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HomeMy WebLinkAboutJuneau 20 Year Power Supply Plan Vol 1, December 1984Alaska Energy Authority LIBRARY COPY 1040C JUNEAU 20-YEAR POWER SUPPLY PLAN VOLUME 1 SUBMITTED TO: ALASKA ELECTRIC |.1GHT AND POWER COMPANY GLACIER HIGHWAY ELECTRIC ASSOCIATION ALASKA POWER ADMINISTRATLON ALASKA POWER AUTHORITY NOVEMBER, 1984 EBASCO SERVICES INCORPORATED JUNEAU 20-YEAR POWER SUPPLY PLAN TABLE OF CONTENTS VOLUME _1 1.0 INTRODUCTON . 2. 2... 22. 22 ee eee ee ee ee eens 2:0: UGAD FORECASTS =... =. 5 0 sw ww wt ww ww we .1 Assumptions Underlying Load Forecasts ......... -2 Sensitivity of the Forecasts ........4-4-+-2+.2. mr 3.0 POWER SUPPLY ALTERNATIVES . . 2... 2 2 ee eee ee eee 3.1 Interconnection with Existing Hydroelectric-Based SR = —— =o a ae mC Cae aa aaa Undeveloped Hydroelectric Projects .......... Upgrading Existing Hydroelectric Projects ....... Fossil-Fuel Thermal Plants ..........2-2486- Other Energy Sources. - . ws 2 3 ew ww wWwww OPwnr 4.0 TRANSMISSION SYSTEM DEVELOPMENT . ~~... 2. eee ee ee ‘1 itr... ee 4.2 The 69 kV Transmission System. .........2.446-. 4.3 Distribution/Feeder Losses ...... 2. ee ee eee 4.4 Project-Specific Transmission Lines... ....... 5.0 PLAN FORMULATION AND EVALUATION .. ~~... 2. ee ee eee -) Planning Approach... ....-.-2-e+2eecreercece 52 EXA SEUNG SVSUGIR cms 0 oo in oe ew = 0s -3 Base Case Thermal Plan ...... 2 6 ee eee eee 25 _NydToe lectern GaP AMS acento tee ote ola tes -6 Interconnection Plans... ... 2. 6 ee ee ee eee .1 Cost of Power Forecast ... 1... ee eee ee eee 5 5 5 5.4 Alternative Thermal Plans... .... 2 ee ee eee : 5 5 5 6.0 FINDINGS AND RECOMMENDATIONS... 2... 2. ee ee ee eee oe SEU Y Fi OGG Sor woe rots ote meter 6.2 Recommended Plan of Action ........+4-++++464-8 1040C TABLE OF CONTENTS (Continued) VOLUME_1 (Continued) 7.0 APPENDICES Tables of Significant Data ..... 7.1 7.2 T. E. Neubauer and Associates Report Voc References ........66+62+ ees VOLUME 2 7.0 APPENDICES (Continued) 7.4 Project Financing and System Cost of Power ..... 7.5 Planning Model. .........24.-. 7.6 Planning Model Results ....... 1040C ii ~s~s~S won— asNS ant ed ened ed ed eed oo) Table =| 2-2 3-1 ane 3-3 3-4 3-5 3-6 3-7 3-8 3-9 3-10 3-11 3-12 3-13 1040C TABLE OF CONTENTS (Continued) LIST OF TABLES Energy Sales by Load Forecast Peak Demand by Load Forecast Economic Parameters Summary for the Transmission Interconnection Alternatives Construction Cost Estimate - Reconnaissance Level Whitehorse to Juneau Transmission Interconnection Construction Cost Estimate - Reconnaissance Level Tyee to Snettisham Transmission Interconnection Construction Cost Estimate - Reconnaissance Level Snettisham to Juneau Submarine Cable Transmission Interconnection Economic Parameters Summary of Undeveloped Hydroelectric Projects Construction Cost Estimate - Reconnaissance Level Crater Lake Hydro Project (27 MW) Construction Cost Estimate - Reconnaissance Level Lake Dorothy Hydro Project (26 MW) Construction Cost Estimate - Reconnaissance Level Sweetheart Lake Hydro Project (26 MW) Construction Cost Estimate - Reconnaissance Level Thomas Bay Hydro Project (44 MW) Construction Cost Estimate - Reconnaissance Level Speel River Hydro Project (57.1 MW) Construction Cost Estimate - Reconnaissance Level Nugget Creek Hydro Project (10.8 MW) Economic Parameters Summary for Upgrading Existing Hydroelectric Projects Construction Cost Estimate - Reconnaissance Level Annex Creek Hydro Project (2.9 MW) Pelton Addition iii 3-5 3-6 3-11 3-13 3-21 3-22 3-25" 3-31 3-36 3-40 3-45 3-47 3-51 Table 3-14 3-15 3-16 3-17 3-18 3-19 3-20 3-21 4-1 4-2 4-4 4-5 4-6 4-10 1040C _ TABLE OF CONTENTS (Continued) LIST OF TABLES (Continued) Construction Cost Estimate - Reconnaissance Level Salmon Creek Hydro Project (6.7 MW) Economic Parameters for Thermal Generation Alternatives Construction Cost Estimate - Reconnaissance Level Prime Power Diesel, 20 MW (4-5 MW Units) Construction Cost Estimate - Reconnaissance Level Prime Power Diesel, 20 MW (2-10 MW Units) Construction Cost Estimate - Reconnaissance Level Diesel Standby, 20 MW (8-2.5 MW) Construction Cost Estimate - Reconnaissance Level Combustion Turbine, 20 MW Construction Cost Estimate - Reconnaissance Level 30 MW Coal Fired Steam Plant Construction Cost Estimate - Reconnaissance Level MSW Electric Plant (80 Ton/Day, 1 MW) Transmission Line 1 - Conductor Sizes and Structures Transmission Line 2 - Conductor Sizes and Structures Transmission Line 1 - Positive Sequence Impedances Transmission Line 2 - Positive Sequence Inpedances Per unit Impedances on 100 MVA Base and Line Chargings used in Load Flow Studies Percent Substation Loads Used in the Load Flow Studies Snettisham-Juneau 138 kV Line Data Parameters Used for Project-Specific Transmission Lines AC Transmission Losses Between Projects and the Juneau 69 kV System at Full Utilization HVDC Transmission Losses of Projects at Full Utilization iv 3-57 3-61 3-62 3-63 3-64 3-66 3-68 3-71 4-5 4-6 4-9 4-11 4-14 4-17 4-18 4-20 4-21 TABLE OF CONTENTS (Continued) LIST OF TABLES (Continued) Table No. 5-1 Summary of Results, Base Case Thermal 5-2 Summary of Results, Low Forecast, Thermal 5-3 Summary of Results, High Forecast, Thermal 5-4 Summary of Results, Mining Forecast, Thermal 5-5 Summary of Results, No Fuel Escalation, Thermal 5-6 Summary of Results, Dorothy 1996 (with Snettisham Transmission Line) 5-7 Summary of Results, Dorothy 1996 (With Separate Transmission Line) 5-8 Summary of Results, Low Forecast, Dorothy 1999 5-9 Summary of Results, High Forecast, Dorothy 1993 5-10 Summary of Results, Dorothy 1993 5-11 Summary of Results, Dorothy 1999 5-12 Summary of Results, Zero Fuel Escalation, Dorothy 1996 5-13 Summary of Results, Whitehorse Intertie 1996 5-14 Summary of Results, Tyee Intertie 1996 5-15 Summary of Results, Tyee Intertie 1996 (Low Tyee Power Cost) 6-1 Summary of Plan Costs 6-2 Sensitivity Test Results 1040C 5-11 S-2 5-14 5-16 St 5-18 5-20 5-21 Sa22 5-24 $=25 5-26 6-4 6-5 Figure 3-5 3-6 3-7 3-8 3-9 3-10 3-11 3-12 3-13 3-14 4-2 4-3 4-4 4-5 4-6 5-1 6-1 1040C TABLE OF CONTENTS (Continued) LIST OF FIGURES Transmission Interconnection Alternatives Juneau Area Hydro Sites Juneau Area Hydro Facilities Snettisham and Crater Lake Plans Lake Dorothy Plan Sweetheart Lake Plan Lake Dorothy and Sweetheart Lake Project Profiles Thomas Bay Plan Thomas Bay Project Profile Speel River Plan Nugget Creek Plan Salmon Creek General Map Lower Salmon Creek, Powerhouse Plan and Sections Lower Salmon Creek Site Plan and Penstock Modifications Existing 69 kV Transmission Existing 69 kV Transmission Existing 69 kV Transmission Transmission Pole Structure Types 69 kVC System One Line Diagram Used in Load Flow Studies 69 kV System Load Flow in 2003 Forecast Year Planning Model Lake Dorothy Preliminary Project Schedule vi 3-24 3-28 3-29 3-33 3-34 3-39 3-43 3-54 3-55 3-56 4-3 4-4 4-1 4-10 4-15 6-7 _1.0 INTRODUCTION The Juneau area has grown rapidly in recent years and will continue to grow. Such growth in population and economic activity is reflected in the area's power requirements, both historical and projected. Issues facing Juneau's electric utilities include capacity sufficiency for reliably meeting peak demand, optimum mix of generating resources to minimize costs of generation, and transmission facility planning to assure efficient system operation. This study was commissioned under the joint sponsorship of Alaska Electric Light and Power Company, Glacier Highway Electric Association, Alaska Power Administration, and Alaska Power Authority. It is based on load growth forecasts developed for the Juneau area by the Alaska Power Administration in cooperation with Alaska Electric Light and Power (AEL&P) and Glacier Highway Electric Association (GHEA). Those forecasts clearly indicate the need to begin planning for the future addition of new generation and transmission facilities. Fortunately, Juneau benefits from an extensive collection of previous studies addressing particular power supply options. Given this base of existing information, the objectives of the Juneau 20-Year Power Supply Plan are several: ° Review and update information on potential power supply options to enable comparative evaluation. ° Develop a long-term power planning model for the Juneau area using analytical tools easily transferable to the Juneau utilities and to federal and state energy agencies. ° Formulate and evaluate alternative long-term power supply plans that are representative of the options available to Juneau. ° Recommend a plan of action. —— Load forecasts are discussed in Section 2.0. The next section provides the results of the work undertaken to review and update the information on the full range of power supply options available to the Juneau area. Evaluation of the individual options is also included. Section 4.0 is a discussion of Juneau's transmission system and presents estimates of both local system and project-specific transmission losses. Section 5.0 presents the planning approach and discusses alternative long-term power supply plans formulated to satisfy the various load growth forecasts. The section concludes with a cost of power forecast for the preferred alternative. Study findings and a recommended plan of action appear in Section 6.0. Section 7.0 contains 0544C Ua three appendices: tables of significant data for hydroelectric projects, a report by 1.£. Neubauer and Associates addressing diesel and combustion turbine options, and a list of references. Three additional appendices of limited interest to general readers are contained in a separate Volume 2 of the report. These appendices deal with a discussion of financing considerations, a detailed description of the planning model, and planning model output sheets. 0544C 2 2.0 LOAD FORECASTS A series of four load forecasts were considered in the analysis of Juneau's 20 year power needs. These include high, mid-range, and low forecasts, plus an additional high growth forecast based on the introduction of a large mining load in the Juneau area. The high, mid-range, and low forecasts represent the range of demands which might be placed on the GHEA and AEL&P systems as Juneau area demand grows over the next 20 years. The differences between the three forecasts are a function of the rate at which that growth occurs. The fourth forecast considers the addition of a major new load; a load which is large enough in itself to produce a major shift in the underlying forecast. A new mining operation was chosen for the fourth forecast because mining appears to be the most likely major load that could be added to the system. The high growth mining forecast, however, represents the system effect of adding any comparable major load. The use of different forecasts in the analysis provides an allowance for the uncertainty of forecasting future demand. In general, conservative utility planning suggests that preparations should be made for accommodating the higher forecast range. With preconstruction phases of project development completed, commitments to actual construction can be postponed until the need actually materializes. Section 2.1 below presents the assumptions underlying each of the load forecasts considered in this analysis. Following that overview, Section 2.2 presents a brief discussion of several factors such as conservation which could influence load growth trends. 2.1 ASSUMPTLONS UNDERLYING LOAD FORECASTS The four forecasts of energy sales and peak demand are shown in Tables 2-1 and 2-2, respectively. The high, mid-range, and low load forecasts are all taken from the Alaska Power Administration's May 1984 update of the Juneau area power market analysis (APA 1984). All three forecasts assume the following: 1) Population growth 1983-1990 3% per year 1990 -2000 2% per year 2) Population per residential customer 2.6 0585C 2 TABLE 2-1 JUNEAU 20-YEAR POWER PLAN ENERGY SALES BY LOAD FORECAS1 Low Mid-Range High Mining Year (GWh) (GWh) (GWh) (GWh) 1970 (actual) 57.0 57.0 57.0 57.0 1980 (actual) 1295 129.5 129.5 129.5 1983 (actual) 198.0 198.0 198.0 198.0 1984 215m ZlSel CARES 215.1 1985 226.0 230.6 2395 230.6 1986 235.0 242.4 248.2 242.4 1987 242.9 252.6 261.6 252.6 1988 250.1 262.4 (a heyats 262.4 1989 256.7 TO 288.5 271.5 1990 261.4 279.0 300.1 410.4 1991 266.4 286.9 312.2 418.3 1992 271.5 295.0 324.7 426.4 1993 2716.8 303.3 Sat 434.7 1994 282.1 311.8 351.3 443.2 1995 287.5 320.6 365.4 452.0 1996 293.2 329.3 379.4 460.7 1997 298.9 338.2 394.0 469.6 1998 304.8 347.4 409.2 478.4 1999 310.8 356.8 424.9 488.2 2000 317.0 366.4 441.2 497.8 2001 323.2 376.3 458.2 507.7 2002 329.6 386.5 4715.8 Ste9) 2003 336.1 397.0 494.0 528.4 0585C TABLE 2-2 JUNEAU 20-YEAR POWER PLAN PEAK DEMAND BY LOAD FORECAST* Low Mid-Range High Mining Year (MW) (MW) (MW) (MW) 1970 (actual) 12.4 12.4 12.4 12.4 1980 (actual) 26.2 26.2 26.2 26.2 1983 (actual) 40.1 40.1 40.1 40.1 1984 41.3 41.3 41.3 41.3 1985 54.0 55 a1 SSL S55 al 1986 56.1 57.9 59.2 57.9 1987 58.0 60.3 62.5 60.3 1988 59.7 62.6 65.7 62.6 1989 61.3 64.8 68.9 64.8 1990 62.4 66.6 71.6 81.6 199] 63.6 68.5 14.5 83755 1992 64.8 10.4 le 85.4 1993 66.0 712.4 80.6 87.4 1994 67.3 714.4 83.9 89.4 1995 68.6 TGR 87.2 9005 1996 10.0 18.6 90.6 93.6 1997 71.4 80.7 94.0 95 aT 1998 12.8 82.9 Sint 97.9 1999 Wee 85.2 101.4 100.2 2000 TST 87.5 105.3 102.5 2001 Thee 89.9 109.4 104.9 2002 18.8 92.3 113.6 107.3 2003 80.3 94.8 117.9 109.8 * Alaska Power Administration peak demand forecast is based on applica- tion of historical system capacity factor (55 percent) to forecasted net generation requirements. Net generation assumed to be 115 per- cent of sales. 0585C 2-3 3) Residential Use per Customer (annual) Single Family General Class 7,500 kWh Hot Water 12,900 kWh All Electric 26,000 kWh Multifamily General Class 6,000 kWh Hot Water 12,900 kWh All Electric 22,000 kWh The three forecasts vary in their assumptions about the rate of load growth in the residential, commercial, and government sectors. Differences in residential sector growth are further related to assumed differences in the growth rates of three residential user classes: the general class, hot water class, and all-electric class. Common to all forecasts, however, is a smaller rate of load growth than the area has experienced in the recent past. The low forecast assumes that by 1990, only 10 percent of new residential customers will enter the all-electric class, while 80 join the general class and 10 percent the hot water class. New multifamily housing construction is assumed to increase compared to single family construction, and use per customer is expected to decline. The commercial sector load growth is assumed to taper off from 12 percent annually in 1984 to 8 percent in 1985 and 4 percent thereafter. Government sector load growth is assumed to decline from 10 percent in 1984 to 6 percent in 1985 and 3 percent annually thereafter. The low forecast results in a 70 percent increase in energy use and a 100% increase in peak demand from 1983 to 2003. Mid-Range Forecast The mid-range forecast assumes that by 1990, 20 percent of new residential customers enter the all-electric class, while 70 percent enter the general class and 10 percent the hot water class. The ratio of multifamily to single family construction remains 75:25, and use per customer decreases only slightly by 2000. Commercial sector load growth is assumed to decline from 12 percent in 1984 to 10 percent in 1985 and 5 percent annually thereafter. Annual government sector growth also declines somewhat, to 8 percent in 1985 and 4 percent in following years. This mid-range forecast produces a 100 percent increase in energy use and a 136 percent change in peak demand by 2003. 0585C 2-4 High Forecast The high forecast assumes further increased growth in the all-electric residential customer class, with 40 percent of new customers entering that class. New hot water customers remain the same at 10 percent, while general customers decline to 50 percent of new households. New single family housing construction increases to 40 percent of the total, while use per customer decreases almost imperceptibly by 2000. Commercial sector growth is assumed to be 12 percent in 1984 and 1985, declining to 6 percent thereafter; government load growth meanwhile would remain at 10 percent in 1984 and 1985, declining to 5 percent in following years. The high forecast results in a 139 percent increase in energy use and a 194 percent increase in peak demand by 2003. High Growth Mining Forecast The high mining forecast uses the mid-range forecast as a base and adds an additional load associated with the proposed AJ and Treadwel] Mines. It has been estimated that the mines would require 1 kw/ton of production. The AJ mine would produce 10,000 to 20,000 tons per day, while the Treadwell could produce 1,000 to 2,500 tons per day. The maximum demand associated with both mines operating at full capacity would be 22.5 MW. The more conservative assumption made for this analysis assumes that only the larger mine would be operating, and at 75 percent of capacity. The associated peak demand would be 15 Mw, while energy requirements would equal 131,400 MWh/year. In the high growth mining forecast, these estimates are added to the mid-range forecast beginning in 1990. Overall growth under this forecast would equal 167 percent of energy use and 174 percent of peak demand by 2003. 2.2 SENSITIVITY OF THE FORECASTS In general, economic theory suggests that the greater the real price of electricity, the lower will be the consumption or quantity demanded of electricity. Besides the price of electricity, the prices of substitute fuels such as oi], gas and coal and complementary goods such as energy using machines influence the demand for electricity. These prices can influence electricity consumption in the short term by changing utilization rates of existing appliances; over time, old and less efficient appliances can be replaced, weatherization measures may be undertaken, and fuel switching may be possible. Because they are brought about by higher relative electricity prices, these conservation Measures are termed “price induced" conservation. Price-induced conservation can have a marked impact on load forecasts which do not take the phenomenon into account. As part of its analysis of Juneau's 20-year power needs, Ebasco considered the question of price-induced conservation and its possible impact on the load forecasts used in the analysis. The GHEA and AEL&P systems were reviewed separately, and the following discussions present the results of that review. 0585C Glacier Highway Electric Association (GHEA) GHEA currently serves about 8 percent of the total Juneau area load. GHEA's customers are primarily residential consumers. In 1983, the number of residential customers was 1,144 with associated sales of 12,316 kWh, representing approximately 91 and 73 percent of the respective system totals. The other customers include commercial, government, and street lighting and they account for the remaining system sales. GHEA has two rate schedules for residential customers, one affecting services in use before June 1, 1983, and one affecting newer service. The newer rate includes a demand charge as well as an energy charge, a price structure which tends to encourage conservation. The electric rates of GHEA are relatively high although GHEA has preference status in obtaining inexpensive wholesale power from federal hydroelectric sources. The Crater Lake phase of the Snettisham project should help to keep GHEA's electric rates down, although increased dependence on diesel generation will tend to increase generation costs and future electric rates. The recent 10 percent rate increase to recover the costs of the Auke Bay diesel generating plant provides a case example. Such noticeable price increases also tend to encourage conservation. It is apparent that GHEA is attempting to curb peak loads on the system through load management rates which include substantial demand charges. The demand charges reflect the anticipated higher costs of thermal generation in future years and the greater current dependence on such sources to meet electric requirements. The impact of these charges is evident in the assumptions underlying the current forecasts. Although growth in residential customers of over 7 percent per year out to 1992 is anticipated, it is also assumed that consumption of electricity will be tempered by a decreased use of electric space and water heating equipment. These anticipated changes in utilization are in response to predicted electric price increases over time. Because they have been incorporated in the load forecasts used in this analysis, it appears that no further adjustment to the forecasts is necessary. The availability and price of heating oi] will also have an effect on future electric consumption by residential and commercial customers. The rapid rise of oi] prices in 1979 set off a trend of electric space and water heating. GHEA's power requirements grew at an annual rate of 19.1 percent from 1979 through 1982. Since 1983 oi] prices have stabilized and heating oil has been available to the residential consumer at $1.20 per gallon. With GHEA's electric rates escalating due to major additions and improvements in its electric system there has been a trend to return to oil fired space and hot water heating systems, using wood stoves for supplementary heating. For example, during the 1983 construction season, approximately 1/3 of the residential units constructed employed oi] fired space and water 0585C 2-6 heating equipment. However, this trend may be short lived depending on the world price of crude oil and petroleum production and refining in Alaska. Because of the uncertainty about the future price and availability of heating oil, the projected load forecast is also uncertain. The GHEA load forecast assumes that the same proportion of electric to oil heat customers will occur in 1987 and 1992; the electric usage rate for each heating customer type is the same in 1987 and 1992 denoting no assured change in space heating equipment efficiency. Although these assumptions are simplistic and likely to be deviated from over time, the high and low load forecasts provide a more than adequate range within which to capture future price changes in heating oil prices as well as electricity prices. Alaska Electric Light and Power Company (AELP) AEL&P's residential customers account for about 83 percent of total customers and 49 percent of total system sales in 1983. However, the commercial and government customers are also important. These classes represent approximately 15 percent of the total number of customers but 50 percent of total system sales in 1983. AEL&P is an investor-owned utility and does not have preference status for federal hydroelectric power. Able to take advantage of early investments in cost-stable hydroelectric projects, however, AFL&P has relatively low electric rates in comparison to GHEA. The AEL&P projection of loads takes into account the effect of likely higher electricity prices and efficiency gains in energy-using equipment by assuming the annual increases in use per residential customer would decrease to zero by 1986 or 1990 (depending on the growth scenario), and to decline thereafter. Analogously, load growth in the commercial and government sectors were assumed to decline over future years in part due to anticipated higher electricity prices and fuel switching. The uncertainty of future oil prices on the cost of electric power generation and use of oi] for space heating in AEL&P's service area is no different than that for GHEA's service area. The forecasts of AEL&P's loads takes the effect of electric prices into consideration to some extent. The high and low forecasts appear to not only account for different economic growth paths but fuel price and supply uncertainty as well. In future years more explicit treatment of price induced conservation would seem in order to limit the degree of uncertainty and to attain more accurate forecasts. 0585C Load Management and Energy Conservation Programs Both GHEA and AEL&P have in effect load management rates to reduce loads and to achieve some electric energy savings. A load management study was performed for GHEA recently which considered the feasibility of alternative direct and indirect load controls in the residential sector. AEL&P's rate structure increasingly reflects actual cost of service. For example, rates are seasonally adjusted to mirror the relatively higher cost of generating winter energy when supplemental diesel production is required. Additionally, a major initiative is underway at AEL&P to encourage dual fuel heating systems. Customers who install dual heating systems and are willing to switch from electric to oil heating during the winter hydroelectric energy deficit periods enjoy special reduced summer energy rates. The commercial program is in effect and presently provides a winter load reduction of about 3.5 MW. A companion residential program is to start with a pilot program during the 1984-1985 winter. Long-term electrical use from space heating may be further impacted by implementation of a proposed City and Borough of Juneau ordinance providing for thermal standards in residential construction. These utility and municipal efforts are still at an early stage of development and the extent to which these programs will defer, limit, or avoid future peak loads and reduce electrical energy consumption rates is unclear. At the present time, however, there is no evidence which suggests that such programs will reduce growth rates further than has already been assumed in the current Juneau forecasts. As experience is gained with the load management and energy conservation programs, the load forecast range should be reviewed to reflect the degree of impact these programs are having. 0585C 2-8 Five categories of power supply alternatives are available to serve Juneau's future power needs. These categories include 1) transmission line interconnection with existing hydroelectric-based systems; 2) undeveloped hydroelectric projects; 3) upgrading existing hydroelectric projects; 4) fossil fuel thermal plants; and 5) other energy sources. A subsection of this report is devoted to each of these categories. Analysis of the power supply alternatives was undertaken using information developed in previous studies. A large number of data sources were reviewed to obtain information on the supply alternatives, and they are referenced where appropriate in the discussion of specific alternatives. A general list of project reference documents is provided in Appendix 7.5. Although there were large amounts of existing information on power supply alternatives, efforts were required to assemble the information so that it would be consistent. lechnical studies dating back as far as 1916 were examined in this analysis, as were other technical studies completed as recently as 1984. A basic engineering review of these previous studies, conducted at a reconnaissance level, was undertaken to ensure that technical findings were consistent, and to facilitate development of consistent cost estimates. Information was updated as necessary so that separate cost estimates could be prepared and updated for each of the supply alternatives. In addition, basic project parameters and significant data were developed for the power supply alternatives which appear to offer the most potential for the Juneau area. An important activity in the analysis of all generation alternatives was the preparation of cost estimates. Ebasco cost estimates were prepared using two basic approaches. First, cost estimators used available quantity information prepared in previous studies to develop cost estimates based on those quantities and on Ebasco experience with similar Alaskan projects. Thus, technical information developed previously by others could be combined with current Ebasco cost information to provide cost estimates suitable for planning purposes. The second approach was simply to escalate previously prepared cost estimates. This approach used standard escalation rates for water resources and power projects as reported in the Engineering News Record dated March 29, 1984. The escalation rates which appeared in the Engineering News Record were developed by the Bureau of Reclamation, Denver, Colorado. Thus, a consistent, industry accepted approach for escalating project costs was adopted. Further, to insure consistency, all cost estimates were updated to January 1984 dollars. The considered power supply alternatives extend over a large portion of southeast Alaska and into British Columbia and the Yukon Territory of Canada. The general location of the power supply alternatives is shown in Figure 3-1. 0072¢ 3-1 WHITEHORSE, YUKON POTENTIAL TRANSMISSION INTERCONNECTIONS TO SERVE JUNEAU POWER NEEDS LEGEND seseseensssses §~=DC TRANSMISSION weeeeee AC TRANSMISSION (Addition) eccccccececooe AC TRANSMISSION (Existing or under construction) QO 50 100 I SCALE - MILES r } UA neg au ante HILL Say Y d a ca JUNEAU AREA 20 YEAR POWER SUPPLY PLAN TRANSMISSION INTERCONNECTION ALTERNATIVES FOR JUNEAU DATE NOV 1984 | FIGURE 3-1 EBASCO SERVICES INCORPORATED 3.1 INTERCONNECTION WITH EXISTING HYDROELECTRIC-BASED SYSTEMS A portion of Juneau's future power requirements could be supplied by transmission interconnection with existing hydroelectric projects. These possibilities are examined below. The first alternative would provide Juneau with power from Whitehorse, Yukon Territory. Under this alternative, excess hydroelectric capacity in the Whitehorse area could be made available to Juneau. Initial discussions with Canadian officials indicated that the power would only be available to Juneau when not needed in the Yukon Territory. Therefore, energy from this alternative is tentatively considered nonfirm, pending the outcome of further negotiations. The second alternative would provide firm energy to the Juneau area by the development of a transmission line connecting the Tyee Lake hydroelectric system with Juneau. There will be firm energy available from the Tyee Lake project that could be used in the Juneau area. This energy could be made available to Juneau if a transmission line is constructed from the existing transmission line system near Petersburg north to the existing transmission line at the Snettisham project. The third transmission alternative would involve the installation of a submarine cable from the Snettisham project to Juneau. The purpose of this cable would be to increase the reliability of the power generated at the Snettisham project and any other projects developed in the future south of Taku Inlet. Installation of this submarine cable, in combination with certain hydroelectric developments, would eliminate the need for some standby thermal generation capability in the immediate vicinity of Juneau. Since its purpose is an increase in reliability, not transmission of energy from a new source of generation, this alternative is not directly comparable to the other two transmission interconnection alternatives. The important parameters associated with each of these projects is described below. 3.1.1 Whitehorse-Juneau Transmission Line A transmission system linking Whitehorse and Juneau would involve three types of transmission lines. For the first 105 miles from Whitehorse, the line would be an overhead 115 kV alternating current (AC) transmission line. Ninety-three miles of this line would be in Canada, with the remaining 12 mile section of the line being the portion of the line from the Canadian border to Skagway. At Skagway, a 64-mile, 100 kV direct current (DC) submarine cable would begin. That cable would extend south to Yankee Cove, where an overhead 69 kV AC transmission line would be constructed to interconnect with existing facilities near Auke Bay. The general location of this project is shown in Figure 3-1. 0072C 3-3 The project would also involve the installation of AC/DC converters and transformers. The capacity of this line would be 20 megawatts. Further, intermediate service could be provided to Haines and Skagway with the addition of certain supplemental facilities. Previous Studies: Two sources of information were used for the analysis of the Whitehorse-Juneau transmission line. The first prepared by R. W. Beck (1984) is entitled "Economic and Financial Analysis of a Proposed Transmission Intertie Between Whitehorse, Yukon Territory, and Haines, Skagway, and Juneau, Alaska." This report was sponsored by the Alaska Power Administration, the Alaska Power Authority, and the Northern Canada Power Commission. It analyzed a 138 kV transmission line. In addition, a report prepared by Teshmont (1982) was also used. Information from that report was updated and used for the cost estimate. The Teshmont report examined the 115 kV system. Updating: Updating activities relating to this transmission line alternative involved examination of previous studies and the preparation of a cost estimate and basic economic parameters sheet. The basic economic parameters are shown in Table 3-1. It is important to note on Table 3-1 (as well as on similar Tables 3-5, 3-12, and 3-15) that the estimated unit capacity and energy costs shown are based on a constant dollar analysis. Thus, the figures are useful for comparing relative projects, but do not reflect estimates of actual power costs. The cost estimate prepared for this alternative is shown in Table 3-2. The cost estimate used in this study assumed development of a 115 kV system as identified by Teshmont, and not the 138 kV system identified in the R. W. Beck report. The 115 kV system data was used because of its general availability in the Teshmont report and because of the fact that both the 115 kV and 138 kV systems appeared adequate. For planning purposes, either one could be used without affecting the results. Along with reviewing previous studies, suppliers of submarine cables were contacted to obtain better information in order to properly escalate previous cost estimates. Contacts with submarine cable manufacturers confirmed Ebasco's other experience with submarine cable cost estimating and the fact that the cost of such facilities is highly uncertain. The relatively little amount of submarine cable installed in North America, together with the fact that there are only a few high voltage submarine cable manufacturers, make it difficult to obtain a good, reliable cost for the installation of a submarine cable in the project area. Estimated costs of AC/DC converter stations are even More uncertain. One manufacturer, ASEA, provides approximately 80% of all converter stations, although Westinghouse and Brown-Boveri are also suppliers. Therefore, the cost estimate for this alternative cannot be considered as accurate as some of the others. Similarly, any alternative involving a long segment of submarine cable is of less accuracy than other estimates presented in this report. o072c 3-4 TRINTALT OCTOBER 18, 1984 PROJECT NAME FACILITIES: TOTAL LENGTH (Ml) CAPITAL COST ($) TRANSFER CAPACITY (MW) TRANSMISSION LOSSES PERCENT Mw NET CAPACITY (MW) ENERGY AT SOURCE FIRM (GWh) SECONDARY (GWh) TOTAL AVERAGE ANNUAL (GWh) TRANSMISSION LOSSES PERCENT GWh NET AVERAGE ANNUAL (GWh) ENERGY COST AT SOURCE CENTS/KWh-CANADIAN (2) CENTS/KWh-U.S. HEAT RATE OPERATION & MAINTENANCE SIYEAR-U.S. (1) CONSTRUCTION DURATION (MONTHS) CONSTRUCTION CASH FLOW YEAR 1 ($) YEAR 2 ($) YEAR 3 ($) ECONOMIC LIFE (YEARS) RELATIVE COST CAPACITY ($/KW) ENERGY (CENTS/KWh DELIV.)(6) (1) WHITEHORSE BASED ON $112,000 FOR CANADIAN SEGMENT AND $1,400,000 FOR U.S. SEGMENT. TABLE 3-1 ECONOMIC PARAMETERS SUMMARY FOR THE TRANSMISSION INTERCONNECTION ALTERNATIVES WHITEHORSE-JUNEAU 105.5 MI OF 115kV AC WOOD POLE LINE 64.0 MI OF 100kV DC SUBMARINE CABLE 6.5 MI OF 69kV _ 176 102460000 20 8.2 1.64 18.36 175.2 6) 8.2 14.37 160.83 3.5 2.8 N/A 1532000 15369000 57378000 29713000 30 5,123 7.22 (5) TYEE-SNETTISHAM 110 MI of 100kV DC SUBMARINE CABLE 3 MI OF 100kV DC _WOOD POLE LINE 54820000 SNETTISHAM-JUNEAU 42 MI OF 100kV DC SUBMARINE CABLE 42 57744000 74 (3) 9.7 7.18 66.82 DEPENDS ON PROJECTS DEVELOPED DEPENDS ON PROJECTS DEVELOPED DEPENDS ON PROJECTS DEVELOPED DEPENDS ON PROJECTS DEVELOPED DEPENDS ON PROJECTS INTERCONNECTED NIA 589000 24 28000000 29744000 30 780 (3) (4) DEPENDS ON PROJECTS INTERCONNECTED (2) PLUS 4% MARK-UP ON DEBT SERVICE AND O&M COSTS FOR CANADIAN PORTION. CANADIAN CONVERSION RATE IS $1 CANADIAN = $0.80 U.S. (3) ASSUMES 74MW OF TRANSFER CAPACITY OF LINE IS UTILIZED. IF ALL 110MW ARE USED, THE RELATIVE CAPACITY COST IS $525/KW. _ (4) 9.0 CENTS/KWh DELIVERED IF COST AT SOURCE IS 4.6 CENTS/KWh, 6.9 CENTS WHEN PURCHASE PRICE IS 2.52 CENTS/KWh. (5) THEORETICAL CAPABILITY OF THE LINE. AT 97.5 GWh TRANSFERRED, ENERGY COST EQUALS 10.7 CENTS/KWh. (6) CONSTANT DOLLAR ANALYSIS FOR COMPARATIVE PURPOSES ONLY. 35 Code TABLE 3-2 CONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL WHITEHORSE TO JUNEAU TRANSMISSION INTERCONNECTION Description Unit Quantity Unit Cost Total (1984 $) TRANSMISSION PLANT 350 ~— Land LS $226,000 352. Station Str & Impr (incl. clearing) AC Line LS 20,865,000 DC Line Ls 372,000 Converter Stations Ls 1,541 ,000 353. Station Equipment AC Line Ls 1,777,000 DC Line Ls N/A Converter Stations LS 10,647,000 354 Steel Towers (AC) LS 19,335,000 355 ——- Poles & Fixtures (DC) LS 1,073,000 356 OH Conductors & Devices AC Line, 115 kV, AC Ls 8,346,000 DC Line, 100 kV, DC Ls 364,000 358 Submarine Cable (100 kV, DC) Ls 13,822,000 Subtotal Transmission Plant $77,768,000 GENERAL PLANT 397 Communications Equipment LS 1,8%,000 Subtotal Transmission & General Plant $79,662,000 Contingency @ 18% 14,338,000 Subtotal "¥4,000,000 71 — Engineering and Administration @ % 8,460,000 TOTAL PROJECT COST (w/o IDC) $102 460,000 7056B 3-6 Summary of Findings: The important economic parameters are shown in Table 3-1. It includes an entry for the price of energy at the source of the line (Whitehorse). This energy cost of 3.5¢/kWh (Canadian) is the price that Juneau would need to pay for power if it were to be purchased at Whitehorse. This price does not include line losses between Whitehorse and Juneau. In the face of uncertain surplus firm energy availability, unit energy costs were calculated for two levels of energy transfer, the theoretical capability of 175 GWh and a lesser amount of 40 Gwh. Corresponding unit energy costs vary from $0.07 to $0.22 per kwh (constant 1984 dollars). The development of the Whitehorse to Juneau transmission line would enable power to be transmitted in either direction should conditions warrant such exchanges. The benefits of this diversity, however, are not considered great in the near term and are not analyzed in this report. There are several advantages and disadvantages associated with this alternative. These are summarized below. Advantages ° Significant step for development of a Yukon/southeast Alaska/B.C. Hydro transmission link. If this alternative were to be developed, the first leg of a transmission line linking all of southeast Alaska would be established as transmission capacity would exist between the Canadian border north of Skagway and the Snettisham project, which is well south of Juneau. Development of a major transmission grid would improve electrical service to any areas that are interconnected with it, as well as enable the economic development of various generation alternatives that would otherwise be precluded from development because of long transmission distances or excessive scale for individual isolated load centers. 0 Minimal environmental impacts. The installation of a submarine cable would have very little environmental impact. Further north, the overhead portion of the project would involve the construction of a 12.5 mile transmission line in southeast Alaska. The area disturbed by such developments is small, especially when compared to other generation alternatives. In spite of the relatively low potential for environmental affect in the United States, the 93 miles of transmission line in Canada could cause some impact. ° Transfer capability in both directions. Development of the transmission line from Whitehorse to Juneau could enable power to be sent either north or south depending on overall supply and demand, and on seasonal diversity. The link would also 0072C 3-7 allow reduction in the sum of U.S. and Canadian reserve requirements. Such a situation offers potentially valuable flexibility in future planning. ° Service could be provided at little additional cost to Haines and Skagway, two communities with few reasonable-cost power alternatives. Disadvantages ° High capital cost. The length of transmission line involved, the fact that a large portion of it is a submarine cable, and the difficult construction conditions all contribute to the project's high cost of $102,460,000. 0 While the Northern Canada Power Commission has an incentive to seek markets for its power, to date there has been no commitment to a long-term firm sales contract. Additional discussions will be required to establish the availability of firm power. ° Uncertainty of submarine cable costs. As noted above, there is a wide variation in the estimated cost of submarine cables among the different manufacturers. This introduces a relatively higher degree of uncertainty in the cost estimate for this alternative. ° Potential failure of submarine cable. Well designed and properly installed submarine cables perform well and have a high reliability. We are unaware of any failures of an electrical nature on high voltage DC cables. The only failures reported have been caused by shipping (anchoring) and fishing (trawling). By routing cables in low shipping traffic areas and by trenching where necessary, the danger of mechanical failure can be minimized. 3.1.2 Tyee-Snettisham Transmission Line This project would involve installation of 110 miles of submarine cable and 3 miles of overhead line. The project would be a 100 kV DC line capable of transferring approximately 30 megawatts. AC/DC converters would be required at both ends of the project. The existing Tyee transmission system terminates in Petersburg. The line up to the Snettisham project would follow the Stephen's Passage in the general location shown in Figure 3-1. Although the line is primarily submarine cable, an overhead portion is anticipated near Petersburg, where an overhead DC line would be constructed. Previous Studies: The installation of a submarine cable between Petersburg and the Snettisham project was examined by Teshmont (1982) in their report 0072C 3-8 entitled "Southeast Alaska Intertie DC Transmission System." That report provided the basic information used in the present analysis of the Tyee-Snettisham option. Updating: As discussed in the preceding discussion in Section 3.1.1, manufacturers of submarine cable were contacted. Information obtained during these contacts was used, in conjunction with information in the Teshmont report, to update the cost estimate for this alternative. As indicated above, the primary result of contacts with submarine cable manufacturers was confirmation of the fact that estimating costs of submarine cables is highly uncertain. Thus, updating the previously prepared submarine cable cost estimates was accomplished using the standard escalation approach described earlier, but it should be recognized that the basic underlying cost information is highly uncertain. Summa ry : The Tyee-Snettisham transmission line project would be able to transfer 30 megawatts of power. That capacity would be adequate to transmit the ultimate full capacity of the Tyee lake project, although it is recognized that the entire capacity is not available. The 30 megawatt size was determined to be appropriate because it would be adequate for all of the output of the present Tyee Lake project, plus the 10 Megawatt future addition, while allowing sufficient flexibility in the future to transfer power either north or south depending on how generation alternatives and loads develop. The actual amount of power which would be available to the City of Juneau depends on what type of long term commitments could be made by the Alaska Power Authority, the developer of the Tyee Lake project, which would in turn depend on the growth in loads presently served by the Tyee Lake project. The estimated cost of purchased power from the Tyee Lake Project is based on Ebasco's interpretation of information provided by the Alaska Power Authority (Four Dam Pool Briefing Document, August 20, 1984). Several pricing scenarios are presented, but the “adjusted debt service" version of the "state loan case" is used as a representative estimate. In the mid-1990s, a cost of 7.6 cents/kWh is indicated; this figure is in 1984 constant dollars. At that point in time (1995), Power Authority load growth forecasts for Petersburg and Wrangell indicate that 75 percent of Tyee's power potential would remain unutilized. This, of course, assumes that service has not been initiated to Ketchikan in the interim. Using this assumption, as much as 91 GWh of firm energy would be theoretically available for purchase by Juneau. That amount would fall over time as the usage by other service areas increased. The increased utilization of the project's potential by Juneau would have a beneficial effect on the cost of Tyee power, although that affect would be attenuated because of the "pooled" nature of the Power Authority's four dam system. At the extreme, full utilization of Tyee would result in a 40 percent reduction in cost to about 4.6 cents/kwh. 0072C To explore the full range of possible Tyee-Snettisham Interconnection power costs, a sensitivity test was conducted with the purchase price of Tyee power ranging from 7.6 cents/kWh to 2.5 cents/kWh. The constant dollar unit cost for the Tyee-Snettisham Interconnection becomes equivalent to the cost of the diesel option at about 3.5 cents/kWh. Pertinent economic data covering the range of possible prices are presented in Table 3-1, while the cost estimate for this alternative is presented in Table 3-3. The major advantages and disadvantages of the Tyee-Snettisham transmission line project are summarized next: Advantages ° Would provide firm energy to the Juneau area. Constructing a transmission line from the existing Tyee transmission system to the Snettisham project area would enable Juneau's future power requirements to be satisfied by an existing hydroelectric project. ° Establishment of southeast Alaska transmission grid. Installation of a submarine cable from the existing Tyee system to the Snettisham project would be a key element in the establishment of a transmission grid in southeast Alaska. If this project were to be constructed, the only remaining link in establishing a transmission system from Ketchikan to Juneau would be for a connection between the Tyee Lake Project and Ketchikan. The establishment of a grid in southeast Alaska would improve the electric service to all communities served by that grid. If further interconnected to the B.C. Hydro system, additional supplies of surplus power could be tapped. Disadvantages ° The high capital cost ($54.8 million) and the significant cost of purchased power (7.6 cents per kWh, initially) hurt the economic feasibility of this alternative. This assessment is dependent upon the final negotiated price for Tyee power. ° Uncertain cost of submarine cable. As noted previously, the cost of submarine cable material and installation are relatively uncertain. ° Potential failure in DC cable. Although, as indicated previously, the chance of a well designed and properly installed submarine cable failing is quite low, an extended outage (approximately one month) should be anticipated if such a failure does occur. 0072C 3-10 TABLE 3-3 CONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL TYEE TO SNETTISHAM TRANSMISSION INTERCONNECTION Code Description Unit Quantity Unit Cost Total (1984 $) TRANSMISSION PLANT 350 Land LS $73,000 352 Station Str & Impr (incl. clearing) AC Line LS N/A DC Line LS 111,000 Converter Stations Ls 1,509,000 353 Station Equipment DC Line Ls N/A Converter Stations LS 14,451 ,000 355 Poles & Fixtures (DC) Ls 316,000 356 OH Conductors & Devices (DC) Ls 107,000 358 Submarine Cable (100 kV, DC) Ls 23,139,000 Subtotal Transmission Plant $89,706 ,000 GENERAL PLANT 397 Communications Equipment LS 2,151 ,000 Subtotal Transnission & General Plant $41 ,857 ,000 Contingency @ 18% 7,533,000 Subtotal "¥49,390,000 71 Engineering & Administration @ 11% 5,430,000 TOTAL PROJECT COST (w/o IDC) $54,820,000 70568 3-11 3.1.3 Snettisham-Juneau DC Cable A submarine cable examined for linking the Snettisham project directly with Juneau would be 42 miles long and 100 kV DC. Its general location would parallel the existing 138 kV overhead line, as shown in Figure 3-1. The submarine cable would terminate at the Thane substation, south of Juneau. Converters would be installed near the existing Snettisham project and at Thane substation. Previous Studies: The primary study used in the analysis of this alternative was entitled "Shettisham/Juneau DC Transmission System," prepared for the Alaska Power Administration (Teshmont 1983). This study provided technical and cost information on the DC cable alternative. Updating: As with the other submarine cable alternatives, updating activities on this alternative included contacts with submarine cable manufacturers which confirmed the uncertainty associated with submarine cable costs. It also included updating the April 1983 cost information (Teshmont 1983) to January 1984 dollars. Sumnary of Findings: The key economic evaluation parameters are presented in Table 3-1 while the estimated costs of the Snettisham-Juneau DC cable are presented in Table 3-4. The primary reason for installing the Snettisham-Juneau submarine cable would be to increase the reliability of power generated at the Snettisham project. Current policies call for providing full back-up for all power produced at the Snettisham project. This full reserve requirement was established during the initial years of operation of the Snettisham project when there were severe problems with the transmission line, which was out of service a significant portion of the time. This situation vastly improved with the relocation of the line from its exposed position to lower elevations. In order to prevent loss of the existing Snettisham-Juneau transmission line and isolating the Snettisham project from the load center, a submarine cable could be installed which would provide 100% back-up for the existing line. The primary purpose of the Snettisham-Juneau line is to improve reliability, not to provide additional generation capacity to Juneau. While the additional line provides complete redundancy for the transmission component of the system, it does not preclude outages at Snettisham. As a result, the additional line, while improving reliability by backing-up a portion of the Snettisham system, would not necessarily eliminate the need for sufficient reserves independent of Snettisham to meet peak load. 0072C 3-12 Code TABLE 3-4 OONSTRUCTION COST ESTIMATE REOONNAISSANCE LEVEL SNETTISHAM TO JUNEAU SUBMARINE CABLE TRANSMISSION INTERCONNECTION Description Unit Quantity Unit Cost Total (1984 $) TRANSMISSION PLANT 350 Land LS $71 ,000 352 = Station Structures & Improvenents (including clearing) DC Line LS 48,000 Converter Stations ES 1,616 ,000 353 Station Equipment Converter Stations LS 28,575,000 355 ~~ Poles & Fixtures (DC) LS 204 ,000 356 OH Conductors & Devices OC Line LS 68,000 358 Submarine Cable (100 kV, DC) LS 11,377,000 Subtotal Transmission Plant $41,959,000 GENERAL PLANT 397. Communications Equipment LS) 1,733,000 Subtotal Transmission & General Plant 43,692 ,000 Contingency @ 18% 7,865,000 Subtotal ‘J5T,557,000 71 ‘Engineering and Administration @ 12% 6,187,000 TOTAL PROJECT COST (w/o IDC) $57,744,000 70563 3-13 Because of the fact that the Snettisham-Juneau transmission line is intended to improve the reliability of service, developing this project should be compared to the cost of developing additional standby capacity, although, as noted above, the extra transmission line is not as valuable as reserve capacity that is completely independent of Snettisham. Otherwise, this project has many of the same characteristics, advantages and disadvantages as other submarine cable projects. These are summarized below. Advantages ° Improves reliability of Snettisham project. If the submarine cable alternative were constructed, the transmission component of the Snettisham project could be assumed to be 100% available. ° Will provide additional transmission capacity between Snettisham and Juneau which could be utilized by other future projects developed in the vicinity of the Snettisham project. ° Environmental concerns related to this entirely submarine cable project would be limited. Disadvantages ° The high cost of this project ($57.7 million), together with the fact that it provides only standby power, cause it to be uneconomical. The economic infeasibility of this project becomes apparent when one views its relative cost per kW, assuming that the Snettisham and Crater Lake projects were to be backed up by this submarine cable. In that case, the relative cost would be $779/kW, a value significantly higher than that for standby diesels or combustion turbines (see Table 3-15). Further, the transmission line does not provide as high a degree of reliability as standby thermal units located in Juneau. 3.2 UNDEVELOPED HYDROELECTRIC PROJECTS Southeast Alaska is rich in hydro potential including several projects in the general vicinity of Juneau. Some of these projects have already been developed while others have gone through various levels of analysis ranging from mere identification to having undergone feasibility level analysis. This section addresses hydroelectric projects which have not yet been developed, but offer potential to meet Juneau's future power requirements. Potential hydroelectric sites are identified in Figure 3-2, while existing Juneau area hydroelectric facilities are shown in Figure 3-3. 0072C 3-14 es Nab dn LONG LAKE Wi LAKE Se i NUGGET ee GOLD le SAN. “ANNEX (CREEK its DOROTHY SPEEL RIVER mui LAKE a BAY TERSBURG 3-15 HYDRO PROJECTS TO SERVE JUNEAU POWER NEEDS LEGEND & HYDRO SITES Qo 50 100 ES SCALE - MILES JUNEAU AREA 20 YEAR POWER SUPPLY PLAN JUNEAU AREA HYDRO SITES DATE NOV 1984 | FIGURE 3-2 EBASCO SERVICES INCORPORATED JUNEAU AREA 20 YEAR POWER SUPPLY PLAN JUNEAU AREA HYDRO SITES GLACIER ww” » DOUGLAS /SLAND COMBINATION WOOD & STEEL T-LINE 22kV | | } ps TAKU INLET -* SUBSTATIONS: 1. WEST JUNEAU 2. SECOND STREET 3.G0LD CREEK 4. LEMON CREEK S. AIRPORT 6. LOOP 7. THANE SUBSTATIONS OPERABLE POWERHOUSE /OLE POWERHOUSE Se, € CREEK yk =TRANSMISSION LINE JUNEAU AREA 20 YEAR POWER SUPPLY PLAN : JUNEAU AREA HYDRO FACILITIES DATE NOV 1984 | FIGURE 3-3 EBASCO SERVICES INCORPORATED There are several types of hydroelectric projects which are discussed in the following section. In general, they fall into two broad categories: lake taps and projects requiring construction of a dam. Lake tap projects involve the construction of an underground tunnel from lower elevation, usually sea level, to the lake bottom. Flows through the tunnel are then regulated and pass through a turbine to generate power. On such projects, storage may be large or small, as there is an existing lake which serves as a reservoir. Reservoir clearing and dam construction are not needed. However, lake tap projects are of somewhat limited application throughout the world because they require relatively unique site conditions. The lake must be situated in a relatively high elevation above a suitable location for a powerhouse and the lake itself must rest above stable and other suitable bedrock which can be tunneled through from below. A more standard type of hydroelectric project involves the construction of a dam and the diversion of flow by the installation of piping and penstocks to convey the flow into a powerhouse where electricity is generated. Projects involving the construction of dams can either be run of the river projects where a relatively low dam is constructed and no sizable reservoir is developed or a relatively high dam could be constructed leading to the creation of a larger reservoir where relatively large volumes of water could be stored for seasonal regulation and release. Both types of projects have been studied in the Juneau area. Hydroelectric projects under consideration for development are typically analyzed in terms of the capacity and energy they provide to the area. The relative economic viability of such projects is determined by the head, flow, and storage of the project. In the Juneau area, it is desirable for projects to be able to produce energy in the winter when loads are highest and when water inflow is limited on some hydroelectric projects. Another factor that can be important in influencing the desirability of individual hydroelectric projects is their proximity to load centers and existing transmission lines. There are several sites in southeast Alaska which would be excellent projects were it not for the fact thal they are remote. The high cost of transmission line construction over long distances through rugged terrain and line losses associated with transmission of energy over these distances hurt the economics of individual projects. Specific projects considered in this 20 year power plan include Crater Lake, Lake Dorothy, Sweetheart lake, Thomas Bay, Spee] River, and Nugget Creek. There are other potential projects, such as Sheep Creek and Carlson Creek, which are smaller and closer to Juneau, but relatively costly. At Carlson Creek, conventional development would require a large dam to develop a limited amount of storage, and long waterways would be needed to develop the available head. Sheep Creek, with an apparent dam site at the outlet of its basin, offers a small drainage area, limited storage, and relatively low head. Additionally, its reservoir would flood a historic mining area. 0072C 3-17 It should also be noted that there was considerable existing information on the potential of individual hydro projects in the Juneau area. Studies have been conducted on hydroelectric projects since the early 1900s, although the most relevant studies were conducted more recently. Individual references used in this investigation are sited throughout the text while a general list of references used is provided at the end of the document. The discussions which follow summarize the important features of each project and present the project parameters used in the economic analysis. Significant data for each project are included in Appendix 7.1 of this report. 3.2.1 Crater Lake Addition to Snettisham Crater Lake is located 1.3 miles from the existing powerhouse for the Snettisham project. The development of the Crater Lake project will be accomplished by adding a third unit to the existing underground Snettisham powerhouse, excavating a tunnel, and constructing a lake tap at Crater Lake. In constructing the initial Snettisham phase (Long Lake), space was provided for the third turbine and generator unit in the powerhouse, and all the engineering and planning work for the Crater Lake phase has been completed. Construction of the project will commence in 1984. The installed capacity of Snettisham will be increased by 27 MW, and the Crater Lake phase will provide an average of 121 GWh of electrical energy annually. The project, which is located approximately 30 miles southeast of Juneau, is shown on Figure 3-2. A more detailed map of the project area is provided in Figure 3-4. Previous Studies: The Crater Lake project, which was designed by the Corps of Engineers, has gone through an extensive number of engineering analyses. These studies date back to the 1950s with the final results being represented in the design drawings for the project. In the present planning analysis, information on the project was obtained from U. S. Corps of Engineers Design Memorandum No. 23. Also, basic background information on the project and its cost were presented in a letter dated April 18, 1984, by Harlan E. Moore, Chief, Engineering Division, U. S. Corps of Engineers, Anchorage, Alaska (Moore, 1984). Updating Activities: Updating activities related to the Crater Lake Project consisted of reviewing design memoranda and other project documents and consulting with the Corps of Engineers. The cost estimate was reviewed and some slight modifications were made to it based on Ebasco's experience on other hydroelectric projects in Alaska. These minor modifications pertained to the construction camp costs and were relayed to the Corps of Engineers project staff who subsequently included them in the official project estimate. An aerial reconnaissance of the project area was conducted and a site visit was also performed. 0072C 3-18 1/2 1 2 SCALE - MILES EXISTING “ UNDERGROUND JUNEAU AREA 20 YEAR POWER SUPPLY PLAN SNETTISHAM & CRATER LAKE PLANS DATE NOV 1984 | FIGURE 3-4 a SE EBASCO SERVICES INCORPORATED Summary of Findings: This project, which has been authorized for construction, has a high head and offers considerable seasonal storage. It will fit in well with the future needs of Juneau. The important parameters affecting the economic evaluation are presented in Table 3-5 and significant data for the project are presented in Appendix 7.1. The cost estimate appears in Table 3-6. In general, it is the most cost effective project available to Juneau and is entering the construction phase. It is assumed to be completed and on line in 1988 and is therefore incorporated into the base case analysis as a committed project. The important advantages and disadvantages of this project are summarized below. Advantages ° Cost for size of units. Because the Crater Lake Project can utilize space available at the existing Snettisham powerhouse, as well as other facilities of the existing project, and because the Crater Lake Project is a lake tap type project, it has a relatively low installed cost per kilowatt. ° Lake tap projects do not involve the construction of dams and therefore that costly element is avoided. Elimination of the need for a dam also lowers the geologic and subsurface risks associated with constructing a major project feature such as a dam. ° High confidence in cost estimates. The design level of information available on the Crater Lake project together with the fact that there has been recent construction experience for similar hydroelectric projects in southeast Alaska allows the cost estimate of the Crater Lake project to be considered More accurate than those of other hydroelectric projects analyzed in this plan. Disadvantages ° Project is located south of Taku Inlet. The Crater Lake project would be off line if there is a disruption to the existing 138kV transmission line linking the Snettisham project to Juneau. 3.2.2 Lake Dorothy The Lake Dorothy project is a high head (2,400-foot elevation) lake tap project in an undeveloped area just south of Taku Inlet. The project would be located approximately four miles north of the existing east submarine cable termination point for the Snettisham project. The powerhouse would be located at tidewater and would house two 13 MW 0072C 3-20 UNHYDPRJ OCTOBER 18, 1984 TABLE 3-5 ECONOMIC PARAMETERS SUMMARY OF UNDEVELOPED HYDROELECTRIC PROJECTS PROJECT NAME CRATER LAKE* LAKE DOROTHY** SWEETHEART LAKE SPEEL RIVER*** THOMAS BAY NUGGET CREEK POWER FACILITIES NO. OF UNITS 1 2 2 2 3 2 SIZE OF UNITS (MW) 27 13 13 28.55 15 5.4 CAPITAL COST ($) 55422000 71920000 104900000 169802000 121580000 24830000 CAPACITY (MW) 27 26 26 57.1 45 10.8 TRANSMISSION LOSSES PERCENT 42 1 49 7.2 17.9 2.13 MW 1.13 0.26 1.27 4.41 8.06 0.23 NET CAPACITY (MW) 25.87 25.74 24.73 52.99 36.95 10.57 ENERGY GENERATION FIRM (GWh) 105 200 22 SECONDARY (GWh) 16 ia a TOTAL AVERAGE ANN.(GWh) 121 127 125 400 200 22 TRANSMISSION LOSSES PERCENT 2.3 07 2.8 44 14.4 37 GWh 2.8 0.9 3.5 17.6 28.8 08 AVG. AN. ENERGY DELIVERED 118.2 126.1 121.5 382.4 171.2 21.2 FUEL USE NONE NONE NONE NONE NONE NONE HEAT RATE NONE NONE NONE NONE NONE NONE OPERATION & MAINTENANCE $/YEAR 235000 304800 304800 254000 304800 304800 CONSTRUCTION DURATION MONTHS 36 32 46 48 36 24 CONSTRUCTION CASH FLOW YEAR 1 (8) 12706000 16541000 11539000 18674000 27960000 14900000 YEAR 2 ($) 23832000 30926000 45107000 72989000 52280000 9930000 YEAR 3 (8) 18884000 24453000 35666000 57731000 41340000 YEAR 4 (8) 12588000 20408000 ECONOMIC LIFE (YEARS) 50 50 50 50 50 50 RELATIVE COST CAPACITY ($/KW) 2053 2766 4035 2974 2702 2299 ENERGY (CENTS/KWh DEL.) .20 2.67 3.93 1.96 3.21 6.44 *ADDITION TO SNETTISHAM **WITH SEPARATE TRANSMISSION LINE TO JUNEAU, CAPITAL COST IS $75638000 UNIT COSTS ARE 2909 $/KW AND 2.80 CENTS/KWh. ***RELATIVELY HIGH DEGREE OF UNCERTAINTY DUE TO POTENTIALLY DIFFICULT FOUNDATION CONDITIONS; LESS THAN FULL UTILIZATION OF ENERGY WOULD ADVERSELY AFFECT UNIT ENERGY COST. 3-21 TABLE 3-6 CONSTRUCTION COST EST IMATE REOONNAISSANCE LEVEL CRATER LAKE HYDRO PROJECT (27 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not Included 331 Powerhouse Str & Imp 332 Reservoirs, Dams, Waterways Primary Rock Trap/ G ~*~ § a 8 Lake Tap LS 1,860,000 Primary Trashrack LS 963,000 Secondary Rock Trap LS 189,000 Final Rock Trap LS 729 ,000 Final Rock Trap Access Adit LS 3,313,000 Access Adit to Lake LS 1,666,000 Power Tunnel LF 6,020 900 5,418,000 (11' Horseshoe) (5 Fault Zones) Surge Tank LS 2,395,000 Penstock LS 7,376,000 Gate Structure/Access Adit Ls 6,987,000 333. Waterwheels, Turbines, Gens MW 27 139,963 3,779,000 3% = Accessory Electrical MW 27 23,407 632,000 335. ~~ Misc Power Plant Equip Ls 23,000 Subtotal Production Plant $36,105,000 TRANSMISSION PLANT 352/ = Switchyard Ls 362,000 353 GENERAL PLANT 39 Buildings 250,000 Subtotal Production, Transmission and General Plant $36,717,000 63 Indirect Const Cost: Camp MD 55,000 75 4,125,000 Subtotal $40,842,000 Contingency @ 15% LS 6,126,000 Subtotal We, 56B, 000 71 — Engineering & Administration @ 18% 8,454,000 TOTAL PROJECT COST (w/o IDC) $55,422 ,000 ODES ple MTP TI TVD pede L nn TGP n TG PDI) lilly Wanna 3-22 units. The project's average annual energy is estimated at 127 Gwh. The general location of this project is shown in Figure 3-2 while the specifics of the project are shown on a general plan view map (Figure 3-5) and a profile drawing on Figure 3-7. revious Studies: There have been many studies of the Lake Dorothy project including a report by the Bureau of Reclamation entitled "Preliminary Geologic Report, Lake Dorothy Project", dated October 1954, and one by R.W. Beck prepared in 1983 entitled "Haines-Skagway Region Feasibility Study, Volume 4, Supplemental Investigations." The latter report (Beck 1983) was the one used to develop information used in the reconnaissance level cost estimate. Upgrading: Previous studies were reviewed and some modifications made to more closely reflect recent practices in tunnel excavating and underground construction. Specifically, the project quantities were changed to provide an 11-foot rather than a 7-foot diameter tunnel to tap lake Dorothy. This change in tunnel diameter was made because recent experience on the Terror Lake project on Kodiak Island and other projects in the lower 48 suggest that the 11-foot diameter tunnel is the smallest practical size which can be constructed using newer, advanced technology, tunnel boring machines. This change in the project features was reflected in the cost estimate, although no studies were undertaken to adjust the capacity and energy output which could be expected from the project. For planning purposes, however, it is not considered necessary to evaluate how the 11-foot diameter tunnel would affect operations and overall project performance as such a change should have a relatively limited effect on operations and, if anything, offer potential for improving project operation. Operation and maintenance costs for the project were estimated using the report on hydroelectric power evaluation prepared by the Federal Energy Regulatory Commission (FERC 1979). Along with adjusting the tunneling cost brought about by the use of an 11-foot diameter tunnel boring machine, the project cost estimate was also revised to reflect a corresponding adjustment in project quantities affected by the change in tunnel diameter. For example, the quantities associated with lining the tunnel, excavation, support steel, and concrete were adjusted. The cost estimate is presented in Table 3-7. Summary of Important Findings: The important features of the Lake Dorothy project are summarized on Table 3-5. The advantages and disadvantages are summarized below. 0072C 3-23 v2-€ Val ek Altefnative 3» \ all nent yon ‘ “Ae Powerhouse (2-13 MW units) I S8 FE es ak Sie" ee ~~ _\\Power tunnel — Loke top - _. Gate shaft wv yt 7-11" Dio. unlined) ~~ 138/12. 5- kV - / SEN substation ao Op Ligug 7 ; SEZ Gocpar A 4 L es ‘gs \ Proposed 138- kVoc = submorine transmission line 2, al ean ae Alternative 2 alignment Existing 138-kVac 57 transmission ling to Juneau a < Topography is besed on- Bishop Pt pe a tsneP ff Q USGS | : 63,360 scale mapping 136- kV 7% ' > switchyard ~. Existing 138- Voc fo ine transmission line : = LEGEND. Sa ee g { / Wew— Existing 138-kVac overhead transmission line JUNEAU AREA 20 YEAR Rae a ' —— qeayee Existing 138-kVac submarine transmission line POWER SUPPLY PLAN Se NX +B Proposed 138-kVac submarine transmission lin Existing 138- kVac 4 Substation LAKE DOROTHY PLAN transmission line s Powerhouse DATE NOV 1984 | FIGURE 3-5 EBASCO SERVICES INCORPORATED fe Snettisham Project o Switchyard TABLE 3-7 CONSTRUCTION COST ESTIMATE REQONNATSSANCE LEVEL LAKE DOROTHY HYDRO PROJECT (26 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not included 331 PH Structures & Impr Ls $6,170,000 332 Reservoirs, Dams, Waterways Lake Tap & Trashrack LS 513,000 Intake Gate Shaft LF 460 2,074 954,000 Intake Gate Shaft Equip LS 1,304,000 a Tumel LF 2,400 2,726 6,544,000 (11' Dia. a Tunnel LF 480 3,029 1,454,000 (11' 9 Unlined Tunnel (11'Q) LF 11,120 760 8,451,000 Vertical Shotcrete-] ined Shaft LF 1,440 1,3% 2,011,000 333 Waterwheels, Turbines, Gens MW 26 211,538 5,500,000 (2 Pelton @ 13 MW/ea. ,2200'HD) 334 ~~ Accessory Electrical MW 26 61 ,538 1,600,000 335 = Misc Power Plant Equipment MW 26 30,769 800,000 336 — Roads/Port Facility LS 2,018,000 Subtotal Production Plant $37,319,000 TRANSMISSION PLANT 352/ Substation (138/12.5 kV) HS 4,223,000 353 355/138 kV Switchyard LES 567,000 356 358 138 kV Submarine Cable w/2 End Sta MI 4.5 1,057,111 4,757,000 Subtotal Transmission Plant $ 9,547,000 Subtotal Production and Transmission Plant $46,866,000 63/69 Indirect Construction Cost Labor Camp/Food Service 4,622,000 Mobil ization/Dembi1 ization 1,966,000 Subtotal Indirect Costs “$6,588,000 eee $53,454,000 tingency @ 15% 8,016,000 Subtotal Yor.470,000 71 Engineering & Administration @ 17% 10,450,000 TOTAL PROJECT COST (w/o IDC) $71,920,000 3-25 Advantages oO 0072C Low installed cost. The installed capacity cost of this project is $2,766/kW, a value which is relatively attractive. The low cost is primarily a result of the fact that the Lake Dorothy project is a lake tap project (not requiring construction of a dam) and the fact that it is relatively close to existing transmission facilities. Very high head project (greater than 2,000 feet). This project would be the highest head project in Alaska. Further, because of the steepness of the terrain in the area, it can be developed with a relatively short tunnel. Large storage capacity. In relation to annual inflow, the Lake Dorothy project offers a very large reservoir. This high degree of flow regulation makes the project particularly valuable for meeting winter energy requirements. Peaking potential. Due to its substantial flow regulation capability, the project offers the opportunity for installing and effectively utilizing additional capacity for peaking operation. This aspect should be the subject of further evaluation. The total length of the transmission facilities required (a submarine cable across Taku Inlet) is only 4-1/2 miles. This is a very short interconnection distance, given the size and potential of the project. An additional nine miles of overhead line to Thane substation would result in a project completely independent of the Snettisham system. Proximity to Juneau as compared with other projects south of Taku Inlet. This project is the closest to the load centers of Juneau of those hydro projects south of Taku Inlet. This proximity helps reduce line losses and the risk associated with transmission line problems. Studies have been conducted. There have been a number of studies of the Lake Dorothy project including a prefeasibility study, stream gaging, and some geotechnical investigations. Studies for this project date back to the 1940s. Environmental impacts for this project should be limited, as fishery concerns related to this high elevation lake are limited, and because of the fact that no clearing or new dam construction is required. 3-26 Disadvantages ° Proposed powerhouse location is an area of extreme weather on a steep hillside. The location of the proposed powerhouse west of Lake Dorothy is in an area which experiences extreme winds and other inclement weather. In addition, there is only a limited topographic area suitable for use as a powerhouse site. Construction activity associated with developing the powerhouse could be costly, thereby affecting overall project cost. Consideration should be given in future detailed evaluations of this project to locating the powerhouse underground. ° Currently in undeveloped area. The Lake Dorothy project, located several miles away from the Snettisham project, would require development of additional site support facilities and mobilization for construction in an area which has previously experienced no work activity. The development of such new sites can be costly. 3.2.3 Sweetheart Lake Project The Sweetheart Lake project would involve construction of a concrete arch dam and an 11-foot diameter tunnel approximately 9,000 feet long. The tunnel would connect with a 2,000-foot long penstock leading to the powerhouse. The powerhouse itself would house two 13 MW units whose energy output would be connected to the existing transmission system at the Snettisham project by a six mile long submarine cable. Average annual energy production is estimated at 125 GWh. The project, located about 40 miles southeast of Juneau, is shown on Figure 3-2. A more detailed plan and profile drawings of the project are shown in Figures 3-6 and 3-7. Previous Studies: Previous studies undertaken on the Sweetheart Lake project were reported in many of the same documents that were reviewed for work on the Lake Dorothy project. On the Sweetheart Lake project, cost estimates and other general project information used in this planning evaluation were taken from the Haines-Skagway Region Feasibility Study, Volume 4, Supplemental Investigations, prepared by R. W. Beck (Beck 1983). Updating Activities: As with other projects involving the excavation of a tunnel, the reconnaissance level construction cost estimate for the Sweetheart Lake project was changed to reflect an 11-foot tunnel diameter instead of 9 feet, as seen in the previous studies. Related quantities in the cost estimate (e.g. steel lining, excavation quantities, concrete 0072C 3-27 82-€ \ 138-Kv ac submarine YO transmission line ~ ® (see insert) - - aor N x &® Gilbert Bay ® Powerhouse 2-13 MW units 138/12.5-kV substation Port facilities Access road Power tunnel 11’Dia nominally ~~ Surge shaft unlined) Pl SS See ae | \ (FEES | o ; | Lsveeineart © | [ Reservoir \ \ / / Normal maximum | / W.S. El. 684 7 / a \ 4 Construction 4 staging area / i NOTE , Topography is based on 2000 USGS | : 63,360 scale mapping LEGEND ——— Access road —heW— Existing 138-kVac overhead transmission line —He~ Existing 138-kVac submarine transmission line -#- Proposed 138-kVac submarine transmission line 0 Switchyard 4a Proposed substation A Existing substation TRANSMISSION SYSTEM 5 Thane Substation DOROTHY PROJECT, Q Proposed 138 - kVac submarine crossing 9 SNETTISHAM PRO, Existing 138-kV Snettisham Transmission Line 138 - kV switchyard 138/12. 5-kV substation SWEETHEART ® LAKE PROJECT Proposed 138 -kVac submarine & transmission JUNEAU AREA 20 YEAR POWER SUPPLY PLAN SWEETHEART LAKE PLAN DATE NOV 1984 EBASCO SERVICES INCORPORATED FIGURE 3-6 bene ELEVATION, FEET (X 1000) ELEVATION, FEET (X 1000) Loke Dorothy, E\.2422 Sta. 0+00 Gate shaft Sto. 3+80 Taku inlet 10' excovated Dio. ki 1 E1.2240 Intake tunne! Stort of lined portion Sta. 120+00 _ Sta. 141+80 Concrete lined section " jortial steel lining) 7 excavated Dio. drop shoft ie s Powerhouse 2-13MW units 4 4 4 a 4 4 i abv 10+00 20+00 30+00 40+00 50+00 60+00 70+00 80+00 90+00 100+00 10+00 120+00 130+00 140+00 STATION PROFILE - LAKE DOROTHY PROJECT (ALTERNATIVE 1) NOTE Topography is based on USGS 1:63,360 Scale mapping. Sweetheart Reservoir E1.684 - Intake Sta.0+00 Start of steel lining Sta. 90+80 Portal structure Sta.91+00 Sta.106+50 Surge shaft Sta.76+50 Powerhouse 2-13MW units 11’ Dio. nominally unlined tunnel (machined bored) S=.0088 78" Dia surface penstock 1 4 4 4 4 4 . 4 rn a 0+00 10+00 20+00 30+00 40+00 50+00 60+00 70+00 80+00 90+00 100+00 STATION PROFILE- SWEETHEART LAKE PROJECT JUNEAU AREA 20 YEAR POWER SUPPLY PLAN LAKE DOROTHY and SWEETHEART LAKE PROJECT PROFILES DATE NOV 1984 | FIGURE 3-7 EBASCO SERVICES INCORPORATED quantities, and support steel) were also adjusted to be consistent with the revised tunnel diameter. The cost estimate is presented in Table 3-8. Summary of Important Findings: The economic parameters for this project are presented in Table 3-5 while the significant data for this hydro project are tabulated in Appendix 7.1. Advantages and disadvantages of this project are presented below. Advantages 0 Large drainage area and more available storage. This project, which would involve construction of a dam and development of a reservoir, would capture the flow of a relatively large drainage area, thereby providing considerable storage for seasonal flow regulation and energy production. Disadvantages Oo 0072C This project is a relatively low head project thereby requiring greater flows to yield the same amount of energy as comparably sized high head projects. Located in an undeveloped area further away from Juneau than Snettisham project. The Sweetheart Lake project is located south of the existing Snettisham project, further removed from the Juneau area load centers. The remote nature of the area will increase construction mobilization costs and will require additional transmission facilities to connect with the existing 138 kV system at Snettisham. Requires access road construction. Mobilization difficulties will be increased by the fact that a new, permanent access road would need to be constructed to the dam site. This compares with lake tap projects where such a road can often be avoided. Longer construction period. The need for access to the relatively remote site, together with the need to construct a dam, lengthen the construction period for the project. This can affect project financing costs and other difficulties which may arise from delays in project development. High cost. The installed cost per kW would be $4,035, and the total capital cost of the project would be $104,900,000. These are high compared to some other available projects. 3-30 TABLE 3-8 CONSTRUCTION COST EST IMATE RECONNAISSANCE LEVEL SWEETHEART LAKE HYDRO PROJECT (26 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not Included 331 Powerhouse Str & Imp $6,283,000 332 Reservoirs, Dams, Waterways Concrete Arch Dam cy 25,000 442.25 11,051,000 Other Dam-Related Work LS 4,309,000 Tunnel Excavation (11' dia) LF 9,100 1 8,382,000 Tunnel Supports & Lining (11' dia) LF 4,500 1,405 6,324,000 Penstock (78" dia) LF 2,550 774 1,974,000 Surge Tank LS 2,040,000 Intake LS 1,645,000 333. Waterwheels, Turbines, Gens MW 26 250,000 6,500,000 334 ~=— Accessory Electrical MW 26 61 ,538 1,600,000 335. Misc Power Plant Equip MW 26 30,769 800,000 336 = Roads, Port Facility LS 1,028,000 Subtotal Production Plant $51 936,000 TRANSMISSION PLANT nd Substation LS 5,605,000 358 138 Submarine Cable (w/end Sta) MI 9 1,057,666 9,514,000 Subtotal Transnission Plant $15,119,000 Subtotal Power and Transmission 329, 63/69 Indirect Costs Labor Camp/Food Service [ES 8,224,000 Mobil ization/Dembi1 ization Ls 3,357,000 Subtotal Indirects “$17,587,000 Subtotal $78,636 ,000 Contingency @ 15% ES 11,794,000 Subtotal JO,7H,000 71 Engineering & Administration @ 16% 14,470,000 TOTAL PROJECT COST (w/o IDC) $104,900,000 70568 3-31 ° Environmental impacts would be significant. Because the project would be located in a previously undeveloped area, it would require the construction of an access road, affect flows in areas where fish reside, and lead to the development of a relatively large reservoir. Environmental impacts could be of concern. 3.2.4 Thomas Bay Project The Thomas Bay Project is located over 100 miles south of Juneau in an undeveloped area of southeast Alaska. The project would involve a lake tap with a head potential of approximately 1500 feet and would involve the excavation of a 12,700-foot long, 11-foot diameter tunnel. It would have considerable seasonal storage and a total installed capacity of 45 MW, providing an estimated 200 GWh average annual energy. The project would be interconnected with the existing 138 kV transmission facilities by a 110 mile long, 100 kV DC line. The general location of the project is shown on Figure 3-1 while plan and profile views of the project are shown in Figures 3-8 and 3-9. Previous Studies: There has been a long history of interest in the development of the Thomas Bay project. Inventory studies of hydro sites in southeast Alaska have been occurring for some time and the Thomas Bay project studies date back to the mid-1940s when the Federal Power Commission and U.S. Forest Service prepared the report entitled “Water Powers in Southeast Alaska." More recent specific studies dealing with the Thomas Bay project include the R.W. Beck (1984) report entitled, "Future Hydro Power Resources, Ketchikan, Petersburg, Wrangell, and Quartz Hill." Currently, studies of the project are being undertaken by Hosey & Associates Engineering Company. These studies are being supported by the City of Petersburg who filed a FERC preliminary permit application for the project development. Because the Hosey studies are currently underway, and not yet finalized, they were not available for this report. The R.W. Beck (1984) study mentioned above was the primary source for cost data on the project. Updating Activities: Previous studies on the Thomas Bay project were reviewed and updated based on current technology and Ebasco cost estimating experience. Updating activities included review of the previous material and consultation with Hosey and Associates Engineering Company. Consultation with that organization, however, revealed that no final engineering studies were available. Therefore, as noted above, the R. W. Beck report (1984) was used. As with all other generation alternatives, cost estimates were escalated using industry accepted practices. In the case of the project transmission line, a general routing was identified as a part of the present Ebasco studies and cost information provided in the Teshmont Report (1982) entitled, "Southeast Alaska Intertie DC Transmission System" was used. 0072C 3-32 c < Ww > So N < Ww c < > < Ww z2 = = POWER SUPPLY PLAN ve-€ _-Swan Lake Normal maximum WS. EL. 1515 / 10D gate shaft 11°10. unlined / power tunnel —— —— cake Tap invert El. 1339 Matchline A NOTE ‘ Profile developed from USGS Quadrangle : 7 power tunnel Sumdum (A-3) Alaska. € = = . 60 2 BenstSek 1 1 1000" ° 1000' a | Powerhouse Scale - Thomas Bay / Tailwater El. 30.0 (MLLW) ee | JUNEAU AREA 20 YEAR POWER SUPPLY PLAN THOMAS BAY PROJECT PROFILE DATE NOV 1984 | FIGURE 3-9 EBASCO SERVICES INCORPORATED | The project features were also reviewed and it was determined that the Thomas Bay project when considered in this planning exercise should include three rather than two units. Earlier work on the project had suggested that it would be more appropriate to install only two units at present and allow for the installation of the third unit in the future. Summary of Important Findings: In general, the Thomas Bay project is located in an area that is ideally suited for hydroelectric development. The flow volume, head, and storage capabilities of the proposed project are all favorable for the economic development of a hydroelectric project. Two major interrelated obstacles, however, remain which will make it difficult to develop the project in the near term. First, the location of the project, so far from any major load centers, requires the development of a long and costly transmission interconnection. In the case of interconnection with Juneau, the transmission line represents approximately 42 percent of the overall estimated cost. The second major obstacle is the fact that the project will have a relatively large capacity of 45 MW. Loads must be substantial in order to support the capital for constructing this project. These factors work against the use of the Thomas Bay project to meet the future power requirements of Juneau, unless it is developed as a regional project with interconnection to additional markets. Specific information about the economic parameters associated with the project are presented in Table 3-5. While significant data on the project is presented in Appendix 7.1, the cost estimate summary table is presented in Table 3-9. The major advantages and disadvantages of the Thomas Bay project are summarized below. Advantages 0 Lake tap project, no dam required. The setting of the proposed project is ideal for a hydroelectric project involving a lake tap. This project has virtually all of the advantages of a lake tap project as discussed earlier. 0 Low installed cost per kilowatt. The installed capacity cost of the project is relatively low. The cost of $2,702 per kW compares favorably with other hydroelectric projects despite its substantial transmission costs. 0 Large storage area. The Thomas Bay project would be capable of storing large quantities of water and would include seasonal storage. ° High head (1500 feet). 0072C 3-35 TABLE 3-9 OONSTRUCT ION QOST EST IMATE REOONNATSSANCE LEVEL THOMAS BAY HYDRO PROJECT (44 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not included 331 Power Plant Structures MW 45 155,555 $7 ,000 ,000 332 Reservoirs, Dams, Waterways Lake Tap & Trashrack LS 1,993,000 Intake Gates & Appurt. Ls 2,679,000 Penstock (5' dia.) uF 2,000 875.50 1,751,000 Power Tunnel (11' dia) LF 12,700 1627 20,664 ,000 333 Waterwheels, Turbines, Mi 45 306,700 13,800,000 Gens (3 @ 15 MW) 34% Accessory Electrical Mw 45 44,444 2,000,000 335 Misc Power Plant Equip. MW 45 22,222 7,000,000 336 Roads (Permanent) MI 0.5 486,000 243,000 Mitigation Ls 653,000 Subtotal Production Plant $51,783,000 TRANSMISSION PLANT 352 Substation/Comunication LS 3,515,000 353. Converter Stations(49¥W) EA 2 6,750,000 13,500,000 358 100 kV DC Cable MI 110 190,000 20,900,000 (1 Conductor/1 Core) Subtotal Transmission Plant $87,915,000 60/69 Indirect Costs Ls 3,860,000 Subtotal Production & Transmission Plant 93,558,000 Contingency @ 15% 14,032,000 Subtotal $107,590,000 71 Engineering and Administration @ 15% 13,990,0900 TOTAL PROJECT COST (w/o IDC) $121 580,000 3-36 70568 ° Development of the project would hasten establishment of a southeast Alaska transmission grid. Construction of a transmission line from the Thomas Bay project to Juneau would be a major step in the development of such a transmission grid. Construction of this 110-mile segment would leave only a relatively short remaining distance to the existing Tyee Lake system for completion of a grid from the Juneau area south through Petersburg and Wrangell to the Tyee Lake project. Development of an interconnected system would have Many advantages, as discussed earlier. Disadvantages ° The Thomas Bay project is located in an undeveloped area over 100 miles south of Juneau. Logging, sand, and gravel operations have previously occurred in the general vicinity. Mobilizing construction along the transmission line route would be costly. ° Very long transmission line required. The installation of a 110 mile 100 kV DC submarine cable is costly and affects the overall economic viability of the Thomas Bay project. The transmission requirements associated with the Thomas Bay project are the single largest detriment to the project's successful development. ° High capital cost. The Thomas Bay project, although having a favorable installed cost per kW, has a high total cost which will make financing difficult. ° Uncertainty surrounding cost estimate. A cost estimate for the Thomas Bay project is highly uncertain. The lack of detailed feasibility level engineering together with the uncertainties surrounding the cost of a DC submarine cable make it difficult to develop an accurate cost estimate for this project. This uncertainty must be reflected in all deliberations related to the project. 3.2.5 Speel River This project would involve the construction of two dams. The larger structure would be located at the northeast end of the project on the Speel River and would be a concrete arch dam. At the southwest end of the proposed reservoir a smaller earth and rockfill dam would be installed to ensure that the water backed up from the dam at the northeast end of the reservoir would not spill south down the Speel Arm drainage. The earth and rockfill dam would be located at the south end of Indian Lake. The powerhouse would be located near the earth and rockfill dam and would consist of two Francis turbines with a combined capacity of 57 MW. The project would have a head of approximately 300 0072C 3-37 feet. As envisioned, the project would impound a large amount of water and would capture the flows from a relatively large drainage area. The project would have the largest flows of any regional hydro project under consideration. The Speel River project is close to the existing Snettisham project and would require approximately 1.5 miles of 138 kV transmission line to interconnect with the existing transmission system near the Snettisham project. The general location of the project is shown on Figure 3-2 while a more detailed plan map is shown in Figure 3-10. As noted above, the project is located near the existing Snettisham project which is approximately 30 air miles southeast of Juneau. Previous Studies: There have been relatively few studies of the Speel River project. Early studies were conducted by the Bureau of Reclamation in the 1960s. Other limited studies were undertaken by the Alaska Power Administration and information available from the Power Administration files was used in the present analysis. Updating Activities: Because of the limited amount of previous study, some of the basic input needed to evaluate this project was developed during the course of the generation planning studies being undertaken on the Juneau Area 20-Year Power Supply Plan. These updating studies included verification of the hydrological assumptions and hydraulics used in previous analysis. This verification was accomplished by reviewing flow records and hydraulic sizing of project features compared with information prepared by the Bureau of Reclamation. It was also necessary to estimate the cross sectional area of the earth and rockfill dam near Indian Lake and assume its height in order to calculate the approximate quantities of material required for the project. From this and other basic quantity information, parametric cost curves were used to determine the costs of the dam, intake structure, powerhouse, clearing, and other project features. Representative costs for 1984 were used in developing the overall cost estimate, which appears on Table 3-10. A review was also conducted to determine whether the existing Snettisham transmission line would accommodate the additional Speel River project load. Summary of Findings: The Speel River project offers opportunity to capture high flows and proximity to the existing Snettisham development. Much of the project development, however, would occur in an old existing river channel where subsurface conditions are often difficult to predict. Such 0072C 3-38 CONCRETE ; ARCH DAM Vf Height - 220 FT. yy S | SS RESERVOIR Ly EL. 325 FT. mia) Rapids Rapeaae’ ; jones \) 16 FT. pia. ik - O42 4 2 Sas 4 Aes ov pd JUNEAU AREA 20 YEAR ‘SCALE - MILES LA Te PANTO en POWER SUPPLY PLAN Ra \\ , Y tad. Man | \57.1 MW POWERHOUSE WS) VE 138 kV of \ ; i \ _ TRANSMISSION LINE ci SPEEL RIVER PLAN Sree a vs ( iS Latog “| fo ; \~ , $ ar a fee ‘ Sta x r EBASCO SERVICES INCORPORATED TABLE 3-10 CONSTRUCTION QOST EST IMATE RECONNAISSANCE LEVEL SPEEL RIVER HYDRO PROJECT (57.1 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not Included 331 Powerhouse Str & Imp MW §7.1 175,009 $9,993,000 332 Reservoirs, Dams, Waterways Arch Dam cy 53,400 442.25 23,616,000 Other Dam Costs LS 3,708,000 Diversion & Care of Water LS 1,460,000 Rockfill Dike CY. 507,400 7.50 3,806,000 Other Dike Costs Ls 2,268,000 Reservoir Clearing AC 750 3,433 2,575,000 Intake LS 1,480,000 Tunnel Excavation (unl ined 16' dia x 3,200') cy 23,800 330.40 7,864,000 Surge Shaft (60' x 120') cy 22,000 399.82 8,796,000 14' Diameter Penstock LF 300 7,603 2,281,000 333. + Waterwheels, Turbines, Gens MW 57.1 402,800 23,000,000 33% = Accessory Electrical MW 57.1 45,009 2,570,000 335 = Misc Power Plant Equip MW Sie 25,009 1,428,000 336 ~—- Roads MI 9 600,000 5,400,000 Subtotal Production Plant $100,245,000 TRANSMISSION PLANT 3527 Switchyard LS 2,165,000 353 355/138 kV Transmission Line MI 1.5 370,000 555,000 356 Subtotal Transmission Plant $ 2,720,000 Subtotal Power and Transmission $102,065.00 63/69 Indirect Costs Labor Camp/Food Service MD 115,000 75 8,625,000 Mobil ization/Demobi1 ization Ls 4,000,000 Subtotal Indirects $ 12,625,000 Subtotal $115,590,000 Contingency @ 30% LS 34,677,000 Subtotal 3150,767,000 71 Engineering & Administration @ 13% 19,535,000 TOTAL PROJECT COST (w/o IDC) $169,802 ,000 3-40 considerations can greatly increase costs of subsurface and foundation treatment for dam, water conductor, and powerhouse structures. The higher contingency factor used in estimating the cost of this project (30%) reflects these uncertain conditions. A summary of the economic parameters for this project are presented in Table 3-5. Significant data on this project are presented in Appendix 7.1. The major advantages and disadvantages associated with development of the Speel River project are summarized next. Advantages ° Proximity to existing Snettisham project. Because the Speel River project is within 1-1/2 miles of the existing Snettisham development, certain cost advantages accrue. First, a relatively short, 1.5 miles, segment of transmission line is needed to interconnect the Speel River project with the Snettisham project. Second, mobilization for construction would be easier for this project as mobilization experience at the Long Lake and Crater Lake projects will be directly applicable to the Speel River project. Finally, depending on project layout and operation and maintenance plans, it may be possible to realize some efficiencies during operation of the project because the Speel River project would be located near the Snettisham project. Disadvantages ° High total project costs. Because the project requires construction of two dams and is relatively large (57 MW), its total costs are high. ° The lack of previous study on this project limits the confidence in the cost estimate developed and in generally constructing the project as identified. The lack of geotechnical data is especially critical because the proposed concrete arch structure location, in an old river channel, is potentially a major factor which would affect technical and economic development of this project. ° Construction of two separate dams. Along with increasing the overall project costs, the fact that this project involves construction of two dams is of concern because there are added difficulties associated with mobilizing construction at two project sites which are not currently connected by a road. Thus, mobilization requirements would be greater for this project than many of the others considered because this project actually consists of two separate projects. Further, additional operation and maintenance expense could be expected because operation and maintenance activities cannot be fully shared between the two facilities. 0072C ° Project located south of Taku Inlet. As discussed previously, projects located south of Taku Inlet involve transmission interconnection with an existing 138 kV transmission line. The capacity available from projects south of Taku Inlet is considered less desirable from a system planning standpoint than the capacity provided by projects which are completely independent of the Snettisham system. 0 Environmental impacts. The construction of two dams, the inundation of a relatively large area by the proposed project reservoir, and the presence of fish and wildlife in the relatively low elevation habitat adjacent to the project suggests that the Speel River project would have potentially serious environmental impacts. ° Limited storage in relation to inflow. Flow regulation is not adequate to allow full utilization of available energy potential. 3.2.6 Nugget Creek This small hydroelectric project would be located in the same area as the existing remnant dam structure along Nugget Creek. The proposed project would involve development of a 100-foot high concrete faced rockfill dam. It would have a much larger reservoir than the abandoned project. The project would include an 800-foot long tunnel, 1/4 mile of 4.5 feet diameter penstock, a two unit (5.4 MW each) powerhouse, and two miles of 23 kV wood pole transmission line. Average annual energy production would be approximately 22 GWh. The project would store runoff from a relatively small drainage area fed by glacier melt, but the amount of storage would be very limited (about 10 percent of average annual inflow). Nugget Creek, a tributary to the Mendenhall River, is approximately 14.5 miles northwest of Juneau and is located within the Mendenhall] National Recreation Area. Maps showing the general location of the project are shown in Figure 3-2 and 3-3, while a more detailed project layout appears in Figure 3-11. Previous Studies: The Nugget Creek project was initially constructed in 1914 and included a 27-foot high timber crib dam, tunnel, flume, and wood stave pipe. The old powerhouse, part of which remains today, contained two units. The project was operated for a number of years but little information remains regarding its operation. Data on this project is available in the Preliminary Report on Economic Feasibility of Electrical Utility System Development prepared by Bechtel (1959). Information on this project is also contained in a Bureau of Reclamation study completed in 1964. Another source used in the investigations of this project is an undated report prepared by Galloway and Markwart Engineers. 0072C 3-42 | Strotter White NATIQNAL 32 { CONCRETE FACED ROCKFILL DAM\—= ~ Z Mendenhall AN Lake 10.8 MW q-~ as ‘ POWERHOUSE '| x val vf ® FT. DIA. JUNEAU AREA 20 YEAR POWER SUPPLY PLAN NUGGET CREEK PLAN DATE NOV 1984 | FIGURE 3-11 EBASCO SERVICES INCORPORATED Updating Activities: The Bureau of Reclamation study provided basic information. Using this information and Ebasco experience on similar southeast Alaska hydro project developments, construction quantities for the dam, penstock, and other features were determined. Because of the lack of information, there was a need to price project components using quantity take-offs and parametric cost curves. Such estimates were developed by examining the cost estimate for the West Creek project near Skagway, which is similar in some respects to the Nugget Creek project. Bureau of Reclamation calculations were used for estimating firm energy. Summary of Important Findings: The Nugget Creek project is relativeiy small and close to the Juneau area load centers. Because of the limited amount of previous study on the old abandoned hydroelectric project, only rough reconnaissance level information could be developed. The major economic parameters for the project are shown in Table 3-5 while the cost estimate is presented in Table 3-11. Significant data on the project is presented in Appendix 7.1. The major advantages and disadvantages of the project are summarized below. Advantages ° Proximity to Juneau. The proposed project would be located near the Mendenhall Glacier relatively close to the Juneau load centers, and would be independent of the Snettisham transmission system. ° Short transmission line required. It is envisioned that only two miles of transmission line would be required to interconnect this project with the existing system. It is expected that this line would be 23 kV and would be fully compatible with the existing 23 kV system in the Juneau area. Disadvantages 0 Environmental concerns. The proposed project would be located in the Mendenhall National Recreation Area. That area is of naLional significance and recognized for its pristine and scenic quality. The development of a project within such an area would create environmental concerns and might preclude development. The proposed powerhouse would be located on the shore of Mendenhall Lake between the Visitors' Center and the glacier. 0072¢ 3-44 TABLE 3-11 CONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL NUGGET CREEK HYDRO PROJECT (10.8 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not Included 331 Powerhouse Str & Imp MW 10.8 235,000 $2,538,000 332 Reservoirs, Dams, Waterways Rockfill Dam cy 230,000 10 2,300,000 Other Dam-Related Work Ls 1,000,000 Diversion & Care of Water LS 1,339,000 Reservoir Clearing AC 243 3,433 834,000 Spillway LS 1,400,000 Tunnel Excavation (8' H.S.) CY. 1,700 352 598,000 Surge Shaft cy 230 352 81,000 Penstock (4.5' dia) LF 1,570 700 1,099,000 333 Waterwheels, Turbines, Gens MW 10.8 300,000 3,240,000 334 Accessory Electrical MW 10.8 74,074 800,000 335 Misc Power Plant Equip MW 10.8 46,296 500,000 Subtotal Production Plant $15,729,000 TRANSMISSION PLANT 392/ Switchyard Ls 335,000 353 355/23 kV Transmission Line MI Z 116,000 232,000 356 Subtotal Transmission Plant $567,000 69 Indirect Const Cost (MOB/DEMOB ) (Labor Camp not required) Ls 2,000,000 Subtotal Power and Transmission $18,296,000 Contingency @ 15% Ls 2,744,000 Subtotal $21,040,000 71 Engineering & Administration @ 18% 3,790,000 TOTAL PROJECT COST (w/o IDC) $24,830 ,000 7ud66 3-45 ° High installed cost. The project has an installed cost of $4,642 per kilowatt. This is higher than many of the other alternatives and reflects the fact that the project is relatively small in size. 0 Project reservoir would fill with sediment relatively quickly. Nugget Creek is a glacially fed stream which, like other glacial streams, transports relatively high volumes of sediment. This material would gradually fill in the reservoir and over time, would require a revision to the project operation or periodic sluicing of the reservoir. ° Lack of engineering and geotechnical data. The Nugget Creek project has received only limited study, and cost estimates developed for it are not as accurate as other presented in this 20 year power plan. The concern is particularly strong for the lack of geotechnical investigations. Surface and subsurface investigations must be undertaken before a dam could be constructed in this glacially carved stream valley. ° In relation to annual inflow, the project's storage capacity is limited, thus adversely affecting the project's ability to regulate flows for winter generation. 3.3 UPGRADING EXISTING HYDROELECTRIC PROJECTS Currently, four hydroelectric projects serve the Juneau area. Of these four, three were constructed in the early 1900s. These projects, Gold Creek, Salmon Creek, and Annex Creek, require careful evaluation as technological advances made since the early 1900s suggest that improved power output could be achieved at relatively low cost by upgrading these facilities. In addition, there are opportunities to increase the output of the Snettisham project by raising the height of the dam on Long Lake. These rehabilitation and expansion options are evaluated in this section. There are two basic types of upgrading activities contemplated for the Juneau area. First, it would be possible to modify a facility's mechanical and electrical equipment and install new higher efficiency turbines and generators to obtain better yields from current flows. Second, it would be possible to increase dam heights or make other modifications which would increase the storage or otherwise raise the energy output of existing facilities. The four existing hydroelectric projects were analyzed from this perspective and alternative upgrading schemes are presented below. Table 3-12 presents a summary of the economic parameters developed for those three projects that merit further consideration. 0072¢ 3-46 EXHYDPRJ OCTOBER 16, 1984 TABLE 3-12 ECONOMIC PARAMETERS SUMMARY FOR UPGRADING EXISTING HYDROELECTRIC PROJECTS* LONG LAKE PROJECT NAME SALMON CREEK ANNEX CREEK (SNETTISHAM) MODIFICATIONS NO. OF UNITS 1 1 NONE SIZE OF UNITS (MW) 28 29 NIA CAPITAL COST ($) 7400000 2770000 43000000 CAPACITY (MW) 28 29 NONE TRANSMISSION LOSSES PERCENT 0.00 38.60 NIA MW 0.00 1.12 NIA NET CAPACITY (MW) 2.80 1.78 NIA ENERGY GENERATION FIRM (GWh) 1.20 50.00 SECONDARY (GWh) 12.00 3.48 0.00 TOTAL AVERAGE ANNUAL (GWh) 12.00 4.68 50.00 TRANSMISSION LOSSES PERCENT 0.00 34.00 2.40 GWh 0.00 1.59 1.20 NET AVERAGE ANNUAL ENERGY (GWh) 12.00 3.09 48.80 FUEL USE NONE NONE NONE HEAT RATE NIA NIA NIA OPERATION & MAINTENANCE ($/YEAR) 60000 100000 0 CONSTRUCTION DURATION (MONTHS) 6 8 24 CONSTRUCTION CASH FLOW YEAR 1 ($) 7400000 2770000 21500000 YEAR 2 ($) 21500000 YEAR 3 ($) ECONOMIC LIFE (YEARS) 50 50 50 RELATIVE COST CAPACITY ($/KW) 2643 955 NIA ENERGY (CENTS/KWh DELIVERED) 3.13 7.06 3.67 *Data shown is for the increment only. 3.3.1 Gold Creek The Gold Creek project, constructed in 1914, is a run of the river project with no storage capacity. The diversion dam is located just east of downtown Juneau and is readily accessible by vehicle. Because it is a run of the river project, it does not produce any firm energy, and frequently during the winter, it does not produce any power. For this reason, the project offers little potential in itself to meet some of Juneau's long term needs. Because of the fact that the Gold Creek project is a run of the river project, investigations focused on increasing the efficiency of the existing units to possibly produce additional energy at certain times of the year. As indicated above, the project dam is located close to downtown Juneau as shown on Figure 3-3. Previous Studies The primary source of information on the Gold Creek project are the two Bechtel reports, one prepared in 1959, the other in 1966. These reports provide information on the Gold Creek project, including limited information on its design, and other information on its operation. Updating Activities Because this project did not offer any opportunity to increase firm encrgy output, studies undertaken focused on the efficiency of the existing system and whether the drainage area was being optimally utilized. To accomplish this evaluation, hydrologic data was examined including information on the flows in the drainage and the head of the project. Efforts were made to match the capacity and operation schedule with the existing hydrologic data. Unfortunately, output and efficiency information was not available to complete the evaluation. In general, it was concluded that the project, which had been upgraded in 1950, should not be expanded unless a detailed performance study reveals an economic rehabilitation of the existing units would improve the energy output. Project data is summarized in Appendix 7.1. Summary of Important Findings Because there is no storage capacity, and because the existing project is sized appropriately, there are no improvements which could be made to the Gold Creek project which would markedly improve its operation and contribution to the generation resources of the Juneau area. The 6,800 MW hours of energy produced by the project seems appropriate and it appears that improvements which could have been made in the project were made in the 1950s. An overall summary of advantages and disadvantages of the Gold Creek project is presented below. 0072C 3-48 Advantages ° Close to load center. The Gold Creek project powerhouse is in downtown Juneau at the load center. Its location in this area makes it a good project which can provide energy to customers in the downtown area relatively efficiently. ° Operating pattern can be used to store water in other reservoirs. Although the Gold Creek project does not provide firm energy, its output can be used to allow other projects to store energy to more optimally operate all generation resources in the Juneau area. Thus, indirectly, the Gold Creek project can be used to help meet Juneau's winter energy needs. Disadvantages ° Very limited potential for further development. As discussed above, the Gold Creek project offers only limited or no potential for future development. ° No dependable capacity. The run of the river nature of the Gold Creek project limits the value of this project's contribution to meeting the Juneau area's power requirements. 3.3.2 Annex Creek The existing Annex Creek project was built in 1914 and 1915 and has provided power to the City of Juneau since that time. The project is located southeast of Juneau and has been studied for possible rehabilitation using newer, high efficiency turbines. The proposed rehabilitation would involve installing a new unit at the dam site to better utilize the existing flow of the project. The new unit would be added adjacent to the existing powerhouse on the west side of the existing units. The general location of the Annex Creek project is shown on Figure 3-3. A noteworthy characteristic of the project is the transmission line that links Annex Creek to Thane substation. The transmission line crosses Powerline Ridge on the east slope of Sheep Mountain, an area of heavy snowfall and high winds. Because of the harsh conditions of this area, special conductors have been utilized to facilitate winter operation of the line. During some winters, the entire conductors are under snow. Previous Studies: Two reports prepared by Bechtel (Preliminary Report on Economic Feasibility of Electrical Utility System Development for AEL&P, 1959 and Preliminary Report on Electric Utility System Development for 0072C 3-49 AEL&P, 1966) provide much background information on possible rehabilitation of the Annex Creek project. Other background information was also provided in a report by the Alaska Gastineau Company prepared in the early 1900s. Data from these reports, primarily Bechtel (1966), provided the bulk of the information on this project. Updating Activities The Bechtel Report (1966) provided the basis for studies of modification of the Annex Creek project. That study, together with a site visit and discussion with David Stone of AEL&P, provided the basic input into the analysis of adding an additional unit to the Annex Creek project. Using the basic information, it was determined that the powerhouse expansion should be located west of the existing units, and quantities were estimated for the amount of excavation, concrete, piping, and other facilities which would be needed. No investigations were made of upgrading the transmission line to provide transmission capacity for the additional generation unit to be installed. A preliminary review of this proposed powerhouse addition, as compared to the transmission line's capacity, indicated that the existing line may be adequate to handle the new generation, however, the line losses would be considerable. As mentioned earlier, the Annex Creek to Thane transmission line is of a very unconventional design in order to withstand the extremely severe weather conditions. Summary of Important Findings: The economic parameters associated with the modification of the Annex Creek project described above are presented in Table 3-12 while the cost estimate is presented in Table 3-13. Other significant data on the Annex Creek project are presented in Appendix 7.1. A summary of the advantages and disadvantages of the proposed modification is provided below. Advantages ° Modification of Annex Creek project would involve effective utilization of existing facilities. Because the dam and penstock are in place, it would be possible to add an additional unit to the project without the addition of a large number of expensive facilities. ° Additional unit would be more efficient than existing units in Annex Creek powerhouse. Technological improvements in the development of hydroelectric generation equipment has increased the efficiency of such units considerably since the early 1900s. If a new unit were to be installed at the Annex 0072C 3-50 TABLE 3-13 CONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL ANNEX CREEK HYDRO PROJECT (2.9 MW) PELTON ADDITION Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 Land Not required 331 Powerhouse Extension Bldg/Bldg Services F 3,200 100 320,000 Concrete LS 250 ,000 332 Reservoirs, Dams, Waterways Penstock LB 8,000 4 32,000 Rock Excav cy 1,000 40 40,000 (PH/Tai Trace) 333 ~~ Waterwheels, Turbines, MW 2.9 293,000 850,000 Gens . 33% Accessory Electrical MW 2.9 63,100 183,000 335 = Misc Power Plant Equip MW 2.9 25,200 73,000 Subtotal Production Plant 1,728,000 TRANSMISSION PLANT N/A 63/69 Indirect Costs Labor Camp/Food Service M+D 1,800 85 153,000 Mobil ization/Damobi1 iz. LS 180,000 Subtotal Indirect Construction Cost 333,000 Subtotal $2,061 ,000 Contingency @ 15% 309,000 Subtotal $2,370,000 Engineering & Administration @ 20% 470 ,000 TOTAL PROJECT COST (w/o IDC) $2,770,000 70568 3-51 Creek project, it would be of higher efficiency and would be able to produce more energy given the flow conditions at the project. In general, the unit would be added to capture flow currently spilled, but installation of a new unit would also result in the new unit being utilized first, when flows were lower, thereby increasing the output for a given flow as compared to the older, less efficient units. Project is located north of Taku Inlet. An additional unit added to the Annex Creek project would increase capacity north of Taku Inlet and would not involve transfer of energy over the existing transmission line to the Snettisham project. Using the transmission line to Annex Creek, as compared to the Snettisham project, reduces the risk associated with having virtually all of the generation capacity serving the Juneau area transmitted via the 138 kV Snettisham transmission line. Minimal environmental and regulatory requirements. A modification of the Annex Creek project, as envisioned, would have very few environmental impacts and would not require much in the way of additional regulatory studies as the proposed development would not substantially affect the way the project is currently operated, nor would it physically disturb the project area to any significant extent. Disadvantages ° Increasing output of Annex Creek project would result in higher losses in Annex Creek transmission line. The high resistance conductor used on the Annex Creek transmission line leads to relatively high transmission losses. These losses would become more pronounced if more energy were to be transmitted over the transmission line. Therefore, there would be additional losses on the Annex Creek transmission line if the project were developed. Many of the studies done on the Annex Creek project were conducted in the 1950s and were not at a detailed feasibility level. Therefore, there is some uncertainty as to their usefulness for decision making. Were expansion to proceed on the Annex Creek project, additional studies would be needed to clarify the cost involved and the benefits. These studies would need to consider hydrologic factors. 3.3.3 Salmon Creek The rehabilitation and modification of the existing Salmon Creek project is currently under way. A new penstock and powerhouse is being installed to obtain energy from the total project head. The Lower Salmon Creek project currently under construction involves bypassing 0072C 3-52 the upper powerhouse with a new penstock and connecting it to a new powerhouse to be installed adjacent to Glacier Highway. This project, although undertaken primarily to upgrade the existing Salmon Creek project, is also being undertaken in conjunction with the City/Borough of Juneau's water supply activities. The location of this project is shown on Figure 3-3 and three drawings of the project layout are presented in Figures 3-12, 3-13, and 3-14. The powerhouse itself is immediately adjacent to the Glacier Highway, approximately 2 miles northwest of Juneau. Previous Studies: Data on the Lower Salmon Creek project used in the planning study were obtained from two primary sources. First, Alaska Electric Light and Power Company's application to the Federal Energy Regulatory Commission for an amendment to the license application for Salmon Creek project, FERC project Number 2307, provided general information about the project. Other information was obtained from the Robert W. Retherford March 1978 report ("Final Feasibility Study of Alternatives for Rehabilitation of Salmon Creek Hydroelectric Project") and from the Bechtel reports prepared in 1959 and 1966. More current cost information will be available once construction is complete, but for the purpose of this planning study, it is appropriate to use information contained in the application for the FERC license application amendment. Updating Activities: Cost information used on this project was obtained from AEL&P and escalated as appropriate. Final cost related to the construction of the project will not be available from AEL&P for some time and, for the purposes of the planning study, it is appropriate to treat cost estimates consistently, using the same level of detail for the various alternatives. Since the Salmon Creek project is under construction and will be on line by 1985, cost and other information is only needed to complete the economic analysis, and will not affect the decisions regarding the development of Salmon Creek. Summary of Important Findings: The modifications currently being constructed for the Salmon Creek project will increase the output of that project to provide more capacity and energy than the existing facility. The project being undertaken is a logical redevelopment of the Salmon Creek drainage and is cost effective. It was appropriate to develop that project prior to other ones identified in this plan. The economic parameters on that project are included in Table 3-12, while the cost estimate is presented in Table 3-14. Significant project data are presented in Appendix 7.1. The major advantages and disadvantages of the Salmon Creck project are described below. 0072C 3-53 Mg wens v @ wie i fe wanna "et Se |CONNECT TO EXISTING PENSTOCK wif 30° Y- BRANCH, SO"CLASS 300 VALVE TO POWERHOOSE INO.2 AND INCREASER WITH 42° KLASS 300 VALVE TO 42° PEWSTOCK + \ wr we a, es me \ > & (wew) 42" WELDED STEEL PENSTOCK ~ Yy W LOWER SALMOR-CREEK POWERHOI Ns PN re ND _TAILRAGE LMON CREEK RESERVOIR Xi = im Y Y ae NS Gam DRIVE We — GRAPHIC SCALE PLAN © oe $00 a aE 3 Se eal Scat Te Roe JUNEAU AREA 20 YEAR POWER SUPPLY PLAN SALMON CREEK GENERAL MAP. DATE NOV 1984 | FIGURE 3-12 EBASCO SERVICES INCORPORATED LT A ET TT Y YJ } } l l H C er re ee eee ce JUNEAU AREA 20 YEAR POWER SUPPLY PLAN LOWER SALMON CREEK POWERHOUSE PLAN and SECTION DATE NOV 1984 [FIGURE 3-13 _| EBASCO SERVICES INCORPORATED 9S-€ TERR gm om ox \ \ \ \ \ a. \ \ itm — sae =I . x \. Hi] \ Y Y Y = 44 \ a —=—_— FH T 7 SITE_PLAN-LOWER SALMON CREEK POWERHOUSE SCALE: = 2 Ham — See, K POWER MOUSE PER Exist. FERC Ucense SITE_PLAN-RELOCATION OF seu . ow 42° ic 500) BuTTEAFLY, | VALVE RAPH A om 30 a) iene te 30 LOWER SALMON CREEK SITE PLAN and PENSTOCK MODIFICATIONS | DATE NOV 1984 [FIGURE 3-14 EBASCO SERVICES INCORPORATED a perenne TABLE 3-14 QONSTRUCTION COST ESTIMATE REQONNATSSANCE LEVEL SALMON CREEK HYDRO PROJECT (6.7 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 330 ~—_ Land LS $2,000 331 Powerhouse Str & Imp Ls 200,000 332 Reservoirs, Dams, Waterways Penstock & Valves LS 2,404,000 333. -Waterwheels, Turbines, Gens LS 1,600,000 334 = Accessory Electrical LS 100,000 335 ~~ Misc Power Plant Equip LS 40,000 336 ~—- Roads, Railroads, Bridges Ls 1,200,000 Subtotal Production Plant $5,546,000 Contingency @ 15% LS 832,000 Subtotal 378,000 71 Engineering & Administration @ 16% 1,022,000 TOTAL PROJECT COST (w/o IDC) $7,400,000 70568 3-57 Advantages 0 Modification utilizes much of the existing facilities. The modifications under construction for the Salmon Creek project do not involve any construction associated with the dam itself. Much of the existing penstock is utilized. Therefore, overall project costs are reduced and the cost effectiveness of the modification is enhanced. 0 Large storage capacity. The Salmon Creek project has a relatively large reservoir and can provide winter storage. The project configuration being constructed enhances the ability of the project to utilize the existing flows most effectively. ° Interconnection with area transmission line. The Salmon Creek project powerhouse is located along Glacier Highway. In this location, the project will be able to tie into the existing 69 kV transmission system at a minimum cost. Further, interconnecting at this point decreases line losses and enhances overall system reliability. Disadvantages 0 Modification of Salmon Creek utilizes the old dam and portions of the existing penstock. Although such an approach is cost effective, these existing facilities are quite old and the rehabilitated project will not have as long an economic life as would have been the case if it were developed entirely using new equipment. 0 The project is relatively small because of the drainage area and hydrology. The project has only a limited potential both in terms of energy and capacity. As modified, the project basically realizes that potential. 3.3.4 Long Lake Dam, Snettisham The final authorized stage of the Snettisham Project is the construction of the Long Lake Dam. According to existing designs, the proposed concrete gravity dam would have a crest length of about 800 feet and a height of 110 feet above the lowest point of the foundation. The normal lake level will be increased by 67 feet. An ungated spillway, in two sections totaling 225 feet in width, would discharge into the existing bifurcated channel of Long River. The Long Lake Dam addition would add approximately 50,000 megawatt-hours of firm energy to Snettisham generation. 0072C 3-58 Previous Studies: Data on the Long Lake Dam comes from the Alaska District, Corps of Engineers' Snettisham Project Design Memorandum Number 13, dated January 1967, along with an updating letter from Harlan E. Moore, Engineering Division Chief of the Alaska District, dated March 1, 1984. Updating Activities: The design of the Long Lake Dam is to be reviewed by the Corps to take into consideration foundation information that became available during construction of the existing weir at Long Lake and revised stability criteria. In the absence of that review, the Corps' cost estimate of $43 million has been adopted for use. Significant project data are summarized in Appendix 7.1. Summary of Important Findings: The Long Lake Dam Project's relative economic standing is presented in Table 3-12. As an addition to an existing project, it offers environmental advantages and reduced uncertainty in estimated cost and constructibility. As an addition to a project located south of Taku Inlet, it exacerbates the lack of geographical balance in Juneau's generation resources. Offering no additional dependable capacity, the project's cost of energy is relatively high in comparison to several alternative hydroelectric alternatives. Because of changes in the value of energy and construction costs, since this project was formulated, it merits a reassessment of the economic dam height as part of a system-wide operations study. 3.4 FOSSIL FUEL THERMAL PLANTS This section addresses diesel-fueled power plants and coal-fired steam plants. The diesel-fueled power plants are examined either as sources of prime power to supplement Juneau's hydroelectric generation or as standby equipment to sustain electrical power in the event of failed hydroelectric generation or the failure of transmission facilities transmitting that power. 3.4.1 Diesel Engines Prime power generation requirements center around fuel economy, durability, low maintenance costs, and reliability. The most likely candidate for prime power generation would be a medium speed heavy-duty diesel (HDD). Two alternative size configurations have been adopted for evaluation: four 5 MW units and two 10 MW units. For standby generation, fuel economy is a much lesser concern, while low first cost, ability to start promptly, and reliably are primary considerations. Durability is of lesser importance than for prime power generation since the machine is not expected to operate many hours, and serviceability is also relatively less important. A 2500 kW 2-stroke, 20 cylinder high speed diesel (EMD) is proposed for Juneau's standby applications. 0072C 3-59 Previous Studies: Historical information from AEL&P and GHEA relating to existing diesel operating experience and generation costs have been reviewed. Upgrading: T. E. Neubauer and Associates provided recommendations on plant selection and developed purchase installation, and operating cost data. Cost estimates were derived from the analysis of two other Alaskan projects, the installation of a 7 MW medium-speed diesel in the Kodiak Electric Association power plant completed in 1981 and the construction of a 5.5 MW standby plant at Auke Bay for GHEA completed in 1983. Line item costs were reviewed and modified as necessary to reflect estimated costs for new plants at Juneau. Inflation factors were also applied to give January 1984 cost equivalents. The cost estimates for the two prime power diesel configurations and the diesel standby alternative are presented in Tables 3-15, 3-16, 3-17, and 3-18. The Neubauer report appears as Appendix 7.2. Summary of Important Findings: Key data associated with each of the three internal combustion diesel-fueled alternatives appears in Table 3-15. The advantages and disadvantages are summarized below. Advantages ° Lower capital cost. The cost per kW for these alternatives are a small fraction of the corresponding cost of hydroelectric options. This reduces financing difficulties, risk and utility debt levels or other long term obligations. It also indirectly means that the Juneau utilities can more readily finance the projects with their own resources and thereby retain full control of their generation plant. oO Ready availability. The proposed plants are commonly available, and therefore the planning and installation period is much less than would be required for a hydroelectric project. Flexibility for meeting future unknown requirements is Lhereby enhanced. ° Familiarity. Plants of this type are familiar to both Juneau utilities, thereby reducing uncertainties of installation and operation. ° Location. The plants would be installed north of Taku Inlet and therefore provide needed geographic balance to the Juneau syslem. Reserve ratios would be favorably impacted. 0072C 3-60 THERGEAL OCTOBER 16, 1984 ECONOMIC PARAMETERS FOR THERMAL GENERATION ALTERNATIVES TABLE 3-15 COMBUSTION ALTERNATIVES PRIME DIESEL PRIME DIESEL DIESELSTANDBY TURBINESTANDBY COAL FIRED MSW TYPE OF UNIT NUMBER OF UNITS 2 4 8 1 1 1 SIZE OF UNITS (MW) 10 5 25 20 30 1 CAPITAL COST ($) 12555000 16464000 9222000 11040500 109000000 10650000 CAPACITY (MW) 20 20 20 20 30 1 TRANSMISSION LOSSES PERCENT 0 0 0 0 0 0 MW 0 0 0 0 0 0 NET CAPACITY (MW) 20 20 20 20 30 1 ENERGY FIRM (GWh) 117 117 NIA NIA 210 Z SECONDARY (GWh) 0 0 NIA NIA 0 0 TOTAL (GWh) 117 117 NIA NIA 210 7 TRANSMISSION LOSSES PERCENT 0 0 NIA NIA 0 0 GWh 0 0 NIA NIA 0 0 NET AVG. AN. ENERGY (GWh) 117 117 NIA NIA 210 7 FUEL COST ($/GAL, $/TON) 0.959 0.959 0.959 0.959 43 0 FUEL ESCALATION (%/YR) 1984-1988 0 0 0 0 0 0 1989-2003 3 3 3 3 a 0 FUEL USE (kWh/GAL or TON) 15 15 13.5 9 1364 318 HEAT RATE (BTU/KWh) 11000 11000 _ 14000 11740 18825 OPERATION & MAINTENANCE CENTS/KWh 08 08 0 0 0.09 0.014 SIKW-YR 3.5 s 350 CONSTRUCTION DURATION MONTHS 12 12 6 12 18 12 CONSTRUCTION CASH FLOW YEAR 1 ($) 12555000 16466000 9222000 11040500 85000000 10650000 YEAR 2 ($) 24000000 ECONOMIC LIFE (YEARS) 20 20 20 20 40 20 CAPITAL RECOVERY FACTOR 0.070361 0.070361 0.070361 0.070361 0.04627 0.070361 RELATIVE COST CAPACITY ($/KW) 628 823 461 552 3633 10650 ENERGY (CENTS/KWh DEL.) 1984 7.95 8.18 NIA NIA 5.67 15.72 1985 7.95 8.18 NIA NIA 5.67 15.72 1986 7.95 8.18 NIA NIA 5.67 15.72 1987 7.95 8.18 NIA NIA 5.67 15.72 1988 7.95 8.18 N/A NIA 5.67 15.72 1989 8.14 8.38 NIA NIA 5.77 15.72 1990 8.34 8.57 NIA NIA 5.87 15.72 1991 8.54 8.78 NIA NIA 5.97 15.72 1992 8.75 8.99 NIA NIA 6.07 15.72 1993 8.97 9.20 NIA NIA 6.18 15.72 1994 9.19 9.42 NIA N/A 6.28 15.72 1995 9.42 9.65 NIA NIA 6.40 15.72 1996 9.65 9.89 NIA NIA 6.51 15.72 1997 9.90 10.13 NIA N/A 6.63 15.72 1998 10.15 10.38 NIA NIA 6.76 15.72 1999 10.40 10.64 NIA NIA 6.88 15.72 2000 10.67 10.91 NIA NIA 7.02 15.72 2001 10.94 11.18 NIA NIA 7.15 15.72 2002 11.23 11.46 NIA NIA 7.29 15.72 2003 11.52 11.75 NIA NIA 7.43 15.72 TABLE 3-16 OONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL, JAN 1984 PRIME POWER DIESEL, 20 MW (4-5 MW WITS) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 340 Land and Land Rights LS $250,000 341 _— Structures and Improvenents Sitework LS 160,000 Plant Building LS 220,000 Foundation LS 270,000 Interior Finish and Systems LS 320,000 Miscellaneous LS 160,000 $1,730,000 342 Fuel Holders, Producers & Acc. Diking and Containment LS 40,000 Bulk. Storage LS 260,000 Transfer System LS 16,000 Plant Distribution LS 180,000 Miscellaneous LS 50,000 ¥3~~—s~Prime Movers LS 0 344 Generators HDD Medium Speed Diesel Gen. Ls 9,520,000 Foundation LS 360,000 Generator Installation LS 700,000 Engine Installation Ls 1,600,000 $12, 180,000 345 ~~ Accessory Electrical Equipment Switchgear LS 300,000 Step-Up Transformation LS 140,000 Miscellaneous LS 20,000 Installations Ls 240,000 "$700,000 Subtotal Production Plant $14,806,000 71 Engineering & Administration Owner's Overhead (3%) 500,000 Engineering Design (4%) 520,000 Contract Administration (5%) 640,000 $1,660,000 TOTAL PROJECT COST (w/o IDC) $16,466 ,000 TABLE 3-17 OONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL, JAN 1984 PRIME POWER DIESEL, 20 MW (2-10 MW WITS) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 340 Land and Land Rights Ls $125,000 341 Structures and Improvenents Sitework Ls 50,000 Plant Building LS 160,000 Foundation LS 160,000 Interior Finish and Systems LS 240 ,000 Miscellaneous ES 120,000 342 Fuel Holders, Producers & Acc. Diking and Containment LS 20,000 Bulk Storage Ls 240 ,000 Transfer System LS 15,000 Plant Distribution LS 165,000 Miscellaneous LS 45,000 ¥3~~—s~Prrime Movers LS 0 344 Generators HDD Medium Speed Diesel Gen. LS 7,340,000 Foundation BS 240 ,000 Generator Installation LS 500,000 Engine Installation Ls 1,300,000 $9,380,000 345 Accessory Electrical Equipment Switchgear LS 200,000 Step-Up Transformation ts 120,000 Miscellaneous LS 15,000 Installations LS 220,000 "$555,000 Subtotal Production Plant $11,275,000 71 Engineering & Administration Owner's Overhead (3%) 300,000 Engineering Design (4%) 440,000 Contract Adninistration (5%) 540,000 $1,200,000 TOTAL PROJECT COST (w/o IDC) $12,555,000 Tee 3-63 TABLE 3-18 CONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL DIESEL STANDBY, 20 MW (8-2.5 MW) Code Description Unit Quantity Unit Cost Total (198 $) PRODUCTION PLANT 340 Land and Land Rights Ls $125,000 341 ~—s Structures and Improvenents Si tework LS 50,000 Plant Building LS 0 Foundation LS 0 Interior Finish and Systems LS 0 Miscellaneous LS 60,000 342 Fuel Holders, Producers & Acc. Diking and Containment LS 20,000 Bulk Storage Ls 240,000 Transfer System LS 15,000 Plant Distribution LS 165,000 Fuel Inventory LS 307,000 Miscellaneous LS 45,000 $792,000 ¥3 ~~~ Prime Movers LS 0 344 ~~ Generators High Speed Diesel or Turbine LS 5,500,000 Foundation LS 160,000 Generator Installation LS 200,000 Engine Installation LS 500,000 "$6,360,000 345 = Accessory Electrical Equipment Switchgear LS 200,000 Step-Up Transformation LS 120,000 Miscellaneous LS 15,000 Instal lations Ls 220,000 "$555,000 Subtotal Production Plant $7,942,000 71 Engineering & Administration Owner's Overhead 300,000 Engineering Design 440,000 Contract Adninistration 540,000 > > TOTAL PROJECT COST (w/o IDC) $9,222,000 70568 ° Efficiency. For standby application, fuel consumption rates are better than the alternative standby plant, a combustion turbine. ° Unit size. The scale of plant size can be better matched to system requirements as demand grows and units are retired. Disadvantages ° Higher operating costs. The advantages of lower capital costs are offset by the disadvantages of dependence on a non-renewable fuel resource. Over the life of the plant, fuel costs are the predominant cost element. These costs are subject to the influence of both general price increases (inflation) as well as relative price changes. The uncertain future fuel cost trend is the primary drawback of these alternatives in a prime power application. 0 Longer warm-up period. In a standby application, a longer warm-up period may be required before loading in comparison to combustion turbines. 3.4.2 Combustion Turbines A standby machine should be as inexpensive to install as possible, while still providing reliable start-up, ability to start cold loads, and reliable service until the primary power source is again available. A 20 MW combustion turbine has been selected for evaluation for use in a standby mode. Data Source: 1.£. Neubauer and Associates provided data on costs and operating characteristics. Recent plant acquisitions at KEA and GHEA were used as reference points. The Neubauer report appears in full as Appendix 7.2. The cost estimate is presented in Table 3-19. Summary of Important Findings: Significant data and economic parameters associated with the combustion turbine alternative are summarized in Table 3-15. The relative advantages and disadvantages in a standby application are listed next. Advantages ° Ready availability. The proposed plant is readily available and can be ordered, delivered, and installed in less than 24 months. This permits rapid response to capacity shortfalls or reserve margin maintenance. 0072C 3-65 TABLE 3-19 CONSTRUCTION COST ESTIMATE REQONNAISSANCE LEVEL, JAN 1984 COMBUSTION TURBINE, 20 MW Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 340 Land and Land Rights Ls $250,000 341s Structures and Improvenents Sitework LS 160,000 Plant Building Ls 200,000 Foundation LS 270,000 Interior Finish and Systems LS 320,000 Miscellaneous LS 160,000 $1,170,000 342 ~~ Fuel Holders, Producers & Acc. Diking and Containment Ls 40,000 Bulk Storage LS 260,000 Transfer Systen LS 16,000 Plant Distribution LS 180,000 Miscellaneous LS 50,000 JO 000 A3 «Prime Movers Ls 0 344 ~—s Generators High Speed Diesel or Turbine LS 6,400,000 Foundation LS 200,000 Generator Installation LS 700,000 Engine Installation LS 1,600,000 t 000 345 ~— Accessory Electrical Equipment Switchgear LS 300,000 Step-Up Transformation LS 140,000 Miscellaneous LS 20,000 Installations Ls 240,000 $700,000 Subtotal Production Plant $11,506,000 71 Engineering & Administration Owner's Overhead 500,000 Engineering Design (4%) 520,000 Contract Administration (5%) 640,000 $7,660,000 TOTAL PROJECT COST (w/o IDC) $13,166,000 3-66 ° Efficient in standby condition. Very little energy is required to keep the plant in a ready condition. ° Well developed technology. Combustion turbines have been successfully used in Alaska for base, peak, and standby applications and have been demonstrated to be highly reliable. Disadvantages ° Somewhat more expensive than comparable refurbished high-speed diesel option. 3.4.4 Coal-Fired Steam Plant The project envisions the use of Western Canadian coal, which would be shipped to Prince Rupert and then barged to Juneau. The estimated cost assumes adequate and appropriate siting in Juneau, totaling some 30 acres for fuel handling and storage, the power plant itself, ash handling systems and pond, and buffer zones for aesthetic protection. The coal would fuel a 270,600 1b/hr boiler. The high pressure steam would then be expanded in a turbine-generator producing the 30,000 kW. Flue gas from the coal combustion would be passed through a limestone Flue Gas Desulfurization system for S09 control, and through a fabric filter (baghouse) for particulate removal. The design would be configured to meet all air quality, water quality, solid waste disposal, and other environmental regulations. Previous Studies: The project layout, conceptual design, and cost estimate is based on a conceptual level cost estimate prepared for the Alaska Power Authority by Ebasco in 1981 for a similar sized project sited at Kodiak, Alaska. Upgrading: Project costs were updated to their January 1984 equivalent and expressed according to the FERC Account Codes. The assumed source of coal has been changed and coal costs updated. The cost estimate appears in Table 3-20. Summary of Important Findings: Key features of the coal-fired steam plant alternative are presented on Table 3-15. Advantages and disadvantages of this option are discussed below. Advantages: 0 Coal-fired steam electric generation is a mature, reliable power technology. 0072C 3-67 TABLE 3-20 OONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL 30 MW OOAL FIRED STEAM PLANT Code Description Unit Quantity Unit Cost Total (198 $) PRODUCTION PLANT 311 Structures & Improvenents LS $23,800,000 312 ~~ Boiler Plant Equipment LS 39,000,000 314 ~~ Turbogenerator Units Ls 6,700,000 315 Accessory Electric Equipment LS 9,700,000 316 — Misc. Powerplant Equipment LS 500,000 Subtotal Production Plant $79,700,000 60/69 Indirect Costs $10,100,000 Subtotal $89,800,000 Contingency @ 12% 11,200,000 Subtotal $101 ,000,000 71 Engineering and Administration @ 8% 8,000,000 TOTAL PROJECT COST (w/o IDC) $109,000,000 70568 3-68 ° Location. The plant would be located north of Taku Inlet, providing geographic balance to the Juneau system and thereby reducing reserve margin ratios. Disadvantages ° Relatively high cost. Capital costs compare unfavorably with several of the more cost effective hydroelectric project alternatives; fuel and operating costs further degrade its cost position. ° Susceptibility to price increases. A large component of the cost of generation is the cost of coal, which is exposed to inflation and relative price increases. ° Plant siting. Actually locating a suitable site in Juneau could prove difficult and time consuming. Approximately 30 acres would be required. ° A large operation and maintenance staff (approximately 35 individuals) would be required. 3.5 OTHER ENERGY SOURCES In addition to hydroelectric and fossil fuel energy sources, other less conventional sources have been considered for Juneau. To date, neither AEL&P or GHEA has any first hand experience with projects of this nalure. They include municipal solid waste-fired steam plants, wind generators, solar-electric generation, geothermal energy, tidal power, and wood-fired steam generation. 3.5.1 Municipal Solid Waste-Fired Steam Plant A municipal solid waste (MSW) to energy facility offers a potentially attractive power supply alternative in that such a facility can contribute to the electric energy needs for the area as well as solve some of the community's disposal problems. The November 1983 Solid Waste Management Study for the City and Borough of Juneau has been used as the source of resource data for this concept, while an Ebasco-developed MSW reference plant has been used as the basis of conceptual layouts and cost estimates. The estimated MSW quantity to be disposed of in Juneau in 1985 is 391 tons per week, while the amount is forecasted to rise to 588 tons per week in 2005. These quantities would support a plant capacity of between 70 and 90 tons per day. A waste to electricity facility can operate 24 hours per day, seven days per week, feeding energy into the power system. An 80-ton per day plant with 1 MW capacity is proposed for Juneau. It would have the capability to handle the maximum waste 0072C 3-69 flow from the community anticipated over the next 5 to 10 years. An 80 ton per day facility would require a 2 to 3 acre site to accommodate traffic flow and the plant facilities. The plant could be located on or near the existing landfill, which is in the same general area as the Lemon Creek Power Plant. Assuming 80 percent availability, the plant would generate 7,000 MWh annually and could be designed with provisions for future expansion should the waste flow increase substantially. The existing landfil] could be used for ash and non-burnable disposal, as well as backup storage for the facility during shut-down periods. Incinerating MSW will reduce the volume of material to be landfilled by up to 90 percent, thereby extending the useful life of the existing landfill by 5 to 8 times present projections. Given present costs for waste disposal, use of the MSW could result in a potential cost saving of approximately $20 per ton. The major components of this facility would include the building, MSW storage, burner-boiler, material handling facilities (including separators), turbine-generator, and environmental controls. Two complete and independent burner-boiler lines, five-day waste storage, and a single turbine-generator are proposed. The two burner-boiler lines would provide capacity to handle the maximum waste flow, and, during periods of low waste flow, one line could be shut down for maintenance while the other line could carry the load. The five day storage is provided to assure waste supply for the burner-boiler around the clock, seven days per week. The turbine-generator would be selected to be able to receive the maximum stream flow and operate efficiently at reduced steam flow rates. The facility would include equipment designed to meet all codes and standards, with special atlention to water quality and air quality requirements. Presently, operating plants of this type demonstrate that proven technology is available to successfully convert MSW into useful energy in an environmentally acceptable and aesthetically unobtrusive manner. The cost estimate for the proposed 80 tons per day plant is presented in Table 3-21, while pertinent economic parameters are shown in Table 3-15. While the cost per kilowatt is high for this alternative ($10,650/kW), the beneficial effect of an assumed zero cost of fuel enhances the energy cost (15.7 cents per kWh). If incineration of the wasle could be credited with saving landfill operating costs, further energy cost reductions would be realized. A figure of $20 per ton of waste saved results in unit energy costs of 9.62 cents per kWh. 3.5.2 Wind Energy Conversion System Wind energy conversion systems are commonly discussed in terms of three size categories. Key attributes such as cost, availability, dependability, and applicability for utility use all vary substantially with the size category. The 1982 report for Ebasco by Polarconsult's 0072C 3-70 TABLE 3-21 QONSTRUCTION COST ESTIMATE RECONNAISSANCE LEVEL MSW ELECTRIC PLANT (80 TON/DAY, 1 MW) Code Description Unit Quantity Unit Cost Total (1984 $) PRODUCTION PLANT 310 Land Not Included 311. Str & Improvements 1EA 2,000,000 312 Boiler, appurt. & Piping 1 LOT 3,000,000 314 —_Turbine-Gen. w/Access. Controls & Piping 1 LOT 1,500,000 315 = Accessory Electric 1 LOT 500,000 316 ~— Misc. Power Plant Equip. ] LOT 500,000 Subtotal Production Plant 7,500 ,000 TRANSMISSION PLANT 350/ Transmission Plant (Allowance) LS 250,000 359 Subtotal Production and Transmission Plant 7,750,000 69 Indirect Costs Mob/Demob 100,000 Subtotal $7 850,000 Contingency @ 15% 1,180,000 Subtotal $9,030,000 71 ~~ Engineering and Administration @ 18% 1,620,000 TOTAL PROJECT COST (w/o IDC) $10,650,000 7056B 3-71 Barkshire and Newell entitled "Evaluation of Unconventional Energy Alternatives" and the March 19, 1984 edition of "Alaska's Energy Resources" provide the basis for this discussion. Small wind generators are characterized by rotor diameters up to 15 meters (50 feet) with capacities up to 50 KW (rated at 30 mph). Wind gencralors in these sizes are the most readily available and are the most commercially developed. All of the wind generators operating in Alaska (approximately 140) are of this size category. Small machines represent a relatively poor investment to a utility. Maintenance requirements, increased cost from special metering and control equipment, potential problems from the larger number of required Machines, and the siting constraints in Juneau for a large number of small machines all tend to outweigh any advantages for utility application of small wind generators. At the other extreme are large machines having rotor diameters greater than 75 meters (250 feet) and rated capacities between 1,000 and 5,000 kW. The multi-million dollar capital cost and their experimental nalure preclude consideration of large wind generators for Juneau. Medium sized turbines (25-75 meters rotor diameter and 50-1,000 kW raled capacity) offer the most attraction from a utility standpoint. Over 10,000 hours have been logged on machines in the 200 kW size supplying power to remote diesel grids. However, no medium size units are operating in Alaska, and there are only a handful of manufacturers presenlly building machines of this size. Most of the medium size wind turbines employ a constant speed synchronous generator and their output is monitored by a microprocessor to maintain utility tolerances. On most machines intertied to utilities, controls are built into the design so that the wind generator will not produce power when the utility power is off. Storage of excess power is economically infeasible due to the lack of available storage technologies. The placement and evaluation of wind generators at Juneau, as in most of Southeast Alaska, must be site specific. The winds tend to be gusty and potential locations are limited by steep slopes and forests. While by no means a reliable indication of the wind resource at all locations in Lhe area, Juneau has been classified as Wind Power Class 4. This classification lies in the mid-range of the scale, suggesting there are Many areas in the Southeast with indications of a more favorable resource. Alt Lhe same time, there are substantial limitations concerning wind generation technology, with none of the more appropriate medium-sized units operating in Alaska. For these reasons, it is not deemed advisable for a Juneau utility to introduce wind generators at this time. 0072C 3-72 3.5.3 Solar-electric Generation lwo basic methods for generating electric power from solar radiation are under development: solar thermal conversion and photovoltaic syslems. Solar thermal systems involve the conversion of solar energy to heal via a transfer medium. Energy is realized as work when the fluid is used to drive a turbine. In photovoltaic systems, solar energy is converted to electric energy by activating electrons in photosensitive substances. The availability of solar energy is variable both over the day and seasonally, and is subject to uncertainties of cloud cover and precipitation. Inducements for developing this resource are reduced where electric load profiles are out of phase with solar resource availability, as they are in Juneau. Solar energy facilities must either be employed as solar radiation is available to displace conventional generation, or they must be installed with storage capacity. Solar radiation data for Juneau reflect both cloudiness and the annual cycle in the sun angle. Information on Juneau's solar resource has becn developed from “Evaluation of Unconventional Energy Alternatives" (Polarconsult 1982). The daily incident solar radiation on a horizontal surface is 70 Btu/ft@ in December and 1,414 Btu/ft2 in June. On an optimally oriented vertical surface the December figure is only slightly improved to 184 Btu/ft?. These values compare very unfavorably to even poor sites in the continental United States (550 to 2,000 BLu/ft2 in Minnesota, for instance). The lack of sufficient solar radiation and the lack of coincidence belween peak loads and maximum radiation suggests that solar-electric generation is not a practical alternative for Juneau. 3.5.4 Geothermal Power Generation This discussion of geothermal energy is based on conversations with Mr. David Denig-Clarkroff, of the Alaska Power Authority, and on the report, "Candidate Electric Energy Technologies for Future Application in the Railbelt Region of Alaska" (Battelle 1982). A geothermal-electric plant uses geothermal heat to produce a vapor (eilher steam or a low boiling point organic fluid), which is used to drive a turbine generator. The two basic components of a geothermal-electric plant are the well field and the power plant. The well field includes production wells, the piping to convey fluid to the power plant, the piping to return fluid to the well field for reinjection, and the reinjection wells. The power plant is comprised of the turbine, switchyard, and heat rejection equipment. Other equipment which can be located either at the well field or at the power plant include pumps, steam flashing drums, and heat exchanges. 0072C 3-73 The four most important siting criteria used to evaluate geothermal resources for application to electric power production are as follows: Fluid temperatures in excess of 280°F; Heat sources at depths less than 10,000 ft, with a temperature gradient at least 25°F per 1,000; Good rock permeability to allow heat exchange fluid to flow readily, and; Water recharge capability to maintain production. The most promising Alaska site for geothermal power production is at Unalaska in the Aleutians. The Unalaska situation is characterized by proximity to a sizable load center, relatively high alternative power costs, and a high quality geothermal resource. It is a water dominated system with temperatures of 370°F at about 2,000 ft depth. Preliminary analysis shows that development of this site may result in electrical energy costs comparable to the existing cost of diesel generated power al Unalaska (approximately 34 cents per kWh). There is no site in the Juneau area as promising as the Unalaska situation in terms of proximity to the load center combined with quality of the geothermal resource. Inasmuch as development at Unalaska is only marginally competitive with diesel-powered generation at 34 cents per kWh, economic geothermal power generation for Juneau is extremely unlikely and does not merit further consideration unless some as yet unidentified geothermal resource is someday found. 3.5.5 Tidal Power Evaluation of Juneau's tidal power resource is based on "Tidal Current Tables" (NOAA 1980) and “Angoon Tidal Power and Comparative Analysis" (R.W. Retherford and Associates 1981). Tidal fluctuations may be used to provide energy for electrical generation. Thus far, utility-scale tidal electric power has been developed at only two sites worldwide. These are both characterized by construction of a barrage, where the amount of energy available is a function of usable head, area of the tidal basin formed by the barrage, capacity of the sluiceways to fill the basin, capacity of turbine and generating units, and mode of operation. There are no sites in the vicinity of Juneau that lend themselves to economic tidal power development of this conventional sort. An alternative method of exploiting the tides has been suggested for Angoon at Turn Point in Kootznahoo Inlet. A submerged open type marine propeller would be driven by the tidal currents to produce power. With 0072C 3-74 average velocities for the maximum tidal currents exceeding 6 knots, a 42-foot channel depth, ideal hydrological configuration and very close proximity to the load center, preliminary estimates for the theoretical system suggested a cost of $413,400 (1980 dollars) for a 96 kW unit capable of producing 300 MWh per year. Of course, this capacity would be intermittent, and the energy could only be used to periodically displace other generation from dependable sources. There is no site in the vicinity of Juneau that offers the set of characteristics required for this type of installation. For instance, the highest average velocities for the maximum tidal currents in the Juneau area are less than one third that of the Angoon site. Therefore, even with eventual maturity of the technology, tidal power is nol a serious contender for consideration at Juneau. 3.5.6 ‘Yood-fired Steam Generation Wood has always been an important boiler fuel for producing steam and electrical energy in the forest products industry. Wood-fired power plants are distinct from fossil-fired units in that maximum plant capacities are relatively small, and specialized fuel handling equipment is required. Plants tend toward smaller sizes because of the expense of transporting low-energy-density biomass fuels appreciable distances. A plant layout recently developed by Ebasco for the City of Kake is used here as representative of the facilities required for Juneau. The planl would consist of a fuel receiving and processing area, fuel storage and handling, and a building housing the boiler, turbine, generator, and auxiliary systems. The viability of any biomass-fired power plant is intimately related to the source of fuel. This relationship has two aspects: cost and reliability of supply. The most opportune source for biomass fuel for Juneau would be the long-term timber sale at Hoonah. The Juneau Ranger Dislrict estimates that about 20 percent of available timber is left on the ground given the present poor market for pulp timber. This waste timber is low grade with defects that make it unsuitable for lumber production. The District estimates that the cost of pulp timber presently wasted is 75 to 100 dollars per bd-ft at the water, rafted. This equates to approximately $2.00 to $2.70 per MMBtu, assuming 8,736 lbs/MBF and 4,250 Btu/1b. Towing costs would add 0.3 cents per MMBtu per mile. Handling costs at Juneau would be an additional expense. A 5 MW plant, used as a base load unit would require 82,400 tons per year of fuel assuming 8,300 hours of operation per year. This relatively high utilization is within achievable limits demonstrated in the pulp and paper industry. The plant would generate 41,500 MWh annually. 0072C 3-75 At an estimated heat rate of 17,000 Btu/kwWh and a fuel cost assumed at the midpoint of the estimated range, the fuel component of generation costs would be 3.9 cents/kWh in the present poor market for pulp timber. Nonfuel operating and maintenance costs are estimated at $830,000 per year, or 2.0 cents/kWh. Annual interest and amortization expenses for the $14 million capital cost, 20-year economic life, and 3.5 percent real discount rate would equate to 2.4 cents/kWh. Thus, tolal energy costs in the first year would be approximately 8.3 cenls/kWh, excluding transportation, and the handling of fuel at the Juneau end. The prospect for a long-term reliable fuel supply at the estimated price is not favorable. If market conditions deteriorate, the continuation of logging operations, which is the source of the waste, becomes uncertain. If, on the other hand, demand for pulp timber increases, waste becomes more valuabie and the price would rise. This vulnerability in the supply and price of wood-waste fuel is considered a very significant disadvantage of this alternative, which is not offset by any cost advantage. Planned cutting rates at the most accessible source of wood fuel, near Hoonah, would result in only 50,000 tons per year compared to the 82,400 tons required for the proposed plant. Contrary to the plan, however, present logging aclivity is nil. The current situation is very indicative of the risks inherent in development of a wood-fired steam plant. 0072C 3-76 4.0 TRANSMISSION SYSTEM DEVELOPMENT 4.1 INTRODUCTION As part of this study, the existing transmission and distribution system was reviewed and analyzed. The purpose of this work was twofold; to determine the power and energy losses which exist now and will exist in the future, and to assess the adequacy of the existing system in view of future needs. For the purpose of this project the transmission system studies have been divided into three sections corresponding to the three major functional areas of the Juneau electricity supply system. First, the 69 kV transmission system was analyzed. Second, the distribution system was investigated, including the 69/12.5 kV transformers. Third, losses related to project-specific transmission lines were calculated. Losses associated with the generators and powerhouse auxiliaries were accounted for in the spreadsheet labeled "HYPRO - Summary of Existing and Committed Hydro Projects." 4.2 THE 69 KV TRANSMISSION SYSTEM The existing 69 kV transmission system located in the Borough of Juneau was built in stages and consists presently of 37 different line segments as it can be seen in Figures 4-1, 4-2, and 4-3. Data of these line segments were gathered and are shown in Tables 4-1 and 4-2 and sketches of the structures in Figure 4-4. From these data the necessary impedance calculations were carried out and the results were tabulated in Tables 4-3 and 4-4. For the purpose of these studies, it was assumed that this transmission system remains the same for the entire study period. This assumption was verified by the finding that, with the mid-range forecasted loads used in this study, only one short section of the transmission system will need to be upgraded before the year 2003. Two alternatives were investigated next. First, it was assumed that the energy was supplied from the Snettisham plant via the Thane substation. In the second case, all of the generation is provided by the diesel and combustion turbine units. The one-line diagram used in the load flow studies is shown in Figure 4-5. The line parameters used are shown in Table 4-5. In order to distribute the forecast load among the individual substations, the following procedure was used. The basis of distribution was data published earlier in an CHoM Hill report. The 0455C 4-1 OP SUBSTATION SEE FIGURE 4-3 FOR DETAILS LLEY SUBSTATION (FUTURE) LOW! in Fi SALMON CREEK SUBSTATION e-0 DOUGLAS SUBSTATION “ ——— 2 Se 4000 2000 0 2060 3000 SCALE IN FEET NOTE: 23kV TRANSMISSION LINES TO UPPER. SALMON CREEK AND ANNEX CREEK PLANTS NOT SHOWN, ‘SEE FIGURE 4-2 FOR DETAILS JUNEAU AREA 20 YEAR POWER SUPPLY PLAN EXISTING 69 kV TRANSMISSION DATE NOV 1984 FIGURE 4-1 EBASCO SERVICES INCORPORATED e- tenes LEGEND 1252 125¥/7 2 kV 24=243kV ALSEY pistRIBUTION —OeKY TRANSMISSION 4 ———— UNDERGROUND DISTRIBUTION —-— UNDERGROUND TRANSMISISON JUNEAU AREA 20 YEAR POWER SUPPLY PLAN EXISTING 69 kV TRANSMISSION DATE NOV 1984 | FIGURE 4-2 EBASCO SERVICES INCORPORATED vb AIRPORT SUBSTATION JUNEAU AREA 20 YEAR POWER SUPPLY PLAN EXISTING 69 kV TRANSMISSION DATE NOV 1984 | FIGURE 4-3 EBASCO SERVICES INCORPORATED TABLE 4-1 TRANSMISSION LINE 1 CONDUCTOR SIZES AND STRUCTURES Line Length Conductor Lowest Cond. GMD Structurel/ Section (Feet) Type Height (Feet) (Feet) Type APA-101 3,800 652 AAAC 49.0 8.0 2 101-102 2,975 2/0 CU 44.5 8.2 2&1 3 102-103 1,050 652 AAAC 44.5 8.2 2&3 103-104 3.025 2/0 CU 44.5 8.2 2&3 104-105 980 652 AAAC 44.5 8.2 2&3. 105-106 4,990 2/0 CU 44.5 8.2 2&3 106-107 1,670 652 AAAC 44.5 8.0 2 107-108 2,000 2/0 CU 44.5 8.4 3 108 -SS 100 4/0 ACSR 44.5 8.0 2 SS -GC 3,200 500 CU UG N/A - GC-CA 80 500 CU UG N/A - 108-109 160 2/0 CU 43.5 6.5 ] 109-110 3,300 652 AAAC 43.5 6.5 ] 110-205 250 4/0 ACSR 43.5 625 1 110-111 3,350 652 AAAC 43.5 6.5 1 111-112 1,800 4/0 ACSR 43.5 6.5 1 112-113 5,220 2/0 CU 44.5 8.2 2&3 113-LS 2,400 652 AAAC 4535 its 4 \/ Refer to Figure 4-4. NOTES: UG Abbreviations for substations: Stands for underground cable. AIR Airport APA Alaska Power Administration - Thane CA Capitol Avenue GC Gold Creek GHEA Glacier Highway Electric Association LC Lemon Creek LP Loop LS Lower Salmon Creek SS Second Street WJ West Juneau 0455C 4-5 TABLE 4-2 TRANSMISSION LINE 2 CONDUCTOR SIZES AND STRUCTURES Line Length Conductor Lowest Cond. GMD Structurel/ Section (Feet) Type Height (Feet) (Feet) Type APA-201 7,060 652 AAAC 43.5 6.5 ] 201-202 1,080 4/0 ACSR 100.0 15.0 6 202-203 2,110 652 AAAC 43.5 6.5 1 203-204 1,320 652 AAAC 100.0 15.0 6 204-205 12,560 652 AAAC 43.5 6.5 1 205 -GC 800 4/0 ACSR 43.5 6.5 ] 205-206 1,190 652 AAAC 55.0 3 5 206-207 680 652 AAAC 43.5 6.5 ] 207-WJ 3,210 652 AAAC 120.0 5+0 6 207-208 9,550 652 AAAC 43.5 6.5 ] 208-LS 2,010 652 AAAC 45.5 ilies 4 LS-LC 16,395 652 AAAC 43.5 6.5 ] LC-209 6,170 652 AAAC 61.5 6.5 ] 209-210 14,280 652 AAAC 43.5 6.5 ] 210-211 1,800 652 AAAC 48.0 6.5 ] 211-AIR 2,450 652 AAAC 48.0 6:5 1 211-212 1,200 652 AAAC 48.0 6.5 ] 212-GHEA 3,650 2/0 ACSR 48.0 6.5 1 210-LP 11,600 652 AAAC 48.0 6.5 / Refer to Figure 4-4. NOTES: Abbreviations for substations: AIR Airport APA Alaska Power Administration - Thane CA Capitol Avenue GC Gold Creek GHEA Glacier Highway Electric Association LC Lemon Creek LP Loop LS Lower Salmon Creek SS Second Street WJ West Juneau 0455C 4-6 Lo TRANSMISSION POLE STRUCTURE TYPES GMD - 6.5’ TYPE 1 GMD - 11.3’ TYPE 4 12’ GMD - 8.4’ TYPE 3 24" | | 12° I GMD - 15.0° TYPE 6 Figure 4-4 TABLE 4-3 TRANSMISSION LINE 1 POSITIVE SEQUENCE IMPEDANCES Resistance Reactance Capacitance Line Section ohm ohm megohm APA-101 0.131 0.489 0.220 101-102 0.271 0.443 0.325 102-103 0.0362 0.136 0.799 103-104 0.339 0.555 0.259 104-105 0.038 0.127 0.856 105-106 0.455 0.744 0.193 106-107 0.0576 0.215 0.500 107-108 0.182 0.299 0.485 108-SS 0.0106 0.0153 9.13 SS-GC (UG) 0.0865 0.202 0.00175 1/ GC-CA (UG) 0.00216 0.00505 0.07 1/ 108-109 0.0146 0.0230 5.81 109-110 0.114 0.409 0.243 110-205 0.0267 0.0369 3.52 110-111 0.115 0.415 0.239 111-112 0.192 0.266 0.489 112-113 0.476 0.778 0.185 113-LS 0.0827 0.328 0.371 1/ Estimated impedance values. NOTES: UG Stands for underground cable. Abbreviations for substations: AIR Airport APA Alaska Power Administration - Thane CA Capitol Avenue Gc Gold Creek GHEA Glacier Highway Electric Association LC Lemon Creek LP Loop LS Lower Salmon Creek SS Second Street WJ West Juneau 0455C 4-8 TABLE 4-4 TRANSMISSION LINE 2 POSITIVE SEQUENCE IMPEDANCES Resistance Reactance Capacitance Line Section ohm ohm megohm APA-201 0.243 0.875 0.114 201-202 0.115 0.180 0.937 202-203 0.0727 0.262 0.380 203-204 0.0455 0.189 0.707 204-205 0.433 1.56 0.0639 205-GC 0.0853 0.118 1.10 205-206 0.0410 0.151 0.690 206-207 0.0234 0.0843 1.18 207-WJ 0.111 0.460 0.291 207-208 0.329 1.18 0.0841 208-LS 0.0693 0.275 0.442 LS-LC 0.565 2.03 0.049 LC-209 0.213 0.765 0.130 209-210 0.492 1.77 0.0562 210-211 0.0620 0.223 0.446 211-AIR 0.0845 0.304 0.328 211-212 0.0414 0.149 0.669 212-GHEA 0.590 0.565 0.251 210-LP 0.400 1.44 0.0692 NOTES: Abbreviations for substations: AIR Airport APA Alaska Power Administration - Thane CA Capitol Avenue Gc Gold Creek GHEA Glacier Highway Electric Association LC Lemon Creek LP Loop LS Lower Salmon Creek SS Second Street WJ West Juneau 0455C 4-9 69 kV SYSTEM ONE LINE DIAGRAM 69 KV APA Thane (108) (°) | Second Street Gold Creek Capitol Ave. West (2°) Juneau ei euiiike — Airport Loop Numbers in parenthesis cross reference Tables 4-1 and 4-2. Shown inside the circles are the bus numbers used in the load flows. Lemon Creek JUNEAU AREA 20 YEAR POWER SUPPLY PLAN 69 kV SYSTEM ONE LINE DIAGRAM USED IN LOAD FLOW STUDIES DATE NOV 1984 | FIGURE 4-5 EBASCO SERVICES INCORPORATED 4-10 TABLE 4-5 PER UNIT IMPEDANCES ON 100 MVA BASE AND LINE CHARGINGS USED IN LOAD FLOW STUDIES Bus Substation Resistance Reactance Line Charging No.1/ (Location) 2/ P.U. P.U. MVA i” bic 0.0191 0.0643 0.14 a fe 0.0316 0.0632 0.11 6 ed erieut 0.0182 0.0375 0.068 ° an 0.000567 0.000777 0.0013 - Oa 0.00271 0.00907 0.02 a an Saar 0.00835 0.0306 0.067 13 Lemon creek —-9-0119 0.0478 0087 cig ed 0.000865 0.00424 2.72 F oe a 0.000225 0.000315 0.00052 2 BEET ceo oo ! co 0.0018 0.00248 0.0043 uu a 0.0013 0.0049 0.016 : ee seal 0.00233 0.00966 0.016 1/ Refer to Figure 4-5 2/ Refer to Figures 4-1, 4-2, and 4-3 0455C 4-11 TABLE 4-5 (Continued) Bus Substation Resistance Reactance Line Charging No.1/ (Location) 2/ P.U. P.U. MVA 7 in crest 0.0148 0.0533 0.12 = aon 0.0084 0.0302 0.069 7 oe 0.0013 0.00469 0.011 : eel 0.00179 0.00639 0.015 = (Bs 0.0133 0.015 0.026 1/ Refer to Figure 4-5 2/ Refer to Figures 4-1, 4-2, and 4-3 0455C 4-12 substation peak MW loads taken from said report are reproduced in Table 4-6. From these data, the percentage distribution was calculated as shown in the same table. The individual substation loads for any forecast year were calculated by distributing the forecasted peak demand according to these percentage values. As the objective of these studies was mainly to establish the losses of the system, it was assumed that the Thane substation 69 kV bus is at constant voltage, i.e., this bus was considered to be the swing bus. The load flow calculations were carried out using the remote access computer facilities of Westinghouse Electric Corporation (WESTCA1). This is a time-share system whose facilities are accessed through the Tynnet Computer Network from any part of the United States, although the computer itself is located in Pittsburgh. With the 1984 peak demand of 41.3 MW applied to the system, the 69 kV transmission capacity losses were calculated to be 0.44 MW when the system was fed from the Thane substation. The losses were 0.07 MW when the power was generated at the AELP stations. For any other forecast year, the losses were assumed to be proportional to the square of the peak demand. The largest peak demand applied to the system was 94.8 MW corresponding to the forecast year of 2003. This load was assumed to be supplied from the Thane Substation because, as it was shown earlier, this mode of supply produced the largest losses in the 69 kV system. It also produced the larger loadings in the individual lines when compared to generation by AELP sources alone. The only overload condition that occurred while conducting the load flow studies was in conjunction with the 2003 study year shown in Figure 4-6. In this load flow case, the 4/0 ASCR segment of Line 2, between locations (201) and (202) became overloaded by 12 percent. This line segment is part of the branch of Line 2 out of Thane Substation as can be seen in Table 4-2 and Figure 4-1. This finding indicates that this line segment may have to be upgraded sometime around the year 2000. 4.3 DISTRIBUTION/FEEDER LOSSES The distribution/feeder losses calculated in this section include the line losses, the losses of the 69/12.5 kV transformers, and the transformation losses of the distribution transformers. It was assumed that there will be no extensions to the distribution system over the forecast period. 0455C 4-13 TABLE 4-6 PERCENT SUBSTATION LOADS USED IN THE LOAD FLOW STUDIES Substation Peak Load (MW) 1/ % West Juneau 6.8 13.4 Lemon Creek 5.0 9.8 Loop 8.1 15.9 Airport 9.4 18.5 GHEA 3.5 6.9 Second Street 6.8 13.4 Capitol Avenue 7.9 15,6 Gold Creek 3.3 = 620) TOTAL 50.8 100.0 1/ Taken from the CH2M Hill report. These load values were used to establish the percent load distribution. All loads were assumed to have 0.9 power factor. 0455C 4-14 69 kV SYSTEM LOAD FLOW IN 2003 FORECAST YEAR 69 kV APA Thane @) + z= f 10.; Lower Salmon @) o- | - fess 1.032 v= 3 48.5) ‘n° 12.7 MW 6.2 MVAR 0.996 17.5 MW 8.5 MVAR 15.1 MW 7.3 MVAR 4-15 9.3 MW 4.5 MVAR 0.978 Lemon Creek JUNEAU AREA 20 YEAR POWER SUPPLY PLAN 69 kV SYSTEM LOAD FLOW IN 2003 FORECAST YEAR DATE NOV 1984 FIGURE 4-6 EBASCO SERVICES INCORPORATED Line loss calculations indicated that the feeders' losses are small and, therefore, do not influence the results significantly. The feeder line losses were calculated using the REA loss factor formula.1/ These losses were assumed to be proportional to the square of the load. It was assumed that the total installed transformer capacity equals 3.5 times the peak demand. This includes all transformers, namely those transforming the voltage from 69 kV to 12.5 kV and also all the distribution transformers. It was assumed that these transformers on the average have no-load losses equal to 0.5% of their kVA rating and copper losses equal at full load to 1.5% of their kVA rating. Furthermore, it was assumed that all transformers are constantly on the system and therefore generate losses over 8,760 hours per year. 4.4 PROJECT-SPECIFIC TRANSMISSION LINES The transmission losses of each of the projects discussed in this report were calculated. Each of the project-specific transmission lines was assumed to feed either into the existing 69 kV system or into the Snettisham-Juneau 138 kV line. All transformer and/or converter station losses were included into the calculations. The parameters used for the existing Snettisham Juneau transmission line are shown in Table 4-7. These were extracted from earlier reports and from information gathered on site. All newly to be constructed 115 kV AC lines were assumed to be equipped with 795 kCM ACSR, "Drake" conductors. This conductor is used on most of the Snettisham-Juneau 138 kV line and, in general, withstood the conditions prevailing in the area.2/ The conductor wires of the cables were estimated from available ampacity data with 300 kCM considered as minimum for HVDC and 350 kCM for AC cable, because these seem to be the smallest conductor sizes that could be laid in the Juneau area. The parameters defining the transmission lines used in the calculations are presented in Table 4-8. 1/ (Loss Factor) = 0.16 x (load factor) + 0.84 x (load factor)2 REA Bulletin 60-9, p.39. 2/ Only the section which was exposed to record high winds had to be relocated. 0455C 4-16 TABLE 4-7 SNETTISHAM-JUNEAU 138 KV LINE DATAL/ Resistance Line Segment Mile Conductor Ohm/Mi le Snettisham - Taku East 83.7 Drake 0.128 Taku East - Taku West2/ 3.0 300 kCM-Cu 0.178 Taku West - Thane (Juneau) ie Drake 0.128 5.6 Falcon 0.0666 east Drake 0.128 44.7 miles 1/ present status. 2/ Submarine cable. 0455C 4-11 TABLE 4-8 PARAMETERS USED FOR PROJECT-SPECIFIC TRANSMISSION LINES Resistance Line Mile kV Conductor Ohm Snettisham and Crater Lake to Juneau weeenece oe EXIStINg -------- 5.5 Snettisham w/raised dam and Crater to Juneau aoeeeee Existing -------- 5.5 Dorothy Lake and Snettisham and Crater to Juneau Dorothy-Taku West 5 138 AC 350 kcMl/ 0.89 Snettisham-Taku West son-~ > Existing --~------ 4.86 Taku West-Juneau were em Existing --------- 0.67 Sweetheart Lake and Snettisham and Crater to Juneau Sweetheart - Tap point 7 138 AC 350 kcMl/ 1.25 Snettisham - Tap point 10 9 ------- Existing ------- 1.28 Tap point - Juneau 34.7 ---~--- Existing ---~---- 4.22 Speel River and Snettisham and Crater to Juneau Speel - Snettisham 135 138 AC Drake 0.19 Snettisham-Juneau ween Existing ~------ 5.5 Thomas Bay and Snettisham and Crater to Juneau Thomas - Tap point 110 100 oc = 300 kcml/ 22.9 Snettisham - Tap point V4 wenn s-- Existing ------- 1.79 Tap point - Juneau 30.7 --~----- Existing ---:---- 3.7) Nugget Creek - Loop Station 1.52/23 AC Oriole 0.45 1.93/23 AC. Oriole 0.56 Tyee Lake to Snettisham 113 100 pc ~=— 300 kcml/ 23.5 Snettisham to Juneau 42 100 pc ~=—400 kcml/ 6.55 Whitehorse to Juneau 105 115 AC Drake 13.4 64 110 DC = 300 kcMl/ 13.3 6.5 69 AC Elgin Ase 1/ Submarine cable, copper conductor. 2/ New construction. 3/ Reconductoring. 0455C 4-18 Iransformer losses were estimated based on the existing transformer at Snettisham and at Thane Substation. The HVDC converter station losses were taken at 1.5% of rated load for each converter station and for rated currents less than one kiloampere, and at 1.25% in case of higher current ratings. The results of the loss calculations are shown in Tables 4-9 and 4-10 for all alternatives investigated. The loss factors were calculated using the REA formula. It was assumed that the transformers are energized 8760 hours per year. The loss figures shown in the tables were used in the Economic Parameters Summary spreadsheets previously discussed in Section 3 (Tables 3-1, 3-5, and 3-12). 0455C 4-19 TABLE 4-9 AC TRANSMISSION LOSSES BETWEEN PROJECTS AND THE JUNEAU 69 kV SYSTEM AT FULL UTILIZATION —___lLosses Capacity Energy Load Capacity Energy Project MW GWh Factor MW GWh/yr Snettisham (as exists) 46 168 0.42 0.76 2.49 Crater L. & Snettisham 73 271 0.42 1.9 4.98 Crater L. & Snettisham with raised dam 713 321 0.50 1.9 6.20 Dorothy L. & Crater L. & Snettisham 99 398 0.46 nie 5.88 Sweetheart & Crater L. & Snettisham 99 396 0.46 sali? 8.492/ Speel R. & Crater L. & Snettisham 130 671 0.59 6.0 22.42/ Thomas B. & Crater L. & Snettishaml/ 118 47\ 0.46 9.96 33.72/ Nugget Cr. 10.8 64 0.67 0.23 2.43 1/ Partly HVDC transmission; figures shown include all losses. 2/ Loading the Taku Inlet segment of the existing 138 kV line in excess of 90 MW may require addition of a second cable circuit. Capacity of the cable is a function of actual grounding conditions, which remain a matter of uncertainty. 0455C - 4-20 TABLE 4-10 HVDC TRANSMISSION LOSSES OF PROJECTS AT FULL UTILIZATION Capacity Project MW Tyee L.-Snettisham HVDC 30 Snettisham-Juneau HVDC 110 Whitehorse-Juneau HVDC!/ 20 = Losses Energy Load Capacity Energy GWh Factor MW GWh/yr 100 0.38 3.0 Tt 271 0.28 10.7 S252 175 1.0 1.64 14.4 V/ Partly AC transmission; figures shown include all losses. 0455C 4-21 5.0 PLAN FORMULATION AND EVALUATION 5.1 PLANNING APPROACH The objective of the planning effort is to identify a set of generation expansion scenarios that satisfy forecasted power requirements and to evaluate their cost effectiveness. The methods used in this study for formulating and evaluating alternative power plans are consistent with those mandated by the State of Alaska. All plans are formulated to meet the forecasted peak load and energy requirements discussed in Section 2.0. Future requirements were forecast over the established 20-year planning period, with zero growth arbitrarily assumed thereafter in keeping with State of Alaska procedures. Existing generating and transmission resources were identified, along with those additional projects which are committed for development. Existing resources are assumed to be retired according to the following schedule, which reflects historical and anticipated use of the various facilities and their present condition. ° Upper Salmon Creek Hydroelectric Plant will cease as a generating resource when the Salmon Creek Project expansion is complete. 0 Diesel units installed in the 1950's have an economic life of 35 years. ° Diesel units installed in the 1960's have an economic life of 30 years. ° All new diesel units planned for installation at Lemon Creek have an economic life of 25 years. All diesel units located at the Lemon Creek Plant are considered as potential sources of prime power, while other existing diesel units and combustion turbines are considered as standby facilities. Losses within the Juneau system were evaluated and are discussed in Section 4.0. The first step in formulating alternative plans was the identification and preliminary evaluation of all reasonable energy supply and transmission options. The results of this work are presented in Section 3.0, where the advantages, disadvantages, and pertinent data for each option are discussed. Given the set of existing resources, the retirement schedule, the range of forecasts of peak loads and energy requirements, and the system reserve policy, a series of alternative plans were developed. 0599C All plans are formulated to satisfy capacity and energy requirements while minimizing the system costs over the economic evaluation period. The evaluation period extends from 1984 to 2045 in order to fully evaluate the economic life of the longest-lived project added during the 20-year planning period. All costs associated with the generating and transmission system are addressed in the economic evaluation, except those which are common to all plans. Examples of the latter are capital costs of committed resources and fixed operation and maintenance costs of existing and committed resources. All costs are estimated in constant 1984 base year dollars. The only relative price changes addressed in this study are those for fossil fuels. For both diesel and coal, prices are assumed flat, in constant terms, through 1988, rising at 3 percent annually from 1989 through 2003, and flat thereafter. These relative fuel price assumptions were adopted from Alaska Power Authority standards. Alternative fuel price assumptions were evaluated in sensitivity testing. Capital costs, in the year they are incurred, are added to yearly operation and maintenance costs, fuel costs and power purchase costs to give the total yearly cost of each plan. Noncapital costs occurring in the year 2010 are assumed constant thereafter. (The generation mix continues to change until the year 2010 when all existing and committed units are finally retired.) New projects added as part of the various plans are assumed to be replaced at the end of their economic lives and the replacement cost is accounted for. The salvage value of projects existing at the end of the economic evaluation period is calculated on the basis of remaining economic life. All yearly costs are discounted at 3.5 percent to give their equivalent value in the 1984 base year. This 3.5 percent constant dollar discount rate is consistent with State of Alaska standards. For any given load forecast, all plans that satisfy that forecast provide equivalent monetary benefits, and economic comparison is therefore simply a matter of comparing the discounted total system costs for the various plans. The analytical tools developed to assist in the formulation and economic evaluation of alternative plans are discussed in Volume 2, Appendix 7.5. The planning model is conceptually depicted in Figure 5-1. This spreadsheet-based model is designed for continuing use and can be readily modified to account for altered assumptions and additional generation expansion plans. The following sections contain a discussion of several alternative long-term power plans. The assumptions made and the plan formulation process followed in each case are described, and the planning model results are presented. First, the existing and committed resources are compared to the several load forecasts to determine the generation mix and capacity shortfall that would occur in the absence of any further resource additions. Then, a thermal plan is formulated to meet various load growth forecasts; the thermal plan developed for the mid-range 0599C 5-2 €-S + PROJECT STUDIES, *UPDATES CONCEPTUAL DESIGNS, COST ESTIMATES, ETC.+ LEGEND & CHANGES* HYPRO ALTERNATIVE PROJECTS Easedion exis ag a —_—————4 Listing of alternate AVRIURGLE ENERGY — > DENOTES EXOGENOUS INPUT > projects with technica FR calculates total . and economic data for HYDRO PROJECTS ee a SPREAD See er oe eG ee ae ee | Usen sel ection iana ee eee pacity gy. i input to the model NEW RES ! DENOTES AUTOMATED spread sheets. OURCE @ ! ADDITIONS | A) SPREAD SHEET LINKAGE New RESOURCE 1 ENERGY GENERATION,» (EXTERNAL ) ADDITIONS , CAPITAL COST IcaPACITY, INDIVIDUAL} =| cam cost, | | + DENOTES EXOGENOUS INPUT [LOCATION PROJECT Ieenece FUEL COST, FROM NON-UTILITY SOURCE p& LIFE PARAMETERS | PROJECTS LIFE | NON I * DENOTES EXOGENOUS INPUT | N \ FROM UTILITY SOURCE | ' TOTAL | AVAILABLE GENERATION EXISTING ! CAPACITY MIX | HYDRO “AND CAPACITY SYSTEM @® COSTS, CAPITAL REQUIREMENTS REQUIREMENTS CAPACITY @ CAPPLAN Compare system capacity to ECONANAL Dispatch generating resources and *ENERGY SALES *PEAK LOAD AND RESERVE requirements, ENERGY_SUFFICIENCY calclivate system FORECAST* REQUIREMENTS* aber Pecenveieargines CAPACITY ADDITIONS AND TIMING *ECONOMIC ANALYSIS * AVAILABLE © an PARAMETERS EXISTING © ‘Summary of THERMAL completed alternative CAPACITY plan; power, energy, AVAILABLE and costs CAPACITY SYSTEM SYSTEM FROM EXISTING CAPACITY ENERGY THERMAL DEMAND LOSSES PROJECTS THERPRO Based on present * JUNLOSS planned addvtions, CatcuTates capacity JUNEAU AREA 20 YEAR pvatlable’ thermal within the Juneau ENERGY REQUIREMENTS POWER SUPPLY PLAN 7 Area Distribution capacity. System PLANNING MODEL *UPDATES & + LOAD FLOW CHANGES* STUDY RESULTS + | DATE NOV 1984 [FicuRe 6-1 __| EBASCO SERVICES INCORPORATED forecast is called the "base case" plan. Possible alternative thermal plans are discussed, and this is followed by presentation of hydroelectric and interconnection plans. A discussion of preliminary cost of power estimates then follows. All plans have been formulated in keeping with the spirit of the present reserve policy. In general, that policy calls for sufficient capacity to meet peak loads even if the Snettisham system is out of service. Snettisham could be out of service either because of problems at the plant or anywhere along the Snettisham transmission line. Any projects which either utilize the Snettisham transmission line or are part of the Snettisham Project (i.e., Crater Lake and the Long Lake Expansion) are considered vulnerable to a single outage event that could result in a disruption of all service from those projects simultaneously. Said in another way, then, the reserve policy requires that there be sufficient capacity to meet peak load with the largest generating resource out of service. The “largest generating resource" throughout the planning period is the set of units at Snettisham and/or using the Snettisham transmission line. In this study, the term "South of Taku" has been adopted to describe the set of Snettisham-dependent generating resources. All projects not dependent on the Snettisham system are termed "North of Taku". Projects added “south of Taku" cannot contribute to reserve requirements as long as the combined units south of Taku comprise the largest single unit in the system; this is the case throughout the planning period. Thus, with all else equal, a unit added south of Taku is not as valuable as a unit added north of Taku, because the unit south of Taku cannot contribute toward the required reserve capacity. Of course, all else is not equal, and it may well occur that it is more cost effective to add a project south of Taku for its energy generation potential, in combination with inexpensive standby capacity north of Taku, rather than to add a prime power unit north of Taku. This aspect of the Juneau system is treated in the planning model, and the results are discussed in following sections. With the capacity south of Taku as substantial as it is, an appreciable investment in standby capacity is required. A comparison of existing and committed resources north of Taku to the forecasted mid-range peak load indicates that no additional capacity will need to be added to satisfy reserve requirements under the present policy until 1994. Recently installed and presently planned diesel units, added to insure cost effective energy production during the winter hydroelectric energy deficit periods, create a capacity reserve margin sufficient to last about ten years. In other words, the actions taken in response to one problem (winter energy generation) have had the associated benefit of precluding capacity reserve problems for the next decade, under the mid-range forecast. Thus, consideration of relaxing, or otherwise modifying, the present reserve policy can be postponed several years with no economic penalty. This respite will allow the accumulation of important additional outage rate experience with the Snettisham system. 0599C When capacity sufficiency for meeting reserve requirements again becomes a concern in the mid-1990's, it may then be appropriate for the Juneau utilities to review the existing reserve policy with consideration given to accepting something less than full capacity independent of the Snettisham system. Specifically, an emergency curtailment program could be considered as a substitute for a portion of the standby capacity requirements. 5.2 EXISTING SYSTEM 1/ Existing and committed hydroelectric projects (Salmon Creek, Annex Creek, Gold Creek, Snettisham, the Salmon Creek expansion and the Crater Lake phase of Snettisham) provide 206 GWh firm annual energy initially and 308 GWh starting in 1989. These estimates are net of transmission losses, but exclude local system losses. As of 1989, there will be 80 MW of hydroelectric capacity, with 72 of those 80 MW being “south of Taku". These figures are also net of transmission losses. Including the Lemon Creek diesel units scheduled for 1985, Juneau has 71 MW of thermal capacity. In keeping with the adopted planning assumptions regarding economic lives, this amount declines beginning in 1987 due to retirements until there is no remaining thermal capacity in the year 2010. (Note that actual retirement schedules will vary depending on usage, maintenance practices, etc.) For purposes of this long-term planning study, 25 MW of the total are considered available for prime power generation. For the mid-range forecast, local system losses vary from 5.6 to 7.8 percent over the planning period for capacity, and from 5.6 to 7.3 percent for energy. When these local losses are added to project-specific transmission losses from existing generating units, present total system losses are estimated at 8.5 percent and 7.9 percent for capacity and energy, respectively. Existing and committed hydroelectric resources provide the bulk of generation through the planning period. The incremental cost of generating additional energy from these units is nil, and they are assumed to be fully utilized before turning to diesel generation. In the case of the mid-range forecast, and assuming firm hydroelectric energy production, diesel-generated energy is needed in the first year of the planning period and is required to contribute increasing amounts of energy thereafter until the Crater Lake phase of Snettisham is available. In 1988, the system requirement reaches 74 GWh of diesel generation, or 26 percent of total generation in that year. With Crater Lake complete, the system is characterized by 100 percent hydroelectric generation until 1992. 1/ The planning model spreadsheet output on which the discussion in Sections 5.2 through 5.6 is based can be found in Volume 2, Appendix 7.6. 0599C After 1992, the energy contribution by existing and committed diesel plants grows until it reaches 21 percent, or 88 GWh, in the year 2003. The variable cost of that diesel-generated energy, in 1984 constant dollars, is estimated at $5.9 million in 1988 and $10.4 million in 2003. 5.3 BASE CASE THERMAL PLAN For purposes of this study, plans based on additions of thermal units are used as a baseline for comparison with other plans. In formulating the base case, as well as other plans, existing and committed hydroelectric units are assumed to generate up to their firm annual energy. The thermal plan formulated in response to the mid-range load growth forecast is termed the "base case plan" and is discussed first. Thermal plans developed to satisfy other load forecasts are presented subsequently. The impact on the base case thermal plan of alternative fuel price assumptions is also discussed in this section. When choices are available as to the type of thermal unit to add to the system, the least cost option is used, as long as that choice conforms to general Juneau utility practice. Thus, a coal-fired steam plant or municipal solid waste fired steam plant would not be considered part of the base case plan. To satisfy reserve requirements in the face of the mid-range peak load forecast, capacity is first needed north of Taku beginning in 1994 to supplement existing and committed resources. Standby units are used to satisfy this need, unless there is also a shortfall in energy. In the latter case, which first occurs in 2001, prime diesel units are added. Among the standby options available, high speed (EMD) diesels are most cost effective and are fully appropriate in this application. For purpose of prime power, medium speed heavy duty diesels are used, with the capital cost being determined by the size of the unit required. The base case plan is formulated through the year 2010 to take account of retirement of existing and committed thermal facilities. (Recall that load growth and fuel cost escalation are assumed to cease in 2003, at the end of the 20-year planning period). Through 2010, a total of 90 MW of diesel capacity is needed to meet peak demand while also satisfying reserve requirements. Of that total, all but 20 MW is in the form of standby units. The twenty megawatts are prime diesel capacity needed to satisfy energy requirements. The relative contribution of generation by type and the estimated plan costs by type and by year, along with other pertinent plan characteristics, are summarized for the base case thermal plan on Table 5-1. The total discounted (1984) cost of this plan is $248.4 million over the economic evaluation period, which runs through the year 2045. This $248.4 million represents those aspects of generation and transmission costs which are not locked-in as of 1984, and therefore, which are susceptible to change depending on the plan adopted. Thus, capital costs and fixed operation and maintenance costs of committed units, for instance, are not included in the total plan cost. 0599C 5-6 L=S C) JUNPLAN OCTOBER 18, 1984 BASE CASE THERMAL 1984 1985 1986 1987 1988 1989 1990 1991 PEAK DENAND FORECAST (MW) 41.30 55.10 57.90 60.30 62.60 64.80 66.60 68.50 EXISTING & COMMITTED HYDRO RESOURCES 5.62 6.62 8.62 8.62 6.62 8.62 8.62 8.62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 CAPACITY AVAILABLE TO MEET PEAK (MW) 64,54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (MW) 23.24 24,74 21.94 18.29 15.99 12.59 10.79 5.39 ENERGY SALES FORECAST (Gwh) SQURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO NEW HYDROELECTRIC #1 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 NEW ORIME THERMAL 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0.00 EXISTING DIESEL 21.65 39.78 52.49 63.49 74.07 0.00 0.00 0.00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 FIXED O8w 0 0 0 0 0 0 0 9 VARIABLE O&M 173 318 «420 508 593 0 0 0 PURCHASED ENERGY 0 9 0 0 0 0 0 9 FUEL COST 1538 2826 «37294510 Se62 0 0 0 TOTAL 1711 3144 4149 5018 5854 0 0 0 TOTAL DISCOUNTED PLAN COST ($000) 246406 TABLE 5-1 JUNEAU 20-YEAR PLANNING STUDY SUMMARY OF RESULTS 1992 1993 1994 1995 199 1997 1998 1999 70.40 72,40 74.40 76.50 78.60 80.70 82.90 85.20 8.62 8.62 8.62 8.62 862 8.62 8.62 8.62 65.27 64.14 64.14 69.14 68.00 73.00 73.00 75.50 73.89 72.76 72.76 77.76 76.62 61.62 81.62 64.12 3.49 0.36 -1.64 1.26 -1,98 0,92 -1.28. -1.08 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0,00 0.00 0,00 63, 30 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 6.77 15.78 25.00 34.56 44.02 53.70 0.00 0 0 2306 0 0 18 3 5412200 276 0 0 0 0 S42 1299 2120-3019 59% 1425 4643 5636 2306 2306 33 430 582 0 0 0 4977 6043-7274 7765 6602 10242 0 33 506 £8 a5 2000 2001 2002 2003 87.50 89.90 92.30 94,80 8.62 8.62 6.62 6.62 78.00 83.00 83.00 88.00 86.62 91.62 91.62 96.62 0. 68 0.00 0.00 0.00 0.00 84.46 2306 88 676 0 8554 11623 1.72 0.00 0.00 0.00 29.35 65.93 4116 762 %33 14599 0.68 0.00 0.00 0.00 23.35 77.08 88 851 11120 12059 0.00 0,00 0.00 23.35 88. 04 2306 105 939 0 12667 16016 2004 =2005 «2006 «2007 94.80 94.60 94.80 94,80 8.62 8.62 6.62 8.62 88.00 85.50 85.50 85.50 %.62 94.12 94.12 94.12 1.82 0.68 -0.68 -0.68 0.00 0.00 0.00 29.35 88.04 105 12667 13711 0.00 0.00 0.00 0.00 0.00 0.00 29.35 29,35 88.04 88.04 6917 0 158158 939 0 0 12667 12667 20680 13763 0.00 0.00 0.00 29.35 88. 04 158 939 12667 13763 2008 94. 80 6.62 87.50 %. 12 1,32 0.00 0.00 0.00 38.69 59.23 13338 228 943 0 12401 26910 2009 2010 94.80 94.80 8.62 8.62 87.50 90.00 %. 12 1.32 3.62 215.10 230.60 242.40 252.60 262.40 271.50 279.00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308. 16 308,16 308.16 308.16 308. 16 308.16 308.16 308. 16 0.00 0.00 0.00 0.00 0.00 0.0 58.69 117.38 59.23 0.00 0 8584 228 245 943 (939 0 0 12401 11692 13572 21460 If instead of following the mid-range forecast, actual load growth approximates the low range forecast, supplemental diesel generation will still be required through 1988, but in somewhat reduced amounts. In the case of the low forecast, diesel generation reaches 61 GWh in 1988 at an estimated cost in that year of $4.8 million (1984 dollars). With the advent of Crater Lake, diesel generation is not again needed until 1996. This is the same year that additional diesel capacity is first needed to satisfy reserve requirements. A total of 75 MW of added diesel capacity is needed through 2010 under this low load forecast, all but ten of which is in the form of standby units. The total discounted cost of this low load forecast thermal plan is estimated at $122.6 million. The plan characteristics are summarized in Table 5-2. If actual load growth should follow the trend of the high forecast, plan costs are affected dramatically. The total discounted cost of this thermal plan is $448.1 million. A total of 110 MW of additional thermal capacity is needed, and as much as 42 percent of total annual generation is supplied by diesel units. See Table 5-3 for pertinent characteristics of this plan, and Table 5-4 for comparable statistics for the thermal plan formulated in response to the mining load forecast. The sensitivity of the base case plan cost to alternative fuel pricing assumptions was evaluated by recalculating total discounted plan costs with an assumption of zero fuel cost escalation. This is in contrast to the base case assumption of zero escalation in all years except from 1989 to 2003 when fossil fuels are assumed to rise at an annual rate of 3 percent above the general rate of inflation. The only change to the base case plan is the resultant cost of fuel, which lowers the total discounted plan cost from $248.4 million to $188.1 million. A summary of this case is contained in Table 5-5. 5.4 ALTERNATIVE THERMAL PLANS Additional thermal plans can be formulated by making use of alternative resource options. For standby capacity, combustion turbines could be used rather than high speed (EMD) diesels. The combustion turbines are estimated to be slightly higher in installed cost, but the effect on overall plan costs would be slight. See Section 3.4 and Appendix 7.2 for further discussion. Substituting coal-fired steam plants for prime diesel units would reduce total plan costs, based on cost information summarized on Table 3-15. If a thermal plan is pursued, consideration should be given to use of coal-fired steam technology. Some of those considerations were discussed in Section 3.4. However, since there are More cost effective plans than a coal-fired steam-based thermal plan, a detailed coal-fired plan was not formulated in this study. 0599C 5-8 JUNPLAN OCTOBER 22, 1964 TABLE 5-2 THERMAL JUNEAU 20-YEAR PLANNING STUDY LOW FORECAST SuMAgY OF RESULTS 1986 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 20602 2003 2004 2005 2006 2007 2008 2009 2010 PEAK DEMAND FORECAST (MW) 41.30 54.00 56,10 58.00 59,70 61.30 62.40 63.60 64.80 66.00 67.30 68.60 70.00 7:.40 72.80 74.20 75.70 77.20 78.80 80.30 80.30 80.30 80.30 80.30 80.30 80.30 80.30 EXISTING & COMMITTED HYDRO RESOURCES 5.82 8.62 6.62 8.62 862 862 8.62 6.62 862 662 6.62 862 862 8.62 862 8.62 862 6.62 8.62 8.62 6.62 8.62 8.62 8.62 68.62 8.62 8.62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 63.00 63.00 63.00 65.50 68.00 68.00 68.00 73.00 73.00 70.50 70.50 70.50 72.50 72.50 75.00 CAOACITY AVATLABLE TO MEET PEAK (MW) 64,54 79,84 79.84 78.59 78,59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 71.62 71.62 71.62 74.12 76.62 76.62 76.62 81.62 81.62 79.12 79.12 79.12 81.12 B1.i2 83.62 (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (MA) 23.24 25.84 23.74 20.59 18.89 16.09 1499 10.29 9.09 6.76 0.46 0.84 1.62 0.22 1.18 -0.08 0,92 +058 -2.18 1.32 1.32 -1.18 -1.18 -1.18 0,62 0.62 33 ENERGY SALES FORECAST (Gwh) 215.10 226,00 235,00 242.90 250. 10 256.70 261.40 266.40 271.50 276.80 282.10 287.50 293.20 298.90 304.80 310.80 317,00 323.20 329.60 336,10 336,10 336.10 336.10 336.10 336.10 336.10 336,10 SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO 205.59 205.59 205.59 205.59 205.59 273.5: 278.58 283.98 289.49 295.2: 300.96 306.80 308,16 308.16 308,16 308.16 308,16 308.16 308,16 308. 16 308.16 308.16 308.16 308,16 308.16 308.16 308. 16 NEw HYDROELECTRIC #1 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0,00 0.00 0,00 0,00 0,00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0.00 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 51.43 EXISTING DIESEL 21.65 34,63 44,51 53.03 60.79 0.00 0,00 0.00 0.00 0.00 0.00 0.00 483 11.01 17,41 23.92 30.65 37.40 44.37 51.43 51.43 51.43 51.43 51.43 51.43 51.43 0,00 PLAN COSTS ($000) CAATTAL COSTS 0 0 0 0 0 0 0 0 0 0 o 0 2306 0 0 2306 2306 0 0 2306 0 6917 0 0 11526 0 8584 FIXED O&M 0 9 0 0 0 0 0 0 0 0 9 0 18 18 18 3 53 33 33 70 7 123 123 «123 ek0 0 2B VARIABLE O&M 173. 279) 356 424 BG 0 0 0 0 0 0 0 39 6B 139191 45299 SS AL ALLA AML AN AEE EL 4M SURCHASED ENERGY 9 0 0 0 0 0 0 0 9 0 0 9 9 0 0 0 0 9 0 0 9 0 0 0 0 0, 0 cos* 1538 2478 «3162-3767 4319 0 0 0 0 0 0 0 434 102: 1662 2352 «5:05 3Wi «4767 «S692 HVE EGE HFA HHA HHIA HGR S123. TO 7: 275335184151 4805 0 0 0 9 0 0 0 2796 3126 18:9 4884 S708 4253 S175 8479 6173 13142 6226 6226 1784: 6313 14345 TOTAL DISCOUNTED PLAN COST ($000) 122575 TUNOLAN OCTOBER 22, 1964 THERMAL HIGH FORECAST ERK DEMAND FORECAST (Mw) . EXISTING & COMMITTED HYDRO RESOURCES (NORTH OF TAKU INLET) 1984 1985 41.30 55.70 59.20 5.82 8.62 8.62 62.50 65.70 8.62 8.62 1989 1990 1991 68.90 71.60 74.50 8.62 8.62 8.62 TABLE 5-3 JLNEAL 20-VEAR DLAWNING S"UDY SUMMARY C= RESULS 1992 1993 1994 1995 1996 77.50 80.60 63.90 87.20 9.60 8.62 8.62 8.62 8.62 8.62 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 = avi0 97.70 101.40 105.30 109.40 113.60 117.90 117.90 117.90 117.90 117.90 117.90 117.90 117.90 8.62 8.62 6.62 8.62 8.62 8.62 6.62 8.62 862 862 8.62 8.62 8.62 OI-S EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 70.27 7414 74.14 79.14 78.00 63.00 88.00 95.50 98.00 103.00 103.00 108.00 108.00 105.50 105.50 105.50 107.50 107.50 110.00 CAPACITY AVAILABLE TO MEET PERK (MW) 64.54 79.84 79.84 78,59 78.59 77.39 77.39 73.89 78.89 82.76 82.76 87.76 86.62 91.62 %6.62 104,12 106.62 111.62 111.62 116.62 116.62 114.12 114.12 114,12 116,12 116.12 118.62 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MW) 23.24 26.14 20.64 16.09 12.89 8.49 5.79 -0.61 1.39 216 -1.14 0.56 -3.98 -2.38 -108 2.72 1.32 2.22 -1.98 -1.28 -1.28 -3.78 -3.78 -3.78 -1.78 -1.78 0.72 ENERGY SALES FORECAST (Gwh) 215.10 233.50 248,20 261.60 275.20 288,50 300.10 312.20 324.70 337.70 351.30 365.40 379,40 394.00 409.20 424.90 441.20 458.20 475.80 494.00 494.00 494.00 494.00 494.00 494.00 494.00 494.00 SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO 205.59 205.59 205.59 205.59 205.59 307.90 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 306,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308,16 NEW HYDROELECTRIC #1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0,00 NEW TRANSMISSION IMPORT 0.00 0,00 0.00 0.00 0,00 0,00 0,00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 29,35 88,04 88.04 117,38 117.38 146.73 146.73 146.73 146.73 146.73 176.08 176.08 224.66 EXISTING DIESEL 21.65 42.89 58.74 73.22 87.91 0,00 12.30 25.43 39.02 53.16 67.98 83.35 98.66 114.62 101.94 60.47 78.39 67.77 67.18 77.93 77.93 77.93 77.93 77.93 48.59 48.59 0.00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 2306 2306 2306 ©9206 0 2306 4116 6278 2306 4116 0 4116 0 6917 0 0 15644 0 8584 FIXED O8M 0 0 0 0 0 0 0 0 18 35 353 70 70 88 68 88 4105 «105 105 1051058158158 AHS AS BB VARIABLE D8 173. 343 470 S86 703 0 9 23 312 425 54 667 789 917 «105011881331 1481 1636 «1797 «1797 «1797«:1797)«1797« 179717971797 PURCHASED ENERGY 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 FUEL COST 1538 3047) 4172 S201 6245 0 927 1974 3119 4378 5766 7282 8878 10624 12253 13737 15964 18090 20719 23240 23240 23240 23240 23240 22916 22916 22378 TOTAL 1711 3390 46425787 6948 0 1025 2178 S755 7143 8668 10325 9737 13934 17507 21291 19706 23793 22660 29259 25143 32112 25195 25195 40601 26958 33021 TOTAL DISCOUNTED PLAN COST ($000) 448087 IT-S JUNI FN OC“SBER 29, 1984 THERMAL MINING FORECAST DEQ DEMAND FORECAST (MW) EXISTING & COMMITTED HYDRO RESOURCES (NORTH GF TAKU ENLET) EXISTING & COMMITTED THEQMAL RESOURCES CAOACITY AVAILABLE TD MEET PER (MW) (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (%W) ENEGY SALES FORECAST (Gwh) SGURCES CF GENERAT, EXISTING & COMMI NEW EVDRCELECTRIC #2 NSW RYDRG: #2 NEw TRANSYISSION 12097 NEW PRIME “4E24AL EXISTING DIESEL (Gwh) VDRO ®LAN COSTS ($000) Cagiva. COSTS FINED 98" VARIAB_= Ob DURCMASED ENERGY FUEL COST TOTAL TOTAL DISCOUNTED SLAW COST ($000) 1984 41.30 5.82 58. 72 64,54 23.24 215.10 230,60 242,40 252.60 262.40 271.50 4:0.40 418.30 426,40 424,70 443,20 452.00 460,70 469.60 478.40 488.20 497.80 507.70 517.90 528,40 528.40 528,40 528.40 526.40 526.40 528,40 528. 40 205.59 205.59 205.59 205.59 205.59 289.49 308.16 308,16 308.16 308.16 308.16 308, °6 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308, 16 308.16 308.16 308. 16 308,16 0.00 0.00 0,00 0.00 0.00 0,00 0.00 0.00 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88.04 68.04 117.38 176.08 176.08 176.08 176.08 176.08 176.08 176.08 176.08 205.42 205.42 260.03 72.32 83.96 83.96 83.96 83.96 83.96 54.61 54.61 0,00 0.00 0.00 0.00 21.65 173 1538 1711 556568 1985 55.10 8.62 71.22 79.84 24,74 0,00 0.00 0.00 0.00 39.78 318 2826 3144 57.90 60.30 62.60 8.62 8.62 8.62 69.97 69.97 79.84 78.59 78.59 21.94 18.29 15.99 0.00 0,00 0.00 0.00 0.00 0.00 00 29.35 29.35 58.69 58.69 130.00 138.66 118.19 127.30 107.29 116,97 o8oce eis oto TABLE 5-4 SUNEAL 29-YEAR OLANNING STUDY SUMMARY DF RESULTS 1992 1993 1994 1995 1996 85.40 87.40 89.40 91.50 93.60 8.62 8.62 8.62 8.62 8.62 80.27 79.14 79,14 84.14 68.00 88.89 87.76 87.76 92.76 96.62 0.39 3.49 (0.36 -1.64 1.26 3.02 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88.04 97.20 4116 0 4116 2306 4116 35 35 35 53 1180 1253) 1328 1405 1482 0 0 0 0 19561 12659 13561 14834 15877 16893 13947 139060 18597 21527 1999 2000 2001 «2002 2003 2004 «= 2005 2006 2007 2008 2009 N10 97.90 100.20 102.50 104,90 107.30 109.80 109.80 109.80 109,80 109.80 109.60 109,60 8.62 8.62 8.62 862 62 8.62 6.62 8.62 6.62 6.62 8.62 8.62 6.62 88.00 90.50 98.00 98,00 98.00 193.00 103,00 100.50 100.50 100.50 102.50 102.50 100.00 96.62 99.12 106,62 106,62 106,62 111.62 111.62 109,12 109,12 109,12 111.12 111.32 108,62 1.72 -0.68 1.82 -0.68 -0.68 -0.68 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 107.00 116.71 98.18 50.09 61,04 4116 6278 0 13338 2080 ©2080 «2080 ©2080 «2080 «2080 §=2080 = 2080 24799 26830 25830 26830 26830 26830 26505 26505 2590! 26838 31286 28980 35949 29033 29033 42116 28778 34452 18707 20042 21123 22899 20397 25935 29263 26849 JUNPLEN CCTOBER 22, 1984 TABLE 5-5 BASE CASE THERMAL JUNEAU 20-YEAR PLANNING S7UDY (Zero Fuel Escalation) SUMMARY OF RESULTS 1984 1985 1986-1987 198819891990 1991 1992 1993 1994 1995 19961997 1998 1999 2000 2001 2002 2003 2004 «= 2005 2006) 2007 2008) 20092010 DEAK DEMAND FORECAST (MW) 41.30 55.10 57.90 60.30 62.60 64.80 66.60 68.50 70.40 72.40 74.40 76,50 78.60 80.70 62.90 85.20 87.50 89.9 $2.30 94.80 94.80 94.80 94.80 94.80 94.80 94.80 94,80 EXISTING & COMMITTED HYDRO RESOURCES 5.82 8.62 8.62 68.62 8.62 68.62 8.62 862 8.62 6.62 862 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 6.62 8.62 6.62 8.62 6.62 6.62 8.62 8,62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 68.00 73.00 73.00 75.50 78.00 63.00 63.00 88.00 88.00 85.50 85.50 85.50 87.50 87.50 90.00 CAPACITY AVAILABLE TO MEET PEAK (MW) (64,54 79,84 79,84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 72.76 77.76 76.62 81.62 81.62 8412 86.62 91.62 91.62 9.62 %.62 94.12 94,12 9412 96.12 96.12 96,62 (wiT4 SNETTIS40™ T-LINE OUT OF SERVICE) RESERVE STATUS (Mb) 23.24 24.74 21.94 18.29 15.99 12.59 10.79 5.39 3.49 0.36 -1,64 1,26 -1.98 0.92 -1,28 -1.08 -0.88 1.72 -0,68 1.62 1.82 -0.68 -0.68 -0,68 1.32 1.32 3.62 ENERGY SALES FORECAST (Gwh) 215.10 230.60 242,40 252.60 262.40 271.50 279.00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376,30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 SOURCES OF GENERATION (Gwn) EXISTING & COMMITTED HYDRO 205.59 205.59 205,59 205.59 205.59 289.49 297,61 306.16 308.16 308.16 308.16 308,16 308.16 308,16 308.16 308,16 308,16 308.16 308.16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 NEW HYDROELECTRIC #1 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0,00 0,00 0,00 0.00 0.00 0,00 0.00 0,00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 NEW HYDROELECTRIC #2 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 NEW TRANSMISSION IMPDRT 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 9.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0,00 0.00 29.35 29.35 29.35 29.35 29.35 29.35 29.35 58.69 58.69 117,38 EXISTING DIESEL 21.65 39.78 52.49 63.49 74.07 0.00 0.00 0.00 6.77 15.78 25,00 34.56 44.02 53.70 63.30 73,98 84.46 65.93 77.08 688.04 88.04 68.04 68.04 88.04 59.23 59.23 0,00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 0 0 2306 2306 0 2306 0 2306 2306 4116 0 2306 0 6917 0 0 13338 0 8564 FIXED O8™ 0 0 0 0 0 0 0 0 0 0 18 35 35 53 53 70 88 88 68 105 105158158158 22B 2B HS VARIABLE CEM 173, 318 420, SOB «593 0 0 0 54 12% 00276352 430 Hii 67H 762 S139 939 939 9389 939 HH HK 93. PURCHASED ENERBY 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 FUEL COST 1538 2826 «37294510 = Se62 0 0 O 481 1121 1776 2455 3127 3815 4497 S255 6000 6560 7352 «130 8130 8130 8130 8130 7960-7980) 7505 TOTAL W711 314441495018 5854 0 0 OQ S35 1247 4299 5072 3514 6602 5056 8223 9068 11525 B29. 11480 9174 16143 9227 9227 22468 9130 17272 TOTAL DISCOUNTED PLAN COST ($000) 188124 5.5 HYDROELECTRIC PLANS As presented in Sections 3.2 and 3.3, there are numerous hydroelectric options available to Juneau for consideration in formulation of a long-term hydroelectric-based plan. Annex Creek Expansion should be considered as an addition to the Juneau system in lieu of a comparable amount of prime diesel capacity. Being as small a project as it is (net capacity of 1.8 MW), it does not lend itself to effective evaluation in the long-term planning model, but certain conclusions can nonetheless be drawn. Located “north of Taku", Annex Creek Expansion would provide energy, while also contributing to reserve capacity requirements. Referring to Tables 3-12 and 3-15, it can be seen that energy from the Annex Creek Upgrade has a slightly lower unit generation cost than prime diesel units. The cost differential would be substantially greater if incremental transmission losses associated with the upgrade were not so great. The undeveloped hydroelectric project with the apparent lowest unit cost is the Speel River Project. There are at least three reasons, however, why Speel River is not presently a prime candidate for development. First, there is relatively little known about the project site; the cost estimate, therefore, should not be viewed in the same light as those for other projects. Second, its energy output is not fully matched to Juneau's load shape because of the project's limited storage capacity in relation to annual inflow. Third, the project's energy output is so large that even under the high forecast, only 56 percent of its energy could be utilized by Juneau in the year 2010. For the latter reason, alone, the Speel River Project is less cost effective than other undeveloped hydroelectric projects. The Lake Dorothy Hydroelectric Project offers both a low unit cost and appropriate scale for Juneau's forecasted needs. A plan was formulated to include Lake Dorothy. Using the mid-range forecast and assuming firm generation from existing and committed hydroelectric facilities, the Lake Dorothy Project was initially assumed operational in the year 1996, when diesel generation would otherwise become a substantial contributor to total generation. When sharing a portion of the existing Snettisham transmission line, the Lake Dorothy Project is considered, for purposes of this study, to be "south of Taku", i.e., dependent on the Snettisham system. As such, the Lake Dorothy Project does not contribute to reserve requirements. The plan requires addition of standby thermal units beginning in 1994. A total of 90 MW of diesel capacity is added over the planning period; no prime diesel units are needed. With the exception of the years 1994 through 1988, and again in 1992 through 1995, all energy requirements are met with hydroelectric generation. Refer to Table 5-6 which summarizes this plan. In the last year of the planning period, there remains 8 GWh of annual energy still available from Lake Dorothy to accommodate future load growth at no incremental cost. The total discounted plan cost is $114.1 million; this compares to the $248.4 million for the base case thermal plan. 0599C 5-13 vI-S JUNPLAN OCTOBER 22, 1984 . TABLE 5-6 DOROTHY = 1996 JUNEAU 20-YEAR PLANNING S”UDY (w/Smet T-Line) SUMMARY OF RESULTS 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 199% 1997 1998 1999 2000 200! 2002 2003 2004 2005 2006 2007 2008 2009 2010 PEAK DEMAND FORECAST (MW) 41.30 55.10 57.90 60.30 62.60 64.80 66.60 68.50 70,40 72.40 74.40 76.50 78.60 80.70 62,9 85.20 87.50 89.90 92,30 94,80 94,80 94,80 94.80 94.80 94.80 94.80 94,80 EXISTING & COMMITTED KYD90 RESOURCES 5.82 8.62 8.62 6.62 6.62 8.62 8.62 8.62 8.62 862 6.62 8.62 8.62 8.62 8.62 8.62 862 B62 8.62 8.62 8.62 8.62 8.62 8.62 862 8.62 8.62 (NORTH OF TRKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 73.00 73.00 78.00 80.50 78,00 83.00 83.00 88.00 86.00 85.50 85.50 65.50 87.50 67.50 65.00 CAPACITY AVAILABLE TO MEET PEAK (MM) 64,54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 72.76 77.76 61.62 81.62 86.62 89,:2 86.62 91.62 91,62 96.62 96.62 9412 9412 9.12 96.12 96.12 93.62 (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (MW) 23.24 24.74 21,94 18.29 15.99 12.59 10.79 5.39 3.49 0.36 -1.64 1.26 3.02 0.92 3.72 3.92 +88 1.72 -0.68 1.82 1.82 0.68 -0.68 0.68 1.32 1.32 -1.18 ENERGY SALES FORECAST (Gwh) 215, 10 230.60 242.40 252.60 262.40 271.50 279.00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO 205,59 205.59 205,59 205.59 205,59 289.49 297.61 306.16 308.16 308.16 308.16 308.16 308.16 308,16 308.16 398.16 308.16 308.16 308.16 308.16 308.16 308.16 308. 16 308.16 308.16 308,16 308. 16 NEW HYDROELECTRIC #1 0.00 0.00 0,00 0,00 0,00 0.00 0.00 0,00 0,00 0,00 0,00 0,00 44,02 53.70 63.30 73,98 84.46 95.28 106.42 117.92 117.92 117,92 117.92 117.92 117.92 117,92 117.92 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 EXISTING DIESEL 21,65 39.78 52.49 63.49 74.07 0,00 0,00 0,00 6.77 15.78 25.00 34.56 0,00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0,00 0.00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 0 16541 33232 26759 2306 0 2306 2306 0 2306 0 2306 0 63917 0 0 11526 0 46it FIXED O&M 0 0 0 0 0 0 0 0 0 0 18 3 37) OS7Hs—CiHR SHR 410 10s 427427 BB SET SET 0 VARIABLE O&M 173 318 = =420, 508 593 0 0 0 5412 200 276 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 PURCHASED ENERGY 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 FueL COST 1538 2826 «37294510 Sebe 0 0 0 See 1299 2120 3019 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 1711 3144 4149 5018 5854 0 0 0 596 17966 35569 30089 2663 357 2680 2698 «= 392 ATI) 4102733 4277398 «= 480) 480 12095 567“ S213 TOTAL DISCOUNTED PLAN COST ($000) 114116 In evaluating the Lake Dorothy Project, thought should be given to developing Lake Dorothy independent of the Snettisham system. By doing so, standby capacity requirements could be reduced. Further analysis is in order to determine whether the threat of an outage of both Lake Dorothy and Snettisham due to transmission line failure between Thane Substation and Taku Inlet is sufficiently real to consider Dorothy dependent on Snettisham facilities. If it is concluded that outage of the entire Snettisham/Dorothy system is a real concern, then consideration should be given to including separate transmission facilities from the Lake Dorothy powerhouse to Thane Substation. A reconnaissance level cost estimate was completed for such additional facilities. An incremental cost of $3,718,000 is indicated, which would bring Lake Dorothy's total estimated project cost to $75,638,000. An alternative long-term plan was formulated using this higher cost and assuming Lake Dorothy was a resource independent of the Snettisham system. Refer to Summary Table 5-7. Since, under this scenario, Lake Dorothy can contribute to reserve requirements, less capacity must be added: 85.7 MW rather than 110.7 MW. From 1996 on, all energy is provided from hydroelectric facilities. The total discounted plan cost is approximately $104.6 million. Comparing this figure to the previous Lake Dorothy plan cost of $114.1 million, the addition of separate transmission facilities over the full distance to Thane serves to reduce plan costs by about 8 percent, despite the higher cost of the Lake Dorothy project, itself. As a result of this finding, further evaluation of the Lake Dorothy project plan in this study concentrated on the Lake Dorothy project with separate transmission facilities to Thane. The planning model was also used to evaluate hydroelectric plans formulated to satisfy the requirements of the low- and high-range load growth forecasts. The Lake Dorothy Project, as in the previous plan, is modified to be independent of the Snettisham system, and firm generation is assumed from all hydroelectric facilities. In the case of the low forecast, Lake Dorothy is not brought on line until 1999, and 60 percent of Dorothy generation potential remains unutilized at the point when load growth is assumed to cease. Refer to Table 5-8 for a summary of plan characteristics. With reduced energy generation requirements, reduced capacity needs and postponement of the need for Lake Dorothy, the low forecast Lake Dorothy plan has an estimated total discounted plan cost of $86.1 million. This figure can be compared to that for the thermal plan with the same forecast, $122.6 million. With the high load growth forecast, Lake Dorothy is brought on line in 1993, as shown on Table 5-9. Its energy potential is fully utilized by 1998; diesel units provide the supplemental generation from that point on, ending up contributing 19 percent of total net generation in the final years of the planning period. Total discounted plan costs for this scenario are $238.7 million, which compares very favorably to the high forecast thermal case ($448.1 million). 0599C doo) JUNPLAN OCTOBER 18, 1984 TABLE 5-7 DOROTHY = 1996 JUNEAU 20-YEAR PLAWING STUDY (w/Seoerate T-Line) SUMMARY OF RESULTS 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 PERK DEMAND FORECAST (MH) 41.30 55.10 57.90 60.30 62.60 64.80 66.60 68.50 70.40 72.40 74.40 76.50 78.60 80.70 82.90 85.20 87.50 89.90 92.30 94,80 94.80 94,80 94,80 94.80 34,80 94.80 94.80 EXISTING & COMMITTED HYDRO RESOURCES 5.62 8.62 8.62 8.62 8.62 8.62 862 8.62 8.62 8.62 8.62 8.62 34.32 34.32 34.32 34.32 34.32 M32 W.32 WR UR MUR WR UR WR WR (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 68.00 68.00 68.00 65.50 63.00 63.00 63.00 63.00 63.00 60.50 60.50 60.50 62.50 62.50 60.00 CAPACITY AVAILABLE TO MEET PEAK (MM) 64.54 79.84 79,84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 72.76 77.76 102.32 102.32 102.32 99.82 97,32 97.32 97,32 97.32 97.32 94,82 94.82 94.82 96.82 %.82 94,32 (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (MW) 23.24 24.74 21.94 18.29 15.99 12.59 10.79 5.39 3.49 0.36 -1.64 1.26 23.72 21.62 19.42 14.62 9.82 7.42 5.02 252 252 0.02 0.02 0.02 202 2,02 -0,48 ENERGY SALES FORECAST (Gwh) 215.10 230.60 242.40 252.60 262.40 271.50 279.00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 NEW HYDROELECTRIC #1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 44.02 53.70 63.30 73.98 84.46 95.26 106.42 117.92 117.92 117.92 117.92 117.92 117.92 117.92 117,92 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 EXISTING DIESEL 21,65 39.78 52.49 63,49 74.07 0.00 0,00 0,00 6.77 15.78 25.00 3456 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0,00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 0 1739 34831 28023 0 0 0 0 0 0 0 0 0 6917 0 0 11528 0 4611 FIXED O&M 0 0 0 0 0 0 0 0 0 0 18 3 40 40 40 HO HO %O HO BHO HO 392 Be 32 480 480 SIS VARIABLE O&M 173, 318 «420, 508 593. 0 0 0 SH 12% 200 276 0 0 0 0 0 0 0 ° 0 0 0 0 0 0 0 PURCHASED ENERGY 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 FUEL COST 1538 2826 «37294510 Sebe 0 0 0 S4e 1299 2120 3019 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 1711 3144 4149 5018 5854 0 0 0 596 18821 37168 31353 340 340 340 340 30 %0 30 3O WO 7309 392 392 12007 480 S12 TOTAL DISCOUNTED PLAN COST ($000) 104577 LT-S JUNPLAN OCTOBER 22, 1984 DOROTHY LOW FORECAST 1984 «1985 1986 «1987 1988 PEAK DEMAND FORECAST (MW) 41.30 54,00 56.10 58.00 59.70 EXISTING & COMMITTED HYDRO RESOURCES 5.62 862 862 862 862 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 CAPACITY QVAILABLE TO MEET PEAK (MW) © 64.54 79.64 79.64 78.59 78.59 (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (MW) 23.24 25.84 23.74 20.59 18.89 ENERGY SALES FORECAST (Gwh) SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO NEW HYDROELECTRIC #1 0.00 0.00 0.00 0.00 0.00 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 NEW ORIME THERMAL 0.00 0.00 0.00 0.00 0.00 EXISTING DIESEL 21.65 34,83 44,5) 53.03 60.79 PLAN COSTS ($000) CASTTAL COSTS 0 0 0 0 0 FIXED O&M 0 0 0 0 0 VARIABLE 08m 173, 279-356 424 886 PURCHASED ENERGY 0 0 0 0 0 Fue. COST 1538 2474 «3162-3767 4319 TOTAL 1711 2753-3518 «4191-4805 TOTAL DISCOUNTED PLAN COST ($000) 86134 1989 1990 61.30 62.40 8.62 8.62 68.77 68.77 77.39 77.39 1991 63,60 8.62 65.27 73.89 16.09 14,99 10.29 0.00 0.00 0.00 0.00 0.00 ecoocooo 0.00 0.00 0.00 0.00 0.00 coocoo]s 0.00 0.00 0.00 0.00 0,00 coooos TABLE 5-8 JUNEAU 20-YEAR PLANNING STUDY SUMMARY OF RESULTS 1992 64.80 8.62 65.27 73.89 9.09 0.00 0.00 0.00 0.00 0.00 ecooooo 1993 1994 66.00 67.30 8.62 8.62 64.14 59.14 72.76 67.76 1995 68.60 8.62 59.14 67.76 6.76 0.46 0.84 0.00 0.00 0,00 0.00 0.00 cocoocoe 0.00 0.00 0.00 0.00 0.00 ocoooce 0.00 0.00 0.00 0.00 0,00 ecocooco]e 1996 70,00 8.62 63.00 71.62 1.62 0.00 0.00 0.00 0.00 4,83 19702 18 33 0 434 20192 1997 1998 71.40 72.80 1999 74,20 8.62 8.62 34,32 63.00 63.00 60.50 71.62 71.62 94,82 2000 2001 2002 2003 «2004 =2005 2006 | 2007 75.70 77.20 78,80 80.30 80.30 80.30 80.30 80,30 332 W432 W.32 H.32 3432 34.32 3632 34.32 58.00 58.00 58.00 58.00 56.00 45.50 45.50 45.50 92.32 92.32 92,32 92.32 92.32 79.82 79.82 79.62 0,22 1.18 20.62 16,62 15.12 13,52 12.02 12,02 -0.48 0.48 0.48 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.01 17.44 32525 25717 18 i 88139 0 0 1021 1662 33651 27536 23.92 0.00 0.00 0.00 0.00 BR. a & RoOO 30.65 0.00 0.00 0.00 0.00 37.40 0.00 0,00 0.00 0.00 Rooc8. 4.37 0.00 0.00 0.00 0.00 Re bd Rococo 51.43 0.00 0.00 0.00 0.00 51.43 0.00 0.00 51.43 0.00 0.00 0.00 0.00 51.43 0.00 0.00 0.00 0.00 Scccts Bec o8. 51.43 0.00 0.00 0,00 0.00 2008 §=2009 2010 80,30 80.30 80.30 H.32 34.32 34.32 47.50 47.50 45.00 81.82 61.82 79.32 1.52 51.43 0.00 0.00 0.00 0,00 Boo SB 1.52 51.43 0.00 0.00 0.00 0.00 Biciciotic 0.8 215.10 226.00 235.00 242,90 250.10 256.70 261.40 266.40 271.50 276.80 262. 10 287.50 293.20 298,90 304,80 310.80 317.00 323.20 329,60 336.10 336.10 336.10 336.10 336,10 336.10 336.10 336,10 205.59 205.59 205.59 205.59 205.59 273.51 278.58 283.98 289.49 295.21 300.96 306.80 308.16 308,16 308.16 308.16 308.16 308.16 308,16 308. 16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 51.43 0.00 0.00 0.00 0.00 8T-S UNDLAN OCTOBER 22, 1984 DOROTHY = 1993 +10 =GRECAST 1984 1985 1986 19871988 ERX DEMAND FORECAST (MW) 41,30 55.70 59.20 62.50 65.70 EXISTING & COMMITTED HYD9O RESOURCES 5.82 6.62 8.62 6.62 8.62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 CAPACITY AVATLABLE TO MEET PEAK (MW) 64,54 79,84 79.84 78.59 78.59 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MH) 23.24 24.14 20.64 16.09 12,89 ENERBY SALES FORECAST (Gwh) SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO NEW HYDROEL! 0.00 0.00 0,00 0.00 0,00 NEW HYDROELEC 0.00 0.00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0,00 0,00 0,00 NEW DIME THEQMAL 0.00 0.00 0.00 0.00 0.00 EXISTING DIESEL 21,65 42.89 58.74 73.22 87.91 BLAN COSTS ($000) CASITAL COSTS 0 0 0 0 0 FIXED Ga 0 0 0 0 0 VARIABLE 08M 173, 343 «470586703 SURCMASED ENERGY 0 0 0 0 0 FUEL COST 1538 3047) 4172 «5201 = 6245 TOTAL 1711 3330 4642 «5787-6948 TOTAL DISCOUNTED PLAN COST ($000) 283731 1989 68.90 8.62 68.77 77.39 8.49 0.00 0.00 0.00 0.00 0.00 coooos 1990 71.60 8.62 68.77 71.39 5.79 0.00 0.00 0.00 0.00 12.30 17396 0 98 0 927 18421 1991 74.50 8.62 65.27 73.89 0.61 0.00 0.00 0.00 0.00 25.43 32525, 0 203 0 1974 34703 TABLE 5-9 SLNEAS 20-YEAR GLANNING STUDY SUYYRRY OF 2ESL7S 1992 77.50 8.62 70.27 1993 1994 1995 1996 80.60 83.90 87.20 90.60 34032 34.32 H.32 34.32 69.14 64.14 64.14 63.00 78.89 103.46 98.46 98.46 97.32 1.39 22,86 14.56 11.26 6.72 0,00 0.00 0.00 0.00 39,02 28023 { sie 0 319 3.472 53.16 0.00 0.00 0.00 0,00 67.98 83.35 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 Bocok. 1997 94.00 34.32 63.00 97.32 3.32 1338 1999 2000 2001 92002 «2003 2004 «2005 «2006 «2007 2008) 2009 2010 97.70 103.40 205,30 109.40 113.60 117,90 117.90 117.90 117.90 117.90 117.90 117.90 117.90 4.32 63.00 97.32 0.38 34,32 34,32 34.32 34.32 34.32 H32 H.32 H.32 WR UB MR 32 65.50 73.00 73.00 78.00 83.00 83.00 85.50 65.50 85.50 82.50 82.50 85.00 99.82 107.32 107.32 112.32 117.32 117.32 119.82 119,82 119,82 116.82 116.82 119.32 71.58 2.02 -2.08 -1.28 -0.58 -0.58 1.92 1.92 1.92 -1.08 -1.08 1.42 215,10 233,50 248.20 261.60 275.20 288.50 300.10 312.20 324.70 337.70 351.30 365.40 379.40 394.00 409.20 424,90 441.20 458.20 475.80 494.00 494.00 494.00 494,00 494.00 494.00 494.00 494.00 205.59 205.59 205.59 205.59 205.59 307.90 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 98.66 114.62 126.00 126.00 126.00 126.00 126.00 126.00 126.00 126.00 126.00 126.00 126.00 126.00 126.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 3.23 BR oaR. 0.00 0.00 0.00 0.00 29.35 29.35 69.32 69,32 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 29.35 58.69 58.69 98.66 69.32 39.97 39.97 0.00 0.00 0,00 0.00 0.00 0.00 0.00 22.51 40,43 0.00 0.00 0.00 59.15 0.00 0,00 0.00 78. 56 0.00 0.00 29.35 69, 32 0.00 0.00 29.35 69. 32 2306 9222 0 0 40 0375) «375392 410 410 480 550 550 602 180 323) «473628789 789 789 789 789 789 789 789 0 0 0 0 0 0 0 0 0 0 0 0 2213 4094 «6171 441 10595 10595 10595 10595 10595 10270 10270 9828 5038 9404 709 11768 18215 11794 21086 11864 11864 24947 11609 2414 4611 0 2306 6422 0 13338 0 13195 Other long-term plans centered on projects such as Sweetheart Lake and Thomas Bay would also compare favorably to the Base Case Plan under certain load forecasts. Such plans, however, could not compete in cost with the Lake Dorothy Project plan and were therefore not evaluated in detail. Nonetheless, both projects offer very significant unit cost advantages over thermal generation options and merit continued planning attention, especially in terms of an overall Southeast Alaska power plan. The preferred hydroelectric plan was subjected to several sets of sensitivity tests. The first set explored the sensitivity of plan cost to variation in project timing, assuming the mid-range load growth forecast. Plan costs were evaluated when Lake Dorothy is placed in service in 1993 and 1999 for comparison with the 1996 on-line case earlier described. Placing Lake Dorothy in service in 1993 negates the need for supplemental diesel generation for an additional three years (1993 through 1995), but the associated cost savings are more than offset by the cost penalty realized by advancing Lake Dorothy construction. As shown on Table 5-10, total discounted plan costs rise from $104.6 million to $106.5 million when Lake Dorothy completion is advanced from 1996 to 1993. JTable 5-11 presents the plan summary for the case when Lake Dorothy is postponed three years to 1999. In this case, the costs of additional supplemental diesel generation exceed the savings associated with delaying the Lake Dorothy Project. Total plan costs rise from the $104.6 million characteristic of the 1996 on-line date to $109.4 million. Sensitivity of Lake Dorothy plan costs to modified fuel cost assumptions was also explored. Table 5-12 shows the results of the mid-range forecast Lake Dorothy plan when zero fuel price escalation is assumed. Total discounted plan costs fall only slightly from the $104.6 million to $103.8 million. This relative insensitivity reflects the vary limited amount of diesel fuel utilized in the Lake Dorothy plan after 1988. The insensitivity of the Lake Dorothy plan is an important favorable characteristic, that would become extremely valuable in the event that oi] prices exceed the assumed price trend. 5.6 INTERCONNECTION PLANS The planning model was also used to evaluate two interconnection-based plans. The third interconnection option, the Snettisham-to-Juneau 100kV DC submarine cable neither provides any additional power, in and of itself, nor does it increase Snettisham reliability sufficiently to alter the treatment of reserve capacity. It was not included as part of a long-term plan. The relative standing of the remaining two interconnection options, in terms of unit energy cost, varies as a function of the assumed purchase price for power and of the amount of power transferred (Refer to Table 3-1). A long-term power supply plan was formulated for each of the options. 0599C 5-19 02-S JUNPLAN OCTOBER 18, 1984 TABLE 5-10 DOROTHY = 1993 JUNEAU 20-YEAR OLANNING STUDY (w/Severate ‘-Line) SUPMARY GF RESULTS 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 «2005 2006 «2007 2008 «2009-2010 PEAK DEMAND FORECAST (MW) 41.30 55.10 57.90 60.30 62.60 64.80 66.60 68.50 70.40 72.40 74,40 76.50 78.60 80.70 62,90 85.20 87.50 89.90 92,30 94.80 94.80 94.80 94.80 94.80 94.80 94,80 94.80 EXISTING & COMMITTED HYDRO RESOURCES 5.82 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 36.32 34,32 34.32 34.32 34.32 34.32 34,32 34.32 34.32 34.32 34.32 34.32 32 M32 H.32 M32 34.32 U.32 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 58.00 58.00 58.00 63.00 63.00 60.50 60.50 60.50 62.50 62.50 60.00 CAPACITY AVAILABLE TO MEET PEAK (Ml) © 64.54 79,84 79.84 78.59 78.59 77.39 77.39 73,89 73.89 96.46 93.46 93.46 92.32 92,32 92.32 89.82 92.32 92.32 92.32 97.32 97.32 94.82 94.62 94.82 96.82 96.82 96,32 (WITH SNETTISHAM T-LINE OUT OF SERVICE) RESERVE STATUS (MW) 23.24 24.74 21.94 18.29 15.99 12.59 10.79 5.39 3.49 26.06 19.06 16.9% 13.72 11.62 9.42 4.62 4.82 2.42 0.02 252 252 0.02 0.02 0.02 202 2.02 0.48 ENERGY SALES FORECAST (Gwh) 215.10 230.60 242.40 252.60 262.40 271.50 279.00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308,16 308.16 308.16 308.16 308.16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 NEW HYDROELECTRIC #1 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0,00 0.00 15.78 25.00 34.56 44.02 53.70 63.30 73.98 B4.46 95,28 106.42 117.92 117,92 117.92 117.92 117.92 117.92 117,92 117.92 NEW HYDROELECTRIC #2 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 NEW PRINE THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0 0.00 0.00 0.00 EXISTING DIESEL 21.65 39.78 52.49 63.49 74.07 0.00 0.00 0.00 6.77 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 1739 32525 25717 0 0 0 0 0 0 0 2306 0 0 2306 0 6917 0 0 11526 0 46it FIXED 08" 0 0 0 0 0 0 0 0 0 35 35 MS WH WH WS WS Be Re Wl WO WO 32 Je 32 460 480 SIS VATIABLE O&M 173, 318 420, 508 5393 o 0 0 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Qo 0 0 0 DURCYASED ENERGY 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 FUEL COST 1538 2826 «37294510 S262 0 0 Oo 54 0 0 0 ° 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 1711 314441495018 = 5854 0 17396 32525 26313 305 35 WS 35S WS 305 305 2628 2 322 64S 340 7309 392 392 12007 480 “S126 TOTAL DISCOUNTED PLAN COST ($000) 106542 Té-s JUNPLAN OCTOBER 22. 1984 DOROTHY «= 1999 (w/Seoerate T-Line) 1984 PERK DEMAND FORECAST (MW) 41.30 EXISTING & COMMITTED HYDRO RESOURCES 5.62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58,72 CAPACITY AVAILABLE TO MEET PEAK (MW) = 64,54 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MW) 23.24 ENERGY SALES FORECAST (Gwh) SQURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO NEW HYDROELECTRIC #1 0.00 NEW HYDROELECTRIC #2 0.00 NEW TRANSMISSION IMPORT 0.00 NEW ORIME THERMAL 0.00 EXISTING DIESEL 21.65 PLAN COSTS ($000) CAPITAL COSTS 0 FIXED O&M 0 VARIABLE 08M 173 PURCHASED ENERGY 0 FUEL COST 1538 TOTAL 1712 TOTAL DISCOUNTED PLAN COST ($000) 109368 55.10 8.62 71,22 79.84 24.74 0.00 0.00 0.00 0.00 39.78 1986 7.9 8.62 71.22 79.84 21.94 0.00 0.00 0,00 0.00 52.49 1987 60.30 8.62 69.97 78, 59 18,29 0.00 0.00 0,00 0.00 63.49 1988 62.60 8.62 69.97 78.59 64. 80 6.62 68.77 71.393 1990 66.60 8.62 66.77 77.39 1991 68.50 8.62 65.27 73.89 1992 70. 40 8.62 65.27 73.89 TABLE 5-11 JUNEAU 20-288 PLAYING STUDY SUMMARY OF RESIS 1993 72.40 8.62 64.14 72.76 15.99 12.59 10.79 5.39 3.49 0.36 0.00 0.00 0.00 0.00 0,00 0.00 0.00 coooceo 0,00 0.00 0.00 0.00 0.00 eoooooo 0.00 0.00 0.00 0.00 0.00 ecoococoo 0.00 0.00 0.00 0.00 6.77 Rslotiole 0.00 0.00 0.00 0.00 15.78 126 1299 1425 1994 74,40 8. 62 64.14 72.76 1.64 0.00 0.00 0.00 0.00 25.00 2306 i 200 0 2120 4643 1995 1996 76.50 78,60 8.62 8.62 69.14 68.00 77.76 76.62 1.26 -1.98 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 34.56 44.02 2306 173% 3 38 27% (Se 0 0 3019 3961 5636 21744 1997 1998 1999 2000 2001 2002 2003 2004 «2005-2006 2007 80.70 82.90 85.20 87.50 89.90 92.30 94.80 94.80 94.80 94.80 94.80 8.62 8.62 34.32 34,32 34.32 34.32 34.32 M32 WH 34,32 34.32 73.00 73.00 70.50 68.00 68.00 68.00 68.00 68.00 60.50 60.50 60.50 B1.62 81.62 104,82 102,32 102,32 102.32 102.32 102,32 94.82 94.82 94.82 0.92 -1.28 19.62 14.82 12.42 10.02 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 53.70 63.30 34831 25717 53 53 4300 (6 0 0 4977 6043 40290 32319 73.98 84.46 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2008 2009 94.80 94.80 34,32 34,32 62.50 62.50 96.82 96.82 2010 94. 80 U3 60.00 94. 32 7.52 7.52 0.02 0.02 0.02 202 2.02 -0.48 215. 10 230,60 242,40 252,60 262.40 271.50 279.00 286,90 295.00 303,30 311.80 320.60 329.30 338,20 347.00 356.80 366,40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308.16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308,16 306.16 308.16 308.16 308,16 308,16 95.28 106.42 117.92 117,92 117,92 117.92 117.92 117,92 117.92 117.92 0.00 0.00 0.00 0,00 GocoHe 0.00 0.00 0.00 0.00 4sc0495 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $o058. 0.00 0.00 0.00 0.00 4611 515 0 0 0 ‘5126 cess JUNPLAN OCTOBER 22, 1984 TABLE 5-12 DOROTHY = 1996 JUNEAU 29-YE02 O_ANNING S“UDY (w/Severate T-Line) SUMMARY DF RESULTS (Zero Fuel Escalation) 1984 1985 1986 1987 1988 «1989 1990 199. 1992 1933 1994 1995 199 1997 1998 1999 2000 2001 «22 ©2003 2004 «= AWS) 20068» 2007 200 2009-2010 DEAK DEMAND FORECAST (Mk) 41,30 55.10 57.90 60.30 62.60 64.80 66.60 68.50 70.40 72.40 74.40 76.50 78.60 Q0.70 82.90 85.20 87.50 89.90 92.30 94.80 94.80 94.80 94.80 94.80 94.80 94.80 94.80 EXISTING & COMMITTED HYDRO RESOURCES 5.82 8.62 68.62 862 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 3432 34.32 34.32 34.32 34.32 34.32 34,32 34.32 34,32 34.32 34.32 34.32 3.32 34,32 34.32 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 68.00 68.00 68.00 65.50 63.00 63.00 63.00 63.00 63.00 60.50 60.50 60.50 62.50 62.50 60.00 CAPACITY AVAILABLE TO MEET PEAK (MW) © 64.54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 72.76 77.76 102.32 102.32 102,32 99.82 97.32 97.32 97.32 97.32 97.32 94.82 94.62 96,82 96.62 96,82 94,32 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (HM) 23.24 24.74 21.94 18.29 15.99 12.59 10.79 5.39 3.49 0.36 -1.64 1.26 23.72 21.62 19.42 14.62 9.82 7.42 5.02 252 252 0.02 0.02 0.02 202 202 -0.48 ENERGY SALES FORECAST (Gwh) 215.10 230.60 242.40 252.60 262.40 271.50 279.00 286,90 295.00 303,30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376.30 386,50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308.16 308.16 308.16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308,16 308.16 308,16 308,16 308.16 308,16 308.16 NEW HYDROELECTRIC #1 9,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0.00 44.02 53.70 63.30 73.98 84.46 95.28 106.42 117.92 117.92 117.92 117.92 117,92 117,92 117.92 117.92 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0,00 0,00 0.00 0,00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 NEW PRIME THERMAL 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 EXISTING DIESEL 21.65 39.78 52.49 63.49 74.07 0.00 0,00 0,00 6.77 15.78 25.00 34.56 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0,00 0.00 PLAN COS*S ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 0 17396 34831 28023 0 0 0 0 0 0 0 0 0 6917 0 0 11528 0 4611 FIXED O8¥ 0 0 0 0 0 0 0 0 0 0 18 35 340 HO 40 0H HH HH HOsH2_s 392s 392 BO SIS VARIABLE O&M 173, 318 420, 508 593 0 0 0 S412 200 276 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 SURCHASED ENERGY 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Fue. COST 1538 2826 «37294510 S262 0 0 0 481) M21) 1776 2455 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL A711 3244-4149 5018 5854 0 0 0 S35 18643 36824 30789 340 40340 340 40 340 3H 340 340-7309 392) 392 12007 4805126, TOTAL DISCOUNTED PLAN COST ($000) 103769 In developing a Whitehorse-Juneau interconnection plan, it was assumed that a long-term firm power sales contract could be negotiated and that up to 118 GWh could be available for purchase at Whitehorse and for transfer south. Further, no account was taken of the possibility for project cost sharing with Haines and Skagway. Existing and committed hydroelectric generation was assumed at firm energy levels,and the plan was formulated in response to the mid-range forecast. The plan is summarized is Table 5-13. Standby thermal capacity is added beginning in 1994, and the interconnection comes on line in 1996. A total of 88MW of capacity is added during the planning period, 70 MW of which is standby diesel. The Whitehorse-Juneau transmission line helps satisfy reserve requirements and supplies all generation not provided by existing and committed hydroelectric projects. At the end of the planning period, the transmission line is providing 28 percent of total system generation. Total discounted plan costs are estimated at $223.6 - million, in comparison to the base case thermal plan cost of $248.4 million. The Tyee-Juneau interconnection plan differs from the Whitehorse plan, because the Tyee transmission line shares the Snettisham transmission facilities. In keeping with the reserve policy, the capacity associated with the Tyee transmission line, therefore, cannot be counted toward meeting the peak load requirement. As a result, additional diesel standby is required in this plan. Tables 5-14 and 5-15 show the summary results of the Tyee interconnection plan, using two Tyee power purchase price assumptions. At a price of 7.6 cents per kilowatt hour for Tyee energy, the total discounted plan cost is $278.2 million. With a purchase price of 2.5 cents, the plan cost becomes $203.7 million. 5.7 COST OF POWER FORECAST The estimates of project costs and total plan costs discussed in the previous sections of this report were presented in terms of constant 1984 dollars. This approach is useful for comparing alternatives on a common basis, but it does not offer an indication of the actual cost of power that can be expected with any particular project or plan. It is not possible to accurately forecast the future cost of power from a project for a combination of at least three reasons: the future rate of inflation cannot be accurately predicted, the financing terms have not been established, and the utilization of the project's potential output is variable depending on load growth and project timing. Assumptions have been made to address each of these sources of variability, and the resulting cost of power for the Lake Dorothy Project has been estimated. The result is only useful in conjunction with the assumptions, which follow: 0599C 5-23 ve-s JUNPLAN OCTOBER 22, 1984 WHITEHORSE INTERTIE 1996 PEAK DEMAND FORECAST (Mw) EXISTING & COMMITTED HYDRO RESOURCES (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES CAPACITY AVAILABLE TO MEET PEAK (MW) (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MW) ENERGY SALES FORECAST (Gwh) SOURCES OF GENERATION (Gh) EXISTING & COMMITTED HYDRO NEW HYDROELECTRIC #1 NEW HYDROELECTRIC #2 NEW TRANSMISSION IMPORT NEW PRIME THERMAL EXISTING DIESEL PLAN COSTS ($000) CAPITAL COSTS FIXED O&M VARIABLE O&M PURCHASED ENERGY FUEL COST TOTAL TOTAL DISCOUNTED PLAN COST ($000) 1984 1985 1986 1987 1988-1989 1990 41.30 55.10 57.90 60.30 62.60 64.80 66.60 5.82 8.62 8.62 862 862 862 8.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 64.54 79.84 79.84 78.59 78.59 77.39 77.39 23,24 24.74 21.94 18.29 15.99 12.59 10.79 215.10 230.60 242.40 252.60 262.40 271.50 279.00 205. 59 205.59 205.59 205.59 205.59 289.49 297.61 0.00 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 21.65 39.78 52.49 63.49 74.07 0.00 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 173, 318 420, 508 593 0 0 0 0 0 0 0 0 0 1538 2826 «37294510 S262 0 0 1711-3144 4149-5018 5854 0 0 223557 1991 68, 50 8.62 65.27 73.89 5.39 TABLE 5-13 JUNEAU G0-YEAR PLANNING STUDY SUMMARY OF RESULTS 1992 1993 1994 1995 1996 1997 1998 70.40 72.40 74,40 76.50 78.60 80.70 62.90 8.62 8.62 8.62 8.62 27.02 27.02 27.02 65.27 64.14 64.14 69.14 68.00 68.00 68.00 73.89 72.76 72.76 77.76 95.02 95.02 95.02 3.49 0.36 -1.64 1.26 16.42 14.32 12.12 1999 2000 27.02 27.02 27.02 27.02 27.02 27.02 65.50 63.00 68.00 68.00 73.00 73.00 92.52 9.02 95.02 95,02 100.02 100.02 7.32 2.52 5.12 272 5.22 5.22 2001 2002 2003 2004 «= 2005 2006 )«= 2007 2008-2009 85.20 87.50 89.90 92.30 94.80 94.80 2010 94,80 94.80 94.80 94.80 94,80 94.80 27.02 27.02 27.02 27.02 27.02 27.02 70.50 70.50 70.50 67.50 67.50 70.00 97.52 97.52 97.52 94.52 94.52 97.02 2.72 272 272 -0.28 0.28 2.22 286, 90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356,80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 306. 16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308,16 308,16 308,16 308.16 308.16 308.16 308.16 308.16 308,16 308,16 308.16 308,16 0.00 0.00 0.00 0.00 0,00 ococoocofo 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0,00° 44,02 53.70 0.00 0.00 0.00 0.00 0.00 0.00 6.77 15.78 25.00 3456 0.00 0,00 0,00 0.00 63.30 0.00 0.00 15369 59684 32019 0 0 0 0 18 35° 1567 15671567 12 200 276 0 0 0 0 0 0 1334 1627 1918 1299 2120 3019 0 0 0 16794 62021 35349 2901 3194 3485 Fisteeote 0.00 0.00 0.00 0.0 73.98 84.46 0.00 0.00 0.00 0.00 1567 1567 2241 e559 0 0 3808 4126 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0,00 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0,00 0.00 0.00 95.28 106,42 117.92 117,92 117.92 117,92 117,92 117.92 117.92 117,92 0.00 0.00 2306 1585 0 2887 0 6777 0.00 0.00 0 1585 0 3224 0 4809 0.00 0.00 2306 1602 0 3572 0 7480 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0 6917 0 0 9222 0 6917 1602 1655 1655 1655 1725 1725 1777 0 0 0 0 0 0 0 3572 «3572 «3572 «3572 «3572 «3572 3ST2 0 0 0 0 0 0 0 S174 12143 5227 5227 14519 5297. 12266 Se-s JUNOLAN OCTOBER 18, 1984 TYEE INTERTIE 1996 1964 1985 1986 1987 1988 =| 1989 PEAK DEMAND FORECAST (MW) 41.30 55.10 57.90 60.30 62.60 64.80 EXISTING & COMMITTED HYDRO RESOURCES 5.62 8.62 8.62 8.62 8.62 8.62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 CAPACITY AVAILABLE TO MEET PEAK (MW) 64,54 79.64 79.84 78.59 78.59 77.39 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MW) ENERGY SALES FORECAST (Gwh) SQURCES OF GENERATION (Gem) EXISTING & COMMITTED HYDRO NEW HYDQQELECTRIC #1 0.00 0.00 0.00 0.00 0.00 0.00 NEW HYDROELECTRIC #2 0.00 0.00 0,00 0.00 0.00 00 NEW TRANSMISSION IMPORT 0.00 0.00 0.00 0.00 0.00 0.00 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 EXISTING DIESEL 21.65 39.78 52.49 63.49 74,07 0.00 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 FINED Cow 9 0 0 0 0 0 VARIABLE C8" 173, 318 420 508 593. 0 PURCHASED ENERGY 0 0 0 0 0 0 Fue. COST 1538 2826 «= 37294510 Se62 0 TOTAL 171i 3244 4149) S018 5854 0 TOTAL DISCOUNTED PLAN COST ($000) 278243 1990 1991 66.60 68,50 8.62 8.62 68.77 65.27 77.39 73.89 0.00 0.00 0.00 0.00 0.00 cooooo 23.26 26.74 21.94 18,29 15.99 12.59 10.79 5.39 3.49 0.36 0,00 0.00 0.00 0.00 0.00 ecoocoofo TABLE 5-14 JUNEAU 2U-¥203 DAMNING STUDY SUMMARY CF RESULTS 1992 1993 1994 1995 19% 70.40 72.40 74.40 76.50 78.60 8.62 8.62 8.62 8.62 8.62 65.27 64.14 64.14 69.14 73.00 73.89 72.76 72.76 77.76 81.62 1.64 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 6.77 15.78 25.00 0.00 0.00 0.00 0.00 0.00 44,02 0.00 0.00 34.56 0.00 33006 18206 2306 0 0 16 35 875 M12 200 «276 0 0 0 0 0 3720 S42 1299 2120-3019 0 5% 9645 35343 21536 6900 80.70 8.62 73.00 81.62 0.00 0.00 53.70 0.00 0.00 0 875 0 4538 0 SH3 1998 82.90 8.62 78.00 86.62 1.26 3.02 0.92 3.72 0.00 0.00 63.30 0.00 0.00 2306 892 8547 1999 2000 2001 «2002 2003 2004 = 2005 2006 2007 2008) 2009 20:0 85.20 87.50 89.90 92.30 94,80 94,80 94.80 94.80 94.80 94.60 94,80 94.80 8.62 8.62 8.62 8.62 8.62 662 8.62 862 8.62 8.62 8.62 8.62 75.50 78.00 83.00 83.00 68.00 68.00 85.50 85.50 65.50 87.50 87.50 9.00 84.12 86.62 91.62 91.62 6,62 %.62 94.12 94.12 94.12 96.12 96.12 96.62 71.08 -0.88 1.72 ~.68 1,62 1.82 0.68 -0.68 -0.68 1.32 1.32 3.82 215.10 230.60 242,40 252.60 262.40 271.50 279,00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308.16 308.16 308.16 308.16 308.16 308,16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308. 16 0.00 0.00 86.60 86.60 0.00 29.30 31.32 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73.98 84.46 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86.60 86.60 0.00 0.00 6.68 19,82 9.00 0.00 66.60 0.00 31.32 0.00 0.00 86. 60 0.00 3.32 0.00 0.00 86. 60 0.00 31.32 0.00 0.00 0.00 0.00 86.60 86.60 86.60 0.00 0.00 0.00 31.32 31.32 31.32 8727 1120 24 T3i9 2918 20318 2306 0 4S HS 251 ast 739 = 7319 3466-3466 14285 11980 6917 0 0 97° «(997987 1 StS 731973197319 3466 3466 3466 18949 12032 12032 11526 0 1085 1085 1 THY = 7319 3466 3466 23647 12120 0 2306 2306 0 90 927 97 0 0 69 159 7138-7319 7319 #5 2130 10353 11526 10535 92-S TUNPLAN OCTOBER 18, 1984 TABLE 5-15 TYEE INTERTIE 1996 JUNEAU 20-YEAR PLANNING STUDY Low Tyee Cost SUMMARY OF RESULTS 1984 1985 1986 1987 1988-1989 1990 1991 1992 1993 1994 1995 1996 «1997 1998 1999 2000 2001 2002 «2003 2004 «2005 2006-007 2008 200901 ERK DEMAND FORECAST (MW) 41,30 55.10 57,90 60.30 62.60 64.80 66.60 68.50 70.40 72.40 74.40 76.50 78.60 80.70 82.90 65.20 87.50 89.90 92.30 94.80 94.80 94.80 94.80 94.80 94.80 94.80 94.8 EXISTING & COMMITTED HYDRO RESOURCES 5.82 8.62 6.62 6.62 8.62 8.62 8.62 8.62 8.62 862 6.62 8.62 8.62 8.62 8.62 8.62 862 8.62 6.62 8.62 6.62 862 862 862 862 862 86 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERMAL RESOURCES 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 73.00 73.00 78.00 75,50 78.00 83.00 63.00 88.00 88.00 85.50 85.50 85.50 67.50 87.50 9.0 CAPACITY AVAILABLE TO MEET PEAK (MW) © 64,54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 72.76 77.76 B1.62 81.62 86.62 @4.12 86.62 91.62 91.62 96.62 96.62 94.12 94.12 94.12 %.12 %.12 98.6 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MH) 23,26 24.74 21.94 18.29 15.99 12.59 10.79 5.39 3.49 0.36 -1.66 1.26 3.02 0,92 3,72 -1.08 -0.88 1.72 0.68 1.82 1.82 +068 0.68 0.68 1.32 1.32 3.8 ENERGY SALES FORECAST (Gwh) 215.10 230.60 242.40 252.60 262.40 271.50 279,00 286.90 295.00 303.30 311.80 320.60 329.30 338.20 347.00 356.80 366,40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.0 SOURCES OF GENERATION (Gh) EXISTING & COMMITTED HYDRO 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306. 16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308.16 308, 16 308.16 308.16 308.16 308. 1) NEW HYDROELECTRIC #1 0.00 0,00 0.00 0,00 0,00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0 NEW HYDROELECTRIC #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0 NEW TRANSMISSION IMPORT 0,00 0,00 0.00 0.00 0,00 0,00 0,00 0,00 0,00 0.00 0,00 0,00 44.02 53.70 63.30 73.98 84.46 86.60 86.60 66.60 86.60 86.60 86.60 86.60 06.60 86.60 86,61 NEW PRIME THERMAL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 29.3) EXISTING DIESEL 21,65 39.78 52.49 63.49 74.07 0.00 0.00 0,00 6.77 15.78 25.00 34.56 0.00 0.00 0.00 0.00 0.00 6.68 19.82 31.32 31.32 31.32 31.32 31.32 31,32 31.32 0.0 PLAN COSTS ($000) CAPITAL COSTS 0 0 0 0 0 0 0 0 0 6220 33006 18206 2306 0 2306 0 2306 2306 0 2306 0 6917 0 0 11526 0 872 FIXED O8¥ 0 0 0 0 0 0 0 0 0 0 18 35° 675) «B75 B92 BSE 910 27 RT HHS MHS 997 997) 997 1085 1085112 VARIABLE O&M 173 318 «420, 508 593 0 0 0 SH 12 200 2% 0 0 0 0 0 1 ee CS -) +) rr -~) -~) ~) -) --) PURCHASED ENERGY 9 0 0 0 0 0 0 0 0 0 0 0 1236 1505 1774 2073 2367 2627 «2427 24272427 2h27 227) 2427) 2427) 2427) 7 FUEL COST 1538 2826 «37294510 S262 0 0 0 S42 1299 2120 3019 0 0 0 0 0 WS 2130 3466 3466 3466 3466 3466 3466 | 3466 ONE TOTAL 1711 3144 4149-5018 5854 0 0 0 S96 9645 35343 21536 4414 2379 4971 «2965 «5582 6634 «5643 9393-7088 «14057 7140 (7140 18755 7228 15428 TOTAL DISCOUNTED PLAN COST ($000) 203738 ° Inflation rate of 6 percent; ° Financing interest rate of 10 percent; ° Financing term of 35 years; ° Project operational as of 1995; ° Two alternative utilization rates: 50 percent and 100 percent; ° Total project cost (in 1984 dollars) of $71,920,000, with a three year construction cash flow of $16,451,000, $30,926,000, and $24,453,000; and ° Annual operation and maintenance cost of $305,000 (in 1984 dollars). Adding capitalized interest to the nominal construction cost gives an amount to be financed of $145.1 million. Level annual debt service would be $15.1 million. Adding the 1995 nominal operation and maintenance cost of $579,000, gives an annual revenue requirement of $15,679,000. With full utilization of the project's 126 GWh delivered energy, the resulting cost of power would be 12.4 cents per kilowatt hour in 1995. With 50 percent utilization, or 63 GWh, the unit energy cost would rise to 24.8 cents per kilowatt hour. This range of utilization (63 to 126 GWh) is representative of Juneau's forecasted requirement for new hydroelectric generation in the 1995 to 2005 time frame. The comparable 1995 cost of power estimates for diesel generation and several other hydroelectric projects are compared to the Lake Dorothy figures in the following tabulation. The estimates are based on the same utilization as was assumed for Lake Dorothy. The proportion of total output represented by the 126 GWh and 63 GWh amounts is shown in Parentheses in each case. 1995 ESTIMATED COST OF POWER (¢/kWh) 126 GWh Utilization 63 GWh Utilization Lake Dorothy 12.4 (100%) 24.8 (50%) Diesel 20.6 (N/A) 20.6 (N/A) Sweetheart Lake 18.1 (104%) 36.3 (52%) Thomas Bay 20.7 (74%) 41.3 (37%) Speel River 29.0 (33%) 58.0 (16%) Comparable nominal cost of power figures for the transmission intertie alternatives have not been estimated, because of the extreme variability in certain of the project parameters associated with the intertie options. Added to the uncertainty of inflation rate, 0599C 5-27 financing rate, and percent utilization that is common to all the power supply options, the intertie alternatives are characterized by the further uncertainty in the amount of power available at the source, the cost of that power, and the opportunity for shared costs and benefits. The estimated effect of Lake Dorothy costs on the overall system retail elective costs is discussed in Appendix 7.4, which can be found in Volume 2. 0599C 5-28 6.1 6.0 FINDINGS AND RECOMMENDATIONS STUDY FINDINGS Review of the information covered in the previous sections leads to several findings, which are enumerated in the following paragraphs. ° The combination of low, mid-range and high Juneau load growth forecasts developed by the Alaska Power Administration, along with an additional forecast developed in this study to reflect the possible introduction of a mining load, together provide a reasonable basis for long-term power supply planning. The forecast range in the year 2003 varies from 336 Gwh to 528 Gwh. This compares to actual 1983 energy sales of 198 Gwh. No single forecast should be used to the exclusion of the others. The future pattern of change in energy requirements and peak loads is highly uncertain and will likely remain so; long-term power planning should explicitly address that uncertainty. The losses experienced in the local transmission and distribution system are moderate. The 69 kV system needs no major extensions or upgrades through the planning period. The present reserve policy calls for maintaining sufficient capacity to meet peak loads, when the largest element of the system is out of service. Snettisham is currently the largest system element, and it will remain so through the planning period. Any future project that is part of Snettisham or relies on its transmission facilities does not contribute to meeting reserve requirements, given the present policy. Recent and currently planned diesel plant installations, added to provide cost effective supplemental winter energy, have resulted in a reserve margin sufficient to last ten years under the mid-range peak load forecast. When the need for additional capacity to meet peak loads again becomes a factor, consideration should be given to substituting an emergency short-term curtailment program of load shedding in lieu of a limited amount of standby thermal capacity. This recommendation is based on the improved reliability of the Snettisham transmission line since its relocation, and on the associated reduced down-time that can be expected in the event of line failure. Juneau is facing several years of increasing requirements for diesel generation to supplement energy available from its hydroelectric facilities. When Crater Lake is completed, the need for supplemental diesel generation will temporarily cease. Throughout the planning period, however, thermal plants will remain important for their capacity contribution toward meeting reserve requirements. The use of refurbished, EMD high-speed diesels is a sound and cost-effective approach for dealing with this interim 1075C 6-1 situation. In the near-term hydro deficit period, the lower EMD capital cost, as compared to medium speed prime diesel engine costs, offsets the extra fuel expense resulting from the EMD's 11 percent lower efficiency. In the period after Crater Lake, when the units are used in a standby mode, the high speed units will offer clear advantages. Thus, adding the EMD units is prudent for both short and long term requirements. o System costs are very sensitive to the amount of diesel generation needed to meet energy requirements. Based on estimated firm annual energy potential from existing and committed hydroelectric projects, up to 24 percent of total annual generation will have to be contributed by diesel units as 1988 approaches, assuming the mid-range load growth forecast. The percent grows appreciably with the higher forecasts. AELP, GHEA, and the City and Borough of Juneau have instituted, and continue to pursue, innovative and meaningful programs designed to minimize winter energy requirements. These programs, such as differential rate structures, dual-fuel incentives and thermal standards, offer the best opportunity in the short term for reducing the need for supplemental winter diesel generation. The availability of the Crater Lake phase of Snettisham will bring immediate, but short term, relief from reliance on diesel generation. The energy conservation and load management programs will, after about three years of ample hydroelectric-produced energy, again become important as a means to postpone Juneau's next major investment in power generation facilities. As experience is gained with these programs and their affects are measured, load growth forecasts should be reviewed accordingly. o Available to Juneau are several potential hydroelectric developments that offer cost advantages over additional thermal generation. Additionally, these hydroelectric projects offer the benefits of renewable energy and, once constructed, insulation from inflation and any relative fossil fuel price increases. o Among major resource addition options, the Lake Dorothy Hydroelectric Project offers clear advantages. Lake Dorothy's scale is well suited to forecasted load growth, it results in the lowest cost long-term plan, and it's substantial storage capability affords excellent opportunities for improving performance of other Juneau hydroelectric projects through coordinated operations. Consideration should be given to developing the project so that it operates independently of the Snettisham transmission facilities. Development in this manner will permit Lake Dorothy's capacity to be counted toward meeting reserve requirements. Also, consideration should be given to taking advantage of the project's large storage capability by designing the project with substantial capacity. Lake Dorothy could then be used very effectively to provide extra winter energy to complement Juneau's existing and committed hydroelectric resources. Depending on the path of future load growth and the cost of supplemental diesel generation, the 1075C 6-2 Lake Dorothy project could be needed early in the 1990's. Given project lead times for planning, site exploration, environmental data collection and analysis, design and permitting, preconstruction activities should begin soon. Having the Lake Dorothy project poised for construction at relatively short notice would introduce a great deal of flexibility into Juneau's power planning in the face of uncertain load growth trends. While not as cost effective as the Lake Dorothy project, interconnection options merit continued consideration. Advantages include contribution to a Southeast Alaska regional intertie, better utilization of existing generating resources, opportunity for the sharing of benefits and costs with other southeast Alaska communities and Canada, and operating savings arising from seasonal diversity and reserve sharing. Additionally, interconnection is inherently flexible, permitting accommodations to an uncertain future. Both the Lake Dorothy project and the Intertie options are expensive capital intensive developments. Early attention should be given to financing constraints that may preclude development. All else being equal, it is easier and less risky to finance relatively small projects. Unfortunately, Annex Creek expansion is the only small project reviewed in this report that offers unit costs competitive with diesel generation. Opportunities for small-scale hydroelectric development should continue to be sought. The Lake Dorothy hydroelectric plan results in the lowest long term costs to Juneau, irrespective of load forecast. The relative advantage of Lake Dorothy over the thermal plan increases with higher load growth forecasts. A comparison of total discounted plan costs (1984 constant dollars) for selected thermal, hydroelectric and interconnection plans is presented in lable 6-1. Not addressed in this table are regional benefits that may result from one or both interconnection alternatives. Optimal timing for Lake Dorothy completion is a function of load growth and diesel fuel costs. Referring to Table 6-2, total plan costs are fairly insensitive to variation in on-line dates between 1993 and 1999. This suggests that financing and cost of power considerations should play the dominant role in establishing the development timetable. The earliest indicated need for the project arises in the case of the high-range and mining forecasts, wherein existing and committed hydroelectric generation potential becomes insufficient beginning in 1990. In contrast to a thermal plan, the total system cost of the Lake Dorothy alternative offers a high degree of insulation from the affects of oil price variations (See Table 6-2). 1075C 6-3 TABLE 6-1 SUMMARY OF PLAN COSTS Total Discounted Plan Cost ($Million) lake Dorothy Interconnection Thermal Plan Plan Plan Low Forecast 122.6 86.1 Mid-Range Forecast 248.4 104.6 223.6/278.21/ High Forecast 448.1 283.7 Mining Forecast 558.6 V/ Whitehorse Intertie plan cost is $223.6 million and Tyee Intertie plan cost (assuming 7.6 ¢/kWh for the purchase of Tyee power) is $278.2 million. See Table 6-2 for results of alternative Tyee power purchase cost assumptions and other sensitivity tests. 1075C TABLE 6-2 SENSITIVITY TEST RESULTS Total Discounted Sensitivity Test Plan Plan Costs ($million) Lake Dorothy Timing 1993 106.5 (mid-range forecast) 1996 104.6 1999 109.4 Fuel Cost Escalation Base Assumption, Thermal 248.4 Base Assumption, Dorothy 104.6 Zero Escalation, Thermal 188.1 Zero Escalation, Dorothy 103.8 Tyee Power Purchase Tyee Intertie 278.2 Price (@ 7.6 ¢/kWh) Tyee Intertie 203.7 (@ 2.5 ¢/kWh) Lake Dorothy Trans- Shared Facilities with mission Facilities Snettisham 114.1 Separate Facilities 104.6 1075C 6.2 RECOMMENDED PLAN OF ACTION The foregoing suggest three major directions for Juneau's long term power supply planning. First, energy conservation and load management efforts should be continued over the next four years so as to reduce the need for supplemental diesel generation. Second, planning flexibility should be maintained by initiating the lengthy series of Lake Dorothy pre-construction activities so as to shorten the lead time required to place the project in service. Third, concurrent with pursuit of the Lake Dorothy Project, Juneau should encourage continued consideration of a regional interconnected system. Several specific recommended actions follow. Short Term Actions o Continue to emphasize innovative rate structures, dual fuel incentives, thermal building standards and other programs designed to reduce electrical energy requirements, particularly winter electrical energy use during the period of hydroelectric energy shortfall. ° Pursue present plans for installation of refurbished high speed diesels to insure the ability to provide supplemental diesel generation in a cost effective manner. Lake Dorothy Project Development o Initiate preconstruction activities for the Lake Dorothy Hydroelectric Project with the goal of being prepared to initiate construction as early as 1990. Meeting this milestone would permit Lake Dorothy to enter operation as early as 1993, if needed. Figure 6-1 indicates the primary activities leading to project completion, and the approximate duration associated with each. For Juneau to be prepared to respond to the full load growth forecast range in a cost effective manner, initial Lake Dorothy development activities should be undertaken in 1985. o Initial activities should include the identification and scoping of engineering and environmental issues and the initiation of baseline data collection to support timely resolution of those issues. An immediate need is for stream flow data collected at the outlet of Lake Dorothy. Local orographic effects associated with Lake Dorothy's high elevation necessitates installation of a stream gage at the lake outlet to improve the estimate of available flow for power generation. At the same time, the gage at the former site near tidewater will require reactivation to permit correlation with the gage at the upper site. o Subsequently, a detailed feasibility study should be undertaken to provide a preferred plan of development, a high confidence cost estimate, a reliable estimate of power production, identification 1075C 6-6 LAKE DOROTHY PRELIMINARY PROJECT SCHEDULE £9 BASELINE DATA ACQUISITION FEASIBILITY STUDY LICENSING AND PERMITTING FINANCE PLAN AND POWER SALES DETAILED DESIGN in YEAR 1 YEAR2 YEAR3 YEAR 4 YEARS YEAR6 YEAR7 YEAR8 YEARQ9Q YEAR 10 CONSTRUCTION JUNEAU AREA 20 YEAR POWER SUPPLY PLAN LAKE DOROTHY PRELIMINARY PROJECT SCHEDULE DATE NOV 1984 EBASCO SERVICES INCORPORATED of mitigation measures to minimize any adverse environmental affects, and an update of the preferred development timetable. The scope of the feasibility study and the presentation of results should be designed for ready incorporation into license and permit applications. The advisability of continuing with pre-construction activities should be thoroughly reviewed in light of the feasibility study results. Assuming a favorable feasibility study determination and non-federal project sponsorship, application should be made for a Federal Energy Regulatory Commission license to construct the project. In the latter stages of licensing, application should be made for other required permits. Concurrent with license application processing, a finance plan should be developed, cost of power estimates prepared, and power sales contracts finalized. Assuming resolution of power sales agreements and favorable findings from FERC's draft environmental impact statement, consideration should be given to initiation of detailed design. This decision should be influenced by a review of then current load growth forecasts and of the potential for realizing additional energy conservation and load management opportunities. Upon receipt of a license and completion of detailed design, a final review should be made of optimum project timing. Implementation of the finance plan and project construction should commence accordingly. Other Planning Considerations oO Throughout the development phases of the Lake Dorothy Project, Juneau should participate with other southeast Alaska communities, with state and federal power agencies and with Canadian officials in the continuing evaluation of a regional transmission system. Development of projects as cost effective and inherently flexible as Lake Dorothy can only complement an eventual Southeast Alaska Intertie and enhance the regional benefits to be realized by such an interconnected system. Periodically review load growth trends and the affects of energy conservation and load management programs with the objective of updating this long-term power supply plan and potentially postponing the next major investment in generating resources. 1075C APPENDIX 7.1 TABLES OF SIGNIFICANT DATA ANNEX CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: On Taku Inlet, 11 miles east of Juneau Initial Construction: 1915 Existing Expansion HYDROLOGY Drainage area, sq. mi. 6.15 Same Average annual streamflow, cfs 67.6 Same Maximum daily streamflow, cfs sos “-- Minimum daily streamflow, cfs -- - Period of record, years RESERVOIR (Existing) Normal maximum water surface elevation, fms1 844 Same Minimum water surface elevation, fms] 690 Reservoir area at normal pool, ac Total storage capacity, ac-ft 23,400 Type of regulation Seasonal Same DAM & SPILLWAY (Existing) Type limber Crib Same Number of gates None Height, ft 25 Same Top of dam elevation (WWP Datum), ft 884 Same Spillway crest elevation (WWP Datum), ft None None Year of construction 1935/36 INTAKE Type Invert elevation, ft WATER CONDUCTOR Flume size/length None Same Tunnel size/length 8'x8'/1,418' Penstock size/length 34"&42"/7,112' POWER STATION (New) Turbine type Impulse Impulse Number of units 2 1 Rated net head, ft 780 780 Unit rated flow, cfs Turbine unit rating, kW 2-1,750 1-2,900 Transformer, kV 4-2.3/23 Same 71068 7.1-1 ANNEX CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: On Taku Inlet, 11 miles east of Juneau Initial Construction: 1915 Existing Expansion _ TRANSMISSION (Existing) Type Steel & Wood Same H Pole Voltage, kv 23 Same Length, mi 15 Same POWER AND ENERGY Installed capacity, MW 3.5 +2.9 Average annual energy, MWH 24,840 +4,680 est. Firm annual energy, MWH 22,680 +1,200 82 51* Annual plant factor, % *Total plant 71068 7.1-2 GOLD CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: Powerhouse in Juneau Initial Construction: 1914 Existing ___Expansion HYDROLOGY Drainage area, sq. mi. 9.76 Average annual streamflow, cfs 108 Maximum daily streamflow, cfs -- Minimum daily streamflow, cfs 0 Period of record, years 42 RESERVOIR (Existing) Normal maximum water surface elevation, fms] Minimum water surface elevation, fms] Reservoir area at normal pool, ac Total storage capacity, ac-ft Type of regulation DAM & SPILLWAY (Existing) Type Number of gates Height, ft Top of dam elevation, fms] Spillway crest elevation, fms] Crest Length, ft Year of construction - Reconstructed INTAKE Type Invert elevation, fms] WATER CONDUCTOR Flume size/length Tunnel size/length WATER CONDUCTOR (continued) Penstock size/length 2nd Penstock size/length 7106B 7.1-3 Run-of -River Concrete None 8 1950 Tyrolian Weir 5'x5'/2800' None 48"& 36"/1700' 32"& 24"/1625' GOLD CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: Powerhouse in Juneau Initial Construction: 1914 _ Existing | Expansion POWER STATION (New) Turbine type Impulse Number of units 3 Rated net head, ft 225 (Gross) Unit rated flow, cfs 2-28,1-56 Plant Hydraulic Capacity, cfs 112 Turbine unit rating, kW 2-400; 1-800 Generator voltage, kV 2.4 Transformer, kV N/A TRANSMISSION (Existing) Type Grid Voltage, kv N/A Length, ft N/A POWER AND ENERGY Installed capacity, MW lino None Average annual energy, MWH 6,800 Firm annual energy, MWH None Annual plant factor, % 50 (est.) *Total plant 7106B as 1-4 SALMON CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: 2.5 Miles North Of Juneau (Upper Salmon) (Lower Salmon) Initial Construction: 1914 Existing | Expansion HYDROLOGY Drainage area, sq. mi. 11.0 11.0 Average annual streamflow, cfs 64.2 Maximum daily streamflow, cfs Minimum daily streamflow, cfs 2 2 Period of record, years RESERVOIR (Existing) Normal maximum water surface elevation, fms] 1,140 1,140 Minimum water surface elevation, fms] 1,019 1,019 Reservoir area at normal pool, ac Total storage capacity, ac-ft 12,000 12,000 Type of regulation Seasonal DAM & SPILLWAY (Existing) Type Concrete Arch Same Number of gates None Height, ft 167 Top of dam elevation, fms] eee Spillway crest elevation, fms] Crest Length, ft 648 Year of construction 1914 INTAKE Type Tunnel Same Invert elevation, fms] WATER CONDUCTOR Flume size/length N/A N/A Tunnel size/length N/A N/A Penstock size/length 40" & 30"/4,447' 42"/11,000' 7106B SALMON CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: 2.5 Miles North Of Juneau (Upper Salmon) (Lower Salmon) *Total plant 71068 7.1-6 Initial Construction: 1914 Existing Expansion __ POWER STATION (New) Turbine type Turgo Impulse Number of units 2 (1938) One Rated net head, ft 980 Unit rated flow, cfs 120 Turbine unit rating, kW 2-1400 6,700 Generator voltage, kV 2.4 2.4 (est.) Powerhouse dimensions, 1 x wx h, ft 57'x44x22' Transformer, kV 2.4/23 (est.) TRANSMISSION (Existing) Type Wood Pole Voltage, kv 23 Length, mi Unknown POWER AND ENERGY Installed capacity, MW 2.8 5.6* Average annual energy, MWH 13,680 26 ,000* Firm annual energy, MWH 9,480 Unknown Annual plant factor, % 44 54 CRATER LAKE (SNETTISHAM) HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: On Crater Creek near the mouth of Speel River, 28 miles southeast of Juneau Proposed HYDROLOGY Drainage area, sq. mi. 11.4 Average annual streamflow, cfs 193 Maximum daily streamflow, cfs Minimum daily streamflow, cfs == Period of record, years 18 RESERVOIR Normal maximum water surface elevation, fms] 1,022 Minimum water surface elevation, fms] 820 Reservoir area at normal pool, ac Total storage capacity, ac-ft 81,500 Type of regulation Seasonal DAM & SPILLWAY Type Natural Number of gates N/A Height, ft N/A Top of dam elevation, fms] N/A Spillway crest elevation, fms] 1,020 Crest Length, ft N/A Year of construction N/A INTAKE Type Lake Tap Invert elevation, fms] 800 (est.) WATER CONDUCTOR Flume size/length None Tunnel size/length 11' horseshoe/6,020' Penstock size/length 6'/1,903' 71068 Ue CRATER LAKE (SNETTISHAM) HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: On Crater Creek near the mouth of Speel River, 28 miles southeast of Juneau Proposed POWER STATION (New) Turbine type Francis Number of units 1 Rated net head, ft 945.5 Unit rated flow, cfs 300 Generator rating, MVA 34.5 Generator voltage, kV 13.8 Transformer, kV 13.8/138 TRANSMISSION (Existing) Type Existing Voltage, kv 138 Length, mi 45 POWER AND ENERGY Installed capacity, MW 27 Average annual energy, MWH 121,200 Firm annual energy, MWH 105,100 Annual plant factor, % 51 71068 7.1-8 LAKE DOROTHY HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: About 15 miles east of Juneau Proposed HYDROLOGY Drainage area, sq. mi. Te Average annual streamflow, cfs 100 Maximum daily streamflow, cfs - Minimum daily streamflow, cfs es Period of record, years 38 RESERVOIR Normal maximum water surface elevation, fms] 2,422 Minimum water surface elevation, fms] 2,259 Reservoir area at normal pool, ac Total storage capacity, ac-ft 130,000 Type of regulation Seasonal DAM & SPLLLWAY Type None Number of gates None Height, ft N/A Top of dam elevation, fms] N/A Spillway crest elevation, fms] N/A Crest length, ft N/A Year of construction N/A INTAKE Type Lake Tap Invert elevation, fms] 2,240 WATER CONDUCTOR Flume size/length None Tunnel size/length 11'/14,180' (TBM) Penstock size/length None 7106B 1.1-9 LAKE DOROTHY HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: About 15 miles east 7 of Juneau Proposed POWER STATION (New) Turbine type Pelton Number of units 2 Rated net head, ft 2,400 (est.) Unit rated flow, cfs 715 Turbine unit rating, kW 2-13,000 Generator rating, MVA Unknown Generator voltage, kV Unknown TRANSMISSION (Existing) Type Voltage, kv 138 kV Length, mi 4.5 POWER AND ENERGY Installed capacity, MW 26 Average annual energy, MWH 127,000 Firm annual energy, MWH Unknown Annual plant factor, % 56 71068 7.1-10 SWEETHEART LAKE HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: About 40 miles southeast of Juneau Proposed HYDROLOGY Drainage area, sq. mi. 35.2 Average annual streamflow, cfs 345 Maximum daily streamflow, cfs Minimum daily streamflow, cfs Period of record, years 13 RESERVOIR Normal maximum water surface elevation, fms] 684 Minimum water surface elevation, fms] 550 (est.) Reservoir area at normal pool, ac Total storage capacity, ac-ft 215,000 Type of regulation Seasonal DAM & SPILLWAY Type Concrete Arch Number of gates None Height, ft 200' Top of dam elevation, fms] 695' Spillway crest elevation, fms] 684 Crest length, ft Year of construction N/A INTAKE Type Reinforced Conc. Gate Tower Invert elevation, fms] 530 WATER CONDUCTOR Flume size/length None Tunnel size/length 11'/9,100' Penstock size/length 6.5'/2,600' 71068 7.1-11 SWEETHEART LAKE HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: About 40 miles southeast of Juneau Proposed POWER STATION (New) Turbine type Francis Number of units 2 Rated net head, ft 600 (est.) Unit rated flow, cfs 260 (est.) Turbine unit rating, kW 13,000 TRANSMISSION (Existing) Type Voltage, kv Length, mi POWER AND ENERGY Installed capacity, MW Average annual energy, MWH Firm annual energy, MWH Annual plant factor, % 7106B Tale Submarine cable 138, ac 6 26 125,000 Unknown 55 THOMAS BAY HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: On Cascade Creek, 16 miles Northeast of Petersburg, AK Proposed HYDROLOGY Drainage area, sq. mi. 18.9 Average annual streamflow, cfs 226 Maximum daily streamflow, cfs -- Minimum daily streamflow, cfs -- Period of record, years RESERVOIR (Existing) Normal maximum water surface elevation, fms] eons Minimum water surface elevation, fms] 1,300 Reservoir area at normal pool, ac 600 Total storage capacity, ac-ft 154,000 Type of regulation Seasonal DAM & SPILLWAY (Existing) Type Natural Number of gates None Height, ft N/A Top of dam elevation, fms] None Spillway crest elevation, fms] 1,515 Crest Length, ft N/A Year of construction N/A INTAKE Type Lake Tap Invert elevation, fms] 1,280 (est.) WATER CONDUCTOR Flume size/length None Tunnel size/length 11'/12,700' Penstock size/length 5'/2,000' 71068 71.1-13 THOMAS BAY HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: On Cascade Creek, 16 miles northeast of Petersburg, AK Proposed POWER STATION (New) Turbine type Pelton Number of units 3 Rated net head, ft 1,370 Unit rated flow, cfs 72 Turbine unit rating, kW 15,000 Transformer, kV 12.5/138 TRANSMISSION (Existing) Type Submarine Cable Voltage, kv 100 dc Length, mi . 110 POWER AND ENERGY Installed capacity, MW 44 Average annual energy, MWH 200,000 Firm annual energy, MWH 200,000 (est.) Annual plant factor, % 52 (est.) 71068 7.1-14 SPEEL RIVER HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: On Speel River 30 miles east of Juneau _ Proposed HYDROLOGY Drainage area, sq. mi. 194 Average annual streamflow, cfs 2,581 Maximum daily streamflow, cfs 35,600 Minimum daily streamflow, cfs 127 Period of record, years V/ RESERVOIR Normal maximum water surface elevation, fms] 325 Minimum water surface elevation, fms] 223 Reservoir area at normal pool, ac Unknown lotal storage capacity, ac ft 137,000 Type of regulation Seasonal DAM & SPLLLWAY (Existing) ‘lype Concrete Arch & Rockfill Number of gates None Height, ft 220 lop of dam elevation, fms] 330 Spillway crest elevation, fms| 325 Crest length, ft Unknown Year of construction N/A INTAKE Type Unknown Invert elevation, fms] 220 + WATER CONDUCTOR Flume size/length None Tunnel size/length 16'/3,200' Penstock size/length 14'/300' Surge Tank size/height 60'/210' Penstock thickness, in. Ae 71068 eee SPEEL RIVER HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: Proposed POWER STATION (New) Turbine type Francis Number of units 2 Rated net head, ft 300 + Unit rated flow, cfs 1,454 Plant Hydraulic Capacity, cfs 2,900 Turbine unit rating, kW 28,550 Generator voltage, kV 13.8 Transformer, kV 13.8/138 TRANSMISSION (Existing) Type Voltage, kv Length, mi POWER AND ENERGY Installed capacity, MW Average annual energy, MWH Firm annual energy, MWH Annual plant factor, % *Total plant 71068 SHEVA AC, overhead 138 Tea Sic 400,160 (est.) 375,000 (est.) 10 (est.) NUGGET CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: On tributary to Mendenhall River 14.5 miles northwest of Juneau Initial Construction: 1914 Existing _ Rehabilitation HYDROLOGY Drainage area, sq. mi. 16 16 Average annual streamflow, cfs 174.7 175 Maximum daily streamflow, cfs unk unk Minimum daily streamflow, cfs unk unk Period of record, yrs RESERVOIR Normal maximum water surface elevation fms] Minimum water surface elevation, fms] Reservoir area at normal pool, ac Total storage capacity, ac-ft Type of regulation DAM & SPILLWAY Type Number of gates Height, ft Top of dam elevation, fms] Spillway crest elevation, fms] INTAKE Type Invert elevation, fms] WATER CONDUCTOR Flume size/length Tunnel size/length Penstock size/length 7.1-17 3 (unofficial) 600 600 unk N/A Run-of -River Timber Crib None 27 unk unk Tunnel 600 Abandoned 700 600 243 12,000 Monthly Rockfill, Concrete Faced None 100 7104 700+ Tunnel 600 None 8' mod horseshoe/800' 4.5'/1,570' NUGGET CREEK HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: On tributary to Mendenhall River 14.5 miles northwest of Juneau Initial Construction: 1914 Existing Rehabilitation _ POWER STATION Turbine type Abandoned Francis Number of units 2 2 Rated net head, ft 490 615 Unit rated flow, cfs 125 Plant hydraulic capacity, cfs 250 Generator rating, kVA 6,000 Generator voltage, kV 13.8 Valve type Butterfly Transformer, kV 13.8/23 TRANSMISSION Type Abandoned Wood H pole Voltage, kV 23 Length, ft 10,600 POWER AND ENERGY Installed capacity, MW None 10.8 Average annual energy, MWH Firm annual energy, MWH 21,900 Annual plant factor, % 23 7.1-18 LONG LAKE (SNETTISHAM) HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE Location: Near the mouth of Speel Rive 28 miles southeast of Juneau vr, Initial Construction: Existing Expansion HYDROLOGY Drainage area, sq. mi. 30.25 Same Average annual streamflow, cfs 448 Same Maximum daily streamflow, cfs i -- Minimum daily streamflow, cfs “= .-- Period of record, years RESERVOIR (Existing) Normal maximum water surface elevation, fms] 818 885 Minimum water surface elevation, fms] 7104 Same Reservoir area at normal pool, ac 1,300 1,440 Total storage capacity, ac-ft 340,000 484,000 Type of regulation Seasonal Same DAM & SPILLWAY Type Concrete Weir Concrete Gravity Number of gates None None Height, ft 5 110 Top of dam elevation, ft 820 905 Spillway crest elevation, fms] 818 895 Year of construction 1972-75 INTAKE Type Lake Tap Same Invert elevation, ft 684 Same WATER CONDUCTOR Flume size/length None None Tunnel size/length 11.5'/8,230' Same Penstock size/length 8.5'/1,200' Same 71068 at-t9 LONG LAKE (SNETTISHAM) HYDROELECTRIC PROJECT SIGNIFICANT DATA TABLE (Continued) Location: Near the mouth of Speel River, 28 miles southeast of Juneau Initial Construction: Existing _ Expansion _ POWER STATION (New) Turbine type Francis None Number of units 2 N/A Rated net head, ft N/A Unit rated flow, cfs Turbine unit rating, kW 2-23,580 Same Transformer, kV 13.8/138 Same TRANSMISSION (Existing) Type Steel Tower Same Voltage, kv 138 Same Length, mi 45 Same POWER AND ENERGY Installed capacity, MW 46 Same Average annual energy, MWH 211,000 Firm annual energy, MWH 179,000 229 ,000* Annual plant factor, % 44 51 *Additional 50 GWh firm energy. 71068 7.1-20 APPENDIX 7.2 NEUBAUER REPORT MAY 16, 1984 ESTIMATE COSTS FOR PRIME POWER AND STANDBY GENERATION PLANTS Hay 16, 1984 T.£. NEUBAUER AND ASSOCIATES P. 0. Box 6097 Lynnwood, Washington 98036 SCOPE: This brief report presents data to support estimated costs of purchasing equipment and constructing diesel-fueled power plants either as prime power producers to supplement hydro generation, or as standby equipment to sustain electrical power in the event of failed hydro generation and/or its delivery system. The short time allocated to this task did not allow an in-depth examination of all possible alternatives or available equipment, but the examples studied are believed to provide representative costs with an order of accuracy sufficient to indicate relationship between alternatives. GENERATION ALTERNATIVES: The generating alternatives examined are confined to Giesel fueled reciprocating engines or gas turbines. Other alternatives exist, of course, but machines in these catagories are probably the most likely to be chosen because of availability, relatively low first cost, localized support and familiarity among the Alaskan utilities. Prime power generation requirements center around fuel economy, durability, low maintenance costs, and reliability. Superior fuel economy usually justifies heavier, slow speed diesels over nigh speed diesels, and invariably rules out simple cycle gas turbines. Combined cycle gas and steam turbine plants can compete with the best diesels, but usually only where they can be base loaded at total capacity and run long hours at constant full load; combined cycle plant efficiency falls quickly at part load. Very large, two-stroke engines as manufactured by Sulzer or H.A.N (commonly used for ship propulsion and called “cathedral engines” because of their cross-sectional shape) are probably tne most fuel efficient of all and are available in sizes from 2 m# to 40 m# and larger. They are also the most expensive, however, and even the recent increases in fuel prices have failed to provide justification for applying this class of engine to any great extent in the United States. An exception is a new plant in Sebring, Florida where two 20 mé Sulzers have been installed. The plant cost, which includes extensive waste heat recovery and a bottoming cycle steam turbine, is reported in the neighborhood of $50,000,000. High first cost, including expensive foundation and installation, and the lack of nearby support probably rule out this type of engine for the forseeable future in Alaska. Tne most likely candidate for prime power generation seems to be the medium Neavy-duty diesel (HOD) commonly availole in 1000 kW to 10, 000kW units. Several American manufacturers either produce their ow design (Transamerica Delaval, Cooper Energy Systems, Colt Industries Fairbanks/torse) or are licensed to manufacture engines of forein design (Colt Industries-Peilstick). Host of the prime power generation in Alaska by reciprocating diesels of 1000 kW and larger is of one of these manufacturers, with Transamerica Delaval (Enterprise) probably the most common. Standby generation presents an entirely different set of criteria. Fuel economy is probably at the bottom of the list, so long as operation is confined to only 200 or 300 nours a year. Reliability (adility to start promplty when needed and continue operation for as long as needed) and low first cost are primary considerations. Durability is of lesser imprtance than for prime power generation, since the macnine is not expected to operate many actual hours Guring a typical lifetime. Serviceability is also less important, since daily care and maintenance is not usually necessary. Therefore “packaged” units (engine-generators in individual, self-contained housings) may be preferred to multiple installations in conventional plant buildings. 7.2-1 Simple cycle gas turbines (“aircraft derivatives") are in many ways ideal Standby machines. They are light weight, usually easy to install, and can be started and put on line in a very short time. very little energy is needed to keep them in a “standby” condition; usually a smal] amount of lube 01] heating and dryers in the generator coils is sufficient. Ratings of simple cycle gas turbines are sensitive to inlet air temperature and altitude; ratings increase in cooler temperatures and lower (sea-level) altitudes. Since lower temperatures usually coincide witn nigher loads in Alaska, this feature of the gas turbine is no handicap. High speed (900 RPM and above) diesels are also widely used for standny applications. Probably the most common example is the EMD (Electro-Motive Division) 20 cylinder, 2-stroke diesel rated 2500 kW. The prime mover is commonly found in locomotives, but has also been adapted to stationary service Power generation. The units can be had as components to be installed in a conventional plant, or may be purchased “packaged” in self-contained enclosures Teady to plug in to a power system. Typically, fuel consumption is not quite as good as for medium speed, heavy duty machines, but is many times better than for @ gas turbine. Physical size and weight per kW will be greater than for a gas turbine, and installation costs (when foundations are considered) may be more. Heating of lube oil and jacket water is required to keep the unit in standby readiness. A longer warm-up period before loading may be required unless jacket water and oil are kept at near-operating temperatures at all times. Load Tatings are nearly independant of temperature up to 90° F and turbocharged engines are little affected by atmospheric pressure changes from sea-level to at least 2500 feet. To summarize, schemes requiring prime power generation (whether base loaded or peaking) will probably be served by the more efficient, medium speed 4 stroke heavy duty diesel. If hydro is the principal power source for all generation, however, the standby requirements could more appropriately be met by light, “air craft derivative” turbines or high-speed diesel engines. SIZE OF UNITS: Relating the “ideal” size of thea generating unit to tne system load depends mainly on operating philosophy, whether the plant is prime power or standaadby, and the availability of sizes among certain machines. Economy of scale competes against reliability afforded by multiple units. One large unit is often sufficient to carry peak system load in tne small Alaskan systems, but odviously provides no protection from outages during failures. Many small units increase the probability that enough will be operable to meet demand, but often per-unit first cost and operating and maintenance costs are greater. Units for prime power generation should be small enough to be operated near peak fuel efficiency when demand is minimum. A S m# machine operating 1 mW load is wasting fuel and likely to wear out faster than a fully loaded machine. Very small Alaskan utilities often lack the operating expertise and equipment required to connect two or more units together in parallel. Often these plants will have two or three units, any one of which will be large enough to carry the peak demand alone. In other cases, only one machine is larger enough to meet peak demand; the other(s) is(are) smaller and reserved for off-peak loads. Larger utilities do nave full time personnel and sophisticated control that allows paralleling, so that several units can be on line simultaneously. Typically, unit size within a single plant will range from 10% to 35% of system peak demand. The smaller units are usually the oloer units, left over froma time when system loads were smaller. Some of the older Air Force power plants used 12-100kW Cummins diesels to make up a 1200kW plant. The apparrent feeling was that more units provided greater security and allowed greater flexibility in loading. There are no figures available to compare operating costs for these Plants as opposed to the public or private utility. Standby plants are usually designed to provide capacity to just cover the system peak demand with some surplus for growth. Since fuel economy is not so important, matching loads to optimum operating points on a machine's fuel curve is usually neglected. The standby machine should be as inexpensive to install as possible, while still providing reliable start-up, ability to start cold loads, and maintain service until the primary power source is again available. Standby requirements usually favor one or two larger machines as opposed to a larger number of smaller units. USED MACHINERY: Diesel and gas turbine generators of all sizes and manufacture become available on the used market from time to time. The ubiquitous EMD probably heads the list in the high speed diesel, 2.5 m# catagory, simply because so many have been sold. Often these machines were installed for standby Quty, and have few running hours. With proper inspection and refurbishing as needed, they can be a relatively inexpensive alternative to new machines, particularly for standby applications. Occasionaly, prime power plants also come up for sale. The purchase price may 100k attractive, but the prospective. buyer must add the cost of moving (prime power machines will probably be neaver, and mounted directly on concrete foundations rather than skids) and Overhaul ing. Because prime power producers are required to run a nigh number of hours each year. used machines are likely to be worn out and require extensive rebuilding. Older units are usually less fuel efficient than their newer counterparts. Used units are often a good deal for the standby application. For prime power applications, good used machinery is narder to find and may not pay off in the long run. CAPITAL COSTS: Estimates of capital costs are derived from analysis of two other Alaskan projects. These were the installation of a 7,000 kW medium speed Giesel in the Kodiak Electric Association power plant completed in 1981, and the construction of a 5,500 kW standby plant at Auke Bay for Glacier Highway Electric Association completed in the spring of 1983. Other information included current estimates from representatives of Transamerica Delaval (Enterprise), EMD, and Solar of the current selling price of new and used machines. Construction costs have been reduced to per unit ($/kW) costs in order to give a truer picture. Some facilities, particularly at the GHEA plant, have a larger Capacity than the present installation; for instance, the site improvements at GHEA are adequate for a plant of 20,000 kW. Therefore, total cost in each line item has been divided by the “Kilowatt Potential” of that item to produce a per-k®¥ cost for each item. The Kodiak project did not include any expenditures in tne FERC accounts of Land and Land Rights (340) or Structures and Improvements (341), since the installation was made in an existing plant building on property already owned by the utility. Costs in account 342, Fuel Holders and Producers represent only extension of the fuel system to the new generator, and do not include any of the bulk storage or distribution system which was already in existance. Likewise, costs in account 345, (Accessory Electrical Equipment) are low because much of the station service, building distribution, step-up substation, etc. was installed previously. Tne Glacier Highway Electric Association standby plant is much more representative of total construction of a new plant. No land purchase was necessary, but all other accounts started from scratch. Site improvement costs are probably at the high end of the spectrum, because of the unimproved state of the property, and because of tne extensive landscaping and replacement of organic material required. Building costs are also high for a standby plant, although probably about average for a prime power plant. Foundation costs were hign because of the indeterminate nature of the sudsoil conditions and the requirement for a driven pile foundation. Accounts 342 (Fuel) and 345 (Accessory Electric) would be about the same for either standby or prime power plants. Inflation factors are simply the multiplication of inflation factors for each year since construction was completed. For Kodiak’s project, an inflation factor of 1.1 (10%) was used for 1981-82 and 1982-83, and and inflation factor of 1.05 (5%) used for 1983-84 resulting in an overall inflation factor of 1.27 (1.1 x 1.1 x 1.05 = 1.27). For the GHEA project, and inflation factor of 1.05 (5%) was used. Land costs are hignly variable. The estimate is based on the assumption that the minimum area necessary for a 20 mW plant (in itself, an arbitrary assumption) 1s two acres. Two acres, or adout 83,000 square feet, should allow the construction of a plant building or space for several packaged generating units, a small substation area, and 300,000 gallons or more of fuel storage, witn some space allowed at the boundaries for screening and setbacks. No space 1s allowed for storage and maintenace buildings, administration, etc. More area mignt be necessary if tne lot is on a nillsice, or has access or other problems. No attempt nas been made to research current prices for industrial zoned Parcels, but it is believed that asking prices range from $1.50 to $3.00 per square foot. Therefore, a 2 acre lot could run from about $125,00 to $250, 000, or $6.25 to $12.50 per kW of installed plant capacity. Estimated capital costs for prime power and standby plant construction are shown on the following tables and grapns. “Low” and “nigh” estimates reflect the variability in land costs, installation difficulty, differences in unit costs for different size machines, etc. A wider variation is possible for standby Plants because the plant building may be ommitteo if modularized units are installed. Foundation requirements can also vary widely, from extensive pile or concrete structures to little more than railroad ties on a gravel bed. Fuel storage and fuel system requirements would be about the same for either type of Plant; owner's overnead and engineering costs are also judged to be roughly equal. Generally, lower costs in the 343 and 344 accounts are associated with larger machines (say, 10 mW capacity vs 5 mW capacity). In the standby plant estimate, lower generator/prime mover costs are for used equipment, refurbished to “like new’ condition. Accounts 343 and 344 are lumped together, since Quotations are seldom broken down between generator and prime mover for units of tnis size. 1402 COST SUMMARY - PRIME POWER FERC ACCT @ UNIT COST ($/K¥) PLANT COST, 20 MW CAPACITY DESCRIPTION Low HIGH Low HICH 341 342 343 344 Structures and Inprovenents Sitework $ 2.50 $ 8.00 $ 50,000.00 $ 160,000.00 Plant Building $ 8.00 $ 11.00 $ 160,000.00 $ 220,000.00 Foundation $ 8.00 $ 13.50 $ 160,000.00 $ 270,000 .00 Interior Finish and Systems $ 12.00 $ 16.00 $ 240,000.00 $ 320,000 .00 Hiscelleneous $ 6.00$ 8.00 $¢ 120,000.00 $ 160,000.00 $ 36.50 $ 56.50 $ 730,000.00 $ 1,130,000.00 Fuel Holders, Producers 6 Acc. Diking and Containnent $ 1.00 $ 2.00 $ 20,000.00 $ 40,000.00 Bulk Storage $ 12.00 $ 13.00 $ 240,000.00 $ 260,000 .00 Transfer Systen $ 0.75$ 0.80 $¢ 15,000.00 $ 16,000.00 Plant Distribution $ 8.25$ 9.00 § 165,000.00 $ 180,000.00 Hiscellaneous $ 2.2 $ 2.50 $ 4,000.00 $ 50,000.00 Prine Movers Generators HOD Nediun Speed Diesel Gen $367.00 $476.00 $ 7,340,000.00 $ 9.520,000.00 Foundation $ 12.00 $ 18.00 $ 240,000.00 $ 360,000.00 Generator Installation $ 25.00 $ 35.00 $ $00,000.00 $ 700,000 .00 Engine Installation 00 $ 80.00 $ 000.00 00 -00 Accessory Electrical Equip. Switchgear $ 10.00 $ 15.00 $ 200,000.00 $ 300,000 .00 Step-up Transformation $ 6.00$ 7.00 §$ 120,000.00 $ 140,000.00 Miscellaneous $ 0.75$ 1.00 $ 15,000.00 $ 20.000 .00 Installation $ 11.00 $ 12.00 $ 220,000.00 $ 240,000.00 $ 27.75 $ 35.00 $ 555,000.00 $ 700 ,000 .00 OQuner’s Overhead $ 15.00 $ 25.00 $ 300,000.00 $ 500 , 000 .00 Engineering Design + Contract Administration GRAND TOTAL $627.75 $823.30 12,555,000.00 $ 16, 466,000.00 o AVERAGE $725.52 $ 14,510,500 .00 ESTIMATED PRIME POWER PLANT COSTS Project 1402.4101 COST ($/KW) LOW ESTIMATE U “THIGH ESTIMATE 1000 900 700 600 400 300 200 100 340 341 342 343-344 345 OH ENGR TOTAL AVE CATAGORY 1402 COST SUMMARY -STAMDBY POWER FERC UNIT COST ($/KW) PLANT COST, 20 MW CAPACITY acc 'T ss DESCRIPTION Low HICH Lou WICH Sssssssssssssssssssss= 340 Land and Land Rights $ 6.25 $ 12.50 $ 125,000.00 $ 250. 000 .00 341 = Structures and Inprovenents Sitework $ 2.50$ 8.00 $ 50.000.00 $ 160,000.00 Plant Building $ 0.0 $ 10.00 $ 0.0 $ 200,000.00 Foundation $ 0.0 $ 13.50 $ 0.0 $ 270,000 .00 Interior Finish and Systems $ 0.0 $ 16.00 $ 0.0 $ 320,000.00 Miscellaneous $ 3.00$ 8.00 $ 60,000.00 $ 160, 000 .00 342 Fuel Holders, Producers 6 Acc. Diking and Containnent $ 1.00 $ 2.00 $ 20,000.00 $ 40.000 .00 Bulk Storage $12.00$13.00 ¢ 240,000.00 $ 260,000 .00 Transfer Systen $ 0.75$ 0.80 §$ 15,000.00 $ 16,000 .00 Plant Distribution $ 8.25$ 9.00 §$ 165,000.00 $ 180,000.00 Wiscellaneous $ 2.23 $ 2.50 § 4,000.00 $ 50,000.00 $ 24.25 $27.30 $ 485.000.00 $ 546,000 .00 343. Prine Movers 344 Generators High Speed Diese) or Turb. $275.00 $320.00 $ 5,500,000.00 $ 6,400,000.00 Foundation $ 8.00 $ 10.00 $ 160,000.00 $ 200,000 .00 Generator Installation $ 10.00 $ 35.00 $ 200,000.00 $ 700,000 .00 Engine Installation $ 25.00 $ 80.00 $ 500,000.00 $ 1,600,000.00 345 Accessory Electrical Equip. Switchgear 10 is $ 200,000.00 $ 300,000 .00 Step-up Transfornation 6 7. $3 120,000.00 $ 140,000.00 Miscellaneous 75 1 $ 15,000.00 $ 20.000 .00 Installation 11 12. $ 220,000.00 $ 240, 000 .00 $ 27.75 $ 35.00 $ 555,000.00 $ 700 , 000 .00 Quner’s Overhead $15.00 $ 25.00 § 300,000.00 § 500 , 000 .00 Engineering Design $ 22.00 $ 26.00 $ 440,000.00 $ Contract Administration $ 27.00$ 32.00 $ 540,000.00$ 640,000.00 AVERAGE $552.02 $ 11,040,500 .00 STANDBY POWER PLANT COSTS Project 1402.4101 COST ($/KW¥) Low Estimate U High Estimate 800 700 400 300 200 340 341 342 343-344 345 OH ENGR TOTAL AVE CATEGORY MAINTENANCE ANO OPERATION COST: An analysis of AEL&P’s Gold Creek and Lemon Creek diesel plants shows a wide variation in M & 0 cost between the two. 4&0 cost seems to be more directly tied to plant capacity than to k#nr production. M & 0 cost for the energy production in years 1977 to 1983 averaged 5.3¢ per kW@nr for Gold Creek plant, and only .8¢ per k#nr for the Lemon Creek plant. On a basis of per kW of installed capacity, the costs were $10.90 and $3.50 per kW, respectively. Some of the difference probably comes from the difference in the type of plants, and the fact that the Lemon Creek plant has newer equipment. Some of the variation may also be explained by accounting custom it is not known if tne Lemon Creek figures include all assignable overneads, for instance. FUEL RATES: Quoted fuel rates for simple cycle gas turbines vary greatly. Solar lists 16,250 BTU/kenr for the Saturn (1000 kW), 13,930 BTU/kWnr for tne Centaur (3400 k#) and 11,000 BTU/kwnr for the Mars (10,500 k¥). Assuming fuel witn a lower heating value of 125,000 BTU per gallon, these translate into 7.69, 8.97, and 11.36 k#hr per gallon respectively. Actual rates will be less, since tne Quoted rates are at full load under ideal conditions. Figures for AEL&P’s 17.5 mé Pratt and whitneys show about 7.8 kWhr per gallon. This realively poor rate May be due running at part load and fuel consumed due to start up. Rates of 8& to 10 kWhr per gallon are probably realistic for turbines. (0 High speed diesels regularly produce at the rate of 13 to 13.5 kWnr per gallon, while medium speed diesels offer rates at optimum loads of from 14.75 to 15.25 knrs per gallon. Unlike turbines, fuel rates for diesels are almost “flat” from full load Gown to approximately half load. CONSTRUCTION DURATION: Construction duration is affected by the scope of the project, the time of year, and the weather. The GHEA project, including wite work and all building erection and equipment installation, took about six months. Part of the most difficult work was done in the late fall and winter, although weather that particular year was unusually mild. Four to six months is probably the very minimum allowable for a standby plant not requiring extensive sitework or plant building construction. Twelve months is more realistic for a prime power plant. : Equipment lead time also varies. Used equipment may be immediately availaple, although three or four months should be available should be allowed for factory Tefurbisning. Solar is quoting 8 montns for tne smaller macnines and about 12 Months for the 10 mW Mars, after approval of final drawings. Transamerica Delaval also estimates 12 montns after approval of final orawings for tneir medium speed diesels. Other equipment, such as switchgear, power transformers, etc. typically take from 6 to 9 montns. Total time from beginning of studies and planning to “on-line” should be estimated at from 15 to 30 months. LIFE EXPECTANCY: Life expectancy of any macnine depends neavily on tne kind of maintenance it receives and how hard it is used. Both diesels and turbines can fave useful service lives of over 100,000 nours, with major overnauls required at 30,000 to 50,000 hours. Medium speed diesels (less than 720 RPH) are considered to have a service life of 33 years by REA, with higher speed units having a life of 15 years. These are probably unrealistically high figures for prime power units. Although there are some machines in Alaska that are approaching that age, most are relagated to standby service and seldom produce much energy. Standby units may last much longer, since they should not run more than 200 to 300 hours per year. Properly cared for, little deterioration should occur, and the only reason to retire them might be lack of spare partrs. 10 EXHIBIT GHEA COST ANALYSIS KEA COST ANALYSIS AEL&P M&O COSTS 1402 - <A COST ANALYSIS PROJECT: Glacier Highway Standby Plant YEAR COMPLETED: 1983 eee eee ee ee — FERC KILOWATT INFLATION 1984 ACC'T # DESCRIPTION COST POTENTIAL COST/KW FACTOR COST/KW 340 Land and Land Rights 341 Structures and Improvements Site work $ 150, 000.00 20, 000 $ 2,950 1.05$ 7.88 Pre-Enginneered Bldg Package $ 75,000.00 18,000 $ 4.17 1.053 4.38 wood Piling $ 30, 000.00 18, 000 $ 1.67 1.05$ ie Misc. Owner Furnished Materials $ 16, 000.00 5,500 $ 2.91 1.05$ 3.05 Misc. Services Provided by Ower $ 23, 000.00 5,500 $ 4.18 1.05$ 4.39 Building Foundation $ 200, 000.00 18, 000 $ ait 1.05% 11.67 Building Erection $ 75, 000.00 18, 000 $ 4.17 1.05$ 4.38 Building Interior Finisn $ 270, 000.00 18, 000 $ 15.00 1.05$ 15375 $ 839, 000.00 $ 50.70 1.058 53.24 342 Fuel Holoers, Producers & Access. Bulk Stor. Tank, 120,000 gal. $ 90, 000.00 7,500 $ 12.00 1.05% 12.60 Fuel Diking and Containment $ 30,000.00 20,000$ 1.50 1.05$ 1.58 Fuel Transfer Pumps $ 15, 000.00 20, 000 $ 0.75 1.05$ 0.79 Fuel System Installation $ 150, 000.00 18, 000 $ 8.33 1.053 8.75 Misc. Owner Furnished Materials $ 1, 000.00 3,000 $ 0.33 1.05$ 0.35 Misc. Services by Owner $ 6,500.00 3,000 $ 2.17 1.05$ Zh “ 8 3 “ R & ¥ R ¥ Page 1 1402 - A COST ANALYSIS FERC KILOWATT INFLATION 1984 ACC'T # DESCRIPTION COST POTENTIAL COST/KW FACTOR COST/KW 343 Prime Movers Gas Turbine, Soler Centaur $ 370, 000.00 3,000 $ 123.33 1.05$ 129.50 Governor Replacement $ 8, 500.00 3,000 $ 2.83 1.05$ 2.98 Start-up Fuel $ 3,500.00 3,000 $ i? 1.05$ 1.2 Misc. Owner-Furnisnhed Materials $ 35, 000.00 3,000 $ 11.67 1.05% 12.25 Misc. Owner-Furnished Services $ 11, 000.00 3,000 $ 3.67 1.05$ 3.85 Turbine Installation $ 135, 000.00 3,000 $ 45.00 1.05$ 47.2 $ 563, 000.00 $ 187.67 1.05$ 197.05 344 Generators 3000 kW Generator $ 370, 000.00 3,000 $ 123.33 1.05$ 129.50 Misc. Owner-Furnished Services $ 9, 000.00 3,000 $ 3.00 1.053 3.15 Gererator Installetion $ 73, 000.00 3,000 $ 24.33 1.053 25.55 $ 452, 000.00 $ 150.67 1.05$ 158.20 Page 2 1402 - <A COST ANALYSIS FERC KILOWATT INFLATION 1984 ACCT # DESCRIPTION COST POTENTIAL COST/KW FACTOR COST/KW SSSsoessseeseseessse sees sees esses eSSseSreSeee SSS ese sess SS sss Sees sees ssessssssssssaessssessssessesssssosecs 345 Accessory Electrical EquipmentAccesso Step-up Transformer $ 60, 000.00 10,500 $ Ss71 1.05$ 6.00 Auxillary Generator $ 37, 000.00 20, 000 $ 1.85 1.05$ 1.94 Low voltage Switchgear $ 17,000.00 20,0003 0.85 1.05$ 0.89 Station Transformer $ 6, 000.00 20, 000 $ 0.30 1.05% 0.32 Misc. Owner-Furnisned Equip Misc. $ S, 000.00 20, 000 $ 0.2 1.05$ 0.26 Equipment Installation $ 230, 000.00 20, 000 $ 17-50 1.05% 12.08 $ 355, 000.00 $ 20.46 1.05$ 21.49 Owner Overhead Labor $ SS, 000.00 3, 000 $ 15.35 1.05$ 19.2 Payroll Overnead $ 30, 440.00 3,000 $ 10.35 1.05$ 10.65 $ 85,440.00 $ 28.48 1.053 29.90 Engineering Desig $ 75, 000.00 3, 000 $ 2.00 1.05$ 26.25 Contract Acministration $ 90, 000.00 3,000 $ 30.00 1.05$ 31.50 $ 165, 000.00 $ 5S.00 1.05$ $7.75 Page 3 1402 ~<A COST ANALYSIS PROJECT: Kodiak Eletric 1980 Power Plant Exp YEAR COMPLETED: 1981 FERC KILOWATT INFLATION 1984 ACC'T # DESCRIPTION COST POTENTIAL COST/KW FACTOR COST/KW 340 Land and Land Rignts 341 Structures and Improvements 342 Fuel Holders, Producers and Access Day Tank, 600 gal $ 1,500.00 7,000 $ 0.21 1.278 0.27 Fuel O11 Filters $ 4,000.00 20, 000 $ 0.20 1.278 0.25 Misc. Accessories $ 2, 000.00 7,000 $ 0.29 1.27% 0.36 Mechanical Installation, Fuel Pog $ 40, 000.00 7,000 $ 5.71 1.27% 7.26 $ 47,500.00 $ 6.41 1.27% 8.15 343 + =Prime Movers Engine, TADL RV-16 $ 1,655, 261.00 7,000 $ 236.47 1.278 300.31 Turbochargers $ 50, 000.00 7,000 $ 7.14 1.27$ 9.07 Lube 011 Sump Tank $ 10, 000.00 7,000 $ 1.43 1.27% 1.81 Duplex oil Filters $ 12, 000.00 7,000 $ Ti 1.27% 2.18 Pre-Lube Pump $ 6, 000.00 7,000 $ 0.86 1.27% 1.09 Exnausts Silencer $ 41, 000.00 7,000 $ 5.86 1.27$ 7.44 Intercooler Pump $ 8, 000.00 7,000 $ 1.14 1.27% 1.45 Governor $ 7,000.00 7,000 $ 1.00 1.27$ 1.27 Intake Air Silencers $ 25, 000.00 7,000 $ 3.57 1.278 4.54 Radiator $ %, 000.00 7,000 $ 13.57 1.27% 17.24 Intake Air Filters $ 15, 000.00 7,000 $ 2.14 1.278 2.72 Lupe O11 Cooler $ 30, 000.00 7,000 $ 4.29 1.27% 5.44 Engine Gage Board $ 20, 000.00 7,000 $ 2.86 1.27% 3.63 Page 1 1402 - A COST ANALYSIS FERC KILOWATT INFLATION 1984 ACC'T tt DESCRIPTION COST POTENTIAL COST/KW FACTOR COST/KW Air Compressor, Starting Air $ 5,700.00 20, 000 $ 0.28 1.27$ 0.36 Air Storage Tarks $ 3, 200.00 20, 000 $ 0.16 1.27$ 0.20 Engine Foundation $ 60, 000.00 7,000 $ 8.57 1.27$ 10.89 Engine Installation $ 390, 200.00 7,000 $ 55.74 1.27$ 70.79 $ 1,974, 261.00 $ 282.04 1.27$ 358.19 344 Generators Generator $ 310, 000.00 7,000 $ 44.29 1.27% 56.24 Exciter $ 4, 000.00 7,000 $ 0.57 1.27% 0.73 Generator Pedestal Bearing $ 2, 700.00 7,000 $ 0.39 1.27$ 0.49 Voltage Requletor $ 3, 100.00 7,000 $ 0.44 1.27$ 0.56 Generator Foundation $ 30, 000.00 7,000 $ 4.29 1.27% 5.44 Gererator Installation $ 165, 900.00 7,000 $ 23.70 1.27$ 30.10 $ 515,700.00 $ 73.67 1.27$ 93.56 34SAccessory Electrical Equipment Circuit Breaker and Controls $ 4S, 000.00 7,000 $ 6.43 1.27% 8.16 Varielble Freq. JW Pump Drive $ 20, 000.00 7,000 $ 2.86 1.27$ 3.63 Motor Control Center $ S, 000.00 7,000 $ 0.72 1.27$ 0.91 Installation $ 30, 000.00 7,000 $ 4.23 1.27$ 5.44 $ 100, 000.00 $ 14.29 1.27$ 18.14 Page 2 1402 - _A COST ANALYSIS FERC KILOWATT INFLATION 1984 ACC'T # DESCRIPTION COST POTENTIAL COST/KW FACTOR COST/KW Owner's Overhead Labor $ 62 725.00 7,000 $ 8.96 1.27$ 11.38 Payroll Overnead $ 17, 207.00 7,000 $ 2.46 1.27$ Reals $ 79, 932.00 $ 11.42 1.27$ 14.50 Engineering Design $ 130, 000.00 7,000 $ 18.57 1.27$ 23.59 Contract Adaninistration $ 153, 000.00 7,000 $ 21.86 1.27$ 27 .76 $ 283, 000.00 $ 40.43 1.27$ 51.34 Page 3 a4c nf avaly le. vwcto Net Generation Operation Maintence Op Cost/KWHR Nt. Cost/KWHR Installed NM 6 0 Cost/Cap Year Nane of Plant (KMHR) Cost ($) Cost ($) (¢/Kddhr ) (¢/Muhr) = Cap. (kW) ($/7Kw) 1977 Gold Creek Int. Conb > 100$ 4,252 $ 72,999 12.07 19.05 8,222 $ 14.50 1978 . 73,650 $ 41,637 $ 6,125 11,14 12.08 8,222 3 10.55 1979 2 1, 7 9709 30,%8$ 53,865 2.4 4.% 8,222 $ 10.24 1980 : 551.455 $ 26,761 $ 34,257 4.85 6.21 8,222 9 7.42 1981 : 213,103 $ 23,020 $ 15,503 10.80 Var 8,222 $ 4.69 1982 : 2,007,285 $ 38,198 $ 79,207 1.90 3.95 $,222 $ 14.28 1983 . 1,957,023 $ 64,716 $ 55,347 3.31 2.83 8,222 $ 14.60 6721586 270952 356303 4.03 5.30 (AVERAGE): $ 10.90 1977 Lenon Creek Plant 1876500 5284 18151 0.28 0.97 7,500 $ 3.12 1978 15208250 110 20165 0.00 0.13 10,000 $ 2.03 1979 1970000 16071 33039 0.82 1.68 10,000 $ 4.91 1980 758000 13292 6131 1.75 0.61 10,000 $ 1.94 1981 46000 18155 50143 0.45 1.24 27,500 $ 2.48 1982 10807600 4556 130358 0.41 1.21 27,500 $ 6.36 1983 12177100 49830 114569 0.41 0.94 4,000 $ 3.65 16 14 beeeenca, AEL&P STANDBY PLANT O & M COST PER kW Project 1402.4101 COST ($/kW) Year 77 78 79 80 81 82 83 AVE 77 78 79 80 81 82 83 AVE Gold Creek Plant Lemon Creek Plant AEL8P STANDBY PLANT O & M COST PER KWHR Project 1402.4101 Operating Cost Costs (¢/kwhr) » no o o a Oo - a € @ Pet Cs - wo = 77 78 79 80 81 82 83 - AVE 77 78 79 80 81 82 83 - AVE Year - Lemon Creek Plant Gold Creek Plant APPENDIX 7.3 REFERENCES 0342C REFERENCES Alaska District, Corps of Engineers. January 1, 1967. Snettisham Project, Design Memorandum No. 13, Dam, Spillway, and Intake Structure. Alaska District, Corps of Engineers, and H.E. Moore. Cost data for components of the Snettisham Project. Alaska Electric Light & Power Company. October 1, 1967. Schedules for electric service applicable in the service area of the Company within the Greater Juneau Borough. Alaska Electric Light & Power Company. November 1982. Current rate charges. Alaska Electric Light & Power Company. January 1984. To FERC - Application for amendment of license for Salmon Creek Project. Alaska Electric Light & Power Company. March 1984. Consolidated financial statements and additional information, December 31, 1982 and 1983. Prepared by Price Waterhouse. Alaska Electric Power & Light Company. April 1984. 1983 diesel generation costs from Alaska Light and Power Company. Alaska Office of Mineral Development, Alaska Division of Geological and Geophysical Surveys. 1982. Alaska's mineral industry - 1982. Special Report 31. Alaska Power Administration. Alaska electric power statistics, 1960-1982. Alaska Power Administration. October 1980. Juneau area power market analysis. Alaska Power Administration. Datapoint System Documentation. March 1981. Alaska Power Administration. September 1983. Juneau area power market analysis, update of load forecast. Alaska Power Administration. May 1984. Update of load forecasts for Juneau area. Alaska Power Administration and the State of Alaska, Department of Fish & Game. April 1980. Agreement executed for fish rearing facility at Snettisham Hydroelectric Project. Barkshire, J. and M. Newell. 1982. Evaluation of unconventional energy alternatives, Kake-Petersburg Transmission Line Study. Polarconsult, Anchorage, Alaska. 0342C Ue3=l Bechtel Corporation. 1959. Preliminary report on economic feasibility of electrical utility system development for Alaska Electric Light & Power Company, Juneau, Alaska. Bechtel Corporation. 1966. Preliminary report on electrical utility system development for Alaska Electric Light & Power Company, Juneau, Alaska. CHoM Hill. December 1983. Ten year transmission and distribution system planning study for AEL&P. City and Borough of Juneau, Planning Department. January 1984. Juneau Economic Quarterly. 1(1). City and Borough of Juneau. October 1, 1984. An Ordinance Amending the Building Code to Provide for Minimum Thermal Standards for Residential Construction. Corbus, W. Information received: cost data on AELP facilities. Datapoint. DOS Basicplus - Users Guide Version. May 1978. Datapoint. Mastering Multiplan D Version 1.2. February 1983. Debelius, C.A., Colonel, Corps of Engineers, District Engineer. Alaska District Corps of Engineers, Department of the Army. December 19/3. Memo to Division Engineer, North Pacific re: Snettisham Project, Alaska. Design Memorandum No. 33, Crater Lake Plan of Development. Ebasco Services Incorporated. May 1984. Ebasco fossil generating plant historical cost index. In: Ebasco Cost/Schedule Newsletter, Issue No. 84-1. A.P. Gladkowski (ed.). Ebasco Services Incorporated. October 1981. Conceptual design and cost of a 30 MW coal-fired steam plant for Kodiak, Alaska. Prepared for the Alaska Power Authority. Engineering News-Record, March 29, 1984. Page 79. Glacier Highway Electric Association, Inc. October 1983. Power requirements study, Alaska 7 Juneau. Kramer, Chin & Mayo, Inc. February 1982. The role of electric power in the southeast Alaska energy economy - Phase II. 1981 Juneau energy balance. Prepared for the U.S. Department of Energy, Alaska Power Administration. National Oceanic and Atmosphere Administration. Tidal currents tables 1980, Pacific coast of North America and Asia. 0342C Wse=2 Newell, M. and S. Konkel. Bush seeks power cost savings. In: Alaska's Energy Resources, March 19, 1984. The Okonite Company. Letter to J. Szablya from C. Russell re: Snettisham cable. R. W. Beck & Associates, Inc. December 1983. Haines-Skagway Region - Feasibility study. Volume 4, Supplemental investigations. Prepared for the Alaska Power Administration. R.W. Beck & Associates, Inc. February 1984. Future hydropower resources, Ketchikan, Petersburg, Wrangell and Quartz Hill. Preliminary appraisal study. Prepared for Ketchikan Public Utilities. R.W. Beck & Associates, Inc. January 1984. Economic and financial analysis of a proposed transmission intertie between Whitehorse, Yukon Territory and Haines, Skagway, and Juneau, Alaska. Prepared for the Alaska Power Administration and Northern Canada Power Commission. R.W. Retherford and Associates. 1981. Angoon tidal power and comparative analysis. R.W. Retherford and Associates. March 1978. Final Feasibility Study of Alternative for Rehabilitation of Salmon Creek Hydroelectric Project. SRI International. October 1979. Development of markets for electricity in the Alaska Electric Light and Power Company service area. Prepared for the Alaska Electric Light and Power Company. Project No. 7749. Southeast Alaska Intertie Committee. September 1983. Position paper on economic development in region of Ketchikan, Petersburg, and Wrangell. 1. &. Neubauer & Associates. Load management study. REA system designation: Alaska 7 Juneau. Prepared for Glacier Highway Electric Association. 1.£. Neubauer & Associates. Load management study for Glacier Highway Electric Association. Teshmont Consultants Incorporated. November 1982. Snettisham/Juneau DC transmission system - Reconnaissance design and cost estimate. Prepared for the U.S. Department of Energy, Alaska Power Administration. Teshmont Consultants Incorporated. November 1982. Southeast Alaska Intertie DC Transmission System reconnaissance design and cost estimate. Prepared for the U.S. Department of Energy, Alaska Power Administration. 0342C 1.3-3 Teshmont Consultants Incorporated. November 1982. Southeast Alaska Intertie DC Transmission System. Reconnaissance design and cost estimate. Appendix 1. Prepared for the U.S. Department of Energy, Alaska Power Administration. The Juneau Heat Pump Program Progress Report. February 1982. U.S. Department of Agriculture. October 1980. System planning guide - Electric distribution systems. Rural Electrification Administration Bulletin 60-8. USDOI/APA. December 1973. Snettisham Project - Contract for electric service to GHEA. Contract No. 14-15-0001-SN-4. USDOI/APA. December 1973. Snettisham Project - Contract for electric service to AELP. Contract #14-15-0001-SN-1. Vilander, D.R., Chief Program Staff, BPA, USDOE. January 9, 1983. Cost trends of BPA Transmission Line. U.S. Government Memorandum. 0342C 71.3-4 JUNEAU 20 YEAR POWER SUPPLY PLAN : UN = Foe eee sa HIGHSMITH #42-302L PRINTED IN U.S.A.