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Home My WebLink AboutJuneau 20 Year Power Supply Plan, Presentation Summary, March 1985 [} &. "PRESENTATION SUMMARY] ' _ JUNEAU 20 YEAR POWER SUPPLY PLAN March 1985 EBASCO LIBRARY COPY EBASCO SERVICES INCORPORAT| Alaska Energy Authority INTRODUCTION 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. 2280C 3/12/85 FINDINGS AND RECOMMENDATIONS STUDY FINDINGS ° 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 situation. In the near-term hydro deficit period, the lower EMD capital cost, as compared to medium speed prime diesel engine 2280C 3/12/85 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 2280C 3/12/85 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 Table 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 oi] price variations (See Table 6-2). 2280C 3/12/85 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 1/ Whitehorse Intertie plan cost is $223.6 million and Tyee Intertie plan cost (assuming 7.6 ¢/kWh for the purchase of Tyee power) is $278.2 million. See Table 6-2 for results of alternative Tyee power purchase cost assumptions and other sensitivity tests. 2280C 3/12/85 TABLE 6-2 SENSITIVITY TEST RESULTS Total Discounted Sensitivity Test Plan Plan Costs ($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 ¢/kwWh) Lake Dorothy Trans- Shared Facilities with mission Facilities Snettisham 114.1 Separate Facilities 104.6 2280C 3/12/85 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 preconstruction 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. o 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 2280C 3/12/85 PRELIMINARY PROJECT SCHEDULE LAKE DOROTHY BASELINE DATA ACQUISITION FEASIBILITY STUDY LICENSING AND PERMITTING FINANCE PLAN AND POWER SALES DETAILED DESIGN CONSTRUCTION Ht | | | YEAR 1 YEAR 2 YEAR3 YEAR4 YEARS YEAR6 YEAR7 YEAR8 YEAR9 YEAR 10 JUNEAU AREA 20 YEAR POWER SUPPLY PLAN LAKE DOROTHY PRELIMINARY PROJECT SCHEDULE | bate NOV 1984 [FicuRE 6-1 _| EBASCO SERVICES INCORPORATED estimate, a reliable estimate of power production, identification 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 preconstruction 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 ° 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. 2280C 3/12/85 ESTIMATED COST OF POWER 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, 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. 2280C 3/12/85 =10" NORTH SLOPE GAS-FIRED ELECTRICAL GENERATION SYSTEM FOR SUPPLYING ELECTRIC POWER TO THE RAILBELT AREA Action Item A review of cost estimates to do a detailed feasibility analysis of North Slope gas-fired electrical generation is to be considered. Issues A detailed review of the preferred option of the Ebasco feasibility level assessment of "use of North Slope Gas For Heat and Electricity in the Railbelt", September 1983, is re- quired. Staff was directed to develop the scope of work required, contract consultants not involved with Susitna, estimate Alaska Power Authority requirements and report the estimate cost of the detailed feasibility study. As of May 1, three responses by firms willing to estimate study costs have been received. A limited number of firms have indicated that they will respond by May 15th. Less than ten have notified the Power Authority that they will not be able to provide estimated costs. The responses received to date are not statistically signifi- cant for staff to estimate exstudy costs. They do affirm the low end estimate of $1.5 m lion that Ebasco offered as a low-end cost estimate without a review of the proposed scope of work. Options 1. Continue to receive estimates from consultants and finalize report after May 15, 1985. Distribute report to Board when complete. 2. Modify option one. 3. No action. Recommendation Option one. 9293/372 Oh cans 20 - fewel Ce ia i + Bn Shed Srenred ty weit Arh ae oe ce A Sbedy pon he, ge: cel Honig Ste raon et ee” ee ee 2, a Ary tithlly Sprcve tr ©) UpdahS eng fubif EE, atl eget. hale ee ie A Ane uf Wele,f Tyee * eit adi Bodice fee a X Expearcon of Lasting Foose %s K Viorael Meats x Ofkees Ciel Moanin) Medd Texans To meh wf V be apteeted by Nhe beh os exailelle befleeas agpnarers (O AU e/beru heen were competed apecer! an eh bel terol bute take (ovenar enre oc most cast a = Faw he ‘ Ack Lech es ein ap Wf Ne. Con ae. Juneau 20 Year Power Supply Plan Sponsored by AEL&P, GHEA, APA (State), & APA (Federal) o PURPOSE: Reconnaissance level study to look at power supply options available to Juneau after completion of the Crater Lake addition to Snettisham (completion 1988). o STUDY PROCEDURES: o Used a 20 year planning horizon. o Developed total system costs for comparison against a diesel generation case. o Used State APA economic criteria. o Used range of load forecasts developed by APA and two local utilities. o Updated engineering plans and costs for projects previously studied. Brought all up to 1984 cost level. o Looked at previous interconnection studies with Northern Canada Power Commission, and also a tie south to the Tyee Project. o Numerous undeveloped hydro projects from small to several large ones within a reasonable area. Went as far as Thomas Bay Project near Petersburg. o Expansion of existing projects such as AEL&P's Annex Creek Hydro Project. o Thermal plants-coal. o Others such as wind and biomass. o AlTof, these alternatives were compared to the all diesel case. o RESULTS: o Lake Dorothy located about 14 miles south of Juneau across Taku Inlet offers clear advantages. It is 26 MW project that would fit well under Juneau load curve and be particularly important for meeting winter peak loads. A separate transmission line to Thane Substation would partially relieve the 100% backup requirement for Snettisham. Lake Dorothy would be needed in 1993-1996 timeframe. o Interconnections were found to be important options for Juneau, although not as cost effective as Lake Dorothy. Ebasco only analyzed interconnections as alternatives to Lake Dorothy. They did not attempt to evaluate benefits associated with intertying other areas of SE Alaska, such as providing better utilization of existing and planned hydro resources, sharing reserve capacity, and seasonal diversity. o basco was asked to prepare a computer planning model as part of the contract. The model is sensitive to changes in load fore- casts, costs, timing of developments, economic criteria (interest rates, inflation, etc.), and allows introduction of other projects. The model appears to be a handy way to see effects on overall future system costs. o RECOMMENDATIONS: o basco suggests proceeding with feasibility level planning activities now so that all pre-construction activities are completed as early as 1990. This would allow POL from Lake Dorothy in 1993. o Continue working with other SE communities and Canada on inter- connection systems. Unit Nameplate RRR RAR AEL&P NAN Facilities Type No. RNR etter Annex Ck. Hydro 5 6 Upr.Salmon Hydro 3 (Standby with Lur. 4 Salmon on-line.) Lwr.Salmon Hydro Gold Ck. Hydro z 2 3 Diesel 4 Ss 6 7 8 Lemon Ck. Diesel 1 2 3 4 7 8 a Gas Turbine 5S 6 TOTALS Hy dro Diesel Gas Turb. KW 1,750 1,750 3, 500 1,400 1,400 (2, 800) 5, 600 800 400 400 1, 600 1,250 1, 200 1,136 3,500 1,136 8,222 2,500 2,500 2,500 2,500 2,500 2,500 2,500 17,500 17,500 17,500 35, 000 10,700 25,722 35, 000 71,422 JUNEAU AREA aN Installed Capacity (KW) APAdmin. NANA Facilities Type ANNA RAN Snettisham Hydro --Long Lk. TOTAL --Crater Lk. (Future) Future Total Unit No. RNR RRR 23, 580 4 2 Namep late Kw Facilities RRR RNY Auke Bay standby leased TOTAL GHEA | nett 1 Nameplate 1 Type KW ' RNR nny | Diesel 2,500 ' Diesel 275 | Gas Turb. 2,800 | il Diesel 2775 1 Gas Turb. 2,800 | =eecsse 1 5,575 ' | 1 ' 1 1 AREA TOTALS RR Nn Namep late Type KW RN enemy Hy dro 57, 860 Diesel 28, 497 Gas Turb. 37,800 * TOTAL 124, 157 * 31,050 Add B4-000-KW to Hydro & TOTAL for Crater Lk. Tate! Creter Ly 155,207 Alaska Power Admin. 1-1985 ALASKA POWER AUTHORITY Board of Directors Planning Committee Meeting Juneau Department of Commerce & Economic Development Conference Room 9th Floor State Office Building Thursday, May 2, 1985 1:00 p.m. AGENDA 1. Status of the Advisory Committee's Report on Statewide Power Production Costs 2. North Slope Gas Fired Electrical Generation System for Supplying Electrical Power to Railbelt Area Juneau 20-Year Power Supply Plan Unalaska Geothermal Project Little Diomede Diesel Generation oO a > w . . . e St. Paul Wind Farm Proposal 9174/370 ALASKA POWER AUTHORITY Board of Directors Finance Committee Meeting Juneau - Department of Commerce & Economic Development Conference Room - 9th Floor State Office Building Thursday, May 2, 1985 2:30 p.m. AGENDA 1. Rural Electrification Revolving Loan Fund (RERLF) Regulation Amendments 2. Bradley Lake Hydroelectric Project Adoption of Resolution 1985-05 Finding Project Economically and Financially Feasible and Recommending Construction 3. Galena Waste Heat 9174/370 ALASKA POWER AUTHORITY Board of Directors Project Management Committee Meeting Juneau - Department of Commerce & Economic Development Conference Room - 9th Floor State Office Building Thursday, May 2, 1985 3:30 p.m. AGENDA Bradley Lake Hydroelectric Project Approval to Initiate Final Design and Contract for Construction Management Services and Status of Power Sales Agreements Waste Heat Project: Findings and Recommendations Anchorage/Fairbanks Intertie: Ahtna Appraisal Susitna Hydroelectric Project: Licensing Status and Staging Proposal 9174/370 OLD BUSINESS I. A. 9174/370 Alaska Power Authority Board of Directors Meeting Juneau Borough Chambers Friday, May 3, 1985 8:30 a.m. AGENDA Action Items 6. Approval of Minutes of the February 26, 1985 Board Meeting Adoption of Rural Electrification Revolving Loan Fund Regulation Amendments / Readoption of Former Policy to Provide for any Board Member to NO be a Voting Member when in Attendance at Committee Meetings Bradley Lake Hydroelectric Project a. Adoption of Resolution 1985-05 Finding Project k Economically and Financially Feasible and Recommending oO Construction De se. b. Approval to Initiate Final Design and Contract lia Construction Management Services Licensing Review and Consideration of Proposed Stagi De aa Construction of the Susitna Hydroelectric Project ©, Approval of contract with Recon Resources, Inc. Information Items 1. Four Dam Pool: Development of a Renewable Short-Term Agreement; status of pending legislation and negotiations on long-term agreements Status of Analysis of the Statewide Power Production Costs Report North Slope Gas Fired Electrical Generation System for Supplying Electric Power to the Railbelt Area FY86 Legislation Update II. NEW BUSINESS A. Action Item 1. Recommendations for Juneau 20-Year Power Supply Plan — OK 2. Unalaska,R i : Findings and R dati nalas a F egonnais 1 inding ecommendations CYOK tS. Stu 3. Waste Heat: Findings, Recommendations and Approval of 0% FY86 Program 42m 4. Galena Waste Heat Proposal—of APA Li / bo shedy Gok) 5. Little Diomede: Diesel Generation z7gk treo -Ax75K of i] g.I. Wweste free et 6k ~6. Approval of Letter of Intent for St. Paul Wind Farm proposal es ¥00K for Jeverase mewey Loe heveleppwoet, Diesel ¢ Ud 19.2 YO ftec B. Information Items jae [Ker “ 1. Alaska Power Administration _Deberrel 2. Presentation by Representatives from Signal on the Matanuska Power Project C. Other Business — III. PUBLIC COMMENT 9174/370 ALASKA POWER AUTHORITY 334 WEST 5th AVENUE - ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 April 26, 1985 Mr. Don Shira Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 Subject: Juneau 20 year Power Supply Plan Dear nr Aira Enclosed is the action item for the Alaska Power Authority Board Meeting which relates to the Juneau 20 year power supply plan. If approved, the action item would adopt the findings and recommenda- tions of the Ebasco report. Some additional Power Authority staff recommendations are included which recommend initiation of stream gaging at Lake Dorothy, geotechnical and environmental scoping of the Lake Dorothy project and interties, continued planning for a Southeast Alaska-Canada intertie, and continued analysis of load trends. The Planning Committee of the Board will consider the action item on May 2, 1985 and the full Board will consider it on May 3, 1985. Meeting agendas are enclosed for your information. Brent Petrie and I will be at the meetings. If you have any questions or comments, please call Brent direct at 263-7327. Sincerely, Edwin L. Morris Associate Executive Director of Planning Attachments as stated. BNP: ELM: it cc: Brent Petrie, Alaska Power Authority 9245/370 Distribution List Mr. William A. Corbus Vice President and General Manager Alaska Electric Light & Power 134 North Franklin Juneau, Alaska 99801 Mr. Robert Cross, Administrator Alaska Power Administration Department of Energy P.0. Box 50 Juneau, Alaska 99802 Mr. Don Shira Alaska Power Administration P.0. Box 50 Juneau, Alaska 99802 Mr. Charles Y. Walls Manager Glacier Highway Electric Association P.0. Box 115 Auke Bay, Alaska 99821 JUNEAU 20-YEAR POWER SUPPLY RECONNAISSANCE A. Action Item Consideration and transmittal of findings and recommendations regarding the reconnaissance study of Juneau Power Supply Alternatives. Background In early 1984 Alaska Electric Light and Power, Glacier Highway Electric Association and the Alaska Power Administration funded a study effort to prepare a 20 year power supply plan for the Juneau area. The Alaska Power Authority participated by providing information and technical review, and economic analysis parameters. Analytical methods, economic analyses and lifecycle of capital items were consistent with Alaska Power Authority economic analysis parameters in order to meet the requirements of state reconnaissance and feasibility studies. A competitive RFP was issued in early 1984 and after evaluation of proposals a contract was executed between Alaska Electric Light and Power and Ebasco Services, Inc. of Bellevue, Washington. The contract required Ebasco to make maximum use of existing information including using May 1984 Alaska Power Administration load forecasts for the Juneau area. These load forecasts did consider conservation measures and load manage- ment programs that are designed to reduce customer energy and peak requirements. Other options which were considered to meet demand were: 1) Interconnection with existing hydroelectric based systems. -Northern Canada Power Commission System . Tyee Lake System 2) Undeveloped hydroelectric projects near Juneau. 3) Fossil Fuel plants. 4) Other sources. -Solid waste incineration -Wind energy conversion systems -Solar-electric - Geothermal -Tidal power -Wood fired steam Issues The basic issue is that the Crater Lake expansion of the Snettisham project appears to be fully absorbed in the early 1990's and some form of additional power supply will be required even with continued emphasis on conservation and load management programs. The main issues for new 9210/370 D. supply becomes the timing and type of new generation. The report pre- pared by Ebasco offers a comprehensive array of alternatives for meeting Juneau power needs. In summary, the Power Authority staff concur with recommendations offered in the report (these are included as an attachment) and offer the following specific recommendations: 1) Since the planning of new projects is driven by the load forecast, it is important to continue comprehensive annual updates for the Juneau area. For many years this service has been provided by the Federal Alaska Power Administration (APAd). Since APAd will phase out this effort effective June 30, 1985, it is recommended that the Power Authority assume this function in cooperation with the Juneau area utilities. Since Juneau's growth is highly dependent upon state government employment, updated load forecasts should consider the effects that declining state revenues may have upon Juneau area employment and population growth. : 2) Beginning in FY86, a stream gauge should be established at the outlet of Lake Dorothy. A previous stream gauge was located at a much lower elevation near tidewater which included another lake and additional area in its watershed. Since Lake Dorothy is proposed to be developed with a lake tap, the hydrology of the portion of the basin that would supply the project is of extreme importance. A five year record is recommended. 3) Interconnection alternatives to Juneau from either Whitehorse or the Tyee project should continue to be considered. The storage charac- teristics of Lake Dorothy are such that it would complement a Southeast transmission intertie. In addition interties enhance reliability and provide some flexibility for dealing with an uncer- tain future through transfer of surpluses and sharing of reserves. 4) A scoping effort should be initiated to determine environmental, geotechnical, and engineering issues that need to be considered in development of Lake Dorothy or interties. This scoping effort could be used to define the scope of work needed in a subsequent detailed feasibility study and licensing effort. Costs The following is an estimate of costs associated with following through with certain recommendations on the Juneau 20 year plan. Action on this item is not a commitment to expend these funds at this time. Such action will have to await a review of the FY86 budget and may form the basis for future budget requests. 1. Lake Dorothy stream gauging through USGS (helicopter access only) $35 ,000 5 year estimate = $150,000 first year installation and operation. 9210/370 Coordination on interties. Load forecast and utility coordination can be handled by staff with incidental expense related to travel and communications. A special expense is required for submarine cable surveys as requested in the APA FY86 budget. $400,000 would cover cable routes of a Southeast Intertie. 3. Scoping sessions. This would involve utility, $30 ,000 APA, and agency staff. Contractual would be required from specialty consultants in geotech- nical and fishery areas. E. Options 1) Endorse the Findings and Recommendations as outlined above and in the attachment and transmit, along with the reconnaissance report, to the Office of Management and Budget (OMB) for its review pursuant to AS 44.83.179. OMB has thirty days to approve or disapprove the reconnaissance study. 2) Disapprove the Findings and Recommendations and refer to staff for revision. 3) Refer to staff for further elaboration or revision with no endorse- ment at this time. Fis Recommendation Adopt Option 1. 9210/370 From Volume I, Juneau 20 Year Power Supply Plan, Ebasco Services Inc.,Dec. 6.0 FINDINGS AND RECOMMENDATIONS 6.1 STUDY FINDINGS Review of the information covered in. the previous sections leads to several findings, which are enumerated in the foliowing paragraphs. o 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. o 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. o 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. o 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. Za 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 6-1 198¢ 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 Table 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 Low Forecast Mid-Range Forecast High Forecast Mining Forecast TABLE 6-1 SUMMARY OF PLAN COSTS Total Discounted Plan Cost ($Million) lake Dorothy Interconnection Thermal Plan Plan Plan 122.6 86.1 248.4 104.6 223.6/278.21/ 448.1 283.7 558.6 ¢ 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 $278.2 million. See Table 6-2 for results of alternative Tyee power Purchase cost assumptions and other sensitivity tests. 1075C 6-4 TABLE 6-2 SENSITIVITY TEST RESULTS Total Discounted Sensitivity Test Plan Plan Costs ($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 6-5 er 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. o 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 £-9 PRELIMINARY PROJECT SCHEDULE LAKE DOROTHY BASELINE DATA ACQUISITION FEASIBILITY STUDY LICENSING AND PERMITTING FINANCE PLAN AND POWER SALES DETAILED DESIGN CONSTRUCTION YEAR 1 YEAR 2 YEAR3 YEAR4 YEARS5 YE ft YEAR 7 YEAR 8 YEAR9 YEAR 10 JUNEAU AREA 20 YEAR POWER SUPPLY PLAN LAKE DOROTHY PRELIMINARY PROJECT SCHEDULE | OaTe NOV 1984 [Ficune 6-1 | 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. Deveitopment 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 6-8 Juneau 20 Year Power Supply Plan Sponsored by AEL&P, GHEA, APA (State), & APA (Federal) o PURPOSE: Reconnaissance level study to look at power supply options available to Juneau after completion of the Crater Lake addition to Snettisham (completion 1988). o STUDY PROCEDURES: ° ° Used a 20 year planning horizon. Developed total system costs for comparison against a diesel generation case. Used State APA economic criteria. Used range of load forecasts developed by APA and two local utilities. Updated engineering plans and costs for projects previously studied. Brought all up to 1984 cost level. Looked at previous interconnection studies with Northern Canada Power Commission, and also a tie south to the Tyee Project. Numerous undeveloped hydro projects from small to several large ones within a reasonable area. Went as far as Thomas Bay Project near Petersburg. Expansion of existing projects such as AEL&P's Annex Creek Hydro Project. o Thermal plants-coal. o Others such as wind and biomass. o All of these alternatives were compared to the all diesel case. o RESULTS: o Lake Dorothy located about 14 miles south of Juneau across Taku Inlet offers clear advantages. It is 26 MW project that would fit well under Juneau load curve and be particularly important for meeting winter peak loads. A separate transmission line to Thane Substation would partially relieve the 100% backup requirement for Snettisham. Lake Dorothy would be needed in 1993-1996 timeframe. Interconnections were found to be important options for Juneau, although not as cost effective as Lake Dorothy. Ebasco only analyzed interconnections as alternatives to Lake Dorothy. They did not attempt to evaluate benefits associated with intertying other areas of SE Alaska, such as providing better utilization of existing and planned hydro resources, sharing reserve capacity, and seasonal diversity. ‘} ® ©,’ Ebasco was asked to prepare a computer planning model as part of the contract. The model is sensitive to changes in load fore- casts, costs, timing of developments, economic criteria (interest rates, inflation, etc.), and allows introduction of other projects. The model appears to be a handy way to see effects on overall future system costs. o RECOMMENDATIONS: o Ebasco suggests proceeding with feasibility level planning activities now so that all pre-construction activities are completed as early as 1990. This would allow POL from Lake Dorothy in 1993. o Continue working with other SE communities and Canada on inter- connection systems. 1. 2. PLO 7 a September 16, 1983 7th DRAFT REQUEST FOR PROPOSAL FOR JUNEAU AREA 26 YEAR GENERATION/ENERGY PLAN Invitation To Submit A Proposal You are invited to submit a written proposal at the offices of the Alaska Electric Light and Power Company, 134 Franklin St t, Juneau, Alaska 99891 not later than 4:69 p.m. Decembe 983 to prepare a 29 Year Generation/Energy Plan to sati the Juneau area electrical needs through the year (1994) ee The Plan The Plan will cover sources of electrical ‘generation/energy to satisfy energy and capacity require-— ments as well as the impact of rates and control of customer load and consumption practices through local ordinances and regulations for a 2% year period. The Plan may be utilized by the local utilities to support investments in equipment to satisfy hydroelectric energy deficits, standby capacity requirements and load and energy management devices. It may also be used be used as justification for construction of major energy sources such as hydroelectric plants or transmission line interties. Funding The preparation of this Plan is sponsored by the Alaska Power Administration (APADM), the Alaska Power Authority (APAUTH) and the Alaska Electric Light and Power Company (AELP). Background a. At present there are three entities serving a role in supplying electric energy to the City and Borough of Juneau (CBJ) - APADM, AELP and the Glacier Highway Electric Association (GHEA). The APADM is an agency of the United States Government and operates the Snettisham Hydroelectric Project which is the major energy source for CBJ. AELP is an investor owned electric utility serving approximately 99% of the CBJ population. Its service territory generally covers the area to the south of the Mendenhall River. AELP's rates and service policies are regulated by the Alaska Public Utilities Commission. GHEA is a consumer owned rural electric cooperative in general serving the area north of the Mendenhall River. GHEA is a preference customer and as such has first call on the output of federally financed hydroelectric projects such as Snettisham. Its rates and service policies are not subject to the jurisdiction of the Alaska Public Utilities Commission. GHEA's rates encourage higher customer consumption in order to reduce their average cost per kwh. AELP's rates are not designed to encourage higher consumption. APAUTH is an agency of the State of Alaska whose responsibility among other things includes planning, developing, operating and financing electric generation facilities. To date other than loaning money to AELP for transmission and distributior and minor hydroelectric improvements APAUTH has not had a presence in the Juneau area. Historically the utilities, AELP and GHEA, which provide electric service at the retail level have experienced growth rates well above industry standards. Enclosure (1) is a summary of the statistics of the growth of population, customers and electric energy requirements of CBJ for the last 10 years. During the last 18 years CBJ has experienced above average population growth because of the rapid expansion of its primary employer State government which has been kindled by revenues received from the oil industry. Looking to the future, growth is expected to be strong for 1983 and 1984 to satisfy housing and commercial demand held in obeyance because of the proposed capital move. Looking beyond 1984 growth is expected to slow substantially by historical standards because of a reduction in the growth rate of government employment caused by Alaska's relatively unfavorable oil revenue outlook. Enclosure (2) is a forecast of Juneau's electric energy and load forecast for the next 26 years. This forecast does not assume a substantial energy conservation program. Juneau's primary energy source is the Snettisham Hydroelectric Project. The U.S. Department of Interior, through the Bureau of Reclamation, made the preliminary studies and obtained Snettisham authorization from the U.S. Congress in 1962. Construction was started in 1967 and upon completion in 1973 was turned over to the APADM for operation. The powerplant for the Long Lake portion of the project is at the head of Speel Arm about 28 airline miles Southeast of Juneau. It is an underground plant housing two turbine-generator sets, each with a rated capacity of 23,580 KW. The total capacity of 47,168 KW may be operated at a 25 percent overload for two hours out of every 24 hour period. Power is transmitted to Juneau over a 44-mile long 138 KV transmission line. Three miles of the line goes underwater at the Taku Inlet crossing. The balance is an overhead line supported on steel and aluminum ‘towers, The total investment in the Snettisham Project to date is about $79,900,998. The project is financed entirely by Federal money at 3 percent interest and principal to be repaid in 68 years. Rates are reviewed every five years and adjusted to insure that principal and interest will be repaid by the end of the fifty year period. Wholesale rates are currently 1.56 cents per Kwh but are expected to increase to 2.58 cents per Kwh on December 1, 1983. The firm annual output from Long Lake is 179,696,906 Kwh. The estimated average output of firm and non-firm energy for the present Long Lake stage is 216,994,098 Kwh. One shortcoming of Long Lake in the near term is that more of its energy is available during the low load seasons of the year when it cannot be utilized and so some of the water spills. In other words, the storage capacity of the Long Lake reservoir is inadequate and AELP cannot always utilize the energy when available. AELP is now in such a deficit hydroelectric condition during the winter months. As the Juneau load grows, more of the summer energy will be utilized but also the hydroelectric Geficit will be larger during the winter months. As far as AELP is concerned the deficit of hydroelectrically generated energy will be compounded because GHEA is a preference customer of Snettisham energy. AELP owns and operates three hydroelectric projects: Annex Creek, Salmon Creek and Gold Creek, which’ combined contribute 45,699,666 kwh annually and 6469 KW of firm capacity to the CBJ sources. An improvement to the Salmon Creek Project will add 9,069,668 kwh annually and 2869 KW of capacity to the CBJ energy pool at the end of 1984. Other AELP and GHEA generation facilities consist of a variety of diesel generators and diesel fired gas turbines. Enclosure (3) is a tabulation of all generation facilities in the Juneau area. The Snettisham Hydroelectric Project's 42 miles of overhead and underground transmission line connecting with CBJ is subject to high winds, snowslides and avalanches. Prior to construction of the line and after economic analysis the decision was made to hold the local utilities responsible for providing standby generation capacity to cover the annual peak load rather than a more reliable or redundant transmission line. Some of the generation facilities listed in Enclosure (3) were installed to serve this purpose. AELP, GHEA and APADM all believe that development of the Crater Lake Additon to the Snettisham Project will best satisfy Juneau's immediate electric needs and is the most economically feasible alternative. Crater Lake is part of the Snettisham scheme and was included in the original authorization by the U.S. Congress. The construction plan calls for tapping Crater Lake with a 8698 foot power tunnel 11 foot in diameter leading to the existing underground Snettisham powerplant where provision was make for the additional generator at the time it was constructed. The Crater 7 Lake addition will add 27,960 KW of capacity, 166,069,066 Kwh of firm energy and 117,889,066 Kwh average of firm and non-firm energy. The current cost estimate of the project is around $67,996,669. This is based on construction commencing in 1984, finishing in 1988 and an allowance for inflation. Assuming the Crater Lake Addition was financed with Federal money and rolled in with the 1983 adjusted rates of Long Lake, the most recent combined energy cost is estimated at 2.5 cents per Kwh. There are many reasons favoring the Crater Lake Addition as compared to other alternatives: 1.) The transmission line is already built. 2.) The powerhouse is already built and will require no alterations to accommodate the additional generator. 3.) The power transformers at the powerhouse and Thane Substation are sized to accommodate the Crater Lake Addition. 4.) BA base camp, aircraft landing strip and boat harbor are already constructed thereby substantially reducing the mobilization effort required. 5.) The environmental impact statement is complete and accepted. There is no significant additional permitting required. 6.) The U. S. Army Corps of Engineers have nearly completed the final design and bid specifications. The Long Lake portion of the Snettisham Project was completed in 1973 and it was anticipated that the Crater Lake addition would commence construction in 1977. However, in 1977 resulting from lower than project@kwh sales growth in the early years of the project operation and the uncertainty raised by the Capital move resulted in the effort to start the funding and construction of the Crater Lake addition being postponed (although preparation of the final design and bidding dockings continued). In August of 1982 U.S. Senator Ted Stevens stated that in view of the near and long term budgetary problems he did not believe the Federal government would be able to fund the entire cost of the Crater Lake addition. He suggested that for completion of the Crater Lake addition financial participation by the State of Alaska would probably be required. There have been efforts to encourage the State since that date to participate financially but to date such efforts have been stymied for these following reasons: 1.) The State of Alaska has run into financial constraints as a result of the reduction of oil revenues. 2.) Some disenchantment with State funded hydroelectric projects under construction or recently completed. 3.) Uncertainty on the part of the State of Alaska that Federal government will put up their share of monies to construct the addition. 4.) Contractual arrangements between the State and Federal government: a.) The Federal government currently does not have the administrative mechinism to accept non- Federal money to assist in paying for a project they propose to construct. This will take an act of Congress. b.) The type of security the State would receive to protect its financial participation ina Federal project. 5.) Reports in newspaper articles that the Federal government will transfer ownership of the Snettisham Project to the State of Alaska. These uncertainies have resulted in many unknowns as to when Crater Lake addition will be completed. In the meantime AELP as a non-preference customer intends to satisfy the energy deficit using diesel generators whose fuel costs estimated at 6.68 cents per Kwh assuming fuel 98 cents per gallon and energy output of 13.7 Kwh per gallon. Maintenance cost on average is estimated to add another 1.33 cents per Kwh. There are numerous other potential hydroelectric projects in the Juneau vicinity which could satify CBJ's long term energy requirements. Annual Firm Energy Project KW MWH Crater Lake 27 166,996 Lake Dorothy 34 158,688 Tease Lake 16 70,868 Sweetheart Falls 29 125,006 Speel River 63 . 275,086 Long Lake Dam Addition a= 57,956 Total 16 783,988 Enclosure (4) is a description of such projects including construction cost estimates and construction schedule prepared by the APADM. These projects could be included as part of the 26 Year Generation/Energy Plan. Ke There are existing hydroelectric projects to the north and south of Juneau with unutilized electric energy and capacity. To the north the Northern Canada Power Commission has kwh of excess energy and kw of exces capacity. Enclosure (5) is a report examining the feasibility of constructing a transmission line between Whitehorse, Yukon Territory, Haines, Skagway and Juneau. To the south exists the Tyee Hydro electric Project built by APAUTH to satisfy Peters-— burg and Wrangell electric needs. Enclosure (6) is a study by APADM on the feasibility of a trans-— mission intertie with Petersburg, Wrangell and Ketchikan. Ae Other potential sources of energy to satisfy the CBJ long range generation/energy requirements include: 1.) Modernizing and developing other small scale hydroelectric projects in the Juneau area such as Salmon and Annex Creek. 2.) - Large scale thermo plants utilizing fossil fuels such as natural gas, fuel oil, coal, etc. 3.) Exotic energy sources such as wind, solar, geothermal, etc. 4.) Energy purchased from qualifying facilities as per PURPA Regulations. m. AELP and GHEA have developed load management and energy conservation plans to varying degrees. Undoubtedly they could be strengthened and improved. At present CBJ has no minimum insulation requirements in its building codes. Tasks to be Accomplished in Preparation of the Plan a. The Background presented in Paragraph 4 above is not a complete review of the Juneau electric energy picture. Prior to commencing preparation of the Plan the consultant should do extensive research on CBJ electric energy situation including interviewing key personalities, reviewing other reports available, collecting data, etc. b. Review long range generation alternatives including: 1.) APADM prepared cost estimates for constructing various hydroelectric alternatives listed Paragraph 3.j. above. Utilize this information to prepare unit energy cost for each alternative. 2.) 3.) 4.) 5.) 6.) APADM, APAUTH and the Northern Canada Power Commission have prepared (see Enclosure (5)) a study examining the feasibility of interconnecting Canadian hydroelectric projects in excess of their needs with northern Southeast Alaska. Utilize the information contained in this study to develope unit costs for this energy source alternative. APADM have prepared (see enclosure (6)) a study on the feasibility of a DC transmission grid connecting the major loads and energy sources of Southeast Alaska. Utilize the information contained in this study to develope unit costs for this energy source alternative. Thermo alternatives a.) Based upon accepted industry standards adjusted for the Alaska factor estimate the installed cost per installed KW assuming construction in CBJ b.) Estimate energy cost per kwh for alternative ' types of fossil fuels. c.) Identify optimum plant sizing da.) Estimate total energy cost per kwh including fuel, fixed charges and operation and maintenance. Exotic energy sources a.) Determine if there is significant potential . energy resources from wind, solar, geothermal, etc. in the Juneau area. b.) If such resources are available estimate, the annual energy available and total cost per kwh. c.) Discuss qualitative factors associated with any such energy sources which offer potential. Qualifying facilities a.) Estimate potential energy available from qualifying facilities located in the Juneau area b.) Estimate cost to AELP and GHEA based on Alaska Public Utilities Commission regulations c.) Discuss any qualitative factors associated with energy from qualifying facilities. Develop methodologies for comparing alternatives over the 28 year study period. 1.) Develop a spread sheet and graphs displaying the timing of introduction of energy sources over the study period and also associated cash flows and unit energy costs. 2.) Suggest alternative critria and corresponding methodology for determining the optimum selection and timing of new energy facilities. 3.) Recommend a criteria and methodology Develope long range scenarios to satisfy energy needs over the 28 year study period including but not limited to the following: 1.) Alternative hydroelectric projects as listed in Paragraph 4.j. above. 2.) Purchasing energy through transmission interties to the north, south or both directions. 3.) Combination hydroelectre listed in Paragraph 4.3. above and transmission intertie. 4.) Meeting additional demands with thermo plants. 5.) Installation of a second transmission line from Snettisham to Juneau. 6.) Develope energy conservation programs that includes discouraging the use of electrc heat and implementation of incentives to increase efficient use of electric energy in order to postpone the requirement of energy resources in excess of the Crater Lake Addition during the study period. 7.) Other Discuss qualitative factors associated with alternative energy scenarios. Recommend #€ new energy facilities and their optimum scheduling to satisfy CBJ needs over the next 29 years. Review the prudence of the current policy of providing 186% backup generation for Snettisham. Make alternate recommendations if applicable. h. Review AELP policy utilizing EMD diesels to satisfy energy deficits between introduction of new base load sources of energy ate Perform sensitivity analysis to analyze impacts of: 1.) Major increase in the price of fuel oil 2.) Introduction of a major unanticipated load in the Juneau area such as a mine 3.) Delay in the completion of Crater Lake addition to Snettisham or other new additions. 4.) Other Contents of Proposal Your proposal should include the following information: a. Statement of Qualifications 1.) Resumes of individuals who will perform the study 2.) Description of previous projects in which your firm has participated that would indicate relevant experience. b. Statement of the Problem - Briefly state the problem as seen by your firm. e, A draft work Plan including definition of work elements and their scheduling to assure completion of the Plan in a timely manner. a. Billing information 1.) Provide estimated number of hours and hourly billing rates by individuals who will participate in the project 2.) Indicate breakout of cost by work elements, by labor, materials and other cost classifications 3.) Indicate total cost of performing the Study. Reports and the Public Process a. Prior too commencing the Study a meeting shall be held with the Juneau Energy Commmittee to receive their input. Within 45 days after the notice to proceed with the Plan preparation issue of brief memorandum on the status of the work. After issuance of the brief memorandum meet with APADM, APAUTH, AELP, GHEA and the Juneau Energy Committee to receive input and discuss issues. At this meeting obtain concurance of the sponsors the criteria and methodology for selection and timing of new energy facilities as per Para. 5.c.3.) above. Within 98 days present draft Plan. Verbally present findings of draft Plan in Juneau Public Hearing. After receiving and incorporating verbal and written comments prepare final Plan. Print 258 copies of final Plan. Turn over computer program and data base for energy model to APADM after completion of the final Plan. Selection Process - ae You may be asked to make a verbal presentation to the selection committee which will consist of a representative from AELP, APADM and AP ion is expected to be made not later than $83. Evaluation of proposals will be in accordance with the procedures outlined in Enclosure (7). 16 JUNEAU AREA POWER MARKET ANALYSIS UPDATE OF LOAD FORECAST MAY 1984 ALASKA POWER ADMINISTRATION U.S. DEPARTMENT OF ENERGY Department Of Energy Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 May 8, 1984 Colonel Neil Saling Alaska District Engineer Corps of Engineers P.O. Box 7002 Anchorage, AK 99510 Dear Colonel Saling: We are enclosing our latest update of load forecasts for the Juneau area. This study incorporates actual power use data through March 1984 and projected re- quirements through the year 2000. We are estimating FY 1984 net generation of 247 million kWh -- 10.3 percent above the previous year. A very mild winter plus curtailment of interruptible customers have helped to hold down the size of the increase. Our future estimates include low, medium, and high projections. The results show projected requirements of from 300 to 345 million kWh per year by 1990 and 364 to 507 million kWh per year by 2000. The estimate indicates full marketability of Crater Lake power by 1990, or shortly thereafter. The estimate of future demands incorporate much smaller rates of increase than the area experienced in recent years. Given the current strength of the area economy, our estimates may be too conservative. The area has experienced a hydro deficit the past two winters, as had been predicted in previous studies, requiring use of oil-fired generation to supple- ment the hydro supply. The deficit will increase each year until the Crater Lake unit of Snettisham Project is completed. We believe the new studies reaffirm the need to proceed as quickly as possible with completion of the Crater Lake Unit. Sincerely, Kibet Cer Robert J. Cross Administrator Enclosure CONTENTS Page INTRODUCTION. ............. alaisielevelelerelcielacievercvelaiclerstercieleielereielateretereieleleterciererene 1 BASIE BRR crore ro ercloloieie = oleleieinie ereleicicic cicieia a telelelcietorcieteleletetetererelalereielolelerelsvelele ee 1 EVALUEION OF RONG DATA 10 0.0.c1e s cicie/n ciclc'eisicfererere: eee! ete /eisiaieielo!s clelelielejerels erelele 8 Mem MOR LT) SRANON crcicicin cicielsiolelereie[aleloieie o cleleleisieie efela/a cleleiatelciclore)olelele) crore 8 Commercial anaymovermment Sector. < <5 6..c.ccinseccvcccccceccicccwcee 9 Weather Influence on Eneray Use... 0c cceccececcccecccseccccsesse 9 ESTIMB Ie (GE Finer, DEMANDS srever\cicre1o aise <lelelele cicie’ slave cleveleisicisiovsie'eys\eieie le ierercieve 12 RESULTS AND CONCLUSIONS. ......cccccececccececcucccececcseeeeucceees 18 TABLES 1. Juneau Area Net Generation and Peak Demand.................--05 2 2. Juneau Area Energy Sales and Percent of Sales by Sector........ 3 Qa. ene OF Calendar Year Statistics. <.s< <6j5ic ssc sisic cleieciwicicwisios cies. 4 3 Juneau: Airport Heating Degree Days...........sccesccesccccccees 6 4. Juneau Area Recent Electric Trends................00- alclonetetercieters 10 5. Juneau Net Generation Adjusted for Weather................-.005 11 6. Estimate of Future Demands, Low Projection................e005- 15 7. Estimate of Future Demands, Medium Projection.................- 16 8. Estimate of Future Demands, High Projection...........s-sseeeee i 9. Comparison of Juneau Area Hydro Resources Ye ESC IMMCOd PORES <4 ci5:5 inc < cinte <'<ibim Saiic.c 0:0 5 ernie c.s'~ o's aig tle mirisie a FIGURES 1. Estimated Enengy Requirements . u55% <.00.< <.0/c'00,0100.0¢ amlelsiciels «0101s te 20 INTRODUCTION Alaska Power Administration (APA) estimated Juneau area power requirements through the year 2000 for this study. This estimate updates similar studies completed annually for the past several years. The area has experienced a significant increase in peak demand and energy use since 1980 and the previous studies indicated area power use would exceed critical year firm energy from existing hydroelectric plants during fiscal year 1983. This actually occurred during the spring of 1983 as local utilities were required to furnish over 5 million kWh of diesel-generated electricity to supplement that available from the hydro plants. The hydro shortage during the past winter would have been much higher than the 13.0 million kWh actually gener- ated by diesel if the weather had not been so mild. The need for diesel gener- ation will generally increase each spring as area reservoirs are drawn down until additional hydro energy is available from Crater Lake. BASIC DATA The basic data and assumptions used for this study are essentially the same as those used in previous studies and includes data on energy use, economic, and climatic conditions. Energy and capacity use data came from monthly and annual reports by APA and the two local utilities, weather data from the National Oceanic and Atmospheric Administration (NOAA), and economic data from State and local sources. Table 1. presents annual system net generation and peak demand for fiscal years 1970 through 1984 along with annual percent increases. The dramatic increase in 1982 is partially attributable to the cold weather during that winter while the lower annual increase in 1983 is due to a combination of the cold winter in 1982 and the mild winter in 1983. The winter in 1984 was also mild which kept the energy growth rate and system peaks down. Energy use in 1983 and 1984 would, ave been about 3 million kWh higher if the interruptible class customers— had not been shut off in the winter. Table 2. presents sales by residential, commercial, and government sectors for the 1970-83 calendar year period while Table 2a. examines the 1982 and 1983 years in more detail. Residential customer use continues to be the largest sector with 1983 sales accounting for 51 percent of the total sales compared with a 13-year average of 45 percent for that sector. Com- mercial and government sectors have both decreased in the percent of over- all sales since 1979. Part of the reason for this strong growth in the residential sector had been the trend to all-electric homes in the area. An examination of recent residential sales in the AEL&P service area is shown below. 1/ Building Peak Demand Federal Bldg. 2,000 KW Bill Ray Center 300 KW Harborview School 1,000 KW Gold Belt Bldg. 500 KW Table 1. JUNEAU AREA ENERGY AND PEAK DEMAND System Net MWH X Peak MW X Generation Annual Demand Annual Fiscal Year MWH /1 Increase Mw Increase man eec St see eS acme eenane Seeeeeacec Sete ec2eee0 Bec e2ece2e= 1970 58, 266 12.4 . : 9.5 11.3 1971 63, 786 13.8 10.1 6.0 1972 70, 255 14.9 7.8 4.0 1973 75. 753 15.5 9.6 4.5 1974 83,059 16.2 13.9 TF 1975 94, 609 17.8 12.4 11.2 1976 106, 296 19.8 5.6 3.0 1977 112. 197 20.4 8.9 14.7 1978 122, 218 23.4 9.2 -1.3 1979 133, 457 23.1 7.2 13.4 1980 143, 128 26.2 16.5 22.9 1981 1646, 700 32.2 21.7 29.2 1982 202, 900 41.6 10.4. -3. 6 1983 224, 000 40.1 10.4 3.0 1984 247,400 /2 41.3 41 — Includes AEL&P and GHEA sales and losses. 42 — Estimate based on 6 months data. APA 4/84 giti AELUP OHEA Totel Percent AELOP QHEA Totel Percent AELUP QHEA Outdoor Lights Totel Percent TOTAL Table 2. JUNEAU AREA ENEROY SALES AND PERCENT OF SALES BY BECTOR (1,000 KWH) CALENDAR YEAR 1970 1971 19728 1973 1974 1975 1976 1977 1978 1979 1980 1901 1902 1983 Residential Beles 23,034 24,963 28,009 30,298 31,875 33,066 36,175 36,702 42,143 45,815 351.999 64,907 63.819 93.690 a@318 a. 980 3,027 3,165 2.545 3.794 4,126 4,292 4 o> 3.359 6,376 7,902 10,477 12,316 RENEE EERE BUREN E BEARER RANE RNRAR ARAN SERNA SERRE SERRA RE BANARAS SERRNS BARRE SERRE 25,349 27,143 31,036 33,4639 35,420 37,660 40,301 42.994 47,079 91,168 56,315 72.2809 94,290 106,174 “4 as a6 as 46 42 42 a2 43 43 45 aa 32 so Average Percent 1970-863: 45 x Commercial Seles 18,719 17,322 10,911 @8,03% 21.367 25,614 27,016 29,552 31,406 34,654 36,548 38,798 46,929 984,037 1,201 1.300 1,399 1, 106 1,622 1,628 1,951 2,060 2, 483 1,319 1,973 1,040 1,900 OC ORE ONE EN ORRRIN WRN WRENN BANNERS SEANAD BERNER BEEN TS SENN SS S88 NEES 868 BORED 16,964 18,710 19.900 29,978 22.5993 27,236 26,046 31,503 33.466 37,197 37,867 40,371 48,769 989.937 20 a1 2 EF] 29 EY 30 ke] | 31 29 27 27 27 Average Percent 1970-83: 30 % Gevernment Beles 13,942 13,927 15,327 16.399 17,5946 22,009 25,2539 27.232 26,626 30,671 31.329 32,931 36,004 42,971 395 “17 404 566 621 616 769 673 932 632 1,968 1,964 2, 168 2.936 7e2 741 734 695 703 795 ‘1: om 9 861.292 RCRD —ROMaMUREReMeMe NUMER MUI Re —MuREREMI eRe Ry MURAD Rennie RUMIMRE RA ARR Re My Me Mure ReRy Se MyM RyRyRe Ry eRe RRR ANY SRR Mey SRR Rely Gye ty Rete aety 14.719 19,009 16,545 17,660 18,872 23,620 26,042 28,105 27,798 31.309 33,318 35,966 40,010 46.399 2 25 29 24 25 27 27 27 26 26 26 24 22 zz Averege Percent 1970-83: 25 % 57,032 60,990 67,481 74,521 76,645 @8,716 95,189 102,602 108,303 119,408 129.500 148,226 189,069 208. 470 APA 4/04 . gle2 StS ttttttstsesee+ AELS&P SHFEE+ FFF esse Residential General Hot Water All Electric Subtotal Commercial Government Outside Lighting Street Lighting AEL&P Total SHEHEES Ett e tt eese GHEA SH ttt ttt eettt Residential Commercial Government Street Lighting GHEA Total PEPE HEE HEE t tt COMBINED ttt ttt tt Residential Commercial Government Outside Lighting Street Lighting JUNEAU Total Teble 2e. END OF CALENDAR YEAR STATISTICS Number of Customers 1962 ced 120 9, 444 1,018 47 SO 3 1,118 8.840 1,233 287 79 123 10, 562 1983 121 9,856 1,144 59 52 1,258 9,291 1,309 316 74 124 11,114 % Chg. -5.6 -2.4 46.4 4.2 5.4 11.4 -6.3 0.8 4.4 12.4 25.5 4.0 0.0 12.5 5.1 6.2 10.1 -6.3 0.8 5.2 Annual Gales (MWh) eee ee ae ee ee eee 1982 28. 439 25. 647 29. 727 "83, 613 46.925 36. 884 187 778 168, 587 10. 477 1.840 2.161 73 14.551 94,290 48. 765 39.045 187 851 183. 138 1983 26,258 25.743 39, 657 1,021 191, 632 12,316 1,900 2, 536 86 16, 838 106, 174 55,937 45.107 145 1,107 208, 470 x Chg 31.) 13." LTA £74 17-4 15.° 12. 14.° 13. APA 4/8: gl4 AEL&P October through April Sales (million kWh) Class Residential Customer 1980 1981 1982 1983 1984* General 18.6 18.1 18.5 17.8 18.2 Hot Water 11.0 12.9 15.7 15.7 16.2 All Electric 1.3 6.5 19.1 24.0 xy ae A TOTAL 30.9 37.5 53.3 57.5 67.1 *April sales estimated. The trend toward all-electric homes through 1983 is further shown by the shift in the number of AEL&P customers from the general class to the hot water and all-electric class. Number of AEL&P Customers Class of Residential Customer Dec'80 Dec'81 ODec'82 Dec'83 Mar'84 General 4,829 4,327 4,470 4,221 4,256* Hot Water 1,753 1,886 2,008 1,959 1,998 All Electric 348 872 1,344 1,967 2,130 TOTAL 6,940 7,085 7,822 8,147 8,384 *As of March 1984, approximately 800 customers are boat slips with 150 live aboard. This results in less than 50% of the total customers now in the General class. AEL&P data was presented above since GHEA does not report residential classes in this form. AEL&P serves 90 percent of the area customers and is considered representative of GHEA customers. The shift in the residential sector to the hot water and all-electric classes caused the use per customer in the sector to increase. Tracking this energy use for both AEL&P and GHEA for the last several calendar years shows: Residential Customer Energy Use cy1979 CY1980 cCyY1981 CY1982 CY1983 Average No. of Customers 7,197 7,490 7,801 8,493 9,074 Residential Energy Sales 51.2 58.2 72.3 94.3 106.2 (million kwh) Use per Customer (kWh) 7,110 7,770 9,270 11,100 11,700 The increases in use per customer can be attributed primarily to new electric heat and hot water use, however, part of the 1982 increase is due to the cold weather during that year's heating season. A summary of heating degree days for the past 25 years is shown in Table 3. Economic and construction information was obtained from contractors, utilities, and Borough officials. A summary of the major points revealed: Fy gaz2e8 1959 1960 1961 1962 1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1960 1981 1982 1983 Table 3. JUNEAU AIRPORT HEATING DEGREE DAYS Oct Nov Dec 736 737 660 760 645 625 614 654 812 671 902 724 783 611 810 732 690 712 679 695 612 609 626 682 699 928 911 915 1027 610 1093 980 1045 1433 973 920 975 1110 1001 907 1253 s51 1088 T4F 1062 1037 830 783 841 1027 1076 926 9356 1246 1132 993 1496 1162 1188 1162 1405 921 1343 1360 1275 1143 957 1244 938 1423 1134 1187 1333 1175 1029 Jan Feb Mar 1449 1146 1062 1182 1147 1098 1291 1746 1291 1432 1801 1329 1607 1519 1423 1550 1296 1132 918 1233 1370 1404 843 1584 1073 1022 911 932 1097 ses 835 1154 1090 963 1043 1219 830 1029 1315 1126 1006 1129 1131 690 922 1505 895 899 1213 924 9359 1019 938 1095 1023 11186 923 1071 1261 984 1054 876 1112 1166 986 1242 1063 1006 893 954 904 949 786 1017 931 Apr May Jun Jul 781 Se2 285 328 713° 470 #409 321 746 S36 371 262 756 627 447 250 846 SOO 431 288 785 610 336 324 813 693 487 292 805 667 355 265 824 S92 300 340 e0s SOS 374 248 727 464 #218 343 770 601 422 387 784 658 346 227 906 6168 432 207 7532 S64 404 343 765 S56 437 349 791 S41 402 281 706 SF7 384 280 673 531 320 243 683 S25 317 298 712 S28 378 251 678 477 278 283 772 392 316 257 816 627 257 220 663 470 272 235 Aug Sep Tot 378 355 339 305 244 347 297 382 303 281 448 405 290 293 404 315 337 275 196 262 205 308 275 310 317 498 466 Sit 486 375 453 435 466 444 516 S2i 553 504 535 505 437 402 427 428 427 415 472 469 435 502 90 64 82 92 83 86 94 97 95 90 99 67 97 101 95 97 87 89 72 88 90 83 Th 91 81 Ree eRe Pee ee Ne Re ee Pea Per Parte Pa Peg a Pa Pea eg Pes Peg eg Pea Pra hg Peg rg Re Pes rg Rag Pra hg Rg Pea ey Re Prag Peg Rg Pa Re Rete y My Pa Me My Re a Re Pa My Ry Rey Mg Rae Re Pe he Re Re Ray Rae 25-Year Average 704 971 1169 1317 1031 1014 763 S558 359 285 315 467 8&9 ee Pe Pee Ree Re Pe Rr Pes a Par ar ag Pes ag eg Pra Par a Pras Pe Peg Pe Pr a Per Pap Pg Pr Prag 1984 Source: 7o1 Climatological Data. 989 1425 1015 839 794 National Oceanic and Atmospheric Admin. Re Re Paths Re he Pee Re Pea Per Re Pea Ry Rey Ree Rep ag Pes Mer Po Pag Peg Pea Pry Pea Pegs APA 4/\ git: Residential Sector Plans: Essentially all new housing in 1982 was all- electric. The 1983 construction showed a trend back to fuel oi] heating systems with about 50 percent of homes being built at the start of the 1984 season being all-electric. Basically, most single-family residences being built were oil-heated while multi-family units were all-electric. About 75 percent of new residential units are multi-family and 25 percent single-family. A number of re-conversions back to oi] systems were also noted by heating contractors. Commercial Sector Plans: Growth in this sector should continue strong this year with completion of the Fred Meyer store, Jordan Creek Mall, expansion of Nugget and Mendenhall Malls, and construction of numerous office and other buildings throughout the city. The Gold Creek Development should contribute significantly to growth in the downtown area. Government Sector Plans: Moderate growth should continue in this sector to meet new programs and maintain existing state positions in Juneau. Federal employment should continue at its present level. Nearly 300,000 square feet of additional space requirements, at a minimum, have been identified by 1991, and an additional 300,000 square feet of optional office space according to load forecasts by ALE&P. Noranda Mining Corporation is continuing plans for operation of its' Greens Creek site on Admiralty Island by about 1987. Approximately 300 employees would be involved, with most living in Juneau. Evaluation of future mining at the AJ and Treadwell Mines is continuing. It is estimated that AJ could process 10,000 to 20,000 tons of ore per day and Treadwell about 1,000 to 2,500 tons a day. This would require an electrical supply of about 22.5 mw. These loads are not included in the forecasts. EVALUATION OF BASIC DATA This section evaluates the basic historic data, explains the recent growth, and looks for trends that could affect future growth. Residential Sector A summary of October through April AEL&P residential sales and number of customers for the past five seasons was presented in the previous section. Examination of this data shows the following trends: Residential Sales by Class of Customer Oct-Apr Oct-Apr Oct-Apr ; Oct-Apr* FY 1981 FY 1982 FY 1983 FY 1984 Increase Increase Increase Increase Class Gwh = Gwh % Gwh % Gwh = & General -0.5 -2.7 0.4 2.2 -0.7 -3.8 0.4 2.2 Hot Water 1.9 1753 2.8 21.7 0.0 0.0 0.5 3.2 All Electric 5.2 400.0 12.6 193.8 4.9 25.6 8.7 36.2 TOTAL 6.6 21.4 15.8 42.1 4.2 7.9 9.6 6.7 *April sales estimated. General Class - - Sales have decreased slightly the past few years to users without electric hot water heating and have increased to those with electric hot water heaters. Overall, the net increase has been about 3.8 per- cent annually. - - Number of customers has declined 5 percent between December 1980 and March 1984. - - Use per customer has increased about 3 percent annually the past few years. All Electric Class - - Almost all homes built from 1979-1983 were in the all-electric class. This trend is diminishing with about 50 percent of new residences presently being all-electric. - - For FY 1981 through FY 1984, 87 percent of the increase in October to April AEL&P residential energy use occurred in the all-electric class. - - October to April energy use during the past five years increased from 1.3 million kWh (4 percent of total residential use) to 32.7 million kWh (49 percent of total residential use). Commercial and Government Sectors Commercial - - Sales have increased about 11 percent annually since 1979, however, the increase for 1983 alone was 15 percent. - - This sector accounts for 27 percent of energy sales. Government - - Sales have increased about 10 percent annually since 1979, however, the 1983 increase amounted to 16 percent. - - This sector accounts for about 22 percent of energy sales. Residential Energy Use Per Customer Residential customer use increased 4,590 kWh per customer (65 percent) between 1979 and 1983, primarily because of the trend to all-electric heating. A breakdown in energy use in the various classes for the past five years show: Kwh per Customer Class cy1979 cY1980 cy1981 cy1982 cY1983 General 5,850 5,970 6,070 6,460 6,500 Hot Water 11,070 11,520 12,120 13,060 12 ,980 All Electric 23,560 24,530 23,760 26,590 24,075 A summary of recent trends in electrical use in the Juneau area is shown in Table 4. Weather Influence on Energy and Capacity Juneau power demands have always been sensitive to weather and this is clearly shown on Table 1. where the 1981, 1982, and 1983 generation and peak figures are shown. The cold 1982 season resulted in increases in energy and peak demand of 21.7 percent and 29.2 percent respectively while the warm 1983 season following the cold 1982 season resulted in an energy increase of only 12.4 percent and a decrease in the peak of 3.6 percent. It is then possible to adjust the energy usage during cold and mild winters to annual heating degree days to determine what that usuage would have been during an “average" winter. Table 5. presents a summary of adjusted, net generation figures for the past winter. It shows that an “average” winter would have required about 4 million more kWh of energy than was actually generated. If the past winter had been colder than normal, calculations show that about 12-15 million kWh of additional energy would have been required. Table 4. JUNEAU AREA RECENT ELECTRIC TRENDS ; Change Change Change FY79 <--%--> FY8O <--%--> Fv@i <--%--> FY82 <--%--> Fye3 Population 19,174 2 19,300 3 20,085 7 21,495 6& 22,680 Residential Customers 7,197 4 7,490 3 7,725 7 8, 267 6 8, 800 All-Electric Customers 69 110 145 259 520 101 1,043 60 1,670 Residential Sales (MWH) 51,168 14 58,315 24 72,289 30 94,290 13 106, 174 S Commercial Sales (MWH) 37, 137 2 37,867 7 40,371 21 48,765 15 55,937 Government Sales (MWH) 31,303 6 33,318 7 935,366 12 ‘40,010 16 46,359 Residential Sales 43 5 45 9 49 6 52 -2 51 % of Total Commercial Sales 31 -6 29 -7 27 0 27 0 27 % of Total Government Sales 26 ° 26 -8 24 -13 2i +} 22 % of Total APA 4/84 pits Il Table 5S. JUNEAU NET GENERATION ADJUSTED FOR WEATHER <FY84> 3 DEQREE DAYS ORO a Ra Ra ae a a Ps a a a a eg Pa eg a Pea Pea Peg a a eg Pa a Peg Pg Pg Ps Re Ra Morn a Rg Variation from Temperature Ad justed Average Net Ad yustment Net 25-VYear Pea eo Pea Pa Peo Ma Ra a Pa er er Pea a a Pathe Mo Rg Generation RUNUUUUUUUUNNUUNN Boneration Month Actual Average Degrees (%) OWH % (C1) OWH C2) OWH ae es es te a we oe ns ae eet Ne Pm at eno seaeeeee ow ee we sauenee eo Oe ae oe a Oct 701 704 -3 0.4 20.4 0.2 0.0 20.4 Nov 989 971 18 1.9 22.4 -0.9 -0.2 22.2 Dec 1,425 1,169 256 21.9 27.3 -10.9 -3.0 24.3 Jan 1,015 1,317 -302 -22.9 24.1 115 9s— 2.8 26.9 Feb 839 1,031 -192 -18.6 21.8 9.3 2.0 23.8 Mar 794 1,014 -220 -21.7 21.5 10.8 2.3 23.8 asauenem ee a 137.5 141.5 C1] - Degree Days percent variation times 0.5 C2] — Adjustment percent times net generation. APA 4/84 jltSa ESTIMATE OF FUTURE DEMANDS Estimates for future loads were made for three cases which are identified as low, medium, and high projections. Assumptions The FY 1984 estimated loads were based on net generation data for the first six months of the fiscal year and were extended to a 12 month period by assuming that the growth rate for the second half of the year would be essentially the same as the rate for the first half. Additional assumptions include: All_cases Population Growth (based on estimates in the April 1983 "Juneau Economic study" by Homan-McDowell and forecasts for AEL&P prepared by CH2M Hill). 1983-1990 3% annually 1990-2000 2% Population per residential customer 2.6 Residential Use per Customer: Single Family General Class 7,500 kWh annually Hot Water 12,900 kWh annually, All Electric 26,000 kWh annually2/ Multi-Family General Class 6,000 kWh annually Hot Water ‘ 12,900 kWh annually, All Electric 22,000 kWh annual ly“/ Low Projection Case Residential Sector General Class: About 40 percent of new customers are going into this class in 1984. This is assumed to increase to 80 percent by 1990 and hold constant thereafter. Hot Water Class: About 10 percent of new customers in 1984 are going into this class and this percentage is assumed to remain unchanged for future years. All Electric Class: About 50 percent of new customers are going into this class in 1984. This is assumed to decrease to 10 per- cent by 1990 and hold constant thereafter. 1/ From a sample of individual residential use in the Lakewood area. (AEL&P) 2/ From a sample of users in the Parkshore Condominiums. (AEL&P) 12 New residential construction is about 75 percent multi-family in 1984. This is assumed to increase to 90 percent by 1990 and hold constant. Annual increases in use per customer are assumed to decrease to 0 percent by 1986. Use per customer will then decrease starting in 1988. This decrease is assumed to reach 2 percent annually by 1995 and remain at that figure thereafter. Commercial Sector Loads in this sector were assumed to increase by 12 percent in 1984; 8 percent in 1985; and 4 percent annually for all following years. : c Government Sector Loads in this sector were assumed to increase by 10 percent in 1984; 6 percent in 1985; and 3 percent annually for all following years. Medium Projection Case Residential Sector General Class: About 40 percent of new customers are going into this class in 1984. This is assumed to increase to 70 percent by 1990 and hold constant thereafter. Hot Water Class: About 10 percent of new customers in 1984 are going into this class and this percentage is assumed to remain unchanged for future years. All Electric Class: About 50 percent of new customers are going into this class in 1984. This is assumed to decrease to 20 per- cent by 1990 and hold constant thereafter. New residential construction is about 75 percent multi-family in 1984. This figure is assumed to remain unchanged for future years. Annual increases in use per customer are assumed to decrease to O percent by 1988. Use per customer will then begin to decrease. This decrease is assumed to reach 2 percent annually by the year 2000. Commercial Sector Loads in this sector were assumed to increase by 12 percent in 1984; 10 percent in 1985; and 5 percent annually for all following years. Government Sector Loads in this sector were assumed to increase by 10 percent in 1984; 8 percent in 1985; and 4 percent annually for all following years. 13 High Projection Case Residential Sector General Class: About 40 percent of new customers are going into this class in 1984. This is assumed to increase to 50 percent by 1990 and hold constant thereafter. Hot Water Class: About 10 percent of new customers in 1984 are going into this class and this percentage is assumed to remain unchanged for future years. All Electric Class: About 50 percent of new customers in 1984 are going into this class. This is assumed to decrease to 40 percent by 1990 and hold constant thereafter. New residential construction is about 75 percent multi-family in 1984. This figure is assumed to decrease to 60 percent by 1990 and hold constant thereafter. Annual increases in use per customer are assumed to decrease to QO percent by 1990. Use per customer will then begin to decrease. This decrease is assumed to reach 1 percent annually by the year 2000. Commercial Sector Loads in this sector were assumed to increase by 12 percent in 1984 and 1985; and 6 percent annually all following years. Government Sector Loads in this sector were assumed to increase by 10 percent in 1984 and 1985; and 5 percent annually for all following years. Tables 6. through 8. present the load forecasts for the three cases through the year 2000. 14 ST Population e@ per Customer tial Customers (Average) Residential Bales Generel Class, Customers KWH/Custemer Millien KWH Hot Water Clase, Customers KWH/Custemer Millien KWH All Electric Class, Customers AWH/Customer Million KWH Commercial Beles (Hieteric 30%) Bubtetel Commercial, Millien KWH Government Seles (Histeric 29%) Bubtotel Oovernment, Million KWH Btreet Lighting, Residential & Government, Million KWH Totel Sales, Million KWH Net Generation, Millien KWH (119% Beles) Bystem Cap. Facter % 1/ Peat Demand, MW (Mieteric 45%) Actual Fv 21,495 2.6 @, 267 7,052 37.3 1,938 13, 100 23.3 1,043 26, 700 27.6 46.7 37.1 174.2 202.9 93.0 42.0 Table 6. ESTIMATE OF FUTURE DEMAND LOW PROJECTION Actual FY 1963 22, 880 2.6 @, e800 3,169 4, 900 33.6 1,961 12, 900 29.3 1,670 24,500 40.9 53.5 43.7 1.0 198.0 224.0 63.0 40.1 1/ Mild winters caused 1983 and 1984 to differ. FY 1904 23, 566 2.6 9,064 1.2 214.1 246.2 48.0 41.3 FY 19@5 24,273 2.6 9,336 3, 4a1 6,991 35.7 2,019 13, 094 26.4 1,911 24, 47.1 109.2 44.7 51.0 226.0 260.0 55.0 54.0 FY 1906 25, 002 2.6 9,616 5,969 6, 986 36.6 2,043 13,094 26.7 2, 009 24,599 49.4 112.8 67.3 53.8 1.2 295.1 270.3 55.0 56.1 FY 1987 25.752 2.6 9,904 3.7308 6,378 37.7 2,071 13, 094 27.1 2,099 24,5230 51.4 116.3 70.0 1.2 242.9 279.3 55.0 38.0 fv 1908 26, 324 2.6 10, 202 3,991 6,537 38.8 2.101 13, 029 27.4 2.170 24,954 92.8 119.0 72.6 97.1 1.3 250.1 267.7 53.0 59.7 ev 19989 27,320 2.6 10, 508 6,145 6, 462 39.7 2,132 12,698 27.5 2,231 24,065 33.7 120. 9 73.7 36.6 1.3 256.7 295.2 55 0 61.3 FY 1990 27,066 2.6 10. 718 @ 313 6. 356 40.1 2.199 12.7035 27.4 2.292 23. 689 53.3 78.7 60.5 1.3 261.4 300.6 39.0 62.4 fv 1999 20. 767 2.6 11,633 7, 206 % 712 41.2 2, 363 21,343 30.4 117.6 72.7 1.4 267.9 330.6 FY 2000 33, 969 2.6 13, 063 @.19%1 3. 198 42.1 116.9 1.9 17.0 364.9 39.0 79.7 APA 4/04 site oT (Average) Residential Gales (Hieteric 45%) General Class, Customers KWH/Customer Million KWH Hot Water Clase, Customers KWH/Customer Million KWH All Electric Clase, Customers KWH/Custemer Mil lion*KWH Gubtetel Residential, Millien KWH Commercial Gales (Histeric 30%) Gubtetel Commerciel. Million KWH Government Gales (Histeric 28%) Gubtetel Cevernment, Million KWH Street Lighting, Residential & Gevernment, Millien KWH Totel Gales, Miliien KWH Net Generation, Million KWH (119% of Beles) Gystem Cap. Factor X 1/ Peat Demand, MW 1/ Mild winters caveed 1983 and 1984 to differ. Actual 1982 21,499 2.6 @, 267 5.209 7,092 37.3 1,999 13. 100 23.3 1,043 26. 700 27.8 46.7 37.4 174.2 202.9 55.0 42.0 Table 7. E®TIMATE OF FUTURE DEMAND MEDIUM PROJECTION Actual FY 22,680 2.6 @, 800 5,169 6, 500 39.6 1,961 12, 900 23.3 1,670 24,300 40.9 99.6 33. 1. 198. 224. 63. 40. FY 1904 23, 544 6 9,064 8,275 6, 627 1,987 13,156 26. 1,@02 24,8676 a4. 2158. 247. 41. wos FY 1985 24,273 2.6 9,336 3.397 6,724 346.3 2,019 13,355 26.9 1,924 25, 160 46.4 63.9 1.9 1.2 230.6 263.2 55.0 55.1 FY 1986 25, 002 2.6 9,616 3.937 6, 788 37.6 2,043 13, 489 27.6 2,036 25, 396 51.6 116.7 69.2 12 242.4 278.6 59.0 97.9 FY 1967 23.792 2.6 9,904 2.137 25, 402 34.3 72.7 57.3 12 292.6 290.5 55.0 40.3 FY 1988 26,524 2.6 10, 202 3.674 6 @15 40.0 2,101 13, 956 28.9 2.227 25,959 56.4 76.3 59.8 1.3 262.4 301.7 55.0 62.6 FY 1989 27,320 2.6 10, 308 6.073 6. 777 41.2 2,132 13, 489 26.8 2,303 25, 167 38.0 127.9 62.2 1.3 271.3 312.3 53.0 64.8 FY 1990 27, 666 2.6 10,718 6, 2720 6.707 41.7 2,199 13, 354 20.7 2.945 24,919 3a. 4 128.9 1.3 279.0 320.8 55. ° 66.6 FY 1999 30. 767 2.6 11,633 7,008 6, 207 43.9 107.4 1.4 320.6 368.6 59.0 7.3 FY 2000 2.014 20. 727 38.3 1.9 366. 4 421.4 39.0 e7.9 APA 4/04 git? LT aod Actual Fy 1902 Population People per, Customer Residential Customers (Average) al Seles 21,495 2.6 @, 267 (Histeric 45%) Customers 5.209 AWH/Custeomer 7,052 Millien KWH 37.3 Hot Water Clase, Customers 1,935 KWM/Customer 13, 100 Millien KWH 25.3 All Electric Clase, Custemers 1,043 KWH/Custemer 26, 700 Millien KWH 27.8 Bubtetel Residential, Millien KWH 90.35 Commercial Seles (Mistoric 30%) Bubtetel Commercial, Millien KWH 46.7 Government Geles (Historic 25%) Subtotal Oovernment, Millien KWH 37.1 Street Lighting, Residential & Government, Million KWH Total Gales, Millien KWH 174.2 Net Generation, Millien KWH (115% ef Gales) 202.9 Bystem Cap. Facter % 1/ 89.0 Peat Demand, MW 42.0 Table 8. ESTIMATE OF FUTURE DEMAND HIOH PROJECTION Actual FY FY FY FY FY 1983 1904 1985 1986 1987 Emeuwre Oe mm eseeeee @eeevee 22,880 23,566 24,273 29,002 25.752 2.6 2.6 2.6 2.6 26 @,800 9,064 9,336 9% 616 9% 904 3.169 9,279 3.989 5,509 9,699 6,900 6.627 6.758 6.892 6.99% 33.6 93.0 36.4 28.0 39.4 1,961 1,987 2,019 2,049 2,071 12,900 13,198 13,421 13.690 19,699 29.3 26.2 27.0 20.0 208.8 1,670 1,002 1.999 2,064 2,194 24,900 24,076 25,286 25,717 26,049 40.9 44.0 48.2 93.1 57.1 99.8 109.9 112.39 119.0 129.4 99.5 39.9 67.1 74.1 73.4 49.7 40.1 92.9 36.8 99.7 1.0 1.2 1.2 1.2 1.2 198.0 219.1 293.5 248.2 261.6 224.0 247.4 266.9 209.4 300.9 63.0 68.0 39.0 595.0 983.0 40.1 41.9 59.7 99.2 62.9 1/ Mild winters caused 1983 and 1984 to differ. FY 1996 26, 524 2.6 10, 202 3.779 7,067 40.8 2.101 14,034 29.5 2,392 26,2598 61.0 131.3 79.9 62.6 1.3 273.2 316.4 95.0 65.7 FY 1989 27,320 2.6 10, 508 3.926 7,104 42.1 2,132 14,104 30.1 2.490 26,954 64,6 136.7 04.7 65.8 13 268.5 331.8 55.0 489 27, 066 2.6 10, 718 @,031 7.106 42.9 2,199 14, 104 30.4 2,994 26, 336 66.7 140.0 69.1 1.3 300.1 349.2 99.0 71.6 20, 767 11,033 6, 908 6.939 43.7 2. 264 13,799 u.1 2, 9e1 25, 606 76.3 193.2 90.6 1.4 369.4 420.2 59.0 @7.2 8 ait 7,208 6, 607 2.473 24,292 119.7 1.3 aa. 907. 4 APA 4/04 gite RESULTS AND CONCLUSIONS Considerable increases in electric power use have been experienced in Juneau in the past few years. These increases reflect substantial growth in the area's economy and the shift from oil to electricity for a significant part of space heating. Weather related factors have also played a role in creating large increases during certain years. This is shown by the increases in energy use in 1981; 1982, and 1983 of 16 percent, 22 percent, and 10 percent, respectively. These three years consisted of a warm weather year followed by a colder year, followed by a warm year again. Adjusting those years for weather would result in increases of about: 1981-18 percent; 1982-17 percent; and 1983-15 percent (if the interruptible customers were not shut off, 1983 would have been about 17 percent). . The first six months of fiscal year 1984 indicate that this high growth has started to decrease as energy use was only about 10 percent higher than the same period in 1983. This can be attributed to a number of things; the first being the stabilization of oi] prices and hydro shortages during winter months have made oi] heating systems attractive again. Also, the tremendous spurt in construction activity following the capital move vote has started to subside. Home building permits numbered over 900 in 1983 while 1984 is expected to see fewer than 500. The three forecasts prepared for this study included low, medium, and high projections. The following general statements relating to annual electric growth under the latest estimates can be made: Low Projection - Future annual growth decreases from the 9.9 percent projected for 1984 to about 1.8 percent by 1990. Annual growth from 1984 to 1990 is about 3.4 percent and about 1.9 percent from 1990 to 2000. Annual growth from 1984 to 2000 is about 2.5 percent. Medium Projection - Future annual growth decreases from the 10.4 percent pro- jected for 1984 to about 2.7 percent by 1990. Annual growth from 1984 to 1990 is about 4.4 percent and about 2.8 percent from 1990 to 2000. Annual growth from 1984 to 2000 is about 3.4 percent. High Projection - Future annual growth decreases from the 10.4 percent pro- jected for 1984 to about 4.0 percent by 1990. Annual growth form 1984 to 1990 is about 5.7 percent and about 3.9 percent from 1990 to 2000. Annual growth from 1984 to 2000 is about 4.6 percent. Figure 1. graphically compares this year's forecast and those completed previously. A comparison of Juneau area hydro power resources and forecasted demands is shown on Table 9. The firm energy deficit which began in 1983 increases each year and by 1988 amounts to a shortage of 67 million kWh for the low projection case, 81 million kWh for the medium projection case, and 95 million kWh for the high projection case. Deficits would also occur under average energy conditions since the Juneau area load is not large enough to utilize the large portion of this average energy occurring in the fall. Colder than normal winters will also have a serious effect on energy deficits. 18 APA presently has plans to temporarily increase the storage capacity at Long Lake by installing a small timber dam structure at the outlet. Modifications are scheduled for the summer of 1984 and could result in an increase in average annual -generation of about 4-6 GWH. AEL&P is presently underway with the rehabilitation of the lower Salmon Creek Power Plant. This work could result in an increased average annual generation capability of 15-19 GWH. However, due to timing of the runoff, this total amount may not be available each year. Although increased costs of energy (rate increases) were not evaluated for this study, it is obvious that consumers are more conscious of their energy usage and try to conserve where possible. As rates continue to increase, price elasticity will become an important factor in future load forecasts. The overall conclusion of this study is that the Crater Lake addition to Snettisham is needed regardless of which forecast is chosen as from 60 to 90 percent of the project's output could be utilized in 1988. APA will continue to monitor and assess energy use and changing economic conditions in order to determine the appropriate generation facilities beyond Crater Lake and the optimum timing for these facilities. Potential hydro sites beyond Crater Lake would include Long Lake Dam, Lake Dorothy, Sweetheart Lake, and Speel River. The two local utilities (AEL&P and GHEA), APA, and the Alaska Power Authority are jointly sponsoring a contract study with Ebasco Services, Inc. to look into the future development of generation facilities in the Juneau area. This reconnaissance level study will assist in defining the best utilization of the area's hydro resources and is expected to be completed this summer. 19 Comp2rison of Fieure 1. ESTIMATED ENERGY REQUIREMENTS oo ' \ ' \ " rk \ el SSeS Es Se 3 8 Kanennos “£31 a 20 Sroeth Tum, Low. Heat Morat tie Load o jection oO jecti Wiebe i Forecast. c i ih es tori ¢ 4 t 2 es a 2 ? Urili aeor LEGEND Resources scoersce=s= Estimated FY i985 1986 1987 1988 TABLE 9. Snettisham Long Lake AEL S&P Hydro Loads and Deficits Low Pro jection RNR I Estimated Loads Deficit 260 —38) zZ7O -49 279 -38 2388 -67 COMPARISON OF JUNEAU AREA HYDRO AND ESTIMATED LOADS (GWH Medium Pro jection POI II II IN ON Estimated Loads Deficit 265 -44 273 -53 230 -69 302 -81 21 RESOURCES High Pro jection Estimated Loads Deficit 268 -47 zes -84 301 -80 316 —3S APA 4/84 sits