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Home My WebLink AboutKotzebue Electric Association Wind Power Economic Evaluation, January 2000Kotzebue Electric Association Wind Power Economic Evaluation Prepared For Kotzebue Electric Association P.O. Box 44 Kotzebue, Alaska 99752 January 2000 Prepared By Global Energy Concepts, Inc. 5729 Lakeview Drive NE, Suite 100 Kirkland, Washington 98033-7340 Phone: (425) 822-9008 Fax: (425) 822-9022 Email: gec@globalenergyconcepts.com Kotzebue Electric Association — Wind Power Economic Evaluation Kotzebue Electric Association Wind Power Economic Evaluation Executive Summary This report evaluates preliminary cost and performance data from the Kotzebue Wind Energy Power Project, a collaborative effort of the Alaska Energy Authority, Alaska Industrial Development Export Authority (AEA/AIDEA), formerly the Department of Community and Regional Affairs, Division of Energy (DCRA/DOE), the Kotzebue Electric Association (KEA), and the U.S. Department of Energy (DOE). The report also documents KEA’s early experiences in planning, installing, and operating wind turbines, discusses the economic value of wind energy for Kotzebue, and estimates future wind energy development costs in Kotzebue and surrounding communities. KEA installed the first three AOC 15/50 wind turbines in Alaska in the spring of 1997. AEA/AIDEA provided $200,000 of the capital investment for Phase 1, which had a total cost of approximately $591,000. With the addition of Phases 2 and 3, the Kotzebue Wind Project consists of 10 AOC 15/50 wind turbines. = The analyses in the report include the calculation of cost of energy (COE) at the Kotzebue project and the development of cash flow models to determine the 1999 net present value. The expected COE for Phase 1 is $0.131 per kWh, without consideration of the AEA/AIDEA funds. Based on total costs, the Phase 1 turbines are shown to have a net present value of -$100,416 and an internal rate of return of 3.4%. Due to lessons learned during Phase 1, cost reductions are expected for Phases 2 and 3 and potentially for future wind developments in similar communities in Alaska. To evaluate future scenarios, a baseline analysis was developed based on the expected cost and performance of the seven additional wind turbines. The expected COE for the baseline scenario is $0.099 per kWh, and Phases 2 and 3 are estimated to have a net present value of $121,950. A COE calculation combining the actual costs for Phase 1 with the expected costs for Phase 2 and 3 results in a COE of $0.109 per kWh. An internal rate of return was not calculated as the baseline analysis assumes 100% debt financing. The report discusses the basis for economic and financial assumptions used in the evaluation, including the fixed charge rate, turbine design life, financing term and depreciation, fuel escalation, inflation, interest and discount rates, as well as capital costs and turbine maintenance costs. Numerous sensitivities to the baseline scenario were performed to assess a variety of economic uncertainties, including variations in capital costs, financing assumptions, energy estimates, and turbine maintenance costs. The scenario with the highest COE was based on an energy production shortfall of 20% below the baseline projections. The low production would result in a COE of $0.124 per kWh and a net present value of approximately -$125,396. However, 10% higher than projected energy production Global Energy Concepts i January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation results in a COE of $0.090 per kWh and a net present value of $245,624. Table ES-1 below summarizes the COE values for the basic sensitivities that were calculated and discussed in the report. Other scenarios estimate the value of wind energy in more energetic wind regimes identified at several sites in northwestern Alaska and utilize additional economic sensitivities. The most favorable scenarios are based on a higher fuel escalation and installation of AOC turbines in a 7.5 m/s (16.8 mph) annual wind resource, compared to the actual annual Kotzebue wind speed of 6.0 m/s (13.5 mph). Although the fuel escalation change does not affect the COE because the analysis does not consider revenues (fuel savings), that scenario shows Phases 2 and 3 to have a net present value of $522,441. Under the 7.5 m/s (16.8 mph) wind resource scenario, Phases 2 and 3 have an expected COE of $0.076 per kWh and a net present value of $494,236. The net present value and COE results for all of the economic scenarios examined in the report are summarized in Table 12 on page 35, and detailed cash flows are provided in Appendix C. Table ES-1. Summary of Basic Sensitivities Scenario COE per kWh Phase 1 Project 13.1¢ Baseline for Future Development 9.9¢ Capital Cost Variation; 10% lower and higher 9.1¢-11.5¢ Financing Assumptions; 20-yr project and 6% interest 10.9¢-11.9¢ Energy Estimates; 10% higher and 20% lower 9.0¢-12.4¢ Turbine Maintenance; 10% lower and 20% higher 9.7¢-10.3¢ Wind Resource; 7.5-6.5 m/s 7.6¢-9.2¢ Wind Resource; 7.5-7.0 m/s with 30% higher capital 9.5¢-9.7¢ The economic value of wind energy was also evaluated by comparing the cost of generating energy at the existing diesel plant with the cost of generating the same amount of energy by supplementing diesel production with wind energy. The analysis is based on KEA’s expected energy demand and the operation of 10 AOC turbines. The baseline scenario using the same assumptions for fuel efficiency, fuel costs, fuel cost escalation, and maintenance costs as in the previous cash flow analyses shows a net present value of -$103,103 compared to diesel-only generation. The sensitivities assess fuel price escalation levels ranging from 0% to 3%, resulting in net present values of -$303,539 to $464,208 after the installed cost investment. This analysis is particularly sensitive to economic variables. For example, changing the general inflation assumption from 2.0% to the 10-year average of 3.3% (1989 - 1998) results in a savings of over $200,000. These savings are conservative estimates because they do not consider any capital cost for diesel equipment. Details of the cost comparison are presented in Table 13 on pages 38-40 and the related sensitivities are summarized in Table 14 on page 41. Global Energy Concepts ii January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Many potential benefits of wind energy development are difficult to quantify but may offer additional incentives in rural Alaska. For example, in reducing the use of diesel fuel, wind projects mitigate some future economic and environmental risk. Many of the state’s small villages are facing the need for additional fuel storage, which can be prohibitive depending on the geo-technical conditions of the area. The cost comparison of increasing fuel storage versus adding wind energy could be quantified on a site-by- side basis similar to the analyses presented in this report. Other benefits include increased independence by using an indigenous natural resource and the creation of needed jobs for local communities. During the last 10-15 years, commercial wind energy has experienced many technological advances resulting in significant improvements in turbine reliability and substantial reduction in equipment costs. However, the advanced turbine technology is still a relatively unproven technology and therefore carries some implied risk. Additional uncertainties are related to the wind resource and the economic assumptions. The report includes background information on KEA’s wind program and involvement with the DOE’s Turbine Verification Program (TVP), the AOC 15/50 wind turbine, and the wind resource at the Kotzebue wind project site. The report also discusses some of the benefits and risks associated with wind energy development. KEA anticipates continuing collaborative efforts with the AEA/AIDEA and other agencies and organizations in order to reach mutual goals supporting energy cost reduction in tural Alaska. Global Energy Concepts iii January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation LIST OF ACRONYMS AEA/AIDEA Alaska Energy Authority, Alaska Industrial Development Export Authority AEP Annual Energy Production AOC Atlantic Orient Corporation ASOS Automated Surface Observing System AWEA American Wind Energy Association COE Cost of Energy DCRA Department of Community and Regional Affairs DOE Department of Energy EPRI Electric Power Research Institute FCR Fixed Charge Rate GEC Global Energy Concepts, Inc. ICC Initial Capital Cost IRR Internal Rate of Return KEA Kotzebue Electric Association NCDC National Climatic Data Center NREL National Renewable Energy Laboratory O&M Operation and Maintenance PCE Power Cost Equalization REPI Renewable Energy Production Incentive RUS Rural Utility Service SCADA System Control and Data Acquisition STEP Sustainable Technology Energy Partnerships TVP Turbine Verification Program UWIG Utility Wind Interest Group WECTEC Wind Economics and Technology, Inc. Global Energy Concepts iv January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation TABLE OF CONTENTS 1.0 INTRODUCTION. BAY Overviews! eit tt el lle eee detail 1.2 Report Purpose and Organization...... 3 2.0 KEA’S WIND ENERGY ACTIVITIES... 4 2.1 Background ........ 4 2.2 The TVP Program..... <0 2.3 Turbine Installation ........0......... 6 3.0 WIND RESOURCE ASSESSMENT... 8 4.0 PROJECT DEVELOPMEN [oaicesscecctecsucevvesceveentssesacsuassurens sassoussususssauvevetavensrasauness 15 4.1 Turbine Procurement and Installation.............. cc eeceecesseceseeeseeeeeeseeseceeeeeeeeaeeeneeees 15 4.2 Problems Encountered................004+ Leto d 5.0 PROJECT PERFORMANCE ...........:ccccccsssseseeseeseeseeeeseseeaeeseeaeeaeeaeeeeseeseeaeceeaeeaeeaes 19 6.0 ECONOMIC EVALUATION. ..........ccscccccssscssssesessesseeescsssesssaccnracoonsosesessososenbesenens 23 CLT Appr eer. Ll atars rat apeentensts sates stat arseutesusustonessasestersnretswsssvesieursatarsmasssntuy 23 6.2 Discussion and Basis of Economic and Financial Assumptions..........0....::::006 23 GZ FUXCU CRORE ROLE aici el tele tedetet stat ss chvsdadsdadubadeteveresbatersneeshdsdedstchossoalseslen 23 6.2.2 Levelized Replacement CoSt ......cccsssssssessesesesesseseseseesesessesesensesesesseseeseeeaeees 24 6:2:3 Turbine Design Life .........cccccesssssseecensscssccssenseosecscnaceccescacsasecenesossnsinesnssveases 24 6.2.4 Financing Term and Depreciation........c.cccccccisscesesessesesseseseeseseseseeseseesesenseseees 24 G2, 5 TrlereSt ROC oise recors cu cscraseva save yetasosd aztetudesaaaucsarsrase cevahswesvecussereterereeoussparenie 25 6.2.6 General Inflation and Fuel Cost ESCQIation ........:.ccccccccccssesesseseeseeseeseeseeneees 25 (OVA A DTK 111,120 (01: ee ee eee ee 25 6: 250 NGL Presents VOUUE ses te ses ees eis vetoreee sec cevo cee ovebevenesntienssevesrsncsscuearoteassarcaniee. 25 6.3 Capital Costes ciel tate ic csacdesedsdeslohsashalenendbcadesazetetulabatal slcavastavatdssededlsuctalalecbetdcdadel 26 6.3.1 LANA ACQUISILION 0... c.cececeteseteseteeseseseseeeesesseseeceeseesesesecsesecassesesecsessesesenseneraes 26 0.3.2 Wind Turbines and SHIPPINg cicccvcbecncedssvoss stsvetsacsxssseesvesenconsreseseenensesocorssi ousts 26 Global Energy Concepts v January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 6.3.3 Project ENQineering .......ccccccccccccccscces css ecceseesceeesseeseceneeeseessecsecsseeeesseeseesaees 26 6.3.4 Project CONStTUCTION ......0..ccceccccccece cee e eee eeeeeecsecseesseesaeeeseesuessesessessenssesessaeeates 26 6.3.5 Maintenance Equipment .........ccccccccccccccseeseeseseeseeeeeseeeeeeseeeseeesesseceseenseseeesee 28 6.3.6 Commissioning & Additional Startup COStS ....c.cccccccccssseseecsseseeteeeneseesenes 28 6.4 Annual Energy Production ...........ccccccecescecseescseeseesenscesessessesseseceeseeseesseessessees 29 6.5 Operation and Maintenance Costs .........cccccccccsceeseesesceeesceseseescseseesssssecssieessssseees 30 6.6 Cost Of Emery st tase tal shal tsacs tle seeas otoneretoreysvsanvsrurveneyerasan searessserssyesetrassyesssants 31 6.7 Potential: Cost Reduction shststesccevseteesretexestonssescouessteteverstonsustustsceenvacusostvtsscasasessats 32 6.8 Cash Plow Anal ysis.:.i.1.).).0.1sss.csedessssteseverascssstsusssseteurssseespasevassesnsesisasevesaeasntsttery 34 7.0 POTENTIAL ECONOMIC AND ENVIRONMENTAL BENEFITS ...........:00005 42 8.0 RISKS AND UNCERTAINTIES ......0. cc ccceeccsesesesceseesseceeeeeesseeesssesssessseeenseesseseaes .43 9.0 THE WIND ENERGY INDUSTRY wetscctescsivesesive oscee cxctseveasseessouecusevovtesoteaseiesssseoses 44 10:0 FUTUREIREA ACTIVITIES ide sat ivcvdedecedetovedervbesheta tcvabcnsbessatasbaresetessess 46 Global Energy Concepts vi January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation LIST OF FIGURES Figure 1. Phase 1 Wind Turbines in Kotzebue, Alaska...........scsecsessceseeseeeeeeesees 2 Figure 2. Regional Map............csccscceceecsecsscnceeeeseeeeeeeeeeeeeeeseeseseeeeseesoeees 5 Figure 3. Long-term Wind Speed at 10 meters (33 feet) - Airport ...............:000008 11 Figure 4. Annual Diurnal Wind Speed (m/s) - Airport .............ceeeeeesecececeeeeeeees 11 Figure 5. November Diurnal Wind Speed (m/s) - Airport............sccseeseeeeeeeeeeees 11 Figure 6. Long-term Annual Wind Energy Rose ...........scseseceececeeeeceeeeeeeeereens 12 Figure 7. KEA Diurnal Load Profile - August 1998.............ccsceeeeeeeceeeereeeeeners 14 Figure 8. Wind Energy Contribution to KEA Energy Demand................esseeeeeeee 14 Figure 9. Vicinity: Map ......-sccsrrescossessessdostesescevscestestconosssvescouseasdaveasseeurs 16 Figure 10. Monthly Energy versus Turbine Availability ..............ccscceeeeeeeeeee sees _21 Global Energy Concepts vii January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 1. Table 2. Table 3. Table 4. Table 5. Table 6. Table 7. Table 8. Table 9. Table 10. Table 11. Table 12. Table 13. Table 14. LIST OF TABLES Monthly Wind Speed (m/s) at 10 meters (33 feet) - Kotzebue Airport....... 10 Actual Wind Speed at Kotzebue Airport 1984-1996 10 meters (33 feet) ..... 10 Estimated Long-term Wind Speed at 25 meters (83 feet) - Project Site...... 13 Performance Summary - Phase 1 (3 AOC 15/50 Turbines)...............00068 20 Performance Summary by Turbine - 1998.0... cece cecec eee eeeeeeeeeeeeeees 22 Comparison of Actual and Projected Energy ...........:ccecceceeseeeceeeeeeeeee 22 Capital Cost Summary - Phase 1 (3 AOC 15/50 Turbines) ................0685 28 Estimated) Bnergy WOSSes i... 100s sjssacpsaeconessdss ows sleaaisss olsbine sa saws asnes sic 30 Estimated Annual O&M Costs.........cccscsecsecseceeceeceseceeeeseeeeeeeeeeeneees 31 Detailed O&M Labor Costs ..........ccccceecseceecedeeeeeceseeeeseeeeeeeeeeeaeens 31 Potential Balance of Station Cost Reductions from Phase 1 .............00065 33 Summary of Cash Flow Analysis ...........ccccseecseeeeeeeeeeeeeeeeeeeneeeeeeens 35 Cost Comparison of Diesel Generation versus Wind-Diesel Generation... 38 Estimated Savings from Wind Project (with 10 AOC 15/50 turbines) ...... 41 Global Energy Concepts viii January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 1.0 INTRODUCTION 1.1 Overview Kotzebue Electric Association (KEA) and the Alaska Energy Authority, Alaska Industrial Development Export Authority (AEA/AIDEA), formerly the Department of Community and Regional Affairs, Division of Energy (DCRA/DOE) have undertaken a demonstration project to evaluate the economic and technical performance of wind turbines connected to an isolated grid in Kotzebue, Alaska, 26 miles north of the Arctic Circle. This report describes the recent experiences of the project and discusses the economic value of wind energy for Kotzebue, based on the information available as of time. Much of western Alaska has abundant wind resources and the cost of wind energy has been steadily decreasing. Nonetheless, there is limited experience with wind technology in arctic climates and insufficient information is available to determine if wind energy is a viable generating option for the remote communities in northwest - Alaska. Although Kotzebue may not necessarily reflect the exact conditions in other Alaskan villages, KEA is gaining experience with installing and operating wind turbines in an arctic environment and incorporating a high penetration of a new, intermittent energy source in their utility grid. Their experiences provide valuable insight into the technical and economic viability of wind energy projects for the utility and wind energy industries. The wind turbines installed in Kotzebue are funded as three distinct project phases. The initial work on the project began in 1995 and included the installation of three wind turbines. In the spring of 1997, KEA installed their first three grid-connected wind turbines, approximately four miles south of the town of Kotzebue. These Phase 1 turbines were commissioned in September of 1997 and have been operating continuously for over 28 months. Through a Sustainable Technology Energy Program (STEP) grant with the National Renewable Energy Laboratory (NREL) and direct appropriations from the U.S. Department of Energy (DOE), KEA expanded their wind energy installation in 1999 to include a total of 10 operating wind turbines by June of 1999. The utility is also in the process of installing two wind turbines in the nearby village of Wales and evaluating options for further expanding their own wind energy capacity in the future. Figure 1 shows the first three turbines installed in Kotzebue. All 10 turbines installed at Kotzebue are model AOC 15/50, manufactured by Atlantic Orient Corporation (AOC) of Norwich, Vermont. The AOC 15/50 is a three-bladed, downwind turbine with a 15-meter rotor diameter. The turbine manufacturer provides a 1-year warranty against defects in material or workmanship. The turbines are each rated at 50 kW by the turbine manufacturer; however, for the purposes of this report, Global Energy Concepts 1 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation they are considered to be 66 kW turbines because they are designed with a maximum sustainable power output level of 66 kW.' Each turbine is installed on a 24.4-meter (80-foot) lattice tower. The towers are secured to specially designed pile foundations developed with consideration for the tundra and permafrost conditions at the site. The pile foundations elevate the towers approximately 1.5 meters (5 feet) above ground level resulting in a turbine hub height of approximately 26.5 meters (87 feet). Figure 1. Phase 1 Wind Turbines in Kotzebue, Alaska ' This is consistent with the International Electrotechnical Commission definition for the rated capacity of a wind turbine. Global Energy Concepts January 2000 te Kotzebue Electric Association — Wind Power Economic Evaluation 1.2 Report Purpose and Organization The purpose of this report is to present a summary of the costs and performance associated with Phase 1 of KEA’s wind energy development. KEA has retained Global Energy Concepts (GEC), an engineering consulting firm in Kirkland, Washington, to review and analyze the preliminary cost and performance data from the wind project, document KEA’s early experience in planning, installing, and operating the wind turbines, and estimate future wind energy development costs in Kotzebue and surrounding communities. As cost and performance information is currently available for the first three wind turbines, the economic evaluation in this report uses this experience as a baseline for examining potential cost reductions achievable in future wind projects. The recently completed expansion of KEA’s wind project is discussed on a limited basis, and subsequent reports will more fully describe the experience and costs associated with these new additions. The report is organized in 10 sections. The first two sections include the report introduction and some background information on the project and the wind energy program at KEA. Sections 3 through 5 include a summary of the wind resource assessment for the project site, a chronology of the project development, and a summary of the turbine performance. The economic evaluation in Section 6 includes the cost of energy (COE) calculation for Phase 1 of the project, COE estimates for the additional installations, and a 30-year cash flow including a sensitivity analysis. This section also includes a thorough discussion of the Phase 1 capital costs, operation and maintenance (O&M) costs, and annual energy estimates. Potential cost reductions and the impact of these reductions on the COE are also discussed. Potential economic and environmental benefits and risks and uncertainties not addressed in the economic analysis are outlined in Sections 7 and 8. An overview of wind energy activities in other parts of the world is provided in Section 9. KEA’s outreach activities and their vision for future wind energy involvement are summarized in Section 10. Global Energy Concepts 3 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 2.0 KEA’S WIND ENERGY ACTIVITIES 2.1 Background With approximately 3,000 residents, Kotzebue is the largest native community in northwest Alaska. Diesel fuel is imported to generate electricity, and KEA is not interconnected to a utility grid outside the immediate vicinity of the town itself. Fuel is barged in during the summer months and stored for use throughout the winter. Due to the remote location, electricity in rural villages is expensive relative to other areas: approximately four times as much as in urban areas of Alaska and five times as much as the U.S. average. To help offset the high cost of electricity in Kotzebue, the State of Alaska currently supports a Power Cost Equalization (PCE) program. This program provides almost $17 million a year in state energy assistance money with approximately $450,000 going to Kotzebue. Of the funds available to Kotzebue, approximately $150,000 per year is allocated to public infrastructure costs and the remaining $300,000 is used to directly reduce the cost of electricity to KEA customers. However, future funding of the PCE program is uncertain due to a decline in oil revenue in the state. The elimination of the program or a change in its implementation would have a significant impact on the cost of energy in Kotzebue and the other northwest Alaskan villages. In recognition of the village’s limited energy options and potential cost exposure, KEA began to explore alternate energy technologies for Kotzebue and other communities in northwest Alaska in the early 1990s. As a first step, KEA joined the Utility Wind Interest Group (UWIG), a non-profit association providing its members with information on wind energy technology and implementation. In addition, KEA began working with the AEA/AIDEA to formulate plans for a wind energy project to investigate small utility-grade wind turbines that would be suitable for use in rural Alaskan communities. As the concept for a wind project developed over the next several years, KEA identified a parcel of land approximately four miles south of town that appeared to be suitable for development. Figure 2 shows the site location on a regional map. In 1995 KEA began wind monitoring work at the site to quantify the characteristics of the wind resource. The project planning activities received a boost when KEA received funding commitments from both the state and federal governments to supplement their own investment in the project. The AEA/AIDEA has provided $239,000 towards the development of Phase 1 of the project, and the U.S. DOE has committed approximately $4.5 million to the overall efforts of KEA’s wind energy development program. Additional U.S. government funds are expected to be available for use in future wind project work in Kotzebue and other surrounding communities. Global Energy Concepts 4 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation “20 i 5 8 a DEPARTMENT OF ENERGY KOTZEBUE WIND FARM PROJECT REGIONAL MAP @Bethel ‘Anchorage é were 30822-112 mt net LOCMAP Figure 2. Regional Map Global Energy Concepts 5 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation The project is of interest to the federal and state energy agencies because it provides an opportunity to gain valuable experience and to identify the challenges for wind energy deployment in arctic environments. In addition, the project offers the opportunity to determine expected costs and performance for similar projects and to share this experience with other communities contemplating wind power projects. Of approximately 200 remote villages in Alaska, over 70 are estimated to have significant potential for wind energy development. The experiences in Kotzebue are also applicable outside of Alaska, in other states and countries. 2.2 The TVP Program In 1997, KEA became an associate host utility for the wind Turbine Verification Program (TVP). The TVP is a collaborative effort of the U.S. DOE, the Electric Power Research Institute (EPRI), and host utilities to develop, construct, and operate wind power projects. The objective of the program is to provide a bridge from development programs to commercial purchases. The TVP is intended to assist utilities in learning about wind power through first-hand experience and to build and operate enough turbines to gain statistically significant operating and maintenance data. A ~ further objective of the TVP is to provide other utilities with information about wind technology and the project development process from the perspective of utility owners and operators. The TVP is providing technical assistance to KEA through NREL and their support contractors and has supplied KEA with a Supervisory Control and Data Acquisition (SCADA) system developed by Second Wind Inc. of Sommerville, Massachusetts to facilitate data collection from the project. Under the TVP program, monthly performance reports for KEA’s wind project are generated and distributed to interested parties. In addition, EPRI will publish a series of reports describing the project development and the operating experience of the project. The first of these reports, completed in December 1999, describes the background of the project, equipment procurement, construction activities, and start-up and commissioning activities. The TVP program benefits will encompass the first 10 AOC turbines installed at KEA (Phases 1, 2, and 3). 2.3 Turbine Installation The AOC 15/50 wind turbine was chosen for the KEA project because it is a utility- grade turbine and small enough to be used in a small, isolated power system typical of the systems found in rural Alaskan communities. The size also eliminates some of the obstacles inherent in transporting and installing equipment in remote locations. The AOC turbine and tower are ruggedly designed and manufactured for operation in isolated environments. The turbine is designed for cold weather operations and is being tested in similar climate conditions in north central Ontario in Canada. Global Energy Concepts 6 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Phase 1 of KEA’s wind project includes the first three AOC 15/50 wind turbines. The turbines were ordered in 1995 and delivered to the site in February 1997. The first of these turbines began limited power production in late May 1997 but start-up of the other two turbines was delayed because their blade sets were not delivered until July. After working out several other start-up problems, all three turbines were released for full capacity generation on September 28, 1997. The next seven AOC 15/50 wind turbines (Phase 2 and 3) were ordered in early 1998 and delivered to the site in December 1998. Because of weather constraints in the winter months, the installation was delayed until the spring of 1999. The Phase 2 and 3 turbines were commissioned in May 1999 and released for full operation in June 1999. Global Energy Concepts 7 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 3.0 WIND RESOURCE ASSESSMENT KEA began collecting on-site meteorological data in August 1995. In addition to the on-site data, wind data are also available from the Kotzebue Airport. The airport is located a few miles from the project site and serves as a long-term reference for the wind resource in the area. In March 1999, Wind Economics & Technology, Inc. (WECTEC) summarized the data that had been collected in a report, Wind Resource and Theoretical Energy Estimates for Kotzebue, Alaska. The report also includes theoretical energy estimates for the project site for several types of wind turbines that have been considered by KEA. Energy estimates are discussed in a later section of this report. The body of the WECTEC report is included as Appendix A. The on-site data collection suffered from marginal data recovery during its first few years due to equipment problems. The met tower was moved during the summer of 1998 because it was too close to Turbine 1, which was installed in May 1997. WECTEC used concurrent data from the site met tower and the airport data to establish a correlation between the sites. The correlation coefficient is 0.92, which indicates a good statistical relationship between the wind resource at the airport and the project site. The long-term estimated wind speed for the project site is based on hourly data from the airport, which has been adjusted based on the correlation.” The wind resource of a particular area is often expressed as a long-term annual average. The long-term wind resource is the accepted basis for developing energy projections for a project. However, the actual wind speeds that are experienced at a site have diurnal, monthly, and annual variation. Fifteen years of average monthly wind speeds from the Kotzebue Airport are presented in Table 1. These data were measured at a height of approximately 10 meters (33 feet) above ground level. As shown in the table, the annual average wind speeds vary more than 10% from year to year. Table 2 presents the monthly diurnal wind speeds from the Kotzebue Airport for the period 1984 through 1996 (13 years) as summarized in the WECTEC report. The monthly and diurnal patterns are also illustrated in Figures 3 and 4. The highest wind month on average is November and the lowest wind months are April and May. While there is not a significant diurnal variation of the wind speeds at the project site on an annual basis, there is more variation during some months. For example, the winds ? Data from airports, generally measured at 10 m, are commonly used to determine annual variation of the wind resource for nearby project sites and are not heavily relied on for estimating on-site wind resource. However, the Kotzebue Airport is close to the project site, the terrain is relatively flat, and there were adequate on-site data to establish a strong correlation between the two locations. Therefore, the airport data were used to estimate the wind resource for the project site in lieu of on-site data. Global Energy Concepts 8 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation are somewhat higher in afternoons during November (the highest wind month) than they are on an annual basis. The November diurnal pattern is illustrated in Figure 5. Based on the airport data, the predominant wind energy direction in the area is E to SSE with the lighter summer winds from the WNW. A long-term annual wind rose is presented in Figure 6. As previously discussed, the estimated long-term wind speed for the project site is based on hourly airport data that were adjusted based on a correlation developed with concurrent site data. The estimated long-term wind speed for the project site at approximate turbine hub height is presented in Table 3. Global Energy Concepts 9 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 1. Monthly Wind Speed (m/s) at 10 m-Kotzebue Airport Percent of Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avg 15-yr Avg 1984 59 40 40 48 52 38 57 50 51 60 66 70 5.2 92% 1985 GBS) S52) 15'S) 319) 75'8) 15:4) 5°39). 5:8) | 6:2!) 177.01) \9:2)0) 7-2 |) 16:0 106% 1986 47 61 43 53 54 52 55 61 76 51 56 64 56 99% 1987 65 53 54 46 60 5.7 51 59 62 61 51 63 5.7 100% 1988 73 #71 #41 46 54 58 59 55 55 53 50 76 5.8 101% 1989 6.0 103 7.3 67 52 48 59 55 60.67 64 63 6.4 113% 1990 48 40 51 48 44 57 55 61 64 66 80 64 5.7 100% 1991 63 63 57 48 46 51 63 57 58 74 49 44 56 99% 1992 56 51 39 51 51 45 52 69 59 59 58 7.5 5.5 97% 1993 6.7 72 45 46 47 56 53 63 69 69 76 59 6.0 106% 1994 S767 82) 64 27 64 47) 68 GS 89 72 O8! 27 100% 1995 60 56 45 48 49 53 51 52 63 64 46 60 54 95% 1996 6:2) 7) 7:6) 16:0) 7) 74-2) 15:8 | 15:6) 15:6) 16:3, | 19:91) 5:91) 16.1) 14.9) | 16:0 106% 1997 §1 50 42 55 48 58 56 58 54 58 82 42 5.5 96% 1998 43 28 62 63 48 46 46 60 54 63 54 46 51 90% Average 58 58 51 50 60 52 54 59 60 62 65 6.1 5.7 - Table 2. Monthly Diurnal Wind Speed (m/s) 1984-1996 at 10 m-Kotzebue Airport Hour Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual 1 62 62 55 45 44 54 48 60 58 61 67 58 5.6 2 64 65 54 45 46 53 50 60 59 61 7.1 5.7 5.7 3 63 66 54 44 43 50 50 59 59 62 68 59 5.6 4 65 67 52 43 44 51 51 60 58 62 66 6.1 5.7 5 63 65 52 42 43 50 50 60 58 63 66 6.0 5.6 6 62 63 54 41 42 51 51 60 59 63 63 6.1 5.6 7 63 64 51 42 44 50 51 58 59 62 64 58 5.5 8 63 67 50 44 46 50 50 57 58 63 64 5.9 5.6 9 61 65 51 43 48 50 53 58 60 63 69 59 5.7 10 62 68 51 44 50 51 54 58 62 65 66 58 5.7 11 62 67 52 44 50 53 56 59 65 64 69 59 5.8 12 63 67 52 46 50 55 56 61 65 65 7.0 5.9 5.9 13 63 67 52 48 53 57 56 64 67 67 7.3 6.0 6.0 14 6.0 7.0 52 50 52 59 56 64 66 67 7.3 60 6.1 15 62 7.1 55 51 53 57 55 66 65 64 7.3 5.9 6.1 16 61 69 54 50 53 58 55 66 63 65 7.3 59 6.0 17 5.9 67 54 50 53 60 54 65 63 63 7.0 56 5.9 18 5:0) 627/49-5) 10:0 70:2) Ont 0:2) 16507 6.1 5:9) 7 tl tose 5.9 19 G:SieiG63 79 lero sterol 6:20:21 O40 O!Oma 77 One o57 5.9 20 5.9 66 52 50 50 59 53 64 59 58 7.1 5.7 5.8 21 5.9 66 50 50 47 58 50 62 5.7 58 7.0 5.9 5.7 22 §9 66 51 50 46 57 48 61 58 59 66 57 5.6 23 §9 64 52 50 44 55 46 60 58 59 65 56 5.5 24 §8 66 53 49 45 54 48 60 56 59 64 5.7 5.6 Average 61 67 52 47 48 55 52 61 61 62 69 59 5.8 Global Energy Concepts 10 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation N Wind Speed (m/s) a a Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Figure 3. Long-term Wind Speed (m/s) at 10 m-Kotzebue Airport N o a Wind Speed (m/s) ; : 123 4 5 6 7 8 910111213 1415 16 17 18 19 20 21 22 23 24 Hour of the Day Figure 4. Annual Diurnal Wind Speed (m/s) at 10 m-Kotzebue Airport “ Wind Speed (m/s) o a tia > ——r ——r 7 12.3.4 5 67 8 9 1011 1213 14 15 16 17 18 19 20 21 22 23 24 Hour of the Day Figure 5. November Diurnal Wind Speed (m/s) at 10 m-Kotzebue Airport Global Energy Concepts 11 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Kotzebue, Alaska January 1, 1986 through December 31, 1990 Level = 10m Ss Winds: Direction rr eee) | Wind Economics & Technology, Inc. 5 to 10 15 to 20 25 to 30 511 Frumenti Ct. Martinez, CA 94553 a Email: wectecefmi I. 10 to 15 20 to 25 >=30 (mph) | y3° B25 220-D84ee Fans 925-226-0805 Number of Records Used: 43629 Figure 6. Long-term Annual Wind Energy Rose Global Energy Concepts 12 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 3. Estimated Long-term Wind Speed (m/s) at 25 m-Project Site Hour Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual 1 63 62 56 52 50 59 54 63 61 64 7.0 6.1 5.9 2 64 66 56 52 50 59 56 63 62 64 7.2 6.1 6.0 3 64 66 55 51 49 56 55 63 60 65 71 63 5.9 4 65 66 54 50 48 58 55 63 60 65 68 64 5.9 5 63 65 55 50 48 56 56 63 60 65 68 6.3 5.9 6 62 65 55 49 46 57 56 62 61 65 66 64 5.9 7 62 64 53 49 47 57 56 61 60 65 67 62 5.8 8 63 66 52 50 50 56 55 60 60 66 67 63 5.9 9 62 65 53 50 51 56 58 60 63 66 7.1 63 5.9 10 63 67 54 50 52 56 59 61 64 67 69 6.1 6.0 11 6.3 67 55 50 52 58 60 63 67 67 7.1 62 6.1 12 64 67 55 50 54 59 59 63 67 67 7.2 62 6.0 13 63 67 54 53 56 59 59 65 68 70 7.5 63 6.3 14 62 69 55 54 55 60 59 67 67 69 75 63 6.3 15 63 7.0 56 55 56 59 58 66 67 67 7.5 62 6.3 16 63 67 56 55 57 59 59 67 66 67 7.5 6.2 6.2 17 62 67 56 55 58 62 58 66 66 65 7.2 6.0 6.2 18 6:2—8:6-—-§:6>--6.6-—6.7-—6:2—-5.7-+6.7_6:3—6.3-—7.3-—-6:0 6.2 19 65 66 54 57 56 64 58 66 63 63 7.2 6.0 6.2 20 62 66 54 55 55 62 59 66 62 61 7.3 6.0 6.1 21 62 66 53 55 54 61 57 64 61 62 7.2 62 6.0 22 62 65 54 56 52 61 55 64 63 63 69 6.0 6.0 23 62 63 54 56 50 59 53 63 62 62 67 539 5.9 24 61 64 55 55 50 59 55 64 60 62 67 6.1 5.9 Average 63 66 55 53 52 59 57 64 63 65 7.1 62 6.0 Another important factor related to the wind resource of a project is the potential for the project to produce energy at the times when the utility needs the energy. The KEA peak load generally occurs between noon and 6:00 P.M. Winds at the project site do pick up slightly in the afternoon, about the time of KEA’s peak load. During the summer, the winds tend to have a somewhat greater variation than the annual pattern. Figure 7 illustrates that the diurnal wind pattern is similar to KEA’s energy use. Figure 8 provides a monthly comparison of the projected wind energy for the 10 AOC turbines to the total energy demand for the period of July 20, 1998, through July 20, 1999. Based on the data reviewed, the 10 AOC wind turbines are expected to make an annual contribution of approximately 6% of Kotzebue’s electricity needs. Global Energy Concepts 13 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 4,000 8.0 3,500 + 3,000 60 > _ E = 2,500 = = 0 x ® > 2,000 + 40 0 3 & © 1,500 4 ss z 1,000 4 205 500 0 + 00 o 2 4 6 8 10 12 14 16 18 20 2 Hour of the Day Mmm Load Wind Speed Figure 7. KEA Diurnal Load Profile - August 1998 250 2,500 = i = = = 20 200 = 3 z 3 150 1500 £ a o z a = | > = 100 100 & 3 2 2 3 sot H so W & 3 = ° 7 Ee 0 r — r 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Wa Projected Wind Energy Total Energy Demand Figure 8. Wind Energy Contribution to KEA Energy Demand By comparison, in the village of Wales, Alaska, where KEA is installing two AOC turbines, the annual wind speed is approximately 9.0 m/s (20 mph). Due to the cubic relationship of energy to wind speed, a moderate increase in wind speed can have a significant impact on the energy production. The higher winds that are experienced at Wales could result in turbine production 75 to 100% more than is expected at the Kotzebue project. There are several sites being monitored in Northwest Alaska that have excellent potential for wind energy development. A wind speed summary and energy projections for these sites are also included in the WECTEC report. Global Energy Concepts 14 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 4.0 PROJECT DEVELOPMENT KEA served as the developer and general contractor for all phases of the wind project. AOC provided the turbines, towers and installation supervision, but KEA performed all the on-site electrical and civil work. KEA staff was particularly qualified to conduct the on-site work because they were able to incorporate their knowledge of the local conditions and environmental constraints into the overall project design. As the project developer, KEA was also responsible for coordinating the project schedule. Because of the logistical and weather constraints on equipment transportation and construction activities, the scheduling of tasks was particularly challenging. For example, there is only a small window of time in which equipment can arrive by sea because the water is frozen a large part of the year. Construction activities are easier and less damaging to the tundra in the winter months when the ground surface is frozen; however, limited daylight hours and extremely cold temperatures pose additional restrictions. The late fall and early spring provide the best opportunities for most construction tasks. The site layout is illustrated on a vicinity map that is included as Figure 9. The Phase 1 turbines are located in the northwest corner of the project site in a single row. The turbines are oriented north to south perpendicular to the predominant wind direction. In the spring of 1997, KEA extended the distribution line from the existing radio station tower out a half-mile to the project site. Freezeback pile foundations, which are commonly used in arctic construction, were used for the AOC turbines. The holes were drilled, and the pile foundations were installed in the spring of 1997. The Phase 1 construction was completed in July 1997. The seven turbines in Phases 2 and 3 were installed in the northeast corner of the project site in two rows. The new turbines are also oriented north to south. Phase 2 and 3 construction was completed during the late spring of 1999. The current project comprised of 10 AOC 15/50 wind turbines occupies approximately 25% of the 148 acre property. KEA anticipates additional wind energy development at the site. 4.1 Turbine Procurement and Installation The AOC turbine was chosen because its simplified design is suitable to remote locations and its capacity is appropriate for small grids. In addition, the size of the turbine was a major factor for selecting the AOC turbine. In Kotzebue, as well as other nearby villages, there are no large cranes for installing large wind turbines. Transporting a crane to the site to use for construction is expensive and impractical. Fortunately, KEA was able to purchase a small, used crane from a local corporation in Kotzebue, but other nearby communities considering wind energy development will not likely have access to a crane. For these projects the AOC turbines are small enough to Global Energy Concepts 15 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation be erected with a gin pole and will not require the use of a crane. Wind turbines of this size have been erected successfully in northern Canada without the use of a crane. EXISTING 7200 V DISTRIBUTION LINE | SECTION 26 | EXISTING WIND TURBINES | KEA WIND FARM SITE | -N- | ° 500 1000 1500 — SCALE 1” = 1000° DEPARTMENT OF ENERGY KOTZEBUE WIND FARM PROJECT CATION MAP VICINITY MAP Located in 17N, 18W, Koteel River Meridion, AND PLOT PLAN Alaska Kotzebue Recording District Figure 9. Vicinity Map Global Energy Concepts 16 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation The AOC 15/50 is based on the design of the Enertech 44/40 turbine that was originally designed and manufactured in the early 1980s. After several years the manufacturer of © the Enertech turbines went out of business. The design was reengineered by AOC based on the operating experience of the installed turbines. Some of the major improvements are the incorporation of the NREL Advanced Thick Airfoil and an increase in the turbine’s rotor diameter, which resulted in increased energy capture and a decrease in energy losses due to blade soiling. The tower parts for the first three turbines were shipped from Rohn, the tower manufacturer, to Kotzebue and were assembled in Kotzebue with local labor. Although turbines arrived in February 1997, blades were shipped separately and were not immediately available. One set of blades arrived in March, and the installation of Turbine 1 was completed in late May. Turbines 2 and 3 were also tilted up in May but without blades. AOC turbine installation generally specifies that the rotor is installed on the ground, and then the turbine is tilted up. However, when the blade sets for Turbines 2 and 3-arrived in July, they were installed in the air on the erected turbines with a block and tackle rigging. In order to collect data from the first three turbines, KEA contracted with Island Technologies to design and install a customized data acquisition system. The system uses a Campbell Scientific data logger and allows KEA to remotely monitor the site and store hourly time-series performance data. The system was installed in 1997 and will continue to operate until the Second Wind SCADA system is fully commissioned in early 2000. 4.2 Problems Encountered The turbines experienced some initial startup problems. The power output of each turbine was significantly lower than designated by the AOC power curve. In addition to low power output, the control system was blowing an unusual number of fuses. KEA determined that the control system was assembled with the incorrect power factor correction capacitors. However, after the correct capacitors were installed the turbines continued to blow fuses and experience failures in the low voltage surge protection equipment. With further troubleshooting, it was discovered that the generators had been assembled in a wye configuration rather than a delta configuration. The configuration problem was an assembly mistake by Westinghouse, the generator manufacturer. AOC and KEA rewired the generator on each of the turbines to a delta configuration. Fortunately, the rewiring was able to be performed in the field and did not require removal of the turbines from the towers. The turbines were returned to service in late September 1997. Although the reengineering that was done by AOC provided significant improvements to the original design, there were several problems that required troubleshooting by Global Energy Concepts 17 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation AOC and KEA. In some cases, additional modifications were incorporated by KEA. For example, the rotary transformers were slipping so KEA designed and built a bracket that secured the rotary transformer to the turbine housing which eliminated the slippage. This bracket has been added to the Phase 2 and 3 turbines as well. There were also problems with the tip brakes. Rust developed on the magnetic steel catch plate and the electromagnet. This condition increased the air gap between the two parts, which resulted in premature deployment of the tip brakes during wind gusts. Problems with the dampers were preventing the tip brakes from resetting after deployment. Unexpected deployment of the tip brakes significantly reduces the output of a turbine. Ultimately, most of the dampers were replaced and operation improved significantly. However, occasional problems still occur and AOC is considering using a different vendor for the dampers used in the tip brake. KEA continues to perform periodic pull tests as part of their routine maintenance activities. Finally, KEA encountered problems with the Matrix parking brake. After several attempts at troubleshooting the problem the Matrix parking brake was replaced with a Stearns self-adjusting parking brake. AOC originally used the Matrix brake because it was significantly cheaper than the Stearns brake. All of the AOC turbines are now configured with the Stearns parking brake. AOC has benefited from the troubleshooting activities in Kotzebue, while KEA gained valuable hands-on experience with their turbines. The experience and knowledge they gained from the installation and operation of Phase 1 has provided numerous lessons that have assisted with the installation of Phases 2 and 3. Global Energy Concepts 18 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 5.0 PROJECT PERFORMANCE The Phase 1 turbines have over two years of operating experience. For a project of this size, it is not practical for AOC to provide on-site support on a full-time basis. In addition, the distance between their headquarters in Vermont and Kotzebue makes it difficult for AOC personnel to travel to the site to assist with O&M tasks. Asa result, KEA personnel provide a significant amount of the engineering and technical services required to maintain and adjust the turbines. Although KEA has incurred additional labor and consulting costs to perform these activities themselves, they are gaining hands-on experience and a greater understanding of the AOC turbine operation. The Phase 1 project performance through September 1999 is summarized in Table 4 and Figure 10. The success of KEA’s efforts is evidenced by the steady increase in turbine availability. The turbine performance is evaluated on a monthly basis as part of the TVP program. The Kotzebue project was available approximately 87% of the time during the first half of 1998. Turbine downtime was reduced considerably during the second half of the year, when the availability averaged 97%. Sustained project 7 availability of 97% in a remote environment is a respectable achievement, particularly for a first-time developer. The performance improvement can be credited to KEA’s commitment to effectively monitoring the turbines, responding quickly to problems, and the general improvement in turbine reliability. The energy produced from the turbines at Kotzebue varies significantly based on the winds at the site. For example, production during the January and February 1999 reporting periods were the lowest and highest to date, respectively. The average daily production was 202 kWh for January and 1,809 kWh for February, nearly a nine-fold difference. While the two months had similar availability, the estimated hub height wind speed for January was 4.8 m/s (10.7 mph) compared to 7.6 m/s (17.0 mph) during the February reporting period. Table 5 provides a breakdown of energy production and availability for each turbine during 1998, which was studied in more detail for this analysis. Annual energy projections are discussed below in Section 6.4. The 1998 production reported in Table 4 is based on turbine operation from January 1 through December 20, or 8,496 hours, due to a change in the monthly TVP reporting periods. In Table 5 the December values have been adjusted to include production and availability through December 31. The actual production for the 1998 calendar year is approximately 77% of the projected annual energy of 356 MWh. The shortfall is due to the lower than projected turbine availability and a lower than average annual wind speed. The project produced approximately 273 MWh in calendar year 1998; enough power to provide electricity for approximately 41 homes in Kotzebue. When operating at expected levels, the Phase 1 wind turbines will provide electricity to supply approximately 54 homes. Global Energy Concepts 19 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 4. Performance Summary — Phase 1 (3 AOC 15/50 Turbines) Monthly Average Daily Production Production Wind Speed [1] Time Period (kWh) (kWh) Availability at 26.5m (m/s) 1997 Estimate 48,618 N/A N/A N/A January 1998 22,673 731.4 88.7% 5.5 February 8,724 311.6 100.0% 3.8 March 39,341 1,269.1 91.3% 6.3 April 26,640 888.0 73.8% 7.2 May 14,698 474.1 86.2% 5.7 June 7,488 249.6 84.9% 5.0 July 10,204 329.2 88.1% 4.9 August 28,320 913.5 95.4% 6.5 September [2] 8,913 445.7 99.5% 5.4 October 32,917 1,097.2 99.7% 6.4 November 43,804 1,412.9 99.6% 7.3 December 27,152 905.1 98.2% 5.1 1998 Total [3] 270,874 763.0 92.1% 5.8 January 1999 6,269 202.2 97.3% 4.8 = February 56,090 1,809.4 97.9% 7.6 March 13,827 493.8 97.9% 5.0 April 36,548 1,179.0 99.0% 6.9 May 17,446 581.5 83.0% 48 June 12,089 390.0 78.1% 512 July 5,569 185.6 91.5% 4.9 August 18,431 594.5 94.8% 5.9 September 5,653 182.4 95.6% 4.3 Lifetime Totals [3,4] 491,414 783.8 92.4% 5.7 [1] Wind speed was measured on the Phase 1 turbine towers at approximately 18m. The measured wind speeds were adjusted to the turbine hub height of 26.5 m (87 ft) assuming a standard shear of 0.14. A new site met tower was installed in summer 1999. [2] September 1998 values are for the 1* through the 20" only. Beginning with October 1998, the monthly reporting periods are from the 21° of the previous month through the 20" of designated month. [3] Lifetime total availability and wind speeds are the simple average of the monthly values presented in the table. As shown in Tables 4 and 5, the project availability during 1998 was approximately 92%. The long-term estimated production assumes a turbine availability of 95%. For comparison purposes, Table 6 shows an adjustment that accounts for the shortfall due to low availability. If the project had achieved expected availability, it would likely have produced approximately 79% of the estimated energy or 282 MWh during 1998. However, this adjustment assumes that the turbines would have produced average hourly energy during each hour of downtime. In actuality, the turbines may have produced more or less energy during the downtime periods than the rest of the year’s average hourly production rate. Global Energy Concepts 20 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation It appears that the majority of energy shortfall is due to lower than average wind speeds. The average annual wind speed recorded at the Kotzebue Airport for 1998, as reported in the 1998 Annual Summary of the Local Climatological Data from the National Climatic Data Center (NCDC), was significantly lower than the long-term average. Kotzebue Airport’s 1998 average 10 m wind speed is reported as 5.1 m/s (11.4 mph) compared to the 15-year average of 5.7 m/s (12.7 mph). The low annual wind speed is presumably due to a significant reduction in cyclonic storms that are inherent to the area and normally contribute substantially to the sites high winds. The NCDC 1998 wind speed is based on data from a new Automated Surface Observing System (ASOS) that was installed at the Kotzebue Airport in December 1997. A correlation between the old station and the ASOS station has not been verified. While the airport data and information from KEA personnel indicate that 1998 was a low wind year, there is some uncertainty in quantifying the energy shortfall due to low winds. Theoretically, a 10% increase in the annual wind speed would more than cover the 20% shortfall in energy production. However, additional operating experience is required to verify the performance of the turbines. 60 r 100% 80% 60% Availability 40% Energy (MWh) 20% + 0% Jan Feb Mar Apr May* Jun Jul Aug Sep Oct Nov Dec Wm 1998 MWh Mill 1999 MWh =e 1998 Availability e= 1999 Availability Figure 10. Monthly Energy and Turbine Availability Global Energy Concepts 2! January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 5. Performance Summary by Turbine - 1998 Turbine 1 Turbine 2 Turbine 3 Phase 1 Total kWh __ Availabili kWh __ Availabili kWh __ Availabili kWh _ Availabili January 6,141 99.7% 10,355 99.8% 6,177 66.6% 22,673 88.7% February 3,226 100.0% 2,894 100.0% 2,604 100.0% 8,724 100.0% March 10,348 75.5% 14,574 996% |14420 98.7% 39,342 91.3% April 2,982 26.7% 11,609 97.2% |12,049 97.4% 26,640 73.8% May 2,711 58.5% 6,171 100.0% 5,816 100.0% 14,698 86.2% June 748 69.5% 3,535 100.0% 3,206 85.2% 7,488 84.9% July 3,610 89.6% 3,635 98.5% 2,959 76.1% 10,204 88.1% August 10,109 99.6% 9,626 99.6% 8585 87.1% 28,320 95.5% September [1] } 3,135 98.6% 2,846 100.0% 2,932 100.0% 8,913 99.5% October 11,173 99.7% 10,560 996% |11,184 99.7% 32,917 99.7% November 15,100 99.6% 14,651 99.6% |14,052 99.6% 43,803 99.6% December [2] |10,476 _ 99.2% 9686 99.3% 9162 97.5% 29,323 98.7% {Annual 79,758 _ 84.3% 100,142 99.4% 93145 923% 273,045 _ 92.0% [1] Data only includes 480 hours (20 days) due to a change in TVP monthly reporting period for KEA. [2] Production and availability for December is adjusted to include the monthly reporting period (11/20- 12/20) plus remainder of the calendar month. Table 6. Comparison of Actual and Projected Energy % of Projected kWh Energy Projected Annual Production 356,195 Actual 1998 Production (8,760 hours) 273,045 76.7% Adjusted to 95% Availability 281,642 79.1% Global Energy Concepts January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 6.0 ECONOMIC EVALUATION 6.1 Approach Throughout the development of the Phase 1 project, KEA tracked actual costs through a specific work order number in their accounting system. KEA reviewed and summarized these actual project costs. GEC reviewed the summarized costs, held discussions with KEA personnel to clarify areas of uncertainty, and allocated the costs to categories commonly designated for wind power projects. GEC and KEA discussed the lessons learned during the construction of Phase 1 that were likely to reduce specific costs in subsequent phases of the project. KEA also identified costs that were unique to Phase 1 and would not be required for expansion of the KEA project or development of other projects in the area, such as the purchase and repair of the crane. These potential cost reductions are discussed below in Section 6.7. The annual energy production (AEP) is estimated for the Phase 1 turbines based on the expected long-term wind speed at the site, the manufacturer’s power curve, and the expected energy losses. GEC reviewed a recent wind resource analysis prepared by a meteorological consultant to estimate the gross AEP. GEC estimated the expected energy losses based on site conditions and industry experience to predict the net energy for the wind project. Cost of energy was calculated with the actual Phase 1 costs based on the approach recommended by the EPRI Technical Assessment Guide (TAG)’. The potential cost reductions were applied to the Phase 1 costs to estimate the COE for Phases 2 and 3 of the project as well as future projects using AOC turbines. This estimate is preliminary and can be updated to reflect actual Phase 2 and 3 costs once records are finalized. This report includes a 30-year cash flow of the KEA wind project which values the project based on the estimated diesel fuel and O&M costs saved and payments from the federal Renewable Energy Production Incentive (REPI) program. This analysis presents a variety of assumptions to determine the economic viability of wind energy under different circumstances. 6.2 Discussion and Basis of Economic and Financial Assumptions 6.2.1 Fixed Charge Rate On an annual basis, a wind project will cost a utility a certain amount for the capital investment including financing the debt, equity, and depreciation. The expenses related 3 The Electric Power Research Institute publishes a Technical Assessment Guide (EPRI TAG) that provides a methodology and general guidelines for estimating the energy and costs of a power plant. This methodology is commonly used by utilities to consider all elements of a project in a consistent manner in order to compare generating options against each other. Global Energy Concepts a January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation to capital investment are usually referred to as the carrying charges and are expressed as percentages of the initial capital investment. The sum of these percentages is often called the fixed charge rate (FCR). The FCR is the component of the COE calculation that levelizes the capital costs over the life of the project. The FCR used for the KEA analysis is based on 100% debt financing that is available to KEA. The interest rate of the debt financing is 5% and is discussed below. The remaining component that affects the FCR calculation is the depreciation of the capital costs. The design life of the system, which is discussed below, is the basis of the book depreciation. The FCR for the KEA analysis is 6.5%. This low rate is a result of the favorable financing terms available to KEA. The calculation of the FCR for this analysis is included in Appendix B. 6.2.2 Levelized Replacement Cost For this analysis, levelized replacement costs are the levelized equivalent cash sums ~ required for a $5000 per turbine overhaul in the year 2013. Discounting back to 1999 dollars using the discount rate, which is described below, levelizes the cash sums in the year 2013. 6.2.3 Turbine Design Life The AOC 15/50 wind turbine has a design life of 30 years based on analysis and testing of the major components. AOC performed life cycle testing on the transmission and tip brakes for an equivalent of 30 years. These tests were performed under contract to NREL. AOC has also rated the generator and blades as having a 30-year life. GEC recently conducted an industry survey of wind turbine manufacturers of both large and small wind turbines. All manufacturers indicated either 20-year or 30-year design lives. Some environments could be expected to reduce equipment life, such as an extremely corrosive environment. Although the arctic climate is severe and requires special consideration in terms of construction and maintenance of the equipment, the climate is not expected to reduce the operating life of the AOC turbines. However, due to the limited operating experience of the turbine, a major overhaul is assumed in 2013. As discussed above, the overhaul is estimated to cost $5,000 per turbine. To further address the risk associated with the long-term reliability of the wind turbine, a sensitivity was performed that assumes a design life of 20 years. 6.2.4 Financing Term and Depreciation Utility financing for power plants in rural Alaska are financed through the Rural Utility Service (RUS). RUS recently indicated to KEA that although RUS currently has no wind energy loans, they expect that the financing term would be based on the design Global Energy Concepts 24 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation life of the turbine. This financing term is RUS’s standard criteria for determining the term of their loans. The book depreciation rate is also determined by the design life of the system. 6.2.5 Interest Rate The RUS currently has financing available for power projects at an annual interest rate of 5.0%. This rate is subject to change, and the cash flow sensitivities include a scenario that assumes an interest rate of 6.0%. 6.2.6 General Inflation and Fuel Cost Escalation General inflation is assumed to be 2% annually. The actual consumer price index (CPI) in 1998 was only 1.6%. However, this was the lowest annual inflation rate since 1986 when the CPI was 1.1%. The 10-year average CPI-based annual inflation rate from 1989 through 1998 was 3.3%. An assumed inflation rate of 2% over the life of the project is conservative. A higher inflation rate would increase the value of the project. Fuel cost escalation accounts for the assumption that fossil fuel prices will increase beyond general inflation. While accurate forecasting of fuel escalation may not be possible, GEC believes that our assumed escalation rate of 1% is conservative. 6.2.7 Discount Rate A discount rate is generally based on the cost of capital and the required rate of return on equity. Since the RUS offers 100% debt financing, the analysis assumes there will be no equity investment by the utility. Consequently, we have assumed a discount rate of 5%, which is the current cost of available capital. The discount rate is used to account for the time value of money by attaching relative “weights” to each of the annual cash flows. Discounted cash flows allow determination of the current value of future cash flows. 6.2.8 Net Present Value The net present value of a project is the sum of all discounted annual cash flows associated with the project. A net present value of $0 indicates that the project has a rate of return equivalent to the discount rate. In general, an investor would view a project with a positive net present value favorably. 6.2.9 Diesel Fuel Efficiency Diesel fuel efficiency is used to estimate the diesel fuel that will be saved as a result of operating the KEA wind project. The cash flow analyses assume a fuel efficiency of 14.9 kWh per gallon of diesel. This assumption is based on the 1998 energy generation and diesel fuel consumption at KEA. Global Energy Concepts 25 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 6.3 Capital Costs The total costs allocated to Phase 1 are approximately $591,000, representing a cost of $2,985 per kW of installed capacity. The capital costs are significantly higher than the industry average for commercial wind energy projects due to a number of reasons. The AOC turbine is considerably smaller than most commercial turbines, and as such, it is more costly on a capacity basis than larger wind turbines. In addition, the balance of station costs are significantly higher in Kotzebue due to the remote location and arctic climate. Special construction methods are required, scheduling is challenging due to cold temperatures, and other factors that limit access to the site. Development in remote areas with harsh climates will always be more costly. Nonetheless, as mentioned above, many Phase | costs can be reduced in later phases and for other projects. These potential reductions are discussed in Section 6.7. The allocation of the capital costs for Phase 1 are summarized in Table 7, and the major cost elements are discussed in more detail below. 6.3.1 Land Acquisition No capital expenditure was required for KEA land acquisition. The project is located on 148 acres secured with a long-term lease agreement between KEA and the Kikiktagruk Inupiat Corporation. The land lease payments are included in the project’s operating expenses. 6.3.2 Wind Turbines and Shipping The turbine equipment costs include the nacelles, towers, turbine controllers, spare parts inventory, and all related shipping costs. 6.3.3 Project Engineering The project engineering costs shown are for outside engineering services. Thompson Engineering of Anchorage provided a variety of services related to the layout and design of the wind project and interconnection with the KEA distribution grid. 6.3.4 Project Construction There are nine categories included in Project Construction. Following is a discussion of costs allocated to each category. 6.3.4.1 Roads, Pads, Site Survey & Restoration This category includes the on-site road work, snow removal, the site survey, and site restoration work that was done after the turbines were installed. This category does not include costs related to the site access road, which was paid for with separate funding. The access road was built in 1998, nearly a year Global Energy Concepts 26 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation after the construction of Phase 1. The road facilitates access to the site during the summer when vehicles cannot drive on the tundra. However, the access road was not necessary to the development of the project and the costs have therefore not been included. 6.3.4.2 Foundations The largest components of the turbine foundation cost were $50,000 for the nine pilings (3 per turbine) and approximately $24,000 paid to an outside contractor for pile driving services. KEA was able to obtain inexpensive surplus pilings left over from the construction of the medical center in Kotzebue. For Phases 2 and 3, the foundation design was modified and smaller, less expensive pilings are being used. Although a cost reduction is expected, the actual costs have not yet been verified. 6.3.4.3 Turbine and Tower Installation The turbine and tower installation includes all of the direct and indirect labor™ costs allocated to KEA’s Phase 1 work code, the purchase and repair of a used crane for approximately $22,000, and approximately $9,000 for hardware and supplies used during turbine installation. This category also includes costs associated with the use of KEA vehicles during project construction. 6.3.4.4 Electrical Infrastructure The costs allocated to electrical infrastructure are for on-site electrical collection including cabling and wiring for Phase 1 of the project. 6.3.4.5 Electrical Transformers The three single-phase pole transformers and the 225-kVA transformer bank used in Phase 1 of the project were in KEA’s inventory. The transformers had originally been purchased for a different project but not needed for it. The cost of the transformers was not allocated to the Phase 1 work order but was expensed through the Rural Utility Service loan program. The cost included in Table 5 is based on the estimated market value of the transformers and is included in the analysis for comparative purposes. 6.3.4.6 Data Acquisition System The data acquisition category includes the Campbell Scientific data logger and outside engineering services for software programming required for data collection of the Phase 1 turbines. Global Energy Concepts 27 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation 6.3.4.7 Central Building The costs allocated to the control building category include site communication equipment, in this case radios. The labor costs associated with wiring the site control building were also included in this category. The actual building was originally a shipment container and donated by AOC at no cost to KEA. 6.3.4.8 Line Extension & Interconnection The electrical line extension that extended the KEA distribution grid 0.5 miles out to the wind site was allocated to this category. The total cost includes the direct and indirect labor allocated to this specific work code, as well as the poles and electrical line required for the line extension. 6.3.4.9 Miscellaneous The items included in the miscellaneous category were bank charges, meeting expenses, and small miscellaneous expenses related to Phase 1 of the project that lacked sufficient information to be classified in other categories. 6.3.5 Maintenance Equipment Costs included in the maintenance equipment category were for the purchase of safety equipment. No vehicles were purchased specifically for this project. 6.3.6 Commissioning & Additional Startup Costs KEA has allocated some labor and engineering costs to the commissioning and additional startup cost category that were incurred after the turbines were installed in July 1997. These costs were related to extensive troubleshooting and reengineering required for proper operation of the turbines. Some of the engineering services included in this category were for review of a generator problem, tip brake analysis, rotary transformer slippage, and problems with the Matrix parking brake. Global Energy Concepts 28 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 7. Capital Cost Summary - Phase 1 (3 AOC 15/50 Turbines) Number of Turbines 3 Rated Capacity 66 Materials Cost per] Percent Cost Category Labor| Unit $ Total LAND ACQUISITION WIND TURBINES Turbines & Towers 49,653 148,960] 148,960 Cold weather package 805 2,415 2,415 Spare Parts 824 2,471 2,471 SHIPPING 20,922 62,766 62,766 PROJECT ENGINEERING 51,525 51,525 PROJECT CONSTRUCTION Roads, Pads, Site Survey & Restoration 2,688 8,063 Foundations 27,752 83,256 8,063 83,256 Turbine and Tower Installation [2] 67,372 35,963 | 103,335 Electrical Infrastructure 8518 25,554 25,554 Electrical Transformers 1,200 3,600 3,600 Data Acquisition Equipment 16,714 16,714 Central Building 5,764 3,102 Line Extension & Interconnection ASiiat 7,634 Miscellaneous 446 8,866 23,406 446 MAINTENANCE EQUIPMENT 1,551 COMMISSIONING & ADDITIONAL STARTUP COSTS [3] 48,129 1,551 48,129 TOTAL EQUIPMENT COSTS TOTAL BALANCE OF STATION COSTS 88,908 $216,613] $216,613 $285,536] $374,444 TOTAL PROJECT COSTS [1] Based on a turbine rating of 66 KW.’ [2] Includes approximately $22K for crane purchase and repair. [3] These costs were incurred after construction was completed in July 1997 and include additional engineering analyses and modifications required for proper operation of the turbines. 6.4 Annual Energy Production For the purpose of this analysis, GEC used data from the wind resource assessment performed by WECTEC. The production estimates presented in this report were based on the long-term wind resource at the project site as described above in Section 3.0 of this report. Based on the annual distribution of winds at the KEA site and the AOC 15/50 published power curve, the gross annual energy is estimated to be 131,400 kWh per turbine. Expected energy losses summarized in Table 8 are based on site conditions and industry _ Global Energy Concepts 29 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation experience. The 9.7% total cumulative losses assumed by GEC are more conservative than the 6.5% losses estimated in the WECTEC report. Based on the expected losses listed in Table 8, the net annual energy is estimated to be approximately 118,700 kWh per turbine or 356,200 kWh for Phase 1. Based on the actual adjusted energy production for 1998 and long-term wind resource measurements the estimated annual energy appears to be reasonable. Table 8. Estimated Energy Losses Estimated Loss Factors Loss Efficiency Availability 5.0% 95.0% Transformer/Line Losses 1.0% 99.0% Control System 1.0% 99.0% Blade Soiling 1.0% 99.0% Wake/Off-axis 2.0% 98.0% Net Efficiency 90.3% Total Cumulative Losses 9.7% 6.5 Operation and Maintenance Costs The annual O&M costs for KEA’s Phase 1 project are estimated to be approximately $2,600 per turbine or $0.022 per kWh. The O&M costs include replacement parts and labor for scheduled and unscheduled turbine maintenance, land lease payments, insurance expenses, and other administrative costs. The estimated annual expenses for Phases 2 and 3 as well as other larger projects are expected to be somewhat lower, approximately $2,150 per turbine or $0.018 per kWh. The breakdown of estimated O&M costs are provided in Table 9. This estimate can be further refined when the project has more operating experience. Land lease payments are based on the terms of the lease contract between KEA and Kikiktagruk Inupiat Corporation. The majority of the annual land lease payment is a fixed fee of $400 per turbine. A remaining annual payment is based on the energy production of turbines and the avoided cost of fuel. For this variable portion of the lease payment, KEA pays the Lessor 1.5% of KEA’s 1998 avoided fuel cost of $0.064 per kWh produced by the turbines. Annual insurance expenses are estimated (in 1998 dollars) at $100 per turbine for general liability. The parts and labor costs are based on scheduled and unscheduled turbine maintenance activities. The labor hours associated with scheduled maintenance are based on the manufacturer’s recommended periodic maintenance for the AOC 15/50 and discussions with KEA maintenance personnel. The labor costs shown in Table 10 are based on KEA’s fully burdened labor rates. Global Energy Concepts 30 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 9. Estimated Annual O&M Costs 3-Turbine | 7-Turbine per WT Total per kWh | per WT Total per kWh Land lease fixed $400 $1,200 $0.003 $400 $2,800 $0.003 variable $114 $342 $0.001 $114 $798 $0.001 Insurance $102 $306 $0.001 $102 $714 $0.001 Parts usage $300 $900 $0.003 $300 $2,100 $0.003 Labor $1,680 $5,040 $0.014 $1,176 $8,232 $0.010 Total O&M $2,596 $7,788 $0.022 | $2,092 $14,644 $0.018 Table 10. Detailed O&M Labor Costs Annual Burdened Hours Rate Costs Scheduled 108 $28/hr $3,024 Unscheduled 72 $28/hr $2,016 Total for 3 Turbines 180 $5,040 - On capacity basis, the estimated O&M costs are higher than the industry average, which is generally in the range of $0.005-$0.01 per kWh for large turbines. The higher costs for the KEA wind project are due to the additional labor required to maintain small wind turbines and the additional time required to perform maintenance activities in extremely cold temperatures and in limited daylight hours. 6.6 Cost of Energy The EPRI approach to calculating COE is derived from a standard cash flow analysis of the wind energy project. The FCR, discussed above in Section 6.2.1, is 6.5%. The COE calculation is based on constant dollars without the effect of inflation. Constant dollar COE calculations are generally preferred by EPRI because technological improvements would be difficult to perceive in the presence of increasing inflation. In a constant dollar calculation the annual levelization is a function of the FCR and the LRC related to the assumed turbine overhaul in year 2013. The project costs include initial capital costs and annual O&M expenses. Annual O&M costs are carried separately in the COE analysis. The sum of the carrying charges and the annual expenses are the required revenue. The COE is the annual levelized required revenue divided by the annual energy output. The COE formula is expressed as: Global Energy Concepts 3] January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation COE = (ICC x FCR) + 1*year O&M + LRC AEP Where: ICC = initial capital cost FCR = fixed charge rate AEP = annual energy production LRC = levelized replacement cost The estimated COE for Phase 1 of the KEA project is: COE = ($591,000 X 6.5%) + $7,800 + $500 = $0.131 per kWh 356.2 MWh As discussed above, the FCR assumed in this calculation is based on KEA’s expected cost of debt and a 30-year design life. KEA’s access to 100% debt financing at a low interest rate has a positive impact on the COE. Municipal utilities and other non-profit entities that install non-hydro renewable energy projects are eligible for the REPI. The 10 AOC turbines installed at KEA are eligible for this 10-year incentive payment of $0.017 per kWh in 1999, The payment rate is adjusted annually based on the general inflation index. However, the REPI payment can not be assured as it depends on annual appropriations from Congress. With the REPI payments, the COE would be reduced during the first 10 years of the project by nearly $0.02 per kWh. 6.7 Potential Cost Reduction A review of KEA’s Phase 1 costs shows several areas of potential cost reduction that would favorably impact the costs for Phases 2 and 3 of the project and other future development in the Kotzebue area. The reductions are most likely to occur in the balance of station costs. It is unlikely that the equipment costs will be significantly reduced; however, there may be some cost reduction in shipping, depending on the location of the future projects and the ability for advance planning. Some of the cost reductions will occur because they will not be necessary for Phases 2 and 3 and other projects. For example, Phase 1 costs included the purchase and repair of a crane for the installation of the turbines that will be used in Phases 2 and 3. As discussed in Section 4.1, crane costs are also not likely to be incurred in nearby communities, as the turbines will instead be erected with the use of a ginpole. In addition, there will be cost reductions associated with the line extension and interconnection. During Phase 1, the KEA construction crew learned cost effective methods of installing the tower piling foundations and assembling and erecting the turbines. The Phase 2 and 3 foundation modification includes the use of a significantly smaller diameter piling and reduced the cost of materials compared to the Phase 1 materials. Global Energy Concepts 32 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Although the final cost numbers are not yet available for Phases 2 and 3, the construction work has been completed. Construction crew managers indicated that the construction time was cut by at least one-third due to the experience gained in Phase 1 construction. Table 11 provides an estimate of the potential cost reductions between Phase 1 and later development. Future development in Kotzebue and other rural Alaskan communities would not likely bear the cost of a data acquisition system, so that cost has been removed from the balance-of-station costs. Line extension and interconnection costs can vary widely from project to project. For Phases 2 and 3 and other developments it is assumed that the line extension costs will be reduced by 50% from the Phase 1 costs. The commissioning and additional startup costs arose from problems that were for the most part resolved during the Phase 1 development and are not anticipated to resurface. Assuming the reduced balance of station costs presented below, the new calculated COE will be reduced overall by approximately 25%. This calculation can be updated when construction is completed and the actual costs for Phases 2 and 3 become available. Table 11. Potential Balance of Station Cost Reductions from Phase 1 Actual Balance of Station Cost — Phase 1 $1,891 per kW Percent Per kw Category Reduction Reduction Project Engineering 40% $104 Foundations 25% $105 Turbine and Tower Installation Labor 35% $119 Crane 100% $111 Data Acquisition System 100% $84 Line Extension 50% $59 Additional Startup 80% $194 Total Potential Reduction 41% $777 Potential Balance of Station Cost - Phases 2 & 3 $1,114 per kW Based on the potential cost reductions, the estimated COE for future development assuming seven AOC 15/50 turbines is: COE = ($1,020,000 X 6.5%) + $14,600 + $1,200 = $0.099 per kWh 831.1 MWh This is an estimated COE that is dependant on actual costs. In the case of development at other locations, the COE may also be impacted by the site wind resource. Global Energy Concepts 33 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Development after Phase 1 not only benefits from the reduction of capital costs but also from a reduction in O&M costs. The labor costs associated with maintenance is expected to be reduced by approximately 30% on a per turbine basis. These cost savings may not be applicable to locations other than Kotzebue. Without the O&M cost savings, the COE would be $0.103 per kWh. A COE of $0.099 per kWh represents a reduction of approximately 25% from the COE for the Phase 1 project. A cost of $0.099 per kWh for wind energy is still considerably higher than the cost of diesel generation at Kotzebue of approximately $0.074/kWh. The calculation of diesel generation cost is based on the average annual operating cost (fuel, labor, and materials) for 1996 through 1998 and the total energy generated in 1998. The actual avoided cost of energy will be slightly lower than $0.074/kWh due to fixed annual expenses that would not be offset by production of wind energy. The estimated COE for the 10 wind turbines installed in Kotzebue combines the actual Phase 1 cost with the estimated Phase 2 and 3 costs as follows: COE = ($1,611,000 X 6.5%) + $22,800 + $1,700 = $0.109 per kWh 1,187.3 MWh As previously discussed, the COE may be further reduced during the first 10 years of operation by the receipt of REPI payments. For 1999 the REPI payment is $0.017/kWh, reducing the estimated cost of wind energy to $0.082. The REPI payments have not been included in the above calculations. 6.8 Cash Flow Analysis The cash flow analysis is based on the same basic assumptions used in the calculation of the COE. The assumptions are included on the cash flow spreadsheets, included in Appendix C. Project size, capital cost, financing terms, the basis of the benefit calculation, and a breakdown of operating expenses assumed in the cash flow analysis are identified for each scenario. The value of the energy produced from KEA’s wind project is based on the estimated savings from not burning diesel to produce the same amount of energy. The diesel savings include the cost of the fuel and related O&M costs. The savings are calculated on a per kWh basis. Based on discussions with KEA, it is assumed that 25% of the diesel O&M costs are fixed and 75% are variable costs related to energy production. In spite of being related to run-time hours, the annual diesel O&M costs can vary significantly from year to year. For this reason, the annual diesel O&M costs used in the calculations are an average of the actual costs for 1996 through 1998. Actual diesel O&M costs that will be saved are not yet known and will continue to be reviewed. The value of the wind energy also includes the REPI payments assuming that Congress will continue to appropriate the necessary funds for that program. Table 12 summarizes the results of the cash flow scenarios. Global Energy Concepts 34 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation As shown in Table 12, the Phase | project scenario results in a net present value of -$100,416, an internal rate of return of 3.4%, and a COE of $0.131 per kWh. Phases 2 and 3 are expected to benefit from significant cost reductions resulting in a baseline net present value of $121,950 and a COE of $0.099 per kWh. Table 12. Summary of Cash Flow Analysis Net Present Internal Cost of Scenario Value Rate of Return Energy [1] Phase 1 Project -$100,416 3.4% $0.131 Baseline; assumes potential reductions; 7 WTs; 100% debt; no subsidy $121,950 [2] $0.099 Capital Cost Variation 20% higher costs -$77,188 [2] $0.115 10% lower costs $221,519 [2] $0.091 Financing Assumptions 20-year debt financing and project life -$173,714 [2] $0.119 6% interest on debt and discount rate -$9,159 [2] $0.109 Energy Estimates 20% lower than expected -$125,396 [2] $0.124 10% higher than expected $245,624 [2] $0.090 Turbine Maintenance Costs 20% higher expenses $73,912 [2] $0.103 10% lower expenses $145,969 [2] $0.097 Wind Resource 6.5 m/s wind resource $213,834 [2] $0.092 7.0 m/s wind resource $454,716 [2] $0.078 7.5 m/s wind resource $494,236 [2] $0.076 Other Economic Sensitivities Fuel escalation 3% (plus 2% inflation) $522,441 [2] N/A General inflation 4% (plus 1% fuel escalation) $553,491 [2] N/A Diesel O&M Savings 50% (versus 75%) $75,784 [2] N/A Without REPI payments $7,771 [2] N/A FCR of 0.10 N/A N/A $0.142 7.0 m/s resource; 30% higher capital $156,009 [2] $0.097 7.5 m/s resource; 30% higher capital $195,529 [2] $0.095 [1] The COE values do not include REPI payments that may be available for up to 10 years. [2] Internal Rate of Return (IRR) is used to evaluate an equity investment. This analysis assumes 100% debt financing, and therefore is not an applicable financial measure. As shown in Table 12, some variables have significantly more impact than others on the economic feasibility of a wind project. For example, because of limited operating experience, a sensitivity is included to account for the uncertainty related to the actual maintenance cost of AOC turbines. However, as shown in the table, 20% higher than Global Energy Concepts 35 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation expected maintenance costs only increases the COE from $0.099 per kWh to $0.103 per kWh. The variable with the most obvious impact is energy production. As previously discussed, while the KEA site has a favorable wind resource, several other communities considering wind development have more energetic resources. Using the same baseline assumptions for a project in a 7.0 m/s wind regime (compared to the 6.0 m/s resource at Kotzebue), the COE is reduced to an estimated $0.078 per kWh. On the other hand, energy projections could be too high either because the actual wind resource is lower than estimated or because the turbines do not perform as well as expected. If the project produces 20% less energy than assumed the estimated COE increases to $0.124 per kWh. An additional analysis for determining the value of adding wind energy to a utility grid compares the cost of diesel generation for Kotzebue with and without the addition of wind energy. The cost of generating energy from the existing diesel plant is compared to the cost of generating the same amount of energy when wind energy is supplementing the diesel generators. Table 13 presents a cash flow analysis that assumes the operation of 10 AOC 15/50 turbines in the Kotzebue wind regime. The total energy required is based on the actual electricity used in Kotzebue during 1998 and assumes an annual load growth of 2.8%. The assumptions related to diesel efficiency, fuel costs and wind turbine maintenance are the same as used in the previous cash flow analysis. In this comparison analysis, the wind project was valued as a fuel saver. The net present value of the cost of diesel fuel and O&M without the wind project was calculated and compared to the net present value of the system including the wind project. In the “Diesel Only” calculation, only the diesel fuel and O&M costs were considered. The “Wind-Diesel” calculation includes consideration of the capital and operating costs of the wind project. The capital costs assumed in this analysis include the actual cost for Phase 1 plus the estimated cost for Phases 2 and 3. The Wind-Diesel calculation also includes the value of the fuel and diesel O&M savings from the contribution of the wind project to the energy mix. The difference of value between the “Diesel-Only” and the “Wind- Diesel” represents the value of the wind project to the utility. The results of the comparison analysis indicate that the addition of the wind project, without consideration of the capital cost of diesel, does not add value to the overall generating system. Table 14 shows a variety of scenarios reflecting different fuel escalation rates. As seen in the table, even a small change in fuel escalation from the baseline assumption will result in a significant change in potential savings from the wind project. Although Table 14 only addresses fuel escalation changes, there would be similar results for changes in general inflation. For example, an increase in general inflation to the 10-year average of 3.3% (1989-1998) results in an after-investment savings from wind energy of over $200,000. Even a 0.5% increase in the assumed fuel cost escalation results in the wind project adding economic value to the KEA generating Global Energy Concepts 36 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation system. Likewise, an increase in general inflation results in economic value to KEA. These results are conservative since the wind project performance is based on the Kotzebue wind regime and because there are no capital costs taken into account for the diesel system. Global Energy Concepts 37 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 13. Cost Comparison of Diesel Generation versus Wind-Diesel Generation $0,063 per kWh “1999 2. Diesel O&M $0.0116: per kWh in 2013) “2001 2002 ‘Energy Generated (MWh) [1], Le gallons required : ft Cost of Diesel Energy Year 22,102.0 2,720.9 23,357.0 | 24,011.0 | 24,6833 | 25,3745 | 26,085.0 1,702,985 , “$1,911,446 “$317,252, -$332,6 122,479: $2,244,104: $2,372,72 26,815.3 :Net Wind Energy (MWh) Diesel Energy Required Net Present Value _ Savings after Investment ; 1,531,793 1,57 $4,620,604 $1,718,302 $1,822,006 Global Energy Concepts 38 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 13 continued. Cost Comparison of Diesel Generation versus Wind-Diesel Generation IESEL ONLY O&M cost [2] Global Energy Concepts 39 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 13 continued. Cost Comparison of Diesel Generation versus Wind-Diesel Generation Diesel Only versus Wind-Diesel based on 10 AOC 15/50 wind turbines with a 30-year system life DIESEL ONLY Year 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Energy Generated (MWh) [1] 38,396.7 39,471.8 40,577.0 41,713.2 42,881.1 44,081.8 45,316.1 46,585.0 47,889.3 49,230.2 Cost to Produce gallons required 2,576,960 2,649,114 2,723,290 2,799,542 2,877,929 2,958,511 3,041,349 3,126,507 3,214,049 3,304,043 fuel cost $4,506,270 $4,771,419 $5,052,169 $5,349,438 $5,664,199 $5,997,481 $6,350,373 $6,724,029 $7,119,670 $7,538,592 O&M cost [2] $677,481 $710,379 $744,875 $781,046 $818,974 $858,743 $900,444 $944,169 $990,018 $1,038,093 Cost of Diesel Energy $5,183,750 $5,481,798 $5,797,044 $6,130,485 $6,483,173 $6,856,224 $7,250,816 $7,668,198 $8,109,688 $8,576,685 Net Present Value WIND-DIESEL Year 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Net Wind Energy (MWh) 1,187.3 1,187.3 1,187.3 1,187.3 1,187.3 1,187.3 1,187.3 1,187.3 1,187.3 1,187.3 O&M costs $31,707 $32,342 $32,988 $33,648 $34,321 $35,008 $35,708 $36,422 $37,150 $37,893 Diesel Energy Required 37,209.4 38,284.5 39,389.7 40,525.9 41,693.8 42,894.5 44,128.8 45,397.6 46,702.0 48,042.9 Cost to Produce gallons required 2,497,274 2,569,429 2,643,604 2,719,856 2,798,243 2,878,825 2,961,664 3,046,821 3,134,364 3,224,357 fuel cost $4,366,925 $4,627,894 $4,904,338 $5,197,173 $5,507,366 $5,835,942 $6,183,988 $6,552,652 $6,943,153 $7,356,779 O&M cost [2] $656,531 $689,011 $723,079 $758,815 $796,298 $835,613 $876,851 $920,105 $965,473 $1,013,057 Cost of Diesel Energy $5,023,456 $5,316,905 $5,627,418 $5,955,988 $6,303,664 $6,671,556 $7,060,839 $7,472,758 $7,908,626 $8,369,836 Cost of Wind-Diesel $5,055,164 $5,349,246 $5,660,406 $5,989,636 $6,337,985 $6,706,563 $7,096,547 $7,509,179 $7,945,776 $8,407,729 [1] Energy production is based on the 1998 kWh generated and KEA's historical load growth of 2.8%. ' [2] O&M costs include burdened labor rates but do not include miscellaneous administrative costs. Global Energy Concepts 40 January 2000 Kotzebue Electric Association — Wind Power Economic Evaluation Table 14, Estimated Savings from Wind Project (with 10 AOC 15/50 turbines) $2,075,213 $464,208 :[3] Although the cashflow is based on all ten turbines, the remaining assumptions are ithe same as those used in the baseline cash flow discussed in Section 6.2 and i ndix C. j Global Energy Concepts 41 August 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 7.0 POTENTIAL ECONOMIC AND ENVIRONMENTAL BENEFITS Several potential benefits of the use of wind energy are not necessarily captured in a traditional economic analysis. These benefits are difficult to quantify, yet may provide additional incentive when considering wind energy projects in the future. They include: Wind energy development mitigates the risk associated with future fuel cost increases. Diesel energy cost increases may come in two forms, fuel escalation and legislative action such as subsidy cuts and emission taxes. In addition to the financial risks of increasing fuel prices, economic and environmental risks are associated with the transportation and storage of fuel. Asa fuel saver, wind energy reduces the quantity of fuel transported and stored. In many of the region’s small villages, the need for additional fuel storage may be eliminated or postponed by adding wind energy. The cost of adding fuel storage’ varies widely and should be evaluated on a case-by-case basis to determine the potential benefit of adding wind energy. Over the past decade wind energy has benefited from a steady decline in cost and a significant improvement in efficiency and reliability, discussed further in Section 8. Wind energy development in northwestern Alaska will benefit from some degree of economies of scale if additional projects are installed in surrounding communities. The KEA wind project has and continues to provide much-needed jobs for the local community. The project was constructed and is operated and maintained with local labor. For example, all of the control buildings for Phases 2 and 3 were built in Kotzebue. The basic structure of a wind energy training program has been established through this project. The training program will improve the capabilities of the local work force and provide economic opportunity as discussed further in Section 9. The development of wind energy is an opportunity to use indigenous natural resources, which reduces dependence on outside resources. Many of the design innovations developed during the design and construction of the project are related to arctic conditions and may be applicable to other industries. Global Energy Concepts 42 August 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 8.0 RISKS AND UNCERTAINTIES Risks and uncertainties exist in the development of any type of project. Although the wind industry has made numerous technical and economic improvements in the last 10 years, there are still greater risks and more uncertainties associated with wind energy development than with development of more traditional power projects, such as: ¢ Commercial wind energy is a relatively new technology and carries risks inherent in any new technology. For instance, assumptions related to the performance and reliability of the equipment are largely based on theory and not historical data. e Limited wind resource data have been collected at the actual project site. Although the comparison of the airport data to the site data indicates a strong correlation, the analysis was based on limited data and may be less accurate than calculated. Additional data collection is necessary to confirm the actual wind resource at the project site. e Predicted energy losses are based on site conditions and industry experience. However, actual energy losses may be higher than predicted and will also vary from year to year potentially reducing the energy production from the project. e The estimated COE for future wind energy development is based on potential cost reductions, which may or may not be realized. This is particularly true for projects developed in outlying communities. Project economics are very site specific and difficult to accurately predict without a thorough feasibility study for each site being considered for development. The sensitivity analysis that is summarized in Section 6.8 accounts for some of the variables that will exist between different sites. Global Energy Concepts 43 August 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 9.0 THE WIND ENERGY INDUSTRY Wind power has been the fastest growing energy technology worldwide during the 1990s, expanding at an annual rate of 22.6%. Although the U.S. dominated the early market for commercial wind energy installations in the 1980s, the Europeans have exceeded the U.S. in terms of installed wind energy capacity in more recent years. Significant wind energy development has also occurred in other regions of the world, notably in India, China, the Middle East, and Latin America. As a result of large capacity additions in the U.S. and Europe during the past year, the worldwide wind capacity exceeded 10,000 MW in the spring of 1999. The American Wind Energy Association (AWEA) has documented more than 1,000 MW of new wind energy projects that came on-line in the U.S. between July 1998 and June 1999. The majority of these new projects are in the Midwest, particularly in Minnesota, Iowa, and Texas. At the end of 1998, wind energy projects installed in the U.S. were generating 7 approximately 3 billion kWh of electricity each year, enough to serve the residential power needs of approximately 1.4 million people. This wind-generated electricity produces the energy equivalent of 6.4 million barrels of oil and avoids 1.7 million tons of CO,, as well as sulfur and nitrogen oxide emissions that cause smog and acid rain. The prospects are favorable for continued growth of the wind industry both in the U.S. and internationally as the economics of wind energy continue to improve. Wind power today costs only about one-fifth as much as in the mid-1980s, and its costs are expected to decline by another 35-40% by 2006.* Long-term forecasts in the early 1990s by EPRI and Pacific Gas & Electric that wind power would ultimately become the least expensive electricity generation source are close to being realized. The reliability of wind turbine technology has improved dramatically over the last two decades. Some of the early wind turbines suffered from design, material, and workmanship problems. Although typical in a new industry, these problems caused widespread concern about the use of the technology among members of the utility community. Wind turbine designers and equipment manufactures have learned from this early experience. These lessons, coupled with design innovations from federal and industry research laboratories, have been incorporated into improved wind turbine models for use in utility applications. Newer wind energy projects typically achieve an availability of 95-98%. The use of wind energy in grid-connected village power applications and remote, stand- alone systems has received increased consideration. In many locations, electrical energy is unavailable or extremely expensive due to the cost and logistical difficulties of “Chapman, Jamie, Steven Wiese, Edgar DeMeo, and Adam Serchuk. “Expanding Wind Power: Can Americans Afford It?” Research Report No. 6. Washington, D.C.: Renewable Energy Policy Project. November 1998. Global Energy Concepts 44 August 1999 Kotzebue Electric Association — Wind Power Economic Evaluation obtaining fuel. Small-scale wind energy projects compete favorably with grid extension in many of these locations, and the market for this type of wind energy application is substantial. A number of different commercial wind projects and prototype installations are underway in various parts of the world, which will provide additional information about the cost, and performance of such projects. Global Energy Concepts 45 August 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 10.0 FUTURE KEA ACTIVITIES Kotzebue, Alaska, and the numerous smaller villages throughout northwest Alaska are unique from any other area of the U.S. The isolated and harsh environment presents unusual challenges to utility companies that provide energy to these communities. Energy subsidies that have helped to equalize the high cost of energy in Kotzebue and other rural communities are expected to be reduced or discontinued in the near future. KEA has aggressively pursued the integration of wind energy into their power system, and expects to expand their wind energy capacity to the penetration level that their grid is able to support. KEA is not only interested in reducing the future electric costs of Kotzebue customers, but is also committed to supporting the integration of wind energy into the power systems of surrounding communities. KEA plans to support neighboring communities with developing wind energy from several perspectives. KEA has outlined the structure for a renewable technology center at their facility in Kotzebue where residents of outlying communities can receive training in the operation and maintenance of wind - systems. Further developing the local labor pool is an important goal to KEA. KEA has also developed a plan for creating informational materials to communicate with the public, partners, consumers, utilities, and others that are interested in the wind energy project. Major elements of the KEA outreach program are informational brochures, news releases, an information kiosk at the wind site, and site tours. KEA is also preparing a renewable energy curriculum for local schools that will include educational presentations. A prime example of the impact that the KEA project is having in northwest Alaska is the wind power project in the village of Wales. The Wales wind project currently under construction will make Wales the first community in Alaska powered almost exclusively by wind energy. The Alaska Science and Technology Foundation, AEA/AIDEA, KEA, Alaska Village Electric Cooperative, NREL, and the U.S. Environmental Protection Agency through the Innovative Technology Initiative are supporting the Wales wind project. An estimated 70 communities in rural Alaska have the ability to develop wind energy projects. KEA expects to play a leadership role in supporting all aspects of wind energy development in these communities. KEA anticipates continuing its involvement with the AEA/AIDEA in attaining the agency’s objective of meeting the energy needs of rural Alaska. Global Energy Concepts 46 August 1999 APPENDIX A WIND RESOURCE AND THEORETICAL ENERGY ESTIMATES Wind Resource and Theoretical Energy Estimates For Kotzebue, Alaska and the Northwest Coast Prepared For: Kotzebue Electric Association P.O. Box 44 Kotzebue, Alaska 99752 Prepared By: Wind Economics & Technology, Inc. 511 Frumenti Ct. Martinez, CA 94553 March, 1999 Table Of Contents 1.0 INTRODUCTION ....ccsssesessssesesscsecsestesesesecseencensesssesesenenseucsreassusaeseseseesessseenenesnenessenssncassesacaneatenees 2.0 BACKGROUND w..ccscsessssesssseenesnesesesessesnesescsssnesescessensansencsssncsieseaneneseaeseseeneacsecscenesesessesnssesessssnanegees 3.0 WIND RESOURCE essssssscocssssevsessvosssensosaccsnenssevvesonessnononsseseasonsseovssonsssessosaesouscasssoesssereovessieoonesgsuseses 3.1 GENERAL WIND INFORMATION .......cecesseseeeeeeeeees 3.1.1 Battelle - Pacific Northwest Laboratory. 3.1.2 National Climatic Data Center.. Bid ROTZEBUB sons csessessvsssecewscicsersssrsoeon 3.2.1 Annual Average Wind Speed. 3.2.2 Monthly and Diurnal Wind Speed 3.2.3 Extreme Wind Speeds.....cccccee 3.2.4 Wind Speed Frequency Distribution. 3.2.4 Wind Rose....... 3.2.5 Climatic Data.. 3.3 NORTHWEST COAST.... 3.4 ON-SITE METEOROLOGICAL MONITORING PROGRAM. 3.4.1 Annual Average Wind Speed........ 3.4.2 Diurnal and Monthly Wind Speed 3.4.3 Wind Speed Frequency Distribution. 3.4.4 Joint Frequency — Wind Speed and Wind Direction.. 3.5 WIND ATLAS ANALYSIS AND APPLICATION PROGRAM Wwod CWO MMUWNUNUWHLWWwWWwWHN 4.0 THEORETICAL ENERGY PROJECTION ....ccscsesssssssessesesssssseeseseseseseeacsecaesneneenencsscaseuesseneareneaes 13 4.1L INTRODUCTION... eeeeceeseeeeeeeteeee 4.2 WIND TURBINE POWER CURVES 4.2.1 Bergey.. 4.2.2 AOC 15/50. 4.2.3 Northwind 100. 4.2.4 Vestas V27... 4.2.5 Micon 225 4.3 THEORETICAL ENERGY ESTIMATE FOR THE KOTZEBUE WIND 4.3.1 Kotzebue Wind Energy Facility....c...cc0 4.3.2 Wind Speed - Airport Versus Wind Facility 4.3.3 Long Term Wind Speed.. 4.3.4 Annual Theoretical Energy Estimate 4.3.5 Mean Diurnal Energy Output (kWh) 4.3.6 Average Monthly Energy Production... 4.3.8 Theoretical Net Energy Output - 660k 4.4 NORTHWEST ALASKA ....ccsecsessessesecscsscseeeeeeees 4.4.1 General Theoretical Energy Estimates 4.4.2 Theoretical Energy Estimates — Northwest Alaska... soe 2S APPENDIX A CLIMATOLOGICAL SUMMARIES FOR SELECTED ALASKAN STATIONS ii nn List of Tables TABLE 3-1 WIND POWER CLASS AND ANNUAL AVERAGE WIND SPEED 2 TABLE 3-2 MONTHLY AVERAGE WIND SPEEDS FOR KOTZEBUE 4 TABLE 3-3 MEAN DIURNAL WIND SPEED FOR KOTZEBUE 4 TABLE 3-4 PEAK WIND SPEED DATA 5 TABLE 3-5 WIND SPEED FREQUENCY DISTRIBUTION 7 TABLE 3-6 CLIMATOLOGICAL DATA FOR KOTZEBUE 7d TABLE 3-7 MONTHLY AVERAGE WIND SPEED (MPH) FOR LOCATIONS IN NORTHERN, NORTHWESTERN, AND WESTERN ALASKA 8 TABLE 3-8 MEAN DIURNAL WIND SPEED (MPH) —- OLD KEA MET SITE (110 FT) 10 TABLE 3-9 WIND SPEED FREQUENCY DISTRIBUTION - OLD KEA MET TOWER SITE 11 TABLE 3-10 JOINT FREQUENCY OF WIND SPEED AND WIND DIRECTION - OLD KEA MET TOWER SITE (110 FT) i TABLE 3-11 WIND ATLAS ANALYSIS FOR KOTZEBUE, ALASKA 12 TABLE 4-1 WIND TURBINE CHARACTERISTICS 13 TABLE 4-2 POWER CURVE - BERGEY EXCEL-S 14 TABLE 4-3 POWER CURVE - AOC 15/50 15 TABLE 4-4 POWER CURVE - NORTHWIND 100 7 15 TABLE 4-5 POWER CURVE - VESTAS V27 17 TABLE 44 POWER CURVE - MICON M700 17 TABLE 4-7 DIURNAL MEAN WIND SPEED - WIND PLANT SITE - 83 FEET 20 TABLE 4-8 ANNUAL THEORETICAL ENERGY OUTPUT - AOC 15/50 22 TABLE 4-9 DIURNAL MEAN ENERGY - SINGLE AOC 15/50 TURBINE 23 TABLE 4-10 | AVERAGE MONTHLY ENERGY PRODUCTION 24 TABLE 4-11 THEORETICAL NET ENERGY OUTPUT - 660KW WIND PLANT a TABLE 4-12 THEORETICAL ENERGY OUTPUT (KWH) FOR VARIOUS TURBINES AND ANNUAL AVERAGE WIND SPEEDS 25 ili TABLE 4-13 TABLE 4-14 TABLE 4-15 FIGURE 3-1 FIGURE 4-2 FIGURE 4-2 FIGURE 4-3 FIGURE 4-4 FIGURE 4-5 ESTIMATED ANNUAL AVERAGE WIND SPEED FOR 33 FEET, 85 FEET, 25 AND 100 FEET ABOVE GROUND LEVEL THEORETICAL ENERGY OUTPUT FOR NORTHWEST ALASKA SITES = 26 TURBINE CAPACITY FACTOR FOR NORTHWEST ALASKA SITES 26 List of Figures WIND ROSE - KOTZEBUE, ALASKA 6 BERGEY EXCEL-S POWER CURVE 14 AOC 15/50 POWER CURVE 15 NORTHWIND 100 POWER CURVE 16 VESTAS V-27 POWER CURVE 17° MICON M700 POWER CURVE 18 iv 1.0 Introduction The Kotzebue Electric Association (KEA) of Kotzebue, Alaska installed a wind farm of three AOC 15/50 wind turbines in mid-1998. The utility has completed the construction of seven more AOC 15/50 wind turbines and plans to commission them in 1999. The ten turbine wind farm will have an installed capacity of 660kW. Prior to installing the wind farm, KEA conducted an on-site meteorological measurement program from August 1995 to June 1998 using NRG Systems equipment. This report uses these data as well as the data from the airport in Kotzebue to describe the wind resource at the wind farm site, estimate the long term annual average wind speed at the hub height of the AOC 15/50 turbine, and present monthly and annual theoretical energy output estimates for the wind farm. 2.0 Background There are a number of villages throughout Alaska comprised of a few hundred to a few thousand residents, The villages are characterized by the common fact they do not have interconnecting electric power lines and surface roads. Each village has their own individual diesel system for generating electricity. As a result, fuel oil must be barged into the villages during the open water summer season and stored for use during the winter season. This results in a disproportionally higher fuel cost for an electric generating facility that also has higher operating costs due to design requirements and the village’s isolated location. With decreasing Alaskan oil production and potential changes in the village energy subsidies program, the cost of electricity is expected to rise in the future, even if world oil prices remain the same. It is easy to see that wind energy is a desirable compliment to the existing diesel generating systems where there is a reasonable wind resource and local support for renewable technology. KEA has taken an aggressive approach to the introduction and integration of wind energy technology to their power system. The installation of a 660kW wind facility, consisting of ten AOC 15/50 wind turbines and the plan to increase the capacity of the wind plant in the future, shows a strong commitment to renewable energy by KEA. In addition, the utility plans to become a renewable technology center for the region and support other village utility systems as they struggle to balance the need to increase capacity, maintain system reliability, and lower overall energy costs. Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 3.0 Wind Resource 3.1 General Wind Information 3.1.1 Battelle - Pacific Northwest Laboratory As part of the U.S. Department of Energy’s Federal Wind Energy Program, Battelle - Pacific Northwest Laboratory developed a wind power classification scheme. This scheme is presented in Table 3-1. Areas were classified on the basis of wind power, ranging from 1 (lowest) to 7 (highest). Each class represents a range of wind power density (Watts/m?) or a range of equivalent mean wind speeds (mph) at specified heights above ground level. In this study, the wind power classification is applied to a grid block. Each grid block, with dimensions of 1/4 degree latitude by 1/3 degree longitude, covers a large area. At 45 Degrees North latitude, this grid block has dimensions of 28 kilometers by 27 kilometers, or nearly 750 square kilometers. The extrapolation of wind speed between 10 meter and higher levels is based on the 1/7th power law. Typically, grid blocks designated as Class 4 or greater are considered to be suitable for most wind turbine applications. Class 3 areas are suitable for wind energy development using taller wind turbine towers. Class 2 areas are considered marginal for wind power development and Class 1 areas are unsuitable. Local conditions can cause the wind resource to vary widely within one grid block. The classification scheme is not designed to handle variability on a local scale, merely to identify the potential wind resource for the best sites within the cell boundaries. Table 3-1 Wind Power Class And Annual Average Wind Speed (mph) 10M (33Ft) 30M (100Ft) 40M (131Ft) 50M (164 Ft) Wind Speed Wind Specd Wind Speed Wind Speed mph) (mph) (mph) (mph) Wind Power Class s1l4 $11.9 $12.5 < 13.4 $13.9 $143 <14.5 s14.9 $15.7 $15.6 < 16.3 < 16.8 $168 $17.4 $17.9 S183 < 19.0 < 19.7 $24.6 $ 25.5 $26.6 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast The analysis for the State of Alaska is included in the Wind Energy Resource Atlas of the United States (DOE/CH10094-4, March 1987). The wind resource for the area along the north and west coastlines ranges from Class 5 to Class 7. For example, Barrow is considered Class 5; Kotzebue is Class 5; and Wales is Class 7. Interior locations fall into Class 2 to Class 3. 3.1.2 National Climatic Data Center The National Climatic Data Center (NCDC) in Asheville, NC is the repository for meteorological data collected in the United States. NCDC prepares and maintains both summarized as well as original data in either paper copies or digital files. Sources of wind speed and wind direction data include the Local Climatological Data (LCD) Summaries for First Order National Weather Service Stations and summaries prepared for civilian and military sites. A comprehensive source of climatological data is the International Station Meteorological Climate Summary (Vol 4.0, September 1996). The data files include historical climate information for a large number of stations in Alaska and the neighboring countries (Canada and Russia). These data are presented in the Appendix. 3.2 Kotzebue Kotzebue is located at the tip of the Baldwin Peninsula in Kotzebue Sound, between the Seward Peninsula (south) and Point Hope. Climatological data for the town is available principally from observations taken at the airport. The most continuous period of record begins in 1943. The wind sensors have been at the western end of the airport since 1982 and the indicated measurement height is 33 feet. An Automatic System Observing Station (ASOS) was commissioned at Kotzebue on 12/1/97. 3.2.1 Annual Average Wind Speed The annual average wind speed for Kotzebue, obtained from the Local Climatological : Data Summaries (LCD) published by the National Climatic Data Center (NCDC), is 12.9 mph. The Weibull shape and scale parameters characterizing these data are 1.71 and 14.46 mph, respectively. 3.2.2 Monthly and Diurnal Wind Speed The monthly average wind speeds are presented in Table 3-2. The highest monthly average wind speed typically occurs in November while the lowest occurs in May. The diurnal average wind speeds are presented in Table 3-3. Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 3-2 Monthly Average Wind Speeds (mph) For Kotzebue Airport Table 3-3 Mean Diurnal Wind Speed For Kotzebue Airport 3.2.3 Extreme Wind Speeds The maximum 2-minute wind speed and the peak gust data are available in the LCD. The period of record is different for these two variables; the period of record for the maximum 2-minute wind speed covers 45 years while the period of record for the peak gust only covers 18 years. Due to the differences in the period of record, there are Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast corresponding differences in the magnitude of the peak winds. For example, the maximum 2-minute speed of 93 mph was recorded in February 1951 but peak gust information was not available until after 1979. These data are presented in Table 3-4 Table 34 Peak Wind Speed Data (mph) for Kotzebue Airport Max2-min Peak Gust Max2-min Peak Gust 64 72 51 45 93 63 49 53 55 66 52 54 62 31 47 60 40 49 {oy 88 63 42 46 66 68 3.2.4 Wind Speed Frequency Distribution The wind speed frequency distribution for the airport is presented in Table 3-5. This table presents the number of hours in each year in each wind speed bin. For example, in a one year period, on average, there are 626 hours when the wind speed is between 9.5 mph and 10.4 mph. Note in the table that there are no hours in certain wind speed categories, for example, 3.0, 11.0, 19.0, and 26.0 mph. As hourly observations were made by manual methods through review ofa strip chart, there was most likely a bias on the part of the observer, as they preferred to select a wind speed value above or below these categories. This bias, especially for the 19 mph category, has been observed at other National Weather Service Sites. 3.2.4 Wind Rose The wind rose, or the joint frequency of wind speed and wind direction, for Kotzebue is presented in Figure 3-1. The principal wind directions are east-northeast, east, and east- southeast and west and west-northwest. 3.2.5 Climatic Data The climatic data for Kotzebue, extracted from the LCD for the site, are presented in Table 3-5. The data indicates the climate is quite dry with normal annual rainfall of 8.98 inches but exhibits a wide range of temperatures characterized by extreme winter cold. Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska und the Northwest Coast Figure 3-1 Wind Rose Kotzebue, Alaska Kotzebue, Alaska January 1, 86 through December 31, 90 . \ . \ \ i ‘ \ ny | Ve \ \ | A \ \ \ . \ \ | C , \ \ \ \ \ \ \ \ \ 1 \ ' i t Snes E i ! ' - ' 1 4 ae 1 ! ' 1 i 1 ! i . i 1 1 Yor 1 ! ‘ 1 , ’ / / f , , / , : / | Level: 10 m Winds: Direction Sd Wind Economics & Technology, Inc $1010 1510 20 25 to 30 511 Framerti Ct. Martinez, CA94583 10 to 15 20 to 25 =o | Bea Number of Records Used: 43629 Tel 925-229-0648, Fax.025-229-0685 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 3-5 Wind Speed Frequency Distribution Kotzebue Airport 0 9 9 9 0 0 0 28 0 2 0 xd 0 31 0 32 0 3 0 4 0 3s 0 % 0 37 0 38 0 3% 0 0 0 Table 3-6 Climatological Data for Kotzebue, Alaska Extreme Normal Normal Extreme Normal Maximum = Minimum = Normal = Maximum Month |Maximum Maximum Minimum Minimum Precipitation Monthly Monthly Snowfall Monthly Precipitation Precipitation Snowfall Deg F Deg F Deg F Deg F (inches) (inches) (inches) (inches) (inches) 56 -75 49 0.43 1.77 0.00 62 23.9 «0 23 12.0 52 0.32 1.24 0.00 5.0 19.1 3 87 8.0 48 0.35 1.23 0.00 5.6 21.9 20.3 23 44 0.37 1.41 0.00 5.7 18.1 74 37.9 24.5 18 0.33 1.05 0.00 2.0 12.0 49.7 37.8 20 0.52 1.43 0.01 0.2 24 8s 59.1 485 x 1.46 3.51 0.01 0.1 $7.0 47.3 2 1.78 5.18 0.08 03 46.9 37.0 13 1.58 431 0.03 14 7.4 51 27.6 18.2 “19 0.73 3.20 0.04 7A 18.0 13.1 2.4 6 0.59 2.22 0.09 66 24.3 052 1.40 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 3.3 Northwest Coast Monthly and annual average wind speeds for selected locations in northern, northwestern, and western Alaska are presented in Table 3-7. These are airports and the data was extracted from the NCDC International Station Meteorological Climate Summary (Vol 4.0). These data are typically collected on masts that are between 5 and 10 meters in height. The highest annual average wind speeds are at Tin City AFS (near Wales), St. Paul Island (Pribilof Chain, Bering Sea), and in Kotzebue. The lowest wind speed (5.7 mps) is found at Nome. Table 3-7 Monthly Average Wind Speeds (mph) for Location in Northern, Northwestern, and Western Alaska Monthly Average Wind Speed (mph) Location Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 139 128 139 139 150 139 139 150 150 161 15.0 161 17.2 150 128 114 11.4 128 139 139 139 15.0 Cape Lisburne 11.4 114 103 103 103 81 92 103 128 139 139 Cape Newenham 139 128 128 92 92 81 81 103 11.4 128 13.9 Cape Romanzoff 183 183 172 150 128 103 92 103 128 150 16.1 Nome 161 15.0 139 139 128 11.4 s 128 92 92 150 St. Paul Island 206 21.9 183 17.2 15.0 15.0 12.8 16.1 17.2 183 Tin City 208 219 242 208 17.2 15.0 139 150 161 19.7 3.4 On-Site Meteorological Monitoring Program An on-site meteorological data collection program was conducted by KEA at the wind plant site. A 110 foot guyed tower was installed in August 1995 and operated until June 1998. The tower was then moved to a new location in August 1998. For the old site, wind speed and wind direction data were collected using NRG Maximum #40 wind speed sensors and NRG 200P wind direction sensors. The booms were mounted at 65 feet and 110 feet above ground level and data was collected using an NRG 9200 datalogger. The sensors were sampled once per second and hourly averages were created. The analyses presented in this section are based on the old site data. For the new site, wind speed sensors (Maximum #40’s) are installed at 32 feet, 65 feet, 83 feet, and 99 feet. Wind direction sensors (NRG 200P’s) are installed at 75 feet and 100 feet above ground level. Data acquisition and averaging are via a NRG Systems 9300SA. Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 3.4.1 Annual Average Wind Speed The annual average wind speed at 110 fect above ground level is measured as 14.1 mph. This is based on the actual average wind speed of 13.3 mph, adjusted by the recommended Maximum #40 slope and offset of 1.711 and +0.78. 3.4.2 Diurnal and Monthly Wind Speed The diurnal and monthly wind speed at 110 feet above ground level is presented in Table 3-8. The highest monthly wind speeds occur in October, November, January, and March. The lowest monthly average wind speeds occur in July and August. 3.4.3 Wind Speed Frequency Distribution The wind speed frequency distribution for the 110 foot level of the old met tower is presented in Table 3-9. 3.4.4 Joint Frequency — Wind Speed and Wind Direction The joint frequency of wind speed and wind direction for the 110 foot level of the old met tower is presented in Table 3-10 As can be seen in the table, the majority of the power producing winds, defined as hourly average wind speed greater than 10 mph, are from the east-southeast and west-northwest. 3.5 Wind Atlas Analysis and Application Program The Wind Atlas Analysis and Application Program (WAsP) is a computer program developed by Riso National Laboratory in Denmark. WAspP is a general regional wind climatology program which uses, as input, raw wind data, topography, surface roughness, and surface features, to develop an estimate for the wind resource at a site. WAsP is not a substitute for on-site meteorological measurements but can be used to prepare an initial indication of the likely wind resource. This wind resource is expressed in Weibull shape and scale parameters. WASP is used to create a wind atlas for Kotzebue. The raw wind data (hourly wind speed and wind direction) for the airport in Kotzebue is combined with the actual surface roughness of the surrounding area. The result is the wind atlas presented in Table 3-11. The roughness classes correspond to the general surface features surrounding a site. Roughness Class 0 comprises open ocean, lakes, and other water surfaces; Class 1 comprises open, generally flat areas with a few farm buildings and trees, Class 2 comprises gently rolling terrain with numerous wind breaks and farm buildings; and Class 3 comprises urban districts, forests, and more densely populated areas. The first two lines of the table are the wind direction sectors (every 30 degree sector) and the 9 Wind Resource and Theoretical Energy’ Estimate for Kotzebue, Alaska and the Northwest Coast percentage of time the wind is from that sector. The succeeding lines are the Weibull scale and shape factors for various heights above ground level (10m, 25m, 50m, 100m, and 200m) for each wind direction sector and then averaged for all sectors. Table 3-8 Mean Diurnal Wind Speed (mph) Old KEA Met Tower Site 110 Foot Level 10 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast _ Table 3-9 Wind Speed Frequency Distribution Old KEA Met Tower Site 110 Foot Level ° BN Sg gRN a 1 2 3 4 5 6 7 8 9 SBBNRGFRRB Bess hat aan a ww wt oe oO aORON=60 = gq Se eal oe oon a SBBBLSBRRBB ©EOBZSBRRRABBADB BESAGHLBSR ooooo0oocoo0o0ocjcooooso ooaooooo0oo0o0ao0aoaoaoaaoanaow wo © 8 Table 3-10 Joint Frequency of Wind Speed and Wind Direction Old KEA Met Tower Site — 110 Foot Level Wind Wind Speed Bin (mph) Direction 0-10 11-15 16-20 21-25 26-30 31-35 36-60 Oto 15.0 17 rr] 02 04 04 0.0 0.0 15.0to 46.0 | 43 23. 04 0.1 0.0 0.0 0.0 45.0to 75.0 | 3.6 23. 09 03 0.0 0.0 0.0 75.0to 105.0 | 3.7 37 35 28 13 09 14 105.0 fo 135.0] 21 25 22 1.4 06 0.4 02 138.0 to 165.0| 1.6 12 08 os 03 02 0.0 165.0t0195.0| 22 11 10 OS Of 00 00 195.0 to 226.0 | 2.7 10 06 0.4 0.1 0.0 o.1 225.0to2850| 40 14 O05 O02 O41 00 00 256.0t0286.0} 54 37 25 12 03 00 00 286.0t0315.0| 43 34 25 18 O06 03 00 315.0t0345.0| 26 14 12 04 08 00 00 345.0to360.1] 14 11 O08 03 Of 00 00 TOTAL 6 262 17.2 10.0 3.6 18 1.4 11 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 3-11 Wind Atlas Analysis for Kotzebue, Alaska 0 30 60 90 120 150 180 210 240 63 7S 13.4 14.8 13.2 44 42 4 5.7 Roughness Class 0 59 54 2.76 2.89 64 59 2.85 2.98 69 63 2.92 3.06 75 68 2.83 2.97 83 7.6 2.68 2.81 Roughness Class 1 40 37 2.32 2.44 48 44 2.51 2.63 56 51 2.82 2.96 66 60 3.00 3.15 82 75 2.67 3.01 Roughness Class 2 35 3.2 64 6.6 2.31 2.37 1.66 2.10 2.13 1.98 2.01 4.77 158 2.16 2.330 1.81 Sector % 270 300 330 9.7 12.1 10 5.8 1.88 6.4 1.94 68 148 7.4 1.93 82 1.83 10.7 2.34 11.7 2.37 12.4 2.43 13.3 2.40 14.4 2.33 10.9 2.36 11.9 2.40 12.6 2.45 13.5 2.42 14.6 2.36 9.0 2.28 9.9 2.34 10.5 2.40 11.4 2.35 12.4 2.25 79 2.41 87 2.49 93 2.55 10.1 2.47 112 2.34 5.4 1.69 $.9 1.95 63 2.00 68 1.94 75 1.83 65 2.57 mM 2.65 76 2.72 83 2.64 9.1 2.49 25 50 10 40 7s 2.10 88 2.18 99 2.32 W113 2.49 13.2 2.41 7.6 2.14 89 2.23 10.1 2.36 115 2.54 13.4 2.46 62 5.4 3.7 48 74 6.4 44 5.6 84 2.30 98 7.4 $1 139 61 8s 8.2 76 10 25 43 39 43 78 8.0 66 5.7 49 3.9 48 5.8 46 2.48 2.54 1.78 2.18 221 2.09 2.15 1.90 1.69 2.31 250 1.94 so 5.1 4.6 SA 9.0 91 77 67 5.7 46 5.6 68 5.4 2.74 2.81 1.96 2.30 2.32 2.28 2.38 2.10 1.87 2.56 2.76 = 2.15) 100 60 55 64 10.4 10.5 9.0 8.0 68 5.5 66 81 6.4 3.01 3.08 2.15 2.51 2.54 2.50 2.61 2.30 2.05 2.81 304 = 2.36) 200 74 68 7S 12.4 123 10.9 9.9 84 6.7 82 10.0 7.9) 2.88 2.95 2.06 2.44 2.46 2.41 2.50 2.21 1.96 2.69 291 2.26 Roughness Class 3 10 28 25 28 5.0 5.1 4.2 3.6 3.1 25 3.0 37 2.9 2.34 2.48 1.71 2.13 2.17 1.98 2.03 1.77 1.71 2.15 2.36 61.83 25 36 33 37 65 67 5.5 48 41 3.4 40 48 3.8) 2.48 2.6 1.81 2.20 223 2.08 2.45 1.87 180 228 250 1.94 so 44 40 44 78 79 66 5.8 49 44 48 5.8 46) 2.69 2.86 197 230 233 2.24 233 2.03 196 248 2.72 2.11 100 52 48 63 91 93 79 69 5.9 49 5.7 7.0 5.6) 3.07 3.260 «62.24 = 2.49 2.52 2.53 266 2.31 223° 283 3.10 2.40) 200 64 59 6S 108 10.9 95 85 72 6.0 7.0 86 68 296 3.14 2.16 2.50 2.53 2.45 256 223 215 273 299 2.31 12 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 4.0 Theoretical Energy Projection 4.1 Introduction The annual theoretical energy production for a wind turbine is calculated by integrating the power curve with the wind speed frequency distribution. As monitoring programs typically span a limited amount of time, it is essential to adjust the measured data record to the potential long term wind speed at the site. The theoretical energy output is considered the gross energy output. The net energy output, that is, the energy delivered directly to the grid, is determined by deducting certain losses associated with turbine availability, the electrical distribution system, blade contamination effects, array or off-axis wind direction effects, and the turbine control system. 4.2 Wind Turbine Power Curves Five wind turbines are included in this analysis of theoretical energy output. These include the Bergey EXCEL-S, the AOC 15/50, the Northwind 100, the Vestas V-27, and the Micon M700. These turbines range in size from 10kW to 225 kW. The characteristics are presented in Table 4-1. The Bergey EXCEL-S is commonly used in remote off-grid environments. The AOC 15/50 is installed at the Kotzebue Electric Association’s wind plant in Kotzebue, Alaska. The Northwind 100 design is undergoing testing via a single prototype unit at a mountain top site in Vermont. The Vestas V27 is a 225kW turbine with a proven design with numerous units installed in Tehachapi Pass, California. One unit is installed as part of a wind diesel system on St. Paul Island in the Bering Sea. The Micon M700 is a 225kW turbine, also considered a proven design. One application of the Micon M700 is as part of a wind-diesel system for a US Navy installation on San Clement Island off the Southern California coast. Table 4-1 Wind Turbine Characteristics | Manufacturer Description Rating Rotor Tower Height Comments (kW) _|_ Diameter (m) (m) Bergey Three bladed, fixed pitch; 10 7 24 Widely used free yaw; upwind small turbine. Three bladed; fixed pitch; 65 15 24 Installed at free yaw; downwind Kotzebue Two bladed; fixed pitch; 100 ‘ 30 active yaw; upwind Vestas Three bladed; variable pitch, 30 Proven Design; active yaw; upwind Installed at St. Paul Island Three bladed; fixed pitch; . Proven Design; active yaw; upwind Installed on San Clemente Island 13 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 4.2.1 Bergey Bergey makes small wind turbine systems of 10kW or less. These are simple fixed pitch, upwind, free-yaw turbines on a 24 meter truss tower. The manufacturer supplied power curve is presented in Table 4-2 and plotted in Figure 4-1. Table 4-2 Power Curve - Bergey EXCEL-S, 10kW (Grid) Power (kW) 8.17 6.54 4.90 2.21 2.45 2.45 2.45 Figure 4-1 Bergey EXCEL-S 10 kW 10.00 8.00 6.00 4.00 2.00 0.00 - Power (kW) Wind Speed (mps) 4.2.2 AOC 15/50 The Atlantic Orient Company (AOC) Model 15/50 is a horizontal axis, three bladed, downwind, free yaw wind turbine with a maximum power rating of 66kW. The rotor diameter is 15 meters. The turbine is mounted on a truss tower with a standard height of 24 meters. The turbine achieves a power output of 50kW af 11.0 mps (24.5 mph) and a rated output of 64.9 kW at 16.5 mps. The manufacturer supplied power curve is presented in Table 4-3 and plotted in Figure 4-2. 14 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 4-3 Power Curve - AOC15/50 Power (kW) 62.0 63.8 64.4 64.9 64.3 Figure 4-2 AOC 15/50 Power (kW) oB SSS h 0 5 10 15 20 25 Wind Speed (mps) 4.2.3 Northwind 100 The Northwind 100 is a horizontal axis, three bladed, upwind, yaw-controlled, fixed pitch wind turbine. The blade diameter is 16.6 meters with a swept area of 239.7 m’. The turbine is mounted on a truss-type tower with a hub height of 24 meters. The manufacturer supplied power curve is presented in Table 4-4 and plotted in Figure 4-3. Table 4-4 Power Curve — Northwind 100 Power (kW) 86 86 86 80 80 15 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Figure 4-3 NW100 Power vs. Wind Speed D= 16.66 m, Pitch = 2.20 deg, Speed = 58 RPM 1100 100 s0 &00 . 0 s20 i 20 = Power (kW) 8 Oo x0 -—— Spt pa 20 100 ao 4.2.4 Vestas V27 The Vestas V27 is a horizontal axis, three bladed, upwind, variable pitch, yaw controlled wind turbine. The rotor diameter is 27 meters with a swept area of 573m’. The turbine is mounted on a 31 meter truss tower or tubular tower. The power curve for the turbine is presented in Table 4-5 and Figure 4-4. A sister turbine is the V-29 with the same rating (225kW) and a larger swept area (661m’). 16 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 4-5 Power Curve — Vestas V-27 Figure 4-4 Vestas V-27 NON ou oO oO a ot ouw oO Power (kW) an oO oO 10 15 Wind Speed (mps) 4.2.5 Micon 225 The Micon M700 is a horizontal axis, three bladed, upwind, yaw-controlled, fixed pitch wind turbine with a rating of 225kW. The rotor diameter is 29.6 meters with a swept area of 688 m’. The turbine is typically mounted on a 30 meter tubular tower. The power curve for the Micon 700 is presented in Table 4-6 and Figure 4-5. Table 4-6 Power Curve — Micon M700 (225kW) 229.0 23 230.0 24 210.0 25 210.0 0 17 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Figure 4-5 Micon M700 (225kW) 250 200 150 100 Power (kW) a oO | 0 7 : r 7 0 5 10 15 20 25 Wind Speed (mps) 4.3 Theoretical Energy Estimate for the Kotzebue Wind Plant 4.3.1 Kotzebue Wind Energy Facility The Kotzebue Wind Energy Facility is located on a leased parcel of land south-southeast of the town and southeast of the USAF Radar Facility. Three AOC 15/50 wind turbines are currently installed and operating on the parcel and seven more AOC 15/50 wind turbines will be operational in the spring of 1999. The facility will have an overall capacity of 660kW. 4.3.2 Wind Speed - Airport Versus Wind Facility The hourly data from the airport is compared to the hourly data measured both at the 83 foot level and the 99 foot level of the meteorological tower at the wind generation facility. A linear regression analysis is performed to determine the relationship between the two parameters, the hourly wind speed at the airport and the hourly average wind speeds at the tower. The wind speed at the airport is not a true hourly average. The wind speed is a 2-minute average and is measured using the ASOS system. The wind speed obtained at the meteorological tower site is a true hourly average computed from the average of 3600 one-second values. The period of record is August 1998 to November 1998. 18 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast The results of the analysis are as follows: 83 Foot Wind Speed = (0.89 X Airport Wind Speed) + 2.17 (R = 0.92) 99 Foot Wind Speed = (0.88 X Airport wind Speed) + 2.87 (R = 0.92) The correlation coefficient of 0.92 indicates a good statistical relationship between the two parameters. 4.3.3 Long Term Wind Speed An estimate of the long term wind speed at the 83 foot level of the meteorological tower is prepared using the statistical relationship presented above. The hourly wind speed from the ajrport over the 5-year period from January 1, 1993 to December 31, 1997 is used to create the hourly average wind speeds for the same period. A mean diurnal summary of these wind speeds is presented in Table 4-7. The annual average wind speed at 83 feet above ground level is estimated as 13.5 mph (5.6mps). The highest monthly average wind - - speed occurs in November while the lowest occurs in May. 4.3.2 Methodology The wind speed frequency distribution is integrated with the manufacturer’s power curve of the turbine to determine the annual theoretical energy output. The wind speed frequency distribution is based on the meteorological data collected at the airport in Kotzebue adjusted to the hub height of the turbine using the linear relationship presented above. The power curve of the AOC 15/50 is provided by the manufacturer and is based on standard sea level conditions with an air density of 1.225kg/m*. The actual annual air density of the site, based on the annual average temperature and annual average pressure data from the airport, is 1.31 kg/m’. The actual energy produced by the wind electric energy facility must be adjusted by various loss factors including wake losses associated with the interaction between turbines, wind turbine availability, electrical line losses, control system losses, and blade contamination losses. Wind turbines extract energy from the wind and, therefore, reduce the amount of energy available to downwind turbines or, in the case of off-axis wind directions, from adjacent turbines. This condition is referred to as wake losses. Given the predominant east-west wind direction at the site, the minimum number of hours from other directions, and the actual crosswind and downwind spacing of the turbine strings, the annual energy losses associated with wake and array effects are 2%. 19 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 4-7 Diurnal Mean Wind Speed (mph) KEA Wind Plant Site 83 Foot Level OOn Onn WN Other losses typical in a wind power facility must also be deducted from the gross energy production estimates for the Project. These losses are described and quantified below. Turbine Availability. No turbine can operate 100% of the time. A reasonable wind turbine availability is 98% (2% energy loss). Transformer/Line Losses. These result from the electrical inefficiencies of voltage transformation and conducting of electricity along power lines. The estimated loss in production is 0.5% for the 10 wind turbines. Control System. The AOC 15/50 is a downwind, free yaw turbine. An annual energy loss of 1% is associated with the inefficiencies associated with yaw activity. Blade Contamination, Decreases in turbine performance are associated with blade icing and dirt. This is not expected to be a significant source of annual energy losses and a value of 1% has been assigned for this parameter. 20 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast The total loss factor for these “other losses” are obtained by multiplying the “efficiencies” (100% - percent loss) due to the individual loss factors. The energy losses expected are calculated below: Loss Factor Est. Annual Loss (%) Equivalent Efficiency Wind Turbine Availability 2 0.98 Transformer/Line Losses 0.5 0.995 Control System 1 0.99 Blade Contamination 1 0.99 Wake/Off- Axis 2 0.98 TOTAL 0.935 The estimated “efficiency” of the Project based on the above is 93.5%, which translates to an annual energy loss of 6.5%. 4.3.4 Annual Theoretical Energy Estimate The manufacturer’s power curve is used to prepare theoretical energy estimates for the Kotzebue Wind Generating Facility. A total of 10 AOC 15/50 wind turbines will be installed at the facility. The manufacturer’s power curve is based on a standard air density of 1.225kg/m’. The annual energy projection, based on the standard conditions, can be adjusted to actual site conditions using the following relationship: Ec =Ea X pa/ pot where Ec is the adjusted energy, E, is the average annual energy output, pa is the air density for the site, and py; is the standard air density. The annual air density for Kotzebue is calculated using the climatic data from the airport. The average annual sea- level pressure is 1005.42mb and the annual average temperature is 21.5 Degrees F (-6.1 Deg C). The annual air density is determined using the following formula: px = 1.225 kg/m? X (1005.42mb/1013.3mb) X (288.15 Deg C/(-6.1+273.15 Deg C)) Based on this formula, the annual air density for Kotzebue is 1.311 kg/m? and the adjustment factor is 1.311/1.225, or 1.07. The annual theoretical gross energy output for a single AOC 15/50 turbine in Kotzebue is 131,435 kWh. This is based on the manufacturer’s adjusted power curve and the calculated wind speed frequency distribution for the site. The calculation is presented in Table 4-8. 21 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 4.3.5 Mean Diumal Energy Output (kWh) The mean diurnal energy output, based on a 5-year period of record and for a single AOC 15/50 wind turbine, is presented in Table 4-9. The highest monthly average occurs in November, followed by January and February. The lowest average values occur in May and April. Table 4-9 Diurnal Mean Energy (Gross kWh) Single Turbine Hour Jan Feb Mar Oct Nov Dec Mean 17 «(17 13 16 19 16] 13 18 18 13 7 15 20 15 | 14 17 19 12 15 19 16 | 13 18 18 11. 16 18 «617 | 13 17 18 12 16 18 8616 | 13 16 18 12 16 17 16 | 13 17 17) 12 16 «618 «615 | 13 17.—‘18 11 16 618 «616 | 13 16 «618 1 16 6190 «616 | 13 17 18 12 17 15 | 14 17 19 12 17 16 | 14 18 18 12 17 16 | 14 17 19 12 19 17 | 15 16 2 12 19 16 | 15 17 2 13 17 16 | 15 16 #19 8613 18 15 | 15 16 #19 8613 17 14] 14 16 «18 13 15 15 | 14 18 #19 =612 15 14 | 14 16 19 12 13 14 | 14 16 18 11 13 15 | 14 16 18 812 15 14] 14 16 17——«12 14 14 | 13 1S 18 «13 14 15 | 13 17 1812 16 1S | 14 oOn oaunn wn = =~ = - oO ©OOONDNAAHN _ Nn ooooo on nnoo a 3 atts ph hah @Onounn = Ss as ZSlsSsso _ o RBRVB 23 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast OEE Table 4-8 Annual Theoretical Energy Output (kWh) AOC 15/50 Kotzebue, Alaska Wind Percent AoC Wind Percent AOC ’ Speed Occurrence 18/50 PC Energy Speed Occurrence 15/50 PC Energy (mph) (kW) (kWh) (mph) (kW) (kWh) 0 0.0 0.2 645 1,209 0.0 O1 649 2.2 01 64.9 0.0 01 6.1 08 01 61 42 0.0 64.8 5.3 0.0 64.0 7S 0.0 6.7 7.4 0.0 6.7 78 0.0 64 87 0.0 62.7 5.9 0.0 62.1 64 0.0 62.1 06 0.0 62.0 3.6 0.0 61.8 5.6 0.0 ° 3.6 0.0 3.5 0.0 4.4 0.0 29 0.0 3.0 0.0 3.2 0.0 1.6 0.0 2.4 0.0 1.2 0.0 1.6 0.0 13 0.0 09 0.0 412 0.0 06 0.0 04 i 0.4 . Total kWh = 0.2 3 Density Adj = 0.4 5. Gross kWh = 0.2 02 oOMn Onawn = eooceeC OOOO eo Boo000000000 SBSRSSEGRESERBPSRERBBLS a = 52 $3 S4 sS sé S7 S38 so € 2 coooooooooocooa0acaoocoocaoao0o0oa0ocea oooo0oo0o0o0o0c 0 0C0 000 BLBR 22 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 4.3.6 Average Monthly Energy Production The percentage of the annual energy production for an AOC 15/50 turbine in Kotzebue is presented in Table 4-10. This is based on the average monthly energy output from Table 4-7 multiplied by the number of hours in that month. On average, 11.5% of the annual energy production will occur in November while 5.3% of the annual energy will occur in May. Based on this distribution and an annual gross theoretical energy output of 120,400kWh for the AOC 15/50 turbine, the average monthly energy production is also presented in Table 4. For example, an AOC 15/50 turbine should produce 15,115kWh (gross — no losses) in November and 6,966kWh in May. Table 4-10 Average Monthly Energy (Gross) Production KEA Wind Plant Percentage | Energy Percentage 13,801 5.9% 13,275 9.2% 9,59 8.3% 7,492 9.9% 6,966 11.5% 9,200 9.2% 100% 4.3.8 Theoretical Net Energy Output - 660KW Wind Plant The monthly and annual theoretical net energy output for a wind plant consisting of 10 AOC 15/50 turbines are presented in Table 4-11. Using the highest output of the turbine as the rating for the facility, this implies the capacity of the facility as 660kW. Assuming a gross to net ratio of 0.935, that is, the total energy losses (availability, electrical line, off axis wind directions/array, control, blade contamination) amount to 6.5%, then the total net annual output for the facility is 1,228,917kWh. The monthly distribution of energy production is based on the percentages in Table 4-10. December and January will have, on average, the highest energy output, while July and August will have the lowest average output. Table 4-11 Theoretical Net Energy Output KEA 660kW Wind Plant Average Per Project Project Net | . Average Per Project _ . Project Net Turbine - Gross kWh kWh : | Turbine ~~ Gross kWh kWh = 13,801 138,010 129,036 7TS 77,50 72,506 13,275 132,750 124,121 12,092 120.920 113,060 9,595 6,50 89,711 10,909 109,080 102,000 7,492 74,920 70,048 13,012 130,120 121,663 6,966 69,660 6133 15,115 151,150 141,325 9,200 92,000 86,024 12,223 122,230 114,289 131,435 1,314,350 1,228,917 24 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast 4.4 Northwest Alaska 4.4.1 General Theoretical Energy Estimates Theoretical energy estimates are created for various annual average wind speeds from 5.0 mps to 8.0 mps for the five different wind turbines. These estimates are presented in Table 4-12. The wind speed frequency distribution used to create these estimates is based on a Rayleigh Distribution, that is, a Weibull Distribution with a shape factor of 2.0. Table 4-12 Theoretical Energy Output (Gross kWh) For Various Turbines and Annual Average Wind Speeds Annual Wind Speed (mph & mps)_ 12.3 13.4 145 | 45.1 16.8 Turbine x 55 6.0 65 | 7.0 15 Bergey 13,400 16,500 19,000 21,700 24,000 AOC 93,700 119,400 141,200 166,800 191,400 Northwind | . 102,300 134,700 163,300 198,500 233,600 Vestas : 375,400 468,700 547,200 640,300 729,900 Micon 379,500 470,100 546,200 636,000 722,600 4.4.2 Theoretical Energy Estimates — Northwest Alaska The monthly and annual wind speeds for stations in Northwestern Alaska and the Pribilof Islands were previously presented in Table 3-7. The annual average wind speeds ranged from 11.4 mph at Cape Lisbume to 18.3 mph at Tin City AFS near Wales. The wind speed power law with an exponent of 0.14 (1/7 power law) is used to estimate the annual average wind speed at 85 feet and 100 feet above ground level. Table 4-13 Estimated Annual Average Wind Speeds (mph) For 33 feet, 85 feet, and 100 feet AGL __- 33 Feet 85 Feet 100 Feet 25 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast The gross theoretical energy output for the Bergey 10kW, AOC 15/50, Northwind 100, Vestas V-27, and Micon M700 for each of the eight sites are presented in Table 4-14. Table 4-14 Theoretical Energy Output (kWh) for Northwest Alaska Sites Turbine Site Bergey | AOC 15/50 | Northwind Vestas Micon Barrow 22,000 169,200 201,000 682,700 677,500 Bethel 22,000 169,200 201,000 682,700 677,500 Cape Lisburne 15,300 109,500 122,000 453,000 456,300 Cape Newenham 15,300 109,500 122,000 453,000 456,300 Cape Romanzoff 22,000 169,200 201,000 682,700 677.500 Nome 19,300 144,400 167,700 580,100 578,400 St. Paul Island 28,700 240,200 322,700 947,300 933,000 Tin City 29,400 259,100 341,900 1,020,500 1,003,600 The annual turbine capacity factors, based on the gross theoretical annual energy values, are presented in Table 4-15. Capacity factor is determined as follows: : Capacity Factor = Theoretical Energy Output / (8760 Hours X Rated Capacity) For the Vestas V-27, given a theoretical energy output of 682,700kWh, the capacity factor is 35%, or 682,700 divided by (225 X 8760). Table 4-15 Capacity Factor for Northwest Alaska Sites Turbine Site | Bergey | AOC 15/50 | Northwind Micon Barrow 25% 23% 34% Bethel 25% 23% 34% Cape Lisburne 18% 14% 23% Cape Newenham 18% 14% 23% Cape Romanzoff 25% 23% 34% Nome 22% 19% 29% St. Paul Island 33% 37% 47% Tin City 34% 39% 51% 26 APPENDIX B FIXED CHARGE RATE CALCULATION w w w Fixed Charge Rate assumes, 100% debt financing, 30-year depreciation & debt term Capital Cost* $591,000 Year Assumption 1 2 3 4 5 6 Z 8 9 10 11 12 13 14 15 Deprec (yrs) 30 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 Cost of Debt 5.0% $29,550 $29,105 $28,638 $28,148 $27,633 $27,092 $26,525 $25,929 $25,303 $24,646 $23,956 $23,231 $22,471 $21,672 $20,833 Cost of Equi 10.0% $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Annual Carry Cost $49,250 $48,805 $48,338 $47,848 $47,333 $46,792 $46,225 $45,629 $45,003 $44,346 $43,656 $42,931 $42,171 $41,372 $40,533 as % of capital 8.3% 8.3% 8.2% 8.1% 8.0% 7.9% 78% 7.7% 76% 7.5% 7.4% 7.3% 7.1% 70% 69% Year 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Deprec (yrs) $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 $19,700 Cost of Debt $19,953 $19,028 $18,057 $17,038 $15,967 $14,843 $13,663 $12,424 $11,123 $9,757 $8,322 $6,816 $5,235 $3,574 $1,831 Cost of Equi $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Annual Carry Cost $39,653 $38,728 $37,757 $36,738 $35,667 $34,543 $33,363 $32,124 $30,823 $29,457 $28,022 $26,516 $24,935 $23,274 $21,531 as % of capital 6.7% 6.6% 6.4% 6.2% 6.0% 5.8% 5.6% 5.4% 5.2% 5.0% 47% 45% 4.2% 3.9% 3.6% Fixed Charge Rate 6.5% * The Phase 1 capital costs are used for illustration purposes. However, any level of capital costs using the same assumptions will yield the same fixed charge rate. APPENDIX C CASH FLOWS Phase 1 Project KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.198 MW Debt 0% O&M (1st yr) Turbine Rating 66 kW Equity 100% Parts $300 per WTiyear Turbine Count 3 Term (years) Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per WT/year Equipment Cost $1,094 perkW kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,891 perkW $/gallon $0.940 Fixed Land Fee $400 per WThyear Total $2,985 perkW $/kWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/Inflation 3.0% Subsidy ($,000) REP! (1998) $0.017 per kWh Total Project Costs $591 ($,000) DieselO&Msaved _$0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 #+%.2005 2006 2007 2008 #2009 2010 Revenue Net Energy Production (MWh) 356.2 356.2 356.2 356.2 356.2 356.2 356.2 3562 3562 356.2 356.2 356.2 Benefit from wind Diesel saved (gallons) 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 Diesel saved (dollars) $23,145 $23,840 $24,555 $25,292 $26,050 $26,832 $27,637 $28,466 $29,320 $30,200 $31,106 $32,039 Other Savings Diesel O&M saved $3,110 $3,172 $3,236 $3,300 $3,366 $3,434 $3,502 $3,572 $3,644 $3,717 $3,791 $3,867 REPI Credit (activated in 7/97) $6,055 $6,412 $6,412 $6,412 $6,768 $6,768 $7,124 $7,124 $0 $0 $0 $0 Total Benefit from Wind $32,311 $33,423 $34,202 $35,003 $36,184 $37,033 $38,263 $39,162 $32,964 $33,916 $34,897 $35,906 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.0925 $0.0952 $0.0980 $0.1008 Expenses O&M $5,976 $5,995 $6,014 $6,034 $6,054 $6,074 $6,094 $6,116 $6,137 $6,159 $6,181 $6,204 Insurance 312 318 325 331 338 345 351 359 366 373 380 388 Land 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 Operating Expenses 7,830 7,855 7,881 7,907 7,933 7,960 7,988 8016 8045 8074 8104 8,134 Net Benefit After Expenses 24,480 25,568 26,321 27,097 28,251 29,073 30,275 31,146 24,919 25.842 26,793 27,771_ ANNUAL CASH FLOW Less: Equity Investment $591,031 Net Benefit After Expenses 24,480 25,568 26,321 27,097 28,251 29,073 30,275 31,146 24,919 25,842 26,793 27,771 Less: Debt Payment 0 0 0 0 0 , 0 0 0 0 0 0 0 Annual Cash Flow ($591,031) (566,550) 25,568 26,321 27,097 28,251 29,073 30,275 31,146 24,919 25,842 26,793 27,771 NPV of Cash Flow 1999$ ($100,416) IRR 3.4% 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 356.2 3562 356.2 3562 3562 3562 356.2 3562 356.2 3562 356.2 356.2 3562 356.2 356.2 356.2 356.2 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 23,906 $33,000 $33,990 $35,010 $36,060 $37,142 $38,256 $39,404 $40,586 $41,803 $43,057 $44,349 $45,680 $47,050 $48,462 $49,915 $51,413 $52,955 $3,944 $4,023 $4,103 $4,186 $4,269 $4355 $4,442 $4531 $4,621 $4714 $4808 $4,904 $5,002 $5,102 $5,204 $5,308 $5,414 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $36,944 $38,013 $39,113 $40,245 $41,411 $42,611 $43,845 $45,116 $46,424 $47,771 $49,157 $50,584 $52,052 $53,564 $55,120 $56,721 $58,370 $0.1037 $0.1067 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $26,020 $6,251 $6,276 $6,300 $6,325 $6,351 $6,377 $6,404 $6,431 $6,459 $6,488 $6,517 $6,546 $6,576 $6,607 $6638 $6,670 396 404 412 420 428 437 446 455 464 473 483 492 502 512 522 533 543 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 1,542 27,958 8,197 8229 8262 8296 8330 8365 8401 8437 8474 8512 8551 8590 8630 8671 8713 8,756 8987 29816 30884 31,983 33,115 34280 35.480 36,716 37,987 39,297 40645 42,033 43462 44933 46448 48008 49614 ——O—O Oe ee ee ee 8,987 29,816 30,884 31,983 33,115 34,280 35,480 36,716 37,987 39,297 40,645 42,033 43,462 44933 46,448 48,008 49,614 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 8,987 29,816 30,884 31,983 33,115 34,280 35,480 36,716 37,987 39,297 40,645 42,033 43,462 44,933 46,448 48,008 49,614 APPENDIX C CASH FLOWS Baseline Assumes potential reductions; 7 wind turbines; 100% debt wv w KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) w Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW _—_ kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkKW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perKW = $/KWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 ($,000) Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 = $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $81,425 $83,780 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 2011 2012 831.1 831.1 55,780 55,780 $77,000 $79,310 $9,203 $9,387 $0 $0 $86,203 $88,697 $0.1037 $0.1067 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449. 18,511 18,574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After nses 27,567 59,774 _61,534 63,346 66,042 67,962 70,769 72,804 — 74,899 77,887 62,654 64940 67,294 69,717 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 27,567 59,774 61,534 63,346 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64,940 67,294 69,717 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow ‘5,609 6, 4,81 3, (309) 1,611 4,419 6,454 8,549 11,537 697 1,411 943 3,366 NPV of Cash Flow 1999$ $121,950 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 = ':- 2006 2007 2008 2009 2010 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 65,234 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 26,030 74,780 77,424 80,146 82,949 85.834 88.805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 26,030 74,780 77,424 80,146 82,949 85,834 88,805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (40,321) 8,429 11,073 13,795 16,598 19,484 22,454 25,513 28,662__—31,904_ — 35,243 38,679 42,218 ~— 45,861 49,612 53,474 —-26,823 APPENDIX C CASH FLOWS Baseline with Capital Cost Variation a. 20% higher capital costs b. 10% lower capital costs KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,313 perkW —_ kWhigalion diesel 149 Inflation 2.0% per year Balance of Station $1,336 perkW = $/gallon $0.940 Fixed Land Fee $400 per WTiyr Total $2,649 perkKW = $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,224 ($,000) _ Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001: 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diese! saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $81,425 $83,780 $86,203 $88,697 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3598 3,598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18,511 18,574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After Expenses 27,567 (59,774 «61,534 63,346 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64,940 67,294 69,717 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 27,567 59,774 61,534 63,346 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64940 67,294 69,717 Debt Payment (39,810) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) Annual Cash Flow 12,244) 19,84 18,08' 16,275) (13,579) 11,659) 8,852 6,81 (4,722) (1,734) (16,967) (14,681) (12,327) (9,904) NPV of Cash Flow 1999$ ($77,188) Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 = ' 2006 2007 2008 2009 2010 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1126 1148 1,171 1195 1,219 1,243 634 3,598 3598 3,598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 1,799 65,234 19,126 19,202 19,279 19,357 19,437 19519 19,602 19,687 19,773 19,862 19,952 ~ 20,043 20,137 20,233 20,330 12,117 26,030 74,780 _(77,424 ~—«80,146~—«82,949_—85,834_ —8B8.805 _—91,864 _—95,013 —98,255 101,593 105,030 108569 112,212 115,963 119,825 _ 59,999 26,030 74,780 77,424 80,146 82,949 85,834 88,805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (39,810) (53,591) (4,841) (2,197) 525 3,328 ~—s 6,213 9,184 —*12,243~—« 15,392 18,634__—21,972 _—25,409_~—«28,948 ~—«32,591 «36,342 —«40,204 ~—-20,188 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $985 perkW —_kKWhigallon diesel 149 Inflation 2.0% per year Balance of Station $1,002 perkW = $/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $1,987 perkW = $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $918 ($000) _ Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 = $7,855 $8,012 $8,172 $8335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $81,425 $83,780 $86,203 $88,697 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18511 18574 18,639 18,704 18,771 18,839 18909 18,980 Net Benefit After Expenses 27,567 59,774 61,534 63,346 _—66,042 67,962 70,769 72,804 —74,899 77,887 62,654 64,940 67,294 69,717 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 27,567 59,774 61,534 63,346 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64940 67,294 69,717 Debt Payment (29,858) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) Annual Cash Flow 2,291 58 1,818 3,630 6,326 8,246 11,054 13,089 _—‘15,184 18172 2,939 5,225 7,578 10,001 NPV of Cash Flow 1999$ $221,519 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 ' 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REP! rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 65,234 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 26,030 74780 77,424 80,146 82,949 85834 88805 91,864 95,013 98255 101,593 105,030 108569 112,212 115,963 119,825 59,999 26,030 74,780 77,424 80,146 82,949 85,834 88,805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (29,858) 15,064 17,708 20,430 _—*23;,233—=—«26,119 29,090 _—«32,148 ~—«35,20738,540_—«41,878 45,315 48,853 52,496 56,247 _—60,109 30,141 APPENDIX C CASH FLOWS Baseline with Financing Assumptions a. 20-year debt financing; 20-year project life b. 6% interest on debt; 6% discount rate KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 20 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 per kW kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 per kW $kWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year . Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Revenue : Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 = 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $81,425 $83,780 $86,203 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18511 18574 18,639 18,704 18,771 18,839 18,909 Net Benefit After Expenses 27,567 59,774 «61,534 63,346 ~— 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64,940 67,294 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 27,567 59,774 61,534 63,346 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64,940 67,294 Debt Payment (40,923) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) Annual Cash Flow (13,356) (22,071) __ (20,311) __(18,500) (15,804) (13,884) (11,076) __(9,041) __(6,946) (3,958) (19,191) (16,905) (14,552) NPV of Cash Flow 1999$ ($173,714) Renewable Energy Production Incentive ‘ Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2012 2013 2014 2015 2016 2017 2018 2019 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $79,310 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $48,771 $9,387 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $5,391 $0 $0 $0 $0 $0 $0 $0 $0 $88,697 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $54,162 $0.1067 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $14,477 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $9,000 906 924 942 961 980 1,000 1,020 520 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 18,980 65,234 19,126 19,202 19,279 19,357 19,437 11,320 69,717 __- 26,030 74,780 77,424 80,146 = 82,949 85,834 42,842 69,717 26,030 74,780 77,424 80,146 82949 85,834 42,842 (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (40,923) (12,129) (55,816) (7,066) _—_—(4,422)__—(1,699) 1,103 3,989 1,920 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 6.0% 15 year Overhaul $5,000 per WT Discount Rate 6.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW = kWh gallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkKW = $/kWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $81,425 $83,780 $86,203 $88,697 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3598 3598 3598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18511 18574 18,639 18,704 18,771 18,839 18909 18,980 Net Benefit After Expenses 27,567 59,774 61,534 63,346 «66,042 67,962 70,769 72,804 ~—74,899 77,887 62,654 64940 67,294 _69,717 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 27,567 59,774 61,534 63,346 66,042 67,962 70,769 72,804 74,899 77,887 62,654 64940 67,294 69,717 Debt Payment (37,050) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) Annual Cash Flow (9,483) (14,326) (12,566) _(10,755)__(8,058) (6,138) (3,331) (1,296) 799 NPV of Cash Flow 1999$ ($9,159) 3,787_(11,446) (9,160) (6,806) (4,383) Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2005 | 0.020 2006 0.020 2007 0.020 2008 0.021 2009 0.000 2010 0.000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $o $o $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 65,234 19126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 26,030 74,780 —77,424 80,146 ~— 82,949 85,834 — 88,805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 26,030 74,780 77,424 80,146 82,949 85,834 88805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (37,050) 48,070) 680 3,324 6,046 8849 11,734 14,705 17,764 20913 24,155 27,493 30,930 34,469 = 38,112 41,863 45,725 22,949 APPENDIX C CASH FLOWS Baseline with Energy Estimates a. 20% lower than expected b. 10% higher than expected KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 16.4% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkKW ~ kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkKW = $/kWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0,009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 332.4 664.9 664.9 664.9 664.9 664.9 664.9 664.9 664.9 6649 664.9 6649 664.9 664.9 Benefit from wind Diesé! saved (gallons) 22,312 44,624 44,624 44624 44,624 44,624 44624 44624 44,624 44,624 44624 44624 44624 44,624 Diesel saved (dollars) $21,602 $44,501 $45,836 $47,211 $48,628 $50,086 $51,589 $53,137 $54,731 $56,373 $58,064 $59,806 $61,600 $63,448 Other Savings Diesel O&M saved $2,903 $5,921 $6,040 $6,160 $6,284 $6,409 $6,538 $6,668 $6,802 $6,938 $7,076 $7,218 $7,362 $7,510 REPI Credit (1st 10 years) $5,652 $11,968 $11,968 $11,968 $12,633 $12,633 $13,298 $13,298 $13,298 $13,963 $0 $0 $0 $0 Total Benefit from Wind $30,157 $62,390 $63,844 $65,340 $67,544 $69,129 $71,424 $73,103 $74,830 $77,273 $65,140 $67,024 $68,962 $70,957 Total Benefit per kWh . $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $6,804 $11,550 $11,593 $11,637 $11,681 $11,727 $11,773 $11,820 $11,868 $11,918 $11,968 $12,019 $12,071 $12,125 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,719 3,438 3,438 3,438 3,438 3,438 3,438 3,438 3,438 3,438 893,438 9=— 3,438 3,438 3,438 Operating Expenses 8,873 15,702 15,759 15,818 15,877 15,938 16,000 16,063 16,127 16,193 16,259 16,328 16,397 16,468 Net Benefit After nses 21,284 46,688 48,085 49,522 51,667 53,191 55,425 57,040 _58,703 61,081 48,881 50696 52565 54,489 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 21,284 46,688 48,085 49,522 51,667 53,191 55,425 57,040 58,703 61,081 48,881 50,696 52565 54,489 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 11,892 19,663) 18,266) (16,829) (14,684) 13,160) 10,926) 9,314 64 5,270) (17,470) (15,655) (13,786) (11,862) NPV of Cash Flow 1999$ ($125,396) - Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 ' 2006 2007 2008 2009 2010 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REP! rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2025 2026 2027 2028 2029 664.9 664.9 664.9 664.9 332.4 44,624 44624 44624 44624 22,312 $93,175 $95,971 $98,850 $101,815 $52,435 $9,714 $9,909 $10,107 $10,309 $5,258 $0 $0 $0 $0 $0 $102,890 $105,879 $108,957 $112,124 $57,692 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $12,922 $12,992 $13,064 $13,137 $8,508 1,171 1,195 1,219 1,243 634 3,438 3,438 3,438 3,438 1,719 17,532 17,626 17,721 17,819 10,861 85,358 88,254 91,235 94,306 46,831 85,358 88,254 91,235 94,306 46,831 (66,351) (66,351) (66,351) (66,351) (33,175) 2013. 2014. «2015S «2016.-=S ss 2017.-—S «2018 «= 2019S «2020.2 «2021 «Ss «2022, 2023S 2024 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 44,624 44624 44624 44624 44624 44624 44,624 44,624 44,624 «44,624 «44,624 «44,624 $65,351 $67,312 $69,331 $71,411 $73,553 $75,760 $78,033 $80,374 $82,785 $85,269 $87,827 $90,461 $7,660 $7,813 $7,969 $8,129 $8,291 $8,457 $8,626 © $8,799. $8,975 $9,154 $9,337 $9,524 . $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $73,011 $75,125 $77,300 $79,540 $81,845 $84,217 $86,659 $89,173 $91,760 $94,423 $97,164 $99,985 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $58,361 $12,234 $12,201 $12,349 $12,407 $12,467 $12,528 $12,591 $12,655 $12,719 $12,786 $12,853 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 3,438 3438 3438 3438 3,438 3438 3,438 3,438 403,438 «= 3,438) 3,438) 3,438 62,723 16615 16690 16,767 16845 16,925 17,007 17,090 17,175 17,262 17,350 17,440 10,289 58,510 _60,610 _62,773 64,999 67,292 _—69,652_—72,082_—74,585 77,161 _—«79,814_—82,545. 10,289 58,510 60,610 62,773 64,999 67,292 69,652 72,082 74585 77,161 79,814 82,545 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) __ (66,062) (7,841) (5,740) (3,578) __(1,352) 941 3,301 ~—=S«5,732_—«8,234_—«'10,810_—«*13,463_—«16,195 _—*19,007__—21,903 24,885 _—-27,955__—13,656 wv w KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 22.6% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkKW ___kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perKW = $/kKWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.009 per KWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 457.1 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 9142 9142 9142 9142 914.2 Benefit from wind Diese! saved (gallons) 30,679 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 Diese! saved (dollars) $29,703 $61,189 $63,025 $64,915 $66,863 $68,869 $70,935 $73,063 $75,255 $77,512 $79,838 $82,233 $84,700 $87,241 Other Savings Diesel O&M saved $3,991 $8,142 $8,305 $8,471 $8,640 $8,813 $8,989 $9,169 $9,352 $9,539 $9,730 $9,925 $10,123. $10,326 REPI Credit (1st 10 years) $7,771 $16,456 $16,456 $16,456 $17,370 $17,370 $18,285 $18,285 $18,285 $19,199 $0 $0 $0 $0 Total Benefit from Wind $41,465 $85,787 $87,785 $89,842 $92,873 $95,052 $98,209 $100,516 $102,892 $106,251 $89,568 $92,158 $94,823 $97,567 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $8,568 $15,078 $15,121 $15,165 $15,209 $15,255 $15,301 $15,348 $15,396 $15,446 $15,496 $15,547 $15,599 $15,653 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,839 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 Operating Expenses 10,757 19,470 19,527 19,585 19,644 19,705 19,767 19,830 19,894 19,960 20,027 20,095 20,165 20,236 Net Benefit After Expenses 30,709 66,317 68,259 70,257 _—_—73,229 75,347 78,442 80,686 — 82,997 86,291 69,541 72,062 74,658 77,331 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 30,709 66,317 68,259 70,257 73,229 75,347 78,442 80,686 82,997 86,291 69,541 72,062 74,658 77,331 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 2, (34) 1,908 3,906 6,878 8,996 12,091 14,336: 16,647 19,940 3,190 5,712 8308 10,980 NPV of Cash Flow 1999$ $245,624 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 =' 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) ‘ 2013 2014 2015 2016 2017 2018- 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 914.2 457.1 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 61,358 30,679 $89,858 $92,554 $95,330 $98,190 $101,136 $104,170 $107,295 $110,514 $113,829 $117,244 $120,762 $124,385 $128,116 $131,960 $135,918 $139,996 $72,098 $10,532 $10,743 $10,958 $11,177 $11,400 $11,628 $11,861 $12,098 $12,340 $12,587 $12,839 $13,095 $13,357 $13,625 $13,897 $14,175 $7,229 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $o $0 $0 $o $0 $0 $0 $100,390 $103,297 $106,288 $109,367 $112,536 $115,799 $119,156 $122,612 $126,170 $129,831 $133,600 $137,480 $141,473 $145,584 $149,815 $154,171 $79,327 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $61,889 $15,762 $15,819 $15,877 $15,935 $15,995 $16,056 $16,119 $16,183 $16,247 $16,314 $16,381 $16,450 $16,520 $16,592 $16,665 $10,272 - 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 3,678 1,839 66,490 20,382 20,457 20,534 20,613 20,693 20,774 20,858 20,942 21,029 21,117 21,207 21,299 21,393 21,489 21,586 12,745 33,900 82,915 _ 85,831 88,833 91,924 95,106 98,382 101,755 105,227 108802 112,483 116,273 120,174 124191 128327 132,585 66,582 33,900 82,915 85,831 88,833 91,924 95,106 98,382 101,755 105,227 108,802 112,483 116,273 120,174 124,191 128,327 132,585 66,582 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (32,451) 16,564 19,480 22,482, 25,573 28,755 32,031 35,404 38,876 42,452, 46,132 49,922 53,823 57,840 61,976 66,234 33,407 APPENDIX C CASH FLOWS Baseline with Turbine Maintenance a. 20% higher expenses b. 10% lower expenses w wv KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $360 per WT/year Turbine Count 7 Term (years) 30 Labor $0.017 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $6,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW —_kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkKW _—$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkW = $/kKWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $81,425 $83,780 $86,203 $88,697 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $9,576 $16,682 $16,734 $16,786 $16,840 $16,894 $16,950 $17,007 $17,065 $17,124 $17,184 $17,245 $17,308 $17,372 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 Operating Expenses 11,725 20,994 21,060 21,127 = 21,195 21,265 21,336 21,409 21,483 21,558 21,635 21,714 21,794 21,875 Net Benefit After Expenses 25,971 56,994 58745 60,548 63,235 65,146 67,944 69,970 72,055 75,033 59,790 62,066 64,409 66,822 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 25,971 56,994 58,745 60,548 63,235 65,146 67,944 69,970 72,055 75,033 59,790 62,066 64,409 66,822 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 205) 9, 606) (5,803 (3,116) 1,205) 1,594 3,619 5,704 8.683 (6,561) (4,285) (1,942) 471 NPV of Cash Flow 1999$ $73,912 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 =' 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 eee 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $o $0 $0 $o $0 $0 $0 $o $0 $o $0 $0 $0 $o $0 $o $0 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $72,855 $17,504 $17,571 $17,641 $17,711 $17,783 $17,857 $17,931 $18,008 $18,086 $18,165 $18,246 $18,329 $18,413 $18,499 $18,587 $11,621 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 77,377 =. 22,044 =. 22,130 22,219 22,309 22,401 22,495 22,590 22,688 22,787 22,889 22,993 23,098 23,206 23,316 23,428 14,054 13,887 71,862 74,495 77,206 79,997 __—82,871 85,829 88,875 92,012, 95,241 98,566 101,989 105514 109143 112,880 116,727 58,062 13,887 71,862 74,495 77,206 79,997 82,871 85,829 88,875 92,012 95,241 98,566 101,989 105,514 109,143 112,880 116,727 58,062 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (52,464) 5,512 8145 10,855 13,646 16,520 19,478 22,525 25,661 28,890 32,215 35,638 39,163 42,792 46,529 50,376 24.887 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt : 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $270 per WT/year Turbine Count 7 Term (years) 30 Labor $0.013 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $4,500 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perKW _ kWhigallon diesel 149 Inflation 2.0% per year Balance of Station $1,114 perkKW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkKW = $/KWh $0.063 Variable Land Fee $0.001 per KWh . Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $37,696 $77,988 $79,805 $81,675 $84,430 $86,411 $89,281 $91,379 $93,538 $96,591 $61,425 $83,780 $86,203 $88,697 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $7,182 $12,512 $12,550 $12,590 $12,630 $12,671 $12,712 $12,755 $12,798 $12,843 $12,888 $12,934 $12,981 $13,029 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3598 3598 3,598 3,598 Operating Expenses 9,331 16,824 16,877 16,930 16,985 17,041 17,099 17,157 17,216 17,277 17,339 17,402 17,467 17,532 Net Benefit After Expenses 28,365 61,164 62,928 64,744 67,445 69,369 72,182 74,222 76,321 79,314 64,086 66,377 68,736 71,165 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 28,365 61,164 62,928 64,744 67,445 69,369 72,182 74,222 76,321 79,314 64,086 66,377 68,736 71,165 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (4,811 (5,186, 422) 4 1,094 3,019 5,831 7,871 9,971 12,963 (2,265) 272,385 4,814 NPV of Cash Flow 1999$ $145,969 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 = =' 2006 2007 2008 2009 2010 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $54,641 $13,128 $13,179 $13,230 $13,283 $13,337 $13,392 $13,449 $13,506 $13,564 $13,624 $13,685 $13,747 $13,810 $13,875 $13,940 $8,715 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 59,163 17,668 17,737 17,809 17,881 17,955 18,030 18,107 18186 18,266 18,348 18,431 18,516 18,603 18,691 18,781 11,148 32,101 76,238 78,888 81,616 ~— 84,425 87,316 = 90,293, 93,358 = 96,514 =— 99,762 103,107 106,551 110,096 113,746 117505 121,374 60,967 32,101 76,238 78,888 81,616 84,425 87,316 90,293 93,358 96,514 99,762 103,107 106,551 110,096 113,746 117,505 121,374 60,967 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) _ (34,250) 9,888 -12,537__—15,265 18,074 _—-20,966~—23,943 ~—27,007__—30,163__—«33,412—«36,756 —«40,200—«43,745 «47,396 «51,154 55,023 _27,792 APPENDIX C CASH FLOWS Baseline with Wind Resource a. 6.5 m/s wind resource b. 7.0 m/s wind resource c. 7.5 m/s wind resource o = KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) Kt) Labor $0.014 per KWh Capacity Factor 22.1% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW —_ KWhgallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW = $/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 per kW $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000, Diesel O&M saved $0.009 per KWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 446.4 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 Benefit from wind Diesel saved (gallons) 29,962 59,924 59,924 59,924 59,924 59,924. 59,924 59,924 59,924 59,924 59,924 59,924 59,924 59,924 Diesel saved (dollars) $29,009 $59,759 $61,552 $63,398 $65,300 $67,259 $69,277 $71,355 $73,496 $75,701 $77,972 $80,311 $82,721 $85,202 Other Savings Diesel O&M saved $3,898 $7,951 $8,111 $8,273 $8,438 $8,607 $8,779 $8,955 $9,134 $9,316 $9,503 $9,693 $9,887 $10,084 REPI Credit (1st 10 years) $7,589 $16,072 $16,072 $16,072 $16,965 $16,965 $17,857 $17,857 $17,857 $18,750 $0 $0 $0 $0 Total Benefit from Wind $40,496 $83,782 $85,734 $87,743 $90,703 $92,831 $95,914 $98,168 $100,487 $103,768 $87,475 $90,004 $92,607 $95,287 Total Benefit per kWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $8,417 $14,776 $14,819 $14,862 $14,907 $14,952 $14,999 $15,046 $15,094 $15,143 $15,194 $15,245 $15,297 $15,350 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,829 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 Operating Expenses 10,595 19,147 19,204 19,262 19,322 19,382 19,444 19,507 19,572 19,637 19,704 19,772 19,842 19,913 Net Benefit After Expenses 29,901 64,635 66,530 _— 68,481 71,381 73,449 76,470 _ 78,660 80,916 84,131 67,771__70,232__72,765 75,374 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 29,901 64635 66530 68,481 71,381 73,449 76,470 78,660 80,916 84,131 67,771 70,232 72,765 75,374 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (3,274) (1,715) 179 2,130 5,031 7,098 10,119 12,310 14,565 17,780 1,420 3,881 6,414 9,023 NPV of Cash Flow 1999$ $213,834 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 * 2006 2007 2008 2009 2010 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 eee 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 892.9 446.4 59,924 59,924 59924 59,924 59,924 59,924 59,924 59924 59,924 59,924 59,924 59,924 59,924 59,924 59,924 59,924 29,962 $87,758 $90,391 $93,103 $95,896 $98,773 $101,736 $104,788 $107,932 $111,170 $114,505 $117,940 $121,478 $125,122 $128,876 $132,742 $136,724 $70,413 $10,286 $10,492 $10,702 $10,916 $11,134 $11,357 $11,584 $11,816 $12,052 $12,293 $12,539 $12,789 $13,045 $13,306 $13,572 $13,844 $7,060 $0 $0 $0 $0 $0 $0 $0 $o $0 $0- $0 $o $o $0 $0 $0 $0 $98,044 $100,883 $103,804 $106,812 $109,907 $113,093 $116,372 $119,747 $123,221 $126,797 $130,478 $134,267 $138,168 $142,182 $146,315 $150,568 $77,473 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $61,586 $15,460 $15,517 $15,574 $15,633 $15,693 $15,754 $15,817 $15,880 $15,945 $16,011 $16,079 $16,148 $16,218 $16,290 $16,363 $10,121 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 3,657 1,829 66,167 20,059 20,135 20,212 20,290 20,370 20,452 20,535 20,620 20,706 20,794 20,885 20,976 21,070 21,166 21,263 12,583 31,877 80,824 — 83,670 ~— 86,600 ~— 89,617 — 92,723, 95,920 99,212 102,602 106,091 109,684 113,383 117,191 121,112 125,149 129,305 __ 64,890 _—— eee =< 31,877 80,824 «83,670 «86,600 «89,617 92,723 95,920 99,212 102,602 106,091 109,684 113,383 117,191 121,112 125,149 129,305 64,890 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351). (66,351) (33,175) (34,474) 14,473 17,319 20,249 23,266 —-26,372_—«-29,569 32,862 -36,251_—39,740 —-43,333_—47,032__—50,840 54,761 58,798 62,954 31,715 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 26.1% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkKW __ kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW — $/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkW = $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.009 per kWh Wind Power Project - KEA ; FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 527.4 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 Benefit from wind Diesel saved (gallons) 35,394 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 Diesel saved (dollars) $34,269 $70,594 $72,711 $74,893 $77,140 $79,454 $81,837 $84,292 $86,821 $89,426 $92,109 $94,872 $97,718 $100,650 Other Savings Diesel O&M saved $4,604 $9,393 $9,581 $9,773 $9,968 $10,167 $10,371 $10,578 $10,790 $11,006 $11,226 $11,450 $11,679 $11,913 REPI Credit (1st 10 years) $8,965 $18,985 $18,985 $18,985 $20,040 $20,040 $21,095 $21,095 $21,095 $22,150 $0 $0 $0 $0 Total Benefit from Wind $47,839 $98,972 $101,278 $103,651 $107,148 $109,661 $113,303 $115,966 $118,706 $122,581 $103,334 $106,322 $109,397 $112,562 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $9,562 $17,066 $17,109 $17,153 $17,197 $17,243 $17,289 $17,336 $17,385 $17,434 $17,484 $17,535 $17,588 $17,641 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,906 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 Operating Expenses 11,818 21,593 21,650 21,708 21,768 21,828 21,890 21,953 22,017 22,083 22,150 22,218 22,288 22,359 Net Benefit After Expenses 36,020 77,379 79,628 «81,943 85,380 87,833 91,413, 94.013 96,689 100,498 81,184 84104 87,109 90,203 ANNUAL CASH FLOW Less: Equity Investment $0 : Net Benefit After Expenses 36,020 77,379 79,628 81,943 85,380 87,833 91,413 94013 96,689 100,498 81,184 84104 87,109 90,203 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 2,845 11,029 13,277___: 15,592: 19,029 21,482 25,062 27,662_—-30,338 34147 14,834 17,753 20,759 ~—«23,853 NPV of Cash Flow 1999$ $454,716 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 =| «2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014. «2015S 2016-=S 2017'S «2018 = 2019S 2020.-Ss «2021 «Ss «2022, 2023'S «2024 «= «2028-=S «2026 «= 2027'S «2028 += 2029 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 11,0547 1,054.7 11,0547 10547 1,0547 1,0547 1,0547 10547 527.4 70,789 70,789 70,789 70,789 70,789 + 70,789 + 70,789 70,789 + 70,789 70,789 70,789 70,789 70,789 + 70,789 70,789 70,789 35,394 $103,669 $106,779 $109,983 $113,282 $116,680 $120,181 $123,786 $127,500 $131,325 $135,265 $139,323 $143,502 $147,807 $152,242 $156,809 $161,513 $83,179 $12,151 $12,394 $12,642 $12,895 $13,153 $13,416 $13,684 $13,958 $14,237 $14,522 $14,812 $15,108 $15,410 $15,719 $16,033 $16,354 $8,340 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $115,820 $119,173 $122,624 $126,177 $129,833 $133,597 $137,470 $141,458 $145,562 $149,786 $154,135 $158,611 $163,218 $167,960 $172,842 $177,867 $91,520 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $63,877 $17,751 $17,807 $17,865 $17,924 $17,984 $16,045 $16,107 $16,171 $16,236 $18,302 $18,370 $18,438 $18,509 $18,580 $18,654 $11,266 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1148 1,171 1,195 1,219 1,243 634 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 3813 1,906 68,613 22,505 22,581 22,657 22,736 22,816 22,897 22,981 23,066 23,152 23,240 23,331 23,422 23516 23612 23,709 13,806 47,207 96,668 100,044 103,519 107,097 110,781 114,573 118,477 122,496 126,634 130,894 135,280 139,795 144,444 149,230 154,158 77,713 47,207 96,668 100,044 103,519 107,097 110,781 114,573 118,477 122,496 126,634 130,894 135,280 139,795 144,444 149,230 154,158 77,713 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (19,144) 30,317 33,693 37,168 40,746 44,430 «48,222 52,126 56,145 60,283 64,543 68,929 73,445_—78,093_ 82,879 87,807 __—-44,538 we wv KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count r Term (years) w» Labor $0.014 per kWh Capacity Factor 26.7% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW kWh gallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,114 perkW = $/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkW = $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue _ Net Energy Production (MWh) 540.7 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 Benefit from wind Diesel saved (gallons) 36,286 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 Diesel saved (dollars) $35,132 $72,371 $74,542 $76,779 $79,082 $81,454 $83,898 $86,415 $89,007 $91,678 $94,428 $97,261 $100,179 $103,184 Other Savings Diesel O&M saved $4,720 $9,630 $9,822 $10,019 $10,219 $10,423 $10,632 $10,845 $11,061 $11,283 $11,508 $11,738 $11,973 $12,213 REPI Credit (1st 10 years) $9,191 $19,464 $19,464 $19,464 $20,545 $20,545 $21,626 $21,626 $21,626 $22,707 $0 $0 $0 $0 Total Benefit from Wind $49,043 $101,464 $103,828 $106,261 $109,846 $112,423 $116,156 $118,886 $121,695 $125,668 $105,936 $108,999 $112,152 $115,397 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $9,750 $17,442 $17,485 $17,529 $17,573 $17,619 $17,665 $17,712 $17,761 $17,810 $17,860 $17,911 $17,963 $18,017 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,919 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 Operating Expenses 12,019 21,994 22,051 22,109 22,169 22,230 = 22,291 22,354 = 22,419 22,484 22,551 22,620 22,689 22,760 Net Benefit After nses 37,024 79,470 81,777 84,151 87,677 90,193 93,865 96,531 99,276 103,183 83,385 86,380 89,463 92,636 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 37,024 79,470 81,777 84,151 87,677 90,193 93,865 96,531 99,276 103,183 83,385 86,380 89,463 92,636 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 3,849 13,119 15,426 17,800 _—21,326 23,842 27,514 _ 30,180 32,925 36,833 17,034 20,029 23,112 26,286 NPV of Cash Flow 1999$ $494,236 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 = «(2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 7,081.3. 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 $40.7 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 = 72,571 72,571. 72,571 36,286 $106,279 $109,468 $112,752 $116,134 $119,618 $123,207 $126,903 $130,710 $134,632 $138,671 $142,831 $147,116 $151,529 $156,075 $160,757 $165,580 $85,274 $12,457 $12,706 $12,960 $13,219 $13,484 $13,754 $14,029 $14,309 $14,595 $14,887 $15,185 $15,489 $15,798 $16,114 $16,437 $16,765 $8,550 $o $0 $0 $0 $0 $0 $0 $0 $0 $o $0 $0 $0 $o $0 $0 $o $118,736 $122,174 $125,712 $129,354 $133,102 $136,961 $140,932 $145,019 $149,227 $153,558 $158,016 $162,604 $167,328 $172,189 $177,194 $182,345 $93,824 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $64,253 $18,126 $18,183 $18,241 $18,299 $18,359 $18,421 $18,483 $18,547 $18,612 $18,678 $18,745 $18,814 $18,884 $18,956 $19,029 $11,454 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 1;919 69,014 22,907 22,982 23,059 23,137 23,217 23,299 23,382 23,467 23,553 23,642 23,732 23,824 23,917 24,013 24,110 14,007 49,722 99,267 102,730 106,295 109965 113,743 117,633 121,638 125,760 130,004 134,374 138,873 143,504 148,272 153,181 158,235 79,817 ne a a 49,722 99,267 102,730 106,295 109,965 113,743 117,633 121,638 125,760 130,004 134374 138,873 143,504 148,272 153,181 158,235 79,817 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (16,629) 32,917 36,379 39,944 43.614 47,393 51,282__—55,287 59,409 63,654 68,023 72,522 77,153 ___— 81,921 86,830 91,884 46,642 APPENDIX C CASH FLOWS Baseline with Other Economic Sensitivities a. Fuel escalation 3% (plus 2% inflation) b. General inflation 4% (plus 1% fuel escalation) c. Diesel O&M savings 50% (versus 75%) d. Without REPI payments e. 7.0 m/s wind resource; 30% higher capital costs ft. 7.5 m/s wind resource; 30% higher capital costs e we KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW —_ kWh gallon diesel 149 Inflation 2.0% per year Balance of Station $1,114 perkKW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkW = $/kKWh $0,063 Variable Land Fee $0.001 per kWh Fuel Escal/inflation 5.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000, Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,527 $57,808 $60,698 $63,733 $66,919 $70,265 $73,779 $77,468 $81,341 $85,408 $89,678 $94,162 $98,871 $103,814 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 = $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $38,220 $80,169 $83,208 $86,394 $90,565 $94,068 $98,573 $102,425 $106,466 $111,534 $98,524 $103,185 $108,073 $113,201 Total Benefit per kWh $0.0920 $0.0965 $0.1001 $0.1039 $0.1090 $0.1132 $0.1186 $0.1232 $0.1281 $0.1342 $0.1185 $0.1242 $0.1300 $0.1362 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18511 18574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After nses 28,091 61,955 64,937 68,064 — 72,177 75,619 80,062 _—83,851_—87,827 92,830 79,753 84346 = 89,165 94,221 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 28,091 61,955 64,937 68,064 72,177 75,619 80,062 83,851 87,827 92,830 79,753 84346 89,165 94,221 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (5,084) (4,395) (1,414) 1,714 5,826 9,268 13,711 17,500_—21,476 26,479 13,402 17,995 22,814 27,870 NPV of Cash Flow 1999$ $522,441 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 = ' «2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 eS 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $109,005 $114,455 $120,178 $126,187 $132,496 $139,121 $146,077 $153,381 $161,050 $169,102 $177,557 $186,435 $195,757 $205,545 $215,822 $226,613 $118,972 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $0 $0 $o $0 $o $0 $0 $0 $0 $o $o $0 $0 $o $o $o $0 $118,579 $124,221 $130,139 $136,347 $142,860 $149,692 $156,860 $164,379 $172,268 $180,545 $189,229 $198,340 $207,900 $217,931 $228,456 $239,499 $125,544 $0.1427 $0.1495 $0.1566 $0.1641 $0.1719 $0.1801 $0.1887 $0.1978 $0.2073 $0.2172 $0.2277 $0.2386 $0.2501 $0.2622 $0.2749 $0.2882 $0.3021 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 65,234 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 53,345 105,095 110,938 117,069 123,503 130,255 137,341 144,777__ 152,581 160,772 169,367__ 178,389 187,857 _ 197,794 208,223 219,169 __ 113,427 53,345 105,095 110,938 117,069 123,503 130,255 137,341 144,777 152,581 160,772 169,367 178,389 187,857 197,794 208,223 219,169 113,427 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (13,005) 38,744 44,587_— 50.718 _—57,152__—63,904_ 70,990 78,426 86,231 94,421 103,016 112,038 121,506 131,443 141,872, 152,818 80,252 ww wv KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) x Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW —_kKWhigallon diesel 14.9 Inflation 4.0% per year Balance of Station $1,114 perkKW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perKW = $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/inflation 5.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,527 $57,808 $60,698 $63,733 $66,919 $70,265 $73,779 $77,468 $81,341 $85,408 $89,678 $94,162 $98,871 $103,814 Other Savings Diesel O&M saved $3,628 $7,547 $7,849 $8,163 $8,489 $8,829 $9,182 $9549 $9,931 $10,328 $10,741 $11,171 $11,618 $12,083 REPI Credit (1st 10 years) $7,480 $14,960 $15,791 $16,622 $17,454 $18,285 $18,285 $19,116 $19,947 $20,778 $0 $0 $0 $0 Total Benefit from Wind $38,636 $80,314 $84,338 $88,518 $92,862 $97,379 $101,245 $106,132 $111,219 $116,514 $100,420 $105,333 $110,488 $115,897 Total Benefit per KWh $0.0930 $0.0966 $0.1015 $0.1065 $0.1117 $0.1172 $0.1218 $0.1277 $0.1338 $0.1402 $0.1208 $0.1267 $0.1329 $0.1394 Expenses O&M $7,980 $13,944 $14,031 $14,122 $14,217 $14,315 $14,417 $14,523 $14,634 $14,749 $14,869 $14,993 $15,122 $15,257 Insurance 350 728 757 787 819 852 886 921 958 996 1,036 1,078 1,121 1,166 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 Operating Expenses 10,129 18,270 18,386 18,507 18,633 18,765 18,901 19,042 19,190 19,343 19,503 19,668 19,841 20,020 Net Benefit After Expenses 28,507 62,045 65,951 70,010 74,229 78614 82,344 87,090 _—92,029 97,171 80,917 85,665 90,648 95,877 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 28,507 62,045 65,951 70,010 74,229 78,614 82,344 87,090 92,029 97,171 80,917 85,665 90,648 95,877 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (4,669) 4,306) 3,659 7,878 12,263 15,994 20,739 25,678 30,820, 14566 19,314 24,297 29.526 NPV of Cash Flow 1999$ $553,491 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 | 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.018 0.018 0.019 0.020 0.021 0.022 0.022 0.023 0.024 0.025 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $109,005 $114,455 $120,178 $126,187 $132,496 $139,121 $146,077 $153,381 $161,050 $169,102 $177,557 $186,435 $195,757 $205,545 $215,822 $226,613 $118,972 $12,566 $13,068 $13,591 $14,135 $14,700 $15,288 $15,900 $16,536 $17,197 $17,885 $18,601 $19,345 $20,118 $20,923 $21,760 $22,630 $11,768 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $121,571 $127,523 $133,769 $140,321 $147,196 $154,409 $161,977 $169,916 $178,247 $186,987 $196,158 $205,780 $215,875 $226,468 $237,582 $249,243 $130,740 $0.1463 $0.1534 $0.1610 $0.1688 $0.1771 $0.1858 $0.1949 $0.2044 $0.2145 $0.2250 $0.2360 $0.2476 $0.2597 $0.2725 $0.2859 $0.2999 $0.3146 $76,005 $15,542 $15,693 $15,851 $16,014 $16,184 $16,361 $16,545 $16,737 $16,936 $17,143 $17,358 $17,582 $17,815 $18,057 $18,309 $12,691 1,212 1,261 1,311 1,364 1,418 1,475 1,534 1,595 1,659 1,725 1,794 1,866 1,941 2,018 2,099 2,183 1,135 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 80,815 20,401 20,602 20,812 21,030 21,257 21,493 21,738 21,994 22,259 22,535 22,822 23,121 23,431 23,754 += 24,090 = 15,625 40,755 107,123 113,167 119,509 126,166 133,152 140,484 148,178 156,253 164,728 173,623 182,957 192,754 203,036 213,828 225,153 115,114 40,755 107,123 113,167 119,509 126,166 133,152 140,484 148,178 156,253 164,728 173,623 182,957 192,754 203,036 213,828 225,153 115,114 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (25,595) 40,772 46,816 53,159 59,815 66,801 74,133 81,827 89,902 98,377: 107,272 116,607 126,404 136,686 147,477 158,803 _ 81,939 KEA Wind Farm Project Configuration Project Size Turbine Rating Turbine Count Capacity Factor Project Costs (US$) Equipment Cost Balance of Station Total Total Project Costs Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year 0.462 MW 66 kW 7 20.5% $1,094 per kW $1,114 per kW $2,208 per KW Financing Option Debt Equity Term (years) Interest rate Discount Rate Revenue kWhigalion diesel $/gallon $/KWh Fuel Escal/Inflation REPI (1998) 100% 0% 30 5.0% 5.0% 149 $0.940 $0.063 3.0% $0.017 per kWh Operating Costs (in 1999$) O&M (1st yr) Parts $300 per WT/year Labor $0.014 per kWh 15 year Overhaul $5,000 per WT Insurance General Liability $100 per turbine Inflation 2.0% per year Fixed Land Fee $400 per WT/yr Variable Land Fee $0.001 per KWh $1,020 _($,000) Diesel O&M saved $0.006 per kWh Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $2,419 $4,934 $5,033 $5,134 = $5,236 $5,341 $5,448 $5,557 $5,668 $5,781 $5,897 $6,015 $6,135 $6,258 REPI Credit (1st 10 years) $7,065 $14,960 $14,960 $14,960 $15,791 $15,791 $16,622 $16,622 $16,622 $17,454 $0 $0 $0 $0 Total Benefit from Wind $36,486 $75,521 $77,288 $79,108 $81,812 $83,740 $86,557 $88,600 $90,704 $93,701 $78,477 $80,772 $83,135 $85,568 Total Benefit per kWh $0.0878 $0.0909 $0.0930 $0.0952 $0.0984 $0.1008 $0.1041 $0.1066 $0.1091 $0.1127 $0.0944 $0.0972 $0.1000 $0.1030 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3598 3,598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18,511 18574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After Expenses 26,357 57,307 59,017 60,779 «63,423 65,291 68,045 70,026 72,065 74,997 59,706 61,933 64,226 66,588 ANNUAL CASH FLOW . Less: Equity Investment $0 Net Benefit After Expenses 26,357 57,307 59,017 60,779 63,423 65,291 68,045 70,026 72,065 74,997 59,706 61,933 64,226 66,588 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (6,818) (9,044) 333) (5,572) 2. 1,060) 1,695 3,675 5,715 8.646 (6,645) (4,418) (2,125) 237 NPV of Cash Flow 1999$ $75,784 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 ~=' «2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $6,383 $6,511 $6,641 $6,774 $6,909 $7,048 $7,188 $7,332 $7,479 $7,628 $7,781 $7,937 $8,095 $8,257 $8,422 $8,591 $4,381 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $88,072 $90,651 $93,305 $96,038 $98,851 $101,748 $104,730 $107,800 $110,960 $114,214 $117,564 $121,014 $124,565 $128,221 $131,985 $135,860 $69,925 $0.1060 $0.1091 $0.1123 $0.1156 $0.1189 $0.1224 $0.1260 $0.1297 $0.1335 $0.1374 $0.1415 $0.1456 $0.1499 $0.1543 $0.1588 $0.1635 $0.1683 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 65,234 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 22,838 71,524 74,103 76,759 79,494 82,311 85,211 88198 91,274 94.441 97,703 101,062 104,521 108,083 111,752 115,530___— 57,808 22,838 71,524 74,103 76,759 79,494 82,311 85,211 88,198 91,274 94,441 97,703 101,062 104,521 108,083 111,752 115,530 57,808 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (43,513) 5,174 7,753 ___ 10,408 13,143 15,960 18,860 21,847 24,923 28,090 31,352 34,711 38,170 41,733 45,401 49,179 24,633 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,094 perkW — kWhygallon diesel 149 Inflation 2.0% per year Balance of Station $1,114 perkKW = $/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,208 perkW = $/kKWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 415.6 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 Benefit from wind Diesel saved (gallons) 27,890 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 Diesel saved (dollars) $27,003 $55,626 $57,295 $59,014 $60,784 $62,608 $64,486 $66,421 $68,413 $70,466 $72,580 $74,757 $77,000 $79,310 Other Savings Diesel O&M saved $3,628 $7,402 $7,550 $7,701 $7,855 $8,012 $8,172 $8,335 $8,502 $8,672 $8,846 $9,022 $9,203 $9,387 REPI Credit (1st 10 years) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Benefit from Wind $30,631 $63,028 $64,845 $66,715 $68,639 $70,620 $72,658 $74,756 $76,915 $79,138 $81,425 $83,780 $86,203 $88,697 Total Benefit per KWh $0.0737 $0.0758 $0.0780 $0.0803 $0.0826 $0.0850 $0.0874 $0.0899 $0.0925 $0.0952 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $7,980 $13,902 $13,945 $13,989 $14,033 $14,079 $14,125 $14,172 $14,220 $14,270 $14,320 $14,371 $14,423 $14,477 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,799 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 Operating Expenses 10,129 18,214 18,271 18,329 18,389 18,449 18,511 18,574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After Expenses 20,502 44,814 46,574 48,385 _ 50,250 52,170 54,147 56,182 58,277 60,434 62,654 64940 67,294 69,717 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 20,502 44,814 46,574 48,385 50,250 52,170 54,147 56,182 $8,277 60,434 62,654 64940 67,294 69,717 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 12,673) (21,53 19, 17,965) (16,100) 14,180) 12,204) (10,169) (8,074) 5,91 3,69" 1,411 943 3,366 NPV of Cash Flow 1999$ $7,771 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 ~=—' «2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 55,780 27,890 $81,689 $84,140 $86,664 $89,264 $91,942 $94,700 $97,541 $100,467 $103,481 $106,586 $109,783 $113,077 $116,469 $119,963 $123,562 $127,269 $65,544 $9,575 $9,766 $9,962 $10,161 $10,364 $10,571 $10,783 $10,998 $11,218 $11,443 $11,672 $11,905 $12,143 $12,386 $12,634 $12,886 $6,572 $o $0 $0 $o $o $0 $o $0 $o $0 $0 $0 $o $0 $o $o $o $91,264 $93,906 $96,626 $99,425 $102,306 $105,271 $108,324 $111,466 $114,700 $118,029 $121,455 $124,982 $128,612 $132,349 $136,196 $140,155 $72,116 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $60,713 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 65,234 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 26,030 74,780 ~— 77,424 80,146 — 82,949 85,834 88,805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 _ 59,999 26,030 74,780 77,424 80,146 82,949 85,834 88,805 91,864 95,013 98,255 101,593 105,030 108,569 112,212 115,963 119,825 59,999 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (40,321) 8429 11,073, 13,795 16,598 19,484 22,454 25,513 28,662 31,904 35,243 38,679 42,218 45,861 49.612 53,474 26,823 wv w KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 26.1% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,422 perkKW —_kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,448 perkW —$/gallon $0.940 Fixed Land Fee $400 per WT/yr Total $2,870 perkKW = $/KWh $0.063 Variable Land Fee $0.001 per KWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,326 _($,000) Diesel O&M saved $0.009 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 527.4 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 Benefit from wind Diesel saved (gallons) 35,394 70,789 70,789 70,789 70,789 70,789 + =70,789 + 70,789 70,789 70,789 70,789 70,789 70,789 70,789 Diesel saved (dollars) $34,269 $70,594 $72,711 $74,893 $77,140 $79,454 $81,837 $84,292 $86,821 $89,426 $92,109 $94,872 $97,718 $100,650 Other Savings Diesel O&M saved $4,604 $9,393 $9,581 $9,773 $9,968 $10,167 $10,371 $10,578 $10,790 $11,006 $11,226 $11,450 $11,679 $11,913 REPI Credit (1st 10 years) $8,965 $18,985 $18,985 $18,985 $20,040 $20,040 $21,095 $21,095 $21,095 $22,150 $0 $0 $0 $0 Total Benefit from Wind $47,839 $98,972 $101,278 $103,651 $107,148 $109,661 $113,303 $115,966 $118,706 $122,581 ‘HHHHHH iHHHHHHE tHHHHHHE $112,562 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $9,562 $17,066 $17,109 $17,153 $17,197 $17,243 $17,289 $17,336 $17,385 $17,434 $17,484 $17,535 $17,588 $17,641 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,906 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 Operating Expenses 11,818 21,593 21,650 21,708 21,768 21,828 21,890 21,953 22,017 22,083 22,150 22,218 22,288 22,359 Net Benefit After Expenses 36,020 77,379 79,628 81,943 85,380 87,833 91,413 94,013 96,689 100,498 81,184 84104 87,109 90,203 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 36,020 77,379 79,628 81,943 85,380 87,833 91,413 94,013 96,689 100,498 81,184 84,104 87,109 90,203 Debt Payment (43,128) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) Annual Cash Flow 108) 8,8: (6,628) 4,313) 876) 1,577 5,157 7,756 __ 10,432 14,242 (5,072) (2,152) 853 3,947 NPV of Cash Flow 1999$ $156,009 Renewable Energy Production Incentive , Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7. 1,054.7 1,054.7. 1,054.7 1,054.7 527.4 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 70,789 35,394 $103,669 $106,779 $109,983 $113,282 $116,680 $120,181 $123,786 $127,500 $131,325 $135,265 $139,323 $143,502 $147,807 $152,242 $156,809 $161,513 $83,179 $12,151 $12,394 $12,642 $12,895 $13,153 $13,416 $13,684 $13,958 $14,237 $14,522 $14,812 $15,108 $15,410 $15,719 $16,033 $16,354 $8,340 $o $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $115,820 $119,173 $122,624 $126,177 $129,833 $133,597 $137,470 $141,458 $145,562 $149,786 $154,135 $158,611 $163,218 $167,960 $172,842 $177,867 $91,520 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $63,877 $17,751 $17,807 $17,865 $17,924 $17,984 $18,045 $18,107 $18,171 $18,236 $18,302 $18,370 $18,438 $18,509 $18,580 $18,654 $11,266 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 1,906 68,613 22,505 22,581 22,657 22,736 += 22,816 = 22,897 = 22,981 23,066 23,152 23,240 =. 23,331 23,422 23,516 23,612 23,709 13,806 47,207 __ 96,668 100,044 103,519 107,097 110,781 114,573 118,477 122,496 126,634 130,894 135,280 139,795 144,444 149,230 154,158 77,713 47,207 = 96,668 §9=100,044 103,519 107,097 110,781 114,573 118,477 122,496 126,634 130,894 135,280 139,795 144,444 149,230 154,158 77,713 (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (43,128) (39,049) 10,412 13,788 17,263 20,841 24525 28,317 32,221 36,240 40,378 44638 49,024 53539 58188 62,974 67,902 34,585 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count Z Term (years) 30 Labor $0.014 per kWh Capacity Factor 26.7% Interest rate 5.0% 15 year Overhaul $5,000 per WT Discount Rate 5.0% Insurance Project Costs (US$) Revenue General Liability $100 per turbine Equipment Cost $1,422 perkKW —_ kWhigallon diesel 14.9 Inflation 2.0% per year Balance of Station $1,448 perkW = $/galion $0.940 Fixed Land Fee $400 per WT/yr Total $2,870 per KW $/KWh $0.063 Variable Land Fee $0.001 per kWh Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,326 _($,000) Diesel O&M saved $0.009 per KWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Revenue Net Energy Production (MWh) 540.7 1,081.3 1,081.3. 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 Benefit from wind Diesel saved (gallons) 36,286 72,571 72,571 72,571 = 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 = 72,571 Diesel saved (dollars) $35,132 $72,371 $74,542 $76,779 $79,082 $81,454 $83,898 $86,415 $89,007 $91,678 $94,428 $97,261 $100,179 $103,184 Other Savings Diesel O&M saved $4,720 $9,630 $9,822 $10,019 $10,219 $10,423 $10,632 $10,845 $11,061 $11,283 $11,508 $11,738 $11,973 $12,213 REPI Credit (1st 10 years) $9,191 $19,464 $19,464 $19,464 $20,545 $20,545 $21,626 $21,626 $21,626 $22,707 $0 $0 $0 $0 Total Benefit from Wind $49,043 $101,464 $103,828 $106,261 $109,846 $112,423 $116,156 $118,886 $121,695 $125,668 $105,936 $108,999 $112,152 $115,397 Total Benefit per KWh $0.0907 $0.0938 $0.0960 $0.0983 $0.1016 $0.1040 $0.1074 $0.1099 $0.1125 $0.1162 $0.0980 $0.1008 $0.1037 $0.1067 Expenses O&M $9,750 $17,442 $17,485 $17,529 $17,573 $17,619 $17,665 $17,712 $17,761 $17,810 $17,860 $17,911 $17,963 $18,017 Insurance 350 714 728 743 758 773 788 804 820 837 853 870 888 906 Land 1,919 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 Operating Expenses 12,019 21,994 22,051 22,109 22,169 22,230 22,291 22,354 22,419 22,484 = 22,551 22,620 22,689 22,760 Net Benefit After Expenses 37,024 79,470 81,777 ___84,151__—87,677 90,193 93,865 _ 96,531 99,276 103,183 83,385 ~— 86,380 ~— 89,463 ~—— 92,636 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 37,024 79,470 81,777 984,151 87,677 90,193 93,865 96,531 99,276 103,183 83,385 86,380 89,463 92,636 Debt Payment (43,128) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) Annual Cash Flow (6,104) 6,786) ‘4,479 2,105) 1,421 3,937 7,609 10,275 _ 13,020 16,927 2,871 124 3,207 6,380 NPV of Cash Flow 1999$ $195,529 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 = «2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 1,081.3. 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 540.7 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571 72,571. 72,571 72,571 72,571 72,571 72,571 72,571 72,571 36,286 $106,279 $109,468 $112,752 $116,134 $119,618 $123,207 $126,903 $130,710 $134,632 $138,671 $142,831 $147,116 $151,529 $156,075 $160,757 $165,580 $85,274 $12,457 $12,706 $12,960 $13,219 $13,484 $13,754 $14,029 $14,309 $14,595 $14,887 $15,185 $15,489 $15,798 $16,114 $16,437 $16,765 $8,550 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $118,736 $122,174 $125,712 $129,354 $133,102 $136,961 $140,932 $145,019 $149,227 $153,558 $158,016 $162,604 $167,328 $172,189 $177,194 $182,345 $93,824 $0.1098 $0.1130 $0.1163 $0.1196 $0.1231 $0.1267 $0.1303 $0.1341 $0.1380 $0.1420 $0.1461 $0.1504 $0.1547 $0.1592 $0.1639 $0.1686 $0.1735 $64,253 $18,126 $18,183 $18,241 $18,299 $18,359 $18,421 $18,483 $18,547 $18,612 $18,678 $18,745 $18,814 $18,884 $18,956 $19,029 $11,454 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 3,838 1,919 69,014 22,907 22,982 23,059 23,137 23,217 23,299 23,382 23,467 23,553 23,642 23,732 23,824 23,917 24,013 24,110 14,007 49,722 99,267 102,730 106,295 109,965 113,743 117,633 121,638 125,760 130,004 134,374 138,873 143,504 148,272 153,181 158,235 79,817 49,722 99,267 102,730 106,295 109,965 113,743 117,633 121,638 125,760 130,004 134,374 138,873 143,504 148,272 153,181 158,235 79,817 (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (43,128) (36,534) 13,011 16,474 20,039 —-23,709_—27,487__—31,377__—*35,381__—39,504 43,748 48,118 52,616 57,248 62,016 _—66,925 71,979 _—36,689