Joint UNDP/World Bank Energy Sector Management Assistance Program Activity Completion Report No. 004/83 Country: wAx Activity: POwNER SYSTD LOSS REDUcTIoN STuDY JUNE 1983 Report of the Join UNDP/Wxd Bank Eneg Sect Management Asstn Program This document has a restrted distribution. Its cortents may not be disclosed without authorization from the Government, the UNDI or the Mrbid Bank. Energ= Sector Management Program The Joint UNDP/World Bank Energy Sector Management Prograr is designed to provide a rapid and flexible response to governments Rho request assistance in implementing the policy, planning and institutional recommendations of the Energy Assessment Reports produced under another Joint UNDP/World Bank Program, or in carrying out prefeasibility studies for energy investments identified in these reports. The Energy Sector Management Program can provide the following types of assistance for countries which have had assessments: o assistance to Improve a government's ability to manage its energy sector, for example by defining staffing aud work programs, evaluating management iuformation needs, ii~entifying sources of public and private finance, developing a medium-term investmeet plan; o prefeasibility work on priority investment plans, especially those which will inprove the efficiency of energy use, bring about economic fuel substitution, or provide enough affordable energy to rural areas; o specific short-term assistance in institutional and manpower development, both at the sectoral and agency levels. The Program aims to supplement, advance and strengthen the inpact of bilateral or multilateral resources already available for technical assistance in the energy sector. Funding of the Program The Program is a. major international effort and, while the core finance has been provided jointly by the UNDP and the World Bank, important financial contributions to the Program have been made- by the Governments of the United Kingdom, the Netherlands, Denmark, Finland, Norway, Sweden, Australia and New Zealand. POWER SYSTXK LOSS REDUCTION STUDY JUNE 1983 CURRENCY EQUIVALENT Currency Unit a Balboa (B/.) US$1.00 = B/.$1.00 UNITS Thousand circular mills (kemil) - 1.94 sq.mm. 1 meter (m) = 3.28 feet 1 kilometer (km) = 1,000 meters 1 kilovolt (kV) - 1,000 volts 1 kilowatt (kW) 1,000 watts 1 megawatt (MW) = 1,300,000 watts 1 kilovolt ampere (kVA) = 1,000 volt-amperes 1 mega volt-ampere (MVA) = 1,000 kilovolt-amperes 1 kilovolt-ampere reactive (KVAR) - 1,000 volt-amperes reactive I mega volt-ampere reactive (MVAR) - 1,000 kilo-volts ampere reactive I Gigawatt-hour (GVh) =1 million kilowatt-hours ELECTRICAL CHARACTERISTICS Frequency - 60 Hertz Secondary Distribution and Service Voltages - 240/120, 208Y/120, 240, 480Y/277 volts Primary Distribution Voltages - 2.4, 4.16Y/2.4, 6.6, 13.8Y/7.96 34.5Y/19.9 kilovolts GLOSSARY AND ABBREVIATIONS IRHE - Instituto de Recursos Hidraulicos y Electrificacion OA - Self-cooled transformer rating FA - Fan-cooled transformer rating FOA - Forced oil (pumped) transformer rating AAC - All aluminum conductor ACSR - Aluminum conductor, steel-reinforced AWG - American Wire Gauge FISCAL YEAR (FY) Begins January 1 and Ends December 31 TABLE OF CONTENTS Page No. FOREWARD AND SUMMARY OF FINDINGS AND RECOMMENDATIONS Foreword ..... 0 0. iii Conclusions and Recommendations ....... ii Loss Reduction Project ...... v Transmission System Project . v Generation Expansion Program . vi CHAPTER I - PANAMA POWER SECTOR Overview I 1 CHAPTER II - DISTRIBUTION SYSTEM ANALYSIS AND LOSS REDUCTION Overview 0..... 2 Distribution Circuit Analysis 2 Existing Computer Program *. ... ..... .0.0..... .3 Long Run Marginal Costs 3 Distribution System Loss Reduction Project 3 Non-Technical Losses .....o 5 Recommendations 6 CHAPTER III - TRANSMISSION SYSTEM LOSSES Overview 6 CHAPTER IV - THERMAL PLANT REHABILITATION PROJECT Overview **ooooo...,.....v*.........*..... 7 Thermal Plant Operations ..... 7 Maintenance of Bahia Las Minas Plant 7 BLM Rehabilitation Project ..... 8 Other Efficiency Improvements 00000 000o0000o0000000040000o000 9 Postponement of Hydro Generation Plant .... 9 - ii - LIST OF TABLES IN TEXT Page -No. 2.1 IRHE tocal System Technical Losses ........................... 4 2.2 Distribution System Lose Reducton ..*.*.....*......... 4 4.1 BLM Rehabilitation Cost and Be:iefite ......................... 8 ANNEXS 1 IRHE Power Generating Facilities ............................. 10 2 IRHE Power System Data ..........................0.0 **..*..*... 11 3 Distribution Circuit Analysis ............................... 15 4 Rehabilitation of the BLM Thermal Plant Terms of Reference .............. ........ .... e.....,.. 16 - iil - PANAMA UNITED NATIONS DEVELOPMENT PROGRAMME POWER SYSTEM LOSS REDUCTION STUDY PROJECT IDENTIFICATION REPORT FOREWORD AND SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS Foreword i. This is one of a series of studies being sponsored and financed by the United Nations Development Programme (UNDP), which are being undertaken by the World Bank as Executing Agency. Power system efficiency improvement and loss reduction have been pin-pointed as issues in almost all the country energy assessment reports completed under the joint UNDP/World Bank Program. In response to these findings the UNDP agreed to sponsor a preliminary program to identify improvements which could be made to the electric power systems of the countries studied to reduce technical losses and thereby conserve energy. This report is presented in three sections: (1) The Project Identification Report (2) The Transmission and Distribution Technical Supplement (3) The Generating Plant Technical Supplement ii. In Panama the power entity, Instituto de Recursos Ridraulicos y Electrificacion (IRHE), has already started investigating lose reduction procedures and is purchasing some equipment for that purpose. In addition, the World Bank is financing substantial distribution system improvement and expansion programs, which will, by their nature, also reduce losses. Thus a lo0s reduction program is essentially in progress. The role of the UNDP study in this case is to outline a long range loss reduction program and to provide additional advice and suggestions on specific areas of loss reduction where system losses could be profitably reduced. Conclusions and Recommendations iii. The conclusions of the report show that by introducing a complete analysis of distribution circuits on a continuing basis, using a suitable computer program, substantial improvements in systemi losses can be achieved. It is recommended that IRHE take steps to make its loss analysis program operational by acquiring the additional computh.' programs needed and the instrumentation to improve its data base (2.01 and 2.07). - iv - iv. Technical losses on indilidual distribution circuits can be reduced by: (a) Adding or relocating capacitors (b) Reconductoring circuits (c) Redesigning circuits (2.03). v. Dist'ibution system design criteria should be reviewed because the relatively low tost of material compared to the high cost of energy can make investments in distribution network improvement profitable. In many cases improvements calculated by traditional design methods can be enhanced by computer based analysis. An average benefit to cost ratio of 4 to 1 can be achieved (2.03). vi. These techniques, when systematically applied, could reduce present high total system technical losses (equivalent to $24 million annually in fuel cost) from 17.3% to 13.4% of not energy generated by 1934. However, in the longer term by fully implementing a loss reduction program, a reasonable target would be to reduce total system losses to 1 or less of net energy generation by 1988 (2.12). vii. Over 50% of all system losses occur in the Distribution System at the 13.8 kV voltage level and below (2.10). This is consequently the principal target area for loss reduction. It is obvious from the comments above that substantially higher investments than heretofor in distribution betterment will be required for a number of years to compensate for past under- investment. viii. In addition to the technical losses, that is the losses inherent in the physical characteristics of the system, there are 'non-technical" losses from billing and metering errors and unaccounted for energy consumption-- principally illegal diversions of current. These losses are both difficult to estimate and hard to control. A major effort is required with the full support of management to bring these losses under control. Improvements should be made to customers metering and billing procedures and for meter checking and testing both for technical loss reduction and to aid in a campaign to bring non-technical losses under control (2.13, 2.14). It is estimated that by using the long rmn varginal cost of electric energy, these losses which represent about 28% of total system losses cost IRHE $10 million annually. ix. The second major area for loss reduction concerns the generating plant. In general, hydroelectric plants are satisfactorily maintained and operated. On the other hand, the Bahia Las Minas Steam Plant (BLM), is urgently in need of rehabilitation. This work could be accomplished in about 6 months and the cost, under one million dollars, would be recovered in fuel savings in one year. Terms of Reference for this work are given in Annex 4. Loss Reduction Prolect x. The various areas and activities discussed in the report are listed below in groups. The first group consists of Loss Reduction Projects for the Distribution System and for the Thermal Generating Plant. Costs and benefits are quantified. The second group consists of a Transmission System Project and a Generation Expansion Program alternative. Both items give operating benefits and some loss reductions but do not have the same direct relationship between cost and benefits as the projects in Group One. Group One: Cost Benefit Item Action _$ $M 1 Distribution Analyze all distribution circuits 4.6 13.5 System by using the computer programs. Improvement Add capacitors, change conductors Program and rearrange circuits as in- dicated by the studies for period 1984 to 1988, after which circuit conditions are expected to change. 2. Generating Improvements to BLM oil-fired 1.00 10.5 Plant Steam Plant to improve thermal Rehabilitation efficiency and extend life beyond 1994 and other thermal plant betterment. Benefits are assumed on operation of BLM for 7 years at full normal output, after which the plant would be held in stand-by. TOTAL 5.6 24.0 Group Two: 1. Transmission System Project. In order to avoid possible nation-wide system blackouts, improve system stability and reduce losses, le is studying the advantage of advancing the construction of the pro- posed 345-kV transmission line scheduled for about 1990, or the possibility of reconductoring the existing 230-kV line to improve system reliability and at the same time reduce losses (Chapter III). - vi - 2. Generation Expansion Program. IRHE is reviewing the Generation System Expansion Program to supply forecast system demand after 1990. Tentatively, the Changuinola Hydro Plant was scheduled for 1991. It is recommended that the further postponement of this plant to 1993 should be examined by IRHE in detail. The system forecast demand might be supplied by using the BLM Thermal Plant after it is rehabilitated (Group One, Item 2) and by moving all off-loaded diesel units into a central diesel park. The financial benefit to IRRE consists in the difference in cost of fuel burned in the thermtal plants and the interest saved to finance the hydro plant. The therma plants would all be almost completely amoritized by 1990. A preliminary partial estimate shows savings of up to $25 million, however, IRHE would have to make a full analysis to reach a decision. xi. This report has been discussed with IRHE's Management who expressed their satisfaction with the recommendations made and signified their intention of implementing the principal items and to give further r*view to other items. CHAPTER I PANAMA POWER SECTOR Overview 1.01 The Power System is owned and operated by IRHE, a Government-owned agency created in 1961, which by 1978 had gradually acquired the five private companies which previously provided electric service in various parts of the country. RHEE's Board of Directors regulates the sector, but electric tariffs, recommended by IRHE, must be approved by the Cabinet. 1.02 The. only indigenous source of energy currently used for the generation of electricity in Panama is hydro energy. The potential of geothermal, oil and coal resources is being investigated but no firm estimates are y*t available. All petroleum is imported and refined at the local refinery. Until 1976 almost all electricity was generated in oil-fired thermal plants. The Government then decided to maximize the use of hydro energy to reduce imports of fuel and by 1981 70% of all energy was generated in hydro plants. The known hydro sites could provide sufficient energy to meet forecast electricity demands well into the first half of the next century. 1.03 The Power System is generally well operated and the technical staff Is well qualified and competent. However, some suggestions are given in this report for improvements in specific areas. The principal problem area, which has been receiving attention siace 1975, concerns badly needed rehabilitation and expansion of the distribution network which was taken over from the private companies and which had not been expanded to meet growth in demand during the period of negotiations prior to takeover. This work will take several more years to complete. 1.04 The bydro plants are generally in good condition and satisfactorily maintained. On the other hand, the Bahia Las Minas Steam Plant is in less satisfactory condition and urgently needs rehabilitation as d'.scussed in Chapter III, Thermal Plant Rehablitation. 1.05 Details of the generating capacity, system demand forecast, transmission and distribution systems are given in Annexes I and 2. -2- CHAPTER II DISTxIBUTION SYSTEM ANALYiES AND LOSS REDUCTION Ove. view 2.01 IRHE started a program to improve parts of its distribution system in 1979 and is now In the process of negotiating financing for a second three- year betterment project (1983 to 1986), which forms part of a Distribution System Master Plan, to meet forecast system demand and expand and rehabilitate the system. The project also includes financing for instrumentation to provide basic losd data and consulting services where required for its loss reduction program. IRRE has also purchased, as part of the 1979 to 1983 Distribution System Program, some computer programs for distribution system circuit analysis (2.11). 2.02 This section will review IRHE's proposed loss reduction activities and comment upon these. The distribution system will also be reviewed and loss levels among other matters will be discussed. Distribution Circuit Anal sis 2.03 In order to assess the condition of the distribution system, where the major proportion of system losses occur (2.10) and where maximum loss reduction may be achieved, an analysis of selected distribution circuits was made by the UNDP/Bank team using a computer program developed under a World Bank-sponsored research program. An analysis of the wholb distribution system was not contemplated because of t4m constraints. In all, eight substations were chosen-five in the urban area of Panama City and three in rural areas and from these substations 33 distribution circuits were analyzed. The results of these analyses showed that very substantial loss reduction could be achieved by installing new or relocating existing capacitors; changing conductor for larger sizes; raising voltage levels or transferring load to neighboring circuits. The benefit-to-cost ratios ranged from 10:1 to circuits where no significant improvements could be made. The overall average showed a benefit-to-cost ratio of 4:1. The detailed results are given in the Transmission and Distribution System Technical Supplement to this Project tdentification Report and are summarized in Annex 3. 2.04 Some of the test circuits had previously been included as part of the Distribution System Master Plan, however, by comparing the improvements previously proposed with the results of the team's analysis It was obvious that the possibility of achieving even further loss reduction over results obtained by traditional design procedures, was very real and clearly demonstrated the value of using a computer based circuit loss analysis program. It was also evident because of the differences between individual circuits, that optimum betterment and loss reduction requires a program of distribution eircuit analysis on a continuing basis circuit by circuit. 2.05 In analyzing the selected test circuits, it was also observed that distribution system design could be reviewed advantageously, particularly to optimize condctor sizes in view of estimated loading and anticipated load growth. Underground cable duct design should be checked to avoid excessive loss of capacity caused by poor heat dissipation. -3- 2.06 In using the computer program, it was found that the principal impediment to achieving optimum results was either the lack of or inaccuracies in th'e basic data. For example, circuit maps are up to three years out of date: Load data is inadequate because of inadequate substation metering or lack of records--the physical circuit characteristics were not always correct. Partial correction of this problem is planned under the distribution Master Plan. It is essential to correct these deficiencies otherwise the best results can not be obtained from the computer program and system planning will be unsatisfactory. Existing Computer Program 2.07 Computer programs are now accepted as a basic tool for distribution system analysis. IRHE has ordered some co'zputer programs which it hoped to use on its existing billing computer and sou-e supplementary equipment for load forecasting, circuit analysis, mapping and transformer load management. These programs have not become operational because the supplier is still in the process of adapting its program for use in IRHE's computer. The mapping program has not come up to IREE's expectation, the transformer load management program has not been Implemented and can not be made operational until a considerable amount of preparatory work is done. In order to obtain a satisfactory distribution system analysis program, the basic computer programs will have to be made operational by the supplier; a capacitor locating program and economic analysis program will have to be added. Now that IRHE has had the opportunity of seeing the team's computer program in operation they should be in a position to request the supplier to provide the additionai programs required to make the system operational. IR=E has indicated that it proposes to make the computer program operational. tong Run Marginal Costs 2.08 In order to calculate the value of losses the economic long run marginal cost (LRMC) is used. This reflects the economic cost of the incremental supply facilities that would be required to provide an incremental unit of demand. Capacity marginal cost is determined by the incremental investment and the associated fixed operating and maintenance costs. Long run marginal cost of energy is determined by the marginal fuel, variable operating and maintenance costs of generating plant required to provide the incremental kilowatt-hour. 2.U9 For Panama, the LRMC of the peak kilowatt (capacity marginal cost) and that of energy at the distribution voltage are estimated at US$ 353/kW/year and USt 6.95/kWh, respectively. Details on the LRMC are given in the Transmission and Distribution System Technical Supplement. Distribution SYstem Loss Reduction Project 2.10 The total system losses in 1982 are shown in Table 2.1. -4- Table 2.1: IRHE Total System Technical Losses - 1982 Item Energy Losses System net Generation, GWh 2,013 Total System Losses, GWh 348 Losses as a Percentage of Generation, X 17.3 Distribution System Losses, GWh 185 Distribution Losses as a Percentage of Total Losses, % 53 Value of Total Losses a/ $M/ 24,2 Value of Distribution Losses $M/ 12.8 a System energy losses estimated by IRHE, see para. 2.12. 2.11 An estimate was made by the team of the possible benefits which would result by applying the corrective measures discussed in para. 2.03 to the distribution system as a whole during the 1984 to 1988 period. The result is given in Table 2.2. It will be seen that by investing an estimated $4.6 million over the four year period the reduction in losses would be equivalent to a fuel savings of $13.5 million to give a benefit-to-cost ratio of about 2.9:1. Table 2.2: Distribution System Loss Reduction Year Item 1983 1984 1985 1986 1987 1988 Total System Energy Lossrs without Betterment, GWA1a 319 307 327 348 379 394 Value of Losses, $M 22 21.3 22.7 24.2 26.3 27.4 Loss Reduction from Better- ment, GWh 9.1 26.2 29.2 16.6 4.4 New Energy Loss, GWh 298 301 319 363 390 New Loss as a Percentage of Net Generation, % 13.4 12.4 11.5 11.6 11.1 Investment in Loss Reduction, $M 1.0 1.2 1.2 0.9 0.3 4.6 Value of Losses Reduce, $M 2.1 4.3 4.5 1.9 0.7 13.5 Benefit-to-Cost Ratio 2,1:1 3.58:1 3.75:1 2,1:1 2:1 2.9:1 a/ System energy losses estimated by IRHE, see para. 2.12. b/ Value of losses calculated by using long run marginal cost of energy. -5- 2.12 The total system loss for 1982 based on actual results is 17e3% of net generation (Table 2.1), these losses are estimated by IRHE to drop to 13.4% in 1984, as shown in Table 2.2. This improvement is largely due to the substantial distribution betterment program undertaken by the distribution system master plan from 1979 to 1983 and which will continue through 1986. From 19-84 to 1988, the proposed loss reduction program referred to in para. 2.11 will also contribute towards further loss reduction, as shown in Table 2.2, which shows that forecast total system losses drops from 13.4% to 11.1% of net generation by 1988. Non-Technical Losses 2.13 So far in this report, the losses which can be identified by a computer study are technical losses, that is losses resulting from the measured circuit load and the circuit's physical characteristics. It is to be recognized that in addition there are losses resulting from unaccounted for diversion of current; errors in meter reading and billing and incorrect meters. These are the non-technical losses. These losses are very difficult to quantify and can only be tested by coordinating the out flow from a circuit and the consumption of all customers supplied by that circuit. This requires adequate metering and even then can only approximate the real load. IRIE has attempted one such test and based on these very approximate results and other approximations made by the team, it is assumed that IRHE's system non- technical losses represented about 28% of the 1982 total system loss of 17.3% of net generation. These non-technical losses cost IRHE an estimated $10 million a year in lost revenue. The only effective way to keep illegal usage under control is by applying a strict, continuous and aggressive inspection of all customer metering installations and using any available method of monitoring customer consumption, for example by programming the billing computer to identify unusual changes in consumption. Such a program must have the active support of management to be successful. 2.14 On the basis of visual inspections made by the team, it is recom- mended that a special audit team be created with the following responsibili- ties: (i) make a systematic inspection of all metering installations, identify unmetered customers, verify that meters and service connections have not been tampered with, that meter sockets are covered and have not been jumpered. (ii) check to see that all meters are read on schedule and that customers consumption is properly entered into the billing computer and that the computer is programmed to indicate any abnormal change in consumption and steps are taken to determine the cause. 2.15 A program should be started to improve meter testing facilities and organize the procedures for on-site testing of large bulk supply customer's meters. -6- Recommendations 2.16 The loss reduction program should include the following: - Examine existing 4.16-kV, 13.8-kV and 34.5-kV circuits to determine whether or not capacitors should be installed and/or the circuits reconductored in all or part in order to reduce losses. - Examine existing 2.4-kV circuits to ascertain whether or not they should be converted to 4.16-kV or to a higher voltage. - Examine existing 230-kV transmission to determine whether or not losses can be reduced economically. - Examine new projects including the transmission system to determine whether or 1not the most economic conductor size has been selected for use in the project. - Re-evaluate the location of existing capacitor banks to check that they are in the best location for loss reduction-cxcept where capacitors are installed primarily for voltage control. In addition, existing capacitor banks that are not in use should be repaired and relocated. CHAPTER III TRANSMISSION SYSTEM LOSSES Overview 3.01 The existing transmission system consists of a 230 kV double circuit line connecting the hydro plants in Chiriqui Province to the Metropolitan Area and the Bayano Hydro Plant in the south. At the present time, the line is relatively lightly loaded, however, when La Fortuna Hydro Plant comes into service at the beginning of 1984, the existing transmission system loading will increase substantially and what is even more serious is that by 1985 almost half of Panama's generating capacity will be in the northern extremity of the country and the 230-kV transmission will be the only connecting link with the Metropolitan Area (Panama City and Colon). Should that transmission line be cut by lightning or some other fault, there would be a real danger of a nation-wide power blackout. .3.02 In the earlier generating plant expansion program the Changuinola Hydro Plant was contemplated for service in the late 1980's and a new double circuit 345 kV transmission liUe was to have been added to transmit the additional energy. Since the Changuinola Plant has been postponed because of the slowdown in forecast demand, it now becomes necessary to review the transmission system expansion. 3.03 One feasible option would be to advance the construction of the 345- kV line but eonductor only one circuit and operate it at 230-kV until the full 345-kV double circuit transmission capacity was required. There are other -7- optioits, such as reconductoring the existing 230-kV line. The solution is also tied to the decision taken on the postponement of hydro plant (4.11). 3.04 IRHE is aware of these problems and is reviewing the entire situation. CHAPTER IV THERMAL PLANT REHABILITATION PROJECT Overview 4.01 The principal thermal generating plant is Bahia Las Minas (BLM) (144 MW), a steam plant. The other thermal capacity consists of a steam unit, four diesel units and a gas turbine at San Francisco (SF) and two new gas turbines (42.8 MW) and 16 diesel units (40.0 MW) at various rural locations throughout the system. 4.02 The Government's policy of maximizing the use of hydro generation to save imported fuel essentially means that the existing thermal capacity will be out of service or in cold storage from 1985 to 1988 after La Fortuna Hydro Plant comes into service, except for the gas turbines and diesel units, which might be placed in operation for peaking or emergencies for short periods at iifrequent intervals. The steam units at BLM (1 x 24 MW and 3 x 40 MW) are, by their nature, unsuitable for periodic short term service interspersed with up to three or more years out of service. The Generating Plant Technical Supplement to the Identification Report gives details of the thermal plant rehabilitation project, which is sumarized below. Thermal Plant Operations 4.03 Since 1982 IREE has experienced severe dry year conditions so that the hydro plant reservoirs are at low levels and all thermal plants are operating at their maximum, except for the two new gas turbines which were commissioned in early 1983. This situation is expected to continue during 1983 and 1984. In 1985, the first stage of La Fortuna hydro plant (255 MW) is scheduled to come into service and from then until about 1988 the forecast system demand would be supplied almost entirely from hydro plants, except during emergencies or very dry seasons. The BIM units would only be required under average year conditions, from about 1989 to about 1993, after which additional new generating capacity is presently scheduled to b% brought into service to meet forecast system demand. See, Postponement of Hydro Generating Plant, 4.11. Should the present dry year conditions continue or recur, the Pielstick diesels and the BLM units would be required for service. This possibility is not considered very likely. The infrequent short duration requirement for thermal backup could be supplied by the diesel units at the SF plant, the rural diesel units and the new gas turbines. Maintenmce of Bahia Las Minas Plant 4.04 A review of generating facilities by the loss reduction team showed that the BLM plant was urgently in need of rehabilitation. The other generating facilities were either in satisfactory condition or are scheduled for retirement in the near future. -8- 4.05 The principal problems at BLt, are attributable to poor maintenance due to the difficulty the plant operators and maintenance personnel have had in keeping the equipment in satisfactory operating condition. The instrumentation and controls of the boilers and turbines are inoperative, inaccurate or missing, consequently combustion control is rudimentary and there is the danger of a boiler explosion. The condenser cooling system is infested with clams because the chlorination systems are not operating so that design vacuum cannot be achieved. The units are being operated below rated temperature and pressure. Heat rates are therefore considerably above design levels. BLM Rehabilitation Project 4.06 It has already been stated that BLM plant will most likely only have to operate at full capacity during 1983 and 1984, after which with normal rainfall it may not again be required until 1989. In spite of this likelihood, the rehabilitation of the plant is considered by the team to be of the highest priority and should, if possible, be done during 1983. The fuel savings accruing from these corrective measures would more than repay the rehabilitation cost during 1984 alone. In addition, some of the defects as now existing represent safety hazards. This rehabilitation would give substantially greater savings if the thermal units are used after 1990 to postpone new hydro plant additions as discussed in paragraph 4.11 4.07 The required corrective measures, the estimated cost and the resulting benefits as shown in Table 4.1, where it will be seen that for an investment of about $880,000 a benefit equivalent to about $1,600,000 in fuel savings would accrue in 1984 alone. The cost would be recovered in less than a year. All savings during future operations would be net savings. Table 4.1: sK RehabilitatiLon Cost and Benefits Cost in US$ ODD lal &i0 Estliaed for 1984 a -ad toe Corzsotie mesawe tmdd Serioss Labo Total tem 1s$ 000 1. GtAide conraeo to plI" 50 22 50 320 Operate touin at rate! 230 Ist-ea aid cortols in testiwe aid puage - oader ard train ain- tnI and opeatil staff 2. %1par faiy Irautio 3 10 13 Reduwe heat ls dhwa 63 lImulation 3. sairol wuts 295 40 100 435 lWi coabtioa cmtml 450 aid r4aiait of baEw1 4. Relr air W*eater alse 12 3 15 air pnoer al 129 5. 88bmlittioa of am] 5 15 20 Rinto oas 725 matr q,tei to des* leel vanm 6. oxtireAm 36 36 17 79_ _ ITal 40 286 M9 1,597 -9- 4.08 In view of the poor condition of the BLM plant, it is recommended that an outsi4e contractor specialized in boiler and turbine instruments and controls and steam plant operations be engaged to organize and supervise the corrective measures outlined ab)ove. At the same time this contractor should train IRHE personnel so that they will be able to continue maintaining the plant in good operating condition and efficiency after the contractor leaves. Proposed Terms of Reference are given in Annex 4. Other Efficiency Improvements 4.09 Should the BLM plant be required for continuous operation from 1989 to 1992 or beyond. IRHE should discuss with the turbine manufacturer the possibility of improving steam turbine efficiency by replacing Labrynth seals and turbine blade spill strips. Also, consideration should be given to replacing existing fixed speed drives on boiler fans by variable speed motors or hydraulic couplings. Substantial fuel savings could accrue, however, these changes are subject to an indepth engineering review and can only be justified if a reasonably long peried of continuous operation is anticipated, such as would occur in 1990 to 1993 if the hydro installation was postponed (see below). Postponement of Hydro Generating Plant 4.10 The Government of Panama has indicated its desire to limit its foreign debt and one o the major items concerns the financing of the proposed Changuinola Hydro Plant. 4.11 It would appear from a rudimentary examination of the available generating capacity on IRHE's system, from 1991 to 1993, that Changuinola could be posponed if the BLM units were rehabilitated as described in 4.06 and 4.07 and the diesel units were centralized in a diesel park so that they could be maintained better and operated as a single generating station (3.08). 4.12 This possibility has already been examined by IREE and a comparison made between constructing Changuinola and a new coal-fired steam plant. The latter appears to be a lower cost alternative. IRHE expects to review its generation expansion program further. - 10 - ANNEX 1 TABLE 1 IRHE POWER GENERATING FACILITIES a/ Nameplate Available Date Capacity Capacity Name of Plant Type Installed (MW) (MW) Bahia Las Minas (BLM) Unit 1 Steam 1964 22.0 22.0 Unit 2 Steam 1969 40.0 40.0 Unit 3 Steam 1972 40.0 40.0 unit 4 Steam 1974 40.0 40.0 San Francisco (SF) Unit 3 Steam 1955 11.5 11.0 UAnit 4 Gas turbine 1964 14.0 12.0 Pielstick-Diesel Bunker oil 1976 4 x 7.0 28.0 Load Dispatch Center GTDC Units 1 & 2 Diesel fuel Gas turbine 1983 2 x 21.4 40.0 Rural Diesel Plants Aggregate units Diesel 1961-72 16 x 25 40.0 Bayano Units 1 & 2 Hydro 1976 2 x 75.0 150.0 Unit 3 (future) Hydro 1990 75.0 75.0 La Fortuna (Under Construction) Units 1, 2 & 3 Hydro 1985 3 x 85 255 Raise Dam Hydro 1987 45 45 Estrella Los Valles Estrella units 1 & 2 Hydro 1978 2 x 21.5 43.0 Los Valles units 1 & 2 Hydro 1979 2 x 23.5 47.0 Mini Hydros La Ye3guada Hydro I x 1.0 1.0 La Yeguada Hydro 1967 2 x 3.5 7.0 Coclesito Hydro 0.25 0.25 Santa Fe Hydro 0.35 0.35 Changuinola (Under Study) Units 1, 2 & 3 Hydro 1992 3 x 100.0 300.0 TOTAL 1,204.4 1 ,188.4 a/ Source: IIRE. - 11 -X .ANNEX 2 IRHE POWER SYSTEM DATA Generation Facilities 1. The existing and potential hydro sources are estimated at about 4,000 MW. Prior to 1976, excluding the Panama Canal which generated its own electric power in hydro and thermal plants, only 17 MW of hydro potential had been developed in the rest of the country. The Bayano Hydro Plant (150 MW) came into service in 1976 and by 1981 the total hydro capacity was 252 MW. Another 300 MW is now under construction at La Fortuna in northern Panama for service in 1984. A further 1,500 MW at eleven sites is under review for service from 1990 onwards. An interconnection with Costa Rica is being planned to allow Panama to purchase surplus energy from Costa Rica's hydro plants. 2. The installed generation capacity and energy generation by each type of plant in 1981 is given in Table 1. TABLE 1 INSTALLED CAPACITY AND ENERGY GENERATION (1981) Item Total Hydro Steam Diesel Gas Turbine Nameplate Generating Capacity (MW) 535.1 100% 247.646.3% 166 31.0% 69.5 13% 12 9.7% Energy Generated (GWh) 1897 100% 1334 70% 508 26% 54 4% 0.5 OX 3. Captive plants in industry and plantations have steadily declined from 16% of total electric generating capacity in 1970 to 7.5% in 1980. The tendency is for these plants to be retired gradually as IRHE's transmission and distribution system is extended. Transmission and Distribution Facilities 4. The main transmission system consists of 230 kV lines connecting the hydro plants in the northern provinces near the Costd Rica border with the metropolitan area and the Bayano Hydro Plant in the south. These lines were to have been reinforced by 345 kV lines when the next hydro plant came into service about 1990. The existing 230 kV lines will be approaching their rated capacity after 1984 when La Fortuna comes into service and transmission losses will reach excessive levels. This matter is examined in detail in Chapter III. The other transmission voltage is 115 kV which forms the Integrated System by Interconnecting the many small localities with the main load centers. -12 - ANNEX 2 Page 2 of 4 5. The distribution system in the urban areas which supply approximately 68% of the energy sales, operates at 13.8 kV, however, small amounts of 2.4 kV and 4.16 kV are still in service in Panama City and some of the smaller cities in the other provinces. Rural areas are supplied principally at 34.5-kV and 13.8 kV, although scattered segments at other voltages are in use. The distribution and transmission network is almost all overhead, the aggregate of all underground cables would constitute only about 3% of the total network. The Power Market 6. The power market is characterized by the heavy concentration of demand in the urban areas of Panama City, parts of the Canal Zone, and Colon and the Province of Chiriqui, which aggregate 81.8% of all erergy consumed (Table 2). The other feature is that 61.2% of the energy consumed is by residential and commercial customers served at low voltage. Industry only consumes 12.3% of total energy sales and of this only 4.5% are bulk sales (Table 3). Because of these characteristics, the distribution system at 13.8 kV and below is the principal source of system losses, comprising over 50% of system peak demand losses (2.10). TABLE 2 ENERGY SALES AREAS, 1982 Areas MWh Percentage of Total Panama City 1,139,888 68.2 Colon 109,694 6.5 Panama West 62,052 3.7 Central Provinces 123,082 7.3 Chiriqui 113,593 6.8 Isolated Systems 6,766 0.4 Ancon and Cristobal 39,445 2.3 Canal Zone 16,000 0.9 Bulk Sales 62,000 3.7 TOTAL 1,671,520 100.0 TABLE 3 ENERGY CONSUMPTION BY CATEGORY OF CUSTOMER. 1982 Category of Customer MWh Percentage of Total Residential 496,700 29.7 Commercial 525,695 31.5 Industrial 204,580 12.3 Government and Municipal 319,550 19.2 Street Lighting 35.060 2.0 Subtotal 1,583I585 Bulk Sales and Canal Zone 78.000 4.5 Subtotal TE3,65958 IRHE's own usage 11 935 0.8 TOTAL TT.o ANNEX 2 -13 - Page 3 of 4 7. Energy requirements, maximum system demand and system losses for the interconnected system from 1980 to 1994 are given in Table 4. The data for 1980 and 1981 are actual results and from 1982 to 1994 are IRHE's forecast. 8. It will be seen from Table 4 that load growth during 1980 to 1983 shows irratic variations caused by a slowdown in Panama's economy; the impact of a Government-sponsored energy conservation campaign and the earlier than expected completion of two major new loads in 1982. After 1983, the forecast is based on the anticipated long term recovery of the economy and a sustained annual load growth of about 72, which is considered reasonable in relation to the average long term power demand growth in Panama in the past. 9. In its review of IRHE's load forecasting procedures, the team noted differences in the forecasts made by the Generation Planning Group, the Commercial Department and the Transmission and Distribution Planning Groups. It concluded that there is a clear need for IRHE to review its forecasting procedures to coordinate the various departmental forecasts so that all elements affecting the forecast are properly taken into consideration. ,6NZ 4 EXISIIN AM FEOR S ENRGY FEoIRMEST, DEM"N AND ID6Se (F 19D KniNNCIMED SYST 1980 81 1981 al 1982 1983Mb 1984 1985 1990 1994 Sales, Thterated Siwtm -Gh Lw Voltage 1,416.3 1,485.8 Nb Data 1,687.7 1,801.2 1,923.5 2,675.2 3,487.8 115-kV or R4gber ) 30.5 85.9 99.3 116.2 117.4 117.4 Less than I ) 30*5 ) 62 32.3 23.3 14.3 14.3 14.3 Total Sal e 1,446.8 1,548.2 1,664.0J 1,805.8 1,923.7 2,054.1 2,8D6.9 3,619.5 !me Lost and ihUnaccnmted for - GWh Iw VolStge Nb Data No Data Nb Data 277.9 296.2 315.7 436.4 566.2 115I-k or Hig1er 6.5 7.4 8.7 8.8 8.8 Less tbwa 115-kn 4.9 3.5 2.1 2.1 2.1 Total lWa" 299.2 305.5 348.8 289.2 307.1 326.6 447.4 577.2 Net G/enati _ o Arnmil Generatin, GQh 1,746.0 1,853.7 2,012.8 2,095.0 2,230.8 2,380.6 3,254.2 4,196.7 Akn"nl Growth Rate, 1 7.3 8.6. 4.0 6.4 6.7 7.3 7.2 Amnlalt d Factor, % 65.1 66.1 63.4 66.0 66.0 66.0 66.0 66.0 NMain Deznld, W 305.5 320.0 362.2 363.6 387.2 416.2 564.8 728.4 Arual Growth Rate, 2 4.7 13.1 0.4 6.5 7.4 7.1 7.2 Total &nrgy Lcuses As a l of Total Sales 20.7 19.7 21.0 16.0 16.0 15.9 15.9 15.9 As a I of Generation 17.1 16.5 17.3 13.8 13.8 13.7 13.7 13.8 Pea Tos (Calwlal) te/ 1)6MM, NW 49 ! 52 .5 58 c/ 70.2 74.6 79.32 108.7 140.2 As a l of MxdinmDl)6zand 15.9 16.3 16.0 - 19.3 19.3 19.1 19.2 19.2 Estivasted E9amcmc Value of TAoss Esexgy @ B/. 0.0695%/IMI,$B3 19.69 24.2 22.10 2D.10 21.34 22.70 31.09 40.12 Capad4ty @ B/. 353/W, 17.30 18.36 20.47 24.78 26.33 28.00 38.37 49.49 a/ 198 to 1981 Actual fron bAlletln of Elctrical Satistics. Year 1981, by the Depertunt of Exegy ad Tariffs. 1983 data fron a operation eports, except as nO.- . b/ 1983 to 1994, Forecast of adm andDAs mal Net Eney r , 14 July 1982, in Ceneratio Master Pln, -y 1983 Revsio. 5!1 Fatimu*nB. d/ Inegrat system - kncli koown purdie. Base cn astieated tedvical loses. - 15 - ANNEC 3 DISTRIBUTION CIRCUIT ANALYSIS SUMMARY OF TEST RESULTS The test circuits detailed below include two rural and two urban circuits which gave good examples of significant loss reduction by adding capacitors, reconductoring or coverting to cdgher voltage. The remaiuing 29 circuits tested gave benefit-to-cost ratios that ranged from 10:1 to circuits where no significant loss reduction could be obtained. DISTRIBUTION CIRCUIT ANhLYSIS 1985 Loem Investiet Benefits Beneit-to-rCst kV $ $ Ratio 1. Cerr Viento Sub3tatipn Citrdt 8-63 Bse Coe 1,401 - - - lostanl capaitors 694 7,900 61,740 .-/ 79 Tnstall opitors acd recokiuctor 457 90,700 853,900 9.4 2. Santa Mari Substatlon Ctirwt 5>4# Bae Case 695 - -a - ReloCate exdStiz capaitors 586 2,000 153,50 77 RFACutor 425 25,000 370,900 15 lasta1l aiditial capaitors 341 39,000 473,0 12 3. C,rwaido Substation Bae Ce 8.1 - 'b/ Istal capacitors 6.0 5,450 15,000 2.9 4. stfttntfo Base Cm,e 2.4-kV 266 - -/ - Conxs1o to 4.16-W 37 48,000 820, 2D. - 15.8 Cer sionto 4.16, reoductor and add goscitors 19 59,000 870,000 14.6-/ a/ The gesent wrth of loses for a tw-ear padod, 1984-1986 only. F 7he esent worth of lnses for a five-year perWd, 1984-1989 only. c/ The fzesep t worth of loss for a four-year period, 1984-M 8 ony. I When the in4rerteAl ftestnt and benefits are amsidered for increasig maictor sie, the befit-to-cost ratio is 4.5. - 16 - ANNEX 4 REHABILITATION OF THE BLM THERMAL PLANT TERMS OF REFERENCE Instrument and Control Rehabilitation 1. The rehabilitation of the instrument and control systems on the BLM units is to be tendered based upon the terms of reference outlined herein as well as the bidders' assessment of any additional work elements which are believed to be required to restore these units to an efficient operating base. 2. The present status of the controls systems is such that a large percentage of the unit controls, recorders and supervisory instruments are either inoperative, missing, or inaccurate. As a result of this, many unit systems are regulated by hand operation rather than by automatic operation. This is especially true of the boiler combustion control systems. 3. It is necessary that the instrument and control systems of these units be overhauled, replaced and/or calibrated to permit them to operate at their proper design points. In order to achieve this, an instrumentation and controls contractor is to be retained to rehabilitate the BLM units. The tender is to be based upon an onsite inspection of the individual units and upon the partial list of work elements listed in Table 1. Some of the tasks are necessary on only one or possibly two of the three units whereas in other cases, the repairs are required on all three units. 4. It is mandatory that the bidding contractors visit and inspect the plant site to assess the degree and complexity of the rehabilitation work required to restore the units to satisfactory operating condition. The contractor is to supplemeat the work listed in Table 1 with additional tasks or work elements which he finds should be included to achieve satisfactory operation of the units. Detailed descriptions of the work proposed for each work element shall be included in the tender separately for the work listed in Table 1 and the supplementary work recommended by the contractor. 5. The eontraetors shall include in the tonder, the services of a field supervisor or service engineer, to oversee, supervise, and manage the base tender work and the supplementary work. The service cost for the tendered and supplementary work shall be quoted as separate items. 6. The contractor shall include as a work element, the furnishing of procedures for In place storage and protection of the controls and instrumentation during long periods of cold plant shutdown. The procedures shall allow for the climate and environment indigenous to Panama. 7. A comprehensive training program covering the repair and upkeep of the plant control systems shall be included in the contractors tender. A detailed description of the training program and its cost shall be included it the tender. 17 - 4 Page 2 of 3 TABLE 1 System Remarks Boiler air flow cotrls anl recorders Inoperatie on all t6.De wits. oplete sote trol litt reired iiicAidg recorders ard dharts. Tlrltre supervisory recorders asd irstru- RePir ard or rep lemit required on units 3 rents aid 4. Recardes are mlssit on unit 2. Biler 02 cats a rrs Ga sml aid alzig systemB to be replaced, all t-hree units. Stem pressure and teperatum anrols R tin rred oa aU three unit sstemo for auUwtis ctrol caqration. Calbrate all oantrol sigals to oearollers meral overall unit relacemet, repair and/ or ra rran aEofrt reeEirei. All three units. Repair and/or replaw and calibate mtssit Reqdred on all thre mits. cotrols, recorders ard ixdicators tkat plant. Prokr dirts are to be furdahbd by C004XVtors for we year's operatio for eadh unit. Provide cQtol fstems to sUp- All three units. port opratin ard umitoDrig of new lew esm air henr to be iretalied by otbOS. Czuloe fla seer syten replacemt with nw alanme aid essary air cool' aid sea" system are requtred to provlde co- stant udtodng of fam stablity on all bumers at all lads RelesWitation of hedpi and cidensat All tee units. pump xotrol systems for efficient, amae cOtrol of feIter yele. 8. The tenders shall include resume's of the personnel proposed for both the service engteer's position and the training program instructor's position. - 18 - ANNEX 4 Page 3 of 3 9. In addition, the basic daily rates for each classification of personnel proposed shall be included with a separate rate to cover the expenses of the contractors' personnel. 10. A plan and schedule for the implementation of the rehabilitation program shall form an integrated part of the contractor's proposal. 1I. The successful contractor shall warrant the quality of the equipment furnished for one year and shall repair or replace any and all devices which are found defective during the warranty period. In the event a device is furnished which does not function properly with the balance of the system, it shall be replaced on all BLM units at no cost to IRHE. - 19 - ANNEX 4(a) RERABILITATION OF THE BLM THERMAL PLANT TERMS OF REFERENCE Fuel Burner Replacereist 1. The Bahia Las Minas (BLM) units 2,3 and 4 boilers, were supplied by Franco Tosi of Italy with the basic boiler design being furnished by the Combustion Engineering Co. (U.S.). The fuel oil burners are a Peabody Engineering Co. (U.S.) design based on the technology and environmental requirements of the late 1960's. The units are identical in design and were installed in 1969, 1972 and 1974. 2. The present-day fuel oil burner designs are acknowledged to be far superior in quality when compared to earlier designs in emissions of gaseous pollutants and the efficiency of combustion of the fuels being fired by the burner. These improvements include the capability of the burners to burn the fuel efficiently at significantly reduced excess air values (at or less than five percent). In a similar manner, the improvement in the capability of electronically monitoring burner fires has also been greatly improved over the past 10 to 20 years. 3. Based upon current design criteria, it is requested that Peabody Engineering Co. Inc., tender the furnishing of 18 new design, high efficiency, low excess air burners based upon the same heat release and other design criteria as that furnished on the original BLM units. It is assumed that Peabody Engineering has on file the basic technical and physical data required to enable them to submit a responsive tender. 4. The tender sball include the furnishing of oil atomizers compatible with the existing fuel forwarding systems. This is to minimize the supplementary work required to incorporate the new burners into the existing plant and unit configuration. 5. Fuel oil ignitors shall also be included in the tender. The ignitor fuel is diesel oil as it was in the original design. Air operated piston drives shall be furnished to insert and remove the ignitors from the firing positions. 6. The flame scanning system is to be furnished by others, however, openings on the burners to position and support the ignitors shall be included in the supply of the burner. 7. A service engineer shall be included in the Peabody tender. The per diem service rate and expense rates shall be quoted in the tender. The service engineer shall supervise the removal of the o14 burners and the installation of the new burners and shall manage a crew to carry out the work. -20 - ANNEX 4(a) Page 2 of 2 8. An estimate of the boiler outage time required to remove the existing burners and to install new burners shall be included in the Peabody tender. An overall time schedule to perform all the work on one of the boilers shall also be included in the tender. 9. The tender shall include the predicted and guaranteed burner performance. The guarantees and warantees are to be valid for one year after installation. The data shall Include but is not limited to the following: (a) The operating value of the excess air level under which the boilers can safely operate at all loads, (b) The expected carbon losses over the operating range of the boiler, (c) The burner turn down ratio, (d) Expected nitrogen oxide and carbon monoxide emissions. 10. Operating and maintenance procedures manuals shall be included with the material furnished. Spanish would be the preferred language of these documents but this not mandatory. 11. Peabody shall include a training prograA in their scope of services covering the operation of the burners with the operating department and the maintenanee of the burners with the maintenance personnel. These programs would be best handled in Spanish. 12. In the event a device proves deficient, defective or Incompatible with existing systems in the fuel handling train, Peabody shall furnish new devices on any and all duplicate parts for each burner on all three boilers. - 21 - ANNEX 4b REHABILITATION OF THE BLM THERMAL PLANT TERMS OF REFERENCE Air Preheater Seal Repairs 1. The regenerative type air preheaters installed on the four Bahia Las Minas (BLM) boilers use a design (air) seal which should be adjusted and eventually replaced if the seal wear is beyond the adjustment range. These seals are to be inspected by a field engineer of the Air Preheater Corp., Inc. (U.S.) to ascertain their condition and the need for either adjustment or replacement. If the seals only require resetting, this shall be done by the inspecting engineer. 2. Air Preheater is requested to inspect the airpreheater on the four BLM koiler units and to advise as to the condition of the seals. In the event the seals need replacement, the field inspection report shall include a quotation to furnish and supervise the installation and setting of new seals. TRANSMISSION AMD DISTRIBUTION TECHNICAL'SUPPLEMENT TO PROJECT'IDENTIPICATION'REPORT CURRENCY EQUIVALENT Currency Unit - Balboa (Bl.) US$1.00 = B/.$1.00 UNITS Thousand circular mills (kcmil) = 1.94 sq.mm. 1 meter (m) = 3.28 feet 1 kilometer (km) - 1,000 meters 1 kilovolt (kV) 1,000 volts 1 kilowatt (kW) a 1,000 watts 1 megawatt (NW) - 1,000,000 watts 1 kilovolt ampere (kVA) - 1,000 volt-amperes Imega volt-ampere (MVA) 1,000 kilovolt-amperes 1kilovolt-ampere reactive (KVAR) - 1,000 volt-amperes reactive 1 mega volt-ampere reactive (MVAR) - 1,000 kilo-volts ampere reactive 1 Gigawatt-hour (GWh) - 1 million kilowatt-hours ELECTRICAL CHARACTERISTICS Frequency = 60 Hertz Secondary Distribution and Service Voltages - 240/120, 208Y/120, 240, 480Y/277 volts Primary Distribution Voltages 3 2.4, 4.16Y/2.4, 6.6, 13.8Y/7.96 34.5Y/19.9 kilovolts GLOSSARY AND ABBREVIATIONS IRHE - Instituto de Recursos Hidraulicos y Blectrificacion OA - Self-cooled transformer rating FA - Fan-cooled transformer rating FOA - Forced oil (pumped) transformer rating AAC - All aluminum conductor ACSR - Aluminum conductor, steel-reinforced AWG - American Wire Gauge FI3CAL YEAR (FY) Begins January 1 and Ends December 31 TABLE OF CONTENTS . ~ ~ ~ ! 2 Page No. CHAPTER I - INTRODUCTION .......................I.............. 1 CHAPTER II - EXISTING AND FORECAST SYSTEM LOSSES ................... 1 CHAPTER III - LOSS ANALYSIS 4 Areas of Study 4 Methodology 5 Methods of Loss Reduction 5 Assumptions 6 Cost of Modifications .........................,......... 6 Long Run Marginal Costs .........................,.......... 6 Marginal Peak Capacity Cost 7 Marginal Energy Cost 7 Economic Analysis 8 Time Period 8 CHAPTER IV - RESULTS 8 Avenida Sur Power Plant and Substation 9 Santa Maria Substation Feeder 5-43 .....o..o.o..o.o......,.. 10 Cerro Viento Substation Feeder 8-63 o..........oo..o..o...o. 12 Coronado Substation Circuits, 15-17 and 15-25 *............. 12 Santiago Substation Circuit 3 0........................... * 12 Santa Maria Transformer Losses ...........oo....o........... 15 Conclusions .o......o...o .o0.o.....o.o...oo....o...o.. o,o* 15 CHAPTER V - OBSERVATIONS ...............e,.............,........ 18 CHAPTER VI - REVENUE METERING oo...........o....o.o.o...o.....o.o.o.o 19 CHAPTER VII - FUTURE LOSS REDUCTIONS...o..o.....o.o...o...e........So 21 Technical Losses 21 Non-technical Losses ....oo ..oo *** ***0* o***00o.o. 24 CHAPTER VIII - RECOCMNDATIONS........O.............. .....o.. 25 - il - Page No. LIST OF TABLES IN TEXT 2.1 Existing and Forecast Energy Requirements, Demand and Losses of the Interconnected System......,..... 2 2.2 System Loss Distribution, 1982.,..........@............ 3 2.3 Energy Distribution Maranon Substation, Metropolitan .............................. ............... 3 4.1 Loss Analysis - 2.4-kV and 4.16-kV Systems, Avenida Sur Power Plant and Substation .......................9....... 9 4.2 Loss Analysis - Feeder 5-43, Santa Maria Substation, Metropolitan District ..............................o..... 11 4.3 Loss Analysis - Feeder 8-63, Cerro Viento Substation ....... 13 4.4a Loss Analysis - Feeder 15-17, Coronado Substation, Panama, Occidente District ............................ 14 4.4b Loss Analysis - Feeder 15-25, Coronado Substation, Panama, Occidente District ............ooo.e ... ................ 14 4.5 Loss Analysis - Feeder 3, Santiago Substation, Province of Coele Veraguas ........................................... 16 4.6 Loss Analysis - Santa Maria Substation and Feeders ......... 17 7.1 Estimated Distribution System Loss Reduction ............... 23 7.2 Comparison of Losses in 230-kV Transmission Line............ 24 ANNEXES 1. Summary of Circuits Analyzed, Instituto de Recursos Hidraulicos y Electrificacion ............................ 28 2. Adopted Unit Costs ......................-.......e.... . 30 3. Typical Computer Printouts 31 4. Long Run Marginal Costs for Valuation of Technical Losses in Panama Electrical Distribution System 51 5. Substation Metering ..........57...... , 57 PANAMA UNITED NATIONS DEVELOPMENT PROGRAMME POWER SYSTEM LOSS REDUCTION TRANSMISSION AND DISTRIBUTION TECHNICAL SUPPLEMENT TO PROJECT IDENTIFICATION REPORT CHAPTER I INTRODUCTION 1.01 This report is the Transmission and Distribution Technical Supplement to the Project Identification Report and reviews the power and energy losses in the distribution system of the Instituto de Recursos Hidraulicos y Electrificacion (IRHE). CHAPTER II EXISTING AND FORECAST SYSTEM LOSSES 2.01 An analysis of existing system losses is shown in three different ways in the following tables. Losses on an overall system basis are shown in Table 2.1. For the years 1980 to 1982, energy lost or unaccounted for is 15% to 17%. Although not shown, losses for the years 1977 to 1980 averaged 16% per year. Table 2.1 also includes a calculated peak demand loss, an indicator of how much generator capacity is required to supply losses. 2.02 Table 2.2 is an order of magnitude estimate of the 1982 energy and peak power loss in different segments of the system. This includes data obtained as part of the loss analysis discussed later. Note that approximately 28% of the energy lost can not be accounted for and is presumed to be lost due to theft, metering or billing errors. 2.03 Table 2.3 presents data on energy losses from a special study initiated by the Metropolitan District Office of IRE, in part of the area supplied by Maranon Substation. To the data already collected, estimated energy losses based on a partial feeder analysis of the circuits from Maranon substation and estimated no-load and load losses based on the connected distribution transformers have been added. TAKE 2.1: Ezdtig and Forecast Knewy Re.uraiDnts. Deid and loses of the System 1980 A 1981 at 982 1983 1984 1985 1990 1994 Sabo, hteated S G9B -h 1aw Voltag 1,416.3 1,485.8 No Data 1,606.6 1,801.2 1,923.5 2,675.2 3,487.8 11! w 30eg5)r 62.4 ' 85.9 99.3 116.2 117.4 117.4 Iess than l15-W ) _ 32.3 23.3 14.3 14.3 14.3 Total Sales 1446.8 1,548.2 1,6564v0 1,805.8 1,923.8 2,054.0 2,806.9 3,619.5 Eoexr Lost and Unacci_mte for - GWh Lw Vol±tg No Data No Ldta No Data 277.9 296.2 3L¶.7 436.4 566.2 115-WK or Higher ' '9 6,5 7.4 8.7 iŽB 8.8 less than 115ky _ 4.8 3.5 2.1 2.1 2.1 Total TIsEem 299.2 35.5 48 292 307.1 326.5 447.3 577.1 Net Generatton aI h Ammal G-nration, GWh 1,746.0 1,853.7 2,012.8 2,095.0 2,230.9 2,380.5 3,254.2 4,196.6 Anral Grth Rate, z 7.3 8.6 4.0 6.4 6.7 7.3 7.2 Amnul Tosd Factor, % 65.1 66.1 63.4 66.0 66.0 66.0 66.0 66.0 ,dimmDemunoi, NW 305.5 320.0 362.2 363.6 387.2 416.2 564.8 728.4 Amua Grcwth Rate, 2 4.7 13.1 0.4 6.5 7.4 7. 7.2 Tota l &er8gr Los As a X of Total Sales 2D.7 19.7 21.0 16.0 16.0 15.9 15.9 15.9 As a Z of Geeratia 17.1 16.5 17.3 13.8 13.8 13.7 13.7 13.8 Pe& tLss (Calwlated) e/ Demand, lf 49 c 5258 58 0j 70.2 74.6 79.32 108.7 140.2 As a % of Himadun Daunx 15.9 16.3 16.0 - 19.3 19.3 19.1 19.2 19.2 Estimated Ewconcic Val= of lAsses Ekergy Q E/. OXM095/kiw, B/al 19.69 21.48 24.20 20.10 21.34 22.70 31.09 40.12 Capacity @ B/. 353/W, W/1K 17.30 18.36 20.47 24.78 26.33 28.00 38.37 49.49 0L 1980 to 1981 Actusl fron Thlletin of MeUietrcal Satistic. Year 1981, by the Depatrent of Energy and Tariffs. 1983 dta from operat'on roorts, exIpt Es ncted. b/ 1983 to 1994, Forecast of Mtmum Damemds avd Armal Net Eng Requirements, 14 July 1982, in Generation Master Plan J 983 RevIls__ C Esthkd. d tegrated SyBtem - 'Incxe8s knan pudums. Based an es8 teduical losss. Table 2.2. System Loss Distribution, 1982 System Peak Demand - 1982 362 MW 1,664 GWh Transmission, Subtrnsdmission and Substation Loss a, 16 MW 66 GWh Primary Distribution Lines - Demand Loss Metropolitan Area 13 MW 53 GWh Rural Area 7 Mw 29 GWh Distribution Transformers - Demand Loss Metropolitan Area 7 MW 41 GWh Rural Area 4 MW 17 GWh Secondary Distribution Lines Services Metropolitan 8 MW 33 GWh Rural 3 MW 12 GWh Total Technical Losses --n MW 251 GWh Unaccounted - 97 GWh Total 348GWh a/ From an internal IHRU report covering the period January to June 1982 and slightly modified to reflect maximum demand for 1982. Table 2.3: Energy Distribution Maranon Substation, Metropolitan Districta/ L I Sal l s Month Resi- Corner- Thdzm- Govrm- Llft- Adast- aIe Prfmin Transformers Enery Lot & Lf Energy 198 dential cia try mn¢ ip Subtotal LImsaw No tlod toad Total Semd Out Unwe:mtew Sent Out Jue 2,193 7,545 634 4,627 78 557 14,520 60 357 103 15,040 19,255 4,215 21.8 July 2,263 7,883 632 4,574 78 593 14,837 59 357 101 15,354 19,361 4,013 20.7 August 2,320 8,060 630 5,112 78 591 15,609 64 357 109 16,137 19,89% 3,757 18.8 Septen*er 2,28 7,749 632 5,418 78 573 15,536 65 357 110 16,066 19,421 3,355 17.3 October 2,252 7,736 599 4,683 78 540 14,775 63 357 105 16,300 19,457 4,157 21.3 Noeifrer 2,263 7,468 634 4,691 78 548 14,586 66 357 114 15,123 18,759 3636 19.4 OVeral 93,020 116,155 23,133 19.9 a/ AUl data In mnzatt hmr. b/ i#ng use caloihted. Miusbet to reconc meter data with substatim sevice area. d/Bd an primuy Use low analysis calwlatios. e Bas on awesk W/VA oaed, no loed toas and cormected trmsformer caquity. Tncludes estimate for 13.2-W to 2.4-W -soi,ftiruem at Amwnda Sur Pser Plan and Substation. f/ Incldes seoehay ditribzio and service loss-. -4- 2.04 Future system losses for selected years, as shown in Table 2.1, have been taken from the projections used for planning the requirements for future generation. These values are based on a percentage of sales based on historical system loss data. The continued use of high values of energy that is lost and unaccounted for would seem to imply that no attempt will be made to reduce losses. In addition, the projections do not appear to consider the changes that will occur in transmission losses with the proposed new hydro- electric projects. Operation of La Fortuna Hydroelectric Plant in 1985, for example, will increase the total 230-kV transmission peak demand loss from the present 2.3 MW to 33 MW along with an increase in energy losses of 75 GWh, which is substantially higher than data shown in Table 2.1. 2.05 The value of 1981 energy that is lost or unaceounted for in fuel alone is $19.61 million and in 1982, $24.2 million. A rough estimate of the value of IRHE's future losses, based on long run marginal costs, is also shown in Table 2.1. Depending on the approach taken, the value of these losses is a very high operating cost or, alternatively, represents a major loss in revenuee CHAPTER III LOSS ANALYSIS 3.01 The purpose of the loss analysis is to identify areas where loss reduction might be achieved. Complete analysis of all of the power system is not contemplated. Instead, sample areas and distribution circuits that appeared representative, with certain exceptions, were selected as test cases. The analysis is limited normally to evaluating technical losses in the primary circuit itself and does not Include distribution system transformers, secondary distribution, services or the losses attributable to theft or billing errors (although these have been estimated in some cases). The corrective action considered to reduce losses in each test case may not be the optimum solution due to assumptions made and the lack of time for a detailed analysis of all possible options in each individual circuit. The intent is to demonstrate that system losses can be reduced through a series of examples. Areas of Study 3.02 Circuits selected for loss analysis were selected principally from the Metropolitan District (Panama City and the adjacent area). The largest number of IREE's customers and the greatest part of IRHE's energy sales are in this district. Load in this district is a mixture of single family residential, large apartment buildings, new office buildings (8 to 16 floors), commercial, warehousing and light industry. A substantial component of load appears to be air conditioning. This area had the advantage that it could be readily inspected and some load data was available. 3.03 In additiou, analysis was made on two circuits in the Panama Occidente District and one in the Cocle-Veraguas District. Two are essentially rural 13.8-kV feeders; the other a small city supplied at 2.4- kV. The latter circuit was selected as an example of loss reduction that could be obtained by changing voltages. A summary of the circuits considered is in Annex 1. -5- Methodology 3.04 The methodology used for making a technical analysis consists of preparing a computer model of the circuits to be analyzed. The computer model requires data on circuit length, type and size of conductors, comnected distribution transformer capacity and for each feeder maximum demand, voltage, load factor and power factor at the substatiou. The computer allocates total feeder load along the circuit proportional to the connected transformer capacity. The computer then calculates the existing losses and future losses using forecast load growth. The computer model can be modified to simulate the addition of capacitors, changing conductor sizes, shortening the circuit or changing voltage levels. The computer also calculates the percentage conductor loading and voltage at different points on the feeder since these limit circuit capacity. Typical computer printouts of circuit analysis may be found in Annex 3. 3.05 Using suitable costs for capacity and energy, the present worth of losses can be calculated for the time period under consideration. Also present worth of construction and material costs for each modification can be calculated, so that benefit-cost ratios cau be determined. Methods of Loss Reduction 3.06 Power and energy losses can be reduced by one or more of the following procedures: (a) changing to a larger size conductor (b) installation of shunt capacitors (c) shortenuig a circuit by transferring load to another less loaded circuit (d) changing to a higher circuit voltage (e) balancing loads (equal load per phase) 3.07 In this study the three principal methods considered were changing conductor size, installing capacitors, and changing voltages. Shortening a circuit or transferring load depends on the physical arrangement of the distribution system and requires a more detailed study than was feasible under the present study. Installation of capacitors on the high voltage distribution circuits usually provides the greatest benefit. Alternatives are large banks of capacitors at a substation bus or, for motor loads, small individual capacitors for each motor but at a higher cost and lower benefits. For this study 300 to 1,200-kVAR capacitor banks were used as the basic size. Larger capacitor bank sizes are available at a lower cost per unit as the bank size increases. The local standard conductor sizes of 1/0 AWG (53 sq.mm.), 266.8 kcmil (135 sq.mm.) and 477 kciil (240 sq.mm.) ACSR (aluminum conductor, steel reinforced) have been used where reconductoring has been considered. -6- AssumptioPs 3.08 Circuit lengths were scaled from distribution system maps. The short branch circuits along with the effect of conductor sag were ignored. Circuit electrical characteristics were obtained from IRHE and are the same used in earlier studies conducted by MRUE. 3.09 The number of connected transformers were also taken from distribu- tion maps; however, maps for the Metropolitan District are approximately 3 years old and have not been updated. Where discrepancies in the larger trans- former sizes were noted these were reconciled by checking with the pertinent District, at the same time the status of existing capacitors was field checked. 3.10 Existing circuit load was derived from thermal demand ammeter readings in the distribution feeders. A few circuits in the rural areas also included kilowatt-hour meters with demand attachments from which kilowatt demand data could be obtained. 3.11 Load factor and power factor data is also limited. Load factors in the Metropolitan District were derived in part from 10 day spot readings of transformer loading, substation load curves and judgment. Some circuits in the rural areas had adequate instrumentation to calculate load and power factors, however, readings are not taken. The substations in the Metropolitan area supply a large amount of air conditioning load and industrial load and it is believed that individual feeder power factors may be much lower than the ones used in this study, which would imply that more capacitors could probably be added than is shown in some of the test results. 3.12 Although load forecasts for overall areas were made as part of the development of a master plan for the Metropolitan area and for the proposed master plan of distribution system improvements, detailed data on a feeder-by- feeder basis was not available. In general, in the Metropolitan District, 7% load growth was used for the years 1983 to 1987 and 6% thereafter. In the rural areas, load growth varies between 7% and 1¢%. Cost of Modifications 3.13 Data for estimating the cost for distribution circuit modifications was obtained from IRUE, except the cost of capacitor and accessories which are based on current prices from UoS. manufacturers. The unit cost data is summarized in Annex 2. Long Run Marginsl Costs 3.14 The economic long run marginal cost (LRMC) reflects the economic resource cost of the incremental supply facilities that would be required to provide an incremental unit w.gn demand is constrained by the existing available supply facilities. Marginal capacity cost is determined by the incremental investment and the associated fixed operation and maintenance costs of the incremental capacity related supply faeilities. The incremental capacity related investment is that which over the planning horizon appears to -7- be most sensitive to changes in the incremental power demand and also constitutes the least-cost means of providing the incremental peak kilowatt demand. 3.15 Long run marginal cost of energy is determined by marginal fuel and variable operation and maintenance costs of the marginal generating plants required to provide the incremental kilowatt-hour. Marginal Peak Capacity Cost 3.16 Of the various alternative sources of providing the incremental capacity, analysis shows that the Changuinola hydroelectric scheme appears as the cheapest alternative that the system planners would adopt. 3.17 The relevant costs for derivation of LRMC of peak capacity for valua- tion of peak kilowatt losses are the investment and fixed operation and main- tenance costs of the power house, electro-mechanical equipment and associated transformation and transmission facilities (kilowatt related incremental facilities) of Changuinola and the investment, fixed operation and maintenance costs of the incremental additions to the network included in the "optimum' investment program for Panama from 1983 to 1993. 3.18 All costs are expressed in constant 1982 prices and in economic terms to reflect the economic value of scarce resources. Using a 12% discount rate as the opportunity cost of capital to Panama, the long ron marginal capacity cost is estimated at 192 B.lkW/year at the generation level and 353 B./kW/year at the distribution voltage level. Marginal Energy Cost 3.19 Marginal energy cost is based on TRHU's generation planning program from 1983 to 2000 with generation system simulation under average hydrological conditions which shows "optimal" ranking of plants to meet energy require- ments. From the generation program, marginal generating plants that would be needed to provide energy at critical periods are identified. The gas turbine recently installed at Panama Sup?ytation and the Pielstick diesels appear as the most likely marginal plants_ 1/ For additional data, see the Technical Supplement, Generating Plant. 3.20 'tslang probability estimates of thermal generation, a probability weighted fuel cost is determined for each year. Marginal energy cost is made up of fuel, variable operation and maintenance costs. 3.21 The international border price of fuel as opposed to the price paid by IRHE is used to reflect the economic cost of fuel since the actual price paid by IRHE includes transfer payments which do not constitute economic resource cost. 3.22 The marginal energy costs, based on international fuel prices of B/. 171 per ton for Bunker C (heavy fuel) and B/. 280 per ton for diesel, are B/. 0.0165 per kWh at the generating plant and 8/. 0.069 per kWh at the medium voltage level. Detailed discussion of the long run marginal costs is given in Annex 4. Economic Analysis 3.23 The basis of the economic analysis Is the trade-off between increased distribution costs for investment in circuit improvements to reduce losses and the value of the reduced losses. Both peak kilowatt and kilowatt-hour losses are valued at their respective long run marginal costs. Investment costs are expressed in constant prices of a base year and shadow priced to reflect the economic value of resources. A benefit-to-cost ratio test is performed by comparing the discounted present value of losses to the discounted present value of the investment requfred to reduce the losses. Normally to determine an o;otimal distribution system, the analysis is continued until all technically feasible loss reducing options have been tried and accepted or rejected. Time Period 3.24 Normally, a ten-year period starting in 1985 has been used in prior studies for the period in which losses were calculated and evaluated. For this study, the time period used for economic analysis has varied from circuit to circuit. A two to four year period starting in 1984 has been used principally in the Metropolitan District as load growth is high and existing circuits are approaching their capacity and will soon have to be changed physically. Further, circuit modifications must be made to accommodate new substation transformers thet will be installed In the next few years. As a result because of these changes, it is not feasible to run an extended time analysis, particularly where conductor changes have been considered. CHAPTER IV RESULTS 4.01 The results of the analysis are summarized in the following tables. The base case referred to in the tables represent the losses that would occur -9- if no corrective action is taken to reduce losses and is used to compare the benefits obtained by reducing losses. Avenida Sur Power Plant and Substation 4.02 A complete loss analysis of the 2.4-kV and 4.16-kV circuits from this substation was not made other than computing losses for the year 1982. The most likely method of reducing losses in this system is a change in voltage and a complete reconstruction of the system (conversion of a small part of the existing 4.16-kV is already included in the 1983-1986 distribution system expansion program). The existing 2.4-kV system and most of the 4.16-kV system is underground and is understood to be in poor physical condition. A replacement system would be an extension of one of the 13,8-kV circuits from Maranon Substation. The time required for a preliminary engineering design and cost analysis for a conversion is beyond the scope of this study. The estimated value of the existing 1982 losses, including the existing 13.8 to 2.4-kV or 13.8 to 4.16-kV step-down transformers at Avenida Sur, and the reduction in losses by converting to 13.8-kV is shown in Table 4.1. The principal point at this analysis is that a significant source of losses originate in the step-down transformers. Table 4.1: Loss Analysis - 2.4-kY and 4.16-ky Systems Avenida Sur Power Peant and Substation Existing After Conversion 1982 to 13.8-kV 1. Distribution Feeder Loss Demand 2.4-kV System 20.2 kW 0.6 kW 4.16-kV System 28.7 kW 2.6 kW 2. Stepdown Transformers Loss Demand ai No LoMd Loss 53.9 kW - Load Loss (peak demand>}I 54.9 kW - 3. Energy Losses of Losses:b. Distribution Feeders - kWh 98,500 kWh 6,450 kWh Transformers, No Lo#b 472,200 - Transformers, Load- 110,600 - 681,300 kWh 6,450 kWh 4. Estimated Value:AI Capacity B/. 55,668 B/. 1,130 Energy 47 350 448 B8. IO31W B/. 1,537 a/ Based on the following transformers: two 1 500 kVA, 4.16-2.4 kV; three 3,000 kVA 13.8-4.16 kV; one 3,000 kVA 13.8-2.4 kV; and, two 3,000 kVA 4.16 kV grounding transformers. b/ Load Factor - 40X, Loss Factor - 23%. c/ Transformer loss demand is 0.6 of transformer rated loss. / Based on long run marginal cost. - 10 - 4.03 Since the Avenida Sur Power Plant is, scheduled for retirement in 1985, conversion of the existing system to 13.8-kV, in addition to loss reduction, could be justified on elimination of a step-down substation, which would then permit disposing of the old power plant and substation. Santa Maria Substation Feeder 5-43 4.04 Several different alternatives were considered for this circuit. The circuit, as is, consists primarily of 32 km of predominantly 477 kcmil ACSR and 1/2,AWG ACSRVJ conductor, heavily loaded and with three existing capacitor banks.±' The initial base case analysis indicated a large kVAR requirement and low circuit voltage. The circuit was reanalyzed by letting the computer program selec the optimum location for the existing capacitor banks. At the new location - and for a relatively low cost, substantial savings in losses are obtained as indicated in Table 4.2. 4.05 The initial analysis also indicated two segments of the existing line were approaching the limit of their thermal capacity. These two segments also contributed approximately 25 percent of the line loss. Replacement of the existing 1/0 AVG ACSR with 477 kcmil ACSR (or AAC) also gives a substantial reduction in peak loss demand. 4.06 Two other alternatives were considered-reconductoring and relocating existing capacitors and adding capacitors. Each change produced a positive benefit. Note that additional circuit capacity was made available and circuit voltage improved by these changes, particularly cases 4 and 5, Table 4.2. 4.07 From a practical standpoint, the relocation of the existing capacitor banks is the most feasible. Reconductoring does not appear feasible until 1984. A long range economic analysis is not feasible due to the changes that will be required to reduce circuit loading and other modifications that may be made when the third substation transformer is added at Santa Maria Substation. Annex 3 includes computer runouts showing changes in losses by the addition of capacitors or load reduction on other circuits supplied from Santa Maria Substation. 1i The designation ACSR (aluminum cable steel reinforced) has been used throughout this report for conductor type; however, AAC (all aluminum conductor) is also in use. 2/ Two banks are rated 600 kVAR each and are adjacent to each other. These have been treated as a single 1,200 kVAR bank in this study. The other is 900 kVARO 3/ New location are for the 1,200 kVAR banks is 8.1 km from the substation and for the 900 kVAR bank, 8.8 km from the substation. Table 4.2s Loss Analysis - Feeder 5-43. Santa Karia Substatton Metropolitan Dtstrict Present Worth Number 1983-198S Case 1982 1983 1984 1985 Balboas 1.* Base Case - Existiag Circuit. Including Cavacitors a/ Demand, kVA 7,098 7,729 8,423 9,189 -/ Demand, kW 6,459 6,958 7,502 8,096 Energy, MWh - 33,962 38,773 41,843 Losses, kW 418 494 585 695 554,340 Louses, kWh - 1,817 2,152 2,557 402 915 Total Present Wortb Losses ,zxz Minimu Voltage, kV 12.6 11.9 11.8 11.6 2. Relocation of Existing Capacitor Banksb/ Demand, kVA 7,627 8,342k/ 9,045 AS Denand kW 6,879 7,409 7,987 Energy, MWb 35,553 38,293 41,280 Louses, Id 414 492 586 466,115 Louses, MWh 1,523 1,810 2,56 337.640 Logs Reduction % 16 16 16 Present Worth, Losses 803,755 Present Worth, Savings 153,500 Investment 1,980 Benef,t-to-Cost Ratio 77 Minisin Circuit Voltage, kV 12.2 12.0 11.9 3. Reconductorins 1.8 km of Line A Deand, kVA 7,530 8,183 8 898 Deand, kW 6,769 7,276 7,825 Energy, MWh 34,985 37,605 40,443 Losses, Id 30.1 339 425 340,060 Lo4seds, uih 1,119 1,321 1,564 246,335 Lose Reduction Z 38 39 39 Present Worth, Looses 586 395 Present Worth, Savings 370,860 Tnvestasat 24,720 Beaefit-to-Cost Ratio 15.0 Minlmum Cir¢uit Voltage, kV 12.4 12.3 12.1 4. Reconductorlng and Relocating Existirg Capacitor Banks Demand kVA 7,478 8,122 8,826 Demand, kW 6,741 7 244 7,788 Energy, MWh 34,840 37,440 40,251 Louses, kIW 276 327 387 309,400 Losses, 1Wh 1,016 1,203 1,440 224.120 Loss Reduction 2 44 44 44 Pramnt Worth, Losses 533,520 Present Worth, Savings 423 735 I,vestment 26 700 Benefit-to-Cost Ratio 15.9 Mlinium Circuit Voltage, kV 12.6 12.4 12.3 5. AdditiOn of 1,200 kVAR Capacitor Banks to Case 4 e/ Demand, kVA 6,992 7,591 8,251 Demand, kW 6,710 7,205 7,742 Ensrgy, MMh 34,680 37,238 40,013 Losses, km 245 289 341 273,530 Losses, MWh 901 1,063 1,255 210.425 Loss Reduction 50 51 51 Present Worth, Louses 483 955 Preseat Worth, Savings 473,300 Investment (Including Case 4) 39,000 Benefit-to-Cost Ratio 12 MNninun Circuit Voltage. kV 12.8 12.7 12.5 a? Assumptions: (1) Load Factor - 592, (2) Loss Factor - 422, (3) Base Case - Power Factor - 912, (4) Load Growth - 72 per annum. / Existtig Capacltors No. 1 - 900 kVAR bank; Capacitors No. 2 - two 600 kVAs banks essentially at the same location. Si Feeder cable at substation overloaded. Existing ACSR segment of line ls loaded to approximately 902 of therbal capacity. Assumed raconductoring is 477 kcail ACSW.. eJ Svitched capacitor bank. - 12 - Cerro Viento Substation Feeder 8-63 4.08 This 13.8 kV circuit, due to its length (88 km) and loading, was found to have one of the highest peak demand loss. In addition, voltage levels are very poor, although the circuit has two existing capacitor banks and two voltage regulators. The loss analysis summarized in Table 4.3 indicated a high kVAR flow and one 5.6 km segment of line with 165 kW of peak loss. The lose analysis indicates that installation of an additional 1,200 kVAR capacitor bank in 1983 will pay back the cost within two years, however, circuit voltage would still be low. Simulating reconductoring the worst section of line consisting of 5*6 km of 1/0 ASCR with 477 kcmil ACSR provided additional loss reduction and voltage improvement. These are summarized in Table 4.2. 4.09 Several other variations are feasible on this circuit such as reconductoring an additional 5.5 km of line, or the further addition of capacitors after 1985, however, they were not considered in this loss analysis. Coronado Substation Circuits. 15-17 and 15-25 4,10 Loss analysis on these two 13.8 kV circuits indicated a 1982 peak demand loss of 5.4 kW on circuit 15-17 and 9.9 kW on 15-25. Although the peak demand loss is low, a 5-year analysis (Table 4.4), indicates that a 600-kVAR capacitor bank in circuit 15-17 and 300 kVAR bank in circuit 15-25 will reduce losses and that the savings in losses will recover the cost of the capacitor banks in about four years. The analysis indicates that loss reduction on lightly load circuits may be justifiable. Santiago Substation Circuit 3 4.11 Project CV-CPI-05-83/86 which is part of the 1983-1986 distribution program proposes to convert the 2.4-kV circuit serving part of the City of Santiago, Province of Veraguas, to 4.16-kV. Included as part of this project is reconductoring approximately 3 km of the 13 km-long circuit with 266.8 kcmil ACSR. A related project is the installation of a large capacity 34.5- 2.4/4.16-kV transformer, voltage regulators and additional switch gear at the Santiago Substation. 4.12 A loss analysis made on this circuit indicates a remarkable reduction in peak demand loss by the change in the circuit voltage from 2.4-kV to 4.16-kV. The savings that will result are more than enough to pay for the project within a year. Because of the high growth rate of 10%, voltage drop, even at 4.16-kV and with heavier conductor in several years is excessive. - 13 - Table 4.3: Loss Analysis - Feeder 8-63, Cerro Viento Substation Present Worth Number 1984-1985 Case 1982 1983 1984 1985 Balboas 1. Base Case - Existing A/ b/ Demand, kVA 5,226 5,839 6,614 7,790 Demand, kW 4,508 4,937 5,466 6,244 Energy, MW 23,299 25,515 28,249 32,274 Losses, kW 555 706 939 1,401 773,032 Losses, MWh 2,599 3,456 5,155 559,965 Total Present Worth, Losses 1,332,997 Minimum Voltage Level, kV 11.3 10.6 9.6 8.1 2. Installing one 1,200 Capacitor Bankb/ Demand, kVA 5,452 6,063 Demand, kW 5,083 5,537 Energy, MWh 26,269 28,619 Losses, kW 556 694 415,002 Losses, MWh 2,045 2,552 300,617 Present Worth, Losses 715,619 Loss Reduction % 41 50 Present Worth, Savings 617,378 Investment in 1984 7,855 Benefit-to-Cost Ratio 79 Minimum Voltage Level, kV 11.9 11.2 3. Installing one 1,200 Capacitor Bank and Reconductor 5.6 km with 477 kemil ACSR Demand, kVA 5,445 5,777 Demand, kW 4,906 5,301 Energy, MWh 27,074 29,253 Losses, kW 379 457 277,824 Losses, MWh 1,560 1,881 201.248 Loss Reduction Z 60 67 479,072 Present Worth, Savings 853,925 Investment in 1983 7,855 Investment in 1984 82,835 Benefit-to-Cost Ratio 9.4 Minimum Voltage Level 12.8 12.3 a/ Assumptions: (1) Load Factor - 59%, (2) Loss Factor - 42%, (3) Base Case Power Factor - 86%, (4) Load Growth 7% per annum. b/ Includes one 900 and one 1,200 capacitor bank and two banks of voltage regulators. - 14 - Table 4.4a: Loss Analysis Feeder 15-17. Coronado Substation Panama. Occidente Distrtet Year 1983 1985 1989 1. 9ase Case Demand, kVA 1,124 1,287 1,665 Demand, kW 899 1,030 1,329 Eaergy, MWh 3,325 6,866 Losses, kIW 6 8 14 Locees, MWh 30 50 Minimum Voltage Level, kV 13.5 13.5 13.4 2. Installing One 600-kVAR Ca acitor lank (lnsuitched) Demand, kVA 1,041 1,383 Demand, kW 1,028 1,325 Energy, MUh 5,314 6,844 Losses, kW 6 10 Losses, MWh 22 38 Loss Reduction % 25 28 Minimum Voltage Level, kV 13.6 13.5 3. Economic Analysis a/ Capaeity Energy Total Present Worth of Losses, 1983-1989 Balboas Base Case 20,350 14 740 35,090 With Saving Capacitor Bank 11,065 8,6200 19,085 Present Worth of Savings, 1985-1989 16,003 Investmant 3,800 lenefit-to-Cost Ratlo 4.2 Table 4.4b: Loss Analysis Feeder 15-25. Coronado Substation Panama. Occidente Districet Year 1983 1985 1989 oBase Case - Demand, kVA 975 1,120 1,451 Demand, kW 780 895 1,157 Eergy, MMh 4,031 4,626 5,982 Losses, kV 11 15 25 Losses, MRh 40 55 93 Minimum Voltage Level, kV 13.3 13.2 13.1 2. Installing one 600-kVAR Capacitor Bank (naswitched) Demand, kVA 963 1,268 Demand, kV 890 1,139 Energy, MWb 4,602 5,888 Losses, kW 10 18 Losses, MII 38 66 Loss Reduction 2 33 26 Minimum Voltage Level, kV 13.4 13.3 3. Economic Analysis ~Cayattv Energy Total Present Wortk of Losses, 1985-1989 Balboa Base Case 27,600 19,990 47,590 Including Cpseitor Bank 19,220 13,293 32,515 Present Worth of Savings, 1985-1989 15,015 Investnt 4,900 Benefit-to-Cost Ratio 3.1 Ay hsmpw td Fac U 5U Lss Fator - 421t Lod QCctsh Rate 72 per aa tqle to 6? In 198 - 15 - 4.13 Alternate studies were made simulating the addition of capacitors and reconductoring on the first 3 km of line from the substation with 477 kemil ACSR which obtained a further reduction in loss. Note that the incremental cost of B/. 6,520 to install 477 kemil conductor insteaq of 266.8 kemil resulted in an incremental reduction in losses of $33,000*." This analysis covers a five year period. Actual savings over a longer time span make the installatiot' of a 477 kcmil conductor even more attractive. Circuit voltage improvement is such that the installation of substation voltage regulators could be deferred until 1987. A summary of the results may be found in Table 4.5 and additional technical data in Annex 3. 4.14 The loss reduction obtained using 13.8-kV as the circuit voltage was greater and voltage regulation negligible. However, inadequate data is available to estimate the cost to change to 13.8 kV. Two basic conclusions from this example are: - Conversion of any 2.4-kV overhead system to 4.16-kV, even with low growth rates, can be easily justified on loss reduction alone. - Conductor loss should be evaluated and the least cost conductor size determined where system betterments such as in Santiago are being made. Santa Maria Transformer Losses 4.15 Table 4.6 illustrates the reduction in transformer load losses when losses are reduced in the substation related feeders. In this case, the addition of capacitors was simulated on the feeders. If the savings in losses in the substation are considered, the benefit-to-cost ratio of any proposed reduction scheme is increased. Similarly, a reduction in losses will occur in the transmission line supplying the substation. Conclusions This study indicates that: - The overall energy lost and unaccounted for in IRHE's system is high. 1/ Review of the cost estimate for this project indicates several defects. High strength all-aluminum ateel-reinforced cable is proposed, whereas lower cost all-aluminum would be better for short span urban construction. On the other hand, nothing is indicated in the estimate for a neutral conductor, usually required when converting from 3-phase, 3-wire to 3-phase, 4-wire, and miscellaneous materials such as line guards, tie wire and connectors. - 16 - Tablp 4.5: Loss Analysis - Feeder 3, Santiago Substation Province of Cocle Veraguas Present Worth 1985-1988 1983 1985 1988 Balboas 1. Base Case - Existing 2.4-kV System A/ Demand, kVA 1,570 2,005 3,258 Demand, kW 1,361 1,720 2,697 Energy, MWh 7,034 81,889 13,939 Losses, kW 159 266 761 534,870 Losses, MWh 585 977 2,801 387 440 Total Present Worth, Losses 1.9b/ 1.8 1 Minimum Voltage, kV 1 1.8 _ 1.3 _ 2. Proposed Chan-Conversion to 4.16-kV Reconductor 3 km with Zbb.8 kcmil ACSR Demand, kVA 1,387 1,686 2,273 Demand, kW 1,227 1,491 2,003 Energy, MWR 6,341 7,707 10,351 Losses, kV 25 37 67 59,245 Losses, MWh 92 135 246 42 915 Present Worth, Losses 102,160 Present Worth, Savings 820*160 Investment 48,020 Benefit-to-Cost Ratio 17.1 b Minimum Voltage, kV 4.0 3.9 3.8 3. Alternate, Circuit Conversion to 4.16 kV. Reconductor 3 km with 411 kemil ACSR Demand, kVA 1,373 1,670 2,244 Demand, kW 1,216 1,476 1 ,974 Energy, MWh 79627 10,205 Losses, kW 21 39 34,250 Losses, MWh 78 142 24 810 Present Worth, Losses 59YuDu Present Worth, Savings 863,250 Investment 54,540 Benefit-to-Cost Ratio 15.8 Minimum Voltage, kV 4.0 4.0 3.9 4. Alternate. Circuit Case 3 with Addition of one 300 kVAR Capacitor Bank Demand, kVA 1,373 1,547 2,110 Demand, kW 1,214 1,473 1,970 Energy, MWh 7,613 10,182 Losses, kW 14 19 34 30,155 Losses, MWh 68 126 21 845 Present Worth, Losses SZ,000 Present Worth, Savings 870,310 Investment (Case 3 and Capacitors) 59,440 Benefit-to-Cost 14.6 Minimum Circuit Voltage, kV 4.0 4.0 4.0 a/ Assumptions: Load Pactor-59Z, Loss Factor"42%, Base Case Power Factor-9OZ, Load Growth-10Z per annum. b/ Unacceptable voltage levels. - 17 - Table 4.6: Loss Analysis - Santa Maria Substation and Feeders 1984 1985 Demand Losses Demand Losses Feeder kW kVA kW kW kVA kW 1. Base Case - Existing System -a Feeder 5-42 c/ 6,875 7,836 188 7,373 8,421 218 Feeder 5-43 7,502 8,423 585 8,096 9,189 695 Feeder 5-44 6,465 7,360 166 6,927 7,894 133 Feeder 5-45 4,443 5,170 73 4,761 5,604 80 Subtotal v25,285 28,789 1,012 27,157 31,108 1,126 Coincideng Transformer Demand /' 23,858 27,377 25,558 29,598 Power Factor 0.87 0.86 Transformer Load Loss, kW 285 333 2. With 5,400 kVAR Capacitors Installed on Feeders Feeder 5-42 A' 6,836 7,009 149 7,329 7,557 173 Feeder 5-43 7,084 7,438 406 7,627 8,100 481 Feeder 5-44 6,449 6,839 100 6,909 7,362 115 Feeder 5-45 4,428 4,646 59 4,747 5.043 67 Subtotal 24,797 25,932 714 26,612 28,062 836 Coincideng Transformer Demand !' 23,652 24,634 25,279 26,658 Power Factor 0.96 .95 Transformer Load loss 231 270 Released Transformer Capacity 2,743 2,940 Reduction in Feeder Loss 258 301 Reduction in Transformer Load Loss 54 63 Total Reduction, kW 312 364 Value of kW Loss Reduction - Balboas 128,492 Value of kWh Loss Reduction - Balboas 93,076 Total Balboa 221,568 Investment - Balboas d/ 36,933 First Year Benefit-to-Cost Ratio 6.0 dExistIg sytm has 2,100 WAR and 900 kVAR on Feeders 5-43 and 5-45, repectively. b/ AMsmed Concindwe Fact=-.95,Load Facrst , Loss FaCtOt42%, Load Gr(wthl7% per anm. 2 Feedrs are supplied from Transfomr No. 2, ratd 15/20/25/28 VA, OA/FA/A%A with 65C rise. Asmed that wpadtors are titalled by 1984 - 18 - - A high percentage of the losses appear to be non-technical, i.e., involved with metering and billing practices. A discussion on metering practices may be found in Annex 5. - The existing distribution system technical losses can be reduced economically. - The highest benefit-to-cost ratios in the reduction of technical losses are obtained with the application of capacitors. - The positive benefits in the reduction of losses can be obtained by reconductoring, changing from 2.4-kV, 3-phase, to 4.16-kV, 3-phase, 4-wire or alternatively to 13.8-kV or 34.5-kV (although higher distribution transformer losses must be considered at 34.5 kV). s - Voltage levels and regulation can be improved by the application of capacitors or reconductoring and if necessary by the use of regulators. CHAPTER V OBSERVATIONS 5.01 As part of this study, several points were noticed that should be given consideration: (i) Outgoing high voltage feeders from substations in the Metropolitan District are in a common duct bank. The result is a thermal bottleneck in system capacity from heat generated in the cables. The reduction in circuit capacity, for example, in 500 kemil paper-insulated cable is 457 amperes in a duct bank with three active cables to 375 amperes inlt duct with six active cables (assumes a 63X load factor).-. The capacity problem is becoming worse in some parts of the system where the load factor has been increasing. The addition of more cables in the same duct will reduce capacity even further. Where existing feeders are to be added to new substations, a new duct bank on a different route should be built and for new substations, two separate routes selected. In addition, soil thermal resistiv,p surveys should be made to establish firm circuit ratings.- 1/ See IPCEA - AIRE Publication S-135, Vol. IA Cable Ampacities. 2/ Thermal resistivity surveys should also be initiated along the proposed route of the underground cable, San Francisco Substation to the future Mt. Obscuro Substation. - 19 - (ii) When obtaining data for pf t of this study from the 1983-1986 master distribution plan,- the use of ACSR (aluminum cable, steel reinforced) was noted in the cost estimates. AAC (all aluminium conductor) would be a better choice where short span overhead lines are built, such as those in urban areas. MC is 10-15% less costly and easier to install than ACSR because of the absence of a steel core. (iii) The Generation Master Plan does tot include a realistic estimate of losses and apparently does not include the effect of losses calculated in load flow studies. High voltage losses are much higher than that used for the Master Plan. Further, the maximum demand and energy sales for the year 1982 exceeds the forecast demand. A revised forecast should be made. (lv) Input data for any feeder analysis requires data on existing distribution circuits and the transformers installed on the feeder. Normally, this type of data is found on distribution maps. High voltage circuit maps apparently have not been updated since 1979. Maps showing secondary circuits and services could not be found. System maps must be updated for proper planning. Further, maps must be updated if the transformer load management computer program supplied by Westinghouse is to be utilized, since correlation between supply transformer and customer is usually determined by map coordinates. All maps should have a common base (grid system), although not necessarily the same scale. Existing maps should either be updated and possibly redrawn by couventional drafting methods or alternately a suitable computer map program purchased to permit multiple layer mapping, i.e., preparation of a geographic or base map, on which a primary feeder map, a secondary and services map, a street lighting map and a transformer location map that can be overlaid on the base map. The updated maps should also be field checked, particularly secondary and services. This could be done concurrently with meter audit (Annex 5). CHAPTER VI REVENUE METERING 6.01 As indicated, a large amount of unaccounted for energy occurs in the low voltage distribution system and apparently there are considerable metering irregularities. 6.02 Inspection of a number of watthour meter installations in the commercial area along Via Espana, Panama City showed the following: 1 Plan Mastro Para La Expansion y Mejoras Del Sistema de Distribution, 1983- 1986. - 20 - - At least two meter sockets were found with jumpers across the socket jaws. - At least ten meters were found without seals indicating possible tampering with the meter. - Wireways leading to meter sockets were missing covers. Unsealed meters and wireways are an open invitation for customers to tamper. - Essentially all unused meter sockets were uncovered, a safety violation due to exposed energized electrical connections. - Access to meters was blocked; at one location by trash piled up in front of the meters; at a second location by a large unused water tank. These are normally a safety vialation since access to the customer's service switch is blocked. Lack of access will contribute to inaccurate meter readings and lowered meter reader productivity. - Some meters are too high above the ground for accurate meter reading. - IRHE meter identification numbers are large, obscuring in some cases, the view of the meter register. - Substantial amounts of dirt were noted on several meter covers, obscuring the view of the meter register. These irregularities in meter installation contribute to theft, incorrect or inaccurate meter readings. 6.03 The jumpered meter sockets are an indication of possible theft; whether or not this is intentional by the customer or due to the lag in IRHE setting a new meter is not known. Also, whether or not meter readers report this type of situation is not known. Several methods are available to cure this type of problem: - Install clear coverplates with seals on all unused sockets to discourage jumpering meter sockets. - Leave watthour meters in place at all times. At such time as a customer discontinues service, make a special watthour meter reading on the existing meter which will bacome the cut-off reading for the old customer and the beginning reading for the new customer. - If IRHE's policy is to inspect and test a watthour meter when a customer discontinues service, either use a portable test set and check the meter in place or change meters immediately. Further, without a meter and its identifying number the meter reader may not be able to identify the customer who has jumpered a socket. - 21 - 6.04 It is understood that IRHE has transferred billing records to a new computer and the computer has lost billing data and/or customers' billing data has not been entered into the computer, which contributes to energy that is unaccounted for. 6.05 From a brief inspection of IRHE's meter testing facilities, it was noted that the area used for testing was cramped and equipment outmoded. Meter testing staff also apparently do not do much field testing. Purchase of a new large capacity meter test bench with solid state type test equipment will expedite bench testing. Portable high accuracy test equipment is also available for field testing meters. Consideration should also be given to establishing a second meter test facility in the Chiriqui District due to the District's distance from Panama. 6.06 Although not a matter of accounting for energy, IRHE's Tariffs 31 and 36 include a power factor penalty clause which is to be calculated with the aid of a varhour meter. At one meter installation that was inspected (high voltage service to a school), space had been provided for a varhour meter but the meter had not been installed. To what extent varhour meters or standard watthour meters and phase shifting transformers, are missing is not known but varhour meters should be installed and power factor penalties enforced. A poor customer power factor increases system losses. 6.07 The load survey equipment proposed for substation and system loss evaluation is equally capable of being used' for customer load cnaracteristics studies, a necessity for use with a transformer load management program. In addition, the same type of equipment can be installed permanently as the principle metering equipment for large custmers. This type of metering equipment has a higher degree of accuracy which can result in a substantial increase in revenue. Further, application of time-of-day rates and faster billing can be obtained if the translator used with the load survey equipment is properly programmed. The translator could be also connected to the existing computer. CHAPTER VII FUTURE LOSS REDUCTION 7.01 The value of 1982 energy losses was es nte. at $24.2 million. This value is sufficiently large to warrant a major ma agement effort to reduce both technical losses and non-technical losses in the system. The level of losses that can be tolerated is purely economic. What is proposed here is a short run scheme to reduce losses in the existing system and guidelines for future loss reduction. Technical Losses 7.02 Technical losses can and should be reduced. Loss analysis presented above indicates that savings can be achieved by the application of capacitor or conductor changes in the existing system. IRHE's computer programs, when completely debugged, and with the acquisition of an additional program for optimun capacitor location, can be utilized for analysis on a circuit-by- circuit basis. - 22 - 7.03 Some reduction in the distribution system technical losses sho ,d occur within the next two years as part of tgs planned 1983 to 1986 substation and distribution system improvement programs.- 7.04 Thirty-three feeders, comprising approximately 27% of the 2.4, 4.16 and 13.8 kV system were analyzed for losses. From this an estimate of the peak kilowatt and energy loss reduction that might be obtained for the whole distribution system by the use of capacitors and some circuit reconductoring and the costs and benefits is shown in Table 7.1. This projection is based upon average kilowatt peak loss and kVARs per kilometer of line obtained from the samples analyzed. This table does not reflect the reduction that will also occur in substation transformers and transmission lines which, if evaluated, would increase the benefits. The overall system losses are based on thpae used in the Generation Master Plan (Table 2.1). It is assumed that the initial loss reduction program would take place over a fiveovyear period, 1984-1988, and initially with materials supplied through the Sixth Power Project. 7.05 Transmission line losses should be reviewed. Peak dewand loss in the Panama-L. Sanchez-Mata de Nance 230-kV transmission lines is now 0.5 to 1.0 megawatts. With the operation of La Fortuna Hydroelectric Plant at the end of 1984, peak demand loss will increase to 22-23 megawatts. After 1985, the estimated energy losses in this part of the system will be 71 GWh per year. The Costa Rica interconnection can Increase the peak demand loss to 33 megawatts. Data is not available on the operation of the interconnection that would permit estimating energy losses. 7.06 Several potential methods are available to reduce losses in this segment of the transmission system. The addition of shunt compensation in the form of capacitors on substation busbars would help. Alternatively, the construction of a second 230-kV line, reconstruction of the existing 230-kV to use bundled conductor or advancing the construction of part of the proposed 345-kV line for the Changuinola project will reduce losses. For the latter, the installation would be a single circuit for operation at 230-kV and provision for a second circuit when the line is converted to operate at 345- kV. The installation of additional circuits is attractive because the outage of the existing 230-kV line would cause a complete collapse of the IRHE system. 7.07 The reconstruction of the existing 230-kV line as a bundle conductor will reduce losses by one-half. A new line built for 345-kV will permit a greater reduction in losses because of heavier conductor is usually used or selected. A reduction of one-third is estimated. 7.08 Annual losses in the existing 230-kV line is $8.75 million. The estimated cost of wire, accessories and installation for reconstruction of the existing line as bundled conductor is $20.7 million. This does not include an allowance for tower strengthening. The estimated cost of a 345-kV line is $81 million which probably can not be jtstified on loss reduction alone. IRHE indicated that it would review this problem. 1/ Plan Maestro Para la Expansion y Mejoras del Sistems de Distribution, 1983 to 1986. - 23 - Table 7.1: Estimated Distribution System Loss Reduction 1983 1984 1985 1986 1987 1988 Without Loss Reduction Demand, MW 364 387 416 440 468 498 Demand, MVA 414 440 473 500 538 572 Peak Loss, MW ± 66 70 74 79 84 89 Generation, GWh b/ 2,095 2,231 2,381 2,533 2,696 2,869 Energy Loss, GWh - 289 307 327 348 370 394 As a % of Generation 13.8 13.8 13.7 13.7 14.1 13.7 Energy Loss B/.million 45 48 b 51 53 55 49 After Loss Reduction Loss Reduction, MW/year 4 7 7 2 1 GWh/year 9.1 26.2 29.2 16.6 4.4 Cumulative reduction by 1988, MW 21 GWh 85.5 New Demand, MW 383 405 422 448 477 New Demand, MVA 426 435 444 472 502 New Generation Requirement, GWh 2,222 21,346 2,468 2,615 2,784 New Losses, GWh 298 292 284 289 309 As a % of Generation 13.4 12.4 11.5 11.6 11.1 Capacitors, MVAR/year 34 34 32 15 15 Reconductor, km/year 30 40 40 40 - Investment, B/. million/year 1.0 1.2 1.2 .9 .3 Benefit, B/. million/year 2.1 4.3 4.5 1.9 .7 Present Worth, Investment, 1984-1988 3.9 Present Worth, Benefits, 1984-1988 11.3 Benefit-to-Cost Ratio 1:3 a/ Based on a Load Factor of 63.4%, a Loss Factor of 47%. b/ Energy losses used above have been projected by IREE for use in planning generation requirements. This projection is low based on actual losses in 1981 and 1982. IRHE's projections have been used, however, for lack of better data. - 24 - Table 7.2: Comparison of Losses in 230-kV Transmission Line Costs (Million B/.) Existing Reconductored Item 230-kV Line 230-kV Line Annual Losses 8.75 4.38 Annual Cost of Conductor Change - 2.15 Total Annual Cost 8.75 6.53 Savings 2.25 Non-Technical Losses 7.09 Non-technical losses represent a significant amount of energy. The meter reader is the first line of defense for any utility company in detecting theft, fraud or other irregularities. The meter reader should be given adequate training to detect these and be offered a suitable inducement to report theft or fraud such as special recognition or a monetary reward. 7.10 A quick method of identifying irregularities is to add additional coding to the mark-sense cards now used by meter readers to indicate meters without seals or those which have apparently been tampered with. Program the billing computer to print a summary for follow-up by the commercial department. 7.11 One method to 'catch-up' on the existing metering problem is to establish special audit teams. this would be a joint office/field team whose function would be to: (a) Inspect all meters and meter installations for irregularities and to initiate corrective action where meters are defective, missing or have been tampered with. (b) Install covers on unused sockets and arrange for covers to be installed on all open wireways. (c) Verify that each customer is being billed and that the billing data is being entered into the billing computer. (d) Review billing records for abnormal changes in customers' billing and investigate whether or not the change is reasonable. (e) Report obstructed or poorly located meter installations for action by the commercial department. The commercial department should then contact the customer or building owner and request corrective action. - 25 - 7.12 Establish a series of customer penalties for: (a) Meter socket covers and seals that are broken or have been tampered with. (b) Energy theft. ;s a minimum, charge interest on a monthly basis and at the current rate being charged for consumer loans on the estimated value of the energy theft. 7.13 In order to improve the accounting for energy, the following steps are recommended: (a) Install watthour meters on a selected group of street lights. At present, energy use in street lighting is estimated. Watthour meters installed in selected light 4nstallations should improve the accuracy of estimates. (b) Establish a watthour meter test program for high energy use customers, generating plants, and substations. At the minimum, a two-year period between tests is suggested, the test program may find meter errors that will indicate that the customer is under or over billed. (c) Install a watthour meter in substation service transformers. 7.14 Existing criteria for the selection of primary line conductor is not known. Secondary conductor sizing appears to be based on a table in the Distribution Standards which relates conductor size to transformer capacity. Costs of material, energy and capacity change over the years and periodic re- examination of economic conductor sizes should be made. 7.15 Transformer loss evaluation when new transformers are purchased should be continued. Values for energy and capacity should be determined on a long run marginal cost basis for the different voltage levels in use in IRHE's system. Note that energy and cappcity costs should be included in the bid documents when bids are requested.-' CHAPTER VIII RECOMMENDATIONS 8.01 On the basis of the results of the studies made on the distribution system, an overall system loss reductlon program should be initlated. Where applicable, this program should be utilized to check the betterment proposed for the 1983 to 1986 Master Plan for Expansion and Improvement of the Distribution System, because the test results show that the computer based analysis can often identify additional betterment over and above those obiained by traditional methods. 1/ Edison Electric Institute Publication 06-81-08, "A Method for Economic Evaluation of Distribution Transformers," suggests a standard procedure. In addition, this document recommends renuesting loss data at 85°C. - 26 - 8.02 The loss reduction program should cover the following: - Examine existing 4.16-kV, 13.8-kV and 34.5-kV circuits to determine whether or not capacitors should be installed and/or circuits reconductored in all or part in order to reduce losses. - Examine existing 2.4-kV circuits to determine whether or not they should be converted to 4.16-kV or to a higher voltage. - Examine existing 230-kV transmission to determine whether or not losses can be reduced economically. - Examine new projects including the transmission system to determine whether or not the most economic conductor size has been selected for use in the projects - Re-evaluate whether or not existing capacitor banks are in the best location for loss reduction (except where capacitors are installed primarily for voltage control). In addition, existing capacitor banks that are not in use should be repaired and relocated. - Establish economic sizes of primary and secondary conductors for different loads and load growth rates as a guide for district distribution engineers when planning line extensions and services. - Either modify existing Westinghouse computer programs or acquire additional programs to identify feeder losses and calculate the optimum method of reducing losses. The addition of a program to determine the optimal location of capacitors is recommended in particular. An economic analysis program is desirable. - Improve the existing data base by requesting that the operating districts include in their reports all data from all substation meters. - Install watthour meters with demand attachments in the secondary of all substations now without meters to improve the system data base (Annex 5). - Initiate the proposed project to acquire cassette or cartridge type load survey equipment for use in obtaining substation and feeder load characteristics for system planning and loss analysis. - Include with the above, additional load survey equipment that can be used for analysis of customer load characteristics for tariff calculations and future transformer load management program. Use of a consultant to prepare specifications and select equipment is recommended. The services of a factory engineer to help set up equipment should also be included in specifications. - 27 - - Review and refine long run marginal costs at the different voltage levels for use in economic evaluation of losses (including the evaluation of power and distribution transformer losses). - Update distribution system maps to include latest data and to include secondary distribution, street lighting and service locations and establish the procedures to keep the maps updated. - Purchase of 34-MVAR capacitors and associated accessories. Advance purchase now will permit capacitors being on hand at the time initial loss reduction studies are completed. 8.03 In addition to the above, the program should cover the following areas: - Improve watthour meter testing including the acquisition of suit- able bench equipment capable of testing 20 meters simultaneously and a portable watthour meter standard for checking the accuracy of meters at power plants, substations and large customers. - Establish a metering audit team as discussed in Annex 5. A 1 SMofAil 0? CIRCUITS ANALYZED INSTYTUTO DE RECURSOS HIDRAULICOS Y ELECTRIVICACION Metropolitan Distric.t Panama Substation Circuit Demand 1982 1982 Capacity & Circuit Voltage Length Connected / Losse, to Load Designation kV km kVA kVA kV a W a Ratio AVENDA SUR Transformers 13.8-2.4 kV, 3 x 1.0 MVA, Single-Phase and 4.16-2.4 kV, 2 x 1.5 MVA 1-A 2.4 .78 1,705 760 676 12.2 2.24 1-1 2.4 .97 1,522 967 861 3.7 1.57 1-2 2.4 .98 1,173 390 331 4.2 3.01 1-3 2.4 .43 367 315 280 .1 1.12 T6 T:7T67 2,149 -20.2 Transformers 13.8-4.16 kV, 3 x 3.0 MVA, Three-Phase 1-4 4.16 2.41 1,819 1,443 1,284 4.9 1.26 1-5 4.16 2.4 2,479 1,221'. 1,087 7.3 2.03 1-6 4.16 1.3 2,086 1,938 1,667 8.8 1.08 1-7 4.16 1.9 2.864 1,444 1.719 7.7 1.93 8.01 9,248 5,757 2 .7 SAN FRANCISCO Transformer No. 1, 110-13.8 kV, 1 x 2S/33/42/46 MVA, OA/PA/?OA k 2-12 13.8 5.6 7,122 6,130 5,456 91.3 1.16 2-19 13.8 9.7 6,245 5,666 5,044 32.5 1.10 2-20 13.8 5.9 3.500 3,346 2 978 24.6 1.05 2i1.2 16,867 it37r T14. SANTA MARTA Transformer No. 1, 110-13.8 kV 1 x 15/20/25/28, OA/FAIPOA 3-36 13.8 4.2 10,998 6,700 35695 51.2 1.64 5-37 13.8 15.2 10,906 7,900 6,715 61.7 1.39 5-38 13.8 11.3 7.670 6,900 5,865 95.2 1.11 5-39 13.8 817 9.637 7,770 6.545 136.3 1.24 39.4 39,211 24,820 344.4 Transformer No. 2, 110-13.8 kV, 1 x 15/20/25/28 MVA, OAk/A/FOA 5-42 13.8 24.8 10,972 6,800 5,984 145.6 1.61 5-43 13.8 32.8 11,516 6,759 5,953 385.2 1.70 5-44 13.8 11.0 7,951 6,400 5,632 87.2 1.24 5-45 13.8 8.1 6 466 4,400 3.872 53.5 1.47 -7F.T 36,905 21,441 6791-.5 QR9O VUNTO Transformer No. 1, 110-13.8 kV, 1 x 15/20/25/28 MVA, OA/YA/FOA I/ 8-62 13.8 17.0 10,812 5,612 4,826 113.2 1.93 8-63 13.8 88.6 14,897 5,226 4,508 354.5 2.85 8-64 13.8 20.5 12 407 5,796 4 985 88.4 2.14 126.1j* 38,116 14,319 736:r Transformer No. 2, 110-13.8 KY, I s 25/33/42 MVA, OA/FA/FOA / 8-66 13.8 20.6 15,839 6,992 6,013 68.4 2.27 8-68 13.8 11.0 6.314 5,336 4 589 111.0 1.18 31.6 22,153 1062 7. Transforer No. 1, 1 x 110-13.8-kV, 25/33/42/46 WA, OA/FA/POA i 6-46 13.8 2.5 7,338 7,181 6,391 9.4 1.02 6-47 13.8 3.7 10,784 6,740 5,99" 12.1 1.50 6-48 13.8 2.0 6,582 6,407 5,702 95.1 1.03 6-49 13.8 2.6 11,325 6,021 5,479 8.7 1.88 6-51 13.8 6.6 11 817 4,801 4 273 13.8 17.4 Lms acizbg mm ade cm alyu 3 at of 7 cxatdts fa Trmfommr No. 1. Tha S corasds out of T _nshf NM. 2 (25/33/42/46 WA) i arem salyz.L /Cly 3 aot of 4 drudts mWpJidh frc this r 1SUer a42: } hely 2 cot of. 2'l57 3/42/46 zfYf a lyrad. - 29- ANNEX Page 2 of 2 SUMMARY OF CIRCUITS ANALYZED INSTITUTO DE RECURSOS RIDRAULICOS Y ELECTRIFICACION Rural Areas - Panama Substation Circuit Demand 1982 1982 Capacity & Circuit Voltage Length Connected Losses to Load Designation kV km kVA kVA kW a/ kW Ratio PANAMA OCCIDENTE DISTRICT CORONADO Transformer 34.5-13.8 kV, 1 x 3.75/4.7/5.25 MVA, OA/FA, 65C Rise 15-17 13.8 72.8 2,647 1,049 859 5.4 2.52 15-25 13.8 68.3 2,141 910 728 9.9 2.35 141.1 4,788 1, 587 15.3 COCLE - VERAGUAS DISTRICT SANTIAGO Transformer No. 2, 34.5-2.4 kV, 1 x 2.50/3.12 MVA, OA/FA 3 2.4 11,1 3,566 1,400 1,218 125.5 2.5 CHIRIQUI DISTRICT MATE DE NANTE Transformer No. 1, 230-115-34.5 kV Valbuena - San Lorenzo 34.5 195.1 6,267 2*610 2,245 73.6 2.4 a/ Non-coincident demand. ANNEX 2 ADOPTED UNIT COSTS 1. Capacitors Normal Bank Rating 300 kVAR a/ 600 kVAR b/ 900 kVAR al 1,200 kVAR b/ Unswitched Switched Unewitched Switched Unswitched Switched Unswitched Switched Capacitors 1,371 1,371 1,487 1,487 2,556 2,556 2,994 2,994 Rack 290 290 290 290 290 290 290 290 Cutouts and Surge Arresters 244 244 244 244 244 244 244 244 Oil Switch - 1,285 - 1,285 - 1,285 - 1,285 Controls - 1,000 - 1,000 - 1,000 - 1,000 Misc. Materials 110 115 110 115 110 115 110 115 Subtotal 2,015 4,305 2,131 4,421 .3,200 5,490 3,638 5,928 0 Export Pack, Shipping 302 646 320 663 480 823 546 889 Subtotal 2,317 4,951 2,451 5,084 3,680 6,313 4,184 6,817 Installation Labor 90o s 960 900 960 900 960 900 960 Contengency 10% Material 232 495 245 508 368 631 418 682 Local Transport 232 495 245 508 368 631 418 682 Subtotal 3,681 6,901 3,841 7,060 5,K16 8,535 5,920 9,141 Engineering 592 692 592 692 592 914 592 914 Administration 286 346 286 346 286 457 286 457 Grand Total 4,559 7,939 4,719 8,098 6,194 9,906 6,798 10,512 Estimated 1983 Cost 4,900 8,533 5,072 8,704 6,658 10,647 7,307 11,300 Estimated 1984 Cost 5,268 9,173 5,453 9,357 7,158 11,446 7,855 12,148 a/ 150 kVAR units. b/ 200 kVAR units. c/ Based on estimated crew hours required for work. - 31 - ANNEX 3 TYPICAL COMPUTER PRINTOUTS 1. The following are typical computer printout sheets of the results of the loss analysis program. The basic computation is a loss and voltage drop computation (Program BALVOL). The results can be obtained in a detailed computation of losseo fcr each part of the circuit, or a summary by years showing losses, demand, voltage level and line capacity. The other printouts are a financial calculation, which provide the present worth of the cost of losses. 2. Most column headings are self explanatory, except the following: Lgth K - Section length in 1,000 meters. Cond. % - Percentage loading of the conductor as based on the rated conductor capacity in the data base. Tran - Connected distribution transformer capacity in the section. Specific examples are: Santa Maria Substation Summary Coronado Substation (BALVOL) without capacitors (1982) Circuit 15-17 Coronado Substation (BALVOL) with 600 kVAR capacitors (1982) Circuit 15-17 Coronado Substation Summary Circuit 15-17 Coronado Substation Financial Circuit 15-17 AmNEX 3 - h~~~~~~~~tga a ot 19 8*8 B A 8 E C A S E 8** NO CHANGES 1982 JA/27/S3 SANTA MARIA 5-36 SUMMARY FOR FEEDER 36 YEAR X - KW--- KVA. KVAR ---MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 5698.4 51.2 6703.1 3529.7 1 78. 280.4 64 97.2 83 7.00 6101.3 58.0 7181.1 3787.1 1 84. 300.4 64 97.0 84 7.00 633.1 67.6 7694.0 4064.1 1 90. 321.9 64 96.9 85 7.00 6995.7 77.6 8244.3 4362.3 1 96. 344.9 64 96.5 86 7.00 7491.6 89.2 8835.0 4683.4 1 103. 369.6 64 96.3 87 6.00 7947.1 100.6 9378.4 4979.9 1 109. 392.4 64 96.1 as 6.00 8430.7 113.4 9956.2 5296.2 1 116. 416.5 64 95.8 6*.00 8944.3 128.0 10570.7 5633.8 1 123. 442.2 64 95.6 90 5.00 9398.7 141.6 11115.2 5934.0 1 130. 465.0 64 9S.3 91 5.00 9876.7 156.7 11688.7 6251.2 1 136. 489.0 64 95.1 92 S.00 10379.4 173.4 12292.9 6586.7 1 143. 514.3 64 94.8 8*8 WITH CAPACITORS i88 -2 l JA/27/83 SANTA MARIA 5-36 SUMMARY FOR FEEDER 36 b YEAR . --KW-- KVA KVAR ---MAX LOAD- MAX VOLT DROP GROW DEN LOSS DEM DEN SEC %CAP AMPS SECT LEVEL 92 0.00 5689.2 41.9 6138.0 2304.1 1 72. 256.8 64 98.0 83 7.00 6091.1 48.5 6606.7 2558.8 1 77. 276.4 64 97.8 84 7.00 6521.7 56.2 7110.4 2832.8 1 83. 297.5 64 97.6 es 7.00 6983.2 65.1 7651.7 3127.8 1 89. 320.1 64 97.4 96 7.00 7477.8 75.4 8233.4 3445.5 1 96. 344.5 64 97.1 87 6.00 7932.1 85.6 8769.0 3738.7 1 102. 366.9 64 96.9 a8 6.00 8414.5 97.2 9339.1 4051.5 1 109. 390.7. 64 96.7 89 6.00 8926.7 110.3 9943.7 4385.3 1 116. 416.1 64 96.4 90 5.00 9379.9 122.7 10483.5 4682.2 1 122. 438.6 64 96.2 91 5.00 9856.5 136.5 11050.3 4995.9 1 129. 462.3 64 95.9 92 5.00 10357.8 151.8 11647.6.. 5327.5 1 136. 487.3 64 95.7 *** a A S E C A S E %HITleOAt 1982 JA/27/83 SANTA QRIA 5-36 SUMMARY FOR FEEDER 36 YEAR * - KW- KVA KVAR -MAX LOAD-- MAX VOLT DROP RtOW DEM LOSS DEN DEN 8EC %CAP AMPS SECT LEVEL 82 0.00 5698.4 51.2 6703.1 3529.7 1 7B. 290.4 64 97.2 53 7.00 6101.3 58.8 7181.1 3787.1 1 84. 300.4 64 ! 97.0 84_ -20.00 4871.3 37.3 5723.4 3004.7 1 .67. 239.5 64 97.6 85 7.00 5215..2 42.8 6130.5 3222.4 1 ,.71. 256.5 64 97.4 86 -30.00 3641.4 20.7 4271.0 2232.0 1. 50. 178.7 64 98.2 87 6.00 3861.3 23.3 4530.3 2369.4 1 53. 189.5 64 98.1 88 6.00 4094.5 26.3 4905.4 2515.5 1 56. 201.0 64 98.0 89 6.00 4341.9 29.6 5097.6 2670.9 1 59. 213.3 64 97.9 90 5.00 4560.5 32.6 5356.0 2808.s5 1 62. 224.1 64 97.8 91 5.00 4790.4 36.1 5627.7 2953.5 1 66. 235,4 64 97.7 92 5.00 5031.8 39.8 5913.4 3106.2 1 69. 247.4 64 97.5 *3 SHIFT.OF LOAD + CAPACiTOR(181200 DIRECT) J.A27/83 SANTA MARIA 5-36 SUMMARY FOR FEEDER 36 YEAR % --KW-- KVA KVAR ---MAX LOAD- MAX VOLT DROP GROW DE4 LOSS DEN DEN SEC %CAP AMPS SECT LEVEL 82 0.00 5689.2 41.9 6138.0 2304.1 1 72. 256.8 64 98.0 83 7.00 6091.1 48.5 6606.7 2S58.8 1 77. 276.4 64 97.8 84 -15.00 5170.3 34.2 5535.4 1976.8 1 65. 231.6 64 98.3 8r 7.00 5535.2 39.5 595S.9 2206.8 1 69. 249.3 64 98.1 t -30.00 3865.5 18.5 4036.2 1161.4 1 47. 169.9 64 98.9 87 6.00 4098.7 20.9 4301.9 1308.3 1 50. 180.0 64 98.8 88 6.00 4346.1 21.7 4595.0 1460.5 1 53. 191.8 64 98.7 89 6.00 4608.6 26.8 4886.5 1624.5 1 57. 204.4 64 98.6 90 5.00 4840.6 29.7 5134.0 1769.8 1 6O. 215.6 64 98.4 91 5.00 5084.4 33.0 5435.9 1922.8 1 63. 227.4 64 98.3 92 5.00 5340.7 36.6 5732.9 2084.1 1 67. 239.8 64 98.2 ANNEX 3 33 Pag 3 of 19 *8 A S E CASE A 2* NO CHANGES JA/27/83 SANTA MARIA 5-S7 SUMMARY FOR FEEDER 37 YEAR % ----KW----- KVA KVAR --MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC XCAP AMPS SECT LEVEL 82 0.00 6719.0 61.7 7903.7 4162.2 1 92. 330.7 35 97.8 83 7.00 7194.1 70.8 8467.8 4466.2 1 99. 354.3 Vs 35 97.6 84 7.00 7703.3 81.3 9072.9 4793.4 1 106. 379.6 35 97.5 85 7.00 8248.9 93.3 9722.3 5145.8 1 113. 406.9 35 97.3 9A 7.00 8833.6 107.2 10419.3 5525.3 1 121. 435.9 35 97.1 E 6.00 9370.8 120.8 11060.6 5875.8 1 129. 462.7 35 96.9 8S8 6.00 9941.2 136.2 11742.5 6249.8 1 137. 491.3 35 96.7 89 6.00 10546.9 153.6 12467.8 6649.0 1 145. 521.6 35 96.5 90 5.00 11082.8 169.9 13110.5 7004.1 1 153. 548.5 35 96.3 91 5.00 11646.5 187.9 13787.5 7379.4 1 161. 576.8 35 96.1 92 5.00 12239.4 207.9 14500.8 7776.2 1 169. 606.7 Z5 95.9 2* WITH CAPACITORS(1*1200 * 1*900) 2*2** JA/27/83 SANTA MARIA 5-37 SUMMARY FOR FEEDER 37 YEAR X - KW- KVA KVAR --MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6705.8 48.5 7005.4 2026.5 1 82. 293.1 18 98.6 83 7.00 7179.5 56.2 7547.1 2326.6 1 88. 315.7 18 98.5 84 7.00 7687.1 65.1 8130.9 2649.7 1 95. 340.2 , 18 98.3 85 7.00 8230.9 75.4 8759.7 2997.5 1 102. 366.5 18 98.2 86 7.00 8813.8 87.4 9436.9 3372.1 1 110. 394.8 35 98.0 87 6.00 9349.3 99.3 10061.5 3718.0 1 117. 420.9 3 97.8 88 6.00 9917.8 112.8 10726.9 4087.0 1 125. 448.8 35 97.6 89 6.00 10521.5 128.2 11435.9 4481.0 1 133. 478.4 35 97.4 90 5.00 11055.6 142.7 12065.2 4831.3 1 141. 504.8 35 97.2 91 5.00 11617.4 15S.8 12728.7 5201.6 1 148. 532.5 35 97.1 92 5.00 12208.3 176.7 13428.5 5593.1 1 156. 561.8 35 96.8 DA S E C A S E %III 5 VL.&P JA/27/83 SANTA MARIA 5-37 SUMMARY FOR FEEDER 37 YEAR X ----KW- KVA KVAR --MAX LOAD, MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6719.0 61.7 7903.7 4162.2 1 92. 330.7 35 97.8 83 -17.00 5567.8 42.2 6540.0 3431.0 1 76. 273.6 35 98.2 84 7.00 5960.8 48.4 7005.1 3679.8 1 82. 293.1 35 98.0 85 7.00 6381.8 55.6 7503.9 3947.3 1 87. 313.9 35 97.9 86 -40.00 3815.5 19.7 4471.9 2332.5 1 52. 187.1 35 98.8 87 6.00 4045.7 22.2 4743.*1 2475.8 1 55. 198.4 35 98.7 s8 6.00 4281.9 25.0 5030.9 2628.2 1 59. 210.5 35 98.6 89 6.00 4548.9 28.1 5336.4 2790.1 1 62. 223.3 35 98.5 90 5.00 4777.8 31.0 5606.6 2933.6 1 65. 234.6 35 98.4 91 5.00 5018.4 34.2 5890.7 3084.7 1 69. 246.4 35 98.4 92 5.00 5271.2 37.8 6189.3 3243.8 1 72. 258.9 35 98.3 2* WITH CAPACITORS(1*1200 & 12900) + UNLOADING (83&86) JA/27/83 SANTA MARIA 5-37 SUMMARY FOR FEEDER 37 YEAR % -r-KW- KVA KVAR --MAX LOAD-- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6705.8 48.5 7005.4 2026.5 1 82. 293.1 18 98.6 83 -17.00 5558.1 32.6 5709.2 1304.5 1 67. 238.9 18 99.0 84 7.00 5950.0 37.6 6148.6 1550.1 1 72. 257.2 18 98.8 F 7.00 6369.7 43.5 6623.0 1814.3 1 77. 277.1 18 98.7 8.. -40.00 3811.0 15.2 3817.3 219.6 1 44. 159.7 18 99.5 87 6.00 4040.5 17.0 4056.6 361.1 1 47. 169.7 18 99.4 88 6.00 4284.0 19.1 4314.4 511.6 1 50. 180.5 18 99.3 89 6.00 4542.3 21.5 4591.6 671.6 1 54. 192.1 18 99.3 90 5.00 4770.5 23.7 4839.4 813.3 1 56. 202.5 18 99.' 91 5.00 5010.4 26.2 5102.0 962.5 1 59. 213.5 18 99.1 92 5.00 5262.4 29.0 5380.2 1119;7 1 63. 225.1 18 99.1 - 34 AN= 3 Paga 4 of 19 2 BA S E C A S E JA/27/83 SANTA MARIA 5-38 SUMMARY FOR FEEDER 38 YEAR X --KW----- KVA KVAR ---MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 5868.5 95.3 6902.4 3633.7 1 59. 275.0 7 100.0 83 7.00 6287.1 109.7 7403.4 3909.2 1 63. 295.0 7 99.6 84 7.00 6736.3 126.4 7942.3 4207.4 1 68. 316.5 7 99.2 85 ".QO 7218.4 145.8 8522.4 4530.6 1 73. 3Z9.6 7 98.8 c 6.00 7661.8 165.0 9057.5 4830.6 1 78. 360.9 7 98.4 8. 6.00 8133.4 186.7 9628.1 5152.6 1 83. 383.6 7 98.0 88 6.00 8634.9 211.4 10236.9 5498.4 1 88. 407.9 7 97.5 89 5.00 9079.4 234.7 10778.1 5808.0 1 92. 429.5 7 97.1 90 5.00 9547.6 260.7 11349.9 6137.1 1 97. 452.2 7 96.6 91 5.00 10041.0 289.7 11954.3 6487.3 1 102. 476.3 7 96.2 92 5.00 10560.9 322.1 12593.6 6860.4 1 108. 501.8 7 95.7 2* WITH CAPACITORS(l1200 DIR. & 1%1200 SWITCH) ** JA/27/83 SANTA MARIA 5-38 SUMMARY FOR FEEDER 38 YEAR % -K!W----- KVA KVAR ---MAX LOAD- MAX VOLT DROP BROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 5845.3 72.0 5961.0 1168.9 1 52. 242.1 7 100.1 S3 7.00 6260.8 83.4 6423.3 1435.8 1 56. 260.9 7 99.8 84 7.00 6706.6 96.8 6924.8 1724.7 1 60. 281.3 7 99.4 85 7.00 7185.0 112.5 7468.4 2037.6 1 65. 303.4 7 98.9 s6 6.00 7625.1 128.2 7972.6 2328.2 1 70. 323.8 7 98.5 87 6.00 8093.0 146.3 8512.7 2640.0 1 74. 345.8 7 98.1 a8 6.00 8590.6 167.1 9091.1 2974.9 1 79. 369.3 7 97.6 89 5.00 9031.5 186.9 9606.8 3274.5 1 84. 390.2 7 97.2 90 5.00 9496.0 209.1 10153.0 3593.1 1 89. 412.4 7 96.8 91 5.00 9985.3 234.0 10731.6 3932.1 1 94. 435.9 7 96.3 92 S.00 10500.9 262.1 11344.6 42935.1 1 99. 460.8. 7 95.8 2*2 BASE CASE 22 SHIFT.OF LOAD 5 JA/27/83 SANTA MARIA 5-38 SUMMARY FOR FEEDER 38 YEAR X ---KW- - KVA KVAR --MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEN DEN SEC XCAP AMPS SECT LEVEL 82 0.00 5868.5 95.3 6902.4 3633.7 1 59. 275.0 7 100.0 83 -9.00 5332.0 78.3 6262.0 3283.8 1 54. 249.5 7 100.5 84 7.00 5711.5 90.1 6714.8 350.9 1 58. 267.6 7 100.2 85 7.00 6118.7 103.8 7201.7 3798.1 1 62. 286.9 7 99.8 86 -27.00 4444.9 54.0 5207.7 2713.4 1 45. 207.5 7 101.3 87 6.00 4715.3 60.9 5528.4 2886.2 1 47. 220.3 7 101.0 88 6.00 5002.3 68.7 5869.6 3070.7 1 50. 233.9 7 100.8 99 5.00 5256.3 76.0 6171.9 3234.7 1 53. 24S.9 7 100.6 90 5.00 5523.4 84.1 6490.3 3408.2 1 56. 258.6 7 100.3 91 5.00 5804.4 93.1 6825.8 3591.6 1 58. 272.0 7 100.1 92 5.00 6100.0 103.1 7179.2 3785.7 1 62. 286.1 , 7 99.8 22 SHIFT.OF LOAD + CAPA.(121200 D.&121200 S.)*$ JA/27/83 SANTA MARIA 5-38 SUMMARY FOR FEEDER 38 YEAR X. -- KW----- KVA KVAR --MAX LOAD- MAX VOLT DROP 2 Rf L DEM LOSS DEM -DEt---,cKC ZCAP - AMPS __SECT LEVEL 82 0.00 5845.3 72.0 5961.0 1168.9 1 52. 242.i 7 0i0.i 83 7.00 6260.8 83.4 6423.3 1435.8 1 56. 260.9 7 99.8 84 7.00 6706.6 96.8 6924.8 1724.7 1 60. 281.3 7 99.4 S 7.00 7185.o 112.5 7468.4 2037.6 1 65. 303.4 7 98.9 &i. -29.00 5075.1 53.6 5120.5 679.9 1 45. 208.0 7 100.8 87 6.00 5383.3 60.6 5453.9 874.7 1 48. 221.5 7 100.5 88 6.00 5710.7 68.5 5812.4 1082.8 1 51. 236.1 7 100.2 89 5.00 6000.4 76.1 6132.9 1268.2 1 54. 249.1 7 100.0 90 3.00 6305.1 94.7 6473.0 1464.4 1 57. 262.9 7 99.7 91 5.00 6625.7 94.2 6833.5 1672.1 1 60.' 277.6 7 99.4 92 5.00 6963.1 105.0 7215.6 1892.1 1 63. 293.1 7 99.1 -35- ANEX 3 Page 5 of 19 B A S E C AE *8 JA/27/83 SANTA MARIA 5-39 SUMMARY FOR FEEDER 39 YEAR X ----KW----- KVA KVAR ---MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6541.9 136.3 7897.1 4055.6 1 85. 306.7 11 100.2 83 7.00 7014.5 160.4 8348.0 4526.3 1 93. 332.8 11 99.8 84 7.00 7522.6 188.8 9053.2 5037.0 1 100. 360.7 11 99.3 85 7.00 8069.5 222.3 9817.5 5591.6 1 109. 391.2 11 98.7 F 6.00 8573.8 255.8 10527.1 6108.1 1 117. 419.4 11 98.2 8. 6.00 9111.5 294.4 11288.4 6664.0 1 125. 449.8 11 97.6 88 6.00 9685.0 338.9 12105.8 7263.0 1 134. 482.4 11 97.0 89 5.00 10194.9 381.5 12837.0 7800.8 1 142. 511.5 11 96.5 90 5.00 10733.5 429.4 13614.0 8374.6 1 151. 542.4 11 95.9 91 5.00 11302.9 483.6 14440.6 8987.5 1 160. 575.4 11 95.3 92 5.00 11905.1 544,9 15320.5 9642.9 1 10. 610.4 11 94.7 ** WITH CAPACITORS12*1200 SWITCH) 8* JA/27/83 SANTA MARIA 5-39 SUMMARY FOR FEEDER 39 YEAR X ---KW-- KVA KVAR --MAX LOAD-- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6510.9 105.2 6697.3 1569.3 1 74. 266.9 11 102.0 83 7.00 6978.9 122.9 7241.1 1938.1 1 80. 288.5 11 101.6 84 7.00 7477.7 143.9 7834.7 2338.1 1 87. 312.2 11 101.1 85 7.00 8015.8 168.6 8481.7 2772.4 1 94. 337.9 11 100.7 86 6.00 8511.4 193.4 9084.9 3176.6 1 101. 362.0 11 100.2 87 6.00 9039.2 222.1 9733.9 3611.4 1 108. 387.8 11 99.8 88 6.00 9601.3 255.2 10432.0 4079.5 1 116. 415.7 11 99.3 89 5.00 10100.2 286.7 11057.1 4499.5 1 123. 440.6 11 98.8 90 5.00 10626.5 322.4 11721.8 4947.2 1 130. 467.0 11 98.3 91 5.00 11181.9 362.6 12428.3 5424.8 1 138. 495.2 11 9/.s 92 5.00 11768.3 408.0 13180.2 5935.0 1 146. 525.2 11 97.3 .*s BASE CASE *5 SHIFT. OF LOAD TEST: JA/27/83 SANTA MARIA 5-39 SUMMARY FOR FEkDER 39 YEAR X -KW-- KVA KVAR --MAX LOAD- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6541.8 136.2 7696.9 40554 1 85. 306.7 11 100.2 83 -20.00 5204.0 79.5 5883.1 2743.9 1 65. 234.4 11 101.6 84 7.00 5576.8 93.6 6383.6 3106.3 1 71. 254.4 11 101.2 85 7.00 5977.3 110.2 6925.7. 3498.3 1 77. 276.0 11 100.8 86 -14.00 5122.2 76.5 5773.9 2664.7 1 64. 230.1 11 101.7 87 6.00 5436.5 88.1 6194.7 2969.7 1 69. 246.8 11 101.3 88 6.00 5770.8 101.5 6645.6 3295.8 1 74. 264.8 11 101.0 89 5.00 6066.9 114.2 7047.7 3586.4 1 78. 280.8 11 100.7 90 -16.00 5075.2 74.9 5711.2 2619.3 1 63. 227.6 11 101.7 91 5.00 5334.6 84.3 6057.9 2870.1. 1 67. 241.4 11 101.4 92 5.00__5607.7 94.8 6425.2 3136.5 1 71. 256.0 11 101.2 *8* SHIFT.OF LC - + CAPA.(2*1200) s JA/27/83 SANTA MARIA 5-39 SUMMARY FOR FEEDER 39 YEAR % -KW-- KVA KVAR --MAX LOAD- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 6510.9 105.2 6697.3 1569.3 1 74. 266.9 11 102.0 83 7.00 6976.9 122.9 7241.1 1938.1 1 80. 288.5 11 101.6 84 -21.00 5486.8 72.2 5540.7 770.7 1 61. 220.8 11 102.8 8S 7.00 5877.5 83.8 5974.8 1073.5 1 66. 238.1 11 102.5 E 6.00 6236.9 95.6 6382.2 1354.1 1 71. 254.3 11 102.2 87 6.00 6619.0 109.2 6822.6 1654.5 1 76. 271.8 11 101.9 88 6.00 7025.3 124.9 7298.0 1976.5 e 81. 290.8 11 101.5 89 -21.00 5524.6 73.2 5582.2 799.9 i 62. 222.4 11 102.8 90 5.00 5805.5 81.6 5894.0 1017.5 1 65. 234.8 11 102.6 91 5.00 6101.1 91.0 6227.4 1247.8 1 69. 248.1 11 102.3 92 5.00 6412.2 101.7 6583.5 1491.7 1 73. 262.3 11 102.1 .~~~~~~~~~~~~~~~ -36- AMNX 3 page 6 of 19 222 X A S E C A S E $22 1982 JA/28/83 SANTA MARIA 5-42 SUMMARY FOR FEEDER 42 YEAR X ----KW----- KVA KVAR --MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC /.CAP AMPS SECT LEVEL 82 0.00 5982.2 141.6 6793.5 3219.3 1 43. 287.1 50 92.5 83 7.00 6413.0 163.5 7295.2 3477.6 1 46: 308.3 50 92.0 84 7.00 6875.8 188.9 7836.5 3759.5 1 49. 331.2 50 91.4 85 7.00 7373.4 218.4 8421.0 4067.6 1 53. 355.9 50 90.9 86 7.00 7908.7 252.8 9052.6 4404.9 1 57. 382.6 50 90.2 87 6.00 8402.1 287.0 9637.9 4721.5 1 61. 407.3 50 89.6 88 6.00 8928.1 326.0 10264.7 5064.9 1 65. 433.8 50 89.0 89 6.00 9488.9 370.7 10936.7 5438.0 1 69. 462.2 50 88.3 .90 5.00 9987.3 413.1 11537.1 5775.8 1 73. 487.6 50 87.7 91 5.00 10513.6 460.8 12174.7 6139.0 1 77. 514.5 50 87.0 92 5.00 11069.9 514.4 12852.5 6530.2 1 81. 543.1 50 86.3 222 WITH CAPACITORS 2222 JA/28/83 SANTA MARIA 5-42 SUMMARY FOR FEEDER 42 YEAR . KW-- KVA KVAR --MAX LOAD-- MAX VOLT DROP GROW DEN LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 5951.7 111.1 6040.9 1034.2 1 38. 255.3 50 95.3 83 7.00 6378.2 128.8 6505.5 1280.8 1 41. 274.9 50 94.9 S4 7.00 6836.3 149.4 7009.7 1549.5 1 44. 296.2 50 94.4 85 7.00 7328.7 173.7 7556.8 1842.9 1 48. 319.3 50 93.8 86 7.00 7858.0 202.1 8150.4 2163.7 1 51. 344.4 50 93.2 87 6.00 8345.7 230.6 8702.0 2464.4 1 55. 367.7 50 92.6 88 6.00 8865.3 263.2 9294.0 2790.1 1 59. 392.8 50 92.0 89 6.00 9419.1 300.8 9929.8 3143.5 1 63. 419.6 50 91.4 90 5.00 9910.8 336.7 10498.4 3462.9 1 66. 443.7 50 90.8 91 5.00 10429.9 377.0 11102.6 3805.9 1 70. 469.2 50 90.1 92 5.00 10978.1- 422.6 11745.0 4174.6 1 74. 496.3 50 89.5 .4 _ __&r * U- LUAD TEST I JA/28/83 SANTA MARIA 5-42 SUMMARY FOR FEEDER 42 YEAR X --KW- KVA KVAR ---MAX LOAD- MAX VOLT DROP GROW DEM LOSS DEN DEM SEC YUCAP AMPS SECT LEVEL 82 0.00 5982.3 141.7 6793.6 3219.5 1 43. 287.1 50 92.5 83 7.00 6413.0 163.5 7295.2 3477.6 1 46. 308.3 50 92.0 84 -21.00 5036.5 99.4 5698.2 2665.3 1 36. 240.8 50 93.6 85 7.00 5397.2 114.6 6115.0 2874.5 1 39. 258.4 50 93.2 86 7.00 5784.6 132.2 6563.9 3102.0 1 41. 277.4 50 92.7 87 -16.00 4839.7 91.6 5471.4 2552.2 1 35. 231.2 50 93.8 88 6.00 5136.4 103.5 5813.6 2723.0 1 37. 245.7 50 93.5 89 6.00 5451.9 117.0 6178.2 2906.4 1 39. 261.1 50 93.1 90 5.00 5731.3 129.7 6502.0 3070.6 1 41. 274.8 50 92.8 91 5.00 6025.5 143.8 6843.8 3245.1 1 43. 289.2 50 92.4 92 5.00 6335.3 159.4 7204.6 3430.8 1 45. 304.5 50 92.1 22 SHIFT.OF LOAD . CAPACITOR(1*1200 8. & 1*900 D.) JA/28/83 SANTA MARIA 5-42 SUMMARY FOR FEEDER 42 YEAR X ---KW - KVA KVAR --MAX LOAD-- MAX VOLT DROP GROW DEN LOSS DE" DEN SEC %CAP AMPS SECT LEVEL 82 0.00 5951.7 111.1 8040.9 1034.2 1 38. 255.3 50 95.3 83 7.00 6378.2 128.8 6505.5 1280.8 1 41. 274.9 50 94.9 84 7.00 6836.3 149.4 7009.7 1549.5 1 44. 296.2 SO 94.4 85 -22.00 5303.0 87.2 5344.7 665.9 1 34. 225.9 50 96.1 86 6.00 5627.5 98.7 5691.2 849.2 1 36. 240.5 50 95.7 87 6.00 5972.4 111.9 6063.3 1046.1 1 38. 256.2 50 95.3 88 6.00 6=39.2 127.1 6462.8 1258.1 1 41. 273.1 50 94.9 89 6.00 6729.3 144.4 6891.4 1486.3 1 43. 291.2 50 94.5 90 -6.00 6315.8 126.1 6437.3 1244.5 1 41. 272.0 50 94.9 91 5.00 6639.5 140.3 6792.5 1433.6 1 43. 287.0 50 94.6 92 5.00 6980.5 156.3 7169.4 1634.9 1 45. 303.0 50 94.2 _ 37 All.=;tEX 3 Page 7 of 19 B A S E CASE A 2* JA/28/83 SANTA MARIA 5-44 SUMMARY FOR FEEDER 44 YEAR % ----KW---- KVA KVAR ---MAX LOAD--- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC XCAP AMPS SECT LEVEL 82 0.00 5633.4 87.5 6400.6 3038.6 7 64. 76.5 20 93.8 83 7.00 6034.8 100.7 6862.9 3268.2 7 68. 82.0 20 93.5 84 7.00 6465.3 115.9 7359.7 3516.4 7 73. 87.8 20 93.2 * 85 7.00 6927.4 133.5 7894.0 3785.1 7 78. 94.2 20 92.9 86 7.00 7423.2 153.8 8468.7 4076.1 7 84. 101.0 20 92.5 87 6.00 7879.4 173.8 8998.7 4346.4 7 89. 107.2 20 92.2 88 6.00 8364.4 196.4 9563.4 4636.4 7 95. llS.9 20 91.8 89 6.00 8880.2 222.2 10165.6 A947.8 7 101. 121.0 20 91.5 90 5.00 9337.3 246.4 10700.6 _126.5 7 106. 127.3 20 91.1 91 5.00 9818.8 273.4 11265.4 5522.7 7 112. 134.0 20 90.8 92 5.00 10326.2 303.4 11862.1 5837.8 7 117. ?41.0 20 90.4 2** BASE CASE *2* WITH CAPACITORS - %'LO* hVAft JA/29/83 SANTA MARIA 5-44 SUMMARY FOR FEEDER 44 YEAR X --KW--- KVA KVAR -MAX LOAD- MAX VOLT DROP GROW DEM LOSS DEM DEM--- SEC %CAP AMPS SECT LEVEL 82 0.00 5620.7 74.9 5904.0 1807.0 7 63. 76.0 20 95.0 83 7.00 6020.5 86.5 6334.5 2032.9 7 68. 81.5 20 94.7 84 7.00 6449.4 100.0 6839.6 2277.1 7 73. 87.3 20 94.4 S5 7.00 6909.6 115.7 7362.1 2541.3 7 78. 93.6 20 94.1 86 7.00 7403.4 133.9 7924.9 2827.5 7 84. 100.4 20 93.7 87 6.00 7857.6 152.0 8444.5 3093.1 7 89. 106.6 20 93.4 88 6.00 8340.5 172.5 8998.6 3378.1 7 94. 113.2 20 93.1 89 6.00 8854.0 195.9 9589.9 3684.1 7 100. 120.3 20 92.7 90 5.00 9309.0 218.1 10115.4 3957.7 7 105. 126.6 20 92.4 91 5.00 9788.2 242.8 10670.5 4248.6 7 111. 133.2 20 92.0 92 5.00 10293.1 270.3 11257.1 4557.9 7 117. 140.1 20 91.7 2* 8MSE CASE ** LOAD TRANSFER JA/29/83 SANTA MARIA 5-44 SUMMARY FOR FEEDER 44 YEAR % - KW--- KVA KVAR --MAX LOAD- MAX VOLT DROP GROW DEN LOSS DEN DEN SEC %.CAP AMPS SECT LEVEL 52 0.00 5633.4 87.5 6400.6 3038.6 7 64. 76.5 20 93.8 83 7.00 6034.8 100.7 6862.9 3268.2 7 68. 82.0 20 93.5 S4 7.00 6465.3 115.9 7359.7 3516.4 7 73. 87.8 20 93.2 85 -20.00 5152.6 73.0 5848.1 2766.0 7 58. 69.9 20 94.1 86 7.00 5519.1 84.0 6269.2 2973.6 7 62. 74.9 20 93.9 87 6.00 5855.9 94.7 6656.9 3165.7 7 66. 79.5 20 93.6 88 6.00 6213.8 106.9 7069.4 3371.1 7 70. 84.4 20 93.4 89 -15.00 5267.2 76.4 5979.7 2830.8 7 60. 71.5 20 94.0 90 5.00 5534.9 84.5 6287.3 2982.6 7 63. 75.1 20 93.8 91 5.00 5816.3 93.4 6611.3 3143.0 7 66. 79.0 20 93.6 92 5.00 6112.4 103.4 6952.5 3312.8 7 69. 83.0 20 93.4 2*2 LOAD TRANSFER + CAPA_(11200 D.T) *** JA/29/83 SANTA MARIA 5-44 SUMMARY FOR FEEDER 44 YEAR % ---KW- - KVA KVAR --MX LOAD- MAX VOLT DROP GROW DEN LOSS DEN DEM SEC %CAP AMPS SECT LEVEL 82 0.00 5620.7 74.9 5904.0 1807.0 7 63. 76.0 20 95.0 83 7.00 6020.5 86.5 6354.5 2032.9 7 68. 81.5 20 94.7 84 7.00 6449.4 100.0 6839.6 2277.1 7 73. 87.3 20 94.4 85 7.00 6909.6 115.7 7362.1 2541.3 7 78. 93.6 20 94.1 86 -21.00 5437.0 69.9 5697.8 1703.9k 7 61. 73.5 20 95.1 87 6.00 5768.3 79.1 6070.1 1890.2 7 65. 78.1 20 94.9 88 6.00 6120.1 89.5 6466.9 2089.4 7 69. 82.9 20 94.6 89 5.00 6431.5 99.4 6819.3 2266.8 7 73. 87.1 20 94.4 90 5.00 6759.1 110.4 7191.0 2454.6 7 76. 91.6 20 94.2 91 -7.00 6277.7 94.5 6645.2 2179.1 7 71. 85.0 20 94.5 92 5.00 6597.3 104.9 7007.3 2361.7 7 74. 89.4 20 94.3 -38 - 3 Page a of 19 8*8 A s E C A S S JA/29/83 SANTA MARIA 5-45 SUMMARY FOR FEEDER 45 YEAR % ----KW----- KVA KVAR --MAX LOAD- MAX VOLT DROP GROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 3869.7 53.5 4398.0 2089.9 20 32. 38.4 21 94.7 83 7.00 4146.2 62.8 4769.1 23S6.5 20 :4. 41.2 21 94.4 84 7.00 4443.0 73.8 5170.4 2644.4 20 37. 44.3 21 94.0 85 7.00 4761.6 86.6 5604.3 2955.4 20 40. 47.5 21 93.7 86 7.00 5103.9 101.6 6073.4 3291.8 20 43. 51.0 21 93.3 87 6.00 5419.0 116.5 6507.8 3603.6 20 45. 54.3 21 93.0 88 6.00 5754.3 133.7 6972.6 3937.7 20 48. 57.8 21 92.6 89 6.00 6111.2 153.4 7470.0 4295.9 20 51. 61.5 21 92.2 90 5.00 6427.8 172.0 7913.4 4615.8 20 54. 64.8 21 91.8 91 5.00 6761.5 193.0 8383.0 4955.4 20 57. b 68.3 21 91.5 92 5.00 7113.4 216.5 8880.5 5316.2 20 60. 72.0 21 91.1 *8* 8 A S E C A S E *8* WITH CAPACITORS(1*1200 g.) JA/29/83 SANTA MARIA 5-45 SUMMARY FOR FEEDER 45 YEAR % -- KW--- KVA KVAR -MAX LOAD- MAX VOLT DROP GROW DEN LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 3859.1 42.9 3954.1 861.4 13 33. 39.3 21 95.6 83 7.00 4133.6 50.2 4283.4 1122.7 20 34. 40.8 21 95.3 84 7.00 4428.2 59.0 4645.7 1404.8 20 37. 43.8 21 95.0 85 7.00 4744.5 69.5 5043.1 1709.5 20 39. 47.0 21 94.7 86 7.00 5084.2 81.9 5477.8 2039.0 20 42. 50.5 21 94.3 87 6.00 5396.9 94.4 5884.0 2344.3 20 45. 53.7 21 94.0 88 6.00 5729.5 108.9 6321.6 2671.3 20 48. 57.2 21 93.6 89 6.00 6083d6 125.7 6792.7 3021.7 20 51. 60.8 21 93.2 90 5.00 6397.5 141.8 7214.4 3334.7 20 53. 64.1 21 92.9 91 5.00 6728.4 159.9 7662.7 3666.8 20 56. 67.6 21 92.5 92 5.00 7077.3 180.4 8139.0 4019.4 20 59. 71.2 21 92.1 8*8s L O A D TR A N S F E R 8*8* JA/29/83 SANTA MARIA 5-45 SUMMARY FOR FEEDER 45 YEAR Z -KW- KVA KVAR ---MAX LOAD-- MAX VOLT DROP GROW DEN LOSS DEM DEN SEC %CAP AMPS SECT LEVEL 82 .0.00 3869.8 53.5 4398.1 2090.0 20 32. 38.4 a1 94.7 83 7.00 4146.2 62.8 4769.1 2356.5 20 34. 41.2 21 94.4 84 7.00 4443.0 73.8 5170.4 2644.4 20 Z7. 44.3 21 94.0 85. 7.00 4761.6 86.6 5604.3 2955.4 20 40. 47.5 21 93.7 86 7.00 5103.9 101.6 6073.4 3291.8 20 43. 51.0 21 93.3 87 6.00 5419.0 116.5 6507.8 3603.6 20 45. 54.3 21 93.0 &8 6.00 5754.3 133.7 6972.6 3937.7 20 48. 57.8 21 92.6 89 -21.00 4516.9 76.6 5270.8 2716.4 20 38. 45.0 21 94.0 90 5.00 4748.3 86.0 5586.1 2942.4 20 39. 47.4 21 93.7 91 5.00 4991.9 96.w 5919.6 3181.5 20 42. 49.9 21 93.4 92 5.00 5248.5 108.3 6272.4 3434.6 20 44. 52.5 21 93.2 888 LOAD TRANSFER + CAPACITORS(1*1200 S.) 888 JA/29/83 SANTA MARIA 5-45 SUMMARY FOR FEEDER 45 YEAR % -KW- KVA KVAR --MAX LOAD- MAX VOLT DROP GROW DEN LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 3859.1 42.9 3954.1 961.4 13 33. 39.3 21 95.6 83 7.00 4133.6 50.2 4283.4 1122.7 20 34. 40.8 21 95.3 84 7.00 4428.2 59.0 4645.7 1404.8 20 37. 43.8 21 95.0 85 7.00 4744.5 69.5 5043.1 1709.5 20 39. 47.0 21 94.7 86 7.00 5084.2 81.9 5477.8 2039.0 20 42. 50.5 21 94.3 87 6.00 5396.9 94.4 5884.0 2344.3 20 45. 53.7 21 94.0 88 6.00 5729.5 108.9 6321.6 2671.3 20 48. 57.2 21 93.6 89 6.00 6083.6 125.7 6792.7 3021.7 20 51. 60.8 21 93.2 90 5.00 6397.5 141.8 7214.4 3334.7 20 53. 64.1 21 92.9 91 -16.00 5347.2 92.3 5819.1 2295.6 20 44. 53.2 21 94.0 92 5.00 5621.6 104.1 6179.2 2565.0 20 47. 56.0 21 93.7 ANNEX 3 ~~ 39 ~~~~ Page 9 of 19 PROGRAM BALVOL DATE FE/16/83 BASE CASE 1982 FEEDER 17 CORONADO 15-17 VOLTAGE = 13.80 KV LINE TO LINE SECT LGTH PHAS COND ---LOAD THRU SECTION--- VOLTAGES (PERCENT) LOSSES K- CONF SIZE COND KW KVAR AMPS TRAN. SECT ACCU LEVEL KW UNITS X DROP DROP SUBSTATION TOTALS 840. 629. 100.0 1 0.7 3 477 ACSR 6.6 840. 629. 43.9 176. 0.1 0.1 99.9 1. 2 0.7 3 477 ACSR 0.3 41. 30. 2.1 7. 0.0 0.1 99.9 0. 3 2.5 1 1/0 ACSR 5.1 74. 55. 11.6 20. 0.3 0.5 99.5 0. 4 0.5 1 1/f ACSR 0.3 5. 4. 0.7 1. 0.0 0.5 99.5 0. 5 1.0 1 1/0 ACSR 0.6 9. 7. 1.5 2. 0.0 0.5 99.5 0. 6 1.5 1 1/0 ACSR 2.7 39. 29. 6.2 12. 0.1 0.6 99.4 0. 7 0.5 1 1/0 ACSR 0.2 3. 2. 0.5 1. 0.0 0.6 99.4 0. 8 1.0 1 1/0 ACSR 2.0 30. 22. 4.7 9. 0.1 0.6 99.4 0. 9 0.5 1 1/0 ACSR 0.2 3. 2. 0.5 1. 0.0 0.6 99.4 0. 10 1.8 1 1/0 ACSR 1.2 17. 13. 2.7 5. 0.0 0.7 99.3 0. 11 2.5 1 1/0 ACSR 0.5 8. 6. 1.2 2. 0.0 0.7 99.3 0. 12 5.3 3 477 ACSR 5.7 724. 543. 37.9 149. 0.8 0.9 99.1 3. 13 2.0 3 477 ACSR 1.6 203. 150. 10.7 39. 0.1 1.0 99.0 0. 14 0.1 3 266 ACSR 1.4 122. 90. 6.4 23. 0.0 1.0 99.0 0. 15 0.4 3 1/0 ACSR 0.3 11. 8. 0.6 3. 0.0 1.0 99.0 0. 16 0.0 1 1/0 ACSR 0.2 3. 2. 0.5 1. 0.0 1.0 99.0 0. 17 0.6 1 1/0 ACSR 0.3 5. 4. 0.7 1. 0.0 1.0 99.0 0. 19 0.7 3 266 ACSR 1.3 111. 82. 5.8 20. 0.0 1.1 98.9 0. 0.2 3 266 ACSR .1.1 95. 71. 5.0 18. 0.0 1.1 98.9 0.. . 0.6 1 1/0 ACSR 6.5 95. 71. 15.0 18. 0.1 1.2 98.8 0. 21 0.7 1 1/0 ACSR 3.8 56. 41. 8.8 8. 0.1 1.2 98.8 0. 22 0.3 1 1/0 ACSR 0.9 13. 9. 2.0 2. 0.0 1.2 98.8 0. 23 0.8 1 1/0 ACSR 1.8 26. 19. 4.1 3. 0.0 1.3 98.7 0. 24 0.9 1 1/0 ACSR 2.1 30. 22. 4.7 7. 0.0 1.2 98.8 0. 25 0.2 1 1/0 ACSR 0.3 5. 4. 0.7 1. 0.0 1.2 98.8 0. 26 0.3 1 1/0 ACSR 0.3 S. 4. 0.7 1. 0.0 1.2 98.8 0. 27 0.8 1 1/0 ACSR 0.3 5. 4. 0.7 1. 0.0 1.2 98.8 0. 28 0.0 3 1/0 ACSR 1.0 44. 33. 2.3 6. 0.0 1.0 99.0 Oo 29 0.2 1 1/0 ACSR 1.1 16. 12. 2.5 2. 0.0 1.0 99.0 0. 30 0.2 2 1/0 ACSR 1.0 28. 21. 2.2 4. 0.0 1.0 99.0 0. 31 0.1 1 1/0 ACSR 0.3 5. 4. 0.7 1. 0.0 1.0 99.0 0. 32 0.4 1 1/0 ACSR 1.1 16. 12. 2.5 2. 0.0 1.0 99.0 0. 33 1.5 3 1/0 ACSR 0.8 36. 27. 1.9 10. 0.0 1.1 98.9 0. 34 1.5 3 1/0 ACSR 0.5 20. 15. 1.1 6. 0.0 1.1 98.9 0. 35 0.6 1 1/0 ACSR 2.5 36. 27. 5.7 7. 0.0 1.0 99.0 0. 36 0.6 1 1/0 ACSR 0.6 9. 7. 1.5 2. 0.0 1.0 99.0 0. 37 1.4 1 1/0 ACSR 1.3 19. 14. 3.0 3. 0.0 1.0 99.0 0. 38 0.3 1 1/0 ACSR 20.2 294. 218& 46.4 61e 0.2 1.2 98.8 0. ANNEX 3 Page 10 of 19 - 40 - bECT LGTH NO. COND --- LOAD THRU SECTION --- VOLTAGES(PERCENT) LOSSES K- PHAS SIZE COND KW KVAR AMPS TRAN SECT ACCU LEVEL KW UNITS . *h DROP DROP 39 0.3 1 1/0 ACSR 0.5 8. 6. 1.2 2. 0.0 1.2 98.8 0. 40 0.1 3 1/0 ACSR 6.0 262. 194. 13.8 55. 0.0 1.2 98.8 0. 41 0.3 1 4 ACSR 0.9 8. 6. 1.2 1. 0.0 1.2 98.8 0. 42 0.3 3 1/0 ACSR 5.8 255. 188. 13.4 54. 0.0 1.2 98.8 0. 43 0.7 3 1/0 ACSR 5.4 237. 176. 12.5 51. 0.1 1.3 98.7 0. 44 0.6 3 1/0 ACSR 5.0 218. 161. 11.5 47. 0.1 1.4 98.6 0. 45 0.5 3 1/0 ACSR 4.5 194. 144. 10.2 43. 0.1 1.4 98.6 0. 46 4.0 1 1/0 ACSR 1.0 14. 11. 2.2 v. 0.1 1.5 98.5 0. 47 3.3 11/0 ACSR 0.3 5. 4. 0.7 1. 0.0 1.5 98.5 0. 48 0.2 3 1/0 ACSR 3.8 167. 124. 8.8 37. 0.0 1.4 98.6 0. 49 0.8 3 4 CU 1.6 50. 37. 2.7 12. 0.0 1.5 98.5 0. 50 0.6 3 4 CU 0.7 24. 19. 1.2 5. 0.0 1.5 98.,5 0. 51 0.8 31/0 ACSR 2.7 117. 86. 6.2 25. 0.0 1.5 98.5 0. 52 0.1 3 1/0 ACSR 0.7 28. 21. 1.5 6. 0.0 1.5 98.5 0. 53 0.6 1 1/0 ACSR 4.5 65. 48. 10.3 14. 0.1 1.6 98.4 0. 54, 0.9 1 1/0 ACSR 0.8 11. 8. 1.8 3. 0.0 1.6 98.4 0. 55 4.0 1 1/0 ACSR 2.8 41. 30. 6.5 9. 0.3 1.8 98.2 0. 56 3.5 1 1/0 ACSR 1.9 27. 20. 4.3 6. 0.1 1.9 98.1 0. 57 1.6 3 477 ACSR 1.3 161. 119. 8.5 38. 0.0 1.0 99.0 0. 58 0.9 3 477 ACSR 1.0 126. 94. 6.6 32. 0.0 1.0 99.0 0. 0.5 1 1/0 ACSR 0.6 9. 7. 1.5 2. 0.0 1.0 99.0 0. o 0.4 3 477 ACSR 0.8 104. 77. 5.5 26. 0.0 1.0 99.0 0. 61 3.3 3 477 ACSR 0.7 93. 69. 4.9 23. 0.1 1.1 98.9 0. 62 2.5 1 1/0 ACSR 0.4 6. 5. 1.0 2. 0.0 1.1 98.9 0. 63 3.5 3 477 ACSR 0.6 79. 58. 4.2 19. 0.1 1.1 98.9 0. 64 2.5 3 477 ACSR 0.5 61. 46. 3.2 14. 0.0 1.2 98.8 0. 65 1.8 3 477 ACSR 0.3 35. 26. 1.8 7. 0.0 1.2 98.8 0. 66 0.9 3 477 ACSR 0.1 11. 8. 0.6 3. 0.0 1.2 98.8 0. END OF FEEDER TOTAL LOSSES ON FEEDER 17 KW 5.4 KVAR 11.6 NOTEs KW AND KVAR LOADING THRU SECTION INCLUDES DEMANDS WITHIN SECTION, LOADING FROM DOWNSTREAM SECTIONS, AND LOSSES. SUMMARY OF FEEDER 17 VOLTAGE DROP MAXIMUM VOLTAGE WIRE LOAD MAXIMUM LOSSES SECT.NO. VOLTS DROP LEVEL SECT.NO. PCT.CAP. KVA KW KVAR .06 1.95 98.0 38 20.19 12.77 5.40 11.57 ANNEX 3 Page 11 of 19 - 41 - PROGRAM CAPLOC DATE 03/14/83 ADD 600 KVAR CAPACITORS FEEDER 17 CORONADO 15-17 VOLTAGE 13.80.KV LINE TO LINE SECT LGTH PHAS COND ---LOAD THRU SECTIOt'--- VOLTAGES (PERCENT) LOSSES K- CONF SIZE COND KW KVAR AMPS TRAN SECT ACCU LEVEL KW UNIT % DROP DROP SUBSTATION TOTALS 838. 26. b 100.0 1 0.7 3 477 ACSR 5.2 838. 26. 35. 176.0 0.0 0.0 100.0 0. 2 0.7 3 477 ACSR 0.3 41. 30. 2. 7.0 0.0 0.0 100.0 0. 3 2.5 1 1/0 ACSR 5.0 74. 55. 12. 20.0 0.3 0.4 99.6 0. 4 0.5 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.4 99.6 0. 5 1.0 1 1/0 ACSR 0.6 9. 7. 1. 2.0 0.0 0.4 99.6 0. 6 1.5 1 1/0 ACSR 2.7 39. 29. S. 12.0 0.1 0.5 99.5 0. 7 0.5 1 1/0 ACSR 0.2 3. 2. 0. 1.0 0.0 0.5 99.5 0. 8 1.0 1 1/0 ACSR 2.0 30. 22. 5. 9.0 0.1 0.5 99.5 0. 9 0.5 1 1/0 ACSR 0.2 3. 2. 0. 1.0 0.0 0.5 99.5 0. 10 1.8 1 1/0 ACSR 1.2 17. 13. 3. 5.0 0.0 0.6 99.4 0. 11 2.5 1 1/0 ACSR 0.5 8. 6. 1. 2.0 0.0 0.6 99.4 0. 12 5.3 3 477 ACSR 4.5 723. -61. 30. 149.0 0.2 0.2 99.8 2. 13 2.0 3 477 ACSR 1.6 203. 150. 11. 39.0 0.1 0.3 99.7 0. 14 0.1 3 266 ACSR 1.4 122. 90. 6. 23.0 0.0 0.3 99.7 0. 15 0.4 3 1/0 ACSR 0.3 11. 8. 1. 3.0 0.0 0.3 99.7 0. 16 0.0 1 1/0 ACSR 0.2 3. 2. 0. 1.0 0.0 0.3 99.7 0. 17 0.6 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.3 99.7 0. i8 0.7 3 266 ACSR 1.3 111. 82. 6. 20.0 0.0 0.3 99.7 0. 19 0.2 3 266 ACSR 1.1 95. 71. 5. 18.0 0.0 0.4 99.6 0. 20 0.6 1 1/0 ACSR 6.5 95. 71. 15. 18.0 0.1 0.5 99.5 0. 21 0.7 1 1/0 ACSR 3.8 56. 41. 9. 8.0 0.1 0.5 99.5 0. 22 0.3 1 1/0 ACSR 0.9 13. 9. 2. 2.0 0.0 0.5 99.5 0. 23 0.8 1 1/0 ACSR 1.8 26. 19. 4. 3.0 0.0 0.6 99.4 0. 24 0.9 1 1/0 ACSR 2.0 30. 22. 5. 7.0 0.0 0.5 99.5 0. 25 0.2 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.5 99.S 0. 26 0.3 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.5 99.5 0. 27 0.8 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.5 99.5 0. 28 0.0 3 1/0 ACSR 1.0 44. 33. 2. 6.0 0.0 0.3 99.7 0. 29 0.2 1 1/0 ACSR 1.1 16. 12. 2. 2.0 0.0 0.3 99.7 0. 30 0.2 2 1/0 ACSR 1.0 28. 21. 2. 4.10 0.0 0.3 99.7 0. 31 0.1 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.3 99.7 0. 32 0.4 1 1/0 ACSR 1.1 16. 12. 2. 2.0 0.0 0.3 99.7 0. 33 1.5 3 1/0 ACSR 0.8 36. 27. 2. 10.0 0.0 0.3 99.7 0. 34 1.5 3 1/0 ACSR 0.5 20. 15. 1. 6.0 0.0 0.4 99.6 0. 35 0.6 1 1/0 ACSR 2.5 36. 27. 6. 7.0 0.0 0.3 99.7 0. 36 0.6 1 1/0 ACSR 0.6 9. 7. 1. 2.0 0.0 0.3 99.7 0. 37 1.4 1 1/0 ACSR 1.3 19. 14. 3. 3.0 0.0 0.3 99.7 0. 38 0.3 1 1/0 ACSR 26.4 294. -382. 61. 61.0 0.1 0.3 99.7 0. CAPACITOR IN SECTION 38 600 .3 ANNMC 3 Page 12 of 19 - 42 - FEEDER 17 1982 600 KVAR SECT LGTH NO. COND --- LOAD THRU SECTION --- VOLTAGE8(PERCENT) LOSSES K- PHAS SIZE COND KW KVAR AMPS TRAN SECT ACCU LEVEL KW UNITS X DROP DROP 39 0.3 1 1/0 ACSR 0.5 8. 6. 1. 12.0 0.0 0.3 99.7 0. 40 0.1 3 1/0 ACSR 6.0 262. 194. 14. 55.0 0.0 0.3 99.7 0. 41 0.3 1 4 ACSR 0.9 8. 6. 1. 1.0 0.0 0.3 99.7 0. 42 0.3 3 1/0 ACSR 5.8 255. 188. 13. 54.0 0.0 0.4 99.6 0. 43 0.7 3 1/0 AC5R 5.4 237. 176. 12. 51.0 0.1 0.5 99.5 0. 44 0.6 3 1/0 ACSR 5.0 218. 161. 11. 47.0 0;.1 0.6 99.4 0. 45 0.5 3 1/0 ACSR 4.4 194. 144. 10. 43.0 0.0 0.6 99.4 0. 46 4.0 1 1/0 ACSR 1.0 14. 11. 2. 4.0 0.1 0.7 99.3 0. 47 3.3 1 1/0 ACSR 0.3 5. 4. 1. 1.0 0.0 0.7 99.3 0. 48 0.2 3 1/0 ACSR 3.8 167. 124. 9. 37.0 0.0 0.6 99.4 0. 49 0.8 3 4 CU 1.6 50. 37. 3. 12.0 0.0 0.6 99.4 0. 50 0.6 3 4 CU 0.7 24. 18. 1. 5.0 0.0 0.6 99.4 0. 51 0.8 3 1/0 ACSR 2.7 117. 86. 6. 25.0 0.0 0.7 99.3 0. 52 0.1 3 1/0 ACSR 0.6 28. 21. 1. 6.0 0.0 0.7 99.3 0. 53 0.6 1 1/0 ACSR 4.4 65. 48. 10. 14.0 0.1 0.7 99.3 0. 54 0.9 1 1/0 ACSR 0.8 11. 8. 2. 3.0 0.0 0.8 99.2 0. 55 4.0 1 1/0 ACSR 2.8 41. 30. 6. 9.0 0.3 1.0 99.0 0. 56 3.5 1 1/0 ACSR 1.8 27. 20. 4. 6.0 0.1 1.1 98.9 0. 57 1.6 3 477 ACSR 1.3 161. 119. 8. 38.0 0.0 0.3 99.7 0. 58 0.9 3 477 ACSR 1.0 126. 94. 7. 32.0 0.0 0.3 99.7 0. 59 0.5 1 1/0 ACSR 0.6 9. 7. 1. 2.0 0.0 0.3 99.7 0. 60 0.4 3 477 ACSR 0.8 104. 77. 5. 26.0 0.0 0.3 99.7 0. 61 3.3 3 477 ACSR 0.7 93. 69. 5. 23.0 0.1 0.4 99.6 0. 62 2.5 1 1/0 ACSR 0.4 6. 5. 1. 2.0 0.0 0.4 99.6 0. 63 3.5 3 477 ACSR 0.6 79. 58. 4. 19.0 0.1 0.4 99.6 0. 64 2.5 3 477 ACSR 0.5 61* 46. 3. 14.0 0.0 0.5 9P.5 0. 65 1.8 3 477 ACSR 0.3 35. 26. 2. 7.0 0.0 0.5 99.5 0. 66 0.9 3 477 ACSR 0.1 11. 8. 1. 3.0 0.0 0.5 99.5 0. END OF FEEDER TOTAL LOSSES ON FEEDER 17 KW 4.0 KVAR 3 8.0 NOTE: KW AND KVAR LOADING THRU SECTION INCLUDES DEMANDS WITHIN SECTION, LOADING FROM DOWNSTREAM SECTIONS, AND LOSSES. ANX 3 Page 13 of 19 - 43 - SASE CASE 03/14/83 CORONADO 15-17 SUMMARY FOR FEEDER 17 YEAR % ----KW----- KVA KVAR ---MAX LOAD--- MAX VOLT DROP BROW DEM LOSS DEM DEM SEC %CAP AMPS SECT LEVEL 82 0.00 839.8 5.4 1049.5 629.4 38 20. 46.4 56 98.1 83 7.00 899.0 6.2 1123.8 674.4 38 22. 49.7 56 97.9 84 7.00 962.4 7.1 1203.5 722.6 38 23. 53.3 56 97.8 85 7.00 1030.3 8.1 1288.8 774.3 38 25. 57.1 56 97.6 86 7.00 1103.1 9.3 1380.4 829.9 38 27. 61.1 56 97.4 87 7.00 1181.0 10.7 1478.5 889.5 38 28. 65.5 56 97.2 88 6.00 1252.6 12.1 1568.7 944.4 38 30. 69e. 56 97.1 89 6.00 1328.5 13.6 1664.5 1002.8 38 32. 73.8 56 96.9 90 5.00 1395.7 15.0 1749.3 1054.5 38 34. 77.6 56 96.7 91 5.00 1466.3 16.6 1838.5 1109.0 38 35. 81.5 56 96.6 92 4.00 1525.7 18.0 1913.5 1154.9 38 37. 84.9 56 96.4 93 4.00 1587.5 19.5 1991.7 1202.8 38 38. 88.4 56 96.3 5 ANNEX 3 Page 14 of 19 - 44 - ADD 600 KVAR CAPACITORS 03/14/83 CORONADO 15-17 SUMMARY FOR FEEDER 17 YEAR % ---- KW…----- KVA KVAR --- MAX LOAD-- MAX VOLT DROP (ROW DEM LOSS DEM DEM SEC XCAP AMPS SECT LEVEL 82 0.00 838.4 4.0 838.8 25.8 38 26. 60.7 56 98.9 83 7.00 897.3 4.5 900.1 70.2 38 26. 60.9 56 98.7 84 7.00 960.5 5.2 967.7 117.8 38 27. 61.3 56 98.6 85 7.00 1028.1 6.0 1041.9 168.8 38 27. 61.9 56 98.4 86 7.00 1100.6 6.9 1123.1 223.7 38 27. 62.8 56 98.3 87 7.00 1178.2 7.9 1211.6 282.5 38 28. 6A.1 56 98.1 a8 6.00 1249.5 9.0 1294.0 336.7 38 28. 65.4 56 97.9 89 6.00 1325.1 10.2 1382.5 394.3 38 29. 67.1 56 97.7 90 5.00 1392.0 11.3 1461.5 445.3 38 30. 68.8 56 97.6 91 5.00 1462.3 12.6 1545.1 499.1 38 31. 70.7 56 97.4 92 4.00 1521.4 13.7 1615.9 544.3 38 32. 72.5 56 97.3 93 4.00 1583.0 15.0 1689.9 591.6 38 32. 74.4 56 97.1 .~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ ANNEX 3 Page 15 of 19 _ 45 - PROGRAM LPDAIN BASE CASE CORONADO 15-17 CONTENTS OF WORLD BANK LOSS ANALYSIS FILES NUMBER OF STUDY YEARS = S INTEREST RATE (t) = 12.00 NUMBER OF SEASONS 1 MONTHS IN 1ST SEASON 12 COSTS IN "BALBOAS PEAK PEAK LOAD LOSS ENERSY CAPACITY YEAR/ DEMAND LOSS FACTOR FACTOR COST COST SEASON (KW) (KW) (%) (X) ($/KWH) ($/KW) 85 1 1030.30 8.10 59.00 42.00 0.0695 353.00 86 1' 1103.10 9.30 59.00 42.00 0.0695 353.00 87 1 1181.00 10.70 59.00 42.00 0.0695 353.00 88 1 1252.60 12.10 59.00 42.00 0.0695 353.00 89 1 1328.50 13.60 59.00 42.00 0.0695 353.00 ANNEX 3 Page 16 of 19 - 46 - PROGRAM LPDAIN BASE CASE CORONADO 15-17 WORLD BANK LOSS ANALYSIS DEMANDS AND ENERGY YEAR/ DEMAND ENERGY ---- LOSSES ---- PERCENT LOSSES FACTORS(%) SEASON KW MWH PEAK KW MWH PEAK ENERGY LOAD LOSS 85 1 1030.3 5325.0 8.1 29.8 0.79 0.56 59.0 42.0 86 1 1103.1 5701.3 9.3 34.2 0.84 0.60 59.0 42.0 87 1 1181.0 6103.9 10.7 39.4 0.91 0.64 59.0 42.0 88 1 1252.6 6473.9 12.1 44.5 0.97 0.69 59.0 42.0 4 89 1 1328.5 6866.2 13.6 50.0 1.02 0.73 59.0 42.0 ANNEX 3 47 P*ge 17 of 19 PROGRAM LPDAIN BASE CASE CORONADO 15-17 WORLD BANK LOSS ANALYSIS COSTS AND PRESENT WORTH OF COSTS YEAR/ ANNUAL COST OF LOSSES PRESENT WORTH OF COST OF LOSSES SEASON CAPACITY ENERGY TOTAL CAPACITY ENERGY TCTAL 85 1 2859.3 2071.2 4930.5 2859.3 2071.2 4930.5 86 1 3282.9 2378.1 5661.0 2931.2 2123.3 5054.4 87 1 3777.1 2736.0 6513.1 3011.1 2181.2 5192.2 88 1 4271.3 3094.0 7365.3 3040.2 2202.3 5242.5 89 1 4800.8 3477.6 8278.4 3051.0 2210.1 5261.1 TOTALS 18991.4 13756.9 32748.3 14892.8 10787.9 25680.7 FUTURE 96016.0 69551.6 165567.6 20347.5 14739.2 35086.8 SERIES (25 YRS) TOTALS 115007.4 83308.5 198315.9 35240.3 25527.2 60067.5 NUMBER OF STUDY YEARS - 5 INTEREST RATE (%) = 12.00 NUMBER OF SEASONS = 1 MONTHS IN 1ST SEASON = 12 COSTS IN "BALBOAS ANNEX 3 Page 18 of 19 -48- WORLD BANK LOSS ANALYSIS DEMANDS AND ENERGY CORONADO 15-17 ADD 600 KVAR CAPACITORS YEAR/ DEMAND ENERGY ---- LOSSES ---- PERCENT LOSSES FACTORS (Y.' SEASON KW MWH PEAK KW MWH PEAK ENERGY LOAD LOSS 85 1 1028.1 5313.6 6.0 22.1 0.58 0.42 59.0 42.0 86 1 1100.6 5688.3 6.9 25.4 0.63 0.45 59.0 42.0 87 1 1178.2 6089.4 7.9 29.1 0.67 0.48 59.0 42.0 a8 1 1249.5 6457.9 9.0 33.1 0.72 0.51 59.0 42.0 89 1 1324.1 6843.5 10.2 37.5 0.77 0.55 59.0 42.0 ANNEX 3 Page 19 of 19 - 49 - WORLD BANK LOSS ANALYSIS COSTS AND PRESENT WORTH OF COSTS ADD 600 KVAR CAPACITORS CORONADO 15-17 YEAR/ ANNUAL COST OF LOSSES PRESENT WORTH OF COST OF LOSSES SEASON CAPACITY ENERGY TOTAL CAPACITY ENERGY TOTAL 85 1 2118.0 1534.2 3652.2 2118.0 1534.2 3652.2 86 1 2435.7 1764.4 4200.1 2174.7 1575.3 3750.1 87 1 2788.7 2020.1 4808.8 2223.1 1610.4 3833.5 88 1 3177.0 2301.3 5478.3 2261.3 1638.0 3899.4 89 1 3600.6 2608.2 62o8.8 2288.2 1657.5 3945.8 TOTALS 14120.0 10228.2 24348.2 11065.4 8015.5 19081.0 FUTURE 72012.0 52163.7 124175.7 15260.6 11054.4 26315.1 SERIES (25 YRS) TOTALS 86132.0 62391.9 148523.9 26326.1 19070.0 45396.1 NUMBER OF STUDY YEARS = 5 INTEREST RATE (X.) - 12.00 NUMIS' OF SEASONS 1 CAt MOl'HS IN 1ST SEASON = 12 COSTS IN "BALBOAS - so - ANNEX 4 LONG RUN MARGINAL COSTS FOR VALUATION OF TECHNICAL LOSSES IN PANAMA ELECTRICAL DISTRIBUTION SYSTEM Introduction 1. Both technical and non-technical losses in the power distribution network constitute a component of the demand on the electrical power system at any point in time. Non-technical losses which consist of thefts and unmetered consumption do not constitute economic cost to a country since they are consumed within the country and the marginal utility of consumption is at least equal to the marginal cost of providing a unit of non-tecehnical loss. However, technical losses which 'depend on the amount of load and the electrical characteristics of the distribution network constitute an economic resource cost since they are not available for consumption. The aim of a loss reduction program is to attempt to reduce these losses and to save economic resources which otherwise are lost in the form of increased technical losses as the network expands to meet the growth in load on the prior basis that it is economically beneficial to reduce such losses in the electric power distribution system. 2. A reduction in the losses is therefore a reduction in the demand on the system. Since a unit increment in demand should be valued at the economic resource cost of the facilities required to provide that unit increment in demand, marginal losses should be valued in the same way. Altevnatively stated, a unit reduction in losses at the margin should reflect the avoided incremental economic resource cost of the facilities that would have been used to provide that same unit. Technical losses consist of peak kilowatt and kilowatt-hour losses, and must be valued at the long run economic marginal costs of peak capacity and energy. 3. The long run marginal cost reflects the economic resource cost of the incremental generation facilities that would be required to meet the incre- mental demand. The 'optimum" (preferred) investment program in additional generation, traniformation and transmission facilities and optimm generating system simulation which enables indetification of marginal generating plants provide bases for deriving the LRMC of peak capacity and of energy. 4. For Panama, the preferred power system investment program in additional generating facilities for the period from 1983 to 1993 include the La Fortuna hydroelectric scheme which is to be completed in two stages; Stage I in 1984 with installed capacity of 225 MW, and Stage II which involves increasing the height of the dam to provide an additional 45 MW of capacity. This stage is expected to be completed in 1987. The other hydro-scheme is Changuinola of 300 MW installed capacity expected to be in service in 1991. A gas turbine of 42.8 MW Installed capacity was commissioned in early 1983. 5. Network investment totalling about $276 million includes both systems improvement and extensions. Of this amount 92% is expected to be spent on distribution and the remaining 8% on high voltage transmission including interconnection with Costa Rica which is expected to be in service in 1984. - 51- ANNEX 4 Page 3 of 6 6. Electrical energy demand is expected to grow at 6% per annum from 2,095 GNh in 1983 to 4,424 GWh in 1995. Maximum demand is forecast to grow at about 7% per annum from 364 MW in 1983 to 683 MS in 1993. The investment program is shown in Tables 2 and 3. Marginal Peak CaDacity Costs 7. The derivation of the long run marginal cost of peak capacity for valuation of peak kilowatt losses is based on the component of the preferred long term investment program which is most sensitive to changes in the incremental peak kilowatt demand and which the system planners would adopt as the least cost means of meeting the incremental peak kilowatt demand. The relevant capital cost and fixed O&M costs are those of incremental power house, electro-mechanical equipment and of the associated transformation and transmission facilities (kilowatt related costs tnly, excluding civil works related to storage) and of the incremental network included In the optimum investment program. 8. For Panama, these costs reflect the economic cost of providing the incremental capacity from Chanquinola hydroelectric scheme and the incremental additions to the network from 1983 to 1993. All costs are expressed in ecvmaomic terms and in constant 1982 prices. 9. The incremental capacity created when Chanquinola is commissioned is sufficient to provide peaking capacity all year round and the incremental peak kilowatt cost Is sufficient to purchase firm power (for example, gas turbine) for dry periods. 10. The estimate of peak kilowatt cost for the medium voltage range using 12% discount rate as the opportunity cost of capital to Panama is given below. PEAK CAPACITY COST B/./kW/year Generation Distribution Voltage Generation 192 224 * Medium Voltage - 129 Total 192 353 Peak Losses (X) 18 Marginal Energy Cost 11. Marginal energy cost is basci on the fuel, operation and maintenance costs of the marginal generating facility that is used to provide the Incremental kilowatt-hour. -52 - ANNEX 4 Page 3 of 6 12. Computation of marginal energy cost for valuation of kilowatt-hour losses in the Panama electrical distribution network is based on IRHE's proposed generation program from 1983 to 2000 under conditions of long term average hydrology. From the generation program, the marginal generating plant is identified for each year and hydrology. The Pieletick diesels and the new gas turbines appear as the most probable marginal plants. Probability of requiring thermal generation to meet energy requirements is calculated for each year using data on required generation and available hydro generation in wet and dry years. The probability estimates are used to determine the present value of probability weighted average fuel cost. Energy cost is made up of the fuel costs and the variable component of operation and maintenance costs of the marginal plants. Supply of Fuel to IRHE 13. Fuel for power operations is supplied to PEHE from a Texaco refinery at Las Minas at prices determined by the Government of Panama. The price is based on an after-tax earning of Texaco of 10% per annum on revalued assets which are being operated at about 60% capacity. The crude oil is imported by the Government of Panama for the refinery. Part of the production of the refinery is consumed in Panama and the rest is exported. IRHE purchases fuel from the refinery at prices much higher than the CIF international competitive price. The difference between the domestic sales price to IRHE and the CIF price if IRHE were to purchase its fuel on the international markat is rather substantial, as shown below: Texaco Price CIF (International Fuel Typ to IRHE (ton) Price) (ton) Bunker C US$221 US$171 Diesel US$385 US$280 14. However, the entire difference between the two prices does not constitute an economic resource cost, since there are transfer payments involved in the domestic price. 15. In order to arrive at a measure of the economic cost of fuel for power operations, the domestic price must be adjusted to reflect: (a) taxes paid by Texaco to the Government of Panama; (b) re-invested earnings in Panama by Texaco, and (c) the economic subsidy on the proportion of production exported. ANNEX 4 - 53 Page 4 of 6 16. In the absence of information on transfer payments and the proportion of production: exported, the international CIF price is adopted as a measure of the economic cost of fuel. Analysis of fuel cost per type of plant is shown in Table 1. 17. The estimated long run marginal cost for valuation of kilowatt-hour losses is given below. LRMC OF ENERGY US$/kWh Generation Distribution Voltage 0.0615 0.0695 D Average kWh l1eses (X) 13 - 54 - ANNEX 4 Page 5 of 6 TABLE 1 ANALYSIS OF FUEL COSTS 1. Plant: Ia Nnas Units 2. 3 & 4 4, Plant: Pielatic Diesels Plant teat rate: 11,900 Btu/kWh plait heat rat: 10,500 t/h Fuel type: 8uner c Fuel type: Bunr C CCF vale: $171/ton (12/1982 price) C Bnraloz factor: 6.7 brrels/ton c ,kw 10,500 x $25.5 Cost per barrel: MB$ 25.5 6,369,375 1 poud resiul fuel: 18,750 Btu - Ob/ 339.7 pounds: 1 barrel of Bunker C iut/barrel: 339.7 x 18,750 . Plan: SFansoG38 Turbfne - 6,369.375 119a00x $25.5 Plait beat rate: 18,000 BtuAfth Cost/kWh: 11,900 x $25P5 Fuel type: DLesel ol 6,369,375 CIP value: $280/ton Cost per barrel: $37.8 - $D.0476 I 18,000 x $37.8 2. Plant: Las Minas Unit 1 5,830,76 Plant heat rate: 12,900 Btu/h $0.1167 Fel type: bnker C cost 12,900 x $25.58 6. Plant: San Franesco Stean 6,369,375 Fbel type: abnker C Plant bear rate: 13,560 Btu/kWh - -013518 3 Elant Nbw Gbs Ibrbfine Cost/kWh: $25.5 x 13,560 *Plant: Nw Gas TUrb*ne 6,369,375 Plait beat rate: 13,200 B:u/kWh , Fuel type: Diesel oil CII value: UB$ 280/ton Cost per barrebL U5$ 37.8 ito/barrel: 5,830,761 Cast>>"kb. 37.8 x 13,200 5,830,761 f -$0J3857 j Orrest rate If ifnscmeodatf in Power Plant Srudy are Implemented. /Consuptmolaf lubrieates included tn operation and lnt cus cost. 55 - ANNEX -4 Page 6 of 6 TABLE 2 IVVESTMENT PROGRAM 1982 - 1991 HYDRO POWER DEVELOPMENT Cost Estimates in January 1982 prices lillion US$ Fortuna I Fortuna II Changuinola* Bayano Total Cum. 1981 132.7 - - - 132.7 1982 107.4 - 2.2 - 109.6 1983 79.3 - 7.6 - 86.9 1984 74.7 0.9 14.3 - 89.9 1985 19.5 22.3 - 41.8 1986 25.2 55 8 - 81.0 1987 10.2 93.'7 - 103.9 1988 162.2 - 162.2 1989 109.0 - 109.0 1990 55.0 - 55.0 1991 TABLE 3 INVESTMENT PROGRAM 1982-1991 NETWORK Cost Estimates in January 1982 prices Million US$ Power V Substations Power VI Rural Intercon. Distribu- & Other Dis- Distribu- 115 kV Electri- Costa tion tribution Works tion Line fication Rica Total Cum 81 11.1 - - - 2.0 - 13.1 82 13.7 8.3 - - 0.4 i 1 23.5 83 10.5 10.7 4.9 0.2 11.8 5.5 43.6 84 2.2 11.7 14.7 3.5 5.6 1.8 39.5 85 16.8 18.8 5.2 1.8 - 42.6 86 17.4 9.7 4.1 - 31.2 87 18.2 18.2 88 89 90 - 56 - ANNEX 5 SUBSTATION METERING 1. As indicated above, availability of metering and load data for the different substations varies. All stations inspected for which data was obtained had combined instantaneous and thermal demand ammeters. Some stations had watthour meters in the transformer secondaries, others did not (in the Metropolitan District, these watthour-meters had pulse initiators to transmit watthour data to the Leeds and Northrup computer at the control center, however, this system is incomplete). In the Panama Occidente District, substations transformers and feet'ers were equipped with both watt and varhour meters. The wattmeters had demand attachments. In other districts, meters were apparently installed but not read or the data was not included in the monthly operating reports. l 2. Furthermore, several different types of forms are used in the operating department monthly reports for reporting substation and feeder loading. Apparently not all available information is listed. 3. Over the above the proposed load survey metering included in the proposed 1983 to 1986 distributica system expansion program, the following is recommended for installation to all existing and new substations: - Instantaneous and thermal demand ammeters in each feeder. Data can be used to monitor feeder maximum demand and in conjunction with the kilowatt meters an approximate power factor. - Kilowatt-hour meter with a demand attachment and with a pulse generator in the transformer secondary. The later is used as an input to the casette or cartridge type load survey systems now on the market and to the load control center. - Kilowatt-hour meter in the supply to substation service transformers 5 KVA and larger to report IRHE's use. - Kilovar-hour meter (or a kilowatt-hour meter with a phase shifting transformer) in transformers all substations 2,500 kVA and larger. These meters should also have a generator for future use with any load survey equipmuent. - Kilowatt-hour meters in all feeders with a design capacity in excess of 5,000 kVA (primarily in the !*tropolitan District). These should also have a pulse generator for future use with load survey equipment. - Voltmeters to check the voltage level of all substation buses. Major substations should be provided with volt-transducers to transmit bus voltage data to the load control center or for use with load survey equipment. -57- ANNEX 5 Page 2 of 2 4. Installation of the above, in particular, watthour meters, should be initiated now to improve the data base for system planning since the proposed load survey equipment will take some time to purchase and install. The watthour-meters, in particular, are a back-up if the load survey equipment fails or is not in use. In addition, a universal substation and feeder report form, with space for entering the above data, should be used by all operating districts. The form should also provide space to make note both of whether or not instrumentation is working, and of major switching changes which would alter report data or other unusual circumstances which would affect system analysis. 5. Substations in the Metropolitan District have watt and var transducers and an incomplete installation of kilowat6 meters with pulse transmitters in the low voltage side of the substation transformer. This information is transmitted to the load dispatch genter. The instantaneous watt and var readings are displayed on the dispatch CRT, but use of the kilowatt-hour data is not clear. The Leeds and Northrup systems' dispatch control can be utilized to obtain load data and daily load curves for some substations. G,ENATING PLANT T1 CRflICAL SUPPMET TO PROJECT IDhENTMCATION REPORT I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ . .. TABLE OP CONTENTS Page No. CHAPTER I - INTRODUCTION.. ......... .......... ....,... 1 CHAPTER II - THERMAL PLANT OPERATIONS,................................ 1 CHAPTER III - THERMAL PLANT MAINTENANCE.............*** ................. 3 Bahia Las Minas Plant .........................*...... 3 San Francisco Plant .................. e ...................... 4 Rural Diesel Units ............... . 4 CHAPTER IV - GENERATION LOSS REDUCTION PROJECT .............. .*. 4 CHAPTER V - OTHER OBSERVATIONS ....... ........., ...................... 6 Steam Turbine Efficdency ... e.eeee. eeeeeeeeee..eeeee..., 6 Variable Speed Drives ........................ 6 Postponement of Hydro Generating Plant ...................... 7 TABLES 2.1 Preferred Sequence for Loading Thermal Plants ................ 2 4.1 Estimated Cost of Generation Loss Reduction Project at BLM ..e.........eeeeeee.ce.ee.eccc.ecCececeececeeccecee 5 4.2 Benefits in 1984 from Loss Reduction Project at BLM ......... 5 ANNEES 1. IRHE Power Generating Facilities .......e-....-.........-- 9 2. Forecast Generation (GWh) (based on Stacking Sequence) ...... 10 3. Improveuents to Boiler and Turbine Efficiency ............... 12 4. Cold Storage Procedures eece.ee...ee,ceeoeeeeeceeee..... e.e .. 15 PANAMA UNITED NATIONS DEVELOPMENT PROGRAMME POWER SYSTEM LOSS REDUCTION STUDY GENERATING PLANT TECHNICAL SUPPLEMENT TO PROJECT IDENTIFICATION REPORT CHAPTER I INTRODUCTION l 1.01 This Section of the Technical Supplement reviews the operating efficiency of the principal steam plants namely Bahia Las Minas (BLM) and San Francisco (SF) and makes observations on some of the other generating facilities. The power generating facilities of IRHE are listed in Annex 1. CHAPTER II THERMAL PLANT OPERATIONS 2.01 In general, IRHE's policy is to maximize the use of hydro generation aad, consequently, to minimize the use of thermal plants to save fuel, which has to be imported. Starting in 1982 exceptionally low stream flow has been experienced at the Bayano Hydro Plant so that the thermal plants (BLM and SF) have been operating at full capacity. The two new gas turbines at the load dispatch center (GTDC) were only placed in service in February 1983 and had not been placed in commercial operation during the team's visit. It is expected that BLM and SF units will have to continue operating at present output through 1983 and 1984. After that time the La Fortuna Hydroelectric Plant (300 MW) is scheduled to come into service and system demand, under average hydrological year conditions, will be almost entirely supplied by the hydroelectric plants until about 1988. 2.02 The forecast order in which the thermal plants would be placed in operation under dry and average year hydrological conditions from 1983 to 1992 to supplement hydro generation was estimated by the team and is shown in Annex 2. This schedule is based upon the following assumptions: (a) that under average or wet year conditions, the BLM Plant would not be required from 1985 to 1988 and could be placed in cold storage, (b) should thermal geneneration be required in emergency or for short or infrequent periods it would be more economical to use the Pieletick Diesel units at SF because of their low heat rate (TabIe 2.1), followed by the rural diesel units and then the GTDC Gas Turbines because of their quick start-up ability. -2- (c) should present dry year conditions persist or reappear, it would be necessary to have the BLM Plant available. The probability of a repeat of dry year conditions so soon after the recent occurrence is possible but not very likely. 2.03 IRHE would appear to have ample thermal backup for its presently planned hydro plants even under dry year conditions. However, as discussed in subsequent sections of this report, the BLM Plant is suffering from maintenance and operating problems, which are causing substantial energy losses and, in some cases, can be dangerous to plant safety. IRHE's management discussed these matters with the team and is congnizant of the problems. 2.04 It is to be noted that the forecast i Annex 2 does not include energy from the proposed Costa Rica lnterconnection or the possibility of generating more than estimated energy from I'HE's hydro plants. Energy from both of these sources would further reduce the requirement for thermal genera- tion. 2.05 Another factor influencing the operation of the thermal plants is the heat rate of the various units, the type and cost of the fuel burned, and the availability of tht units to meet unforseen increases in demand. Table 2.1 illustrates this point. Table 2.1: Preferred Sequence for Loading Thermal Plants Unit RV4meted And Preferred Heat Rate Fuel TAX e LoedIz Sequen (M/kUdb) Fuel Cbst/MI v Ctmet SF Iesels Pie]l*tk 10,500 iber Oil 4 x 6 MgJtw btaratt - desp $0.0434Mqh fuel - quidk start EM 2,3 & 4 11,900 BDierOil 3 x40 Mwstem $0.0491/kWh LM 1 12,940 BlwerO1l l x 24 MWstem - 17 yeams old $.52/M& SF 3 16,060 BuliarOil 1 x 11.5 Mstam - 29 yam old $D.06641qd1 DLiels - urnal Areas 11,000 Diese oil 16 x 2.5 NW - 10-20 yeas old $.0718/kI Gas TSwUbs (GMC) 13,M0 Diesel Oil 2 x 21.4 NW high fuel cost, $0.0861/Mh quidck stt for ped and e2?gat ewxO Gas Turbine SF 4 18,00 Diesel Oil 1 x 14 W high hat rate and $0.1175/tWh high fel muet - quidk start al Basd on 1982 ful wets: $171/tui *er oil; $280/ton diesl ol. 3- 2.07 Table 2.1 shows that the SF diesels have the lowest heat rate and burn the cheapest fuel. They would, therefore, be the first choice to supply thermal energy during 1985-1988. They would be followed by using the rural diesel units and the GTDC gas turbines because of their fast start capability. The BLM steam units are not suitable for intermittent operation at very low plant factors, as would be required during 1985-1988. It would appear that they would most probably be held in cold storage. This, however, would leave unresolved the problem of the operating and maintenance crews, which is a matter beyond the scope of the Loss Reduction Study. CHAPTER III THERMAL PLANT MAINTENANCE 3.01 In making an inspection of the BLM, SF steam and diesel units the following observations were made: Bahia Las Minas Plant (BLM) 3.02 There are two principal problems with the BLM units: 1. There is an urgent need to repair, replace and make operational the instrumentation for boiler combustion control, which is at present virtually Inoperative. As a consequence boiler efficiency is considerably below its normal level. This also creates a dangerous possibility of a boiler explosion. With the restoration of combustion control it would also be possible to consider replacing burners to tske advantage of never technology to achieve further improvements in combustion efficiency and lower fuel consumption (Annex 3). 2. The second problem concerns the condensers and cooling water system at ELM which Is plagued by a very large clam population. The chlorination system is in place but has not been operated for a long time, fot reasons which could not be ascertained. The result is that the cooling water system is now so Infested by clams that if chlorine were injected the clams would be killed; however, the dead clams would almost immediately completely clog the system and the unit would shut down because of a loss of vacuum. 3.03 The cooling water system is designed on the basis of a year round cooling water temperature of about 30°C. The vacuum is designed to be 2.0 inches Hg but, due to the clam infestation, it is 2.9 inches Eg on units 2 and 3, which Increases the heat rate of the units by 2%. It is suspected that Unit 1 is also affected. Unit 4 has a back-washing system which overcomes most of the problem. 3.04 If the vacuum were restored to the design level in units 1, 2 and 3 a savings in fuel of about 22,000 barrels during 1984 at the forecast generation level would be obtained, equivalent to about $750,000. -4- 3.05 The restoration of these units to design vacuum only requires ihe use of local labor and a minimum of spare parts to put the chlorination equipment in service. The condensers would have to be cleared of clams, which can only be done by taking the unit out of service. Once this is done and the chlorinators are restored to permancut service, design vacuum should be achievable under normal operations. The estimated cost is $5,000 for material and $15,000 for local labor for 3 units. 3.06 It is recognized that the BLM units may not be required to operate from 1985 to 1988, as discussed earlier. Nevertheless, thte two problems outlined above could be solved during 1983 and the savings accruing in 1984 alone would repay the investment costs. Benefits accruing after 1984 would be net savings. In addition, the problem of combustion controls is more than an improvement in efficiency al3ne, it would eliminatO a serious saftey hazard. San Francisco Plant (SF) 3.07 As seen from Table 2.1, the San Francisco plant tnits, except for the Pieletick diesels, are low in the sequence of plant loading. This plant is well maintained and operated but the units are old and heat rates are hlgh. Under the circumstances and requirement for thermal generating capacity already discussed it would be difficult to justify investment in improvements. Rural Diesel Units 3.08 There are 16 diesel units, aggregating 40 MW at individual locations throughout the country, being used as stand-by at various points on the Interconnected System. These diesels will gradually be off-loaded as the Interconnected System is extended or they could be moved to other localities where no electric service exists. They could also be relocated to a 'diesel park" at a central location and be used as a fast start4ng source of capacity in an emergency (5.13). 3.09 These units are considered to be in good condition at this time. They might also contribute to generating power which would enable IRHE to postpone the installation of the Changuinola units (5.13). CHAPTER IV GtERATION LOSS REDUCTION PROJECT 4.01 The Generation Loss Reduction Project would consist of correcting the loss problems at BLM as outlined Chapter III. The estimated costs are summarized in Table 4.1 and would total $882,000. 4.02 The benefits from loss reduction, assuming the correction of the problems were completed in 1983, would be $1,597,000 during 1984 alone (Table 4.2). Thus the entire cost of restoring BLM to normal operations could be saved during 1984. -5- Table 4.1: Estimated Cost of Generation Loss Reduction Project at BLM Cost US$ 000 Imported Imported Local Item Material Labor Labor Total 1. Outside contractor to place 50 220 50 320 instrumentation and controls in operating condition and train IRHE staff to maintain this equipment 2. Repair faulty insulation 3 - 10 13 3. Excess air control 295 40 100 435 4. Air preheater seals 12 - 3 15 5. Rehabilitation of condensers 5 - 15 20 Subtotal 365 260 178 803 6. Contingencies 36 26 17 79 Total 401 286 195 882 Table 4.2: Benefits in 1984 From Loss Reduction Project at BLM Oil Savings Item US$ 000 1. Restoring condensers to rated vacuum 725 2. Operating turbine at rated temperature and pressure 230 3. Repairing insulation 63 4. Excess air control 450 5. Air preheater seals 129 TOTAL 1,597 -6- CHAPTER V OTHER OBSERVATIONS 5.01 In general the forecast operations of the BLM units contemplaze long periods when they will be out of service or operating at low levels. However, should these condltions change and the units again be needed for base load operation such as if Changuinola is postponed, the following should be taken into consideration: Steam Turbine Efficiency 5.02 The current design of new steam turbine generating units are significantly more efficient than earlier equipment. Two areas of significant improvement have been made in labrynth shaft seals and in turbine blade radial spill strip designs. In addition, new blade profiles with slant tipped blades have made turbine performance considerably better. 5.03 The application of these new designs to older units is a practical means of increasing efficiency, particularly when s,4veral more years of active service is anticipated. However, before adopting these measures the equipment manufacturer should be consulted. 5.04 The minimal cost of installing new labrynth seals would be approxi- mately $75,000.00 per unit and would achieve about a 0.5% increase in turbine efficiency. If it is assumed that the units will operate as forecast for 1984, a 0.5% increase in turbine efficiency would yield an annual fuel saving of $218,000. The cost of the seals for three units would be $225,000, thus the cost would be recovered in fuel savings in about one year. 5.05 The BLM turbines were installed and opened for the first time as follows: Units 1 2 3 4 Installed: 1964 1969 1972 1974 Opened: 1972 1980 1980 1980 5.06 A check revealed that no seals were replaced. It is suggested that IRHE should discuss the matter wizh the manufacturer. Variable Speed Drives 5.07 Power generating units which operate at variable loads are subject to periods of low load operation at lnefficient design operating points. The auxiliary equipment used to generate electric power historically is driven by constant speed motors. This is the case at BLM. The forced draft (FD) fans, -7- boiler feed (BF) pumps, and the condenser circulating water (CW) pumps are the largest motors in the plant and are all driven by constant speed motors. 5.08 If a unit is to operate a great deal of time at reduced load, it may be advisable to install variable speed drive units which allow the auxiliary equipment to operate at or near peak efficiency points at low unit loads. This could be done to the ELM auxiliary drive units if they are to operate under normal load factor for the remainder of their expected life. 5.09 The use of high efficiency motors for the smaller drive applications could also be an attractive retrofit application. In general, larger motors, over 75 kW, are usually very efficient; whereas motors smaller than 30 kW are not highly efficient and can be replaced by higher efficiency drives. The increase in efficiency is in the range of five to ten percent. 5.10 Assuming the BLM units are to operate at 80% load factor in 1984 (IREE forecast), with the same availability as experienced in 1982, i.e., 83%. Also assume the following operating regimes: Percentage of Time Percentage of Load 20 100 70 87.5 5 50 5 0 Based upon a 100 percent friction system (no static head required), a variable speed unit will save 35% of the energy which would be expended when operating at full speed. Allowing for fan design ma gins, an energy savings of 107 kW/hr. for three units for 1984, would amount to 2,337,800 kWh per year, or a cost savings of $149,250. Three variable speed drive systems would cost about $250,000 giving a cost-to-benefit ratio of 1 to 0.6. Changes to the boiler feedwater and circulating water pumps would not lead to appreciable savisigs. 5.11 Terms of Reference for the work outlined above are given in Annex 4 of the Project Identification Report. Postponement of Hydro Generating Plant 5.12 In order to supply forecast system demand from about 1990 to 1993, the Changuinola Hydro Plant was originally scheduled for service about 1990. This has been rescheduled to 1991 to reflect the expected slowdown in load growth due to recent changes in Panama's economy. It also meets the Government's wishes to slow the growth in foreign debt. The team has consequently reviewed this program of generating plant expansion and recommends that IRHE should restudy the proposed program to ascertain whether a further delay of Changuinola, by using existing available thermal generating capacity to meet forecast demand until 1994 would be an even more economic alternative. -8- 5.13 If the BLM thermal units were rehabilitated as recommended in Chapter IV, they could be continued in service beyond 1994 at acceptable heat rates, provided an adequate maintenance program is instituted. The niany diesel units now scattered at rural sites which are gradually being off-loaded by the interconnected system could be transferred to a central diesel park where they would provide ar economical and reliable stand-by thermal capacity. These measures would give a low cost thermal energy source because much of the thermal plant capital investment would have been amortized by 1990, in other words, it would be a sunk cost. Only the operating and maintenance cost would be incurred. Since the entry into service of La Fortuna in 1985 makes thermal generation practically unnecessary from 1985 to 1988, there would be ample time to rehabilitate the BLM and SF units and create the diesel park. -9- ANNEX 1 IRHE POWER GENERATING FACILITIES a/ Nameplate Available Date Capacity Capacity Name of Plant Type Installed (MW) (MW) Bahia Las Minas (BLM) Unit 1 Steam 1964 22.0 22.0 Unit 2 Steam 1969 40.0 40.0 Unit 3 Steam 1972 40.0 40.0 Unit 4 Steam 1974 40.0 40.0 San Francisco (SF) Unit 3 Steam 1955 11.5 11.0 unit 4 Gas turbine 1964 14.0 12.0 Pieletick-Diesel Bunker oil 1976 4 x 7.0 24.0 Load Dispatch Center (GTDC) Diesel fuel Units 1 & 2 Gas turbine 1983 2 x 21.4 40.0 Rural Diesel Plants Aggregate units Diesel 1961-72 16 x 2.5 40.0 Bayano Units 1 & 2 Hydro 1976 2 x 75.0 150.0 Unit 3 (future) Hydro 1990 75.0 75.0 La Fortuna Units 1, 2 & 3 Hydro 1985 3 x 85 255 Raise Dam Hydro 1987 45 45 Estrella Los Valles Estrella units 1 & 2 Hydro 1978 2 x 21.5 43.0 Los Valles units 1 & 2 Hydro 1979 2 x 23,5 47.0 Mini Hydros La Yeguada Hydro 1 x 1.0 1.0 La Yeguada Hydro 1967 2 x 3.5 7.0 Coclesito Hydro 0.25 0.25 Santa Fe Hydro 0.35 0.35 Changuinola Units 1, 2 & 3 Hydro 1992 3 x 100.0 300.0 TOTAL 1,204.4 1,188. aJ Source IRHE. - 10 - ANNEX 2 FORECAST GENERATION (GWh) (Based on Stacking Sequence - Table 1) Dry Auerap Year Piat Seaot Season AmIsl 1d3 Hydro ) it/ 967.8 1,195.3 * Diesl Pielstidt (P) 168.0 168.0 Stea (S) 959.2 731.7 Diesel Rural Is)R - - Gas Turbnes (GT) - - 2,095.0 2,095.0 1984 H 1,107.5 1,195.3 IP 168.0 168.0 S 955.0 867.5 DR - Gr - 2,230.8 2,230.8 1985 H 2,058.5 2,366.5 iP 168.0 14.1 8 154.1 - 47% Plant Factor, aie XM unit. Gr - - 2 W;O6i 2,380.6 1986 H 2,073.5 2,397.1 DP 168.0 135.6 8 291.0 - 45% Plat Factor, t toEM wits. DR -- Y2,532.7 2,532.7 1987 H 2,383.6 2,629.2 IP 168.0 66.3 S 143.9 - 45% Plant Factor, one M wit. Gr-- 2,69.35 2,695.5 1988 H 2,383.7 2,694.4 Avrs* wee rerIas; Gh requtred after IP 168.0 168.0 Pielstik too swalI to start steM Uit. Uge S 503.2 257.6 rura dLesl to _mt ?a Avra 10.25 NI, ER - 17.7 Dry a - 48 Plant Factor for two KLM uits. Gr - _ 2,869.1 2,6.1I / Syxboas used for sulmquaqw years. - 11 - ANNEX 2 Page 2 of 2 FORECAST GENERATION (GWh) (Based on Stacking Sequence - Table 1) (Continued) Dry Averap Year plant Season Season Remw3cs 1989 H 2,383.8 2,629.4 DP 168.0 168.0 S 503.2 257.6 Dry - w NM units. 111 - - hvg. = one BEM unit. GT - - (Rural jiesels as bad p) 3,055.0 3,055.0 1990 H 2,383.9 2,599.5 1P 168.0 168.0 S 702.3 516.7 Dry - three NM uits. DR - - Avg. - BMM units. r - - (Rwral diesels as badep) 3,254.2 3,254.2 1991 H 2,477.3 2,618.6 Chlaruinola delayed beyond this year. Reserve t1 168.0 168.0 capadty 291.6NW. Larg8t wnit is 10ONW. S 821.7 680.4 Capacity available 105 W. 11 - 3,467.0 3,467.0 1992 H 2,477.4 2,622.0 O1rpfinola delayed beyond this year. Reserve 1t 168.0 168.0 capacity: 247.2 M1 - 28%. S 1,018.5 904.3 DR 30.4 - 100 MW - lart wit. Gr :^ 694.3= 694 -- 95 NW- capacity available. 3,694.3 3,694.3 1993 H 2,477.4 2,622.0 Chawguinola delayed beyond this year. Reserve DP 168.0 168.0 capacity:- 205 ? - 23% S 1,018.5 1,018.5 ER 245.0 128.7 100 MW- lrpst nit GT 28.3 - 60 MW -dry eaona silable. 3,937.2 3,937.2 77 W - avg. season availbble. 1994 H 2,477.4 2,622.1 ChaqiAnala 8bDuld rst be delayed to this year DP 168.0 168.0 due to hih plant factroa on the 9ss turbine s 1,018.5 1,018.5 units. Reserve capacity: 160 W - 18% ER 245.0 245.0 1995 capacity reserve forecast as 12.6% GT 287.8 143.1 4,196.7 4,196.7 - 12 - ANNX 3 IMPROVIEWNTS TO BOILER AND TURBINE EFFICIENCY Background 1. This Annex deals with the Bahia Las Minas (BLM) thermal plant and refers specifically to the condition of the boiler and turbine equipment. Instrumentation and Controls 2. The principle problem with the boilers at BLM is that many of the instruments which indicate and record the operations of the boiler, such as pressure and temperature monitors, flame scanners, flue gas analyzers, etc. are inaccurate, inoperative, or missing altogether. The following are noted: (a) The flame scanners on the burners are not in use in any of the units. (b) The Bailey recording meters which measure and record the principal operating parameters of the boiler, have charts reading from O-100l. It would be better if the charts were to read the appropriate units of temperature, pressure, flow, etc. (c) No excess air recording is operational, so that the operator does not know whether the fuel/air mixture is adequate - at worst this could lead to a boiler explosion. (d) The swoke stacks are a dark grey color indicating iitcomplete combustion which is resulting from the defective instrumentation and the inability of the operator to properly control the boiler. (e) It would appear that many of the controls *ead calibrating to make sure that when the proper instrumentaticn is in place the controls will respond adequately to the signals received. (f) There is a crucial problem of the inability of the BLM maintenance staff to keep the instrumentation and controls in satisfactory repair. It is unsatisfactory and uneconomical to allow BKM to continue operating under present conditions. Therefore it is recommended that an outside contractor specialized in the controls, instrumentation and operations of the boiler and turbogenerator uaits should be engaged to make a survey of the BLM plant and then proceed to put the plant into satisfactory condition. The same contractor, while carrying out the work, should initiate training of local staff to take over the future maintenance and operation of the plant. It is estimated that this contractor would need to send three men who would take six months to place the BLM units in good operating condition at an estimated cost of $50,000 for imported parts, $220,000 for foreign labor and $50,000 for local labor. Total cost is about $320,000. See Annex 4 of the Project Identification Report for proposed Terms of Reference. ANNEX 3 -13 - Page 2 of 3 (g) There are numerous areas where insulation has been damaged or is cracking (parting) badly which increases heat loss considerably. This occurs In the boiler area and other sections of the plant, such as on feedwater heaters, piping, etc. In several of these cases, repair work could be carried out while the units are in service. It is estimated that by improving the insulation of the main steam line from the boiler to the turbine at a cost of $13,000 for labor and material, the annual savings in heat loss in this line alone would be equal to $63,000 of oil. Excess Air Control 3. The BLM units are all designed to opejate at 15% excess air as verified during the acceptance tests. By replacing the old burners with the new Peabody burners designed for low excess air operations, the excess air could be reduced from 15% to 5% and combustion efficiency increased by 1%, which in turn, based on the forecast generation at BLM during 1984 of 694.5 GWh, would result in a fuel savings o! $450,000 (details below). 4. In 1982 the average heat rate for units 2, 3 and 4 was 11,900 BTU/kWh. This is equivalent to 0.634 pounds of oil per kWh generated. A 1% gain in &'ficiency would achieve a savings of 203 lbs of oil per hour, per unit, which would give an oil savings for the three BLM units of 13,090 barrels or $450,000 in 1984 alone. Savings in future would be net. 5. The equipment needed to achieve this improvement in combustion is given below: (a) Combustion flue gas oxygen analyzer for three units $ 20,000. (b) Replace flame scanner system - three units each with six burners at $25,000 per boiler $ 75,000. (c) New Peabody burners for low excess air operation including ignitors and atomizers for three boilers $ 200,000. (d) Foreign labor cost $40,000. Local labor cost $100,00 $ 140,000 Total cost for excess air control $ 435,000 Thus, if this improvement is made during 1983 the cost would be recovered in less than one year during 1984. Air Preheater Seals 6. On the basis of the condition of the BLM units overall, it is suspected that the seals may be in need of replacement. An inspection would be required to verify this. ANNEX 3 -14 - Page 3 of 3 7. It is to be noted that if only a 5% leakage is taking place it would rr-iult in an excess usage of 3,700 Bbls of oil per year on the basis of 1984 f tecast generation, equivalent to $129,000. The cost of replacing the seals for the 4 BLM units would be approximately $12,000 at a labor cost of $3,000. Total cost is $15,000. Operating Temperature and Pressure 8. If the steam temperature and preseure at which the BLM units 1, 3 and 4 are now operated is compared with the values used in the acceptance tests or with the nameplate ratings, it will be seen that the units are operating significantly below the design limits. Consequently there would appear to be room for improving the heat rate simply by restoring instrumentation and controls to working order and running the units at the-r rated temperatures and pressures. v 9. For example, on units 3 and 4 the turbine temperature reading was 504°C compared with an acceptance test reading of 510°C. If this difference is real and not the result of a faulty instrument, it represents a 0.4% loss in heat rate. Similarly, the turbine steam pressure 2indicators showed 85kg/cm while the acceptance test pressure was 88kg/cm . This would be equivalent to a 0.25% loss in heat rate. The combined loss in heat rate for these two items is 0.65%. If the two units are operated under the conditions forecast for 1984 this ioss in the heat rate would be the equivalent of 7,000 Ibls of oil annually at a cost of $230,000. 10. Whe opposite is occurring with unit 2 which is operating at 513'C and 89.6kg/cm compared to nameplate ratings of 500C and 87kg/cm . In this case it would be prudent to check with the manufacturer to see if the higher temperature and pressure now being used is acceptable. This could also be in violation of the insurance policy and should be verified. :. Obviously the solution lies first in correcting the defects in instrumentation and then improving operating practices. - 15 - ANNEX 4 COLD STORAGE PROCEDURES 1. The future operati n of the Bahia Las Minas units will be sporadic at best over the remaining life of the plant. Intermittent operation of the plant will result in extended periods in cold storage. In order to protect the unit from deterioration during these per4ods, proper lay-up and storage procedures should be used to assure that the units are maintained in good working condition. 2. Areas of special concern relate to the internal parts of the equipment, systems and materials which use steam, water air, gas and miscellaneous liquids. This includes nitrogen blanketing and dry storing of the internal pressure parts of the boiler, the turbine, the generator, switchgear, motors, the feedwater heater cycle (including the bleed steam lines), feedwater and condensate pipe, pumps, controls, etc. The lube and fuel oil systems and the water treating plant system also require a lay-up and storage procedure to be sure that corrosion or oxidation of the systems are controlled and minimized. 3. Indepth discussions and reviews should be held with the various suppliers on the best means of protecting their equipment.