I J~ X Report No. 79!3-AR Argentina Energy Sector Study (In Two Volumes) Volume 1: Executive Summary and Main Text February 26,1990 Infrastrtcture and Energy Operations I Country Department IV Latin America and Caribbean Regional Office ! FOR OFFICIAL USE ONLY , ,' . --'Is Doumn of th Wo'; Ban'k . ¢,'' IN E I~~~~~~ Documen of the World Bank.. This document has a restricted distribution and may be used by recipients only in the perfornance of their official duties. Rts contentsnmay not otherwise be disclosed without World Bank authorization. _ ! CURRENCY EQUIVALENTS Currency Units Austral (A) per US$ Commercial Free Exchange Exchange Rate Rate 1985 IVQ 0.80 0.89 1986 IVQ 1.15 1.37 1987 IVQ 3.41 4.18 1988 IQ 4.37 5.84 IIQ 6.79 8.35 IIIQ 11.2 13.5 IVq 12.7 15.4 1989 IQ 14.7 27.9 IIQ 135.9 229.1 IIIQ 611 654 IVQ (prelim.) 797 966 Energy Conversion Factors TOE/Metric Specific Tonne Gravity LiterslTonne 1,PG 1.06 0.56 1,785 Gasoline 1.03 0.72 1,351 Kerosene 1.01 0.80 1,240 ATF (Aviation Fuel) 1.01 0.80 1,240 Diesel/Gas Oil 1.00 0.85 1,176 Fuel Oil 0.94 0.96 1,041 1.0 TEP = 1.0 TOE = 10.2 X 106 kcal = 40.5 x 106 BTU 40,500 cubic feet; 1.0 GWh = 86 TOE, 1.0 kWh - 860 kcals (net calorific values, note that net calorific values are 5% less than gross for oil and 9 to 102 less than gross for gas). There are 6.29 bbl per cubic meter (CM) of oil. Conversion Factors for Gas 1.0 MCF (Thousand Cubic Feet) - 1.0 MMBTU (Million B:.tish Thermal Units) 38,500 CF = 1.0 tonne fuel oil 0.12 MMCDF - 1.0 tonnes of fuel oillyear 35.3 MCF = 1.0 CM (cubic meter) Particular Conversion Factors for Energy Balances KCAL/CU M TEP/CU M CU M/TEP CU M/1000 TEP Gas Dry 8,300 0.83 1,205 1204.82 Nat. Gas, in field 9,000 0.90 1.111 1111.11 Liquid Gas 5,880,150 588.02 1.701 1700.64 Crude Oil 8,850,000 885.00 1.130 1129.94 Gasolines 7,607,250 760.73 1.315 1314.54 Intermediates 8,517,000 851.70 1.174 1174.12 (Diesel, Gas-oil) Fuel Oil 926,1000 926.10 1.080 1079.80 KWH/TEP 11.62 FOR OFCML USE ONLY GLOSSARY OF ABBREVIATIOSS AND ACRONYMS AyE Agua y Energla Electrica S.E. (federally-owned, nationwide electric utility and water supply agency) Bbl Barrel bpd Barrels per day CM Cubic Meter CNEA Comision Nacional de Energla Atomice (National Nuclear Energy Commission) CTMSG Comision Tdcnica Mixta del Salto Grande (Argentine/Uruguayan Commission in charge of the Salto Grande DEP Directorio de Empresas Pfblicas (Public Enterprises Directorate) DUC Despacho Unificado de Cargas (National Electric Power Dispatch Center) EBY Entidad Binacional Yacyreta (Argentine/Paraguayan entity in charge of the Yacyreta Hydroelectric Plant) EFEE Empresa Federal de Energia Electrica (Federal Enterprise of Electricity) FC Fondo de Combustibles Liquidos (Liquid Fuel Fund) FCCC Fondo Chocfn Cerros Colorados (Choc6n Fund for Cerros Colorados) FEDEI Fondo Especial para el Desarrollo El#ctrici del Interior (Special Fund for Hinterland Electric Development) FNE Fondo Nacional de Energia (National Energy Fund) FNEE Fondo Nacional de Energia Electrica (National Electric Energy Fund) FNGOE Fondo Nacional de Grandes Obras El4ctricas (National Fund of Major Electric Works) GdE Gas del Estado gState Gas Company) GOR Gas to Oil Ratio HIDRONOR Hidroelectrica Norpatag6nica (Federally owned, electricity generation utility) LPG Liquified Petroleum Gas MCF Thousand Cubic Feet ME Ministerio de Economia (Ministry of Economy) i ~~MMBTU Million British Thermal Units [ MMCFD Million cubic feet per day (gas) | MMCMHMillion cubic meters IMH.OSP Ministerio de Obras y Servicios P6blicos (Ministry of Works and Public Service) PFE Pacto Federal Electrico (Federal Electric Pact) I PEN Poder Ejecutivo Nacional (National Executive Authority) | SE Secretaria de Energia (Secretariat of Energy) SEBGA Servicios Electricos del Gran Buenos Aires (Federally owned, electric utility serving the Buenos Aires metropolitan area) TCF Trillion Cubic Feet TEP Tonnes Petroleum Equivalent TOE Tonnes Oil Equivalent YCF Yacimientos Carboniferos Fiscales (State Coal Company) YPF Yacimientos Petroliferos Fiscales (State Oil Company) This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without Wor!d Bank authodzation. PREFACE This report is based on World Bank missions which visited Argentina in Noveuiber/December, 1988 and March 1989, comprised ofs Dale F. Gray (Mission Leader, Economist) Fernando Zuniga-Rivero (Petrolewm Specialist) Hernan Garcia (Power Engineer) John Stoddart (Financial Analyst) William Simmons (Consultant - Petroleum Geologist) Guillermo Perry (Consultant - Economist and Tax Specialist) Carlos Givogri (Consultant - Economist) Tom Joyce (Consultant - Gas Specialist) Tom Steigervald (Consultant - Refinery Specialist) Preliminary conclusions in a draft report were discussed with the Government in March 1989. The Green Cover report was issued in August 1989. Discussions were held in October and December 1989. Between July and December 1989 the Government took significant measures to reduce subsidies, increase prices and deregulate the oil and gas sector. Many of the measures were along the lines recommended in the draft report and Green Cover report. Written comments on the Green Cover Report, received from the Secretariat of Energy in December 1989, are shown in Annex 11. Descriptions of the reforms are described in this final report (particularly in Chapters III and V) and the recommendations updated to reflect changes as of December 1989. Secretarial Assistance was provided by Margarita G. More. ARGENTINA ENERGY SECTOR STUDY TABLE OF CONTENTS Page No. *EXECUTIVE 5UMHARY A. overview'... ....... . .................. i B. Energy Subsidies, Pricing, and Taxation ........... . v C. Petroleum and Gas Supply.................... xi D. Natural Gas...........................x.v E. Refining Operations .......................xviii. F. Electric Power Sector...................... xx G. Institutional and Regulatory Framework...... ........xxii H. Energy Investment, Planning, Conservation and Environment .. xxiv I. OVERVIEW AND BACKGROUND OF THE EPERGY SECTOR A. Energy Supply and Demund ....................1 B. Energy Sector and the Hacroeconomy............... 5 C. Institutional Arrangements in the Energy Sector..... .... 5 D. Energy Sector Finances..................... 7 E. Past World Bank Participation................. 9 I. ENERGY SECTOR AND THE ECONOMY A. The Energy Sector and Public Finances ............ . 11 B. Evolution of Investments in the Energy Sector......... ... 16 C. Impact of Government Policies and Regulations on Energy Sector Enterprises . . ....................... . ... ..... 18 II. PROBLEMS AND DISTORTIONS CAUSED BY CURRENT SYSTEM OF ENERGY PRICING AND TAXATION A. Introduction ......................... 23 B. Description of Crude Oil and Oil Products Pricing and Taxation .......................... . 24 C. Description of Natural Gas and LPG Pricing and Taxation .... 32 D. Comparison of Natural Gas and LPG to Economic Opportunity Costs........................ 37 E. Description of Electricity Pricing and Taxa on.... ..... 38 F. Financial Distortions in the Hydrocarbon Subsector...... . 41 G. Financial Impact of the Present System of Pricing, Taxation, and Royalties on Finances of State Energy Companies........................... 42 H. Summary of Disencentives and Economic Distortions caused by the System of Pricing and Taxation Existing as of June 1989......................... 45 I. Measures Taken and Proposed Changes from July to December 1989 to Reform the Systez- of Subsidies, Royalties, and Taxation....... ......... .... . ... 47 IV. ENERGY PRICING AND TAXATION SYSTEM REFORM A. Summary of Tax Recommendations .............................. . 52 B. Reform of Crude and Crude Oil Petroleum Products Pricing ..... 54 C. Reform of Natural Gas Pricing System . . . . 55 D. Electricity Pricing ..................... .. 58 E. Integrated Pricing and Taxation . ... 58 F. Fiscal Impact o' the New System ............................. . 62 V. PETROLEUM AND GAS SUPPLY A. Reserves and Production ... . 65 B. Historical Participation of the Private Sector in Exploration and Production (1958 to Mid-1989) ................ 67 C. Production and Operating Costs of YPF ........................ 69 D. Projections of Crude Oil Production .......................... 70 E. Increased Private Sector Participation ....................... 75 F. Improving Efficiency in YPF and GdE Operation ................ 88 VI. REFINING A. Refining Capacity and Operation .............................. 91 B. Improving Efficiency ......................................... 95 VII. NATURAL GAS UTILIZATION A. Introduction ................................................. 99 B. Supply/Demand Projections ... 99 C. Financial and Economic Cost of Supply Gas to Consumers ..... 102 D. Netback Value of Natural Gas ................................. 107 E. Optimization of Natural Gas Use . . . 108 F. The Adequacy of Natural Gas for Power Generation . ....... 109 G. Natural Gas Imports ........................ .... ... 110 H. Natural Gas Exports . . . 110 I. LPG Supply and Marketing8. $ . . .. .11....... I J. Summary of Key Conclusions on Gas Utilization ................ 112 VIII. POWER SECTOR A. Background ................................................... 115 B. The Electric Pcwer Market ........ . ...... 115 C. Sector Development Plan ..... . .18........ l D. Generation Development Options . ..................... 124 E. Operational Issues . . . 128 F. Power Sector Finance . . . 131 IX. ENERGY DEMAND A. Introduction . . .135 B. Past Energy Demand . . .135 C. Energy Price and Income Elasticities of Demand . .136 X. INTEGRATED FINANCES IN THE ENERGY SECTOR. . . 141 ANNEXs (Volume II) Annex 1.0t Official and Adjusted Hydrucarbon Reserves Annex 1.1: Institutional Structure of the Hydrocarbon Subsector Annex 2.0s Taxes, Royalties, and Earmarked Funds Annex 2.1: Public and Private Energy Investment Shares and Growth Rates Annex 2.2, Projection of Foreign Debt 1989-1995 Annex 3.1: Comparison of Prices Annex 3.2: LPG Pricing Annex 3.3: Details of SEGBA's Tariff System Anrnex 3.4: Example of Subsidies and Distortions in the Hydrocarbon Subsector Annex 4.0: Implementation of Deregulation of Crude Oil and Oil Products Prices Annex 4.1: Controlled Transition to a New Natural Gas Pricing System Annex 4.2t Reforming Institutional Arrangements on Gas Production and Transmission Annex 4.3: Cost Based Tariffs for Transmission and Distribution Annex 4.4: Netback to Producers from Reformed Pricing System Annex 5.1s YPF and Service Contracts Annex 5.2: History of Wells Drilled (1977-1988) Annex 5.3: Crude Oil Production History & Refinery Runs (1977-1988) Annex 5.4: Natural Gas Production & Utilization Fistory (1977-1988) Annex 5.5: Production Operating Costs of YPF Administration - Oil & Gas Annex 5.6: Incremental Prod. Costs Annex 5.7: Incremental Net Income Amnex 5.8s Investment Requirements for the Next Five Years Annex 5.9s Hydrocarbon Deregulation Decrees 1055, 1212 and 1589 (all issued fourth quarter 1989) Annex 6.1: Evaluation of YPF and Private Refinery Capacity Annex 6.2: Inefficiencies in Present Refinery Operations Annex 7.1: Average Incremental Cost Calculation for Gas Annex 7.2(a)s Netback Value Calculations for Gas Annex 7.2(b): Petrochemical Sector Annex 7.3: LPG Production by Source t Annex 7.4s Methodology for Calculating Financial Costs Annex 8.1s SE's Energy Plan Electricity Demand Scenario I Annex 8.2s Most-Likely Electricity Demand Scenario Annex 8.3s Low Electricity Demand Scenario Annex 8.4: Electricity Demand Projection - Three Scenarios Annex 8.5: Investment Requirements Under Two Demand Scenario Annex 8.6: Estimated Generation Cost of Hydroprojects Annex 8.7: Installed Capacity by Company by End 1987 (MW) Annex 8.8: Age of Major Thermal Plants Annex 8.9: Scheduled Retirement of Major Thermal Plants Annex 8.10: Evolution of Unavailability of Thermal Plants (NIS) Annex 8.11: SEGBA: Electricity Rates for Residential Consumers in October 1989 Annex 8.12: SEGBAs Electricity Rates for Industrial Consumers in October 1989 Annexes 9.1- Annex 9.5: Energy Balances Annex 9.6: Household Expenditures on Energy Annex 10.1: Projections of Income and Expense 1989-1995 (Individual Companies) Annex 10.2: Projections of Income and Expense (Consolidated) Annex 10.3: Projections of Balance Sheet 1989-1995 (Individual Companies) Annex 10.4: Projections of Balance Sheet 1989-1995 (Consolidated) Annex 10.5: Projections of Source and Use of Funds 1989-1995 (Individual Companies) Annex 10.6: Projections of Source and Use of Funds 1989-1995 (Consolidated) Annex 10.7: Projections of Source and Use of Funds 1990-1995 (Power Clos. and Yacyreta) Annex 11: Written Government Comments received December 1989, on Green Cover Version of Energy Sector Report (dated August 19891. ARGENTINA ENERGY SECTOR STUDY EXECUTIVE SUMMARY A. OVERVIEW 1. Argentina's energy resources are abundant and diverse. They include oil, gas, and hydropower, as well as small amounts of coal and uranium. Since -Q84, over three-fourths of the energy produced was from hydrocarbons; the remainder was provided by hydropower, nuclear biomass, coal, and other sources. These resources have been developed primarily by the state. Inadequate pricing and taxation in combination with distorted investment and regulatory policies have compounded inefficiencies within the state-owned energy institutions, and have resulted in a heavy financial burden on the public sector and a high growth in energy demand. 2. The unusually high energy demand reflects the wasteful consumption that has been encouraged by low consumer prices for electricity, natural gas, and (until the last few years) very low prices for petroleum products. Following the global crude oil price shocks of the early and late 1970s, most countries increased energy prices, which promoted energy conservation. Argentina did not take these measures and therefore unlike many cthers, continues to have an elasticity of energy consumption relative to real GDP greater than unity. 3. The two most notable structural shifts in demand have been the steady increase in final energy consumption of natural gas from 30 in 1960 to 322 in 1985 and the doubling of electricity use. Sixteen percent of final demand for energy in 1985 was electricity, 322 natural gas, 452 petroleum products, and 72 other fuels. These shares have remained basically the same from 1985 to 1988. 4. Energy prices are set by the Government, but without the discipline of linkage to international prices (for hydrocarbon fuels) and marginal costs (for electricity), and the Government has been continually pressured by many special interest groups (private companies, labor unions, the Provinces, public companies, etc.) to receive favorable prices to resolve their financial problems. Unfortunately, Government attempts to accommodate all these interest groups on an individual basis has led to complex, distorted policies for pricing, regulations and taxation. Since energy prices are set and frequently revised by the Government, these interest groups have little incentive to reduce costs or save energy, but instead have a strong incentive to negotiate favorable prices and seek special treatment. 5. Energy prices received by pioducers have not reflected real economic costs or been adequate to cover financial costs. Public energy producing companies have not been able to recover their capital investments, to pay their operating costs, or to receive a reasonable return on invested capital. Although producer prices for energy are low, the higb level of energy taxation (particularly on petroleum products) - ii - tends to force final consumer prices of petroleum products above their economic cost, while most consumer orices for natural gas and electricity remain below ecoramic cost. Energy taxation has been characterized 'i high levels of taxation, ^ complex system of specific taxes, inflexible earmarked funds, and multiple taxation at many stages. This pricing and taxation system has created severe distortions for both producers and consumers, financial problems for public energy companies, and leads to wasteful energy use. 6. Regulatory policies and institutional structure of the energy sector have resulted in overlapping responsibilities of many Government agencies that are involved in operations of the state energy enterprises. This has prevented the development of clear and consistent operational guidelines and has discouraged both public and private entities from pursuing the most profitable activities. Even more importantly, there is no clear separation of the Government's role as policy maker and regulator from its role as owner of public energy enterprises. Lack of such clear institutional arrangements has prevented, and will continue to prevent, slubstantial improvement in the efficiencies of state enterprises, and it has also prevented mobilization of large private sector resources for energy sector investments. 7. Although self-sufficiency in energy has been a long-term major G(-vernment objective, this goal has not been achieved. While production of electricity and natural gas has increased, crude oil production has fallen steadily since 1981. Crude oil production rates in recent years have exceeded additions to t_e resource base, with consequent depletion of this most essential resource to a critical level from which it will be difficult to recover. Significant potential exists to increase crude oil production and find additional volumes of low-cost natural gas; however, fulfillment of this potential is frustrated by low natural gas prices, lack of adequate financial resources, distortions in the regulatory framework that prevent less than optimum private sector investment, and compounded inefficiencies in the state enterprises. 8. Investments in electric power supply to meet rapidly growing electricity demand have been based heavily on hydropower. This strategy has been financially costly because of high capital costs and construction delays in large hydropouier and nuclear projects. The relatively high proportion of hydropower has left the country vulnerable to electrical power shortages during periodic droughts, as occurred this past year. Efforts to control the public sector deficit have compounded the distortions in investments by cutting the smaller, more flexible crude Gil, natural gas, and rehabilitation investments, while continuing to fund large, ongoing hydro power projects. Unfortunately, the result of the energy investment strategy over the last decade has been to increase the share of investments in large, inflexible hydropower generation schemes, which have had low productivity for the macroeconomy, and to decrease the share of investments in crude oil and natural gas exploration and production, which could have provided valuable exports during the period of high world petroleum prices. The past investment strategy has resulted in a high level of foreign debt for the sector (US$13.5 billion at the end of 1988) representing 232 of Argentina's total external dett. - iil - 9. Between July and December 1989 the 'lovernment took a number of bold measures to deregulate the hydrocarbon sector (Decrees 1055, 1212 And 1589) by reducing some subsidies and partially reforming of energy taxation and the system of earmarked funds. 10. The following measures have been enacted or planned to be enacted: a) reduction of excessively high crude oil and natural gas royalty payments to 122 of international value through Law 23696; b) significant steps toward increasing incentives for private sector investment in crude oil and natural gas production, thru Decrees 1055 and 1212 bys i) offering "marginal, areas to bid (marginal areas are small fields and inactive areas previously held by YPF) ii) establishing a framework and incentives to have private firms participate in joint ventures in YPF's central producing areas; iii) establishing a framework and incentives to convert service contracts to concessions or association contracts, thus creating multiple crude oil suppliers c) adoption of an aggressive plan to deregulate prices of crude oil, petroleum product prices, natural gas prices and allow free disposability of crude oil and petroleum products by January 1, 1991 if not sooner; d) elimination of preferential fuel prices to electric power; e) virtual elimination of the distortionary refinery tax by reducing it from 102 to 0.225 f) in the draft tax reform law, VAT will be extended to all fuels; 8) simplification of the earmarked fu- y8ystem; h) intention that natural gas prices are to be increased to 902 of fuel oil for industry and power, and establishment of netback pricing principles for natural gas producers (Decree 1212); i) reduction or proposed reduction of some subsidies to the private sector; (See Chapter III, section "I', Chapter V, and Annex 11 for more details) 11. These measures constitute a substantial step forward in reducing subsidies and toward deregulation. However, various interest groups continue to try to frustrate reform efforts and serious problems remain to - iv - be solved. First, the deterior;tting macroeconomic environment at end 1989 hba created severe financial difficulties for public and private enterprises, as well as difficulties in maintaining or increasing real energy prices. Second, the deregulation decrees need some clarifications, and need to be fully implemented effectively, in such a way that the Government receives fair value for the rights and assets sold. Also the deregulation needs to be made permanent, thriugh changes in the Hydrocarbon Law, if necessary. Third, several institutional and regulatory reforms are planned to be implemented in 1990. While these could support the move to a full deregulation, a regression or errors in these reforms could have damaging consequences for the reform process. 12. Pricing distortions, investment misallocations, and regulatory policy distortions will continue to impose a heavy cost on the economy unless sustained reforms are undertaken. It is estimated that US$10 billion in potential revenue for the Government and the economy could be realized over the next seven years if action is taken to: (i) restructure energy pricing and taxation policies; (ii) redirect investment priorities; and (iii) improve the institutional structure and regulatory environment. Of primary importance is the need to permanently eliminate energy subsidies, increase producer energy prices, and deregulate hydrocarbon prices so that they are set at international prices. To do this properly requires an integral reform of the energy tax system, so as to simplify the structure and adiust tax rates. These reforms are crucial if energy waste is to be reduced. Sucb changes would also improve the financial position of state energy companies, so that important ongoing investments can be completed (such as the Yacyreta hydropower dam), reliance on government financial support reduced, and productive crude oil and natural gas investments made. Along with the price and tax changes, certain regulatory and institutional changes are required to eliminate overlapping regulatory functions and, within each subsector, to: (i) improve operational efficiencies; (ii) increase private sector investment; (iii) promote conservation; and (iv) encourage competition. A substantially different and more efficient regulatory and institutional arrangement is needed with a clear separation of the Government's role as regulator and policy-maker from its role as owner of public enterprises; moreover, state energy companies should be placed on an equal basis with the private sector in a competitive environment. To limit the burden on scarce public resources and to improve efficiency, a reformed pricing and regulatory framework is also required. This implies a reduction in the role of the state with a concomitant expansion of private sector participation. Among the strategies to expand the participation of the private sector, the Government may wish to consider partial or whole divestiture of selected energy-related activities. Ultimately, increased competition among the participants in the energy sector will be required to brirg about optimal sector efficiency. Described below are issues and recommendations to reform the system of subsidies, pricing and taxation, to increase crude oil and natural gas supply, to improve natural gas utilization, to improve refinery operaticas, and to improve operations and investment strategy in the electrical power sector. v B. ENERGY SUBSIDIES, PRICING, AND TAXATION 13. Many of the inefficiencies and problems in the energy sector for both producers and consumers derive from an overly complex system of subsidies, pricing, and taxation. Most producer prices received by state companies for crude oil, natural gas and electricity are below financial and economic costs, which exacerbates the financial problems of these energy enterprises and the public sector. There are also large subsidies to private sector entities and to the provinces. Moreover, heavy taxation of energy is overly complicated, misapplied and creates financial as well as economic distortions for both producers and consumers. The accelerating inflation in 1989 unfortunately has reduced real energy price levels, particularly for residential energy fuels. However, the current crisis situation provides an excellent opportunity to make urgently needed reforms in the energy pricing, taxation, and subsidy system. Subsidies 14. Many private sector entities that sell equipment and inputs to state enterprises receive favorable prices above economic and financial costs. Those that obtain feedstock from state enterprises (,!nch as private petrochemical companies and private refiners) pay prices usually below economic and financial cost. Financial distortions are particularly large in the 1k'drocarbon subsector where it is estimated that subsidies in 1988 amount .o about US$1,600 million per year. This figure includes approximately one billion US$ in subsidies to Private sector entities and also $327 million to the Provinces as excess royalty payments. This financial drain has contributed to the severe financial problems of YPF and GdE and, as a result, the country. Fortunately, measures taken between July and December 1989 have reduced excess royalty payments and temporarily reduced the cost of "Compre Argentino" policies. If Compre Argentino is permanently eliminated, and if proposed hydrocarbon deregulation plans and tax ptoposals are implemented these subsidies would be substantially reduced. Pricing 15. Retail prices paid by the final consumer for petroleum products during the fourth quarter of 1988 were generally much above the actual economic cest (varying from 52 to 222Z above, with gasoline being the highest) due to large taxis on petroleum products. Natural gas and electricity are also taxed, but final consumers pay prices significantly below economic cost (particularly consumers of residential natural gas, residential electricity, and other natural gas products). As shown in Table 1, in the fourth quarter of 1988, all natural gas prices (without taxes) were very low, 412 to 67? of economic cost, while residential electricity prices were 51? to 632 of economic cost. However, residential prices (including taxes) of natural gas slipped from 71Z of economic cost in 1988 to 15? in 1989. SEGBA's residential electricity prices (including taxes) also slipped, from 72? of economic cost in 1988 to 44Z in 1989. These consumer price distortions encourage wasteful consumption of electricity and natural gas and distort oil product demand patterns leading to costly refinery imbalances. Unfortunately, the accelerating inflation Tub;. 1t hCII IP DtUML Pmii in11 C T 100t 2. lam PR! C 55 PSRCSNTA6S RATIOS ____I PERCEN_ C (Incree_eDoecr4e) to Comercial Commercial Price Ceomercial Price Cmercial Price Comercial Pr'ce so frm Coerciel Price Commciml Pric Esommic i_ JiC 0/ x tesm ui/tams u/tesm u/ne taxes (u/etm) PAL *pree fuxesm Price I/ Price to conomic Price to Iec Price to _cenoic Price to Ecoomic Prie to e_ooic Price zm_I&ln_ ter M RIOm z am a a_S. _sm *o tl to belim -4aler 189 2 44 84 148.6 875.4 lo ff us 95 296 118 92 256 -IS 9 -Prei ;m 175 146 518 418 161.1 478.6 109 9s m 257 IN IS 294 - 65 14 M woeene S16 is 5 12 168.8 218.7 96 76 140 :6 S07 iR i10 -6S 71 6m41 159 3 927 215 168. "7 8 94 78 194 12? or 87 Zs i 16 76a DimI 184 IGO 194 31S6 18.9 2m 79 9 115 92 so 71 1so tax 41 Fasl Oil -.dutuy/Oer 1M2 el 114 1S7 1S9 141.8 149 75 9S6 144 eo 112 1s8 24 -10 _r Scor 102 SO 77 80 1*9 1i 94 74 71 78 62 6 11 61 1 LPG i° O(A/ia 12 14.4 9.7 14.8 18.6 84 100 p 77 62 180 29 91 "$ "K1EAL SM2WeAL as etidemtial/SC;eaccll 1.69 0.40 2.87 0.60 4.06 J/ 5.26 4S 10 n i 64 12 180 88 776 -20dustrial 1. 1.81.2 2.64 2.79 2.78 4/ 8.61 67 es 100 1*0 9 7? 180 27 29 Power 1.74 1.27 2.6 1.65 2.78 8.19 e2 4S 94 68 92 46 1o 21 107 .4eiaimg 1.U1 2.40 2.78 A.61 M 8S s6 10 s0 S_e -11midersala 4.5 2.9 S. a8. 6.7 U.8 U sa 72 44 so 80 180 7 S 19 .cinrcbIl 18.6 18.8 6.8 6.64 1le 247 190 1N -0 -Zojuetriul 4.8 4.6 6.7 6.0 5.6 7.28 76 82 no9 17 a2 8l 1M0 9 21 A ee of l0 bjor Utiliie 4amld.tial 5.6 7.6 6.7 1.8 S 67 S7 1s0 iO -Coscles 12.4 18.6 6.8 6.64 Sl2 269 207 1O -48 Aidoebtril 4.9 7.2 5.6 7.59 B7 yM 97 UN0 S 1/ amAic prime /co toe bum_ an Inernaionl petrlum projet price. ir. 0O_Ir 1968 plum diatribution amt. 2/ Ei to 61*1/ton CEF borde plea 65/too twampoqt plus diet, noto that If FB boo dr price for ept amid be 1114/tm. S/ _a of e_omie prime from 4.96 Web is 9N of fuel oil equivalent (2.78) plum diearibution flumcill cet (1.2?). to keroee equvalen (64.62 *intma). 4/ Eomic price defmed me 91 o fuel dII equivalent. 2.7Sw 90a.09 _E.ge rate _e- 12.00 Augot 196, 15.6 In o_cler 1966. on": Coinrmiel prices d taxes fo 198f "er prries in effect beceuber 19l8, from Tables 8.2 nd 8.8. Dobt for 1960 prie. .ording to eeolotimm of SE dae July 10. 1969. price In effet frm JkJly 10 to 0Decer 1969. - uht that _nw teal refer tD em toea Wc we rCiomed In this ruport. doeribed Ir deal in Couwter IV. - vii and sharp devaluations in 1989 have eroded the real energy price levels and reduced ratios of domestic to international prices. The large price Increases in July 1989 have brought many energy prices close to the levels of fourth quarter 1988. These price changes resulted in Increased prices to many industries while reducLng real prices to the residential sector. However, inflatlon remains hlgh and a permanent erosion of real prices will have serious economic and financial consequences for the energy sector. 16. The indirect and direct costs of pricing distortions to the economy have been large, estimated in excess of US$3 billion over the last 10 years. This is additional net revenue that might have been earned through reduced waste of energy resources plus improved production incentives and more efficient energy use. Taxation 17. Argentina imposes excessively high taxes in the energy sector. Such taxes have risen in the 1980s to account for a full 20Z of national government tax revenue. This is unusual for a country that is not a significant energy exporter. The rise in energy taxes has reoulted in part from the deterioration in the collection of broad-based taxes (such as VAT and income taxes) at a time when the need to reduce the consolidated public sector deficit is urgent. In addition, the structure of taxation has many serious problems. Numerous taxes at various levels distort incentives throughout the energy production process. There is a complex, inflexible system of earmarked taxes, and little or no rellance has been placed on corporate income taxes. Earmarked funds, which primarily go from the hydrocarbon sector to the power sector, create particular distortions in investment priority selection and by reducing the incentive for state enterprises to be financially self-sufficient. 18. This level of taxation (in most cases not completely passed on to the consumer) has had a negative financial impact on public sector energy enterprises. The public energy sector companies (YPP, Od!, and national electric power companies) experienced an aggregate operating income of US$3.6 billion in 1987, and US$4.8 billion in 1988. However, after subtracting a myriad of sales taxes, fuels taxes, provincial taxes, federal taxes and royalties, those public companles had a consolidated net loss of around US$2 billion each year. The cash flow for 1987 and 1988 is a negative US$0.9 billion. This has affected the ability of these companies to make crucial lnvestments and forced the central government to increase transfers to the energy sector. For example, in 1987, the Government received US$3.26 billion in taxes and royalties, but it also provided compensation to the sector of US$2.63 billion, leading to a net transfer to the Government of US$0.63 billion. In 1988, after imposeing large taxes on gasoline, the net transfer was a positive US$2.15 billion to the Government. Recommendations on Subsidies, Pricing, and Taxation (a) Remove all subsidies to private sector entities as quickly as possible through a phased program of feedstock price increases and a permanent elimination of "Compre Argentino" restrictions. - viii - (b) Increase prices of crude oil, natural gas, and refined products as quickly as possible to cover economic costs. Immediately link these prices to the international value of these products, then implement oil and gas price deregulation, as soon as possible, (as described in deregulation Decrees 1212 and 1055). This implies real increases in natural gas prices (before tax) of about 50Z, and increases in LPG prices (before tax) by about 202 to reach economic levels. The real increase in electricity prices (before tax) needed to cover marginal cost is about 202. (All these price increases are approximate increases, above inflation, over prices existing in the fourth quarter 1988). Lifeline tariff rates for poor consumers of natural gas and electricity should be preserved. (c) Restructure the taxation of energy fuels bys (i) merging all existing taxes (except VAT) into one (ad valorem) tax applied to the commercial price; (ii) reducing tax rates so as to create a more efficient and equitable structure; and (iii) applying VAT uniformly to all fuels, as proposed in the draft tax law. Example total tax rates, including new ad valorem tax (as a percent of commercial price, and also shown as 'new taxes' in Table 1) are as followss Present Proposed Gasoline -Extra 195 195 -Regular 155 155 Gas oil 105 125 Diesel 45 30 Kerosene 46 30 Fuel Oil 48 30 LPG 20 30 Natural Gas 44 30 Electricity 38 30 (d) The proposed taxes would be composed as follows: (i) All energy prices would be subject to VAT (existing rate is 152, proposed change is to reduce it to 132). In this way all the energy sector companies could deduct all VAT they paid on purchases. (ii) All energy (except that purchased by the power companies) would be subject to a basic ad valorem tax of about 151, destined for an Energy Fund or general fund, the resources of which would be utilized to finance investments in the sector accotding to priorities established by the Secretariat of Energy. (iii) Fuels used in the transport sector (gasoline, gas oil and CNG) would carry and additional ad valorem tax made up of two parts: - ix - (a) A tax of 352 destined for the Road Fund. (b) Another tax destined for general funds to reach the above mentioned levels (premium gasoline 1302, regular gasoline 85-95Z, gas oil 60Z). To the extent that the objectives of the fiscal policy and the increase in other taxes contemplated in the fiscal reforms permit, it would be proper to reduce this last mentioned tax component. (e) Commercial pricec on which taxes are based would bet ex-refinery international prices for oil products, 902 of international fuel oil equivalent for natural gas, and at least long-run marginal cost (LRMC) for electricity. The ad valorem tax should apply to electricity to cover the higher financial costs of electricity (about 152 higher than LRMC), to contribute to investment and limit interfuel distortions. Electricity prices to the final consumer, including the ad valorem tax (but excluding thte VAT) should cover financial costs of the entire power sector. Also, income taxes and windfall profits tax should be applied to YPF, which will have increased income. (f) Wholesale electricity rates (bulk tariffs) for sales into the interconnected system should be set at a minimum of long-run marginal cost. (g) YPF and GdE, should be subject to the normal corporate income tax, as are the private petroleum and natural gas producers and distributors. As proposed in the draft tax law YPF should be subject to corporate income tax. In addition, corporate income tax, plus possibly an income surcharge tax (or a windfall profits tax) should be levied on YPF. Proceeds of these taxes might be placed in an Investment Stabilizatior. Fund and assigned to Government, YPF, GdE, or other public agencies for investment purposes. The Fund could accumulate financial resources in periods of 'high" international prices and be used in times of "low" prices. In this way, total public investment financed out of oil surpluses would be made more stable than if all of it were spent immediately, and contribute to sound macroeconomic management and increasing investment. 19. The potential net fiscal impact (shown in Table 2) of the combined tax, price, and subsidy recommendations would be about US$1,650 million a year of which an estimated US$1,217 million would flow from reduced Government subsidies and US$411 million from taxes paid by YPF under the new tax regime, (based on fourth quarter 1988 exchange rate), which should go to needed investment and help reduce the fiscal deficit. (It would be proportionally less if subsidy reduction and price increases were phased in more slowly.) While some tax rates on energy fuels would decline, producer prices would increase and more tax revenue would be collected from income (and possibly windfall profit) taxes. Revenues going to energy and road funds would be preserved at their present level. The impact on consumers would be minimized by the new lower tax rates and lifeline rates for poor consumers. Energy price increases should have a small impact on poor households due to the relatively small monthly energy expenditures on energy by low-income groups. Tabl- 2. Approxlut Fiecel Effect of Reorawdmtion oen Taxtlon asd on Prilin (1988 tillIone of USf) Proposed wIth incressn In coumsrciol prices 1. INDIRECT TAXES Estimated Impact with changes In taxatlon system (based on new rates applied to un- changed before tax prices) 1/ -128 Additional Indirect tax revenue with incresso0 to before tax prices 2/ +266 Additional VAT not deducted 8/ -111 2.REDUCED COMPENSATIONS FROM OOVERNMENT (not effect of beforo tax price Increase and reductions of subsidiee) s1,217 8. APPROXIMATE INCREASE IN DIRECT TAXES (FROM INCREASED YPF INCOME) +411 NET FISCAL EFFECT .1,650 1/ Tax rates are described In Chapter IV, Section A 2/ Cormmrcial price increases In real terms above De_ember 1906 levels of 21X In LPG, S2.2SX for natural gas, 20# for electricity. 8/ VAT not deducted on pre snt rates, but which would be deducted by tate companies under the nw system. 20. In addition to numerous improvements in efficiency and incentives that could lead to large savings, the price increases would restrain energy demand. The immediate short-run effect of raising prices (above inflation from fourth quarter 1988 levels) is estimated to be an annual savings in crude oil equal to about US$70 million a year, increasing to over US$200 million a year by the mid-1990s. If, for example, all energy prices instead were reduced permanently to 30% below the levels of fourth quarter 1988 in real terms, the subsequent increase in demand is estimated to entail a loss of US$180 million per year in the short term, growing to US$560 million per year by the mid-1990s. Argentina simply cannot afford to pursue such a costly strategy of low real energy prices. xi - C. PETROLEUM AND NATURAL GAS SUPPLY 21. Production of crude oil fell 142 from 1981 to 1987, and continues to decline (excluding a short-term surge in natural gas liquids production in 1988). YPF's production, which accounts for two-thirds of all crude oil production, fell 172 from 1983 to 1987. Fewer development wells were drilled during the years 1986-87, largely because of limited funds for new investments. Although the total number of active producing wells was higher by 1987 (up 182 over 1981), the average production per well had dropped about 272 between 1981-87. Consequently, more expenditures will be required to maintain the same crude oil production, since well production rates probably will continue to decline. If YPF's actual exploration and development investments continue to be only about US$500 million per year, crude oil production is likely to decline by 32 a year, leading to increasing crude oil imports (Minimum Supply Scenario, as shown in Graph 1). While new petroleum exploration and production contracts under Plan Houston have recently been signed, any additional hydrocarbon production is likely to occur only in the mid-1990s and will probably be moderate. 22. Additional investments in crude oil and natural gas exploration are urgently needed to maintain and, if possible, expand production to avoid costly crude oil imports and natural gas shortages in the early to mid-1990s. Additional investments of about US$300-500 million per year could lead to increasing oil production and even oil exports (3aximum Supply Scenario, Graph 1). Such an expanded program would have large benefits for the economy, even under very conservative assumptions (i.e., assuming a low world oil price projection of US$11/bbl and relatively high production costs), the net present value of such a program is near US$1 billion. The net present value is substantially higher, at over US$6 billion, if projected future world oil prices rise to higher levels (US$16/bbl) and local production costs can be reduced by 402. Production costs could feasibly be reduced by 402 through a combination of: (i) efficiency improvements; (ii) lower local costs due to lower real exchange rates; (iii) higher efficiency of private sector investments; and (iv) reduction in Compre Argentino, which alone adds extra costs of about 402. 23. Mobilizing large additional investments is unlikely given the scarcity of public investment funds; thus, more private sector investment is needed. Since the petroleum sector has an advantage over other sectors in mobilizing domestic and foreign private investment, petroleum policies should be oriented to attract as much private sector investment as possible. Investments undertaken by the private sector in a competitive environment of reformed prices and regulations are also likely to be less costly and more efficient than public investment. 24. Very decisive actions have been teren by the new Government from July to December 1989 through the approval of the Upstream Activities Deregulation Decree No. 1055 of October 10, 1989 and then through a second Decree No. 1212 of November 8, 1989 deregulating the downstream hydrocarbon sector, including the natural gas subsector. In the first decree, the Government's objective is clearly stated, as replacing the Government intervention in determining prices and quotas by the free play of market mechanisms, which hopefully will lead to freely disposable crude oil, GrW lo---~~~~~~~~~c Y,,. 6 -~~~~~~- I ~~~~~~~~~~~- xiii - petroleum products and fully deregulated prices. The objective is to deregulate hydrocarbon prices, deregulate trade in petroleum and petroleum products, and to create multiple suppliers of crude oil and natural gas. Private companies will be allowed to have 'freely disposable' crude oil which would come from three possible sources. First, production from marginal areas, (small fields and inactive areas previously held by YPF), which are to be sold to private companies under a cash bonus bid. Second, production from possible joint ventures between YPF and private companies (which can now be established). Third, production from the conversion of existing service contracts into new contracts, such as association contracts. However, crude oil supplies will not be fully decontrolled until December 31, 1990 or when the 'freely disposable' crude oil reaches 8 million m3 (about one-third of Argeotine production). 24, The deregulation decrees are an important step in the right direction. Priority should be given to promoting joint ventures in well selected YPF main producing areas, since these have a high probability of achieving significant production increases in the near term. However, the Government should move cautiously to make sure that it receives fair value for the rights offered, particularly in the conversion of service contracts and sale of marginal areas. There are certain obstacles to success of the deregulation decrees such as the lack of free exportability of oil, uncertainty regarding the free disposability regime, and unwillingness of petroleum companies to commit large up front payments. Ambiguities in the decrees need to be clarified, as described below, along with other recommendations on oil and gas supply. Recommendations on Increasina Petroleum and Natural Gas Supply (a) Increase investment in exploration and development for crudi oil and natural gas over those levels achieved during the last several years by a combination of increased public and private sector investment. (b) Adopt incentives for increased private sector participation in petroleum exploration and production operations, as followss (i) deregulate producer prices; (ii) eliminate obstacles for more rapid approval of contracts for exploration and production under the Houston Plan; (iii) increase exploration in new areas by offering additional technical information; (iv) implement procedures allowing the private sector to operate some of YPF's marginal areas with free disposition of crude; (v) move towards wider private sector participation in YPF's operations through joint ventures as quickly as possible; (vi) sell off YPF drilling and workover rigs, and contract out drilling, well services and workover services under open competitive contract conditions. (c) Issue clarifications to deregulation Decrees 1055 and 1212 and effectively implement hydrocarbon sector deregulation plans as quickly as possible. Specifically: (i) Regarding free disposition of crude oil - eliminate cequirement for Government export approval ; continue phase out of export tax (present schedule is reduction to 102 by July, 1990) with complete phase out by third quarter 1990. (Failing immediate action on the above, set minimum internal price at FOB export equivalent and assure appropriate minimum payment in foreign exchange); - xiv - (ii) Regarding free disposition of crude oil in service contract conversions - Various different contracts should be handled on a case by case basis; Government should move cautiously and should carefully assess the potential value of YPP's rights; Government should evaluate alternative ways of achieving free disposition for these areas and the economic implications of each. Alternatives should includes (a) association contract; (b) international tender of YPF's rights/obligations; (c) production payment (or gross production split to YPF and/or Government); and (d) cash bonus. (iii) Regarding opening of marginal areas to bid - Issue detailed bid criteria and proposed contract; group blocks into areas of sufficient size containing potential for both existing and yet to be discovered reserves; provide access to complete and well organized technical data; and (iv) Regarding joint ventures in YPF areas - Define options of sale of rights for incremental production or of incremental and existing production (i.e. farm-in); prepare bid criteria (which include investment commitments) and model association (farm-in) and joint operation agreements; streamline contract approval process; transfer of all or part of YPF operatorship role to contractor; ensure that some of the best acreage is included in areas offered; and (v) Regarding natural gas terms in deregulation decree - Initiate study as soon as possible on transportation and distribution costs and tariffs; establish clear criteria for establishing producer netback (before contract renegotiations); develop guidelines to allow at least partial payment for natural gas in foreign exchange; initiate detailed market and demand study with view to expanded natural gas use; issue new dorree allowing multiple natural gas supplies and allowing private suppliers of natural gas to sell directly to consumers (as outlined in principle in deregulation decree). (d) Restructure YPF and GdE and improve operational efficiency. Key recommendations include: (i) Change the organizational structure into a holding company of strategic busine3s units (with sub-holdings such as exploration/production, industrialization, transport/ shipping, marketing, natural gas, petrochemicals). While initially each subsidiary would be owned by the holding company, subsequently private ownership (by private companies and/or private shareholders) could be incre-sed. (ii) Establish clear market based transfer prices between various operating units. (iii) Improve strategic planning capabilities and prepare a long-term investment program. l ~~~~~~- xv - (iv) Improve efficiency in upstream and downstream operations through selected priority investments and corresponding technical assistance. (v) Transfer current regulatory functions of state enterprises (YPF and GdE) to the Government regulatory authorities. (e) Establish an effective regulatory mechanism for setting and implementing hydrocarbon policy, whicht (i) eliminates the present unproductive overlap of responsibilities; (ii) sets clear guidelines for operations of public and private enterprises; (iii) provides equal treatment for public and private companies within a competitive environment: and (iv) protects national interests with a minimum of regulations and controls by limiting Government role to setting general guidelines for the sector and regulating its operation. D. NATURAL GAS 25. Natural gas plays an increasingly important role in Argentina as a source of ene-y for electrical power generation and industrial production; and as a residential and commercial fuel for cooking and space heating. Over the past 10 years, production has increased 52 a year and is projected to grow 4? a year through the year 2000. However, the policy of rapid development of natural gas was based on an overly optimistic estimate of proven natural gas reserves. Argentina's proven natural gas reserves are adequate to meet current needs, but as consumption increases, new reserves must be discovered to maintain an adequate inventory. The existing pricing structure provides insufficient incentive to explore for and develop natural gas. If the nation's goal of increasing the use of natural gas to replace exportable liquid fuels is to be fulfilled, incentives to explore for natural gas must be provided and an accelerated exploration and development program must be initiated. 26. An accelerated program to develop additional natural gas resources will have significant benefits for the national economy. Net benefits of such a program over the next 10 years are estimated to be US$4-6 billion through natural gas substitutions for more expensive petroleum products and electricity. Analysis indicates that the economic cost of producing and delivering natural gas to consumers is less than the economic netback value for all projected uses, except possibly for fertilizer production. Natural gas is more efficient and lower cost than many other fuels. More use of natural gas in the residential sector would be desirable as the cost per -mit of useful energy is lower than substitute fuels (e.g., one-third that of electricity). The financial cost of producing natural gas, including royalties, VAT, and income taxes, as well as a reasonable return on equity invested in natural gas production, is less than the internationally-based price of substitute liquid products. An appropriate pricing structure based on the international value of the fuels, vbich natural gas could replace, would generate sufficient revenue to attract investment in natural gas exploration and development. - xvi - 27. The highest value uses for gas are in those sectors where netback value is much higher than economic cost, such as residential. commercial, and general industry, see Table 3. If no new reserves were developed, the economic cost of supplying natural gas for some petrochemical projects could exceed the netback value. The existing pricing structure for petrochemical feedstocks is complex, and the retention price received by the feedstock supplier may not be sufficient to encourage development of new natural gas reserves. If known natural gas reserves are increased about 82, there will be enough natural gas supply for power sector thermal stations scheduled for installation through the year 2000. TABLE 3. COMPARISON UF ECONOMIC COST AND NETBACK VALUE (Fourth Quarter 1988 US$/MCM (thousand cubic meters)) AIC Supply Depletion Economic Netback Sector Cost Allowance Cost Value b~ Residential 85 15-25 100-110 200 Comn/Inst. 83 15-25 98-108 203 Genl.Ind. 41 15-25 56-66 121 Cement 30-50 15-25 45-75 92 Power 38 15-25 53-63 79 Fertilizer 17 15-25 32-42 30 Source2 Tables 7.4, 7.5, and 7.7 23. Policies must be implemented to accelerate exploration and production of natural gas in all regions. In addition to developing new reserves, the delivery infrastructure must be expanded to meet growing demand. The timing of expansion of natural gas lines in the north (and possibly the south) is dependent on the size of potential resources in Neuquen. If the pipeline system is not expanded, the capacity of these parts of the system, will reach a limit in 1996. Even with assumptions of relatively low growth in natural gas demand, there would be no opportuaity for further growth in natural gas supply, and the available natural gas would have to be conserved for the highest value users. An interruption or slowing of the pipeline expansior program would have significant economic costs, since the value of the fuels that additional natural gas could replace would be much higher than production and new pipeline costs. If the expansion program were delayed five years, the cost of the extra liquid fuels burned during the 1996-2000 period would be about US$200 million in present value. This clearly illustrates the benefits of expanding the pipeline system to keep pace with growing demand. 29. An additional problem is the utilization and pricing of natural gas and natural gas liquids (NGL's) in petrochemical projects. The current pricing system is inflexible and producer prices are too low to encourage development of new natural gas reserves. A new pricing formula is needed, that for example could index the producer price to the international price - xvii - of alternative feedstocks, such as naphtha. This is somewhat similar to the method now used; however, instead of the retention price and rebate structure, the supplier would negotiate directly with the buyer. A floor price for natural gas would have to be established as well as an appropriate base price and indexation factors. For projects such as methanol or MTBE production, where dry natural gas is the feedstock, a product-price-based system would be preferred. The formula could provide for a fixed price during start-up and market development period. Subsequently, if earnings exceeded a pre-established level, the feedstock supplier would receive a share of these 'excess" earnings. This formula is applied in the case of the natural gas supply contract between YPF and Petroquimica Auatrali if methanol price in the international market rises above US$ll/ton YPF will receive a proportionately higher price for natural gas (than the floor price of US$0.70 per MMBTU). Recommendations for Improving Natural Gas Utilization (a) Implement a oontrolled transition to a new pricing system. During this transition a new system of controlled prices would be put in place while needed studies and institutional arrangements are completed. This would entail: (i) gradually increasing the controlled price to just below the international level of fuel oil for the industrial sector, plus additional distribution costs for the other sectors; (ii) eliminating arbitrary transfer prices for natural gas and natural gas liquids; (iii) establishing a system for regulating downstream natural gas operations as public utilities; and (iv) ultimately eliminating retail price controls, except the margin for delivering natural gas from the wellhead to the consumer. The tax regim2 will have to be modified to assure that all types of energy that compete with natural gas are subject to the same unified energy tax (on an energy-equivalent basis) as natural gas. The Government should also capture a larger share of the economic rent from the producer in the form of income tax and, if necessary, windfall profits tax on windfall profits from existing natural gas production. (b) Implement natural gas price deregulation, as described in deregulation Decree 1212, to set the retail price of natural gas in the industrial and power market equivalent or nearly equivalent (90X) to the price of fuel oil-- the next best substitute and the marginal fuel displaced by incremental natural gas production. The price in the residential and commercial sectors should be set to cover the additional incremental transmission and distribution costs plus an excise tax, if needed, to reach kerosene energy equivalent price. (c) Utilize the available natural gas to maximize the economic benefits to the national economy. Applications that appear to offer lower benefits should be carefully evaluated to ensure that such use is economically justified. The analyses should take into account regional factors and balance of payments effects that may affect the economic benefits or costs of specific projects. - xviii - (d) Set up a regulatory system for natural gas transmission and distribution. Increase competition in natural gas supply by allowing producers to sell natural gas directly I.o consumers or transporters other than GdE. (e) Expand exploration in the Neuquen area. Prepare a strategic plan for optimal least-cost natural gas exploration/production and pipeline expansion options. (f) Establish and implement a new pricing formula for natural gas and natural gas liquids used in the petrochemical industry based on alternative feedstock and profit-sharing principles. (g) Undertake studies on: (i) Natural gas demand, which takes into account different demand growth rates, different price assumptions, and ceit/benefit analyses of natural gas use in each sector. (ii) Cost of service and appropriate tariff-setting to establish the long-run marginal cost of producing, transporting, and distributing natural gas. (iii) Institutional structure to regulate natural gas distribution and transmission. Civ) Pricing formula for NGL's used in the petrochemical sector. E. REFINING OPERATIONS 30. In recent years, large investments in refinery conversion facilities have been made to convert lower value fuel oil into more valuable gasoil and gasoline. It had been expected that increasing natural gas production would displace fuel oil that could then be refined in the new conversion units. However, declining investments in crude oil production have reduced crude oil supply for refining; also, demand for gasolines has gone down sharply due to higher retail prices (from higher taxee). Because of both the reduced refined crude oil supply and the distorted demand pattern for refined products, the refinery sector cannot operate in an optimal manner. At present, there is an excess of refinery capacity, a surplus of gasoline (which cannot be exported due to quality and logistical problems), and shortages of refined fuel oil. Steps need to be taken to profitably use this excess refinery capacity, to improve operational efficiency in the refineries, and to restructure the demand pattern for petroleum refined products. 31. The large installed Argentine refining capacity, almost double actual domestic requirements, can be considered a resource waiting to be exploited. A US$1.00 per barrel marginal profit might be obtained from processing additional crude oil and exporting the products, which could earn US$35 million a year in revenue. In addition, the lack of optimization causes opportunity losses worth possibly US$50 million a year, :xjx - which could be earned if the products were to be brought up to international market quality and then exported. Marginal refinery capacity could be economically employed for generating exports and for arranging third-party 'foreign) processing agreements. However, the existing 102 tax on refined crude effectively nullifies the incentive to optimize this resource, in much the same way that unrealistic and unnecessary price controls distort demand and stifle efficiency of operations for the domestic market. Thus, a prerequisite for optimizing the Argentine refining industry is to tie refined crude oil prices refined with ex- refinery product prices that are linked to international values and elimination of distortionary taxes that now reduce the effective exploitation of this industry's potential. 32. Although the Argentine refining industry has moved to higher-value production, there is further scope to improve yields, efficiency, and profitability. Refining capabilities to produce these higher-valued yields have not been fully developed. The basic reasons for a consistent lack of optimization include the followings (a) Import and export controls that have reduced the refineries' ability to balance crude slates and product yields with international market requirements and standards; (b) Reliance on Government protected refinery margins; (c) Domestic price controls that maintain overall prices at low levels relative to international markets, and that distort price spreads betweer different product grades; (d) Strategies by the private refiners to overcome both the local regulations and distorted price structures and to increase private company profitability at the (partial) expense of YPF refineries; and (e) Inability of YPF to act promptly as a profit-seekit.g entity. 33. A solution to these problems is to create an adequate operating environment for all domestic refineries, to encourage better economic use of existing facilities, which would increase production to satisfy the domestic market and, at the same time, promote export of substantial volumes of refined petroleum products to maximize foreign revenue. These objectives may be reached by implementing a combination of adequate regulatory as well as price and tax changes. Recommendations (a) Improve refinery use. Options could include awards to the refineries of throughput licenses to obtain the crudes needed to maximize profits. The combined value of potential optimization of domestic product qualities is estimated at US$60 million a year. (b) Expand physical port facilities and control infrastructure to expand Importlexport of refined crude oil and petroleum products. Upgrade marine terminals. - xx- (c) Implement measures to improve refinery efficiency, reduce losses, improve product blending, handle high sulfur and heavier crudes, and export excess naptha. (d) Take steps to further increase private sector participation in downstream operations where the main options include the followingt ti) selling off specialty-producing refineries and plants; (ii) disposal of the transport fleet; (iii) selling shares in the large YPF refineries and petrochemical plantss (iv) privatizing the pipeline transportation system (or portions thereof) for both refined crude oil and petroleum products. F. ELECTRIC POWER SECTOR 34. From the mid-1960s to the mid-1980s Argentina enjoyed reliable and extended electricity service, provided originally by private companies. with increasing participation of the national utilities and reliance on Government contributions. Ini the last 16 years the country's total installed capacity has grown at a rate of 6.4Z p.a. A large National Interconnected System (NIS) covers a substantial part of the country and supplies about 90Z of public electricity services. However, the sector faces important problems arising from: (i) an inadequate legal/institutional framework, (ii) lack of consistent planning, (iii) deterioration of generation and distribution facilities, and (iv) a weak financial situation characterized by a heavy foreign debt burden and a low level of internal cash generation. The economic difficulties now faced by the country call for an increased effort to coaduct power activities efficiently and economically, thus reducing the sector's reliance on Government support. To achieve this objective, corrective measures should be promptly taken to: (i) improve the sector organization, (ii) ensure that the sector expansion follows principles of economy and efficiency, (iii) improve the sector's operational efficiency, (iv) promote energy conservation, (v) reduce technical losses and electricity theft, and (vi) improve sector finances. 35. Because of inadequate tariff levels and structure, electricity consumption has grown in the past at a higher rate than the economy and current demand projections appear to be on the high side. Additionally, because of investment decisions taken outside the sector and inadequate planning procedures, past expansion plans have included large hydro and nuclear projects (compounded by long delays) that have put a heavy financial burden on the sector's finances. in the short term, a major issue is how to make the power sector financially self-sufficient (through tariff adjustments and cost reductions), so it can finish ongoing projects that are not yet completed but are near completion. In the medium term, substantial investment savings could be achieved by using less capital intensive solutions, such as combined-cycle plants and rehabilitation of existing thermal facilities, which are likely to be selected as least cost options. In the longer term, expansion planning should be selected from scenarios based on least-cost principles, realistic demand projections, and robust development options. It is estimated that electricity consumption - xxi - is likely to be 17X lower than the SE's current projection by the year 2000 and investment requirements in generation works about US$1.8 billion lower than the current estimates. Additionally, savings could possibly be achieved with optimum planning using less costly options. Reconmendations on Improving Power Sector Supply (a) Expansion Planning: (i) The SE should improve demand projection moeils. (ii) The expansion plan should be based on the most likely demand scenario. Sensisitivity analysis should reflect possible fluctuations of the planning parameters. (b) Development program: (i) Government policies should reflect least-cost principles. Appropriate consideration should be given to all relevant supply options including the use of combined cycle plants and rehabilitation of existing thermal facilities. (ii) Priority should be given to completion of ongoing works. Eliminate new nuclear plants (after Atucha II) from development plan. tc) Operations: Xi) Speed implementation of SEGBA's loss-reduction program. (ii) Expedite execution of the SEGBA V Project. (Mii) Evaluate actual market for coal in power generation to define whether expansion of YCF's mine at Rio Turbio is justified. (d) Organizational and Institutional Structures (i) Define role of the EFEE and the national entities, and the provincial utilities in the Framework of the Federal Electric Pact (Pacto Federal Electrico). (ii) Increase private sector participation by providing a sound environment to private investors. (e) Pricing Policies: (i) Complete LRMC study, implement recommendations, and align wholesale rates (bulk tariff) for the DUC transactions with long-run marginal cost, as well as bring prices to the final consumer, before tax, up to at least long-run marginal cost. (ii) Reduce power utilities' dependence on Government financial support. - xvii - G. INSTITVTIONAL AND REGULATORY FRAMEWORK 36. Excessive Government regulations and the inevitable overlapping responsibilities of many Government agencies that are involved with operations of these large public enterprises, in combination with distorted pricing and taxation policies, have resulted in deep-rooted inefficiency in state enterprises and a negative impact on public sector finances. Limited private sector participation in the energy sector (particularly in crude oil and natural gas), which is primarily it. the form of either a service contractor or supplier to one of the large public enterprises; in many cases the private companies receive substantial subsidies from the Government/public enterprises. 37. What is needed is a substantially different and truly regulatory institutional framework that establishes a clear separation of the role of the Government as policy-maker and regulator, and that places the state energy companies on a financially independent position within a competitive environment with private sector enterprises. Corrective actions should be implemented such as (i) separate the Government as policy maker and regulator from all business activities of the various public sector enterprises, (ii) establish an environment of open competition and equal opportunities for both public enterprises and private companies in all aspects of the production and disposition of energy resources, and (3) encourage efficiency and profitable objectives by all energy companies, while at the same time ensuring that national interests are protected with a minimum of regulations and controls. 38. The basic objectives of the regulatory authorities in each energy subdivision should be: (i) to monitor, regulate, and maintain an open competitive environment and equal opportunities for all companies, public and private, tomestic and international, that are now or may in the future participate in the energy sector; and (ii) to ensure that national interests are protected through regulations and controls in the production and disposition of all energy resources under efficient, open, competitive conditions. Examples of the activities that regulatory authorities might oversee include: (a) Hydrocarbon Sub-sector - As a result of the planned deregulation of the hydrocarbon sector, the regulatory agencies should be carefully designed and should have an important role in : (i) Energy policy and planning, which would need to replace the strong logistical support it had received from YPF; (ii) Exploration/production activities in terms of promotion of new acreage and joint ventures for investments by both state enterprises and private concerns, negotiations with these entities and monitoring of implementation of their contracts; (iii) Logistics (transportation and shipping) in terms of regulating access to transportation facilities and deciding tariffs applicable to both owners and non-owners of the system; - xxiii - (iv) Implementation and monitoring of natural gas and oil pipelines as common carriers, and gas regulations. (v) Ensuring that taxation of crude oil, natural gas and petroleum prod-cts reflect Government policy; (vi) Ensuring that companies maintain official standards in the design of installations and pipelines and certifying that installations meet standards; (vii) Ensuring public safety and environmental protection from hydrocarbon related activities. (b) Electric Power The power sector legal/institutional framework is complex and does not favor efficiency. There is no comprehensive electricity law and existing regulations are not effective with overlapping responsibilities among the various institutions that oversee the sector, thereby impeding clear definition of authority and accountability among sector institutions, (i.e. national and provincial utilities, binational entities, and the Nuclear Commission). National utilities report to the MOSP through the SE. CTMSG reports to the Minister of Foreign Affairs, while EBY reports directly to the Ministry of Public Works and Services. CNEA reports directly to the President. The SE has overall responsibility for planning and operations at the national level and for collection and distribution of the electricity funds. The Ministry of Economy retains final authority for setting electricity rates. Provincial governments have independence for defining development policies and tariffs, which may be inconsistent with national policies and priorities. Because this overly complex institutional framework is in part responsible for the sector inefficiencies, the Government has lately taken steps for improving the legal/regulatory framework. Recently enacted measures includes (i) the creation of a Federal Enterprise of Electricity, EFEE, which will possibly absorb generation and transmi3sion facilities of AyE, HIDRONOR, the Argentinian interests in binational entities (Yacyreta and CTMSG), and other facilities of national significance, and (ii) the signature between the Federal Government and the Provinces of the Federal Electric Pact (Pacto Federal Electrico, PFE), which se the basis for improved coordination of the sector. Important details regarding the above measures must be worked out before they become fully implemented. Also, the PFE will require legislation from the Provincial Congresses to be legalized. Improvement of the legal and institutional framework is required as a foundation to obtain Bank support for sector activities and is expected to be closely linked to Bank lending operations. - xxiv - H. ENERGY INVESTMENT, PLANNING, CONSERVATION AND ENVIRONMENT 39. Investment. The 1986 Energy Plan was a very useful integration of supply, demand, and investment. However, it is now out of date with many objectives unfulfilled. At present, there is no official integrated investment program. Table 4 summarizes approximate ranges of investment levels in crude oil, natural gas, refinin&, and power for 1989-2000 based on the analysis in this report. High and low estimates are provided. Power investment should be based on the Most Likely Demand scenario. Crude oil and natural gas exploration and development investment figures show investment levels to reach the Minimum Supply Projection (which assumes a continuation of recent trends), and another level of investment from increased public and private investment to reach Maximum Supply Projection. The other investments in natural gas and petroleum infrastructure are partially dependent on the level of crude oil and natural gas investment and optimal planning. A reduction in the role of the state and expansion of the role of the private sector, particularly in crude oil and natural gas activities, is necessary both to improve efficiency and to limit the burden on scarce public financial resources. A large expansion in the role of the private sector (under existing conditions of distorted pxlcing, taxes, subsidies and regulatory policies) could worsen the drain on public finances. However with reforms of these policies, the role of the private sector could be expanded significantly, contributing increased technical and financial inputs to expand energy production in a competitive environment and leading to increased benefits for both the state and the private sector. As shown in Table 3, the potential role of the private ector is large under a reformed system of pricing and regulation. 40. Planning. Improved energy planning is needed to increase efficiency in the sector and to better allocate scarce investment resources. The Energy Plan should be updated annually including alternative investment plans to meet different energy demand growth projections, the impact of price changes, and interfuel substitution possibilities. The costs and benefits of each investment program need to be carefully evaluated, and investment priorities should be ranked according to economic criteria. Investment options should be evaluated at a single discount rate, plus sensitivity analysis of optimal investment timing, using higher discount rates for several years to reflect the unusually high cost of capital in Argentina, prevailing at present. 41. Conservation. Energy conservation options to complement price changes in each subsector also should be evaluated. The realization of reduced demand growth, in addition to the adoption of appropriate pricing policies, will require the execution by the Government of a clear and systematic conservation policy that should be developed and enforced by the Secretary of Energy (SE). Cogeneration with industrial projects is also a potential field for energy savings and could be explored if measures are taken to increase coordination between the energy and industrial sectors. Energy losses, by producers, transporters, processors, distributors and consumers deserve special attention to reduce the waste of these valuable resources. 42. Environment. The SE has also taken responsibility for environmental protection with regard to power projects, such as Yacyreta and Piedra del Aguila, which have been the object of an in-depth evaluation of - xxv- their potential impact on the environment prior to proceeding with actual construction. In the case of Yacyreta, the studies covered aspects related to protection of aquatic fauna and flora, water quality, protection of endangered species, control of possible waterborne diseases, forestry, and archaeology. A large component of the project is addressed to minimize the effects on the displaced population. On the basis of experience gained in these projects, the Secretary of Energy recently has issued guidelines for environmental assessment of hydroprojects, whose execution constitutes, in accordance with a presidential decree, a prerequisite for the approval of any new plant. These guidelines have been reviewed by the Bank and have been found to be sound. The Secretary of Energy is currently preparing similar guidelines for the assessment of the environmental impact of thermal power plants. 43. There are also important environmental aspects that need to be addressed in the petroleum and natural gas sector. Key issues needing further study and appropriate legislation are measures tot (i) reduce andlor eliminate use of leaded natural gasoline; (ii) reduce the level of sulfur in diesel and restrict present and future pollution from high sulfur crudes in refining; (iii) reduce natural gas flaring and related pollution: and (iv) take measures to minimize risk of oil spills. TABLE 4: ESTIMATES OF ENERGY SECTOR INVESTMENT (millione of constant 1968 US18) 1989-1995 1986-2000 1988-2000 Oil and Natural as. Exploration and Development Minimum Supply (continuation of B,772 2,22B 5,9m recent Investment trends) Maxtmu Supply (expanded private 7,028 7,007 14,100 sector Investment) Refining, Tronsportatlon and Moaketing LoW 1,500 1,000 2,500 Nigh 2,600 1,750 4,250 Electric Power Most Likoly Domand 8,080 1,786 4,866 High Demand 4,218 2,412 6,326 Natural gas LoW 900-1,800 500- 700 1,400-2,000 High 1,200-1,700 900-1,100 2,100-2,800 Tot I Low 9,460 5,660 15,110 High 16,200 12,239 27,440 (Portlon of high scenario which could be new potential privote sctor Investment) (2,000-8,000) (2,000-8,000)(4,000-16,000) Excludes: Private crude oil and natural gas Invostment under present contracts as well as nucloar and coal investment. CYIAPTER I b OVERVIEW AND BACKGROUND OF ENERGY SECTOR 1.1 Argentina's energy sector is characterized by a historically limited capacity to produce sufficient crude oil and natural gas to meet the demands required for the country's internal consumption, while the supply of electricity, which used to be reliable, has been characterized by recent frequent shortages. Since the late 19409, successive governments have always followed the customary political path of keeping Argentina isolated from the world of internationally competitive prices for energy resources based on supply and demand, while electricity prices have not reflected either economic or financial real costs. 1.2 The Government's energy policies concentrate on attaining self- sufficiency in the various forms of energy required; however, there are no adequate pricing policies to permit the public energy producing companies to recover their capital investments and operating costs and to receive a reasonable profit. The Government's energy prices and tariffs have been freqinently directed more towards political ends with a quasi-economic rnt'.onale, such as to contain inflation, promote development of certain regions of the country, subsidize certair industries, but primarily to collect additional revenue for the Treasury and the provinces. 1.3 This chapter provides an overview and background on energy resources, oil and gas supply, power supply, institutional arrangements, and present sector finances in Argentina. A. ENERGY SUPPLY AND DEMAND Hydrocarbon Resources ! 1.4 Argentina, although endowed with substantial and diversified energy resoucces, depends heavily on crude oil and natural gas to meet its energy requirements. However, the country has rarely been in a position of having an adequate supply of hydrocarbon reserves, and in recent years production rates have consistently exceeded the rate at which depleted reserves have been replaced by new discoveries. Hence, Argentina has severely reduced its most essential energy resources to a critical level from which it will be difficult and costly to recover. New large investments are required to discover new hydrocarbon reserves. 1.5 As a result of recent reassessments proven crude oil reserves as of January 1, 1988 are now estimated to be only 224 million m3 (1.41 billion barrels)--versus the previous estimate of 357 million m3 (2.3 billion barrels)--which at the current production rate of about 70,000 m3/day needed for present consumption requirements, puts the proved reservelproduction ratio for crude oil equal to eight years of supply. Thus, projected future demand for liquid hydrocarbons will be increasingly more difficult to supply from known sources. Similarly, realistic proven natural gas reserves as of January 1, 1988, are now estimated to be only 554 billion m3 (19.6 trillion cu. ft.)--versus the previous estimate of 693.4 billion m3 (24.5 trillion cu. ft.)--which at current production rates puts the known reserve/production ratio for natural gas equal to 20 years of supply. (Details of adjusted oil and gas reeerves are in Annex 1.0.) -2- Petroleum SuPPlY 1.6 The Government's primary objective in the hydrocarbon sector has been to reach self-sufficiency. In the early and mid 1970s, Argentina had to import significant vulumes of crude oil and ref4ied products, but after the first oil price shock of 1973, which caused a balance of payment difficulties, the Government decided in 1976 to increase the role of the private sector in crude oil and natural gas production. This change in policy, together with the discovery and development by YPF of two large gas and condensate fields in the late 19708, increased crude oil and natural gas production and resulted by 1983 in reducing such imports to zero. However, produc.ion of crude oil fell 14Z between 1981 and 1987, although there was a turnaround in 1988 to positive levels of production due largely to an increase in the production of petroleum liquids from natural gas fields. 1.7 The main problem has been the 172 decline in YPF's crude oil production, which accounted for two-thirds of all crude oil production in the years 1983-87. The cause for this decline natural depletion of older reservoirs and that fewer development wells were drilled during the period 1986/87, largely because of limited funds for new investments. The total number of actively producing wells was higher by 1987 (up 182 over 1981), Individual well average production rates dropped about 27Z between 1981-87. Increased investments will be required to maintain the same future crude oil production, as average well production rates most probably will continue to decline. In fact, YPF's crude oil production and reserves have been in steady decline since 1981 because of: (i) lack of effective exploration efforts leading to discoveries of significant new petroleum reservoirs amenable to development; (ii) reduction in the level of development drilling investments for crude oil production; (iii) lack of investments for the implemen.ation and development of secondary and enhanced oil recovery projectc: and (iv) general inefficiency in production operations. 1.8 In recent years, YPF has been forced to cut its planned investments because the Government, facing major fiscal constraints, did not authorize all of the funds required for new investments in exploration and production of crude oil. Also, Government policies restricted private sector exploration and production investments in YPF's producing areas, presently under production service contracts with private companies, in accordance with legislation approved in 1976. Therefore, declining public sector investment in hydrocarbon exploration and development has not been offset by an increas4 in private sector investment. These limitations have been exacerbated during recent years because YPF has had to devote substantial portions of its available funds for the development of new natural gas reservoirs to facilitate deliverability into the rapidly expanding natural gas pipeline systems built by GdE. However, YPF has not received adequate reimbursement on these investments because of the low prices established by the Government for natural gas at the wellhead. 1.9 In 1985, the Houston Plan was devised to attract private sector participation. The first three rounds of bidding resulted in the award of 36 contracts from the 116 blocks offered. A fourth round was completed, but two-thirds of the blocks did not find any takers. A fifth round of 70 -3- areas were offered in late 1989. Nevertheless, with the Houston Plan format, Argentina and YPF have finally been able to attract wide participation by international petroleum companies in searching for hydrocarbons In the country through cooperative ventures with local private oil companies. The main feature of the Houston Plan is a 8r rantee that payment of services would be made in exportable crude oil ii. the event that YPP is unable to make timely payments in foreign exchange. However, hydrocarbon production from these contract areas cannot be expected before 1993 to 1996, partly because of long delays (often extending 18 months) for the approval of the contracts by the Government, the extended exploration periods, and the work program and small investment commitments by the contractors. Also, production levels from the Houston Plan are likely to be modest. Natural Gas Supply 1.10 Recently, it became evident that Argentina's known natural gas proved reserves are about 25 less than officially estimated. Hovever, it is quite possible that large, undiscovered natural gas reserves exist, which could be exploited at relatively low economic cost. Ae a result of this reassessment of natural gas reserves, future shortages of natural gas are likely to develop in certain regions of the country, depending on the availability of transport and distribution systems. More natural gas reserves have not been discovered primarily because the wellhead price paid to natural gas producers is too low to provide sufficient incentive to explore for and produce natural gas. The net wellhead price received by YPP is only US$0.19/MK8TU, or less than 202 of the equivalent international fuel oil price, and the price received is only about one-third the actual natural gas production cost, representing for YPF a net loss of about US$800 million per year. Prices charged by GdE to natural gas consumers do not even cover operating costs, much less the large investments made in the transportation and distribution systems. Oil and Natural Gas Demand 1.11 As increased natural gas reserves have been discovered and developed by YPF since 1978, the patterns of energy production and consumption have changed, mainly for certain refined petroleum products and natural gas. These changes began to occur in Argentina in the late 19703; but became more dramatic during the early and mid-1980s. The share of natural gas in final energy consumption increased from 1SZ in 1970 to approximately 282 in 1982, reaching almost 33S in 1988. Natural gas essentially has replaced fuel oil, both in general industry and in electricity generation; so it is not surprising that the share of fuel oil in final energy consumption declined from almost 30Z 3.n 1970 to less than 8S in 1982, reaching only 4Z in 1988. Meanwhile, participation of hydroelectricity increased from 8.2S1i 1970 to 12Z in 1982, while other petroleum products decreased approximately 2Z over the same period, with all of them remaining basically unchanged in their share of consumption from 1982 to 1988. Shares in final energy demand have evolved from 1960 to 1985 as follows: 1960 1970 1985 Oil Products 75 71Z 502 Natural gas 7Z 151 272 Electric Power 1.51 2S 12Z Solid and Other Fuel 17S 12S 9Z -4- 1.12 Between 1970 and 1981, final energy consumption increased in Argentina by approximately 2.5Z per year, in spite of constantly rising energy prices in real terms duriL.g the latter years of this period. These increases, when compared with the average growth in GDP of 2.4? per year for the same period, indicate that there is still scope for energy conservation in Argentina, since GDP growth during 1982-88 has been almost negligible, but consumption levels still rose. Although final energy consumption has continued to increase, it has not done so at the same rate as before since prices to consumers during recent years have risen more steeply than between 1970-82. Details of energy demand are also given in Chapter IX and energy balances in Annexes 9.1 through 9.5. The Electric Power Supply and Demand 1.13 Power facilities installed in the country are sizeable. The total generation capacity available by end 1987 is estimated at 14,300 MW, ef which 12,400 MW correspond to public service and 1,900 MW to autoproducers. Public service companies are national utilities, binational entities, and the nuclear commission. They are described in Section C. There are also about 20 provincial utilities, some own generation facilities; most of them distribute energy purchased from the national utilities. Additionally, Argentina has a strong rural electrification cooperative system. Total public service energy generation is estimated at 46,000 GWh for 1987. Most of the generation, about 42,000 GWh, was done in a National Interconnected System (NIS), which covers a substantial part of the country and is expected to continue expanding its coverage to take advantage of economy of scale from the large power generation facilities under construction. The estimated coincident demand of the NIS for 1987 is estimated at 7,660 MW. 1.14 The degree of electrification in Argentina is high compared to other Latin American countries. About 852 of Argentina's inhabl..ants have access to electricity. Almost all the urban centers and about 502 of the rural population have electricity service. Electricity per capita consumption was about 1,450 kWh in 1987 (compared with 1,400 kWh p;a. for Uruguay and 270 kWh p.a. for Bolivia). Total country consumption grew at a rate of 8? p.a. in the period 1960-70 and at a rate of 6.1X p.a. in the period 1970-80. It slowed after 1980, reflecting the difficult economic conditions, reaching 2.82 in the period 1980-84 and decreasing by 2.21 in 1985. Consumption growth recovered in 1986 and 1987, however, at a high rate (7.42 p.a.). In 1987 industrial consumption accounted for 482 of total consumption from public service utilities and residential and commercial consumption for 402. Electricity demand has grown at a higher rate than the economy (between 1970-87, per capita electricity consumption grew 1.6 times, while per capita GDP in constant terms decreased) and the current demand projections prepared by the sector assumes a high growth rate (6.2? p.a. for 1989-2000), which, as discussed in Chapter VIII seem overly optimistic. B. ENERGY SECTOR RELATED TO THE MACROECONOMY Energy Sector Share of GDP 1.15 The energy sector as a share of GDP has increased from !.4 percent of GDP in 1980 to 6.9 percent in 1987. The oil subsector share has been relatively constant at about 2Z of GDP while the natural gas subsector has increased from 0.9Z in 1980 to 1.3Z in 1987. The electricity subsector has increased from 2.4Z of GDP to 3.42 in 1987. The coal subsector share has been very small, at about 0.032 of GDP since 1980. Projections for 1988-2000 are th.at the share of the oil subsector is likely to remain constant (at near 2.3Z), and the natural gas and electricity subsector will continue to increase to 2.52 of GDP and 4.42 of GDP, respectively, by the year 2000. Coal is projected to remain very small. These figures imply that the share of energy is likely to increase from the present 7S of GDP to nearly 92 by the year 2000. 1.16 The finances and operations of the energy sector in Argentina are heavily influenced by mac':oeconomic factors and certain economic developments affecting public finances. The present economic system dominating the energy sector is characterized by a high level of taxation imposed on all energy sector activities, varying degrees of distortion occurring in the level and structure of energy prices, and a complex, inflexible system of earmarked funds, largely designed for specific investments but mainly in the power subsector. There are also many distortions in the compositica, structure, and coordination of various energy subsectors investments. In particular, the investment strategy and policy framework guiding the hydrocarbon subsector has discouraged exports of crude oil and petroleum refined products, which effectively eliminates any possibility of obtaining benefits for the balance of payments problem from the energy sector. C. INSTITUTIONAL ARRANGEMENTS IN THE ENERGY SECTOR 1.17 During the more than 80 years of hydrocarbon production in Argentina, many policies evolved in the form of laws, decrees, and regulations that directly involve all levels of Government in every aspect of this sector. The overlapping responsibility of numerous bureaus of the Government has contributed to institutionalized sector inefficiency. Among the agencies and ministries involved in setting policies, approving budgets, fixing prices, appointing top-level persor.nel, and approving contracts are the Ministry of Economy (ME). Ministry of Works and Public Services (MOSP), Finance Secretariat (SH), Energy Secretariat (SE), and the National Executive Authority (PEN). 1.18 The operating entities within the institutional structure of the hydrocarbon sector are dominated by YPF and GdE. (Details appear in Chapter II and Annex 1.1.) (a) Yacimientos Petroliferos Fiscales (YPF) YPF is a state corporation (empresa del estado), having a corporate structure similar to a private corporation, but the only shareholder is the Government. In actual practice, YPF controls all exploration and production of hydrocarbons in Argentina, with the exception of certain small old mining concession areas, and YPF also controls the majority of refining and marketing activities. Excluding the small concession areas, all private companies, both local and international, which participate in the exploration for or production of hydrocarbons perform thei- activities under service contracts with YPF. (b) Natural Gas del Estado (GdE) GdE was established in 1946 as a Government enterprise to provide natural gas distribution services as a public service. GdE purchases natural gas frceu YPF in producing areas located primarily in the Northwest, Neuquen, and Austral. Imported natural gas is also received from Bolivia. From the producing areas, GdE processes the natural gas and then transports the natural gas to consuming centers from where it is distributed to the individual end-users. GdE also produces and markets LPG (propane and butane). 1-19 The Argentine power sector is characterized by a fragmented and complex organizational structure. National utilities are in charge of the development, production, transmission, and distribution of electricity as well as the development of binational hydro resources. There are also about 20 provincially-owned utilities mainly in charge of electricity distribution. The utilities owned by the Government and their role in the power sector are described belows (a) Servicios Electricos del Gran Buenos Aires (SEGBA), in charge of generation, transmission, and dietribution in Greater Buenos Aires. (b) Aaua v Energia Electrica (AyE), in charge of na'ionwide generation, transmission and bulk supply, and also distributes electricity to a few provinces. It has responsibilities for integrated basin development, irrigation, flood control, drainage, and land reclamation. (c) Hidroelectrica Norpatan6nica (BIDRONOR), responsible for developing hydro resources in the northern Patagonia region. In addition, the Government participates in two binational entities with Uruguay and Paraouay, which are, respectively: (d) Comision T4cnica Mixta del Salto Grande (CTMSG), in charge of the Salto Grande Hydroelectric Plant (1,620 HW), operating since 1980. (e) Entidad Binac.0onal Yacyret& (EBY), in charge of the construction and eventual operation of the Yacyreta Hydroelectric Plant (2,700 Mg, to be finished in the mid-199Cs). (f) The Federal Government also owns the Comision Nacional de Eneraia Atomica (CNEA), which builds and operates nuclear power plants that supply energy to the sector's interconnected system. The CNEA reports directly to the president; since its creation in 4 t 't, -' . _- -7- National utilities report to the MOSP through the SE. The CTMSG reports to the Minister of Foreign Affairs. CNEA reports directly to the President and during previous governments has been able to influence the sector expansion towards nuclear options which were not subject to optimization studies. There is no comprehensive electricity law nor regulatory body in Argentina. Legislation is dispersed among various laws and decrees which sometimes overlap and at times leave important aspects of the electricity industry unregistered. The SE has overall responsibility for planning and operations at the national level and for the collection and distribution of the electricity funds. Since the SE has a weak technical capability, it resorts to borrowing staff from SEGIA and AyE; but still it is not able to fulfill its wide range of responsibilities. In practice the Miniptry of Economy retains final authority, since the Government perceives rates to have an important political consequences. As the provincas in Argentina enjoy a great degree of autonomy, the forum for discussing relationships between the Government and the provincial utilities is the Federal Electricity Co'mcil, a coordinating body which cannot make decisions. Thus, provincial governments have absolute independence for defining development policies i'nd tariffs that may not be consistent with national policies and priorities. 1.20 Since this overly complex institutional framework is, in part, responsible for the sector inefficiencies, the Government and the Bank have agreed on a plan of action for improving the legal/regulatory framework. As a first step, expected to be completed in 1989, a commission formed by experienced professionals with legal, planning, engineering, operational and financial background is preparing a diagnosis of the issues affecting the operations of the sector and a set of recommendations on how to overcome them. In a second step, measures which can be taken without special legislation by the Government should be implemented, while mes ures which would require special legislation are to be proposed to the Congress. improvement of the legal/institutional framework is required as a foundation for Bank support to the sector activities and are expected to be closely linked to Bank lending operations. D. ENERGY SECTOR FINANCES 1.21 In 1987, the public energy sector (YPF, GdE, and national power companies) had an operating income in the aggregate of US$3.6 billion. The aggregate operating income for 1988 is estimated at US$4.8 billion. However, when a myriad of sales taxes, fuel taxes, provincial taxes, federal taxes and royalties are applied the sector has a consolidated net loss of around US$2.5 billion each year. The cash flow for 1987 was a negative US$0.9 billion and is expected to be about the same in 1988. 1.22 The 1987 and 1988 results are summarized below: -8- Utilities YPF GdE Power Cos. 1987 - 1988 1987 - 1988 1987 - 1988 Actual Est. Actual Est. Actual Est. In Millions USS Gross Income 5659 6580 1087 1165 1397 1596 Operating Expenses -2906 -3248 -730 -910 -1077 -971 Operating Income 2753 3332 357 255 520 625 Royalties and Taxes -2366 -3157 -17 -36 -451 -521 Interest Expenses -988 -944 -173 -176 -292 -270 Depreciation -1.Z6 -1076 -200 -252 -248 -257 Total Non-Operating Expenses -4480 -5177 -390 -464 -991 -1048 NET INCOMEILOSS -1727 -1845 -33 -209 -671 -423 1.23 Much of the negative income in the energy sector is caused by an irrational taxation and royalty system, primarily in the hydrocarbon sector, which is described in detail in Chapter II (also see Annex 2.1). Distribution of Income Within the Energy Sector 1.24 Table 1.1 shows the distribution of energy sector sales income in 1987 and hig1lights the large central role of YPF in supplying fuels and feedstock to the private and public sector. As a result, most of these raw materials are supplied below economic cost. The petrochem.ical sector paid only US$127 million for raw materials (natural gas and liquids), which eventually generated US$1.5 billion in gross sales. In 1987, GdE paid only US$327 million for natural gas, which generated US$903 million of the US$1 billion of their gross sales during the year. The private oil sector sales to YPF of natural gas and crude oil in terms of sector revenue are relatively small compared to YPP, and are sold direc.ly to YPF. In addition to sales of fuels and feedstocks to other public and private sectors, there are large financial transfers frGA YPF to the power sector and the Government. Therefore, any attempt to seriously improve the efficiency of the energy sector must deal with reform of the system of pricing, subsidies, low-priced feedstocks, and financial transfers through taxes and earmarked fund from YPP to the many private and public sector entities. -9- Table 1.1z DISIRIWIIOn OP SALES PC - 1667 (E I ll en of Use) ..~~~~~~~~~~~~~~~mlin . . 53 Petra Ga. Private Cem. del Pmer Crude aI1 Alcohol Federal Provincial -PF Rdinri Q. fg& t _t01M Pin Plament Gen ]MthL Sales (outside the Sect.) 5.659 2,157 1.55 1,007 1,897 11.815 Sales to P.trebh.le l- 177 -127 85 -105 0 Sales to PriV&tX Refineries 888 -588 0 lnteSr-Secto. sales 8 42 -02 0 Natural sae Sales to CdE 20 -820 0 Fuel Sales to Pee r Coepanies 240 d12 -602 0 later-Sector Fund Trnnfere 4S07 -4 -72 465 0 T1... -2089 -18 -17 -516 8,81 0 R4watteym -20 297 0 Crude from Contractor. 664, 65 0 Alcamol turae -48 -27 70 0 4,129 852 1.588 1.187 8n 66 70 8.481 297 11.818 E. PAST WORLD BANK PARTICIPATION 1.25 Power Sector Participation. Since 1962, the Bank has made eight loans to Argentina's power sectors five to SEGBA to help finance an oil- fired thermal generation plant, and transmission, subtransmission and distribution expansions; one to BIDRONOR for the construction of the 1,200 MW El Chocon Hydroelectric Plant; and two to the Federal Government, the first one (in 1979) to help finance the Yacyreta Hydroelectric Project and the second one (in 1987) for a Power Engineering Project that is expected to provide the basis for improving the efficiency and economy of distribution expansions countrywide. Project performance audit reports have concluded that, while the physical objectives of the first five projects were largely met, their financial objectives were not. The latest of these reports, on the SEGBA IV Project (Loan 1330-AR, approved in September 1976 and completed in June 1985), indicates that the project was successful in meeting its technical and physical objectives of providing facilities to meet the growing electricity demand of the Greater Buenos Aires area; also, the SEGBA succeeded in improving its overall efficiency during the period of project execution. However, because of the lower- than-expected demand and the poor financial situation of SEGBA, the project suffered a completion delay of 4.5 years and a 40Z increase in total costs. Moreover, the Government's failure to implement adequate tariff increases prevented SEGBA from complying with its financial covenants except for a short period of time, thus contributing to its weak financial performance. 1.26 Initial execution of the Yacyreta project suffered significant implementation problems (para. 3.01), while the Power Engineering Project - 10 - (Loan 2751-AR) is progressing satisfactorily. A US$276 million loan to SEGBA was signed in June 1988 to help SEGBA finance its transmission and distribution expansion program, improve its operational performance and reduce losses. 1.27 Oil and Natural Gas Sector Participation. During recent years the Bank has been involved with and supported the energy sector in Argentina through several loans. In the 19808 activities have been undertaken in a complex environment of changing international oil prices, uncertain oil and natural gas reserve estimates, incomplete data, and changes in key personnel in the Argentine energy sector. Loans to this sector can be summarized as follows: (i) an engineering loan of US$27.5 million dedicated to performing seismic surveys and other resource studies; (ii) a refinery conversion loan of US$200 million was made in 1981 designed to convert the production of low-value fuel oil into higher value products. When the expected loans from foreign commercial sources failed to materialize, this Loan iias supplemented by a US$116 million loan in 1986; (iii) a line of credit through the National Development Bank of US$100 million to support the Argentine private sector in their efforts for increasing exploration and production activities in the country; and (iv) a natural gas utilization and technical assistance loan of US$180 million to provide assistance in building necessary infrastructure to allow increased uatural gas use. 1.28 Through the GUTA loan (Loan No. 2592-AR), a number of projects are being implemented for natural gas conaervation and transportation, for enhanced oil recovery project in older reservoirs, and for the application of automation technology to improve the efficiency of production operations. The Bank is also assisting through that loan in the development of a Master Plan for restructuring YPP and improving overall corporate efficiency. - 11 - CHAPTER II ENERGY SECTOR AND THE ECONOMY 2.1 This chapter analyzes the linkage of the energy sector to the macroeconomy related tot (i) public finances; (ii) the level and composition of sector investments compared to overall public investment; and (iii) the impact of Government policies and regulations. The broader non-price policies and regulations are emphasized. (See Chapters III and IV for discussion of sector price and tax policies.) A. THE ENERGY SECTOR AND PUBLIC FINANCES 2.2 The share of Government income from the different taxes collected and paid by the State Energy Companies has increased considerably in recent years (Table 2.1). Between 1970-1980 this share was between 8Z and 14Y and continuously increased to 212 in 1984; it decreased slightly in 1985 and 1986, and the increased again in 1987 to an estimated 19.1?. In 1988, there was a marked increase due to the introduction of new taxes earmarked for retirement pension funds and less developed provinces. Such a high share is unusual in a non-energy exporting country. 2.3 Three basic factors explain this tendencys (i) the need to control the consolidated deficit of the public sector; (ii) the deterioration of the country's basic taxes (the Value Added Tax (VAT) and the direct taxes); and (iii) the political and administrative tendency to impose charges on the energy sector rather than other sectors. 2.4 The consolidated deficit of the public sector increased to 15.2Z of GDP in 1983. subsequently decreasing in 1985 and 1986, to increase again in 1987 to 9.9Z of GDP (including an estimate of about 2.5Z of the so- called 'quasi-fiscal" deficit of the Central Bank). Estimates indicate that in 1988 it decreased again to 7.6Z of GDP, including 1.6Z for the "quasi-fiscal' deficit. 2.5 Argentina's total tax collection increased until 1980, when it reached a share of 20Z of GDP in 1980, decreasing to 15.8? in 1984, and recovering in 1985 and 1986 at 19.9?. Consequently, increases in the energy sector taxes in the 1980s as a percentage of GDP have been compensated with reductions in the collection of other taxes (such as direct taxes and the VAT). Income taxes represented 2.12 of GDP in 1970. This figure decreased to 0.55Z in 1984 but increased to 1.52Z in 1987. On the other hand, income derived from VAT increased up to 5.82 of GDP in 1981, decreased to 2.93Z in 1984, and recovered slightly in the subsequent years (3.39? in 1987). 2.6 There are three basic reasons for these tendencies. First, when there is accelerating inflation, there is a decrease in the share of both direct and indirect taxes, especially in the income tax (the so-called Olivera-Tanzi effect). Second, income tax efforts have not increased and collections of the VAT have been affected by variations in basic rates and specific exemptions. Third, the Industrial Promotion Law offered large exemptions over long periods of time for new investments in less developed provinces; consequently, it represents a progressive erosion of the tax I 1 tA a - 12 - 2.7 Increased taxation in the energy sector has produced the following consequencess (a) When taxes have been added to the 'commercial prices' (i.e., opportunity cost), they have caused considerable distortions in relative prices of energy products. (b) 'When taxes have not been added to the opportunity cost (as in the case of natural gas, LPG, and electricity prices, and occasionally other products), finances of energy sector companies have been severely affected. This has influenced to a certain extent the investment capacity of these companies. Above all, it led the Argentine Government to increase its transfers or compensations to the energy sector in such a way that the net effect on public finances has been low or even sometimes negative. (c) The cross-transfer system among the energy sector companies, other public sector companies and the Treasury has become exceedingly complex and is characterized by a broad range of specific earmarkings, including revenue transfers to companies in the same sector through the so-called 'energy funds.' This situation causes a considerable inflexibility in the allocation of public resources and impedes sound financial planning and execution of investment priorities by the energy companies and the Government. (d) The tendency to increase energy taxes at times has conflicted with anti-inflationary policies. During the first semester of 1988, the imposition of large new energy taxes sent a signal that led to increased monthly adjustments of prices and salaries in a large portion of the Argentine economy. On the other hand, when the Government tried to reduce inflation using an anti-inflationary policy mechanism, such as freezing or reducing monthly adjustments of energy prices (as happened with the Plan Primavera), prices fell in real terms, thus reducing the effective taxes collected by the Government. This resulted in higher transfers and compensations to the energy sectcr companies and coincidentally higher public sector deficits. TIble2: mREMCR OF' TOTAL TAX (I Of M8P) 1970 1971 1972 1978 1974 1978 197 1977 197I8 1979 1980 1981 1982 1983 1984 1985 1986 1.Tesbl 16.02 14.20 12.76 13.68 17.11 12.66 12.88 16.41 17.41 17.70 20.02 18.14 17.4C 18.81 18.79 18.78 19.66 2.Znomme tax 2.24 1.87 1.59 1.77 1.74 0.88 1.07 1.86 1.8o 1.19 1.68 1.71 1.56 1.41 0.8e 1.1 1.48 2.1 Profits 2.10 1.77 1.48 1.48 1.44 0.88 1.02 1.78 1.71 1.11 1.48 1.89 1.49 1.17 0.68 0.91 1.24 8.Soclal seur1ty rnd eaeries 4.78 4.n 8.98 4.79 6.82 4.86 4.82 4.00 4.62 8.94 6.69 8.40 8.20 8.48 8.88 8.06 8.22 4.Copitsl tsa 1.06 0.88 0.72 0.68 0.92 0.82 0.58 1.18 1.21 1.18 1.28 1.15 1.49 1.86 1.07 1.26 1.70 8.4ds nd servieet 8.28 4.76 4.12 4.01 6.06 4.92 4.42 6.68 7.91 7.69 8.87 9.94 9.48 8.86 7.77 8.01' 0.78 8.1 Grovs VIlu udded tea 1.86 1.76 1.44 1.20 2.09 2.01 2.69 8.81 8.87 8.89 4.29 8.88 4.72 3.94 2.98 8.11 8.481 8.2 Enerw tes 1.28 1.21 1.05 1.86 2.46 1.88 0.64 1.88 2.89 1.tU 1.68 2.44 2.67 8.06 8.84 6.19 8.20 5.2.1 Liquid fuel, grose 1.08 1.05 0.91 1.20 2.11 1.68 0.70 1.21 1.69 188 1.28 1."9 2.27 2.89 8.01 2.69 2.87 8.2.2 Eietric *ener consumption 0.12 0.09 o.o7 0.07 0.11 0.04 0.06 0.17 0.25 0.28 0.24 0.28 0.18 0.17 0.88 0.20 0.24 8.2.8 Obtura, W* coubl aat z 0.01 0.02 0.01 0.01 0.00 0.00 0.00 0.04 0.06 0.04 0.04 0.04 0.04 0.06 0.05 0.09 0.08 S.2.4 PtIa,a productics of crudr eli 0.07 0.05 0.06 0.5 8 0.24 0.16 0.88 0.18 0.20 0.18 0.17 0.18 0.18 0.26 0.20 0.21 0.09 6.Internatonanl trade & trs satlan 1.99 1.88 2.89 2.28 2.14 1.77 2.82 2.10 1.CS 1.78 2.18 1.98 1.78 2.94 2.86 J.21 2.78 7.Other 0.73 0.19 0.01 0.88 0.72 0.21 0.01 0.68 0.21 0.01 0.01 0.01 0.01 0.81 0.27 0.88 0.00 ers, tes o I of total 7.99 8.82 8.20 9.98 14.88 14.45 6.82 9.45 18.78 9.89 8.89 18.45 1U.27 16.82 21.15 17.08 16.80 SOF¢: Finane Secretri t - 14 - Transfers Between the Energy Sector and the Rest of the Public Sector 2.8 An analysis of financial transfers of the energy sector companies (based on information from the Argentine Energy Secretariat) with respect to those of the consolidated public sector (prepared by the Finance Secretariat) shows that between 1980 and 1988, YPF has had operational surpluses that, except for 1982 to 1985, were higher than the company's investment expenditures; however, transfers made from YPF to other public entities were higher than the transfers received by it (except for 1983). Table 2.2 shows financial transfers in 1987 and 1988. During 1987 and 1988 GdE had operating surpluses, although lower than its investment expenditures. However, GdE had operational deficits between 1981 and 1986. During this period, the shortages in financing were made up primarily from net transfers received from other public sectors, but also from an increase in net indebtedness. The state power companies had operating shortages during most of 1982-88. Until 1982, the main financing source was the net increase in indebtedness. From 1983, deficits were mainly financed by net transfers received from the rest of the public sector, much of it directly or indirectly from the petroleum sector. 2.9 As a whole, the energy sector had operating deficits between 1982 and 1985, but surpluses before and after. During the deficit years (apart from 1985), the shortfall was a small share of the public sector consolidated debt (between 3.92 and 5.1Z), while during the surplus years this surplus significantly contributed to reduce the public sector consolidated deficit. Transfers received by the energy sector during such periods ranked between 5.62 and 23.72 of total transfers among public sector companies. The share of sector investments has increased, especially during the last two years; however, this is mainly due to a severe fall in other public sector investments. Between 1980 and 1986 (apart from 1984) the sector absorbed significant percentages of the total public sector net indebtedness, especially during 1985-86. Within the last two years its net indebtedness was negative. 2.10 Table 2.2 shows the result of a more complete accounting of taxes and transfers to and from the energy sector. In the power subsector, in 1987, collection ef taxes and royalties was less than half the transfers and compensations received, but the energy sector as a whole collected and paid US$3,266 million in taxes and royalties, receiving about US$2,633 million in transfers and compensations. An important portion of taxes and royalties were received by specific public entities (e.g., the provinces and the electric and public works sectors). Supporting the Government finances with energy sector taxes has not produced the desired result. The process has led to unnecessary administrative complexity and introduced much uncertainty regarding the management of public finances by the energy sector companies and the Government. This situation undoubtedly has had negative effects on the sector's overall investment potential, as well as on macroeconomic management. 2.11 In 1988, there was an increase in transfers from the energy to the public sector, mainly as a result of the new tax on oil products earmarked for retirement pension funds and for less developed provinces. - 15 - Table 2.2. TOTAL TRANSFERS BETWEEN THE ENERGY SECTOR AND OTHER PUBLIC SECTORS (Millions of US$) 1987 i988 TAXES AND COMPENSA- NET TAXES AND COMPENSA- NET ROYALTIES TIONS ROYALTIES TIONS YPF 2805.00 1350.00* 1455.00 3608.00 977.00* 2631.00 Gas del Estado 17.00 227.00 -240.62 36.00 127.3 93.13 (Energy Funds) 30.62 1.83 Electric Sector 443.50 758.99 -518.35 407.00 587.7 -351.66 (Energy Funds) 202.86 170.97 YCF 0.84 52.81 -62.71 0.61 20.47 -39.15 (Energy Funds) 10.74 19.28 TOTAL 3266.34 2633.02 -633.32 4051.61 1904.55 2147.06 1987 Average exchange rate A/US$ 2.2535 1988 Average exchange rate A/US $ 12.33 1987 1988 F For Excess Royalties 439 451 For Foreign Debt Payments 911 526 Svstem of Earmarked Revenues until mid-1989 2.12 Many of the energy taxes have specific destinations. Royalties are assigned to provinces and the tax on refined crude goes to the Chocon Cerros Colorados Fund (FCCC) and the National Electric Energy Fund (FNGOE) (Figure 2.1). The earmarked funds in turn are assigned in various proportions to companies of the electric sector. About 352 of the taxes collected for the Fuel Fund are assigned Li FNE, and resources from this fund in various proportions are assigned to other funds and companies in the electric sector, to GdE, and to YCF. The remaining 652 is assigned to two other road funds that in turn are allocated to national and provincial zoads. Taxes collected for FONIT also are allocated in different proportions to national and provincial roads. The new tax on oil products (1988) is assigned in fixed proportions to pension funds and to less developed provinces. The Treasury receives only the VAT and the net revenues obtained by the difference between the consumer price (without VAT) and the ex-refinery price minus taxes assigned to the Fuel Fund Aad to FONIT. These net revenues are affected by a series of compensatory subsidie- granted by YPP to the provinces, private oil producers, and petrocheidcal industries, as well as to pay for most of the interest on YPF's external debt. So the final net revenues received by the Treasury are unpredictable. Figure 21 TAXES, FUNDS AND ALLOCATION OF RESOURCES Gasoline 10%) Taxes on Oil Gan (5%) 25 Oor 1 X 35% NE 1090ttG D.E FNE \ xEE (10%) 3 Nr % I (1031 VAT (15%) 3 FEDEI } ni (10%) F >O Taxss rv (1/3)~~_ - 17 - System of Earmarked Funds mid-1989 to end 1989 2.13 lTnder the Emergency Decree in July 1989, it was established that it is the intention of the National Executive Power to put a limit as to the National Treasury contributions towards providing subisides or direct cash to the public enterprises as of the end of October of 1989. Also, a unique fund was set up temporarily to be admini6tered by the Ministry of Public Works and Services (502 for 180 day, and 802 until December 31, 1990). This unique fund takes all the revenues from the excise taxes and surcharges (flowing into FONIT, FC, FNE, FNEE, FCCC, FNGOE) into one fund. For 180 days after the Emergency Decree, these are then split 502 to the National Treasury and 502 allocated in an unspecified manner among the various uses. These measurespaimed at providing flexibility in the administration of the resources during the emergency period, will not interfere in the development of projects under construction for the expansion of the electric system. Energy Sector Foreign Debt 2.14 The foreign debt of the energy sector as of December 31, 1987 and 1988 was US$34.6 billion and $13.5 billion, respectively. This represented 252 of Argentina's total external debt of US$58.3 billion in 1987 and 232 of the US$58.7 billion total external debt at the end of 1988. The breakdown of this external debt is as follows: Table 2.3: ENERGY SECTOR DEBT (US$ MILLION) YPF GdE Federal Power Co's EBY Total 1987 6,909 2,296 4,188 1,206 14,599 (of which current portion) 1,474 370 475 72 2,391 1988 5,713 2,250 4,058 1,505 13,526 (of which current portion) 856 216 178 54 1,304 (Annex 2.2 shows projections of the energy sector external debt in the period 1989-1995.) B. EVOLUTION OF INVESTMENTS IN THE ENERGY SECTOR 2.15 A summary of the evolution of expenditures and the consolidated public investment as well as energy sector investments (details in Annex 2.1) shows that investment in the energy sector has slightly increased its share of national and consolidated public investment over the last 20 years, increasing from 2.222 of GDP (average 1967-70) to 3.462 (average 1975-80), and then decreasing toz 2.532 in 1987. This was the result of an investment increase in this sector at an average annual real rate of 2.7Z, - 18 - while public investment increased by 1.82, and consolidated public investment increased by 0.5Z. During periods of rapid expansion, investments in the energy sector did not increase more than investments in other public sectors. So there does not appear to be a displacement of other investments by investments in the energy sector. 2.16 Investments in the energy sector have been somewhat more stable than other public or private investments in periods of crisis. This is because many investment projects have long gestation periods, earmarked funds (particularly in the electric sector), and because the sector has access to multilateral and bilateral credit. 2.17 Within the energy sector, the share of investments in the power subsector has shown a tendency to increase relative to investments in the hydrocarbon subsector (as shown in Table 2.4). This is due in part to hydrocarbon investments (exploration and production) being shorter term and flexible, so they can be more easily cut in times of budgetary crisis, as well as to large earmarked transfers from the petroleum to the power sector, with no reverse transfer, as there are no earmarked funds for the petroleum sector. 2.18 The increased share in electric power investment is the result of an increase in CNEA investments and in large hydropower projects. Many of the large hydropower and nuclear investments have had considerable construction delays, which has reduced the productivity of these investments to the economy. This tendency suggests an inefficient allocation of resources in this sector that should be carefully evaluated. The composition of the energy sector investment program has shifted ove. time, which effectively reduced the share of petroleum production investments (foregoing significant oil exports), and thus lowered the potential positive contribution of the petroleum sector during the recent period of high oil prices. The net effect has been to reduce productive hydrocarbon subsector investments and shift reso'irces to CNEA and large, inflexible hydropower projects, which historically have lower economic productivity. This implies that from a macroeconomic perspective it is most important to reduce subsidies and nonremunerated transfers to lower- productivity subsectors using instead tariff adjustments, which make such subsectors more financially self-sufficient. It also implies the need to shift resources to productive sectors that have export potential, such as oil and gas. 2.19 For depletable resources, such as oil and gas, the production and consumption of these nonrenewable resources has been counted as income as to the economy when in fact the country is consuming its capital. The past investment and production strategy has depleted this "capital" of nonrenewable oil and gas resources with insufficient investments in exploration to replenish this valuable stock of capital. - 19 - Table 2.4: COMPOSITION OF INVESTMENTS IN THE ENERGY SECTOR 1967 1967170 1970/75 1975/80 1980/86 1986 YPF 49.9 43.4 41.8 38.9 44.6 45.9 GdE 23.1 13.8 12.2 7.6 7.1 9.6 Subtotal hydrocarbon 732 57.2Z 54.0 46.5 51.7 55.5 CNEA 1.2 3.4 2.3 10.3 16.0 18.3 Electric sector 1/ 23.7 38.1 41.4 41.2 30.6 31.11 Electric sector and CNEA 24.8 41.5 43.7 51.5 46.6 49.4 Other 2/ 2.1 1.3 2.3 2.0 1.7 n.d. 1/ National and binational. 2/ YCF, energy sector, and other. C. IMPACT OF GOVERNMENT POLICIES AND REGULATIONS ON ENERGY SECTOR ENTERPRISES 2.20 Excessive Government regulation and past policies have had a negative impact on energy sector enterprises. This is due to pricing and taxation policies (described in detail in Chapter III), as well as other regulations and policies that cut across various state enterprises and sectors, as described below. Overlapping Responsibility 2.21 Overlapping responsibility of various Government agencies has contributed to inefficiency within the oil and gas sector. This complex system of regulation and control is as follows: (i) the Poder Ejecutivo Nacioral (PEN) appoints top-level personnel and approves all contracts with private companies for exploration, production, refining or sale of hydrocarbons; (ii) the Hinisterio de Economia (ME) participates in setting prices for all hydrocarbons and establishes annual budgets of expenditures for the parastatals; (iii) the Secretaria de Hacienda (SH) sets all taxes and provincial royalty payments; (iv) the Hinisterio de Obras y Servicios Publicos (MOSP) approves most contracts, budgets, key personnel changes, and numerous minor regulations that affect YPF and GdE; (v) the Secretaria de Energia (SE) fixes the final prices of all principal products, including crude oil and natural gas, and determines refinery margins, marketing margins, and the quantities, types, and disposition of all crude oil within the country (i.e., which refineries should process what kind of crude). - 20 - Impact of Policies and Regulations on YPV 2.22 YPF, the state-owned integrated petroleum organization, explores for and produces crude oil and natural gas, transports and refines crude oil, and markets crude oil, natural gas, and refined products to Lath end- users and other marketing organizations to satisfy internal requirements. YPF and its contractors account for over 972 of the total production of Argentina, out of which YPF itself produces some 47,300m3 per day and contractors to YPF about 22,700m3 per day. Of the total natural gas produced (some 54 million m3 per day), YPF produces 80? and private contractors produce the remainder. YPF controls enormous resources and occupies a position of great importance in the Argentine economy; however, its actual contributioi. to the economy is limited by: (i) distorted prices that are frequently less than actual costs of production for crude oil, natural gas, and refined products; (il) a royalty scheme whereby the Government requires YPF to pay the provinces about 242 of its crude oil revenue and nearly 75Z of natural gas revenue to satisfy s 12? royalty; (iii) a multiple excise tax system that increases costs and diminishes incentives to profitability, e.g., 15Z VAT (IVA) taxes on all purchases of goods and services (which cannot be recovered from the final sales of most refined products), plus a 10? tax on the value of all crude oil processed in local refineries, which effectively eliminates any possibility of competing in the products export market; (iv) contract pricing practices that result in YPF paying contractors more for crude oil production services than the price at which that same crude oil can be resold in the internal or export markets; (v) regulations that require YPP to sell a significant portion of its crude oil (nearly 40Z) to competitor refiners at a price that is less than YPF's actual cost of producing that same crude oil; (vi) obligations to purchase locally produced or supplied goods and services, even though these may be of poor quality and/or significantly more expensive than any imports (the consequences of Compre Argentino); (vii) labor and wage policy decisions set outside the company; (viii) severe restrictions on oil imports, exports, and products, and similar constraints, including subsidies to other entities. Between July and December 1989, efforts have been made to reduce the level of these subsidies and transfers, such as the temporary reduction of Compre Argentino restrictions, the change to limit royalty payments to 12? of international price. However, full price deregulation and tax changes still remain to be fully implemented to put YPF operations on commercial terms. 2.23 YPF does not have autonomy of decision-making nor the freedom of action to plan its own future program of investments and operations. Most fundamental decisions affecting the economic and productive operations of YPF are discussed or decided, not by its management, but by numerous agencies of the GoveLnment. These complex operating conditions do not allow YPF to function as a normal, competitive, profit-oriented organization, and result in poor financial performance. To achieve acceptable performance by YPF, the Government needs to implement fully measures to deregulate prices for crude oil, natural gas, and refined products, and at the same time establish an environment that will permit YPF to function with autonomy of decisions in the interest of increased profits and better management, within a competitive environment. - 21 - Impact of Policies and Regulations on GdE 2.24 GdE, as a parastatal, operates within numerous constraints imposed by Government policies and other regulations pertaining to the natural gas subsector. It gathers natural gas from YPP producing areas, processes and transports it to consumer centers, and distributes essentially all of the natural gas and LPG produced in Argentina. Natural gas is also imported from Bolivia under a contract that expires in 1992. Some 9,600 personnel are employed by GdE, distributed among 117 branches located throughout the country. 2.25 GdE is in a position to play a major role in the continuing future expansion of natural gas utilization in the energy sector, and has the potential for generating substantial additional revenue for the Government, provided that prices for natural gas, LPG, and other fuels are deregulated. GdE also must be granted decision-making autonomy and management authority over its operations to function in a business-like (i.e., profit-making) manner. Impact of Policies and Regulations on the Power Sector 2.26 Current policies and regulations do not foster efficient development of the power sector for several reasons: (i) they limit the autonomy of power utilities and increase their reliance on Government financial support; (ii) very little room is left for participation of the private sector in power ventures; (iii) there are no clear rules for pricing electricity and political interference in tariff setting is common; and (iv) public utilities are obliged to follow public service rules and limitations on employment and procurement. Impact of Compre Argentino 2.27 Compre Argentino has caused higher costs for goods and services to both private oil and gas producing companies and State enterprises (including YPF and GdE), while at the same time it also restricts real competition. This has led to obsolete technology and overall inefficiency. These complex restrictions also result in price protection of up to 200-3001. For example, YPF will pay about US$1,375 million for equipment, materials, and contract services this year. Of this amount, estimates show that the effect on YPP from the "Compre Argentinow and 'Contrate Argentino' legislation will amount to an increase in the nominal cost (cost without this "protection") of about 40X. Thus, about US$550 million per year was paid annually by YPF to subsidize the local private petroleum industry and other interests as added costs for its necessary operations. Also, the obligation to follow the "Compre Argentino" increases the cost of projects, since there is little competition among local manufacturers of electric materials. For example, SEGBA estimates that purchases of locally made products increases the cost of materials by 30-402, with the estimated effect on SEGBA's annual budget increased by about US$50 million. The Economic Emergency Law in July 1989 has transformed the virtually unlimited protection of domestic suppliers to the public sector to a 52 preference over the nationalized value of competing imports. However, with high tariffs and para-tariffs and only weak - 22 - competition between domestic suppliers, the public sector contirnues to be overcharged by the private sector. The problem would, of course, be substantially mitigated thorugh the actions on para-tariffs and tariffs. A more direct way, however, would be to replace the 5S preference over the nationalized value with a higher, say 152, preference over the CIF value. Thus a permanent elimination of Compre Argentino is needed to reduce its large distortions. Other Policies and Restrictions 2.28 Trade Restrictions. At present, there are numerous restrictions on crude and refined products trades for example, they cannot be freely imported or exported, and there is a complex systcm of restricti-ons on refinery crude oil supply and products output for both private and YPF refineries. Such restrictions lead to distortions and losses due to uneconomic allocations within the refining and marketing systems. Marketing should be adequately deregulated to provide proper incentives to competition and conservation, and at the same time to encourage and permit YPF and GdE to compete effectively under the same conditions that prevail for the private sector. 2.29 Exchange Rate System. The multiple excbange rate system, until its elimination in mid-1989, had a negative financial. impact on YPP, and acted as a disincentive for certain private oil producers and other state and private companies. Wide swings in the exchange rate have had and continue to have negative effect on financial and enterprise performance. 2.30 Labor and Other Policies. Labor and employment policies for all the state energy companies are heavily influenced by external groups, which increase costs, reduce management authority, create inflexibility for operations, and promote inefficiencies in all aspects of the energy business. 2.31 In addition to the above-mentioned policies and their impact on the energy sector, energy pricing and taxation policies are complex and create numerous inefficiencies and distortions. The following chapter is devoted to analyses of the problems with the current system of pricing and taxation. - 23 - CHAPTER III ENERGY PRICING AND TAXATION A. INTRODUCTION 3.1 This chapter first describes the complex system of pricing and taxation, comparing actual prices (with and without taxes) to economic opportunity costs for each energy type: crude oil and oil products, natural gas, LPG, and electricity. It then describes the specific financial distortions and subsidies in the hydrocarbon subsector, where financial distortions are particularly large. The impact of the pricing and tax system on the state energy enterprises is then discussed. A simmary is presented of the economic distortions and disincentives caused by the present system. Section I describes measures taken and proposed by the Government between July and December 1989 to reform the system of subsidies, royalties, and taxation. Recommendations for a comprehensive reform of taxation and pricing are given in Chapter IV. 3.2 Many of the inefficiencies and problems in the energy sector for both production and demand are caused by distortions and problems engendered by the current complex system of pricing and taxation. 3.3 Most producer prices received by state companies for crude oil, gas, and electricity are below financial and economic cost, which further exacerbates the financial problems of these enterprises and the public sector. However, many private sector entities that sell hydrocarbons to state enterprises receive favorable prices above economic and financial costs, while those private sector entities that obtain feedstock from state enterprises (such as private petrochemical companies and refineries) receive the corresponding feedstock at prices below economic and financial costs. This also contributes to the financial problems of the state enterprises, particularly YPF. Retail prices paid by the final consumer for petroleum products are generally much above economic cost--varying from 5Z to 2221 above, with gasoline being the highest--due to the large taxes on petroleum products. Natural gas and electricity have sizeable taxes but many final consumers pay prices significantly below economic cost, particularly consumer of residential gas, residential electricity, and other natural gas consumers. Large regional variations in electricity prices can be found as well. 3.4 There is a high level of excise taxation and royalty payments to provinces for oil and natural gas. In addition to this high overall level of taxes, the structure of taxation has many serious flaws including: (i) numerous taxes at various levels that distort incentives throughout the production process; (ii) a very complex and inflexible system of earmarked taxes; and (iii) little or no reliance on corporate income tax. 3.5 Economic distortions and disincentives affect all producers, refiners, and consumers. The cost to the economy, both indirect and direct, has been large, in excess of US$3 billion over the last 10 years. This is the foregone benefit to the economy due to unrealized oil exports, unnecessary losses of gas, waste in energy production and consumption, and - 24 - unrealized benefits of improved refinery operations. In addition, financial distortions are particularly large in the hydrocarbon subsector, where it is estimated that excess royalties and subsidies cost the Government at least US$2,200 million per year. This financial drain has contributed to the severe financial problems of YPY and GdE and, by implication. the country as a whole. B. DESCRIPTION OF CRUDE OIL AND OIL PRODUCTS PRICING AND TAXATION Crude Oil Pricing and the Royalty System until mid-1989 3.6 The present system of setting crude oil prices results in a controlled price that is below international parity and below YPF costs, with high royalty payments based on crude oil prices that are much higher than international parity. Two-thirds of the crude oil in Argentina is produced by YPF and the rest by private production companies working under 27 service contracts. (YPP pays each contractor according to the terms for all crude oil produced under each contract.) YPF, in turn, transfers part of this crude oil to YPF refineries and sells the remainder to private refineries at prices set each month by the Energy Secretariat. 3.7 The starting point for establishing the monthly crude transfer price for YPF is the contractual guideline that it be at 80 percent of the world crude price. The usual procedure is to s the Cuenca Nequina crude oil at 80 percent of the Arab medium crude oil price. FOB Saudi Arabia, and then develop prices for other Argentine crudes based on quality differentials. These quality differentials are established after discussion with YPF staff and representatives of the private 'efineries. Since actual quality differentials can vary with the refinery taking the crude, allocations of crude to the refineries is an important consideration in the decisions of the Energy Secretariat. 3.8 The end result of the transfer price determination is a price that historically is lower than YPF's upstream costs. The upstream costs are the average costs to YPF of its upstream operations, including taxes, royalties, capital recovery, plus crude purchases from contract producers. By international standards these YPF financial costs are high, due in large part to extra taxes, subsidies (e.g., Compre Argentino), and high overhead. 3.9 YPF pays royalties on all crude oil and gas produced (excluding small concessions) including that produced by service contractors. Royalties for crude oil have been based on a series of official wellhead prices set monthly by the Energy Secretariat, based on escalation of a base price defined on a December 1986 world crude price--which has been substantially higher than either the YPF transfer price or current world crude prices. 3.10 In 1987, the Treasury provided compensation to YPF for the significant net differences resulting from royalty determinations using wellhead values fixed by the Secretary of Energy (SE) for crude oil and natural gas and the actual local transfer prices (set by the SE) credited to YPF. A new Decree (941188), issued officially on August 5, 1988, el4minated this compensation to YPF by the Treasury (retroactive to March 1, 1988), which resulted in immediate and serious financial consequences for YPF. - 25 - 3.11 Based on June 1988 wellhead prices and crude oil costs, YPF must now pay the royalty for its own as well as its contractor's production. Therefore, for 25 MMCM per year of oil production, subsidies for excess crude royalties are estimated as follows: Royalty on wellhead value (SE) (at 121) $350,000,000 Royalty based on transfer price (at 122) - $217.000.000 Subsidy on crude to provinces $133,000,000 due to excessive royalties 3.12 Similarly, a royalty has to be paid by YPF for natural gas production of 18,000 NMCM per year, on the basis of June 1988 prices and costs, the subsidy is estimated as follows: Royalty on wellhead value (SE) (at 122) $227,000,000 Royalty on transfer price (SE) (at 122) - $ 33.000.000 Subsidy on gas to provinces $194,000,000 due to excessive royalties 3.13 In June 1988, the international crude oil price was $14.38/bbl, and the transfer price to YPF was $11.50/bbl with a royalty of $2.23/bbl. The result was a net realized price for YPF of only $9.27/bbl yielding a negative upstream margin of 1.79/bbl. YPF production costs, excluding royalty and contributions from National Treasury are $11.06/bbl ($69.57/rm3). These costs include the purchase of about one-third of the total Argentine crude oil production from private producers operating under service contracts. Table 3.1s EXAMPLE YPF CRUDE PRICE CALCULATION June 1988 A/Cubic Meter S/Bbl. International Price 788 14.38 (FOB Persian Gulf, Arab Medium) Transfer Price 631 11.50 Official Vellhead Price 1,071 18.55 Actual Royalty 122 2.23 Net Realized Price - YPF 509 9.28 YPF Production Costs 607 11.06 Upstream margin for YPF -97 -1.78 (Transfer price minus YPF financial upstream costs) 3.14 The consequence of this pricing anomaly is simply the more that YPF or its contractors produce, the greater the loss to YPF. The following figures demonstrate the magnitude of current losses. - 26 - Based on June 1988 crude oil prices (USS per m3) and costs for production of 25,000,000 m3 per year: Actual YPP costs (incl. royalty) $2,088,000,000 Less YPF gross credit - trans5er price -$l.809.000000 Net loss - crude production $ 279,000,000 Less excess royalty to provinces -$ 133.000.000 Subsidy to Government+private sector $ 146,000,000 3.15 YPP production costs less the excess royalty, are $78.21/1m3 ($12.43/bbl), which is significantly below international prices; depending on actual international price levels, the subsidy due to the low transfer price for crude oil is actually greater than stated when the opportunity value of crude oil is considered. 3.16 Rising YPF upstream costs, excluding royalty payments, during a period when wo-ld crude prices declined have contributed to the negative margin problem. The margin is highly variable since it depends on the exchange rate, international prices, and YPP cost escalation. 3.17 The current system does not provide the correct incentive to find and develop additional incremental crude oil. To create a more rational basis for crude oil pricing and to provide YPF with economic targets for its operations, field prices should be established by a realistic netback procedure starting from international crude oil and or product prices. If Argentina has more costly onshore transportation, marine terminal, or refining operations than major oil exporters, the field prices of Argentine crude should reflect them. Cost savings in these downstream operations could then raise field prices and increase the incentive to find and develop additional crude reserves. Netback pricing would likely provide field prices that are higher than the transfer prices, which are now set at about 80 of the world crude price. A 12? royalty based on netback values would certainly be lower than royalties based on "official wellhead prices' now in use. Crude Oil Product Pricing System until mid-1989 3.18 The Energy Secretariat has established several levels for oil product prices. Refinery product (tank) prices covers (i) the transfer price of crude; (ii) the 10? crude oil tax applied to the crude transfer price; (iii) a crude transport cost to the refinery; and (iv) a refinery margin. The total commercial price (retention value) provides for dealer and marketing margins and distribution costs (or products sold through service station pumps). The 'official sales price' includes two taxes added to the commercial prices. The first tax (Ley 17597) is for specific earmarked funds and projects, with rates that vary from negative to well over 100? of the commercial price. This tax includes revenues for the fuel fund, FONIT, and general income. The tax rates of Ley 17597 are designed tos (i) reduce prices in some areas for fuels like kerosene which is used to heat rural dwellings; and (ii) to produce large Treasury revenues from other products like premium grade gasoline. The second tax (Ley 23549) is used to raise funds for contributions to certain provinces and for pensions. -27- 3.1, An additional VAT of 15Z is added to commercial prices of fuel oil, diesel oil, lubricants, and specialty products, to arrive at a final consumer price for these items. However, VAT is not applied on gasolines, kerosene, or gas oil. Fuel oils delivered in bulk have an additional transportation charge based on actual transport costs. 3.20 Tables 3.2 and 3.3 give the structure of taxes and prices in australs (Table 3.2), and in order to facilLtate comparison, percentages of final retail prices and commercial prices are given (Table 3.3(a) and (b)). The prices and taxes shown are averages for Argentina. The impact of the various taxes (Ley 17597 and Ley 23549) and VAT is apparent in the official product sales prices shown. The power sector receives fuel oil and dlesel oil at prices substantially below other consumers. The gasoline consumer price is nearly double that of kerosene and diesel oil, since the two products show nearly equal commercial prices. 28 - (AueSwaSe per cAbic sour. October 1016) U - obtural W"F Gas bIbmlr Ea,. DlemI Fel Dieel 45 Ik.) Aware 9411n. 6.le" Keresen a".1 0 Oil oil oll Poel oil (Ai"en Ful I. User Price 6M79.9 0." 370.00 110.00 J1ZI0.80 U66.06 1775.8 1253.01 Z34.41 85.42 0S.O0S 2. VAT 0.04 0.00 0.00 0.00 38.10 22.08 400.35 IS2.00 05.48 8.55 8.68 S. Official eel I a price *6." 07.59 m67.00 51O.O0 0595.00 18501 17.00 960.01 196.08 12.3 4706.40 4. To. mo, ptpeam and pr.rine. 10.00 140.00 00D.0D <6.00 450.0D 4I0.D 0.00 0.00 0.00 3.66 915.00 5. Pul fea 691S#.00 8555.00 145.00 19.00 18.00 4.00 -1194.00 -730.00 0.00 0.c0 15.69 a. FAnl Fnd 19.00 144.5.0 954.50 741.10, 2D.20 146.70 056.90 15.00 770.31 h. Fa1 37.00 D5.70 45.55 157.45 4.44, 26.4 55.15 55.So 154.061 e. Oneal It 695.00 1590.60 -145.75 6U0.tS 45.64 -119.04 -15.18 -9.60 411.5 6. Ineilpel and prwtanct i- taxes 1O.14 0.71 7. CommerclmI retention Value 777.5 116l6.9 2966.00 2617.00 71001.00 1467.01 S9.00 160.01 117.60 5.98 W7.51 S. Dietribution mr4n 7b0. OD O.O 366.00 173.00 17S.00 M2.00 M.00 65.91 16.44 872.49 9. En-ref iner, price 07.5 6.ee 949.00 244904.1 S049.O0 12.01 2049.00 1294.01 15.66 9.54 1645.45 10. Crude Sax 181.10 116.15 185.44 115." 1S5.49 45.81 115.49 65.5? 124.65 11. Rmltie 1/ 94.60 0.95 217.5 057.85 07.85 181.60 257.55 1*1.00 514.54 12. tP_ i 10.20 1488.60 160.96 16.9o 15.95 145.64 19.96 10.64 1495.65 TOTAL TAII DIlS ROVLTAUL WZfl0 VAT 410.10 80.15 1157.49 959.49 6061.49 481.57 -1159.51 -64.43 0.00 6.04 73.54 TOTAL TAX UGDlUS U'ALTI Kl VAT 419.10 519.15 115.4e 211950.49 941.75 673.62 -758.16 461.43 25.45 11.69 1749.1? TOTAL TAE PUS IYA.LTI KIFH VAT 4410.70 5518.10 144.S 9916.0 12.34 681.26 -470.61 -900.48 s1e.n I/ Crude tSmi an roweltie. hee bee 1mi.ed proportionally sto e-refinra price. - 29 - mm si11ur N TeM ON PAL co ol ,la (h/pe l Reular EmIt, Oleml _ el OI- e1 45 4- A"ra noeilne Oseolin Keroeme G. I Oil Olil Fuel Oil il. (A$M) Ful 1. User Price 100.00 100.00 100.00 100.00 .00 1.00 100.00 1.00 100.00 1.0 2. VAT 0.00 0.00 0.00 0.00 0li 10.71 Z. 10.79 U.70 9.66 7.26 3. official selling price 100.00 100.00 100.00 100.00 W.9" 0.20 77.45 79.11 66.02 90.13 91.74 4. Ta for peneim en prwlncee 04.00 24.01 0.2*8 17.05 35.19 15.57 0.00 0.00 0.00 15.0 17.00 8. Fuel tax 04.69 40.26 8.60 U.76 0.48 2.84 -71.00 -6.81 0.00 0.00 26.05 a. Fuel Fund 00.62 17.67 7.10 1*.86 7.84 7.14 1U.0O 18.46 0.0 0.00 16.18 b. FOWNT 4.10 8.67 1.44 8.07 1.47 1.48 8.O1 2.77 0.00 0.00 8.04 c. General Incoe 10.27 18.0 4.06 15.a2 4.86 -.5 -910.05 -78.04 0.00 0.00 6.11 6. ohnclpul and provincial tfwee 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.05 1.05 0.00 7. Corcl.l retention value 41.05 5.78 2.1 8.2 78.87 n.8e 10.84 i1.61 6.70 72.84 46.41 6. Dietribution mrgIn 11.00 10.5 16.05 11.1 5.71 6.42 84.92 81.65 57.07 45.17 11.5 9. E-ref inery price 29.96 25.64 6.05 40.10 67.66 0s.97 115.41 106.77 46.63 26.66 7.14 10. Crude tax I/ 1.96 1.69 8.69 It." 4.47 4.16 7.66 7.06 2.4t I1. Roaptlt ie 4.20 8.0 7.84 8.63 9.80 6.84 18.2D 14.05 6.21 12. VW Income .77 210.0 44.00 81.62 8.69 49.97 91.59 84.72 29.47 TOTAL TAIX NIUI RIYALTnI WIT)f VAT 60.95 48.98 81.84 8.44 10.09 .07 -4.#5 -.S5 0.00 022.7 46.77 TOTAL TAM MULB ROYALTI WMTH VAT 60." 6J.95 81.64 51.44 81.10 02.78 -41.70 41.8 11.7S J2.2t 14.08 TOTAL TAXm PLIS RDYALTIE WITH VAT 63.15 69.68 89.J7 87.07 40.60 41.61 -16. -16.67 69.25 If Crude tax and rcyltie- kaw. been m* end proportionelly 1to -refInery price. - 30 - MM1C SllWtUS NO TA ON IWL To lcrle Secdnr .P Natural (A/p.r Ce. Rewlnr Entr Oiesel Ful Diesel 45 kg. Averea Oollqe Onollnn Kiroaee Gae 01 Oil1 oil Oil FueI Oil i1. (AIMM l 1. User Price 43.70 M7S.S 96.60 145."9 18.99 140.06 64.8. 72.14 l11.47 811.24 206.61i 2. VAT 0.00 0.00 0.00 0.00 8.00 18.00 1.00 5.OO 14.06 38.66 1t.00 S. Official e*lilne price 248.70 279.66 138.60 115.96 191.29 126.09 61.62 87.14 106.40 134.S8 191.51 4. Tom for pensions and province. -6.66 67.20 66.61 86.24 90.70 91.61 0.00 0.00 0.00 21.66 li7.1 5. Fiul ton 66.06 112.66 4.96 62.02 0.59 3.27 .4 .46 42.6 0.00 0.00 64.i6 a. Fual Fund 60.00 80.00 10.00 80.00 10.00 10.00 10.00 10.00 0.00 0.00 61.851 b. FON1T 10.00 10.00 2.00 6.00 9.00 2.00 9.00 2.00 0.00 0.00 1.27 c. General Incoa 26.06 62.60 -7.02 26.02 -11.41 -8.78 -60.4i5 -6.06 OCO 0.00 16.74 6. Imielpal Vnd prvincsl texas 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5.40 2.7J 0.00 7. Co_arcial rentIon value 10.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 1O.OO 100.00 S. Distribution srgin 27.00 98.66 99.62 91.70 7.79 11.79 28.92 92.90 44.9 66.96 98.16 9. -oineQ price 7J.00 71.82 77.66 76.i0 92.91 86.91 7.77 77.02 6.71 86.719 .70 10. Crude fax / 4.80 4.79 S.19 5.t8 6.10 5.66 5.00 5.00 6.0? I1. Rvaultie / 10.94 10.01 10.66 10.9 12.94 19.86 10.77 10.61 10.70 12. IPP Income 67.95 ti.59 61.40 62.18 78.15 70.00 80.02 61.12 60.67 TOTAL TAXES MS ROYALTI6 Wrr11O.I VAT 140.6 1*.69 46.71 10.44 27.t8 80.92 45.41 -47.7 0.00 30.95 ".811 TOTAL TAXES MSS ROYALTIM WIT VAT 140.63 1*4.69 46.71 10.44 42.t8 45.92 -28.41 -22.75 14.00 44.6o 11.8 TOTAL TAXES PS ROYALTI66S WtH VAT 168.77 194.60 64.87 111.48 S5.66 86.80 -17.66 -11.95 192.88 1 Crude ta and ralties hove been aesined proportionally to ax-refinry price. - 31 - ComparJson of Argentine Petroleum Product Prices to Economic or Opyortunity C0ot Prices 3.21 Since petrolum products are easily tradeable, the economic cost of petroleum products is the international value. Domestic petroleum product prices generally have been above international prices in the last few years, in contrast to the 19708 when prices were much below international prices. Table 3.4 compares the end-user retail prices of petroleum products in Argentina (including ex-refinery price plus marketing margin, both with and without taxes) to the equivalent international price (landed price plus marketing margin). The approximate international prices are taken from price data of SeptemberlOctober 1988 (detailed figures in Annex 3.1(a)). Domestic retail prices of gasoline (including taxes) were three times the international prices and slightly lower than many developed countries (see Annex 3.1(b)). Gas oil was about twice as high as international prices. Fuel oil commercial prices (without taxes or subsidies) were at or above the economic price. Considering the subsidies on fuel oil, the retail price to industry is only slightly higher than international prices; these range from 5-1OZ higher during periods of strong fuel oil prices to 302 higher when world fuel oil prices are low. However, fuel oil and diesel fuel for the power sector are significantly lower than international prices. 3.22 The ratio of domestic to internationLl prices fluctuates over the year. For example, the overvaluation of the exchange rate in late 1988 increased the ratio, while the exchange rate devaluations in mid-1989, coupled with the 402 rise in international oil and product prices by the end of March, led to a significant reduction in the ratio of domestic to international prices. In May 1989, Argentine gasoline prices fell to nearly half the international price. Table 3.4 also shows the percentage ratio of 1989 prices (those prevailing July to mid-December 1989) to international prices (see Table 4.1). As can be seen gasoline prices were close to fourth quarter 1988 levels. However, all before tax and after tax fuel price ratios in 1989 were below the 1988 levels, except the after tax price of fuel oil to industry. - 32 - Tabl 8. 4: COMPARISON OF ARGENTINE PETROLEU PRODUCT PRICES TO INTERNATIONAL PRICES (Economic Opportunity Cost) PERCENTAGE RATIOS Commerc4l Price Comerclal Price w/o taxes to with taxes to Economic Price Economic Price w/o taxes w/o taxes 1988 1989 1988 1989 Gasoline - Regular 115 95 296 2S6 - Premium 109 91 822 267 Kerosens 96 76 140 76 GOsoll 94 78 194 127 Dieel - Industry/Other 79 S9 116 92 - Pwer Sector 62 - 78 - Fuel Oil - Industry/Other 149 75 1065 144 - Power Sector 94 74 71 7N Source: Table 4.1 C. DESCRIPTION OF NATURAL GAS AND LPG PRICING AND TAXATION Producer Prices and Costs for Natural Gas 3.23 Most natural gas produced in Argentina is the controlled by the state oil company, YPF. About 81S of the gas is produced by YPF and the rest either imported from Bolivia or produced under service contracts with private production companies. Thus, all gas in Argentina appears in the ledgers of YPF, although it may not pass through the physical facilities of YPF. Gas imports from Bolivia are paid directly by GdE. Gas, not used or lost in field operations, is also sold to GdE. The present system of gas pricing has several serious flaws. The producer price is much too low to encourage exploration and production of new gas: also, royalty payments are too high relative to wellhead natural gas prices. 3.24 Each month the Energy Secretariat publishes a natural gas transfer price for sales to GdE. This price is arbitrarily set along with gas tariff rates, the official wellhead price on which production royalties are based, and a series of crude oil and oil product prices. The gas transfer price is set well below a reasonable market value. The official wellhead price is based on artificially-high 1986 world oil prices with inflationary Adjustments. This, in turn, means that the 121 royalty payment is well above 12Z of the actual transfer price. YPP natural gas transfer prices varied from 17 to 32Z of official wellhead prices and royalties from 38 to 73Z of the transfer prices. Between 1986/87 the transfer prices were lowerei by 202 while the royalty was reduced by 11Z. Between 1987/88 transfer prices were eroded even more, being reduced by 14Z while royalties declined only 4Z. Neither transfer prices nor official wellhead prices y ve be, set at levels comparable to market values since 1985. - 33 - 3.25 In 1987 and the first two months of 1988, YP' was compensated by the Treasury for part of the royalty payments it made on gas produced domestically. In 1987 this compensation allowed the net price YPF realized on natural gas sales to rise to US$0.53 per mcf--equal to the 1984 net price. After royalty compensation payments were eliminated, the net price fell to a new low, below US$0.20 per mcf. Such prices fall far short of covering YPF's costs for finding and producing natursl gas, as the following figures attest: Based oa June 1988 natural gas prices (USS per CM) ani costs for production of le,000 M m3 per years Actual YPF costs (incl. royalty) $ 854,000,000 YPF gross credit - price to GdE -$ 276,000.000 Net loss - gas production $ 578,000,000 Less excess royalty to provinco,s -$ 194.000.000 Subsidy $ 384,000,000 3.26 Field prices for natural gas (10 to 20 cents per mcf) that YPF now receives provide no incentive for gas exploration, development, and production. Some service contracts YPF has with private producers provide slightly higher prices. These producers received prices in June 1988 that ranged from US$0.17 to US$0.97 per mcf and pay no royalties. In June 1988, the average contractor price was US$0.46 per mcf, which was below the US$0.53 per mcf transfer price in 1987, but well above the transfer price less royalty payment (that YPF must make for all gas) of US$0.15 per mcf. 3.27 Higher field prices that take into account the market value of natural gas in relation to substitute international fuels prices are urgently needed to provide incentives for additional private producers to discover and produce natural gas. Table 8.S: PRODUCER PRICE AND GAS ROYALTIES (US$/Thousand Cublc Feet (MCF)) Transfer Royalty Incom Price Pric Royalty (I )P) Compensation YPF 1984 0.841 2.642 0.815 (88%) 0.524 1985 6.731 2.814 0.8U6 (48%) 0.348 1986 0.745 a.u8o 0.439 (545) o.3a6 1987 0.59 8.289 0.889 (6SX) 0.82 0.524 1986 0.6.1 8.128 6.878 (78S) 0.062 0.217 - 34 - GdE Tariffs and Consumer Gas Prices 3.28 Consumer prices for natural gas are set by the Energy Secretariat each month. The present pricing system is complex, inflexible, and adds many taxes on top of the low producer price. Social consideraticns and the desire to replace other fuels with natural gas have lead to gas tariffs that are low compared to substitute fuels market values for gas. From July to December 1989, in an effort to offset the low price for domestic users, the price for industrial users was set at level higher than the fuel oil equivalent which reuslted in a return to the situation existing in 1977. (See Table 3.7) 3.29 Gas tariffs in Argentina can vary based ons the type of consumer, the volume of gas used by the consumer, and the geographic location of the consumer. Location influences tariffs in two ways. Tariffs are lower near producing fields because of lower transportation costs. Also, tariffs are lower in the south where customer incomes are relatively low. For residential customers, tariffs rise with increasing volumes on the assumption that those customers with large gas needs can afford higher prices (even though unit costs usually decline with rising volumes). All other castomers have tariff rates that decrease with increasing volumes, since unit coste usually decline with greater volumes. 3.30 Taxes on Natural Gas. In addition to basic natural gas tariffs, each consumer has to pay up to five taxes (another 50 to 552) to constitute the final price. These taxes include the 151 VAT (GdE is allowed to pass on all of this tax), the 10 National Tax, the Provincial Tax (which varies between 0 and 12S), the Municipal Taxes (which vary between 0 and 101), and the Ley 23,549 Tax (241, which provides funds for retirement pensions). For example, for a typical industrial consumer in August 1988, GdE averaged sales revenues of about US$1.89IMIBTU, of which half went for gas purchases from YPF and the rest covered GdE operational costs. The taxes total another US$0.98/WMBTU to arrive at a US$2.871NMBTU as the natural gas price to the industrial consumer. GdE is exempt from income taxes until 1992. It is not known whether this exemption will be continued. 3.31 Competitive Fuel Costs. Natural gas is considerably cheaper than any other liquid hydrocarbon in Argentina except for the subsidized heavy fuel oil used for electric power generation. Natural gas for nonresidential use costs somewhat more than comparable US prices. However, in the residential sector, Argentine gas is sold at a price of only 431 of the US average--another illustration of the unreasonably low price of residential gas. In the US, residential gas (based on cost of service regulation) is priced at 2.5 to 3 times the charge for industrial and power generation uses. The highest tariff in Argentina shown is $0.094 per cubic meter ($2.66 per mcf) for central Buenos Aires area residential customers' gee use above 600 cubic meters per month. (See Table 3.6 for comparison.) - 35 - Table 8.4: COMPETITIVE END-USER FUEL PRICES IN BUENOS AIRES, AUGUST 1986 USS/Cubic USS/MM Btu US Meter Excluding Excluding Including Average Tax"s Taxes Taxes Pric_e Residential Natural Gas o.0667 1.81 2.75 6.4' Keronse 191.2S 8.58 6.06 7.68 Propane - .6 6.48 9.85 Industrial Natural Gas O06696 1.69 2.87 2.61 Industrial Light Fuel Oil 160.88 4.89 6.18 4.00 Industrial Heavy Fuel Oil 99.68 2.62 8.62 2.66E.t Elec. Poer Natural Gas 0.6014 1.66 1.91 2.18 El e. Poor Light Fuel Otl 192.60 65.2 6.04 - El e. Posr Heavy Fuel Oil 114.08 2.68 8.81 2.45 Notes: - Natural gas residential consumer taxes estimated at 52% of tariff rates; natural gas *t 1,045 Btu/cubic foot. - Exchange rate for August 11.5 swa 12,000A/US1S. - Kerosene and fuel ol s Include the general sates tax of 15% on retention values. Heavy fuel oils xexlude fInal de Ivery cost becuse no data wee obtained. - Gas prices based on consumption rates of 100 cm/month for residential, 409 cm/day for lndustriol, and 60,16 cm/day for electric generating stations. Propane price based on consumption of SW Btu/month. US price based on consumption of 5M Btu/month. US prices are for June 1986. Prices Including tax of fuels to electric poser are calculated assuming only a VAT of 15%. Source: Oil products from PF PIndleadorex Economic* Financloros, Sept. 1956.' Gas and propane from CdE transmittal. 3.32 Consumer Pricing. The ratio of fuel oil to natural gas prices charged to industry was 1 to 3 from 1980 to June 1989. For the residential sector the ratio has been 2 or higher since 1977. - 36 - Table 3.7: RELATIVE CONSUMER PRICE OF NATURAL GAS (Prices of each fuel on heat-equivalent basis) Industry Residential Ratio of Ratio of Ratio of Kerosene/ Year Fuel Oil/Natural Gas LPG/Natural Gas Natural Gas 1977 0.70 2.10 2.0 1980 1.08 3.00 2.6 1984 1.74 4.31 4.2 1986 2.64 3.62 3.3 1988 (August) 1.26 2.00 2.7 1989 (July-Dec.) 0.80 2.40 1.9 Ideally, the ratio should be near 1 to reflect substitutability of fuel oil. LPG, and kerosene by natural gas. The impact of this pricing policy has been to promote greater use of natural gas with no incentive to control waste and promote energy conservation. 3.33 LPG Pricing and Market. The current system of LPG pricing provides low prices to private sector LPG distributors and petrochemical companies, and high energy costs to consumers of bottled LPG. (Details of LPG pricing and taxation appear in Annex 3.2.) About 822 of the LPG supply (about 1.2 million tons in 1986) is controlled by GdE (50Z) and YPF (322), while the rest is shared among two private companies (ESSO and SHELL) and two mixed companies (PETROQUIMICA GENERAL MOSCONI and PETROQUIMICA BAHIA BLANCA). GdE sells LPG to private companies after the liquids contained in natural gas are separated into butane and propane. Private companies then bottle and distribute the LPG to consumers. The remainder of the LPG is sold to petrochemical companies or exported. GdE is not directly involved in the distribution of butane and propane to consumers, but plays a regulatory role in the control of safety, quality, and quantity standards of LPG in bottles. This regulatory role should be transferred to the Secretaria de Energis. Table 3.8: THE PRICING STRUCTURE OF LPG (MARCH 87) Australs USS per ton: per ton: Purchase price paid by GdE to YPF 95 61.65 Sales price of YPF to petrochemical companies 155 100.58 Petrochemical companies payment to YPF (net of contribution by Treasury) 110 71.38 GdE sales price to bottling companies 211 136.92 Bottling companies sale to consumers 480-550 311-357 - 37 - Table 3.9s PRICE OF LPG AS PETROCHEMICAL FEEDSTOCK Price Paid International Price by Petrochemical Companies LPG (Australs/Ton) (Australs/Ton) C3 Propane 1272 868 C4 Butane 1380 808 C4 Isobutane 1572 889 Source: YPF - October, 1988 3.34 GdE wholesale price for LPG reflects the additional investment and operating costs for processing of natural gas and transportation of LPG for delivery to 16 wholesale distribution locations in Argentina. While prices paid to YPF and GdE for LPG are fixed by SE, prices to end-users for bottled propane and butane are not, except for a reference price which serves as a guide to private distributors. The end result is high LPG prices paid by the final consumer, many of whom are medium to low income. Table 3.9 shows the low price paid by petrochemical companies. 3.35 These distortions and subsidies to private sector entities could be solved if LPG prices were deregulated at various stages of production, fractionation, and distribution. D. CONPARISON OF NATURAL GAS AND LPG PRICES TO ECONOMIC OPPORTUNITY COSTS 3.36 The economic opportunity cost for natural gas is the value of the marginal fuel displaced by incremental gas production. In Argentina, this marginal fuel is fuel oil mainly used in power and industry. Therefore, a natural gas price set just below (e.g., 10? below) the international fuel oil price represents the economic opportunity cost for gas used in power and industry. The value of gas in residential and commercial markets is the same as that in the power and industrial sectors, but with additional distribution costs added. Since the determination of which fuel is the marginal fuel displaced by incremental gas production, an overall evaluation of natural gas supply, demand, and economic cost, including depletion premium, is necessary. (This is discussed in detail in Chapter VII; discussion of natural gas pricing principles appears in Chapter IV.) Table 3.10 shows that, for 1988, natural gas prices without taxes are very low, between 46Z to 672 of the economic cost, with residential prices being the lowest. Prices, including taxes, were between 70 and 1001 of the economic cost. LPG commercial prices without taxes were 84? of LPG economic cost (based on imported LPG costs, since LPG was imported in 1988); LPG prices with taxes are equal to economic cost. In 1989 (July to December), the already low ratio of natural gas to its economic cost in the residential sector dropped to a very low level, with commercial prices (including taxes) being only 151 of economic cost. Industrial price ratios were about the same in 1988 and 1989. The very low residential natural gas prices are a serious concern and compound interfuel price distortions. - 38 - Table 3.10. COMPARISON OF NATURAL GAS AND LPG PRICES TO ECONOMIC OPPORTUNITY COSTS Z Ratios Commercial Price Commercial Price without taxes to with taxes to Economic Price Economic Price without taxes without taxes 1988 1989 1988 1989 Natural Gas -Residential 46 10 71 15 -Industrial 67 65 100 100 -Power 62 46 94 55 LPG 84 n.a. 100 67 Sourcet Based on Table 4.1 E. DESCRIPTION OF ELECTRICITY PRICING AND TAXATION Backtround 3.37 Electricity rates in Argentina show a high dispersion both in terms of level and structure. A complex system of surcharges and taxes distorts the price signal to the final consumer. Cross-subsidizing exists among regions and categories of consumer. On top of this, average rates in real terms are subject to permanent fluctuations as no systematic ways to keep pace with inflation erosion is in place. These problems stem from the procedures for tariff setting which are not based on economic considerations and subject to political interference. At the production level, energy and power transactions at the DUC fail to reflect production costs. At the retail level, low level of average rates and important subsidies to residential consumers have resulted in chronic revenue shortfalls for the national utilities. Tariff adjustments made in July 1989 --after a period in which average rates in real terms fell dramatically as result of the hyperinflation process--did not provide for average rates to reflect costs. Moreover, those adjustments tended to deepen price distortions and to increase the amount of subsidies to some customers. The paragraphs below review the procedures for tariff setting, the estimated production cost of electricity, and briefly analyses the prevailing price/cost relationship at the producer and f5r.al user levels. Procedures for Tariff Setting 3.38 Argentina's electricity pricing system is quite complex. In addition to the value added tax (VAT), which is applied to electricity sales and goes into general funds, a substantial part of the revenues of each utility is paid by the final consumer to the Federal Government in the form of earmarked Electricity Fund surcharges, which then return to the - 39 - sector as Government equity contributions. On top of these taxes, the final user also pays provincial and municipal taxes as part of their utility bill. These taxes vary widely throughout the country. The aggregate effect of surcharges and taxes is that the price paid by the end user is between 30.6 and 65.62 over the rate received by the utility. 3.39 Electricity rates for the national utilities, as well as transactions by the national utilities at the national dispatch center, Despacho Unificado de Cargas (DUC), by law are to be set by the SE. In practice, final approval is given by the Ministry of Economy and is often, subject to political considerations. The recently signed PFE (para. 38 (b)) is expected to set clearer rules for tariff setting. Rates for provincial utilities are set by the provincial governments. Economic Cost of Electricity Supply 3.40 Costs of electricity supply are estimated at the various tension levels: (i) High Tension (HT) before transmission (generation level) and after transmission (applicable to large industrial consumers); (ii) Medium Tension (MT) distribution (applicable to industrial consumers and large commercial consumers); and (iii) Low Tension (LT) distribution (applicable to small commercial and residential consumers). A comprehensive study of supply costs of the power sector based on LRMC analysis is being carried out under the Power Engineering Project for which preliminary results at the generation level are available. To provide a preliminary basis for comnaring the current prices with costs, a rough estimate of costs of supply was prepared under this study and shown in Table 3.11. The energy costs were estimated on the basis of a simulation of system operation with the current configuration and assume a marginal fuel price of US$2.40/MMBTU. The investment costs were estimated on the basis of installing of a gas turbine unit, the most likely solution to supply one additional kW of demand. At generation level, the results of this estimate (US$41 mills/kWh) are close to those of the tariff study (US$39 mills/kWh). Costs for MT and LT were estimated on the basis of typical investment requirements for such distribution networks. Results are shown belows - 40 - Tabl- 8.11: ESTIUATED MARGINAL COSTS CUSS/k1h) A. For Tenslon Level peak Off-Peak Generation J.041 0.041 Transmisson 0.654 9.042 Medium Tension 9.074 0.948 Low Tens on 0.097 9.094 B. Applied to Tariffs Peak Off-Peak Average Transmission O.OU 0.042 IT (industrial) 9.112 0.048 C.OW MT (industrial) 0.16S 0.046 0.068 LT (residential) 0.148 O.OU 0.097 Using weight for the share of Industrial consumption (about 60X) of HT, cenmrcial consumption (about 15X) of MT, and residential consumption (about 8S) of LT, the approximate weighted avrerge cost Is US89.07/kWh (=70 till/Kwh). Rates AvSlied to DUC Transactions 3.41 Operation of the SIN is coordinated by the DUC (Despacho Unificado de Carga), in which all producers are represented and which is manged by AyE. The results of the operations are reflected in energy and power transactions, subjects to cross compensation among the utilities on the basis of tariffs set by the SE. Though the stated purpose of the DUC is to minimize the NIS's operating costs, bulk rates set by the SE do not promote efficiency. Prices for purchasing utilities are set as the average of power and energy prices the SE assigns to the seller utilities. In practice, it has happened that the prices offered to sellers have been too low to compensate for generation expenses. 3.42 The average price paid by the purchasing utilities in the DUC transactions has suffered fluctuations not related to production costs. In the last times it has decreased from US$ 30.2 mills/KWh in December 1982 to US$ 14 mills/KWh currently. This value is very low as compared with the estimated transmission level marginal cost of US$ 45 mills/KWh. This means that the purchasing utilities are receiving an incorrect price signal; thus the average cost for these companies decreased with increasing purchases while the producing companies are not able to recuperate production costs. - 41 - 3.43 The DUC rate system is expected to be revised under the PEE on the following principles: (i) prices should reflect cost structure and levels, (ii) the whole production system should be incorporated to the DUC --currently rates are applied only to net transactions--, (iii) rates should be set ex-ante and not a posteriori, to send the price signal to purchasers, (iv) the financial adjustments should be made on the basis of each utility's operation costs and investment commitments. Electricity Prices in Relation to Costs 3.44 Residential electricity prices (including taxes) are far below economic cost all around the country (for example for SEGBA, average residential rate is estimated at US$ 24 mills/KWh -- see Annex 8.11 -- or about one fourth of economic costs; EPEC's average residential rate is estimated at US$ 53 mills/KWh). Commercial prices (including taxes) are over economic cost while industrial prices (including taxes) are from one half to twice the economic costl (see Annex 8.12). 3.45 The above differences show that tariff-setting in Argentina is based on political rather than technical considerations and is heavily influenced by macroeconomic developments. The present method of setting tariffs restricts rational and efficient development of the electricity market. It is clear that important transfers exist, mainly subsidies from commercial to industrial and residential consumers. 3.46 Estimates of costs of supplying electricity for the sector on the basis of the national utilities financial statements ($0.08/kwh without tax) are higher by about 15Z than the marginal cost ($0.07/kwh). This is reflected in the poor financial performance of the sector (para. 8.48). F. FINANCIAL DISTORTIONS IN THE HYDROCARBON SUBSECTOR 3.47 There are numerous financial subsidies and distortions in the hydrocarbon subsector. Distortions arising from the high level of royalties, low crude oil prices, and low natural gas prices have been described earlier in this chapter. Additional subsidies (described in Annex 3.4) come from nonrecovery of VAT (IVA) tax, forced sales (of petrochemical feedstock, LPG, and coke) to companies at low prices, tax on refined crude, and low sales prices of crude to refineries. 3.48 Subsidies (actual and implied) for 1988 are sammarized in the following tabulation for the hydrocarbon subsector (Fourth Quarter 1988 US Dollars)t 1/ Exchange rates used to compare cost to domestic prices was A635/US$ -42- *1 Excess Royalties and Subsidies in 1988 Crude oil price subsidy to public & private sector 146 Natural gas subsidy 384 Value-added tax subsidy 130 Petrochemical feedetock subsidy 68 Sale of LPG subsidy to GdE and LPG distributors 21 Sale of coke subsidy to YCF 18 Excess royalty on crude oil 133 Excess royalty on gas 194 Compre Argentino subsidy to local private 550 Total 1.644 Note: This tabulation is for illustration only; it is not considered to be all inclusive, and some of the subsidy amounts may be compensated to other parts of the hydrocarbon subsector, or transfers to other portions of the country's economy. Excess crude oil and gas royalties were eliminated in September 1989. 3.49 Several changes and proposals for changes to reduce these excess royalties and subsidies were made between July and December 1989, as described in Section I of this Chapter III and in Chapter IV. If the Government implements these changes on a permanent basis and effectively implements proposed price changes and deregulation, then this level of subsidies would be reduced substantially. 0. FINANCIAL IMPACT OF THE PEESENT SYSTEM OF PRICING. TAXATION. AND ROYALTIES ON FINANCES OF STATE ENERGY COMPANIES 3.50 Variations in the structure and price levels have created complex variations in YPF, OdE, and in state power company finances, as well as a reliance on a complex system of cross transfers. The system has had a very negative and direct financial impact on YPF and GdE finances and a negative but indirect impact on Government finances. Neaative Imnact on Finances of YPF and OdE YPF had an operating income of US$2.9 billion in 1987 and US$3.9 billion in 1988. However, after the deduction of multiple surcharges, taxes, royalties, contributions to special sctor funds and interest payments, YPF incurred losses (before depreciation) of US$601 million in 1987 and US$769 million in 1,988, as shown in the following table: - 43 - Table 8.12: FINANCES OF YPF US$ millons 1987 19m Gross Income 6,669 6,see Lees Operating Expenses -2.906 -3.248 Operating Incom 2,768 8,332 Less: Royalties -277 -259 Fuel Tax -1,706 -2,525 Hydro Development Tax -176 -168 Dir ct Tax -208 -205 Interest Expense -998 -944 Total Royalties, Taxes and Interest -8,854 -4,191 Income before Depreciation -681 -769 Depreciation -1,126 -1,076 Not Incoe/ (Lose) -1,727 -1,845 3.51 YPP's external debt, which before Government support amounted to US$5.4 billion and US$4.9 billion as of end-1987 and end-1988, respectively, deserves special mention. In the past, ex-refinery prices were fixed at levels well below production costs and below prices paid for petroleum products on the international markets. This forced YPF to incur external debt to finance its investments and cover its losses after deducting non-operating costs. At the same time consumer prices were fixed at amounts much higher than the aggregate of the ex-refinery price plus the taxes assigned to the Fuel Fund and Energy Fund. The resulting excess revenues flowed to the Treasury from whence a portion returned to YPF as Government support for YPF's debt service. 3.52 GdE had operating income of US$357 million in 1987 and US$255 million in 1988. Taxes in both these years were minor, since GdE is exempt from provincial income tax until 1989, from Federal income tax until 1992, and from capital income tax until 1990. However, GdE had high interest payments in both 1987 and 1988, which reduced its income to US$167 million and US$43 million for 1987 and 1988, respectively; depreciation then turned this income into losses as shown in the following table: - 44 - Table 8.18: FDUW4ES OFC E US, millon. 1987 1988 Gros Incos 1,687 1,165 Low.: Operating Expense -78U -916 Operating Incoe 8$57 266 Loe: Sales Tax N/A -18 Other Taxes -17 -23 Interest -178 -176 -190 -212 Income before Dpreciation 167 48 Depreciation or Reserve for SeIt-Insurance -200 -252 Net Income/(Loss) -88 -209 3.53 Modest income before depreciation in both 1987 and 1988 was possible only because GdE received 852 of its gas from YPF at a transfer price of only US$0.6/MCF. For the 152 of total sales received from Bolivia, GdE must pay USS2.461MCF, and the Government no longer compensates GdE for the price differential on imported gas. 3.54 Although not reflected in GdE's financial reports, its gas tariff includes a VAT, National Tax, Provincial Tax, Municipal Tax, and Social Security Retirement Tax, which adds US$1.03/MCF more to the average rate of US$1.971MCF that a typical industrial customer paid in 1988. Negative ImDact on Finances of State Power Companies 3.55 The Federal power companies (SEGBA, AyE, and Hidronor) had an aggregate operating income of US$320 million and US$625 million, respectively, for the years 1987 and 1988. After payment of Income Tax, Sales Tax, Royalties, contribution to the Electricity Fund, and interest expense, the power companies incurred losses before depreciation of US$671 million in 1987 and US$423 million in 1988, as shown belows - 45 - Table 8.14: FINANCES OF NATIONAL POWER COMPANIES US$ mllions 1987 1989 Gross Income 1,897 1,595 Los: Operating Coot -1.077 -971 Operating InCo 820 625 Loes: Income Tax Provinces -78 -91 Income Tax Federal -a -76 Sales Tax -172 -201 Electricity Fund -115 -185 Royalties -20 -8 Intereet Expone. -292 -270 Totel Non-Operating Expense -748 -791 Incom before Depreciation -428 -106 Depreciation -249 -267 Net Incoms/(Lose) -671 -428 3.56 Electricity tariffs that average between US$0.05-0.06 per kWh are not sufficient to cover both operating and non-operating costs. R. SUMMARY OF DISINCENTIVES AND ECONOMIC DISTORTIONS CAUSED BY THE SYSTEM OF PRICING AND TAXATION EXISTING AS OF JUNE 1989 3.57 The variations in real prices and in effective excise taxes bear no relationship to variations in international prices of crude o^l and oil products. This has created misleading signals for both consumers and producers and has led to many economic distortions and disincentives. The result is foregone benefits, lost profits, and unrealized economic growth. Some of the major economic distortions and disincentives ares (a) Low wellhead prices and high royalty payments (until September 1989), which have created disincentives to explore for and develop additional natural gas, and a waste of natural gas by producers through flaring and other losses. (b) Low crude oil prices and high royalty payments have been a disincentive to exploration and development of small oil fields or optimally to develop marginal oil fields. (c) Retail pricing policy for gasoline and gasoil has led to a distorted demand pattern of reduced gasolin- usage and increased gasoil consumption. This also has led to large investments in - 46 - refinery conversion facilities to supply the distorted demond pattern, as well as a gasoline surplus that cannot be exported due to logistical problems, and a quality of domestic gasoline below international standards. (d) Refining tax and pricing policies, which have discouraged import or export of crude oil and export of products, have also discouraged the use of excess refining capacity and not allowed optimal use through crude mix and product blending in existing refinery capacity. (e) The structure of ex-refinery prices for diesel and fuel oil creates considerable distortions. In particular, diesel's low ex- refinery price (among other reasons) has caused private refineries to stop producing diesel, so that production of this derivative has become the exclusive responsibility of YPP. Also, diesel and fuel oil prices are fixed at the refining plant, while other products are fixed at supply plants. Therefore, the diesel price, including VAT and the domestic freight often has been higher than the price of gas oil, thus stimulating the uneconomical use of gas oil instead of less expensive diesel by the electric sector. (f) Subsidized prices of diesel and fuel oil for electric companies (50? of the official price) have led toi (i) discrimination against the use of coal by such sector companies; (ii) discouragement of the accumulation of fuel oil inventories by such compani's; and (iii) a minor production of fuel oil at certain times of 'he year, thus causing YPF to resort to imports which are subsidized _t those times. (g) Large subsidies to private sector entities through sales of feedstock (LPG, gas, gas liquids, certain oil products) at low prices below economic value lead to uneconomic utilization patterns. (h) Implicit subsidies are given to final consumers of some products primarily domestic users of gas and electricity which are borne in turn by industrial users creating a vicious circle of production disincentives at times of low economic activity, while there are implicit subsidies for domestic gas and electricity final consumers there are high prices charged to final consumers of other petroleum products. This causes distortions in demand patterns that result from final fuel price differentials deviating from economic price differentials. Mi) A complex system of numerous taxes at many stages of the production process distorts costs and creates disincentives, which could be easily converted to a simpler system of a single end-user tax on commercial prices, complemented by an improved corporate income tax. (j) A complex, inflexible system of earmarked funds consists largely of transfers from the hydrocarbon sector to destinations in the power sector, roads sector, the pension :sunds, the provinces or general Government revenues. While this system facilitates the - 47 _ transfer of funds between companies vhich would be very difficult to accomplish by other means in Argentina. The system should be changed to allow allocation of funds to priority investments, and should be flexible enough to adapt to changing investment requirements. (k) Provincial taxes on many products (primarily gas and electricity) and large regional disparities in setting (mainly) electricity, prices have caused complex distortions and subsidies, and are the source of related financial problems for producers and consumers. I. MEASURES TAKEN AND PROPOSED CHANGES FROM JULY TO DECEMBER 1989 TO REFORM THE SYSTEM OF SUBSIDIES, ROYALTIES AND TAXATION 3.58 The New Legal Framework Recently two important laws were approved, which will be the basic legal instruments to propel the structural reforms at the level of the public sector. These laws are: The Administrative Emergency Law and the Economic Emergency Law. The reform of the taxation system, which will be implemented through a new law, whose draft has already been sent to the Congress, constitutes the third essential element. The main aspects of the two already approved laws, in relation h the energy sector (as stated by the Secretariat of Energy), are the lowing: 1) Declaration of a state of emergency for all public services, for the execution of contracts, and in relation with the economic-financial situation of the public enterprises. 2) Authorization given to the National Executive Power for the intervention of the various public enterprises and other organizations, and with the faculty to reorganize provisionally these entities and change their legal structure. 3) Establishment of an emergency system for handling all contracts and obligaticns of the State, its enterprises and institutions. 4) Cancellation of all subsidies and subsidy payments, which may affect the economic-financial situation of the state enterprises, and the obligation to submit to Congress any of these measures, if they need to be maintained, in which case they should be carefully explained and must be included in the National Budget. 5) The procedures for privatization should be made very easy to apply and the systems for awarding public works concessions and for the participation of private capital in public services should be enlarged. - 48 - 6) The Na:ional Executive Power (ad referendum from Congress) should be empowered to approve the annulment of all legislation which establishes privileges or which wvil make difficult the implementation of deregulation or demonopolization of public services. 7) Establish proErams for allowing participation in the ownership of state enterprises by their employees, users of their services and/or suppliers. 8) Modification of the Compre and Contrato Argentino Laws. 9) Linkage of reference prices to calculate petroleum and natural gas royalties to international prices using a basket of crude oils (up to 80? of the international price for petroleum and up to 702 for natural gas at its caloric equivalent) and establishment of an option for their payment in hydrocarbons of free disposition. 10) Establishment of a Federal Electric Energy Enterprise, which will include the existing enterprises known as Agua y Energia, Hidronor, and the electricity generation of other national entities. 11) Planned establishment of a National Fuels Enterprise, which will include the existing enterprises known as YPF, GdE and YCF (planned for early 1990). 12) Establishment of concessions, asssociations and/or service contracts in those exploration and exploitation areas presently under YPF, and the establishment of mixed societies for those areas under secondary recovery. 13) Provide priority to the cooperative sector for the eventual transfer of distribution concesfions for electric energy services, presently supplied by SEGBA and AYEE, as well as those for natural gas, presently supplied by Gas del Estado (likewise, and eventually, these services could be transferred to Provincial or Municipal entities), through adequate contracts for the ownership and operation of the distribution networks. 14) Declaration that existing mixed petrochemical and coal- chemical enterprises are also subject to privatization. 3.59 Principal measures implemented and to be developed from July 1989 to December 1989 With the objectives increasing efficiency, restoring economic and financial health to public enterprises and reducing subsidies. From July to December 1989, various actions have been implemented to try to reach these objectives. The most important (as stated by the Secretariat of Energy) ares - 49 - 1) Tariff readjustment aimed at insuring in a first stage, the coverage of operational costs of the public enterprises. The tariff increases in real terms, between July and August of 1989 were of 279Z in the case of the electrical tariffs for AyEE, of 256Z for SEGBA, and of 279Z for RIDRONOR. As for the hydrocarbon enterprises, the prices and tariffs were increased in real terms by 242Z for YPF, by 2381 for Gas del Estado, and by 2822 for YCF. In all cases, the recovery of tariffs and prices in real terms implied increases in nominal terms that were near or above 11002 on the average, for the period indicated above. 2) Interruption for 180 days of all subsidies channeled through the public enterprises and other state enterprises. The Ministry of Public Work and Services and the Secretary of Energy will review and revise the subsidies and special tariffs applicable to AyEE, HIDRONOR and SEGBA, for the supply of electricity and water for irrigation, with the purpose of establishing in each case whether it is still necessary to award the exception or to eliminate them. Simmilarly, they will proceed in the hydrocarbons subsector. 3) It has been established that the final sales prices of hydrocarbons cannot be less than the retention prices determined for all petroleum products of national origin. 4) It is the intention of the National Executive Power to put a limit as to the National Treasury contributions towards providing subsidies or direct cash to the public enterprises as of the end of October of 1989. 5) A unique fund will be set up transitorily to be administered by the Ministry of Public Works and Services, utilizing the remaining funds specifically assigned for this purpose (50? for 180 day, and 20Z until Dec. 31, 1990). These measures aimed at providing flexibility in the administration of the resources during the emergency period, will not interfere in the development of projects under construction for the expansion of -he electric system. 6) Establishment of a special system of credit and debt compensation between entities within the public sector, as of June 30, 1989, including those entities of Prov!ncial and Municipal character. 7) Cessation of all appointments and hiring, whenever these actions imply increases in personnel costs, enlargement of the facilities granted for the relocation of personnel belonging to the various enterprises and entities, and revision of the employment systems with the purpose of correcting those factors that may attempt against the objectives for increasing efficiency and productivity. - 50 - 8) Preparation of an agreement to establish jurisdictional reorganization of the electrical subsector, which will be signed between the National Government and the Provincial authorities. 9) Preparation of proposal aimed at guaranting payment for the supply of public electrical services, within the framework of the various measures already approved and which redefine the financial relationship between the Federal Government and the provincial entities. 3.60 Changes Proposed to the Taxation Systom in the Hydrocarbons Subsector Recently, the procedure to calculate the payment of petroleum royalties to the Provinces has been modifiedt and the rate of the processing tax on crude oils refined locally has also been changed. The National Congress in December 1989 discussed a new taxation system law, which will be aimed at simplifying the taxation system. The main modifications on the tax system, applicable to the hydrocarbon subsector, may be summarized as followes i) Royalties As per Law No. 23696, the basis for calculating the payment of royalties to the Provinces has been changed, and instead of using as a reference the prices fixed by the S.E., now the reference will be the international price of a barrel of crude oil and on this price, the percentage to be applied will be only 122. The producing Provinces will be allowed to opt to receive payment in kind consisting of crude oil of free disposition, which they may market internationally, or within the country, if they choose to do so (Annex 5.9 describes the new royalty system in detail). ii) Tax on Crude Oil Processing This tax has a final destination, which means that the funds obtained go to a specific Fund. As per the Decree No. 105589, the tax rate has been lowered from 102 to only 0.22, and when temporary imports are required they are exonerated from this payment. iii) Taxes to Final Users and Value Added Tax T"e proposal for reforming the taxation system, which has been presented to the National Congress, would include the following aspects concerning the hydrocarbons subsectors - The Law No. 17557 and its modifications has been eliminated - 51 - - .Th payment of IVA has been made obligatory for all fuels at a rate of 13Z. [ - Slight modifications on taxation of internal consumption of liquid fuels has been proposed. The basis for calculating this consumption tax would be the sales price less the value added tax or IVA. Finally, it is important to indicate, that by an administrative resolution, YPF had been exonerated from paying income tax since 1979, but this anomalous situation will come to an end if the new law of tax reform is approved. - 52 - CHAPTER IV ENERGY PRICING AND TAXATION SYSTEM REFORM 4.1 Chapter III described the present system of energy pricing and taxation and its detrimental economic and financial consequences. This chapter provides recommendations for reform of the pricing and taxation system. Initially, recommendations are given for simplifying and impreving the energy tax system, while at the same time preserving investment funds (energy and roads) and improving producer and consumer price incentives. This is followed by a discussion of ways to reform pricing of crude oil and crude oil products, natural gas, and electricity, with emphasis on the complex and highly distorted natural gas pricing system. The benefits of a new system of pricing and taxation are described along with the fiscal benefits of these changes. A. SUMMARY OF TAX RECOMMENDATIONS 4.2 An improvement in energy taxation could be accomplished through measures that simplify the tax system, consolidate multiple taxes into a single uniformly applied ad valorem tax, and move toward greater reliance on direct income taxes of the petroleum and natural gas companies. The following reforms are recommended: (a) Implement proposal that VAT should apply to all petroleum products, natural gas and electricity. YPF, GdE, and the power companies should then be able to deduct all VAT paid on inputs. (b) All other consumption taxes and surcharges (plus the crude tax and the "national" tax on natural gas) should be substituted by a single ad valorem energy tax applied to petroleum products, H natural natural gas, and electricity. There should be a rebate for the ad valorem tax paid on fuels and power consumed by the power companies themselves (otherwise there would be double taxation). (ii A basic rate could be 15Z for an ad valorem energy tax. This would replace all existing energy and electricity funds and any specific earmarking. The proceeds of which would be distributed in a manner to temporarily fund ongoing high priority investments, such as Yacyreta, in order to finish these works. Once these works are finished the earmarking of funds for energy projects would cease. (ii) An additional "road users charge" at a rate of about 35Z of the commercial price should be applied to gasoline and gasoil, earmarked for a single "Road Fund." This would replace present specific earmarking for national and provincial roads. - 53 - (iii) Total rates for gasolines, gasoil, and diesel used in transport would have to be higher if the intent is to maintain actual levels of gross revenues from indirect taxes on fuels. A new tax rate structure on transport fuels could be (as percent of commercial price) as follows: Extra gasoline2 179Z Regular gasoline: 141% Gasoil, Diesel for transport: 110X The Treasury (after deducting the 152 earmarked for the single Energy Fund and the 352 earmarked for the single Road Fund) would then get a 1292 tax on extra-gasoline, 912 on regular gasoline and 60Z on gasoil and diesel for transport. Total rates on transport fuels could eventually be lower, given that collections would increase substantially as a consequence of the proposed energy price changes, from the proposed elimination of subsidies, the proposed income taxes (on YPF, GdE and private oil producers), and possible improved tax collection and tax reform in non-energy areas. (c) The VAT and the ad valorem energy tax should be applied to a 'commercial price,' determined according to the following price policy recommendations: 'i) Petroleum Productss The refinery price should be equal to the FOB international price, i.e., the previous month's average, plus distribution and marketing margins. (ii) Natural gas: The price should be approximately 902 of equivalent fuel oil price for industrial and power users, as stated in the decree 1212 of November 1989, plus differential distribution costs for residential-commercial users, including adjustments for any geographical or seasonal differentials. (iii) Electricity: The tariff should be set at least at the long- run marginal cost (LRHC). The final consumer price, including the ad valorem tax (but excluding VAT) should be at a level to cover financial needs of the entire power sector. (d) If the need arises, consideration should be given to ar. additional excise tax on residential natural gas consumption above a monthly minimum, so the total price equals that of kerosene. In the short run, however, this would imply a large increase in the price of natural gas for medium and large residential consumers. Such a tax could be phased in more slowly, and final consumer prices of natural gas and electricity should be coordinated so as not to cause an uneconomic shift toward increased electricity use away from natural gas. - 54 - (e) YPF, GdE, and private petroleum and natural gas producers and distributors ehould be subject to the normal corporate income tax (as proposed in the tax reform law) plus possibly an income surcharge tax (or a windfall profits tax). Proceeds of these taxes might be placed in an Investment Stabilization Fund and assigned to Government, YPF, GdE, or other public agencies for investment purposes. The Fund could accumulate financial resources in periods of "high' international prices and be used in times of "low" prices. In this way, total public investment financed out of oil surpluses would be made more stable than if all of it were spent immediately, and contribute to sound macroeconomic management and increasing investment. (f) As of September 1989 royalties are to be determined on the basis of a basket of international crude prices adjusted by transport cost to the wellhead. This basis for determining the royalty should be maintained. (g) The recommended changes on indirect tax structure, rates, and earmarking defined above could and should proceed as soon as possible along with the establishment of income taxes for YPF, GdE, and private producers. The suggested windfall profits tax and the Investment Stabilization Fund need to be carefully designed before implementation. B. REFORM OF CRUDE OIL AND PETROLEUM PRODUCTS PRICING 4.3 Prices of crude oil and petroleum products should reflect the opportunity cost of oil and refined petroleum products as automatically as possible. Therefore, both the ex-refinery prices of petroleum products and crude oil should be linked explicitly to their export FOB prices. In this way, the appropriate economic signals would be sent to producers and refiners. In addition, this would prevent price adjustments from favoring various special interest groups or specific enterprises. Also, the administrative determination of prices would lose most of its "signal" strength to adjust other prices within the economy, and thus would reinforce anti-inflationary policy goals. 4.4 Since severe distortions have beea caused by royalty payments based on higher than market crtde prices, and by the tax on refined crude, it is very fortunate that law 23696 has allowed royalties to be paid on the basis of crude oil opportunity cost and that the tax on refined crude has been reduced to 0.2Z. However, excise taxes should be further simplified and paid on the basis of ex-refinery prices. Preferential lower prices to the electric sector have been reduced, but those to the petrochemicals should be eliminated. In this way, present stimuli to an inefficient use of refining capacity and to mixing of refined products would be eliminated. YPF's finances would better reflect the economic and administrative efficiency of its operations, and the complex cross-transfer system with the Government would be enormously simplified. 4.5 The price paid to crude oil producers should be determined at ports before export or domestic consumption centers. Prices at supply plants should iniclude ex-refinery prices plus transportation and handling - 55 - costs. For the latter price, excise taxes should be applied to determine the consumer price. International parity prices for crude and its products should be used as the basis for all prices. The Government should proceed as soon as possible with the hydrocarbon price deregulation described in decree 1212. Crude Oil and Refined Products Pricing Principles (a) Flexibility within the petroleum law for royalty rates between 5 and 122 should be used to enable continued production of marginal fields. (b) Wellhead prices for crude oil sales between crude owner and refiner should be set at the FOB or refinery gate price. (c) Fixed refinery and marketing margins should be deregulated, since crude oil and refined product prices will vary with free competitive market conditions. 8d) If crude oil production is in excess of internal requirements or excess refining capacity exists to refine crude oil for the export market, unrestricted export of crude oil and petroleum products should be allowed with export duties or excise taxes waived on imports and exports. Also, there should be no restrictions on importing crude oil and oil products. (e) The tax on locally refined crude oil, which has been reduced from 0I to 0.22, should be eliminated completely. (f) The Government should proceed with oil price deregulatiou described in decree 1212. Until deregulation is implemented, prices for crude and products should be linked to international parity prices (FOB prices for crude oil and ex-refinery prices). Thereafter, there could be a transition to freely negotiated prices between producers and refiners with prices ranging between minimum FOB and maximum CIF prices. Suggestions for such a deregulated system appear in Annex 4.0. C. REFORM OF NATURAL GAS PRICING SYSTEM 4.6 The objective of the natural natural gas pricing system should be to allow the market to determine prices for each consuming sector at a level that would ensure optimum resource allocation while assuring that the entity assuming the greatest risk receives the greatest return on its investment. Based on preliminary analyses carried out as part of the energy sector study, the cost of producing natural gas and delivering it to the consumer is--and will continue to be--less than the cost of the fuels it would replace. The difference between the economic cost of supplying the natural gas to the consumer and the cost of the substituted fuels is - 56 - the economic rent, which can be divided between the producer, the transporter, the consumer, and the Government. In Argentina, as in most countries, natural gas exploration and production is the higher risk activity, while transportation and marketing carries a much lower risk. Producers should seek a rate of return on their equity investment equivalent to the return they might receive for other investments of equal risk. There are no firm guidelines for setting the appropriate return on equity (ROE); it will vary, depending on the investment opportunities. But for a fairly high-risk investmert such as natural gas exploration and development, a 25 to 30Z ROE after taxes may be reasonable. 4.7 All energy prices are set by the Government except the retail price of LPG. The existing system of controlled transfer prices and retail prices has shifted a large share of the economic rent away from higher-risk production operations to the Government and the consumer. Price controls should be minimized to permit the market to allocate resources to their highest value use and to encourage private sector participation in resource development. Obviously, a total decontrol of all transfer and retail prices would not be feasible for public utilities supplying natural natural gas through distribution networks. Transportation and distribution tariffs must be regulated to assure that this component of the tariff will recover the actual operating cost, investment recovery and a reasonable return on investment. A decontrol of retail prices alone would not be feasible, since there would be no way to assure that the economic rent would flow to the higher-risk production activities. 4.8 Given the need to stimulate natural gas development and the desire to encourage private sector investment, the Government should undertake a phased program to implement decontrol of wellhead and transfer prices with regulation of downstream margins for transportation and marketing. This method is used by many industrialized countries. The retail price in each market sector would approach the price of the substituted fuel, but the distributor would retain only the portion covering all costs, including a fair return on invested capital. This would assure that t.- larger portion of the economic rent would flow upstream to the high-risk production operations. Under such a decontrolled system as occurs in industrial countries, in times of natural gas shortage retail prices would approach the pri:e of substitute petroleum fuels; in times of natural gas surplus, retail ;rices would decline somewhat along with producer prices, assuming competition between various natural gas producers. Such a system should provide the right economic signals to producers and consumers alike as well as maximize government revenues through appropriate taxation. 4.9 While the ultimate objective is a decontrolled system, there are a number of reasens why this approach cannot be implemented immediately. First, present controlled prices for natural gas producers, natural gas consumers, and competing petroleum products are below international levels. Second, the institutional structure to regulate the natural gas transporter (GdE) as a public utility does not currently exist. Third, the institutional arrangements for encouraging competition among suppliers is not in place. 4.10 It is recommended that a controlled transition to a new pricing system be implemented. During this transition period a new system of controlled prices would be put in place while needed studies and - 57 - institutional arrangements are completed. This new system by itself would significantly improve incentives for producers and consumers, would increase Government revenues, and eventually allow a relatively easy transition to a decontrolled system (described above). 4.11 All retail energy prices would have to be brought in line with international energy price levels. This could be done by: (i) gradually increasing the controlled price to international levels: (ii) eliminating arbitrary transfer prices for natural natural gas and natural natural gas liquids; (iii) establishing a system for regulating downstream natural gas operations as public utilities; and (iv) ultimately eliminating retail price controls except the margin for delivering natural gas from the wellhead to the consumer. The tax regime will have to be modified to assure that all types of energy that compete with natural natural gas are subject to the same unified energy tax (on an energy equivalent basis) as natural gas. The Government also could capture a larger share of the economic rent from the producer in the form of income tax, windfall profits tax, or dividends in the case of Government-owned companies. 4.12 The basis for pricing during the transition to deregulation should be to set the retail price of natural gas in industrial and power markets at or near the price of fuel oil--the next best substitute and the marginal fuel displaced by incremental natural gas production. Decree 1212 is a very positive step forward as it states that once hydrocarbon prices are deregulated, natural gas prices to industry and power should be set at 90Z of fuel oil with producers receiving; prices based on net-back rates. In some sectors, where several fuels ire consumed, the free market retail price should probably be near the retail price of the lowest cost fuel available to that class of consumers. The price in the residential and commercial sectors should be set to cover the additional incremental transmission and distribution costs. plus an excise tax, if needed, to reach kerosene equivalent. 4.13 Implementing a controlled transition to a new natural gas pricing system would take place in six steps (described in detail in Annex 4.1): Step I - A4reements and commitments from all entities. Step II - Increase in prices for YPF and GdE to cover estimated current production costs. Step III- Studies and evaluations of GdE's and YPF's actual current and future costs. Step IV - Restructuring of the natural gas regulatory system. Step V - Alignment of the natural gas price with full alternative fuel value. Step VI - Final deregulation of prices. Implementation of a new natural gas pricing system requires institutional changes to achieve (i) increased competition among natural gas suppliers and natural gas transporters and (ii) cost-based tariffs for transmission and distribution, including adjustments for different income groups - 58 - (discussed in detail in Annexes 4.2 and 4.3). In this regard the proposed transition described in decree 1212 to allow for multiple suppliers of gas is a very positive step forward and should be implemented as soon as possible. Implementation of this new pricing system would allow producers to receive a higher price for natural gas and provide a strong incentive for natural gas exploration and production. The netback to producer from the new pricing structure should allow producers to receive US$1.00/MCF to US$1.69/MCF for natural gas. (See Annex 4.4.) D. ELECTRICITY PRICING 4.14 The appropriate basis for electricity pricing is to set prices at least equal to the long run marginal cost (LRMC) plus the energy ad valorem tax (152) and VAT (152). Detailed studies of LRMC are currently being undertaken with the Government (related to Bank Loan 7450-AR). Regional variations and wide variations in time should be eliminated. To meet income distribution objectives, lifeline rates for poor households should be established. The comparison of current electricity prices to estimated marginal cost shows that: (i) residential prices on average are very low compared to marginal cost (residential prices without taxes are only 502 to 6O0 of marginal cost without taxes); (ii) commercial prices are very high (over 1502 of marginal cost) and create a cross-subsidy with residential consumption (this cross subsidy is relatively small in revenue terms because commercial consumption is a small share, only 112, of total _.._tricity consumption); (iii) industrial rates without taxes on average are 13 to 24Z below economic cost with taxes. 4.15 In countries with a large share of hydropower in the electricity supply system, the financial cost of electricity is likely to be higher than the economic cost. This is because the repayment of loans on the hydropower project3 occurs much faster than the recovery of economic costs on such long term (20-30 year) projects. As described in the previous chapter, the financial cost--i.e. the price before tax needed to cover operating costs, debt service, a recovery and 12Z return on energy funds with a 12? return to equity contributions--is estimated to be US$80 mills/kWh (details in Annex 10.4) or about 152 higher than the weighted average marginal cost estimated at US$70 mills/kWh (Table 3.11). Therefore, one strong argument for a 152 ad valorem tax on electricity is to reflect this higher financial cost of electricity. Other reasons for applying the ad valorem tax to electricity are: (i) to prevent distortion of the relative price of fuels after tax; (ii) to shift part of the higher burden on hydrocarbons to power sector; and (iii) to provide a larger contribution to power sector investment. E. INTEGRATED PRICING AND TAXATION 4.16 The recommendations for simplifying and reforming energy taxation can be intigrated with the energy pricing at economic levels to show the adequacy of the current price/tax relationship. Table 4.1 compares commercial prices of energy fuels both with and without taxes to economic price levels with and without taxes for 1988 and 1989. As can be seen the very large nominal price increases in July 1989 brought many industrial prices back up near December 1988 level but reduced residential prices, - 59 - particularly for gas and electricity, substantially below December 1988 levels (in US$ terms). The last two columns show the ratio of actual comercial prices (fourth quarter 1988) and actual taxes to economic prices and proposed new tax rates. While there may be some uncertainties concerning prices and costs, the major observation is that all natural gas prices, especially for residential natural gas, are very low as tre electricity pri'es, especially residential electricity prices. Toble 4.1 AIpRIA OF L PRC,C3 TO iUC CrT. 1,0 AN l 108 pPIeRI AaC9a!0m eaTS (Incresae/Pcraae) to Coomrcial Commecial Price Coe.arcal Price Comearcial Price Comarcial Price OD froe Comercial Price Comercial Price EnmMie Economic */0 tate */taxes e /taxse /n.e taxes (0/tates) i"JEL Prices u/tfaxe Price I/ Price to Economic Price to Econgalc Price to Ecnml Price to Economic Price to Eacnmic Price _ w/~~~~*o taxs fo sbs||.1 Nip */t Nnn taes *ele taes , */o texa ZR2AM 1 tsx1_ Nnn taxal no -Regular 169 139 484 844 1.0.6 875.4 11 9 26 288 116 92 26 -_136 9 -Premi"m 178 144 8O 418 111.1 478.6 too 91 322 257 10t as 294 - o 14 Keote11 1U 28 12 163.8 218.7 96 76 140 76 107 sa 230 - 88 71 eolI 1ag 181 a2? 218 166.6 a79.8 94 78 194 127 er 87 12 li 76 Di_el 134 100 194 1N 1.9 220 79 89 1s 92 es 71 UiO 136 41 Fuel Oil -/ead"Wet/er 162 e1 114 18 109 141.3 149 78 108 144 e 112 13 24 -10 r s8ecto, 102 80 77 so 1N i 94 74 n 78 62 64 118 e1 as LG (Al4" I2/ 22 14.4 9.7 14.8 18.6 64 lo0 s7 77 82 130 29 e9 -Re.ide.tial/Ce.siaI 1.66 0.40 2.67 0.60 4.08 S/ .26 46 10 71 18 J4 12 130 a -.Iduetrial 1.W 1.82 2.84 2.79 276 4/ 8.61 67 6s 1o* 100 79 77 10O 27 29 .Peer 1.74 1.27 2.64 1.56 2.76 8.19 62 46 94 as 82 48 118 21 lo0 efining 1.8 2.40 2.78 3.61 as 66 e 180 S0 (Wo) 4e.aidenial 4.8 2.9 6.8 8.6 6.7 11.3 81 72 44 U 6 s IaNO 79 197 -Commarciai 10.6 16.6 6.t 6.84 UN 247 690 1*0 -a -Ladustaial 4.8 4.6 6.7 .0 8.6 7.28 76 82 11l 107 92 82 130 9 21 Avere of 10 Shior Utilities 4aelidtial 8.8 7.6 s.7 11.8 68 sr 67 0o so -Co_n bla 12.4 18.6 6.6 8.e4 182 26e 207 180 48 -Industrial 4.9 7.2 8.6 7.2 s 126 97 U10 8 1/ Econmic prIce W/o tomes based on intenational petrolem product price. In D_ceaer 1966 plus distribution coe. 21 Equal to 618,tan CIF bordor plus 6138/tan transport plus dist, note thbt If F border price for export mould he 164/ton. 8/ Nam. of economic pri,ce frm 64.06 whic *h 90W of fuel ol e uivalent (2.78) plus distribution financWal co (1.27). to kiro_ne quivalent (64.62 *inixA). 4/ Econmic price defined s 901o of fuel oil euivalent, 2.784.903.09 Excit_ag rates *er* 12.00 Augut 196M, 1.6 in Decber 1988. "DU; Commercial prices and taxe. for 19S e*r, prices In effect Daceber 1I6, from Table 8.2 and 8.8. Oats for 1989 price. acording to RAxolution of SE dated July 10. 16. prices in Offset fro July 10 to Dececber 1969. _ 61 - 4.17 However, price ratios in Table 4.1 are likely to be too high, and the increases needed to reach economic levels (including taxes) are even higher. There are two reasons for this: First, prices and costs were calculated during the second half of 1988 when the real exchange rate was overvalued by historical trends (December 1988 was 18? above the December 1987 level). This means that the price ratios (actual to economic) are somewhat higher than would be expected in periods with a lower real exchange rate. Using 18? as a rough indicator of the level of overvaluation, the price ratios for such as natural gas and petroleum products, whose values are tied to tradeable petroleum products, should be 18? lower. For electricity, prices would be lower (in dollars) by 18? but costs would be lower by the fraction of foreign costs in electricity production (foreign costs comprise about two-thirds of costs). The ratio of prices to costs for electricity would thus be between 10? to 18? too high. Second hyperinflation that has occurred to date in early 1989 reduced real prices. Real mid-1989 price levels were increased close to fourth quarter 1988 levels, but inflation surged to higher levels in 1989 and exchange rates increased and can be expected to change rapidly. A severe and long-term erosion from fourth quarter 1988 levels would have severe budgetary, financial, and economic consequences. While the level of energy prices changes frequently, the table does provide a useful guide as to what relative prices should be. Also, residential prices of natural gas and electricity should be raised simultaneously so as not to create large interfuel distortions. In any case, there will be large benefits- -economic, financial, and fiscal--to establishing a new pricing and taxation system as follows: (a) Prices tied to economic opportunity costs would give appropriate signals to producers, refiners, and users of energy products. Production, refining, and consumption decisions would then be based on prices that allow optimal and efficient use of resources and correctly signal profitable export opportunities and lead to profitable pro4uction decisions. (b) Uniform tax rates on non-transport fuels and electricity plus opportunity-cost commercial prices would give appropriate signals to promote efficient substitutions by industria:, commercial, and residential users. This is because the distortions in relative prices cha - to consumers would more closely reflect the relative ecc6 mic costs. (c) Abolition of subsidies for fuel consumption would provide incentives for higher efficiency and lead to appropriate tariff setting in the power sector. (d) The suggested trx rates and price policy for transport fuels would reduce the current incentive for uneconomic substitutions. (e) Monthly adjustment of producer prices would protect the financing of energy producing enterprises, while quarterly adjustments of user prices would avoid translating short-term exchange rate instability and obstacles to the effectiveness of stabilization efforts. - 62 - (f) The recent reduction in the tax on locally refined crude and the proposed price policies would remove the existing misguided incentives to *nderutilize refinery capacity. (g) The system of prices, taxes and transfers would be enormously simplified, thus avoiding the high costs induced by inefficient administration, inflexibility, and excessive uncertainties. (h) The simpler earmarking suggested would reduce the costs of present day inflexibilities, while at the same time guaranteeing a long- term minimum flow of available funds to finish high priority investment. (i) The suggested pricing policy implies the generation of significant profit in crude oil and natural gas production, stimulation of expLuration efforts, and reducing current needs for resource transfers and compensations from the national budget to YPF and GdE. (j) These profits could then be appropriated partially by the Treasury throigh income and possibly windfall profit taxes and dividends. (k) There would be significant variations in profits reflecting international oil price changes; however, it would be unwise to offset this instability by public expenditures financed out of oil and natural gas revenues. At the same time, when oil and natural gas reserves are depleted, other forms of productive wealth will need to be established. Both issues could be addressed by implementing the Investment Stabilization Fund. (1) The new system would increase the net fiscal revenue obtained from the energy sector. 4.18 The price increases in mid-1989, the Emergency Laws and deregulation decrees issued from July to December 1989 are a significant step in transition to a deregulated price system. During the transition period, and in view of exchange rate instability and high and variable inflation rates, energy prices for final users would need to be adjusted at least on a monthly based on previous averages of commercial prices and suggested tax rates (eventually quarterly adjustments might be appropriate if inflation rates are low and stable). F. FISCAL IMPACT OF THE NEW SYSTEM 4.19 A rough calculation of the impact of recommended changes in energy taxation, an increase in related prices, and a reduction in subsidies shows a substantial positive fiscal effect and additional revenue flowing to YPF and the Government for needed investments. 4.20 Subsidies to private sector entities and payments of excess royalties need to be permanently reduced. These subsidies total close to US$1 billion per year (see Chapter III). The recent charges on oil and gas royalty payments should help reduce about one-third to one fourth or the subsidies, a permanent elimination of Compre Argentino could reduce half of these subsidies. - 63 - 4.21 Approximate estimates of the impact of new tax rates (applied to unchanged before tax prices) show that a continuation of the same tax rates on natural gasoline, a higher tax rate on gas oil, and lower rates for other fuels (VAT plus 15 percent ad valorem) result in overall energy fuel tax revenues about US$123 million lower than etisting revenues. However, as shown in Table 4.2, this decline is more than offset by additional tax revenue earned when prices before tax are increased, assuming an increase in before tax prices of 21U for LPG, 52.25Z for natural gas, and 20Z for electricity (which approaches economic costs based on October 1988 prices and exchange rate). Private sector conoumers of fuels thus receive a lower tax rate on higher fuel prices. 4.22 The total net fiscal effect could be as high as US$1,650 million per year assuming the new tax rates and higher prices (as described in the previous paragraph), reduced subsidies to private sector and provinces of close to USS billion, an increase in tax revenue of US$411 million from income tax on YPF, which earns more revenue, and a corresponding reduction in the need of the Government to compensate state energy enterprises. These figures should be viewed as approximate to indicate the general magnitudes of potential savings. Of course other scenarios of price increases and subsidy reductions are possible, since the net fiscal benefit can be divided in various ways between increased YPF investment, increased investment elsewhere, and reduction of the fiscal deficit. - 64 - Table 4.2 A#"roximate Fiscal Effect of Recommendations on Taxation and on Pricing (1988 figures, in millions of US$) Proposed with increases in commercial prices 2/ 1.INDIRECT TAXES Estimated impact with changes in t&xation system (based on new rates applied to un- changed before tax prices) -123 II Additional indirect tax revenue with increases to before tax prices 2! +256 2/ Additional VAT not deducted -111 31 2.REDUCED COMPENSATIONS FROM GOVERNMENT (net effect of before tax price increases and reductions of subsidies) +1,217 3. APPROXIMATE INCREASE IN DIRECT TAXES (FROM INCREASED YPF INCOME) +411 NET FISCAL EFFECT +1,650 ,1 Tax rates are described in Chapter IV, Section A 2/ Commercial price increases of 21Z in LPG, 52.25Z for natural gas, 20S for electricity. 3/ VAT not deducted on present rates, but which would be deducted by state companies under the new system. CHAPTER V PETROLEUM AND GAS SUPPLY A. RESERVES AND PRODUCTION Reserves 5.1 The future supply of crude oil and natural gas in Argentina is dependent on the availability of the nation's producible hydrocarbon reserves. The principal obstacle to evaluating this availability, however, is that the criteria and definitions employed by Argentine authorities for reserve determinations are not comparable or compatible with those used by the international petroleum industry. During preparation of t.he Energy Plan for the period 1986-2000, the proved crude oil reserves used as of December 31, 1985, was 348 million CM, reported by YPF as officia.L crude oil reserves. In fact, the ictual proved crude oil reserves at that date were only about 260 million m3 (after appropriate adjustments), because YPF had included a significant volume of reserves classiflod under the unique concept termed 'conditional reserves'; the exploitation of such reserves would be conditional on overcoming those factors that were restricting actual development and production of those volumes, i.e. not recoverable under existing economic conditions. Since these "conditional reserves" volumes were not then and are not now identified in YPF's annual publication of official reserves, a general misunderstanding of the reslistic proved reserves situation resulted. In order to determine a realistic proved reserves base from which to project the future supply of crude oil and natural gas in Argentina, adjustments must be made to reported oficial reserves volumes in line with criteria and definitions generally a:cepted by the petroleum industry. 5.2 As a result of recent reassessments, proved crude oil reserves as of January 1, 1988 are now estimated to be only 224 million m3 (1.41 billion barrels) versus the VPF official estimate of 357 million m3 (2.2 billion barrels). At the current production rate of about 71,000 m3/day (447,000 bbls/day) needed to meet present consumption requirements, the proved reserve/production ratio for crudp oil is equal to eight years of supply. Thus, projected future demand for liquid hydrocarbons will be increasingly more difficult to supply from known sources. Similarly, realistic proved natural gas reserves as of January 1, 1988, were estimated to be only 554 billion m3 (19.6 trillion cu. ft.) versus the YPF official estimate of 693.4 billion m3 (24.4 trillion cu. ft.), which at the current production rate puts the proved reserve/production ratio for natural gas equal to about 20 years of supply. TherE has been some increase in official crude oil and natural gas reserves ss of 1/1/89, compared to 1/1/88 figures which were used in the preparation of this report. With a crude oil production volume of 25,539 MCM during 1988, and an increase in official proved crude oil reserves of 5,319 MCM as of 1/1/89 (as shown in Annex 1), the total volume of official proved crude oil reserves added during the year 1988 amounted to 30,858 MCM. Of this total volume added, 77Z resulted from review and studies of known reservoirs, 202 from development of known reservoirs, and 3Z (926 MCM) from exploration. - 66 - 5.3 With a natural gas production volume of 22,700 LMCM during 1988, and an increase in official proved natural gas reserves of 79,623 MMCM (shown in Annex 1), the total volume of official proved natural gas reserves added during the year 1988 amounted to 102,323 MMCM. All of this total volume added resulted from review and studies or further development of known reservoirs. Of the net official proved natural gas reserves increase of 79,623 MMCM as at 1/1189, 62X was from known fields in the Northwest basin, and 22L was from known fields in the Austral basin. The net increase in proved natural gas reserves in the Neuquen basin, where spare capacity in trunklines is available, amounted to only 52 of the total. Official probable natural gas reserves were reduced during 1988 by 36,046 MMCM; this volume was incorporated into the total net increase in official proved natural gas reserves. From the information available the net increase i. proved plus gas reserves was 43,577 MMCM. It is not possible make a specific evaluation of the results from exploration, but from all ineications, exploration contributed very little to the natural 3as reserves situation during 1988. Withcut detailed data for each field and the "condicionada" reserves, it is not possible to make adjustments for the official natural gas reserves in Annex 1 as of 1/1/89. Declining Oil Production 5.4 Argentina's energy resources are abundant and diverse, but the couentr still depends heavily on hydrocarbons (refined petrnleum products and natural gas) as its main source of energy, with over two-thirds of total energy demand being supplied by these sources. For this reason, the Government's primary objective in the hydrocarbons sector has been to reach self-sufficiency. In the earl) to mid-1970s, Argentina had to import significant v,.'umes of crude oil and products, but after the first oil price shock of 1973, which caused severe balance of payments problems, the Government decided in 1976 to increase the role of the private sector in crude oil and natural gas production. This change in policy, together with the discovery and development by YPF of two large natural gas and condensate fields in the late 1970s, brought increased oil and natural gas production and resulted in reducing imports to zero by 1983. However, production of crude oil fell 142 between 1981 and 1987. although this decline tr' nd was reversed in 1988. The decline in YPF's production was in response to the decision made by the Government to reduce investments to a minimum and only produce sufficient volumes to satisfy internal requirements. 5.5 In recent years, YPF has been forced to cut its planned investments because the Ministry of the Economy and the Secretary of the Treasury have not authorized the total expenditures programmed by YPF for new investments in exploration and production of crude oil. Government policies also restricted private sector exploration and production investments in YPF producing areas. Therefore, the public sector decline in investment for hydr^ arbon development has not been offset by private sector investment. These investment limitations have intensified in recent years because YPF had to devote a substantial portion of its available funds for the development of new natural gas reservoirs to provide for deliveries to the rapidly expanding natural gas pipeline systems built by Gas del Estado. - 67 - B. HISTORICAL PARTICIPATION OF THE PRIVATE SECTOR IN EXPLORATION AND PRODUCTION (1958 to mid-1989) 5.6 A mixture of legal opinion has existed in Argentina as to whether petroleum rights can be held directly by the private sector or only through contracts with YPF, in conformance with the Petroleum Law enacted in 1967. At present YPF is considered to be the holder of all petroleum rights in the country and thus has been the contracting entity with the private sector. However, the local private sector has always indicated they prefer to deal directly with the Government on petroleum matters. Exploration and Production by the Private Sector from 1958 to 19q5 5.7 Historically, exploration/production activities by international petroleum companies have been sporadic in Argentina. Although for a number of years international petroleum companies were not welcome, there was private sector activity in the country, conducted mostly by local private companies under various types of contracts with YPF, usually production services and secondary recovery agreements. The main feature of these service contracts is that the operators can deliver crude oil production to YPF at prices in certain cases greater than international prices, as well as deliver natural gas at prices better than those offered under the Houston Plan-type contracts. These, and other agreements between YPF and the private sector, were the result of modifications to the Petroleum Law approved in 1976. The structure of these service contracts should be revieewed to determine if the appropriate incentives are provided for optimum exploitation of both large and small fields. Houston Plan 5.8 Since 1985, significant efforts have been made by the Government to attract increased private sector participation in hydrocarbon exploration and production by both local and international petroleum companies. The first such effort was the Houston Plan, implemented in 1985, with direct participation of the Government and YPF. Under this plan, a total of 164 exploration areas--ranging in size from 10,000 km2 onshore to 150,000 km2 offshore, each with varying degrees of exploration risk assessment, and distributed through all the sedimentary basins of the country--were offered to the private sector under bid contracts with YPF. The first three rounds of offerings under this plan have resulted in the award of 35 contracts to various consortia comprised of local and international petroleum companies. Sixteen of the contracts had already been signed by mid-1988, and the corresponding geological and seismic work (which is allowed up to three years) had been initiated by mid-December 1988. Contracts on five other areas were sigued by the President of Argentina around that time, but Government approval for the remaining 15 contracts is still pending. The total investments required to carry out the work commitments amounts to about US$500 million. 5.9 The most significant aspects of the Houston Plan are: (i) linking the contractor's compensation for crude oil and natural gas produced to 802 and 14-282, respectively, of international crude oil prices; and (ii) the commitment made by YPF to pay an agreed percentage of the contractor's compensation (this percentage was part of the contractor's proposal at bidding) for crude oil produced (nothing was said about the compensation for natural gas) either in US dollars or in exportable volumes of crude oil if YPF was not able to pay the dollar amounts. - 68 - 5.10 The fourth round ef bidding under the Houston Plan called for bids covering a total of 63 arfas, which were opened on March 2, 1989; about 20 areas are expected to be ,Awarded. More than1 two-thirds of the blocks offered have not found takers due ira part to the lack of adequate basic technical data needed to generate enough interest by prospective private international oil companiet.. The current bidding conditions and ensuing model contract do not show substantial differences with respect to the previous bidding documents, elthough some clarifications have been introduced derived from the experience acquired in previous negotiation rounds. The provisions of Compre Argentino, and a growing number of new nuisance taxes (such as the recent attempt to require IVA payments on billings from the operator of each contract area to the joint venture participants in the contract), will necessarily significantly increase the cost of exploration of these areas. The contract terms for natural gas- -mainly those concerning prices (which are low) and payments to contractors (made only in australes)--will discourage both exploration and production of natural gas by contractors. Important modifications are still needed in the Houston Plan format, primarily to address these problems, but also to streamline the lengthy Government approval procedures. The requirement of including a domestic private company in each consortia that presents an offer is not considered to be of national interest because it only serves to increase the total cost. Olivos Plan 5.11 T e second approach taken by the GoveNrnent to increase private sector participation in the petroleum industry was the Olivos Plan, which was implemen*ed in 1987. This was a one-time effort designed to provide incentives for new investments aimed at achieving a short-term increase in crude oil production from the existing 22 exploitation contracts (mainly entered into with local private companies). Under these contracts, the negotiated prices for crude oil production prior to 1987, in general were much lower than international prices. To encourage new and necessary investments, the price for any incremental crude oil production to be obtained from these contract areas was set at 802 of the international price. In spite of this apparently att active incentive only two contracts had been renegotiated by December 1988. Petro Plan U 5.12 The third program which was proposed by the Alfonsin Government for increasing the participation of the private sector in the exploration and production of hydrocarbons was the so-called Petro Plan. This proposed program was based on offering marginal YPF producing areas for bids based on an initial cash bonus to be paid to YPF for the remaining petroleum reserves still existing in the reservoir, and for the use of all existing field equipment and producing facilities. In return YPF was to receive a monthly participation in production equivalent to 20 percent of the value of the crude oil extracted, from which it would satisfy the provincial royalty payments and retain any balance to pay for administration and overhead expenses. Although this program was designed to provide a true incentive for increasing production from the YrE marginai areas by direct private sector investments, and mainly through the participation of local private companies, the Petro Plan was never implemented. - 69 - C. PRODUCTION AND OPERATING COSTS OF YPF 5.13 Production operating costs of YPF comprise all direct exploration, drilling, and production expenses for ,.ersonnel, materials, and servicca, including administrative overhead expenses plus administrative investments apportioned to these upstream activities. A summary oi YPF's annual budgets for 1988 and 1989 is included as Annex 5.5, with all expenses and investments for each of these periods dist-ibuted into two categoriess (i) production operating costs and (ii) refining, transportation, and marketing costs. The costs shown in Annex 5.5 exclude all YPF payments for contractor's oil and gas production, taxes, royalties and interest, in order to determine direct YPF production operating costs. For the purpose of projecting future YPF production operating costs with varying levels of oil and gas production, and because of the excessive numbers of personnel employed relative to the actual operating requirements, the average personnel expenses of US$369.3 million per year were considered a fixed annual expense, i.e., no additional personnel would be required even for substantial future production increases. In a similar manner, the portion of administrative investments (computers. office equipment, etc.) pertaining to production operating costs amounting to an average of US$45.6 million per year was considered to be a fixed annual expense. Expenses for materials and services were considered to be variable depending on the volumes of crude oil and natural gas produced each year. Based on the substantial efforts of YPF to increase the production of natural gas at this time, it was assumed that about one-third cf the average total materials and services expense (US$492.7 million) would be for natural gas production; this amount of US$164.23 million for an average natural gas production of 22.807 billion m3 defined a variable natural gas operating cost of US$7.20 per thousand m3. In a similar manner, the remaining two- thirds of the average materials and services expense, US$328.47 million for an average crude oil production of 16.72 million m3, defined a variable crude oil operating cost of US$19.60 per m3. Investment Costs of YPF 5.14 YPF explores for and produces crude oil and natural gas from five general geographic areas--these are regionally classified as Northwest, Mendoza (Cuyana), Neuquen, Gulf of San Jorge, and Austral. The costs of drilling wells, both for exploration and development, and conducting seismic operations varies considerably in each area and between the five areas due to depths of wells, surface terrain conditions, subsurface conditions, etc. For the purpose of making projections of future YPF investments, detailed well cost data and seismic cost data were determined based on the 1988 and 1989 annual YPF budgets, together with other YPF estimates of the costs for future deeper wells or offshore wells for each of the five geographic areas. Based on the numbers and types of wells expected to be drilled in each area, the specific investments were defined. Subsequently, the five areas were combined into a total overall YPF annual investment projection distributed into exploration wells, development wells, and seismic data. - 70 - D. PROJECTIONS OF CRUDE Oil PRODUCTION S~.15 Two scenarios have been developed for estimating future crude oil productien in Argentina. The annual crude oil production projections have been estimated by starting from the revised proved crude oil reserves as of January 1, 1988, and using the actual crude oil production projections for YPF contractors and concessionaires. 5.16 The two cases developed under the sector study are as follows: (a) Minimum Supply Case (or pessimistic case) assumes that Argentina will not be in an economic position to support an exploration and develo?ment effort any greater than the current and historical effort conducted by YPF during the last seven years; and (b) Maximum Suppiy Case (optimistic) assumes that by 1990 Argentina could begin with an exploration and development effort substantially greater than before in line with the basic assumptions and technical parameters assumed in the Energy Plan and thus be able to increase crude oil production above the estimated future internal demand. 5.17 Under the Minimum Supply Case, the basic assumptions made were that, (i) future annual crude oil production rates would be limited to a maximum equivalent to eight years' supply based on rhe proved remaining crude oil reserves at the beginning of each year, including estimated new reserves generated from exploration during the prio year, and (ii) future investments and work programs by YPF and the private sector would be very similar to those conducted in the recent past, i.e., from 1981-88, resulting in similar annual new reserves additions. Therefore, although exploration activity will be conducted during the entire period, 1989 through 2000, the generation of nmw crude oil reserves less than the actual volumes of production during each annual period results in a projected constant decline in production from 1990 through 2000. From mid--1989 to mid-1990, crude oil production will experience a small increase resulting from new fields put into production by the consortium of Total-Bridas- Deminex in the offshore areas of the Austral Basin. Under the Maximum Supply Case, the basic assumptions made were that, (i) beginning in the fourth quarter of 1989, exploration and development investments (number of exploratory wells, seismic lines, development wells, etc.) would be in line with the technical parameters included in the Energy Plan 1986-2000; (ii) investment costs were based on actual 1988 and 1989 annual budgets of YPF: and (iii) future annual crude oil production rates would be limited to a maximum equivalent to eight years' supply based on he proved remaining crude oil reserves at the beginning of each year. Therefore, the large increases in investments, particularly for exploration activity, is projected to generate new crude oil reserves each year in excess of --tual produced volumes resulting in increasing crude oil production rates r^rom 1990 through 2000. The Energy Plan Proiections 5.18 Petroleum production projections, which were included in the Energy Plan for 1986-2000, were prepared by the Secretary of Energy in late 1985. The critical problem of crude oil reserve levels was recognized in - 71- the preparation of this Energy Plan. The basic assumptions and technical parameters used in preparing this Energy Plan can be summarized as follows: (i) the crude oil reserve base was that of December 31, 1985, i.e., 348 million m3, as reported officially by YPF; (ii) the basic objective of the Energy Plan was to achieve sufficient crude oil production to assure adequate supply of domestic liquid petroleum products; (iii) another objective was to allow an adequate substitution of natural gas for those petroleum products amenable to substitution, mainly fuel-oil; and (iv) the final objective was to attain a minimum ratio of proved crude oil reserves to production equivalent to 15 years of consumption by 1990 and thereafter at the projected required demand xate. 5.19 The hydrocarbon sector's obligations under this Energy Plan called for an aggressive level of exploration and development activities and corresponding investments each year from 1986 to 2000. By 1996, some 250 exploration wells would be drilled each year, with a total investment in exploration and development of about US$1,300 million per year, which by the year 2000 would have increased to over to US$1,500 million per year. 5.20 From the beginning, the Energy Plan suffered a series of setbacks and has lacked an adequate and realistic approach. For instance, the proved crude oil reserves at that time were only about 260 million m3 instead of the volume of 348 million m3 estimated by YPF in December 31, 1985. This was because YPF had included as official reserves a significant volume of 'conditional" crude oil reserves which could not be recovered under existing economic conditions. Similarly, the actual exploration and development work and investment programs carried out during 1986-88 have been drastically smaller than projected in the Energy Plan. 5.21 Therefore, based on the experience derived from the first four years of actual implementation of the Energy Plan--during which the number of exploration wells drilled was 414 less than programmed and total investments short by US$1,445 million--it is evident that the plan has not been implemented as programmed. This was mainly because of the financial limitations imposed by the Government on YPF's investments and because no arrangements were made for increasing private sector investment to offset the reduction in YPF investment. The best future alternative to solve this deficiency would be to foster significant participation by private international petroleum companies in both exploration and development activities. This should be done quickly 'f the production goals of the Energy Plan are to be realized. Minimum SuPPly Case 5.22 The minimum supply case shows an annual crude oil production of 25.691 million m3 by 1990, steadily declining over the remainder of the period, reaching 16.105 million m3 by the year 2000 (Annex 5.1). However natural gas production is projected to increase during the next four years from 26,174 billion m3 in 1989 .o 30.572 billion m3 in 1992, and remain constant thereafter (see Annex 5.7). This limitation on natural gas production is due to the limitation of proved natural gas reserves and deliverance in the Neuquen area, which is the only area with trunkline capacity available prior to 1995. As new natural gas reserves are discovered and developed in Neuquen this limitation will eventually be the capacity of natural gas trunklines. - 72 - 5.23 The basic assumptions and parameters used in the priparation of production estimates for the minimum supply case are based entirely on YPF's existing budget constraints for exploration and development activities and investments. Therefore, the exploration and development work program of YPF reflects historical and current work programs plus investments carried out by YPF contractors and concessionaires. It also includes a very limited amount of seismic surveys and exploration drilling to be performed by those private companies that have taken over areas under the Plan Houston. The administrative and operating costs used to develop the minimum supply case are based on the actual annual budgets prepared by YPF for the years 1988/1989, where all expenses and investments for exploration, drilling, and production operations plus the proportionate part of administrative overhead investments and expenditures are included. Payments for taxes, royalties and interests have been excluded. In the calculation of YPF production operating costs used to develop this minimum supply case, fixed operating costs for exploration, drilling, and production comprise all personnel costs for those activities and the proportionate part of administrative investments; these fixed operating costs are maintained constant on an annual basis for the period 1989-2000. The average variable operating costs per unit of production for materials and services were apportioned with two-thirds of the total materials and service costs to the actual crude oil production by YPF and with one-third of the total materials and services costs to the actual natural gas production (based on 1988 and 1989 budgets). Annual Investments for oil and gas exploration and production were estimated directly based on the projected level of these activities. The Maximum Supply Case 5.24 The scenario for the Maximum Supply Case (Annex 5.1) may appear only theoretical at best under present conditions; however, it was developed to demonstrate the production level that might be reached under expanded investment conditions and improved policies. The main assumptions and technical parameters used for the preparation of this case are similar to those of the Minimum Supply Case, and are identical to those used for the preparation of the Energy Plan alternative. The Maximum Supply Case assumes substantially increased levels of exploration and development activities, and the corresponding increased levels of investments from 1989 through the year 2000 (as in the Energy Plan), the purpose of which is to increase crude oil production above the requirement for meeting internal demand. To accomplish this objective, however, the restriction to maintain a 15-year reserves/production ratio (as assumed in the Energy Plan) has been eliminated, and instead, only an 8-year reserve/production ratio is assumed. 5.25 As is evident from the actual level of exploration and exploitation activities during the period 1986 through 1988, and considering the current critical economic condition of Argentina, a substantial increase in direct participation and investments by the private international petroleum sector will be necessary to attain this potential production level. This will require that the Government take the necess ry actions to establish favorable investment conditions and stable long-term development policies, with adequate guarantees to attract both local and international investors. - 73 - 5.26 The benefits of this Maximum Supply Case over the alternative case, ares (i) better use of available resources; (ii) additional production available for possible exports, thus generating an additional source of revenue '-at can be reinvested in exploration-production activities; (iii) by opening the possibility of exports, the participation or private international petroleum companies would be increased; (iv) availability of additional crude oil production would allow better use of installed refinery capacity; and (v) the exploration/production investment plan has a higher net present value, since oil would be found and produced earlier. Benefits of Expanded Production 5.27 To determine the benefits of expanded production, projections of crude oil production, natural gas production and corresponding costs for the Minimum and Maximum Supply cases, and simple net present values at an annual discount rate of 122 were used. The results indicate significant positive net benefits for all scenarios. The net benefits are naturally larger if oil prices are higher and costs of production can be reduced through a combination of efficiency improvements in YPF, higher efficiency of the private sector, or a reduction in Compre Argentino (which alone adds up to 402 to the cost). Table 5.1 summarizes the results for two oil price scenarios ($11/bbl and $161bbl) and two cost scenarios (full YPF cost and 602 of cost). As shown in Table 5.1, the net present value of the Minimum Supply Case is betweea $3.6 billion to $15 billion depending on costs and prices. This large benefit is to be expected since a large share of existing production has a marginial cost equal to operating cost, i.e. less than $51bbl. The Maximum Supply Case also has large net present values between $4.5 billion and $21.48 billion. The important test is whether the incremental production, i.e., the difference between the Maximum and Minimum Supply Cases, has a positive net present value. Under the most pessimistic assumptions of a constant real $11/bbl international price for oil (from now until the year 2014) and full cost of production, there is a net present value of $900 million at a 122 discount rate. All these scenarios also have one other "conservative assumption on costs, since local costs (that comprise a large share of total cost) are valued at the December 1988 exchange rate, which is about 182 overvalued compared to historical trends. The most important calculation in Table 5.1 is the large net present value of $6.084 billion for incremental production at a constant real $16.50/bbl oil price and costs at 602 of current YPF costs- -which is equivalent to $1.7 billion additional income in the next five years and $10.6 billion in the next ten years (see Annex 5.7 for details). Clearly, there are large benefits to be obtained from expanding exploration and production as soon as possible, and from implementing policies for reducing costs throught (i) improved YPF efficiency (e.g., drilling and production optimization, reducing drilling costs); (ii) arranging for the private sector (which has lower costs) to explore and produce more oil; (iil) reducing costs through partial or full reduction of Compre Argentino for oil equipment and drilling services. Without such an effort, the alternative becomes the Minimum Supply Scenario, which implies oil imports costing $500 million to $1,000 million by 199'193 and beyond. _ 74 - Table 5.1. NET PRESENT VALUE OF OIL AND GAS PRODUCTION FOR DIFFERENT OIL PRICE AND COST ASSUMPTIONS We. head price of crude oil $11.50 $16.50/bbl Equivalent International ($11.00/bbl) ($16.00/bbl) price for crude oil (valued at import replacement) A. Total Production - Minimum Supply Pull Cost $3,670 million $12,551 million 601 Cost $6,526 million $15,398 million B. Total Production - Haximum Supply Full Cost $4,570 million $16,292 million 602 Cost $9,760 million $21,482 million C. Incremental Production - Difference between Maximum Supply and Minimum Supply Full Cost $ 900 million $ 3,741 million 60n Cost $3,234 million $ 6,084 million Note: All NPV's calculated at 122. Sourcet Annexes 5.1 thru 5.7, Bank estimates. Incremental Production Costs 5.28 The Minimum Supply Case is predicated on continuation of the similar type and levels of crude oil and natural gas investments made during the period 1985-88. The Maximum Supply Case is based on investment levels corresponding to the numbers of exploration wells, development wells, and seismic lines as specified for each year and geograplhic area by the Energy Plan 1986-2000. Annex 5.6 shows the projection. of crude oil and natural gas production for each of these cases, together with the production costs for each case. Production costs include both Droduction operating costs plus investments. The differences between the maximum and minimum production and overall production costs defines the incremental production volumes and costs. These incremental production volumes and costs are also shown in Annex 5.6 discounted to a net present value of 12 percent per year. From Annex 7.1, the average incremental cost for exploration and production of natural gas is US$19.79 per MCM. This incremental cost multiplied by the discounted incremental natural gas (45,986 MHCM) yields US$910.1 million of the total discounted incremental production costs of US$5,637.0 million. The difference of US$4,726.9 million corresponds to the discounted incremental crude oil production of 70,819 MCM, resulting in an average incremental production cost for crude oil of US$66.75 per CM (US$10.61 per bbl). These production costs include the effect resulting from YPF's payments for crude oil and natural gas production by its production service contractors; however, no taxes, royalty payments or interest expense are included. - 75 - E. INCREASED PRIVATE SECTOR PARTICIPATION 3.29 The large investments required for discovering new hydrocarbon reserves, and the inherent risks associated with these exploration activities, have resulted in the Government taking decisions approving only minimum expenditures of public funds for hydrocarbon exploration by YPF in recent years. The consequence of these decisions has been that Argentina has seen its most essential eiiergy resources, i.e., proved crude oil and natural gas reserves, drastically reduced to F. critical level (the ratio of proved crude oil and natural gas reserves to production is now only eight years, and twenty years, respectively)--a situation from which it will be difficult and costly to recover, as shown in the discuision of the verious future supply options for crude oil and natural gas. 5.30 If the decline trend in proven crude oil and natural gas reserves is to be reversed, and the internal consumption of liquid fuels maintained using domestic hydrocarbon sources, then large investments in exploration and development should be made by both YPF and the private sector beginning immediately and continuing beyond the year 2000. 5.31 Tht only alternative open to Argentina at present is to encourage more private sector involvement in oil and gas exploration. The main reasons why further private sector participation is needed, include: (i) YPF cannot efficientl, operate all the producing fields under its direct operations and at the same time continue managing an aggressive exploration program for hydrocarbons, due to its lack of highly trained and motivated senior technical and managerial personnell (ii) severely restricted public sector resources will not allow increased allocation of funds for investment in exploration by YPF; and (iii) the private sector, primarily the international petroleum private sector, possess the capital, modern technology, and more efficient management capabilities, to enable it to obtain better and quicker resulto. Options for Private Sector Involvement 5.32 As of mid-1989 the principal options for fu-ther private sector participation in petroleum exploration and producing operations, were as follows: (i) increasing the prices to be paid at the wellhead for newly found crude oil and natural gas, and for any incremental production of these hydrocarbons; (ii) eliminating obstacles for more rapid approval of contracts for exploration ard production under the Houston Plan; (iii) making exploration operations for new areas much easier, by offering additional technical information, both of regional and aerial extent including data from airmag, satellites, and seismic surveys; (iv) allowing the private sector to operate many of YPF's marginal areas and allowing free disposition of crude and royalties based on market crude oil values; (v) moving towards closer private sector participation in YPF's producing operations, such as allowing the operation of certain main central areas of YPF through joint venture type contracts, or by more traditional service contracts. Increasing private sector participation in hydrocarbon exploration and production has potential major benefitss (i) to reduce public sector investments in risk-type operations, (ii) to provide improved efficiency based on more modern technology; and (iii) to provide more rapid results based on the combined effect of several enterprises acting independently, but simultaneously, each with their own ideas and access to proprietary technology, to achieve the same objectives. _ 76 - 5.33 The private sector should also undertake a larger role in the natural gas industry bys (i) increased participation in natural gas exploration and production; (ii) increased participation in transportation through trunk pipelines; and (iii) increased participation in distribution and marketing of natural gas to end users. 5.34 In addition, it will be importantt to furthe;- increase private sector participation iL .ownstream operations, where the main options include the followings {i) selling off specialty producing refineries and plants; (ii) disposal of the transport fleet; (iii) selling shares in the large YPF refineries and petrochemical plants; (lv) contracting out the drill4ng, well service, specialized industrial services, and workover services; and (v) privatizing the pipeline transportation system for both crude oil and products. iost of these downstream operations could be converted readily to mixed-capital companies by (i) making each operation a separate legal entity owned initially lOOZ by YPF, and (ii) subsequently selling a portion of each legal entity to domestic and/or foreign private interests. Objectives and Measures taken by the Government to Deregulate the Petroleum and Natural Gas Subsector (during July to December 1989) 5.35 In October and November 1989, two decrees (1055 and 1212) were issued to deregulate the oil and gas industry and increase private sector participation. According to the Secretariat of Energy, the new model, which is now proposed implies a qualitative change in the incentives to both the domestic and international capital. This implies that the Argentine petroleum industry must adapt to the new rules of the game prevailing in the international industry, which include the possibility of importing and/or exporting freely crude oil and petroleum products. 5.36 The objective of this policy to obtain a rapid expansion of the hydrocarbon reserves, an increase ir duction and possibly of the exports of hydrocarbons, both liquid and natu. _ gas. As a result, it should be possible to avoid the bottlenecks that might be produced in the near future, as a consequence of an insufficient level of new reserve discoveries and slow growth in the production of crude oil and natural gas. 5.37 To accomplish the new policies, it is necessary to increase the level of investments in both the exploration and exploitation of petroleum and natural gas, as well as in the treatment, transportation and distribution of natural gas. This expansion of the investment levels will be possible because of the new rules. Objectives of the new policies are: i) Alignment of crude oil, natural gas and refined petroleum products with international prices. ii) Deregulation of the various markets (at the levels of upstream operations for crude oil and natural gas production, and downstream operations for refining, distribution and export markets) and the elimination of subsidies. - 77 - (iii) Increase private sector participation in areas until now restricted to state enterprises. (iv) Application of a taxation system compatible with the open market operations of the petroleum industry and the increased deregulation of the hydrocarbons subsector. 5.38 The new policies are aimed at changing the monopolistic or oligopolistic structure of the hydrocarbon market by actions to free up supply. In this respect, the Executive Power has approved Decrees No. 1055/89 a.ad 1212/89, which together with those that have ratified and deepened the application of the Houston Plan, constitute the starting point of these new policies. The most important changes introduced by these two Decrees, as stated by the Secretariat of Energy (in points 1 through 12 below), are the following: 1) Establishment of timing and conditions for deregulation of the hydrocarbons subsector not later than January 1, 1991 (or sooner, if a volume of eight million cubic meters of free disposable crude oil is obtained), giving priority to market mechanisms for the determination of prices, volumes and margins in the various stages of the activity. 2) It establishes competition as the basic principle, under similar conditions, for the operations of public and private enterprises. Prices will be oriented towards the indifference of export prices, and crude oil quotas will be eliminated, and the export market will be opened. 3) t transitory system for the allocation of ctude oil to the refineries has been set up, which includes the administration of prices, taxes and the award of import permits for hydrocarbons, which will be in place until the new system which will liberalize prices and all activities within the sector becomes fully operational. 4) The price of natural gas will be fixed for industries (once the transitional period is over), based on 902 of the price of fuel-oil, and the price for residential customers will be determined on the basis of producer prices, plus treatment, transport and distribution costs. The price to the producer will be fixed on the basis of a 'net back" criteria, with the treatment and transport costs taken at their international referencial values. 5) A period of six months has been established for negotiations between YPF and the private contractors holding exploitation - 78 - contracts, or any other type of contracts, whereby YPP is obligated to receive or purchase the hydrocarbons produced (exception made of the Houston Plan contract) with the purpose of transforming all those contracts into concession type agreements at the private sector risk. 6) The legal basis and the timing have been established for the award under public international tendering of all areas of secondary interest presently operated by YPF. These areas will be awarded to the company (domestic or foreign), which in each case will offer the highest amount for the concept of exploitation rights. 7) The payment of the exploitation rights will be made in cash, and the produced hydrocarbons will be of a free disposable. The legal basis and timing have been established for YPF to call for bids under an international public bidding system, with the purpose of associating herself with private companiea, with the aim of jointly exploiting those areas where secondary recovery pro,ects can be developed. The association contracts will be finalized with the company that offers the highest amount for the concept of association rights. The payment of association rights will be made in cash. The contracts will be for 25 years, and the percentage of produced hydrocarbons belonging to the private partners will be freely disposable. 8) The free disposition of crude oil has been established for the hydrocarbons produced from those concessions under the legal framework of the Mining Code, for the hydrocarbons produced from those areas governed by the contacts established under the regulations of the Decrees 1055/89 and 1212/89, and those hydrocarbons produced under the framework of the contracts corresponding to the fifth call of the Houston Plan (but in this case only under condition of reducing the time share originally assigned for surveying and exploration). Likewise, the modifications to the Hydrocarbons Law introduced by the Economic Emergency Law allows the Provinces to freely market the petroleum received as payment for royalties. 9) The hydrocarbon producing Provinces can also participate, in association with private petroleum companies whether domestic or foreign, in all the bid calls for those areas located within the boundaries of their territorial jurisdiction. 10) The taxes of specific application on domestically refined crude oil have b-en substantially reduced for the crude oils domestically produced and assigned for internal consumption, and likewise these taxes are not applicable to imported crude oil used for processing in the country and their re-export. - 79 - 11) The installation of new refining capacity and new service stations will become free of any restriction. And likewise, once the transition period is over, the service stations may be owned freely by the operator. 12) YPF is guaranteed the necessary management autonomy to compete adequately with the private sector companies. Likewise, a Special Fund has been created within the Ministry of Public Works and Service, which will be replenished with the proceeds of the sale of the secondary recovery area and of the association rights, which will be used to finance the investment programs to be undertaken by YPF. 5.39 In addition to Decrees Nos. 1055 and 1212, a third follow-up Decree No. 1589 was issued on Dec. 27, 1989. This Decree was issued to clarify the uncertainties regarding the Houston Plan contractual agreement as per the application of the new regulations contained in Decrees 1055 and 1212. Decree No. 1589 allows Houston contractors to have the option to elect free disposability at the time of declaration of commerciality and provides details on preference of natural gas purchases, allows crude oil exports through permits up to one year (renewable), allows foreign exchange proceeds to be fully converted at the "real" rate of exchange and other related details. 5.40 For reference, the approximate English translations of the hydrocarbon deregulation Decrees 1055, 1212 and 1589 are provided in Annex 5.9. Issues, Questions and Clarifications Needed to Hydrocarbon Deregulation Decrees 5.41 The above described reforms are an important step in the proper direction to deregulate and improve efficiency in the hydrocarbon sector. However, certain clarifications to the decrees or changes are necessary if the deregulation is to be successful. 5.42 Potential Obstacles to Success in Implementation of Decrees.- The following potential obstacles to success in implementation of the three Decrees need to be taken into accounts (i) Too many investment opportunities may be offered at the same time. (ii) Local companies have limited financial resources and most international companies may be unwilling to commit significant up-front payments in Argentina. (iii) The free disposability regime is still quite imprecise (e.g. "freely marketed in local and foreign markets within the scope of legal regulations in force"). _ 80 - (iv) The crude oil cannot be freely exported because oft a) export permit requirement, b) lack of infrastructure that would permit commercially viable export of crude oil, c) local price guarantee under Decree 1589 that is too imprecise for oil, and iv) uncertainty about actual foreign exchange availability. (v) There are strong legal constraints on the private sector's being granted true concessionary rights and on actual ownership of petroleum reserves. The legal framework underlying the various decrees is imprecise and often ambiguous. (vi) Inadequate attention has been given to assessing the potential worth of the rights/assets being offered and alternate ways of achieving fair value. (vii) Decree 1212 offers the opportunity for joint ventures between YPF and a private contractor in YPP's currently producing areas. While this important step has the potential to significantly increase oil production from YPF fields, many questions remain (on the operatorship, areas offered, type of contract, minimum investment program, currency of payment association fee, etc.). While Government may view the sale of an interest in production from these fields as a potential major source of cash the association fees that can be reasonably anticipated at this time in Argentina may not reflect the real value of the rights being offered. For this reason, the following two alternatives are recommendeds Alternative 1: a sale only of rights to incremental production (which could have big upside potential), with YPF retaining a working interest in the incremental investment. (Companies might be convinced to 'carry' YPF during initial stages and other financing from a third party for a portion of YPF's share may help to mobilize investment), or; Alternative 2: offer the private sector partner the right to earn an interest ("farm-in") in the existing production as well as in the increaental production, by bearing 100O (or some higher share - e.g. 752 to earn a 502 participation) of future costs up to a certain threshold. The association fee, in such case, would be more of a signature bonus (which should be payable in foreign exchange) and a large farm-in work commitment (or a specified percentage interest for each threshold of expenditure met), depending on the area. - 81 - Once the basic approach is resolved and the above listed questions answered, the package of required "model agreements* need to be outlined and drafted. (viii) The opening of marginal areas to bid is also a very positive step toward increasing production but questions stlll remain regarding access to accurate technical data and detailed bid criteria. (ix) The Decree provides for negotiations between YPF and a diverse group of production service contractors (about 28 different contracts), during the six month period ending May 7, 1990 to try to reach agreement on the conversion. The agreement shall be subject to approval of the Executive Branch (preceded by the opinion of the Energy Secretariat). A major problem in the conversions of these contracts is that companies may push for significantly better contract terms which might result in an eventual loss of revenue for the Government. Trying to avoid this situation, the Government could offer several clearly defined alternative options. In structuring alternatives, it is important to achieve free disposability of petroleum, while granting enough (but not too much) financial incentive for the contractor to keep investing. For those who take the right of free disposability, there should be an incentive to undertake the market and currency risks involved. Each contract should be dealt with separately. Some options which could be offered are: a) Association Contract - Each working interest owner has the right to take and dispose of its respective percentage share of production, and the obligation to bear and pay its own income taxes plus its respective share of investments and costs, including the royalty. This would mean that YPF would have to finance its share of costs. b) Sale of YPF's Rights under Contract - Rather than dealing only with the contractor, YPF could offer an international tender sale of its rights to purchase the petroleum under one or more contracts. c) Production Payment to Government or YPF - Another alternative would be for YPF or Government to receive in cash or in kind (at the recipient's option), a share of gross production. This approach differs from the production sharing scheme in that YPP would assume no obligation whatsoever and the contractor would bear directly all of the costs currently borne by YPF. In determining the percentage of the production payment, one should take into account the additional costs to be - 82 - borne by the contractor (royalty, transportation, storage, etc.) plus provide some fiscal incentive for the contractor to make new investments and to assume market and currency risks. d) Others- Such as possibly cash bonus or other option. 5.43 Summary of issues and Clarifications/Recomendations for Hydrocarbon Deregulation Decrees.- While the three deregulation hydrocarbon Decrees are a major step in the right direction for the deregulation of the sector, still there axe issues and clarifications that are necessary to be resolved, which as of end December 1989, are as follows: Rowmes Rec>eode Actions Clarif letlme needed U C~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 1. FE3 SPOSITMSI OF MMD OIL I A. Fr. dlopooltion In litemtd by export restrlctions resulting from: (1) Legal regulotlonu In place (1) Identify restrictions and .11.1 nate. (*x) Government approval reuired; (11) Elmimnote.any Govornm nt *xport approval. (111) 80t Export Tax (111) Continue phase out of export tax (pr e nt schedule Is reduction to 1OX by July, 1990) Complete phase out by third quarter 1990 (Iv) Failing ledliote action on (1) through (ii) set minimum Internal price at FOB export and assure appropriate minimum pay- ment In foreign exchange I S. While free dlspoeit1on to deferred there ic continued fixed *llocation of crude to refineries: - 83 - (I) Allocation* would continue until (1) Confirm preedence of 12/a1/90 or stop sooner, If 12/81/90 deadline over disposable production reaches any volume criteria 8 million m3/yr; but the (except It free possibility exits that crude disposable production allocation could continue rache 8 million w3/yr beyond 12/81/90. untlI before) productlon raches 27 million ma/yr (11) Allocotion may continue beyond 12/81/90 If freo disposable production does not reach 8 million im/yr or total production does not roach 27 million m8/yr I C. Goal of tree disposition Implies the change following aspects In terms of contractual relationshipe (ether than Houston plan contracts) (1) A voriety of different contractual (I) Since background and circumstances which must be taken types of affected Into account, and; contracts vory significantly, the" should be handled on case by case heeis. (11) Desirability of achieving free (1i) Government should move dloposition, as soon as possibl-, cautiously, bearing in (because of atmosphere of mind the multiple step uncertaintly), but at the sam procedure In Decree timo the need to make sure that 1212/69, and should the new contractual relatlon- carefully aoose the ahipo will fairly value the potential value of YPF o Governmnete rights. righte. Government should evaluate alternative ways of achieving tree dloposi- tion for thew areas; and economle Implications/ex- pectations of each. Alter- natives should Include: a) association contract, b) international tender of YPFs rights/obli- gations, c) production payment - 84 - (or groe production split to WF and/or 0o- vern nt), d) Cash bonus. I D. Freo disposltion may not coincide with prioe deregulation: (t) Uncertainty over tim of price (I) Crude oil and petroleum deregulatlon and time of product prlces should transition to tree dispoeability first be linked to International prices and then move to freely negotited prices t the sme time as free crude oil disposition. I E. Inadequate attention has been given to assessing the present worth of the righte/assets being offered. (i) Too many petroleuvm nv etment (1) A good marketing strategy opportunitles may be planned need to be developed almd to be offered at the same time at achieving rel Interns- tion competition for the opportunities offered. II) Fair value for the aseete/righte (tt) In order for the Govrnment bilng offered can probebly not be to recelve fair value for achieved form up-front cash the *aseft/rights, grst bonuse. attention should be given to packaging, timing, ssessment of realistic value and, most importently Identification of specfic areas where private sector investmnt Is most crucial In achieving major pro- duction Incrases. II. WPUNDW OF WMODIAL AREAS 1D BID Investor Interest may be limited by: (t) Lack of bid criteria and absence (T) Issue deta led bid crT- of contractual framwork; and toriT and proposed contract; streamline contract approval process. - 85 - (11) Smll size of areas (blocks). (11) Group block* Into area of sufficient size with potentiol for both Increased production and exploration (131) Limlted occos to technical date (iii) Provide acces to coplete and well organi- zed technical data. II. JOINT VEhTURES IN CUTRAL DRS Priority should be given to prooting Joint ventures for enhanced rocovery In well selected win producing aras, since these have s high probablity of achieving significant productlon In- creoose in the near term. However, Investor Interest my be limited by: (I) Absence of Joint venture (I) Define optlons of set1 of frameorkI rights for Incremental production or existing and Incremental production (farm-in). Prpare bid criteria (which Include Investment commitments) and model association (farm-in) and Joint opereting *grements. Stremline contract approvel process. (11) Denial of operatorehip (I1) Transfer of all or part of YPF oparstorehip role to contractor (1i1) Num_r of areo (blocks) (llt) Ensure that san of the available and potential best acreage Is Included prospecti venes In areas offered IV. "AiWAL GAS Limited Interest In exploration and production for natural gas, as well as for trentment, transportatlon, distrlbution, and marketing of natural gas: - 86 - (i) Leck of procedures for (1) Initlate study as soon as calculation of producer poxsoble on tronsport.- netback tion and distribution costs and tariffs; *stabilh clear criteria for establishing producer netback (before contract renegotlitions) (11) Uncertainty on currency of (11) Develop guidelines, for at payment for natural goc; least for partial paymant of natural gas produced In foreign exchange. (ili) Uncertainty over market potential (iii) Initiate detalled market and demand growth study with viow to expanded natural gas use. (1v) Monopoly on natural gas supply (Iv) Issue noe decree allowing multiple see supplies and allowing private suppliers of natural gas to se l directly to conoumers (as outlined in principle In deregulatlon decree) - 87 - Roles and ResPonsibilities for Petroleum Policy 5.44 To overcome the difficulties in making a successful transition to a deregulated system, it will be necessary to establish a new institutional framework that is less complicated and more attractive for private sector participation, and one that provides stability for both state enterprises and the private sector on the basis of long-term commitments. To resolve the inefficient relationship between the Government-public enterprises and private companies, corrective ac.ions should be implemen id such ass (i) separate the Government functions as policy-maker and regulator from those of directing business activities of the enterprises; (ii) establish an environment of open competition and equal opporttnities for both public enterprises and private companies in all aspects of the production and disposition of energy resources; and (iii) encourage efficiency and profitable objectives by all energy companies, while at the same time ensuring that national interests are protected, with a minimum of regulations and controls. As a result of the planned deregulation of the hydrocarbon sector, the regulatory agency will have an important added role in the following matterst i) energy policy and planning, relying on its own staff and resources; (ii) exploration/production activities in terms of promotion of new acreage for investments by both state enterprises and private concerns, negotiations with these entities and monitoring of implementation of their contracts; (iii) logistics for regulation of pipelines and other transportation facilities and deciding tariffs within the system; (iv) ensuring that taxation of crude oil, natural gas and petroleum products reflect Government policy; (v) ensuring confidance with public safety and environmental standards. 5.45 As a result of these added responsibilities, the role of the regulatory agency would expand. The agency should be adequately staffed with competent expertise, and the legal framework should be complemented with needed regulations, such as common carrier regulations and natural gas regulations. 5.46 In keeping with deregulation of the hydrocarbon sector, state enterprises should strive to become efficient and financially viable. Restructuring should achieve two main objectives: (i) clear identification and assessment of its separate business activities, with a decision being taken as to which business units possess the capability and resources to compete effectively and (ii) maximization of YPF's and the business units efficiency, as a company measured in terms of productivity and profitability. In order to achieve those objectives, YPF would be structured into a holding company of strategic business unit companies. _ 88 - Each unit would cover specific business activities (Exploration and Production, Industrialization, Marketing, Transportation and Shipping, Gas Transmission, Petrochemicals) with defined scopes and limits, drawing on its own resources and controlling all inputs that may affect its performance. The holding company would be responsible for the strategic planning and general direction of all the business units taken as a group, the allocation of financial resources between business units, and the control of operations by results. 5.47 The exploration and production business unit would cover oil!gas exploration and production operations, including geophysical and geological data acquisition and interpretation, drilling wells for exploration and field development and oil/gas field production as well as sale of crude oil to the refiners and/or export and natural gas to the natural gas unit or other customers. The industrialization uniit would cover all refining activities, including design, installation and refinery engineering, procurement and construction, as well as refinery operations and purchase of crude oil and sale of petroleum products ex-refinery. The transportation and shipping unit would cover engineering, procurement and construction, as well as operations of oil trunk pipelines, shipping terminals and tanker shipping. The marketing unit would cover all petroleum products pipelines, construction and operation as well as the operation of the truck fleets and the retail petroleum products station required for distribution of products. The natural gas unit would cover purchase of natural gas (from producers in Argentina as well as from foreign suppliers), and gathering, separation, treatment, conditioning and transport of natural gas through transmission pipelines (natural gas transmission activity is left separate from the transportation and shipping unit involved with crude oil because of the unique problems of natural gas). The petrochemicals unit tiould cover all of the fertilizers and petrochemical plants in which YPF owns an interest. 5.48 The ownership composition of each business unit company could take many forms, such ass (i) totally owned by the holding company, or (ii) associated with private operating companies, or, (iii) include private shareholders through sales of shares in the stock market. 5.49 The business units companies could also be themselves owners or shareholders of more specialized operating companies, which would thus be subholdings of the main holding company. F. IMPROVING EFFICIENCY IN YPF AND GdE OPERATIONS 5.50 A large potential exists for improving YPF's and GdE's external and internal efficiencies. In addition to the changes in YPF structure outlined above in section E, external effi-iencies can be improved substantially by providing each of these companies with autonomy of decision ia a profit-oriented competitive environment. There should be clear regulations and prices based on market values (as described earlier) within clear and consistent regulatory guidelines, such as those described - 89 - w'*.hin clear and consistent regulatory guidelines, such as those described in the previous section. YPP has initiated certain internal organizational changes and efficiency improvements, of which the key elements are: (a) Changes in organizational structure to allow operating departments 'lo function as true cost/profit centers. The establishment of clear transfer prices between the various operating departments; (b) Implementation of strategic plannin.g capabilities and preparation of a long-term investment progran; (c) Improvement of efficiency in upstream and downstream operations. (d) Installation of a comprehensive management information system and increased training. 5.51 Declining hydrocarbon production aAd reserves in YPF's fields are partly the result of poor operational efficiency in YPF. YPF has concentrated on the development of larger existing fields to the near exclusion of exploration to find new reserves. YPF has neglected to implement new and improved production techniques and enhanced recovery methods mainly because of budget restrictions imposed by the Government. YPF needs to develop a new strategy for exploration and development that will focus on projects that make economic sense for the areas in which it operates. A 2.0-252 efficiency improvement in YPF could yield about US$400 million per year in net gains. 5.52 At present, the refineries in Argentina are 2.5-352 underutilized as their capacity has increased; in fact, crude oil production has fallen. The existing refinery configuration allows for considerable flexibility in product output. To make full use of this flexibility, improvements are needed to reduce losses, optimize transport, and optimize crude and product blending. Improvements in YPF refining and transport operations could eventually result in total cost savings of US$200-400 million per year. 5.53 GdE, which has the monopoly on gas purchases and sales, had a current cash operating deficit of near US$200 million for 1987, and previous deficits of US$420 million accumulated from 1984-1986. There also are cumulative obligations for the next five years of nearly US$800 million for COGASCO, and there are large new investments, mainly related to NEt3BA II and other pipeline expansions, of over US$800 million. Among the causes of these financial problems are: problems from the COGASCO legal dispute; planned large new investments without adequate financing; and other management problems, including labor union interference. 5.54 With the completion of the NEUBA IX pipeline, there is a need to plan carefully optimal utilization. Annual capacity to transport natural gas is expected to grow from 18.4 billion m3 to 32.7 billion m3 by 1995 with the planned amplifications of NEUBA II and the Center West pipelines. At present, 14.5 billion m3 is piped from domestic sources plus 1.6 billion m3 is imported from Bolivia (this contract terminates after 1992 and whether or not imports will continue is not clear). However, present proved gas reserves cannot support the increases in supply projected after - 90 - 5.55 With the completion of the NEUBA II pipeline, there is a ueed to plan carefully optimal utilization. Annual capacity to transport natural gas is expected to grow from 18.4 billion m3 to 32.7 billion m3 by 1995 with the planned amplifications of NEUBA II and the Center West pipelines. At present, 14.5 billion m3 is piped from domestic sources plus 1.6 billion m3 is imported from Bolivia (this contract terminates after 1992 and whethe: or not imports will continue is not clear). However, present proved gas reserves cannot support the increases in supply projected after 1991. Future discoveries of natural gas, and whether there will be supply increases after 1991, depend on whether production 'ncentives (such as an increased producer price) are implemented soon. Building the NEUBA II pipeline without an adequate secure supply source from the Neuquen region shows that there needs to be an improved coordination of supply investment plans and utilization options. Also, the rapid increased production of gas in Neuquen has resulted in the loss of significant liquids production. Hence, there should be a detailed economic evaluation of all future prospective investments to determine the optimal expansion system. 5.56 The less than optimum use of natural gas in Argentina is the result of several factors: (i) distorted pricing and incentive policies; (ii) inadequate sector planning, that failed to optimize supply, transport, and demand for natural gas; and (iii) institutional constraints limiting the participation of the private sector in natural gas activities. To overcome these difficulties, the following actions are needed: (a) Increase the role of the private sector in the natural gas subsector, with adequate tariff increases and internal organizational changes in GdE prerequisites for such actions; (b) Implement Resolution 441, which allows the pri-ate sector to build and operate branch distribution lines, together with arrangements to facilitate financing of such lines; (c) Consider the implementation of a system of linking natural gas purchases to increasing private ownership in GdE; and, (d) Organizational changes within GdE should be made to: (i) Establish cost/profit centers for each operating department, (ii) Improve billing and collection systems, (iii) Reduce stocks of replacement equipment and spare parts, and (iv) Improve investment evaluation and selection procedures by basing future investment choices on economic criteria. - 91 - CHAPTER VI REFINING A. REFINING CAPACITY AND OPERATION 6.1 Argentine refineries have a capacity of 710,000 barrels ner day, which is in excess of current domestic requirements of 435,000 barrels per day. As much as 802 of this capacity can efficiently be used for the refining of light Argentire crudes, with the remainder of downstream capacity devoted to fuel oil cqnversion to middle and light distillate productr. 6.2 YPP's conversion capability is new, with units brought on stream in 1988189 consisting of US$1 billion investments in the La Plata and Lujan de Cuyo refineries. This brings YPF generally in line with the capabilities of the ESSO and SHELL refineries in Argentina, and also is consistent with world trends to install similar capacities. (An evaluation of conversion compared to topping capacity for all Argentine refineries appears in Annex 6.1.) Refinery Operations 6.3 Several operational issues emerge as key factors in measuring the health of the refining sector, specificallys (a) Control of Operations. To achieve the highest yields on higher value products, all refineries in Argentina have improved their yields of clean products over the past 10 to 15 years. (b) Energy Efficiency. To reduce costs, YPF is presently running its refineries at 225 percent of efficiency guidelines for energy utilization. This represents a significant effort on their part in recent years, since they have reduced inefficiencies from even higher levels. Initial diagnostic work indicates that YPF can reach a nominal 170 percent of guideline efficiency through new investments and operating changes. ESSO is already 150? of guideline efficiency, with a program targeted to go even lower. SHELL is operating at a level similar to ESSO. Both these programs represent a significant part of international private company efforts over the past 15 years. (c) Loss Control. From refining operations through transportation to marketing, YPF does not have a comprehensive assessment on control of corporate losses. Initial evaluations would indicate that losses are two to three times higher than the industry average. In contrast, both ESSO and SHELL have excellent loss control programs functioning. (d) Product Blending Efficiency. Initial diagnostic work has indicated a weakness in YPF's ability to blend products economically. Part of this problem is the result of Government regulations that force YPF to remain in negative-to-low-margin business lines, e.g. In the provision of fuel oil, which the private companies have abandoned as uneconomic. For this reason, YPF is at a clear disadvantage compared to its main private sector competitors in effective and economical blending. _ 92 - (e) Ability to Handle Crude Oil with High Sulfur Content. The entire Argentine refining industry is relatively weak in its ability to deal with crude oil with high sulfur content, since the local crude oils are slate and there have always been restrictions on imported crude. Crude oil swaps that would allow exports of high- quality, locally produced crude oils, and the import of lower- quallty crude oils are important considerations in profit-seeking refineries. If crude oil swaps were allowed, then desulfurization facilities for jet fuel and motor gasoline would need to be installed by the deregulated industry, both to facilitate a relatively inexpensive increase in r orage capacity and to process crude oils with higher sulfur contenL. Of course, environmental safeguards are necessary to prevent pollution. (f) Ability to Handle Heavier (Lower API) Crudes. If heavier crude oils were imported, this would allow a more economic optimization of crude feedstock slates versus product demand. The entire Argentine refining industry is relatively weak in this area. Vacuum distillation capicity is relatively low, as are the capacities of other downstream conversion units. If the Government were to allow free import and export rights of crude oils and refined products, and eliminate the system of guaranteed profits for local refineries (which international industry does not enjoy), then freeing projects to increase the capacity of downstream conversion units could be done at relatively low cost, since these facilities would permit a profit-seeking refinery to process heavier, i.e., lower-cost crud* oils. When the large excess motor gasoline produced by YPF !s considered, changes in refinery crude slates to heavier and cheaper crude oil become a viable, economic alternative, while lighter crude oils should be exported at a premium, and thus increase overall profitability. (g) Self-Sufficiency versus Export-Oriented Refinery ORerations. Argentine refining capacity has been used to meet domestic requirements; however, this approach i not economic for the country nor efficient for the local petroleum refining industry. The size of Argentine refining capacity, however, should provide excellent capabilities to import and export crude oil and its products to achieve an economic balance between supply and demand. The physical location of the refineries--YPF's La Plata, ESSO's Campana, and SHELL's Doc Sud--indicate that about 580,000 barrels per day of capacity is sufficient to participate effectively with the international crude oil and refined products markets. One result of an export- oriented refinery industry would be that the topping-only refineries, which comprise 10 percent of the Argentine industry total, would not be considered economically viable in a market with free market crude oil and refined products prices. (h) Excess Naptha Production. Currently, YPF refineries are producing excess naptha and distillate (caused by (i) sharply lower demand due to higher prices from a gasoline tax hike in 1988, and (ii) significant increases in condensate production with increased natural gas production to meet expanded capacity). This results in excess naptha being exported at a loss from normal market - 93 - prices since it does not meet international quality standards. The volumes could be reduced as much as 20-502 by optlmizing unit operations and by using other domestic crudes, but this has not occurred. The excess distillate could provide potential profits. This is mainly because jet-fuel, high quality cetane gas-oil, and lubes are not segregated, and because other imported crude slates have not been considered. 6.4 In summary, although the Argentine refining industry has engaged in a large-scale effort to move to higher-value production, there is further scope to improve yields, efficiency, and profitability. Refining capabilities to produce these higher valued yields have not been fully utilized. The basic reasons for lack of optimization include (see also Annex 6.2): (a) Import and export controls, which have reduced the refineries ability to balance crude slates and product yields with international market requirements: (b) Industry reliance on Government protected refinery margins; (c) Domestic price controls that maintain overall prices at lower levels relative to international markets and distort price spreads between product grades; (d) Strategies by the private refiner to overcome both the local regulations and distorted price structures to increase private company profitability at the (partial) expense of YPF refineries; (e) Inability of YPF to act efficiently as a profit-seeking entity. 6.5 The large installed capacity of Argentine refineries, almost twice domestic requirements, is considered as a resource waiting to be exploited. Marginal refinery capacity can be economically employed for generating exports of products and for arranging third-party (foreign) processing agreements. However, the existing 102 tax on refined crude oil effectively eliminates any incentive to optimize this resource in much the same way that unrealistic and unnecessary price controls distort demand and stifle efficiency of operations for the domestic market. Thus, a prerequisite for optimizing the Argentine refining industry is price deregulation, with prices linked to international values, and elimination of distortionary taxes that reduce the effective use of this industry's potential. In the present situation, it is more economical to export Argentine crude oil to Chile or Trinidad for processing than to employ Argentine refining capacity, since both of these countries have clear policies and programs to solicit this type of marginal operation. Optimization of Existing Refinery Capacity 6.6 The overall Argentine refining capacity and its conversion capability are greatly underutilized despite the incorporation of new and expensive resources. A preliminary analysis shows that on a marginal economic basis the nominal 100,000 barrels per day of probable efficient idle capacity only needs to cover fuel costs to become operational if domestic or imported crude oil becomes available for refining. A US$1 per - 94 - barrel marginal profit--to be obtained from processing additional crude oil and exporting the products--could yield US$35 million per year in additional revenue. Also, the lack of optimized domestic product pools causes opportunity losses worth possibly US$50 million per year if the products were brought up to international market quality and then exported. 6.7 To overcome these problems, an adequate operating environment for all refineries must be created to encourage better economic use of existing facilities. The aim is to increase production to satisfy the domestic market and at the same time facilitate exports of substantial volumes to maximize foreipn revenue. These objectives can be reached by a combination of adequate r' ilatory changes as well as price and tax changes (see Chapters III and IV). Clearly, one of the most important changes would be to eliminate the 102 tax on crude oil refined in Argentina. The lost Government revenue can be more than offset by end-user petroleum product taxes. 6.8 The implementation of adequate policies might include the award to refineries of exports through licenses, with the lead time to obtain significant increased volumes for exports as much as one to two years. It may be necessary to import different types of crude oils. It also would be important to allow the use of various domestic crude oils to obtain the crude slates to maximize profits. The estimated combined value of potential optimization of domestic product quality is about US$60 1-4illion per year, as shown belows (a) Export of jet fuel or high cetane gas oil, rather than ordinary gas oil, at a US$l per barrel advantage, on a nominal 800,000 cubic meters per year surplus basis, may yield up to US$5 million a year. (b) Export of lube oil stocks, worth at least US$16 per barrel more than fuel oil, on a nominal 100,000 cubic meters per year surplus, which presently are not recovered, could provide an income of US$10 million per year. (c) Optimization of fuel oil pool volume availability, to export a product with higher qualities and to import lower quality components, on the basis of 1 million cubic meters per year volume, at a minimum of US$0.5 per barrel after freight differential, could produce about US$5 million per year in additional revenues. (d) Optimization of earnings on the export of gasoline components by upgrading qualities and eliminating lead content, based on 1.5 million cubic meters per year surplus, at a minimum US$0.1 per gallon additional export differential, will provide an income of US$40 million per year. 6.9 The above improvem-nts in refinery operations and the increased benefits still do not include the probable economic benefits in the internal market, which could be the following: (a) Higher refinery prices for fuel oil, which would be tied to the end-user alternative cost to import fuel oil of comparable .4 - 95 - (b) Generally lower refinery profits on domestic "clean' products. (c) Higher refinery profits derived from domestic sales at true market value for coke, LPG, and chemical feedstocks, which are now set by the Government at unreasonably low prices. (d) Efforts by all refineries to further automate operations and to streamline the work force (which appears to be excessive in most all cases) will definitely increase efficiency. B. IMPROVING EFFICIENCY 6.10 Evaluation of all YPF operations shows its refineries are grossly inefficient energy consumers. A possible 30 percent reduction of guideline efficiency to 170 points could be worth US$20 million per year in savings. To date, the necessary work planned by YPF to reduce energy costs is not the result of a systematic review of problems and options or a comprehensive and encompassing management program. Many projects already underway o; already completed implicitly accept unreasonable design criteria and operating conditions that institutionalize inefficiency. All inefficiencies should be identified and the best alternatives selected. Moreover, YPF should quantify costs and benefits, establish critical design and operating criteria, and provide overall priorities and schedules. If these recommendations are carried out, all existing units, including those newly constructed, would be economically well integrated; additionally, management would have a matrix of future efficiency improvements on which to base subsequent actions. Reduction of Production Losses 6.11 A diagnostic study performed to evaluate YPF operations indicates that the refineries suffer high levels of production losses. A detailed evaluation of the operations and a comp-ehensive loss reduction program should include vapor-loss-reduction facilities for crude oil and products' storage tanks, reduction in flaring, cleanup of effluent systems, and improved measurement and control. YPF must seek competent technical assistance to develop and implement a comprehensive program of loss reduction. The expected benefit from such a program probably could be equivalent to 22 of crude oil throughout, i.e., about US$30 million per year. Reducing Inefficiencies in Storage, Transportation, Distribution and Fleet Operations. 6.12 The discretionary but profitable international trade to export/import crude oil and refined products is jeopardized by inadequate port facilities, which lead to a loss of potential revenue. Also, YPF relies on imported fuel oil to cover shortages caused by increased demand in winter, which is usually required by industry and the power sector. YPF also faces investment requirements to improve other terminals--either to replace existing mooring facilities or to relocate or construct new terminals to serve new locations, or upgrade storage capacity in existing terminals. - 96 - 6.13 Argentina does not have a deep draft port with adequate facilities, i.e., reliable pumps, lines, and storage tanks, to economically load or discharge refined petroleum products for import/export or domestic operations. The port facilities for the ESSO, SHELL, and YPF refineries located in the Buenos Aires area are all draft limited to 25 feet by the depth of the river channel when 40 feet is actually required. 6.14 The marine terminal at YPF's La Plata refinery does not meet internationally accepted standards for a safe port, mainly because of: (i) the large number of ships and facilities cause congestion, (ii) the naturally restricted path for access/egress; and (iii) the type of products handled. To avoid these problems, SHELL is presently negotiating with YPF to upgrade the terminal facilities at YPF's Doc Sud refinerys also SHELL needs to replace its own terminal, which was lost due to a fire. However, the similarity between SHELL's old facilities and those at La Plata are disconcerting. The La Plata terminal can only pump crude oil at 20-502 of efficient rates, and storage tanks for qaality control and cargo optimization are not available for key products, such as motor gasoline, jet fuel, kerosene, atd diesel. 6.15 The key to proper definition of the scope and timing of these projects is the quantification of needed requirements based on long-term volumes and harbor loads, which have yet to be established by YPF. However, these investments are badly needed to improve both the reliability and economy of the existing marine terminals. For instance, in the case of crude storage tanks at Puerto Rosales, the adequacy of these facilities, which are needed for the national crude oil distribution system, is crucial to guarantee the utilization of crudes shipped from the south. 6.16 To provide an early solution to these problems, the marine terminal facilities at YPF's La Plata refinery must be upgraded now and with subsequent upgrading at other locations, where facilities are needed for YPF's own use. Nevertheless, strong consideration should be given to the construction of a terminal with a 40-foot draft to replace the existing terminal, since it not only would eventually serve all industry but will nloo be YPP's primary outlet for international trade. 6.17 To address deficiencies that need to be remedied in the areas of storage, transportation, distribution, and fleet operations, the following actions should be taken: (a) First, YPF must complete its long-term operating plans for domestic and international trade to determine volumes to be moved and loads to be handled in each terminal; this would provide the basis for guiding future marine terminal investment decisions. (b) To complement (a) above, YPF must complete the economic ranking of all projects for defining terminal upgrading and for replacement options, which will help to determine the most economical, long- term facilities that need to be constructed. (c) Additionally, YPF should solicit technical assistance from expert marine terminal consultants for the identification and quantification of project costs and benefits, and to establish optimum design criteria. - 97 - (d) Furthermore, detailed discussions should be held with all parties concerned to determine the feasibility of constructing a marine terminal that can be used by the entire Argentine petroleum industry. (e) Finally, sectoral planning must reflect the importance of improved harbor facilities, especially for international trade, whereby Government intervention in providing support for costs and expected benefits should be equally parceled to YPF as well as the rest of the Argentine industry. 6.18 If these recommendations were to be implemented, the expected investments would be as followss for the near term, only key minimum facilities at La Plata would be upgraded. This would require a probable minimum investment of US$10 million. This investmeL does not include the facilities projected for segregating unleaded gasoline, which could add another US$5-10 million to the total cost. For the long term, YPF and the entire Argentine industry should consider the construction of facilities with at least 40 feet of draft: external financing would be needed to support this US$200 million investment. Other marine terminal investments are likely to cost about US$100 million, but these will be mainly for facilities needed only by YPF. However, with these investments, Argentina will have the appropriate terminal facilities to earn important profits on the large investments already made in refining capacity and new conversion capabilities. Inefficiencies in Domestic Marketing Operations 6.19 The Argentine domestic market for refined petroleum products is extremely overregulated and characterized by erratic demand patterns and poor profitability--both caused by governmentally fixed prices that are generally unresponsive to true market conditions. Therefore, conditions must be created that will allow restoration of economic equilibrium to the domestic market prices for refined petroleum products by aligning them with world petroleum prices (as described in chapter IV). 6.20 Even though YPF is the dominant marketer in Argentina, it does not have a comprehensive marketing strategy for each product line to ensure adequate performance in an excessively regulated environment. Hence, there is a need to assist YPF in developing a strategy for effective marketing in a deregulated environment. 6.21 The solution is to position YPF strategically both as a revenue- generating arm of the Government and as a company that can effectively market domestically a whole range of petroleum products in a freely competitive market. The implementation of these measures will require substantive internal changes within YPF as well as technical assistance from consultants to develop a comprehensive and long-term marketing strategy designed with specific objectives for each product line. This marketing strategy should include programs for evaluating investments in dispatch plants, service stations, airport terminals, and all other customer oriented service facilities, along with the quantification of expected economic benefits in a new regulatory environment. - 98 - 6.22 Similarly, and consistent with the proposed long-term YPF marketing strategy development, all rules, regulations, and practices that restrain YPF from actively competing with the private sector on an equal footing must be identified and eliminated. These will include regulations that appear to give YPF an advantage over private sector competitors, such as a mandatory obligation to buy goods and services from and sell to other public enterprises. In practice, such transactions are usually not done on a true commercial basis, either because the prices at which the goods and services must be transacted are out of line with prevailing market prices, or the transactions only result in further indebtedness of YPF for lack of payment by other public enterprises. 6.23 The best alternative for the Government seems to be privatizing YPP's marketing operations. However, privatization is not recommended until existing marketing operations of YPF are first put on a sound and profitable basis. The benefits to the Government for divesting revenue generating operations should be studied and evaluated. The studies should provide YPF with a rational strategy matrix for solving these problems, including privatization options and a detailed evaluation of opportunities for developing its domestic marketing capabilities, with costs and economic benefits clearly defined. 6.24 Although YPF is the dominant petroleum product marketer, its dispatch plants need modern technology for automation and product loss control. The upgrading of existing dispatch plants should proceed concurrently with the efforts to develop a new overall marketing strategy. YPP urgently needs assistance from experienced consultants in defining a realistic program to upgrade key dispatch plants. Priority should be given to improving those dispatch plants located in 1 Igh-volume areas and for closing or downsizing low-demand centers. With these investments--which could be as much as US$125 million spread over the next five years--YPF will be able to obtain operating efficiencies to match their competitors, who are also engaged in dispatch plant upgrading. 6.25 The evaluation of YPF's mode of operations indicates that to improve its marketing capabilities it must upgrade customer service facilities like service centers for motor gasoline and jet fuel. This will require investments that not only will support the implementation of an effective marketing program but also assist in the simultaneous development of a new overall marketing strategy. - 99 - CHAPTER VII NATURAL GAS UTILIZATION A. INTRODUCTION 7.1 Natural gas plays an increasingly important role in Argentina as a source of energy for power generation, industrial production, and as a residential and commercial fuel for cooking and space heating. Over the past 10 years production has increased 52 per year and is projected to grow 42 per year throagh the year 2000. The policy of rapid development of natural gas use was predicated on an overly optimistic estimate of proved reserves that could be produced and marketed. Argentina's proved natural gas reserves are adequate to meet current needs, but as consumption increases, new reserves must be discovered to maintain an adequate inventory. The existing pricing structure provides little incentive to explore for and develop new sources of natural gas. If the Government's goal of increasing the use of natural gas to replace exportable liquid fuels is to be realized, incentives to explore for natural gas must be provided, and an accelerated exploration and development program initiated. 7.2 This chapter provides estimates of the economic and financial costs of producing and delivering natural gas. The economic costs (including the depletion premium) by sector are compared to netback values, and a ranking of optimal natural gas utilization by subsector is also provided. B. SUPPLY/DEMAND PROJECTIONS Demand 7.3 Two demand scenarios, a Base Case and a High-Demand, are used to assess the adequacy of available natural gas resources to meet the projected level of demand under different economic conditions. The Base Case is similar to the mid-line projection ('hipotesis de media") recently prepared by GdE. However, this projection was modified to incorporate adjusted fuel requirements for the power sector and a modified -chedule for construction of some of the proposed petrochemical projects. GdE had projected requirements only until the year 2000, so it was necessary to project the demand for the post-2000 period. 7.4 Base Case projections for the residential, commercial, transport, industrial, and refining sector are the same as the GdE median projection. Power sector requirements are based on projections of electric power demand and natural gas consumption made by the Secretaria de Energia in March 1989, nnd are somewhat lower than GdE's 1988 projections. Natural gas requirements for the petrochemical sector have been modified to reflect a slower rate of industry development. The Resinfor project (Santa Fe) would be rescheduled from 1992 to 1997; the ammonia plant (Planta Loyola) deferred from 1992 to 1997; the Fertineu and Fertinoa fertilizer plant operations postponed until 1995; and the ammonia export projects eliminated from the plan. The existing export/import contract commitments are maintained. Under this modified schedule, the total requirements and indigenous production, including allowances for field use and losses, would be: - 100 - REQUIREMENTS PRODUCTION YEAR MMCM MMCM 1990 20,859 20,671 1995 23,276 25,603 2000 27,832 30,616 7.5 The High-Demand scenario is based on GdE's projected requirements for the residential, commercial, transport, industrial, petrochemical, and r-finery sectors. Power sector demand is based on the maximum use of gas- fired thermal stations until 2010. The projected demand would be: REQUIREMENTS PRODUCTION YEAR MMCM MMCM 1990 22,387 22,352 1995 26,424 29,067 2000 34,317 37,748 SuPply 7.6 Four supply scenarios were considered in developing the supply/demand balance. The Minimum Supply Program and three different development scenarios have been postulated to determine the adequacy of gas resources to meet projected requirements under each of the growth scenarios. Under the Minimum Supply Program, the supply would be limited to the minimum reserves volume of 504.6 billion CM; however, it is anticipated that additional reserves will be discovered. On the other hand, over the past five years, gas reserves have been added at a rate of less than 19 billion CM per year, barely matching production. YPF has proposed a 10-year exploration program that they project would add 396 billion CM of reserves over a 10-year period. Based on an analysis of historic results of exploratory efforts, this estimate seems optimistic. The development programs are based on adding production from the estimated probable and possible reserves that may be discovered in the Deep Neuquen Basin strata, the Austral Onshore and Offshore Basin, and the Northwest Basin. Table 7.1 lists the proved and probable reserves in each of these areas and the ratio in which these reserves are assumed to be produced under each of the production scenarios. Indications from the official proved natural gas reserves as of 1/1/89 are that the proved natural gas reserv s in the Northwest and Austral basins are somewhat larger than those utilized as minimum proved natural gas reserves scenario (see chapter V and Annex 1 for details). - 101 - Table 7.1: PRODUCTION 9,ENARIOS Probable/ Possible Scenario (2) Reserves Basin MMCM A B C Deep Neuquen 81.1 50 50 0 Austral Onshore 30.8 25 15 15 Austral Offshore 85.4 0 10 35 Northwest Basin 52.6 25 25 50 7.7 The need to add more natural gas reserves is a function of the rate of consumption, the level of imports and exports, and the desire to maintain a minimum critical reserves/production (R/P) ratio. The level of the critical reserves/production ratio varies from country to country, depending on the prospects for adding new reserves. In a country where geological evidence indicates that prospects are good, and the industry is in an early stage of development, a 10-year RIP ratio may suffice. In countries where prospects are less certain, maintaining a minimum R/P ratio of 15-years would be more prudent. In the case of Argentina, a 15-year R/P ratio has been selected to determine the rate of new reserve additions that will be required. 'When the critical R/P ratio level is reached, a demand management program should be instituted to assure that the currently- attached customers will continue to receive natural gas for the remaining life of the installed equipment. Normally, this would be done by permitting additional sales only when new reserves are found. The year in which the critical R/P ratio would be reached under the various supply/demand scenarios is shown below. Table 7.2s YEAR CRITICAL RESERVE TO PRODUCTION (RIP) RATIO IS REACHED Base Case High Supply Scenario Demand Demand Minimum 1994 1993 Scenario A 1998 1995 Scenario B 2002 1998 Scenario C 1998 1996 Based on these projections, natural gas can play a growing role in the Argentine energy economy after the year 2000 only if an accelerated natural gas reserve exploration and development program is undertaken soon. - 102 - C. FINANCIAL AND ECONOMIC COST OF SUPPLYING NATURAL GAS TO CONSUMERS Financial Cost 7.8 The financial cost of supplying natural gas includes all investment and operating costs, plus all transfer payments such as royalties, taxes, and other charges levied against the supplier. In estimating the financial costs, the field development costs are based on local costs, including the effect of any subsidies or added costs for locally produced goods and services. GDE's financial costs are based on projections of historical data and may not provide an adequate return on actual investment. A cost-of-service study should be conducted to confirm GdE's costs. Table 7.3 lists the financial cost of natural gas delivered to the same classes of customers described above (Fourth Quarter 1988 US Dollars); Annex 7.4 provides details on the assumptions used. Economic Cost 7.9 The economic cost of supplying natural gas to end-users is the cost to the national economy exclusive of transfer payments, such as royalties, taxes, and duties. The economic cost includes two main components--the average incremental cost and the depletion allowance. The average incremental cost (AIC) includes the cost of exploration, field development, production, field gathering and treatment, pipeline transportation and distribution if required. In the case of a depletable resource such as natural gas, a depletion allowance must be included to calculate the total economic cost. The required investments are based on international costs so as to eliminate economic distortions due to subsidies, inefficiencies, or other local cost factors. Average Incremental Cost 7.10 The average incremental cost (AIC) of supplying natural gas from each of the producing and prospective basins to the city gate at Buenos Aires, and to each class of customers served from the distribution network, is shown in Table 7.4 (see Annex 7.1 for details). The average city-gate cost is the weighted average of deliveries from each basin, as defined for each scenario. The AIC for residential, commercial, and general industry customers is based on distribution in the Buenos Aires area. The AIC for fertilizer is the cost delivered from the Neuquen Basin to a plant in the immediate arsa. Similarly, the AIC for deliveries to the proposed methanol plant is for delivery to a plant in Tierra del Fuego. The average city- gate cost varies from US$35.41 per MCM for Scenario A, assuming historical exploration costs in the northwest region, to US$39.01 per MCM for scenario C, assuming high exploration costs in the Northwest Basin. Depletion All_wance 7.11 The depletion allowance for natural gas, or anv other exhaustible resource, is the foregone future value of the resource if used today; thus, it is the cost of the replacement fuel, when natural gas is exhausted, discounted at the applicable discount rate to the present. In effect, the depletion allowance is money that should be set aside to purchase replacement fuel when it is reauired. Therefore, the depletion allowance is determined by: (i) the future real cost of the replacement fuel, (ii) 103 - the depletion period, and (iii) the discount factor. The depletion period is determined .~, the total resource base and the rate at which it is consumed. The future cost of the replacement fuel is based on projections made by the World Bank, which indicate that the price of crude oil in terms of 1986 costs would be US$12.20 bbl in 1995 and US$15.40 bbl in the yea 2000.1 These were the basis used to estimate the depletion allowance under the four supply scenarios and the two demand projections. 7.12 Based on proved natural gas reserves, which were estimated at a minimum of 504.6 billion CM in 1988, and the Base Case projection of natural gas requirements, the depletion allowance would be US$25.36 per MCM (US$0.72 per MCF). However, it is unrealistic to assume that no new reserves will be added to the resource base. The depletion allowance has been calculated under the development programs assumed for Scenarios A, B and C. To provide a full range of analysis, the depletion allowance was also calculated for two other scenarios; Scenario D asswumes no additional reserves would be discovered in the Deep Neuquen Basin, but the estimated probable reserves in all other basins would be developed. Scenario E, the most extreme case--except for the Minimum Developmert scenario--assumes that ouLly the probable and possible reserves in the onshore and offshore Austral Basin will be added. Table 7.5 lists the depletion allowance for each scenario. These figures were prepared based on January 1, 1988 reserve figures. As noted earlier there has been some increase in reserves in the Austral and Northwest basins during 1988. There is also preliminary information that some additional gas reserves have been found in Neuquen, in the last half of 1989. This kind of self-praise is not very professional or apt to leave a good basis for collaboration with the Government. Thus, at the time of finalizing this report gas reserves are now higher than the minimum case. An addition of 80 billion CM to Minimum Case reserves, would bring it up to 584 billion CM. This reserve level (at the end of 1989) results in a depletion premium estimate of US$15 per MCM 'US$0.43 ner MCF). 1/ Price Prospects for .Kaior Primary Commodities, International Economics Department, World Bank Report No. 814/88, Washington, D. C., 1988. - 104 - Table T.8s FINANCIAL COST Developmnt Scenario A (6/MCI) ou4uen Austral Noroest De p q Offshore SxplorCtion 7.97 10.14 7.68 12.98 18.69 Production 44.19 82.98 77.41 59.02 84.68 P/L Transport 24.00 46.86 27.60 24.00 48.88 City ont. 16.16 91.6 112.64 96 96.65 Dlitribution Residential 44.98 44.96 44.96 44.98 44.90 Comerclel 44.98 44.96 44.96 44.90 44.96 Industry and Power 1.28 1.21 1.28 1.28 1.28 Pat of Proved A Prob R xrves 42.6 16.1 26.6 12.8 0.1 Average city gate cost 91.00 I/1CM a 2.56 6 /MCF Average Residentill 18S.98 "/MCM a 8.65 I/MCF Average Comercial 185.96 S/MCI a 3 8.6 /MCF Average Industry (Buenos Aires) 92.28 I/MCM a 2.61 3/ICV Cemnt 50-e0 S/MC - 1.41-2.27 I/ICF lower (Buenos Aires) 92.28 S/MCI = 2.61 I/MCF Fortilizer (Nequen) 6S.16 S/1CM a 1.59 S/MCF (Assumptions for calculations are decribed In Annex 7.4.3 - 105 - Table 7.4: AVERAGE INCREMENTAL COST (Scenario A) (9/KM) Neuquen Austrol Noroets D p Moo. Offshore Explorstion 6.00 7.60 6.67 10.00 10.50 Production 9.46 8.46 16.21 11.46 6.86 P/L Transport 18.29 29.67 16.92 18.29 29.67 City Gate 20.74 46.68 41.00 84.76 40.62 Distribution Rewidential 48.80 46.80 48.80 48.80 48.80 Cowmurclal 4e.20 46.20 46.20 46.20 46.20 Industry 4.12 4.12 4.12 4.12 4.12 Pct of Proved A Prob Reervea 42.0 18.1 26.6 12.8 0.10 Average city gets c%vt 85.61 */mC 1.01 8/MCF AIC Residential 84.11 I/MCU 2.88 */MCF AIC Comme-cilo 82.01 $/MCU 2.82 I/MCF AIC Gn. Ind. 80.98 I/ECU 1.18 S/MCF AIC for Commnt. 80 - 50 S/MCM 0.65-1.42 S/MCF AIC tor Power 86.84 I/UCW 1.04 I/MCF AIC for Fertilizer (Naquen) 17.45 S/MCU 0.49 8/mCF AIC f'r Methanol (T. del Fuego) 17.06 S/ECU 0.51 8/MCF *Varies for oech location Siournss Bank *.ti. t . Table 7.5: DEPLETION ALLOWANCE ALL FLDS NEqDEEP NORWEST AUSTONS AUSOFFSH TOTAL DEPLETION DEPLETION MINIMUM PROS/POSS PROS/POSS PROS/POSS PROB/POSS RESERVES ALLOWANCE ALlOWANCE RESERVES RESERVES RESERVES RESERVES RESERVES SCENARIO SCENARIO MMCM MMCm MMCM MMCm MMCM MMCM 9/MCm I/MCF =mum .. u.= zm== ain. =uuz = = u A 6K4.8 ".I 62.8 80.8 0 669.1 7.49 0.212 6 504.6 61.1 62.6 80.8 865.4 754.5 8.09 0.118 C 604.6 0 62.6 80.8 65.4 678.4 7.28 0.206 D 604.0 81.1 0 80.6 66.4 701.9 5.69 0.167 E 604.6 0 0 80.8 65.4 620.0 10.72 0.804 Minimum 604.6 0 0 0 0 504.6 26.86 0.716 Sources Sank stimate Note: See paragroph 7.12 for alternative estimate of depletion allowance - 106 - 7.13 The difference in the depletion allowance under the Minimum Supply scenario and Scenario B, US$21 per MCM, is the amount which should be set aside by the national economy to provide replacement fuel if additional natural gas resources are not discovered. Over a 10-year period, this would amount to approximately US$5,250 million. If the proposed exploration program were carried out and succeeded in finding all of the probable and possible reserves as estimated, the cost would be approximately US$2,100 million. This shows the large benefit (US$3,150 million) of implementing a vigorous natural gas exploration program immediately. 7.14 In addition, there are large benefits to the economy of using more gas since natural gas has a much lower cost energy source (US$8/NMBTU of useful energy) compared to electricity (US$32lMMBTU of useful energy), as shown in Table 7.6. 7.15 If natural gas is consumed as projected under the High-Demand scenario, the depletion allowance would be higher. For the Minimum Supply case, the allowance would be US$30.78 per MCM and proportionally higher for the other development scenarios. The savings to the national economy by undertaking an immediate development program would be about 15-202 greater than under the Base Case demand scenario. Table 17.: COMPARISON OF RESIDENTIAL ENERGY PRICES BASED ON PRICES OF USEFUL ENERGY Natural Residential age LPG Kerosene Electricity Comercial Price w/taxas -orllnnl units 82.07/MCF 8330-380/Ton 8199/Ton 86.7/Kwh8 -8/fa0TU 2.878 6.49-7.99 5.00 14.85 -$/UMMTU Useful .74 18.00 12.60 18.81 Energy Economic Cost -original units U4.05-4.62/mcf1/ 8360-400,Ton 1184/Ton US cents 8.7/kwh -S/MITU 4.05-4.82 7.86-8.41 4.62 26.49 2/ (48 peak to 18 off peak) -8/MJTU Usful Energy 8.10-9.24 1S.7 13.8 31.88 Efficiency sox 5O UX 80% (Stove top cooking) 1/ Economic cost of gas baosd on fuel oIl equlvalent plus distribution costs to residential households. December 1986 prices usod In the example. 2/ Bosed on estimated marginal cost, see Chapter III. 1/ From July to Docembr 1989 reoidentlo! gas prices dropped to t'80.60/WSTIU and electricity to US983./Kwh - 107 - 7.16 In addition to developing natural gas resources, the delivery infrastructure must be expanded to meet growing demands. If the pipeline system is not expanded, the capacity of the systcsa, including the expanded NEUBA II pipeline, will be exceeded in 1996. There would be no natural gas for further growth, and the available natural gas would have to be conserved for the highest value uses. This could limit attachment of new residential customers and would certainly mean that industrial consumers and electric generating plants would burn more light and heavy fuel oil. As shown above, the economic cost of supplying natural gas, including the depletion allowance, will be in the range of US$40-45 per MCM; however, the cost of the fuels it replaces (primarily heavy fuel oil, and also some LPG, kerosene and distillate fuel oil) will be higher. The economic value of the fue±s replaced is roughly comparable to the city-gate price of natural gas. If the composite border price of fuels is US$12 bbl in 1995 and US$15 bbl in the year 2000 (in 1988 constant prices), the present value (PV) of the difference in the cost of natural gas and the fuels it would replace would be approximately US$1,800 million over the period 1989-2000. If the liquid fuels price io US$20 bbl in the year 2000, the PV would be about US$2,800 million. Any interruption or slowing of the pipeline expansion program would also have a significant economic impact. If the expansion program were delayed five years, there would be a supply shortfall during the 1996-2000 period, and other fuels would have to be burned. Even if the pipeline system were expanded after 2000 to meet the demand, the PV of the extra liquid fuels burned during the 1996-2000 period would be about US$200 million. This clearly illustrates the benefits of expanding the pipeline system to keep pace with growing demand. D. NETBACK VALUE OF PATURAL GAS 7.17 To determine if it is economical to use natural gas in specific market applications--such as residential cooking and heating, manufacture of specific industrial products, or for puwer generation--the netback value must be established. The netback value is the economic value of natural gas as compared to the next best alternative fuel or feedstock (details on netback calculations appear in Annex 7.2). For some new installations and most existing installations the netback value is the cost of an alternative fuel after taking into account any differences in the cost of using the fuel. In other applications, such as petrochemical manufacture, the netback value may be either the cost of another feedstock or the price that could be paid for gas that would result in a manufacturing cost less than the cost of importing the product. In some instances, the netback value could increase. For example, when calculating the netback value of natural gas used for power generation, it was assumed that a gas-fired steam plant would be used for the baseload portion of the station, because that is the only technology accepted by the Secretaria de Energia for baseload operation. If a combined-cycle station were used as the basis for comparison, the capital requirements could be reduced by as much as 25% and the efficiency increased by 10%. These technological improvements could significantly reduce generating costs and increase the netback value of natural gas. - 108 - E. OPTIMIZATION OF NATURAL GAS USE 7.18 If the supply of natural gas is limited, it should be reserved for those uses yielding the greatest economic benefit to the national economy. Gas should not be used for projects where tile economic cost of supplying the natural gas plus the depletion allowance is greater than the netback value. As previously discussed, the cost to the national economy of supplying gas includes all costs for finding, producing, and delivering to consumers. The economic cost of supplying natural gas to the principal market sectors, including the depletion allowance required if no new reserves are added, and the netback value of natural gas needed in each sector, are listed in Table 7.7. While the netback value is higher than the economic cost for natural gas to residential, commercial, and general industry customers, it only marginally exceeds the netback value of natural gas for electric power generation and cement manufacture. If only the minimum reserves are considered the netback value of natural gas used to produce fertilizer is near to, or less than, the economic cost. Therefore, uses of gas should be carefully evaluated to assure that they are economically justified, as some uses are much more economically profitable than other uses. Table 7.7: COMPARISON OF ECONOMIC COST AND NETBACK VALUE (Based on Fourth Quarter 1988 US Dollars) AIC Supply Depletion Economic Net-back Sector Cost Allowance (4) Cost Value $/MCM $/MCM $lMCH $/MCM __-w==S _| Residential 85 15 - 25 100 - 110 200 Comm./Inst. 83 15 - 25 98 - 108 203 Genl. Ind. 41 15 - 25 56 - 66 121 Cement 30-50 (1) 15 - 25 45 - 75 92 Power (2) 38 15 - 25 53 - 63 79 Fertilizer (3) 17 15 - 25 32 - 42 30 (1) Varies depending on location. (2) Generated in Buenos Aires area. (3) Located in Neuquen area. (4) Based on minimum reserves, 504.6 billion CM, depletion allowance is estiamted to be S251MCM; based on higher reserves of 585 billion CM, the depletion allowance is estimated to be S15IHCM (see table 7.5). 7.19 If the reserve base is expanded to meet the Scenario B development program, the resource base would have to be increased to 754.5 billion CM, and the netback value would then exceed the economic cost for all applications. This indicates that if an expanded exploration effort is undertaken, it is better to use the available natural gas for all applications than to use an alternative fuel. - 109 - F. THE ADEQUACY OF NATURAL GAS FOR POWER GENERATION 7.20 During 1987, 3,203 MHCM of natural gas (22Z of GdE's sales) were used to generate electricity. Because of limitations on delivery capacity to the Buenos Aires region, the power plants were forced to burn fuel oil for part of the year. With the completion and commissioning of the NEUBA II pipeline from the Neuquen region, it was anticipated that natural gas consumption by the power plants would increase rapidly during 1988, but then fluctuAte over the next 10 years, as new hydroelectric plants are brought on-stream and the existing natural gas-fired thermal stations are retired or relegated to intermediate or peak-load service. The Secretary of Energy estimates that about. 75 billion CM of natural gas will be consumed during the 1989-2000 period in existing thermal stations, and in those that are scheduled to come on-stream in the 1990s. Although much of the thermal station capacity is old and will have completed its economic life by the year 2000, the units scheduled to begin operation in the 1990s will still have an economic life of 15-25 years by the year 2000. One thermal station (Bahia Blanca, with two units) is scheduled to come on- stream by 1993. A second station, with two units, may come on-stream after 1997. If these stations, with an aggregate capacity of 1,240 MW, operate at an average load factor of 502--reflecting some service as intermediate and peak load units--for an average of 20 years after 2000, they will require 30 billion CM of natural gas to realize their full economic potential, assuming no fuel oil is burned. The units will have the dual capability of burning either natural gas or fuel oil, so they could be fired with fuel oil if gas is not available but at some additional cost. Based on the projection of gas use through the year 2000, a 10-year phaseout of the pre-1990 stations and the operation of the three new stations installed by 1993 for their full economic life would require about 130 billion CM. 7.21 Natural gas use in other sectors of the economy is projected to grow at an annual rate of 42 through the year 2000. It is projected that 204 billion CM will be consumed during the 1989-2000 period. Even if further growth were to stop, an additional 100 to '.50 billion CM of natural gas would be required by existing customers over the remaining economic life of appliances and equipment (average remairing life, 5 to 10 years). Under these conditions it is likely that a demand management program would be instituted under which some natural gas would continue to be available for highest value uses (e.g., residential consumption), but lower value uses would be curtailed. 7.22 Thus, if non-power consumption grows at current projected rates, the proved natural gas reserves will be adequate to fuel all of the thermal stations projected to be built through 1997 for their full economic life. 7.23 To estimate the maximum requirements for gas used for power generation, a maximum gas use scenario was assumed. Under this scenario all new power plants required until the year 2010, except the hydroelectric plants already committed, would be gas-fueled. The thermal stations would require 293 MMCM through the year 2010 and an additional 207 MMCM for the remaining economic life of the stations, which would still be operating in the year 2010. Other sectors of the economy would require approximately 500 K(CM; so the total requirement under the maximum gas use scenario would - 110 - be almost 1000 MMCM. This exceeds the most optimistic projection of the natural gas resource base; therefore, it is unlikely that there would be sufficient natural gas to fuel all of the projected growth in the power sector and still meet the requirements for other uses. G. NATURAL GAS IMPORTS 7.24 Argentina is a net importer of natural gas. Since 1972, Bolivian natural gas has been delivered at the border to GdE for processing and tranport via the Northwest Pipeline. In 1987, these deliveries averaged 5.8 million cubic meters per day, and comprised approximately 152 of all- natural gas sold by GdE. Although the Bolivian contract will expire in April 1992, discussions between the countries have been underway for two years to consider options for its extension. The original contract linked the border price of natural gas to crude oil prices, but when world prices rose rapidly in 1980/81, the price of natural gas also increased rapidly, becoming much higher than the producer transfer price received by YPr. The price is now negotiated annually and has declined. In 1986, the average price was US$148 per thousand CM (equivalent to US$4.20 per MCF), but in 1987, the price had declined to US$108 per thousand CM (US$3.07 per MCF). Nevertheless, it is still much higher than the transfer price that YPF receives for natural gas produced in Argentina. Through bilateral agreements, a portion of this cost is paid in countertrade with Argentine goods and services. 7.25 Although negotiations continue, it is still not clear whether the contract will be renewed in 1992. Bolivia depends heavily on natural gas exports as a source of foreign exchange revenue, but under the current contract terms, the income will be reduced compared ta earlier years. Other options include local use to replace exportable liquid products or through exports to Brazil or Chile. A natural gas development program is underway, but it will be several years before it has a noticeable impact on the exports of liquid products. The Bolivian Government is currently considering a proposal to build a pipeline to the Brazilian border, where they will sell to Brazil electricity and petrochemicals produced from natural gas. This project will also require several years to develop and, at best, could not begin to generate significant revenues before the mid- 1990s. Therefore, it is likely that the Bolivian Government will be willing to extend the Argentine export contract on reasonable price terms. In view of the uncertainties surrounding the long-term availability of natural gas from the Neuquen and the northwest regions, the Argentine Government should continue negotiations with a view to possibly extending this contract to gain the time required for developing additional reserves within the country. The pricing formula would probably establish a border price more in line with the economic cost of producing gas in Argentina. H. NATURAL GAS EXPORTS 7.26 Several proposals have been made to export natural gas from Argentina to neighboring countries. Studies have been carried out for a project to deliver natural gas from the Mendoza region to consumers in Santiago, Chile, and to industrial consumers located along the pipeline route from the border crossing at Paso Maipu to Santiago. The plan - ill - currently under review would require a 16-inch diameter pipeline to deliver up to 600 million cubic meters of natural gas annually. This is a relatively small volume, but it would require dedicating 10-12 billion CM of natural gas, 22 of known reserves, for the project. A larger export project to sell natural gas at the Brazilian border is under consideration. At one time it was proposed that 3-4 billion CM be exported annually, but these plans have been scaled back. This project would provide a source of revenue and a base load for the proposed pipeline to supply natural gas to the provinces located in northeastern Argentina. This would serve both a social and economiic purpose of distributing the mineral resources throughout the country. The Brazilian Gasplan Study, completed in December 1988, considered the benefits of importing Argentine gas, but concluded that the delivered price would be significantly higher than the current price of alternative fuels. A project similar to that proposed between Bolivia and Brazil might be feasible. A pipeline connecting the existing trunklines with an industrial complex at the border could supply natural gas for power generation and fertilizers or other derivative products for markets in the border region. Such a project might require 3-6 million CM per day, a volume roughly equivalent to Bolivian imports, and require dedication of about 10? of proved reserves. It also has been proposed that natural gas be exported to Uruguay. A 40-km underwater pipeline would be built from near Buenos Aires to the Uruguay shoreline and then overland to Montevideo. The total market would' be small, about 800 million CM per year, but about 32 of the nation's known reserves would have to be committed to the project. 7.27 As long as Argentina imports natural gas from Bolivia to meet a significant portion of its requirements, it may be difficult to justify exports. This is especially true until the long-term availability of natural gas reserves above the national needs is confirmed. In the case of all three export projects now being considered, natural gas will primarily substitute for heavy fuel oil. Until fuel oil prices increase markedly, it may be difficult to negotiate a border price for natural gas that covers the economic cost, including a depletion allowance. The buyer vho must make a significant investment in pipelines (e.g., Chile) will insist on a long-term supply contract and probably reouire that adequate reserves be explicitly dedicated to their project. None of the proposed export projects would impose a limit on near-term gas availability--although the Brazil project might require expansion of the trunklines--but they would reduce availability over the long term. Discussions should be continued with potential buyers of Argentine gas; however, the national long-term supply base should be assured before long-term export commitments are made. The border price should recover the full economic cost of natural gas production plus transportation costs and a reasonable depletion allowance. I. LPG SUPPLY AND MARKETING 7.28 LPG (propane and butane) is widely used as a hou'ehold fuel in Argentina. The LPG sold in the warmer climates consists primarily of butane, while the LPG sold in the south contains a higher proportion of propane. In 1987, sales totalled 919,665 tons, equivalent to approximately 52 of the natural gas sold. The Government is encouraging consumers to switch from LPG to natural gas, but LPG use is expected to grow in regions where natural gas is not available. As LPG production increases in line - 112 - with rising natural gas production, and existing LPG customers switch to natural gas, it is anticipated that Argentina will become a net exporter of LPG in the 1990s. 7.29 LPG is also produced in refineries as well as being extracted from natural gas. In 1987, 352 of the total volume of LPG was produced in refineries. YPF was the principal supplier of refinery produced LPG, but private companies produced about 152 of the total. YPP also operates five natural gas extraction plants that pr(duced a total of 233,000 tons of LPG in 1987. The extraction plants operated by GDE produce more than 502 of the total supply. 7.30 Argentina is currently a net importer of LPG. In 1986, 44,000 tons were imported from Brazil, and in 1987, 83,000 tons were imported from the Middle East; however, it now appears that the 1987 imports were not required and may be reexported in 1989. Very small quantities of LPG were exported to Paraguay in 1987. Overall, there is no consistent pattern for LPG exports. 7.31 LPG supply and demand are now nearly in balance, and GDE projects that demand in its historic markets will grow only 1? per year. If the new extraction plant at Loma la Lata comes on-stream as projected and the refinery production is maintained, thete will be a surplus of LPG in the early 1990s. As shown in Table 7.7, the surplus could exceed 500,000 tons per year in 1995. However, it appears that most of the surplus will be propane and the additional butane will be required for local markets. (LPG production by source is shown in Annex 7.3.) Table 7.7: LPG SUPPLY/DEMAND BALANCE Thousand Tons GdE Other Total Demand Balance Year 1990 640.0 350.0 990.0 806.9 183.1 1991 619.0 350.0 969.0 817.2 151.8 1992 731.2 350.0 1081.2 825.7 255.5 1993 940.3 350.0 1290.3 831.4 458.9 1994 938.3 350.0 1288.3 843.9 444.4 1995 1023.3 350.0 1373.3 855.5 517.8 J. SUMMARY OF K.EY CONCLUSIONS ON GAS UTILIZATION 7.32 Based on the foregoing analysis of the natural gas subsector, the economic cost of producing and delivering natural gas to consumers, plus a depletion allowance to replace the exhaustible resource, is significantly less than the netback value of gas used by residential, commercial, and general industry consumers. The economic cost is marginally less than its netback value for power generation and cement manufacture, but the margin could be reduced or eliminated if the price of - 113 - the alternative fuels were to change. The generalized analysis indicates the economic cost exceeds the netback value of natural gas used to produce fertilizers or methanol, and therefore such uses should be carefully evaluated to assure they are economically justified. An accelerated program to develop additional natural gas resources will have a positive benefit on the national economy. 7.33 The financial cost of producing natural gas, including payment of royalties based on the market value of the natural gas, payment of VAT and income taxes, as well as a reasonable return on investments in natural gas exploration and production, is less than the internationally-based price of substitute liquid products. This indicates that an appropriate pricing structure based on the international value of the fuels that natural gas would replace (therefore linked to fuel oil, which is the marginal fuel most likely to be displaced by natural gas), would generate sufficient revenue to attract additional investments in natural gas exploration and development. 7.34 The urgent need for an accelerated exploration and development program is clearly shown by the trend in R/P ratio. In 1987, the minimum proved reserves were 504.6 billion CM and the R/P ratio in Argentina was 20 years, comforta''y above the critical level of 15 years. However, if no additional natural gas reserves are developed and consumption grows, as projected under the Medium Demand scenario, the R/P ratio would be 15 years by 1994. If the high-growth scenario were followed, the critical ratio could be reached as early as 1913. Even if a substantial exploration program is undertaken immediately, and all of the probable and possible reserves are actually discovered, the critical RIP ratio will be reached by the year 2002. Natural gas can play an increasing role in the energy economy aftet the year 2000, but only if an aggressive exploration program is undertaken as quickly as possible. 7.35 Natural gas use for power generation is projected to increase as new thermal stations come on-stream in the 1990s. Current plans call for installation of 1,240 MW of thermal capacity before the year 2000. The minimum reserves will be adequate to meet the projected demand for non- power uses, and also provide sufficient natural gas to fuel all the existing thermal stations and the new plants to be installed through the year 2000 for their full economic life. However, hydroelectric stations will also be required. If ail new generating capacity required through the year 2010 were gae-.' ed, consumption including other uses would exceed the estimated known, probable, and posoible natural gas reserves. 7.36 Preliminary analyses have indicated that natural gas is and will continue to be an economic source of energy for the Argentine economy well into the twenty-first century, but only if an aggressive exploration and development program is undertaken. Even so, results are preliminary and additional analyses will be required to define the specific plans to be implemented. These should include: (a) A detailed survey of the geological and economic characteristics of the prospective basins such as the deep Neuquen formations, the Northwest Basin and the Austral offshore formations. - 114 - (b) An independent, detailed study of natural gas demand that takes into account the economic costs and benefits of the use of natural gas in each market sector. (c) A cost of service and tariff study to establish the long-run marginal cost of producing, transporting, and distributing natural gas to end-users. (d) An analysis of the institutional structure required to regulate gas distribution companies as public utilities. This may require new legislation and will certainly require preparation of a natural gas code for economic regulation and tariff-setting. (e) A review of pricing options for natural gas and NGLs used in the petrochemical sector, including a review of the existing standards for setting international prices, freight rates, and competitive petrochemical feedstock prices that need to be updated, and similarly, the basis for applying the corresponding discount coefficient should be clarified. (f) A modified pricing structure for petrochemical feedstocks should be evaluated and adequate contract negotiating guidelines developed. U~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ - 115 - CHAPTER VIII POWER SECTOR A. BACKGROUND 8.1 From the mid-1960s to the mid-1980s Argentina enjoyed reliable and extended electricity service, provided initially by private companies and increasingly by the national utility companies. In the last 16 years the country has increased its total installed capacity at a rate of 6.42 p.a., developing a large National Interconnected System (NIS) that supplies about 902 of the public electricity services. Currently, about 952 of the urban population and about 502 of the rural population ha&e access to electricity. However, the sector faces important problems arising from: (i) an inadequate legallinstitutional framework; (ii) lack of consistent planning; (iii) deterioration of generation and distribution facilities caused by low investment levels and poor operating and maintenance practices; and (iv) a weak financial system burdened by a heavy foreign debt and a low level of internal cash generation, mainly due to rate levels not reflecting actual costs. The economic difficulties now faced by the country call for an increased effort to conduct power activities efficiently and economically, thus reducing the sector's dependence on Government support. To achieve this objective, corrective measures should be promptly taken to: (i) improve sector organization; (ii) ensure that sector expansion follows principles of economy and efficiency; (iii) improve the operational efficiency of facilities; (iv) promote energy conservation, and reduce technical losses and electricity theft; and (v) reduce the level of investments and improve sector finances. 8.2 Bank lending in the sector has encouraged the Government to carry out a program of reforms to address the main sector issues including: (i) a study of sector organization and efficiency of public utilities, expected to provide recommendations to improve the institutional structure (underway); (ii) SE commitment to adhere to least-cost principles in updating the expansion plan: (iii) SE, SEGBA and AyE preparation of a program for the rehabilitation of thermal facilities, (iv) implementation of a program by SEGBA, the largest national utility, to reduce losses and electricity theft; and (v) Government initiation of a Financial Rehabilitation Program (FRP) to recover sector financial health. The following paragraphs provide an overview and recommendations regarding ways to address issues not fully covered in the existing Bank/Government agreements, and analyze activities being addressed in current Bank lending efforts. B. THE ELECTRIC POWER MARKET Demand Growth 8.3 Electricity demand in Argentina traditionally has grown at a high rate with current per capita consumption representing one of the highest in the region. Total consumption grew at a rate of 8 p.a between 1960-70 and - 116 - 6.12 p.a. between 1970-80. The growth rates slowed to 2.8Z between 1980-84 and consumption even decreased by 2.22 in 1985, reflecting the countri's economic difficulties. Consumption growth increased again to about 7.42 p.a. between 1985-87, despite little or no improvement of the economy. As with global energy consumption, electricity consumption has not kept pace with economic growth; i.e., between 1970-87 per capita electricity consumption grew 1.6 times, while per capita GDP in constant terms has decreased. Demand Projections Methodology 8.4 Sector demand projections are prepared under responsibility of the SE in the framework of the overall energy planning by an ad hoc workirg group that includes representatives from the SE as well as the major electricity companies. This encourages an open exchange of views about methodology, the interpretation of data trends, the adoption of criteria and parameters, and also eontribute to consensus building. Projections are updated annually during the second quarter of the year on the basis of the previous year's actual consumption. 8.5 The working group uses an econometric model applied to each class of consumers: residential, commercial, industrial, Government, ar.d others. For the residential sector, projections are based on a correlation between consumption per household and rer capita GDP growth, changes of the electricity prices, and a variable that captures "autonomous" or unexplained growth. To obtain total consumption, the number of households is estimated on the basis of population growth and projections of the number of persons per household plus electricity coverage. Commercial sector projections are based on a model using as explanatory variables the commercial component of GDP and commercial elactricity prices. For the industrial sector, heavy industry is treated separately, with projections based on the expected increase in demand determined for each major consumer on the basis of expansion plans, while light and miscellaneous industries are correlated to manufacturing GDP and industrial electricity price. Finally demand projections for others e.g., Government, transportation, irrigation--are based on simple extrapolation of previous trends. 8.6 Through projections by class of consumers are adequate, the above methodology contains some weaknesses that need to be remedied to improve results. The model does not include changes in the pattern of fuel consumption and interfuel changes. Moreover, no verification is possible for global energy consumption. Given the inherent lack of precision of any demand forecasting method, it would be advisable to focus demand projections on the preparation of a few alternative feasible scenarios of which the most likely one would be selected for expansion planning. Section that leave room for improvement are discussed below: 8.7 Residential sector: (i) Electricity demand is projected without due consideration to possible substitution due to interfuel price differences. Even though substitution of electricity used for producing heat is limited (since in Argentina heat for residential use is generally - 117 - produced by burning gas), it may be appropriate to check total energy consumption. (ii, The information used in the model (population, per capita consumption, GDP, prices) has a high degree of aggregation, which might mask significant differences in regional patterns that would be useful to identify in the preparation of a more detailed model after carefully checking basic data for consistency. (iii) The price elasticity data were obtained from an external source and their validity should be reviewed. 8.8 Commercial sector: (i) The price elasticity should be reviewed, as data came from an external source. (ii) The high value attributed to the autonomous growth (4.42 p.a.) reduces the validity of the explanatory variables in accounting for most of the sector growth (6.1X p.a.). 8.9 Industrial sector: (i) Fuel and gas p-ices are not included among the explanatory variables, which eliminates the possibility of representing price substitution in the model. (ii) Use of price elasticity values from a separate source reduces the validity of model conclusions. (iii) The use of an "autonomous" component has no analytical justification while it appears .o account for a substantial proportion of sector growth. Given the importance of industrial coisumption in total electricity consumption, an attempt should be made to construct a more detailed model that represents consumption by regions and by activity to capture differences in the production processes and locations. 8.10 In summary, there should be a thorough revision of projection methodologies. It is recommended that the SE take this responsibility by carrying out a study, with support from external consultants. A report to be given to SE contains detailed recommendations on revisions to the forecast model and draft Terms of Reference for a new, more rigorous study. Current Demand Projections 8.11 Annex 8.1 presents the demand projections prepared by the SE, which provide the basis for defining sector expansion plans. Public service energy consumption increases are projected at 6.22 p.a. between 1988-2000, based on a 4.9Z p.a. gruwth in the residential sector, 6.22 p.a. in the commercial sector, 7.92 p.a. in the industrial sector, and 5.22 p.a. for oti.er classes of consumers. These projections are based on the current methodology using the following assumptionst (i) GDP growth of 3.52 p.a. for 1990 and 42 p.a. thereafter; (ii) industrial value-added growth of 4X in 1988, 42 in 1989, 52 in 1990 and 62 p.a. thereafter; (iii) commercial GDP growth of 2.72 p.a. until 1989 and 3.6S p.a. thereafter; ('v) population growth of 1.32? p.a. until 2000; (v) increases in electricity coverage from the current 852 to 902 in 2000, with the number of persons per household decreasing from the current 4.4 to 4.0 by 2000; and (vi) consumption of large industrial consumers to grow from 3,387 GWh per year in 1985 to 4,351 GWh per year by 2000; (vii) price elasticities of -0.19 for residential consumption, -0.42 for commercial consumption, and -0.11 for industrial consumption. - 118 - 8.12 The above growth rates seem high sincet (i) The demand methodology gives considerable weight to "autonomous, growth, so that, on the basis of historical data it well could be forecasting high electricity consumption growth despite low economic growth. (ii) Forecast of economic parameters seems overly optimistic given the current stagnation of the economy and the dim prospectu of a strong recovery in the medium term. (iii) The projection of electricity coverage is not empirically justified, and the same is true for the projections of the number of persons by household. (iv) The demand projection of the major industrial asers. which represents about 202 of the total industrial consumption (.LUAR, HIDASAM, ACINDARI Agua Pesada, and SIDESUR) is based on expansion plans of the corresponding industries, which might not materialize due to lack of marketing or financing. Alternative Demand Scenarios 8.13 Alternative demand scenarios were prepared to aissess the possible impact of a more likely demand growth on sector investment requirements, assuming GDP growth rates lower than that adopted by thc SE, while leaving all other assumptions unchanged. Since no alternative methodology was available, the exercise made use of the sector model, despite the limitations already noted. Assumptions of the two alternative scenarios tested and results (presented in detail in Annex 8.2 and 8.3) are shown below in summary form as compared to the base case (Case 1) developed by the SE: Assumptions Results (1988-2000) (Average Demand Growth) Case 1. GDP growth 1989 ... 3.5Z p.a. 1990-2000 ... 4Z p.a. 6.2Z p.a. Case 2. GDP growth 1989-1994 ... 22 p.a. 1995-1996 ... 32 p.a. 1996-2000 ... 42 p.a. 5.32 p.a. Ca_;e 3. GDP growth 1989-2000 ... 22 p.a. 4.62 p.a. 8.14 Annex 8.4 and graph 8.1 show the three demand scenarios developed for this exercise. Energy demand for scenario 3 by 2000 would be 172 lower than scenario 1 and would probably permit the postponement of all generation expansion and associated transmission works for about three years. Graph 8.1 shows that a moderate demand scenario or most-likely scenario (5.32 p.a. average growth) is not far away from the historic tendency of the demand variations; thus, moderate price adjustments and other conservation measures would probably keep demand following this GRAPm 8. 1 ARGENTINA - ENERGY SECTOR STUDY- POWER THREE SCDEARIOS FOR ELECIRICrlY OEMAND 90I 70 - 0 6 - 50 -…--- 1 0 ---… 1.97 1.g74 1.978 1.982 1.986 1.99 1.994 1.998 (Thousands) R D HIGl ME 0 LO - 120 - trend. It is recommended that this demand scenario be adopted for planning purposes, through given the serious economic crisis that currently affects the country, a lower demand growth (like case 3 with 4.6Z p.a. demand increase) is not unlikely, at least in the short-term. C. SECTOR DEVELOPMENT PLAN Development Planning Procedures 8.15 Generation and transmission planning is the responsibility of the SE, which updates the planning studies every two years. Generation expansion is based on the interactive use of three mathematical models: (i) an investment selection model based on linear programming that defines the optitmm configuration of the system over three-year periods within the planning horizon; (ii) a simulation model that defines more precisely (year-by-year) when additional generation is required; and (iii) a reliability model that verifies whether the system configuration obtained through the operation of the two previous models meet agreed reliability standards. Transmission expansion is defined on the basis of state-of-the- art, conventional studies done with the assistance of foreign consultants. Distribution expansion planning is the responsibility of each distribution utility. 8.16 The methodologies currently used by the SE for defining least-cost generation alternatives are generally sound. However, the SE should carry out methodological research in two important areas: (i) the need to give more weight to uncersiinties and risk factors in the planning process; and (ii) the severity of the recent drought calls for a careful review of supply security criteria and of the reliability model. 8.17 Studies were performed by a few highly specialized, high-level staff with very little technical support. The planning team at the SE should receive support from consultants and should be reinforced wit.:, additional engineers and economists and provided with adequate technology (computer and office equipment). This could be achieved through the technical assistance component the Bank currently is financing under the Power Sector I project. 8.18 Expansion plans already implemented by the sector sometimes have departed from the least-cost iolution becauset (i) special projects have been imposed (see para. 8.33 on the nuclear option) while valid options have not been considered, i.e., comb_ned cycle plants, rehabilitation of existing thermal plants; and (ii) the sector has chosen inappropriate economic parameters i.e., a 8X p.a. discount rate. These plans have resulted in sector commitments for nuclear and hydro projects that require a high level of investments, while underestimating the potential contribution of natural gas expected to be available in the country if adequate exploration and development efforts are made. In the framework of Bank lending for power, the SE has agreed to adhere to least-cost - 121 - principles under a 122 p.a. discount rate. (Under the current scarcity of capital resources this figure may be still low). Additionally, the SE has initiated a study on generation options to: (i) evaluate the operating conditions of existing thermal plants and prepare feasibility studies for rehabilitating some of the units that have deteriorated; and (ii) examine the merits of introducing the combined cycle alternative in future generation expansion plans. These are positive steps towards a more economic development of the sector, which would may result in the switching of the first in line hydroprojects to gas fueled thermal projects. Current Expansion Plan 8.19 Most of the projects to be completed in the next few years correspond to works located in the NIS. The generation projects and associated transmission systems originated in expansion plans prepared in the 19709 on the basis of optimistic demand growth expectations (9.4Z p.a. average between 1978-1980) and a low assumed opportunity cost of capital (82 p.a.). The completion of such projects in a time frame compatible with the revised demand projections constitutes the main sector priority. These projects are: (i) the 2,700 MW binational Yacyreta hydroproject, expected to initiate generation in 1993 and be completed by 1997; (ii) HIDRONOR's 1,400 MW Piedra del Aguila, to be completed in 1991-1992; (iii) DEBA's 620 MW Piedrabuena steam thermal plant to be completed in 1990; and (iv) CNEA's 695 MW Atucha II nuclear plant, which has been approved and is being constructed outside the power sector, scheduled for completion by 1994. Also under the current SE's demand scenario, (6.2 p.a. demand growth), the following additional generation capacity is to be committed: (i) two 320 MW steam thermal plants to be located close to Buenos Aires, which should be commissioned in 1993; (ii) AyE's 325 MW Los Blancos hydroproject, located in the Cuyo area and required to shore up local generation in the Cuyo subsystem by 1996; (iii) two 325 MW steam thermal plants to be commissioned, one in the Buenos Aires area in 1999 and the other one in the Litoral area in 2000; and (iv) the following hydroprojects for 1997 and beyond: Carrenleufu, 240 MW, 1997; Cordon del Plata, 850 MW, 1998; Garabi, 790 MW, 1999; Los Blancos II, 40 MW, 1999; Collon Cura, 380 MW, 1999; El. Chihuido, 565 MW, 2000. Investment Reauirements 8.20 In accordance with current SE expansion plan, in the short term, the projected level of investment is high, since priority is put on investments that would secure completion of ongoing works. In the medium term, sector investments would still remain high due to planned additional generation works. The bulk of investments would be for generation plants. As shown in Annex 10.5, the investment requirements of the sector for generation (AyE, EBY and HIDRONOR) between 1989-2000 would amount to about US$6,625 million. This figure does not include: ti) investments for completion of the Atucha II nuclear plant; (ii) transmission works associated with generation plants; and (iii) investments in distribution expansion (e.g., SEGBA's budget for transmission and distribution expansion between 1989-1995 is about US$1,000 million). - 122 - Plans Under the Most-Likely Scenario 8.21 Currently, the sector still might be planning for a demand scenario that is too high. The generation expansion needs under the most- likely demand scenario could result in substantially lower financial requirements. Under this scenario (4.6Z p.a. average demand growth between 1988-2000), energy requirements would be substantially lower, and consequently, projects could be delayed. Assuming that a revised least- cost expansion plan would select the same sequence of projects as under the current SE's scenario, a preliminary estimate made for this report shows that such projects not yet committed could be delayed from four to six years, as shown below in Table 8.1. Because of the dynamic nature of electricity planning it would be necessary to follow closely the evolution on the demand and eventually take corrective actions through short time gestation options to adapt the expansion plan should the demand grew at a higher than the expected pace. Table 8.1: Revised Commissioning Scenario Relative to Expansion Plans Project Name Capacity(MW) Commui,sioning Date Current Revised Yacyreta 2700 1993-1997 1993-1997 Piedra del Aguila 1400 1992 1992 Piedrabuena 620 1990 1990 Atucha II 695 1994 1994 Steam Plants First Unit 300 1993 1999 Second Unit 300 1993 1999 Third Unit 300 1999 2003 Fourth Unit 300 2000 2004 Los Blancos 325 1996 1999 Carrenleufu 240 1997 2001 Cordon del Plata 850 1998 2002 Garabi 790 1999 2003 Los Blancos II 40 1999 2003 Collon Cura 380 1999 2003 Chihuido 565 1999 2004 8.22 As a result of these delays in project implementation, capital expenditures to be incurred in by AyE, HIDRONOR and SEGBA between 1989-1996 could be reduced from US$7,236 million to about US$5,052 million, as shown in Table 8.2 (and Annex 8.5). System operation simulation studies done recently by the SE show that under the 4.62 p.a. demand growth scenario - 123 - would be also lower than those of the 6.2Z p.a. demand growth scenario as thermal generation in the period 1990-1996 would be lower. The corresponding yearly average decrease in thermal generation is estimated at 4,150 Gwh, and the corresponding decrease in operating costs is estimated at US$130 millionlyear in the eame period. 8.23 Additional postponement of investments could be obtained from the postponement of distribution networks. Projects for rehabilitating part of the existing thermal facilities which are currently been evaluated by the SE also could contribute to reducing the need for investments in generation, as unit cost of rehabilitation is usually a fraction of the installation cost of a new plant and they would be good candidates to be selected in an optimization process. 8.24 Under a low demand scenario (2-32 p.a. demand growth), generation works currently under construction (Yacyreta, Piedra del Aguila, Piedrabuena, and Atucha II) could be delayed by two years without jeopardizing the power supply. These delays, however, would increase the final cost of the projects and the operiting cost of the system; thus, any decision to delay these projects should be preceded by an evaluation of its economic and financial implications. 8.25 In retrospect, it is clear that some of the decisions taken in the past for investment selection were wrong because assumptions made regarding the future evolution of some of the planning parameters did not materialize. The precarious financial situation of the sector and the difficulties that the country is encountering in obtaining external financing call for the need to develop robust expansion plans based on the most-likely demand scenario (4.6Z p.a. average growth). Within least cost principles, these plans should consider financial restrictions--through appropriate values of the opportunity cost of capital--and minimize the potential risks associated with unforeseen change£ in the planning parameters. D. GENERATION DEVELOPMENT OPTIONS Hydroprojects 8.26 Hydropower potential is estimated at 44,000 KW, or about four times the country's total installed capacity. For the preparation of the 1986 National Energy Plan, the most promising projects were identified, which totalled 35 projects with a total capacity of about 22,000 MW. Generating costs of these projects at project site were estimated in the range between US$18-77 mills/kWh at 1986 price levels and 8.0Z p.a. discount rate. Generating costs for half of the projects were estimated to be below US$30 mills/kWh. Though efforts were made to take into account uncertainties associated with the various projects, the above figures should be viewed with caution, since they seem too low when compared with actual costs of projects recently implemented or expected actual costs of - 124 - Table 8.2 Neatelnll Uf-i reentet d t ed ScenrIo (1) laesw_^ ii ft i row% * (in LOS million; Price Lev*lD Oecemr 1%8 19"9 1i90 i9 iwS iws 199" 1i8 lo9 Total A.- High OseA Scenario A;wm anal-i 198.7 88l.0 879.2 486.6 447.2 86O.0 0.8 2.1 1 3d.6 HNiranor 380.9 45.6 M6.8 147.2 116.2 188 277.9 0 1.8 1916.2 So= I6.8 260.7 264.8 200.6 182.8 176.2 176.l 12. 1887.6 Total 688 1 10225. 947.0 606.4 747.6 897.7 1186.8 1001.7 728.6- 6.- Last-ikely O_eand Scenrie A" ay energia 198.7 880.0 808.2 310 . 241.9 260.7 5O1.8 270.0226.9 Hidroor 802.9 428.8 O 188.8 147.2 90.6 8X.0 38.6 21.0 1818.6 6815= 188.8 220.7 254.8 200.6 182.5 178.2 176.0 15.1 1497.8 Total 618.1 979.8 661.0 844.6 823.2 471.9 498.2 421.9 S082.2 C.- Difference A- 0.0 48.0 106.0 141.8 24.6 425.9 668.8 S79.9 2164.4 __ ~~~~~~~~~- - -- - - - - - - -----_,*,, (1) Injveatmenta for AuE. 41AGI and SE066 only. LUt of Project. Avg Scenario A Ongog V.Mr 17.2 2zi.0 84.1 48.8 48.7 48.7 48.7 48.7 710.6 Pier Plants 1fdro 8.0 76.0 141.6 206.1 818.2 42.? 46.8 1t6. Thermi 12.U 7.8 0.0 0.0 19.6 Traneiaeion Work, 11.8 69.7 196.6 28.8 187.4 20.1 22.4 417.0 16.9 Other. 13.0 13.0 13.0 13.0 18.0 13.0 12.0 13.0 104.0 Scenrio 6 Ongeing Work. 171.2 2o8 0 86.1 48.8 48.7 48.7 48.7 48.7 710.6 Power Plant. bdro 0.0 0.0 0.0 0.0 81.8 67.1 120.2 225.7 Thcml 12.8 7.8 10.8 Tranmiesicn Wor" 11.8 o9.7 148.6 266.8 188.2 172.8 218.0 6u.9 1189.7 Others 18.0 18.0 13.0 18.0 13.0 13.0 18.0 18.0 104.0 HIURONORt Scenario A OIo; no Works 267.7 361.1 178.0 88.6 29.6 16.9 13.8 18.8 971.8 Nydree lent. Pichi-PMcun-Leufu 1i.1 39.6 94.8 68.0 s8.9 14.8 28.3 9.6 319.3 Colton Cure 10.4 29.6 82.6 7S.2 168.6 michihus 9.0 68.1 121.1 198.1 Trnastemiion Sytem 7.6 18.7 r .8 10.2 7.2 67.6 1.4 256.8 Scenario a Ongoing Wor. 287.7 381.1 178.0 8.8 29.6 16.9 18.8 18.8 971.6 Mydrog lent. Pichi-Picun-Lrqfu 18.1 39.8 94.8 68.0 86.9 14.6 28.8 9.6 819.8 Col ton Cure 0.0 Michih.,o 0.0 Traneico;rn Syates 7.6 18.7 27.8 10.2 1.4 82.8 Scenario A Ongoing Wel, 100.9 22. 1.2 124.6 Theral Grnertion 81.9 146.7 181.3 2t.2 16.8 18.0 12.4 12.4 890.2 Tranra.ieion 2.8 22.4 48.8 61.8 88.7 29.0 80.4 12.0 242.6 Dlstributien 21.2 63.0 80.7 94.0 108.6 112.8 114.9 92.7 682.9 Others 80 28.6 19.2 28.9 2S.4 19.2 10.2 127.4 Scenarlo a Ongoing Work. 100.9 22.8 1.2 u4.6 Theral Genration 81.9 106.7 101.8 18.2 16.8 18.0 12.4 12.4 10.2 trdanieiol - 2.5 22.4 48.S 81.8 9 t.1 29.0 80.4 12.6 242.6 Distr;hution 21.2 68.0 i0.7 94.0 10t.6 122.8 114.9 92.7 662 60 25.6 19.2 28.9 28.4 19.2 10.2 12.4 - 125 - projects under construction; these are rather in the range of US$40-55 mills/kWh. Annex 8.6 shows estimated costs of selected projects that appear in the current expansion plan. The only project on this list which has a firm cost estimate--since it is in the final design stage--is Pichi Picun Leufu; the others need further engineering studies. Before implementing any of these projects, an effort should be made to assess their costs on the basis of more complete estimates. Planning under the most-likely demand scenario will not require committing new hydropower before the year 1995 if then--except possibly for the small Los Blancos project, which could be required to firm up local generation in the Cuyo area. This would provide enough time for a better definition of these projects. Such review would probably result in the identification of a few, less expensive projects in the range of US$600-1,200/kW for installed capacity and US$35-50 mills/kWh for generation. Gas Fueled Thermal Plants 8.27 Currently, the SE is considering steam plants and gas turbines as the only valid options for new gas-burning thermal generation. It has been reluctant to consider CC technology as a valid option for baseload generation, probably because of the negative experience AyE has had with a small (80 MW) plant it installed in 1987. CC plants, which make use of a gas turbine's waste Leat, currently achieve efficiency levels of 47Z (compared with 382 for modern steam plants) and have capital expenditures in the range of US$600-700/kW (compared with about US$1,000 kW for steam plants). These plants incorporate factory assembled, modular components, including advanced gas turbines, and have implementation times shorter than steam plants. Recent technological improvements also have resulted in good reliability. Given the availability of gas for power generation, the CC option is now a proven technology, is highly competitive with other thermal and hydro options, and should be seriously considered for baseload generation. Use of Coal for Power Generation 8.28 Although imported coal, in principle, could be considered an alternative fuel for power generation, the actual possibilities of its use are limited because of its price (about US$1.7-2/million BTU), which probably would not be lower than the netback value of natural gas, after making allowances for differences in burning efficiency. 8.29 While Argentina has sizeable reserves of medium quality coal, the use of coal produced by YCF in Rio Turbio for power generation is limited by high production costs, the distorted fuel price system, and lack of demand. Apart from the 70-80,000 tons sold annually to the steel industry, the only current client for Rio Turbio is AyE, which burns coal in its fifth steam thermal unit at San Nicolas. That unit can consume the current level of production of 400-500,000 tons per year, although a dedicated mine-consumer arrangement may pose potential problems for the producer in - 126 - case of a prolonged outage of the unit, and for the client--in case of production disruptions like the one that occurred in 1988. The other two potential clients for Rio Turbio are: (i) SEGBA, ihich has two small units able to burn coal in Buenos Aires, but in practice has discontinued use of coal because of high costs, contamination, and the union's resistance; and (ii) DEBA, whose two 310 MW units at Bahia Blanca (the Piedrabuena project) would be able to burn 1 to 1.5 million tons per year. 8.30 The current production cost of YCF, including transpert costs, is extremely high (about US$140/ton) compared to international coal prices, which would probably be below US$50 per ton C.I.F. to power plants. While past administrations of YCF have not promoted efficiency, the blame for its poor operating results cannot be totally put on YCF, since the Government has burdened the company with the responsibility of providing infrastructure and social services to Santa Cruz Province. Prices charged to AyE, (US$40) are arbitrarily set by the SE without consideration of the relative prices of alternative fuels--gas and fuel oil--or the international prices. Under these circumstances, AYE reluctantly burns its quota, which in fact corresponds to whatever YCP can produce after discounting sales to the steel clients. 8.31 YCF is promoting implementation of an Expansion Project for its Rio Turbio mine, which through an investment estimated at about US$250 million in the period 1989-93 would expand production capacity to 2 million tons per year while reducing unit production cost to about US$50/ton. The project is based on a restructuring plan that includes: (i) divesting the company of all non-mining operations, i.e., railroad and shipping transportation systems, social services provided to the Santa Cruz province, operation of the power plant, and forestry cultures; (ii) reducing the company's staff from 3,360 to 1,200; and (iii) expanding the mining operations to reduce production costs. YCF has prepared a pre- feasibility study along these lines, which conclusions cannot be confirmed until a full feasibility report is prepared. The economic merits of the expansion project are questionable. Even assuming that the political environment would permit implementing measures (i) and (ii), and the feasibility study shows that expansion is an economically viable alternative for which investment financing is found, the fundamental issue of the market for the increased level of production still would need to be addressed. YCF's expansion project is based on the assumption that the DEBA's two Piedrabuena units would burn coal. Though these units could burn coal, DEBA has not considered this possibility because: (i) to do so, substantial investments (estimated at about US$50 million) in port facilities at Bahia Blanca would have to be made, which DEBA is not in a position to finance; and (ii) DEBA has no financial incentive to burn coal, since alternative fuels are priced lower by the SE. 8.32 Consideration should be given to closing the Rio Turbio mine's operations. Before YCF'S operations can be considered feasible, fuel prices to the power utilities should be based on economic costs; if subsidies cannot be avoided, a uniform level of subsidy for all fuels - 127 - should be set based on net heat content. The feasibility study should be carried out by independent foreign consultants. Once production costs and potential markets are clearly defined, the actual possibilities of an expanded market for coal should be established based on long-term 'zntracts with the corresponding utilities that Would clarify the options for future operation of the mine. The Nuclear Option 8.33 Argentina has developed the largest nuclear power program in South America. Currently, CNEA has two nuclear power plants in operation with an installed capacity of 1,018 MW (Atucha I, 370 MW and Embalse, 648 MW) and a third plant under construction (Atucha II, 745 MW). A fourth 600 MW nuclear plant has been planned for the year 2000 under an initial agreement with a foreign supplier, and a fifth 600 MW plant is planned for the year 2003. All these plants reflect energy decisions taken outside the power sector. It is likely that the nuclear option would not be selected in a true optimization process. Thus, the two additional 600 MW nuclear plants currently included in the sector expansion plan for the years 2000 and 2003 should be eliminated from the sector expansion plan. Rehabilitation of Thermal Plants 8.34 About 1,350 MW in steam thermal plants are scheduled for decommissioning between 1993-2000 because of the reaching of their useful life. Additionally, a number of plants whose aggregate capacity is about 2,030 MW are deteriorated and have low reliability due to unsatisfactory maintenance. Rehabilitation of existing thermal plants is another option that could provide a quick, less-expensive alternative to adding new capacity, and for that reason should also be considered by the sector. According to preliminary estimates, the cost of rehabilitating an existing thermal plant would be in the range of US$200-350/kW. The SE has begun an extensive review of this option through the preparation of a feasibility study which is reviewing the possible rehabilitation of about 20 plants with aggregate capacity of about 3,400 MW. It is expected that this study will provide an adequate basis for properly evaluating this option. Currently the first results of the study have permitted to start rehabilitation of five units with a total capacity of 600 MW. Private Sector Participation in Power Generation 8.35 Participation of private initiatives in power supply has practically disappeared in Argentina as a result of Government policies. Because of the current crisis in the power sector the government is giving, consideration should be given to a substantial change in such policies. There are good prospects for increasing the presence of the private sector if adequate regulations are established to provide long-term assurances to prospective investors about preservation of their capital in real terms and their ability to earn a reasonable return. Currently there is no sound - 128 - environment to attract private enterprises to the power sector, since no basic principles for return on investments are recognized. The review of sector legislation and organization being conducted by the SE should consider, on a priority basis, the analysis of reforms that would permit a meaningful participation of private ventures in the power sector. 8.36 Generation of power is a promising area for independent suppliers. The availability of gas at low economic cost provides a unique opportunity for competitive proposals from qualified private investors to provide the necessary financing and build and efficiently operate thermal generation facilities independent of the volatility of fuel costs. Potential investors in generation capacity would receive compensation for fuel costs, which would be priced as the economic cost of gas, plus operating costs and a reasonable return on investment. Appropriate incentives would be required to ensure efficiency. Consideration should also be given to the participation of the private sector in distribution, as there are a large number of small distribution companies suited to run efficiently in private hands. Finally, the option of selling securities of the national utilities either internationally or locally in the form of bonds and equity or semi- equity papers should also be considered. Table 8.3 - GENERATION OPTION COST COMPARISON Generation Installation Plant Production Option Cost Factor 1/ Cost (US$/KW) (Z) (USS mills/KWh) Hydroprojects 600-1200 50-75 35-50 Gas Turbines 350 20-50 60-40 Combined Cycle 600-700 40-80 46-31 Steam Plants 1000 60-80 49-42 Nuclear 3700 70-80 140-123 1/ A measure of the energy output in relation to the plant capacity. 100Z plant factor would indicate that the plant runs at full capacity all the time. International Interconnections 8.37 International interconnections is the other area that should be further explored. Economic benefits of interconnections are well known: (i) savings in capital expenditures for lower reserve margins: (ii) savings in operating costs for better use of energy resources in daily operations; and (iii) lower economic losses based on reductions in energy losses due to reliability improvement. Argentina is currently interconnected to Uruguay through the Salto Grande project, which played an important role in reducing the energy deficits during the recent energy crisis. The Uruguay - 129 - system, however, is small when compared to Argentina'p and its support capacity is limited. Interconnection with Brazil wou'd represent important benefits for both countries and is being studied in connection with the construction of the Garabi hydroproject, a binational venture. The Garabi project, however, currently planned for the year 1999, is likely to be substantially delayed under the most-likely demand scenario, especially if appropriate consideration is given to the CC option. Another option that could be explored is a possible interconnection of the NIS at Yacyreta with the 12,000 MW Itaipu Brazil/Paraguay binational project. Access of Argentina to energy from Itaipu is not permitted by the Brazil/Paraguay international treaty that made possible the implementation of Itaipu; thus, an amendment to the treaty would be required. A possible interconnection with Chile has been studied for many years, as the predominantly Chilean hydro system and the diversity of hydrological conditions would result in economic benefits for both systems and merits further consideration. Summary of Generation Options 8.38 Table 8.3 shows a very rough comparison of capital expenditures and costs of energy production for the various generation options, assuming the fuel would be gas at an economic price of US$2.23/MHBTU (as estimated in Annex 7.2) and plant sizes of 300 MW for conventional thermal and 1,000 MW for nuclear. E. OPERATIONAL ISSUES Existing Facilities 8.39 Most of the country's power facilities are installed in the SIN. The total installed capacity of the SIN by end 1987 was 12,802 MW of which 5,960 MW (462) was hydro, 5,824 MW (462) conventional thermal, and 1,018 MW (8X) nuclear. A 500-kV transmission system links the major consumption areas with the production centers and is used for the transfer of large blocks of energy. A network of 230 kV lines completes the grid and permits energy transfers between production and load centers. Annex 8.7 shows data on the installed capacity of the different utilities by type of generation and the energy generated in 1987. Operational Performance 8.40 The main sector concern regarding facility operations is the high degree of deterioration reached by thermal generation plants, which has reduced their availability. Annex 8.8 shows the age of different installations. Of the about 4,500 MW installed in steam plants in the NIS, which are expected to provide baseload during dry hydro conditions, only about 232 is newer than 15 years and 282 is between 15 and 25 years old. (The date of installation for the remaining 162 is not available.) Thus, a substantial part of the baseload generation facilities is obsolete - 130 _ and other part requires extensive, costly maintenance. Because of the obsolescence of thermal installations, many of these plants should be decommissioned in the near future (see Annex 8.9). The annual combined unavailability level of power plants of AyE, DEBA, EPEC, and SEGBA has increased dramatically from 17Z in 1982 to 36Z in 1988 (see Annex 8.10). These indexes are abnormally high and are the result of the previous insufficient level of expenditures in maintenance and renovation and unsatisfactory maintenance practices. A sustained effort of coordinated actions is needed to recover availability and reliability of these facilities; some actions are already being taken by sector authorities, while others are in various stages of study. 8.41 Availability of thermal plants assumed for planning purposes is low (i.e., 5,500 hours/year for steam plants). Future assumptions regarding availability and reliability of thermal plants should be based on international standards and reflect improved maintenance schedules. Electricity Losses. 8.42 The level of distribution losses is high for SEGBA and may be as high for other utilities. In SEGBA's system, the high level of technical losses and electricity theft is a cause of concern, which brought about a Loss Reduction Program, agreed between SEGBA and the Bank in Loan 2854-AR. At appraisal, it was estimated that losses could be reduced from 212 to 132 by 1992. These reductions have not taken place; instead, total losses currently run at 22Z. The estimated value of the foregone earnings for SEGBA is US$30 million a year. A similar evaluation is still to be made for other distribution systems. Reduction of losses and suppression of fraud at the national level should greatly reduce demand and improve sector earnings, and thus should be a sector priority. The Energy Crisis 8.43 The energy shortage that has taken place since mid-1988 (and has yet to be overcome) has spread the perception that insufficient investments were made in generation. Under ordinary circumstances, it is likely that the current installed capacity would have sufficed to provide adequate energy. The energy shortage is the result of a combination of a severe drought and the failure of a nuclear plant, compounded by the poor status of a substantial part of the thermal installations. The increased pressure on the generation output from the existing thermal facilities is likely to continue during early and mid 1990, when availability of gas for power generation usually reaches its lowest level. To avoid severe fuel shortages logistical planning for fuel supplies should be done, since a substantial amount of fuel oil will have to be imported. The SE, YPF, and the utilities concerned should establish a working group to review and analyze the demand/supply for fuel-oil for power generation, including the financial implications for the power and oil sectors, and to present to the SE a supply plan for 1990. Energy Conservation and Cogeneration 8.44 Electricity consumption in Argentina has grown at a much faster pace than the economy. Between 1977-87 the average GDP growth was - 131 - practically zero while electricity production expanded 472. This suggests energy waste. Apart from emergency measures taken as result of the energy shortage in 1988/1989, there are no comprehensive, systematic policies for promoting conservation. The Department of Conservation of Energy and New Energy Sources (DCE), which is a part of SE, is in charge of defining policies and action plans to promote conservation. T"is department is responsible for planning and coordination of all activities related to corservation, substitution, and investigation of new sources. Activities of this entity are supported by a Presidential Decree (Number 2247, dated Noeember 1985) that provides authority and funds; however, it will expire by end 1989. 'While the SE is trying to promote conservation through an appropriate, correct price structure, the DCE has done research in the following complementary areas: (i) preparation of energy audits for industries; (ii) possible energy savings in transport; (iii) improvement of architecture and construction methods for energy efficiency irs buildings and dwellings; and (iv) training programs and international agreements with related organizations. Concrete results of these activities have been limited mainly due to a lack of financial support and specialized staff. 8.45 The Argentine Association for Rational Use of Energy (Asociacion Argentina para el Uso kacional de la Energia - AAPURE), a non-profit organization, has been active in the last few years in promoting energy conservation through the organization of seminars and the execution of studies for concerned industries. AAPURE is promoting the enactment of specific legislation to enforce energy conservation. A draft bill has been sent to Congress for consideration ('Proyecto de Ley sobre Uso Racional de la Energia"). The bill proposes policies to: (i) promote the use of renewable forms of energy; (ii) promote conservation; and (iii) reduce contamination resulting from the use of different forms of energy. Although legal support would be desirable, the enacting of a law would not suffice to produce the desired results. The proposed law is too general and gives total responsibility for application and funding to the SE, which has no staff budget to apply these policies. Actually, the current responsibilities of the SE provide for application of conservation policies; hence, perhaps the law is not necessary for a more effective role, since under the current legislation the SE could play a meaningful role in conservation if it had more human and fiscal resources. 8.46 The realization of a reduced demand growth, in addition to the adoption of appropriate pricing policies, will require the execution by the Government of a clear and systematic conservation policy that should be developed and enforced by the SE. Cogeneration with industrial projects is also a potential field for energy savings and could be explored by the SE if measures are taken to increase coordination between the energy and industrial sectors. Environmental Aspects 8.47 The SE has also taken responsibility for environmental protection with regard to power projects. Large hlydroprojects, such as Yacyreta and Piedra del Aguila, have been object of an in-depth evaluation of their potential impact on the environment before proceeding with their construction. In the case of Yacyreta, for example, the studies covered - 132 - aspects related with protection of aquatic fauna and flora, water quality, protection of endangered species, control of possible waterborne diseases, forestry, and archaeology. A large component of the project is addressed to minimize the effects on the displaced population. On the basis of experience gained in these projects, the SE recently has issued guidelines for environmental assessment of hydroproject, which execution constitutes, in accordance with a presidential decree, a prerequisite for the approval of any new plant. These guidelines have been reviewed by the Bank and been found sound. The SE is currently preparing similar guidelines for the assessment of environmental impact of thermal power plants. F. POWER SECTOR FINANCES 8.48 Over the past several years the power sector has had to bear the impact of changing economic policies and the burden of an investment program decided at a time when growth demand expectations were higher and external financing assumed to be readily available. During 1976-82, the sector incurred a high level of external indebtedness to a large degree prompted by the Government, which was financing a substantial portion of its foreign currency needs. The major devaluation of local currency that followed placed a heavy debt service burden on the power sector and caused a major deterioration in its financial structure, which has been somewhat corrected by the refinancing of the sector's debt. However, since 1986, the decline in the value of the dollar, to which the austral is pegged, is again causing problems because of its effect on the sector's investment and debt service programs, which have significant components of Japanese and European hard currencies. 8.49 Power sector financial requirements in the last several years have been large. The power sector (excluding Yacyreta) had operating losses in each of the four years, 1985-1988: US$ Millions 1985 1986 1987 1988 Operating Loss 286 165 379 152 Capital investment in the period was financed through the Electricity Fund and the Energy Fund, but these were insufficient in 1985 and the imbalance had to be covered by loans. US$ Millions 1985 1986 1987 1988 Capital Investment 377 330 367 450 Financed by: Electricity Fund 66 82 96 98 Energy Fund 245 271 287 365 Subtotal 311 353 383 463 Loans 66 - - - Investment in Yacyreta in 1987 and 1988 was US$306 million and US$730 million, respectively. Only US$96 million came from the Energy Fund in _ 133 - 1987 and US$247 million in 1988. The difference was made up from equity contributions (US$50 million in 1987 and US$173 million in 1988) and foreign loans. In addition to a cronically low tariff level. the financing terms for long-gestation hydroprojects has had an important impact on sector finances. In particular, grace periods are generally only about one-half of the construction period and the amortization period tends to be only about one-third of the depreciation period. 8.50 The recent economic difficulties also resulted in a deterioration of financial discipline among public sector entities. Arrears for the purchase of electricity by nacional, provincial and municipal agencies and by autonomous agencies have mounted. As of December 31, 1987, the balance of accounts receivable from electricity consumers of the three federally- owned utilities was as follows (in US$ million)s No. of Of Which: Of Which: Utility Days Balance Overdue Public Sector 1/ AyE 167 223.2 184.4 134.4 HIDRONOR 96 31.1 12.4 12.0 SEGBA 63 107.4 48.7 28.2 1/ Excludes debt from other national utilities As can be seen from the above table, the public sector had overdue accounts to the power sector of about US$175 million. 8.51 Argentina's recent economic difficulties may have been a contributing factor to the increase in electricity theft, which accounts to a great degree for the increase in distribution losses that has been taking place since 1981. The financial problems of the power sector itself, however, were also an important contributing factor for the increase in distribution losses, since they resulted in curtailment of expenditures in network expansion and maintenance. 8.52 In March 1986, the Federal Government prepared a program to address the various financial problems faced by the sector. The key aspects of this program were: (a) To increase the internal cash generation of the sector; (b) To reach a prudent mix of self-financing and external borrowings; and (c) To review annually the five-year financial targets for the federal utilities for the following year. 8.53 Based on the policies outlined above to face the new realities, in late 1987 the Government began preparation of a Financial Rehabilitation Plan (VRP) meant to reverse the dismal financial situation of the national - 134 - utilities that at present have negative rates of return and are significantly dependent on Government contributions. The FRP relates to the group of national utilities (AyE, SEGBA and HIDRONOR) representing about 602 of sector operations. The basic principles for the preparation of the FRP -ere as follows: (a) Each utility and the consolidated grout of national utilities would show clear improvement trends as measured by the cash operating ratio (cash operating expenses as a percentage of revenues) and by the contribution to investment from non-borrowed sources, all within a reasonable level of indebtedness; (b) The required overall tariff increases would be made in a phased manner consistent with the stabilization program; (c) The financial situation among utilities would be balanced fairly; (d) The investment program for each utility would be strictly in line with the least-cost expansion of the sector agreed with the Bank, and; (e) The working capital needs would reflect sound practices of power utility financial management, especially regarding collection and payment periods. 8.54 As of December 1989, new financial projections were being developed by SE. (Previous flow of fund projections are given in Annex 10.7). 8.55 The FRP was based on a set of assumptions that take into account the limitations imposed by the stabilization program on: (i) rate increases and the corresponding availability of Electricity and Energy Funds; (ii) Government contributions, to be used mainly for debt-service payments; and (ili) borrowings committed for ongoing projects to be committed to finance the foreign cost component for future projects. The resulting cash operating ratio (cash operating expenses as a percentage of operating revenues) would have a steady and positive trend. The FRP showed in its funding mix that the internal fund generation of the national utilities would increase steadily and with the contribution of electricity and energy funds would show a healthy contribution to investment. 8.56 Execution of the FRP has faced serious difficulties. Despite substantial price increases in nominal terms applied by the Government to electricity rates, under the macroeconomic environment characterized by high inflation, it has been very difficult to increase electricity rates in real terms. Additionally, the severe drought that affected the country for two consecutive years caused substantial increases in operating costs. As a result, the above targets could not be reached in 1988 or 1989. The Government should define path which will allow the financial recovery of the sector. - 135 - CHAPTER IX ENERGY DEMAND A. INTRODUCTION 9.1 Energy consumption growth in ArgentJna has been unusually high compared to other countries of similar GDP level and structure. During the last 25 years, energy consumption has consistently outstripped the GDP growth rate. Income elasticity of final demand was 1.5 in the 1960. and 1.2 in the 19708. For the 1980-85 period, GDP fell about 1.5 percent per year, whereas statistics show a stationary final consumption. Energy consumption per capita of 10 bbl of oil equivalent per year is now almost double that of neighboring Chile and Uruguay, which have a similar GDP structure and GNP per capita. Energy efficiency measures haze not been promoted to a degree comparable to that experienced by developed countries. This primarily has been the result of the energy pricing policy, which has in most cases insulated domestic consumers from the impact of high energy prices during the 1973-85 period. Also, conservation is not encouraged by energy pricing that is determined through a complex system of administered prices not linked to international levels or long-run marginal costs. 9.2 The major issues of energy demand are clearly linked to urgently needed reforms of energy pricing policy (discussed in detail in earlier chapters). For this reason--as well as limitations on up-to-date data regarding energy demand and energy balances--this study has not attempted to make detailed new projections of integrated energy supply and demand balance forecasts. The analysis in this chapter is limited to a diagnostic evaluation of 1986 Energy Plan demand and projections. A summary of energy balances from the 1986 Energy Plan are in Annexes 9.1 through 9.5 for the years 1984, 1986, 1990, 1995, and 2000. These balances provide a good foundation for analyses at past aad future energy demand; however, it is important that these be updated and projections made for many alternative sets of investment and policy scenarios. Annex 9.5 provides a comparison of household energy demand and expenditure. B. PAST ENERGY DEMAND Sectoral Energy Demand 9.3 From 1970 to 1986 the share of consumption of energy in the residential/public and agricultural sectors increased while industrial and transport shares decreased. The residential/public energy consumption share increased from 20t in 1970 to 262 in 1986, and the share from agriculture increased from 3.7Z in 1970 to 5.2? in 1986. - 136 - 9.4 During the period 1970 to 1986, energy demand increased 1.95Z per year while GDP grew 1.22Z per year, or an elasticity of 1.55--which is very high by international standards. The level of energy consumption in the residential sector increased 3.62 per year while real household GNP increased 0.82 per year from 1970 to 1986. Industrial energ' consumption increased 0.82 per year while real industrial GDP increased 0.52S per year. Transport sector energy consumption increased 1.52 per year on average while transport GDP increased 1.402 per year. Agricultural sector demand increased 42 per year while agricultural GDP increased 1.862 per year. Structure of Energy Demand 9.5 There have been important structural changes in the use of energy resources. Natural gas has replaced heavy and middle distillates in the power and industry sector, and has replaced LPG and kerosene in the residential, commercial, and public sector. As a result, the share of gas in final consumption has increased from 32 in 1960 to about 272 in 1985. During the sane period the share of electricity in final energy consumption more than doubled to a share of almost 112 in 1985. The penetration of electricity has occurred mostly in industry and the public sector. 9.6 No major changes in consumption patterns have occurred in the transport and agricultural sector. In transport, about half the demand is met by gasoline and the other half by diesel. Fuel oil consumption (mainly in shipping) decreased to about 42 of total energy consumption in the sector compared to 302 in 1960. It is also important to note the success of compressed natural gas (CNG), which is expected to replace about 0.7 MMTOE of gasoline by the end of the century. The agricultural sector continues to consume almost exclusively middle distillates, which account for 982 of energy used in this sector. 9.7 The transport sector now clearly drives the demand for petroleum products (more than 602 of final petroleum products demand in 1985). Economy-wide demand for petroleum products will further shift towards gasoline and automotive diesel as fuel oil, kerosene, and industrial diesel are replaced by gas and primary electricity. C. ENERGY PRICE AND INCOME ELASTICITIES OF DEMAND 9.8 A relatively thorough analysis of energy price and income elasticities has been recently completed. This analysis used annual and quarterly data in certain cases to estimate short- and long-run price and income elasticity estimates. Table 9.1 gives a summary of elasticities. As can be seen, there are significantly large price elasticities for most fuels, particularly gasoline. Although not as large, there are significant price elasticities for electricity and for natural gas. This level indicates that there will be a moderate effect on demand, and significant revenue increases if these prices are adjusted upward. Clearly more work is required to focus on cross-price elasticities and interrelationship of prices, as price policies for residential natural gas, LPG, and residential electricity need to be coordinated and prices increased together in a rational way. - 137 - Effect of Price Changes on Energy Demand 9.9 In Chapter IV, numerous recommendations were made on changes in the system of energy pricing. Some rough estimates have been made of percentage changes from prices, including taxes (from prices of a level in place during the fourth quarter 1988), to economic prices including new recommended tax structure. While price increases should be phased in and lifeline rates established, it is useful to estimate the demand impact in the medium-term (five years) of moving prices to economic levels (including new suggested taxes). Table 9.2 shows the effect of price changes. If the Scenario One price changes are made, there will be final demand savings estimated at 1.75 million TOE equal to US$208 million per year. If prices slip 302 in real terms, as in Scenario Two, the extra cost to the economy would be US$560 million per year. Table 9.1: SUMMARY OF ELASTICITIES OF PRICE AND INCOME FOR ENERGY SOURCES Price Elasticity Incom Elssttcity Adjusted Incoa Short-run Long-run Short-run Long-run R2 Measure Gase, Ii I e -Regular -0.220 -1.86 0.115 0.65 0.94 GDP per Cap -Pr_mlum -0.100 -0.60 0.237 1.45 0.92 GDP per Cap Ke rose-0.243 -1.62 0.067 0.42 0.91 GDP per Cap LPG -0.070 -0.12 0.842 0.60 0.66 GoP per Cap Fuel Oil -0.884 -0.77 0.46e 0.91 0.8 Ind. GDP Gas Oil -0.07 -0.47 0.88 2.75 0.98 Tranep. GDP DieseI Oil -0.807 */d 0.417 - 0.64 -- Natural Oas 1/ -Industrial -0.176 -0.28 0.882 0.6 0.66 Ind. GDP Natural 0a" -Residential -0 I to -0.21 to 0.474 .066 0.99 OP per Cop -0.214 -0.89 Electriecity -Residential -0.046 to -0.074 to 0.270 0.48 0.66 GOP per Cap -0.9 -0.19 2/ -Industrial -0.160 0.422/ to 0.68 0.440 1.6 0.98 Ind. ODP NJ Note: Cross-price elasticity with price of fuel oil Is 0.42 short-run, and 0-89 long-run. / Estimates used In electrietty demand projection model at SE. Source: sEERAL de Is Fundaclon Meditorranes, regression on annual data. - 138 - Table 9.2: APPROXIMATE LONG-RUN EFFECT OF PRICE CHANGES ON ENERGY DEMAND Differenc. beftwen Scenario One Scenario Two Sc.lUSc.2 Long-run Percent Percent Hypothetical Percent Percent Price Price Increases Change In Reduction Change Change Elasticity Require to Demand In all Prices in Demand In Move to by Box Omand Eeonomic Prices _ _------ Gasl ine -Regular -1.88 -16 +19 -80 41 22 -Premium -0.6 -18 +7 -80 15 8 Keroren -1.52 -6 .9 -80 45 so Gasoil -0.47 a -4 -80 14 18 Diesl -0.8 18 -10 -80 24 84 Fuel Oil -.77 24 -18 -80 28 41 LPG -0.12 29 -8 -80 4 7 Natural Gas -Residential 1/ -0.21 sa -18 -80 6 24 -Industrial 2/ -0.2 27 -6 -80 7 18 Electricity -Residential 1/ -0.19 9S -19 -80 6 25 -Industrial 2/ -0.56 12 -7 -80 17 24 1/ Estimt of price elasticity very from -0.1 to -0.2 short-run and -0.2 to -0.87 long-run, since there I a significant cross price elasticity with LPG (and LPG prices are assured to Increase the -0.2 elasticity ts use as an approximatlon. 2/ Thore Is a significant cross price elasticity with fuel oll 0.42 short-run, 0.89 long-run. 9.10 Energy Demand Forecasts. Oil and gas account for about 50 percent and 30 percent, respectively, of gross energy consumed in Argentina. Demand forecasts indicate that, under a wide range of assumptions, they will continue to play a major role in the energy sector. Estimates indicate their shares will be about 43 percent and 33 percent, respectively, in the year 2000. This means that (i) oil and gas will continue to supply more than three-quarters of all gross energy consumed in Argentina, and (ii) natural gas will become more important relative to oil. 9.11 The Government completed the Energy Plan in 1986, which emphasizes three objectives: (i) to increase the contribution of gas and hydro resources to the country's energy supply; (ii) to increase oil exploration efforts to improve the reserve-production ratio; and (iii) to correct pricing distortions and foster conservation and substitution. Specifically, the Energy Plan projects that Argentina should maintain its energy independence through the year 2000 by increasing the shares of gas and hydroelectricity in the country's energy balance (gas: from 25 percent in 1985 to 36 percent in 2000; hydro: from 11 percent in 1983 to 15 percent in 2000), thereby reducing oil's share from 47 percent to 37 percent. The Energy Plan has been a valuable planning tool but requires review and continuous updating to ensure cost-effectivs and balanced use of subsequent resources on a regular basis. - 139 - 9.12 Under the Energy Plan, the Planning Srbsecretariat (SPE) within the Energy Secretariat together with specialists from energy sector enterprises projected demand and supply until the end of the century. The creation of the Plan is a major and very positive accomplishment. However, the 1986 figures still provide the bases for planning and have not yet been updated. Also, the sectoral demand projections are of uneven quality due to the lack of an adequate data base, especially for the industrial sector, which represents almost 302 of final consumption. 9.13 In general, simple econometric time-lag functions have been used to estimate demand for the following sectors: (i) residential, commercial and public; (ii) industry; (iii) transport; (iv) agriculture; and (v) petrochemical and other. SPE projected final teergy demand to increase 4.72 a year between 1986-90 and 3.2Z a year thereafter based on GDP increasing at 32 a year until 1990 and 42 a year thereafter. Supply requirements and investments were determined under the National Energy Plan using these demand projections. 9.14 It is useful to consider alternatives with lower demand scenarios based on lower economic growth, possible saturation effects, and effects of possible energy price increases to better capture the range of possible developments. Table 9.3 shows a comparison of demand projections from the 1986 energy plan with a lower energy demand projection based on a lower average GDP growth of 22 p.a. (instead of 42 a year under the Energy Plan). The low-demand scenario includes the low electricity demand projections (from Chapter VIII) and low gas demand assumptions. Prices are generally assumed to be held constant in real terms at fourth quarter 1988 levels. It does, however, assume additional gas will be discovered to meet increasing demand. As can be seen, lower economic growth results in total final energy demand being 122 lower and primary energy demand about 172 lower than the higher GDP growth case. As described earlier, substantial permanent real price increases could reduce demand significantly (9-122) and specific energy conservation investments could provide additional energy savings. 9.15 This analysis points to the need for more detailed new studies of energy demand and supply projections that account for differences in GDP growth, differences in price levels, interfuel substitution, and energy conservation programs. - 140 - Table 9.3: COMPARISON OF DEMAND PROJ 'TIONS (SPE - Energy Plan Projection, and Alternative Low Demand Projection prepared by the Bank) (a) Growth in percent per year 1990-2000 SPE Low GDP 4.0 2.0 Energy Elasticity 0.8 0.96 Final Energy Demand 3.2 1.92 - Electricity 6.2 4.5 - Natural Gas 4.0 4.0 - Gasoline 1.2 1.6 - Middle Distillate 3.0 2.0 - Fuel Oil (1.7) (0.7) (b) Final and Primary Energy Demand (MHTOE) 1985 1990 2000 SPE Low SPE Low Final Energy Demand 29.6 36.3 33.1 49.7 43.7 - Electricity 3.3 4.2 4.1 7.8 6.6 - Natural Gas 7.4 12.0 11.2 17.8 15.3 - Gasoline 5.1 4.8 4.1 5.4 4.8 - Middle Distillation 7.3 8.8 7.5 11.8 9.1 - Fuel Oil 1.6 1.2 1.4 1.1 1.6 Primary Energy Demand 45.0 53.4 46.4 71.4 58.4 - Crude Oil 22.9 22.0 21.8 26.5 23.5 - Natural Gas 14.8 24.0 18.3 31.9 23.4 - Hydro & Nuclear 3.5 3.5 3.5 8.9 6.5 - 141 - CHAPTER X INTEGRATED FINANCES IN THE ENERGY SECTOR 10.1 This chapter describes the financial projections for 1989-1995 for YPF, GdE, state power companies, and EBY, which implies a continuation of pricing, tax and investments policies, and plans as of first quarter 1989. The projections do not reflect the World Bank's viewpoint. They are based on data presented to IBRD by YPF, GdE, and the state power companies during the preparation of this report (details are given in Annexes 10.1-10.7). Neither do the projections reflect urgently needed reforms in the structure and cross-subsidization of the sector. Events subsequent to the March 1989 mission may have made some of the ddta obsolete with revisions required, and references to 1989 data in the report and in Annexes 10.1-10.7 are preliminary figures. New integrated projections have not yet been obtained from the newly elected government. The financial projections are followed by a summary of the potential impact of pricing policy changes, recommended changes in taxation, and alternative investment plans to illustrate potential magnitude of the changes. Projections of Financial Performance of the Energy Sector 1989-1995 10.2 Based on the continuation of the present pricing policies and projected investment levels--assuming dollar inflation of 52 annually, and that electricity tariffs and prices of crude oil, petroleum products, and natural gas are kept constant in December 1988 dollars--the energy sector is expected to have a positive aggregate operating income in the period 1989-1995 amounting to almost US$55 billion (Annex 10.1). However, after the deduction of multiple surcharges, taxes, royalties, contributions to special sector funds, and interest payments, this operating income is reduced to US$11 billion. Depreciation of US$12 billion reduces the cumulative income for the sector to a net loss of US$1.2 billion in thej period (see table 10.1). Table 10.1: FINANCIAL PERFORMANCE PROJECTIONS 1989-95 Federal YPF GdE Pow.Cos. EBY Totals Gross Income 60626 12302 17417 1163 91508 Less: Operating Expenses -23738 -7607 -7703 -50 -39098 Operating Income 36888 4695 9714 1113 52410 Less: Non-Operating Expenses -29807 -1966 -7619 -2321 -41713 Income/kLoss> Before Depreciation 7081 2720 2095 -1208 10697 Depreciation -7214 -2102 -2231 -377 -11924 Net Income/ -133 627 -136 -1585 -1227 Most of the loss stems from Yacyreta, where huge loan repayments fall due as soon as the corporation begins to generate electricity. 10.3 Balance Sheet Projections. A distinct improvement is projected through 1995 in the performance indicators for the consolidated sector as follows (Annex 10.4): - 142 - 1987 1988 1992 1995 (actual) (actual) (projected) (projected) Consolidated Energy Sector Rate of Return 162 222 33X 38Z Operating Ratios 0.56 0.49 0.40 0.33 Long-Term Debt/Equity Ratio 0.42 0.49 0.40 0.32 Current Ratio 0.72 0.76 1.23 1.31 Quick Ratio 0.45 0.55 1.00 1.1 Individual performances by YPP, GdE, and the consolidated power sector is projected as followss 1987 actual YPF GdE Power Sector Rate of Return 422 72 7Z Operating Ratios 0.41 0.78 0.61 Long-Term Debt/Equity Ratio 0.49 0.60 0.40 Current Ratio 0.92 0.59 0.66 Quick Ratio 0.68 0.35 0.48 1992 (Projected) YPF GdE Power Sector Rate of Return 682 202 122 Operating Ratios 0.36 0.60 0.42 Long-Term Debt/Equity Ratio 0.34 0.75 0.44 Current Ratio 1.90 0.86 0.65 Quick Ratio 1.54 0.66 0.49 1995 (Projected) YPF GdE Power Sector Rate of Return 111% 242 12? Operating Ratios 0.29 0.58 0.34 l.ong-Term Debt/Equity Ratio 0.24 0.41 0.38 Current Ratio 1.98 1.00 0.68 Quick Ratio 1.64 0.78 0.57 - 143 - 10.4 These tables show that YPF turns in the best financial performance until the myriad non-operating costs are incurred. The power sector out- performs GdE until 1993, when Yacyreta comes on-stream and the huge Investment In the project is capitalized, leading to a very poor rate of return and poor current ratio. Prolects Source and Use of Funds 10.5 The projected source and use of funds for the consolidated energy sector in the period 1989-1995 indicates an aggregate deficit of US$627 million (see Annex 10.6). Table 10.2s PROJECTED SOURCE AND USE OF FUNDS, 1989-95 Consolidated Energy Sector Source (US$ millions) Net income 30,543 Depreciation 11,924 Long Term Loans 3,291 Energy Fund 4,033 Electricity Fund 794 Refinancing COMGASCO 441 Equity Contributions 2,758 TOTAL 53,784 - 144 - Consolidated Energ Sector Use (US$ mllions) Increase/(Decrease) Working Capital -73 Increase Other Assets 1.760 Loan Principal Repayments 5,750 Loan Interest Payments 9,621 Royalties 2,285 Fuel Tax/Capital Tax/Income Tax 18,849 Investment 16,281 TOTAL 54,471 10.6 The projected deficit of US$687 million over the seven-year perLod is less than 42 of the aggregate investment, which would normally not be cause for concern. However, this deficit could increase considerably If tariffs do not keep pace with the devaluation of the austral and the sector is unable to finance the US$15.4 billion of debt servlce over the next seven years. The projections on investment ln oll and gas production, according to YPF figures, are estimated to generate oil production at about 25.3 million cubic meters for 1993. Thls production level ls slightly below the energy plan projection and between the Minimum and Maximum Cases (Chapter V). The Minimum Case scenario is the projected productlon by YPF based on a continuation of investment levels YPF has actually achieved ln recent years. Benefits of Improved Investment, Pricing, and Tax Policies 10.7 Although detailed projections of the Lmpact of new pricing policies are not possible within the scope of this study, some rough indications of the size of the adjustments and benefits are possible. First (as described in detail in Chapter IV), about US$1,650 million per year is possible given a reduction in subsidies. changes in tax-r. anO. increases in prices of gas. electricity. and LPG. Savings from reduc.ed demand would gross about US$200 million per year after a few years. In addition, if private sector investment in oil and gas exploration and production can be used to increase the US$3,770 million (Mlnimum Supply Case exploration and development investment) to US$7,156 million (Maximum Supply Case) for the period 1989-1995, the incremental net benefits would be very large, about US$1.7 billion over the period and up to US$10,266 million in net benefits from 1989 through 2000. - 145 108 For the power sector (see Chapter VIII), based on the expansion plan, under the most-likely demand scenario will reduce investment requirements from US$4,213 million to US$3,080 million between 1989 and 1995. Improved efficiency and loss reduction in refining and the power sector imply potentala benefits of US$150-$250 million per year. In total fiscal benefits, the finances of the energy sector could potentially be lmproved by US$10-12 billion over the next seven years.