Report No. 7993-AR Argentina Energy Sector Study (In Two Volumes) Volume II: Annexes February 26, 1990 Infrastructure and Energy Operations Country Department IV Latin America and Caribbean Regional Office FOR OFFICIAL USE ONLY ; . 1 Document~~~~~~ of thoodBn C) . h m a a pnly X, bedisclosed/withoutWor[dBankauthorization.-- Domn o h ordBn 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ / FOR OMCUAL USE ONLY ANNUES Annex 1.0: Official and Adjusted Hydrocarbon Reserves Annex 1.1: Institutional Structure of the Hydrocarbon Subsector Annex 2.Os 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 r'-e.em Annex 3.4: Example of Subsidies and ristortions in the Hydrocarbon Subsector Annex 4.0: Implementation of Deregulation of Crude Oil and Oil Products Prices Annex 4.1: Controlled Transition to a NPv Natural Gas Pricing System Annex 4.2t Reforming Institutional Arrangements on Gas Production and Transmission Annex 4.3: Cost Based Tariffs for Tranesission and Distribution Annex 4.4: Netback to Producers from Reformed Pricing System Annex 5.1: YPF and Service Contracts Annex 5.2: History of Wells Drilled (1977-1988) Annex .3t Crude Oil Production History & Refinery Runs (1977-1988) Annex 5.4: Natural Gas Production & Utilization History (1977-1988) Annex 5.5: Production Operating Costs of YPF Administration - Oil & Gas Annex 5.6: Incremental Prod. Costs Annex 5.7s Incremental Net Income Annex 5.8: Investment Requirements for the Next Five Years Annex 5.9: Hydrocarbon Deregulation Decrees 1055, 1212 and 1589 (all issued fourth quarter 1989; Annex 6.1: Evaluation of YPF snd Private Refinery Capacity Annex 6.2: Inefficiencies in Present Refinery Operations Annex 7.1: Average Incremental Cost Calculation for Gas Annex 7.2(a)t Netback Value Calculations for Gas Amnex 7.2(b)s Petrochemical Sector Annex 7.3: LPG Production by Source Annex 7.4: Methodolgy for Calculating Financial Costs Annex 8.1: SE's Ene jy Plan Electricity Demand Scenario Annex 8.2: Most-Likely Electricity Demand Scenario Annex 8.3: Low Electr.,zity Demand Scenario Annex 8.4: Electricity Demand Projection - Three Scenarios Annex 8.5: Investment Requirements Under ?wo Demand Scenario Annex 8.6: Estimated Generation Cost of Hydroprojects Annex 8.7: Installed Capacity by Company by End 1987 (MW) Annex 8.8s 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.il: SEGBA: Electricity Rates for Residential 'onsumers in October 1989 Annex 8.12: SEGBA: Electricity Rates for Industrial C.nsumers in October 1989 Annexes 9.1- Annex 9.5s Energy Balances Annex 9.6t 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 1C.3: Projections of Balance Sheet 1989-1995 (Individual Companies) Annex 10.4: Projections of Br.lance 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 Co's. and Yacyreta) Annex 11: Written Government Comments received December 1989, on Green Cover Version of Energy Sector Report (dated August 1989).. This document ha a restricted distribution and may be used by recipients only .n the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. Annex 1.0 Page 1 of 27 ARGENTINA OFFICIAL and ADJUSTED HYDROCARBON RESERVES Responsibility for Reserves Evaluations 1. With exception of minor old concession areas, the Government of Argentina is the legal owner of all hydrocarbon reserves. The State entity, Yacimientos Petroliferos Fiscales (YPF), has been assigned the objective of implementing the Argentine petroleum policies and is charged with the study, the exploration and exploitation of liquid or gaseous hydrocarbon reservoirs, as well as the industrialization, transport and commercialization of these products and their derivatives. Thus, it follows that YPF is responsibile for preparing periodic reserves evaluations of crude oil and natural gas, and providing official reports of remaining reserves volumes to other Government agencies. These official reserves reports are normally issued by YPF as of the end of each calendar year. No audit of YPFFs total hydrocarbon reserves has ever been made by an accredited independent consulting firm. Reserves Evaluations by YPF 2. Reserves evaluations have been prepared by YPF for many years. Geologists and reservoir engineers employed by YPF and who work in t*h Carencia de 1:ineria y ueologia de Explotacion (GkGE), have the experience and capabilities required for adequate determinations of all hydrocarbon reserves. Although the GMGE does not have full capability of performing mathematical modeling of hydrocarbon reservoirs, they are making strong efforts to obtain the necessary hardware and software to provide in-house reservoir modeling applications of this sophisticated technology. Until such time that the GMGE has obtained this hardware and software and trained their professional people with this capability, they are utilizing the services of a private Argentine firm, INLAB, to perform reservoir modeling evalu.tions of their more importait reservoirs. Criteria and Reserves Definitior! 3. During different time periods, the criteria and definitions which YPF employed for reserves determinations were changed, resulting in reported volumes of reserves which were not necessarily comparable between the same reservoirs or fields. Since 1984, the GMGE has used a written guide for reserves, "Definition of Reserves for the Internal Use of YPF"'. As described in that guide, YPF has introduced a unique concept, termed 'conditional", as applied to the generally accepted reserves terminology utilized within the petroleum industry. This term is applied to reserves, proved or probable, in any case where the expio:itation of such reserves iLs *onditionai xn other factors that impede the actual exploitation of these reservtes, such as not having facilities to collect the gas, or the lack of implementation of special exploitation techniques, or whatever other cause that does not permit actual exploitation of the subject reserves. However, in the annual publication of official reserves, YPF does not identify which proved or probable reserves are categor- - 2- Annex 1.0 Page 2 of 27 ized as "conditional"; this results in confusion and a general misunderstanding of the actual reserves situation. YPF Reserves pefinitiona 4. The follcwing definitions were extracted from the reserves guide used by GMGE ia the determinations of YPF official reserves: A. RESERVES: the volume of liquid or gaseous hydrocarbons (at standard conditions) existing in a reservoir, of which a percentage is feasible to be extracted in a profitable form under existing technology, whether by natural reservoir energy or added energy by means of special methods. As a function of the measure of uncertainty, reserves can be subd4vided in: 1. PROVED: The proved reserves are estimated quantities that geological and engineering data demonstrate with reasonable certainty will be recovered in the future, from known reservoirs and under existing economic conditions. 2. PROBABLE: As indicated by ths name, those reserves which are more uncertain than proved reserves, having less certainty of lithological continuity and petrofisical characteristics of the reservoir. B. TERMS IN COMMON USE: included below are terms which are applicable for petroleum as well as gas. le ORIGINAL RESERVES IN-SITU: the volume of hydrocarbons existing in the reservoir under surface conditions prior to exploitation, expressed in m3. 2, ORIGINAL RECOVERABLE RE11WRVES: the volume of hydrocarbons that can be extracted from a reservoir either by natural energy or the addition of artificial energy. 3. FACTOR OF RECOVERY: the value in percent of the original reserves in situ that can be extracted from a reservoir during its useful life. This is expressed in X and in case it cannot be calculated by one of the known methods, average values for the basin and type ef reservoir will be applied. 4. EXTRACTED: accumulated volume of hydrocarbons recovered, expressed in m3. 5. REMAINING RECOVERABLE RESERVES: the value resulting from deducting the volume extracted from the original volume of recoverable reserves, expressed in m3. The above descriptions and previous definitions constitute Annex 1.0 3 Page 3 of 27 the maximum level of reserves details, for whatever hydrocarbon substance. 1. CRUDE OIL 1.1. PRIMARY RESERVES Primary reserves are defined as the volume of crude oil at surface conditions that can be extracted by natural resarvoir energy. 1t1.1. PROVED PRIMARY RESERVES The volume of primary reserves that can be considered proved by the definition oased on the characteristics. 1.1.l.t. PROVED PRIMARY RESERVES NOT CONDITIONAL Proved primary reserves corresponding to reservoirs that by their characteristics ot low GOR or existing installations for natural gas collection permit continuous and rational production. 1.1.1.2. PROVED CONDITIONAL PRIMARY RESERVES Within this subdivision are included proved primary reserves pertaining to reservoirs, that because of the type (gas-condensate, extra-heavy crude oil, etc.) have their exploitation conditional on gas collection, or on the implementation of special exploitation technologies or whatever other cause that could impede their actual exploitation. 1.1.2. PROBABLE PRIMARY RESERVES The volume that could be extracted by primary exploitation, from the probable original in-situ reserves. For this determination the recovery factor utilized for proved primary reserves will be assumed as valid. 1.2 * SECONDARY RESERVES The additional volume of crude oil or 4.ondensate that could be extracted from the reservoir as a consequence of inJecting water or gas. 1 .2.1. PROVED SECONDARY RESERVES Considered to be that volume substantiated by a secondary recovery study. 1.2.1.1. PROVED SECONDARY RESERVES NOT CONDITIONAL The reserves corresponding to an integral project, the evaluation of which does not depend upon the results of a pilot project. - 4 - Annex 1.0 Page 4 Of 27 1.2.1.2. PROVED SECONDARY CONDITIONAL RESERVES Under this classification are included the reserves of pilot projects until definite evaluations can be made and that of extensions or remainder of the project until the results and conclusions obtained from the pilot certify the convenience of implementing the full project. Is= 1.2.2. PROBABLE SECONDARY RESERVES Under this category are included the reserves to be obtained by secondary recovery from those reservoirs that offer good prospects but no studies have been finalized with which to implement an actual pilot project. 2. NATURAL GAS 2.1 PROVED RESERVES Those volumes that correspond to the definition of proved. 2.1.1. PROVED RESERVES DISSOLVED GAS All crude oil at reservoir conditions contains a certain determinable volume of dissolved gas; osemve!!.tly, thte value of proved di-^lvzd ga3 is directly related to the proved crude oil reserves. 2.1.1.1. PROVED DISSOLVED GAS NOT CONDITIONAL Those reservoirs with a very low gas-oil ratio, so the gas can be vented, or that have surface installations adequate for collecting the gas. The reservoir should also be exploited in a rational manner. 2.1.1.2. PROVED CONDITIONAL DISSOLVED GAS Includes those reservoirs with gas-oil ratios above that permitted for venting the gas, and that do not have gas collection facilities, or the lack of transport capacity or reinjection capacity. 2.1.2. PROVED RESERVES OF FREE GAS Under the classification of free gas reserves are included all gas that is not normally dissolved in crude oil, irregardless of its relation to the crude oil. In order to differentiate the types of tree gas, terms are applied to distinguish between (1) gas-caps associated with crude oil. (2) gas-condensate, and (3) dry gas or reservoirs where the gas-oil ratio is above 20,000 m3,m3. This free gas must also satisfy the definition of proved reserves. Annex 1.0 -5- Page 5 of 27 2.1.2.1. PROVED FREE GAS RESERVES NOT CONDITIONAL 'hese reserves pertain to those reservoirs, with free gas, that produce volumes according to their potential, that do not interfere with the final oil recovery, and that have adequate facilities installed to collect the volumes of gas produ-ed. PROVED CONDITIONAL FREE GAS RESERVES These reserves pertain to those reservoirs with proved free gas that, (a) do not have facilities for collecting the gas produced, (b) if facilities exist, they are not adequate for the potential of the reservoir, and (c) the production fluctuates according to the seasonal fluctuation of gas collection. 5. It is evident that the inclusion of. conditional"' reserves, interpreted to be those for which one or mo-e basic conditions does not exist to permit the rational economic production of those reserves, leads to misconccptions as to the actual volumes of hydrocarbons that can be recovered under existing conditions. The YPF definitions of proved secondary reserves, both conditional and not conditional, are not acceptable to the international petroleum industry. A study of secondary reserves, irregardless of the experience and reputation of the organization preparing such stucy, is nothing otore than an indication of the prospective vou-mame of secondary -eserves to be recovered. Successful actuai response from an install.d secondary recovery project must provide support for the engineering study on which the project is based before those reserves can be classified as proved. YPF has included as proved reserves a large volume of secondary reserves, mainly from estimations provided by contractors at the time of bidding on the contract areas. Even though subsequent experience has demonstrated that these secondary reserves volumes will not be recovered under existing economic and technical conditions, YPF has not made appropriate reductions in their official proved reserves reports. 6. After a number of years of research and exchange of concepts regarding various definitions being utilized by international petroleum companies pertaining to reserves of hydrocarbons, in February 1987, the Society of Petroleum Engineers (SPE) approved definitions of reserves that they believe will be accepted by most Governments and companies concerned with the hydrocarbons industry. As a comparison with the definitions of reserves being utilized by YPF, extracts from the definitions acceptable to SPE are included as follows: A. RESERVES: estimated volumes of crude oil, condensate. natural gas, natural gas liquids, and associated substances anticipated to be comercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserves estimates are based on interpretations of geologic and/or engineering data available at -6 - Annex 1. 3 Page b or 27 the time of the estimate. Reserve estimates generally will be revised as reservoirs are produced, as additional geologic and/or engineering data become available, or as economic c nditions change. All reserves estimates involve some degree of uncertairty, depending chiefly on the amount and reliability of geologic and engineering data available at the time of the estimate and the interpretatior of these data. The relative degree of uncertainty may be conveyed by placing reserves in one of two classifications: 1. PROVED: Proved reserves can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Proved reserves may be developed or undeveloped. a) Reserves are considered proved if commercial producibility of the reservoir is supported by actual production or formation tests. The term proved refers to the estimated volume of reserves and not just to the productivity of the well or reservoir. b) The area of a reservoir zonsidered proved includes (1) the area delineated by drilling an" df-"ed by fluid contacts, if any, mnd (2) the undrilled areas that can be reasonably judged as commercially productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the proved limit unless otherwise indicated by definitive engineering or performance data. c) Proved reserves must have facilities to process and transport those reserves to market that are operational at the time of the estimate, or there is a commitment or reasonable expectation to install such facilities in the future. d) Proved undeveloped reserves are assLgned to undrilled locations that satisfy the following conditions: (1) the locations are direct offsets to wells that have indicated commercial production in the objective formation, (2) it is reasonably certain that the locations are within the known proved productive limits of the objective formation, (3) the locations conform to existing weil spacing requlations, ir any, and (4) it is reasonably certain that the locations will be developed. e) Reserves that can be produced through the application of established improved recovery methods - 7 - Annex 1. v Page 7 of 27 are included in the proved classification when (1) successful testing by a pilot project or favorable production or pressure response of an installed program in that reservoir, or one in thG immediate area with similar rock and fluid properties, provides support for the engineering analysis on which the project or program is based and (2) it is reasonably certain the proJect will proceed. f) Reserves to be recovered by improved recovery methods that have yet to be established through repeated commercially successful applications are included in the proved classification only (1) after a favorable production response from subject reservoir from either (a) a representative pilot or (b) an installed program, where the response provides support for the engineering analysis on which the project is based, and (2) it is reasonably certain the proJect will proceed. 2. UNPROVED: Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of prved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of thie estimate. Estimates of unproved reserves may be made for internal p4Sanning or special evaluations, but are not routinely compiled. Unproved reserves are not to be added to proved reserves because of different levels of uncertainty. Unproved reserves may be divided into two subclassifications: probable and possible. Probable reserves are less certain than proved reuerves and can be estimated with a degree of certaint'r sufficient to indicate they are more likely to be recovered than not, and may include the following: a) Reserves anticipated to be proved by normal stepout drilling where subsurface control is inadequate to classify these reserves as proved. b) reserves in formations that appear to be productive based on log characteristics but that lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area. C) incremental reserves attributable to in:il. drilling that otherwise could be classified as proved but closer statutory spacing had not been approved at the time of the estimate. d) reserves attributable to an improved recovery - 8 - Annex 1.0 Page 8 of 27 method which has been established by repeated commercially successful applications when a project or pilot is planned but not in operation and rock, fluid, and reservoir ch&racteristics appear favorable for commercial application. e) reserves in an area of a formation that has been proved product4ve in other areas of the field but subject area appears to be separated from the proved area by faulting and the geologic interpretation indicates subJect area is structurally higher than the proved area. f) reserves attributable to a successful workover, treatment, change of eqLipment, or other mechanical procedure where such procedure has not been proved successful .n wells exhibiting similar behavior in analogous reservoirs. g) incremental reserves in a proved producing reservoir where an alternate interpretation of performance or volumetric data indicates significantly more reserves than can be classified as proved. .over the vaars yPF has made diBcov ies nf cru4e o',iind aiatu rai gas in numeroui small ±ieia^. Because tne volume ot reserves is small, these fields have not been developed nor have any surface facilities been installed for actual production of these small fields. YPF has included the calculated reserves volumes from these small fields as proved reserves, but it is most unlikely that these reserves could be recovered under existing conditions. 8. Reservoir modeling studies perform.. .:i INLAB on the L.oma de .a Lata field have resulted in strong indi-..';oans that the volume of hydrocarbons originally in-situ, and especially the volumes of natural gas and condensate liquids that will be recovered at an adequate abandonment pressure to avoid the installation of excess compressor capacity, will be substantially lower than previously predicted. Previous reserve estimations made for Loma de la Lata were based on volumetric calculations and assumptions that the effective reservoir area covered more of the geological structure. With more recent information from wells defining the productive limits of the reservoir, and the fact that the reservoir character- istics tend to become very poor as the re.ervoir limits are approached, it is evident that previous volumetric estimates of reserves were overlY optimistic. Based on the results from the INLAS studies, the condensate reserves from the Sierras Biancas formation were adjusted downward by 25,415,000 m3, an¶d the natural gas reserves were adjusted downward by 112,646 million m3. These adjustments for Lona do la Lata obviously change the entire perspective of the natural sias availability situation from the Neuquen area. Annex 1. 0 Page 9 of 27 9. The official YPF reserves report for the Ramos field, located in the Northwest basin and operated by Pluspetrol under a service contract with YPF, shows the proved natural gas reserves to be 30,231 million m3. This volume is actually the estimated volume to be produced by the time the service contract expires. The actual proved natural gas reserves are in excess of 75,000 million m3, and consequently an upward adjustment in proved reserves to this level is justified. 10. YPF has included all of the offshore Tierra del Fuego reserves discovered by Total Petroleum, another service contractor, as proved reserves. The faxt is that Total is just now installing production facilities to permit production of a small portion of these reserves, and with the limited capacity of the natural gas trunkline from that area,.the production from other fields will be delayed for years. As a consequence, most of these reserves have been adjusted from proved to probable, since there are no facilities to process and transport those reserves to market that are operational at this time. 11. In order to obtain hydrocarbon reserves volumes which are more in agreement with the definitions of proved and probable reserves as generally understood in the petroleum industry, adjustments were made to the YPF official reserves report on a field by field basis as considered necessary. The details of adjustments in crude oil raszr-fe are siic-a IM TabLes I thru a', aad adJumt=nt. in naaturai 'as reserves are shown in Tables 7 thru 12. The final consequences of these adjustments for crude oil and natural gas reserves in Argentina as from January 1, 198a, are as follhws: Crudo Oil Official YPF Adjusted Reserves M m3 M m3 Proved 357,151 237,082 Probable 188,391 217,925 Natural Gas Reserves MM m3 Mm m3 Proved 693,3C9 539,253 Probable 163,268 215,221 ;4ay 989 - 10 - Annex 1.0 Page 10 of 27 Table YPT - COMPARISON OF OFFICIAL with ADJUSTED OIL RESERVES Remaining Oil Resorves - JanuarY t, 1988 Cuaulative Proved Probabl. Production Reserves Rosorves thousand m3 thouaaad m3 t?housand m3 Official YPF Adm. 416,048 245,353 157,2S3 N ntracts J 111I 3t6 Total: 538,281 357.151I t 8391T Adjusted YPF Ada. 416,048 172,113 163,635 Cent-tracts 222.233 64 .9649 5 Total: 63a 2a 2U082a 217,925 - 11 - Annex 1.0 Page 11 of 27 Table 2 YPF - ADJUSTED OIL RESERVES Adjusted Remaining Oil Reserves - January 1, 1988 Cumulative Proved Probable Production Reserves Reserves thousand .3 thousand .3 thousand d3 Noroeste YPF Adm. 28,695 21,388 15,323 Cuntracts 874 12.043 3.819 Sub-total: 29,569 J3,431 19,142 Cuyana YPF AdM. 70,538 20,086 3,623 Contracts 59.472 8.074 2.777 Sub-total: IM7013¶ 28,160 6,400 Neuquina YLPF Ada. 107,321 82,128 39,224 Contractu 48.98i 11.i9 3.093 3ub-total: 156,30S 93,219 42,317 Sa'n Jorge (L) YPF Ada. 180,162 38,463 87,710 Contracts 112.9Q] .;4101 Sub-total: 293.06S 62,564 88,016 San Jorge (CC). YPF Ads. 24 0 8,285 Contracts ° Sub-total: 24 0 8,285 Austral (L) YPF Adm. 29,308 :!0.048 6,054 Contracts. a a , Sub-total: 29,308 10,048 6,054 Austral (S) YPF Ada. 3 O 3,416 Contracts a 2.Lo60 44.295 Sub-total: a 9,660 47,711 Total Oil Reser. Total YPF Ada. 416.048 1i2,113 163,635 Total Contract 222.233 54.969 54.290 Grand .aota;: 638.28! 237,082 217,925 'LL) land (S3) sea (CC) coadtal bait 12 - Annex 1.O. Page 1t of 27 Table 3 YPF - OIL RESERVES ADJUSTMENTS (as from January 1, 1988) Cumulative Proved Probable Production Reserves Reserves thousand W3 thousand m3 thousand m3 Noroeste Official 28,695 21,469 ISS92 Adjustment -a1 -26L AdJ. reserves 28,695 21,388 15)323 Cuyana Official 70,538 21,457 3,627 Adjustment -1 371 -4 AdJ. reserves 70,538 20,086 3,623 Neuquina official 107,321 123,772 40,053 Adjustment -4t.644 -82 AdJ. reserves 107,321 82,128 39,224 San Jorge (L) Official 180,16? S1,388 87,710 Adjustment - 1L925 O Adj. reserves 180,162 38,463 87,710 San Jorge (CC) Official 24 8, 2as 0 Adjustment -8285 8L215 Adj. reserves 24 0 8,28S Austral (L) Official 29,308 11,004 6,857 Adjustment -9-6 -803 Adj. reserves 29,308 10.048 6,054 Austral (S) Official 0 7,978 3,416 Adjustment -7.978 0 Adi. reserves 0 0 3,416 Total official: 416,048 245,353 157,255 Total adjustment: -_3_240 _.___ Totai adi. reserves: 416.3.48 I7Z.113 '3,5*35 (L) land (8) sea (CC) coastal belt - 13 - Annex 1.0 Page 13 of 27 taSi 4 ADJUSTMENTS - YPF OIL RESERVES (as from January 1. 1988) Proved Probable Reserves Reserves thousand m3 thousand m3 Noroeste La Tiqra - not prod -46 -269 Agua Blanca - not prod -35 -26 Sub-total: ^8 -269 Cuyana Carrizal - conditional -670 a Puesto Rojas - conditin -700 0 Los Tordillos -net prod -1 -4 Sub-total: -1,371 -4 tNeuquina C. 9oleadero - not prod -20 0 C.Fortunoso E.-not pro -2 0 C. Mollar O.-not prod -32 -141 El Sosneado N.-not prod -74 -262 La Buitrera - not prod -2 -3a Loma Peladas E.-not prd -20 0 Rincon Amarillo-not prd -2 0 Paso Bardas - not prod -15 0 Cerrito 0.-not prod -1 -35 Loma La Lata SB-reduce -25,415 0 Loma Neqra - not prod -5 0 Mangrullo - not prod -6 a Senillosa - not prod -56 -353 aartolo N.- not prod -4 0 Divis.Catriel-not prod -2 0 Pta. RosadaS.-not prod -6 0 Aguada Toledo- conditio -1 ,074 0 p.iHernandez - condition -4,481 0 P. Malina - conditional -362 0 A.del Cajon-conditional -457 0 Ag.Toledo -conditional -1,918 0 P.molina -conditional -865 0 Ag.Baquales-conditional -240 0 Hedanito O.-conditional -6,585 ub-total: -41 ,44 -A29 Annex 1.0 -14 - Page 14 of 27 .abla 4 cont'd ADJUSTMENTIS - YPF OIL RESERVES (as from January 1, 1989) Proved Probable Reserves Reserves thousand m3 thousand .3 San Jorge Cpo.Central D(EII)-cond -215 0 Tordillo N.-conditionai -136 '3 z.Central S(EI)-conditi -140 0 Cdon. Leon aXInb-condit -660 0 P.Truncado - conditiona -83 0 C.Central -conditional -3,826 0 El Trhbol-8.Vista-condi -1,100 0 EL Tordillo-conditiOnal -3,753 0 Escalante-conditional -1.420 0 Cdon. Leon-conditional -1.1S2 a El Dest.no-conditional -1 a P. Truncado-conditiOnal 37 Sub-total: -12,925 San Jorge (CC) Cinturrin Costero-not pr -8 285 8.285 Sub-total: Austral )L) Campo Bola-not prod -89 '3 C. aolleadoras- prod -14 -23 Cdon. Salto-not prod -15 n C. Salto O.-not prod -8 -12 Cerro Norte-not prod -1 -94 C. Suen Tiempo-not prod -9 -50 Filomena-not prod -30 2 Guanaco Muerto-not prod -7 0 Las Buitreras-not prod -11 G La Carmen-not prod -8 -26 La Leona-not prod -13 a2 La Marchand-not prod -14 0 Lag. El Palo-not prod -97 -257 .a aehueicne-not prod -28 -.7 La Terraza-not prod -7 -51 Puesto Quince-not prod 37 -95 S. Cristobas-not prod -8 0 Cerro Mesa-not prod -5 -:;ao El Monte-not prod -6 2 Annex 1.0 - 15 - Page 15 of 27 Table 4 cont'd ADJUSTHNTS - YPF OIL RESEP.VES (as tram January 1, 1988) Proved Probable Reserves Reserves :housand m3 thousana me L. Flamenc/Fe-not prod -20 -20 La Sara -ozndiUtional -206 0 Cdon. Salto-conditional -!95 a La Sara - conditional -83 e Sub-tOtal: -356 -8.3 Austral (5) Magallanes-not prod -7.927 * sub-total: -7,978 a Tatal Adjustment: -73.240 6,380 (L, land (S) sea (CC) coastal belt - 16 - Annex 1.0 T a Page 16 of 27 CONTRACT OIL RESERVES ADJUSTMTS (as from January 1, 1988) Cumulative Proved Probable Production Reserves Reserves thousand a3 thousand m3 thousand 23 Noroests Official 874 4,856 1,540 Adjusted 7.187 2.279 Adj. reserves 874 2,043 3,819 Cuyana Official 59,472 10, 194 2,777 Adjusted -2.120 0 Adj. reserves 59,472 8,074 2,777 N uquina official 48,984 23,842 3,093 Adjusted -12.751 0 Adj. reserves 48,984 11,091 3,093 San Jorne Official 112,903 42.371 306 Adjusted _ -18,270 a AdJ. reserves 112,903 24,101 306 Austral (S) Official 0 30,535 23,420 Adjusted -20.875 20.975 Adj. reserves 0 ,,295 Total official: 222,233 111t,798 31,136 Total adjustment: -46.829 23.134 Total adj. reserves: 2 64,969 54,29 - 17 - Annex 1. 0 Page 17 of 27 ADJU8TMNTS - COWIRACT OIL RESERVWS (as from January 1, 1988) Proved Probabls Reservre Reserves thousand m3 thousand m3 Noraosta Ramos 7.187 2.279 sub-total: 7 187 2.279 Cuymaa RefugioTupungato-condit -2 0 P. CoLoradas-conditioa -2.118 0 sub-total: 120 o Nluqcaunlo-uecooUic -4,388 0 Anticlin, cap.-conditi -1,028 0 centenrio-conditional -1, 906 0 Catriel Oeste-condition -21 a medianera-conditional -i, 158 0 M4danito SE-conditional -4.250 0 Sub-total: -12,751 J san Jorge (Li Amoco-conditional -4,828 o m4anan.fhr-conditional -2,463 0 Cdon.-Sco-conditional -2,312 0 m4eseta Espin.-condition -6,717 0 F.] Cordon-conditional -1 ,571 0 Piedra Clavada-conditio 397 0 Koluel Daike-canditiona -776 Sub-total: -18,270 3 Austral (S) Ara - not prod -49? 4.j7 Ara (Oi8) - not prod -'03 t03 Argo C - not prod -700 100 Argo P - not prod -s.4o0 5,400 Aries C - not prod -1,000 1,000 Aries P - not prod -1,700 1.700 Carina C - not prod -oa0 300 Klaus P - not prod -1 ,000 i .0o Lobo C not prod -300 300 t.obo P - not prod -1,100 1,a ?oius C - aot prod -25 zi Vega C - not prod -355a 5_ Vega-Pleyade - not prod -'.600 7, sub-total: -20 ZO,8720 Total Adjustment: -46,829 23,154 18 - Annex 1.0 Page 18-of 27 Table 7 YPF - COMPARISON OF OFFICIAL with ADJUSTED GAS RESERVES Remaining Natural Gas Reserves - January 1, 1988 Cumulative Proved Proved Probable Production Free Gas Dissol.Gas Gas reser. million m3 million m3 million a3 -million m3 NATUR}AL GAS Official YPF Adm. 254,823 524,687 39,428 l03,648 Contracts S7.145 119.210 10.064 59.6l0 Total: 311,968 643,897 49,492 163,268 AdJusted YPF Adm. 254,823 401,038 37,5os 106.801 Contracts 57.145 93.379 7.786 108.420 Total: 311,968 494,417 44,836 215,221 - 19 - Annex 1.0 Page 19-of 27 Table 8 YPF - ADJUSTED NATURAL GAS RESERVES Adjusted Remaining Natural Gas Reserves - January 1, 1988 Cumulative Proved Proved Probable Production Free Gas Dissol.Gas Gas reser. million m3 million m3 million m3 million m3 Noroeste YPF Ada. 47,933 68,916 1,243 27,229 Contracts 5.212 75.278 16.800 Sub-total: 53,145 144,194 1,243 44,029 cuyana YPF Adm. 1,831 0 1,657 0 Contracts 02.355 238 0 Sub-total: 4,186 a 1T950 Neuquina YPF Ada. 69,SO4 268,873 19,875 48,904 Contracts 37,50Q 5fju 5.748 6.138 Sub-total: 107,004 28S,386 2S,623 55,042 San Jorge YPF Ada. 60,491 12,117 9,129 2,976 Contracts 12.078 1.588 1.270 102 Sub-total: 72,569 13,705 10,399 3, Austral (L) YPF Adm. 75,064 51,132 S,146 27,692 Contracts O O a Sub-total: 75,064 51,132 5,146 27,692 Austral (S) YPF Adm. 0 0 0 0 Contracts 530 85.38Q Sub-total: .0 0 530 8s,380 Total Gas Reser. Total YPF Adm. 254,823 401,038 37,050 106,801 Total Contract 57,145 93.379 7.786 108.420 Grand total: 311,968 494,417 44,836 215,221 - 20 - Annex 1.0 Page 20 of 27 Table 9 YPF - GAS RESERVES ADJUSTMENTS (as from January 1, 1988) Free Gas Dissolved Probable Cumul. Prod. Proved Proved Gas million m3 million m3 million m3 million m3 Noroeste Official 47,933 68,971 1,293 27,229 Adjustment -_s _ -50 . AdJ. reserves 47,933 68,916 1,243 27,229 Cuyana Official 1,831 0 1,657 0 Adjustment - Q 0 Adj. reserves 1,831 a 1,657 0 Neuquina Official 69,504 386,008 20,132 46.137 Adjustment -117.135 -2S7 2.767 Adi. reserves 69,504 268,873 19,875 48,904 San Jorge Official 60,491 12,117 9,129 2,976 AdJustment - , ° AdJ. reserves 60,491 12,117 9,129 2,976 Austral (L) Official 75,064 57,182 5,221 22,372 Adjustment -6.00Q -75 5.320 Adj. reserves 75,064 51,132 5,146 27,X92 Austral (3) Official 0 409 1,996 4,934 Adjustment -409 -1,996 -4 934 AdJ. reserves 0 0 0 Total official: 254,823 524,687 39,428 103,648 Total adjustment: -123.649 -2.378 3.153 Total adJ. reserves: 2s4,823 401,038 37,050 106,801 - 21 - Annex 1.0 Page 21 of 27 Table 10 ADJUSTMENTS - YPF GAS RESERVES (as from January 1, 1988) Free Gas Dissol. Gas Probable Proved Proved Gas million m3 million m3 million m3 Noroeste La Tigra - not prod 0 -49 o Agua Blance - not prod -1 0 Sub-total: Ss -Z O Neuquina C. Boleadero - not prod -322 0 322 C. Fortunoso E.-not pro -67 0 a C. Mollar 0. - not prod 0 -16 0 El Sosneado N. - not pr 0 -1g 0O La Buitrera - not prod 0 -1 0 Lama Espinas - not prod -24 -12 0 Loma Peladas E.- not pr -781 0 781 Puesto Adobe - not prod -43 -S -99 P.A.Calientes- not prod 0 -S9 Rincon Amarillo- not pr -22 0 -273 Paso Bardas --not prod -1,036 0 1,036 Paso Bardas N.- not pro -52 0 52 Cerro Vagon - not prod 0 -1S 0 Cerrito Oeste - not pro -1 a -192 F.de Piedra - not prod -23 0 -123 Loma La Lata SB-roduce -112,646 0 0 Mangrullo - not prod -510 0 510 Pto. Opazo - not prod -14 -5 -147 P'ta.Senillosa- not prod -150 -3 -190 Senillosa - not prod -185 -35 0 Barr. Loroa N.-not prod 0 -70 o Bartolo N. - not prod -45 0 a Blanco Olivos- not prod -480 -1 4ao Divis. Catriel - not pr -60 0 -50 Puesto Silva - not prod -14 -16 0 Pta. Rosada - not prod -660 0 660 Sub-total: -117,135 -257 2,767 San Jorge Sub-total: - 22 - Annex 1.0 Page 22 of 27 Table 10 cont'd ADJUSTMENTS - YPF GAS RESERVES (as from January 1, 1988) Free Gas Dissol. Gas krobable Proved Proved Gas million m3 million m3 million m3 Austral (L) C. Boleadoras- not prod -2,170 0 2,170 Cdon. salto O.-not prod 0 -2 0 Cerro Norte - not prod -644 0 644 C.Buen "iempo- not prod 0 -13 0 Chorrillos N.- not prod 0 -6 0 Filome.a - not prod -562 -14 562 Guanaco Muerto-not prod -103 0 103 Las Buitraras - not pro -280 0 0 La Carmen - not prod -179 -1 179 La Leona - not prod -337 0 337 Le Marchand - not prod -339 0 339 Lag.El Palo - not prod 0 -7 0 La Tehuelche - not prod 0 -5 0 La Terraza - not prod -77 -2 a Arroyo Cachimba-not pro 0 -4 0 Castillo O.- not prod 0 -1 0 Puesto Quince - not pro 0 -18 0 S.Criatobal - not prod -180 0 -193 El Monte - not prod -138 0 '38 L. Flamenc/E - not prod -1,041 0 1,041 Rio Chico N.- not prod 0 -2 0 Sub-total: -6,050 -75 5,320 Austral (8) M4agallanes - not prod -409 -1.996 -4.934 Sub-total: -409 -1.996 -4,934 Total adjustment: -123,649 -2,378 3,153 - 23 - Annex 1.0 Page 23 of 29 Table 1t CONTTRACT GAS RESERVES ADJUSTMENTS (as from January 1, 1988) Frea Gas Dissol. Gas Probable Accum. Prod. Proved Proved Gas Reserved million m3 million m3 million m3 Million m3 Noroeste official 5,212 30,509 0 6,,780 adjustment 4,769 IG.020 adj. reserves S,212 75,278 .0 16,800 Cuyana official 2,355 0 238 adjusument - 238 adj. reserves 2,355 0 238 Nouquina official 37,500 16,S13 S,786 6,138 adjustment ° -38 0 adj. reserves 37,500 16,513 5,748 6,138 san Jorge (L) official 12,078 1,588 1,270 102 adjustment 0 a . ° adj. reserves 12,078 1,588 1.270 102 Austral (8) official 0 70,600 2,770 46,600 adjustment -70.600 -2.240 38.780 adj. reserves 0 0 530 85,380 Total official 57,145 119,210 10.,064 59,620 Total adjustment 0 -25.a31 -2.27a a48.800 Total adi. reserves 57,145 93,379 7,786 10a,420 Annex 1.0 -24 - Page 24 of 27 Table 12 ADJUSTMENTS - CONTRACT GAS PESERVES (as from JanUarY 1, 1988) Free Gas DissolWi' Probable Proved Proved Gas Reserves million m3 million m3 million m3 Noroest4 Ramos 44.769 0 10.020 Sub-total: 44,769 0 10,020 Cuyana aub-total: 0 0 0 Neuquina Llancanelo -unecon. 0 -38 0 Sub-total: -38 0 San Jorge (L) Sub-tp%tal: 0 0 0 Austral (8) Ara C - not prod. -10,000 -100 10,100 Argo P - not prod. -6,300 -400 6,700 Aries C - not prod. -10,500 -100 10,600 Carina C - not prod. -29,000 -1,100 0 Klaus P - not prod. 0 -40 0 Lobo C - not prod. -3,800 -120 0 Vega-Pleyade P-not prod -11.000 -380 11,380 Sub-total: -70,600 -2,240 38,780 Total adjustment: -25,831 -2,278 48,800 ! - 25 - Annex 1.0 Page 25 of 27 Comments Pertaining to Official Crude Oil and Natural Gas Reserves as at 1/1/89 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 at 01/01,'89 as shown in Table __, the total volume of official proved crude oil reserves added during the year 1988 amounted to 30,858 MCM. Of this total volume added, 77% resulted from review and studies of known reservoirs, 20% from development of known reservoirs, and 3% (926 MCM) from exploration. Official probable crude oil reserves were also increased during 1988 by 26,664 MCM, all of which resulted from the San Jorge and Austral basins. Of this total volume of official probable reserves added, 47% resulted from review and studies of known reservoirs, 7% from development of known reservoirs, and 45% (11,999 MCM) from exploration. The volume of official proved secondary recovery crude oil reserves, which is included in the total volume of official proved crude oil reserves of 362,470 MCM as at 01/01/89, was reduced by 29,180 MCM during 1988, implying corrective adjustments to those official proved crude oil reserves previously classified as 'condicionada-. It was not possible to make adjustments to the official reserves as at 01/01/89 because details for each field and the "condicionada" reserves volumes- have not been made available. With a natural gas production volume of 22,700 MMCM during 1988, and an increase in official proved natural gas reserves of 79,623 MMCM - 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 01/01/89, 62% was from known fields in the Northwest basin, and 22% was from known fields in the Austral basin. The net increase in proved natural gas reserves in the Neuquin basin, where spare capacity in trunklines is available, amounted to only 5% 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, it is not possible to make a specific evaluation of the results from exploration, but from all indications, exploration contributed very little to the natural gas reserves situation during 1988. Without detailed data for each field and the *condicionada' reserves, it is not possible to make adjustments for the official natural gas reserves as at 01/01/89. - 26 - Annex 1. 0 Page 26 of 27 ARGENTINA - COMPARISON OF OFFICIAL NATURAL GAS RESERVES VOLUMES (Official reserves as at '/1,'88 & 11/'89 - without adjustments) Free Gas Dissolved Probable Proved Provad Gas million m3 million m3 million m3 Noroeste Official 1/1/88 99,480 1,293 34,009 Official 1/1/89 148.794 960 0 Net change, + or - 49.314 -333 -34,009 Cuyana Official 1,'1/88 0 1,895 0 Official 1/1,'89 0 t.290 a Net change, + or - G -605 0 Neys2ina official 1/1/88 402,521 25,918 52,275 Official 1/'1 /89 405 020 27 765 51,083 Net change, + or - 499-1,192 San Jorae Official 1/1/88 13,705 10.399 3,078 Official 1/1/89 't,633 22.075 4,659 Net change, + or - -2,072 11,676 1,5819 Austral Official 1/'1,'88 128,191 9,987 73,906 Official ,'11/89 147 271 8.204 71.480 Net change, + or - 19,080 -1,783 -2,426 Total Official 1/,1/88 643,897 49,492 163,268 Official 1/1/89 742.718 60.294 127,222 Net change, t or - 68,821 10,8027 -361,046 (1) Natural gas production during 1988 was 22,700 million m3. (2) Most of the increase in proved natural gas res- erves resulted from Aguarague and Ramos conden- sate fields in the Northwest Basin. (3) Adjustments have not been made to these official natural gas reserves 0 1/1/89 because details for each field and those "condicionada" reserves volumes have not been made available. - 27 - Annex 1.0 Page 27 of 27 ARGENTINA - COMPARISON OF OFFICIAL CRUDE OIL RESERVES VOLUMES (Official reserves as at 1/1/88 & 1/1/89 - without adjustments) Proved Probable Reserves Reserves thousand m3 thousand m3 -- -- - -- --- …- - Noroeste Official 1r/1/88 26,325 17,132 Officiai 1fl'/89 33.694l 1.516 Net change, + or - 7,369 -15,616 Official 1/1/88 31,651 6,404 Official 1/1,'89 37.234 ".301 Net change, + or - 5,583 -5,103 Neuquina Official 1/1/88 147,614 43,146 Official 1/1/89 147,540 35.851 Net change, t or - -74 -7,295 San Jorge Official 1/1/88 102,044 88,016 Official 1/1/89 _966,96 119.040 Net change, + or - -5,348 31,024 Austral Official 1/1/88 49,517 33,693 Official 1,'1/89 47.306 57.347 Net change, + or - -2,211 23,654 Total Official 1/1/88 357,151 188,391 Official 1/1/89 362.470 215.0.5 Net change, + or - 5,319 26,664 (1) Crude oil production during 1988 was 25,539 thousand m3. (2) Most of the increase in proved crude oil reserves resulted from previous probable reserves. San Jorge and Austral probable reserves increased significantly. (3) Adjustments have not been made to the official zrude oil reserves Q 1/1/89 because details by fieeld and *condicionada not available. 28 - Annex 1. 1 Page 1 of 10 RGENWTNA INSTITUTIONAL STRUCTURE OF THE HYDROCARBON SUSSECTOR 1. The institutional framework in Argentina for the development and implementation of policies pertaining to the local hydrocarbons industry, for strategic planning affecting this industry, and for the management and operation of th. hydrocarbons energy subsector, is characterized by five distinct levels of decision-making: (1) the Executive Power (PE) represented by the President of the nation; (2) an executive level represented by the Ministry of Economy (HE) and the Ministry of Public Works and Services (MOOP): (3) a superior mfanaqment level represented by the Directorate of Public Enterprise. (DEP (4) a regulatory and planning level represented by the Secretariat of Energy; and (5) an implementation 2nJ operational level represented by the State-owned companies (PEs), Yacimientos Petroliferos Fiscales (YPF), and Gas del Estado (GdE). The Exeutive Power (PMN1 2. The PEN exercises the highest position of authority to influence the appointment of top-level personne in the State-owned energy companies, and among other responsibilities, gives final approval to all contracts with private companies for exploration, production, transportation, processing, export/import, and/or sales of hydrocarbons and their derived products. The Ministry of EconomY (ME) 3. The ME, either directly or with intervention of the Secretariat of the Treasury (8R), participates in setting prices and taxation on all crude oil, natural gas and liquid products, and in establishing the amounts of royalty payments to those provinces from which hydrocarbons are produced. All contracts that require final approval from the PEN, are first subject to approval by the ME. Guidelines for limits of annual budgets of expenditures and investments for the PEs are established by the ME, and subsequent adiustments in budget amounts of PEs are made from time to time by the ME. In addition to other responsibilities, the HE reviews non-economic objectives/con- straints assigned to PEs, approves subsidies or compensation for non-economic objectives assigned to PEs, and approves investments and debt servicing requirinq budget transfers or Government guarantees an foreign loans. The Ministrv of Public Works and Services (MOSP) 4. The MO8P is the formal liaison between the onergy sector and the PEN; the minister is a member of the cabinet and a spokesman for the - 29 - Annex 1.1 rage 2 of 10 energy sector at this decision level. Since all petroleum and natural gas resources in Ar;entina are the exclusive property of the nation, with exception of certain small private concessions which existed prior to the ostablishment of the Law of Hydrocarbons, the MOSP is the principal overseer of the hydrocarbons subsector. Within this role, the HOSP approves most contracts, annual budgets, key personel changes, and issues numerous regulations that affect the petroleum and natural gas subsectors. TU MOSP also makes decisions regarding divestitures and privatizations, prepares related draft legislation for the Congress, and arbitrates any disputes between DEP and the Secretariats. 30 - Annex 1.1 Page 3 of 10 The Secretariat of Energy (SE) 6. The Law of Hydrocarbons, No. 17,319, designated the SE as the Application Authority for all technical aspects related to the production, processing and marketing of petroleum and natural gas in Argentina. Since 1985, certain other functions, previously reserved for Ministry level, were delegated to the SE, such as setting final official prices for all commercialization of crude oil, natural gas, and liquid products. These official prices are set by the SE after consulting with and subject to the approval by the ME and MOSP in consideration of the economic consequences and the large tax revenue that is generated. The PEs and all private companies involved with production, transportation, processing, and/or marketing of hydrocarbons are thus dependent upon the SE for all of their prices and profit margins for marketing functions (with exception of service contractors with prices established iny contracts). Other specific functions performed by the SE are as follows: - Energy sector planninq - Approval and enforcement of contracts between the State and/or PES and private companies engaged in the hydrocarbons industry - Distribution of crude oil among the various public and private refineries (both quality and quantity) - Authorizations for importation/exportation of hydrocarbons - Locations for retail service stations - Margins for refining, commercialization and service station sales of petroleum products - Allocation of financial resources to the different energy subsectors - Energy conservation - Development new sources of energy - Coordination of the activities of the diverse companies operating within the energy sector 7. The SE, functioning as a Secretariat under the MOSP, is directed b;. & designated Energy Secretary. This orgaaization includes four subsecretariats: (1) Fuels, responsible for the supervision of the three state owneu companies dealing with fuels, YPF, GdE, and YCF, and other private concession producers, refining and marketing companies; (2) Electricity, responsible for controlling four principal electricity generating companies; (3) Planning, responsible for energy planning, conservation, efficiency improvements in PEs, - 31 - Annex 1 .1 Page 4 of 10 loss reductions, and development of new energy sources; and (4) Relations with Enterprises, responsible for coordination and evaluation of the companies participating in the hydrocarbons industry, and also providing liaison with agencies and organizations oultside of the energy sector. 8. The BE is small in size, with some 15 professional employees, including the Energy Secretary and the four undersecretaries. Not only does this small group formulate policies, but they also produce long-range plans, revise budgets, assist in the allocation of financial resources, coordinate inter-coWpany activities, and try to establish relative priorities for energy use. They do not have a technical staff which is qualified to perform all of the functions necessary for decision-making. They do not have an Cxperienced group cf technical inspectors/evaluators with which to maintain vigilance over the actions of the PEs and private companies participating in the energy sector. The SE, under certain conditions, authorizes selected personnel within the PEs to exercise these regulatory control functions, responsibilities which should be done by and with its own pdrsonnel. At times, the SE is obligated to reinforce its own staff with technical or administrative personnel from the PEs, designated to work "on commission". These staffing deficiencies only conspire to result in less than adequate performance of the very important functions that are designated to the SE and contribute to confusion between activities that should be performed only by the State with those that should be strictly the responsibility of thM PEs. In spite of these limitations, the implementation of political decisions pertaining to the energy sector by the Government a:e correctly channeled through the SE, which also provides input and participates in the formulation of these decisions. The actual results, many times, depend oan the personality of the individual designated as Energy Secretary at that particular time. Yacimientos Petroliferos Fiscales (YPF) 9. - YPF is a State corporation (emprosa del estado), having a corporate structure similar to a private corporation, but the only shareholder is the Government represented by DEP. With the transformation to this corporate structure in April 1977, the expressed intention was to provide an organization that would be in condition to act with fluidity of decisions and attain the level of efficiency and asility comparable to a private corporation. At the same time that YPF was provided with a corporate structure that would supposedly contribute to improved agility of operation, the State guaranteed its absolute predominance in the management and control of YZPF. As might be expected. only the latter objective was realized. 10. The Law of Hydrocarbons, No. 17,319 (1967) states, "The activities pertaining to the exploration, exploitation, industriali- zation, transport and commercialization of hydrocarbons will be performed by State companies, private companies or mixed companies in - 32 - Annex 1.1 Page 5 of 10 conformance with the dispositions of this Law and the regulations that the PEN decrees". The statutes of YPF, dated July 31, 1987, state the objective of YPF to be ".... to implement the Argentine petroleum policies and will have as its role the study, the exploration for and exploitation of liquid or gaseous hydrocarbon reservoirs, as well as the industrialization, transport and commercialization of these products and their direct and indirect deriviatives to which effect it can produce them, buy them, sell them, trade them. import or export them and realize whatever other complimentary oparation of their industrial and commercial activity. For the better fullfilment of these objectives, it can promote the formation of official entities and establish, associate or participate in private corporations, State corporations, corporations with maJority of State participation, or of whatever other legal framework". In actual practice, YPF controls all exploration and production of hydrocarbons in Argentina, with exception of certain small old 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 their activities under a service contract with YPF. 11. YPF was established in 1922, making it one of the oldest State oil companies in Latin America. For its own account, YPF produces about 70% of all crude oil production and more than 8OX of all gas production, and maintains supervisory contrcl over the private company service contractors who produce the remainder. Although YPF is structured as a corporation, its main function is to produce a large amount of revenue for the Government. YPF currently generates about US$7 billion per year (including fuels taxes) in gross revenues. 12. YPF is undergoing a basic reorganization program, with the objective of defining the general structure, the nature and atributes of each principal corporate unit, and the relations of subordination, coordination and control inherent to these units. The Board of Directors of YPF (BOD) is the maximum level of administration and direction within the corporation. The BOD consists of a President, an Executive Vice-President, and from one to five Directors designated to serve fer three years. In addition to being the lesal representative of the corporation and presiding over the BOD, the President is charged with the direct supervision over the following units of the organization: - Foreign Relations - Auditing - Center of Investigation and Development - General Security - General Secretary - National Defense - Civil Engineering - 33- Annex 1.1 Page 6 of 10 13. The Executive Vice-President of YPF, as the vxecutive officer, is charged with implementing the directives and !.upervising the compliance with rules amanating from the BOD, and administering the resources of the corporation, within the Laws, statutes and according to corporate plans. In addition to other responsibilities, the Executive Vice-President supervises directly the following organiza- tion functional units: - Exploration and Exploitation - Industrialization - Commercialization - Maritime and River transport - General Planning - Legal Assistance - Administration and Finance - Industrial Relations - Purchasing and Supply 14. Under the direct supervision of the Executive Vice-President, the four operating divisions and their respective missions are stated to be as follows: A. Exploration and Exploitation: Manage the exploration, drilling, and production of crude oil and natural gas, and to decide on the-conditions of sale, under business principals, that will ensure the profitability of this division, in accord with the corporate statutes, the plans and programs and all other regulatory norms. S. Industrialization: Manage the industrialization of hydrocarbons and their transportation via pipelines at minimum costs and according to the preestablished quantities and qualities, and to decide on the conditions of purchase-sale of these, under business principals, that will ensure the profitability of this division, in accord with the corporate statutes, the plans and programs and all other regulatory norms. C. Commercialization: Manage the commercialization of hydrocarbons, under business principals, that will ensure the profitability of this division, in accord with the corporate statutes, the plans and programs and all other regulatory norms. 0. Maritime and River Transport: Manage the activities of maritime and river transport of crude oil and its derivatives, under business principals, that will ensure the profitability of this division, in accord with the corporate statutes, the plans and programs and all other regulatory norms. 1S. All administrative functions of YPF are being organized into - 34. 34 - Annex 1.1 Page 7 of 10 specialized "Central Units". These Central Units will assist top management and all other operating units of the corporation. Each Central Unit is responsible for planning, advising and regulating matters that come within its specialization, even though the implementation of that activity is not subordinated to its formal or organizational authority. In addition to these responsibilities, the Central Units, within their respective specializations, will carry-out the activities required of their cenzralized functions, as follows: A. General Planning: Plan the operating, economic and financial acti-ities of the corporation. Propose the organization and norms oriented to the necessities of the corporate functions. Coordinate the activities of data processing, information systems and communications. - S. Legal Advice: Oversee all legal matters. and advise, represent and regulate for all of the areas in legal matters, intervening when necessary in those acts that might compromise the assets of the corporation. C. Administration and Finances: Exercise the functional suwervision of accounting and financial activities of the corporation in a manner that wiil permit a measure of the results from financial operations by the corporation. D. Industrial relations: Propose, advise and regulate the policies of the corporation in matters of personnel, industrial security and labor rela- tions. Manage, advise and regulate matters regarding social services. Coordinate the development of company policies. E. Purchasing and Supply: Propose, advise and regulate the policies of the corporation in matters concerning purchases and warehousing. Assist the different Purchasing Units of the corporation in terms of procedures and conditions of contracting. F. Center of Investigation and Development Encourage and realize efforts of investigation and develop- ment of techno'.ogies for the petroleum industry and other activities of the corporations. Manage and provide internal services and to third parties, under business principals that wiil ensure profitabil-ity. G. General Secretary: Comply with the activities conducive to normal functioning of the Stockholders Meetings and activities of the BOD; regulate and coordinate the entrance controls of the corporation at its headquarters building. 35 - Annex 1.1 Page'8 of 10 H. National Defense: Comply with the activities of National Defense imposed cn the corporation by legialation and the norms and directives issued by the defense authorities. r. Auditing: Audit the compliance of norms and procedures vithin the corporation, covering technical-operating, economic-financial and legal, operating above the Internal Control and informing the BOD of any deficiencies detected. J. General Security: Direct and oparate the protection of assets of the corporation, in order to ensure a normal functioning of activities without interference or perturbanceso plan, regulate and direct the tasks of prevention of security lapses. K. External Relations: Plan, implement, and coordinate the relations of representatives of the corporation with the community and its inscitutions. L. Civl Engineering: Convene with other areas regarding projects within this specialization whenever these areas cannot adequately design their technical projects. Encourage the development of good design and engineering tecbniques and assist other corporate areas in these matters. Gag del Estado (GdE) 16. GdE was established in 1946 as a Government enterprise to provide natural gas distribution services as a public service. In 1978, GdE's statutes were amended to the effect that it would operate as a State Corporation, and its fundamental objective was stated to be the provision of gas as a public service, rather than economic considerations. GdE purchases natural gas from YPF in producing areas located primarily in the provinces of Neuquen, Chubut, Santa Cruz, Rio Negro, Salta, and the National Territory of Tierra del Fuego. Imported gas is also received from Bolivia. From the producing areas, GdE processes the natural gas to remove hydrates and heavier liquids, and then transports the natural gas to consuming centers from where it is distributed to the individual end-users. In addition to the sales of natural gas, GdE also produces and markets LPG (propane and butane) and subproducts such as ethane and natural gasoline. 17. The head office of GdE is located in Buenos Aires, where the corporation also maintains 5 branches and 1 matece facility. in 17 provinces and in Tierra del Fuego, GdE has 101 branches, 6 maintenance facilities, and 3 agencies. dE employs soms 10,000 36 - Annex 1.1 Page 9 of 10 people. During 1986, GdE supplied an average of 39 million m3 per day of natural gas to end-users and produced gross revenues of near US$1.0 billion. odE is basically a transporter of natural gas rather than transforming natural gas into other products. The company does not participate in residential repair of natural gas burning devices. 18. The organization of OdE at the top level of authority comprises a Board of Directors, the President, the Vice-president, and the General Manager. In practice, even though the directors do not have specific areas of assigned responsibility, they do perform important executive responsibilities. The President exercises the maximum responsibility, especially with regard to relations with other Government agencies in matters such as tariffs, investments, financing, etc. in which GdE does not have autonomy. The Vice-president also exercises the function of the General Manager, and as such is the maximum authority within the corporation; he provides the connection between the Board of Directors and career operating managers. 19. From the General Manager depend 4 General Submanagers: (I) Technical-Operating, (2)Commercial. (3)Plaznning and DeveLopment, and (4) Administration. Under these Submanagers are a Departmental Managers, but there are in addition 5 other D*partmental Managers that depend dirsctly upon the superior authorities. 20. Formally, other agencies who are involved include t ; 8E, the HE. the MOSP, the SR, and the Sindicatura de Emprsas Publicas. Informally, the palitical connec- tions of the Directors and certain other high-level manageMent personnel create divergent relations with strong power groups, such as other State Secretariats. provincial Governors, congresssen, political bosses, private companies, etc. Consequently, even though Zormal authority is concentrated in the Vice-pr.694dent and General Manager, the many informal relatiosl create superpositions of lines of decision direct to the General Submanagers, resulting in most important decisions that affect the economic condition of GdE being taken outside ox GdE and without the adequate participation of individuals who are experienced iL the matters under consideration. At the same time requests for all types of urgent information from numerous Government agencies impose requireaumts on the time and activities of the Directors and other managers, creating confusion and dilution of the official strategic program or other directives for the corporation. This situation is not unique only to GdE, but it also exists in most other state companies; it results basically from adopting the corporate form resembling private corporations, but without Directors who h.&ve the career experience and dedication to "their" corpozation. Being a State corporation, with a number of Directors, only contributes to the multiPle lines of dependence that extend to all of the other special interest groups. 21. With regard to lower levels within dE, organi2zational problems - 37 - Annex 1 .1 Page 1U f 10 are eVident with an overabundance of 'chiefa", that is directly related to the progressive decline in real wages that has been observed since 1980. With salary levels frozen, the only manner to obtain a higher level of pay was to promote individuals to higher category positions. An excessive concentration of authorities and decisions are in Buenos Aires, relative to the dispersion of activities and clients that GdE has throughout the country. 22. At the management levels, problems persist with low morale and lack of drive to improve individual activities. The motives for this situation, in the majority of cases, are due to: - low salaries and small differentiation between categories; - lack nf recognition for extra efforts and/or capabilities; - permanent interforences from political and other interests; - unrational changes in the plans and programs of GdE. 23. The apparent Loss of efficiency and prestige for GdE has led to increasing attitudes of just doing whatever is necessary to maintain the position and employment among many lower level managers, who have considerable experience in the functions to which they are assigned and would prefer to see the company run efficiently, with a better future for all concerned. However, this overriding defensive attitude of maintaining their positions and their employment also contributes to their strong resistance to any possible incorporation of private capital into any of the activities which in the past have been the functions of Md. A fundamental change will be required in the entire political and economic environment affecting GdE in order to reverse the actual negative influences that prevail. _ 38 - Annex I .0 Page 1 of 3 Tax.s, Rovalties, and Earmarked Funds YPT I a) Royalties. The 12S royalty which YPF pays the Provinces on crude oil production is based on a 4referenced* price rather than the regulated producer transfer price. The *referenceo price in June 1988 vas US$18.55/bbl and the actual transfer price was only US$11S50. The burden on YPP for this royalty surcharge in 1988 was USSl36 million based on a production of 161 milllon barrels. The 12S royalty which YPT pays the Provinces on natural gas pcoduction is based on an outdated fuel oil price of US$16.68/bbl. YPF pays an equivalent of US$2.00/bbl royalty out of an equivalent USSZ.44/bbl which they receive for gas sales to Gas del Estado. b) Fuel Taxes. YPF charges thelr customers and delivers to the Treasury fuel taxes on petroleum products ranging from 65? on premium gasoline, to aS: on kerosene. this fuel tax -ias abcut USS2.5 billion in 1968 and if unchanged will average about USS5.6 billion annually through 1995. The National Energy Fund (FNE) receives 352 of the fuel tax and this in turn is distributed 30Z to Rational Electric Energy Fund (FREE), IO for the Special Fund for Electric Development in the Interior (FEDET). S3 to federal. electric utilities, and 252 to other energy utilities (Gas del Estado. YCF). C) EnernY Taxes. A 3? tax on the value of oil processed in the refineries is destined for the development of hydro power (Chocon PC=C) and a further 52 tax goes to the National Fund for Hajor Electric Worki (FNGOE). This tax is currently running around US$170 aillion per year. Gas del EZcado a) Gas del Estado's annual gross income of just over USS1 billion is only a quarter of YPF's gross income an their tax burden is correspondingly less. They have been given an exemption from capital tax until 1990 and have a loss carry forward on their federal income tax which will last until the end of 1991. as del getado acts as a tax collector for the federal. ?rovincia., and Municipal authorities. In 1988 they collected as follows: National L. VAT, Pension Fund, and Energy Fund (10o of natural gas sales). - 39 - Annex 2.0 Page 2 of 3 'Provincial 2. Taxes included in customers billings in Buenos Aires, Santa Fe, Rio Negro, Neuquen, and San Juan. Huicipal 3. Tazes included in customers billings in Buenos Aires, Santa Fe, Rio Negro. Salta. Cordoba. Jujuy. Tucuman. Sgo. de Estero, Chlbut, and Santa Cruz. Federal Power Companies a) The federal power companies are recipients from and contributors to a vatiety of funds. Reciiientst The federal electric utilities receive 352 of the Natural Gas Energy Fund, and 1002 of the National Funtd for Major Electric Works (FNGOE). Individually AyEg receives 652 of .he National Electric Fund (FUZZ) and Uidronor receives 1OOZ of the Chocon Cerros Colorados Fund (FCCC). Contributos-: A 52 surcharge on electricity sales gces to the National Electric Energy Fund (FUSE), another S2 surcharge on electricity sales goes to the Chocon Fund (FCC) and a third 52 surcharge on electricity sales goes to the National Fund for I jot Electric Works (TFOOS). 4. The irrational transfer of funds between the federal power companies and the various Znergy Funds in 1988 meant that the various companies paid an aggregate of US$135 million into the Electricity Fund (PUSC) but received a total of US$98 mlllion from the fund. from the rest of the Energy Punds the federal electric companies received an estimated US$364 million in 188. (See Annex I) Annex 2.0 -40- Page 3 of 3 Estimated Transfors nteo and From Energy Fumb 1936 USS *i I onI J$4nœw& £999 National Energy Fund (FNE) From Liquid Fuels 1188 Natural ps s0 To FNHE 128 FIDEX 48 Not. Electric Utilities 190 lalance to be allocated 87 National Electric Energy Fund (FNEE) Prm FN 126 Electricity Seles 01 To FEDES O Not. Electrc Utilitles 117 Balance to be allocted a Choew Core" Colorados (FCCC) Froe Electricity Sales 62 Oil Proceslng 141 -; Nat. Electriec Utilities 203 National Fund for MIjor Electric Works (FNC0£) From Electricity Sales 61 Oil Prolng 94 TO Fedral Electric Utiilties 149 to be allocated 6 SP CIl Fund for Electric Day. in the Interior (FEDEI) From FNE 48 FtEE so TO Prow. Electric Utilities 109 Allocated to Nation. Utilities and Yacyreta From FtE 190 F4NEE 117 FCCC ; P1N001 149 TO SECSA a6 AyE 171 HIORONOR 207 YACYRETA 149 Annex 2. 1 - 41 ~~~~~Pass I of I - 41 - Annex 2.1 Public and Private Enerav Investment Shares and Growth Rates PUMLIC AND ENERGY SECTOR INVESTMENS ( GDP) e----------------------------------------------------------______…_____________ 1967 1967/70 1970/75 1975/80 1980/86 1987 Total Public Expenditure 31.82 35.092 41.182 46.172 Current 24.12 26.742 29.75? 37.79Z Public Investments 7.2? 7.71? 0.352 11.43? 8.38? Investment in the Energy Sector 2.232 2.22? 2.742 3.46? 2.88? 2.53Z As Z of National Public investment 43.82 39.5? 44.2 44.5? 52.0? 51.6? As 2 of Total Public Invest,ment 30.97? 28.8? 32.85? 30.22 34.32 As Z of Public Expenditures 6.98? 7.822 8.38? 6.232 Annual rates of actual increase in real terms 1967/86 Total Public Investment 13.72 2.0? 4.12 -102 0.5Z National Public Invest. 12.31? -1.3? 6.62 -2.3? 1.8? Investment in the Energy Sector 7.82 2.32 6.22 -2.22 2.72 PUBLIC AND PRIVATE INVESTMENTS (Increment Rates) e----------------------------------------------------------__------------- Private Investment Public Investment 1967/80 12.6? 13.72 1970/75 1.8? 2.02 1975/80 4.8? 4.1? 1980/86 -14.72 -10.02 1967/86 1.42 -0.52 - 42 - Annex 2.2 ARENTINA PUBLIC ENERGY SECTOR PROJECTION OF FOREIGN ODET 1999-1996 USS THOUSANDS YPF GAS DEL FED. POWER YACYRETA TOTAL ESTADO COMPANIES 1/ 1909 TOTAL FOREIGN DEBT 5289 2112 4170 1820 13849 (of which current portion) 726 167 186 65 1086 1990 TOTAL FOREIGN DEBT 6077 2024 4866 2040 1850s (of which current portion) 560 182 le 64 994 1991 TOTAL FOREIGN DEBT 4865 1906 4407 2169 18449 (of which current portion) 6o1 161 284 70 1066 192 TOTAL FOREIGN DEBT 4025 1790 4421 2196 18084 (of which current portion) 561 161 275 64 1101 1998 TOTAL FOREIGN DEBT 4391 8459 4801 2196 14847 (of which current portion) 680 190 885 151 1586 1994 TOTAL FOREIGN DEBT 8975 1586 4116 2127 11756 (of which current portion) 651 190 s00 196 1006 1995 TOTAL FOREIGN DEBT 8646 1400 8067 2011 11026 (of which current portion) 848 100 B49 209 1501 1/ AyE, Hidronor, and SEGOA John A. Stoddert:mhc 7/26/69 Annex 3.1 43 - Page 1 of 2 iI~ I~ o -a S I~ ~ S: Sd 8 * _ 44 - Annex 3.1 Page 2 of 2 Annex 3. 1(b) COMPARISONS OF UNLEADED GASOLINE PRICES IN ARGENTINA AND OTFER COUNTRIES U.S. Dollar Price is for one gallon of regular leaded gasoline. (An asterisk follows a price for unleaded gasoline in countries where unleaded is more widely used). Argentina - (Sept. 88) $1.94 (Dec. 88) (Apr. 89) Australia 1.58* Austria 2.39* Bahamas 1.56 Belgium 2.24 Brazil 1.62* Britain 2.40 Canada 1.52* Denmark 3.26 Egypt .56 Finland 3.81 France 2.82 Greece 1.71 Ireland 3 4 Italy 3.58 Japan 3.39* Mexico .82 Netherlands 2.71* Portugal 2.83 Singapore 2.04 Spain 2.22 Sweden 2.77 United States 1.06* West Germany 1.84 Source: Lundberg Surveys' Prices of Eastern Hemisphere countries and United States published April 14: for Western Hemisphere. March 17. H Annex 3.2 - 45 - LPG Pricina 1. The LPG pioduced by YYP is sold to ODL at a transfer price established by the governmnt. In 1987 the transfer price was $45 per ton which was well below ODE's average production cost. For the smll plants, e.g. Canadon Seco and Caimancito, the production cost exceeded $130 per ton, but at the General Ceri plaet the production cost wae $86 per ton and at the Lowa La Lata plant it was $53 per ton. GDE's average production cost was $81.76 per ton. The differential between the transfer price YPF receives, $45 per ton, and the transfer price at which ODZ sells to LPG bottlers, $141 per ton, is another avenue whereby funds are transferred from YPF to ODE. In order to balance the payments from GDE to YPF, the transfer price should be set at a level which would at least ensure that YPP recovers all operating costs plus amortization and a return on investament. Th information is not available to analyze YIP's LPG production costs, but based on the volumes transferred in 1987 and the differential between YPP's transfer price and GDP's transfer price, YPF received the full transfer price, less the transportation cost of $19 per ton, they would realize an additional $18 million annually. 2. ODE sells most f the LPG to privately owned distribution companies which operate bottling plants but it operates two large bottling plants in the southern region where distribution is not economically attractive -for private owners. Table 7.3 shows the price breakdown at the wholesale and retail levels. GD1's sale price to distributors, which is set by the governmuet, was, as of December 1, 1968, $141 per ton (2040 Austral per ton at an exchange rate of 14.5 Austral per $US). The bottlers' platfom price, that is the price at which the LPG is sold to retail distributors is g275 per ton (4000 Austral per ton). The retail price is not controlled by the government and currently (December 1986) it is 4.6 - 5.5 Austral per kg. ($330 -$380 per ton). Competition between bottling companies is vigorous and currently -- according to LPG distributors -- retail prices are depressed. 3. Most of the LPG, 94S, is sold in 10 and 20 kg bottles by 5000 retailers to approximately 5 million individual domestic consumers for cooking and some space heating. They consume an average of 15 - 18 kg per month. There are about 12,000 comercial customers and two or three companies sell bulk LPG to small indust2ies and agrlcultural consumers for grain and tobacco drying. The government does not offer any promotional program to encourage LPG use and its use as vehicle fuel is prohibited. The LPG marketers would like for the government to institute a program to ancourage LPG use as a vehicle fuel in regions where natural gas is not available. The distributors collect the value added tax and ln some municipalities must pay local taxes which usually do not exceed 22 of the sales price. LPG Price Structure YPJ Transfer Price 45.00 S/Ton 1987 ODE Production Cost 82.76 $/Ton 1967 Bulk Transport 25.25 $/Ton 1967 Price to Bottlers 140.68 $ITon Dec 1988 Platform Price 275.86 S Ton Dec 1988 Retail Price 330-380 $/Ton Dec 1988 Annex 3.3 -46 - PaeIfo 1 Annex 3.3 Details of 813*'. Tariff System 1. Residential consumsrs are included in Tariff 1. which by May 1985 had four blocks of progressively decr asing rates plus a base charge. The blocks are fort ti) up to 20 KWh/month, (ii) from 20 to 250 KWh/month. (iii) from 250 to 325 Kwh/moth, and over 325 KWh/month. In practice, the two first blocks have a very Important weight in SEGBA's earnings, as they lnclude 96Z of clients and 882 of energy consumption. While the structure is sound, it has never been fully applied. To produce a mooth transition from the tariff system previously in effect, a progressive implementation of the new structure was devised but never realised. Annex 84 aIhows, on comparable basis, the residential tariff structure prevailing in May 1985 and in JanuLry 1989 which are compared with the "Theoretical, structure as approved In 1983. 2. While the average rates declined from May 1985 to January 1969 for consumption levels lower than 300 KWh/month, they increased for consumption levels over 300 KWh/month, which results in a transfer of income between affected group of consumers. Tariffs Increased the limit for the first block from 20 to 40 KWH/month and set the lImit for the second block to 250 MM/month. Annex 8.12 shows the actually applied rates for May 1985 and January 1989. This Annex shows that for a typical consumption of 250 KWh/month, the average rate of US$ mills 60 by May 1985 has decreased to U8$ mills 53 in January 1989. estimates of the total bill for consumers in every block *ad the Internal transfer among groups of consumers show that the almost 2 million consumers, who consuae between 100 and 300 KWh/month --562 of the total number of consumers-- saw their bills decreased by US$ 0.12 to 1.30 per month, while the remaining groups of consumers saw their bill' Increased. In partlcular, bills for the group which consumed between 500 and 600 ZUh/month licreased by US$ 11.42 per month. 3. The tariff applied to the medium consumero, mainly low tension industrial consumers --with contracted capacity between 3.3 and 25 KVA-- is structured with a fixed charge, which depends of the contracted demand and an energy price in two blocks; the first applied to consumption which does not exceed the contracted demand and the second for energy consumed over the contracted demand. This is a sound way to transfer the demand charges to consumers which impose additional demand on the system and thus precipitate the need for further investments in grid expansion. The current price difference between the twu blocks is 39Zt Rate variations between May 1985 and January 1989 for this class of consumers are small between 1 and 2S. 4. The tariff applied to larze industrial consumers is structured with a fix charge for demand which depends upon the supply tension --low, medium and high voltage.., thus reflecting appropriately the supply costs. Also power taken at off-peak hours are valued lower than the peak capacity and appropriate surcharges are included for penalizing the capacity factor --reactive energy. Energy charges also depend on the tension level and the time of day --peak, off-peak and night-. Annex 8.13 shows the tariff structure prevailing by May 1985 and January 1989. expressed in dollar term and using as deflator the 'indice de precios al por mayor'. It is demonstrated that even though price increases applied to the tariff sttucture are substantial, ranging from 4.3Z to 25.02 in real terms, the average rate increase for the consumer is lower than the increase in the tariff level --between 112 and 142. - 4-7 Annex 3.4 Page 1 of 2 Annex 3.4 Example Subsidies and Distortions in the Hydrocarbon Subsector 1. Distortions from Non-Recovery of the Value Added Tax (I.V.A.) Under the Argentine VAT (IVA) system, all Argentine producers of goods and services are allowed to pass-on, to the final consumer, the value added tax paid by them during the production-marketing process. YPF is not allowed to pass on or recover the Value Added Tax previously paid to its own suppliers. 2. On the average, YPF's annual costs are increased by US$'30,000,000 because of the exemptions imposed upon the inclusion of VAT in the sales price (SE) of most liquid hydrocarbons. Cumulative cost from 1981 through 1988 are over US$1 billion. 3. Forced Sales to Other Companies at Low Prices - In the intezest of promoting the development of other industries, which require hydrocarbons as feedstocks or, in some cases when only a service is involved, the Government utilizes YPF to sell its crude oil, natural gas, and products at prices which are fixed by the SE below the market price. Some examples are: a) Petrochemical feedstock - with the publication of Resolution 105/88, issued officially on August 31, 1988, the SE established the prices for liquid hydrocarbons, LPG and gases utilized or to be utilized as feedstocks by the petrochemical industry. Prices are not established through negotiation between buyer and seller. Resolution 105/88 fixes only one price for each product to be used for petrochemicals without any regard to the alternative uses of each product or refinery integration involved. If shortages of the feedstocks should occur, YPF is required to import them to meet its contractual commitments, but YPF cannot pass on the additional import costs. Based on the established prices as fixed in Resolution 105188, and the volumes which YPF is currently providing as feedstocks to petrochemical plants, the difference between international prices and those received represent a subsidy to the petrochemical industry of some US$68 million per year; but YPF receives compensation from the Treasury to cover this subsidy. b! Sales of LPG to Gas del Estado - YPF produces approximately 200,000 tons per year of liquified petroleum gases (LPG). YPF is required to sell all of its LPG to GdE at the low price fixed by the SE of US$55.92 per ton. ^-'E immediatelv sells the same LPG to the wholesale bottling plat- aF a price fixedJ bv the SE of US$163.17 per ton. This price differential amounts to an annual subsidy of some US$21 million. - 48 - Annex 3.4 Page 2 of 2 c) Sales of Residual Carbon (sponge coke) - Decree 2977 dated September 18, 1984, re-e3tablished a previous requirement whereby YPF was required to sell all of its production of residual carbon to Yacimientos Carbonlferos Fiscales (YCF) at a below-market price of US$35 per ton fixed by the SE. YPF must absorb the difference between the market price of US$52 per ton and the price fixed by the SE; this direct subsidy tc YCF amounts to over US$18 million per year. 4. Tax on Crude Oil Processed in Refineries - Law No. 17,574 fixed a tax of 52 on the value of crude oil processed in each Argentine refinery with the proceeds dedicated to the El Choc6n - Cerros Colorados Fund for hydroelectric development. A subsequent new law, No. 19,287 fixed an additional tax of 52 on the value of crude oil processed in each Argentine refinery with the proceeds dedicated to large hydroelectric projects. Based on the internal transfer crude oil price set by the SE for June 1988, of US$72.37 and the total volume to be processed by YPF during 1988 of 17,800,000 m3, this 1OZ refinery tax costs YPF about US$168 million per year, which presumably continues to subsidize the development of hydroelectricity. 5. Decree No. 1554/86 provided for the temporary importation of crude oil for processing in Argentine refineries, and then reexporting refined products with a higher market value. This measure provides the flexibility necessary to take full advantage of the new refinery conversion units. However, the 102 refinery tax, which applies to all volumes of crude oil processed, without regard to the source, effectively eliminates any possibility of this temporary importation of crude oil for utilizing excess refinery capacity, because the only result would be an economic loss. This refinery tax so distorts the economic balance that, if YPF were free to do so, it would be more profitable to export crude oil than refined products. 6. Distortions from Low Sales Price of Crude Oil to Other Refineries. The SE fixes the volumes and sources of crude oil to be processed by each refinery in Argentina via a distribution process referred to as the 'Mesa de Crudos". As all of the crude oil produced in Argentina is controlled by YPF, either from its own production or from its contractors, or purchased from private concessions, the SE established the allocations of crude oil that must be sold by YPF at prices set by the SE to Shell. Esso, and other small refiners. It is estimated *hat of the total crude *-l volume to be processed during 1988, some 25.5 MMCM, about 7.7 MMCM was aliocated for processing in the private refineries for subsequent products marketing by those private companies. At the estimated internal sales price of US$86.10 per m3, the private refineries paid YPF US$663,496,000 for this crude oil volume. If YPF had been free to export this same volume of crude oil at the estimated FOB price of USS10l t- CIM. it: would have received a total income of US$770,600.000. The differevnce nf ttSSl17.000.A00 was a subsidy by YPF to these private refiners. - 49 - Annex 4.0 Page 1 of 2 IMPLEMENTATION OF DEREGULATION OF CRUDE OIL AND OI1. PRODUCTS PRICES 1. Negotiating guidelines should be established for domestic refiners, crude oil suppliers, and international buyers of crude oil. A. For domestic refiners, the alternative cost for crude oil supply is the cost of international comparable ctude oil delivered to their location (CIF) port of entry, plus any local handling costs to deliver to their refinery. This is the highest they would be willing to pay. B. YPF's or other crude oil owners' alternative value for local crude oil is the international export value of comparable crude oil, less the international transportation costs to buyers location. This is the minimum value that YPF or other crude oil owners should be willing to accept for local produced crude oil. C. Negotiation of a price for comparable crude oil between the theoretical maximum and minimum values should also recognize term vs. spot commitme;.ts, the desirability of the crude to other buyers, and payment terms. 2. YPF must set sale guidelines for local produced crude oil not sold in the domestic market, which would be a candidate for sale to international buyers generally at a lower net value than domest!c sax.es because int.ernational freight to buyers location is subtracted. A. The maximum an international buyer would pay for local produced crude oil is the net cost to the buyer of a comparable international crude oil delivered to some international consumption reference point. less the freight cost to deliver the Argentine crude oil to the same consumption reference point. B. The minimum value for Argentine crude oil is some variable amount above marginal production costs, which is set by overall crude oil production and management strategy. C. Negotiation of a price for Argentina crude oil between the theoretical LtximUw and minimum values should recognize term vs. spot conmitments, the desirability of the crude to other buyers, and payment terms. 3. YPF must establish the full range of other commercial terms and conditions for crude oil purchases and sales to insure compatibility with international terms and conditions. The appropriate authorizations for negotiations of prices, terms. and conditinns for crude oil purchaseslsales must also be resolved. 4. Commercial rates for pipeline transportation and any marine transportation offered to YPF crude buyers must also be resolved and coordinated as part of an overall crude trading policy. A. The minimum rate is the actual cost to YPF. B. The maximum rate is the buyers alternative - 50 - Annex 4.0 Pag-. 2 of 2 5. The crude oil values "charged" to YPF refineries by crude oil owners must also reflect YPF's alternative market values to allow true assessment of YPF's economic role in delivering crude oil to market. Guidelines for internal crude oil value assessment must be established for each crude oil in each refinery to guide decisions on which crude oil to sell, retain for YPF's use# 6. YPF must establish long term objectives for each refined product and appropriate short-term and long-term product marketing strategies. The following examples demonstrate key objectives/challenges ir a competitive free market environment: A. YPF's fuel oil sales contracts should be totally restructured with local power companies to vary the price of fuel oil in competition with the international price (FOB) of comparable quality fuel oii, less any discounts required to meet local or international competition. Local power companies should be free to buy elsewhere. A key issue will be payment terms. The buyers should also seriously consider the many possible fuel oil quality reductions when it is made clear that they must pay for fuel oil quality. B. Domestic and international jet fuel sales and supply strategy will also have to be highly competitive, as all airlines will have access to real international source jet fuel alternatives. Control of local airport jet fuel facilities will be crucial to maintaining local market share. C. Pricing policy will have to be established such that motor gasoline sales will be discounted as producers act to avoid marginal dumping sales in international low price markets, and will rise as marginal international values become seasonally more attractive. Service, product quality, and price will become increasingly important to the effective marketing of motor gasoline in local markets. D. Gas oil marketing strategy will also have to examine internal competitive value versus international export value. With markedly higher government tax on gas oil, parity with motor gasoline at the pump is predicted and desirable. Domestic demand for gas oil Wi i fall. International margins for export sales may be better. Domestic product quality of gas oil can probably be diminished. - 51 - Annex 4.1 Page 1 of 3 CONTROLLED TRANSITION TO A NEW NATURAL GAS PRICING SYSTEM Step I - Argreements and Commitments from all Entities A. Explain in all possible detail to the Ministry of Economy, the Ministry of Works and Public Services (both at the Ministry level and to the Secretary level). GdE and YPF the proposed steps and appropriate actions necessary by each entity to effect the controlled transition from the actual natural gas pricing system to finally attain a free competitive market system. B. Finalize a comprehensive written agreement and commitment letter with each of these entities covering the details of this process, with time deadlines for the completion of all required appropriate actions. C. Define the tax revisions that will be effected, when these will occur, and in what manner each of the current recipients of these taxes on gas sales will be affected during the transition period and after implementation of the final alignment of prices with the lowest price alternative fuels. The entities are the national treasury, the provinces, municipalities, and certain pension funds. Responsibilities for proper coordination of these tax modifications should be clearly established. Step II - Increase Prices for YPF and GdE to Cover Estimated Current Production Costs A. Increase producer price to a level which is either a) based on the best estimate of current production costs for natural gas by YPF, and increase the transfer price paid by GdE to at least cover these costs, or b) a fixed percentage (60 to 852) of international fuel oil value. B. The royality paid to the producing provinces should be limited to no more than 122 of the actual transfer price paid by GdE to YPF. C. Based on the best estimate of costs for purchasing natural gas from YPF, gas treating, transportation, and distribution, increase the sales price to end users (or reduce taxes) to at least cover these costs of GdE. Retail price for natural gas plus taxes should not be increased above domestic fuel oil prices (including taxes). Annex 4.1 - 52- Page 2 of 3 Step III - Studies and Evaluation of GdE's and YPF's Actual Current and Future Costs A. Conduct the required detailed studies and evaluations of both GdE's and YPF's actual costs (excluding any internal social costs of these State companies) to define actual current and future costs of exploration, production, treating, transportation, and distribut4on of natural gas. B. Long-term investment programs must be included for proper depletion determination, as well as projections made for the new natural gas discoveries that will result from the exploration program. C. A procedure should be established for adequate periodic revisions of these detailed actual costs for consideration and use by the independent regulatory agency to be established. Step IV - Restructure of the Natural Gas Regulatory System A. An economic regulation system should be established. Each step in the delivery sequence would have to be monitored and regulated in accordance with prescribed regulations and rules. The first step would be to establish legislation which defined the scope of the regulations, i.e. construction of facilitiesi tariffs, etc.; the responsible organizat!in (s), and the extent of federal or provincial authority; and, the regulatory structure. B. The natural gas regulations should then be codified. Most countries have a code of regulations (Codigo de Electricidad) for the electrical power sector; a similar Codigo de Gas would have to be developed. C. An independent regulatory authority for natural gas should be established as defined above. D. Public utility type tariffs for natural gas gathering, treating, transport and distribution should be established by the regulatory authority based on the actual operating costs, investment recovery and a reasonable rate of return on all fixed investments. E. During the price deregulation phase-in period, the net-of-tax end user natural gas retail sales price to industrial users (industries, refineries, power and others where gas is a substitute for fuel oil) should be adjusted periodically to reflect the international price of fuel oil. F. The unified single natural gas ad-valorem tax rate should be established and implement. If necessary an excise tax on residential customers (above a certain minimum consumption) should - 53 Annex 4.1 Page 3 of 3 be implemented to bring the retail residential gas price (including taxes) up to the international value of kerosene (including taxes). G. During the price deregulation phase-in period, the wellhead transfer price for natural gas would be the net-of-tax end user retail sales prices, net of (1) the regulated tariffs for natural gas services between the wellhead and the end users, and (2) the unified single natural gas ad valorem tax to the consumers. During this price deregulation phase-in period, the wellhead transfer price for natural gas should increase as consumer retail net-of-tax sales prices are increased. GdE's and YPF's actual costs, as determined in Step lIl, must be utilized to ensure that appropriate economically efficient incentives are provided. H. The reference price for natural gas royalty payments to the provinces should be the actual wellhead transfer price for natural gas. Flexibility within the Petroleum Law allowing royalties between 5t and 122 should be used to enable continued production of marginal fields. Step V - Alignment of Natural Gas Prices with Full Value of Alternative Fuel followed by Deregulation A. Continue to adjust the net of tax sale prices of natural gas to approach or equal the delivered price of the lowest priced alternative fuel/feedstock. This would be 901 - 95? of fuel oil price for industry and power, plus differential distribution costs for residential-commercial users. If necessary for income distribution reasons, lifeline prices for low income households could be established and/or a supplementary excise tax for medium to large residential consumers applied. Step VI - Final Deregulation of Prices A. At such time that the natural gas supply and regulatory system for setting transport and distribution margins is in place and functioning in an acceptable manner, and domestic fuel oil prices (which natural gas is linked to) then are deregulated and essentially equal to international fuel oil prices, implement a final free competitive market system with deregulated retail prices for large industrial consumers and where the wellhead sales contracts can be negotiated between the natural gas producers and purchasers. B. Implement a windfall profits tax on existing gas production if necessary, to capture windfall revenues in excess of natural gas investments requirements and reasonable return on investments. - 54 - Annex 4.2 Page 1 of 1 Reforming Institutional Arrangements on Ga3 Production and Transmission 1. At present YPF is the sole seller of natural gas and GdE is the sole purchaser. The gas produced by private companies is bought by YPF at a negotiated contract price and resold to GdE at the transfer price set by the SE. This system has two principal faults. First, it interposes a third party between producing companies and the buyer and second, it requires YPF to sell natural gas at less than actual cost. The transfer price is less than YPF's production cost 8o it also loses money on its own production. It is recommended that the buyer, whether it be GdE or other purchasers, be free to negotiate directly with all producers. The existing law grants GdE the right of first refusal to purchase all gas, but if GdE does not offer a fair price the producer should be free to negotiate with other customers. In addition, if GdE is the sole transporter it could exercise its monopolistic position to force producers to sell at unfairly low prices. Therefore, the producer should have the right to install its own delivery system or to purchase transportation service from GdE at a fair price (this must be regulated). 2. At present all of the natural gas sold to ultimate end-users is transported to the city gate and distributed by GdE. Decree No. 385 provides that municipalities, private companies a- ' mixed public/private companies may distribute natural gas through local urban networks but GdE would continue its role as the only gas transporter in the country. If the existing laws permit, producers should be allowed to negotiate direct sales contracts with local distribution companies or large industrial consumers. GdE should not be allowed to use its monopolistic position as the only transporter to limit access to its pipelines. However, GdE would have the right to charge a reasonable transportation tariff and to impose reasonable operational requirements (with approval of the regulating iuthority) 55 - Annex 4.3 Page 1 of 2 Cost Based Tariffs for Transmission and Distribution 1. The tariff established by GDX or other retail sellers of natural as should be cost-based and established using public utility tariff-setting methods. GDE's existing tariffs are differentiated by class of service and (to some degree) by the transportation distance. This structure should be continued and expanded to include categories of firm industrial anid interruptible customers. This would allow the retailer to index che interruptible tariff to competitive fuel prices or to negotiate interruptible service agreements with large customers who might otherwise switch awav from natural gas. 'When establishing the retail price to residential customers, it may be necessary to provide some mechanism to assure that low income consumers are able to receive natural gas. A tariff based on 'fully allocated' costs may result in gas prices which the low income users could not afford. There are a number of ways to deal with this problem. They are briefly described below: - The most direct method is to ^tilt' the tariff so that a portion of the costs are allocated to non-residential consumers. This method is often used in industrialized countries to shift some of the fixed costs to larger volume industrial consumers. - Lifeline or subsistence tariffs could be established. In this case the first increment of use, that required for subsistence, would be priced at a very low level. All use which exceeds that level would be priced higher and would recover the remaining cost of service. This has the disadvantage that high income consumers also benefit from the reduced price. - Energy stamps could be used. The low-income consumer would receive vouchers or stamps which could be used only for paying for natural gas. They would be redeemed by the government and the utility would recover all service costs. - Service lines and appliances could be supplied at no charge by the government. A large portion of the distribution cost is the cost of installing pipelines to serve the customer and the appliances which would have to purchased. In some countries, such as Colombia, the government has undertaken a program to provide free cooking appliances to LPG users. A similar program could be initiated in Argentina. 2. A complete cost of service and tarification study will be required in order to determine the best option and to allocate all costs correctly. - 56 - Annex 4.3 Page 2 of 2 3. An interruptible service agreement is somewhat different from the programmed interruption program now used in Argentina. Under an interruptible service agreement the customer's deliveries can be interrupted on short notice and they must provide their own stand-by fuel. This means they must have dual-fuel capability or be willing to shut down operations when interrupted. There are a number of methods for designing an interruptible service tariff. It is normal practice to assign some of the fixed costs, usually gas acquisition costs and some portion of the cost of the larger pipelines, to the interruptible customers. A detailed cost of service study would be required to determine the appropriate type of tariff and the prices to be charged. - 57 - Annex 4.4 Page 1 of 1 Netback to Producers from Reformed Pricing System 1. When well-head price controls are phased out and the royalty and tax structures are changed, YPF'a revenues will increase significantly. Table 8.1 provides an illustrative calculation of the impact of the revised pricing structure, based on GDE's 1987 sales and 1987 operating costs. It is assumed the retail price would be the international price of the lowest priced fuel consumed in each market sector. The retail price bases are: - Residential market. The price of imported kerosene, $147 per ton plus a transportation and marketing margin of $37 per ton. The retail price of natural gas to the residential consumer would be $131 per MCM ($4.62 per MMBtu), well below the economic net- back value of $200 per MCM. - Commercial market. The price of imported gas oil, $154 per ton plus a transportation and marketing charge of $25 per ton. The retail price would be $127 per CM ($4.50 per MMBtu). This also is well below the economic net-back value of $203 per MCM. - General industry. The export price of heavy fuel oil (HFO), $103 per ton plus a $20 per ton handling and marketing charge. The retail price would be $87 per MCM ($3.09 per MMBtu). This is essentially equivalent to the net-back value. - Power generation. The dame as general industry. 2. Using these retail prices and GdE's 1987 sales, the total revenue generated would have been $1,459 million. From the total revenue GdE's operating costs, $347 million, is subtracted. GdE's estimated operating cost is based on historical data and may not provide reasonable return on invested capital. The VAT is calculated at 152 of revenues to be $219 million, and also subtracted to establish the net revenue, including royalties. A fiLeld treatment allowance of $5 per INCM ($87 million) is subtracted as is the royalty payment, calculated as 122 of the well-head proceeds to be $86 million. The producer's realization, net of all cost and sales taxes would be S720 million. After allowing for field use and losses, the unit revenue would be $48 per MCM ($1.70 per MMBtu). Based orn the proposed gas pricing structure, YPF's before- income tax revenue would have been over $400 million higher. The additional revenue resulting from the sale of gas from existing fields at the higher price could be used for new gas exploration and production or returned to the government as taxes or dividends. The cost of producing new gas will be higher than the historical cost so the margin will decline unless international energy prices increase correspondingly. This system would encourage producers to operate efficiently and minimize co-tq. thereby increasing profitability. Page I of 1 41 S st~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~- -='' |,~~~~~ifAobd I n4,A 20 A C IAO | 5\ ___ ______ - 59 - Annex 5.2 Page 1 of 1 U6L7tIU - EI8?0lJ Of WLLS DUILLD (191 - 1988) (Ios drille by 1 and eteam) -WlLs Drilled by 1ff- -tells Orilled Oters- -total Wells Drilled- gal. DBoel. Total lipl. DoBel. Total 1pl. Donl. total leer 1917 132 475 607 11 70 81 143 54S 688 1978 84 533 617 0 225 22S 84 758 84 19179 71 41 562 0 204 204 71 695 766 1960 104 581 66S 7 267 274 1-11 848 9S9 1981 86 596 682 40 2U1 269 t26 825 951 1982 75 736 8l1 34 98 132 109 834 943 198 117 749 866 16 14S 161 133 894 1,027 1984 136 809 94S 0 75 75 136 884 1,020 1985 10 776 916 it 87 98 1St. 863 1,Ot4 1986 94 467 561 0 160 160 94 627 721 1987 92 680 772 1988 89 683 772 -60 - Annex 5.3 Page 1 of L i* rEIS& - ClOD! OIL PROIDCtIOI 516101 & IM1I1 1018 (1977 - 19188) (Crde oil produced by 1P Idas, service contracts, concession L isport) -11! Crude Oil Prot.- Cosacssious laports total Avail. -Oe livered--rot Ida. Coatract total Crude Oil tn lefiin. Prir. Ref id. I I3 .3 o3 3m3 ,3 m3 3 c3 3 13 1977 18,786 6,063 24,849 193 1,435 27,477 20,365 7,S90 1978 17,790 5,219 26,009 244 1,954 28,207 20,415 1,129 1979 18,276 8,185 27,161 274 1,487 28,912 21,057 7,509 1980 18,368 9,802 28,170 401 I,IS2 30,323 21,312 .7,865 t181 18,189 10,196 21,355 448 1,029 29,862 21,034 8,337 19182 18,494 9,425 27,919 532 715 29,166 19,740 8,816 1983 19,367 8,495 27,162 612 0 28,474 19,000 8,532 1984 18,t7 8,344 27,141 698 0 27,839 19,086 8,121 19185 18,tS0 7,721 25,971 704 -521 26,154 18,234 8,030 19186 16,8S 7,726 24,582 597 -115 25,064 11,151 7,577 1957 15,967 8,311 24,278 579 -11S 24,742 16,976 7,449 I988 17,036 8,503. US,539 570 -464 2S,64 5 11,257 7,744 - 61 - Annex 5.4 Page 1 of I U6UTIJI - JU RlL GAU PIODOCTIGI 1 UTILIUAIO3 lIlTOl? (1977 - 19188) (katual gau produced by F1 Ads. & service coatracts) -0 lNatural 6a Prod.- - G ses of Iatural Gs Produced- d Md. Contuact Total Sell 4 1ell Others ia.inect Consued flared am 3 ml 63 NN 3 ma a Im MN m3 m3 Na 3 Teat 1977 10,1t3 1,418 11,531 6,556 71 676 994 3,234 1978 9,782 1,664 11,446 6,202 73 SO0 1,020 3,1SI t179 10,939 1,606 12,545 7,329 8l 236 1,013 3,1825 1980 11,330 1,873 13,203 8,001 79 4U2 t,1tt 3,550 1911 11,059 2,227 13,286 8,2S1 66 838 1,165 2,966 ;982 12,129 3,013 IS,2t2 9,699 66 953 1,241 3,253 1913 13,572 3,SQ2 17,074 11,S92 67 1,012 l,2t0 3,193 1984 tS,2916 3,354 18,6S0 12,719 72 860 1,317 3,682 1985 16,033 3,079 19,112 13,115 76 826 1,442 3,653 1986 16,205 2,977 19,182 14,230 91 497 1,449 2,91S 1987 15,695 3,433 19,128 14,569 f02 477 1,430 2,550 1988 est. 18,370 4,325 22,695 17,420 107 558 1,468 3,142 Note: The volue of matural gas consed includes shrinkage resultiAg from the esttaction of G I uatural guoline. Annex 5.5 - 62 - Page I ofl IGEU?INA - PRODUCTIOU OPUATING COSTS of IPF ADNIRISTUTI03 - OIL & GAS (IlI values are O85hillioaS exezpt ptoduced voluus * var. unit costs) lear 1988 Tear 1989 Average IPF Total Espnses (Imcl. Ad. Overhead) Personnel Exploration, Dtilling & Productiotn 413.7 5 324.8 5 169.3 efininqt trasportation & Marketing 5 226.9 $ 207.7 S 217.3 materials & Services txploration, DrilliAg & Production 3 504.4 5 481.5 8 492.7 Itaialmg, Transportation & Marketing 499.1 5 4S152 $ 487.2 Total £ pesses: t 1,6144.1 $ 1,488.7 5 1,566.4 TnI Total nvestuents (Imcl. Ads. Overhead) 1Eloration, Drilling A Production $ 502.9 5 610.0 5 556.5 1etifimg, Transportation & Narketing $ 230.7 5 33.5 S 280.6 Total tnvestanat: 5 733.6 5 940.5 $ U37.1 TIF Total Auual ixpenss and auetuents: 5 2,377.1 3 1,429.3 5 2,403.5 TtI Production (by VPT Adtiaistratioa) Cude Oil, I3 17,036,000.0 16,404,O00.0 16,720,000.0 Iatural oas, N I3 20,526,000.0 25,088,000.0 22,807,.000.0 1 ids. Oil & Gau Production Operating Costs for £xploration, Drilling & Production Personnel Expes (fixed) 3 413.7 $ 324.8 J 369.1 Materials & 8ervices Expense (variable) S 504.41 481.0 9 492.7 Administrative lnvestatent (find) 5 56.9 f 34.2 1 45.6 (1) Filed Op1rating Costs, per year 1 414.9 (2) variable Operating Costs, per Unit of prod. 2/3 for Production of Crude Oil , 5/.3 S 19.6 1/3 for Production Natural Gas, sil aI 5 7.2 (1) Invutnents - Oil & Gas Operations, est. Estiuated Direct lnvest. Note: All of tie tiove YPF budget costs excludo paymetu for contractors oil lnd asu production, taxes, royalties and interest. - 63- Annex 5.6 AiglITINA - INCUINITIL PlOD. COSTS (MUWINN EXPOIT less N~~ININ SPPLY) Page 1of I 9A8 10 ON P? 8QUITS (1988-1989) & ME 1986 EVNIS PLUN (1989 - 2014) - rude Oil Prod.- - at'l gas Prod----- -cost of ?- -Cost of P- Incremental Minimum Mani.. 01ff. Minimum Mlimu fliff. min. Costs Nal. Costs Prod. C4sts N .3 N I3 N aS Ma .3 MN 233 N a)1 ussuillion USSaillion U8lmallaon 1989 25,691 25,69w 0 26,174 26,174 0 5 2,246.0 $ 2,363.5 $ 117.5 1990 26.,164 26,317 153 26,406 27,975 1,569 5 2,383.4 $ 2,868.6 5 485.2 1991 24,572 27,153 2,581 28,904 28,904 0 5 2,335.1 S 2,817.3 5 482.2 1992 22,950 27,708 4,758 30,572 30,880 308 5 2,265.3 5 2,830.2 $ 564.9 1993 21,494 28,195 6,701 30,572 33,240 .2,668 5 2,151.7 $ 2,822.6 $ 615.9 1994 20,245 28,621 8,376 30,572 35,070 4,491 8 2,093.1 $ 2,873.3 £ 780.2 .1995 19,177 28,913 9,816 30,572 35,300 4,718$ 2,023.9 $ 2,917.8 5 893.9 1991 18,255 29,319 11,064 30,572 36,240 5,668 $ 1,963.3 $ 3,056.9 S 1,093.6 1997 17,510 30,704 13,194 30,572 38,170 !,598 5 1,919.6 1 3,158.5 S 1,238.9 1998 16,896 31,916 15,020 30,572 37,835 1,263 $ 1,856.4 $ 3,189.2 S 1,332.8 1999 16,434 32,976 16,542 30,572 39,280 3,708 8 1,824.1 S 3,219.0 S 1,394.9 2000 16,105 33,904 17,799 30,572 40,299 9,727 S 1,823.4 $ 3,323.5 S 1,500.1 2001 15,954 34,717 18,763 30,572 41,000 10,428 S 1,347.5 $ 1,790.4 5 442.9 2002 13,960 30,377 16,417 30,572 41,000 10,428 $ 1,275.8 $ 1,672.6 $ 396.8 2003 12,215 26,580 14,365 '30,572 41,000 10,42k $ 1,208.8 S 1,565.5 S 356.7 2004 10,688 23,275 12,587 30,572 41,000 10,428 $ 1,146.2 8 1,467.7 S 321.5 2005 9,352 20,350 10,998 30,572 41,000 10,428 $ 1,080.8 S 1,371.4 S 290.6 2006 8,183 17,806 9,623 30,572 41,000 10,428 5 795.4 $ 1,059.1 S 263.7 2007 7,161 15,581 8,420 30,572 41,000 10,428 1 775.4 S 1,015.5 $ 240.1 2008 6,265 13,633 7,368 30,572 41,000 10,428 S 757. $ 977.3 5 219.5 2009 5,482 11,929 6,447 30,572 41,000 10,428 $ 742.5 $ 943.9 S 201.4 2010 4,797 10,438 5,641 30,582 41,000 10,418 S 729.0 $ 914.7 S 185.7 2011 4,197 9,133 4,936 30,582 41,000 10,418 $ 717.3 5 889.1 $ 171.8 2012 3,673 7,991 4,318 30,582 41,000 10;418 $ 707.0 $ 866.7 $ 159.7 2013 3,214 6,993 3,779 30,582 41,000 10,418 $ 698.0 $647.2 $ 149.2 2014 2,812 6,118 3,306 30,572 41,000 10,428 S 690.1 5 830.0 S 139.9 Totals: 353,446 586,418 232,972 784,680 981,367 t96,687 8 37,561.9 55S1,651.5 $ 14,089.6 RPV 0122 70,819 45,986S 5,637.0 Note: Vith an average incremental cost for natural gan of US$18.58 per N a), then the portion of total incremenaUl production costs that correspond to the 196,687 NM . of incremental natural gas is equal to U8S3,654.4 million. Production costs include all inesitments and operating casts. The balance of total incremetal production costs, 05510,435.2 million correspod to the 232,972 1 .3 of incremental cnude oil, for an average Q854.79 per aS (08$7.12 per bbl.). With bath volumes and incremental costs d4iscounted at 121 per-year, ind the same inicremental gas cost, crude oil then has an average productiou cost of 08367.53 per iS (08510.74 per bbl.). - 64 - Annex 5.7 A11g?TIIA - INCUNINTAL It? INCONI (UIIlU m19ou1 less NIIN SUPPLY) Page 1 of 1 Uso 01 TIn 1916 EEll? PLUB / 60S INlls. I fit. COS1 (1989 - 2014) --Crude Oil Prod.- -Nt*l Gas Prod- -Not lnoe From Prod.- Ninim alzimu Oiff. Niaiu Nuil Diff. inisu Maliuu Siff. m3 0 N3 11N e .3 NIN *l NN *3 88Sillion USSuillion USuillion 1989 25,691 25,691 0 26,174 26,174 0 S 1,946.2 $ 1,917.9 -218.3 1990 26,164 26,317 153 26,406 27,975 1,S69 S 1,904.7 $ 1,731.6 $ -166.1 1991 24,572 27,1S3 2,581 28,904 28,904 0 S 1,890.6 S 1,902.9 8 12.3 1992 22,950 27,708 4,758 30,572 30,880 308 $ 1,857.9 5 2,052.3 $ 194.4 1993 21,494 28,195 6,701 30,572 33,240 2,668 5 1,806.8 S 2,237.0 S 430.2 1994 20,245 28,621 8,376 30,S72 35,070 4,498 5 1,729.4 S 2,337.3 S 607.9 199S 19,177 28,993 9,116 30,572 35,300 4,728 S 1,674.0 S 2,367.8 S 693.8 1996 18,255 29,319 11,064 30,S72 36,240 5,668 $ 1,627.7 $ 2,367.0 $ 739.3 1997 17,510 30,704 13,194 30,572 36,170 5,598 S 1,588.3 $ 2,451.4 S 863.1 1998 16,896 31,916 15,C20 30,S72 37,835 7,263 S 1,573.4 t 2,635.1 S 1,061.7 1999 16,434 32,976 16,542 30,572 39,280 8,708 S 1,S54.4 S 2,793.8 S 1,239.4 2000 16,105 33,904 17,799 30,572 40,299 9,727 S 1,529.0 $ 2,875.4 $ 1,346.4 2001 15,954 34,717 18,763 30,572 41,000 10,428 S 1,813.3 S 3,921.4 t 2,108.1 2002 13,960 30,377 16,417 30,572 41,000 10,428 S 1,672.4 t 3,S70.8 S 1,898.4 2003 12,215 26,580 14,365 30;S72 41,000 10,428 $ 1,553.6 S 3,268.5 S 1,714.9 2004 10,688 23,27S 12,S87 30,572 41,000 10,428 S 1,453.9 $ 3,008.2 $ 1,SS4.3 200S 9,352 20,350 10,998 30,572 41,800 10,428 5 1,377.9 S 2,792.0 t 1,414.1 2006 8,183 17,806 9,623 30,572 41,000 10,421 S 1,554.8 5 2,894.8 S 1,340.0 2007 7,161 15,581 8,420 30,572 41,000 t1,428 $ 1,464.9 S 2,652.1 $ 1,187.2 2008 6,265 13,633 7,368 30,572 41,000 10,428 5 1,386.1 $ 2,479.0 5 1,092.9 2009 S,482 11,929 6,447 30,572 41,000 10,428 5 1,317.2 S 2,327.6 5 1,010.4 2010 4,797 10,438 5,641 30,582 41,000 10,418 8 1,257.0 S 2,195.1 $ 938.1 2011 4,197 9,133 4,936 30,582 41,000 10,418 $ 1,204.2 5 2,079.2 $ 875.0 2012 3,673 7,911 4,318 30,582 41,000 10,418 $ 1,158.2 $ 1,977.7 5 819.5 2013 3,214 6,993 3,779 30,582 41,000 10,418 5 1,117.8 $ 1,889.0 5 771.2 2014 2,812 6,118 3,306 30,572 41,000 10,428 S 1,082.5 S 1,811.3 S 728.8 totals: 353,446 586,418 232,972 784,680 981,367 196,618 540,096.2 S 64,543.2 S 24,447.0 Notoe: 1) the net vlihead value of crude oil is USt16.50/bbl. (U01103.78/m3). 2) the net nliltad valu of produced ut tural gin is US$1.25 per Ncf (US$44.11 per 11 W). 3) lot incose results frau gross incomu less total investmeAts, contract oil and gau production costs, and !PF Ads. operating costs. 4) Th not effect from *Coupre Argentino' and 'Contrate Argentine' on the investents, umterials, and contract services that 9F omuwt use in its zxploration, drilling, and producisg opetations is estinated to result in an iacreasd cost of at least 40S. Us 601 value used herein for thse costs deonstrates the significant ecotohic effect on net incoves. - 65 - Annex 5.8 Page I of 2 Investment Requirements for the Next Five Years 1. YPP projected investment requirements, based on its five-year action plan, designed to supply the projected internal demand for petroleum products and natural gas during this period on an annual basis are as follows: Production Requirements 1989 1990 1991 1992 1993 Nat'l Gas, MM m3 20,877 21,389 23,412 24,716 25,481 Crude Oil, M m3 26,291 26,225 26,330 25,868 25,303 From Concess. M m3 600 550 500 460 500 From Contract X m3 *9,287 8,823 8,787 8,016 7,134 From YPF Adm. X m3 16,404 16,852 17,043 17,392 17,663 Develop Wells Needed 597 645 654 653 653 2. YPF's 1989 Budget calls for a total net investment of US$906,454,000 in providing the production of crude oilsand natural gas a shown above. This amount includes US$41,336,000 financed for the refinery conversion project, and US#$231,410,000 financed for the GUTA project. Excluding these financed projects, YPP's actual investment for 1989 is budgeted at US$663,708,000. - 3. In 1990, most of the remaining investments financed for the GUTA project, US$112,605,000, will be utilized, and therefore, the actual net investment by YPP during that year will be approximately US$782,000,000. for each year, thereafter, YPP's investment budget will be about US$700,000,000 in order to produce the volumes shown above for the respective annual periods. 4. For comparative purposes, the actual net investments by YPF during 1987 were US$850,731,000, and during 1988 were slightly reduced to US$833,960,000. In both years the net investments included those amounts financed under the GUTA and the refinery conversion projects. 5. The annual volumes shown above, and the estimated net YPF investments for the corresponding annual periods are only minimum requirements to satisfy the projected internal demand. Therefore, the five year program is demand driven, and other than attempting to maintain investments to a minimum. no other economic considerations have been included. Since the Government's policy is to not produce additional hydrocarbons for the export market, YPF is limited to only meeting the internal demand objective for crude oil, refined products and natural gas production. 6. Nevertheless, YPP's obligations, under the 1986 Energy Plan was required to follow a much larger level of investments in exploration and development activities during each of the years 1986-1989: (cost estimates are based on YPPFs actual 1988-1989 costs for these activities) -66 - Annex 5.8 Page 2 of 2 Seismic Exploration Development Eat. Tptal Year Lines, Wells Wells Investment, USS 1986 21,800 198 700 852 million 1987 21,800 198 730 871 m!llion 1988 21,800 198 835 941 million 1989 21,800 198 894 982 million Totalt 87,200 792 3,159 3,646 million 7. However, the actual exploration and development investments made by YPV and private companies from 1986 to 1988, and those programmed for 1989, show little relation with those specified in the 1986 Energy Plan, and have actually been as followst Seismic Exploration Development Est. Total Year Lines km Wells Wells Investment, US$ 1986 10,141 94 587 515 million 1987 18,580 92 880 620 million 1988 10,128 97 656 570 million 1989 15,491 95 678 496 million Total: 54,340 378 3,001 2,201 million 8. It is important to note, that the 1986 Energy Plan projected an increasing level of exploration and development activity from 1986 through the year 2,000. By 1996, some 250 exploration wells would have been drilled each year, with a total annual investment in exploration and development of about US$1,300 million. By the year 2,000, these investments would have increased to over US$1,500 million. Based on the actual esperience of the first four years of implementing the exploration and developmiet investment programs, during which time the number of exploration wells drilled was 414 less than programmed, and the total investment was short by US$1,445 million, it is evident that the financial limitations of the Argentine Government will only permlt YPF to provide for about one-half of the specific investment requirements for the hydrocarbon sector. Therefore, significant investments by private petroleim companies shc ld be required to be implemented, urgently and by all possible means, if te Energy Plan is to accomplish any of its future objectives regarding the crude oil and natural gas sector. - 67 - Annex 5.9 Pane 1 of 12 Annex 5.9 1. In this Annex are approximate English translations of four documents: 1. Section of Law 23.697 on changes in crude oil and natural gas royalty payments, 2. Hydrocarbon Deregulation Decree 1055g Upstream deregulation issued October 10, 1989, 3. Hydrocarbon Deregulation Decree 1212, Downstream Deregulation issued November 8, 1989, 4. Decree 1589, issued December 27, 1989 - 68 - Annex 5.9 Page 2 of 12 TRANSLATION Law No. 23.697 Economic Emergency Law Approved September 1st, 1989 Issued parcially Sept. 15, 1989 CHAPTER XII Petroleum and Natural Gas Royalties Art. 32: The following paragraphs should be incorporated to Art. 1st. of Law 23.678t 'To calculate the royalties to be paid corresponding to July 1989, and successive payments, the 'wellhead' value that results from the application of this law should not exceed the international price of petroleum that will be its reference, which would correspond to that prevailing the month before the payment calculation is made for, and could not be either less than 802 of such price' "Such international price will be the average of the official export prices FOB per cubic metric of the following crude oils: Arabian Light, Arabian Medium, Kuwait, Tia Juana Light and Bonny Light, as published by Platt's Oilgram Price Report in the column OSP of the world Crude Oil Prices table, expressed in U.S. dollars, prevailing the immediate month before the production being appraised' 'For the conversion of this average expressed in dollars per cubic meter to australes per cubic meter, it will be necessary to take the exchange rate prevailing at Banco de la Naci6n Argentina at the closing on the last working day immediately before the day the transaction was made for paying the royalty, "To determine the reference price for natural gas, the value to be used will be 701 of the value obtained for crude oil as determined using the procedure indicated above, on a a caloric equivalence'. Art. 33: The following should be incorporated into Law 23678, as Articles 2nd and 3rd; Art. 2nd. - The authority of application will proceed to discount from the reference price, as established in Art. lst., the expenses incurred by the producer to accondition the crude oil and natural gas for markating" Annex 5.9 -69 - Page 3 of 12 "The discount thus established could not exceed the international values recognized par marketing under similar conditions, as long as these do no exceed 4? of the "wellhead value as determined under Art. 1st. above". The Executive National Power, with the participation of the Hydrocarbon producing Provinces, will modify Decree No. 1671/69, with the purpose of making such decree more adequate to the one established above" Art. 3rds Yacimientos Petroliferos Fiscales Sociedad del Estado, or other concessionaires will calculate the obligations of the National Government, in favor of the Provinces for the payment of royalties of crude oil and natural gas, using a 121 rate to be based on the values resulting from the application of the above described articles' 'The Provinces could opt and agree with the Secretary of Energy for the total or partial payment in crude oil, petroleum products or natural gas of the corresponding royalties, which they will have the free disposable for their marketing within the country or abroad" Art. 34s 'During the 180 days, to be counted from the effective day of promulgation of this law, for the calculation of royalties of crude oil, it will be possible to take 80 of the international price determined as indicated in Art 1st of law No. 23.678 (text modified by this law), and for natural gas, 70? of the international price of crude oil, at its caloric equ_.valencefn Annex 5.9 -70- Page 4 of 12, It i he N al Govnmets consern to bnce_s ede te StWs cr i ntave sio in maste such e fixing of pdics margins bourn.s, quouta etc. replacng the man by Ins - arhs mobschnm. The Naiona Govarnnn's Palsy ia ragard hydroabons I basean pen_udiw dw lain as whole ctivity, ths oading to a" emupeium sd bhc reft ltsaon .9 puica& b Is dh Governmen' intention to- Introduce tbhus chagnw as qicl - Poss ibeIn acdan_ Wi d a poy, the f dasposal of hyroarbon pductio obtained under tw above mentiod chas is prdd Or. Such e" dipol re t local mareing " we a r exportation parposm e applo o the frging exloat, exploitaion HYDROCARBONS DECREE No. 105S/89 ad dweelopmt schem requir -etig tims for each of the viowu Au vld, tu eurg peroman. In view at Law 17319 sad MM w'd Articln, 9,10. and 11 of law 2366 and ate 2, 6, 11, 9$W A U ad 06 of law 17519 ve te E utive Bnch with The Nadiol Govenment ha decded to promoe th emaptnc on th subJet. reativatido of the xplato, o hydrorbon by mas_ NOW TERFORN, of Inrang the potducio el currently operaed by THE REINT OF THE ARJGNTIE NATION YJP`Z DECREES AS FOLLOW&S Soe D oss opeat by Y.P.F. yield a low production a want of inahtivit ove and exteded perid and/or ARTILE Hrby1, atcs8, 9, 10 and 11 of Law 23.690 s -_otaon and atdl 2, 6, 11,t a96d 98 of low 17319 a regulated, to orde So reacivate and inaue th producto of such delaing as of fist pority and necesty th promotion, marina Gelide, n exploitation c ha be devsd developmnat sAd eecution of plans Intend to increae so a to pvid for thw eoctiv and diret pacpatio d the local production of liquid and gaseous hydrocearbons prvat Iaet Inclh by-products, in ardw to ensur local self- LIwise, in tos ollields operted by Y.P.T. yielding a sufficieny and an adequate agin of reserve, achieve full highr prduction it Is nece_ay to att a highe development of petrochemical industries and attain recovery of oil thmugh th adoption of tbniques of exportable surplus, favouing the industrialization of associated production, reource at soue location. Such techiques require the supply of modern technoloU A XICLE 2 AREAS OF SECONDARY INTEREST: Fcr and economic and financial means concurn with the the purpos of the enforcement of article 98 of Law 17.319 develipment of oil field in asoiation with Y.P.?. Y.P.P. will, within a period of forty (40) days as from the The foregoing prposd sctemes for the reaivation of effctive dat of the present dece, urnish the ENERGY hydrocabon prduction will remult in the collection of an SECRETARLAT with all existing technical information expoitatin or sociation f", the rate of which will relect concerning the eas that have the following the fild's potential, Its curnt level of production, itA charactetistice: surtfa installations and rmlted technical information a) those which to the effective dae of the preent decree avaible have remained inactive for five (5) or wore year. The foregoig procts, cal for a clasification oth field, b) thos in which the average daily production, during hen it is coered convenient to group them into areas, 1988, has not exceeded two hundred (200) cubic meters of so a to encourP the exploration, exploitation and oU. developnt of the aos a a whole. The ENERGY SECRETARIAT will within the next 40 The paricipato, in th production phase of the days following the submittal of the information, grant proiil States b considered a nsnea of attaining approvl for th inclusion of the areas in the program; econ_omc develpmnt and a stop towards the achievement YP.?. will within tgm (10) days a of the gr.nting of the of an activef tfedrasm apprvl, return to the Stat -by way of abdication- the approved ares. Annex 5.9 - 71 - Page 5 of 12 _aie oplettlea aow (obls) dat wh do Pubis hUMs,, ass.ch. we unbl obJect of adeas In ae for bdo awaidea In pXes as In tw 1tWuaon compete Bids Ieae, tm In Wh* V.P.P. Is attally caryIn o reeiA to In ade s In aeowdnae Wi the tar of embamd wa w m da I neso lwoyae amluedA bur the arc III at low 11810. -_ - UdoW_AS AREas OF BDIHAC RECOVERY: V.P.P. ude the duerlist th do RGY Wii tht (SO) da Of th - Mettv dae at te prsen S rAZIAT a wihin a tIms o forty (40) day as dMe Y.P.? mulk INfoS th ==RT SCRETARIAT urnthe M date of e present d will group the about th developmet progra n d Investment hlsoltal mm (feld( ) mtabldhd in artfice 2, so a to budgt ed fo with respec to tose fid not sha a f *h eplor and expotaIo of put up for tender In cordane with th osboe st out in hyoecabons, wIch wm be approved by reoution ottf. toh present deeroo, ENEGY SECTE . IL 10: Within ni (90) days of th ective dae A?Ig&L iVthdd tddsy (30) days r tho grantings o the pmst der YVP. wM cal gr Intentoal of the _prvat areas referred to in atIcle 4, th Competite Ds In ode t sel do lodca o fre ENEtaY SECRETARIAT wil cal for InteatIoal private compan/ls W m the w l enter into Compitiv for their exploration, development and c or aclae wit regard to th aew or filds explot In tbu folowing mnners Anho d by the ENERGY SECRETARIAT, for the. a) dh am wi be awwded to the bidder olfg the purp of edntrutIng bsgat teonomlelly possible highe exploitation fee. The hMINISY OP WORKS volu o bydresbom eurIng thu op_mlsaton of the AND PUBLIC SW/RVICES my, at the poposal of the ial actleo ao In tu In Ad awn or field. ENERGY SECRETARIT, declare th ndr unaward ATfCLR 11: Companies interested in amacitn with * a rsult o th disadvantageous ntu o t hi bd. Y.P. must offr in the bidIng procedur a cas payment submitted. by way of aoatlen Am. b) In oder o drmIne the fee the bidde wiU take Into a) The bidding conditlen wi specf thi paticipation account the remainig rsves and the invesmets pernta ad th responsibility of the associated effcwd In te area. comay In rspect of the opeatio of ech are or field. c) paymt o the e itation feo mut be made In cah, b) The pwtIcIpatin companies smut offr atte-of-ths-.t befoe ety Into the a, to the NATIONAL tehnology aceording to the obJective staed in the TREASURY, who wil pay four pecnt (4%) to Sth foreoing artUcle, shing ppr evidence of txpernence respective provincdal State as an advanced paymet of and economic and nandalt standing. corresponding royalty. c) Amogt the companies meting the requirements stated d) the hydrocarbon produced by the pantee of the in th above pargrph b), the awrd will go to the tendered ara unde the trms of the prest artici wil comnpy that offe the highet amount by way ot be Orey disposable. asotidon fee. e) th term do the concesson contact wiUl be that d) The assiation will be constituted pursuant to the sipulated by Law 17319. method so out in Secdon 11 of Chapter III of Law 19s50 ) In the case pvied for in article 2 paagraph b) of this (rtated tet 194). decrern contractor wll asume the obligation, durig the a) The mimum trm of the contrct will be twenty-frvd e thre yaw as of the cimmengement date of the (25) yer. eontract, of yiding n annual production of hydrocabons AICLE It-1 The total amount of the asciation fee must that s no bml thansighty percent (80%) of tho voluma be pd in cash to the ENERGY SECRETARIAT by the produced by Y.P.. in the yea immediaely preceding that grntee within sven (T) days of the comrmencement date of th receptin of the area. of the contrat. 6IU I± The exploitation arew (fields) rev rted to tbh ATICZ IS: As compensaton the emciated company Ntionl Stat purunet to afti;le 2, will be directly wIl reciv from the production of hydrocarbons the grasd to th successW bidders of tendon envisaged in pentagw eorponding to its associaton, which will be rIkle 5. freely disposable. A?ZS 3 Participation In the International Call for ARTICLE 14 REGARDtNG TUIE FRE DISPOSAL OF Did. praides fo in article S will be conditional on the I YDROCARBONS: The hydrcbon obtained from bidd fitusbhig sufficient evidence of technical eoacsen regulad by the Natonal Minin Code will be quallikatons, selvenc and financial standing. fey dispobl of a hunde and eighty days (10) bum the effective dat a tha prnt der. Annex 5.9 Page 6 of 12 -72- rmeI to la es I, pespwa d), a" is 1 Us do wd Sawme It 14 Elba pre-at dsu wlh avumedyellewlag MUA. C _U TMU AREAS or regul1M PW3OATORY Dl3U3T Y.P.. Wl dwet to es a) _e a" be hub usobsa In lu.. ad frlg aN_ I Sat, witi t (15) da W et t ef e dnctiv mabs wiM b m.dI IrgltomI oe.da Ofb psusat is... wus own as ret ber wbat b) Acess to do slwo or mass dsashlwAhed 1I ankle U of Law 13119. Wt the _movem, age sd &hPama as tEs eompals with epti oths to dte us d ubjeg matt of inmdnal vaue wi be auted fr the compan. In firs a rllo fo bui sA wawa in p r oce. c) pmeat d hab oyalt on the bydro of mr 1'r lb purpiss so Oat In t artce, th sMr d_Isp shall ba bo. by ahe co=paies. in codanea establsd In a"tc9l Lw ILM1 wI be calculated s with th prvsls establusd by the ENERY bern do dat d the dem ordeig ab revaton tr USRTARIBLAT. _semmat lo a ea In fou d Y.Pr'. am guato ARTI 10L.IL CONCERNING TS1 EXPLORATION to bontrar beig h rby spis CONTACTS: As f td effective da o the psnt US=& OONCRNIN TM D3UGUATION Of deem hydrocarons obtained under cntrc TM INDUSTRIY: Witn fts (1) da a om the rrespondItg ta t ift Rhund eo 8ids et out in deet date dam ma as abaIISR S 01 Dom_e 148/S11 a'd 633/$7 will be bosy dbspw WCONOMY Ad PUOf C WOREO AND SEVICES The be diposa wl be conditional upo th acaptam mst ubmi* a Wesi d espta p_ogred - of thd rduco of te terms for proasn ad deegulato S thdiuy b_isi d ba 1h at d the exlatIon a propoasI by Y.P.P. nd appovd by heo pow pi= o hrocabo poduetbe, I of the ENERY SECRTARIAT. c0ntr'S so sad N squtai prtspads In the AR ILna17 CONCERNINma OREICN TRADE We d o ae l an ON that i gusa from all roasom reae to supply to toe ll m ar id, duly bs st that coatrlbute to Its fsmt_n Tb. progm wched for by the compan to theENRY t be drwn up must at fot objocte NW ten as d a ISCRETARITZ the later y au owrisd bmprt o o propr follw-up mahmim or by-produsb required. ARTICLu 2i The MN rY 07 PUDUC WORKS AND A8339LmU The Buha mntOind In t proviso of SERVICE at th proposal dof ENERGY arIcle 2 paragrap c) f Law 175174 ad ankle 2, SECRTARIAT aprovWe the idding Conditons for paagrph b) of Law 19267 applicbble on 703 prc of the Exploitaton Concons - wel a the constitution of crud os t an prosd locally. is fixed a a rawt of companis associations sad a otmr form of agrcment 0.1%. entered into by Y.P.F.. as provid for in the presnt Oiba 'tmporrAiy Impoate into the county fr deee. proces_ng. with the intetion of re-exporting th by- ARTICLE 24 Let It be pubished, delivered produec al a incesed value, wil be exmptd from to h Natlnal Registry and Ied. payment of the wmtureag. In h lar ca _ c ot eoly th, oil but the by-products alo wi ha exmpt km any export or impert duty. ADTILL hi CONCIRNIN¢ THE HYDROCARBON PRODUCING PROVINCES: The hydrocarbon-producing pr 1ov Stats actin in association with loca or forein private comPane wIl h qualified to participat and be gte In the tender procsdin of aeas located In their ten. hIMSMGL3J Any expoitation aris (fields) abandoned or hwin scany ves, may he asgned to the provindal SBta In w_ trdiy they am locad, without payt_ of t exploitation fee. The provincial Sta will decde wheher to exploit We arew by themselve or In ssociat with pdvat loea or foreign compaies. The MI rY 01 PUBLIC WORKS AND SERVICES, hrou th ENEOY SZCRETARIAT, wau authorisa the Annex 5.9 73 !Page 7 of 12 leIatin. In all cuss, tho convasion will be conditional on the ECUTIVE BRANCWS approval which will be prcede by the opion at the ENERGY SECRETARIAT. Contrwt executed punrsut to the roeme at Der 1443/8S, as amended by Deee 623/87. ar excluded from ths foregoing prvisio. The MINISTRY OF PUBUC WORKS AND SERVICES wil within a ter of a HUNDRED AND EIGHTY (160) days. set ot the pdicy to be followed in thb ca of said contracts that mwSt be compatible with the pdrincpls laid down in Deem No. 10S5/89 and in the prseut dec Once the abovemtioned tam of SIX (6) monts expires. YPF wil submit the prceedings to the ENERGY SECRETARIAT, who wfll ptope to the contractors the meaur qond appropriate fo the r-etablishment of the economic finandcal equilibm Should thbi not be possible and sdoud jusifie reasons of r_______________________,__________ public or fsal interet eit that obstret the continuance DECREE NO. 1212/89 of the rpctive cOntrts, the Ener Sctaoiat win ecide on the logd menau to be adopted fw sucb The proceds d thm tansatIo wi be paid into a AMAlCILJ1 DEREGULATION. The objective is the spea account at the iMISTRY OF PUBUC OF derlation at the Hydcarbons sector. for wbich pupoe WORKS AND SERVICEL reatim awe ablisbed so as to favou mrket The multianoul investment progms at YPF wdi bc meabim in t xing d prices, alloction of amounts finaonced, prior appovl of the ENERGY SECRETARIAT tran value and/or disonts in the vius stes of by meas of a charg to sad cot, contributing ih this the tWvity. way to the incea of th compay's net wth. ABTI.CLL2 COMPETITION. The authorities win AIt4 FREE DISPOSAL The od produced by ORter the eotece ot true and fair competitio under the now concessin holders and the pectoa Wual coditions for all th companis that operate in the corresponding to the private partner wil be freey sc, whoth State mowd Ot pdvae, fo the benefit of disposable in accordance with article IS of Decree No. the gnal intet and the o 1SS/89. An at shol be made to improe the dfiency nd A RL:.& TEMPORARY ALLOCATION OF pro4ctiVe Maloction in the Seco, thus esduding the CRJDEL The ENERGY SECRETARIAT will continue to Mae tran c of revens betwen in components as an allocate crude in accordac with the ytem in oce, as objectiv fi the deregulation, for wcb pupose prime wi indicated in Annex I at the proet decreae up to December be diete towar the of export neutralIty. 31. 1990, unles a production volume is previosy reached WV Wi ptimbe the integrtin of its activitie in equivalet to EIGHT MILUON (8,000.000) cubic mters ealdilom of autonomy that wi ensure its efficiency and pr year o oil of free diposl. As from that time the competitlve in equal conditions witb private aIcation of q.ot# of crde wil bhe eiimated and the oil. eompiaL owned by YPF, wil be freldy diposale. in accordance with artide 15 ot Decrem No. 1055/59. ARIUILk EIXTNSION Of P FREE MARKEr. YPF is bby instrucd to neWotiato within a ATICLE 6: FR IMPORT AND EXPORT. The p d Of SIX (6) months, with the parties to import of rtde oils and its bypoducts wi not require bydcrbon elotito4, prductio and extraction pio autholiatioo nd wil be exempt frm import dutie eitrcts in fc, unde the tm of which YP is until expiratio of the team or fulmt of the condition dblgad to reive the extrctd hydaros. the sated In artidce 5 of this decree posib convi of id ontrots to tbh conceosio at Thereafter the impot d cr oil oand of its by-pioducts aocation $yste regulated in LAW 17.319 Ad rlated will be subject to the geon tart poicy. Annex 5.9 _74 - Page 8 of 12 As regards the export of crude oil Aad its by-products, the ARTCLE LLi REFINERIES. The installation of ENERGY SECRETARIAT will pronounce itself over the additional refining capacity will be free with no further expert authorization within a maximum term of SEVEN requirement other than the compliance with the safety and (7) working days, as ftom tbe date the application is filed, technical rules established by the general regulations in upoM cOdclulon od which the export authorization will be force. deomed as automatically granted. ARICLE 12 ESTAEIUSHMENT OF OUTLETS. ARgCzE 7 TRANSITORY REGIME. During the When the tem or condition set out in article S is fultfilled, period d transition the current tariff levd as well as its the installation d new outlets will be free, subject to the price structure will be maintained in force, unless the safety and technical rules established by the ENERGY MINISTRY OF ECONOMY should decide to use the SECRETARIAT. authority conferted in article I d Decree 110S/89. ARTICL13i TRANSITORY REGIME. The system hM7Lgg&L TRANSITORY TAX REGIME. Within in force for the authorization of outlets will be maintained SIXTY (60) days as from the effective date of the present until the condition for the fre installation of new outlets is decree, the MINMSTRY OF ECONOMY and the Met. MNISTRY OF PUBLC WORKS AND SERVICES wUi submit to the EXECUTIVE BRANCH a proposa for a tax ARTICL U1 FREE OWNERSHIP OF OUTLETS. system to be applied during the transition period. There wil be free ownership of the outlets when the term or condition provided for in article 5 is fulfied. The ARTCLE 9- PRICE FREEDOM. At the end of the owners must comply with the tequirements of technical, tnition period oil prices wil be freely agreed. The prices commercial and economic competence established by the of oil by-prducts in their various stages will aso be appropriate authority assming all the liabilities arising f 1eed1The MINISTRY OF PUBUC WORKS AND from the service SERVICES vi the ENERGY SECRETARIAT will propose Within a term of SIX (6) six months the ENERGY a reme of adequate compensation for the steady supply of SECRETARIAT will define the enftingements and geogrphically distant aa of the country. establish the regime of corresponding sanctions AIITICI PRICES OF NATURAL GAS. Once the &MICEIS: PRESENT OUTLETS. The existing tnsitin period is ended, the prices of natural gas to ownen of businese for the retailing of fuels may be eonsme and prdues will be fixed monthly by the included in the regime of free ownership when their present MIMSTRY OF PUBUC WORKS AND SERVICES via contracts expirm the BNERGY SECRETARIAT untD such time as market conditions of multiple bidder prevai. ARTICLE- 16: SAFETY CONDITIONS. Compliance The sal price of natural gas to industry power stations with national provincial or municipal regulations will be of and the commecial seetom wil be NINETY PERCENT the exclusive responsibility of the company owning and/or (90*) of the average price of fdoil in the month retailing the fuels. The provincial States and municipaiities immetd y priotr, at calori equivalent, wil exercise the policing of the outlets and will prant the The ptice of comptr d natura ga will tend to be authorization for use if applicable. betwean SEVENTY PERCENT (70%) and SEVENTY As f(om the date of efectivenes of the free ownenhip FIVE PERCENT (75%) of the averae price of the gasoil regme any other prior allocation of responsibility will be in the montb immediately prior, at caloric equivalent, extinguished and any povisions contrary to the regime The pice tO riddmtial coners wil be determined on envisaged hereinabove will be repealed. the basis of the price to the producer plus the cost of ceWditioni0 transport and distribution. In cases where a ARTICLE 17 QUALJTY. The individual or lwe price for idential consumers is required, the corporation that is the owner of the identifying trademark tamt cresonding to the subsidy will be distinctly of the outlet will be the only one responsible for the exprsed and chargd to the generd revenue, quality and quantity of the products and that same should Tfe prie to the prducer w*i be fixed on a net back basis, conform to what is advertised or prmised. witb tranot and conditioning costs based on Verification and contrl wil be the responsbility of all the intenational value agencies that exercise authority in the area of 'fair - 75 - Annex 5.9 Page 9 of 12 d t an_ d o the ENERGY ANNEXI SECRRTAT. ALLOTMENT OF QUOTAS OF CRUDE OIL PRODUCED BY YPF AE A IhUMINATION OF RESRICTONS. The MINISTRY OF PUBIUC WORKS AND SERVICES will sbit, withn a period of THIRTY (30) das a drdt 1- Durng the transition and until a total production law prpoing the diminaton of the limitatis set out in volume of TWENTY SEVEN MILLION (27.000,000) cubic articles 23 (second paragralp) and 34 (scond paragaph) meters per year of crude oil of domestic origin is reached of Law 17,319 in oder to faciitate the conversion of pro- the distribution will be effected on the basis of the existnt contracts to the eime set out. in the present percentges arising from the aellowing annual volumes. derea and promote the participation of the greatest effective a of the fourth quartr of 1989. number of companies in future calls for bids Until the effective date of the legisation referred to in the precedidAg paSagraph, the limitations contemplated in Law MM3/YEAR 17,319 wiIl be applied according to the regulation set forth in next YPF 19,020 puaphb ESS 3.450 Ia order to calculate the limitations set forth in atides 25 SHELL 3,280 (seod paragraph) and 34 (second pararsaph) of Law ISAURA 960 17,319 whe the holdGr of an explortion permit or tn SOL 160 xpiotation concessio is organiea either as a separate DAPSA 130 corporate entity or as a Temporary Union of 27,000 Companie (*) or n association, the abovementioned its shall be exclusively applied with respect to the a-pa,Ste entity Ot the Temporary Union of Companies as a The quotas of SOL and DA1SA will be understood as who prvided that in aU case the same members are fixed. The allocations will co0template1 if possible, the maintainance of habitusi qualities to esch refiner. ARIT& I REGULATIONS REPEALED BY PRESENT DECREE As from the date of enactment of the The quota of SHELL indude ONE MILLION THREE et decree, the provisions incuded in deeest 337/83 HUNDRED AND FIFIY THOUSAND (1,350.000) cubic and 690/81 and in Resolutions MOSP 510/83 of the metes per year, fixed, of crude Neuqueo - Rio Negro for Mitry of Public Works and Service and SE 6/879SE the elaboirttio of lubricants 55/86, SE 702/83 end SE 194/89 of the Energy In the regime in force, the quota of crude toresponding to Secretariat re epeale YPF includes the THREE THOUSAND AND THIRTY As km the date of commencement of the dectiveness of SIX THOUSAND (336,000) allocated to AsTRA. and YPF the rgme freeg prices, the following regulations are supplie poducts to CGC and ASTRA, situation that will repeed De 2233/84, 2404/84, Resolution MOSP be maintained during the transition period. 649/82, 1OSP 439/83, OSF 649/83, MOSP 629/84 of As ftom now on, it wiUl not include any supply whatsoever th Miitq of Public Works and Services. Resolution SE to ISAURA. 174/86, S 177/86, se 105/87. SE 437/88 and SE 7/89 of All conditions of delivery wil be those stated in Resolution the Eney Secretrit. SE 621/85, as up to date. As from the date d commencement of the regime freeing the establishment of outlets set out in article 12. 2- Volumes exceeding the total production of crude. Resolution SE 125/71 is repealed. domestic origin of TWENTY SEVEN MILLION (27,000.000) cubic meten per year is asocated to YPF. (T) al ton note: Legal form of joint venture provided 3- The volumes of crude oil freey disposable must be for in artidce 377/383 t Corporations Law 19,S50. deducted from the aUoted quotas as per this Annex, in orde to maintain an adequate balnce in the tefining capacity. - 76 - Annex 5.9 Page 10 of 12 DECREE mO. 1569 ISSU¢D ON 12127189 IN VIEW OF LAW 17319, Decrees 1055/89, and 1212/89 and CONSIDERING: That Article 3 paragraph 2 of Decree 1212/89 exempts contracts under Decree 1443/85 modified by 623/87 from the regime and establishes that HOSP will fix the policies for said contracts in accordance with the principles of Decree 1055/89, establishing a period of 180 days in which to do this. That it is in the Government's interest to establish clear and definitive rules to guarantee the stability and legal rights of existing contracts in the petroleum sector. That the so called "Houston Plan" contracts resulting from Decrees 1443/85 and 623/87 have shown to be suitable for attracting investments for the exploration and later development of hydrocarbons. That the first four rounds were reasmnably successful and resulted in the undertaking of considerable investments. That the letter and viirit of the above mentioned decrees in the context of deregulation supported .y the Government's petroleum policy should be applicable to the "Houston Plan" contracts in that which concerns the principle of free disposal. That there is a need to achieve this as quickly as possible to eliminate any uncertainty among those companies in the "Houston Plan". In as much as Article 3 of Decree 1212/89 has established that MOPs will fix the policy for those under the "Houston Plan" the following regulations are now issued. Article I. On the exploration contracts. Option at declaration of commerciality to.come under the "free disposal" regime of Ley 1055/89. YPF is instructed to included this clause in the contracts if requested by contractor. Article II. On the preference for gas purchases. G de E must reach agreement with producers who wish for "free disposal" of gas within 30 days of receiving an offer from the producer. The preferential right of G de E to acquire the gas will expire within 30 days. In that case, the producer may dispose of the gas under the terms of Article 15 of Decree 1055/89 and Article 4 of Decree 1212/89 and the complementary rules established in the decree. Article III. The export and import of hydrocarbons. The export and import of hydrocarbons and products is authorized and these will be exempt from all duties, tariffs retention present or future. These operations will not benefit from repayment or reimbursements now or future from - 77 - Annex 5.9 Page 11 of 12 the effective date of this decree. Export documents will be authorized according to Article 6, para. 2, Decree 1212/89. These documents can cover a single transaction or a program of exports of liquid hydrocarbons but cannot be for more than one year. Article IV. Exchange Rate. The exchange rate to b? used to settle the local currency portion of the export and import of petroleum products will be the selling rate quoted on the transfer of USS by the Banco de Argentina at the close of operations on the day preceding the settlement date. If there are more than one exchange rate, the one which better reflects the real exchange rate will be used. The Central Bank, jointly with the Ministry of Economy, will establish the arbitration procedures to b)e used in agreement with the concessionaire. Article V. Free Disposal. Producers with the right of free disposal of crude oil, natural gas or LPG in accordance with the terms of Articles 6 and 94 of Law 17319, Articles 14 and 15 of Decree 1055/89, and Articles 3 and 4 of Decree 1212/89 and producers who in the future opt for this will have free disposal of the foreign exchange established in the tenders and/or renegotiations agreed in the respective contracts. Whether the hydrocarbons are exported - in which case producers will not be obliged to bring in the foreign exchange corresponding to said percentage, - or if sold on the local market - in which case producers will have access to foreign exchange corresponding to said percentage. But in no case will the foreign exchange component excede 70Z. The disposable foreign exchange will be in effect for all exports of crude oil and for products derived from the refining of freely disposable crude. For the conversion of the percentage of foreign exchange due, the exchange rate mentioned in the previous Article will apply. Article VI. Restriction on Exports. In case the Government establishes export restrictions on crude or products Article 6 of Law 17319 will apply under which the producers, refiners and exporters will receive for each barrel no less than the value of crude and products under similar circumstances (prer mably FOB prices). Where restrictions apply on the free disposal of gas, the price per mm3 (of 9300 BTU's) will not be less than 35Z of the international price of 34 API Arabian Light. The Government must give 12 months notice of export restrictions. The exchange rate to be used under this clause is that of Clause 4. Article VII. Transport of Hydrocarbons. The owners or concessionaires of oil lines, product lines, etc. are obligated to transport as long as there is capacity the hydrocarbons belonging to third parties at the same price for the same circumstance. Until there is competition in the pipeline business the S.E. may fix the transport costs as provided for in Article 15(b) Decree 1055/89. Article VIII. Interchange of Crudes. - 78 - Annex 5.9 Page 12 of 12 To effect a rationa. utilization of pipelines and better handle the available production YPF and the producers :an agree on crude swaps. Article IX. Pipeline Transport Concessions. In accordance with Article 39 of Law 17319 the Government may, when necessary, authorize pipeline concessions including tanks and pumping stations subject to general laws and technical norms. Those companies with existing contracts will be substituted by what YPF authorizes in its role as owner of the area under Article 28 and in accordance with Law 17319. The steps necessary to obtain the rights in accordance with Article 42 and the Mining Code must be taken through application to the AUTHORITY with the obligation to advise the decisions adopted by the mining authorities where pertinent. This regime will be applied to all future contracts in their different kinds. Article X. This regime will be applicable on all future contracts what ever their nature. Article XI. From this date the dispositions of Decree 6220171 are abolished. JAStoddart:mhc February 16, 1990 - 790 -79- ANNEX 6.1 Page I of 2 EVALUATION OF YPF AND PRIVATE REFINERY CAPACITY a) Total topping capacity stands at 710 thousand bbls per day, with YPF, ESSO and SHELL controlling 97 percent. b) The small private refineries are relatively unsophisticated, filling special niches in the market. c) YPF plays a dominat ro , with 62 percent of topping capacity and 68 percent of bottoms conversion capacity. However, &lmost 15 percent of YPP's topping capacity is concentrated in 'topping only refineries, and it is not clear whether all of their production sees efficient conversion as feedstock in other refineries. In addition, the capacity of La Plata, the largest refinery, currently includes topping units which are grossly inefficient and ineffective even for processing light crudes. d) Nite average vacuum capacity, as a percent of topping capacity is 41 percent. This would have to be increased, if local refineries wish to efficiently process heavier, Imported or domestic crudes, either for their use in the local market or for exports. e) The total bottoms destruction capacity of YPF's two largest reflneries provides them with efficient capability to produce higher yields of clean, higher value products through fuel-oil destruction. In this regard, YPP refineries have a clear edge over the ESSO refinery, and both appear to be better off than S-RL. However, a closer look at SHELL overall refining operations, versus the others, leads to the conclusion that SELL has the potential to be more profitable in current operating conditions, and, marginally, could be more capable of handling heavier crudes. f) The SHELL refinery has greater vacuum capacity than both ESSO and YPF, which means that SHELL can effectively handle heavier crudes without by-passing processing steps. The SHELL ref!nery also relies heavily on visbreaking to further reduce fuel oil yields. SEELL's refinery reliance on catalytic cracking is just under YPF's capacity to produce gasolines instead of distillates. SHELL clearly has a different strategy than ESSO to reduce fuel-oil, while pursuing higher conversion. SHELL's reforming capacity, as a percent of topping, is the highest of the three in Argentina, and almost twice that of YPF. Thus, SHELL is best positioned to produce marginally more motor gasoline than its competition. - 80 - ,AMN 6.1 Page 2 of 2 g) ISSO and YIP have similar refining strategies, in that they rely less On visbreaking and more oan coking to reduce fuel oil production. This would be viable, if there is an economic outlet for coke -which has not been the case In the over regulated Argentine economy, which has price i coke low to subsidize the national coal company (YC?). The combination of hydro-cracking and catalytic cracking capacity, in YPF's refineries, gives them an edge over both ZSS0 and SHELL In total capacity, but 3880 is the strongest as a percent of pipe still capacity. h) YPF controls significantly more refoming capacity than any other company, however, as a percent of topping capacity, the YPp reforming capability is still weaker than the rest of Industry. -81- ANNEX 6.2 Page 1 of 3 INEFPICIENCIES IN PRESENT REFINERY OPERATIONS 1. The term 'Production Barrel^ is used to describe the relative coposition of refined petroleum products produced by a refinery as a function of crude oil thoughput. This approach clearly provides an indication of the actual performance of any refinery in producing higher valued, higher quality cleaner products, as opposed to lover quality products. The results of a complete analysis of the situation, using this approach, shows that the collective impact of sector regulations, operational restrictions and pricing practices, have acted to prevent full optimization of refining yields, and also provide a complete picture of Argentina's present refinery situation and historical performance. However, this analysis should be valid only to show relative trends, but not the absolute economical situation. 2. The primary role of a refinery is to convert crude oil into finished products required by the market. The physical facilities existing in a refinery, the severity of refining operations, the intrinsic natures of the crude oil feedstocks, and the desired qualities of the finished products required by the market, all act to set the relative yields of finished products. Under normal conditions, a refinery operator manipulates all of these variables to maximize refining profits. This has not been the case in Argentina and, thus, there are significant discrepancies between Argentine conditions and international standards. 3 A knowledgeable marketer of refined products would allow to operate his refinery only if it is less costly than buying the required products in the open market. In the past 10 years, significant worldw.ide refining capacity has been shut down, mainly because the refineries could not compete with the purchase of finished products. As a consequence, many export refiners, including the relatively sophisticated refineries located in Rotterdam, have operated with low or negative margins in recent years. However, this has not been a factor up to now for the inefficiencies detected in the sheltered Argentine refining industry . 4. Disregarding the lack of incentives to fully optimize the cost of refined products brought to market, or to optimize refining operations, even if less expensive finished products could be purchased, it is obvious that the Argentine refining industry has gone through a virtual revolution, when 'Production Barrel' statistics are reviewed, as we will discuss below. 5. The relationships between clean and dirty product yields are simple and generally valid indicators of increasing refining capability to produce higher quality products, through a combination of capital investments. operating changes and blending discipline. In Argentina. between 1970 and 1986, the percent of clean product yields increased from 50Z to 71Z . This was almost a 50Z improvement of clean products for all the industry, and YPF refineries rose from 452 to 70, while private yields rose from 56Z to almost 74 Z. This indicates that private industry refineries have been the leaders in this regard, but YPP performance has been equally important. The improvedyields in the next few years, steming from the new conversion facilities, could be as good or better than those .of the private refineries, if YPP fully utilizes the economic potential or the new facilities. - 82 - Annex 6.2 Page 2 of 3 6. A more detailed analysis of product yields, analyzing each product by product pool, shows the same trend as the simple clean versus dirty products review. However, following this detailed analysis, it becomes evident that the yield of gas-oil (Diesel, in international trade language), was the clean product with the largest growth over the study period. Industry production went from under 17? to over 35S, between 1970 and 1986, and the trend was continuous. During the same period, YPP's yield of gas-oil went steadily from 172 to almost 362, while private yields rose erratically from 16? to just under 352. Accepting that private refiners are usually more responsive to economics, than YPP has ever been, then YPP's steady growth had more to do with production quotas than refining economics. 7. Overall Naphtha yields (Total of regular and premium gasolines, plus aviation gisoline) also increased slightly over the period, but the pattern was highly erratic for all industry. Private refineries show yields which are significAntly higher, both at the beginning and end of the period under study, but still show about 10 percentage points higher than YPP yields over the same period. This analysis doeu not permit an exhaustive evaluation of refining margins, but these yield analysis and other studies, which will be pointed out in this report, lead to the co4clusion that YPP refining operations have not been as profitable as those of private refineries. 8. YPP's yields of jet fuel and kerosene are presently twice those of private industry refineries, although YPP started out with a lower yield in 1970. This conclusion is consistent with recent market share data. However, earlier diagnostic studies indicated that YPF could easily increase its jet fuel yield by 25? to 30S,-or about 1,000 cubic meters per day,-at the expense of gas oil, if international sales or export markets were pursued. Similatly, an equal volume is probably currently downgraded by private refiners. From this, it appears that the refining industry is artificially limited by local self sufficiency concerns, but with increasing access by the private sector refineries into the domestic jet fuel market, the private sector will most probably swing their refineries to capture as much as possible of this better market. Therefore, unless international trading is deregulated, this competition from the private refining sector for the marginal domestic jet fuel barrel will just cause a downgrade in both YPF refineries yields and profits, with minimal national benefit. In this restricted local market scenario, the growth in YPF jet fuel yields, from 45? of the volume produced in 1970 to 86? in 1985, could be significantly reversed. 9. The Argentine industry for lube oil production has increased yields from an average of 1.17? to 1.37?, however, private yield growth has been stronger, in the range of 1.27 to 2.01 X. while YPP yields have ranged between 0.89? to 1.372. Although the volumes are low, but the profit potential is significant. mainly because there is a strong possibility that the overall lubes qualities have not been fully exploited. A diagnostic evaluation of YPP operations shows, that 60,000 cubic meters of lube stock, or a 30? increase in YPF's production over 1986 volumes, is possible. This would further reduce fuel oil yields, since significant marginal lube oil stock production is in effect degraded to the low value local fuel oil pool, when the lube oil stock has an international trading value that is about twice that of gas oil. The required investments for upgrading the facilities for lube oil stock production have a potential DCF in excess of 100?. 83 - Annex 6.2 Page 3 of 3 10. The yield of the largest volume of the so-called dirty products (Fuel-oil and diesel) went steadily down from 302 to less than 29Z during the study period. YPF's production dropped steadily from 54S to 30SZ, but the private industry refineries yield was reduced even more, although erratically from 442 to 26Z. Further review of the data, from 1986 through the present, indicates that the private sector yields have decreased even further, as their market share dropped, which also indicates that the private refineries have the ability to optimize their profit even on the basis of highly regulated prices, while YPP is less adept at adopting the necessary changes, mainly because it is forced to a great extent to perform its social obligation, and contributes to subsidize the power sector, where margins are low, as recent market conditions indicate. - 84 - AamaK 7A AVERAGE INCREMENTAL COST CALCULATION FOR GAS 1. Ezploration costs must be included in the analysis and recovered over the productive life of the fields which were discovered. In many, if not most cases, exploration programs are undertaken to discover oil so it might be argued that the cost of gas exploration is near zero. However, in some gas-prone regions natural gas is the target. As the Argentine economy becomes increasingly dependent on natural gas, new reserves will have to be discovered so it is reasonable to assign some portion of the exploration expenses to natural gas. YPP has proposed to carry out an extensive exploration program over the next ten years to increase the natural gas reserves. They propose to conduct seismic surveys and drill exploratory wells in all three of the producing provinces. The Secretaria de Energia calculated exploration costs to be $5.43 per MCK of gas in the Neuquen; $7.48 per CM in the Austral; and $5.87 per MCM in the Noroeste. Based on an analysis of YPF's historic costs, the estimates for the Neuquen and Austral basins appear reasonable, but for the Noroeste basin they are low. Therefore, the exploration costs used in conducting the economic analyses are: Deep Neuquen $10.00 per 1M4; Austral Onshore, $7.50 per MCM; and Austral Offshore, $10.50 per MCM. The cost of exploring in the Northwest region is very uncertain because previous exploration has been very limited. Therefore, two values which are expected to cover the range have been used in making the economic analyses. The lower end of the range would be the historical cost, $3.87 per MCM while the upper end would be $12.00 per MCM. 2. The average incremental cost (AIC) of producing gas is a function of the cost of producing wells and appurtenant equipment and facilities; the production rate of wells; the well fluids composition; and the quality of the gas. The AIC could be ralculated for each known field, based on known or projected field and sell performance and the average could be calculated on the basis of the projected rate of production from each field. However, this is a time-consuming procedure so, for this evaluation, the AIC was calculated for a single field which was adjudged to be typical of the fields in the basins. The Loma la Lata field was selected for the shallow Neuquen basin; the Aguarague field for the Northwest basin; and the Condor/Redondo field for the Austral onshore basin. As there are little or no date for the Austral offshore and Deep Neuquen basins, the performance characteristics were estimated on the basis of geological inference. The AIC was calculated on the basis of the all of the energy produced from the well, including natural gas, natural gas liquids (NGL) and condensate. In order to calculate a wellhead cost of production, all of the costs must be included. It would be incorrert to credit the NGLs and condensate at their full market value unless all related investment and operating costs were allocated to their production. By calculating the AIC of the total wellhead stream, the NGLs and condensate are credited at their energy value. It would be better to credit each product at its market value and allocate all related costs to that product. However, that requires an iterative procedure which would not change the calculated AIC for natural gas significantly. The AIC for gas delivered to the main pipeline for each producing and prospective basin, including gathering and gas treatment costs, based on a 122 discount rate, are susmarized below: - 85 - Annex 7.1 Page 2 of 8 AIC AIC BASIN FIELD STATUS $SMCM $ MCF mmm mmmmmmisn=m mmn yeuquen Lomi la Lata Producing 9.45 0.267 Noroeste Aguarague Producing 18.21 0.515 Austral Condor/Redondo Producing 7.35 0.240 Deep Neq. -- Prospective 11.46 0.324 Offshore -- Prospective 8.35 0.236 3. The incremental cost of transporting gas from the field to Buenos Aires is a function of the cost of the pipeline, the operating costs and the utilization factor. In order to estimate the cost of meeting incremental demands, the long run merginal cost (LRMC) has been estimated for the pipeline delivery from the Neuquen region to Buenos Aires. GDE has established cost estimating standards for constructing pipelines in Argentina, but the standard costs appear somewhat low when compared to cost estimates for other Latin America gas pipeline projects. In view of these variations, costs for the Neuquen pipeline and the Northwest pipeline were adjusted to reflect recent bids for pipeline projects in Latin America. The LRHC for deliveries from the Northwest were estimated on the basis of the pipeline distance relative to the Neuquen pipeline. The pipeline from the Austral region will be more expensive. primarily due to the cost of the crossing at the Strait of Magellan. SNAM Spa. prepared an estimate of the cost of a pipeline from the south to Buenos Aires in 1988. Based on this estimate, the LRHC for transporting gas to Buenos Aires is estimated to be $29.67 per MCM. The LRHC was estimated to bet TRANSPORTATION COST ROUTE $I/MCM S/MCP Neuquen - Buenos Aires 13.29 0.376 Austral - Buenos Aires 29.67 0.840 Noroeste - Buenos Aires 16.92 0.479 4. The economic cost of gas delivered to the city gate, that is the point of custody transfer to the distributor or bulk customer, includes the cost of exploration, production and pipeline transportation. There is an added economic cost to deliver the gas through intermediate or low pressure pipeline mains to residential, commercial and industrial customers. It includes the cost of recovering the capital investment and the operating cost. The distribution costs are affected by the cost of attaching new customers; the operating costs for reading meters, preparing bills, etc,; and the quantity of gas consumed. The average attachment costs which GDE uses in its cost estimating manual for a city of 20,000 customers were used. The operating costs were based on <-DE's historical levels and the level of consumption was based on the aver&ge consumption of customers in each classification in 1987. The investment and operating costs for a long term period, in this case 20 years, are discounted at 12? and the present value is divided by the discounted volume of gas used each year. Based on the average demand for commercial, institutional and small industrial customers, the economic cost of distribution service to each customer class ist Resedential - $48.30 per MCM Com rcial/institutional - $46.20 per MCM General industry - $4.12 per HCM. ARGENTINA GAS SECTOR tSTUD DEMAND PROJECTOO (BSASS CASE) 8/C/TRAUS GOE UIPOTESIS MVUIA POST 2000 DEM"D GROUTU IWDIREF GDE 4IPOTESIS EDIA w asv so54400 OmCM PETRCN WDE UlPTESIS MEDIA RESWCOW 3 X/YR PmSER SECT ENEIGIA ESTIMATE (HARCM 1969) TRANSPORT 4 V YR RSVADON 0 miosY INPORTS 6 MM60. INUSRY 2 VtR fUELUSE 10 S EXPORTS DOlS REFIUERY 1 X/Yt DOMESTIC COYICL TRANSPORT IUDUSTRY REFINERY PIRCUE POSER TOTAl TOTAL PROD/ITNS INTERNAL CMUH RSV REMAiNING ISVILIFE USE USE USE USE USE USE USE CONSUIP IMPORTS USE aROD PRO ADDED RESERVES INDEX TEAR oC" OmCM NM&0 96CM am 0H "C mm 10 nu 3M m4 NM M64CM TEARS .***O. **.*0* m,**t* *t~* ~*eh* -~~** e***** *****O* *.*~b* *.g* *.*.*.*. " *.*** ****** i**.**O .e***k 1989 4315.0 1186.0 90.0 6857.0 920.0 168.2 6100.0 1966 2067 1757 19326 19326 0 S04680 26 1990 4565.0 1252.0 135.0 7157.0 1090.0 168.2 6512.0 20859 2067 16 20671 39M 0 4839 23 1991 4816.0 1275.1 150.0 7407.5 1123.0 168.2 SK9.0 2089 207 187n m94 60592 0 463335 22 199Z SO81.0 1319.7 210.0 7666.8 1156.0 166.2 6803.0 22405 688 2172 23886 60 0 439446 18 1993 560.4 1365.9 270.0 795.1 1191.0 168.2 6612.0 2903 0 220 25193 10967 0 414253 16 1994 S55.2 1413.7 330.0 8212.8 1226.0 252.2 69.0 23189 0 2319 2550 135181 0 388746 15 1995 59360 1456.2 390.0 8459.2 1264.0 252.2 5516.0 2376 0 23 2s60 16075 0 363142 U 8 1996 6234.9 1499.8 450.0 6713.0 1301.0 612.2 5345.0 241S6 0 2416 26571 1873ss 0 336571 13 1997 6546.6 1544.8 S10.0 8974.4 1340.0 612.2 S568.0 25416 0 25i 2J956 215313 0 308613 11 1996 6806.5 1583.5 570.0 9225.7 1380.0 612.2 5585.0 25765 0 2576 26341 243654 0 280272 10 1999 7080.6 1623.0 630.0 9484.0 1422.0 612.2 5623.0 26475 0 2646 29123 2727m 0 251149 9 2000 7364.1 1663.6 690.0 9749.S 1465.0 612.2 6288.0 27642 0 27d3 30616 3i3392 0 220534 7 2001 7s55.0 1713.5 717.6 9944.5 1479.7 612.2 6018.3 28071 0 2607 30678 334270 0 189656 6 2002 7812.6 1764.9 746.3 10143.4 1494.4 612.2 6018.3 28592 0 28S9 3145 36572M 0 158205 S 2003 6047.0 1817.9 776.2 10346.2 1509.4 612.2 6018.3 29127 0 2913 32040 397761 0 12616S 4 2004 8288.4 1872.4 807.2 10553.2 1524.5 612.2 6018.3 29676 0 2968 2644 430405 0 93521 3 200S 8537.0 1928.6 839.5 10764.2 1539.7 612.2 6018.3 30240 0 3024 33264 463669 0 60257 2 2006 6793.1 1986.4 873.1 10979.S 1SS5.1 612.2 6018.3 30818 0 3082 33900 497568 0 26358 1 OQ s 00 0 . elI,- OD 886131IVA GAS SECTOR 51W? OMM PROECTI LIGN S21A830) mcmsmUIPOTEUS 16 OTM SUE SWI SVU 504600 tolollf NOE *UI,ESIS via -o 90 PETUCOI M 1 9IS WN 181 xi s" mm 0 PUEZ 1N36 IML 2018 (M1IS1SO 1513311) * IAIT 4 in 0mJSTu1 2 axi" FLOAUEL 10 X lmsESc aNE l mRASPORTu R RUEtX suuc m mE OAL AL noBR INTEIIAL ouM isv RaNA16 ISV/RMO USE USE USE USE use UN on Comm RllTS USE PROD PRMS O0E RESERVES 311D 11*3 mm6C 161 iM a KNW= NC MUM NM0 EE 161 16W gR 16u0 Wu6C 3610 Wm0 Wu TEAR * . ** .**_*e .a*-.. **** *... * o.**" .a. ." *..a. *a.a.. *..eaa ete*a .a..a .a.... a...... *.e.... ...**" 199 478.0 1222.0 ".0 7M.0 920.0 166.2 6.0 235 2067 1830 20123 20128 0 5600 25 1990 473.0 1269.0 135.0 7429.0 1090.0 166.2 74.0 2236 27 2032 225 42480 0 462248 22 19M 5014.4 1313.4 150.0 m4.9 1123.0 245.6 6130.0 216 20 192 21W 4067 0 460661 21 1992 5290.2 6359.4 210.0 79#4.9 1156.0 1337.6 6651.0 24189 689 2350 2OO 89917 0 434811 17 1993 S501.2 1406.9 270.0 W264.4 1191.o 137.6 101.0 25152 0 2515 27667 1175 0 40n744 1s 1904 S888.1 1456.2 330.0 S553.6 1228.6 133A.6 "65.0 RS487 0 2S49 2605 145620 0 3791O0 14 9 ff 6182.5 149.9 390.0 8810.2 1264.0 1578.6 6699.0 2MM24 0 2642 2906T 1m686 0 350042 12 co 1996 6491.7 1S44.9 450.0 9074.6 1301.6 1576.6 651.0 27392 0 2739 30131 204817 0 319911 11 1997 6816. 1591.2 510.0 9346.8 1340.0 157.6 673.0 27956 0 2796 30751 235569 0 2891S9 9 19I 7088.9 1Ul.0 S70.0 9608.S 138.0 1578.6 8190.0 30847 0 3005 33052 268620 0 256108 a 1999 372.5 1671.8 630.0 981 .S 1422.0 1578X6 9567.0 32119 0 3212 3S331 303952 0 220776 6 2000 7667.4 m13.6 690.0 101S4.1 146S.0 1S78.6 H1O48.0 34317 0 3432 3774 341700 0 183028 S 2001 7091.4 1765.0 717.6 10357.2 1479.7 1S01.2 12466.0 36184 0 3616 39602 381503 0 143226 4 2002 8134.3 1618.0 746.3 1056.3 1494.4 1581.2 13964.0 382 0 322 42045 423547 0 101181 2 2003 8378.4 172.5 776.2 1o05.6 1509.4 1501.2 15549.0 4032 0 4036 4398 46796 0 5672 I 2086 8629.? 1928.7 807.2 10991.1 1524.S 1501.2 1M3.0 42685 0 4261 46166 514812 0 916 0 00 0 . o - r0 - 88 - ~~~~Annex 7.1 -88- Page2igts- 5 of g l$l - 8- …- i --- s X------…------- i ! ii Iig 'Iiit=t2X I i ||| '3ili§llil§l§i i~~~~ _"** Uf$f6aS - 89 - Annex 7.1 Page 6 of 8 Averge Ineramital Cost NW ept High Scario A Nuqm kwtrst emtoe Vaimn Atrat shlatw Ondwe Dow 0OeS8 Exptoration 6.00 7.50 12.00 8.00 10.50 Prouietion 9.45 7.35 18.21 11.46 8.3S Pit Trnsport 13.29 29.67 16.92 U.29 29.6? City CGte 28.74 44.52 47.13 32.75 48.52 Distrfbition Residentiat 48.30 48.30 48.30 48.30 48.30 Carcitl 46.20 46.20 46.20 46.20 46.20 Gent. Ind. 4.12 4.12 4.12 4.12 4.12 X of Proved/Prob/Poas ReVS 4;.6 18.2 26.8 12.3 0.1 Avg city gte cuot 37.05 $I/IM 1.05 S /Cf AIC for Rstidential 85.35 S/imS 2.42 S/HCf AIC for corfetl 83.25 5/HM 2.36 S/NC? AIC for geefral iniastry 41.17 S/HCM 1.17 S/FC AIC for Cmnt 30 - 50 S/HIM 0.85-1.41S/NC? AIC for poer 38.08 S/wCx 1.08 $/NC? AIC for fertilizer CHapuun) 17.45 SiN 0.49 S/NCF AIC for Nthanol CT dsl fueo) 16.85 S/M 0.48 S/HCF 'Varies for each loction. -90 - Annex 7.1 Page 7 of 8 Average Incrumuitat Cost Swmarfo I auqumn Austrat Noroaste V quen 1ustra1 Sbelleo Owhore Doep OmqpY/S Exploration 6.00 7.50 5.87 8.00 10.50 Productifn 9.45 7.35 18.21 11.46 8.35 P/L Tr aport 13.29 29.67 16.92 13.29 29.67 City Gate 2L.7 44.52 41.00 32.75 48.52 Distributi n Residwnttat 4.30 48-30 48.30 48.30 48.30 Comci eat *6.20 *6.20 46.20 46.20- 46.20 Gamt. Ind. 4.12 4.12 4.12 4.12 4.12 5 of Proved/Prab/Poa Rav 42.6 15.7 26.8 12.3 2.6 Avg city gate cost 35.51 S/MW 1.01 S/Ncr AIC for Rasfdmntial 83.81 $/UM 2.3? S/NCF AIC for cmuuAreial 81.71 S/NW 2.31 S/ncf AIC for gamrsl Industry 39.63 S/NOW 1.12 S/NC? AIC for C e nt 30 - 50 S/1CN 0.85-1.415/NCF AIC for power 36.54 S/NC 1.03 S/NCr AIC for fertilizer (Mequen) 17.45 $/1NM 0.49 S/NCF AIC for Nethanot (T del Fuesgo) 16.85 S/NCN 0.48 S/NCF *Varias for each Location. Annex 7.1 Page 8 of 8 - 91 - Avrge Inc.wmtel Cost NW empL Nigh Sceurfo C lNem Autrat lNoreste Isian Austrat Shittu Or_hwe Ocp OeeplOS bElpatf on 6.00 7.50 12.00 8.00 10.50 Proaition 9.45 T.35 18.21 t;.46 8.35. P/L Trnport 13.29 29.67 16.92 13.29 29.67 City Gat* 28.7 44.52 47.13 32.75 48.52 Sfstrfbution Rinidtial 48.30 48.30 48.30 48.30 48.30 C_erclal 46.20 46.20 46.20 46.20 46.20 Gent. tnd. 4.12 4.12 4.12 4.12 4.12 I of Prvvd/PrbPo cn 42.6 15.7 33.0 0 8.7 Avg city gate cot 39.01 W/MU 1.10 SimC AIC fwr RSientlat 87.31 S/U 2.47 S/C AIC for cuusiciat 85.21 $/NOB 2.41 $/PC? AIC for gehat irnmtry 43.13 S/o= 1.22 SIND AIC for Cmmt 30 - 50 S/ 0.85-1.41S/N AIC for power 40.04 S/M 1.13 S/NCF AIC for fertilizer (Nlln) 17.4! S/MNO 0.49 S/NCF AtC for Nethanot (T dot Fuese) 16.85 S/MlC 0.48 S/NCF -varies for each Location. Annex 7.24% Page I or 6 - 92 - NETBACK VALUE CALCULATIONS FOR GAS 1. The net-back value of gas for residential use is the cost of alternative fuels which are used in markets not presently served by natural gas. GDE uses the following consumption pattern to calculate the economic feasibility of extended gas service to new areas: propane 25Z; butane 11 S; kerosene 44X, fuelvood 20X. It is anticipated that the use of fuelvood and kerosene will decline and the use of LPG will increase. The percentages have been adjusted to reflect the trends and the values used to calculate the net-bock vale are: LPG - 50Z; kerosene; 402; and fuelwood 102. Therefore, the net-back value is most sensitive to the price of LPGs. At the present time Argentina's LPG sspply and demand are closely balanced so it is reasonak'le to use the export value of LPG as the economic value in the local narket. The cost of bottling LPG must be added. As of December 1, 1988 the bottler's margin was estimated to be approximately $135 per ton (based on an exchange rate of 14.5). Based on an export value of $100 per ton, the economic value of LPG is $235 per ton. GDE's estimated cost of kerosene is $162 per ton and the market price of fuelwood is $75 per ton. The unit value must be adjusted by the combustion efficiency relative to natural gas. The relative efficiencies which have been used are: LPG - 100Z; kerosene - 80?: fuelwood - 50Z. Based on these economic values and fuel use efficiencies. the net-back value of natural gas in the residential market is $200 per MC0. A similar procedure was used to calculate the net- back value in the commercial and general industry markets. They are: commerciallinstitutional - $203 per MCM; general industry - $121 per MCM. 2. The net-back value of natural gas for power generation is the amount which could be paid for natural gas which would result in the same incremental cost for electricity delivered to the Buenos Aires market as any other alternative source of supply to meet the incremental demand. In addition to hydrocarbons, hydropower and nuclear energy are also available for power generation. As the nuclear options are likely to be more expensive than hydro in the foreseeable future, the net-back value of natural gas for power generation could be based on hydroelectric project now under consideration. A large number of hydro projects have been evaluated at the prefeasibility level but the estimates of project costs are uncertain. The 250 MV Pichi Picun Leufu hydroelectric project is the only project for which e final design has been prepared and a construction contract has been negotiated. There may be less expensive -- larger -- projects among those examined, but Pichi Picun Leufu was selectqd as the basis for estimating the incremental cost because firm cost estimates were available. Based on current estimates of the construction cost and the projected load factor, the generating cost is estimated to be $0.047 per kwh. The cost of transmission from the site to Buenos Aires would be about S0.004 per kwh. resulting in a delivered cost of $0.051 per kwh. An equivalent gas-fired thermal station would consist of a 150 mw steam unit and a 100 mw simple cycle gas-turbine unit. The net-back value of natural gas used in such a station, located in the Buenos Aires area, would be $79 per HCM ($2.23 per MCF). The technology used to estimate these values meets the development criteria currently used by the Secretaria de Energia. It should be noted, however, that the Secretaria de energia is considering the installation of combined-cycle plants which could have capital costs as much as 25? lower than stiam plants and operate at 10 higher efficiency. 9 3 Annex 7.2(8) Page 2 of 6 This would reduce overall production costs and increase the net-back value of natural 8as as a power plant fuel. The detailed analysis of the net- back calculation is presented in Annex 4. 3. The net-back value of natural gas when used for fertilizer (ammonialurea) manufacture is the price which could be paid for natural gas which would result in a lower manufactured cost than the price of imported urea. The net-back value is affect by the unit investment per ton of production, the cost of operating labor and utilities, but most directly by the value of the urea produced. The World Bank International Economics Departmenc has projected that international urea prices will increase, in real terms, until 1990 but decline thereafter until 2000.(l) Based on .heir projections of real urea prices, plus the cost of transporting urea from the U.S. Gulf Coast to the Neuquen area, and the operating factors established for the Fertineu project, the net-back value of natural gas is estimated to be $45 per MCM ($1.28 per MCF). However, the net-back value is very sensitive to the international price of urea. If the price should increase 252 above the World Bnk projected level, the netback value would increase to $88 per MCM. The net-back analysis is detailed in Annex 5. 4. Cement manufacture. The cement industry is well established in Argentina. Eight manufacturers operate a total of 41 kilns -i all regions of the country except the far southern zone. In the early 19808 capacity was rapidly expanded but demand and production have declined in recent years so the industry currently is operating at about 522 of capacity. Natural gas is the most commonly used fuel, providing approximately 63Z of the fuel requirements. Oil is used in most of the other plants and small quantities of coal are used. Coal would be a preferred alternative for natural gas if it were available at an economic price. Coal production is very limited and it does not appear it would be an economic substitute. The other alternative fuel would be heavy fuel oil. Based on the 1987 export realization price of $102 per ton, and estimated freight costs of $10 per ton, the cif price of HFO would be $92 per ton. Some of the plants are already equipped to use fuel oil so the added cost of equipment would be minimal, primarily for storage equipment where it was needed. Therefore, the net-back cost of natural gas for cement manufacture is considered to be the delivered cost of heavy fuel oil, $92 per HCM ($2.30 per MCF). 5. The largest petrochemical projects -- iD. terms of natural gas use -- which is included in GDE's high demand scenario is a methanol plant which would be built in Tierra del Fuego. It would be approximately the same size as the recently commissioned plant at Punta Arenas, Chile. If a long term market can be established for the output as a chemical intermediate, the net-back value of the natural gas feedstock may be sufficiently high to cover production costs. However, long term market prospects for methanol use as a chemical intermediate are uncertain. 7here will probably be a large market for methanol as motor fuel when engine technology is improved and the marketing infrastructure is in place. In this market the price will be set relative to gasoline prices and at current prices, the net-back for a methanol plant would be negative. In the early 1980s Argentina exported small quantities of methanol at prices exceeding $200 per ton but in 1986 the export realization price was $175 per ton. At that price the net-back value is $4 per MCM ($0.11 per MCF). - 94 - Annex 7.2t4) Poge 3 of 6 If the export price reaches $250 per ton, the net-back value would be $18 per MGC ($0.52 per MCF). In view of the market and pricing uncertainties, the net-back value used for economic evaluations should be no greater than $15 - 25 per MCM. 6. The net-back value of natural gas liquids as feedetock for che petrochemical industry is a function of the product, the cost of extraction and the cost of the alternative feedstocks. The net-back value for the ethane extracted from natural gas is $81 per ton and for LPGs it is $88 per ton. The economic net-back values for each of the principal consuming sectors are listed below. Net-back Values Net-back value Sector $/Mc14 $IMCP Residential 200 5.67 Commercial 203 5.74 Genl. Industry 121 3.43 Cement 99 2.80 Power 79 2.23 Fertilizer 45 1.28 Petrochemicalz 0.480/Mcal l.91ImMBtu Annex 7.2(a) 95- Page 4 of 6 NETUAC vALI at unmAlJ uAs PU Pam3 GIaURtIS IRTIoM COST FM P1CM! P10 l tSufu KWIC 111 2 16$ U HILL CAPACIT Z0 NW 01 0 2 S OPONI s*w.ll oamm a x2I UT I ""ASWI 4 MILLAKW o* 0 r x 1t 6 2 LOAT 4.50 X OUM 16 2 IN a 3 NY= 179 515313 2SIN61ye WPNW 3816 0VA a0 s 1N131 M 5 46.8 NILLIIO ONAWII 1216 13uYR6 ODA"U 112ZIhy? A tSF I0 0.12 O-ITIS tlo TOTAL m COST a COST COST GEunETED VM MILLS NILLS MILLS MILLS SM ***o *Oeea _** 6*"*** 1 5.27 5.27 2 15.45 16.45 3 42.10 42.10 4 n.Si 73.51 S 52.2n 52.n 6 42.18 42.15 7 29.00 29.00 9- 01. 75 4.05 4.63 1020.:0 9 0.75 4.06 4.6 1020.10 10 0.75 4.06 4.8 1020.10 11 0.75 4.06 4.3 1020.10 0.75 4.08 4.3 1020.10 0.75 4.00 4.83 1020.10 14 0.75 4.06 4.83 1020.10 15 0.75 4.06 4.63 1020.10 16 0.75 4.06 4.63 1020.10 17 0.75 4.06 4.63 1020.10 1 0.75 4.08 4.63 1020.10 19 0.75 4.06 4.63 1020.10 20 0.75 4.40 4.3 m 1020.10 2t 0.75 s.0o 4.63 1020.10 22 0.75 4.06 4.3 1020.10 83 0.75 4.06 4.83 1020.10 24 0.75 4.6 4.8 1020.10 25 o.7 4.03 4.3 1020.10 2 0.7 4.0 4.83 i020.10 2 0.75 4.06 4.83 1020.10 28 0.75 4.08 4.83 1020.10 29 0.75 4.08 4.83 1020.10 30 0.1 4.08 4.83 1020.10 31 0.7n 4.06 4.83 1020.10 32 o.n 7 4.0 4.u3 1020.10 33 0.75 4.00 4.83 1020.10 34 0.75 4.08 4.83 1020.10 35 0.75 4.08 4.83 1020.10 36 0.7n 4.08 4.83 1020.10 ST 0.75 4.08 4.83 1020.10 38 0.75 4.08 4.83 1020.10 Annex 7.2(a) -96- Page 5of 6 NuTM vYA OF NATURUL GU M CURSEC S OUE3I CTM of PICUI P103 POJC) STIWCST 1100 U311 sTCAp ISO WJ STnIII a001U MCA ,,,,sv I0, NILL U seiuFc 62.76 1 v-mi 400 uwSa TISA IceKN TUNTTI tn M ui0i,i nmtw 40 ToFCTW 2.3 x TOTASIV 205 TOtW 2 Inc 0s OPCOS 13.2 *MW-TlN W8 0 COIU 20 X1I Ye I 1*A3 0 N'IS ON 02 O LRIOI 40 X 1in 2 oAMS to x n13 0 3 4K NILLIW kYAL 2.3418 U OlIJACTOS 0.12 PTINS TRAIIWt Pm m1 FUEL TOTAL 1N11S c cWT WIT ERTUD iN cm COST YUAM ILLS tILLS PILLS WA MILL IU MILL MILL I 1 41.0 41.0 a U82.0 U.0 3 41.0 41.0 s 3.3 0 1020 6941507. 21.0 24.3 5 3.3 0 1020 6941507. 21.0 24.3 4 3.3 a 1020 6941507. 21.0 24.3 7 3.3 0 tOOO SR1"07. 21.0 24.3 a 3.3 0 I100 1WM. 21.0 24.3 9 3.3 0 10o 64150. 21.0 24.* 10 3.3 0 1020 6941W. 2123 24.3 11 3.3. 0 1020 6941SO7. 21.0 24.3 1t 3.3 0 1020 6417. 21.0 24.3 13 3.3 0 1020 8941507. 21.0 24.3 14 3.3 0 1020 694150?. 21.0 24.3 Is 3.3 0 1020 69150. 21.0 2.3 16 3.3 0 120 91507. 21.0 24.3 17 3.3 *0 1020 891O7. 21.0 24.3 1l 3.3 0 1020 691507. 21.0 24.3 19 3.3 0 1020 894107. 21.0 24.3 20 3.3 0 1020 6o150. 21.0 24.3 21 3.3 0 1020 61507. 21.0 24.3 22 3.3 0 1020 6941507. 21.0 24.3 23 3.3 0 1020 941507. 21.0 24.3 24 3.3 0 1020 8941507. 21.0 24.3 25 3.3 0 1020 8941S07. 21.0 24.3 26 41.0 3.3 0 1020 941507. 21.0 65.3 27 a2.0 3.3 0 1020 6941507. 21.0 106.3 2 41.0 3.3 0 1020 641507. 21.0 46.3 29 3.3 0 1020 64150. 21.0 24.3 30 3.3 0 1 6941507. 21.0 24.3 31 3.3 0 1020 94107. 21.0 24.3 32 3.3 0 1020 941s507. 21.0 24.3 33 3.3 0 1020 941507. 21.0 24.3 Annex 7.2(a) 97 Page 6 of 6 UETRACK VALUE CALCWITIPI AMIONIAIURE KFACTURE ELINCR 2 WU AFE 2000 FEIGUT 30 STOM UWICEU 200 S/TON (CULFCA) INVESMHT 750 SON/YR GRSUSE 40 NCF/TON CAPACITY l,000 TPO OPAIOR 2.28 NILL * emSw 5 HILL S PRCONS 300 KWINTON INVFACTOR I PURCOSI 0.04 S/1IH ODRWIY1 20 X UTIL 2.00 S/ToN Dr0IY so X DlSCCT 0.12 0RWSWiR 30 S NETUAL 1.26 S/NCF 45 SC NPYPRtS 531660.2 tRI 12.0 X NPVT 103.8194 COST CT TOTIWT UlFA URA SALS COST TOTAL W.T tWISTMT OPCOST EXfOSTOCK PRCO PRICE REWVIU VAT GS COST REWEOU YUA iISSLL USSLILL USINILL TON/Il S/N ILL S UuSNILL USUNiLL -US".LL me. - .me. m_n e.m mm O o m I 15.00 15.00 230.00 0.00 15.00 -15.0 2 37.50 37.50 212.00 0.00 37.50 -3.5. 3 22.50 22.50 215.00 0.00 22.50 -22.5 4 3.65 3.68 100000 209.00 20.90 5.12 8.80 12.1 5 3.66 3.66 100000 204.00 20.40 5.12 8.80 11.6 6 3.66 3.68 100000 199.00 19.90 5.12 8.80 11.1 I 3.6 3.68 100000 194.00 19.40 5.12 8.80 10.6 8 3.6U 3.66 100000 190.00 19.00 5.12 8.80 10.2 9 3.66 3.68 100Q00 168.00 18.80 5.12 8.80 10.0 10 3.66 3.66 100000 186.00 18.60 5.12 8.80 10.0 11 3.6 3.66 100000 164.00 18.40 5.12 8.80 9.6 12 3.66 3.6 10000 187.66 1.77 5.12 8.60 10.0 13 3.66 3.68 100000 191.43 19.14 5.12 8.80 10.3 14 3.6 3.66 100000 195.26 19.53 5.12 8.60 10.7 15 3.66 3.66 100000 199.17 19.92 5.12 8.80 1l.1 16 3.68 3.68 100000 203.15 20.32 5.12 6.80 11.5 17 3.68 3.66 100000 207.21 20.72 5.12 8.80 11.9 18 3.66 3.66 100000 211.36 21.14 5.12 8.80 12.3 19 3.6 . 3.68 100000 215.59 21.56 5.12 6.80 12.8 20 3.68 3.66 lO00 219.90 21.99 5.12 6.80 13.2 21 3.66 3.68 100000 224.29 22.43 5.12 8.80 13.6 22 3.6a 3.66 10000 226.76 22.86 5.12 8.80 14.1 23 3.66 3.66 100000 23.36 23.34 5.12 8.80 14.5 Annex 7 .2 (b) Page 1 of 7 - 98- Petrochemical sector Although a wide range of chemical intarmediates and finished products are manufactured in Argentina, almost all of the natural gas and natural gas liquids (NGLs) used In the sector are consumed to produce four basic chemicals: a_monia, methannl, ethylene, and propylene. The principal derivative chemicals are urea which is produced from ammonia; and plastics which are produced from ethylene and propylene. Methanol is used to produce resins and solvents. Three different petrochemical feedstocks are derived from natural gas. Residual natural gas, from which natural gas liquids (NGLs) including propane. butane and heavier hydrocarbons have been extracted, can be used as feedstock for amuonia and methanol production. Wets can be used to produce intermediates such as ethylene, propylene and bu- lene. However, ethane is the preferred feedstock to produce ethylene and several of the proposed projects will be designed t-o extract ethane from the gas stream along with the heavier hydrocarbons. As of January 1, 1987, avmonia was produced by three manufacturers. Petrosur SA operated a plant with an installed capacity of 72,000 TPY at Campanas D.G.F.M operated a 12,000 TPY plant at Rio Tercero and Electroclor operated a small plant, using electrolytic hydrogen. at Cap. Bermudez. Approximately 702 of the ammonia is converted to urea by PETROSUR SA at a 103,000 TPY plant at Campana. Production in 1986 was 75,733 tons, indicating a plant atilization factor of 872. Urea production in 1988 was 91,942 tons and the plant operating factor was 89S. Small quantities of urea are exported but larger quantities are imported. Ethylene is produced from light naphtna and refinery gases but 782 of the conversion capacity is at the Petroquimica Bahia Blanca SAIC plant, which utilizes ethane feedstock. Total installed capacity is 255,000 TPY but in both 1985 and 1986, production was 261,000 TPY, exceeding plant capacity. Essentially all of the output is used to produce polyethylene. Propylene production for petrochemical use was 33,700 tons on 1986. In addition to the 20,000 TPY P.B.B. SAIC plant, YPF has a 48,000 TPY plant at Ensanada and a 20,000 TPY plant at Lujan de Cuyo. Two smaller plants are ope;-ated by Shell CAPSA and Esso SAPA. Two -mmll methanol plants produced 33,00 TPY in 1986. ATANOR SAM operates a 1..000 TPY plant at Rio Tercero and CIA. CASCO SAIC operates a 21,000 TPY plant at Pilar. Three-quarters of the methanol is used to produce formaldehyde and the balance is used for solvents. Less than 102 was exported and a small quantity was imported. Ax part of its program to expand the use of natural gas, the government has encouraged growth of the petrochemicals sector. A number of projects have been proposed but it is unlikely all will be realized. The petrochemical industry has identified 18 potential petrochemicals projects but GDE includes only eight in its Sigh Demand scenario. These would probably be more likely to be built, but even some of these are questionable. The projects listed by GDE, the volume of gas (or equivalent NaLs) consumed, and the projected start-up date are listed in Table Table 1. Potential Petrochemical Projects NG Use Project Location MKQY Start-up - 99 - Annex 7.2(b) Page 2 of 7 P. oral. Mosconi Bahia Blanca 43 1989 Acrylonitrile Neuquen Neuquen 77 1991 Resinfor Santa Fe 119 1992 AsMonia (local use) Pta. Loyola 241 1992 Petroquimica Austral Tierra del Fuego 648 1992 Fertinoa (Fertilizer) Noroeste 42 1992 Fertineu (Fertilizer) Neuquen 42 1992 Ammonia Bahia Blanca 241 1995 If these projects were completed as scheduled. total 8as consumption in the sector would increase more than ten-fold from 125 MKCMY to 1,579 UMCHY but would still represent only about S of total consumption. Over the life of the projects they would consume approximately 72 of the proved reserves (504.6 BCM). The pricing structure for sale of residual natural gas and NGLs to petrochemical manufacturers was revised in 1988 when Resolution No. 105 was issued. The structure is complex and requires transfers of large amounts of money from the government to the petrochemical industry. Natural gas purchased for fuel use -- as distinguished from that used as a raw material -is sold at the standard industrial price. The man,ifacturer pays the posted price (the Resolution No. 105 reference value) for each product to the producer, primarily GDE. However, the manufacturer receives a rebate for all natural gas, ethane, propone and butane used as feedstock. The rebate is the difference in the retention price established in accordance with Resolution No. 105 and the reference price. The purpose of the pricing policy is to enable Argentinean producers to campete in world markets. The reference price is the calculated average price. c±f Argentina, for a basket of world prices for each product. After the reference price is established, it is reduced by applying a coefficient' which currently is 0.9 Zor existing plant3 and 0.8 for new plants. The basis for applying the lower coefficient is not clear and it is subject to negotiations between the government and the petrochemical manufacturer. Since the inception of Resolution No. 105 the reference price for ethane has increased 432; propane, 482; and butane, 422; while the reference price for virgin naphtha has remained almost uichanged. Table .2. lists, the differences between the retention prices paid to the .4pplier and the reference prices established under xesolution No. 105 as "i September 1988. - 100 - Annex 7.2(b) Page 3 of 7 Table Z. Feedstock Prices September 1988) Retention Reference Price Price Differenoe Feedstock S/Ton S/Ton S/Ton _ ~ - Virgin naphtha 187 106 81 Propane 162 62 l00 Butane 162 55 107 Ethane 146 56 90 Natural gas 60 (per MCM) 30 30 Based on the volumes of each product sold in 1987, the implied transfer payments made by the government to the petrochemical industry would be $115 million. The pricing structure for NGLs used in the petrochemical industry wili undergo a significant change as the new projects come on-stream. Rather than GDE extracting the heavier hydrocarbons and selling them to the manufacturers, the manufacturer will receive 'wet' gas containing NGLs from YPF, process the gas to extract the NGLs including ethane. and deliver the residue gas to ODE. The current plan, as typified by the Dow project in Neuquen, is for the manufacturer to install the extraction plant and pay only for the 'shrinkage', that is the heavier hydrocarbons extracted and fuel gas, on the basis of the calorific value. For the Dow project the negotiated price is approximately $21 per MCM ($0.60 per MCF). Historically in world markets, NGL prices have exceeded natural gps prices (on an energy equivalent basis) by at least a sufficient margia to pay for the extraction cost. If alternative feedstocks, e.,.naphtha, were available at a lower price petrochemical manufacturers would switch from NOLa and the producer would shut down the extraction plant. Currently that is happening in the U.S. Gulf Coast even though spot natural gas prices are also low. Ethane is a better feedstock for ethylene production than light naphtha because it yields a smaller proportion of low value by-products. Ethane's value can be distorted if higher than market prices are paid for the co-products such as butylene and propylene. The reference prices established under Resolution No. 105 may be reasonable, but a more flexible contractually based arrangement could protect both the seller and the buyer against large changes in prices. Based on the 1987 export price for naphtha -- assumed as the price received for nafta comun -- of $106 per ton plus $10 per ton for freight, ethane's net-back value would be $113 per ton. The economic cost of extracting NGLs from the Loma la Lata gas stream is S32 per ton so the economic net-back value of ethane woule be S8l per ton, 51.82 per HMBtu. This is equivalent to $62 per SCM or almost three times the energy equivalent price. The unit cost of extracting ethane would be higher than the average cost of $32 per ton because extra equipment is needed to make the deep extraction. Nevertheless, it appears the ethane fraction would be significantly underpriced if sold on an energy equivalent basis. This is supported by a recent World Bank study which found that: - 101 - Annex 7.2(b) Page 4 of 7 ...countries with access to (N!SLJ feedstock at US$0.60 per MMBtu or less will be able to produce basic olefins with a cost advantage ... For example, ethylene production costs will be about 302 low"r... compared to similarly sized and efficient producers in Western Europe or naphtha importing countries such as Japan and S. Korea.02 Light naphtha prices are depressed and an international price in the range of $150 per ton over the longer term may be more realistic. As shown in table 3., the ethane's value increases as the competitive feedstock price increases. Tab-e 3. Ethane Value Versus Naphtha Price Naphtha price, Slton 11 125 150 Ethylene price, S/ton 352 3o 444 Ethane value, $/ton 113 134 188 Eztraction cost, S/ton 32 32 32 Ethane netback price, Slton 81 102 156 Ethane netback price-, SIMBtu 1.82 2.29 3.50 Percent of energy value 303 380 583 The net-back value is 70 - 802 of the naphtha price while under Resolution No. 105 the price of extracted ethane is 852 of the naphtha price. This indicates the extraction margin provided by the Resolution may not be sufficient to cover extraction costs. If world naphtha prices increase as expected, the disparity between the energy content based price and the market value will increase rapidly. A method whereby-YPF could share in the increasing value of the ethane fraction should be established. If all well-head and transfer prices are eliminated, as discussed in section 8, the seller would be free to negotiate a market based pricing iormula. Several options for pricing the ethane fraction are reviewed below. The propane and butane fractions could be priced in relation to international prices and adjusted periodically to reflect changes. This is somewhat similar to the present method used for setting Resolution No. 105 prices, but the discount coefficient would be eliminated and an allowance would be made for the cost of extraction. The pricing parameters, that is the basket of prices and freight ratea should be updated to reflect current conditions. There are several ways in which some portion of the higher value of NGLS as a chemical feedstock mlght be captured by the producer. The simplest would be to increase the price of the extracted components to reflect their value more accurately. The price of ethane could be set on the basis of lts value as a substitute for light nap1"ia while the price of propane and butane would be based on the cif price of imports or the fob price of exports. Argentina is likely to be a net exporter of LPG so the export price may be the better basing point. In many countries this is done through a 'percentage' type contract under which the owner of the liquids receives a portion of the liquids -- or the equivalent value of that portion - from the extraction plant operator In the case of the 21 Vergara, Walter and Brown, Donald, The New face of the World Petrochemical Sector, World Bank Technical Paper No. 84, Industry and gnergy Series, Washington, D.C., 1988. - 102 - Annex 7.2(b) Page 5 of 7 Argentine projects, YPF would hold title to the residue gas until it reached the tailgate of the plant and would receive the percentage payment. The residue gas would be sold to GDZ at the plant tailgate. This method has the advantage that it is somewhat simpler than the Resolution No. 105 procedure and eliminates the transfer payments made by the government. However, it does transfer a portion of the downside risk of falling prices to YP,. A second way to capture a portion of the.higher value would be to allow the plant operator to charge a processing fee for extracting the liquids. The price of the liquids w,uld be set on the basis of their economic value but the extraction plant operator's return on investment could be guaranteed and he would be insulated from the risk of declining feedstock prices. This would increase the attractiveness to private investors, but it would require careful monitoring of costs and operations by a government entity. The risk for the downstream purchasers of NGLs would be increased and therefore they may be somewhat slower to invest in capital equipment. A third method would be share the benefits of higher feedstock value between the producer and the manufacturer by indexing raw material costs to the value of the nroducts which in turn would be established by the free market price of alternative feedstocks. The plant operator would retain a portion of the increased revenues, but a portion would flow back to YPF in the form of higher prices or direct payments. One formula which could be used would allow the producer to retain all profits until the naphtha price exceeded a prescribed level, such as 1102 of the base price. When this level is exceeded, the feedstock supplier and the plant operator would share the 'excess' profits. For example, if the naphtha price was in the range of 110 to 1252 of the base price the price of the feedstock would be increased by a factor which was related to its increased value. The indexing-factor could be set so that the manufacturer retained the larger share of the 'excessw profits. When the naphtha price exceeded 1252 of the base price the supplier's portion of the 'excess' revenues could be increased. The exact values would, of course be negotiated prior to project initiation. This wouAld allow the government to offer low feedstock prices to encourage the petrochemical industry, but provide a means for capturing some of the economic rent when energy prices increase. This method would require that the transfer price from the extraction plant to the downstream consumera be adjusted periodically and monitored to assure that it reflected the changes in market prices of the end-products. This could become complicated as a number of independent but interlocked companies would be involved. The fourth method would be to assure the manufacturer's return on investment. This would also require an extensive cost monitoring and regulating system and assurance that the transf- prices charged for intermediate products reflect the actual value. It does have the advantage that the rate of return could be negotiated at a level which would be attractive to private investors. Before a new pricing policy can be formulated a detailed evaluation must be made of the long range value of NGLs and the cost of extraction. The various contractual options should be examined and the ipact of each alternative, on the willingness of private investors to -103- - Annex 7.2(b) Page 6 of 7 commit to construct plants should be evaluated. However, it is possible to estimate the economic value of NGLs which serves as an upper bound for the financial price. Based on the -omposition of Loma La Lata wet gas and the design criteria for the proposed oxtraction and fractionation plant. 498.010 tons of NOL can be extracted from 18 MKCMD of gas. Based on the 1987 export price for light naphtha - $106 per ton and LPG - $.20 per ton; and the net-back value of ethane as a replacement for light naphtha - $113 per ton, and deducting the coct of extraction and freight, the value of NGLe is $69 per MCM ($1.95 pe: MMBtu). This is well above the economic production cost for Loma La Lata gas, $15.50 per MCM, so a pr ice which allowed YPF to recover a portion of the economic rent should st1l1 pcr"tide sufficient incentive to private investors to build the extraction pla.ut. Proposals have been made to construct export-oriented methanol or methyl-tertiary-butyl-ether (MTBE) plants using methane (dry natural gas) as the principal feedstock. The future market price for these motor fuel related products is uncertain and it mav be necessary to offer a low feedstock price at the outset in order to iustify construction. However. the natural gas sales contract should incorporate provisions which would enable the supplier to share in the benefits of higher market prices for the products if they occur. A formula similar to that proposed for the NGLs, under which the price of the feedstock would be related to alternative feedstock prices might be used. This would require that an international pricing base for natural gas used as feedstock be established. The procedure would be complex and would not necessarily meet the requirements for sharing future benefits. Since the risks and benefits in this instance are market oriented it would be better to key the price of the feedstock to the value of the product. The reference price of natural gas used to produce nitrogenous fertilizers is based on a similar indexing methodology. Another way would be to negotiate a-feedstock pricing formula which provides sufficient inducement to the owner to make the initial investment, but provide that the gas supplier share the increased revenues if the international price of the products increase. The negotiated price formula would have to be tailored for the needs of all the parties and would be unique for each project but some similar type contracts have provided for three or more price levels over the life of the project: I. The early market development period, 2 to 4 years. during which the gas price would probably remained fixed to assure the operator's income until a market is established. Il. Project amortization period during which the owner would require assured cash flow to service debt a.ad amortize the investment. Typically this period may be 8 to 10 years. During this period the gas price could be indexed to the value of the product(s) so that the 'excess' revenues, would be shared between the owner and the gas supplier, with the larger portion still being retained by the owner. The gas supplier would require a floor price for natural gas. probably the initial price, unless they chose to accept some risk in return for a higher share of the excess revenues. III. The profit period which would cover the balaee of the project life. The gas price would be indexed to world prices for - 104 - Annix 7.2(b) Page 7 of 7 products and the supplier's share of the excess revenues would be higher than during Phase II. The contract could also include a rwversionary provisirn whereby ownership of the equipment and facilities would revert to the gas supplier. or more likely to a governmen.--owned enterprise, at a time certa.ta. The owner would seek to extend the period. but a 20 25 year period would be reasonable. Annex 7.3 Page I of 1 - 105 - LPG Production by Source Table 7.1 LPG Prodwetion Location Source Ownership Production Chaco Bayo Nat. gas YPF 16.000 Campo Duran Nat. gas YPF 107,000* San Sebastian Nat, gas YPF 68,000 Lujan de Cuyo Nat. gas YPF 101,000 La PLata Nat. gas YPF 41,000 El Condor Nat. gas YPF 7,000 Carl Cerri Nat. gas GDE 395,000 Caimancito Nat. gas GD! 18.000 Centenario Nat. gas CDR 12,000 Canadon Seco Nat. gas CDs 9,000 Lama La Lata Nst. gas CDE 117,000 From natural gas 784,000 YPF Refinez) 191,000 Esso SAPA Refinery 77,000 Shell CAPSA Refinery 23,000 PASU 20,000 Oral. Mosconi Petrochemicals 30,000 Duperial Petrochemicals 8,000 From petroleum 349.000 Total production 1.097,000 *Equivalent red.livered for petrochemical feedstock. Anne,- 7. 4 -106- Page I of 2 Methodologv for Calculatina Financial Costs 195. The methodology adopted for calculating the financial cost of gas exploration and production adheres, as closely as possible, to the methodology used by the Secretaria de Energia. However, the SdE calculated the rate of return for developing each field, based on assumed values for the gas and condensate produced. In order to calculate the cost of producing the gas, the calculating procedure, but not the underlyJng methodology, had to be modified. The well 4rilling costs, production razes and the values for the other technical parameters for basins where there has been little or not experience, e.g. the Deep Meuquen. were estimated by the B3ak' s technical consultants. The Values for the economic parameters were adapted from the values which are beint, used ln the study now being conducted by the Argentine Petroleum Institute, except that the royalty allowance was modified. In order to simplify the computation, it was assumed that the condensate value would be equivalent to the value of the natural gas. The condensate value may be 20 - 40? higher than its production cost, depending on the quantity of natural gas liquids produced. and the production cots. However, if all drilling and recovery costs were allocated to NGL production, the cost of production would be higher than the average production costs. As calculated, the cost of natural gas production is probably slightly overstated. 196. The capital and operating costs required to develop and produce natural gas were estbi ted for one field in each producing basin which is felt to be typical of fields in that basin. Technical and economic parameters were estimated for two, as yet non-producing basins, the Deep Weuquen and the Austral Deep and Offshore fields. The costs were amortized over the producing lifetime of the field on a unit of production basis. A capi;al tax rate of 1.5? per year of the yearly -et earnings and a revenue tax rate of 2.5? were used. The Vk'r ^a calculated as 15? of the investmnt in any year and amortimr- 'ver the life of the field. At present YPF recovers only 30? of the VAT so the unrecovered VAT (702) was included in the cost of production. The royalty was calculated as 122 of the reference price for natural gas. The natural gas reference price as- calculated as 602 of the crude oil reference price, which in this Instance was taken as $15 per barrel. The gas production cost was based on 1002 equity financing and an income tax rate of 332. The Argentine Petroleum Institute had proposed to use a debt/equity ratio of 60140 with 70? of the debt financed in the international market of 13 2, and 30 Z local financing at 30 2. Leveraged financIng could reduce the production somewhat, while still yielding the desired 30? return on equity, but because of the high interest rates, the impact would be limited. After the gross income was calculated, a wlevelized' cost wss calculated as the constant price which would yield the same present value as the varying revenue streom, when discounted as 122. - 107 - Annex 7.4 Page 2 of 2 197. ?he financial cost of transmission and distribution was calculated on the basis of Gas del Istado's estimates of their costs over the next five year period. The costs include wages and salaries, taxes, aon-recoverable VAT, operating costs, amorsiz:tion, incarance, interest, capLtal taxes and Income taxes. The total cost of service was allocated between tranmission and distribution using the allocation factor, 722, which wag supplied by Gd. The distribution costs were then allocated among the classes of service, i.e. residentiallcomuercial and industrial, oan the basis of the investment required to serve each customer class, the operating costs required for customer service, billing. etc., and the volumes sold to customers in each class. - 108 - AN * .1 Pe. 1 oI 1 (FILEsDEMANDI) ARGENTINA - ENERGY SECTOR STUDY - POWER SUB-SECTOR OEMAND PROJECTIONS - TOTAL COUNTRY SCENARIO: SE'e Energy Plan. GDP Crowtht 8.51 for 1989 *nd 4X p.s. for 199062066 [-Consump--------consumption from Public Utilities- I Auto- '.tal Country (--Total-- prod- Consumption Residential Coomenciel Industrial Others Annual uvers Annual Yoor (iWh) I (GWh) X (GWh) X (Cwh) X (CUb) Growth (CUb) (4Ch) Growth(S) 1970 4996 86.2x 1882 18.8X 4933 85.71 20a9 14.6X 18799 4681 18486 1976 6621 82.4s 2282 16.91 8856 48.51 2686 18.1X 26416 6.21 4548 24966 6.21 1980 6M61 80.1X 8160 10.71 18658 47.06 8567 12.2X 29451 7.61 8W 83886 6.MS 1981 6959 0.611 3242 11.It 18276 46.6X 8689 12.51 20116 -1.1X 8479 82595 -2.2X 1962 6649 29.2X 8122 16.6OX 1404 47.41 8756 12.61 2056o 1.6X 569s a8a81 1.5X 196 9s84 28.7x 8826 16.61 15227 48.8X 3988 12.51 1626 6.6X 8M6l 86461 7.21 1e4 057 20.0x 8556 10.71 15904 4.111 4049 12.2X 8866 4.9s 4100 87186 4.61 1965 9746 29.7X 858 16.SM 16456 47.11 4060 12.41 a2624 -4.6X 8579 86468 -2.1X 1986 10460 2.41 8n77 10,6X 16698 47.6X 4878 12.81 85665 8.2X 34 8S084 64.11 1967 11326 29.61 4184 16.9X 17911 47.2X 4614 12.11 87064 7.05 8893 41677 6.41 1966 11744 86.ax 4162 11.6X 17971 46.41 48U 12.X1 38760 2.06 8802 42652 1.91 1989 18267 83.6X 4896 16.9x 17065 48.1x 4928 12.61 80554 2.6X 42865 48689 2.65 1960 ' t 8 a2.21 4481 10.41 19641 45.41 5262 12.06 48252 0.1 4466 477)0 8.sx 1991 f65 81.21 4787 16.1X 216S6 46.91 5486 11.71 46718 6.61 4610 51826 7.60 19m 15224 86.41 5656 M6.1X 289sa 47.61 5624 11.61 60048 7.11 4066 54726 6.6x 1998 156C 29.7x 5469 16.1S 28647 46.7X 6172 1.51X a524 7.6X 4756 56262 6.6X 1914 165o6 29.03 6706 16.1X 20887 49.41 6504 11.41 56657 6.2X 4823 61680 5.61 1996 17185 26.41 6147 19.2X 86261 56.11 6646 11.81 69860 6.21 464 65278 5.691 1996 17648 27.6x G65 10.2X1 2641 60.81 7215 11.2X 64276 6.41 4989 61209 6.6X 1997 16577 27.11 7024 10.2X 5341 51.61. 7607 11.1X 6669 6.71 494 7Sc48 6.8x 1996 19838 26.C1 7609 16.81 88146 52.21 8016 11.1 78013 6.51X 562s 7842 6.11 1999 20126 26.sx 8629 16.8X 41206 58.06 8452 10.01X 7712 6.6X 5651 8286 6.21 2660 26942 26.2X 8656 10.81 44566 58.7X 8916 16.71 62998 8.71 5659 68652 6S8. NOTES Porlod 1970-1987: actual data Year 1966: estimated Period 1986-2000: projections HOG-11/15/99 - 109- ANNEX .2 Pae I oft (FILE:DEMAND2) ARGENTNA - ENERGY SECTOR SIWY - POWER SUB-SECTOR DEMAND PROJECTIONS - TOTAL COUNTRY SCENAROt: Mobt-Lt kly GOP 4rowth: 2.06 tor 1989-1994, 8.1 tfor 105-1909 and 43 p.s. for 1997-2166 C---------------eConsumption from Public Ubiliti. .t lAuto- Total Country R-Total -prod- Consumption R lenttel Cosneirl Industrial Others LAnnuol ucers Annual Year (oh) X (Gh) X (Ol) X (oh) X (OW?) Growt (01k) (0t) Growt" () 1976 4996 86.21 1632 13.31 4903 86.71 266 14u.6 13796 4681 16463 1975 S662 32.41 22$2 16.91 6665 43.61 268 18.11 20416 6.21 4548 2496 6.21 106 6661 30.15 816 10.71 13658 47.61 8567 12.21 20451 7.631 384 338 6.61 1901 6059 86.6s 8242 11.1X 13276 46.61 6809 12.51 29116 -1.11 8479 8256s -2.21 1902 6640 20.21 8122 10.61 14634 47.4X 8775 12.6s 29666 1.61 30 8806 1.51 1068 9084 28.711 U326 16. 16227 48.391 838 12. 5 81520 6.611 981 8561 7.21 1904 0577 29.0x 8S6 10.71 15904 46.11 4049 12.2X 336O8 4.01 4100 8n7o 4.SX 1066 9746 29.711 356 19.51 16465 47.13 4067 12.41 32s24 -o.6x 879 36468 -2.15 196 164 29.4n $776 1O.6 16868 47.61 4876 12.31 35565 6.21 34 0a345 6.1X 1067 1826 20.6x 4134 10.91 17911 47.21 4614 12.11 87984 7.O6 3698 41677 0.40 1066 11744 30.81 4162 19.86 17971 46.41 468 12.65 38760 2.10 8692 42652 1.61 1906 12317 o.61o 4876 19.71 19247 46.91 5126 12.51 4106 6.61 8071 45089 5.61 1*90 12011 29.90 454 6.ex6 26821 47.1 46s 12.53 48229 6.31 4019 4724 4.91 100 18447 29.41 4835 16.6M 21771 47.6 6694 12.41 46747 5.6% 4961 49026 5.51 1m 13669 20.01 50 10.61 23964 46.61 692 12.51 47986 4.90 419 526" 4.51 1008 14821 20.61 6878 19.7T 24248 46.21 6826 12.61 56268 4.0% 4119 54362 4.4X 1904 14765 20.21 5671 10.81 25362 46.31s O6t 12.71 62466 4.41 4127 56612 4.11 1006 15815 27.7X 612 1.9.1 26856 46.61 7626 12.7X 65218 5.21 4159 59372 4.95 1990 1695 27.sx 6861 11.61 28621 40.06 7406 12.7X 56826 5.41 4167 62392 5.15 1997 16581 26.7X 7096 11.61 89617 40.7x T769 12.61 01961 6.43 4246 6109 6.15 190 17202 26.13 7249 11.61 38161 60.41 6220 12.51 65l 6.31 4296 7M15 6. 1990 1769 25.5 7741 11.O1 85766 61.01 0674 12.43 70679 6.43 4886 74495 6.1% 2 16628 26.611 627 11.15 88676 51.71 9141 12.3 74612 6.51 4366 76076 6.1% NOTES Poreod 1970-1967: actual date Year 1.06 estimated Period 1908-20s projetions HNG-11/15/69 - 110 - NNEX 68 Page 1 of 1 (FXLE:MEMAND8) ARGENTINA - ENERGY SECTOR STUDY - POWER SUB-SECTOR DEMAND PROJECTIONS - TOTAL COUNTRY SCENARIO: Low. GDP Growth: 2.0X for 1989-200 tE----- Consumption from Public Utilitlee jAuto- Total Country (t otal - prod- Consumption Residentlmi Como_neial Industrial Othe Annual ucere Annual Year (GWh) X (OWh) X (GWh) X (GUb) S (CUb) Growth (GDh) (Cwh) Grow"h(I) 1970 4995 96.2X 1632 18.8X 4988 85.7M 20a9 14.SX 18796 4U81 16480 1976 6621 82.4x 2282 10.91 6885 48.5S 260a 18.1X 29416 s.21 4546 24w66 6.2X 1980 686l M0. 811 0 19.7X 13865 47.0X a857 12.2X 29451 7.61 8664 8a886 6.05 1061 6899 30.6s 8242 11.1X 18276 45.6X 8639 12.51 29116 -1.1X 8479 82566 -2.21 1982 8649 29.2x 8122 19.6S 14084 47.41 3776 12.8X 20960 1.01 85u9 aJJss 1.5S 1968 9084 28.7X 8826 10.6X 16227 48.8x s398 12.1X 81629 6.6X 9801 16461 7.2X 1984 9577 29.0x 8559 10.7X 15964 46.1X 4049 12.2X 33900 4.91 4190 87109 4.6X 1965 9746 29.7x 8653 11.SX 15465 47.1X 4076 12.41 82624 -o.61 8579 8648 -2.1X i16 19456 29.4x1 8778 1.61 16698 47.6X 4876 12.1 855656 6.2 8s4, 89846 6.1X 1907 11825 29.61 4184 10.9X 17911 47.21 4814 12.11 37084 7.6 3xss 41877 6.41 1968 11744 89.8X 4162 10.sx 17971 46.41 483 12.5S 88769 2.091 892 42062 1.91 1969 12817 39.06 4376 10.7X 19247 46.9X 5126 12.51 41068 6.65 8971 41689 5.6x 199 12911 29.9X 4594 19.61 20321 47.6X 54U8 12.51 48229 6.81 4a19 47246 4.S0 19 18447 29.41 4685 19.61 21771 47.6X 6694 12.4X 45747 6.sx 4961 49826 5.51 1992 18669 28.91 5991 16.6 28694 46.06 6692 12.61 47966 4.01 4198 S29 4.CX 1993 14821 2s.5x 8378 10.7X 24248 48." 6329 12.1 56268 4.8X 4119 64862 4.41 1994 147865 28.2x 6671 19.81 25862 4S.8X 6667 12.7X 52465 4.41 4127 66s12 *.1X 1"S 15208 2.1 6997 11.95 28639 48.41 7028 12.8X 54847 4.5X 4181 56976 4.2X 1996 15829 27.61 6342 ll.6X 27845 48.6x 7406 12.91 67415 4.7X 4139 01645 4.41 1967 16874 27.2x 6767 11X 29385 48.7x 7698 13.65 69224 4.9X 4129 64852 4.61 1996 16948 26.SX 7094 11.3 86788 46.sx 8229 p3.1X 68049 4.7X 4119 67169 4.41 1999 17589 20.6X 7652 11.41 82818 46.9x 8674 18.lX 624 4.7X 493 70062 4.81 290 18183 26.2X 7986 11.61 88963 49.1X 9141 18.2X 69ITi 4.sx 49"0 7216 4.5 NOTES Poriod 1970-1997: actual data Year 1998: estimated Period 1968-2009: projections HGG-11/15/89 - 111 - ANNEX 0.4 Page I of 1 (Ff le:ttEn) ARGENTINA - ENERGY SECTOR STUDY - PC128 SECTaR ENERGY DEMND P8OJECTIONS - 1UHE SCENARIOS i--- - Total Country Consumption ]Consumption Difference (1) Annual (2) Annual (8) Annual High Minus L, Scenario Year (0h) Growth(M) (GWh) Growth(M) (0th) GrowUh(S) (0th) () 1976 18486 1e486 184 197S 24966 0.23 24966 6.23 24966 0.2X 1900 esess *.es aaaas s.ux aaaas o.ax 1981 32596 -2.2X 32595 -2.2X 82s5n -2.23 ia easo. 1.SX eamse 1.6X 3ass. 1.6X 1988 86481 7.23 36461 7.23 85481 7.2X 1964 87186 4.3 37158 4.93 83710 4.83 1985 86403 -2.13 6468 -2.1X 30408 -2.1X 196 89846 8.1X 39345 8.U3 89345 8.15 1987 41877 6.4X 418" 0.4X 41877 0.4X 1989 42652 1.93 42662 1.95 4262 1.93 1989 48889 2.98 45639 6.60 456089 5.6X -12 -2.71 1990 47710 8.98 47248 4.93 47248 4.9X 476 1.OX 1991 61328 ?.OX 49828 5.5C 49828 6.65 156 2.9X 1992 54726 6.6X 52669 4.56 62669 4.53 2669 4.9X 1998 gemVI 6.53 54882 4.43 64802 4.4X 8900 6.7 1994 6165s 6.83 66612 4.1X 66012 4.13 6608 8.2X 199C 65278 5.98 69372 4.9X 59878 4.2X 62" 9.63 1996 69209 6.6X 62892 5.1X 01545 4.4X 7604 11.1X 1997 78648 0.83 66199 6.1 04862 4.03 9191 12.53 1998 78042 0.13 76156 6. 67169 4.43 15888 1l.9X 199 82868 6.2X 74466 6.13 76062 4.3X 12661 16.4X 2060 8852 6.3B 76978 6.1X 78218 4.53 14084 10.9X _***ce*" c ****_ * e"O ee (1) SE$o Energy Plan; Hlgh Deand Scenario (2) Mewt-Likely Deand Scenario (8) Low Demand Scenario Period 1970-198?; actual date Year 198s etimated Period 19f8-2w projected - Hi - A0.4A - Dwom ScR sna - P o Anneo Netlasal Ifh.rOA44.ee1 Sp%d ls - .t.tvust i. JOuwrt.2a S.d Tr2eussloelo WosIsa Issv..tmet Ilee "mate .md. two Dusesid soearl (1) (in s$ "I I Illss3 Price LevelsI Oear.,p 19o" 199 199w 191 191 i 199w 1994 1995 1996 Total A.- Hi$% Oeaaad 6c#serbc ToW Bwl. 195.7 5M5.0 879.1 4O6.6 4t4.2 U.o M1.$ 42.0 572.6 C.4-rear 801.9 428.6 2t.O 147.2 115.1 1W.6 7S.9 2.5 1916.2 SEA 186.5 16.? 204.5 200.0 1M.5 176.2 176.0 11.1 1W87. Total 6815.1 1021. 947.0 606.4 747.06597.7 1186.5 1001.7 718.6 S.- Net-Llk*lp Deomd scenario Agse y b ie 195.7 3 .0 805.1 818.6 161.9 280.7 8.0 170.6 2100. l4drno 801.9 428.6 1M6. 147.2 96.6 85.0 W6.6 28.0 186.6 SENA N13 220.7 2 U4.5 2e0.6 2S 17.12 176.6 18i.1 1497.6 Total 685.1 979.8 641.0 684.6 8.2. M71. 495.1 4=1.9 808.2. C.- Ciffer..A 0.0 4 7.0 100.0 141.6 224.5 428.9 M.2 579.9 214.4 (1) I- ..lstea oe1 AgE. NN8.S and sA ass sip. List of Projects AAs Sca ario A Ongoing Week 171.2 15.0 54.1 45.8 46.7 45.7 4i.7 4S.7 1n.6 Pass? Pl ant lWdro 5.0 78.0 141.8 2085.1 818.1 428.7 466.8 1684.8 Thof=I 12.8 7.5 0.0 0.0 19.6 Tranonileeloes Work. 11.5 69.7 196.6 2118.8 187.4 106.1 218.4 107.0 1265.9 Othes.. 13.0 13.0 18.0 18.0 18.0 18.0 18.0 18.0 106.0 Owiesels Wwee 171.2 255.0 64.1 45.5 46.7 43.7 46.7 45.7 710.6 Pmer. Plants *dro 0.0 0.0 0.0 0.0 81.5 67.1 Uo.2 st2.7 Th.ral 12.6 7.5 19.8 Trane.1.tlo. Work, 11.5 6o.7 196.6 216.5 111.1 172.8 1o 5.0 O5.9 1139.7 Others 13.0 18.0 18.0 1O.0 1t.0 O8.0 1O.0 1O.0 104.0 5~ss"rbo A Oeing Worss 2e7.7 381.1 17s.0 56.s 19.6 16.9 18.8 18.3 971.6 ltIdrsplest. Piclsl-Picw,-Lewfu 15.1 39.6 94.8 6s.0 8.9 14.8 28.8 9.6 819.6 Cel lo Cur. 10.4 29.6 82.6 76.2 165.6 ichihrsao 9.0 66.1 121.1 196.1 Trana_t_.lon System 7.6 18.7 17.6 10.2 7.1 67.6 12I. 266.3 scenrio 6 onsgoing we"k 167.7 86.1 178.0 15.6 29.6 16.9 18.8 138. 971.6 ltIdeopnt. Pioe i-Plo,n.Leu 18.1 59.6 94.6 6O.0 e8.9 14.6 2S.8 9.6 819.8 Cal los CGar 0.0 Nicb;hlso 0.0 Trawnms_lss Sy.te 7.6 18.7 17.5 10.2 1.4 62.5 Scenario A Oesnein Works 100.9 21.5 1.2 124.6 Tlns_l Oeeroatloe 81.9 146.7 181.5 6.1 16.6$ 18.0 12.4 12.4 390.2 Trom_elosi 1.5 22.4 45.8 U.8 85.7 29.0 80.4 11.6 242.6 ODltribatlus 21.2 63.0 80.7 94.0 1to.6 112.6 114.9 92.7 682.9 Other. 6.0 S.6 19.1 a.9 28.4 19.2 10.1 17.4 055901no Works 10.0. 22.8 1.1 11.6. Th ml Ceeratio 81.9 106.7 101.5 21.1 16.8 18.0 12.4 12.4 800.1 Truesmalenlo 1.5 22.4 45.8 61.8 so.7 28.0 80.4 128 . 12.6 Distribatlie 11.3 sa.0 60.7 94.0 108.6 1. 114.e9 92.7 16.9 StAres 6.0 26.6 19.1 28.9 16.4 19.1 10.1 1*7.4 - 113 - Annex 3.6 Page 1 of 1 (FILE:tVORO) ARNTINA - ENEMY SECTOR Sr.9Y - POWER SECTOR ESTIMATED GENRATION COST OF HYDROPROJECTS SELECTED FOR THE EXPANSION PLAN Averago Averase Generation Cot Instelled Energy ease At Diecount Rate Capactty Productlon Co"t as 1S Name (MW) (Wh) (U38 H) ( Illa/M) _ __ __ _ ____ _____ ____ - Corpus 4109 20100 2644 17.6 25.0 Coarenleutu 240 IlNe 16n 10.0 26.6 Cordon del Plate 1 849 2272 400 21.8 80.2 ColIon Cur 376 1492 261.6 21.6 JP.7 Los Slncos I 100 aso 64.1 22.1 81.4 Michihuso 617 2928 5689. 23.0 83.6 arabi goo 3126 626.4 24.0 $4.1 Picht Picun Leufu 251 1020 222.6 25.5 86.2 Los Blancos 324 802 184.8 29.4 41.7 El Chihuide II 26W 1060 290.6 80.9 48.7 _ _ _ _ _ _ _ ___ton- Ene-r SourCe: Nbttonal Energy Plan, SE - 114 - Annex S.7 Page 1 of 1 (FILE:CAPS9) ARGETINA - ENERGY SECTOR STUDY - POWER SU-SECTOR INSTALLED CAPACITY BY COMPANY BY END 197 (I) Type St.a. Diosel Gas Turb. Hydro Nuclear Total S AyEE 148.0 182.0 900.6 1727.0 4867.6 86.23 SEGOA 2209.0 2.0 262.0 2478.0 17.83 DEBA 856.0 64.0 207.0 627.6 4.43 EPEC 249.6 24.0 844.6 178.0 795.0 5.6. HIDRON3R 2776.9 2776.0 19.4X CTMSG (1) 1418.0 1419.0 0.9X CNEA 16180. 1618.0 7.1X Provincial 45.6 86S.0 164.0 99.6 668. 4.63 Others 156.0 85.0 1.0 192.0 1.83 Total 4407.0 788.0 1912.6 6198.0 1016.0 14268.0 180.63 x 86.9X 5.1X 18.43 48.43 7.1X 16.6x (1) Assigned to Argentinx In accordance with the International Tret ENERDY GENERATED BY COMPANY IN 1987 (GWh) Type Stem Diesl Gas Turb. Hydro Nuclear Total X AyME 6264.2 101.0 18065.0 6712.4 12872.6 26.8X SEGBA 6166.8 889.0 6445.8 17.60 DEBA 1875.7 26.7 824.1 1728.5 8.6X EPEC 992.0 7.0 616.2 486.1 2095.8 4.4X HIORONOR 7486.9 7480.9 15.63 CTSG (1) 7657.8 7657.8 15.9X CHEA 6464.8 6464.8 13.53 Provincial 81.6 426.7 214.8 478.4 1198.5 2.53 Othrc 67.6 608.8 0.6 121.7 o.83 Total 15810.3 628.0 886M.4 21610.9 6464.8 48665.4 16.63 X 82.93 1.83 7.63 45.4X 18.65 100.63 (1) DolIvered to Argentina - 115 - Andox 0.8 Pag 1 of 1 (tile:.9.) ARGENTINA - ENERGY SECTOR S1IDY - POWER SUB-SECTOR AOE OF MAJOR THERMAL PLANTS Aggregate Iutstalled Capacity (VW) Ag. (Yeare) )25 )15 (15 Unknown Total (26 SEOSA -Costanera 6of see al3 1280 -P. Nuevo 339 260 689 -Nuevo Puerto 369 8tO Total 099 960 310 0 2209 x 43X 43X 14X eX 1JOX AyE -Lujan de Cuyo 120 209 829 -San Nicolel 820 8so 070 -Sorrento 0 10 226 -3u_mas 120 120 Tote I800 120 719 120 1345 1 29X Os 53X 9X 1091 NEBA -Necochee 140 200 4. Bianca 890 0 140 Total 146 2W O 9 u4s X 42X sex eX Os 100X EPEC 616 61S TOTAL 1471 1280 1029 736 4610 1 38X 281 238 16x 1093 Source: SE - 116 - Ann x S.9 Paso 1 of 1 ARGENTIN - ENERCY SECTOR SJTUDY - POWER SUB-SECTOR SCHEDULED RETIREMENT OF MAJOR THERMAL PLANTS Not Capacity to be Retirod (MW) Plant/Unit 198 1994 1995 1990 1997 1999 1999 2000 Totel Costanera. 1 II 118 Co.tanorn 2 its 118 Coetanrna 8 118 118 Coastnee 4 1us 118 Costanera 6 us 11s P. Nuevo 7 185 1i5 P. Nuevo 8 182 182 S. Nlcolas 1 70 70 S. Nicolas 2 70 76 S. Nlcolas 8 To 76 S. Nicolas 4 76 TO Sovernto 1 81 SI Sorrento 2 81 81 D. Fun. 81 1 9 Ju1to 4 28 29 N