MMAEMMEAMBAMM hM.AM - iI h ur, A% AM ]jfA-M IEE1EMORSEE11011UIN Energy Sector Management Assistance Programme Jamaica Energy Sector Strategy and Investment Planning Study Volume III: Power Sector Review and Energy Conservation Report No. 135C/92 Consultants' Reports JAMAICA ENERGY SECTOR STRATEGY AND INVESTMENT PLANNING STUDY VOLUME III Power Sector Review and Energy Conservation PART A ELECTRIC POWER SECTOR REVIEW PART B ELECTRICITY DEMAND SIDE MANAGEMENT AND INDUSTRIAL ENERGY CONSERVATION STRATEGIES CONSULTANTS' REPORTS August 1992 This volume, in two parts, presents the consultants' findings and recommendations as follows: Part A: Eectric Power Sector Review; report prepared by M-. Tom Norris with particular emphasis on the evaluation of the Least Cost Expansion Plan as proposed by SWECO In its draft report of March 1991. Agreement was reached with JPS and SWECO concerning the recommended LCEP and is so reflected In this report. The final SWECO report was not available at the time of revising this report; however, no further revisions to this report are anticipated, since the LCEP has been jointly agreed. Part B: Eectricity Demand Management oat ladustrW Energ Conervaron Strategy; a summary report prepared by Mr. Joseph Oiling, ESMAP Task Manager, based on Inputs from Individual consultants Messrs. Brian Kelly, Fred Gordon, Tom Norris, and Tom Tamblyn, working with JPS and MPUTE staff. The ESSIPS report was discussed with the government of Jamaica in September 1991. In its formal comments, received In January 1992, the government accepted the conclusions and recommendations concerning the electric power sector and energy efficiency strategies. As part of the technical review in preparation for expected funding from the Global Environment Facility, however, it was recommended by the GEF Technical Review Panel in February 1992 that the establishment of ENERCO as an energy service company for the laplementation of demand side management projects should be deferred. In the long term, following an evaluation of JPS's experience with DSM programs, the potential for energy service companies should be reviewed. ABBREVIATIONS AND ACRONYMS AAC ambient air concentrations JPS Jamaica Public Service ADO automotive diesel oil Corporation ASTM American Society for Testing kBD thousand barrels per day and Materials LCEP least cost expansion plan bbl barrel ((42 U.S. gallons, 159 LDC less developed country litres) LPG liquifled petroleum gas B-C ratio benefit-cost ratio LSFO low sulfr fuel oil CBI Caribbean Basin Initiative LV liquid volume CFB circulating fluidized-ed MDO marine diesel oil C&I commercial and industrial MFPP Ministry of Finance, Planning, CIDA Canadian International and Production Development Agency mlo million CPE centrally planned economy MME Ministry of Mining and Energy DSM demand side management MOP Jamaican Ministry of Finance EC European Community MOGAS motor gasoline. EIA environmentalimpactassessment MW megawatt ENDC Energy Sector Development NAAQS National Ambient Air Quality Committee Standards ESDPP Energy Sector Deregulation and NCS National Conservation Strategy Privatization Project NGO nongovernmental organizations ESMAP Energy Sector Management and NO, nitrogen oxides Assistance Programme NRCA National Resources Conservation ESSIPS Energy Sector Strategy and Authority Investment Planning Study PV present value PGD flue gas desulfurising S sulfur PS feedstock SPS Saybolt Purol Seconds GPM gallons per minute SO sulfur dioxide GWh gigawa,. hours SWECO Swedish Energy Company HFO heavy fuel oil T tonne (metric ton) HSFO high-sulfur fuel oil USGC United States Gulf Coast HO heating oil WASP power sector expansion planning HIS hydrogen sulfide model EIRR or IERR internal economic rate of return VOLUME I PART A ELECTRIC POWER SECTOR PARLT A ElECTRIC POWER SECTOR REVIEW CONTENTS S.mary and S- Sedon 1 Introducton and Terms of Reference . . . . . . . . . . . . . . . . . . . . . . . 1-1 Sctdon 2 Forecast of Dmand for Electricity . . . . . . . . . . . . . . . . . . . . . . . . 2-1 Seldon 3 ExsagGeneradngPlant . .. ......................... . 3-1 3.1 PS generadon stadlons ............................... 3-1 3.2 Other generadng plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4 Secdon 4 Options for Futur Gnerang Plant ........................ 4-1 4.1 Dual-fird (coal/oll) steam plant . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 4.2 Other fael-fired options ...................... ....... . 4-3 4.3 Rnwable energy sources . . . . . . . . . . ..... . . . . . . . . . . . . . .. 4-4 Se~don 5 Least-cost Expansn Plan for Genrao .................... 5-1 5.1 SWECO LCEPrpot ............ ..... .... 5-1 5.2 Comparson of SWECO and WASP resul ................... 5-2 5.3 Prelimnary~rang study .............................. 5-5 5.4 Basic data for WASP modelling . . . . . . . . . . . . . . . . . . . . . . . ... 5-5 5.5 Resuts of WASP In modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-7 5.6 Conclusions from LCEP studis . . . . . . . . . . . . . . . . . . . . . . . . . 5-11 5.7 Avolded costs of loss rducon and dmand-side maa ....... 5-12 5.8 Hydroelectric schemes ................. ...... . . 5-13 Secdon 6 Privat. Sector Participadon . . . . . . . . . . . . . . . . . . . ... . . . . . .. 6-1 6.1 Reasons for privat.sector patcipadon ................. ..... 6-1 6.2 Techncalaspects ................................... 6-2 6.3 Contractualmatters ............... .... . . . . . . 6-2 Se~don 7 EnvronmentalAsp ................................ 7-1 7.1 Genera~7-1 7.2 Sulphurdioxide .................................... 7-1 7.3 Nitrogenoxides(NO,) ................................ 7-2 7.4 Dust andas* ............................. . . . . 7-3 7.5 Effluents......................................... 7-3 7.6 SIt-specfcatt....... .......................... 74 7.7 Cost of environmnu~al measures .......................... 7-4 7.8 Insdtutional ................. .................... 7-4 Seedo 8 Transmanand Distribudon ........................... 8-1 8.1 Tranmn ionsystem ................................. 8-1 8.2 Distdr do ................ . . . . . . . . . . . 8-1 Secdo 9 Invesment Progra=we ..................... 9-1 Sedon 10 Insdtudonal and Technical Aatsns . . . . . . . . . . . . . . . . . . .. .10-1 ANNUXES A List of Persons Met B Terms of Reference C References D Notes from Discussions with JPS and SWECO B Additions to Terms of Reference for Power Plant Audit to Cover Environmental Issues F Results of WASP Modelling 0 Terms of Reference for Possible Study of Heavy Fuel Oil at Power Stations H Aide Memoire on Proposed Private Sector Energy Development Project, Washlngton, 24-25 April 1991 JAMAICA ENERGY SECTOR STRATEGY AND INVESTMENT PLANNING STUDY ELECTRIC POWER SECTOR SUMMARY AND RECOMMENDATIONS INTRODUCTION 1 The World Bank ESMAP Energy Sector Strategy and Investment Planning Study Mission (the Mission) has worked closely with Jamaica Public Service Co, the Ministry of Mines end Energy, SWECO (who have prepared a Least Cost Expansion Plan) and CIDA (on environmental matters) and others. his Report summarises the main aspects and conclusions of the Power Sector aspects of the Mission. Thanks are due to all the above and especialy to JPS Planning Department for their willing cooperation and hard work. 2 ThIs summary of the conclusions and recommendations refers to the paragraph numbers used throughout this Report. SUMMARY Lad Growth 3 The base SWECO forecast of electrical demand was reviewed and accepted (2.09) as the basis for system planning as follows: MD Deand Energy Growth Load HN afh %/year Fac 4 1991 345 2167 72 6.0 1995 435 2764 72 3.5 2000 516 3288 73 2.9 2005 596 3808 73 The above figures are before adjusting for the effects of loss reduction (2.12) and Demand-Side Management (DSM) measures (2.15). The effect of loss reduction is a saving of 4% on energy and 5% on maximum demand by 1995 and thereafter. The effect of DSM has been taken as the mean of the low SR-2 and high scenarios (2. 15) estimated In the DSM report of the Mission. This reduction is substantial and amounts to some 500 OWh and 84 MW by 2005. The reductions in load due to loss reduction measures and DSM are: Lose reduction DSM MW OWh MW GWh 1991 - 1995 22 111 21 107 2000 26 132 52 269 2005 30 152 64 350 2010 34 177 71 405 A turther advantage of DSM is the Improvement in system load factor. 4 The reduced forecast (Table 2-1A) used In further analyses by JPS and the Mission, Is summarised below: HD Demand Energy Growth Load MW OWh %/year Fac % 1991 345 2167 72 3.2 1995 392 2547 74 2.3 2000 439 2887 75 2.7 2005 502 3306 75 Existing Generating Plant 5 The current implementation of detailed computer-based performance monitoring of plant is very profitable both In fuel economy and availability. The computer-based economic despatch system recently put into service Is estimated to have saved about 4% on fuel costs and the monitoring system wll boost that saving to about 10% (3.02). 6 The forthcoming rehabilitation of the plant will restore efficiency and availability. An Important aspect for the LCEP is the retirement of existing plant which amounts to 230 MW by the end of 2000 and 360 MW by 2006 (3.10). The total new capacity by the end of 2000 is 439 MW, over half of which is required to replace retired plant. By 2010, the retirements total 360 MW out of the total of 760 MW of new plant It is important, therefore, to examine in due course the retirement policy with a view to further rehabilitation and life extension beyond that presently included in the LCEP. The forthcoming Plant Audit should examine the possibilities for further life extension. The Plant Audit should also include an assessment of the environmental aspects at each site. For the benefits of rehabilitation and life extension to last, it will be vital to ensure that adequate maintenance resources will be availablt to deal with both the routine planned work and the work identified by the monitoring equipment just referred to above (3.02, 3.09, and 5.21-f). SR-3 7 There are currently small prospects (3.11 and 3.15) of using significant amounts of existing private power plant. The main prospect (3.14) for significant co-generation Is at Frome sugar factory, though no technical or cost details are yet available. Options for future generatIng plant 8 The options for the future comprise a coal/oil fired steam station (4.01) at Rocky Point (Salt River), low speed Diesels and gas turbines at sites yet to be identified (4.11). Some of these plants could be located existing power station sites, including a combined cycle plant proposed for Hunt's Bay power station. Selection and proving of sites should be undertaken as soon as possible (4.11). Medium speed Diesels were considered by SWECO but it has been agreed that they are not suitable (4.10) for use with the high vanadium heavy fuel available in Jamaica. The resulting low availability and high maintenance costs will be included in the SWECO final Report which is expected to exclude medium speed Diesels on economic grounds. 9 The coal station should be pursued urgently since it is a significant long term project. Proving of the site by physical investigations should be done quickly (4.03) so that a reserve site can be brought forward if necessary. This work should be done before site specific environmental assessments are made. 10 A design study (4.04) will be required to take the project to the stage where specifications and tender documents can be prepared. This study should include consideration of Circulating Fluldised- Bed boilers, to minimise the SO and NOx emissions, particularly if it proves feasible to burn heavy fuel oil. In that case, Orimalsion (4.05) may prove to be an attractive new fuel, though Its commercial acceptability has not yet been proved by experience. The size of the generating units should also be reviewed. 11 Renewable resources in the form of cogeneation from bagasse (4.19) seems to be the most immediately promising, though technical and financial information on the bagasse project at Frome sugar factory (some 20 MW) is disappointingly not available. The Back Rio Grande hydro scheme (4.17) at 50 MW is the largest of the hydro renewable resources. Least Cost Expansion Programme (LCEP) 12 Detailed discussions on the SWECO Draft LCEP Report were held in Jamaica and later in Washington between the SWECO Study Manager, JPS, and the Mission. Certain differences (5.02) In costs and availability were identified and to largely resolved. There remain, however, seeming differences in the computer modelling (5.08) which have not been resolved, though in the event, these do not lead to different conclusions. 13 The base expansion plans by SWECO, and results using JPS WASP M software on SWECO data ( investment costs, operation and maintenance costs, availability and constant fuel prices), are shown in Table 5-2. These studies use the base SWECO load forecast before the deductions for loss SR-4 reduhdon and DSM. The SWECO sudie give a scenado with a coal station as being some 2% (5.05) more costly in mt present valuo than with a combined cyco stadon. Frther runs on WASP Indicate thO revers s~ution, le combined cyc* 3% mor costly than coal (5.06), ven on the basis of Wodd Bank forecast of reas price movoments, which pupalis coai prices to the wtent of about 12%. 119 difference of about 3% In t pru valu thought to bo withn the accuracy of the vous cstngrediets; hence m unambguous conciusion cannot be drawn on the basis of nat present value alone. 14 'the determining factor which cannot be quafled is the oporational advantago that the coal/og 1~ton will Introduce divrsity of foks avallable, givo protlon against volatlilty of ol prics, and bumn tho lowest pdced &el avaiable at any time. For this roan. the coalol stadon is to bo proferrd. is conclusion In favour of a coal stadon confirm previoM studios. Pre& nary ranking studics 15 Table 5-3 is a preliminary ranking study of plant combinatons whIch shows that most of tho optfons are clos. In economic morit. The stoam addition to ga turbiun to make a combined cyce plat sems to be on of the last oconomic options (5.13) It high f~ciency dos not offset the hgh led cost and it will operat on peak load, which wil rther reduce its efuctve officioncy. Seaivity analyss 16 Snsitivity studies on WASP (5.19 show that the Plan including coal is rasonably robust as a long-trm source of olectricty, though all options are fairly close In oconomic mrit from time to thm and both gas turbinm and low sped Dicsels find k place in the LCEP. The coul-fird station bcom ova mor a*tractls if oi and cosi prices are assum d to stay at their preent relativo evel, Inad of coal pricms ncreaing more than oil prices. Combined cycio plant is not selectod by WASP under ny sats of data tried. Even whon combined cycie is forced into the plant programm, It is shown to bo uneconomic, and coal fired stum is selected to follow, though somwhat delayed. 17 Lns reducdon and Donand-Side Management measuras are potendally vory aconomic and shoud both bo impl~mnted with vigour. 18 The Last Cost Expansion Plan to 2000, on the basis of tho forocast reduced by loss reduction and DSM appears to bo (5.21): 1993 Low speed Diesel 20 MW 1994 Low speed Diesel 20 MW 1995 Low speed Diesel 20 MW 1996 Ga Turbine 33 MW 1997 Coal-fired stum staton, Unit 1 61 MW 1998 Cosl-fired stam stadon, Unit 2 3 122 MW 1999 Coal-fired stam stadon, Unit 4 61 MW 2000 Coa-färed stum station, Unit 5 61 MW SR-5 rhis program ls the Least Cost Expansion Plan a selected by WASP and conined by SWECO (Ann e 1). Some doubts were upressed about the rate at which DSM measure will becom. effective and the programme was re-aamond on the bis of the SWECO Base forecast without any load reduction. This leads to the following accelerated programe: 1993 Low speed Dinels 40 MW 1994 Low speed Dimel 20 MW 1995 Gas turbn 33 MW 1996 Gas turbine 33 MW 1997 Coal-fired stam station, Unit 1 61 MW From the above, It would be prudent to ordet the first two Diesels for as early as possible,(nominally In 1993) with an option on the 3rd machine for 1994 or 1995, depending on annual revews of load growth and progm with DSM. A decision on the timing of the ps turbine(s) can be deferred for about two years. Concusions and Srategne 19 a. It slmportant to exne thertirement policy with a vew to possible ther lIfe etonsion In du. course. The current rehabiltation is shown by SWECO to be very attractve (5.10). b. The forthcoming Plant Audit should *amine the possibillties for rther lif etension to avoid unnecesary earlyrtrmns c. The enirnmntlIssues at ~isting statons should be mind under an extenson to the Terms of Reference of the Plant Audit (3.09 and 7.11). New co red station 20 a. Apart fom its prime position In the WASP LCEP (5.20), a coul/oli fired plant would introduce diversity of Ikel avaIable for generation and give protecion aganst the volatility of oll prices. The bas. toad can be supplied by oll- or coal-firing, according to the cheapest fuel available at any tie (4.02). b. The coal staton should be deigned at last to be converdble to heavy oR firing (4.04), and possibly for dual firng from the outuet. OrlmMlsion is also a possibUity. Whle Orimlsion (4.05) has been proved In tuts, Jamaica should not commit itselfunti more extensive oommerca xperlnce has been ganed elsewhere. On the present programme, the d of the statonneed not be finlised for about2 yea so thereistlme fr SR-6 further assessment of Orimulsion; in any case Orimalsion could be used in the later units, if not In the first units. c. The use of circulating fluldised-bed coilers to minimise SO and NOX emissions (4.04) shoul# be considered for the station, though the ability of a fluldised-bed boiler to burn solid and liquid fels requires to be checked. Circulating fluidised-bed (CFB) boilers are a recent development, but there is accumulating considerable commercial experience with such boilers in the size range suitable for Jamaica. Should CFB boilers not be capable of burning liquid fuels, a decision would have to be made on whether it would be economically preferable to use conventional boilers to retain the dual fuel capability, or to stay with CFB boilers to burn higher sulphur (and lower price) coals. d. The proposed coalloil station seems to be the preferred long term option in the LCEP; at any rate, it is sufficiently attractive to warrant proceeding as quickly as possible with completing the siting studies, and implementing the environmental Impact assessment. Delays in doing this work may be costly. e. It would be wise to investigate and rank other possible sites (4.03) in case the proposed Salt River site proves to be unacceptable. It is also important that, at least, preliminary physical site investigations (boreholes, test pits etc) be made quickly at Salt River to confirm its suitability and avoid the possibility of having to abort the Environmental Impact assessment. If the site investigations prove Salt River to be unsuitable, a second site should be immediately investigated. f. A Final Feasibility Report (4.04) should be commissioned for completion at the end of 1992, as soon as the siting and Environmental Impact Assessment studies show the site to be acceptable, with a view to ommssioningthe first unit for service in 1997. The report should Include layout, harbour facilities, size of generating units, type of boiler, dual or triple fuel facilities, ash disposal etc. Other new plant 21 a. It Is necessary to Identify the possible sites (4.11) for the more immediate new plant, particularly the low-speed Diesels required in 1993 and 1994 and the gas turbine(s) to follow. This plant will probably be installed at existing power station sites but it is desirable to have a number of optional sites identified as reserve. b. The Environmental Impact Assessments for these sites should be started immeadiately. c. Preparation and implementation of procurement procedures for the low speed Diesels should be started immediately. SR-7 d. The Back Rio Grande hydroelectric scheme (50 MW) is not selected by WASP and estimates of Its benefit/cost ratio show it to be about 0.8 at 12% discount rate. Tis seems to correspond closely with the SWECO/CIPS Report which shows an Internal rate of return of 7.8%. Nevertheless, it is possible that the project may be attractive to countries who can place a high value on reduction of carbon dioxide emissions and who may be prepared to offer concessionary financing. e. The possibilities of cogeneration at Frome and other sugar factories should be investigated as soon as technical and financial information becomes available from the promoters. Transmission and Distribution 22 a. 'The upgrading of the system to reduce losses and cater for load growth is in prospect under an IDB loan. Further work requires to be done in designing the system for optimum losses, particularly in quantifying the optimum losses. The opportunity for this will be in the forthcoming Master Distribution Study and the terms of reference should include this matter. b. The unaccounted losses are variously given as 5% or 10%. Tey represent uncollected revenue and effort should continue to identify and reduce them. Demand Side Management 23 a. The reduction and spreading of load by Demand-Side Management and energy efficiency measures should be pursued vigorously; it is potentially very profitable both to consumers and to JPS. The viability of some of the measures will need to be checked as part of the continuing development of DSM (5.20). b. The avoided system costs (5.24) as a basis for assessing DSM measures may require to be studied further to provide adequate breakdown of the costs for the whole range of DSM characteristics. Ehronment 24 a. The development of environmental awareness and the future imposition of environmental standards (7.01) will affect all generating stations. The standards should be set at a level appropriate to the developing status of Jamaica. For example, the fitting of flue-gas desulphurising equipment is very costly (7.05); other means of reducing sulphur dioxide emissions should be examined, eg using low sulphur coal (even if at - premium price) or by using circulating fluidised bed boilers. SR4 b. Improvements can and are being Implemented to reduce emissions, for example, through the constant monitoring of burner performance, and the state operation of the plant. Such monitoring, however, can have no effect on emission of sulphur dioxide. Retirement of existing plant for environmental reasons would be prohibitive. For example, retirement in 1993 of one of the 60 MW units at Hunt' Bay or at Old Harbour would require replacement investment of US$ 6040 million and Increase the Net Present Value of the LCEP by some US$ 30-40 million. c. The use of Orimulsion will fhrther exacerbate emission problems (7.07) since it Is high in Sulphur (3%) and is equivalent to a high sulphur coal and worse than the typical heavy fuel :oil now used. d. The existing stations may also have a problem in the discharge of dirty water, oil, and some chemicals into the sea. This could be reduced close to elimination by reconstructing the station drainage system and collecting and treating before discharge to the sea. Such a system should be a design feature for all new stations. The Intended Plant Audit should include this matter, as well as measuring and assessing the existing chimney emissions. The rehabilitation of the plant should give combustion Improvements and reduce the emission of smoke due to incomplete combustion. e. The discharge of NOx can be reduced somewhat by careful burner management but substantial reduction at existing stations would require new low-NOx burners on both steam and gas turbine plant; the xtent to which this would be possible requires detailed examination and could usefully be part of the forthcoming Plant Audit. The discharge of NOx can be minimised in new plant by specifying low-NOx burners to meet the required standards. f. For the assessment of environmental impact of the various stations in the LCEP, it is necessary to have measurements of existing (base) air and water quality and to identify the main sources of pollution (7.21). Ideally, there should be modelling of the effects of existing pollution to which can be added the effluents of proposed projects of all types, not just power stations. 7. Private Sector participation 25 a. ltre are no signiicant technical problems with private, BOO, power stations. However, it is essential that JPS thoroughly examine the design of all proposals to assure Itself that they will be designed and built to a reliable technical and envionmental standard (6.03 and 6.04). JPS will not be excused by the public If a possibly cheap but Inadequate private station were to perform so badly as to be the cause of load shedding or environmental pollution. SR-9 b. It Is also desirable for PS to invite proposals for private power stations only of the type which Is appropriate to the LCEP (6.07). An open bidding for any type of plant will be difficult to adjudicate and could be unfair to proposers (6.07). c. The contract terms for purchasing the output of a private power station will require special and careful attention (6.08) to protect JPS from poor availability, to ensure that the cost of energy reflects the best fuel prices, and to allow JPS to purchase power as and when it requires so as to minimise the total system running costs. d. The contract will be particularly important for the coal/oll station where the benefts of using the cheapest fuel should accrue to JPS and their consumers and not to the private owner. The possibility of the owner of the first stage of the coal/oll station not wishing to continue with later stages should also be covered. JPS Investment Programme 26 The investment programme including the generating plant forming the Least- Cost Expansion Plan to meet the reduced load forecast Is based only on draft and Incomplete work by JPS. The figures are, therefore, are tentative but indicate that for the five years to 1995/6, the investment amounts to US$ 350 million in foreign currency and US$ 120 million in local currency. These figures are tentative, but include the generation projects outlined above and are on the basis of the reduced load forecast. JAMAICA ENERGY SECTOR STRATEGY AND INVESTMENT PLANNING STUDY ELECTRIC POWER SECTOR SECTION 1 INTRODUCTION AND TERMS OF REFERENCE Introduction 1.01 This Report forms part of the broader ESSIP Study and is based on field work in Jamaica in March 1991 preceded by discussions in Washington. The SWECO Draft Least Cost Expansion Study (Ref 12) was available to the Mission and the SWECO Study Manager was available for discussions with the ESSIP team. Further discussions during 24-25 April 1991 In Washington, resolved some detailed differences between the Draft Reports of SWECO and the Missiov and arrived at common conclusions as recorded in Annexe H. Terms of Reference 1.02 The World Bank Office Memorandum dated 7 March 1991, repeated in Annexe B, outlined the Terms of Reference. Admowledgements 1.03 A list of persons met during the Study is given in Annexe A. The contribution of all, but particularly the counterpart staff in Jamaica Public Service Co and the Ministry of Mining and Energy, is gratefully acknowledged. Reference documents 1.04. The main documents which are pertinent to this Report, and which were examined or to which reference is made, are listed in Annexe C. They are referred to by the reference number. 1.05 The three main basic planning parameters used by SWECO and the mission are: a. A discount rate of 12%; b. A maximum loss of load probability (LOLP) of 2 days per year; c. A cost of unserved energy (due to load shedding) of US$ 1.5/Kuh based on a JPS study. SECTION 2 FORECAST OF DEMAND FOR ELECTRICITY Istoral 2.01 The historial growth of energy ales In the 1970s was at the modest rate of about 3.3% per yar foliowed by 2.2% per year to 1985 and then anncreas to 6.1 per year to 1990, in spite of the set back due to Hrrlcae Gfbert in September 1988. The producdon and sal slnce 1979 are: tear Møt generation Sales Company Losses and and purchases use unaccounted -Wh «Wh @wb Vh % 1979 1295 1060 7 228 17.6 1980 1274 1023 6 246 19.3 1981 1282 1017 6 259 20.2 1982 1338 1079 8 252 18.8 1983 1463 1172 6 285. 19.5 1984 1440 1157 7 276 19.2 1985 1437 1147 9 281 19.5 1986 1525 1227 7 291 19.1 1987/88(Apr/Mar) 1722 1370 7 273 16.5 1988/89(Apr/Kar) 1651 1271 7 372 22.5 1989/90(Apr/ar) 1944 1569 8 375 19.3 1990 2008 1650 8 343 17.1 Te salø comfprise abot 32% to residendal customers, 48% to small commeal and industrial, 11% to 1~rg commercial and bndustrial, and 9% to others. 2.02 At leastsx forc ofthe demd for city have b n madecent yem.Iey are: eport final date Subject Noneno 1985 Power Plan AN Back (Rei 2) August 1989 Power Plan R GNagler Bailly Inc (Ref 1) Decomber 1989 Tariffs Asbby/PIOi February 1990 8WEC0 (ze 11) Yebruary 1991 Demand Forecast JPa November 1990 Demand rorecast Metroeconmlca Ltd (Ref 15) January 1991 Demand Yorecast 2.03 The work by Metroconomica wa usentlally a crtqu of the SWECO, Ashby/POI and PS forca which took bnto accou the macro economic growth frecasts avalable to the World Bank In December 1990. Metroecoomica provided adjusted forecasts which showed all three after adjust~nt to be within +/- 3% by 1995 and withia +/-4% by 2000. One of the difficulties not Idendfed In d adjustments was a differet starting polat In 1989. SWECO ar quite elear In their Report (Section 2.2) 2-2 that their basis Is the actual sales, losses, and maximum demands for 1989. Another cause of confusion Is the "year." The IPS forecast appears to be by fiscal year which changed from a calendar year to a April-4arch year in 1988/89, whereas SWECO define their years as calendar years (Section 2.2). It is not clear whether the AshbylPCJ forecast was In calendar or fiscal years.Metroeconomica made some valid criticisms of method but they do not appear to be significant when placed in the context of all the other uncertainties and assumptions. 2.04 In view of the confusion over type of year and over actual loads in 1989 and in view of the remarkably small spread of the loads after adjustment by Metroeconomica, the SWECO base case forecast has been retained as the basis for planning In this Report. SWECO Demand Forecast (Ref 11) 2.05 The SWECO forecast is based on a detailed analysis and then synthesis of the various sectors and sub-sectors of the tariff categories and reflects econometric indicators. This detailed breakdown allowed estimates to be made by the Mission of the effect on the total demand of Demand-Side Management and energy conservation measures.The SWECO forecast is based on certain assumptions which can be changed for future forecasts and which are modified in this Report in respect of losses and Demand-Side Management: - Losses at 18.8% of the energy sent out from the power stations throughout the study period. - No change In tariffl from those promulgated in April 1990 - Consumption is independent of price and other variables such as household income, and foreign trade. SWECO acknowledge that such elasticities could be Included in future as a refinement but give the opinion that electricity consumption is "rather independent of price". - No change In the relative cost of electricity and its competitors, eg bottled gas and kerosene - No change in the high cost of solar water heaters (in large part due to import duties) - GDP to grow at 2.5% per year to 1990, then by 3%, 3%, 3.5%, and 3.5%, in the following years 2.06 The forecast is based on computer software which has been handed to JPS and can be used to update the forecast; such updating should be done at least annually. 2.07 The SWECO forecast is on the basis of calendar years and energy and demand sent out from the power stations. The Base Forecast is repeated in Table 2-1A. The Low Forecast and the High Forecasts are in Tables 2-1B and 2-1C respectively. The range from Low to High is somewhat large, being 22% lower and 27% higher than the Base by 2000. 2-3 2.08 The forecasting work was carried out by SWECO Ia mid-1990.The actual loads for 1990 were 315 MW and 2001 OWh, which are 3% and 2% respectively below the forecast for 1990. The shortfall refects a shortfall in the planned growth of GDP, a contribution to the shortfall probably be*ag the Gulf crisis, a decline in tourism and recession In the USA. The system load factor in 1990 was 69.6 % compared with the forecast of 71.7% rising to 73.3% in 2010. 2.09 As mentioned above, it was agreed with JPS to use the SWECO Base forecast for further planning studies. Ls Reduction Measures 2.10 JPS have undertaken, both themselves and through consultants (Refl4, 19 and 30), a number of studies dealing with loss reduction between the power stations and the consumers. These studies have either concentrated on losses or have dealt with losses as part of a wider remit. A Master Distribution Plan is expected to start in the near future; the Terms of Reference should specifically include an analysis of losses and a recommendation for the optimum level of losses. 2.11 The latest Report specifically on loss reduction was by Ebasco in July 1988 (Ref 14). Unfortunately, this report was unclear in declaring the loss reductions by the various measures and In stating the value of losses, both kW and kWh. The main figures given were the values of the monetary savings and from these, the following loss reductions can be inferred: Conversion from 12kV to 24kV 3.9% Reconductoring 2.6% Phase balancing 1.0% Correction of power factor to 0.95 . 1.0% Total 8.5% This reduction of 8.5% from 14% technical losses to 5.5% seems very optimistic; it may be that the total reduction is overestimated since the study was done on a sample of situations which may have comprised the worst cases and hence the scaling up to the whole system may be overstated. 2.12 The effect of loss reductions can be in two directions. First, there will probably be an improvnent in the voltage at the consumers terminals which will result in some increase in his demand for electricity, which will result in the benefit to JPS of inacreised revenue. Secondly, it will be possible to reduce the loading on the generators and the benefits to JPS will be in reduced fuel consumption and, In the longer term, a reduction In the amount of new generating plant required. It is uncertain how the loss should be proportioned between the two directions. The only direction of relevance to the Least Cost Expansion Plan is the one which results in reduced generation requirements.Clearly the Ebasco loss reductions have to be discounted in some degree. The matter was discussed at some length with JPS and it was agreed that a loss reduction of 4% on energy and 5% on maximum demand was a reasonable expectation and should be adopted. The reduction would be effective in equal increments over the years 2-4 1992 to 1995 Inclusive; the reduction would remain constant at the above figures after 1995 In the expectation that transmission and distribution developments would be designed to maintain the reduced level of losses. 2.13 The unaccounted losses due to theft, faulty meters, and In2dequate collection and billing procedures will mainly result in Increased revenue and is not relevant to the LCEP. These unaccounted losses are also uncertain In magnitude, Ebasco quoting them as being about 5% of the energy sent out from power stations and SWECO taking them as 10%. 2.14 The total of all energy losses will be reduced from the current level of 19% to about 10% (assuming the unaccounted losses are largely eliminated). Of this 9% reduction, some 5% will yield increased sales and 4% will, as stated above, reduce the load on the power statlons.The amount of losses to be saved by loss reduction measures Is given In Tables 24A, B and C. Demand-Side Management and Energy Conservation 2.15 Details of the Demand-Side Management and Energy Conservation proposals and their implementation are given In a separate Mission Report by the ESSIPS energy conservation specialist. A low (conservative) and high (optimistic but achievable) forecast was prepared and this Power Sector Report uses the mean of the two. The two forecasts of potential reductions in maximum demand and energy were essentially a matter of judgement between practical extremes and are as follows: Year Low (Conservative) High (optimistic) MW OWh aW GWh 1991 - - - - 1992 1 4 2 15 1993 3 15 2 49 1994 6 33 15 96 1995 12 56 28 156 1996 17 so 41 222 1997 21 102 51 281 1998 24 118 57 - 334 1999 25 129 63 384 2000 26 140 67 418 2005 32 189 83 540 2010 36 224 93 631 2.16 The Implementation of Demand-Side Management and a more detailed assessment of the likely effects is currently being planned and therefore the above figures most be used with some reserve, but they represent the best judgement available at present. One of the aspects of quantifying the likely reductions In demand is to assess the overall costs and benefits both to JPS and to the consumers. The benefits to JPS in reduced Investment, fuel and operating costs are assessed later as avoided costs in the 2-5 Least Cost Expansion Plan and will be used In further work on Demand-Side Mavagement and Energy Conservation. Lead Forecast 2.17 Both the basic SWECO forecast and the Reduced Forecast after loss reductions and Demand-Side Management are given In Tables 2-lA, 11, and 1C for the Base, Low and High forecasts. The reductions for the Low and High forecasts use the same percentage figures for Loss Reduction and the same absolute figures for Demand-Side Management as for the Base forecast. 2.18 SWECO have used their unreduced Base forecast for their main studies of the Least Cost Expansion Plan (LCEP) and will use the unreduced Low and High forecasts for sensitivity analyses. This Report uses the unareduced Base forecast for purposes of comparison with the SWECO LCEP and then uses the reduced Base forecast (right hand side of Table 2-lA), both as a basis from which to make sensitivity studies and to derive the Rvoided cost of the load reduction measures. 2.19 An effect of both loss reduction and Demand-Side Management is the increase in system load factor from about 73% to 75%, as can be seen from Table 2-lA. The effect on the Low forecast of the loss and DSM reductions is to almost eliminate growth of load. Tariffs 2.20 An increase In tariffs of about 37% was Implemented In April 1990 as part of a recasting of tariffs to refect long run marginal costs. Provisions were made for fhel cost adjustments In respect of the price of fuel due to both international oil price changes and exchange rate changes. While the fuel price adjustment clause protects JPS from events outside Its control, it should also be noted that the tariff is set on a cost plus basis, and as a result, there is little direct incentive for JPS to vigorously pusue efficiacy improvements. 2-6 TABLE 2*IA BASIC LOAD FORECASTS Forecast reduced after Balsi forecast by SECO toss reduction and DSN Dedution for Naiusm Growth Lead Deduction for Demand-de RadoamI growth Load Calender Energy Demand Rate Factor lose reduction Management Energy Demand Rate Factor Year W W x 0A NU A W GW BW 2 % 1989 1944 309 72 0 0 1944 309 72 1990 2041 325 5.2 72 0 0 2041 325 5.2 72 1991 2167 345 6.0 72 0 0 2167 345 6.0 72 1992 2301 365 5.9 72 23 5 9 2 2269 359 4.2 72 1993 2448 387 6.1 72 49 10 30 6 2369 372 3.5 73 1994 2597 410 5.8 72 78 15 57 12 2463 382 2.9 74 1995 2764 435 6.1 73 111 22 107 21 2547 392 2.5 74 1996 2868 451 3.8 73 115 23 145 30 2608 398 1.7 75 1997 2973 467 3.6 73 119 23 185 37 2669 407 2.2 75 1998 3078 484 35 73 123 24 218 4 2737 416 2.2 75 1999 3183 500 3.4 73 127 25 248 48 2808 427 2.6 75 2000 3288 516 3.3 73 132 26 269 52 2887 439 2.8 75 2001 3392 532 3.1 73 136 27 289 - 55 2967 451 2.8 75 2002 3496 548 3.0 73 140 27 306 58 3051 463 2.7 75 2003 3600 564 2.9 73 144 28 316 59 3141 4?? 2.9 75 2004 3704 580 2.8 73 148 29 336 62 3220 489 2.5 75 2005 3808 596 2.7 73 152 30 350 4 3306 502 2.8 75 2006 3930 614 3.1 73 157 31 361 66 3412 518 3.1 75 2007 4052 633 3.0 73 162 32 373 67 3517 534 3.2 75 2008 4175 651 2.9 73 167 33 379 68 3630 551 3.0 75 2009 4297 670 2.8 73 172 33 395 70 3730 567 2.9 75 2010 4419 688 2.8 73 177 34 405 71 3837 583 2.8 75 2-7 TASLE 2-18 LOM LOAD FORECASTS Forocest reduced efter Low forecst by SECP toss reductio and DM Deductlon for Mxlmän Growth Load Dduotion for Demand-side maximua Grouth Lad Catondar Enor Dem nd Rate factor Loss rduction Management Enorgy Domnd Rate grouth 7ur 4% Kw h % uGWh M41 Kw ltK % a 1989 1944 309 72 0 0 1944 309 72 1990 2004 319 3.1 72 0 0 2004 319 3.1 72 1991 2090 331 4.1 73 0 0 2090 331 4.1 7 1992 2176 345 4.0 72 22 4 9 2 2145 339 2.3 72 1993 2270 358 3.9 72 45 9 30 6 2195 343 1.2 73 1994 2353 370 3.4 73 71 14 57 12 2226 344 0.4 74 1995 2441 383 3.4 73 98 19 107 21 2237 343 -0.5 74 1996 2468 387 1.1 73 99 19 145 30 2224 338 •1.5 75 1997 2495 391 1.1 73 100 20 185 37 2210 335 -0.9 n 1998 2522 395 1.1 73 101 20 218 44 2203 332 .0.8 76 1999 2548 400 1.1 73 102 20 248 48 2199 332 -0.2 76 2000 2547 404 1.1 72 102 20 269 52 2176 332 0.1 n 2001 2589 406 0.5 73 104 20 289 55 2196 331 -0.3 76 2002 2603 408 0.5 73 104 20 306 58 2193 330 -0.3 76 2003 2616 410 0.5 73 105 21 316 59 2196 331 0.1 76 2004 2630 413 0.5 73 105 21 336 62 2189 330 -0.3 76 2005 2644 415 0.5 73 106 21 350 64 2189 330 0.2 76 2006 2659 417 0.6 73 106 21 361 66 2192 331 0.1 76 3007 2674 420 0.6 73 107 21 373 67 2195 332 0.4 73 2008 2690 422 0.6 73 108 21 379 68 2204 333 0.2 75 2009 2705 424 0.6 73 108 21 395 70 2202 334 0.3 73 2010 2720 427 0.6 73 109 21 405 71 2206 334 0.2 75 2-8 IABLE 2.C IGm LOAD FORECA8T Forecast reduced after Nioh foreast by «IECO loss reductton and D&M Deduton for "axiom croth Lond Duöction for emdside maxima Growth oad Caleider Enfi emand Rate factor loss reduction Managm nt Energy Demand Rate factor year Wh Kw % % m0 K mle "w mW mw 1989 1944 309 72 0 0 1944 309 72 1990 2093 332 7.4 72 0 0 2093 332 7.4 72 1991 2279 360 8.5 72 0 0 2279 360 8.5 72 1992 2468 391 8.6 72 25 5 9 2 2434 384 6.8 72 1993 2714 426 9.0 73 54 11 30 6 2630 409 6.4 73 1994 2948 461 8.3 73 88 17 57 12 2803 432 5.6 74 1993 3202 500 8.5 73 128 25 107 21 2967 454 5.2 75 1996 3396 530 5.9 73 136 26 145 30 3115 473 4.2 75 1997 3589 559 5.6 73 144 28 185 37 3260 494 4.5 75 1998 3782 589 5.3 73 151 29 218 44 3413 516 4.4 76 1999 3976 618 5.0 73 159 31 -248 48 3569 539 4.6 76 2000 4168 648 4.8 73 167 32 269 52 3732 564 4.6 76 2001 4398 682 5.2 74 176 34 289 55 3933 593 5.2 76 2002 4627 716 5.0 74 185 36 306 58 4136 623 4.9 76 2003 4857 750 4.7 74 194 37 316 59 4347 653 4.9 74 2004 5086 784 4.5 74 203 39 336 62 4547 683 4.5 76 2005 5315 818 4.3 74 213 41 350 64 4753 713 4.5 76 2006 5610 862 5.4 74 224 43 361 66 5025 753 5.6 76 2007 5905 905 5.1 74 236 45 373 67 5296 794 5.4 76 2008 6200 949 4.8 75 248 47 379 68 5574 834 5.1 76 2009 6495 993 4.6 75 260 50 395 70 5840 874 4.8 76 2010 6789 1037 4.4 75 272 52 405 71 6112 914 4.6 76 SECTION 3 EXISTING GENERATING PLANT 3.1 JPS Genating Stations 3.01 The sent out capacity of JPS thermal generating stations will amount to some 499 MW comprising 297 MW of oil-fired steam plant, 40 MW of low-speed Diesel plant and 162 MW of gas turbines, after rehabilitationby the end of 1993. Table 3-1 gives some details of the plant which is in four stations at Old Harbour (all steam), Hunt's Bay (steam and gas turbines), Rockfort (Diesels) and Bogue (all gas turbines). Some of the plant, especially the steam plant, is undergoing or Is shortly to undergo rehabilitation at a cost of some US$ 25 million; fArther rehabilitation is planned for Hunt's Day gas turbines In about 1994 and two gas turbines at Hunt's Bay have just been rehabilitated. 3.02 An updated off-line computer based economic load despatching system has recently been Introduced and is estimated to have reduced fuel consumption by about 4%; the cost of this system has probably already paid for Itself in fuel savings. A further computer-based plant monitoring system is being introduced and will bring two further benefits. First, there will be very early warning of deterioration In plant performance allowing early remedial action or adjustments (eg to burners) to be taken to maintain the plant efficiency at a high level. Secondly, the monitoring will Identify Incipient faults which will allow tarly warning of possible outages for repair or maintenance and provide time to prepare for remedial action and ensure that the required spares and parts are available. This Information will, however, be of little advantage if remedial action is not taken quickly; it Is therefore vital that maintenance resources are available to deal with both the routine planned work and the work Identified by the monitoring system. 3.03 JPS also has nine hydroelectric stations. All are small, the largest at Magotty Falls having a capacity of 6.3 MW. The stations are listed below: Plant Year in Installed Annual service Capacity Energy N4W Gt4h Upper White River 1945 3.8 17 Lower White River 1952 4.9 23 Roaring River 1949 3.8 29 Rio Bueno A 1949 2.5 17 Magotty Falls 1966 6.3 40 Constant Spring 1959 0.8 L Rams Horn 1988 0.6 3 Rio Bueno River 1988 1.1 5 Morant River 1988 0.2 1 Total 24.0 141 3-2 The older schemes are to be rehabilitated under an IDB loan following a feasibility study in June 1989 by MC Energle - und Umwelttechalk GMBH (Ref 37). The work will comprise general modernisation and replacement of wood stave pipelines. The cost Included in the JPS draft Investment Programme is US$ 3.5 million Fuels 3.04 The steam and Diesel plant all burn Number 6 heavy fuel oil (HFO) supplied from the refinery near to Hunt's Bay station. The oil has about 2.8% to 3% of sulphur. It is of a quality suitable for use as a feedstock for catalytic cracking and is about US$ 1.50/bbl more costly than Bunker C oil bought on the open market. Fuel cost savings of US$ 4-5 million per year over the next 7-8 years could result from any necessary modifications to the plant, probably at modest cost. The gas turbines all burn adesel No 2, an Automotive Diesel Oil. The heavy fuel oil (Bunker C) price is some US$ 18/bbl and does not bear any taxes or duties. The ADO costs about US$ 33/bbt before taxes and bears a 40% tax giving a total price of US$ 46/bb; this is the financial price that JPS must pay though it is passed on to the consumers. Taxes and duties are, of course, excluded from this economic analysis of the least cost expansion plan. 3.05 The need to burn an expensive fuel arises from the inability of gas turbines to burn a *dirty' fuel; they require a clean or distillate fuel for adequate life and performance. The consequence is that the gas turbines are operated on the peak of the load or kept as standby in order to minimise costs. Availability 3.06 The availability of the existing plant over the last five years, based on outage statistics from IPS (Ref 18), is given in Table 3-2A and B. The contribution of unavallablity of generating plant to total interruptions to the supply to consumers is shown in Table 3-3; generating plant outages cause only some 10% (le about 100-150 minutes per year) of the total interruptions to supply, though the proportion was much greater in 1982 and 1984. It is not possible to directly link this average outage per consumer of about 2 hours per year with the Loss Of Load Probability (LOLP) criterion of not exceeding 2 days per yar or 48 hours per year. However, there are 300,000 consumers and so the interruptions amount to 600,000 consumer-hours. It seems not unreasonable to assume that, on average, a generation outage probably causes some 20,000 consumers to lose their supply, which at the criterion of 48 hours per year would give 960,000 consumer-hours of interruption, which compares with the earlier calculation. Ali that this suggests is that the actual interruptions and the 2 days per year LOPL are not widely different. 3.07 These availablity figures are at some variance with statistics reported by SWECO to have been obtained by examination of station logsheets. This raw data obtained by SWECO has not been available for study for this Report; the experience for 1989 is quoted in the SWECO Report (Ref 12) but it is not known if earlier years were also examined. It can be seen from Tables 3-2A and 3-2B that the availability assumed by SWECO Is worse than the apparent availability from JPS statistics. This apparent anomaly has not been resolved. The SWECO figures used for existing and new plant are shown in the 3-3 Tables. Forced outage rates used later in The JPS WASP II model are taken to be 7% for all types of new plant; this is somewhat lower than SWECO but reflects more reasonable expectations. 3.08 Availability of plant Is greatly affected by the availability of spare parts and this, In the past, has been made worse by delays In obtaining foreign exchange for the purchase of parts, sometimes needed at short notice. This foreign exchange problem appears now to have been solved. Ilteiablitation 3.09 Much of the plant was rehabilitated about 1985, but since then, its performance and availability has deteriorated as can be seen from Table 3-2. A further rehabilitation programme is under way, especially for the steam plant at Old Harbour and Hunt's Day. This will improve both the efficiency of the plant and Its availability. The plant rehabilitated and the corresponding investment are shown In Table 3-1. A Plant Audit Is being arranged by JPS to investigate in greater depth the extent of rehabilitation work and the resulting effects on life extension. As already mentioned in para. 3.02, adequate maintenance resources are vital, particularly to maintain the benefits of rehabilitation and life extension and to minimize the need for further rehabilitation in a few years' time. Environmental Factors 3.10 The existing power stations affect the environment in two main ways. The first Is chimney emissions containing sulphur dioxide (SO,) and nitrogen oxides (NOJ. Little can be done about SO without spending excessively on plant to remove the SQ or on low-sulphur fuel, especially in the context of the limited life of the plant. The extent to which these omissions affect the local environment is unknown and will remain so until baseline measurements have been made, as recommended later in Section 7.8. NO, may be reduced at the steam stations if it proves feasible to modify the burners. The second main environmental effect is in the release of dirty water, oil, chemicals and boiler blowdown into the station drains and hence into the sea. Improvements are possible by rearranging the station drainage system with a view to catching the waste and treating it before discharging to the sea. The Plant Audit should have these environmental aspects added to the Terms of Reference, and indeed should identify all other environmental difficulties; suggested additions to the Terms of Reference for the Plant Audit are given in Annexe E. It would be possible to reduce ground level concentrations of emissions by increasing stack heights on existing plants. These measures would again be costly, particularly in view of the planned retirement of the Hunts Bay steam plants over the next 10 years. In the longer term, environmental Improvements in Kingston can be more cost effectively achieved by relocating the generating plant. This issue is a matter for further study in the current plant environment. Retrement 3.11 The retirement of plant for planning purposes assumes sowewhat arbitrary dates based on plant accounting lives, typically 25 or 30 years, the presently envisaged retirement dates having been given in Table 3-1. The forthcoming Plant Audit will give an indication of the expected future life but actual retirement dates will depend on the state of the plant at the time. It may well be economic, if 3-4 necessary, to undertake fArther rehabilitation or life extension In another 5 or more years time. The SWECO Report (Ref 12) shows that the current rehabilitation programme is highly profitable and this may be repeated in the future. 3.2 Other generating plant Bauxhaf/Alumina Industry 3.12 The bauxite and alumina industry requires substantial amounts of power and steam for process. Details of the generating capacity at some of the mines is given in the JPS Report (Ref 18). The plant is largely co-generation, using back pressure or pass-out-condensing turbines; the process steam and generatizg capacities are broadly in balance so that the process does not need to import electricityr nor has it surplus to sell to JPS. There Is a connection between JPS and at number of bauxite/alumina mines but the exchange of electricity is small. Studies have been made at various times into the possibility of installing significant amounts of generating capacity at the mines with a view to selling surplus to JPS, for example at Clarendon (Ref 32). None of these proposals have materialised. 3.13 The bauxite industry uses heavy fuel oil bought on the international market at a price generally lower than that paid by JPS, the fuel also being of lower quality. Coal conversion has been evaluated, for example by Alcan Jamaica, in the form a coal-fired topping plant, but was rejected as being uneconomic. The aluminium industry is somewhat depressed and it seems unlikely that any investment in new plant or conversions will be undertaken in the foreseeable future. 3.14 The boiler plant is typically 20 or more years old so that conversion and more efficient cogeneration may arise as a possibility in the future, particularly if the market for aluminium improves. Some of the bauxite/alumina plants operate at 60 Herts which adds an additional frequency conversion cost to any proposals for cogeneration and supply to JPS. Sugar Pactories 3.15 Details of boiler and generating plant at some of the sugar estates are also given in the JPS Report (Ref 18). The equipment is generally 15-20 years old or more but only operates during the cropping season of 6-7 months per year. The generating plant seems to be mainly pass-out and back- pressure types and hence the output is very largely dependent on the steam demands of the factory. It is well known that sugar factory boilers are designed to get rid of the bagasse at whatever efficiency produces the required steam. It is also well known that the bagasse can be burned at much higher efficiencies and allow the generation of surplus electricity from condensing turbines; this is an option discussed later. Generation Augmentation Programme 3.16 The Energy Conservation Unit has identified some 40 MW of emergency generating capacity in the country, most of it being in small diesel driven machines. It would be possible to use these 3-5 machines as emergency support for the JPS system under appropriate contractual terms which are being developed by the ECU with the owners. However, some of the owners may prefer to keep the machines for their own emergencies (including those due to cuts in supply). Some of the machines may require additional equipment to protect the system from faults and to allow the emergency generators to be synchronised with the system. A tariff for the availability and use of the machines will have to be agreed. The practical capacity that could be made available Is clearly less than 40 MW, particularly as some of the machines will be too small to bother with, and is taken as zero for the purposes of this Report. Nonetheless, Investigation of available capacity should clearly proceed for use in emergencies. 3.17 The Caribbean Cement Co has some 27 MW of Diesel generating plant and could supply 6-7 MW to JPS; negotiations are currently in progress to arrive at an agreement for the supply of this capacity when required. The Cement Co has attempted to use heavy fuel oil in its Diesels but found that exhaust valves were wearing out faster than they could be replaced; the problem was Vanadium and Sodium in the fuel. They now can only burn heavy fuel oil when mixed with the same quantity of Diesel oil No 2. Experience elsewhere in the Caribbean confirms serious problems in burning high vanadium heavy fuels (derived from Veneauelan crude) in medium-speed diesels, and It is recommended later in Section 4 that medium speed diesel generators should not be an option for JPS in Jamaica. 3-6 TABLE 3-1 EXISTING TUERNAL CAPACITY AND RENABILITATION (1993> Sefore rehablitation After rehablitation Station NmeteCapcfty Keet rate Capotty Neat rate Capacity RetfremnCot of and capacIty generated generoted sent out yar rehab Unit N9 Kw stu/kNh N Stu/kUh h UKw8,00 STm PLANT Old 6arbaur No 1 33 27 16600 30 13620 28.5 1998 5000 No 2 60 55 13300 60 1260 57 1999 500 No 3 68.5 55 12950 55 12720 52.2 2000 5500 No 4 68.5 60 13100 68.5 12160 65.1 2002 1800 un's Bay No 1 12.5 Old plant, run when necesary No 2 12.5 Old plant, run mhen necesary No 3/4 15 10 20000 None planed 10 1995 0 Nos 20 20 14750 None aned 19 1996 0 No 6 68.5 68.5 12600 68.5 12160 65.1 2006 5720 Nunt's Bay No 1 14 14 19000 14 19000 14 1996 3800 No 2 14 14 19000 14 19000 14 1998 3800 No 4 20 20 18500 20 14750 20 1997 5400 k05 20 20 18400 20 14750 20 1997 5400 No3 22.8 20 16M400 23 14750 22 1998 5400 No 6 18.5 18.5 12650 New plant 18 2015 0 No 7 18.5 18.5 12650 New plant 18 2015 0 No 8 18.5 18.5 12650 New plant 18 2015 0 No 9 18.5 18.5 12650 New plant 18 2016 0 LOW DIESELS Rockfort No 1 20 20 850 20 8600. 20 2012 350 No2 20 20 8850 20 8600 20 2012 350 TOTAL 563.3 497.5 517 498.9 43020 Source: Ref 18 - JPK Electricity System Irprovement Project Ref 12- UECO Draft Report 3-7 TABLE 3-2A JTAGE RATES FOR STEAN PLANT 2 of year 1/2 yar =cEco 196 1987 1968 1989 1990 Avorao Ratcs MORCED m RITAGE RATE; Old Harbou No 1 10.5 2.8 4.4 7.2 2.3 6.0 15.0 No2 18.8 1.2 7.5 11.7 4.1 9.6 10.0 No 3 0.8 0.1 3.3 15.4 3.9 5.2 10.0 No 4 0.8 2.2 0.5 9.2 10.9 5.2 10.0 Rnt's Bay No 6 0.2 4.9 18.7 5.3 10.0 Average 6.3 11.0 CODULED OUTAGE RATEM New plant 10.0 Old Nerbour No 1 3.2 2.9 2.0 13.8 12.1 7.6 No 2 4.6 0.4 6.6 3.6 5.5 4.6 No 3 7.4 0.5 10.2 13.4 2.9 7.6 No4 2.2 3.8 11.2 9.7 0.8 6.2 Nunt's Boy No 6 4.7 31.3 12.7 10.8 Average 7.4 TOTAL MUTAGE RATE New plant 11.0 Old Narbour No 1 13.7 5.7 6.4 21.0 14.4 13.6 No 2 23.4 1.6 14.1 15.3 9.6 14.2 No 3 8.2 0.6 13.5 28.8 6.8 12.9 No4 3.0 6.0 11.7 18.9 11.7 11.4 Nunt's Day No 6 0.0 0.0 4.9 36.2 31.4 16.1 Averagp 13.6 Now Plant 21.0 Source: Ref 18 • JPS Electricity System Inprovement Project 348 TABLE 3-2 GUTAGE MATES FN GAS TURSIE AD DIESEL PLAMT 2 of yma 1/2 yfar 8MCO 196 1987 198 1989 1990 Average Ratos FORCED OUTAGE RATES - DIESELS Rockfort mo 1 0.4 5.9 6.7 10.2 1.6 5.5 8.0 No 2 0.4 1.7 3.7 6.0 0.3 2.7 8.0 Avrage 4.1 8.0 *CMEDULED OTAGE RATES • DIESELS New plant 8.0 Rockfort No 1 5.8 12.4 4.9 11.5 0.5 7.8 No 2 3.0 10.5 2.7 9.6 0.5 5.8 Averago 6.8 TOTAL OUTAGE RATE • DIESELS New plant 11.0 Rockfort ko 1 6.2 18.3 11.6 21.7 2.1 13.3 Mo 2 3.4 12.2 6.4 15.6 0.8 8.5 Average 10.9 New plant 19.0 TOTAL OUTAGE RATSS• GAS TURMINES amt's Bay No 1 0.3 4.7 11.9 24.2 15.7 13.1 No 2 2.2 9.1 4.9 2.8 3$.8 12.7 No 4 7.8 19.2 17.3 19.8 19.9 19.4 No 5 2.4 0.6 1.9 11.9 2.1 4.4 Average 11.4 12.5+ New Plant 10.8 3-.9 TASLS 3*3 RELIABILITY OF SUPPLY Arages miutes lost per customar as a result of outages Year Seneration Transamssion Distribution Total 1982 6131 429 500 7060 1983 693 845 938 2476 1984 1727 1811 1987 5525 1985 286 875 1581 2742 1966 165 555 1023 1743 1966/87 116 584 1056 1756 1967/88 151 314 1002 1467 1988/89 74 354 594 1022 1990 347 309 827 1483 Source: Ref 18 - JPS Etectricity System Improvement Project SECTION 4 OPTIONS FOR FUTURE GENERATING PLANT 4.1 Dual41red (coal/oll) steam plant 4.01 A coal-fired steam plant has been under consideration for a number of years. EPDC of Japan (Ref 33) made a detailed study In 1988 and proposed a site at Cow Bay for a station with 6-66 MW units together with a jetty for 30,000 ton ships. The site at Cow Bay has since been found to be unsuitable for reasons of Instability, particularly under hurricane conditions. Leading particulars of the station set out by EPDC are given below: Areas Coal storage 78,000 sq m Ash disposal 1077,000 sq a 25 years Power station 245,000 sq m Total 1400,000 sq a chimneys Height 69 m Number 3 2 flues Power house Height 25 m Area 3,140 sq m Volume 59,600 cub a Boilers Max cont rating 270 t/h Steam pressure 92 kg/sq cm Steam temperature 513 Deg C Turbines Single cylinder, single flow, condensing Rated output 66 NW Back pressure 700 mm Hg Condenser outlet temp 36.4 Deg C Precipitator Efficiency 99 % or more Dust burden at outlet 0.109 g/cub m at NTP 4.02 The Government Coal Committee reporting In 1989 (Ref 31) confirmed the attractiveness of coal as a fel for power generation and recommended that coal be adopted by JPS as the generation option and that the Iplementation of the programme should start as a matter of urgency: This was based on the availability of low sulphur coal at reasonable and negotiable rates and an attractive return, amongst other factors. An additional attraction is the ability to burn either coal or oil and so take advantage of the cheapest of the fuels at any time. 4-2 Siting 4.03 One of the alternative sites identified by EPDC at Rocky Point (Salt River) is currently being investigated by consultants financed by CIDA (Ref 21), both to confirm its suitability and to carry out an environmental impact assessment. It is equally Important to undertake at least preliminary site investigations to establish the suitability of the site for founding a power station and to give an Indication of the type of foundations required. This work should be completed before site-specific environmental assessments are carried out. If the site proves to be unsuitable, it will be necessary to move to one of the reserve sites and these should be ranked now to avoid delays. Design 4.04 The detailed design of the power station will probably be similar to that proposed by EPDC, but suited to the particular site chosen. A ful Feasibility Report should be undertaken, for completion by the end of 1992, to establish the design to a stage from which tender documentation could be prepared. The station should clearly be designed to burn coal from the outset with at least provision for heavy fuel oil. The extra investment for providing for a ftture oil burning facility will be small since the design of the boiler is dominated by the coal burning mode. The eventual cost of actually installing the oil burning facilities is modest, and the decision whether or not to be able to burn oil from the outset can be made later. The design should re-examine the environmental aspects and the size of generating unit in the light of load growth and the effects of loss reduction and DSM. In particular, the possibility of using circulating fluidised-bed boilers should be seriously considered; these would allow the use of high sulphur (and cheaper) coals, but may preclude the use of oil as an alternative fuel. It would be Important to ensure good staff training and proper safety devices for all types of plant but particularly If pulverised coal in conventional boilers is to be used. Orimulsion 4.05 A new oil from Venezuela is now available. It is derived from reserves of bitumen and extra-heavy hydrocarbons In the Orinoco basin which must be emulsified with 30% water. The fuel has been tested in rigs operated by major boiler manufacturers in USA UK, and Japan. Full scale tests on operating boilers have been carried out at Dathousle generating station in New Brunswick and the reports are promising (Ref 23 and 26). Orimulsion is currently being burned by Florida Light and Power and by PowerGen at the 2000 MW oil-fired Pembroke power station in UK for which 1 million tons of Orimulsion are reported to have been bought. 4.06 The prospects for Orimulsion seem promising. There are certain restrictions on Its treatment, for example heating surfaces must be kept within the range 5-80 dog C, sudden pressure changes (to limit shear forces) must be limited to about 5-6 bar and it should not be contaminated with other liquid fuels. Its combustion characteristics seem good, the Dalhousie trials achieving excess air requirements as low as 0.2% oxygen at the boiler exit. Flame temperature Is lower and carbon conversion Is better than 99% without the need for fly-ash reinjection. The main problem with Ormulsion would 4-3 appear to be environmental due to the high (3%) sulphur content which on a heat basis is 50% worse than 3% sulphur In heavy fuel oil and three times as bad as low-sulphur coal. 4.07 While the prospects for Ormulslon seem promising, it Is recommended that Jamaica not make any commitment until more experience on a commercial (rather than a trial) basis has been accumulated. There is no need to make any commitment since the design of the coal station need not be finalised for about 2 years and there is some time to observe the use of Orimulsion in commercial operation. The use of Orimulsion may also affect the choice between conventional dual-fired boilers and circulating fluidised-bed boilers. Environment 4.08 Reference has already been made to CIDA financed siting studies and the environmental impact assessment of the proposed coalloil station (Ref 21). Environmental matters are discussed in detail in Section 7. 4.2 Other fuel-fired options 4.09 The main generation options in addition to coal are: Heavy oil-fired steam station Medium speed Diesel generators Low speed Diesel generators Gas turbine generators Combined cycle plants 4.10 It is not recommended that medium speed Diesel generators should be considered for Jamaica because of the Vanadium and Sodium In the fuel, which derives from Venezuelan crude. Reference has been made in Section 3 to the problems encountered by the Caribbean Cement Co and the risks of poor avall-ability due to abast valve and other problems are too great, in spite of the claims by manufacturers to offer satisfactory fuel treatment. Similar experience Is reported at other medium. speed Diesel stations in the Caribbean area. This elimination of medium-speed Diesels on technical grounds was agreed to by SWECO (see Annexe H), who will reflect the poor availability and high maintenance costs in their final Report; this Is expected to confirm the exclusion of medium-speed Diesels on economic grounds alone since the margin between medium- and low-speed Diesels in the draft Report is very narrow. All the remaining options are acceptable, JPS having experience of them all, except for combined cycle and, even for that, it has experience of most of the components. * 4.11 Proposals have been made for sites for some of the options, for example the combined cycle plant could go at Hunt's Bay and in due course other plant could go at existing sites when plant is retired. A detailed examination 4-4 of possible sites for the various options should be made to establish their suitability and ranking for the plant; for example, the foundation conditions for low speed Diesels will be quite different from those required for gas turbines. 4.12 It will also be necessary to make an Environmental Impact Assessment for each site and It does not necessarily follow that a new plant on an old power station site will be acceptable. 4.13 The combined cycle option Is not economically suited to the existing plant mix and load. The fuel prices are such that a combined cycle plant would operate at modest load factor near to the peak of the load, just below the gas turbines which will be on peaking or standby duty. This operating regime Is most unusual for combined cycle plant. Its operation on peak load in Jamaica will mean that its efficiency and maintenance costs will be impaired due to the extensive stopping and starting on peak load duty and this will further reduce the already modest advantages of high efficiency for peak load duty. Most combined cycle plants operate on natural gas in places where that fuel is relatively cheap so that the plants work on base load; there are few examples of combined cycle plant using expensive diesel oil. Maintenance costs on distillate fuel are reported to be 50% higher than running on natural gas. 4.14 All options should be designed to reduce environmental impact for the specific sites, when they are identified. They should also be technically advanced in the reduction of NO, emissions. 4.15 The fuel burned at the existing steam and Diesel power stations Is Heavy Fuel No 6 from the Petrojam refinery. It is a good quality fuel oil in that It is capable of being further cracked and Petrojam are considering the addition of a cracking plant. The resulting fuel would be more viscous, of greater gravity and contain more residual constituents such as Vanadium, sodium and ash. It would be known by the generic name of Bunker C. Similar fuels are available on the open market and are used by other industries in Jamaica, notably the bauxite/alumina industry. The benefit is, of course, the lower price. 4.16 Before going ahead with the burning of such Bunker C in the JPS steam and Diesel stations (existing or new) It would be prudent to obtain assurance that the fuels can be so used either In the plants as they are or with such modifications as may be necessary and that the environmental Impact ofthe change would be acceptable, again in the plants as they are or with such modifications as may be needed. There is little doubt that the stations can be made to burn Bunker C with little or no costly modifications but the environmental impact in the context of the Kingston area may be more difficult. Suggested Terms of Reference for a study to evaluate the possible change to Bunker C are given in Annexe G. This study could be combined with the Power Plant Performance Audit (para 3.09). 4.3 Renewable eergy sources Hydro electric 4.17 The main hydroelectric option is the Back Rio Grande Project, the subject of a recent Report by SWECO and CIPS (Ref 13). The leading details of the recommended scheme are: 4-5 Back Rio Grande Power station Underground Installed capacity 2 x 25.25 XV Grose head 182.5 m Design discharge 33.7 cub m/a Headrace tunnel 25 m Penstock 240 m Tailrace tunnel 4,610 a Dependable capacity (95%) 45.6 V Peak energy 64 GWh/y Off-peak energy 33 GWh/y Capital cost 103.9 US$ million Capital cost per 2,278 US$/kW dependable kW Upper scheme Power station Surface Installed capacity 6.0 MW Design head 84.7 m Dependable capacity (95%) 0.7 XW Peak energy 7 GVh/y Off peak energy 16 GWh/y Capital cost 20.4 US$ million Capital cost per dependable kW 29,142 US$/kW 4.18 There are a number of other hydroelectric prospects In the size range up to about 8 MW installed and these have been Reviewed In a Report for the Ministry of Mining and Energy in September 1990 by Glen Ichikawa (Ref 40). These are summarised in Table 4-1 and are considered later when examining their economics. Ile dependable capacity totals to nearly 6 MW out of an lastalled capacity of 40 MW; it is clear that the schemes have little storage and would operate as run-of-river stations. agsse 4.19 The prospect of better use of bagasse at the sugar factories has been mentioned earlier and there is little doubt that improvements could be made resulting in an excess of electricity for the JPS system. It had been hoped that technical and financial information would have been available for at least one project, at Frome, said to be capable of supporting 25 MW of capacity with perhaps 20 MW for sale to JPS. Unfortunately, no such information has become available and bence it is not possible to consider the economics in the context of the Least Cost Expansion Plan. or in any other context. The matter should be pursued by JPS as soon as information becomes available. There appear to be further prospects at Moneymusk (10-12 MW), Long Pond (5-7 MW) and Bernard Lodge (5-7 MW). The Frome project would be developed as a private sector venture on the basis of a power purchase tariff with JPS. 4-6 Peat 4.20 The main peat deposits near Negril estimated to be capable of providing sufficient fuel for a 90 MW power station for 30 years. However there are environmental problems arising from interference with the flora and fauna of the area and due to the proximity of the Negril Beach tourist centre, and the prospect has been put in abeyance, and has been specifically excluded from this study. Windpower 4.21 The Ministry of Mining and Energy has received a proposal from US Windpower for three 20 MW wind farms, each made up of 200 wind generators of 100 kW capacity. The proposal has no costs and Is subject to monitoring wind speeds in selected locations before making proposals. There is clearly insufficient data on which to make any studies at present. As wind power does not provide firm energy, Its principle benefit is in fuel saving. Solar energy 4.22 Solar energy is being pursued on a demonstration basis in a number of projects in different countries using concentrated,and distributed collection methods and using photo-voltaic devices. None have yet demonstrated economic but generation of electricity, the main hurdle being to supply electricity while the sun Is not shining, the maximum demand in most sunny countries being after sunset. The best established solar energy technique Is in solar water heaters which are used extensively In some other countries and have the merit of taking the electric water heating load off the system. These are being included in the Demand-Side Management options referred to in Section 2 and discussed in detail In the Mission's Report on Demand Side Management and Energy Conservation. Conclusion - Renewables 4.23 Bagasse cogeneration is the most promising form of renewable power generation at present and should be pursued as a private sector venture. Other energy forms such as wind power can be analysed in the context of updates to the LCEP as information becomes available. Solar water heating is viable and is being pursued under the Demand Side Management program (see separate report). 4-7 Table 4-1 Small Hydroelectric Schemes Installed Firm Peak Secondary*--* Capital cost***-** Cost per capacity capacity energy Energy Foreign Local Total Instfd kV Scheme Nu NU Gh GVh USS,000 USS,000 US.000 US$ Back Rio Grande 50.5 45.6 64 33 71792 32060 103852 2056 AG Upper 6.0 0.7 7 16 14552 5908 20460 3410 (incremental) Great River 8.0 0.0 0 38 7377 10360 177 7 2217 Laughtands Vteat 5.6 0.2 1.62 21.38 3241 3522 6763 1203 Rio Cobre 1.0 0.2 1.60 2.69 878 1491 2369 2369 Negro River 2 0.9 0.3 2.38 2.69 2126 1620 3746 1442 Negro River 3 1.0 0.3 2.73 2.98 2452 2078 4530 6..J yettahs River 2.6 6.6 4.99 8.27 6312 4552 10864 4131 Mild Cane River 2.5 0.8 6.37 7.47 4196 3968 8164 3319 Norgans River 2.3 0.7 5.94 6.45 3404 3175 6579 2860 Green River 1.4 0.4 3.08 3.69 2893 2087 4980 3689 Spanish River 4.6 0.5 4.16 14.67 8223 4666 12889 2814 Spanish River 4.5 0.5 4.16 8.86 6838 2027 8865 1961 (Alt 1) Rio Grande 3.9 0.5 4.00 13.03 5068 4547 9615 2491 Dry River 0.8 0.1 0.98 2.66 2841 1446 4287 5165 Nartha Bre River 5.4 0.0 0.00 22.39 8055 5116 13171 2462 Notes The capital costs exclude interest during construction Sources - Ref 13 SMECO-CIPS Back Rio Grands Draft Final Report Ref 40 Review of Smattacate Hydro Projects SECTION 5 LEAST COST EXPANSION PLAN FOR GENERATION 5.1 SWECO LCEP Report 5.01 The SWECO draft Report on the Least Cost Expansion Plan (Ref 12) was studied first In Washington and then with JPS. The Report raised a number of queries which JPS sent to Sweden prior to a visit by Mr Joran Vedin, the Study Manager for SWECO. The Report was discussed in detail with Mr Vedin and JPS during the period 19 to 23 March 1991 and a number of differences in basic parameters were Identified; these differences were referred to Sweden and have not yet been fully resolved. The Final Report from SWECO has yet to be received. 5.02 The main items discussed are summarised below: a. The SWECO capital costs were judged to be some 10% high, especially for the coal-fired station. The SWECO prices were based on the EPDC Report (Ref 33) and it was not known to what extent these prices reflected international competitive bidding or whether there may have been an element of bilateral pricing. The capital cost of the combined cycle plant seemed low relative to that used for the coal station. It was agreed to adopt the SWECO prices since the differences were within estimating accuracy, though the sensitivity studies would examine the effects of reduced prices for the coal station and increased prices for the combined cycle station. b. The SWECO operation and maintenance costs also were considered by the Mission to be high. They amounted to some 40% of fuel costs for steam plant and over 50% for low speed Diesels; these figures compare with an overall operation and maintenance cost for JPS of about 20% of fuel costs. On the other hand, the operation and maintenance for combined cycle appeared to be low at only 10% of fuel, especially in the context of the peak load operating regime of the plant. It was finally agreed with JPS that in-house modelling on WASP W would assume operation and maintenance at 75% of the SWECO figures. c. Fuel prices used by SWECO were: Heavy fuel oil (Bunker C) US$ 20/bbl Diesel Oil No 2 US$ 35/bbI Coal US$ 50 /ton These prices are slightly higher than prices adopted by the Mission (see later discussion) but are in a similar proportion to each other. 5-2 d. Unavailability was another area of discussion, the SWECO rates being thought high, based on experience elsewhere, though based on different statistics (Ref 18 and 35) as discussed In Section 3. It was agreed with JPS that, for in-house studies, SWECO figures would be used for existing plant and a lower Forced Outage Rate of 7% would be used for all new plant. e. The results of the SWECO study were questioned In two respects. Firstly, the total capacity shown in Table 5-2 Is significantly lower than the capacity required by WASP, and as a result, the reserve capacity (in excess of the mximum demand) seemed low in the later years. For example, the reserve in 2007 in the Scenario with combined cycle plant was only 89 MW, insufficient to cover the planned outage of two of the largest units on the system; SWECO agreed to investigate and explain. On the other hand, in the Scenario with a coal station, the reserve Is mostly adequate to cover 3 of the largest units on the system. The second question concerned the combined cycle plant. Its operating regime would be on peak load duty, just below the gas turbines. It is doubtful that a combined cycle plant with high efficiency and suited to run at high load factor Is appropriate for peak load duty. In particular, the efficiency will be Impaired by the starting and stopping required in peak load duty and the time required to raise steam and warm through the steam turbine. 5.03 Following the discussions with JPS and SWECO, a Note concerning questions for resolution was prepared and is attached as Annexe D. At the meeting in Washington on 25-26 April 1991 (see Annexe E), Sweco tabled some revised parameters to be used in their final report; both the draft and final parameters are given in Table 5-1. 5.2 Comparison of SWECO and WASP results 5.04 The SWECO Draft Report showed that the Least Cost Expansion Plan (LCEP) included a combined cycle plant in 1998, the balance of the plant being a mix of medium speed Diesels, low speed Diesels and gas turbines (Scenario 02).The next most economic Plan included a coal-fired steam station In 1997, again with a similar 'multi-layer sandwich'. The basic data used by SWECO Is shown in Table 5-1 and the two sequences are shown in Table 5-2. The net present values at 12% discount rate of the two sequences in the draft Report are: Scenario 01 - Coal-fired steam US$ 1403 million Scenario 02 - Combined cycle US$ 1357 million The Final Report on modifWed data give the same Scenarios but with slightly altered costs as follows: Scenario 01 - Coal-fired steam US$ 1385 million Scenario 02 - Combined cycle US$ 1351 million 5-3 5.05 The extra with coal-fired steam Is US$ 34 million, or 2.6%. If medium-speed diesels are excluded as being inappropriate and uneconomic on high vanadium fuel oil, the extra net present value of the coal Scenario reduces to US$ 29 million, or 2.1%. The two scenarios are dose, and within the accuracy of the basic investment and fael costs, particularly the fuel costs which for coal, at US$ 50/ton, are probably high. As has been mentioned earlier, the coal option (with or without dual firing of coal or oil) has the distinct (but unquantiflable) advantage of introducing diversity of fuels available to JPS and of providing some protection against the volatility of oil prices.The coal station capital costs would have to be reduced by 13% to achieve breakeven with Scenario 02. This Is close to the Missions view expressed earlier that the SWECO coal station costs were about 10% high. SWECO have also commented that their first estimates were 10% lower than finally used in the Report and that the Report figures were increased after discussion with JPS. The two Scenarios are clearly so close that it can be said that they are within the accuracy of the basic investment and fuel costs and are indistinguishable in quantifiable economic terms. The coal option is to be preferred for the reasons of diversity given above. Match of SWECO with WASP 5.06 In order to assess the comparability of the SWECO computer model and the WASP M model used by JPS for a number of years now, WASP was run using SWECO draft Report data and the results are in Table 5-2. Comparison with the SWECO plans show the reverse, i.e. WASP selects a LCEP with the coal station as the main element as soon as it is possible to put such a station into service ie in 1997. Further studies, forcing a combined cycle plant in 1993/94 show the following present values, at 12% discount rate over the study period to 2010: With coal station US$ 1280 With combined cycle in 1993/4 US$ 1330 5.07 The flgures show that coal is better than combined cycle by about US$ 50 mlion or 3.7%. Further, even with combined cycle in early, WASP still selects the coal steam station to follow even If delayed by a year. SWECO follow their combined cycle with neither coal nor more combined cycle; it might be expected that having determined that combined cycle is best for 1998, a similar plant would be repeated sometime later. 5.08 The difference between the two computer-based models has not been satisfactorily resolved. Use of WASP and discussion with ISP identified some difficulties: a. Unconventional options are a problem to model, particularly hydroelectric schemes which have a high early investment and require rather better treatment of the full range of the hydrology. Other energy sources which are spasmodic, have to be assigned a manageable but somewhat artificial loading regime. b. Early investment in projects, such as the coal station, require manual adjustments to the WASP output since WASP can only deal with such plant on a coastant cost per set. 5-4 c. The computational burden is high; the WASP runs for JSP typically take some 9 hours to run and sometimes more due to shortage of storage. d. Stratagems have to be devised to deal with multiple-unit plant such as combined cycle where the outage of one part causes a partial outage of varying magnitude. e. It is not possible to model some data which may vary with time, eg forced outage rates which may fall quickly to a mature minimum and then slowly deteriorate as the plant gets older. This limitation also makes It difficult to model the effects of rehabilitation on older plant. 5.09 There may also be shortcomings with the SWECO model, which it has not been possible to discuss. Nevertheless, it would seem that JPS should investigate alternative models to WASP, not only for improvements in the simulation and modelling methods, but also in the running time. WASP should be retained and used in parallel with any new model to provide a mutual check, especially during the first year or so of using a new model. It may even prove to be advantageous to retain WASP for certain aspects of system modelling. Conclusions from the SWECO Report 5.10 At the April meeting in Washington (Annexe H) SWECO confirmed the main conclusion that a coal station was the preferred long-term generation option and that in the short term, some 60 MW of low-speed diesels was the economic choice, to be followed by I or 2 gas turbines prior to the coal station. Other conclusions from the SWECO Report are that rehabilitation is very profitable (which is to be expected) and that Back Rio Grande hydroelectric project is not included in any of the lower cost sequences. An examination of bagasse-generated electricity from Frome sugar factory shows it to be of doubtful merit on the basis that it only saves other fuel; however, it would be possible to claim capacity benefits by operating it on peak load through the off-crop season by using fuel oil for steam generation and this option is to be examined. 5.11 Finally, the SWECO LCEP by 2000 is made up of 424 MW of new capacity in 8 different projects. These have yet to sited and the project management may prove to be a burden for JPS. Over half the new capacity will be required to replace plant due for retirement; this reinforces the comment made in Section 3 that further life extension should be closely examined as part of the Plant Audit. Indeed, the SWECO Report shows rehabilitation (and life extension) to be well worthwhile. The plant retirement programme used by SWECO is: 5-5 First Cumulative Year out MW MW Hunt's Bay No 5 Steam 1996 19 19 No 4 GT 1997 20 39 No 1 GT 1998 14 53 No 2 GT 1998 14 67 NoS OT 1998 20 87 Bogue No 3 OT 1998 22 109 Old Harbour No 1 Steam 1998 28 137 No 2 Steam 1999 57 194 No 3 Steam 2000 52 246 No 4 Steam 2002 65 311 Hunt's Bay No 6 Steam 2006 65 376 53 Preliminary ranking study 5.12 The SWECO model produced a LCEP which can only be described as a mix of almost all types of plant. In order to understand why this should be, and to gain a better understanding of the plant cost characteristics, a preliminary ranking of options has been prepared by the Mission on the basis of the costs of each option in supplying 1 kW of load growth and the associated 6307 kWh of energy, corresponding to the average load factor of 72%. The ranking is shown in Table 5-3, which is based on: -SWECO capital costs -75% of SWECO operation and maintenance -Fuel prices at constant present World Bank rates (see later) -SWECO availability except for a forced outage rate of 7% for new plant - base load plant saving energy in excess of 6307 kWh, at gas turbine rate - Peak load plant having its energy made good at base load plant. - all plant operates roughly at the margin according to its position in the order of merit in the system as it is expected to be in the late 1990s. 5.13 Table 5-3 shows that all the options are very close. If the combined cycle efficiency on peak load were to be included its costs could rise to well over US$ 400 /kW of load growth, but this would still be within the broad brush accuracy of the ranking. The steam end of a combined cycle plant is also shown as an increment to two gas turbines; the steam increment is less attracti** than the basic gas turbines. Back Rio Grande hydro project does not look to be very attractive. On the other hand, Frome (which here benefits from firm capacity) looks to be promising, bearing in mind that the figures are 'guesstimated'. 5.4 Basic data for WASP modelling 5.14 The basic data for further runs on WASP by JPS used the SWECO basic data but modified for 75% of SWECO operation and maintenance costs and 7% forced outage rate for all new 5-6 plant. In addition, the World Bank Price Prospects for Major Primary Commodities (Ref 28) was used for oil and coal price movements. The earliest dates by which future options could be in service were assessed and agreed with JPS as follows: Earliest In-service Date Year for WASP Coal/oll steam station Jan 1997 1997 Oil steam station Oct 1995 1996 Low speed Diesels Jql 1994 1994 Gas turbines Jul 1993 1993 Combined Cycle GTs Jul 1993 1993 Steam Jan 1994 1994 The earliest date for the coal/oil stetam station implies an unusually long lead-time, due to the need to complete site selection, a feasibility study and an Environmental Impact Assessment. Fuel Prices 5.15 The basic oil prices at 1990 price levels were assessed from product import prices as part of the work of the Mission in the petroleum sector. These were adjusted for delivery to the power stations and referred to 1991; these 1991 prices are: US$/bbl Auto Diesel ol CIP 31.32 Terminal 0.95 Local transport Hunt's Bay 1.15 Bogue 2.04 Total Hunt,s Bay 33.42 Bogue 34.31 Heavy fuel oil CIF 16.53 Terminal 0.83 Local Transport Hunt's Bay 0.42 Old Harbour 1.24 Rockfort 0.91 Total Hunt's Bay 17.77 Old Harbour 18.59 Rockfot 18.26 5-7 Local transportation and terminalling costs were derived from Petrojam information. 5.16 The price of coal sourced from the USA is given In the Commodity Prices Report (Ref 28) as US$ 44/ton for 1991. A check on this price was obtained from the Caribbean Cement Co who have been paying about US$ 50/ton for coal sourced from USA, mixed with petroleum coke, delivered in 20,000 ton carriers and for a usage of about 80,000 ton/year. Further, the coal is bought from the parent company, Skancem, and it is not known to what extent international competition was used. On this basis, a price of about US$ 45/ton for a coal-fired station using some 800,000 tons per year delivered in 30,000 ton carriers seems to be reasonable, and may be even high. A basic price in 1990 of US$ 45.4/ton was in fact used, being a price obtained in Jamaica by another Mission. A check price in early 1990 is for Colombian coal delivered to Lima for US$ 45/ton. 5.17 The real relative escalation of oil and coal was derived from the Commodity Prices Report using the forecasts in current $ terms deflated by the Manufacturing Unit Value Index for the Group of 5 countries. The derivation of the relative escalation is given in Table 5-4, which applies the escalation only to the FOB part, freight at about US$ 5/ton being kept constant. The corresponding changes to the various fuel prices at the power stations are derived as part of the Petroleum Sector Mission Report but are included in Table 5-4 for completeness 5.18 Table 5-4 shows that oil is expected to benefit from price reductions in the next few years while coal will slowly escalate. By 2005, the index for coal is 1.099 compared with 0.977 for oil. Overall coal Is put at a disadvantage of approximately 10% throughout the period from 1997. It seems difficult to believe that coal will not respond, even if only to retain its market share and that a more likely outcome is that coal will match oil and remove any change In the differential. One of the sensitivity tests will be to assume that coal escalates in the same way as oil. The relative escalation factors for the individual fuels and stations are also given in Table 5-4. They were calculated at an earlier date and do not precisely match the crude oil and coal indices, but the differences are of minor importance. 5.5 Results of WASP II modelling 5.19 Having made attempts to resolve and explain the differences between the SWECO and WASP 'black box' models, it was agreed to continue to use WASP as a consistent basis for further modelling and sensitivity studies. The first base run was to model the system on the data described in paragraphs 5.14 to 5.18 above and the Base load forecast by SWECO given in the left hand side of Table 2-1A. The second run was to use the same data except for the load forecast which takes account of loss reduction and DSM measures, as in the right hand side of Table2-lA. This will allow the avoided costs of the loss reduction and DSM to be assessed and also act as a sensitivity study on the load forecast. This second run is then used as a base plan for further sensitivity analyses. The runs performed on WASP are summarised as follows: S-8 Base 1 SWECO load forecast, modified data, World Bank fuel prices. Base 2 As Base 1 but with load forecast reduced by loss reduction and DSM measures. Base 2A Coal price profile same as for oil. Base 2B Effect of 10% cLange in capital cost of the coal steam station. Base 2C Assume no new capacity possible before 1994 Base 2D Force combined cycle plant into the programme to indicate the economics of combined cycle. Base 2E Effect of 10% change in the capital cost of combined cycle plant. Base 2F Rehabilitate say Old Harbour No 2 for US$ 5 million in 1997 and retire 5 years later, to examine the benefits or life extension. 5.20 The results of the above runs on WASP are recorded in Annexe F. The conclusions to be drawn are: Base 1 The results in Table F-I confirm that WASP selects the coal steam station as the main energy source after its earliest in-service date of 1997. It is notable that low speed Diesels are selected from 2006 and the reason is that, since all the assumed retirements have been effected by then, new plant meets only load growth which is about 18 MW per year which requires some 23 MW per year of new capacity. The 20 MW unit size of the Diesels matches this rate of load growth much better than 61 MW steam sets which leads to the conclusion that the size of the coal-fired steam units may be too large and thata smaller unit size, say 30 MW, should be examined. This confirms the suggestion made in para 4.04. Base 2 The effect of the reduced load forecast in Table F-2 is to reduce the need for new capacity, the reduction by 2010 being from 747 MW to 625 MW. The coal-fired station is again selected, but only for 6 (instead of 8) 61 MW sets. The preference after 2005 is again for Diesels; the rate of load growth is even lower, at 16 MW per year, than Base 1. This reinforces the need to examine a smaller unit size for the coal-fired station. The net present value of Base 2 Is US$ 1,001 million. Base 2A Table F-3 shows that making the future coal price profile the same as for oil, on the likely basis that coal will tend to match oil price movements, reduces the net 5-9 4 present value but does not change the planting programme and, In particular, the capacity and timing of the coal station units is unchanged. This coal price profile reduces the net present value of this least cost expansion programme by US$ 8 million from the Base 2 value of US$1,001 million to the Base 2A value of US$ 993 million. A more extreme sensitivity study has been made In which the coal price is increased from US$ 43.8 to US$ 50 per ton and retaining the price profile in Base 2. This reduces the coal capacity from 366 MW to 305 MW with a corresponding increase in low speed Diesels; the coal station is delayed by one year to 1998. These sensitivity studies show that the requirement for a coal station in 1997 is robust to reasonable changes in coal prices. Base 2B Table F-4 shows that a 10% Increase in the capital cost of the coal station reduces the coal station capacity from 366 MW to 305 MW and delays it by one year to 1998; in fact, the programme and net present value are virtually the same as for an increase in coal price from US$43.8 to US$50 per ton, as referred to above. A 20 % increase in the capital cost of the coal station eliminates it from the programme entirely and replaces it with 24 low speed Diesel sets; neither more gas turbines nor combined cycle plant are included. These two capital cost Increases are both extreme in the context of the comments In para 5.02 and Annexe D that the basic coal station capital costs were high and hence the most appropriate sensitivity test is to reduce the coal station capital costs by, say, 10%. The effect of this reduction would be to reduce the net present value of Base 2 by about US$ 16 million. Taking this capital cost reduction and combining it with the common fuel price profile in Base 2A, gives the Missions view of the most likely outc6me; the result is an overall reduction of the net present value to about US$ 971 million. Base 2C The least costs expansion programme in Base 2 includes a gas turbine in 1993 followed by 2 low speed Diesels and a further gas turbine in 1996 prior to the coal station in 1997. The need for the first gas turbine has been examined more closely in Base 2C in Table F-5 which asumes no plant is Installed before 1994. The effect on the plant programme is to put in 3 low speed Diesels in 1994 and 1995 with a single gas turbine in 1996 prior to the coal station. The overall programme is reduced by one 33 MW gas turbine; the programme for the coal plant is unaffected. The net present value is hardly changed, being US$ 250,000 higher in US$ 1000 million, is only 0.025% higher than Base 2. The LOLP In 1993 is nearly double the maximum allowed in the studies and ,as a consequence, the value of the energy not served rises to US$ 2 million in that year, though this' is included in the above present values. At the April meetings in Washington, a view was given that the delivery times for gas turbines had increased and it was probable that low speed Diesels could be procured nearly as quickly. Since the gas turbine in 1993 no longer has priority on the grounds of lead time, it can be inferred that it should be replaced by low-speed Diesels as in Table F-5. This Is 5-10 confirmed by a WASP run which removes timing restraints and selects a programme of I low-speed Diesel in ach of 1993, 1994 and 1995 follwed by a gas turbine in 1996 prior to the coal station. The not present value of this sequence is US$ 987.8 million, some US$ 3 million less than Base 2 It is clear that no new capacity can be in service for the beginning of 1993 but it is possible that low speed Diesels could be in service towards the end of the year when the maximum demand will be highest. Base 2D Table P4 shows the effect of Introducing a combined cycle plant, the gas turbines in 1993 and the steam turbine in 1994. Comparing the net present value of US$ 1,030 million with that of US$ 1,001 million for the Base 2 programme shows the combined cycle to be about 3% worse. The coal-fired steam station is selected to follow the combined cycle plant, though one year later is In 1988. This margin of 3% might be considered to be within the estimating accuracy of the study and this would be a valid comment if the basic costs were reckoned to be the average expectation. However, comment has been made that the capital costs of the coal station are thought to be high and the coal price profile also is high. If these two aspects are taken into account, as in Base 2A and 2B above, the net present value will reduce by US$ 15 million in respect of the reduction in coal station capital cost and by about US$ 10 million in respect of coal price profile giving a new net present value of US$ 106 million. This is US$ 35 million more than the corresponding present value for Base 2A plus 2B of US$ 971 million, an extra of 3.6%. The likely direction of capital costs and coal prices thus worsens the combined cycle option. All the above sensitivity studies, including the extreme ones adverse to coal, do not bring in combined cycle, but rather bring in increased capacity of low speed Diesel plant. Base 2E The effect of a 10% iacrease'in cost of a combined cycle plant will be to make it less likely to be selected as part of the least cost expansion plan. The not present value in Table F-6 would Increase by some US$ 6 million making it US$ 35 million worse than Base 2. This differential is similar to that derived above in the discussion on Base 2D. Bae 2F Table P-7 shows the effect, as an example, of retiring Old Harbour No 2 Unit in 2004, 5 years later than in Base 2. The final new plant additions are unchanged, but the coal station Is developed rather more slowly, with one unit less in each year to 2004. The not present value US$ 2 million less than Base 2, but this is before including any expenditure on further rehabilitation or life extension measures. Such measures would need to be Incurred about 1998 for which the present value factor is 0.42; the maximum expenditure an rehabilitation is thus about US$ S million for breakeven. It thus seems that further expenditure on rehabilitation is unlikely to be as attractive as the current rehabilitation is shown to be by SWECO. The difference may be due to the fact that the later S-11 rehabilitation has a greater effect on the coal station programme and its thel savings than does the current rehabilitation. Ensuring adequate maintenance resources, as mentioned in Section 3, may well be a more economic way of achieving life extension of some of the existing plant and could lead to increased savings not only by helping to achieve life extensions but also by improving availability of the existing plant. 5. Conclusions from LCEP studies 5.21 The following conclusions can be drawn from the SWECO and WASP studies: a. The proposed coal-fired station at Salt River is the preferred long-term generation source. This is a fairly robust economic conclusion from the WASP modelling. The SWECO studies are less positive in their outcome but the added advantages of the coal station as introducing diversity of fhels and giving protection against the volatility of oil prices, are seen to make the coal station the preferred long term option. b. The most economic short term programme Is 3 - 20 MW low speed Diesel generators in 1993, 1994,and 1995, on the basis of the forecast reduced by loss reduction and DSM measures. This is also the economic sequence for the Base SWECO forecast without reduction, except that the first two units are required in 1993. Since there Is some doubt about the speed with which DSM will be introduced and about the basic rate of load growth, it will be prudent to place in service the first two low-speed Diesels as early in 1993 as possible, with the third unit to be in service in 1994 or 1995, in accordance with annual reviews of load growth and progress with introducing DSM. c. The need for gas turbines In 1995 and or 1996 can be reviewed annually. d. Preparations for the 3 x 20 MW Diesels should proceed on an urgent basis in respect of site selection, environmental impact assessment and procurement under Build-Own Operate contract. e. Preparations for the coal station should proceed on an equally urgent basis in respect of site investigations to confirm the site, environmental impact assessment, and a Feasibility Report to finalise the station design with particular reference to layout, harbour facilities, type of boiler, provision for fuels other than coal, ash disposal etc. f. Emphasis on improving maintenance resources will assist and reinforce rehabilitation with benefits in life extension and in improved availability. The extent of life extension measures will be indicated by the forthcoming Plant Audit. 5-12 5.7 Avoided costs of loss reduction and Demand-Side Management 5.22 Reference has been made in para 2.16 to the benefits to JPS of loss reduction and DSM measures. These benefits can be quantified by comparing Base I with Base 2, the reduction in costs in Base 2 arising directly from the reduction in load forecast due to loss reduction and DSM measures. The calculations are given in Table 5-6. The reduction In the forecast energy demand used by WASP differs slightly from that In Table 2-IA because of need to limit the number of descriptions of the load curve; the differences are small and the present value of the energy reduction in Table 2-1A is 1945 GWh compared with 1941 OWh in WASP, an Insignificant difference. The calculations derive the average (or levelised) specific cost savings (per kW and per kWh) arising from the reductions In load: Sum of (present value of load reduction X cost per unit load reduction) must equal Sum of (present value of cost reductions) Hence: Cost per unit load reduction equals: Sum of (present value of cost reductions) Sum of (present value of load reductions) The calculations in Table 5-6 are made separately for maximum demand (kW) and energy (kWh) using the appropriate costs relating to each. noB resulting rates averaged over the entire period to 2010 are: US$ 150 per kW-year plus 3.0 US cents per kWh 5.23 Reference to Table 5-6 shows that the avoided cost of energy varies significantly from year to year and particularly over two periods; from 1991 to 1997 the rate averages about 4.5 cents per kWh and thereafter it averages about 2.5 cents per kWh. This is the consequence of the introduction of the coal-fired station and arises because the load reductions delay the benefits of the coal station and hence reduce the energy savings. A further variation is that occurring from hour to hour which can be roughly assessed by assuming that savings are at the gas turbine rate for some 4 hours per day at time of peak load with lower rates at other times of the day. 5-13 5.24 Investment costs will also be avoided in the transmission and distribution system. Baglar/Builly (Ref 1) derive these costs separately for the RV, MV and LV systems and they add some 25-50% to the generation capacity costs. 5.25 The long term average avoided costs in 5.21 can thus be elaborated as follows: HV System US$ 157/kW-year sent out MV System US$ 175/kW-year sent out LV System US$ 200/kW-year sent out up to 1997: On-peak energy 7 US cents/kWh sent out Off-peak energy 4 US cents/kWh sent out 1998 and after. On-peak energy 6 US cents /kWh sent out Off-peak energy 1.8 US cents/kWh sent out The above avoided costs could probably be refined even further but would require a much more detailed study. Such a study could be worth undertaklng if the Individual characteristics of the various DSM measures show avoided capacity and energy In different piterns to the simple off- and on-peak used above. All the above figures relate to the capacity and energy sent out from the power stations. Avoided demand and energy In the HV, MV, or LV systems must be referred to the sent out basis by addng losses of about 1%, 2% and 8% respectively. The above avoided costs will be compared in further DSM work with the costs to JPS and its consumers of Implementing DSM and energy efficiency measures. 5.8 Hydroelectric schemes 5.26 Of the hydroelectric schemes listed in Table 4-1, only Back Rio Grande was included In the variable options in the WASP modelling and that scheme was not selected. The schemes are re- examined In Table 5-5 on the basis of valuing their output (benefits) at the following rates: Firm capacity at the approximate average rate for the plant mix to be installed over the next 20 years of US$ 1200/kW. Firm, peak, energy at the rate for gas turbines, both fuel and variable operation and maintenance of US$ 0.083/kWh. Secondary energy at the rate for base load plant taken as the mean of low speed Diesels and coal-fired steam plant Ie US$ 0.031 covering fuel and variable operation and maintenance. 5-14 A discount rate of 12%. Interest during construction at the discount rate on average for half the estimated construction period. Table 5-5 shows none of the schemes, achieve a benefit cost ratio greater than unity but that Back Rio Grande and Laughlands Great give the highest ratios at 0.79 and 0.86 respectively. If the discount rate is reduced to 10%, these two schemes have benefit/cost ratios close to unity. 5.27 Refirence has been made earlier to the deficiencies of WASP in dealing with hydroelectric schemes. In the case of hydro schemes in Jamaica, the main difficulty Is thought to be modelling the secondary energy which is spasmodic and unpredictable in occurrence. Nevertheless, Table 5-5 indicates that Back Rio Grande (without the Upper Scheme) and Laughlands Great are not attractive and should not be implemented, unless shadow pricing has sufficient impact to bring their benefit cost ratios up above unity. In this context, the hydro schemes will reduce the carbon dioxide released into the atmosphere. For example, Back Rio Grande will produce about 97 GWh/year, which will directly reduce the burning of some 43,000 tons of coal or its equivalent and reduce Carbon dioxide release by some 90,000 tons per year. This may be an attractive aspect to some lenders and may attract soft finance. It is recommended that JPS consider seeking soft finance for one or other of the schemes, provided that soft finance does not prevent support being denied to some other, more economic project. 5-15 TABLE 5*1 SWARY OF DATA FOR SWECD LEAST COST EXPANSION (PLAN Units CapitaL Specific Operat'nsintoce Oil Coat Forced Scheduled and size cost cost Fixed Variable price price outage outages Plant NW US$,mitnUSS/kU USS/year USS/NA USS/bbt USS/ton rate,% Days/year OLd Harbour No 1-stem 28 280000 8 20 15 40 No 2-steam 58 280000 8 20 10 40 No 3-steam 52 280000 8 20 10 40 No 4-steam 66 280000 8 20 10 40 munt's Bay No 5-steam 20 280000 8 20 15 40 No 6-steam 66 280000 8 20 10 40 BT-I 14 120000 2.5 35 15 21 GT-2 14 120000 2.5 35 15 21 GT*4 20 120000 2.5 35 10 21 GT*5 20 120000 2.5 35 10 21 GT-3 20 120000 2.5 35 10 21 CT-6 18 80000 4 35 5 21 AT*? 18 80000 4 35 5 21 T*8 18 80000 4 35 5 21 GT*9 18 80000 4 35 5 21 Rockfort Dieset-I 20 200000 8 20 8 10 Ofeset 2 20 200000 8 20 8 10 New Plant Coal stem 6 x 61 542 1481 1600000 6.7(8.6) 50 8(10) 40 Oil steam 65 60 923 300000 5 20 500) 40 Gas turbine 33 20 606 100000 5 35 5 21 Ned speed Diesel 3 x 12 38 1056 600000 16(17) 20 10 30 Low speed Dieset 2 x 20 56 1400 400000 13(16) 20 8 20 Combined cycle 100 79 790 300000 4.7 35 10 30 Figures in brackets refer to the Draft SWECO Report 5-16 TABLE 5•2 IEAST C=0T EMPANSION PLANS Cø SECO DATA AP III «mC0 SECO en SWECO ver Scenarlo 02 NU Sconrio 01 NU Data m 1992 MSDst 36 m st 36 NS Dst 24 1993 S D[l 24 1994 S Dst 24 1995 L$ Det 40 L Det 40 "S Ds 24 1996 GT 33 GT 33 GT 33 1997 SaOt 36 L$ ft0 40 Coat 61 1998 Cmbi - 100 Coat 61 Coat*+T 94 1999 GT.LS Ost 73 GT+Coat 94 CoetGT 94 2000 L^+N8 Det 106 Coat 61 Coat 61 2001 LU Dst 40 Coat 61 2002 LW ost 80 Coat 61 Coat 61 2005 2004 S Dst 36 "S st 36 GT 33 2005 2006 t.~8 ost 76 Kg OstCoat 97 Coat 122 2007 NS Dst 36 2008 LSOst 40 mS Dst 12 2009 aS ost 36 MOst 36 L$ Dst 20 2010 RS Ost 12 Total 692 671 760 Mots S Ost mediæs peedøieset LU Det Lou speed Dieset GT Gas trbIne Coat Duta-f fred (coat and olt) stem plant Cahi Caind cycte (gas and steam turbinu) ediun speed diesets are not retlab4 on Jamaican heevy fuet .11 and milt be reptaced by low speed Dlesets The coat station will bum coat and /or heavy fuel oft Diese s il burn heavy fuet ot Oas tubines and coéined cycle plant wilt onty burm Dieset oft No 2. 5-17 TAL8 5-3 PRELINIMARY RANKING OF OPTIONS Stea. Fuct pricc Ste Stea Lo Addition Beck Rio UFO US$/bbt 18 Coat Oi speod C~ined Gas to Ges Grande Fromc 00 Uf$/bbt 33.4 Station Station Dieset eyece turbines turbines Nain Suger Coat Utk/te 45.4 .•• .. .. . ---- ••••..- ....... ... .--- Interest Z/year 12 Capacity sent out KW 372 58 40 102 33 34 45.6 15 Investment US~5it 542 59.5 56 90 20 50 103.8 15 Specific sent out cost US9/11k 1457 1026 1400 882 606 1411 2276 1000 Working ife Years 35 35 25 25 25 25 50 25 Construction period Years 3 2 2 2.2 1.3 2.2 2.5 2 IDC rate /yar 12 12 12 12 12 12 12 12 Total specific cost USM/kW 1719 1149 1568 999 653 1665 2618 1120 Heat rate Stu/kh 11370 11300 8530 8400 12600 0 Fuct price U/te 45.4 US*/bt 18 18 33.4 33.4 USS/NStu 1.790 3.020 3.020 5.910 5.910 3.238 Ust/km 0.0204 0.0341 0.0258 0.0496 0.0745 0.04 Fixed operation USS/kW-yr 1.61 5.17 10 3 3.03 3 13.5 5 Variebe operation USS/kM 0.007 0.004 0.0095 0.004 0.005 0.005 0.001 0.005 Lod/total capmcity 6 80 80 80 80 80 80 Avaitability Forced 7 7 7 7 7 7 2 5 Ptannd 6 11 11 5.5 8.2 5.7 11 0 10 Totat x 17 17 12 15 12 17 2 15 Firm output kW/k 0.8277 0.8277 0.87885 0.85374 0.87699 0.8277 0.98 0.855 Investuent for ikU of toad USS/kV 2077 1388 1784 1170 745 2011 2671 1310 Annuwl coste of metin lkm of lad and 6307km of energy Generation at station k% 7251 7251 7699 2500 1500 2500 2171 3002 Make-up generation kU .944 .944 -1392 3807 4807 3807 4136 3305 Fuel at station Um% 148 247 198 124 112 149 0 26 Make-up fuet 118$ .70 .70 .104 98 124 111 107 164 Operatfon at station USm 52 34 83 13 11 11 16 20 Mke-up operation Us$ .5 .5 .7 36 46 41 39 13 Investment amuity US$ 254 170 227 149 95 256 322 167 TOTAL Ut$ 379 376 398 420 387 568 483 391 5-18 TABLE 5*4 REAL RELATIVE ESCALATION OF FUEL OIL AM COAL PRICES Crude Crude oil, FB oit Coat FOB USS/ton Jamica ----Fuel oi price indices at power statos---- IGN *................ret ee * * **.....................Ee foe on Hunt's Bay Old NarboRockfort Bogue Year efalator Current WA-1990 factor Current XN-1990 Esc Fae *45.4Iton Heavy DieseL Heavy eavy Oeasel .................................................... 1985 100.00 1986 117.91 1987 129.51 1986 138.94 1989 138.49 1990 147.17 21.60 21.60 0.989 42.00 42.000 1.041 1.036 1991 160.48 23.80 21.83 1.000 44.00 40.351 1.000 1.000 1.00 1.00 1.00 1.00 1.00 1992 162.30 20.50 18.59 0.852 43.00 38.991 0.966 0.970 0.86 0.86 0.87 0.86 0.86 1993 161.62 18.50 16.85 0.772 44.00 40.066 0.993 0.994 0.78 0.77 0.79 0.78 0.78 1994 164.26 19.60 17.56 0.804 44.00 39.422 0.977 0.980 0.80 0.80 0.81 0.81 0.80 1995 170.43 20.90 18.05 0.827 47.00 40.586 1.006 1.005 0.83 0.83 0.84 0.84 0.83 1996 177.29 22.96 19.06 0.867 49.80 41.339 1.025 1.022 0.87 0.87 0.88 0.88 0.8? 1997 185.65 25.02 19.83 0.907 52.60 41.698 1.033 1.030 0.91 0.91 0.92 0.91 0.91 1998 191.68 27.08 20.79 0.947 55.40 42.536 1.054 1.048 0.95 0.95 0.96 0.95 0.95 1999 198.26 29.14 21.63 0.967 58.20 43.202 1.071 1.063 1.00 0.99 1.00 1.00 1.00 2000 204.88 31.20 22.41 1.027 61.00 43.818 1.086 1.076 1.04 1.04 1.04 1.04 1.04 2001 213.16 32.10 22.16 1.017 63.80 44.049 1.092 1.082 1.03 1.03 1.03 1.03 1.03 200 221.44 33.00 21.93 1.007 66.60 44.263 1.097 1.086 1.02 1.02 1.02 1.02 1.02 2003 229.72 33.90 21.72 0.997 69.40 44.461 1.102 1.091 1.02 1.01 1.02 1.02 1.01 2004 238.00 34.80 21.52 0.987 72.20 44.646 1.106 1.095 1.01 1.01 1.01 1.01 1.01 2005 246.28 35.70 21.33 0.977 75.00 44.818 1.111 1.099 1.00 1.00 1.00 1.00 1.00 2006 246.28 35.70 21.33 0.977 75.00 44.818 1.111 1.099 1.01 1.00 1.01 1.01 1.00 2007 246.28 35.70 21.33 0.977 75.00 44.818 1.111 1.099 1.01 1.01 1.01 1.01 1.01 2008 246.28 35.70 21.33 0.97? 75.00 44.818 1.111 1.099 1.02 1.01 1.02 1.02 1.01 2009 246.28 35.70 21.33 0.977 75.00 44.818 1.111 1.099 1.02 1.02 1.02 1.02 1.02 2010 246.28 35.70 21.33 0.977 75.00 44.818 1.111 1.099 1.03 1.03 1.03 1.03 1.03 Source: orld Sank Comuodity Price Forecast, Noveser 991, Mission Estimates. 5-19 Table 5.5 smil W~ydroectrie 8hmes Instatled Firm Peak Sbondary•.••. Capital cost ..---.- .•-. •neits-•..••••• Total Benefit capaclty capbWity onergy Inergy Foreign Local Total Fir M Pek Sfh SePdy hBenefits Cost 8chems N N Blh Gi US8,00 US8,000 U.000 U88,000 U88,000 ,88,000 U38,000 Ratio ack Rio Srande 50.5 45.6 64 33 71792 32060 103852 54720 44113 8496 107329 0.79 mRl Upper 6.0 0.7 7 16 14552 5908 20460 840 4825 4119 9784 0.41 (incrumntal) Sremt River 8.0 0.0 0 38 7377 10360 17737 0 0 9868 9868 0.47 ~Laubhends Great 5.6 0.2 1.62 21.38 3241 3522 6763 240 1119 5503 6862 0.86 Rio Cobre 1.0 0.2 1.60 2.69 878 1491 2369 228 1101 693 2022 0.72 Negro River 2 0.9 0.3 2.38 2.69 2126 1620 3746 348 1640 693 2681 0.61 egro kiver 3 1.0 0.3 2.73 2.98 2452 2078 4530 39 1882 767 3045 0.57 attlahm River 2.6 0.6 4.99 8.27 6312 4552 10864 720 3442 2128 6290 0.49 Uitd Cum River 2.5 0.8 6.37 7.47 4196 3968 8164 924 4388 1924 7236 0.75 Norgans River 2.3 0.7 5.94 6.45 3404 3175 6579 11 4096 1660 5767 0.74 Gren River 1.4 0.4 3.08 3.69 2893 2087 4980 444 2122 950 3516 0.60 pnish River 4.6 0.5 4.16 14.67 8223 4666 12889 600 2868 3776 7244 0.48 pmnish aiver 4.5 0.5 4.16 8.86 6838 2027 8865 600 2868 2281 5749 0.55 (Att 1) Rio Grande 3.9 0.5 4.00 13.03 5068 4547 9615 576 2754 3353 6683 0.59 Dry River 0.8 0.1 0.98 2.66 2841 1446 4287 144 677 684 1505 0.30 Marthe gre River 5.4 0.0 0.00 22.39 8055 5116 13171 0 0 5764 5764 0.37 Avoidød cost of fir. capacity, U~8/kW 1200 Fet cp 8 Ne Total Avoided cost of pak energy, US/kWh 0.078 0.005 0.083 Avolded cost of secondary energy, UO/kih 0.025 0.006 0.031 0iscount ratc,% 0.12 Interest during construction at discount rate for hatf the constrution period 5-20 TABLE 5-6 AVOIDED COST OF LOSS REDUCTION AN0 DENAN-0SIDE MANAGENENT ••..-R~tion in Load---- Avolded Present Teble2-IA '-Present value.- ---Rduction In PV of cash fLous..• cost of vatue ad WASP Tabte2-1A WASP of WASP reduction Investøetla valu~0perationTotaL mnergy Year lator N 1dh OUh 0U 41K US.000 US$,000 US$,000 USM,000 Cents/klM 1991 0.936 0 0 0 0 0 0 0 0 0 0.00 1992 0.836 7 31 37 6 31 0 0 1984 1984 6.41 1995 0.746 16 79 69 12 52 0 0 2484 2484 4.82 1994 0.667 27 135 119 18 79 19930 -1839 1882 19973 2.37 1995 0.595 43 218 222 26 132 0 0 6113 6113 4.63 1996 0.531 53 260 253 28 134 0 0 6557 6557 4.88 1997 0.474 60 304 298 28 141 0 0 6630 6630 4.69 1998 0.424 68 341 344 29 146 36105 .7738 3288 31655 2.26 1999 0.378 73 375 377 28 143 0 0 3635 3635 2.55 2000 0.338 78 401 403 26 136 0 0 3754 3754 2.76 2001 0.301 82 425 428 25 129 .2575 720 4027 2172 3.12 2002 0.269 85 446 453 23 122 0 0 4008 400 3.29 2003 0.240 87 460 465 21 112 19058 .7610 2026 13474 1.81 2064 0.215 91 484 490 20 105 0 0 1911 1911 1.82 2005 0.192 94 502 509 18 98 •5729 2726 2349 •654 2.41 2006 0.171 97 518 526 17 90 3420 -1898 2239 3761 2.49 2007 0.153 99 535 543 15 83 4567 -2799 1742 3510 2.10 2008 0.136 101 546 554 14 76 0 0 1588 1588 2.10 2009 0.122 103 567 571 13 70 0 0 1534 1534 2.21 2010 0.109 105 582 588 11 64 .689 616 1519 1446 2.38 TotaL 376 1941 74087 .17822 59270 115535 3.05 PV of inwestmnt cost 74087 ,$, 000 Less PY of salvage value -17822 USS,000 PV of Net Investment 56265 U$$,000 PV of reduction In max demand 376 mU Avolded cost of reduced mx demand 150 US$ per kUyear PV of operating costs and energy unserved 59270 US$,000 PV of reduction In onergy 1941 G&h Avoided cost of redued energy 3.1 USS cmnts per kWh Surce: Tables F-1 and F-2 Note that operating costs Include the cost of nrgy unserved. SECTION 6 PRIVATE SECTOR PARTICIPATION 6.1 Reasons for private sector participation 6.01 A prime reason for privatisation or public sector participation in electricity supply is to encourage private financing for the electricity supply system and relieve the financing burden on the utility (JPS) and the Government. It is, however, useful to look at other reasons which may have applied In other countries, (though this does not pretend to be a thorough examination of such reasons). In the UK, further reasons for privatisation were to introduce a measure of competition into the business, to open the previous organisations to commercial realities, and to change the 'culture' of the previous organisations. The operation of the nationalised supply industries had allowed a large measure of overstaffing which on its own may not have been of significant cost but which resulted in substantial over-design, and interference, with design changes throughout the contractors' own design and construction. The result was extended delays and substantial increases in final cost. It is possible that similar reasons may apply in other countries though the introduction of private finance is probably the driving force for private sector participation. 6.02 The situation in Jamaica in respect of finance still stands. However, the other reasons do not stand. JPS is not over-staffed; indeed it appears to be under staffed both in total and in experience. The need is for more staff and more training and experience, the latter unfortunately taking time. It will be important to JPS to take into account the possible effects of private power stations, particularly on their own staffing. Salaries and wages at private power stations may well be higher than in JPS with consequent loss of staff and problems in operating their own power stations. JPS may in due course lose the staffing ability to own and operate power stations. JPS must be careful not to allow the construction of power stations which are not in the interest of the lowest cost system, eg by allowing gas turbine stations to be built when the system needs a source of cheap base load energy. 6.03 There is often a claim that private participation increases competition and hence keeps down prices; this is not necessarily so. With conventional procurement by the utility, international competitive bidding will ensure competition and in recent years has resulted in some low prices from work-hungry contractors. With a privately-owned power station, the competition is between Build-Own- Operate companies and they may not be very numerous, especially for the first private station in the country. The BOO companies may themselves invite competitive bids for the construction but they may also have close ties with major manufacturers with consequently restricted competition. It would be prudent to investigate the gree of competition realised in BOO projects in other countries. 6-2 6.2 Techical aspects 6.04 There are no serious technical reasons why privately owned power stations cannot be successful provided that certain design and safety aspects are carefully controlled, for example: - control, synchronising and protection arrangements should be such as to eliminate any risk of faults at the private station causing damage or threatening the safety on the rest of the system. -governor response and performance should be consistent with the rest of the generating plant, and indeed should be specified by JPS. -the characteristics of the generators, and transformers (short circuit ratios, and reactances) and automatic voltage controllers should be consistent with the overall system design. -in general, all aspects which affect the Interface between the station and the system and all aspects which affect the design and operation of the system should be specified by JPS or at least should be checked for acceptability. 6.05 It is most important that JPS should thoroughly examine the design of all proposals for private power stations to ensure that the private proposals are technically sound and meet the environmental standards. It would be unwise to assume that the private owner will provide the type and design of plant required by the system and that the plant can continue to operate satisfactorily throughout Its life. Failure of the plant to give reliable supplies, even if at the owners cost, will not absolve JPS from being responsible for any consequential load shedding, especially in the eyes of the public. Similarly, failure to meet environmental standards may cause the station to be shut down until the failure is remedied, again with risk of load shedding. Finally, it would not be in JPS interest to have to take over an inferior station in the event (albeit unlikely) of the owner withdrawing, whatever the penalties. 63 Contractual matters 6.06 It is desirable for JPS to invite proposals for private stations only of the type which is appropriate to the Least Cost Expansion Programme. An open bidding for any type of plant would in theory be possible; it would, however, be difficult to adjudicate since it will be necessary to introduce financial adjustments to allow not only for the different operating regimes of the different types of plant that may be offered, but also for the different operating regimes for all the remaining plant on the system. Such open bidding would have to face up to the possibility of the adjustments being challenged by some bidders. Ideally these adjustments should be made known beforehand to the bidders so that they can take them into account and probably avoid offering plant which does not fit the system requirements at the time. Open bidding without declaring the adjustments for type of plant would be unfair to proposets and inhibit future participation. JPS should certainly be wary of any offer which is not in accordance with the LCEP at the time. 6-3 6.07 The 'type' of station can be defined by Its required duty, e.g. base load or peak load, or It can be defined more closely by type of plant and fuel. For example, the need for base load plant could be met by medium-speed or low-speed diesels or by coal-fired steam plant, and BOO tenders for all three could be considered. If, however, government wishes Jamaica to benefit from diversification of fuels, it may be necessary to specify the fuels, e.g. coal and orimulsion, together with the appropriate plant and emission abatement. Without such specification, BOO tenderers may well confine themselves to the cheapest first cost option, for example, a steam station using conventional boilers burning low-sulphur coal and without sulphur removal, or even medium-speed diesels which are thought to be technically unsuitable in the context of fuels available in Jamaica. There will always be a tendency for BOO tenderers to offer the option with the lowest first cost, and the strength of this tendency will have to be assessed on each occasion, to decide the degree to which the new plant should be specified by JPS. 6.08 The contract terms for purchasing the output of a private power station will require special and careful attention to protect JPS from poor availability and to ensure that the cost of energy reflects the best fuel prices. The rates should not be on a take-or-pay basis; they should give JPS the scope to schedule generation in accordance with the order of merit and so miamise system operating costs. JPS should be wary of any attempt by the private station owner to distort prices so that they do not reflect costs, for example to reduce the price for energy at the expense of increasing capacity charges; this may well lead to trouble later on when the owner may wish to renegotiate when he meets problems. 6.09 There may be special problems in respect of the coal-fired station. Tbe distinct advantage of the coalloll station is the ability to buy the cheapest fuel on the market at the time. The contract will have to define how this advantage (some or perhaps all of it) will be passed on to JPS and the ultimate consumers. Perhaps more important, the contract must ensure that the effort is made to buy the cheapest fuel available. This responsibility could be put on the owner's shoulders but he will no doubt require an incentive; it could be that JPS purchase the fuel and supply it free of charge to the owner who would simply base his energy pricing on the operation and maintenance costs; if the owner purchases the fuel, his energy rate could be linked to some coal and oil indices, the lowest index ruling; there may well be other ways of ensuring that the consumer benefits from getting the lowest priced fuel. The matter may be further complicated if Orimulsion proves to be a third contender as the fuel for a private coal/oil station. 6.10 The coal/oil station is a long term project which will meet the bulk of the base load energy requirements for many years to come. It is not known to what extent a private power station owner may wish to be committed to developing such a project over perhaps 10 years. His involvement in the early large investment in the harbour and site development amy ecourage him to take a long term Interest, on the other hand he may consider it too great a risk. The long term commitment will be an Important part of any contract and JPS should endeavour to get appropriate flexibility and protection against the owner wishing to withdraw, or at least not to continue with the development of the site. 6-4 6.11 fa proposal were made for a plant that was not close to the LCEP, JP should again satisfy itself that the plant was appropriate and soundly costed and designed; JPS should be suspicious of any proposal which departed significantly from the LCEP since such a proposal would have to better the LCEP and in order to do so may well have been designed to a price and hence be technically Inferior to what Is really required. SECTION 7 ENVIRONMENTAL ASPECTS 7.1 General 7.01 The Government of Jamaica has pursued environmental improvements through the establishment of the Natural Resources Conservation Authority as the regulatory body to set and enforce environental standards. The Energy/ Environment Steering Committee has recently been established under the chairmanship of the Permanent Secretary MME (Ministry of Mining and Energy) to supervise not only the coal EIA (environmental Impact assessment) but also more general issues affecting the sector. The arrangements are dealt with in more detail In the Mission's Environmental Report. This present Report concentrates on the environmental aspects of the power sector. 7.02 Some of the measures required to limit pollution, for example Flue Gas Desuiphurisation (POD) equipment, can be very expensive. While it is being used in some of the industrialised countries of North America, Europe and Japan, it seems unreasonable to require developing countries to adopt the same standards. Clearly, Improvements must be made, but the standards to be established should take into account the costs involved, particularly if they are excessive, and the ability of the country to afford then. 7.2 Sulphur dioxide 7.03 Sulphur dioxide, a possible source of acid rain, is formed from the combustion of sulphur In the thel and Is emitted through the chimneys of steam, plant and exhausts of diesel plant. There are many proposals and methods for removing SO% during and after the combustion process and a number of experimental and demonstration plants have been built. The two main methods seem to be by PGD equipment using limestone in large quantities and producing gypsum in large quantities and removal during combustion in fluldised beds, particularly the Circulating Fluldised Bed (CPB) boiler. Existing plant 7.04 While diesel oil No 2 has no significant problems from sulphur, heavy fuel oil No 6 is the principal fuel used at present at Old Harbour, Hunt's Bay and Rockfort and contains about 3% of sulphur which is emitted as sulphur dioxide. It would be very costly, but technically feasible, to fit Flue Gas Dem_phurising (FOD) equipment. It would also be possible to treat the fuel, but this also is costly. The steam plant will be retired over the period 1996 to 2003 and it is recommended that the plant be allowed to continue to operate without sulphur removal. The possibility of using a cheaper fuel oil after further cracking (see pan 14.15) or purchasing a similar oil (Bunker C) on the open market has been 7-2 discussed and may acerbate slightly the evironmental effects. Early retirement of the plant on envlronmental grounds would be the most costly option of all, involving an advance in investment of some US$ 80 million In new plant for each 60 MW set retired early, the advance in Investment matching the number of years of early retirement. Indeed, it has been stated in Section 5 that it would be very economic to defer the retirement date of some of the plant If it proves technically feasible. Future plat 7.05 Coal for the proposed dua oalloll fired station at Rocky Point (Salt River) will contain sulphur according to the source. Low sulphur coal (1% or less) Is available Internationally at acceptable prices and should be used. The sulphur dioxide emissions will be modest and should be acceptable in the context of Jamaica without the need for the very costly PGD equipment. 7.06 The use of heavy hel oil with about 3% sulphur will present a sulphur dioxide problem similar to that at existing plants ,and this would apply to steam plant and to diesel plant. The use of oil at the coalloll fired steam station will probably be limited since coal is expected to continue to be the cheaper fel. It is recommended that FGD equipment not be fitted but that the arrangement of the plant be such that it could be added at a later date f necessary. The siting of the coaloll station and the use of high chimneys will minimise local problems from SO. The use of heavy fuel oil In new diesel stations may raise more difficult problems, especially if they are to be Installed on existing power station sites,and thus continue the emission of S% for many years. 7.07 The possible use of Orimulsion will create a S emission 50% greater than with heavy fuel oil. It is proposed that the same provisions at the coal/obil team station im made for Orimulsion as for fael oil. The use of Orimulsion . new diesel stations on existing sites may be unacceptable without expensive POD equipment or, possibly, cleaning of the fuel. 7.08 The use of CFB boilers at the coal-fired station will certainly reduce S% emissions but will introduce the need to supply limestone for the fluidised bed and will produce gypsum with the fly ash, thus Increasing the ash quantity but probably improving the nature of the ash and any leachates from the ash-disposal area. If It proves possible to burn heavy hel oil and Orimulsion in a CFB boiler, the S0Q problem would be solved at modest cost. The possibilityof using CPB boilers should certainly be pursued during the Feasibility Report and at the detailed design stages of the station. 7.3 Nitrogen oxides (NO) Existing plant 7.09 NO. emissions arise from high combustion temperatures. Recent developments in the design of low-NO, burners can reduce NO, emissions and this applies to gas turbines, steam plant and combined cycle plant. The Plant Audit should consider the possibility and costs of fitting low NO, burners to the existing steam and gas turbine plant (see Annexe B). It is unlikely that the NO, emissions from diesel plant can be significantly reduced. 7-3 New plant 7.10 New plant should Include the requirement for low NO, burners, and appropriate emission levels (requiring specialist advice) should be specified. These emission levels may vary according to the type of plant. For example it will be easier to specify reduced emission levels for steam plant and gas turbines than for diesels. The possible use of CFB boilers at the coalloil steam station will do much to reduce NO. emissions by reducing the temperature at which combustion takes place. 7.4 Dust and ash Eisting plant 7.11 The problem of dust and ash in stations using heavy fuel oil is relatively small compared with coal-fired stations. However, heavy fuel oil does contain small (up to about 0.5% by weight) quantities of ash but it has not been the general practice to install dust collection equipment; it may be necessary to do so at future stations, especially If they are built in the Kingston area on existing power station sites. A noticeable (by the public) problem with oil-fired stations is unburned carbon which makes black smoke. This is usually caused by badly adjusted burners and Incorrect fuellair ratios and, In the case of diesels, by worn fuel pumps and dirty or worn injectors. Much can be done to alleviatm the problems by careful monitoring, adjustment and maintenance of the equipment and the Installation soon of computer-based plant-condition monitoring equipment will both reduce emissions and improve efficiency. The Plant Audit should cover these aspects (see Annexe E). New plant 7.12 Dust and ash is a much bigger problem for coal-fired stations. Dust emissions from the chimney can be reduced to acceptable specified levels by the usual installations of mechanical dust collectors, and electrostatic precipitators. The pressure to use low-sulphur coal may affect the precipitator performance which toods to deteriorate at low Sq levels in the flue gases. The use of CFB boilers would increase the amount of ash due to the use of limestone in the fluidised bed to trap the sulphur, though it may also improve the quality of the ash. 7M Effluents EsistIng plant 7.13 The Plant Audit should assess the extent of effluents from the sites of the existing power stations. These will comprise boiler blowdown, chemicals, fuel and lubricating oil spillages and leaks, cleaning fluids and other material. Proposals for reducing, If necessary, the effluents will entail collecting them and treating them; the cost of this will depend on whether or not the dirty effluents can be reduced in quantity and whether they can easily be separated from the site drainage system. 7-4 7.14 The cooling water system for all types of station in Jamaica, but mostly for steam stations, requires the discharge of warm water to the sea. This matter should also be investigated by the Plant Audit in co-ordination with the work of the Kingston Harbour Pollution Abatement Committee. New plant 7.15 The design of new plant should ensure that all potential dirty effluents are collected and treatel before discharge from the site. This applies as much to blowdown, spills etc from the station as to the leachates from an ash disposal area. This will simply be the application of good practice to the design of the station. 7.6 Site-specific matters 7.16 These will be dealt with as they arise at each existing and new site. They will include the effects on the local populace including benefits such as employment opportunities, visual effects which can be reduced by good architectural treatment, noise from machinery, safety valves and transformers etc, and the flora and fauna on and around the site any rivers and the sea. 7.7 Cost of environmental measures 7.17 The cost of environmental measures at existing power stations will be a matter for the Plant Audit on the basis of the extended Terms of Reference suggested in Annexe E. It is not expected that major expenditure will be incurred if it is accepted that FGD will not be required. With the possible exception of modifications to site drainage, much of the expenditure on environmental improvements will be common with other improvements such as to burners, air heaters and other boller parts 7.18 Similarly, any new station should be designed to modern environmental standards In respect of low-NO. burners, collection and treatment of station waste, provision of dust collecting equipment, visual impact etc. The reduction of SO should not need FGD equipment especially if coal is likely to be the main fuel, though the use of CFB boilers would substantially reduce both the S02 and NO. emissions. It is not possible in this Report to identify costs changes due to environmental protection measures; it is thought that for the coal/oil steam station they are well within the accuracy of the existing cost estimates and that no further provision need be made. The same applies to gas turbine plant which will be expected to come with low-NO, burners. Low speed diesel plant retains the problem of emitting SO and this may prove costly to reduce should it be necessary to do so. 7.8 Institutional 7.19 Reference has already been made to the responsibilities of the Natural Resources Conservation Authority which has the duty to impose and monitor standards. These matters are more fully covered covered in the Mission's Report on Environmental matters. The need for Environmental Impact 7-5 Assessments (EIA) for all new projects has been Identified and CIDA are currently Involved in site selection advice for the proposed coal station at Rocky Point (Salt River) and In discussing the extent of their Terms of Reference for an EIA for the station. Concern was expressed by CIDA that there appeared to be some doubt about the firmness of the proposed coal station and Its timing. 7.20 For a specific EIA, it Is desirable to know the base data of the site and the region so that the impact of the project can be assessed. Such data Is not available In Jamatca. One of the first tasks of the NRCA must be to move as quickly as possible (and as finance will allow) towards establishing the environmental base. A first step would be to take ground level measurements of SO, NO,, and dust and identify the major polluters; the latter are easy to find since they are essentially large and obvious Industries such as power stations, cement works, refineries, bauxite mines and alumina plants etc. This information together with wind patterns will give the main spot sources of pollutants and where they are likely to travel. Overlaid on this, particularly In Kingston, Is the exhaust from traffic and the burning of waste in the open. This is a first step towards quantifying and understanding the degree and spread of pollution and to establishing an environmental base. 7.21 A much more sophisticated approach is to increase the number of measurements, taken not only at ground level but at higher levels, monitor the main emission sources and track them, and model by computer the base system and any new projects on a country-wide basis. The cost and time required for such a study both increase dramatically. 7.22 It Is thought that the first step in 7.20 will be adequate for NRCA and its advisers to establish standards for emission levels. These standards may well vary according to the location, the standards for Kingston probably being more stringent than for a country site In view of the existing level of pollution and the number of people affected. Specialist advice on the establishment of the base data and on the setting of standards should be obtained. SECTION 8 TRANSMISSION AND D R1BrON 8.1 Transmisson system 8.01 The existing transmission system comprises 138 and 69 kV systems. The 138 kV system of 171 circuit-miles connects the Old Harbour power station to the load centres at Kingston, Spanish Town, Ocho Rios and Montego Day at Bogue. The 69 kV system comprises 445 circuit-miles and is supplied from 8-138169 kV substations with a transformer capacity of 277 MVA, and from the Hunt's Bay and Rockfort power stations. 8.02 The SWECO Report (Ref 12) identified from load flow studies some reinforcements required over the next 20 years on the basis of all the generation belbg in the Kingston and Old Harbour area. The studies used the JPS criteria for voltage regulation and line or substation outages. The proposals are obviously subject to change according to load growth; they are not dated and no costs are given though the costs will probably be small in relation to the generation expansion programme. 8.03 A Report by Acres International (Ref 19) Investigated transmission (and distribution) developments up to 2005 and developed designs and costs for those projects required in 1995 or earlier. Eight transmission projects were identified, all at 69 kV, though the largest in cost is new lines from Paradise and Bogue to Orange Bay north of Negril constructed for 138 kV but initially operated at 69 kV. The total Investment In these proposals is US$4.6 million in local currency and US$ 15.8 million In foreign currency. 8.04 In July 1988, Ebasco (Ref 14) prepared a loss reduction study which has been referred to earlier in Section 2. This study Indicated that the losses in the transmission system were about 1% of the energy sent out from the power stations or about 6% of the total losses. The only measure worth carrying out on the transmission system to reduce losses was found to be power factor correction. The loading is well below the thermal limit due to the design requirements for voltage regulation under outages of a line section. 8.2 DIstribution 8.05 The Acres International Report (Ref 19) also dealt with the distribution system to 1995. The report considered three sub-projects as being typical of others, the sub-projects including three different voltage levels, urban, suburban and rural areas and a range of physical conditions and ages of equipment. Performance was considered satisfactory if there were no thermal overloads and voltage 8-2 regulation was under 5% for urban areas and 6.5% for rural areas. The basis for this was not clear and did not appear to involve an assessment of the economic optimum level of losses. Ite capital cost of three projects, eleven similar projects and two further projects was estimated to be US$ 10.5 milion in local currency and US$ 16.4 million in foreign currency. 8.06 The Ebasco Report on Loss Reduction (Ref 14) concentrated on the distribution system where 67% of the total losses occurred. It recommended the progressive conversion of 12 kV feeders to 24 kV and piase balancing; reconductoring of heavily loaded feeders was shown to be attractive, but presumably nt in addition to Increasing the voltage. As mentioned In Section 2, the actual loss savings for each option were not clear. 8.07 A contract for a Distribution Expansion Master Plan is about to be placed. The Terms of Reference (Ref 39) have been read and appear to be adequate with the exception that there seems to be no specific reference to determining the economic optimum level of losses in the various parts of the system, primary feeders, secondary feeders and transformers. 8.08 The Ebasco and Acres laternational Reports form a basis for the JPS Investment programme in transmission and distribution, as discussed in the Section 9. 8.09 JPS are currently undertaking a major computer-based database of the transmission and distribution system including mapping the system and all the roads and accesses. The latter is a very time- consuming task and will be of perhaps more use to the local authority and other utilities such as water supply. JPS requirements could be met by a simpler mapping system, perhaps based on locating only the nodes. It Is recommended that JPS should either abandon the present detailed mapping, or obtain participation by others so that the basic mapping Is on a shared cost and manpower basis. SECTION 9 JPS INVESTMENT PROGRAMME 9.01 JPS prepare Investment programmes annually. The latest complete programme is for the period 1990/91 to 1999/2000 and was prepared in early 1990 (Ref 42). The current programme is a draft dated March 1991 and is Incomplete. (Ref 41). These programmes have been discussed briefly with JPS, but it has not been possible to carry out a detailed study. 9.02 A tentative Investment Programme has been prepared and is in Tables 9-1 for foreign currency, 9-2 for local currency and 9-3 for the total of all currencies. The programme is based on Refs 41 and 42 for all except the Production and Generation Sectors, though in the longer term, some of the figures have been smoothed and rounded; the figures have not been oiscussed with JPS. 9.03 The Production Sector draws heavily on Refs 41 and 42 but also uses some of the rehabilitation costs from SWECO (Ref 12) 9.04 The Generation Sector is based on the Least Cost Expansion Plan as indicated by the WASP studies and in particular uses Base 1, le Is based on the SWECO Base forecast without any reductions for loss reduction or DSM measures. This is in accordance with the agreements recorded in Annexe H. The Investment costs include interest during construction at 12% per year as calculated in the WASP model.An additional 5% for import duties has been added to the foreign component of expenditure. Consulting services directly associated with the generation projects are part of the capital Investment in those projects, and have not been included In the Consulting and Training Sector. 9.05 Ile Programme as presented assumes that all the projects are conventionally financed by IPS and its leaders, le JPS becomes responsible for all capital expenditure or for loans obtained for the expenditure. Should any of the projects be Implemented privately, the investment programme for JPS would be correspondingly reduced. 9.06 The Investment in generation would be reduced if the loss reduction and DSM measures prove to be close to the estimates In Table 2-lA. The second and third low-speed diesels could be delayed by about 6 months and the first gas turbloe in 1995 would not be necessary. Later investment in the coal station units 2 to 6 are each delayed by about one year and the 3rd gas turbine is delayed by 2 years. 9.07 JPS will be preparing a tentative investment programme as agreed during the meetings of April 17-19, 1991 in Washington between the Government of Jamaica delegation and the World Bank. At this time, revisions of the annual expenditures and financing requirements can be made, taking private sector financing into account. 9-2 TABLE 9.1 CAPITAL frESa~MT FonRCAT Comtnt 1991 USS mitimns rmua aimuuc TMTAL TOTAL 1991919 199 Im N45 IMM 1991199 1/ 1M/98 19 1999/00 2000/011991/01 9BRSUCTON Plant I~provemnt wyd~ w~gradin 0.2 0.8 0.9 0.9 2.9 2.9 Old #arbmur 0.3 0.3 0.3 Iunt's ay 0.7 3.6 3.6 0.0 7.9 71.9 Rokfort 0.9 0.9 1.8 1.8 ntabtitation Old 8hrbour 12.0 4.0 16.0 12.0 4.0 32.0 amt's oay 4.0 1.2 5.2 4.0 1.2 10.4 kplmements 5.5 0.1 5.5 5.6 0.0 16.5 5.8 5.9 6.0 6.0 6.0 46.2 kton 1o,d aan 2.3 2.3 2.3 mnergy onsvn 2.1 13.9 16.1 16.1 isolettaneous 0.6 0.2 0.2 0.2 0.2 1.4 0.5 0.5 0.5 0.5 0.5 3.9 Tout Prodution 28.5 21.1 10.2 10.3 0.2 70.2 22.3 11.6 6.5 6.5 6.5 123.6 GEMM?lmO Cas Wins fr 1995 2.2 19.2 21.4 21.4 for 1996 2.2 19.2 21.4 21.4 for 2001 2.2 19.2 21.4 Low speed dieses for o 1993 18.4 37.4 55.8 55.8 for Jul 1994 4.6 14.0 9.3 27.9 27.9 COSI statfon for 1997 9.2 48.9 58.1 24.2 62.3 for 1996 18.4 18.4 97.8 48.4 164.6 for 1999 9.2 48.9 24.2 82.3 for 2000 9.2 48.4 26.2 81.8 for 2002 9.2 48.9 58.1 Reab of hro 0.7 0.3 1.0 1.0 Total goration 0.7 23.3 53.6 39.9 86.5 204.0 -131.2 106.5 72.6 35.6 68.1 618.0 0.0 , 0.0 iAsftssogl 2.8 5.5 6.2 3.4 0.0 17.9 -2.0 2.0 2.0 2.0 2.0 27.9 0.0 0.0 zuTATIOSm 3.7 9.9 7.2 1.4 0.4 22.5 5.0 5.0 5.0 5.0 5.0 47.5 0.0 0.0 Di0 lu0Tu10 6.4 1.8 1.7 1.2 1.9 13.0 2.5. 2.5 2.5 2.5 2.5 25.5 0.0 0.0 aUssAL PRWPRTY 7.7 7.6 6.4 6.9 7.0 35.6 7.0 7.0 7.0 7.0 7.0 70.6 0.0 0.0 00m AND TMININ 1.1 1.0 1.0 1.0 1.0 5.1 1.0 1.0 1.0 1.0 1.0 10.1 ........ ý ......................... ........................... .~.............. ....... SRAl TOTAL 50.9 70.1 86.3 64.0 97.0 368.3 171.0 135.6 9&6 59.6 92.1 95.2 -ORE JPS Uch 199 t&dia bdmns. 9-3 TAL8 9- 0APITAL INVESTNENT iMCAT constant 1991 USS Itin LO0AL -UREO TMTAL TOTAL 1991/92 1992/93 1993M1993 1995/91991/% 199MM 199/90 199899 1999/00 3000011991/01 PROMICU #~ydro dino 0.0 0.1 0.2 0.2 0.2 0.6 0.6 etd marbu 0.2 0.2. . ~4t's Bay 0.3 0.3 0.2 0.7 0.7 ookfort 0.0 0.0 ebtittation Old Harb~u 0.8 0.3 1,1 0.8 0.3 2.2 ht's may 0.4 0.1 0.5 0.4 0.1 1.0 Replacommnts 1.1 0.1 1.1 1.2 0.0 3.5 1.2 1.2 1.2 1.2 1.2 9.5 Econ &ad M~gt 0.4 0.4 0.4 Enrgy consvin 1.3 7.0 8.3 8.3 miscellaneous 1.1 0.4 0.4 0.4 0.4 2.7 1.0 1.0 1.0 1.0 1.0 7.7 Total Produ~tion 5.5 7.9 1.9 2.0 0.6 17.9 3.4 2.6 2.2 2.2 2.2 30.5 GENERATION eas turbns for 1995 0.1 1.0 1.1 1.1 for 1996 0.1 1.0 1.1 1.1 for 2001 0.1 1.0 1.1 Lou speed diesets for Ow 1993 2.9 5.9 0.8 8.8 for Jul 1994 0.7 2.3 1.4 4.4 4.4 Coat station for 199? 3.5 18.7 22.2 9.2 31.4 for 1998 7.0 7.0 37.3 18.4 42.7 for 1999 3.5 18.7 9.2 31.4 for 2000 3.5 18.7 9.2 31.4 for 20 3.5 18.7 22.2 ehabofhydro 0.7 0.3 1.0 1.0 .... ,;... :..................4044........... 0........................................ Totat generation 0.7 3.9 8.3 6.0 36.7 45.6 50.0 40.6 27.9 12.8 19.7 196.6 TRs1issio 1.8 2.2 1.7 1.4 0.3 7.3 2.0 2.0 2.0 2.0 2.0 17.3 SUBSTATIWs 2.5 2.8 3.3 0.6 0.4 9.7 3.0 3.0 3.0 3.0 3.0 24.7 01saTRUT1I 6.1 1.8 1.2 0.9 0.8 10.8 1.5 1.5 1.5 1.5 1.5 18.3 GENERAL PUPERTY 4.0 4.1 5.3 4.6 4.9 22.9 5.0 5.0 5.0 5.0 5.0 47.9 cNS AND TRAINING 1.1 1.3 1.4 1.5 0.3 5.5 1.0 1.0 1.0 1.0 1.0 10.5 7 .................................................... 4............. . . 0RAND TOTAL 21.8 24.0 23.0 16.9 34.0 119.7 45.9 55.7 42.6 27.5 34.4 345.8 SOURCE: JPS ManhIk 191isuiea~n Eee. 9-4 TADLE 9-3 CAPITAL INV=TENT FORCAST Constant 1991 US illtioens TOTAL CUJRRENCV A MOAL 1MAL 1991/92 1992/93 1993/ 194/95 1995/9 1991/96 1996/97 1997/98 1998/99 1999/00m8000/011991/0 ........ ~ ~ ~ f .......................0................... .... PRNUCitN Plant lapovwnan ~ydr upgradin 0.2 0.9 1.1 1.1 0.2 3.6 3.6 Old ~arbour 0.4 0.4 0.4 iunt's lay 0.9 3.8 3.8 8.5 8.5 Reokfort 0.9 0.9 1.8 . 1.8 Rehabilitation Old Narbur 12.8 4.3 17.1 12.8 4.3 34.2 kut's ay 4.4 1.3 . 5.7 4.4 1.3 11.4 Reptacemmnts 6.6 0.2 6.6 6.8 20.0 7.0 7.1 7.2 7.2 7.2 55.7 tomn td iun, t 2.6 2.6 2.4 Energy conmvtn 3.4 20.9 24.3 24.3 soettenaous 1.8 0.5 0.6 0.6 0.6 4.0 1.5 1.5 1.5 1.5 1.5 11.5 Total Productlmn 34.1 29.0 12.0 12.3 0.8 88.1 25.7 14.2 8.7 8.7 8.7 154.1 cENIRATION Ga turbins for 1I 2.3 20.2 . 22.5 22.5 for 1996 2.3 20.2 22.5 22.5 for 2001 2.3 20.2 22.5 Lo speed dieets for Dec 19m 21.3 43.3 64.6 64.6 for Jul 194 5.3 16.3 10.7 32.3 32.3 Coat station for 1997 12.7 67.6 180.3 33.4 113.7 for 1998 25.4 25.4 135.1 66.8 227.3 for 1999 12.7 67.6 33.4 113.7 for k00 12.7 67.1 33.4 113.2 for 200 12.7 67.6 80.3 ofhab fhydro 1.4 0.7 2.1 2.1 Total gneration 1.4 27.3 61.9 45.9 113.2 249.7 181.2 17.1 100.5 48.4 87.8 814.7 TRAUSNI88300 4.6 7.6 7.9 4.7 0.3 25.2 2.0 2.0 2.0 2.0 2.0 35.2 susTATIONs 6.2 12.7 10.4 MO 0.8 32.2 5.0 5.0 5.0 5.0 5.0 57.2 olsToU 12.5 3.6 2.9 2.0 2.7 23.7 2.5 2.5 2.5 2.5 2.5 36.2 UWNERAL PRoPRTY 11.7 11.7 11.7 11.5 11.9 58.5 7.0 7.0 7.0 7.0 7.0 93.5 COS AND TRAININg 2.2 2.3 2.4 2.5 1.3 10.6 1.0 1.0 1.0 1.0 1.0 15.6 .....*.... .................................................................................... RamD TOTAL 72.7 94.1 109.3 80.9 131.0 487.9 224.4 178.8 126.7 74.6 114.0 1206.4 SOURce JPs Mesel. 1et N-.- semwes. SECTION 10 INSTITUTIONAL AND TECHNICAL ASSISTANCE 10.01 It was not possible in the course of the Mission to examine and discuss broadly with JPS the institutional and technical assistance issues. The comments in this Section are therefore based only on observations made during the course of working with JPS, particularly with the planning department. 10.02 The level of computer literacy seems to be high as would be expected from engineers comparatively recently trained; this is clearly a good foundation for planning and other work. However, the sense of what is likely to be right and the 'feel' for the overall proportions of a problem is, with a few exceptions, lacking in many of the staff. This 'feel' is something that can only be obtained by experience and by contact with others with the experience and willingness to impart it. A problem with computer software is that staff tend to use It as a 'black box' without adequate understanding (and availability of someone else with that understanding) of what the black box does and how it does it. An understanding of a problem is perhaps best obtained by putting aside the computer and solving the problem manually, or at least with the use of a calculator. This engenders a sense of understanding and Indeed, it would be good training if all computer output were to be checked by 'back of envelope' calculations; this Is, of itself, a good quality assurance practice, especially if it Is done by a colleague not doing the computer work. 10.03 It would seem likely that other parts of JPS suffer from similar problems, though the Production Directorate and its power station staff seemed competent and experienced. They are also making use of a full time and very experienced expatriate engineer, and there may be alesson here for other directorates. 10.04 The sense of proportion may also be lacking to some extent in more senior positions. For example the computer based mapping referred to In Section 8 seems to be an example of a somewhat routine and, to the fine detail being worked to, unnecessary task being tackled by an understaffed organisation. In contrast, the reduction of unaccounted losses (or rather accounting for them and increasing revenue) is a task which could return value for the effort many times over. 10.05 The above snatches of observations lead to the general view that more contact by staff, probably at most levels, with experienced staff from other utilities would be of considerable benefit. This contact could be obtained by: 10-2 a. Secondment of staff to other countries on a practical training and xperience basis, working with and alongside experienced staff. b. Seconding staff to work with consultants and other specialists retained by JPS for specific tasks; the recent SWECO work on the Least Cost Expansion Plan is a good example of this and should be the usual practice. c. Retaining specialist staff or consultants to work in JPS on specific projects from time to time to give an overview and discuss technical, planning, financial or management matters; these could be relatively short, (a few weeks) assignments. 10.06 There is, of course, nothing new in the above. The great problem with technical assistance is to ensure plenty of it and to ensure that it is effective. The effectiveness depends to a large extent on the abilities and personalities of both the specialist and the staff he is working with and training, though a proper understanding of the task from the outset is a good start, remembering that we are discussing the training of professionals. Ensuring that there is plenty of technical assistance available is a matter of JPS making f ai use of its consultants and contractors, of cultivating links with one or two other utilities to facilitate training and possibly exchanges, and of lobbying the sources of technical assistance In the appropriate Industrial and governmental departments of the developed countries. 1 A List of persons met a Terms of Reference C References D Notes of Discussions with JPS and SWCO a Additions to Terms of Reference for Power Plant Audit to cover Environmental Issues 7 Results of WASP Modf'ling a Terms of Reference for possible Study of Heavy Fuel Oil at Power Stations 8 Aide Memoirs on Proposed Private Sector Energy Development Project, Washington, 24-25 April 1991. A-1 AUNEB A LIST OF PERSONS MBW World Bank- Washington DC Alastair J Mcechnie Chief,EES& Unit Winston Hay INOD Edwin A Moore INED Abderrahamane Megateli Sr Fin An LAC III Suman Babbar Sr Pow Eng,Cof a Fin Adv Serv Bernard Bara*s Pr Env Spec, Env Div John. Besant-Jones IENED World Bank Energy Sector Mission 8 Joseph W Gilling Mission Leader William 0 Matthews Petroleum Sector Brian Kelly Energy Efficiency Robert Van Der Plas Household and Biomass Jamaica Public Services Co Ltd Derrick Dyer ChieftExecutive Basil Sutherland Director of Planning Earl Monroe Director of Production Hopeton P Heron Planning Manager Mrs Polderness Corporate Planning Manager Valentine Pagan Planning Consultant Albert Gordon Planning Engineer Ray Congdon Production Manager Earl Booth Manager, Hunt's Bay power station Paul Rose Dep Manager, Hunt's Bay WR Ashby Energy Conservation Consultant Ministry of Mining and Energy Godfrey Perkins Permanent Secretary Arthur JS Geddes Technical Director Sia Mian Energy Adviser Ainsworth Lawson Director, Alternative Energy Dr Ind Christoph Menke Energy Adviser (GTZ) Alcan Jamaica Co MA Woodstock Power Consultant Cement Company of Jamaica Dr Maurice BP Mcleod Plant Superintendent Earl LA Barrett Deputy Technical Director Henry Reid Quality Control Manager RC/Raglar, Bailly, Inc Robert 8 Ciliano Senior Vice President A-3 Arun P Sanghvi SenLor Vice President Canadian 2ateratIonal DevelopMeat Agensy Philip Schubert Team Leader Albert Dobson Power Bngineer Dr Alan Jones Znironmental Scientist Greg Whitworth Znvironmentalist Natuaal Reaoureas Conservation Antoeity Richard Thelvell Znvironmental Consultant S"mc0 (Bergman & Ca) Joran Vedin Chief Engineer, Blectrical A-4 AN2Z a T88M8 OF REBREN=CB The following Terms of Reference are taken from the memo dated March 7,1991 from Alastair J Mckechnie, Chief,IZNPD. AMAIC& 88NAPs Bergy fficiency Project - Strategic Study WORs 1. You should travel to Washington on about March 4,1991 to meet with Bank staff and prepare for the mission to Jamaica in connection with the subject project. You should then travel to Kingston on March 10 for about 18 days to participate in a mission led by Mr Joseph Gilling. During your stay you should carry out the field work required to complete the power sector portion of the study. 2s. You should pay particular attention to the following pointst (a) while in Washington meet with Bank staff responsible for the Power IV and Power V projacts, environmental matters, and commodity price forecasts notably coal; (b) review the SWECO Least-Cost Generation Expansion Plan; (c) review the demand forecast, transmission and distribution expansion, and Back Rio Grande hydro power developmentsl (d) meet with representatives of bauxite, sugar industry and other firms who are potential of cogeneration power producers and review the engineering and cost aspects of such production; (e) assess the potential impact of demand side management and end use efficiency projects on the load characteristics, demand growth rate, and generation expansion planning; (f) evaluate the loss reduction and technical efficiency programs for generation, transmission, and distribution presently under way and proposed, and identify further projects and investment requirements. (g) review the present policies, institutional responsibilities,and standards for pollution control from generating plants; (h) review the JPS Co investment program for over a ten-year horizon in terms of program composition, cost estimates(foreign and local currency requirements); 3. Zn reviewing SWCO generation plan you should work with JPS staff to make sensitivity analyses by varying one parameter at a time. 4. You should prepare a summary of your initial conclusions regarding the composition of an investment program and power sector strategy for inclusion in the Aide Memoir to be left with Go at the end of the mission. S. You should prepare an outline of your main report in the field and submit the final report by April 15 1991. A-5 1. Electricity Tariff Study. RCG/Hagler, Bailly,Inc December, 1989. 2. Report on Evaluation of Near Tem Options. AN Seck and Associates, August 1989. 3. Letter from World Bank to the Minister, Mining and Energy (on Study Framework) 25 June 1990. 4. Letter from Planning Institute of Jamaica to World Bank, 28 March 1990. 5. JPS legislation- Licence, Electric Lighting Act, Memorandum and Articles of Association, The Electricity Development Act. 6. JPS Tariffs, April 1990 7. Staff Appraisal Report-Fourth Power Project. World Bank, June 1987. 8. Terms of Reference for Blectricity Demand Forecast and Least Cost Expansion Study. 9. T&rms of Reference for Technical Assistance to Establish JPS Energy Conservation Unit. Draft, May 1990. 10. Review of Power Sector Operations and issues. John Ruiper, World Bank, September 1989. 11. Report on Electricity Demand Forecast. SWCO, February 1991. 12. Least Cost Power Expansion Study. Draft. SWCO 1991. 13. Back Rio Grande Hydroelectric Development Study. Interim Report on Feasibility Study. SWCO-CIPS, July 1990 and Draft Final Report, March 1991. 14. Electric Power Lose Reduction Study. Ebasco, July 1988. 15. JPS Organisation Structure, September 1990. 16. Private Sector Participation in Power through BOOT Schemes. World Bank Energy Series Paper No 33, December 1990. 17. Congo. Power Development Study. S8AP Report No106/90 (for description of WASP II software) 18. Electricity System "aprovewAnt Project. JPS CO Ltd, August 1990. 19. Transmission and Distribution Projects for Electricity Expansion Progeamme. Acres International, March 1990. A-7 C-2 20. Least Cost Expansion Plan. Summary of SWCO Draft Report. JPS March 1991. 21. Environmental Impact Assessment - Coal Fired Power station. Work Program and Terms of Reference. September 1990. 22. US Windpower. Proposal for 60 MW Private Sector Power Project. 23. Orimulsion fuel characteristics. 24. ADO and H8O characteristics from Hunt's Bay power station. 25. Peat Development Project. Report by B Barats, World Bank, November 1984. 26. Testing of Veneauelan Orimulsion as a Boiler Fuel. Energy Development Note No 25. World Bank February 1991. 27. Price of Low Speed Diesels. Memo by Edwin A Moore, World Bank, 20 February 1991. 28. Price Prospects for Major Primary Commodities. World Bank Report NO 814/90, December 1990. 29. 1991/92 Major Maintenance Plans. JPS March 1991. 30. Spanish Town and Portmore Development Study. Draft. JPS, November 1990. 31. Coal Committee Report. Government of Jamaica, 1989.. 32. Clarendon Coal- Fired Cogeneration Plant Proposal Gibbs and Hill, 1986 33. Report on Coal Plant and Harbour Siting studies. Electric Power Development Co Ltd, October 1988. 34. Jamaica Public Service Company Ltd. 1989-90 Annual Report. 35. JPS Annual Statistical Report. 1989-90. 36. 'JPS Capital Investment Programme (Draft) 1991/2-1995/6. 37. Feasibility Study on the Upgrading of the JPS Hydra Stattons MC Energie- und Uwelttechnik GMB. June 1989. 38. Torms of Reference for Power Plant Audit and Assessment Studies, JPS 1991 39. Terms of Reference for Preparation of Distribution Bxpansion Master Plan, JPS 1991. 40. Review of Nine Small-scale Hydra Projects. Glen Ichikawa, September 1990. 41. Draft Capital investment programme 1991/92 - 1995/96. JPS, March 1991 42 Capital Investment Forecast 1990/91 - 1999/2000, JPs, 191.0 43 Private Sector Participation in Power through BooT Schemes. World Bank Energy Series Paper No 33, December 1990. A-8 AMRUZN D NOTES FROM DISCUSSIONS WITH JPS aND SWO0 On SBCW' 8 DRAFT REPORT ON TOB taSW COST EXPANSON PLAN Kingston, 19-22 March 1991 1. According to the World Bank's opinion the investment costs as well as the variable costs for operation and maintenance are on the high side. This specifically refers to coal fired steam power. the costs are however not so high as to necessitate the calculations to be changed. The impact from reduced investments and maintenance costs specifically for coal fired steam power will be investigated by sensitivity analysis. 2. Information on the availability as referred to in the Draft Report has been obtained by SWo from the station log sheets. These reliability figures are lower as compared with those appearing in a JPS Report prepared by K. 8. Julien in August 1990. The difference particularly refers to the forced outage rates. In absence of an explanation to the difference the original figures will be maintained. 3. The selection of combined cycle was questioned by World Bank especially as it is a high efficiency plant running at diesel fuel at moderate load factor just below gas turbines. SWUOO will study the matter and explain. 4. It was questioned the low reserve capacity e.g. only 89 MW is anticipated for 2007. The reserve capacity shall be seen against the background of having units as big as 60 MW and furthermore in consideration of the forced outage rates which according to the Bank*s opinion are on the high side. SWM00 will investigate and explain. S. In addition to what is stated above the following issues shall be dealt with in the Final Report. - The possibility to use oil as a complement to bagasse for power generation from Frome Sugar Factory during the off-crop season. - 3conomic impact from extended life of some of the better steam units. - sensitivity analysis of changed load demand especially of the low load forecast. - All figures to refer to calendar year. - The impact of shadow pricing to be investigated. - Capital investment flow per plant will be shown and the total capital investment programme for scenario 01 and 02 will be presented. A-9 D-2 6. These notes sumatise and conclude the comments on the Draft Report. Taking them into consideration SWCO will prepare the Final Report. Kingston* Marh 22o 1991 lor JP8CO For IBRD For SWECO V. Pagan TZ Norris J Vedin (Consultant) A-10 AMU= u ADDITIOS TO S OF REPUABCB 70R PONZR PlanW AUDIW AND ASSESSMENT STUDIES To COVR ENRROMM0NERL ISSUBS The contractor for the Plant Audit and Assessment Studies is currently being selected by JPS# The studies are aimed ats -Assessing the condition and remaining life of the generating plant -Identifying the cost effective measures to upgrade and renovate the plants with the intent to extend the useful life of the generating units to the point where their operation continues to be economic. -Providing valuation of the company's generating plant fixed assets and recommending an appropriate valuation methodology for continuing appraisals of plant and equipment for accounting and insurance purposes. The plant to be assessed is all the plant at all the power stations with the exception of sets 1-4 at Hunt's Bay. It has been sec-mended in Sections 3 and 7 that the Ters of Reference for the Plant Audit be extended to cover environmental aspects. The following additions to the Terms of Reference are suggested* 1.0 Objectives Add.* 4. To assess the extent of environmental pollution from chimney emissions and effluents into the sea and to examine the cost of measures to reduce them. To accomplish the objectives it will be necessary to conduct a general assessment of the generating system. This assessment will include: Add.. 4) A review of the environmental impact of emissions and effluents. 3.0 Study Plan Add after 6. 7. Evaluation of measures to reduce emissions and effluents. Insert 3.4* Task 4. Perform Environmental evaluation The contractor and JPS will agree a programme for evaluating environmental pollution and assessing measures to reduce it. The contractor will undertake at least the following: 1. Measure the chimney emissions in respect of particulates and their analysis, sulphur oxides, nitrogen oxides and unburnt carbon. 2.Investigate the effluents discharged into the sea either directly, via the site drainage system, or otherwise. The evaluation will describe fully the methods used and the results A-11 8-2 obtained. The contractor will propose and cost measures to reduce the pollution which should includes a. refurbishment of boiler parts including burners b. operational procedures C. proposals for gathering and treating effluents including chemicals 4. re-arrangement of site drainage should this be appropriate e. equipment for continuing to monitor environmental effects f. any other aspects affecting the environment. The contractor will not be required to carry out any off-site investigations, nor will he be required to investigate Flue Gas Desulphurisation equipments other than to provide a general review of sulphur removal methods and their capital and operating costs. After discussion of the costs and benefits with JPS, the contractor will propose an implementation and procurement programme for those measures agreed to be Implemented. The contractor will consult with and take guidance from the Natural Resources Conservation Authority and the Snergy/fnvironmental Steering Committee chaired by MW. A-12 RXBULWS 0? WASP MMODLMMS The Tables in this Annexe give the results of the models run on WASP by JPS, as follows a Table P-1 Base 1 8WO0 load forecast, modified data, World Bank fuel prices. Table P-2 Base 2 As Base 1 but with load forecast reduced by lose reduction and DOM measures. Table P-3 Base 2A Coal price profile same as for oil. Table F-4 Base 28 ffect of 10% change in capital cost of the coal steam station. Table F-S Base 2C Assume no new capacity possible before 1994 Table P-6 Base 2D Force combined cycle plant into the programme to indicate the economics of combined cycle. Base 23 ffect of 10% change in capital cost of combined cycle plant. Table P-7 Base 21 Rehabilitate say old Harbour No 2 in 1997 and retire 5 years later in 2004 to examine the benefits of possible further life extension. A-13 7-2 al. .eR TABLE F-1 RESULTS OF WASP IODEL Ba1 SiECO Load Forecast, modified data, World Bank fuel prices *New capacIty, NJ sent out * ..... -Present values of cash flows, US$, 000*** Tear Coal Low speed Gas Const- Salvage Operating Energy tLP Steam Diesel Turbine Total ruction value cost unserved Total % 1991 91395 618 92013 0.26 1992 77359 1344 78703 0.58 1995 33 33 15945 -1207 67688 811 85237 0.40 1994 40 40 39660 -3677 63122 366 99671 0.21 1995 20 20 17795 -1972 61779 882 78484 0.52 1996 33 33 11349 -1494 60290 736 70881 0.49 1997 61 61 84272 -15950 53256 383 121961 0.28 1998 122 2 7210 -15475 44040 337 101112 0.26 1999 61 61 32236 -7811 395 466 64473 0.39 2000 61 61 28783 -7878 353(. 547 56755 0.49 2001 33 33 6440 -1801 328 278 37816 0.29 2002 61 61 22946 -7991 29141 426 44522 0.49 2003 61 61 24192 *9492 25628 113 4041 0.15 2004 0 0 0 23800 187 23987 0.27 2005 0 0 0 22096 301 22397 0.47 2006 61 20 81 22335 -12391 19716 247 29907 0.44 2007 20 20 4567 -2799 18225 221 20214 0.4" 2008 20 20 4078 -2829 16822 192 18263 0.43 2009 20 20 3641 -2857 15543 172 16499 0.43 2010 20 20 3998 -3547 14228 136 14815 0.38 Total 488 160 99 747 394647 *99171 811912 8763 1116151 NOTES: Salvage ior residual) value is at the and of year 2010 and relates to the plant installed in each stated year Energy unserved is the energy not a4*pied, valued at US$ 1.5/kih LOLP is the Less of Load Probability and is the percentage of the year that the generating plant is estimated to be unable to meet the load, fe there will be load shedding due to unavailtability of generating plant Construction cost includes Interest during construction The WASP output in respect of construction costs and salvage values has been corrected to take account of the early site establishment costs of the coal station A-14 F-3 61.*.n40 TABLE F-1 Continued RESULTS OF WSP NDEL WUECO toad forecat, modif led data, World Bank fuel prices I.--••••••••....••••.CasIFtomwSS,00-----------•---•--- xisting New Total Maxinu Reservo i . ••••••••Fuet.•..•••••••••• i Operation capaity capcity capacity DOmnd Invetømt an Yer KW NU NU N % of ND Cost9 Cot HFO #o6 Diøsøl Total maintee Total 1991 526 526 345 52 0 72424 8378 80802 16575 178179 1992 526 526 365 44 0 64524 10638 75162 18124 168448 1993 526 33 559 387 44 21600 60144 12347 72491 18434 185016 1994 526 73 599 410 46 62000 64674 8972 73646 20752 230044 1995 508 93 601 434 38 31000 67150 13877 81027 23310 216364 1996 491 126 617 450 37 21600 69406 20993 90399 23419 225817 1997 471 187 658 467 41 193700 8139 67426 12289 87854 24191 393599 1998 377 309 686 483 42 185900 23659 52195 2997 78851 24972 368574 1999 319 370 689 500 38 93000 31556 43156 4044 78756 26182 274694 2000 267 431 698 516 35 93000 39308 34754 4832 78894 27315 278103 2001 267 464 731 532 37 21600 40059 34899 6767 81725 27325 212375 2002 202 525 727 548 33 93000 47565 23336 9288 80189 28659 282037 2003 202 586 788 54 40 109800 54095 1929 4137 77526 28607 293459 2004 202 586 788 580 36 0 54855 20491 5772 81118 2953 191889 2005 202 586 788 596 32 0 55605 21560 7720 84885 30955 200725 2006 136 667 803 614 31 140800 62602 13340 7639 83581 32058 340020 2007 136 687 823 653 30 31000 63083 15610 7569 86262 33411 236935 2008 136 707 843 651 29 31000 63453 18088 7387 88928 34699 243555 2009 136 727 863 670 29 31000 63804 20746 7258 91808 36078 25069 2010 136 747 883 688 28 31000 64100 22833 6776 93709 37218 255636 A-15 P-4 at..e52 7A8LE F-2 RESULTS OF WSP NDEL 8Au 2 Reduced Load Forcast, modif led data, World 8Mn fumt prices ..-mu capcity, »j sant out.•• ---Present values of cah f tom, UM8, 000... Ter CosM Lom speed Gas Const- Saves,. ~Oerating Energy Lap Steam Oleset Turbin* Total ruction vatue cost unserved Total 2 ..... ..... .... .. . ..... .... .... .... ... . ....... 1991 91395 618 92013 0.26 1992 684 1035 76719 0.46 1993 33 33 1595 -1207 685 530 80753 0.27 1994 20 20 19930 -188 61293 313 7%98 0.18 1995 20 20 17795 .1972 56235 313 72371 0.20 19% 33 33 11349 •1494 54253 216 64324 0.16 1997 61 61 84272 -15950 46822 187 115331 0.07 1998 61 61 36105 -7737 40665 424 69457 0.34 1999 61 61 32236 -7811 35949 464 60838 0.41 2000 61. 61 28783 -7878 31622 474 53001 0.46 2001 20 20 9015 -2521 28828 322 35644 0.35 2002 61 61 22946 -7991 25131 428 4051 0.52 2003 33 33 5134 -1882 23523 192 26967 0.27 2004 0 0 0 217% 280 22076 0.43 2005 20 20 5729 -2726 19851 197 23051 0.35 2006 61 20 81 18915 -10493 17581 143 26146 0.29 2007 0 0 0 16458 246 16704 0.53 2008 20 20 4078 -2829 15220 206 16675 0.50 2009 20 20 3641 -2857 14016 165 14965 0.45 2010 20 20 4687 -4163 12734 111 13369 0.34 Total 366 160 99 625 320560 -81349 754541 6864 1000616 mOt8: Salvage (or residuat) vatue Is st the end of yGar 2010 and relates to the plant Installed In ach satated y@ar Energy unserved is the cnergy not supplied, valued at US 1.Skum LGLP Is the Loss of Load Probablity and Is the tage of the year that the generating plant Is estimatd to be to to meet the load, le there will be oad sheddIng duae to unavalabillty of generating plant Construction costa Includes Interest during construction The WSP output in respect of construction costs and salvage values has been corrected to take account of the carty stte establishimnt costs of the coat station A-16 lp-s TABLE F-2 Continund RESULTS 0F VAFP N®EL BASE 2 Roduced Lad forecast, modiffed data, World Bank fucl prices --•••••••••CasIFIowsJ1S8,000-•••••••••.-- Existing New total MaxINm Reserve 1 ••• • •••••••Fuct--.•••••••••.I Operation capacity cpacity capcity emnd Invetlt and Year Kw MU MW Kw % of HD Costa Cool NF0 No6 Diesel Total mainto'c Tota& 1991 526 526 345 52 72424 8378 80802 16575 97377 1992 526 526 359 47 6833 9522 73355 17580 90935 1993 526 33 559 372 50 21600 59205 10665 69870 17768 109238 1994 526 53 579 382 52 31000 63163 9334 72497 19101 122598 1995 508 73 581 392 48 31000 63732 10209 73941 20226 125167 1996 491 106 597 398 50 21600 65775 15614 81389 20201 123190 1997 471 167 638 407 57 193700 8126 62088 6795 77009 20959 291668 1998 377 228 605 416 45 93000 16172 53891 4223 74286 21844 189130 1999 319 289 608 427 42 93000 24059 43741 4980 72780 22635 188415 2000 267 350 617 439 41 93000 31808 33434 5520 70762, 23433 187195 2001 267 370 637 451 41 31000 31996 34954 4537 71487 24326 126813 2002 202 431 633 463 37 93000 39422 23278 5991 68691 25400 187091 2003 202 464 666 477 40 21600 40111 24253 8159 72523 25256 119379 2004 202 464 666 489 36 40659 24762 10324 75745 26198 101943 2003 202 484 686 502 37 31000 4084 26785 889 76495 27193 134688 2006 136 565 701 518 35 93000 47925 18038 8399 74362 28305 19567 2007 136 565 701 534 31 48530 18672 11447 78649 29720 108369 2008 136 585 721 551 31 31000 48711 21439 10944 8104 31002 143096 2009 136 605 741 567 31 31000 48841 24232 10154 83227 32815 147042 2010 136 625 761 583 31 31000 48864 26372 8722 83958 33119 148077 A-17 F-6 al*..n6 TABLE F-3 RESULTS OF WASP NODEL BASE 2A Reduced Load Forecast, modif led data, World Bank fuel prices Coat price profile same as for oit *****NOw capacity, MU sent out -**Present values of cash flos, USM, 000--- Year Coat Low speed Gas Const- Salvage Operating Energy LOLP Steem Oieset Turbine Total ruction value cost unserved Total I 1991 91395 618 92013 0.26 1992 75684 1035 76719 0.46 1993 33 33 15945 -1207 65485 530 80753 0.27 1994 20 20 19930 -1838 61293 313 79698 0.18 1995 20 20 17795 -1972 56235 313 72371 0.20 1996 33 33 11349 -1494 54253 216 66324 0.16 1997 61 61 84272 -15950 46396 187 114905 0.07 1998 61 61 36105 -7737 40019 424 68811 0.34 1999 61 61 32236 -7811 35405 464 60294 0.41 2000 61 61 28783 -7878 31260 474 52639 0.46 2001 20 20 9015 -2521 28360 322 35176 0.35 2002 61 61 22946 -7991 24480 428 39863 0.52 2003 33 33 5134 -1882 22890 192 26334 0.27 2004 0 0 0 21112 280 21392 0.43 2005 20 20 5729 -2726 19140 197 22340 0.35 2006 61 20 81 18915 -10493 16911 143 25476 0.29 2007 0 0 0 15852 246 16098 0.53 2008 20 20 4078 -2829 14758 206 16193 0.50 2009 20 20 3641 -2857 13639 165 14588 0.45 2010 20 20 4687 -4163 12397 111 13032 0.34 Total 366 160 99 625 320560 -81349 746944 6864 993019 NOTESs Salvage (or residual) value is at the and of year 2010 and relates to the plant Instalted in each stated year Energy unserved is the energy not supplied, valued at UIS$ 1.5/kNh LOLP is the Loss of Load Probability and is the percentage of the year that the generating plant is estimated to be unable to met the load, fe there will be load shedding due to unwaltability of generating plant Construction costs includes interest during construction The tMiP output in respect of construction costs and salvage values has been corrected to take account of the early site estabishment costs of the coat station A-18 F-7 at..nS4 TABLE F-4 RESULTS Of WASP NWEL SASW 2 Reduced Load Forecast, modified data, World Bank fuel prices Capital cost of coat station increased by 10% *.*.*New capacity, 11 sent out-* ***Present values of cash fous, U1S, 000.* Year Coat LoW Speed Gas Const- Salvage Operating Energy LLP Stem Diesel Turbine Total ruction value cost unserd Total 5 1991 91395 618 92013 0.26 1992 75684 1035 76719 0.46 1993 33 33 15945 -1207 65485 530 80753 0.27 1994 20 20 19930 -1838 61293 313 79698 0.18 1995 20 20 17795 -1972 56235 313 72371 0.20 1996 .20 20 15888 -2091 52827 360 46986 0.16 1997 20 20 14186 *2198 49135 454 615? 0.07 1998 61 33 94 95475 -19928 42396 603 118548 0.34 1999 61 20 81 47354 -11112 36978 296 73516 0.41 2000 61 61 32184 -8809 32579 316 56270 0.46 2001 0 0 0 30075 467 30542 0.35 2002 61 33 94 31407 -10779 26290 169 47087 0.52 2003 0 0 0 24559 278 24837 0.27 2004 20 20 6417 -2683 22300 16? 26221 0.43 2005 0 0 0 20650 291 20941 0.35 2006 61 20 81 21421 -11881 18247 212 27999 0.29 2007 20 20 4567 -2799 16801 169 16738 0.53 2008 20 20 4078 -2829 15542 140 16931 0.50 2009 20 20 3641 -2856 14319 111 15215 0.45 2010 0 1436 -1282 13188 163 13505 0.34 Total 305 200 99 604 331724 *84264 765980 7025 1020465 NOTES: Salvage (or residual) value is at the end of year 2010 and relates to the plant installed in each stated year Energy unserved is the energy not supplied, valued at US 1.5/kh LOLP Is the Loss of Load Probability and is the percentage of the year that the generating plant is estimated to be unable to meet the load, Io there will be toad shedding due to unavalability of generating plant Construction costs includes interest during construction The WASP output In respect of construction costs and salvage values has been corrected to take account of the early site establishment costs of the coat station A-19 V-8 a1. .v64 TAMLE P-5 88UJLI8 0F VAP 18O8L SASE 2C Redced Led Forecast, modif fed data, gorld Sank fuct prices No neu especity befora 1994 .••New Cpeolty, W sent out••••- .••Present values of cash ftos, USS, 000-. var COSt Lemup Gos Const- setvage Operating Energy L0LP otem Dind Turbine Total rustion value cost unservd Total 2 1991 91395 618 92013 0.26 1992 75684 1035 76719 0.46 1993 66334 2033 68369 0.95 1994 40 40 39860 -3677 60178 528 9889 0.30 1995 20 20 17795 -1972 55202 531 71536 0.34 1996 33 33 11349 -1494 52827 360 63042 0.26 1997 61 61 842 2 -15950 45981 130 114433 0.11 1998 61 61 36105 -7737 40109 667 69144 0.52 1999 61 33 94 4015 -920 35468 212 66745 0.20 2000 61 61 28783 -7878 31212 221 52338 0.23 2001 0 0 28828 322 29150 0.35 2002 61 61 22946 -7991 25131 428 40514 0.52 2003 5134 -1882 23523 192 26967 0.27 204 0 0 21796 280 22076 0.43 200 2 5729 2726 1951 197 23051 0.35 2006 61 20 81 18915 -10493 17581 143 26146 0.29 2007 0 0 0 16458 246 1674 0.53 2008 20 20 4078 •2829 15220 206 16675 0.50 2009 20 20 3641 -285? 14016 165 14965 0.4 2010 20 20 4687 -4163 12734 111 13369 0.35 Total 366 160 66 92 323609 -80899 749528 8627 100086 N01IS: Salvep (or restdual) value ts at the end of yar 2010 and reltaes to the Plsant instaed in each stated year Enegy unservd is the ener y not sptiod. valued at t=S 1.5/kWh LOLP is the Len of Load Prebebility and is the rcentage of the year that the gnerating plant is estimted to be * to meet the toad, le there mit be ad Ing dua to ~uvability of generating plant Cnstruction Iosts inluds interest during construction The WEP utput In respect of construction coss and salvage value has been correeted to take account of the early alt# establtishmnt costs of the cost station A-20 P-9 TABLE F-6 RESULTS OF MASP NODEL BASE 2D Reduced Load Forecast, modified data, Vorld Bank fuel prices Combined cycle plant in 1993/94 **********.ew capacity, MW sent out*..... * ***Present values .- cash flows, USS, 000*** Year Coal Combined Low speed Gas Const- Salvage Operating Energy LOLP Steam Cycle Diesel Turbine Total ruction value cost unserved Total % ******.* * *..... ******** ******** ******** ******** ******** ........* ******* ******** ******** *****.** 1991 91395 618 92013 0.26 12 75684 1035 76719 0.46 1993 66 66 31890 *2414 65157 127 94760 0.07 1994 36 36 30830 -3580 61568 305 97123 0.16 1995 0 0 0 57509 645 58154 0.34 1996 33 33 11349 -1494 54694 451 65000 0.27 1997 33 33 10133 *1570 52064 341 60968 0.23 1998 61 33 94 91209 -19014 45765 415 118375 0.31 1999 61 61 32236 -7811 40731 450 65606 0.36 2000 61 61 28783 -7878 34576 452 55933 0.40 2001 61 61 25699 *7938 29422 99 47282 0.11 2002 61 61 22946 -7991 25482 140 40577 0.16 2003 0 0 0 23723 210 23933 0.27 2004 0 0 0 21930 289 22219 0.39 2005 20 20 5729 -2726 19991 207 23201 0.32 2006 61 61 14582 -8153 17803 310 24542 0.52 2007 20 20 4567 -2799 16421 247 18436 0.46 2008 33 33 2913 *2021 15449 132 16473 0.29 2009 0 0 0 14449 207 14656 0.48 2010 20 20 4687 -4163 13107 143 13774 0.38 Total 366 102 60 132 660 325553 -79552 776920 6823 1029744 NOTES: Salvage (or residual) value is at the end of year 2010 and relates to the plant instatted in each stated year Energy unserved Is the energy not supplied, valued at US$ 1.5/kuh LOLP is the Loss of Load Probability and is the percentage of the year that the generating plant is estimated to be unabie to meet the toad, is there will be toad shedding due to unavailability of generating plant Construction costs includes interest during construction The MASP output in respect of construction costs and salvage values has been corrected to take account of the early site establishment costs of the coat station A-21 P-10 al*..o54 TABLE F-7 RESULTS OF UASP PODEL BASE 2 Reduced Load Forecast, modified data, World Bank fuel prices Old Harbour No2 Unit * deferred retirement *****eNw capacity, NW sent out--*** ***Present values of cash f Lows, USs, 000--- Year Cost Low speed Gas Const- Salvage Operating Energy LOLP Steam Diesel Turbine Total ruction value cost unserved Total x ......... ........ ........ ........ ........ ........ ........ ........ ........ ........ 1991 91395 618 92013 0.26 1992 75684 1035 76719 0.46 1993 33 33 15945 -1207 65485 530 80753 0.27 1994 20 20 19930 -1838 61293 313 79698 0.18 1995 20 20 17795 -1972 56235 360 72418 0.20 1996 20 20 15888 -2091 52827 130 66754 0.16 1997 61 61 84272 -15950 45981 667 114970 0.07 1998 61 61 36105 -7737 40109 274 68751 0.34 1999 33 33 8078 *285 38155 282 46230 0.41 2000 61 61 28783 -7878 33642 408 54955 0.46 2001 0 0 C 31005 152 31157 0.35 2002 61 33 94 27815 -9553 27011 244 45517 0.52 2003 0 0 0 25201 280 25481 0.27 2004 61 61 18292 -8081 t*'796 197 32204 0.43 2005 20 20 5729 -2726 19851 143 22997 0.35 2006 61 20 81 18915 *10493 17581 246 26249 0.29 2007 0 0 0 16458 206 16664 0.53 2008 20 20 4078 -2829 15220 165 16634 0.50 2009 20 20 3641 -2857 14016 111 14911 0.45 2010 20 20 4687 -4163 12734 111 13369 0.34 Total 366 160 99 625 309953 -79660 761679 6472 998444 NOTES: Salvage (or residual) value is at the end of year 2010 and relates to the plant installed in each stated year Energy unserved is the energy not supplied, valued at US$ 1.5/kWh LOLP to the Loss of Load Probability and Is the percentage of the year that the generating plant is estimated to be unable to meet the toad, fe there will be load shedding due to unavailability of generating plant Construction costs Includes interest during construction The WASP output in respect of construction costs and salvage values has been corrected to take account of the early site establishment costs of the coat station A-22 IIaS o REPMOCE POR 908ta STUDY OF XURV PUEL OIL A2 POM8R Sa203S 1. The existing power stations at Old Rarbour* Runt's say, and Rockfort, all burn Heavy fuel Oil No 6 from the Petrojam Refinery. The oil is capable of further cracking to leave a lower quality residue (hereafter referred to as Bunker C) . Similar qualities of Bunker C are available on the open market and are used by other industries, eq the bauxite/alumina industry; the price of such oil is lower than that of RO No6. 2. The aim of the Study shall be to assess the consequences for the power stations and for the environment of using a low quality Bunker C unsuitable for further cracking. 3. The study shall cover, but not be limited to, the following matterss a. Comments on the existing H10 No6 and its analysis b. Typical expected analysis and characteristics for a Bunker C fuel whether bought on the open market or after further cracking of UFO No 6 by Petrojam, includings -Viscosity -Gravity -Chemical composition - Va,Na,Mg*Ash,H, U20 and other -Cetane No -Pour point -Calorific value, gross and not c. The effects of using Bunker C on the performance of the burners and boilers at the steam stations and on the Rockfort low speed Diesels. d. The need for fuel treatment and heating in storage and in pipelines. e. An assessment of the changes needed, if any, to storage tanks, pipes, pumps, burners, boilers and other equipment to enable the Bunker C to be burned satisfactorily. f. The environmental effects of changing to Bunker C and measures available to minimise those effects, including emissions of SOx, NOx, ash and unburned carbon. g. The capital and operating costs associated with d to f. h. Recommendations as to the measures which should be taken and their costs. 4. The contractor shall work closely with JPS, Petrojam and the Natural Resources Conservation Authority. JPS and Petrojam will provide analysis facilities, counterpart staff, drawings of equipment and practical experience of operating the power stations. A-23 AKDE NEMOIRE ON PROPOSED PRVAT8 SZCTOR NRO DEVULOPMENT PROJECT (PSED) UETNGS 0 jps CO, MMCC>, ID AND WORLD AMN TAg M WARINTON, 24-25 APRIL 1991 A-25 PROPOSED PRIVATE SECTOR ENERGY DEVELOPMENT PROJECT (PSED) MEETINGS OF JPS CO, SWECO, IDB AND WORLD BANK TEAMS WASHINGTON. 24-25 APRIL 1991 AIDE MEMOIRE 1. As agreed between the Government of Jamaica delegation and World Bank during the meetings of April 17-19, 1991, further meetings took place April 24-25, 1991 among representatives of JPS, SWECO, Inter-American Development Bank and World Bank to discuss the Least Cost Expansion Program (LCEP) and define the units to be included in the prequalification and bidding documents for the first power sub-project of the PSED. This Aide Memoire records the conclusions and recommendations of the team for the approval of the cofinancing partners and the Government of Jamaica. It was agreed that both the World Bank and SWECO final reports would reflect the conclusions of these meetings and that this Aide Memoire would be included in an Annex to the respective reports. 2. The meetings were attended by: (a) 1EM Basil Sutherland, Director Planning Division George Wilson, Sr. Legal Counsel and Corporate Secretary Val Fagan, System Planning Consultant Albert Gordon, Planning Engineer (b) World Bank Joseph Gilling, Sr. Economist, ESMAP (IENPD) Thomas Norris, Power Engineer, ESMAP consultant Kirit Parikh, Power Engineer, PSED Consultant (c) Inter-AmericantDevelopment.Bn Jaime Millan, Prinicipal Economist Valiko Sikirica, Electrical Specialist (d) SWECO (LCEP consultant to JPS) Joran Vedin, Power Engineer, LCEP consultant to JPS 3. Following meetings in Kingston in March 1991, both the SWECO and Bank consultants had carried out further analyses which narrowed the differences between the results obtained using the SWECO and WASP computer programs for analyzing the LCEP options. Revisions to some parameters have been made by both teams based on these discussions and further clarification of certain points. As a result, the two alternative long-term developments proposed by SWECO based on Scenario 01: (the coal steam option), a steam coal plant in 1998 developed in further stages, and Scenario 02: (the no steam option), a combined cycle plant in 1998 followed by low speed diesel units as the base load plants were found to be indistinguishable in terms of present worth of costs. The no steam option was found to be 2% cheaper; however, this difference is well within the error of estimate of the parameters involved. The WASP model analysis showed the coal steam option as being cheaper by 3% with an on-line date of 1997. A-27 Aide Memoire - LCBP Meeting - 2 - 4. Since the alternatives were Indistinguishable on cost grounds, the alternatives were compared on the basis of robustness in the face of risk and uncertalnt. In this respect, the coal station provides a substantial advantage through ftel diversification and protection against the volatility of oil prices, which SWECO agree makes it the preferred choles. S. Having established that the coal fired steam alternative is preferred in the long-term beginning In 1997, the earliest feasible on-line date, the short term options were examined using the SWECO Base load forecast without loss reduction and DSM measures which were taken into account In the WASP-analysis. The SWECO and WASP analyses are in agreement in calling for a nominal 3 x 20 MW low speed Diesels which could be Implemented as a single Build, Own, Operats (B00) project as shown in the Attachment. The first two units would be Installed by December 1993 ani the third in 1994 depending on the annual reviews of load growth and the rate of Implementation of the loss reduction and Demand Side Management (DSM) programs. te timing of the third 20 MW low speed diesel unit should be determined at the option of JPS. This short term programme is confirmed by WASP as being the least cost programme. 6. The value of the loss reduction and DSM are apparent in the deferment of the installation of the diesel units and the elimination of one 33 MW gas turbine unit in 1995. There is, however, considerable uncertainty concerning the feasible rate of implementation of DSM programs since these programs are only now being organized by JPS. The incentive to implement the program is clear in terms of the investment and operating cost saving; however, the meeting participants agreed that it would be prudent to Install the first two units assuming limited DSM benefits with an option kept open to delay the installation of the third 20 MW LSD unit from 1994 to 1995 depending on the results of the DSM program. Decisions concerning the 33 MW gas turbine units in 1995 and 1996 would also be deferred to later dates as feasible. 7. The option of using medium speed Diesels burning high vanadium fuel oil available in Jamaica were reviewed in detail because of the slight cost advantage revealed by the SWECO analysis based on average expected reliability and maintenance costs. Operating experience, however, in the Caribbean region with these units using high vanadium fuel oil derived from Venemelan crude oil has revealed severe difficulties leading to higher than normal forced outage rates and higher maintenance costs than considered by SWECO in its initial analysis. It was therefore agreed that the small economic advantage would not be sufficient to compensate for the uncertainties associated with the medium speed units. 8. The SWECO draft LCEP report includes some medium speed Diesels but by a very small economic margin compared with the all low speed diesel case. Based on the present review, therefore, SWECO agreed to modify the reliability and maintenance costs in light of the regional experience using high Vanadium fuel oil and re-run the analysis. It is expected that these revisions will eliminate medium speed diesels from the LCEP. 9. Following the low speed Diesels, one or two gas turbines in 1995 and 1996 (depending on load growth) are included in the LCEP immediately prior to the coal station in 1997. The planning of these units is not, however, as urgent as the need for planning the coal fired plant. A-28 Aide Memoire - LCZP Meeting - 3 - 10. In view of the discussions and conclusions as outlined above, the meeting participants recommend that: (a) the first BOO project be defined on the basis of three or four low speed diesels totalling 55 *65 MW with the first two units to be Installed by December 1993 and the third andlor 1994 depending on load growth and the success of the DSM and loss reduction programs; (b) the DSM program be vigorously pursued to implement the demonstration projects now beginning and to develop the Institutional capacity to design and implement further DSM components; 8a (c) preparation of the coal fired am plant also as a BOO project should be undertaken with the same urgency as the diesel plants in view of longer planning period required. it. It was agreed that the following next steps are on the critical path for execution of the LCEP: (a) preparation of plans for the nominal 3 x 20 MW low speed diesel units required by December 1993 and during 1994 should proceed urgently in respect of: * site selection - Environmental Impact Assessment (EIA) * procurement procedures on a BOO basis to meet the required Installation dates (b) preparation of plans for the coal-fired steam plant required on line by January 1997 should also proceed urgently in respect of: - site Investigations and confirmation of the selected site - Environmental Impact Assessment * feasibility to Include site layout, harbor facilities, size of units, type of technology, ash disposal, etc. (c) confirmation of the availability of fundings for all studies particularly for the EIA for the coal fired steam plan. J4 G10i )ime Millan Basil Sutherland Jt Vedia World Bank *American JPS Co SWECO Development Bank 26 April, 1991 A-29 Aide Memoire - LCxp Meeting 4- ATTACHMENT AGREE JpS LgASIST EXPNSION PROGAM Required On*le Without DSM or With DSM and Date Loss Reduction Less Reduction 1991 ongoing rehabilitation) 1992 - 93 ) add'I 10 MW + increased reliability and efficiency 1993 December 2 x 20 MW LSD lx2OMWLSD 1994 mid year x 20 MW LSD lx20MWLSD 1995 January Ix 33 MW T lx2OMWLSD 1996 January x 33 MW GT 1 x 33 MW OT 1997 January Ix 61 coal 1 x61 coal 1998 January continuing coal and LSDunits as required for load growth Meeting participants Government of Jamaica Messrs. Clarke, Perkins, Geddes, Mian (MME) Dyer (JPS), Matalon, Black (PCJ) World Bank Mesars./Mmes. Smith, Megatell (LA31); Elwan, Babbar, Baughman, Joshi-Ghani (CFSPS); Menendez (cons) Flood, Hoppenbrower, Thompson (LA3C2); Parry, Hooks, Ifill (CLID2); McKechnle (IENPD); Mashayekhi, Hay (IENOD) Division files; LAC Info Center A-30 VOLUME III PART B ELECTRICITY DEMAND SIDE MANAGEMENT AND INDUSTRIAL ENERGY CONSERVATION STRATEGIES A-31 STRATEGIES FOR ELECTRICITY DEMAND SIDE MANAGMT AND INDUSTRIAL ENERGY CONSERVATION INTRODUC ION .. .......... ................. ................... 1 TARGER AREA 1: DEMVAND SDE MANAGHME1T ........................ I Ehmgy Service Companies .... ..... ............. . .. .... .. I Demand Side Managem ent Costs and Benefits ........................... 3 Pota Capacity and Ee y Savings ........................... 3 IndividualProgram Savings ........ .......................... S AggregateDSM Savings ...... ............................. 7 Economic Evaluation of DSM Programs ............................... 7 Bais of Analysis ................ .. ................... 7 Benditsof DSM Prograns .................................. 9 DailyLoadCharacteristics ................................. 10 Costs of DSM Programs ................................... 12 CasbH Flow ...................................... ..... 15 DSM Priorities.................. .... ....................... 16 Residential Sector DSM Programs ....................... . .. . 16 CostRemveryforSM ................. . ...... ... .... ...... 17 TARGET AREA 2: INDUSRIUAL ENERGY CONSERVATION ................. 18 Targta"k .............................................. 18 Program Benefits .................. .......................... 18 Program Delivery ...... t............................... o... .... 19 Cost Recovery ...................... ........................... 19 ENERGY CONSERVATION PROGRAM DELIVERY: THE ROLE AND ORGAIZATION OF ENERO ................ * .... . ........ . 20 ConceptofENERCO ............ .... .. *.. ........ ... ..... . 20 ENERCO Development Plan ..................................... 21 COpan t En .......................................... 22 CanwAm p ........................................... 23 Calianflma................00..... 0..... ........oo....... 23 ActionPlan orlBNERCO Developen .............................. 23 Phase I - Conceptual Development ............................ 23 Phase B- Approvals and Capitalization ..... ........................... 24 PhaseI-Start-upandProgramDevelopment ..................... 25 Phase IV - Progranm plm aon........... ................. 26 OraLzational Tietable ............................. .... 26 A-33 Lis Of TablS 1. Electricity Consumption 1990 and DSM Program Coverage 2. Savings by Program - Year 2000 3. DSM Power and Energy Savings 4. Avoided Costs with Demand Side Management 5. Trend of Daily Peak Period 6. DSM Costs and Benefits L ofWFjgre 1. DSM Energy and Peak Power Savings 2. Hourly Demand by Rate Class 3. DSM Program Cash Flows 4. Operation of ENERCO 5. ENERCO Organization Timetable Ane=e 1. Analysis of Potential DSM Programs 2. Cost/Benefit Cash Flow Analysis - Low Case 3. Cost/Benefit Cash Flow Analysis - High Case This volume was prepared by Joseph Gilling, Task Manager, basd oan the work carried out together with consultants to ESMAP during several missions to Jamaica to work with e staff of JPS Eergy Conservation Unit and MME. ESM CoU s MiM Brian Kelly, MARBEK Resource Consultants December 1990, March 1991 Fred Gordon, Pacific Energy Associates March 1991 Tom Norris, Ynnedy and DoWan March 1991 Tom Tamblyn, Engineering Interface Ltd. June 1991 Ken Tomlinson, Manager Roddy Ashby, Consultant Ministry of Mining and Enery Karl McKenzie, Director of Energy Conservation Zia Mian, Energy Policy Advisor A-34 STRATEGIES FOR XLECIRIC1TY DEMAND SIDE MANAGEMENT AND INDUSTRIAL ENERGY CONSERVATION INTRODUCTION 1. While the technologies, costs, and benefits for energy conservation are readily Identifiable, the means to realize these benefits are less apparent. This Annex outlines a strategy for energy conservation program delivery which focusses () on electricity demand side management and ladustrial energy efficiency as target areas, (1J) cost recovery issues, and (i) a delivery agency, tentatively named ENERCO. All aspects of this srategy emphasize the development of programs that can be implemented to largely through ENERCO as a joint private sector/JPS entrepreneurial venture. TARGET AREA 1: DEMAND SIDE MANAGEMENT 2. Until recently, the power sector has generally focused on expanding power supply, and given little attention to the benefits of reducing consumption. In North America, this view has been modified, mainly through regulatory reforms which, in the absence of tariffs which reflect the full cost of supply expansion, have made it cheaper for public utilities themselves to Invest in energy conservation equipment on the demand side rather than expand supply to meet the same end-use need. As a result, many North American utilities have established demand-side management programs and energy service companies have been created to perform energy audits, install conservation equipment, and pay investment costs out of the savings which are shared with the consumer. Energy Service Companies 3. In North America and to some extent Europe, a variety of Energy Service Companies (ESCOs) have evolved to provide a package of services that overcome many of the barriers faced by consumers (Vol. I, paras. 5.3-5.9). These companies typically provide a combination of audits, financing, project management, monitoring and ongoing equipment maintenance and recover their costs plus a profit by sharing, in one fashion or another, in the stream of savings that rtsult from the conservation project. While the principle has been shown to be sound and the contribution of ESCOs to energy conservation is growing, experience over the past two decades has taught that ESCOs must have: (a) strong financial, technical and managerial skills (b) access to debt financing (c) sufficient capitalization to accommodate payback periods in the 3-5 year range. In the absence of these attributes, there has been a tendency in some quarters to "cream skim," that is A-35 Lnergy conservation *2- Sumnary to finance only the most attractive options In a building in order to minimize payback periods. UtUlit- owned ESCOs or ESCOs Involved in utility demand-side bidding appear to have the corporate financial strength and longer term mission to achiove most of the cost-effective savings In a building. 4. Electric utilitieshavetdonallydeveloped and delivered their demand side management programs through their existing corporate structure. his delivery method, however, has led to several problems In North American utilities: (a) DSM progas are often conceived by planning staff and Implemented by field personnel. Communications problems have developed and program changes result in confusion for planners, field staff, and customers alike. (b) Administration costs grow significantly for mass market DSM programs involving a staff to process the high volume of applications. Customers perceive bureaucratic delays and slow turnaround as disincentives to working with the utility. (c) DSM programs attract a large number of "free riders" who apply for incentives and rebates even though they would do the retrofit measures if left to their own resources andlor with the assistance of energy service specialists. (d) The verification of DSM program savings such as in residential lighting is very difficult since the savinp are often estimated a ae based on energy calculations rather than actual a . Verification upon program completion would require even more administration and overhead. 5. The ENERCO concept discussed in detail in paras. 40-43 can address many of the problems experienced by North American utilities as discussed above by drawing on the strengths and advantages of both the private sector (entrepreneurship) and JPS (client base and billing mechanism). In order to put the organizational Issues and recommendations into perspective, the size and nature of the DSM market is first presented in this Annex through an analysis of the associated costs and benefits of achieving demand side savings. 6. Given the growing but untried market In Jamaica for DSM programs, i is MMended that ENERCO be develooed as a int private sector and utility-based (PS) company rather than attem g to establish an eirey Rie sur rise. Initially, this company could be an extension of JPS' Energy Conservation Unit, but would be spun off as rapidly as possible as an independent subsidiary in order to develop an entrepreneurial culture with the firm. Eventually ENERCO could have a mjority private sector ownership but should maintain operational links with JPS. The potential savings of DSM programs, the role of ENERCO in those programs, and ENERCO's organization and operation, are discussed b.ow. A-36 Energy Conservation -3- Summary Demand Side Managanent Costs and benefits PBtentia Capait and BaeWySaing 7. To assess the potential for demand side savings, ESSIPS analyzed the eight DSM measures that were the basis of the Conservation Law Foundation report Power by Jiciency (June 1990). CLF Identified and analyzed eight program concepts summarized as follows: 1. Reldential Lghtlng Program Assistance to Jamaican manufacturers to produce more efficlient fluorescent lights and the direct installation of compact fluorescent lights for 'esidential customers. 2. Reidential Water Heating Program Conversion of electric water heaters to solar through support payments to manufacturers and lease-to-buy plans for consumers as well as direct installation of insulating blankets on electric water heaters. 3. Residential Refrigeration Program Financial support to Jamaican manufacturers to improve refrigerator efficiencies and application of higher taxes on inefficient models. New refrigerators would meet US standards within five years and best available standards in ten years. 4. ResIdential/Small Commercial/Industrial Air Conditioning Program Program similar to the residential refrigeration program. S. Commercial/Industrial New Construction Program Design and financial assistance to architects, engineers, and building owners to Increase building energy efficiency beyond the minimum standard established in the Energy Efficiency Building Code. 6. Small Commerdal/Small Industrial Direct Installation program Direct Installation of efficient equipment in commercial buildings of less than 10,000 sq. ft. 7. Large Commercial/Medlum Industrial Retrofit Program Energy audits and retrofits combined with financial incentives for large commercial/medium industrial customers (greater than 10,000 sq ft). 8. Large Industry Retrofit Program Energy audits and retrofits involving process engineering otherwise similar to the large commercial program. A-37 Energy Conservation -4- Summary 8. The eight programs were targeted at all end use sectors whose consumption pattern in 1990 is estimated to be broken down as shown In Table 1. Table 1 ELECTRICITY CONOMPTION 1990 AND DSN PROGRAM COVERAGE Sector/End*Use Estimated % Sector % Total Program 1990 t Use Use Coverage RESIDENTIAL Lighting 93,11? 195 Program I Water Heating 42,435 8X Program 2 Refrigeration 151,647 30% Program 3 Cooling 85,136 17 Program 4 Other 129,032 26% Total 501,367 100% 33% SMALL COISERCIAL & INDUSTRIAL Lighting 49,000 25% Program 6 Cooling 98,000 50 Program 4 Refrigeration, 49,000 25% Program 6 Water Heating, Other Total 196,000 10O 131 NEt CONSTRUCTION Att Users 16,000 100 1K Program 5 LARGE COMMERCIAL & INEDItM INDUSTRIAL Lighting 139,500 25% Program 7 CootIng 279,000 50 Program 7 Refrigeration, 139,500 25% Program 7 Water Heating, Other Total 558.000 100 37 LARGE INDUSTRIAL Cogeneration 38,000 39% program 8 Conservation 59,000 61% Program 8 Total 97,000 100K 6% OTHER Public Lighting 129,000 100% 9% TOTAL 1,497,367 100 Soum.: Powr by Jfficieny, ConsevadonLaw Foundedon, June 1990. A-38 Energy Conservation -5- summary 9. The DSM programs and potential savings were evaluated by CLF In terms of energy savings and associated peak capacity savings. The potential energy savings estimated by CLF - about 20 - 25% of projected total consumption, equivalent 1,500 GWh of total consumption In 1990 - were judged by the ESSIPS mission as being overly optimistic in terms of penetration rates and ultimate level of savings. The mission therefore critically examined the basic assumptions for each program and made Independent estimates of the DSM potential assuming also a reduced level of Incentives with the result that the savings which might be realistically achieved by 2000 range from 5% in the low/pessimistic case to 13% in the highloptimistic case. IndHvidual Pro&am an 10. The ESSIPS analysis took into account the economic and financial viability of each measure, the lead time for pilot testing and development, the necessary delivery infrastructure, the total number of customers involved (fewer customers, easier delivery), customer participation, program delivery rates, and possible risks. Given the many uncertainties of designing and Implementing a new program, estimates were deliberately conservative even In the optimistic case, particularly in terms of the penetration that could be achieved in the early years. The analyses of individual programs are shown in detail in Annex I and are summarized for the year 2000 In Table 2. A-39 Bnergy Conservadon -6- summary Table 2 Savings by Proaram - Year 2000 Program ligh cas Low Cam GWh Peak MW GWh Peak MW 1. Residential Lighting 25.2 20.7 11.9 9.8 Program ,2. Residential Water Heating 18.4 2.8 2.0 0.3 Program 3. Residential Refrigeration 53.0 6.0 20.5 2.3 Program 4. Residential Small 73.8 12.6 41.5 7.1 Commercial/Industrial Air Conditioning Program 5. Commercial/Industrial 43.5 4.0 25.4 2.3 New Construction 6. Small Commercial/Small * 31.9 3.3 8.1 0.8 Industrial Direct installation Program 7. Large 145.0 13.6 16.3 1.5 Commercial/Medium IndustrialRetrofitProgram 8. Large Industrial Retrofit 221 Program TOTAL 418 67 140 26 Source: ESSIPS mission estimate. A-40 Energy Conservation -7- Summlary Asarmat DSM Sana 11. The aggregate energy and peak load capacity savings for all DSM programs for three years (1995, 2000, and 2010) is shown below in Table 3 and graphically in Figure 1. The average of the high and low, the mid case, was used to estmate the avoided costs of energy and peak demand (capacity) as part of the evaluation of the power sector Least Cost Expansion Program (para. 14). Table 3 DSM Power and Enery Savings High Case Low Case Hid Case Saving % of Fest' Saving % of Fast' Saving % of rest' Year 1995 *nergy (GIh) 156 6% 56 2% 106 4% *Peak (NW) 28 6 12 3% 20 5% Year 2000 *Energy 414 13% 140 4% 279 82 *Peak (I)' 75 15% 28 5% 47 92 Year 2010 * Energy 631 14% 224 5% 427 10% *Peak (M)1 93 14 36 5% 65 95 Notess 1. Percentage reduction from SECO base demand forecast Table 7.2. 2. Based on an assmed evening peak 6-10 PN Economic Evaluation of DSM Programs Basis of Analysis 12. In order to examine the economic viability of the proposed set of DSM programs, a benefiticost analysis was undertaken. This analysis was undertaken from a national economic perspective based on the eight program concepts developed by CLF (para. 7) as modified by the ESSIPS mission. Taxes and duties were excluded from both the cost of energy efficiency measures and the cost of power generation to assess the costs and benefits of the DSM programs. Unless the distortion between the cost of energy saving and energy consumption can be reduced by further reduction of CET and GCT to end-use equipment or the.GCT is applied to electricity sales as part of the tariff, it is roughly estimated that the program penetration rates and, hence, the DSM savings in capacity and energy would be cut by one-third to one-half. A-41 * Enrgy Conservadlon -8 - Figure 1 DSM Energy and Peak Power Savings ENERGY SAVINGS 680 •M ~ NCA E emoe ik lik a4 iå iik a- ;k ;å; YEAR PEAKSAVINGS esfl fl f6lCA ie A-42 EAergy Conservadon -9- summary 13. Details of the DSM costs and benefits are presented in Annex 1 and summarized in Table 6. Both the high and low cases indicate a strong economic justification for DSM programs, since they have, respectively, overall IERRs of 35% and 27%, and benefit/cost ratios of 1.5 and 1.3. The internal rates of return are significant compared with the 12% discount rate, which is used to assess the economic ftasiblity of Jamaica's public sector Investment programs. bm ofDM.ms 14. DSM programs lead to savings in () energy (kWh) and/or (ii) generating capacity (kW). Capacity savings i.e. by avoiding or deferring the need to install additional generating capacity will occur if the reduced energy demand occurs during the peak generating period. For example, the substitution of 15 W compact fluorescent lamps giving the same light level as 60 W incandescent lamps would save both power (45 Wilamp) and energy (45 Wh/lamp for each hour of use). Normally used during the peak period. Shifting loads such as airconditioning from the peak to the off peak period by using thermal cold storage equipment would result in a capacity saving and reduced energy costs. 15. The unit energy and capacity avoided cost savings were estimated as part of the power sector Least Cost Expansion Program (LCEP) analysis (Vol. H-A). Capacity benefits were calculated as the avoided capital costs of generation between the LCEP with and without DSM, based on the long- term expansion program to 2010. Energy costs on peak and off peak were assessed on an annual basis according to marginal fbel costs. On-peak energy costs are higher than off-peak costs because of the need to operate high fNel cost gas turbines and older less efficient generating plant. Estimated avoided capacity and energy costs mociated with DSM are shown In Table 4. The difference in energy costs after 1997 is due to the introduction of base-load coal fired plant. 16. Note that while the DSM potential analysis included cogeneration and absorptive cooling technologies In Program 8, Large Industrial Retrofit, they were excluded from the cost/benefit analysis because of the uncertain estimates of the costs and benefits. A-43 Eergy Conservation - 10- Summary Table 4 Avoided Costs with Demand Side Management Capacity Coste On-peak Energy Off-peak Energy USS/kWvt us/ USm- ets/W 1991 - 1997 157 7.0 4.0 1998-2010 17 6.0 1.8 Notes: 1. Based on capital cost savings associated with the mid-case level of DSM peak power savings (Table 3). 2. Reduction in energy cost In 1997 due to the introduction of coal-fired plant. Dil Loa& haatritc 17. FIgure 2 shows the hourly variation in demand by rate class based on an analysis of 1986 data. Commercial and industrial loads (C&I, R20 and R40) are predominantly day time loads with a fairly fat peak from 0900-1500 hrs and a sharp drop after 1900 brs for 120 to about half the peak load while R40 loads drop only to about two-thirds of peak. Residential loads (R10) increase by about half the day time level to peak In the evening around 1900 bs. These load patterns need to be re-examined with regard to both magnitude and trend; however, the variation in contribution to daily peak is apparent. Dpending on the trend of the occurrence of the daily peak as shown in Table 5, differentDSM programs will have different avoided costs which could be affected by the results of complementary DSM progrms. * C4p=cfy and enery cos meured at the h(gh akage level on an asstw oabass alowig jbr 1%!kw at r V Far*er losen of 2% and 8% cree the avoided capacq y cosanso US$175, and US$200AW-yr at the MV and LV leek, respectlvy. A44 70 60- 0 50- 40 30 20 lo. 10- o- 1 3 5 7 il 13 15 17 19 21 23 HOURS 0 RIO + R20 9 R40 å R50 X R60 Source: JPS Tariff Study, 1986 Energy Conservation - 12- summary Table 5 Trnd of Daily Peak Period 1984 1985 1986 1987 1988 Jan-Jun 1989 Daytime Peak (MW) 246 240 264 268 303 305 0800 - 1800 hours Evening Peak (MW) 219 215 258 286 295 314 1800 - 2200 hours Evening Peak as Percentage of Daytime Peak 89% 90% 98% 107% 97% 103% Source: JPS Electricity Tariff Study, Fnal Report; RCG/Haglar, Bailly, Dec. 1989. Costs of DSM ProgrMs 18. Cost estimates for each DSM program include (i) investment costs for installed equipment and technology and (11) program administration and marketing. The investment costs were estimated as the Incremental Installed capital cost of efficiency equipment (without duties and taxes) compared to the non- efficient alternative. In some cases, actual incremental costs of individual technologies were used (e.g., compact fluorescent lamps). For retrofit programs, the investment cost is repeated after one lifecycle of the equipment (conservatively estimated at 9 or 10 years). 19. Cost estimates for each DSM program were prepared for each technology and each level of savings (high and low cases). In several instances, cost estimates were made for a specific DSM measure, on the assumption that the participant would accept a maximum two-year payback. In the absence of more detailed information, and pending the results of pilot programs now underway. in Jamaica, the costs and benefits associated with retrofit programs were based on a two-year payback. With more aggressive marketing and with greater acceptance of DSM measures as a long-term investment, however, it may be possible to include programs with paybacks of 3-5 years. Such programs are common in other countries. 20. In nearly all cases, the program administration and marketing costs (including energy audits where applicable) were assumed to amount to an additional 20% of the investment costs. For retrofit programs, the program administration and marketing costs are not repeated for the second round of equipment. Details of the various costing assumptions and calculations are found in Annex 1. It should be cautioned that the cost estimates for DSM are very preliminary. More detailed information will only become available once the results of the pilot programs (para. 52) now under way are analyzed. A-46 Energy Conservation - 13 - Summasy 21. Based on the emerging predominance of the evening peak, estimates of DSM benefits to commercial and industrial programs, shown in Table 6, assume that only 30% of the total load reduction would translate into reduced peak load. These estimates would be very conservative if the system peaks were to occur during working hours, with air conditioning and lighting loads adding to the burden. A-47 E~ugy Conservadon -14- Table 6 pv pv WC ERR PV PV 80 InR ___________ . (J million) .($ millon> -J$ million) ~Jmillion) 1. Reidentl ~ 177.3 98.0 1.8 48. 79.8 4.1 1.9 41.8% 2. RsidtialWate 68.7 59.9 1.1 1 5.6 0.6 8.8 NA Hting 3. Rsidential 115.8 107.2 1.1 16.5 46.5 41.3 1.1 16.8% Refgaln_ _--- - 4. sid 248.4 137.8 1.8 48. 98.5 99.1 1.0 9. C8i Air CEgLl - 5. New Commerolat 0.7 32.3 1.9 48. 47.9 27.1 1.8 45.2% n ral Constucion_ & Sma Commercal/ 65.8 24.9 2.6 NIA 18.3 7.4 2.2 WA Smallindustrial 7. LargsComnu la 110.7 110.0 1.0 12.3 34.2 27.4 1.2 28.3% Medium industrial 8. L. Industral 61.2 28.3 2.2 70. 25.1 19.4 1.3 TOTAL PROGRAM 908.7 598.3 1.5 35 350.8 26.4 1.3 26.8 Not: Prsnt values at January 1991 IERR u Intemal economio rute of returm D~scount Rate a 12 per«ent P a present value 80 - bensl~lcoot CMl- Comiercial and Industrial A-48 Energy Conserva0on - 15- Summy 22. The projected cash flow for benefits, costs and net'benefits of the package of eight programs are Illustrated in Figur 3. This shows that for a period of 5 years the set of programs will Incur a negative cash flow. Tis is to be expected as costs are incurred each year but bene~ts accrue and build over time with an average payback period for each investment in the 2 to 4 year range. However, in contrast to an investment In new power plants, DSM programs produce a rapid payback and major net benefits la a relatively short time. In order to minmize the period of negative cab flow, both to the country and to te delivery agency (BNBRCO), consideratIon could be given to staging the programs so as to lead with the most economically attractive program first ad to bring in the longer-term programs somewhat later when they can be buoyed by the tlow of beneffts from the initial program. Figure 3 DSM Program Cash Flows LOW CASE 2 - v- YEAR HNON CASE YEAR A-49 Energy Conservation * 16- Summary DSM Priorities 23. Due to uncertainties on both the savings and costs of the DSM measures in Jamalca, it is premature to draw firm conclusions regarding the economic or financial viability of individual programs or technologies. The results of the economic analysis are reliable enough, however, to indicate the general attractiveness of an overall DSM program, but precise selection of technologies, program approaches and financing mechanisms must necessarily require further analysis. Because the DSM pilot programs (para. 52) are in their early stages, priorities based on the evaluation of Individual programs must be regarded as indicative. The shift in daily load pattern from daytime to evening peak (Table 5), if it continues, will give greater value to a residential lighting program, since such a program will yield both energy and peak load benefits. Success in this area could shift the peak back to the afternoon, which will result in both peak reduction and energy benefits to commercial and Industrial programs. 24. Based on the foregoing preliminary analysis, it is recommended that DSM programs give priority In the following order to: (a) new commercial and industrial buildings with a benefit/cost ratio of 1.8, since the EEBC is in place, and benefits from initial design will be long-lasting; (b) residential lighting programs, since the benefit/cost ratio is on the order of 2, and various marketing strategies can be used to Increase penetration; (c) commercial and Industrial lighting programs; (d) commercial and Industrial retrofit programs other than lighting, requiring detailed energy audits, engineering design, and financial intermediation; and (e) solar water heating, which requires further cost reduction and financial intermediationto make it attractive to most consumers. ReWSinta SeOr DSM PrgM s 25. Regarding the residential sector, where aggregate savings could be about one-third of total DSM savings (3% of total JPS sales in 2000 based on the mid range DSM case) of total JPS sales and where savings opportunities per customer may be high In percentage torms but relatively small in absolute terms compared with individual industrial and commercial customers, it may be necessary to find creative ways to deliver DSM. As the largest potential savings are in lighting, an approach similar to that of power companies in the United States may be considered: i.e. offering rebates for the installation of compact fluorescent lamps, or undertaking direct installation programs at nominal cost to consumers with cost recovery through JPS billing. With a 0% GCT rate on compact fluorescent lamps, market penetration is expected to accelerate. Nnetheless, as with DSM programs for other sectors, the means of optimum delivery to the residential sector will be determined during the business planning study to be carried out for ENERCO. A-50 Energy Conservation - 17- Summy Cost Recovery for DSM 26. There is considerable debate concerning the extent to which DSM measures should be promoted by electricity corporations. A rigorous application of economic theory leads to the conclusion that If "the prices are right," I.e. If power tariffs fully reflect costs and if there are no significant distortions In the pricing of other goods and services, then consumers should be left to make their own choices concerning the adoption of energy-efficient equipment. The role of government in this case should be confined to the macro policy issues as discussed in Vol. I, para. 2.36, and to ensuring that consumers are sufficiently informed to make rational decisions. The argument continues that if distortions do exist in pricing then interventions In favor of DSM would create further distortions and that energy conservation programs can be regarded as second best solutions. 27. In practice, however, much consumer reluctance to adopt energy efficient measures arises from a difficulty in their financing rather than a lack of appreciation of the economic benefits. One cannot assume, then, that the non-adoption of energy conservation measures is based entirely on an economic choice in favor of other commodities. Consumer financing is often provided by the supplier for a number of goods Including electrical appliances through lease options, hire-purchase arrangements, etc. To overcome financing problem for DSM programs, power utilities in the United States in many cases have been permitted by their regulating authorities to finance such measures on behalf of customers as a power company investment to be included in the fixed-asset rate base for tariff setting purposes. 28. As with other power sector investments, investments in DSM measures should first be economically justified as part of the overall least-cost end-A supply strategy. Least cost planning should not stop at the point of supply but should also consider the least cost means of providing the end-use service such as lighting or cooling. The financing and cost recovery for the end-use equipment then become the key issues to be resolved. Recovery through general tariffs of the costs of DSM programs which directly benefit individual customers would not be justified on either economic or social grounds. Low-income customers would most certainly and quite rightly object to paying for measures which provide the greatest savings to high income consumers. It is important, therefore, to link the cost recovery mechanism as directly as possible to the beneficiary to avoid objections from non-beneficiaries. The ability of JPS to identify potential customers for DMS programs through its billing records, the availability of a credit history, and the direct means of cost recovery through monthly bills, provides a major opportunity for devising the financing programs best suited to the DSM measure and the consumer category. 29. On the other hand, experience of service companies and utilities in USA Indicates that for many conservation measures, significant penetration and avoidance of cream skimming can only be achieved if the utility directly invests in the conservation measures and recovers the costs through the I ena saming rers to the energy service company practice of undertakint only the most profitable measures, and gnoring lss profitable but noetheless aconomae meares which should be part of a conprehensve DSM butasaation. A-51 Energy Conservation - 18- summary general electricity tariff. This approach may be appropriate for Jamaica when the willingness to pay of large consumers has been tapped to the greatest extent possible. 30. The recommended strategy for DSM Implementation should, therefore, consider the cost recovery mechanism and. give priority to projects which offer a combination of (1) high economic viability, (ll) ease of implementatio, and (il) financability and cost recovery. These considerations have been taken into account In recommending the priorities In paras. 23-24. TARGET AREA 2: INDUSTRIAL ENERGY CONSERVATION Target Market 31. Oil-fired bollers are used In heavy industry (particulany bauxite) to generate electricity and process steam. In lighter industry (particularly food processing plants), boilers are used to generate process steam, and In the Institutional sector (hotels, hospitals, etc.) to provide steam and domestic hot water. The boilers are fired by heavy fuel oil (especially in large Industry), and by kerosene and diesel oil in smaller Installations. In some cases. LPG may also be used for domestic water heating. Ol-fired industrial use In the non-bauxite sector accounts for 15% of total ftel oil consumption, and it is estimated that savings from 10-20% are economically achievable. 32. Under the USAID program in the mid 80s, more than 100 energy audits were undertaken in public and private sector facilities. Many of these Involved boiler efficlency testing and the identification of a range of corrections Including: (a) tuning for maximum combustion efficiency; (b) no costilow cost measures involving boiler cleaning and maintenance, steam trap and steam line repair, etc.; (c) fuel switching from diesel to heavy fuel oil; (d) higher cost measures such as Insulation, combustion air preheating, heat recovery, and boiler replacement. Program Benefits 33. Overall it was found that eficiency testing, tuning, and no cost/low cost measures alone could reduce fuel use by about 10% at very little cost, and a considerable amount of this was performed during the program. The higher-cost retrofit measures were also financially attractive but relatively few were carded out, due to poor financing polbillties. A-52 Baergy Conservation - 19- Summary 34. However, the no cost/low cost measures are not one-time actions; they require repeated application. Since the termination of the USAID project, the energy auditors involved report very little activity In terms of regular efficiency testing, tuning, and maintenance. Therefore It is expected that a significant potential for energy savings exists in the boiler population and, therefore, that a repetition of a boiler efficiency program Is warranted. Program DelIery 35. Currently in Jamaica, all boiler owners are required to have annual safety inspections on their equipment in order to satisfy the licensing regulations of the Factories Inspectorate, Ministry of Labour. In addition, such safety Inspections may be required for insurance purposes and by food industry inspectors. These annual inspections, which do not at this time include an efficiency component, are carried out by a group of 29 certified private sector boiler inspectors who each have a clientele and are paid directly by the boiler owners for this inspection service. Where warranted, a certificate of boiler safety Is issued by the inspector, which allows the owner to maintain his boiler operating license. Unfortunately, an integrated database of all boilers in Jamaica does not presently exist at the Ministry of Labour. 36. There appears to be an opportunity to "piggyback" a renewed boiler efficiency testing service on the annual safety inspection program. This service would involve training the safety inspectors, where necessary, to carry out: (a) a combustion efficincy test, (b) combustion tuning for optimum efficiency, (c) a maintenance review and identification of no cost/low cost measures. Cost Recovery 37. In order to persuade boiler owners to opt for this add*donal service, it would be necessary to either promote it heavily or to subsidize the inspectors for, say, the first year, as a demonstration project. The cost of the efficiency Inspection would be small, involving only an additional hour or two of an inspector's time once on site. In order to tie the efficiency inspection into a larger retrofit program, it is proposed that the Inspectors should also "market* to their clients a full energy audit that would be provided through ENERCO. 38. Since the vast majority of Industries and commercial facilities which use petroleum fuels also use IPS supplied electricity, ENERCO should offer to owners an energy audit covering all end-uses and a project financing package that would include boiler retrofit, measures to reduce steam and hot water use as well as electricity conservation measures. The cost of the oil conservation measures would be recovered in full over an extended period on a shared savings basis on the JPS bill or on a separate bill A-53 Energy Conservation -20- Summary for non-electricity services if necessary. In those few cases where a large industry may not be a JPS customer, a separate contractual arrangements would be made. 39. The safety inspectors offering the additional efficiency inspection would in effect be acting as agents of ENERCO to both deliver the efficiency testing service and to market a fuller energy audit. ENERCO would hire these inspectors, provide necessary training, and pay for the efficiency inspection service for a period of time. These inspectors would form part of the private sector infrastructure through which ENERCO would work. ENERGY CONSERVATION PROGRAM DELIVERY: THE ROLE AND ORGANIZATION OF ENERCO Concept of ENERCO 40. An institutional structure is needed for the detailed design and implementation of the energy conservation programs. The following section outlines how ENERCO as the primary delivery agency would be organized. The ENERCO concept is based both on (1) the model of Energy Service Companies (ESCOs) In North America and Europe, and on (i) the existing JPS subsidiary which operates the Rural Electrification Program. The Rural Electrification Subsidiary accesses IDB financing on behalf of new off-grid customers and recovers line extension costs over time through JPS billing. Like other ESCOs, ENERCO would provide a combination of audits, financing, project management, monitoring, and equipment maintenance, and would recover its costs from the savings that result from the conservation project. It would be an entrepreneurial venture with operational links to JPS as shown in Figure 4 and would contract out for specialist services as much as possible. 41. The ENERCO concept has been developed and discussed with a number of officials in Jamaica during the course of the ESSIP Study, and both MME an JPS have expressed their support in principle. GIZ and ESMAP are currently providing technical assistance for the conceptual and business planning for ENERCO which is now underway in JPS on the basis of the following corporate mission statement "To develop and deliver energy conservation projects and programs for Jamaican energy users based on sustained economic and environmental benefits.* A-54 Energy Conservadon -21. Sunnnary OpeR~EION OF ENfRCO Jammica Public service Co. .............. ...y .............. $ Internal/Local ..... Loan Funda $8 $t4 ..JP8 Investment t a * : ** 3 8 8 -8- ENERCO 3..: 8 4 ...........8 8 8 4--custommr . Training 8 Repayment . Management 8 on JPS . Services a sill . Monitoring 3 3 8 8 LE.. Equip. 8 $ :$ . Foreign 8 8 ------- 8 Vs . Local * .. .. .. .. .. . .....v .. .. . . ............... .4 $: 3 TV - T A 8 :$ 1:$ j:S :$ $: a Contractor Contractor 3 1 Contractor 3 Contractor 3 Audit 2 Audit 4 8 Installation Installation 8 3 Energy Services . Audits ---. Equipment 8 . Installation . Maintenance 3 V 3 CUSTOMER - 8 8 3 v s.....: A55 Energy Conservation -22 - Sumnary 42. Although by implication the mission statement could cover biomass fuels and substitutes such as kerosene, it Is not so Intended. Rather, ENERCO would focus on electricity and petroleum fuels used in the Industrial, commercial, and residential sectors. The specification of economic and environmental benefits as part of the corporate mission is Intended to ensure that ENERCO adheres to the GO strategy of Improving national energy efficiency. In other words, ENERCO should not set its corporate mission purely as a commercial venture but should include these broader objectives. Environmental benefits will accrue Inherently with energy conservation through the reduction of petroleum use and the substitution of solar for fossil fuels where economic. 43. In the opinion of the ESMAP consultant and President of a private sector ESCO, the ENERCO concept can address many of the problems experienced by North American utilities (para. 4) in Implementing DSM programs. ENERCO would have several advantages as it would or should: (a) target energy users with a turnkey approach, thereby avoiding most barriers to energy conservation, achieving faster penetration of the large energy user market, and providing the greatest pay-off for all parties; (b) reduce the time spent on administration and overhead, since all efforts would be directed at actual DSM delivery to a targeted clientele; as much as possible, technical services would be contracted out for auditing and equipment Installation; (c) build in technology transfer and training as part of the turney package; (d) qualify for better financing rates than those available to many Individual firms seeking to carry out their own energy conservation projects, by reducing technological and business risk on the strength of its expertise and a viable business plan; (e) minimize *free riders,* since DSM project costs would be recovered through shared savings; (t) have a built-in monitoring of energy savings for all projects, thereby providing a basis for evaluating the overall costs and benefits of the energy conservation programs; and (g) cover all potential energy conservation opportunities in customer buildings, as part of its corporate mission. ENERCO Development Plan 44. ENERCO would be involved in the entire range of activities associated with power sector demand side management and Industrial energy efficiency: A-58 Eergy Conservation -23- summary (a) Program Definition and Management - ENERCO would take the lead in identifying priority markets and programs, establishing audit techniques, and providing standard contract formats. (b) Marketing - ENERCO would undertake marketing for all of the programs Identified In its business plan. (c) Development of Private Sector Delivery Capacity - Through training, monitoring and quality control of its private sector contractors and engineering firms, ENERCO would develop professional energy conservation delivery capability in Jamaica. Initial training costs for auditors and contractors would need to be covered by external ftnding and would not be recovered through normal energy savings contracts with customers. (d) Financial Intermediation - ENERCO would access funding from commercial banks, international funding agencies, and the Private Sector Energy Development Fund on a project or program basis as appropriate. A spread on the borrowing and effective lending rate would cover the operating costs of ENERCO. ENERCO would be responsible for carrying out the energy audit and specifying the equipment, arranging installation and periodic maintenance over the life of the energy service contract ad in effect lease this package to the customer. The leasing costs would be covered by the energy savings. (e) Repayment/Investment Mechanism - Through the regular monthly JPS billings, ENERCO would collect lease installments from its customers for the energy efficiency measures undertaken on their premises. Terms of repayment would be flexible to the extent possible to ensure a positive net cash flow to the customer, i.e., monthly payments would be less than the energy savings achieved. (t) Monitoring and Quality Control - Through the JPS billing records, ENERCO would monitor the energy savings actually achieved. Quality control would be ensured, since ENERCO would be responsible for meeting performance standards under the energy service contract. OrMaizaton 45. In order to minimize costs and encourage entrepreneurial behavior, ENERCO core managerial staff should be kept to about five, comprising the following positions: Managing Director Marketing/Sales Manager Administration Manager secretary Operations Manager A-57 Energy Conservation -24- Summary Depending on the growth In the volume of operatios, additional technical staff would be required in the operations group for both the commissioning of technical measures and the training of customer staff. The operations group would also be accountable for project/program delivery and supervision of contractors (Figure 4). Ownership 46. There is no a priori basis for selecting a specific ratio of private sector/MP ownership. It is proposed then that a 50/50 participation be assumed for planning purposes. The interest of potential private partners Is a more open question. A financial Institution such as a merchant bank would provide access to funding. A more broadly based ownership structure could be achieved by offering participation to other stakeholders such as engineering firms or contractors. Foreign participation from established ESCOs wishing to expand their range of activities may also be possible? Further study is required In the business planning phase to assess the ownership Issues. 47. Whatever the ownership structure, about two years' start-up capital would be required to cover staff salaries and expenses. Funding should be tied to deliverables in the business plan. Project financing should be pre-arranged on the basis of a proforma for each project. Afer the early growth years, ENERCO would reach a steady state revenue position and can be expected to be self funding. Action Plan for ENERCO Development PhaselI- Conceptnal.Development 48. Based on the potential for DSM savings, JPS Energy Conservation Unit with consultant assistance provided by CLF, ESMAP, and GTZ has begun the conceptual development of ENERCO. This Phase is expected to be completed by and September 1991. Step 1- .Definition of Corporate FUctions The six major Corporate roles Identified in para. 44 above need to be elaborated and defined as distinct functions for the corporation. Step 2 - Identification of Relationshis wth lPSIOwnership The Corporate, reporting, legal and financial relationship with JPS need to be explored and defined. This will include the subsidiary relationship, initial capitalization, cost recovery for efficiency investments and definition/monitoring of energy savings. A Wh".eft4as cow*acW = AP 4 .e. m- wors.bee A a geow W n raW d axpressd t M in Janak&. A-58 Energy Conservation -25 - Summary Ste 3 - Oranization and Staffin& Plan An initial organization plan addressing the Corporate functions and reporting relationships needs to be created, along with the staffing requirements. Step 4- nitiatBusiness Plan An initial business plan being prepared to summarize the foregoing work and present it in the form of Corporate functions, markets, capital and operational requirements, expected financial returns and cash flows. This plan will determine initial financial viability. PhasII - Approvals and Capitalization 49. Following the presentation and approval of the Initial Business Plan to MME and JPS, the following steps would be taken to obtain financing for ENERCO: Ste) I - Preparation of Prospectus A formal Corporate Prospectus is next required to summarize the ENERCO concept for presentation to MMB, JPS, and prospective funding agencies. The results of Phase I, including the initial business plan would form part of the Prospectus. Real cases and pro forma energy service contracts based on the energy audits and demonstration projects being carried out by JPS can be used as the basis for preparing the Prospectus in addition to the Energy Peformance Contracting Guidefor Businss prepared by Ontario Hydro.4 It is possible that if there is sufficient international interest from qualified ESCOs that the preparation of the Prospectus could be requested as part of the selection process. Step 2 - Presentation of Prospectus to JPS and International Donors The Prospectus will then be presented to MME, JPS, and prospective funding agencies for formal decisions for both capitalization for the corporation and for financing for efficiency investments. Step 1- Capitalization Of Company Commitments of capital are required for the remainder of the ENERCO development process and to cover Corporate overheads for the initial period of 2 - 3 years before cash flows permit self-financing. JPS and donor agency decisions are required at this time. 4hi d cee is a&Cffable Separately and ha been circUated to MME ad JPS. A-59 Energy Conservation -26- Summary Step 4 - Financing for EMdleno bvestments Sources of financing for energy efficiency investments also need to be secured at this time along with definition of terms and conditions. Sources of financing include loan funds from various International development agencies. Investment funds would come from JPS as Its investment In Identified efficiency opportunities and subsequent rate-basing of this investment. The basis for JPS investment (e.g., projected savings, monitored savings, capital costs) and investment rates (e.g., unit cost of saved energy, portion of project costs) would need to be defined. Phase I - Start-up and Progtam Development 50. DSM project implementation and further program development should begin In parallel as soon as core staff have been hired. Step 1 - Hire Core.Staff Begin Operations Executives and senior staff of ENERCO would next need to be hired. Operations should begin immediately on the basis of energy conservation opportunities previously identified. Step 2 - Refinement of Business Plan The initial business plan should be revised And refined to reflect the nature of the approvals and capitalization received for ENERCO. This document would also identify office and staff requirements and (in conjunction with the JPS/CLF Pilot Projects) the priority programs for delivery. Step 3 - Scure Office Space and Equipment Suitable office space, office equipment and other requirements (possibly energy monitoring equipment) need to be identified and obtained as the staff size is brought up to full complement. Step 4 - Plan and Refine Program The initial set of 8 DSM programs from the CLF study, together with other programs (such as the proposed boiler tune-up program) need to be refined and planned for delivery. This should be done in close association with the JPSICLF team working on the pilot projects in order to refine markets, technologies, audit approaches, delivery mechanisms, expected savings, monitoring and quality control; and to identify the priority programs for early delivery. A-60 Energy Conservadon -27- Summary Phase IV - ProgmIlplementation 51. Program implementation should begin as quickly as possible and the following additional steps undertaken as necessary. Step 1 - RecruitHe and Sta The operational staff of ENERCO would be hired and trained as needed with the growing volume of business. Included will be technical staff (engineers), financial, clerical and marketing staff. Step 2 - Identify Private Sector Contractors Various types of private sector contractors such as auditors, engineers, installation contractors and program delivery contractors will need to be identified on an as required basis for program implementation through a Request for Proposals. The RFP will identify qualifications and experience, set performance standards and establish prices or rates for the work to be done. Step 3 - Develop Operational Plans and Execute ProMMaMs Plans detailing the day-to-day operation, management and procedures on each of the priority programs will be required for full scale program execution. Orniztin etable 52. A timetable for the development of ENERCO is presented in Figure 5. While the organizational development is underway, JPS Energy Conservation Unit will be carrying out a series of energy audits and a demonstration program of retrofits in commercial and industrial facilities. These demonstration projects are being carried out with assistance from CLF and include assessments and evaluations of the results which would be used in the development of the ENERCO program. A-61 EliBRCO OR@ANIZATICOP TIMIIE B~LE VOR DIDDING.1 am r~ t I~ET~~aT PILOT ASSSUU 8 8 8 11110o PnLSE 1: Conceptual Development 8 PM= is App~ovals and CapItaliation PSE XXX: Start-up Program Dev1opment PæSE IVS Implementation Ap "y june Aug. Sept.i Oct. Nov.i Dec. Jan. eb. i m . A pr. May 1991 1992 ANNEX 1 ANALYSIS OF POTENTIAL DSM PROGRAMS Program 1 - Residential Lighting Program 2 - Residential Water Heating Program 3 - Residential Refrigeration Program 4 - Residential/Small Commercial/Industrial Airconditioning Program 5 - New Commercial/Industrial Buildings Program 6 - Small Commercial/Small Industrial Direct Installation Program 7 - Large Commercial/Medium Industrial Retrofit Program 8 - Large Industrial Retrofit A-63 FOGRM # . RESMENTIAL LIGHTING HIGH CASE LOW CASE A. TARGET MARKET 1. Market Description The market is all resdential custors , edat at a 1989 a= of 264,100 and oeltad at the foliowing rates: 1989 .0 1990 1.060 1991 1.155 (Growth ras are sam as in SWECO Basic Load 1992 1.249 Forecast, Vol M-A, Table 2-lA) 1993 1.363 1994 1.457 1995 1.556 2000 1.718 2005 1.794 2010 1.871 Only åamt la in high-use sockets (over 3 bra/day) are costeffective to replace with compact ~~uorescent Iajp. The market for this program is *anmed to be repreuemted by: High Usr LOw Umr Average Unr %ofTotal Market 20% 80% Fixtes mtrofitted/ 6 3 3.6 ho=e Pr. Program 100W 75W 80W Wattage/Pixture lirs/Day 3 3 3 Prm Program 657 246 315 (kWh/yr.) 2. Penetratios ats a) Anaul % Participante % Participants 1991 0% 0 0% 0 1992 0% 0 0% 99 1993 4% 14,399 4% 14,299 1994 8% 30,783 8% 30,783 1995 15% 61,641 15% 61,641 1996 15% 62,924 15% 62,924 1997 7% 29,964 8% 34,244 b) Tota 49% 199,771 50% 204,091 3. Ho=s of Operation averag 3 hours per day : 365 days sam as high cass 1,095 hr/yr. A-65 PROGRAM #1 - RESIDENTIAL LGRING HIGH CASE LOW CASE 4. Peromt of Lmad ovning 90% 90% Peak 5. Votage Levet low low . PROP~OSED PiOGRAM 1. Technical Measmures Repao~emt of incandescent mps in Same as high case except ssume highuse sokets mostly with copact 2.0 sockets per house. fluorescet lamps and in some case circine ~amps. Assum average of 3.6 sokets per house. 2. Progma Me~aaim A ødoor-to.door" di~ect instalation A retailer rebate program wherby program designed to retroit the high- customesm uign agreement to insta us sokets in.vh household. Lamp compct fluorescents and repay and instalation would be provided at rebate over time on JPS bil. On no cast although some form of cost presemtation of coupen at retailer recovery is possble on JPS bils. price is owered by amount of bate which ls puid by JPS to retaliers. 3. De~ivery Agents Contractos or -tudents on a swmmer Mass advertising would be required employment program. Note abour along with co-operation of lighting costa per lamp of $132 below and retailers. program admin. costs of 20%. 4. Savings a) Per Patcipmnt 44 annua kWh/amp x 3.6 33 annual kWh/Iamp 1 2 = 158 annua kWh/house = 66 anat kwhIbouse Note: 'Ibe kWh havings per amp ar. quite modest compured to the 75 - 80% savings attibutable to compact fuorescent aps over incande~nts of simila tmen outpu. lh assumptioms e that some upgrading of lightoutput occurs and some ow-usesockets ar retrofited. Note: It is assumed that 20% of the cacuated savings would have occurred withont a promotiona program because of consumurs' own perception of benefits. Therefore, nt program enurgy and peak power savings are take at 60% of gros~ vaues b) Auas Saving om $15/yr. for 9 yrs. $S/yr. for 9 yrs. inén fn ap A-66 PROGRAM BI - RESIDENTIAL IGBTFING 1BGHR CASE LOIW CAIE 0) % of Enrgy Savings on Evening Peak 30% 30% 5. Caat Incemntal cost over d $1123 wilaat tam ist with deate markps at current rates. a) Investment per Iae per Iko.auup pbr hopembom (without taxes) * 3.6 0. equipmnt $1123 1442.8 $246 mabow for $132 $1115.2 Total $1558 $1246 b) Admin. & Maeting 20% 20% C. RESULTS OF ENERGY ANALYSIS GWh Pak MW OWh Pek MW Savingsin 1995 13.5 11.1 5.8 4.8 2000 25.2 20.7 11.9 9.8 2005 25.2 20.7 12. 10.2 2010 25.2 20.7 13.0 10.7 D. RESULTS OF ECONOMIC ANALYSIS 1. PVofBen.fits 177.3 79.8 ($1millioni) 2. PV of Costs 96.0 43.1 (*ImiDicon) 3. PV of Net efits 81.4 36.7 4. D/C Rai 1.8 1.9 5. laeal Rate of Rtn 43.6% 41.8% PROGRAM #2 - RESIDENTIAL WATER BEATING mGH CASE LOW CASE A. TARGET MARKET 1. Market Desoription Eectric residenal water heating accounht for a fairly small portion of JPS oad amounting to about 42 ~Wh/yr. or 3%. 'llis is projected to grow to 62 GWh by the year 2000. It ig estimatet that 33,500 rnidential utility customrs (11% of total reuintial c n) have detric water heaters and that tho market divides ito large water us e and small wate users as follows Proportion Aveage Consumption Largo Usr 20% 2,850 kWh/yr. Small Ums 80% 1,100 kWh/yr. Averag Unr 100% 1,450 kWh/yr. Currently ther. mre an eutimated 2,000 new electuic water heaters sold in Jamaica esch year for both newInoaflatifand replacemmnts. hs program aims to replace a portion of the with solar war heaters, to penetrat the existing dlr water heater stock with solar heaters to a modest degre (both in high eas. only) and to install hot wate consvation measures in a portion of all residences. 2. Penetration Rats a) Annual New Instatas Existing Instalins New Installns Existing bnstalins Solar COnS. Solar Cong. Solar Cons. Solar Cons. 1991 0% 0% 0% 0% 0% 0% 0% 0% 1992 2% 2% 0.15% 0% 0% 0% 0% 0% 1993 3% 4% 1% 2% 0% 4% 0% 1% 1994 5% 6% 2% 4% 0% 6% 0% 2% 1995 6% 8% 4% 8% 0% 8% 0% 4% 1996 8% 10% 5% 10% 0% 10% 0% 5% 1997 16% 20% 5% 10% 0% 20% 0% 5% 1998 24% 30% 5% 0% 0% 30% 0% 0% 1999 32% 40% 5% 0% 0% 40% 0% 0% 2000 40% 50% 5% 0% 0% 50% 0% 0% 2005 60% 75% 5% 0% 0% 75% 0% 0% 2010 60% 75% 5% 0% 0% 75% 0% 0% b) Total 70% 34% 0% 17% 3. Hurs of Operation 5.840 hrs/yr. (turned off 8 tr/day) 5,840 hrs/yr. (tuned off 8 h/day) 4. Percent of Load on 90% 90% Evening P * 5. Volage Lavl low low * assun ~s electric water hat are turned on in tho evening and that the najority of hot water use is in the evening. A-69 PROGRAM . RESIDENTIL WATER HEATING miGe CASE LOW CASE . PROPOSED PROGRAM 1. Technical Memus . Domstic solar ater heaters are a . Hot water .conservation proven tec r y and can rnge measures incIude wrapping from .impk gravity circulauion electric water hatr with an systems with int ed tank and extra 8 cm of glas filter p to mars eponsive systems insulation anda durable plastic with multiple cofcitos, Indoor cover, ånsulating water pipes storge tank, pump, control and mea tank, low flow faucets backup heating. and*aoerhmdandcanging tap washers. High cass also mludes aU hot water measures from low case. . No solar water heatrs in low cas. 2. Program Mecmnism Solar water heaters would be provided Hot water conservstion measure and installed for the consuers on would be provided directly to cither a los or hire-purchase basis by residential customers by contractor ENERCO working through who would visit homes and install commercial suppliers. The monthly the equipmmnt. Customers would charge on the utility bill would be less pay charge on their JPS bill for than the cast of operating an the measures. cquivalent electric water heater. 3. Delivery Agents ENERCO working through Contractors to ENERCO commercial suppliers/installers 4. Savings a) Annal kWh/ participating homs. Solar Conservation Solar Conservation Large Uuer 1,992 300 0 300 Sml Uaer 1,100 200 0 200 b) % of Energy Savings 30% 30% on Evening Peak 5. Costs a) nvetma per Hous~ (without taxe) Solar Conservation Solar Conservation Large User 16,225 $114 0 $1114 Smaln User $4,170 $66 0 $66 b) Acmin. & Marketing 20% 20% A-70 PROGRAM a1- REMENTIAL WATER =uATllG inGi CAE .. OW CASE C. RESMLTS OF ENERGY ANALYSI oWh Peak MW oWh Peak MW Savinin 1995 4.2 0.7 0.6 0.1 2000 18.4 2.8 2.0 0.3 2005 35.8 5.5 3.6 0.6 2010 49.0 7.6 5.2 0.8 D. RESL OF ECONOMIC ANALYSIS 1. PV of Bnts 68.7 5.6 W ~mlion) 2. PV of Cost 59.9 0.6 01~llion) 3. PV of NEt Bfits 8.8 5.0 $~)iliom) 4. B/C Ratio 1.1 8.8 5. I Ral Rat. of Rturm 18.2% >100% A-71 PROGRAM #3 - ~UnTIAL RERUMGERATOR PROGRAM HIGH CASE LOW CASE A. TARGET MARET 1. Market Des~ription Residnta refrigoators are the largst sigle oad in the reuldental setor mnnnng an e~it 30% or 152 Wh anmally, an amount which is estiated to grow to 204 Wh by 2000 du. to increasing market penetration and unt sia. It is esrimadtd that 20,000 new refrigerators are dold on averag each yer with an averag n annual consupdo of 978 kWh esch. 2. Penetration Rtes a) Annual 75% of new refrigerator sales each sam as high cas year (i. 25% go unregulated) 3. Hors of Operation 8,760 hr./yr. 8,760 hrs./yr. 4. Perment of Lad on 100% (savings distributed equally) 100% (savings distributed equaly) Evening Peak 5. Voltage Lvei low low . PROPOSED PROGRAM 1. Techicul Meaures The meamres to Improvö refdgerator efficiency include higher levis of inuation, high efficiency compresors, rotary compressors, more efficlmnt hat exchangers, tightersals, improved and electronio controis. 2. Program Me im Progressively higher efficiency One efficiency sanda~d bewong standarsl beSoming effective in 1992, efective in 1992 and conting in '95 and '98. place. 3. Delivery Agmats The program couldinvolvesolely testing, ~abelling, and conmne information program. or could inoude a regulatory standard by the Bureau of Standard. 4. Savings a) Per Participating Unit % annual kWh/unit % annual kWh/unit 1992-1994 17 171 17 171- 1995-1997 53 520 17 171 1998 -2010 60 584 17 171 b) % of Eergy Savingo 20% 20% en Peak A-73 PROGRAM D•nemRNTIAL RERIGERATOR NIOGRAM m0 CA0 Low CA 5. Cos a) Iave~tmet Di. 50% Total Towl per unit Mm. Cad Mask-p 1992 - 1994 263 132 $395 $395 1995 - 1997 473 237 $1710 m395 1997-2010 98 499 $11497 $395 b) Ad. & Madlbg 20% 20% C. RESLTS OF ENERGY ANALTSIS GWh Peak MW GWh Peak MW &avagii 1995 11.6 1.3 7.7 0.9 20 53.0 6.0 20.5 2.3 2005 96.8 11.0 33.3 3.8 2010 140.6 16.0 46.1 5.3 D. RESUL I OF ECotIC ANALT 1. PV OfE.a.la 115.8 46.5 2. PV of Cos 107.2 41.3 ($1million) 3. PV of Net Bent 8.6 5.2 (Simillio.) 4. s/CbRao 1.1 1.1 5. IaternalRateof Reur 16.5% 16.8% A-74 PROGRAM #4 - RESIDENTIAL, SMALL COMMERCIAL/NDUSTRIAL AIR CONDIONING mmGH CASE LOW CASE A. TARGET MAREET 1. Market Deecuiption Room and centra air condiioner are used in residences and s~ll commercial and industrial buildigs. lis program aims to imre the efficiency of ncw air conditioners sold to thee markets. C~tently there are about 20,000 room air conditioners sold per year in Jamaica with an esuatd averae consmpticn of2,682kWhlunit/yr. Ther. are also about 1,000 cmtral air oonditioners sold with an averg. consumption of 10,500 kWh/unit/yr. The weighted erage co~sonptian is 3,054 kwhunitlyr. The total annual electricity consnption of nw air conditioners is 64 GWh. 2. Peetration Rates a) Anul 75% of all new air oonditioner sales saeo as high oase ech year (ie. 25% go unregulated) 3. Hours of Operatio . 2,920 hrs./yr. 2,920 hrs./yr. 4. Per nt of Lad onBeing 50% 50% Peak 5. Voltag Lve low low . PROFOSED PROGRAM 1. Technical Measures lhe uamres to improve air conditioner efficlency include high eficiency compressoms, rtary and variable speed compressors, moreefficienthot excbangers, split systemroom air conditioners that alow ~oning and better controls. 2. Program Mechanism Progressively higher efficiency One officiency standard becoming standards becoming effective in 1992, effeotive in 1992 and continuing in '95 and '98. plac. 3. Dlivery Agents le program could involve solely testing, labelhug, and conmumer information programs or could inciude a regulatory standard by the Jamaica Bureau of Standards. 4. gavings a) Per Pardicipting Unit % annuad kWh/unit % annual kWh/unit 1992 - 1994 14 416 14 416 1995-199y 22 669 14 416 1998-2010 28 851 14 416 b) % of Energy Savings 25% 25% on Peak A-75 PROGRAM #4 - RESIDENTIAL, SMALL COMMERCIALiNDUSTRIAL AIR CONDITIONING IGH CASE LOW CASE S. Costs a) Investmot Diff. 50% Total Total Costs per uni Manuf. Cost Mark-up 1992 - 1994 602 301 $1903 $1903 1995- 1997 777 389 $11166 $1903 1997 - 2010 945 473 $11418 $1903 b) Admin. & Marketing 20% 20% C. RESULTS OF ENERGY ANALYSIS GWh Peak MW GWh Peak MW Savings in 1995 24.9 4.3 19.7 3.4 2000 73.8 12.6 41.5 7.1 2005 97.7 16.7 46.8 8.0 2010 103.7 17.8 47.9 8.2 D. RESULTS OF ECONOMIC ANALYSIS 1. PV of Benefits 248.4 95.5 2. PV of Costs 137.8 99.1 ($1010ic0) 3. PV of Net Denefts 110.6 (3.6) ($aiuioa) 4. B/C Ratio 1.8 1.0 5. Internal Rato of Reur 45.7% 9.3% A-76 PROGRAM #5 - NEW COMERCIAL AND DUSTRIAL B=ILDNGS mGH CASE LOW CASE A. TARGET MAREET 1. Mar~t Deription EBch year in Jamica about 800,000 sq. ft. of new commrcial and industrial floons is oontrted with an averag. lcticiy inte~sity of about 20 kWh/sq. ft./yr. resulting in an additinal oad of 16,000 MWh. Of the 800,000 sq. t. of nw stock about 600,000 is in abut 6 large b"~tdng (offices, hotel, rtal outlets and school) and about 200,000 sq. L. is in app:nraatay 100 small building. 2. Pecetration Ratos a) Annual 75% of annual nw stck (io. 25% contiss to be built ccording to m as high cas t practics) 3. Hour of Operation 3,250 hrs.yr. OUik progra 7) m as high cas 4. Percmnt of Lad on Typ % of % of Load sm as high cas Evening Peak Floorspace on Evening (coincdm factor) Peak Hotel 17% 80% Office 34% 20% Jndustrial 48% 29 weighted avegle 30% 5. voltage .veR medium medium I. PROPOSED PROGRAM 1. Te~nicul Measures A host of conservation m sus apply to nw commercial and industria buildings. Building She~ - increased insntatiom in roof and wds -improvedar skaing - window ahading -improved (lw E) windows Lighting - high efficiency lamp - electronic ballast - fluorescent reflectors - lighting control systeas - daylight åmming occupuncy sensor, etc. Cooling - high eiciency air conditioners, chillers, compresors Ventilation - high ewicimncy metors - variable sp~d drives Centrois energy nsytemsa Cogeneration/Ablorptive Cooling (high cas only) (se Technology Nota) On average the conservation menm~s in the EBC will red~ce ectricity Om by 30% (ia. from 20 to 14 kWbsq. f./yr.) A-77 PROGRAM 05 - NEW COMMECIAL AND IDUSTIAL xUILDNGS 1HSH CASE __ ,WC E _ 2. Proguam Mlais The Energy Efficint Building Codm Ms 1.~i a~e to bo manatory for dl wew privat. ad publk comercial and smal industriul buildings. In patice not all wil conr . In additon to m~ting the =ew cod, it Is samnd that a portion of larg mew budings wIR install combined oogmuntion/aboptive cooling systems. 3. Del~very Agent Jamaica Buren of standards -am higb me ENERCO 4. Savinga Shar. of Savings Shar of Savings New Stock New Stock a) Coservation 75% 30% 75% 30% b) Cogeneration & 30% 40% 0% 40% Absorption Cooling c) % of Energy Savings 25% 25% on Evening Pek 5. Costs a) Invusmtnr $18.3/sq. it. ·· $.g.3/sq. ft. (without taxes) (consrvaton only, based on (conurvtion only, baed on a 2 yr. paybck) 2 yr. pybck) b) MAn. & Marketi g 5% 5% C. RESULTS OF ENERGY ANALYSI GWh Peak MW GWb Peak MW Savings in 1995 15.9 1.5 7.4 0.7 2000 43.5 4.0 25.4 2.3 2005 71.1 6.6 43.4 4.0 2010 98.7 9.1 61.4 5.7 D. RESULTS OF ECONOMIC ANALYSM 1. PV of Benefits ($~miRio) 60.7 47.9 2. PV of Cost ($~milion) 32.3 27.1 3. PV of Net enefits 28.4 20.8 ($lmifon) 4. D/C Ratio 1.9 1.8 5. Internal Rate of Return 48.3% 45.2% A-78 R0GRAM 16.- SMALL COMBXCIAL/SMA L iNDUSTIUAL D1RECT NSTALLATION HIGH CASE LOW CASE A. TARGET MAREET 1. Markut DeM~ription The mrket ~ slas of small commerial ad industdal customerm with le than 10,000 &q. IL of ~oor spc. Buildings smalt r than 3,000 &q. ft. guumtly have widow air conditioners wherm. buildingsbetwee 3,000 and 10,000 n. .havecental single zon air condtlones ofth supplemented by window air condtoer. In gmeea, upgrdes in such air cndtionu~ are only practical at time of replacement which is add~esed by Program #4. In this m~aret segmt, ther. ae appm iWtay 24,000 building, with en avage area of 1850 aq. f. Total ou. RESULiS OF ECONOMIC ANALYSIS 1. PV of Benets 110.7 34.2 ($bmillion) 2. PV of Cost 110.0 27.4 ($Imllion) 3. PV of Net B~ets 0.7 6.8 ($Imlilon) 4. B/CRado 1.0 1.2 5. Intral Rate of 12.3% 23.3% * Retur A-86 PROGRAM #8- LARGE NDvSTRAL RETRO~W A. TARGET MARKET 1. Mark~t Dacrption The imrket cannlul of the 14 larget ndu miali cufiff in amnia iach a.e about 97,000 MW per year. The. 14 plas contaln thee qIor g~oups; a food procesuing wih inludes two sugar sauares, a floor silt, a keswsry, 8 ahi~en fam. and an io plat b) pr~namalsproceusigIncludiag8fmndry, sel nd and ba.auta plant; c) mimoansous plaasIncluding aglas plat, paper paa, cRlinerauy, tim plant and a m ft gfality. 2. Penttion Rates Plant % PlaIs a) Anual 1991 0 0 0 0 1992 0 0 0 0 1993 3 21 1 7 1994 3 21 2 14 1995 3 21 3 21 1996 3 21 3 21 1997 .1 21 b) Total 14 100% 12 g6% 3. nors of peration 2 dift operation om aveag mmi as high - - 16 ha x 6 dys a 52 weas S4,992 hrs/yr. 4. P«rcn ofLad on Eveng 75% 75% Peak (coincidence factor) 5. Voag Lvad high high I. PROPOSED PROGRAM 1. Technical Measumes indsial mandns includign ams high oam . adjiutable speed drives . nfisanmroemna . o riv* iprovemnts . high eWiciuncy mtrs . efficient lighting . etectrio fiace imprown--ta A-87 rROGRAM #8 - LARGE INDSTRIAL RETROFI HIGH CASE LOW CASE 2. Pogram Menhaniam 'Te program, deliv~red by MBRCO and Its cotractors, would consiut of ftv el ens . audi-a ful agy audit wuld be pefomd by naudt frmto identify all conservatio meamures ad to rank them by payback, ROI, etc. . prumeMt Identifkan - ENERCO would negotiat with the building owner a package of retrofit mesnes finuncially attractve to the owner and JPS. . fnancing- the aged package would be nanced through BNBRCO cn a lease basis with no up-front cost to the owner. . rerofit - contractors to ENERCO would instal alu of the equipment identifed in the project and maintain It as necessary. . reayment on udlity bi - the owner would make his tea payments over time on his JPS bil at a rate of le than the energy savings 6 m cuK"lwE e= 0 AN~ am NEW UNT PMTKX- LONY a~ SM~ SM~ SM~ t~ LG« Lom Pk~ Nw~ UNT ME~ P~MW %OF OK FE~ T. sa TOT/L 28 20= m im 0% 2i 3M ^140 416 0 OLO 0,0 om av im am 21~ 3M lm~ am 418 am 02 OA m m im en 2~ 3M om 418 om dy 1.1 3% m im im 21M am 2% we 415 ism Iz 22 5% 3w im 78L 2~ am 3247M we 411D am 22 &4 en 31>1 im 79% 8 inom am 384~ 1~ we 419 2=9 &0 43 7% 3w im 7M 21~ 3= 44~ 41e &7 &6 7% » im 7= 304 M130 15= 418 4,5 OL7 8% 3M im 304 W?~ 0 om 416 cm 4A 7% 30 am lum wo 418 4107 4Y 7.1 en 30 2WI 2~ 304 MW m 418 4=0 M> 73 om MW 2~ =54 ism we 418 4= SA 73 214= 3M 15= om 418 4~ M 72 2WC 7M 21~ 304 ism wo 411B 4p49 52 Ls en 7= 21~ am lum 419 4~ &3 60 m m 2~ 3M IX~ MW 416 ta u a2 ta 312 2= TU 2~ 30M Ix~ MW 416 4m3 sz aa 4% m 9= 7= 21~ 3M 1~ en 419 4; a2 4% 34 2= 796 2t 304 13~ me 416 4 EL2 4% am 7= alm 3M 10= 419 4~ u &2 av ale I 〕，必〕 ”。l當曇―_____＿廈 ．臺，。．！一，奪者量量遲；響蠶鑲霸遲翁邇邊群蘿翁蘿 蓄萬才jgl__ ，曆。＿―一騷藝讓登垂邊騙賽賽婦寫著藝翁翁屠邊婦婦 霎考寫霧― 一，鬱蘆騙。．!’彎賽據樣鑾響鑲遣憂釁藝豐彎翁鑾響箠藝藝 盡澴盒藝藝―_ ,_-’要•藝垂糁糁蘿雜華釁釁華寡華曄遲釁釁釁 ’寫”-::::：。：。：::::::::::: 。釁〕 響蘆― 晝。〕籐權藝藝藝藝擊擊變養涌養養養養翁參養賽易 喜：! 邊·丰‘甲 蒙《。，。。．。。。．。。．。。。．。。。。。。。。。，，。，，。，。，：矛 ’斗100 r 斗0斗付 l藝筠“,“聲釁”獄’&&“號“&&&!!!!!！戀：！·！ &,“。矓。。煎。襲峰！i！·！ 騷i鉑1 11―。離 漢巢巢讓離離購巢購巢弟讓巢離讓華祟樂離呆’一纏藝基繁！ 弱i擊‘I―。 祟祟拿祟泵祟祟桌祟讓祟祟離祟祟巢離泵果華‘驕！ 錯i_i&!. 呆呆呆寡呆呆雜皋爭寧呆呆呆呆呆呆呆呆呆呆離藝呆呆巢一讓l 喜韋響要量量驕囊呈I ，森莽”藝藝藝群I, 藝谷藝藝谷藝碧谷藝藝藝秀秀谷碧藝藝秀谷藝妥妥呆離離泵豆！ 。。．。。。。。郵每！!&！· ----------------－一華艷！ 龍鼴龍鯀鰓龍“識“。一r!& ’離！- ·。·。·。。。·。。。。。。一，!.!& 驢 〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕。〕〕，，。〕． JM~ DEM LJ0W CABE ^A T u v w x y z AA AB AD AD AR AF 329 LOWCASE m t~ com~ ww bu~ 2yrPB 4~ Ad~ 2% h~ Equ~ Du m Um On peak og~ Cod b~ Nd 6~ m a~ *emu w~ 9~ 9~ c~ A~C~ 6~ Cad m yaw ~W om om om 4~ 4~ AM 4~ 4~ 3v ----------------------------------------- ----------------------------------------------- -- im u 0 0 0 0 0 0 0 0 0 0 182 0.1 79D iw 50 w 0 377. m se lm -m 30 im 02 2= m lew im 0 im 1992 10 2m2 -m 941 lom 0.4 4= im 3~ 2= 0 22W 2= 149 3W -om 342 im 0.7 740 im om 3= 0 382 431e 218 4= 34 im 1.0 lim 2M am 5775 0 SM 4= 240 e= 3« im 1.4 14= am lom 788 0 7m8 49W 240 om am 345 im 13 lem 4= 13M WI4 0 6714 49W m e= 14M 348 len 2.0 om low om 0 om 49W m cm mo 347 2= L3 2~ e= 19= om 0 om 49W m em 4= 348 2= L7 29~ me 217M lom 0 IOND 49W m 5229 ffl 349 =2 u 32= om 244W 12515 0 12DIS 490 m 5229 6~ 3W 2= 33 30M me 27180 13= 0 tam 48W 249 om mil =4 3.7 39= 14= 0 14e85 49M m om om am 4.0 4340 lom 325M lom 0 ism 4980 s~ lom am 4.3 47040 117e0 17318 0 17318 49W 249 5229 l~ 354 ew 4.7 am 12= w= 1e541 0 IN41 4= 24 e= 13412 355 2= &0 5~ 135W low 0 lem 4WO om 14737 38 2= &3 w= 14M 43= 2101 0 21= 49W am imm m 2010 &7 e144 lem 49M 2m7 0 22517 49M 249 e= 173% 355 359 m 0 PM VPL 47854 270M 3M ffl 30-~-98 A B c D E F G H I J 229 IALL OSU D~RECT NAL agk acreiroft 230 231 LOGI 232 AIR CONDTININGMULTIPUER ONLY WORKS HALF THE TUE (~UUR SAI 238 UGHING 80 2, NOT8w% 234 235 ULTMATE PENETRAT1ON 70% 236 SAG: VEIC LOWCASE 237 AMONGPART~OPANTS 39% 15% 23B 239 HOURSOF OPERATION: 280 10 HOURSX 60AYSX52WEEKS 240 % OF SAVN ON PEAK 30% 90% OF AFlTE 00 PLUS 30% OF ~MNNG 241 1.68461538 242 TOTAL TOTAL SAWiGS SAVINGS S*INGS 243 PENETRA- MARKET MARKET ANNUAL MWH AVEMW PEAKMW %OF 244 TION (buildga) MWH PARTIOIPANTS TOTAL 245 1991 0% 23886 196000 0 0 C.0 0.0 0% 246 1992 003% 23,888 196000 6 7 a.0 C0 0% 247 1993 0L21% 23888 196000 50 8o 0.0 0.0 0% 248 1994 2% 23888 198000 500 684 0.1 0.1 0% 249 199 4% 2388 19800 1000 1,915 0.2 0.2 1% 250 198 4% 23888 196000 1000 3146 0.4 0.3 2% 281 1997 4% 24886 196000 1000 4,377 OS as 2% 252 1998 4% 2~6 19600 1000 '0e.6 0.6 3% 283 1999 4% 2a86 19600 1000 S8I (18 (L7 3% 254 2000 4% 23,86 198M~ 1000 4070 0.9 O18 4% 255 2001 4% 23,88 196000 1000 %300 1.1 1.0 8% 256 2OM 4% 23,886 19000 1000 1531 1.2 1.1 5% 257 2003 4% 2888 196000 1000 11,782 1.3 1.2 6% 258 2004 4% 23,8M 196000 1000 1z998 1.5 1.4 7% 259 2005 4% 2896 196000 10o 14224 1.6 1.5 7% 260 2006 2% 28m 196000 478 14812 1.7 1.6 8% 261 2007 23,88 196000 0 14.812 1.7 1.6 8% 262 20 28 1960 0 14,812 1.7 1.6 8% 268 2009 23i886 19000 0 14.812 1.7 1.6 8% 264 2010 23i88 196000 0 14,812 1.7 1.6 8% 285 50# 266 ~0-May-91 tililllliiitil1 il - __- __ lillililas. 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'.'9-'.9-'.'.9-'.9-9- I I uusmuasuuswuu -u * m * I I ~ I e I z I I~t i I I .1 "I I ii I SIR I ~ I~ 99 SL' 19. * II ~ ~SI I: i m I II I i ~RU I Ol iI'~ I IBIIBBBII~BIB i mi I uuiiI:ii~' II f * I Al 20 1011 ehiI~UII °D!!i ilii i 0liitiililil A-2 才 芻奉－v ;．藝擺繳，拱川擺珊珊謝m川樂縱·離 &’·軋矓i!!.! 樂矓m鐵謝m岷二．藝垂一藝’量愛【蠶 ,g驪洛蠶豐名纔煙．勵 ：。．。。。。二。二啡蘇遺囊羹！。’ 辭辭辭辭辭辭辭辭辭辭辭扼辭辭辭辭承辭承寧視6一F豐 ！非軍荒I！。 要購讓粤要要巢讓購華驕購離讓購祟祟泵果寧‘藝釁 弱i二l&1. 雜泵祟嬝桌祟嬝韋韋讓離韋離離離華購審華讓．離藝滌呆巢一讓I 瞧藝聽l權！, 藝藝藝藝賺藝藝藝藝藝藝藝藝藝藝藝藝藝藝釁逐妥祟購讓鑒蠹豐 。。。。。二’矓i!&！· ----------------－一藝鑒騷！ 龍“朧矓鸛龍“&“一r!& ’離―- 〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕〕。〕〕，。。”〕 。紼―& I 亂 。，磨鳥―’華華，,&&&&&&,，。，，。。，, 纏 I 。，g曇―’。。．。。．。。。。。。…，。。。翁‘ 《一I l 遲粹賽。斗壇呈―·，:::::::::::::::::: 發醒磚””州 I ＿雜，：基g露―·，尋。。。。。尋。。。。。。。。尋。。 夜騙‘〕i 馴 I 。，l尋―。‘&‘。‘,&，。，。，,，。，,，。 讓 邊 廈參露―·。·····。·。。。·。。。。一 ”汙‘一― ．。邊，奮鳥―&&，。‘,&,，。。，。。。，。，, 豐―連 ·I喜奮‘-&&&&，萋‘翁‘’藝餐‘,’華” ，豐；曆糁蘿―”星糁響華尋．羅牌蠱羅象曇藝暑曇曇義參垂 鑒遝l ．屋奮舞―。藝果響量變量暑邊鑲藝釁華華暈曇叢織這藝 • I 粩―:,::::::::::：。：。：::; ―〕’〕，·，,,,，一’&; 寫一婦縴賺總鳥總釁婦輪總婦糁總總馳雜婦婦話彎彎蓬彎彎馳總織寫總鰓馳藝總森 ^.1幼 斗 JAMAIGA OM HIGH CASE A a c 0 E F 6 H 228 229 SMALLMJ DIRECTINSTALL 230 231 LOGC: BLMR «D UGHTING SAMNGS ARE X 1.25 DUE TO AIR CONDMONING SAMNGS 232 WE SAID OMLY FOR HALF THE UGHTS 18 THIS TRUE; SOME ROOMS HAVE NO AC OR rrS UNDERISMED. 233 UGMTING NOT 01% 234 235 ULMMATE PENETRATION 70% 236 SAVILM: VEIC MMICASE 2r AMONG PART0PANMö 39% 30% 238 239 HOURS OF OPERAMON: 2M 10 HOURS X 6 DAY8 X 52WEEKR 240 % OF SAMNGS ON PEAK 30% 9^ OF AFTERMOON PLUS 30% OF EVEMNG 241 1.6~ 5w 242 TOTAL TOTAL SAMNM SAMNGS SAVINGS 243 PENETRA- MARKET MARKEr ANNUAL MWH AVE PEAK MW % OF 244 TION (bullogs) MWH PARTIC1PANTS TOTAL 1 245 1991 0% 23,= 1~ 0 0 0.0 0.0 0% 248 lm 0.03% 231~ 19~ 8 15 0.0 0.0 096 247 19m 0.42% 23,~ 19~ 100 258 0.0 0.0 0% 248 1994 4% 23,us 19~ 1000 z~ 0.3 0.3 1% 249 im 8% 23,= 1~ 2WO 7,549 0.9 0.8 4% 250 im 8% 23,~ 19~ 2m0 M410 1.4 1.3 6% 251 1997 8% 231~ 196= 2000 17.271 2.0 1.8 9% 252 im 8% 23,886 19~ 2= 2ZI32 2.5 2.3 11% 253 im 8% 23^8 10~ 2= 28~ 3.1 2.8 14% 254 20W 8% 23,~ 1~ 2000 31,854 3.6 3.3 16% 255 2001 8% 23,= 196~ 2= 30,715 4.2 3.9 19% 256 2002 7% 23,= 195= len 40.779 4.7 4.3 21% 257 2m3 23~ 19~ 0 40.7n 4.7 4.3 21% 258 2004 23,8% 19~ 0 40.7» 4.7 4.3 21% 259 =5 23.886 196= 0 40.779 4.7 4.3 21% 260 20M 23,= 198= 0 48.779 4.7 4.3 21% 281 2007 23,~ 1~ 0 40,r19 4.7 4.3 21% 282 2NS 23,8% 19~ 0 40,779 4.7 4.3 21% 263 2= 23,8M 1~ 0 40.7» 4.7 4.3 21% 284 2010 23,= im= 0 40.779 4.7 4.3 21% 265 70% ism 288 30-May-91 〔〕：& ，霎權旦｝ &&}&&，離。。。。。。。，，藝，。。，。。 ，嘎震暴！--－一。 一’｝。’”蘿露萬鑾雙垂奉墾認養認養瞋餐餐餐養·騷 乏＿鑲濺I 。綢’二＿______ ．〕一。〕―&&“鄉戰認‘∥“養‘ &&&！。·，。．。。矓矓織謝縱 ”唱！奮。！．澀 ．萬寫”―一；。鯀““離龍龍龍龍－ 拇巡居償。！ ,&&&&―…，戀綴議聯樂導 &,,-::::,:：。：;;:::&&&:&& 一―。。，。：：〕魚，,,,& 卉1飭 斗 論騙 !,．、。，：〕〕〕〕； ^-1飾 。。鉀嶼”鋼殲F 讓 。，,,―【 :．。―’尋華琴華華離奪“蘿雙著藝“&&‘養‘曄 選召彎l 。＿.-’遼蓬騙織認萋萋翁藝”譽藝蘊藝藝面蘊藝易尋 廈屋尋l__－一織 _!’寡霧賽攤遺易易寫日。。。’。。。”& 萬響。藝！ 澀召婦― :._―輊棘茲棘易’輊n棘棘易 呈屋喜l__- :_.:!’鳥‘離鵝離頸棘輪聽棘要囊 屋邊衫 〕，，〕〕〕〕！:&.’一 &,!：。。。。：。。〕！!!!!!!!!!!!!!!!!!!!:：·。。一’·’;& A-127 斗 凶開卹膩誠馴細瀾鉤闢編悶颼 粩．00細寧O馳你J膩L留細0妒O 闕•••••••••••••••個•••。•••••••••••••一。••••．•••－一•一•••一•。••••．•••。••。••。一。一•－一•－一•••••。••，。。••一••－－•．•••一••－－••．。•－•－。•••間••－－••• 騙口劇閑誠織叩觔叮啊細也 口 粤卹以州鑰祠夢嗡露編實黝 騰鸞黝肱個矚 購O口嗎鸛‘瀾勝闢唱 儲中牌田當開悶閱開個唱倡細嗎 戲 總州萬婦由《乎O門籐姨留口險細團口個紳中紹目X．。瞭間X個伯唱口曄 勵個之，個鑰觔口露口開州向膩調唱騰啊劉開膩網•瀾‘劇屆閱昤中．刀口 馴 編 購O口口劉叫闖閑馴凡U•口口圈騙睡凡悶闖啊命鬨牌輛CO州口馴闈悶闖啊 卹剎匯繙糁開賽視自騙你口日口織滷睡口個頃滷臟曦煙月網鹹睡網晚騙開口個曉滷贓睡纏細爾囑睡劇圈矓唱口病憫膩細細觔偉開睡 牌網。總•跑O鱸細州閑口肩屹闔胄騰綢膩細崙俗Cr開騰露禹衫騷細榭，庭向膩口鯽俗C戶開閑嗡團唱為膩濺瀾屆闔彎網馴膩闔彎嗚C寧 勵相鴉啊口闢申開畸閱館闢．龍馴肱馴頗潤讓觔啊口n膩 才籐個口個O鳥鑽抑勵必楓O觀0中編．楓0 Ob自論00纖O戲O個騷 n個睡O鳥·田抑勵O亂0 000騰O楓O蠱0個略0．必O織00歸 論劊細口馴唱卹口勵鳥觸綺楓才他00鴉禹口細楓」楓嗡審結鳥觀寶寫騙惑么唱亂6讓鳥 論．個爾戲唱騰口勵，奮戶編鴆，．曾略鳥奮開楓O亂口口萬”亂觀嗡個b奮觀舀唱j才鳥 料憫劉唱劊俗卹口勵楓劉煙跑必記才鰓略氦冽婦楓O,a口鴉奮亂戲門個抑才t，〝藝物鳥 為馴開口觔俗婉口勵露鳥屆勵亂才細酒讓觀臨閱牌開，a lal個偶協月購雙口勵奮名讓勵唱．嗚 為劍開口神略啊戶勵粤p唱牌遺哺遞劉嗎審幼涌，.’奮j奮魚編誡劍勵個曰勵1名忽壇開唱 霄劇開目O騙啊網勵訂戶喝蹴總嗡邊劉麗震亂鰓嗚，.. ta唱言編個氏網勵，禺日。，名皂忽開陽 抽劊認勵口略口口勵訂戶喝數寫嗡盧劍勝祇奮鴉，濾，易唱馴略劊亂啊勵翅纏越t．讓讓習鳥 袖讓闖口O認卹悶勵訂戶唱勿名嗡遺劉唱魚個浩，..,．唱讓略劊氏網勵個爾祕t．忽讓潤陽 他讓勵奮O誌卹網勵訂戶唱忽蠶磚遺劍陽奮馴鴉，..,j唱劉略奮久劍勵，，•”奮a記牌物編 ‘劇馴開總O鴉中網勵‘訂戶唱•二磚邊劍唱錢奮歸，磚個』t讓略個取劍勵，•配。ta記，奮嗚 『騰勻中酒O鳥卹戶物訂戶編跑壇．盧劉陽誠劍睡t.. t．奮，編馴亂啊勵，，•” ta亂念籥嗚 磚幼閱綱O鴉啊潤勵訂戶婦亂讒唱遺劉唱咸個綢唱湯lb奮馴皓誡欄勵，，跑。ta認讓開陽 挫馴細國口O鳥卹戶蔔訂戶螂念壇磚遺細唱胤個騙t為，名唱讓略劊氏啊勵雙圈蔔la讓」切嗚 彎編口馴論O鳥•劉膩勵訂戶唱亂讒唱』劉唱劉幼綢t為，a&，言舊劊氏網勵瀾細•，a神曾藝 幼個膩膠O鳥口。勵訂戶口忽認嗡盧劍陽魚他鴉，..,a個，騙個戶闖唱田劉口，a亂，開陽 價細闖口．0嗚卹口勵訂戶唱讓盧磚邊劍唱騖認屆，濤tal讓倡編劍沁個細蔔t洛亂讓個嗚 開言以勵O鴉印p勵訂戶唱讓之磚壇激唱胤他6，磚，」，方認個鳥劍勵，開•”t奮亂訪憤戲鳥 e．幼袖O籐露劉以勵總取劇唱么蠶‘』細唱騖鰓唱，.& t.t名略伯戶吋個望。他a亂，曾為 卹個劍陽 戲•••。••一•••。••••••－．一•一‘••••。一••••••••一••一••一•••••．•••一。•潤•••••••••。•一••一•••••。••••■•一•••••••一••一••“■。一。•一•••。•。•••••••一•。•••••－。•。 縴。 &: 幼一臘卹•戲 \&&&&&;；魚牧’t&&’〕！ :::::::::::::&&&&＼、、，。 ,，紲認”!，、、、擊 、、、、，,,,,,,,,,,，〝，&!，、甩‘· 。、、‘,,”鶴，,&&！謬、· ,&&&&&&&&&”發化 1 ，、，,,&,,,“〝〝，,&&！。、。 0:!！註：：艾裊狙訕 ’。鱗縱：以．兀 、 鳥 認 曉 審口 萬 ,i’辦鑣邏鄹躑騙 選 ＿。髮蠶藝豐〕！霎i蠶露i華1!I荔擊邊無l 屋 工 ·｝，。”&&&&&&&&&&&‘寫， ‘寥 叢 0“卜爍為；不話召細訌牌文寫露跑細紹石露 &11 。11!&&&&&&&&&&&&&&&&& ，·I。”,,,,:&&!!!&!！。！,，。 【。！&,,,,&,,&&&&&,”養要養‘.&, 畫‘一’拿 導一濾姿認馳認露婦蘇驪鬱總姿鬱總委編鳥蘇群露基爍露鳥露群婦論 A-130