Colombia - The power sector and the World Bank, 1979-1987 (Vol. 3 of 3) : Annexes

Report No. 8893 Colombia The Power Sector and the World Bank, 1970-1987 (in Three Volumes) Volume 1II: Annexes June 28, 1990 Operations Evaluation Department FOR OFFICIAL USE ONLY Document of the World Bank This ?Icument has a restricted distribution and may be used by -recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. FOR OMCIL US ONLY ABREVIATIONS AND ACRONYMS AR - Accounts Receivable COL$ - Colombian Peso CONPES - National Economic and Social Policy Council CORELCA - Corporacion Electrica de la Costa Atlantica CPP - Country Program Paper CPS - Central Projects Staff, World Bank CVC - Corporacion Autonoma Regional del Valle del Canca DNP - Departamento Nacional de Planeacion DS - Debt Service Coverage Ratio ECOPETROL - Epresa Colombians de Petroleos EEB - Empress de Inergia Electrica de Bogota EP - Empresas Publicas de Medellin EMCALI - Empresas Municipales de Cali FEN - Financiera Electrica Nacional GDP - Gross Domestic Product gVh - Gigawatt-hour (106 kWh) IC - Long-run average incremental cost ICEL - Instituto Colombiano de Energia Slectrica IR - Internal Economic Rate of Return IFRR - Internal Financial Rate of Return ISA - Interconexion Electrica S. A. JNT - Junta Nacional de Tarifas kW - Kilowatt kWh - Kilowatt-hour LAC - Latin American and Caribbean Region LRHC - Long-run marginal cost HME - Ministerio de Mines y Inergia OED - Operations Evaluation Department, World Bank OMS - Operational Manual Statement, World Bank OPS - Operations Policy Staff, World Bank ROA - Return on Assets ROI - Return on Investment SAR - Staff Appraisal Report SF Self-Financial Ratio Twh - Terawatt-hour US$ - United States dollar WC - Working Capital This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. т COR8E1+iCY BXCHANGB RATEB Ув+а3 Mi„ д-Уенг (COLS per ŭSS) 1я7о 1а.б 1971 1Я.4 1972 21.9 1973 29.6 197б 26.1 2976 g6.T 1978 38.1 � 198о ат.з 198I 5�.5 1982 64.1 1983 78�g 1984 10б.8 1г8.S 1��. ь � 19$6 194.3 1987 2б2.б VOLUS III COLOMBIA THE POWER SECTOR AND THE WORLD BANK (1970-1987) AN!=ES TABLE OF CONTENTS PaKe No. CHAPTER I 1.1 World Bank Lending to the Colombian Power Sector 1970-1987 ...... 1 1.2 Inter-American Development Bank Lending to the Colombian Power Sector (1968-1987) ...................................... 2 1.3 Input of Bank Personnel Into Projects ........................... 3 1.4 Approval and Effectiveness of Bank Loans for the Power Sector ... 4 1.5 Ex lee of Discrepancies Between Facts Known at the Time of Appraisal and Presentation in the SARe ................ 5 CHAPTER IV 4A.1 Electricity Generation, Demand, and Sales Evolution, 1971-86 Total System ................................................ a 4A.2 Percent Average Annual Changes in Growth of Energy Sales Generation and Demand for Different Regional Markets, 1971-86 9 4A.3 Structure of Total System Electricity Sales, 2971-86, By User Type ................................................ 10 4A.4 Structure of Electricity Sales within Regional Power Markets, 1971-86, By User Type .............................. 11 4A.5 Industrial Sector Value Added and Use of Electricity, 1970-86. 12 4B.1 Methodologies Used in Forecasting ............................. 13 4B.2 Total Colombian Power System Energy Requirements, Sales and Losses ............................................ 15 4B.3 Total Colombian Power System Peak Domd (MW) and Load Factor (L.P.) ...................................... 16 4B.4 Models Reviewed to Assess Relationship Between Electricity Generation, GDP. and Prices ................................. 17 4B.5 Total Energy Deniand, Losses, and Sales and GDP Actuals 1971-86 19 4B.6 GDP and Its Growth ........ 20 4B.7 Deviation Between Forecasted and Actual GDP, 1972-86..**#****. 21 4B.8 17m Markets Energy Required, Sales, and Losses .............. 22 4B.9 ZPM Markets Energy Required. Sales. and Losses ............... 23 4B.10 ICEL Group: Energy Requiremnts, Sales, and Losses ........... 25 4B.11 CORELCA Group Market: Energy Requirements, Sales, and Losses. 26 4B.12 C.V.C. (Valle de Cauca): Energy Required, Sales, and Losses.. 27 4B.13 Generation, Sales, and 28 4B.14 Projected Versus Actual Energy Sales Performance .............. 29 Table of Contents (cont'd.) Page No. 4C.1 VEEE Markets Energy Losses.................... ........ .. . 30 4C.2 VFM Markets Energy Losses..................................... 31 4D.1 The Cost of the 1981 Power Rationing.......................... 32 4D.2 Cost to the Economy of Surplus Generating Capacity............ 36 4E.1 Energy Balance ............................................... 40 4E.2 Peak Demand . ......................... .... .*...... 42 4E.3 Energy Balance: December 1978 Plan and Historical (Actual) Demand .........*.*..... 00*..... *................ 44 4E.4 Energy Balance: December 1978 Plan and Historical Demand ..... 46 4E.5 Excess Power Supplys Original Investment Schedule (December 1978 Plan)........................................ 49 CHAPTER V 5A.1 Price Deflators. ................. .......... ........... 50 58.1 Evolution of Average Tariffs for the Power Sector By User Type, 1971-1987...... ..... . .................. 54 53.2 Evolution of Average Tariffs for the Power Sector By Company, 1971-1987 .................................. .............. 55 58.3 Percent Average Annual Changes in Average Retail Tariffs in Real Terms for Different Regional Markets................ 56 5C.1 Performance of Tariffs Relative to Projections................ 57 5C.2 Projected Versus Actual Tariff Performance............to...... 65 5C.3 Projections of Macroeconomic Variables in SAR...........to... 67 5D.1 Marginal and Incremental Supply Cost Studies.................. 73 5D.2 Reference Subtransmission and Distribution Marginal Costs..... 75 5D.3 1979 Marginal Cost Estimates Based on the ISA/EP Study....... 77 5D.4 1983 and 1986 ISA Studies of System Incremental Costs for 1984-93 Period ........................................... 87 5D.5 Average Retail Tariff Distortions Relative to LIMC, 1978-86, By Company and Type of User..............#................ 89 5E.1 The Development of Bulk Tariff Policy 1971-86................. 90 51.2 Ratio of ISA Bulk Tariff to Average Retail Tariffs at the Overall National Level By Consumer Type................. 94 57.1 Internal Rates of Return...................................... 95 5F.2 Ex-Ante Internal Rate of Return for Consolidated Power Sector at Guavio Appraisal (1980) ................ .. ... ... .... 97 5F.3 Ex-Ante Internal Rate of Return for Consolidated Power Sector Investment Program (1983-1987) in the P.E.N. Operation (1983) 99 57.4 Average Incremental Generation Costs for Sector Investment Program 1983-87 Set Out in the FEN SAR (1983).... 101 Table of Contents (cont'd.) Page No. 57.5 Ex-Ante AIFRR of the EEEB Investment Program for 1983-87 Set Out in the PEN SAR................................ 103 57.6 Unit Cash Operation, Maintenance, and Administrative Costs of Power Companies 1971-1986........................ 105 57.7 Ex-Ante Internal Rate of Return for Consolidated Power Sector Investment Program 1987-1990s Power Sector Adjustment Loan (1986-87) ................................................... 106 5F.8 Ex-Ante Estimates of Adjusted Internal Rates of Return for the for the Consolidated Power Sector's Investment Programs Between 1980-1990...... ..... ... ....... . ............. 108 5G.1 Re-Estimation of the San Carlos I Ex-Ante Rate of Return...... 111 5G.2 Re-Estimation of the San Carlos Complex Ex-Ante Rate of Return 113 5G.3 Absence of Fuel Savings Claimed in the Economic Appraisal of Mesitas SAR .............................................. 114 5G.4 Ex-Ante Estimation of Mesitas Project - Generation Component AIERR Assuming Bulk Sales into Inter-connected System...... 116 5G.5 Re-Estimation of the Bogota Distribution I and II Ex-Ante Rates of Return.......................... ................. 117 5G.6 Re-Estimation of Guadalupe IV and Playas Ex-Ante Rates of Return ............................................. 124 5G.7 Re-Estimation of the Guavio Ex-Ante Rate of Return............ 130 5H.1 Ex-Ante Average Incremental Costs of Expansion Programs of EEEB and EPM for the 1981-88 Period...................... 133 5J.1 Power Tariffs.... .0 .................... . ................ 137 5J.2 Resolution JNT 086 of 1986 on Tariffs....................... 138 5J.3 June 1987 Retail Tariff Structures and Levels for Residences.. 139 5J.4 Typical Bills for Residences.................................. 140 5J.5 Intra-Residential Sector Subsidies per User for Fixed and Variable Portions of Tariff............................. 142 5J.6 Impact of Resolution 086 on Residential Tariffs............... 143 5J.7 Rural Vers s Urban Residential Subsidies...................... 145 5J.8 Consumption Patterns of Modern Household Fuels By End-Use and Fuel Type................................................ 147 5J.9 Relative Retail Prices of Modern Household Fuels, 1971-1986... 149 CHAPTER VI 6A.1 Consolidated Funds Flow Statement for ISA, RPM, EEEB, and ICEL, Based on Audited Accounts... ........................ 151 6A.2 Methodological Issues Arising in the Financial Evaluation...... 152 6B.1 EEEB-Income Statement 1970-86......................... .... 167 6B.2 IEEE-Balance Sheet, 1970-86.................................... 168 63.3 EEEB-Funds Flow, 1970-86.................... ..9........ 169 Table of Contents (cont'd.) Pase no. 63.4 888-Performance Indicators, 1970-86......................... 170 6B.5 EPM-Income Statement, 1970-86.............. ... . ............ 171 68.6 EPM-Balance Sheet, 1970-86.................................... 172 63.7 EPM-Funds Flow, 1970-86....................................... 173 63.8 EPM-Performance Indicators, 1970-86.......................... 174 65.9 ISA-Income Statement, 1970-86................................. 175 63.10 ISA-Balance Sheet, 1970-86.................................. 176 63.11 ISA-Funds Flow, 1970-86................ ................ 177 63.12 ISA-Performance Indicators, 1970-86...... .................. 178 63.13 ICEL-Income Statement, 1970-86............................... 179 63.14 ICEL-Balance Sheet, 1970-86....... .......................... 180 68.15 ICEL-Funds Flow, 1970-86............ ......... 181 CHAPTER VII 7.1 Colombia: Interconnected System: Capacity and Peak Demand (Actual and Projected)........................................ 182 Colombias Interconnected System Energy Required and Generation Capability (Actual and Projected).............. 183 7.2 Scheduled and Actual Implementation of Major Facilities.... .... 184 7.3 Analysis of Bank Project Costs ............................. 188 7.4 Analysis of Escalation in Bank Project Costs..................... 189 7.5 Distribution Investment in Terms of Total Investment............ 190 ANNEM-1I WORLD BAN LENDING TO TE COLOMBIAN POMER SECTOR 1970-87 Loan Date of Loan no. Borrower Proiect Approval Amount (US$ millions) 0681 ISA Chivor Hydro 05/70 52.3 0874 EPM Guatape 11 Hydra 01/73 56.0 1582 ISA San Carlos I Hydra 05/78 126.0 1583 Gov't 500-KV Interconnection 05/78 50.0 1628 Z8EB Mesitas Hydra 11/78 84.0 1725 ISA San Carlos II Hydra 06/78 72.0 1807 piEB Bogota Distribution I 03/80 87.0 1868 3PM Guadalupe IV Hydro 06/80 125.0 1953 BPK Playas Hydra 03/81 85.0 1999 CORELCA, Village Electrification 05/81 36.0 2008 NEEB Guavio Hydra 05/81 359.0 2401 PEN Power Development Finance 03/84 170.0 2449 BPM Rio Grande Multipurpose 06/84 164.5 2634 1EB Bogota Power Distribution II 11/85 171.0 2889 Gov't Power Sector Adjustment 12/87 300.0 -2- ANNEX 1.2 INTER-AMERICAN DZVELOPHWr BANK LENDING TO THE COLOMIAN POWER SECTOR (1968-1987) LOAN APPROVAL LOAN NO. BORROWER PROJECT AMOUNT DATE (US$ millions) OC-175 CVC/CHI Alto Anchicaya Hydro 63.0 12168 OC-211 ICEL Subtr. Distribution 9.8 02171 80-290 ICEL Subtr. Distribution 16.0 02171 OC-214 ISA Chivor Hydro 53.0 05/71 OC-249 8EER Transa. Distribution 21.2 06/73 OC-258 CHEC Esmeralda/Iusula Hydra 4.9 10/73 80-374 CHEC emeralda/Insula Hydro 2.4 10/73 OC-263 ISA Chivor II Hydra 58.6 12/73 IR-19 ISA San Carlos Hydro 96.6 12177 IR-39 ISA Jaguas Hydro 111.7 11/78 IR-40 ISA Jaguas Hydro 30.0 11/78 OC-371 CVC Salvajina Hydro 51.5 12/79 50-608 ICEL Rural Electrification 50.0 08/80 IR-70 EPM Playas Hydra 106.4 12/80 IR-77 WEB Guavio Hydro 173.8 06/81 OC-438 GOVERNMENT Small Hydro (ICEL) 25.0 08/83 IR-126 BEEB Guavio Hydra Suppl. 411.5 12/83 IR-160 ISA Jaguas Hydro Suppl. II 52.0 05/85 IR-195 ISA Transmission 115.8 12/85 IR-237 MN Distribution Program 80.0 12/86 IR-242 ISA Interconnection Suppl. 86.6 07/87 OC-540 ISA Guavio Suppl. II 360.0 11/87 OC - Ordinary Capital IR - Inter-Regional Capital SO - Special Operations COLOMBIA THE POWER SECTOR AND THE WOLD BAK (1970-1987) Input of Bank Personnel into Projects Loan Project Preparation Grand no. Proiect and Processing Follow-Up Total Programs Projects Total Programs Proiects Procurement Total *-*-*- - ************---- -- Manweeks --*a*- - -- .-- .......e- ...... 0874 Guatape Hydro ZZ - 33.2 33 12.5 82.6 - 95 128 1582 San Carlos I Hydro 44.7 64.1 109 5.4 47.7 - 53 162 1628 Mesitas Bydro 13.9 57.1 71 3.6 43.3 - 47 11a 1725 San Carlos II Hydro 13.8 53.6 67 3.7 59.4 5.9 69 136 1807 Bogota Distribution 15.0 87.5 103 1.5 73.3 3.1 78 181 1868 Guadalupe IV Hydro 8.8 42.6 51 4.0 58.4 9.4 72 123 1953 Playas Hydro 7.4 16.3 24 3.0 40.8 2.5 46 70 1999 Village Electrification 12.3 46.9 59 5.4 60.6 2.6 69 128 2008 Guavio Hydro 21.4 77.0 98 12.7 62.8 5.2 81 179 2401 Power Dev. Finance 67.6 64.6 A2 2.8 31.0 - 34 166 2449 Rio Grande Hultipurpose 19.0 97.8 7 0.5 15.9 8.8 25 142 2634 Bogota Distribution II 15.0 57.0 72 - 11.8 8.9 21 93 2889 Power Sector Adjust. 45.0 224.9 270 - 20.8 - 21 291 Total 283.9 922.6 1,207 55.1 608.4 46.4 710 1,917 --4 - -4-4 ANNEE 1.4 COLOMBIA TiE P0N1R SECTOR AND TEE BANK (1970-1987) Approval and Zffectiveness of Bank Loans for the Pover Sector No. of Other Tim E1apsed Loans NOcr Beteen Board Effective Loan «onth of Approval and at Time of No. Borroer Plroect Awproval Effectiveness Approval (months) 0681 I8A Chivor Hydro 05170 4 0 0874 ElH Guatape II Bydro 01/73 2 0 1582 I8A Sa. Carlos I Bydro 05/78 11 1 1583 Gov't 500-xV Interconnection 05178 5 1 1682 EE= Meitas äydro 11,78 9 1 1725 ISA San Carlos II Hydro 06/79 21 1 1807 EEE Sogota Pover Distribution 03/80 18 1 1868 gPm Guadalupe IV Kydro 06/80 12 2 1953 £mN playas Hydro 03/81 15 3 1999 C0EELCA Village Electrificattoa 05/81 21 5 2008 EES Guavio Nydro 05/81 17 5 2401 FE Poer Dev. Finance 03184 6 0 2449 EPM Uio Grande Nultipurpose 06/84 6 1 2634 EEB Bogota Pover Distribution II 11/85 22 0 2889 Gov't Poer Sector Adjustment 12/87 21 0 -5- ANNEX 1.5 Page 1 of 3 COLOMBIAs POWE SECTOR REVIEW 1970-1987 Examples of Discrepancies Between Facts Known at the Time of Apraisal and Presentation in the SARs 1. The following are a few striking examples supporting review team's finding that the image projected in the SARs for power projects of the early 1980s in Colombia was far too optimistic and that this optimism was less than fully justified at the time. The examples are taken mostly from the SAR for the Guavio project, because the discrepoancy between image and facts proved expecially dramatic in this operation, which developed to a major problem project. However, similar examples, some of them set forth here, too, appear in many other operations. 2. The sector section of the SAR for the Bogota Distribution Project of March 1980 does not mention the *Acuerdo de Call,* though the latter took place four month before Board presentation. The Guadalupe IV SAR of June 1980, however, states that the ownership issue was Ounder discussion* because ISA's shareholders had misgivings about (i) the loss of parity among them-selves and ISA and (ii) ISA's over-commitment in construction. It then describes the agreement reached in s board as a Oproposal.f(l) In reality, it was a de-ision which the Bank was desperately trying to have modified in the general direction of its own concept of ISA's role. The SAR then plays down the impact of the 'Acuerdo' on construction and ownership of the next round of plants (2740 MW), by mentioning that the reallocation concerns less than 1Z of the hydro resources Colombia would develop over the next 20 to 30 years, a manifest error, that, however was repeated in the SARa for Playas and Guavio. (2) These two SARs go on to describe the agreement ultimately reached between the Bank and the sector, but fail to put it in the perspective of previous compromises in a similar vein in the late 1960s and In 1976 (Acuerdo de Sochagota. (3) 3. As to the financial situation of the sector as a whole and that of ISA, in particular, the two SARs submitted in 1980 concentrate on the measures envisaged(4) without mentioning that in 1979, tariffs had failed to increase in real terms and had led to the highly unsatisfactory state of affairs. This state made it impossible for ISA to meet its obligations towards the Bank and other creditors from its own means.(5) The Playas and Guavio SARs, which were submitted in spring 1981, do not discuss the late 1979 situation at all. They are also rather evasive about that in late 1980, which, if anything, was worse. (6) Only the fact that corrective measures are said to have been taken, may lead the reader to the conclusion that M88B, ICEL, and CORELCA were in arrears with ISA. Nothing, however, appears about success or failure of the measures considered one year earlier.(7) Only a footnote indicates that in 1980 net internal cash generation contributed only about 7Z to financing the sector investment program, and that the Government had to chip in 27Z of the require- ments from budgetary resources. (8) -6- ANNE 1.5 Page 2 of 3 4. The most Important point concerning the presentation of EEED, especially the company's finances, is the assumption that rates would be increased by an unprecedented 20Z per year in real terms for three years. There is not the least Zaubt about *xe necessity of such increases, however, the Bank's experience with the Colomb power sector should have dictated a presentation of the well known obstacles ,. the course of deciding and implementing such measures. A further unclear point refers to EEU's accounts receivable, which, in accordance with audited financial statements were at 372 and 47% of operating revenues for 1979 and 1980; the SAR for Guavio indicates 22? and 231, respectively;(9) a possible explanation of the discrepancy could be that the SAR did not take into account the arrears of Empresa de Agua y Alcantarillado de Bogota (EAAB), which EEB was offsetting against its capital contributions for the Chingaza project.(10) Further, the presentation of the Guavio operation does not include a discussion ol ISA, which was supposed to provide in excess of US$150 million of counterpart financing and for which the information provided in the SAR for San Carlos II was in many respects outdated.(11) Such a presentation, if candid, would have shown that ISA was in a worse financial shape than that of EEB which was far from brilliant. 5. In the more technical field, the three SARa dealing with hydropower projects assumed the physical contingencies for underground work uniformly at 20? of base cost, which suggests that the risks were considered about the same for all the projects. The appraisal cost estimates were based on actual bids in the case of Guavio and on actual contracts for similar nearby projects in the case of Guadalupe IV and Playas. The uncertainty implied in the Guavio estimate was somewhat lower than for the two other projects. However, this cannot make up for the known difference in the risks of tunnelling in the Central Cordillera in the Medellin area, where the two EPM plants are located, as against similar underground work in the eastern Cordillera where Guavio is situated in the same general area of the Chivor, Chingaza, and Mesitas projects, all partly financed by the Bank and fraught with substantial tunnelling problems. 6. Instances of SARs projecting an image at odds with reality are also to be found in earlier and later appraisals reviewed here. Thus, the SAR for the San Carlos II loan includes a rather misleading error in the projected income statement for the four years immediately ahead. Indeed, for 1979 to 1982, ISA purchases have been added to ISA sales and shown as sales. The correct figures would have shown ISA not meeting the rate of return covenant under the San Carlos loan.(12) The SAR for the FEN operation (Loan 2401) provides a similar example. Indeed, comparing Annexes 1.3 and 1.4 of that SAR shows that the assumed sales growth for the sector was 13.82 between the actual value of 16.7 TWh for 1982 and the estimated value of 19.0 TWh for 1983. Actually, sales grew only by 5.5?, a key figure that should have been available, at least in its order of magnitude, at the end of 1983, when Bank staff had to finalize the report, which it submitted to the Board in March 1984. -7- ANNEX 1.5 Page 3 of 3 ENDNOTES (1) SAR Guadalupe IV Hydro Power Project, May 16, 1980, para.1.11. (2) SAR Playas Hydro Power Project, February 9, 1981, para.1.11 and SAR Quavio Hydro Power Project, May 6, 1981, para. 1.11. (3) SAR Playas Hydro Power Project, February 9, 1981, para.1.11, and SAR Guavio Hydro Power Project, May 6, 1981, para.1.11. (4) SAR Guadalupe IV Hydro Power Project, May 16, 1980, para. 1.12 and 1.35. (5) Francisco J. Ochoa: Incidencia de los problemas Financieros en los Racionamientos de Energia Electricas Lecturas de Economia. No. 19. Medellin, enero-abril 1986, p.70. (6) Francisco J. Ochoa: Incidencia de los problems Financieros en los Racionamientos de Energia Electrica; Lecturas de Bconomia. No. 19. Medellin, enero-abril 1986, p.71. (7) SAR Playas Hydro Power Project, February 9, 1981, para. 1.12 and SAR Guavio Hydro Power Project, May 6, 1981, para.1.12. (8) SAR Guavio Hydro Power Project, May 6, 1981, footnote on p.40. (9) SAR Guavio Hydro Power Project, May 6, 1981, para.2.07. (10) PPAR for Mesitas Project, February 13, 1987, ORD Report No.6638, para. 5.4.1. (11) IDB Project Report a Guavio Hydroelectric Project, June 9, 1981, paras. 3.50 and 3.51. (12) SAR San Carlos II, May 30,1979, Annexes 3.2 and 5.1. ANNEX 4A.1 ELECTRICITY GENERATION, DEMAND. AND SALES EVOLUTION, 1971-86 TOTAL SYSTEM 1971 1976 1980 1986 Generation (TWh) 8.19 13.52 19.45 27.55 of which: Hydro 6.28 10.06 14.31 21.09 Own Use (TWh) 0.12 0.24 0.41 0.57 Losses (TWh) 1.37 2.28 3.97 6.57 as X of Net Generation 17.00 17.20 20.90 24.40 Sales (TWh) 6.71 11.02 15.10 20.41 of which: Residential 2.78 4.53 6.85 9.88 Industrial 2.26 3.70 4.47 6.16 Comercial 0.85 1.41 1.87 2.15 Other 0.83 1.38 1.90 2.22 Peak Demand (MIW) 1,620 2,580 3,570 4,840 Load Factor (M) 57.60 59.80 62.30 65.00 -9- ANNEX 4A.2 PERCENT AVERAGE ANNUAL CHANGES IN GROWT OF ENERGY SALES GENERATION AND DEKMD FOR DIFFERENT REGIONAL MARETS 1971-86 (Percent Sales) Peak Residential Commercial Industrial Total Generation Demand ----- (Percent)----- 1971-76 CORELCA 6,8 9.3 15.7 13.2 14.4 n.a. ICEL (Group) 14.0 12.1 11.4 12.5 7.8 n.a. EBEB 12.9 10.3 8.8 10.3 8.7 8.3 EPM 7.5 9.4 9.6 8.4 11.0 6.5 ECALI 10.1 12.8 6.8 8.8 - 10.2 CVC (propio) 11.9 9.2 16.5 12.6 14.4 4.4 ISA *- - - - - Average National 10.3 10.6 10.4 10.4 10.5 9.8 1976-1980 CORELCA 14.3 9.2 1.1 8.8 11.9 n.a. ICEL (Group) 16.2 9.6 9.1 129 2.7 n.a. EB 9.0 5.6 5.8 7.0 -2.7 8.2 EPM 5.6 6.3 4.1 5.9 8.0 5.6 ECALI 7.8 5.6 4.2 5.8 - 5.4 CVC (propio) 15.7 9.1 5.2 10.1 2.1 14.8 ISA / - - - - 669.2 L - Average National 10.9 7.3 4.9 8.2 9.5 8.5 1980-86 CORELCA 10.2 6.5 11.6 e.0 4.7 n.a. ICEL (Group) 7.6 3.0 6.7 6.4 3.5 n.a. EBM 5.6 -2.7 3.5 3.5 -0.5 4.0 EPM 3.5 6.2 4.1 4.0 2.0 4.9 ECALI 5.8 4.7 2.1 4.2 - 5.4 CYC (propio) 6.8 -2.3 4.6 5.0 6.2 5.4 ISA - - - - 16.2 - Average National 6.3 2.3 5.5 5.2 6.0 5.2 1971-86 CORELCA 10.1 8.1 10.0 9.9 9.8 n.a. ICEL (Group) 12.0 7.7 8.9 10.1 4.7 n.a. BEB 8.9 3.7 5.8 6.7 1.9 6.5 EPM 5.4 7.3 5.9 6.0 6.5 5.6 ENCALI 7.7 7.6 4.2 6.1 - 7.0 CYC (propio) 10.8 4.4 8.6 8.8 7.8 7.5 ISA / - - - - 83.0 L - Average National 8.8 6.3 6.9 7.7 8.4 7.6 /a ISA's generation only began in 1977; before then it was zero. - 10 - ANNEX 44.3 STRUCTURE OF TOTAL SYSTEM ELECTRICITY SALES, 1971-86, BY USER TYPE (2, Percent) SALES 1971 1980 1986 Residential 41.4 45.4 48.4 BEES 23.1 24.2 23.3 KIM 30.5 22.0 18.7 ENCALI 10.3 9.1 8.9 ICEL (Group) 17.3 24.6 26.5 CORELCA 12.3 11.8 14.6 CYC (propio) 3.2 4.1 4.2 Sub-Total a 100.0 100.0 100.0 Industrial 33.6 29.6 30.2 Ew8 27.5 26.5 23.6 EtH 23.1 21.5 19.9 sCALI 17.1 14.1 11.6 ICEL (Group) 13.8 16.8 17.9 CORELCA 13.8 15.1 21.1 CVC (propio) 3.6 4.8 4.6 Sub-Total fa 100.0 100.0 100.0 Commercial 12.8 12.4 10.5 EE 36.8 34.1 25.4 EPM 14.6 13.6 16.8 RCALI 9.5 9.8 11.3 ICBL (Group) 18.1 21.3 22.4 CORELCA 14.0 14.4 18.4 CYC (propio) 3.2 3.2 2.4 Sub-Total 1& 100.0 100.0 100.0 Others 12.2 12.6 10.9 TOTAL 100.0 100.0 100.0 La The sub-totals do not add to 1002 since some small markets are not included In the above classification, e.g. the mAnicipal markets of Amenia, Pereira, Quindio, Tulua, and Cartago. b Includes sales for public lighting, official, and other sales. - 11 - ANNEX 4A.4 STRUCTURE OF ELECTRICITY SALES WITHIN REGIONAL POWER MARETS, 1971-86, BY USER TYPE (Z, Percent) Sales Structure in User Group/Year 1971 1976 1980 1986 I. REE Market Residential 35.1 39.4 42.5 47.9 Industrial 33.9 31.7 30.4 30.3 Commercial 17.2 17.2 16.4 11.3 Other 13.8 11.7 10.7 10.5 Total 100.0 100.0 100.0 100.0 II. EPH Market Residential 52.4 50.3 49.6 48.0 Industrial 32.1 33.9 31.7 31.8 Commercial 7.9 8.2 8.3 9.4 Other 7.6 7.7 10.4 10.8 Total 100.0 100.0 100.0 100.0 III. CORELCA Market Residential 38.4 28.8 35.1 39.7 Industrial 35.1 39.3 29.3 35.7 Commercial 13.6 11.5 11.7 10.8 Other 12.9 20.4 29.3 13.8 Total 100.0 100.0 100.0 100.0 IV. ICEL (Group) Market Residential 43.9 46.8 52.8 56.5 Industrial 28.1 26.8 23.4 23.7 commercial 14.3 14.1 12.5 10.3 Other 13.6 12.3 11.3 9.4 Total 100.0 100.0 100.0 100.0 V. EKCALI Market Residential 35.0 37.1 40.0 43.8 industrial 47.0 42.9 40.4 35.8 Commercial 9.9 11.8 11.8 12.1 Other 8.1 8.2 7.9 8.3 Total 100.0 100.0 100.0 100.0 VI. CVC (propio) Market Residential 39.3 38.0 46.7 51.3 Industrial 35.8 42.8 35.7 35.0 Commercial 11.9 10.3 9.9 6.4 Other 13.0 9.0 8.0 7.2 Total 100.0 100.0 100.0 100.0 - 12 - ANNEX 4A.5 INDUSTRIAL SECTOR VALUE ADDED AND USE OF ELECTRICITY, 1970-86 Ratio, R2* Public Kwh of Electricity Industrial Electricity Self-Generation Used by Industry Sector Sales to of Electricity Per Peso of Value Industrial by Industrial Industrial Year Added Sector Sector Value Added (1970 Peso (gh) (gb) 10-3(vh/1970 Ps) x 109) 1970 27.43 N.A. 1,096 N.A. 1971 28.69 2,255 1,136 118.2 1972 32.37 2,650 1,216 119.4 1973 36.71 2,910 1,312 115.0 1974 39.67 3,110 1,322 111.7 1975 40.64 3,250 1,151 108.3 1976 44.30 3,700 1,211 110.9 1977 45.52 3,710 1,159 106.9 1978 48.13 4,115 1,199 110.4 1979 49.02 4,385 1,259 115.1 1980 52.84 4,475 1,105 105.6 1981 49.52 4,480 1,532 121.4 1982 49.75 4,680 1,576 125.8 1983 49.98 5,005 1,477 129.7 1984 54.43 5,325 1,834 131.5 1985 54.70 5,480 1.415 126.1 1986 65.20 6,160 2,125 127.1 Sourcet DANE for data on Industrial sector's self-generation of electricity. - 13 - ANNEX 4B.1 Page 1 of 2 METHODOLOGIES USED IN FORECASTING 1. Electricity demand forecasting methodologies employed by the Colombian power sector up to the early 1980s were very simple. They were based on purely 'statistical models" that essentially relied on a least-squares statistical fit to historical sales igeneration data and from this extrapolations were made into the future to arrive at projections of energy requirements, taking. into account forecasts of GDP. These methods had withstood the test of time well in the 1960s and 1970s, which was characterized by steady and high rates of economic growth coupled with very high rates of electricity demand increases characteristic of the early stages of electrification in a country. It is, therefore, not surprising that the power sector relied on such forecasting methodologies as the basis on which to project demand into the 1970s at the time that the 1978-84 sector investment plan was being prepared in 1977178. In this context, the Bank's 1977 and 1979 Economic Reports both foresaw strong GDP growth in the 1980s. This resulted in the forecasted rates of demand growth into the 1980s being roughly similar to what had transpired in the 1970s. This is shown clearly in Attachment 6.15, where actual demand growth rates in the 1970s are compared with those forecasted for the 1980s in all of the markets. From this it is evident that in the cases of the REEB, ICEL, and the overall sector projected rates of growth of either sales or energy required between 1979/80- 86 were virtually identical to actual rates from 1971-79/80. In the cases of the CORELCA and CVC (Valle) markets, however, projected rates were higher, while it was only in the RPM market where growth was projected to slow down due in part to perceived saturation effects. 2. It was not until 1980/81 that econometric demand models, which were able to capture income, price, and demographic effects, were introduced ati planning tools into the power sector. Two main models were developed -- one for ISA, which was completed in 1981, and the other through the ENE project, which involved a comprehensive study of the entire energy sector. The principal difference between the ENE and ISA demand models was that the former took into account the effect of inter-fuel substitution, which was especially important for household users, whereas the ISA model did not. From the standpoint of this evaluation two points are relevant regarding the use of these models in the 1980181 period. First, the ENE model had projected for the 1980s that electricity demand for the overall power sector would grow at a rate between 6.92 and 8.82, the upper and lower ranges being determined partly by the degree of inter-fuel substitution. The most likely rate considered by that study was 8.5% annually. Second, in 1981 the ISA model forecasted that electricity demand for the power sector during the 1980s would grow at about 82 annually on the average. 3. These two forecasts contrasted with the 10.82 annually that the sector had accepted for growth in the 1980s based on the *statistical* approach. It was not until 1983/84 that the power sector *accepted' that power demand forecasting would be based on econometric methods. Concurrently, demand projections began to be lowered from 1983, since the recession was then fully recognized, though it took another 3 years before the investment program was slashed. It proved to be an expensive learning curve. It would appear that - 14 - ANNX 4B.1 Page 2 of 2 there were four reasons behind the reluctance to reduce the demand forecasts to levels even compatible with those produced by econometric methods. First, the astatistical models had established good track records in the 1960s and 1970s. Second, the econometric models represented unknown quantities of much less transparency than the 'statistical models.I Third, the rationing in 1981 created an atmosphere that shortages need to be avoided at almost any cost and this was reinforced by the alarmist estimates of the economic cost of the outages that were being canvassed at the time. Fourth, reducing the demand forecast meant that the investment program in generation would be slashed, resulting in some of the pet projects of companies being postponed or cancelled--a fate all considered to be too 'costly,* especially in regional political terms, to entertain. 4. There is a lesson to be learned here. The Bank was not an important actor in Colombia in the area of assisting the development of methodologies for power demand forecasting until it was the executing agent for a UNDP-financed effort in power system planning that began in 1983 and which contained a component on demand forecasting. Before this, the work on demand forecasting that emerged out of the ENS project was bilaterally financed. In addition, it was as a result of the outgrowth of the SSE study on the power sector that ISA decided to commission, in 1979, the preparation of an econometric demand model. The ESSE study was also bilaterally financed. In other words, there had been no focus in the Bank's Technical Assistance on demand forecasting. This was probably justified in view of what appeared, legitimately, to have been higher priorities in the late 1970s. This is likely to have reduced the potential influence the Bank could have exerted during the critical 'transitional years, from a *statistical* to an 'econometric' view of demand forecasting--i.e. the period 1978/79 to 1983. 1 ESSE study, 1979. cs R с ���#����3�3�$��� � �` �� � � � � � � �' � о iв .в'�i й i % � � � _ ^$ -,,..,в's��яs�,��. �� _ 7 � �.� � � � � i. а • а . а s а а � � �� 1� рΡ 9 t t�� t f ir � в� f� 1� t� v а $ ё ������ ��„��,�����.,�� 3� � епа�'� �в����s�r� � � з п� i . �sвк'вп��'вв � . . � а „�� ���� .. л Т а s s s s s s s s s �� �_'; �'r . Ж � в i i i i i i i i i� t t t� v S i� 9� � g � $ s i ������.����„ ��� З � g � 1�t �1 � р ��i1 gрΡ � tvв �и Ол �б +�,ei 3 � � �� � � � О О1 r р О л О 9 t / i � 1 t 1 v � 1: � 6� � V р N � О�в у�в 01 ав � � �t'j � т� � � 1 $ � � Й р У & $ � 1 � t 1 / 1 V � � • А А А А А А А�в 1► � 4� >� s V�i д V S MV Ов 4 � $ � •� � v ь4 ь�i v v вi � в�� � � � � � � � � ' � g С а � � �i �i Pi � � � ё v � � ' 'i w io � $ 8 � 8 � � � � � � � � � � � . ''� �g► � � � �s��b йq ё чуΡ� Sq�i л � Gj� � �i О� ii О� О О V i 1 � 1 t 1 1 1 v 1в /�в� А А А А А � � ` Р V О О� О О� Q с У О � ь�i ьаё � vi у вi S wpi 1 � � � � t � � '3 � . сы � ..1 �p�ОΡ�V�рΡ �{G� �_ � � р д У О � � � � � 1 1 � t / 1 � �» 2 л• �рΡ �t 1`i S � р ; 1". i� О � д # iь �i �� t r � • г � � � � � � г �� � �_O • ii w о v .3 � р ь�i v�i v / � � 1 1 1 / 1 � 1 1 � л иnю�•p �в1r�.в с а � V р 7� Oi i+ О О V р 1~. Р Ч й О О О � � � &' i $ 8 $�' $ S � ё iв i: о Sj � � о ,,, � � : а p�S j[ � О О�в�рΡ V Ат 0p1 д�л�sD �ы �рΡ О�рΡ О bb Vp РуΡ �(_в а д влв Ф Ч��1 д 9 Р О д д О: Ф i О � 1Гi� �л� ��л цs�оv й й З� ь� v V�7 V V V V V . с z •s7 х�нл� - s,� - ` . , - 16 - AM= 0. 3 MAL ~0 com n- m PEM R~- OM Am Lm FACTOR (6.Fä Foc~ and Amma#* IM:ffl $= Carlo* I cm Carl« 11 A22m~ #Mraleal - 444v19 82e-relagt mu im -May ftz am wrob IN4 Acual P«k P«k P«k P«k P«k RMndLJ. £Mod L. _F. D~nd LJ. D~nd _LJ. Rfflgd LY- om M (M m om (9) (M m (WC (0 1,628 b7.6 1,774 59.4 1,979 69.2 1974 2,168 69.6 im 2,30 80.4 19782,478 60.; 2~ 59.9 1"7 2,90 89.4 2,737 89.9 2,8n 80.3 im 3,141 60.0 *~ 60.8 3,00 60.7 1979 80.8 60.4 3,319 81.5 im 61.4 60.8 8^7 81.2 *,ma 82.9 INI 49= 61.9 4,ug 81.6 4,~ 81.2 8,4« ~ im 4,~ 61.9 4,760 61.6 4,«» 80.7 3,~ 88.8 im Lin 62.4 6,192 62.1 8,111 81.2 4,120 84.0 4,040 U.2 1m4 $~ 62.8 8,~ 82.0 8,= 41.0 4,408 64.0 4~ 68.4 im @,om 62.7 6,246 61.6 6,216 61.0 4,160 64.0 4,486 86.2 im 8,«1 60.8 6,101 84.0 4,~ - 17 - ANNEX 48.4 Page 1 of 2 MODELS REVIEWED TO ASSESS RELATIONSHIP BETWEEN "ECTRICITY GENERATION, GDP, AND PRICES 1. There were three simple models OED looked at to shed some light on the relationship, at the sector level, between GDP, electricity prices, and electricity generation requirements. The first and most simple model is the one discussed in the text which represents s linear relationship between GDP and electricity demand growth. This model, at the aggregated level of the sector, gave the best explanation of past trends. 2. OED also assessed the degree to which models, other than the simple one discussed above, could shed further light on the ex-post behavior of energy demand in the review period. Two models looked at that incorporate income, price, and lag effects, as specified by equations (2) and (3) below, are: Model 2 log(Et) * A1 + B, log(GDPt) + Cjlog(Pt)*****...........(2) Model 3 log(Bt) - A2 +'2 log(GDPt) + C2 log(Pt) + D2 log(Et-)..(3) Here, Et, Pt, and GDPt refer to the overall system electrical energy require- ments, national average retail electricity price, and GDP level, respectively, in year t. The income and price elasticities are measured by Bl* B2* and Cl, C2, respectively. The difference between Model 2 and Model 3 is that the latter purports to estimate long- and short-run income and price elasticities, the assumption being that the influence of income and price on electricity demand are strongest in the current year. Under Model 3, the short-run elasticities are measured by 82 and C2, with the long-run ones obtained by dividing B2 and C2 by (1-D2). 3. These two models did illuminate that the price impacts have been small on the overall power sector's energy requirements. However, the price elasticities differed quite widely dependent both on the model specified as well as on the period chosen for estimation -- with the incorrect sign occurring for several runs. Indeed, there are so many factors exerting an influence on energy demand that cannot be quantified, one would expect that they would reflect on the elasticities of the remaining variables in the equation. Moreover, the statistical assumptions of the least-squares technique assume that any factors not accounted for explicity in the explanatory side of the equation will be captured by the error term. This is not completely correct because the regressors are, to some extent, collinear with such excluded factors and, therefore, capture some of their effect. In the case of Models 2 and 3, some of the results obtained are shown below in the table as a function of the time period of estimation. These data are purely illustrative and not con-dered definitive. - 18 - ANEX 43.4 Page 2 of 2 OVERALL PO~ER SECTOR ELECTRICITY DEAND ELASTICITY E8T3SATION, 1971-86 Model 2 Model 3 Incom Price Income Price Pørod Elasticity Elasticity Perlod Elasticity Elasticity -------<Long un)------ 1971-81 1.83 -0.003 1972-86 1.76 +0.08 1971-82 1.82 +0.002 1972-80 1.82 +0.016 1971-86 1.87 +0.09 1978-86 1.98 1979-86 2.17 +0.16 - 19 - ANNEX 48.5 TOTAL ENERGY DEMAND, LOSSES, SALES AND GDP ACTUALS 1971-86 TOTAL SYSTEM Total System Transmission Ratio, Rl of Total and Total GDP Total System System Distribution System z 109 Electricity Year Demand /a Losses k Sales Pesos Demand to GDP (GH) (GVh) (1970 (10-.2ugH/ Pesos) 1970 Pesos) 1971 8,192 1,366 (16.95) 6,708 141.7 57.8 1972 9,226 1,515 (16.7Z) 7,577 151.7 60.8 1973 10,263 1,763 (17.51) 8,327 162.1 63.3 1974 11,252 1,919 (17.4Z) 9,141 171.5 65.6 1975 12,192 2,108 (17.61) 9,900 175.4 69.5 1976 13,540 2,276 (17.1Z) 11,022 183.6 73.8 1977 14,184 2,514 (18.1%) 11.391 191.4 74.1 1978 16,190 2,986 (18.8Z) 12,883 207.2 78.1 1979 17,875 3,505 (20.01) 14,012 218.2 81.9 1980 19,481 3,974 (20.81) 15,100 227.2 85.7 1981 19,520 3,844 (20.11) 15,257 232.5 83.9 1982 21,549 4,653 (22.12) 16,386 234.7 91.8 1983 23,073 5,211 (23.21) 17,287 238.6 96.7 1984 24,588 5,733 (23.9%) 18,265 246.4 99.8 1985 25,739 6,017 (23.92) 19,127 252.5 101.9 1986 27,551 6,570 (24.41) 20,409 265.3 103.9 ]a Sam of Sales and Losses does not necessarily equal demand, because *station on use is excluded from T + D losses. lb Numbers in parenthesis indicate percentage of ? + D losses relative to net energy available (i.e. gross energy available - station ovn use*). GDP ja AND ITS OROW7N Forecasts and Actualt 1970-1980, Economic eport Economic ReOrt Economic Rho-r EconRMIC Report EconmC Report EconomIc Report Yer May 1978 May 1976 May 1977 .hn* 1979 Sobemer 1981 August 1988 Actuail Annai AnmBal Annual Annual Aftual Annual Annua .et.. brg .~. agna GDP ~ . han.MP,s. .WP hnge . - Chagm -E . (000' (N) (000' (1) (000'. (5) (000I (5) (000'. () (000.. (5) (000. () 1970 1970 1970 17 1970 1970 Pesos) Pesos) Pesos) Pesos) Pesos) Peo.) Pes..) 1970 - - - - - - - - - - - . 132.8 - 1971 - - - - - - - - - - - - 141.2 6.8 1972 12.7 - - - . - - - - - - - 151.5 7.8 1973 168.8 7.0 . . • . - - - - - - 162.1 7.0 1974 174.8 7.0 - - - . - - - - - 171.3 6.7 1975 197.0 7.0 176.4 5.1 - - - - - - - - 176.1 2.2 1970 200.1 7.0 186.6 6.8 188.9 6.9 - - - - - - 188.3 4.7 1977 214.1 7.0 198.4 6.3 199.9 7.0 - - - - - - 191.8 4.3 1978 229.1 7.0 211.8 6.8 218.9 7.0 207.6 8.0 - - - - 207.1 8.8 1979 - - 22.8 7.0 2&0.7 7.9 221.8 8.6 - - - - 218.3 5.4 1980 - - 242.4 7.0 248.9 7.9 286.2 6.8 229.9 4.0 - - 227.3 4.1 1981 - - - - 287.7 7.8 262.9 7.0 289.2 4.6 - - 282.4 2.2 1982 - - - - 286.6 7.1 270.7 7.0 262.8 6.6 - - 234.7 1.0 1988 - - - - - - 288 6.5 287.0 5.8 248.1 2.0 238.4 1.6 1984 - - - - - - 808.8 6.8 282.7 6.9 251.8 8.5 240.4 3.4 1985 - - - - - - 325.4 8.8 299.7 8.0 268.1 4.8 252.4 2.4 198 - - - - - - - - - - 278.1 6.0 256.3 $.1 LawP at arkot pricec in conctant 1970 P~sos. $ougg: obok eo6It Rports and Cuntry Program Papera. * 21 - AMEX 4B.7 DEVIATION BETWEEN FORECASTED AND ACTUAL GDP 1972-86 World Bank Country Economic Reports Year Percent Deviation /a May 1973 May 1977 MayL1977 June 1979 September 1981 August 1983 1972 0.8 - - - * - 1973 0.7 - - 1974 2.0 - - - - - 1975 6.4 0.7 - - - - 1976 8.4 1.8 1.9 1977 10.7 3.6 4.3 -- 1978 9.6 2.2 3.2 0.2 - - 1979 - 3.7 5.4 1.4 - - 1980 - 6.2 8.7 3.8 0.7 - 1981 - - 13.2 8.1 2.8 - 1982 - - 18.1 13.3 7.0 - 1983 - - - 17.3 10.7 1.9 1984 - - - 19.6 12.8 2.1 1985 - - - 22.4 15.8 4.1 1986 - - - - - 3.9 a Deviations are expressed as a percentage and equal to 1-ratio of actualiforecasted quantity. � - 22 - А� .4В..: 8 ssz�сrssяяяя�вгг � �4а�s��гп�������� � s д qн� pц sS� Yi ��а ir: i лii � А ц i i _ � �� �Аiг V V У�$� М 4� 8 У V V�1 V V � • вsава::п8паакssп � ..»aaaw: w в:в.г: i �: Е ��,�� :яппяааваап�лпаа � � С1 01 !� р А А:: в1 1С :•: О:: �� ...••....,...яя^ . = ��$ а � ! д � � � А . t . i , . • . 1 1 1 . . а а д � Q � � � • • • � � ах о � iF � � . . . . . . . . . . . . . : S а � д i i � � � t . , , • . t 1 1 1 t . в t , . � �� 1..•,,,���в�аSаS i = : 1! д 10 f � � � � t ! • е i 1 г г . 1 . , . = � : в � � GG i ё i : _ � � ' ��. .... r... LрΡ` Cgw^g gi Egi L'S4!w^Q i У5 ti п ц У3 � iS i'. i а ...�•..,я8пая5:� � � � : : • • О + • М � а��� .....,,,аахкв.явЕ � � 3� � ::::..::: а � � �8 .,,..,,асыzяггя. � i � ., � ��zx�� �� � � i � , . , � . , . 8 8 & : 8 i i & � � � � а i : : : : : w У ; � �а � . � , ���� ,••, ••aяs�sssт� � � �3 i : : в : i : i = � г , , _ г ?ь �i• ••� • i i i i i�: i � i t� i ё i г s i г s J= � � . . . . , . . 8 : & �° п i Е й _2 � а � i i i в вi л:,. 1 � � � � � � E�i�� .....,.ао��:8�:� � � �Q� ~ , . . . . . . CQSZSi�B. , а 3� wT � w • � ё п�� S 9 3 = е �� � . . . . . � а : r Н ? g R � � ,§ �� + �iw: J о •: � � � � '� ���� ...•��,хяяпвzа�� � �!�� � : : ,а в : .. w : 3 » �р в г г • . s , sëi�я�'.�в г � i�7 � �: � � О �й��аа� � _ � � , , . . . , . а Q II п 3t 8 А � � _ � г � � [ а w w ё i i в в � а '�� _� ���� ,..,,..аакапк:.. а g.� i : : : : w i } Е впсяяппr,..,в,,, ; ��$�� Z� � 3 3� Н� 9у � Я aaaaaass.,..,�.. � � ��s ?> �� dadвiwia.i � � _ � � � а� а � ваа�я::Пп,....... ���� аа � � � д w а w w w : : � � � t � � j 7 . � s£�������t����1� а mRa mja � i . .r.. _�^'^.i . � QlERO11 REQUI�iEO. 5ALE8 �. AND �SSE. S �,gtu.�: :пд Foгвessts 1sт1-вб СЫvаг 2 Ао�гвiиl Оив8вм II Ааnгвlавl Sвд Свгlее I Apj►гвisвl Sвп Св„�еs iI Аоагвlиl Сивдаlасв �У Арагвiиl Уиг Wy f070�� ОвеввА,вг 1075 Wy 1я78 У�.у 19Т�� Ys�S ��8О � Емгву ЕЧвry1у Емг�r Емг�г Епагlfу Rвqu1 гм Rвqai ги Rpa1 гв- Rвqui гм Rвqui гr мпts Ss1a Lb os мпts , Sa1es Lb sиs msnts Sв es L 1.евве �ients 3в1еs L osses мпtв Sstи L �osиs (�i �) tвI (�i (�i (в) (�i (m►D (� �+I (�) (� (�) (�i i� 19?1 Z.20 1.в9 (1.QAj (26.Z) - - - - - - - - - - - - 1У79 4.88 1.М (1.89) (97.т) а.в. 1.8f (2.вВ� n.в. - - - - - - - - - 1978 9.б1 1.в7 (Z.14) (2t.4) п.а. l.о8 (8.2?) п.в. - - - - - - - - - 197в п.ев я.а (s.o4j (ге.4) п.•. s.п1 (п.Т4) п... - •� - - - - - - _ � . 1а7в 8.1о п.па (4.па) а... п.4о (п.ав) n... - - - - - - - - - N i97в a.8s п.�8 (я.4а) А... �.в1 (з.ев) п.в. 8.�в г.ав (1в.i) - - - - - - W 1яn е.в9 п.ы (п.ы) (пв.4) п... ?.е4 ta.a9j п... а.в1 ?.в9 - - - - - - � 197е 4�о4 п.ее (п.ее) �sв.4� А.а. а.ое te.eo) п... а.ее в.1в (1е.о) е.е� 8.оя (1�.1) а.ы а.а (1а.в) 1s7я - • - - 4.47 в.48 (19.е> 4.1в а.в9 4.а а.а9 1� - .. - - 6.07 8.71 4.47 8.в7 4.87 8.Q? 1961 - - - - 8.4в 4.1д 4.В4 8.97 4.78 8.9q 1� - - - _ в.ев 4.w (1в.7) в.я: 4.в8 (17.г) в.11 4.а4 1� _ - - - б.81 в.81 (1в.9) 6.78 4.б8 (19.4) 6.88 4.71 (14.в) 19� _ - - - б.в0 S.7Q (1б.8) в.19 6.08 (1Т.9) 6.9Q 6.1Z 1� - - - - - - б.б8 в.48 (17.9) а.47 &.60 1�е - - - - - - - 7.оо е.о4 (18.7) L А11 вмгgу геqиiгмюпt snd иlвs двtв shoвn ви вxprossed ia 108 �h. L Sв1и поЕ 1п рвгмLАевiв гдвг !,о и1и inal�кlliю Ыоеk sвlа to пвlрlгЬогlпя manialpвliLiи, Aatioquis впд рвг� ot qroeo� Ьад eкeiudes bulk ввlи to ISA. Sвlа 1n рвгмWиsis гrГвг to и1и tneladlaa бulk osla to 2SA. - ,.q L Iпеtадвв Ы eek sаlлв to пвiяЬЬогinв wnaioipв1141вв sпд Aп8loquis апд рвгб ot Choes bvL sxcludes :в1лs Ео ISA. Thвss wи иlвs иsвд �� in !he sрргвlиl !ог thв tlпвпеiвl иslувiв. � и � о оо м• �о ю RECLUIRED, SA1.0 10 Actuals and Forocesta 1971-88 Play@* AMAM b202 AffirDIMI FEM A22Msal- -- Ria Grande Apprelsal- Y«r fthrugry mer 1901 iLorg 1994 juom 1984 R~ ro- *mol ro- ~ re- RoquIro- Lataa g Lojgc gmte sa s ag totcow 9 o m La 9~9 hk g~ (in> (nyh) (n) OWII) (TU) (TWII) 2.16 1.60 (1~ 1972 2.87 1.93 (1.81) 1973 2059 2.11 (1.94) 1974 - - - - 2.77 2.28 (2.06) (18.3) 1978 2.96 2.42 (2.18) (17.9) 1974 3.24 tM (2.31) (17.9) 1 1977 8.20 2.81 (1~ (19:4) t4 1976 8.84 (188) 1979 9.97 9.97 3.28 (2.76) (19.1) im 4.w 9.67 (2.99) (19.4) im 4.70 8.91 9.90 9.90 4.60 *.n (8.0% im 8.09 4.24 0.9. 9*50 0.9. 4.82 8.94 (8.17) im 5.60 4.80 (18.4) 8.71 0.9. 0.9. 9.42 8.05 4.%; 8.05 4.10 (8.31) im IlM 4.99 8.92 m. 0.9. s.10 6.49 4M (17.1) $.N 4.97 (8.40) (17.9) im 0.49 5.41 4.16 0.9. 9.9. 8.90 s." 4.w (17.1) sm 4.95 (8.46) (18.6) im 8.96 6.87 (16.8) 4.47 nog. 4.04 6.27 9.20 (17.1) sm 4.88 (8.78) (17.7) La All onorm rowlroinont mw «#« <lat* ~ bra «pr~ In 10 ^ Le 10619d99 bio-ck 091« to nolobberlog omffilefpolftlas bod Antlowla ~ part at ~ 0 h"oxolmåm oblog to IsA. w~ wore, 991« uffd la tho, öpprötc&I for tho floömfal analyeN. 14 The** **§** oxofock block 001« ta Antt"olm. ~ * and XIBA. Th~ war* celoc data unad In Mo approloal for f Inanelet önalyele. Le ~ remont rofera to scr27 rogulfm- ta ~ ~ ad 10 ~ 1110. AfttIffyls and part of chm. old Salos n~ In påronthoela rofore ta 9~91 EPM sålow oxeloMng bulk 81« to Antl~la, Choco and ISA. Tho enten otomhere ~ 14 d~t* åetmål Eft walow Inclodlog klock «1« to Antlowla and Choco, 1:" oxolodt block salec to ISA. to - гs - �х� в. �.о гс�,_ �• t�l9�1г�- я.l� .. ав iа�в Аеlwla � �веввбв 10у1-10в6 8м б�,еа й Аим:ав! биоiл�ргаiрl РВ! Аеемiавl Мвr 1070 lЬ+r 1961 �� 1981 Аебиlа Fлвг'Фг бМваr FпвгУУ Еiигвlr Rвquirв- Rвввiгв- 1ев4дiгв- Rвоиiгв- 7аlL а8в4.� �! te 1it L4eu! �..- �е1ц l� lв�t 64� �l.+иt La 1�и б�. ,Ld �вLs /s lами rn�� спм� т пм� rnп�� rn rn�� rnы с+� rn�� сп�и т 1971 • • - - • • - • - 1.86 1.10 19Т2 - • - • ^ • - - • 1.ц 1.41 �9Т8 • - ' • • - - • - 1Jt 1.8б 197� • - - - • - ' • - 1.96 1.д4 1478 • • - • - • - - - 4.4b 1.77 197Е • •• - - - - • • • 4.� 1.99 19Т7 4.t�! 4.01 п.в. - - • - - - 4.Т1 4.ц 107@ 8.б7 2.79 д.д. - - - - - - 8.29 4.86 19Т0 4.81 8.4В дл. - • - • • • 8.70 4.�0 198р 4.81 8.70 д.д. д.в. 8.7II - - - - 4.0� 8.40 1981 Ь.19 8.90 д.в. д.в. 4.Sll • • • - 4.3в 8.4� 19в� а.Тв вss д.•. w.•. а.ао - - - - в.т9 a.as 1988 8.1Т 4.� п.в. д.в. б.А1 - n.в. 4.b0 - 8.18 8.64 1986 б.в9 8.?д д.д. д.д. б.ц - n.д. b.Об - b.b� 4.1Т 2�Вб 7.84 b.87 а.в. as. Т.84 - п.д. 8.84 • б.01 4.14 1990 - - - д.в. Т.Qб - n.s. b.9H - 6.87 4.Q4 (� А11 мвгр�г гвоniгвwп0 м/ оiдв д4д дгв �гаид 1n 1б$ �1!►. ��ав 1аRв !rм 1e nsd iпвtидв ввlвп in !ha Овевг�вмs в1 Mbiaeniв вhiaA �м ineludвi iп sвlа Iаг (Э�М � Ма 8м бгlав 12 Iим�,. jg ?hвдп а1и гвfм bo и1и !о tiwвl оааивn iп !ha мliгв DCEt ОгеW ldгkss. i.в. 61и 14 вtвабгifiадегдд aA/ QB. , f,� багтi г�вовiгwллв гдм Ое Мд вдАiгв ICB. Сга►о Flвгkвb. _ 2� r ANNER 4В.11 . � � �� v�����������S�E�� г � �$ • � а �� ^ � � � � У � � � � � 8 � 8 � � � = • � � � �� р ы н w н н w.+ д р р 01 д д д р а а � д ` п � '� а г „ � � R � � $ � А � !� � а 8 � � 8 � � ь . г � � ев ы ы ы ы р р С•� р р д А�� в �0 х �_ �� �i _ : �Q � ii=SSii � � � � ! 1 1 1 � 1 1 1 � 1 • а � F g � s б i а S �_i • У � � • � � п • ~ . � G � � � i � • � i i i t е id �% w » н �� � д д .i .i �+ 'ь � � i � �� г � г г�� � г г г i � • � w i i в � : i s : � i II i � в � ��.���.�,.,,�.�t � » в � i � � � i • i �' � .. ,.��,�.,.�8���в� � "6• $ п g ��. р 01 д f+ О tl вв i � 8 �_ в = � �• °r _ �.�.�,.��RSx�8x� � 1. � �ъ � � � � о �о i о � о w � � S � � � ' � � � _е � �� i t��� г� Se' S 6 о^, in' н^ .^� � g в = � �� ������5� g � � _ �� � „ .. ,, а � »� S . у • в � � - ъ � � � � � � � 8 °. 8 � � � � • � а ! � • � � г � � � � � � � г i R ië S iS �i � S ~_ i р р А �Г •► 14 r4 � w = .S = ь � � ` ог = пв : � �s ��� ..,.,�.,,�в��sа� �п '� А Ч f tl 1У О А � � 6 • ` .� $ п =4 + � � � . � � � о f: t? i`о, � S о^, S,� i � 'ёи • � $ �� � L: '�м v v i'i ��.. v v • ° � g �������8� � �. А �� • $ � • :� 3 :: f.' £S�L°S°. �, � � 3`а ` � •• � � � � � � t 8 Ж i i � a � � ' Z � � � 2 • _ �� .i �Oi р Q1 вд А в • �О i д i r 17df1 ы - в . � � � � � � � � � � « i ё� � �.: ië g гв � � � S п � � о ь . � � � « а д а + п .ii �s о � п ле � в S � � . g ` а G ь� � • б О Z_ � . � , � � : : : : : : : : : : � i т � . •• � . g Ё i ё t � i i i � i ё = • 8 �� о i�в���•si as � � � . � � � � � $ � � � � : 8 � � � г � = s�t � � ! : : � � � � � $ S g £S � S � � .,, в �$ � i � в S � $ : е� �а����~в$�� � � � � � � � � 8 А � � � 8 ю � � � � � п � п � � � п : �� ы oi д д й a w.i в.i = i _л � <��� ��?����� � ���5������������ �4 � � �� 9 С.У.С. (VALLE дЕ CAUCAI ENEROY REQUIRED. SALES AND LOSSES L j� L Аеtивlа and Foreessis 1971-88 Ch}vог I Aaaraissl Ssn Csгlos I Aaarвtssl Ssa Свгlов II Apprsisвl Оивvlо Аоргs}sв1 FEN Асагаiввl Мву 1970 Мву 979в Увя 1979 УвУ 1981 Увгсh 19в4 Aetusl Епвгру ЕмгОу Елегрr Energr ЕлвгgУ Елвгру Rеаиlм- Rвqu}ги Rоqиlгв- Reqniгe- Rвquiгa- Rериiги r-е�вг tил в Sв1ев Losses msnts Sв1м Losses msnLs stes L lоввев pюn�s Sв1м Lossм амп Sв1es оsвм ewsnta Sв1м L Lossм (тwл) tтwh) (� (тwм) (тwn) +с� (т�) (тм) (� (тrг►) (т�) (� (T10i� rnмл) (� (тм�) (тм) (� 1971 1.8в 1.п1 a.s. - - - - • - - - - - - - 1.81 1.10 (18.4) 1я7п 1.в1 1.8в а.в. - - - - - - - - - - - - 1.в1 1.пп (1в.в) 197а 1.в7 1.47 а.а. - - - - - - - - - - - - 1.в9 1.8в (1в.1) 1я74 1.еа 1.в1 а.в. - - - - - - - - - - - - 1.тв 1.<е t1s.9) i97s п.Оп 1.77 n.s. - - - - - - - - - - - - 1.в� 1.б9 (18.б) 197е п.пп 1.9в л.в. - - - - - - - - - - - - z.o0 1.7в t18.o) � 19» п.м п.1в n,.. п.1в 1.99 л... п.оа 1.77 (1п.в) - - - - - - п.оп 1.тв (1п.я) н 1в7в п.ее п.ав а.•. п.ю п.а1 а.в. п.е7 z.a� (1п.е) - - - - - - п.яо 1.9в (1в.п) � 1979 - - - п.е9 п.89 л... z.ьв г.zа (1?.в) - - - - - - г.бо я.1т t1a.z) � 19в0 - - - п.69 п.вв n.s. п.81 п.4в (1?.в) п.78 п.56 а.в. - - - п.71 п.29 {15.6) 19в1 - - - п.91 п.79 п.в. а.ов п.а7 (1п.е) a.oz п.тв n.s. - - -�.вв п.п7 (1в.в) 19вп - - - в.1в в.Оп а... в.а1 п.е9 (1п.в� в.в1 а.ов а... - - - п.sв п.4г (1ь.1) 19ва - - - в.�о 8.п7 а.а. а.во а.14 (1п.е) я.е1 а.вв n.s. а.в. п.е1 л... а.Ов я.б1 (17,п) 19е8 - - - а.ве в.ва а.а. в.ю а.4о t1s.a) а.ва а.ап a.s. л... а.оп в... а.п8 п.ве (17.а) 19ев - - - - - - �.пб а.7о (14.в) 1.па в.s4 л.в. п.в. в.пв п.•. а.1п п.е4 t17.o) lяве - - - - - - - - - �.в1 4.во п.в. л... в.49 л... в.ап п.9в (1в.п) L А1) вnвгву гвqиirмвлt влд ввlвв двtа вrв вкргмввд }а 10 яMfh. L,b Тhв влвr�r гвриlгета�t двtв геlвг to мвгgу амдs tог tho м�iго Уа11• дв Csnea� i.в. С.У.С. (Ргор}о), EYCALI� влд оthвг дiилlе}pвi1L}м. L Un1мs оlheгr}ss }nd}еslвд, мвгяу sвlи двt.в гвtлг to tYC/Chidгsl'в ввlеs }л bu,.,1k to Етеа11 sлд ot!►вг awnle}ps1 аотрвniи }л thв Ув11• plns CVC'в diгeci ввlи to }ts o�rn tteal еоnвwмгs. In such евsев losses вгв not shorrn slли they до noi мtlее0 �М sееолдвгу dlstiгibulsion lossвв tл thв Евса1l syвtвw. 8�_tk иtвв �о Емаа Н весоппЕвд Гог АвЕмвл Z/8-8/4 ot СУС/Chidrat :вlвs дагtая !ди рвгJод 2o?L-66. � Sа1м двtв hвгв гвlвг to tinвl соnsмвг воlм ot СУС/Chidral, Еsсв11 snd Еhв оtМг тилiсiрвl смрвn}м }п thв Ув1tв. In thв свsв о! t.Ав Ssn Свг1м II projвct, thв Арргslввб 1n its tinвneisl sлslysls ивед ав CYt •вslм• iп tfiв рвгlогтвnев indicвZon thв •омг9r rвqn}гвQ.• � . � ад r n� �c�Q� �������3����$��� � ���= �п "� . х��� п а. и r о о е � , i � ! ! ! ! ! ! пs п; S 8 ! � ! ! ! ! � �а�$п � g � ц � s s r о е о S i !! г г г r i i� g в�•i � ��gп� .. � �:' Э� �� а$^ ! 1• 1 1 1 1!/ 1 1 1 . ��i�� � i.р• = п' й О V•• р 0! р» � . 8 � а = ! 8; & � � � 8 � S п; ! ! ! ! ! ! � п��� о е r а• ar а и r � :п. LLL_' ! в��вп:вS: ! ! ! ! ! ! .,�rr а /► А А I► А А I► � � � � �� л л ♦ ♦ л ♦ ,o�i л а � ��� 'sз��ss�з�!!!!!! � � s � ;� . � v_ � i � b о 0! w v о а М � �3 �. ! ti4S��Sl�ëv$$ ! ! ! ! ! ! .пi � � .. � п й е о а а а er а о �$ � lжк���яяs�!!!„ ! � � � � L� З S�'д 8 i3 � •• п в жв����5�s :п � с . _ � � ё о 'еТ '.i о �oi i лрΡ и� �j% � � р ! g У� 1� � s g� V 0� • 1 t ! ! t V � � i �$ � 1~s+ рs sО �Ов e1 0! ♦д � ,д•. �О1 � О Р б Ч Р� • 1 1 ! ! 1 ! ! ! t r •�ggg� � � � �� s а а s а а s Э7} � СΡ в в• в 1•� t!! 1 t 1 1!/ �+ S g а s s а s s s д, i i о i i i i ! ! ! ! ! ! ! ! ! '!� � а � � а s а а � � п iiii!!!!!,!!!!!! � .. � а « о и . � 8 8 У L ! ! ! ! ! ! . ! , ! ! ! � � • ! ! ! ! ! ! ! г ! ! r ! ! ! ! ! � � а•♦! s�!♦w о�! s аq� ррΡ арΡ е�ОΡ � i+ q1 v О р п• О # • �О 1 1 t ! 1 1 у О{� в в}�1 ♦e д i! дрΡ! р q 9s О М V Р пi Р о � � Ч 1 ! 1 1 i 1 � �'�«'�1^л'ai'dS3{3�^о'дЗ,^о3 � V �������g������� . С "ё '3 '3 ё :i й �ai w w О � � �:3333:t3�98 ! ! ! , ! ! st•но x�tиv - вг - . 。－----―、―・―--&-―・―-―・―--―・―------―里―---―「――・―&1&：『．,－・1-- 30 AM= 4. 1 ump Lt Fem~ md ~11 ffl-IM ~ta DIgtrIbutjon ffiltas mergaleal Aeffligat 2m19 AMMLa &Ural year IM Fcbrua!z gav 1128 Loan A~ §* Loffi~ ion 14.1 1972 16.6 1973 15.9 1974 14.4 im 16.0 im 14.4 im 14.; 14.8 iffl 18.1 17.0 16.7 im WO 18.6 19.4 19.8 im 16,7 15.9 21.6 21.0 igel 16.3 UJ 21.6 19.2 im 14.6 16.0 19.6 21.0 im - 14.1 19.6 22.8 M4 14.0 ».0 23.9 - 28.6 im 13.4 17.9 28.0 - 24.7 im 17.1 21.4 - 28.0 1"7 16.7 24.6 im 18.6 20.0 im 14.13 19.0 im 18.5 18.0 im 14.0 im 18.0 La T a D Lössm are «pr~ 99 b por~ of coopp avel lob#* for Effl99 am hm -31- ANNEX 4C.2 EPM NABEET ENERGY LOSSES /a /b Forecasts and Actuals 1971-1986 Guadalupe IV Appraisal Playes Appraisal Rio Grande Appraisal Year fth 1980 February 1981 June 1984 Actuals Losses Losses Losses Losses (glih) (2) (gih) (2) (gf11) (2) (2) 1971 - - - - - - 21.5 1972 - - - - - - 17.5 1973 - - - - - - 17.7 1974 - - - - - - 18.1 1975 * - - - a - 17.1 1976 - - - - - - 17.7 1977 - - - - - - 17.3 1978 * - - - - - 16.2 1979 653 18.0 - - - - 18.2 1980 696 17.8 824 21.7 * - 19.2 1981 734 17.4 797 19.8 - * 19.0 1982 774 17.0 848 19.8 - * 19.5 1983 817 16.6 903 19.7 851 20.3 19.6 1984 868 16.4 961 19.7 926 20.6 20.2 1985 910 16.0 1,022 19.6 992 20.9 19.5 1986 960 15.6 1,088 19.6 1,063 21.2 19.6 /a T & D losses are expressed in absolute glh and as a percentagp of net energy available (i.e. after deducting station use). b Actual losses shown here refer to losses in EPM's own system after excluding its block sales to Antioquia and Choco. Sources Actuals from EPM and forecasts from SARs. - 32 - ANNE 4D.1 Page 1 of 4 TIE COST OF TH8 1981 POR SATIONING 1. According to ISA's operations report, power curtailments in 1980- 1981 reached the following values set out in the table belows SA ISTIMATES 0? ENERGY ATIONING IN 1980 AND 1981 (Estimate of Curtailed Energy (gh) WEB SEP CWC ICEL TOTAL L (Valle) 1980 97 18 48 80 243 1981 1,006 177 312 541 2,036 Total Gross (gWh) for 1980 and 1981 1,103 195 360 621 2.279 Losses 223 35 56 121 429 Net Energy 1980 and 1981 (gh) 880 160 310 500 1,850 Net Energy 1981 (jah) 805 142 250 433 1,630 / CORELCA is not Included since it was then not part of the interconnected system and did not experience rationing. The amount of energy rationed was estimated by ISA on the basis of forecasted demand for 1981. A closer scrutiny of the demand statistics shows, however, that ISA's calculation overestimates the amount of rationed energy, particularly in the case of EERB and ICEL when viewed from an ex-post perspective. Actual demand data show the following values: - 33 - ANNEX 4D.1 Page 2 of 4 Year 1979 1980 1981 1982 1983 E (Sh) La Actual Demand /b 4996 5372 5047 5689 5919 Forecast Demand Lc 6045 Residential Sales 1658 1783 1721 2027 2044 Coamercial Sales 664 685 613 637 627 Industrial Sales ICEL (Uh) Id Actual Demand b 3385 3650 3677 4125 4313 Forecast Demand Ic 4119 Residential Sales 1306 1427 1483 1590 1671 IndustrJU Sales 643 684 695 750 771 Commercial Sales 326 347 335 341 347 CVC (Valle) (&h) fe Actual Demand lb 2502 2706 2675 2854 3031 Forecast Demand Lc 2932 Residential Sales 872 975 991 1093 1128 Industrial Sales 839 863 825 840 872 Commercial Sales 248 268 260 279 285 La EBB market here defined as EBM market plus market of Cundinamarca and Meta. E Historical demand. including losses. Ic Demand estimated by ISA for 1981 without rationing. d ICEL market here defined as that of the ICEL (Group), excluding Cundinamarca, Neta, Choco, and Antioquia. Ie CVC (Valle) market here includes all Valle de Cauca- i.e. CVC, EKCALI, etc. 2. A cursory examination of this data shows that, with the benefit of hindsight, the estimated forecasted demand for REB in 1981 should have been between 5400 and 5600 gVh (based on the actual demand in 1980 and 1982), thus indicating a probable value of rationed energy in 1981 of between 280 and 440 gVh, respectively, after correct -g for 20% losses. This is less than one-half the 805 gVh (see earlier table), .ased on ISA's estimate of the 1006 gVh gross amount of rationed energy for 88-* in 1981 (after correction for the 20Z losses on the 1006 gVh gross). Assessment of the residential sector's sales for EREB reduces the differences even more. The potential or forecasted residential BEEB sales in 1981 would likely have been between 1800 and 2000 gVh, i.e. between - 34 - ANNEX 4D.1 Page 3 of 4 between the actual 1980 and 1982 sales levels. Given the observed residential sales in 1981 of 1721 gVh, this Implies that the probable level of rationed energy to residences in ESEB in 1981 would have been between 80 and 280 gvh. As far as the comercial sector of the MEB market was concerned, the post-1981 actual demand never recovered to the 1980 level, even by 1986t This was due to very rapidly rising commercial tariffs in Bogota in this period and to a shift of some consumers out of the commercial category (e.g. hotels). This suggests, if a similar reasoning to that advanced above is applied, that any rationing experienced by the commercial sector in the BEEB market would have been very small in 1981 and between 30-40 gVh. In the industrial sector the onset of the recession in 1981 would have influenced demand and tended to *mask* the effects of any rationing. The data below illustrate the behavior of total GDP and industrial added value through 1981: GDP AT 1975 PRICE LEVELS (Billions of Pesos) 1980 1981 1982 1983 Total GDP 526 538 543 552 Manufacturing 118 115 113 114 Commerce 53 54 54 54 Given the slackening of industrial activity due to the recession, it is again very likely that public electricity sales to industrial users in Bogota would not have exceeded in 1981 the level achieved in 1982 of 1220 gWh. This would imply a rationing level to industry of around 10-20 gVh in 1981, at the most. This gross analysis would suggest that rationing in 1981 for the EEE market was in the range of 120-340 gVh, with its Impact on different consumers being for residences 80-280 gWh, for commerce 30-40 gWh, and for industry 10-20 gWh. If one uses the upper limits of all ranges and the corresponding unit outage costs for the different consumer groups given in Table #.9 in Section 4.6 of Volume II, then the estimated cost of the 1981 rationing for the EEB market was about December 1985 Pesos 11,720 million, or US$70 million (December 1985 US$). 3. Similar reasoning applied to ICEL would show that total curtailed energy was in the region of 50-70 gVh in total, broken down according to consumer category as followes residential 30-40 gVh; commercial 10 gVh, and industrial 10-20 gWh. Again, taking the upper limits, results in a total cost in the ICEL market in 1981 of rationing of some December 1985 Pesos 4990 million, or US$30 million (December 1985 US$). In the case of the CVC market, the corresponding figures would be an estimated total rationing of about 90 gVh with residential accounting for 60 gVh; commercial and industrial for 15 gVh each. This gives - 35 - ANNEX 4D.1 Page 4 of 4 a total cost for this market of about December 1985 Pesos 4380 million, or US$26 million. For the EPM market meaningful levels of rationing could not be identified by applying the same line of reasoning as above. 4. The conclusion of this analysis indicates that the 1981 energy rationing in the central sone of Colombia was by no means remotely close to the costs estimated in the President's Report of the Guavio loan--namely, some US$3 billiont Instead, this analysis indicates a cost much closer to about 41 of the above figure or US$130 million (1985$) from an ex-post standpoint. Even if viewed from an ex-ante perspective the highest estimate of the cost of the 1981 outages that can be defended is about US$500 million (1985$)--only 17Z of the estimate in the President's Report. This is derived by assuming first that the rationing to different consumer types occurred in the same ratios as their share in total sales (which was not the way the rationing was actually pro-rated since the explicit policy was to restrict residential users the greatest and industrial the least). Second, that the outage costs differential between industrial and residential users was roughly 101, which was well known for systems, in general, in 1981. - 36 - ANNEX 4D.2 Page 1 of 4 COST TO THE ECONOMY OF SURPLUS GENERATING CAPACITY 1. This annex estimates the gregret' associated with the Colombian power systems surplus generating capacity over the 1985-1993 period. The first approach to estimation is based on a complete ex-post basis. whereas the alternative approach on a mixed ex-ante ex-post approach in that the least cost expansion plan is determined to meet a demand that was the actual and not projected demand. (a) Value of 'Regret* - First Approach to Estimation 2. By the end of 1985 the power sector had a nominal installed capacity of about 6350 MW to serve a peak demand of some 4,400 MW. This represents a 44Z reserve margin with respect to demand, and, additionally, the following plants were expected to be put into service between 1986 and 1988: Mesitas- 1986 (600 MW); San Uarlos 11-1988 (620 1W); Calderas-1988 (18 W); Jaguas-1988 (170 MW); Betania-1988 (500 MW)t Thermoguajira-1988 (150 MW); and Playas-1988 (240 W). These additions, totalling 2300 MW, would result in an installed capacity of around 8650 1W by 1988 for an expected load of 5300 1W. The reserve margin would increase to some 602 or more in 1988. Furthermore, 320 1W additional will come into service in 1991 (Rio Grande II) and in 1992 some 1000 W due to Guavio. As a consequence, there is a period of around 9 years (1985- 1993) when, at least from a peak demand point of view, the reserve margin is above normal levels. Determining a *normalO reserve margin is not straightfor- ward, but a very conservative figure could be around 302 of demand. In this case, the system would need around 1600-2000 1W of reserve between 1988 and 1992, in contrast to an expected reserve of between 3400-3300 MW in this period, suggesting an excess of about 1800 W in 1988, declining to around 750 MW in 1991, rising again to about 1200 MW in 1992 as Guavio is commissioned (see Annexes 41.1 and 41.2). 3. However, due to the predominantly hydro character of the Colombian power system, the latter estimates regarding peak balances have to be qualified by analyzing the energy balance. In this case, the key variable concerns thermal generation with detailed assumptions set out in Annex 61.1. The system has a thermal generation potential of about 9,000 gVh annually but actual thermal dispatch is only around 5,000 gVh for complying with 'minimum generation, constraints (see Annex 4E.1). The difference between this potential and Iminimume generation dispatch gives a measure of the first element of excess capacity assuming a plant factor of 0.70. To assess the second element of excess capacity, the difference is needed between the actual Ominism* dispatch and the thermal energy required to cover energy demand after incorporating firm (952 guaranteed) hydro energy available. This provides a measure of the amount of hydro being spilled (see Annex 49.1). Assuming this excess spillage is associated with a 0.50 plant factor this provides the corresponding capacity excess due to spillage (see Annex 41.1). The net present value in 1985 of the total capacity surplus for the period 1985-93 is estimated at about US$730 million assuming a 112 discount rate. - 37 - ANNEX 4D.2 Page 2 of 4 Partially off-setting this cost are the Ooenefits' of excess capacity in the sense that there are savings in fuel from the undispatched thermal generation valued at about US01.51kfh. This yields a net present value in 1985 for the period 1983-93 of some US$295 million. Bence, to a first approximation, the estimated value of *regret' arising from the excess capacity in the system up to 1993 has a net present value in 1985 US$ of around US$455 million. (b) Value of "Rearet' - Alternative Approach 4. An alternative method of determining the cost of *regret' associated with the lower demand consists of taking the mixed ex-ante ex-post view mentioned above. As noted earlier, the causes of the surplus capacity can be attributed to the plants coming into service between 1985 and 1992 to satisfy a demand considerably below what was projected in 1978/79 when the investment decisions were being made. 5. The first question that occurs is *What would the excess capacity have been if the power plants decided on in 1978-79 had cone on line at their planned dates with the actual demand?" The answer to this question is provided in the energy balance of Annex 41.3. For 1980 and 1982 there is no significant margin between generation and demand but starting in 1983 surpluses became very significant, culminating with an excess of around 12000 gVh in 1987 when Guavio was supposed to start generating. This would be the equivalent of around 2700 MV, assuming a 0.5 plant factor. The result is not surprising, nor even very relevant, given that the 1978 plan was built around a demand projection that showed a value of 36.8 TWh in 1986 versus an actual value of 27.6 TWh. 6. The next question that arises is: 'Given that the expansion plan was not executed as originally formulated, insofar as in-service dates are concerned, what has the energy margin between potential generation and actual demand been? Annex 41.4 illustrates the potential guaranteed hydro and thermal generation for the period 1971-1987 period lies between a high of 15% (1985) and a low of -6? (1982). This is a rough measure of system security of supply: years with a low margin tend to be those with rationing problems (e.g. 1976-1977 and 1980-1981). It should be noted that the worst value (-6% in 1982) was, in fact, compensated because hydrological conditions, particularly during the critical dry season, were exceedingly favorable. In 1983 hydrology was very dry and there was rationing during peak hours; there was no energy rationing but energy reserves were severely depleted during the year. In any case, the high margins of Annex 4E.3 never materialized due to project delays and it can be said that until 1984 there was, in fact, no excess capacity in operations even in 1985-1987 excess energy is not inordinately high. The differences between Annexes 4E.3 and 4E.4, due to changes of in-service dates, are summarized as followss - 38 - ANNEX 4D.2 Page 3 of 4 Power Plant Original Date Actual Date Delays (Dec 1978) (Years) Guadalupe IV Jan 85 Nov 85 1 Tasajero Jan 83 Feb 85 2 Cerrejon II Oct 84 Nov 87 3 Betania Oct 85 Nov 87 2 Playas Jan 86 Nov 88 2 Guavio Nov 86 Nov 92 6 7. Project delays have multiple causes but certainly the financial difficulties that the sector has experienced have been a significant factor. One question that can be answered is, therefore, 'if investments had been planned to put plants into service as they occurred in reality, what would the capital cost savings have been as viewed in December 1978? Annex 4E.5 summarises (i) the investment plan underlying the 1978-79 decisions and (ii) the investment plan that would have been contemplated had it been known beforehand what the in- service dates would be. The difference in net present value (1978) for the two plans is US$225 million at December 1976 price levels. Using the MV index as a deflator (1976 - 66.6, 1985 - 100), this becomes equivalent to US$340 million in December 1978 at 1985 price levels. With an 111 discount rate it becomes equivalent in 1985 to US$705 million. This value is a rough measure of the cost of delays in power plant commissioning. Subtracting the estimated cost of thermal savings due to the excess capacity yields a net "regret" of around US$410 million. 8. The saving of US$225 million does not, however, encompass the full potential savings had demand developments been accurately forecasts there was still scope for schedule readjustments that would have generated additional savings, particularly for those projects being put into service in 1987-88. Using the historical security of supply margin as a guideline, an alternative plan can be constructed such that the margin lies in the 5Z to 10% range. The result is shown in Annex 4B.6--the Tasajero and Zipaquira thermal plants are delayed an additional year and the Guadalupe, Betania, and Playas plants are delayed an additional two years. 9. Finally, the ex-ante savings associated with this alternative schedule are shown in Annex 43.7. The result is a savings at December 1976 price levels of US$282 million. Using the MUV index as a deflator, the result is equivalent to approximately US$420 million in December 1978 at December 1985 price levels. Bringing this net present value of savings in December 1978 to December 1985 results in a *regret" of roughly US$870 million. Subtracting the value of undispatched thermal energy savings estimated in Annex 43.1 (US$295 million) results in a net regret of US$575 million (1985$). 10. The main findings of the preceeding analyses are twofold. First, on the basis of a purely ex-post analysis, in which actual demand up to 1987 is taken along with the projected energy supplyldemand balance up to 1993, and the actual in-service dates of the plants coming on-stream between 1985 and - 39 - ANNEX 4D.2 Page 4 of 4 1992, but for which decisions to proceed were made in 1978179, the net present value of 'regretO of the excess generating capacity In the system between 1985- 93 is some US$455 million (1985 US$). This provides a lower limit of this OregretO but, at the same time, it could be argued that this is the estimate closest to reality because it does not feedback to the ex-ante analysis any knowledge earned from hindsight. Second, if the value of *regret' is estimated by using hindsight aretroactively" by having the plants put into service as they were in reality, contrasted with their planned commissioning dates as viewed ex- ante from 1978/79, the net present value of the *regret' lies around US$575 million (1985 Us$). - 40 - A 4.1 Pag 1 of 2 1985 1986!87 1988!! 19!!9 19!0 199 !!92 199 Guaranteed (95Z) hydro E 4,128 4,128 4,919 4,919 4,919 4,919 4,939 5.236 8,018 1M4 5,736 6,314 6,314 7,132 7,744 7,753 8,649 9.189 9,189 CVC 2,534 2,919 2,919 2,919 2,919 2,919 2,919 2,919 2,919 ICEL 1,434 1,434 1,434 2,934 3,689 3,685 3,685 3,685 3,65 CiUWrA 0 0 0 0 0 0 0 0 0 ISA (ecl. Betmnia) 7,850 7,850 7,850 10,670 10,700 10,700 10,700 10,763 11,317 System 21,682 22,645 23,436 28,574 29,961 29,976 30,872 31,792 35,128 Demn~ ge (5.8%) (actual for 19851986) 25,739 27,551 28,640 30,252 31,877 33,799 35,690 37,862 40,192 Kin. =beal Req. 4,057 4,906 5,204 1,678 1,910 3,823 4,818 6,070 5,067 Hinhum gn1 Dispatch (actual for 19851986) EE 397 302 526 526 526 526 526 526 526 CUC 140 1.1 imE 2,235 1,398 1,450 1,450 1,450 1,450 1,450 1,450 1,450 OMAå 4,290 4,194 3,573 3,573 3,573 3,573 3,573 3,573 3,573 ISA 334 476 SYt 7,044 5,895 5,549 5,549 5,549 5,549 5,549 5,549 5,549 Ave. Wir 804 673 633 633 633 633 633 633 633 Min~ 8Spillage , 2,987 989 345 3,871 3,639 1.726 731 0 482 z of dro G 14 4 1 14 12 6 2 0 1 Ae. w 341 13 39 442 415 197 83 0 55 Peak 16 (0.Spf) 682 226 79 884 831 394 167 0 110 0Basic" (Pobn)a mnl Gnr~ 1!EEM 1,386 1,407 1,407 1,407 1,407 1,407 1,378 1,378 1,378 CC, 197 197 197 197 197 197 197 177 177 ! 2,364 2,364 2,364 2,354 2,344 2,319 2,319 2,286 2,252 wraA 4,600 4,60b 4,600 5,051 5,565 5,468 5.434 5,376 5,272 ISA 146 146 146 146 146 146 146 146 146 - 41 - AE 4E.1 Page 2 of 2 2.985 1.98" 198? ff8l 198 19m 199m 1.99 1993 Syst=i Total 8,693 8,714 8,714 9,155 9,659 9,537 9,474 9,363 9,225 3~14ip. 2amm1 1,649 2,819 3,165 3,606 4,110 3,988 3,925 3,293 3,676 Ae. W6 188 322 361 412 460 455 448 376 420 Peak W6 (0.70f) 269 460 516 588 670 650 640 537 599 Total Peak wma 11< 951 686 595 1,472 1,501 1,044 807 537 710 Cost ($ uiL~4n) 124 89 77 191 196 136 105 70 92 Present ValU (1985-93) 745 Valu of nU~ ah 5w 1 Savings (1.5 USc/kf) H$ Savings 25 42 47 54 62 60 59 49 55 Prent .-t* (1985-1993) 295 Total Ba1r Total PoRntial 30,375 31,359 32,150 37,729 39,626 39,513 40,346 41,155 44,355 45,598 Da~an 25,739 27,551 28,640 30,252 31,877 33,799 35,690 37,862 40,195 42,485 Main/DI D 18 14 12 25 24 17 13 9 10 7 N~: Typical cost aplied to oeess cape~cty ms soa $51O30 per W6-yesr after along for OM o ~us and assd~g an 111 dism rate. Tis corm~espmxl to a unt cost of arnd U$1,10016, ine~adng internet duriag cnstzucti, which ca be ~sided an the vey cnservativ side. - 42 - Page 1 of 2 PEA DENN (KW) 121 193& 12AZ 12AA 12A1 1222 121 122Z 1223. 1226t Installed Capactty: Plants in Service in 198M EEB 548 xPm 975 CVC 545 ICEL 348 CORELCA SA 1,620 EEEB 130 EP CVC 45 ICEL 498 CORELCA 893 ISA, 265 Annual Additions to Capacit EEEB 600 1,000 EPN 213 200 322 CVC 270 ICEL '500 CORELåA ISA 808 EEB EPN CC ICEL CORELCA 170 ISA A E43RE Page 2 of 2 19. 19. 12.1 128A 19.12 19.. 1221 122 1921 1994 Total Installed CapactyX Hydro 4,518 5,118 5,118 6,636 6,626 6,626 6,948 7,948 7,948 7,948 Thermal 1,831 1,831 1,831 2,001 2,001 2,001 2,001 2,001 2,001 2,001 Intal 63A2 .9.949624.. A,27 A.27 A,21 A.J 9292 92J9 2J.94 Demands-(5.8%) 4,404 4,690 4,991 5,272 5,607 5,954 6,297 6,691 7,114 7,531 Reserve 1,945 2,259 1,958 3,355 3,020 2,673 2,652 3,258 2,835 2,418 % of Capacity 31 33 28 39 35 31 30 33 28 24 % of Demand 44 48 39 64 54 45 42 49 40 32 Reserve (30% of Demand) 1,321 1,407 1,497 1,582 1,682 1,786 1,889 2,007 2,134 2,259 Excess Reserve 623 852 460 1,773 1,338 886 763 1,250 700 158 % of Caacit 10 12 7 21 16 10 9 13 7 2 Cost of Excess Reserve (USsmins) 81 111 60 231 174 115 99 163 91 21 Present Value (1985-93) (US$ millions) 750 New Plants Gpe IV Mesitas Calderas R. Grande Guavio Salvajina Betania San Carlos 2 Jaguas Playas T. Guajira -44- ANNEX 48.3 Page 1 of 2 ENERGY BALANCEs DECEMBER 1978 PLAN AND RISTORICAL (ACTUAL) DEMAND 1980 1981 1982 1983 1984 1983 1986 1987 1988 1989 EEB Bogota River 2840 2840 2840 2840 2840 2840 2840 2840 2840 2840 Chingaza 550 1385 1385 1385 1385 1385 1385 1385 Meeitas 650 650 650 650 650 650 650 650 Guavio 5000 5000 5000 Subtotal 2840 2840 4040 4875 4875 4875 4875 9875 9875 9875 EPm Guadalupe 1444 1894 1894 1894 1894 1894 1894 1894 1894 1894 Guadalupe IV 1120 1120 1120 1120 1120 Rio Grande 543 545 545 545 545 545 545 545 545 545 Rio Grande II Guatape 2650 2650 2650 2650 2650 2650 2650 2650 2650 2650 Other 30 30 30 105 105 105 105 105 105 105 Playas 1400 1400 1400 1400 Subtotal 4669 5119 5119 5194 5194 6314 7714 7714 7714 7714 CYC Anchicaya 360 360 360 360 360 360 360 360 360 360 Calima 190 190 190 190 190 190 190 190 190 190 Alto Anchicay 1400 1400 1400 1400 1400 1400 1400 1400 1400 1400 Other 44 44 44 44 44 44 44 44 44 44 Salvajina 925 925 925 925 925 925 Subtotal 1994 1994 1994 1994 2919 2919 2919 2919 2919 2919 ICEL Chec 665 665 665 665 665 665 665 665 665 665 Norde-te 57 57 57 57 57 57 57 57 57 57 Other 535 535 535 535 535 535 535 535 535 535 Betania 2250 2250 2250 2250 Subtotal 1F57 1257 1257 1257 1257 1257 3507 3507 3507 3507 ISA Chivor 3000 3000 3150 3409 3525 3950 3950 3950 3950 3950 San Carlos 1950 3900 3900 3900 3900 3900 3900 3900 San Carlos II 1000 1990 1990 1990 1990 1990 1990 Jaguas 400 780 780 780 780 780 780 Calderas 40 79 79 79 79 79 Subtotal 3000 3000 5100 8749 10274 10699 10699 10699 10699 10699 Total Hydro 13760 14210 17510 22069 24519 26064 29714 34714 34714 34714 Increase ERR 450 3300 4559 2450 1546 3650 5000 0 0 -45- ANNER 4E.3 Page 2 of 2 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 EuB Zipaquira 712 1088 1088 1088 1088 1088 1088 1088 1088 1088 CvC Yumbo 217 217 217 217 217 217 217 217 217 217 ICEL Paipa 487 700 914 914 914 914 914 914 914 914 Barranca 301 301 301 301 301 301 301 301 301 301 Palenque 27 27 85 85 85 85 85 85 85 85 Zulia 22 22 22 22 22 22 22 22 22 22 Tibu 33 33 33 33 33 33 33 33 33 33 Tasajero 920 920 920 920 920 920 920 Subtotal 670 1083 1355 2275 2275 2275 2275 2275 2275 2275 EEBB+CvC+IcEL 1799 2388 2660 3580 3580 3580 3580 3580 3580 3580 CORELCA Barranquilla 1560 1560 1560 1560 1560 1560 1560 1560 1560 1560 Cartagena 1156 1156 1156 1156 1156 1156 1156 1156 1156 1156 E1 Rio 322 322 186 186 186 186 186 186 186 186 Chinn, Ballena 119 119 119 119 119 119 119 119 119 119 T. Guajira 490 981 981 981 981 981 981 981 T. Quajira II 350 1042 1042 1042 1042 1042 La Union 225 225 123 123 123 123 123 123 123 123 Cospique 170 170 103 103 103 103 103 103 103 103 Chinn 82 82 46 46 45 46 46 46 46 46 Diesel 100 100 Subtotal 3734 3734 3783 4274 4624 5316 5316 5316 5316 5316 ISA China Total Thermal 5533 6122 6443 7854 8204 8896 8896 8896 8896 8896 Increase 589 321 1410 350 692 0 0 0 0 0 System Total 19293 20332 23953 29923 32723 34960 38610 43610 43610 43610 Increase 1039 3621 5969 2800 2237 3650 5000 0 0 Real Demand 19481 19520 21549 23073 24588 25739 27531 28640 30252 31877 GMh Margin 188 813 2404 6850 8135 9221 11059 14970 13358 11733 CORELCA 3231 3449 Central System 16250 16071 MarxinLDemand (M) System -1 4 11 30 33 36 40 52 44 37 Central System -4 3 CORELCA 16 8 �явr s�исв:__аб_._�г 197,+ в Рии, лю нisтавiСл�. о�о 19�71 },я�,►g 1, ятз ��s„�s„ 1� 19rf 1s7в 1s7,s, �� 1� 1в____ва � 19s6 1� 19вt 1„r„ea � � 8о�в Riwr �840 9940 ю40 4'840 8940 4840 29�W х640 2840 Z840 2840 2840 ZB�W g840 ZWO ?840 2В40 29�i0 2610 pijp�pдe 680 1886 1888 1386 1886 18Q6 18�'i lNsilьвs бю ю0 +860 Cesvie _ 6дЬ8о#а1 48+0 ю+4 ZЧО l9�W Z840 28,4 ZB�Q Z840 4840 ?910 2840 4944 8890 4�6 42?6 4Z'l6 4876 д87В 4876 � бггадвlирв 1444 14Ч 1Ч4 14+�t 11И 1444 i111 1Ч4 14И 1Ч4 1994 1894 1894 189К 1BW 1894 18Я4 i894 1894 � gy���, �у 8аб 1MQ 1180 11т0 11ю � вtо аг.ла. 64в ыв s4в ыв 646 646 б�са ыв в4а в#6 ыь 646 r►#s 6<6 в4в 64е ыб ыв ыв о. _ Rie Onndв ii � an#.о. юбо so6o вюо �о �aso жо sою пвбо гббо zвбо zвбо пебо �вбо �sю юбо zвбо пвю пвбо о8м� ео ю ю ю ю ю ео ю ю ю 8о ю 1ю 1а 1� 1а6 1ю 1ов 1as Рlервп ..� �. ....� ..�. � 1400 ToSs1 3i0i9 10li9 408i1 1089 �089 4469 А0611 4089 1б89 �{889 4Q89 6119 6194 6194 6664 б81# б814 7014 7Т1+1 � лaCntoari 8ео 8ео вео аво sso 8во 8so вю 8ю 8во 8во вво адо вво 8а�о 8®о вю 8во 8во Coisм 1ю 1ю 19о 1ю 1ю 39�а 19о 1ю 1ю 1ю 1ю 1ю 1ю 1ю 1ю 1ю 1ю 1ю 1ю A1tro Aдchirar 1i00 1�100 1100 1400 1400 1100 140G 1404 1#00 1#00 140о 1400 1400 1400 1400 огb.г м #в и #в �м м и м м м м м #в м м м м м ы $alvвjiaa 8#7 92S 926 9Z6 9х6 Su�tar#вt В94 Ь94 S94 694 1994 1994 1994 1994 199� 1994 i89�1 1994 2994 199�t 2841 2919 2919 29I9 Z919 2CEL. Сlюе юб 9б6 dQ8 ббб 986 !Кб б86 686 086 е86 886 966 8б6 666 ббб б65 QB6 906 066 'b NoгdвsLe 67 67 67 67 67 87 ВТ 57 67 6Т 67 67 67 67 57 6Т Ь7 67 67 � д8Мг 20б 20б 20б 88б 686 686 686 586 686 686 688 b86 685 686 686 686 585 6$6 686 N ц 8вЕваis 2Z60 226о о � s,�ьtoai 9гв 9хе 9ге 11ов 1�ы 1�ьт 1267 1�67 1�67 lгбт lzsт lгбт 1гы 17ьт 1zь7 8г,ет 8ко� 8ют вбот �, . � � м � .w w о � и т а� � �968 9968 9966 946L 0888 LZBг 089L 918г тб0г 9т1Т 8тtТ 9т1т 8S9i 849т 988 688 088 086 it8 1�I+��Э 91гг 91гг 91гг 91гL 9Lгг гLSt 99Sт tlгт 99L 98L 98t 981 �0@8 089 68L 88г t8L S8L т9г 1M�:9+►S Ot8 Ой8 0�8 OZe Ог8 OL8 Ог6 " '-' . ывjвst1 86 @t 66 88 66 66 R8 Н8 68 6S У8 86 86 г8 iS г8 г8 г4 88 �9l1 ZL гS Lг Lг гг Lг Lг гZ гг гL �L гг Lb Ег Lг гг La aL �l1AZ 88 9S 98 g8 � 98 98 88 tг 1г lS tг lг tг tг lE lE lг lL в�вlвд тОг тОг тОQ Т08 т08 тОг TOS Ltг 1тг LtL 1тг Lтг т� Т9 Т� t� 'IO т� 'W ы�в��вА rts пв втв пв ыв пв пв ыв tеь tаь tеь tsf tвr свь мт мт оьт оы +оы гдt•д � � 1тг стг 1тг стг си си 1тг 1тг гтг 1тг гтг 1тг iu 1и .ти ги tta 1ta tu �� � r � � � t�1t i�1►T f�9tт 1�fт 88Sт 890Т 89бт 880т 960t гтL Ец гтL гтL гtL 9S6 � Y�S �6 �66 ыt^�!У � бтtt 0�89 49�1 888Т гSвt t9ri 1�8А 00! 0 0 000 i88Y �Ttt 0 �i9т f�бt 0 О�Е ввiыs�i aaass та�а aasas ап�sп пап�п тпаап ацаапп татап шп� вааап атпап aaasa аппап ааштп птеаs поаее п�аа asas ааеаш а� litвг 9в3Аг 9тЕ8г 9S9Zг LггтL 9618т riL9t 096►► o81St 0�16t OëL6t 09т8Т S1гтt О�тот 09тОт tTK tбf6 TSiS t869 ыР1Н 1�М1 ввsот овтот osвL ogsc oset �гтL воье ost8 ооов ооое ооов оо� �ттт 0 0 о о 0 0 lмosvps бL 01� ._..._ _.� �. _.. ..._ ..�. _.... sв� вр{в� 00L 00~ ввnliв� ОQбт ОfбТ ц <еi1в3 deg ООбг � 0066 ООб� 00� ООа6 �1��9 �$ 04li8 р�д8 0968 03а8 0366 9г98 гОт'6 о9тб 0006 0008 00� 0006 �ttt .+в�lу� � веат вт r вт ю т sввт iввт вввт гв`ат т'�i �t � t�s г иат �ui 's� в' t�i �f tst � с 'imr av т за = м � .w w о � м at � � а � в вт п- о тт вг- вт- в- в w ат- r»за� т- я- в в �t а п t- о вт т +r•u�гs i�м� а ог ат гt ят ot в- в• а т- т с е г- е г- в ы г- мn*�гв (� w �а7�'s � г Т[ов[ 09авТ ва0qТ Овввt вббтт S8►Et бсвоt 889б тгсв L9в! a8tt rв'♦�S 1� 8ььв Твгб сьвг Os9L T6tL t9бг бtвт ьбвt a18t ввбt O10t � � 8ьц вввЕ UR8 9цв tьы L9L 1вТУ 9!i aLa- Lat LOat 68оТ 9ва- ОвS вта• Ов9 iost пSТ- �lы�11 УМli саТ тsоае оьввг t9sta ввс9г ве9ьг в�овг вь9тг огsет tвьвт есвст овтвt reты оьяеt автгт аягtт вваот оаав автв р�а�•а вттт гаw овв ыы ааьг виь вьвт ш всв tttt оов ыта вввt вгс srsz овт вгв овьа «��s �������������������� бТтбв ООовв 8c8t6 0LS08 rT88Z sLOCE ttHtt LвSOL 9838i 80ЕвТ �68ct L66rt S1t9t 806вТ L89Lt в8ott s9A0t ca90t св0в !�1 �:�5 о тwт о ос ваоs свт эвот гст о�в атгт о оьг т9е егс о о вгв оть .:м+�j + ���.�.��.���������......��� �у вОМ 801�8 8ввв ввв8 Lва8 rBLL L9ol а009 9t89 бьь9 LsLr estr Lввв 9rtS ZLra LцьЕ айьЕ ввоL вввl 1�++41 !�1 s � �!� � втв9 втея ыгь ь�гь ьсаь ьсгь ьиь ввгв rscs ьвtе аа�а агпа евьа ввst вввт юпт овят ооаТ асв l�ов�в � " оот �� оот оот оот оот о�iт оот � оот 1�lа вь вь вь 4► вь вr вь пь ав ае ав • ае ав ав ав ав ав пе ав �Ир вОт воt воt воС воТ воt воТ воТ OLT oLt OLT ОсТ OlT Ост O1t Odt ОсТ Ott O1t �►!� ват ват sLT вгt ваt Sat ваТ бат 9tL 9aL $гL 9LL 9aZ 8aS 8ES qaS � 9г3 8aZ �l�1 в'1 aioY tlot 2I Чl�� '1 Твв tвв t8s t8d твв tK tвв иli�� '1 втт втт вtт втт вtт втt втт втт вtт вТt вtt втс яв пв ss яв яв яв пв �»!�•е ��lц� ввт ввt веt 9аТ ввт ввt osT эвт аав аав ыв пав пгв ыв гав ьав ые г�гв ова ota �э вяtт вstt вятт astt вэтt вяtт я�rtt ввтт �tt вятт tяс аяt аяt �n o�t ооsт оап овgт ов9t овзт oast овзт овsт овзт tяt гя� а9� г9я авя аяв аяя �tв •�tl�++� а ао� вввт вввт 1 вТ ю`вт sт ь �т вввr г вт тв`вт о т� в� fв вт э т � ь в в�iв Е� �f о �vзr�ois : 49 4E.5 E~ KM SUMY Od~ Imestmt Sd~ (Der, P, * Pr 1978 plan) (Us$ Mill 4 1991 im Tämjero 5.4 18.2 32.5 38.1 Gmjim 2 3.5 29.3 39.4 19.0 ~ 1x 4 5.0 18.2 35.5 32.9 15.6 PlaYas 7.5 10.5 30.6 48.8 47.8 20.1 Betanla 9.7 40.9 60.4 83.0 106.1 38.3 Guavio 20.5 23.6 51.5 91.0 10.1144.9 161.5 65.3 Total 5.4 38.8 82.8 lffi.5 255.9 292.8 314.4 219.8 65.3 NM 1978 8M.4 lipp 01 Inves~ Sch~ (mm cwu, n~ in-se~ dates) 1979 1~ 1M DE 1M 1~ 1M M6 1987 1M 1M 1M IM 1%2 Tmjero 5.4 18.2 32.5 38.1 Gmjira 2 - 3.5 29.3 39.4 19.0 ~ 11 4 6.0 18.2 35.5 32.9 15.6 PlAYas 7.5 10.5 30.6 48.8 47.8 2D.1 Be~ 9.6 40.9 60.4 83.0 106.1 38.3 0~ 20.5 23.6 51.5 91.0 109.1144.1161.5 65.3 Total 5.4 24.2 67.9 M S 173.7 210.5 224.4 149.3 109.1144.9 161.5 65.3 NK 1978 577.0 _~ 225.4 Notes DIwamt Rate 11L - 50 - ANNE SA.1 Page 1 of 4 PRICE DEFLATORS 1. Blectricity has been a non-traded commodity in the Colombian context with all production being consumed locally. As a result, assessments of power tariff movements in "real" terms have been defined generally only relative to domestic inflation. In this event, the GDP Deflator Index (which provides a broad gauge of local price evolution) is used often to deflate such tariffs. However, given that tariffs are expected to reflect costs, they should maintain presumably their value in *real* terms where this is defined relative to the localiforeign currency component of inputs to the sector. This implies that tariffs need to be deflated using a combination of three indicatorst (i) the GDP deflator for the local currency component of sector investments; (ii) the peso exchange rate; and (III) foreign inflation indices for the foreign currency component of such investments. 2. During the review period Investments in the power sector in terms of local and foreign currency components have been as follows: COMPONENTS OF POWER SECTOR INVESTMENTS 1971-86 ja Period Local Currency Foreian Currency (M) (M) 1971-81 40 60 1982-84 45 55 1985 50 50 1986 42 58 /a 'Evolucion de las Tarifas de Energia Electrica Periodo 1971-86,6 Document ISA-OPUN-30/11/87-137E. Which, for all practical purposes, has approximated a 40160 localiforeign currency split during the review period. Given this very high foreign currency component, the power sector's capacity to service its foreign debt during periods of exchange rate adjustments becomes dependent on the degree to which tariffs reflect these realities. - 51 - ANNEX 5A.1 Page 2 of 4 3. The three indices - GDP deflator, peso exchange rate, and external inflation - are not independent and, under competitive conditions, the exchange rate should reflect both changes in external and local prices. In particular, the devaluation rate should approximately be equal to the rate of change of the GDP deflator minus the rate of foreign price inflation. Although deviations from this may occur In some years, a sustained difference (such as long-term over- valuation) is unsustainable and, therefore, should not form the basis of projections (see para. 5 below). The table below shows the development of important macroeconomic indices during the review period, in particular, the GDP deflator index, the historical pesolUS dollar nominal and real exchange rate indices, and a foreign price inflation index as measured by the Unit Value Index of Manufactured Exports to LDC markets, from the USA, Japan, UK, Germany, and France, expressed in US dollars. As evident from this table, the real exchange rate index: shows an increasing peso under-valuation, especially between 1973- 1976, with this trend reversing in 1975. Indeed, relative to 1975, the trend in the real eychange rate was towards over-valuation until 1983/84, at which time this trend was reversed through an accelerated devaluation rate policy, so that by 1986 the real exchange rate was roughly on a par with its 1975 level, though again, under-valued relative to 1970. 4. Also shown in this table is the Composite Deflator Index. This index is designed to take account of the local and foreign currency inputs to the sector's investment, particularly during periods of adjustment. It has been defined as the sum of the GDP deflator Andex, weighted 40%, and the foreign currency index, weighted 602. As can be seen from this table, during adjustment periods (e.g. the 1974175 period of high external inflation and that of 1985/86, during the period of accelerated peso devaluation), the Composite Index is a ,harder' deflator than the GDP deflator. 5. As mentioned above (para. 3), the underlying macroeconomic assumptions in SARs regarding the relation between exchange rate forecasts and local/foreign inflation forecasts need to be consistent. This means that the forecasted exchange rate index and the index of the localiforeign inflation ratio should not present a widely divergent trend. In this context, the *exchange rate index, purely refers to the ratio of the projected exchange rate to the rate at appraisal, and the index of the local/foreign inflation ratio is just the ratio of the projections of these two indices. The degree of such consistency in SAR forecasts in relation to this criterion can be assessed from the data in Annex 7C.1. Observations pertaining to specific SARs are the following* 1 As defined by the product of the nominal exchange rate and foreign price indices divided by the local price index. - 52 - ANNEX SA.1 Page 3 of 4 The Guatape I SAR (1972) is inconsistent in its assumptions of constant exchange rate, coupled with 4Z foreign and 102 local inflation. This results In the untenable hypothesis of a continuous increase in the real exchange rate. The Chivor I SAR (1970) is consistent in so far as it assumes sero local and foreign inflation and a constant exchange rate. All other SARs assume that in the forecasted periods the nominal exchange rate will increase faster than the localiforeign inflation ratio. i.e. an assumption of decreasin relative prices and a trend of peso under-valuation, which is consistent and can be considered as a reasonable hypothesis. оеrааРwЕит OF к�г W►скоБст�оrпс n�кcES . 1 a8tпia �vкar Patloo 14Т1-ю , _ 1470 �4.71 �� i4T� � 18'_,!8 14�Т7 1978 14Т4 �88б 1481 � 1� ,1984 1466 �,1�,487 � Рвмs мг 18� (вiд-увsг) 18.4 14.4 41.4 38.8 20.1 80.4 8�.7 8б.8 84.1 44.6 87.8 64.6 в4.1 7В.4 100.8 144.8 24�.$ Z4Z.0 Рвюs еаг И�4# (в�ад-уwг) 14.1 50.4 У4.9 Z4.6 Z8.в 88.0 �.8 88.0 11.0 44.0 60.4 64.1 Т0.8 86.В 118.4 17S.Z 314.0 �8.7 tkдlмl ЕхеМд4в �У�. � . Qвiд-2гиг) 100 109 114 1S8 181 106 188 144 Z14 481 26е S46 847 424 6�Т 774 1,OS8 1,814 Nов1 м 1 E�iehsn4a �itв (вад-vвагl 100 1� 114 180 160 178 140 144 ц8 g80 R8T 80! 808 486 69в 40Z 1,UT 1,881 ODP рвllвtог Iпдвх (мд-уваг) 100 ц0 146 160 18t 281 $40 874 484 646 в46 668 1,084 1,480 1,БбS 1,4ZT Z,41B 3,486 0� рвt 1 аiог IмМх � (вlду►иr) � - 106 118 188 164 410 481 888 �107 48Z б20 77�1 969 1,174 1,428 1,74б 2,171 2,7� и Fonlon Рг1ав Iлдьх 100 106 116 188 1б4 180 188 301 481 ZбZ 46Т 468 4В4 Z77 lt7Z 276 826 8Q0 t"' (as ввиимд Ь�г WVj � Rва 1 Bxabs�a Rat�e Yndax 100 104 i04 116 1Z4 186 114 10Т 118 111 110 104 48 101 104 284 164 188 FОм�яр сУГНЛСу Ifldмt � .(мд-ург) 100 118 18Т 1Т8 448 811 848 100 447 Q08 78б 840 1,046 1,488 1,в21 2,481 8,728 4,47Z Coiq�oaiй aвtfatoг Indnc (•id-�nааг) Lь - 1оТ 1я8 148 148 �о 8сп в68 48lt s2T вs4 8о7 4м 1,1в4 1,44? 1,424 s,T81 а,в4Z - Савровl8в Рааг 8ва8ог Dвtlstoг Iпдах �g (мд-�гмг) 100 118 184 1в4 ZZ1 2Т8 8Z6 840 4Т4 690 Т8В 876 i,068 1,286 1,84Q 2,Z84 8,708 4,181 L ОrГiмд ав t�hв ргадие4 ot 8bв toмi{р� огiсв lддnс аад W�в мвiмl вкаhаляа мtв iпдвх. �(.,Ь filtia ha: Ьаем двгlwд !мв !гМ мд-2маР еов�►оаl8tг datlвZer римlr bp 8аk1п4 а siмдl• 1iм:г swга4в. lg Овflмд ss 8bв sw ot tM 09Р datlateг indax мt4bйд 44х адд l�hв tомiрл еигмnе�► iadax иi4А8вд б0�Е. т � � г� и м9 r � - 54 - ANNEX 5B. I EVOLUTION OF AVERAGE TARIFFS FOR TIM POWER SECTOR BY USZR TYPE, 1971-1987 (1986 Pesos/kVh) Year Residential Commercial Industrial Total National Real 1 Real 2 Real I Real 2 Real 1 Real 2 Real 1 Is Real 2 lb 1971 4.81 5.93 7.22 8.90 5.25 6.47 5.23 6.13 1972 4.63 5.49 7.14 8.47 3.02 5.93 4.S3 5.55 1973 4.29 4.83 6.60 7.65 4.51 5.22 4.51 5.17 1974 3.72 4.11 6.03 6.67 4.24 4.6$ 4.11 4.53 1975 3.65 3.86 6.16 6.51 4.49 4.74 4.18 4.37 1976 3.58 4.03 6.16 6.94 4.66 5.25 4.33 4.70 1977 3.61 4.34 6.39 7.67 5.03 6.04 4.52 5.34 1978 4.02 4.70 7.65 8.95 5.78 6.76 5.12 5.88 1979 4.12 4.84 8.16 9.58 5.99 7.03 5.29 6.27 1980 4.24 5.13 8.31 10.04 6.29 7.48 5.39 6.42 1981 4.87 6.10 9.57 12.99 7.36 9.22 6.26 7.48 1982 5.13 6.71 10.64 13.92 8.22 10.74 6.79 8.47 1983 5.13 6.72 11.82 15.49 8.66 11.34 7.11 8.61 1984 4.85 6.25 12.25 15.80 8.66 11.16 7.04 8.64 1985 4.91 5.80 13.18 15.56 9.81 11.58 7.51 8.46 1986 4.98 4.98 13.67 13.67 10.32 10.32 7.84 7.84 1987 4.98 4.59 14.53 13.39 10.48 9.66 8.04 7.41 ja Deflated to 1986 pesos using the GDP Deflator Index (mid-year) In Annex Sk.l. Lb Deflated to 1986 pesos using the Composite Deflator Index (mid-year) in Annex 5A.1. which takes account of local and foreign inflation and peso devaluation against the US$. - 55 - ANM 5.2 EVOLUTION OF AVERAGE TARIFFS FOR THE POWER SECTOR .Y COMPANY. 1971-1987 (1986 Pesos/kWh) X1M COEL IM .SU, EP ENCALL .C. Total. National Beal.2 /a Real.2 eal 2 eal Beall anal.2 Real.Z 1971 7.20 5.60 5.90 4.90 7.40 7.60 6.10 1975 6.17 4.30 4.08 3.64 4.85 5.18 4.41 1980 8.70 6.20 6.20 4.60 7.60 8.00 6.40 1982 11.20 8.30 8.50 5.60 9.30 10.70 8.50 1984 8.50 7.20 12.00 6.70 8.70 9.40 8.60 1986 7.61 6.30 10.90 6.60 7.70 7.35 7.84 1987 7.84 6.01 10.00 6.28 6.90 6.50 7.40 La Deflated to 1986 pesos using the Composite Deflator Index (mid-year) in Annex 5A.1, which takes account of local and foreign inflation and peso devaluation against the US$. - 56 - ANNEX 58.3 PERCENT AVERAGE ANNUAL CHANGES IN AVERAG RETAIL TARIFFS IN REAL TRMS FOR DIFFERNT REGIONAL WmEuTS is 1971-1987 (Percent) Residential Commercial Industrial Total 1971-1975 CORELCA - 7.4 - 1.6 - 4.0 - 3.8 ICEL - 9.3 - 7.6 - 5.5 - 6.7 EEES - 7.0 - 9.6 -11.5 - 9.9 EPM -11.5 - 5.3 - 5.5 - 7.1 ENCALI -15.6 -12.5 - 7.1 -10.2 CVC -10.3 -11.3 -11.3 - 9.5 Average National - 9.2 - 6.5 - 6.4 - 8.1 1975-1983 CORELCA 5.7 6.7 6.0 5.5 ICEL 5.1 9.6 13.4 7.9 REB 9.0 17.1 17.0 13.2 EPM 5.0 9.3 9.8 7.3 ENCALI 11.3 8.8 9.9 9.3 CvC 5.4 7.9 9.4 7.5 Average National 6.6 10.8 10.9 9.2 1983-1987 CORELCA -11.3 - 9.3 - 6.7 - 4.7 ICEL -10.3 - 8.4 - 8.0 - 6.7 BED -11.8 3.3 2.5 - 2.0 RPM - 1.6 - 0.4 - 1.2 - 0.5 BMCALI - 6.1 -10.6 - 9.4 - 8.3 CVC -14.9 - 3.1 - 0.1 - 8.1 Average National - 7.8 - 2.2 - 2.6 - 4.2 1971-1987 CORELCA - 1.5 1.1 0.6 0.5 ICEL - 2.1 1.0 3.6 0.4 EM8 0.1 6.6 5.8 3.4 EPM - 1.0 3.3 3.3 1.6 ENCALI - 0.1 - 1.3 1.1 - 0.4 CvC - 3.3 0.2 1.6 - 1.0 Average National - 1.3 2.9 2.9 1.2 .&, The Composite deflator of Annex SA.1 was used to deflate the retail tariffs. - 57 - ANNER 5C.1 Page 1 of 8 PERPOMUANCE OF TARIFFS RELATIVE TO PROJECTIONS 1. The data below set out the tariff assumptions used in financial projections for each company In each project as well as the actual tariffs that were observed for that company during the period of the projection. The forecast tariffs are shown in current pesos (Pa.) and are expressed in constant pesos using the composite deflator index projected for that project and shown in Annex 5C.3. The actual or observed tariffs are also shown in current pesos and then converted to constant pesos of the base year. The observed composite deflator index resulting from historical outcomes is given in Annex 5A.l. Finally, the last row of each table for each project shows the ratio of the actual to forecasted tariffs derived from these tariffs expressed in constant pesos for the base year indicated in each table. These ratios of actual to projected tariffs are then summarised by company and project and presented in Annex 5C.2. 2. Before commenting on these ratios some remarks are relevant about the characterization of tariff projections from an analysis of the data in this annex. First, for early projects, i.e. those presented to the Board between 1977 and 1980, tariff forecasts had two important characteristics. The projects covered in this period Include San Carlos I and II, Mesitas, Guadalupe IV, and CORELCA's Village Electrification. These characteristics were a real increase in tariffs for about the first 3 years of project implementation, followed by real declines during the remaining 3-4 years of implementation. This was marked, especially in the case for EPM under the San Carlos I and Guadalupe IV projects. These trends were also evident for projections of KEEB tariffs in the San Carlos I and Nesitas SARs, as well as for the CORELCA Village Electrification project, though in all three cases the declines were not as dramatic as in the case of EPM. Second, for the later projects, i.e. those presented to the Board after 1981 (Guavio, Bogota Distribution I and II, Playas, PEN, and Rio Grande), tariff projections were all based on real increases during the entire project implementation period, though at different rates, dependent on the company. This would suggest that, at least around 1980181 in the cases of the Bogota 1, Guavio, and Playas projects, that there appeared to be increased recognition on the part of the Bank of the need for sustained improvement in tariffs in real terms if the earning capacity of the borrowers was to Iaprove--though this was still very remote from what was really required. 3. Given the difficulties in forecasting, values of the ratio of actual to forecasted tariffs in real terms that fall between 90 and 110 can be considered reasonable. Based on the data summarized in Annex 5C.2, high outliers are defined as those ratios greater than 110 and low outliers as those below 90. The high outliers correspond to cases generally where projected tariffs have followed a *low trajectorya compared to actual tariff outcomes (i.e. conservative tariff projections). For the low outliers, actual tariff performance has been - 58 - ANNEX SC.1 Page 2 of 8 disappointing relative to the levels projected. Just under 113 of the ratios in Annex 5C.2 correspond to low outliers campared to just under 14 that are high outliers, with the remaining 502 of values falling within the "reasonable' range. Turning to the values of the ratio for individual companies, the following observations are relevants IEPB (M) The high outliers, beyond 1982183, for the San Carlos 1, Mesitas, and Bogota Distribution I projects correspond to rapid real increases in IEB's actual tariffs, allied with real declines in what was forecasted post-1981. (ii) In the case of Quavio, the rapid real increases in BEB's tariffs up to 1984 even exceeded the 602 projected real increase between 1980-84, resulting in a rise in the ratio followed by a quick decline after 1984 as the actual tariff decreased because the accelerated devaluation impact was not passed through. (iii) As far as the FIN operation was concerned, the stability of the ratio up to 1985 merely reflected that the marginal decrease of EE's real average tariff between 1983-85 was approximately in keeping with a projection of tariffs that possessed virtually no change in real terms, i.e. the status quo as forecasted and as observed. Of course, in 1986 the drop occured as discussed above. EPM (i) The low outliers for 1979 and 1980 in the San Carlos I operation highlight the marginal change in actual tariffs before 1980 compared to projections that envisaged real increases of about 402 between 1977 and 1980. (ii) The high outliers, between 1983-86, for Guadalupe IV reflect almost solely the decline in the projected tariff since the actual tariffs over this period underwent only small changes. (III) Low outliers are pronounced in the 1984-1986 period for both the Guavio and FEN projects due to actual tariffs being unable to keep in tandem with the reAl Increases projected, especially in the FEN operation. It is relevant to note that in the Guavio operation, BEM retail tariffs were projected to increase by about 92% in real terms between 1980-86, and in the PEN operation, EPM's tariffs were projected to rise by 362 in real terms between 1983 and 1986. - 59 ANNEX 5C.1 Page 3 of 8 CORLCA There are significant numbers of low outliers associated with all projects after 1983. This arises from the continued real collapse in observed tariffs in this market after 1982, even before the accelerated devaluation began. ICEL The low outliers in 1985 and 1986 for the FEN operation were due solely to the significant real decline in observed tariffs between 1983 and 1986 since virtually no real increase had been projected for the ICEL tariff in this loan. In the case of the Guavio operation, high outliers existed up to 1983 due to a rapid increase in the observed tariff. However, the rapid decline in the ratio after 1983 arises from a 242 real decline in the observed tariff and a similar rise in the projected tariff. Consolidated Power Sector The modest rise in the ratio between 1980-83 for the Guavio operation reflects similar increases in both the observed and projected tariffs; post-1983, however, as actual tariffs went into fairly rapid decline, but forecasted tariffs continued increasing, the ratio experienced a significant decrease. Finally, the collapse in the ratio for the F=N operation, arises primarily from the steady decline in the observed tariff from 1983. - 60 - ANNE SC.1 Page 4 of 8 PERFORMANCE OF TARIPPS R8LATIVE TO PROJECTIONS San Carlo. I REED Tariffs 1977 1978 1979 1980 1981 1982 1983 1984 Current Pa. Forecast 0.56 0.86 1.15 1.49 1.79 1.95 2.12 2.3 Constant Base-1977 0.56 0.72 0.83 0.94 0.99 0.96 0.93 0.89 Actual Current Pa. 0.58 0.85 1.12 1.49 2.14 3.00 4.65 6.35 Actual-Constant 1977P9. 0.58 0.70 0.76 0.81 0.95 1.11 1.42 1.58 Actual/Forecast Ratio 100 97 92 86 96 116 154 177 EPH Tariffs 1977 1978 1979 1980 1981 1982 1983 1984 Current Ps. Forecast 0.53 0.67 0.97 1.16 1.28 1.38 1.49 1.49 Constant Base-1977 0.53 0.56 0.70 0.73 0.71 0.68 0.65 0.58 Actual Current Pa. 0.56 0.7 0.88 1.11 1.44 1.96 2.72 3.51 Actual-Constant 1977Ps. 0-56 0.58 0.59 0.60 0.64 0.73 0.83 0.87 Actual/Forecast Ratio 106 104 85 0.83 90 107 128 150 mesitas EEB Tariffs 1978 1979 1980 1981 1982 1983 1984 Current $ Forecast 0.86 1.15 1.49 1.79 1.95 2.12 2.3 Constant Base-1977 0.72 0.83 0.94 0.99 0.96 0.93 0.89 Actual-Current $ 0.85 1.12 1.49 2.14 3.00 4.65 6.35 Actual-Constant 1977Ps. 0.70 0.76 0.81 0.95 1.11 1.42 1.58 Actual/Forecast Ratio 97 92 86 96 116 154 177 Bogota Distribution I EEB 1978 1979 1980 1981 1982 1983 1984 1985 Current Pa. Forecast 1.14 1.58 2.0 2.65 3.44 3.96 4.59 Constant Base*1979Ps. 1.14 1.31 1.40 1.55 1.70 1.69 1.68 Actual-Current Pa. 1.12 1.49 2.14 3.0 4.65 6.35 8.34 Actual-Constant 1979Ps. 1.12 1.19 1.40 1.64 2.10 2.32 2.28 Actual/Forecast Ratio 98 90 100 106 125 138 135 - 61 - ANNEX 5C.1 Page 5 of 8 Guadatlpe IV ERm 1980 1981 1982 1983 1984 1985 1986 Current Pa. Forecast 1.03 1.42 1.9 2.28 2.3 2.53 2.79 Constant Base-1979 0.84 0.97 1.09 1.10 0.96 0.91 0.86 Actual-Current Ps. 1.11 1.44 1.96 2.72 3.51 4.95 6.6 Actual-Constantl979 Pa. 0.89 0.94 1.07 1.23 1.28 1.35 1.27 Actual/Forecast Ratio 106 97 98 112 134 348 148 Plaas RPM 1980 1981 1982 1983 1984 1985 1986 Current Pa. Forecast 1.0 1.39 2.0 2.88 3.81 4.8 5.7 Constant Base-1980 Forecast 1.0 1.110 1.288 1.520 1.658 1.751 1.791 Actual-Current Pa. 1.11 1.44 1.96 2.72 3.51 4.95 6.6 Actual-Constant 1980Ps. 1.11 1.214 1.383 1.598 1.662 1.741 1.570 Actual/Forecast Ratio 111 109 107 105 100 99 88 Village Electrification CORELCA 1980 1981 1982 1983 1984 1985 1986 Current Pa. Forecast 2.02 3.15 4.35 5.87 6.97 8.19 9.08 Constant Base-1980 Forecast 2.02 2.530 2.858 3.189 3.153 3.102 2.877 Actual Current Pa. 2.1 3.09 3.94 4.03 4.49 5.92 7.61 Actual-Constant 1980Ps. 2.1 2.606 2.781 2.368 2.126 2.082 1.810 Actual/Forecast Ratio 104 103 97 74 67 67 63 Guavio BEB 1980 1981 1982 1983 1984 1985 1986 Current Ps. Forecast 1.48 2.10 3.11 4.08 5.36 7.03 9.23 Constant Base-1980 Forecast 1.48 1.67 1.98 2.10 2.26 2.47 2.76 Actual Current Pa. 1.49 2.14 3.0 4.65 6.35 8.34 10.9 Actual-Constant 1980Ps. 1.48 1.75 2.05 2.62 2.90 2.85 2.63 Actual/Forecast Ratio 101 105 104 125 128 115 95 62 - ANNEX 5C.1 Page 6 of 8 Quavio 1980 1981 1982 1983 1984 1985 1986 Current Ps. Forecast 1.09 1.54 2.27 3.35 4.38 5.54 6.65 Constant Base-1980 Forecast 1.09 1.22 1.45 1.73 1.857 1.94 1.99 Actual Current Ps. 1.44 1.96 2.72 3.51 4.95 6.6 Actual-Constant 1980Ps. 1.18 1.34 1.53 1.60 1.69 1.59 Actual/Forecast Ratio 97 92 88 87 87 80 Guavio ICEL-Electrificadoras 1980 1981 1982 1983 1984 1985 1986 Current Ps. Forecast 1.43 1.89 2.39 3.04 4.1 5.05 6.24 Constant Base-1980 Forecast 1.43 1.50 1.52 1.57 1.73 1.77 1.87 Actual Current Pa. 1.49 2.17 2.94 3.36 3.81 4.83 6.28 Actual-Constant 1980Ps. 1.49 1.77 2.01 1.89 1.74 1.65 1.52 Actual/Forecast Ratio 104 118 132 120 101 93 81 Guavio CORELCA Electrifica4oras 1900 1981 1982 1983 1984 1985 1986 Current Ps. Forecast 2.04 3.19 4.37 5.58 6.73 8.0 9.27 Constant Rase-1980 Vorecast 2.04 2.53 2.78 2.88 2.84 2.81 2.78 Actual-Current Ps. 2.1 3.09 3.94 4.03 4.49 5.92 7.61 Actual-Constant 1980Ps. 2.1 2.52 2.69 2.27 2.05 2.02 1.84 Actual/Forecast Ratio 103 100 97 79 72 72 66 Guavio - Consolidated Power Sector 1980 1981 1982 1983 1984 1985 1986 Tariff Forecast-Current 1.44 2.07 2.92 3.77 .. 4.84 5.99 7.37 Tariff Forecast- Constant (1980) 1.44 1.64 1.86 1.94 2.04 2.10 2.21 Tariff Actual-Current 1.55 2.21 2.99 3.77 4.56 5.99 7.84 Tariff Actual-Constant (1980) 1.55 1.81 2.04 2.13 2.08 2.05 1.89 Tariff Actuall Forecast Ratio (2) 108 14-0 110 110 102 98 86 - 63 - ANNEX 5C.1 Page 7 of 8 PEN EEEB 1983 1984 1985 1986 Current Pa. Forecast 4.79 6.21 7.43 8.77 Constant Base-1983Porecast 4.79 5.05 4.95 4.87 Actual-Current Ps. 4.65 6.35 8.34 10.9 Actual-Constant 1983Pa. 4.65 5.15 5.05 4.67 Actual/Forecast Ratio 97 102 102 96 EPM 1983 1984 1985 1986 Current Ps. Forecast 2.84 4.11 5.57 6.8 Constant Base-1983 Forecast 2.84 3.34 3.71 3.78 Actual-Current Ps. 2.72 3.51 4.95 6.6 Actual-Constant 1983Ps. 2.72 2.85 3.0 2.82 Actual/Forecast Ratio 96 85 81 75 ICEL 1983 1984 1985 1986 Current Ps. Forecast 3.3 3.99 4.79 5.74 Constant Base-1983 Forecast 3.3 3.24 3.19 3.19 Actual-Current Ps. 3.36 3.81 4.83 6.28 Actual-Constant 1983Ps. 3.36 3.09 2.92 2.69 Actual/Forecast Ratio 102 95 92 84 CORELCA 1983 1984 1985 1986 Current Pa. Forecast 4.13 4.94 5.92 7.14 Constant Base-1983 Forecast 4.13 4.02 3.95 3.97 Actual-Current Ps. 4.03 4.49 5.92 7.61 Actual-Constant 1983Ps. 4.03 3.64 3.59 3.26 Actual/Forecast Ratio 98 91 91 82 FEN - Consolidated Power Sector 1983 1984 1985 1986 Tariff Forecast-Current 3.65 4.65 5.72 6.84 Tariff Forecast-Constant(1983) 3.65 3.78 3.87 3.89 Tariff Actual-Current 3.77 4.56 5.99 7.84 Tariff Actual-Constant(1983) 3.77 3.70 3.63 3.36 Actual/Forecast Ratio of Tariffs 103 98 95 88 - 64- ANNEX 5C.1 Page 8 of 8 Rio Grande SPM 1983 1984 1985 1986 Current Ps. Forecast 3.08 4.08 5.47 Constant Base-1984 Forecast 3.08 3,087 3.309 Actual-Current Ps. 3.51 4.95 6.6 Actual-constant 1984P. 3.51 3.677 3.316 Actual/Forecast Ratio 114 119 100 Bogota Distribution II BEB 1983 1984 1985 1986 Current Ps. Forecast 6.17 8.44 11.48 Constant Base-1984 Forecast 6.17 6.81 7.5 Actual-Current Pa. 6.35 8.34 10.9 Actual-constant 1984P.. 6.35 6.24 5.76 Actual/Forecast Ratio 103 92 77 - 65 - ANNE 5C.2 Page 1 of 2 PROJECTED VERSUS ACTUAL TARIFF PERFORMANCE (Ratio of Actual/Projected Tariffs in eal Peso Terns) Percent EEB Project/ Year 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 San Carlos 1) (1977 Base)) 100 97 92 86 96 116 154 177 - - Mesitas ) (1977 Base)) Bogota Dist. I - - 98 90 100 106 125 138 135 - (1979 Base) Guavio - - - - 105 104 125 128 115 95 (1980 Base) FEW - - - - - - 97 102 102 96 (1983 Base) Bogota Dist. II - - - - - - - 103 92 77 (1984 Base) ICZL Guavio - - - 104 118 132 120 101 93 81 (1980 Base) FEN - - - - - - 102 95 92 84 (1983 Base) Consolidated Power Sector Guavio - - - 108 110 110 110 102 98 86 (1980 Base) FEN - - - - -103 98 95 88 (1983 Base) ISA San Carlos I - 83 90 82 76 88 104 106 - - (1977 Base) FEN - - - - - - 96 106 109 95 (1983 Base) CORELCA San Carlos I - - (1977 Base) Village Elec. - * - 104 103 97 74 67 67 63 (1980 Base) Guavio - - - 103 100 97 79 72 72 66 (1980 Base) EN- - - - - - 98 91 91 82 (1983 Base) 66 - AtM=B SC.2 Page 2 of 2 EPM Project/ Year 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 San Carlos 1 106 104 85 83 90 107 128 150 - - (1977 Base) Guadalupe IV - - - 106 97 98 112 134 148 148 (1979 Base) Playas - - - 111 109 107 105 100 98 88 (1980 Base) Guavio - - - - 97 92 88 87 87 80 (1980 Base) FEN - - - - - - 96 85 81 75 (1983 Base) Rio Grande - - - - - - - 114 119 100 (1984 Base) - 67 - ANNEX 5C.3 Page 1 of 6 PROJECTIONS OF MACROECONOMIC VARIABLES IN SARS 1. The lconsistency" of the projected macroeconomic assumptio.-i made in SARs can be assessed based on the data presented below. Such "consistency" would require that first the projected exchange rate index and the projected local inflationiforeign inflation ratio index should not present a widely divergent trend. Second, that the projected exchange rate index should increase faster than the local/foreign inflation ratio index, which implies an assumption of decreasing relative prices. 2. Observations relevant to specific SARs include: - the Chivor I macro assumptions are internally consistent--i.e. no changes in local or foreign prices or the exchange rates - the Guatape II macro assumptions are "inconsistentO in that they assume Colombian prices would increase relative to the USA throughout the forecast period; - the macroeconomic assumptions in the San Carlos I and Hesitas SARs indicate that Colombian prices would increase relative to those in the USA between 1978 and 1982, with some correction occurring toward the end of the forecast period, 1984; and - virtually all other SARs assume that Colombian prices decline relative to those of the USA in the forecast period. - 68 - ANNEX SC.3 Page 2 of 6 Chivor I Appraisal (1970) 1970 1971 1972 1973 1974 1975 1976 1977 1978 Local Cost Rate (2) 0 0 0 0 0 0 0 0 0 Foreign Cost Rate (2) 0 0 0 0 0 0 0 0 0 Exchange Rate (Psi$) 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 Local Index 100 100 100 100 100 100 100 100 100 Foreign Index 100 100 100 100 100 100 100 100 100 Exchange late Index 100 100 100 100 100 100 100 100 100 Composite Index 100 100 100 100 100 100 100 100 100 Local/Foreign Ratio (Z) 100 100 100 100 100 100 100 100 100 Guatape II Appraisal (1972) 1972 1973 1974 1975 1976 1977 1978 Local Cost Rate (2) 10 10 10 10 10 10 10 Foreign Cost Rate (%) 4 4 4 4 4 4 4 Exchange Rate (Pa/$) 21.4 21.4 21.4 21.4 21.4 21.4 21.4 Local Index 100 110 121 133 146 161 177 Foreign Index 100 104 108 112 117 122 127 Exchange Rate Index 100 100 100 100 100 100 100 Composite Index 100 106 113 121 129 137 147 Loc4liForein Ratio (2) 100 106 112 118 125 132 140 San Carlos I Appraisal (1978) 1977 1978 1979 1980 1981 1982 1983 1984 Local Cost Rate (2) 36 24 15 12 10 8 8 8 Foreign Cost Rate (Z) 8.0 7.5 7.5 7.5 7 7 7 7 Exchange Rate (Psi$) (mid-year) 36.5 37.4 39.8 43.0 46.5 50.2 54.2 58.6 Local Index (mid-year) 100 132 159 178 198 216 233 252 Foreign Index (mid-year) 100 108 116 124 133 142 152 163 Exchange Rate Index (mid-year) 100 103 109 118 127 138 149 161 Composite Index (mid-year) 100 120 139 159 181 204 229 258 Local/Foreign Ratio (2) 100 122 137 144 149 152 153 155 - 69 - ANNEX 5C.3 Page 3 of 6 Mesitas Appraisal (1978) 1977 1978 1979 1980 1981 1982 1983 1984 Local Cost Rate (M) 36 24 15 12 10 8 8 8 Foreign Cost Rate (S) 8.0 7.5 7.5 7.5 7 7 7 7 Exchange Rate (Ps/$) 36.5 37.4 39.8 43.0 46.5 50.2 54.2 58.6 Local Index (mid-year) 100 132 159 178 198 216 233 252 Foreign Index (mid-year) 100 108 116 124 133 142 152 163 Exchange Rate Index (mid-year) 100 103 109 118 127 138 149 161 Composite Index (mid-year) 100 120 139 159 181 204 229 258 Local/Foreign Ratio (Z) 100 122 137 144 149 152 153 155 San Carlos II Appraisal (May 1979) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (M) 18 16 14 12 12 12 12 12 Foreign Cost Rate (M) 7.5 7.1 6.5 6.5 6.5 6.5 6.5 6.5 Exchange Rate (Pals$) 39.1 41.8 45.0 47.9 50.8 53.8 57.1 60.1 Local Index (mid-year) 100 118 136 154 173 195 219 246 Foreign Index (mid-year) 100 107 115 123 130 139 148 158 Exchange Rate Index (mid-year) 100 107 115 123 130 138 146 155 Composite Index (mid-year) 100 116 134 152 171 193 217 245 Local/Foreign Ratio (2) 100 110 118 125 133 140 148 156 Bogota Distribution I Appraisal (February 1980) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (2) 25 20 17 15 15 15 15 Foreign Cost Rate (%) 10 9 8 7 7 7 7 Exchange Rate (Psl$) 42.1 45.4 49.5 56.0 62.7 68.3 74.5 Local Index (mid-year) 100 124 148 172 199 228 265 Foreign Index (aid-year) 100 110 119 128 138 147 157 Exchange Rate Index (mid-year) 100 108 118 133 149 162 177 Composite Index (mid-year) 100 121 13 171 203 235 273 Local/Foreign Ratio (M) 100 113 124 134 144 156 169 - 70 - ANNEX SC.3 Page 4 of 6 Guadalupe IV Avpraisal (May 1980) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (2) 25 20 17 15 15 15 15 15 Foreign Cost Rate (1) 12 10 9 8 7 7 7 7 Exchange Rate (Ps/$) 42.1 45.4 49.5 56.0 62.7 68.3 74.5 81.2 Local Index (mid-year) 100 124 148 172 199 229 263 303 Foreign Index (mid-year) 100 111 122 133 143 153 164 175 Exchange Rate Index (mid-year) 100 108 118 133 149 162 177 193 Composite Index (mid-year) 100 122 146 175 207 240 279 324 Local/Foreign Ratio (M) 100 112 121 129 139 150 160 173 Plavas Appraisal (February 1981) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (M) 25 25 23 21 19 17 14 Foreign Cost Rate (2) 10.5 9 8 7 7 7 6 Exchange Rate (Psi$) 47.3 54.4 62.8 72.0 82.6 93.2 103.2 Local Index (mid-year) 100 125 154 186 221 259 295 Foreign Index (mid-year) 100 109 118 126 135 144 153 Exchange Rate Index (mid-year) 100 115 133 152 175 197 218 Composite Index (mid-year) 100 125 155 189 230 274 318 Local/Foreign Ratio (M) 100 115 131 148 164 180 193 Village Electrification Appraisal (May 1981) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (2) 26 22.7 20.6 18.7 17 17 Foreign Cost Rate (2) 9 8 7 7 7 7 Exchange Rate (Psi$) 50.6 57.3 64.7 73.3 82.9 93.8 106.2 Local Index 100 126 155 186 221 259 303 Foreign Index 100 109 118 126 135 144 154 Exchange Rate Index 100 113 128 145 164 185 210 Composite Index 100 124 152 184 221 264 316 Local/Foreign Ratio (2) 100 116 131 148 164 180 196 - 71 - ANNEX 5C.3 Page 5 of 6 Guavio Appraisal (May 1981) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (2) 25 25 23 21 19 17 14 Foreign Cost Rate (2) 10.5 9 8 7 7 7 6 Exchange Rate (Psi$) 47.3 54.4 62.6 72.0 82.5 93.3 103 Local Index (mid-year) 100 125 157 193 234 278 322 Foreign Index (maid-year) 100 110 119 128 137 147 157 Exchange Rate Index (mid-year) 100 115 132 152 174 197 218 Composite Index (mid-year) 100 126 157 194 237 285 334 Local/Foreign Ratio (M) 100 114 131 151 171 189 205 PEN Appraisal (March 1984) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (2) 23 22 20 18 Foreign Cost Rate (2) 7.5 7.5 7.5 6 Exchange Rate (Pa$) 73.5 84.1 95.1 106.5 Local Index (mid-year) 100 124 151 181 Foreign Index (mid-year) 100 108 116 124 Exchange Rate Index (mid-year) 100 114 129 145 Composite Index (mid-year) 100 123 150 180 Local/Foreign Ratio (M) 100 115 130 146 Rio Grande Appraisal (June 1984) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Cost Rate (M) 20 20 20 Foreign Cost Rate (Z) 10 8 9 Exchange Rate (Ps/$) 101.3 126.8 148.9 Local Index 100 120 144 Foreign Index 100 108 118 Exchange Rate Index (mid-year) 100 130 152 Composite Index 100 132 165 Local/Foreign Ratio (2) 100 111 122 - 72 - AMER SC.3 Page 6 of 6 Sogota Distribution II Apraisal (May 1985) 1978 1979 1980 1981 1982 1983 1984 1985 1986 Local Price Rate (2) 20 20 20 Foreign Price Rate (2) -2.8 5 7.5 Eachange Rate (Psi$) 101.2 126.7 148.8 Local Price Index (mid-year) 100 121 145 Foreign Price Index (mid-year) 100 101 108 Echange Rate Index (mid-year) 100 124 124 Composite Index (mid-year) 100 124 153 Local/Foreign Ratio (2) 100 120 134 - 73 - ANNEX 5D.1 Page 1 of 2 MARGINAL AND INCREMENTAL SUPPLY COST STUDIES 1. Marginal cost studies conducted for the Colombian power system consist oft (i) a 1979 analysis made by ISA and EPM of such marginal costs at the generation level, which was complemented by an analysis of incremental network expansion costs based on the EPM system. This covered the 1978-84 periods (ii) a 1983 analysis done by ISA of the average incremental supply costs for the interconnected system based on the COOPES-approved 1983 power expansion plan which covered the period 1983-93: and (iii) a 1986 survey of incremental supply costs down to the LV level for all utilities undertaken by ISAl for the period 1986-93 after accounting for the reduced investment program and Guavio cost and time overruns. 2. There are two additional sources of Information on marginal costs, but at the interconnection level, that can be pieced together. First, in the early 1970s Motor Colombus undertook a study of commercial and operating conditions for the new interconnected system. This study, on the one hand, contained an analysis of historical costs upon which the initial bulk tariffs were based and, on the other hand, also had a simulation of operations for the first few years of the interconnected system. The historical asset valuation analysis is not relevant to a marginal cost approach, but the simulation element provided, though only in a sketchy sense, insight into operating expectations for the Interconnected companies between 1972-1975. The second source of additional information on marginal cost expectations at the generation level 1 'Estructura de Costos Marginales en el Sector Electrico Colom- biano,' November 1979. 2 'atudio Sobre la Unification de las Tarifas de neorgia Electrica," ISA-OPUN, July 1983, 1218. 3 OZstructura de Costos en el Sector Electrico Colombiano,' 27/06/86, ISA-OPUN-86R. 4 Principios Comerciales y operacionales para el Sistema Central Interconectado,* ISA/Motor Colombus, November 1971. - 74 - ANNEX 5D.1 Page 2 of 2 exists from the Chivor tariff studyS of 1976-1977 (essentially a cost study for that plant) and subsequent complementary studies done by ISA to support bulk tariff reforms. 3. However, a substantial element of uncertainty relative to this analysis of marginal costs lies in the absence of information regarding incremental network costs from the interconnection level down to the LV distribution level. As noted above, the first such effort in the 1979 IAISPM study was limited to the EPM system. Such incremental network cost information for other companies only appears In the 1986 ISA survey of marginal costs mentioned earlier. Significant problems arise, however, regarding the validity of the network cost estimates in this 1986 survey, which are discussed further in Annex 5D.2. In essence, what that study concluded conflicts, in the judgment of OED, with common sense arguments. In particular, the study estimated that the high load density markets, such as EPM and NEED, have much higher incremental network costs (more than double at the MV level) than in the low density ICEL market. In addition, at the LV level EPM's incremental network costs were estimated to be virtually three times higher than those of ICELt This is at variance with experienced judgment. Therefore, the approach that has been followed in this evaluation in regard to incremental network costs has been along the following lines. Since the only distribution network for which estimates of incremental costs were made in 1979 for the period 1979-1984 was the EPM network, these data have been taken as a proxy for incremental network costs in all other markets during this period and, indeed, up to 1986. This introduces a systematic underestimation of the incremental supply costs of electricity down to the MV and LV levels, since the EPM market is characterized by its high load density, very limited spatial coverage combined with high level of service coverage, compared to all other power markets in Colombia. The RPM market covers an area 114 that of EEB, and about 22 and 0.62 of that of CORELCA and ICEL, respectively. Indeed, RPM's incremental network costs are likely to be the lowest of all markets and hence, by taking these costs as representative of the rest of the power system, there is little danger that incremental network supply costs down to the MV and LV levels would have been overestimated. 5 "Estudio Tarifario de la Planta Chivor 1,' ISA, 1975. - 75 - ANNEU 5D.2 Page 1 of 2 REFERENCE SUBTRANSMISSION AND DISTRIBUTION INCREMENTAL COSTS 1. In ISA document 27/06186-863 OPUN of June 1986, network costs were estimated by ISA for all of the distribution companies in the Colombian power sector. The methodology used by ISA consisted of estimating average incremental costs defined as the ratio of discounted investment to discounted demand increments, annualized at a 12Z discount rate. 2. The basic data collected by ISA for reaching these estimates consisted of the projected investments of each distribution company, by voltage level, for the 1986-1995 period. 3. The results of the analysis are summarized in the following table. They show (i) the cost contribution between the common interconnection level and the medium voltage delivery level (i.e. 13.2 or 11.4kV) and (ii) the cost contribution of the low voltage network (including MV/LV transformer costs). NV AND LV COSTS (December 1985 Pesos/k-year) SEB EPM CVC CHRC ICEL CORELCA EMCHLI MV 9075 7471 5129 8183 3669 46975 7369 LV 4140 9774 2924 2565 3329 22401 5240 4. Estimates for rural areas in LEEB, EPM, and CHEC yielded the following values: MV AND LV COSTS (December 1985 Pesos/kW-year) REEEB PM CHEC MV 32482 7612 8183 LV 32788 6313 4317 5. ISA's results conflict with common sense argumentss it is not logical that high load density markets, such as SEEB and EPM, have higher costs than ICEL, nor does the very large difference between CORELCA and the rest of the system appear to be justified. ANNE 5D.2 Page 2 of 2 6. A broader perspective can be obtained by breaking down the ICEL and CORELCA groups a ICEL GROUP Antioquia gica Clmaca Huila Marino Santander Tolima MV 4190 6504 5197 5646 3180 2956 2494 LV 594 1484 2068 827 727 1134 1601 CORELCA GROUP Atlantico Bolivar Magdalena Cordoba Sucre Cesar Guailra V 61936 28963 35632 35341 41182 22890 LV 15182 23595 19625 55076 30782 16987 14958 7. All of ICEL's 'electrificadoras' have predominantly rural, low density markets and yet they show widely differing costs both at the MV and LV levels. In the CORELCA group, costs are uniformly high and it is difficult to accept that Atlantico, with the best market of the region (Barranquilla). can have the highest MY-level cost. 8. The conclusions of this survey ares 1. that using these network costs for estimating differences in delivery costs between companies. would not provide a reliable reference; and 2. that the problem lies basically in the methodology itselfi an incremental cost approach requires a reliable investment plan, but this is not possible at the distribution level where plans are essentially of a short-term nature even for the largest companies. A more laborious statistical approach, seeking to relate distribution Infrastructure to demand density or population density, which would require taking samples from different areas in order to approximate marginal costs, would prove most likely to be more fruitful. - 77 - ANNE SD.3 Page 1 of 10 1979 MARGINAL COST ESTIMATES BASED ON THE ISAIEP STUDY Reference Distribution Costs 1. Given the absence of data related to networks below the interconnection level, the objective of this annex is to privde such estimations based upon data available from the 1979 RPM studyl/ and the 1986 ISA study.21 2. The 1979 analysis for EPM shows the following results for different voltage levels: COST BY VOLTAGE LEVEL AT MARKET PRICES (December 1978 Pesos/kW-year) Outside Main Grid Main Grid Col$/kW-Year US$/kW-Year Col$1kW-Year USIkW-Year 115kV 1499 36.6 1499 36.6 13.2kV 1490 36.3 1490 36.3 Low Voltage 232 5.7 3245 79.2 The striking difference between the cost contribution within and outside the main grid (the so-called parrilla of Medellin) is probably overstating the cost due to low demand projections. On the other hand, the low voltage values are much lower than expected if compared to medium voltage costs. In this case, it would seem that a reference cost for medium voltage supplies would be on the order to Col$2990/kW-year whereas low voltage costs should fluctuate between Col$3222 and Col$6245/kW-year. An average between the latter would show approximately Col$4700/kW-year (114.6 US$1kW-year). 3. Deflating these costs using the GDP index shows the following values in current pesos* 11 Estructura de Costos Marginales en el Sector Electrico Colombiano, Medellin, November 1979. 21 Estcuctura de C4stos del Sistema Electrico Colombiano, ISA OPUN 27106186. - 78 - ANNEX 5D.3 Page 2 of 10 MEDIUM AND LOW VOLTAGE COSTS (Current Col$1kV-Year) 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 W0 760 912 1143 1406 1764 2275 2669 3310 4222 5184 6467 7784 9572 11715 14673 LV 1195 1433 1798 2211 2774 3577 4196 5204 6637 8151 10169 12239 14955 18419 23079 4. The ISA study shows a national average with the following values% COST BY VOLTAGE LEVEL AT MARKET PRICES December 1985 December 1985 Pesos1kW-Year US${kW-Year Transmission 8159 47.4 Subtransmission 2695 15.7 M' Distribution 6630 38.5 LV Distribution 9527 55.3 This would indicate reference values of Col$17484 for MV deliveries and Col$27011/kW-year for LV supply. Deflating these costs as in the previous case yields: MEDIUM AND LOW VOLTAGE COSTS (Current Col$/kW-Year) 1972 1973 1974 1975 1976 1977 1976 1979 1980 1981 1982 1983 1984 1985 1986 M 1007 1208 1515 1863 2338 3014 3535 4385 5593 6869 8568 10313 12602 15521 19447 LV 1556 1866 2340 2878 3611 4652 5462 6775 8641 10612 13237 15932 19468 23978 30044 5. Whether these values are reasonable to use as proxies for distribution costs in the earlier years must be tested, for example, against the dollar equivalents. In current dollars, these costs are equivalent to (US$/kW-year): - 79 - ANNEX 5D.3 Page 3 of 10 EPM COSTS (US)kW-Year) 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 NV 35 39 44 45 51 62 68 78 89 95 101 99 94 82 76 LV 55 61 69 71 80 97 107 122 140 150 159 155 148 129 119 ISA COSTS (US$/kW-Year) 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 MV 46 51 58 60 67 82 90 103 118 126 134 131 125 109 100 LV 71 79 90 93 104 127 140 159 183 195 207 202 193 168 155 These costs seem reasonable in the early years of operation. The difference between ISA and EPH costs can be explained by (i) lower demand densities relative to Medellin in the rest of the country and (ii) EPM's efficiency. For these reasons, ISA's values are probably more representative of average nationwide costs than EPH's. However, starting in 1977, ISA's distribution costs in dollars appear to grow unreasonably; this can be explained by the distortion in the exchange rate associated with a surplus in the current balance; the combined effect of high inflation and low devaluation contributes to inflate costs in dollar terms, whereas the relatively high component of foreign goods that goes into distribution development should tend to stabilize this cost. Based upon these considerations, it may be that the EPM data, based as it is on 1978-79 information, is more representative of costs for the 1977-1984 period. Consequently, the values adopted for network costs during the 1971-1986 period weres ACCUMULATED MEDIUM AND LOW VOLTAGE COSTS a (Current Col$1kW-Year) 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 MV 1007 1208 1515 1863 2338 2275 2669 3310 4222 5184 6467 7784 9572 15521 19447 LV 1556 1866 2340 2878 3611 3577 4196 5204 6637 8151 10169 12239 14955 23978 30044 La From interconnection to MV and interconnection to LV. - 80 - ANNEX 5D.3 Page 4 of 10 As a rough approximation to the equivalent kWh costs, utilization factors of 60Z (5256 hourslyear) were assumed, resulting in the following valuess ACCOWLATED MEDIUM AND LOW VOLTAGE COSTS (Current Col$/kVh) 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 MV 0.19 0.23 0.29 0.35 0.44 0.43 0.51 0.63 0.80 0.99 1.23 1.48 1.82 2.95 3.70 LV 0.30 0.36 0.40 0.55 0.69 0.68 0.80 0.99 1.26 1.55 1.93 2.33 2.85 4.56 5.72 Marginal Operating Costs 6. The 1979 ISAIEPH study provides a detailed dispatch with an identification of marginal plants by season and time of day, with the following results$ MARGINAL FUEL COSTS AT MARRET PRICES (December 1978 Col$1kWh) Year/ Mouth 1979 1980 1981 1982 1983 1984 Off- Off- Off- Off- Off- Off- Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Jan 0.84 0.67 1.00 1.00 0.90 0.80 0.84 0.67 0.80 0.60 0.57 0.31 Feb 1.00 1.00 1.00 1.00 1.00 1.00 0.95 0.90 0.88 0.80 0.59 0.36 Mar 1.00 1.00 1.00 1.00 0.90 0.80 0.95 0.90 0.90 0.81 0.71 0.38 Apr 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 0.95 0.90 0.83 0.68 May 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 0.90 0.80 0.64 0.36 Jun 0.84 0.67 1.00 1.00 0.90 0.80 0.90 0.80 0.66 0.60 0.59 0.36 Jul 0.72 0.49 0.84 0.67 0.82 0.67 0.66 0.60 0.77 0.60 0.55 0.29 Aug 0.84 0.67 0.84 0.67 0.62 0.38 0.66 0.60 0.59 0.36 0.55 0.29 Sep 0.84 0.67 0.90 0.80 0.62 0.38 0.90 0.80 0.53 0.36 0.55 0.29 Oct 0.84 0.67 0.90 0.80 0.62 0.38 0.77 0.59 0.51 0.29 0.47 0.29 Nov 0.84 0.67 0.90 0.80 0.82 0.67 0.73 0.59 0.51 0.29 0.47 0.29 Dec 0.72 0.49 0.82 0.67 0.82 0.67 0.69 0.38 0.51 0.29 0.50 0.29 Averagess Jan-Jun 0.95 0.89 1.00 1.00 0.95 0.90 0.94 0.88 0.85 0.75 0.66 0.41 Jul-Dec 0.80 0.61 0.87 0.74 0.72 0.53 0.73 0.59 0.57 0.37 0.52 0.29 - 81 - ANNE 5D.3 Page 5 of 10 The time weighted averages discounted at 122 result in the following values: TINE WEIGHTED AVERAGE FUEL COSTS Peak Off-Peak Average fa Jan-Jun 0.91 0.83 0.86 Jul-Dec 0.72 0.55 0.61 Average 0.82 0.69 0.74 /a 3055 Peak Hours, 5705 Off-Peak Hours. 7. The study provides an estimate of marginal fuel costs at border prices using a global conversion factor. A more realistic approach consists of using the actual border prices used in the December 1978 Generation Expansion Plan: Fuel Market Price Border PrLe Coal Col$7241ton US$20/ton (Col$820/ton) Gas Col$48.4/HBTU US$1.4/kCF (Col$57/MBTU) Fuel-Oil Col$13.441gal US$13/bbl (Col$13/gal) The major difference in fuel prices is is due to gas prices because the marginal plants are mostly gas-fueled. 8. The recalculation of marginal fuel costs using border prices as in the December 1978 planning study shows the following values: NARGINAL FUEL COSTS AT BORDER PRICES (December 1978 $/kWh) Year 1979 1980 1981 1982 1983 1984 Off- Off- Off- Off- Off- Of Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Averagess Jan-Jun 1.08 0.89 1.14 1.14 1.10 1.05 1.09 1.03 1.02 0.89 0.75 0.43 Jul-Dec 0.92 0.70 1.01 0.88 0.83 0.59 0.91 0.66 0.64 0.37 0.56 0.29 - 82 - ANNEX 5D.3 Page 6 of 10 With the following time weighted averagess TIME WEIGHTED AVERAGE FUEL COSTS (Border Prices) Peak Off-Peak Averale /aI Jan-Jun 0.05 0.93 0.97 Jul-Dec 0.84 0.61 0.69 Average 0.95 0.77 0.83 /a 3055 Peak Hours, 5705 Off-Peak Hours. Capacity Costs 9. The study contains a reference cost for gas turbines (200NW) of US$295/kW (December 1978$12095/kW) equivalent to US$338/kW-year (December 1978$1540/kW-year) at border prices and December 1978 price levels. Interconnection Costs 10. The 1979 study does not contain a breakdown of interconnection network costs. However, a later analysis ('Estimacion de las Tarifas Economicas de Energia y Potencia con Base en los Costos de Expansion del Sistema Interconectado," ISA, July 1981) provides the following basic data based upon transmission investments for 1981-1988: Present Value (Jan. 81) of Transmission Investmentes 434484 KUVC Present Value of Projected Demand Increments: 3096H Average Investment Coats 140 UV/kW, equivalent to L181 UV11kW- year (Dec. 78$678/kW-year) 11. Using the data from Annex 1, a breakdown of costs can be summarised as followes SUMMARY OF COMPONENT COSTS (December 1978$) (December 1978 Prices) Market Prices Border Prices Generations Energy Cost 0.74 $IkVh 0.83 $/kWh Generations Capacity Cost 1540 $ikW-year 1540 $/kW-year Interconnection Cost 678 $/kW-year 678 $1kW-year K Network Cost 4700 $/kW-year 4700 $JkW-year - 83 - ANNEX 5D.3 Page 7 of 10 12. The preceding costs should be corrected for losses at the generation and interconnection levels (costs for MV and LV already contain them): Capacity Costs Energy Costs (Dec 1978$/kW-year) (Dec 1978$!kW-year) Market Bqrder Market Border Generation 1540 1540 0.74 0.83 Interconnection 678 678 Interconnection Losses 62 62 0.03 0.03 Subtotal - Interconnection 2280 2280 0.77 0.86 1V Network 2990 /a 2990 /a KV Losses 0.04 0.04 KV Costs 5270 5270 0.81 0.90 MV+LV Network 4700 /a 4700 a MV+LV Lossess 0.09 0.10 LV Costs 6980 6980 f/a Loss Cost included. 13. Finally, as a check, it is interesting to confront marginal costs as calculated above, i.e. through an examination of expected short-run costs, with long-run costs, i.e. those calculated using the incremental cost approach. In this respect, the ISA study has a methodological errors it adds marginal fuel costs to capital incremental costs whereas the latter already contain an implicit *fuel' component related to investments that substitute or limit the operation of thermal plants. The incremental fuel cost, to be added to the incremental investment cost, can be calculated as shown in the following tabless - 84 - AlNNEX 5D.3 Page 8 of 10 Plant Factors Plant K . 1979 1980 198t 1982 1983 1984 B 136.5 0.70 0.70 0.70 0.70 0.60 0.45 C 50.0 0.68 0.70 0.68 0.69 0.61 0.45 D 119.0 0.70 0.70 0.67 0.70 0.57 0.39 E 66.0 0.51 0.64 0.53 0.54 0.40 0.27 F 39.0 0.34 0.34 0.21 0.21 0.13 0.15 8 200.0 0.12 0.40 0.45 0.30 0.20 I 66.0 0.70 0.70 0.61 0.46 J 66.0 0.33 0.69 0.61 0.46 K 330.0 0.56 0.62 0.69 0.69 0.58 0.56 L 132.0 0.56 0.62 0.69 0.60 0.50 0.33 m 74.0 0.30 0.30 0.30 0.59 0.44 0.33 N 222.0 0.20 0.20 0.20 0.34 0.23 0.23 0 132.0 0.61 0.51 p 150.0 0.36 0.59 Q 150.0 0.13 -85- ANNEX 5D.3 Page 9 of 10 Generation Cost (M$) at Market Prices Generation Cost (MS) at Border Prices 1979 1980 1981 1982 1983 1984 Plant 1979 1980 1981 1982 1983 1984 301 301 301 301 258 194 B 301 301 301 301 258 194 146 150 146 148 131 97 C 146 150 146 148 131 97 277 277 265 277 226 154 D 277 277 265 277 226 154 198 248 205 209 155 105 E 236 296 245 250 185 125 116 116 72 72 44 51 F 132 132 82 82 51 58 0 168 561 631 420 280 R 0 200 666 749 499 333 0 0 146 146 127 104 I 0 0 146 146 127 104 0 0 73 152 134 101 J 0 0 73 152 134 101 955 1057 1177 1177 989 502 K 955 1057 1177 1177 989 502 389 430 479 416 347 229 L 460 509 566 493 410 271 156 156 156 306 228 171 M 185 185 185 363 271 203 350 350 350 595 403 403 N 416 416 416 707 479 479 0 0 0 0 254 212 0 0 0 0 0 254 212 0 0 0 0 137 225 P 0 0 0 0 137 225 0 0 0 0 0 50 Q 0 0 0 0 0 50 2888 3254 3930 4430 3854 2877 Total 3109 3524 4268 4845 4151 3107 367 675 500 -576 "977 Increment 416 743 577 -693 -1044 338 -32 -793 -1448 -977 Present 382 -37 -874 -1626 -1044 Value 18853 20688 22507 25569 28107 30628 Gh 18853 20688 22507 25569 28107 30628 Demand 1835 1819 3062 2538 2521 1835 1819 3062 2538 2521 9309 8371 7338 4789 2521 Present 9309 8371 7338 4789 2521 Value 14. The corresponding incremental cost for fuel is, therefore, given by 33819309-$0.036Vh at market prices and 382/9309-$0.041/kVh at border prices. The incremental investment costs found by ISA are the followings Market Border Prices Prices Present Value of Investment (M$) 62095 59162 P. V. of Demand Increments (GVh) 8495 8495 Average Incremental Investment ($/kWh) 7.31 6.96 Annual Cost ($IkMh) 0.89 0.85 Incremental Fuel Cost 0.04 0.04 Total Incremental Cost ($/kVh) 0.93 0.89 - 86 - ANNEX 5D.3 Page 10 of 10 the marginal costs found beforehand can be reduced to an equivalent energy cost assuming a 60% load factor (5256 hourslyear of capacity utilisation)l the corresponding capacity cost becomes 1540/5256$0.291kMh, which, added to the marginal fuel ($0.74/kVh and $0.831kMh), yields costs of $1.03/kWh and $1.121Mh at market and border prices. These values are rcughly of the same order of magnitude as the incremental cost. - 87 - ANNEX 5D.4 Page 1 of 2 1983 AND 1986 ISA STUDIES OF SYSTEM INCREMENTAL COSTS FOR 1984-93 PERIOD 1. In 1983 CONPES approved a new national electricity expansion plan for the period 1983-1993. This plan envisaged the following plants being added to the system. The operation dates shown refer to those in the FEN and Rio Grande SARa, on the one hand, and in the Bogota Distribution II SAR, on the other. SYSTEM XPANSION PLAN OF MAY 1983 (For Plants Entering Service After 1986) Plant Capacity Date of Operation Original Later Estimate Estimate (FEN SAR-1984) (Bogota II SAR-1985) Jaquas (ISA) 170 - 01187 Betania (ICEL) 500 04/87 04/87 Playas (EM) 200 12/87 04/87 Thermoamaga (CORELCA) 150 n.a. 12/89 Guavio (EEB) 1000 10/90 10/90 Rio Grande (EM) 322 04191 04/S1 Caliaa III (CVC) 240 04192 04/93 La Miel I (ICEL) 384 04192 10/93 Urra I & II (CORELCA) 1200 10/92 01/94 2. ISA's estimate of incremental costs for the interconnected system from the generation and interconnection level down to the LV level are given below in end-1983 prices based on the 1983 ISA study of marginal costs over the 1984-94 period. ESTIMATED AVERAGE INCREMENTAL COSTS FOR THE 1983-93 PERIOD USdjkVh (end 1983 prices) Generation and Interconnection 5.17 Trtnsmission 6.00 Sub-Transmission 6.39 Primaky Distribution 6.79 Secondary Distribution 7.63 Sources Bogota Distribution II SAR (Annex 5.6). - 88 - ANNEX 5D.4 Page 2 of 2 STRUCTURE OF COSTS IN THE INTERCONNECTED 03OME SYSTEM /a 3. ISA's estimates of incremental costs for the interconnected system based on investments for the period 1986-941 (December 1986 Prices) Energy Capacity Average L (Ps/kh) (PslkW year) (PslkVh) Generation and Interconnection 6.29 13,926 8.94 Transmission 6.42 20,346 10.29 Subtransmission 6.55 21,650 10.67 Primary Distribution 6.80 25,884 11.73 Secondary Distribution 7.27 31,479 13.26 La Report ISA-OPUN 20111187-1688, 'Estructurs de Costos del Sistema Interconnectado Co abiano - Actualizacion Program de Inversiones Proyecto Guavio).8 b Load factor of 60%. - 89 - ANNEX 5D.5 AVERAGE RETAIL TARIFF DISTORTIONS RELATIVE TO LEC 1978-86 BY COMPANY AND TYPE OF USER (Percent) Comany Residential Commercial Industrial Total 1978 EmB -69 -32 -50 -56 3Pm -75 -31 -51 -64 ENCALI -59 -14 -34 -43 ICEL -58 -31 -48 -52 Average National -63 -28 -43 -52 1983 BEEB -47 71 27 - 8 -66 4 -23 -46 5LI -37 16 1 -17 -51 -1 - 6 -34 Average National -48 25 - 4 -25 1986 EB -64 88 37 -13 EPM -67 3 -26 -47 ENCALI -48 -17 -25 -38 ICEL -65 -24 -27 -50 Average National -61 11 -13 -37 - 90 - ANNEX 5E.1 Page 1 of 4 THE DEVELOPMENT OF BULK TARIFF POLICY 1971-86 1. Initially, ISA's bylaws stipulated that energy would be purchased from power pool companies at their generation cost and would be sold at a price equal to the average cost paid for exports. The former was interpreted as the cost of generation and transmission facilities owned by exporting companies. Accordingly, Motor Columbus designed, in 1970-71, a system of so- called "differential tariffs' for each power pool member. It is exceedingly impottant to note that the tariffs were calculated on the basis of Unidades de Valor (UVs), a factitious monetary unit that would be revalued seasonally, according to fluctuations in the exchange rate, the CPI, and the price of gold on the international market. In other words, the bulk tariff initially was indexed to reflect the real costs to producers in the power sector. When the US went off the gold standard, this factor was eliminated. The methodology used by Motor Columbus consisted of calculating a rate base for each utility according to its historical investments and a certain amount of working capital. Annual costs were then based on (I) depreciation (0Z for land, 2% for civil works, and 42 for equipment), (ii) a rate of return of 92 on the rate base, and (iii) O&H costs. Dividing annual costs by annual firm energy gave costs per kVh. 2. The power pool's initial bulk tariffs for *basic' energy weres Day Tariff (f UV/kWh) Dry Season Vet Season EEEM 0.5707 0.4267 EPM 0.4649 0.3451 CHEC 0.5759 0.5611 These basic tariffs changed according to time of days peak deliveries had a 40Z surcharge and night deliveries had a 602 rebate. The UVIPeso exchange rate showed the following pattern during the initial years of operations DEC MAY DEC MAY DEC MAY MAY HAY 1973 1974 1974 1975 1975 1976 1978 1979 Pesos/UV 26.62 29.61 32.60 36.10 38.40 41.25 96.10 111.00 Pesos/US$ 24.79 26.06 28.60 30.90 32.90 34.70 39.10 42.60 - 91 - ANU 51.1 Page 2 of 4 The latter shows a sigmificant increase in dollar terms of the bulk tariff, due to the slow rate of devaluation in the late 1970's but high rate of local inflation. Mhen CVC started exporting energy, the UY tariff assigned to it had the value shown in the next table, when the Northeast (NE) system was incorporated operationally, its tariff was also calculated as follows* Day Tariff (0 UVIkVh) Dry Season Wet Season CVC 0.8187 0.6342 NE 0.9700 0.9500 The percent differences between the lowest tariff (EPM) and the other companies' prices becames Percent Differences Dry Season Wet Season EEEB 23 24 EPH 0 0 CVC 76 84 CHEC 24 63 Ns 109 175 The effect of these tariffs can be appreciated from the table belows in 1975 CYC exported at an average of $0.24/kWh, whereas 1PM exported at an average of $0.14/k1h. - 92 - A4NEX 5.1 Page 3 of 4 BASIC ENERGY AVERAGE EXPORT TARIFF (Current Col$IkVh) FEEEB PM CVC ICEL fa CORELCA ISA TOTAL 1974 0.13 0.11 - 0.17 0.13 1975 0.15 0.14 0.24 0.21 0.17 1977 0.37 0.39 0.39 0.41 0.40 0.39 1979 0.45 0.51 0.58 0.48 0.66 0.63 1981 1.47 1.13 1.43 0.94 1.07 1.09 1983 2.63 1.64 4.22 1.22 3.24 1.74 1.80 1985 2.28 4.06 2.20 2.70 3.11 2.95 1986 - 1.14 1.74 3.07 2.87 3.53 3.22 a Includes CHEC. 3. The problems created by the bulk tariff system in the initial years of operation became particularly intractable in 1974175. However, the reason was not the price of basic energy but rather the average price for all energy exports of RPM and the *optimizing* energy, in particular. "Optimizingg or "secondary" energy prices then fluctuated around Ps 0.04-0.06 per kWh between 1974-1976. EPH repeatedly protested this price, although it was the item least subject to discussion in the tariff system, given that, in most cases, it simply replaced costly resources by cheap 'run of rivera energy and the price was defined as the average between the two costs. At the time, the argument within EPK revolved around the fact that they were selling energy to other regions at Ps 0.04-0.061k0h, while tariffs to their consumers were on the order of Ps 0.231kWh (residential) to Ps 0.40/kWh (commercial). 4. Tariff reform became imminent with the operation of Chivor I -- the initial tariff agreement explicitly limited its coverage to the pre-Chivor operations period -- the Chivot cost study (March 1977) using the Motor Columbus rate base methodology resulted in values of 0.8544#UV/kWh (dry period) and 0.7783#UVIkWh (wet period). These values were higher than all others, with the exception of NE. In order to eliminate the distortions of the differential tariffs, export prices for all systems (including ISA) were unified, with the exception of NE; a system of gradual monthly increases was instituted in order to reach the level of the Chivor tariff. This transition period lasted from July 1976 until April 1978: - 93 - ANJEX 5E.1 Page 4 of 4 Price Evolution ($1MWh) All System NE July 1976 260.4 391.9 June 1977 380.0 495.0 April 1978 480.0 558.0 5. The Chivor tariff was applied starting in May 1978. It consisted of a binomial tariff with energy ($/MWh) and capacity ($IHw-month) charges. The time-of-day energy price differences were eliminated and the demand charge was applied to peak periods (0900-1200h and 1800-2100h, Monday-Friday, and 1800- 2100h, Saturdays). The adopted values were: Dry Period Energy: 0.477JUVIkVh Wet Period Energy: 0.367#UV/kVh Demand Charget 1. 189 W/k-month This tariff structure was applied through 1980 and it was complemented by energy and demand contracts that were agreed to for periods of two years. 6. CORELCA's integration into the power pool initiated a period of tariff adjustments oriented towards reaching levels in accordance with ISA's expansion costs, including Chivor II, Zipaquira IV, Chinu, and the inter- connection line with CORELCA. This period lasted from May 1981 until September 1982. A substantial amount of discussion surrounding tariff levels centered around the problem of 'thermal' systems (CORLCA, NE) and "hydro, systems, the latter being assimilated to low cost suppliers as opposed to the former. As a consequence, the tariff for CORLCA maintained a special status during 1982-84: CORELCA's tariffs were equal to the bulk tariff applied to its subsidiaries, excluding the regional surcharge (Isobretasa'). This tariff consisted of an energy charge with no demand charge or time of day differences. 7. Beginning in 1986, CORELCA's special treatment was eliminated. Also, a new operations agreement was implemented in which the tariff system was reformed while maintaining the essential distinction between contracted purchases and goptimizing' interchanges. The levels for tariffs continue to be calculated notionally on the basis of ISA's incremental costs. -94- ANNE 5E.2 RATIO OF ISA BULK TARIFF T AVERAGE RETAIL TARIFFS AT THE OVERALL NATIONAL LEVEL BY CONSUMER TYPE National Year Average Residential Comercial Industrial 1974 0.41 0.45 0.28 0.39 1975 0.43 0.49 0.29 0.40 1976 0.48 0.58 0.34 0.45 1977 0.56 0.70 0.39 0.50 1978 0.56 0.71 0.37 0.50 1979 0.53 0.68 0.34 0.47 1980 0.50 0.64 0.33 0.44 1981 0.48 0.62 0.31 0.41 1982 0.52 0.68 0.33 0.43 1983 0.48 0.66 0.29 0.39 1964 0.52 0.76 0.30 0.42 1985 0.52 0.79 0.30 0.40 1986 0.50 0.79 0.29 0.38 RATIO OF ISA BULK TARIFF TO AVERAGE RETAIL TARIFFS IN REGIONAL MARKETS, 1974-198f Year ICEL EEEB EPM EWCALI CYC CORELCA 1974 0.41 0.43 0.50 0.36 0.35 n.a. 1975 0.44 0.46 0.52 0.39 0.36 n.a. 1976 0.51 0.57 0.57 0.42 0.39 n.a. 1977 0.57 0.67 0.70 0.49 0.44 n.a. 1978 0.56 0.61 0.74 0.47 0.46 n.a. 1979 0.53 0.56 0.72 0.44 0.44 U.a. 1980 0.52 0.52 0.70 0.43 0.41 n.a. 1981 0.49 0.50 0.74 0.44 0.40 U.S. 1982 0.52 0.51 0.79 0.47 0.41 U.a. 1983 0.54 0.39 0.66 0.43 0.46 0.45 1984 0.62 0.37 0.68 0.52 0.48 0.53 1985 0.64 0.37 0.63 0.53 0.57 0.53 1986 0.63 0.36 0.60 0.51 0.54 0.52 - 95 - ANNEX 5P.1 Page 1 of 2 INTERNAL RATES OF RETURN 1. In regard to the adequacy of tariff levels from an economic or financial perspective, the Bank's appraisal process relies on the determination of the internal economic rate of return (IERR), which is the discount rate equating the present value of economic benefits and costs associated with the investment. However, since the economic benefits of power projects cannot be estimated directly or easily, what is calculated is not really an IERR in the strict sense, but an adjusted internal financial rate of return (IFRR), this being the discount rate that equalizes the present worth of incremental costs and incremental revenues (as a proxy for benefits) over the project life. It provides a measure of the financial impact of the project on the utility. By adjusting the cost data to reflect costs to the economy (through shadow prices) and revenues to reflect border prices, what results is an adjusted internal economic rate of return (IERR). Since the revenues are used as a minimm proxy for benefits, the IERR estimate primarily is a test of price levels (not structures); in fact, it asimply shows the relationship between the price and cost of incremental output.011 Indeed, if the load forecasts have been estimated using LRMC as the relevant price, there are no indivisibilities and the expansion plan is least- cost, then the IERR should be greater than or equal to the estimated opportunity cost of capital (assuming this was the discount rate underlying the least cost plan) if the tariff rate is set equal to LRMC. 2. The use of the IFRR or the IERR is subject to the following pitfalls: (i) As presented in the SARs, it is not clear whether these benchmarks are measures of project desirability or measures of tariff adequacy. (ii) Insofar as a project should be part of the least cost expansion program it should be at least marginally justified, i.e. the benefits measured by the marginal costs it avoids should compensate for its investment and operating costs. This is particularly true for generation projects where a least cost expansion program can be formulated; the concept is more difficult to apply to distribution projects where least cost programs are not formulated explicitly or where the project is imbedded within a group of other investments for which individual benefits cannot be isolated. (III) Central to the question of economic appraisal is the concept of avoidable costs. In those cases in which an expansion program involves unavoidable costs, such as those associated with ongoing projects, the IER is not an adequate benchmark for project desirability and, rather, becomes a 11 World Bank, Public Utilities Department, Public Utilities Report No. GASIO, September 1974, *Economic Evaluation of Public Utility Proj- ects,* p. 3, para. x. - 96 - ANNEX 5F.1 Page 2 of 2 test of tariff adequacy to cover program financial costs. This arose, In particular, in the cases of the time slice investments supported in the ll= (1984) and Power Sector Adjustment (1987) operations. fiv) Calculating these indices for long-lived projects, such as those in the power sector, poses the problem of benefit evaluation far into the future. Given that operations simulations are not feasible (nor realistic) for such time spans, the usual assumption used consists of perpetuating project benefits corresponding to the terminal year of the analysis (i.e. year no. 5 or 6). Depending on specific conditions of the terminal year, this assumption may be unrealistic and care must be taken in order not to under- or over-estimate benefits. - 97 - ANK 5F.2 Page 1 of 2 EX-ANTE INTERNAL RATE OF RETURN FOR CONSOLIDATED POVER SECTOR AT GUAVI 0 PRAISAL (1980) . . Based on Sector Investments from 1980-88 1 2m1 12m2 1281 128 2 129 121 1211 1212 A Annual Incremental Sales (TMh) - 1.8 1.9 2.8 2.1 3.1 2.3 3.0 3.1 3.5 Cumulative Incremental Sales (TMh) - 1.8 3.7 6.5 8.6 11.7 14.0 17.0 20.1 23.6 Annual Incremental Cash operating Costs - 1.8 2.2 1.0 1.5 2.3 2.2 0.7 3.0 3.1 (Constant 1980 Ps 10') Cumulative Incremental Cash Operating Costs - 1.8 4.0 4.9 6.5 8.7 10.9 11.6 14.6 17.8 (Constant 1980 Ps 10') Sector Investment Cost (Current Ps 10') 31.2 67.7 84.1 103.8 98.3 134.2 149.9 216.5 211.4 * Sector Investment Cost (Constant 1980 Ps 10') 31.2 54.2 54.6 55.0 43.0 49.0 48.0 60.0 50.0 - Total Costs-Investment and Cumulative Incremental Operating Costs 31.2 56.0 58.6 59.9 49.5 57.7 58.9 71.6 64.6 17.8 (Constant 1980 Ps x 10') Revenues (Incremental) x 10' Based on Appraisal Report (Constant 1980 Ps) & (Annex 5.10-Attachment 4) - 6.3 14.1 22.2 30.7 40.6 51.5 59.5 67.9 74.8 La Data from Guavio SAR. The data in this SAR for 1989 and 1990 exclude operating expenses and revenues for the CORELCA Electrificadoras (Annex 5.10, Attachments 1 and 4). This has been corrected for in this table. For this reason, the returns have only been based on sector investments between 1980-88. A In the case of sales, operating expenses and revenues for 1989 this includes the extrapolation of these quantities for the CORELCA Electrificadoras. - 98 - Page 2 of 2 121$ 1211 121 1211 19m! 1211 12l11 1121 1912 /a Neft Benef It a 109 ,Costant 1980Ps1 Vage - 31.2 -49,7 -44.5 -37.7 -18.8 -17.1 - 7.4 -12.1 3.3 57.0 Cage 1: IFRR - 12.8% Za Extrapolation. -99- ANNEX 5F.3 Page 1 of 2 EX-ANTE INTERNAL RATE OF RETURN FOR CONSOLIDATED POWER SECTOR INVESTMENT PROGRAM 1983-1987 IN THE F.E.N. OPERATION (1983) /a ItemlYear 1983 1984 1985 1986 1987 1988 b Annual Incremental Sales (TWh) - 1.67 1.72 1.79 1.98 2.10 Cumulative Incremental Sales (TWh) - 1.67 3.39 5.18 7.16 9.26 Cash Operating Costs 32.27 32.91 33.77 35.86 38.73 41.83 (Constant 1983 Ps x 109) Annual Incremental Cash Operating Cost - 0.64 0.86 2.09 2.87 3.10 (Constant 1983 Ps x 109) Cumulative Incremental Cash Operating Cost - 0.64 1.50 3.59 6.46 9.56 (Constant 1983 Ps x 109) Sector Investment Cost 117.1 117.90 96.00 90.95 81.00 - (Constant 1983 Ps x 109) Total Costs (Investment + Cumulative Incremental Cash O&M Cost) 117.1 118.50 97.50 94.50 87.45 9.56 (Constant 1983 Ps x 109) Incremental Revenues % 109 (Constant 1983 Ps) 1. Case 1 - Based on Tariffs in SAR, Annex 5.36 - 9.4 18.4 26.4 35.0 47.8 2. Case 2 - Based on Tariff of Pa 7.0/kWh - 11.70 23.70 36.30 50.10 64.80 (Constant 1983 Ps) /a Data from F.E.N. (SAR). lb Extrapolation. -100- Page 2 of 2 (Constant 1983 Ps x 109) 1. Cage 1 -117.10 -109.10 -79.10 -68.10 -52.45 38.20 2. Cang 2 -117.1 -106.80 -73.80 -58.20 -37.35 55.24 Case1- IFRR - 6.5% QUe82 - IFRR - 10.31 -101'- ANNEX 51.4 Page 1 of 2 AVERAGE INC: AGENERATION COSTS FOR SECTOR INVESTMENT PROGRM 1983-87 SET OUT IN THE R EUSAR (1983) /a 1983 1984 1985 1986 1987 1986 (est.) Generation Investment (Current CPS) ISA PC 9.3 10.8 4.7 5.7 14.6 IEB PC 5.4 11.2 11.2 19.6 10.2 SPM PC 3.2 4.8 7.7 7.9 5.5 CVC PC 3.4 4.0 3.2 7.3 6.8 CORELCA C 4.1 5.6 12.8 14.9 29.0 ICEL PC 8.6 15.3 9.2 2.9 1.6 Total PC 34.0 51.7 48.8 58.3 67.6 PC 1983 MUS$ 463 572 444 447 436 ISA LC 7.9 14.0 9.1 6.7 14.9 BSEB LC 12.1 9.3 13.1 11.2 7.0 REM LC 5.6 8.1 6.7 7 - 4.2 CVC LC 4.1 4.8 2.2 5.. 5.5 CORELCA LC 3.7 3.6 12.2 9.8 15.6 ICEL LC 10.1 8.2 5.1 4.4 2.8 total LC 43.7 48.2 48.4 45.0 50.0 LC 1983 MUSS 596 588 450 354 334 Total 1983 MUS$ 1057 1109 894 801 770 NPV (1983, 11%) 3675 Req. TWh 23.1 24.7 26.7 28.6 30.8 33.3 Incremente (1982-21.3 Th) Annual 1.8 1.6 2.0 1.9 2.2 2.5 NPV (1983, 112) - 9 TUh Cumulative 1.8 3.4 5.4 7.3 9.5 12.0 NPV (1983-2023, 11%)*91 TWh Avs. Cost - 4.3SSkVh with IDC - 5.3US0kh Fuel Costs Current GPs 6658 5579 4655 5695 7698 1983 MUS 91 62 43 45 51 60 Increments (1982-80 MMS) Annual 11 -28 -19 2 6 9 PW (1983, 11%) -20 Avg. Cost * -0.22 USkWh a Data from P8N SAR. This indicates that in 1983 prices the incremental generation cost was some USt4.1/kVh or 'US5.1/kVh if interest during construction (IDC) was taken into account. An average incremental cost based on an expansion plan Tields the average value per ,kV related to the investments in the program. It should be expected, therefore, that in an optimal expansion plan this average value should be near the cost of the individual power plants forming part of the plan. In - 102 - ANNEX S.4 Vage 2 of 2 this case, the FUN SAR mentions costs of about US$670/kW for Mesitas and Guadalupe IV and US$800IkW for Guavio. This translates the average investment cost for Quavio into an energy value of around only USjl.8jkVh (assuming 112 discount rate and 5,000 hours annual use). Yet, the incremental generation cost for the sector investment program was estimated to be as high as US#4.1/kWh, which was about 802 of the estimated generation cost for base-load oil-fired steam plant--the highest cost source of the Colombian system. Notes PC - foreign costs; LC - local costs. - 103 - AER 5P.5 Page 1 of 2 n-ANTZ IFRR OF THE 8888 INVSTHENT PROGRAM FOR 1983-87 SET OUT IN THE FEN SAR 1. The low IFRR obtained In the projections for'the overall sector investment program in the FEN operation is equally low for the individual power companies. A particularly striking case consists of EEB's investment program, as shown in the following tables FEN DATA FOR EEE 1983 1984 1985 1986 1987 1988 (est.) Investment Program - Current GPesos PC 9.6 15.1 17.6 25.3 16.5 LC 16.5 13.9 23.6 21.3 17.2 Constant 1983 MUS$ FC 131 167 159 194 107 LC 224 155 219 188 115 Total 355 322 379 382 221 Cash Operating Costs Current IMPesos 8909 9991 15404 20717 29482 Constant MUS$ 11 111 143 163 197 212 Cumulative Increment -10 22 42 76 91 Revenues GMh Sales 4594 5066 5500 5973 6472 7000 Increment 472 908 1379 1878 2406 Tariff Current $Col 4.79 6.21 7.43 8.77 10.35 Constant UScl 6.50 6.90 6.90 6.90 6.90 6.90 Senefits Constant MUS$ 38 68 95 130 166 Net Cash Flow -355 -280 -338 -308 -167 75 IFRR - 2.7% Guavio Corrections Guavio Investment PC 2.30 9.10 10.80 19.60 10.10 LC 7.90 5.10 8.60 11.20 7.00 Constant NUS$ VC 31 101 98 150 65 LC 107 57 82 88 47 Subtotal 139 158 180 238 112 ISA Share (40Z) 56 63 72 95 45 New Net Cash Flow -300 -217 -266 -213 -122 75 IFRR Subtracting ISA's Share of Guavio Costs - 4.42 IEB without Quavio Investment 216 165 199 123 109 Net Cash Flow -216 -122 -158 -70 -55 75 IPR of BEBB's Investment Proaxam Ignoring Guavio - 8 .92 - 104 - Page 2 of 2 2. As seen from the previous data, BB's IMaR projected for the FEN operation is only 2 . If the Guavio investment is corrected by subtracting ISA's share, the IFRR increases to 4.42. It could be argued, however, that this value I -:oo low given that Guavio's benefits would only materialize in 1989. Rower. , even if the Guavio Investment Is Ianored entirely, the iFRR yields a val A of only 8.9, a clear indication that tariffs were either too low or that the projected Investments were too ambitious. - 105 - 28EK 5F.6 I117 CAS OIEIW, MANNEE AND AMUR«N IVE C2OM OF ~(ZU 0362E 1971-1986 1986 esos/k1h Sol ja ä? YeE ECALI 3Cm EEB /c EEM _mx^ la d (16I sold at Q ol bulk leel bulk le~e) 1971 - - 3.95 (4.87) 1.70 (2.10) 1.10 (1.36) - - - - 1972 4.78 (5.77) 4.00 (4.83) - - - - - - - - 1973 - - 3.73 (4.37) 1.60 (1.87) 0.80 (0.94) 1974 4.33 (4.76) - - - - - - - - - - 1975 - - 3.68 (3.89) 1.99 (2.11) 0.84 (0.89) 1976 4.33 (4.71) 4.04 (4.40) 1.78 (1.93) 0.75 (0.82) 1977 - - - - 1.71 (1.99) - - 1978 4.99 (5.92) 4.80 (5.69) 2.45 (2.90) 1.35 (1.60) 2.22 (2.64) - - 1979 - - 5.13 (6.02) 2.65 (3.11) - - 2.41 (2.83) 0.99 (1.16) 1980 5.50 (6.50) 5.65 (6.69) 2.90 (3.43) 1.25 (1.48) 2.76 (3.27) 1.24 (1.47) 1981 6.82 (8.23) 5.98 (7.22) 3.61 (4.36) 1.36 (1.64) 3.17 (3.82) - - 1982 6.91 (8.64) 6.64 (8.31) 3.86 (4.84) - - 3.11 (3.89) 1.93 (2.41) 1983 6.67 (8.41) 6.89 (8.70) 3.95 (4.98) 1.34 (1.69) 2.48 (3.12) 1.10 (1.39) 1984 5.96 (7.40) 6.76 (8.39) 5.32 (6.61) 1.59 (1.97) 2.93 (3.63) - - 1985 5.72 (6.51) L.85 (7.80) 4.35 (4.96) 1.84 (2.10) 2.61 (2.97) 0.94 (1.07) 1986 6.n5 (6.05) 6.97 (6.97) 4.57 (4.57) 2.28 (2.28) 0.61 (0.61) _a DefatM to 1986 Peso using GP deflator (Aex 5.1) and ~wzonite Deflatm (Anne~ Sl). the resulta with GDP deflator a=nm nters In pen * m; those f=a c~e+ defhator are ~nbrs In parntesese. /b For the =taU oramne, RCALI, ICEL, EEB and E M B sold- are at the etail level. For zetaiting canie that also sUell bk pwr - <, an E befoe 1978, IM ld1 bas been expr as oequiv t l h sod." IFr o p in the case of E if x Uh sold as retail in its et and y sold as bulk, the OequiUvlnt retail U ldl - x + y(1-L) 1~bere L are the loses in the Inter- , unt+, systen don to the kaw voltag distrih*im le~el. e !EE begm the practice In 1983 of capitalizing a part of its trativ costs. For ~xnzpl*, in 1986 a~st 771 of its gmss a ~ninstrative omni m m ~tere capdal Ued and, t=efifre, not reflected in the ernsrny's inenma statm-mt.he efflet %eu d be to iouer the aboe mit cas costs. d IM8's låh sold" refer to bulk 16Wk and so its mit costs are tot ca~Wimrh1 with other ~ . - 106 - ANNEX 57.7 Page 1 of 2 EX-ANTE INTERNAL RATE OF RETURN FOR CONSOLIDATED POWER SECTOR INVESTMENT PROGRAM 1987-1990 POUER SECTOR SECTOR ADJUSTMENT LOAN (1986187) Item/Year 1987 1988 1989 1990 1991 Annual Incremental Sales (TWh) - 1.4 1.5 1.7 1.7 Cumulative Incremental Sales (TWh) - 1.4 2.9 4.6 6.3 Annual Incremental Cash Operating & Maintenance Costs (Constant 1987 US$ millions) Case 1 - Assumption In President's Report - 0.0 0.0 0.0 0.0 Case 2 - 5Z/Year Increase in Cash Operating & Maintenance Costs - 16.5 17.3 18.2 14.1 Cumulative Incremental Cash Operating & Maintenance Costs (Constant 1987 US$ millions) Case 1 - Assumption in President's Report - 0.0 0.0 0.0 0.0 Case 2 - 5Z/Year Increase in Cash Operating & Maintenance Costs - 16.5 33.8 52.0 71.1 Sector Investment Costs 502.0 529.0 508.0 412.0 - (1987 US$ millions) - 107 - ANNEX 5F.7 Page 2 of 2 Item/Year 1987 1988 1989 1990 1991 Cumulative Incremental Revenues (1987 US$ millions) Case 1 - Based on 3%/Year Real Tariff Increase (Annex 6, President's Report) - 57.0 119.1 197.4 276.6 Case 2- Same as Case 1 plus Cash Operating & Maintenance costs Increasing at S/Year in Real Terms - 57.0 119.1 197.4 276.6 Case 3 - Constant 1987 $ Tariff of USc5.5/kih and Cash Operating & Mainte- nance Costs Increase 5 Annually in Real Terms - 77.0 159.5 253.0 346.5 Net Benefit (1987 US$ millions) Case 1 -502.0 -472.0 -388.9 -214.6 276.6 Case 2 -502.0 -488.5 -422.7 -266.6 205.5 Case 3 -502.0 -468.5 -382.3 -211.0 275.4 IFRR - IERR Case 1 - 13.22 Case 2 - 9.31 Case 3 - 13.31 Sources Data from the President's Report, Power Sector Adjustment Loan, 1987. EX-ANTE ESTIMATES OP ADJUSTED INTRNA. RATES OF RETURN FOR THE C~NSOLIDATED POWER SECTR'S INVESTENT PROMRANS SETVEEN 1980-1990 Tariff Levøl Adjusted Internal Adjusted Intørnal Tariff Level Current *k Rate of R*era AEpraisal Refort/Y*ar Rato of Retur# Aeumd AppraslI With Higher Benefits Comment* (S) 1. Coneolidated Poser Setor A* in SAR (Annom 5.10), Average natlonel Inv~etment program Inveta.nt Program tro. 12. Attchmaent 4 - Incoe retai tariff f ,12.8 viablo for proposed 1980-1990 (fInancal) Statement. Average USØS.05/kWh l tarifts ln SM. national reti1 toriff 1980 In current - Gusvo SM (1981 (not est1ated la rising from US98.9/kWh pri"s. To b. vleble, averag. SAR) l 1980 to proleted national retall tariff US4.9/kWh In 1986 In needed to rise by sø0 I constan v 1980 prices by 198 above 1980 reb~l1 1- using cmosite deflator, leve. ote". By 1986, G L.e. 601 inNrea in *ver*gø ational tarlff real tors. 201 above 1980 leve osing composite defl ator. Tariff Level Adjust~d Internal Adjusted Internal Tariff Level Current at Rate of Retrn Amrafai Repfrf/ear ata of Return Assumed Affraieul With HiGher Benef it Coents 2. Conseidated Poer ke*ter As tn SAR (Annex G.M1) - Average natenal To åcheve 10.85 Ivetet Prograe fro. Ine.. Statoment. retalt tariff of 10.8 (financial), the average 1988-1987 (fim~ntal) Average nattonal retat! USn4.6/klh tn (fnantal) natlonal retal tatlff tariff from Ps 3.6k e 1988 ln current (See usmeInts) meuld have had te be et a - .LN. SAR (19841 (no hl etimted 1n (USd4./khV ) In 1988 to prices. .111 lewal of P 7.Oki AR) 1releted Ps 3.9lkWh (eenelC) (US¢.OkhlI), In ceetant (USG.8kW% )n 1987. In 1988 prie, from 1984 1983 Prices. enward*. Té make inves- men program viable, averae natienal reat tariff needd to rice by 90 above 1988 retal l tevet. el 0 M Tariff Leve Adjusted Internal Adjusted Internal Tariff Level Current at Rat of Return Apørasl Retor]/Year Rat* £t Røturn Asumed Appraisal With Higher Benefitt Commente 8. Consolidated Power 18 Seeter Investent (finanil a Ag in President's Averago national 18.8n To achive 18 i R of Program frem Oe«na) Report, Anne 8 - .rIff In 1986 (fInnelet) President's Reprk 1987-1990 An sellted In Inome Støtment was USd4.08/kWh. (en coementn) aslplon ade tbt President's using *vorge national unit OM cons wouid Report (see torrlf/kWh from de«line by f6 annally commente). UMd.95fkWh in 1987 in real terms. prol«etod to UU¢4.47fkWh in 1992 in constant 1987 prices. I - Porer Setor Re-estlmted by To achieve 185 lR With oE asnuption et Adjuntmen Lonn SED to b 9.85 President's Report alt cash costs duelin- (lAR 1987) (noe comamets) assumes cash OM con~ Ing 1.4% annually, ~hen constant in 19978 R becomes 9.85. To beteen 1987-1991. obieve mUR et 18.8% setr unit rvenu would have to be *t UU.6/kWh In 1987 USI from 1988 onwards. Thls Imelies Inerss over the 1986 levef of soes 8MI In real tøris by198 - 111 - ANNX 5G.1 Page 1 of 2 RS8TIMATION OF THE SAN CARLOS I R-ANTS RATE OF RETURN 1. The SAR for the San Carlos I (1978) project calculated the IERR on the basis of the following costs (SAR, Annex 7.2): (i) Cost streams for the San Carlos I generation project and associated transmission (ii) The 1980-84 distribution network investments commensurate with the added generation; and (iii) Operations and maintenance costs related to these works. 2. In terms of benefits, the average 1976 retail tariff in the Central and Atlantic regions was used which was about USc/1.45/kWh (Ps.0.50/kWh). This was then combined with a consumption conversion factor of 0.785 and estimated losses down to the distribution (LV) level of some 122 assumed for determining sales and benefits. Based on these assumptions, an I E of 7.5% was obtained which indicated that the retail tariff level was too low. The SAR argued (SAR, Annez 7, pars. 12) that the consumption conversion factor of 0.785 may not be justified because the consumers' surplus was likely to be high. The SAR, therefore, observed that using a standard conversion factor around 0.92 instead of the consumption conversion factor would enable an IR= of around 112 to be achieved if the retail tariff was increased about 302 in real terms. 3. There is an important limitation with this approach. ISA, the owner of San Carlos 1. is a wholesaler and not a retailer of power. The key issue of focus for an ISA project is the bulk or wholesale tariff at which power should be sold to ISA's shareholders. It is on this basis that the IERR for this project is re-estimated below as a function of the bulk tariff and not the retail tariff. This, therefore, results in the cost streams including solely the investment in San Carlos I generation and allied transmission and the operating and maintenance (O&M) costs for this plant. The distribution investments are not ISA's costs but are those of the retailers of electricity. In terms of benefits, the average 1976 ISA bulk rate of Ps.0.251Mh (USc/0.72/kWh), was used along with a standard conversion factor of 0.92 and transmission losses of some 62 of the San Carlos I generation. The table below sets out the basis on which the IER was determined, using the costs and energy generation data from the SAR. - 112 - ANNER 5G.1 Page 2 of 2 SAN CARLOS I PROJECT Calculation of Rate of Return (US$ Million 1976 Prices) Generation and Trans- mission 0 a M Total Genera- Bulk Year Investment Costs Costs tion Sales Benefits Net Benefits (gh) (gVh) Case A Case I Case A Case B 1977 18.6 - 18.6 - - - - -18.6 -18.6 1978 40.5 - 40.5 - - - - -40.5 -40.5 1979 42.4 - 42.4 - - - - -42.4 -42.4 1980 75.7 - 75.7 - - - - -75.7 -75.7 1981 24.2 0.4 24.6 - - - - -24.6 -24.6 1982 13.2 0.7 13.9 940 884 5.9 13.0 - 8.0 - 0.9 1983 5.7 1.0 6.7 1,500 1,410 9.3 20.8 + 2.6 +14.1 1984 - 1.0 1.0 2,685 2,524 16.7 37.2 +15.7 +36.2 1985 * 1.0 1.0 2,685 2,524 16.7 37.2 +15.7 +36.2 IERR for Case A - 5.72. IRR for Case B - 12.01. Case A corresponds to the average 1976 ISA bulk rate of US#O.72IkVh (1976 prices). Case B corresponds to an ISA bulk rate of US1.60{kVh In 1976 prices. * 113 - ANNEX 50.2 RE-ESTIMATION OF TE SAN CARLOS COMPLEX E-ANTE RATE OF RETURN 1. The SAR for the San Carlos II (1979) project followed a similar procedure as for the San Carlos I project in estimating the IRR in that investment between 1980-86 in distribution network expansion commensurate with the San Carlos generation complex was included in the stream of costs and the tariffs assessed were the average 1978 retail rate for the Central and Atlantic regions. This rate was taken as US02.0/kWh to which a standard conversion factor of 0.92 was applied along with losses down to the distribution level of 152. These assumptions gave an IER of 13.5? for the entire San Carlos complex, i.e. San Carlos I and II, Jaguas, and Calderas. This suggested that that level of retail rate was appropriate in 1978. As noted earlier in Annex 5G.1, since ISA is a wholesaler of power, the key variable to assess is the bulk rate. The IZRR. is re-estimated in the table below on this basis, i.e. without distribution investmentes using the 1978 ISA bulk tariff rate of US#1.33/kVh as a proxy for benefits along with a standard conversion factor of 0.92 and transmission losses of 6%. The IERR recalculated refers not to San Carlos II but to the entire San Carlos complex, which consists of San Carlos I and II, Jaguas, and Calderas, using the costs and energy generation data from Annex 6.1 of the San Carlos II SAR. SAN CARLOS COMPLEX Rate of Return (US$ Million 1978 Prices) Generation and Trans- mission 0 & M Total Genera- Bulk Year Investment Costs Costs tion Sales Benefits Net Benefits (gVh) (gVh) Case A Case B Case A Case B 1978 51.0 - 51.0 * - - - - 51.0 - 51.0 1979 65.7 - 65.7 - - - - - 65.7 - 65.7 1980 100.7 - 100.7 - * - * -100.7 -100.7 1981 119.6 - 119.6 * - - - -119.6 -119.6 1982 86.9 1.0 87.9 1,240 1,166 14.3 17.2 - 73.6 - 70.7 1983 39.2 1.2 41.1 2,095 1,969 24.1 29.0 - 17.0 - 12.1 1984 1.9 2.1 4.0 3,435 3,229 39.5 47.5 + 35.5 + 43.5 1985 - 2.2 2.2 4,755 4,470 54.7 65.8 + 52.5 + 63.6 1986 - 2.2 2.2 5,755 5,410 66.2 79.6 + 64.0 + 77.4 1987 - 2.2 2.2 6,755 6,350 77.7 93.5 + 75.5 + 91.3 IERR for Case A - 11.7%. IERR, for Case B - 13.6?. Case A corresponds to the average 1978 ISA bulk rate of US1.33kWh. Case B corresponds to an ISA bulk rate of US#1.60{kWh in 1978. - 114 - ANNEX 5G.3 Page 1 of 2 ABSENCE OF FUEL SAVINGS CLAIMED IN THE ECONOMIC APPRAISAL OF MESITAS SAR 1. What this annex shows is that the fuel savings assumed as a benefit in the Mesitas SAR did not exist. The esseAtial data are set out in the table below in which the Mesitas project was to be commissioned in 1982. What this table shows is that since the annual incremental gross generation requirement in 1982 for the total interconnected system (line 2) was greater (by about 330 gWh) than the output of Mesitas (line 6), this meant that an additional 330 gMh of thermal generation would have been called for by the system after absorbing Mesitas's 1990 gh of output; hence, there could have been no reduction in thermal generation due to Nesitas. From an economic appraisal standpoint, what was relevant was that for 1982 and 1983, MBE8 could sell to ISA surplus Mesitas generation (as shown in the table below lines 8 and 10). If this was valued at the level of the bulk ISA tariff in 1977 (i.e. USJl.1/kWh in 1977 market prices), in contrast to fuel saving values of some USJ2.16/kWh (mid-1977 market prices) assumed in the SAR (Attachment 6.2), then the IERR for the Mesitas project drops 0.6 percentage points to 9.82, with the EELB retail tariff still projected to a 1981 value of US42.4/kWh (in mid-1977 market prices). - 115 - ANNEX 50.3 Page 2 of 2 ABSENCE OF FUEL SAVINGS CLAIMD IN ECONOMIC APPRAISAL OF MESITAS SAR 1981 1982 1983 1984 1. Total Interconnected System Gross Generation Requirements (Annex 3.2, San Carlos I SAR) 22.85 25.17 27.65 29.34 2. Annual Increment in Total System Gross Generation (TWh) - 2.32 2.48 1.69 S. VEEB Energy Sales (Attachment 6.1, Mesitas SAR) 4.90 5.45 6.07 6.77 4. Annual Increment in REB Sales (TWh) - 0.55 0.62 0.70 5. Cumulative Increment in NEB Sales (TWh) 0.55 1.17 1.87 6. Total Hesitas Generation (TWh) - 1.99 1.99 1.99 7. Mesitas Generation Absorbed in NEB System (assuming 15% losses in ZEEB system) - 0.65 1.38 1.99 8. Surplus Mesitas Generation Available for Bulk Sales to ISA (TUh) - 1.34 0.61 - 9. Additional Cumulative Generation Incremental Required by Total (Interconnectedl System after Absorbing Total Mesitas Oatput (Th) - 0.33 2.81 4.50 10. EUB Bulk Sales to ISA from (TWh) Hesitas (assuming 62 transmission losses) - 1.26 0.57 Notes Fuel savings ex-ante would only have arisen if the increment in 1982 of the total system's gross generation needs was less than the total output of Mesitas, i.e. line 2 in 1982 was less than line 6. - 116 - EK-ANTE ZSTIMATION OF MESITAS PROJECT - GENERATION COMENT AIERR ASSUMING BULK SALES INTO INTERCONNECTED SYSTEM Hag: No fuel savings. Border prices based on standard conversion factor of 0.92 for sales and 0.86 for investments. Metiftas Generation and Transmission Investment 11.5 34.9 57.5 6*0 8.5 9.8 - (mid-1977 US$W) 06 Costs - Generation - - - - - 1.1 1.1 (US$m) Bulk Energy Sales (KIh) - * - - 1868 1868 (assuming 6% losses) BenefitV (US$m) Cass..1 1977 ISA Bulk Price - - - - - 18.9 18.9 (UjS.1/kfh-market) Cae-.. Bulk orice USd1.7/kWh - - * - 29.2 29.2 (mid-1977 market prices) Net Benefits (US$m) CAA 1 -11.5 f34.9 -57.5 -62.0 - 8.0 8.0 17.8 gAs -11.5 -34.9 -57.5 -62.0 - 8.5 18.3 28.1 C8g 1 - - 7.1% CA I ERR - 11.8% - 117 - ANNEX 5G.5 Page 1 of 7 RE-ESTIMATION OF THE SOGOTA DISTRIBUTION I AND 11 EX-ANTE RATES OF RETURN 1. The analysis set out in this annex shows that the determination in the SARs of the Bogota Distribution I and II projects of the IERRS has the following problemst (i) upstream costs, i.e. generation and transmission are not explicitly taken into account In the evaluation of the distribution projects; (11) the IERR estimated for the construction program corresponds to market prices and does not reflect the economic In; and (iii) the fact that the distribution investment program is included within the overall construction program may overstate (Distribution 1) or understate (Distribution II) the economic IRR. Evaluation of Distribution Projects 2. The internal rate of return of a distribution project can be calcu- lated by an evaluation of costs (usually straightforward) and benefits (usually more difficult). Benefit calculations require an assessment of the incremental energy that the project can deliver and the not revenue that it can generate. The latter value can be conceptually defined, in the case of a distribution company, as the difference between gross revenue generated by the incremental energy and the purchase cost of this energy from the bulk genera-tion/transmis- sion company. In the case of a company that simultaneously has generation and distribution roles, the net revenue generated by the project must be calculated as the difference between gross revenue and the upstream costs of transmission and generation. 3. Finally, when a distribution project is really part of a greater distribution program it may not be possible to identify the benefits of incremental energy associated with the project and it is generally better to evaluate the distribution program as a whole. In particular, if the project is an *essential link" in the program, it will yield a very high IERR, as all the program benefits would logically be allocated to the execution of the particular subproject; if such a procedure were taken to its extreme, a separate evaluation of each essential link could lead to the justification of the individual components, whezeas the program as a whole may not be justified. The Bogota Distribution I Project-1979 Appraisal 4. The SAR for this project contains an estimate of the internal rate of return where costs correspond td the total construction program of EEEB and are not limited to the specific project being financed. Upstream costs of generation and transmission are not explicitly taken into account; however, the fact that the overall construction program comprises investments in generation (Mesitas, - 118 - ANNEX 50.5 Page 2 of 7 Sesquile, and Muna dam reinforcements) would tend to partially offset this problem. If this were the case, the procedure used in the SAR would implicitly equate the incremental energy of the project as being associated to Mesitas and the other generation investmentes this assumption is certainly not warranted. The explanation lies partially in the "operation and maintenance, cost associated with the incremental energy: this cost, as stated in the assumptions, is a fraction of EEB's total operations costs, including purchases from ISA, plus generation, transmission, and distribution expenses and, therefore, accounts for another portion of the upstream cost related to the incremental energy of the project. 5. Finally, another question arises: costs included in the IER calculation do not encompass EEB's investments in ISA. If a *global* approach to the IERR estimation is taken, it would seem that these investments should also be included as part of the 'construction program.* The rationale for not including them is that the upstream cost associated with ISA investments has been taken care of through the ISA purchase component of the operations and maintenance cost. Despite the explanations provided for these conceptual questions, the procedure used in the SAR raises too many doubts insofar as the project's IEM& is concerned. 71 particular, the upstream cost component is estimated at market prices and would only yield a correct economic cost if ISA's bulk tariff were based on marginal costs. 6. As an alternative way of estimating the IRR, the OED evaluation team proposes isolating the distribution investments and include as costs the purchase of energy from ISA plus an allowance for variable O&M costs of the project. According to the SAR in question, purchases from ISA show the values set out in the table below. Here the same fraction of Incremental sales attributed to the project in the SAR is attributed to such sales in the re-estimation, with energy losses applied with respect to energy supplied. - 119 - ANNEX 5G.5 Page 3 of 7 ZZEB'S PURCHASES FROM ISA Purchases from ISA 1979 1980 1981 1982 1983 19r4 1985 1986-2010 Current M$Ps. 1306 1654 2396 2928 3680 5196 7382 Deflating Factor 42 52 61 72 84 92 107 Constant 1979 USIM 31 32 39 41 44 56 69 Gah Supply of ISA 1554 2061 2437 1908 1924 2626 3407 Average Cost 1.99 1.55 1.60 2.15 2.29 2.13 2.03 (1979 US#/kWh) Project Incremental Sales (Vh) - 205 615 1210 1780 2425 3201 4012 Project Incremental Requirements (&Vh) - 257 731 1404 2041 2740 3591 4539 Upstream Cost - 4 12 ?0 47 58 73 93 (1979 US$M) 7. A corrected version of the project's IFRR at market prices, along these guidelines, assuming an O&M cost of US$20/kW-year and a 25-year project life (instead of 33 years), yields the following resultss - 120 - ANNEX 5G.5 Page 4 of 7 Project Costs 1979 1980 1981 1982 1983 1984 1985 1986-2008 Local (Current PsSM) 1244 1482 1973 2104 2335 2958 3539 Foreign (Current PsK) 585 1607 2142 1337 2134 3402 2782 Total Constant (1979 US$M) 44 61 69 48 52 66 57 Costs of Upstream Energy (Bulk Tariff- Market Price) - 4 12 30 47 58 73 93 Project O&M Costs - 0.5 1.6 3.1 4.5 6.2 8.1 10.2 Total Costs (1979 US$14) 44 66 83 81 104 130 138 103 Program Revenues (1979 US$N) - 9 26 50 74 102 133 168 Net Benefit -44 -57 -57 -31 -30 -28 -3 65 Internal Rate of Return, IMR - 15.0? 8. The FR, of 152 when the project is teated as distribution investment is to be contrasted with an IFRR of 122 as determined in the SAR when total REEB construction costs are considered. This result is interesting because it shows that, at market prices, a distribution company can make profitable investments. This is unfortunately a reality not generally accepted in Colombia. There is the perception that to be profitable companies must have their own generation. This is only relevant for RPM because of its access to lower cost hydro historically. This margin in BPM's favor is vanishing and should cease by the end of the next decade. The problem, from the point of view of project Justification, is that the analysis should be made at border or marginal prices, i.e. by taking into account the marginal generation cost in the system, which, in the Colombian case, was above the 2US#IkVh level assumed above. For example, the 1979 ISA marginal cost analysis yielded values of 2280 Ps./kW-year plus Pa.0.77/kh, i.e. an average of 1979 USJ3.16/klh. With this reference cost, the values shown above change as follows: - 121 - ANNE 5G.5 Page 5 of 7 1979 1980 1981 1982 1983 1984 1985 1986-2008 Costs of Upstream Energy (Bulk Tariff US#3.16/kVh - 8 23 44 65 87 113 143 Project 08W Cost - 0.5 1.6 3.1 4.5 6.2 8.1 10.2 Total Costs (1979 USIM) 44 70 93 95 121 159 178 153 Program Revenues (1979 US$) (3B retail tariff US44.2/kVh 1979 prices) - 9 26 50 74 102 133 168 Net Benefit -44 -61 -67 -45 -47 -56 -45 15 Internal Rate of Return (1?RR) - 0.22. 9. The IFMR collapses to 0.2Z. The conclusion of an analysis similar to this one at the time of appraisal would have indicated that (i) ISA's rates were too low relative to bulk marginal costs, and (11) that EB's assumed tariff of US#4.18/klh was also too low. As shown here, the suggested approach to distribution project evaluation provides significantly more feedback to project appraisal than the approach used in the SAR. Indeed, based on ISA's rate being set at the LIMC for bulk power, the distribution program of 33B becomes viable with E1 retail tariffs at a mid-1979 level of some US5.0/kWh. At these prices the above IM1 of 0.22 increases to 11.12. In other words, this type of analysis of the Bogota Distribution I loan would have illuminated that 3E3B's retail tariff needed to be around US#5.0/kWh (1979 prices), i.e. about 202 above that recommended in the SAR if upstream costs were fully accounted for at marginal costs. The Bogota Distribution II Proiect-1984 Appraisal 10. In general, the same observations are applicable to this SAR, namelys (i) E3B's total construction program is included in the evaluation, with the major component being generation (Guavio, Zipaquire) rather than the distribution project itself (11) upstream and 0&M costs are taken into account as the incremental cost over a base year; and (iii) the evaluation is meaningful at market prices but an evaluation at marginal costs is missing. 11. This project SAR is dated May 1985, and was based upon findings of November 1984. It is a well documented report with a clear presentation of all assumptions, together with project cost estimates in current pesos, current dollars, and constant dollars. It also contains data on average marginal costs based upon recent ISA analyses. - 122 - ANNEX 50.5 Page 6 of 7 12. The SAR calculated the AIFRR for BEBB's total construction proiect - it obtained a value of 12.12. Although the benefits of the project per _s cannot be isolated, an IFRR can be estimated for BmEB's distribution investment program. The question is how to estimate the upstream costs of the distribution program; fortunately, the marginal cost estimates provide a reference value for energy deliveries at the bulk level of 6US/kVbh in end-1983 prices (Annex 5.6 of SAR), equivalent to 5.77USilkWh at mid-1984 price levels. 13. The Bogota Distribution II project was not only to provide incremental sales but also to reduce energy losses. Loss forecasts in the SAR (which, as discussed earlier, stretch the bounds of credibility--Section 5.4) take this effect into account by adjusting the *Total Energy Requirements., The difference between the increment in total energy requirements and the increment in total incremental energy supply, including 'nominal losses,' represents the lose- reduction benefits of the distribution program. The "nominal loss* was taken as 132 with respect to supply and would cover 'normal' losses involved in transmission and distribution. 14. An evaluation of the merits of EEEB's distribution investment program using the data in the SAR is presented below. Here upstream costs are based on the US#5.77/kVh (mid-1984 prices) reference value for bulk supplies and the total Incremental supply, including nominal losses. Together with incremental O&M costs and the total distribution investments, this yields an ex-ante AIFRR of 7.2Z for the distribution program as a whole. However, when the loss reduction benefits of lower incremental supplies are included the IFRR increases to 171 for the distribution program, as shown in the table below. The reason for this high value is that the loss reduction more than compensates for the incremental sales. For example, as evident from this table, in 1986 there is a sales increment of 376 gJh but the total energy requirement increase is only 344 gVh. This indicates that the loss reduction measures would not only absorb the 'nominal losses' of incremental sales but also generate added benefits by reducing losses associated with *old' or non-incremental sales. Calculated this way, the analysis shows that the benefits from loss reduction are supposed to exceed the benefits from incremental sales. - 123 - ANNEX 5G.5 Page 7 of 7 Bogota Distribution I1 ProJect 1985 1986 1987 1988 1989 1990 1991-2021 Investments (mid-1984 MUS$) Distribution I 30.5 Rural Electrification 22.2 19.0 13.1 13.7 16.2 17.1 Distribution II 10.5 52.5 60.3 65.8 57.4 54.0 Total 63.2 71.5 73.4 79.5 73.6 71.1 Incremental Gh Sales 367 823 1290 1756 2213 2663 Tariff Projections Current Ps/kVh 8.4 11.6 14.2 16.8 19.8 23.4 27.6 Deflator (1984-1.2) 1.4 1.7 2.0 2.4 2.8 3.4 4.0 1984 Ps'h 7.0 8.0 8.4 8.4 8.4 8.4 8.4 1984 US /kWh 7.0 7.9 8.3 8.3 8.3 8.3 8.3 Incremental MGS$ Revenue 29 68 107 145 183 220 Upstream Cost (US5.77/kUh-mid-1984 prices) Incremental Supply (132 losses) GMh 422 946 1483 2019 2545 3062 Incremental Supply Cost (US$1) 24 65 86 111 147 177 O&1 Cost Current MPs 2870 3618 4517 5597 6932 8595 10640 Constant HPs 2392 2510 2657 2787 2929 3070 3224 Constant MUS$ 24 25 26 28 29 30 32 Cumulative Increment OM 1.2 2.6 3.9 5.3 6.8 8.2 Net Cash Flow -63 -68 -63 -62 -50 -42 35 IFRR Without Lose Reduction Component - 7.22 Projected Incremental Supply (Annex 3.2 of SAR) 344 704 1087 1493 1918 2421 Loss Reduction 78 242 396 526 627 641 Loss Savings (MUS$) 5 14 23 30 36 37 Net Cash Flow -63 -63 -49 -40 -20 -6 37 IFRR With Loss Reduction Component - 17Z - 124 - ANNE 50.6 Page 1 of 6 RESTIVATION OF GUADALUPE IV AND PLATAS EX-ANTE RATES OF RETURN Guadalgpe IV SAR (ay 16, 1980) 1. This power plant replaced the obsolete Guadalupe I1 generating station. It is an addition to the Guadalupe-Troneras chain and, therefore, did not require major civil works in the way of dams (it only Involved 6.5 km of tunneling, a surface power station, and surface penstocks). The SAR was based upon findings of November/December 1979. 2. Costs for Guadalupe IV show the following investment schedule according to the SARa 1979 1980 1981 1982 1983 1984 1985 Current HCol LC 15 164 696 837 1069 890 PC 163 787 2285 1569 596 254 Constant December 1978 LC 13 118 424 440 508 155 FC 138 608 1629 1040 370 147 Constant December 1978 must 0.3 6.0 22.9 40.1 29.4 8.3 2 3. With an installed capacity of 210MW and an estimated generation of 1077 GMh/year, representative data for the plant, using a 1OZ discount rate, yields the following valuest In-service Cost (December 1978 MUS$)s 148MUS$ Reference Capacity Costs US$695/kW Reference Energy Costs USJ1.37Ikh These values are evidently low for a hydro station with a plant factor in excess of 60Z. 4. Guadalupe IV is clearly a generation project; if benefits are measured at the interconnection level, the relevant proxy consists of the value of generated energy at ISA's bulk tariff. The SAR shows the following values for the latter variables - 125 - ANNE 50.6 Page 2 of 6 ISA bulk tariff for 1978: Col$0.38/kWh (US01.Ok1h) Projected ISA bulk tariff 1984 1985 1986 Current Col$JkVh 1.66 1.77 2.04 Constant (Dec. 1978) Col$1kWh 0.66 0.61 0.61 Constant USJJkVh 1.67 1.54 1.54 Using the ISA bulk tariffs, the cash flow in constant terms becomes as followss 1979 1980 1981 1982 1963 1984 1985 1986-2034 Costs 0.3 6.0 22.9 40.1 29.4 9.3 2.0 Average 05 1.3 1.3 1.3 Generation (Gh) 460 940 1080 Benefits (1978 ISA Tariff) 4.6 9.4 10.8 New Cash Flow -0.3 -6.0 -22.9 -40.1 -29.4 -6.0 6.1 9.5 Benefits (Forecast Bulk Tariffs) 7.7 14.6 16.6 New Cash Flow -0.3 -6.0 -22.9 -40.1 -29.4 -2.9 11.2 15.3 Benefits (LEMC of 2.63US/k1h) 12.1 24.7 28.4 New Cash Flow -0.3 -6.0 -22.9 -40.1 -29.4 -1.5 21.4 27.1 The resulting IRn using the 1978 tariff is 7.5, whereas with the forecast bulk tariffs (50Z-602 higher) the IRR Increases to 11.62. If a generation LEMC of 2.63USilkWh is taken as the basis for valuating benefits, the IRR becomes 182, thus showing Guadalupe IV's inframarginal character and confirming its economic desirability. S. 1hen SPH's entire development program is taken into account, a reevaluation of the AIFRR yields the following valuess - 126 - ANNEX SG.6 Page 3 of 6 SMN PROGIMX 1979 1980 1981 1982 1983 1904 198 1986 1987-2034 Current MPesos Local 1083 1310 2505 2074 3303 3339 2988 1757 Foreign 264 706 1977 4198 4420 5438 5439 2580 Deflators to December 1978t Local 0.883 0.722 0.609 0.526 0.475 0.398 0.346 0.301 Foreign 0.943 0.848 0.773 0.713 0.663 0.620 0.579 0.541 December 1978 MPeso Local 958 946 1526 1091 159 1329 1034 $29 Foreign 249 599 1528 2003 290 3372 3149 1396 Total 1207 1545 3054 4084 4499 4700 4183 1925 December 1978 MUS$ (41P$IUS$) 29 38 74 100 110 115 102 47 Benefits Own GUh 3386 3674 3992 4338 4713 5119 5561 6040 Increment 288 606 952 1327 1733 2175 2654 Operating Costs-Current M$Col Current 953 1186 1426 1729 2117 2533 3118 3655 ISA -44 306 138 368 -80 -52 4 1440 Net 997 880 1288 1361 2197 2585 3114 2215 Constant 882 635 784 716 1044 1029 1077 667 December 1978 MUS$ 22 15 19 17 25 25 26 16 Increment -6.0 -2.4 -4.1 3.9 3.6 4.8 -5.3 0 Revenues-1979 Tariff 0.82$1kVh (Dec. 1978 $0.73/kVh-US#1.77lkVh) December 1978 MUS$ 5 11 17 23 31 38 47 47 Net Benefit 11 13 21 20 27 34 52 47 Not Cash Flow -29 -27 -61 -79 -90 -88 -68 5 47 IRR - 7.7% 6. This relatively low rate of return assumes that the December 1978 tariff level remains constant. The SAR assumes that there will be a rate increase, and the IFRR yields the following values using the same figures for investment and operating costs as in the previous cases - 127 - ANNEX 50.6 Page 4 of 6 1979 1980 1981 1982 1983 1984 1985 1986 1987-2034 Forecast Tariffs Current $ColIkWh 0.82 1.03 1.41 1.91 2.28 2.30 2.53 2.79 Dec. 1978 $ColikVh 0.73 0.74 0.86 1.00 1.08 0.92 0.88 0.84 0.84 Dec. 1978 US41kVh 1.77 1.81 2.09 2.45 2.64 2.23 2.14 2.05 2.06 Revenues Dec. 1978 MUS$ 5 13 23 35 39 46 54 54 net Benefit 11 15 27 St 35 42 60 48 Net Cash Flow -29 -26 -59 -72 -79 -80 -60 13 48 IRR =-8.5 The R is only 8.52 -- using forecast tariffs does not reach close to the SAR's estimate of the UR of 132, despite the price increases due to the decline in real terms starting 1984. However, if the tariff level of USJ2.64 is maintained throughout the period of analysis after 1983, the AIFRR improves to 11.32. Playas SAR (February 1981) The Playas hydro project SAR was conducted one year after the Guadalupe IV appraisal and was based on findings of September/October 1980. As in the case of Guadalupe, this is mainly a generation project and an economic analysis can be conducted at the project level by assuming that it delivers energy to a common system generation busbar. Playas generation costs were, according to the SARs 1980 1981 1982 1983 1984 1985 1986 December 1979 MLYS$ 0.4 6.5 55.2 53.1 58.8 51.1 5.3 The project generates 200MW and l450MhIyear. In-service investment costs amount to around 300MUS$ and the resulting unit costs are, therefore, US$1500/kW and US#2.28IkVh. These index costs are significantly above the Guadalupe IV project given that Playas involves considerably greater civil works. 7. According to the Playas SAR, the market price for the bulk tariff in 1979 was Col$0.5/kVh, equivalent to 1.2US4/kWh. The forecast bulk tariff for Obasic' energy wass 128 - ANNEZ 50.6 Page 5 of 6 198 1987 1988 Current Col$1kWh 1.79 2.07 2.39 Current Col$JkW-year 6280 7260 8400 Constant December 1979 Col$kWh 0.52 0.52 0.53 Constant Col$/kW-year 1815 1837 1865 Average at 601 load Factors Constant December 1979 Col$/kWh 0.87 0.87 0.88 Constant US#/kWh 2.05 2.05 2.07 8. With bis forecast bulk tariff, Playas cannot yield an IRR in the 10%- 122 range. Indeed, the IMt for the project becomes 1980 1981 1982 1983 1984 1985 1986 1987 1988 Investment Costs 0.4 6.5 55.2 53.1 58.9 51.1 5.3 O4 1.2 1.2 Meh 525 1090 1150 Benefits (HUs$) 10.8 22.4 23.6 Net Cash Flow -0.4 -6.5 -55.2 -53.1 -58.9 -51.1 5.5 21.2 22.4 The resulting IM8 is 8%. In order to obtain an 112 IFRX, the bulk tariff would have to be on the order of 2.6US/kWh. a value very near the estimated LIM at the generation level in 1978. 9. The Playas SAR presents an IERR analysis using EPM's entire investment program and concludes that the rate of return is 15.5%. The retail tariff assumptions underlying the financial projections in the SAR wores PLAYAS PROJECTED TARIFFS 1980 1981 1982 1983 1984 1985 1986 1987-2034 Current PolkWh 2.00 1.39 2.00 2.88 3.81 4.80 5.68 6.43 7.28 Constant December 1979 PslkWh 0.88 0.97 1.12 1.31 1.41 1.47 1.48 1.43 1.39 Constant December 1979 US#JkWh 2.00 2.20 2.60 3.00 3.20 3.30 3.40 3.30 3.20 Constant December 1978 US#fkWh 1.80 2.00 2.30 2.70 2.90 3.00 3.00 2.90 2.80 - 129 - ANNX 50.6 Pae 6 of 6 From this table it becomes apparent that the tariff requirement for EPM's own sales increased from 2.79PskVh In 1986 (Guadalupe SAR) to 5.68Pskwh (Playas SAR) for that same year In current tertss In constant teras, the tariff requirement increased from 2.6US#/kh to around 37SIkVh in evaluations that were less than a year apart. In any case, the Playas appraisal *corrects' for the fact that the Guadalupe IV IR could not yield an acceptable level with the tariff projections it had envisaged. 10. The Playas case illustrates the opposite of the Guadalupe IV projects as a generation plant it is only marginally acceptable using the generation LBM as a reference, but 't is not justified at market prices and the IFRR, taking the whole of SPH's investment program, disguises these facts by lumping it together with other, high-profit, Investments. - 130 - Page 1 of 3 RR-.STIMATION OF THE .GUAVIO EX-ANTE..ATE. O .ETURN 1. In estimating the rate of return of the Guavio project, the SAR based its assessment on EEEB's total investment program between 1980-88, including generation, transmission, and distribution investments. The SAR analysis resulted in an IERR of some 15.0% based on EEEB retail tariffs projected to increase by some 100% in real terms between 1980 and 1987/88. The investment costs included in Annex 6.1 of the Guavio SAR (where the rate of return calculation is set out) are supposed, therefore, to encompass all of EEEB's construction program. However, the OED evaluation team was unable to reconcile the investment data used in Annex 6.1 of the SAR for the IERR estimation with the investment data for KEEB's construction program set out in Annex 4.3 of the SAR. In particular, the total construction cost data in the latter annex appears to be substantially lower than the investment data used in Annex 6.1 for the rate of return calculation. 2. Given that Guavio is a major generation project, what is of special relevance is how did Guavio's ex-ante generation costs compare with the bulk tariff and other system generation costs? This was not assessed in the SAR and is addressed below. Investment Costs 3. The following table summarizes the Guavio and EEEB total investment costs both in current pesos and constant US$ millions of 1980. These data are taken from the SAR (Annex 4.3). I=n am iA 1U m au an 1W M IM QuaLo .yetMnt (Curvent MCo00) Foreign Component 3215 3243 _966 10005 22050 10363 4635 60475 Local Component 176 2197 22A, 4063 5602 7629 4963 1652 28546 Quaio Zavestment (Constant 1980 MUSS) Foreign Component 0.0 54.2 43.9 76.8 89.7 164.1 85.6 25.2 0.0 519 Local Component 3.7 37.2 31.1 46.2 63.6 62.3 35.4 10.4 0.0 280 Total 3.7 91.4 75.0 123.0 143.3 226.A 101.1 35.5 0.0 799 sas Constrnuin rone (current icols) foreign Component 3504 9412 8412 9462 11429 25160 16467 15335 9740 107121 Local Component 2578 5262 7595 9430 21964 12575 21665 29669 28716 139474 EinB Constaction Proaram (Constant 1980 NDS) Foreign Component 74.1 158.7 113.9 104.3 102.5 187.3 104.2 83.3 36.9 965 Local Component S4.5 89.0 104.3 107.2 210.1 102.6 155.4 186.1 158.1 1167 Total 128.5 247.7 218.1 211.4 312.6 289.9 259.3 269.3 195.0 2132 - 131 - ANNMraS-.7 Page 2 of 3 4. As a first approximation to the IFRR, the benefits of the project, independent of ownership, can be assumed to obtain when it adds resources to the bulk supply of the interconnected system. At market prices, those benefits materialize as sales from the project at the bulk tariff. In the SAR, sales to ISA are assumed to take place at a price of 198OUS02.1/kWh. Presumably this tariff applies to firm energy of the project (5350 GWh/year when in full operation, 7500 GWh/year average, according to the SAR); the difference between average and firm generation corresponds to secondary energy that also generates benefits but at a lower rate. Secondary energy benefits were taken at one-half the rate for firm energy. Finally, O&M costs of the project were assumed to be US$6/kW-year. 5. With these aasumptions, the not cash flow associated with the Guavio project becomes: %uav"e Proot Cash W Flow (1980USS) I192 M 1 L L1 129& I=31122312311MAR122 10-2023 Investmet 3.7 91.4 75.0 123.0 143.3 226.4 101.1 35.5 in GVb 3328 6025 5320 5350 Piva Eneay Senefits 70 106 112 112 Secondary Enear Muh 2150 210 secondary Energy Snefits 23 23 Total Benefits 70 106 135 135 08&M 6 6 6 6 Net Cash Plow -3.7 -91 -75 -123 -143 -226 -101 29 100 129 129 The cash flow of the project yields an IFRR of 11.],. Given that secondary energy benefits are usually quite speculative, ignoring them yields a "firm" IFRR of 10.2%. The ex-ante IFRR can, therefore, be said to be within the 10%- 12% range with this approach. 6. This result is somewhat surprisi- coming, as it does, from the present "bete noire" of the Colombian pot ."c sector. Two questions arise in this respect: (i) How did Guavio's ex-ante costs compare with system costs at the generation level and the bulk tariff? and (ii) Were the bulk tariff assumptions realistic? 7. In answer to the first question, Guavio's costs, taken to the commissioning year (1987) at a 12% discount rate, yield a total in-service cost of MUS$1160 (80014US$ in direct costs and 350MUS$ in IDC). It should be noted that IDC appears higher than the value allocated in the SAR (250MUS$) because it comprises the opportunity cost of capital for both foreign and local funds. In any case, the power plant shows a cost of 1980 US$1150/kW and an equivalent cost of 138MUS$/year at a 12% discount rate. This implies a cost of iSdtjLkWh for firm energy and about USd1.8/kWh if average energy is considered. ISA's incremental cost calculations at the time (tariff study of July 1981) showed an average cost of .OTUSIMkh. Therefore, Guavio would have been classified as an inframarginal project with a significantly higher rate of return than the evaluation at projected market prices indicated. - 132 - ANR50. 7 Page 3 of 3 8. In answer to the second question, in 1980 and 1981 the bulk tariff showed an average of Ps.0.76 and Ps.1.09/kWh (US01.61 and US02.06/kWh). Given these base values, an increase in real terms to USg2.1/kWh by 1987 was a reasonable assumption. - 133 - ANNEX 5H.1 Page 1 of 4 EX-ANTE AVERAGE INCREBTAL COSTS OF EXPANSION PROGRAMS OF 8EMl AND EPM FOR THE 1981-88 PERIOD The purpose of this analysis is to assess the ex-ante average incremental expansion costs of the EEE and EPM expansion programs during the 1981-88 period, the objective being to demonstrate the higher ex-ante incremental costs experienced by EEB compared to EPM and, hence, to identify the minimum level by which EEMB tariffs would have been expected to exceed those of EPM in the 1980s when viewed from the perspective of 1981. The costs used for the purpose of calculating average incremental costs were (i) the operations cost, which includes fuel expenses, plant operation expenses, and purchases from ISA, and (ii) the capital cost associated with planned investments in ow plant during the period under study. For obtaining the capital cost during the period, the investment value was calculated at the in service date, thus allowing for interest during construction (IDC), and converted to an equivalent annual cost using a useful plant life of 50 years for hydro projects. The annual cost was then charged as a cost to those years of the period when the asset is supposed to be in operation. Having obtained total annual operations and capital costs, everything is brought to present value and divided by the present value of total incremental energy supplied during the period in order to obtain an average incremental cost. The question that arises is "what about each system's investments in ISA?' Due to the institutional set-up, the shareholders have a dual role of investors and clients via-a-via ISA. Investments in ISA are a cash flow that the utilities undertake in their role of investors. In their role as clients, the actual generation expenses are 'taken care of" by the purchases they make from ISA at the bulk tariff and, for this reason, their capital contributions to ISA's projects have not been taken into account in the incremental cost calculation. In any event, if an attempt were made to include such contribu- tions, it is likely to viden the cost differences between these two systems (EEEB and EPM) even further. BEEEB Incremental Cost (1981-1988) Discounted costs are obtained using a 30Z discount rate, composed of a 192 average Inflation rate, as projected in the SAR, plus real cost of capital of 11. This 302 discount rate coincided with the market rate of interest in Colombia at the time. Energy requirements are discounted at the 11Z rate since it is a grealm good. A summary of the results obtained from the table are (NPV - Net Present Value)s - 134 - ANNEX 58.1 Page 2 of 4 NPV is yearly increments of required energy 1981-88: 3708 gUh NPV of total incremental energy 1981-1988: 13586 gVh NPV of yearly increments in variable generation costs 1981-1988s MPs.4271 NPV of annual capital costs for 1981-1988: HPs.25584 Average ex-ante variable incremental generation costs Ps.1.l5/kVh Average ex-ante capital incremental cost for 1981-1988: Ps.1.88/kWh Total ex-ante incremental costs Ps.3.0/kVh EPM Incremental Cost (1981-1988) In the case of 1PM, data are taken from the Playas SAR. Given that EPM is not always a net buyer of energy from ISA, the variable generation expense was calculated as the difference between its revenues from own sales and the not gross revenues estimated in the SAR. The results are summarised as follows (using the same discount rate, given that the Guavio and Playas SAR assumptions fortunately coincide since they were in the same year). These results were obtained from the table belows NPV in year increments of required energy 1981-1988: 2293 gVh NPV of total incremental energy 1981-1988: 8392 gVh NPV of yearly increments in variable generation costs 1981-1988: MPs. 1984 NPV of annual capital costs for 1981-1988: HPs.11149 Average ex-ante variable incremental generation cost: Ps.0.87/kWh Average ex-ante capital incremental cost for 1981-1988: Pa.1.331kUh Total ex-ante incremental costs Ps.2.2/kVh * 135 - ANNER 58.1 Page 3 of 4 B888 AVERAGE INCREMENTAL COST OF 1981-1988 EXPANSION (Millions of Pesos) 1980 1981 1982 1983 1984 1985 1986 1987 1988 gWh Required 5226 5751, 6364 7021 7708 6502 9422 10275 11267 increment 525 613 657 687 794 920 853 992 Accumlated 525 1138 1785 2482 3276 4196 5045 6041 NPV Increments 3708 Accumlated Increments 13585 Variable Generation Ezpenses (Current MPs.) Costs 514 789 1519 1618 2164 2746 3226 4896 6248 Purchases 1454 2240 1696 3300 4668 6791 10687 7460 10286 Total 1968 3029 3215 4916 6832 9537 13923 12355 16534 Increment 1061 186 1703 1914 2705 4386 -1568 4179 NPV Increments 4271 Total 18312 Investments (Current mPs.) Mesitas 5103 6939 5019 2699 1426 1251 NPV 33999 Annual Cost 10200 10200 10200 10200 10200 10200 Guavio 176 5412 5507 11029 15607 29679 15326 6285 602 Guavio /a 106 3247 3304 6617 9364 17807 9196 3771 NPV 113897 Annual Cost 34169 34169 Annual Capital Cost 10200 10200 10200 10200 44369 44369 NPV 25584 /a Only 60Z of Guavio's investment costs are allocated to BUN since ISA would own the other 402. It should be noted that EPH only participated to a level of 1 in the ISA portion of its ownership in Guavio. Notes Discounted costs were obtained using a 30% discount rate composed to 19X for peso inflation and 112 for the real cost of capital. Energy was discounted at 112 since it is a real good. Sources Guavio Appraisal Report, May 1981. - 136 - ANNEX 58.1 Page 4 of 4 EPH AVERAGE INCREMENTAL COSTS 07 1981-88 EXPANSION Discount Rates 0.30 (Cash) 0.10 (Gb) 1980 1981 1982 1983 1984 1985 1986 1987 1988 GMh Required 4391 4703 5087 5500 5947 6430 6954 7520 8130 Increment 312 384 413 447 483 524 566 610 Accumulated Increment 312 696 1109 1556 2039 2563 3129 3739 NPV Increments 2293 Accumulated Increments 8392 Calculated Generation Expenses (Current M$Col) Costs 170 212 266 322 464 543 742 846 964 Calculated Net ISA Cost Operating Rev. 4092 5426 7966 12050 16522 23952 33288 38276 44467 Own GMh Sales 3566 3908 4260 4600 4990 5412 5869 5365 6903 EM Tariff 1.00 1.39 2.00 2.88 3.81 4.80 5.68 6.43 7.28 Own Rev. 3555 5430 8520 13256 19015 25952 33353 40934 50246 ISA Cost (Profit) ($537) $4 $554 $1206 $2493 $2000 $65 $2658 $5779 Total Gen Costs ($367) $216 $820 $1528 $2957 $2543 $807 $3504 $6743 Increment 583 604 708 1429 -414 -1736 2697 3239 NPV Increments 1984 Total 4620 Investments Guatape II 173 Ayura 44 306 49 River Diversions 273 554 198 Guadalupe 1111 141 91 Guadalupe IV 16 1163 2593 4220 2511 187 Playas 22 494 4314 5060 6733 6894 816 Total 528 2658 7245 9280 9244 7101 816 Net Present Values Guatape II 173 Ayura 521 River Diversions 1380 Guadalupe 11111 274 Guadalupe IV 19661 Playas 60496 Annual Costs: Guatape II 52 52 52 52 52 52 52 52 52 Ayura, Rivers, Guadalupe I/III 653 653 653 653 653 653 653 Guadalupe IV 5898 5898 5898 5898 Playas 18149 18149 Total 52 52 704 704 704 6603 6603 24752 24752 Present Value 11149 - 137 - AMBE= 53.1 POWER TARIFFS DECREE NO. 2545 - OCTOBER 1984 - TARIFFS 1. This decree classified residential users into six stratao with a different fixed basic tariff charged for each astrata.8 These six *strata* were defined geographically according to the construction quality of dwellings t Stratum IsTemporarylad hoc construction (few public services, possibly stolen electricity). Stratum 11sDwellings of durable materiallaultiple families in congestion- public services of water, power and sewerage available. Stratum IlIsPlanned single family tenements with public services. Stratum IVsPlanned single family tenements with public services and telephone. Stratum VsUpper class residences. Stratum VIsLuaury residences. 2. As far as the variable portion of the residential tariff was concerned it consisted of five consumption blocks which were i Block No.Consumption Range (kWh(month) 1 0 - 200 2 201 - 400 3 401 - 800 4 800 - 1,600 5 above 1,600 - 138 - ANNEX 5J.2 RESOLUTION JNT 086 OF 1986 ON TARIFPS 1. Under Resolution JNT 086 Government took control of tariff policy for the power sector by removing the utilities' discretionary faculty to request and apply authorized rates. This resolution set targets based on the structure of the cost of service and social considerations with the tariffs for consumers of all of the power companies expected gradually to reach these targets. The targets were determined in accordance with the following criterias (i) All consumers who are able to cover the cost of service (which includes industrial and commercial users) must pay a rate that is not lower than the long run incremental cost (IC), and not hiher than 252 above LRMC: (ii) Low-income residential users are to be given subsidies based on their ability to pay and the electricity consumption level to meet their basic requirements. That level would depend on the availabil- ity of more economic energy to satisfy such requirements (this would especially be relevant for substituting electrical cooking in low- income households with other energy sources); 2. The residential tariff structure consists of a fixed charge (which depends solely on the user's ability to pay) plus a charge for consumption. The following targets for power tariffs were sets (i) subsistence consumption (up to 100 kWhImonth) when other energy substitutes available and up to 200 kWh/month in other cases) - 202 to 302 of ICI (ii) basic consumption (the difference between 400 kWhlmonth and the subsistence consumption) - 502 to 80 of IC; (iii) intermediate consumption (401 to 800 kWh/month) - 90% to 125% of IC; and (iv) hish consumption (over 801 kVhlmonth) - 1002 to 125% of IC. 3. The fixed charge (Annex 5J.3) is designed to ensure that the subsidy implicit in the lowest consumer blocks goes to lower income households only. The subsistence consumption block was set on the basis of national consump- tion statistics by strata which indicated that Stratum I on average used 170 kWhImonth and Stratum II some 235 kWhImonth. - 139 - ANNEX 5J.3 JUNE 1987 RETAIL TARIFF STRUCTURES AND LEVELS FOR RESIDENCES Variable Price Block (June/87) (Ps/kVh) Monthly Fixed Char&e (PsUser) (kWhImonth) ATL CAL MD EC Stratum ATL CAL MDE EM 0 - 200 3.27 3.00 2.41 2.51 I 36.45 36.45 36.45 36.45 201 - 400 9.35 6.55 4.54 10.76 II 94.98 94.98 94.98 94.98 401 - 800 15.80 8.89 7.88 13.04 III 249.61 249.61 249.61 249.61 801 - 1,600 18.81 '4.67 14.27 14.92 IV 523.53 523.53 513.53 523.53 above 1,600 22.55 19.52 25.38 25.38 V 1,073.54 1,073.54 1,073.54 1,073.54 VI 1,678.81 1,678.81 1,678.81 1,678.81 ATL - Atlantico; CAL - Caldas: MDR - Medellin; and EMC - Cali. The table below highlights the average rer .dential consumption per stratum and the relative distribution of users jetween strata in the four different regions. There are two important differences between regions illustrated in this Table. First, average consumption in Medellin is twice that in Atlantico in the lower strata, and second, the distribution of users is heavily skewed towards the lowest income groups (I and II) except in Medellin and Cali. AVERAGE RESIDENTIAL CONSUMPTION PER STRATUM AND RELATIVE DISTRIBUTION OF ELECTRICITY USERS (1986) Stratum Ihfmanth Stratum Percent Users ATL CAL MDI MC SEEB ATL CAL MDE 1MC I 102 186 266 247 220 1 12.4 70.3 2.5 8.1 II 182 193 358 308 256 11 40.5 4.7 32.6 36.7 111 285 244 426 322 321 III 27.6 15.0 38.8 28.1 IV 384 325 468 364 416 IV 7.8 6.0 15.3 5.9 V 488 456 620 503 574 V 5.4 2.3 8.8 15.7 VI 886 551 972 777 775 VI 6.3 1.7 2.0 5.5 Average 277 216 434 367 Total 100.0 100.0 100.0 100.0 ATL - Atlantico; CAL - Caldas; MDB * Medellin; SM - Cali; and EEB - Bogota. - 140 - ANNE 5J.4 Page 1 of 2 TYPICAL BILLS FOR RESIDENCES (June 1987) Typical bills for each of the four regions and strata in question, based on the average consumption of each group, are set out in the table below. Using the average monthly cost per klh estimated in this table as a benchmark and the average consumption by strata, the difference between the total bill for each group based on the foregoing value and the actual total bill would be a measure of the subsidy receivediprovided by each category. - пгксм. ews �ок аЕ8кавы�8 ки п+в Fout г�каиs � �et!l�р,.г � �' �"_ _ . . � Е�Лk�й • У�г,1аЬ�,о Рвгвlеn 13 Р�.._ _� ' R�8 1L$�_ .L� .�LMS@1� ' Z4��б1 �! lS � � � � � � � � � � � � I а84 <�8 7б8 1.OQ8 8б.46 8D.46 8б.46 ,8б.46 870 b84 б18 1,М4 кt-- 68б Е!0 1,18У 1,бМ б1.8, б4.8л 04.88 84.М б80 б74 1,>ю4 1,76а III 1,44б 888 1,бlб 1,816 448.б1 448.б1 448.б1 44б.б1 1,68б 1,188 1,б44 4,бА4 � к11 4,874 1,418 1,83д 4,467 $43.1Ft- 548.63 6�3.88 �8.8f 4,8У8 1,l44 5,448 Z,780 �,,, �� а.е14 п.�аг а,1п4 а,ее� 1,ате.ы 1,о78.ы 1,о78.ы 1,о78.м 4,абе 8,481 4,18т в,ат1 � п 1о.4в4 а,sвя б,�в 7,sю 1.б7в.а11,е7е.б11,в78.811,б78.е1 1п,14о 4�ю�1 s,б7s 8.448 - г � в�,i 1,8t4 7� 1,6i8 4,488 81б.46 164.17 38б.87 888.71 4,048 !00 4,078 4,780 MoatAly Awrayв Совьlt {Рв/1с1�� 7.41 4.17 4.78 7,68 se�s вsвгs ms в:вs � �ii, 8вид ва awrгa� �ioa sad bвritt ip Адnв� вJ.3. � 8rм и ia Амих W.B. jg This 1s ilив sав et еАв wrld►!в sad tlквд psrCioдв= в�сввр4 4Ав �, вbteA is Ьаовд ел дisбг16ие1е» ef wвn кговв tAs s�ralи. � � , � .. - О 4 � м' � N 142 ANNEX 5J.5 INTRA-RESIDENTIAL SECTOR SUBSIDIES PER USER FOR FIXED AND VARIABLE PORTIONS OF TARIFF The estimated intra-residential sector subsidy per user can be broken down into the part due to fixed charges and that costing from the variable energy charge as shown in the table below. What is evident from this table is, first, that the subsidy benef its to Stratum I stem mainly f ram the f ixed charge. Second, in Strata 11 and III these benefits derive more from the variable charge. and third, Stratum IV provides a subsidy from the fixed charge in all cases but receives a subsidy from the variable charge, except in Medellin and Caldas. INTRA-SECTOR SUBSIDIES PER USER FOR FIXED AND VARIABLE PORTIONS OF TARIFF /a Stratum Fixed Portion Subsidy/User Stratum Variable Portion Subsidy/User ATL CAL MDR EMC ATL CAL MDE EHC 1 280 116 300 363 1 106 66 153 465 11 222 57 242 305 11 437 74 175 271 111 67 -97 87 150 111 347 -24 104 226 IV -207 -371 -187 -124 IV 155 -216 -26 93 V -757 -921 -737 -674 V -615 -658 -497 -584 VI -1,362 -%527 -1,342 -1.279 VI -4,213 -1,106 -2,687 -2,080 L The sum of the fixed and variable portions shown here are equal to the total subsidy given in Table 5.12. ATL - Atlantico; CAL - Ca)das; HDE - Medellin; and IMC - Cali. - 143 - ANNE 3J.6 Page 1 of 2 IMPACT OF RESOLUTION 086 ON RESIDENTIAL TARIFFS 1. Based on the estimated June 1987 value of the low voltage system incremental cost (IC) of P9l4.8/kWh in June 1987 and application of Resolution 086 to the variable part of the tariff structure results in the rates in the table below. Here the tariff level for each consumption block was derived using the following percentages of ICs 252 for 04200 khlmonthl 652 of IC for the next block; 1102 of IC for the next blocks and 1202 of IC for consumption above 800 klhlmonth--this reflects the md-point of the discounts envisaged in Resolution 086. RESIDENTIAL TARIFF VARIABLE CHARGE BASED ON RESOLUTION 086 Consumption Block Tariff (PskWh) (kVhlaonth) ATL CAL MDR EMC 0 - 200 3.72 3.72 3.72 3.72 201 - 400 9.67 9.67 9.67 9.67 401 - 800 16.36 16.36 16.36 16.36 801+ 17.84 17.84 17.84 17.84 If one takes the fixed charge of the residential tariff as unchanged (see Annex 5J.3), the total monthly bill and subsidy per user are -.s set out belows TOTAL MONTHLY BILL FOR RESIDENCES AND ECONOMIC SUBSIDY PER USER (Based on Implementation of JUT Resolution 086 and Low-Voltage Incremental Costs of June 1987 of Ps. 14.87/kVh) /a Stratum PslMbuth Total Bill Economic Subsidy per User ATL CAL MDE 2KC ATL CAL MDE EMC I 416 728 1,419 1,235 1,101 2,038 2,536 2,438 11 772 813 2,367 1,883 1,934 2,057 2,957 2,697 III 1,816 1,419 3,353 2,173 2*422 2,209 2,982 2,615 IV 3,047 2,476 4,314 2,853 2,663 2,357 2,645 2,560 V 5,191 4,668 7,351 5,437 2,066 2,113 1,868 2,043 VI 12,435 6,827 13,969 10,525 740 1,366 485 1,029 Average 2,167 1,135 3,694 3,003 Average /a Assuming the Fixed Charge component of the Tariff is as In Annex 5J.3. - 144 - ANN= 53.6 Page 2 of 2 2. The average price per kUh paid Is then given by Averave Price Paid (p91kMh) Itrat ATL CA. MDE mC I 4.08 3.91 5.34 5.00 II 4.24 4.21 6.61 6.11 III 6.37 5.82 7.87 6.75 IV 7.94 7.62 9.22 7.84 V 10.64 10.24 11.86 10.81 VI 14.04 12.39 14.37 13.55 Average 7.82 5.26 8.51 8.18 ....... - - - 490" 3. It is evident that the discounts on the incremental cost set out in Resolution 086 for consumption below 400 khlmonth are so sizeable that the average prices paid by residences in the four markets in question are still between 113 to 1/2 of the reference incremental cost. - 145 - ANNERSJ. 7 Page 1 of 2 RURAL VERSUS URBAN RESIDENTIAL SUBSIDIS 1. A persistent income distribution problem of Colombian electricity pricing policies has been the disparity between the subsidies received by urbau households and rural ones. The following table illustrates the average residential tariff for selected years and some representative utilities with *strong* markets ( E, VPM, ENCALI, Atlantico) and *weak* ones (Tolima, Huila, Narino, Cordoba, Sucre, Cesar) -- some ICEL and CORELCA electrificadores. AVERAGE RESIDENTIAL TARIFF (Constant 1987 PesoslkVh) Rural Urban Utilities 1972 1975 1980 1983 1987 Central Region ZEEB 4.99 3.99 4.30 6.28 5.94 EM 4.65 3.54 3.27 4.06 5.90 EMCALI 6.28 4.09 6.17 7.43 8.59 Cundinamarca 7.26 4.61 6.48 6.21 5.27 Antioquia 5.19 4.56 5.43- 3.67 5.09 Tolima 7.98 5.09 4.75 6.66 5.86 Huila 6.96 4.77 6.75 6.47 6.94 Narino 5.38 4.37 5.07 5.44 6.76 Costal Region Atlantico 7.28 6.65 7.71 8.85 9.14 Cordoba 11.67 8.03 8.35 7.67 8.07 Sucre 11.52 7.77 8.73 6.65 6.23 Cesar 14.24 9.82 10.70 7.65 8.24 National Average 5.96 4.54 5.35 6.20 6.76 2. In this table some of the differences are especially striking -- in the case of 8888, serving Bogota. as contrasted to the Cundinamarca utility, which serves the surrounding area. A similar contrast appears between ESMl, covering Medellin, and the Antioquia utility servicing the rest of that state. In both cases, up to 1982. urban average residential tariffs were substantially lower than their predominantly rural counterparts. For example, in 1980 these urban tariffs were about 213 of the rural ones in Cundinamarca and Antioquia. Since 1983. however, the situation has tended to reverse itself. The point to be made here is that, despite the real cost differences - 146 - ANNEX5J.7 Page 2 of 2 of supplying urban and rural households, the massive subsidies incorporated into the residential tariffs have been allocated principally to urban dwellers rather than to the more needy rural ones. This situation has begun to improve somewhat since about 1983. In the case of the Atlantic region (CORELCA market) the differences were significant In 1972 (about a factor of two) between the market of the Atlantico electrificadora, which possesses a 'strong' market structure, as distinct from the "weak* structure markets of Cesar and Cordoba. However, by 1986 these differences had declined both within the Atlantic Region and between that region and the Central Region. 3. The ability of the urban utilities to subsidize heavily their residential users has come about from cross-subsidies from their industrial and commercial consumers--the worst case of this being in Bogota. The rural utilities, in contrast, have been unable to do this on the same scale for two reasons. First, their costs are higher and, therefore, they require higher subsidies to achieve the same absolute level of average residential tariffs as their urban counterparts. Second, their structure of market sales is more heavily skewed to residential use and, hence, cross-subsidies from industrial and commercial users would have to be even higher than in urban areas, thereby distorting the cost/price structure of tariffs even more. What is, however, evident Is that since 1983 some Important progress has been made in reducing the degree of inequities between rural and urban residential tariffs and the implementation of Resolution 2545 of 1984 (on residential billing by social strata) has played some role perhaps towards achieving this objective. - 147 - ANNB 5J.8 Page 1 of 2 CONSUMPTION PATTERNS OF MODERN HOUSEHOLD FUELS BY END-USE AND FUEL TYPE 1. In understanding the structure of modern fuel use in residences in the urban areas, the distribution of households by strata among the main cities in 1981 is shown below. DISTRIBUTION OF HOUSEHOLDS BY INCOME STRATA - 1981 (Percent) -t- Strata PoDulation 1 A (Millions) Bogota 2 21 46 20 8 3 4.0 Medellin 3 25 44 23 4 1 1.6 Barranquilla 17 27 31 12 9 4 1.0 The dominance of the stratum 3 (middle-low income) group in Bogota and Medellin is apparent in contrast to that of strata 1 (low-low) and 2 (low income) groups in Barranquilla. The consumption structure by fuel type between cities and among strata is shown below. Of significance is the fact that the gross energy used per dwelling in strata 2 and 4 differ, at the most, by about 2 in any given city, though the incomes of households between these strata are likely to differ by more than 10-20:1. This graphically illustrates the severity of household energy prices on the disposable incomes of strata 1 and 2 households compared to those of strata 4 and above. Even though Barranquilla possesses the most diversified fuel mix, with natural gas and kerosene being used in important amounts by strata 4 and 2 households, respectively, electricity remains the main energy source (around 601) for both strata in this city, which, along with Cali, has been characterized traditionally by the highest residential electricity prices in the country. It is only in Bogota, among stratum 2, that electricity use is reduced to 21% of energy use. This is due to the important role of "cocinol" (68%) for cooking. LPG is also important in all strata in Bogota, increasingly so in strata 4 and above. - 148 - ANNEX 5J.8 Page 2 of 2 1981 AMMUM, MMODER SHERG USB PU =no350 BySI= UltTTPR pa uqMcLL. an _R an._ Neo CAt% . Ao 19! £ IR I latB I I U I M I M a M I Electriviry 3.73 (21) 10.71 (98) 8.73 (87) 11.91 (66) 21.43 (76) 26.39 (100) 13.49 (93) 15.08 (80) WAtu=al GAS * - 9.13 (36) eEsAe - - 0.24 ( 2) 1.03 (10) 5.16 (29) * - - - - - - - M 1.91 (11) - * 0.24 ( 3) 0.87 C 5) 6.75 (24) * * 1.07 ( 7) 0.87 ( 4) =cqLnoV 12..3 _.1 _-- -_-_-=- - - Total 17.94 (100) 10.95 (100) 10.00 (100) 17.94 (100) 28.18 (100) 26.59 (100) 14.36 (100) 25.08 (100) 2. "Cocinol" is the main cooking fuel used by the poor in Bogota in place of kerosene, which is used extensively by low-income groups living at lower altitudes. This is a case where topography affects the choice of household fuels in urban areas in Colombia. wCocinol's" main constituent is gasoline, which burns more effectively than kerosene at the higher elevations and is, therefore, a preferred fuel at such elevations. Of course, altitude also affects the efficiency of cooking devices using thermal fuels; for, example, it can take up to 40X-50% more gross energy to boil water at Bogota's altitude than at sea level. Altitude does not, in contrast, affect the efficiency of electric cookers since these rely on heating by resistance and not oxidation. This altitude penalty for thermal fuel use is compensated somewhat by the lower intensity of use of electrical appliances like refrigerators and air conditioners at the high elevations compared to lower altitudes. 3. The table below shows the breakdown of urban household energy use by end-use rather than by fuel type. What emerges from this table is the dominance of cooking in both low and upper income groups in terms of gross energy use patterns. AMM MMM CWPSUMPM M NUM -Y M N-M ROD M U 2 CA - JL 2RA!UM & A4A ~-- Lrk CCl _ .a __j6 a 1CCL_ _jCal_a _ 299MMa 3.70 82 1.70 62 1.50 58 2.70 59 2.80 39 2.70 40 2.00 55 3.30 52 w aas e.0 20 .13 s - - - - 2.50 3s 2.10 31 0.04 1 0.01 - Allances 0.72 16 0.93 34 1.10 42 1.90 41 1.80 25 1.90 29 1.60 44 3.00 48 Toal 4.50 (100) 2.76 (100) 2.60 (100) 4.60 (100) 7.10 (100) 6.70 (100) 3.60 (100) 6.30 (100) - 149 - AMNEX 5J.9 Page 1 of 2 RELATIVE RETAIL PRICES OF MDDERN HOUSEHOLD FUELS 1971-1986 (1986 Pesoslmillion BTU) Year Electricity Cocinol LPG Kerosene Naturzl Gas Average Residential Bogota Atlantic Rate in Bogota Only Region Only 1971 1.344 N.A. N.A. N.A. N.A. 1975 1,000 285 355 350 220 1977 1,07I 375 520 710 295 1979 - - - - - 1980 1,205 475 1,085 1,470 390 1982 1,600 335 1,105 1,580 345 1984 2,035 225 1,020 1,410 310 1986 1,370 115 760 1,040 205 Assumptions for Cooking Fuel Cost Comparison First, the supply cost of petroleum products down to the retail level has been based on the c.i.f. border price then prevailing, expressed in US dollars, plus the local currency costs (in current US dollar equivalents) of distributing and marketing these products. Given the structure of costs between the retail and c.i.f. levels, the foreign and local currency shares in the final retail cost vary from around 50150, in the case of LPG when marketed in small cylinders, to about 60/40, in the cases of "cocinol* and kerosene -- in other words, broadly similar to the 60140 foreigallocal currency share in the power sector investment cost structure over the past two decades. Second, changes in the relative prices of different cooking devices over the period have not been evaluated due to the absence of data. The result is that only changes in relative fuel prices have been assumed to Impact fuel choice. Of course, this is not correct since reality is more complex and the externalities of front- end costs for cooking devices are important, especially for lower income users; however, these factors have had to be ignored. Third, as far as electric cooking costs are concerned, it has been assumed that at least for 2 hours daily such cooking occurs coincident with the overall system peak, which takes place between 1800 and 1900 hours; the remaining daily cooking time is assumed to occur off- peak. This results in the cost of residential cooking with electricity at the LV level being around 302 above the estimated LRMC of supply to LV users with 602 load factors, as shown in Table 5.6 in the text. ESTIMATED COMPARATIVE COSTS OF COOKING FUEL COSTS, 1975-08 (Current USS/Militon BTU of Useful Energy) &g Cocinol Kerosene Natural as* Residential Electricity A L.P.O. (Bogota OnlV) f (Low Altitude) 1 (Atlantic Coast Only) Ld Cooking Fuel Cost Cooking Fuel Cost Cooking Fel Cost Cooking Fuel Cost Cooking Fuel Cost Vat a ased on Based ot Based on: Based ons Based ont Average Economic Economic Economic Econceic Economic Retll e Supply Supply Retell Supply Roall Supply Retel Supply Price Cost Retall Price Coat Price Cost Price Cost Price Cost Low JA High jo Low /d High Lo Alt. Alt Al Alt. 1008 9.4 ( 0.9) 81.4 9.8 12.8 15.0 20.0 2.4 22.0 17.0 18.7 2.8 n.e. 1984 11.4 (12.8) 80.6 12.0 16.0 81.3 41.7 4.4 45.2 22.0 84.8 8.6 n.e. 1982 12.9 (10.6) 82.1 18.8 18.8 85.0 48.7 0.8 50.4 28.0 88.0 4.5 n.s. 1980 0.5 ( 7.6) 80.7 18.0 17.8 84.5 45.8 9.2 50.4 28.8 88.0 5.0 D.S. 1979 8.0 (0.5) 27.8 11.0 14.7 21.0 27.8 4.4 80.4 14.8 28.0 4.8 n.e. 1977 5.8 ( 4.8) 21.4 4.8 5.7 14.6 19.2 4.0 20.6 8.0 15.7 2.5 n.s. 1976 4.1 ( 8.6) n.e. 2.5 8.8 12.5 10.7 3.8 18.0 8.8 18.7 1.8 n.a. /a Costs are expressed here in terms of current USS per unit of useful energy, 1.e. after accounting for the officiency of the device. ,& Electric cookers are asseumed to be only top-renge (no ovens) with efficiencies of 805. Le Numbers not to parentheses rotor to national average retail price to households, those In parentheses are based on average household retell prices In 8ogote. Id At low altitude the efficiency of the LPO and natural gas stove taken as 401. Lo At high oltibedso (like Bogots) the efficiency of the LPO stove taken s 80. Lf At the Bogote elevation, cooking with **ocInoll is assumed to have on efficiency of 255. 1g At the low atitudes, kerosene stove efficiency Is taken as 80. aC. Iii * ��lF Qa$ �ев т. ао. 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АМ АМ 1.М м �.а М4 RM W/ tW.: lяа.а Ми.ь lь1t.Д и»at ааа nпааим ама ья.а +и:.ь :ья.Я а+.а аьа аля w.a wыь маr жи.ь ам.а ааа м.а a>.w 1а.и wя.а w.s ьм.а аа►.а иьа.а ьиь.ь аиь ил.а w.a in.м тьа.а 1и.и кюа.а тмлs аяа.а лаа.ю m.s а+ц аыь аАа и- ет и».я ам.w аа.а яи.а ья.а иа.» ааьа wa.a aw.a ам.ь ти.и ап.а иlаа иьа.а аьи.п wь1.а и• аЬ рЯ.ь ир.а Ч17.а ья.1: 71М.а ьь.а аМ.а аа.» ая.ь аКЧ аа.р и7а.р aa1.q WaM Ма.Ч аа4а .+• а. lала »1t.M аь.и иа.а ЯЯ.а аа.а яа.П an.a аа.а wa.a иеа.а яа►и яаs.я Мя..а uw.» taw.a и• 1а 21Ч.а 2К).а lul.a яа.М аМ.а аа1.а t1а1.ь 7аа.l1 fац.М аа0.а я1а.а 1Яд.р a0a.tl ta41a ЧМа.М ь1а1.а и�а�Чаввпwмwв w.a др,ь 7q.u 7ал2 а1.а аRЯ 7М.П ьц.а iW.ь ьа.а ьр,и рlИа aaW aat�t ь7ь.а lаЛ.а •' � � �' . r 152 - ANNEX 6A.2 Page I of 15 METHODOLOGICAL ISSUES ARISING IN THE FINANCIAL EVALUATION 1.1 Background 2. Investment decision-makin$ by the Rank's power sector borrowers has been done traditionally on the basis of the *least total economic cost" Investment program. This involves the selection of the generation and transmission investment sequence that minimizes one attribute, the present worth of total investment and operating costs over the lifetimes of these assets (discounted at the opportunity cost of capital). Having found this sequence the issue then become one of putting together a financing plan to implement the investments selected. 2. What is of significance is that decisions on the relative merit of different investment choices is made exclusively on the basis of economic criteria and not the financial criteria typical of corporate financial analysis. This absence of an iterative ' economic and financial assessment of competing investment sequences could result in the selection of least economic cost sequences which are not necessarily of least financial cost. given the terms and type of financing available. indeed, one of the lessons learned in this review (see Section 7.3) Is the Increasing need to view investment decision-making in the power sector in the broader light of multi-objective planning whereby economic, financial, and other attributes can be Incorporated into the analysis of investment choice--thereby reducing the exclusive dependence on economic criteria. 3. Since the selection of power sector investments by the Bank's borrowers traditionally has followed purely economic criteria, the Bank's financial appraisal focusses only on the selected project and a determination of the financial viability and satisfactory financial performance of the agency implementing this project. In this context, the financial appraisal is not aimed at facilitating the investment decision regarding alternative investment choices and, indeed. appears too narrow in its scope. 4. one of the major problems encountered in this financial evaluation was the quality of the unaudited financial data covering the review period, which was of uneven quality and reliability whether the source was individual power companies or the Bank. Such data was, therefore, considered an unreliable basis for the evaluation undertaken in this review. Hence, the data base used in this evaluation was the externally audited accounting data of the individual power companies. Even here, however, uniformity did not exist. For example, in the treatment of the principal payment component of debt service, only in the case of EPX's audited data are the scheduled and actual payments shown, with the actuals invariably exceeding scheduled estimates by ;&de margins in some years. In 1984 and 1985, for example, actuals vere between 602-901 higher than scheduled principal payments for EM. For ZEEB and ISA, only scheduled principal payments are shown in the audited accounts. In order to have some uniform treatment for all companies only the scheduled estimates for principal payments were used in the determination of ex-post seff-financing and debt service coverage ratios. - 153 - ANME 6A.2 Page 2 of 15 The treatment of foreign exchange losses was also not uniform in the audited accounts. For example, In NIRI's and ISA's income statements foreign exchange losses are shown explicit-ly but not in ZPM's Income statement. Additionally. despite high levels of local inflation (averaging about 22% annually in the review period), Colombian law and accounting practice does not allow for the full revaluation of assets and liabilities. What is permitted by local law is a partial revaluation to the extent of revaluing the outstanding foreign liabilities component of the balance sheet at the prevailing end-year pesolUS dollar exchange rate. This has meant that the fixed assets and foreign liabilities shown in the audited balance sheets in Annexes 63.2, 6B.6, and 6B.10 for EE, SPM, and ISA, respectively, reflect the partial revaluation accepted by local practice. Here again, it was only in the case of ZPK's audited accounts that the exchange revaluation of fixed assets was separately shown for assets in service and assets in construction. In what follows, the merits and disadvantages are discussed of the different financial indicators used by the Bank in its appraisals, and in this review, to judge financial performance. 1.2 Return on Assets 5. Traditionally, in assessing financial performance special prominence is given to the rate of return on assets (RDA). There are several variants of the ROA, three of which are discussed. There is the 'Corporate* return on investment (201) which is not used in the Bank's financial assessment of the power sector. This R01 is defined as* Corporate 201 - Operating margin plus depreciation p a not non-operating income divided by average total gross fixed assets.....................(1) Ex-post values of this Indicator were calculated for each of the three companies, 3313, EPM, and ISA and are shown in the respective Annexes for performance indicators (Annexes 63.4, 63.8, and 6B.12). 6. There are two variants of the ROK used by the Bank to evaluate power companies' performance. The first is that defined in the Bank's Operational Manual (Statement 3.72) and termed here, ROI-OHS: ROX-OHS - Operating margin divided by net fixed assets In service ...........................(2 There are four differences between the ROI-OHS and the Corporate R01. The first, and most Important, is that the latter refers to total fixed assets employed whereas the former, solely to fixed assets in operation. This is very significant in the case of small- and medium-sized, rapidly growing, utilities In which fixed assets under construction (which are excluded from ROI-OHS) represent large, lumpy, long gestation investments and often account for over 602-70% of total fixed assets employed. Second, the fixed assets in - 154 - ANNEX 6A.2 Page 3 of 15 the two cases also differ in that one is on a gross basis (Corporate R01) whereas the other is on a net (after depreciation) basis. The third and fourth differences are of lesser significance and relate to the numerators of equations (1) and (2) above. In particular, the Corporate Rl Includes depreciation and non-operating income in its numerator whereas these are excluded from RO-0OMS. Ex-post values of R01-0MS are shown in Annexes 61.4, 61.8, and 61.12 for EEEB, EPM, and ISA, respectively. 7. Relying on only assets in service to determine the asset base for the ROA (as in R01-0MS) is normal in North American and British utility practice. For large, matured utilities experiencing limited growth rates and for which fixed assets in service are likely to represent 85Z-90% or more of total fixed assets employed, the use of the assets in service definition as the rate base is justified. First, because it represents the actual revenue-producing fixed assets. Second, as such, this asset base is well defined since it is in operation, and third, these fixed assets in service represent a very large fraction of total fixed assets employed. However, for less matured, fast growing, and small- to medium-sized utilities, where 60-702 of the fixed assets employed could be under construction and not in service, the use of the asset in service definition as the asset base appears inappro-priate. First, because of the much narrower asset base, very high rates of return are called for in order to achieve satisfactory financial performance. Second, these high returns tend to be resisted by borrowers due to their shear size. Addi-tionally, it also means that the ROO-MS Indicator undergoes dramatic swings, increasing as long as a significant portion of assets are under construction but showing dramatic drops as soon as they are put into service (see Figures 1-3 below). Of course, the degree of escalation and collapse of the RO-OMS intdicator becomes even more stark in the presence of high inflation since after only a few years the value of assets in service, even at the partially revalued levels, can become just a fraction of assets under construction. 8. This is one reason that the Bank, in its power lending operations, uses another variant of the ROA (Revalued R01) to assess utility performance. This indicator is defined ass Revalued ROI - Operating margin divided by fully revalued net fixed assets in service....................(3) In this case, the net fixed assets in service are fully revalued annually at their replacement cost. In principle, the Revalued R01 is equivalent to the ROI-0MS adjusted for inflation. By revaluing fixed assets in service annually at their replacement cost this is equivalent to a policy of investing to main- tain these assets constant in real terms to the degree that there is no demand growth. Of course, with demand growth this real asset base will rise and the revaluation policy can be viewed as equivalent to adding new investments (,plant- in-construction*) onto the fixed assets already in service valued at historical costs. - 155 - ANNEX 6A.2 Page 4 of 15 9. Since Colombian law and accounting practice only allow partial revaluations, this has meant that a full revaluation of fixed assets is done purely on a pro-forma basis for the determination of the Revalued ROI, which is the ROA indicator the Bank uses to covenant power utility earnings perfor-mance. One of the issues that arise in the revaluation is the basis on which it is done. Traditionally, in Colombia the pro-forma full revaluation of fixed assets has been performed on a quarterly basis starting from a base year. In the case of MEEB, this base year was 1976, to which was applied the quarterly Colombian 'blue collar' consumer price index (CPI) as the basis for the revaluation. The use of such an index represented a questionable proxy for the replacement cost of major civil works and equipment about 60% of which were foreign, especially since the post-1976 period up to 1983 was one in which the peso was appreciating in real terms, an effect not captured by the CPI. The result of this was that as of end-1982 EEB's actual fully revalued fixed assets in service, determined through a detailed study (called for under the Mesitas loan), were valued some 40% higher than that arrived at from the quarterly revaluations using the CPI. This meant that, since 1976, ZEEB's key rate of return on assets indicator (Revalued R01) had been increasingly overstated. This experience with EEB illustrates an important lesson about the severe limitations of using the Revalued ROI as the key covenanted earn-ings indicator since it is susceptible to significant errors when the revalua-tion is done on purely a pro forma basis, to meet the Bank's needs, and is not embedded in local legal and accounting practices. 10. The Revalued ROI, by focussing on fully revalued assets in service, is designed to provide, when compared to the average (or better, the marginal) cost of funds used to finance the assets, a measure of the efficiency with which the company uses its operating assets. However, in the framework of power sector lending, the Bank uses a ROA indicator purely to determine the company's capacity to generate sufficient funds to cover its operating and debt service costs, as well as some contribution to its investments. Presum-ably, some relationship exists between the above efficiency and resource mobilization objectives. What is clear is that when the objective is to monitor the efficiency of fixed asset use in operation, then works-in-construction are not included in the fixed asset base. However, when the ROA indicator is used as a measure of resource mobilization capacity it would appear Important that plant-in-construction be included in the fixed asset base since this would signal better the need to generate adequate returns at an earlier stage. This is especially relevant in the power sector, where, for major hydro investments, the construction periods considerably exceed loan grace periods. This results in debt service becoming due long before the asset is in service. The cash generation to achieve this is then less likely to be available if the asset base of the ROA indicator has excluded plant-in-construction, unless very high rates of return are set, which, in turn, lead to the problems noted above (see para. 7) of borrower resistance. 11. Figures 1, 2, and 3 below show the differences in the ex-post behavior of two ROA indicators (ROI-0MS and Corporate 801) for EEB, EPM, and ISA, respectively, during the review period. In the case of Figure 1 for REEB, three points are illustrated. First, there was very close correlation between the FIGURE 1 COLOMBIA POWER SECTOR EEEB: RETURN ON ASSET INDICATORS 120 90 go- Mesitas on-5tream -- 30 .............. 0 - - T ¯ - i i i 1970 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 a Year ........ Rvud ROI ROI.OMS ....... Corporate ROI 1 1 FIGURE 2 COLOMBIA POWER SECTOR EPM:L RETURN ON ASSET INDICATORS, 1970-86 ø ROI-OM8 CORPORATE Rol Gualape I Gitatape iI Guadalupe IV on4tr~a 40 30 20 1970 71 n 73 74 75 78 77 78 79 80 a1 82 83 8 ~s YEAR FIGURE 3 COLOMBIA POWER SECTOR ISA: RETURN ON ASSET INDICATORS, 1977-86 ROI-OMS CORPORATE ROI Chivor I San Carlos I on-stream on-stream 30 1970 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 88 YEAR - 159 - ANNEX 6A.2 Page 8 of 15 Corporate 101 and ROI-OMS until 1975, however, they began to diverge dramatically by 1977. For example, in 1977 the ROX-OMS exceeded the Corporate RO by 35Z compared to less than 92 in the period 1970-75. Part of the reason for this divergence (which reached in excess of GOOZ by 1985) was the Increasingly large "works in progress* that began for IMED around 1977 but is not reflected in the *assets in service* base of the RDI-OHS indicator. There is then the sharp decline in ROZ-OMS (by over 1001) in 1986, as the Mesitas project entered the 'asset in service' category. However, at that time, the Guavio project was still outside the asset base for the ROI-OMS indicator, resulting in it exceeding the Corporate 101 by a factor of 4. The other part of the reason is due to the distorting effects of high local infla-tion (averaging annually 24Z between 1975- 85). The ROI-OMS continued its meteoric rise up to 1985, when it peaked at 12421 Of course, the asset base of this indicator is valued only at the partially revalued levrl of assets in service, which during high domestic inflation still erodes rapidly the asset base. This demonstrates the loss of relevance of the RO-OMS indicator in a high inflation environment, illustrating one of the rationales for the Bank resorting to the Revalued RO indicator. The third point shown in Figure 1 is the far less erratic behavior of either the Corporate ROI or Revalued 101 indicators. 12. Figure 2 shows for EPM the variation of ex-post values of the RoI-OHS and the Corporate ROI between 1970-86. The point clearly illustrated is the close correlation of these two indicators between 1979 and 1980 after the Guatape II project came into the asset base of plant-in-service and there remained little work in progress. This is also graphically demonstrated in Figure 3 for ISA around 1978 after Chivor I was commissioned. Of course, because of the larger asset base, the behavior of the Corporate RO is more stable in the case of all three companies. 13. On the other hand, Figure 4 illustrates for REEB the ex-post behavior of the Corporate RO and the Revalued Ro in the review period. There are three points of relevance. First, the Corporate 101 experienced a steady rise from about 121 in 1974 to around 252 by 1979. This marked a period of little investment for EEED combined with fairly rapidly increasing tariffs. Second, there was a steady decline in this indicator from 1979 to 1986 (apart from the increase in 1983) associated with a very large investment program and poor tariff performance after 1983. By 1986, the Corporate RO for ZEEB had declined to close to its 1974 level, though, unlike then, the massive investment program of Guavio was still underway. Third, in contrast to the significant turn-around of the Corporate ROI after 1979, the trend of the Revalued RO remains upward throughout the period 1975-1986, increasing from some 5.5% in 1974 to about 162 in 1986. Clearly, the Revalued 101 was unable to signal an important change in ZEBB's earnings performance post-1979 and, as such, failed an important test as a dynamic indicator of earnings trends. The Bank uses the Revalued ROI as a yardstick of the sufficiency of resource generation measured with respect to certain self-financing objectives. Because of its limitations in rapidly growing, small- to medium-sized utili-ties, if it is still used in these situations, then this makes it all the more important for a self-financing ratio covenant to be used as a suMlemental tool through which overall financial performance can be monitored (see para. 15 below). This practice was temporarily мвv� � ' со�ом�а�оw�г s�с-сто� � т� со�о�►т� �ыаи� а�а.и� асм � ,• � ,.. : , ,. . ,е ; ; ; : • . ; :е ; . . е • • ,. о• ееееев�е ев ве • е � еее• i • • •е • � � го i i в ' в • е • � � • • • е �е еее • � . е е ' ' .. . еее t • •• • • h+ е r i О • е • •S е е . 1 е: : � , : � � е i i � ее ее • еееееее je : в • •евее• �• 1о � _ Ф 5 � , 19п) i1 72 73 74 75 76 77 78 ТА 8о $1 $2 $З &l &5 8В ' v� Уваt м, �+ . и ....... Coгporste RO1 и...... Revalued RO1 - 161 - ANM ". 2 Page 10 of 15 dropped when the self-fina=lng ratio vas no longer covenanted for SEEB In the Bogota Distribution I loan (1980). but was then re-instated in the Guavio operation (1981). It was a practice never followed, however, In the case of lending to either ISA or ZPM. This is discussed In Chapter 6, Section 6.3. 14. There are three main conclusions arrived at In regard to the use of ROA indicators In the evaluation of financial performance In the Colombian power sector* First, in the case of small- to medium-sized, fast-growing power utilities, the use of a ROA Indicator, such as the Corporate ROI, which includes in its asset base total fixed assets employed, appears to provide a better signal regarding resource generation, especially during the critical period before assets are In service. Second, the Revalued ROX has been characterized by three problems. First, its asset base, though fully revalued, reflects purely assets in service. Second, if full asset rovalua-tion is not part of the country's law and accounting practices then the pro-forms, full revaluation, done purely for the Bank's purposes, is more likely to Include errors which can lead, unknowing- ly, to significant undergeneration, of needed resources. Third, it can fail to signal Important changes In earnings performance, particularly during project implementation. The final conclusion is that the Bank needs to study further the type of ROA indicator it wishes to covenant In its power lending operations. 1.3 Self-rinancag (SF) Ratio 15. In any assessment of the financial performance of a power company it is not only the level and trend of the ROA Indicator (be it the Revalued BOX or the Corporate ROI) that is of relevance, but, above all, a determination of what the ex-ante level and trend of this indicator would enable the company to achieve in term of contributing to its Investment program after meeting its costs of operation and debt service. In other words, how much self-f inancing is achieved for a given ROA. 16. In the course of this review several different definitions of the self- financing ratio were encountered In SAR9, which in some cases contributed to overstating the borrower*# true self-financing capacity. The definition of the self-financing ratio used in the Bank's Operational Manual Statement (ONS) is* 0MS_SF - Cash flows lose principal repayments divided by increase in gross fixed This definition focusses on the net cash flow available, after debt service payments, to meet the investment costs of the company, including any of Its investments in ISA. The OHS also suggests that the Inclusion of vorking capital changes in the Investment base is permissible. However, owe SARs presented a variant of the SF definition, which Inflated ONS-SF by adding the *increase in employee pension fund reserves' (e.g. Guavia, SAR, p. 60) as follows: - 162 - ANNEX 6A.2 Page 11 of 15 OMS-SF (pension fund) - net cash flow gLue increase in pension fund liability reserves divided by increase In gross fixed assets.......(5) While it can be argued as correct from a cash management standpoint, it appears inappropriate to include it as a resource to cover debt service or investments in fixed assets since creditors have no claims on utility employees' pension fund resources. The effect of including *increase in pension fund reserves' in the SF definition considerably enhanced EEB's self-financing performance. For example, in 1980 the company's ex-post OHS-SF was 21% compared with an SF (pension fund) of 322. In this review, unless explicitly stated to the contrary, the OMS-SF definition has been used in estimating ex-ante and ex-post values of this ratio. 17. In the case of ISA, because of the ownership structure of the company and the fact that part of the dividends payable on its shareholders' equity and of the interest due to shareholders on its bonds, have been re-invested in ISA, the self-financing definition can be broadened legitimately to include these dividends and interests re-invested in ISA, since they are derived from ISA's own cash flow. As such, 0MS-SF (ISA) - net cash flow plus re-invested dividends and interest due to shareholders divided by increase in gross fixed assets................(6) However, in one case (the PCR on ISA's 500 IV Interconnection Project, dated June 1988, Footnote 3, p. 31), the self-financing definition was extended further to include ISA's shareholders' capital and bond contributions. This clearly overstates ISA's true self-financing capability since, unlike re-invested dividends and interests on bonds, its shareholders' capital and bond contribu- tions do not flow from ISA's own cash flow. 18. In order to assess the impact of increases in accounts receivable, which represents a foregone cash flow, on self-financing an OS-SF adjusted for such increases is shown in Annexes 63.4, 6B.8, and 6B.12 for EB, EPM, and ISA, respectively: OMS-SF (adjusted) - net cash flow less increase in accounts receivable divided by increase in gross fixed assets...........(7) Also shown in the above Annexes is another self-financing ratio, the so-called Corporate S Corporate SF - cash flow divided by increase in gross fixed assets............................ (8) This measure of self-financing is before principal repayment and does not preclude any priority use of the cash flow, whether for investment or to meet debt service. Other than in the above Annexes, the Corporate SF is not referred to further in this review. - 163 - ANER 6A.2 Page 12 of 15 1.4 Debt and Equity 19. The debtlequity (DIE) ratio is one of the indicators of the capital structure of a company. However, it is not covenanted in Bank power sector operations since the debt service (DS) coverage ratio (see Section 1.5 below) is the preferred form of debt limitation covenant. The lack of major focus in Bank power operations on the DIE ratio appears to arise from the following factors. First, the D/E ratio says nothing about the terms and conditions of the debt and, above all, the impact of such debt on the debt service burden. Second, the DS coverage ratio, in contrast, recognizes that the terms of debt are more significant than the amount in measuring borrowing capacity. Third, power companies enjoy a strategic monopoly position in a closed market over which most LDC governments invariably exercise full control over the prices charged for electricity. As such, their earning capacity is not exposed to the same degree of major fluctuations as, for example, industrial entities operating in a competitive market. Hence, the need for very conservative DIE ratios, to cover earning capacity uncertainties, is not as relevant for power entities in such a monopoly environment as for non-monopolistic industrial companies. Furthermore, in the unlikely event of the power company's earnings experiencing significant shortfalls, there can always be the resort by government to an upward price adjustment, an option unavailable in a competitive market. Finally, most LDC power companies are state owned and not privately owned. 20. The DIE ratio is defined as: D/E - gross long-term debt divided by total net worth........(9) This balance sheet ratio is much affected by the partial and full asset revaluation practices in Colombia and the Bank, respectively. From the standpoint of the financial realities viewed by Colombian utilities through their audited accounts there has been a continuous de.erioration in the DIE ratios of BEl and ISA since the early 1980s and of EPNs in the mid-1980s. Table 1 below shows the ex-post D/E ratios for IEEE, SPM, and ISA based on their audited accounts, as well as from Bank SARs. 21. An important feature of the DIE ratios in Table 1 is the significant difference between the ex-post ratios derived from the audited accounts, on the one hand, and from the Bank's SARa, on the other. These differences arise from the partial and full revaluations undertaken in the audited accounts and Bank SARs, respectively. In all cases, the D/E ratios from the Bank SARs portray a more favorable picture than that seen from the audited accounts. This is because the pro forma full revaluation of fixed assets presented in Bank SARs is offset on the liability side of the balance sheet by the increase in outstanding foreign liabilities according to the prevailing peso exchange rate, as well as an increase in equity considered as a "revaluation reserve.* - 164 - ANNEX 6A.2 Page 13 of 15 Table Is Bx-Post Debt(Equity Ratios, 8EES, RPM. and ISA (1970-86) 1970 1975 1978 1980 1981 13E! 1986 EEB DIE Audited Accounts 1.80 1.60 1.10 1.00 1.60 2.20 4.30 DIE Bank SARe 0.80 0.50 0.70 0.70 1.40 EPm DIE Audited Accounts n.a. 1.60 1.80 1.20 1.10 1.00 2.20 D/E Bank SARs 0.70 0.70 0.34 0.45 n.a. ISA DIE Audited Accounts n.a. 4.00 3.80 2.20 2.00 2.70 5.90 DIE Bank SARs n.a. n.a. 0.70 0.47 0.54 1.60 However, such a *reserve* does not exist since Colombian law only sanctions the partial revaluation of outstanding foreign liabilities. Of course, with the non- existent "revaluation reserve* construed as equity, the DIE ratios shown in Table 1 for Bank 8ARs become very favorable, compared to those ratios from the audited accounts. Indeed, the latter exceed the former ratios by between two to five times. This contributed to erroneous conclusions being drawn abouth the borrowers' indebtedness levels and capital structure. For example, at the time of the FER appraisal In 1983 the claim that the DIE ratios were mcomfortable' (FEN SAR, p. 41) reflected the pro forma revaluation and not the financial reality confronting the power companies as illustrated by these ratios based on the audited accounts. In the case of SEEB and ISA, for example, in 1983 these latter ratios were 2.2 and 2.7, respectively, rising by 1986 to 4.3 and 5.9, respectively. 22. This highlights the need for the Bank to assees, In terms of the interpretations of DIE ratios, the broader ramifications of its, pro forma, full asset revaluation policy in countries where this is not accepted In local law and accounting practices. 1.5 Debt Service (DS) Coverage Ratio 23. As discussed above, this is the ratio covenanted by the Bank to assess borrowing capacity--it is defined as follows in the Bank's Operational Manuals - 165 - ANNEX 6A.2 Page 14 of 15 OMS - DS - Net profit after tax but before interest (including other financial charges) and depreciation divided by principal and interest (including other financial charges) on debt ........................................... (i0) The OMS specifies two possible DS ratio covenants, one based on actual cash flows and the other on forecast cash flows. Of course, in both cases all the covenant seeks to ensure is that the borrower shall not incur additional debt unless the DS ratio exceeds that in the covenant. The former definition is based on the actual net income of the borrower for the 12-month period iame- diately preceeding the date of such debt incurrence, whereas the latter is based on the forecasted net income for the 12-month period immediately follow-ing the date of incurrence. Both types of covenants were used in operations covering the review period. For example, in the Mesitas, Guavio, and Guadalupe IV loans the DS covenant was defined according to actual cash flows, but in the Bogota Distribution II loan the basis was on forecasted cash flows. 24. There were two areas in which variations were introduced to the above definition of the DS ratio. First, in SARe the increase in employee pension fund reserves was added to the numerator in equation (10) above, resulting in an enhancement of the DS ratio. Of course, the same observations made in para. 16 above regarding this practice and the self-financing ratio are relevant here. Second, in the case of EPM operations, the covenanted DS ratio was defined so that to the denominator of equation (10) above was added all amounts payable in the period by EM to ISA for ISA shares and bonds. Since the covenanted DS ratio for EEB operations did not include such an addition, it meant that the covenanted DS ratio for BPM was more conservatively defined than that of EEEB. In order to view all DS ratios for the different borrowers on an equivalent basis, the OMS-DS definition above has been used in estimating ex-ante and ax- post values of this ratio. In all of the Bank operations in the review period the covenanted level of the DS ratio was 1.5, whether conservatively defined as for EPM or the more standard definition in equation (10) as for EEEB. In the Guatape II loan, however, the DS covenant was set at 1.4. 25. Given the poor accounts receivable record (see Section 1.6 below) of ISA and FEE, a DS ratio is also defined which takes into account the impact of increases in accounts receivable in terms of the utility's ability to service its debts because its billed sales are severely reduced by the increase in accounts receivable. This adjusted DS coverage ratio is defined as: OMS - DS (adjusted) - Net profit after tax but before interest (including other financial charges) and depreciation less increase in accounts receivable divided by principal and interest on debt.........(11) - 166 - ANNE 6A.2 Page 15 of 15 1.6 Accounts Receivable 26. The monitoring of accounts receivable (AR) is covenanted through the following definitions Covenanted AR - Outstanding AR related to energy sales divided by annul energy sales revenue.........(12) The definition used in this review is slightly broader by using all operating revenues instead of just revenues from sales of electricity. This definition tends to understate the ratio. Other operating revenues are included since they consist mainly of connection costs billed to customers and are, therefore, also exposed to arrears. This appears to have been the definition used in SARa, although the legal documents solely mention energy sales revenue as the denominator. 27. A useful indicator of the extent cash flows are affected by arrears compares flows instead of the above mix between stocks and flows: Incremental AR ratio - Variation of Accounts Receivable divided by Operating Revenue..........(13) A declining ratio indicates that efforts are successful in limiting the growth rate of arrears to below that of sales. BB�„8-I� 1�1ТФ�11l. 1_ 97�0-8б_ � � I � • ' 1410 1471 1412 1413 191t 19i5 1916 1411 14)0 l979 1980 19В1 1981 1903 � 1401 19BS f9вb I1N�E BTAtElEMi ЕЕЕО • mms,a.wwoпss:e 9a1es Reteanet 319.11 156.31 562.:G9 691.93 161.21 1010.об 141i.S1 1402.9i 3020.62 1210.11 3964.66 0315.91 12519.30 t9191.51 26139.i1 31Ь21.б5 ц161.41 1о/ r�1cдD - indivieoalв Oi.4S 104.01 1д4.20 191.6Z 23B.6i I1B.21 918.=1 J>s.i4 81�.92 1lВ1.00 1624.53 220i.S6 i1A4.8S S21i.i2 6110.62 BS1S.94 1O11S.11 - сwвпсiаl ti ioQastгla! 21А.б2 265.16 313.В4 з11.16 121.12 311.4з 166.36 1103.11 161/.01 1600.ц 3680.13 5139.i1 1112.31 12026.i3 16916.l1 246/4.1i 3623Е.92 - Oa1k si1� зВ.ц 12.14 ЬО.ВЬ 44.l9 ES.60 42.60 ЛОО.SО 130.35 11.В1 81.3I 98.1t 1J0.91 191.20 165.� ifE.20 128.19 /60.35 - offlcid i citr ligbtiag 31.14 11.3! ®В.ЬО 61.61 i1.4o 41.t8 12Ь.�1 111.01 260.01 3)1.1з 564.2I 0l2.10 1I19.9'Р 1Т39.90 2640.1Z 3911.32 5цI.11 � OtMr Opц+tiao Nstwroei 24.52 39.29 36.11 91.А0 125.0� 113.90 096.39 269.9i 3В1.б3 905.26 584.11 811.61 1110.14 119f.61 131i.94 201А.01 2131.10 м.-и .«-и .....и и--.- .---и «и.и •ииw и..и ---'-- и•-.- •-•.и ии.в «.-.. и.в.• м---. в.•... Tcta1 Operatiaq Rereш�s 100.1J 143.60 б14.01 181.01 09з.1б 1190.01 1609.4b 2252.01 3{08.2) {1SS.S1 бц1.31 9133.33 fS151.S0 20986.35 24201.70 346Ы.б9 ц30s.11 Otбa lисае /.b3 1.в1 10.9J I1.13 31.1i 01.62 12б.24 211.11 192.61 301.14 Ы 1.03 101Т.34 1lOB.IIO 1191.15 111b.i3 2i11.ОЬ llSf.B6 TOTAL 1t� l13.3) 3f11.11 б29.41 01b.31 921.30 l217.бЬ 1136.23 21)0.31 3400.91 5337.87 7132.24 101�.91 ИВбЬ.00 32101.10 3139LS1 A161t.1S 5b66i,o0 одагасsпq esa�set: •�tuгatioд 31.93 :,9.9д 86.41 В0.08 111.01 15/.39 252.31 20t.00 319.2! 390.92 619.19 tOt6.69 131S.OI 1560.5f 1421.1b 2590.52 1142.23 -�� Oatclиьяд 0.00 8.00 0.l6 1.9А 5.61 10.А4 16.11 l21.ц 124.00 4ц.б6 1361.14 1699.84 311i.t1 3ц1.i9 16:1.� 4406.28 11341.10 - di:tri0ol3oa 16.36 f9.4! 26.19 36.00 62.tS 109.91 1l0.41 102.11 1&1.03 251.11 362.30 191.ВТ 634.13 641.03 1169.11 1t91.98 13зS.04 - tг�sdssiao l2.i4 14.2В 10.8! l4.2S д1.21 W.1S ц.06 ц.39 99,91 110.91 114.21 258.11 361.61 119.66 SI1.2I i11.41 В11.11 - pW1ic 1iqOtia4 cost 14.п 25.9! 31.33 3b.l6 10.65 3А.бб i/.14 41.ОВ 121.06 l89.21 211.В1 3BA.lS 359.16 AS0.64 l104.13 20.i2 2164.зб i - uiotlоик! � - Oi11i�q tг cotlпtioa 12.32 16.14 21.ог 21.1ь sб.et 40.19 s0.38 SO.o1 86.54 1?0.46 sы.29 22зs1 з1l.1з 1t3.9б 61ьл1 sб1.4б в�.1з „� - ovдrla�ls 18.08 3s.N ц.Я 31.t1 ' 6i.6i l04.S6 1i0.OB N1.10 21i.00 1l2.з0 i�.Z2 � 162.i2 61i.3A 1t/4.9B 1201.2i 1�1.62 1?65./6 � r - Oeqпiatioo of assets 6t.82 п.п 9ы0S u1.SS 112.96 119.91 т.ц t96.bA г1s.т1 202.36 J1e.1/ зц.S1 /1s.i8 боз.82 пб.14 11ео.о1 1632.о1 - otbeг орагпiз� aiOeдsQS � total �er,tiaq йoeases 193.w tц.31 ц2.s4 361.бб sи.ц 7t1.N 90з.ц иs1.т1 2оз1.оУ 2'1ы,зt 39+9.1о S?O1.oa ttt3.и 91IS.1ь tsslb.a0 lтооt.2ь Узв13.а9 Nвадсlо! й�es 9t./! 04.90 181.61 129.11 1i9.11 2i4.S2 2J9.?3 281.92 171.п ц1.16 113.66 1311.16 l136.1А 2А16.36 39r1.90 11l6.16 АТВ1.99 to1 вllattгeot �r.Canstгac. li.21 ы.22 6.11 5.91 12.01 31.11 11.1б 8.т0 0.04 0.00 о,04 О.об 0.00 0.00 4.00 4.00 0.� forвlqe Excбooqe losoeo 1.31 3.91 1.ц 23.OS 0.00 й.46 S4.S9 16.бА 30.t1 50.ц 101.32 164.66 1031.11 2S11.B0 1351.11 9152.31 1Ь50.Вб Соайleutioa to 1S0 costa 1.29 3.60 13.59 1.В2 22.64 2'1.19 11.26 3t.3S на.9а l2ь.н �12.13 �11.о1 122.t9 21t.os l1б.42 89.9s 1.2! Т01й1 E�IPE�ES 291.86 350.02 /SB.38 St/.3o b96.00 1010.11 1213.81 1483.Yt 2637.о0 3321.21 1892.82 723S.1o 1tц9.21 t5081.15 Т1148.39 315{4.I1 31241.59 oo�atiay ыгqiо +Ев1Т) 213.о9 210.23 7bь.12 11т.1а 3т0.б2 110.►ь тоа.13 11o1.s1 13те.г1 1УВь.46 Узо5.26 3929.30 ы1ь.36 11s10.89 1зiц.4о 42ььб.13 з169f.ь5 � 8roas Pгofit u1s1 130.28 r11.l6 242.21 Z31.1o 261.и /9Y.6S 401.1t 12ы.41 101о.бs sц4.39 29/s.s1 ц2б.1е n49.ц пw.1s 1024г.о1 n111.11 10t ?аа to 1MиicioaiitY 12.15 f3.Ot 11.i8 24.22 23.13 26.1i 14.26 40.Tt 126.39 181.07 233.41 0.00 0.� О.о0 0.1� 0.06 0.00 а Otдeг,i�l.lot.Oor.Constfaet 24.21 13.21 11.18 3.91 12.о1 31.11 11.10 -16.1b 0.00 0.00 0.00 0.� 0.00 0.00 0.00 0.00 0.80 w NET f4)�1T tог lO1;S1 133.60 110.1Т 116.15 26В.93 22о.16 211.6А 10i.]В 8SI.2S 113т.S2 1629,59 21US.11 1443.ST 3526.70 1399.35 7Y14.1S 102?Z.01 l9113.11 i.• GsA NN Pгofit 1ад of Асс. о.о. 128.50 111.91 269.49 118.13 21i.04 263.91 >s2.OS В1b.п 4�.74 401.51 1021.А2 1ВВО.В0 l261.� 3965.14 SS1S.86 17101.� GдМ 8о1ео ta0ilAcc.Aпei�1 1bB.31 426.31 691.99 12i.02 966.21 1192.69 10ëQ.1S 2694.81 33У1.31 1185.13 639S.ц 109ц.10 1Т3ц.l9 Z3i13.36 31Вlt.SO i3T30.32 и�► flом 2о1.12 t2s.e1 т.т т0о.1е rn.a 121.е2 бдг.t4 tae.4i tгеl.тб 1911.9s tп1.1е zla.ae т9п.tе ваоt.и ао2s.ы 111зz.OS 21о1s.1т i � � 1 вкsяа ва sr sяs - в � й �4��1�s. � � �г�l�gа� в$�_ (� �� ����г���� °�5�� �1� ������а���� �� "i� ������I� ��� � &я���� 8���i� �� ' i1: в $ � g йR�$ п � а � � � � � ������' � ��� � ���� � � �Э6�� � � � � � С ������ ! � °��� � 1 ���� � _� �� � МΡ °а� � ввs вв а вв � � ��z� �$ в � ��г'���f � � "��� � � � ��й���т� � �� � � � � � ��м��� � � ��� � ���� � �+,� �F: _ � � = II _ �gаа �cf� s в х х хj +пв 9� � в жвесss � авс аi ай с а}� в�еаырΡ� � g � � й���р� � � е��� � � Т, д°$������ � i2� � � � � ед���� � � �`�� $ Т�ц�' # ���r.! � � � � �i ��'������ g��� ��� ���й������а�� �� . �i� вв��я��� �►$� � ������ �£���� �� авв а • � о а:: �е а _ в агаг в an я_sa��r s� в 4 � � � ��°�`�� � � ������ � � ������ � � �� � � � � � а����� 4 � �°� � а��� l � $��� � � � � . ° � '��°у'jй � � r..S��€�� � � ���цiiй�� " о� �� � � ��Sв8���в � � ^д� ��•а�� � � ���� • �t �� Р� ���7�i=�1� ������1� ��а�����1�� �9 �1�������аl� _�� ��й����� ���в�� �' �i ��°s="�t� �аз��+�'� ���й�� �1�� �! �i� ���$�а1� �8s � �ё�$l� ������ �� � ' � � 4 ��°��fi I Е� �°�� я � � ������ � � �� � f � `$ �°_��� � _ �а� � '���� I � $��#� I � � � оо '� а ���,jкаав вв�цq_qцв� х�.j a:s:�a� s,.t а t� & гк вв�_п�вf я r�в� �а�пi � впа� �! i � � '��',г:т�''�� � � оо.в'C+i:� � � Z'l����� .д.". � �� � � У � � ���$�� { � вtо� � '�3���$ 1 � '�+��� �'� �D �'� �''И..�°�R:i�'� °i''мi�iLi�1� х'c�S��ë '�s��� ё� ��,.ф� 3dsьj.Fdd�й �д�� .�..+�i3f,�' ��i'�R«��� i� ^� � r.°�$�i3i:► 1 i в�°Ч7� в 1 � ��1:в°�� � 1 ,i� � � � � s ва�'S�в � � в�rд � S$�`�� � '� ��SJ� � � ,�'ь � � :! .�'.�'..'�в"�.Ро � н �,,t'й :i а Si в,,�s'й1:..Рi.в ёц.11 �4�уΡi �. вв�'Sвв .i ëвiS$�j :еС{аΡд S:+' в$%�L� в�'�. 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'в • � `_ . _ . COLOMBIA: INTERCONNECTED SYSTEM Capacity and Peak Demand (Actual and Projected) 10000 1982 - - - Program r -1 Actually AValtab4e ww - sm San Carlos I (interconnection r Assumed Throughout) 10%/Anftum SAR FEN Loan r 1984 40 8000- 1975 Program 1078 50AIAnnum Program 0 SAR Quatape 11 ion 666 Actually Available (Central System) 1970 2000 - - - - - -- Peak Demand I-- North-Central Interconnection Pd (Actual) 1 00 I Actually Avwfable (CORELCA System) 0 1972 1973 1974 1975 1978 1977 1978 19M 1980 1981 1982 1983 1984 1985 ION 1987 ION IM 1990 1991 1992 19M Yew COLOMBIA* INTERCONNECTED SYSTEM Energy Required and Generation Capablilty (Actual and Projected) 50- Actual: Average Hydrological Year with Average Thermal Output Actual: Dry Hydrological (" Year with Averag* ----Thermal Output (18A Report 1983 40- 1 10%1Annum Projected: SAR PEN Loan r 1984 30 - Projected: SAR San Carlos I **M5%lAnnum (Interconnection * Assumed Throughout) / ,/ g' Actual Generation Projected: BAR Guatape 1 - 20- (1972) --- North-Central Interconnection 0 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1988 1987 1988 1989 1990 1991 1992 1993 �� � J а � � � �I� ��� »�� � � � � ��-ж � � � � � � � �� � � -� s� ��� � ��� �-� ► �� � .�.� � �� � � �� ���� ��.�� ��� � � ���� ������ � � я я � к s ��� �I � � � � � �� � � : $ � � 1 � .уΡ ^� у 9I S н FI :{ S й � � �а�� � � � � ZS �I р .°r :i °н °.J iy � � �1 � . s в � s � � � � � в в в � ��) ` �) � в � s ж s � в ж в 'в `н � �1 � � ��� � � 7.2 PaV 2 of 4 fl= m~ ftm Start CM~. Dec4o4m to to ~ of ~Øct Dec~ Fi~ Øpe~ C~. St= 0mra~ _ Obsava~ Pi~ A~ Pi~ A~ A~l Sen Carløs 1 07173 09180 loiaz 23 61 64 51 Runa~ in fft=IM In pwtl~, with BRI*- mm~ 07/75 osial 03183 25 26 48 66 ?«~ *¥ diffimiti«. Sen Carløs Il 07175 07183 02187 42 54 54 85 ~ ila cmtractor pøyaffits, be= of U* of lam' CLIPPIOW,1 fb=-2 da~te delgx~ slo~ because of re~ ~ of d~ ~ i IV 12l78 atas 09185 27 38 47 44 D~ at pape=lm ~ _ P~ 1v78 10185 02188 54 59 55 78 Redeolep of PlayastJapas; zelo=,fmof a~, c=ern. iq~ IZ/78 07183 05187 8 zo 47 al m~ <£ P~Ijff=; land acnu4g4t1m (10 =sida de~ (4 difflødt4es In ib=ellim and %)i~ a=v~. SalvaJinn, 12175 Galei 10185 13 51 55 67 Delay In ~ up due to diffiag~ In utabl~ I . n t4cn of vu:b= b~el~ in this aulti- p~ ~ - 22/78 03186 05187 18 31 69 71 6 m~ - d~ In defi~ I ra twk 18 ~a fm - 186 - -E 7.2 Pag 3 of 4 nfrn Start CCt. Dein~m to to Start of Pject Dcisn Firat mntr. Start ope~ Observati= å ~- mu-'m PI~m ani kt lpi~u k~ua •rranniaim ines C~ntal 11/66 12/71 12/71 22 26 38 34 Inter=. North-/'tra1 07/75 12/78 02182 5 41 36 39 pratim at 500 kV nly by 07184 ~e of fa~r to cM~plet cD-fnan~'zng for sbst eq n. 'hnml Plants Zipmliran 1V 0577 01/81 05181 17 18 27 30 Paipa m 05177 0181 02182 17 28 27 29 hiim 09/79 07181 02182 7 16 15 13 erranca M 07170 07174 06/78 18 19 30 76 Tmw1 04166 12176 08/83 57 117 71 91 Firt crantor Iuma to ad~ tss4 pry pgtesso. neomxnt zeree~ . MS~1 cmtr eto er a r ajor - diff~ie. Rck faiUures during early operatim. - 187 - ANNEX 7.2 Page 4 of 4 Delays (mths) Decision to Start Constr. Project Decision Constr. Start to Completion Total Hydroelectric Plants Guatape I 03/63 1 30 31 Canoas 06/66 3 1 4 Alto Anchicaya 08/68 5 6 11 Chivor I 04/69 2 23 25 Guatape II 04/69 1 14 15 Chivor II 11171 33 10 43 San Carlos I 07/73 38 -13 25 Mesitas 07/75 1 18 19 San Carlos II 07/75 12 31 43 Guadalupe IV 12178 11 3 8 Playas 12/78 5 23 28 Jaguas 12178 12 34 46 Salvajina 12175 38 12 50 Betania 12/78 13 2 15 Transmission Lines Central Interconnection 11/66 4 -4 0 North-Central Interconnection 07/75 36 2 38 Thermal Plants Zipaquira IV 05/77 1 4 5 Paipa III 05/77 11 2 13 Turbogas Chinu 09/79 9 -2 7 Barranca III 07170 1 46 47 Diversion Chingaza Tunnel 04/66 60 20 80 -188- Annex 7.3 COLONIA: POVER SECTOR REVIEW 1971 - 1986 Analysis of 0ank Project Costs Utility Project Type of Actual Actual Base Actual Escala- Actual Total Cost Costs Cost in Terms tion i Yeres Cost in terms of Estimated of Price of Estimated base Cost + Contingencies Total Cost million Physical in Col S 1986 IIS Contingencies ISA Chivor I Locol .119 1041 no p.c. 232 Foreign 192 111% no p.c4 2441 Total 301 1081 ao p.c. 2391 EPi Suatape II Local 100 1252 9471 2421 Foreign 61 692 1040 155 Total 161 9R 9131 2001 1SA San Carlos I Local 116 100% 2681 18t Foreign 184 912 4332 205? Total 300 94% 345? 194 EEEB Ihesitas Local 190 1941 646? 3552 Foreign 201 125? 4491 2141 Total 392 1521 547? 2741 EPi Suadalupe. V Local 31 77 1522 tit Foreign 34 411 642 542 Total 64 531 93 751 EPit Playas Local 78 81 1282 109 Foreign 85 621 1051 8 Total 163 70 1152 961 EEE hiavio Local 594 250 262 2562 Foreign 657 1502 1342 1401 Tqtal 1251 1881 1712 1782 ISA Intercon. Local 16 871 no p.C. 103? Foreign 41 93 no p.c. 1041 Total 57 911 no P.c. 1042 ISA 500kV TnterconJdocal 65 137 3242 2261 Foreign 62 51 3052 124? Total 127 941 3152 i65 * Actual Cost in silliom 1986 0t calculated by revaluating Actual Iase Cost (i.e. actual cost in. Colt of the year cost estiate was nad to 1986 Colt add converting to 1986 ISS at 1986. -189- ANNX 7.4 COLOMBIAt POWER SCTOR REVIEW 1971-1986 Analysis of ocalation in Bank Project Cost& (Percent) Actual Actual Escalation Escalation on Base Cost on Actual Total Plus Physical Base Cost Actual Contingencies Due to Incr. Escalation in Term of Base Costs in Teas Price Type of Actual Base and Implem. of Actual Contin- Utility Project Cost Cost Delays Base Cost nencies ISA Chivor I Local 101 22 123 0 Foreign 111 8 120 0 Total 107 14 121 0 EPN Guatape II Local 57 72 130 21 Foreign 144 4 148 10 Total 88 48 136 16 ISA San Carlos I Local 105 144 249 93 Foreign 107 131 238 50 Total 106 136 242 66 EEM Mesitas Local 43 142 185 55 Foreign 56 79 135 38 Total 50 111 160 45 EPM Guadalupe IV Local 176 44 220 112 Foreign 316 -127 189 120 Total 247 -43 204 117 EPH Playas Local 168 53 222 139 Foreign 234 21 256 150 Total 201 37 239 146 EE Guavio ]a Local 60 51 111 105 Foreign 123 20 143 160 Total 91 36 127 139 ISA Intercon. Local 14 4 18 0 Foreign 9 3 13 0 Total 11 4 14 0 ISA 500 kV Intercon. Local 97 119 215 92 Foreip 190 0 191 36 Total 141 63 204 54 a The Guavio Project data reflect actual costs for the period 1981-1987 and 1987 projections for the costs of the parts still to be completed. - 190 - ANNEX 7.5 DISTRIBUTION INVESTMENT IN TERMS OF TOTAL INVESTMENT EEEB 1975, 1976, 1977 Actual$ 192, 41Z, 442 SAR Hesitas 1978-1982 Plannedt 312 SAR Mesitas 1978-1984 Planneds 312 PCR Mesitas 1978-1984 Actual: 232 PCR Mesitas /a EPM 1979-1986 Planneds 171 SAR 1%adalupe IV La 1980-1988 Planned: 142 SAR Irlayas La 1980-1983 Actual: 12% SAR Rio Grande II a 1984-1991 Planneds 162 SAR Rio Grande 11 fa *_a The distribution investment includes at least subtransmission and part of the cost of transmission facilities.