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Kotzebue Electric Association Wind Power Economic Evaluation, June 1999 Draft
OWA ET Kotzebue Electric Association Wind Power Economic Evaluation Prepared For Kotzebue Electric Association P.O. Box 44 Kotzebue, Alaska 99752 June 1999 Prepared By Global Energy Concepts, Inc. 516 Sixth Street South, Suite 200 Kirkland, Washington 98033 Phone: (425) 822-9008 Fax: (425) 822-9022 R Ef E | WE Hit. ; Email: gec@aa.net MUG 3 4 2009 Alaska Industrial Developme; and Export Authority ” MEMORANDUM State of Alaska Division of Energy TO: Percy Frisby, Director DATE: August 9, 1999 Division of Energy FROM: Richard “Villea [wr SUBJECT: Kotzebue Wind — Planner IV Review of Draft Economic Report This memo summarizes my review of the June 1999 draft report entitled “Kotzebue Electric Association — Wind Power Economic Evaluation,” prepared by Global Energy Concepts, Inc. At the time the draft report was prepared, the initial 3 wind turbines had been operating in Kotzebue for about 1.5 years. The next 7 turbines were brought on line at about the same time the draft report was released. In addition to the economic analysis, the report includes data on costs, performance, and technical issues. This review, however, is limited to the economic analysis and methodology — all reported costs and technical data are assumed to be valid. The basic economic question is whether wind energy, when coupled with diesel energy in remote village systems, is likely to result in a significant reduction in the cost of power on an unsubsidized basis. Because costs and conditions vary by location, we cannot provide a general answer to the economic question based on our limited experience. What we can do, however, is evaluate this specific project in Kotzebue and cautiously interpret the results as an indicator of what might be possible at other locations. It is likely that both the costs of wind energy and the avoided costs of diesel generation will be higher in smaller, remote villages. SUMMARY AND CONCLUSION The draft report prepared for Kotzebue Electric Association (KEA) is based on preliminary data — future reports will be based on more complete data for the entire, 10-turbine installation and on more extensive operating experience. The report presents two different methodologies for addressing the economic question: . The first methodology is based on the cost per kWh of wind energy compared with the avoided cost per kWh of diesel generation. Kotzebue Wind Economics August 9, 1999 Page 2 7 The second is a “cash flow analysis” that estimates the present value of future system costs in a diesel-only scenario and compares that with the present value of future costs in a wind-diesel scenario. Based on the first methodology, the report concludes that the cost for wind energy is comparable to the cost of diesel generation at Kotzebue on an unsubsidized basis, and that the wind energy cost can be further reduced by taking advantage of the federally-funded “Renewable Energy Production Incentive,” an applicable federal subsidy program. Based on the second methodology, the report concludes that “the addition of the wind project adds value to the overall generating system.” In the base case, the wind-diesel system is projected to result in $237,446 in present value savings. As discussed below, | do not believe these findings are warranted given the data at hand. As far as | can tell from the figures in the report, the cost of wind energy incurred at Kotzebue is significantly higher than the avoided costs of diesel generation: roughly 12.8 cents per kWh incurred for wind energy compared with avoided diesel cost of roughly 8.0 cents or less. DISCUSSION My comments on the economic analysis are presented below, roughly in the order that each topic appears in the draft report: 1. Design life. A 30-year design life based on the turbine manufacturer's testing program is assumed in the base case. A 20-year life is assumed in one of the sensitivity cases. | would question whether a utility manager considering an investment of utility funds in wind energy would assume a 30-year life in Alaska conditions given the limited field experience with the latest wind technology and the unfavorable experience with much of the earlier wind technology. More evidence should be supplied on this key assumption. For example, have late generation wind turbines been financed either by RUS or other financial institutions? If so, what is the typical term to maturity for such loans? Are there any current practices or recent decisions by regulatory commissions in the United States or Canada that establish an allowable period of time to depreciate wind energy installations? If financial institutions have thus far been unwilling to extend financing for wind machines for more than 20 years, or if public regulatory commissions have established no more than 20 years as the depreciable life of wind installations, then it would be difficult to argue that a 30-year life should be used at this point for capital investment planning. | believe the base case Kotzebue Wind Economics August 9, 1999 Page 3 assumption should be a 20-year economic life in the absence of compelling evidence to the contrary. This makes for a more difficult economic test but | would ask: should wind energy be recommended for widespread adoption in remote Alaska villages if it can’t return a net economic benefit within a 20-year planning horizon? 2. Interest and discount rate. The analysis uses 5.0% nominal interest and discount rates based on the RUS “hardship” interest rate available to Kotzebue and other Alaskan RUS borrowers. Two observations: a. RUS financing may be available for wind if RUS is persuaded that wind represents the least cost option for the borrower and is sufficiently reliable. The individual | contacted at RUS was unaware of any previous RUS loans for wind projects. b. A 5.0% nominal discount rate implies a real discount rate of approximately 2.0%. These nominal and real discount rates are well below those that have normally been used in the past by both the State and federal government for power project feasibility analysis. Overall, however, the case for a 5.0% nominal rate, representing KEA’s cost of capital, is probably as strong as any other. A low rate should favor wind energy by attaching a higher value to fuel savings in later years. 3. Capital cost of wind project. It is not clear from the analysis what part of the access road to the site is included in the project capital cost and what part is not. Any portion of the access road that was built or upgraded to gain access to the project site should be included in the capital cost regardless of the funding source for the work. This is the case with access roads to other types of projects, such as hydro projects. If the road was already built to the site for another purpose, then its cost can be properly excluded from the analysis. More information is needed to determine which principle applies. 4. Operations and maintenance cost of wind project. Excluding the land lease, the annual O&M cost for all 10 turbines is estimated at $17,300, or about $1,700 per turbine per year — primarily labor and parts — for 30 years. As discussed later in this review, no additional allowance is made for major repairs or overhauls except in a sensitivity case. 5. Cost of energy for Phase 1 (initial 3 turbines). The cost of energy for the wind project in its initial year is estimated in the report by adding the annualized capital cost to the annual O&M cost, and then dividing the sum by the amount of energy expected to be produced in an average year: Kotzebue Wind Economics August 9, 1999 Page 4 a. Annual debt service on the capital cost of $591,000, assuming a 30-year amortization at 5.0% interest. As noted above, | believe the base case should reflect no more than a 20-year amortization period. Annual debt service (30 year term) $38,445 Annual debt service (20 year term) $47,423 b. Annual O&M cost is estimated at $7,800 for the first 3 turbines, including land lease payments. Although the narrative indicates that O&M cost can escalate over the life of the project (p. 29), no escalation is built into the report's cost of energy calculation nor, as noted above, is there any allowance for major repairs or overhauls. This means that the result shown in the report is the estimated cost of wind energy in the early years of operation, not the “levelized” cost (the term used in the report) over its expected life. Given these estimates, the cost of wind energy in the early years from the first 3 turbines is as follows: As shown in the report (assuming 30-year amortization): $38,445 + $7,800 = $0.130 per kWh 356.2 MWh Based instead on a 20-year amortization period, the result would be: $47,423 + $7,800 = $0.155 per kWh 356.2 MWh 6. Projected cost of energy for next 7 turbines. Again assuming a 30-year amortization of capital cost, the cost of wind energy for the next 7 turbines is projected in the report to be 9.8 cents per kWh. The capital cost numbers on page 31 are confusing. If! understand them correctly, however, the 9.8 cent estimate is the incremental cost of wind energy given that certain up-front development costs such as the initial project engineering, site selection, transmission line extension, control building and SCADA equipment have already been paid for. It also reflects lower installation cost in labor and materials due to the experience gained in setting up the first three turbines at the Kotzebue site. Incremental cost is relevant for a utility that has already established a wind energy system, has already incurred similar up-front costs, and is now considering whether Kotzebue Wind Economics August 9, 1999 Page 5 to invest in an expansion of its wind energy system. However, for a utility considering whether to establish a wind energy system to begin with, the incremental cost of additional turbines is not the right figure to look at. For that purpose, the relevant figure would be the cost of wind energy in Kotzebue for the full installation of 10 turbines, including the costs incurred for the first 3 plus the incremental costs for the next 7. Ue Combining these two costs — the initial 3 units plus the next 7 units — yields the following results for the early years of the wind installation: Assuming a 30-year amortization: $104,798 + $22,800 = $0.107 per kWh 1,187.3 MWh Based instead on a 20-year amortization period, the result would be: $129,271 + $22,800 = $0.128 per kWh 1,187.3 MWh Of the various estimates of the cost of wind energy considered thus far, | believe the 12.8 cents per kWh estimate derived above is the most appropriate — it is based on all of the capital and O&M cost data presented in the report but makes two adjustments: a. The capital cost is the sum of two costs presented in the report: ° $591,000 for the first 3 turbines. . $1,020,000 for the next 7 turbines. $591,000 + $1,020,000 = $1,611,000 b. The capital costs are annualized over 20 years instead of 30. 8. Avoided costs. There are two avoided cost figures given in the report: a. On page 28, avoided cost is represented to be 6.4 cents per kWh. This is approximately equal to the avoided fuel cost derived from the following figures in the Division of Energy's FY98 PCE Statistical Report: is Average fuel cost of $0.94 per gallon. ii. Diesel generation efficiency of 14.1 kWh sold per gallon. Kotzebue Wind Economics August 9, 1999 Page 6 Avoided fuel cost = $0.94 + 14.1 = 6.7 cents per kWh b. On page 31 of the report, the “cost of diesel generation” is represented to be 8.1 cents per kWh. The derivation of this figure is not provided. The “cost of diesel generation” could include costs that are not avoided as a result of the wind installation — however, the 8.1 cent figure is used in the report as though it does represent avoided cost. What diesel generation costs are likely to be avoided? Fuel Costs. Based on average generation efficiency, fuel costs of 6.4 (or 6.7) cents per kWh are avoided for every kWh produced by the wind machines. Since there is no basis at present to project either more efficient or less efficient loading of the diesel units as a result of the wind project, it is reasonable to assume fuel savings based on average generation efficiency. Capital Costs. The wind project does not allow KEA to reduce its diesel generating capacity because the wind is not always adequate to drive the turbines. A case in point occurred in January 1999 — Kotzebue experienced very cold temperatures, relatively high electrical demand, and very little wind for the better part of the month. | understand that, before the wind project, KEA typically had one diesel unit on line at any one time — that unit being large enough to carry the entire system load. Now that the wind project is functioning, KEA still keeps one diesel unit on line at any one time. However, because of the wind project, KEA has been able to run its largest diesel units for fewer hours while running its smaller units for additional hours. Because of these marginal changes in use patterns, it may be possible for KEA to replace its largest units somewhat later than it otherwise would, while replacing its smaller units somewhat earlier. This would translate into some amount of long term savings in diesel capacity costs, although the amount is unlikely to be very large and the concept is not developed in the report. Another category of capital cost that could be affected is the cost of fuel storage capacity — reduced fuel use could allow the utility to avoid or defer the addition of fuel storage capacity to meet electrical demand growth. The report does not discuss this, however, and it appears that KEA itself was not planning to increase its fuel storage capacity in the absence of the wind project. Kotzebue Wind Economics August 9, 1999 Page 7 10. O&M Costs. On page 32, the report states: “The diesel savings include the cost of the fuel and 75% of the related O&M costs and are calculated on a per kWh basis. Diesel O&M requirements are generally based on the run time hours of the generator. Assuming there is a relationship between the wind energy produced and a reduction in diesel generator run hours the expected savings are calculated on a per kWh basis. However, the actual diesel O&M that will be saved is not yet known.” This is confusing and suggests the need for more attention to this subject. Total run time on the diesel generators will be unchanged except that larger units may be run less and smaller units may be run more. Labor costs for diesel O&M are unlikely to be affected but certain other costs such as oil and parts could be somewhat reduced due to the marginal shift to smaller units. There is no information in the report on whether average loading on the operating diesel unit is higher or lower as a result of the wind project, a factor which could affect the level of wear and tear and resulting maintenance and repair requirements. Overall, then, the avoided diesel cost for KEA is likely to be the fuel cost plus a small, as yet undetermined amount of capital cost and O&M cost traceable to the marginal shift in use from larger to smaller units. A figure on the order of 8.0 cents per kWh would seem at present to be an upper bound on the avoided diesel cost for Kotzebue at the present time. Incurred Cost vs. Avoided Cost. On an unsubsidized basis for the Kotzebue case, | believe the appropriate comparison is an estimated 12.8 cents per kWh cost for wind energy vs. an avoided diesel cost no greater than 8.0 cents per kWh. ‘Cash flow analysis”. The following comments pertain to the “cash flow analysis,” i.e. the present value comparison of future “diesel only” costs with future “wind-diesel” costs: a. The $200,000 DCRA grant contribution, referenced on page 32 and in the table of results on page 33, should not be part of the economic analysis. The analysis should be focused on underlying costs and efficiencies, not on the impact of varying levels of subsidy. b. If | understand it correctly, the capital cost of the full,10 turbine installation in Kotzebue is assumed in the cash flow analysis to cost Kotzebue Wind Economics August 9, 1999 Page 8 $1,457,280 — this is derived by assuming that the incremental cost of installing the last 7 turbines is applied to the initial 3 turbines as well. As discussed in item “7a” above, | believe the estimated cost of installing the initial 3 turbines plus the estimated incremental cost of installing the last 7 turbines is $1,611,000. The economic analysis of the Kotzebue wind project should be based on the actual costs that have been incurred. In the report's cash flow analysis, the estimated gallons of fuel saved each year is based on an efficiency estimate of 13.5 kWh generated per gallon. PCE statistics indicate that, in FY97, 13.4 kWh were sold per gallon. Assuming losses of approximately 10%, generation efficiency in FY97 was probably closer to 14.7 kWh per gallon. According to more recent PCE reports, efficiency improved further in FY98 to 14.1 kWh sold per gallon. Again assuming 10% losses, generation efficiency for FY98 would be closer to 15.5 kWh per gallon. The report's cash flow analysis indicates fuel savings of 87,950 gallons per year. Assuming that diesel generation efficiency is 15.5 kWh per gallon would reduce this estimated savings to 76,600 gallons per year. The analysis assumes a real increase in diesel fuel prices of 1.0% per year for 30 years, ending up with a diesel price of about $1.18 per gallon (in 1998 dollars) in the year 2028. The assumption of any significant, long-term, real growth in fuel prices has not formed the basis for State energy planning for a number of years. However, the report's cash flow analysis begins with a fuel price of 87.6 cents in 1998, which is already less than the reported price of 94.0 cents shown in the FY98 PCE Statistical Report. It is unlikely, then, that the fuel price assumption overall is very much different from what the State would assume over the long term, but the subject is important and warrants more careful consideration in any follow-up analysis of the wind project. The cash flow analysis indicates that the new O&M requirement for the wind installation is nearly equal to the O&M savings that will be realized on the diesel side. Kotzebue Wind Economics August 9, 1999 Page 9 i. Savings in diesel O&M. As noted previously, it appears there may be O&M savings in oil and parts in addition to some long-term reduction in capacity costs, based on the idea that smaller units will be used more and larger units will be used less. This should be more carefully examined in follow-up work to determine if the annual savings of roughly $20,000, as shown in the cash flow analysis, is a reasonable estimate. ii. Long-term O&M requirement for wind turbines. The cash flow analysis indicates that O&M for the wind system will be about $17,000 per year in 1998 dollars, excluding the annual land lease payments of about $5,500. In the base case, there is no provision for any major repairs or overhauls over the projected 30-year life of the facility. Clearly, the AOC turbines are tough units and represent a major improvement in durability compared with their predecessors in the 1970s and 1980s. However, | believe it would be rare for any generating technology to show a track record of 30 years continuous service with no major repairs or overhauls, especially when continuously exposed to harsh weather conditions. | believe this assumption needs more support before it could reasonably be adopted as a basis for investment planning. f The results of the present value analysis would be less favorable to the wind project if the term of the analysis were reduced to 20 years, as | believe it should be, rather than 30 years. COMMENT ON THE REPORT'S OVERALL PERSPECTIVE The appropriate perspective would be that of an impartial utility manager in rural Alaska who is interested only in whether investing the utility's funds in wind energy at this time would produce net costs or benefits with respect to overall system costs and reliability. However, the report does not adopt this perspective. For example: . On page 31 the report concludes: “A cost of $0.098 per kWh for wind energy is comparable to the cost of diesel generation at Kotzebue, which was approximately $0.081/kWh for 1997.” Aside from the validity of the $0.098 estimate and questions about avoided cost discussed above, these figures without any adjustment Kotzebue Wind Economics August 9, 1999 Page 10 indicate that wind energy costs 21% more than diesel energy in Kotzebue. That is a lot closer than much of the early speculation but still represents a significant cost disadvantage at this point. Calling them “comparable” suggests a pro-wind orientation. ° Section 7.0 lists a number of potential economic and environmental benefits of wind energy in addition to the benefits estimated earlier in the report. However, the report does not describe any risks, concerns, or potential problems that could be associated with wind energy in remote Alaska village utility systems. Are there no downsides to consider? For example, is a wind-diesel system technically more complex than a diesel- only system, requiring new skills, tools, contractors, and expertise? The description of other potential benefits without mention of other possible drawbacks again suggests a pro-wind orientation. . On page 30, after estimating the cost of wind power from the initial 3 turbines at 13.0 cents per kWh, the report states: “As a point of reference, the cost of electricity for KEA customers in 1998 was approximately $0.215 per kWh. This rate is significantly higher than the national average largely due to the high cost of diesel and related shipping, handling, and storage.” KEA’s retail rate is irrelevant to the analysis and should not be loosely juxtaposed with a generation cost estimate. . A related point is made on page 4: “Diesel fuel is imported to generate electricity... Fuel can only be barged in during the summer months, and it is then stored for use throughout the winter. As a result, the diesel-generated electricity in the 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.” These statements exaggerate the impact of fuel cost on the cost of power. Since the value of wind energy is nearly equal to the value of displaced fuel, they suggest that wind energy has greater potential to reduce these cost disparities than it actually does. . One last word on perspective and how the report comes across to the reader — especially a reader on the lookout for the authors’ predispositions. The following statement appears on page 1, one of the first few sentences of the report: Kotzebue Wind Economics August 9, 1999 Page 11 “Much of western Alaska is blessed with abundant wind resources...” (emphasis added) It may seem trivial but right away a clear impression is created: who but a wind enthusiast would consider a region to be “blessed” by powerful, sustained winds? cc: Brad Reeve Kotzebue Electric Association Dennis Meiners Division of Energy Kotzebue Electric Association — Wind Power Economic Evaluation LIST OF ACRONYMS 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. Kotzebue Electric Association —- Wind Power Economic Evaluation TABLE OF CONTENTS 1.0 INTRODUCTION |... ececcceesceseseseeseseesescsescsenevseseseeecseaenecssseseeecsetesseessatseeatacsaees 1 TET OVC EV SW coe) cepa cece er ccecl coset ee eperrene aire eae oeeebera eens rabaaceterenedsedlecs tae tatsk vaste dedele teats 1 1.2 Report Purpose and Orgamization.................cccccccssessesesseeseseseeeeseeseeseacessneneneneeens 2 2.0 KEA’S WIND ENERGY ACTIVITIES ....0....0..cccccccssesseseseseseseeseeseseesesetevseseessseseeees 4 De BACK BTU srecareca coctscazcsstsscuaca caessusvavsees vetstsestsesvessestodsdusadesendusesesecdadordsdadodetotetel 4 Dek EME TV EF PYOQUAIM i cassasccctsnedelacatelceceobatdedededadetorstetal dudvdededonscvesezatete tel dodudedadetcledehs 6 2.3 The AOC Turbine... csesessesssesccsssssscescessceseesscsssnesessesesessesnssssesessesesaserseees 6 3.0 WIND RESOURCE ASSESSMENT.............0cccccccseeseseesesesensnsesesecseescsesseseneeseaseeneees 8 4:0 PROJECT DEVELOPMENT iscecetsscterctos srssscacteeavacetcsetssacuoasvortyeevers petsusisserasaaasesy sues 15 4.1 Turbine Procurement and Installation..............:.ccsceseesesessesnseseeeeseeseseeecseeeereaeeeees 15 4.2 Problems Encountered...........cccccecssesscsecseeseeeeecsecseeeeeeeeeaeeceeceeeeeeeeeeetaeeaeeaeertee 16 5:0 PROJECT PERFORMANGE ai as tetsterattsestes cust cswtaraes tons sssustureveseseesensersasastevesavererers 19 6:0 ECONOMIC EVALUATION de steretctesencrateaetesshatesshares tuostudarsdeetesetttatehensishsedeter ator 23 TSA PDUOACH ois caatc esos usudvonanescenesesntusesovesatdseedetesasetatgre toreeseassesudvenad=sateteteeateshsetacstetse> 23 6.2 Discussion and Basis of Economic and Financial Assumptions.............0.:0000 23 6.2.1 Fixed Charge RAte .....c.ccccccescessssssssveseeeseeeeseseseeeseanessessseeessenenees sciditededstateas 23 0.22 TUPDINE! Desi oTi Efe Lo dttateteteh ote ranensatecet chase srattet tesedenedeacancverusesstacesotasdeanterers 24 6.2.3 Financing Term and Depreciation .........ccccccceeceesesseseseeseeesseeseeeesenseeeaeeaeaee 24 0.2.4 Interest ROLE ss caes saedeesactaxstriovers cazond passe nea hctavenssovazaetsarievicisiorenssasesicaeiscwseteaes 24 6:2) DISCOUNE ROLE 6, <cdasicescoa ca tot scssasaaev1 sdnaes stateies cosbosataatusonaddasudetebabalavdededadenctotags 24 6.2.6 Net Present Value ........ccccccececeesesec reece eeneseeeseeneseeiessesesessesseneseeseseenenseneneetey 25 G3 Capital Costs ca cacetstacencscscutzaszscatatasarasecdssseaustataeasebotdbdenasttoledecteashabebetcttedecadedalatehe 25 6.3.1 Land ACQUiSitiOn ........ccccccccccccess ese eteeeseetseseseeseeseeseeseseceesecsecseesecsecseeeeeceeneees 25 6.3.2 Wind Turbines and Shipping ...........cccccccccccesssseseseesesesesnsssesseseessseesscseeassesenes 25 O:3:3| PYOJECE ENGINCCTING samc ntcsesctrstors save nasteustscancaveacesieuaseres ee elatateneadsieasiaacasesses 25 10: 354 POjeCt CORSETUCHON ca vsctstnvercversesevessta sey ata eaees an tsaedebeleladecsbebacdhencelcoetadelatats 26 Kotzebue Electric Association — Wind Power Economic Evaluation 235 Si MAINIENANCETEQUIDINENS stosctrcctcrcrescctstctriinta s statetetetateteigt atthe anes eoreertce er ea 28 6.3.6 Commissioning & Additional Startup COStS .......c.ccccccccsesseeseseseseeeseeseseeeees 28 Gr4yAnnual energy, Production irrtrscccstarscarareccorsststarssrecrcoiscaegeretsteresceersrerereroetess 28 6.5 Operation and Maintenance Costs ............ccccccessesesessesesesesesseseseeeeeeeesesesnseseeeeneeees 29 6.6 Cost of Energy.............. =30 6.7 Potential Cost Reduction ... aie! 6:8 iCashisEloweA maby sis se tc tatateesetasec tte tec crates at gesesreeaenaeeee ce preegeseereretet rere 33 7.0 POTENTIAL ECONOMIC AND ENVIRONMENTAL BENEFITS .................0++ 40 8/0 THE) WINDIENERG YEIND US TRY errrcttteccorrccrseticrsncescccrecesstcaesneisincassreresrarssrs 41 OF RUUREIREACA CRIV IDES tetstrtacst scat esepreserentatesnara tients aeoseareegeteesrpteerarererscears 43 Figure 1. Figure 2. Figure 3. Figure 4. Figure 5. ‘Figure 6. Figure 7. Figure 8. Figure 9. Kotzebue Electric Association - Wind Power Economic Evaluation LIST OF FIGURES Phase 1 Wind Turbines in Kotzebue, Alaska................ceccecececeeeececeees 2, Regional! Mapieerecocesesesnctasssosscssncnssrossasscascuveccsnscsensenecnscwesstereses 5 Long-term Wind Speed at 10 meters (33 feet) - Airport ................ceeeee 10 Annual Diurnal Wind Speed (m/s) - Airport ............:.cceceeeeceeeeeeeeeeeee 10 November Diurnal Wind Speed (m/s) - Airport.............cscseeeeeeeeeeeeees 10 Long-term Annual Wind Energy ROS€ ...........sccsceeseeeeeeneeeeneeeseeeeenes 11 KEA Diurnal Load Profile - August 1998..............ccsscssssescssceseseeeees 13 Wind Energy Contribution to KEA Energy Demand.................0sceeeeees 13 Wicinity Map. cccescsesasscosscssesecusscoscessovecssonsrcesreossescudstvessesees 18 Figure 10. Monthly Energy versus Turbine Availability .................secseeseeeeeeeee 21 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........ 9 Actual Wind Speed at Kotzebue Airport 1984-1996 10 meters (33 feet) ...... 9 Estimated Long-term Wind Speed at 25 meters (83 feet) - Project Site...... 12 Performance Summary - Phase 1 (3 AOC 15/50 Turbines)...................- 20 Performance Summary by Turbine - 1998 ............ceceeeseeeeeeeeceeeeeeneenes 22 Comparison of Actual and Projected Energy ............ccssccseceeeseseseeeeees 22 Capital Cost Summary - Phase 1 (3 AOC 15/50 Turbines) ................0646 26 Estimated Energy Losses .............sccecesesesececeeneeeeeeeencneneeeeeeneaeesenes 29 Estimated Annual O&M Costs Detailed O&M Labor Costs ....... : Potential Balance of Station Cost Reductions from Phase 1 ...............044 32 Summary of Cash Flow Analysis ...........:scccsecssecseseeeeesesseseseusceneees 34 Cost Comparison of Diesel Generation versus Wind-Diesel Generation.... 36 Estimated Savings from Wind Project (with 10 AOC 15/50 turbines) ...... 39 Kotzebue Electric Association —- Wind Power Economic Evaluation 1.0 INTRODUCTION 1.1 Overview Kotzebue Electric Association (KEA) and the Department of Community and Regional Affairs (DCRA), Division of Energy 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 O wind energy for Kotzebue, based on the information available at this time. ward ; we Ss Much of western i aaa wih abundant wind resources and the cost of wind energy has been steadily ing. 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 called for 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 18 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 further expanded their wind energy installations 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 expanding their own wind energy installations 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 defect in material or workmanship. The turbines are each rated at 50 kW by the turbine manufacturer; however, for the purposes of this report, they are considered to be rated at 66 kW because they are designed with a maximum sustainable power output level of 66 kW.' Each turbine is installed on a 25 meter (83 " This is consistent with the International Electrotechnical Commission definition for the rated capacity of a wind turbine. Global Energy Concepts 1 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation feet) lattice tower. The towers are secured to specially designed pile foundations developed with consideration for the tundra and permafrost conditions at the site. The top of the pile foundations are approximately 1.8 meters (6 feet) above ground level resulting in a turbine hub height of approximately 27 meters (89 feet). ae Figure 1. Phase 1 Wind Turbines in Kotzebue, Alaska 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. Global Energy Concepts 2 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Cost and performance information is currently available for the first three wind turbines (Phase 1 of the project); therefore, the economic evaluation in this report focuses on the experience of these turbines and 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 9 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 not addressed in the economic analysis are outlined in Section 7. An overview of wind energy activities in other parts of the world is provided in Section 8. KEA’s outreach activities and their vision for future wind energy involvement is summarized in Section 9. Global Energy Concepts 3 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 2.0 KEA’S WIND ENERGY ACTIVITIES 2.1 Background With approximately 3,500 residents, Kotzebue is the largest native community in Vi 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 i L can only be barged in during the summer months, and it is then stored for use K \ throughout the winter. Asa result, the diesel-generated electricity in the villages is ° Ve expensive relative to other areas: approximately four times as much as in urban areas of { oy) Alaska and five times as much as the U.S. average. Hi r To help offset the high cost of electricity in Kotzebue, the State of Alaska currently supports a Power Cost Equalization (PCE) program. In Alaska, this program provides almost $17 million a year in state energy assistance money with approximately $450 thousand going to Kotzebue. Of the funds available to Kotzebue, approximately $150 thousand are allocated to public infrastructure costs with the remaining $300 thousand used to directly reduce the cost of electricity to KEA customers. However, the 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 the 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, they began working with the DCRA to formulate plans for a wind energy project and 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 DCRA has provided $239,000 towards the development of Phase 1 of the project (the first three turbines), 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 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation ho mention ALASKA DEPARTMENT OF ENERGY KOTZEBUE WIND FARM PROJECT ° Fairbanks REGIONAL MAP ‘Anchorage @Bethel 3/98 me 30822- ron =o. Figure 2. Regional Map June 1999 Global Energy Concepts 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 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. There are approximately 200 remote villages in Alaska, and over 70 of these villages 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 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 a utility owner and operator. The TVP is providing KEA with a Second Wind Supervisory Control and Data Acquisition (SCADA) system to facilitate data collection from the project and is providing technical assistance through NREL and their support contractors. Under the TVP program, monthly performance reports for the wind project are generated and distributed to interested parties. In addition, EPRI plans to publish a series of reports describing the project development and the operating experience of the project. The first of these reports, scheduled to be completed in the summer of 1999, will describe 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 (Phase 1, 2, and 3). 2.3 The AOC Turbine 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 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 to full capacity generation on September 28, 1997. Phase 2 and Phase 3 consist of the next seven AOC 15/50 wind turbines. The turbines were ordered in early 1998 and delivered to the site in December 1998. Because of weather constraints in the winter months, the installations were delayed until the spring Global Energy Concepts 6 June 1999 Kotzebue Electric Association - Wind Power Economic Evaluation of 1999. The turbines were commissioned in May and released to full operation in June 1999. 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 the Northwest Territories of Canada and north central Ontario in Canada. Global Energy Concepts 7 June 1999 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 there are also wind data 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 in its first few years of operation and the met tower was moved during the summer of 1998. WECTEC used concurrent data from the site met tower and the airport data to establish a correlation between the sites. The correlation coefficient is .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 a 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 can vary more than 10% from year to year. The monthly diurnal wind speed from the Kotzebue Airport for the period 1984 through 1996 (13 years) was summarized in the WECTEC report and is presented in Table 2. The monthly and diurnal patterns are also illustrated in Figures 3 and 4. The highest wind month is November and the lowest wind month is May. On an annual basis there is not a significant diurnal variation of the wind speeds at the project site although there is more variation during some months. For example, the winds are somewhat higher in the afternoon 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. Global Energy Concepts 8 June 1999 Kotzebue Electric Association —- Wind Power Economic Evaluation Table 1. Monthly Wind Speed (m/s) at 10 meters (33 feet) - Kotzebue Airport Percent of Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avg 15-yr Avg 1984 §.9)| 4.0) 4.0) 4.8) | 5:2 | 3:8) 5.7 | §.0) 5:1) 6.0 | 6:6 | (7:0) | 5.2 92% 1985 Bx 5 2 5 Ss OS'S 15:4) 5:35.01 G27 ONO: 2ilali7 2ianG:0) 106% 1986 47 61 43 53 54 52 55 61 76 51 56 64 56 99% 1987 6:5') (5:3)) 5:4) 14.6) 6.0) | 15:7) /5.1) (5:9) 16-2) 6.1) |) 1554) 16:3) S17, 100% 1988 73) 720) 450) 4.6) |) S245) 158) 15:9) 15.5) | 5:5) 5:37) 15:0!) 7.6) | (5:8 101% 1989 6.0 103 73 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 5.7 48 46 51 63 57 58 74 49 44 56 99% 1992 SG S34 SO) Set Sit 4.5) 5-210 6.9 to: 9 5.8 MO. O as .ONlMo:9) 97% 1993 6.7 72 45 46 47 56 53 63 69 69 76 59 6.0 106% 1994 S57) Ost Sez San ace 5:40 4-710) 6-9 ln o-3) 5:8 17-21 ClO NO-¢ 100% 1995 6.0 56 45 48 49 53 51 52 63 64 46 60 54 95% 1996 62 76 69 42 58 56 56 63 58 55 81 49 60 106% 1997 51 50 42 55 48 58 58 58 54 58 82 42 5.5 96% 1998 43 28 62 63 48 46 46 60 54 63 54 46 5.1 90% Average §8 58 5.1 50 50 52 54 59 60 62 65 61 5.7 Table 2. Actual Wind Speed at Kotzebue Airport 1984-1996 10 meters (33 feet) 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 5.9 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 5.8 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 5.9 5.7 10 62 68 51 44 50 51 54 58 62 65 66 5.8 5.7 11 62 67 52 44 50 53 56 59 65 64 69 5.9 5.8 12 6.3) (6:7) 5:2) (4:6 | 5:0) 5.5) 5.6) 6.1 6:5 |'6'5 | 17.0) 5.9 5.9 13 6:37) 6:7.) 5:21) 14.8) 5:3) /5:7/) 15.6 | (6:4) 6:7) 6:7, 7-3) 6.0 6.0 14 60 70 52 5.0 52 59 56 64 66 67 7.3 6.0 6.1 15 6:2) 74) 115.5) 5.1) | (5:3) 587) 15:5) 16.6) 6!5) 6:42) 723)) 5:9 61° 16 61 69 54 50 53 58 55 66 63 65 7.3 5.9 6.0 17 §9 67 54 50 53 60 54 65 63 63 7.0 56 5.9 18 SO Ort oe OO nm o-2) 1m Calin SLi Ost eOnt i O:@.1 ize Ion, 5.9 19 GS Oreos heoctaio-1in G:2 9:20.48 0.0 1G:Olln2O)snocd, 5.9 20 5:9) 6.6) 25:2) | 5:0)) /5:0)5) 5.9) (5:3) 16:4") 15:95:68) 720) 5:7, 5.8 21 59 66 50 50 47 58 50 62 57 58 7.0 5.9 5.7 22 59 66 51 50 46 57 48 61 58 59 66 57 5.6 23 59 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 57 5.6 Average 6.1 6.7 52 4.7 48 55 52 61 61 62 69 59 5.8 Global Energy Concepts 9 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Wind Speed (m/s) ofPF NN WHA HDN OW | ” 7 7 — —r + Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Figure 3. Long-term Wind Speed at 10 meters (33 feet) - Airport N a Wind Speed (m/s) a _____ 123 4 5 6 7 8 9 10111213 14 15 16 17 18 19 20 21 22 23 24 Hour of the Day Figure 4. Annual Diurnal Wind Speed (m/s) - Airport “ Wind Speed (m/s) a a 4 — ~— 12.3.4 5 6 7 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) - Airport Global Energy Concepts 10 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Kotzebue, Alaska January 1, 86 through December 31, 90 Winds: Direction Wind Economics & Techndogy, Inc. 511 Frumenti Ct. Martinez, CA 94553 E-Mail: we cte cefm@ad.com Tel: 925-229-0648; Fax: 925-229-0685 5 to 10 15 to 20 25 to 30 10 to 15 20 to 25 >=30 (m/s) Number of Records Used: 43629 Figure 6. Long-term Annual Wind Energy Rose 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 data. The estimated long-term wind speed for the project site at approximate turbine hub height is presented in Table 3. Global Energy Concepts 11 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Table 3. Estimated Long-term Wind Speed at 25 meters (83 feet) — Project Site Hour Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual 63 62 56 52 50 59 54 63 61 64 7.0 6.1 5.9 64 66 56 52 50 59 56 63 62 64 7.2 6.1 6.0 64 66 55 51 49 56 55 63 60 65 7.1 63 5.9 65 66 54 50 48 58 55 63 60 65 68 64 5.9 63 65 55 50 48 56 56 63 60 65 68 63 5.9 62 65 55 49 46 57 56 62 61 65 66 6.4 5.9 62 64 53 49 47 57 56 61 60 65 67 62 5.8 63 66 52 50 50 56 55 60 60 66 67 63 5.9 62 65 53 5.0 51 56 58 60 63 66 7.1 6.3 5.9 10 63 67 54 50 52 56 59 61 64 67 69 61 6.0 11 63 67 55 50 52 58 60 63 67 67 7.1 62 6.1 12 6:4°| 6:7) (5:5) |5:0) 5:41) 5:9) | 5:9) 16:3.) 6:7) | 6:7) 7:2) 6:2 6.0 13 63 67 54 53 56 59 59 65 68 7.0 7.5 63 6.3 14 6:2) (6.9 (5.5) |5.4) 5:5) 6.0 5.9) 6:7| 6:7) | 6:9 | 7:5) (6:3 6.3 15 6:3)) 17.0) (5.6) 5.5, (5:6) | (5:0) 5:8) 6:6) |6:7) | 6:7, | 75) [6:2 6.3 16 63 67 56 55 57 59 59 67 66 67 7.5 6.2 6.2 17 62) 6.7 56 5.5 58) 62 58 66 6.6 6:5 7.2) \6:0 6.2 18 62 66 56 56 57 62 57 67 63 63 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 5:9 66 6.2 6:1 7.3) 6.0 6.1 21 62 66 53 55 54 61 57 64 61 62 72 62 6.0 22 62 65 54 56 52 61 55 64 63 63 6.9 6.0 6.0 23 62 63 54 56 50 59 53 63 62 62 67 59 5.9 24 6346-4), 18:5)):'5:5) 5:0 15:9) 5:5 | 16:416.0 | 6:2) 657/61 5.9 Average 63 66 55 53 52 59 57 64 63 65 7.1 62 6.0 CON Onhwhd = 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. On an annual basis the diurnal ie variation of wind speed is not very significant, however, the winds 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 August 1998 through April 1999. Energy demand data for May, June, and July were not available. Based on the data available, the 10 AOC wind turbines are expected to make an annual contribution of approximately 6% to Kotzebue’s electricity needs. Global Energy Concepts 12 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Load (kWh) Wind Speed (m/s) 6 8 10 12 14 16 18 20 2 Hour of the Day ME Load Wind Speed Figure 7. KEA Diurnal Load Profile - August 1998 3,500 150 Total Energy Demand (MWh) ro oF NN Ny Ww o § 8 § 8 8 8B o g 5 Wind Energy (MWh) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec mms T otal Energy Demand Wind Energy 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 that KEA is monitoring in northwestern 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 13 June 1999 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 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 tasks were 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. Prior to the development of the project site and installation of the turbines, a road to the 5 3 site was constructed (with funding from a separate project). Also included in the Ce development of Phase 1 was the transmission line extension. In the spring of 1997, ari) KEA extended the transmission 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 turbine. The holes were drilled, and the pile foundations were installed in the spring of 1997. The seven turbines in Phase 2 and 3 are installed in the northeast corner of the project site in two rows. The new turbines are also oriented north to south. The current project including 10 AOC 15/50 wind turbines occupies less than a third 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 Global Energy Concepts 14 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Kotzebue, but in general, nearby communities considering wind energy development will not have access to a crane. For these projects it is believed that the AOC turbines are small enough that they can be erected with the use of a gin pole and will not require the use of a crane. Erection of wind turbines of this size has been done successfully in northern Canada without the use of a crane. 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 purchased by AOC and reengineered 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 turbines 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 installed and commissioned in late 1999. 4.2 Problems Encountered The turbines experienced some initial starting 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 fusés. KEA determined that the control system was assembled with the incorrect power factor correction capacitors. However, after the correct capacitors were installed the turbine 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 Global Energy Concepts 15 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 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 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. The increased air gap resulted in premature deployment of the tip brakes during wind gusts. Problems with the dampers were causing the tip brakes to not reset after deployment. Unexpected deployment of the tip brakes significantly reduce 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 that are used in the tip brake. KEA continues to perform periodic pull tests as part of their routine maintenance activities. KEA encountered problems with the Matrix parking brake. After several attempts at troubleshooting the problem it was decided to replace the Matrix parking brake 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 impacted the installation of Phase 2 and 3. Global Energy Concepts 16 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation EXISTING 7200 V DISTRIBUTION LINE | SECTION 26 | EXISTING | WIND: TURBINES | KEA WIND FARM SITE 1000 1500 DEPARTMENT OF ENERGY KOTZEBUE WIND FARM PROJECT VICINITY MAP AND PLOT PLAN 30622112 mine VICMAP Locoted in 17N, 18W, Koteel River Meridicn, Alosko Kotzebue Recording District =e me. 3/98 Figure 9. Vicinity Map Global Energy Concepts 17 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 5.0 PROJECT PERFORMANCE The Phase 1 turbines have over a year and a half of operating experience. For a project of this size, it was 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 made it difficult for AOC personnel to travel to the site to assist with O&M tasks. As a result, KEA personnel provided a significant amount of the engineering and technical services required to maintain and adjust the turbines. Although KEA incurred additional labor and consulting costs to perform these activities themselves, they gained hands-on experience and a greater understanding of the AOC turbine operation. The Phase 1 project performance from installation through April 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 76% 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 availability of 97% in a remote environment is a respectable achiévement, 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 9-fold difference. While January and February had similar availability, the average wind speed (at Turbine 1) for January was 4.1 m/s (9.2 mph) compared to 7.1 m/s (15.9 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 production reported in Table 5 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. When the production is adjusted to include production through December 31, the actual 1998 production 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 for approximately 54 homes. Global Energy Concepts 18 June 1999 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 | (m/s) 1997 Estimate 48,618 N/A N/A N/A January 1998 22,673 731.4 88.7% §2 February” 8,724 311.6 100.0% 3.6 March 39,341 1,269.1 91.3% | 6.0 April 26,640 888.0 73.8% 6.4 May 14,698 474.1 86.2% 4.9 June 7,488 249.6 84.9% 4.3 July 10,204 329.2 88.1% 4.1 August 28,320 913.5 95.4% 5.8 September [2] 8,913 445.7 99.5% 4.7 October 32,917 1,097.2 99.7% 5.7 November | 43,804 1,412.9 99.6% 6.4 December 27,152 905.1 98.2% 4.5 _| 1998 Total [3] 270,874 763.4 | 92.0% 5.1 January 1999 6,269 | (202.2 97.3% 3.4 February 56,090 7809.4 97.9% 6.6 March 13,827 493.8 97.9% 4.0 April : 36,548 1,179.0 99.0% 5.9 Lifetime Total BLL 432,226 93.6% 5.1 [1] Wind speed values reported are based on the anemometers mounted on Turbine 1's tower at approximately 18 meters (59 feet) and are expected to be lower than the actual wind speeds at turbine hub height 27 meters (89 feet). A new site met tower will be installed in the near future. [2] September values are for the 1° through the 20" only. Beginning with October, the monthly reporting periods are from the 21° of the previous month through the 20" of designated month. [3] Availability and wind speeds are the simple average of the monthly values presented in the table. As shown in Table 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 adjustments to account for the shortfall due to reduced hours and low availability. If the actual production were adjusted for expected availability, the project would likely have produced approximately 79% of the estimated energy or 282 MWh. 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. It appears that the majority of energy shortfall is due to low 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’s 1998 average 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 Global Energy Concepts 19 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 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 the low wind year. 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. 100% 80% = > = 60% = = 5 > & 5 40% g a 20% 0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Mm 1998 MWh ME 1999 MWh —aie—= 1998 A vailability t= 1999 vailability Figure 10. Monthly Energy versus Turbine Availability Global Energy Concepts 20 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Table 5. Performance Summary by Turbine - 1998 Turbine 1 Turbine 2 T Turbine 3 kWh _ | Availability kWh Availability kWh Availability January 6,141 99.7% 10,355) 99.8% 6,177 66.6% February 3,226} 100.0% 2,894} 100.0% | 2,604} 100.0% March 10,348 75.5% 14,574 99.6% 14,420 98.7% April 2,982} 26.7% 11,609 97.2% 12,049 97.4% May 2,711 58.5% 6,171} 100.0% 5,816} 100.0% June 748 69.5% 3,535] 100.0% 3,206 85.2% July 3,610} 89.6% 3,635) 98.5% | 2,959 76.1% August 10,109} 99.6% 9,626 99.6% 8,585 87.1% September * 3,135} 98.6% 2,846} 100.0% 2,932} 100.0% October 11,173 99.7% 10,560 99.6% 11,184 99.7% November 15,100} 99.6% 14,651 99.6% 14,052 99.6% December 9,687} 98.9% 8,929 99.0% 8,536 96.6% Annual 78,969} 84.3% 99,386 99.4% 92,519 92.0% * Change in monthly reporting periods. This month only includes 480 hours (20 days). Table 6. ‘Comparison of Actual and Projected Energy % of Projected kWh Energy Projected Annual Production 356,195 Jan 1-Dec 20, 1998 Production 270,874 76.0% Actual 1998 Production (8,760 hours) 273,045 76.7% Adjusted to 95% Availability 281,642 79.1% Global Energy Concepts 21 June 1999 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 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 later development, 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 project. Cost of energy was calculated for the actual Phase 1 costs based on the approach recommended by the EPRI Technical Assessment Guide. The potential cost reductions were applied to the Phase 1 costs to estimate the COE for Phase 2 and 3 of the project and future expansion using AOC turbines. These costs are preliminary and can be updated to reflect actual costs when the project construction is completed. This report also includes a 30-year cash flow of the KEA wind project, based on the 30-year design life specified by the turbine manufacturer. This analysis presents a variety of assumptions to determine the economic viability of wind energy under different circumstances. The impact of the federal Renewable Energy Production Incentive (REPI) payment is also discussed and illustrated in the cash flow analysis. 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 to pay for the capital investment including the cost of debt, equity, and depreciation. The expenses related 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). Global Energy Concepts 22 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation The FCR used for the COE calculation is based on 100% debt financing that is available to KEA. The financing term normally available from the Rural Utility Service (RUS) is equivalent to the design life of the system unless a shorter term is requested by the utility. The design life of the system, which is discussed below, also determines the depreciation of the capital cost. The remaining component that affects the FCR calculation is the interest rate of the debt financing discussed below. 6.2.2 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 a 20-year or 30-year design life. Because there is limited operating experience of the AOC turbine, two sensitivities were performed to address the risk associated with the long-term reliability of the wind turbine. One sensitivity assumes a design life of 20 years and the other assumes a major system overhaul during the 15th year of operation. 6.2.3 Financing Term and Depreciation Utility financing for power plants in rural Alaska are financed through the RUS. As discussed above, the RUS bases the financing term on the design life of the system unless the utility requests a shorter term. The depreciation rate is also determined by the life of the system. 6.2.4 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%. 6.2.5 Discount Rate * A discount rate is generally based on the cost of capital or the required rate of | Ya . 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. Global Energy Concepts 23 June 1999 Kotzebue Electric Association - Wind Power Economic Evaluation 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. 6.2.6 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, a project with a positive net present value would be viewed favorably by an investor. 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 and 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 1 costs can be reduced in later phases and 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 here: 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 Native 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. Global Energy Concepts 24 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation Table 7. Capital Cost Summary - Phase 1 (3 AOC 15/50 Turbines) Number of Turbines 3 Rated Turbine Capacity [66 kw Materials Cost Percent Cost Category per kW of Total LAND ACQUISITION N/A WIND TURBINES Turbine & Tower 49,653) 148,960) 148,960 752 25.2% Cold Weather Package 805 2,415 2,415 12 0.4% Spare Parts 824 2,471 2,471 12 0.4% SHIPPING 20,922 62,766 62,766 317 10.6% PROJECT ENGINEERING 51,525 51,525 260 8.7% | | PROJECT CONSTRUCTION Roads, Pads, Site Survey & Restoration 2,688 8,063 8,063 41 1.4% Foundations 27,752 83,256 83,256 420 14.1% Turbine and Tower Installation [1] 67,372 34,445] 103,335} 103,335 522 17.5% Electrical Infrastructure 8,518 25,554] 25,554 129 4.3% Electrical Transformers 1,200 3,600 3,600 18 0.6% Data Acquisition System 16,714 16,714 84 2.8% Central Building 5,764 3,102 8,866 45 1.5% Line Extension & Interconnection 15,771 7,634 23,406 118 4.0% Miscellaneous 446 446 2 0.1% MAINTENANCE EQUIPMENT 1,551 1,551 COMMISSIONING & ADDITIONAL STARTUP COSTS [2) 48,129 TOTAL EQUIPMENT COSTS 216,613 1,094 36.6% TOTAL BALANCE OF STATION 88,908 285,536 374,444 1,891 63.4% TOTAL PROJECT COSTS 591,056 2,985 100.0% [1] Includes approximately $22K for the purchase and repair of a crane. [2] 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. 7 6.3.4 Project Construction There are nine categories included in Project Construction. Following is a discussion of costs allocated to each category. Global Energy Concepts 25 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 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 any costs related to the off-site road extension, which was paid for with separate funding. 6.3.4.2 Foundations The largest component of the turbine foundation cost was $50,000 for the 9 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 the Phase 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 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 and had not been needed. 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. 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. Global Energy Concepts 26 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 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 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. As mentioned above, expenses associated with vehicles owned by KEA are allocated to the project as O&M expenses. 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. 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 in a previous section 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 experience. The 9.7% total cumulative losses assumed by GEC are more conservative than the 6.5% losses estimated in the WECTEC report. Jf Based on the expected losses in Table 8, the net-annUahenergy is estimated to be pel? approximately 118,700 kWh per turbine ee for Phase 1. Based on they | ay~ a \ 42 oft bag 1999 Global Energy Concepts Kotzebue Electric Association — Wind Power Economic Evaluation 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 so The annual O&M costs for KEA’s three-turbine project are estimated to be approxiniately $2,600 per turbine or $0.022 per kWh. The O&M costs include replacement parts and labor for scheduled and unscheduled turbine maintenance, maintenance equipment expenses allocated to the project, land lease payments, insurance expenses, and other administrative costs. The estimated annual expenses for a larger project 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 Native 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 oerky iV production of turbines and the avoided cost of energy. For this variable-porti he lease payment, KEA pays the Lessor 1.5% of KEA’s avoided cost i produced by the turbines. Annual insurance expenses are estimated (i $100 per turbine for general liability. é Table 9. Estimated Annual O&M Costs { 3 ine 7-Turbine | per WT Total per kWh | per WT Total |Land lease fixed $400 $1,200 $0.003 $457 $3,200 variable $114 $342 $0.001 $114 $798 Insurance $102 $306 $0.001 $102 $714 Parts usage $300 $900 $0.003 $300 $2,100 Labor $1,680 $5,040 $0.014 | $1,176 $8,232 Total O&M $2,596 $7,78 $0.022 | $2,149 $15,044 Global Energy Concepts 28 v we Kotzebue Electric Association — Wind Power Economic Evaluation 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 fully burdened labor rates. 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 190 $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 for the project discussed above in Section 6.2 is 6.5%, which is quite low as a result of the favorable financing terms available to KEA. The calculation of the FCR is attached as Appendix B. The project costs also include annual O&M expenses. O&M costs can escalate over the ) life of the project and 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: f / COE = (ICCx FCR) + Annual O&M lo” v AEP } : i * Where: ICC = initial capital cost a yh t FCR = fixed charge rate AEP = annual energy production \ The estimated COE for Phase 1 of the KEA project is: LE / COE = ($591,000 X 6.5%) + $7,800) = $0.130 per kWh 356.2 MWh Global Energy Concepts 29 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 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 LH 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 1998. The payment rate is \n\9 A 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. a point of reference, the cost of electricity for KEA customers in 1998 was approximately $0.215 per kWh. This rate is significantly higher than the national average largely due to the high cost of diesel and related shipping, handling, and storage. 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 plan. Some of the cost reductions for Phases 2 and 3 will occur because it will not be necessary to replicate costs already incurred. For example, Phase 1 costs included the purchase and repair of a crane for the installation of the turbines which will be used in Phases 2 and 3. 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 is expected to reduce the cost of materials compared to the Phase 1 materials. Although the final cost numbers are not yet available for Phase 2 and 3, the majority of the construction work has been completed. Construction crew managers have indicated that the construction time has been 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 would not likely bear the cost of a data acquisition, 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 Phase 2 and 3 and other developments it is assumed that the line extension costs will be reduced by 50% from Global Energy Concepts 30 June 1999 (Pp ok Kotzebue Electric Association —- Wind Power Economic Evaluation aM vs y N 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 OE is reduced overall by approximately 25%. This calculation can be updated when oi aiid is completed and the actual costs for Phase 2 and 3 become available. oe \m Tab) e.11. Potential Balance of Station Cost Reductions from Phase 1 ere) | LTS Cost — Phase 1 Percent Per kW Category Reduction Reduction Project Engineering 40% $104 Foundations 25% $105 Turbine and Tower Installation | Labor 35% $119 Crane 100% $11t Data Acquisition System 100% $84 . |Line Extension 50% $59 Additional Startup 80% $194 Aeon Reduction $777 Potential Balance of Station Cost — Phase 2 & 3 $1,114 per kW Based on the potential cost reductions, the estimated COE for future development in Kotzebue assuming seven AOC 15/50 turbines is: Oo COE = ($1,020,000 X 6.5%) + $15,000) = $0.098 per kWh » 831.1 MWh L a \d A Development after Phase 1 not only benefits from the reduction of capital costs but also NY y from a reduction in O&M costs. The labor costs associated with maintenance is a expected to be reduced by approximately 30% on a per turbine basis. Without the O&M cost savings, the COE would be $0.102 per kWh. aS As previously discussed, the COE may be further reduced during the first 10 years ofX x LP operation by the receipt of REPI payments. The REPI payments have not been n v included in the above calculations. Ps od Global Energy Concepts 3] June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation 6.8 Cash Flow Analysis the COE. The assumptions are included on the cash flow spreadsheets, included in Appendix C. Project size, capital cost, financing terms, basis of the benefit calculation, and a breakdown of operating expenses assumed in the cash flow analysis are identified VU for each scenario. \ The cash flow analysis is based on the same basic assumptions used in the calculation of Pe 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 atid 75% of the related O&M costs and are calculated on a per : e e are-p a tun time hours of the generafor. Assuming there is a relationship Between the wind erpy produced and a reduction in diesel generator run hours the expected savings are V calculated on a per kWh basis. However, the actual diesel O&M that will be saved is not yet known. The value of the wind energy also includes the REPI payments assuming that Congress will continue to appropriate the necessary fund for that program. Table 12 summarizes the results of the cash flow scenarios. The Phase 1 project. scenarios presented in Table 12 clearly show the benefit of the 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 include to account for the uncertainty related to the actual maintenance cost of the AOC turbine. However, as shown in the table, 10% higher than expected maintenance costs only increase the COE from $0.098 per kWh to $0.102 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. Even though development in other areas may incur higher capital costs, higher energy production can significantly increase the value of the moe ver | at y Sept bet” Global Energy Concepts 32 June 1999 Kotzebue Electric Association — Wind Power Economic Evaluation \ , Table 12. Summary of Cash Flow Analysis Scenario Phase 1 Project Does not include $200K DCRA grant Includes $200K DCRA grant Baseline; assumes potential cost reductions 7 WTs; 100% debt; no subsidy Capital Cost Variation 10% higher costs | 10% lower costs Financing Assumption 20-year debt term & depreciation 6% interest on debt Energy Estimates | 20% lower than projected | 10% higher than projected | Turbine Maintenance Costs 10% higher expenses | 10% lower expenses | Major overhaul at 15 years [2] | Wind Resource i | 6.5 m/s wind resource | 7.0 m/s wind resource | 7.5 m/s wind resource Other Economic Sensitivities Fuel escalation/nflation at 6% | Diesel O&M savings 50% (versus ae | | | | Without REPI payments FCR of 0.10 7.0 m/s resource; 30% higher capital 7.5 ms resource; 30% higher capital [1] The COE values do not include REPI paym t Present Internal Cost of Value Rate of Return Energy [1] / ($202,806) 3.9% $0.130 ($12,330) 7.2% $0.093 $332,884 ($84,938) $117,027 ($31,861) $365,904 $189,720 $255,113 $210,657 $331,822 $590,069 $632,437 $916,253 $168,410 $119,136 N/A $291 ,36 $333,7 [2] [2] [2] [2] [2] [2] [2] [2] [2] [2] [2] [2] (2] N/A (2] [2] N/A N/A $0.141 $0.096 $0.094 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, IRR is not an applicable financial measure. [3] To mitigate some risk associated with the turbines limited operati turbine overhaul is assumed at 15 years. The sensitivity assu dollars. This cost was adjusted for annual inflation and then adde 2013. 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 Kh Global Energy Concepts 33 June 1999 Pp ie rade | _\ . yr) Kotzebue Electric Association — Wind Power Economic Evaluation total energy required is based on the actual electricity used in Kotzebue during 1998 and assumes an annual load growth of 2.8%. a“ = - —__ 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 4 the diesel fuel and O&M were considered. The “Wind-Diesel” calculation included consideration of the capital and operating costs of the wind project as well as the 4 - reduced fuel and O&M costs for the diesel system reduced to reflect the contribution of | the wind project to the energy mix. The difference between the two calculations represents the value of the wind project to the utility. J / The results of the comparison analysis indicate that the addition of the wind project adds value to the overall generating system. Table 14 shows a variety of scenarios / reflecting different escalation and inflation rates. The value of the wind project / increases as the escalation/inflation rate of the fuel increases. These results are \ \ Global Energy Concepts 34 June 1999 Kotzebue Electric Association — Wind Power Economic ay NO Table 13. Cost Comparison of Diesel Generation versus Wind-Diesel oe Oy NALS Diesel Only versus Wind-Diesel based on 10 AOC 15/50 wind turbines with a 30-year system life Diesel fuel efficiency 13.5/kWh/gallon Discount rate 5.0% _|(cost of debt) Cost of diesel $0.876|per gallon Cost of diesel $0.065]per kWh Diesel O&M $0.0164| per kWh Historical load growth 2.8% |annuall 0.0182) per kWh el price escalation 1.0% General Inflation 7 DIESEL ONLY Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Energy Use (MWh) [1] 22102.0 22720.9 23357.0 24011.0 24683.3 25374.5 26085.0 26815.3 27566.2 28338.0 Cost to Produce gallons required 1,637,185] 1,683,026} 1,730,151 1,778,595] 1,828,396] 1,879,591] 1,932,220] 1,986,322) 2,041,939] 2,099,113 fuel cost $1,476,525) $1,563,404) $1,655,394 $1,752,798] $1,855,932] $1,965, 135] $2,080,764] $2,203, 196] $2,332,832] $2,470,096 O&M cost [2] " $368,966) $386,882) $405,669 $425,369} $446,025] $467,684) $490,394| $514,208] $539,178] $565,360 Cost of Diesel Energy $1,845,490] $1,950,286] $2,061,064 $2,178, 167| $2,301,957] $2,432,819] $2,571,158] $2,717,404| $2,872,010| $3,035,456 Net Present Value $58,099,995 poe (ABS) | 985 | TY | OO A LS WIND-DIESEL . Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 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 $22,087 $22,529) $22,979 $23,439) $23,908) $24,386] $24,874] $25,371 $25,879] $26,396 Diesel Energy Required (MWh) 20,914.7) 21,533.5) 22,169.7 22,823.7| _23,496.0] _24,187.2| 24,897.6| 25,628.0) 26,378.9| 27,150.7]» Cost to Produce gallons required 1,549,236] 1,595,077} 1,642,202 1,690,646] 1,740,447] 1,791,642} 1,844,270] 1,898,372/ 1,953,989] 2,011,164 fuel cost $1,397,206] $1,481,705] $1,571,245) $1,666,124] $1,766,658) $1,873, 183] $1,986,053/ $2, 105,644| $2,232,354] $2,366,603 O&M cost [2] $349,145| $366,665] $385,048 $404,335) $424,570] $445,800) $468,073) $491,440] $515,955] $541,673 Cost of Diesel Energy $1,746,351] $1,848,371] $1,956,293 $2,070,459] $2,191,229] $2,318,983] $2,454, 126] $2,597,084] $2,748,308] $2,908,276 Cost of Wind-Diesel $1,768,438] $1,870,900} $1,979,273) $2,093,898] $2,215, 136] $2,343, 369| $2,479,000| $2,622,455] $2,774, 187| $2,934,672 Net Present Value $56,405,268) Savings from Wind Energy $1,694,726 - 4 i) e Wind Investment $1,457,280 — Weihok f wl Savings after Investment $237,446 a a \(1] Energy production is based on the 1998 diesel production and KEA's historical annual load growth of 2.8%. \[2) O&M costs include burdened labor rates but do not include miscellaneous administrative costs. : pry me ee 0 Global Energy Concepts 35 06/21/99 jot Kotzebue Electric Association — Wind Power Economic Evaluation Diesel Only versus Wind-Diesel based on 10 AOC 15/50 wind turbines with a 30-year system life | Diesel fuel efficiency 13.5|kWh/gallon Discount rate 5.0% __|(cost of debt, Cost of diesel $0.876] per gallon | Cost of diesel $0.065]per kWh Diesel O&M $0.0164/per kWh | Historical load growth 2.8%| annually WT O&M $0.0182|per kWh | Fuel price escalation 1.0% Gen. Inflation 2.0%! DIESEL ONLY [ Year 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Energy Use (MWh) [1] 29131.5 29947.2 30785.7 31647.7 32533.8 33444.8 | 34381.2 35343.9 36333.5 37350.9 Cost to Produce gallons required 2,157,888] 2,218,309] 2,280,422 2,344,274| 2,409,913] 2,477,391] 2,546,758) 2,618,067) 2,691,373] 2,766,731 fuel cost $2,615,436] $2,769,329] $2,932,276] _ $3,104,811] $3,287,498] $3,480,935] $3,685,753) $3,902,623] $4,132,253] $4,375,395 O&M cost [2] $592,814] $621,601] $651,786 $683,437! _$716,625| $751,424 $787,913| $826,174| $866,293] $908,360) Cost of Diesel Energy $3,208,251] $3,390,930] $3,584,062] $3,788,248] $4,004,123] $4,232,359] $4,473,666] $4,728,797| $4,998,546] $5,283,755] Net Present Value WIND-DIESEL Year 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 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 $26,924 $27,463 $28,012 $28,572 $29,144] $29,726] $30,321] $30,927| $31,546] $32,177 Diesel Energy Required (MWh) 27,944.2| _ 28,759.9 29,598.4 30,460.4| 31,346.5| 32,257.5| 33,193.9] 34,156.6] 35,146.2] 36, 163.6) Cost to Produce ar gallons required 2,069,939] 2,130,360] 2,192,472 2,256,324] 2,321,964] 2,389,442/ 2,458,808] 2,530,118] 2,603,424| 2,678,782 fuel cost $2,508,839) $2,659,533] $2,819,187) $2,988,329] $3,167,522) $3,357,359 $3,558,470| $3,771,521 $3,997,218) $4,236,309 O&M cost [2] $568,653} $596,957| $626,649 $657,797| $690,472) $724,748) $760,703) $798,420) $837,984] $879,485) Cost of Diesel Energy $3,077,492] $3,256,490] _$3,445,835| _ $3,646,126] $3,857,993] $4,082, 107| $4,319, 173] $4,569, 941| $4,835,202] $5,115,794 Cost of Wind-Diesel $3,104,416} $3,283,952) $3,473,847) $3,674,698] $3,887, 137| $4,111,833] $4,349,494] $4,600,869) $4,866,748] $5,147,971 1] Energy production is based on the 1998 diesel production and KEA's historical annual load growth of 2.8%. \[2] O&M costs include burdened labor rates but do not include miscellaneous administrative costs. Global Energy Concepts 36 06/21/99 Kotzebue Electric Association — Wind Power Economic Evaluation Diesel Only versus Wind-Diesel based on 10 AOC 15/50 wind turbines with a 30-year system life Diesel fuel efficiency 13.5|/kWh/gallon Discount rate 5.0% cost of debt) Cost of diesel .$0.876]per gallon Cost of diesel $0,065] per kWh Diesel O&M $0.0164| per kWh Historical load growth 2.8%] annually WT O&M $0.0182| per kWh Fuel price escalation 1.0% Gen. Inflation 2.0% DIESEL ONLY Year 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Energy Use (MWh) [4] 38396.7 39471.8 40577.0 41713.2 42881.1 | 44081.8 | 45316.1 | 46585.0 | 47889.3 | 49230.2 | Cost to Produce gallons required 2,844,200| _2,923,837| 3,005,705 3,089,865] 3,176,381] 3,265,319) 3,356,748] 3,450,737| 3,547,358] 3,646,684 fuel cost $4,632,843] $4,905,439] $5,194,075] $5,499,695] $5,823,297] $6,165,940! $6,528,744 $6,912,895] $7,319,650] $7,750,338) O&M cost [2] $952,470] $998,722] $1,047,220] $1,098,073] $1,151,396] $1,207,308] $1,265,934] $1,327,408 $1,391,867| $1,459,456 Cost of Diesel Energy $5,585,313] $5,904,162] $6,241,296] $6,597,768] $6,974,693] $7,373,247| $7,794,678] $8,240,303] $8,711,517| $9,209,794 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 $32,820 $33,477) $34,146 $34,829 $35,526] $36,236] $36,961} $37,700) $38,454) $39,223 Diesel Energy Required (MWh) 37,209.4 38,284.5 39,389.7 40,525.9| 41,693.8} 42,894.5] 44,1288] 45,397.6| _46,702.0| _— 48,042.9) Cost to Produce gallons required 2,756,250| 2,835,888] 2,917,755 3,001,915] 3,088,431] 3,177,370] 3,268,799] 3,362,788) 3,459,409] 3,558,735 fuel cost $4,489,585| $4,757,883] $5,042,093] $5,343,153] $5,662,058] $5,999,864) $6,357,686] $6,736,705) $7,138,174] $7,563,418 O&M cost [2] $923,018] $968,681| $1,016,578] $1,066,818] $1,119,515] $1,174,789] $1,232,766] $1,293,576) $1,357,359] $1,424,258 Cost of Diesel Energy $5,412,602] $5,726,564] $6,058,670| $6,409,971] $6,781,574] $7,174,653] $7,590,452) $8,030,281] $8,495,533) $8,987,676) Cost of Wind-Diesel $5,445,423] $5,760,041] $6,092,817| $6,444,800] $6,817,099] $7,210,890] $7,627,413] $8,067,982] $8,533,987| $9,026,899) [1] Energy production is based on the 1998 diesel production and KEA's historical annual load growth of 2.8%. [[2] O&M costs include burdened labor rates but do not include miscellaneous administrative costs. Global Energy Concepts a7 06/21/99 Kotzebue Electric Association — Wind Power Economic Evaluation Table 14. Estimated Savings from Wind Project (with 10 AOC 15/50 turbines) Wind-Diesel Fuel Savings After Scenario Savings Escalation [1 Wind Investment Baseline (see Table 13) $1,694,726 1.0% $237,620 No fuel escalation |__ $1,477,057 0.0% $19,950 Escalation increased 1% $1,954,739 2.0% $497,632 Escalation increased 2% $2,266,369 3.0% $809,262 Wind Investment $1,457,107 [1] The cash flow assumes a 2% general inflation rate in addition to the fuel escalation. eK [2] Th: $2,208 per kW. investment assumes the cost of 10 AOC 15/50 turbines with an installed cost of Global Energy Concepts 38 06/21/99 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: e 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. e 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. e 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. e 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 8.0. e Wind energy development in northwestern Alaska will benefit from some degree of economies of scale if additional projects are installed in surrounding communities. e 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 Phase 2 and 3 were built in Kotzebue. e 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. e 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 39 06/21/99 Kotzebue Electric Association — Wind Power Economic Evaluation 8.0 THE WIND ENERGY INDUSTRY Wind power has been the fastest growing energy technology worldwide during the 1990s, expanding at an annual rate of 25.7 percent between 1990 and 1997. 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 expected to come on-line in the U.S. between June 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 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 displaces 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 ? Chapman, Jamie, Steven Wiese, Edgar DeMeo, and Adam Serchuk. 1998. “Expanding Wind Power: Can Americans Afford It?” Research Report No. 6. Washington, D.C.: Renewable Energy Policy Project. November 1998. Global Energy Concepts 40 06/21/99 Kotzebue Electric Association —- Wind Power Economic Evaluation energy is unavailable or extremely expensive due to the cost and logistical difficulties of 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 41 06/21/99 Kotzebue Electric Association — Wind Power Economic Evaluation 9.0 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, KEA is also committed to supporting the integration of wind energy into the power systems of surrounding communities. KEA plans to support neighboring communities in 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 will be 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, DCRA, 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 a continuing involvement with the DCRA, Division of Energy in attaining DCRA objectives for meeting the energy needs of rural Alaska. Global Energy Concepts 42 06/21/99 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. .....ssscsessssessnessesssecscnssesessesssassersencseneencsesesecaseasensncassesesseeseeaceneseseqaeaseesesneasscseseeses 1 2.0 BACKGROUND....-.csssscscssssserssssconsensssesecscnsecsnsssensecoeecasssonsetoncsesssensanssencessessnssecesasesesessessessosesosseseess 1 3.0 WIND RESOURCE 3.1 GENERAL WIND INFORMATION .......cesseseseeseesseese 3.1.1 Battelle - Pacific Northwest Laboratory. 3.1.2 National Climatic Data Center.. 3.2, ROTZEBUE iesiscssecoststssntrcortctotwsresen 3.2.1 Annual Average Wind Speed. 3.2.2 Monthly and Diurnal Wind Speed 3.2.3 Extreme Wind Speeds... 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 4.0 THEORETICAL ENERGY PROJECTION .....cccscssssssssssssesesssssssesescssecssssssssessssssessecssessesssessesoenses 13 4D INTRODUCTION wo... eeeceteeeeeee 4.2 WIND TURBINE POWER CURVES. <i 4.2.1 Bergey.. 14 4.2.2AOC 15/50. 14 4.2.3 Northwind 100. ~15 4.2.4 Vestas V27... 16 4.2.5 Micon 225... aad. 4.3 THEORETICAL ENERGY ESTIMATE FOR THE KOTZEBLE WIND 4.3.1 Kotzebue Wind Energy Facility... 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 ...esesssesssecscsssessceseeseneees 25 4.4.1 General Theoretical Energy Estimates . 4.4.2 Theoretical Energy Estimates — Northwest Alaska... atoanob ae APPENDIX A CLIMATOLOGICAL SUMMARIES FOR SELECTED ALASKAN STATIONS ii 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 7 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 ll TABLE 3-10 JOINT FREQUENCY OF WIND SPEED AND WIND DIRECTION - OLD KEA MET TOWER SITE (110 FT) 11 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 : 15 TABLE 4-5 POWER CURVE - VESTAS V27 17 TABLE 446 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+ 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 Power Wind Speed Wind Specd Wind Speed Wind Speed Class mph (mph) mph (mph ww 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. w Wind Resource und 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 = Sant anrh won 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 Month Max2-min Peak Gust 64 72 Jul 51 45 93 63 Aug 49 53 55 66 Sep 52 54 62 51 Oct 47 60 40 49 Noy 88 63 42 46 Dec 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 of a 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 pea ' Tio aor ' ~ - . ys ee ae 515% ’ Be ig cS ’ yee ‘ < NY Ver eoor shana Sains / Pe ~~ ‘. 4 a i ~.40 AG 7 27 --7-- < me N / a , eee la amet S. . \ Level: 10m Ss Winds: Direction Wind Economics & Technology, Inc. 511 Frumert Ct. Martnaz CA 94553 St010 15020 25 to 30 a 1010 15 200 25 >= 30 (mis) | Fulsnetasooa Foc so ras.oees Number of Records Used: 43629 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Table 3-5 Wind Speed Frequency Distribution Kotzebue Airport 1 0 2 9 3 9 4 3 5 0 6 oO 7 0 8 0 9 oO 10 ° 1 31 0 12 322 fo] 13 3 ° 140 3 0 15 3s 0 16 % ° 17 37 0 18 38 ° 19 ] 0 20 * 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) i) 56 -75 ~49 0.43 417 0.00 6.2 23.9 Feb 4 23 12.0 52 0.32 1.24 0.00 5.0 19.1 Mar 39 8.7 8.0 48 0.35 1.23 0.00 5.6 219 Apr 4 20.3 23 “4 0.37 1.41 0.00 5.7 18.1 May 74 37.9 24.5 -18 0.33 1.05 0.00 2.0 12.0 Jun 85 49.7 37.8 20 052 1.43 0.01 02 2.4 Jul 8s $9.1 45 x 1.46 3.51 0.01 04 Aug 80 57.0 473 2 1.78 5.18 0.08 03 Sep 8 46.9 37.0 13 158 431 0.03 43 7.4 Oct 51 27.6 18.2 19 0.73 3.20 0.04 7A 18.0 338 13.1 2.4 6 0.59 2.22 0.09 8.6 243 37 -7.4 052 1.40 we 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 Feb Mar Apr May Jun Jul Aug Oct Nov Dec 128 139 139 15.0 139 139 15.0 16.1 15.0 17.2 150 128 11.4 11.4 128 139 13.9 15.0 Cape Lisburne 11.4 103 103 103 81 92 103 13.9 13.9 Cape Newenham 128 128 92 92 61 81 103 12.8 13.9 Cape Romanzoff 183 17.2 150 128 103 92 103 15.0 16.14 Nome 15.0 139 139 128 114 11.4 128 zi 9.2 15.0 St. Paul Island 219 183 17.2 150 15.0 11.4 128 17.2, 18.3 Tin City 8 21.9 242 28 17.22 150 139 139 16.1 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. WAspP 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 SANA A RON aa nu So 13 a~aaennnn RSRRSsaeraaer 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 o 1 2 3 4 5 6 7 8 9 SBBRB 3 88s ee ee Qa on = 2 g —_ = on — oO oooooooo0o0oco0o0o0o0 0 a SBBBALKBRRBK BSESAGHRL BR 8 oooo0oooo0o 0c 0co 0 0 0000 0080 0 0 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 2630 3135 96-60 Oto iso | 17 #«+41 #202 OF Of OO 00 15.0to 450 | 43 23 04 Of 08 00 00 45.0to 750 | 36 23 098 03 08 009 00 75.0to16.0 | 37 37 35 28 13 O98 14 105.0f01350| 21 25 22 14 06 04 02 138.0t0165.0| 16 12 08 O05 03 02 00 165.0to195.0| 22 11 10 OS O01 00 00 195.0to225.0| 27 10 O06 04 Of OO O14 225.0t0265.0/ 40 14 O05 02 Of 00 00 256.0t02860/ 54 37 25 12 03 00 00 286.0t0315.0/ 43 34 25 18 06 03 00 315.0t03450| 26 14 12 04 00 00 00 345.0to360.1/ 14 11 #09 03 Of 08 00 TOTAL 26 262 17.2 10.0 3.6 18 1.4 11 ZL Wwe 667 Le sve tz 9sz sr esz ost 92 vee 967% 29 99 ol og tL se s6 eo vor s9 6s v9 oz Or'z =OL'E owe eee ez 99% est woz 6yZ eT sve LOE 3's o2 us 6y 6s 69 el 6 ve eg wy zs OOF We 7Lt rz 96b 0% eee vee coz 08% Leb 982% 69% 9'y es ay ty 6y vs a9 el v2 vy Or vp os rEL OSS 87% Osh leh sve 0% £72 Ove Lob eo2 Srz ee ey Ov ve ‘y ee ss ug s9 ze ce of 4 eek 896% ste wb ne £07 seb Le ere tb ore rET ze oe sz ve ge zp Vs os gz st #2 oL £ $se¥/9 ssauyBnoy 16% 69% 96 ee osz bye ora wre 90°% S67 SB ol oo ze “9 ve 66 oor ez v7 gL v9 PL 002 se2 POE wt 0% oz oz osz *S% st she s0'e LOE 9 ve 99 ss v9 os 06 go. vor Vo ss os OO 1 ee a4 9st Leb oe sez azz wee ore ost We PL eS 39 9s oy us zg oe ve o6 Vs oy 1S os ret OST ez eat ost sez 607 rr ere elt oS% rz oy es vy 6c 6y zs 99 oe el ty 6e ty sz wb eee oe sh ee Loz eeb 4 ore sob 4e% 1€2% 99 se we se ZSseig ssauyBnoy OTZ BB 79 70% “vz ere £e% svz tee 661 toe 197% gL ver wer ze sl 78 SZ = 6rZ ste oof OL 6e cL vo gL 8 a6 stb eu 99 os 99 Ob coz 6eL wwe occ sez wee 967% 787 gL Vs vl ve Vor 66 ts 9s eve st toe 1Sz 6s ve vy oy Pee ore ree 787 2 sz ie oF £ Sse1D ssauyuBnoy Le 6rz cot coz rez Sszvz sez cee cot We S97 6s eu ve sl s6 Th va orb LAAs ze go. 8 002 We Lee rz ve 4 lv sz wwe ore teh 462 C97 o8 zOL ce v9 98 vor ve ser eet vl v9 SL OOoL 96% ze oz soz ore sz tre 6st S0'€ 767 v6 92 9 6 sor gz ra v9 ts 69 os ez soz sob 6rz ree ore Lez rob s62 STZ ze ve 6s Le 66 ot au v9 6s 9 4 ovz 4s@ eet bre 97% 9e7% ree sek 692 9L7 og g9 Ss 24 o6 SOL Lor vs ys 6S OL 0 SSRI ssauyBnoy ly ve 46 is » wy vy zen or ver SL e9 % vs s9 vy v9 we visi wl er ss ze zo or 37 oe OLz Orz ost Ost Oz 06 o9 oc ° 203295 eysely ‘anqazjoy J0J sishjeuy Seiyy PUIM bbe s1qeL ISO) JAasYUON] ay} pun DySD]P ‘angazj0y sof apunsy (Siauq jooyasoay yy puv arsnosay purf{ 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 Tower Height Comments (m) Bergey Three bladed; fixed pitch; 24 Widely used free yaw; upwind small turbine. Adc Three bladed, fixed pitch; Installed at free yaw: downwind Kotzebue Northwind Two bladed; fixed pitch; In Testing active yaw; upwind Vestas Three bladed; variable pitch, Proven Design; active yaw; upwind Installed at St. Paul Island Micon 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 5OkW at 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 80 - oo 3 40 i 8 20 0 ! 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 15 ow 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 = 220 deg, Speed = 58 RPM 1100 co| m0 800 70 {--——- ——— \ = 0 }- ls |g mo 1 ae = {== Paver Etec (caice)} x00 T 20 TTT I 100 }+— + ao} : 1 : 0 5 10 15 D 5 Wind Speed (rr/s) 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 Power i Power (kW) 225 223.2 225 225 20-25 225 22s >25 0 225 Figure 44 Vestas V-27 nN a oO So -a@ -2@ ND ou o Power (kW) | a oOo o 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. Wind Power Speed (kW) mps, a Table 4-6 17 Wind Resource and Theoretical Energy Estimate for Kotzebue, Alaska and the Northwest Coast Figure 4-5 Micon M700 (225kW) 250 200 Power (kW) a o 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 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/ put 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: Pa = 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 Table 4-8 Annual Theoretical Energy Output (kWh) AOC 15/50 Kotzebue, Alaska Wind Percent Aoc Wind Percent AOoc Speed Occurrence 15/50 PC Energy Speed Occurrence 15/50 PC Energy (mph) (kW) {kWh) (mph) (kW) (kWh) 0 0.0 02 645 1,209 0.0 0.1 64.9 2.2 O41 64.9 0.0 Ot 1 08 01 6.1 4.2 0.0 64.8 53 0.0 64.0 75 0.0 6&7 7.4 0.0 6.7 7.8 0.0 6.4 8.7 0.0 62.7 5.9 0.0 62.1 6.4 0.0 62.1 06 0.0 62.0 3.6 0.0 61.8 5.6 0.0 oO 3.6 0.0 35 0.0 44 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 1.2 0.0 06 0.0 04 : 0.4 TotalkWh= 122,836 0.2 z Density Adj = 8,599 04 . GrosskWh= = 131,435 0.2 02 oon oaunrk WH = ooooooo0oo0oco°9o nwo o-oo Booe00000000 © o un = SEBAFHLBR = ooooooocooooo0oc0ao0o0coco0o0o0o0o0ao0o0cna oooo0ooo0oooo0oo0o0o000 R2BR 22 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 Sep Oct Nov Dec Mean 7 6«17—~—«13 13 #15 «19 18 16 13 13 15 2 17. 19 = 12 13 «15 «19 18 «#18 «ff 13 16 «18 17 18 12 12 16 18 16 18 12 12 16 17 17 17 12 12 16 18 17° 18 13 16 16°18 #11 14 16 17 18 12 15 17 17 19 12 17 «17 18 18 12 17 17 17 19 12 18 8619 16 2 12 17 «#19 17 2 613 16 «17 16 19 613 16 «= «18 16 #19 «613 16 «17 16 «618 )~=— 13 1515 18 19 12 15 15 16 19 12 14 13 16 18 1 13 13 16 18 12 14 «15 16 17012 14 14 18 13 13 14 18 12 14 16 oOan ann wn = pees oe n- Oo 9 9 9 a 7 7 9 9 9 9 9 9 <2 at oe ok ot ot ot OoOOMn orn Ww Oe I) ee oe =~-/-0o0 0o+-000— os = °o 23 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 Energ Percentage 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 3] = = |< Turbine " “Gross kWh = kWh = 13,801 138,010 129,006 775 77,50 72,506 13,275 132,750 124,121 12,092 120.920 113,060 9,595 96,50 89,711 10,909 109,050 102,000 7,492 74,920 70,048 13,012 130,120 121,663 6,966 68,660 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 114.2, [ 123 | 134 [| 14.5 15.1 17.9 Turbine 5.0 5.5 6.0 6.5 7.0 8.0 Bergey 19,000 21,700 25,900 AOC 141,200 | 166,800 171,000 Northwind | . 163,300 | 198,500 262,100 Vestas 547,200 | 640,300 800,900 Micon 546,200 | 636,000 791,200 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. 13.9 15.8 16.2 13.9 15.8 16.2 11.4 13.0 13.3 11.4 13.0 13.3 13.9 15.8 16.2 12.8 14.6 14.9 17.2 19.7 20.1 18.3 20.9 21.4 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 ey AOC 15/50 | Northwind [ Vestas [| Micon Barrow , 169,200 201,000 682,700 677,500 Bethel , 169,200 201,000 682,700 677,500 Cape Lisburne , 109,500 122,000 453,000 456,300 Cape Newenham ‘ 109,500 122,000 453,000 456,300 Cape Romanzoff k 169,200 201,000 682,700 677.500 Nome , 144,400 167,700 580,100 578,400 St. Paul Island . 240,200 322,700 947,300 933,000 Tin City . 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 Vestas__| Micon Barrow 25% 23% 35% 34% Bethel 25% 23% 35% 34% Cape Lisburne 18% 14% 23% 23% Cape Newenham 18% 14% 23% 23% Cape Romanzoff 25% 23% 35% 34% Nome 22% 19% 29% 29% St. Paul Island 33% 42 37% 48% 47% Tin City 34% 39% 52% 51% 26 APPENDIX B FIXED CHARGE RATE CALCULATION Fixed Charge Rate assumes, 100% debt financing, 30-year depreciation & debt term Capital Cost* $591,000 Assumption 30 5.0% 10.0% Year Deprec (yrs) Cost of Debt Cost of Equi Annual Carry Cost as % of capital Year Deprec (yrs) Cost of Debt Cost of Equi Annual Carry Cost as % of capital Fixed Charge Rate 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 $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 $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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $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 8.3% 8.3% 8.2% 8.1% 8.0% 7.9% 7.8% 7.7% 7.6% 7.5% 74% 7.3% 7TA% 7.0% 6.9% 16 17 18 19 20 21 22 23 24 25 26 27 28 29 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 $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 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $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 6.7% 6.6% 6.4% 6.2% 6.0% 5.8% 5.6% 5.4% 5.2% 5.0% 47% 4.5% 4.2% 3.9% 3.6% 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 Appendix C includes the following cash flow analyses: 1. Phase 1 Project 2. Baseline 3. Baseline with Capital Cost Variation 4, Baseline with Financing Assumptions 5. Baseline with Energy Estimates 6. Baseline with Turbine Maintenance Costs 7. Baseline with Wind Resource 8. Baseline with Other Economic Sensitivities APPENDIX C CASH FLOWS Phase 1 Project a. Includes the $200k DCRA grant b. Does not include the DCRA grant ~ w KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) 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 Insurance Discount Rate 5.0% General Liability $100 per WT/year Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkW kWhigallon diesel 13.5 Fixed Land Fee $400 per WTiyear Balance of Station $1,891 perkW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,985 perkW $/kWh $0.065 Fuel Escal/Inflation 3.0% Subsidy ($,000) REPI (1998) $0.017 per kWh Total Project Costs $591 ($,000) Diesel O&M saved $0.012 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Revenue Net Energy Production (MWh) 356.2 356.2 3562 3562 3562 356.2 356.2 356.2 3562 356.2 356.2 356.2 356.2 Benefit from wind Diesel saved (gallons) 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 Diesel saved (dollars) $23,103 $23,796 $24,509 $25,245 $26,002 $26,782 $27,586 $28,413 $29,266 $30,144 $31,048 $31,979 $32,939 Other Savings Diesel O&M saved $4,286 $4,372 $4,460 $4,549 $4,640 $4,733 $4,827 $4924 $5,022 $5,123 $5,225 $5,330 $5,436 REPI Credit (activated in 7/97) $6,055 $6,055 $6,412 $6412 $6,412 $6,768 $6,768 $7,124 $7,124 $0 $0 $0 $0 Total Benefit from Wind $33,444 $34,223 $35,381 $36,205 $37,053 $38,283 $39,181 $40,461 $41,412 $35,266 $36,273 $37,309 $38,375 Total Benefit per kWh $0.0939 $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.0990 $0.1018 $0.1047 $0.1077 Expenses O&M $5,958 $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 306 312 318 325 331 338 345 351 359 366 373 380 388 Land 1,542 1542 1542 1542 1542 1,542 1542 1542 1,542 1,542 1542 1542 1,542 Operating Expenses 7,806 7,830 7,855 7,881 7,907 7,933 7,960 7,988 8,016 8,045 8,074 8,104 8,134 Net Benefit After Expenses 25,638 26,393 27,525 28,324 29,147 30,349 31,220 32,473 33,396 _ 27,222 28,199 29,205 30,241 ANNUAL CASH FLOW Less: Equity Investment $591,031 Net Benefit After Expenses 25,638 26,393 27,525 28,324 29,147 30,349 31,220 32,473 33,396 27,222 28,199 29,205 30,241 Less: Debt Payment 0 0 0 0 0 0 0 0 0 0 0 0 0 Annual Cash Flow ($591,031) 25,638 26,393 27,525 28,324 29,147 30,349 31,220 32,473 33,396 27,222 28,199 29,205 30,241 NPV of Cash Flow 1997$ ($202,806) IRR 0.5% Renewable Energy Production Incentive Year 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.017 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) a 2011 2012 2013 2014 #2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 #2025 2026 2027 356.2 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 356.2 3562 3562 366.2 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26385 26,385 26,385 26,385 26,385 26,385 26,385 $33,927 $34,945 $35,993 $37,073 $38,185 $39,331 $40,510 $41,726 $42,978 $44,267 $45,595 $46,963 $48,372 $49,823 $51,317 $52,857 $54,443 $5,545 $5,656 $5,769 $5,884 $6,002 $6,122 $6,245 $6,370 $6,497 $6,627 $6,759 $6,895 $7,032 $7,173 $7,317 $7,463 $7,612 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $o $0 $39,472 $40,601 $41,762 $42,957 $44,187 $45,453 $46,755 $48,095 $49,474 $50,894 $52,354 $53,857 $55,404 $56,996 $58,634 $60,320 $62,055 $0.1108 $0.1140 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $6,228 $6,251 $6,276 $6,300 $6,325 $6,351 $6,377 $6,404 $6,431 $6,459 $6,488 $6517 $6546 $6576 $6,607 $6,638 $6,670 396 404 412 420 428 437 446 455 464 473 483 492 502 512 522 533 543 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1,542 8165 8197 8229 8262 8296 8330 8365 8401 8437 8474 8512 8551 8590 8630 8,671 8,713 8,756 31,307 32,404 33533 34695 35,891 37,123 38390 39,695 41,037 42419 43,842 45,307 46,814 48366 49,963 51,607 53,299 31,307 32,404 33,533 34,695 35,891 37,123 38,390 39,695 41,037 42,419 43,842 45,307 46,814 48,366 49,963 51,607 53,299 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 31,307 32,404 33,533 34,695 35,891 37,123 38,390 39,695 41,037 42,419 43,842 45,307 46,814 48366 49,963 51,607 53,299 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.198 MW Debt 0% O&M (ist yr) Turbine Rating 66 kW Equity 100% Parts $300 per WTi/year Turbine Count 3 Term (years) Labor $0.014 per kWh Capacity Factor 20.5% Interest rate Insurance Discount Rate 5.0% General Liability $100 per WT/year Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkW kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/year Balance of Station $1,891 perkW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,985 perkW $/kWh $0,065 Fuel Escal/inflation 3.0% Subsidy $200 ($,000) REPI (1998) $0.017 per kWh Total Project Costs $391_($,000) Diesel O&M saved $0.012 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Revenue Net Energy Production (MWh) 356.2 356.2 3562 3562 356.2 356.2 356.2 3562 3562 3562 3562 3562 3562 Benefit from wind Diesel saved (gallons) 26,385 26,385 26,385 26,385 26385 26,385 26,385 26,385 26385 26,385 26,385 26,385 26,385 Diesel saved (dollars) $23,103 $23,796 $24,509 $25,245 $26,002 $26,782 $27,586 $28,413 $29,266 $30,144 $31,048 $31,979 $32,939 Other Savings Diesel O&M saved $4,286 $4372 $4,460 $4,549 $4640 $4,733 $4827 $4924 $5,022 $5,123 $5,225 $5,330 $5,436 REPI Credit (activated in 7/97) $6,055 $6,055 $6,412 $6,412 $6412 $6,768 $6,768 $7,124 $7,124 $0 $0 $0 $0 Total Benefit from Wind $33,444 $34,223 $35,381 $36,205 $37,053 $38,283 $39,181 $40,461 $41,412 $35,266 $36,273 $37,309 $38,375 Total Benefit per kWh $0.0939 $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.0990 $0.1018 $0.1047 $0.1077 Expenses O&M $5,958 $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 306 312 318 325 331 338 345 351 359 366 373 380 388 Land 1,542 1542 1542 1542 1542 1,542 1542 1542 1542 1542 1542 1542 1,542 Operating Expenses 7,806 7,830 7,855 7,881 7,907 7,933 7,960 7,988 8016 8045 8074 8104 8,134 Net Benefit After Expenses 25,638 26,393 27,525 28,324 29,147 30,349 31,220 32,473 33,396 27,222 28,199 29,205 30,241 ANNUAL CASH FLOW ‘ Less: Equity Investment $391,031 Net Benefit After Expenses 25,638 26,393 27,525 28,324 29,147 30,349 31,220 32,473 33,396 27,222 28,199 29,205 30,241 Less: Debt Payment 0 0 0 0 0 0 0 0 0 0 0 0 0 Annual Cash Flow ($391,031) 25,638 26,393 27,525 28,324 29,147 30,349 31,220 32,473 33,396 27,222 28,199 29,205 30,241 NPV of Cash Flow 1997$ ($12,330) IRR 4.6% Renewable Energy Production Incentive Year 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 REPI Incentive Payment per kWh 0.017 0.017 0.017 0.018 0.018 0018 0.019 0.019 0.020 0.020 (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) — 2011 2012 2013 2014 #2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 #=%2025 #2026 #2027 356.2 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 3562 356.2 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 26,385 $33,927 $34,945 $35,993 $37,073 $38,185 $39,331 $40,510 $41,726 $42,978 $44,267 $45,595 $46,963 $48,372 $49,823 $51,317 $52,857 $54,443 $5,545 $5,656 $5,769 $5,884 $6,002 $6,122 $6,245 $6,370 $6,497 $6627 $6,759 $6895 $7,032 $7,173 $7,317 $7,463 $7,612 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $39,472 $40,601 $41,762 $42,957 $44,187 $45,453 $46,755 $48,095 $49,474 $50,894 $52,354 $53,857 $55,404 $56,996 $58,634 $60,320 $62,055 $0.1108 $0.1140 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $6,228 $6,251 $6,276 $6,300 $6,325 $6,351 $6,377 $6,404 $6,431 $6,459 $6,488 $6517 $6,546 $6576 $6,607 $6,638 $6,670 396 404 412 420 428 437 446 455 464 473 483 492 502 512 522 533 543 1,542 1542 1,542 1542 1542 1542 1,542 1542 1542 1542 1542 1542 1542 1542 1542 1542 1,542 8,165 8197 8229 8262 8296 8330 8365 8,401 8,437 8,474 8512 8,551 8590 8630 8671 8713 8,756 31,307 32,404 33,533 34,695 35,891 37,123 38,390 _39,695__41,037_ 42,419 43,842 45,307 __ 46,814 48,366 __49,963_51,607__53,299 31,307 32,404 33,533 34,695 35,891 37,123 38,390 39,695 41,037 42,419 43,842 45,307 46,814 48,366 49,963 51,607 53,299 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O 0 31,307 32,404 33,533 34,695 35,891 37,123 38,390 39,695 41,037 42,419 43,842 45,307 46,814 48366 49,963 51,607 53,299 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 APPENDIX C CASH FLOWS Baseline Assumes potential reductions; 7 wind turbines; 100% debt, no subsidy) KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 per KW kWhgallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per KW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 perkW = $/kKWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 $94,735 Total Benefit per kWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 29,798 64,341 66,208 68,129 70,937 72,972 75,898 __78,053 80,272 83,387 68,283 70,702 _73,192 75,755 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 75,755 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (3,377) ___ (2,010) (143) 1,778 4,586 6,621 9547 11,703 13,921 17,036 1,933 4,352 _—6,841 9,404 NPV of Cash Flow 1999$ $233,315 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $o $o $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $14,531 $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 19,052 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 78,392 81,107 83,902 86,778 —89,738_— 92,785 95,922 99,150 102,473 105,894 109,415 __ 113,039 116,769 120,609 __124,562__ 128,630 __—6 4,507 78,392 81,107 83,902 86,778 89,738 92,785 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 64,507 (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) 12,042 14,756 17,551 20,427 23,387 26,434 29,571 32,799 36,122 39,543 43,064 46,688 50,418 54,258 58,211 62,280 31,332 APPENDIX C CASH FLOWS Baseline with Capital Cost Variation a. 20% higher costs b. 10% lower costs KEA Wind Farm Project Configuration 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,313 per KW kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,336 per KW $/galion $0.876 Variable Land Fee $0.001 per KWh Total $2,649 per kW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,224 ($,000) Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 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 29,798 64,341 66,208 68,129 70,937 72,972 75,898 _ 78,053 80,272 83,387 68,283 70,702 92 ANNUAL CASH FLOW Less: Equity Investment $0 ‘ Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 Debt Payment (39,810) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) Annual Cash Flow 10,012) 15,280) 13,413) (11,492) 8,684 (6,649) __(3,723)__(1,568) 651 3,766 (11,338) (8,919) _ (6,429) NPV of Cash Flow 1999$ $34,177 Renewable Energy Production Incentive Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 REPI Incentive Payment per KWh 0.017 0.018 0.018 0.018 0.019 0.019 0.020 0.020 0.020 0.021 0.000 0.000 Financing Option Operating Costs (in 1999$) 2012 831.1 61,565 $81,538 $13,197 $0 $94,735 $0.1140 $14,477 906 3,598 18,980 75,755 73, . (REPI rate is adjusted based on annual inflation but only changed when it rounds to the next tenth of a cent) 75,755 (79,621) 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $14,531 $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 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 19,052 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 78,392 81,107 83,902. 86,778 ~— 89,738 ~— 92,785 95,922 99,150 102,473 105,894 109.415 113,039 116,769 120,609 124,562 128,630 _—46 4,507 78,392 81,107 83,902 86,778 89,738 92,785 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 64,507 (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (79,621) (39,810) 1,229) 1,486 4,281 7,157 10,117 13,164 16,301__—«19,529_22,852__—26,273 29,794 33,418 37,148 40,988 44,941 49,009 24,697 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (ist 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $985 per KW kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,002 per KW $/galion $0.876 Variable Land Fee $0.001 per kWh Total $1,987 perkKW = $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $918 ($,000) Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 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 18,511 18574 18639 18,704 18,771 18,839 18,909 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 Debt Payment (29,858) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) Annual Cash Flow (60) 4,625 6,492 8,413 11,221 13,256 16,182 18,338 20,556 23,671 6568 10,987 13,476 NPV of Cash Flow 1999$ $332,884 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 831.1 61,565 $81,538 $13,197 $0 $94,735 $0.1140 $14,477 906 3,598 18,980 75,755 75,755 (59,716) 16,039 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $14,531 $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 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 19,052 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 78,392 81,107 _—83,902_—— 86,778 ~— 89,738 — 92,785 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 _128,630_—6 4,507 78,392 81,107 83,902 86,778 89,738 92,785 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 64,507 (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) ‘ (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (59,716) (29,858) 18677 21,394 24,186 _-27,062_—30,022_ 33,070 ~— 36,206 = 39,434 42,757 — 46,178 49,699 53,323_—57,053__—60,893 64,846 68.915 34,650 APPENDIX C CASH FLOWS Baseline with Financing Assumptions a. 20-year debt financing & depreciation b. 6% interest on debt KEA Wind Farm ne ar=>T TuEnEEE-—<Snnsy- mT SnE 7-7” < GlnInIID Inn SISSn Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count UL Term (years) 20 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkW —_ kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per kW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 perkW = $/kWh $0.065 Fuel Escal/nflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 $94,735 Total Benefit per kWh $0.0961 $0.,0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 18574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After Expenses 29,798 64,341 66,208 68129 70,937 72,972 _ 75,898 —78,053_—80,272 83,387 68,283 __70,702__ 73,192 __—75,755 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 75,755 Debt Payment (40,923) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) Annual Cash Flow (11,125) (17,504) _(15,638)__(13,717) (10,908) (8,873) __(5,948)__(3,792)__(1,573) 1,541 (13,562) (11,143) (8,653) 6,091 NPV of Cash Flow 1999$ ($84,934) 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 831.1 831.1 831.1 831.1 831.1 831.1 415.6 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $50,140 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $7,580 $0 $o $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $57,720 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $14,531 $14,586 $14,643 $14,701 $14,759 $14,819 $9,000 924 942 961 980 1,000 1,020 520 3,598 3,598 3,598 3,598 3,598 3,598 1,799 19,052 19,126 19,202 19,279 19,357 19,437 11,320 78,392 81,107 83,902 86,778 —89,738_ ~— 92,785 46,401 78,392 81,107 83,902 86,778 89,738 92,785 46,401 (81,845) (81,845) (81,845) (81,845) (81,845) (81,845) (40,923) (3,453) _—(738)_—2,056 = 4.932 7,893 10,940 5,478 KEA Wind Farm Project Configuration Financing Option Project Size 0.462 MW Debt 100% Turbine Rating 66 KW Equity 0% Turbine Count 7 Term (years) 30 Capacity Factor 20.5% Interest rate 6.0% Discount Rate 5.0% Project Costs (US$) Revenue Equipment Cost $1,094 per KW kWhvgallon diesel 13.5 Balance of Station $1,114 per kW $/galion $0.876 Total $2,208 per KW $KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Operating Costs (in 1999$) O&M (1st yr) Parts $300 per WT/year Labor $0.014 per kWh 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 $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 $94,735 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 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 18909 18,980 Net Benefit After Expenses 29,798 64,341 66,208 68,129 ~—70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702__73,192__—75,755 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 75,755 Debt Payment (37,050) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) (74,100) Annual Cash Flow (7,252) (9,759) (7,892) _(5,971)__(3,163) (1,128) 1,798 3,953 6,172 9,287 __ (5,817) _ (3,398) (908) 1,655 NPV of Cash Flow 1999$ $117,027 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $14,531 $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 19,052 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 78,392 81,107 —83,902__— 86,778 —89,738_ ~— 92,785 — 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 __—64,507 78,392 81,107 83,902 86,778 89,738 92,785 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 64,507 (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) 4,292 7,007 9,801 12,678 15,638 18,685 21,822. 25,050 28,373 31,794 35,315 38,939 42,669 46,509 50,462 54,530 27,457 APPENDIX C CASH FLOWS Baseline with Turbine Maintenance Costs a. 20% higher expenses b. 10% lower expenses c. Major overhaul at 15 years ($5 per WT) KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkW —_ KWhygallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 perkW — $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per KW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 ($,000) Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 $94,735 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 3598 3,598 3,598 3,598 Operating Expenses 11,725 20,994 21,060 921,127 21,195 21,265 21,336 21,409 21,483 21,558 21,635 21,714 21,794 21,875 Net Benefit After Expenses 28,202 61,561 63,419 65,331 68,131 70,156 73,073___—-75,219_ 77,428 80,533 65,419 67,828 70,307 _72,859 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 28,202 61,561 63,419 65,331 68,131 70,156 73,073 75,219 77,428 80,533 65,419 67,828 70,307 72,859 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (4,973) (4,790) (2,932) __ (1,020) 1,780 3,806 6,722 8,868 11,077 14,182 931 1,477___3,957 NPV of Cash Flow 1999$ $189,720 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 nN a 7 roan 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $o $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.155S5 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $17,437 $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 $11,621 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 21,959 22,044 22,130 22,219 22,309 22,401 22,495 22,590 22,688 22,787 22,889 22,993 23,098 23,206 23,316 23,428 14,054 75,486 78,190 80,973 83,838 86,786 89,821 92,946 96,162 99,472 102,879 106,387 109,998 113,714 117,540 __121,479 _ 125,533 62,571 75,486 78,190 80,973 83,838 86,786 89,821 92,946 96,162 99,472 102,879 106,387 109,998 113,714 117,540 121,479 125,533 62,571 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 9,135 11,839 14,622 17,487__- 20,435 23,471 26,595 29,811 33,121 36,529 40,036 ——43,647__—47,363___—51, 189 55,128 59,182___—-29,395 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (ist yr) Turbine Rating 66 KW Equity 0% Parts $270 per WTi/year Turbine Count 7 Term (years) wn Labor $0.013 per KWh Capacity Factor 20.5% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perKW — KWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per kW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per KW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 $94,735 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 30,596 65,731 67,602__ 69,528 72,340 74,380 7,310 _79,471 81,694 84,814 69,715 72,139 74634 77,202 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 30,596 65,731 67,602 69,528 72,340 74,380 77,310 79,471 81,694 84,814 69,715 72,139 74634 77,202 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (2,579) (620) 1,251 3,177 5,990 8,029 10,959 13,120 15,343 18463 3,365 5,789 ~— 8,284 10,852 NPV of Cash Flow 1999$ $255,113 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $13,078 $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 $8,715 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 17,599 17,668 17,737 17,809 17,881 17,955 18,030 18,107 18,186 18,266 18,348 18,431 18,516 18,603 18,691 18,781 11,148 79,845 82,566 85,366 88,248 91,214 94,267 97,410 100,644 103,974 107,401 110,928 114,559 118,297 122,144 126,103 130,179 65,476 79,845 82,566 85,366 88,248 «(91,214 94,267 97,410 100,644 103,974 107,401 110,928 114,559 118,297 122,144 126,103 130,179 65,476 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) | (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 13,495 16,215 19,015 21,897 24,863 27,916 31,059 34,294 37,623 41,050 ~— 44,578 ~— 48,208 51,946 = 55,793 59,753 63,829 32,300 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 per kW kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 perkW _—$/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 perkKW = $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $39,927 $82,555 $84,479 $86,458 $89,326 $91,421 $94,409 $96,628 $98,911 $102,091 $87,054 $89,542 $92,101 $94,735 Total Benefit per kWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 18574 18,639 18,704 18,771 18,839 18,909 18,980 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 _78,053_——-80,272 83,387 __ 68,283 70,702 73,192 _—75,755 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 29,798 64,341 66,208 68,129 70,937 72,972 75,898 78,053 80,272 83,387 68,283 70,702 73,192 75,755 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (3,377) (2,010) (143) 1,778 4,586 6,621 9,547 __ 11,703 13,921 17,036 1,933 4,352 6,841 9,404 NPV of Cash Flow 1999$ $210,657 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 <a 831.1 831.1 831.1 415.6 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $o $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.155S $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $61,636 $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 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 3,598 1,799 66,157 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 20,330 12,117 31,287 ___ 81,107 83,902 86,778 —89,738_ 92,785 95,922 99,150 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 _—64,507 31,287 81,107 83,902 86,778 89,738 92,785 95,922 99,150 \ 102,473 105,894 109,415 113,039 116,769 120,609 124,562 128,630 64,507 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (35,063) __ 14,756 17,551 20,427 23,387 26,434 29,571 32,799 36,122 39,543 43,064 46,688 = 50,418 54,258 58,211 62,280 31,332 APPENDIX C CASH FLOWS Baseline with Wind Resource a. 6.5 m/s wind resource b. 7.0 m/s wind resource c. 7.5 m/s wind resource KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WTiyear Turbine Count 7 Term (years) 0 Labor $0.014 per kWh Capacity Factor 22.1% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkKW —_ kKWhygallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per KW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per KW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 ($,000) Diesel O&M saved $0.012 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) 33,069 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 Diesel saved (dollars) $29,824 $61,438 $63,281 $65,179 $67,135 $69,149 $71,223 $73,360 $75,561 $77,827 $80,162 $82,567 $85,044 $87,595 Other Savings Diesel O&M saved $5,480 $11,179 $11,403 $11,631 $11,863 $12,101 $12,343 $12,589 $12,841 $13,098 $13,360 $13,627 $13,900 $14,178 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 $42,893 $88,688 $90,755 $92,881 $95,962 $98,214 $101,423 $103,807 $106,259 $109,676 $93,522 $96,194 $98,944 $101,773 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 32,298 69,541 71,551 73,619 76,641 78,831 81,979 84,299 _— 86,688 90,038 73,818 76,422 79,102 _81,860 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 32,298 69,541 71,551 73,619 76,641 78,831 81,979 84,299 86,688 90,038 73,818 76,422 79,102 81,860 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (877) 3,191 5,200 7,268 10,290 12,481 15,628 17,949 20,337 23,688 7,467 10,071 12,751 15,509 NPV of Cash Flow 1999$ $331,822 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 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 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 66,138 33,069 $90,223 $92,930 $95,718 $98,589 $101,547 $104,593 $107,731 $110,963 $114,292 $117,721 $121,252 $124,890 $128,637 $132,496 $136,471 $140,565 $72,391 $14,461 $14,750 $15,045 $15,346 $15,653 $15,966 $16,286 $16,611 $16,944 $17,283 $17,628 $17,981 $18,340 $18,707 $19,081 $19,463 $9,926 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $104,684 $107,680 $110,763 $113,936 $117,200 $120,560 $124,017 $127,575 $131,236 $135,003 $138,881 $142,871 $146,977 $151,203 $155,552 $160,028 $82,317 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $15,405 $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 $16,200 $16,363 $10,121 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1104 1126 1148 1,471 1,195 1,219 1,243 634 3,657 3,657. 3,657. Ss 3,657, «3,657 «3,657. «Ss 3,657. «Ss «3,657. Ss «3,657. «Ss 3,657 3,657. «3,657. «Ss «3,657 «Ss -3,657. «3,657. «Ss: 3,657 —s«‘1,829 19,985 20,059 20,135 20,212 20,290 20,370 20,452 20,535 20620 20,706 20,794 20,885 20,976 21,070 21,166 21,263 12,583 84,699 _87,621 90,629 93,724 96,910 100,190 103,565 107,040 110,616 114,297 118,086 121,986 126,001 130,133 134,386 138,765 69,734 84699 87,621 90,629 93,724 96,910 100,190 103,565 107,040 110,616 114,297 118,086 121,986 126,001 130,133 134,386 138,765 69,734 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 18,348 21,270 24,278 27,373 30,560 33,839 37,215 40,689 44,265 47,946 51,735 55,635 59,650 63,782 68,035 72,414 _ 36,558 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count lg Term (years) 30 Labor $0.014 per kWh Capacity Factor 26.1% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation © 2.0% per year Equipment Cost $1,094 perkW —__ kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per kW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per kW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.012 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) 39,065 78,130 78,130 78,130 78,130 78,130 78,130 78130 78,130 78,130 78,130 78,130 78,130 78,130 Diesel saved (dollars) $35,231 $72,576 $74,754 $76,996 $79,306 $81,685 $84,136 $86,660 $89,260 $91,938 $94,696 $97,537 $100,463 $103,477 Other Savings Diesel O&M saved $6,473 $13,206 $13,470 $13,739 $14,014 $14,294 $14,580 $14,872 $15,169 $15,473 $15,782 $16,098 $16,420 $16,748 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 $50,670 $104,768 $107,209 $109,721 $113,361 $116,020 $119,811 $122,627 $125,524 $129,560 $110,478 $113,634 $116,883 $120,225 Total Benefit per kWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 3813 3813 3,813 3,813 3,813 3,813 3,813 3,813 3813 3,813 3813 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 38,852 _ 83,175 _—-85,559 88,013 91,593 94192 _97,921 100,674 103,507 107,477 _88,328 91,416 94595 _ 97,866 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 38,852 83,175 85,559 88,013 91,593 94,192 97,921 100,674 103,507 107,477 88,328 91,416 94595 97,866 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 5,676 16,824 19,208 21,662 25,242 27,841 31,570 34,323 37,156 41,126 21,977 25,065 28,244 31,515 NPV of Cash Flow 1999$ $590,069 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) w 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 78,130 78130 78,130 78,130 78130 78130 78,130 78,130 78,130 78130 78130 78,130 78130 78130 78,130 78,130 39,065 $106,581 $109,778 $113,072 $116,464 $119,958 $123,557 $127,263 $131,081 $135,014 $139,064 $143,236 $147,533 $151,959 $156,518 $161,213 $166,050 $85,516 $17,083 $17,425 $17,773 $18,129 $18,491 $18,861 $19,238 $19,623 $20,016 $20,416 $20,824 $21,241 $21,666 $22,099 $22,541 $22,992 $11,726 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $o $0 $0 $0 $0 $123,664 $127,203 $130,845 $134,593 $138,449 $142,418 $146,502 $150,704 $155,029 $159,480 $164,060 $168,774 $173,625 $178,617 $183,754 $189,041 $97,241 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $17,695 $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 $11,266 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1,126 1,148 1,171 1,195 1,219 1,243 634 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 3,813 1,906 22,431 22,505 22,581 22,657 22,736 22,816 22,897 22,981 23,066 23,152 23,240 23,331 23,422 23,516 23,612 23,709 13,806 101,233 104,698 108,264 111,935 115,713 119,602 123,604 127,724 131,964 136,328 140,820 145,443 150,202 155,101 __ 160,142 165,332__— 83,435 101,233 104,698 108,264 111,935 115,713 119,602 123,604 127,724 131,964 136,328 140,820 145,443 150,202 155,101 160,142 165,332 83,435 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 34,882 38,347 41,914 45,584 _49,362_—«53,251__—57,253__—61,373__—«65,613 «69.977 74,469 ~—79,092 83,851 «88,750 93,792 98,981 _—50,260 = KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (‘st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count a Term (years) 30 Labor - $0.014 per KWh Capacity Factor 26.7% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkW —_ kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 perkW —$/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 perkW = $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 ($,000) _Diesel O&M saved $0.012 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) 40,048 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 Diesel saved (dollars) $36,118 $74,404 $76,636 $78,935 $81,303 $83,742 $86,255 $88,842 $91,507 $94,253 $97,080 $99,993 $102,992 $106,082 Other Savings Diesel O&M saved $6,636 $13,538 $13,809 $14,085 $14,367 $14,654 $14,947 $15,246 $15,551 $15,862 $16,180 $16,503 $16,833 $17,170 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 $51,946 $107,406 $109,909 $112,484 $116,215 $118,941 $122,828 $125,715 $128,685 $132,822 $113,260 $116,496 $119,826 $123,252 Total Benefit per kWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 4 =22,291 «9 22,354 = 22,419 22,484 22,551 22,620 22,689 22,760 Net Benefit After Expenses 39,927 85,412 87,857 90,374 94046 96,712 100,537 103,360 106,266 110,338 90,709 93,876 _ 97,136 __ 100,492 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 39,927 85,412 87,857 90,374 94,046 96,712 100,537 103,360 106,266 110,338 90,709 93,876 97,136 100,492 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 6,752__19,061 21,507 24,024 __—-27,695 30,361 34,186 37,009 39,915 43,987 24,358 27,525 30,786 34,141 NPV of Cash Flow 1999$ $632,437 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) 1,081.3 1,081.3 1,081.3. 1,081.3 1,081.3 1,081.3 1,081.3 1,081.3 80,097 $109,265 80,097 $112,543 80,097 $115,919 $119,396 80,097 80,097 $122,978 80,097 $126,668 80,097 $130,468 80,097 $134,382 $17,513 $17,864 $18,221 $18,585 $18,957 $19,336 $19,723 $20,117 $126,778 $0.1172 $130,406 $0.1206 $134,140 $137,982 $0.1276 $141,935 $0.1313 $146,004 $0.1350 $150,191 $0.1389 $154,499 $0.1241 $0.1429 $18,071 $18,126 $18,183 $18,241 $18,299 $18,359 $18,421 $18,483 22,833 03,945 22,907 107,500 22,982 111,158 23,059 114,923 23,137 118,798 23,217 122,787 23,299 126,892 23,382 131,117 131,117 (66,351) (66,351) (66,351) 103,945 (66,351) 37,594 107,500 111,158 (66,351) (66,351) 41,149 114,923 (66,351) 48,572 118,798 (66,351) 52,447 122,787 (66,351) 56,436 _ 60,541 126,892 44,807 64,766 _ 69,115 , - 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 S407 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 40,048 $138,413 $142,566 $146,843 $151,248 $155,785 $160,459 $165,273 $170,231 $87,669 $20,520 $20,930 $21,349 $21,776 $22,211 $22,655 $23,108 $23,571 $12,021 $0 $0 $0 $0 $0 $0 $0 $0 $0 $158,933 $163,496 $168,191 $173,023 $177,996 $183,114 $188,381 $193,801 $99,690 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $18,547 $18,612 $18,676 $18,745 $18,814 $18,884 $18,956 $19,029 $11,454 1,082 1,104 1,261,448) 1,171 1,195 1,219 1,243 634 3,838 «= 3,838 «3,838 «= «3,838 «= «3,838 = 3,838 «= 3,838 «= 3,838,919 23,467 23,553 23,642 «23,732 «23,824 «23,917 24,013 24,110 14,007 135,466 139,942 144,549 149,292 154,173 159,197 164,368 169,691 _ 85,683 135,466 139,942 144549 149,292 154,173 159,197 164,368 169,691 85,683 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 73,591 78,199 82,941 _87,822__-92,846 98,017 _ 103,340 _ 52,508 APPENDIX C CASH FLOWS Baseline with Other Economic Sensitivities a. Fuel escalation/inflation at 6% b. Diesel O&M Savings 50% (versus 75%) c. Without REPI payments d. 7.0 m/s resource; 30% higher capital e. 7.5 m/s resource; 30% higher capital - KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WT/year Turbine Count a Term (years) 30 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation ° 2.0% per year Equipment Cost $1,094 perkW —_ kKWhigalion diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 perkW = $/galion $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per KW $/KWh $0.065 Fuel Escal/Inflation 6.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 ($,000) _ Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $28,570 $60,569 $64,203 $68,055 $72,138 $76,467 $81,055 $85,918 $91,073 $96,537 $102,329 $108,469 $114,977 $121,876 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 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 $40,736 $85,935 $89,777 $93,841 $98,972 $103,522 $109,166 $114,259 $119,648 $126,183 $114,766 $121,154 $127,916 $135,073 Total Benefit per KWh $0.0980 $0.1034 $0.1080 $0.1129 $0.1191 $0.1246 $0.1313 $0.1375 $0.1440 $0.1518 $0.1381 $0.1458 $0.1539 $0.1625 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 18909 18,980 Net Benefit After Expenses 30,607 67,721 71,506 75,512 _—80,584 85,072 90,655 95,685 101,010 107,479 95,994 102,315 _109,007__ 116,093. ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 30,607 67,721 71,506 75,512 80,584 85,072 90,655 95,685 101,010 107,479 95,994 102,315 109,007 116,093 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (2,569) 1,370 5,155 9,161 14,233 18,721 24,304 29,334 34,659 41,128 29,644 35,964 42,656 49,742 NPV of Cash Flow 1999$ $916,253 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $129,189 $136,940 $145,156 $153,866 $163,098 $172,884 $183,257 $194,252 $205,907 $218,261 $231,357 $245,239 $259,953 $275,550 $292,083 $309,608 $164,092 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $o $0 $0 $0 $0 $0 $o $0 $o $0 $o $0 $0 $0 $0 $0 $0 $142,650 $150,670 $159,161 $168,151 $177,668 $187,746 $198,416 $209,715 $221,679 $234,349 $247,766 $261,976 $277,025 $292,964 $309,845 $327,725 $173,332 $0.1716 $0.1813 $0.1915 $0.2023 $0.2138 $0.2259 $0.2387 $0.2523 $0.2667 $0.2820 $0.2981 $0.3152 $0.3333 $0.3525 $0.3728 $0.3943 $0.4171 $14,531 $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 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 1126 1148 1171 1,195 1,219 1,243 634 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 1,799 19,052 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 «20,330 = 12,117 123,597 131,544 139,960 148,872 158,311 168,309 178,897 190,113 __201,992__214,576 227,905 242,024 256,981_272,826 289,612 _ 307,395 161,215 123,597 131,544 139,960 148,872 158,311 168,309 178,897 190,113 201,992 214,576 227,905 242,024 256,981 272,826 289,612 307,395 161,215 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (68,351) (66,351) (66,351) (66,351) (33,175) 57,247 65,193 73,609 82,521 91,961 101,958 112,547 123,762 135,641 148,225 161,554 175,673 190,631__ 206,476 ~—- 223,261 241,044 128,040 - KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 kW Equity 0% Parts $300 per WTiyear Turbine Count 7 Term (years) 3 Labor $0.014 per kWh Capacity Factor 20.5% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 per kW kWh/galion diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 perkW —$/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 perkW = $/kWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.008 per kWh Wind Power Project - KEA FINANCIAL CASHFLOW - 30 year Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 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 Benefit from wind Diesel saved (gallons) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $3,401 $6,937 $7,076 = $7,218 += $7,362 $7,509 $7,659 $7,812 $7,969 $8,128 $8,291 $8,456 $8,626 $8,798 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 $38,227 $79,086 $80,941 $82,849 $85,645 $87,667 $90,579 $92,721 $94,926 $98,027 $82,909 $85,313 $87,788 $90,336 Total Benefit per kWh $0.0920 $0.0952 $0.0974 $0.0997 $0.1030 $0.1055 $0.1090 $0.1116 $0.1142 $0.1179 $0.0998 $0.1026 $0.1056 $0.1087 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 350 714 728 743 758 773 788 804 820 837 853 870 906 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 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 28,098 60,872 62,670 -64,520___—«67,256 69,218 72,068 74,147 76,288 79,323 64,138 66,474 68879 71,356 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 28,098 60,872 62,670 64,520 67,256 69,218 72,068 74,147 76,288 79,323 64,138 66,474 68,879 71,356 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (5,078) (5,478) (3,681) (1,831) 905 2,867 5,717 7,796 9,937 12,972 (2,213) 123 5,005 NPV of Cash Flow 1999$ $168,410 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 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $8,974 $9,154 $9,337 $9,523 $9,714 $9,908 $10,106 $10,308 $10,515 $10,725 $10,939 $11,158 $11,381 $11,609 $11,841 $12,078 $6,160 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $o $0 $0 $0 $0 $0 $o $92,958 $95,657 $98,435 $101,295 $104,238 $107,268 $110,387 $113,598 $116,903 $120,304 $123,806 $127,411 $131,122 $134,942 $138,874 $142,922 $73,544 $0.1118 $0.1151 $0.1184 $0.1219 $0.1254 $0.1291 $0.1328 $0.1367 $0.1407 $0.1447 $0.1490 $0.1533 $0.1578 $0.1624 $0.1671 $0.1720 $0.1770 $14,531 $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 $9,684 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1104 1126 1,148 1171 1,195 1,219 1,243 634 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 3598 1,799 19,052 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 19,773 19,862 19,952 20,043 20,137 20,233 «20,330: 12,117 73,905 _76,530__79,233 «82,016 _—<84,881__—87,831__—90,869—93,996_—97,216 100,531 103,945 107,460 111,078 114,805 118,641 122,591 _ 61,428 73,905 76,530 79,233 82,016 84,881 87,831 90,869 93,996 97,216 100,531 103,945 107,460 111,078 114,805 118,641 122,591 61,428 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 7,555 10,180 12,882 15,665 18530 21,480 24,518 27,645 30,865 34,180 37,594 41,109 44,728 48.454 52,290 56,241 28,252 KEA Wind Farm Financing Option Operating Costs (in 1999$) Project Configuration 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 per KW kWh gallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 perkW —$/gallon $0.876 Variable Land Fee $0.001 per KWh Total $2,208 per KW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) per kWh Total Project Costs $1,020 ($,000 Diesel O&M saved $0.012 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) 30,782 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 Diesel saved (dollars) $27,762 $57,189 $58,904 $60,672 $62,492 $64,366 $66,297 $68,286 $70,335 $72,445 $74,618 $76,857 $79,163 $81,538 Other Savings Diesel O&M saved $5,101 $10,406 $10,614 $10,826 $11,043 $11,264 $11,489 $11,719 $11,953 $12,192 $12,436 $12,685 $12,938 $13,197 REPI Credit (1st 10 years) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Benefit from Wind $32,862 $67,595 $69,518 $71,498 $73,535 $75,630 $77,786 $80,005 $82,288 $84,637 $87,054 $89,542 $92,101 $94,735 Total Benefit per KWh $0.0791 $0.0813 $0.0836 $0.0860 $0.0885 $0.0910 $0.0936 $0.0963 $0.0990 $0.1018 $0.1047 $0.1077 $0.1108 $0.1140 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 22,734 49,381 51,247 53,169 55,146 57,181 59,275 _ 61,431 63,650 65,933 68,283 70,702 _73,192 75,755 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 22,734 49,381 51,247 53,169 55,146 57,181 59,275 61,431 63,650 65,933 68,283 70,702 73,192 75,755 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (10,442) (16,970)__(15,103) (13,182) (11,205) (9,170) (7,076) _ (4,920) (2,701) (418) 1,933 4,352 6,841 9,404 NPV of Cash Flow 1999$ $119,136 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) 2022 2023 2024 2025 2026 2027 2028 2029 831.1 831.1 831.1 831.1 831.1 831.1 831.1 415.6 61,565 61,565 61,565 61,565 61,565 61,565 61,565 30,782 $109,580 $112,867 $116,253 $119,741 $123,333 $127,033 $130,844 $67,385 $16,087 $16,409 $16,737 $17,072 $17,413 $17,762 $18,117 $9,240 $0 $0 $0 $0 $0 $0 $0 $0 $125,667 $129,276 $132,990 $136,813 $140,746 $144,794 $148,961 $76,624 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $15,071 $15,138 $15,205 $15,274 $15,344 $15,416 $15,489 $9,684 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 1,799 19,773 19,862 19,952 20,043 20,137 =. 20,233 20,330 12,117 105,894 109,415 113,039 116,769 120,609 124562 128630 64507 89,738 92,785 95,922 99,150 . , . 2013 2014 2015 2016 2017 2018 2019 2020 2021 631.1 631.1 631.1 6311 631.1 631.1 631.1 631.1 631.4 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 61,565 $83,984 $86,503 $89,098 $91,771 $94,524 $97,360 $100,281 $103,289 $106,388 $13,461 $13,730 $14,005 $14,285 $14,571 $14,862 $15,159 $15,463 $15,772 $0 $0 $0 $0 $0 $0 $0 $0 $0 $97,445 $100,234 $103,103 $106,056 $109,095 $112,222 $115,440 $118,752 $122,160 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $14,531 $14,586 $14,643 $14,701 $14,759 $14,819 $14,880 $14,943 $15,007 924 942 961 980 1,000 1,020 1,040 1,061 1,082 3,598 3598 3598 3598 3598 3598 3598 3598 3,598 19,052 19,126 19,202 19,279 19,357 19,437 19,519 19,602 19,687 78,392 81,107 _83,902_86,778 102,473 78,392 81,107 83,902 86,778 89,738 92,785 95,922 99,150 102,473 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) ‘(66,351) 12,042 14,756 _ 17,551 _-20,427_~—=a23,387—«26,434_—s29,571 —«32,799 «36,122 105,894 109,415 113,039 116,769 120,609 124,562 128,630 64,507 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) 39,543 43,064 46,688 50,418 54,258 58,211 62,280 __ 31,332 w KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) 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% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation * 2.0% per year Equipment Cost $1,422 perkW —_ kKWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,448 perkW = $/gallon $0.876 Variable Land Fee $0.001 per KWh Total $2,870 perkW = $/KWh $0,065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,326 _($,000) Diesel O&M saved $0.012 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) $27.4 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) 39,065 78,130 78,130 78,130 78,130 78,130 78,130 78,130 78,130 78,130 78,130 78,130 78,130 78,130 Diesel saved (dollars) $35,231 $72,576 $74,754 $76,996 $79,306 $81,685 $84,136 $86,660 $89,260 $91,938 $94,696 $97,537 $100,463 $103,477 Other Savings Diesel O&M saved $6,473 $13,206 $13,470 $13,739 $14,014 $14,294 $14,580 $14,872 $15,169 $15,473 $15,782 $16,098 $16,420 $16,748 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 $50,670 $104,768 $107,209 $109,721 $113,361 $116,020 $119,811 $122,627 $125,524 $129,560 $110,478 $113,634 $116,883 $120,225 Total Benefit per kWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 38,852 83,175 85,559 88,013 91,593 94,192 97,921 100,674 103,507 107,477 88,328 91,416 94,595 97,866 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 38,852 83,175 85,559 88,013 91,593 94,192 97,921 100,674 103,507 107,477 88,328 91,416 94595 97,866 Debt Payment (43,128) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) Annual Cash Flow (4,276) (3,081) (697) 1,757 5,337, 7,936 11,665 14,418 17,251 21,221 2,072 5,160 8,339 11,610 NPV of Cash Flow 1999$ $291,362 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) w 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 78,130 $106,581 78,130 $109,778 78,130 $113,072 78,130 $116,464 78,130 $119,958 78,130 $123,557 78,130 $127,263 78,130 $131,081 78,130 $135,014 $17,083 $17,425 $17,773 $18,129 $18,491 $18,861 $19,238 $19,623 $20,016 $123,664 $0.1172 $127,203 $0.1206 $130,845 $0.1241 $134,593 $0.1276 $138,449 $0.1313 $142,418 $0.1350 $146,502 $0.1389 $150,704 $0.1429 $155,029 $0.1470 $17,695 $17,751 $17,807 $17,865 $17,924 $17,984 $18,045 $18,107 $18,171 22,505 = 22,581 108,264 22,657 111,935 22,736 22,816 119,602 22,897 23,604 23,066 127,724 131,964 101,233 104,698 115,713 f x . F 131,964 (86,256) 41,468 45,708 50,072 54,564 101,233 (86,256) 14,977 104,698 108,264 (86,256) (86,256) 18,442 111,935 (86,256) 25,679 115,713 (86,256) 29,457 119,602 (86,256) 33,346 123,604 (86,256) 37,348 127,724 (86,256) 22,008 2022 2023 2024 2025 2026 #2027 «2028 2029 1,054.7 1,054.7 1,054.7 1,054.7 1,054.7 11,0547 11,0547 527.4 78,130 78,130 78,130 78,130 78,130 78,130 78,130 39,065 $139,064 $143,236 $147,533 $151,959 $156,518 $161,213 $166,050 $85,516 $20,416 $20,824 $21,241 $21,666 $22,099 $22,541 $22,992 $11,726 $0 $0 $0 $0 $0 $0 $0 $0 $159,480 $164,060 $168,774 $173,625 $178,617 $183,754 $189,041 $97,241 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $18,236 $16,302 $18,370 $16,438 $16,509 $16,500 $16,654 $11,266 1104 1,126 1,448 1,171 1,195) 1,219 1,243 634 3813 3813 3813 3813 3813 3813 3813 1,906 23,152 23,240 ©«-23,331 «23,422 «23,516 23,612 23,709 13,806 136,328 140,820 145,443 150,202 155,101 160,142 165,332 _ 83,435 136,328 140,820 145,443 150,202 155,101 160,142 165,332 83,435 (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (43,128) 59,187 63,946 _—68,844_—73,886 ~—*79,076~—_—40,307 a KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) 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 26.7% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation * 2.0% per year Equipment Cost $1,422 perkW —_ kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,448 per KW $/gallon $0.876 Variable Land Fee $0.001 per KWh Total $2,870 per KW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,326 _($,000) Diesel O&M saved $0.012 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) 40,048 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 80,097 Diesel saved (dollars) $36,118 $74,404 $76,636 $78,935 $81,303 $83,742 $86,255 $88,842 $91,507 $94,253 $97,080 $99,993 $102,992 $106,082 Other Savings Diesel O&M saved $6,636 $13,538 $13,809 $14,085 $14,367 $14,654 $14,947 $15,246 $15,551 $15,862 $16,180 $16,503 $16,833 $17,170 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 $51,946 $107,406 $109,909 $112,484 $116,215 $118,941 $122,828 $125,715 $128,685 $132,822 $113,260 $116,496 $119,826 $123,252 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 39,927 85,412 87,857 90,374 94,046 96,712 100,537 __103,360__ 106,266 __110,338_ 90,709 93,876 97,136 __ 100,492 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 39,927 85,412 87,857 90,374 94,046 96,712 100,537 103,360 106,266 110,338 90,709 93,876 97,136 100,492 Debt Payment (43,128) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) Annual Cash Flow (3,201) (844) 1,601 4,118 7,790 10,456 14,281 17,104 20,010 24,082 4,452 7,620 10,880 14,236 NPV of Cash Flow 1999$ $333,731 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) -w 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 80,097 80,097 80,097 80,097 80,097 80,097 80,097 980,097 80,097 80,097 80,097 80,097 980,097 80,097 80,097 80,097 40,048 $109,265 $112,543 $115,919 $119,396 $122,978 $126,668 $130,468 $134,382 $138,413 $142,566 $146,843 $151,248 $155,785 $160,459 $165,273 $170,231 $87,669 $17,513 $17,864 $18,221 $18,585 $18,957 $19,336 $19,723 $20,117 $20,520 $20,930 $21,349 $21,776 $22,211 $22,655 $23,108 $23,571 $12,021 $0 $0 $0 $0 $o $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $126,778 $130,406 $134,140 $137,982 $141,935 $146,004 $150,191 $154,499 $158,933 $163,496 $168,191 $173,023 $177,996 $183,114 $188,381 $193,801 $99,690 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $18,071 $18,126 $18,183 $18,241 $18,209 $18,359 $16,421 $18,483 $18,547 $18,612 $18,676 $16,745 $16,814 $16,884 $18,956 $19,029 $11,454 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1104 1126 1148 1,171 1495 1,219 1,243 634 3838 3,838 3838 3838 3838 3838 3,838 3838 3,838 3,838 3838 3838 3838 3838 4 86093,838 «863,838 «~—«1,919 22,833 22,907 22,982 23,059 23,137 23,217 «23,299 «23,382 «23,467 «=—«- 23,553 23,642 «23,732 «23,824 «23,917 24,013 24,110 14,007 103,945 107,500 111,158 114,923 118,798 122,787 126,892__ 131,117 135,466 139,942 144,549 149,202 154,173 159,197 164,368 169,691 __ 85,683 103,945 107,500 111,158 114,923 118,798 122,787 126,892 131,117 135,466 139,942 144,549 149,292 154,173 159,197 164,368 169,691 85,683 (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (86,256) (43,128) 17,689 21,244 24,902 28,667 32,542 36,531 40,636 44,861 49,210 53,686 58,293 63,036 ~— 67,917 72,941 78112 83,435 42,555 APPENDIX C CASH FLOWS Baseline with Energy Estimates a. 20% lower than expected b. 10% higher than expected KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WT/year Turbine Count i. Term (years) 30 Labor $0.014 per kWh Capacity Factor 16.4% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 perkW —_ kWhygallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per kW $/galion $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per KW $/KWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per kWh Total Project Costs $1,020 _($,000) Diesel O&M saved $0.012 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) 332.4 664.9 664.9 664.9 664.9 664.9 664.9 664.9 664.9 664.9 6649 6649 664.9 664.9 Benefit from wind Diesel saved (gallons) 24,626 49,252 49,252 49,252 49,252 49,252 49,252 49,252 49,252 49,252 49,252 49,252 49,252 49,252 Diesel saved (dollars) $22,209 $45,751 $47,124 $48,537 $49,993 $51,493 $53,038 $54,629 $56,268 $57,956 $59,695 $61,486 $63,330 $65,230 Other Savings Diesel O&M saved $4,081 $8,325 $8,491 $8,661 $8,834 $9,011 $9,191 $9,375 $9,562 $9,754 $9,949 $10,148 $10,351 $10,558 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 $31,942 $66,044 $67,583 $69,166 $71,461 $73,137 $75,527 $77,302 $79,128 $81,673 $69,644 $71,633 $73,681 $75,788 Total Benefit per kWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 3438 3438 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 Expenses 23,068 50,342 51,823 53,349 55,584 57,199 59,528 _61,239 63,001 65,480 53,384 55,306 57,283 59,319 ANNUAL CASH FLOW Less: Equity Investment $0 Net Benefit After Expenses 23,068 50,342 51,823 53,349 55,584 57,199 59,528 61,239 63,001 65,480 53,384 55,306 57,283 59,319 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow (10,107) (16,009) (14,527) (13,002) __ (10,767) (9,151) (6,823) (5,111) (3,349) (871) (12,967) (11,045) (9,067) __(7,031) NPV of Cash Flow 1999$ ($31,861) 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 ss 2017-—S« 2018 = 2019S 2020-2 2021-«S-s2022,-—S/s 2023'S 2024-«Ss 2025«= 2026 «= 2027. «Ss« 2028 += 2029 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 6649 3324 49,252 49,252 49,252 49,252 «49,252 49,252 49,252 49,252 49,252 © 49,252 «49,252 49,252 49,252 49,252 49,252 49,252 24,626 $67,187 $69,203 $71,279 $73,417 $75,619 $77,888 $80,225 $82,631 $85,110 $87,664 $90,294 $93,002 $95,792 $98,666 $101,626 $104,675 $53,908 $10,769 $10,984 $11,204 $11,428 $11,657 $11,890 $12,128 $12,370 $12,618 $12,870 $13,127 $13,390 $13,658 $13,931 $14,209 $14,494 $7,392 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $77,956 $80,187 $82,483 $84,845 $87,276 $89,778 $92,352 $95,002 $97,728 $100,534 $103,421 $106,392 $109,450 $112,597 $115,836 $119,169 $61,299 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $12,179 $12,234 $12,291 $12,349 $12,407 $12,467 $12,528 $12,591 $12,655 $12,719 $12,786 $12,653 $12,922 $12,992 $13,064 $13,137 $8,508 924 942 961 980 1,000 1,020 1,040 1,061 1,082 1,104 = 1,126 1,148) 4,711,195 1,219 1,243 634 3,438 «6«3,438 Ss 3,438 3,438 3,438) 3,438 3,438 3,438 3,438) 3,438) 3,438) 3,438 3,438 3,438 3,438 3,438,719 16,541 16,615 16,690 16,767 16845 16,925 17,007 17,090 17,175 17,262 17,350 17,440 17,532 17,626 17,721 17,819 10,861 61,415 63,572__-65,792__—68,078 —70,431_—«72,852__—S75,345__—S7,911_. 80,553 __—83,272—«86,071_—88.952_—91,918 ~—94,.971—98,114 101,350 50,438 61,415 63,572 65,792 68,078 70,431 72,852 75,345 77,911 80,553 83,272 86,071 88,952 91,918 94971 98,114 101,350 50,438 (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (33,175) (4,936) (2,779) (558) 1,727 4,080 6,502, 8,994 11,561_—14,202— 16,921 19,720 22,601 _—25,567_—28,621_—31,764 34,909 __—17,263 KEA Wind Farm Project Configuration Financing Option Operating Costs (in 1999$) Project Size 0.462 MW Debt 100% O&M (1st yr) Turbine Rating 66 KW Equity 0% Parts $300 per WTi/year Turbine Count 7 Term (years) 30 Labor $0.014 per kWh Capacity Factor 22.6% Interest rate 5.0% Insurance Discount Rate 5.0% General Liability $100 per turbine Project Costs (US$) Revenue Inflation 2.0% per year Equipment Cost $1,094 per KW kWhigallon diesel 13.5 Fixed Land Fee $400 per WT/yr Balance of Station $1,114 per kW $/gallon $0.876 Variable Land Fee $0.001 per kWh Total $2,208 per KW $/kKWh $0.065 Fuel Escal/Inflation 3.0% REPI (1998) $0.017 per KWh Total Project Costs $1,020 ($,000) Diesel O&M saved $0.012 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 914.2 914.2 Benefit from wind Diesel saved (gallons) 33,860 67,721 67,721 67,721 ‘67,721 67,721 67,721 67,721 67,721 67,721 67,721 ‘67,721 67,721 67,721 Diesel saved (dollars) $30,538 $62,908 $64,795 $66,739 $68,741 $70,803 $72,927 $75,115 $77,368 $79,690 $82,080 $84,543 $87,079 $89,691 Other Savings Diesel O&M saved $5,611 $11,446 $11,675 $11,909 $12,147 $12,390 $12,638 $12,891 $13,148 $13,411 $13,680 $13,953 $14,232 $14,517 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 $43,920 $90,810 $92,927 $95,104 $98,258 $100,564 $103,850 $106,290 $108,802 $112,300 $95,760 $98,496 $101,311 $104,208 Total Benefit per KWh $0.0961 $0.0993 $0.1016 $0.1040 $0.1075 $0.1100 $0.1136 $0.1163 $0.1190 $0.1228 $0.1047 $0.1077 $0.1108 $0.1140 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 33,163 71,341 73,400 75,519 78,614 80,859 84,083 86,460 —- 88,907 92,340 _75,733__ 78,401 81,146 83,972 ANNUAL CASH FLOW Less: Equity Investment $0 : Net Benefit After Expenses 33,163 71,341 73,400 75,519 78,614 80,859 84,083 86,460 88,907 92,340 75,733 78,401 81,146 83,972 Debt Payment (33,175) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) (66,351) Annual Cash Flow 13 4,990 7,049 9168 12,263 14,508 17,732___ 20,110 22,556 25,989 9,382, 12,050 14,796 _—«17,622 NPV of Cash Flow 1999$ $365,904 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 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 67,721 33,860 $92,382 $95,153 $98,008 $100,948 $103,977 $107,096 $110,309 $113,618 $117,027 $120,538 $124,154 $127,878 $131,715 $135,666 $139,736 $143,928 $74,123 $14,807 $15,103 $15,405 $15,714 $16,028 $16,348 $16,675 $17,009 $17,349 $17,696 $18,050 $18,411 $18,779 $19,155 $19,538 $19,929 $10,164 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $o $107,189 $110,257 $113,414 $116,662 $120,005 $123,444 $126,984 $130,627 $134,376 $138,234 $142,204 $146,289 $150,494 $154,821 $159,274 $163,857 $84,287 $0.1172 $0.1206 $0.1241 $0.1276 $0.1313 $0.1350 $0.1389 $0.1429 $0.1470 $0.1512 $0.1555 $0.1600 $0.1646 $0.1693 $0.1742 $0.1792 $0.1844 $15,707 $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 20,308 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 86,881 89,875 _— 92,956 96,128 99,392 102,752 106,210 109,770 113,433 117,205 121,086 125,082 129,195 133,428 137,785 142,271 71,542 Se en 86,881 89,875 92,956 96,128 99,392 102,752 106,210 109,770 113,433 117,205 121,086 125,082 129,195 133,428 137,785 142,271 71,542 (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) 20,530 23,524 «26,605 _~—«29,777 ~_—«33,041~—«36,401_~—2«39,859 ~—«43,419 ~—47,083—50,854 54,736 —58,731 —62,844_—G7,O77__—71,435 —75,920 38,367 — So eo Se ee SS ee