................................................................................. 47 Figure 6.4 Model 3: Separate Gas Buyer ................................................................................ 47 Figure 6.5 Model 4: Power Sector as Gas Buyer ........................................ ........................................ 48 Figure 6.6 Trading Arrangements and Contractual Relations-Model 3 ......................................................... 52 Figure 8.1 Financing Structure for Model 3 ................................................................................ 61 Figure 9.1 Projected Plant/City Gate Price of Gas, by Component ............................. ................................... 65 Figure 9.2 Base Case: (A) Wholesale Power Tariff in 2007 to Achieve ROR Thresholds and (B) Retail Municipal Gas Price in 2007 to Achieve ROR Thresholds ........... ........................ 65 Figure 9.3 Sensitivity of Wholesale Power Tariff, 2007 ................................................................................ 67 Figure 9.4 Sensitivity of the Retail Municipal Gas Tariff, 2007 .................................................. .................... 68 Figure 9.5 Comparison of Base Case and No Tax Case at 15 percent ROR: (A) Wholesale Power Tariff in 2007 (B) Retail Municipal Gas Tariff (Base 2007) ................ 69 vi Liquefied Natural Gas in China  Foreword Over the past two decades, the World Bank has supported initiatives by the Chinese government to meet the growing and diverse needs of its energy sector. In an effort to meet the continuing demand growth of the power sector and ensure stability of fuel supply sources, the State Power Corporation (SP) requested World Bank assistance to assess the viability of imported LNG as a fuel source for coastal provinces. Detailed economic assessment of LNG as an alternative fuel source was undertaken, and the institutional, regulatory and financing issues necessary to support its introduction were reviewed. SP took a lead in supporting the study and participated in all stages of its preparation. It made significant effort to coordinate cooperation with Chinese ministries and agencies, particularly State Development Planning Commission. In publishing this report, we hope to provide an insightful analysis of the long-term opportunities LNG presents for China. Yukon Huang Director China Country Programs East Asia and Pacific Region vii  Abstract This report presents a summary of key issues and options relating to the development of a LNG project in China and is based on two more detailed reports (Phase I and Phase H), which discussed the market for gas and the institutional and financing issues necessary to support its introduction. The objectives of the study, from which this report developed, were to examine the projected market for gas, including demand for energy in the power and nonpower sectors, netback value of gas compared with alternative fuels, and environmental issues supporting its introduction. A second objective was to review the mechanisms and structures necessary to support the introduction of gas, including the long-term gas supply chain, institutional and regulatory structure, financing issues, and structure and final price of energy to consumers. The beginning of this report provides a general overview of energy demand in East China and the potential market for gas. This is followed by an assessment of fuel and gas supply options. The later half of the report reviews key factors for the successful introduction of LNG, including institutional, regulatory and financing issues. viii  Preface This report is a consolidated summary report of two separate reports prepared by the study team during a 16-month period. The study was carried out in two phases. Phase I, 'Strategic Options for Natural Gas,' assessed the strategic energy options and the potential demand for natural gas (hereafter referred to as gas or natural gas) in selected coastal provinces of East China. This included detailed assessment of available energy sources and analysis of the potential demand for gas in the power and nonpower sectors of Jiangsu and Zhejiang provinces and the municipality of Shanghai (hereafter collectively called the Yangtze Delta). The study determined the value of gas for each sector and explored the availability and cost of gas from alternative supply sources, including offshore gas, piped gas, and liquefied natural gas (LNG). Finally, the team reviewed national and local environmental regulations and assessed the economic benefits of improved environmental quality from gas relative to continued use of coal. Phase 2, 'Institutional Issues and Financing of LNG and Power Infrastructure in the Yangtze Delta of China,' identified the key institutional and financing factors. It provided appropriate options for (1) designing the institutional framework for the implementation of a LNG project and (2) developing an appropriate financing structure and preparing a detailed cash-flow analysis of each project component. (An accompanying report, 'LNG Guidelines for China,' serves as a general reference source.) An appropriate institutional framework is vital for successful implementation of LNG, considering the size of such projects, their duration, the number of Chinese parties involved, and the potential involvement of external investors both within and outside China. All of these factors contribute to the overall risk profile for LNG, particularly for a first major project in China. The design of the institutional framework should take this risk into account and seek to mitigate it to the extent possible. Reducing project risk will not only protect against overall failure of the project but will lower the cost of supplied LNG as well. Objectives of the Report As noted, the study took place in two Phases: Phase I focused on the strategic energy supply options, establishment of demand for gas, and assessment of its value for various consumer sectors. Phase II addressed institutional, policy, commercial, and financial issues associated with the development of gas in the study area. ix  Objectives for Phase I were as follows: * Assessment of strategic energy alternatives to meet power demand projections and development of a least-cost plan, including the most appropriate power generation technologies and fuel options * Estimation of the demand for gas and its market value for power generation and other sectors * Assessment of fuel resources and supply costs (focusing on gas) * Review of environmental issues and policies driving investment in technologies for clean power generation, focusing on increased use of clean fuels such as gas. Objectives for Phase II were as follows: * Review of long-term commitment for a gas supply chain * Review and assess the institutional and regulatory mechanisms relevant to promoting gas * Review financial issues, options, and slructures and their impact on the cost of energy. Structure ofthe Report This report provides a detailed analysis of energy sector in China, including environmental issues, and reviews the market value for natural gas and its potential demand. The chapter-by-chapter breakdown of topics is as follows: 1. Brief overview of energy demand in China 2. Energy profile of East China, focusing on Shanghai, Jiangsu, and Zhejiang, highlighting key issues in the energy sector such as power sector growth, dominance of coal, role of hydro and energy, and environmental issues for the Yangtze Delta 3. Assessment of the potential demand for gas in the power and nonpower sectors of the Yangtze Delta and review of the principal environmental benefits 4. Review of options for gas supply including domestic gas sources, piped gas, and LNG; presentation of an integrated gas development strategy 5. Outline of key issues for developrrment of LNG, including gas pricing, institutional framework, role of government agencies, financing, and final cost of energy to consumers 6. Discussion of the ownership structure and trading arrangements, focusing on contracts and ownership structures 7. Review of regulation and the role of government, including gas pricing, institutional issues, and the necessary regulatory and legal conditions for developing LNG in China 8. Discussion of the financing strategy; options for downstream LNG investments and LNG purchase contracts; review of potential financing structure and risk mitigation measures 9. Analysis of the financial viability of LNG using several sensitivity factors 10. Review of the principal conclusions of the study. x Liquefied Natural Gas in China  Acknowledgments EPDC International, Ltd. and Tokyo Electric Power Co. (Iepco) were contracted to complete this study with financing provided by the World Bank's Japanese Consultants' Trust Fund. Toshiro Nishino of EPDCI and Hajime Murata and Kunio Uchida of Tepco guided the completion of this study. Dean Girdis, Stratos Tavoulareas, and Ray Tomkins were the authors of this sunumary report, as well as of the Phase I and Phase II reports on which it is based. Critical input and assistance were provided by local consultants, particularly Zhou Jianglong, Zhengxiang Ge, Jiang Liping, and Hu Ming of the Beijing Economic Research Institute (BERI; the organization changed its name in 1999 to the Center for Economic Research). John Wood-Collins provided thoughtful insight and commentary. Valuable comments and guidance were provided by the two World Bank task managers: Noureddine Berrah (East Asia Energy and Mining Development Sector Unit) and Phil Murray (Oil and Gas Group, Energy, Mining and Telecommunications Department), and by the client, Zhang Hongbo (vice director, Gas Based Power Generation) and Li Yong (project officer, Department of International Cooperation) of the State Power Corporation of China. Important commentary was also provided by Zhao Jianping (Operations Unit, World Bank Resident Mission in China) and Ralf Dickel (Oil and Gas Group, Energy, Mining and Telecommunications Department of the World Bank). Numerous meetings with government, private sector companies, and international banks assisted in the gathering of information for preparation of the report. Representatives from the following organizations were particularly helpful: SDPC, SETC, CNOOC, CNPC, Shanghai Municipal Government, East China Electric Power Company, Shanghai Municipal Electric Power Bureau, Shanghai Municipal Gas Company, Zhejiang Provincial Government, Zhejiang Provincial Electric Power Company, Jiangsu Provincial Government, Jiangsu Provincial Electric Power Company, Shell, Mobil, BP, Enron, Gaz de France, Wing Group, Total, ABN-AMRO, Chase, ING- Barings, USEXIM, and JEXIM. Ian Thomson prepared a separate unpublished paper, 'LNG Guidelines,' in conjunction with this report. Paul Wolman edited the present summary report and prepared it for publication. xi  Abbreviations and Acronyms BCF Billion cubic feelt sCM Billion cubic meters BOE Barrels of oil equivalent BOO Build-Own-Operate SOT Build-Operate-Transfer Btu British thermal units CAPEX Capital expenditure CCGT Combined cycle gas turbine ChinaOil China United Oil Corporation CIF Carriage, insurance, and freight (included) CiS Commonwealth of Independent States CHP Combined heat and power plant CM Cubic meter CNOOC China National Offshore Oil Corporation CNPC China National Petroleum Corporation CNSPC China National Star Petroleum Corporation CO2 Carbon dioxide DCA Discounted cash-flow analysis DFO Distillate fuel oil (gas-oil) DWT Dead weight ton ECA Export Credit Agency ECEPG East China Electric Power Group ECPN East China Power Network EPC Engineering (design), procurement, and construction FGD Flue-gas desulfurization FO Fuel oil FOB Free On Board FSU Former Soviet Union GDC Gas Development Company GDP Gross domestic product GEF Global Environment Facility GWh Gigawatt hours (106 kWh) HSE Health, safety and environment IBRD International Bank for Reconstruction and Development I EA International Energy Agency I FC International Finance Corporation lOCs International oil companies I PP Independent power producer kWh Kilowatt hours LDC Local distribution company LIBOR London Interbank Offer Rate LNG Liquefied natural gas LPG Liquefied petroleum gas Aii  LRMC Long-run marginal cost LSTK Lump-sum turn-key MCF Thousand cubic feet MCM Thousand cubic meters MICA Multilateral Investment Guarantee Agency MMCM Million cubic meters MOEP Ministry of Electric Power (China) MENR Ministry of Energy and Natural Resources (China) MICA Multilateral Investment Guarantee Agency MMbtu Million British thermal units MMSCFD Million standard cubic feet per day MMTCE Million tons of coal equivalent MMTOE Million tons of oil equivalent MOCI Ministry of Coal Industry MOFTEC Ministry of Foreign Trade and Economic Cooperation MOG Ministry of Oil and Gas MW Megawatt NEPA National Environmental Protection Agency (China) NG Natural gas NO, Oxides of nitrogen (NO and NO2) N PV Net present value OECD Organization for Economic Cooperation and Development O&M Operation and Maintenance Opex Operating expenditure P.a. per annum PPA Power purchase agreement PSC Production sharing contract RFO Residual fuel oil RMB Renminbi (Chinese currency) ROR Rate of return Rf/P Reserves to production ratio (expressed in years). SAFE State Administration for Foreign Exchange SAR Staff Appraisal Report (World Bank) SCF Standard cubic feet measures at 60 'F and 30 inch Hg SDB State Development Bank SETC State Econornic Trade Comrnission SinoChem China National Chemicals Import/Export SinoPec China Petrochemical Corporation SO2 Sulfur dioxide SP State Power corporation SPA Sales and purchase agreement (gas or LNG) SDPC State Development Planning Council TCM Trillion cubic meters (1012 CM) TCE Tons of coal equivalent TOE Tons of oil equivalent UAE United Arab Emirates Abbreviations and Acronyms xiii  Glossary Allowable costs The costs that the regulator permits to be included in the prices charged (excessive costs may not be allowed). Back-to-back provisions The linking of a condition in one contract to a similar condition in a related contract (e.g., the duration of a gas supply contract is the same as the duration of the related power off-take contract). Buildup The rate at which demand increases. Business chain The linked set of businesses that complete LNG production, delivery, and use by final consumer (also caled LNG chain). Capacity payment Payment of a fixed charge for making capacity available (e.g., part of a PPA) independlent of consumption. City gate Price of gas delivered to the city. Commercial risk Risks associated with selling to consumers (e.g., market, credit, price). Completion risk See Construction risk. Concession A contract for a defined period that confers the right to use a facility to supply a service to a defined area or set of customers (e.g., a monopoly or exclusive right to supply gas for several years in a defined area). Construction risk Risk that the plant construction will overrun on cost or time, or fail to operate to design standards (also called Completion risk). Contract structure The set of contracts between parties implementing a project. Contracts for differences A particular form of contract for purchasing electricity in a competitive market, by which the final settlement price is fixed and may be different from the market price. Controllable risks Risks that are under the control of one of the parties in the business chain (e.g., dispatch of power stations). Cost of capital The interest rate that must be paid on funds invested. Cost of capital varies depending on whether the funds are borrowed from a bank or raised from shareholders. Credit risk Risk that customer may default on payment Creditworthiness Ability of a borrower to provide security for the repayment of a loan, typically determined by the lending community. Cross-subsidy Price paid by one category of consumers recovers cost incurred by another. Discount rate Rate applied to discounting or calculating net present value (N PV). Discounting Adjusting future costs and benefits to make them equivalent to current money by applying a defined discount rate, often chosen to be the required rate of return (ROR). Dispatch risk Risk that power plant may not be dispatched as much as expected. Distribution system The low-pressure gas pipeline system that delivers gas from the high- pressure system to the final consumers. Downstream Here refers to the receiving terminal, regasification, pipelines, distribution, and power stations. Economic value The value of the resource calculated at the discount rate applicable to the country as a whole (the social or economic discount rate), usually specified by the government. Economic viablity When ROR of a project exceeds the government-specified discount rate. xiv  Electricity pool A centralized, short-term electricity market through which electricity is traded. The pool determines the dispatch of plant and the electricity price by competitive bids by generators (and consumers, in some pools). Eligibility criteria The criteria for selecting which consumers are allowed to purchase electricity directly from generation companies rather than from a centralized supplier, as in the single buyer model. Typically, large companies are the ones selected to purchase directly. Energy charge Payment for the variable part of a fuel supply or power purchase agreement, depending on units of energy (electricity) supplied. Energy conversion contract See Energy tolling contract. Energy elasticity The relationship between GDP growth and energy demand growth. Energy tolling contract Contract for operation of a power plant in which the power off-taker purchases and owns the fuel and the plant is paid only for the use of its capacity and operation. Also called an energy conversion contract Expansion project Investment in expansion of an existing LNG facility. Financial viability When the ROR of a project exceeds the investor's required ROR (i.e., exceeds the investor's cost of capital). Force majeure Conditions outside any contractual party's control (e.g., earthquake) severely impair or prevent performance of a contract. Fuel supply agreement A contract for purchasing agreed quantities of fuel for a power station. Typically a long-term contract with some take-or-pay obligations, which is usually backed by a power purchase agreement (PPA). Gas buyer The entity that signs the long-term LNG purchase contract. Gas development company A new company, probably a joint venture (JV) between a number of state-owned or private companies, formed to carry out key activities in the development of the new gas market. These could include investment, trading, and marketing. Gas marketer Organization that markets and sells gas to final consumers. Gas off-take agreement A contract for purchasing agreed quantities of gas, typically a long-term contract with some take-or-pay obligations and an indexed gas price. Gas-to-gas competition Competition between alternative suppliers of gas to a consumer Greenfield project A new (LNG or CCGT) plant on a new site. Guarantee Herein, a government promise to meet obligation of borrower. Indexation The linking of a price to an index, so that the price is automatically adjusted as the index price changes (e.g., gas price linked to international oil price index). Institutional framework The ownership structure of the sector, contractual relations, trading arrangements, and legal and regulatory framework. I nterfuel competition Competition between different fuels that can supply the same use (e.g., power generation or cooking). joint venture (IV) Agreement between two parties to invest jointly in a project. Liberalization of market Removal of institutional and/or regulatory restrictions to new investment or to operation of the market. LNG chain See Business chain. LNG train Facilities for LNG liquefaction. Market creation stage Initial investment in a market and development of new consumers sufficient to make the project viable. Market development stage Expansion of market by extending supplies to new consumers or new Glossary xv  geographical areas. Market risk Risk that demand or revenue may be less than expected. Mature market stage Stage when gas supply is available to all consumers and inter-fuel competition becomes a major determinant of further growth. Merchant pipeline The owner of the pipeline is the only company that may use it, and it owns the gas that is transported through the pipeline. Merchant power plant A power plant wvithout any long-term contracts other than with final consumers and that operates competitively in the market. Mid-merit operation Intermittent (of ten two cyde) operation of power station to meet daytime load, typically operating for 4,000 to 6,000 hours annually. Minimum scale project The smallest size of a project to achieve acceptable unit costs. Must-run obligation A power station contract (dispatch agreement or part of the PPA) that specifies mininium dispatch in a specified time period or allows the operator to determrine when the plant is dispatched. Net present value (N PV) The net value in money of a defined year of all future costs and benefits, discounted at a defined discount rate. Netback value The value of a fuel (gas) calculated as the final selling price less all the costs of delivering the fuel to the final consumer. The netback value can be calculated to any point in the business chain. Netback price The highest delivered cost of gas to the consumer, adjusted for conversion costs and operating efficiencies, as compared with currently used fuels, for gas to remain just competitive with currently used or alternative fuels. Nodal pricing Prices set between points of entry to and exit from a network. Nondiscrimination The termns for supply or price to each consumer in a defined category must be the sarne and must not exploit any form of monopoly or market power against a particular consumer or group of consumers. Open-access pipeline A pipeline to which any gas supplier has access on nondiscriminatory terms for transporting his own gas Ownership structure The owners and the type of company (state-owned or private, single shareholder or joint venture, monopoly or multiple companies, etc.). Pass-through of costs Seller may add the full costs of purchase to selling price and adjust the selling price whenever costs change (e.g., costs of fuel). PipeCo Short name for the pipeline owner or operating company. Political risk Risk associated with political, legal, tax, or macroeconomic factors of the particular country (some are under the control of the government). Postage-stamp pricing The transportalion charge is uniform and does not vary by distance, node, or zone. Power off-take agreement A contract for purchasing agreed quantities (or fixed capacity) of electricity. Typilcally a long-termn contract and an indexed or regulated power price (see also power purchase agreement). Power purchase agreement Typically includes separate charges for capacity and energy, and (PPA) minimum dispatch requirements. A power off-take agreement. Price cap Price regulation that fixes the formula for energy prices for a number of years and is designed to give incentives for efficiency. One of the cornmon price cap arrangements is known as RPI-X+Y, in which the price is indexed to inflation (RPI), less a factor designed to increase efficiency (X), plus indexation against uncontrollable costs (Y). Primary law Legislation passed by the national legislature. Process-or-pay agreement The minimum rate of use of or payment for a facility (e.g., regasification terminal). Similar in effect to a take-or-pay agreement. xvi Liquefied Natural Gas in China  Rate of return (ROR) The annualized rate of profit earned by an investment over its lifetime, usually expressed in real terms (i.e., after removing the effect of inflation). The Required ROR is the minimum that an investor would accept to carry out the investment, and is usually equal to or greater than the investor's cost of capital. Receiving terminal Harbor, unloading facilities, storage tanks, and regasification plant. Regas terminal Alternate term for receiving terminal. Regulatory framework The legal basis for economic and technical regulation, the bodies responsible for regulation, and the scope and method of regulation. Remittability The ability to transfer funds out of the country. Revenue cap Form of price regulation that fixes the formula for total revenue for a number of years. Revenue cap is typically applied to activities that have a high proportion of fixed costs (e.g., pipeline transportation). Risk The chance that the financial cost may be higher, or that the benefit may be lower, than expected. Risk premium The component of a discount rate that reflects the risk of the particular project compared with the rate of return that would be acceptable on a .zero risk' (i.e., very low risk) investment. Security of supply The risk involved in the availability of supply of a fuel Single buyer A centralized power model in which all generators must sell all their electricity to the 'single buyer,' who then sells to electricity suppliers and large consumers at a uniform bulk supply tariff. Take-or-pay contract A contract that specifies minimum quantities that must be paid for even if not taken in a specified time period if made available. Some take-or-pay contracts have 'roll-over' provisions that allow quantities paid for but not taken in one time period to be taken in a subsequent period. TermCo Short name for the receiving terminal company. Trading arrangements The form of the market and the type of trading that occurs (direct or through an intermediary, short term or long term, negotiated or open competition, etc.). Transparency Decisions or calculations that are based on defined and objective criteria and information. Transportation charge The charge for use of the network facilities to transport energy between a supplier and a consumer. Unbundling The accounting separation of different activities within a utility-either services or companies. 'Unbundling' does not necessarily require separation of ownership or creation of separate companies, but it usually requires some degree of management separation. Uncontrollable risks Risks not under the control of any party in the business chain (e.g., weather, international oil prices; compare fbrce majeure). Uniform pricing No price differentiation is made based on location, but gas prices will vary by category of consumer (e.g., small and large consumers). Upstream Here, production of gas, liquefaction, and transport to China. Volume risk Risk that demand quantity may be less than expected. Zonal pricing Prices that depend on the geographical zone of the supplier or consumer. Glossary xvii  Units of Measure Natural Gas Volume 1 MCF (1,000 CF) = 28.32 cubic meters (CM) 1 BCM= 35.3 BCF = about 0.9 MM TOE = about 1.35 MMTCE 1 ton of LNG = 2.35 cubic meters of LNG = 1,400 CM of natural gas Energy 1 MMBtu (252,000 Kcal) = 28.32 CM 1 CM = about 9,000 Kcal Town Gas 1 CM = about 3,700 Kcal Energy and Power 1 kWh 3,412 BTU = 860 Kcal 1 MW = 1,000 kW 1 GWh of electricity consumes approximately * 250 tons of oil in an oil-fired conventional steam power plant * 390 tons of coal in a coal-fired power plant * 282,000 CM of natural gas in a combined-cycle power plant. Currency Units 8.3 Yuan Renminbi (RMB) = 1 US$ (1998) xviii  Energy Demand Growth in China As of 1999, China was the second largest energy consumer in the world, after the United States, with a total demand of about 36 quadrillion Btu in 1995. China's energy demand is expected to grow by about 4 to 5 percent annually through 2015-a rate significantly higher than the 1 percent forecast for the industrial countries (U.S. Department of Energy 1999). Given these demand projections and the growing supply deficit, the growth in China's energy imports is expected to become increasingly important, particularly for liquid fuels and gases. Last, the production and efficient distribution of energy will be one of China's greatest challenges in coming years, as most energy reserves (i.e., coal) are located inland, at some distance from the coastal demand centers, and bottlenecks in transport of coal and electricity have been significant. From 1980 to 1995, commercial energy demand in China, driven by rapid economic growth, increased at about 4.1 percent annually-a much faster rate than in developed markets such as the United States, where energy demand grew at a rate of less than 2 percent. The expansion has been particularly pronounced in China's coastal provinces of Jiangsu, Zhejiang, Fujian, and Guangdong and in the municipality of Shanghai. In these areas, industrial growth and the resulting rise in living standards in cities led to annual GDP growth rates of about 16 percent from 1990 to 1996. Energy will continue to play an integral role in China's highly industrialized coastal regions even though slower economic growth is likely in the near term. Energy demand forecasts indicate that to the year 2020, total energy consumption in these provinces will grow by about 4 percent per year. Aware of the increased demand for energy, the Chinese government is striving to develop a comprehensive strategy to ensure that continued economic growth is sustained by sufficient energy supplies. Energy and environmental security are driving forces of national energy policy. Principal concerns of the emerging Chinese energy policy include the following: * Development of indigenous oil and gas resources * Development of domestic oil and gas markets * Diversification of energy sources * Diversification of imported energy suppliers * Protection of the environment at reasonable cost * Investment in energy conservation and energy efficiency. 1  China is addressing each of these concerns, and it appears that the most appropriate solution given long-term demand growth projections for energy consumption is diversification of fuel supply. Ideally, this diversification would focus on clean fuels that are price competitive with currently available fuels, such as coal. The substitute fuels must also be available in sufficient quantities. In this context, gas appears to meet the requirements of Chinese energy policy. Power Demand China's power demand is unmatched in the world. In 1997, China had an installed capacity of about 250 Gigawatts (GW; Table 1.1). Between 1980 and 1997, total power generation in China more than tripled, with average annual capacity additions of between 15 and 16 GW (8 percent annually). The country has 13 power grids with capacities of 1 GW or greater, 5 of which are wholly operated administrative regional groups. As of 1997, total electricity generation was 1,135 Terawatt hours (IWh), of which about 83 percent was thermal (944 TWh) and 17 percent hydro (191 TWh). Coal-fired plants provide more than 90 percent of the thermal generation. About 80 percent of the generating capacity added to the system from 1980 to 1997 consisted of coal-fired units. Oil-fired plants accounted for the remainder, although they have been declining sharply in recent years. Table 1.1 Power Capacity and Generation in China, 1980-97 Annual % growth Power demand item 1980 1990 1995 1997 1980-97 Total capacity (GW) 65.9 137.9 217.2 250.0 8.2 Percentage hydro 30.7 26.1 24.0 23.4 Percentage thermal 69.3 73.9 76.0 76.6 Total generation (lWh) 301.0 621.3 1,006.9 1,135.0 8.1 Percentage hydro 19.4 20.2 18.5 16.8 Percentage thermal 59.3 79.8 81.5 83.2 The growth in power demand is tied directly to economic growth, as the elasticity of electricity generation growth to GDP growth during 1980-97 was 0.83. Even though this is an exceptionally low elasticity for any country over a sustained period, it does demonstrate that with continued economic growth China will need to meet increasing energy demand. Even with aggressive conservation efforts, electricity demand/GDI' elasticity is expected to remain low, at about 1.0, well below elasticities in comparable developing countries. As of 1997, the largest consumer of electric power was the industrial sector (74 percent), followed by households (11 percent), services.(9 percent), and agriculture (6 percent). Compared with the previously noted average yearly increase of about 16 GW from 1980 to 1997 (8.2 percent rate), average yearly additions to electric power capacity will be 16.7 GW from 1997 to 2000, 22 GW from 2000 to 2005, and 28 GW from 2005 to 2010, according to Chinese estimates. This amounts to a 6.3 percent rate over the period from 1997 to 2010 (Table 1.2). 2 Liquefied Natural Gas in China  Table 1.2 Electricity Forecast (1997-2010) Annual % growth Forecast item 1997 2000 2005 2010 1997-2010 Electricity demand (IWh) 1,135 1,400 1,870 2,500 6.3 Installed capacity (GW) 250 300 410 550 6.3 Average annual additional capacity (GW) n.a. 16.7 22 28 Note: n.a. = not applicable Energy Supply Options China has a diverse mix of indigenous energy resources available to fuel the growing demand in the power and industrial sectors, including coal, crude oil, natural gas, hydropower, nuclear, and renewables. Of greatest strategic importance to China is its rich endowment of coal and hydro resources. These have played, and will continue to play, an integral role in the development of China's energy potential. Unfortunately, these resources are located primarily in central and southwestern China, far from the more industrialized coastal provinces in the East and South, where energy demand is the greatest and alternative energy supplies are most limited. Transporting and transforming these resources into exploitable energy is fraught with difficulties, including constraints in transport supply, insufficient capacity, and high cost. Moreover, although coal will continue to play a major role in meeting energy demand, environmental problems and the resulting costs associated with its use are becoming a major concern to Chinese authorities. Energy-induced Environmental Damage Energy consumption is a major cause of pollution and has extremely effects on the environment, the peoples' health, and the economy. The reduction of particulates and SO2 from households and small industries will have the most beneficial impact on the urban population, which suffers severely from indoor and outdoor air pollution. The devastation wrought by such pollution is illustrated by the following facts (World Bank 1996, 1997): * Air and water pollution damage to human health may be as high as $54 billion a year- nearly 8 percent of GDP in 1995. * As many as 289,000 deaths a year could be avoided if air pollution alone is reduced to comply with Chinese government standards. * Indoor air pollution, primarily from burning coal and biomass for cooking and heating, causes 111,000 premature deaths each year, mainly in rural areas. * Each year, some 7.4 million person work years are lost to health damages related to air pollution. Chapter 1: Energy Demand Growth 3  Acid rain in the high-sulfur coal regions of southern and southwestern China threatens to damage 10 percent of the land area and may already have reduced crop and forestry productivity by 3 percent overall and up to 25 percent in the worst areas. Chronic obstructive pulmonary disease, linked to particulate pollution, is the number one cause of all adult deaths in China, at 26 percent of the total. This is five times the rate of the United States. 4 Liquefied Natural Gas in China  2 An Energy Profile of the East China Region Profile ofthe Study Area The study briefly surveyed the energy situation in four coastal provinces of China-Jiangsu, Zhejiang Fujian, and Guangdong-and the municipality of Shanghai. The team also completed a detailed analysis of the energy market and potential use of gas for the Yangtze Delta area. This comprised, specifically, the provinces of Jiangsu and Zhejiang and the municipality of Shanghai. This study area was selected as a result of a review by the State Power Corporation of China and is intended to serve as a representative example for gas use in coastal areas. Although the study concentrated on the Yangtze Delta, it reviews the available gas and other energy resources in several coastal provinces as well in as some interior provinces. In addition, the results of the study, both in terms of the methodology employed and the conclusions reached, are applicable to other provinces that are considering using gas. Figure 2.1 shows the coastal areas and provinces in the East that the Chinese government is studying for the potential use of gas, as well as the major coal- and gas-producing provinces in the West. The study assessed demand for energy-principally in the power sector and in selected nonpower sectors. The power sector analysis assessed electricity demand and developed least-cost plans for the three areas as an interconnected system. For the nonpower sector, the study focused on Shanghai and the immediately adjoining urban and industrial areas of Jiangsu and Zhejiang as the demand center. In 1996, Jiangsu and Zhejiang provinces and Shanghai had a combined population of 128 million with an average annual per capita income of about $1,600, approximately 60 percent above the average for China of about $700. These areas also had an economic growth rate of more than 40 percent above the average for China. 5  Figure 2.1 Energy Resources and Target Areas for Use of Natural Gas in China io70 b6 o loo 70 20 . bXSSIAN FEDERATION _. >s KAZAMSTAN \ _ t0r . - o *... H- A .94A . MOONGOUAo r, 0. f 0,. KORF A t.~~~~~_________________ '. '. iC i ENE,KRGYZ REOUCE AND TReT AREAS> i FOR USEUBUC O' NAT GAKRE _-_bW XGJ C07*iCC *7 A ?.:?e& >55 -5 -.GOAr0 AAGCCCO P7ILPP7 CHNA g"W t/2 r Si5??a???>? ??? ? ENERGY RESOURCES AND TARGET AREA'S li W C st \ ?l l . ???-???>aQl ?ja > c; -> FOR USE OF NATURAL GAS 0 ? | >?:?;??j,,??;???? Energy Demand Growth in Coastal China From 1990 to 1996, economnic growth in China was dramatic-an average annual growth of 11 percent. China's coastal provinces, in particular Shanghai and Guangdong, led the surge, with annual rates of about 16 percent. Energy has been a critical component supporting this growth. The power and industrial sectors have contributed largely to the growth in energy demand, relying principally on domestic coal resources. The energy demand growth in the Yangtze Delta is expected to continue. Despite the recent slowdown in Asia, economic forecasts for the area are robust. Moreover, because many parts of China face constraints in domestic coal supply, is increasingly aware of environmental impacts, and has instituted new regulations to control pollution, the country is now seeking both a larger and a cleaner energy supply. As Table 2.1 notes, total energy demand in the coastal provinces is projected to grow from 253 million tons of coal equivalent (FCE) in 1995 to 798 million TCE by 2020. Energy demand growth in the five provinces during the period 1995-2020 exceeds the average for China, with total energy demand for the provinces growing to more than 30 percent of China's total energy consumption in 2020, compared with about 19 percent in 1995. 6 Liquefied Natural Gas in China  Table 2.1 Projected Energy Demand in China's Coastal Provinces (million TCE) Annual growth Province 1995 2000 2010 2020 1995-2000 Shanghai 45 59 89 117 3.9% Jiangsu 80 105 166 236 4.4% Zhejiang 46 68 106 145 4.7% Fujian 21 35 62 91 6.0% Guangdong 61 85 148 209 5.0% Total coastal provinces 253 322 571 798 4.7% as % of total energy 19.3% 21.3% 27.4% 30.2% consumption China 1,312 1,515 2,083 2,640 2.8% Source: Beijing Economic Research Institute (BERI; 1998). Energy Demand in the Yangtze Delta Growth in energy demand in the Yangtze Delta is projected at 500 million TCE by 2020, reflecting a 4.4 percent annual growth rate versus 2.8 percent for all of China. The estimate is conservative because it is based on income elasticity of energy demand growth of less than 0.70, consistent with China's historical patterns but low compared with Asian countries at similar stages of growth. Power Sector Demand The two Yangtze Delta provinces (Jiangsu and Zhejiang), along with Shanghai, make up most of the East China Power Network (ECPN). The combined capacity of the ECPN (which also includes Anhui Province, not part of this study) was just over 37,000 MW in 1998 and consisted mainly of coal-fired plant and some hydro. Most of the coal imported to China is consumed in these regions. Table 2.2 shows a projected power balance for the first modeling year of the study, 1998. More than 80 percent of the capacity for that year is coal fired. The system reserve margin is 19 percent, but a further 1,200 MW of connected capacity at Shidongkou, Shanghai, is included in the analysis (raising the margin to 23 percent). Future expansion at Wujing, in Shanghai, is also included. As Table 2.2 shows, Shanghai currently has no spare power capacity; Zhejiang has the largest surplus. Table 2.2 Projected Power Balance, 1998 (MW) Balance element Zhejiang Shanghai Jiangsu Total Percent Power demand 9,357 8,600 13,250 31,207 100% Installed capacity a Coal 8,158 6,030 11,025 25213 81% Other thermal 424 2,570 5,182 8,176 26% Hydro 3,643 0 0 3,643 12% Total capacity 12,225 8,600 16,207 37,032 Percent 33% 23% 44% 100% Reserve margin 31% 0% 22% 19% Source: BERI (1998). a Includes reserve margin Chapter 2: An Energy Profile of the East China Region 7  Table 2.3 shows the installed capacity and generation of the three provinces. Jiangsu has more than 44 percent of total capacity at almost 14,000 MW; Zhejiang, 10,700 MW; and Shanghai, 6,900 MW. Table 2.3 Installed Capacity (MW) and Generation (GWh) in Yangtze Delta, 1996 Province Installed capacity Total generation Jiangsu 13,882 75,639 Shanghai a 6,916 39,130 Zhejiang 10,715 44,835 Total 31,513 159,604 Source: BERI (1998). a Figures for Shanghai are for1995. The study area is not itself rich in local energy resources. Available resources are at some distance, and transportation issues exacerbate the problem of supply (the issues are mainly coal transportation bottlenecks and the high costs of transmission lines from inland hydroelectric plants and minemouth coal-fired plants). For this reason, the area is pursuing a balanced energy supply strategy embodying the use of all available energy resources for diversification and security. Nuclear power is on line in the region (a 280 MW plant in Zhejiang) and is expected to increase to a total of 5,000 MW by 2005. Local hydroelectric resources are limited (full potential, 13 GW), and are approximately 50 percent exploited to date. Power imports from other provinces are also intended, as demonstrated by the plans to purchase 5,400 MfW from the Three Gorges hydroelectric station after 2005 and the building of the Yacheng coal-fired power plant (6 x 350 MW) in Shanxi, which is dedicated to provide power to Jiangsu by 1999. In the future, other hydro resources may become available, but the study limited its analysis to hydro resources from outside the Yangtze Delta that had been identified and included in the development plans of the various provinces. Jiangsu is among the most developed provinces in China. Indigenous energy resources are limited, so, like the other provinces in this study, Jiangsu will have to import most of its energy from other areas. Oil, hydroelectric, and gas make up only a small share of the province's supply. To address the growing need for greater energy, a nuclear power plant is planned for Lianyunguang City and is scheduled to open in 2005-6. In the near term, the province has signed a power purchase agreement (PPA) to secure coal from Shanxi Province for the soon-to-open Yacheng power plant. Shanghai-China's largest industrial, commerciaL and financial center-is powered primarily by coal- fired thermal plants. However, as virtually all of its primary energy consumption depends on imports from other regions in China or from abroad, Shanghai suffers from energy shortfalls and load shedding. With energy consumption per capita and energy intensity far greater than in most of China, Shanghai faces a challenge in meeting its future energy needs in an environmentally sustainable manner. Zhejiang has limited coal reserves and some hydro resources. About half of the potential hydro (4,700 MW) is already developed. These hydro facilities make up more than a quarter of Zhejiang's capacity but typically provide only a tenth of electricity generation. Coal accounts for more than two-thirds of total energy consumption, but 97 percent must be imported from other provinces. Industry still uses 75 pecent of the total electricity generated, but demand is growing in light industry, construction, transportation, and retail. Zhejiang, the second-fastest developing region in China, is expected to continue to grow more rapidly than the national average. Zhejiang has good access to sea transport and available sites for construction of thermal and hydro plants. 8 Liquefied Natural Gas in China  Nonpower Sector Demand The Yangtze Delta has five principal sectors of nonpower energy demand: residential, commercial, industrial, metallurgical, and petrochemical. Coal is the dominant fuel for four of these sectors (80 percent of nonpower demand); the exception is residential, where LPG and town gas have increased dramatically. Heavy fuel oil (7 percent of nonpower demand) is the second major fuel, used mostly in metallurgy and petrochemicals. Heat processes are the major use of these fuels. LPG and town gas are the only gas-based fuels consumed, with most demand in the residential and commercial sectors. LPG consumption has grown rapidly in recent years, largely in response to economic growth and the absence of alternative clean fuels. The increase has been from about 3,000 tons in 1990 to more than 7,500 tons by 1995, an annual growth rate of 14 percent. In the cities of the Yangtze Delta study area, consumption of all gases and access to gas increased significantly from 1985 to 1995. LPG consumption increased by 255 percent, and town gas consumption increased by 425 percent. Concurrently, residential access to gas in urban areas has increased dramatically-from 17 percent in 1980 to more than 70 percent by 1995. In comparison, urban consumption of coal grew only by 12 percent during this same period. LPG access has increased from only 52 cities in 1980 to 430 cities by 1993, with more than 70 percent of LPG consumption is Eastern Chinese cities. LPG has been used as an interim fuel, primarily to replace coal and other heating fuels in urban areas. Typically, LPG consumption in consumer and commercial sectors declines rapidly when other, more attractive fuels are available, such as natural gas. Future plans are to divert LPG to feedstock applications in the chemical industry, using natural gas to meet the growing urban energy demand. Coal's Dominance Continues China has large coal deposits, with recoverable reserves of about 900 billion tons, of which approximately 115 billion tons, or 13 percent, are proven. The geographic distribution of reserves is quite uneven. Some 80 percent of China's coal reserves are located away from the coastal consuming regions. A growing share of total coal production comes from three provinces in the north central area: Shanxi, Inner Mongolia (Nei Mongolia), and Shaanxi, which account for 28.1 percent, 22 percent, and 17.5 percent, respectively, of total proven reserves. Coalbed methane may provide a significant source of energy in the future, although current annual production is only about 500 million cubic meters (MCM), with reserves of about 3,500 billion cubic meters (BCM) distributed mainly in Hubei and the northwestern areas of China. Because of the distance of coal resources from most industrially developed areas, interregional coal trade is massive. The supply chain that brings coal from the producing areas to the coastal areas, and specifically to the Yangtze Delta, has three critical components: railway transport, coastal and inland waterway transport, and port unloading facilities. Unfortunately, this supply chain suffers from major bottlenecks as a result of insufficient rail and port unloading capacity. As a result, the supply of coal to the eastern provinces is limited, and the security of energy supply is questionable. Figure 2.2 presents an overview of coal flows to the Yangtze Delta. Chapter 2: An Energy Profile of the East China Region 9  Figure 2.2 Major Coal Transport Corridors to Yangtze Delta ~~~~ ~~RUJSS&Ak F"RAMIt410 KAZAXHSL ro._ x, X R z > . jo~~~~-, .~ N~~, x . n'>' ,,1 w . t . ~~~~~, < i^I _.J r =_) I e^ ONGOLIAC, - :f - P~~~ _, . _00101J00r , ,:: s~~~~ _0900000 ' - 40 SG= ej0{j> ) </CHN- . .S .. . .... .. .... ... .. . TO: THE YANGTZE DELT.'.A 000 demand' for caraeo ca.Cretl,ri right cpityJ met 70 percent of demand, and the consumption~~~ cEnes Mre recntl, ter asbensoemroemn. A majr fator hre i CHINA .>, - 2 e 7 2 g2> 22222A A I YL .K3 5 . Q ( . .................. 222 > :22 2: 2> 2 ig: :2 2B 2 -2-2222222,2. -: :...BB inrsrutr to handle th voum apea toeee oesevr problem. Th iiedcpct A study by the World Bank (1994) on China's coal and electricity delivery system concluded that the country's transport capacity and infrastructure may not be keeping pace with the growing demand for carriage of coal. Currently, rail freight capacity meets 70 percent of demand, and the inland coal producers have experienced serious bottlenecks in transporting coal to the eastem consumption centers. More recently, there hLas been some improvement. A major factor here is lack of a sufficient number of locomotives, but shortfaas of rolling stock and inabivty of the infrastructure to handle the volume appear oth be even more severe problems. The limited capacity of China's ports also presents a major challenge for energy transport. In the study area, for example, Shanghai needs an additional 25 niillion tons of new unloading capacity, and other ports south of Shanghai and on the Yangtze River require an additional 10 million tons to meet the demand forecast for coal deliveries. Limitation in the coal supply chain reflects the information available at the time of the study but does not affect the analysis in a quantitative way. More specifically, no constraints were imposed Olli the arnount of coal available, and the coal prices reflect the economic costs of production a:nd transportation. If the transportation costs have declined since the study was completed, obviously this could have an impact on the LNG demand. 10 Liquefied Natural Gas in China  Before the pricing reform in 1993, coal prices were set at artificially low levels. Today, however, most coal prices in China reflect actual economic prices. With only a few exceptions, current consumer prices do not have any government subsidies and are equal to or exceed the economic cost of supply. The typical coal price that consumers in Shanghai and Guangzhou pay for Shanxi coal (5,200 kcal/kg heating value) averages 300 RMB/ton, or about US$35/ton. Adjusting to a heat content of 6,500 kcal/kg, which is typical of internationally traded thermal coal, makes the equivalent price US$44/ton, near the top of the average price range (US$35 to $45/ton) for imported coal in the region. Role of Hydro Relatively speaking, hydropower is the least-cost generation source in China. It serves, and will serve, a major role in meeting the base-load power generation needs of the country. The generation cost is about $0.03/kWh. Hydro resources are abundant in China as a whole. The country has a hydroelectric potential of 670 GW, of which 380 GW are considered suitable for exploitation (Sinton et al. 1996). This capacity may generate up to 1,900 TWh per year. By the end of 1996, 56 GW of installed hydro capacity were in operation, reflecting approximately 14.7 percent of the exploitable resource. The installed capacity is expected to increase to 70 GW by the year 2000 and to 100 GW by 2010. It is possible that hydro resources inland are more cost-effective than LNG-based power generation. However, the study (because of limited resources) had to use as a base the official development program in the region. To the extent that hydro resources are included in the official plans of the various provinces, the study took them into account. Three Gorges is a good example. As Tables 2.4 and 2.5 show (included as Tables 4.4 and 4.5 in Phase 1 report), the capacity allocated to Shanghai, Jiangsu, and Zhejiang reaches 5,400 MW by year 2009. These were the official estimates at the time of the study, identified by BERI. Table 2.4 Power from Three Gorges Allocated to Jiangsu, Shanghai and Zhejiang Year 2003 2004 2005 2006 2007 2008 2009 Three Gorges capacity (MW) 1,400 4,200 7,000 9,800 12,600 15,400 18,200 Capacity allocated to study region 415 1,246 2,077 2,908 3,738 4,569 5,400 Table 2.5 Seasonal Variation of Average Power from Three Gorges Allocated to the Study Area (TWh) Year 2006 2010 2020 Season 1 June-September) 5.1 10.1 12.6 Season 2 (October-December) 4.9 5.1 5.4 Season 3 (anuary-May) 3.9 5.4 6.9 Total 13.9 20.6 24.9 The demand analysis was reported more fully in the Phase 1 report, which also showed a number of sensitivity cases with different annual load factors for the gas fired plant. Note that any thermal plant can take the complementary role with Three Gorges, including coal-fired plants. Because Chapter 2: An Energy Profile of the East China Region 11  seasonal coal storage is more practical than seasonal gas storage, and considering the probable requirement for a take-or-pay contract for gas, coal-fired plants could be preferred in some circumstances to gas plants for fulfilling the complementary role. However, constraining factors on hydro development are also noteworthy. Some 75 percent of the hydro potential is in the West.(e.g., in the ongoing Three Gorges project), more than 1,500 km from the load centers of coastal China. Hydro capacity is limited in some coastal areas, such as that served by the ECPN. Although China has increased its efforts to develop large-scale hydro resources, three factors in particular are likely to slow hydro development: * The existing transmission system is inadequate. * The distance of the resources from the demand centers adversely affects the economics of transmission projects, making them uneconomic to finance. * Many hydro projects have significant environmental impacts and face strong opposition from local and international groups. Key Energy and Environmental Issues in the Yangtze Delta Several key issues drive the energy market in coastal China, particularly in the Yangtze Delta: * EEnergy resources are in limited availability in demand centers of coastal China. * Infrastructure supply constraints hamper delivery. This is particularly a problem with regard to the bulk transport of coal from mines in western and central China. Limitations are also evident in the high-voltage transmission system carrying electricity from western China to power-deficit areas in easteni China. * Coal consumption is a direct cause of high and increasing levels of urban air pollution. Coal reserves currently supplying the Yangtze Delta are located principally in Shanxi and Shaanxi provinces. Transporting coal to demand centers in the Yangtze Delta requires a complex supply chain, often including railway and inland waterway transport, along with oceangoing barges. As a result, the delivered cost of domestic coal tc the coast areas approximates that of internationally priced coal-greater than $40/ton. This situation is not Likely to improve much in the long term. Other energy resources will play a role in the coastal region's energy balance, but they are not available in sufficient quantities to meet the forecast demand growth, especially in the power sector. The coastal provinces have already exploited the limited hydroelectric power available from local sites. Power delivered by long-distance transmission from large hydroelectric facilities (including Three Gorges) and minemouth plants in inland China could meet some of the demand. But because existing transmission capacity is limited, expansion plans would need to scrutinize the economics of using long-distance transmission versus other options for power supply. Similarly, although China has embarked on an ambitious nuclear development program, questions remain regarding both its economics and its ability to meet the projectedL schedule. Petroleum-based resources in coastal China are not significant and are used primarily to meet demand for transport fuel. Air quality in both inland and coastal areas has continued to deteriorate because of increased levels of sulfur and suspended particulates. These are directly related to coal consumption in both the power and nonpower sectors. The power and, industrial sectors are major contributors to emissions from coal burning, although the deleterious effects of large-scale coal combustion are in part 12 Liquefied Natural Gas in China  mitigated by pollution control equipment and dispersion of emissions from high smokestacks. Burning of coal in commercial and residential applications is thus perhaps more injurious to people, as the emissions tend to be dirtier and less easily dispersed. Last, the resulting regional and global environmental benefits will also affect neighboring countries, such as Japan and.South Korea. Recognizing these external benefits, non-Chinese entities may well facilitate LNG investment in China. Chapter 2: An Energy Profile of the East China Region 13   Projected Demand for Gas and Influence of Benefits of Gas Use The competitiveness of gas as an alternative fuel is the principal determinant of its long-term market demand not only in the Yangtze Delta but also in China as a whole. In most geographic areas and uses it will compete directly with coal. At present, domestic gas may compete in areas where it can be produced economically, and imported gas may compete in areas where alternative energy sources are unavailable, where they are prohibitively expensive, or where air pollution dictates the use of a clean fuel. The envirornental benefits of gas are important considerations and a principal driver in promoting increased use of gas. The combination of both environmental and nonenvironmental benefits means that several key factors will drive the establishment of gas markets. Demand for Gas Characteristics of Demand The projected demand for gas is greatest in three geographic/ demographic areas: * Areas of high energy demand growth, both in power and household demand * Areas characterized by increasingly limited access to domestic coal supplies and prices approaching international levels * Areas with high levels of air pollution and newly introduced or pending restrictions on the burning of coal. Most locations that fulfill these three characteristics are in urban areas and include Beijing and the coastal cities of Hong Kong, Shenzhen, Guangzhou, Shanghai, Hangzhou, Nanjing, Qinqdao, and Tianjin. In some of these areas, however-particularly East China and Guangdong-gas or LNG may not be the most logical fuel option. More detailed analysis of each market is required before such a conclusion can be reached. I15  Yangtze Delta Case Study The study team calculated gas demand for the power and nonpower sectors in the Yangtze Delta. Gas demand in the power sector was based on a power system model for the East China Power Network, which developed a least-cost power expansion plan and dispatched the various power plants based on production cost economics. For the nonpower sector, demand for gas was determined by direct substitution of selected fuels- such as town gas, LPG, and light fuel oil--with gas, where gas was competitive, based on its economic cost of supply, adjusted for its relative efficiency and related conversion and equipment costs. Considering that gas demand varies with the price of delivered gas (its netback price), rising as the price of gas falls, the consulting team developed alternative plans for expanding power generation and evaluated the sensitivity of gas demand to gas price in all sectors. Demand for natural gas in the power and nonpower sectors ranges widely depending on the netback price to the consumer. Using values of $4.00 to $4.30/MMBtu as the possible supply cost range of gas, demand for gas is about 2.5 BCMI in 2005, 12 to 14 BCM in 2010, and 35 to 55 BCM in 2020. Figure 3.1 presents total gas demand and demonstrates its price sensitivity. Moreover, the analysis shows an aggregate demand for the Yangtze Delta (Jiangsu and Zhejiang provinces and the municipality of Shanghai) that makes LNG viable by 2005. Calculating demand for each province and municipality separately, however, probiably would show sufficient gas demand for separate LNG projects until after 2010. (We assume that demand needs to be, or rapidly grow to, about 3 BCM for an LNG project to be viable.) Figure 3.1 Total Projected Demand for Gas 6 2003 5 0 lo 20 30 40 50 60 70~~~~~~~~~~- 00 --2007 E 3 -* ------2010 2 . I I ---~~~~~~~~~~~~~~2015 2020 0 0 10 20 30 40 50 60 70 Gas demand, BCM 16 Liquefied Natural Gas in China  Power Sector Demand and Load Forecast A Base Case power demand forecast was developed using the latest projections of the central and provincial governments. Two alternative load forecasts were also developed-low and high demand. The low and high forecasts were established by subtracting and adding 1 percent per annum, respectively, to the Base Case annual growth forecast for the period 2000-20. The power sector analysis took seasonal and daily load profiles into consideration. Approach The study considered all available energy alternatives in developing a least-cost plan for expanding the power system to meet demand for electricity in the study area to the year 2020. To address key uncertainties and gain a better insight on the strategic importance of the various alternatives-in addition to the three alternative demand forecasts-the sensitivity analyses included the following: * Various prices of gas, ranging from $3.0 to $5.5/MMBtu, used to establish the sensitivity of gas demand versus gas price * The impact of take-or-pay contracts on the least-cost plan, the incremental costs to the power system, and the gas demand * The impacts of alternative levels of environmental constraints on the least-cost plan and demand for gas, including the following: - Including flue-gas desulfurization (FGD) plants in all new coal-fired power plants - Imposing a cap on the total emissions released by the power sector - Recalculating the least-cost plan using a number of alternative environmental externality values for particulates, SO2, NO,, and CO2. The analysis used the GESP II model, which uses mixed-integer programming. The World Bank and Asian Development Bank have used this model extensively to develop least-cost plans for China's power sector. Gas Demand The medium-term supply options. for the power sector include coal-fired generation, hydropower, (including allocated energy supply from Three Gorges), nuclear, and natural gas. The new hydro options are limited, however, because almost all the available resources are already exploited. Power imports from hydroelectric and minemouth plants in inland China, as well as nuclear expansion options, are included in the analysis of the power system as competing options. The required gas-fired power plants identified by the least-cost analysis appear in Figure 3.2. Chapter 3: Projected Demand for Gas 17  Figure 3.2 Cumulative Installed Capacity Additions of Gas-Fired Power Plants 40,000 - 35,000 - 30,000 - 25,000- 2 ~~~~~~~~~~Com bined cycle = 20,D00 - 15,000 10,000 - Open cycle 5.000 0 2005 2007 201)0 2015 2020 aYtear Note: $4.20/MMBtu at burner tip. Estimated by Least-cost plan analysis. Demand for gas varies with price. Demand for gas in the power sector is only about 1.3 BCM by 2005 but rises rapidly to 5 BCM by 2007 and to 10 BCM or more by 2010. The demand curves tend to have a characteristic 'kink' price above which the demand falls rapidly; this 'kink' price indicates the highest price at which gas is likely to be introduced into the market in large volumes. Figure 3.3 shows that this price probably lies in the range of $4.00 to 4.50/MMBtu (burner tip). Figure 3.3 Gas Demand from the Power Sector, 2003-20 6 -2003 ---- -2005 5 k ---2007 -- -2010 3 1\ ", \ 0 ---2015 I I ____~~~~~~~~~~~~~~~~2020 0 5 10 15 20 25 30 35 40 45 50 55 60 Gas demand, BCM The approach was to let the least-cost plan place the LNG projects in the appropriate dispatch order based on marginal costs of the plants in the power system. The results suggest that, indeed, for the first few years, the least-cost plan selected a significant amount of open-cycle gas turbine plants (e.g., 2,660 MW by 2005 and 3,200 MW by 2007) compared with combined-cycle plants (1,546 MW by 2005 and 5,645 MW by 2007), as shown in Table 3.1 (cf. Table 4.7, Phase 1 report). This suggests that originally peaking gas-fired capacity is needed, as also demonstrated by the capacity factor (average capacity factor of open-cycle plus combined-cycle of 39 percent in 2005, 43.5 percent in 2007, and 50 percent in 2020). 18 Liquefied Natural Gas in China  Table 3.1 Required LNG-based Power Generation Capacity Open cycles LNG/combined cycles CC utilization CC capacity factor Year (cumulative MW) (cumulative MW) (hrs/yr) (%) 2005 2,660 1,546 3,413 39.0 2007 3,200 5,645 3,814 43.5 2010 3,300 13,521 4,116 47.0 2015 5,100 21,020 4,202 48.0 2020 6,800 36,032 4,407 50.3 Also, the seasonal variation of LNG demand was evaluated (see Figure 4.11 of the Phase 1 report). This includes the impacts from projects such as Three Gorges. Of course, the final recommendations of the LNG report take into account the financing of the LNG project, which requires a higher capacity factor at the beginning of the project (initial 2 to 3 years) as demand ramps up above the minimum-size LNG plant (2.5 to 3 BCM). Nonpower Demand Forecast Energy demand growth was calculated to 2020 for the nonpower sector and was based largely upon estimates provided by provincial and local planning authorities, central government, and other government offices. Three cases were calculated: Low, Base, and High. Elasticities of energy consumption in nonpower sectors are below 0.60, comparable to the current forecast. Gas demand beginning in 2005 was estimated for the urban and surrounding industrial areas of the cities of Shanghai and Ningbo and Hangzhou of Zhejiang Province. In 2010, additional cities were added, including urban and industrial areas of Wuxi and Suzhou in Jiangsu Province and Jiaxing and Shaoxing in Zhejiang Province. Several provincial government agencies have reported higher gas demand from nonpower sectors than estimated in this study. Such demand is possible, but the project team could not substantiate it because it lacked access to all data and did not include the possibility of new environmental laws that may restrict the use of coal and stipulate the use of clean fuels such as gas. Approach The approach for estimating the demand for gas in nonpower sectors was based on identifying the nonpower sectors where gas is competitive. This was determined by assessing the fuels and processes in which gas could serve as a substitute fuel. The netback value for gas was then calculated based on its relative price compared with currently used fuels, adjusted for differences in efficiency and connection costs, equipment costs, or both. Based on the analysis, gas is competitive with LPG, town gas, and diesel / light fuel oil for several sectors. Gas is not price competitive with coal used primarily as a heating fuel in any of nonpower sectors, however. As a result, energy-intensive sectors such as direct smelting of metals (though not refined processing) and cement production, which require large amounts of energy for heat, were deemed uncompetitive markets for gas. Chapter 3: Projected Demand for Gas 19  Gas Demand The Base Case was chosen as the most likely demand scenario. Figure 3.4 shows demand for gas in the nonpower sector varying with price, as it did in the power sector. For a price of $4 to 6/MMBtu, demand for gas is about 1 BCM between 2005 and 2007 but rises rapidly to 2.5 BCM by 2010. The netback value for the bulk of demand is between $4 and 10/MMBtu. Additional demand (e.g., in the residential and commercial sectors) could be available at much higher prices. Figure 3.4 Base Case Nonpower Demand for Gas 16.0 14.0 [> 2003 12.0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~---2005 10.0 - - -200 -2007 6.0 4.0 015 2.0 * 0.0 2.22 0 1 2 3 4 5 6 7 Gas demand, BCM As Figure 3.5 shows, with a netback value of gas of $4.2/MMBtu (example-does not imply a recommended price for LNG), demand for gas in the nonpower sector is about 1.5 BCM in 2007, 2.5 BCM in 2010, and 6.5 BCM in 2020. The residential sector accounts for the largest portion of nonpower gas demand. Figure 3.5 Nonpower Demand for Gas 7.00 6.00 - Residential E u 5.00 ~4.00- 3.00 Commercial g 2.00 - Light industry 1.00 O.. - Metallurgy 0M E Fertilizer 0.00 2000 2005 2010 2015 2020 Year Note: $4.20/MMBtu, city gate. 20 Liquefied Natural Gas in China  In 2007, nonpower sector demand for gas is the greatest in Shanghai, with approximately 76 percent of the total nonpower sector demand. Significant demand exists in Jiangsu and Zhejiang but is highly sensitive to the location of the LNG terminal and its proximity to urban and industrial centers and construction of gas transmission and distribution systems. Nonpower demand in these two provinces increases to 44 percent of the total by 2010. Although gas is not economically competitive with LPG in several sectors until 2015, it is highly unlikely that residential, commercial, and industrial consumers would not begin using gas earlier because of the convenience factor over LPG, a typical response in such cases. Gas would serve as a cooking and heating fuel and would compete directly with town gas and LPG. Netback values were calculated only for use of gas as a cooking fuel. Gas would substitute for town gas and would displace current and projected use of LPG in Shanghai and other systems over 10 years, as the systems are upgraded. In cities such Hangzhou, which have newer infrastructures capable of direct substitution, the displacement would happen sooner. Total estimated demand should rise from 0.75 BCM in 2005 to 0.83 BCM in 2007, 1.5 BCM in 2010, and 3.5 BCM in 2020. Commercial demand will focus principally on enterprises using town gas and LPG for heat processes with which gas is economically competitive. Projected commercial gas demand in 2003, based on town-gas substitution, is estimated at about 0.11 BCM, rising to almost 0.40 BCM by 2015. Estimated demand from LPG substitution is 0.08 BCM in 2003, rising to 0.25 BCM by 2015. Light industry, including processing and manufacturing industries, uses coal, heavy fuel oil, light fuel oil, diesel, and LPG. Gas is the preferred fuel for processes requiring clean combustion and temperature regulation. Gas is competitive with light fuel oil and LPG, with a projected demand in 2005 of 0.125 BCM, rising to 0.17 BCM by 2010. Coal is the predominant fuel for the metallurgy industry, although some light fuel oil and self- produced coal gas are used for refined metallurgy processes. The Baoshan Steel Factory, located in Shanghai, currently uses self-produced coal gas and has plans to use LPG in the near future. Gas can economically displace future use of LPG and current use of light fuel oil, although it would not displace coal. Estimated demand is 0.38 BCM in 2005, rising to 0.48 BCM by 2010. The Wujing Chemical Complex in Shanghai currently uses about 260,000 tons per year of naphtha to produce ammonia and urea. Using imported gas for producing fertilizer is considered uneconomic unless the supply cost for gas is less than $1/MMBtu. In coastal China, the cost would be above $2/MMBtu. Chinese government policy strongly encourages indigenous production of fertilizer to maintain a degree of 'self-sufficiency,' however. In this context, use of gas at Wujing is considered economically justified, as gas is less expensive than the currently used naphtha and because it is in an existing facility that will continue operation. Potential gas demand is about 0.30 BCM. Key Factors for Establishment of a Gas Market Given the analysis completed during Phase 1 and 2 of this study, several key factors regarding the establishment of a market for gas and a viable LNG project can be identified: Gas is an economic and environmentally advantageous fuel in several uses. Based on the projected energy demand and available energy resources in the study region, and in China Chapter 3: Projected Demand for Gas 21  in general, gas is an economic fuel in a number of uses and should be promoted as part of China's strategy for development of fuel supply options. Gas also has benefits in other areas, such as in improving energy supply security and mitigating energy-induced environmental problems. Alternative energy sources have limited availability or associated delivery problems. Coal is presently available in inland provinces, but transportation system constraints and costs make coal expensive, even without factoring in environmental impacts. New hydro sites are almost nonexistent. Import of power from large hydroelectric and minemouth plants in inland provinces is feasible but costlyr because of the long distances to the Yangtze Delta. Last, nuclear power is being slowly developed for this region, but it is unlikely on its own to meet the growing energy demand of the region. LNG and other gas supply options are complementary, with LNG and offshore gas essential to satisfy projected energy demand in shorter term. All steps possible should be taken to move ahead with development of an LNG industry. LNG and other gas supply options are complementary, and both LNG and offshore gas will be required to satisfy projected energy demand in the shorter term. Onshore piped gas (from inland and international sources) does not appear to be economic for this region until the longer term-10 to 15 years. After 2015, projected demand for gas may justify introduction of pipeline gas in this region. Indications are that offshore gas is present in moderate volumes and could be developed. Further assessment of this resource should be pursued as a priority. None of the alternative gas supply sources are likely to be low cost, and imported LNG is therefore likely to be competitive with other gas supply options and could meet some of the gas demand from 2005. The total demand for gas varies with its price, particularly in power generation. For a price range of $4.00 to 4.50/MvMBtu, total demancd could be about 2.5 BCM in 2005, increasing to about 5 BCM in 2007, 12 to 14 BCM in 2010, and 20 to 60 BCM in 2020. In 2010, demand in the following sectors would be as follows: - 8 to 12 BCM for power generation - 1.5 BCM for residential - 1 BCM for selected industrial users. * Gas demand could be satisfied economically with LNG imports from sources including Australia, Indonesia, Malaysia, and Qatar. That is, LNG could be made available in the study region at prices consistent with the market value of gas. At present, LNG prices in the $3.75 to 4.50/MMBtu range (burner tip or citygate prices) are projected for the study area. * The minimum initial volume for a viable project would be to provide 3 BCM of gas by 2005 to meet energy demand in power and industrial facilities. Earlier introduction of LNG is possible in 2003 if 1,200 to 2,100 MW of existing and planned oil-fired power plants are converted to gas. It is unlikely, however, that LNG facilities could be approved and constructed much before 2003. Any earlier seems unrealistic. Although the study dealt with uncertainty associated with the energy demand forecast through sensitivity analyses, the Asian financial crisis may have greater effects on China than expected. Such effects, if they materialize, are expected to influence only the short-term demand (next 2 to 3 22 Liquefied Natural Gas in China  years), with only limited impact on the long-term growth trends. Reduced short-term demand may delay the need for LNG by 2 to 3 years. Alternatively, the LNG development could proceed on schedule by converting the existing and planned oil-fired power plants (1,200 to 2,100 MW) to gas. Environmental Benefits of Gas The introduction of gas into the power and nonpower sectors will reduce emissions of particulates, SO2, NO,,, and CO2 significantly. Figure 3.6 projects the beneficial impact of using gas as the basis for expansion of power generation in Shanghai, Jiangsu, and Zhejiang: it would virtually stabilize SO2 emissions at present levels without retrofitting existing coal-fired power plants with flue-gas desulfurization equipment. Compared with a business-as-usual scenario that bases expansion of generation on coal, use of gas would reduce SO2 emissions in the power and nonpower sectors (based on the expansion case scenario) by approximately 15 million tons between 1998 and 2020. This is a reduction in emissions from the power sector alone of more than 90 percent. Figure 3.6 Impact of Gas Use on Power Sector Emissions in Shanghai, Jiangsu, and Zhejiang, 1999-2021 3,500 - 3,000- 0- 5s2without gas re2,500 so 52wkth gas-- - 2,000- o 1,500 1,000 2000 012 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 2020 Year Nonenvironmental Benefits ofGas Interfuel Substitution and Reduced Dependence on Coal China's inadequate and inefficient infrastructure for transporting coal cannot meet the energy needs of the country-particularly in coastal areas such as the Yangtze Delta. Coal is now the dominant energy source, and high demand throughout the country often leads to supply shortages and uneconomic pricing by suppliers and transporters. Promoting alternative fuel sources will encourage more competitive pricing in the domestic energy sector. In particular, introducing gas Chapter 3: Projected Demand for Gas 23  into the energy balance will give consumers an alternative fuel that will reduce their dependence on coal and, concomitantly, the stress on the transport system. Fuel Diversification Coal meets more than 90 percent of energy requirements in China's power sector alone. The combination of the continued supply constraints affecting inland coal and the rapidly rising demand for power in the coastal provinces will endanger continued economic growth. China thus badly needs more a reliable and diverse energy supply. Natural gas could play a critical role in meeting the energy needs of China's power sector by 2010, potentially replacing both coal and the polluting town-gas systems currently in use in many of the coastal cities. More Efficient and Flexible Operation of Power Systems The introduction of properly sized power stations that meet specific load requirements will increase the efficiency of the power system and reduce costs. Current cycling of coal power plants to meet load variations is inefficient and unnecessarily increases the cost of generation. With the introduction of peaking and middle-load gas plants, tailored to the specific demand requirements, power networks will be more efficient. 24 Liquefied Natural Gas in China  4 Gas Supply Options Having established the demand for gas and the noneconomic benefits associated with its introduction, the study examined the cost of supply from alternative sources. The study evaluated three sources of gas for coastal China: * Domestic gas, principally in the East China Sea and onshore * Imported pipeline gas * LNG imports. Domestic Gas Reserves Domestic reserves of gas are significant, but they are relatively undeveloped, meeting only about 2 percent of the country's energy needs. CNPC expects that this figure will rise to 5 percent by early in the next century. Nonetheless, even with additional investment in needed production and transmission infrastructure, the growing demand for energy in the coastal provinces is unlikely to be met in significant measure by current domestic reserves. This is because the location of the major gas reserves, primarily in inland Sichuan Province, are limited, constraining their ability to meet large-scale demand in far-off coastal provinces. Offshore fields now produce only about 4 BCM. The coastal provinces could be served to some extent, however, by several gas finds in the East and South China seas. Unless these areas yield major finds, however, China will likely need to identify alternative gas supplies for gas to play a major role in satisfying energy demand and in meeting the projected growth in gas demand. According to the Chinese government, the nation's possible gas resources are large, with an estimated 51.7 trillion cubic meters (ICM). As of 1996, however, proven reserves were a total estimated volume of only 1.7 TCM. In 1995, China produced 17.9 BCM of gas, of which Sichuan Province was the largest domestic producer, at more than 7 BCM. As noted, most gas production is in the interior provinces, far from the coastal demand centers. Recent estimates by CNPC, included in the 9th Five-year Plan, project a doubling of annual gas production by 2005 to more than 30 BCM. Most the growth is based on recent discoveries in western China. Although gas supply from offshore fields in the East China Sea may increase as the -25  development of offshore oil fields progresses, the coastal region will likely need to rely on gas imports to secure a sufficient supply of low-cost gas to meet projected demand growth. Major existing and future gas production areas are presented in Table 4.1. Table 4.1 Major Chinese Gas Fields Field and location Description Yacheng field, China's largest offshore gas field, with proven reserves of 85 BCM, it will deliver South China Sea 2.9 BCM of gas annually via an 800-km pipeline to a 2,400 MW power plant in Hong Kong in 1999. Ping Hu field, By the end of 1998, it will supply a maximum 0.5 BCM/year to the Pudong area of East China Sea Shanghai. Total estimated recoverable reserves are about 8 to 10 BCM. Xihu Trough, Could have recoverable reserves of 70 BCM and total potential gas reserves of 400 East China Sea BCM. Estimated production would be 5 to 8 BCM/year. Ordos Basin, Production capacity is 2 BCM, although current production is less than half that. Shaanxi Province An 850-km gas pipeline runs from the Ordos Basin to Beijing, where less than 0.3 BCWyear of gas are being consumed. Estimated reserves are about 20 to 30 BCM. Sichuan Basin, The largest gas basin in China, producing about 7 BCM of gas annually, with Sichuan Province potential expansion to 10 BCM. Increase in production is limited by the gas transmission network, wvhich needs upgrading and expansion (CNPC and Enron have recently announced plans to build a pipeline to transport gas to Henan by 2000 and to Shanghai by 2002). Estimated reserves are 400 to 600 BCM. Tarim Basin, Only minor discoveries of gas have been made to date with no major production Westem China at present, although the area is geologically promising. Domestic Production In 1997, China produced 21.2 BCM of gas, of which Sichuan Province was the largest domestic producer, at more than 7.5 BCM. Most gas production is far from the coastal regions and potential high-demand centers with offshore fields producing only about 4 BCM. Nonassociated gas production has remained relatively stable for the past 15 years at about 7 BCM in 1994, whereas associated gas production has almost doubled in this period from 5.4 BCM to 9.9 BCM. Natural gas field production was 42 percent of total gas production in 1994. In the future, China's efforts onshore will focus on rehabilitating and upgrading the Sichuan fields; developing the Shaan-Gan- Ning field in central-western China and the l'arim basin in the far West; and building pipelines to serve major cities. Consumption Cedigaz estimates that gas consumption in China will rise from 17 BCM in 1995 to 91 BCM in 2010 and 174 BCM in 2020. At present, most gas is consumed near the source in Sichuan, the major gas- producing region. Sichuan is one of the least industrialized provinces in China, and most of the natural gas is consumed within the province because of the limnited gas transmission network and to meet the growing local demand, which includes power generation and industry. Beijing is targeted as a second major consumption area, behind Sichuan, with an 853-km gas pipeline recently completed from the Changqing gas field in Shaanxi to Beijing. The pipeline will deliver gas to 300,000 gas consumers, principally residential and commercial. It is estimated that 26 Liquefied Natural Gas in China  this gas will replace more than 2 million tons of coal annually, which could lower the air pollution index by 15 percent and the density of dust and TSP by 23 percent. By the year 2000, when combustion of coal within Shanghai's third ring road will be prohibited, gas supply is projected to reach 0.7 BCM/year. This goal is likely to be delayed for several years, however. In the Yangtze Delta, the Ping Hu field is projected to meet natural gas demand in the Pudong area of Shanghai up to a maximum of 0.5 BCM/year for residential and industrial use, although it will be insufficient to meet total potential demand in the Shanghai area. Hangzhou and Zhejiang will have access to a recent offshore gas find of 340 million CUM, with major consumers including the residential sector. Cost of Supply Domestic gas production and transport costs vary in China, and the difficulty of obtaining accurate field data makes firm estimates problematic. Typically, production and transport costs of natural gas are calculated from currently operating fields in China, although in many cases actual production and transport costs are unknown, and data instead reflect established government cost ranges. The Sichuan gas field, the largest in China, produces gas with government-admninistered wellhead prices (as of 1994) of $0.91 and $1.70/MMBtu, the lowest in China. The Changqing field, of the northwestern Ordos basin, will supply Beijing beginning in 1998 with gas at citygate price of $3.75/MMBtu, exclusive of taxes. The most expensive gas is from the Ping Hu field (end 1998) off the coast of Shanghai. Its delivered cost is $5/MMBtu. Another expensive source of supply is the Yancheng 13-1 field, which currently delivers gas to Hainan Island for power generation at about $4.00 to 4.45/MMBtu. Supply Infrastructure As of 1997, China had a total of 192 natural gas pipelines with a total length of more than 8,000 km and a capacity of 10 BCM annually. Most pipelines are intraregional, serving local demand, although several new interregional pipelines are planned Shaanxi to Beijing is the first, with total capacity of 2 BCM when it is in full operation. Even in Sichuan, the major gas-producing area of China, transmission and distribution pipeline infrastructure are minor and in need of serious upgrading. Imported Piped Gas Two potential regional sources of imported pipeline gas are available for China's coastal provinces. The first of these, Northeast Asia, has four major gas and oil supply sources: the Sakhalin Islands; the Sakha Republic; East Siberia's Irkutsk; and the Krasnoyarsk region. The second, Central Asia, has three major sources of gas: Kazakhstan, Turkmenistan, and Uzbekistan. Although hydrocarbon reserves have not yet been accurately assessed, preliminary data indicates total recoverable gas volumes of 2,400 to 4,300 BCM in both fields combined. In Northeast Asia, the Irkutsk region presents one of the most likely sources of pipeline gas and has a potentially major gas producer in the Kovyktinskoye field, 350 km north-northeast of Irkutsk. The possibility of gas development in Irkutsk includes a gas pipeline over 2,900 km from Irkutsk to China, via Mongolia, with a flow rate of about 30 BCM per year to Beijing. Initial estimates by BP indicate that it would be impractical to extend the pipeline beyond the Beijing metropolitan area, despite proposals to extend the pipeline to South Korea. Chapter 4: Gas Supply Options 27  In Central Asia, Kazakhstan, Turkmenistan, and Uzbekistan have significant quantities of gas for export. A major challenge for these landlocked countries is to secure access to international markets. At present, they must rely almost entirely on Russian pipelines to export gas to Western Europe, and as a result they have decided to diversify to markets in China as a means of securing a degree of political and economic independence. Turkmenistan, with the largest gas reserves in the region (nearly 3,000 BCM, is the most likely gas exporter to China. Turkmenistan's incentives to seek alternative export markets such as China has recently increased, as Russia's state-owned gas monopoly, Gazprom, has recently stopped Turkmenistan's exports to European gas markets in an effort to reduce competition. The most feasible pipeline project is difficult to determine at present. Russian gas pipelines from Irkutsk, Sakhalin, and the Sakha Republic are much closer and more accessible to the Asia Pacific markets and China, and they are likely to be less expensive and to make gas available in more marketable quantities than a pipeline from more distant Turkmenistan. The latter would require delivery of significant gas volumes, 20 to 30 BCM/year and would cost upward of $10 to $20 billion to build. Construction of pipelines from Northeast Asian Russia would likely delay or preempt a pipeline from Central Asia, as Japanese financing would likely play a role for either. LNG Supply Sources Worldwide LNG demand is expected to grow significantly over the next two decades. In 1995, the nominal liquefaction capacity of 20 plants am.ounted to 103 BCMWyear. This is expected to grow by an additional 84 to 126 BCM/year by 2010. At present, almost 20 major projects are currently under discussion around the world. Geographically, China's coastal provinces have access to many potential sources of supply, including expansion of existing facilities or greenfield development (see Table 4.2 and Figure 3.6). Existing producers couLd provide a potential volume of 36 BCM/year and are located in Asia and Qatar. Greenfield projects include Asian producers, Qatar, and Alaska North Slope with a combined potential volume of 102 BCM/year. Speculative projects such as Natuna, Alaska, and Yemen are not likely to be potential suppliers to China in the first round of projects. Table 4.2 Potential Sources of LNG Supply Source-expansions Volume (BCM/year) Source-greenfield Volume (BCM/year) Australia N.W. Shelf 10 Alaska North Slope 17 Indonesia (Bontang) 9 Australia-Bonaparte 3 Malaysia Tiga 10 -Gorgon 10 Qatar (Ras Laffan) 7 -Undan-Bayu 3 Indonesia-Natuna 21 -Irian Jaya 10 PNG 6 Qatar (Enron) 7 Sakhalin 15 Vietnam 5 Yemen 5 Total expansions 36 Total greenfield 102 Source: BP (1997) and others. 28 Liquefied Natural Gas in China  Despite the recent emergence of spot sales, the short-term availability of LNG is limited. Most spot sales and other short-term contracts are piggybacking on existing contracts. Of currently operating projects, only Oman has significant uncontracted volumes of about 2.5 BCM/year. Several other projects have spare capacity attributable to the recent Asian economic slowdown, but that capacity will probably have been contracted by the time a China project would start up, even by 2002-3. Forecast LNG Demand The principal LNG markets in Asia are Japan, Korea, and Taiwan, countries that lack indigenous energy resources and are ready to pay a high premium for diversity in energy supply. Their economies thus have sustained high market prices for suppliers. New market entrants could include India, Thailand, and China. As presented in Table 4.3, LNG demand is forecast to rise considerably by 2010. Japan will maintain its dominance of the market, and Korea, with demand doubling between 1996 and 2005, will be an active player. Demand in Taiwan is expected to rise fourfold by 2010. India is expected to purchase about 5 BCM in 2005, and Thailand may purchase shortly, although the country has recently delayed its first LNG project because of the economic crisis in Asia. Table 4.3 Forecast LNG Demand in Asia Pacific (BCM) 2000 2005 2010 Countr.y 1996 Low High Low High Low High Japan 65 76 78 80 84 84 98 Korea 13.3 19 24.5 22 32 25 39 Taiwan 3.5 8.4 11 13 17 17 20 India - - - 3.5 7 3.5 7 Thailand - - - 2.8 8.4 2.8 8.4 China - - - 0 5.6 0 5.6 Total 81.8 103.4 113.5 121.3 154 132.3 178 Source: Cedigaz (1996). - = not available. Comparing Natural Gas Options fbr the Yangtze Delta Several domestic gas options are available for the Yangtze Delta. Initial results indicate that significant reserves may be available in the East China Sea, although development of these reserves would require significant investment, and even with such development, supply may prove insufficient to meet potential gas demand. CNPC is also proposing to build a domestic gas pipeline from Sichuan, but this proposal could take a long time to develop, given the potential gas demand in Sichuan and neighboring provinces and the potential high cost of transport. Further assessment is necessary for both options. International pipeline gas and LNG are possible supply options. Each requires completion of an integrated business chain from its upstream (e.g., gas production) through the downstream (e.g., gas utilization) components; a long-term commitment for gas supply; and purchase agreements. The investment costs are large, generally more than US$5 billion for a grassroots project. Whereas contracts for LNG are typically based on bilateral agreements, delivery of piped gas is may be more complex, because it often involves agreements with the pipeline transit countries as well as between the countries of seller and purchaser. Chapter 4: Gas Supply Options 29  International Piped Gas versus LNG LNG has several advantages over international piped gas supply sources that makes it more economic to meet small gas demands in the early years of the introduction of gas in the study area, including the following: * Faster mobilization. LNG does not necessarily exclude other options, but it is more feasible in the short and medium terms. * The LNG option can be built on a mocdular basis, providing much more flexibility than the pipeline option; LNG's projects' size and project cost can be significantly smaller than the pipeline option. * The LNG option is viewed as less risky politically because no transit countries are involved, and as having less risky commercially because the gas output can be absorbed quickly. * Because of its smaller project cost, and its lower risk, LNG option is more easily financed than the pipeline option. * Large, underexploited gas supplies and the proliferation of LNG projects under development have lowered prices, leading to multiple supply options. Piped gas to East China might be competitive with large demand (above 15 BCM). Preliminary studies indicate the cost of piped gas ranging from $3.0 to 7.7/MMBtu, depending on volume. The lowest-cost pipeline option would likely be gas from Irkutsk, at an estimated delivery cost of about $3/MMBtu for 20 BCM/year-a level of demand that is not expected to be reached before 2015. With an estimated initial demand for gas of atbout 5 BCM/year, the actual supply costs to coastal China for piped gas would range from $5 to 7.7/MMBtu CIF, significantly higher than for LNG. As noted, LNG is based on a bilateral agreement, whereas piped gas options are often multilateral, involving seller, purchaser, and transit countries. Thus, cross-border pipeline projects are often more time-consuming and complex to complete agreements for the development and sale of gas and are more difficult to finance. The need for high initial demand and the potential complexities in the transit arrangements make international piped gas nonviable in the medium term. LNG Prices and Competitiveness As of August 1998, estimated delivered cost of LNG to coastal China would range from $3.25 to 3.75/MMBtu CIF. (LNG prices on the world market have been falling, as evidenced by recent price negotiations for the LNG projects in India, where the final price of LNG is near $3.00/MMbtu CIF.) Additional costs of regasification and terminztling would likely add $0.4 to 0.8/MMBtu. Estimated citygate or power plant prices for LNG woulcl likely range from $3.75 to $4.50/MMBtu. As Figure 4.1 shows, the current potential supply price for LNG would make it competitive based on netback analysis of the value of gas in the power and rionpower sectors. 30 Liquefied Natural Gas in China  Figure 4.1 LNG Supply Price Compared with Netback Value of Gas _...~~~~ a fr L r a r <B * sIlleX.ilpls.LNG sw* p 3.00 4.00 5.00 IQOO LEuW LNG may be available at the lower range of prices noted above depending on market conditions at the time of contract negotiations. At present, Japan dominates the Asian LNG market, contracting more than 70 percent of LNG shipments in Asia. As a result, Japanese contracts set the market price, which has been quite high partly because of Japan's need to ensure security of supply. With greater price sensitivity this is likely to change in the future, particularly with several existing contracts due for renewal in the next few years. Moreover, increased competitiveness in the LNG supply market appears to be driving down prices, with recent price quotes (of LNG projects in India) near $3/MMBtu CIF. Integrated Gas Development Strategy An integrated gas development strategy that includes utilization of domestic gas resources, long- range pipelines, and importation of LNG would best meet the gas demand profile in East China. A concurrent development plan would consist of further exploration and development of offshore gas in the East China Sea to confirm reserve estimates and the initiation of an LNG project. LNG can perform a highly useful role in initial opening of the market and creation of the growing demand that can later be served by large-capacity pipelines. LNG can continue to meet small incremental demands, and large pipelines can be brought on stream when significant expansion of the market occurs. Development of a gas transmission and distribution infrastructure would be needed to serve both supply sources and provide gas to power and nonpower applications. Gas production from the East China Sea should be able to contribute from 3.7 to 5.5 BCM/year. Although this is a significant supply source, it will be insufficient to meet forecast gas demand, unless new finds are discovered, and that underlines the need for alternative and supplementary gas supply sources to meet demand. Sichuan gas could contribute a significant quantity of gas, but questions remain regarding the economic feasibility of such a proposal, given the distance to market and the high production cost of gas. Independent review and assessment of the proposed CNPC Sichuan-Shanghai pipeline is recommended. Thus, LNG can perform a crucial role in the early stages of market development. In the future, as the gas market is established and demand builds, additional LNG and domestic and international pipeline projects may be necessary. These factors reinforce the need for a complementary gas development strategy. Chapter 4: Gas Supply Options 31   5 Key Issues for LNG Development A number of possible sites for the first LNG project are being discussed by the various Chinese parties, and at this time, initial support has been given to the proposed Guangdong project. This approval does not exclude an additional site, however, and feasibility studies are under way to select the most appropriate site in the Yangtze Delta. The institutional and financial issues discussed refer to any site selected and are not limited to a particular site. For a typical scenario of gas demand in a nascent market such as the Yangtze Delta (see chapter 4, Base Case Assumptions, in 'China: Strategic Options for Natural Gas, Main Report: Phase 1"), the buildup of annual demand could be as follows: * 2003 1.2 BCM * 2005 3.2 BCM * 2007 6.3BCM * 2010 16.2 BCM. Based on these assumptions, a sample project was proposed and a financial analysis carried out. For this scenario, it was assumed that a minimum-scale regasification plant and storage terrninal sufficient to meet demand in 2005 (i.e., annual capacity of 3 MMT or 4.2 BCM) would be constructed. It was assumed that 3 X 1,000 MW CCGT intermediate-load plants would be built, and municipal gas distribution networks would be upgraded or built in Shanghai, Hangzhou, and Ningbo. Accompanying investments would be made in gas transmission pipelines, power generation plants, and gas distribution systems. It is estimated that net annual available gas (after regasification) would be about 4.1 BCM. Take-or-pay contracts would be signed with major gas purchasers for minimum purchase requirements (based on the analysis in chapter 4 of the Phase 1 report), as follows: * CCGT power generation 2.7 BCM/year * Municipal gas in Shanghai and Zhejiang 1.3 BCM/year * Total 4.0 BCM/year. 33  Development of LNG Project An LNG project is a major long-term infrastructure investment comprising all the components of an LNG business chain. Such a chain starts with the gas producers, continues with liquefaction and transport of gas as LNG, and finishes at the end users. The business chain is described more fully in the accompanying report, 'LNG Guidelines," but is summarized below. In principle, three components are involved: upstream (production), transport, and downstream (receiving terminal and pipeline). Figure 5.1 profiles the key project components. Figure 5.1 Profile of an LNG Project Gas mme Gas producton & IKquacdon LNG taflws demand The functions of the various components of the LNG project are detailed below: * LNG production. This occurs at a liquefaction plant, which receives gas via a pipeline from the gas fields. Any party in the investment chain can carry out investment in liquefaction facilities, but the gas producers usually are closely associated with the activity. The LNG thus produced may be contracted to ai single consumer in a dedicated business chain, or it may serve a source of supply for a number of consumers. * LNG tanker. LNG tanker transportation is another critical element of the project investment. This could cost as much as $1/MiMBtu for a greenfield project requiring construction of new tankers. The current standard design capacity of LNG tankers is 130,000 to 140,000 CM, but larger tankers are now being built. These ships are normnally owned and operated by either the seller or the buyer. Occasionally, however, a third-party shipper operates LNG transportation. LNG receiving terminal. A LNG receiving terminal consists of a harbor with facilties for off- loading tankers, LNG storage tanks, and a regasification plant. These facilities are not technicalry sophisticated compared with the infrastructure for lquefaction and transportation, but the acquisition of land for the receiving terminal is critical for the buyer because the terminal must be constructed close to a regasification plant. The buyer usuary owns and operates the facilties, but a third party can do so, charging users a terminal throughput fee. LNG sellers may do tiis when they wish to spread their risks along the gas chain by holding an equity position in the receiving terminal. Pipeline. The receiving termianal is usualy sited to minimize the distance to the demand centers, power stations, or city gate. If the distance is short, then the cost wfll be a relatively 34 Liquefied Natural Gas in China  small component of total project cost. Nonetheless, the planning of the pipeline system should take account of future expansion both of demand locations and new sources of gas supply. These niay require creating some form of open access to the pipeline. LNG users. Most LNG buyers are either power generation plants or large gas distribution companies. Power plants tend to dominate in the startup of an LNG project because they can rapidly create the volume of demand to meet the minimum economic scale of an LNG project. Later, gas distribution to industrial, commercial, and residential consumers will become more important. Overview of Downstream LNG Finance Until 1997, opportunities for international energy investments grew rapidly, outpacing available risk capital. With the recent collapse in many emerging markets, investment opportunities have been seriously curtailed, leading to greater competition for capital and resources. Where in the recent past developers were able to demand higher returns because of a surplus of opportunities, they now face diminished opportunities and increased aversity to risk. As a result, securing the financing for an integrated LNG and power project in China will present greater financing hurdles and will likely require more negotiation over the terms and greater security for lenders. LNG financing is heavily dependent on each component of the supplier chain, and, as such, requires stringent contracts to ensure performance by each party and complete financial coverage and risk management. Each component of the chain must be economically and financially viable on its own merits. Historically, LNG finance of the upstream components (including development, liquefaction, and transport) has been driven by long-term off-take contracts with investment-grade off-takers and countries. Expansion of LNG sales into emerging markets such as India and China presents attractive growth opportunities, albeit with a higher risk profile than past LNG financing. In China, two components of downstream LNG finance must be taken into consideration: * Capital expenditure for construction of infrastructure and related investments * Long-term gas off-take contract. Total expected investment for all the downstream components (regasification terminal, pipeline, power plants, and municipal gas distribution) is about US$3 billion over about three years before the onset of the first gas delivery. Although this is a substantial sum, the long-term gas off-take contract for the purchase of gas over the typical 20-year period will likely amount to more than $10 billion (about $500 million per year). Capital investment can be secured and guaranteed based in part on the assets and cash flow of the investment. Guaranteeing the long-term gas off-take contract is more complicated and will rely heavily on a number of factors, particularly, the creditworthiness of the gas purchaser-that is, the respective financial strength of buying entity or entities. Typically a detailed credit review will be needed. In the past, government guarantees have been used to provide credit enhancement. Factors Influencing Economics A number of factors in the design and type of LNG project can affect the overall cost. These should be considered early on the project design. Chapter 5: Key Issues for LNG Development 35  * Variability of demand. LNG projects are capital intensive, and therefore the unit cost of LNG supply is sensitive to the overall load factor on the capital. Investments throughout the business chain must be sized to meet the peak demand. If average demand is significantly lower than peak demand, the capital will have a low load factor. Baseloaded power stations provide the highest load factor, whereas residential gas demand may provide the lowest- especially where heating is highly seasonal (gas is not used for heating in the Yangtze Delta). As documented in Phase 1 report, the least-cost plan for the power sector indicates that the most economic role for gas power stations in China is to run in mid-merit range (40 to 55 percent capacity) for a number of reasons: - Other plants may be capable of supplying the base load. These include large coal-fired power stations and nuclear plants. - A significant seasonal hydro component is present. This means that some or all of the thermal power stations will experience seasonal demand. This seasonality of demand may increase in China when the Three Gorges project is completed. However, constraints from the LNG supply side-namely, the need to sign long-term take- or-pay contracts with minimum fluctuation of LNG volume deliveries-will dictate that gas- fired power plants operate at a higher capacity factor (e.g., 55 to 70 percent). A high load factor throughout the business chain will ensure the lowest cost for gas delivered to the user but may be achieved at a higher system-level cost as lower cost power plants may be replaced with gas. The lower the load factor, the higher the delivered gas price will need to be. The price to different consumer categories will therefore usually be set to reflect their individual load factors. * Distance from the gas-producing country. This obviously affects the direct cost of transportation. In addition, the capital costs may increase because of the need to increase the volume of storage at the receiving terminal and to increase the number of LNG tankers. These components must be sized to achieve the desired frequency of LNG delivery (e.g., twice per month) and to cope with the additional variability of delivery time caused by distance-related risks. * Type of LNG project. A greenfield project will usually not be built unless sales contracts for a mninimum of two LNG trains can be secured. A new project will need to carry out all the infrastructure investment in harbor facilities. An expansion project, where an additional LNG train is added to an existing project, may therefore be considerably less expensive, and faster but may be limited in the size of the further expansion. * Port facilities. Adequate facilities must be available that fulfill internationally accepted standard requirements for the construction and operation of an LNG receiving terminal. This should include not only site selection and preparation but also the requisite shipping requirements. Failure to select the most favorable site on a purely technical and least-cost basis may increase operational and finamcial risk of the regasification terminal. * Tankers. Traditional LNG trade was based on new, purpose-built tankers. One way to lower the initial investment is to use second-hand tankers, a number of which are available for charter. These will be cheaper in capital cost but more expensive to operate and will have a shorter lifetime. If this lifetime does not match that of the other investments, it may increase the riskiness of the project. This may be particularly true if the LNG buyer relies 36 Liquefied Natural Gas in China  on contracting for gas transport in the spot market rather than on long-term charter. A further way to seek to lower initial capital costs is to use smaller tankers, but this would increase the unit cost. As can be seen, a number of options are available for lowering the initial capital cost. However, lower capital costs may be partially or fully offset by higher operating costs, and the risk of the project overall may be increased (this has a secondary effect of increasing the costs by raising the cost of financing). Gas Pricing Issues The underlying economic factors determine the average level of initial cost but the mechanism for adjusting prices as costs change is important for establishing a balance between producer and consumer interests. This has an impact on the viability of LNG as a fuel option and the role government should play. The LNG (gas) imnport price will drive the final price of power and gas to consumers, as fuel cost will be passed through to the final consumer. As a result, project developers will be concerned with their ability to pass any price changes through the energy chain to the gas or electricity buyer (through the security and enforceability of gas sales contracts). Conversely, the potential price variability of LNG could adversely affect consumers through large price swings. Consurners (of city gas companies) are most at risk, as LNG will likely be the only source of gas. Power system buyers will be able to average down the cost of power produced from gas through the power system. Government will play a major role in pricing, particularly in balancing the impact of dramatic price variations on the consumer. Yet, gas prices will need to reflect full economic costs, thereby limiting the scope of government influence on prices. Creating an Appropriate Institutional Framework The institutional framework for the development of LNG needs to take account of a number of different components. These include the following: Ownership structure. This concerns which organizations will own which parts of the LNG project. It is the key starting point in determining who is carrying the main project risks, who will be the buyer of LNG, what will be its creditworthiness, who the customers will be, and whether competition can emerge in the future. * Contracts and risk allocation. Contracts need to be established between the organizations making up the business chain as the basis for determining the trading arrangements and the allocation of risk. * Trading arrangements. These indicate how the market will operate. * Legal and regulatory framework Involved are the framework governing ownership and operation of the gas business chain and the regulation of monopoly aspects, including prices, access to the networks, and customer standards. Chapter 5: Key Issues for LNG Development 37  Infrastructure Development Objectives Objectives for infrastructure development may often conflict, and this is also the case for LNG development. Two examples will serve to illustrate the point. Minimizing the cost of gas supply could be achieved by the government carrying out the total investment itself or by providing some form of sovereign guarantees for private investors. However, this would conflict with the plan to minimize the financial burden of the development of gas on the State budget. A second example is the conflict between the desire to introduce gas as quickly and easily as possible in the short term, with the desire for the long-term development of gas as a fuel source for a wide range of activities. In the first case, priority would be given to gas for the a small number of power stations, in the second case, priority would also need to be given to creating incentives for developing gas distribution systems. These examples illustrate the importance of a clearly stated set of objectives for assessing the institutional options. The Chinese government has not given an unequivocal or definitive policy statement for its objectives in developing LNG. From our discussions with SP and other state government agencies, however, we understand that the government's objectives may include the following: * Facilitate development of gas as a strategic fuel supply option. This will improve security of supply and create interfuel competition, particularly for fuel options in power generation. v Minimize the cost of gas supply. This should include the cost of imports and the cost of financing. This, in turn, requires minimizing the project risk. * Lower the financing cost through private sector investment. This will also assist in minimizing the financial burden on the state budget. D Introduce competition into the energy markets. * Promote long-term development of gas as a fuel supply for all sectors. * Introduce clean fuels to support improved environmental quality and living standards. * Ease implementation to enhance chances of success and reduce the risk of failure. * Support consistent general social and political aims. These include pricing of fuels, social equity, development of competitive market structures, and strategic control of fuel supply. In our discussions, it was apparent that debate continues within Chinese policy circles on the interpretation and priority of these objectives. It is always difficult to determine unambiguously clear objectives, especially when inherent conflicts exist between them and trade-offs are necessary. Therefore, the government should make its objectives and priorities clear for LNG development in the Yangtze Delta. Two of these trade-offs are discussed in greater detail in the following sections. Balancing Short- and Long-term Development Goals The options for encouraging the development of the gas market can be differentiated according to the priority given to the short- and long-term development aspects and the characteristic time scales of development of different consumer mnarkets. The initial development of the LNG requires the creation of a minimum-scale market in as short a time as possible. This is necessary to reduce the cost of carrying the finance of the infrastructure investment in the business chain. 38 Liquefied Natural Gas in China  The simplest way to create a large initial demand that quickly justifies a minimum-scale project for LNG is through power generation, which can encourage a rapid buildup of demand either by converting some existing capacity or by building new capacity. In contrast, buildup of demand in the nonpower sectors (industrial, commercial, and residential) will be slower because of the time needed to construct a distribution system and to convert and connect a large number of small new customers. Still, the long-term potential demand of the nonpower sector may be even higher than that of the power sector, and an LNG business chain that relies solely on the power sector could face difficulties in creating incentives for the development of nonpower demand later. Thus, the merits of both power and nonpower demand should be considered. Balancing Strategic and Social Aims Strategic aims for the development of gas include the improvement of overall security of fuel supply and the promotion of market liberalization through the growth of private sector financing and interfuel competition. The introduction of gas as a new fuel, particularly if financed through private investment, will require that the gas price is sufficiently high to create incentives by allowing investors to achieve an acceptable rate of return in relation to the risk. If the gas price were not regulated, investors would themselves choose a gas price that balanced their own aims of creating a sufficient short-term profit while promoting the longer-term development of their market. The economic value (i.e., economic or monopoly "rent') of gas would pass entirely to the investors. If gas-to-gas competition (i.e., the presence of competing gas suppliers) were possible, the gas price would be driven down toward its cost of supply. Without such competition, regulation of gas prices is usually required to produce a similar effect. Social aims for the introduction of gas might include the desire to provide the choice of fuel to priority economic groups or to subsidize its use in some sectors for social or environmental purposes. These could include economic development priorities, such as particular industrial sectors or regions, and social priorities, such as support for low-income households through price subsidies and potentially distorted markets for investors. Social aims will play an important role, but a major conflict could result if the government has to choose between meeting social objectives and achieving financial viability in the sector by passing through the higher costs of imported fuel to the final electricity and gas consumer. If the government does not have an ability to influence gas prices (except via the initial pricing mechanism), international markets will be the final determinant of price. Rapid or dramatic price increases caused by exogenous events could test the ability of the government to maintain financial stability in the sector) by passing through the burden of price increases on the final consumer. Risk Analysis The analysis of risk is the assessment of the possibility that the project may not achieve its expected rate of profit or may even suffer a significant or total loss. The riskiness of a project depends on the extent to which potential risks can be mitigated through appropriate managerial or contractual measures. The analysis of risk is important for determining the overall level of risk and how the proposed ownership and contract structure allocates the risks between the parties. Investors may view the development of the first LNG project in China as highly risky for several reasons: Chapter 5: Key Issues for LNG Development 39  * It is a new fuel option for East China and has little existing market or infrastructure. * A general 'country risk' is associated with investing in China, comprising a number of factors: - Political risk (e.g., general approach to private and foreign investment) - Security over the ownership of assets - The remittability of profits and foreign exchange risk - The tax regime. * A project or sector risk, concerned with the ability to earn a satisfactory profit, is involved. That is, how will demand develop, what prices will be charged, and what will be the competition? When the state carries out a publicly funded infrastructure project, risk is quite low, because the government can be assumed to provide whatever support is necessary for the project to succeed. A project financed privately (in whole or in part) is entirely different. The investor's capital is at risk for all the above reasons and, the higher the risk, the higher the return the investor will require before committing equity to the project. Behind the investors are banks and other financing institutions providing loan finance. In a centrally planned economy, a project's feasibility is essentially its acceptability to the government. In a market-oriented economy, the focus is to create an economically viable project in which the risk profile is acceptable to the financing institutions-that is, it is a 'bankable' project. The complexity of the business chain for an LNG project highlights the fact that the design of the sector structure is itself a significant factor in determining the overal risk and who bears it. Risks build up along the chain. From the gas producer to the consumer, risk inheres in the level and buildup of costs. In the opposite direction, risk relates to the revenues of the project and whether they will be received and passed on. In general, a long and inflexible business chain implies a long .risk chain' and increasing difficulties in managing or mitigating those risks. Contracts between the parties are the main instrument for managing and allocating the risk between them. The general principle of risk management of a project is that the risk should be allocated to the party best able to control it. The reason for this is that controlling and minimizing each individual risk also minimizes the project's total risk, and this reduces its overall financing cost. Not all risks are controllable, however. Controllable risks, such as technical operation of the plant and colection of revenues, should be allocated within the risk chain to the appropriate party. Uncontrollable risks include the weather, exchange rates, international fuel prices, and government policy. These are frequently passed through to the final consumer. Role of Government Agencies As the evolving gas sector introduces a number of new, private sector investors, so too will the role of government need to change, and government departments will need to fulfill a number of new roles. The general principle of efficient management of the gas sector is that a clear distinction should be made between who carries out the following broad functions: * Policy. Setting out a general framework to implement the broad objectives of government. 40 LiquefiedNatural Gas in China  * Ownership. Management of the state-owned assets should be carried out according to commercial interests. * Regulation. Independent regulation safeguards the long-term interests of investors and consumers and should not be unduly influenced by the state's interests as an owner. Assigning these functions to separate entities in a manner to avoid conflicts can assist the development of the sector in the following ways: * Clear definition of objectives * Transparency in decisionmaking * Assignment of responsibility according to competence. Financing Issues and Requirements for Proposed Project Several financing issues will affect the ability of securing necessary financing for a LNG project and related infrastructure. These include the ROR the investors will be able to obtain, the allocation and mitigation of financial risks, the price of gas, the use of security documents, and the creditworthiness of off-takers. Financing requirements for a proposed LNG project and related infrastructure were estimated based on the capital cost of construction, including associated financing and closing costs for the requisite loans. Equity and debt requirements are broken down according to source-local or foreign-and project component. It was assumed that Chinese entities would maintain majority control, holding at least 51 percent equity in the regasification terminal and power plants and 100 percent ownership in the pipeline and municipal gas company. It is not entirely clear whether any foreign participation will be allowed in these sectors, however. Estimated total project cost (example only) for all components is estimated at about US$3.6 billion, of which about $1.7 billion was for CCGT power plants; $1.1 billion for municipal gas distribution system; and $0.8 billion for regasification termninal, storage system, and transmission pipelines. The total estimated equity requirement for Chinese entities, based on these ownership percentages, was $660 million, the largest portion of which, $340 million, was for the municipal gas system. Some $220 million was for the CCGT power plants. The total debt requirement for Chinese entities is $1.75 billion, and again the largest amount is required for the municipal gas system-about $785 million. The capacity of Chinese entities to raise this quantity of equity and debt will be a major concern of financiers. The most challenging will be for the municipal gas and pipeline components, which will likely have the lowest rate of return. This is evidenced by the situation of the current municipal gas company of Shanghai, which receives a subsidy and is of questionable profitability partly because of the aging distribution system and related losses. Participation of major state companies in the other components should be sufficient to meet the basic lending criteria. Unresolved issues that will affect both the financial analysis and financing of a LNG project are worthy of note. In particular, the some uncertainties associated with these issues need to be addressed, including the following: * The rate of return ('ROR) required by investors. This will affect the ability to finance and structure the project successfully. Chapter 5: Key Issues for LNG Development 41  * Risk allocation and mitigation. Both are necessary to ensure that risk is fairly allocated among the various parties. * Use of security documents and guarantees. In recent project financing deals, political risk, an issue for projects in China, has been covered by export credit agencies (ECAs) or commercial banks. Given the current climate, this is likely to continue. Creditworthiness of off-takers. Gas and power off-takers will need to be of investment grade. 42 Liquefied Natural Gas in China  6 Ownership Structure and Trading Arrangements One of the reasons for designing an appropriate institutional framework is to minimize the overall risks of developing LNG. The complexity of the business chain for an LNG project highlights the fact that the design of the ownership structure of the sector is itself a significant factor in determining the overall risk and who bears it. That is, a complex and long business chain implies a long 'risk chain' and increasing difficulties in managing or mitigating those risks. Contracts between the parties are the main instrument for managing and allocating the risks between them, and the regulatory framework is important in providing stability and confidence for the investors. The main issues for the institutional framework for LNG, discussed below, are thus the ownership structure, contracts, trading arrangements (market structure), and the legal and regulatory framework (the legal and regulatory aspects are discussed separately, in chapter 7). Ownership Structure Today's LNG market is marked by a small surplus of existing and committed LNG production capacity. It is possible to secure a long-term LNG contract without an equity involvement in production. It therefore may make the most sense for China to purchase its LNG on a CIF basis (i.e., carriage, insurance, and freight costs to the receiving terminal), and for the rest of this report we assume that this is the case. Key Elements The development of gas-fired CCGT power stations is well understood and can be financed readily as an integral component of an LNG project or as separate independent power projects (IPPs). Four principal investment components must be considered in determining the structure of ownership: the receiving terminal, pipeline, power stations, and gas distribution. Similarly, design of the structure requires determining who will play each of three key roles: LNG buyer, terminal owner and operator, and pipeline owner. In relation to the potential objectives of governments, the main criteria for preferring one ownership structure to another will be as follows: 43  * How well does each option achieve acceptable risks and provide effective guarantees for the LNG purchase contract? * How easily can the first project be implemented? * How well does the structure create incentives for longer-term development of the gas market, both in the power and nonpowver sectors? Control and Ownership It is important to emphasize that control or guidance in the development of a modem gas sector does not necessarily require direct ownership by the government of every project component within the sector. Government may achieve its goals in the development of the gas sector without exercising direct ownership of the various companies but instead by focusing on establishing sound policy and regulation. The government can achieve its aims in such a privately owned, regulated sector through a number of means, including the following: * Issuing licenses * Regulating prices * Paying targeted and transparent subsidies to clearly identified groups or sectors * Approving contracts (e.g., for purchase and sale of gas) i Approving takeover, merger, or transfer of ownership or entitlements. Impact of Power Sector Reform and Single Buyer Model A major issue to consider for all models is the implication of the future reform of the power sector. The likely model for the restructuring is a single buyer (SB) model, in which all of the generation is separated from direct management and corporate control of the SB. Some or most of the generating capacity could be privatized, and thle model could readily incorporate IPPs. However, among the power sector reform options under consideration, it is proposed to examine approaches to introducing competitive bidding (for dispatch) between the generating companies. One mechanism proposed is to give the generating companies contracts for differences (CfDs) to cover about 80 percent of their expected generation. They would therefore be guaranteed revenues (and dispatch) for most of their capacity, but a small share would be uncontracted and could compete against other generators for marginal sales to the SB. Their bids would set the marginal or clearing price for balancing supply and demand. A number of implications should be noted with regard to introducing LNG into an SB market with CfDs and bidding for dispatch. These are considered below, although the implications are highly tentative, as the shape and details of the new -markets are not yet known: * Unless the new gas IPPs have long-term power off-take contracts, they would not be in a position to sign long-term gas off-take contracts (although the new gas-fired power plants could operate under many ownership options, we call them IPPs throughout this discussion for simplicity). In this case, the LNG buyer would have no guarantee for the sales and, probably, no possibility to sign an LNG purchase contract. 44 Liquefied Natural Gas in China  * The three power companies would no longer be the power generators. They would become the SBs and would therefore probably not be allowed to enter into the joint venture project company for LNG. The IPP companies could play the role of power generator, but they would be greenfield companies and considerably less creditworthy than the former power companies. * Because the IPPs would have take-or-pay gas contracts with the joint venture company, they would frequently bid at or close to zero into the SB market up to the limit of their take- or-pay obligations, and they would therefore seldom enter into the competition to set the marginal price. * Instead of the IPPs, the SB could guarantee the LNG purchase. The IPPs would then have energy-tolling contracts rather than power purchase contracts with the SB and would have to lie outside the envisaged SB competitive power market. With the development toward a competitive power market, it may not be possible to create a power company gas buyer that is financially strong enough to guarantee the LNG purchase, unless it could look elsewhere (e.g., to the SB) for such guarantees. Furthermore, the inflexibility of such an arrangement would hinder the development of a competitive power market. The reform of the power market may therefore increase the risks associated with the LNG purchase contract by increasing the risk to the seller of the LNG. Alternative Models of Ownership Structure To examine and provide provisional answers to the key issues of ownership structure, let us consider four alternative models and their implications. Model 1: Two Variants of the Integrated Company Model 1 is probably the simplest structure. It gives the power companies the dominant role, reflecting their likely major gas demand in the early stages, but it creates poor incentives for long- term nonpower market development. Figure 6.1 shows the integrated single-buyer scheme, in which the single, integrated project company carries out the LNG terminal, pipeline, and power stations. This company would also be the gas buyer and have exclusivity for the LNG purchase and wholesale gas sales. The project company could be owned by a single party or by a joint venture comprising the power sector companies and other interests, such as the gas distribution companies and other state bodies. The LNG off-take from the LNG supplier and the gas off-take from the terminal would both be backed by the power purchase agreement (PPA) for the power off-take from the power station to the principal power company buyers. An additional gas off-take contract could be signed with nonpower sector customers, such as municipal gas companies. Chapter 6: Ownership Structure and Trading 45  Figure 6.1 Model 1: Integrated Company-Single Buyer Elecitdty customr Nanpowen- omawes Gas customers Figure 6.2 shows a variant of model 1 that introduces a significant change-multiple buyers instead of a single buyer. LNG purchase and gas sales are now no longer exclusive. Instead, instead each major consumer is allowed to arrange its own LNG purchase and to deliver its gas through its own pipelines. The companies would coordinate puirchase of LNG on common contract terms, but each buyer would guarantee its own volumes. The LNG terminal would be owned and operated by a joint venture company with representation from each major buyer. The LNG off-take from the LNG supplier would be backed by the power purchase agreement (PPA) for the power off-take from the power station to the power companies and by the gas off-take for the municipal gas companies for their own volumes. Additional gas sales contracts could be signed. For example, a power sector buyer could sell on some gas to a gas distributor or large user. Figure 6.2 Model 1 a: Integrated Company-Multiple Buyers ERectriciry customers (power cnmpanies) Gas disu Gas austomems Gas anstamers Model 2: The Gas Development Company Figure 6.3 shows the structure by which a gas development company (GDC) is formed to own and operate the LNG termiNnal and pipeline. This company would also be the gas buyer and would therefore operate like a merchant gas pipeline company. The LNG off-take from the supplier would be the responsibility of the GDC, wich would have to be sufficiently creditworthy to guarantee the LNG purchase. The GDC would market gas to all consumers and could promote the development of gas in conjunction with government policy for the sector. 46 Liquefied Natural Gas in China  Figure 6.3 Model 2: Gas Development Company Gas development Ektricky oustomers company (GDC) (x 5") Ga dNonpower:on Gas customers Model 3: Separation of Gas Buyer from Terminal and Pipeline Owner/Operator Figure 6.4, the structure of Model 3, shows how the functions of LNG buyer and of owner / operator of the terminal and pipeline may be separated. The GDC is the LNG buyer and has operating agreements with the pipeline and terminal. A separate project company carries out the terminal and pipeline investment and operation. The pipeline has open access to allow future suppliers to compete with the GDC. Figure 6.4 Model 3: Separate Gas Buyer Gas development company (GDC) Elearicdy cIOnwI (Po-e' companies) Staton Nanpower Gas aistxmer Model 4: Power Sector as LNG Buyer Figure 6.5 shows Model 4, in which the LNG buyer is the power sector-either the IPPs or the power companies. This creates a direct back-to-back contract link between the gas purchase contract and the power off-take contract. The role of the GDC is to develop and operate the infrastructure for LNG importing and gas transmission. The power companies have operating agreements with the GDC (which owns or has operating agreements with the terminal and pipeline JV companies). The power companies then sell gas on to other consumers. Chapter 6: Ownership Structure and Trading 47  Figure 6.5 Model 4: Power Sector as Gas Buyer 13etildty custome (powe compnpi-) LNG= Gas development GMs customer company (GDC) Assessment of Alternative Models As Table 6.1 indicates, none of the options are without disadvantages, and each has strengths in relation to some of the objectives. The models differ in terms of their suitability for meeting the objectives of the governmient at different stages of the market's development. All the models appear to be feasible for the initial implementation of an LNG project, but some would need adaptation at later stages of the market's development. The government appears to have selected an approach similar to Model 2 for the implementation of the first LNG project announced for Guangdong Province. This may imply that the goverunment places significant emphasis on the potential for the GDC to provide control and guidance for the development of the market in this first project. However, this does not necessarily signify a long- term commitment to this approach. The government may choose other models for subsequent LNG projects in East China or elsewhere. (It should be noted that we were not asked to make, and have not made, any recommendation on the mrost suitable or preferred option for East China.) 48 Liquefied Natural Gas in China  Table 6.1 Key Advantages and Disadvantages of Proposed Models Model Advantages Disadvantages Model 1: Integrated * Allows rapid development . Complicated contracts because of presence Company- * Short contract chain. of three power companies Single Buyer * Low incentives for nonpower sector * Inhibits competition * Under liberalized market, power stations are less financially secure * Control of sector lies with users, not government. Model la: Allow rapid development * Complicated contracts because of presence Integrated * Direct contract chain with of three power companies Company- buyers * Nonpower sector may not be able to Multiple Buyers New entrants have access guarantee LNG purchase * Good incentives for long-term * Potential conflict over shares in JV as development nonpower market grows * Proven financing model- * Under liberalized market, power stations are Japan. less financially secure * Control of sector lies with users, not government. Model 2: * Rapid development of power * Unlikely that guarantees will be available Gas Development and nonpower sectors * Complex contracting between PPAs and Company Channel for some form of LNG contracts government guarantee * Creditworthiness of buyers is essential - Proven financing model-Korea * Future competition may be difficult. - GDC can provide a channel for strategic guidance of the sector by the government. Model 3: * Incentive to develop power e Creditworthiness of buyers depends on Separate Gas Buyer and nonpower sectors backers * LNG off-take contract is well * Complex model with strong legal due secured by buyers diligence requirement. * Open-access pipeline fosters competition. Model 4: * Most direct contract chain for * Complex gas purchase and operating contracts Power Sector Gas LNG purchase * Power companies carry all risk Buyers * No barrier to creating open- * Creditworthiness is very important access pipeline. . LNG buyer needs PPA to back gas supply contract, inhibiting power sector reform. Chapter 6: Ownership Structure and Trading 49  The requirements will change during the different stages of development (market creation, market development, and mature market). In the early (market creation) stages, the priority is to ensure a rapid and successful first project. During the growth phase (market development), the need is to promote the expansion of the market to supply new consumers and to encourage the development of new sources of supply. In the last stage (mature market), when the infrastructure is fully developed, the priority may switch to promoting competition and ensuring efficiency and low cost. Ultimately, the appropriate choice of model will depend on the government's objectives. Contracts A number of contracts and agreements will be necessary to implement the LNG project. The importance of ensuring that all contracts are signed and implemented at the same time is critical, as each component is essential if the entire project is to succeed. Once the ownership structure and trading arrangements are determined, the contract structure for the project can be designed. The key purposes of the contract structure are to allocate the risks between the various parties and to ensure, through the take-or-pay conditions, that a minimum level of revenue is received to guarantee the financing of the project. The most important contracts, together with the main purposes, are likely to be as follows: * LNG purchase contract. This contract will govern the supply of LNG from the upstream producer and shipper to the LNG buyer. The contract will be long term (e.g., up to 20 years) with substantial take-or-pay provisions for annual quantities but with some flexibility on minimum and maximum takes. The LNG supplier will require the contract to be signed by a financially strong company * (Gas off-take contract. This contract governs the sale and purchase of gas from the LNG buyer to the gas user. For the IPPs, this contract is more usually called the fuel-supply agreement. * Power off-take agreement. The power plant will need an agreement with the power company for a take-or-pay contract to match its gas take-or-pay obligations. Traditionally this is referred to as a power purchase agreement (PPA). Under the proposed reform of the generation market and implementation of the single buyer model, the PPAs will be replaced by contracts for differences. These CfDs will have a similar effect of ensuring a minimum revenue security to cover the financing and fuel purchase. However, it is not clear whether their duration will be sufficient to provide the security for the LNG purchase. * Terminal and pipeline operating agreements. These will be required to ensure that the technical risks of operation are born by the operator, not the LNG supplier or consumer. They will also ensure that, under normal operating performance, the investors receive a guaranteed revenue to secure the financing. The overall contract structure for an LNG projiect will need to include a number of other contracts and agreements, including construction contracts, financing agreements, shareholders agreements and pipeline access agreement. Back-to-back contract provisions create links in the risk chain between parties. The back-to-back provisions provide matching risk allocation terms by ensuring complementarity of a range of terms covering base price, indexation, duration, and termination; all these contracts would need to be 50 Liquefied Natural Gas in China  negotiated and signed simultaneously. It is also necessary that any external regulation of prices (gas or power) should permit the pass-through of costs and prices to ensure the sanctity of the contracts and the viability of the companies. For this reason, regulators will sometimes require powers of initial approval of contracts. Options being discussed for the. proposed reform of the power generation market could lead to the need to minimize the extent of the long-term take-or-pay type of contracts. This would create a conflict between the financing requirements of the LNG project and the flexibility of dispatch needed to create a competitive generation market. Careful consideration should be given to the design of the gas contracts as well as to the design of the power market to strike the best balance between these conflicting requirements. Trading Arrangements Trading arrangements, which will be based on contracts and agreements between the various parties, will differ somewhat for each of the models. For illustrative purposes, we summarize the arrangements for Model 3: * The GDC will be set up as a new company that will probably have a number of shareholders. A shareholders' agreement will cover the allocation of shares and responsibilities for providing finance. A financing agreement with lending institutions may be required for longer-term financing needs. The GDC will be the LNG buyer and will contract for long-term LNG supplies delivered at CIF prices to the terminal. The terms of the import of LNG will be governed by one or more competitively negotiated LNG purchase agreements. The LNG Terminal and Pipeline could be subsidiaries or separate companies * Title to the gas will remain with the GDC up to the exit from the pipeline, when it will pass to the gas consumers. The terminal owner/operator will provide terminal services under a processing agreement with the GDC. The agreement will include a large process-or-pay component to guarantee its financing. * The pipeline company will provide transportation services under a transportation agreement, which will also include a large capacity payment. Regulations for operation of the pipeline system will embody open-access provisions. * Power stations and gas distributors (and also possibly large industrial consumers connected to the high-pressure pipeline) will purchase their gas from the GDC under long- term gas sales agreements. These will include large take-or-pay cornmitments and will be subject to external regulation. * The power stations will sell their electricity to the power companies under long-term power purchase agreements. These could include provisions to be converted into CfDs when or if an SB model is introduced. * The distribution companies will sell their gas to various small consumers under externally regulated gas sales contracts. Figure 6.6 shows the contracts that formalize the trading arrangements (again, Model 3 is used for illustrative purposes). Chapter 6: Ownership Structure and Trading 51  Figure 6.6 Trading Arrangements and Contractual Relations-Model 3 _hrshle Agrewnt Fiawdng Agreement I LNG Gas development Gas Supply Purchase company (G ', <Agreement PPA Elecicit iProcesnig . -Transporon \Power