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HomeMy WebLinkAboutJuneau 20 Year Power Supply Plan Update 1990August 1990 ee Alaska Energy Authority LIBRARY COPY UNEAU 20-YEAR POWER SUPPLY PLAN UPDATE PREPARED FOR Juneau Power Supply Plan Sponsors: Alaska Electric Light and Power Company Alaska Energy Authority Alaska Power Administration Juneau Energy Advisory Committee ° ME engincers EES] Planners Economists ME scientists August 15, 1990 ANC28989.A0 Juneau Power Supply Plan Sponsors c/o Alaska Electric Light & Power Company 612 West Willoughby Avenue Juneau, Alaska 99801 Attention: Mr. William A. Corbus Subject: Juneau 20-Year Power Supply Plan Update CH2M HILL is pleased to present the Juneau 20-Year Power Supply Plan Update. It has been a pleasure to work for the Juneau Energy Advisory Committee, Alaska Electric Light and Power Company, Alaska Energy Authority, and the Alaska Power Administration on this important and challenging assignment. If you have any questions regarding this document, please call me at 206/453-5000. Sincerely, CH2M HILL bottle Robert K. Schneider Project Manager ss/sea7308/062.51 cc: Don Shira, Alaska Energy Authority Bob Cross, Alaska Power Administration CH2M HILL Seattle Office 777 108th Avenue, N.E., Bellevue, Washington 206.453.5000 P.O. Box 91500, Bellevue, Washington 98009-2050 August 1990 NEAU 20-YEAR POWER SUPPLY PLAN UPDATE PREPARED FOR Juneau Power Supply Plan Sponsors: Alaska Electric Light and Power Company Alaska Energy Authority Alaska Power Administration Juneau Energy Advisory Committee ANC28989.A0 MDV CONTENTS Executive Summary I. Il. Ill. VII. Introduction Existing Conditions Load Forecast Existing Generation Resources Specific Alternatives Considered Overview Conservation Resource Options Energy Conservation and Management Plan Recommendations ~ Transmission Intertie Options Generation Resource Options Comparable Cost Procedure Planning Approach Overview Selection of Least-Cost Mix of Resources Computer Model Bus Bar Cost Analysis Reliability Evaluation Findings Net Present Value Analysis Project Financing Mining Company Participation in Energy Development Sensitivity Analyses / Bus Bar Cost Analysis Reliability and Reserve Considerations Environmental Considerations Implementation Plan Letters Responding to Draft Plan Juneau Economic Development Council Alliance for Juneau’s Future, Inc. Alaska Applied Sciences, Inc. Page ES-1 I-1 II-1 II-1 II-5 II-1 Til-1 Til-1 Iil-2 IH-9 I-19 If-29 IV-1 IV-1 IV-5 IV-6 Iv-8 V-1 V-1 V-12 V-20 V-22 V-27 V-33 V-40 VII-1 VII-3 VII-7 VII-11 Appendix A. Analysis of Alternatives Appendix B. Computer Model Analysis Appendix C. APA Letter on Rates Appendix D. Economic Concepts TABLES II-1 II-2 II-3 III-1 Ill-2 III-3 III-4 III-5 Ill-6 Il-7 III-8 IV-1 V-1 V-7 V-8 V-9 Peak Demand and Energy Requirements Forecasts Existing Power Supply Resources Net Energy Generation (MWh) by Plant Conservation Programs Chosen for the Plan Payback Period Versus Penetration Rate Peak Demand and Energy Savings Due to Demand-Side Options Annual Energy Requirements Before and After Programmatic Conservation Transmission Interties Estimated Firm Energy, Average Energy, and Costs of Hydroelectric Projects Long Lake Hydro Alternatives Diesel-Fueled Alternative, Life-Cycle Levelized Costs 1990 Life-Cycle Levelized Costs Historical and Projected Fuel Costs Key Assumptions for Existing and New Power Supply Resources Results of Net Present Value Analysis, A. J. Mine Scenario Results of the Net Present Value Analysis, Multiple Mine Scenario Financial Data on Major Resource Sponsors Changes in Net Present Value Under A. J. Mine Scenario Changes in Net Present Value Under Multiple Mine Scenario Analysis of Lake Dorothy on a 10-year Bond Life Results of the Net Present Value Analysis Sensitivity Analysis Page Il-2 II-7 II-8 Iil-3 Ti-5 IHl-10 Til-11 III-16 Il]-22 TH-24 II-29 Iv-3 V-4 V-7 V-10 V-12 V-19 V-19 V-21 V-23 V-10 V-11 V-12 V-13 V-14 V-15 V-16 V-17 Projected Diesel Fuel Nominal Costs Results of the Net Present Value Analysis Fuel Cost t Sensitivity Analysis Changes in Annual Residential Customer Costs, Diesel Resource Package, A. J. Mining Forecast Changes in Annual Residential Customer Costs, Lake Dorothy Resource Package, A. J. Mining Forecast Changes in Annual Residential Customer Costs, Diese] Resources Package, Multiple Mining Load Forecast Changes in Annual Residential Customer Costs, Lake Dorothy Resource Package, Multiple Mining Load Forecast Reserve Requirements (MWh) Installed Reserves (MW) V-31 V-32 V-33 V-37 V-38 FIGURES I-1 1-2 1-3 Ill-1 II-2 INl-3 Il-4 V-1 v-2 Vv-3 v-4 V-5 V-6 Energy Requirements Forecasts With and Without Mining Loads Peak Demand Forecasts With and Without Mining Loads Area Map | Peak Demand, A. J. Mine Forecast Peak Demand, Multiple Mine Forecast Energy Requirements, A. J. Mine Forecast Energy Requirements, Multiple Mine Forecast Diesel Fuel Costs, Historical and Projected Results of Fuel Price Scenarios, A. J. Mine Forecast Bus Bar Costs Base (No-Mine) Forecast Average Bus Bar Costs, A. J. Mine Forecast Cases Average Bus Bar Costs, Multiple Mine Forecast Cases Bus Bar Costs, Lake Dorothy (A. J. Mine Forecast) Iil-12 IIl-13 TH-14 II-15 V-26 Vv-30 V-34 V-35 V-36 eS EXECUTIVE SUMMARY EXECUTIVE SUMMARY The Alaska Electric Light and Power Company provides electric service to the City and Borough of Juneau. The primary sources of power are small hydroelectric projects owned and operated by AELP and the larger Snettisham/Crater Lake hydroelectric projects owned and operated by the Alaska Power Administration. The capacity of these projects exceeds the current need for electricity in Juneau by over 70 GWh per year, or about 25 percent of current use. If the present, relatively mild, growth rate continues, no new generating sources will be needed in the near future. However, mining companies are investigating the possibility of reopening gold mines in the area. The largest of these mines, A. J. Mine, could start operating as early as 1993. Two other major mines may open around the same time or shortly afterwards. Electric loads for the mines and the resulting stimulus to the local economy were not taken into account when the 1984 Juneau 20-Year Power Supply Plan was prepared. Even though each mine operator currently intends to install sufficient onsite diesel or gas generating facilities to satisfy their own loads, the community must prepare for any contingencies that may occur. To prepare for these contingencies, the 1984 plan was updated for the 20-year period from 1990 to 2010. The approach used for this update was to evaluate options under a “one-utility” concept, as if there were a single utility owner, so that all parties could gain insight into least-cost options from a societal perspective. LOAD FORECASTS The most recent APA load forecasts were used for the update. Peak demands and annual energy requirements were forecast for three development scenarios: no mines, A. J. Mine, and multiple mines. These forecasts indicate that consumption will nearly double under the A. J. Mine scenario and will increase an additional 15 percent under the multiple-mine scenario. The forecasts reflect estimated energy savings from increased use of energy efficient appliances, better building codes, and greater consumer awareness. It was assumed that, in the no-mine scenario, Juneau will continue to grow at a mild rate due to in- creases in tourism and fishing. It was also assumed that mining activity will begin in 1993 and continue through the 20-year period. Although the mines’ proven reserves are not sufficient to last that long, additional explorations may extend these resources. ES-1 EVALUATION OF VIABLE RESOURCES The most promising demand-side, transmission intertie,.and generation or supply-side options were evaluated for their ability to meet forecast loads for the mining scenarios. Options included conservation and load management programs, 10 hydroelectric proj- ects at 4 sites, diesel-fueled engines and combustion turbines, and a small garbage in- cineration facility. The initial screening of options resulted in the following conclusions: ° Intertie options, incineration, and small simple-cycle combustion turbines do not warrant further analysis at this time, mostly on the basis of costs. ° Lighting-based commercial conservation programs could represent a major source of conservation in the Juneau area. Selected conservation programs are projected to save an average of approximately 35,000 MWh annually by the year 2010 for all three scenarios, representing a 5 to 10 percent reduction of the total 2010 energy needs. This is in addition to the "embedded" conservation included in the load forecasts. . Load management, in the form of AELP’s residential water heater con- trol program, is projected to save approximately 5 MW of capacity in the year 2000. New hydropower plants that were evaluated further were as follows: the Lake Dorothy, Annex Creek/Carlson Creek, and Lake Dorothy/Long Lake Tunnel projects. Modifications to existing hydroelectric projects that were evaluated further involved raising the dams at Crater and Long Lakes. The selected options were combined to form three least-cost alternative resource pack- ages. The packages were named after the major hydroelectric resources they included: Lake Dorothy, Annex Creek/Carlson Creek, and Lake Dorothy/Long Lake Tunnel. These packages were then evaluated against an optimized diesel base case for net pres- ent values, rates, financing, reliability, and environmental concerns. FINDINGS Existing resources total 152 MW. If existing hydroelectric surplus and reserve diesel units are used and if conservation and load management programs are implemented, an additional 12 MW (and 233,000 MWH) will be needed under the A. J. Mine scenario and an additional minimum of 25 MW (and 301,000 MHW) will be needed under the multiple-mine scenario to meet 1993 peak demands. An additional 3 to 5 MW will be needed to meet the growth in non-mining loads during the remainder of the period. ES-2 Lake Dorothy appears to be the best major hydroelectric project for both mining sce- narios. The Lake Dorothy least-cost package requires $140 million in long-term capital. The optimized diesel package requires only $24 million in long-term capital, but will entail substantially higher annual expenses, mainly in fuel costs. For the A. J. Mine scenario, the Lake Dorothy package has a net present value that is $59 million less than the next lowest cost package, and $129 million less than the opti- mized diesel base case. For the multiple mines scenario, the net present value for the Lake Dorothy package is $2 million less than for the Annex Creek/Carlson Creek package, assuming average water conditions each year. In addition, the Annex Creek/Carlson Creek project has substantial nonfirm energy that may not be present in a dry year and that could require more than $5.9 million per year in added fuel costs. In the 1984 power supply plan, the Lake Dorothy hydroelectric project was found to be more cost-effective than hydroelectric projects at Speel River, Sweetheart Lake, and Thomas Bay. Because of their low ranking relative to Lake Dorothy in the 1984 study, the Speel River, Sweetheart Lake, and Thomas Bay projects were not evaluated in this update. Their rankings relative to the Annex Creek/Carlson Creek and the Lake Dorothy/Long Lake Tunnel projects, therefore, are not known. Even though the Lake Dorothy package is the lowest-cost package over its life cycle, its unit energy cost is substantially higher than unit energy costs for current resources. New electric generating resources are usually more expensive than existing resources. IMPLEMENTATION PRIORITIES The mines have not yet completed their electric plans of service. Until they do, the uncertainty surrounding this update will continue. The most important priorities then are to help the mines in their decisionmaking process and to continue preparing to put contingency plans into action once decisions are made. If the mines decide to provide their own power, the most important priorities for AELP will be to negotiate power sales and forced outage agreements and to explore intercon- nection options with the mines. Sales of existing surplus energy to the mines could potentially reduce residential electric rates by $33 to $96 per year, while reducing the mines’ dependency on diesel fuel and the associated impacts to the environment. If the mines do not provide their own power, AELP will need to carefully consider implementing the Lake Dorothy package and recommended conservation and load management programs. AELP will support major resource development only if it can eliminate the retail rate impact to existing customers by charging the costs of the new resources to the mine operators. The mines are reluctant to make long-term commit- ments. A typical bond financing period extends for 30 years. It is not plausible for the mines to sign a take or pay contract for the term of financing when their proven re- sources range from only 10 to 15 years. Shortening the bond financing period to 10 years would cause the cost of hydropower to exceed mine-financed diesel power costs. Even if the mines agree to provide contractual support for the Lake Dorothy project, over $140 million in long-term capital must be raised. sea7309/007.51 ES-4 CE ES I. INTRODUCTION I. INTRODUCTION The study sponsors, Alaska Electric Light and Power Company (AELP), Alaska Energy Authority (AEA), Alaska Power Administration (APA), and the Juneau Energy Advisory Committee, chose CH2M HILL to update the 1984 Juneau 20-Year Power Supply Plan. Because numerous studies of resource options in the Juneau area have been performed, the approach taken in this study was to update previous work on the most promising alternatives and to refine the work only where needed.. Special areas of refinement include a more critical analysis of Lake Dorothy, Long Lake, Crater Lake, and Carlson Creek. Another change from the previous power supply plan was the emphasis on conservation and the use of both least-cost planning techniques and a financial evaluation that focused on electric power costs. Since electricity was introduced to the community nearly 100 years ago, power supply in Juneau has been developed using both hydroelectric and thermal generating resources. Gold mining entrepreneurs established one of the nation’s first hydroelectric plants, Gold Creek. At that time, hydromechanical energy and small-scale coal-fired steam generation were used in gold mining operations. However, between 1910 and 1915 the mines made substantial investments in hydroelectric facilities for use in mining opera- tions. Annex Creek, Salmon Creek, Sheep Creek, and other hydroelectric projects were built. AELP purchased surplus energy from these facilities for distribution to meet the electrical needs of the growing community. The utility relied heavily on these hydroelectric supplies until availability and load conditions required investment in diesel units in the 1950s.. Over the next 20 years, hydroelectric supplies to AELP alternated between surplus and deficit conditions. AELP purchased the mining-company- developed hydroelectric facilities from the A. J. Mining Company in 1973. The advent of the Snettisham hydroelectric project in the mid-1970s brought a sub- stantial hydroelectric surplus to the Juneau area. Snettisham project power was made more reliable by transmission improvements in the late 1970s. Due to increases in population and the resulting increase in load, the Juneau community was again in hydro deficit conditions by the early 1980s. Currently, the Crater Lake addition has put the community back into a surplus position. However, the prospect of substantial mining development foreshadows a shift back to an areawide hydroelectric deficit and the need for additional demand-side activities and new generation resources. This power supply plan is intended to provide a strategy for meeting electric energy requirements should substantial growth in electric load result from new community development. The tradition of the Juneau community has been to look for innovative and low-cost renewable energy resources within the region rather than to rely princi- pally on imported and unpredictably priced fuel for diesel resources. Not only have the community and the agencies serving Juneau met the challenges of developing local low- cost renewable resources, they have managed the difficult task of building transmission lines through rugged terrain to bring the energy to market. This 20-year power supply I-1 plan presents evaluations of opportunities for continuation of this historic hydro/thermal development program. In addition, innovative supply- and demand-side approaches are evaluated to seek least-cost solutions. Power supply planning is broader than just generation planning. The shift between surplus and deficit generation in Juneau and the sponsors’ commitment to conservation require that AELP’s demand-side opportunities be incorporated into the plan. CH2M HILL has worked with the sponsors to evaluate conservation alternatives that can be used to minimize the operation of high-cost diesel generation resources. Because of the relative size of the supply from Snettisham, Juneau’s major planning challenge is a significant reserve capacity (or standby) requirement. This has been considered in the power supply plan. Currently, reserve requirements are planned to equal the largest single contingency. The reserve requirements and reliability criteria appear reasonable, based upon both the size of the utility and its geographic location. Currently under investigation are several major gold mines that operated prior to World War Il, all located within the City and Borough of Juneau (CBJ). Neither min- ing electric loads nor the resulting stimulus to the CBJ economy were anticipated at the time the 1984 Juneau 20-Year Power Supply Plan was prepared. The largest of these mines, the A. J. Mine, to be developed and operated by Echo Bay Mines Ltd., would be located several miles south of the Juneau central business district on Gastineau Channel and could begin operation as early as 1993. Of the major mines, the Jualin Mine to the north of Berners Bay, under lease to Curator American, Inc., is expected to be brought into operation sometime after the development of the A. J. Mine. Just to the north of the Jualin Mine is the Kensington Mine, which is also to be developed and operated by Echo Bay Mines. The prospective plan for development calls for the Kensington to start production at about the same time as the A. J. Mine. At this juncture, for various reasons, each mine operator intends to install sufficient generating facilities onsite to satisfy its own needs. The mine operators have evaluated a number of sources of energy: diesel fueled engines, reciprocating piston engines and combustion turbines fueled by LNG and LPG, and construction of the Sheep Creek hydro project. In the event that one or all of the mines are developed as now planned, AELP’s responsibility will be to satisfy the nonmining energy requirements of the result- ing stimulation of the CBJ economy. Although the mines are now planning to serve their own loads, it was decided to establish a “one-utility" planning perspective to evaluate the total electric power needs for the community. This one-utility perspective in planning for the needs of an area is especially appropriate for the Juneau area. AELP and APA are the two major owners of existing generating resources. The mines and the AEA are likely owners of future resources as are consumers, who will be the owners of conservation resources. By reviewing various least-cost packages of resources for the total community and then analyzing costs from both a present value and a rate perspective, all members of the community can view the advantages and risks of alternate generation service plans. In this way they can judge the costs and benefits of their participation in resource development. Conservation options have been emphasized in this update. Conservation is treated in two separate ways. First, there are embedded conservation-savings included in the load forecasts furnished by the sponsors. Second, there are additional programmatic conser- vation savings based upon an update of the 1987 Energy Conservation and Manage- ment Plan and a fact-finding session with the sponsors as to new conservation opportunities. The sponsors have expended considerable effort on studies of various major alterna- tives. A review of these past studies was needed to place the alternatives on a com- parable basis. Additional field work was required on some of the hydroelectric alternatives so that they could be fairly evaluated. The hydroelectric projects evaluated are Lake Dorothy, Annex Creek/Carlson Creek, Long Lake expansion, and Crater Lake expansion. Special emphasis in the evaluation of these projects was placed on their seasonal energy, transmission costs and reliability, and ways to reduce the initial cost to the Juneau area, such as through staged construction. This perspective led to the evaluation of an alternative not previously considered, a tunnel from Lake Dorothy to Long Lake. This alternative would increase the energy from Snettisham. Not evaluated in this study were certain hydro projects previously studied, including projects at Sweetheart Lake, Speel River, and Thomas Bay. Because past studies found Lake Dorothy superior to these projects, the Power Supply Plan Update focused on either new major hydro alternatives to Lake Dorothy not explored in the previous Juneau 20-Year Power Supply Plan or on small hydro projects associated with existing facilities that could be constructed more quickly than the Lake Dorothy project. There- fore, it should not be assumed that the Annex Creek/Carlson Creek, Lake Dorothy/ Long Lake tunnel projects are superior to the Sweetheart Lake, Speel River, and Thomas Bay hydro projects evaluated in the 1984 Juneau 20-Year Power Supply Plan. Consideration also was given to the financial impacts of program options. Hydroelec- tric projects may be economically feasible because their inherent large fixed costs are not subject.to inflation. However, their annual costs during initial years of operation can be large relative to those of other resource options. This is especially true if the project’s output cannot be fully utilized at the time of commercial operation. Under such conditions, a project that is economically feasible in the long term can result in substantial costs in initial years and rate shock to consumers. Because exact retail rate structures are determined by the interaction of AELP with the Alaska Public Utilities Commission (APUC), the sponsors concluded that it was inappropriate and potentially misleading to forecast retail rates in this study. Instead, we focused upon the average cost of generation. For the Juneau area, the average total cost of generation (also known as the average bus bar cost of generation) is the principal component of the retail rate. Consequently, a projection of changes in aver- age bus bar costs will serve as an indicator of retail rates. In our analysis of average costs of generation, we have ‘shown the costs in cents per kilowatt hour from three perspectives. The first perspective is based on a system aver- age cost over all energy sold. The second perspective assumes implementation of "take-or-pay" contracts under which the mines would pay for the marginal costs of new generation required by planning criteria regardless of whether they used the power. This perspective shows the average costs to the mines of surplus firm hydroelectric power, surplus nonfirm hydroelectric power, and diesel generation. The third perspec- tive is an average generation cost for the non-mine customers under a mining "take-or- pay" contract concept. This perspective shows relatively low costs because of the allo- cation of marginal costs to the mines. From these perspectives, the potential for rate shock from large projects can be evaluated by policymakers, as can the short-term rate difference between the least-cost energy path and a particular alternative. In implementing a least-cost plan, certain specific actions were recommended. These recommendations were based upon a variety of factors including the most likely owners of specific resources if they are built. Regulatory agency criteria and utility financing capability were also principal considerations in the implementation recommendations found in Section VI. The Lake Dorothy and Annex Creek/Carlson Creek hydroelectric projects would have an installed capacity of between 26 and 28 MW and would each generate more than 120 million kilowatt-hours (kWh) of energy annually. However, each project has distinctly different characteristics in terms of reservoir storage, transmission line costs, transmission line reliability, and potential for construction staging. Similarly, other power supply alternatives were quantified, such as continued reliance on diese] generation, demand-side management techniques, transmission interties, and waste-to-energy steam turbines. All alternatives were evaluated against an optimized diesel generation base case. Least-cost planning concepts were used to compare demand-side alternatives to added generation. The demand-side and generation resources were ranked on the basis of an economic index (lifecycle levelized cost) and combined with one of the major hydro resources to create a least-cost package of resources. Under both the A. J. Mine and the multiple mine load forecasts, conserva- tion and demand-side alternatives could not provide all of the needed additional energy. The work led to the preparation of a comprehensive evaluation system. sea7308/072.51 ESS Il. EXISTING CONDITIONS Il. EXISTING CONDITIONS LOAD FORECAST The load forecast used in the Juneau 20-Year Power Supply Plan Update was prepared by the APA and reviewed by CH2M HILL and the sponsors. The forecast recognizes that the greatest impacts on future loads would be reopening of the A. J. Mine by Echo Bay Mining and the opening of mines just to the north of Juneau. Because of this, the forecast comprises a base scenario without added mining activity, an A. J. Mine sce- nario, and a multiple mine scenario. These three scenarios represent a reasonable range of loads that could occur in the Juneau area, based on current information. The base or no-mining-activity load forecast, the A. J. Mine scenario loads, and the multiple mine scenario loads are shown in Table II-1 and Figures II-1 and II-2. The forecast recognizes several changes from historical experience. It includes reduc- tions in average energy use per customer (about 0.5 percent per year) in the water heating and all electric residential customer classes. Use per general class customer is expected to remain constant at an average of 6,500 kWh per year. The number of general class residential customers decreases at 2.5 percent per year, while customers in the hot water class increase at 2.5 percent per year. Street light energy use remains constant at an average of approximately 1 million kWh per year. Conservation savings are contained within both the load forecast and the resource packages that are part of the least-cost planning process used this report. "Embedded" conservation savings have been included in the forecast assumptions in the previous paragraph. For example, the reductions in the water heating and all electric classes are based upon an expectation that energy efficiency will increase in these sectors. Re- placement of older major appliances by new energy-efficient appliances, better building codes, and greater consumer awareness of energy are expected to be the most impor- tant factors in this reduction in residential energy use. Additional savings from conser- vation programs are evaluated in Section III of this report. These program-based sav- ings are then compared to generation options in the development of the least-cost resource packages discussed in Section IV. The number of residential customers is projected as a constant function of employment in the Juneau area (0.7 residential customers per job). Energy use in the commercial class and government energy use also vary in proportion to employment. The base (or no-mining) scenario envisions mild growth in Juneau’s economy due to moderate increases in tourism and fishing. Under this scenario, employment is pro- jected to increase at 100 jobs per year. There is a belief that employment and, hence, population could drop if state oil revenues continue to decline and potential mining activity does not materialize. Such a reduced forecast would not significantly change the recommendations in this study because no new generating resources are required II-1 Peak Demand Forecast (MW) Base AJ. Multiple Year | (No Mine) Mine Mine 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 sea7309/026.51 52.7 53.4 53.9 54.5 55.1 55.6 56.1 56.6 57.1 57.6 58.1 58.5 58.9 59.3 59.8 60.1 60.5 60.9 61.3 61.6 62.0 Table H-1 Peak Demand and Energy Requirements Forecasts TI-2 Energy Requirements Base (No Mine) 277,000 280,600 283,500 286,400 289,700 292,400 295,100 297,600 300,000 302,800 305,200 307,500 309,700 311,900 314,100 316,100 318,100 320,100 322,000 323,800 325,600 Forecast (MWh) AJ. Mine 277,000 288,500 300,100 534,300 543,600 552,900 555,400 557,900 560,400 562,700 565,000 567,300 569,500. 571,600 573,600 575,600 577,600 579,400 581,300 583,000 584,800 Multiple Mine 277,000 293,300 309,700 612,200 625,500 638,600 641,200 643,600 646,000 648,300 650,600 652,800 654,900 657,000 659,000 660,900 662,800 664,700 666,400 668,200 669,800 a) €-II MWh ENERGY REQUIREMENTS FORECASTS WITH AND WITHOUT MINING LOADS 700,000 600,000; 500,000; 400,000- 300,000- 200,000- 100,000 HISTORICAL Base Forecast Multiple Mine Forecast A.J. Mine Forecast Multiple Mine Forecast w/o Mining Load A.J. Mine Forecast w/o Mining Load PROJECTED 0 1970 1975 1980 1985 1990 1995 2000 2005 2010 TI eanary vil MW PEAK DEMAND FORECASTS WITH AND WITHOUT MINING LOADS 110 100- Multiple Mine Forecast 90- A.J. Mine Forecast 80- HISTORICAL 70- Multiple Mine Forecast w/o Mining Load| 60- \ 50; 40, A.J. Mine Forecast w/o Mining Load 30- Base Forecast PROJECTED | 20, 10 T T T Uy 1970 1975 1980 1985 1990 1995 2000 2005 2010 TIL aansiy under the base scenario. However, a lower forecast could result in higher bus bar costs for the base scenario and increase the relative economic attractiveness of the A. J. and multiple mine scenarios. Under the A. J. Mine scenario, general employment is the same as in the base forecast, with additional construction jobs requiring 300 employees in 1991, 600 employees in 1992, and 300 in 1993. Operations at the A. J. Mine are assumed to require 500 em- ployees in 1993. Secondary Juneau employment is assumed to be an additional 250 employees in 1994 and 250 employees in 1995. The direct mining load is estimated to be 234 million kWh per year starting in 1993. The multiple mine scenario assumes that general employment increases at the same rate as in the base forecast. Construction of mining facilities would employ 480 addi- tional people in 1991, 960 in 1992, and 480 in 1993. Operation of the mines would employ 800 people in 1993, and the Juneau economy would respond with 400 second- ary jobs in 1994 and 400 in 1995. The direct energy requirements for mining are assumed to be 234 million kWh per year for the A. J. Mine, 60 million kWh per year for the Kensington mine, and 20 million kWh per year for the Jualin mine. All mining loads are assumed to start in 1993 and remain constant for the entire study period. Although the proven reserves of the A. J. and other mines are not sufficient to last throughout the study period, discussions with a representative of Echo Bay Mining indicated that additional exploration may extend proven reserves. The sponsors have concluded that "take-or-pay" provisions in the power contracts with the mines will miti- gate the economic risk of developing major new resources associated with assuming continued mining operations past the period of proven reserves. EXISTING GENERATION RESOURCES AELP’s existing power supply resources consist of AELP-owned diesel and hydroelec- tric power plants and the Snettisham/Crater Lake hydroelectric project, which is owned and operated by APA. These resources are shown in Figure II-3 and summarized in Table II-2. Table II-3 summarizes net generation by resource for each of the years from 1985 through 1989. Crater Lake operation began in late 1989 and should contribute to a greater share of power generation by the overall Snettisham project in future years. sea7308/032.51 TI-5 to Whitehoree Taku Inlet oe Satmon Creek e Annex Creek Lake Dorothy “A - 20 30 mites La) to Tyee Lake Figure II-3 AREA MAP II-6 Table II-2 Existing Power Supply Resources Firm Capacity Resource AELP System Hydroelectric Annex Creek 3.5 Salmon Creek 5.5 Gold Creek* 0.0 Total Hydroelectric 10.2 Diesel Lemon Creek CTs 35.0 Lemon Creek Diesels 22.5 Auke Bay Diesel Gold Creek Diesels Total Diesel Total AELP System APA System Snettisham/Crater Lake Hydro** Total AELP Power Supply Resources *Gold Creek is a run of the river hydro project and has no firm capacity due to a lack of reservoir storage. **Snettisham power is reduced for camp and hatchery loads. sea7309/002.51 II-7 Table II-3 Net Energy Generation (MWh). By Plant AELP Hydro Annex Creek Salmon Creek Gold Creek Subtotal (Percent of Total) AELP Diesel Lemon Creek Auke Bay Gold Creek Subtotal (Percent of Total) Total AELP Generation 95,124 | 81,690 66,113 Snettisham/Craker Lake 169,160 180,832 191,571 197,276 206,880 (Percent of Total) 64% 69% 75% 75% 16% Total Generation and Purchases 264,284 262,522 256,179 263,836 272,993 sea7309/003.51 II-8 IL]. SPECIFIC ALTERNATIVES CONSIDERED Il. SPECIFIC ALTERNATIVES CONSIDERED OVERVIEW This report is an update of the 1984 Juneau 20-Year Power Supply Plan. Because numerous studies have been made of resource options in the Juneau area, the ap- proach in this study has been to update previous work on the most promising alterna- tives and refine the work only where needed. This study, therefore, has relied heavily upon the 1984 Juneau 20-Year Power Supply Plan, the 1987 Energy Conservation and Management Plan, and the 1987 Southeast Alaska Transmission Intertie Study. The major change since the publication of the 1984 Juneau 20-Year Power Supply Plan is the potential reintroduction of gold mining in Juneau. Extra effort was taken to review past studies, update results to a consistent basis, and focus on rate, financial feasibility, and least-cost planning analysis. This chapter is a review of the most promising demand-side management program options, transmission intertie options, and generation or supply-side resource options considered in previous studies. Also discussed is the method used for updating costs to a consistent basis. The resources covered in this chapter are the options from which the alternate least-cost packages were constructed. The analysis shows that lighting-based conservation programs in the commercial sector have the greatest amounts of energy savings potential. They also have short payback periods and hence the potential for strong market penetration. Transmission intertie alternatives were found to be very expensive and did not provide access to inexpensive sources of surplus power. Ten hydroelectric options of various sizes, quantities of firm and nonfirm power, and seasonality were evaluated. Some of these projects, such as Lake Dorothy, appear quite attractive if all of their energy is needed. Other, smaller projects, such as dam additions to Crater and Long Lakes, appear to be quick and reasonably priced alternatives for adding firm energy to meet growing loads. A variety of diesel-fueled engine and combustion turbine alternatives were also evalu- ated. Of these alternatives, 900-rpm diesel engines appear to have distinct advantages of size, fuel efficiency, and cost. Finally, a small waste incineration facility was examined. CONSERVATION RESOURCE OPTIONS A major enhancement of this study over the 1984 Juneau 20-Year Power Supply Plan is the consideration and specific evaluation of a number of demand-side management program options. These options allow cost-effective conservation measures to be com- pared with supply-side resources. The recommendations of the 1987 Energy Iil-1 Conservation and Management Plan served as the initial basis for our selection of spe- cific conservation programs. This initial selection was subsequently modified by close work with the sponsors and members of the Juneau Energy Advisory Committee to fine-tune the alternatives to a list of the best and most promising options. The conser- vation savings discussed in this chapter are in addition to those embedded within the load forecast. . ENERGY CONSERVATION AND MANAGEMENT PLAN RECOMMENDATIONS The 1987 Energy Conservation and Management Plan recommended that conservation programs be part of a three-phase approach to allow for changes in response to signifi- cant projected shifts in Juneau’s future load-resource balance. The phases were Phase 1, the Pre-Crater Lake Period; Phase 2, the Period of Crater Lake Hydroelectric Surplus; and Phase 3, the Conservation Period to Delay or Avoid Additional Genera- tion Resources. : , Crater Lake is now operational, and Juneau is currently in Phase 2. Unless loads in- crease significantly, a hydroelectric surplus is forecast throughout the 20-year study period of this power supply plan. The 1987 Plan recommends consideration of dual- fuel heating systems and other methods of marketing the temporary surplus during this phase as a way of using local non-polluting resources. It also stresses the need for caution and careful market research to prepare for the time when the surplus diminishes. Either the A. J. Mine or the multiple mining load forecast scenarios would immediately move Juneau from Phase 2 into Phase 3. In Phase 3, a recommendation was made in the 1987 Plan to implement 27 specific conservation programs that passed a "no-losers" test. Such a test ensures that the conservation measures are of such a level of cost- effectiveness that no one is economically harmed by their implementation. Table S-2 in the 1987 Plan identifies the initial 27 conservation programs evaluated. Table III-1 shows the conservation programs chosen for this plan. From the utilities’ perspective, the most cost-effective of these programs are in the commercial sector. CONSERVATION IMPLEMENTATION METHODOLOGY In addition to reviewing programs identified in the 1987 Plan, we reviewed the methods used to calculate the savings of the various programs. Annual energy savings were estimated on the basis of the square footage of buildings in which programs were ap- plied. Initial Seattle City Light data within the 1987 Plan were checked for order-of- magnitude changes, and none were found. In the 1987 Plan, maximum penetration rates for various conservation measures were assumed to be a function of the payback to the customer. The maximum penetration rate of a measure as a function of its pay- back is shown in Table III-2. Iil-2 Table III-1 Conservation Programs Chosen for the Plan Electricity Savings Per Square Foot kWh per year Capital Cost 1990 First Lifecycle Economic Per Square Year Cost Levelized Life Foot (expensed) Costs (1990 $) Summer Winter (years) ($ 1990) cents/kWh cents/kKWh RESIDENTIAL New Single-Family Heat pump in place of FA 2.04 6.26 20 0.72 8.64 0.58 11 Reduce infiltration plus heat exchanger 0.05 1.54 30 1.47 92.25 4.71 88 Windows R2 to R8 1.15 3.53 30 0.86 18.38 0.94 2.4 Existing Single-Family Space heat = Heat pump retrofit in place of FA 2.04 6.26 20 3.77 45.44 3.05 5.6 oo Temperature Setback 0.89 2.72 15 0.05 1.39 0.12 0.2 kWh Savings per home Reduced infiltration .9 to .4 achhr (Cd=0.65) 4,819 annual 30 1.01 6 to 4 ac/hr (Cd=0.65) 1,928 annual 30 2.55 Floor insulation , R6 to R30 (Cd=1.0) 2,424 annual 30 1.77 R2 to R30 (Cd=1.0) 3,698 annual 30 1.16 Ceiling insulation R19 to R38 (Cd=1.0) 1,204 annual 30 1.49 Existing Multi-Family Space Heat Ceiling RO to R38 111 3.42 20 0.58 Floor R2 to R30 (Cd=1.0) 3.36 annual 15 0.98 (all general residential on a per-item basis) , Continued on next page a vil Table III-1 Conservation Programs Chosen for the Plan General Residential (on a per-item basis) Water heat--new housing New tank with improved--single-family Insulation and heat traps--multi-family Water heat--existing housing--single-family Tank wrap and heat traps--multi-family Lighting porch Internal COMMERCIAL Office Temperature setback Ceiling insulation Efficient lights Retail Temperature setback Ceiling insulation Efficient lights Other Temperature setback Ceiling insulation Efficient lights Street lights (on a per bulb-basis) Electricity Savings Per Square Foot kWh per year Capital Cost 1990 First Per Square Year Cost Foot (expensed) ($ 1990) cents/kWh Lifecycle Levelized Costs (1990 $) cents/kWh 303.5 150 242.5 116.5 500 annual 250 annual sea7309/004.51 Table III-2 , Payback Period Versus Penetration Rate Payback Period Maximum Penetration (years) (percentage) . fiesta [a estan? | Greater than 5 Source: Page 83, Volume 1, Energy Conservation and Management Plan, April 1987. Discussions with staff of Seattle City Light, the Bonneville Power Administration, and the Pacific Northwest Regional Power Council were held to probe the reasonableness of the assumptions used in Table III-2 in light of Pacific Northwest conservation imple- mentation experience. Based upon conservation experiences in the Pacific Northwest at Hood River, in Bonneville’s residential weatherization program, and in a number of commercial conservation programs, the values were generally felt to be reasonable for residential programs. During the fact-finding meeting with the sponsors, a concern was expressed that the commercial sector penetration rates in Table IIJ-2 might overstate actual maximum market penetration. This concern was based upon observed problems in persuading commercial and industrial operations to install conservation measures because of the costs of business interruptions. The concern is somewhat mitigated by the lack of traditional industry in the Juneau area and the governmental, educational, and institu- tional nature of much of the commercial office space in Juneau. Pacific Northwest conservation experience indicated that government buildings, educational buildings, and institutions like churches and hospitals tend to have less resistance to implementation of conservation than retail and industrial operations. The reader is cautioned against applying these penetration rate functions in the com- mercial and industrial sector without additional market research. Another caution is that implementation of certain measures in oil-heated buildings may increase the amount of fuel oi] consumed and thus indirectly increase the effective payback period. When we discussed conservation penetration rates with Seattle City Light, Bonneville Power Administration, and Pacific Northwest Regional Power Council staff, we also dis- cussed the length of time it would take to implement a conservation retrofit program. For all such calculations, Bonneville currently uses a 20-year implementation period before maximum penetration is achieved. Ti-5 Several of those interviewed urged caution in implementing short-lived retrofit pro- grams. Examples were given of the lack of trained conservation specialists and contrac- tors, which created initial problems in the Pacific Northwest. It was also pointed out that short-term programs can attract conservation delivery companies that are oriented to make quick profits and leave. Firms that are attracted by a long-term market op- portunity should be more oriented toward providing quality work and building a word- of-mouth reputation within the community that would allow for long-term profits and market share. Another point made in favor of a long-term retrofit program was that it would reduce swings in local employment, which became an issue when Bonneville reduced its residential weatherization program. On the basis of the above research and after consultation with the sponsors, this study uses the penetration functions found in Table III-2 for both residential and commercial conservation programs. We also assume that retrofit conservation programs are de- signed to capture the maximum retrofit market defined by Table IIJ-2 on a linear basis over a 20-year period. SELECTED CONSERVATION RESOURCE OPTIONS In the joint review by CH2M HILL and the sponsors of the 27 conservation programs included in the 1987 Plan, it became clear that a number of the programs would pro- duce few, if any, electric energy savings because of a combination of changes in tech- nology, historic building practices, and lack of potential places for application. Representatives from the Juneau Energy Advisory Committee also identified nine addi- tional conservation programs that should be considered in this update. After evaluation of these additional programs in a joint fact-finding workshop, 20 conservation measures were identified as the most promising opportunities. These 20 conservation resource options can be separated into five general categories: New Single-Family Electrically Space Heated Existing Single-Family Electrically Space Heated Existing Multiple-Family Electrically Space Heated General Residential Commercial Our approach was to identify the programs considered in each of these categories and discuss their general features. New Single-Family Electrically Space Heated There are three programs in this category: replacement of forced-air electric furnaces with heat pumps; special techniques to reduce infiltration, including the installation of a heat exchanger; and installation of special high-efficiency windows that have approxi- mately an R8 thermal resistance or insulating value. Ill-6 Four programs from the 1987 Energy Conservation and Management Plan are no longer applicable. These programs are installation of triple-pane windows instead of double-pane windows, installation of insulated doors, requiring that roof insulation be increased from R30 to R38, and requiring that floor insulation be increased from R19 to R30. Construction techniques and code requirements negate most.of these as viable conservation program options. For example, savings from thigh thermal efficiency (R8) windows surpass those from triple-pane windows. While it is recognized that only about 25 percent of new homes heated by electricity will be of a type that would contain central forced-air electric furnaces, it is expected that heat pumps can penetrate this market. Heat pumps have not had a good reputa- tion in the Juneau area because of problems with the design, installation, and mainte- nance of units installed in the 1970s. Despite this reputation, it is assumed that heat pump installation in new homes will be governed by the general market penetration assumptions. Existing Single-Family Electrically Space. Heated There are seven programs within this category. Of the seven, six were not part of the 1987 Plan. The seven programs are retrofitting heat pumps into electric forced-air furnace homes, installing temperature setback thermostats, two levels of air infiltration reduction based upon housing stock, two levels of improvement to floor insulation based upon housing stock, and increasing ceiling insulation from R19 to R38. Within the estimation of the energy savings from infiltration, floor insulation, and ceil- ing insulation, there was debate as to the appropriateness of American Society of Heat- ing, Refrigeration, and Air Conditioning Engineers (ASHRAE) empirically derived correction factors (Cd) when using a modified degree-day method for estimating heat- ing energy requirements. The sponsors agreed to use a Cd value of unity for floor insulation calculations and 0.65 for air infiltration and ceiling insulation calculations. ASHRAE recommends that Cd be set to 0.65 for climates with approximately 9,000 degree-days per year. To this extent, the conservation estimates may overstate conservation savings that would have been calculated by using ASHRAE methods. However, the level of accuracy of the conservation estimates using this approach was judged appropriate by the sponsors. Existing Multiple-Family Electrically Space Heated In the 1987 Plan, four conservation programs were identified for this sector. Only one of these was judged by the sponsors to have significant potential in the Juneau area. This program is increasing ceiling insulation from RO to R38. A new measure was calculated based on insulating floors in multi-family units from R2 to R30. As with the existing single-family structures, there was debate on the floor insulation estimation as to the appropriateness of ASHRAE empirically derived correction factors in accounting for the effects of degree days upon a typically unheated and vented crawl space. Il-7 Again, the use of a Cd of unity was judged appropriate by the sponsors for the level of accuracy of this study. General Residential In the 1987 Plan there were five general residential conservation programs. Our final selection included six such programs. Four of the six are from the 1987 Plan and in- volve water heating savings for existing and new single-family and multiple-family dwell- ings. The final two programs, not included in the 1987 Plan, involve the installation of energy-efficient lighting, both external and internal, to most residences in the Juneau area. While further research should be done on residential lighting savings potential, it was assumed that efficient exterior porch lighting could save approximately 500 kWh per year where applied, and that interior lighting could save approximately 250 kWh per year where applied. Commercial In the 1987 Plan, the commercial sector had four principal conservation programs: temperature setbacks of 10°F; increase in wall insulation from RO to R13; increase in ceiling insulation from RO to R30; and efficient lights. Based upon discussions with the sponsors, we have removed the wall insulation program because of building practices of including some wall insulation and the lack of economic practicality. The commercial sector has been divided into four subcategories: Office, Retail, Street Lights, and Other. The programs and savings for these subcategories are identical to those out- lined in the 1987 Plan. , SEASONAL AND CAPACITY ASPECTS OF CONSERVATION The electric power conservation programs described above are divided into two general categories: improved efficiencies in electric space or water heating and improved effi- ciencies in lighting. Both of these types of programs will produce the majority of their savings during the winter. We considered two methods of distributing conservation savings by season. The first method was to ensure that the savings were proportional to monthly average heating degree-days. The second method was to ensure that con- servation savings were proportional to monthly "burning hours." The U.S. Weather Service in Juneau was contacted for monthly daylight hours data. Average monthly daylight hours were subtracted from the total number of hours to determine the "burn- ing hours." Because most of the conservation savings are due to lighting programs, and because the winter proportion of burning hours to total burning hours was comparable to the proportion of winter heating degree-days to annual heating degree-days, total conservation savings were distributed on the basis of monthly burning hours. Conservation was also assumed to reduce winter peak load and resource capacity re- quirements. The reduction in capacity was assumed to be equal to the average level of Iil-8 conservation. Specifically, winter conservation energy savings were divided by the num- ber of hours during the winter period. EFFECTS OF CONSERVATION ON PEAK AND ENERGY FORECASTS Peak demand and energy savings due to demand-side options, including conservation and load management, are shown in Table III-3 for the A.J. Mine and multiple mine load forecasts. The first line shows the maximum potential savings (as discussed ear- lier) after considering the penetration rate for each program option. The remainder of the table shows the expected annual savings from each program type as the programs are ramped in. The effects of programmatic conservation load forecasts are shown in Table III-4. Figures III-1 and III-2 show the effects of programmatic conservation and load manage- ment on the peak demand forecasts under the A.J. Mine and multiple mine scenarios. Figures IIJ-3 and III-4 show the effects of programmatic conservation on the energy requirements forecasts. TRANSMISSION INTERTIE OPTIONS OVERVIEW Transmission interties can be considered as resource options if they provide access to existing sources of energy or if they can reduce the need for additional capacity. Both ‘types of interties were evaluated in the Power Supply Plan Update. In the 1984 Juneau 20-Year Power Supply Plan, three transmission interties were evalu- ated: Whitehorse (Yukon) to Juneau, Tyee Lake (Petersburg) to Snettisham, and a submarine cable from Snettisham to Juneau. Of these three alternatives, the White- horse-to-Juneau line appeared the most promising because it could potentially provide energy and capacity and reduce reserve requirements. The Tyee Lake-to-Snettisham project was expensive and did not add to reliability, but would have provided access to any excess Tyee Lake power. The Snettisham-to-Juneau submarine cable would have provided greater reliability but no additional capacity. Updated construction costs and life-cycle levelized costs for these three alternatives are summarized in Table III-5. Based upon the cost of transmission and the lack of low-cost surplus power, none of the interties were judged cost-effective. Iil-9 OT-TI Potential 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 A. J. Mine Forecast MW Savings Load Programmatic Management 2.9 3.4 3.9 4.2 45 48 5.0 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 Table III-3 Peak Demand and Energy Savings Due to Demand-Side Options MW Savings Load Management Programmatic Conservation Programmatic Conservation Conservation Multiple Mine Forecast 5.7 6.2 6.8 7.2 8.0 8.0 8.2 8.4 8.7 8.9 9.1 9.4 9.6 9.8 MWh Savings Due to Programmatic Conservation 33,973 1,836 3,673 5,315 7,120 8,925 10,609 12,293 13,967 15,640. 18,988: " 18,988 20,662 22,336 24,004 25,672 27,340 28,999 30,657 32,315 TTI Table III-4 Annual Energy Requirements Before and After Programmatic Conservation Base (No-Mine) Forecast AJ. Mine Forecast Multiple Mine Forecast MWh MWh MWh MWh MWh MWh Requirements Savings Requirements Savings Requirements Savings Before Due to Before Due to Net Before Due to Net Programmatic | Programmatic Programmatic | Programmatic MWh Programmatic | Programmatic MWh Conservation Conservation Conservation Conservation Requirements Conservation Conservation Requirements 277,000 0 277,000 277,000 0 277,000 277,000 0 277,000 280,600 1,670 278,930 288,500 1,779 286,721 293,300 1,836 291,464 283,500 3,339 280,161 300,100 3,559 296,541 309,700 3,673 306,027 286,400 5,003 281,397 534,300 5,217 529,083 612,200 5,315 606,885 289,700 6,667 283,033 543,600 6,981 536,619 625,500 7,120 618,380 292,400 8,331 284,069 552,900 8,745 544,155 638,600 8,925 629,675 295,100 9,995 285,105 555,400 10,428 544,972 641,200 10,609 630,591 297,600 11,659 285,941 557,900 12,112 545,788 643,600 12,293 631,307 300,300 13,323 286,977 560,400 13,786 546,614 646,000 13,967 632,033 302,800 14,987 287,813 562,700 15,460 547,240 648,300 15,640 632,660 305,200 16,651 288,549 565,000 17,134 547,866 650,600 17,314 633,286 307,500 18,315 289,185 567,300 18,807 548,493 652,800 18,988 633,812 309,700 19,969 289,731 569,500 20,481 549,019 654,900 20,662 634,238 311,900 21,623 290,277 571,600 22,155 549,445 657,000 22,336 634,664 314,100 23,271 290,829 573,600 23,823 549,777 659,000 24,004 634,996 316,100 24,920 291,180 575,600 25,492 550,108 660,900 25,672 635,228 318,100 26,568 291,532 577,600 27,160 550,440 662,800 27,340 635,460 320,100 28,216 291,884 579,400 28,818 550,582 664,700 28,999 635,701 322,000 29,865 292,135 581,300 30,476 550,824 666,400 30,657 635,743 323,800 ° 31,513 292,287 583,000 32,135 550,865 668,200 32,315 635,885 325,600 33,161 292,439 584,800 33,793 551,007 | 669,800 33,973 | 635,827 Cr-T PEAK DEMAND A.J. MINE FORECAST 120 1005 80- After Programmatic Conservation and Load Management 60- Before Programmatic Conservation and 40 Load Management 0 T T T J T T T T T . 17990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 ~ TI aansiy eI-Il PEAK DEMAND MULTIPLE MINE FORECAST Fak fter Programmatic Conservation 120 100+ 80- and Load Management Before Programmatic Conservation and 60- Load Management 40- 20; 0 T T T T T T T T T 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 TI ans vt-Ill i= = = ENERGY REQUIREMENTS _ sBetore A.J. MINE FORECAST Programmatic Conservation 600,000 , ~_! 500,000; . / After Programmatic Conservation 400,000; @ a 300,000 é 200,000+ 400,000+ 0 T T T T T T T T T . 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 yo ST-UI MWh ENERGY REQUIREMENTS __ Before MULTIPLE MINE FORECAST Programmatic Conservation 700,000- la 600,000, After Programmatic Conservation / 500,000- 400,000; Ill aansry 300,000- 200,000- 100,000- 0 T T T T T T t T T | 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 Table III-5 ‘ Transmission Interties |__| Whitehorse Juneau | Tyee-Snettisham | Snettisham-Juneau| January 1990 : Construction Costs $87 million $108 million $50 million 1990 Life-Cycle Costs NA (cents/kWh) 11.3 13.9 (no added energy) WHITEHORSE (YUKON) TO JUNEAU Since the 1984 Power Supply Plan, the Yukon assets of the Northern Canada Power Commission have been transferred to the Yukon Energy Corporation. To update pre- vious findings on the Whitehorse-to-Juneau transmission line, we contacted Yukon Electrical Co. Ltd., which manages the resources owned by the Yukon Energy Corpora- tion. Our initial findings indicate that neither surplus low-cost firm energy nor capacity exists on the Yukon electric system. This change from the 1984 Power Supply Plan and the costs of transmission produce high costs for this alternative. Although we have judged this alternative as not being cost-effective, a detailed discussion of our analysis follows. Currently, winter loads for the Yukon electric system are about 7? megawatts (MW). Of this, about 55 MW are served with hydro power and the remainder with diesel gen- erators. The Currugh Resource’s Cyprus Anvil mine (lead and zinc) represents about 22 MW and 160 GWh of annual load on the Yukon electric system. This mine, which was reopened in 1984, currently has about 10 years of proven reserves.: Its reopening has changed the Yukon power supply picture since the 1984 Power Supply Plan. Therefore, if proven mineral reserves were exhausted or world base mineral prices dropped, there could be some surplus power available from the Yukon. This power might be available on an annual basis at a melded hydro-thermal rate and could there- fore provide a partial basis for justifying transmission. However, current information indicates that no such surplus power is available. The Yukon Energy Corporation and the Yukon Electrical Co., Ltd., have evaluated a number of new generating projects, including several 1- or 2-MW hydro projects and a few projects up to 50 MW. Power costs from these projects have been estimated to be about 8 cents per kWh (10 cents per kWh in Canadian dollars) at the power plant. Adding the cost of transmission to Juneau would increase the price of power to well above that for Juneau diesel alternatives. The Yukon electric system is waiting for TII-16 loads to grow to the point where additional hydro generation can be justified on. the basis of reduced diesel production costs. Our initial information is that the Yukon electrical system has no immediate plans to develop any Jarge and extremely low-cost hydro projects. Costs and alternate methods and alignments were evaluated in a 1987 Southeast Alaska Transmission Intertie Study. The 1984 Power Supply Plan showed a Whitehorse-to- Juneau transmission line cost of approximately $102 million. This intertie consisted of 105 miles of 115-kV overhead transmission, 64 miles of 100-kV DC submarine cable, and a short distance of 69-kV overhead. The 1987 Southeast Alaska Transmission Intertie Study showed a Canadian border-to-Juneau transmission line cost of about $59 million. The 1987 study assumed that the roughly 93 miles of Canadian transmission to Whitehorse would not be paid for by the US. interties parties. It also assumed that the intertie would comprise about 113 miles of 138-kV AC overhead and 2.8 miles of 138-kV AC submarine cable. If the costs of the 93 miles of 138-kV transmission be- tween the Canadian border and Whitehorse are included, and adjustments are made . for the difference in cost between overhead AC construction and DC submarine cables, then the general costs of transmission have not decreased significantly since the 1984 Power Supply Plan. Two factors could modify the basic opinions within the 1984 Plan. First, the Kensing- ton and Jualin mines, which are part of the multiple mine load scenario used in this study, would require the construction of an electric transmission line from Juneau to the mines’ location just north of Breners Bay. Second, a movement has been started in Juneau to open a road between Juneau and Haines. Under the multiple mining load scenario, transmission north to the Kensington and Jualin mines might be required, as the mining loads are assumed to be part of the load served. The 1984 Power Supply Plan assumed, essentially, a Skagway-to-Bridget Cove submarine cable. In the 1987 intertie study, costs were based on transmission from Skagway to Juneau. The transmission line north to the mines will reduce the length of both transmission interties by at least 15 miles and the cost assumed in the previous studies. Second, should a road be built from Juneau to Haines, the cost of overhead transmis- sion in the 1987 study would be further reduced. In the 1987 study, over $7.7 million was included for right-of-way clearing and helicopter construction. Road access from Juneau to either Skagway or Haines would reduce the costs of transmission construc- tion. Similarly, if road access to Whitehorse were to occur along the Taku River and Atlin, the costs of this intertie could also decrease. Because transmission cost reductions have not occurred since the 1984 Power Supply Plan, and because Canadian power is not available due to the reopening of the Cur- Tugh Resource mine, the Whitehorse-to-Juneau intertie is not feasible compared with other alternatives. I-17 By taking the 1987 intertie study’s 138-KV AC H-frame overhead construction values, we were able to estimate the cost of 93 miles of transmission line between the U.S. and Canadian borders to be about $25 million in January 1990 dollars. The cost of the Skagway-to-Juneau preferred alternative in the 1987 study was reduced for the facilities that would be required to serve the multiple mining loads assumed in one of the load forecast scenarios. This resulted in a total Whitehorse-to-mines transmission intertie cost of $87 million at January 1990 price levels. The total estimated cost of this transmission line project is $108 million when interest during construction and bond issue financing costs are included. Our information is that new Canadian hydroelectric power costs an average of about 8 cents per kWh. The estimated effective cost of energy from this intertie alternative is the total of the annual cost, the transmission line cost amortized over 30 years, the expected cost of energy available from the Yukon, and the annual cost of transmission operations and maintenance. We have calculated the estimated 1990 power cost of the Yukon-Juneau alternative to be about 18 cents per kWh. The 1990 life-cycle Jevelized cost is 11.3 cents per kWh. . TYEE LAKE TO SNETTISHAM The Tyee Lake-to-Snettisham intertie was judged in the 1984 Juneau 20-Year Power Supply Plan not to be cost-effective. The costs in 1984 were estimated to be $55 mil- lion. The 1984 Plan assumed 110 miles of 100 kV DC submarine cable and 3 miles of 100 kV DC wood pole line. While the route, costs, and components have changed, the option is still not cost-effective. In the 1987 Southeast Alaska Transmission Intertie Study, a more detailed design was performed that included 79.5 miles of 100-kV DC submarine cable, 1.7 miles of 138-kV AC submarine cable, and 45 miles of 138-kV overhead wood pole H-frame construc- tion. The 1987 study estimated the cost of connecting the Snettisham Project to Tyee Lake at approximately $84 million. In January 1990 dollars, the transmission project would cost approximately $108 million. The total estimated cost of this transmission line project is $134 million when interest during construction and bond issue financing costs are included. The estimated effec- tive cost of energy from this alternative is the cost of Tyee power (6.4 cents per kWh), plus the cost of amortizing and operating the transmission line, over the expected amount of surplus energy available from Tyee Lake. Information from AEA indicated that 85,000 MWh per year of energy is now available from Tyee Lake. Based on these figures, we have calculated the estimated 1990 power costs of the Tyee Lake-Snet- tisham intertie to be about 23 cents per kWh. The 1990 life-cycle levelized cost is 13.9 cents per kWh. It should also be recognized that the energy from Tyee Lake would require either addi- tional backup diesel generation, because of the reliance on the same transmission line I-18 as current Snettisham production, or a second transmission line. Therefore, the full effective cost would be even higher than 23 cents per kWh. SNETTISHAM TO JUNEAU The final transmission alternative would be a submarine cable from Snettisham to Juneau. This alternative would provide no additional energy, but would reduce the need to maintain standby diesel generation. In the 1984 Plan, the estimated construc- tion cost of this 42-mile, 100-kV DC submarine cable was approximately $58 million. Using submarine cable costs for similar length underwater DC submarine cables, the _ Snettisham-Kake DC converter station, and AC terminal costs from the 1987 intertie study and updating the values to January 1990 construction costs results in an estimated cost of about $50 million. This alternative by itself does not produce any extra energy for the Juneau area, but it does improve reliability. The total estimated cost of this alternative, taking into account interest during construction and financing costs, is about $61 million in January 1990 dollars. Because additional energy is not provided, a life- cycle levelized cost cannot be calculated. When Snettisham and Crater Lake’s total 118,108 MWh of annual firm energy is needed, this transmission intertie’s annual costs would add about 4.5 cents to the cost of each kilowatt-hour of energy used in Juneau. GENERATION RESOURCE OPTIONS OVERVIEW . The generation resource options we have considered can be divided into three cate- gories: hydro alternatives, diesel power alternatives, and Public Utility Regulatory Pol- icy Act (PURPA)-type resources. Ten hydro alternatives at four sites were examined: Lake Dorothy, Annex Creek/Carlson Creek, Long Lake, and Crater Lake. Five diesel power alternatives were examined: three diesel engines and two diesel combustion turbines. One PURPA-type resource, Channel Sanitation, was also considered. Echo Bay Mining has been investigating the economics of powering diesel cycle engines with liquefied natural gas (LNG) and more recently with an LNG byproduct, liquefied petroleum gas (LPG). Echo Bay Mining has indicated that, should North Slope natural gas be liquefied in Alaska for shipment as a commodity to the lower 48 states and world ports, the price of LNG fuel in Alaska might be less than that currently charged for diesel fuel shipped to Alaska. Echo Bay Mining’s plan is to purchase LNG or LPG initially from a facility on the Kenai Peninsula now shipping only to Japanese markets and then to switch to the large Northslope LNG facility, or be able to capture the equi- valent cost savings because of competition. After its identification by Echo Bay Mining, this alternative fuel source was discussed with the sponsors. Siting and economic estimates of major natural gas pipelines and LNG port facilities are beyond the scope of this study. The low diesel fuel price TH-19 sensitivity analysis can be thought of as a method of approximating the LNG or LPG assumptions now being evaluated by Echo Bay Mining. On this basis, the sponsors agreed to continue with diesel as the principal fossil fuel, but to note with interest the work being done by Echo Bay Mining and, if major LNG facilities are constructed in Alaska, to consider LNG or LPG as an alternate fuel when the Juneau 20-Year Power Supply Plan is next updated. HYDROPOWER ALTERNATIVES The 1984 Juneau 20-Year Power Supply Plan included evaluation of the following hydroelectric projects: Lake Dorothy, Sweetheart Lake, Speel River, Thomas Bay, and Crater Lake and Nugget Creek. Also addressed, but not fully evaluated, were projects at Carlson Creek and Sheep Creek. Of these projects, Lake Dorothy was evaluated as the best major hydro project. For this 1990 update of the plan, rather than reevaluate Sweetheart Lake, Speel River, or Thomas Bay, the sponsors desired to more carefully evaluate Lake Dorothy in comparison to the Annex Creek site and dam additions at Long Lake and Crater Lake. This revised comparison is not to imply that the Sweet- heart Lake, Speel River, or Thomas Bay projects are worse or better than those studied in this report with the exception of Lake Dorothy. The Sheep Creek project, discussed in the 1984 Power Supply Plan, was not evaluated in this 1990 update because its development is being proposed by the A. J. Mine as part of the mine’s self-generation program. The A. J. Mine is proposing to construct a Sheep Creek hydro project that would reduce its need for burning fossil fuels. The project would produce between 13 and 30 million kilowatt-hours of energy per year with up to 5 megawatts of capacity. A significant aspect of the project is that it will be constructed over a period of time as a place to deposit mine tailings. It is not antici- pated to be in operation at the opening of the mine in 1993. The construction scheduling, energy projection, and engineering cost details of the Sheep Creek project are a function of A. J. Mine operator’s plans and did not lend themselves to evaluation. Capacity and energy from the Sheep Creek project can serve as a direct reduction. in fossil fueled resources in the least cost packages. Four hydropower sites were evaluated in this study. At least two alternative develop- ments were analyzed for each site. The four sites include: Lake Dorothy Annex Creek/Carlson Creek Long Lake at Snettisham Crater Lake at Snettisham FeENP The hydropower site investigation included a helicopter reconnaissance of the sites by the sponsor representatives and CH2M HILL engineers; a review of previous reports; discussions with equipment suppliers; preparation of construction cost estimates; and ‘estimates of the energy generated at each project. Information available from previous Til-20 a) reports was evaluated and used in connection with the cost and energy generation es- timates. Following are descriptions of the hydropower projects. Cost estimates for the projects are as of January 1990. A summary of the firm energy, average energy, and estimated cost of the projects is included in Table III-6. Lake Dorothy The Lake Dorothy hydroelectric project, previously studied for development, is a high head tunnel and lake tap project with an underground powerhouse at tidewater. The rock at this site is diorite, granodiorite, and gneiss. The tunnel would be 11 feet in diameter, approximately 14,000 feet long, and would be connected to a 7-foot-diameter, 1,600-foot-long vertical shaft. A 6-foot-diameter lake tap would extend from the verti- cal shaft to the lake. The lake tap would be at elevation 2,240, 182 feet below the lake surface elevation of 2,422. Approximately 130,000 acre-feet of storage above elevation 2,259, which would be the minimum lake operating level, would be available for generation. The lake tap would originate at the north end of Lake Dorothy, and the tunnel would extend west to Taku Inlet. Alternate tunnel alignments have been proposed from Lake Dorothy under or near Bart Lake. However, a hydrographic survey of Bart Lake made in December 1988 indicated that the lake’s depth is 543 feet, which would result in additional costs for tunnel alternatives near or under the lake. This Lake Dorothy project would produce an estimated 127,000,000 kilowatt-hours of firm annual energy, based on a simulated reservoir operation study made by the Bureau of Reclamation using water flow records for the years 1903-1922 and 1946- 1954. This project would provide a generation and transmission system for the loads in Juneau independent of the present Snettisham Project. The estimated construction cost of the project is $82.7 million. The 1990 life-cycle levelized cost is 3.5 cents per kWh, the second lowest cost of all generation options evaluated. The firm and average energy are the same for this project, making it particularly attractive. It is estimated that the project would take 3 years to construct and could be in commercial operation in 1996, assuming that no significant delay occurred during licensing or design. A specific assignment of this update was to evaluate the potential for staged construc- tion at the various hydroelectric projects. Staged construction is the ability to build a project in segments that can provide benefits as each is constructed. Staged construc- tion could be used to match generation to the size of load and hence minimize rate shock. However, staged construction tends to increase the total cost of construction. In consultation with the sponsors and because of the size and timing of additional energy requirements under the load forecast scenarios, staged construction was not fully evaluated at the Lake Dorothy and Annex/Carlson Creek hydro projects. It is only with Til-21 Table III-6 Estimated Firm Energy, Average Energy, and Costs of Hydroelectric Projects Estimated . 1990 Estimated Annual Life-cycle Annual Firm Average Estimated Levelized Energy Energy Construction Cost> Project (MWh) (MWh) Cost? (cents/kWh) Lake Dorothy 127,000 127,000 82,700,000 Lake Dorothy 42,900 40,300,000. Tunnel to Long Lake Long Lake 13,000 14,500,000 5.7 Elev. 845 (dam addition, 21 feet Long Lake 29,000 37,000,000 Elev. 870 (dam addition, 46 feet Long Lake © 38,000 53,500,000 Elev. 845 (dam addition, 21 feet Crater Lake 14,500,000 Elev. 1034 (dam addition, 13 feet) Crater Lake 38,000 53,500,000 Elev. 1047 (dam addition, 25 feet) Annex Creek 1,200 1,200 2,900,000 Annex Creek/Carlson 59,700 164,400 85,500,000 Creek, No. 1 Annex Creek/Carlson 155,400 165,500 209,300,000 Creek, No. 1 “Includes 15 percent contingencies and 17 percent for engineering and administration. Life-cycle costs are based on a 50-year resource lifetime, total bond issue and O&M costs, and annual average energy. sea7309/006.51 IN-22 the increased loads of the A. J. Mine or multiple mining forecasts that new generation projects are needed. Under these two load forecasts the major hydro projects can be fully utilized by 1993, which is sooner than the projects can be built under an expedited schedule. If the mines are committed to initially providing their own generation and there are capital rationing problems associated with the financing of the preferred _ alternative, Lake Dorothy, the sponsors may wish to reexamine the staged construction options of the preferred alternative. While exploring staged construction alternatives to Lake Dorothy we found a new alter- native which expedited the construction schedule, provided energy benefits and reduced initial costs. This alternative eventually became one of the three major hydro alterna- tives evaluated. This alternative to the development of Lake Dorothy would be to drive a tunnel from the upper end of the Long River and construct a lake tap to Lake Dorothy. The flow from Lake Dorothy would be regulated and discharged into Long Lake and through the Snettisham powerhouse. A significant amount, of head would be sacrificed for this alternative, but this would be a less expensive project and could be completed in less time than the project originally proposed. The estimated cost of this tunnel and facili- ties are $40,300,000; the project would increase the annual firm energy at Snettisham by 42,900,000 kWh. The 1990 life-cycle levélized cost of this project is 4.9 cents per kWh. A further staged modification to this project would be to construct a powerhouse at the end of the tunnel, although this would be expensive because of the inaccessibility of the site. This alternative would not provide an increase in Juneau reliability because it would use the existing Snettisham-to-Juneau transmission system. Long Lake Additional generation at the Snettisham hydro project could be produced by construct- ing a dam addition at the outlet of Long Lake to provide additional storage and in- creased head at the Snettisham powerhouse. The rock at this site is similar to that at Lake Dorothy. The Corps of Engineers studied the cost and benefits of three dam heights at Long Lake in its 1986 letter report entitled "Reassessment of Long Lake Dam." No new generating facilities would be required for this alternative; however, this _alternative would use the existing Snettisham transmission line and would not reduce generation reserve requirements. The natural outlet of Long Lake is at elevation 818. A steel and timber weir was re-_ cently constructed to raise the lake’s elevation to 824. The crest elevations of the three dams investigated by the Corps are 845, 870, and 895. A steel crib dam and a concrete dam were investigated for the low dam, while only concrete dams were investigated for the two higher dam alternatives. The intake gate structure would have to be modified for all three alternatives for operation at the increased reservoir levels. The intake gate allows water from the lake to enter the tunnel, which leads to the hydro turbine genera- tor. The intake structure has a construction joint at elevation 804 to facilitate raising Til-23 the dam. Energy values were calculated taking into account the current 824-foot eleva- tion. Table III-7 summarizes the estimated cost, annual firm energy, estimated earliest date of commercial operation, and 1990 life-cycle levelized cost for the three Long Lake alternatives. Table III-7 Long Lake Hydro Alternatives Estimated Estimated Annual Construction} Earliest 1990 Life-Cycle Firm on Cost Commercial| Levelized Cost Crest Elevation ($) Operation | (cents per kWh) 845 (stel exit 14300000 | 1993 | s6 870 (concrete) 37,100,000 pm | ss | 895 (concrete) 53,700,000 Crater Lake Generation at Snettisham could also be increased by the construction of a dam at the outlet to Crater Lake. This project, like the Long Lake project, would use the Snetti- sham powerhouse and transmission line and would provide no independent source for the Juneau generating system. Construction of a dam at this location would be more expensive than at Long Lake because of the poor access to the area, the limited work area, and the topography of the site. The rock quality at the site appears to be satis- factory for the construction of a dam, although the rock drops off steeply downstream of the outlet, which would make support for a high dam difficult. Construction of a dam over 13 feet high would require modification of the intake structure, which is lo- cated at elevation 1,040, about 20 feet above the outlet of Crater:-Lake. A 13-foot-high concrete dam with a crest elevation of 1,034 is estimated to cost $2.7 million and would produce an additional 2,900,000 kWh of firm energy per year at the Snettisham Project. Its 1990 life-cycle levelized cost would be 4.6 cents per kWh. This dam could be constructed in about 1 year and could be operational by 1993. A concrete dam 25 feet high with a crest elevation of 1,045 is estimated to cost $6.3 mil- lion, including modification of the gate structure, and would produce an additional 6 million kWh of firm energy a year at Snettisham. Its 1990 life-cycle levelized cost would be 5.3 cents per kWh. Construction of a 25-foot-high dam is estimated to take approximately 18 months; the dam could be operational by 1994. TH-24 Annex Creek/Carlson Creek Expansion and rehabilitation of the Annex Creek Project.was investigated by Bechtel in 1959 and 1966 and updated by Ebasco in the 1984 Power Supply Plan. The existing project at Annex Creek consists of a 3.3-MW powerhouse at the end of a tunnel and penstock leading from Annex Lake. A 25-foot-high timber crib dam has been con- structed to raise the elevation of Annex Lake to 844. The Ebasco report states that the addition of a 2,900-kW unit would increase the firm energy produced at Annex Creek by 1,200,000 kWh a year over the current firm energy production of 22,700,000 kWh. The estimated cost for this addition is $2,910,000. The topography of the Annex Lake outlet precludes the economical construction of a dam higher than the existing one. In 1987, Mr. B. G. Hildyard investigated the possibility of increasing the generation at the Annex Creek project by driving a tunnel between the Annex Creek drainage area and the adjacent Carlson Creek drainage area and substantially upgrading the Annex Creek powerhouse. Two sites were investigated for a diversion dam on Carlson Creek to channel the water into the tunnel. This plan would increase the effective drainage area of Annex Lake from 6.4 square miles to 18.9 square miles and would increase the powerhouse capacity at Annex Creek to approximately 28 MW. The present transmission line from the Annex Creek powerhouse over Powerline Ridge to the Thane substation experiences high losses because of the need to prevent icing and is subject to outages in severe weather. Portions of this line are approximately 40 years old. Construction of a new powerhouse at Annex Creek should also include a new transmission line to enhance reliability. This alternative would provide new capac- ity independent of the Snettisham-to-Juneau transmission line. A route near the water line along the west side of Taku Inlet should be investigated as an alternative to re- building the existing transmission line route. Although detailed reconnaissance of this route was not made for this study, a review of the USGS maps and a general observa- tion of the area leads to the conclusion that this may be a feasible transmission line route. The estimated cost of a diversion dam, an 11-foot-diameter tunnel, a 78-inch-diameter penstock, and a new 138-kV transmission line for this project is $96,100,000. The 1990 life-cycle levelized cost of this resource is 3.1 cents per kWh. The project would pro- duce an average of 165,500,000 kWh of energy a year, with firm energy of 59,700,000 kWh based on the low-flow year of 1951-52. The period of record reviewed for the estimate of firm energy was 1940 to 1970, as developed by Mr. Hildyard in his 1987 studies. Much of the energy in this alternative is distributed in the summer months at a time when it may not be usable in serving Juneau loads. Thus, although the life-cycle level- ized cost of this alternative is lower than those for all of the generation options and many of the conservation resource options, it entails economic risk. The risk is based TI-25 upon the high amount of nonfirm energy and the potential for an increase in added costs during dry water years. While life-cycle levelized costs and most economic evaluations are based upon average energy produced over a long period of time, such as 50 years for this resource, the amount of nonfirm energy can be either greater or less in any particular year. In a dry year, diesel generation would need to be run, and the resulting fuel costs would in- crease the total costs for that year. This increase in costs could produce temporary rate shocks to the Juneau economy. Conversely, if loads are well in excess of the average amount of hydroelectric energy and diesel generation could be displaced in an above- average water year, then there could be fuel savings. A key factor in further evaluating this very low life-cycle levelized cost resource is to examine both the impacts of sea- sonal loads and the potential for diesel displacement in an above-average water year. The firm energy output of this project could be increased by the construction of a stor- age dam on Carlson Creek. The rock is metamorphic, and many of the beds are of good quality for rock fill and aggregate. Overburden on the sides of the canyon is min- imal, as most has been scoured away by glaciers. Overburden in the bottom of the can- yon is of unknown, but possibly significant, depth. Because of its granular nature, the material would have to be removed to the top of rock. The site appears suitable for an arch dam of limited height or a roller-compacted concrete dam. A 400-foot-high dam on Carlson Creek would provide 100,000 acre-feet of storage. This storage would increase the firm energy produced by a 28-MW powerhouse at An- nex Creek to 155,400,000 kWh and would increase the cost of the project to $245,200,000. The 1990 life-cycle levelized cost of this resource is 7.9 cents per kWh. A dam at the upper site investigated by Mr. Hildyard would not be economical in pro- viding sufficient storage to warrant the site’s consideration for a storage dam. DIESEL POWER ALTERNATIVES Our evaluation of diesel power alternatives for the Juneau 20-Year Power Supply Plan Update focused primarily on 3-MW, 900-rpm diesel engines. Combustion turbines and slow-speed diesels are alternatives that have advantages for special applications. We focused on 3-MW, 900-rpm diesel engines because of their relatively high fuel effi- ciency, their moderate capital cost, and their flexibility in matching resource installation with load growth requirements. While combustion turbines have lower capital costs on a per-kilowatt basis, they tend to be larger and less fuel-efficient. One method of enhancing combustion turbine fuel efficiency is to include a waste heat recovery steam turbine. Such an approach, how- ever, increases both the size and the capital requirements for the unit. There are many good combustion turbines in the 20-MW or larger size range that are used by utilities in Alaska. Two General Electric combustion turbines were evaluated, III-26 a GE Frame 5 (PG5371PA) and an LM 2,500 PE. An operational problem with the base load use of larger machines in Juneau is that such machines would be among the largest on the electric system and could be the basis for determining reserve requirem- ents. Consequently, for a given level of reliability, more resources would be devoted to reserves than would be required from smaller machines. Similarly, all other things be- ing equal, the smaller machines should provide greater reliability in the event of multi- ple equipment failures. These factors were why we focused on small combustion turbines. Low-speed diesel engines were also examined. They tend to provide high fuel effi- ciency (below 9,000 Btu/kWh-HHV). However, as with combustion turbines, the size used by electric utilities is 10 to 20 MW. Accordingly, these engines suffer from size- related flexibility and capital problems similar to those faced by large combustion tur- bine units. One special advantage of low-speed diesels is that they can burn a variety of petroleum fuels. Some utilities using low-speed diesels have found that burning re- sidual oil (No. 6) and even crude oil allows them to reduce their fuel costs dramatically. Our evaluation of 900-rpm diesel generators included both General Motors Electro Motive Division (EMD) units and Caterpillar (CAT) 3600 series units. Both types of units have a number of positive features. The EMD units are relatively inexpensive due to mass production and their use in railroad locomotives and ships. The CAT 3600 series units have efficiencies comparable to those of slow-speed diesels and the ability to burn heavier blended fuels. In evaluating two-cycle EMD units, we examined 16- and 20-cylinder units with 645- and 710-cubic-inch displacement per cylinder. We selected EMD 20-cylinder 645 mach- ines for two basic reasons: cost per kilowatt and fuel efficiency. The capital costs of the 20-cylinder machines on a dollar-per-kW basis appear to be lower than those for the 16-cylinder machines due to economies of scale. Because the EMD 645 engine has been in production longer, its capital cost on a dollar-per-kW basis is 4.6 percent less than that of a 710 engine. From a fuel efficiency standpoint, 20-cylinder 710 units and 20-cylinder 645 units have approximately the same fuel efficiency. We verified this with both factory and distributor representatives. Therefore, we selected for our modeling the EMD 20-cylinder 645-F series engines as the principal two-cycle diesel engine. We also investigated used or remanufactured engine costs. A good EMD 645-E series engine that has been fully inspected and re- manufactured can reduce initial engine generator costs by about 31 percent. The older E series engine will have slightly higher (5.5 percent) fuel consumption. In the CAT 3600 series we examined both 12- and 16-cylinder units. The CAT 3600 series isa relatively recently designed four-cycle diesel unit. The technology of diesel engines is changing and should be monitored by the sponsors. After determining the number of units in the field and the relative costs of the 12- and 16-cylinder units, we I-27 focused on the 12-cylinder units because there were more in service (36 versus 9) and. the reliability of such new units have been more thoroughly proven. The approximately 9,300 Btu/kWh-HHV net station heat rate of the CAT 3612 engine generator units indicates remarkable fuel efficiency. We verified the general level of engine efficiency by discussions with current and former operators of the Metlakatla CAT 3612 installation. The CAT 3612 is also capable of burning heavier grades of fuel and blended fuels. The 1990 life-cycle levelized costs for diesel-fueled engines and CTs are a strong func- tion of the amount of energy produced by the resource. Plant factor is a common mea- sure of the amount of energy a project produces relative to its maximum production capability. The plant factor of a resource is the average hourly amount of energy the plant produces in a year divided by the maximum amount of energy it can produce in an hour. We selected three alternate plant factors to perform our life-cycle levelized cost evalu- ation of diesel engines: 10 percent, 50 percent, and 80 percent. The 10 percent plant factor would be associated with a diesel unit that is used in a standby power production mode of operation. An 80 percent plant factor represents baseload or near-continuous operation for a diesel unit. The 50 percent value provides an intermediate evaluation point. Because of relatively poor fuel economy, CTs were not evaluated at 80 percent plant factors. Because of the low capital cost in dollars per kW for rebuilt GM EMD diesel engines, CTs did not appear to have an advantage in reserve or standby generation and were not evaluated at a 10 percent plant factor. Rebuilt GM EMD diesels were not considered appropriate for base load generation and were not evaluated for this use. Table III-8 summarizes the life-cycle levelized costs of the diesel-fueled alternatives considered. Detailed information on the calculation of these life-cycle levelized costs can be found in Appendix A. PUBLIC UTILITY REGULATORY POLICY ACT (PURPA)-TYPE RESOURCES Under the Public Utility Regulatory Policy Act (PURPA), utilities are required to buy energy from qualifying facilities, generally cogeneration or small power production facilities, at their avoided cost. Of the PURPA-type resources identified, the Channel Sanitation Corporation, a municipal waste incineration facility, appears to be the most likely. Many communities are using municipal waste incineration as a method of reduc- ing the volume of waste to be landfilled and of providing heat to operate a steam boiler, electric turbogenerator power plant. It is important to point out that Channel Sanitation by itself is a very small resource compared to the major hydroelectric alter- natives. THI-28 Table III-8 Diesel-Fueled Alternative Life-Cycle Levelized Costs (Cents per kWh) 1990 Life-Cycle Plant Factor | Levelized Cost Resource GM-EMD 20-645-F GM-EMD 20-645-E (rebuilt) CAT 3612 10% 13.3 50% 8.4 80% 7, 9 GE PGS37IPA GE LM2500PE While in Juneau, we talked to a representative of Channel Sanitation and viewed their facilities. Currently, Channel Sanitation has a mass-burn facility where the thermal energy of the municipal waste is not used. Past studies of placing a 0.75-MW steam boiler in the flue gas stream to recover energy have indicated a price of electricity start- ing at 6 cents/kWh and increasing at the general inflation rate. The 1990 life-cycle levelized cost for this resource is 6 cents per kWh. From an engineering standpoint, such a modification appears technically feasible. Channel Sanitation indicated that they will be required to modify their pollution control system within the next 2 years to comply with new Alaska air pollution standards. The cost of adding generation would be minimized if the addition were coordinated with the pollution control equipment change at the mass burn facility. ~ COMPARABLE COST PROCEDURE All estimated construction costs were converted to January 1990 dollars. Construction costs were based on either: (1) current manufacturer or vendor estimates, (2) recent CH2M HILL experience, (3) recent bid data and experience of others, furnished by the sponsors, or (4) work performed in previous studies by others that has been reviewed by CH2M HILL. To convert to January 1990 dollars, Pacific Region Handy-Whitman cost indexes were used to bring the values to July 1988 dollars. From July 1988 to July 1989, U. S. Bureau of Reclamation construction cost estimates, as reported in the I-29 September 21, 1989, issue of Engineering News Record, were used. The rate of escala- tion from July 1989 to January 1990 was assumed to be approximately half the U. S. Bureau of Reclamation July 1988 to July 1989 value. Conservation measure costs were based either upon estimates of current labor and material costs or upon values in the 1987 Plan adjusted by the Anchorage, Alaska, CPI from the first half of 1985 to the first half of 1989. To adjust the resulting numbers to January 1990 levels, we increased costs by 1 year of general inflation at 4.5 percent. Because of the numerous studies that have been performed, we were able to gain in- sights into alternate methods of costing and designing similar alternatives. Based on this knowledge, we could compare components and use different studies and our own experience to check the reasonableness of the costs derived for the various alternatives studied. sea7309/027.51 I-30 RAR RE IV. PLANNING APPROACH IV. PLANNING APPROACH OVERVIEW In this study, CH2M HILL first performed an initial screening of resource alternatives that passed a fatal-flaw analysis. Estimated construction and operating costs were used to calculate life-cycle levelized costs for each alternative, which were then used to rank supply- and demand-side alternatives. Life-cycle levelized costs represent projected average costs per kWh in real terms (i.e., relative to other prices) over the economic life of the project. This method has been accepted by the utility industry as a way to compare dissimilar power supply alternatives fairly. Next, we developed three "least-cost" packages of resources to meet the projected load increases under the A. J. Mining and multiple mine forecasts. These scenarios used one of the three most feasible major hydro project alternatives and a mix of conserva- tion, load management, minor hydro dam additions, and GM EMD diesel units studied in the other tasks. The amount of new resources required was generally determined using the lowest life-cycle levelized costs and the ability of resources to serve the fore- cast load. Amounts of conservation and load management were estimated jointly by CH2M HILL and the sponsors. While there may be individual actions, as opposed to the one-utility planning concept assumed within this study, this plan will be of value. The approach identifies the types of resources being considered and presents their costs on an equal basis. To the extent that proprietary information on financing alternatives available to the mines is not in- cluded, this study provides the mines with a document that can be used for the purpose of refining their alternatives. Similarly, should changes occur in the mines’ self-genera- tion plans, then the community has a plan in place that can address the total needs of the Juneau area. In the next step, we evaluated the scenarios against an optimized diesel base case from a net present value perspective, using our computer spreadsheet model. The new energy resource scenarios were evaluated only for the A. J. Mine and multiple mines, as no new generating resources are required under the base (no-mining activity) fore- cast. Our cost analysis extended for 50 years to capture the inherent long-term benefits of hydro power. In our analysis, the load and resource mix were held constant past the 20th year. Present values of the 50-year costs were calculated to allow an economic comparison to be made. We then analyzed each alternative energy supply scenario from a rate and financing perspective. Our interactive spreadsheet model uses power supply costs, load forecast, financial, and average generation or bus bar power cost data to evaluate financial and rate impacts on the customers of AELP. Our rate analysis is based upon calculations of average bus bar cost estimates on a per-kilowatt-hour basis from three perspectives: system average generation costs, mining power costs if take-or-pay contracts are put in place, and non-mining average power costs. One aspect of the bus bar analysis is that the principal hydro project debt is retired over a 30-year period. Rates to the mines would be higher if this debt were retired only over the 12 years of known ore reserves. Finally, a sensitivity analysis determined the impacts of a major increase in the price of fuel oil, minor changes in load level, and changes in the cost of the most likely hydro- power resources. As previously stated, if any of the mines under investigation within the Juneau area proceed to development, each mine operator tentatively plans to install its own diesel generators at or near the mouth of the mine. The mining companies have chosen this course for a variety of reasons: (1) according to mining representatives, the cost of financing using gold loans appears to be substantially lower than for sources of finance available to the sponsors; (2) there is uncertainty as to the ability of the utilities to install generation equipment in a timely manner; and (3) the mining companies’ are reluctant to sign the type of binding take-or-pay. contract necessary to finance and build new generation capacity. It is hoped that the information within this study can quantify options and allow the sponsors and the mine operators to mutually explore electric service alternatives. SELECTION OF LEAST-COST MIX OF RESOURCES Life-cycle levelized costs of the generation, transmission, and conservation alternatives were prepared. These values are summarized in Table IV-1 and presented in detail in Appendix A. During the January 4, 1990, meeting with the sponsors’ representatives and the Juneau Energy Advisory Committee, the alternatives and their life-cycle level- ized costs were discussed. From this discussion we selected the three prime hydro alternatives: Lake Dorothy, Annex Creek/Carlson Creek, and the Lake Dorothy/Long Lake Tunnel. The fourth major resource alternative studied was the diesel alternative. Under the no-mining activity load forecast, no new resources are required. There is a continued surplus of hydroelectric energy. Load management from the yet-to-be-pub- lished AELP Load Management Plan was included as a way to reduce reserve require- ments on the AELP system. Load management is projected to save approximately 5 MW of capacity in the year 2000. Under the other two load forecast scenarios, substantial new generation is required by 1993. Generally, programmatic conservation resources are the most attractive and have been chosen first to meet this added load. Additional embedded conservation savings are included within the forecast scenarios. Next, Crater Lake elevation 1034, Channel Sanitation, and Long Lake elevation 845 were added to meet additional loads because of their availability in 1993 and their low life-cycle levelized costs. Existing diesel gen- erating units were dispatched to serve mining loads, New diesel generating units were IV-2 Table IV-1 1990 Life-Cycle Levelized Costs Resource Cents per kWh Load management Office temperature setback Existing SF temperature setback Other temperature setback Retail temperature setback ‘New SF heat pump in place of FA Existing MF ceiling RO to R38 Existing SF hot water tank and heat traps New SF windows R2 to R8 Existing MF floor R2 to R30 Existing SF .9 to .4 ac/hr Retail ceiling insulation Other ceiling insulation Existing SF floor insulation R2 to R30 Retail efficient lights Other efficient lights Office efficient lights Office ceiling insulation . Existing MF hot water tank and heat traps Existing SF ceiling insulation R19 to R38 New SF hot water tank, insulation, and traps Existing SF floor insulation R6 to R30 Residential porch lighting Residential internal lighting Existing SF .6 to .4 ac/hr New MF hot water tank, insulation, and traps Existing SF heat pump retrofit Annex/Carlson Creek No. 1 Lake Dorothy Other street lights Crater Lake El 1034 New SF reduce infiltration plus heat exchanger Dorothy/Long Tunnel Crater Lake E1 1047 Long Lake E1 845 Channel Sanitation Long Lake E1 870 Long Lake E1 895 CAT 3612 80% Annex/Carlson Creek No. 2 GM-EMD 20-645-F 80% CAT 3612 50% GM-EMD 20-645-F 50% GM-EMD 20-645-E used 50% GE LM2500PE 50% GE PG5371PA 50% Whitehorse-Juneau intertie Annex Creek . GM-EMD 20-645-E used 10% GM-EMD 20-645-F 10% CAT 3612 10% Tyee-Snettisham intertie Snettisham-Juneau intertie NA? 0.11 0.12 0.15 * 0,20 0.58 0.58 0.71 0.94 0.98 1.01 1.12 1.15 1.16 1.17 1.19 1.22 1.32 1.48 1.49 1.60 1.77 2.47 2.55 2.55 2.65 3.05 3.1 3.5 4.42 4.6 4.71 4.9 5.3 5.6 6.0 6.5 14 19 19 8.1 8.4 8.5 8.6 9.2 10.7 11.3 11.6 118 13.0 13.3 13.9 NA? *No added energy; only capacity benefits. 1990 Life-Cycle levelized costs are not first year costs. also added because they would be installed in time to meet mining loads in 1993 and because their life-cycle levelized costs are lower than those of other alternatives. Then one of the three appropriate hydroelectric units was added to serve loads in the A. J. Mine and multiple mine load forecast scenarios. When the hydro unit was added, generation at existing and some new diesel units was curtailed, and these units either re-entered a standby mode of operation or were sold for their salvage value. Once the major hydroelectric project was assumed to enter commercial operation, no further resources were required. The results of the analysis indicated that when diesel generation was initially required, it supplied base load energy to the mines. This resulted in selection of a fuel-efficient diesel over a CT or a rebuilt diesel engine. Because of the closeness in lifecycle level- ized costs between the CAT 3612 and the GM-EMD 20-645-F and because of AELP’s operating and maintenance experience with GM-EMD units, we chose the latter as the diesels to model. The technology of diesel enginges is changing and resulting in more fuel-efficient units such as the CAT 3612. If fuel prices are higher than forecast, the choice of diesel engines should be reevaluated.. When a major hydropower resource was added, the dispatch model tried to reduce generation at both the diesel units and at the Channel Sanitation PURPA unit. Examining these findings, we concluded that the apparent savings associated with the slightly lower life-cycle levelized cost of Channel Sanitation did not lower the total costs of the least-cost resource package. If Channel Sanitation energy was purchased and then displaced, the unit would essentially be shut down after the major hydro project is brought online. In this case, the lack of need for the project and low generation use and energy sales revenues would probably not warrant the investment in equipment. If, on the other hand, Channel Sanitation energy was not displaced, it would raise the costs of the least-cost package. This problem was solved for diesel units by assuming that after the major hydro project came on line, diesel units would be shut down and some sold for their salvage value. Such a salvage sale solution for the Channel Sanita- tion generation is counter to most PURPA resource contracts. Another interesting point was the way in which the need for capacity was initially satis- fied by conservation and diesel generation. While.the Long Lake and Crater Lake dam additions provide relatively low-cost energy, they do not provide any additional capacity, and they increase the plant factor at the Snettisham powerhouse. This lack of capacity tended to work against the higher-elevation dam additions when Long Lake and Crater Lake were included in the least-cost package. The more expensive Long Lake dam addition also did not improve the economics of the least-cost package when combined with the Annex/Carlson Creek No. 1 hydroelectric resource. COMPUTER MODEL The power planning computer model was developed to perform three functions: 1. Determine the need for new capacity or energy resources. 2. Simulate a monthly dispatch of resources to meet projected energy re- quirements and summarize the results seasonally and annually. 3. Determine the annual power costs and net present value associated with specific combinations of supply- and demand-side resources. DETERMINATION OF THE NEED FOR NEW RESOURCES The need for new resources is identified in three steps. First, installed capacity in a given year is compared with the projected peak demand for the year plus reserve re- quirements. Next, the energy-producing potential of installed resources is compared with the projected annual energy requirements. Finally, the results of the energy dis- patch are compared with the annual energy requirements to ensure that seasonal energy limitations of hydroelectric resources do not cause shortages during the year, i.e., unserved energy. New resources, if required, become part of the installed resource ‘base for subsequent years. No new resources are required under the base (no-mine) load forecast. In both the A. J. Mine and multiple mine load forecasts, new capacity resources are required in 1993, Small amounts of new capacity are required during the remainder of the forecast period. In no case did the annual energy requirements exceed the capability of the installed resource base. Often, however, the need for new energy resources accompa- nied the need for new capacity. More significantly, because of economic advantages, new capacity beyond that required to meet peak demands plus reserves was added to displace older, less efficient diesel resources. MONTHLY ENERGY DISPATCH SIMULATION The effects of conservation and load management programs were used to reduce the peak demand and energy requirements forecasts. Next, a simulated monthly energy dispatch was performed, based on the operation of resources in the following order: ° AELP hydro resources (Annex Creek, Salmon Creek, and Gold Creek) ° The Snettisham/Crater Lake hydro project . New major hydro projects (Annex Creek/Carlson Creek, Lake Dorothy, and Lake Dorothy/Long Lake Tunnel) . Modifications to existing hydro projects (expansion of Crater Lake and Long Lake dams) ° Waste-to-energy facilities (Channel Sanitation) ° New diesel units (GM EMD 20-645-F) ° Existing diesel units (Lemon Creek gas turbines and diesels, Auke Bay diesel, and Gold Creek diesels) All units were derated for forced and scheduled outages, and output was adjusted to reflect transmission losses. The monthly dispatch simulation approach was selected based on the need to ade- quately account for seasonal variations in the energy-producing capability of existing and proposed hydroelectric power projects. In particular, the Annex Creek/Carlson Creek project has limited storage capacity and therefore has a relatively large amount of nonfirm or secondary energy that is available only during the summer months. Our monthly dispatch simulation model captures the effects of seasonality, thereby providing more accurate results. Seasonal and annual summaries of the monthly analysis are included in Appendix B of this report. BUS BAR COST ANALYSIS As a basis for insight into potential rate shock from the cost of new resources, bus bar power costs were projected for each forecast scenario. Bus bar costs are the average costs of a generating resource at the point of its connection to the utility transmission and distribution system. The results of the dispatch simulation were used directly in the determination of AELP’s annual bus bar costs in cents per kWh. Three perspectives are used to evaluate the potential impact of the various alternatives on rates: the aver- age bus bar cost of resources to all loads; the average bus bar cost to the mines under a marginal cost allocation to them; and the average bus bar cost to the non-mining load, assuming that the mines pay the full marginal cost of all new resources developed to meet their requirements. Bus bar costs and the three perspectives were chosen to provide a reasonable range of rate information. A single retail rate estimate was not developed because AELP retail rates are set by the APUC. Because the exact cost allocation strategy that would be approved by the APUC is unknown, it is difficult to project future retail rates. Two generation cost allocation strategies would be to base rates to mining loads using either marginal or average generation costs. Bus bar costs are the largest component of cur- rent AELP retail rates and, therefore, changes in the bus bar cost can serve as an indicator of what costs might be added to retail rates. From an examination of bus bar costs, policymakers can determine if rate shock is likely to occur under any of the least- cost packages. To establish the first two perspectives, AELP’s bus bar costs were allocated between mining and non-mining loads under the assumption that mining loads would pay full marginal costs. The mines’ signing of take-or-pay contracts would effectively result in this type of marginal cost allocation. In this analysis, all costs associated with existing AELP hydroelectric projects were assigned to non-mining customers. All fixed costs associated with existing diesel resources were assumed to relate to capacity reserve requirements and were therefore assigned to non-mining customers. Variable costs reflecting power purchases from the Snettisham/Crater Lake project were prorated between the mine(s) and non-mining customers based on the amount of Snettisham energy purchased to serve each of these two groups of customers. All costs (capital, fuel, and O&M) associated with new hydroelectric or diesel resources were assigned directly to the mine(s). An important element in modeling the average bus bar cost of generation is the differ- ence in the cost of Crater Lake and Snettisham power with and without the mining loads. Because APA needs to make Treasury repayments, additional sales of surplus power from Crater Lake and Long Lake at Snettisham at current rates could generate sufficient revenues to prevent an APA increase in wholesale rates to AELP. This is supported by a letter from APA to CH2M HILL provided as Appendix C. In the modeling, we observed near-constant nominal average power costs from a non- mine customer perspective over the study period for the A. J. Mine and multiple mine load levels. When expressed in real terms, this actually translates to a reduction in electric rates to the non-mine customers of AELP. Next, the third perspective was calculated. As the sponsors have suspected, under the average power perspective the diesel or base case shows a lower initial year average power cost than any of the hydro least-cost resource packages, even though the hydro least-cost packages result in lower rates toward the end of the study period and lower present values. Depending upon the specific least-cost package of resources and the specific load forecast scenario (A. J. Mine or multiple mines), the crossover point for system average bus bar costs is between 2005 and 2010. : From the general approach discussed in this section, we developed the specific annual bus bar cost data and then determined annual cost impacts in real and nominal terms for residential customers, using the two alternate cost allocation methods. The specific results of this methodology are discussed in Section V. RELIABILITY EVALUATION This section will discuss general concepts of reliability in terms of the cases examined in this study. A more detailed treatment of specific reliability and reserve levels will be presented in Section V, where findings are discussed. Currently, AELP and APA use a reliability criterion based upon the concept that the system should be capable of serving its load after a single contingency; for example, the loss of a transmission pole or a generating unit. The reliability criterion is not an instantaneous ability to serve load requirements as is found in some areas of the United States. Based on the geography of the area, the size of the utility, its mix of resources, and its distance from other major cities, the reliability criterion for Juneau appears reasonable. An examination of outage records indicated that weather, switching, relaying, and Snet- tisham transmission-related outages are the major determinants of reliability. There are many measures of reliability; the most important for Juneau is the avoidance of total system outages for extended periods of time. The backup diesel and combustion turbine generation provided by AELP is sufficient to prevent extended outages under a reasonable set of scenarios. AELP takes a number of steps to minimize the time necessary to get backup genera- tion into operation. First, diesel engines are kept in a warm standby condition though the use of water jacket heaters. Second, contract maintenance and testing of combus- tion turbines appears to occur regularly. Higher levels of reliability could be achieved on the AELP system if additional diesel units were kept operating to maintain spinning reserves. However, such a change in operating policy would be very unattractive from both cost and environmental perspectives. To keep spinning reserves available to pick up load in the case of a Snettisham trans- mission line outage, large quantities of diesel engine or combustion turbine nameplate capacity would need to be partially loaded. However, partially loaded combustion turbines and, to a lesser extent, partially loaded diesel engines are not as fuel-efficient as units operated at their optimum design load. Partial loading to provide spinning reserves would also increase the amount of water spilled from Crater Lake and Long Lake. Therefore, under partial loading, much higher fuel and operating and maintenance costs would be incurred to provide spinning reserves. Fuel burned in the partially loaded diesel engines and turbines would at times contribute to local air pollution. When these factors are combined with attitudes toward outages expressed in interviews by local leaders of the community, near-continuous reliability, as would be provided by spinning reserves capable of meeting a single contingency outage, does not appear to be required for the general customer of AELP. Of the resource packages evaluated, the optimized thermal (base-case), Lake Dorothy, and Annex Creek/Carlson Creek resource packages provide the most reliability because they provide new transmission paths and spinning reserves. The optimized diesel re- source package contains the largest number of generating units and therefore has, sta- tistically, the lowest reserve requirements. The development of Lake Dorothy would enhance reliability in two ways. First, it would provide another large, independent hydroelectric unit in the Juneau power system. Hydropower resources can be used to follow load and to control frequency to a much finer degree than thermal generation. A 26-MW Lake Dorothy hydro unit would provide more flexibility and quicker response times in matching load changes than synchronizing and changing load levels on approximately eight to ten diesel generators. Second, the transmission from Lake Dorothy would provide a potential alternative Taku Inlet submarine cable crossing should a failure occur on the existing Snettisham submarine cable. While the new transmission submarine cable would be independent, an overhead tie line between the Snettisham and Lake Dorothy lines could be con- structed that would allow switching and load transfers in the event that the existing cable failed. Replacement of the existing submarine cable would require a multi-season outage that could have substantial impacts upon the Juneau community. While the Annex Creek/Carlson Creek project would provide more geographic diversity than would two major hydroelectric resources on the same peninsula on the south side of Taku Inlet, the ability to assist in the event of a submarine cable outage is a major difference. This is especially true because commercial operation of either new hydro- electric resource would not take place until 1996, which is near the end of the design life for the high-voltage submarine cables installed at Snettisham. sea7308/034.51 ss V. FINDINGS V. FINDINGS A base-case thermal plan and three alternative "least-cost" resource packages were evaluated in this study. Each least-cost package comprises resources selected from a list of supply-and demand-side options, as identified in Section IV. . These resource options include: Conservation Load management New hydroelectric projects Modifications to existing hydro projects Diesel power plants Conservation programs are discussed in Section III. Load management refers in this case to AELP’s residential water heater control program, which will be described in the forthcoming update to the AELP Load Management Plan. New hydroelectric power plants evaluated in this study are the Annex Creek/Carlson Creek, Lake Dorothy, and Lake Dorothy/Long Lake Tunnel projects. Modifications to existing hydro projects involve raising the dam at either Crater Lake or Long Lake, or both. The diesel power alternative considered is the addition of General Motors Electro Motive Divi- sion 20-645-F diesel units. The resource packages were evaluated under three load forecast scenarios: no mining loads (base forecast), addition of the A. J. Mine (A. J. Mine forecast), and the addition of the A. J., Kensington, and Jualin mines (multiple mine forecast). NET PRESENT VALUE ANALYSIS A net present value analysis was performed for the base (no-mine) load forecast. ‘A similar analysis was performed for the base-case (diesel) plan and each alternative resource package under the A. J. and multiple mine load scenarios. The analyses con- sisted of running the power planning model, which is described in Section IV, using the appropriate combination of supply- and demand-side resources for the case. The net present value, expressed as of 1990, represents the sum of fuel costs, fixed and variable O&M costs for new and existing units, and amortized capital costs for new units only. Capital costs associated with existing units are considered "sunk costs" and were therefore excluded from the net present value analysis. These sunk costs were, however, considered in the bus bar cost analysis. Net present values are expressed in 1990 dollars. ASSUMPTIONS The nominal discount rate used in this analysis was 7.635. percent, which represents the product of a 3 percent real discount rate and a 4.5 percent annual inflation rate. A 7.635 percent tax-exempt interest rate for bond financing was assumed. Diesel fuel costs were forecast based on an analysis of the historical relationship be- tween diesel fuel prices paid by AELP and the price of crude oil. Historical and pro- jected fuel prices are provided in Table V-1 and are shown graphically in Figure V-1. - Salvage values were included in this analysis. In cases where existing diesel units are ultimately not needed because of the addition of a major new hydroelectric resource, salvage could occur in the first 2 years that the new hydro project was in service (1996 and 1997 for Annex Creek/Carlson Creek and Lake Dorothy; and 1995 and 1996 for the Dorothy/Long Lake Tunnel). It was assumed that AELP would retire the older and less efficient diesel units. Key assumptions regarding existing supply-side resources and new power supply re- source options are summarized in Table V-2. RESULTS The net present value for the base load forecast scenario (without mining activity) is $127.0 million. Under this scenario, no new generating resources are required. The results of the net present value analysis for the A. J. Mine and multiple mine load fore- cast scenarios are summarized in Tables V-3 and V-4, respectively. Under the A. J. Mine scenario, the Lake Dorothy package of resources is the least-cost package. The Annex Creek/Carlson Creek package is significantly more expensive. Because of the Annex Creek/Carlson Creek project’s size relative to the loads and the seasonal distribution of its energy, only a portion (64 percent of project output) can be used to meet Juneau energy requirements. In the multiple mine scenario, nearly the full output of the Annex Creek/Carlson Creek hydro project can be used. As a result, the Annex Creek/Carlson Creek package has the lowest net present value of the resource packages considered for this scenario. The present value of the Lake Dorothy resource package, however, is only slightly higher under the multiple mine forecast, and, despite the difference in cost, we recommend the Lake Dorothy alternative over the Annex Creek/Carlson Creek alternative. This recommendation is based upon the economic impacts that the nonfirm energy of the Annex Creek/Carlson Creek project could have upon Juneau power costs. In a dry or below-average water year, the amount of energy available from the project would be quite low, resulting in the need for substantial amounts of high-cost diesel production. Further, in an above-average water year, there may not be additional displaceable load {| cA DOLLARS PER GALLON DIESEL FUEL COSTS HISTORICAL AND PROJECTED $3.00 $2.50+ $2.00- $1.50+ $1.00; $0.50- Historical - neue Projected Diesel Fue-—_ ude Oil 0.00 $ 1980 1985 1990 1995 2000 2005 2010 T-A 24ns1y Crude Oil ($/bbl) Table V-1 Historical and Projected Fuel Costs Diesel Fuel Cost ($/gal) S-A Table V-2 - Key Assumptions for Existing and New Power Supply Resources New Resources Only Average Forced Annual | Transmission | Outage Fixed Variable Average: Installed Energy Losses Rate O&M O&M Heat Rate First Year Cost (GWh) (%) (%) (S/year) | (cémts/kWh) | (BTU/kWh) Avallable ($ million) Existing System: Annex Creek Hydro 3.5 23.5 12.5 NA 101,000 | Na | NA NA Suimon Cresk | vyico | ss | 350 | oo | wa | 73000 se | | wa__| wa Snettisham/Crater Lake Hyco om | sa | oo Fx [et | ae] wa NA sire | 42 | sms | ts pn [ofan Ta NA Lemon Creek ee ee ee ee wa__|_NA Lemon Creek i | 79,200: | NA NA Ake Bay Gold Creek NA NA Resource Additions: Annex/Carlson Creek Lake Dorothy Dorthyong Lake Tunnel | vitro | 00 | 429 . Crater Lake Elev. 1034 Long Lake Elev. 845 Channel Sanitation GM-EMD 20-645-£ | Hy | oe | 29 | tro | oo | 130 | | wastetocneney | 08 | Diesels 29 4Run-of-river project. NA = Not applicable. Pec wef [oe [a 198 = ee may not reduce diesel fuel costs. Consequently, savings in a wet year will not balance out added costs in a dry year. A "Monte Carlo" or statistical analysis would be required to estimate the costs more exactly and to quantify the risk. The difference between the firm and average water energy for this resource represents about 104,700 MWh in a year. At a diesel engine fuel consumption rate of 14.5 kWh/ gal, this equates to about 7.2 million gallons of diesel fuel. Assuming a 1990 nominal diesel fuel price of 82.7 cents per gallon yields a potential cost swing of over $5.9 mil- lion. Under such swings in power costs, a customer could perceive a loss of rate stabil- ity. Also, in view of the fact that the present value of revenue savings is less than $10 million under this resource package, a potential risk each year in excess of $5.9 mil- lion does not appear appropriate. Under the multiple mine scenario, a relatively small percentage change in the load forecast would reverse the least-cost order between the Lake Dorothy and the Annex Creek/Carlson Creek resource packages. Therefore, temporary mine closures or reduc- tions in Juneau electric loads due to economic factors could negate the attractiveness of the Annex Creek/Carlson Creek alternative, based upon the average water analysis performed in this study. A detailed description of the analysis of each resource package follows. BASE FORECAST Under the base (no-mine) load forecast scenario, no new supply-side resources are required to serve the Juneau area during the study period. Existing hydroelectric power plants, including Snettisham/Crater Lake, can provide sufficient firm energy to meet the projected energy requirements of AELP’s non-mining customers. Capacity is provided by AELP’s own hydro facilities and Snettisham. AELP’s thermal resources provide reserves sufficient to meet peak demands despite a full outage at Snettisham. For the base forecast scenario, demand-side alternatives and conservation savings em- bedded in the load forecast were considered. The conservation savings are due to replacement of older major appliances by new energy-efficient appliances, better build- ing codes, and greater consumer awareness of energy. Therefore, no additional gener- ating capacity was added in the no-mine cases. However, since load management (in this case, residential water heater control) can be used to supplement reserve capacity, tatepayers receive a benefit from investments by AELP in this program. For this reason, load management was considered in the base forecast run. The base forecast scenario resulted in an estimated net present value of $127.0 million. The seasonal and annual results of the energy dispatch and cost analysis are presented in Appendix B. A. J. MINE FORECAST In the A. J. Mine load scenario, new reserve capacity.is required in 1993. Existing resources total 152 MW. After adjusting for peak load reductions due to conservation and load management, the projected 1993 peak demand including the A. J. Mine is 90 MW. . Under the reliability criteria discussed in Section IV, resources totaling 164 MW would be required to ensure that the peak could be met in the event of a full outage of supply from the Snettisham Project. Hence, a minimum of 12 MW of new capacity is required in 1993 under this load scenario. An additional 3 MW of new capacity is required to meet the growth in non-mining loads during the remainder of the study period. The remainder of the mine energy requirements would be met by using surplus Crater Lake power and existing diesel units. Results of this analysis are summarized in Table V-3. Table V-3 Results of the Net Present Value Analysis A. J. Mine Scenario New Diesel | Net Present Index Resource Package (Base= 100) Base-case (Diesel) Plan 453.5 Lake Dorothy 14.5 324.2 with Crater ‘Lake (1034), Long Lake (845), conservation, load management, and GM EMD diesel | Annex Creek/Carlson Creek 20.3 with Crater Lake (1034), conservation, load management, and GM EMD diesel Lake Dorothy/Long Lake Tunnel with Crater Lake (1034), Long Lake (845), conservation, load management, and GM EMD diesel Base Case In the base-case (diesel) plan, all new capacity was added in 1993. This was based on the assumption that the cost of financing a number of new diesel units over a period of several years would be greater than the cost of financing all of the units at one time and that a quantity purchase would also minimize capital through reduced engineering and vendor costs. In practice, financing could be structured to allow AELP to stage diesel capacity additions. This could also help to minimize the potential for rate shock associated with adding large increments of diesel capacity. However, for the purpose of making cost comparisons, it was assumed that all capacity would be added in the first year that a new resource is required. Based on the relative closeness of 900-rpm diesel life-cycle levelized costs and on AELP’s experience in maintaining and operating GM EMD diesel units, additional new capacity beyond the 15 MW required in the A. J. Mine scenario was added as new GM EMD units. In the base-case plan, a total of 29 MW of diesel capacity was added in 1993. This new capacity would be operated to displace energy that would otherwise be generated using AELP’s existing diesel resources. The resulting savings in fuel costs would offset the amortized capital costs associated with these additional units. In sum- mary, the base-case plan was optimized to provide the lowest net present value of total cost (capital plus fuel and O&M). The base-case diesel plan under the A. J. Mine load forecast scenario resulted in an estimated net present value of $453.5 million. The seasonal and annual results of the energy dispatch and cost analysis are presented in Appendix B. Lake Dorothy Alternative The Lake Dorothy resource package includes conservation, load management, the 26-MW Lake Dorothy hydro project, raising of the Crater Lake dam to elevation 1034 and the Long Lake dam to elevation 845, and 15 MW of new diesel capacity. The new diesels and hydro dam modifications were assumed to be completed by 1993; the Lake Dorothy project was assumed to come on-line in 1996. The net present value of the Lake Dorothy alternative is estimated to be $324.2 mil- lion, which is 29 percent lower than the base-case plan. As in the Annex Creek/ Carlson Creek alternative, low-cost hydroelectric energy would be substituted for higher-cost energy generated from diesel units in this case; the fuel cost savings would more than offset the capital cost of the hydro projects. The seasonal and annual results of the energy dispatch and cost analysis for this case are presented in Appendix B. Annex Creek/Carlson Creek Alternative The Annex Creek/Carlson Creek resource package includes conservation, load manage- ment, the 28-MW Annex Creek/Carlson Creek hydro project, raising of the Crater Lake dam to elevation 1034, and 20 MW of new diesel capacity. The new diesels and Crater Lake modification were assumed to be completed by 1993; the Annex Creek/ Carlson Creek project was assumed to come on-line in 1996. V-8 The estimated net present value of the Annex Creek/Carlson Creek alternative is $382.9 million, which is 16 percent lower than the base-case plan. In this case, low-cost hydroelectric energy would be substituted for higher-cost energy that would otherwise be generated from diesel units; the resulting savings in fuel costs would more than offset the capital costs associated with the hydro projects. A relatively large proportion of the Annex Creek/Carlson Creek project’s energy is nonfirm. Although not explicitly quantified in this study, this characteristic introduces uncertainty about project benefits and, therefore, the project. The large quantity of seasonal nonfirm energy is the primary reason that the Annex Creek/Carlson Creek project had the lowest life-cycle costs of all of the major hydro projects (see Sec- tion TV). Loads under the A. J. Mine Scenario are not large enough to utilize the available nonfirm energy, and therefore the Annex Creek/Carlson Creek project is not the least-cost alternative in the net present value analysis. Unlike the other A. J. Mine load cases, this resource package would not benefit from the addition of the Long Lake expansion project. The Annex Creek/Carlson Creek project is a highly seasonal resource, providing most of its energy during the summer when loads are down. During the 7 months from May through November, all of the area’s energy requirements can be met by a combination of the Annex Creek/Carlson Creek project, AELP’s existing hydro resources, and Snettisham/Crater Lake. During this period, additional resources would be idle. There is not enough energy required in the remaining 5 months (after dispatching the Annex Creek/Carlson Creek project, AELP’s existing hydro resources, and Snettisham/Crater Lake) to provide the potential for fuel cost savings from the Long Lake dam addition to offset the capital costs associ- ated with the project. The seasonal and annual results of the energy dispatch and cost analysis for this case are presented in Appendix B. Lake Dorothy/Long Lake Tunnel Alternative The Lake Dorothy/Long Lake Tunnel resource package includes conservation, load management, the Lake Dorothy/Long Lake Tunnel hydro project, raising the Crater Lake dam to elevation 1034 and the Long Lake dam to elevation 845, and 20 MW of new diesel capacity. The new diesels and hydro dam modifications were assumed to be completed by 1993; the Lake Dorothy/Long Lake Tunnel project was assumed to come on-line in 1995, one year earlier than the other major hydro projects could become available. The estimated net present value of the Lake Dorothy/Long Lake Tunnel alternative is $414.7 million, which is 9 percent lower than the base-case plan. As with the other hydro-based alternatives, low-cost hydroelectric energy would be substituted for higher- cost energy generated from diesel units in this case; the fuel cost savings would more than offset the capital cost of the hydro projects. vV-9 The seasonal and annual results of the energy dispatch and cost analysis for this case are presented in Appendix B. MULTIPLE MINE FORECAST As in the A. J. Mine load scenario, new reserve capacity is required in 1993. Existing resources total 152 MW. After adjusting for peak load reductions due to conservation and load management, the projected 1993 peak demand, including the demand of the three mines, is 103 MW. With the inclusion of reserves, resources totaling 177 MW would be required; a minimum of 25 MW of new capacity is therefore required in 1993 under this load scenario. An additional 5 MW of new capacity is required to meet the growth in non-mining loads during the remainder of the study period. Existing diesel resources and excess capability from Crater Lake are also used to meet the increased loads of this forecast. Results of the analysis are summarized in Table V-4. Table V-4 Results of the Net Present Value Analysis Multiple Mine Scenario New Diesel | Net Present Value Index Resource Package ($ million) | (Base=100) Base-case (Diesel) Plan 627.3 Lake Dorothy 493.8 with Crater Lake (1034), Long Lake (845), conservation, load management, and GM EMD diesel. Annex Creek/Carlson Creek with Crater Lake (1034), conservation, load management, and GM EMD diesel Lake Dorothy/Long Lake Tunnel with Crater Lake (1034), Long Lake (845), conservation, load management, and GM EMD diesel Base Case On the basis of the relative efficiency of the new GM-EMD diesel units, additional new capacity beyond the 30 MW required in the multiple mine scenario was added. In the base-case plan, a total of 44 MW of diesel capacity was added in 1993. This new ca- pacity would be operated to displace energy that would otherwise be generated using V-10 | ‘ i _ AELP’s existing diesel resources. The resulting savings in fuel costs would offset the amortized capital costs associated with these additional units. The base-case diesel plan under the multiple mine load forecast scenario resulted in an estimated net present value of $627.3 million. The results of the energy dispatch and cost analysis are summarized in Appendix B. ‘ Lake Dorothy Alternative The Lake Dorothy resource package for the multiple mine load scenario includes con- servation, load management, the 26-MW Lake Dorothy hydro project, raising of the Crater Lake dam to elevation 1034 and the Long Lake dam to elevation 845, and 32 MW of new diesel capacity. The new diesels and hydro dam modifications were assumed to be completed by 1993; the Lake Dorothy project was assumed to come on- line in 1996. The estimated net present value of the Lake Dorothy alternative is $493.8 million, which is 21 percent lower than the base-case plan and slightly higher than the results of the Annex Creek/Carlson Creek alternative. Again, low-cost hydroelectric energy would be substituted for higher-cost energy generated from diesel units in this case; the fuel cost savings would more than offset the capital cost of the hydro projects. The results of the energy dispatch and cost analysis for this case are summarized in Appendix B. Annex Creek/Carlson Creek Alternative Under the multiple mine load scenario, the Annex Creek/Carlson Creek resource pack- age includes conservation, load management, the 28-MW Annex Creek/Carlson Creek hydro project, raising of the Crater Lake dam to elevation 1034, and 35 MW of new diesel capacity. The new diesels and Crater Lake modification were assumed to be completed by 1993; the Annex Creek/Carlson Creek project was assumed to come on- . line in 1996. The estimated net present value of the Annex Creek/Carlson Creek alternative for this load forecast is $496.1 million, which is 21 percent lower than the base-case plan. In this case, low-cost hydroelectric energy would be substituted for high-cost energy that would otherwise be generated from diesel units; the resulting savings in fuel costs would more than offset the capital costs associated with the hydro projects. The results of the energy dispatch and cost analysis for this case are summarized in Appendix B. V-11 Lake Dorothy/Long Lake Tunnel Alternative The Lake Dorothy/Long Lake Tunnel resource package for the multiple mine load scenario includes conservation, load management, the Lake Dorothy/Long Lake Tunnel hydro project, raising of the Crater Lake dam to elevation 1034 and the Long Lake dam to elevation 845, and 38 MW of new diesel capacity. -The new diesels and hydro dam modifications were assumed to be completed by 1993; the Lake Dorothy/Long Lake Tunnel project was assumed to come on-line in 1995. The estimated net present value of the Lake Dorothy/Long Lake Tunnel alternative is $589.1 million, which is 6 percent lower than the base-case plan. As with the other hydro-based alternatives, low-cost hydroelectric energy would be substituted for higher- cost energy generated from diesel units in this case; the fuel cost savings would more than offset the capital cost of the hydro projects. The seasonal and annual results of the energy dispatch and cost analysis for this case are presented in Appendix B. PROJECT FINANCING Our analysis assumed that projects will be financed for 20 to 30 years at a 7.635 per- cent tax-exempt interest rate. Funding may vary depending upon the borrower of the funds (APA, AEA, AELP, or Echo Bay) and the perceived risk in paying back the lenders. This section explores some of the considerations that will be important to the lenders. Table V-5 shows annual gross sales revenues and the long-term outstanding debt of the major organizations that are most likely to sponsor major projects. . Table V-5 . Financial Data on Major Resource Sponsors Annual | Revenue | Generation | Long-Term Debt Sales in in Capacity | Outstanding in Organization| MWh |$million| i $ million | ara [30s] 90 | 7 | ss | In this section, the financing capabilities of the most likely generating resource sponsors are discussed. Next, general requirements for public financing and the possibility that V-12 major projects would be financed by a combination of AELP, APA, and AFA are cov- ered. Finally, some alternative financing methods are discussed. FINANCING CAPABILITIES OF SPONSORS AELP has the smallest financing capability of the resource sponsors. In addition, AELP has just gone through a period of capital expansion, which has constrained its capability to issue additional debt. Specifically, the rehabilitation of the Lower Salmon Creek project, the installation of six diesel generators and a combustion turbine, the recent purchase of GHEA, and transmission and distribution increases in voltage level have all occurred since 1983. These expenditures enhanced reliability and positioned the utility to better serve its customers. However, AELP has a total debt/total capital- ization ratio of about 1.9 to 1, or 65 percent debt. For a private utility, this is a high value. Under current federal regulations, AELP would normally borrow funds with interest taxable to the lender. The rate for taxable interest currently is about 9.75 percent, compared with a 7.635 percent tax-exempt interest rate. Therefore, the cost of money to AELP is higher than for a tax-exempt sponsor. AELP’s principal sources of capital are retained earnings, sale of common and preferred stock, and privately-placed debt. The majority of AELP’s outstanding long-term debt is in notes and first mortgage bonds. The market for AELP common and preferred stock is limited. AELP is closely held and not traded on any major exchange. This limits the market for the sale of stock. Public debt issues, such as bond issues, are also unlikely, due to the same lack of mar- ket. This leaves retained earnings and issuance of private debt as the major sources of capital. As indicated earlier, the period of expansion stretched AELP’s borrowing ability and has resulted in a high total debt/total capitalization ratio. This, when coupled with other bond covenants, will restrict AELP’s ability to finance a large project. Major additional capital expansion to support a large hydroelectric project would be beyond AELP’s ability to finance through retained earnings and would require issuance of long-term debt. Such a loan would need either to rely on the net assets of AELP or to be based upon an evaluation of AELP’s earnings. Traditionally, investor-owned utilities, such as AELP, issue mortgage- or asset-based bonds, as opposed to the reve- nue bonds issued by government utilities such as AEA. Due to the current total debt/ total capitalization ratio, an AELP loan would most likely be examined on the basis of the ability of the new asset to generate an assured and positive stream of net revenues. For the hydro projects, the assured source of revenues could be a take-or-pay contract with the mines. Significant borrowing would also raise the cost of capital, as it would further erode the total debt/total capitalization ratio, and bond coverage requirements would force AELP V-13 to seek higher retail rates from the APUC. Retained earnings, intermediate-term loans, and lines of credit are probably sufficient sources of capital for AELP to fund the smaller capital projects, such as individual diesel generators or small groups of generators, without major impacts on AELP’s cost of capital. AEA AEA is an agency of Alaska state government. It was created in 1976, by an act of the Alaska Legislature, to promote, finance, develop, and operate power production facili- ties in Alaska. Such facilities may operate on fossil fuels, waste energy, and renewable energy resources. AFA is authorized to issue its own bonds and other debt obliga- tions. The debt of AEA is technically not deemed to constitute a debt of the State of Alaska unless so authorized by the Legislature. AEA funding for operations is de- pendent upon an annual appropriation from the State Legislature. Consequently, there may be a perception by some lenders that AEA’s financial condition is reviewed and monitored by the State of Alaska. AEA conducts reconnaissance and feasibility studies; designs, constructs, and operates power projects; issues tax-exempt bonds; administers loan and grant programs; and enters into contracts for power and waste heat sales. AEA has been very successful in issuing bonds to finance new. hydroelectric projects. In 1989, AEA issued over $100 million in bonds. AEA’s financing capability and tax-exempt status were used successfully to help fund the Bradley Lake project. ‘ Generally, major hydro projects are financed with project-specific bond issues. The . revenues from the project that are assured through a take-or-pay contract are the gen- eral collateral that the lenders of municipal revenue bonds examine in a large bond issue. AEA has a track record of being able to fund large projects based on the credit supplied by take-or-pay power sales contracts with utilities. If suitable. contracts for long-term power sales can be negotiated, it appears that AEA would be capable of funding the major projects being considered. In addition to issuing project-specific bonds as a method of financing projects, AEA has a Power Project Loan Fund. This fund provides state assistance to local utilities and other eligible government units for the development of new small-scale power produc- tion facilities, facilities for conservation, bulk fuel storage, transmission and distribution lines, and potable water supply projects. Loans are issued for a maximum term of 50 years at an interest rate of not less than 5 percent and not more than the 52-week average of municipal bond yield rates. The AEA Power Project Loan Fund has pro- vided money to AELP in the past for a number of transmission and distribution im- provements in the Juneau area. V-14 APA APA is a federal power marketing agency of the U. S..Department of Energy whose budget is determined through the federal appropriations process. APA has two major projects: Eklutna and Snettisham. The Snettisham project with both Long Lake and Crater Lake generation is the largest of the projects. For the past several years, the federal budget assumed that APA’s assets would be sold. Because the long-term debt that was issued to build APA projects was from federal appropriations, APA is required to make periodic repayments to the Treasury. These payments are from the revenues collected from the sale of power by APA. APA rates are set under a repayment policy designed to recover the cost of the project (both prin- cipal and interest) over a 50-year period. The repayment policy also has a degree of flexibility to allow revenues to increase as sales increase. Pressure on the federal government to balance the budget has led to consideration of two courses of action with potential consequences for APA and the Juneau commu- nity. First, the sale of APA assets would reduce the federal deficit in the short run. Second, it has been suggested on several occasions that federal power marketing repay- ment policy should be modified to increase the amount of money that the agencies contribute to the U. S. Treasury. Historically, neither of these actions has been taken. However, it may simply be a matter of time before they occur. AEA has tentative agreements to purchase APA’s Snettisham project. AEA would issue tax-exempt bonds secured by take-or-pay power sales contracts from AELP. One factor of going from federal- to state-financed debt that could change the cost structure is the term of the debt. APA is required to repay outstanding federal debt over a 50-year period. To mitigate the potential for major changes in rates, the proposed purchase price of Snettisham has been negotiated on the basis of maintaining approxi- mately the same level of wholesale power rates (or bus bar costs). APA’s ability to obtain long-term capital is a function of its ability to obtain federal appropriations. Also, as with the existing generation at Crater Lake and Long Lake, the U.S. Army Corps of Engineers would be the likely lead federal agency in the con- struction of any APA project. While small amounts of money for such projects as the dam additions to Crater Lake and Long Lake may be possible, securing the necessary votes to get appropriation funding for a large project such as Lake Dorothy or Annex Creek/Carlson Creek would be difficult and would require the active support of more than the Alaska Congressional delegation. Appropriation funding of large hydropower projects is very difficult under the current Gramm-Rudman Act spending limitations. Also, the funds would probably be close to current treasury interest rates, which are higher than current tax-exempt financing values. V-15 ECHO BAY Echo Bay is a relatively large multi-national company with gold mines in a number of locations. Echo Bay had revenues of about $279 million in 1989. The firm has approx- imately $992 million in assets. Stock in Echo Bay is traded principally on the Toronto and American stock exchanges and on other major exchanges in North America and Europe. According to representatives of Echo Bay, the company also has access to low-cost "gold loans." While the details of the funding are considered proprietary, the funds appear to be below the cost of those available to AELP. This financial data indicates that Echo Bay has the capability to finance projects of the size of the major hydro projects being considered. However, while Echo Bay may be able to finance such projects, it may prefer to keep its investment within its core activi- ties (mining), where its management talent resides, rather than diffusing the focus of its operations. REQUIREMENTS TO FINANCE WITH LONG-TERM DEBT In preparing engineer’s reports for bond issues and in making presentations to rating agencies, issues that need to be addressed are who will pay back the lender and how secure the revenue stream is. These questions usually require demonstration that a project is needed, that there are not many other economic alternatives to the project, and that the revenues will be secure even if problems develop with the operation of the resource. Most public agency bonds are issued on the basis of a pledge of revenues from the issuing agency. If the agency does not market to retail customers, then a strong con- tract, usually in the form of a take-or-pay agreement with one or more financially strong power purchasers, is viewed by the lenders as essential in determining the credit rating of the issuing agency. AEA appears to be the logical agency to issue traditional revenue bonds to fund a major project. The bonds would be for the specific project and would be secured by a pledge of revenues from the project. Because AEA does not make retail sales of energy, lenders will want assurance that retail revenues of the project’s power pur- chasers will be committed to pay the principal and interest on the bonds. For this reason, the lenders will want a take-or-pay contract or similar guarantee between AEA and the utility that makes retail sales, AELP. Furthermore, one of the commonly reviewed aspects of lending is an analysis of what would happen if the single largest customer of the utility were to close. If a project is justified on the basis of meeting the need of only one customer, then the retail power sales contract of that customer will be reviewed in the process of preparing the official statement for a bond issue. This knowledge of revenue bond financing is one of the reasons the sponsors believe that a take-or-pay contract between AELP and the mines V-16 and AEA will be needed for a public financing of a major hydro project. The contracts between AELP and AEA and between AELP and the mines will have to be for the same term as the repayment period of the bonds to provide adequate credit assurance to the lenders. The recommended least-cost packages include a variety of projects. As a result, financ- ing for the package will be provided separately for each project. Therefore, a resource package will effectively be financed by a combination of the credit ratings of AEA, APA, AELP, and Echo Bay. The most likely scenario would be for AEA to finance major new hydro projects, AELP and/or Echo Bay to finance new diesel generation and APA, in conjunction with the U.S. Army Corps of Engineers, to finance and construct the dam additions to Crater Lake and Long Lake. The AEA and APA financing would be tied to power sales contracts with AELP and the mines. AELP’s ability to repay the borrowed funds would be examined; to the extent that AELP can contractually secure its revenue stream with its power sales contract to the mines, it will be more likely to receive the needed capital at favorable interest rates. ALTERNATIVE FINANCING There are two other financing alternatives that should be explored. The first is finan- cing a project to be constructed by a federal agency with third-party funds. The second is for AELP to issue tax-exempt funding through a provision in the tax laws for local furnishing of electricity. An example of third-party financing is the Central Arizona Water Conservation District, which is working with the Western Area Power Administration and the U. S. Bureau of Reclamation for accelerated construction of the New Waddell dam. Bonds are ex- pected to be issued this spring. Funds are secured by a four-way take-or-pay contract among the District, Western, the Bureau of Reclamation, and a power purchaser. This novel financing agreement allows a state authority to help pay for construction at a federal facility. The New Waddell dam provides both water and power benefits. While the Central Water Conservation District bond issue contract is complex, it is an exam- ple of how third-party funds can be used to pay for a federal agency project. A simpler and more direct financing approach based upon contracts between APA, the Corps of Engineers, AEA, and AELP should be examined. In the tax laws, a provision exists that allows REA cooperatives and investor-owned utilities to issue tax-exempt bonds. The exemption requires that the service territory of the electric utility be located within two adjacent counties. Preliminary discussions with an investment banking firm indicate that AELP projects would qualify for such tax- exempt bonds. This alternative and the use of the AEA Power Project Fund loans are tax-exempt financing alternatives for consideration by AELP. For the purposes of this analysis, it is assumed that major hydro projects would be financed by AEA and/or APA, since it is likely that the cost of these projects would be V-17 greater than the financing capability of AELP. Under these conditions, it is likely that. AELP will be required to enter into a take-or-pay contract for project output. Further, since the major revenues to support investments in new diesel and hydroelec- tric resources in the Juneau area under forecast conditions ultimately will come from the mining customers, it is reasonable for the sponsors and the financial community to expect the mine(s) to execute a take-or-pay agreement with AELP for power supply from these new resources. This would provide prospective bondholders with additional security that AELP could meet the financial obligations of the bonds that would be issued to finance the construction of new diesel facilities and expansion of existing hydro projects. However, as pointed out in Section IV, the mining companies are reluctant to sign long-term take-or-pay contracts; this is especially true for power con- tracts whose terms exceed the proven mineral reserves of the mines. CAPITAL RATIONING Our analysis originally assumed that the capital market would provide funds for any resource project that is needed, technically feasible, cost-effective, and supported by contracts. The sponsors have expressed concern that they may be limited in their abil- ity.to acquire the necessary capital to pursue all of the resources within the least-cost package of resources. Therefore, it is appropriate to implement a capital rationing analysis within our findings. Using a capital rationing analysis, projects are prioritized on the basis of their greatest economic value per dollar of investment. Such an approach will generally favor low capital cost and high operating cost resources (such as diesel) over high capital and low operating cost resources (such as hydro). It also will favor very low life-cycle levelized cost resources such as the large hydro projects over multiple small, cost-effective hydro projects with higher life-cycle levelized costs. Tables V-6 and V-7 show the impact of prioritizing the hydro additions on both the net present value of annual costs and the required capital for the A. J. Mine and multiple mining load forecasts. It can be seen that the removal or postponement of Crater and Long Lake dam additions does not significantly change the net present value savings. This information can be used by policymakers in discussions with financial advisors on identifying the amount of capital available and in prioritizing projects to be financed. If funding of the preferred alternative major hydro project resource, Lake Dorothy, is not possible, the sponsors may wish to evaluate financing portions of the project through a staged construction program. Smaller take-or-pay contract commitments may prove more acceptable to the mine operators and to the financial markets. V-18 (ou Table V-6 Changes in Net Present Value Under A..J. Mine Scenario Net Present Nominal New Diesel Value Capital Resource Package Added (MW) | ($ Million) | ($ Million) Base-case (Diesel) Plan 453.5 Lake Dorothy / Least-cost Package . 324.2 171.7 w/o Crater and Long Lake . 330.1 148.2 Annex Creek/Carlson Creek Least-cost Package . 382.9 181.0 w/o Crater and Long Lake . 383.7 157.5 Lake Dorothy/Long Lake Tunnel | « - Least-cost Package . 414.7 103.8 w/o Crater and Long Lake . 424.9 80.3 Table V-7 Changes in Net Present Value Under Multiple Mine Scenario Net Present Nominal New Diesel Value Capital Resource Package Added (MW) ($ Million) S Million) Base-case (Diesel) Plan Lake Dorothy Least-cost Package w/o Crater and Long Lake Annex Creek/Carlson Creek Least-cost Package w/o Crater and Long Lake Lake Dorothy/Long Lake Tunnel Least-cost Package w/o Crater and Long Lake sea7308/081.51 V-19 MINING COMPANY PARTICIPATION IN ENERGY DEVELOPMENT The A. J. Mine and Kensington Mine operators have indicated a preference for install- ing their own diesel or gas generation facilities. It is the belief of the sponsors that once either the A. J. Mine or the multiple mine load scenario is in place, each mine has its own specially dedicated generation facilities, and the mines better define their operating costs and proven reserves, the mine owners may reevaluate their long-term sources of electricity supply in view of the long-term prospects for escalating fuel costs, periodic major overhaul expenses for diesel facilities, changes in proven reserves, and environmental impacts of diesel or gas generation. Following such reevaluation, the mines may wish to participate in the development of one of the alternatives outlined in this plan. In many respects, direct third-party financing of diesel generation by the mines is much like the commitment to a hydro project take-or-pay contract. The assets and revenues of the mining operation and company are collateral for either the loan or the take-or- pay contract. The major differences are in the size of the loan, the internal control of generation costs by the mines, and the ability to partially liquidate the commitment or loan by reducing fuel purchases and by selling or salvaging the diesel generation units. Unfortunately, major hydro projects do not provide either a significant salvage value or cost savings if they are not operated. One aspect of the mines’ approach to energy planning is that baseload diesel or gas engines can be thought of as consumable items which, after a fixed number of hours of operation, need to be replaced. Consequently, an initial commitment by the mines to onsite diesel or gas generation is not necessarily an irreversible action; such a commit- ment can be economically changed to a major hydro-based least-cost package when the diesel or gas units reach. the end of their relatively short operating life. - Another important aspect of mining company participation in energy development is alignment of the proven mineral reserves with the financing needs of the sponsors and the economic requirements of the mines. Currently, the A. J. Mine has proven mineral reserves of about 12 years. Extending these reserves will require drilling and the expenditure of money on the part of Echo Bay. The extent of mineral reserves is a factor in Echo Bay’s reluctance in making long-term commitments to major hydro projects. To minimize power costs, the sponsors are considering 30-year tax-exempt bond issues for new hydro generation resources. Shortening bond repayment periods to 10 years to coincide with known mineral reserves would substantially increase the first-year cost of major hydro projects. As stated earlier, the A. J. Mine, with only 12 years of proven Teserves, is reluctant to commit to the type of 30-year take-or-pay contract that would be associated with the development of a large hydroelectric project. In exploring this dilemma, we looked at what the impact would be of reducing the bond life to 10 years V-20 4 — and then compared that to the costs of diesel generation. This analysis is summarized in Table V-8. By reducing the length of the bond repayment period, annual debt service payments are increased as are initial reserve requirements. The first year unit energy. costs of Lake Dorothy increase from about 9 cénts/kWh to 16 cents/kWh or about 80 percent. The first year costs for diesel generators producing the same amount of energy in 1996 is about 11 cents/kWh. . Table V-8 Analysis of Lake Dorothy on a 10-Year Bond Life Equivalent Energy from Diesel Units 10-Year Bonds (assumes no salvage value) Lake Dorothy | Lake Dorothy 10-Year Bonds | 30-Year Bonds Bond Issue Size (1996 construction) ($ millions) Annual Debt Service Net of Interest Income ($ millions) Present Value of First 10 Years of Power (millions of 1996 $) 1996 Power Cost (cents/kWh) 7 Note: For hydro projects, the bond issue is sized to equal the sum of con- struction costs, capitalized interest during construction, reserves of 1 year’s debt service, working capital reserves of 1 month’s debt service, 1996 financing costs of about $390,700, and a bond discount rate of 2 percent. This analysis shows that the Lake Dorothy project and least-cost package associated with it would be beneficial to the A. J. Mine over the first 10 years of operation with 30-year hydro project bonds. The problem in implementing such a Lake Dorothy least- cost package of resources will be in finding an entity financially capable of guaranteeing the bond repayment over the full 30 years. While the analysis suggests that the spon- sors may be able to negotiate some kind of agreement with the A. J. Mine for the first 10 years of operation, there is repayment risk over the remaining 20 years of the V-21 30-year bond life. Therefore, unless the mining operators can economically evaluate a long enough perspective, their ability to justify hydro participation over at-site diesel or gas generation is unlikely. Two ways to change this situation would be to shift the economic risk of longer-term financing either to the lenders or to other Juneau residents. If the economic risk is shifted to the lenders, then the cost of funding will increase, as will the power cost. While shifting of risk to non-industrial customers has occurred in other utilities, it has occurred in utilities where load growth would allow the generation resource to be uti- lized even in the absence of a major customer. In the Juneau area, where moderate growth is projected and the A. J. Mine nearly doubles loads, such a shift of risk does not appear appropriate. A major need in the financial planning for future generation is to develop a coopera- tive plan of service with the A. J. Mine and the two other potential mines. This plan of service will need to be developed jointly by the sponsors and the mine operators. SENSITIVITY ANALYSES Analyses were performed to determine the degree to which net present value results would be affected by changes in the following key parameters: ° Peak demand and energy forecasts . Diesel fuel prices PEAK DEMAND AND ENERGY FORECASTS To test the sensitivity of study results to changes in the peak demand and energy fore- casts, two separate sets of computer runs were made. The first set assumed that the A.J. Mine forecast (both peak and energy) was 10 percent lower than is currently pro- jected, beginning in 1993 when the mining load is expected. The second set of com- puter runs assumed that the multiple mine forecast was 10 percent higher than is cur- rently projected, also beginning in 1993. The results of these sensitivity runs are summarized in Table V-9. As shown in the table, there were no changes in the ranking of alternatives due to changes in the peak and energy forecasts. However, under the low A. J. Mine scenario, both the Annex Creek/Carlson Creek and Lake Dorothy alternatives provide less benefit over the diesel alternative than in the base analysis. Increasing loads under the multiple mine scenario have very little impact on the ranking of the hydro alternatives as compared with the diesel plan, although higher loads would tend to reduce the economic risk of the large nonfirm power component of the Annex Creek/Carlson Creek least-cost package of resources. V-22 | ~ Table V-9 a Results of the Net Present Value Analysis | i Sensitivity Analysis © A. J. Mine Scenario ~ _ Multiple Mine Scenario VY Estimated Net Present Estimated Net Present | 1 Fuel Price Forecast and Value Value Index | Resource Package ($ million) ($ million) | LOW PEAK AND ENERGY FORECAST Base-Case Diesel Pian 339.1 I - Lake Dorothy with 280.0 Crater Lake Elev. 1034 a and Long Lake Elev. 845 Annex Creek/Carlson — Creek with Crater Lake Elev. 1034 i Lake Dorothy/Long Lake Tunnel with Crater Lake and Long Lake HIGH PEAK AND ENERGY FORECAST i Base Case Diesel Plan ., Lake Dorothy with ' Crater Lake Elev. 1034 — and Long Lake Elev. 845 i Annex Creek/Carlson ~ Creek with Crater Lake Elev. 1034 Lake Dorothy/Long Lake Tunnel with Crater o Lake and Long Lake sea7302/081.51 V-23 DIESEL FUEL PRICES In order to test the sensitivity of the results of the net. present value analysis to the projected cost of diesel fuel, the base-case diesel plan and each hydro alternative were run using both high and low fuel price forecasts provided by the sponsors (Table V-10). Since there is no thermal generation in the base (no-mine) load forecast scenario, no sensitivity runs were made for that case. The results of the sensitivity analysis are summarized in Table V-11. Although there were some changes in the relative costs of alternatives within each sensitivity case as compared with the base (medium) fuel price forecast, the basic ranking of the alterna- tives remained unchanged. Hence, the analysis can be considered relatively insensitive to changes in fuel prices over the range of fuel prices considered. An alternate fuel sensitivity analysis was performed. This analysis calculated the three fuel price forecasts as single 1990 levelized values. This resulted in high, base, and low diesel levelized prices of $1.77 per gallon, $1.50 per gallon, and $1.22 per gallon in real 1990 dollars. These values are above current diesel prices because the fuel price is projected to increase at a rate higher than the general rate of inflation. These values correspond to real gas fuel levelized prices of $12.66 per MBtu, $10.69 per MBtu, and $8.71 per MBtu. Next, the net present values of the three hydro-based least-cost re- source packages and the diesel base case were plotted for the A. J. Mine load forecast. By comparing the high, medium, and low diesel levelized price results, we can gain insights into Echo Bay Mining’s consideration of LNG and LPG fuels. The results of comparing the base case (diesel) plan results to the three other least-cost resource packages under the A. J. Mining load scenario are shown in Figure V-2. The order of the resource packages shows that the Lake Dorothy package uses the least fossil fuels and that the Annex Creek/Carlson Creek package uses more diesel fuel because of its seasonal need to generate power. The Lake Dorothy/Long Lake Tunnel is the smallest of the three major hydro projects and requires the greatest additional diesel generation of the hydro least-cost packages. The base case (diesel) plan uses the most diesel fuel and is therefore the most sensitive to diesel fuel price. As the price of fuel used to serve the A. J. Mine increases, the attractiveness of the Lake Dorothy resource package increases. The converse also is true. If the price of fuel, whether it is diesel, LNG, or LPG, decreases, the base-case (diesel) plan becomes more attractive. A fuel cross-over point, at which the base (diesel) plan becomes the least-cost plan, can be extrapolated from Figure V-2. This cross-over point would be reached when the levelized price of fuel was about $6.02 per MBtu in real 1990 dollars ($0.84 per gallon in 1990 real levelized diesel prices). V-24 sea7307/082.51 Table V-10 Projected Diesel Fuel Nominal Costs ($/gal) Fuel Price Forecast V-25, 97-A RESULTS OF FUEL PRICE SCENARIOS A.J. MINE FORECAST 550 . ; e Case — 500- Break-even point (Dipsel) Plan 2 (Base and Lake Dorothy Cases) 2 Dorothy/Long = 450; a e Tunnel & oO. 4 1 ex/Carison 3 400 Creek > + 5 $50 «Lake Dorothy 3 4 ® a e 300 > @ = 250, 200 5.00 $6.00 $7.00 $8.00 $9.00 $10.00 $11.00 $12.00 $13.00 $/MBtu (Levelized) _ FuelPrice Scenario: = |= Low = Base High ZA ainsi Table V-11 Results of the Net Present Value Analysis Fuel Cost Sensitivity Analysis A. J. Mine Scenario | Multiple Mine Scenario Fuel Price Forecast and Resource Package HIGH FUEL COST FORECAST Lake Dorothy with Crater Lake Elev. 1034, conserva- tion, load management, GM EMD Diesel, and Long Lake Elev. 845 Annex Creek/Carlson Creek with Crater Lake Elev. 1034, conservation, load management, GM EMD Diesel Lake Dorothy/Long Lake Tunnel with Crater Lake, conservation, load management, GM EMD Diesel, and Long Lake LOW FUEL COST FORECAST we Cae (Die Plan psn | we | sme | ow Lake Dorothy with Crater Lake Elev. 1034, conserva- tion, load management, GM EMD Diesel, and Long Lake Elev. 845 Annex Creek/Carlson Creek with Crater Lake Elev. 1034, conservation, load management, GM EMD Diesel Lake Dorothy/Long Lake Tunnel with Crater Lake, conservation, load management, GM EMD Diesel, and Long Lake BUS BAR COST ANALYSIS Changes in electricity costs to typical residential customers can be predicted by ana- lyzing changes in bus bar costs. This analysis will be summarized in three subsections, one for each of the three load forecast levels that were examined. Three perspectives have been used to determine bus bar costs. These perspectives are based upon two cost allocation methodologies (average embedded and marginal cost). Only two of the perspectives are discussed in this section. These perspectives are for a typical residential, or non-mining, customer under both average embedded and margi- nal cost allocation methodologies. The third perspective is the bus bar costs of mining customers under a marginal cost allocation. Under an average embedded cost alloca- tion, average bus bar costs for mine and non-mining customers are the same. The V-27 average bus bar rates applicable to residential customers were then multiplied by aver- age residential annual general and all-electric rate class energy consumption values to determine the changes in real and minimal dollars that residential customers might see. The range of potential cost impacts is quite large, depending upon the cost allocation methodology assumed. The sponsors believe that the final impacts will be closer to the marginal cost, non-mining customer perspective. Bus bar costs have been calculated in both real and nominal terms. In this evaluation, nominal values are the actual amounts of money spent; real values are the buying power, relative to a base year, of the money spent. By looking at costs in terms of real values, it is possible to examine the effects of price changes before they are distorted by inflation. A more detailed discussion of real and nominal values can be found in Appendix D. The following analysis shows that, under the no-mining activity forecast, the generation, or bus bar, component of electric rates to typical residential customers will increase by $34 to $138 per year in nominal terms. This is close to the impact to be expected if the mines were to generate all of their own power and not purchase any excess Snettis- ham or Crater Lake power. The slight difference is due to the amount of secondary mining load and its impact on costs. Under the A. J. Mining load level, residential rates could either decrease or increase, depending upon how the costs of new facilities are allocated to the mining load. If the mine signs a take-or-pay contract or the APUC approves a marginal cost allocation of the new resources to the mine, then the generation or bus bar component of electric rates to typical residential customers will decrease about $33 to $96 per year in nominal terms, or $21 to $84 per year in real terms. On the other hand, the bus bar component of residential rates could increase by $104 to $557 per year, in nominal terms, in 1996. An increase of this magnitude seems unlikely, however, for two reasons. First, the A. J. Mine is planning to self-generate. Second, financing requirements for constructing major generation facilities to serve the mine would probably require a take-or-pay contract that would preclude an average embedded cost allocation. The corresponding increase in real terms is $80 to $428 per year. The multiple mining load scenario has the same potential as the A. J. Mining load scenario to decrease bus bar costs to residential customers. The potential bus bar cost increase could be higher, on the order of $137 to $672 per year (in nominal terms) in 1996, or $105 to $516 per year in real terms. However, this level of increase is unlikely for the same reasons discussed above for the A. J. Mining load scenario. While a decline in nominal terms will not cause rate shock, an increase could. Gener- ally, rate shock is thought to occur for one of two reasons. First, prices may increase at V-28 mf above the inflation rate over a period of time, and consumer confidence in affordability is eroded, Alternatively, rates may increase by a very large percentage that affects the lifestyle of consumers. The threshold of rate shock varies with each customer’s particu- lar circumstances. Therefore, the policymakers who determine the new resource fi- nancing arrangements, the mining power contracts, and the mining rate allocation phi- losophy will need to evaluate the possibility of rate shock carefully, with the help of the analysis included within this section. BASE FORECAST (NO MINING ACTIVITY) Because no new resources are added under the base or no-mining activity scenario, the average bus bar rate is equal to the non-mining bus bar rate under a marginal cost allo- ‘cation. This is because there is-no mining load and hence no allocation of costs to min- ing loads. The major increase in bus bar costs under this scenario is due to the probable 1992 increase in APA rates. This increase of 0.52 to 0.72 cents per kWh is due to Crater Lake’s being added to the APA repayment schedule and APA’s need to repay the U. S. Treasury. To the average 1992 customer in the general residential rate class who uses about 6,500 kWh per year, this represents an increase of between $34 and $47 per year. The increase to a 1992 residential customer in the all-electric rate class who uses about 19,209 kWh per year would range from $100 to $138 per year in nominal terms. Figure V-3 shows the nominal average bus bar costs under this load scenario. A. J. MINING LOAD FORECAST SCENARIO Under the A. J. Mining load forecast scenario, bus bar costs were calculated from two perspectives for each of two resource packages: the base or diesel package and the Lake Dorothy package. _ Table V-12 shows how the projected change in bus bar costs with the diesel package of resources translates into real and nominal annual expenses for typical customers in the general residential and all-electric rate classes. These expenses are shown for selected years from both the system average and non-mining customer perspectives. Table V-13 shows similar information for the Lake Dorothy package of resources. Note that costs are lower than in the non-mining scenario. This is due to the fact that the cost of Snet- tisham energy is expected to increase in the base forecast or no-mining scenario but not in either of the mining scenarios. Hence, AELP’s non-mining customers benefit directly from the addition of the mines. V-29 Bus Bar Costs Base (No-Mine) Forecast 14 12- oh, ° ©? Of-A Cents per kWh Snettisham rate increase (2.88 to 3.5 cents per kWh) O-+ 1990 1995 2000 2005 2010 2015 2020 oo Qomy Tp So SoS) 2025 €-A aanshy Table V-12 Changes in Annual Residential Customer Costs Diesel Resource Package A. J. Mining Load Forecast ($/year) Average Bus Bar Seer] a Non-Mining Customer Marginal Cost Perspective | General | General All Electric Year Nominal | Real | Nominal | Real | Nominal | Real fete [= forte tala te 1996 25] 33 | -74 | -96 morte ete tas Pal a fons ior [ae [ais [ois | 0 | ao | 00 | as _| Real costs in 1990 dollars. Table V-13 Changes in Annual Residential Customer Costs Lake Dorothy Resource Package A. J. Mining Load Forecast ($/year) Average Non-Mining Customer Marginal Bus Bar Perspective Cost Perspective Year | Reat | Nominal | Real | Nominal | Reat | Nominal | Real | Nominal | [1ss3| 20 [a | 236] 269 | 20 | 33 | ee | 96 jis96 [4s | 19 | ae | ss7_| 25 [33 rales [se oe taro 96 308 | 595 | -17] -33 | -s0 | -96 | 2005 | 104 ea costs in 1990 dollars. V-31 MULTIPLE MINING LOAD FORECAST SCENARIO Under the multiple mining load forecast scenario, bus bar costs were calculated from two perspectives for each of two resource packages: the base or diesel package and the Lake Dorothy package. While Annex Creek/Carlson Creek was technically the least-cost package for this load level, the economic risk associated with the amount of nonfirm energy was the reason Lake Dorothy was recommended. Therefore, the bus bar power cost impacts of Lake Dorothy were evaluated. Table V-14 shows how the projected change in bus bar costs with the diesel package of Tesources translates into real and nominal annual expenses for general residential and all-electric customer usage levels. These expenses are shown for selected years under the average.and non-mining perspectives. By comparing Table V-13 to Table V-12, it can be seen that additional mining loads result in no change for the non-mining cus- tomers. However, the average bus bar costs increase significantly due to these added loads. Table V-14 Changes in Annual Residential Customer Costs Diesel Resource Package Multiple Mining Load Forecast ($/year) Average / Non-Mining Customer Marginal Bus Bar Perspective Cost Perspective Ye: General | All Electric General All Electric ar | Real | Nominal Nominal Nominal Nominal 97 | im 327 33 | -84 | j1996 105 | 137_| so | aos | as | a3 | 7a | 96 _| }2000|130 | 202 | ses | sos | an | a3 | 2 | 96 _| | 2005 | 293 | 447 | 864 | -20 | -60 | -115 | Table V-15 shows information similar to that in Table V-14, but for the Lake Dorothy package of resources. Comparison of Table V-15 to Table V-14 shows the potential annual cost impacts to the residential customer of changing from a diesel to a hydro resource package at this load level. Comparing Table V-15 to Table V-13 shows the annual cost impact of this higher level of load. V-32 ‘a Table V-15 Changes in Annual Residential Customer Costs Lake Dorothy Resource Package Multiple Mining Load Forecast ($/year) Non-Mining Customer Marginal Average Bus Bar Perspective Cost Perspective | ‘ise ins [ae [sig | oe [as | 3 |e i {a0 fom fe fo [on La Average annual bus bar costs for each of the four cases under both mining load scena- rios are shown graphically in Figures V-4 and V-5. Details of the annual bus bar costs for each case, shown separately for the system average, the mine(s), and non-mining customers, are provided in Appendix B. An example of bus bar costs for the system average, non-mining, and mining customers, representing the Lake Dorothy case under the A. J. Mine forecast, is shown in Fig- ure V-6. RELIABILITY AND RESERVE CONSIDERATIONS Reserve generation capacity is often equated with reliability. For some systems, the amount of reserves can serve to represent the reliability of the system. Table V-16 shows the required amount of generation reserves in megawatts under the major resource packages and load levels. As the table demonstrates, the reserves required are more a function of the capacity of the Snettisham transmission line than of the gen- eral load level or the resource package. Therefore, for the Juneau area, the number and size of generating units is a better measure of reliability than the total amount of reserves. Table V-17 shows the installed reserves in each study year for each of the alternatives considered in this analysis. Our qualitative evaluation of reliability issues is presented in Section IV. V-33 oA aS e Bus Bar Costs ine Forecast Cases 12 Add major hydro projects P-A ANsly Cents per kWh. ° 4, / a \ New diesels are fully depreciated 24 . | _ Add new diesels and small hydro projects 0 . T T T T T 7 1990 1995 2000 2005 2010 2015 2020 2025 [— Base Case (Diesels) ----- Annex/Carlson Creek —— Lake Dorothy -—— Dorothy/Long Tunnel | eT) 4] 4 we : a ap ce-A Cents per kWh Average Bus Bar Costs Multiple Mine Forecast Cases Add major hydro projects . Add new diesels and small hydro projects New diesels are fully depreciated 1990 1995 2000 2005 2010 2015 2020 2025 —— Base Case (Diesels) --- -- Annex/Carlson Creek —— Lake Dorothy —-~ Dorothy/Long Tunnel SA MnsIy 14 Bus Bar Costs Lake Dorothy (A.J. Mine Forecast) 12- —_, 2° 9F-A Cents per kWh Add Lake Dorothy project weocr New diesels are fully depreciated Add new diesels @) T T T T T T 1 990 1995 2000 2005 2010 2015 2020 2025 —— System Average --- A.J. Mine — Non-Mine Customers | 7 Sy SS aan 9-A aIns1y 42.3 Table V-16 Reserve Requirements. (MW) Base (No-Mine) A. J. Mine Year Forecast Forecast 42.3 Multiple Mine Forecast hydro plants, or Reserve requirement is the lesser of: 2. Capacity of Snettisham/Crater Lake 1. Peak demand minus the capacity of AELP’s V-37 8E-A Table V-17 : Installed Reserves (MW) Multiple Mine Forecast Diesel 100.2 1990 98.7 98.7 97.9 973 93 | 955 91.0 | 823 | 765 85.2 92.0 99.8 813 | 75.5 84.2 90.2 998 | 78.1 | 802 80.6 88.5 105.8 | 1005 80.7 718 105.9 80.8 718 992 | 783 | 105.9 80.5 719 106.0 80.9 719 106.0 78.0 105.6 | 1005 | 807 718 105.2 80.6 71.6 T14 979 95. — 83.3 80.4 86.2 81.5 78.6 84.4 798 80.2 105.4 80.2 105.4} 103.0 80.2 105.5 80.4 108.5 80.4 — 105.6 80.5 105.4 103.0 80.5 . 105.2 102.8 80.1 105.0 102.8 79.9 p. 1 of 2 6f-A Table V-17 Installed Reserves (MW) sea7302/079.51 Forecast A. J. Mine Forecast Multiple Mine Forecast Annex/ Dorothy/ Annex/ Dorothy/ Carlson Lake Long Lake Carlson Lake Long Lake Year Diesel Diesel | Creek | Dorothy Tunnel Diesel | Creek | Dorothy Tunnel 2004 105.3 100.0 80.2 7714 | 105.0 102.6 79.9 2o0s| 967 | m6{ 1053 | 99 | 802 | 772 | 1048 | 1024 | 797 _| 2006 2007 99.6 79.8 710 | 1048 | 1022 | 795 2008 95.5 77.2 | 104.6 99.5 79.7 76.8 | 104.6 102.0 79.5 2009 | 952 | 771 | 1047 | 994 79.6 2010 | 948 | 770 | 1046 | 995 79.7 p. 2 of 2 From a reliability perspective, the most significant problem is Juneau’s dependence upon a single transmission line to deliver electricity generated by the Snettisham proj- ect. Any least-cost plan that adds generation resources.of comparable size to one of the large units at Snettisham, but that provides its power over a different transmission path, will increase reliability for the Juneau area. Conversely, any package that routes power over the existing Snettisham transmission line provides no additional reliability. Therefore, the Lake Dorothy/Long Lake Tunnel package is the least beneficial of the alternatives considered from a reliability standpoint, because it adds its additional energy via the Snettisham transmission line. ENVIRONMENTAL CONSIDERATIONS This section qualitatively evaluates environmental considerations associated with the three least-cost resource packages and the base (diesel) plan. Our analysis is based on a single site visit and discussions with the sponsors. There are a number of environ- mental factors to be considered in the siting of diesel and hydropower plants. Our evaluation will discuss the major environmental differences among the energy supply scenarios. Some difficult environmental issues arising from potential energy scenarios for the Juneau area have been avoided due to the high costs of the alternatives involved. For example, had the Channel Sanitation resource been included in the least-cost package, the controversial issue of dioxin production and ash classification from solid waste incin- eration systems would have had to be addressed. Similarly, in the 1987 Southeast Alaska Intertie Study, numerous environmental issues associated with the various inter- ties were raised. Some of the environmental concerns associated with visual impacts of a Juneau-to-Whitehorse overhead transmission line along Lynn Canal and through the Klondike National Gold Rush Park are potentially significant. BASE (DIESEL) PLAN The base plan has the largest potential environmental effect, due to its burning of fossil fuels. While modern air pollution control technology can substantially reduce air emis- sions, this scenario still has the largest air pollution potential. Also, because of its reli- ance on diesel fuel that is imported to the Juneau area, it has the potential for increas- ing secondary ground and water pollution due to transportation and storage spills. The number of sites available for use in diesel generation is also limited. This resource package envisions between 29 and 43.5 MW of additional diesel generation, depending upon the load forecast. This represents about 10 to 15 EMD diesel engines. Currently, AELP has room for about 5 to 8 additional diesel units at its Lemon Creek facility and another 2 units at the Auke Bay facility. Additional diesel units would need to be at new sites, most likely near the mining loads they would serve. While the industrial V-40 nature of surrounding land use at the Lemon Creek site should not represent a fatal flaw, base load operation at the Auke Bay facility could be a problem. . This is due to the mixed commercial and residential uses adjacent to the Auke Bay site. To the extent that onsite generation is provided by the mines, siting concerns will be transferred to those organizations. Echo Bay is evaluating alternative fuels such as LNG and LPG, which have a lower carbon and sulfur content than diesel fuel, as a means of addressing concerns over potential air pollution. LAKE DOROTHY LEAST-COST RESOURCE PACKAGE This resource package has approximately 12 to 15 MW less new diesel than the base plan. Furthermore, the diesel is only used until Lake Dorothy is in commercial opera- tion in 1996. Therefore, the potential for air pollution is smaller and limited in dura- tion. Major areas of environmental concern would be the raising of Crater Lake and Long Lake and the construction of a Lake Dorothy power plant and transmission line. Because of the high elevation of the three lakes and the construction of the hydro facil- ities as "lake taps," there should be little impact on the environment except that due to spillway and intake structure construction and fluctuations in lake levels. The major environmental impact appears to be associated with the development of a construction staging area for the Lake Dorothy project on Taku Inlet and the disposal of tunnel spoils. This in itself does not appear to represent a fatal flaw. The transmission from this project is principally through an underwater cable, which does not appear to consti- tute a major environmental problem. Programmatic conservation and load management programs included in this package can be viewed as a means of mitigating some of the environmental impacts of this least-cost package of resources. The reliability benefits of this package can also be viewed as environmental benefits. ANNEX CREEK/CARLSON CREEK LEAST-COST RESOURCE PACKAGE The Annex Creek/Carlson Creek resource package would require about 9 MW less new diese] generation than the base-case plan. Because of the seasonal nature of the hydro generation, some diesel generation is required after the Annex Creek/Carlson Creek project is in commercial operation in 1996. Therefore, from an air pollution perspec- tive, this resource package has substantially less impact than the base plan but more than the Lake Dorothy package of resources. Also, because of the nonfirm nature of the hydro power, this resource package has the potential for greater air pollution dur- ing dry years. While this resource package does not include a dam addition at Long Lake, the envi- ronmental impact of such an action does not appear substantial. Construction and V-41 staging at the Annex Creek site represent potential environmental impacts. Removal or disposal of tunnel spoils would also be an environmental concern. The aréa is re- mote and the terrain difficult. Potential fishery-related environmental concern over this project will probably be due to the diversion of water from one drainage area to another. The environmental impact of the overhead transmission line from this project will also need to be studied. As with the Lake Dorothy resource package, programmatic conservation, load manage- ment and reliability enhancements can be viewed as mitigation for this predominately hydropower-based resource package. LAKE DOROTHY/LONG LAKE LEAST-COST RESOURCE PACKAGE Of the three hydro-based resource packages, this package requires the most diesel gen- eration. This package has about 6 MW less new diesel generation than the base plan. While the hydro project is on-line in 1995, and hence reduces major base load genera- tion most rapidly, this project also requires the most periodic diesel generation of the three hydro-based packages because its hydro resource produces the least energy. From an environmental standpoint, the major impacts appear to be in the construction staging of the diversion tunnel, tunnel spoils disposal, and diversion of water that nor- mally drains into Taku Inlet to the Port Snettisham/Speel River area. Because of the high elevation of the lakes and previous construction activities on Long Lake, the con- struction impacts will probably not be a fatal flaw. Diversion of water between drain- age basins is a more serious potential impact, and its impact on fishery stock would need to be studied in greater depth. This project has no additional transmission associated with it and therefore has a slightly reduced environmental impact in this area. However, because of the lack of transmission, the enhancement of reliability is the least. As with the previous two hydro-based resource packages, programmatic conservation and load management resources can be viewed as mitigation measures. sea7308/061.51 V-42 ae VI. IMPLEMENTATION PLAN VI. IMPLEMENTATION PLAN This section outlines the major actions that should be performed by the sponsors so that the findings of the Power Supply Plan can be implemented. One of the major reasons for this update of the Juneau Power Supply Plan is planned expansion of min- ing activity in the Juneau area. The proposed mining activity will more than double the electricity needs of the Juneau area. Yet the method, fuel, and level of purchases of electric energy by the mines are unclear. Consequently, the implementation plan is a contingency plan that starts by clarifying the plans of the mines and then recommends actions based upon the analysis performed within the plan. There are several stages to the implementation plan. First is the need to clarify each mine’s energy plan with regard to self-generation. If the mine chooses self-generation, then interconnection to AELP must be evaluated. Similarly, if self-generation is cho- sen, it must be determined what services will be needed and cost-effective for the par- ticular mine. Then a decision can be niade that is supported by the mines and the sponsors as to what resources can best serve these loads. Finally, the implementation plan recommends that certain activities be performed to keep options open and to prepare for contingencies. Most of this final group of recom- mendations is designed to allow the next update of the Power Supply Plan to build upon the findings of this Plan. 1. NO-MINE SCENARIO Under the no-mine scenario, there is no need in the near future for any new generation beyond replacement of existing facilities at the end of their economic life. Sponsor activity should focus on optimizing the use and conservation of existing resources and on keeping options open for future development should the need arise. 2. CLARIFY THE A. J. MINE’S ENERGY PLAN OF SERVICE Work with Echo Bay to clarify the A. J. Mine’s:- energy plan and its interconnection requirements. Three major electric commodities can be sold by AELP to the A. J. Mine that will benefit all parties: surplus firm hydropower, surplus nonfirm power, and forced outage reserves. The mining loads are the key element that has required the updating of the Power Supply Plan. How these loads will be served and what, if any, electric services willbe required of AELP are the key elements in deter- mining what resources, if any, should be developed. Interconnection by the mining loads and the use of hydropower have both economic and environmental benefits to the community. VI-1 Surplus firm hydropower sales to the A. J. Mine will defer the need for a rate increase by APA and hence will help hold down the retail cost of power for AELP’s nonmining customers. Similarly, the sale of nonfirm power to the A. J. and any other mines that self-generate will be beneficial. The use of nonfirm hydropower from APA and AELP projects would allow the mine’s self-generation facilities to be shut down or run at a lower load level. This displacement of fossil fuels (diesel, LNG, LPG) should provide both environmental and economic benefits to the Juneau community. Therefore, the negotiation of surplus hydropower agreements for a mine with self-generation should be a goal of the sponsors. Since one objective of the A. J. Mine’s plan to self-generate is to secure a reliable, independent source of power, surplus capacity (beyond that required to serve the ca- pacity needs of the area’s nonmining loads) can be made available to the mine at those times when the mine’s diesel generation suffers outages. This sale of forced outage reserves should be economically beneficial both to the mine and to the nonmining rate- payers of AELP. 3. EVALUATE INTERCONNECTION COSTS WITH THE KENSINGTON AND JUALIN MINES IF THEY SELF-GENERATE The economics of providing transmission service to the other mines should be evalu- ated. One of the assumptions of this study was that all the loads would be connected to the existing AELP transmission grid. Development of the Kensington and Jualin mines, especially if the mines self-generate, may make transmission to these mines non- cost-effective. This would be due, in part, to the lower quantity of electric sales and the potential for inadequate revenues to offset the fixed costs of building a transmission line to the mines. Also, depending upon the needs of the mines, transmission service could require AELP to convert a portion of its system from 69 kV to a higher voltage. The feasibility of converting from 69 kV to 138 kV and cost estimates on providing service to the mining area should be made or updated in cooperation with the operators of the Kensington and Jualin mines. This information would then be available to the mines as their plans are developed. Similarly, the value of providing the mines with surplus firm and nonfirm hydropower and forced outage reserves, should they self-generate, should be evaluated. Self-gener- ation at these mines and the costs of extending transmission service may effectively preclude AELP’s ability to sell surplus firm and nonfirm hydro energy and to offer forced outage reserves. 4. INITIATE CONSERVATION PROGRAM ACTIONS BY SPONSORS In either the A. J. Mining or multiple-mining load growth scenario, the sponsors should consider implementing conservation programs if the. mines are interconnected. Prior to VI-2 implementing the conservation programs, further market research needs to be: per- formed on internal and external residential lighting options. A more detailed analysis should also be performed on the potential savings from floor insulation. This research may warrant an update of the 1987.Energy Management and Conservation Study. Lighting-related conservation programs, especially in the. commercial sector, will be among the least-cost energy options. Cost-effective conservation programs will allow electricity from existing generation facilities to be diverted to better uses within the community. As such, taking steps to initiate a pilot project that is capable of demon- strating the benefits of commercial-sector programs may be appropriate. Such a pro- gram could be funded by a combination of state and/or federal grants and utility and private-sector (mines, building industry suppliers, etc.) funds. — Commercial lighting programs need to be carefully examined to prevent the introduc- tion by office employees of "task lighting," which can negate the savings associated with new and more efficient general-area lighting conservation programs. The impact of reduced building lighting waste heat on diesel heating costs will need to be observed and quantified. Finally, the conservation programs may cause interruption of business, which will need to be studied and mitigated. Investigation of these elements of lighting conservation in a comprehensive pilot project should help in the design of a long-term conservation program and provide examples that can be followed over the 20-year implementation period. 5. INITIATE LAKE DOROTHY DEVELOPMENT PLAN The next priority item that should be accomplished is to work with Echo ‘Bay to estab- lish the level of the mining loads and the timing of their startup to determine the desir- ability of constructing the Lake Dorothy hydro project. The economic results of the least cost analysis indicate that Lake Dorothy should be considered the prime hydro resource to be developed should the mines agree to support major hydro resources. If the mines agree to support the development of a major hydro project, then the first step will be to investigate the financial feasibility of Lake Dorothy based upon commit- ments that mine operators are willing to make. We recommend that AEA be chosen as the lead agency for these activities because of its proven ability to issue bonds and manage the development of large hydro projects. AEA’s experience and organization structure would lend themselves to an expedited development schedule. If Lake Dorothy cannot be financed, then larger projects are also probably not financ- able. As such, working with the mines to investigate their desire to finance either a staged construction version of Lake Dorothy or dam additions to Long Lake or Crater Lake may be appropriate at that point. The second step in the Lake Dorothy development plan will be to perform the neces- sary environmental analysis to file a FERC license application and to seek the required VI-3 state permits. Because Lake Dorothy is part of the least-cost resource package, stream gauging work by the sponsors should be continued. The sponsors may wish to evaluate the environmental analysis required for an FERC license and identify low- to moderate- cost items on the critical licensing path that could be performed after a tentative agree- ment with the mines is reached. Because Lake Dorothy has been extensively studied, the licensing documents should be comparatively easy to prepare. As licensing proceeds, and assuming that no environmental fatal flaws are uncovered in the licensing process, power sales contracts will need to be developed that will serve as the financial basis to justify the project. The power sales contracts and other formal agreements needed for financing are the third step in the development plan for Lake Dorothy. The prime initial beneficiary of the project will be the mining loads. Investors will recognize that the existing customers of AELP do not need the additional power that would be produced by the facility during the term of the bonds. The investors will also recognize that the development of Lake Dorothy without mining loads could cause a rate shock to AELP’s customers. Consequently, investment would be unlikely without a path of secure contracts and streams of revenues or asset guarantees from users of the additional power to the agency issuing the bonds for the term of the bond repayment. 6. CONDUCT ADDITIONAL WORK RELATED TO FUTURE POWER SUPPLY PLAN UPDATES While consideration of Lake Dorothy should be the first priority, further investigation of other hydroelectric project alternatives is warranted so as to keep options open to the Juneau community. This additional work should be in two forms: additional streamflow data and adoption of a modeling technique that will evaluate variations in stream flow on both a seasonal and annual basis. Specifically, because of the limited streamflow information and the highly seasonal nature of some of the hydro resources, additional streamflow information could change the underlying economics calculated in this study. It is our opinion that additional stream flow data and a different modeling technique would more correctly evaluate the true economics of the Annex Creek/Carlson Creek project. Additional stream gauging work and analysis of historical hydrologic data should be considered for the hydro resources to be studied in the next Juneau Power Supply Plan. Either prior to or during the next update of the Juneau 20-Year Power Supply Plan, a comparison of Annex Creek/Carlson Creek, Sweetheart Lake, Tease Creek, and/or Speel River should be made on the basis of needs for additional generation. If "run of the river" hydro projects such as Annex Creek/Carlson Creek are still viable, then in the next update of the Juneau 20-Year Power Supply Plan, the consultant should perform a monthly "Monte Carlo"-style simulation analysis of the hydro projects using the VI-4 expanded hydraulic information. Such a simulation would take 20 to 40 years of monthly data and randomly select the annual hydraulic conditions for a large number of cases to produce a statistical evaluation of electricity production from the projects. This data could then be used in economically evaluating ‘the hydro projects. 7. DEVELOP A SNETTISHAM SUBMARINE CABLE CONTINGENCY PLAN A contingency plan should be developed to manage the potential for a multiple cable failure of the Taku Bay crossing of the Snettisham submarine cable. The contingency plan should identify possible solutions, the time required to implement them, and po- tential mitigation measures that could either reduce the local needs or reduce lead times for undertaking repairs. The mitigation plan could include the periodic review of submarine cable specifications and contracts to minimize the time needed to acquire replacement cables, as well as an evaluation or pre-qualification of submarine cable- laying and splicing firms. 8. MONITOR LNG FACILITIES IN ALASKA The sponsors should monitor development of LNG production facilities in Alaska and, depending upon progress in this area, consider LNG or LPG fuel options in the next update of the Juneau 20-Year Power Supply Plan. 9. MONITOR ROAD CONSTRUCTION PLANNING Another set of events to monitor will be any road development either along Lynn Canal or along the Taku River, which might reduce potential transmission interconnec- tion costs. 10. © MONITOR MINING ACTIVITY FOR POTENTIAL LOADS The economic changes that have resulted in the activity at the Cyprus Anvil Mine in the Yukon, the A. J. Mine, the Kensington mine, and the Jualin mine could also create interest in opening mines along the Alaska/British Columbia boarder. Such potential developments should be monitored, should the distance to either the Snettisham or AELP make it economical to develop a transmission intertie as a source of mine power. : 11. EVALUATE REBUILDING OR RELOCATING THE ANNEX CREEK TRANS- MISSION LINE When the A. J. Mine is reopened, there may be an opportunity to work with the mine on rebuilding or relocating the Annex Creek Transmission line. This option should be explored by AELP with the A. J. Mine. This line, over 40 years old, has high losses, and rebuilding it would result in additional energy that is not dependent upon fossil fuel. VI-5 a VII. LETTERS RESPONDING TO DRAFT PLAN VI. LETTERS RESPONDING TO DRAFT PLAN VII-1 aes ign od —_ | JUNE. \U ECONOMIC DEVELOPMENT COUNCIL ues eel Tel. sod-3002 ¢ Pax 1907! 463-5670 © 211 4th St., Suite 300 ¢ Juneau. Alaska 99801 oD ee ~— att ‘ MEMAES Greg O'Claray, Treamucer Peter Hildre CB) REPRESENTATIVES Willian Brock Chairperson Patrick Anderson Theedore Ro Merrell Mayor Bruse Botelho Deborah Raley, Vier Ch iiepernon William M. Howe Kevin Ritchie May 31, 1990 Co Robert K. Schneider CH2M Hill 777 108th Avenue N.E. . Bellevue, Washington 98009-2050 ° Dear Bob: As I indicated during our brief discussion during your Juneau visit on May 30/31, I have a few comments to pass on regarding the Draft Juneau 20-Year Power Supply Plan Update. \ First, I suggest you reexamine your assumptions leading to the use of the 0.7 residential customers per job multiplier (Load cy Forecast, page II-1). The Juneau-bdased firm, The McDowell Group, with almost 20 years of economic analysis experience in Southeast, claims their data base shows a population multiplier per job of 2.0. In other words, each job created in Juneau will add a second person to the local population. This may have an impact on the user-demand projections within your model.. I would suggest you at least talk to either Eric McDowell or Jim Calvin of The McDowell Group (907-586-6126). ty Second, I wanted to raise the same question raised during your P| May 31 Alliance presentation regarding the consideration of 7 Canadian mining projects above the Taku River. I appreciate that \ B. C. Hydro ig not looking to serve the remote locations, but the i two potential projects, Tulsequah Chief (Cominco) and the Polaris- a Taku (Suntac) are major projects. Tulsequah could be as significant as Greens Creek. present a significant user demand that could justify bringing the Dorothy Lake project on line ~ potentially with some marginal reserve for Juneau-based users. The Tulsequah project is giving some preliminary thought to designing a road corridor to the Taku River, possibly one-third the distance to Juneau. Juneau will Both projects are within a few niles of each other and could VII-3 “serve as the service center for the project. Again, this may have some impact on your model forecasts. Thank you for the opportunity to comment. If I can be of any further assistance, don’t hesitate to call. —O James M. Kohler Executive Director t VII-4 JUNEAU ECONOMIC DEVELOPMENT COUNCIL Major Points 1. 2. Load forecast may be too low because of job multiplier. Load forecast may be too low because of potential Canadian mining above the Taku River. Comments 1. A sensitivity analysis (Table V-8) was performed upon load forecasts that increased the multiple mine load forecast by 10 percent. This increase did not change the order of the least cost packages. We believe that the sensitivity analysis encompasses the relative range of revision that could occur because of a revised job multiplier. Our recommendation to the sponsors is to perform a sensitivity analysis of loads to changes in economic multipliers the next time the load forecast is performed by APA. The letter correctly points out that there are promising mineral deposits up the Taku River that could result in increased Juneau direct loads and in additional indirect service-related growth. Implementation Plan recommendations 9 and 10 indicate a need to monitor the activities identified in the letter. Mr. Kohler is correct that these developments could assist in justifying cost-effectiveness and construction of hydroelectric resources, such as Lake Dorothy. VII-5 YAN Alliance for Juneau's Future, Inc. June 7, 1989 Robert K. Schneider CH2M Hill 777 108th Avenue N.E. Bellevue, Washington 98009-2050 Dear Bob: I want to express the appreciation of our membership for your special efforts in providing information on the revision of the Juneau 20 Year Power Supply Plan. This has enabled our members to better understand the energy needs of our community in the future.The Draft Plan is well written and covers the major issues under different scenarios. The Plan notes that there is a great deal of uncertainty in determining an optimal resource strategy because mine development energy plans have not been completed. There is also uncertainty related to projected power demands that would be associated with the sharp reduction of Alaska oil production over the next two decades. The Mayor's Task Force on Fiscal Policy and the McDowell Group's study of population projections consider the impact of "Alaska's Fiscal Gap" on the Juneau area. The rapidly changing’ political and socio-economic conditions underway throughout the world, probably add to the uncertainty of when the next: world-wide energy crisis will occur. With depleted oil supplies and the growing restraints on exploration and development of new oil fields, another energy crisis seems inevitable, possibly in the next two decades. National, state and local community energy policies and plans should recognize this, and provide incentives for the development of new hydro electric power sites and the implementation of new technologies in transmission, _interties, etc. The Draft Plan wisely provides for contingency plans and actions for different circumstances. It would be more reassuring if planning for the Dorothy Lake Project could be undertaken, but this does not seem to be economically justified at this time. Again, we appreciate your assistance and the opportunity to comment on this very important issue. (xl eli vila Executive Director 3344 Foster Avenue e Juneau, Alaska 99801 e 586-2495 or 586-2497 Vil-7 ALLIANCE FOR JUNEAU’S FUTURE, INC. Major Points 1. Uncertainty (possibly lower load forecast) in future loads. 2. Plans should recognize possible shortage of oil-based fuels in future, thus favor- ing hydro and transmission. Comment 1, A sensitivity analysis (Table V-8) was performed on the A. J. Mine load forecast that was 10 percent lower. Considering that the A. J. Mine represents about half of the load, this could correspond to about a 20 percent reduction in either mining or Juneau nonmining energy needs. The sensitivity analysis showed no change in the order of least cost resource packages for Juneau. 2. While an independent forecast of world oil price and oil availability was beyond the scope of the assignment, a sensitivity analysis (Table V-10 and Figure V-2) was performed that looked at changes in oil prices. As the letter correctly points out, when the price of oil increases, hydro projects become much more attractive in terms of net present value calculations. VII-9 to Alaska Applied Sciences, Inc. Soy fe. " Box 020993 « Juneau, Alaska 99802 5 905864426 ° FAX: 5861423 5 July 90 Alaska Power Administration Alaska Electric Light and Power Alaska Energy Authority Juneau Energy Advisory Committee Folks: The "Juneau 20-year Power Supply Plan Update (draft)” isa well-crafted and very useful document, for which I thank you all. I've perused the document; please excuse me if I've missed something. Please include these suggestions in the final version: 1. The "plan" imagines only major mines as the demand for Juneau's current hydroelectric surplus, and for any further hydroelectric source development. The "Plan" needs to propose what, to me, is a far more promising long-term alternative: "Petroleum Displacement”, whereby hydroelectric energy-- either directly or after conversion to another form, like hydrogen-- displaces some of the petroleum now used for transportation and space heating in Juneau. 2. Page V-36 "Environmental Considerations” makes no attempt to internalize the environmental externalities in any quantified way. This is a major omission, severely limiting the usefulness, and useful life, of the "Plan". 3. In economic analyses throughout the "Plan”, such as that on page III-3, "payback period’ should be supplemented with present value (PV) and internal rate of return (IRR). Payback, while intuitively appealing and simple, is generally regarded as inferior to PV and IRR, especially for investments with long service life. "Where there is no vision, the people perish” ---- Proverbs 29:18 The twin threats of global warming and the USA’s increasing dependence on imported petroleum require a national and global "petroleum displacement” strategy, a vision by which the people may NOT perish. Please include Juneau's contribution to this strategy as a scenario in the final "Plan"; it should include the conservation options presented in part III. VII-11 I believe enough data and information is available to develop “petroleum displacement” into a credible alternative scenario. Please do so, within your resources. I’m willing to donate some of my time to this end. Advantages of a petroleum displacement strategy for Juneau include: + amelioration of global warming less dependence on foreign oil . relief from price escalation for petroleum fuels attracting a variety of new businesses and jobs to Juneau recognition as an innovative community; an example to other communities; a testing laboratory for new technologies OPAN rH Juneau now enjoys an extraordinary asset, a surplus of non-polluting, renewable, hydroelectric energy: about 100 million Kwh, a third of our present total electric energy consumption. Let’s not commit it to the first project or industry that comes along, but develop alternative use scenarios to most-improve the quality of life, in Juneau and on Earth, for centuries to come. Please see following Appendix page for detailed comments on the ~ "Plan” document. : Thank you for your consideration. Sincerely, —A . William C, Leighty copy: Murray Walsh Mayor Botelho Alliance for Juneau's Future Alaskans for Juneau VII-12 APPENDIX Section II needs to: . a. include total annual megawatt—-hours of generating capacity for each system component and for total system: potential annual energy output b. conclude with the current energy surplus: express in megawatt~hours and percentage of total demand. Table III-1: . a. what type heat pump assumed? air-air, water-air, or ground-air What COP assumed? Serving individual dwelling, group, or district? b. typo in bottom line "Floor R2...” c. Why omit window retrofit? Wall insulation/siding retrofit? Analysis in IV omits energy storage: thermal, electrical, or chemical ‘conversion to hydrogen). These may be distributed, in vehicles, homes, and buildins, for significant generating system savings. VII-13 ALASKA APPLIED SCIENCES, INC. Major Points 1. Load forecast scenarios too low as displacement of petroleum consumption has not been included. Environmental impacts not quantified in dollars and not internalized in evaluation. Economic analysis based upon payback methods is inferior to net present value and internal rate of return analysis. Both conservation programs and petroleum displacement policy should be included in least cost-resource packages. The appendix contains certain specific format suggestions, questions about con- servation programs, and energy storage. Comments 1. To evaluate a Juneau fuel substitution and total energy plan was beyond scope of the study and would require far greater citizen and industry participation. Internalizing environmental costs in analysis also was beyond the scope of the study and was not performed because of the controversial nature of quantifying the range of such costs Mr. Leighty is correct in his statement about net present value and internal rates of return being better methods. This is why all economic analysis was based upon net present value calculations or upon life-cycle levelized costs, which uses present value as part of the calculation. Payback values were shown for reader reference and for their use in customer penetration calculations. Conservation programs discussed in Section III were included in the A. J. Mine and multiple mines least cost resource packages.. The recommended Lake Dorothy least cost package is principally composed of new renewable and conservation resources. Although there is no explicit petroleum displacement policy included, the preferred least cost package of resources substantially reduced the need for petroleum-related electric energy production. The questions on heat pump, window, and wall insulation conservation programs were either discussed in the Energy Conservation Management Plan or in meet- ings with the Juneau Energy Advisory Committee. VII-15 AIA CREED APPENDIX A ANALYSIS OF ALTERNATIVES Unit Name Unit Type Economic. Life (years) Maximum Capacity (MW) - Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond,Term (years) Interest Rate Time Value of Money Construction Period (months) Initial Capital IDC (linear construction) 1 Years Debt Service 1 Month Debt Service (WC) Finance Expenses Bond. Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service PV of Payments Fuel PV of Payments O&M PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) Dorothy/Long Tunnel Hydro 50 NA “NA 42,900 42,900 NA NA NA 0.3 2A 30 7.635% 3.000% 24 $40,300,000 $3,090,997 $4,225,285 $352,107 $300,000 $985,069 $49,253,458 $4,225,285 $49,253,458 $128,700 $3,311,421 10.4 49 Lake Dorothy Hydro 50 26 NA 127,000 127,000 NA NA ’ NA $305,000 1% 30 7.635% ° 3.000% 36 - $82,700,000 $9,908,431 $2,985,022 $748,752 $300,000 $2,094,739 $104,736,994 $8,985,022 $104,736,944 $305,000 $7,847,578 14 3.5 Long Lake El. 845 Hydro 50 NA NA 13,000 13,000 NA NA NA 0.3 2% 30 7.635% 3.000% 18 $14,300,000 $800,242 $1,489,332 $124,111 $300,000 $347,218 $17,360,903 $1,499,332 $17,360,903 $39,000 $1,003,461 12.0 5.6 Unit Name Long Lake El. 870 Long Lake El. 895 Crater Lake El. 1034 Unit Type Hydro Hydro Hydro Economic Life (years) 50 50 50 Maximum Capacity (MW) NA NA NA Assumed Plant Factor NA NA NA Firm Annual Energy (MWH) 29,000 38,000 2,900 Ave Annual Energy (MWH) 29,000 38,000 2,990 Fuel Type . NA NA NA Ave Heat Rate (BTU/kWh) NA NA NA Fuel Consumption (kWh/Gal) NA : NA NA Fixed O&M ($/year) ; Variable O&M (cents/kWh) 0.3 0.3 0.3 Transmission Losses 2% 2% Bond Term (years) 30 30 30 Interest Rate 7.635% 7.635Y0 7.635% Time Value of Money 3.000% 3.000% 3.000% Construction Period (months) 24 36 12 Initial Capital $37,100,000 $53,700,000 $2,700,000 IDC (linear construction) $2,845,558 $6,433,890 $96,516 1 Years Debt Service $3,892,082 $5,844,463 $272,316 1 Month Debt Service (WC) - $324,340 $487,039 Finance Expenses $300,000 $300,000 Bond Discounts $907,387 $1,362,559 Total Bond Issue $45,369,368 $68,127,951 Total Debt Alt. Method $3,174,347 Annual Debt Service $3,892,082" $5,844,463 $272,316 PV of Payments $45,369,368 $68,127,951 $3,174,347 Fuel PV of Payments O&M $87,000 $114,000 $8,700 PV of Payments $2,238,489 $2,933,193 $223,849 1990 Costs (cents/kWh) 14.0 16.0 9.9 1990 LCLC (cents/kWh) 65 7.4 46 Unit Name Unit Type Economic Life (years) Maximum Capacity (MW) Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond Term (years) "Interest Rate Time Value of Money Construction Period (months) Initial Capital IDC (linear construction) 1 Years Debt Service 1 Month Debt Service (WC) Finance Expenses Bond Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service PV of Payments Fuel PV of Payments O&M PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) Crater Lake El. 1047 Hydro 50 NA NA 6,000 6,000 NA NA NA 0.3 2% 30 7.635% 3.000% 18 $6,300,000 $352,554 $647,806 $7,551,366 $647,606 $7,551,366 $18,000 $463,136 11.3 5.3 Annex Creek Hydro 50 2.9 NA 1,200 1,200 NA NA NA 0.3 2% 30 7.635% 3.000% 12 $2,900,000 $103,665 $292,488 $3,409,484 $292,488 $3,409,484 $3,600 $92,627 25.2 11.6 Annex Creek/Carison No.1 Hydro 50 28 NA’ 59,700 164,400 NA NA NA $305,000 2°%/o 30 7.635% 3.000% 36 $96,100,000 $11,513,908 $10,436,178 $869,681 © $300,000 $2,433,056 $121,652,824 $10,436,178 $121,652,824 $305,000 $7,847,578 6.7 a1 Unit Name Unit Type Economic Life (years) Maximum Capacity (MW) Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond Term (years) Interest Rate Time Value of Money Construction Period (months) Initial Capital IDC (linear construction) 1 Years Debt Service 1 Month Debt Service (WC) Finance Expenses Bond Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service _ . PV of Payments Fuel . PV of Payments O&M : PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) Annex Creek/Carison No.2 Hydro 50 28 NA 155,400 165,500 NA NA NA $305,000 2A 30 7.635% 3.000% 48 $245,200,000 $40,509,707 $27,659,531 $2,304,961 $300,000 $6,448,453 $322,422,651 $27,659,531 $322,422,651 $305,000 $7,847,578 17.2 19 GM-EMD 20-645-f Diesel 10% 20 2.85 10% 2,497 diesel 9,625 145 0.44 OY 20 7.635% 3.000% 12 $1,760,000 $62,914 $205,061 $2,069,204 $205,061 $2,069,204 $141,872 $2,591,176 $10,985 $163,430 14.3 13.0 GM-EMD 20-645-f Diesel S0% 20 2.85 SO% 12,483 diesel 9,625 14.5 0.44 % 20 7.635% 3.000% 12 $1,760,000 $62,914 $205,061 $2,069,204 $205,061 $2,069,204 $709,359 $12,955,879 $54,925 $817,148 7.8 Bs Unit Name Unit Type Economic Life (years) Maximum Capacity (MW) Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond Term (years) Interest Rate Time Value of Money Construction Period (months) Initial Capital IDC (linear construction) 1 Years Debt Service 1 Month Debt Service (WC) Finance Expenses Bond Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service PV of Payments Fuel PV of Payments O&M PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) GM-EMD 20-645-f Diesel 80% 20 2.85 80% 19,973 diesel 9,625 145 0.44 0% 20 7.635% 3.000% 12 $1,760,000 $62,914 $205,061 $2,069,204 $205,061 $2,069,204 $1,134,974 $20,729,407 $87,880 $1,307,437 7A 81 GM-EMD 20-645-e Rebuitt Diesel 10% 20 2.85 10% 2,497 diesel 10,185 13.7 0.44 0% 20 7.635% 3.000% 12 $1,250,000 $44,683 $145,640 $1,469,605 $145,640 $1,469,605 $150,126 $2,741,935 $10,985 $163,430 12.3 11.8 GM-EMD 20-645-e Rebuitt Diesel 50% 20 2.88 50% 12,483 diesel 10,188 13.7 0.44 0% 20 7.635% 3.000% 12 $1,250,000 $44,683 $145,640 $1,469,605 $145,640 $1,469,605 $750,631 $13,709,676 $54,925 $817,148 76 8.6 Unit Name Unit Type Economic Life (years) Maximum Capacity (MW) Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond Term (years) Interest Rate Time Value of Money Construction Period (months) Initial Capital IDC (linear construction) 1 Years Debt Service © 1 Month Debt Service (WC) Finance Expenses Bond Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service PV of Payments Fuel PV of Payments O&M PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) CAT 3612 Diesel 10% 20 3 10% 2,628 diesel 9,270 18.4 0.41 ow 20 7.635% 3.000% 12 $2,060,000 $73,638 $240,015 $2,421,909 $240,018 $2,421,909 $143,831 $2,626,953 $10,775 $160,302 15.0 13.3 CAT 3612 Diesel 50% . 20 3 50% 13,140 diesel 9,270 15.1 0.41 0% 20 7.635% 3.000% 12 $2,060,000 $73,638 $240,015 $2,421,909 $240,015 $2,421,909 $719,153 $13,134,764 $53,874 $801,509 77 84 CAT 3612 Diesel 80% 20 3 80% 21,024 diesel 9,270 181 0.41 om 20 7.635% 3.000% 12 $2,060,000 $73,638 $240,015 $2,421,909 $240,015 $2,421,909 $1,150,645 $21,015,623 $86,198 $1,262,415 7.0 79 Unit Name Unit Type Economic Life (years) Maximum Capacity (MW) Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond Term (years) Interest Rate Time Value of Money Construction Period (months) Initial Capital IDC (linear construction) 1 Years Debt Service 1 Month Debt Service (WC) Finance Expenses Bond Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service PV of Payments Fuel PV of Payments O&M PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) GE Frame 5 (PG5371PA) Combustion Turbine 50% 20 26.3 50% 115,194 diesel 13,500 10.4 $79,000 0.0013 O% 20 7.635% 3.000% 12 $12,760,000 $456,127 $1,486,694 $15,001,729 $1,486,694 $15,001,729 $9,181,422 $167,691,410 $80,498 $1,197,600 93 10.7 GE LM 2500PE Combustion Turbine 50% 20 21.23 50% 92,987 diesel 11,200 125 $64,000 0.0013 0% 20 7.635% 3.000% 12 $12,200,000 $436,109 $1,421,447 $14,343,346 $1,421,447 $14,343,346 $6,148,773 $112,302,472 $65,209 $970,143 82 92 Channel Sanitation Municipal Waste 20 0.75 5,631 Municipal Waste NA NA NA NA 0% NA NA 3.000% NA NA NA NA NA NA NA NA NA NA NA $33,786 $502,650 NA NA 60 6.0 Unit Name Unit Type Economic Life (years) Maximum Capacity (MW) Assumed Plant Factor Firm Annual Energy (MWH) Ave Annual Energy (MWH) Fuel Type Ave Heat Rate (BTU/kWh) Fuel Consumption (kWh/Gal) Fixed O&M ($/year) Variable O&M (cents/kWh) Transmission Losses Bond Term (years) Interest Rate Time Value of Money Construction Period (months) . Initial Capital IDC (linear construction) 1 Years Debt Service 1 Month Debt Service (WC) Finance Expenses Bond Discounts Total Bond Issue Total Debt Alt. Method Annual Debt Service PV of Payments Fuel PV of Payments O&M PV of Payments 1990 Costs (cents/kWh) 1990 LCLC (cents/kWh) Whitehorse-Mines Imertie 30 NA NA NA 131,400 Purchased Power NA NA 1,607,920 NA 10% 30 7.635% 3.000% 30 $87,000,000 $8,524,087 $9,266,991 $772,249 $300,000 $2,160,476 $108,023,803 $9,266,991 $108,023,803 $10,512,000 $122,536,674_ $1,607,920 $31,515,942 18.1 11.3 Tyee-Snettisham Intertie 30 NA NA NA 85,000 Purchased Power NA NA §71,100 NA 10% 30 7.638% 3.000% 30 $108,000,000: $10,581,625 $11,496,848 $998,071 $300,000 $2,680,338 $134,016,881 $11,496,848 $134,016,681 $5,440,000 $63,413,195 $571,100 $11,193,812 22.9 13.9 Snettisham-Juneau * Intertie 30 NA NA NA NA NA NA NA 40,000 NA 2% 30 7.638% 3.000% 24 $30,000,000 $3,834,984 $5,235,306 $436,275 $300,000 $1,220,842 $61,027,107 $5,235,306 $61,027,107 $0 $o $40,000 $784,018 NA NA NEMORANDUN CHMHILL TOs File FROM: Bob Schneider/SEA DATE: April 10, 1990 SUBJECT: Intertie Cost Updates PROJECT: ANC282B89.A0 1, Whitehorse to Juneau The Whitehorse to Juneau line was divided into three segments: Canadian Boarder to Skagway; Skagway to Mines; and Whitehorse to U.S./Canadian boarder. The cost basis of the numbers is an update of total costs in the 1987 Southeast Alaska Transmission Intertie Study. January 1990 to January 1987 transmission cost increase index was 1.27908. ce Canadian Boarder to Skagway} Harza value escalated to January 1990 7.132 million # 1.27908 =$9.122 million Skagway to Mines; Reduction from Harza Estimate due to transmission to mines 138 KV AC (Harza table 4-6) $148,000/mile Clearing (Harza table 4-8) $ B5,000/mile $233,,000/mile 15 miles * $233,000/mile = $3,495,000 Revised Harza estimate Skagway to Mines $52.129 million Harza estimate Skagway to Juneau ~ 8.480 million engineering -_7.288 million contingency $36.341 million - 3,495 million 15 wiles OH -_ 4,281 million Bridget Cove to Juneau $28,585 million x 1.20 contingency $34.303 million x 1.194 engineering etc. $40.956 million Revised Harza based estimate escalated to January 1990 $40.956 million, * 1.27908 = $52.386 million aA-9 MEMORANDUA Page 2 April 10, 1990 ANC2B8289.A0 Whitehorse to U.S./Canadian boarder; From Harza table 4-6 $148,000/mile for 138 Kv Overhead assume: utilize existing road, railway & Yukon electric system right of way - no significant land, Clearing or rock contruction costs and a distance of 93 miles. 93 miles * 148.000 million $13.764 million x 4.2 contingency $16.5168 million x 1.194 engineering, CM, land $19,721 (may be low due to Presidential Permit costs) $25.225 million Total Whitehorse to Mines transmission cost (Jan 1990 $) II, Canadian Boarder to Skagway $ 9.122 million Skagway to Mines $52,386 million Whitehorse to U.S./Canadian boarder $25,225 million total $86.7 million Tyee Lake to Snettishan Juneau/Snettisham to Kake $57.986 million x 1.27908 escalate to Jan 1990 $74,169 million Kake to Petersberg $26.452 million x 1.27908 escalate to Jan 1990 $33.834 million Total cost $ 74.169 million $ 33.834 million total $108.0 million A-10 REN Page 3 April ORANDUH 10, 1990 ANC28289.A0 It. Snettisham to Juneau Submarine Cable From the Ebasco Study 42 miles of submarine cable or 221,760 feet of submarine cable From the Harza Study submarine cable costs for similar lengths: Haines Bridget $13.58 million /277,000 ft = 49.0 Kake-Warm Springs Bay $12.35 million/ 190,000 ft 65.0 221,760 feet @ 49.0/ft = $10.866 million x_ 1.27908 escalate to Jan 1990 $13.899 million 221,760 feet @ 65.0/ft = $14,414 million x 1.27908 escalate to Jan 1990 $18.437 million average submarine cable value = $146.2 million AC sub & DC converter station From Snet-Kake costs in Harza study $18.200 million _ 4,320 $22.520 x 1.15 $25,698 x1.16 $30,041 x 1.14 (escalation to Jan 1990 $34.3 Handy-Whitman station equipment 280/263 = 1.0646, Bu Rec 177/169 = 1.047, 1/2 yr escalation = 1.0237) = 1.14 Total Intertie cost $16.2 million + $34.3 million = $50.5 million A-11 NEMORANDUMSA CHEMHILL TOs File FROM: Bob Schneider/SEA DATE: April 10, 1990 SUBJECT: Diesel Fuel Resource Costs PROJECT: ANC 28289.A0 This documents costs for diesel generators and diesel combustion turbines. I. Diesel Engines Capacity Engine Bldg. , Acces Totals $/Kw (MW) Cost connection Overhead ($) including to utility & freight system & Contingency $ T&c EMD 20-645F 2.85 900,000 600,000 260,000 1,760,000 618 Used EMD 20-645E 2.85 650,000 420,000 180,000 1,250,000 439 Cat 34612 3.00 1,150,000 630,000 280,000 2,060,000 687 New and used EMD price information from Stewart & Stevenson. Price for Cat 3612 from NC Machine. Other cost data from 6/83 Standby Generation Alternatives study for AELP. Data escalated to January 1990 values. om Combustion Turbines Capacity Engine Cost Balance of Plant Totals $/Ku (MW) $ and contingency $ GE LM 2500 21.23 8B, 400,000 3,800,000 12,200,000 575 GE Frame 5 26.3 6,140,000 6,620,000 12,760,000 485 LM 2500 BOP estimate based on data in 6/83 Standby Generation Alternatives study for AELP and increased for water injection costs estimated by GE-PDX. GE Frame 5 BOP estimate based upon data in 10/8 GE proposal to GVEA. Turbine costs from 1988-89 Gas Turbine World Yearbook. Data escalated to January 1990 values. : A-13 C C SCHEDULE MPK~-1 GENERAL @ ELECTRIC INDUSTRIAL SALES DIVISION SENERAL ELECTRIC COMPANY « 517 WEST NORTHERN LIGHTS BOULEVARD * ANCHORAGE, ALASKA 99503 * (907) 276-7512 October 4, 1985 Mr. Michael P. Kelly Golden Valley Electric Association, Inc. P.O. Box 1249 Fairbanks, Alaska 99707 Subject: Gas Turbine "Turnkey" Prices Dear Mikes We are pleased to offer the following "turnkey" prices for our ‘family of gas turbines, based on the following assumptions: . Simple cycle Sea level operation 35 degrees F ambient temperature Natural gas fuel, water injection Step-up transformer Metal building with normal utilities 1985 prices Ratings Price per MW Frame 5 27.2" * $403 Frame 6 40 MN 325 Frame 7 84 MW. - : 238 The estimated lead time from order date to operation would be . 15-18 months on a normal basis. Since we advance order Frame 6 and 7 units, a shorter lead time would be possible depending on factory leading. We would be happy to discuss y your requirments for Power generation at your convenience, . Very y yours, “Sales Engineer @B/clp c: Mark Kalejs/Schenectady ‘ _ Al Query/Portland A-15 “Ovemight” Price Levels For Basic Powerplant Packages In today’s marketplace these are the nominal FOB prices (in June 1986 dollars) for a basic electric power generation package and/or plant including the gas turbine, alternator, skid, enclosure, inlet and outlet ducts and controls — without any consideration for escalation. We expect to see higher prices in the months ahead in the face of rapidly growing demand and tightening supply. Model ISQ Base "LHV Heat Rate Effic ~. Budget Price . Per kW Satu .....ceeeeseeseceeeeecs 1080kW 14785Bu. 231% $°°550000 $509 >> TB5000 .......cccccceeeeeeees 3810kW 13,310 Btu 256% $ 1,250000 $928 ;, LM500......0eeeeeeeeeee wees 3850KW 11,120 Btu 30.7% $1,500000 $390 7 Centaur-H ...csceeseeseersee SBBOKW = 12,200 Btu 28.0% $1,300,000 $335 2” SOIKBS ......ceeeeeeeeeeee ees J925 KW 11,305 Btu 30.2% $ 1,400,000 $357 >> eeeeeeees 4875 KW 11,530 Btu 29.6% = $ 1,900,000 $390 37 5910 kW 10,070 Btu 33.9% $ 2,100,000 $355 : 6185 kW 11,385 Btu 30.0% $ 2,000,000 $323 21- 8840 kW 10,980 Btu 31 1% $ 3,100,000 $351 2° 9980 kW 10,500 Btu 32.5% $ 3,700,000 $371 4 SK15.....cceeeeeeeeeeceeeees 12,550 kW 9920 Btu 34.4% — $ 5,000,000 $398 MFINIA ......ccceeeeeeeeeees 12,610 kW 11,250 Btu 30.2% $ 4,500,000 $357 1% SBEO ..... 2. eee eeeeeeeee eee 13,070 kW 11,125 Btu 30.7% — $ 4,600,000 $352 17 LM1600 . 13,400 kw 9620 Btu 35.5% $ 5,200,000 $388 MF111B 14,570 kW 11,020 Btu 31.0% $ 5,000,000 $343 ve Jup/GT35 16,900 kW 10,670 Btu 32.0% $ 6,400,000 $379 \o LM2500PE ........0eeeeeeeee 21 230 kw 9800 Btu "34.8% $ 7,800,000 $367 22,600 kW 10,095 Btu 33.8% $ 6,500,000 $288 - \Y FT8.....0. 25,420 kW 8950 Btu 38.1% $ 8,300,000 $327 RB211 ....eecececeececeerees 26,100 kW 9150 Btu 37.3% $ 8,800,000 $337 PGSSTIPA ......0cecceceeere 26,300 kw 11,820 Btu 28.9% $ 5,700,000 $217 \3 LM2500-STIG40"... 26,465 kW 8535 Btu 400% $7,900,000° $299" LM5000PC......... 33,060 kW 9730 Btu 35.1% $11,200,000 $339 _ PGES4IB.. eee eecese eee es 38,340 kW 10,860 Btu 31.4% $7,800,000 | $203 12 W251PG .......ecceeeeeeeees 42,500 kW 10,845 Btu 31.5% $ 9,300,000 $219 LM5000-STIG8O* +++ -46,890 kW 8175 Btu 41.7% $10,500,000" $224° Type 8 .....cceceeeeeeeee «e+ -48,800 kW 10,425 Btu 32.7% $11,700,000 $240 to IN FTB oo cece ceecceeeeceees 51,100 kW 8905 Btu 38.3% $14,900,000 $292 VE4.3 ..... cece eee eee eeeee = + -56,000 kW 10,250 Btu 33.3% $13,600,000 $243! PG7IT1EA... -- 83,500 kW 10,480 Btu 32.6% $15,500,000 $186 2 Type 11N.... --- -83,200 kW 10,335 Btu 33.0% $16,100,000 $194 3 Type 13 ..... + 100,500 kw 10,395 Btu 32.8% $17,500,000 $174 V84.2 2.6645 +» 103,000 kW 10,310 Btu 33.1% $18,400,000 $179 5 W501-D5.... «+» 104,400 kW 10,290 Btu 33.2% $19,800,000 gig0 $ PGOQIGIE.... seeeeeee 116,900 kW 10,310 Btu 33.1% $19,500,000 $167 7 MW701 ........ seeeeees 126,850 kW 10,130 Btu 33.7% $21,500,000 $1 69 | PG7I91F ....... 150,000 kW 9880 Btu 34.5% $25,100,000 $167 4 PGO2BIF .......secceeeeees 202,300 kW. 10,020 Btu 34.1% $31,100,000 $154 “Steam injected gas turbine (STIG) price does not Include cost of HRSG equipment and associated controls. - gcenario J, base Lase {no ining loads) Input Load Data Year {Federal FY) 19901991 1992 1973 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Hydro Generation (Hh) 380000 380000 — 380000 = 380000» 380000» 3R0000 © 380000 © 380000» 380000 += 380000 += 380000 +~—«-3H0000 ~—-380000 380000 = 380000 = 380000 Juneau Eeployaent 13100 13200 13300 13400 13500 13600 13700 13800 13900 14000 14100 14200 14300 14400 14500 14600 Res Custoners 9170 = 9240 9310 9380 9450 9520 9590 9660 9730 9800 9870 9940 10010 10080 Lots 40220 General Class 37313438 3547 3458. 3372 3288 3205 325 3047 2971 2897 2824 2754 2685 2818 2552 Hot Water 2298 = 2355 2414 2474 2536 2600 2665 2731 2800 2870 2941 3015 3090 3187 3247 3328 All Electric 30913197 3299 3397 3492 3583 3470 3754 3833 3910 39824051 416 4178 4236 4290 Combined Sales & Losses 27t 274.1 277 279.9 282.7 285,4 288.1 290.6 293.1 295.6 298 300.3 302.5 304.7 306.9 308.9 anservation rap = 20 784 enployeent = 13174 Conservation Prograe Data Existing SF Residential Air infiltration 120 120 at Sol 482 602 723 843 94 1,084 1,205 1,325 4,446 1,566 1,487 1,807 Ceiling 4 14 29 43 58 2 87 101 1th 130 144 159 173 188 202 27 Floor . 89 89 179 268 357 4h 536 625 m4 803 893 982 1,071 1,160 1,280 1,339 Heat puap retrofit 6 $ 12 19 25 u 7 44 50 36 62 48 75 Bt 87 %3 water heat 4" ait 81 122 162 203 243 284 324 365 405 aah 486 527 367 608 a. _teaperature setback 48 48 95 143 19t 238 286 334 JBL 429 47 524 372 619 467 115 Existing MF Residential Floor a] 49 98 148 197 246 295 “a4 394 443 492 ol 590 640 689 738 water heat : 3 3 & 9 12 - 15 18 2 24 27 30 3 3 40 43 4 Residential Lighting 307 ' «307 413 920 1,226 1,533 1,839 2,146 2,453 2,759 3,066 3,372 3,879 3,985 4,292 4,599 Existing Comercial Teap setback 109 109 218 327 435 545 654 763 872 981 1,090 1,199 1,308 1,416 1,525 1,634 Ceiling 4 14 28 43 3? 1 85 100 414 128 142 157 {71 185 199 214 Efficient lights 815 BAS 1,630 2,445 3,260 4,075 4,890 5,705 6,520 7,335 8,150 8,965 = 9,780 = 10,595 1,410 12,225 _ Street Lights 27 27 a4 80 107 14 161 (87 214 21 268 294 321 ua 375 401 » Total Congerva Hon for Existing Structures (MWh) 1,642 3,285 4,927 6,569 8,212 9,854 = 11,496 = 13,139 14,781 16,423 18,065 = 9,708 = 21,350 = 22,992 24,835 jen Single Fasily hu 9 Heat Pusp for FA 0 9,960 19,920 29,880 39,840 49,800 59,760 69,720 «79,680 = 89,640 99,600 109,560 109,560 109,560 109,560 109,580 I Air Infiltration 9 126 248 365 478 387 690 7 885 977 4,063 4,145 1,222 1,29 1,365 1,430 New Single & Multi Fanily . New tank, heat traps Q 347 695 1,044 1,395 1,748 2,100 2,952 2,809 3,167 3,522 3,884 4,245 4,609 4,980 5,349 Windows R2 to RB & O 16,848 33,696 44,928 = 56,160 67,392 78,624 = 89,856 101,088 112,320 123,552 134,784 146,016 157,248 162,864 148,480 Total Winter Conservation (MWh) 22 44 61 79 AT] 115 133 150 168 186 204 214 225 232 238 Total Syeaer Conservation (HHH) 9 18 25 2 3” 46 33 60 68 5 82 0 9% 9 Total Conservation (MWh) u 1 86 il 136 + 161 184 it 236 261 286 ., 300 M5 35 BS Total Conservation (MHh) u al 8 it 136 161 186 aut 236 261 286 300 v5 325 334 Cosbined Sales & losses (HWh) 274,100 277,000 279,900 = 282,700 285,400 288,100 290,600 293,100 295,600 298,000 300,300 302,500 304,700 305,900 308,900 Combined Sales & Losses less Conservation (MWh) 274,069 276,939 279,814 282,589 285,264 287,939 290,414 292,889 295,364 297,737 300,014 302,200 304,385 306,575 308,566 Scenario 1. Base Case {no sining loads) Input Load Data Year (Federal FY) Hydro Generation (M#h) Juneau Eep]oyaent Res Custorers General Class Hot Water All Electric Combined Sales & Losses Conservation rasp = ' 20 1984 esploysent = 13474 Conservation Progras Data Existing SF Residential fir infiltration Ceiling Floor Heat pusp retrofit water heat teaperature setback Existing HF Residential Floor water heat Residential Lighting Existing Comaercial Teap setback Ceiling Efficient lights Street Lights Total Conservation for Existing Structure New Single Fanily Heat Puap for FA Air Infiltration New Single & Multi Fasily New tank, heat traps Windows R2 to RB # Total Winter Conservation (H¥h) Total Susser Conservation (MWH) Total Conservation (Hih) Total Conservation (HWh) Coabined Sales & Josses (MWh) Conbined Sales & Losses less Conservation 310,557 A-18 2006 2007 380000 © 3R0000 14700-44800 1027010380 2488 2426 3H 3496 43at 4388 3.9 312.9 1,928 2,048 20 245 1,428 1,518 100 106 648 489 782 B10 787 834 49 52 4,905 «5,212 1,743 1,852 228 242 $3,040 13,854 428 455 26.277 27,919 109,540 109,540 149t 1.547 5.721 809% 174,096 179,712 245 252 98 101 343 353 343 353 310,900 312,900 312,547 2008 380000 14900 10430 2364 3584 4431 314.8 24169 260 1,607 112 729 858 866 55 5,518 1,96! 256 14,669 482 29,562 109,560 1,598 8,477 185,328 258 104 362 342 314,800 314,438 2009 380000 15000 10500 2306 3673 4470 31b.d 2,289 275 1,694 118 770 905 935 58 5,825 2,070 2 15,404 508 3,204 109,560 1684 8,856 190,944 265 106 Rar at 314,600 314,229 2010 380000 15100 10570 2249 3765 4506 318.4 2,410 289 1,785 124 B10 953 984 él 4,131 2,179 285 16,299 535 32,844 109,580 1\687 7,243 194,560 272 109 381 381 318,400 318,019 7 ‘ ‘ 6T-W Po Co Co oo eS oS i a Scenario 2. A. J. Mine (indirect and sine load) Input Load Data : Year (Federal FY) 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Juneau Eepl oyaent 13100 13500 13900 13900 14250 14600 14700 14800 14900 15000 15100 15200 15300 15400 15500 15800 Res Custosers 9170 9450 9730 9730 9975 10220 0290 10360 10430 10500 10570 10640 10710 10780 10850 109: General Class 37313638 3547 3458 3372 3288 3205 3125 3047 2971 2897 2824 2794 2685 2618 oe Hot Hater — 2298 2355 2444 2474 2536 2400 2665 2731 2800 2870 2941 * 3015 3090 3167 3247 3328 AU Electric 3091-3407 vy 747 4017 4283 4370 4454 4533 4610 4682 4751 4816 4878 4936 4990 Coabined Sales & Losses an 282 292.9 293.1 302.4 SL7 314.2 316.7 319.2 325 323.8 32.1 328.3 330.4 B24 334 . Ad. Mine load 234 24 234 234 234 24 234 234 234 234 Ba 24 234 Cosbined Sales & Losses & Mine load 282 292.9 527.1 536.4 545.7 548.2 550.7 553.2 555.5 557.8 560.1 562.3 564.4 566.4 = 568.4 Total Conservation for Existing Structures (Hh) 1,642 3,285 4,927 6,589 8,212 9,854 = 11,496 13,139 14,7BE 14,423 18,065 19,708 21,350 22,992 24,535 Total Conservation for New Structures (MWh) Heat usp for FA 90 179 189 269 uy 378 408 428 448 468 488 508 528 548 3568 Air Infiltration 2 4 4 6 8 a 8 8 8 8 a a 4 8 8 Hew Single & Multi Fasily New tank, heat traps 1 1 1 2 3 3 3 4 4 4 5 i 6 6 4 Windows A2 to RB * 45 Ti 95 135 174 185 197 208 219 230 at 253 264 210 255 Total Winter Conservation (H¥h) 1,269 2,539 3,722 4,980 6,238 7,439 8,641 9,835 11,029 12,223. 13,497 14,611 15,805 = 14,995 18,185 Total Suaaer Conservation (MWh) 510 1,020 1,495 2,008 2,506 2,989 3,472 3,951 4,431 aot 5,391 5,870 = 6,350 6,828 7,308 Total Conservation (MWh) 779 3,559 5,217 6,981 8,745 = 10,428 12,112 13,786 = 15,460 17,134 = 18,807 20,481 22,155 23,823 25,492 Corbined Sales & losses (M¥h) 282,000 292.900 527,100 536,400 545,700 548,200 550,700 553,200 555,500 957,800 560,100 562,300 564,400 564,400 588,400. Coabined Sales & Losses less Conservation (MWh) 289,341 521,883 529,419 536,955 537,772 538,588 539,414 540,040 540.666 541,293 541.819 542,245 942,577 542,908 Scenario 3. Multiple Mines (indirect and nine loads) Input Load Data . Year (Federal FY) 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Juneau Eaployrent 13100 13480 14260 14200 14709 15200 15300 15400 15500 15600 15700 15800 15900 16000 16100 16200 Res Custoners . “9170 9578 9982 9940 10299 10640 10710 10780 10850 10920 10990 11069 11130 11200 11270 11340 General Class ~~ 3731-3838 3547 3458 3372 3288 3205 w25 3047 2971 2897 2824 2754 2685 2618 2582 - Hot Water 2298 2355 2444 2474 2536 2600 2665 2731 2800 2870 2941 3015 3090 3167 3247 3328 All Electric JOM = 3533 37 3957 4332 4703 4790 4874 4953 3030 5102 Sw 5236 5298 5356 S410 Combined Sales & Losses 271 286.8 302.5 301 314.3 327.4 BO | 332.4 334.8 37. 394 M6 | M37 S458 M78 3497 Mine loads 304 304 304 304 304 304 308 304 yoy” 304 304 304 304 Combined Sales & Losses & Hine load 286.8 302.5 405 618.3 631.4 634 636.4 638.8 64t.1 643.4 645.6 647.7 649.8 651.8 653.7 Total Conservation for Existing Structures (Hh) 1,642 3.285 4,927 6,569 8,212 9,854 = 11,496 = 13,139 14,7BE 16,423 18,065 = 19,708 = 21,350 22,992 24,635 Total Conservation for New Structures (MWh) Heat usp for FA 129 259 259 369 478 508 538 558 578 598 618 637 657 677 697 fir Infiltration 2 4 4 & a 8 8 8 8 8 8 8 8 4a 8 Hew Single & Multi Faeily New tank, heat traps 1 2 2 2 3 4 4 4 3 5 5 6 6 6 7 Windows R2 to RB F 62 124 124 174 225 236 247 258 270 28t 292 303 M4 320 3b Total Winter Conservation (MWh) 1,310 2,620 3,292 5,079 6,367 7,568 8,769 9,963 L157 12,352 13,546 14,740 15,934 17,124 18,314 Total Suewer Conservation (MWh) 526 1,053 1,523 2,041 2,508 3,041 3,523 4,003 4,483 4,963 5,442 5,922 6,402 6,880 = 7,358 Total Conservation (MWh) 1,836 3,473 5,315 7,120 8,925 10,609 12,293 13,967 15,640 = 17,314 18,988 = 20,662 22,336 = 24,004 = 25,672 Combined Sales & losses (MWh) 286,800 302,500 405,000 618,300 631,400 634,000 634,400 638,800 641,100 643,400 645,600 447,700 649,800 651,800 453,700 Cosbined Sales & Losses less Conservation (MWh) 298,827 599,685 611,180 622,475 623,391 624,107 624,833 625,460 626,086 9 624,612 627,038 627,464 627,796 628,028 Scenario 2. A. J. Mine lindirect and eine load) Input Load Data Year (Federal FY) 2004 2007 =. =. 2008 2009 2010 my Juneau Expl oyaent 15700 15800 «18900 16000 16100 7 Res Custoaers 10990 11060 41130 11200 “4 General Class 2488 2426 “2366 2308 ho: Hot Hater Malt 3496 3584 3673 ly All Electric 5041 5088 sil 5170 S204 : Combined Sales & Losses 334.4 338.2. M401 341.8 33.4 1 ! fad. Mine load 234 234 24 244 234 -| Coabined Sales & Losses & Mine load 570.4 572.2 744 575.8 577.6 Total Conservation for Existing Structure 26,277 27,919 = 29,542 31,204 32,846 Total Conservation for New Structures (MW Heat Puge for FA 588 598 408 618 27 Air Infiltration 8 8 8 a 8 _ New Single & Multi Family it Hen tank, heat traps 7 7 7 8 8 a Windows R2 to RB t 281 284 292 298 303 Total Winter Conservation (MWh) 19,375 © 20,558 = 21,741 = 22,924 = 24,107 a Total Suaser Conservation (NWh) 7,785 8,260 8,735 9,240 9,484 : Total Conservation (MWh) 27,160 = 28,818 930,476 «= 32,135 33,793 Cosbined Sales & losses (HHh) 570,400 572,200 574,100 575,800 577,400 j ) Combined Sales & Losses less Conservation 543,240 543,382 543,424 543,465 543,807 Scenario 3. Multiple Mines (indirect and sine lo a Input Load Data . na! Year (Federal FY) 2006 2007 2008 2009 2010 ; Juneau Eaployaent 14300 16400 16500 16400 16700 { | i \ Res Custoners 11410 11480 4455 11620 411690 . General Class 2488 2426 2366 2306 2249 ry Hot Water 34ii 3496 3564 3473 3765 : All Electric S4at 5008 Sav 5590 5626 Combined Sales & Losses 351.6 353.5 355.2 357 358.4 _ Hine loads 304 304 304 304 304 i! Combined Sales & Losses & Mine load 655.4 657.5 659.2 bol 662.5 _ Total Conservation for Existing Structure 24,277 27,919 29,562 31,204 32,84 > Total Conservation for Hew Structures (NW 14 Heat Pune for FA Ti7 727 737 747 757 it Air Infiltration 8 a a 8 8 - New Single & Multi Fasily New tank, heat traps 7 8 a § 9 Fy Windows R2 to RB # 33L 37 343 348 354 1 | Total Winter Conservation (MWh) 49,504 20,687 21,870 = 23,053 = 24,2346 : Total Susser Conservation (Hlh) 7,834 8,312 4,787 9,262 9,738 = iy Total Conservation (M#h) 27,340 = 28,999 30,657) 32,315 33,973 i Cosbined Sales & losses (MWh) $55,600 457,500 457,209 661,000 462,400 Combined Sales & Losses less Conservation 628,260 628,001 628,543 628,685 628,427 i] A-20 oa. New Single-Fanily Heat puap in place of FA Reduce infiltration plus heat exchanger Windows R2 to RB Existing single-fasily Space heat Heat puap retrofit in place of FA Teaperature Setback Reduced Infiltration «9 to «4 ac/hr (Cd=0.65) +6 to 4 ac/hr (Cd=0.65) Floor Insulation R6 to R30 (Cd=1.0) R2 to R30 (Cd=1.0) Ceiling Insulation R19 to R38 (Cd=0.65) Existing Multi-Fasily Space heat Ceiling RO to R38 Floor R2 to R30 (Cd=1.0) General Residential Water heat - new housing : New tank with iaproved Asiagle fanily insulation & heat traps }ault family Water heat - existing housing )single fasily Tank wrap and heat trapsieult fasily Lighting Porch Internal OFFICE Teaperature setback Ceiling insulation Efficient lights RETRIL Terperature setback Ceiling insulation Efficient lights OTHER Teaperature setback A jen. inflation rate = Ist half 1985 Anchorage Alaska CPI = 1 Estimate of Ist half 1990 Anchorage CPI = C Celiling insulation Efficient lights Street Lights (on a per bulb basis) ssuaptions ige value of money = st half 1989 Anchorage Alaska CPI = ‘oluan Electricity Savings Per Square Foot c kWh per year Susser Winter 2.04 0.05 1.15 2.04 0.89 6.26 1,54 3.53 6.26 2.72 kWh Savings per hose 4,819 annual 1,928 annual 2,424 annual 3,698 annual 1,204 annual 10 3.42 3.36 annual (all general residential on a 303.5 424.5 150 209.5 242.5 339.5 116.5 163 500 annual 250 annual 1.63 4.98 0.38 1.16 1.60 2.24 0.89 2.72 0.45 1,36 1.66 2.33 1.23 3.76 0.43 1.33 1.63 2.29 70.00 215.00 Econoaic Life (years) 20 0 30 20 15 30 30 30 30 30 30 30 12 12 10 10 3 3 45 30 3 15 30 3 45 30 3 20 CONSERVATION LIFECYCLE LEVELIZED COSTS E Capital Cost Per Square Foot ($ 1990) 0.72 1.47 0.86 3.77 0.05 954.90 965.02 840.00 840.00 351.00 0.52 0.64 per ites basis) 115.80 94.85 35.29 35.29 35.00 18.00 0.09 0.40 0.13 0.09 0.40 0.13 0.09 0.40 0.13 187.49 F 1990 First Year Cost (expensed) cents/kWh 8.64 92.25 18.38 45.44 1.39 19.82 50.05 34.65 22.71 29.15 11.45 19.18 15.91 26.38 6.06 12.63 7.00 7.20 1.33 25.78 3.45 2.44 21.94 3.32 1.77 22.56 3.38 65.79 Lifecycle Levelized Costs (1990$) cents/kWh 0.58 4.71 0.94 3.05 0.12 1.01 2.55 1.77 1.16 1.49 0.58 0.98 cee ee ene ee errecrer -sppren BSGGISSs-arta-as B, C, D sources: Either Tables 111-1 to I11-6, pages III- 5 to I1I-14 of Volume 2 of April 1987 Energy Conservation and Managesent Plan and inforaation calculated with sponsors eerie ancy fact-finding aeeting on conservation. E aon source: Either Tables [11-1 to I1I-6 of April 19 the ratio of the 1989 CPI to the 1985 CPI tises the or based upon 1990 costs estimates during a fact-fin coluan E divided by the sus of coluans B and C Energy Conservation and Management Plan tises greece inflation rate for one year jing meeting with the sponsors coluan E times annual capital recovery factor for years in colun D and tine value of soney divided by sue of coluans B source: Either Table S-2 page xi of volume | of the April 1987 Energy Conservation and Nanagesent Plan or and C for new items calculated at the fact-finding meeting with the sponsors the coluan E divided by the eneray paris in coluans B and C ties an assumed cost of 7 cents per kilowatt hour. source: aarket pene ration data froa Yol 1 page 83 when combined with coluen I. H Custoner Payback (years) 4 8.8 2.38 5.6 0.2 2.57 6.48 4.95 3.24 4.16 1.48 2.74 2.0-3.4 1.0-1.6 as i ase tom «eR Seo it es es eeresvssss ACNE RUE I Market penetration 0.6 0,05 0.5 0.05 0.8 a 0. 0 a ee 2 22 Bm B® ER eeessssessescss= toto ia iwio wm wis owe ce-W AMALYSIS OF LAKE DOROTHY -~ A. J. MINE FORECAST Annual Cost (millions) i : Average caleeeiaeeneimaninies Bus Bar Amortized Energy Cost Capital Fixed * Total Froduction (cents Year Cost * Casts Cost . CMWH) per kWh) 1996 10.7 Ond 1i.d Bao 1997 10.7 0.4 11.1 B.9 1998 10.7 0.4 11.2 8.9 1999 10.7 0.5 11.2 B.9 2000 10.7 0.5 11.2 8.9 2001 10.7 0.5 11.2 8.9 2002 10.7 0.5 11.35 9.0 2003 . 10.7 0.5 11.35 25,592 9.0 2004 10.7 0.6 11.3 25,588 9.0 2005 10.7 0.6 11.3 25.5685 9.0 2006 10.7 0.6 11.4 9.0 2007 10.7 0.6 “L1.4 Pol 2008 10.7 0.7 11.4 9.1 .2009 10.7 0.7 11.4 Pal 2010 10.7 0.7 11.5 Pal Calculated as follows, assuming 4.5°% annual inflation: Millions of Dollars Construction Cost Interest During Construction Subtotal Financing Costs ’ Bond Discounts (2%) Reserves (15 moriths DS) Total Issue 136.4 Annual Debt Service 11.7 Less Interest on, Reserves 1.0 Annual Fayment 10.7 ‘ i C MEMORANDUM CHMTIL . TO: BOB SCHNEIDER FROM: LEE DE HEER DATE: June 11, 1990 PROJECT: JUNEAU POWER SUPPLY PLAN UPDATE Following is a summary of the cost estimate assumptions for the Juneau Power Supply Plan hydropower alternatives: All of the projects reviewed were identified in previous reports except the Lake Dorothy - Long Lake tunnel. Cost estimates for all of the previously identified projects were reviewed and revised where it appeared to be appropriate. Since many of the projects include a tunnel as a major part of the project, a review was made of recent tunnel costs in Alaska and a tunnel project in Utah to arrive at a tunnel unit cost. The bid prices for the following projects were reviewed: 1. Bradley Lake 2. Crater Lake Addition 3. Anchorage - soft ground tunnel 4. Utah - Olmstead tunnel The bid prices of the above listed projects were reviewed to identify the cost of driving the tunnel only, excluding the costs for mobilization, access, and construction camps. The average cost for the tunnels was $900 a foot for hard rock a $1,200 for the soft ground. A unit price of $900 a foot was used for all tunnels reviewed for this study, since the rock conditions are believed to be similar at the all of the locations. However, except for the Lake Dorothy Project, the evaluation of rock conditions is based on a general review of the geology of the sites and not upon subsurface boring information. Therefore, the actual costs may vary from those used in this study. The objective of this study was to make a consistent comparison of the cost of the projects based on the available information. The costs for mobilization, access, and construction camps are site specific and will vary depending upon site conditions and project duration. The costs for these items was based upon the costs for other similar projects and varied from eight to ten percent of the total construction cost. A-23 MEMORANDUM Page 2 June _ 11, 1990 JUNEAU POWER SUPPLY PLAN UPDATE Lake Dorothy. Major quantities FERC ACCOUNT 331 Powerhouse 332 Lake Tap Intake Gates & Equip. Unlined Tunnel Lined Tunnel Steel Liner Shaft 333 Turbine Generator Installation Contingency 334 Electrical 335 . Plant Equipment 336 Roads 352 Substation 355 Switchyard 358 Submarine Cable 63/69 Labor Camp Indirect Costs Quantity L.S ry a o ree A-24 Unit Price $ 610,000 1,135,000 1,552,000 900 3,000 3,200 1,500 Subtotal $3,870,000 * 800,000 330,000 Subtotal $1,952,000 $ 976,000 $2,462,000 $5,152,000 $ 697,000 $1,342,000 $8,037,000 SUBTOTAL © CONTINGENCY ENG & ADMIN TOTAL Total $7,342,000 610,000 1,135,000 1,552,000 10,008,000 7,200,000 1,536,000 2,160,000 $23,813,000 $ 3,870,000 800,000 330,000 $ 5,000,000 $ 1,952,000 $ 976,000 $2,462,000 $5,152,000 $ 697,000 $6,041,000 $8,037,000 $61,472,000 9,221,000 12,018,000 $82,711,000 The project reviewed is the one described in the 1984 20 year Power Supply Plan and shown on Figure 1. 3 ~=3 2 (~ cm MEMORANDUM Page 3 June_11,_ 1990 JUNEAU POWER SUPPLY PLAN UPDATE Lake Dorothy/Long Lake Tunnel. This project is a new concept that we evaluated during our initial site investigations in the Juneau area. In evaluating staged construction alternatives at Lake Dorothy, we found this to be an alternative that could be implemented earlier than the full Lake Dorothy Project. The alignment of the tunnel is found in Figure 2. Following is our cost estimate: Description Quantity Unit Price Total Tunnel 15,800 ft. $900/ft 14,220,000 lined 3,600 ft. $2,100/ft 7,560,000 steel liner L.S. $1,500,000 1,500,000 shaft 800 ft. _ $1,500/ft 1,200,000 tap L.S. , $500,000 500,000 intake, gate, equip.L.s. $2,000,000 2,000,000 Subtotal 26,980,000 Access/Camp ‘2,000,000 2,000,000 Mobilization 1,000,000 1,000,000 nn ee Subtotal 29,980,000 contingency @ 15% 4,500,000 Subtotal 34,480,000 eng. & admin. @ 17% 5,860,000 Total 40,340,000 A-25 MEMORANDUM Page 4 June_11, 1990 JUNEAU POWER SUPPLY PLAN UPDATE Long Lake Elevation *:: =: 845 (dam addition 21 feet), Long Lake’. - Elevation &70 (dam addition 46 feet), Long Lake Elevation : .-.; -.'* 895 (dam addition 71 feet). These conceptual designs were based upon the 1986 U. S. Army Corps of Engineers Snettisham Letter Report Number 1 which studied three concrete Gravity dam additions and one steel buttress alternative. We evaluated the most economical alternatives; the steel buttress dam for the dam to elevation 845, and the concrete dams for the two higher dams. The alternatives are shown on figures 3,4, and 5. Long Lake Elevation 845 steel buttress dam Corps Construction Estimate $11,500,000 conversion factor to 1990 costs x 1.06 Construction Cost $12,200,000 Engineering & Admin. @ 17% . 2,100,000 Total $14,300,000 Long Lake Elevation 870 concrete gravity dam addition Corps Construction Estimate $29,925,000 conversion factor to 1990 costs x 1.06 Construction Cost $31,700,000 Engineering & Admin. @ 17% 5,400,000 Total $37,100,000 Long Lake Elevation 895 concrete gravity dam addition Corps Construction Estimate $43,365,000 . conversion factor to 1990 costs x 1.06 Construction Cost $45,900,000 Engineering & Admin. @ 17% : , 7,800,000 : Total $53,700,000 A-26 ced 3 __) os a) MEMORANDUM Page 5 June_11, 1990 JUNEAU POWER SUPPLY PLAN UPDATE Crater Lake Elevation 1034 (dam addition 13 feet), and Crater Lake Elevation 1047 (dam addition 25 feet). The conceptual design of these projects was based upon the U. S. Army Corps of Engineers Snettisham Design Memorandum Number 23. Crater Lake alternatives are shown on figures 6 and 7. Crater Lake Elevation 1034 (dam addition 13 feet) Discription Quantity Unit Price Concrete 5,300 C.Y. $300/C.¥. Excavation : 1,200 C.Y. $50/C.Y. Access LS. $100,000 Mobilization/Demob. L.S. $100,000 Diversion L.S. $50,000 Misc. L.S. $100,000 Subtotal contingency @ 15% Subtotal eng. & admin. @ 17% , Total Crater Lake Elevation 1047 (dam addition 25 feet) Description Quantity Unit Price Concrete 12,000 C.Y. $300/C.Y. Excavation 3,000 C.Y. $50/C.Y. Acess L.S. $100,000 Modify Intake L.Ss. $250,000 Mobilization/Demob. L.S. $250,000 Diversion L.S. $100,000 Misc. L.S. $200,000 Subtotal contingency @ 15% Subtotal eng. & admin. @ 17% Total A-27 Total 1,590,000 60,000 100,000 100,000 50,000 100,000 $2,000,000 300,000 $2,300,000 391,000 $2,691,000 Total 3,600,000 150,000 100,000 250,000 250,000 100,000 200,000 $4,650,000 698,000 $5,348,000 909,000 $6,257,000 MEMORANDUM Page 6 June 11, 1990 JUNEAU POWER SUPPLY PLAN UPDATE Carlson Annex Creek No. 1 project. See figures 8 and 9. This was based upon the initial work of Ben Hildyard and review with Mr. Hildyard. The dam is project is principally a diversion project. FERC Account No. 331 Structures Above Ground Powerhouse $6,000,000 FERC Account No. 332 Reservoirs, dams R.C.c. dam to elevation 900 (100 ft high) Concrete 150,000 C.Y. $40/C.Y. $6,000,000 Foundation L.s. $1,000,000 $1,000,000 Gates, Valves L.s. $800,000 $800,000 Spillway, diversion L.s. $500,000 $500,000 Misc. L.S. $700,000 $700,000 Tunnel 13,200 ft. $900/ft 11,900,000 lining 1000 ft. $3,000/ft 3,000,000 Portals, misc. $500,000 500,000 Penstock removal L.S. $500,000 500,000 Penstock new 7,100 ft $310/ft 2,200,000 Subtotal $27,100,000 FERC Account No. 333 Turbine Generator L.S. $5,330,000 $5,330,000 Installation L.S $800,000 $800,000 Shipping & Contingency L.S. $370,000 $370,000 Subtotal $6,500,000 FERC Account No. 334 $1,952,000 Accessory Electrical FERC Account No. 335 $ 976,000 Plant Equipment FERC Account No. 336 $1,500,000 Roads, Port Facilities FERC Account No. 352 $5,152,000 Substation FERC Account NO. 355 $ 700,000 Switchyard A-28 co MEMORANDUM Page 7 June_11,_1990 JUNEAU POWER SUPPLY PLAN UPDATE FERC Account No. 63/69 $8,000,000 Labor Camp, Indirect Costs FERC Account No. 358° Transmission Line 10.3 mi. $750,000/mi. $7,800,000 Total all FERC Accounts $65,680,000 contingency @ 25% 16,420,000 Subtotal $82,100,000 eng. & admin. @ 17% 14,000,000 Total $96,100,000 A-29 MEMORANDUM Page 8 June _11, 1990 JUNEAU POWER SUPPLY PLAN UPDATE Mr. Carlson Annex Creek No. 2 project. See figures 8 and 9. This was based upon the initial work of Ben Hildyard and review with project is similar to the diversion Hildyard. The dam project but has a 400 foot high Roller Concrete Compacted dam. FERC Account No. 331 Structures Above Ground Powerhouse $6,000,000 FERC Account No. 332 Reservoirs, dams R.C.C. dam to elevation 1200 (400 ft high) Concrete 3,200,000 C.Y. $30/C.Y. $96,000,000 Foundation L.S. $6,000,000 $6,000,000 Gates, Valves L.Ss. $800,000 $800,000 Spillway, diversion L.S. $500,000 $500,000 Misc. L.S. $700,000 $700,000 Tunnel 13,200 ft. $900/ft 11,900,000 lining 1000 ft. $3,000/ft 3,000,000 Portals, misc. $500,000 500,000 Penstock removal L.S. $500,000 500,000 Penstock new 7,100 ft $310/ft 2,200,000 Subtotal $122,100,000 FERC Account No. 333 Turbine Generator L.S. $5,330,000 _ $5,330,000 Installation L.s $800,000 $800,000 Shipping & Contingency L.S. $370,000 $370,000 Subtotal $6,500,000 FERC Account No. 334 $1,952,000 Accessory Electrical FERC Account No. 335 $ 976,000 Plant Equipment FERC Account No. 336 $1,500,000 Roads, Port Equipment FERC Account No. 352 $5,152,000 Substation FERC Account No. 355 $ 697,000. Switchyard A-30 ~~ MEMORANDUM Page 9 June 1990 JUNEAU POWER SUPPLY PLAN UPDATE FERC Account No. 63/69 Labor Camp, Indirect Costs FERC Account No. 358 Transmission Line 10.3 mi. $750,000/mi. Total all FERC Accounts contingency @ 25% Subtotal eng. and admin. @ 17% Total A-31 $15,000,000 $7,800,000 $167,677,000 41,919,000 $209,596, 000 35,631,000 $245,227,000 4 . Gole shoft_ Power tunnel "oe CN Diowuntinea) EN I 138/12. 5- kv . wo substation © 4s fo Ligus . . i > Lak 3f5eu Upceate SS submarine trai +, Topogrophy is based on- -USGS I : 63,360 scale mapping FIGURE 1 LAKE DOROTHY PLAN FROM 1984 JUNEAU 20 YEAR POWER SUPPLY PLAN SCALE: T = 1 MILE FIGURE 2 LAKE DOROTHY - LONG LAKE TUNNEL pe-W vd af , Yes | CREST ELEY “Veneer evev ods Ss LONG LAKE DAM" » \\] ALTERNATIVES ~ PLAN 7] FROM CORPS OF ENGINEERS “ LETTER REPORT NO. 1 SNETTISHAM HYDROELECTRIC JANUARY 1987 SECTION @ TRANG EL * S74 10-33 {c) Se-w a SECTION @ STA 2-56 prese @ sarees Lace o rerees ME sore COMcmaTe Dube ea ny PO Bren Local, wema we 1a mss. a-cn es Extaerans Counrteras one US OF Ptreces acy roe escn aearen, FIGURE 4 LONG LAKE DAM ALTERNATIVES, TIMBER CRIB - DAM SECTIONS FROM CORPS OF ENGINEERS LETTER REPORT NO. 1 SNETTISHAM HYDROELECTRIC JANUARY 1987 9E-W ME ATED roe recmretse Beara toe oP oe Tit noe ne hae At tee 51057 ROE BAS nam gt i eer qo oo NON-WERFLOW SECTION! 5 SPLLWIAY SECTION STE. 15 +6! FIGURE 5 LONG LAKE DAM ALTERNATIVES CONCRETE DAM SECTIONS FROM CORPS OF ENGINEERS LETTER REPORT NO. 1 SNETTISHAM HYDROELECTRIC JANUARY 1987 Le-Ww ELEV 1045" ELEV 1028' ELEV 1022" PRESENT LAKE LEVEL ELEV 1003" SPILLWAY SECTION SPILLWAY CREST ELEV 1034 ‘CONSTRUCTION JOINT CRATER LAKE DAM ALTERNATIVE DAM CREST ELEVATION 1034 FROM CORPS OF ENGINEERS DESIGN MEMORANDUM NO. 23 8e-v ELEV 1057 ELEV 1041" PRESENT LAKE LEVEL ELEV 995° SPILLWAY CREST ELEV. 1047" ELEV 1022'y ‘CONSTRUCTION JOINT SPILLWAY CREST ELEV-1047" 1 20 ELEV 1022' SPILLWAY SECTION FIGURE 7 CRATER LAKE DAM ALTERNATIVE DAM CREST ELEVATION 1047 FROM CORPS OF ENGINEERS DESIGN MEMORANDUM NO, 23 6€-W FIGURE 8 ANNEX — CARLSON CREEK ALTERNATIVES PLAN Or-W 200° ALTERNATIVE 2 > ELEV 1220 ELEV 1200 ELEV 1200 ELEV 1220 ELEVATION (FEET) I | | ALTERNATIVE 2 ALTERNATIVE 1 4 as 00 "sae obo tao tba STATIONING (FEET) SECTION A~A ELEVATION FIGURE 9 CARLSON CREEK DAM Wii Fa Voith Hydro, Ine. Ess Bertin Read November 8, 1989 : pos Sennen 17404 . Teex £734013 Teleisx 717) 792-3882 CH2M HII Sea 1600 114th Ave S. E, PO. Bex 712, York, PA 17405 Bellevue, WA 98004 ATTN: Lee Deheer Subject: Lake Dorothy and Annex Creek Voith Ing. Number 6-30880 & 6-30881 Dear Mr. Deheer: The purpose of this letter is to provide you with preliminary prices for those machines detailed in my letter to you of 11/2/89. Preliminary price for the Annex Creek units is $5,328,185 and includes two (2) 1.12 m vertical Francis turbines with governcrs, two (2) 16,000 kw generators, two (2) spherical valves, controls and switchgear. Preliminary price for the Lake Dorothy units is $3,870,000 and includes two (2) 1.14 m impulse turbines with governors. one (1) 20,000 kw generator with dual input, two (2) spherical valves, controls and switchgear. Please note that the estimating prices quoted above are preliminary, based upon today's costs (excluding sales tax), and are subject to adjustment up and down, depending on tke scope, availability of materials and manufacturing capacity and terms and conditions of the final inquiry. Again, thank you for considering Voith and feel free to contact me with any questions. _ -—,, 7 Sincerely, a2) 7194 Ww LE; S Apr G03 22> 7 . / 5 Ti fas 7)" Robert A. Rittase Lis Io 709 Project Manager cc. R. Hunt . ” C. Alarie i R. Kunzelman : nie. A Memo ne. 1TH Group A-41 lef Gi the woridwide VO! § soa Ul APPENDIX B COMPUTER MODEL ANALYSIS cp-a Run Date: 09-Mar-90 Run Ties = 11:31 AN Uhgeneeaceeeacsccacsescescececeecags @ POWRPLAN (c) 1990 by CH2M HILL & Seheeeeeesagegseeceseseasessessesets Winter (October - April Ba Energy Requirements (MWh) Energy Dispatch (MHh) a) AELP Hydro: . Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake {3} Dorothy/Long Lake Tunnel (4) Crater Lake Elev. 1034 - (5) Long Lake Elev. 845 (6) Caterpillar 3612 diesel {7} GH EMD diesel (8) Existing Diesel: Gas Turbines Leson Creek Auke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Nine 2008 2009 2010 201 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2: Se fezensss = sBeez 338,085 337,953 337,885 337,885 337,885 337,885 337,885 337,885 337,685 337,885 337,885 337,885 337,885 337,885 337,885 337,885 337,885 337,885 7,943 7,943 7,943 7,943 7,943 7,943 7,943 7,943 «7,983 7,943 7,943 7,943 7,943—7,943 7,943 7,943 7,943 7,988 11,786 11,785 11,78 11,786 11,786 11,786 11,786 11,786 11,788 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 14,784 4,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,922 1,912 1,912 1,912 1,912 1,912 212,727 212,727 212,727 212,727 212727 212,727 212,727 202,727 212,727 212727 212,727 212,727 212,727 2124727 212,727 242,727 212,727 242,727 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 1,831 1,831 1,831 1,832 1,631 1,831 1,831 1,831 1,831 1,831 1,83t 2,831 1,831 1,831 1,831,831 1,831 1,831 8,209 8,209 8,207 8,209 8209-8, 207,207 «8,209 «8,207 8,207 8,209 «8,207 8,209 8,209 «8,209 8,209 «8,209 «8,209 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 66,926 66,870 65,878 86,876 66,875 68,876 66,876 66,876 © 6b,87h 6b, B76 66,875 4b, 876 66,875 4,875 4,876 64,876 66,875 66,878 coco ecco ecco ecco ecco coco cooo ecco ecco coco cooo eccooo ecoce coco coco eoco cccoo cocoo 338,368 338,312 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 5.5 3.5 3.5 3.5 5.5 3 3 31 3 31 31 31 31 31 31 3 3a 0.0 0.6 0.6 0.6 0.6 9.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9. 0.9 1.0 1.0 11 Ld 1.2 7.0 WA 7A 7.2 7.2 7.3 1.3 74 14 1.5 15 7.6 1d 1.7 7.8 LY 19 8.0 10.6 AL 1.6 12.1 12.7 13.2 13.8 14.5 15.1 15.8 16.5 17.2 18.0 18.8 19.7 20.6 AS 225 3e3 sasesess 23.7 24.3 249 25.5 26.4 24.3 25.0 25.7 26.4 27.2 28.0 28.8 29.7 30.6’ 31.6 32.6 33.6 a7 Tr-d Run Date: 09-Mar-90 Run Tine: = As31 AN Seaeargcasssscecsceseccsessegessees # POWRPLAN (c} 1990 by CH2M HILL 8 Sergcgnsascesgesceceseseseseseccsses Winter (October - April) Energy Requireaents (MWh) Energy Dispatch (Mh) w AELP Hydro: Annex Creek Saleon Creek Bold Creek (2) Snettishan/Crater Lake (3) Dorothy/Long Lake Tunnel (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 645 (8) Caterpillar 3612 diesel ie) 6M EMD diesel {8) Existing Diesel: Gas Turbines Lemon Creek fuke Bay Gold Creek TOTAL Cost (€ Millions) Capital Fixed Variable Fuel TOTAL 1990 1991 1992 179,219 185,391 191,624 7,983 7,943 7,943 11,788 11,788 11,786 1,912 1,912 1,912 1993 327, 011 1998 1995 SUNEAU 20-YEAR POWER SUPPLY PLAN Caser Forecast: 1996 Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 AJ Mine 1997 1998 331,507 336,007 336,355. 336,99 337,054 156,469 162,679 168,951 212,727 212,727 e2eooce eooce 0 0 0 0 0 0 0 0 ecco oocoo 7,983 7,943 11,786 11,786 1,912 1,912 0 0 1,831 1,831 8,207 8,209 0 0 80,558 83,683 1,227 2,660 0 6 0 0 0 0 = - 178,111 184,321 190,593 326,190 330,751 7,983 11,788 1,912 212,727 27,033 1,831 8,209 0 63,874 ecco 335,316 7,943 11,786 1,912 212,727 27,033 1,83! 8,209 0 64,297 coco 335,739 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 64,716 336,158 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 65,146 eooo 336,588 1999 2000 2001 2002 2003 2004 2005 2006 2007 SSrrssez canesece 337,281 337,512 337,743 337,911 338,014 338,062 338,110 338,158 338,092 7,943 7,943 11,786 11,786 1,912 1,912 212,727 212,727 27,033 27,033 1,631 1,831 8,209 8,209 0 0 65,448 65,753 0 0 0 0 0 0 0 0 336,890 337,195 550 55 Of 08 6.8 6B bt 65 19.2 7,943 11,786 1,912 212,727 27,033 1,831 8,209 . 0 66,059 e@ooo 337,50! 5.5 0.4 6.8 7.0 19,7 7,983 7,983 11,786 11,786 4,912 1,912 212,727 212,727 27,033 27,033 1,831 1,831 8,209 8,209 0 0 66,302 6,480 0 0 0 0 0 0 0 0 337,744 337,922 5.5 0.4 6.9 8.0 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 66,603 coco 330,085 7,943 7,983 7,983 11,786 11,785 11,788 1,912 4,912 1,912 212,727 212,727 212,727 27,033 27,033 27,033 1,831 1,831 1,831 8,209 8,207 8,209 0 0 0 86,727 6b,B50 66,858 0 0 0 0 0 0 0 0 0 0 0 0 338,169 338,292 338,300 5.50 585 0.5 (05 1070 9.5 10.0 O7-a Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN ~ Run Ties = 11134 AN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: A Mine Uneeeacesacacacaasssscscesesesssess t POWRPLAN {c) 1990 by CH2M HILL & 2008 2009 2010 201 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Mnsgaagasceccsnsecescocceasecsscaaes REantass angesses assesses S25: 2a ReReetes esenesce Suanary of Results (after conservation} Peak Demand (MW) . Peak Deaand 92.5 92.6 «92,792,727 9267926929292 92 T92T9TOLTLT9AT9DT Peak Plus Reserve Requireaent 166.7 166.8 = 166.9 = 166.9 = 166.9 166.9 = 166.9) :166.7 = 166.9 = 166.9) 166.9 185.9) 166.9 = 166.9) 166.9) = 186.9 = 168.9 188,09 Installed Capacity 172.200 172.2) 872.2) 172.2, 92.2 172,.2 1726217262, 724217202 172,2 872.2 972,62 172.2 172,2 172.2172. 172.2 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requirements (MWh) 950,825 590,865 551,007 551,007 551,007 351,007 551,007 551,007 551,007 $51,007 551,007 551,007 551,007 551,007 551,007 551,007 $51,007 351,007 Fire Capability of Installed Units (MWa) 128.2 128.2 12B.2 128.2) 128.2 128.2) 228.2 228.2 128.2 128.2 128.2 128.2 128.2 128.2 128.2 128.2 12862 128.2 New Capacity to Meet Energy Req'ts (Mi) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -~ 1) AELP Hydro: Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,040 35,080 35,040 35,040 35,080 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,080 35,040 35,080 35,080 35,040 Gold Creek 5,400 5,800 © 5,400» 5,400 «= 5,400 = 5,400» 5,400» 5,400 5,800» 5,400 5,400 5,800» 5,400 5,400» 5,800 5,800 5,400 5,400 (2) Snettishae/Crater Lake 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 (3) Dorothy/Long Lake Tunnel 42,042 42,042 42,042 42,042 42,082 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 it} Crater Lake Elev. 1034 2,848 2,848 2,048 2,048 2,848 2,888 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 {5) Long Lake Elev. 845 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 = 12,766 12,76 12,786 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 9 0 0 0 0 0 9 0 0 0 7) 6M EMD diesel 98,373 96,414 98,556 98,556 98,555 98,556 98,556 98,556 98,556 98,556 98,556 98,556 98,556 98,556 98,556 98,556 78,556 98,556 (8) Existing Diesel: Gas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Leson Creek 0 0 0 0 0 0 0 0 oO” 0 0 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 9 Gold Creek 0 0 a 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 seescess sessezss cestse=2 se a TOTAL 550,825 $50,865 $51,007 551,007 $51,007 551,007 551,007 951,007 951,007 551,007 551,007 951,007 551,007 551,007 551,007 551,007 551,007 551,007 Unserved Energy 0 0 0 0 0 0 0 0 0 oO 0 Qo 0 0” O-° 0 0 0 Cost ($ Millions) Capital 9.5 a3 aS %5 9.5 3.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 3.3 0.0 Fixed 1.0 1.0 1.0 1a it 1.2 1.2 1.3 14 14 15 1.6 1.6 L7 1.8 1.8 1g 20 Variable 10.9 10.9 11.0 MM Wal 11,2 M3 Wd 4 11.5 1.6 7 11.8 11.9 12.0 12.1 12.3. 12.4 Fuel 16.0 16.8 17.7 .18.5 19.3 20.2 at 22.0 = 23.0 24.0 251 26.3 7.4 28.7 30,00 MAS S27 LZ eesseses TOTAL v3 Wet Present Value (1990 - 2050) New Resources Added (MW): Dorothy/Long Lake Tunnel Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel 6M EMD diesel 6e-a Run Dates 09-Mar-90 . JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiees = 11331 AN Cases Lake Dorothy/Long Lake Tunned with Crater Lake Elev. 1034 and Long Lake Elev. 645 Forecast: Ad Mine Ceneceneseccsesesesagssessectsssssss $ POWRPLAN [c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1993 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 OORenageranesassagsaassssssssesstess sdeesz msecozcr Peak Demand (HW) y of Results (after conservatio Peak Deaand 51.3 | 52.8 54.2 89.5 90.5 1.6 U5 94 WA W.3 1.3 15 91.6 91.8 92.0 92.1 92.3 92.4 Peak Plus Reserve Requireaent 93.6 96.5 99.$ «163.7 164.7) 165.8 = 185.7 165.6 165.6 = 165.5 165.5 165.7 185.8 = 166.0) 166.2 168.3 Ss 86H.5 1B. b Installed Capacity 154.50 WSLS 150.5 17487 TAT 1726217262, 17262 172,02 87262 1726217262 172,2 172.2722 8726217202 17242 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00° 0.0 0.0 Energy Requirements (MWh) 277,000 286,723 296,340 529,084 536,618 544,155 544,973 545,788 546,615 547,239 547,866 548,494 549,021 549,464 549,778 550,107 550,439 “550,583 Fire Capability of Installed Units (MWa) 103.6 = 103.6 = 103.6 = 123.8 = 123.4 128.2 128.2 128.2 128.2 128.2 128.2 128.2 128,.2 128.2 828.2 128.2 1282 128.2 Wew Capacity to Meet Energy Req'ts (Hi) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -- (a) AELP Hydros Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,820 23,520 23,520 Salaon Creek 35,080 35,040 35,040 35,080 35,040 35,080 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,080 35,040 35,040 Gold Creek 5,400 = 5,400» 5,400» 5,400 = 5,400 5,400 «5,400 5,400» 5,400 5,400 5,400,400 5,400 = 5,400 5,400 5,400 5,800 5, 400 (2) Snettishaa/Crater Lake 213,040 222,763 232,580 330,836 330,836 330,836 330,836 330,836 330,036 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 (3) Dorothy/Long Lake Tunnel 0 0 0 0 © 42,042 42,042 42,042 42,042 42,042 42,042 42,082 42,042 42,042 42,042 42,042 42,042 42,082 4) Crater Lake Elev. 1034 Qo 0 0 72,048 2,848 2,808 2,848 2,848 2,088 2,848 2,888 2,848 2,848 2,848 2,848 2,848 2,848 2,648 (3) Long Lake Elev. 845 0 0 0 «12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 912,766 912,756 912,766 912,766 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 a”) 6M EMD diesel 0 0 0 117,447) 123,549 91,708 92,521 93,336 74,163 94,788 95,415 96,042 96,569 96,992 97,324 «97,656 97,988 98,131 (8) Existing Diesel: Gas Turbines 0 0 0 1,227 2,660 0 0 0 0 0 0 0 0 0 0 0 0 0 Leson Creek 0 0 0 0 0 0 0 9 0 0 0 9 0 0 0 0 0 0 fuke Bay 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL . 277,000 286,723 296,540 529,084 536,18 544,155 544,973 545,788 546,615 547,239 547,866 548,494 549,021 549,444 549,776 550,107 550,439 550,583 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost (8 Millions) Capital 0.0 0.0 0.0 4.2 4.2 9 9.5 5 9.5 9.3 9.5 9.5 95 95 9.5 9.5 9.5 9.9 Fixed 0.8 0.5 0.5 0.5 (0085 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 09 Variable 6.2 4.5 6.7 10.2 10.2 10.3 10.3 10.3 10.8 10.4 10.5 10.5 10.5 10.6 10.4 10.7 10.8 10.8 Fuel 0.0 0.0 0.0 “8.3 a4 MA 7.6 Bl 8.6 a1 9.6 10.4 LL 19 12.7 13.5 144 15.2 TOTAL 6.7 7.0 12 23.2 248 27.0 27,9 28.5 294 29.6 30.2 3d ug 32.8 33.7 46 35.5 3b Net Present Value (1990 - 2050) $414.7 aillion New Resources Added tai): Tater tres rceesccsecce sere sarc r ces oor assessor ororcr aces cose es eee soe cs esses sees esse eee Dorothy/Long Lake Tunnel 0.0 Crater Lake Elev. 1034 0.0 Long Lake Elev. 845 0.0 Caterpillar 3612 diesel 6M END diesel 23.2 8e-d Run Dates 08-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiger = 01527 PH Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Ad Mine Hepgeceaseseagsacsacegssssssessesece $ POWRPLAN (c) 1990 by CH2M HILL $ 2008 2009 2010 2011 2012 2013 2018 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2023 Sennsegnggeasssasegcececsssassessees puseseee gorseest eezseaz exsssess ces! S=2 Steesses ssereses sesre eseseass ES BEuss=st S2asses= sseseses ezeezz: Wining Loads ($millions): Fuel Costs Variable O&M Fixed OM Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total 23.7 26.0 26.2 26.5 7.7 Wl Energy Requireaents (MWh) 234,000 234,000 238,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 Average Bus Bar Cost => Nominal (cents/kWh) 12.1 12.2 12.3 12.4 12.4 10.6 10.7 10.8 10.9 11.0 Wd 1 3. 4.2 11.3 MS 11.6 M1.7 Wg 12.0 ~~ Real (cents/kWh) 5.5 5.3 4 47 3.9 3.7 3.6 3.5 3.3 32003. 3.0 29 2.8 27 27 26 oy Le-@ Run Dates 08-Mar-90 Run Tier = 01:27 PH Cosaseeseseaseesesscsceseessssesesss $ POWRPLAN (c) 1990 by CH2M HILL ¢ Uteecereecogcascecesescogsassgcgssss BUS BAR COST SECTION: Average Costs (Saillions}: Fuel Costs Variable OM Fixed O8M " Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost -- Nosinal (cents/kWh) -- Real (cents/kWh) Won-Mining Loads (Saillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systee) Depreciation Expense (new units} Property Taxes {new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost o> Nominal (cents/kWh) ~~ Real {cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 saece eenesens 2.8 29 Bl 3.2 34 3.5 3.7 4.0 4.2 4.6 4.8 9.8 9.8 9.8 9.8 9.8 99 99 99 99 99 10.0 16 1.7 1.8 1.9 2.0 24 24 2.3 25 27 2.8 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 6.3 6.3 6.3 4.3 6.3 4.5 45 4.3 45 45 45 29 29 29 29 29 29 2.9 29 29 29 24 13.1 13.1 13.1 13.1 13.1 10.4 10.4 10.4 10.4 10.4 10.4 39 39.4 39.7 39 40.1 35.9 36.2 36.5 36.8 WL v4 37.7 381 550,825 550,865 951,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 351,007 551,007 551,007 7A 12 71.2 12 73 6.5 6.6 4.6 6.7 6.7 4.8 6.8 6.9 3.2 31 3.0 29 2.8 2.4 2.3 2.2 24 2.0 2.0 1g 1.8 0.0 0.0 0.0 0.0 0.0 0.0 13 13 7.3 1.3 1.3 1.3 1.0 1.0 Lat Mt 14 1.7 2.6 2.6- 2.6 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 316,825 316,865 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 4 8 3.6 1.0 oo 2021 2022 2023 3.5 10.0 3.2 2.6 4.5 29 10.4 5.0 3.3 10.0 10.0 24 3a 2.6 2.6 4.5 43 29 24 10.4 10.4 38.4 38.8 39.2 551,007 551,007 551,007 7.0 7.0 1B. 17 0.0 0.0 73 1.3 17 1.8 2.6 2.6 0.0 0.0 0.0 0.0 0.0. 0.0. M7 0.0 7.3 1.9 2.6 0.0 0.0 > 0.0 317,007 317,007 317,007 37 37 09 0.9 37 0.9 2024 3.7 10.1 33 2.6 0.0 13 2.0 2.6 0.0 0.0 0.0 1g 317,007 37 0.8 2023 ae seeesse= eesseces 6.0 10.1 35 2.6 43 29 10.4 Run Datez 08-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Times 01:27 Pit Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Ad Mine SRepsseggssseeengstescacecesesseases # POWRPLAN (c} 1990 by CH2H HILL t 199019911992 :1993 199819951998 199719981997 2000» 2001 +2002» 2003-2008 ~=—2008 += 2008 = 2007 Seeegeaceeaseseseeceseseeneseseeses = seesesse 2s: 2 ae Bining Loads (Smillions): Fuel Costs 0.0 9.0 0.0 94 10.8 1.0 i 1.3 14 1.5 1.6 1.8 19 21 2.2 24 26 Variable O&N 0.0 0.0 0.0 34 3.2 2.5 2.5 2.5 2.5 2.5 25 25 25 25 2.5 2.5 25 Fixed O&H 0.0 0.0 0.0 0.0 90.0 0.4 04 0.4 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.8 0.6 Capital Costs (existing systea) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Depreciation Expense (new units) 0.0 0.0 0.0 18 1.8 6.3 6.3 6.3 4.3 23 4.3 6.3 6.3 6.3 6.3 6.3 6.3 Property Taxes (new units) 0.0 0.0 0.0 0.8 0.6 29 2.9 2.9 29 29 29 2.9 2g 29 29 2.9 29 Interest Expense (new units) 0.0 0.0 0.0 27 27 11 Bil 13.1 A3.t 13.1 13.1 13.1 13.1 13.1 13. 13.1 3.1 Tota! 0.0 0.0 0.0 my 19.4 20.4 26.3 2.4 26.6 26.7 26.8 27.0 27 71,3 21,3 21,7 27.9 28.1 Energy Requireaents (MWh) . 0 0 O 234,000 234,000 238,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 Average Bus Bar Cost -- Nosinal (cents/kWh) WA NA NA 7.6 8.2 8.7 11.3 U3 M3 114 4 M5 Nb M7 18.7 11.8 11.9 12.0 ~- Real (cents/&Wh) WA WA WA 6.7 6.8 fn a3 8.0 17 7A nt 6.8 6.6 4.3 bt 59 3.7 w ' w a se-d Run Date: 08-Mar-90 Run Tine: = 01227 PN Seogegcgeseceacacsancescgccsceceesss $ POWRPLAN (c) 1990 by CH2M HILL & HEggrngaeeegearacsagsesescossscessss BUS BAR COST SECTION: Average Costs (Saillions): Fuel Costs Vartable Ou Fixed O8f Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost ~- Wominal (cents/kWh) -- Real {cents/kWh) Non-Mining Loads (Seillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) -"Real (cents/kWh) 1990 sessses semsenst »: 277,000 34 34 0.0 6.2 0.4 2.6 0.0 0.0 0.0 9.3 277,000 34 3 JUNEAU 20-YEAR POWER SUPPLY PLAN we wa we ou nw to 2000 0.0 7.2 07 2.6 0.0 0.0 0.0 10.5 2001 0.0 0.7 2.6 0.0 0.0 0.0 10.5 313,239 313,866 314,495 3.3 2A Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev, 845 Forecast: AJ Mine 2003 0.0 7.2 0.8 2.6 0.0 0.0 0.0 10.6" 315,448 316,439 316,583 mw ue pe-d 08-Mar-90 01:27 PH Run Dates Run Tiees angngnsegceceasacasesecesessessseses # POWRPLAN {c) 1990 by CH2M HILL Segngagaereceasssasnecscsasseacesess Suaner (May - Septeaber Energy Requireaents (MWh) Energy Dispatch (MWh) () AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishan/Crater Lake (3) Lake Dorothy (4) Crater Lake Elev. 1034 (5) Long Lake Elev. 845 (6) Caterpillar 3612 diesel 7) 6M EMD diesel (8) Existing Diesel: Gas Turbines Leaon Creek Auke Bay Gold Creek TOTAL Cost {8 Millions) Capital Fixed Variable Fuel TOTAL 2008 2009 2010 2011 2012 Saaseesz astsaerz ==222221 SEcEare szasees: 212,740 212,913 213,122 213,122 213,122 15,577 15,577 15,577 15,877 15,577 23,254 «23,254 «23,254 | 23,254 = 23,254 3,408 3,488 = 3,488 3,488 = 3,488 118,108 116,208 £18,208 118,108 118,108 44,390 44,363 44,345 44,343 44,345 783 783 783 783 783 3,511 3,511 3,513,511 3,511 0 9 0 0 9 3,346 3,470 © 3,624 3,624 3,628 coco ecocooco eooco gsaceeee cee: 212,457 212,554 212,689 212,689 212,689 6.3 6.3 4.3 6.3 6.3 0.7 0.7 0.8 0.8 0.8 34 34 3a 35 35 0.6 07 0.7 0.8 0.8 AL 11.2 11.3 11.3 i1.4 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Mine 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 202 essse: sseezes: SES SEntszea rosesses 213,122 203,122 213,122 243,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 23,254 «23,254 = 23,254 23,254 23,254 923,254 923,258 23,254 23,254 «23,254 23,258 23,254 23,258 3,488 3,488 «3,408 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 3 ,40B = 3 ,4BB | S,4BB 3,488 118,108 118,108 118,108 118,108 118,108 118,108 118,208 £16,108 118,108 128,108 118,108 118,108 118,108 M4,345 44,345 44,345 84,345 AN, 34S 4434S 44,345 84,345 AN, T4S 44,345 44,3485 44,385 44,345, 783 783783 783 7B3 783 783 783 783 783 783 783 783 3,513,511 3,512 3,512 3,501 3,511 3,512 3,512 3,513,512 3,508 S,5UL 3,51 o- 0 0 0 0 0 0 0 9 0 0 0 0 3,624 «= 3,624 3,628 «= 3,628 3,628 «= 3,624 3,624 3,624 = 3,624 3,624 3,628 3,624 3,824 ecco ecoe ecce ecce ecco o soe eoce ecco a 0 0 0 0 ecco 0 0 0 0 212,689 212,687 212,689 212,689 212,689 212,687 212,687 212,687 212,689 212,689 212,687 212,689 212,689 ay 49 ad ag 49 a 49 4 4a 4.9 ad 49 49 0.9 0.9 0.9 1.0 1.0 Ll Ld 1.2 1.2 1.3 13 14 1S 3.5 35 35 3.5 3.5 3.5 35 35 35 3.5 3.5 35 35 0.8 0.9 09 1.0 1, 1.0 Lal Ll 1.2 1.2 1.3 4 14 10.0 ILS c€-€ 08-Mar-90 01:27 PM Run Date: Run Tieet Heggggeceagsrasescessscenaessgessses $ POWRPLAN (c} 1990 by CH2M HILL Seraggesegsegscceasegesscesesogecess Suaaer (May - Septeaber) Energy Requireaents (MWh) Energy Dispatch (MWh) ) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Lake Dorothy 4) Crater Lake Elev. 1034 (3) Long Lake Elev. 845 (6) Caterpillar 3612 diesel {7} GN EMD diesel (8) Existing Diesel: Gas Turbines Leson Creek Auke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL 1990 1991 1992 1993 1994 97,781 101,332 104,916 202,073 205,111 15,577 15,577 15,877 15,577 15,577 23,258 23,258 23,254 23,254 23,254 3,488 3,488 «3,488 (3,488 «3,488 56,571 60,083 63,629 118,108 118, 108 0 0 0 0 0 0 0 0 1,017 1,017 0 0 0 4,557 4,557 0 0 0 0 0 0 0 0 36,316 38,702 0 .0 0 5781, 188 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 105,947 202,894 203,867 0.0 0.0 0.2 0.2 1.6 1.7 0.0 0.0 1.8 Lg 1995 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Forecast: 1996 Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. Ad Mine 1997 1998 1999 2000 2001 2002 2003 845 2004 2005 2006 2007 SESSR= exsesese 208,249 208,618 209,088 207,561 209,958 210,354 210,750 211,120 211,430 211,724 211,998 212,281 212,491 15,577 23,254 3,488 118,108 0 1,017 4,557 0 41,014 1,825 15,577 23,254 3,488 118,108 44,277 699 2,634 0 1,197 ecco 209,234 15,577 15,577 15,577 15,577 15,577 15,577 15,577 23,254 23,254 23,254. 23,254 23,254 23,254 23,254 3,488 «3,488 3,488 3,488) 3,488 3,488 3,408 118,108 118,108 118,108 118,108 118,108 118,108 118,108 44,313 44,351 44,371 44,392 44,413 44,425 44,429 783 783.—s7B3-—=—(iisBS:STRS TBS 7B 2,709 2,820 2,917 3,014 = 3,112 3,202 3,288 0 0 0 0 0 0 0 1,398 1,647 1,852 2,055 2,259 «2,441 2,599 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 209, 630 210,027 210,349 210,671 210,993 241,277 211,522 15,577 23,254 3,409 118, 108 44,426 783 3,359 0 2,736 cooo 211,730 15,577 15,377 15,577 23,258 23,254 23,254 3,488 3,408 3,408 118,108 119,108 118,108 44,422 44,419 44,401 783 783—TRS 3,438 3,510 3,511 0 0 0 2,873 3,009 3,182 0 0 0 0 0 0 0 0 0 0 0 0 211,939 212,148 212,283 ce-d Run Date: 08-Mar-90 Run Timer = 01:27 PH Segpeageasenecensaessasesecsesstssss $ POWRPLAN {c) 1990 by CH2M HILL $ SReagagsagecacceasasgcacoassesescacs Winter (October - April) Energy Requireaents (MWh) Energy Dispatch (MWh) Ww AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Lake Dorothy (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 645 (6) Caterpillar 3612 diesel ) 6M EMD diesel (B) Existing Diesel: Gas Turbines Leann Creek Auke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL 2008 2009 338,085 337,953 7,03 7,943 11,786 11,78 1,912 1,912 212,727 212,727 B1,163 1,163 1,831 1,832 7,382 7,329 0 0 13,623 13,620 JUNEAU 20-YEAR POWER SUPPLY PLAN Caser Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev, 645 Forecast: AJ Mine 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2028 2022 2023 2024 2028 2 ESEEaase ataessse saceecer 22: posses: 337,885 337,885 337,885 337,885 337,885 337,885 337,883 337,885 337,885 337,885 337,885 337,885 337,885 337,885 337,885 337,885 7,943 7,943 7,983 7,943 7y94S—-7y94S—-7,943 7,983, 943—-7,94S— 7,943 7,94E—-7,943 7,983 79ST TAB 11,786 11,786 11,786 11,786 11,786 11,786 12,786 11,786 © 11,786 11,786 12,786 11,786 4,786 11,785 11,786 11,786 1,912 1,912 1,912 1,912 2,912 1,912 1,912,982 921,912 1,912 1,912 2921912921 912 212,727 212,727 212,727 212,727 242,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 242,727 212,727 212,727 B1,163 BL,163 B1,163 81,163 81,163 1,163 81,163 81,163 BL,163 81,163 BL, 163 B1,163 81,163 B1,163 BL, 163 81,183 1,831 1,831 «1,831 1,831 1,832 1,832 1,832 2B3L BSL 1,832 1,832 1,831 1,831 1,831 1,831 1, B34 7,285 7,285 7,285 7,283) 7,285 7,285) 7,285) 7,285) 7528574285 7528575285 7,285 7,285 7,285 7,285 0 0 0 0 0 9 9 6 0 0 0 0 0 0 0 0 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 13,670 ecooo ecco 0 0 0 0 eooo eoco ecoo eooco eooo eoco eooo coco ecooo ecco 0 9 0 0 821 ae 338,318 336,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 Te-d Run Date: 08-Mar-90 Run Tieer = 01:27 PM eeasegeascacagsacesecesessesagessess $ POWRPLAN (c} 1990 by CH2M HILL 8 Henaseceanagcagagsascocessesesecsess Winter (October ~ April) Energy Requireaents (MWh) Energy Dispatch (MWh) uy AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake (3) Lake Dorothy (4) Crater Lake Elev, 1034 (3) Long Lake Elev, 645 {6} Caterpillar 3612 diesel (7) 6M END diesel (8) Existing Diesel: Gas Turbines Leaon Creek Auke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Mine 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 179,219 165,391 191,628 327,012 331,507 336,007 336,355 336,699 337,054 337,281 337,512 337,743 337,91 338,014 338,062 338,110 338,158 338,092 T)M3 7,943 7,983 7594S 7,943 7,943 7498S 7yTAT—7943—7HHS 7,943 7,9KB_—7,9AB_—7,943— 7,943 7,943 —-7,943—7,988 11,785 11,786 11,786 11,785 11,786 14,786 11,786 11,786 11,785 11,786 11,786 11,786 11,786 11,785 11,788 11,785 11,786 11,786 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912 Ag? 155,469 162,679 168,951 212,727 212,727 2125727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 242,727 212,727 212727 22,727 212,727 0 9 0 0 0 0 Bi,163 BL,163 81,163 81,263 81,163 81,163 81,163 81,163 BL,163 81,163 81,163 BI, 263 0 0 0 «8,631 1,832 4,831 BSE 1,831 2,B3E 1,831,831 1,B3L 1,832 1,832,831 1,832 1,832 1,831 0 0 0 «8,209 = 8,209 8,207 6,867) 6,995 7412575221 7,317 7,413 7,89 7,540 7,513 7,486 7,460 7,418 0 0 0 0 0 0 0 0 0 0 0 9 0 9 0 0 o 0 0 0 © (58,160 58,811 59,022 11,509 14,800 12,099 12,306 12,515 12,725 12,890 13,020 13,169 13,319 13,469 13,528 0 0 0 23,621 27,531 31,647 0 0 0 6 0 0 9 0 0 0 0 6 0 0 0 0 0 Bd 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 9 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 178,111 164,321 190,593 326,190 330,752 335,326 335,737 336,158 336,588 336,890 337,195 337,501 337,744 337,922 338,045 338,169 338,292 338,300 0.0 0.0 aa 21 21 8.9 8.9 8.9 89 a9 |. 8.9 a9 0.3 0.3 0.3 0.3 0.3 9.6 0.6 0.6 0.8 .. 0.8 08 0.9 4.8 49 6.5 6.5 6.5 6.3 6.3 4.3 6.3 63° 6.3 6.3 0.0 6.8 77 8.7 09 1.0 Ml . 1.8 1g Sal 3.2 15.6 16.6 17.6 16.7 16.8 16.9 17.0 17.1 17.3 74 17.6 17.7 ng 18,0 18.2 oe-d Run Date: 08-Mar-90 : JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiee: = 01:27 PH Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 645 Forecast: AJ Mine RNeeageaeeecasecasesseessegsecesses # POWRPLAN (c) 1990 by CH2H HILL & 2008 = 200720102011 201220132014 2015 201820172018» 20192020» 2021- = 2022~S«2023 «S028 ~—2025 MII Seeneeer eeessees eeeserss seseeecs ecesssss ssesescs sesesees secesees seesese2 2522) srencese S25 Sezzecsz sxzezsss seeesess Suaeary of Results (after conservation): Seeaeeessereserssssrezessszeesssezz2222222 Peak Demand (HW) -- Peak Demand 92.5 92.6 92.7 92.7 92.7 92,7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 Peak Plus Reserve Requireaent 166.7 166.8 = 166.9 166.9 = 166.9 166.9 = 166.9 = 166.9 166.9 166.9 166.9 166.9 166.9 166.9 = 166.9) 168.9 166.9 188.9 Installed Capacity 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requirements (MWh) 550,825 550,865 551,007 551,007 551,007 351,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 531,007 Fire Capability of Installed Units (MWa) 131.0 131.0) 131.0 131.0 131.0) 131.0 132.0 138.0 131.0 131.0 13.0 13.0 131.0 131.0 131.0 131.0 13K.0StL0 Wew Capacity to Meet Energy Req'ts (MM) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -- ) AELP Hydro: Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,820 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,080 35,080 35,040 35,040 35,040 35,080 35,040 Gold Creek 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400» 5,400 «5,400 5,400 5,400 «5,400 5,400 «5,400 5,400 8, 400 (2) Snettishan/Crater Lake 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 (3) Lake Dorothy 125,553 125,526 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 125,507 (4) Crater Lake Elev. 1034 2,14 2,614 2,618 2,614 2,614 2,614 2,614 2,614 2,614 2,614 2,614 2,614 2,814 2,614 2,614 2,618 2,614 2,814 (5) Long Lake Elev. 845 10,893 10,839 10,796 10,796 10,796 10,795 10,798 10,79 10,798 10,798 10,795 10,796 10,796 10,795 10,796 10,796 10,796 10,796 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 (7) GH END diese! 16,969 17,091 17,294 17,298 17,298 17,298 17,298 17,298 17,294 17,294 17,294 17,294 17,294 17,298 17,294 17,298 17,298 17,294 (8) Existing Diesel: Gas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 0 Lemon Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 9 tesreess seszezzz 22 seseses2 seseezes =e: ¢ saeseses sesseses seeseze= sesses22 2 isssrses sessssez TOTAL 550,825 $50,865 551,007 551,007 551,007 551,007 $51,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost ($ Millions) Capital 2 15.2 15.2 15.2 15.2 11.7 4.7 11.7 M7 11.7 M7 11.7 11.7 11.7 11.7 M7 M7 11.7 Fixed 6 1.7 1.8 1g 21 2A 2.2 2.3 2.5 2.6 27 2.8 2.9 Bl 3.2 3.3 35 Variable 8 9.8 9.8 9.8 99 99 WD 19 9 99 9 10.0 10.0 10.0 10.0 10.1 10.1 Fuel 8 2.9 31 3.2 3.5 37 39 4.0 4.2 44 4.6 4.8 5.0 5.3 5.5 3.7 6.0 @ gaaesres aecszecze sszessz2 22222: ssseesss 22 2 Eeneeees Eesszzs3 seeeteze ceszsze= 2222: 2 geseese2 sezessse TOTAL 29.4 29.7 29.9 30.2 30.4 mA 27.4 27.7 28.0 28.3 28.6 28.9 29.3 29.6 30.0 30.4 30.8 u.3 Wet Present Value (1990 - 2050) Wew Resources Added (MW): Lake Dorothy Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel 6M EMD diesel 6c-a Run Date: 08-Mar-90 SUNEAU 20-YEAR POWER SUPPLY PLAN Run Times = 01:27 PM Case: Lake Dorothy with Crater Lake Elev, 1034 and Long Lake Elev. 845 Forecast: AJ Mine Ooecorageececsaccasessesegsssonssees # POWRPLAN (c) 1990 by CH2M HILL ¢ 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Oegrogagreceecessscessacsegsscesesse Besccass masezscm saz: eeaes: Bienes excesses Suaeary of Results (after conservation): Peak Denand (MW) -- Peak Demand 31.3 32.8 34.2 89.5 90.5 91.6 WS 1.4 7 11.3 W.3 1.5 1.6 1.8 92.0 92.4 92.3 924 Peak Plus Reserve Requirenent 93.6 96.5 99.4 = 163.7 164.7 165.8 165.7 165.6 165.6 165.5 165.5 165.7 165.8 = 166.0 166.2 16.3 18S 1888 Installed Capacity 151.5 151.5 151.5 166.0 166.0 166.0 192.0. 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 192.0 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requiresents (MWh) 277,000 286,723 296,540 529,084 536,618 544,155 544,973 545,788 346,613 547,237 547,866 54B,494 549,021 549,444 549,776 550,107 550,439 550,583 Fire Capability of Installed Units (Ma) 103.6 = =103.6 = 103.6 = 116.716, 6.7 18.7 138.0 13L0 SLO SLO 130 131.0 131.0 138.0 131.0 131.0 138.0 138.0 New Capacity to Meet Energy Req'’ts (MW) 0.0° 0.0 0.0 0.0 0.0 0.0 0.0 1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -- (i) AELP Hydro: Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,080 35,040 35,040 35,040 35,040 35,080 35,040 35,080 35,080 35,040 35,080 35,040 35,040 35,040 35,040 35,040 35,040 35,040 Gold Creek 5,400 5,400 = 5,400» 5,400 5,400 = 5,400) 5,800) 5,400 5,400) 5,400) 5,400 5,400 = 5,400» 5,400) 5,400 5,400 = 5,400 5,400 (2) Snettishaa/Crater Lake 213,040 222,763 232,580 330,836 330,836 330,036 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,036 (3) Lake Dorothy 0 0 0 0 0 0 125,440 125,476 125,513 125,533 125,554 125,576 125,588 125,592 125,588 125,585 125,582 125,563 4) Crater Lake Elev. 1034 0 0 0 2,848 2,848 2,848 2,531 2,614 2,614 = 2,142,614 2,614 2,614 2,614 2,614 2,614. 2,614 2, OL (3). Long Lake Elev. 845 0 0 0 12,766 12,765 12,766 9,501 7,708 9,945 10,138 10,331 10,524 10,673 10,823 10,872 10,921 10,969 10,927 (6) Caterpillar 3612 diese! 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 m GM EMD diesel 0 0 0 94,476 97,513 100,034 12,706 13,198 13,745 14,158 14,571 14,984 £5,330 15,619 15,905 16,192 16,478 16,683 (8) Existing Diesel: Gas Turbines 0 0 0 24,199 28,695 = 33,472 0 0 0 0 0 0 0 0 0 0 0 9 Lenon Creek 0 0 0 0 0 239 0 0 0 9 0 0 0 0 0 0 9 0 uke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 0 a 0 0 0 Gold Creek 0 0 Q 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 = = =o soa fesseses 222 a2 TOTAL 277,000 286,723 296,540 529,084 536,618 564,155 544,973 545,788 546,615 547,239 547,846 548,494 549,021 549,444 589,776 550,107 590,437 550,583 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost ($ Millions) Capital . 0.0 0.0 0.0 35 35 3.5 15,2 15.2 15.2 15.2 15.2 15.2 15.2. 15.2 1532 15.2 15.2 Fixed 0.4 0.3 0.5 0.5 0.5 0.6 1.0 1.0 Aa 1.2 1.2 Lg 1.3 14 14 LS 1.6 Variable 6.2 6.5 6,7 10.1 10.1 10.1 96 97 97 97 97 9.7 a7 97 97 9.8 9.8 Fuel . 0.0 0.0 0.0 94 10.8 12,3 1.0 Ld LS 15 1.6 18 Lg 21 2.2 2.4 26 eeamsses ees TOTAL 47 Wet Present Value (1990 - 2050) $324.2 aillion New Resources Added (HW): Totes asscssrrcccssccece ese ccs esas ecccc res rres casas es eae ese ener ce eres ceweerereeecee Lake Dorothy 26.0 Crater Lake Elev. 1034 0.0 Long Lake Elev. 645 0.0 Caterpillar 3612 diesel 6M EMD diesel 145 8c-@ Run Oates 02-Jul-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run tines = 03318 PM Cases Annex/Carison Creek with Crater Lake Elev, 1034 Forecast: Ad Mine ASEEReR Eg aseaasae eee seeeeeet esas & POWRPLAN (c} 1990 by CH2N HILL 8 2008 2009 2010 2011 2012 2013 2018 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 QORSRESSSLELT aes eeeeace tes esaeseesS Beeracst ceersezs esss2es2 saseesse 2237: Ssssee5 ssssszas SSG SSSSAete sasseszs zoze===: satecsa Wining Loads ($aillions): Fuel Costs 8.0 8.4 8.8 9.2 9.6 10.0 10.5 11.0 11.4 12.0 12.5 13.1 13.7 14.3 19 16 16.3 17.0 Variable O&M 2.7 27 2.8 2.8 2.8 2.8 29 29 29 3.0 3.0 3.0 3 3a ul 3.2 3.2 33 Fixed O&M 07 0.7 0.7 08 0.8 0.8 09 0.9 1.0 1.0 1.0 MA 1a 1.2 4.2 13 14 14 Capital Costs (existing systes) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0. 0.0 0.0 0.0 9.0 Deprectation Expense (new units) 6.3 6.3 4.3 &3 6.3 3.3 4.3 5.3 3.3 43° 33 3.3 3.3 3.3 3.3 3.3 3.3 3.3 Property Taxes (new units) 3. 3.0 3.0 3.0 30 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3‘ Interest Expense (new units) 13.7 13.7 13. 13.7 13.7 12.1 12.1 12.8 12.1 12.1 121 121 12.1 12.1 12 M21 124 12.1 Total Ma M8 35.3 35.7 36.2 Mat Mb 33.2 35.7 3.3 349 37.6 38.3 39.0 39.7 40.5 a aut Energy Requirenents {Kwh) 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 Average Bus Bar Cost o> Mominal (cents/kWh) 14.7 18.9 15.1 15.3 15.5 14.8 14,8 15.0 15.3 13.3 15.8 16.1 16.4 18,7 17.0 17,3 17.6 > 18.0 ~~ Real (cents/kWh) 66 64 4.3 ba 39 3.3 Sel 5.0 49 47 4b 4a 44 4.3 4 4.0 3 ug Le- 02-Jul-90 03:18 PH Run Dates Run Tises Sadersagsegcessssacessgasecsaasagess % POWRPLAN (c) 1990 by CH2M HILL SESaeseeenesergeseresagseeseseseses $US BAR COST SECTION: Average Costs (Saillfons): Fuel Costs Variable O&H Fired O&M Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense {new units) Total Energy Requiresents, (MWh) Average Bus Bar Cost co Nominal (cents/kWh) o> Real (cents/kWh) Won-Mining Loads ($ailtions)t Fuel Costs Variable Ot Fixed 08" Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units} Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Sar Cost =~ Hosinal (cents/tWh) o- Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAR Cases fnnex/Carlson Creek with Crater Late Elev. 1034 Forecast: Ad Mine 2008 2009 2010 2011 2012 2013” 2014 2013 2016 2017 2018 2019 2020 Qagauraa aanesasz azszsszs2 extacszz rencoes czgeczss eesceres soszz2zz etessczs az2=22" ze2zeree exsazs2z aszeecax 8.0 B.4 8.8 9.2 9.6 10.0 10.5 11.0 1 13.7 10.0 10.0 10.1 10.1 10.1 10.1 10.2 10.2 10.3 10.3 16 7 1.8 19 2.0 2d 2d 2.2 2.7 2.8 2.6 2.8 2.6 2.6 2.6 2.6 2.6 26 2.6 2.8 6.3 6.3 6.3 4.3 4.3 5.3 5.3 3.3 5.3 3.3 3.0 3.0 3.0 3.0 3.0 3. 3.0 3.0 3.0 3.0 13.7 13.7 13.7 13.7 13.7 12.1 12.1 12.1 124 12.4 43.2 43.7 16.2 4.7 47.3 45.2 45.8 46.4 41 49.8 550,825 530,865 551,007 551,007 551,007 $51,007 531,007 551,007 551,007 551,007 551,007 55%,007 $51,007 82 «8388 83 486 82 83 86 BS 86 88 89 90 370K OS 330 3000 29 287k 0.0 0.0 0.0 0.0 0.0 0.0 13 1300073 Le ee 1.0 1200 42 Sb LT 28 2600 2b 0.0 0.0 (0.0 0.0 0.0 = 0.0 0.0 0.0 = 0.0 10.8 M0 UNL 1.2 Me ALS LS 348,825 316,885 317,007 317,007 317,007 317,007 317,007 347,007 317,007 317,007 387,007 317,007 317,007 38 36 1.0 1.0 eu uw a ew nm ew 2025 2022 2023 2024 2025 Esu=sa2a ssaiaszz szzarssa azaceazee arateace M3 149 17.0 10.4 10.4 10.5 2.9 ua 35 2.6 2.6 28 3.3 3.3 3.3 3.0 3.0 30 124 W241 1 50.6 st 34.0 351,007 551,007 551,007 9.2 w3 45 9.6 9.8 23 2.3 2.2 2.2 ab 0.0 13 “7 26 0.0 0.0 0.0 M16 317,007 317,007 317,007 317,007 317,007 37 37 3 09 09 0 9c-d Run Date: 02-Jul-70 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiser = 03:18 PM Cases Annex/Carlson Creek with Crater Lake Eley. 1034 Forecasts AJ Mine Utneregeseaeeeagsagsagasoageegecesss 1 POWRPLAN (c) 1990 by CH2M HILL 8 1990 199l , 1992 1993 1994 1995 1998 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 UUORgRagsoaegeseagesecasageggeeseses aacusaue sexzazes ascazea assaecs ecarsco sssszeaz eazegsss eseacass eee: wQuasesa exaceeas ssareas3 ezze2s2! SEISISS SGIzEae sozcszes acecoees ooseezee Mining Loads (Seillions}: Fuel Costs 3g 0.0 0.0 0.0 9.6 1.0 2.4 aa 4.3 46 4.8 3.2 5.6 6.0 64 47 wa 1S Variable O&M 0.0 0.0 0.0 35 33 3.2 27 27 27 27 27 27 27 27 27 27 27 27 Fined ObM ‘ 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.4 0.4 0.3 0.5 05 05 0.5 0.6 0.6 0.6 0.8 Capital Costs {existing systea) 0.0 fh 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0- 0.0 0.0 0.0 0.0 Depreciation Expense (new units) 0.0 0.0 0.0 1.0 1.0 1.0 8.3 6.3 4.3 4.3 6.3 4.3 4.3 6.3 6.3 43 6.3 43 Property Taxes (new units) 0.0 0.0 0.0 0.3 0.3 0.3 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 Interest Expense (new units) 0.0 0.0 0.0 1.6 1. 1.6 13.7 13.7 13.7 13.7 13.7 13.7 13.7 13, 13,7 13.7 13.7 13,7 Total 0.0 0.0 0.0 1b 17.2 18.5 29.9 30.2 30.4 30.7 9 us UB 32.2 32.6 33.0 33.5 339 Energy Requirements (MWh) . 0 0 0 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 . N Average Bus Bar Cost => Wominal (cents/kWh) WA WA NA bg nA Ww 12.8 12.9 13.0 13.4 13.2 13.4 13.6 13.7 13.9 14 43° hS o- Real (cents/kih) NA NA. OWA 4.0 6.2 43 9.8 v5 WA BB as 8.3 8.0 7.8 1S 13 wl 4.9 Run Date: 02-Jul-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiee: 03:18 PH Case: Annex/Carlson Creek with Crater Lake Elev. 1034 Forecast: AJ Mine Ogragageagsgarseesagsesegeesageeess t POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2008 2005 2007 Uubesegseesecsaceesecsssasessessssee eprascas reazsroe 2: B= Sacess22 sessess= e2casece 32: Sa ans: SEESERE SHSSESSS BReaEse acsazssy sscazzsa =zE=zs22 zzszscac excesses erseessa cearesae $US BAR COST SECTION: Average Costs (Seillions): Fuel Costs, 0.0 0.0 6.0 96 M0 128 3g 4 43 4.8 4.8 42 3.6 6.0. 64 47 I us Varlable O88 ~ 6.2 4.5 4.7 10.1 10.2 10.2 9.8 9.8 9.8 9.8 V9 9 99 9.9 wd wd 10.0 10.0 Fixed OM 0.4 0.5 0.5 03 0.5 0.6 1.0 1.0 La Ld 1.2 1,2 13 3 14 14 Ls 16 Capital Costs (existing systea} 2.6 2.6 2.6 2.6 2.6 2.6 2.6 26 2.6 2.6 2.6 2.6 2.6 2.6 2b 2.6 2.6 2.8 Depreciation Expense {new units) 0.0 0.0 0.0 1.0 1.0 1.0 b3 6.3 8.3 43 43 6.3 4.3 4&3 4.3 8&3 Property Taxes (new units) 0.0 0.0 0.0 0.3 03 0.3 30 300 ' 30 3.0 30 3.0 30 Interest Expense (new units) 0.0 0.0 0.0 1b 16 1.8 13.7 13.7 13.7 13.7 13.7 13.7 13.7 Total 13 98 9.8 25.8 27.2 28.7 40.2 40.5 40.8 at 43.7 44.2 47 Energy Requireaents (MWh) *277,000 286,723 296,540 329,084 536,418 544,155 544,973 545,788 546,615 547,239 547,865 $48,494 549,021 549,444 549,776 550,107 550,439 550,583 Average Bus Bar Cost <> Mominal (cents/kWh) 34 3.3 3.3 4.9 Sa 3.3 1A 14 15 15 2b 78 1 7.8 wy A 8.0 Bl > Real (cents/kWh) 34 3.2 3.0 4.3 ay 4.2 3.7 3.5 3.3 Sl ay 4.7 4.5 4 4.2 4a 4.0 3.8 w Non-Mining Loads ($aillions): t Fuel Costs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Variable O&M 6.2 4.5 4.7 6.7 69 7d 7A WA 7.2 1.2 7.2 7.2 1.2 13 13 Fixed O&M _ O84 0.5 0.35 0.5 0.5 0.6 0.8 0.6 0.6 0.7 07 7 0.7 0.9 09 Capital Costs (existing systes) 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 26 26 Depreciation Expense (new units) 0.0 0.0 0.0 0. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Property Taxes {new units) 6.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Interest Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total v3 9.6 9.8 9.8 10.0 10.2 10.3 10.3 10.5 10.6 , 10.8 10.8 Energy Requirenents (MWh) 277,000 286,723 296,540 295,084 302,618 310,155 310,973 311,788 312,15 313,239 313,866 314,494 $15,021 315,444 315,776 316,107 316,439 316,583 Average Bus Bar Cost =~ Nominal {cents/kWh) 34 33 33 3.3 33 33 3.3 33 3.3 33 33 3.3 34 34 Aa ua 34 => Real (cents/k¥h) ua 3.2 3.0 2.9 2.8 2.6 2.5 24 2.3 2.2 21 24 2.0 1g 1.8 1.8 1.7 1.6 v2-d Run Dater 02-Jul-70 . SUMEAU 20-YEAR POWER SUPPLY PLAN Run Tiner 03248 PR _ Cases Annex/Carison Creek with Crater Late Elev. 1034 Forecast: AJ Nine UMTHUSa erg seas era esaaeee ese e testes 1 POWRPLAN (c}) 1990 by CH2M HILL & 2008 2009 2010 2011 2012 2013 2014 2015 2018 2017 2018 2019 2020 2021 202 2023 2024 2023 QUgnRagaasesesaasageeseesasetes esses azeseits ecameste azczss25 22222222 2: = = SEESEEZ Basssaze acecssz2 232: saagsses 22 Bazassta ueszaszz Susser (May - Septeaber} Energy Requireaents (Mith) 212,740 212,913 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 243,122 213,122 Energy Dispatch (MWh) Wy AELP Hydro: Annex Creek 13,577 15,577 13,577 15,577 13,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,877 13,577 15,877 15,577 15,377 15,577 Salaon Creek 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,258 23,254 23,254 23,254 23,254 23,254 23,254 23,254 Gold Creek 3,488 3,488) 3,488) 3,488 3,488 3,488 3,488 3,488 | 3,488 | 3,488 3,488 3,488) 3,488 =| 3,488 3,488 = 3,483,483, 48B (2) Snettishae/Crater Lake 118,108 118,108 128,108 116,208 128,108 118,108 118,108 116,108 118,108 118,108 118,108 118,108 118,108 128,108 118,108 118,108 118,108 118,108 (3) Annex/Carison Creek No.1 52,030 52,127 52,262 $2,262 52,252 52,262 52,262 52,262 52,262 52,262 52,262 52,262 $2,262 52,262 52,262 52,262 52,262 $2,262 4) Crater Lake Elev. 1034 0 0 0 ° 0 0 0 0 0 0 0 0 6 0 0 0 0 0 (3) Long Lake Elev. 645 o 0 0 0 0 0 ° 0 0 9 0 0 0 0 0 0 0 6 (8) Caterpillar 3612 diesel o 0 0 0 Q a 0 6 0 0 0 0 0 0 0 0 6 0 ”) 6H EMD diesel 6 6 ° 6 0 0 0 0 6 0 0 8 0 0 0 0 6 0 (8) Existing Diesels 6as Turbines 0 0 0 0 0 0 6 0 o 0 0 0 0 0 0 0 0 0 Leaon Creek 0 0 a 6 0 0 0 a 0 0 6 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 0 0 Q 0 0 0 0 a 0 0 0 Sold Creek 0 Q Q Q o 0 Q 0 0 0 0 0 0 0 6 ° 0 0 easessss aestascz aazsse=z ascczsce seezzs20 &: scenacs scsansez zazsezzs sazessea £22: anagazz ssi zeazesze exeszezz TOTAL 212,457 212,554 212,889 212,689 212,689 212,687 212,687 212,689 212,689 212,689 212,489 212,689 212,689 212,689 212,489 212,689 212,689 212,689 Cost ($ Millions) Capital 6.3 6.5 45 4.5 6.5 3.7 3.7 3.7 5.7 3.7 3.7 3.7 3.7 3.7 37 3.7 3.7 3.7 Fixed 0.7 0.7 0.8 0.8 0.8 09 0.9 0.9 ‘1.0 1.0 il ia 1.2 1.2 13 1.3 14 LS Variable 34 34 34 3.4 3.8 3a 34 3 34 “34 34 ua 34 34 34 34 3.4 34 Fuel 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 OL O1 Ot OL On Ot Ot Ot OL astsz2ze sazzezs= r:: sansiss ssaaesce TOTAL 10.8 10.6 10.7 10.7 10.7 9.9 10.0 10.0 10,1 10.1 10.2 10.2 10.3 10.3 10.4 10.4 10.5 10.6 €t-d Run Dater 02-Jul-90 Run Vines O33 18 PM Rasnretesseecesesagsegegseceesessese $ POWRPLAN (c} 1990 by CH2M HILL 8 Beeeaaggagsegnseegesssasassassetesse Suaner (Nay - Septeaber) agcesoercersssiaraseccrz Energy Requirenents (MWh) Energy Dispatch (MWh) a AELP Hydros Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake (3) Annex/Carison Creek No.t (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 645 (4) Caterpillar 3412 diesel a”) 6M END diesel (8) Existing Diesel: Gas Turbines Lemon Creek fuke Bay Gold Creek TOTAL Cost {8 Hillions) Capital Fixed Variable Fuel TOTAL QUHEAU 20-YEAR POWER SUPPLY PLAN Caset Annex/Cartson Creek with Crater Lake Elev, 1034 Forecast: AJ Mine 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 = 2006 2007 wesarnee serszaza Brzzsca2 esexzara wzcsasse essezces arecrese azs3zcz2 =2z30E3" ateseze2 aeaesze: SaNaEE arsesoes azseessa sazazcsa szazass2 uxsszase f=esz=sE 97,781 101,332 104,916 202,073 205,111 208,149 208,618 209,088 209,561 207,958 210,354 210,750 211,110 211,430 211,714 211,998 212,281 212,491 15,377 15,377 15,577 15,577 15,577 15,577 13,577 15,577 © 15,877 15,877 15,577 15,577 15,577 15,577 15,577 15,577 15,377 15,377 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,258 3,488 3,488 3,488 3,488 3,488 3,488 3,488 3,488 = 3,488 3,488) 3,488) 3,488) | 3,483,488) 3,488 3,488 3,4BB : 3,488 36,571 60,083 63,627 118,108 118,108 118,108 118,108 118,108 110,108 118,108 128,108 118,108 118,108 116,108 118,108 118,108 118,108 118, 108 0 0 0 0 0 0 (48,808 49,203 49,601 49,923 50,243 50,566 50,850 91,095 51,304 51,512 51,728 51,858 0 0 0 1,017 1,017 1,017 0 Q 0 0 0 0 o 0 0 0 0 0 . 0 0 0 0 0 0 0 0 6 0 0 0 0 0 6 0 0 0 0 0 8 0 0 0 0 6 ° Q 0 0 0 0 0 o 0 0 0 0 0 (41,851 44,428 47,397 0 0 0 0 0 0 0 0 0 0 0 0 0 9 6 6 o 0 0 0 0 0 0 0 oO. 0 oO 0 0 6 0 o 0 ° 0 0 0 6 0 0 0 0 Q 0 0 0 0 0 0 o 0 o 0 0 0 0 0 o 0 6 0 6 0 o 0 6 0 o 0 0 0 0 0 o a 0 +o 0 0 0 0 0 0 0 Queaeszz exezauaw eoessese sruurene axczesex auczears aeusenze exzgecz3 =az03aE2 3azzEe33 saeazaza capzssza soescesa aceesses taezazsx azsesrs2 sseosz23 saszesse BY 102,802 105,947 202,894 205,857 208,840 209,234 209,630 210,027 210,349 210,671 210,993 211,277 214,522 241,730 211,939 212,148 212,283 0.0 0.0 8 0.8 0.8 4.5 6.5 4.5 45 4.5 65 rr) 45 45 6 0.2 0.2 2 0.2 0.2 04 04 O84 0.5 0.5 0.5 05 0.6 0.6 0. 1.6 4.7 6 3.6 3.8 34 3.4 34 34 3a 34 34 34 34 3 0.0 0.0 9 3.3 37 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 4. asucze2a ezezeser sasz: 3 ECsEas== exaessex szazsez =az¢: 2 sansese: 18 Lg 2.0 ws 8.0 8.3 10.3 10.3 10.3 10.3 10.4 10.4 10.4 10.4 04 10.5 10.5 10.5 ? N NS Run Dates Run Tiae: 02-Jul-90 03:18 PA QUUgagnseseaggesseeaesatatsesagsess $ POWRPLAN (c} 1990 by CH2M HILL VEReeesegesaagagcseseseetacssassegss Winter (October - April) sass Energy Requireaents (MWh) Energy Dispatch (MWh) (2) () (4) () (8) a (8) AELP Hydro: Annex Creek Salaon Creek Gold Creek Snettishaa/Crater Lake Annex/Carison Creek No.! - Crater Lake Elev. 1034 Long Lake Elev. B43 Caterpillar 3é12 diesel GH EMD diese} Existing Diesels Gas Turbines Lenon Creek fuke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL 2008 338,085 7,943 11,788 1,912 212,727 $3,747 1,578 0 0 42,253 2 4 0 0 338,388 2009 2010 337,953 337,685 7,943 7,943 11,786 11,786 1,912 1,912 212,727, 212,727 33,707 $3,876 1,578 1,978 0 0 0 0 48,205 48,204 a3 492 0 0 0 0 0 0 338,312. 338,318 at 1.0 6.7 8.3 ears sasssess 25.1 23.6 2011 337,885 7,943 14,788 1,912 212,727 53,676 1,578 0 ° 49,204 492 0 0 0 sgetsese 338,318 26.1 2012 337,085 7,943 11,788 4,912 212,727 53,676 1,578 0 0 48,204 492 0 0 0 2013 seuzazse 337,885 7,983 11,786 1,912 212,727 53,678 1,978 0 0 48,208 492 0 0 0 seesaaez zezszzaz 330,318 at 1a 6.7 9.8 gaereenc geesssea azzeaaso seacsssz 26.5 338,318 nw 1.2 6.8 10.0 25.9 JUNEAU 20-YEAR POWER SUPPLY PLAN fase: Annex/Carlson Creek with Crater Lake Elev, Forecast: AJ Mine 2014 2015 2018 2017 2018 2019 Sf EUESEESE asteeeze eseazszz 337,885 337,885 337,865 337,885 337,865 337,885 7,943 7,943 7,943 7,943 7,943 7,943 11,786 14,786 11,786 11,786 11,788 11,786 1,912 1,982 4,912 1,912,912 4,912 212,727 242,727 22,727 242,727 212,727 212,727 53,676 53,676 53,676 53,678 53,678 53,476 1,578 1,578 1,878 1,578 1,578 1,578 0 0 0 0 0 0 0 0 0 0 0 0 48,204 48,204 48,204 48,204 48,208 48,204 4249292929 “0 9 0 4 0 0 0 0 0 o 6 0 0 0 0 0 6 0 338,318 338,318 338,318 330,318 338,318 338,318 he A] 13 OL 6.8 88 10.9 2 gasseess os: 26.8 27.0 28.1 28.8 4 says 1034 2020 2021 2022 2023 2024 2025 EsBagSa" eataccss cacsssca agazzeeo uzacazes 337,885 337,885 337,885 337,885 337,885 337,885 7,943 7,943 7,943 7,943 7,943 7,943 41,786 11,786 18,785 12,786 11,786 11,788 1,902 1,912 £,912 1,912 1,942 1,982 212,727 212,727 212,727 212,727 212,727 22,727 33,676 53,678 53,678 53,678 53,678 93,676 1,578 1,578 1,578 1,578 1,578 = 1,578 0 0 0 0 6 0 0 0 0 0 0 0 48,204 48,204 48,208 48,204 48,208 48,208 492 492 492 492 492 492 Q 9 0 0 0 0 6 0 0 0 0 Q 0 0 0 o 0 Q Bentezce estesess sescesz= seencees scarsize 338,318 338,318 338,318 336,318 338,318 338,318 we 1 19 nw 1.8 LY 19 2.0 7.0 wd TA 12 14.8 15.5 16.2 16.9 BS SScuSTaE Seszeasm saszsaN 301 30.8 324 3.2 ua 3b i 1 Run Date: 02-Jul-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Hiees = 03:18 PH Case: Annex/Carison Creek with Crater Lake Elev. 1034 Forecast: Ad Mine Utgngeggeageseasesegsesessesersocses t POWRPLAN (c) 1990 by CH2M HILL & 1990 | 197L, S992) 1993st99A= 1995-1996 = «1997-Ss899B = «1999 = 2000-2001.» -2002- 2003-2008 = 2008S 2008» (2007 Sueasesaaeessaeeegceseesesessceseses ateczcse agzeafsa srascass feces: = eeeresan SSEERERS Bszaseea eescasts eurzazsz Winter (October - April) axseseeraxcossorsacscsex Energy Requiresents (MWh) 179,219 185,391 191,624 327,011 331,507 336,007 336,353 336,699 337,054 337,281 337,512 337,743 337,911 338,014 338,062 338,110 338,158 338,092 ergy Dispatch (MWh) Ww AELP Hydro: Annex Creek TMS 7,943 7,963 7S 7,943 7,94S TS TPS HAS TMS 7, 94S— 7S 7,943 7,943 TMS 7ST 7,743 Salaon Creek 12,786 11,786 11,785 11,786 11,786 11,786 11,786 11,786 12,785 11,786 = 1,786 11,786 911,786 12,786 11,786 11,786 1,788 11,786 Gold Creek 4,912 2,912 1,912 1,912, 1,982 1,912 1,912 $,992 0,912 1,902 2,982 9121922191212 912A E2— 912 (2) Snettishae/Crater Lake 156,469 162,679 168,952 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 222,727 242,727 212,727 282,727 212,727 212,727 - (3) Annex/Carlson Creek No.1 0 0 0 0 0 © 53,080 53,217 53,356 53,462 53,568 53,474 53,763 53,835 33,831 53,818 33,801 $3,770 (4) Crater Lake Elev. 1034 q Qo O 1,831 1,832 1, BSL 1,356 1,356 2,356 1,356,356 1,355 1,356 1,356 1,416 1,487,589 1, 578 (3) Long Lake Elev. 845 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (6) Caterpiltar 3412 diese} 0 0 0 0 0 0 0 Q 0 0 0 0 0 0 0 0 0 0 a) SH END diese! 0 0 0 (78,857 79,963 80,624 46,934 47,217 47,308 47,703 $7,903 48,070 4B, 151 48,195 48,206 48,217 48,228 = 48,209 (8) Existing Diesel: Gas Turbines 0 @ 0 M,133 14,588 16,502 0 0 0 0 0 3 10S 168 223 2g 334 um Leaon Creek 0 0 0 0 0 0 0 0 0 a 0 0 0 0 0 0 0 0 wo fAuke Bay 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 1 - Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N eauseaza wagseses msgzeccx c2tezs22 xetsse22 zsezecce ezessese cxszzz93 32: ma aaizense sascses2 Se eessaaza gacrsctz saeerzez RR TOTAL 178,111 184,321 190,593 326,190 330,751 335,316 335,739 33h,158 336,588 336,890 337,195 337,501 337,744 337,922 338,045 338,169 338,292 338,300 Cost ($ Millions) . Capital 0.0 0.0 0.0 1,2 1.2 42 wt Wt Ai wt aA wl Wt 9 Fined 0.3 0.3 0.3 0.3 03 0.3 0.6 0.6 0.6 0.8 0.8 0.8 (0.9 09 Variable 4.6 4.8 4.9 6.6 6.8 6.6 ad 6.5 6.5 4.5 6.6 8b 6.8 66 Fuel 0.0 0.0 0.0 4.7 7.7 a7 39 4a 4.3 4.0 54 “67 mt 1S asaesees azcaggen ssgsaacz zzce2z3¢ 3529325 = sexa assseese 32 Sceeisa sEaesaz satasg=e zeaas323 = oo = TOTAL 49 5.1 5.2 14.8 15.7 18.8 20.0 20.2 20.5 20.8 at 25 22.0 22.4 22.8 2.3 3.7 4.2 02- Run Date: 02-Jul-90 SUHEAU 20-YEAR POWER SUPPLY PLAN Run Tieer 03:18 PM Case: Annex/Carlson Creek with Crater Lake Elev. 1034 Forecast: AJ Nine Oeeceggrsseegeeggegsegetcgesesesssss 1 POWRPLAN (c} 1990 by CH2N HILL & 2008 = 200920102011, 201220132018 = 20132018 = 201720182019» 2020» 2028 = 2022-2028 2028S 2028 Neeggcgggngscgaggggassgegssersssecss ERESCECH ZEI9EREE ExOceee actessce saerszcz sssa=sze cseseezt waressse extscess szezssce ssesesee seseszce cesesaze Suasary of Results (after conservation): eevauscresrrcaceceastexessceznscesseesse3 Peak Deaand (Hi) -- Peak Deaand 92.5 92.6 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 Peat Plus Reserve Requireaent 166.7 166.8 = 166.9 166.9 166.9 = 166.9 166.9 = 166.9 166.9 = 186.9 = 186.9 166.9 166.9 = 188.9 2B. 18918618 Installed Capacity 199.8 6199.8 199.8 «199.8 199.8 199.8 = 199.8 = 199.8 = 199.8 = 99.8 = 199.8 199.8 «199.8 = 199.8 «= 199.8 = 199.8 «9199.8 = 199.8 Additional Required Capacity 9.0 0.0 0.0 6.0 0.0 0.0 0.0 0.0 0.0 0.0. 0.0 0.0 0.0 9.0 0.0 0.0 ° 0.0 0.0 Energy Requiresents (MWh) 550,825 550,865 551,007 351,007 551,007 $51,007 551,007 551,007 551,007 551,007 551,007 $51,007 551,007 551,007 551,007 551,007 551,007 551,007 Fira Capability of Installed Units (MWa) = 126.8 = 126.4 126.4 126.8 = 126.4 128.4 126.8 126.4 28.4 126.4 128.8 128.8 126124 1264826128128 New Capacity to Meet Energy Req’ts (MW) = 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.0 0.0 0.0 0.0 Energy Dispatch {MWh} -~ a) AELP Hydroz Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,010 35,040 35,040 35,040 35,040 35,080 35,040 35,040 35,040 35,040 Gold Creek 5,400 5,400 5,800 5,400 5,400 5,400 © 5,400 5,400 5,400 5,400 5,400 = 5,400 5,400» 5,400 5,400 5,400 5,400 5,400 {2) Snettishae/Crater Lake 330,836 330,835 330,836 330,835 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,835 330,835 330,636 330,836 330,836 330,836 (3) fnnex/Cartson Creek Ho. 105,777 105,834 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 105,938 ta) Crater Lake Elev. 1034 1,578 4,578 «1,578 «1,578 «1,578 = 4,578 1,578 = 1,578 91,578 = 1,578 1,578 = 1,578 1,578 8,578 1,578 = 1,578 1,578 1,578 (3) Long Late Elev. 845 0 0 0 0 0 Q 0 0 0 0 0 0 0 0 0 0 0 0 (4) Caterpillar 3612 diesel 0 0 _ 0 ° 0 0 0 0 6 0 0 0 0 0 0 o 0 0 7) 6M END diesel 48,253 48,205 48,204 48,204 48,204 48,204 48,204 48,204 48,204 48,204 48,204 48,208 48,204 48,204 48,204 48,204 48,204 48,204 (8) Existing Diesel: Gas Turbines 422 433 492 492 492 492 492 492 492 492 492 492 492 492 492 492 492 492 Leaon Creek 0 0 0 0 0 0 0 0 0 0 o 0 0 Q 0 0 6 0 fAuke Bay “0 0 0 0 0 0 0 0 0 0 0 0 » O° 0 0 0 0 6 Gold Creek . ° 0 ° 0 ° 0 ° ° 0 0 0 ° 0 0 0 0 0 0 esceseem reeseces a aeucscse czrszece soszcece ersacces eazeaces scestzss crceszen =sces=c8 SEE axe: ese eascrsss esaecacs TOTAL 550,825 550,865 551,007 551,007 551,007 551,007 551,007 531,007 551,007 351,007 551,007 551,007 551,007 551,007 $51,007 551,007 551,007 551,007 Unserved Energy 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 o> . 0 0 Cost ($ Millions) Capital 15.6 15.6 15.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 Fixed 1.6 17 1.8 + 2L 2.2 2.3 2.5 2.6 2.7 2.8 29 31 3.2 3.3 3.5 Variable 10.0 10.0 10.1 10.2 10.2 10.2 10.2 10.3 10.3 10.3 10.4 10.4 10.5 10.3 10.5 Fuel 8.0 8.4 8.8 10.5 11.0 4 12.0 12.5 13.1 13.7 14.3 149 15.6 16.3 17.0 ESesRare earsacca ereeszs© ==: SEEEEsE gczesacs sszscezt 2a EREIEEIE s2estese tesssss ersesecz TOTAL 35.2 35.7 36.3 8 37.3 35.8 36.4 37.0 W.b. | 3B.2 38.9 39.8 40.4 41.2 42.0 42.8 43.7 44.6 SEES=== aEEEze2s cotzsrae Wet Present Value (1990 - 2050) Mew Resources Added (MW): Annex/Car}son Creek No.1 Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel GM EMD diesel 61-@ Run Date: 02-Jul-90 Run Tie: 03218 PH Aausesgsceaecegsseatsencesaessseses $ POWRPLAN (c} 1990 by CH2M HILL 8 Sapagserssgessesessesagceacgssssases Suaaary of Results (after conservation): agezzercszent2ez=: Peat Desand (HW) -- Peak Desand Peak Plus Reserve Requiresent Installed Capacity Additional Required Capacity 2anzaeessscz=: Energy Requirerents (HWh) Fira Capability of Installed Units (HWa) New Capacity to Meet Energy Req'ts (MW) Energy Dispatch (MWh) -~ itt) RELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Annex/Carlson Creek No. a) Crater Late Elev. 1034 (5) Long Lake Elev, 845 (8) Caterpillar 3612 diesel i) GM EMD diesel (8) Existing Diesel: Gas Turbines Lemon Creek fuke Bay Gold Creek TOTAL Unserved Energy Cost (8 Millions} Capital Fixed Variable Fuel TOTAL Net Present Value (1990 - 2050) ROesaexe tueczaae sescczss ssszass2 atsnzs3zt easarsc2 asseezaa sasasst= c=253=83 23f5za=3 eaeseaag szcaza=2 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Annex/Carlson Creek with Crater Lake Elev. 1034 Forecast: Ad Mine 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002” 2003 2004 2003 2006 2007 52.8 34.2 89.5 90.5 91.8 9S WA Wd U3 U3 WS 91.8 WB 92.0 92.1 92.3 92.4 98.5 99.8 = 163.7 184.7 165.8 165.7 165.6 165.6 185.5 165.5 185.7 185.8 = 158.0 186.2 16S 18S 1888 131.50 151.50 171.8 17L.8 171.8 199.8 199.8 199.8 199.8 = 199.8 = 199.8 = 199.8 199.8. 899.8 «= 199.8 = 199.8 1978 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 277,000 285,723 296,540 529,084 536,618 544,155 544,973 545,788 546,615 347,239 547,868 548,894 549,021 549,444 549,776 550,107 550,439 550,583 103.6 103.6 103.6 19.7 19.7 19.7 126.4 126.6 126.4 1264 8261284126 1284128128 MH 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 33,040 35,040 35,040 35,040 35,080 35,040 35,040 35,080 35,040 35,040 5,400 5,400 5,400 3,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400) 5,400 = 5,400 5,400 5,400 5,400 213,040 222,783 232,580 330,836 330,836 330,836 330,836 330,835 330,836 330,835 330,836 330,836 330,836 330,835 330,836 330,836 330,836 330,036 0 0 0 ° ° © 101,887 102,420 102,957 103,383 103,812 104,240 104,13 104,930 105,138 105,329 105,522 103,628 0 0 0 «2,848 2,848 2,898 1,356 1,358 1,358 2,358 ,35K L358 14358 138K AAS AB7 AS89878 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 ° o 0 0 0 0 0 0 0 120,308 124,387 128,010 46,934 47,217 47,508 47,703 47,903 48,070 48,151 48,195 48,208 48,217 48,228 48,209 0 0 0 11,133 14,588 16,502 0 ° o 0 0 33 105 aa 0 o 0 0 o 0 0 0 0 0 0 o 0 0 0 0 0 0 0 o 0 0 0 0 0 o 0 o 0 0 0 0 0 0 0 0 0 ° 0 0 o 0 0 0 0 o 0 0 0 ° 0 0 0 0 nsx ueaessea saussers azssessn sqeszecs seszsses a tacszcex eeaesscn £23 — ene acsscexe sxsussee apesetaz sesecera e:: 277,000 286,723 296,340 529,084 $34,510 544,155 544,973 $45,788 544,615 547,239 547,066 548,494 549,021 549,444 549,776 580,107 550,439 530,583 0 0 0 0 0 0 0 0 0 0 0 0 o oo, 0 0 0 0 Cn SX A Be CC CC Oo Cc 04 0S 05 05 OS 08) 10 OA AALS 82 6S 87 101 102 102 98 98 98 F868 99 «989 88 89) 88) OF 100 100 0.0 0.0 0.0 96 + 11.0 24 3g 4 43 4b 48 5.2 3.6 4.0 a4 47 MW “Ss aeesozes anreecae sazcersa sreccszs aauzsree afssctes earszoz= uscaeeee sutersig axseseos acecegea sccecaee xeazzzsc zsalastz sezaztaz Szhtsssz a=zcezza reazerse 67 7.0 12 22.3 23.7 25.2 30.2 30.5 30.8 Mal 4 M9 32.4 * 32.8 33.3 33.8 342 M7 $382.9 afllion Annex/Carlson Creek Mo.1 Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel 6H END diesel 20.3 8T-a Run Date: 08-Mar-90 Run Times §=(OL07 PH * anegngnecegnsasecsccsacsosessseseess & POWRPLAN (c) 1990 by CH2M HILL & Annggegseccagceasocascsccasesscsceet ining Loads (Seillions}: Fuel Costs Variable O88 Fixed O&M Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes {new units) Interest Expense (new units} Total Energy Requiresents (MWh) Average Bus Bar Cost => Wominal (cents/kWh) ~- Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Base Case (Diesel) Plan Forecast: AJ Mine 2008 2009 2010 2011 2012 2013 2014 2015 Sak azcssees sz: 2 sfeseass 25.6 26.9 28.2 29.5 30.8 32.2 33.6 Ril 37 3.8 3g 4.0 4.0 4a 4.2 4.3 0.0 0.0 0.0 0.0 9.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 1.2 1.2 4.2 1.2 1.2 0.0 0.0 “0.0 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 1.8 1.8 1.8 1.8 1.8 0.0 0.0 0.0 32.7 ual 35.5 389 3.3 36.7 38.2 39.8 234,000 234,000 234,000 238,000 234,000 234,000 234,000 234,000 14.6 15.2 15.8 16.4 13.7 16.3 17.0 6.3 6.3 6.3 6.2 3.7 5.7 3.7 = uso 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 36.7 38.4 40.1 ag 43.8 45.8 47.8 50.0 32.2 54.6 44 45 4.6 47 4.8 49 5.0 Sal 5.3 34 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.0 6.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.4 0.4 0.4 0.8 0.4 0.4 0.4 0.4 08 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 5 43.3 5.1 47.0 49.0 Sil 53.3 33.5 37.9 60.4 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 17,7 18.5 19.3 20.1 20.9 21.8 22.8 23.7 4.8 25.8 3.6 3.6 5.6 5.6 5.6 5.6 5.6 5.6 5.5 5.5 LT-@ Run Date: Run Ties 08-Mar-90 01:07 PH eeagcagnasegcegcacsasecsosscecsasees @ POWRPLAN (c) 1990 by CH2M HILL 8 Oneeseseeceassesecececesecesesesssse BUS BAR COST SECTION: Average Costs (Smillions): Fuel Costs Variable O&M Fixed OM Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost ~~ Nominal (cents/kWh) -- Real (cents/kWh) Won-Mining Loads (Seillions}: Fuel Costs Variable O&M Fixed O84 Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requirerents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) ~~ Real (cents/kWh) aS oo J 2008 3. i. 0. 2 1 4 BRoOaoe 43.4 350,625 0.0 13 0.8 2.6 0.0 0.0 0.0 10.7 316,825 34 15 2 ! eonone -—:-J 2009 22 guEssrss s2=32; 6.9 Ad 0.9 2.6 1.2 0.8 4.8 350,865 Soerwrus 0.0 10.7 316,865 34 1S 28. 1 2010 8 1. 6. 2. 1 0 1 Bei een 46.3 551,007 8.4 35 10.8 317,007 3.4 14 2011 21.5 1.2 09 2.6 1.2 0.4 1.8 47,7 551,007 8.7 3.4 0.0 13 0.9 2.6 0.0 9.0 0.0 317,007 2012 3 eferssee 551,007 351,007 10.9 317,007 % 1 Cases Forecast: 2014 3. 1. 2 a i o. 0. 49.2 351,007 10.9 317,007 ma Ha a 2015 = gaess: cone 551,007 0.0 1.3 | 2.6 0.0 0.0 11.0 317,007 Re 3b. u 2016 1 2. 0. 0 eoenui 0.0 52.6 351,007 9.5 3.0 11.0 317,007 38. MW JUNEAU 20-YEAR POWER SUPPLY PLAN Base Case (Diesel) Plan Al Mine 2087 f 2. 0. CeN@s 9 3.0 2018 40.1 9 1.3 2.6 0.0 0.4 0.0 44 36.2 551,007 551,007 10.2 3.0 0.0 nS 1.3 2.6 0.0 0.0 0.0 MAL 14.2 317,007 317,007 2019 a9 12.0 1.3 2.6 9.0 0.4 0.0 358.2 551,007 10.6 29 0 LA 4. 2. 0 0 Soeuus 0.0 11.2 317,007 3" 2021 45.8 12.2 15 2.6 0.0 0.4 0.0 62.4 551,007 0.0 1.3 15 2.6 0.0 0.0 0.0 347,007 3.6 09 2024 = ERzeeser exzszece 52.2 12,6 17 2.6 0.0 0.4 0.0 69.5 551,007 12.6 2.8 0.0 13 47 26 0.0 0.0 9.0 ALS 317,007 3.6 0.8 2023 4.6 12.7 a? 26 0.0 0.4 0.0 72.0 551,007 13.1 2.8 0.0 1S 17 2.6 0.0 0.0 0.0 11.6 317,007 37 0.8 9T-@ Run Date: 08-Mar-90 Run Tiees = 01107 PH Onenreceergnasecesecesscesessessses $ POWRPLAN (c) 1990 by CH2M HILL 8 Heengsgecgcseagecccecessseccsacasecs Mining Loads (Saillions): Fuel Costs Variable Ob Fixed O84 Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -~ Nominal (cents/kWh) ~~ Real {cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Base Case (Diesel) Plan Forecast: AJ Mine 1990 199 1992 1993 1994 1995 1996 1997 1998 1999 2000 22 sReceiss cexssss= 2 2001 2002 2003-2008 2005 2006 = 2007 SREEsess eensases Cessesss sxsecces szresese es: a cena ssessese execcess 0.0 0.0 6.0 9.3 10.8 1.6 12.4 13.1 13.9 14.6 15.4 16.6 9 19.1 20.4 21.7 23.0 42 0.0 0.0 0.0 35 34 3.3 3.3 3.3 3.3 33 34 34 34 35 35 36 3.6 37 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (1.0) (14) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.2 1,2 1.2 1.2 12 1.2 42 1,2 1.2 1.2 1.2 4.2 1.2 1.2 1.2 0.0 0.0 0.0 0.4 0.4 0.4 0.4 0.8 0.4 0.4 04 0.4 0.4 0.4 04 0.4 0.4 04 0.0 0.0 0.0 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 0.0 0.0 0.0 13.3 16.2 18.3 19.1 19.8 20.6 2.4 22.2 23.5 24.8 26.1 27.4 (28.7 3.000 SL 0 0 0 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 WA NA nA 4.3 6.9 7.8 8.2 8.5 8.8 9.2 9.5 10.0 10.6 MLL 1.7 12.3 12.8 13.4 WA NA nA 3.7 5.8 4.3 6.3 6.2 6.2 6.2 bl 6.2 6.2 6.3 4.3 6.3 6.3 4,3 ST- 08-Mar-90 01:07 PN Run Date: Run Tieet Serecececeaessecsceceseesegessecsess $ POWRPLAN (c) 1990 by CH2M HILL ¢ Seegreasesersagsscsceescesesecesesss BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs Variable OW Fined OM Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost - Nominal (cents/kWh) -- Real (cents/kWh) Non-Mining Loads ($aillions): Fuel Costs Variable O& Fixed C8" Capital Costs (existing syster Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) ~~ Real (cents/kWh) 1990 Qmennss= saccesss szessess szessee= 9.3 277,000 3.4 3.4 0.0 6.2 0.4 2.6 0.0 0.0 0.0 9.3 277,000 1994 536,618 49 4 0.0 6.9 0.4 2.6 0.0 0.0 0.0 9.9 302,618 nw 1995 544,135 310,155 Cases Forecast: 1998 eeeeecss ssesess= 11.6 12.4 10.3 10.8 0.5 0.5 2.6 2.6 1.2 1.2 0.4 0.4 1.8 1.8 28.5 29.3 544,973 5.2 3.4 4.2 41 0.0 9.0 7A TA 0.5 0.5 2.6 2.6 0.0 0.0 0.0 0.0 6.0 0.0 10.1 10.2 310,973 33 3.3 2.6 25 nw ay 1998 “0.0 1.2 0.5 2.6 0.0 0.0 0.0 10.3 312,615 3.3 2.3 JUNEAU 20-YEAR POWER SUPPLY PLAN Base Case (Diesel) Plan 1999 14.6 10.5 0.6 2.6 1.2 0.4 1.8 M7 547,239 0.0 10.3 313,239 3.3 2.2 2000 15.4 10.6 0.6 2.6 1,2 0.8 1.8 32.6 547,866 6.0 3.8 0.0 7.2 0.6 2.6 0.0 0.0 0.0 10.4 313,866 2001 16.6 10.6 0.6 2.6 1.2 0.4 1.8 33.9 548,494 0.0 7.2 0.6 2.6 9.0 0.0 0.0 10.4 314,498 ee 2002 = aescs: eenoeosS BREEN Ss 1.8 SSoeENS eoneono 0.0 2003 1.8 35.2 36.5 549,021 549,444 0.0 7.2 0.7 2.6 0.0 0.0 0.0 10.5 10.5" 315,021 315,444 - 0.0 2008 2003 20.4 21.7 10.8 10.8 0.7 0.7 2.6 2.6 1.2 1.2 04 O48 1.8 1.8 7.9 39.2 349,776 550,107 - 6.9 MA 37 3.7 0.0 1.3 0.7 2.6 0.0 0.0 345,776 316,107 2006 Szsster eserreza 23.0 10.9 0.7 2.6 1.2 0.4 18 40.6 350,439 14 37 6.0 1.3 0.7 2.6 0.0 0.0 0.0 10.6 316,439 34 17 08-Mar-90 01:07 PN Run Date: Run Times anagengegagesasaecsacasscegssessaees % POWRPLAN {c) 1990 by CH2M HILL $ Segrseegegssesecsececsessecsaceseses Sumaer (May - Septeaber) Energy Requireaents (MWh) Energy Dispatch (MWh) {1) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Annex/Cartson Creek No.t (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 845 (6) Caterpillar 3612 diesel (7) GN EMD diesel (8) Existing Diesel: Gas Turbines Lemon Creek w fuke Bay e Gold Creek ib TOTAL Cost ($. Millions) Capital Fixed . Variable Fuel ‘ TOTAL 2008 2009 Sazesees rateeees se: JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Forecast: AJ Mine 2010 2011 2012 2013 2018 2015 2086 2 szees: stasrsss sesssee= 242,740 212,913 213,122 213,222 213,122 213,122 213,122 213,122 213,122 15,577 15,377 23,258 23,254 3,408 3,488 118,108 118,108 0 0 0 0 0 0 0 0 52,030 $2,127 0 0 0 0 0 0 0 0 212,457 212,554 1.0 1.0 0.3 0.4 3.9 39 8.7 9.2 Seeezess seszaess 14.0 14.5 15,577 15,577 15,577 15,577 15,877 15,877 15,577 23,254 23,254 23,254 23,254 23,258 23,254 23,254 3,488 3,488 «(3,488 «3,888 «3,408 3,488 3,408 118,108 118,108 118,108 118,208 118,08 116,108 118,108 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 52,262 $2,262 $2,262 52,262 $2,262 52,262 52,262 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 es: See 22 srze|sss =z 212,689 212,689 212,689 212,689 212,689 212,689 1.0 1.0 1.0 0.0 0.0 0.0 0.4 0.4 0.8 0.4 0.4 0.5 0.5 39 4.0 4.0 4.0 4.0 4d al 9.7 10.1 10.6 Md 11.6 12.1 12.6 ESess sesti 15.0 15.5 16.0 15.5 16.1 16.6 17.2 Base Case (Diesel) Plan 2017 2018 2019 2020 2024 2022-2023 2024 2025 fessese= = anesz: Sezceaes tzssazex 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 213,122 15,577 15,577 15,577 15,577 15,577 15,577 15,377 15,377 13,377 23,254 23,254 23,254 23,254 23,258 23,258 23,254 23,258 23,254 3,488 3,488 3,488 «3,488 «3,488 «3,488 3,488 3,488) 3,488 118,108 118,108 118,108 £16,108 118,08 118,108 118,108 118,108 118,108 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $2,262 52,262 52,262 52,262 52,262 52262 52,262 52,262 52,262 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 aa 4.2 4.2 4.3 4.3 4.3 44 44 45 13.2 13.8 14.4 Wl 15.7 16.5 17.2 18.0 18.8 17.9 18.5 19.2 19.9 20.6. 2h4 22.2 BA 24.0 €T-d Run Date: 08-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tises 01207 PH Case: Base Case (Diesel) Plan Forecast: Ad Mine Saeensasencasesecesccecscscsscsceses % POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995. 1996 1997 1998 1999 2000 = 2001 2002-2003, -S 2008 )=— «2008 = 2008 = 2007 Ragasersacgecesaaesecsacogsacscesses = fensess= sascanss 2: SEE nessecsz eaezeazs Sumner (May - Septeaber) Energy Requireaents (MWh) 97,781 101,332 104,918 202,073 205,111 208,149 208,618 209,088 209,561 209,958 210,354 210,750 211,110 211,430 241,718 211,998 212,281 212,49 Energy Dispatch (MWh) () AELP Hydro: Annex Creek 15,577 15,577) 15,577 15,577) 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 85,577 15,577 15,877 15,577 15,577 Salaon Creek 23,25 23,258 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,258 23,254 23,254 23,254 23,254 23,254 Gold Creek 3,488 «3,488 = 3,488 = 3,488 = 3,488 = 3,488) = 3,488 = 3,488 = 3,888 = 3,488 = 3,488 |= 3,488 = 3,488 = 3,4BB 3,888 = 3,488 = 3,40B 3,488 (2) Snettishaa/Crater Lake 56,571 60,083 63,629 118,108 118,108 128,108 316,108 118,108 126,108 128,108 128,108 118,108 118,108 118,108 116,108 118,208 116,108 118,108 (3) Annex/Carlson Creek No.d 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (4) Crater Lake Elev. 1034 0 Q 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 (3) Long Lake Elev. 845 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 - 0 0 0 0 0 0 0 6 0 0 0 (7) 6M EMD diesel 0 0 0 (42,468 45,440 48,413 $8,808 49,203 99,401 89,923 50,245 50,566 50,850 51,095 51,304 51,512 51,721 51,856 (8) Existing Diesel: Gas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Lemon Creek 0 o 0 0 0 0 0 0 0 0 0 Q 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ® peesssss =: 2 22 TOTAL 98,889 102,402 105,947 202,894 205,867 208,840 209,234 209,630 210,027 “240,349 210,671 210,993 211,277 211,522 211,730 211,939 212,148 212,283 Cost ($ Millions) - Capital 0.0 0.0 0.0 0.6 0.5 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Fixed 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.3 03 03 | 03 0.3 0.3 Variable 1.6 4.7 1.8 36 3.6 3.6 3.6 37 37 37 37 37 38 3.8 3a) (3.8 3.8 3g Fuel 0.0 0.0 0.0 3.0 4 3.8 4 4.3 4.6 9 5.2 5.6 6.0 6.5° 6.9 13 7.8 a3 TOTAL 1.8 Lg 2.0 13 17 8.6 8.9 9.5 9.8 10.1 10.6 1.0 11.5 12.0 12.5 13.0 13.4 cT-a Run Date: 08-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tine: = 01:07 PH Case: Base Case (Diesel) Plan Forecast: AJ Mine Meagereageasercacersaceasessessesees , $ POWRPLAN (c} 1990 by CH2M HILL 8 » 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Segscengoceecesacaescsseseseesesesse Eom Eszcrces Winter (October - April) sreczenz: Energy Requirements (HWh) 338,085 337,983 337,885 337,885 337,885 337,885 337,805 337,885 337,885 337,885 337,885 337,885 337,885 337,885 337,885 337,883 337,885 337,805 Energy Dispatch (MWh) (1) AELP Hydro: Annex Creek 7,983 7,943 7,943 7,943 7,943 7,943 7,943 7,943 7,947,943 7,947,983 7,9KS—7,9HS— 7,947,943 79S 7,983 Saleon Creek 11,786 11,786 11,786 11,786 11,785 18,786 11,786 11,786 11,786 11,786 11,785 11,785 11,786 11,786 11,786 911,786 1,786 11,786 Gold Creek 1,912 1,912 2,912 1,912 1,912 1,912 APEZ 912A NZ NZ 2912 NZ 19121982 1,912,912 912 1,912 (2) Snettishae/Crater Lake 212,727 242,727 212,727 212,727 212,727 212,727 242,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 (3) Annex/Carlson Creek No.d 0 0 0 0 0 0 0 0 0 0 0 » 0 0 0 0 0 0 0 (yy Crater Lake Elev. 1034 Q 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 (5) Long Lake Elev. 845 a 0 0 0 0 0 0 0 O° 0 0 0 0 0 0 0 - 0 9 {6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 {7) 6H EMD diesel 102,454 102,375 102,342 102,342 102,342 102,342 102,342 102,342 102,342 102,382 102,342 102,342 102,342 102,382 102,342 102,342 102,342 102,342 (8) Existing Diesel: Sas Turbines 4,543 1,567 1,607 1,607 1,607 1,607 1,807 1,607 1,607 1,607,607 1,607 1,607 1,607 1,607 1,607 1,607 1,807 Lemon Creek 0 0 0 0 0 9 0 0 0 9 0 0 0 0 0 9 0 Q fluke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 9 0 0 0 0 0 a 0 0 0 0 0 seesese eszgcsse ==: TOTAL 338,368 338,312 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 338,318 Cost ($ Millions) Capital Fixed Variable Fuel TOTAL ' TTt-@ Run Date: 08-Mar-90 Run Times 01:07 PM Ouereseereecasoecegassseasecssgssgss $ POWRPLAN (c) 1990 by CH2M HILL & Ceeeeceseeeeaeessesoncessgeescessess Winter (October - April) Energy Requireaents (MWh) Energy Dispatch (MWh) a) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Annex/Carlson Creek No! 4) Crater Lake Elev. 1034 3) Long Lake Elev, 845 (5) Caterpillar 3612 diesel (7) 6M END diesel (8) Existing Diesels Bas Turbines Lemon Creek Auke Bay Gold Creek TOTAL Cost (8 Millions) TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Case: - Base Case (Diesel) Plan Forecast: AJ Mine 1990 1991 1992 1993 1998 1995 1996 1997 1998 1999 2000. 2001 2002 2003 2004 2005 2006 2007 paneress resssens esocress seesess: gesrezeo ecesesez 179,219 185,391 191,624 327,011 332,507 336,007 336,355 336,699 337,054 337,281 337,512 337,743 337,911 338,014 338,062 338,110 338,158 338,092 7,983 7,943 7,983 7,983 7,943_—7,94S—-7,943 7,943 7,7HS—7,94B_—7,9HS—7,9AS_—7,943_—7,943—-7,943 7,943 7,983 7,948 11,786 11,786 14,786 11,786 11,786 12,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,785 11,786 1,912 1,912 1,912 1,912 1,982 1,912 1,912 1,912 191219121912 19121912 1,912 1,912,912 An? 4,912 156,489 162679 168,951 212,727 212,727 212,727 212,727 242,727 212,727 242,727 2124727 212,727 212,727 2124727 212,727 202,727 212,727 212,727 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 9 9 0 0 0 0 0 0 0 9 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 6 0 0 0 91,821 96,382 100,538 100,879 101,257 101,557 101,736 101,918 102,097 102,235 102,325 102,376 102,426 102,476 102,443 0 0 6 0 0 409 470 530 6b! 784 90B «1,032 1,139 = 1,227 1,301 1,378 1,447 1,488 0 0 0 0 0 G 0 0 0 9 0 9 0 0 0 0 0 0 9 9 0 0 0 9 0 9 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 0 9 0 0 9 0 0 0 ses: 178,111 164,321 190,593 326,190 330,751 335,316 335,739 334,158 334,508 336,890 337,195 337,501 337,744 337,922 338,085 338,169 330,292 338,300 LA 05 MW 16.0 ‘ Run Date: 08-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Times = 01:07 PH Caser Base Case (Diesel) Phan Forecast: AJ Mine Onecegeaeecacgetseseseessassecscetet $ POWRPLAM (c) 1990 by CH2M HILL & 2008 = -2009 20102011 2012 2013 2014 2015 2086 = 2017, 2018 = 2019 = 2020» 2021S 2022S 2023S 2028 = 2028 HEReeseegeeeeeececececececgesogssees eses e2: seseeses Suanary of Results (after conservation) Peak Demand (MW) -- Peak Demand 92.5 92.6 92.7 92.7 92.7 92.7 92.7 92.7 92.7 92.7 9247926792679 929,792 0D Peak Plus Reserve Requireaent . 166.7 166.8 = 166.9 166.9 = 166.9 166.9 166.9 166.9 166.9 166.9 166.9 186.9166 186.9 168.9 166.9 165.9 188 Installed Capacity 169.7 169.7 169.7 169.7 189.7 969.7 169.7 189.7 169.7 169.7 169.7 189.7 169.7 169.7 169.7 169.7«189.7 189.7 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 Energy Requirements (AWh} 550,825 550,863 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 531,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 Fire Capability of Installed Units (MWa) = 126.0 = 126.2 = 12,2 126.2 126.2 126.2 126.2261 26D 2B LZ ZBL 1268262 2B A262 128 New Capacity to Meet Energy Req’ts (MM) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -- (i) AELP Hydro: . . . Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,080 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,080 35,040 Gold Creek 5,400 5,400 = 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,800 5,400 5,400 5,400 (2) Snettishae/Crater Lake 330,836 330,836 330,835 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,036 wo 3% Annex/Carison Creek Not 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 rv (4) Crater Lake Elev. 1038 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o (3) Long Lake Elev, 845 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (5) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (7) 6H END diesel 154,404 154,502 154,604 154,404 154,604 154,608 154,608 154,608 154,604 154,604 154,604 154,604 154,604 154,604 154,608 154,608 154,608 154,608 (8) Existing Diesel: Gas Turbines 1,545 1,567 1,607 1,807 1,607 1,607 1,607 1,607 1,607 1,607 1,607 1,607 1,607 1,607 1,607 1,607 1,807 1,807 Lean Creek 0 0 0 0 0 0 0 0 _o 0 9 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 6 0 0 0 9 0 0 0 0 0 9 Gold Creek 0 0 9 9 0 0 0 0 6 0 0 0 0 0 0 0 0 0 seazsxts seeeass: 2 ee: 22 sas est: TOTAL $50,825 550,865 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 nn 0 0 0 Cost: ($ Millions) Capital Fixed Variable Fuel TOTAL Met Present Value (1990 - 2050) New Resources Added (MW): Annex/Carison Creek No.1 Crater Lake Elev. 1034 Long Lake Elev, 845 Caterpillar 3612 diesel 6M EMD diesel 6-a Run Date: 08-Mar-90 Run Vines 01:07 PM Ogeneneegecegceceseseeasesacccsccets $ POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 Seaseancacaecescscsecsececsscssesses Stassess exsssers sseessce 22: Suaeary of Results {after conservation): Peak Demand (MW) ssesezsss: esse Peak Desand 31.3 Peak Plus Reserve Requiresent 93.6 Installed Capacity 131.5 Additional Required Capacity 0.0 Energy Requireaents (MWh) 277,000 Fire Capability of Installed Units (MWa) - 103.6 Wen Capacity to Meet Energy Req’ts (MW) 0.0 Energy Dispatch (MWh) -- q) AELP Hydro: 32.8 34.2 89.5 96.3 99.4 = 163.7 131.5 151.5 180.5 0.0 0.0 0.0 286,723. 296,540 529,088 103.6 = 103.6 = 126.1 0.0 0.0 0.0 Annex Creek 23,520 23,520 23,520 23,520 Salaon Creek . 35,040 35,080 35,040 35,040 Gold Creek 5,400 5,400 §=— 5,400 5,400 (2) Snettishae/Crater Lake 213,040 222,763 232,580 330,836 (3) Annex/Carlson Creek Nod 0 0 0 0 (4) Crater Lake Elev. 1034 0 0 0 0 (5) Long Lake Elev. B43 0 0 0 0 {6) Caterpillar 3612 diesel 0 0 0 0 (7) 6H END diesel 0 0 0 134,288 (8) Existing Diesel: Gas Turbines 0 0 0 0 Leaon Creek Q 0 0 0 Auke Bay 0 0 0 0 Gold Creek 0 0 0 0 s TOTAL 277,000 286,723 296,540 529,084 Unserved Energy 0 0 0 0 Cost {8 Millions) Capital 0.0 0.0 0.0 La Fixed 04 0.5 0.5 0.5 Variable 6.2 6.5 6.7 0.2 Fuel 0.0 0.0 0.0 9.3 = TOTAL 6.7 7.0" Wet Present Value (1790 - 2050) $453.5 aillion JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case (Diesel) Plan Forecast: Ad Mine 1994 1995 1996 1997 1998 1999 2000 2004 2002 2003 2008 2003 2006 2007 Q2RE Srarsese se: 90.5 -- 91.6 1.5 18 8 W.3 W.3 WS 91.6 18 92.0 9241 92.3 92.4 164.7 165.8 165.7 165.6 © 165.6 = 165.5 185.5 165.7 185.8 = 166.0 166.2 16.3 BAS GBA 169.7 $69.7 189.7 169.7 189.7 169.7 189.7 169.7 189.7 189.7 189.7) 189.7 189.7 189.7 6.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 536,618 544,155 544,973 545,788 546,615 547,237 547,866 548,494 549,021 549,444 549,776 550,107 550,437 550,583 126.1 226.2 2262 126.2 126126 126.2126 2612812626 2B 2B 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 35,040 35,080 35,040 35,040 35,040 35,040 35,080 35,040 35,040 35,040 35,040 35,080 35,080 35,040 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 330,836 330,836 330,836 330,836 330,636 330,836 330,836 330,836 330,636 330,836 330,836 330,835 330,836 330,836 0 0 0 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 6 0 0 0 6 0 0 0 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 144,822 148,951 149,707 150,462 151,158 151,659 152,162 152,665 153,086 153,421 153,679 153,938 154,197 154,299 0 409 470 330 bt 784 GOB = 1,032 1,139 1,227 1,301 1,378,447, BB 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 536,618 544,155 544,973 545,788 546,615 547,239 549,776 “550,107 550,583 0 0 0 0 0 0 9 0 0 0 0 0 0 0 1.3 24 24 24 24 24 24 24 0.4 0.5 0.5 0.5 0.6 0.6 0.6 0.8 10.4 10.4 11.0 24.2 eesessee 37.0384 Annex/Carlson Creek No.1 Crater Lake Elev, 1034 Long Lake Elev, 845 Caterpillar 3612 diesel GM EMD diesel 29.0 Run Date: 09-Mar-90 Run Vises = 03:12 PM Shegensgsasesasesasosssesecececscss # POWRPLAN {c) 1990 by CH2M HILL $ sapageaagcagccegssgcgagrsgecaccesaee BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs Variable O&M Fixed O&M Capital Costs {existing systes) Depreciation Expense (new units} Property Taxes (new units) Interest Expense (new units) Total Energy Requirements (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) -~ Real (cents/kWh) Non-Mining Loads {$nillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense {new units) Total Energy Requiresents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) -- Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case Forecast: Base 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 0.0 0.0 9.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 9.0 94 9.2 9.2 9.2 9.2 9.2 9.2 12 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 %.2 1.0 1.0 1a 1 1,2 1.2 1.3 1.3 1.4 14 Ls 1.60 ° 4.7 17 1.8 1.9 2.0 24 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0.0 = 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0, 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.0 322,000 323,799 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 3.9 3g 39 4.0 4.0 4.0 4.0 4.0 4.0 4 41 4a Ad 4a 4.2 4.2 4.2 4.2 1.8 17 1.6 1.6 1.5 14 14 1.3 1.3 1.2 1.2 1a Md il 1.0 1.0 0.9 0.9 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 aA 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 1.0 1.0 1d Ml 1,2 1.2 1.3 1.3 14 14 1.5 1.6 17 1.7 1.8 1g 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0.0 0.0 6.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 12.6 12.7 12.8 12.9 12.9 13.0 13.0 13.1 13.1 13.2 3.3 13.3 13.4 BS 13.6 0 13.6 13.7 1 322,000 323,799 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598 325,598’ 325,598 325,598 325,598 325,598 4,2 4.2 4.2 4.2 4.0 4.0 4.0 4.0 4. 1 1.6 1 al 1.0 1.0 09 0.9 1.5 14 14 —= —- — 09-Mar-90 03:12 PH Run Date: Run Tines Hegngsergcecnsaesasesassecssecsssss $ POWRPLAN (c) 1990 by CH2M HILL & ANgeecegageaasosagcessassssseecssce BUS BAR COST SECTION: Average Costs (Saillions): Fuel Costs Variable Ot Fixed OM Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (Mh) Average Bus Bar Cost -- Nominal (cents/kWh) -- Real (cents/kWh) Won-Mining Loads (Smillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) -- Real (cents/kWh) 0.5 1990 1991 sreseess ©: 0.0 0.0 6.2 6.4 0.8 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 9.3 9.4 277,000 280,598 34 34 3.4 3.2 0.0 0.0 6.2 6.4 0.4 0.5 26 2.6 0.0 0.0 0.0 6.0 0.0 0.0 9.3 94 277,000 280,598 34 34 34 3.2 1992 easesscs 283,502 1993 1994 1995 Ch 7879 (BO 05 0.5 06 2b | 26 2b 0.0 0.0 0.0 00 ©6000 0.0 0.0 0.0 10.9 0 AL 286,402 289,701 292,402 360063838 3300«420~°~«CM 0.0 0.0 0.0 718079 BO 05 05 0.6 260 0 26 2b 00° 0.0 © 0.0 0.0 860.000 0.0 860.000 10.9 11.0 ML 286,402 289,701 292,402 3.8 3.8 3.8 “33 3.2 3a JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Base Case Forecast: Base 1996 1997 1998 1999 0.0 0.0 0.0 0 81 8.2 8.3 8 0.6 0.6 0.6 0 26 2.6 2.6 2 0.0 0.0 0.0 0 0.0 0.0 0.0 0 0.0 9.0 0.0 0.0 11.3 11.4 11.5 iM. 6 295,099 297,598 300,300 302,799 3.8 3.8 3.8 3 29 2.8 2.7 2 0.0 0.0 0.0 8.1 8.2 8.3 0.6 0.6 0.6 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.0 0.0 295,099 297,598 300,300 302,799 0.0 11,7 305,201 3.8 25 305,201 2008 2002 2003 0.0 8.7 0.8 2.6 0.0 0.0 0.0 0.0 0.0 8.5 8.6 0.7 0.7 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 11.8 U9 12.1 307,502 309,701 311,902 3.8 24 =o s ue 2004 2005 2006 2007 0.0 © 00 Be BB Bo 90 . 09 09 2b 2b) 2b Ob 00 0.0 0000 0.0 80.0 ©=—0 0 0.0 12.5 320,099 B98 wt 20 0.0 8.8 0.8 2b 0.0 0.0 . 0.0 12.2 12.3 12.4 12.3 314,099 316,099 318,097 320,099 9 39 ug 39 1 2.0 19 1.8 9- Run Dates 09-Har-90 Run Times = 03312 PH Onenseseatsasccesasascccsonssscesees $ POWRPLAN (c) 1990 by CH2M HILL Agreeesesecerssesssssecocesssscscees er (May - Septesber) Energy Requirements (MWh) Energy Dispatch (MWh) a) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishas/Crater Lake (3) Annex/Carlson Creek No.1 {4) Crater Lake Elev. 1034 (3) Long Lake Elev, 845 (6) Caterpillar 3612 diesel (7) 6H EMD diesel (8) Existing Diesel: fas Turbines Lenon Creek fluke Bay Gold Creek TOTAL Cost {$ Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Base Case Forecast: Base 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2024 2022 2023 2024 2025 ons saRi 143,666 114,301 114,937 114,937 114,937 114,937 124,937 114,937 114,937 218,937 114,937 $14,937 214,937 114,937 114,937 114,937 114,937 114,937 15,577 15,377 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,377 15,577 23,254 23,254 23,254 23,258 23,254 23,254 23,254 23,256 23,254 23,254 23,258 23,254 23,254 23,254. 23,254 23,256 23,254 23,254 3,408 «3,488 «3,008 «3,488 «3,408 «© 3,488 «3,480 © 3,408 «3,488 3,488) 3,488 3,488 | 3,488 3,488 3,488 $= 3,488 3,480 3,408 72,636 73,279 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 73,921 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 a 9 0 0 0 0 0 0 0 0 0 0 0 9 0 0 6 9 0 “0 0 0 9 0 0 9 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 9 0 0 0 0 0 0 0 * 0 0 0 0 Q 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 9 4 seaceess eeeeses ss2seee: Be: = 114,954 115,597 116,239 116,239 “116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 116,239 s-a 09-Mar-90 03:12 PH Run Date: Run Tine: Segngesocasassscccesanesssessseseses @ POWRPLAN (c) 1990 by CH2M HILL $ Henggegcssegeassescecsccgceseecessss Susser (May - Septeaber) pecs: Energy Requireaents (MWh) * Energy Dispatch (MWh) ) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Annex/Carlson Creek No.t (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 845 (6) Caterpillar 3612 diesel (7) GM EMD diesel (8) Existing Diesel: Bas Turbines Leaon Creek fuke Bay Gold Creek TOTAL Cost ($ Millions) Capital Fixed Variable Fuel TOTAL 1990 97,781 15,577 23,254 3,488 56,571 eooo 98,889 0.0 0.2 1.6 0.0 SUNEAU 20-YEAR POWER SUPPLY PLAN Cases Base Case Forecast: Base 1991 1992 1993 1994 1995 199% 1997 1998 1999 2000 2001 2002 2003 2008 2005 2006 = 2007 iia @ acesesse 99,052 100,077 101,099 102,265 103,217 104,171 105,053 106,006 106,888 107,736 108,549 £09,325 110,101 110,878 111,584 112,290 112,996 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,977 15,577 15,577 23,254 23,254 «23,254 «23,254 «23,254 «23,254 23,254 «23,254 923,254 923,254 923,254 923,254 923,254 23,254 «23,258 923,254 23,254 3,488 «3,488 = «3,488 = 3,488 = 3,488 = 3,488 893,488 = 3,488 = 3, 48R | 3,488 = 3,488 93,488 = 3, KBB 3,488) = 3,488 = 3,488 3,488 57,856 58,893 59,927 61,105 62,069 63,033 63,925 64,890 65,782 66,638 67,461 68,245 69,031 69,816 70,530 71,244 71,958 0 9 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 9 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 9 0 9 0 0 0 9 0 Q 0 0 0 0 0 0 0 0 0 9 9 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 9 0 0 9 0 0 0 0 eae se es! 222 100,174 101,221 102,243 103,423 104,387 105,351 106,243 207,208 108,100 108,956 109,779 120,563 111,349 112,134 112,848 113,562 114,276 p-a 09-Mar-90 03:12 PK Run Dates Run Tiee: Aeggngceseesesetecesesecsececesecste % POWRPLAN {c) 1990 by CH2M HILL $ Oneseseceecaesesegcacsesessscsessees Winter (October - April Energy Requiresents (MWh) Energy Dispatch (MWh) mw AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake (3) Annex/Cartson Creek No.t (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 645 {6) Caterpillar 3612 diesel ) 6M END diesel (8) Existing Diesel: fas Turbines Lemon Creek fuke Bay Gold Creek TOTAL Cost ($ Millions) TOTAL 2008 2009 2010 2011 208,334 209,498 210,661 210,661 7,983 7,983 7,983 7,943 11,785 11,786 11,786 11,786 1,912 1,912 1,912 1,912 185,404 186,560 187,717 187,717 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 70 0 207,046 208,202 209,359 209,359 JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Base Case Forecast: Base 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 210,661 210,661 210,661 210,661 210,66! 210,661 210,661 210,661 210,661 210,661 210,661 210,661 210,661 210,661 7,943 7,983 7,983 -7,943—7,9837,983 7,943 7,943 7,983 7,983 7,943 «7,943 7,983 7,983 11,78 11,786 11,785 11,786 11,786 11,786 11,785 11,786 11,786 11,786 11,786 11,786 11,786 11,788 1,912 1,982 1,912 1,912 1,912 1,912 1,912 1,912 1,921,912 1,912 1,912 1,912 1,912 187,717 187,717 187,717 187,717 187,717 187,717 187,717 187,717 187,717 107,717 187,717 187,717 187,717 187,717 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 “0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o -0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 0 0 0 0 0 0 0 0 0 0 0 0 0. 0 0 0 0 0 0 0 0 0 0 0 0 o <0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 209,359 209,359 209,359 207,359 209,359 207,357 209,357 209,357 209,357 209,359 209,357 209,359 209,359 209,357 0.0 0.0 0.0 0.0 0.0 0.0 0 0.7 0.7 0.8 0.8 0.8 0.9 0. - 6 0 €- Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiees 03312 PM Case: Base Case Forecast: Base Heeeeaggcaseagcssgsasecagsssecsseese $ POWRPLAN (c) 1990 by CH2M HILL 8 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Oegegareccercscsessaceescocecssecsss ees: Winter (October - April) Energy Requirements (MWh) 179,219 181,546 183,825 185,303 187,436 189,185 190,928 192,545 194,294 195,911 197,465 198,953 200,376 201,801 203,224 204,515 205,809 207,103 Energy Dispatch (MWh) (1) AELP Hydro: Annex Creek 7,937,943 7,943 7S 7,943 7494S 7947947947, 9KT—7,943— 7,983 7H 7,943 7,943—7,943— 7,943 7,943 Saleon Creek 11,786 11,786 11,786 11,786 11,786 11,786 11,785 11,786 11,786 11,786 11,786 11,786 12,786 11,786 11,786 11,786 11,786 11,786 Bold Creek 1,912 1,912 1,912 1,912 1,912 1,912,912 1,912 1,912 1,912 1,912 1,912 1,912 1,912,912 1,912,902 A982 (2) Snettishan/Crater Lake 156,469 158,782 160,649 162,515 164,636 166,373 168,106 169,713 171,450 173,057 174,603 176,081 177,496 178,911 180,323 181,609 182,895 184,181 (3) Annex/Carlson Creek No.1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (4) Crater Lake Elev. 1034 0 0 0 0 0 0 0 0 (3) Long Lake Elev. 845 0 0 0 0 0 0 9 0 0 9 0 9 9 0 0 0 0 0 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 7 GM EMD diesel 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 (8) Existing Diesel: Gas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Leon Creek 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 Auke Bay 0 0 0 0 0 0 0 9 0 9 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 TOTAL 178,111 180,424 182,291 184,157 186,276 188,015 189,748 191,355 193,092 194,699 196,245 197,723 199,138 200,553 201,965 203,251 204,537 205,823 Cost ($ Millions) 0.0 Capital 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 Fixed 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.8 04 0.4 05 °05 ° 05 0.5 0.5 Variable 4.6 4.7 3.7 5.7 5.8 5.9 5.9 6.0 6.0 4 bf 6.2 6.3 63° 64 6.4 64 6.5 Fuel 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 TOTAL 09-Mar-90 03:12 PH Run Date: Run Tise: Onsegseasaceesecegssseeessasecessess $ POWRPLAN (c) 1990 by CH2M HILL 8 Hgeeeeagccagsaeeaessssesesesssscesss ary of Results (after conservation): (KW) =~ Peak Deaand Peak Demand Peak Plus Reserve Requireaent Installed Capacity Additional Required Capacity Energy Requireaents (MWh) Fire Capability of Installed Units (MWa) * New Capacity to Meet Energy Req'ts (Mi) Energy Dispatch {MWh} -- (4) AELP Hydro: Annex Creek Salaon Creek Gold Creek wo (2) Snettishan/Crater Lake NS (3) Annex/Carlson Creek No.! 4) Crater Lake Elev. 1034 (5) Long Lake Elev. 645 (6) Caterpillar 3612 diesel (7) 6M EMD diese! (8) Existing Diesel: Gas Turbines Lenon Creek . fuke Bay Gold Creek TOTAL > Unserved Energy Cost Millions} Capital Fixed Variable Fuel TOTAL Wet Present Value (1990 - 2050) New Resources Added (MN): Annex/Carison Creek No. Crater Lake Elev. 1034 Long Lake Elev. 845 Catervillar 3612 diesel 2008 2009 2010 2011 2012 2013 JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Forecast: Base 2014 2015 Base Case 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 36.0 103.0 151.5 0.0 322,000 103.6 0.0 23,520 35,040 5,400 258,040 eooce 0 0 0 0 322,000 56.3 103.6 151.5 0.0 323,799 103.6 9.0 23,520 35,040 5,400 259,839 e2oco 323,799 23,520 35,040 5,400 261,638 eoooeo 56.7 104.4 151.5 0.0 325,598 103.6 0.0 23,520 35,080 5,400 261,638 0 ecocoo 325,598 ocooo 56.7 104.4 151.5 0.0 325,598 103.6 0.0 23,520 35,080 5,400 261,638 0 cooe 56.7 104.4 151.5 9.0 325,598 103.6 0.0 23,520 35,040 5,400 261,38 0 coofo 0 0 0 0 325,598 56.7 56.7 108.4 104.4 151.5 151.5 0.0 0.0 325,598 325,598 103.6 103.6 i ) 23,520 23,520 35,040 35,040 5,400 5,400 261,638 261,638 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 325,598 325,598 0 0 0.0 0.0 1.3 9.2 0.0 56.7 104.8 151.5 0.0 325,598 103. 6 9.0 23,520 35,080 5,400 261,638 coo coco 325,598 56.7 104.4 151.5 0.0 325,598 103.5 0.0 23,520 35,040 5,400 261,638 ecooo ecooo 325,598 56.7 104.4 151.5 9.0 325,598 103.6 0.0 23,520 35,040 5,400 261,638 coooe cooeo 325,598 356.7 104.4 151.5 0.0 325,598 103.6 0.0 23,520 35,040 5,400 261,638 0 coco 325,598 56.7 104.4 151.5 0.0 325,598 103. 6 9.0 23,520 35,080 5,400 261,638 0 ocooo coco 325,598 56.7 104.4 151.5 0.0 325,598 103.6 0.0 23,520 35,040 5,400 261,638 coo eooo 325,598 56.7 104.4 151.5 0.0 325,598 103.6 0.0 23,520 35,040 5,400 261 ,638 0 coco coco 325,598 56.7 104.4 151.5 0.0 325,598 103.6 0.0 23,520 35,040 5,400 21 ,638 0 cooo 56.7 104.4 131.5 0.0 325,598 103.6 0.0 23,520 35,040 5,400 261,638 0 coco ecco 325,598 0 0.0 56.7 104.4 13.5 9.0 325,598 103.6 0.0 23,520 35,080 5,400 261,38 eoco 325,598 0 T-@ Run Date: 09-Mar-90 Run Tiger = 03:12 PH Sageeegeessecegeessscstecsecsssassss $ POWRPLAN (c) 1990 by CH2M HILL 8 1990 Oneasoneceeocaasesececcessessessesse =: Summary of Results (after conservation Peak Demand (KM Peak Desand 31.3 Peak Plus Reserve Requiresent 93.6 Installed Capacity 151.5 Additional Required Capacity 0.0 Energy Requireaents (MWh) 277,000 Fire Capability of Installed Units (MWa) = 103.6 New Capacity to Meet Energy Req'ts (MW) 0.0 Energy Dispatch (MWh) -~ (1) AELP Hydro: Annex Creek 23,520 Saleon Creek 35,040 Gold Creek 5,400 (2) Snettishaa/Crater Lake 213,040 3) Annex/Carlson Creek No.1 0 (4) Crater Lake Elev. 1034 0 (5) Long Lake Elev. 645 0 (8) Caterpillar 3612 diesel 0 (7) GM EMD diesel 0 (8) Existing Diesel: Gas Turbines 0 Leaon Creek 0 Auke Bay 0 Gold Creek 0 TOTAL 277,000 Unserved Energy 0 Cost ($ Millions) Capital . 0.0 Fixed 0.4 Variable 6.2 Fuel 0.0 515 94.0 131.5 0.0 280,598 103.6 0.0 23,520 35,080 5,400 218,638 0 ecooe 280,598 1992 31.5 94.0 131.5 0.0 283,502 103.6 0.0 23,520 35,040 5,400 219,542 0 coco cooo Be: 283,502 1993 31.6 94.2 A515 0.0 286,402 103.6 0.0 23,520 35,040 5,400 222,442 0 cooo coco 286, 402 1998 31.7 4 151.5 0.0 289,701 103.6 0.0 23,520 35,040 5,400 225,741 0 coco oooo 289,701 1995 St.7 44 151.5 0.0 292,402 103.6 0.0 23,520 35,080 5,400 228,442 0 ecco coco S 0.0 0.6 8.0 0.0 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: 1996 Base Case Forecast: Base 1997 295,099 | 297,598 103.6 103.8 0.0 © 0.0 23,520 23,520 35,080 35,080 5,400 5,400 231,139 233,638 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 295,099 297,598 0.0 0.6 8.1 0.0 0 1998 52.3 95.6 151.5 0.0 300,300 103.6 0.0 23,520 35,040 5,400 236,340 0 ecooo 300,300 1999 2000 52.6 96.2 151.5 # 0.0 302,799 305, 1 103. 3.6 0.0 23,520 23, 35,040 35 5,400 5 238,839 241 0 ecco ecoo 302,799 305, 52.8 96.6 51.5 0.0 9201 03.6 0.0 +520 1040 400 24 0 coco eoooo 9201 0.0 0.7 84 0.0 2001 53,2 74 151.5 0.0 307,502 103.6 0.0 23,520 35,040 5,400 243,542 0 eooo eooo 2002 2003 53.6 54.0 98.2 99.0 151.5 151.5 0.0 © 0.0 309,701 311,902 103.6 103.6 0.0 © 0.0 23,520 23,520 35,040 35,040 5,400 5,400 245,741 247,942 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 307,502 309,701 311,902 0 0.0 0.7 85 0.0 2008 345 100.0 151.5 0.0 314,099 103.6 0.0 23,520 35,040 5,400 250,139 coco ecoo 314,099 2005 54.8 100.6 151.5 0.0 314,099 103.6 0.0 23,520 35,080 5,400 252,139 0 ecooo 316,099 2006 55.2 101.4 151.5 0.0 318,099 103.6 0.0 23,520 35,040 5,400 254,139 cocoe coco 318,099 55.6 102.2 151.5 0.0 320,099 103.6 0.0 23,520 35,000 5,400 256,139 0 ecocoo eoco 320,099 6 0.0 0.9 9.0 0.0 TOTAL 6.7 Wet Present Value (£990 - 2050) 4.7 OL 9.2 99 New Resources Added (MM): Annex/Carlson Creek No.! Crater Lake Elev. 1034 Long Lake Elev. 645 Caterpillar 3612 diesel cp-d 7 Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Times 11:31 AN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Mine OOgeegaegsegeseagseeseegsegsagsoess $ POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2008 2007 MIM Seeseess seseerss eseseese sorsesss szeeeees seseeze= seeeeess esessezs eeesssss essssse2 sezzsez2 zzzs2222 Stesssss cesecese esassezs Suaser (Nay - Septeaber) aezzz! Energy Requirements (MWh) 97,781 101,332 104,916 202,073 205,111 208,149 208,618 209,088 209,56! 209,958 210,354 210,750 211,110 211,430 211,714 211,998 212,281 212,491 168) AELP Hydro: Annex Creek 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,877 15,577 15,577 15,577 Salaon Creek 23,254 23,254 «23,254 23,254 23,254 23,258 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 Gold Creek 3,488 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 |= 3,488 |= 3,488 | 3,488 = 3,488 3,488 3,488 (2) Snettishae/Crater Lake 56,571 60,083 63,629 118,108 118,108 116,108 118,108 118,108 118,108 118,108 118,108 116,108 118,108 118,108 118,108 118,108 116,108 118,108 (3) Dorothy/Long Lake Tunnel 0 0 0 0 0 15,009 15,009 15,009 15,009 15,009 15,007 15,009 15,009 15,009 15,009 15,009 15,009 15,009 (4) Crater Lake Elev. 1034 0 0 0 =1,017 1,017 1,017 1,017 1,017 1,017 1,017 1,017 1,017) 1,017 1,017 1,017 1,017 1,017 1,017 (3) Long Lake Elev. 845 0 0 0 4,557 4,557 4,557) 4,557 4,557) 4,557 4,557 4,557 4,557 4,557 4,557 4,557 4,557 4,557 4,557 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1) 6M EMD diesel 0 0 0 36,894 39,866 27,830 28,225 28,620 29,018 29,340 29,662 29,983 30,267 30,512 30,721 30,929 31,138 31,273 (8) Existing Diesel: Gas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Lemon Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Auke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 seestess sesseces sseseess eszecess eeeseerz sezsezes sezezees 2tssses2 2222 22 =: sess sszsssss TOTAL 98,889 102,402 105,947 202,894 205,867 208,840 209,234 209,630 210,027 210,349 210,671 210,993 211,277 211,522 211,730 211,939 212,148 212,283 Cost ($ Millions) Capital 0.0 0.0 0.0 1.8 1.8 3.8 4.0 4.0 4.0 4.0 4.0 0 4.0 4.0 Fixed 0.2 0.2. 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.3 0.3 3 0.3 04 Variable 1.6 1.7 1.8 3.6 3.6 3.6 3.6 3.6 3.6 37 3.7 7 3.8 3.8 Fuel 0.0 0.0 0.0 2.6 3.0 2.2 2.4 2.6 2.8 29 31 2 45 Sa sesessee rscsseze sersesss sesssss= gf Easeaess sesssscz sasctecr crsssss secssezs seszsess soz a sizzs seesssz2 TOTAL 1,8 Lg 2.0 8.1 8.6 99 10.2 10.4 10.6 10.8 11.0 U3 11.6 U9 12.3 12.6 12.9 13.3 bp-d Run Date: 09-Mar-90 Run Vises = 18:31 AN Magnenseseesecacsesssescsssssecsese $ POWRPLAN (c) 1990 by CH2M HILL 8 Woegeggrsagscecsceseggecaseceaesate Supaer (May - Septeaber) Energy Requiresents (Wh) Energy Dispatch (MWh) (t) AELP Hydros Annex Creek Salaon Creek Gold Creek (2) Snettisham/Crater Lake (3) Dorothy/Long Lake Tunnel (4) Crater Lake Elev. 1034 (5) Long Lake Elev. 845 (6) Caterpillar 3612 diesel 7) 6M EMD diesel (8) Existing Diesel: Gas Turbines Lenon Creek fAuke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL 2008 2009 2010 = 2011 2012 2013 Case: Forecast: 2014 JUNEAU 20-YEAR POWER SUPPLY PLAN Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. B45 Ad Mine 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 242,740 212,913 213,122 213,122 213,122 213,122 213,122 213,122 243,122 213,122 213,422 213,122 213,122 213,122 213,122 283,122 213,122 213,122 15,877 15,377 15,57 23,258 23,256 23,25: 3,488 3,408 3,48 118,108 118,108 118,10 15,009 15,009 15,00 1,017 1,017 1,08 7 4 B 8 9 7 4,557) 4,557 4,557 o 0 31,447 31,584 31,67! 0 0 0 0 212,457 212,554 212,68 0 9 ecco 9 15,577 23,254 3,488 118,108 15,009 1,017 4,557 0 31,679 ecco 212,689 15,577 23,254 3,488 15,577 23,254 3,488 15,577 23,254 3,488 118,108 118,108 116,108 15,009 1,017 4,557 0 31,879 0 9 9 0 15,009 1,017 4,557 0 31,679 coco 212,689 15,009 1,017 4,557 o 31,679 2 ses: 212,689 15,577 23,254 3,488 15,577 23,254 3,488 15,577 23,254 3,488 15,577 23,254 3,488 15,577 23,254 3,488 118,108 118,108 118,108 116,108 118, 108 15,009 1,017 4,557 0 31,679 0 9 0 0 15,009 1,017 4,557 31,679 coco 212,689 15,009 1,017 4,557 0 31,679 ecco 212,689 15,009 1,017 4,557 0 31,679 eocoo 15,009 1,017 4,557 0 31,679 ecco 212,689 212,889 15,577 23,254 3,488 118,108 118,108 15,009 1,017 4,597 0 31,679 eooo 212,689 15,577 23,254 3,488 15,009 1,017 4,557 0 31,679 coco 212,689 15,577 23,254 3,488 15,577 23,254 3,488 118,108 118,108 15,009 1,017 4,557 0 31,679 oooo 212,689 15,009 1,017 4,557 0 31,679 ecco 212,689 = 212,689 15,577 23,254 3,488 118, 108 15,007 1,017 4,557 0 31,879 coco 15,377 23,258 3,488 118, 108 15,009 1,017 4,587 0 31,679 “ Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Times 11:31 AN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Nine OOggeegnagsegeseasggssagsseeageaess $ POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Henggaggnggraggcgggggseggsgagsegcags Seseeses eseesess eeeeeess sescesss fessssz= seseeess esesesss sseesssz sessstss sessess ssseszs= sseeesss eeesese= =: SESE Erssssss secszcez seesesss BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs 0.0 0.0 0.0 8.3 94 7.6 8.1 8.6 A 9.6 10.4 Ml M9 12.7 13.5 14.4 15.2 Variable O&M 6.2 6.5 6.7 10.2 10.2 . 10.3 10.3 10.4 10.4 10.5 10.5 10.5 10.6 10.6 10.7 10.8 10.8 Fixed Ob 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 Capital Costs (existing systea) 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 Depreciation Expense (new units) 0.0 0.0 0.0 2d 2.1 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 Property Taxes (new units) 0.0 0.0 0.0 0.7 0.7 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 Interest Expense (new units) 0.0 0.0 0.0 33 3.3 1 1 1 19 1g 19 1.9 19 1 1 1 1 Total 9.3 27,7 28.9 wag 35.5 36.0 36.6 37.2 38.0 38.9 39. 40.7 M6 42.5 434 Energy Requiresents (MWh) 277,000 286,723 296,540 529,084 536,618 544,155 544,973 545,788 546,615 547,239 547,866 548,494 549,021 549,444 549,776 550,107 550,439 550,583 Average Bus Bar Cost -- Nominal (cents/kWh) 34 3.3 33 3.2 5.4 6.3 6.4 6.5 6.6 6.7 6.8 6.9 Tl . 7.6 17 WY ~- Real (cents/kWh) 3.4 3.2 3.0 4.6 4.5 5.0 49 4.8 4.6 4.5 44 4.3 4.2 4 39 3.8 37 Non-Mining Loads ($eillions): Fuel Costs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Variable O&n 6.2 6.5 6.7 69 7A 7A A 12 7.2 7.2 7.2 7.2 7.2 7.3 1.3 71.3 1.3 Fixed 08 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 Capital Costs (existing systea) 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 Depreciation Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Property Taxes (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Interest Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total 9.3 9.6 9.8 10.0 10.2 10.3 10.3 10.4 10.4 10.5 10.5 10.6 10.6 10.6 10.7 10.7 10.8 Energy Requireaents (MWh) 277,000 286,723 295,084 302,618 310,155 310,973 311,788 312,615 313,239 313,866 314,494 315,021 315,444 315,776 316,107 316,439 316,583 Average Bus Bar Cost ~~ Nominal (cents/kWh) ~~ Real (cents/kWh) 3.3 2.6 3.3 3 24 2. we ‘= = ne me me ne Be 3.3 34 21 2.0 ied to > eu => yu uy > 99-2 Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Thees = ts3i AM Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 645 Forecast: AJ Mine sagngcgnngngcaggcocaeeeseseeasseses # POWRPLAN (c} 1990 by CH2M HILL & 1990 1994 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Sdgegagaeenseesceccogcesessssacesess REEnascS seeeesss sHeeess 21 a2 S282 Sossacs eceresss Mining Loads ($aillions): Fuel Costs » 0.0 0.0 8.3 WA WA 16 8.1 8.6 9 9.6 10.4 Md Wg 12.7 13.5 44 15.2 Variable On 0.0 0.0 35 34 3.2 3.2 3.2 32 3.2 3.3 33 3.3 34 34 34 3S 35 Fixed ObM 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Capital Costs (existing systes) 0.0 0.0 0.0 0.0 (0.4) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Depreciation Expense (new units) 0.0 0.0 21 24 4.2 42 4.2 4.2 4,2 42 4.2 4.2 4.2 42 4.2 42 4.2 Property Taxes (new units) 0.0 0.0 0.7 0.7 1.8 1.8 1.8 18 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 18 Interest Expense (new units) 0.0 0.0 33 33 WwW 1 nw WwW we wy mw we WwW A 1 WwW ne Total 0.0 0.0 17.9 18.9 23.8 24.7 25.2 25.7 26.2 26.7 27,5 28.4 29.2 30.0 30.9 M7 32.6 Energy Requireaents (MWh) 0 0 0 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 Average Bus Bar Cost , -- Nominal (cents/kWh) WA WA WA 1? 8.1 10.2 10.5 10.8 11.05 9 11.2 M4 11.8 12.1 12.5 12.8 13.2 13.6 139 -- Real (cents/kWh) NA i) i) 6.7 6.8 8.2 Bt we nd 15 74 13 TA 7.0 69 6.8 6.7 4.6 Ly-d Run Date: 09-Mar-90 Run Tiees = 1231 AN Seageegggesesaasceascscsssessesssese © POWRPLAN (c) 1990 by CH2M HILL $ Ongrgassaeecesseacasgsassesegsssses BUS BAR COST SECTION: Average Costs (Smillions): Fuel Costs Variable O&M Fixed O84 Capital Costs {existing systen) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requirements (MWh) Average Bus Bar Cost ~~ Nominal (cents/kWh) -- Real (cents/kWh) Non-Mining Loads (Smillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) > Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: AJ Mine 2008 2009 2010 2011 2012 2083 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Bsssesss 16.0 16.8 17.7 18.5 19.3 20.2 21 22.0 23.0 24.0 25.1 26.3 27.4 28.7 30.0 3.3 32.7 M2 10.9 10.9 1.0 Md Mal 11.2 11.3 M4 M4 15 11.6 11.7 11.8 11.9 12.0 12.1 12.30 124 1.0 1.0 1.0 11 Al 1,2 1.2 1.3 4 14 15 1.6 1.6 17 1.8 1.8 19 2.0 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 4.2 4.2 4.2 4.2 4.2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 0.0 1.8 18 1.8 1.8 1.8 1.8 18 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 19 go nw 19 wy 47 4.7 47 47 4.7 4.7 47 4,7 47 a7 47 4.7 0.0 550,825 550,865 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 551,007 $51,007 8.0 8.2 8.4 8.5 8.7 WW 36 97 © 10.0 10.2 10, 3.6 . 35 ‘ 2 24 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 7.3 1.3 1.3 1.3 7.3 7.3 1.3 13 1.3 1.3 7.3 7.3 7.3 1.3 7.3 1.3 13 13 1.0 1.0 1.0 Al 1d 1.2 1.2 1.3 14 14 15 1.6 1.6 1.7 1.8 1.8 19 2.0 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 9.0 0.0 6.0 316,825 316,865 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 317,007 3 3 re Se ou ey 8r-d Run Date: 09-Mar-90 Run Tine: = 11:31 AN sgagegergsesascsceceesecegessesssees ¢ POWRPLAN (c) 1990 by CH2M HILL Seonensegesansessesecessssssesesess Wining Loads ($eillions): Fuel Costs Variable ON Fixed O8N Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost -- Noninal (cents/kWh} -- Real (cents/kWh) 2008 2009 2010 2011 2012 2013 Sz eemseess gessssss ==: 16.0 16.8 17.7 18.5 19.3 20.2 3.6 37 3.7 3.8 3.8 39 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 42 4.2 4.2 4.2 2.0 1.8 1.8 1.8 1.8 1.8 1.8 nw A) nw WwW WwW a7 JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. £034 and Long Lake Elev, B45 Forecast: Ad Mine 2018 2015 2016 2017 2018 2019 2020 2021 2022 2023 21 22.0 23.0 24.0 Bt 26.3 27,4 28.7 3 4.0 4 4.2 4.2 4.3 AA 4.5 4.6 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 1.8 1.8 1.8 1.8 1.8 1.8 1.8 18 47 4.7 47.047 47 47 47 47 2024 2025 3 32.7 34,2 8 5.0 ‘a 9 9.0 0.0 0 0.0 0 0 2.0 0.0 8 1.8 18 7 47 0.0 234,000 234,000 234,000 234,000 234,000 234,000 14.3 47 15.4 15.4 15.8 13.9 6.5 6.4 6.2 al 6.0 ul 33.6 Mab 35.7 36.8 38.0 39.2 40.5 a8 43,2 4,7 46.2 41.0 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 234,000 M3 14.8 15,2 15.7 16.2 18.7 17.3 17.9 18.5 19, 4 5.0 a9 a 4.8 4.7 4.7 4.6 46 4.5 1 W7 5 3 a 3.8 67-a Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Times = 09337 AM Case: Base Case (Diesel) Plan Forecast: Multi-Mine senegngnscaseagccecesccsoccsssossagy # POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995; 1996 1997 1998 1997 20002001 2002-2003 2008 )=— 2008-2006 = 2007 HOggnseasagagssesesacsesssscaesesees Suanary of Results (after conservation): eccenaccs! =: Peak Demand (MW) Peak Demand 31.3 33.6 36.0 = 103.0 108.8 = 106.5 108.48 = 106.4 = 106.3 106.3 106.2 106.4 = 106.6 = 106.8 = 106.8 = 107.0) 107.2 107.2 Peak Plus Reserve Requireaent 93.6 98.3 103.0 177.2, 179.0 180.7, 180.6 = 180.6 = 180.5 180.5 180.4 = 180.6 = 180.8 = 181.0 © 181.0 = 1BL.2 BLS BLA Installed Capacity W515 131.5 A515 195.0 195.0 195.0 184.2 184.2 184.2 B42 84.2 184.2 184.2 184.2 184.2 188.2 1842 184.2 Additional Required Capacity 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requiresents (MWh) 277,000 291,464 306,028 606,085 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 Fire Capability of Installed Units (MWa) 103.6 = :103.6 = 103.6 = 137.8 137.48 37M STA ST 387A AST AST STA 1378 17ST STA STA AST Wem Capacity to Meet Energy Req'ts (MH) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) ~~ (1) AELP Hydro: Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salnon Creek 35,040 35,040 35,080 35,040 35,080 35,040 35,040 35,040 35,080 35,080 35,040 35,040 35,080 35,040 35,080 35,040 35,040 35,040 Gold Creek 5,400 5,400 = 5,400 5,400» 5,400» 5,800 5,400) 5,400» 5,400» 5,400) 5,400 5,400» 5,400» 5,400 5,400 = 5,400 5,400 5,400 (2) Snettishae/Crater Lake 213,040 227,504 242,068 330,836 330,836 330,836 330,835 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 (3) Annex/Carlson Creek No.1 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 {4) Crater Lake Elev. 1034 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 (3) Long Lake Elev. 645 9 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 6 0 0 0 9 0 0 0 (7) GH EMD diesel 0 0 © 212,089 223,585 234,655 235,502 236,166 236,840 ..237,428 238,005 238,497 238,897 239,297 239,612 239,835 240,058 240,289 {8) Existing Diesel: Gas Turbines 0 0 0 0 0 223 293 M4 37 aa 484 519 a5 571 589 597 606 415 Lenon Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o Auke Bay 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 9 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 277,000 291,464 306,028 606,885 628,381 629,478 630,591 631,306 632,034 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 Cost ($ Millions) Capital 0.0 0.0 0.0 3.6 3.6 3.4 24 2.3 3.6 3.6 3.4 3.6 3.6 3.6 36 36 3.6 36 Fixed 0.4 0.5 05 05 0.5 0.6 0.5 0.5 0.5 0.6 0.6 0.6 0.6 07 0.7 0.7 0.7 0.8 Variable 6.2 6.7 7,0 10.6 10.7 10.8 10.9 10.9 11.0 Ml 11,2 11.2 AL. 114 WS. 16 11.7 11.8 Fuel 9.0 0.0 9.0 14.7 16.4 18.3 19.8 20.5 21.6 22.8 24.0 25.8 27.1 2.6 M5 334 5.30 oS TOTAL 6.7 wt 15 23.4 u.200«Y3.2 33.2 M3 367 38.0 «39.3 41.2 43.2 45.2 47.2 49,2 51.3 53.4 Net Present Value (1990 - 2050) $627.3 aillion New Resources Added (MW): Annex/Carlson Creek Now! Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel 6M EMD diesel 43.5 0Ss-d Run Dates 09-Mar-90 Run Times 09337 AN Haesesgacesescescesesessssesessseses $ POWRPLAN (c) 1990 by CH2M HILL & 2008 Segrasagcagessencecasasssssseseesses sasssse3 Peak Demand 107.4 Peak Plus Reserve Requireaent 181.6 Installed Capacity 184.2 Additional Required Capacity 0.0 Energy Requireeents (MWh) 635,744 Fira Capability of Installed Units (MWa) = 137.4 New Capacity to Meet Energy Req’ts (Mi) 0.0. Energy Dispatch (MWh) -- (1) AELP Hydro: Annex Creek 23,520 Salaon Creek 35,040 Gold Creek 5,400 (2) Snettishaa/Crater Lake 330,836 ( Annex/Carlson Creek No. 0 (4) Crater Lake Elev. 1034 0 (5) Long Lake Elev. 845 0 (6) Caterpillar 3612 diesel 0 ) 6M EMD diesel 240,341 (8) Existing Diesel: Gas Turbines 608 Lenon Creek 0 Auke Bay 0 Gold Creek 0 seescscs TOTAL 635,744 Unserved Energy 0 Cost (8 Millions) Capital Fixed Variable Fuel TOTAL Net Present Value (1990 - 2050) 2009 arenesez exes: 107.5 181.7 4.2 9.0 635,885 137.4 0.0 23,520 35,040 400 330,636 240,481 3 635,885 2010 107.5 181.7 184.2 0.0 635,627 137.4 0.0 23,520 35,040 5,400 330,836 0 0 0 0 240,440 5a 0 0 635,827 2011 2012 107.5 107.5 181.7 181.7 184.2 184.2 9.0 0.0 635,827 635,827 137.4 137.4 0.0 0.0 23,520 23,520 35,040 35,080 5,400 = 5,400 330,836 330,836 0 0 0 0 0 0 0 0 240,440 240,440 sm S01 0 0 0 0 635,827 635,827 2013 107.5 181.7 184.2 0.0 635,827 137.4 0.0 23,520 35,080 5,400 330,836 0 0 0 0 240,440 BT 635,027 0 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case (Diesel) Plan Forecast: Multi-Mine 2014 2015 107.5 107.5 181.7 181.7 184.2 184.2 0.0 0.0 635,827 635,827 137.4 (137.4 0.0 0.0 23,520 23,520 “35,040 35,040 5,400 = 5,400 330,836 330,836 0 0 0 0 0 0 0 0 240,440 240,440 591 Su 0 0 0 0 635,827 635,827 2016 107.5 181.7 184.2 0.0 635,827 137.4 0.0 23,520 35,040 5,400 330,836 0 0 0 0 240,440 5a 835,827 2017 107.5 181.7 194.2 0.0 435,827 137.4 0.0 23,520 35,040 5,400 330,835 0 0 0 0 240,440 sn 2018 107.5 181.7 184.2 0.0 635,827 137.4 0.0 23,520 35,040 5,400 330,836 0 0 240,440 Sa 635,827 2019 2020 107.5) 107. 181.7 1BL. 184.2 184. 0.0 0. 835,827 635,82 137.4 137. 2021 3 107.5 7 1BL.7 2 184.2 0 0.0 2022 2023 107.5 107.5 181.7 161.7 184.2 184.2 0.0 0.0 7 635,827 635,827 635,827 4 137.4 0.0 0.0 0.0 23,520 23,52 35,040 35,04 5,400 5,40 330,836 330,83 0 0 0 0 240,440 240,441 Se 0 0 0 23,520 137.4 137.4 0.0 0.0 23,520 23,520 0 35,040 35,040 35,040 0 5,400 5,400 5,400 }6 330,836 330,836 330,836 0 6 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 240,440 240,440 240,440 1 sat | 31 0 0 0 0 0 0 0 0 2024 107.5 181.7 184.2 0.0 635,827 137.4 0.0 23,520 35,040 5,400 330,838 0 0 240,440 59k 635,827 2025 107.5 181.7 184.2 0.0 635,827 137.4 0.0 New Resources Added (HW): Annex/Carlson Creek No.S Crater Lake Elev, 1034 Long Lake Elev. 645 Caterpillar 3612 diesel 6H EMD diesel “4 Ts-d 09-Mar-90 09:37 AN Run Dates Run Tier eaegescareceeasececsssesesessseatess $ POWRPLAN (c} 1990 by CH2M HILL @ -Henesengeascesagegsesseceseeseesesss Winter (October - April) Energy Requirements (XWh) Energy Dispatch (MWh) 158] AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Annex/Carison Creek No.t {4) Crater Lake Elev. 1034 (3) Long Lake Elev. 645 (6) Caterpillar 36t2 diesel 7) 6M EMD diesel (8) Existing Diesel: Gas Turbines Lenon Creek Auke Bay Gold Creek TOTAL Cost Millions) Capital Fixed Variable Fuel TOTAL 1990 1991 1992 179,219 188,455 197,756 7,943 11,786 1,912 134,469 ecooce 7,93 11,78 1,912 165,726 eosooo 0 0 0 0 187,368 6.0 0.3 4a 0.0 7,943 11,786 1,912 175,050 eooce coco 196,692 1993 375,159 382,106 1994 1995 388,925 389,334 389,618 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Forecast: Multi-Nine 1996 1997 1998 Base Case (Diesel) Plan 1999 2000 2001 389,911 390,142 390,368 390,538 2002 2003 2004 2005 390,643 390,749 390,797 390,783 2006 2007 S Eaassess sseseese 390,770 390,761 7,943 7,943 7,943 7,943 -7,943—7,9AS 7943-7943 7,943,943 —7,94S—7,94S 79K 7,983 7,943 11,786 11,786 11,786 11,786 11,785 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 1,912 1,912 1,912 1,912 1,912 1,912 1,912,912 912 APLZ 191219121912 1,912 1912 212,727 212,727 212,727 212,727 22,727 212,727 212,727 212,727 212,727 282,727 212,727 212,727 212,727 212,727 212,727 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 07 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 139,818 146,823 153,479 153,893 154,200 154,515 154,776 155,035 155,245 155,399 155,555 155,640 155,713 155,766 155,824 0 0 23 m3 We 37 OSD 545. S7k 58997 OHS 0 0 0 0 0 uf 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 374,188 381,193 388,072 388,355 388,914 389,281 389,587 389,889 390,133 390,314 390,495 390,618 390,679 390,741 390,808 1 21 14 14 21 2 24 21 24 21 24 21 21 21 3 0.3 0.3 0.3 0.3 0.3 0.3 0.4 4 0.4 04. 0.4 0.4 0.5 9 7.0 7.0 TA 7A 7.2 7.2 73 7.3 14 14 15 13 76 8 Wg? 12.6 13.3 M41 14.8 15.5. 16.7 17.9 191° 20.3 25 22.8 24.0 Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tine 09:37 AN Case: = Base Case (Diesel) Plan Forecast: Multi-Mine Sonegcgrgenecescscecescesasscecseess 1 POWRPLAN (c) 1990 by CH2M HILL & 2008 2009 20102011 2012 20132018 = 20852088 2017 2018 2019-2020, 2028 = 202220232028 = 2025 Angnenncegcerceaesesasegcecesectess Saseeaes sezszss2 seaecss Winter (October - April Energy Requirements (MWh) 390,633 390,562 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,372 390,371 390,371 Energy Dispatch (MWh) (1) AELP Hydro: Annex Creek 7,983 7,943 7,943 7,943 7,943 7,943 74983 -7,94S—-7,943_—-7,94S—-7,9HS_—7,94S_— 74S 7,943 794S— 79S 7,987,983 Salaon Creek 12,786 11,786 11,786 11,785 11,786 11,786 11,786 11,786 12,786 12,786 11,786 11,786 11,786 11,786 14,786 11,785 11,786 11,786 Gold Creek 1,912 1,912 1,912 1,912 1,912 1,912 1,982 1,982,912 1,912 NZ 91Z 91219121912 1,912,912 1,912 (2) Snettishae/Crater Lake 212,727 212,727 212,727 212,727 212,727 2125727 212,727 212,727 212,727 212,727 212,727 212,727 242,727 242,727 212,727 212,727 212,727 212,727 (3) Annex/Carlson Creek No.t 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (4) Crater Lake Elev. 1034 0 0 0 0 0 0 0 0 9 0 0 0 0 9 0 0 0 0 (3) Long Lake Elev. 845 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0) 6M EMD diesel 155,778 155,782 155,683 195,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 155,683 w (8) Existing Diesel: 1 Gas Turbines 608 608 59 bid 391 31 501 oa 51 59 Ei 591 591 51 591 sm mm 3a uw Leon Creek 0 0 0 0 0 0 o + 0 9 0 9 9 0 0 0 0 0 0 N fuke Bay 0 0 0 0 0 0 0 9 9 0 0 0 0 9 0 0 0 0 Gold Creek 0 0 9 0 9 9 0 9 0 0 9 0 0 0 0 0 0 0 saesess 2: ® = TOTAL 390,755 390,760 390,643 390,643 390,643 390,643 390,643 390,643 390,683 390,643 390,643 390,643 390,643 390,663 390,643 390,643 390,643 390,643 Cost ($ Millions) Capital 21 21 2A 21 21 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Fixed : 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.8 0.8 0.8 Variable 17 1.7 7.8 19 19 8.0 81 8.2 8.3 8.4 8.5 6.6 8.7 8.8 Fuel 25.2 26.5 27.8 29.0 30.3 37 33.1 346 36.2 37.8 395 NAS 43.1 ASL TOTAL 35.5 36.8 38.2 35 40.9 40.3 ag 43.5 45.1 86.9 48.7 50.6 52.6 54.7, es-ad Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tieer 09:37 AK 7 “ Case: Base Case (Diesel) Plan Forecast: Multi-Mine aansagesceceeccceseessezassgtececegs $ POWRPLAN {c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 OReeaegeacaseegesasesesseocecssssege Stssase2 saszcese seerssss ssstzses seezssze ssszeszs est SS. BEssesss =2: 2-22: eaecsses Sueeer (May - Septeaber} eae: = Energy Requirements (MWh) 97,781 103,009 108,272 231,726 236,275 240,749 241,257 241,689 242,123 242,519 242,916 243,274 283,595 243,915 244,199 244,845 244,690 244,939 Energy Dispatch (MWh) () AELP Hydrot Annex Creek 15,577 15,577. 15,577 15,577. 15,577 85,577 15,577 15,577 15,577 15,577, 15,577 15,577 15,577 15,577 15,577 15,377 15,577 15,577 Saleon Creek 23,254 «23,254 = 23,254 23,258 «23,254 23,254 923,254 23,258 23,254 923,254 © 23,254 23,254 923,254 23,254 = 23,254 23,254 23,254 23,2548 Gold Creek 3,468 «3,488 «= 3,488 «= 3,488 §=— 3,488 §=— 3,488) 3,488 93,488 = 3,488 = 3,488 |= 3,488 = 3,488 = 3,888 )8=— 3,488 = 3,488 = 3,48R |= 3,488 3,488 (2) Snettishaa/Crater Lake 56,571 61,777 67,018 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 116,108 118,108 118,108 118,108 {3) Annex/Carlson Creek No. 0 0 0 0 0 0 0 0 0 9 0 9 0 0 0 0 0 0 4) Crater Lake Elev. 1034 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (3) Long Lake Elev. 845 0 0 0 0 0 0 0 0 0 0 0 0 0 o -. 0 0 0 9 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0) 6H EMD diesel 0 0 0 72,271 «76,762 81,178 81,609 81,966 82,326 82,687 82,969 83,252 83,498 83,743 83,951 84,122 84,292 84,466 (8) Existing Diesel: Gas Turbines 0 0 0 0 0 0 0 Leaon Creek 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 sasssese TOTAL 243,679 243,924 244,169 244,378 284,549 244,718 244,892 Cost (9 Millions) Capital 0.0 0.0 0.0 15 1.5 1.5 1.0 1.0 13 13 5 15 1.5 1.5 1.3 BS 1.5 15 Fixed 0.2 0.2 0.2 0.2 0.2 0,2 0.2 0.2 0.2 0.2 0.2 0.3 0.3 03. O03 - 0.3 0.3 0.3 Variable 1.6 1.8 19 3.8 3.8 3.8 39 39 3g 3.9 4a 4 Al 4.2 Fuel 0.0 0.0 0.0 3.7 4 6.8 7.2 7.6 8.0 8.4 1a 1.8 2.6 3.3 TOTAL ps-d 09-Mar-90 09:37 AN Run Date: Run Tine: Necegcecageasacecsasegcagessecesssss $ POWRPLAN (c) 1990 by CH2M HILL 8 Seeneeecesacegsacasssegsasesssessses Suamer (Nay - Septeaber Energy Requirements (MWh) Energy Dispatch (MWh (1) AELP Hydros Annex Creek Saleon Creek Gold Creek (2) Snettishae/Crater Lake (3) Annex/Carison Creek No. (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 845 (6) Caterpillar 3612 diesel ) 6M END diesel (8) Existing Diesel: Gas Turbines Lemon Creek fuke Bay Bold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL 2008 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case (Diesel) Plan Forecast: Multi-Mine 2009 2010 2011 2012 2013 20148 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 245,111 245,323 245,455 245,455 245,455 245,455 245,455 245,455 285,455 245,455 245,455 245,455 245,455 245,455 245,455 245,455 245,855 285,855 15,577 15,577 15,877 15,577 25,577 15,577 15,577 15,577 15,577 “15,577 15,577 15,577 15,577 15,577 15,577 $5,577 15,877 15,877 23,258 23,254 23,754 23,254 23,254 23,254 23,254 23,258 23,254 23,258 23,256 23,254 23,254 23,258 23,254 23,254 23,254 23,754 3,488 3,489 3,489 «3,480 3,488 3,488 -3,48B 3,488 «3,488 3,488 3,480 «3,889 © 3,408} 3,488 3,488 3,488 3,488 3,408 118,108 118,108 116,108 118,108 118,108 118,108 126,108 118,108 118,108 116,108 118,108 118,108 116,108 118,108 118,108 118,208 118,108 118,108 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 B4,563 89,699 84,757 04,757 84,757 4,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 244,989 245,125 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 1.5 1.5 1.5 15 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 04. 0.8 O48 0.4 0.4 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 07 0.7 07 4.2 4.3 4.3 a 4 45 45 4.6 4.6 47 47 4.8 4 49 5.0 3 i 14. 13.5 16.2 16.9 17.7 18.5 19.3 20.2 a 22.0 23.0 wal 25.2 26.3 27,5 28.7 30.0 ss-d Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiees 09:37 AN Case: Base Case (Diesel) Plan Forecast: Multi-Mine Heegeeegeeeeseacagesagcagsssesegeegs $ POWRPLAN (c) 1990 by CH2M HILL ¢ 1990 1991 1992 1993 1994 1995 199% 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 MITT Saseeess eeraeres erzeress eeeseres eazesezs szszeees eeeseess zseszssz szsstses eeessssz seezszez eceeesss seessees seseeezs szseeszs szecezes exeeeeee eszzese2 BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs 0.0 0.0 . 0.0 14.7 16.4 18.3 19.4 20.5 22.8 24.0 25.8 27.7 29.6 5 4 35.3 v3 Variable O&n 6.2 6.7 7.0 10.6 10.7 10.8 10.9 10.9 Ml 1.2 11.2 1.3 4 11.5 11.6 11.7 11.8 Fixed Ob 0.5 6 6 0.6 Capital Costs (existing systea) 2.6 6 6 2.6 Depreciation Expense (new units) 1.8 8 8 1.8 Property Taxes (new units) 0.6 6 +b 0.6 Interest Expense (new units) 2.8 8 8 2.8 Total Energy Requirements (MWh) 277,000 291,464 306,028 606,885 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 Average Bus Bar Cost -- Nominal (cents/kWh) 34 33 3.3 3.5 3.7 3.9 39 6.1 6.5 6.7 6.9 7.2 7.5 7.8 8.1 8.4 8.7 a1 ~~ Real (cents/kWh) 34 3.2 3.0 4.8 4.8 4.8 43 4.5 4.6 45 44 4A 44 44 44 4.3 4.3 4.3 Won-Mining Loads (Smillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) 277,000 291,464 306,028 302,885 314,381 325,674 326,591 327,306 328,033 328,661 329,285 329,812 330,238 330,664 330,996 331,228 331,460 331,700 Average Bus Bar Cost -- Nominal (cents/kWh) 34 3.3 33 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 33 33 3.3 ~~ Real (cents/kWh) 3.4 3.2 3.0 2.9 2.8 2.6 2.5 2.4 2.3 2.2 21 2.0 1.9 Lg 1.8 1.7 1.6 1.6 9S-a Run Date: 09-Mar-90 Run Tises = 09337 AN sgegegnscescecesscscegsestessecsases $ POWRPLAN (c) 1990 by CH2M HILL $8 Segesesengasessssacsesassssssseseses Mining Loads ($millions): Fuel Costs Variable Ol Fixed OO Capital Costs (existing systea) Depreciation Expense (new units} Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Noainal (cents/kWh) ~~ Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case (Diesel) Plan Forecasts Multi-Mine 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 geesstse sseesze= =z: eee 0.0 0.0 0.0 14,7 16.4 18.3 19.4 20.5 21.6 22.8 24.0 25.8 21.7 29.6 ue . 0.0 0.0 0.0 37 35 3.3 3.3 34 34 35 35 3.6 36 37 a 7 * i 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (1.2) (1.2) 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.8 1.8 1.8 18 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 Le 0.0 0.0 0.0 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 © (06 0.6 ub 0.0 0.0 0.0 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 0.0 0.0 0.0 23.6 2541 26.7 26.7 27.8 30.2 ud 32.6 35 36.5 38.4 40.4 42.4 Ma 46.5 o 0 0 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 WA WA WA 1 6 8.3 8.8 8.8 9 10.3 10.7 1.4 12.0 12.6 13.3 14.0 14.6 15.3 Lt) RA na Ml Wd 4.7 6.7 7.0 7.0 6.9 7.0 7A 1! 7.2 7.2 1.200 12 LS-@ Run Date: 09-Mar-90 Run Tine: == 09237 AN Suseagsgneceseaccsesesesscessasesees $ POWRPLAN (c) 1990 by CH2M HILL & Hananaesagseagscagesasgsasesessasess BUS BAR COST SECTION: Average Costs (Saillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing syste) Depreciation Expense (new units} Property Taxes (new units} Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) > Real (cents/kWh) Won-Mining Loads (Saillions): Fuel Costs Variable O&M Fixed D&M Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requirements (MWh) Average Bus Bar Cost ~~ Nopinal (cents/kWh) ~~ Real (cents/kwh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case (Diesel) Plan Forecast: Multi-Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2028 2025 eeessese sazss2zs 222222: 39.3 1.3 43.2 47.3 49.4 51.6 53.9 56.4 58.9 61.5 64.3 67.2 70.2 73.4 76.7 80.1 83.8 M9 12.0 12.2 12.3 12.4 12.6 12.7 12.9 13.0 13.2 13.3 13.5 13.7 13.9 14.0 14.3 14.3 0.8 0.9 0.9 1.0 1.0 1 i 1.2 1.2 1.3 14 15 15 1.6 17 47 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 1.8 1.8 1.8 1.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 2.8 2.8 2.8 2.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 59.7 61.9 64.0 66.1 68.3 66.0 11.0 73.6 76.3 79.2 82.2 85.3 88.6 92.0 95.5 99.3 103.2 635,744 635,885 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 835,827 9.4 97 10.1 10.8 10.7 10.4 10.8 11.2 Mb 12.0 12.5 12.9 1.4 13.9 14.5 15.0 15.6 16.2 4.3 4.2 4.2 41 4 3.8 37 3.7 3.7 3.7 3.6 3.6 3.6 3.6 35 35 35 3.5 9 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7 17 1 7 17 17 ad 17 17 7.7 7 7 17 17 17 17 0 0.9 1 1.0 A i 1.2 1.2 ‘13 1.3 1.4 1.5 15 1.6 1.7 47 2 2.6 2 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0. 9.0 9 0.0 0.0 0.0 0.0 0.0 0.0 - 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0. 0.0 0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4 331,744 331,885 331,027 331,827 331,827 331,827 331,027 331,827 331,827 331,027 331,827 331,827 331,827 331,827 331,827 331,827 331,027 331,827 34 34 34 3. LS 13 wd tow 8s-a Run Date: 09-Mar-90 Run Times 09:37 AN Sacosegegngsegcscgsegsecssetegessss $ POWRPLAN (c) 1990 by CH2M HILL & Degeenaneseacasaseseesstsesecsssesss Nining Loads (Snillions): Fuel Costs Variable OG Fixed ObM Capital Costs existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) > Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Base Case (Diesel) Plan Forecast: Multi-Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 33 MLS ASS O52 7.3 ASSP SKA BHLS 67.2 70,2 . 4200-43 4 AT SOAS BO ta 3 “a ta 0.0 0.0 «0.0 0.0sisiiiiiiiiCiCii 0.0 ©6000 (00siisiitiitiitisiiiiiiitiiiti 18008 SsCdADSCdLSCti«iLSCi ii iistiiisiii 0.6 0.6 «06st CCC Citi 28 «62.8 «6 2.Bsi(‘kKOBOCsiti Liisi 48.6 50.7 52.8 549 37.0 54.7 57.1 39.5 62.1 64.8 67.6 70.5 73.6 76.8 80.1 83.6 87.3 Wd 304,000 304,000 304,000 304,000 304,000 308,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 1b. 7 30.0 7 4 84 0 16.7 17.4 18. 2 7 18.8 18.0 18.8 19.6 20.4 21.3 22.2 23.2 24.2 25.3 26.4 21,5 28. 7,2 7.2 ‘i 6 wl 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.4 6.4 6S-a Run Dater 02-Jul-90 Run Tine: = 03:35 PN Oeneasarcecsestagagsesstesogcesess 4 POWRPLAN (c) 1990 by CH2M HILL & Qgagnseagsagegseaesaseceesosagseass eeagscecacazr: id (HW) ~~ Peak Desand Peak Plus Reserve Requireaent Installed Capacity Additional Required Capacity Energy Requireaents (MWh) Fire Capability of Installed Units {KWa). New Capacity to:Meet Energy Req'ts (AW) Energy Dispatch (HWh) -- uy) AELP Hydros Annet Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Late (3) Annex/Cartson Creek No. (4) Crater Lake Elev. 1034 (3) Long Lake Elev, 845 (8) Caterpillar 3612 diesel a GH EMD diesel (8) Existing Diesel: Gas Turbines Leaon Creek fluke Bay Gold Creek TOTAL Unserved Energy Cost ($ MINI fons) Variable Fuel TOTAL Net Present Value (1990 - 2050) New Resources Annes/Carlson Creek No.! Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel GH EMD diesel ry of Results (after conservation): JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Annex/Carlson Creek with Crater Lake Elev. 1034 Forecast: Multi-Hine 1990 1991 1992 1993 1994 1995. 1996 1997 1998 1999 2000. 2001 2002 2003 2004 2005 2008 2007 SaNSEEEE atauerae aitouea7 conceses ssssscee exscesce Sssesas= essccess eeaccas® scaezzce sacaamc exssuez ssezuuse sessoasa asescstz cozacere wagcacca e2zazens 1.3 33.6 36.0 103.0 104.8 = 106.5 106.4 = 106.4 = 106.3 108.3 106.2 108.4 108.8 = 106.8 06.8 = 107.0 = 107.2107.2 93.6 98.3 103.0 177.2 179.0 180.7 180.6 = 180.6 = 180.5 180.5 180.4 = 180.8 = 180.8 §=— 81.0 = 181.0 81,2 1814 tate AS1.5 151.5 515 1863 1863 186.3 208.3 24.3 USMS NTL 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 277,000 291,464 306,028 606,885 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,995 635,228 635,480 635,700 103.6 103.6 103.6 131.0131. 0.0 0.0 0.0 0.0 0 131,00 9137.6 137.6 A376 137.6 13766 STB 137.6 137.6 137.8 STAB 137838 0 6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 » 23,520 23,520 23,520 23,520 23,520 23,20 33,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 33,040 35,040 35,040 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400» 5,800 5,400 5,400 5,400 5,400 5,400 5,800 5,400 213,040 227,504 242,068 330,836 330,836 330,836 330,836 330,836 330,836 330,834 330,836 330,835 330,836 330,836 330,836 330,836 330,836 330,036 0 0 0 0 0 0 136,752 137,109 137,469 137,790 138,112 138,395 138,641 138,885 139,094 139,265 139,433 139,609 0 0 0 «2,848 = 2,848 = 7,848 1,831 1,832 1,831 2,B3L B32 B32 1,832 1,831 2,831,832 1,831 1,838 0 0 0 0 en) 0 0 0 a 0 0 0 0 0 0 0 0 0 0 0 0 o 0 ° 6 0 0 0 0 0 0 0 0 0 6 0 0 O 203,665 211,073 218,001 97,212 97,571 97,938 98,243 98,546 98,790 98,970 99,152 99,275 99,336 99,398 99,465 0 0 0 5,576 = 9,664 = 14,030 0 0 0 0 6 0 0 0 0 0 0 4 0 0 0 0 0 0 0 0 0 0 0 0 6 0 0 0 0 Q 6 0 0 0 0 o 0 0 0 0 o- 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 @ RARTRRAE uCTaEa LSteceas cagcemss egc2sEss wssecese asssszzs ESsEsEas BEaaESeS ENZIETZE zaxeszag BBeSe== Eazsesse sozzsa=z zacnsese gaszeras anzease 277,000 291,464 306,028 606,885 618,381 629,674 630,591 631,306 632,034 632,46! 633,285 433,812 634,238 634,664 634,996 635,228 635,460 635,700 o> 9 o 860 0 0 6 oo 0 o 0 6 0 #0 +. 0 0 6 6 3.2, 3.2 16.8 16.8 16.8 16.8 16.8 16.8" 18.8 16.8 16.8 16.8 18.8 0.5 0.8 1.0 10 Md ia 1.2 1,2 1.3 13 14 . LS 1.6 A 10.5 10.6 10.7 10.1 10.1 10.1 10.2 10.2 10.2 10.3 10.3 10.3 10.4 10.4 10.5 0.0 0.0 ° 14.8 16.7 18.8 8.0 a4 8.9 94 V9 10.7 M4 12.2 13.0 13.8 14.6 15.4 BassszeR Raessysz ATAEATSx TATATEse BAEEssza Seezaast szsztesz BarzsE22 ssTEIELa aeaEsexs esessore ecceess= esessess asezssae szsssser arsesesa zsessces TA WS 29.0 uA 33.3 33.9 36.4 36.9 3 38.1 38.9 39.8 40.6 4s 42.4 43.3 4.2 0.0 16.8 0.5 . 14 . 1.0 $496.1 ailtion M48 09-4 02-Jul-90 03:35 PM Run Dates Run Tiees Aeesgsaagesacegasagsccesagcsseteees $ POWRPLAN {c} 1990 by CHM HILL ¢ UENSaenssesarotseogsessacsaessesesss 2008 2009 Suasary of Results (after conservation): ausaranscgzazozzazrccatsasaesozcezertets23 Peak Demand (MW) -- Peak Deaand 107.4 107.5 Peak Plus Reserve Requireaent 161.6 = 181.7 Installed Capacity 24.3, 214.3 Additional Required Capacity 0.0 0.0 Energy Requireaents (HWh) 635,744 635,885 Fire Capability of Installed Units (MWa) = 137.6 = 137.6 Wew Capacity to Meet Energy Req'ts (HW) 0.0 0.0 Energy Dispatch (HWh} -~ (1) AELP Hydro: Annex Creek 23,520 23,520 Salaon Creek 35,040 35,040 Gold Creek 5,400 3,400 (2) Snettishae/Crater Lake (3) Annex/Carison Creek No.! 330,836 330,836 139,708 139,842 ay Crater Lake Elev. 1034 1,831 1,831 (3) Long Lake Elev. 845 0 0 (8) Caterpillar 3612 diesel 0 0 (7) BM EMD diesel 99,411 99,46 (8) Existing Diesel: Gas Turbines 0 0 Leaon Creek 0 0 fAuke Bay 0 0 Gold Creek 0 6 eeaseeze azcezsae TOTAL 835,744 635,605 Unserved Energy 0 0 Cost ($ Millions) Capital 16.8 18.8 Fixed Leo. LT? Varlable 10.3 10.8 Fuel 18.2 17.0 suearay senaates TOTAL 1 thd Wet Present Value (1990 - 2050) New Resources Adi Annex/Carlson Creek Ho.t Crater Lake Elev, 1034 Long Lake Elev. 845 Caterpillar 3612 diesel 6M END diesel 2010 2011 2012 2013 Rugugete ferszaqs ereeacss azarzczz arsszzzz zzazec22 exssseae eceac2za aeecszec sseze=za 203z0! JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Annex/Carison Creek with Crater Lake Elev. 1034 Forecast: Multi-Mine 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2023 Seateres sarezsse saeezece ess: 107.3 107.5 107.5 107.5 107.5 107.5 107.5 107.5 107.3 107.5 07,5 107.5 107.5 107.5 107.3 107.5 481.7 08.7 181.7 81.7 181.7 181.7 181.7 ABN? 18L.7 18.7 18.7 8L7 181.7 181.7 B17 181.7 M43 2M3 2S NT NAS NT AS AST TMNT AS EHS NLL 435,827 635,827 635,827 137.6 137.6 137.8 635,027 635,827 137.6 0.0 0.0 0.0; 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 635,827 635,827 635,827 635,627 635,827 635,827 635,827 835,827 635,827 635,827 635,827 137.6 137.6 137.6 137.6 137.8 137.6 37.6 137.6 3781S 137.6 137.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 23,520 23,520 23,520 23,520 23,520 23,520 23,820 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 35,040 35,040 35,040 38,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 33,040 5,400 5,400 5,400 9,400 3,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5, 400 330,838 330,836 330,858 330,636 330,834 330,835 330,836 330,835 330,835 330,835 330,838 330,836 330,836 330,635 330,836 330,836 139,900 139,900 139,900 139,900 137,900 139,900 139,900 139,900 139,900 139,900 139,900 139,900 139,900 139,900 139,900 139,900 1,031 1,831 1,831 1,831 1,831 1,831 1,831,831 1,832 1,831,831 1,831,831 18321831 1,831 0 0 0 4 0 0 0 0 0 0 0 0 o 9 0 0 0 0 0 0 0 o 0 0 0 6 0 0 o 0 0 0 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 97,300 99,300 99,300 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o o 0 0 0 0 0 0 6 0 0 0 0 o-. 0 0 ° 0 0 6 0 0 0 0 6 0 0 o 0 0 0 0 4 0 0 0 0 0 0 0 0 Rareescs 33¢zn735 anzrazex aszaz222 sazzzze3 czze2e52 2: ED EQREREMA BszesEA HAEIasss eeesasez s=sgazass zessrsss essssc2z azazssec seezeese 435,827 635,027 635,827 635,827 635,827 635,827 635,827 635,627 635,827 635,827 635,027 635,827 635,827 635,827 635,827 635,827 0 0 0 0 0 0 0 o 06 0 0 0 0 0” 0 0 16,8 16.8 © 16.8 138 ASS 13h SB SB SSSR ISH SB 1S ISB SB 18. HB. 19-20 BE 2 SAL SS 10.6 10.6 10,7 ' 10.7 108° 10.910 OOS ALS 2 1 17.8 18.6 14 20.3 a. auucarse sacseeze excsese2 eaegeces scazezsa serccacz #zeszs52 o2sesccm asceeszz asssezz¢ axcozze2 seesazcz x22! 47.0. $7.9 48.9 46.7 22.2 23.2 24.2 25.3 26.4 27.6 28.9 30.2 U.S 33.0 4 S22 moeszccz azezeecm eazcesce 47.8 418.9 50.0 31.2 $2.5 33.8 55.2 56.7 38.2 59.7 bt B34 T9-@ Run Date: Run Tines 02-Jul-90 03:35 PH QgGgganeaesgssacaaessssssegessaessss $ POWRPLAN (c} 1990 by CH2M HILL & Ungscgssegsrassasergsegsscseseecesss Winter (October ~ April) snazcsouscesescsaaczssza Energy Requireaents (Hh) Energy Dispatch (MWh) a) AELP Hydro: 1990 1991 1992 ExEaES2e uzrerzz3 sectszca 179,219 168,455 197,756 QUNEAU 20-YEAR POWER SUPPLY PLAN Case: Annex/Carlson Creek with Crater Late Elev. 1034 ° Forecast: Multi-Mine 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 22 3: SSEEEEE CCTEREe= waezse2= seses=sz azcesa=a, 375,159 382,106 388,925 389,334 389,418 38,91 390,142 390,368 390,538 390,643 390,749 Page 3 2004 2005 2008 2007 390,797 390,783 390,770 390,761 Annex Creek Saleon Creek Gold Creek © (2) Snettishae/Crater Lake (3) Annex/Carison Creek Not (4) Crater Lake Elev. 1034 _ (3) Long Lake Elev. 845 (6) Caterplilar 3412 diesel (7) 6M EMD diesel (8) Existing Diesel: Gas Turbines Leaon Creek fuke Bay Gold Creek TOTAL Cost ($ Millions) TOTAL 7,43 7,943 7,943 11,786 11,786 11,786 1,912 1,912 1,912 156,489 165,726 175,050 o- 0 0 ° 0 o o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 178,111 187,368 196,692 0.0 0.3 4.6 0.0 3.3 7,943 7,943 7,943 7,943 7,943 7,983 7,943 7,943 7,943 7, 7KS 7,943. 7,943 7,937,943 -7,943 11,786 11,786 11,786 11,788 11,786 11,786 11,786 11,786 11,788 11,786 11,786 11,786 11,786 11,788 11,786 1,12 1,912 1,912 1,012 1,902,912 8,912,912 A912 AVE A912 191219121912 A 212,727 212,727 212,727 212,727 242,727 212,727 212727 22,727 282,727 212,727 212,727 242,727 22,727 242,727 212,727 0 0 0 S143 55,243 55,143 $5,143 $5,143 55,243 55,243 55,143 55,643 55,143 55,143 55,083 1,831 1,831 1,831 1,831 18311831132 1,831 1,831 1831 1,631 1,832,831 1,831 1,881 0 o. 0 0 0 0 0 0 0 ° 0 0 0 0 ° 0 0 0 0 0 0 0 o 0 0 0 0 0 0 6 132,411 135,328 137,841 97,212 97,571 97,938 98,243 98,546 98,790 98,970 99,192 99,275 99,336 99,398 99,463 5,576 9,664 14,030 0 0 0 0 0 0 0 0 0 0 0 0 o 0 o 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ° 0 0 0 0 o 0 0 0 0 0 0 0 0 0 secuueae enseunse ausucaze sznessse azcscees réseeses ussssese sceccoes steceece eusgedas succes succesce sseutses sesesess szeveces 374,188 381,193 388,072 388,555 368,914 389,281 389,587 389,889 390,133 390,314 390,495 390,618 390,679 390,741 390,608 18.8 9.8 9.8 9.8 98 9.8 9.8 9.8 9.8 9.8 9.8 4.8 0.8 0.6 0.6 0.7 07 0.7 0.8 0.8 0B ° 09 0.9 47 67 68° 6.8 6.8 $9 69 49 1.0: 7.0 1.0 ww B.4 8.8 v3 10.0 10.7 M4 124 12.8 13.8 14.3 BSEceess ceess2ss esssessa eezeczzs 24.6 25.0 23.5 28.0 2.5 27,3 28.1 28.9 29.6 30.8 32 328 79-4 02-Jul-90 03135 PH Run Dater Run Meer Steaasaeresgnacsesessaceassassss sees © POWRPLAN (c) 1990 by CH2N HILL Seracagegseacagssagsssaetosassssses Winter (October - April} waugeersoscecersscaccss2 Energy Requireaents (ih) Energy Dispatch (MWh) ay AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Annex/Carlson Creek No.l 4) Crater Late Elev. 1034 (3) Long Late Elev. 845 (8) Caterpillar 3612 diesel a) 6M EMD diesel (8) Existing Diesel: Gas Turbines Leson Creek Aue Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Annex/Carison Creek with Crater Lake Elev. 1034 Forecast: Multi-Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2023 guseazem Esrgare3 atazacan szozzzsx aszreccs easscssa emazzzsa CSEETEes SeasESEe aszszesz sszrszea szseseza aaszsese Wecssesz ansaic2a sazecaaa vasemsca esacaeet 390,633 390,562 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 7,943 7S 7,937, 9S— 7,947,949 74MS_— MATHS 7,943,947, 94S, 94TH 7,437,943 11,786 11,786 11,786 L786 11,786 11,786 11,786 11,786 11,786 11,786 12,786 £4,786 11,786 11,785 11,786 11,786 11,788 11,786 1,912 1,912 1,912,912 4,912 1,912 1,912 1,912 2912192 1,912 1912 FEZ AMZ 1912 1,912 1,912 1, 912 202,727 22,727 242,727 212,727 212,727 212,727 212,727 212,727 242,727 282,727 242,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 S5,143 S5,143 55,143 $5,143 SS, 143 SH,L4S SS,14T 55, 14F 55,143 55,143 95,143 SS,143 SS A4T 5,14 55,143 55,143 53,143 55,143 1,031 1,832 1,831 91,831 1831 1,831,832 1832 1,832,831 1,832 1,832 2,832 1,831 1,83t 1831 1,831 1,831 0 0 o . 0 0 0 6 0 0 0 0 0 0 ° 0 0 0 0 : 0 0 0 0 0 0 0 0 0 6 0 o 0 0 6 0 0 0 -99,411 99,418 99,300 99,300 99,300 99,300 99,300 97,300 97,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 99,300 0 0 ® 0 0 0 0 0 0 0 6 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6 0 0 0 ° 0 0 0 0 0 0 0 0 0. 0 0 0 O° 0 0 0 0 0 0 9 0 0 0 0 6 0 0 0 0 0 ase msaaseza = 2 sa cesacace sanazeze aazcaza3 szsectos Quxgesex Ezxogats ezgsoss rszscrse earsszr 390,755 390,780 390,843 390,843 390,643 390,543 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 370,643 390,643 390,643 390,443 9.8 8 9.8 9.8 9.8 79 1g 1 nw 1 1 1 10 0 Ld Md La 1.2 1.3 14 14 15 1.6 1.6 nA 1 72 1.2 12 13 14 1S 13 7.6 16 77 20.6 213 22.5 23.5 wb 25.7 SEaEaso SEEEEOSE BERsEsra gEezEsass aeazsss= sesussas =: 16.5 17.3 18.1 18.9 asazxsaa wewzogse eez3zs2 fzfenaza arszzene8 ==3 329 37 36 35.4 36.3 33.3 34.3 33 38.3 39.4 40.5 47 43.0 aay 2 45.6 47.0 48.5 50.1 €9-a rage 5 Run Dates 02-Jul-90 JUREAU 20-YEAR POWER SUPPLY PLAN Run Tine: = 03:35 PH Case: Annex/Carlson Creek with Crater Late Elev. 1034 Forecast: Multi-Mine UNNgRaeeegaasgaegaassaeeaessete ass $ POWRPLAN (c) 1990 by CH2M HILL 8 1990 1991 1992 1993 1994 1995 1998 1997 1999 2000 2001 2002 2003 2004 2005 2008 2007 AQgeaesessseessageassassaeseeteesses anascres r2azazee fcsasza= sse2s523 3 puseseas tceenses Susser (Nay - Septeaber) easaanserszesses Energy Requireaents (HWh) “97,781 103,009 108,272 231,725 236,275 240,749 241,257 241,889 242,123 242,589 242,918 243,274 243,595 243,913 244,199 284,445 284,890 244,939 Energy Dispatch (MWh) ay AELP Hydra: Annex Creek 43,577 15,577 15,577 15,577 15,377 15,377 15,377 15,577 15,577 3,577 15,577 15,877 15,877 15,577 15,577 15,577 15,577 15,377 Salaon Creek 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,258 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,258 ‘ fold Creek 3,488) 3,488) 3,488) 3,488 3,488 3,488 «3,488 = 3,4BB | «3,488 = 3,488 = 3,48B = 3,488 | 3,488 «3,488 3,488 3,488) 3,488 3,488 (2) Snettishaa/Crater Lake 56,571 64,777 67,018 118,108 116,108 118,108 118,108 118,108 118,108 118,108 118,108 £18,108 116,108 128,108 118,108 118,108 118,108 118,108 ik} Annex/Carlson Creek No.t Q 0 0 0 0 0 81,607 81,968 82,326 82,647 82,969 83,252 83,498 83,743 63,951 84,122 84,292 84,4466 (4) Crater Lake Elev. 1034 6 0 0 1,087 1,017 1,017 0 0 0 0 ° o 0 0 0 0 0 0 (3) Long Lake Elev. 845 0 6 0 0 0 0 0 0 9 a, 0 0 0 0 0 6 0 0 (a) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (7) GN EMD diesel 0 6 0 71,254 75,743 80,159 0 0 0 0 ° o 0 0 0 0 0 0 (8) Existing Oiesel: Gas Turbines 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 Leson Creek 0 o- 0 0 0 O° 0 0 o - 0 0 0 0 0 8 4 a fuke Bay 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 6 Gold Creek 4 0 0 0 0 0 0 ° 0 0 0 6 0 0 0 0 6 Soeeaae Bzeerss3 £23: tess: = TOTAL 98,889 104,098 109,336 232,697 237,188 241,602 243,679 243,924 244,169 244,378 244,549 244,718 2 Cost ($ Millions) Capital 0.0 0.0 0.0 1.3 4.3 13 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 Fixed 0.2 0.2 0.2 0.2 0.2 0.2 0.4 0.4 0.4 0.5 05 0.5 0.5 0.6 0.6. 0.6 07 Variable 1.6 1.8 Lg 37 38 3.8 34 3.4 ‘4 34 34 34 34 34 34 ‘a 34 Fuel 0.0 0.0 0.0 $.0 5.6 4.3 0.3 0.3 0.6 0.6 0.8 0.7 0.8 0.9 (0.9 1.0 Ad =: 2 = esscezss Sz suscizex sasa2232 3et22323 TOTAL 1.8 2.0 21 10.2 10.9 17 Md 4 nd aS iL3 Mb 7 11.8 11.9 12.0 12.1 124 p9-a fun Date: 02-Jul-90 Run Tises 03:33 PH Sgessatcecgresseceseesscasegessssss 4 POWRPLAN (c) 1990 by CH2M HILL 8 AUGeangeescagassansssegaepactssasess Suaner (Kay - Septeaber) srazssseszs393: Energy Requireaents (MWh) Energy Dispatch (MWh) a) AELP Hydroz Annex Creek Salaon Creek Gold Creek Q) Snettishae/Crater Lake ik] fnnex/Carison Creek Wot aw Crater Lake Elev, 1034 (3) Long Lake Elev. 843 (6) Caterpillar 3612 diesel ” 6H EMD diesel {8) Existing Diesels fas Turbines Leaon Creek Auke Bay Gold Creek TOTAL Cost ($ Millions? Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Annex/Carison Creek with Crater Lake Elev. 1038 Forecast: Multi-Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 202! 2022 2023 2024 2025 33 aeascsze sseccr: 2 anazaxas =: Sa xEscoscs es3: Sa SDnESSES azcsouaa AAS ALL 245,323 245,455 245,455 245,455 245,455 243,455 245,453 245,455 245,455 245,455 245,459 245,455 245,455 245,455 245,455 245,455 245,455, 45,577 13,577 15,377 15,577 15,577 45,577 25,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 25,254 23,254 23,254 23,254 23,254 23,254 23,254 23,258 23,254 23,254 3,488 «3,488 «3,888 «3,488 |= 3,488 | 3,4BR | 3,488 = 3,488 = 3,488 = 3,488) 3,488) |S, 4GB | 5,488 = 3,488 = 3,488 3,488 3,488 3, 408 118,108 118,208" 118,108 118,108 116,108 118,108 118,108 118,108 118,108 118,108 116,108 118,108 118,108 118,208 118,108 118,108 118,108 118,108 84,563 84,699 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 84,757 0 0 0 0 0 0 0 0 0 0 0 0 o a 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 6 0 Q 0 q 6 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 Q 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 a 6 0 0 0 0 0 0 6 0 4 q 0 0 0 0 0 0 0 0 0 0 0 Q 0 0 0 9 % 0 0 0 9 0 0 o 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Q 6 Segcacte ecezees3 eezssexz t=: gsageres cszsesee sszagrcs 2==2: = gectasss esczssse sssasee2 s2sssszx 2 Eargszse 244,989 285,125 245,183 245,283 245,183 245,183 245,183 245,183 245,163 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,163 7.0 0.7 34 Ma 1.2 1.3 egenases azisrrte rzsescae ares: 12.2 12.3 12.4 12.5 12.6 ud 1.5 M 11.7 1g 12.0 Wt 12.3 12.4 12.6 12.7 12.9 Ba S9-d Run Dates 02-Jul-90 Run Timer = 03:35 PH CO § POWRPLAN (c) 1990 by CH2M HILL 8 PU BUS BAR COST SECTION: Average Costs (Saillions): Fuel Costs Var oun Fixed O&M Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total - Energy Requireaents (MWh) Average Bus Bar Cost => Nominal (cents/kWh) ~~ Real (cents/tWh) Non-Mining Loads (Saillions): Fuel Costs Variable O&n Fixed Ob Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost Woainal (cents/kWh) => Real (cents/kWh) Page 7 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Annex/Carison Creek with Crater Lake Elev. 1034 Forecast: Multi-Nine 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 agseesee tezsasze sesssexz s2222222 = 2008 2007 fe REEEEEIE Ssssases sastcasz sasrares eresse22 szszzszz ressees2 szszsezz esezeres ezeseees stazsssz 0.0 0.0 6.2 6.7 0.4 0.5 18.8 10.7 1 114 12.2 13.0 13.8 14.6 15.4 10.3 10.3 10.3 10.4 10.3 9.3 97 10.0 Bal 33.1 w4 46.4 46.9 47.4 4 4 49.4 50.3 Sa 32.0 52.9 33.8 M7 277,000 291,464 306,028 606,885 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 A 9 1 6 17 7.8 Wy 8.1 8. 8 3.6 5. 1 4 8.3 85 86 49 4.8 4.7 4.5 4.3 . 4.2 4 1 326,591 327,306 328,033 328,661 329,285 329,812 330,238 330,664 330,996 331,228 331,460 331,700 33 3.3 2A 2.0 « ew ne ou ey o> 99-a Run Date: 02-Jul-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tine: = 03:35 PH Caser‘ —Annex/Cartson Creek with Crater Lake Elev, 1034 Forecast: Multi-Mine QGNNSESRASE RR Rage Resa eae e ees TITS $ POWRPLAN (c) 1990 by CH2M HILL 8 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Ugnegaececesesesssagcsssssgsssaseses geecaasa gessesac fanssrss =: gEsngss2 sessscss arezesss 3252: SERESE EREREAEE saesasea gsszsesz sszsscss 23s3rce2 sesessse cxessesa sexessca scasczex Mining Loads (Seillions): Fuel Costs 0.0 = 0.0. 000148 18.7 18.8 a4 89 OO tL 14.6 Variable O4n 0.0 0.0 0.0 37 3a 3.2 23 25 2.6 26 26 u 21 Fixed O&M 0.0 0.0 0.0 0.0 0.0 0.0 04 O84 0.5 0.5 05 0. 0.8 Capital Costs (existing systes) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0. 0.0 Depreciation Expense (new units) 0.0 0.0 0.0 16 1.6 1.6 49 6.9 ae 69 49 4. 6.9 Property Taxes (new units) 0.0 0.0 0.0 0.6 0.6 0.6 3.2 3.2 3.2 3.2 32 3. 32 Interest Expense (new units) 0.0 0.0 0.0 2.5 2.5 25 14.6 14.6 14.5 14.6 14.6 tn 146 Total 0.0 0.0 0.0 23.1 24.8 26.7 35.8 36.1 36.6 vA 7.8 38.3 3. 42.6 435 Energy Requiresents (Hh) 0 0 © 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 Average Bus Bar Cost =~ Honinal (cents/kwh) WA WA WA 1.6 8.2 8.8 M7 19 12.0 12.2 12.4 12.6 12.9 13.2 13.5 13.7 14.0 WI o> Real (cents/kWh) . nA WA WA 47 6.8 7.0 9.0 8.7 4.5 8.2 8.0 7.8 76 14 1.3 A ad 6.8 L9-@ Run Dates 02-Jul-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Ties = 03:35 PH Case: Annex/Carison Creek with Crater Lake Elev. 1034 Forecast: Multi-Mine SGuassearsssgeagssoecesetesoersseseee t POWRPLAN (c) 1990 by CHM HILL $ 2008 2009 2010 2011 2012 2013 2018 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 ERQessanearaeeagsassagsassanascesags Sagasesa onsasssa acecesaz zarsza22 azecseze sssessa esaczss: SE2 sazasses assests sassezsr eserszz= sacs: peecszce seserese BUS BAR COST SECTION: Average Costs (Seillicns): Fuel Costs 18.2 17.0 17.8 18.6 19.4 20.3 21.2 22.2 3.2 42 23.3 2.4 27.6 28.9 30.2 US 33.0 a Variable O&n 10.5 10.6 10.8 10.6 10.7 10.7 10.8 10.9 0.9 1.0 11.0 MeL W.2 WS * ALS wd 1.5 1b ’ Fixed OOM 16 7 1.8 1g 2.0 24 21 2.2 23 2.3 2.6 27 29 3.2 3 Capital Costs (existing systea} 2.6 26 26 2.6 2.8 2.6 2.6 2.8 26 2.6 28 2.6 2.6 26 & Depreciation Expense (new units) ay 6.9 6.9 6.9 6.9 5.3 5.3 5.3 3.3 3.3 5.3 5.3 33 3 Property Taxes (new units) 32 3.2 32 3.2 3.2 32 3.2 3.2 3.2 32 32 2 Interest Expense (new units) 14.6 14.8 14.8 14.6 14.6 12.4 12.1 12.1 12 4 20L 1 Total 35.6 56.8 37.5 58.4 39.4 36.3 57.4 38.5 39.7 60.9 Energy Requiresents (MWh) 635,744 635,885 635,827 635,827 635,827 635,827 635,827 635,627 “635,827 635,827 635,827 435,827 435,827 35,827 35,827 835,827 635,827 35,827 Average Bus Bar Cost . s- Nominal (cents/kWwh) 6.8 89° 9.0 9.2 9.3 8.9 9.0 2 94 9.6 9.8 10.0 10.2 10.4 10.7 10.9 14,2 ‘a =~ Real (cents/kWh) 40 39 3.8 36 3.5 3.2 31 ul 3.0 29 2.8 2.8 2.7 27 2.6 2.6 23 25 Non-Mining Loads ($millions): Fuel Costs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Vartable O&h 11 17 17 7.7 17 17 1? 1? 1? wl 77 77 wT WW a1 ww 7 Fixed 08M 1.0 1.0 Ld 1 1.2 1,3 13 14 4 1S Lb 1.7 17 1,8 Lg 2.0 24 Capital Costs [existing systes) 2.6 2.6 2.6 2.6 2.6 2.6 2.6 26 2.6 2.6 2.6 2.6 2.6 2.6 2.8 2.8 2.6 Depreciation Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Property Taxes (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Interest Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total 1.3 M3 11500 986 0 16 7 BBN 1200 12,0, 2 ‘420200123012 Energy Requireaents (MWh) 331,744 331,885 331,827 331,827 332,827 331,827 331,827 331,827 331,827 $31,827 331,827 331,827 331,827 331,827 331,827 334,827 331,627 331,827 Average Bus Bar Cost - Nominal (cents/kWh) 34 34 34 34 3.5 3.5 3.3 33 35 3.5 3.6 3.6 3b 3.6 37 37 37 37 > Real (cents/kWh) LS 1.5 14 14 L3 Ly 1.2 1.2 Ld Ll 1.0 1.0 1.0 0.9 OF 0.9 0.8 0.8 Run Date: 02-Jul-90 . JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tine: 03:35 PR Case: Annex/Carison Creek with Crater Lake Elev, 1034 Forecast: Multi-Hine Suagaggcergsaseeasagcasesessscetetet $ POWRPLAN (c) 1990 by CH2M HILL 2008 2009 2010 2018 2012 2013 2014 2083 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 MITT gggreaza srrzezsz 2222228 soesess SS ERSSSSSS Ssereszz csarcsez seszcsca sesaesr2 es! cea escrasse Hining Loads ($eillions}: Fuel Costs 17.0 17.8 18.8 19.4 20.3 21.2 22.2 23.2 14.2 23.3 26.4 27.6 28.9 30.2 3S 33.0 aa Variable On 2.8 29 29 3.0 3.0 BA ul 3.2 3.3 33 34 35 38 3b 37 3.8 ug Fixed O&M 0.7 0.7 0.8 0.8 0.8 09 09 1.0 1.0 10 Ma id 1.2 1.2 13 14 4 Capital Costs (existing systen) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 ’ Depreciation Expense (new units) 6.9 6.9 89 6.9 5.3 33 3.3 3.3 5.3 3.3 3.3 3.3 5.3° 3.3 33 5.3 5.3 Property Taxes (new units) 32 3.2 32 3.2 32 3.2 3.2 3.2 3.2 3.2 3.2 2 32 3.2 3.2 Interest Expense {new units) 14, 14.6 14.8 146 12.1 12.1 121 12.4 12. 12. 24 2.1 2.1 2.4 Tota? W400 43.2 HAL 0A AB HSH BAL 5.3 SS SSH. 57.2 SBA Energy Requiresents (MWh) = * 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 Average Bus Bar Cost -- Nosinal (cents/k¥h} M6 14.9 15,2 13.5 15.8 14,7 15.4 a4 15.8 16.2 16.5 17.0 17.4 17.8 18.3 18 Lf 4 8 19.3 19.9 => Real (cents/t¥h) 4.6 64 4.3 41 6.0 34 3.2 Su 3.0 49 4.8 47 - 46 4s 4 4.3 4s w 1 a © 69-a Run Dates 09-Mar-90 . JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tine: = 10:38 AM : Case: Lake Dorothy with Crater Lake Elev, 1034 and Long Lake Elev. 845 Forecast: Multi-Mine Aggeracecagscecssescesscocaceccogete # POWRPLAN (c) 1990 by CH2M HILL 8 1990 1991 1992 1993 1994 1995 1996 1997 1998 19992000 2001 2002 2003 2004 2008 2006 = 2007 Mesegcaseecercgesecesessccgsssesesss sassease recesses = sessesss SSersss= seesssss esesezss Peak Demand (MW) ~ ry of Results (aft ervati Peak Demand 31.3 53.6 36.0 103.0 104.8 = 106.5 106.4 = 108.4 = 106.3 106.3 106.2106. = 106.6 = 108.8 = 106.8 = 107.0 107.2 L072 Peak Plus Reserve Requireaent 93.6 98.3 103.0 177.2 179.0 180.7 180.6 = 180.6 = 180.5 180.5 180.4 = 180.6 = 180.8 = 1BL.0 181.0 1BL.2 181.4 188 Installed Capacity A515) 151.5 151.5 183.8 183.8 183.4 209.4 209.4 209.4 209.4 209.8 209.4 = 209.4 = 209.4 = 209.4 = 209.8 = 209.8 209.8 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0” 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requirements (MWh) 277,000 291,464 305,028 606,085 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 Fire Capability of Installed Units (MWa} = 103.6 = 103.6 = 103.6 = 130.2, 130.2, 130.2, 144.5 148.5 188.5 188.5 104 KS 1485S SSS SS New Capacity to Meet Energy Req’ts (MW) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -- a) AELP Hydro: . . Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,040 35,080 35,040 35,060 35,080 35,040 35,040 35,080 35,040 35,040 935,040 35,040 35,040 35,080 35,040 35,040 35,040 Gold Creek 5,400 5,400» 5,400 5,400 5,400 5,400» 5,400 = 5,800 5,400 5,400 5,400 5,400 5,400 5,400 5,400 = 5,400 5,400 «5,400 (2) Snettishae/Crater Lake 213,040 227,504 242,068 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 (3) Lake Dorothy 0 0 0 0 9 0 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 (4) Crater Lake Elev. 1034 0 0 0 2,048 2,648 2,648 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,048 (3) Long Lake Elev. B45 0 0 © 12,766 12,766 912,766 12,766 12,766 9 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 (6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 9 0 0 0 9 o 0 0 0 0 o 7) 6M EMD diesel 0 0 0 189,018 196,426 202,378 93,957 94,672 95,399 . 96,026 96,650 97,177 97,608 98,030 98,362 98,593 98,825 99,066 (8) Existing Diesel: Bas Turbines 0 0 0 7,858 11,546 16,886 0 0 0 0 0 0 0 0 0 0 0 0 Leaon Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 Q 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 8 0 0 0 0 0 0 0 0 0 “0 0 0 TOTAL 277,000 291,464 306,028 606,865 618,381 629,674 630,591 631,306 632,034 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 Unserved Energy 0 0 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost (8 Millions) . ‘ Capital Fixed Variable Fuel TOTAL Wet Present Value (1990 - 2050) $493.8 aillion New Resources Added (MW): Lake Dorothy 26.0 Crater Lake Elev, 1034 0.0 Long Lake Elev. 845 0.0 Caterpillar 3612 diesel 6M END diesel M9 OL-d 2020 107.5 181.7 209.4 0.0 635,827 144.5 0.0 23,520 35,040 5,400 330,836 126,225 2,048 12,766 0 © 99,192 coco 635,827 635,827 2021 107.5 181.7 209.4 0.0 635,827 MAS 0.0 23,520 35,040 5,400 330,836 126,225 2,048 12,766 0 99,192 ecooo 635,827 9 M17 2.9 1.4 2022 2023 2024-2025 SSERSS2 essgesss 107.5 181.7 209.8 0.0 107.5 181.7 209.4 0.0 107.3 181.7 209.4 0.0 107.5 181.7 209.4 0.0 635,827 635,827 635,827 635,827 144.5 0.0 144.5 0.0 144.5 0.0 144.5 0.0 23,520 35,040 5,400 330,836 126,225 23,520 35,040 5,400 330,838 126,225, 23,520 35,040 35,080 5,400 5,400 330,836 330,836 126,225. 126,225 2,048 2,848 2,848 2,848 12,766 12,766 12,786 12,766 0 0 0 0 99,192 99,192 99,192 99,192 23,520 eooo ecco boooo 635,827 35,827 0° 0 0 0 7007 TAT Ml 2 SSS 500 M6 ALB OL LS Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tieez = 10:38 AN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine sosegegersesegsecscscestssssessesess % POWRPLAN (c) 1990 by CH2M HILL 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Magnengececescanssccccagcsstssseseas sauesese Ssscec2a ses2=2=5 See; Suaeary of Results (after conservation): es: 2 Peak Deaand (KW) Peak Deaand 107.4 = 107.5 107.5) :107.5 107.5 107.5 107.5 107.5 107.5 107.5 107.5 107.5 Peak Plus Reserve Requiresent 181.6 = 181.7) 281.7 181.7) 181.7 181.7) 181.7 184.7 18.7 184.7 188.7 188.7 Installed Capacity 209.8 = 209.4 = 209.8 = 209.8 = 209.4 209.4 209.4 207.4 = 209.4 209.4 209.4 209.4 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requiresents (MWh) 635,744 635,885 635,827 635,627 635,827 635,827 635,827 635,827 635,827 635,627 635,627 635,827 Fire Capability of Installed Units (MWa) = 144.5 184.50 244.50 144,50 14405 48S NAS 14S AS SSS Wew Capacity to Meet Energy Req’ts (MW) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -~ Ww AELP Hydro: Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 35,040 Gold Creek 5,400 5,800 = 5,400 5,400 «5,400» 5,400 5,400 5,400 5,400 5,400» 5,400 = 5, 400 (2) Snettishae/Crater Lake 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,835 330,836 330,836 (3) Lake Dorothy 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 126,225 (4) Crater Lake Elev. 1034 2,848 2,648 2,846 2,648 2,848 2,848 2,648 2,848 2,048 2,848 2,848 2,848 (3) Long Lake Elev. 845 12,766 12,766 12,766 12,766 12,766 12,768 12,766 12,766 12,766 12,766 12,766 = 12,766 (6) Caterpillar 3612 diesel 0 0 0 0 9 9 0 0 0 0 0 0 7) GN EMD diesel 99,110 99,250 99,192 99,192 99,192 99,192 99,192 99,192 99,192 99,192 99,192 99,192 (8) Existing Diesel: , Gas Turbines 0 0 0 0 0 0 0 0 0 oO. 0 Lemon Creek 0 0 0 0 0 0 9 0 _o 0 0 fuke Bay 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 eeeesees sseeecss ee: = ze: 22 = TOTAL 635,744 635,885 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 Cost ($ Millions) Capital 16.6 16.6 16.6 11.7 M7 1.7 14.7 1.7 14.7 M7 Fixed 1.8 Lg 2.0 24 2.4 2.2 2.3 2.5 2.6 27 Variable 10.7 10.7 10.8 10.9 10.9 11.0 11.0 ML 11.2 U3 Fuel 18.6 20.3 21.2 22.2 23.2 26.4 TOTAL Wet Present Value (1990 - 2050) New Resources Added (MW): Lake Dorothy Crater Lake Elev. 1034 Long take Elev. 845 Caterpillar 3612 diesel 6M EMD diesel TL-a i I ! age Bo . Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Vines = 10338 AM Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine aagegsascacassesssseeecgcetssssesss $ POWRPLAN (c} 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1993 19% 1997 1998 1999 2000 = 2001 2002 2003 2008 2008 2008 —-2007 Aeeegegeecegeeceagesassegsaseseeseas se mnsecsse Winter (October - April) Energy Requirements (MWh) 179,219 168,455 197,756 375,159 382,106 388,925 389,334 389,618 389,911 390,142 390,368 390,538 390,643 390,749 390,797 390,783 390,770 390,761 Energy Dispatch (MWh) {1) AELP Hydro: Annex Creek 7,3 7,937,943 7,943 7,983 7,437,943 ——-7,94S 7,943 -7,94S 7,983 7,943 7,94S—-7,94 7,943 7,943 7,943 7,943 Salaon Creek 11,786 11,786 11,786 11,785 11,786 11,786 11,786 12,786 1,786 11,786 11,786 11,786 14,786 11,786 11,788 11,785 11,786 11,786 Gold Creek 1,912 1,912 1,912 2,912 1,912 2,982,912, 9NZ PLZ 1,912,912 912 982,982,912 1,912 1,912 1,912 (2) Snettishaa/Crater Lake 156,469 165,726 £75,050 282,727 202,727 212,727 212,727 212,727 212,727 22,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 (3) take Dorothy 0 0 0 0 0 0 BL,163 81,263 B1,263 81,263 81,163 81,163 81,163 81,163 81,163 BL ,163 81,263 81,163 (4) Crater Lake Elev. 1034 0 0 O = 1,831 1,832 1,831 1,831 1,831,831 1,83 1,311,831 1,831 1,831 1,831 1,831 1,831,832 (3} Long Lake Elev. B45 0 0 0 8,209 8,209 8,209 = 8,209 «8,209 «8,207 ~=— 8,207,207» B,207 = 8,207 By 207,209 8,207» 8,209 8,209 {6) Caterpillar 3612 diesel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 a) GM EMD diese) 0 0 0 122,321 125,238 126,777 62,984 63,342 63,710 64,015 64,317 64,562 64,742 64,923 65,087 65,108 65,170 65,235 (8) Existing Diesel: Gas Turbines 9 0 0 7,458 11,545 16,886 0 0 0 0 0 0 0 0 0 0 0 0 Leeon Creek 0 0 0 0 0 0 0 0 wl 0 9 0 0 _0 0 0 0 o ™ fuke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 178,111 167,368 196,692 374,188 381,193 388,072 380,555 388,914 389,281 389,587 389,889 370,133 390,314 390,495 390,618 390,679 390,741 390,808 Cost (8 Millions) Capital Fixed Variable Fuel TOTAL cL-a 09-Mar-90 10:38 AN Run Dates Run Vines Seaereagnsesesncesarsesessaesesceee $ POWRPLAN (c) 1990 by CH2M HILL & Tanenagneaensssasascsasesesecssssses Winter (October - April) seaeszzzs: Energy Requirements (MWh) Energy Dispatch (MWh) a) AELP Hydro: Annex Creek Saleon Creek Gold Creek {2) Snettishaa/Crater Lake () Lake Dorothy (4) Crater Lake Elev, 1034 (5) Long Lake Elev. 845 (6) Caterpillar 3612 diesel ) 6M EMD diesel (8) Existing Diesel: Gas Turbines Leaon Creek fuke Bay Gold Creek TOTAL Cost ($ Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Caser 2008 2009 2010 2011 2012 2013 2014 390,633 390,562 390,371 390,371 390,371 390,371 390,371 7,3 7,983 7,983 7,943 7,943 7,943 7,983 11,786 14,786 11,786 11,786 11,786 11,786 11,786 1,912 1,912 1,912 1,912 1,912 4,912 1,912 242,727 212,727 212,727 212,727 242,727 212,727 212,727 81,163 81,163 81,163 81,163 81,163 81,163 81,163 1,831 1,831 1,832 1,831 1,831 1,831 1,832 8,209 8,209 = B, 209 »=—-B, 209-8209 8,209 8,209 0 0 0 0. 0 0 9 65,183 65,188 65,072 65,072 65,072 65,072 65,072 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 9 9 0 0 sesasess sesezces sscccses 22 3 390,755 390,760 390,643 390,483 390,643 390,643 390,643 9.7 v7 9.7 97 U7 6.8 6.8 1.0 1.0 Al 1 1d 1.2 1.3 6.8 69 6.9 6.9 7.0 7.0 | 7.0 10.3 10.8 11.3 11.8 12.3 12.8 13.4 Lake Dorothy with Crater Lake Elev, 1034 and Long Lake Elev. 845 Forecast: Multi-Mine 2015 390,371 7,943 11,786 1,912 212,727 B1, 163 1,831 8,209 0 65,072 ecco 390,643 2016 390,371 7,943 11,786 1,912 212,727 81,163 1,831 8,209” 9 65,072 coco 390,683 2017 2018 2019 390,371 390,371 390,371 7,943 11,786 1,912 212,727 81,163 1,831 8,209 0 65,072 ecco 390,643 7,943 11,786 1,912 212,727 81, 163 1,831 8,209 0 65,072 coco 390,643 7,943 11,786 1,912 212,727 81,163 1,831 8,209 0 65,072 eocoso 390,643 2020 2024 2022 2023 390,371 390,371 390,371 390,371 7,983 11,786 a 1,912 2,727 81,163 1,831 8,209 0 65,072 eocos 390,643 7,943 At, 786 1,912 212,727 Bi, 163 1,831 8,209 0 45,072 cooo 390,643 7,983 11,786 1,912 212,727 81,163 1,831 8,209 0 65,072 coco 390,643 6.8 1.8 TA 19 7,983 11,786 1,912 212,727 81,163 1,831 8,209 0 65,072 ecco 390,643 2024 390,371 7,943 11,786 4,912 212,727 81, 163 1,831 8,209 0 65,072 cooo 390,643 2025 390,371 7,043 11,786 1,912 212,727 81,163 1,831 8, 209 o 65,072 390,643 Sib €L~-a Run Dates 09-Mar-90 Run Times = 10:38 AN eagessagsecegsagascesgsssessssscsees $ POWRPLAR (c) 1990 by CH2M HILL & Segegnaesagcesoesancssesesesoccscose Sumner (May -~ Septenber) Energy Requireaents (HWh} Energy Dispatch (MWh) a) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake ) Lake Dorothy (4) Crater Lake Elev. 1034 (5) Long Lake Elev. 845 (8) Caterpillar 3612 diesel 7 6H EMD diesel (8) Existing Diesel: Gas Turbines Lenon Creek uke Bay Gold Creek TOTAL Cost (8 Millions) Capital Fixed Variable Fuel TOTAL 1990 1991 1992 1993 97,781 103,009 108,272 231,726 15,977 23,254 3,488 56,371 0 cooo 0 9 0 9 15,577 15,577 15,377 23,254 = 23,254 = 23,258 3,488 61,777 0 coco ocooo 104,096 3,488 3,488 67,018 118,108 0 0 0 1,017 0 4,537 0 0 0 66,697 0 0 0 0 0 0 0 0 109,336 232,697 1994 1995 236,275 240,749 15,577 15,577 23,258 23,254 3,488 3,488 118,108 118,108 0 0 1,017 1,017 4,557 4,557 0 0 71,188 75,602 0 0 0 0 0 0 0 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Forecast: 1996 Lake Dorothy with Crater Lake Elev, 1034 and Long Lake Elev. 845 Muiti-Mine 1997 1998 1999 2000 2001 2H1,257 241,689 242,123 242,519 242,916 243,278 15,577 23,258 3,488 118, 108 45,062 1,017 4,557 0 30,973 ecco 242,036 15,577 23,258 3,488 118, 108 45,062 1,017 4,557 0 31,329 ooao 242,392 15,577 23,254 3,488 118,108 45,082 1,017 4,557 0 31, 689 eooo 242,752 15,577 23,258 3,488 118,108 45,062 1,017 4,557 0 32,011 ecco 243,074 15,577 23,254 3,480 118, 108 85,062 1,017 + 4,557 0 32,333 coco 243,395 15,577 23,254 3,488 118,108 45,062 1,017 4,557 0 32,616 ecco 243,679 2002 2003 2004 2005 243,595 283,915 244,199 244,445 15,577 23,258 3,488 119,108 45,062 1,017 4,557 0 32,861 coco 243,924 15,577 23,254 3,488 118,108 45,062 1,017 4,557 0 33,108 ecco 244,189 15,577 23,254 3,488 15,577 23,258 3,488 118,108 118,108 45,062 1,017 4,557 0 33,315 coco 45,082 1,017 4,597 0 33,486 oooo 244,378 244,549 2006 244,690 15,577 23,254 3,488 118, 108 45,062 1,017 4,557 0 33,655 eooo 244,718 244,939 15,577 23,254 3,488 118, 108 45,082 1,017 4,587 0 33,029 coco 244,892 PL- 09-Mar-90 10:38 AM Run Date: Run Tises Ugaggenenecseeasescagrscsesecesssses % POWRPLAN (c) £990 by CH2M HILL Onsaesegnscersgcececscossssessessees Suaser (May - Septeaber) Energy Requireaents (MWh) Energy Dispatch (MWh) (1) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake (3) Lake Dorothy 4) Crater Lake Elev. 1034 (5) Long Lake Elev. 845 (6) Caterpillar 3612 diesel (7) 6M EMD diesel (8) Existing Diesel: §as Turbines Lemon Creek Auke Bay Gold Creek TOTAL Cost Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. B45 Forecast: Multi-Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2AS ALL 245,323 245,855 245,455 245,455 245,455 245,455 245,455 245,455 245,455 245,455 245,455 285,455 245,455 245,455 245,455 245,455 245,455 15,577 15,577 13,577 15,377 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,377 15,577 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 23,254 3,488 «3,488 = 3,488 =—3,488 = 3,488 = 3,488 3,488 = 3,488 = 3, 48B 3,488 = 3,48B = 3,488 = 3,488 = 3,488 = 3,488 3,488 = 3,888 = 3,488 118,108 128,108 118,108 128,108 118,108 118,208 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 95,062 45,062 45,062 45,062 45,062 $5,062 45,062 45,062 45,062 45,062 45,062 45,062 45,062 45,062 45,062 45,062 45,062 45,082 1,017 1,017 1,017 1,017 1,017 1,017 1,017,017 1,017 1,087 1,017 1,017 1,017 1,017 1,017 1,017 1,087 1,017 4,557 4,557 4,557 4,557) 4,557 4,557 4,557 4,557 4,557 4,557) 4,557 4,557 4,557 4,557 4,557 4,557 4,557 4,557 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 33,926 34,062 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 34,120 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ee: 2 sees: 244,989 245,225 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 SL-d Run Date: 09-Mar-90 Run Tiees = 10:38 AM ONggeggenegegssassagsaggscecegeegss $ POWRPLAN (c) 1990 by CH2M HILL & SONNeeggeageaagcegereseaessecseesess BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs Variable O&M Fixed Ob Capital Costs (existing systee) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requirements (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) ~~ Real (cents/kWh) Non-Mining Loads (Seillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systee) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) -- Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine 1990 1991 1992 1993 1994 1995 1995 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 ef Seersss2 seazeses ceesesss 14.0 15.9 18.0 0.0 0.0 17 8.2 8.7 9.2 97 10.5 11.3 12.1 12.9 13.7 14.5 15.3 6.2 6.7 7.0 10.5 10.6 10.7 10.1 10.2 10.2 10.2 10.3 10.3 10.3 10.4 10.4 10.5 10.5 10.6 0.4 0.5 0.5 0.5 0.5 0.6 1.0 1.0 Ll 1 1.2 1.2 1.3 1.3 14 14 15 1.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0.0 0.0 0.0 2.5 2.5 2.5 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 71.0 0.0 0.0 0.0 0.8 0.8 0.8 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 0.0 0.0 0.0 3.8 3.8 3.8 14.2 14.2 2 2 14,2 14.2 14.2 14.2 14.2 14,2 14.2 14.2 277,000 291,464 306,028 606,885 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 . 15 5.4 3.2 Sal 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.2 6.7 7.0 6.9 7.2 15 7.6 7.6 7.6 7.6 7.6 1.7 77 17 17 17 17 7 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.8 0.8 0.9 0.9 0.9 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 .! 277,000 291,464 306,028 302,885 314,381 325,674 326,591 327,306 328,033 328,661 329,285 329,812 330,238 330,664 330,996 331,228 331,460 331,700 34 3 3 Re we — a> mw ue ue 3.3 2.2 a au 9L-a Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiaet = 10:38 AN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. B45 Forecast: Multi-Mine Henegaesesssassegcaassassasssgesegss $ POWRPLAN (c) 1990 by CH2M HILL 8 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2008 2005 2006 2007 ANsgeaeagecenssescgesseseesecesosees sesscees seseess= Wining Loads ($millions): Fuel Costs 0.0 0.0 0.0 14.0 15.9 18.0 nd 8.2 8.7 9.2 9.7 10.5 MLS 12.1 12.9 13.7 5 45.3 Variable O&M 0.0 0.0 9.0 37 34 3.2 2.6 2.6 2.6 2.6 2.6 2.6 2.7 27 2.7 2.8 2.8 2.8 Fixed OM 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.4 0.4 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 Capital Costs (existing systes) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Depreciation Expense (new units} 0.0 0.0 0.0 2.5 25 2.5 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 Property Taxes (new units) 0.0 0.0 0.0 0.8 0.8 0.8 3.2 3.2 3.2 3.2 32 3.2 3.2 3.2 3.2 3.2 3.2 Interest Expense (new units) 0.0 6.0 0.0 3.8 38 3.8 14.2 14,2 18.2 14,2 14.2 14.2 14.2 14.2 14.2 14.2 4.2 Total 0.0 0.0 0.0 24.8 26.4 28.3 351 35.6 36 36.7 37.2 38.0 38.9 39,7 40.6 ad : Energy Requireaents (MWh) 0 0 0 304,000 304,000 304,000 304,000 308,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 Average Bus Bar Cost . . . -- Nominal (cents/kWh) WA WA WA 8.1 8.7 9.3 6 11.7 119 12.1 12.2 12.5 12.8 13.1 13.3 13.6 13.9 14.2 -- Real (cents/kWh) WA WA WA TA 13 750+ BY 8.6 8.4 81 1 17 7.5 74 7.2 7.0 69 4.7 LL-@ 09-Mar-90 10:38 AM Run Date: Run Tiae: Segnggesegcaseggescscggessessegecasy $ POWRPLAN (c) 1990 by CH2M HILL & Qgggeggegggcaggoaggeggsecsggsegsetss BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requirements (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) ~~ Real (cents/kWh) Won-Mining Loads (Saillions): Fuel Costs Variable O&M Fixed O&n Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requiresents (MWh) Average Bus Bar Cost -- Nominal (cents/kWh) ~~ Real (cents/kWh) 2008 2009 2010 2011 2012 Seeeeses s22222: 16.1 17.0 1 10.6 10.6 10. 1.6 1.7 18.6 19.4 10.7 10.8 1.9 2.0 7.0 7.0 7.0 7.0 3.2 2 7.8 0.7 1.8 2.6 2.6 2.6 2.6 2.6 7.0 3.2 4.2 35.4 56.4 37.3 38.2 59.2 635,744 635,885 635,827 635,827 635,827 0.0 0.0 0.0 0.0 0.0 17 17 7.7 17 17 1.0 1.0 Ma 1d 1.2 2.6 2.6 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2013 20.3 10.9 24 2.6 4.5 3.2 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine 2014 2015 2016 geeezese s2zzsz 55.0 Sb. 37.3 635,827 635,827 635,827 8.6 8.8 9.0 3.0 29 2.9 0.0 0.0 0.0 17 17 17 1.3 1.3 14 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 SEEEE EEEEEsss ese: 2017 2018 25.3 11.2 2.6 2019 2020 2021 26.4 27.6 28.9 M3 M3 11.4 2.7 2.8 29 2.6 2.6 2.6 45 45 4.5 3.2 3.2 3.2 0.4 0.4 ol. 62.5 63.9 635,827 635,827 635,827 635,827 635,827 9.6 9.8 10.1 2.7 2.6 2.6 2022 30.1 MAS 3a 2.6 4.5 3.2 65.4 635,827 10.3 2.5 2023 2024 2 Seessesz eeeszees 635,827 2025 ua 11.8 3.5 2.6 45 3.2 10.4 70.4 635,827 1 24 331,744 331,885 331,827 331,827 331,827 34 34 34 34 35 1.5 1.5 1.4 1.4 1.3 331,827 331,827 331,827 —w a ru 9.2 9.4 2.8 2.7 0.0 0.0 1.7 77 14 1.5 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 11.8 11.8 331,827 331,827 331,827 331,827 331,827 ew oe wm os 331,827 3.7 0.9 331,827 3.7 0.8 8L-d 09-Mar-90 10:38 AN Run Date: Run Tine: Aungagagcsseasecgasasegasesssesgsese $ POWRPLAN (c) 1990 by CH2M HILL 8 Adegeagngseececacesoecesssagsecetese Wining Loads ($aillions): Fue) Costs Variable O&M Fixed ObM Capital Costs (existing systea) Depreciation Expense {new units) Property Taxes (nex units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost -- Nosinal (cents/kWh) ~~ Real (cents/kWh) 2008 2009 2010 2011 2012 304,000 304,000 15.4 61 15.7 6.0 2013 304,000 13.9 Sel JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Forecast: Multi-Mine 2014 2015 2016 2017 304,000 304,000 304,000 304,000 14.3 14.6 15.0 15.4 5.0 49 4.8 4.7 J = 2018 304,000 15.8 4b 2019 304,000 16.2 45 2020 304,000 16.6 44 2021 304,000 Lake Dorothy with Crater Lake Elev. 1034 and Long Lake Elev. B45 2022 304,000 17.5 4.3 2023 2024 soeee: 304,000 18.5 4,2 2025 Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiaes = 11:08 AM Cases Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine geggngescacsecsesegsesegcgcesesseges $ POWRPLAN (c) 1990 by CH2K HILL & 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2008 2005 2006 2007 Cagseeseseccaceecancessscsseessasecs ee 7 Suamary of Results (after conservation): Peak Desand (HW) Peak Demand 31.3 33.6 56.0 103.0 104.8 108.5 106.4 © 105.4 = 106.3 106.3 108.2 106.4 = :108.6 106.8 106.8 = 107.0 107.2 107.2 Peak Plus Reserve Requirement 93.6 96.3 103.0 177.2 179.0 180.7 180.6 = 180.6 = 180.5 180.5 180.4 = 180.6 = 180.8 = 181.0 181.0 181.2 1814 ABIL Installed Capacity 151.5 158.5 151.5 189.2 189.2 186.7 186.7 186.7 186.7 186.7 186.7 86.7 = 18.7 186.7) 186.7 186.7 186.7 186.7 Additional Required Capacity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Requirerents (MWh) 277,000 291,464 306,028 606,885 618,381 627,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 638,996 635,228 635,460 635,700 Fira Capability of Installed Units (Ma) 103.6 103.6 103.6 134,7) 134.7 139.5 139.5 13965 139.5139.5139%.5 139.5 139.5 139.5 139.5 139513518 New Capacity to Meet Energy Req’ts (Ni) 0.0 8 =60.0 000i Energy Dispatch (MWh) -- (1) AELP Hydro: Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Sataon Creet 35,040 35,080 35,040 35,040 35,040 35,080 35,080 35,040 35,040 35,040 35,040 35,080 35,040 35,040 35,040 35,080 35,040 35,040 Gold Creek 5,400 5,400 5,400 5,400 5,400 5,400 5,800 5,400 5,400 5,400 5,400 5,400 «5,400 5,400 5,400 5,400 5,400 5,400 w (2) Snettishan/Crater Lake 213,040 227,504 242,088 330,838 330,836 330,836 330,036 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 1 (3) Dorothy/Long Lake Tunnet 0 0 0 0 © 42,082 42,082 42,082 42,042 42,042 42,082 42,082 42,042 42,042 42,082 42,042 42,042 42,082 s (4) Crater Lake Elev, 1034 0 0 0 «2,848 «2,848 2,848 «2,848 2,848 «2,048 «2,848 «2,848 «2,848 + «2,848 2,848 ~=— 2,848 «2,848 2,848 2,848 wo (5) Long Lake Elev. 845 0 0 0 12,768 12,766 12,766 12,766 12,766 12,766 12766 12,766 12,766 12,766 12,768 12,768 12,786 12,766 124766 (6) Caterpillar 3612 diesel 0 0 0 o. 0 ° 0 0 0 0 0 ° 0 0 0 0. 0 0 (7) GH END diesel 0 0 0 196,475 207,089 177,222 178,140 178,855 179,582 180,209 160,833 181,360 181,787 182,213 182,545 182,776 183,008 183,249 (B) Existing Diesel: Gas Turbines 0 0 0 0 882 0 0 0 0 9 0 0 0 0 0 0 0 0 Leaon Creek 0 0 0 0 0 0 0 9 0 0 0 9 0 0 0 0 0 0 uke Bay 0 9 0 9 9 0 0 0 9 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 aes 2: TOTAL 277,000 291,868 306,028 606,885 628,381 629,674 630,591 631,305 632,034 632,661 633,285 633,812 634,238 634,664 638,996 635,228 635,460 635,700 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost ($ Millions) Capital 0.0 0.0 0.0 5.4 34 10.3 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 Fixed 0.4 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 Variable 6.2 4.7 7.0 10.6 10.7 10.7 10.8 10.9 11.0 11.0 Wat 1.2 MW.3 3 M4 M15 11.6 Fuel 0.0 0.0 0.0 13.6 15.3 13.8 15.5 16.4 17.2 18.1 19.6 21.0 22.4 23.9 25.3 26.8 28.3 TOTAL 6.7 Tl 15 301 U9 35.4 36.7 v.68 38.6 39.5 40.5 42.0 43.6 ASL 46.7 48.3 49.9 515 Net Present Value (1990 - 2050) $589.1 aillion Hew Resources Added yy TTT ross ses ssesns cress scsccces crc s cece reese seer es eee reese sre see cesses. Dorothy/Long Lake Tunnel 0.0 Crater Lake Elev. 1034 0.0 Long Lake Elev. 845 0.0 Caterpillar 3612 diesel 6M END diesel 3.7 08-g Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Timer = 11:08 AM : Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 645 Forecast: Multi-Nine Hegggeoggeccececesesescesescocsesses @ POWRPLAN {c} 1990 by CH2M HILL 8 2008 2009 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Oegresgcncesscceeeccssgscecesseasses sesazecs sScess: saae a Sunsary of Results (after conservation): Peak Demand (MW) Peak Desand 107.4 = 107.5 107.5 107.5 107.5 107.5 107.5 207.5107.5107.5 107.5 107.5 107.5 107.5 107.5 107.5 207.5 107.5 Peak Plus Reserve Requiresent 181.6 181.7 181.7) 1BL.7) 181.7 1BL.7 181.7 181.7) 181.7 181.7 181,7181.7 181.7 184.7 84.7 181.7 181.7 181,77 Installed Capacity 186.7 186.7 .186.7 186.7 186.7 186.7 = 186.7 = 186.7 186.7 = 186.7 18.7 186.7 186.7 188.7 186.7 = 186.7 «186.7 186.7 Additional Required Capacity 0.0 «60.0 0.0siitiiitiiiiiitititi titi Energy Requiresents (MWh) 635,744 635,885 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 Fire Capability of Installed Units (MWa) 139.5 139.5) 139.5) 139.5) 139.5) 139.5 139.5 139.5 139.5 139.5 139.5 139.5 139.5 139.5 139.5 139.5 39S 38S Wew Capacity to Meet Energy Reg’ts (MW) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Dispatch (MWh) -- {1) AELP Hydro: : Annex Creek 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 23,520 Salaon Creek 35,040 35,080 35,040 35,040 35,080 35,040 33,040 35,040 35,040 35,040 35,040 35,040 35,040 35,080 35,080 35,040 35,080 35,080 Gold Creek 5,400 5,800 5,400 «5,400» 5,400 «5,400» 5,400» 5,400 5,400 5,400 5,800 5,400 5,400 5,400 5,400 5,400» 5,400 5,400 (2) Snettishae/Crater Lake 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 330,836 (3) Dorothy/Long Lake Tunnel 42,082 42,082 42,042 42,042 42,042 42,042 42,042 42,042 82,042 42,042 42,042 42,042 42,042 42,042 42,042 42,042 42,082 42,082 (4) Crater Lake Elev. 1034 2,848 2,848 2,888 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,848 2,888 2,848 2,848 2,648 2,848 2,848 (3) Long Lake Elev. 845 12,766 12,766 12,765 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 12,766 912,766 12,766 (6) Caterpillar 3612 diesel 0 9 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 (7) GH END diesel 183,293 183,433 183,375 183,375 183,375 163,375 183,375 183,375 183,375 183,375 183,375 183,375 183,375 183,375 183,375 183,375 183,375 183,375 (8) Existing Diesel: : Gas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Leaon Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Gold Creek 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 435,744 635,085 635,827 435,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 Unserved Energy 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o° 0 0 0 Cost ($ Millions) Capital 10.7 10.7 10.7 7 107 53 SS SS SS SF BF SB 53 FS SFB 53 FS 00 Fixed 10 LOO 1 ota 120002 23 2 AS TBR 20 Variable M70 1B IL 0 AZZ ADA S122 ATES SLT Fuel 2.8 $3 | 329 3359 «S32 AO A208 487 ABB S10 53,3 55.7 58.2 80,9 3B TOTAL 53.2 Wet Present Value (1990 - 2050) New Resources Added (MW): Dorothy/Long Lake Tunnel Crater Lake Elev. 1034 Long Lake Elev. 845 Caterpillar 3612 diesel 6H EMD diesel ~~) ———Y T8-a Run Date: 09-Mar-90 Run Tiees = 11:08 AN Hengreeecageaessegscescggeegsagseess $ POWRPLAN (c) 1990 by CH2M HILL ¢ Megnggeececesagcesesescessecesgsegss Winter (October - April) Energy Requireaents (MWh) Energy Dispatch (MWh) (1) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake (3) Dorothy/Long Lake Tunnel (4) Crater Lake Elev. 1034 (3) Long Lake Elev. 845 (6) Caterpillar 3612 diesel (7) 6H EMD diesel (8) Existing Diesel: Gas Turbines Leaon Creek Auke Bay Gold Creek TOTAL Cost ($ Millions) Capital Fixed Variable Fuel TOTAL 1990 Seeeeee2 esezeszs eszesss= fe=ze=== 1991 1992 1993 179,219 188,455 197,756 375,159 1 i, i, 158, 178, 943 786 912 469 0 coco ecco M1 7,943 11,786 1,912 165,726 0 ecco coco 187,368 7,943 11,786 1,912 175,050 0 0 0 0 0 sarees 196,692 7,943 11,786 1,912 212,727 0 1,831 8,209 0 129,779 0 0 0 0 sseesest 374,188 3.2 0.3 6.8 8.9 19.3 1994 382,106 7,943 11,786 1,912 212,727 0 1,831 8,209 ° 135,901 882 381,193 3.2 0.3 6.9 10.1 20.4 1995 308,925 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 116,630 ecco 388,072 22.3 JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Forecast: 1996 389,334 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 117,113 coco 388,555 Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 ul ti-Mine 1 997 389,618 1 a 2 u 7,943 1,786 1,912 2,727 7,033 1,831 8,209 0 7,472 ecooo 398,914 =: 6.2 0.3 7.0 10.1 e223 23.7 1998 389,91 7,983 11,786 1,912 212,727 27,033 1,831 8,209 0 117,839 ecocoo 389,281 azz eeszess: 1999 390,142 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 118,145 cooo 2000 390,368 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 118,447 ecco 2001 390,538 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 118,69. cooo 2002 seeesses = 390,643 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 118,872 coco 2003 390,749 7,983 11,786 1,912 212,727 27,033 1,831 8,209 0 119,053 coco 2008 390,797 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 119,176 ecooo 2005 390,783 7,94 3 11,786 1,91 2 212,727 27,033 1,831 8,209 119,23 0 7 2006 390,770 7,943 11,786 1,912 212,727 27,033 1,831 8,209 0 119,299 coco 2007 390,761 7,943 11,786 1,912 212,727 27,033 1,83 8,209 119,366 389,587 389,889 6.2 0.4 TA 11.8 390,133 390,314 390,495 390,618 390,67 9 390,741 390,808 6.2 0.5 15 18.2 23 25.5 24 78-a Run Date: 09-Mar-90 Run Times = 11:08 AN sggggaggggcgagececessgssagsessesesss $ POWRPLAN (c) 1990 by CH2M HILL $ Sueegeagsgaesegcgsesassesessetaasss Winter (October - April} Energy Requirenents (MWh) Energy Dispatch (MWh) Ww AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishae/Crater Lake (3) Dorothy/Long Lake Tunnel (4) Crater Lake Elev. 1034 {5) Long Lake Elev. 845 (6) Caterpillar 3612 diesel (7) 6M EMD diesel {8) Existing Diesel: fas Turbines Leaon Creek fuke Bay Gold Creek TOTAL Cost Millions) Capital Fixed Variable Fuel TOTAL JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev, 845 Forecast: Multi-Mine 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 390,633 370,562 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 390,371 7,983 7,943 7,943) 7,943 7,943 7,943 7,943 7,943 7,943 7,983 7,943 7,94E— 74S 7,943 7,437,943 7HHS 7,943 41,786 11,786 11,786 11,786 11,786 11,786 11,786 11,786 «11,786 11,786 . 11,785 11,786 11,786 11,786 11,786 11,786 11,786 11,786 1,912 1,912 0,912 1,912,912 FN2 1,912 1,912 2,912 2,912 PLZ 1,912 1,912,912 1,912 1,912 2,912 1,912 242,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 212,727 242,727 212,727 212,727 27,033 27,033 27,033 27,033 27,033 27,033 27,033 27,033 «27,033 = 27,033 27,033 27,033 += 27,033 27,033 27,033 27,033 27,033 27,033 1,831 1,831 1,831 1,831 1,831 2,832 1,831 1,831 2,831 1,831 1,832 1,831 1,311,831 1,832 1,831 2,831, 831 8,209 8,209 8,209 8,209 8,209 8,207 8,207 8,209 8,209 8,209» B,209 = 8,209 8,207 = B, 207 = B20? 8,209 = 8,209 8, 209 0 0 9 0 0 0 0 0 9 0 0 9 0 0 9 0 0 9 119,313 119,318 189,201 119,201 219,201 119,201 189,202 119,201 189,202 119,201 119,201 119,201 119,201 119,201 119,202 119,201 119,202 119,201 ecco ecooeo eooo ecco cocoo coco ooceo coco coco coco ecooo oocoo ecooe eooceo ecco coco ecoo ecco 390,755 390,760 390,643 390,683 390,443 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 390,643 6.2 6.2 6.2 6.2 6.2 3A ‘i a1 3A 3 31 3 3a 31 31 A 9.0 0.6 0.6 0.6 0.6 9.7 0.7 0.7 0.8 0.8 0.8 09 0.9 0.9 1.0 A Ll 1.2 7.6 76 7.7 7.8 7.8 Ww 8.0 81 at 8.2 8.3 8.4 8.5 8.7 8.9 9.0 a1 1 20.1 21.0 22.0 22.9 24.0 25.4 26.2 74 28.6 29.9 31.2 32.6 35.6 37.2 38.9 40.7 33.5 345 35.5 36.6 v7 35.6 36.8 3. 39.4 40.7 424 43.8 45.2 46.8, 48.5 50.2 52.1 51.0 €8-d 09-Mar-90 41:08 AN Run Date: Run Tiee: SOCRosnsececeecececsetoesasesess test # POWRPLAN (c) 1990 by CH2H HILL & Aeeregngeeenececeaseecconsnsesessese Suaeer (Nay - Septeaber) Energy Requirements (HWh) Energy Dispatch (MWh) (1) AELP Hydro: Annex Creek Salaon Creek Gold Creek (2) Snettishaa/Crater Lake (3) Dorothy/Long Lake Tunnel (4) Crater Lake Elev. 1034 (5) Long Lake Elev. 845 (8) Caterpillar 3612 diesel {7) GM EMD diesel (8) Existing Diesel: Gas Turbines Leeon Creek fuke Bay Gold Creek TOTAL Cost ($ Millions) Capital Fixed Variable Fuel TOTAL 1990 1991 1992 1993 97,781 103,009 108,272 231,726 13,577 15,577 15,577 15,577 23,254 3,488 56,571 eooco 2ooo 23,254 3,488 81,777 0 econo coco 104,09 23,254 23,254 3,498 3,488 67,018 118,108 0 0 0 1,017 0 4,557 0 0 0 66,697 0 0 0 0 0 0 0 0 109,336 232,697 1998 236,275 15,577 23,254 3,408 118, 108 0 1,017 8,557 0 71,188 2ooo 237,188 1995 JUNEAU 20-YEAR POWER SUPPLY PLAN Cases Forecast: “1996 Lake Dorothy/Long Lake Tunnel with Crater Lake Elev Multi-Mine 1997 1998 1999 2000 2001 2002 240,749 241,257 241,689 242,123 282,519 242,916 243,274 243,595 15,577 23,254 3,498 15,577 23,254 3,488 15,577 23,254 3,488 118,108 118,108 118,108 15,009 1,017 4,557 0 60,593 ecoo 241,602 15,009 1,017 4,557 0 61,026 ecooo 242,036 15,009 1,017 4,557 0 61,383 ecco 242,392 15,577 15,577 23,254 23,254 3,488 3,488 118,108 118,108 15,009 15,009 1,017 1,017 4,557 4,557 0 0 61,743 62,064 0 0 0 0 0 0 0 0 242,752 243,074 15,577 15,577 15,577 23,254 23,254 23,254 3,408 3,4B8 3,488 118,108 118,108 118, 108 15,009 15,007 15,009 1,017 1,017 1,017 4,557 4,557 4,557 0 0 0 62,386 62,689 62,915 0 0 0 0 0 0 0 0 0 0 0 0 243,396 243,679 243,924 450045 OAS 03 03 © 03 RY 690074 + 1034 and Long Lake Elev. 845 2003 2004 2005 2006 2007 283,915 244,199 248,445 248,690 244,939 15,577 15,577 15,577 15,577 15,577 23,254 23,258 23,258 23,254 23,258 3,488 3,488 3,488 3,4BB 3,408 118,108 118,108 118,108 118,108 118,108 15,009 £5,009 $5,009 15,009 15,009 1,017 1,017 1,017 1,017 1,017 4,557 4,557 4,557 4,557 4,557 0 0 0 0 0 83,160 63,368 63,539 63,707 63,883 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 244,169 244,378 244,549 244,718 244,892 4500 SOS SS 0.3.03 -03 08 04 4000 0 OA ny BS v8-d Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Times = 11:08 AM : Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 645 Forecast: Multi-Mine senenesnnceaneesseencessseccsseessy # POWRPLAN (c) 1990 by CHZM HILL 8 2008 ©2009-2010 = 2011. «20122013204 = 20152018 = 2017-2018)» 2019 2020 «202k ~=«2022 «202820282008 anngeanecnscsncagnnesnaseseassegess = Suaner (May - Septeaber) Energy Requireaents (MWh) 2N5,111 245,323 245,455 245,455 245,453 245,455 245,455 245,455 245,455 245,455 245,455 245,455 245,455 245,455 285,455 245,455 245,455 205,455 Energy Dispatch (MWh) W) AELP Hydro: Annex Creek 45,577) 45,577 15,577, 15,577, 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,577 15,877 15,577 Salaon Creek 23,254 «23,254 = 23,254 = 23,254 = 23,254 = 23,254 23,254 23,258 923,254 923,254 9 23,254 23,254 23,254 23,254 «23,258 23,254 23,254 23,254 Gold Creek 3,488 «= «3,488 «= 3,488 «= 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 = 3,488 939 3,488 = 3,888 )=— 3,488 = 3,488 |= 3,488 = 3,488 = 3,488 = 3,488 (2) Snettishaa/Crater Lake 116,108 118,102 118,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 128,108 118,108 118,108 118,108 118,108 118,108 118,108 118,108 (3) Dorothy/Long Lake Tunnel 15,007 15,0097 15,009 15,007 15,009 15,007 15,009 15,009 15,009 15,009 15,007 15,009 15,007 15,007 15,009 15,009 15,009 15,009 (4) Crater Lake Elev. 1034 1,017 1,017 1,017, 1,017) 1,017 1,017 1,087 1,017 1,017 1,017 1,087 1,017 1,017 1,087 1,017,017 1,017 1, 017 (3) Long Lake Elev. 845 4,557 4,557 4,557 4,557 4,557) 4,557) 4,557) 8,557) 8,557 4,557 4,557 4,557 4,557 4,557 4,557) 4,557) 4,557 4,557 (4) Caterpillar 3612 diesel 0 0 0 0 6 0 0 0 0 0 0 0 0 9 0 0 0 0 (7) 6N EMD diesel 63,980 68,116 64,178 64,174 4,178 4,174 6M,174 68,174 64,274 64,274 68,174 64,174 68,178 68,178 64,178 64,178 64,1748 64,174 {B) Existing Diesel: Sas Turbines 0 0 0 0 0 0 0 0 0 0 0 0 9 9 0 0 6 0 Leson Creek 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 fuke Bay 0 0 0 0 0 0 0 0 0 0 0 9 0 9 0 0 0 0 Gold Creek 0 0. 0 0 0 0 0 0 0 0 9 0 0 0 9 9 0 0 TOTAL 244,989 245,125 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 245,183 Cost ($ Millions} Capital Fixed Variable Fuel TOTAL 19.7 20.3 21.0 21.5 22.2 20.6 21.2 29 22.7 23.4 24.2 25.1 26.0 26.9 27.8 28.8 29.9 28.8 Run Date: 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Ties = 11:08 AN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine HORENgeeegageeeegseaggsecagsegeseees $ POWRPLAN (c) 1990 by CH2M HILL & 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Sggsegeeeegearegassssseegecegesess Seaseees seeesese exessess essesss= sz: . BUS BAR COST SECTION: Average Costs (Saillions): Fuel Costs 0.0 0.0 0.0 13.6 15.3 13.8 14.6 15.5 16.4 17.2 18.1 19.6 21.0 22.4 23.9 25.3 26.8 28,3 Variable O&M 6.2 4.7 7.0 10.6 10.7 10.7 10.8 10.8 10.9 11.0 11.0 A 11.2 11,3 11.3 4 1.50 16 Fixed O&M 0.4 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 Capital Costs (existing systea) 2.6 2.6 2.6 2.6 2.6 2.2 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 Depreciation Expense (new units) 0.0 0.0 0.0 27 27 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Property Taxes (new units) 0.0 0.0 0.0 0.9 0.9 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Interest Expense (new units) 0.0 0.0 0.0 4.2 4.2 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 Total 9.3 9.7 10.0 35.1 37.0 42.9 44.2 45.1 46.1 a7 48.1 49.6 Sit 52.7 54.2 55.8 57.8 59.0 Energy Requiresents (wh) 277,000 291,464 306,028 606,885 618,381 629,674 630,591 631,306 632,033 632,661 633,285 633,812 634,238 634,664 634,996 635,228 635,460 635,700 Average Bus Bar Cost wo -- Nominal (cents/kWh) 34 3.3 33 5.8 6.0 6.8 7.0 Ma 1.3 74 7.6 7.8 8.1 8.3 8.5 8.8 9.0 9.3 v ~~ Real (cents/kWh) 3.4 3.2 3.0 Sl 5.0 3.5 5.4 3.3 3a 5.0 49 4.8 4.8 4.7 4.6 4.5 45 4 uw Non-Mining Loads ($aillions): Fuel Costs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Variable O&M 6.2 6.7 7.0 6.9 7.2 1.5 7.6 7.6 7.6 7.6 7.6 7 17 7.7 17 wT 17 17 Fixed O&M 0.4 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 Capital Costs (existing systea) 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 Depreciation Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Property Taxes (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Interest Expense (new units) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total 9.3 9.7 10.0 10.0 10.3 10.7 10.7 10.8 10.8 10.9 10.9 11.0 11.0 11.0 Ml Wt 11.2 11.2 Energy Requiresents (MWh) 277,000 291,464 306,028 302,885 314,381 325,674 326,591 327,306 328,033 328,661 329,285 329,812 330,238 330,664 330,996 331,228 331,460 331,700 Average Bus Bar Cost -- Nominal (cents/kWh) 34 3.3 33 3.3 3.3 3.3 33 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 34 34 34 > Real (cents/kWh) 3.4 3.2 3.0 29 2.8 2.6 2.5 24 2.3 2.2 21 2.0 2.0 1.9 1.8 17 1.7 1.6 98-8 Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tise: = 11:08 AK Cases Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Hine Onenggeasesscsseagsesageesessegsesee # POWRPLAN (c) 1990 by CH2M HILL ¢ 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 20048 2005 2006 2007 SOREgecgeagecgeeesassaacsseest sees = Hining Loads (Saillions): Fuel Costs 0.0 0.0 0.0 13.8 14.6 13.5 16.4 17,2 18.1 19.6 21.0 22.4 23.9 25.3 26.8 28.3 Variable O&M 0.0 0.0 0.0 3.2 3.2 33 33 33 34 35 35 3.6 37 37 3.8 3g Fixed 08H 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Capital Costs (existing system) 0.0 0.0 0.0 (0.4) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Depreciation Expense (new units) 0.0 0.0 0.0 4.8 4.8 4.8 4.8 4.8 4.8 48 48 48 4.8 48 48 4.8 Property Taxes (new units) 0.0 0.0 0.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Interest Expense (new units) 0.0 0.0 0.0 8.9 8.9 8.9 Bo 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 Total 0.0 0.0 0.0 25.1 26.6 32.2 3.5 a4 35.3 36.2 3.2 38.6 40.1 41.6 3.1 44,7 46.2 47.8 Energy Requiresents (MWh) ‘ 0 0 © 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 Average Bus Bar Cost ~~ Nominal (cents/kWh) WA WA WA 8.3 8.8 10.6 11.0 1 7.2 -~ Real (cents/kWh) NA WA NA . 7.3 8.5 8.5 11.6 M9 12.2 12.7 13.2 13.7 14.2 14.7 15.2 15.7 8.2 8.0 ww 7.8 7.8 17 17 1.6 15 nA ot ee L8-4 Run Date: 09-Mar-90 Run Tiee: = 11:08 AM Oaggageagsegscaseagegsaessseceseeges $ POWRPLAN (c) 1990 by CH2M HILL Ongaggegegscssesasascssesessssscees BUS BAR COST SECTION: Average Costs (Seillions): Fuel Costs Variable O&M Fixed O&M Capital Costs (existing systea) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost ~~ Nominal (cents/kWh) ~~ Real (cents/kWh) Won-Mining Loads (Seillions): Fuel Costs Variable O&n Fixed O&M Capital Costs (existing systes) Depreciation Expense (new units) Property Taxes (new units) Interest Expense (new units) Total Energy Requireaents (MWh) Average Bus Bar Cost ~~ Nominal (cents/kWh) -~ Real (cents/kWh) JUNEAU 20-YEAR POWER SUPPLY PLAN Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev. 1034 and Long Lake Elev. 845 Forecast: Multi-Mine 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 suzzeass seeeeezs ezezztez sseezesz eeesesze eeessszz sszseeee setstess 22 SEEEze azessss= see: SEESE Szasszs= exsssez= ezeesese es: 29.8 u.3 32.9 M3 35.9 3.5 39.2 1.0 42.8 4.7 46.7 51.0 53.3 55.7 58.2 60.9 = 63.6 11.7 11.8 ng 12.0 12.1 12.2 12.4 12.5 12.6 12.8 12.9 13.2 13.4 13.5 13.7 13.9 M41 1.0 1.0 1.0 Ll 11 1.2 1.2 1.3 14 14 1.5 1.6 17 1.8 1.8 1g 2.0 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 4.8 4.8 4.8 4.8 4.8 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 0.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 8.9 8.9 8.9 8.9 8.9 7 47 47 47 4.7 47 4.7 4.7 4.7 47 47 635,744 635,885 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 635,827 1 10.3 10.6 9.8 10.1 10.4 10.7 11.0 11.4 11.8 12.1 12.5 13.0 13.4 13.8 13.3 02 41 4.0 3.6 3.5 35 34 34 3.3 3.3 3.2 3.2 3.2 31 3a 2.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 77 1.7 1.7 17 77 7.7 1.7 1.7 1.7 17 17 7.7 1.7 77 1.7 1.7 17 17 1.0 1.0 1.0 1 Lal 1.2 1.2 1.3 1.4 14 1.5 1.6 1.6 17 1.8 1.8 1.9 2.0 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 331,744 331,885 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 331,827 mw Re 3.6 1.0 0.9 0.9 0.9 0.8 0.8 88-a Run Dates 09-Mar-90 JUNEAU 20-YEAR POWER SUPPLY PLAN Run Tiger = 11:08 AK : Case: Lake Dorothy/Long Lake Tunnel with Crater Lake Elev, 1034 and Long Lake Elev. 845 Forecast: fMulti-Nine MM t POWRPLAN (c} 1990 by CH2K HILL # 2008 2009 -=«-2010=«2011.«=«2012=« 201320182015 2018S 2017-2018 aang sunencennesnganesnngcencecanecsesses = 2020202022 02820242025 Mining Loads ($millions): Fuel Costs 29.8 U3 32.9 M43 35.9 v5 39.2 LO 42.8 46.7 48.8 53.3 35.7 58.2 63.6 Variable O&M 4.0 al 42 4.3 44 $5 4.6 4.8 ay 5.2 5.3 5.7 5.8 6.0 iv Fixed O&f 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Capital Costs (existing systes) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Depreciation Expense (new units) 4.8 4.8 48 4.8 48 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 20 0.0 Property Taxes (new units) 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 20 Interest Expense (new units) 8.9 8.9 89 89 8.9 AT 47 47 4.7 47 47 4.7 4,7 47 0.0 Total 494 31.0 52.7 34.3 55.9 50.7 52.5 54.4 36.4 38.5 60.6 42.9 45.2 67.7 70.3 Ts. — In Energy Requireaents (MWh) 304,000 304,000 308,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 304,000 Average Bus Bar Cost ~~ Nominal (cents/kWh) - 16.3 16.8 17.3 17.8 18.4 16.7 17,3 17.9 18.6 19.2 19.9 20.7 21.5 22.3 23.1 24.0 24,9 2.7 ~- Real (cents/tWh) 1.4 7.3 1.2 TL 7.0 61 6.0 6.0 5.9” 5.9 5.8 5.8 5.7 5.7 5.7 5.6 5.6 3a es APPENDIX C APA LETTER ON RATES Department Of Energy Alaska Power Administration P.O. Box 020050 Juneau, Alaska 99802-0050 April 24, 1990 Robert K. Schneider CH2M Hill P.O. Box 91500 Bellevue, WA 98009-2050 Dear Mr. Schneider: The following is a restatement of a letter sent to Mr. Bill Corbus of Alaska Electric Light & Power dated January 26, 1990. You asked for a current appraisal of future wholesale rates for the Snettisham Project. We are happy to respond, recognizing that there are important uncertainties in any such appraisal. Short-Term Outlook APA's most recent rate filing is for a two-year extension of the 2.88 cents per kwh rate through September 30, 1991. The rate is in effect on an interim basis pending FERC's review and approval. This rate filing was premised on cost and revenue experience through September 30, 1988. Subsequent results have been about as expected, except for the increase in the Corps' estimated costs for completing Crater Lake and delays in commercial service date for that unit. These changes do not appear sufficient to require a change in rates before September 30, 1991. Marketing Objectives Snettisham revenues for FY 1989 were slightly over $6 million dollars. We are estimating modest increases to $6.3 million by 1991 because of increased demands. To meet our repayment requirements, we will need to increase revenues to approximately $8 to $8.5 million per year relatively soon (say 3 to 5 years) after the FY 1991 start of Crater Lake repayment period. We would propose increases if necessary to meet that revenue objective. Within the revenue objectives, we are willing to consider just about any marketing approach that will enhance project benefits to the consumers. Case 1--Development of A.J. Mine Our studies indicate that, if the A.J. Mine proceeds as planned, without major delay, we may not need to change the 2.88 cent rate for the next several years. Under such a scenario, we would have revenue adequate to cover annual O&M expenses and interest expenses for FY 1991 and 1992, with minimal principal payments in those years. We estimate that our full revenue objective would be reached by 1994. Minor adjustments, up or down, could occur thereafter depending on O&M costs, the final investment cost for Crater Lake, and actual energy capability of the project including the new Crater Lake Unit.4 Case 2--No mine or significant delay in A.J. Mine Here we would need to consider a rate increase in 1992. The actual amount would depend upon the market outlook of the first half of 1991 when the rate proposal is prepared. Our present best estimate is that Snettisham rates on the order of 3.4 to 3.6 cents per kwh would be needed for the 1992-1995 period under the no-mine scenario. That would be trimmed if growth is stronger than assumed for our studies or if the sample markets develop significantly. Over the longer term, we would expect somewhat lower rates as the area approached full utilization of the project energy capability. The Caveats The above numbers assume continuation of present Federal repayment policies and reflect latest Crater Lake cost information from the Corps. Actual Crater investment cost won't be known until construction is completed and claims are settled. The numbers don't have an allowance for long-range inflation in O&M costs. The kinds of things that could drive rates higher than the iabove estimates include major damage to the transmission lines, major equipment failure, or change in Federal policies. \e We'd be happy to discuss this further. Ki Cnee Robert J. Cross Administrator YwWe're basing our estimates on annual sales of 298 million kwh. The studies indicate more is available in 8 out of 10 years, so actual sales could be more than we now assume. ee ee ee © APPENDIX D ECONOMIC CONCEPTS L_. 7 Appendix D ECONOMIC CONCEPTS Average cost pricing or allocation This is a method of taking all costs in a category during a period, dividing by the total units produced during that period, and then assigning the costs at this average rate to all customers. In this Power Supply Plan, when average cost allocations are discussed, the total production costs of old and new resources were combined and divided by the total annual energy production. Life-cycle levelized cost This is an economic index for comparing different types of resources on an equivalent basis. The index is calculated by determining the present value of a resource’s cost over its useful economic life (life cycle), converting that present value into an equal stream of annual payments, and then dividing each annual payment by the average amount of energy produced each year. Marginal cost allocation This is a method by which costs are allocated or assigned on the basis of the most re- cently produced unit of energy. In this Power Supply Plan, the historical AELP and APA hydro resources are of a relatively low cost in terms of cents/Kwh, while new diesel or hydro generation is more expensive. In this situation, a customer class that has generation costs assigned using a marginal cost allocation will experience higher rates than one using an average embedded cost allocation. Present value Present value is the worth of future costs or revenues at their current value. To calcu- late a present value, future nominal values must be reduced by an interest or discount rate. The net present value of a package of resources is the present value of the re- sources less the initial cost of the resources. Real and nominal values Real values, or real dollars, do not include the effects of inflation. They represent constant purchasing power. A real dollar has the same value in 1990 as it does in 2000. Real dollars are always expressed in relation to a base year, such as 1990. In this re- port, real dollars are generally in 1990 dollars unless noted otherwise. Nominal values, or nominal dollars, include the effects of inflation. For example, if a person purchases a bag of groceries, the amount on the check is the nominal amount. The real value is the nominal amount discounted back to a reference year by the infla- tion from the purchase year. Therefore, a $100 bag of groceries in 1990 might have a 1967 real value of $28.54. This means that if $28.54 had been invested in 1967 at an interest rate equal to the inflation rate, there would have been just enough in the bank for a bag of groceries at any given time. In this example, nominal values range from $28.54 in 1967 to $100.00 in 1990, but real value is the same for any single point in time. sea7310/006.51