KAYNARCA DAM

KAYNARCA DAM
Hydropower Project Turkey
Interim Due Dilligence Review
Report on Feasibility Study
February 2013
KAYNARCA DAM Hydropower Project Turkey
Interim Due Dilligence Review Report on Feasibility Study
Project Authorization Cover Page
REPDC GREEN PTE. LTD.
16 Raffles Quay, #33-03 Hong Leong Building, Singapore 048581
Tel: +656000064422
Fax: +656000064411
www.repdc-green.com
[email protected]
Engineer in charge: Zika Smiljkovic, Dipl.Eng.
E-mail: [email protected]
Economist in Charge: Dusan Smiljkovic
E- mail:
[email protected]
Managing Director: Yossi Edelstein
E-mail: [email protected]
Table of Contents
EXECUTIVE SUMMARY
SUMMARY DD REPORT
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I Introductory Notes
II Key Project Features III DD Review of Regulatory Issues supporting Project Implementation IV DD Review of Topographic and Geologic Conditions V DD Review of Climatologic, Water Resources and Hydrologic Conditions VI DD Review of Reservoir Engineering as planned in FS
VII DD Review of Dam Hydraulic Setup and HP Parameters VIII DD Review of Structural Considerations IX DD Review of Mechanical and Electrical Considerations X DD Review of Capital Cost Considerations
XI DD Review of Economic Considerations
Concluding Notes of DD Review (6)
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APPENDICES (14)
SH1 ‐ Summary of Assessment Notes SH2 ‐ Downstream HP Projects SH3 ‐ Kaynarca Dam Project Watershed SH4 ‐ Kaynarca Dam Axis, MY Mean annual flows SH5 ‐ Key Outcomes of Reservoir Engineering SH6 ‐ MY Flow Duration Curve SH7 ‐ Conventional Concrete Gravity Dam Option SH8 ‐ Roller Compacted Concrete Gravity Dam Option
SH9 ‐ MY Mean Annual Inflow and MY Ecologic Outflows vs Turbine Flows SH10 ‐ Approximate Checkup of Hydropower Evaluation, Ecologic HPP SH11 ‐ Approximate Checkup of Hydropower Evaluation, Main HPP SH12 ‐ Approximate Checkup Analysis of Turbines SH14 ‐ Approximate Checkup of Monthly Productions, Monthly Productions
commensurate to Monthly Inflows
SH15 ‐ Management of Annual Hydropower Resources: Approximate Checkup of
Gross Annual Income by relocating of monthly yields to higher Feed‐In Tariff SH16 ‐ Particular Structures Assessment SH17 ‐ Project Implementation Assessment SH18 ‐ Approximate Checkup of Capital Expenditures SH19 ‐ Economic Analysis of Project (15)
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Acronyms
PROJECT FDC Flow FS FS‐DE DDR HP PH PP DD IPC MW MWh CME M/E HPP BOQ MWA SCADA LV KVA MY MxOL MnOL WW DLP BOQ PU‐CF EU‐CF KAYNARCA DAM Hydropower Project
Duration Curve
Feasibility Study of Project
Design Engineer of Feasibility Study
Due Diligence Reviewing Report
Hydropower
Power House
Power Plant
Due Diligence
Installed Power Capacity
Megawatt
Megawatt‐Hour
Civil/Mechanical/Electrical
Mechanical/Electrical
Hydropower Project
Bill of Quantity
Megawatt – Ampere
Supervisory Control and Data Acquisition
Low‐Voltage
Kilovolt‐Ampere
Multi‐Year
Maximum Operation Level (of the reservoir)
Minimum Operation Level (of the reservoir)
Waterways
Defects Liability Period
Bill of Quantities
Power Cost Factor (CAPEX/kW)
Electricity Production Cost Factor (CAPEX/kWh)
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Executive Summary The Project Passport tabulated hereafter was derived from FS considerations as construed by REPDC as well as from the REPDC DD Review appraisals concluded in Summary DD Report and its Appendices. Description Feasibility Study REPDC DD Review Report Capital Cost Expected Installed Power Expected Annual Production Power Cost Factor Production Cost Factor Time of Construction Return‐On‐Investment Period $ 47.96 M 55 MW 126000 MWh $ 872/kW $ 0.38/kWh 3.5 Years Circa 7.7 Years $ 88.45 M 50 MW 108000 MWh $ 1770 /kW $ 0.82 /kWh 3.5 Years Circa 14.5 Years The Passport presumed the hydraulic setup and structural design as it was envisaged in Feasibility Study. After having reviewed the Feasibility Study and the Project outputs discussed throughout this DD Review Report, the following feasibility grades could be assigned to KAYNARCA Project: Regulatory Feasibility Estimated as achievable . No insurmountable regulatory barriers were recognized in Feasibility Study. Engineering Feasibility Generally estimated as achievable. However, the feasibility rate should be further improved. Economic Feasibility Might be questionable if the declining water resources trends continue to evolve over the concession period of Project. That, even it was proved to be just a cyclic drop, but the optimized design of the Project and the wa‐ ter resources utilization, have been hypothetically found to be of insufficient contribution. Under the circumstances, REPDC would advise the Owner of the Project to prioritize updating of the cur‐
rent feasibility study, aiming to enhance the lower rated engineering and economic feasibility grades re‐
viewed there‐through. To the effect, the optimization measures discussed throughout the Summary Re‐
port are expected to be instrumental to engineering and economic standing of the Project. Here after is the essence of those. To check the source hydrologic data and repeat the statistical evaluations of Ayvalı Tohması River. To put the Ayvalı Tohması River watershed in analogy with those of proximate environment. The process should be managed preferably by an experienced local hydrologist with extensive reconnaissance of Ayvalı Tohması River and neighboring watersheds. The operation should outcome to updated hydrologic study, wherein the reasons for latest hydrological drops are expected be clarified. For more details, see Chapter V of Summary Report. By assuring the hydrological drop was of a matter of occasional meteorological cycling, to resume the ex‐
tensive optimization analysis of HP routing: River Hydrograph ‐ Storage Reservoir – Waterways. Max operation level and active storage volume of the reservoir then the waterways capacity are to be optimized then. The opti‐
mum dam height or crest elevation should be derived there from. The analysis should define as larger as reason‐
able the water volumes to be powered whilst higher Feed‐In Tariff ($0.09756/kWh). The sensitivity analysis to be conducted therewith should be all the time combined with economic parameters. Consequently, the optimum ratio of Production Cost Factor ($ 0.82 /kWh) and Feed‐In Tariff ($0.09756/kWh), should remain below 8. For more de‐
tails see Chapters VI and VII of Summary Report. Soon after the turbines of suitable operation and efficiency ranges were initially agreed with prospective supplier, a sensitivity analysis varying the number then the capacity of turbines should be conducted. The turbines set, running the majority of hours within their pick efficiency zone, would improve the annual production of the REPDC GREEN
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Main Plant. Here, a trial with 3 Nos. turbines could be also worth to resume. For more details see Chapters VII and IX of Summary Report. Subject to geotechnical potential of dam site, the option of roller compacted concrete dam would be ad‐
visable for examination too. The option may come to be cost attractive as well to that of conventional concrete. For more details see Chapter VIII of Summary Report. The detailed BOQ, the updated FS design and sustainable work prices backed, should be a basis for up‐
dated economic analysis. There, the resulting Return‐On‐Investment period of less than 10 years, should enhance the Project lucrativeness. The stake sharing mechanism implemented to concession agreement provisions such as annual expenses of Water Use (12.80%) and Cost of Network System Use (7.31%), may keep the net annual in‐
come of electricity selling at attractive level for the Concessionaire. For more details see Chapters X and XI of Summary Report. In conclusion, the KAYNARCA Hydropower Project is a large scheme in every respect, and subject to results of Feasibility Study optimization, it can be attractive investment undertaking. The Owner of the Project is advised to proceed with Project development following enhancing of its engineering and economic standings. REPDC GREEN
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Summary DD Report I Introductory Notes The KAYNARCA Project Due Diligence Review Report (DDR) following hereafter was established on best under‐
standing of the descriptions, the statements, the analyses, the assumptions and conclusions elaborated through‐
out the Feasibility Study (FS). It would be of merit to reconfirm those with Feasibility Study Design Engineer (FS‐
DE) prior to conclusion of Project feasibility process. II Key Project Features The Project was found to have been planned as a single objective one i.e. intended solely to electricity produc‐
tion. The project will be located in Malatya Province on Ayvalı Tohması Brook. The thalweg elevation of 995.00m should be relative to dam site. The highland geomorphology features the Project footprint. The Project is planned to be constructed as ‘On‐River‐Gravity Storage’ type and be conceded under the ‘Build‐Operate‐Transfer’ model. The overall annual production can be sold in the Market through PMUM. The size of the project is foreseen to remain all the time within the large scale category, meaning the large HP storage (172M cum > 60M cum), the large dam project (H=165m > 10m) and the large HP Plant (55MW > 30MW). The Project Reservoir is not intended to serve the regulation of downstream dam ponds neither to meet the other water users demand during the concession period. The dam block with PP structures integrated in, was chosen as fundamental structural framework. Hence, the waterways and the power house (PH) were embedded within the dam body. Under the dam site topo and geological circumstances, the conventional concrete gravity dam option was selected as appropriate. The initially planned diversion tunnel was presumed to serve bottom outlet during operation of the Plant. As per the FS drawings, the reservoir outflows are to be executed via the bottom outlet, the power intake and the over‐crest spillway. The dam heel spillway jet is envisaged to overlook the draft tube slab and to dissipate in stilling basin. The ‘as designed’ reservoir outlets should safely spill out the reservoir designed flood surcharge. The main valves and gating system was recognized to be of radial gates at the over‐crest spillway, the bonnet gate on the bottom outlet, the slide gates at waterway inlets and the butterfly valves at manifolds. Yet, the roller mounted gates were supposedly designed for draft tube closure from tailrace water. The 15km of 154kVA of energy transmission line was envisaged to connect the Plant with State greed network. Francis turbines were evaluated to satisfy the head/flow conditions. For more details on the Project features, see the Appendices SH1 to SH16 herewith. General Dam Site Layout according to Feasibility Study REPDC GREEN
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III DD Review of Regulatory Issues supporting Project Implementation A locally institutionalized permits and acts affecting regulatory feasibility of the Project deserved to be more spe‐
cifically considered in FS report. This is due to their preconditioning the subsequent consideration of engineering and economic feasibility of the Project. Hence, the preliminaries of land use permit, the water use and environ‐
mental permits, then the construction and electricity producer permits, should be endorsed by the relevant Insti‐
tutional Bodies and concluded at feasibility study stage. The same applies to other water users, if any. The Owner of the Project as well as the future Concessionaire should be made free from any potential risks that could be im‐
posed by the Regulatory Bodies and Commissions during the final design and construction stages of the Project. A due consideration of the issue should be addressed to, whilst its discussion with the Owner, prior to his intention to update the existing FS report. The Concessionaire liberty to sell the energy on wholesale basis with take‐or‐pay obligation or to export the energy would upgrade his financial safety or the regulatory feasibility of the Project. The feed–in tariff de‐
clared in FS to be 0.09756$/kWh or 0.07254$/kWh, should be clarified as for its steadiness or revision during con‐
cession period. The same would apply to its gross or net rate status, the later one being calculated by deduction the dispatching and transmission cost from the gross rate. The issue would deserve a discussion in depth with the Owner, given its great impact to gross financial income generated from the electricity purchase. Under presumption the clarification of the foregoing issues has secured the regulatory feasibility of the Project, the DD reports following hereafter will discuss the engineering and economic feasibility of the Project outputs as concluded in FS. Résumé: Preliminaries of Project Permits, Modalities of electricity selling, Status of Feed‐In Tariff during conces‐
sion period, to be resolved at stage ending Feasibility Study, the latest. IV DD Review of Topographic and Geologic Conditions Of what has been deduced from the FS drawings, it appears that the dam and reservoir footprints were appropri‐
ately adapted to local site conditions. The issues that would remain to be clarified with the Owner are the accu‐
racy of the contour maps used for conceptual drawings of FS as well as that attainable for the contour maps serv‐
ing final design of the Project. The issues influencing the accuracy of reservoir and dam elevation, then the quan‐
tity of concrete and rock works, continue to be vital, because the available power storage and dam structure de‐
sign may be more or less inaccurate otherwise. No information featuring the dam site and reservoir footprint geology was recognized in FS. Although the images appended to FS drawings have indicated a good and probably hard rock mass side‐laying the abutments and underlaying the dam foundation, still a full scale geological report appropriated to FS stage should be vital to estimate the geotechnical feasibility of 165m high dam structure. The report should point the regional and gen‐
eral site conditions, focusing inter alia on faultiness of rock masses, their geological differentiation then their geo‐
logical, geotechnical and seepage properties. Its findings should clearly conclude and favour the risk free large dam setting. The weathering processes, dissolution processes (if any) then geodynamic processes (if expected) are worth to thorough discussion while updating the existing FS, too. The ponded water loss as a result of seepage then sediments accumulation would be of merit to appraise during the reservoir modeling exercise. The detail site reconnaissance in conjunction with minimum core drillings, followed by seismic refraction survey may amplify the confidence of FS report. The issue deserves further discussion during updating of existing feasibility study. The FS design the seismic hazard analysis supported, would be beneficial too. The Project location may lay within the seismic active zone making the seismic hazard study appropriative to FS stage, meaningful. The 165m high dam vulnerability could be largely induced by seismic movements. Hence, the earthquake intense classified according to Modified Mercally Intensity Scale, conjointly with pick ground acceleration estimated for, then, the epicenter recorded earthquake radiating hazardously to dam site and preferably its time history, would be the ba‐
sic data providing for qualitative assessment of high dam seismic behaviour for the FS stage. The Owner of the Project is strongly advised to encourage the Project Design Engineer to update the FS correspondingly. REPDC GREEN
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Résumé: Geological report including the geological investigation already executed, then Seismic hazard report, are advised to take a part of Updated Feasibility Study. V DD Review of Climatologic, Water Resources and Hydrologic Conditions The mean daily temperature seasonally fluctuating from ‐20C to + 270C has classified the dam site being subjected from cold continental to hot tropical climate impacts. Yet, the annual precipitation load of 385 mm indicated the arid climate conditions being dominant. The number of frozen days per a year which may affect the construction program was not indicated. Between the two limnigraph stations (the AGI‐21‐162, 1978 to 2009, and AGI‐21‐45, 1962 to 2009) the former one with 31 years statistical package, was promoted by FS‐DE being relevant to FS considerations. Here, some readings of AGI‐21‐162 have been missing and been undertaken from AGI‐21‐45. No information in FS has been recognized on number of readings the daily discharges were averaged on, the series of those resumed from AGI‐21‐45, then the analogy model applied whilst such statistical transfer. In resume, although the 31 years hy‐
drologic history is looking confident, source material on daily measurements and the analogy model merits detail discussion with the Owner prior to any FS updating. For further details of DD Review, see SH3 appendix herewith. The FS Hydrologic Report has produced the MY mean annual flow distribution and MY mean annual flow duration curves at dam axis, then the maximum flow evaluated for the same axis. Here, the probability rate and the statistical error attributable thereon should be appropriately elaborated aiming to arrive to net graphs of the foregoing curves or, to more certain water resource volumes remaining to be powered. The net hydrological val‐
ues including the methodology applied for, should be implemented to updated FS following their discussion with the Owner’s engineering team. The following hydrologic outputs have come out from the FS report: 9.71m3/s, the MY mean annual dis‐
charge; circa 3.5m3/s, the Q95 flow; 128.54m3/s, the max flow rate measured; 2.74m3/s, the minimum discharge measured. The percentage of 36 % of Q95 into Qmean has ranged the Ayvali Tohması River within those of base flow prevailing. The FS considerations were not extended to design floods returning after 5Yr, 10Yr, 50Yr, 100Yr, 1000Yr, 5000Yr, and 10000Yr, which are typically necessitated to large dam projects design. The probable maxi‐
mum flood was not discussed either. All these, led to conclusion that the existing hydrologic study should be up‐
dated correspondingly. According to SH4 appendix of herewith, the history related mean annual discharges graph, exhibited a viewable decreasing trend over the recent hydrologic history lengthening through 1996 to 2009. Pursuant to SH9 appendix, the recent history (2001 to 2009) is taking 70.44% of that of 31 years range. Given its significant effect to Plant production if the trend has proceeded further on, the issue requires a consideration in depth before any further Project development. The potential reasons for, such as the other water users, climate changes, and the like should be given serious attention. As a conclusion, the Owner of the Plant is advised to update the hydrologic study and actualize the water resources evaluation as soon as practicable. For more details about this section of DD Review, vide SH3, SH4, SH6 and SH9 appendices enclosed herewith. Résumé: Design Flood flows, Probability rate assigned, Attributable Statistical Error, Net MY mean duration curve, Net MY mean flow distribution curve, Impacts of declining trend of the recent hydrologic history(1996‐
2009), are advised to be a part of Updated Feasibility Study. VI DD Review of Reservoir Engineering as planned in FS The SH9 appendix of this DD report would be the most representative to the issue. Here below are the main FS outputs dealing with reservoir modeling which would deserve further consid‐
eration: 125m approximately, the reservoir depth at dam axis; 172.5M cum, the total reservoir storage (100%); 55.2M cum, the active reservoir storage (31.9%); 117.4M cum, the dead reservoir storage (68.3%). Besides, the 6.85 months, the 2.19 months and 4.66 months would be the filling time respectively to particular storages, counting the mean annual flow rate of 9.71m3/s. Finally, the total annual inflow aggregating to 306.2M cum cor‐
responds to 177.52% of reservoir total storage (172.5M cum). REPDC GREEN
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Design flood flow was not specifically discussed in FS. Whilst routing of that, the spillway capacity was construed to be 1546.3m3/s. That, summated with the installed power flow of 35.62 + 3.65 = 39.27 m3/s, makes in total circa 1586 m3/s, the discharge which the Author of FS was presumably adopted to be the design flood flow. Design flood and Design Surcharge depth, given the governing inputs to spillway capacity and dam crest evaluations, should be appropriate analysis backed in FS. The corresponding updating of FS is then recommended. While reviewing the forgoing FS outputs, the REPDC begun from the maximum operation level of the res‐
ervoir which was fixed at 1155m asl. Here the REPDC can only presume that the Author of the Study was primar‐
ily led by hydropower benefits whilst the environmental, infrastructural and resettlement constraints (if any) were not of the effect. Under the circumstances, the Owner is advised to run a cost‐benefit analysis, varying the MxOL and the active storage volume, aiming to realize the minimum production cost factor ($/kWh), the point at which the optimum reservoir solution should be expected. The active storage of the reservoir would be the next priority of FS. Pursuant to FS the active storage was confined to a depth of 15m, i.e. spaced between the elevations of 1140m and 1155m. In the absence of mass curve demonstrated, the REPDC could have only presumed that the Author of the Study had in mind the average April water yield of circa 54.5 M cum, which was subsequently used as ‘demand volume’ i.e. the active storage. Whatever was the Author’s idea, the active storage optimization should be appropriately elaborated within the updated FS. The aim would be allocating as greater as reasonable active storage volume for powering during the higher rated feed‐in tariff (0.09756 US$/kWh, June to August). Here, the issue that would be particularly relevant for further study is: the active storage constrained to only 31.9% of the total reservoir storage or to only the 18% of the total annual inflow. The sedimentation accumulation analysis, the sedimentation handling and mitigation measures inclusive, are to be conceptualized at FS stage too. In conclusion, due consideration in the Study should be paid to performance of the system: river inflow‐
reservoir capacity‐dam outflows, aiming to arrive to optimum reservoir model, including the optimum dam height. Unlike ample of structural issues remaining with final design phase, the reservoir modeling should be evaluated in detail whilst the FS stage. Résumé: Max Operation Level, the height of dam and active storage, optimizations; Preliminary sedimentation accumulation analysis; Potential sedimentation handling means. VII DD Review of Dam Hydraulic Setup and HP Parameters Unless the geological features favour otherwise, the applied barrage system embracing the dam integrated WW and PH, the over crest spillway, and the side bottom outlet, seems to be close to its optimum approach under the prevailing topo conditions. The same would apply to variety of gating systems as envisaged: radial gates, sliding gates, butterfly valves, and roller mounted gates. The butterfly ones are supposed to be of regulating type. Still, there are a number of the technical points that would merit further consideration. Under the circumstances it would be worth to note the SH5 appendix herewith, wherefrom the following elevations should be emphasized: 1155m, the MxOL; 1151m, the spillway crest elevation; 1140m the MnOL; 1080m, the intake elevation; 1078m, the bottom outlet elevation. Here, since the MxOL(1155m) overwhelms the spillway elevation(1151m), it is to presume that the radial gates will also be serving the retention a volume of ac‐
tive storage whilst in their shutdown position. Then, a clarification should be made on the means keeping design flood surcharge under control when a number or all of them should be open, and the way the control system will automate the surcharge process. In addition, the design criteria for evaluation of spillway elevation(1140m), the intake elevation(1080m) and the bottom outlet elevation(1078m) should be specifically clarified whereas their impacting the economic outcomes of the Project. Yet, pointing the bottom outlet to a higher position would di‐
minish the means for handling the fine sediments accumulated in front of dam. The issue was further discussed within SH7 appendix herewith. The Plants hydropower outputs are principally governed by the design (installed) Plants’ flows optimally utilizing the available water resource. To the effect, the 3.65 m3/s and 35.62m3/s proportioned to ecologic and Main Plant respectively, should enable optimum annual production. The optimization should then maximize the annual production of the plants and minimize their power rating, which in turn can decrease the cost of power generating sets. The Owner of the Project is advised to resume a sensitivity analysis aiming to spot the optimum REPDC GREEN
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Plants’ discharges. Meanwhile, the REPDC has conducted an approximate HP evaluation checkup, the results of which were collated with those of FS as follows: Description Feasibility Study REPDC Checkup Analysis ECOLOGIC PLANT MAIN PLANT ECOLOGIC PLANT MAIN PLANT Design(Installed) Flow Design(Installed Power) Mean Annual Produc‐
tion 3.65m3/s 35.62 m3/s 3.65m3/s (100%) (100%) (100%) 35.62 m3/s (100%) 5 MW 50 MW 4.63m3/s 45.23 MW (100%) (100%) (92.6%) (82.2%) 14037 MWh 112228 MWh 13100 MWh 94900 MWh (100%) (100%) (93.3%) (84%) The SHs 10, 11 and 14 herewith have detailed the checkup analysis made by REPDC. Regardless of techniques used in two approaches, a breakdown analysis of power evaluation and annual production evaluation should be conducted, which at the end can decisively affect the Owner decision to go or not with Project development. To this effect, the model of: inflow hydrograph‐the reservoir (operation levels and active storage)‐waterways (eleva‐
tion and capacity)‐power generating sets(capacity and efficiency), should be sensed up to its optimum capacity and economy. Along with that, the manufacturers with up‐to‐date factory techniques should be encouraged to offer the turbines of pronounced efficiency over their pick‐on and pick‐of regimes, followed by major overhauling periods being not less than of 40 years. It is assessed that the Project HP outputs could be improved by an analysis in depth which for the stage of feasibility study is essential and supportable in view of economic parameters arising out there from. The flood design criteria for dam and its associated structures components could be pivotal inputs to their design and subsequently to their cost. Hence the design floods attributable to diversion tunnel in conjunction with the upstream cofferdam, the reservoir flood surcharge and the spillway, merit being subject of debate at the stage of feasibility study. This is to avoid the unforeseen price pyramiding during Project development phase. Résumé: Flood design criteria for diversion tunnel and upstream cofferdam then for spillway; Design criteria for power intake and bottom outlet elevations; Optimization of reservoir‐waterways‐turbines system; Optimization the turbines number aiming to maximize annual production. Recommendation: The issues to be evaluated in depth whilst updated Feasibility Study. VIII DD Review of Structural Considerations As designed, the concrete structures and the underground structures conjointly with geotechnical structures of supporting rock mass, may considerably affect the engineering feasibility of the Project and thus its economic at‐
tractiveness. Correspondingly, the basic geotechnical considerations distinctive to FS stage should be carefully discussed whilst FS phase of Project. Here, the qualitative structural classification of rock substratum upon its inhomogenuity, deformability, shear strength and hydraulic conductivity, may favour the optimum dam option. The Owner of the Project is ad‐
vised to pay due attention to the issue before commencement of Project development phase. Under proviso of favorable geotechnical conditions, the option of conventional concrete gravity dam might be effective, particularly because of its convenience to have the waterways and the PH united in. The op‐
tion may be coded as earthquake resistant too. Direct and indirect cost wise, it would be also merit to make si‐
multaneous examination of roller compacted concrete option again integrating in the power house. Given its shorter construction time the option may offer promising outcomes. For more details about, the SH8 and SH9 herewith might be contributing. If for any site reason the compact concrete dam option has to be abandoned, then CFRD option remains to be considered as a spare alternative. This always under presumption of having locally available the rock fill ma‐
terial at a quantity required for. Résumé: Qualitative definition of bedrock conditions favouring concrete gravity dam options; Alternative op‐
tion with RolCrit Dam. Cost comparison between the two dam options. The appropriate updating of Feasibility study is recommended. REPDC GREEN
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IX DD Review of Mechanical and Electrical Considerations On the basis of parameters handled in FS, it is to conclude that type of turbines was selected to serve the pur‐
pose. The turbines flow (3.65m3/s or, 17.81m3/s) and the net head (159m) fell under the hydropower strip where the Francis turbines will be the most efficient in generating kinetic energy. The SH12 herewith i.e. a checkup analysis conducted by REPDC has confirmed the issue. The Owner of the Plant is advised to prepare the inception tender conditions for turbines supply accentu‐
ating specifically the major overhauling periods of not less than 40 years, the turbines having the pick‐on and pick‐
off efficiencies maximized, the operation range of which exceeds 40%, and finally the turbines with reasonable annual maintenance expenditures. In addition, the Manufacturer Guarantees (Warranties) for, should cover the defects liability period (DLP) of the Project, meaning the guarantee period be not shorter than 4 years from the date of turbines delivery. To the effect, the page 19, article 1.2 of annex 8 of Feasibility Study should be reconsid‐
ered. The same should apply to generators and step‐up transformers. If for any reason the manufacturer would not be able to improve the efficiency/operation range of turbines, an exercise with 3Nos. turbines should be also conducted. The aim would be to have the 3 turbines concurrently working at higher efficiency than 2 of them, which can contribute to higher Plant’s income. The pre‐tender quotations should be then called from the manu‐
facturers with recognized past performance and included in updated issue of FS. As for the electrical setup, the Owner is advised to supplement the existing FS with single line diagram wherefrom the appropriate insight into power, voltages and ampacities (each where appropriate) of the generat‐
ing units then the power transformation and transmission facilities. As for the transmission lines, the type of poles, the conductors cross section, the voltage and power drops should be preliminary calculated. The foregoing could lead to more accurate cost estimate. The Owner is advised to update the FS report correspondingly. Résumé: Efficiency and operation range of turbines to be upgraded; Major overhauling periods not shorter than 40 years. Optimum maintenance cost. The appropriate updating of Feasibility study is recommended. X DD Review of Capital Cost Considerations Under the FS design and detailing provided, the previous chapters of this DD report dealing with dam options and water resources utilizations, then the unit rates for the main work items REPDC has estimated for similar projects in Africa, Balkan Area, Middle and Far East countries, REPDC has conducted the alternative CAPEX analysis, which summary compared to that of FS, has resulted to: Feasibility Study
$47,957,639.65 959.54/kW $0.4440/kWh Versus REPDC Analysis
$88,447,115.40 $1,769.65/kW $0.8188/kWh That, broken‐down to main cost items, was tabulated as follows: Description
As per Feasibility Study
Advance Services and
$3,495,299.00
Works
$29,899,998.85
Civil Works
Mechanical and Electri$12,133,981.20
cal Works
$1,678,360.60
Transmission Line
Consultancy Services
$750,000.00
and Supervision
$47,957,639.65
Grand Total
As assessed by REPDC
7.29% 69.934 /kW
$0.0324 /kWh
$5,220,299.00
62.35% 598.24 /kW
$0.2768 /kWh
25.30% 242.78 /kW
$104.45 /kW
$0.0483
/kWh
$55,937,910.00
63.24% $1,119.21 /kW
$0.5178
/kWh
$0.1123 /kWh
$20,726,406.40
23.43%
$414.69 /kW
$0.1919
/kWh
3.50% 33.581 /kW
$0.0155 /kWh
$2,062,500.00
2.33%
$41.27 /kW
$0.0191
/kWh
1.56% 15.006 /kW
$0.0069 /kWh
$4,500,000.00
5.09%
$90.04 /kW
$0.0417
/kWh
100.00% 959.54 /kW
$0.4440 /kWh
$88,447,115.40
100.00% $1,769.65 /kW
$0.8188
/kWh
5.90%
Again, instead of FS power parameters of 55MW/112000MWh, the foregoing analysis has been referenced to those assessed by REPDC: 50MW/108000MWh. REPDC GREEN
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While drafting the alternative CAPEX analysis, the REPDC was led by his assessment that some CAPEX items were omitted in FS and some others appeared to be underestimated. That prejudiced REPDC professional stance that a successful construction of a project the largeness, and the site conditions similar to those of Kay‐
narca HPP, at a rate down to $1000/kW, could be aligned with uncertainties. Or, even if hypothetically it would appear feasible, the planned lifespan of 100 Years or 40 Years, to civil works and to power generating and trans‐
formation sets respectively, might be brought in jeopardy. Yet, it may be aligned with largely increased repairing works during Plant operation. In order to avoid the potential risks of undervalued capital cost, the Project Owner is advised to resume a much more detailed BOQ which should be priced up to date and be preceded with design optimizations discussed in previous chapters of this report. For more details of Capital Cost Review, see SH18 appendix herewith. Résumé: Original FS price might have been underestimated. Optimization of Feasibility Study design followed by detail BOQ currently priced is recommended. XI DD Review of Economic Considerations While discussing the Project Economic outputs affecting decisively the Project Feasibility process, the first flesh should be put on CAPEX and its power cost factors. Here, the REPDC analysis (SH18 herewith) has outcome the kickoff economic indices aggregating to: US$ 88.45M, the capital cost of Project; US$ 1770/kW, the Power Cost Factor (PU‐CF); US$ 0.82/kWh, the Electricity Production Cost Factor (EP‐CF). While a PU‐CF of US$ 1770/kW can be nowadays judged as economically affordable for the projects of size and type of Kaynarca HPP, the EP‐CF of US$ 0.82/kWh may be beyond the economic margin expected for such projects. The latter may be conjugated with the following causes: ‐
The Kaynarca Project design is still out of its optimum setup, or, ‐
The hydraulic and structural extent of the Project was over proportioned to available water re‐
sources, or, ‐
The utilization of available water resources was not optimized. The Owner of the Project is advised to consider each of the foregoing potentiality at its own merit aiming to reach an EP‐CF/Feed‐In Tariff Ratio which is not higher than 8. See the SH19 herewith for further details. Out of 100% of Operation and Maintenance cost estimated for an average calendar year, the 12.80%, 7.31% and 4.60% remain to Water Use cost, the Cost of State Network System Use and the Maintenance Cost, re‐
spectively. Those conjointly with other items, have reduced the Gross Annual Income of $ 8.55M to Net One of $ 6.10M. The total annual reduction reached thus the amount of circa $ 2.45M. The Return‐On‐Investment Period arising out from, has approached the margin of 14.5 Years. Simultaneously with that, the original analysis of FS would allow the 7.7 years Payback period, the main reason being the CAPEX which according to REPDC could have been underestimated. The details of this exercise were elaborated within the SH19 appendix herewith. Besides, the cost schedule embracing the Water Use cost up to Contingencies was strictly resumed from FS report (see SH19 herewith). As for the Annual Cost of Maintenance, the following lifespans to particular Project components were considered in DD Review Report: 100 Yr to civil structures, 40 Yr to power generating sets, 60 Yr to hydro‐mechanical equipment, 20 Yr to automation system. The fraction of Maintenance Cost was derived there from. Towards mitigating the 14.5 years of Investment payback period resulting from REPDC DD Review, REPDC suggests the stake sharing mechanism be implemented to concession agreement such that the Water Use cost (12.80%) and Cost of Network System Use (7.31%), are partially subsidized by Contracting Authority. The Net An‐
nual Income to Concessionaire would be then augmented, reducing thus the expected length of Return‐On In‐
vestment period. Résumé: The FS design optimization succeeded by subsidizing the Water Use Cost and Network System Use cost bay the Owner (the Contracting Authority), is to be considered. That may bring the Return‐On‐Investment pe‐
riod down to 10 Years. REPDC GREEN
13
Concluding Notes of DD Review The Project Passport tabulated hereafter was derived from FS considerations as construed by REPDC as well as from the REPDC DD Review appraisals concluded in this Report and its Appendices. Description Feasibility Study REPDC DD Review Report Capital Cost Expected Installed Power Expected Annual Production Power Cost Factor Production Cost Factor Time of Construction Return‐On‐Investment Period $ 47.96 M 55 MW 126000 MWh $ 872/kW $ 0.38/kWh 3.5 Years Circa 7.7 Years $ 88.45 M 50 MW 108000 MWh $ 1770 /kW $ 0.82 /kWh 3.5 Years Circa 14.5 Years The Passport presumed the hydraulic setup and structural design as it was envisaged in Feasibility Study. After having reviewed the Feasibility Study and the Project outputs discussed throughout this DD Review Report, the following feasibility grades could be assigned to KAYNARCA Project: Regulatory Feasibility Estimated as achievable . No insurmountable regulatory barriers were recognized in Feasibility Study. Engineering Feasibility Generally estimated as achievable. However, the feasibility rate should be further improved. Economic Feasibility Might be questionable if the declining water resources trends continue to evolve over the concession period of Project. That, even it was proved to be just a cyclic drop, but the optimized design of the Project and the water
resources utilization, have been hypothetically substantiated to be of in‐ sufficient effect. Under the circumstances, REPDC would advise the Owner of the Project to prioritize the current feasibil‐
ity study updating, aiming to enhance the lower rated engineering and economic feasibility grades re‐
viewed there‐through. To the effect, the optimization measures discussed throughout the Summary Re‐
port are expected to be instrumental to engineering and economic standing of the Project. The Owner of the Project is advised to proceed with Project development following its optimization. REPDC GREEN
14
Appendices REPDC GREEN
15
SH1
SH1 - Summary of Assessment Notes
FStudy Statements & REPDC
Recommendations
Descriptions
Project Name
Kaynarca Dam Project
Operation Concept Build-Operate - Transfer
3 Type of HP Project Gravity Storage Type
1
2
4
PPA Arrangement
6
7
Climatology
8
10
55MW/112,229.40MWh
The overall annual production can be sold in
the Market through PMUM
100%
Mean daily temperature
fluctuations
Circa -20C to Circa
+270C
Precipitation load fluctuations
2mm/M to 42mm/M
Total annual precipitation load 385 mm
Arid climate conditions prevail
3,514.80 km2 River: Ayvalı Tohması
Watershed Area
Ayvalı Tohma Water, 1978. The location is
to be clarified. Tohma Water Hisarcık, 1962.
Details, linked under Sheet3!A1
11
Limnigraph Stations
12
Average flow rate at the dam
axis: Qmean= Q28.77
13
Maximum flow rate at the dam
axis
14
Ecologic flow rate
Hydrology
Number of frozen days per a year should be
estimated
Average flow rate exhibits decreasing trend
9.71 m3/s in the period of 1994 onward. To be
Sheet3!A1
Sheet4!A1
clarified. Details linked under Sheet4!A1
128,54 m3/s
1.80m3/s: March, April, May.
1.80 m3/s 0.975m3/s for the rest of the year. P70, 57 Sheet9!A1
15
Q95
16
Flow Characteristics:
Q95/Qmean
17
Flood peak discharges
affecting the dam design
18
MY FDCurve and MY annual
distribution curve
circa 3.5 m3/s
36.00 %
Base flow regime is prevailing.
Details linked under Sheet6!A1
Flood return periods of 50 Yr, 100Yr,
1000Yr, 2000Yr, 5000Yr, and 10 000Yr.
Ending with the Probable Maximum Flood.
Details linked under Sheet4!A1.
The 31 year daily measurements, the
assessed probability rate, other water users,
and the like should be clearly indicted in the
Study
Sheet6!A1
Sheet4!A1
Sheet6!A1
General geology and
engineering geology
Not recognized in Feasibility Study. The
suitability of geological conditions is be
clarified.
To be reconfirmed by the Owner
Surrounding
23 Projects
No upstream projects are
planned
Five downstream projects.
One already constructed whilst the others
are within planning phase.
Details, linked under Sheet2!A1
Sheet2!A1
Reservoir
26 Engineering
Total Storage
Active Storage
Sheet5!A1
27
Dead Storage
Active storage of the reservoir bears only
31.97% of the total one. To be clarified.
Details, linked under Sheet5!A1
20
Geology
22
25
1.725E+08 m3
5.515E+07 m3
1.174E+08 m3
REPDC GREEN
16
SH1
28 Reservoir Engineering
Sedimentation Storage
29
Floods volume
Not discussed in the feasibility study. The
Owner's clarification would of interest to
Project assessment.
Not discussed in the feasibility study. The
Owner clarification would help assessing the
dam crest elevation and the spillway
capacity.
Details, linked under Sheet5!A1
Reservoir
Engineering
30
Floods routing
The Preliminary flood routing analysis, in
conjunction with the outflow dam outlets
capacity as evaluated in the Study, that of
over-crest spillway, the waterway and the
bottom outlet should be a part of the Study.
Details, linked under Sheet5!A1
31
Classified upon Storage
Large HP Storage( >60 M cum)
33
Project Setup &
Dam Options
Conventional Concrete Gravity
dam with over-crest spillway
and integrated PHouse
34
Alternative Option recomeded
by REPDC: Roller Compacted
Concrete Gravity dam with
over-crest spillway and
integrated PHouse
35
Classified upon Height
37
Hydropower
Features
Issues to be particularly discussed in the
Study:
- Foundation geotechnical conditions,
- Sedimentation accumulation discharge,
- Seismic hazard level, expected in the
region,
- Hydraulic model test concept relative to
spillway outflow jet.
- Subject to conclusions outcome, the
conventional concrete gravity dam can be
an option.
Details, linked under Sheet7!A1
The following features may favour the
Rolcrit Dam Option:
- Shorter construction time, and
- More economic construction cost.
To the effect, the option is recommended to
be a part of Feasibility Study considerations
as well.
Details, linked under Sheet8!A1
Large HP Dam(H=165m >10m )
Sheet5!A1
Sheet5!A1
Sheet7!A1
Sheet8!A1
Main Plant + Ecological Plan
within the same HP House.
39 Main Plant
40
Storage Pick-On Type
Type
41
Number
42
Turbine flow
Serving 'Pick -On' demands
Details, linked under Sheet12!A1
Francis
Sheet 12'!A1
2
The turbine flow as indicated in feasibility
2x17.81 m3/s study should be supported by appropriate
Sheet9!A1
analysis.
43
Gross Head
44 Main Turbines
Net Head
45
Installed capacity
46
Working hours per annum
47
48
Annual production
Classified upon capacity
160.00 m
159.00 m
The checkup analysis showed the real plant
2 x 25 MW power of 2 x 22.6 MW.
2,052.00
98,190.70
Hr
MWh
23.4% on average of total annual hour,
equal to 85.5 days during June, July,
August.
Large HP Plant(>30 MW)
REPDC GREEN
Sheet 12'!A1
17
SH1
50 Ecologic Plant
Storage Pick-On/Off Type
51
Type
52
Number
53
Turbine flow
54 Ecologic Turbines
Net Head
55
Installed capacity
56
Working hours per annum
57
58
Annual production
Classified upon capacity
60 Annual Production
61
Francis
1
3.65
Minimum flow rate measured: 2.74 m 3 /s
3
m3/s Q ecolog =3.33m /s(November-April)
Q ecolog =4.44m 3 /s(May-October)
The checkup analysis showed the real plant
5 MW power of 1 x 4.63 MW.
8,766.00 Hr 100% on average of total annual hours
14,038.70 MWh
An analysis in depth should be integrated
with Feasibility Study. The FDC and ADC
daily measurements based and a probability
and statistical error distinctive to watershed
nature should secure the confidence of
annual production.
Annual production
commensurate to
daily/weekly/monthly River
discharges.
66
Exchange Rate US$/TL
67
Management of incremental
storages to be powered under
Peak time price.
69
Upstream Cofferdam and
Derivation Tunnel
Serving 'Pick -On' demands
0.09756 $/kWh P44, P57, P59, June& August
0.07254 $/kWh P44, P57, September to May
1.78150
P92
Average time price
Particular
Overcrest Spillway
Structures Designs
71
15km of 154kVA of energy
transmission line
72
Penstock
Towards the further confidence
improvement, the Design Engineer of the
Owner is advised to run the appropriate
analysis based on MY mean daily or at least
the mean weekly river discharges.
The flood criteria applied for evaluation of
upstream cofferdam height (cca 16m)and
radius of derivation tunnel(cca 6m), should
be clarified.
Clarification to be detailed: The design
criteria on the basis of which the spillway
crest level was evaluated.
Any upgrading of Darende substation due to
Plant connection? To be clarified.
The penstock walls seem to be
underestimated. The brief structural analysis
should be conducted.
Water use and
environmental permits
Status of the permits to be clarified
75
Preliminary construction and
electricity producer permits
Status of the permits to be clarified
76
Permits on Land use
Status of buyout of 2,348,743 m2 land to be
inundated, to be clarified.
Project Implementation
Program
3.5 Years construction time was scheduled.
The project development phase and defect
liability period should be further discussed.
78
Status of Permits
Project
Implementation
Sheet10!A1
Small HP Plant( <10MW)
Peak time price
74
Sheet9!A1
158.65 m
63
Management of Plant
64
annual production
65
70
Sheet 12'!A1
79
REPDC GREEN
Sheet15!A1
Sheet16!A1
Sheet17!A1
18
SH1
80
82
Capital Cost
Expenditures
Civil and Electro-Mechanical
Works
872.00 US$/kWh
Economic Analysis
7.7 vs 14.5 Years
Civil and Electro-Mechanical
of Return-OnWorks
Investment Period
$47,957,639.65
It would be difficult to achieve successful
construction of a project, the largeness and
the site conditions similar to those of
Kaynarca HPP, at a rate beneath
$1000/MW.
Sheet18!A1
There is apparently a significant separation
between the economic parameters
concluded in feasibility study and those
estimated by REPDC.
Sheet19!A1
REPDC GREEN
19
SH2
SH2 - Downstream HP Projects
●Medic Project: 12MW, combined power/irrigation production,
●Gudul WR regulating Project, under planning phase,
●Merkez WR regulation Project, under planning phase,
●Catalbache WR regulating Project, under planning phase,
●Kuskonmaz,WR regulation Project, under planning phase,
●Sadikli, WR regulating Project, under planning phase.
REPDC GREEN
20
SH3
SH3 - Kaynarca Dam Project Watershed
Ayvalı Tohma Water, 1978, relevant for the Project FS design
Description of FS:
(1) AGI-21-162, Ayvalı Tohma Water, LStation. Established on 1-09-1978. 31 Year hydrological
history.
(2)AGI-21-45, EİE Tohma Water Hisarcık. Established on 30-06-1962. 47 Years hydrological
history.
The readings of the AGI-21-162 station have been promoted by the Owner Design Engineer to
be relevant for the Project design. Missing readings of AGI-21-162 have been resumed from AGI21-162.
DD Notes:
(1) Location of AGI 21-162 gauging station should be clarified.
(2) The length of hydrological history used from AGI-21-45 to supplement the hydrological series
of AGI-21-162 would be of effect to Project assessment. The same for the analogy model
between the two stations.
(3) The number of daily measurements used for statistical evaluation should be clarified. Towards
rounding the DD process, the list of all daily measurements used for evaluation of hydrological
inputs for the Plant should be discussed in first instance.
(4) The probability rate and the statistical error assigned to evaluation of MY mean annual flow of
9.714 m3/s would be of interest to analyze too.
(5) Within the Project sensitivity analysis, the mean annual flow reflecting the period of 1996 to
2012 should be considered either.
(6) A comprehensive hydrological analysis or that updated one should be produced in order to
make the economic outputs of the Project more confident.
REPDC GREEN
21
SH4
SH4 - Kaynarca Dam Axis, MY Mean annual
flows
DD Notes:
(1) As per the diagram, the multiyear mean annual flows evaluated for the profile of
dam axis, exhibits the decreasing trends from 1994 onward. It would be of utmost
importance for a competent DD of Project performance, to locate the reasons for
such a trend and to forecast flows trendline for the period spanning at least the
following 30 years.
(2) The MY mean annual flow evaluated from the recent hydrological history (1994
to 2012)might be indicative if included within the sensitivity analysis of power and
the economic outputs of the Project.
(3) The probability rate and the statistical error affecting determination of MY mean
annual flow of 9.714 m3/s are to be clarified. To this effect, the probability of equal
or greater than 50%(P59) assigned to, deserves further consideration.
(4) Under the circumstances, the flood peak discharges defining the design criteria
of the dam and its outlets, should have been discussed within FS too. Those being
but not limited to: flood return periods of 5Yr, 10Yr, 50 Yr, 100Yr, 1000Yr, 2000Yr,
5000Yr, and 10 000Yr. The Probable Maximum Flood is the ending data which
should be appraised at FS stage of dam's design either.
REPDC GREEN
22
SH5
SH5 - Key Outcomes of Reservoir Engineering
1
2
3
Description
Reservoir
4
Engineering
5
6
7
8
9
Total Storage
Active Storage
Dead Storage
Average flow rate at
the dam axis
Reservoir depth at
Dam axis
Design flood depth
Operation depth of
Active Storage
Total Annual Inflow
to Reservoir
Volume
1.725E+08 m3
5.515E+07 m3
1.174E+08 m3
Percentage
100.00%
31.97%
68.03%
Time of Initial
Impoundment
Days
Months
205.62
65.74
139.88
6.85
2.19
4.66
Circa 56% of total annual inflow
Circa 18% of total annual inflow
9.71 m3/s
Circa 125 m
To be clarified
Hoperative = 15 m
3.062E+08 m3
Question: The criterion of having only the 15m operation
depth should be clarified.
177.52%
1155m MxOL
1151m SpL
1140m MnOL
1080m Intake El
REPDC GREEN
23
SH5
DD Notes:
(1) Active storage of the reservoir bears only 31.97% of the total one and only of circa
18 % total annual inflow. It would deserve further clarification, given its influence to
economic outputs of the Projects.
(2) Sedimentation load of the reservoir and in consequence, the sedimentation storage of
the reservoir should be clarified.
(3) Flood volume, affecting the spillway capacity and dam crest altitude were not discussed
in the Study. Clarification would be required prior to final DD Analysis.
(5) Whilst the probability analysis, the flood peak discharges and the appropriate flood
volumes, should be evaluated for several return periods which are meritorious for setting
the dam design criteria. Those being but not limited to: flood return periods of 5 Yr, 10Yr,
50 Yr, 100Yr, 1000Yr, 2000Yr, 5000Yr, and 10 000Yr. The Probable Maximum Flood is the
ending data which should be appraised at feasibility study point of dam's design process.
(6) The depth of flood reservoir surcharge(15m) is to be clarified.
REPDC GREEN
24
SH6
SH6 - MY Flow Duration Curve
Qturbin = Q6=34.2m3/s
Q95=3.5 m3/s
Qmean = Q28.77=9.714 m3/s
REPDC GREEN
25
SH6
DD Notes:
Apart from inflow hydrograph and the inflow MY flow duration graph presented in FS, the
following issues would deserves further discussion at the feasibility study level:
(1) The Preliminary flood routing analysis, in conjunction with the dam outlets designed in
the study, those of over-crest spillway, the waterway and the bottom outlet. As for the
waterways, the scenarios of turbines operation whilst the pick -on electricity production
should be counted in.
(3) The potential losses of ponding water i.e. seepages through bottom and hillsides of
reservoir and due to those being exerted through grout curtains, should be estimated.
REPDC GREEN
26
SH7
SH7 - Conventional Concrete Gravity Dam Option
Over-crest Spillway and integrated PHouse
REPDC GREEN
27
SH7
DD Notes:
Description of Dam Setup
(1) Dam setup: Over-crest gated spillway; Integrated Intake and Power House; Diversion
Tunnel with its subsequent conversion to Bottom Outlet.
(2) Drainage galleries, grout curtain and grouting galleries, not indicated. It should be
clarified before final DD analysis.
(3) Key dam elevations: Dam Crest 1160m; Dam Spillway: 1150.85m; Intake: 1075m;
Foundation Interface: 987.40m to 1015m; PHouse 995m; Diversion tunnel: 1021m;
Bottom outlet: 1078.75m; Dam height: 145m to 165m.
Queries and Recommendations
(4) The dam foundations water tightness and geological competitiveness of dam
foundation should be clarified.
(5) Grout curtain and its depth is to be appraised and included in the economic analysis
appended to FS.
(6) Whereas the appreciable spillway altitude designed, the flow dissipation basin basics
deserve discussion at the feasibility study stage.
(7) Design criteria appropriated to power intake(1075m) and bottom outlet (1078.75m)
evaluations, should be clarified.
(8) Measures alleviating the sediments accumulation, would be important for considering
on feasibility study level.
(9) The radial gates, the bonnet gate and pre-turbine valves, are presumed to control
downstream outflows. Question to be clarified: in case of future needs the Kaynarca
pond should act as regulating storage to the downstream reservoirs, the role of the
designed gating system should be clarified.
(10) Since Max OL(1155m) is designed to be above the spillway elevation(1151m), it
appears that the radial gates were conceived to hold a volume of active storage of the
reservoir. Question to be discussed: Does the economy may favour the use of
fusegates, instead.
(11) Seismic hazard and its effect to potentially faulty structure of dam footprint, should
be appropriately discussed at the level of engineering feasibility.
(12) The need for hydraulic model test of spillway outflow jet, which is customarily
distinctive to final design phase, would be worth discussing in the study. This is to the
effect of safety of handling the draft tubes gates whilst the intensive flow jet is
propagated over the draft tube cover slab.
(14) The dam heal hollowed by Power House, might be critical in view of stress
concentrations. Inward shifting of Power House cavern might be necessary in case of
overstressing.
Interim Conclusion
Subject to conclusions coming out from engineering discussions of the foregoing issues,
the proposed conventional concrete dam option, might be responsive.
REPDC GREEN
28
SH8
SH8 - Roller Compacted Concrete Gravity Dam
Option
Over-crest Spillway and integrated PHouse
Recommendation:
Contemporaneous consideration of a Rolcrit Dam option, with over-crest spillway and
integrated power house, should be examined as well and the cross-comparative outputs
with conventional one, be collated. If the former has been proved feasible, the
consideration should help deriving the optimum dam option. The Rolcrit Dam could only
be promoted under the availability of suitable geological conditions. To the effect of both
dam options, the geological conditions are playing appreciable role and are to be
appropriately detailed in the Feasibility Study.
Under the existing topo and presumably favourable geological conditions, the following
features may promote the Rolcrit Dam Option as prevailing to that of conventional one:
- Shorter construction time, and
- More economic construction cost.
Given that, the recommendation is the Feasibility Study considerations are to be
extended appropriately.
REPDC GREEN
29
SH9
SH9 - MY Mean Annual Inflow and MY Ecologic
Outflows vs Turbine Flows
Average flow rate at the dam
axis: Qmean= Q28.77, 31 Yrs
1 HRange 1978 to 2009
9.71 m3/s 100.00%
3.33 m3/s
34.28%
Minimum flow rate measured: 2.74 m 3 /s
Q Tecolog =3.33m 3 /s(November-April). P56
4.44 m3/s
45.71%
Minimum flow rate measured: 2.74 m 3 /s
Q T ecolog=4.44m 3 /s(May-October). P56
3.65 m3/s
37.57% evaluation. P70.
2
Ecologic Plant Turbine Flow
3
4 Main Plant: Turbine flow
5 Compulsory Ecologic Outflow
Average flow rate at the dam
axis: Qmean, 9 Yrs HRange
1 2001 to 2009
2x17.81 m3/s
1.8 to 0.975 m3/s
6.84 m3/s
Average turbine flow used in hydropower
366% of 9.71 m3/s
Max 18% of 9.71 m3/s.
P57
70.44%
DD Notes and Recommendations:
(1) There are contradictions spotted in the Study between the ecologic plant turbine
flow (3.65m3/s) and compulsory ecologic outflow (1.8m3/s), Pages, 56, 57 and 70.
(2) In the light of Para (1) herein, the design criterion of 3.65 m3/s for ecologic plant
turbine flow, deserves detail clarification and supporting analysis. It is to note that the
installed capacity of ecologic turbine defined in FS, was derived there from.
(3) As regards of Paras (1) and (2) from here above, the analysis supporting the Main
Plant turbine flow of 2 x 17.81m3/s would be vital towards valid assessment of
hydropower and economic parameters of the Project. The two main plant turbines
installed capacities handled in FS, were based thereon.
(4) The mean MY annual flow comprising the period of 2001 to 2009, remains to
70.44% of design one(1978 to 2009: 9.71 m3/s). The appropriately inputted sensitivity
analysis of Project production should be exercised in order to assess the effects of
climate changes (if any).
REPDC GREEN
30
SH10
SH10 - Approximate Checkup of Hydropower Evaluation
Ecologic Hydropower Plant
1
2
3
4
5
On River Storage
Type of the Plant:
Formula:
P =  * g * Qturbine * H net * 
Real Hydraulic Power:
6
Inputs:
7
Max Turbine Flow (March, April, May)
Q turbine
Hnet
ρ
g
hturbin
Net Head at Installed Turbine Flow
Water Density
10 Gravity Acceleration
Turbine Efficiency at Pick(Installed) Flow
8
9
11
12
13
14
15
Generator Efficiency at Pick(Installed) Flow
Transformer Efficiency
[W]
3,650.00 l/s
158.65 m
1.00 kg/dm3
9.81 m/s2
0.93
hGenerator
0.90
hTransf
0.98
P70
Derived Inputs:
16 Installed Plant's Turbine Flow
17 Minimum Turbine Flow:
Q Plant
3,650.00 l/s
Q Plant
hPlant
1,460.00 l/s
0.82
Instl
18 Francis Makeup Application (0.40* InstlQ Turbine)
19 Plant's Efficiency hPlant=hPlant *hTurbin* hTransf
Min
20
Plant's Real-Output Power Evaluation:
Real Hydraulic Power [Preal] of Plant
22
21
23
24
Description
Max & Installed
Min Serviceable
25 Francis
26
27
28
29
30
31
Fraction
[W]
Q Plant
[kW]
Q Plant/KW
[m3/s]
[MW]
[l/s]
100.00%
4.63E+06
4.63E+03
4.63E+00
3.65
0.79
40.00%
1.85E+06
1.85E+03
1.85E+00
1.46
0.79
Q turbin =
Turbined Flow:
P
*10-3 m3 /s
 * g * H net * 
Plant's Input Power Evaluation:
32
Pinput =
33
P
 plant
34
35
36
Input Hydraulic Power [Pinput] of Plant
Description
Max
& Installed
37
Fraction
122.57%
[W]
[kW]
5.68E+06
5.68E+03
Feasibility Study vs REPDC Assessment:
Q Plant
Q Plant/KW
3
[m /s]
[MW]
5.68
5 MW
REPDC GREEN
3.65
vs
[l/s]
0.79
4.63MW
31
SH10
DD Notes & Recommendations:
(1) The vital issue would be the supporting analysis of Feasibility Study justifying
the turbine flow rate of 3.65m3/s.
(2) Secondly, the analysis on the basis of which the input Power of Ecological
Plant of 5.00 MW was concluded in Feasibility Study. This is to locate the reasons
of its separation to the approximate checkup analysis run herein (4.63MW).
(3) The up-to-date turbine assemblies are equipped with operation range of up to
30%. The prospective manufacturer of turbines should be encouraged to
comment the issue in view of 40% operation range achievable by his
manufacturing technology.
REPDC GREEN
32
SH11
SH11 - Approximate Checkup of Hydropower
Evaluation
Main Hydropower Plant
1
On River Storage
Type of the Plant:
2
3
4
5
6
Formula:
7
Inputs:
P =  * g * Qturbine * H net * 
Real Hydraulic Power:
8 Max Turbine Flow (March, April, May)
9 Net Head at Installed Turbine Flow
10 Water Density
11 Gravity Acceleration
Turbine Efficiency at Pick(Installed) Flow
Q turbine
Hnet
ρ
g
hturbin
12
13
14
15
16
Generator Efficiency at Pick(Installed) Flow
35,620.00 l/s
158.65 m
1.00 kg/dm3
9.81 m/s2
0.93
hGenerator
0.90
hTransf
0.98
Transformer Efficiency
[W]
P70
Derived Inputs:
Q Plant
35,620.00 l/s
Q Plant
hPlant
14,248.00 l/s
0.82
17 Installed Plant's Turbine Flow
Instl
18 Minimum Turbine Flow:
19 Francis Makeup Application (0.40* InstlQ Turbine)
Min
20 Plant's Efficiency hPlant=hPlant *hTurbin* hTransf
21
Plant's Real-Output Power Evaluation:
Real Hydraulic Power [Preal] of Plant
23
22
Description
Max
& Installed
25
Min
Serviceable
26 Francis
27
28
29
30
31
24
32
Q Plant
Q Plant/KW
[m3/s]
Fraction
100.00%
4.52E+07
4.52E+04
45.23
35.62
0.79
40.00%
1.81E+07
1.81E+04 1.81E+01
14.25
0.79
[W]
[kW]
Q turbin =
Turbined Flow:
[MW]
[l/s]
P
*10-3 m3 /s
 * g * H net * 
Plant's Input Power Evaluation:
33
Pinput =
34
P
 plant
35
36
37
Input Hydraulic Power [Pinput] of Plant
Description
38 Max & Installed
Fraction
100.00%
[W]
[kW]
5.54E+07
5.54E+04
Feasibility Study vs REPDC Assesment:
Q Plant
[MW]
55.44
50 MW
REPDC GREEN
Q Plant/KW
[m3/s]
35.62
vs
[l/s]
0.79
45.23MW
33
SH11
DD Notes & Recommendations:
(1) The vital issue of FS would be the supporting analysis justifying the turbine
flow rate of 35.62m3/s.
(2) Secondly, the analysis by which the input Power of Main Plant of 50 MW
was concluded in Feasibility Study. This is to locate the reasons of its
separation to the approximate checkup analysis run herein (45.23MW).
(3) The up-to-date turbine assemblies are reaching the operation range of up
to 30%. The prospective manufacturer of turbines should be encouraged
comment the issue in view of 40% operation range offered by his workshop.
REPDC GREEN
34
SH12
SH12 - Approximate Checkup Analysis of Turbines
Background
I
II
III
IV
Impulse Turbines– Pelton, free-jet, high head turbines, hydraulic heads of 200 to 2000m.
Reactive Turbines – Bulb, placed directly in water stream.
Reactive Turbines – Kaplan, axial flow low head turbines, hydraulic heads of 5 to 50m.
Reactive Turbines – Francis, radial-axial flow, medium head turbines, hydraulic heads of 50 to 200m.
REPDC GREEN
35
SH12
Main Plant
I Synchronous Rotational Speed of Generator
Formula:
Sinchronous Rotational Speed:
Type of Generator:
N=
f*120
z
Salient Type
Inputs:
Generator Frequency
Number of Generator's Poles
f
z
50.00 Hz
8.00
Rotational Speed(Number of revolution per a
minute)
N
500.00 rpm
II Turbines Specific Speed
Formula:
Specific Speed:
 Q 
N*  instal Plant 
n
Nq =  ^0.75 
(H) net
^0.5
Installed Turbine Discharge QTurbin 
instl
QPlant
n
Inputs:
Installed Plant's Turbine Flow
n
3
35.62 m /s
2
instlQturbin
17.81 m3/s
Q Plant
Instl
Selected Number of Turbines
Installed Turbine Discharge
Rotational Speed(Number of revolution per a minute )
N
Net Head at Installed Turbine Flow
Hnet
Specific Speed
Nq
Pturbin
Input Turbine Power: Pturbin = P/n
500.00 rpm
159.00 m
47.13
27.72 MW
III Selection of Type of Turbine
Criteria:
Nq < 20
20< Nq < 120
Nq >100
Impulse Pelton Turbine is recommended
Radial Flow -Axial Francis Turbine is recommended
Axial Flow Kaplan Turbine is recommended
Francis Turbine was proved as
appropriate:
instlQturbin
3
17.81 m /s
minQturbin
3
7.12 m /s
27.72 MW
11.09 MW
Pturbin
minPturbin
Comments & Recommendations:
(1) Francis turbine type was proved as appropriate to the Plant.
(2) The real turbine power as checked(45.23MW/2) is below the one evaluated in the
Study(25MW). A detail analysis supporting the IPC of 25 MW is advised to be appended to
Feasibility Study.
(3) The operation range of turbine of 100% to 30% should be considered.
REPDC GREEN
36
SH12
Ecologic Plant
I Synchronous Rotational Speed of Generator
Formula:
Sinchronous Rotational Speed:
Type of Generator:
N=
f*120
z
Salient Type
Inputs:
Generator Frequency
Number of Generator's Poles
f
z
50.00 Hz
8.00
Rotational Speed(Number of revolution per a
N
750.00 rpm
II Turbines Specific Speed
Formula:
Specific Speed:
 Q 
N*  instal Plant 
n
Nq =  ^0.75 
(H) net
^0.5
Installed Turbine Discharge QTurbin 
instl
QPlant
n
Inputs:
Installed Plant's Turbine Flow
Q Plant
n
instlQturbin
Instl
Selected Number of Turbines
Installed Turbine Discharge
Rotational Speed(Number of revolution per a minute )
Net Head at Installed Turbine Flow
N
Hnet
Specific Speed
Nq
Pturbin
Input Turbine Power: Pturbin = P/n
3.65 m3/s
1
3.65 m3/s
750.00 rpm
159.00 m
32.00
5.68 MW
III Selection of Type of Turbine
Criteria:
Nq < 20
20< Nq < 120
Nq >100
Impulse Pelton Turbine is recommended
Radial Flow -Axial Francis Turbine is recommended
Axial Flow Kaplan Turbine is recommended
Francis Turbine was proved as
appropriate:
instlQturbin
3
3.65 m /s
minQturbin
3
1.46 m /s
5.68 MW
2.27 MW
Pturbin
minPturbin
Comments & Recommendations:
(1) Francis turbine type was proved as appropriate to the Plant.
(2) The real turbine power as checked(4.63MW) is beneath the one evaluated in the
study(5MW). A detail analysis supporting the IPC of 5 MW is advised as appendix to
Feasibility Study.
(3) The operation range of turbine of 100% to 30% should be considered.
REPDC GREEN
37
SH14
SH14 - Approximate Checkup of Monthly Productions
Monthly Productions commensurate to Monthly Inflows
1 Active Storage
55,150,000.00 m3
Ecologic Plant Turbine
3.65 m3/s
2 flow
Main Plant Turbine flow:
3 2 x 17.81 m3/s
4 Compulsory Ecologic
5 Flow
7
9
January
11
February
12
March
13
April
14
May
15
June
16
July
17
August
18 September
19
October
20 November
21 December
22
23
1.80 m3/s
0.975 m3/s
March, April, May
June to February
Production of Ecologic Plant
Period
10
35.62 m3/s
Annual
MY Mean
Monthly
Flows(m3/s)
7.585
8.046
13.650
21.004
15.205
9.710
6.802
5.740
5.932
7.257
7.812
7.829
9.714
Average
MY Mean Monthly Storages (m3)
(Max to 5.515 *107)
20,315,664.00
19,464,883.20
36,560,160.00
54,442,368.00
40,725,072.00
25,168,320.00
18,218,476.80
15,374,016.00
15,375,744.00
19,437,148.80
20,248,704.00
20,969,193.60
306,299,750.40
Total
Compulsory
Ecologic
Flows(m3/s)
0.975
0.975
1.800
1.800
1.800
0.975
0.975
0.975
0.975
0.975
0.975
0.975
Storage Volume
exploited by Ecologic
Plant (m3)
Ecologic Plant
Nominal turbine
flow(m3/s)
Power Hours per
Month (Hr)
Ecologic Plant Real
Power (kW)
MY Mean Monthly
Production (kWh)
Storage Volume
outstanding to Main Plant
(m3)
2,611,440.00
3.65
198.74
4.63E+03
9.20E+05
17,704,224.00
2,358,720.00
3.65
179.51
4.63E+03
8.31E+05
17,106,163.20
4,821,120.00
3.65
366.90
4.63E+03
1.70E+06
31,739,040.00
4,665,600.00
3.65
355.07
4.63E+03
1.64E+06
49,776,768.00
4,821,120.00
3.65
366.90
4.63E+03
1.70E+06
35,903,952.00
2,527,200.00
3.65
192.33
4.63E+03
8.90E+05
22,641,120.00
2,611,440.00
3.65
198.74
4.63E+03
9.20E+05
15,607,036.80
2,611,440.00
3.65
198.74
4.63E+03
9.20E+05
12,762,576.00
2,527,200.00
3.65
192.33
4.63E+03
8.90E+05
12,848,544.00
2,611,440.00
3.65
198.74
4.63E+03
9.20E+05
16,825,708.80
2,527,200.00
3.65
192.33
4.63E+03
8.90E+05
17,721,504.00
2,611,440.00
3.65
198.74
4.63E+03
9.20E+05
18,357,753.60
1.31E+07
268,994,390.40
37,305,360.00
Total
12.18%
2,839.07
Total
Of the total annual
yield(22)
REPDC GREEN
Total
1.40E+07
According to
Feasibility Study
Total
38
SH14
26
Production of Main Plant
Period
28
29
January
30
February
31
March
32
April
33
May
34
June
35
July
36
August
37 September
38
October
39 November
40 December
41
42
Annual
MY Mean
Monthly
Flows(m3/s)
7.585
8.046
13.650
21.004
15.205
9.710
6.802
5.740
5.932
7.257
7.812
7.829
9.714
Average
MY Mean Monthly Storages (m3)
(Max to 5.515 *107)
Main Plant
Nominal turbine
flow(m3/s)
20,315,664.00
35.62
19,464,883.20
35.62
36,560,160.00
35.62
54,442,368.00
35.62
Storage Volume
remaining for Main
Plant (m3)
Power Hours per
Month (Hr)
Main Plant Real
Power (kW)
138.06
45,230.00
6.24E+06
17,106,163.20
133.40
45,230.00
6.03E+06
31,739,040.00
247.51
45,230.00
1.12E+07
49,776,768.00
388.18
45,230.00
1.76E+07
1.27E+07
17,704,224.00
40,725,072.00
35.62
35,903,952.00
279.99
45,230.00
25,168,320.00
35.62
22,641,120.00
176.56
45,230.00
7.99E+06
18,218,476.80
35.62
15,607,036.80
121.71
45,230.00
5.50E+06
4.50E+06
15,374,016.00
35.62
12,762,576.00
99.53
45,230.00
15,375,744.00
35.62
12,848,544.00
100.20
45,230.00
4.53E+06
19,437,148.80
35.62
16,825,708.80
131.21
45,230.00
5.93E+06
6.25E+06
6.48E+06
20,248,704.00
35.62
17,721,504.00
138.20
45,230.00
20,969,193.60
35.62
18,357,753.60
143.16
45,230.00
306,299,750.40
9.49E+07
268,994,390.40
Total
Total
87.82%
Total
9.82E+04
Of the total annual
yield(41)
44
46
47
48
MY Mean Monthly
Production (kWh)
According to
Feasibility Study
Cross-Comparable Outputs:
Feasibility Study
5 MW
50 MW
REPDC Assessment
14,037 MWh
98,190.7 MWh
4.63 MW
45.3 MW
13,144.9 MW
94,879.7 MWh
DD Notes & Recommendations:
(1) There was concluded a marginal separation in MY mean annual productions between the Feasibility Study and REPDC checkup analysis.
(2) Still, an elaborative supporting analysis should be presented by the Author of Feasibility Study, aiming to back the real powers and annual
productions there derived.
(3) Probability 50%(P59) the Design Engineer has allocated to flow duration curve and annual distribution curve should be clarified and improved
in the context of their confidence.
REPDC GREEN
39
SH15
SH15 - Management of Annual Hydropower Resources
Approximate Checkup of Gross Annual Income by relocating of monthly yields to higher Feed-In
Tariff
Peak time price
Average time price
Exchange Rate US$/TL
0.09756 $/kWh
0.07254 $/kWh
1.78150
P44, P57, P59, June& August
P44, P57, September to May
Annual Redistribution of Active Storage aiming to
amplify the storage to be powered under higher FeedIn Tariff
Period
MY Mean
Monthly
Flows
(m3/s)
MY Mean Monthly
Inflows (m3)
Annual
Redistribution of
Monthly Yields (m3)
Monthly Storages
intended to Power
(m3)
(Max to 5.515 *107)
MY Average - Gross Ecologic Plant Income
Compulsory
Storage Volume
Ecologic Plant
Power
Ecologic
Ecologic Flows
exploited by
Nominal turbine Hours per Plant Real
(m3/s)
Ecologic Plant (m3)
flow(m3/s)
Month (Hr) Power (kW)
August
7.585
8.046
13.650
21.004
15.205
9.710
6.802
5.740
September
5.932
15,375,744.00 Annual Maintenance
October
19,437,148.80
12,848,544.00
32,285,692.80
November
7.257
7.812
20,248,704.00
0.00
20,248,704.00
0.975
0.975
December
7.829
20,969,193.60
0.00
20,969,193.60
0.975
January
February
March
April
May
June
July
Annual
Average
Gross Ecologic
Plant Income
US$
Main Plant
Nominal
turbine
flow(m3/s)
Storage Volume
exploited by Main
Plant (m3)
Power
Hours per
Month (Hr)
Main Plant
Real Power
(kW)
MY Mean
Feed-In
Monthly
Tariff
Production (kWh) US$/kWh
Gross Main Plant
Income
US$
Gross - Both Plants
Income
US$
Period
2,611,440.00
3.65
198.74 4.63E+03
9.20E+05 0.07254
$66,748.76
35.62
17,704,224.00
138.06
45,230.00
6.24E+06
0.07254
$452,985.83
$519,734.60
January
2,358,720.00
3.65
179.51 4.63E+03
8.31E+05 0.07254
$60,289.21
35.62
17,106,163.20
133.40
45,230.00
6.03E+06
0.07254
$437,683.66
$497,972.87
February
4,821,120.00
3.65
366.90 4.63E+03
1.70E+06 0.07254
$123,228.49
35.62
23,757,360.00
185.27
45,230.00
8.38E+06
0.07254
$607,863.27
$731,091.76
March
4,665,600.00
3.65
355.07 4.63E+03
1.64E+06 0.07254
$119,253.38
35.62
37,776,768.00
294.60
45,230.00
1.33E+07
0.07254
$966,568.24
$1,085,821.62
April
4,821,120.00
3.65
366.90 4.63E+03
1.70E+06 0.07254
$123,228.49
35.62
25,903,952.00
202.01
45,230.00
9.14E+06
0.07254
$662,786.65
$786,015.13
May
2,527,200.00
3.65
192.33 4.63E+03
8.90E+05 0.07254
$64,595.58
35.62
52,622,800.00
410.37
45,230.00
1.86E+07
0.09756
$1,810,822.64
$1,875,418.22
June
2,611,440.00
3.65
198.74 4.63E+03
9.20E+05 0.07254
$66,748.76
35.62
15,607,036.80
121.71
45,230.00
5.50E+06
0.09756
$537,059.52
$603,808.28
July
15,374,016.00
2,611,440.00
3.65
198.74 4.63E+03
9.20E+05 0.07254
$66,748.76
35.62
12,762,576.00
99.53
45,230.00
4.50E+06
0.09756
$439,177.73
$505,926.49
August
2,527,200.00
0.975
2,527,200.00
3.65
192.33 4.63E+03
8.90E+05 0.07254
$64,595.58
35.62
0.00
0.00
45,230.00
0.00E+00
0.07254
$0.00
2,611,440.00
3.65
198.74 4.63E+03
9.20E+05 0.07254
$66,748.76
35.62
29,674,252.80
231.41
45,230.00
1.05E+07
0.07254
$759,254.75
$826,003.51
2,527,200.00
3.65
192.33 4.63E+03
8.90E+05 0.07254
$64,595.58
35.62
17,721,504.00
138.20
45,230.00
6.25E+06
0.07254
$453,427.96
$518,023.54 November
2,611,440.00
3.65
198.74 4.63E+03
9.20E+05 0.07254
$66,748.76
35.62
18,357,753.60
143.16
45,230.00
6.48E+06
0.07254
$469,707.25
$536,456.01 December
0.00
20,315,664.00
19,464,883.20
0.00
19,464,883.20
36,560,160.00
7,981,680.00
28,578,480.00
54,442,368.00
12,000,000.00
42,442,368.00
40,725,072.00
10,000,000.00
25,168,320.00
29,981,680.00
30,725,072.00
55,150,000.00
18,218,476.80
0.00
18,218,476.80
15,374,016.00
0.00
Total
Feed-In
Tariff
US$/kWh
0.975
0.975
1.800
1.800
1.800
0.975
0.975
0.975
20,315,664.00
9.714 306,299,750.40
MY Mean
Monthly
Production
(kWh)
TOTAL
Ecologic + Main
Plant
MY Average - Gross Main Plant Income
306,299,750.40
Total
37,305,360.00
2,839.07
1.31E+07
Total
Total
Total
$953,530.11
Total
268,994,390.40 2,097.72
Total
Total
11.15%
Of Total Gross
Project Income
DD Notes & Recommendations:
(1) Whilst the foregoing approximative analysis, the REPDC used the real power outputs at their nominal i.e.
maximum rates as apprised by REPDC. The operation monthly hours were derived thereon.
(2) Towards the further confidence improvement, the Design Engineer of the Owner is advised to run the
appropriate analysis based on MY mean daily or at least weekly river discharges.
(3) Probability of 50% or more(page 59), supporting the MY flow duration curve and MY annual distribution
curve, should be upgraded up to 70%, reinforcing thus the analysis competence.
(4) The operation hours of main plant(2052Hrs) and ecologic plant(8766Hrs), P82 of FS, should be further
backed whilst the updated issue of FS.
REPDC GREEN
9.49E+07
$64,595.58 September
$7,597,337.49 $8,550,867.60
Total
Total
88.85%
$9,927,214.00
Of Total Gross
Project Income
According to
Feasibility Study
October
40
SH16
SH16 - Particular Structures Assessment
Upstream
Cofferdam and
Derivation
Tunnel
The flood criteria applied for evaluation of upstream cofferdam height (cca 16m)and radius of derivation tunnel, (cca 6m),
should be clarified. If the local material availability proved favourable, the gravity structure of lean or rolcrit Cofferdam
should be considered as an option.
Overcrest
Spillway
Max Operation level of the reservoir….cca 1155m
Min Operation Level of the reservoir….cca 1140m
Spillway crest elevation: ..................... cca 1151m
Clarification to be detailed: The design criteria on the basis of which the spillway crest level was evaluated.
Penstock
Steel penstock of 8mm to 16mm walls thickness. The penstock dia of 3.80m.
The penstock walls seem to be underestimated. The brief structural analysis should be conducted.
Transmission
Line
15km of 154kVA transmission line is planned. Any upgrading of Darende substation due to Plant connection? To be
clarified.
REPDC GREEN
41
SH17
SH17 - Project Implementation Assessment
REPDC GREEN
42
SH17
DD Notes & Recommendations:
(1) The milestones designating the construction and environmental permits award should be clearly indicated in the program.
(2) The land nationalization process should be all the time conducted by the Owner and be terminated the latest by the date of
obtaining of construction permit.
(3) The 'as drafted' program was construed to be in succession of the project development program wherein the geological
conditions then the topo and hydrology statistics updating, then the final design, BOQ and tender documents, were completed
for CME works. The development program deserves further discussion.
(4) The meaning of 'Survey Project Works' '2' should be clarified within the context of the program.
(5) The one month of tendering process (call for and award) might be insufficient. Suggestion: to be reconsidered.
(6) 'Consulting and Technical Services' '3', were understood as aligned with supervision and consulting engineering during
construction. Here, the 'On Owner Design' construction contract package was assumed to apply. In case the chart was
conjugated with 'On Contractor Design' construction contract package the issue would deserve further consideration.
(7) The 3 year chart allocated to civil construction process was estimated as appropriate under the assumption of favourable
geological conditions.
(8) The 2 year for E/M equipment and assemblies manufacturing/erection, might be overestimated whereas the issue is dealt
with the standard power generating sets. The appropriate optimization of the chart is suggested.
(9) The 15km transmission line chart should be clarified.
(10) The defects liability period for the Project is missing and it should be implemented to the program. Given the importance
and size of the projects, the period should not be shorter than 2 years.
(11) Manufacturer Guarantees (Warranties) should coincide to termination of defects liability period. To the effect, the page 19,
article 1.2 of annex 8 of Feasibility Study should be reconsidered.
Conclusion:
The 3.5 year construction period of the Project could be achievable under the comments and recommendations set forth here
above.
REPDC GREEN
43
SH18
SH18 - Approximate Checkup of Capital Expenditures
49.98MW/10.80x107kWh
Output(Real) Power: Main +
Ecologic Plant
49.98 MW
As per REPDC
approximate
analysis
MY Mean Annual Production
108,024,607.30 kWh
As per REPDC
approximate
analysis
Description
As per Feasibility Study
1 Advance Services and Works
2
3
4
5
6
7
8
9
10
11
Contract Documents: Instructions, Conditions, Specifications, BOQ, and Forms for Preliminaries, Civil, Mechanical and Electrical works, roads and tunnels, transmission lines
and substations.
23
24
25
26
27
28
29
2
3
Included(4)
$1,250,000.00
2.61%
Derivation tunnel, 321m
Dam foundation and abutments excavation, including consolidation grouting and rock
strengthening
Excavation for tailrace tunnel, 100m
Tail water leveling
Flow dissipation basin (excavation, lining and rock strengthening)
Dam Structure, 148000 m3
Dam Integrated Power Structure
Dam Instrumentation and Dam abutments instrumentation
1.41%
25.010004 /kW
$0.0116 /kWh
$75,000.00
0.08%
1.5006002 /kW
$0.0007 /kWh
$2,245,299.00
2.54%
$44.92 /kW
$0.0208 /kWh
$2.40 /kW $0.0011 /kWh 11
$1,650,000.00
3.44%
$33.01 /kW
$0.0153 /kWh
$69.93 /kW $0.0324 /kWh 12
$5,220,299.00
5.90%
$104.45 /kW
$0.0483 /kWh
$612,375.00
$227,375.00
$1,038,451.00
$1,908,504.00
1.28%
$12.25 /kW
$0.0057 /kWh
0.47%
$4.55 /kW
$0.0021 /kWh
2.17%
$20.78 /kW
$0.0096 /kWh
3.98%
$38.19 /kW
$0.0177 /kWh
$650,000.00
1.36%
$13.01 /kW
$0.0060 /kWh
$1,824,305.00
2.06%
$36.50 /kW
$0.0169 /kWh
6
$2,245,299.00
4.68%
Preliminaries
Accommodation, Furniture and Fixture
Site offices; accommodation for the Client's and Engineer's staff; furniture for offices and accommodation;
telephone/fax; computers; vehicles; site laboratory; survey equipment; first aid facilities; maintenance of all the
above.
$1,250,000.00
Not specifically priced.
Land Nationalization Process
234.8Ha á $9,562.6
25.01 /kW $0.0116 /kWh 4
5
Call for tenders, tenders evaluation, contract award
12 Sub-Total (1) - (11): Advance Services and Works
13 Civil Works
Access and Service Structures
14
Access road to dam site, 8165m
15
Dam crest service road , 1819m
16
Dam crest service tunnel , 261m
17
Service tunnel to power house, 495m
18
Temporary Structures
19
Upstream=cca 15m) and downstream(H=cca 10m) cofferdams
20
Dam structure and associated works
21
22
1
Project Development Cost
Final Surveys: Topo, Hydrological, Geological, Environmental
Final Reports and Designs: hydraulic, hydropower, structural/geotechnical, access/service
roads and tunnels, environmental mitigation structures. Functional designs of all electromechanical works. Final design of transmission lines and substations.
Cost of Project Construction Contract Award
As assessed by REPDC(Lower Bound Estimate)
$120,000.00
$3,495,299.00
7.29%
7
8
$44.92 /kW $0.0208 /kWh 9
10
13
14
15
16
17
18
19
20
21
22
Included(6)
$339,040.00
$138,086.00
$1,038,451.00
$1,908,504.00
0.71%
$6.78 /kW $0.0031 /kWh
0.29%
$2.76 /kW $0.0013 /kWh
2.17%
$20.78 /kW $0.0096 /kWh
3.98%
$38.19 /kW $0.0177 /kWh
$238,563.00
0.50%
$4.77 /kW $0.0022 /kWh
$1,824,305.00
3.80%
$36.50 /kW $0.0169 /kWh
$982,318.00
2.05%
$19.65 /kW $0.0091 /kWh 23
$2,500,000.00
2.83%
$50.02 /kW
$0.0231 /kWh
$841,987.00
$1,108,616.00
$1,403,312.00
$15,054,168.00
$1,122,649.00
1.76%
$16.85 /kW $0.0078 /kWh 24
0.95%
$16.85 /kW
$0.0078 /kWh
2.31%
$22.18 /kW $0.0103 /kWh 25
1.25%
$22.18 /kW
$0.0103 /kWh
2.93%
$28.08 /kW $0.0130 /kWh 26
1.59%
$28.08 /kW
$0.0130 /kWh
31.39%
$301.20 /kW $0.1394 /kWh 27
28.83%
$510.20 /kW
$0.2361 /kWh
2.34%
$22.46 /kW $0.0104 /kWh 28
$841,987.00
$1,108,616.00
$1,403,312.00
$25,500,000.00
$2,500,000.00
2.83%
$50.02 /kW
$0.0231 /kWh
29
$250,000.00
0.28%
$5.00 /kW
$0.0023 /kWh
Not specifically priced.
REPDC GREEN
44
SH18
30
Dam grouting and Dam seepage control works
Not specifically priced.
30
31
Fish path structure
Not specifically priced.
31
32
33
34
35
36
37
38
39
Environmental mitigation structures
Tributaries barrages mitigating pond sedimentation, wild animal passes,……..
40 Sub-Total (13) - (39): Civil Works
Included(14) to (36)
$3,899,999.85
$29,899,998.85
8.13%
62.35%
$78.03 /kW $0.0361 /kWh 39
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
Turbines, governors, cooling system and other accessories
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
20% contingencies
57
2.67%
$25.60 /kW $0.0118 /kWh
0.58%
$5.52 /kW $0.0026 /kWh
$2,011,300.00
$434,000.00
$561,526.00
$3,087,286.00
4.19%
$40.24 /kW $0.0186 /kWh
0.90%
$8.68 /kW $0.0040 /kWh
1.17%
$11.24 /kW $0.0052 /kWh
6.44%
$61.77 /kW $0.0286 /kWh
Penstock and accessories D/d=3.8m/16mm
$355,567.00
0.74%
$7.11 /kW $0.0033 /kWh 57
58
Plant's bridge crane
$195,564.00
0.41%
$3.91 /kW $0.0018 /kWh 58
59
Drainage and dewatering system, Compressed air system, workshop tools,….
Not specifically priced.
59
Included
60
61
Switchgear
Included
60
61
Included
62
63
64
65
66
67
Generators and accessories
Main Plant: 2 X V227.8 MVA Generators
Ecologic Plant: 1 X V15.56 MVA Generator
Transformers
Radial gates, turbine valves, bonnet gate, draft tube gates, trash racks, ……
Control, protection and automation system
Analog control and indicator cubicles, protective relays, computerized SCADA system, open protocol system,
integrated SCADA software: $84,190.00 + $701,656.00
AC and DC power supply, cabling, Lighting and LV power services, telephone network, fire
fighting system, earthling system, … .
Transportation and Insurance Expenses
Import and Custom Expenses
$785,845.00
1.64%
63
Not specifically priced.
$445,000.00
$185,000.00
D/d=3.8m/38mm
$15.72 /kW $0.0073 /kWh 62
0.93%
$8.90 /kW $0.0041 /kWh 64
0.39%
$3.70 /kW $0.0017 /kWh 65
Erection of mechanical and electrical equipment
Including only the crane works, welding works and small services(min 5% of cost of E/M
equipment). The erection of the equipment and assemblies are included in the prices quoted
here before.
$35.01 /kW
$0.0162 /kWh
$9,322,985.00
10.54%
$186.53 /kW
$0.0863 /kWh
$55,937,910.00
63.24%
$1,119.21 /kW
$0.5178 /kWh
$3,700,000.00
$370,000.00
4.18%
$74.03 /kW
$0.0343 /kWh
0.42%
$7.40 /kW
$0.0034 /kWh
$4,850,000.00
$485,000.00
$1,210,000.00
$3,087,286.00
5.48%
$97.04 /kW
$0.0449 /kWh
0.55%
$9.70 /kW
$0.0045 /kWh
1.37%
$24.21 /kW
$0.0112 /kWh
6.44%
$61.77 /kW
$0.0286 /kWh
$850,000.00
1.77%
$17.01 /kW
$0.0079 /kWh
$195,564.00
0.22%
$3.91 /kW
$0.0018 /kWh
$2,475,000.00
5.16%
$49.52 /kW
$0.0229 /kWh
$650,000.00
$250,000.00
0.73%
$13.01 /kW
$0.0060 /kWh
0.28%
$5.00 /kW
$0.0023 /kWh
$750,000.00
0.85%
$15.01 /kW
$0.0069 /kWh
Included(14) to (36)
$1,279,300.00
$275,900.00
Ecologic Plant: 1 X VFrancis, 1 x 25MW
1.98%
Included(13) to (32)
$598.24 /kW $0.2768 /kWh 40
41 Mechanical and Electrical Works
Main Plant: 2 X VFrancis, 2 x 25MW
$0.0417 /kWh
$1,750,000.00
34
35
36
37
38
Included(13) to (32)
Contingencies
Contingencies estimated to civil works: 15% of (13) to (37)
$90.04 /kW
Included (27)
33
Not specifically priced.
Overhead and profit
On/Off site overhead and profit aligned with civil works
5.09%
32
Value Added Tax
VAT to material and workmanship of civil works
$4,500,000.00
Included
66
$750,000.00
1.56%
$15.01 /kW $0.0069 /kWh 67
REPDC GREEN
45
SH18
68
Commissioning Expenses
69
Contingencies estimated to M & E works: 15% of (49) to (68)
70 Sub-Total (41) - (69): Mechanical and Electrical Works
$185,000.00
0.39%
$3.70 /kW $0.0017 /kWh 68
$1,582,693.20
3.30%
$31.67 /kW $0.0147 /kWh 69
$12,133,981.20
25.30%
$242.78 /kW $0.1123 /kWh 70
71 Transmission Line, Switchyard and Substation Upgrading
71
72
72
73
74
75
76
Structural, foundation and electro-mechanical works
15 km of 154 KVA Transmission Line. According to feasibility study:15km x $77,000 =
1,155.000
Switchyard and Substation upgrading
Included(73)
VAT and O/P
Included(73)
Contingencies estimated to TLines: 15% of (72 ) to (75)
77 Sub-Total (66 ) - (71): Transmission Line
$1,459,444.00
3.04%
29.2006 /kW $0.0135 /kWh 73
Supervision of construction, review of additional designs, POE services, ….
80 Sub-Total (78 ) - (79): Consultancy Services and Supervision
0.28%
$5.00 /kW
$0.0023 /kWh
$1,603,556.40
1.81%
$32.08 /kW
$0.0148 /kWh
$20,726,406.40
23.43%
$414.69 /kW
$0.1919 /kWh
$1,875,000.00
2.12%
$37.52 /kW
$0.0174 /kWh
$187,500.00
0.21%
$3.75 /kW
$0.0017 /kWh
$2,062,500.00
2.33%
$41.27 /kW
$0.0191 /kWh
74
75
$218,916.60
0.46%
4.38008 /kW $0.0020 /kWh 76
$1,678,360.60
3.50%
33.5806 /kW $0.0155 /kWh 77
78 Consultancy Services during Construction and works supervision
79
10% Contingencies
$250,000.00
10% Contingencies
78
$750,000.00
1.56%
$15.01 /kW $0.0069 /kWh 79
$4,500,000.00
5.09%
$90.04 /kW
$0.0417 /kWh
$750,000.00
1.56%
$15.01 /kW $0.0069 /kWh 80
$4,500,000.00
5.09%
$90.04 /kW
$0.0417 /kWh
84
84
Summary of Cost
85
49.93MW/10.80x107kWh
86
86
Description
88 Sub-Total (1) - (11): Advance Services and Works
89 Sub-Total (13) - (39): Civil Works
90 Sub-Total (41) - (69): Mechanical and Electrical Works
91 Sub-Total (66 ) - (71): Transmission Line
92 Sub-Total (78 ) - (79): Consultancy Services and Supervision
93 Grand Total
As per Feasibility Study
$3,495,299.00
$29,899,998.85
$12,133,981.20
$1,678,360.60
$750,000.00
$47,957,639.65
As assessed by REPDC
7.29%
69.934 /kW $0.0324 /kWh 88
$5,220,299.00
5.90%
$104.45 /kW
$0.0483 /kWh
62.35%
598.239 /kW $0.2768 /kWh 89
63.24%
$1,119.21 /kW
$0.5178 /kWh
25.30%
242.777 /kW $0.1123 /kWh 90
23.43%
$414.69 /kW
$0.1919 /kWh
3.50%
33.5806 /kW $0.0155 /kWh 91
2.33%
$41.27 /kW
$0.0191 /kWh
1.56%
15.006 /kW $0.0069 /kWh 92
5.09%
$90.04 /kW
$0.0417 /kWh
100.00%
959.537 /kW $0.4440 /kWh 93
$55,937,910.00
$20,726,406.40
$2,062,500.00
$4,500,000.00
$88,447,115.40
100.00%
$1,769.65 /kW
$0.8188 /kWh
94
94
DD Notes & Recommendations:
(1) From the present stance, it would be difficult to achieve successful construction of a project the largeness, and the site
conditions similar to those of Kaynarca HPP, at a rate beneath of $1000/MW.
(2) In the absence of a BOQ appropriately detailed to Feasibility Study, REPDC has utilized the ranges of prices for particular works
and machineries designed or embedded to similar international projects, whereby it appeared that approximate price in the order of
$1800/kW would more certain to expect.
Conclusion:
The Design Engineer is advised to detail and reevaluate the prices for particular works of the Project.
REPDC GREEN
46
SH19
SH19 - Economic Analysis of Project
49.98MW/10.80x107kWh
General Inputs
Output(Real) Power: Main +
Ecologic Plant
49.98 MW
As per REPDC
approximate analysis
2 MY Mean Annual Production
108,024,607.30 kWh
As per REPDC
approximate analysis
1
3 Exchange Rate US$/TL
4 Capital Expenditures
5
Average Annual Gross
Income
1.78150
$88,447,115.40000
As per REPDC
approximate analysis
$8,550,867.60413
As per REPDC
approximate analysis
Average Feed-In Tariff
(Gross)
$0.07916 kWh
As per REPDC
approximate analysis
Power Cost Factor (PU-CF)
$1,769.65 kW
As per REPDC
approximate analysis
Electricity Production Cost
Factor (EP-CF)
$0.82 kWh
As per REPDC
approximate analysis
EP-CF/Feed -In Tariff Ratio
10.34
The Ratio < 8, being
indicator of lucrative
Investement
REPDC GREEN
47
SH19
Average Annual Cost of Maintenance
Workmanship and Material inclusive
Expected
Lifespan of
Structure &
Equipment(Yr)
Fraction of Capital
Cost remaining to
Total Maintenance
Cost
Total Maintenance
Cost
Average Annual
Maintenance Cost
$1,250,000.00
N/A
N/A
N/A
N/A
Cost of Project Construction Contract Award
Contract Documents: Instructions, Conditions, Specifications, BOQ, and Forms for Preliminaries, Civil, Mechanical and Electrical works, roads and tunnels, transmission lines and
$75,000.00
substations.
Included(6)
Call for tenders, tenders evaluation, contract award
N/A
N/A
N/A
N/A
$2,245,299.00
N/A
N/A
N/A
N/A
$1,650,000.00
N/A
N/A
N/A
N/A
12 Sub-Total (1) - (11): Advance Services and Works
$5,220,299.00
N/A
N/A
N/A
N/A
13 Civil Works
Access and Service Structures
14
Access road to dam site, 8165m
15
Dam crest service road , 1819m
16
Dam crest service tunnel , 261m
17
Service tunnel to power house, 495m
18
$612,375.00
$227,375.00
$1,038,451.00
$1,908,504.00
Description
Capital Cost
1 Advance Services and Works
Project Development Cost
2
3
Final Surveys: Topo, Hydrological, Geological, Environmental
4
5
6
7
8
9
10
11
Final Reports and Designs: hydraulic, hydropower, structural/geotechnical, access/service
roads and tunnels, environmental mitigation structures. Functional designs of all electromechanical works. Final design of transmission lines and substations.
Land Nationalization Process
234.8Ha á $9,562.6
Preliminaries
Accommodation, Furniture and Fixture
Site offices; accommodation for the Client's and Engineer's staff; furniture for offices and accommodation;
telephone/fax; computers; vehicles; site laboratory; survey equipment; first aid facilities; maintenance of all the above.
REPDC GREEN
100
100
100
100
25.00%
25.00%
25.00%
25.00%
$153,093.75
$1,530.94
$56,843.75
$568.44
$259,612.75
$2,596.13
$477,126.00
$4,771.26
48
SH19
19
20
21
Temporary Structures
$650,000.00
Upstream=cca 15m) and downstream(H=cca 10m) cofferdams
N/A
N/A
N/A
Dam structure and associated works
22
Derivation tunnel, 321m
$1,824,305.00
23
Dam foundation and abutments excavation, including consolidation grouting and rock
strengthening
$2,500,000.00
24
25
26
27
28
29
30
31
N/A
$841,987.00
$1,108,616.00
$1,403,312.00
$25,500,000.00
$2,500,000.00
$250,000.00
$4,500,000.00
Excavation for tailrace tunnel, 100m
Tail water leveling
Flow dissipation basin (excavation, lining and rock strengthening)
Dam Structure, 148000 m3
Dam Integrated Power Structure
Dam Instrumentation and Dam abutments instrumentation
Dam grouting and Dam seepage control works
Fish path structure
N/A
25.00%
N/A
100
$456,076.25
N/A
$4,560.76
N/A
50
100
100
30
50
25.00%
N/A
25.00%
25.00%
25.00%
25.00%
25.00%
$350,828.00
$7,016.56
$6,375,000.00
$63,750.00
100
25.00%
N/A
$210,496.75
N/A
$2,104.97
N/A
$625,000.00
$6,250.00
$62,500.00
$2,083.33
$1,125,000.00
$22,500.00
$437,500.00
$4,375.00
Included (27)
Environmental mitigation structures
32
Tributaries barrages mitigating pond sedimentation, wild animal passes,……..
33
Value
Added Tax
34
VAT to material and workmanship of civil works
35
Overhead and profit
36
On/Off site overhead and profit aligned with civil works
37
Contingencies
38
Contingencies estimated to civil works: 15% of (13) to (37)
39
40 Sub-Total (13) - (39): Civil Works
41 Mechanical and Electrical Works
Turbines, governors, cooling system and other accessories
49
Main Plant: 2 X VFrancis, 2 x 25MW
50
Ecologic Plant: 1 X VFrancis, 1 x 25MW
51
Generators
and accessories
52
Main Plant: 2 X V227.8 MVA Generators
53
Ecologic Plant: 1 X V15.56 MVA Generator
54
100
$1,750,000.00
Included(13) to (32)
Included(13) to (32)
Included(14) to (36)
Included(14) to (36)
$9,322,985.00
$55,937,910.00
100
$3,700,000.00
$370,000.00
40
40
$4,850,000.00
$485,000.00
40
40
REPDC GREEN
25.00%
$2,330,746.25
$23,307.46
$12,919,823.50
$145,414.85
50.00%
50.00%
$1,850,000.00
$46,250.00
$185,000.00
$4,625.00
50.00%
50.00%
$2,425,000.00
$60,625.00
$242,500.00
$6,062.50
49
SH19
55
56
57
58
59
60
61
62
63
64
65
66
67
Transformers
Radial gates, turbine valves, bonnet gate, draft tube gates, trash racks, ……
Penstock and accessories D/d=3.8m/16mm
Plant's bridge crane
$1,210,000.00
$3,087,286.00
$850,000.00
$195,564.00
40
60
100
50
50.00%
37.50%
37.50%
37.50%
20
$650,000.00
$250,000.00
50
50
$750,000.00
14.37%
Drainage and dewatering system, Compressed air system, workshop tools,….
Included
Switchgear
Included
$605,000.00
$15,125.00
$1,157,732.25
$19,295.54
$318,750.00
$3,187.50
$73,336.50
$1,466.73
50.00%
$1,237,500.00
$61,875.00
37.50%
37.50%
$243,750.00
$4,875.00
$93,750.00
$1,875.00
Control, protection and automation system
Analog control and indicator cubicles, protective relays, computerized SCADA system, open protocol system,
integrated SCADA software: $84,190.00 + $701,656.00
AC and DC power supply, cabling, Lighting and LV power services, telephone network, fire
fighting system, earthling system, … .
Transportation and Insurance Expenses
Import and Custom Expenses
Erection of mechanical and electrical equipment
Including only the crane works, welding works and small services(min 5% of cost of E/M
equipment). The erection of the equipment and assemblies are included in the prices quoted
here before.
Commissioning Expenses
68
Contingencies estimated to M & E works: 15% of (49) to (68)
69
70 Sub-Total (41) - (69): Mechanical and Electrical Works
$2,475,000.00
Included
$250,000.00
$1,603,556.40
$20,726,406.40
N/A
50
$15.01 /kW
N/A
37.50%
$0.0069
N/A
N/A
$601,333.65
$12,026.67
$9,033,652.40
$237,288.94
71 Transmission Line, Switchyard and Substation Upgrading
Structural, foundation and electro-mechanical works
72
73
15 km of 154 KVA Transmission Line. According to feasibility study:15km x $77,000 =
1,155.000
Switchyard and Substation upgrading
$1,875,000.00
75
37.50%
$703,125.00
$9,375.00
74
VAT and O/P
75
Contingencies estimated to TLines: 15% of (72 ) to (75)
76
77 Sub-Total (66 ) - (71): Transmission Line
$187,500.00
$2,062,500.00
75
37.50%
$70,312.50
$937.50
$773,437.50
$10,312.50
78 Consultancy Services during Construction and works supervision
Supervision of construction, review of additional designs, POE services, ….
79
80 Sub-Total (78 ) - (79): Consultancy Services and Supervision
$4,500,000.00
$4,500,000.00
84
REPDC GREEN
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
50
SH19
Summary of Annual Maintenance Expenses
85
Workmanship and Material inclusive
86
Description
88
89
90
91
92
93
Capital Cost
Sub-Total (1) - (11): Advance Services and Works
Sub-Total (13) - (39): Civil Works
Sub-Total (41) - (69): Mechanical and Electrical Works
Sub-Total (66 ) - (71): Transmission Line
Sub-Total (78 ) - (79): Consultancy Services and Supervision
Grand Total
Expected
Lifespan of
Structure &
Equipment(Yr)
Fraction of Capital
Cost remaining to
Total Maintenance
Cost
$5,220,299.00
$55,937,910.00
$20,726,406.40
$2,062,500.00
$4,500,000.00
$88,447,115.40
Total Maintenance
Cost
Average Annual
Maintenance Cost
N/A
N/A
$12,919,823.50
$145,414.85
$9,033,652.40
$237,288.94
$773,437.50
$10,312.50
N/A
$22,726,913.40
N/A
$393,016.29
Water Use Cost
1
Average Annual
Production
Description
2 Average unit rate according to wholesale price (2007-2012): 10.13US$/MWh
Water Use Unit rate
Average Annual Water Use
Cost
$0.0101
$1,094,289.27
Percentage of Gross Annual Income
12.80%
108,024,607.30 kWh
Plant's Own Consumption Cost
1
Average Annual Cost of
Imported Electricity
Description
2 Estimated to be 1% of Installed Plant's Capacity, equivalent to 49.98 *0.01=0.50MW
REPDC GREEN
$14,520.00
51
SH19
Cost of State Network System Use
Average Annual Cost of
Network Use
Description
1
2 According to Local Board Resolution, No, 3689, dated 9 February 2012
$625,000.00
Plant's Management and Supervision Staff
Description
1
Working Status
Daily Shifts
Gross Daily Rate
Average Annual Cost
2 Plant's Manager
3 Electrical and Mechanical Engineers (two daily shifts by 1)
4 Civil Engineer
Full time
1
2
$2,800.00
$1,950.00
$2,800.00
Full time
Part time
0.5
$1,950.00
$975.00
5 Electrical and Mechanical Technicians(three daily shifts by 2)
6 Civil Technician
Full time
6
$1,400.00
$8,400.00
Full time
1
$1,400.00
$1,400.00
7 Others, not specified
Full time
3
$1,400.00
$4,200.00
8 TOTAL Monthly
9 TOTAL Yearly
$3,900.00
$21,675.00
$260,100.00
Plant's Overheads
Description
1
Average Annual Cost
2 Transportation, communication, hosting, stationary and the like
$42,000.00
Operation Insurance Expenses
1
Description
Working Status
2 Assets All Risk Insurance
Daily Shifts
Gross Daily Rate
Average Annual Cost
$126,000.00
REPDC GREEN
52
SH19
Summary of Operation Cost
Description
1
2
Average Annual Cost of Maintenance
Workmanship and Material inclusive
3
4
5
6
7
8
9
Water Use Cost
Plant's Own Consumption Cost
Cost of State Network System Use
Plant's Management and Supervision Staff
Plant's Overheads
Operation Insurance Expenses
Contingencies
Capital Expenditure
Percentage
10 TOTAL Annual Operation Cost
11 Percentage to the Capital Expenditures
$88,447,115.40
Average Annual Cost
15.09%
$393,016.29
42.01%
$1,094,289.27
0.56%
$14,520.00
23.99%
$625,000.00
9.98%
$260,100.00
1.61%
$42,000.00
4.84%
$126,000.00
1.92%
$50,000.00
100.00%
$2,604,925.56
2.95%
Summary of Economic Analysis
According to REPDC Assessment
1
Period
2
January
3
February
4
March
5
April
6
May
7
June
8
July
9
August
10
September
11
October
REPDC GREEN
Gross Income
$519,734.60
$497,972.87
$731,091.76
$1,085,821.62
$786,015.13
$1,875,418.22
$603,808.28
$505,926.49
$64,595.58
$826,003.51
53
SH19
12
November
13
December
14
Annual Total
$518,023.54
$536,456.01
100.00%
$8,550,867.60
15 Capital Expenditures
17 Annual O/M Cost
Average Annual Cost of Maintenance
18
Workmanship and Material inclusive
Water Use Cost
19
Plant's Own Consumption Cost
20
Cost of State Network System Use
21
Plant's Management and Supervision Staff
22
Plant's Overheads
23
Operation Insurance Expenses
24
Contingencies
25
26
SUB -Total
(18)-(25)
27 Renewable Energy Exemption Certificate
4.60%
12.80%
0.17%
7.31%
3.04%
0.49%
1.47%
0.58%
30.46%
1.80%
$2,604,925.56
$154,000.00
28 Net Income per a Year: (14)-(26)+(27)
71.34%
$6,099,942.04
Years
14.5
29 Return-On-Investment Period (15)/(28)
$88,447,115.40
$393,016.29
$1,094,289.27
$14,520.00
$625,000.00
$260,100.00
$42,000.00
$126,000.00
$50,000.00
According to Feasibility Study
1
Annual Total
100.00%
$8,550,867.60
2 Capital Expenditures
3 Annual O/M Cost
Average Annual Cost of Maintenance
4
Workmanship and Material inclusive
Water Use Cost
5
Plant's Own Consumption Cost
6
Cost of State Network System Use
7
Plant's Management and Supervision Staff
8
Plant's Overheads
9
Operation Insurance Expenses
10
Contingencies
11
12
SUB -Total
(4)-(11)
13 Renewable Energy Exemption Certificate
4.09%
12.80%
0.17%
7.32%
2.46%
0.49%
1.48%
0.59%
29.39%
1.80%
$2,513,513.27
$154,000.00
14 Net Income per a Year: (14)-(26)+(27)
72.41%
$6,191,354.33
15 Return-On-Investment Period (2)/(14)
Years
7.7
REPDC GREEN
$47,957,639.65
$350,000.00
$1,094,289.27
$14,520.00
$625,787.00
$210,497.00
$42,000.00
$126,298.00
$50,122.00
54
SH19
DD Notes & Recommendations:
(1) There is apparently a significant separation between the economic parameters concluded in Feasibility Study and those
estimated by REPDC. Whilst the Feasibility Study had endorsed the economic feasibility of the Project, the REPDC analysis
made it questionable.
(2) It is to note that the Water Use Cost and Cost of State Network System, take circa 19% of total gross annual income which
negatively affect the economic parameters of the Project. The issue deserves serious discussion with Owner of Project before
the next step of Project evaluation.
(3) Towards annulling the disputes among the two Approaches, the Design Engineer is advised to review engineering
solutions of the Project and the price inputs to construction works.
REPDC GREEN
REPDC GREEN Pte Ltd
16 Raffles Quay, #33-03
Hong Leong Building
Singapore 048581
Tel:
Fax:
+65 6000 064 422
+65 6000 064 411
E-mail:[email protected]
Web: www.repdc-green.com
IMPORTANT DISCLOSURE
All information, opinions, expectations and
projections have been obtained from sources we
believe to be reliable; however, REPDC GREEN does
not guarantee their precision and/or completeness.
REPDC GREEN is not liable for the accuracy of
information obtained from external sources. The
contents of this publication may only be used for
information purposes. Investors should conduct
their own research about a project prior to making
investment decisions. Price fluctuations and past
performance do not guarantee future results.
No position, information or projection should be
construed as an offer, requirement or imposition of
sale of any type of security. Information, opinions,
expectations and projections may be affected by
subsequent market developments.