Africa Gas Initiative Main Report Volume I ESM240 Vol 1 Energy Sector Management Assistance Programme CAA A DReport 240/01 JI ILI UL February 2001 JOINT UNDP / WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) is a special global technical assistance program run as part of the World Bank's Energy, Mining and Telecommunications Department. ESMAP provides advice to governments on sustainable energy development. Established with the support of UNDP and bilateral official donors in 1983, it focuses on the role of energy in the development process with the objective of contributing to poverty alleviation, improving living conditions and preserving the environment in developing countries and transition economies. ESMAP centers its interventions on three priority areas: sector reform and restructuring; access to modern energy for the poorest; and promotion of sustainable energy practices. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (ESMAP CG) composed of representatives of the UNDP and World Bank, other donors, and development experts from regions benefiting from ESMAP's assistance. The ESMAP CG is chaired by a World Bank Vice President, and advised by a Technical Advisory Group (TAG) of four independent energy experts that reviews the Programme's strategic agenda, its work plan, and its achievements. ESMAP relies on a cadre of engineers, energy planners, and economists from the World Bank to conduct its activities under the guidance of the Manager of ESMAP, responsible for administering the Programme. FUNDING ESMAP is a cooperative effort supported over the years by the World Bank, the UNDP and other United Nations agencies, the European Union, the Organization of American States (OAS), the Latin American Energy Organization (OLADE), and public and private donors from countries including Australia, Belgium, Canada, Denmark, Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden, Switzerland, the United Kingdom, and the United States of America. FURTHER INFORMATION An up-to-date listing of completed ESMAP projects is appended to this report. For further information, a copy of the ESMAP Annual Report, or copies of project reports, contact: ESMAP c/o Energy and Water The World Bank 1818 H Street, NW Washington, DC 20433 U.S.A. Africa Gas Initiative Main Report Volume I February 2001 Joint UNDPNVorld Bank Energy Sector Management Assistance Programme (ESMAP) Copyright © 2001 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 February 2001 ESMAP Reports are published to communicate the results of the ESMAP's work to the development community with the least possible delay. The typescript of the paper therefore has not been prepared in accordance with the procedures appropriate to formal documents. 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, or 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 whatsoever for any consequence of their use. The Boundaries, colors, denominations, other information shown on any map in this volume do not imply on the part of the World Bank Group any judgement on the legal status of any territory or the endorsement or acceptance of such boundaries. The material in this publication is copyrighted. Requests for permission to reproduce portions of it should be sent to the ESMAP Manager at the address shown in the copyright notice above. ESMAP encourages dissemination of its work and will normally give permission promptly and, when the reproduction is for noncommercial purposes, without asking a fee. Contents Contents .......................iii Foreword .........................v Abbreviations and Acronyms ...................... vi Units of Measure ...................... vii Conversion and Equivalence ...................... viii Introduction .......................1 Objectives ............ 1 Resource Base ..........2 Methodology ..........3 Presentation of Conclusions and Recommendations ........................................4 Gas Resources .......................................................7 Gas Reserves .......................................................7 Gas Uses ......................................................8 Flared Gas Recovery .......................................................8 Associated Gas Recovery vs. Non-associated Gas Extraction ........... ............ 11 Small Fields Development ...................................................... 12 Private Sector Involvement ...................................................... 13 Natural Gas: Building up New Markets ...................................................... 19 Change in Market Perception ................... ................................... 19 A Strong Reserve Base ...................................................... 20 Oil and Gas Demand ...................................................... 20 Traditional Gas Markets ...................................................... 21 Power Generation ...................................................... 25 Gas-to-Liquid ...................................................... 28 LPG ...................................................... 33 A Fuel Too Long Overlooked ...................................................... 33 Narrowing the Gap ...................................................... 34 Commercial Energy: A Tiny Slice of Total Energy Demand ............. ............... 35 LPG Demand and Supply Patterns Remain Strongly Distorted ....................... 36 Institutional Issues ...................................................... 38 Pricing Issues. Are Subsidies an Option? ...................................................... 38 Developing Hubs to Increase Supply at Lower Cost ....................................... 39 Toward New Regional Markets ...................................................... 40 Conclusions ...................................................... 41 Institutional and Regulatory Matters for Gas Downstream Activities .......... ........ 43 Why is a New Regulatory Framework Needed? .................................. ........... 43 Organization and Structure. Competition and Market Access ........... ............. 44 Economic Regulation ...................................................... 45 Compatibility with Government Policy ...................................................... 46 Regulatory Authority ...................................................... 46 iii List of Tables Table 1.1: The Place of Sub-Saharan Africa in the World Gas Industry .................... 2 Table 2.1: Evolution of Proven Oil and Gas Reserves in SSA, 1971-98 .................... 7 Table 2.2: Gas Reserves and Production in Sub-Saharan Africa .............................. 9 Table 2.3: Gas Uses in Sub-Saharan Africa ................................................... 10 Table 2.4: Gas Flaring Worldwide ................................................... 10 Table 2.5: Carbon Dioxide (C02) Emissions from the Consumption and Flaring of Natural Gas ................................................... 11 Table 2.6: A Sample of Gas and Oil Fields Located Close to Markets along the Atlantic Seaboard ................................................... 14 Table 2.7: Distance from Remote Gas Fields to Main Markets in Southern and Eastern Africa ................................................... 14 Table 3.1: Oil Trade and Oil and Gas Reserves-to-Production Ratios in SSA Gas and Oil Producing Countries ................................................... 21 Table 3.2: Oil and Gas Demand and Supply in SSA Oil and Gas Countries ........... 22 Table 3.3: Final Energy Demand in the Main Consuming Sectors .......................... 24 Table 3.4: Oil Demand by the Industrial Sector in SSA Gas Countries .......... ......... 25 Table 3.5: Electricity Demand and Supply in SSA Gas Countries ........................... 27 Table 3.6: Gas Oil/Diesel Oil Demand and Supply in SSA Gas Countries ......... ..... 29 Table 3.7: Gas Oil/Diesel Oil Demand in selected SSA Countries .......................... 31 Table 3.8: Main Characteristics of a Small-scale GTL Plant ................... ................ 31 Table 3.9: Sensitivity Analysis ................................................... 32 Table 4.1: LPG Demand in the Residential Sector in Selected Emerging Economies ................................................... 34 Table 4.2: Biomass vs. Commercial Energy (R&C sectors) in Sub-Saharan Africa ................................................... 36 Table 4.3: LPG Demand in Selected Countries in Sub-Saharan Africa ................... 37 Table 5.1: Areas to Be Regulated and the Powers of the Regulator ............ ........... 48 iv Foreword The Africa Gas Initiative (AGI) Study is aimed at identifying countries where gas flaring could be reduced, for better utilization in the industrial and commercial sectors of their economies. This study was conducted by Mourad Belguedj, Senior Energy Specialist and Team Leader at the Oil and Gas Division of the World Bank and Henri Beaussant, Gas Economist and consultant. The focus of the study, aimed initially at select countries on the West Coast of Africa, is of direct relevance to ESMAP's mandate and might be useful to Policy makers, Industry and practitioners in the target countries. The Study is published as part of the ESMAP series of reports and may usefully contribute to Project Identification and to addressing key Policy Issues in these countries, as well as enriching the debate on Energy Sector Reform. The authors wish to express their gratitude to all the colleagues who contributed directly or indirectly, to the review and completion of this work. v Abbreviations and Acronyms AGI Africa Gas Initiative CAPEX Capital Expenditure CH4 Methane (natural gas) CIF Cost, Insurance, Freight CO Carbon Monoxide C02 Carbon Dioxide DME Dimethyl-ether DoE Department of Energy (US) EIA Energy Inforrnation Administration (US DoE) ESMAP Energy Sector Management Assistance Program FOB Free on Board FSU Former Soviet Union F-T Fischer-Tropsch (GTL technology) GDP Gross Domestic Product GGS Gas Gathering System GHG Greenhouse Gas GTL Gas-to-Liquids GTP Gas-to-Power HSFO High Sulfur Fuel oil lEA Intemational Energy Agency IOC International Oil Company IPP Independent Power Producer LHV Lower Heating Value LNG Liquefied Natural Gas LPG Liquefied Petroleum Gas NGL Natural Gas Liquids NOC National Oil Company NWE Northwest Europe (Rotterdam) O&G Oil and Gas OECD Organization of Economic and Cooperation Development OPEX Operating Expenditure R&C Residential and Commercial RTP Reserves to Production (ratio) SSA Sub Saharan Africa UN United Nations US United States USD US Dollar WLPGA World LPG Association vi Units of Measure BBBL billion barrels BBOE billion barrels oil equivalent BCF billion cubic feet BCM billion cubic meters BL, BBL barrel, barrels BOE barrels oil equivalent CF, CFD cubic feet, cubic feet per day GJ gigajoule GW, GWH gigawatt, gigawatt-hours KCAL kilocalorie KW, KWH kilowatt, kilowatt-hour MBOE, MMBOE thousand, million barrels oil equivalent MBPD thousand barrels per day MCAL megacalorie MCF thousand cubic feet MCFD thousand cubic feet per day MMB million barrels MBL thousand barrels MMBTU million British Units MMCFD million cubic feet per day MMCM million cubic meters MMT million tons MT thousand tons MTOE thousand tons oil equivalent MTY thousand tons per year MW, MWH megawatt, megawatt-hour TCF trillion cubic feet TJ terajoule TCM trillion cubic meters TOE tons oil equivalent M, K thousand, kilo (10^3) MM, M million, mega (10^6) B, B, G billion, giga (10A9) T, T trillion, tera (10"12) vii Conversion and Equivalences Volume 1 cm 35.315 cf I mcf 28.32 cm 1 bl 159 liters; 0.159 cm 1 cm 6.29 bbl Energy content (LHV) keal/kg btu/kg oil equivalent 10,000 39,690 heavy fuel oil 9,750 38,690 gas oil, diesel oil 10,000 39,690 jet fuel 10,470 41,520 kerosene 10,390 41,230 LPG 11,000 43,600 fuelwood 3,000 11,940 charcoal 7,000 27,860 natural gas (per cm) 8,500 33,740 Energy Equivalences I kWh = 0.86 Mcal = 3.6 MJ 1 mmbtu = 252 Mcal = 293 kWh = 1,055 MJ 1,000 cm natural gas = 0.85 toe 1,000 kWh electricity = 0.11 toe (final consumption) 1 ton wood = 0.30 toe 1 ton charcoal = 0.70 toe Rules of thumb natural gas: 1 mcf - 1 mmbtu- 1 GJ natural gas: I mmcfd -10 mmcmy oil: I bpd- 50 tpy natural gas: USD 1/mmbtu - USD I/mcf- USD 40/mcm viii 1 Introduction Objectives 1.1 The Africa Gas Initiative (AGI) has been established by the Oil and Gas Division of the World Bank to promote the utilization of natural gas in Sub Saharan Africa. Initial emphasis was put on countries along the West African coastline and the Gulf of Guinea, where most of the region's gas reserves are located, and where a significant proportion of the gas produced is currently wasted through flaring or venting. 1.2 The AGI was initiated at a conference held in Addis Ababa, Ethiopia in June 1994, hosted by the UN Economic Commission for Africa, and the World Bank. This meeting was attended by Government representatives from eighteen African countries as well as twenty one national oil corporations and private companies. The goal of the participants was clearly stated as the need: * to put an end to gas flaring, * to develop indigenous natural gas resources for local markets and for exports, * to reap more economic benefits from gas substitution, reduced imports or increased exports of oil products, and * to improve environmental conditions at both local and global levels. 1.3 It was recognized that, in order to achieve these goals, an appropriate enabling environment, based on market driven principles was required. Thus the AGI's major objective was set to focus on the development of projects as well as of technical assistance for institutional building. Possible gas projects would include gas flaring reduction by field re-injection, and gas utilization for power generation, industry, and transformation into secondary energy camrers. Another benefit of gas operation was to generate additional revenues through condensate and NGL stripping and sales. 1.4 With regard to environmental benefits, gas development would reduce sulfur and particulates emissions caused by burning polluting liquid fuels. It would decrease greenhouse gas emissions released by liquid fuels combustion and methane venting. Also, natural gas operation would increase the production of LPG by separation 1 2 Africa Gas Initiative: Main Report in the gas stream, which would in turn help mitigate the adverse consequences of deforestation by substituting LPG for charcoal and wood. 1.5 Close co-organization and co-operation between intemational oil companies (IOC) that operate the oil fields, national oil companies, governments and public agencies, was considered a pre-requisite to implement both projects and policies. The World Bank, with its pool of expertise and access to information and people, would facilitate the project development process by providing assistance and by playing the role of 'honest broker'. The World Bank Group is also able to mobilize and engineer financing schemes from various sources, including its own. Resource Base 1.6 Sub-Saharan Africa holds a modest place in the world gas industry. Although oil reserves (thus, associated gas) are far from negligible, the region is not gas prone and does not shelter any of those giant gas deposits that constitute the bulk of the reserves of the Middle East, North Africa and the former Soviet Union. They are either located close to oil fields along the Atlantic seaboard, or they lie stranded across the continent, scattered along a 6,000 km-long bow that stretches from offshore Namibia to Ethiopia. Associated gas is exclusively located in the oil provinces along the Gulf of Guinea, from Angola to Cote d'Ivoire, mostly in the offshore. 1.7 Most of gas produced is associated, and the larger share of this gas is either flared or re-injected. While non-associated gas accounts for about half of gas reserves, the amount of non-associated gas to be produced and marketed remains limited. But among marketed gas, non-associated gas is prominent. In Nigeria, most of the gas consumed domestically (e.g. for power generation) is non-associated. The share of associated gas in marketed gas, however, is expected to increase as export schemes develop. Table 1.1 - The Place of Sub-Saharan Africa in the World Gas Industry Region Gas Gas Gas Oil Reserves Production Marketed Reserves (TcJ) (BcfJ (Bcj) (mmb) North America 296 32.3 25.7 67 Central & South America 222 4.6 2.8 86 Western Europe 173 11.1 10.1 18 FSU and Eastem & Central Europe 2,000 26.3 26.3 59 Middle East 1,726 9.9 5.5 677 North Africa 207 6.0 2.9 43 Sub-Saharan Africa 147 1.8 0.3 27 Share of SSA (percent) 2.8 1.8 0.4 2.7 Far East & Oceania 321 9.2 8.1 42 Total World 5,087 101.1 81.7 1,020 Source: Oil & Gas Journal through US DoE. Figures are for 1998 (Gas reserves) and 1996 (Gas production and gas marketed). Figures for gas marketed include gas exports; they may include own uses. Introduction 3 1.8 Gas markets can be established in Africa. Gas reserves in Sub Saharan Africa are estimated to be 141 Tcf, and these resources should be developed in an efficient manner. Many countries have substantial undeveloped gas reserves. Both associated and nonoassociated gas can be developed from over 400 known oil and gas fields. While Nigeria remains by far the oil (and gas) giant in the region, other countries are endowed with enough resources, whether associated or not, to make gas operation economic. The AGI has focused primarily on Angola (1.7 Tcf), Cameroon (3.9 Tco, Congo (3.2 Tcf), Cote d'Ivoire (1 Tcf), Equatorial Guinea (1.3 Tcf) and Gabon (1.2 Tcf). Within these countries, 11 fields with proven recoverable reserves of more than 400 Mcm have been identified for development. 1.9 The issues raised are being systematically approached by the AGI. The AGI is working to change the current situation and in doing so, has received precious support from many African Governments. It makes sense for all involved that such a valuable resource can be used productively. This includes substituting gas for liquid fuels, e.g. for power generation, to save economic resources by reducing fuel imports. This is the approach which is proposed and it started to show positive results wherever it has been tried. Methodology 1.10 The methodology adopted was built on four key steps leading from study to project phase. First, a desk study was conducted within the Bank to identify the most likely candidate countries, with enough resources and potential to develop small projects. The desk study reviewed existing documents and prior field research conducted by the Bank, to identify the most likely candidate countries with enough resources and potential to develop small projects. For this purpose, AGI developed a database, which compiled information by conducting extensive review of traditional sources of data, supplemented by classic questionnaires sent to governments and operators. The AGI focused initially on areas where the potential for developing gas markets was high. This task however is known to be time consuming as data is often non existent or very approximate and requires besides close collaboration, patience, perseverance and strong commitment from all concerned. 1.11 In the second phase, field visits to countries and Governments were conducted, which were followed by discussions with oil and gas operators, including national oil companies (NOC). A review was undertaken in collaboration with local counterparts, in order to evaluate potential gas projects in greater detail. This step was made necessary as gas fields needed to be assessed, and the availability of indigenous resources determined prior to launching field development. The results of the second phase led to pre-feasibility studies for each identified gas development project. 1.12 In the third phase, subsequent to confirmation of data on reserves and markets, a Bank Mission of experts, including outside consultants where required, would undertake a feasibility study to assess and identify upstream and downstream components of a credible "project idea." Definition and conceptualization of the project idea include data analysis and determination of required gas processing facilities, as well 4 Africa Gas Initiative: Main Report as gas pipeline and distribution systems. Whenever the power sector is found to be a good candidate for project start-up, extensive studies of the local and regional power sector were also carried out. Economic and financial evaluations of the selected project were conducted during the feasibility study phase, using standard World Bank procedure for project viability. 1.13 Fourth, the project idea was refined into a proposal which was submitted to Government and industry at large, for review and decisions aimed at materializinm? and managing the project. Presentation of Conclusions and Recommendations 1.14 Presently, identification of the gas resource base and preliminary recommendations for gas utilization have been completed for Angola, Cameroon, Congo and Gabon. Technical assistance with regard to institutional and regulatory framework have been conducted in Cameroon and Cote d'Ivoire. Also, AGI has undertaken the analysis of current petroleum fiscal legislation, to review the profitability of gas field development from the investors' viewpoint as well. This analysis has enabled the World Bank to provide recommendations to respective governments to introduce required changes in their petroleum laws. The efforts of AGI have resulted in a very comprehensive analysis, and governments are more receptive to the Bank, given its track record of impartiality in its role as "honest broker." 1.15 The current (main) report presents the global findings and conclusions of the first Phase of the AGI program. They are presented in a sectoral fashion, with emphasis on: * Gas resources; * Developing markets for natural gas; * LPG, and * Institutional and regulatory matters. 1.16 The main report is complemented by five Country Reports, which summarize the work performed during the first Phase in the following countries: * Angola * Cameroon * Congo * Gabon, and * Cote d'Ivoire 1.17 In each Country Report, emphasis is put on the issues that appeared to be of particular importance in the relevant country, and on the projects that could be developed in order to address those issues. In particular, the potential use of gas for Introduction 5 power generation is addressed in detail through ad hoc consultant reports prepared for all countries, except Cote d'Ivoire. For the latter, where gas-to-power projects had already been initiated at the time the AGI started activities, emphasis has been put on the need for an institutional and regulatory framework dedicated to gas downstream activities. Such work has also been conducted for Camneroon, where a project exists to develop gas for industry. 2 Gas Resources Gas Reserves 2.1. Although no gas-oriented exploration campaigns have ever been conducted in the region, Sub Saharan Africa is known to be sitting on a sizeable amount of gas, which was found by international oil companies (IOC) while looking for oil. Therefore, actual reserves are likely to be much larger. Some countries, such as Angola, Cote d'Ivoire and the Republic of Congo have launched exploration rounds in the deep and ultra-deep waters offshore, which have proved successful in discovering larger (oil) reserves. In 1997 only, oil reserves increased by 3 Bbbl (430 mmt). Using normative equivalence factors , this represented about 3 Tcf of associated gas, i.e. 3 percent on top of the previous year's figure. 2.2 Estimated proven gas reserves, both in the associated and non-associated forms (the breakdown between associated and non associated gas is about even), amounted in 1998 to 141 Tcf (4 Tcm, about 3.5 billion toe). Although SSA accounts for no more than 3 percent of world gas reserves, they represent 30 years of the overall commercial energy demand of the region, including South Africa. Gas reserves are currently equivalent, in energy content, to oil reserves. Over the last three decades, gas reserves have increased at a much faster pace than oil reserves, bringing the gas to oil reserves ratio from 22 percent in 1971 to 40 percent in 1980, to 96 percent in 1998. Table 2.1: Evolution of Proven Oil and Gas Reserves in SSA, 1971-1998 Unit 1971 1975 1980 1985 1991 1998 Oil Reserves Bbbl 11.8 23.8 19.8 23.0 22.3 27.3 Gas Reserves Bboe 2.6 8.6 7.9 8.2 23.3 26.2 Gas Reserves to Percent 22 36 40 39 105 96 Oil Reserves Ratio Source: Oil & Gas Journal. 2.3 Sixteen of the 42 Sub Saharan Africa countries are endowed with gas reservesl. While Nigeria holds 80 percent of total gas reserves, most countries range Angola, Benin, Cameroon, Cote d'Ivoire, Democratic Republic of Congo, Republic of Congo, Equatorial Guinea, Ethiopia, Gabon, Ghana, Mozambique, Narnibia, Nigeria, Rwanda, Senegal, South Africa, Tanzania. 7 8 Africa Gas Initiative: Main Report between 0.5 and 4 Tcf (15 and 110 Bcm), which is largely sufficient to cover their domestic needs, and, for some of them, to consider exports-based schemes. Reserves may be associated with oil, in particular along the Gulf of Guinea, in first place within the oil producing provinces that stretch from Angola to Cote d'Ivoire. Conversely, hydrocarbon reserves in southern and eastern Africa consist in gas-only deposits, while oil is not to be found in the area. These stranded, non-associated gas reserves are scattered throughout the rest of the continent, drawing a long bow across southern and eastern Africa, from offshore Namibia to southern Ethiopia. Gas Uses 2.4. Ten SSA countries produce gas (whatever the final usage), for a total of 1.8 Tcf (53 Bcm). Most of the gas produced, however, is flared or vented, and this proportion is bound to increase as new oil fields are put on stream. A smaller amount of gas is used by the O&G industry itself, either as a fuel or for re-injection in oil wells to enhance oil recovery through increasing pressure in the reservoirs. Only seven countries2 -- four of them located along the Gulf of Guinea -- use gas for domestic purposes, and market it to commercial consumers outside the oil and gas industry. In total, gas accounts for a low 2.8 percent of the region's primary energy demand. Not surprisingly, the highest share is to be found in Nigeria, where gas represents 22 percent of primary energy demand, mostly for power generation. In the other gas countries, the participation of gas in the coverage of the domestic demand remains limited. Flared Gas Recovery 2.5 Gas flaring and venting is done in oil producing countries where operators are not interested in developing gas markets - whatever the reason. Associated gas is extracted along with oil during production phase, and is generally flared or vented on the production site, sometimes after LPGs are removed from the gas stream. In a typical year, an estimated 4.8 Tcf of gas (135 Bcm) of gas is flared or vented worldwide. SSA holds by far the poorest record with respect to the ratio of gas flared or vented to gross gas production. While gas produced in SSA represents a mere 2 percent of worldwide gas output, the region accounts for 28 percent of all gas flared or vented worldwide, more than any other region. On average, oil operators in SSA flare over 70 percent of overall regional production3 (vs. worldwide average of 4 percent), while they market only about 11 percent of the production. Up to now, in only a few cases does small-scale gas development occur, but with limited market penetration or growth, except in Cote d'Ivoire and Nigeria. If additional gas utilization projects are not implemented over the next twenty years, over half of SSA's current known gas reserves could be flared along the Atlantic seaboard, in particular in Nigeria. 2 Angola, Cote d'Ivoire, Gabon, Nigeria, Rwanda, Senegal, South Africa. 3 Proportion of gas flared is to decrease when Nigeria's Bonny LNG project operates at fuill capacity. Gas Resources 9 Table 2.2: Gas Reserves and Production in Sub-Saharan Africa Country Gas Gas Gas Gas Flared Percent Other Gas Marketed Reserves Production Reinjected or Vented (Y.) Losses Gas4 (Tcf) (Bc) (Bcj) (Bc]) (Bcj) (Bcf) Angola 1.6 208 42 138 71 5 20 Benin <0 1 Cameroon 3.9 73 73 10o Congo, Democ. Republic <0.1 Congo, Republic of 3.2 47 1 46 98 Coted'Ivoire 1.1 19 0 24 Equatorial Guinea 1.3 31 28 88 3 Ethiopia 0.9 Gabon 1.2 91 21 63 69 3 4 Ghana 0.8 Mozambique 2.0 Namibia 3.0 Nigeria 124.0 1,301 139 965 75 4 193 Rwanda 2.0 n/a n/a Senegal 0.4 2 0 2 South Africa 0.8 65 0 65 Tanzania 1.0 Total Sub-Saharan Africa 147.2 1,837 203 1,313 71 15 308 (17 countries) Sources: Reserves: Oil & Gas Journal, as of 1/1999. Other data: US Department of Energy, for 1996 or 1997. Bold case indicates countries where gas is sold in the domestic market. 2.6 Under present oil and gas practices in many developing countries, associated gas is still considered by IOCs a by-product of oil which can hinder the oil flow - which is physically the case. In SSA, it is generally disposed of through flaring or venting for lack of adequate markets or lack of institutional and regulatory framework to support its utilization. The issue in developing associated gas recovery is purely economic, not technical, as associated gas can physically be separated from oil for further use within or outside the industry. Own use includes re-injection, either to improve oil flow, the reservoir productivity and thus increase its useful life, or to be kept in storage for later use. External usage directs gas toward consumption markets, either domestic or international, where it can be used as a fuel or feedstock. Whatever the option, associated gas recovery means a productive use of a depletable energy resource. 4 Including own use. 10 Africa Gas Initiative: Main Report Table 2.3: Gas Uses in Sub-Saharan Africa (B cf/year) (Bcm/year) Percent Gas Produced 1,837 52.0 100 Gas Flared ! Vented 1,313 37.2 71 Gas Re-injected 203 5.7 11 Own Use 126 3.6 7 Gas Marketed 195 5.5 11 Table 2.4: Gas Flaring Worldwide Region Gas Flared or Regionwise Gas Flared, as a Vented Breakdown of Gas Percentage of Gross (TcJ) Flared/Vented Regional Production (°/) (/0) North America 0.5 11 2 Central & South America 0.6 12 12 Westem Europe 0.1 3 1 FSU and Central & Eastem Europe 0.7 14 3 Middle East 0.9 19 9 North Africa 0.4 8 6 Sub-Saharan Africa 1.3 28 71 Far East & Oceania 0.3 6 3 Total World 4.8 100 4 Source: Oil & Gas Journal; Cedigaz. Discrepancies may occur due to rounding 2.7 If associated gas is valued at the price of fuel oil -- its closest competitor in the industrial market - gas flaring represents an economic loss of USD 3 billion annually in SSA. Moreover, gas flaring and venting represents an environmental threat in increasing the release in the atmosphere of greenhouse gases (GHG, in particular carbon dioxide and methane), which are responsible for global warming. The steady growth of carbon emissions was declared no longer acceptable under the Kyoto protocol of 1998 that aims at mitigating global warming through the reduction of carbon emissions by industrialized countries. In SSA's oil producing countries, natural gas flaring (which produces C02) and venting (which frees up CH4) represent the major source of GHG emissions, a proportion significantly larger than emissions from the combustion of all fossil fuels (including gas) fired for industrial and domestic purposes, including power generation (Table 2.5). 2.8 Associated gas recovery, however, is an expensive operation. Whether gas is used for re-injection or for outside customers, it requires the construction and the operation of a gas gathering system that collects raw gas from oil wells and transport it to a gas treatment unit where LPG are removed. It then requires powerful compressors used to either re-inject the gas into the reservoirs, or to send it through high-pressure pipeline Gas Resources 11 to remote consumers. Benefits from increased oil production, LPG recovery or possible future sales of gas, must be sufficient to bring adequate returns on investments for the latter to be considered. Table 2.5: Carbon Dioxide (C02) Emissions from the Consumption and Flaring of Natural Gas Emissions from ... Share of Gas Flaring / Venting... Consumption of which: ... in Total Gas ... in Total Fossil and Flaring / Flaring and Consumed and Fuels Venting of Gas Venting only Flared/Vented Consumption (million ton C) (million ton C) (/0 (°/) Angola 2.28 1.99 87 59 Congo (Republic of) 0.81 0.81 100 75 Gabon 0.94 0.88 94 49 Nigeria 16.04 13.19 82 48 South Africa 0.98 0.02 2 0 Sub Saharan Africa 21.46 16.99 79 11 (5 Countries) Sources: Emissions from Consumption and Flaring: EIA, US DoE. Other data: own computations. 2.9 Therefore, gas flaring recovery is usually only considered for larger projects, and it is frequently not chosen, in particular for small fields. Such large-scale recovery projects, however, are being implemented in SSA, in particular in Nigeria. The first exports-oriented project, Bonny LNG, has just started after three decades of preparation, hesitations and postponements. It is based on collecting 800 mmcfd of associated gas from the Bonny oil field for liquefaction and exports to European markets. A second project is now in the pipe, which will result in exporting up to 180 mmcfd of associated gas from the Escravos oil field area to Benin, Togo and Ghana through an offshore, 980-km long pipeline mainly dedicated to power generation. 2.10 Creating an enabling environment for gas markets, providing incentives to IOC's, evaluating projects and financing them, are possible only with the close co-operation between host governments, IOC's and investors. A review of recent efforts in this direction shows that wherever this type of approach has been applied, results have been successful in reducing or preventing associated gas flaring. The North Sea, and more recently Indonesia, Malaysia, India (Bombay High) and Algeria, are some of these projects. Associated Gas Recovery vs. Non-associated Gas Extraction 2.11 Exploiting the associated gas from oil fields where significant amounts of gas are currently flared or vented, comes first to mind when it comes to developing gas usage and selling it in domestic markets. As suggested above, such option reduces the waste of a valuable source of energy, and contributes to improving global environment. 12 Africa Gas Initiative: Main Report It also increases the quantity of domestic energy available in a given country, thus either reducing the imports of energy (where the country has a deficit), or freeing up additional quantity of energy for exports (where the country has a surplus). 2.12 Associated gas recovery, however, is considered a costly option when compared to the straight extraction of non-associated gas. The AGI has not had the opportunity to conduct a comparative analysis of both options. A previous study performed within the framework of the Nigeria Energy AssessmentS shows that several factors tend to make the economic cost of non-associated gas operation cheaper. Such factors include (i) higher well productivity; (ii) better cost-efficiency of capital expenditure due to higher reserve base; (iii) no need for gas gathering system; and (iv) no need for gas re-compression as non-associated gas is produced at a pressure that allows direct pipeline send out. The latter argument, however, is questionable in the case the non-associated gas stream is conveyed to a gas treatment plant and / or an LPG recovery unit before being sent out to the network, a highly desirable option supported by usually high profitability. While figures would certainly require to be updated, the 4 to 1 ratio in favor of non-associated gas (0.29 USD/mmbtu vs. 1.26 USD/mmbtu at the time of the study) is assumed to keep the demonstration still valid. Small Fields Development 2.13 Although gas flaring reduction schemes remain a valid option for large- scale projects, other options look more attractive in those areas where markets are tight and their absorption capacity limited. They consist in developing small-scale projects based on small, associated or non-associated gas fields located close enough to consumption markets to make operation economic. Focusing on smaller projects is attractive because they are easier to bring to fruition; they mobilize less scarce resources and if proven successful, have great demonstration effect. Such schemes can evolve at a later stage toward projects of regional or even international dimension. In turn this can cause a positive "snowball" effect and attract interest for larger projects, for which groundwork would already have been laid. 2.14 Very often indeed, market size is an asset, no longer a problem. In most SSA countries, limited reserves perfectly suit limited domestic markets. Many gas fields house reserves ranging from 0.1 to 2 Tcf, suitable to ensure limited small-scale commercial operation over 20 years. A recent Esmap study6 has identified in central and southern Africa (except Nigeria) several dozens of such fields, including 85 deposits with less than 0.25 Tcf, 8 fields ranging from 0.25 to 0.5 Tcf, and another 8 fields from 0.5 to 1 Tcf. 2.15 Geographical imbalance and distance to markets. As usual with gas, the key factor to ensure commercial viability is how close to the market is the field located. Due to counter economies of scale, the cost of a small buried pipeline is very sensitive to both the throughput and the distance, so that the cost of transmission may make a project 5 ESMAP: Nigeria - Issues and Options in the Energy Sector, July 1993. 6 ESMAP: Comrnercialization of Small Gas Fields, December 1997. Gas Resources 13 uneconomic if the market is located too far from the production site. The AGI has identified in central and western Africa several gas fields located close to potential markets (table 2.6). Some gas (and oil with associated gas) fields have been recently put in operation, in particular in Cote d'Ivoire. 2.16 In terms of distance from fields to markets, the situation is much contrasted between western and central Africa, on the one hand, and eastern and southern Africa, on the other hand. Along the Atlantic seaboard, from Cote d'Ivoire to Angola's Cabinda province, gas is available within 50 miles of most major consumption centers. This is the case, in particular, for the city-harbors of Abidjan, Douala, Libreville and Pointe Noire, all located close to offshore (and sometimes onshore) gas fields, or oil fields with associated gas. Such proximity makes geographic access to markets not really a problem, as the extra cost generated by gas transmission remains low, and suitable for projects even where demand is limited. 2.17 Conversely, in southern and eastern Africa, gas fields, whether onshore or offshore, are most often stranded in remote areas that can be located several hundred miles from main demand centers. There, gas transmission would account for a significant part of the delivery cost of gas at the city gate, which requires larger projects to be designed in order to lower transmission cost through economies of scale. Such projects are all the more difficult to design as a major characteristic of gas projects in Africa is the limited size of the markets. Private Sector Involvement 2.18 Lack of economic perspectives. The lack of interest by the private sector has often been exacerbated by the absence of appropriate economic conditions for the downstream segments. Even the development of small-scale gas projects on a local level is known to be complex, capital intensive, and to require clusters of expertise far beyond local capabilities. Lengthy project preparation process, high upfront costs and (sometimes) the remoteness of fields from consumption centers, have often discouraged interested investors who do not consider domestic markets sufficiently attractive to develop even small-scale projects. A typical example is to be found in power generation. Industrial markets appear tight to potential investors, even in the main cities, without a lead customer able to secure both a sizable gas demand and a high load factor. Such preferred lead customer is a power plant. Most countries in the region, however, still rely on hydro projects, despite poor economics driven by huge, bulky upfront investment vs. smooth demand growth, lengthy lead time, and irregularity of hydraulic conditions, opposed to the flexibility, modularity and faster construction pace of gas-fired thermal power plants. 13 14 Africa Gas Initiative: Main Report Table 2.6: A Sample of Gas and Oil Fields Located Close to Markets along the Atlantic Seaboard Country Gas Fields Type of Gas Gas Reserves Main Markets Distance to (Ass. /INA) (tcf) Market (km) Senegal Thies NA .13 0.4 Dakar 50 Cote d'Ivoire Lion NA 0.4 Abidjan 105 Panthere Ass. Abidjan 105 Foxtrot NA 24 Abidjan 100 Cameroon Logbaba NA 0.1 Douala 10 Matanda NA 0.5 Douala 40 Sanaga NA 2.0 Douala 80 Equatorial Alba Ass. 0.9 Malabo 30 Guinea Gabon Mbilagone NA 0.5 Libreville 60 Congo Kitina Ass. 0.15 Pointe Noire 65 Litchendjili NA 0.25 Pointe Noire 45 Angola Sanha Ass. 0.34 Cabinda Vanza Ass. 0.35 Cabinda Table 2.7: Distance from Remote Gas Fields to Main Markets in Southern and Eastern Africa Country Gas Field Gas Reserves Main Potential Approximate (Tcf) Consumption Centers Distance (km) Ethiopia Calub Addis-Ababa 600 Mozambique Pande 2.7 Maputo 560 Gauteng area (South Africa) 900 Namibia Kudu Cape Town (South Africa) 840 South Africa Mossel Bay 0.8 Cape Town 380 Tanzania Songo Songo 1.2 Dar es Salaam 180 Mombasa (Kenya) 500 2.19 Small gas fields, key to gas development. IOCs are tied by a long lasting culture dedicated to oil, and to big schemes. Some have been sitting for decades on gas fields without developing them -- and are still not ready to relinquish them. To IOCs, small gas schemes are, and will remain, an odd business -- as they are not equipped to bring them to fruition. Conversely, independent oil companies as well as downstream gas users and operators are attracted by smaller, less capital-intensive projects. They are ready to develop local or sub-regional projects that produce limited returns (limited in global terms, not in percentage) -- and they have already started to implement such projects, as in Cote d'Ivoire. Some conditions, however, need to be met: To develop small and medium size projects, small gas fields, whether associated with oil or not, are better targets than larger schemes which would imply the recovery of large amounts of vented or flared associated Gas Resources 15 gas. The latter operation is generally costly and must be connected, at least to some extent, to gas re-injection. Moreover, current oil operation, hence gas flaring, is run by IOCs that are usually not ready to invest in gas schemes, in particular where the point of application is only local or regional. While mitigating gas flaring and venting is crucial for global environment, IOCs still need stronger economic incentives to promote such projects. * In the beginning, a gas project is likely to develop more efficiently if it includes all physical components of the gas chain, in particular in a country that opens up to gas operation. This has been for decades a well-known pre-requisite with emerging gas industries, because gas producers need a long-term market to develop gas production while gas users need a long-term guarantee of supply. Such a prerequisite, however, may become rapidly obsolete as gas industry develops, in particular when several sources of gas supply have started to compete (like in Cote d'Ivoire). There, a regulatory framework must be implemented very rapidly to organize the gas industry in an efficient manner and to ensure free competition in the market. * Producing gas, transporting it and using it are different businesses. A project does need to be sponsored by (at least) both the supplier at the one end and by a main gas user at the other end. There is no need, however, for a single, integrated developer. Upcoming projects can be developed by consortia that include various skills, responsibilities and areas of expertise. - Institutional reform must accompany the emerging gas industry. On the upstream side, hydrocarbons laws are generally unclear about the ownership of gas and the responsibilities of the contractual parties, including government, vis-a-vis natural gas. Where considered, which is quite unusual, downstream regulation is done through inappropriate legislation and case-by-case, contractual arrangements. Designing a dedicated gas regulatory framework, including the industry's structure, competition management, access to markets and economic regulation is one of the incentives that should be put in place in the early days to attract private capital. 2.20 As discussed above, the current practice for associated gas which is not utilized for oil production and related activities, is venting or flaring. Governments have generally no contractual terms to entice oil companies towards using gas, and may lack the incentive to do so depending on the preference for immediate revenues over future ones. This has led to active Governments' policies to promote oil development, and the driving force is to keep the oil flowing at minimal cost. The flaring of natural gas is also a consequence of cost minimization strategy. Due to these reasons and the lack of economic incentives (whether positive or negative), neither private nor public entities are able to promote gas development in an effective manner. Efforts must therefore focus on making the net revenues from marketing gas more attractive for the operator than the 16 Africa Gas Initiative: Main Report financial benefits of flaring. A properly functioning institutional framework and regulatory regime is also required. However, necessary petroleum legislation needs to be protective of State interests and yet flexible enough to allow growth. A number of countries are considering amending existing petroleum laws, or adopting new ones, that address differently problems related to the development of gas reserves, and to flaring. 2.21 Many African countries now allow and encourage companies which discover gas, to develop the field, instead of the State taking over all the rights. Also, most countries are now willing to allow the foreign investor take the lead and be the operator for the gas project. The introduction of private sector power producers has opened up a large market potential for development which can be attractive to gas producers. 2.22 Utilizing gas in lieu of other fuels can lead to substantial economic, environmental and efficiency benefits. But many African countries lack the appropriate expertise to assess the viability and usage of indigenous gas resources, particularly for domestic purposes. Instead, they often have been diverted, including under outside influence, towards grandiose schemes aimed at exports, few of which so far, have materialized. Although these are not to be excluded in the long run, large projects can hardly be considered the starting point for gas development under the AGI. 2.23 A different approach is needed to minimize preparation and implementation costs, and to bring them to acceptable levels. This is why the AGI continuously and systematically targeted small-scale projects, often related to the development of small gas fields, which are easier to bring on stream. The AGI is stressing the need of gas utilization for domestic markets. Already, some African countries are making the effort to find practical ways to commercialize locally first, their natural gas. In Angola, a comprehensive effort from both the private operator and the provincial government has led to devise the Futila Industrial Park in the Cabinda province, where energy intensive industries will make use of the hitherto flared gas. Further south, newly discovered oil fields are being considered for an overall connection, through a comprehensive Gas Gathering System (GGS) that will introduce the first cross- companies cooperation to store gas in depleted field in lieu of flaring it. The scheme is complemented by a project to deliver gas to shore. Several gas utilization options are presently being considered, including recent or developing technologies such as Gas-to- Power (GTP) and Gas-to-Liquids (GTL). 2.24 Although gas markets are being established on a country by country basis, through both small and medium scale projects, the AGI considers ultimately regional development also to be an equally important medium- to long term goal. The Mozambique to South Africa gas pipeline project could be an example of regional integration. Other regional pipelines, such as the West Africa pipeline (from Nigeria to Ghana through Benin and Togo), and exports of electricity from gas-based generation (Kudu) have recently received approval from concerned governments. 2.25 Governments' New Approach. During the last few years, the political and economic environment in many African countries has drastically changed. This has had a Gas Resources 17 profound effect on the hydrocarbon sector. Issues relating to security of hydrocarbon supplies have receded in the near past, with these products being viewed as commodities, which should be supplied through the most cost-effective channels. Development of domestic resources is seen as justified only when gas can be produced and marketed at internationally competitive prices. 2.26 Many have recognized that the State does not make a good entrepreneur. In light of mounting social and other more pressing internal needs, such as education and health, governments have come to realize that the only way to implement gas infrastructure projects, is to allow private sector participation. Government roles have thus to be redefined. The role of policy maker is of sovereign nature, and should definitely remain at governmental level. With regard to regulation, most African governments consider that the definition and the implementation of institutional and regulatory frameworks are of political nature and should remain the responsibility of the executive authority. While the constitution of a dedicated body may be not questioned, most governments are currently not ready to implement independent agencies and to lift all political control over such bodies. These matters are discussed further in Chapter 5. 2.27 Several countries now allow and encourage companies that discover gas, to develop the field, instead of the State taking over all the rights. Also, most countries are now willing to allow the foreign investor take the lead and be the operator for the gas project. The introduction of private sector power producers has opened up a large market potential for development which can be attractive to gas producers. 2.28 Institutional and regulatory reform. Efforts must focus on making the net revenues from marketing gas much more attractive for the operator than the financial benefits of flaring. A properly functioning institutional framework and regulatory regime are also necessary. In addition, necessary petroleum legislation needs to be protective of State interests and yet flexible enough to allow growth. Creating an enabling environment for gas markets, providing incentives to IOC's, evaluating projects and financing them, are possible only with the close co-operation between host governments, IOCs, and investors, which in turn can be achieved once a level playing field has been established. A review of recent efforts in this direction shows that wherever this type of approach has been applied, results have been successful in reducing or preventing associated gas flaring. 2.29 As far as downstream activities are concerned, dedicated regulation should be put in place. Main topics include the structure of the gas industry, competitive access to market (for the industry) and to product (for customers), economic regulation (prices and tariffs) as well as technical, safety and environmental standards. Chapter 5 of this report presents a deepened analysis of, and make proposals for, institutional and regulatory framework for gas downstream activities. 3 Natural Gas: Building Up New Markets Change in Market Perception 3.1 Until recently, gas was considered a nuisance by major IOCs. Gas reserves were deemed both too big for local markets, and too small for international schemes. Capital intensive gas development was regarded as lengthy and complex, with high distribution and marketing costs, able to only generate returns over the long term from local schemes that produce income in local currencies. Alleged lack of domestic markets meant that the only options left were large, capital-intensive international gas projects, such as Liquefied Natural Gas (LNG) and regional or world-scale petrochemicals, including ammonia and methanol. Such projects require a huge amount of capital, and lead time may be considerable. They must face severe competition from similar facilities that are either located closer to markets, or based on low to very low cost gas. In addition, such export-oriented projects leave limited value added in the host country. They are not really dedicated to directly benefit local economies other than through fiscal revenue. 3.2 Now the old scheme is fading: IOCs still prefer to find oil - and it is not likely to change -- but a gas discovery is no longer a disgrace. Smaller gas schemes, whether gas is associated with oil or not, have become increasingly attractive to both operators and governments. Small independent operators are very active, and operators and gas users team up to embark in joint ventures. This new environment is quite in line with the objectives and the raison d'etre of the AGI, which are to act as a facilitator between governments and the private sector so that an enabling environment develops, within which feasible projects may be initiated and brought to fruition. 3.3 The assistance of the AGI is the more required as the private sector is less attracted in developing projects from its own initiative. For this reason, the AGI has been primarily focusing on small-scale, domestic-oriented projects that may bear less legible benefits than larger, export-oriented schemes for which foreign private financing can be mobilized more easily. As a consequence, the AGI tends to consider small and medium scale markets that can be better supplied by small to medium scale gas schemes, whether based on the development of stranded gas fields or on the valorization of associated gas. 19 20 Africa Gas Initiative: Main Report Such larger projects like LNG, ammonia or methanol production have not been considered in the present section. Along the same lines, it is considered that recent high- technology projects are not likely to develop in SSA in the near future, as the market is not yet ready for the risks associated with them. An exception, however, has been made for Gas-to-Liquids technology, a commercially emerging, albeit technically proven option that looks particularly well suited for African markets. A Strong Reserve Base 3.4 Limited, albeit attractive options include substituting gas for liquid fuels, which allows save economic resources by reducing fuel imports (in countries with oil deficit) or saving more oil for further exports (in countries with oil surplus). A good example of why such desirable policy should be implemented is Cameroon, where oil exports have been steadily decreasing for several years. With only about 11 years of RTP (oil) ratio, Cameroon, a long standing net oil exporter, might well become a net importer in the near future, as new oil discoveries do not make up for field depletion. Although promoting the use of natural gas could not reverse the trend on its own (only new discoveries could), developing gas in the industrial sector and for power generation would help the country remain an oil exporter for an added period of time, and give IOCs more time to pursue exploration campaigns. 3.5 Table 3.1 shows that most gas countries are net oil exporters, in particular those located in oil provinces along the Gulf of Guinea. Actually, all gas countries also produce oil, except South Africa7 and Senegal. Significant discoveries have recently increased RTP (oil) ratios in some countries, such as Angola and the Republic of Congo. Oil RTP ratios, however, remain much lower than gas RTP ratios. They range from 11 to 29 years, with a (non-weighted) average of 24.5 years for the seven oil countries located along the Gulf of Guinea (table 3.1). Conversely, most RTP (gas) ratios are extremely high, in the range of 40 to 90 years, except for Angola, South Africa and Gabon. For the nine SSA gas countries, average RTP ratio is three times larger for gas than for oil. Oil and Gas Demand 3.6 At regional level, energy demand in SSA is still very much met by traditional, non-commercial fuels, in particular in the residential and commercial sector. While the use of commercial energy is logically higher in SSA's more developed countries, charcoal (in larger cities) and fuelwood (in rural areas) still cover 60 to 95 percent of overall energy needs at country level. The demand of commercial energy remains concentrated in urban areas. Except in South Africa, coal is almost absent from the energy market. The bulk of commercial energy is provided by oil products and hydro-power, and, in some countries, by natural gas. 7 South Africa produces synthetic oil from coal and gas, but is not a primary oil producer. Natural Gas: Building New Markets 21 Table 3.1: Oil Trade and Oil and Gas Reserves-to-Production Ratios in SSA Gas and Oil Producing Countries Net Oil Trade8 Oil Gas Country Situation RTP Ratio RTP Ratio (mbpd) (years) (years) Angola 686 20.2 7.8 Cameroon 86 11.0 53.5 Congo, Republic of 194 15.6 68.1 Cote d'lvoire (43) 13.7 43.8 Equatorial Guinea 1.3 41.9 Gabon 348 19.0 13.2 Nigeria 1,663 29.1 95.3 Senegal (24) 0 Sub-Saharan Africa 2,690 24.5 74.9 (selected countries) South Africa (220) 0 12.0 Sources: Oil & Gas Journal; EIA, US DoE. Oil and gas production: 1998. Oil and gas reserves: I/1999. Oil exports and imports: 1996. Oil production includes crude oil, NGL and other liquids. RTP ratio: Reserves in 1/1999 to 1998 production 3.7 Oil demand in Sub-Saharan gas and oil countries9 amounted to 35 million tons in 1997, of which 76 percent was consumed by South Africa and Nigeria. About half of it is used for transportation, with the share of diesel oil increasing faster than that of motor gasoline. Other major uses includes electricity generation and transformation in the refineries (14 percent), households, commercial establishments and agriculture (13 percent), the industrial sector (9 percent), while the balance is used for non-energy uses (chemical feedstock), or is wasted in technical and non technical losses. Gas usage in the industrial sector remains modest, including in the above three countries. 3.8 Natural gas accounted for 27 percent of the overall hydrocarbon demand. The share of gas in the demand may vary significantly. In Angola, Cote d'Ivoire and Nigeria, gas accounts already for one-third and above of total demand, in particular due to power generation. Traditional Gas Markets 3.9 Traditional gas markets (residential and commercial sector; conventional industry) in Sub-Saharan Africa are, and will remain, narrow. The potential demand of the residential and commercial markets is limited to domestic uses (cooking and water heating), which makes the profitability of dedicated gas networks unlikely. While gas requirements in the conventional industrial sector are not negligible, they are concentrated in a limited number of cities where the size of the industrial market has reached the critical mass that could trigger distribution projects. Gas demand development should thus be driven by more recent applications which have either already started to be implemented in Africa, such as gas-based power generation, or which still are under development with a high potential in Africa, such as gas-to-liquids. 8 Oil exports minus oil imports (includes crude oil and petroleum products). 9 Domestic demand, i.e. exc. bunkers. 22 Africa Gas Initiative: Main Report Table 3.2: Oil and Gas Demand and Supply in SSA Oil and Gas Countries Domestic Net Gross Domestic Percent of Oil Oil Oil Products Gas Gas in Demand Imports'° Imports Demand Commercial (mt) (mt) (mt) (mtoe) Energy Demand Angola 1,117 62 613 35 Cameroon 816 14 Congo, Republic of 317 5 4 1 Cote d'Ivoire 1,259 537 302 619 33 Ethiopia 745 383 472 Gabon 609 209 89 14 Ghana 1,134 894 183 Mozambique 672 702 702 Nigeria 9,265 40 5,261 36 Senegal 1,134 709 399 26 2 Tanzania 584 560 171 Sub-Saharan Africa 17,573 3,785 2,559 6,612 27 (11 countries) South Africa 17,871 12,616 Source: IEA: Energy Statistics of Non-OECD Countries, 1997 (1999 Edition), exc. gas in Cote d'Ivoire. Residential and Commercial Sector 3.10 Like in many developing regions, climatic conditions in Sub-Saharan Africa do not favor the economic operation of urban gas networks dedicated to supply the residential and comrnmercial market. Such networks have developed in only two countries, South Africa and Cote d'Ivoire, and they are currently declining. Gas networks were first developed in Johannesburg, Cape Town and Port Elizabeth by municipal utilities to provide households with town gas for cooking, based on the distillation of the country's abundant, cheap coal. Lack of appropriate maintenance along with increasing operating costs led operators to pull out of the town gas business, which only remains to a limited extent in these cities. In Abidjan, a private operator took a different route and built a residential network in the 1970s to supply piped LPG for cooking and water heating. In spite of high distribution cost the operation proved successful and supplied up to 12,000 households and commercial establishments at its peak. There again, insufficient maintenance effort led the system to progressively decay while increasing payment arrears made the operation unmanageable. It is no longer considered suitable for operation. 3.11 The main issue with residential gas distribution in warmer regions is the limited gas demand required by households. Cooking and water heating demand (called "base load") typically account for around 300-400 cubic meters of natural gas on a yearly basis (30-40 cfd), which is low in comparison with any demand that includes space heating. In the base load market, gas would mainly compete with bottled LPG. Based on a typical economic cost of USD 1 0/mmbtul 1, the second best option (here LPG) would '° Includes crude oil and oil products. I" Bottled, delivered at user's gate. USD 10/mrnmbtu is equivalent to USD 480/ton. Natural Gas: Building New Markets 23 generate a yearly bill of USD 120-150 per household for the typical demand mentioned above. Considering that the construction cost of a gas network would typically range between USD 500 and 1,000 per household - in particular in low density residential areas where construction and maintenance costs are higher -- such revenue would prove insufficient to enable the gas operator to repay the capital expenditure of the system, and to operate and maintain it in a sustainable manner, unless customers are willing to pay a very high premium for the uninterrupted availability and readiness of piped gas. 3.12 Since there is no need for space heating, the only option to increase gas demand would be to develop the use of gas for air conditioning. There, the main competitor is high cost electricity. Gas could compete, with reasonable chances of success, in new commercial buildings, such as office buildings, hotels and hospitals. Gas-based air conditioning technology, however, has developed mainly in North America and Southeast Asia, and it is not widely known and used in other regions. The introduction of gas-fired appliances would thus require a strong promotional effort from specialized dealers, and it is expected to be costly. In addition, individual appliances (for houses and small commercial establishments) are significantly more expensive than those based on electricity, which makes their penetration in the market more difficult, even where the cost of gas is lower than that of electricity. Conventional Industry 3.13 While the gas industry started worldwide in the mid-1850s with the construction of large town gas networks dedicated to street lighting and home cooking, the massive development of natural gas began one century later when the medium and large-scale industry considered substituting gas for heavily polluting coal and high sulfur fuel oil (HSFO). In almost every single industrial branch, gas has become in less than three decades the preferred fuel in those activities where cleanliness, flexibility and easy use are key factors to ensuring high quality output while bending operating costs. This is the case in such industries as food processing and refrigeration, vegetal oil processing, ceramic and tiles, glass and metal surface treatment, all industrial branches that usually constitute the mainstay of industrial activities in larger African harbor-cities. 3.14 On average, the industrial sector accounts for 27 percent of the final energy demand of SSA's gas countriesl2, a figure equivalent to that of the residential and commercial sector, about half of transportation requirements. Natural gas already represents a fairly high share of industrial demand, due to the weigh of Nigeria in the SSA's overall industrial demand. Where gas is not developed, the industrial demand is met by electricity and oil, while coal is virtually absent from the fuel mix, except in South Africa. Due to high cost - and sometimes limited availability -- electricity is called mainly for these applications where using fossil fuels or steam is not technically feasible, e.g. to drive motors, and for specific utilization. 12 In conunercial energy of the 11 gas countries listed in table 3.4. Does not include South Africa. 24 Africa Gas Initiative: Main Report Table 3.3: Final Energy Demand in the Main Consuming Sectors'3 Final Share of Share of Energy Demand Total Demand Industry (mtoe) (f/) Demand (O%) Industry 5,425 27.2 100.0 Oil Products 1,544 7.8 28.5 Natural Gas 1,344 6.8 24.8 Electricity 2,513 12.6 46.3 Coal 24 0.1 0.4 Transportation 8,977 45.1 Residential & Commercial14 5,510 27.7 Total 19,912 100.0 Source: IEA: Energy Statistics of Non-OECD Countries, 1997 (1999 Edition) 3.15 The main issues in developing industrial gas networks in Sub-Saharan metropolises deal with the size of the market on the one hand, and the constitution of the fuel mix, which gas will have to compete with on the other hand. Some discrepancies between statistical sources may make it difficult to get a clear picture of the detailed breakdown of the sectoral demand of energy products. In particular, it generally proves uneasy to allocate middle distillates (gas oil and diesel oil) to either industrial usage or transportation. Pre-feasibility studies conducted within the preparation of industrial gas networks projects in Abidjan and Douala evaluate the gas potential market at 80,000 and 45,000 toe in the medium term, respectively. Preliminary estimates for smaller industrial markets, such as Gabon (Libreville and Port-Gentil, where gas is already in use) and Congo (Pointe Noire) result in potential markets ranging between 4,000 and 10,000 toe. 3.16 Most of the industrial demand is currently met by fuel oil. Table 3.4 presents the industrial demand of some fuels used by. the industrial sector in SSA gas countries on the one hand, and the overall oil demand of the sector on the other hand, based on the latest IEA statistical data. In most SSA gas countries, fuel oil is used to a large extent in the industrial sector, due to the high share of hydro in power generation. Also, thermal power generation is typically required for peak shaving purposes, or to supply remote, non-interconnected networks, which is usually achieved through diesel oil-fired gas turbines or reciprocating engines. It is thus believed that most of the fuel oil demand is actually consumed by the industrial sector. The picture is quite different for diesel oil where demand is believed to be used to a large extent for transportation. 3.17 In the beginning, natural gas has to compete mainly with fuel oil, a relatively low cost energy source, which does not enable natural gas to take full advantage of its intrinsic qualities. Standard burner-for-burner conversion gives natural gas only a limited premium over fuel oil, based on slight improvements in burner efficiency, maintenance cost and increased lifetime of the equipment. In steam raising 13 Only conmercial energy. 14 Including agriculture Natural Gas: Building New Markets 25 uses, the premium does not go beyond a few percent. In high temperature uses, e.g. furnaces and kilns, the premium may be higher, but it seldom exceeds 7-8 to percent, unless the thermal process is somewhat modified. Plain substitution thus restricts competition between gas and oil close to the "per btu" value of each fuel. 3.18 In older gas countries, efficient gas-dedicated equipment has progressively replaced conventional, energy-intensive processes, and such historical process is expected to be similar in SSA countries. As an example, the direct use of the flame often enables the plant's operator to replace, totally or in part, steam or hot water by gas as the plant's primary energy carrier, thus to get rid of heat exchangers, which reduces significantly the overall heat losses. In addition, natural gas flexibility allows for fine- tuning the heat supply, which benefits both the quality of the output and the global efficiency of the thermal process. Table 3.4: Oil Demand by the Industrial Sector in SSA Gas Countries Fuel oil (a) Middle Other Oil Total Oil (mrty) Distillates (b) Products (c) Products (mty) (M ty) (M ty) Angola 15 15 Cameroon 49 49 Congo, Republic of 4 4 Cote d'Ivoire 62 71 8 141 Ethiopia 73 30 103 Gabon 32 86 10 128 Ghana 53 38 12 103 Mozambique 10 1 11 Nigeria 710 40 750 Senegal 85 50 135 Tanzania 105 105 Sub-Saharan Africa 1,173 325 46 1,544 (11 countries) South Africa 350 859 135 1,344 Source: IEA, Energy Statistics and Balances of non-OECD Countries in 1997 (1999 Edition). (a) Includes power generation. (b) Gas oil, diesel oil and kerosene. (c) LPG and feedstock. Power Generation 3.19 In the recent years, power generation has become a major potential market for natural gas. In emerging gas industries, including a gas-based power plant is often the pre-requisite for a gas project to take off, as the successful gas history of Cote d'Ivoire has recently highlighted. Natural gas can play a role either as a substitute to currently used liquid fuels, or as a means to increase installed capacity through diversification, where required. A considerable market exists, simply expressed by the fact that 92 percent of the 610 million people living in Sub-Saharan Africa have so far no access to electricity. 26 Africa Gas Initiative: Main Report 3.20 One of the most efficient ways to build up a gas market is thus to focus on the fuel requirements of the power generation sector. With regard to the existing potential market, power plants are often large consumers of petroleum products, compared to industry, even in those countries where hydro power prevails, i.e. most of Sub-Saharan AfricalS. Their level of demand, except for peak shaving purposes, is for the most part stable throughout the year, which helps keep gas production cost low. In conventional power stations, gas can displace liquid fuels in steam turbines or reciprocating engines. Such market, however, is often limited by the real quantities of oil products actually consumed by thermal generation, as well as by the location of thermal power plants. Even in countries where thermal capacity accounts for a notable proportion of the total installed capacity, thermal plants are often used at a low load factor, due to the high cost of fossil fuels or to the poor operating condition of the units. 3.21 In many SSA countries where rainfalls have been erratic and droughts more frequent, diversification in power generation appears critical. Power outages are a common feature in Sub-Saharan Africa, although part of them are attributable to transmission and distribution failures rather than generation conditions. Hydro projects, besides the limited -- and shrinking -- capacity of existing public institutions unable to finance new projects, are environmentally risky and no longer economically viable. They have proved unable to provide acceptable service under severe climatic conditions, and cash-short power utilities have no longer the resources to correctly maintain back-up thermal facilities, set alone promoting new hydro schemes. 3.22 Since the mid-nineties, improving technology coupled with sharply decreasing construction costs have made gas-based power generation facilities the most efficient option to develop additional capacity, whether for base load or peak shaving. Techno-economic achievements are tremendous: the efficiency of combined cycle power plants now is close to 60 percent, almost 15 percent up from where it stood ten years ago. In the mean time, costs are plummeting due to increasing standardization of materials, as more equipment is available "off the shelf'. Cost per kW of installed capacity is now as low as USD400-500 for combined cycles, from nearly twice as much in the beginning of the decade. In addition, the wide range of capacities available, the flexibility of the implementation schedule due to modularity, and short construction time make these technologies well adapted to emerging economies that are characterized by limited market base and slow to moderate growth rates. 15 With notable exceptions, such as South Africa. Natural Gas: Building New Markets 27 Table 3.5: Electricity Demand and Supply in SSA Gas Countries Elecfricity Production Production from Net Demand from Hydro Fossil Fuels Imports (GWh) (GWh) (GWh) (GWh) Angola 794 1,006 103 0 Cameroon 2,517 3,092 36 0 Congo, Republic of 541 425 6 114 Cote d'Ivoire 2,727 2,022 1,191 34 Ethiopia 1,325 1,170 66 0 Gabon 906 740 267 0 Ghana 5,745 6,148 7 (397) Mozambique 893 791 214 203 Nigeria 10,350 5,593 9,586 0 Senegal 1,050 0 1,261 0 Tanzania 1,700 1,449 485 44 Sub-Saharan Africa 28,548 22,436 13,222 (2) (11 countries) South Africa 187,646 4,700 193,005 (6,612) Source: IEA, Energy Statistics and Balances of non-OECD Countries in 1997 (1999 Edition). Figures between brackets indicate net exports. 3.23 Building up gas infrastructure will involve institutional and regulatory changes, leading to adequate power for consumers and inviting contributing independent power producers (IPPs). In the process, indigenous companies can learn more about changes in the industry, by joining forces with new entrants. The recent growth of IPP's willing to work outside their traditional areas is expected to contribute to increased gas demand. In addition, IPP's prefer gas-fired plants which are modular in structure, are cheaper than conventional plants, have shorter lead times and show higher efficiency. Results from around the world show that the power sector is generally the key to developing a natural gas infrastructure. While other sectors are also important in developing this infrastructure, industry experts agree that the gas purchase contract by the power generator is the key to securing financing and getting the project off the ground. Once available, gas then becomes attractive to other potential users, both for its physical and intrinsic qualities as well as for its comparative advantages. 3.24 In countries where gas is not available, gas trade (and gas-based electricity trade) is an adequate answer, as a regional market approach can help excess capacity here meet suppressed demand there. In addition to providing basic electricity supply to those countries that are not endowed with gas resources, energy trade constitutes a reliable back-up for hydro-supplied countries. It, however, requires technical and institutional coordination as governments have a role to play in opening markets in a sector which is still often regarded as strategic. 28 Africa Gas Initiative: Main Report Gas-to-Liquids 3.25 The production of liquid fuels from a different prir ~ry energy source is nowadays based on a well-known technological process from Uerman origin (the Fischer-Tropsch [F-T] synthesis) that dates back to the early 1920s16. As long as the price of the barrel remained moderate, i.e. until the late 1970s, synthetic oil ("synfuel") was mainly produced out of coal in a few large-scale operations located in countries where access to oil was restricted. Although a proven technology, the development of the process was hampered by adverse economics caused by huge capital investment and poor overall efficiency, in particular in coal-based operations. Nowadays, technical improvements, in particular with regard to catalysts, are concurring to improve global economics and to limit the effect of economies of scale, thus downscaling the threshold above which production units may become competitive. 3.26 Typical technology includes a three-step process that produces subsequently synthesis gas; a mixture of straight chain hydrocarbons; and the final, desired product(s). Specific technologies of each component vary according to operators. The first step is common to the production of several other chemical products, including methanol and DME17, as well as the reduction of iron ore. It consists in producing synthesis gas - a mixture of carbon monoxide (CO) and hydrogen - that will serve as a feedstock for the second reaction. For this first step, natural gas has increasingly become the preferred primary fuel due to easy handling and increased efficiency over coal. In spite of better efficiency, the production of synthetis gas (syngas) still accounts for the larger share of the plant's cost - up to 60 percent. 3.27 In the second step, the F-T synthesis converts synthesis gas into hydrocarbons of varying chain length and molecular weights. It is a catalytic reaction (usually iron or cobalt) that by-produces water and carbon dioxide (CO2), along with considerable amounts of heat that can be used to generate electricity through a steam turbine, thus enhancing the overall efficiency of the process. In the final step, products released by the F-T reaction are upgraded to release either light synthetic crude oil ("syncrude"), or middle distillatesl8 such as diesel oil / gas oil, associated to kerosene and naphtha. 3.28 The production of diesel oil is of particular interest in SSA where demand from both transportation and industrial sectors is increasing at a fast pace that exceeds the capabilities of local refineries. Moreover, synthetic diesel oil is a high-quality product that has a very low sulfur and aromatic content, a high octane index and contains fewer particulates; it bums very cleanly in a compression-ignition engine, which gives it a strong environmental premium. 3.29 Table 3.6 presents the middle distillates (gas oil and diesel oil) supply and demand patterns in eleven gas countries in 1997. Figures show that imports are more 16 Another route converts gas to methanol, then to liquid hydrocarbons. Commercialized by Mobil in New Zealand in the 1980s, it is considered not economic and the plant was shut down. i7 Dimethyl-ether, an aerosol propellent. 18 Along with high quality specialty products, e.g. waxes and lubes. Natural Gas: Building New Markets 29 than three times higher than exports, and represent 22 percent of domestic demandl9. All countries (exc. Nigeria and Congo) are net importers of middle distillates, including those countries where refineries are operated. Assuming that all exports from oil refining countries are directed to countries within the region, it can be roughly estimated that regional imports from outside SSA account for at least one-sixth of domestic demand. Table 3.6: Gas Oil/Diesel Oil Demand and Supply in SSA Gas Countries (1997) Domestic Production Exports20 Imports Demand (mt) (mt) (mt) (mt) Angola 262 486 50 56 Cameroon 331 385 7 7 Congo, Republic of 82 92 10 Cote d'Ivoire 573 484 99 Ethiopia 136 116 28 49 Gabon 298 162 137 Ghana 390 315 101 Mozambique 296 26421 Nigeria 1,294 3,002 16422 27 Senegal 322 242 9 104 Tanzania 237 148 12 102 Sub-Saharan Africa 4,221 5,432 280 946 (11 countries) South Africa 4,804 5,147 Sources: IEA, Energy Statistics and Balances of non-OECD Countries in 1997 (1999 Edition). 3.30 At 50 percent efficiency - the level currently reached by GTL technology -- it takes 10,000 cf of natural gas to produce 1 bl of synfuels. A small-scale unit (5,000 bpd - 200,000 tons per year, i.e. the production level required by African economies) thus requires 50 mmcfd of gas, i.e. an amount of gas equivalent to that consumed by a 350 MW combined-cycle power plant running on base load. With as low as 0.5 tcf (14 bcm) of recoverable reserves, a gas field may supply such a production unit for 25 years. 3.31 The major issues are that construction and operating costs remain high, and the number of real-size projects is limited. High-cost GTL plants operate in South Africa (Mossel Bay) and Malaysia (Shell, at Bintulu), while plans for large-scale plants exist in Australia and Qatar. The large-scale unit built by Mobil in New Zealand has been shut down. Developers of GTL technology claim that small-scale units can show positive economics with production levels as low as 2,000 to 5,000 bpd of oil products. 19 Important smuggling, in particular from Nigeria to neighboring countries, is likely to distort official demand and supply figures in the sub-region. 20 Not including international marine bunkers. 21 Not including 33 mt of "transfers" (considered unofficial imports through smuggling). 22 Not including 1,491 mt of "transfers" (considered unofficial exports through smuggling). 30 Africa Gas Initiative: Main Report These promoters, however, such as Syntroleum and Rentech, develop technology and sell licenses to oil companies, but they do not have the financial power that could enable them to take the risk to develop projects on their own without the support of an oil company. This is a major reason why no full-size, small-scale project has been built and operated so far. 3.32 Although developers estimate that full-scale commercial projects can be built for as low as USD 18,000 to 22,000 per barrel of daily capacity, the lowest capex to date of a commercially-run unit amounts to USD 30,000 per bpd. Based on such assumptions23, a recent Esmap-sponsored study24 shows that a GTL plant should have a capacity of 20,000 bpd to economically produce diesel oil at USD 22/bl (i.e. crude oil at USD 16-17/bl), using gas delivered at USD 0.60/mmbtu. 3.33 In Africa, however, the global economics of GTL projects may prove much more attractive than in large oil producing or consuming countries. CIF costs of oil products in SSA are high, in particular when they are imported, due to costly freight applied to the small cargoes required by African markets. In western Africa, the demand already exceeds the production of the regional refineries, so that the sub-region has become a net importer of middle distillates, in particular diesel oil and jet fuel. To meet growing traffic needs, three conventional options can be considered: (i) the expansion of the capacity of existing regional refineries; (ii) the construction of hydro-cracker(s) in these refineries to increase the output of middle distillates out of fuel oil in excess; and (iii) additional imports. The first two options require huge amounts of capital, and the decision may depend on several factors, the demand of middle distillates being only one of them. All three options require to either allocate to domestic markets additional quantities of crude oil that could be sold on the international market (in oil surplus countries), or to increase the dependence on imported energy (in oil deficit countries). 3.34 To develop GTL units based on local gas fields is an attractive alternative, provided that crude oil is in the range of USD 20-24/bl - or above. Table 3.8 shows that, based on data available in the industry, a small-scale GTL plant (5,000 bpd) can produce diesel oil / gas oil under economic conditions as soon as crude oil is over USD 21.60/b1, where gas is available at plant's gate at a reasonable USD 1.00/mmbtu. Due to higher freight costs (see above paragraph) the diesel / crude index for Africa that expresses the ratio of the spot price of diesel / gas oil delivered to African markets, to the price of crude is considered higher (140) than that generally admitted for larger cargoes. 23 CapEx: 30,000 USD/bpd; discount rate: 15 percent; lead time: 3 years. 24 Commercialization of marginal gas fields, December 1997. Natural Gas: Building New Markets 31 Table 3.7: Gas Oil/Diesel Oil Demand in Selected SSA Countries (1990-1 997)(mt) Yearly 1990 1992 1994 1996 1997 Increase (%o) Angola 86 90 85 127 262 17.3 Cameroon 347 300 317 318 331 -0.7 Congo, Republic of 98 80 84 82 82 -2.5 Congo, Democratic Rep. 328 301 339 341 341 0.6 Cote d'Ivoire 339 338 533 552 573 7.8 Gabon 163 176 174 232 298 9.0 Ghana 275 294 394 390 390 5.1 Kenya 592 599 564 674 662 1.6 Mozambique 210 234 230 230 296 5.0 Nigeria 1,396 2,280 1,596 1,278 1,294 -1.1 Senegal 213 250 245 258 322 6.1 Tanzania 207 195 195 201 237 2.0 Sub-Saharan Africa 4,254 5,137 4,756 4,638 5,088 2.6 (12 countries) Sources: IEA, Energy Statistics and Balances of non-OECD Countries in 1997 (1999 Edition). Table 3.8: Main Characteristics of a Small-scale GTL Plant Unit Characteristics Nominal output capacity bpd 5,000 CapEx per bpd of capacity USD 30,000 O&M cost, not including natural gas USD/bl 7 Natural gas demand mmcfd 50 Natural gas demand over 20 years Tcf 0.34 Cost of gas at plant's gate USD/mmbtu 1.00 Cost of diesel oil produced USD/bl 30.30 Diesel oil / Crude oil index (SSA) 140 Opportunity cost of crude oil USD/bl 21.60 Sources: Esmap study (mentioned above); own assumptions. Discount rate ( 12 percent. 3.35 Where gas is cheaper, e.g. if the GTL plant is located next to a gas field, which requires no transmission line, then the plant is economic as soon as crude oil is above USD 1 8/b1. Conversely, crude oil needs to be quoted at a minimum of USD 25 if the cost of gas reaches USD 1.50/mmbtu. The variation of other parameters tend to increase (or decrease) the cost of the output by up to 13 percent. 32 Africa Gas Initiative: Main Report Table 3.9 - Sensitivity Analysis Production Cost of Relevant Price of Diesel / Gas oil Crude oil (USD/bl) (USD/Ibl) Base Case Scenario25 30.30 21.60 CapEx + 15 percent 32.30 23.10 CapEx + 30 percent 34.30 24.50 CapEx - 15 percent 28.30 20.20 Natural gas ( USD 1.50/numbtu 35.30 25.20 Natural gas ( USD 0.50/nimbtu 25.30 18.10 Discount rate @ 15 percent 33.30 23.80 Delivery cost of products @ USD 3/bl 33.30 23.80 25 See Table 3.8, with discount rate @ 12 percent; no delivery cost of products. 4 LPG A Fuel Too Long Overlooked 4.1 Through ESMAP, the World Bank has been very active for almost two decades in promoting efficiency in the household energy sector. Significant efforts have been dedicated to improving the production process and the use of biomass, in particular charcoal, and of some basic commercial fuels such as kerosene. However, LPG was long regarded -- and not only within the Bank -- as , which must comprise three bodies of regulations : (a) a basic law, which defines the major principles of the regulations, with respect to competition and pricing policy, and which is complemented by a series of decrees and / or acts governing its implementation; (b) a model act (whether law or decree) governing the legal relationship between the authority granting the concession and the concessionaires; and (c) a law that sets out the tasks, nature and working methods of the authority responsible for implementing the Code and ensuring its lawful application by the regulated operators and by the government. 5.4 More specifically, the Gas Code should govern the following: * the organization and structure of the gas industry, - the organization of competition among operators and of market access, - operators' legal framework, that is the relationship between the authority granting the concession and the concessionaires, - price-setting, price monitoring and price adjustments over time, that is the principles governing payment of operators, - the exercise of legal power to resolve conflicts between parties involved in gas-industry activities, - the nature, tasks and working methods of the regulatory authority (the Regulator) responsible for implementing the Gas Code. Organization and Structure. Competition and Market Access 5.5 It is intended that gas regulations should endure. They should cover not only prevailing circumstances, i.e., the de facto transmission and marketing of gas, but also circumstances that may exist in the future, whether in terms of activities already envisaged, such as the distribution and export of gas, or those that are technically feasible, such as gas imports or storage. With regard to transmission, the <> solution may be the best option. Under this system, the operator is granted a concession for a specific location and a specific period of time, and there is no one single transmission concession for the nation as a whole. The operator conveys gas on behalf of others (whether sellers or buyers), and is paid in the form of a toll, rather like a freeway operator. He may also buy gas for his own account, and sell it on to his own customers (large consumers, distributors). These two activities, transmission and marketing, are carried out in an equitable manner, and pricing and accounting mechanisms are open to the public. Excess capacity at the gas pipeline is made available to other buyers or sellers, who may borrow the pipeline at a non-discriminatory price. The operator may not refuse to convey gas in his pipeline, as long as it is not over capacity. Institutional and Regulatory Matters for Gas 45 5.6 The distributor will enjoy a monopoly, in terms of physical location and time, over the area for which he has been granted a concession. This monopoly applies to the distribution of gas, but not to its marketing. A seller (producer or transporter) may sell gas directly to his clients, but may not construct and exploit a pipeline for his own account or on behalf of his clients. He must operate through the distributor, who pays him a non-discriminatory toll, while the distributor, for his part, may not refuse to distribute gas on behalf of others as long as his network is not threatened. Similarly, he may not refuse to construct a pipeline, for which he will receive a toll based upon real construction and operating costs. 5.7 In a largely decentralized organization such as that proposed, operators should be as independent as possible, and should not violate the territory of another operator. In this way, conflicts of interest and anti-competitive practices will be avoided. For example, producers or buyers (or groups of buyers) may not have a controlling interest in a transporter. If this were the case, they might enjoy an unfair advantage over other parties, with respect to conveying the gas. Similarly, a transporter controlled (for exanple) by a producer might be required to adhere to the producer's strategy, rather than pursue the logical path of any transporter, which is to build up his network and thus expand his market. Economic Regulation 5.8 Regulation should apply to those components of the gas chain that are natural monopolies. This covers gas transmission and distribution (for oil products, including LPG, it might include bulk storage where a monopoly, or a tight oligopoly is in place at country level). Conversely, the price of gas as a commodity usually does not require regulation as gas has to compete with other energy products and doers not enjoy any monopoly situation. As for most other goods and services, price regulation is thus achieved by the market itself and prices should be negotiated between the seller and the customer. For this reason, the AGI recommends that transmission and distribution tariffs, not end-user prices, be regulated. 5.9 Tariff policy (which includes both structure and levels) is the affair of the operators, who set their tariffs according to their expected investments, costs and resources. But tariff policy should controlled and approved by the regulating authority (the Regulator), who, in particular, sets a cap on the tariffs proposed by the operators in order to avoid the abuse of monopoly situation. Indeed, this is among the Regulator's main tasks. In addition to the examination of the operator's development and resource plans, one of the main criteria for setting tariffs is the way in which tariff regulation is carried out. There are several ways of regulating tariffs, and the underlying principles and regulatory techniques are similar for the transmission and distribution of gas. 5.10 In the case of a new gas industry, the best model is that of regulation by cost of service. Tariffs are fixed in such a way as to enable users to obtain the service they need at a reasonable cost, and to enable investors to recover their costs and earn an acceptable return in terms of the capital they have invested or the risk they have incurred in constructing or taking on a gas pipeline or distribution network. Tariffs are determnined 46 Africa Gas Initiative: Main Report according to the expected gas output levels and volumes to be conveyed by the network in question (control of resources), and the overall cost of the activity (cost control). Also included in the calculation are interest charges on debt repayments, operating costs, tax charges, expected costs for renovation and expansion, and capital amounts to be repaid to investors. Compatibility with Government Policy 5.11 Whenever a concession is being sought, the Regulator reviews the professional and financial credentials of the candidates and advises the Department responsible for granting the concession (wherever the Regulator itself is not the responsible authority). The Regulator studies the operator's development and resource plans, and gives its assessment of those plans - an assessment which may include rejection of the plans or a request that they be modified. The Regulator will also ensure that the plans submitted for its review are compatible with the level of gas resources (national or potentially imported) and that the plans do not conflict with govemment strategy on the exploitation of the nation's national resources (or with their conservation and harmonization, wherever these are relevant concerns). This latter point is particularly important with respect to gas-export projects. Regulatory Authority (the Regulator) 5.12 Within the classic institutional framework (in SSA, i.e. based on public ownership), the govemment, as the embodiment of political power, plays a three-fold role - a policy role (by defining long-term strategies and goals and by controlling the selection of senior staff); a financial role (by controlling - and sometimes setting - the budget, setting prices, and granting concessions); and a technical role (by defining standards for the use of machinery and equipment). The major problem with this type of framework is that it makes no clear distinction between political concerns, on the one hand, and business concems, on the other, nor does it distinguish between the execution of tasks and its own controlling function. It is legitimate that a company operating in an area involving the notion of public service should adhere to strategic guidelines defined upstream at a political level. But the political intervention should cease at that stage, so that day-to-day management may be performed on an independent basis. 5.13 The best way to resolve these problems is to entrust the non-strategic aspects of regulation to the most independent entity possible. This is particularly important when it comes to setting and monitoring both pricing policy and the prices themselves. The role of the Regulator is to implement the Gas Code and ensure that it is applied. Although there is no typical model to be found in a majority of those countries that have this kind of Regulator, there is a certain consensus as to how powers and responsibilities should be shared out between political institutions and the Regulator. One can clearly discem a (