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Kenai Peninsula Power Supply & Transmission Study 1982
RAI 019 vol. 1 KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY R. W. Beck AND ASSOCIATES, INC ENGINEERS AND CONSULTANTS June 1982 ALASKA POWER AUTHORITY KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY R. W. BECK AND ASSOCIATES, INC ENGINEERS AND CONSULTANTS June 1982 ALASKA POWER AUTHORITY RO. BOX 2400 SITKA, ALASKA 99835 FILE NO. R. W. Beck AND ASSOCIATES, INC ENGINEERS AND CONSULTANTS TOWER BUILDING RO. BOX 6818 7TH AVENUE AT OLIVE WAY KETCHIKAN, ALASKA SEATTLE, WASHINGTON 98101 99901 206-622-5000 UU-1559-ES1-AA June 16, 1982 3023 Alaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 Gentlemen: Sub ject: Kenai Peninsula Power Supply and Transmission Study In accordance with the terms of our agreement, we have prepared and herewith submit the report on the Kenai Peninsula Power Supply and Trans- mission Study. Our principal conclusions and recommendations are identified in the Conclusions and Recommendations Section of this report. The details of the study are included in the subsequent sections of the report. We appreciate the assistance and cooperation given to us by the staff of the Alaska Power Authority in preparation of this report. Respectfully submitted, R. W. BECK AND ASSOCIATES, INC. CERTIFICATE OF ENGINEER KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY The technical material and data contained in this report were pre- pared under the supervision and direction of the undersigned, whose seals as professional engineers are affixed below. W. Lowell Shelton Principal Engineer % R. W. Beck and Associates, Inc. nN Myr seeensenesttt a NA CeUFESSIONL Aaas® SSS NY sae or Ala My Li 4 , < enneth P. rriman Vice President R. W. Beck and Associates, Inc. Gy rete essseeettey M2 eraFEssiOWL = W aan Section Number KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY TABLE OF CONTENTS Letter of Transmittal Certificate of Engineer Table of Contents List of Tables List of Figures INTRODUCTION Introduction Scope Study Assumptions and Data Sources Conclusions and Recommendations . FWrh- 1 1 1 1. LOADS AND RESOURCES Load Forecasts Resources and Retirements Alternative Plans Transmission Facilities wMMN NY FWP ECONOMIC ANALYSIS 3.1 Assumptions 3.2 Results BRADLEY LAKE CAPACITY 4.1 Review of Corps' Analysis 4.2 Benefit/Cost Analyses - Bradley Lake Project Capacity ALLOCATION OF TRANSMISSION COSTS 5.1 Transmission Costs 5.2 Allocation of Costs RECOMMENDED TRANSMISSION STUDIES Transmission System Studies Route Selection Transmission System Design Scope of Work OO OOV ee . Fwnr- APPENDIX A - Data Sources Page Number = tt. toe Fuyuny— Table Zz E @o Ss oe ee © © © ww ew FWWWWWWWWPHND — = ida Hout gos J NAAN EWMH HWM -Nh — b NMUNNNNYNNNNNNHNTDY ' = 3.2-4 3.2-5 3.2-6 3.2-7 3.2-8 3.2-9 Frrrrrrrer . venir yy?> WOON WDM FWP | = LIST OF TABLES Title Peaks and Energy Forecasts for Railbelt Area of Alaska Peaks and Energy Forecasts for Kenai Peninsula Existing Resources Peak Load - Resource Comparison Energy - Resource Comparison Plan AA - Bradley Lake at 135 MW with Susitna Plan AB - Bradley Lake at 90 MW with Susitna Plan BA - Bradley Lake at 135 MW with Coal Plan BAA - Bradley Lake at 135 MW (on-line in 1991) with Coal Plan BAB - Bradley Lake at 135 MW (on-line in 1994) with Coal Plan BB - Bradley Lake at 90 MW with Coal Plan C - Combustion Turbines with Coal Plan D - Combustion Turbines with Susitna Summary of Transmission Costs New Generation Plant Data Summary of Economic Analyses Cumulative Present-Worth of Alternatives' Costs Railbelt Economic Analysis - Plan AA - Bradley Lake at 135 MW with Susitna Railbelt Economic Analysis - Plan AB - Bradley Lake at 90 MW with Susitna Railbelt Economic Analysis - Plan BA - Bradley Lake at 135 MW with Coal Railbelt Economic Analysis - Plan BAA - Bradley Lake at 135 MW (on-line 1991) with Coal Railbelt Economic Analysis - Plan BAB - Bradley Lake at 135 MW (on-line 1994) with Coal Railbelt Economic Analysis - Plan BB - Bradley Lake at 90 MW with Coal Railbelt Economic Analysis - Plan C — Combustion Turbine with Coal Railbelt Economic Analysis - Plan D - Combustion Turbine with Susitna Bradley Lake Economic Comparison Capacity and Energy Parameters/Assumptions Used in Bradley Lake Economic Analysis Peak Energy Benefits, Cases I, IIA and IIB Base Load Energy Benefits, Case IIA Base Load Energy Benefits, Case IIB January 1982 Capacity Values Bradley Lake Project Base Load Capacity Benefits Peaking Capacity Benefits Spinning Reserve Benefits LIST OF TABLES Page 2 Table Number an ___Title 4.2-10 Costs 4.2-11 Bradley Lake Benefits Without Susitna, 1982 42-12 Bradley Lake Benefits With Susitna, 1982 42-13 Benefit/Cost Summary, 1982 5.1-1 Transmission Costs, Plans AA and AB Figure Number 2-1 LIST OF FIGURES Transmission Facilities Title KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY SECTION 1 INTRODUCTION 1.1 Introduction The Kenai Peninsula, consisting of primarily the Cities of Kenai, Soldotna, Homer, Seldovia, Seward, and environs, is experiencing a relatively high load growth rate and forecasts indicate that this trend will continue for the next several decades. Presently, electric power is provided from gener- ation in the Anchorage area, and some generation on the Kenai Peninsula. The Corps of Engineers (Corps) is proposing the development of the Bradley Lake Project to provide power for the Kenai Peninsula and possibly the Anchorage area. The Alaska Power Administration (Administration) has performed several studies to assist in determining the Bradley Lake Project output and trans- mission requirements. The Bradley Lake Hydroelectric Project will be located on the Kenai Peninsula at the head of Kachemak Bay, approximately one hundred miles south of Anchorage, and approximately forty-five miles northeast of Homer. The project is an authorized Corps project. As proposed by the Corps and the Administration, the project will have a base load capacity of 70 MW with a 65 MW peaking capacity for a total installed capacity of 135 MW. The project will include a 17-mile double circuit 115-kV transmission line and switching station located 12 miles north of the head of Kachemak Bay. The switching station is proposed to have an interconnection with the Homer Electric Associ- ation (HEA) at their Fritz Creek Substation and the Chugach Electric Associ- ation (CEA) at their Soldotna Substation. 1-2 1.2 Scope The Alaska Power Authority (Authority) has contracted with R. W. Beck and Associates, Inc. (RWBI) to perform a comparative economic analysis of alternative generation and transmission plans for providing power to the Rail- belt area with emphasis on the Kenai Peninsula, and to determine the feasi- bility of constructing the Bradley Lake Hydroelectric Project including the required transmission facilities. The work described in this report was authorized in a contract dated March 19, 1982 between the Authority and RWBI. Existing basic data were used to identify a load-resource program for the Railbelt area. Eight viable alternative generation and transmission plans for the Railbelt area, with emphasis on the Kenai Peninsula, were de- veloped with the assistance of the Authority. The transmission facilities were determined for each plan. An economic analysis was performed on each plan using the Authority's fifty-year economic analysis parameters. The pro- posed installed capacity for the Bradley Lake Hydroelectric Project was re- viewed and analyzed on the basis of incremental capacity and energy benefits developed in the economic analysis for this study. Based on loads developed in the load-resource program, transmission costs for the Bradley Lake Project were allocated to the user utilities. Finally, a scope of work was prepared for the design environmental studies, and route selection for the proposed transmission facilities serving the Kenai Peninsula. This report discusses each of the phases of the study. 1.3 Study Assumptions and Data Sources This study was based primarily on existing basic data developed by others. Appendix A lists the sources of data used in this study. Due to the limited time to accomplish this study, the following major assumptions were adopted to expedite the study: 1-3 Load forecasts are based on projections prepared by the University of Alaska's Institute of Social and Economic Research and addition- al work by the Administration. One-third of the military and industrial load requirements are in- cluded in the total utility load requirements, the balance of these loads being supplied from independent generation resources. The Kenai area and Anchorage area loads were projected to increase at the same rate. Spinning reserve capacity is defined as capacity which can pick up load immediately, equal to the single largest generator capacity located in the Railbelt area. Forced outage reserve capacity is defined as capacity which can sustain the load, equal to the co- incidental capacity of the two largest generation units in the Anchorage area (with a maximum of 200 MW). Fuel consumption of combustion turbines running at speed-no-load (spinning reserves) will be at one-third of fuel consumption at full load. Costs will be based on the fuel consumption plus one- third of the variable operating and maintenance costs. The alternative generation and transmission 20-year plans were defined and coordinated with the Authority. The first circuit of the Fairbanks to Anchorage transmission line will be constructed for 345-kV and will be energized at 138-kV in 1984 and 345-kV in 1993, and the second circuit will be constructed and energized at 345-kV in 1993 in all of the plans. The Beluga to Teeland transmission requirements will first be met by existing excess transmission line capacity. 1-4 ° The costs used in the economic analysis were taken from existing reports and coordinated with the Authority. 1.4 Conclusions and Recommendations Based on the economic analysis of alternative resource plans for the Railbelt (Section 3.0), Plans AA and AB (the Bradley Lake Project at 135 MW and 90 MW with Susitna) were found to be the least costly. The eco- nomic analysis results indicate that there is little cost difference between the Bradley Lake Project at 135 MW or 90 MW. The review of the Corps of Engi- neers! evaluation of Bradley Lake Project incremental capacity indicated that the plant capacity of 135 MW selected by the Corps was reasonable. To confirm this evaluation, an incremental benefit/cost analysis was performed which indicates that the 135 MW project capacity is the better of the two alterna- tives. The economic analysis and the benefit/cost analysis are sensitive to the cost of fuel (oil and gas) for the combustion turbines. Because of the relative high cost of oil the analyses have an additional sensitivity to the percentage of oil as compared to gas used for combustion fuel. The analyses are also sensitive to the transmission costs. Transmission facilities' costs are allocated among the five user utilities based on historical peak and energy requirements. Plans AA and AB, the lowest cost plans, have the same transmission costs. Each utility is allocated a percentage of the total costs based on its percentage of histori- cal peak demand requirements. This study does not identify the transmission system routes. Therefore, a scope of work is defined in Section 6.0 to identify the work necessary to complete the route selection, environmental studies, design and construction of the transmission facilities for the recommended plan. Based on the assumptions and data utilized in this study, the Brad- ley Lake Project at a capacity of 135 MW is only slightly higher in cost than the lowest cost plan, but has the highest benefit/cost ratio. On this basis it is our recommendation that the project be included at a capacity of 135 MW as part of the Railbelt area resource plan. The final decision in regard to the capacity selected for the Bradley Lake Project may need to consider other factors which are not addressed in this study. SECTION 2 LOADS AND RESOURCES Peak loads and annual energy use including existing resources with unit retirement were developed for the entire Railbelt area over a twenty-year period starting in 1982. The Railbelt area was divided into three subareas to assist in defining the transmission intertie requirements. The subareas are as follows: Kenai Peninsula; Greater Anchorage; and Fairbanks. The Kenai Peninsula market area includes the cities and surrounding areas of Kenai, Soldotna, Homer, Seldovia, Seward, and one-third of the indus- trial loads on the Kenai. CEA's resources which serve those markets include the Bernice Lake combustion turbines and Cooper Lake hydroelectric facilities. The Greater Anchorage market area includes the City of Anchorage and its surrounding area; the developed areas of the Matanuska Valley which include the cities of Palmer, Wassila and Talkeetna; and one-third of the military loads in the Anchorage area. The following utilities' resources serve those markets: CEA's Beluga combustion turbines, Knik Arm combustion turbines and International combustion turbines facilities; Anchorage Municipal Light and Power's (AML&P's) Anchorage combustion turbines facilities; and the Administrations's Eklutna hydroelectric facilities. The Fairbanks market area includes the cities of Fairbanks, Nenana, Anderson, Healy and their surrounding areas. The following utilities' re- sources serve those markets: Fairbanks Municipal Utility System's (FMUS') Chena coal-fired and gas turbine facilities and Golden Valley Electric Associ- ation, Inc.'s (GVEA's) Healy coal-fired, North Pole combustion turbines and Zehnder combustion turbines. 2-2 Realistic alternative resource plans consistent with the Railbelt requirements were then developed for a 20-year period based on the forecast loads. The existing and proposed transmission grid in the Railbelt area was reviewed for each of the alternative plans. A transmission plan was developed for the loads and resources identified in the time frame needed for each of the alternative plans. 2.1 Load Forecasts A number of load forecasts were reviewed for possible use in the analysis of electric requirements for the Railbelt area. In order to remain consistent with other recent planning studies prepared for the Railbelt, the forecast of utility requirements relied on projections that were prepared by the University of Alaska's Institute of Social and Economic Research (1sER)'. The ISER forecast was made for customer sales only, therefore, figures developed by the Administration in their Bradley Lake study“, were used, which add system losses and the utilities' own loads to the ISER fore- cast. In addition to the utilities' resources, there are military instal- lations and industries which generate power to meet their own requirements throughout the Railbelt. In both the ISER study | and the Bradley Lake study, 100% of those additional loads were included in the forecast, assum- ing that they would buy all of their power from local utilities if the cost of that power were cheaper than the cost of generating their own power. The military and industrial loads are largely processor heating and are not appli- cable for being supplied from power generation. For this study, only one- third of the total military and industrial electric requirements was included in the forecast, assuming that the larger portion of power requirements would be met by their own generation regardless of the lower utility-generated power costs. This is considered to be a more appropriate and realistic model for the military and industrial loads. The Railbelt was subdivided into three geographic areas of analy- sis: the Kenai Peninsula, the Greater Anchorage area, and the Fairbanks area. Backup work sheets to the Bradley Lake report, supplied by the Adminis- tration, give both annual peak demand and energy forecasts for utilities by area of the Railbelt and for military and industry loads. However, the Kenai Peninsula loads are combined with the Greater Anchorage loads, requiring sepa- ration which was accomplished as follows. The 1980 historical energy figures indicate that the Kenai Pen- insula utilities included about 16.6% of the Greater Anchorage-Kenai Peninsula area's total electric requirements. Assuming that the Kenai area utilities and the Anchorage area utilities will grow at the same relative rate as pro- jected by the ISER study', the total Anchorage/Kenai requirements identified in the Bradley Lake Project study” were disaggregated for each year of the forecast. This assumption differs somewhat from the Administration's most recent forecasts for the Kenai area’ which indicate that the Kenai area will experience more rapid growth than the Anchorge area in the future, resulting in energy requirements 23% higher than this analysis shows for the Kenai area utilities by the year 2000, and 20% higher for the peak. The forecast of annual peak demand and energy requirements for each of the three major areas is shown for 1981-2001 on Table 2.1-1. Average annu- al growth in peak demand for the Railbelt area is 3.82% and growth in energy averages 4.36% annually. The Administration's forecast of requirements for the Kenai Pen- insula was used to determine the relative growth of each of the area's utili- ties: HEA, Seward Electric System (SES) and the Kenai Portion of the CEA service area. These forecast growth rates were then used as a basis for de- termining transmission cost allocation for each of these utilities for future years. The Administration's forecast was prepared for 5-year increments, from which values were interpolated for the remaining years. The results, shown on Table 2.1-2, indicate peak demand growing by 3.9% annually for HEA, by 4.9% for SES and by 3.1% in the Kenai portion of CEA. Energy is forecast to in- crease annually by 4.4% for HEA, by 4.2% for SES and by 3.2% for the Kenai portion of CEA. The transmission cost allocation for the Greater Anchorage utilities is based on the historical relative size of their peak loads as there were no current separate forecasts available for these utilities which are consistent with the ISER forecast. Transmission cost allocation for the Fairbanks area utilities was not addressed due to the emphasis on Kenai Pen- insula-Cook Inlet utilities. Section 5 of this report addresses the allo- eation of transmission costs. 2.2 Resources and Retirements 2.2.1 Resources Existing resources used to serve loads in the Railbelt area are primarily combustion turbines with some hydroelectric generation available to the Kenai Peninsula and Anchorage. A significant amount of coal-fired steam turbine generation is used in the Fairbanks area. Combustion turbines used in and around Anchorage are fueled with natural gas with some oil required as fuel during peak periods. Oil is used to fuel combustion turbines in the Fairbanks area. A detailed list of the existing resources used for the analyses included in this report is shown in Table 2.2-1. No diesel generating plants have been included since these units are used mainly as emergency generating resources. Additionally, the generating resources of military and industrial installations have not been included as these resources are assumed to supply only their respective loads. 2.2.2 Retirement Retirement of existing generating units is based on the assumptions 8 used by Battelle in its report. These assumptions are based on the typical 2-5 economic lifetimes of the various generation types (Battelle) as follows: Hydroelectric - 50 Years Natural gas-fired C.T. - 30 Years Oil-fired C.T. - 20 Years Coal-fired steam turbine - 30 Years Applying these lifetimes to the installation date of the existing generating facilities results in the retirement schedule shown in Table 2.2-1. The two existing hydroelectric plants, Cooper Lake and Eklutna, are assumed to be available throughout the study period. Although the economic lifetimes as assumed in this study provide a means of including the effect of retirements in analytical evaluations, actual retirement of any particular unit could vary significantly from the time shown due to a wide range of uncertainties. Presently utilities are economically writing off combustion turbines in less than 17 years. 2.2.3 Reserves For the purpose of this analysis, total Railbelt forced outage reserves are assumed to be approximately 200 MW based on the coincidental out- age of the two largest generation units in Anchorage. This assumption is based on the sharing of reserve requirements between Fairbanks, Anchorage and Kenai once reliable transmission interconnections are made. Prior to the availability of the Anchorage-Fairbanks interconnection in 1984, it is assumed that Fairbanks will maintain 65 MW of reserve and Anchorage-Kenai will main- tain 135 MW of reserve. Actual reserve requirements may vary significantly due to policy and operational requirements. 2.2.4 Load/Resource Analysis Based on the load forecasts shown in Section 2.1, existing re- sources shown in Table 2.2-1 and the foregoing retirement and reserve assump- tions, an annual peak load and existing resource comparison is shown in Table 2.2-2. Using the same sources of information, annual energy loads and exist- ing energy resources are shown in Table 2.2-3. These comparisons do not in- clude the addition of any new resources. The loads and resources of each of the three areas under study are presented separately and in total for the en- tire Railbelt area. Resource surpluses and deficits for each of the three areas do not include the effects of transmission interties between them except for the sharing of reserves. Although the entire amount of Railbelt reserves is shown as a responsibility of Anchorage upon completion of the Fairbanks to Anchorage intertie, the actual breakdown of where reserves are located will most likely vary. 2.3 Alternative Plans A total of eight alternative plans of generation and transmission consistent with the projected Railbelt area requirements for the next twenty years were formulated with primary emphasis on the portions comparable to the Bradley Lake Hydroelectric Project. The plans were developed such that they are consistent with the entire Railbelt area projected requirements. This study has a primary emphasis on the Kenai Peninsula projected requirements particularly relating to the Bradley Lake Project. Therefore, plans were developed considering various outputs for the Bradley Lake Project with the Susitna Hydroelectric Project and coal-fired generation. Plans were also developed that incorporate combustion turbines instead of the Bradley Lake Project. The plans are as follows: Plan Title AA Bradley Lake at 135 MW with Susitna AB Bradley Lake at 90 MW with Susitna BA Bradley Lake at 135 MW with Coal BAA Bradley Lake at 135 MW (on-line 1991) with Coal BAB Bradley Lake at 135 MW (on-line 1994) with Coal BB Bradley Lake at 90 MW with Coal c Combustion Turbines with Coal D Combustion Turbines with Susitna The following is a discussion of these alternative plans. 2.3.1 Plan AA - Bradley Lake at 135 MW with Susitna Plan AA includes the Bradley Lake Project at 135 MW. Since the Bradley Lake Project is not projected to be in service before 1988, a combus- tion turbine has been included under this plan to meet the earlier load re- quirements of the Kenai Peninsula. The earliest a combustion turbine can be installed is in 1983. It is sized at 20 MW to meet the Kenai loads until the Bradley Lake Project is in operation. Fairbanks has surplus capacity until 1992. In 1993 the Susitna Project is projected to be in service and will meet both the Fairbanks area and Anchorage area load requirements. The Anchorage to Fairbanks intertie, constructed at 345-kV, is planned to be in operation at 138-kV in 1984 with a firm capacity of approxi- mately 70 MW. The Anchorage to Fairbanks intertie is projected to be upgraded with a second circuit along with the first at 345-kV in 1993. Bradley Lake will be on-line by January 1988 and will be intercon- nected to the existing transmission system via 115-kV transmission lines from Bradley Junction switching station to Fritz Creek and Soldotna. The 19 miles of double circuit 115-kV transmission line from Bradley Lake powerhouse to 2-8 Bradley Junction switching station are assumed to be a part of the Bradley Lake Hydroelectric Project. An additional tie line between Soldotna and Anchorage will be constructed for 230-kV operation. Both the 115-kV and 230-kV transmission lines will go into service coincident with Bradley Lake Project on-line date of January 1988. The Susitna Hydroelectric Project on-line date is assumed to be January 1993, including the completed 345-kV transmission system. The results of this load resource plan are shown in Table 2.3-1. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 20 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1988 Bradley Lake Project 135 MW 1988 Anchorage to Soldotna Intertie 230-kV 1988 Soldotna to Homer Intertie 115-kV 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1993 Susitna Project (Watana I and II) 1,020 MW 2.3.2 Plan AB - Bradley Lake at 90 MW with Susitna Plan AB is the same as Plan AA except Bradley Lake Project has a projected capacity of 90 MW, with an in-service date of 1988. Additional early generation is also required under this plan. A 20 MW combustion turbine is included in 1983 at Bernice Lake and a 45 MW combustion turbine in 1990 at Beluga. The second combustion turbine was added at Beluga because it better served the loads in the Anchorage area. 2-9 The transmission facilities and Susitna Project assumptions are the Same as for Plan AA. The results of this load-resource plan are shown in Table 2.3-2. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 20 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1988 Bradley Lake Project 90 MW 1988 Anchorage to Soldotna Intertie 230-kV 1988 Soldotna to Homer Intertie 115-kV 1990 Combustion Turbine at Beluga 45 MW 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1993 Susitna Project (Watana I and II) 1,020 MW 2.3.3 Plan BA - Bradley Lake at 135 MW with Coal Plan BA is the same as Plan AA except a coal-fired generation plant is added at Beluga instead of constructing the Susitna Project. A 20 MW com- bustion turbine is required early at Bernice Lake as before. The 135 MW Brad- ley Lake Project is sufficient to supply the loads on the Kenai and a portion of the Anchorage area when it comes on line in 1988. Additional generation is needed by 1992 to maintain reserves. However, some of the retired combustion turbine units could be available, and so a 200 MW coal-fired generation plant has not been included as a resource until 1993. Additional 200 MW coal-fired generators are added in 1995, 1997, and 1999. As in Plan AA the 230-kV Anchorage to Soldotna intertie is pro- jected to be in operation in 1988. It will transmit excess power between Anchorage and the Kenai as needed. The 115-kV Soldotna to Homer intertie will be needed to meet the Homer area loads in 1988. The 138-kV Anchorage to Fair- banks intertie will be in operation in 1984 to better utilize the surplus 2-10 power in the two areas as well as transmitting the lower cost natural gas com- bustion turbine generation to Fairbanks. When the first 200 MW coal-fired generating plant is added in 1993, two 345-kV transmission lines are planned from the plant to Teeland. The second phase of the Anchorage to Fairbanks 345-kV intertie is also planned to be in operation in 1993. The 345-kV transmission system will intertie Fairbanks, Anchorage, and Beluga instead of Fairbanks, Anchorage, and Susitna as in Plans AA and AB. Since the total 345-kV circuit miles for the two 345-kV systems is very nearly the same, the cost for the Susitna Project 345-kV system was used with a reduction in cost for roads and trails only. The results of this load-resource plan are shown in Table 2.3-3. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 20 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1988 Bradley Lake Project 135 MW 1988 Anchorage to Soldotna Intertie 230-kV 1988 Soldotna to Homer Intertie 115-kV 1993 Coal-Fired Generator at Beluga with Transmission 200 MW 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1995 Coal-Fired Generator at Beluga 200 MW 1997 Coal-Fired Generator at Beluga 200 MW 1999 Coal-Fired Generator at Beluga 200 MW 2.3.4 Plan BAA - Bradley Lake at 135 MW (On-Line in 1991) With Coal Plan BAA is the same as Plan BA except this plan has the Bradley Lake Project delayed to 1991. Since it is delayed, more combustion turbine capacity will be required on the Kenai in the early years. A 30 MW combustion 2-11 turbine is included in 1983 at Bernice Lake. A deficiency occurs in the Rail- belt area reserves in 1989 and 1990 but it could be met by combustion turbine units which are projected to be retired. Fairbanks has insufficient gener- ation resources by 1992 but capacity can be imported by the 138-kV Anchorage to Fairbanks intertie. In 1993 a 200 MW coal-fired generation plant is in- cluded and additional 200 MW units are projected for 1995, 1997, and 1999. The transmission facilities for Plan BAA are the same as for Plan BA except the in-service dates are different. The results of this load- resource plan are shown in Table 2.3-4. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line _ Rating 1983 Combustion Turbine at Bernice Lake 30 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1991 Bradley Lake Project 135 MW 1991 - Anchorage to Soldotna Intertie 230-kV 1991 Soldotna to Homer Intertie 115-kV 1993 Coal-Fired Generator at Beluga with Transmission 200 MW 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1995 Coal-Fired Generator at Beluga 200 MW 1997 Coal-Fired Generator at Beluga 200 MW 1999 Coal-Fired Generator at Beluga 200 MW 2.3.5 Plan BAB - Bradley Lake at 135 MW (On-Line in 1994) With Coal Pian BAB is the same as Plan BA except this plan has the Bradley Lake Project delayed to 1994. With the Bradley Lake Project delayed, combus- tion turbines must be planned to meet the projected load requirements. A 55 MW combustion turbine is included at Bernice Lake in 1983 and two 75 MW com- bustion turbines are included at Beluga, one each in 1991 and 1992. A de- ficiency occurs in the Railbelt area reserves in 1990 through 1993, 1996, 2-12 1998, and 2001. This deficiency may be met by the retired combustion turbines as previously noted. The Fairbanks resource deficiency starting in 1992 again is met by the Anchorage area resources through the Anchorage to Fairbanks interties. The transmission facilities for Plan BAB are similar to those of Plan BAA except the Anchorage to Soldotna and Soldotna to Homer interties will not be in service until 1994, when the Bradley Lake Project comes on-line. The results of this load-resource plan are shown in Table 2.3-5. The follow- ing is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 55 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1991 Combustion Turbine at Beluga 75 MW 1992 Combustion Turbine at Beluga 75 MW 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1994 Bradley Lake Project 135 MW 1994 Anchorage to Soldotna Intertie 230-kV 1994 Soldotna to Homer Intertie 115-kV 1995 Coal-Fired Generator at Beluga with Transmission 200 MW 1997 Coal-Fired Generator at Beluga 200 MW 1999 Coal-Fired Generator at Beluga 200 MW 2.3.6 Plan BB - Bradley Lake at 90 MW With Coal Plan BB is the same as Plan BA except that the Bradley Lake Project has a projected capacity of 90 MW for operation in 1988. A 20 MW combustion turbine is included at Bernice Lake in 1983 for the Kenai loads. By 1990 more generation is needed in the Anchorage area and a 45 MW combustion turbine is added at Beluga. 2-13 In 1993, 1995, 1997, and 1999, 200 MW coal-fired generation plants are included at Beluga to meet Anchorage area and Fairbanks area loads. The Railbelt suffers a reserve deficiency in 1992 and 1998 which may be met by the retired combustion turbine units as previously noted. The transmission facilities for Plan BB are the same for those in Plan BA. The results of this load-resource plan are shown in Table 2.3-6. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 20 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1988 Bradley Lake Project 90 MW 1988 Anchorage to Soldotna Intertie 230-kV 1988 Soldotna to Homer Intertie 115-kV 1990 Combustion Turbine at Beluga 45 MW 1993 Coal-Fired Generator at Beluga with Transmission 200 MW 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1995 Coal-Fired Generator at Beluga 200 MW 1997 Coal-Fired Generator at Beluga 200 MW 1999 Coal-Fired Generator at Beluga 200 MW 2.3.7 Plan C - Combustion Turbines With Coal Plan C is the same as Plan BA except combustion turbines are added instead of constructing the Bradley Lake Project. A 55 MW combustion turbine is included at Bernice Lake in 1983 for the Kenai loads. A 50 MW combustion turbine is included at Beluga in 1990 and 1992 for the Anchorage area loads. The Railbelt area reserves are deficient in 1991, 1992, and 1998, but the re- tired combustion turbines are planned to meet the reserve requirements. Coal-fired generation plants rated 200 MW each are included in 1993, 1995, 1997, and 1999 at Beluga to meet the Railbelt area loads. 2-14 The transmission facilities required for Plan C are somewhat dif- ferent from the other plans. They are the same as for Plans BA and BB except the 115-kV line between Soldotna and Fritz Creek is not needed. The Anchorage to Fairbanks intertie is planned to be in-service the same time as for the previous plans, but the 230-kV Anchorage to Soldotna intertie is not needed until 1993 and the Soldotna to Homer intertie is not needed for the time frame of this study. The results of this load-resource plan are shown in Table 2.3-7. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 55 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1990 Combustion Turbine at Beluga 50 MW 1992 Combustion Turbine at Beluga 50 MW 1993 Coal-Fired Generator at Beluga with Transmission 200 MW 1993 Anchorage to Fairbanks Intertie, Second Phase two 345-kV 1993 Anchorage to Soldotna Intertie 230-kV 1995 Coal-Fired Generator at Beluga 200 MW 1997 Coal-Fired Generator at Beluga 200 MW 1999 Coal-Fired Generator at Beluga 200 MW 2.3.8 Plan D - Combustion Turbines With Susitna Plan D is the same as Plan AA except that the Bradley Lake Project is replaced by combustion turbines. A 55 MW combustion turbine is included at Bernice Lake in 1983 for the Kenai loads. A 50 MW combustion turbine is in- cluded at Beluga in 1990 and 1992 for the Anchorage area loads. The Railbelt area loads are deficient in 1991 and 1992, but the retired combustion turbines are projected to meet the required reserves as in the other plans. In 1993, 2-15 the Susitna Project (Watana I and II) is projected to be in operation with a capacity of 1,020 MW and associated 345-kV transmission facilities. These resources are adequate to meet the forecasted loads. The transmission facilities require the same Anchorage to Fairbanks intertie as for all of the plans considered in this study. The 230-kV Anchor- age to Soldotna intertie is planned for 1993, but the Soldotna to Homer 115-kV intertie is not needed for the time frame of this study. The results of this load-resource plan are shown in Table 2.3-8. The following is a list of the new resources and transmission lines for this plan: Date Resource/Transmission Line Rating 1983 Combustion Turbine at Bernice Lake 55 MW 1984 Anchorage to Fairbanks Intertie, First Phase 138-kV 1990 Combustion Turbine at Beluga 50 MW 1992 Combustion Turbine at Beluga 50 MW 1993 Susitna Project (Watana I and II) 1,020 MW 1993 Anchorage to Soldotna Intertie 230-kV 1993 Anchorage to Fairbanks Intertie two 345-kV 2.4 Transmission Facilities Eight alternative plans were considered in this study. Six of these plans involve the construction of three different voltage levels of transmission, 115-kV, 138-kV, 230-kV and 345-kV. The two remaining plans in- volve only 230-kV and 345-kV construction. Figure 2-1, Transmission Facili- ties, shows the transmission requirements for all of the plans. Some of the segments are not included in all of the plans and the segments are projected for service on different dates depending on the load and resource requirements. The transmission line voltages and conductor sizes were selected based on the projected line losses and the voltage drop. A maximum voltage drop of 5 percent and a line power factor of 0.95 were used to establish the 2-16 line voltages of each transmission line segment. Voltage drop was considered the overriding factor for this study. There are additional factors which should be included in the detailed design stage before the system voltages can be finally determined and detailed design criteria established, such as me- chanical design loading, economic conductor sizing, system load flows and sta- bility analyses. The transmission line corridors identified in this study were based on information from existing studies and topographic maps. There has been no field reconnaissance or studies to determine the engineering and environmental factors which might impact line routing. The following is a discussion of the transmission line segments required by the alternative plans. A 115-kV transmission line is planned to be constructed between Fritz Creek, Bradley Junction, and Soldotna. This line is used only for the plans which include generation at the Bradley Lake Project. Based on a simple voltage drop analysis for the individual line segment between Bradley Junction and Soldotna, it appears that a 230-kV line would be required to carry a 90 MW load with less than a 10 percent voltage drop. However, the Administration's load flow analyses indicate that 115-kV is sufficient and therefore, is used for this study. A 138-kV transmission line is planned to be constructed between Anchorage and Fairbanks. It will be constructed for 345-kV operation, but will be initially energized and operated at 138-kV until the additional ca- pacity of the 345-kV is needed in 1993. This line is common to all plans and is planned to be in operation in 1984. It has a projected firm capacity of approximately 70 MW. A 230-kV transmission line is planned to be constructed between Soldotna and Anchorage. Since this line will be needed regardless of gener- ation location it is common to all plans. The only difference in the plans being the projected in-service date. 2-17 The 345-kV transmission lines would intertie the Anchorage area and the Fairbanks area systems as well as the major generation sites for the al- ternative plans. Two 345-kV lines are planned between Anchorage and Fairbanks to make a firm tie for all plans. The original 138-kV line constructed for 345-kV will be converted to 345-kV for one of the lines and the second will be newly constructed. For the plans using the Susitna Project (Watana I and II) as the major generation point, the 345-kV transmission system would be as pro- posed by the Susitna Project studies.? For the plans using Beluga as the major generation site, the 345-kV transmission system would consist of two parallel circuits between Anchorage and Fairbanks with a switching station near Teeland and two parallel circuits from Beluga to the switching station near Teeland. The 345-kV circuit would be in addition to the existing transmission facilities between Beluga and MacKenzie Point. The existing facilities would first be utilized to their capacity before the new 345-kV transmission lines are built. A summary of costs for the transmission plans is given in Table 2.4-1, All estimates unless otherwise noted are based on January 1982 costs and include materials and labor, equipment, land rights, clearing, engineering and contingencies for substations, switchyards and transmission lines. The 115-kV costs are based on the data given for the Homer-Soldotna line in Table 5-4 of the Corps' Power Studies.> The 138-kV costs are based on costs taken from the Anchorage to Fairbanks transmission intertie route selection report.” The 230-kV costs are based on the cost data given for the 138-kV Soldotna-Anchorage line in Table 5-4 of the Corps' Power Studies” and data obtained from CEA for recent 230-kV construction for similar facilities.® 2-18 The 345-kV costs are taken from the Anchorage-Fairbanks Trans- mission Intertie Route Selection Report’ and from The Susitna Hydroelectric Project Feasibility Reports? The costs given for the 345-kV construction in the Susitna Project are assumed to include all costs associated with completing the 345-kV system between Anchorage and Fairbanks including upgrading the original intertie from 138-kV operation to 345-kV operation. R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY FORECAST OF Kenai Peninsula Utilities Peak (MW) secsssseseeeee Energy (GWh) ..eseeeeeee Industry Peak (MW) sssesececeeees Energy (GWh) eccceeeeeee Total Kenai Peak (MW) «see. Energy (GWh) .. Greater Anchorage Utilities Peak (MW) seeceseseeeeee Energy (GWh) sessseeceee National Defense Peak (MW) .. Energy (GWh) . Total Greater Anchorage Peak (MW) cecccccccvccce Energy (GWh) sescseeseee Fairbanks Area Utilities Peak (MW) sececseeeeceee Energy (GWh) . National Defense Peak (MW) seccccccccccce Energy (GWh) weccccceeee Total Fairbanks Area Peak (MW) .. Energy (GWh) ..eseseeeee Total Railbelt Peak (MW) ... Energy (GWh) PEAKS AND ENERGY FOR RAILBELT AREA OF ALASKA 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 83.5 85.5 87.5 91.8 94.3 96.8 99.5 102.2 104.8 110.2 387.2 407.2 428.6 450.1 462.3 474.6 487.2 500.2 513.5 539.8 8.5 8.6 8.8 8.9 9.1 9.4 9.6 9.9 10.1 10.3 42.3 43.6 45.0 46.6 48.0 49.3 50.6 51.9 53.3 54.6 92.0 94.1 96.3 100.7 103.4 106.2 109.1 112.1 114.9 120.5 429.5 450.8 473.6 496.7 510.3 523.9 537.8 552.1 566.8 594.4 418.5 428.5 438.5 460.2 472.7 485.2 498.5 511.8 525.2 551.8 1,939.8 2,039.8 2,147.4 2,254.9 2,315.7 2,377.4 2,440.8 2,505.8 2,572.5 2,704.2 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 43.6 43.6 43.6 43.6 43.6 43.6 43.6 43.6 43.6 43.6 427.8 437.8 447.8 469.5 482.0 494.5 507.8 521.1 534.5 561.1 1,983.4 2,083.4 2,191.0 2,298.5 2,359.3 2,421.0 2,484.4 2,549.4 2,616.1 2,747.8 124.0 139.0 156.0 169.0 172.0 176.0 180.0 183.0 187.0 196.0 538.0 603.0 676.0 733.0 748.0 764.0 780.0 795.0 812.0 853.0 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 68.9 68.9 68.9 68.9 68.9 68.9 68.9 68.9 68.9 68.9 138.3 153.3 170.3 183.3 186.3 190.3 194.3 197.3 201.3 210.3 606.9 671.9 744.9 801.9 816.9 832.9 848.9 863.9 880.9 921.9 658.1 685.2 714.4 753.5 771.7 791.0 811.2 830.5 850.7 891.9 3,019.8 3,206.1 3,409.5 3,597.1 3,686.5 3,777.8 3,871.1 3,965.4 4,063.8 4,264.1 bL-b°e A1aVL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY FORECAST OF PEAKS AND ENERGY FOR RAILBELT AREA OF ALASKA Kenai Peninsula Utilities Peak (MW) sscccseeecsece Energy (GWh) eessseseeee Industry Peak (MW) sees. Energy (GWh) secccseeeee Total Kenai Peak (MW) seccccccccceee Energy (GWh) .. Greater Anchorage Utilities Peak (MW) .. Energy (GWh) .. National Defense Peak (MW) seccccsccceces Energy (GWh) ..sccceeeee Total Greater Anchorage Peak (MW) weccececceceee Energy (GWh) .eccceseeee Fairbanks Area Utilities Peak (MW) wecccccccccces Energy (GWh) sesceececee National Defense Peak (MW) .. Energy (GWh) .sseceseeee Total Fairbanks Area Peak (MW) cecccccccccces Energy (GWh) .eececeeeee Total Railbelt Peak (MW) cescccceccccee Energy (GWh) weccocccece 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 115.8 121.6 127.8 134.3 140.4 146.8 153.4 160.4 167.7 175.3 566.9 595.9 626.2 657.8 687.7 719.0 751.6 785.7 821.5 858.9 10.6 10.9 ll.1 11.4 11.6 11.7 12.2 12.4 12.7 13.0 55.9 57.3 58.6 59.9 61.3 62.6 63.9 65.3 66.6 67.9 126.4 132.5 138.9 145.7 152.0 158.5 165.6 172.8 180.4 188.3 622.8 653.2 684.8 717.7 749.0 781.6 815.5 851.0 888.1 926.8 580.2 609.4 640.2 672.7 703.6 73542 768.6 803.6 840.3 878.7 2,840.1 2,985.1 3,136.8 3,295.2 3,445.3 3,602.0 3,665.4 3,936.3 4,115.5 4,302.9 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 43.6 43.6 43.6 43.6 43.6 43.6 43.6 43.6 43.6 43.6 589.5 618.7 649.5 682.0 712.9 744.5 777.9 812.9 849.6 888.0 2,883.7 3,028.7 3,180.4 3,338.8 3,488.9 3,645.6 3,709.0 3,979.9 4,159.1 4,346.5 206.0 217.0 228.0 239.0 249.0 260.0 272.0 284.0 296.0 308.5 896.0 942.0 989.0 1,040.0 1,085.0 1,134.0 1,183.0 1,236.0 1,290.0 1,346.4 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 68.9 68.9 68.9 68.9 68.9 68.9 68.9 68.9 68.9 68.9 220.3 231.3 242.3 253.3 263.3 274.3 286.3 298.3 310.3 322.8 964.9 1,010.9 1,057.9 1,108.9 1,153.9 1,202.9 1,251.9 1,304.9 1,358.9 1,415.3 936.2 982.5 1,030.7 1,081.0 1,128.2 1,177.3 1,229.8 1,284.0 1,340.3 1,399.1 4,471.4 4,692.8 4,923.1 5,165.4 5,391.8 5,630.1 5,776.4 6,135.8 6,406.1 6,688.6 “LNOO L-b°2@ 3198vL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY Kenai Peninsula Utilities Homer Electric Association Peak (MW) ..ccceseeseee Energy (GWh) Seward Electric System Peak (MW) ...ececeeeeee Energy (GWh) Chugach Electric Association Peak (MW) ..scseeeeeece Energy (GWh) ..-...-+-6 Total Kenai Peninsula Peak (MW) ... Energy (GWh) ..-..seee8 PEAK AND ENERGY FOR KENAI PENINSULA UTILITIES 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 65.9 67.2 68.7 70.3 73.7 75.9 78.1 80.4 82.7 85.0 89.6 308.7 324.6 341.8 360.1 378.5 390.1 401.8 413.7 425.8 438.0 462.0 5.8 6.2 6.5 6.8 7.3 7.5 7.7 8.0 8.2 8.4 8.8 30.2 31.7 33.2 35.1 36.9 37.4 37.9 38.5 39.3 40.1 41.8 10.0 10.1 10.3 10.4 10.8 10.9 11.0 11.1 11.3 11.4 11.8 29.5 30.9 32.2 33.4 34.7 34.8 34.9 35.0 35.1 35.4 36.0 81.7 83.5 85.5 87.5 91.8 94.3 96.8 99.5 102.2 104.8 110.2 368.4 387.2 407.2 428.6 450.1 462.3 474.6 487.2 500.2 513.5 539.8 * Based on Alaska Power Administration's projected percentage of total growth for each utility applied to the total loads Does not include industry-supplied loads. developed for Kenai per Alaska Power Authority. -b°e A1avl R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY Kenai Peninsula Utilities Homer Electric Association Peak (MW) .. Energy (GWh) .-.------- Seward Electric System Peak (MW) ..-.-eeeeeeee Energy (GWh) ..-..-ee+- Chugach Electric Association Peak (MW) ..ccseseeeeee Energy (GWh) .......e0- Total Kenai Peninsula Peak (MW) .cccecceeeeee Energy (GWh) ....++-+e- PEAK AND ENERGY FOR KENAI PENINSULA UTILITIES 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 94.2 99.0 103.8 108.8 114.1 119.5 124.9 130.5 136.2 142.0 486.0 509.9 536.1 561.8 589.4 617.0 646.1 675.2 704.8 734.9 9.3 9.8 10.6 11.3 11.7 12.1 12.7 13.3 14.1 15.0 43.7 45.3 49.2 52.6 54.2 56.3 58.5 61.4 64.9 68.9 12.3 12.8 13.4 14.2 14.6 15.2 15.8 16.6 17.4 18.3 37.2 40.7 40.9 43.4 44.1 45.7 47.0 49.1 51.8 55.1 115.8 121.6 127.8 134.3 140.4 146.8 153.4 160.4 167.7 175.3 566.9 595.9 626.2 657.8 687.7 719.0 751.6 785.7 821.5 858.9 * Based on Alaska Power Administration's projected percentage of total growth for each utility applied to the total loads Does not include industry-supplied loads. developed for Kenai per Alaska Power Authority. “LNOO 2-L°? AIEGVL TABLE 2.2-1 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY EXISTING RESOURCES Retirement Capacity Resource Year (1) Type (Mm) Kenai Area. Bernice Lake 1 1993 NGT 8.85 Bernice Lake 2 2002 NGT 18.95 Bernice Lake 3 2008 NGT 24.3 Bernice Lake 4 2012 GT 2423 Cooper Lake -- Hydro 15.0 Anchorage Area Beluga 1 1999 NGT 15.25 Beluga 2 1998 NGT 15.25 Beluga 3 2003 NCT 53.3 Beluga 4 2006 NGT 10.0 Beluga 5 2005 NGT 58.§ Beluga 6 2006 NGT 72.9 Beluga 7 2008 NGT 72.9 Beluga 8 2012 cccr 54.0 International 1 1995 NGT 14.0 . International 2 2005 NGT 14.0 International 3 2002 NGT 18.5 Knik Arm 1-5 1990 NGST 14.5 AMLEP 1 1992 NGT 15.13 AML&P 2 1994 NGT 15.13 MMLEP 3 1998 NGT 18.7 AMLEP 4 2002 NGT 30.0 AMLEP 5 2005 NGT 40.0 AMLEP 6 2009 cccr 33.0 DMLEP 7 2005 NGT 79.3 Fairbanks Area (2) Chena 1 1984 Coal 5 Chena 2 1982 Coal 2 Chena 3 1982 Coal 2 ct 4 1983 ost 7 Chena 5 2000 Coal 20 Chena 6 1996 oct 29 Healy 1997 Coal 25 North Pole 1 1996 oct 65 North Pole 2 1997 ost 65 Zehnder 1 1991 ost 18 Zehnder 2 1992 ost 18 Zehnder 3 1995 oct 3 Zehnder 4 1995 ost 3 NTG = Natural gas-fired combustion turbine OGT = 0il-fired combustion turbine CCCT = Combined cycle combustion turbine Coal = Coal-fired steam turbine NGST = Natural gas-fired steam turbine NOTES: Data are from the Alaska Power Administration's Bradley Lake Project Report?, unless noted otherwise. (1) The retirement schedule is based on the on-line date defined in Commonwealth Associates’ Transmission System Data? and the following economic lifes defined by Battelle's Railbelt Study:10 Generation Life Oil-fired combustion turbine 20 years Gas-fired combustion turbine 30 years Coal-fired steam 30 years hydroelectric 50 years (2) The Fairbanks area data are based on data from Commonwealth Associates’ Transmission System Data, 22 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY PEAK LOAD-RESOURCE COMPARISON 1962 1963 1984 1985 1986 1987 19868 1989 1990 1991 1992 1993 KENAI PENINSULA PEAK LOAD (MW) 132.50 RESOURCES 91.40 RETIREMENTS = NET RESOURCES SURPLUS (DEF.) PEAK LOAD (MW) 427,80 437.80 447.80 522.10 534.50 561.10 589.50 618.70 RESOURCES 674.30 674.30 674.30 674.30 674,30 674.30 674.30 © 674.30 RETIREMENTS 0.00 0.00 0.00 0.00 0.00 ~-14.50 -29.60 ~-29.60 NET RESOURCES 674.30 674.30 “674.30 “674.30 “Gaa.70 “644.70 SURPLUS (DEF.) 246.50 236.50 226.50 153.20 55.20 26.00 PAIRBANKS PEAK LOAD (MW) 138.30 153.30 170.30 194.30 197.30 201.30 210.30 9220.30 = 231.30 a Beg MEAD MGS AEA Mag Mae NET RESOURCES 258.00 251.00 246.00 246.00 246.00 246.00 228.00 210.00 210.00 SURPLUS (DEF.) 119.70 97.70 75.70 51.70 48.70 44.70 17.70 = 10.30 -21.30 TOTAL RAILBELT PEAK LOAD (MW) 658.10 685.20 753.50 791,00 811.20 630.50 650.70 691.90 936.20 982.50 RESOURCES (MW) 1027.70 1027.70 1027.70 1027.70 1027.70 1027.70 1027.70 1027.70 1027.70 1027.70 RETIREMENTS 711.00 16.00 “16.00 -16.00 ~-16.00 90.50 AVAILABLE RES. 1023.70 1016.70 1011.70 1011.70 1011.70 937.20 LESS: RESERVES -200.00 811.70 611.70 811.70 40.00 20.70 0.50 NET RESOURCES SURPLUS (DEFICIT) 165.60 131.50 1994 138.90 91.40 -8.90 242.30 262.00 -52.00 -32.30 1030.70 1027.70 1995 1996 145.70 = 152.00 91 712,90 674.30 -58.70 615.60 97.30 253.30 263.30 262.00 262.00 58.00 -152.00 110.00 153.30 1081.00 1128.20 1027.70 1027.70 125.60 -219.60 902.10 702.10 378.90 1997 1998 1999 158.50 165.60 172.80 91.40 91.40 91.40 -8.90 =8.90 90 274.30 298.30 24200 24200 “20.00 30.00 254.30 -278.30 1177.30 1229.80 1284.00 1027.70 1027.70 1027.70 -326.30 -328.30 2000 180.40 91.40 849.60 674.30 -77,.40 596.90 252.70 310.30 262.00 262.00 0.00 -310.30 1340.30 1027.70 348.30 2001 166.30 91.40 8.90 322.30 262.00 -262.00 1398.60 1027.70 e-2% a1avl R. W. Beck and Associate KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY 1982 KENAI PENINSULA 429.50 RESOURCES (GWh) 560.50 RETIREMENTS 0.00 NET RESOURCES 560.50 SURPLUS 231.00 GREATER ANCHORAGE 1983.40 RESOURCES (GWh) 4134.80 RETIREMENTS 0.00 NET RESOURCES ase SURPLUS 2151.40 PAIRBAN! LOAD ‘(cwn) 606.90 RESOURCES (GWH) 1208.00 RETIREMENTS -24.50 NET RESOURCES 1183.50 SURPLUS 576.60 TOTAL RAILBELT LOAD (GWh) 3019.80 RESOURCES (GWh) 5903.30 RETIREMENTS 24.50 AVAILABLE RES. 5878.80 SURPLUS (DEFICIT) 2859.00 2083.40 4134.80 0.00 4134.80 2051.40 671.90 1208.00 67.50 1140.50 468.60 3206.10 5903.30 67.50 5835.80 2629.70 2191.00 4134.80 0.00 4134.80 1943.80 744.90 1208.00 98.10 1109.90 365.00 3409.50 5903.30 98.10 5805.20 2395.70 1985 496.70 560.50 0.00 560.50 63.80 2298.50 4134.80 0.00 1109.90 308.00 3597.10 5903.30 98.10 5805.20 2208.10 2359.30 4134.80 0.00 4134 1775.50 816.90 1208.00 98.10 1109.90 293.00 3686.50 5903.30 -98.10 5605.20 2118.70 ENERGY-RESOURCE COMPARISON 2421.00 4134.80 0.00 4134.80 1733.80 1109.90 277,00 3777.80 5903.30 98.10 5805.20 2027.40 NOTE: RESOURCES CALCULATED AS EXISTING CAPACITY @ 70% PLANT FACTOR. 1988 537.80 560.50 0.00 560.50 22.70 2484.40 4134.80 0.00 4134.60 1650.40 848.90 1208.00 98.10 1109.90 261.00 3871.10 5903.30 98.10 5805.20 1934.10 2549.40 0.00 1585.40 1109.90 246.00 3965.40 5903.30 98.10 5805.20 1639.80 2616.10 4134.80 0.00 4134.80 1518.70 1109.90 229.00 4063.80 5903.30 98.10 5805.20 1741.40 2747.80 413. 10. 90 4045.90 1298.10 4264.10 5903.30 -297.40 5605.90 1341.80 1992 622.80 560.50 0.00 560.50 62.30 2883.70 4134.80 181.50 3953.30 1069.60 964.90 1208.00 -318.90 4471.40 5903.30 -500.40 5402.90 931.50 3028.70 4134.80 -181.50 3953.30 924.60 1010.90 1208.00 -318.90 889.10 121.80 4692.80 5903.30 554.90 5348.40 655.60 1994 684.80 560.50 54.60 505.90 -178.90 3180.40 4134.80 -274.10 3860.70 680.30 1057.90 3338.87 4134.80 -359.90 1108.90 1208.00 5165.47 5903.30 770.20 5133.10 -32.37 3488.90 4134.80 3774.90 286.00 1153.90 1208.00 932.10 275.90 878.00 5391.80 4556.70 835.10 1997 761.60 560.50 54.60 505.90 -275.70 3645.60 4134 3774.90 129.30 1202.90 1208.00 1483.90 275.90 1478.80 5630.10 5903.30 1898.50 4004.80 1625.30 3709.00 134.80 0 3660.20 48.80 1251.90 1208.00 1483.90 -275.90 -1527.80 5776.40 5903.30 -2013.10 3890.20 -1886.20 3979.90 4134.80 0 3660.20 319.70 1304.90 -1580.80 6135.80 5903.30 -2013.10 3890.20 -2245.60 2000 688.10 560.50 54.60 505.90 -382.20 4159.10 4134.80 3660.20 -498.90 1358.90 1208.00 1606.60 -398.60 1757.50 6406.10 5903.30 -2135.80 3767.50 -2638.60 2001 926.80 560.50 54.60 505.90 420.90 4346.50 4134.80 474.60 3660.20 686.30 1415.30 1813.90 6688.60 5903.30 -2135.80 3767.50 -2921.10 €-2°% AIGVL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY PLAN AA-BRADLEY LAKE AT 135 MW WITH SUSITNA 1982 1983 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 1985 1986 1987 198 NEW RESOURCES BERNICE LAKE GT 0.00 BRADLEY LAKE 0 20.00 20.00 = 20.00 © 20.00» 20.00 »~——20.00 20.00 20.00 20.00 135.00 135.00 135.00 135.00 20.00 20.00 20.00 135.00 135.00 135.00 155.00 155.00 155.00 155.00 20.00 TOTAL KENAL 0.00 155.00 BELUGA GT 0.00 0.00 0.00 0.00 0.00 BELUGA COAL 0.00 0.00 0.00 0.00 0.00 SUSITNA 0.00 695.00 695.00 TOTAL ANCHORAGE 0.00 695.00 695.00 695.00 695.00 SUSITNA 0.00 325.00 325.00 325,00 325.00 325.00 TOTAL FAIRBANKS 0.00 325.00 325.00 325.00 325.00 325.00 seeeseee LOAD RESOURCE A KENAI PENINSULA PEAK LOAD (HW) 92.00 94,10 96.30 100.70 103.40 106.20 109,10 122.10 114.90 188.30 RESOURCES BSRNICE LAKE ~ 76.40 76.40. 76.40 = 76.40 76.40 76.40 76.40 76.40 COOPER LAKE 15.00 15.00 15.00 15.00 «15.00 15.00 15.00 15.00 LESS: RETIREMENT 0.00 0,00 0.00 0.00 0.00 0.00 0.00 -8.90 NEW RESOURCES 0.00 20.00 20.00 20.00 20.00 20.00 155.00 NET RESOURCES 92.40 122.40 122.40 121.40 112.40 122,40 SURPLUS (DEF.) -0.60° 17.30 15.10 10.70 8.00 5.20 131.50 49.20 GREATER ANCHORAGE PEAK LOAD (HW) 469.50 482.00 494.50 507.80 521.10 534.50 561.10 589.50 618.70 649.50 682.00 712.90 777,90 812,90 849.60 RESOURCES CEA GT 423-10 413.10 413,20 413.10 413.10 423.20 413.10 413.10 413.10 413.10 413.10 413.20 413.10 413.10 413.10 413.10 AMLEP GT 231.20 232,20 232.20 231.20 231.20 231.20 © 231.20 231.20 © 231.20 233.20 231.20 231.20 231.20 231.20 © 231.20 LESS: RETIREMENT 0.00 0.00 0.00 0.00 0.00 0.00 -14.50 -29.60 -29.60 -58.70 =77,40 0-77.40 -77.40 77.40 NEW RESOURCES 0.00 0,00 695.00 695.00 695.00 695.00 695.00 0.00 0.00 0,00 0.00 0,00 695.00 1280.60 1280.60 1261.90 1261.90 1261.90 1261.90 644.30 644.30 1309.70 1294.60 NET RESOURCES SURPLUS (DEF.) 162,30 123,20 109,80 = 68.70 25.20 691.00 645.10 567.70 536.10 484.00 449.00 412.30 373.90 FAIRBANKS: PEAK LOAD (MW) 138-30 153.30 170.30 183.30 186.30 190,30 194.30 197.30 201.30 210.30 220.30 231.30 242.30 253.30 263.30 274.30 © 286.30 298.30 310.30 322.30 RESOURCES GVEA 197-00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 FMUS 65.00 65.00 65.00 © 65.00 65.00 65.00 65.00 © 65.00 65.00 «65.00 «65.00 65.00 65.00 65.00 65.00 LESS: RETIREMENT “16.00 -16.00 -16.00 -16.00 -16.00 16.00 -16.00 -34.00 -52:00 -52.00 -262.00 -262.00 NEW RESOURCES 0,00 0.00 0.00 0,00 0.00 © 325.00 325.00 325.00 NET RESOURCES 246.00 246.00 246,00 210,00 535.00 325.00 325,00 SURPLUS (DEF.) 119.70 97.70 75.70 62.70 59.70 51.70 48,70 710.30 303.70 14.70 2.70 TOTAL RAILBELT PEAK LOAD (MW) 658.10 771,70 791,00 811.20 830.50 850.70 997.70 997,70 997.70 © 997.70 997.70 716.00 -16.00 -16.00 -16.00 -16.00 20.00 = 20,00 155.00 155.00 155.00 982.50 1030.70 1061.00 1128.20 1177.30 1229.80 997.70 997.70 997.70 997.71 =90.50 -105.60 -125:60 2175.00 1175.00 1340.30 1398.60 EXISTING RESOURCES 997.70 LESS: RETIREMENT NEW RESOURCES 0 997.70 997.70 0 -309.60 -328.30 1175.00 997.70 997.70 =348.30 -348.30 1175.00 0 NET RESOURCES 993.70 1006.70 1001.70 1001.70 1001.70 1001.70 1136.70 1136.70 1136.70 1104.20 2082.20 2067.10 2047.10 1953.10 1863.10 1844.40 1624.40 SURPLUS (DEF.) 335.60 321.50 287.30 248.20 230.00 210.70 325.50 306.20 286.00 212.30 1099.70 1036.40 966.10 685.80 614.60 484.10 425.80 LESS1 RESERVES ~200,00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200:00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 NET SURPLUS (DEF.) 135,60 121.50 87.30 © 48.20 © 30.00» 10.70 125.50 106.20 86.00 ‘12.30 766.10 414.60 225.80 TRANSMISSION REQS. (EXCLUDING LOSSES) ANCH, TO KENAT W/KENAL OUTAGE 25.60 7.70 9.90 14.30 17.00 19.80 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 W/ANC-FAT OUTAGE 0,00 0.00 0.00 0.00 0.00 0,00 -11.80 -28.10 45.50 -120,00 0.00 0,00 0,00 0.00 0.00 0.00 0.00 ANCH. TO FAIRBANKS W/FAIRBANKS OUT. 0.00 0.00 0.00 2.30 5.30 9.30 13.30 16.30 20.30 25.20 0.00 0,00 0.00 0.00 6.30 18.30 50.30 62.30 W/ANC-KEN OUTAGE 0.00 0.00 0.00 -14.50 -29.70 45.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 MAXIMUM OUTAGE KENAI 25.00 = 25.00 25.00 25.00 25.00 25.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 © 45.00 FAIRBANKS 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 «65.00 ANC-FAL COIN. 200,00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 += 200.00 200.00 + 200.00 + 200.00 + 200.00 + 200.00 += 200.00 += 200.00 +—- 200.00 ANC-REN COIN, 200.00 200.00 200.00 200.00 200.00 200.00 200,00 200.00 = 200.00 += 200.00 © 200.00 + 200.00 + 200.00 + 200.00 200.00 += 200.00 += 200.00 += 200.00 += 200.00 b-€°S J1GVL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY PLAN AB-BRADLEY LAKE AT 90 MW WITH SUSITNA 1982 1983 1964 NEW RESOURCES BERNICE LAKE GT 0.00 = 20.00 BRADLEY LAKE 0.00 0.00 110.00 110.00 110.00 110.00 TOTAL KENAI 0.00 BELUGA GT 0.00 45,00 45.00 © 45.00 45.00 BELUGA COAL 0.00 0.00 0.00 0.00 0.00 SUSITNA 0.00 695.00 TOTAL ANCHORAGE 740.00 SUSITNA 325.00 325.00 TOTAL FAIRBANKS 0.00 0.00 325.00 325.00 seeeeees LOAD RESOURCE ANALYSI 58 #0 PEAK LOAD (MW) 92.00 94.10 96.30 100.70 103.40 106.20 109.20 112.10 114.90 152.00 RESOURCES BERNICE LAKE 76.40 76.40 76.40 76.40 76.40 76.40 76.40 16.40 COOPER LAKE 15.00 15.00 = 15.00 = 15.00 15.00 15.00 15.00 15.00 LESS: RETIREMENT 0.00 0.00 0.00 0.00 -8.90 NEW RESOURCES 0,00 =20.00 +§=20.00 »=—- 20.00 110.00 NET RESOURCES 91.400 111 111,40 192.50 SURPLUS (DEF.) 70.60 = 17.30 15.10 89.30 86.50 40.50 GREATER ANCHORAGE PEAK LOAD (HW) 427.00 437,00 447.80 469.50 482.00 494.50 507.80 521.10 534.50 561.10 589.50 618,70 649.50 682.00 777.90 812.90 849.60 888.00 RESOURCES CEA GT 413,20 413.10 © 413,10 © 413.20 413.10 © 413.10 413,10 413.200 413.10 413.10 413.10 413.10 413.10 413.10 413.10 AMLEP GT 231.20 232.20 231.20 232.20 © 231.20 © 23120 231.20 231.20 © 231.20 © 231.20 232.20 231.20 © 231.20 231.20 232.20 LESS: RETIREMENT 0.00 0.00 0.00 0.00 0.00 0.00 7-29.60 -44.70 -58.70 558.70 -77.40 -77.40-77.40 —-77.40 NEW RESOURCES 0.00 0.00 0.00 0.00 0.00 40.00 740.00 740.00 740,00 740.00 740.00 740.00 740.00 NET RESOURCES 644.30 644.30 644.30 644.30 689.30 1354.70 1339.60 1325.60 1325.60 1325.60 1306.90 1306.90 1306.90 1306.90 SURPLUS (DEF.) 216,50 206.50 196.50 174.80 162.30 149.80 154,80 736.00 690.10 643.60 612.70 581.10 529.00 494.00 457.30 418.90 FAIRBANKS PEAK LOAD (MW) 153.30 170.30 183,30 6-30 190,30 194.30 197.30 201.30 210.30 220.30 231.30 242.30 253.30 263.30 274.30 298.30 310.30 322.30 RESOURCES GVEA 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 FMUS 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 LESS: RETIREMENT “16.00 -16.00 -16.00 -16.00 -16.00 -16.00 7242.00 -262.00 -262.00 NEW RESOURCES 0.00 0.00 0.00 0.00 0.00 0.00 325.00 325.00 325.00 NET RESOURCES 251.00 246.00 246.00 246.00 246.00 246.00 345.00 325.00 325.00 SURPLUS (DEF.) 97.70 75.70 62.70 59.70 51.70 44,70 46.70 14.70 2.70 PEAR LOAD (HW) 685.20 714.40 753,50 771.70 791.00 811.20 830.50 850.70 891.90 936.20 982.50 1030.70 1081.00 1126.20 1177.30 1229.80 1284.00 1340.30 1398.60 EXISTING RESOURCES LESS: RETIREMENT NEW RESOURCES Ptiigo 24e:89 222228 297-29 997.70 997.70 997.70 997.70 997.70 997.20 997.70 997.70 997.70 997.70 997.70 997.70 997.70 997.70 997.70 20.00 “1 2 “16.00 16.00 -16.00 -16.00 -48:50 -81:60 -90:50 -10 20 110,00 110.00 155.00 155,00 1175.00 117 NET RESOURCES 993.70 1006.70 1001.70 1001.70 1001.70 1001.70 1091.70 1091.70 1136.70 SURPLUS (DEF.) LESS: RESERVES 7225.60 219.60 -309.60 -328.30 -328:30 -348.30 -348.30 1175.00 1175.00 1175.00 1175.00 1175.00 1175.00 1071.10 2082.20 2067.10 2047.10 1953.10 1863.10 1844.40 1824.40 1824.40 321-50 287.30 248.20 230,00 210.70 280.50 261.20 286.00 212.30 134 90 1099.70 1036.40 966.10 624.90 685.80 614.60 560.40 425.80 -200.00 -200 7200.00 -200.00 -200.00 -200:00 -200:00 -200;00 200.00 -200.00 -200.00 12,30 -65.10 899.70 836.40 766.10 NET SURPLUS (DEF.) 135,60 121.50 87.30 «48.20 «30.00 10.70 80.80 61220 86.00 TRANSMISSION REQS. ANCH. TO KENAI 485.80 414.60 ING LOSSES) W/KENAL OUTAGE 25.60 7.70 9.90 14.30 17,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.00 18.10 25.30 32.90 40.80 W/ANC-FAI OUTAGE 0.00 0.00 0.00 0.00 0.00 -11.80 -0.50 -68.60 © -75.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 ANCH. TO FAIRBANKS. W/PAIRBANKS OUT. 0.00 0.00 2.30 5.30 13.30 16.30 © 20,30 47.30 0.00 0.00 0.00 0.00 6.30 18.30 = 50.30 62.30 W/ANC-KEN OUTAGE 0.00 0.00 714,50 -29,70 0.00 0,00 0.00 = -5,40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 MAXIMUM OUTAGE KENAI 25.00 25.00 25.00 25.00 45.00 45.00 45.00 = 45.00 45.00 45.00 45.00 45.00 45.00 45.00 = 45.00 FAIRBANKS 65.00 65.00 : 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 ANC-FAL COIN, 200.00 200.00 + 200.00 200.00 +200: 00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 ANC-KEN COIN, 200.00 200.00 + 200.00 + 200:00 © 200.00 + 200.00 + 200.00 20000 200.00 200.00 200.00 200.00 200.00 © 200.00 200:00 200.00 200.00 e-€'% AIaVL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY NEW RESOURCES BERNICE LAKE GT BRADLEY LAKE TOTAL KENAL BELUGA GT BELUGA COAL SUSITNA TOTAL ANCHORAGE SUSITNA TOTAL FAIRBANKS RESOURCE KENAI PENINSULA PEAK LOAD (MW) 92.00 94.10 96.30 100.70 RESOURCES BERNICE LAKE 16.40 76.40 = 76.40 76.40 COOPER LAKE 15,00 15.00 15.00 15.00 LESS1 RETIREMENT 0.00 0.00 0.00 0.00 NEW RESOURCES 20.00 20.00 20.00 111,40 NET RESOURCES 91.40 SURPLUS (DEF.) -0.60 17.30 15.10 GREATER ANCHORAGE PEAK LOAD (MW) 427,80 437.80 447,80 469.50 RESOURCES CEA GT 413.10 AMLEP GT 231.2 LESS: RETIREMENT 0.01 NEW RESOURCES 0.00 NET RESOURCES 644.30 SURPLUS (DEF.) 216.50 INKS. PEAK LOAD (HW) 138.30 153,30 170.30 183.30 RESOURCES GVEA 197.00 197.00 197.00 197.00 rHUS 65.00 65.00 65.00 LESS: RETIREMENT -4.00 — -11.00 NEW RESOURCES 0.00 NET RESOURCES 258.00 SURPLUS (DEF.) 119.70 TOTAL RAILBELT PEAK LOAD (HW) 658.10 EXISTING RESOURCES 997.70 LESS: RETIREMENT 4.00 NEW RESOURCES 0.00 NET RESOURCES 993.70 1006.70 1001.70 1001.70 SURPLUS (DEF.) 335.60 LESS: RESERVES -200.00 287.30 © 248.20 -200.00 -200.00 NET SURPLUS (DEF.) 135.60 121.50 87.30 48.20 TRANSMISSION REQS. (EXCLUDING LOSSES) ANCH. TO KENAI W/KENAI OUTAGE 25.60 7.70 9.90 W/ANC-FAT OUTAGE 0.00 0,00 0.00 ANCH. TO FAIRBANKS W/FAIRBANKS OUT. 0.00 0.00 W/ANC-KEN OUTAGE 0,00 0.00 MAXIMUM OUTAGE KENAT 25.00 25.00 = 25.00 25.00 PALRBANKS 65.00 65.00 65.00 65.00 ANC-FAI COIN. 200.00 200.00 200.00 200.00 ANC-KEN COIN. 200.00 200.00 200.00 200.00 PLAN BA-BRADLEY LAKE AT 135 MW WITH COAL 1995 1996 1997 1998 1999 2000 2001 20.00 20.00 20.00 20.00 135,00 20.00 20.00 20.00 135.00 135.00 155.00 0.00 0.00 600.00 0.00 0.00 0.00 NALYSTI 5 #0 103.40 106.20 109.10 112.10 114.90 158.50 165.60 172.80 160.40 188.30 76.40 76.40 76.40 76.40 76.40 76.40 76.40 16.40 15.00 15.00 15,00 15.00 15.00 +00 = 15.00 15.00 0.00 0.00 0.00 0.00 -8.90 90 -8.90 20.00 20.00 155.00 155.00 155.00 155.00 155.00 +00 © 155.00 111,40 246.40 246.40 237.50 237.50 237.50 5.20 137.30 131.50 79.00 71.90 49,20 482.00 494.50 507.60 521.10 534.50 413,10 423.10 413.10 © 413.10 © 423.10 589.50 618.70 649.50 413.10 413.10 413.10 777.90 413.10 849.60 888.00 413.10 © 413.10 231.20 231,20 231.20 231.20 231.20 231.20 231.20 © 231.20 7 231.20 0.00 0.00 0,00 0.00 0.00 -29,60 -29.60 =! 77.40 -77.40 0.00 0,00 0.00 0,00 0.00 0,00 00.00 800.00 644.30 644,30 644,30 614.70 1185.60 1166.90 1366.90 1366.90 136.50 123.20 109,80 25.20 441.10 389,00 517.30 478,90 186.30 190.30 194.30 197,30 201.30 210,30 220.30 231.30 242.30 197.00 197.00 197.00 197,00 197.00 197.00 197.00 197.00 197.00 65.00 65.00 65.00 65.00 © 65.00 65.00 © 65.006 5.00 “16.00 -16.00 -16.00 -16.00 -16.00 -34.00 -52.00 0.00 0.00 0,00 0.00 0.00 246.00 © 246.00 310.30 322.30 197.00 197.00 65.00 65.00 -262.00 -262.00 0.00 0.00 228.00 210.00 51.70 48,70 17.70 -10.30 830.50 850.70 891,90 1030.70 1081.00 1128.20 1177.30 1229.80 1284.00 1340.30 997.70 997.70 997.70 997.70 997.70 997.70 997.70 7105.60 -125.60 -219.60 -309.60 -348.30 355.00 555.00 555.00 755.00 955.00 997.70 997.70 997.70 =16.00 -16.00 -48.50 155,00 155.00 155.00 1136.70 1136.70 1204.20 1071.10 1262.20 1247.10 1427.10 1333.10 1443.10 230,00 210.70 325.50 306.20 286.00 212.30 134.90 279.70 216.40 =200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 10.70 125.50 1001.70 1001.70 1136.70 1624.40 1604.40 204.90 265.80 -200.00 -200.00 340.40 264.10 205.80 -200.00 -200.00 -200.00 106.20 86.00 = 12,30 ~65.10 79.70 16.40 65.80 140.40 64.10 5.80 17.00 19.80 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 745.50 -113,60 -120,00 -25.30 0.00 -80.60 13.20 -71.90 0.00 0.00 5.30 9.30 13.30 16.30 20.30 25.20 86.30 124,30 218.30 319.30 332.30 © 343.30 375.30 387.30 -29.70 45.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 25.00 25.00! 45.00 45.00 65.00 65.00 65.00 65.00 65.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 45.00 45.00 65.00 65.00 200.00 200.00 200,00 200.00 45.00 45.00 © 45.00 45.00 45.00 45.00 45.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 200.00 200.00 200.00 += 200.00 200.00 200.00 200.00 200.00 200.00 © 200.00 200.00 200.00 + 200.00 200.00 €-€'% alavi R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY PLAN BAA-BRADLEY LAKE AT 135 MW (ON-LINE IN 1991) WITH COAL 1984 1986 1987 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 NEW RESOURCES BERNICE LAKE GT 0.00 30,00 30.00 BRADLEY LAKE 0.00 0.00 0.00 TOTAL KENAT 0.00 165.00 BELUGA GT 0.00 0.00 BELUGA COAL 0.00 800.00 SUSITNA 0,00 0.00 TOTAL ANCHORAGE 0.00 SUSITNA 800.00 0.00 TOTAL FAIRBANKS 0.00 0.00 0.00 seeeeees LOAD RESOURCE ANALYSIS ** KENAI PENINSULA PEAK LOAD (MW) 92.00 94.10 96.30 100.70 103.40 106.20 138.90 158.50 180.40 188.30 RESOURCES, BERNICE LAKE 76.40 76.40 76.40 76.40 COOPER LAKE 15.00 +00 15.00 15.00 LESS: RETIREMENT 0.00 +90 -8.90 90 NEW RESOURCES 0.00 00 165.00 165.00 NET RESOURCES 2 247.50 247.50 247.50 SURPLUS (DEF.) -0.60 108.60 89.00 67.10 GREATER PEAK LOAD (HW) 427.80 437.80 447.80 469.50 482.00 494.50 507.80 521.10 534.50 589.50 618.70 649.50 744.50 812.90 849.60 RESOURCES CEA GT 413.10 413.10 413,10 413.10 © 413.10 © 413,10 © 413.10 © 413.10 413.10 413.10 413.10 413.10 413.10 413.10 413.10 413.10 AMLEP GT 231.20 231.20 232.20 232.20 232.20 © 231.20 © 231.20 231.20 © 231.20 231.20 231.20 © 231.20 231.20 231.20 © 231.20 231.20 LESS1 RETIREMENT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 =29.60 -58.70 =77.40 0-77.40 =77.40 NEW RESOURCES: 0.00 0.00 0,00 0.00 0.00 0,00 600.00 800.00 800.00 800.00 NET RESOURCES 644.30 644.30 644.30 644.30 644.30 614.70 799.60 1185.60 1166.90 1366.90 1366.90 1366.90 SURPLUS (DEF.) 216.50 162.30 149.80 136.50 109.80 25.20 150,10 441,10 389.00 554.00 517.30 478.90 FAIRBANKS PEAK LOAD (MW) 153.30 170.30 183,30 186.30 190.30 194.30 197,30 201.30 210,30 220.30 232.30 242.30 298.30 310.30 322.30 RESOURCES GVEA 197.00 197,00 197.00 197.00 197,00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 197.00 FHUS 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 © 65.00 «65.00 65.00 65.00 LESS: RETIREMENT “11.00 -16.00 -16.00 -16.00 -16.00 -16.00 -16.00 -16.00 -34.00 -52.00 -52.00 -52.00 -242.00 NEW RESOURCES: 0.00 0,00 0.00 0.00 0.00 0.00 0.00 NET RESOURCES 251.00 246.00 246.00 246.00 246.00 246.00 210,00 SURPLUS (DEF.) 97.70 75,70 62.70 59.70 55.70 51.70 32.30 TOTAL RAILBELT PEAK LOAD (MW) 658.10 685.20 714.40 753.50 771.70 791.00 811.20 936.20 982.50 1030.70 1081.00 1128.20 1177.30 1229.80 1284.00 1340.30 1398.60 997.70 997,70 997.70 997.70 997.70 997.70 997.70 997.70 997.70 9 81.60 -90.50 -105.60 -125.60 -219.60 -309.60 -328.30 -348.30 365,00 565.00 565.00 765.00 765.00 965.00 965.00 965.00 EXISTING RESOURCES 997.70 997.70 997.70 997.70 997.70 997.70 997.70 LESS: RETIREMENT -4,00 -11.00 -16.00 716.00 -16.00 NEW RESOURCES 0.00 30.00 30.00 30.00 30.00 31 NET RESOURCES 993.70 1016.70 1011.70 1011.70 1012.70 1011.70 1011.70 1011.70 2081.10 1272.20 1257.10 1437.10 1343.10 1453.10 1634.40 1614.40 1614.40 SURPLUS (DEF.) 335-60 331.50 297.30 258.20 240.00 220.70 200.50 181.20 161.00 222.30 144.90 289.70 226.40 356.10 214.90 275.80 204.60 350.40 274.10 215.80 LESS: RESERVES -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200.00 -200,00 -200.00 -200.00 -200.00 -200.00 -200.00 NET SURPLUS (DEF.) 135.60 40.00 20.70 0.50 -39.00 © 22,30 -55.10 = 89.70 156.10 14.90 75.80 15.80 TRANSMISSION REQS. (EXCLUDING LOSSES) ANCH, TO KENAI . W/KENAI OUTAGE 25.60 2.70 9.30 12,00 14.80 17.70 23.50 9.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 W/ANC-PAI OUTAGE 0.00 0.00 0.00 0.00 0,00 -11.80 -6,50 -113,60 -130.00 -25.30 0.00 -80.60 -13.20 -77.30 0.00 0.00 -43.40 ANCH. TO FAIRBANKS W/PAIRBANKS OUT. 0.00 0.00 2.30 5.30 9.30 13.30 20.30 47.30 25.20 86.30 97.30 124.30 218.30 329.30 332.30 343.30 375.30 387.30 W/ANC-KEN OUTAGE 0,00 0,00 74,50 -19.70 -35.00 -51,20 44,70 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 MAXIMUM OUTAGE KENAL 25.00 30.00 30.00 30.00 30.00» 30.00 30.00 30.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 45.00 FAIRBANKS: 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 65.00 ANC-FAI COIN. 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200,00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 ANC-KEN COIN, 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200,00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 200.00 += 200.00 bv-€'e AIGVL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY NEW RESOURCES BERNICE LAKE GT BRADLEY LAKE TOTAL KENAI BELUGA GT BELUGA COAL SUSITNA TOTAL ANCHORAGE SUSITNA TOTAL FAIRBANKS 0,00 0,00 seeeeere LOAD KENAI PENINSULA PEAK LOAD (HW) RESOURCES BERNICE LAKE COOPER LAKE LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) GREATER ANCHORAGE PEAK LOAD (MW) RESOURCES CEA GT AMLEP GT LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) FAIRBANKS PEAK LOAD (HW) RESOURCES GVEA FRUS LESS: RETIREMENT NEW RESOURCES: NET RESOURCES SURPLUS (DEF.) TOTAL RAILBELT PEAK LOAD (HW) EXISTING RESOURCES LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) LESS: RESERVES NET SURPLUS (DEF.) TRANSMISSION REQS. ANCH. TO RENAI W/KENAL OUTAGE W/ANC-FAI OUTAGE ANCH. TO PAIRBANKS W/FAIRBANKS OUT. W/ANC-KEN OUTAGE MAXIMUM OUTAGE RENAL FAIRBANKS ANC-FAL COIN, ANC-KEN COII 92.00 76.40 15.00 0.00 0.00 427.80 413.10 231.20 0.00 658.10 997.70 -4.00 993.70 335.60 -200.00 135.60 25.60 0.00 0.00 0,00 25.00 65.00 200.00 200.00 94.10 76.40 15.00 0.00 55.00 685.20 997.70 11.00 55.00 1041.70 356.50 -200.00 156.50 (EXCLUDING LOSSES) ESOURCE 96.30 76.40 15.00 0.00 55.00 146.40 50.10 447.80 413.10 231.20 0.00 0.00 714,40 997.70 -16.00 55.00 1036.70 322.30 -200.00 122.30 4.90 0.00 0.00 0.00 55.00 65.00 200.00 200.00 100.70 76.40 15.00 0.00 55.00 1036.70 283.20 9.30 0.00 2.30 0.00 55.00 65.00 200.00 200.00 PLAN BAB-BRADLEY LAKE AT 135 MW (ON-LINE IN 1994) WITH COAL NALYSIS 103.40 76.40 15.00 0.00 55.00 146.40 43.00 482.00 413.10 231.20 0.00 0.00 644.30 162.30 186.30 197.00 65.00 -16.00 0.00 246.00 59.70 12.00 0.00 5.30 0.00 55.00 200.00 200.00 106.20 76.40 15.00 0.00 55.00 146.40 40.20 494.50 413.10 231.20 0.00 0,00 644.30 149,80 190.30 197.00 65.00 -16.00 1036.70 245.70 -200.00 45.70 14.80 0.00 9.30 -10.00 55.00 65.00 200.00 200.00 507.80 413.10 231.20 0.00 0.00 30 136.50 194.30 197.00 65.00 -16.00 0.00 246.00 51.70 1036.70 225.50 200.00 17.70 -11.80 13.30 -26.20 55.00 65.00 200.00 200,00 112.10 16.40 15.00 0.00 55.00 146.40 34.30 521.10 413.10 231.20 0.00 0.00 197.30 197.00 65.00 -16.00 0,00 246.00 48.70 830.50 997.70 =16.00 55.00 1036.70 65.00 200.00 200.00 31.50 534.50 413.10 231.20 0.00 0.00 850.70 997.70 -16.00 55.00 1036.70 23.50 -31.50 20.30 44.70 55.00 65.00 200.00 200.00 561.10 413.10 231.20 75.00 704.80 143.70 210,30 197.00 65.00 -34,00 0.00 17.70 29.10 -25.90 47.30 -17,70 55.00 65.00 200.00 200,00 1992 0.00 589.50 618.70 413.10 © 413.10 231.20 © 231.20 =29.60 -29.60 150,00 150.00 764.70 764.70 175.20 146,00 220.30 © 231.30 197,00 197.00 65.00 65.00 -52.00 -52.00 0.00 0.00 210.00 “10.30 -21.30 936.20 982.50 997.70 -90.50 205.00 1221,10 1112.20 129.70 -200.00 -70.30 50.00 -5.00 86.30 0,00 55.00 65.00 200.00 200.00 200.00 200.00 55.00 150,00 0.00 649.50 413.10 231.20 =44.70 150.00 242,30 197.00 65.00 52.00 0.00 210.00 -32.30 1030.70 997.70 -105.60 340.00 1232.10 201.40 -200.00 0.00 -132.20 97.30 0.00 55.00 65.00 200.00 200.00 1995 1996 55.00 135.00 682.00 712.90 413.10 © 413.10 231.20 -58.70 350.00 253.30 © 263.30 197.00 197.00 65.00 65.00 -$8.00 -152.00 0.00 0.00 204.00 110.00 749.30 -153.30 1061.00 1128.20 997.70 2412.10 1318.10 331.10 189.90 -200.00 -200.00 131.10 -10.10 0.00 120.50 218.30 0.00 55.00 55.00 65.00 65.00 200.00 200.00 200.00 200.00 1997 55.00 135.00 190.00 150.00 400.00 1135.60 391.10 274.30 197.00 65.00 -242,00 0.00 20.00 -254.30 1177.30 997.70 1428.10 250.80 -200.00 0.00 -63.20 319.30 0.00 55.00 65.00 200.00 200.00 55.00 135.00 777.90 413.10 550.00 1116.90 339.00 1229.80 997.70 1409.40 179.60 0.00 106.90 331.30 0.00 55.00 65.00 200.00 200.00 504.00 1284.00 997.70 328.30 940.00 1609.40 325.40 -200.00 125.40 0.00 0.00 343.30 0.00 55.00 65.00 200.00 200.00 1316.90 2000 55.00 135.00 190.00 150.00 600.00 0.00 750.00 0,00 1316.90 467.30 1340.30 997.70 -348.30 940.00 1589.40 249.10 -200.00 0.00 -43.00 375.30 0.00 55.00 65.00 200.00 200.00 1316.90 428.90 1398.60 997.70 -348.30 940.00 1589.40 190.80 -200.00 -9.20 0.00 -84.20 387.30 0.00 55.00 65.00 200.00 200.00 s-€°% AIaVL eck and Associates, inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY 1982 1983 1984 1965 NEW RESOURCES BERNICE LAKE GT 0.00 = 20.00 20.00 BRADLEY LAKE 0.00 0.00 0,00 TOTAL KENAI 0.00 20.00 BELUGA GT 0.00 0.00 BELUGA COAL 0.00 0.00 SUSITNA 0.00 0.00 TOTAL ANCHORAGE 0.00 SUSITNA 0.00 TOTAL FAIRBANKS 0.00 0.00 LOAD RESOURCE KENAI PENINSULA PEAK LOAD (MW) 92.00 94.10 96.30 100.70 RESOURCES: BERNICE LAKE 76.40 76.40 76.40 = 76.40 COOPER LAKE 15.00 15,00 15.00 15.00 LESS: RETIREMENT 0.00 0.00 0,00 0.00 NEW RESOURCES 0.00 20.00 20.00 20.00 NET RESOURCES 91.40 111.40 111,40 SURPLUS (DEF.) -0.60 17.30 15.10 10.70 GREATER ANCHORAGE PEAK LOAD (MW) 427,80 437.80 447.80 469.50 RESOURCES: CEA GT 413.10 413.10 423.10 © 413.10 AML&P GT 231.20) 231.20 231.20 © 231.20 LESS: RETIREMENT 0.00 0.00 0.00 0.00 NEW RESOURCES 0.00 0.00 0.00 0.00 NET RESOURCES 644,30 644.30 644.30 644.30 SURPLUS (DEF.) 216.50 206.50 196.50 174.80 FAIRBANKS. PEAK LOAD (HW) 138,30 153.30 170.30 183,30 RESOURCES GVEA 197.00 197.00 197,00 197.00 FHUS 65.00 65.00 65.00 LESS: RETIREMENT “11.00 -16.00 -16.00 NEW RESOURCES 0.00 0.00 0.00 NET RESOURCES 251.00 246.00 246.00 SURPLUS (DEF.) 97.70 75.70 62.70 TOTAL RAILDELT PEAK LOAD (HW) 658.10 685.20 714,40 753.50 EXISTING RESOURCES 997.70 997.70 997.70 LESS: RETIREMENT 16.00 -16.00 NEW RESOURCES: 20.00 20.00 NET RESOURCES 993.70 1006.70 1001.70 1001.70 SURPLUS (DEF.) 335.60 321.50 287.30 248.20 LESS: RESERVES -200.00 NET SURPLUS (DEF.) 135.60 -200.00 -200.00 121.50 87.30 TRANSMISSION REQS. (EXCLUDING LOSSES) ANCH. TO KENAI W/KENAI OUTAGE 25.60 H/ANC-FAI OUTAGE 0,00 ANCH. TO FAIRBANKS W/PAIRBANKS OUT, 0.00 W/ANC-KEN OUTAGE 0.00 MAXIMUM OUTAGE KERAT 25.00 FAIRBANKS 65.00 ANC-FAI COIN. 200.00 ANC-KEN COIN, 200.00 9.90 0.00 0.00 0.00 25.00 25.00 65.00 65.00 200.00 200.00 200.00 200.00 14.30 0,00 2.30 “14.50 25.00 65.00 200.00 200.00 PLAN BB-BRADLEY LAKE 1966 20.00 0.00 NALYSIS #eee0 103.40 76.40 15.00 0.00 20.00 482.00 413.10 231.20 0.00 0.00 644.30 162.30 186.30 197.00 65.00 -16.00 0.00 246.00 59.70 771,70 997.70 -16.00 20.00 1001.70 230.00 -200.00 30.00 17.00 0.00 5.30 -29.70 25.00 65.00 200.00 200.00 1988 20.00 0.00 20.00 20.00 90.00 90.00 106.20 109.10 112.10 76.40 15.00 0.00 2 494,50 507.80 521.10 534,50 413,10 413,10 © 413.10 © 413.10 231.20 231.20 231.20 0.00 0.00 0.00 0.00 644.30 644,30 149.80 123,20 197.30 201.30 197.00 65.00 16.00 0.00 246.00 48.70 830.50 850.70 997.70 997.70 997.70 -16.00 -16.00 16.00 110.00 110.00 155.00 1001.70 1091.70 1091.70 1136.70 210.70 280.50 261.20 286.00 -200.00 -200.00 -200.00 -200.00 10.70 80.50 61.20 86.00 0.00 0.00 0.00 -11.80 -0.50 9.30 13.30 20.30 45,00 0.00 0.00 25.00 45.00 45.00 65.00 65.00 65.00 200.00 200.00 200.00 200.00 200.00 200.00 561.10 413.20 231.20 210.30 197.00 65.00 -34.00 0.00 228.00 17.70 1104.20 212.30 200.00 12.30 47.30 5.40 45.00 65.00 200.00 200.00 AT 90 MW WITH COAL 45.00 0,00 0.00 589.50 413.10 231.20 -29.60 45,00 659.70 70.20 220.30 197.00 65.00 -52.00 0.00 1993 1994 20.00 90.00 110,00 45.00 200.00 0,00 2110.00 45.00 200.00 245.00 0,00 649.50 413.10 231.20 844.60 195.10 65.00 65.00 -52.00 -52.00 0.00 0.00 982.50 1030.70 997.70 -105.60 355.00 997.70 =90.50 355.00 1262.20 1247.10 279.70 216.40 -200.00 1995 90.00 2110.00 45.00 400.00 0.00 45.00 0,00 0.00 682.00 413.10 231.20 -58.70 445,00 1030.60 1061.00 997.70 125.60 555.00 1427.10 346.20 -200.00 146.10 0.00 0.00 114.30 0.00 45.00 65.00 200.00 200.00 110.00 45.00 400.00 0.00 1030.60 317.70 1128.20 997.70 -219.60 1333.10 204.90 4.50 -35.60 218.30 0.00 45.00 65.00 200.00 200.00 600.00 0.00 1230.60 486.10 1177.30 997.70 309.60 645.00 0.00 110.00 45,00 600.00 0.00 777,90 413.10 231.20 =77.40 645.00 1211.90 434.00 1229.80 997.70 45.00 65.00 200.00 200.00 1999 2000 20.00 90.00 110.00 45.00 45.00 800.00 800.00 180.40 76.40 15.00 -8.90 110.00 12.10 612.90 849.60 413.10 413.10 231.20 7.40 77.40 845.00 845.00 2411.90 1421.90 599.00 562.30 310.30 197.00 65.00 -262.00 1284.00 1340.30 997.70 -348.30 955.00 1604.40 264.10 -200.00 -200.00 140.40 64,10 25.30 0.00 343.30 375.30 0.00 0.00 45.00 45.00 65.00 65.00 200.00 200.00 200.00 200.00 45.00 0.00 188.30 76.40 15.00 +90 110.00 192.50 4.20 888.00 413.10 231 =77.40 845.00 1411.90 523.90 322.30 197.00 65.00 1398.60 997.70 1604.40 205.80 -200.00 40.80 0.00 387.30 0.00 45.00 65.00 200.00 200.00 9-€°% J1IGVL KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BERNICE LAKE GT BRADLEY LAKE TOTAL KENAL BELUGA GT BELUGA COAL SUSITNA TOTAL ANCHORAGE SUSITNA TOTAL FAIRBANKS KENAI PENINSULA PEAK LOAD (MW) RESOURCES BERNICE LAKE COOPER LAKE LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) GREATER PEAK LOAD (HW) RESOURCES CEA GT AML&P GT LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) FAIRBANKS PEAK LOAD (HW) RESOURCES GVEA FMUS LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) TOTAL RAILDELT PEAK LOAD (HW) EXISTING RESOURCES LESS: RETIREMENT NEW RESOURCES NET RESOURCES SURPLUS (DEF.) LESS: RESERVES NET SURPLUS (DEF.) TRANSMISSION REQS. ANCH. TO KENAL W/KENAI OUTAGE W/ANC-FAI OUTAGE ANCH. TO FAIRBANKS W/FAIRBANKS OUT. W/ANC-KEN OUTAGE MAXIMUM OUTAGE KENAL FAIRBANKS ANC-FAI COIN. ANC-REN COIN. (exctut 92.00 16.40 15.00 0.00 0.00 91.40 -0.60 427.80 413.10 231.204 0.00 0.00 216.50 138.30 197.00 65.00 -4.00 0.00 258.00 119.70 658.10 997.70 4.00 0.00 993.70 335.60 -200.00 135.60 25.60 0.00 200.00 * LOAD 94.10 76.40 15.00 0.00 55 146.40 52.30 437.80 413.10 231.20 0.00 0.00 644.30 206.50 153.30 197.00 65.00 -11.00 0.00 665.20 997.70 =11.00 55.00 1041.70 356.50 55.00 65.00 200.00 200.00 eck and Associates, Inc. 96.30 196.50 170.30 197.00 65.00 -16.00 0,00 246.00 75.70 714.40 997.70 -16.00 55.00 1036.70 322.30 -200.00 122.30 4.90 0.00 0.00 0.00 55.00 65.00 200.00 200.00 RESOURCE 100.70 469.50 413.10 231.20 0.00 0.00 644.30 174.60 183.30 197.00 65.00 -16.00 0.00 246.00 62.70 753.50 997.70 =16.00 55.00 1036.70 283.20 -200.00 55.00 65.00 200.00 200.00 PLAN C-COMBUSTION TURBINES WITH COAL NALY SI § *teeeeee 103.40 15.00 0,00 146.40 43,00 482.00 413.10 231.20 162.30 186.30 197.00 65.00 16.00 1036.70 265.00 12.00 0.00 5.30 0.00 55.00 65.00 200.00 200.00 106.20 76.40 15.00 0.00 0 146.40 40.20 494.50 413.10 231.20 0 644.30 149,80 190.30 197.00 65.00 246.00 55.70 1036.70 245.70 100.00 14.80 0.00 9.30 -10,00 55.00 65.00 200.00 200.00 109.10 76.40 15.00 0.00 55.00 194.30 197.00 65.00 -16.00 1036.70 225.50 -200.00 17.70 -11.80 55.00 65.00 200.00 200.00 1989 112.10 76.40 15.00 0,00 55.00 146.40 34.30 521.10 413.10 231.20 197.30 197.00 1036.70 206.20 -200.00 6.20 20.70 16.30 -42.50 55.00 65.00 200.00 200.00 1991 100.00 0.00 31.50 25.90 20.00 534.50 561.10 589,50 413.10 © 413.10 © 413.10 231.20 231.20 -29.60 100.00 714.70 125.20 201.30 210.30 + 220,30 197,00 197.00 197.00 65.00 65.00 65.00 16.00 -34.00 © -52.00 0.00 210.00 10,30 850.70 891.90 936.20 997.70 997.70 997.70 -81.60 00 1086.70 1054.20 1072.10 236.00 162.30 134.90 -200.00 -200.00 -200.00 36.00 -37.70 -65.10 23.50 35.00 0.00 -20.00 20.30 75.30 0.00 55.00 55.00 65.00 65.00 200.00 200.00 200.00 200.00 300.00 5.00 618.70 413.10 231.20 -29.60 300.00 296.00 231.30 197.00 65.00 -52.00 0.00 982.50 997.70 -90.50 355.00 1262.20 279.70 -200.00 79.70 50.00 0.00 86.30 0.00 55.00 65.00 200.00 200.00 300.00 00 138.90 76.40 15.00 -8.90 55.00 137.50 -1.40 649.50 413.10 231.20 -44.70 300.00 899.60 250.10 242.30 197.00 65.00 -52.00 0.00 210.00 -32.30 1030.70 997.70 105.60 355.00 1247.10 216.40 200.00 56.40 0.00 97.30 0.00 55.00 65.00 200.00 200.00 253.30 197.00 1081.00 997.70 125.60 555.00 1427.10 346.20 -200.00 146.10 63.20 0.00 114.30 0.00 55.00 65.00 200.00 200.00 1996 55.00 0.00 100.00 400.00 0,00 152.00 76.40 15.00 -8.90 0 5 137.50 -14.50 712.90 413.10 231.20 1085.60 372.70 263.30 197,00 65.00 -152.00 0.00 110.00 -153.30 1128.20 997.70 219.60 555.00 1333.10 204.90 -200.00 4.90 158.50 76.40 15.00 137.50 21.00 744.50 413.10 231.20 -58.70 700.00 1285 541.10 274.30 197.00 65.00 -242.00 0.00 20.00 -254.30 1177.30 997.70 -309.60 755.00 76.00 0.00 319.30 0.00 55.00 65.00 200.00 200.00 177,90 413.10 231.20 -77.40 700.00 1266.90 489.00 1229.80 997.70 328.30 755.00 1424.40 194.60 83.10 0.00 331.30 0.00 55.00 65.00 200.00 200.00 812.90 413.10 231.20 -77.40 900.00 1466.90 654.00 1284.00 997.70 ~328.30 955.00 1624.40 340.40 90.30 0.00 343.30 0.00 55.00 65.00 200.00 200.00 188.30 76.40 15.00 -8.90 849.60 413.10 231.20 900.00 1466.90 617.30 1340.30 997.70 -348.30 955.00 1604.40 97.90 0.00 375.30 +00 55.00 65.00 200.00 200.00 137.50 -50.80 413.10 231.20 -77.40 900.00 1466.90 578.90 105.80 0.00 387.30 0.00 55.00 65.00 200.00 200.00 2-€% AVL R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY NEW RESOURCES BERNICE LAKE GT BRADLEY LAKE TOTAL KENAL BELUGA GT BELUGA COAL SUSITNA TOTAL ANCHORAGE SUSITNA TOTAL FAIRBANKS KENAI PENINSULA 1985 RESOURCE PEAK LOAD (4H) 92.00 94.10 96.30 100,70 RESOURCES BERNICE LAKE 76.40 76.40 76.40 76.40 COOPER LAKE 15.00 15.00 15.00 15.00 LESS: RETIREMENT 0,00 0:00 0.00 0:00 NEW RESOURCES 0.00 55.00 © 55.00 55.00 Net RESOURCES 91.40 146.40 146.40 146.40 SURPLUS (DEF.) 0.60 52.30 50.10 45,70 GREATER ANCHORAGE PEAK LOAD (HW) 427.80 437.80 447.80 469.50 RESOURCES CEA GT 413.10 413.10 413.10 413.20 AMLEP GT 231.20 231.20 23 231.20 LESS: RETIREMENT 0.00 NEW RESOURCES NET RESOURCES SURPLUS (DEF.) FAIRBANKS PEAK LOAD (MW) 170.30 RESOURCES: GVEA 197,00 FHUS 65.00 LESS: RETIREMENT -16.00 NEW RESOURCES: 0.00 NET RESOURCES 246.00 SURPLUS (DEF.) 75.70 ror! PEAK LOAD (HW) 658.10 685.20 714.40 753.50 EXISTING RESOURCES 997.70 997.70 997.70 997.70 LESS: RETIREMENT -11.00 -16.00 -16.00 NEW RESOURCES 0.00 55.00 55.00 55.00 NET RESOURCES 993.70 1041.70 1036.70 1036.70 SURPLUS (DEF.) 335.60 356.50 322.30 283.20 LESS1 RESERVES -200.00 -200.00 -201 -200.00 NET SURPLUS (DEF.) 135.60 156.50 122.30 83.20 TRANSKISSION REQS. (EXCLUDING LOS: ANCH, TO KENAT W/RENAL OUTAGE 25.60 2.70 4.90 9.30 W/ANC-FAI OUTAGE 0.00 0.00 0.00 0,00 ANCH. TO FAIRBANKS W/FAIRBANKS OUT. 0.00 0.00 0.00 2.30 W/ANC-KEN OUTAGE 0.00 0.00 0.00 0.00 MAXIMUM OUTAGE KENAT 25.00 55.00 55.00 55.00 FAIRBANKS 65.00 65.00 65.00 65.00 ANC-FAL COIN. 200.00 200.00 200.00 200.00 ANC-KEN COIN. 200.00 200.00 200.00 200.00 PLAN D-COMBUSTION TURBINES WITH SUSITNA ANALYSIS 103.40 76.40 15.00 0,00 55.00 482.00 413.10 231.20 0.00 1036.70 265.00 -200.00 12.00 0.00 5.30 0,00 55.00 65.00 200.00 200.00 106.20 76.40 15.00 0.00 55.00 146.40 494.50 413.10 231.20 0.00 791.00 997.70 16:00 55.00 1036.70 245.70 -20 200.00 200.00 507.80 413.10 231.20 0.00 1036.70 225.50 -200.00 25.50 17.70 -11,80 13.30 -26.20 55.00 65.00 200.00 200.00 521.10 413.10 231.20 0.00 0.00 830.50 997.70 16.00 55.00 1036.70 206.20 -200.00 6.20 20.70 -28.10 16.30 42.50 55.00 65.00 200.00 200.00 114,90 76.40 15.00 0.00 55.00 “146.40 31,50 534.50 413.10 231.20 0.00 50.00 23.50 0.00 20.30 8.70 55.00 65.00 200.00 200.00 561.10 413.10 231.20 14.50 29.10 -25.90 47.30 -17.70 55.00 65.00 200.00 200.00 100.00 0,00 126.40 76.40 15.00 0.00 55.00 936.20 997.70 ~81.60 155,00 1071.10 134.90 -200.00 -65.10 35.00 -20,00 75.30 0.00 55,00 65.00 200.00 200.00 132.50 138.90 76.40 15.00 -8.90 55.00 137.50 137,50 5.00 -1.40 618.70 649.50 413.10 413.10 231.20 © 231.20 -29.60 -44.70 795.00 1409.70 791.00 231.30 © 242,30 197.00 197.00 65.00 65.00 ~52.00 -52.00 325.00 325,00 535.00 535.00 303.70 292.70 1030.70 997.70 105.60 1175.00 2067.10 1099.70 1036.40 -200.00 -200.00 899.70 836.40 56.40 0.00 0.00 0.00 55.00 65.00 200.00 200.00 145.70 76.40 15.00 8.90 55.00 137.50 413.10 795.00 1380.60 698.60 253.30 197.00 1081.00 997.70 125.60 1175.00 2047.10 966.10 -200.00 766.10 63.20 0.00 55.00 65.00 200.00 200.00 1997 55.00 0.00 55.00 100.00 0.00 695.00 152.00 158.50 16.40 76.40 15.00 15.00 -8.90 = - 8.90 55.00 55.00 137.50 137.50 -14.50 -21.00 712.90 413.10 231.20 -58.70 795.00 1380.60 1380.60 667.70 636.10 263.30 274.30 197.00 197.00 65.00 65.00 “152.00 -242.00 325.00 325.00 435.00 171.70 70,70 1128.20 1177.30 997.70 997.70 -219.60 -309.60 1175.00 1175.00 1953.10 1863.10 824.90 685.80 -200.00 485.80 76.00 0.00 0.00 0.00 55.00 65.00 65.00 200.00 200.00 200.00 200.00 777.90 413.10 231.20 -77.40 795.00 1361.90 584.00 1229.80 997.70 -328.30 1175.00 1844.40 614.60 83.10 0.00 6.30 0.00 55.00 65.00 200.00 200.00 1361.90 549.00 298.30 197.00 65.00 -242.00 325.00 345.00 46.70 1264.00 997.70 -328.30 1175.00 1044 560.40 -200.00 90.30 0.00 18.30 0.00 55.00 65.00 200.00 200.00 849.60 413.10 231.20 77.40 795.00 1361.90 512.30 1340.30 997.70 -348.30 1175.00 1624.40 97.90 0:00 50.30 0.00 55.00 65.00 200.00 200.00 2001 55.00 0.00 55.00 100.00 0.00 888.00 413.10 231.20 -77.40 795.00 1361.90 473.90 1396.60 997.70 -348,30 1175.00 1824.40 425.80 -200.00 225.80 105.80 0.00 62.30 0.00 55.00 65.00 200.00 200.00 8-€'% AlaVvL TABLE 2.4-1 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY SUMMARY OF TRANSMISSION COSTS Plan Estimated Cost ($1,000) AA 680,121 AB 680, 121 BA 673,371 BB 673,371 BAA 673,371 BAB 673,371 Cc 651,079 657 ,829 2-HSkV one et] BRADLEY LAKE 8 LEGEND WE CCOAL FIRED GENERATION (@ COMBUSTION TURBINE GENERATION 0 HYDRO GENERATION AA SUBSTATION /SWITCHING STATION EXISTING TRANSMISSION SYSTEM == PROPOSED TRANSMISSION SYSTEM 5 oO 5 10 IS 20 25MILES Looiat ft SCALE R. W. BECK and ASSOCIATES ENGINEERS AND CONSULTANTS Seattle, Washington Denver, Colorado General offices: Tower Building, Seattie, Washington 96101 ALASKA POWER AUTHORITY KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY TRANSMISSION FACILITIES DATE: 4-21-82 SECTION 3 ECONOMIC ANALYSIS An economic analysis was performed to evaluate the overall costs for the entire Railbelt area for each alternative plan as defined in Section 2.3. The economic analysis utilizes the Authority's standard methodology with an annual inflation rate of zero percent and an annual real discount rate and interest during construction of 3 percent. Estimated capital and operating costs for the generation and transmission facilities associated with each alternative plan have been totaled for each year of the 50-year evaluation period. These costs were then discounted to January 1982 and summed to pro- vide the cumulative present-worth of each alternative plan's costs. All costs represented in the analysis are in January 1982 dollars except for fuel costs which are assumed to escalate over and above inflation through the analysis period. 3.1 Assumptions The following assumptions were used in the economic analysis for each alternative as applicable: ° Annual costs are discounted to January 1982 using an inflation-free discount rate of 3%. ° All costs are in uninflated and unescalated January 1982 dollars except for fuel costs which are escalated at the following annual rates (Battelle studies): Natural Gas - 14.3% through 1996, 2% thereafter Oil - 2% Coal - 2% Total projected annual energy load requirements are those shown in Table 2.1-1. All cost projections made after the initial 20-year period (1982-2001) are based on no additional load growth or esca- lation beyond 2001. Existing generation capacity including retirements is as shown in Section 2.2. Capital and operating costs and capacity and energy of the various generation plant types are as shown in Table 4.1-1. Interest Dur- ing Construction (IDC) is included based on a 3% interest rate and construction periods of 6, 8 and 4 years for Bradley Lake, Susitna, and a generic coal plant, respectively. Annual capital costs of the various generation plants and trans- mission additions are based on level debt service on the total capital cost including IDC, at a 3% interest rate over amortization periods of 50 years for hydroelectric plants and 30 years for gas-fired combustion turbines, steam turbines, and transmission facilities. No capital costs on existing generation or transmission facilities are included. Forty-five MW of existing coal-fired steam turbines in the Fair- banks area are assumed to operate through their projected retire- ment except in the alternatives including the Susitna Project. In these cases, the existing coal plants are assumed to be retired in 1993 when the Susitna Project comes on-line. Existing and new coal plants are assumed to provide energy based on a 70% plant factor. 3-3 Existing oil-fired combustion turbines in the Fairbanks area are assumed to supply the Fairbanks energy requirements over and above local coal-produced energy and estimated energy imports from the Anchorage area through 1992 at which time the availability of Susitna energy or new Beluga coal energy and additional transmis- sion interties will eliminate the need to use these combustion tur- bines. For all cases, natural gas-fired combustion turbines supply the energy requirements additional to those supplied by hydroelectric and coal facilities and the Fairbanks area combustion turbines. During certain peak periods, available natural gas in the Cook Inlet area is insufficient to supply all generation resource re- quirements. At these times, oil is used to fuel some combustion turbines to supply the additional power. The estimate of the amount of oil required each year for this purpose has been devel- oped by AML&P through the Authority and ranges from 1.6 million gallons in 1983 to 8.6 million gallons in 1991 assuming nearly 100% combustion turbine generation. The amounts of oil to be used in the Bradley Lake Project alternatives have been reduced with Brad- ley Lake on-line due to peak load energy available from the Bradley Lake Project. Additionally, with the installation of the Susitna Project or a large coal plant at Beluga the use of oil for gener- ation in the Anchorage area is assumed to be eliminated. Spinning reserve requirements for the entire Railbelt area are assumed to be 100 MW in all cases except when large 200 MW coal plants are installed. Spinning reserves are then assumed to be 200 MW. The costs of spinning reserves are based on the fuel and variable operating and maintenance costs of running gas-fired com- bustion turbines at speed-no-load. Fuel consumption under these conditions is assumed to be approximately one-third the consumption under loaded conditions. The Bradley Lake Project is assumed to provide 65 MW or 20 MW of spinning reserve for the 135 MW and 90 MW plant sizes, respectively. The Susitna Project is assumed to pro- vide all Railbelt area spinning reserves when it is installed. ° Fuel costs in January 1982 dollars are as follows: Fuel Type $/MM Btu Natural gas 0.69 Nenana coal 1.43 Beluga coal 1.69 Oil 6.93 ° Costs for new transmission facilities required under each alterna- tive are as shown in Section 2.4. Operation and maintenance costs for new transmission facilities are assumed to be 1.9 percent. 3.2 Results Based on the foregoing methodology and assumptions, the cumulative present-worth of each alternative has been calculated. These results are sum- marized in Table 3.2-1. The individual economic analyses are shown in Tables 3.2-2 through 3.2-9. Alternative Plans AA, AB and D include the Susitna Project. As shown in the tables, the lowest evaluated cost alternative is Plan AB, the Bradley Lake Project at 90 MW with Susitna, followed closely by Plan AA, the Bradley Lake Project at 135 MW with Susitna. Both of these cases have a lower total evaluated cost than Plan D, Susitna with combustion turbines. This indicates the advantage of the Bradley Lake Project over continued use of com- bustion turbines. The evaluated costs of the Bradley Lake Project at 135 MW and at 90 MW are very close in this evaluation and either could be considered better based on the sensitivities of the evaluation. Alternative Plans BA, BAA, BAB, BB and C include coal-fired gener- ation resources. If the Susitna Project were not to be built and coal plants were constructed instead, the lowest evaluated cost alternative would involve alternative Plans BA and BAA, the construction of the Bradley Lake Project at 135 MW. As expected, when power from the Bradley Lake Project is used to off- set coal generation rather than Susitna generation, the more generation the Bradley Lake Project can provide, the higher the benefits. Alternative Plans BA and BB, the Bradley Lake Project at 135 MW and 90 MW, respectively, with coal have lower evaluated costs than Plan C, combustion turbines with coal. This again indicates the advantage of the Bradley Lake Project over continued use of combustion turbines. Another consideration is the effect produced by delaying the Brad- ley Lake Project. Plans BAA and BAB include a 3-year delay and a 6-year delay, respectively, in the on-line date for the Bradley Lake Project with coal. Results of the economic analysis indicate that Plan BAA, with the 3-year delay, has a lower total cost than the case with no delay, Plan BA. Since the total costs of these plans are very close, any rearrange- ment of the variables could easily change the comparable outcome. As an example, reducing the amount of oil-fired combustion turbine generation in Fairbanks as a result of placing the Bradley Lake Project on-line favors the no-delay plan over the 3-year delay plan. This indicates that a close evalu- ation of the actual operational procedures to be used by the Railbelt utili- ties under the proposed alternative could vary the outcome of the economic analysis. Based on the level of sensitivity, it is not recommended to delay the Bradley Lake Project. R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY NEW GENERATION PLANT DATA Annual Capital Fixed Variable Capacity Heat Rate Energy cost (5) OsM O&M Fuel Resource (MW) (Btu/kWh) (GWh) ($/kW) ($/kW/yr) (mills/kWh) ($/MM_Btu) BRADLEY LAKE 2-unit ...... see 90 -- 346 (4) 3,629 (3) 9 (1) -- -- 3-unit .......0. 135 -- 356 (4) 2,732 (3) g (1) -- = SUSITNA Watana I & II .. 1,020 (1) -- 3,459 (1) 2,952 (2) 5 (@) -- -- COAL PLANT Beluga ......... 200 10,000 1,226 2,051 16.71 0.6 1.69 Nenana ......... 200 10,000 1,226 2,110 16.71 0.6 1.43 COMBUSTION TURBINE Gas-fired ..... : 20-75 12,000 (3) 429 266 (3) 2.7 (3) 4.8/mMwh (3) 0.69 Oil-fired ...... 20-75 12,000 (3) 429 266 (3) 2.7 (3) 4.8/Mwh (3) 6.93 NOTES: Costs are from Battelle Technical Data Sheetstl except where noted. (1) (2) (3) (4) (5) (6) Battelle's Railbelt Study!9, Tables 2.1 and 4.2. ACRE's Susitna Project Feasibility Report.8 Alaska Power Authority. Alaska Power Administration's Bradley Lake Project Report.2 Excluding IDC. Battelle's additional studies. T-T°€ ATaWL B BA BAA BAB BB R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY SUMMARY OF ECONOMIC ANALYSES CUMULATIVE PRESENT-WORTH OF ALTERNATIVES' ur y Alternative 7 Bradley Lake at 135 MW with Susitna ........... Bradley Lake at 90 MW with Susitna .........e0- Bradley Lake at 135 MW with coal ....ssceceeeee Bradley Lake at 135 MW (3-year delay) with coal ...ccccececcccccccce Bradley Lake at 135 MW (6-year delay) with coal ........eeeeeeeee a Bradley Lake at 90 MW with coal ......scesceees Combustion turbine with coal ....cecccecccvcces Combustion turbine with Susitna .......sceceees TABLE 3.2-1 COSTS Cumulative Present-Worth ($ x 106) 6,954 6,949 7,354 7,340 7,756 7,486 7,606 7,031 R. WwW. B KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY 1982 3020 4s 254 1963 3206 45 254 1964 3410 45 254 1965 3597 4s 254 1966 3687 4s 254 1987 3778 45 254 1986 3671 180 254 1969 3965 160 254 1990 4064 180 254 1991 4264 180 254 1992 447. 160 254 1993 4693 1200 254 1994 4923 1200 254 1995 5166 1200 254 1996 5392 1200 254 1997 5630 1200 254 1996 5776 1200 254 1999 6136 1200 254 2000 6406 1200 254 2001 6689 r200 254 BRAD. LAKE CAP. COST ($/KW) SUSITNA CAPITAL COST ($/KW) NENANA COAL (§/HHBtu) BELUGA COAL (§/KMBtu) COAL HEAT RATE (Btu/KWh) COAL ESCALATION COAL CAPITAL COST ($/KW) COAL FIXED O&M ($/KW-YR) COAL VAR. O6M (mills/KWh) NATUKAL GAS ($/HHBtu) OIL COST ($/HHBtu) COB. TURBINE HEAT RATE NAT. GAS ESC. THRU 1996 NAT. GAS ESC. APTER 1996 OIL ESCALATION COM. TUK. CAPITAL COST ($/KW! COM. TUR. PIXED O6M ($/KW-¥R| COM. TUR. VAR. O&M ($/HWh) DISCOUNT FACTOR SPINNING RESERVES (MW) SPINNING RSRVS. W/COAL (HW) HYDROELECTRIC NEW GEN. (Gin) 3012 3307 1.43 1.69 10000 1.02 2051 16.72 0.60 0.69 6.93 12000 1.143 1.02 1.02 266 2.70 4.8 2.03 100 200 cap. cost ($000) 15600 15800 15800 15600 15600 146910 146910 146910 146910 146910 146910 146910 146910 146910 ecccce 1215 1215 1215 1215 1215 6315 6315 6315 6315 6315 6315 6315 6315 6315 eecccccce RAILBELT ECONOMIC ANALYSIS PLAN AA-BRADLEY LAKE AT 135 MW WITH SUSITNA 0 0 0 0 0 0 0 o ° o 0 0 0 0 0 0 0 0 0 0 eccoccccecesccceccce 0 0 0 ° 0 oO 0 0 0 PUEL cost eccceecce TOTAL COMBUSTION TURBINES OIL CT NAT.GAS GEN (Gwin) 345 as 207 306 26 331 326 344 eee Ese Ess eccccccce GEN. (Gwh) 2145 2261 2593 2761 2642 2917 2659 2735 2826 3006 3m 624 054 1097 1323 1562 1707 2067 2337 2620 cap. cost (000) o an an 2 271 271 271 2 2 a 2 an 27 an 271 an 271 221 27 an O6M cost ($000) 14459 15389 16365 17265 17695 28133 16872 17325 17759 18720 19575 5335 6400 7510 0342 9310 9921 11605 12903 14259 FUEL cost ($000) 90587 102459 219851 141699 22469 35164 51599 74g 85646 95546 217971 136068 155566 TRANSMISSION ======== SPINNING CAP. LK RESERVE ‘TOTAL cost cost cost ($000) ($000) ($000) o 3819 © 69592 ° 4165 369 1264 4560 © 64176 1264 5012-93879 1264 5528 102352 1264 6118 = 112385 2640 2378 = 132138 2640 2647 © 143910 2640 2956 © 156616 2640 3308 = 175414 2640 3711198614 11486 0 227484 11486 0 241244 11486 0 256768 22486 0 = 279172 11486 0 © 294637 11486 0 305247 11486 0 329257 11486 0 346651 11486 0 369504 CUMULATIVE PRESENT WORTH 30 YEARS (2002-2031) CUM. PW AT NO ADDITIONAL GROWTH TOTAL CUMULATIVE PW OP ALTERNATIVE PW TO JAN 62 ($000) 69592 78999 19344 65913 90939 96944 110663 117012 123634 134440 147768 164339 169203 176222 164565 109116 190158 199206 204796 210723 2623597 41302668 6953064 e-2€ AVL R. W. Beck and Associat inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY RAILBELT ECONOMIC ANALYSIS PLAN AB-BRADLEY LAKE AT 90 MW WITH SUSITNA HYDROELECTRIC COMBUSTION TURBINES TOTAL os aaa INNING ENERGY exist. TOTAL EXIST. TOTAL OIL CT NAT.GAS cap. oun PUEL Osm RESERVE TOTAL = PW -TO REQS. GEN. CAPAC. GEN. CAP. GEN GEN. cost cost cost cost Cost (Giih) » co) (Gib) (000) — ($000) — ($000) ~— ($000) ($000) ~—_( $000) 1982 3020 45 254 276 o 0 918 3947 345 2145 46449 3e19 1983 3206 45 254 45 276 0 0 918 4026 45 2261 56601 4165 1984 3410 45 254 45 276 0 0 oe 4106 287 2593 52875 4560 1985 3597 45 254 45 276 0 0 a8 4188 306 2761 61144 5012 93879-85913 1986 3687 45 254 4s 276 0 o 918 4272 316 2641 68588 5528 102352 += 90939 1987 3778 45 254 4s 276 0 o a8 4358 331 2917 77507 6118 112385 = 96944 1966 3871 135 254 45 276 0 0 918 4445, 328 2667 79961 5434 133380111704 1989 3965 135 254 45 276 o 0 918 4534 346 2743 90947 6051 145525 118325 1990 4064 135 254 45 276 0 0 918 4624 354 2634 102847 6756 159387 125822 1991 4264 135 254 4s 276 0 0 918 477 374 3014 120270 7562 178670 = 136936 1992 447d 135 254 45 276 0 0 918 4el) 43 3162 242154 8483 © 202424 = 150623 1993 4693 2155 254 0 0 0 0 0 0 0 634 22829 0 226428 =163576 1994 4923 1155 254 0 0 0 0 o 0 0 664 35575 0 240239 «168499 1995 5166 2155 254 0 0 0 0 0 0 0 1107 52069 0 «257843 175578 1996 5392 1155 254 o 0 0 0 0 0 0 1333 71687 0 276266 = 163967 1997 5630 1155 254 0 0 0 0 0 0 0 1571 86195 0 293769 «186559 1998 5776 1155 254 0 0 0 0 0 0 0 1717 96106 0 304290 189624 1999 6136 1155 254 145118 0 0 0 0 0 0 0 2077 128542 O 328411 «198694 2000 6406 1155 254 145118 5910 0 0 0 0 0 0 0 2347 136650 0 204306 2001 6689 1155 254 145118 5910 0 0 0 0 0 0 0 2630 156159 0 210254 CUMULATIVE PRESENT WORTH 2828196 30 YEARS (2002-2031) CUM, PW AT NO ADDITIONAL GROWTH 4121072 TOTAL CUMULATIVE PW OP ALTERNATIVE 6949269 BRAD. LAKE CAP, COST ($/KW) 4004 SUSITNA CAPITAL COST ($/KW) 3307 NENANA COAL ($/HMBtu) 1.43 BELUGA COAL ($/HMBtu) 1.69 COAL HEAT RATE (Btu/KWh) 10000 COAL ESCALATION 1.02 COAL CAPITAL COST ($/KW) 2051 COAL PIXED O&M ($/KW-YR) 16.71 COAL VAR. O6M (mille/KWh) 0.60 NATURAL GAS ($/MMBtu) 0.69 OIL COST ($/HMBtu) 6.93 COMB. TUKBINE HEAT RATE 12000 NAT. GAS ESC, THRU 1996 2,143 NAT. GAS ESC. AFTER 1996 1.02 OIL ESCALATION 21,02 COM.TUR. CAPITAL COST($/KW) 266 COM. TUR. PIXED O64 ($/KH-YR) 2.70 COM. TUR. VAR. O&M ($/Mih) DISCOUNT FACTOR SPINNING RESERVES (MW) SPINNING RSRVS. W/COAL (MW) 200 e-c7€ 31avl eck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY ‘TOTAL ENERGY TOTAL EXIST. REQS. CAPAC. GEN. (Gun) (aw) (Guin) 3020 45 254 3206 45 254 3410 45 254 3597 45 254 3687 45 254 3778 45 254 3671 180 254 3965 180 254 4064 160 254 4264 180 254 4a 180 254 4693 160 254 4923 180 254 5166 160 254 5392 160 254 5630 160 254 5776 160 254 6136 160 254 6406 140 254 6689 180 254 BRAD. LAKE CAP. COST ($/KW) SUSITNA CAPITAL COST ($/KH) NENANA COAL (§/HMBtu) BELUGA COAL ($/HHBtu) COAL HEAT RATE (Btu/KWh) COAL ESCALATION COAL CAPITAL COST ($/KW) COAL FIXED O&M ($/KW-YR) COAL VAR. O6M (mills/KWh| NATURAL GAS ($/HMBtu) OIL COST ($/HMBtU) COMB. TUKBINE HEAT RATE NAT. GAS ESC. THRU 1996 NAT. GAS ESC. AFTER 1996 OIL ESCALATION COM.TUR, CAPITAL COST($/KW) COM. TUR. PIXED OsM($/KW-YR) COM.TUK. VAR. O4M ($/HWh) DISCOUNT PACTOR SPINNING RESERVES (MH) SPINNING RSRVS. W/COAL (MW) HYDROELECTRIC 301) 3307 1.43 1.69 10000 1.02 2051 16.71 0.60 0.69 6.93 12000 1.143 2.02 1.02 266 2.70 1.03 100 200 ‘TOTAL CAPAC, CAP. cost ($000) RAILBELT ECONOMIC ANALYSIS PLAN BA-BRADLEY LAKE AT 135 MW WITH COAL Exist. GEN. (Gwh) 276 276 276 276 276 276 276 276 276 276 276 276 276 276 276 123 123 123 oO 0 0 0 0 0 0 0 0 0 0 0 0 S 5 o 1226 2453 2453 3679 3679 4905 4905 4905 ($000) o 0 0 0 0 0 0 0 0 0 0 4M cost 16719 16311 16311 PUEL cost ($000) 768 118535, 118394 120762 COMBUSTION TURBINES OIL CT NAT.GAS GEN GEN. (Gwh) 345 as 267 306 316 331 326 344 352 372 a 0 0 0 0 0 1218 0 1364 0 498 0 891 0 1174 PUEL cost (9000) ¢ 27115389 27116365 27117265 27117695 27118133 271 16672 27.:17325 271 «17759102459 271 16720119851 27119575 141699 2711472992959 271 15794115734 2711101485951 2711846120414 27 1664 66828 2 8274 = 76352 2 4074 = 28414 271 5962 51881 an 7318 = 69695 CUMULATIVE PRESENT WORTH ‘TRANSMISSION CAP. Osn cost cost $000) — ($000) o o o o 3617 1264 3817 1264 3817 1264 3617 1264 7974 2640 7974 2640 7974 2640 7974 2640 7974 2640 34355 11372 34355 11372 34355 11372 34355 11372 34355 11372 34355 11372 34355 12372 34355 11372 34355 41372 —~ SPINNING RESERVE cost ($000) 3819 4165 4560 5012 5528 61 237 2647 2956 3308 3711 16091 18122 20442 23095 23519 23952 24393 24843 25302 132138 143910 156616 175414 198614 244641 271124 292594 321717 326265 338552 343884 369139 391136 30 YEARS (2002-2031) CUM. PW AT NO ADDITIONAL GROWTH TOTAL CUMULATIVE PW OP ALTERNATIVE 212693 209417 210974 206056 216830 223059 2962435 4372063 7354498 y-ce AIaVL w. KENAI PENINSULA eck and Associates, Inc. POWER SUPPLY AND TRANSMISSION STUDY YEAR 1962 1983 1984 1965 1986 1967 1968 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 TOTAL ENERGY REQS. (Gun) 3020 45 254 3206 45 254 3410 45 254 3597 45 254 3667 45 254 3778 45 254 3672 45 254 3965 45 254 4064 45 254 4264 180 254 aan 160 254 4693 160 254 4923 160 254 5166 180 254 5392 160 254 5630 160 254 5776 160 254 6136 180 254 6406 160 254 6689 160 254 BRAD. LAKE CAP. COST ($/KW) SUSITNA CAPITAL COST ($/KW) NENANA COAL (§/HMBtu) BELUGA COAL ($/HMBtu) COAL HEAT RATE (Btu/KWh) COAL ESCALATION COAL CAPITAL COST ($/KW) COAL FIXED O&M ($/KW-YR) COAL VAR. O6H (ni115/KWh) NATUKAL GAS ($/HMBtu) OIL COST ($/HMBtu) COMB. TURBINE HEAT RATE NAT, GAS ESC. THKU 1996 NAT. GAS ESC. AFTER 1996 OIL ESCALATION COM.TUK, CAPITAL COST($/KW) COM.TUR. PIXED O4M($/KW-¥R) CON. TUR. VAR. O&M ($/HWh) DISCOUNT FACTOR SPINNING KESERVES (HW) SPINNING RSRVS. W/COAL (MW) HYDROELECTRIC eccceccce Sas aan 356 356 356 356 356 356 356 356 301d 3307 1.43 1.69 10000 1,02 205) 16.71 0.60 0.69 6.93 12000 1.143 2,02 1.02 266 2.70 4.8 1.03 100 200 PLAN 0 0 0 o 0 0 0 0 oO 1215 1215 1215 1215 1215 1215 1215 1215 1215 RAILBELT ECONOMIC ANALYSIS BAA-BRADLEY LAKE AT 135 MW (ON-LINE 1991) WITH COAL GEN. (Guh) a 1226 2453 2453 3679 3679 4905 4905 4905 0 0 0 0 0 0 0 0 0 0 0 x 2 22164 44368 44368 66552 66552 88736 68736 88736 4995 4995 9073 9073 12641 12641 16719 16311 16311 cost (9000) 3947 4026 4106 4168 427 4358 444s 4534 4624 477 4g11 30669 31283 58733 59908 46047 97768 116535 118394 120762 407 94918 407 221853 407 119851 407 141699 407 92959 407 115734 407 85951 407 210414 407 66828 407 76352 407 26414 407 51861 407 69695 CUMULATIVE PRESENT WORTH 3817 3817 7974 7974 34355, 34355, 34355 34355, 34355, 34355 34355 34355, 34355 ObM = RESERVE cost cost ($000) = ($000) 3819 4165 4560 5012 5528 6118 6793 7564 e445 3308 3711 16091 16122 20442 23095 23519 23952 24393 24843 25302 122548 123277 136462 150622 175577 198777 244804 271267 292757 321860 326428 338715 344047 369302 391299 30 YEARS (2002-2031) CUM. PW AT NO ADDITIONAL GROWTH TOTAL CUMULATIVE PW OP ALTERNATIVE Pw TO JAN 82 (9000) 69592 79157 79498 86062 91084 97085 103242 110972 119062 134565 147909 176851 190275 199353 212601 209521 211076 208154 216926 223152 2966338 4373885 7340223 s-2'e AlavL R. WwW. B ck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY RAILBELT ECONOMIC ANALYSIS PLAN BAB-BRADLEY LAKE AT 135 MW (ON-LINE 1994) WITH COAL HYDROELECTRIC ION TURBINES TRANSMISSION TOTAL oo = ---- =~ SPINNING ENERGY TOTAL EXIST. TOTAL OIL CT NAT.GAS cap. oun PUEL OsK RESERVE TOTAL Pw TO REQS CAPAC, GEN. CAP. GEN GEN. cost cost cost cost cost COST JAN 82 (Gin) (mie) (Gun) (MW) (Gh) (Gh) ($000) (5000) ($000) ($000; 1982 3020 254 o ° ° 45 276 0 918 3947 214s 0 46449 o 3019 69592 69592 1963 3206 254 0 0 0 45 276 0 918 4026 2261 146 56601 0 4165 81938-79552 1984 3410 254 ° ° ° 45 276 o 918 4106 2593 146 52875 1264 4560 © 84746-79881 1985 3597 254 ° 0 0 45 276 0 918 4188 2761 246 =—«:173600 61144 1264 501294448 86434 1966 3687 254 0 0 0 45 276 0 918 4272 2041 746 «17789 68588 1264 $528 102922, 91445 1987 3778 254 0 0 0 45 276 0 918 4358 2917 746 = 18227-77507 1264 6118 112955 97436 1988 3871 254 0 o 0 45 276 0 918 444s 3004 18675 © 87026 1264 6793 123683 103583 1989 3965 254 0 o 0 45 276 0 918 4534 3080 19128 © 98918 1264 7564 «136688 = 111303 1990 4064 254 ° ° 0 45 276 0 918 4624 3171 19562 111853 1264 8445 151229 119381 1991 4264 254 o 0 0 45 276 0 918 477 3351 20726 = 130456 1264 9452173114 132677 1992 447d 254 0 0 0 45 276 0 a8 4811 3519 21783153686 1264 = 10603 199665 148569 1993 4693 254 0 0 ° 45 276 0 918 4907 3625 22822 186193 9996 11919269734 194861 1994 4923 254 356 15800 1215 45 276 0 918 5005 3449 22178 = 204015 11372 4698 302339 212054 1995 5166 254 356 15800 1215 245 276 1226 4995 31908 3054 17403 143691 11372 20442306147 = 208472 1996 5392 254 356 = 15600 1215 245 276 1226 499532547 3280 16235 176411 11372 23095 342991226757 1997 5630 254 356 = 15600 1215 420 123 2453 8564 = 58161 2444 24048 134090 11372-23519 348274 223544 1996 5776 254 356 © 15800 1215 420 123 2453 8564 59324 2590 14659 144959 11372 23952 361349 - 22518 1999 6136 254 356 © 15800 1215 620 123 3679 12641 89523 1724 10459 98393 1137224393 367485 © 222334 2000 6406 254 356 15800 1215 600 0 3679 66552-12233 88801 2117 2782-12346 = 123259 11372) 24843393559 231175 2001 6689 254 356 = 15800 1215 600 0 3679 © 66552, 12233-90577 2400 2762 © 13702142501 1137225302 416392 237462 CUMULATIVE PRESENT WORTH 3101694 30 YEARS (2002-2031) CUM. PW AT NO ADDITIONAL GROWTH 4654368 TOTAL CUMULATIVE PW OF ALTERNATIVE 7756061 BRAD. LAKE CAP. COST ($/KH) 301 SUSITNA CAPITAL COST ($/KH) 3307 NENANA COAL ($/MMBtu) 2.43 BELUGA COAL ($/MMBtu) 1.69 COAL HEAT RATE (Btu/KWh) 10000 COAL ESCALATION 1.02 COAL CAPITAL COST ($/KW) 2051 COAL PIXED O&M ($/KW-YR) 16.71 COAL VAR. O6M (mills/KWh) 0.60 NATURAL GAS ($/HMBtU) 0.69 OIL COST ($/MMBtu) 6.93 COMB, TURBINE HEAT RATE 12000 NAT. GAS ESC. THRU 1996 1.143 NAT. GAS ESC. AFTER 1996 1.02 OIL ESCALATION 1.02 COM.TUR. CAPITAL COST($/KH) 266 COM. TUR, PIXED O&M ($/KW-YR) 2.70 COM.TUR. VAR. O&M ($/HWh) 4.8 DISCOUNT PACTOR 1.03 SPINNING RESERVES (HW) 100 SPINNING RSRVS. W/COAL (MH) 200 9-2 AIGVL R. W. Beck and Associates, inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY RAILBELT ECONOMIC ANALYSIS PLAN BB-BRADLEY LAKE AT 90 MW WITH COAL HYDROELECTRIC --: =- SPINNING TOTAL EXIST. wew cal cap. Oem RESERVE CAPAC, Gen. cost cost cost (my (Gwh) (8000) (8000) ($000) 4s 256 o 929 345 o o 4s 254 0 942 as o 0 4s 254 o 942 287 7 1264 4s 254 0 942 306 7 1264 93679 85913 as 254 o 942 n6é 7 1264 202352 90939 45 254 0 942 331 3817 1264 112385 = 96944 135 254 346 = 14008 942 328 7974 2640 133380111706 135 254 34614008 942 346 7974 2640 245525 126325 135 254 346 =—:14008 973 354 17929 102847 1974 2640 159387 125822 135 254 34614008 973 374 18890 = 120270 7974 2640 178670 136936 135 254 34614008 901 413 19691 142156 7974 2640 202370 = 150582 135 254 34614008 912 0 1489893320, 34355 11372 248948 = 179845 135 254 34614008 877 o 15909) 116146) 3435511372 276106 = 193655 135 254 346 =—(14008 057 o 2212986422, -34355) 11372 298408 © 203202 135 254 34614008 763 o 22962110952, 3435511372 326483 © 217166 135 254 34614008 698 ° 7779 6737734355) 1372, 333182 213857 135 254 346 664 0 8390-76911 34355 1372-31935) 345625 215382 135 254 346 649 o 4190 26985-34355) 1372 «32524352115 212432 135 254 346 649 o $076 = 52463-34355) 12372 «33124 376532 221173 135 284 346 120762 ous o 7434 70268) = 34355 11372-33736 = 398693 227369 CUMULATIVE PRESENT WORTH 3029180 30 YBARS (2002-2031) CUM. PW AT NO ADDITIONAL GpowrH 4456537 TOTAL CUMULATIVE PW OF ALTERNATIVE 7485717 BRAD. LAKE CAP. COST (§/KW) SUSITNA CAPITAL COST ($/KW) MENANA COAL ($/HHBtu) BELUGA COAL ($/HMI COAL HEAT RATE ( COAL ESCALATION COAL CAPITAL COST ($/xw) COAL PIXED O&M ($/KW-YR) COAL VAR. O6M (mille/KWh) NATURAL GAS ($/HHBtu) OIL Cost ($/MMBtu) COMB. TURBINE HEAT RATE NAT. GAS ESC. THRU 1996 NAT. GAS ESC. APTER 1996 OIL ESCALATION COM.TUR. CAPITAL COST($/KW) COH.TUK. PIXED O4H($/KW-YR) COM.TUR. VAR. O&M ($/MWh) DISCOUNT PACTOR SPINNING KESEKVES (HW) SPINNING KSRVS, W/COAL (Hw) 24-2 AIGVL R. W. Beck and Associates, inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY RAILBELT ECONOMIC ANALYSIS PLAN C-COMBUSTION TURBINES WITH COAL HYDROELECTRIC COMBUSTION TURBINES TRANSMISSION yraL -- - an a= a= ‘=~ SPINNING ENERGY TOTAL EXIST, NEW CAP. 6M TOTAL = EXIST. NeW CAP. Osn FUEL TOTAL «OIL CT NAT.GAS cap. 04K FUEL O&K = =RESERVE = TOTAL — PW‘ TO REQS. CAPAC. GEN, GEN. cost COST CAPAC, GEN. GEN. cost cost cost CAP. GEN GEN. cost cost cost cost = cosT COST = JAN 82 YEAR = (Gh) (at) (Gwh) (Gah) — ($000) ($000) (ati) (Guin) (Giih) ($000) ($000) ($000) (at) (Gah) (Gwh) ($000) ($000) ~— (5000) ($000) ($000) ($000) ~— ($000) 1982 3020 45 254 o 0 o 45 276 0 3947 929 345 2145 0 3819 = 69592 69592 1983 3206 45 254 o 0 0 45 276 0 4026 977 as 2261 0 4165 81936 = 79552 1964 3410 45 254 0 0 0 45 276 0 4106 977 267 2593 1264 4560 © 84746 1965 3597 45 254 0 0 0 45 276 o alee 977 306 2761 1264 5012 94448 1986 3687 45 254 o 0 0 45 276 0 4272 977 26 2641 1264 5528 102922 1987 3778 4s 254 0 0 0 45 276 0 4358 977 331 2917 1264 6118 = 112955 1988 34871 45 254 0 0 0 45 276 0 4445, 977 337 3004 1264 6793 123683 1969 3965 45 254 0 0 0 45 276 0 4534 977 355 3060 1264 7564 = 136868 = 111303 1990 4064 45 254 0 0 o 45 276 0 4624 1013 363 3171 1264 8445 152046 120026 1991 4264 45 254 0 0 0 45 276 0 any 1013 363 3351 1266 9452 172710 132368 1992 aan. 45 254 0 0 0 45 276 0 4611 1011 422 3519 1264 = 10603198655 147967 1993 4693 45 254 0 0 0 245 276 1226 30669 = 1002 0 2937 2107 105782 20996 = 22437249191 180021 1994 4923 45 254 0 0 0 245 276 1226 31263 987 0 3167 2107 130391 10996 = 25445278486 = 195324 1995 5166 45 254 0 0 0 445 276 2453 58733 967 0 2183 2107 102704 10996 303169 © 206443 1996 5392 45 254 0 0 0 445 276 2453 59908 873 0 2409 2107 129562 20996 = 32813335965 = 222112 1997 5630 45 254 0 0 0 620 123 3679 66047 808 0 1574 2107 86359 10996 = 33441341099 218939 1996 5776 45 254 0 0 0 620 123 3679 87768 714 0 1720 2107 96274 10996 = 34082353966 220592 1999 6136 45 254 0 0 0 820 123 4905 16719 128535 159 0 B54 2107 40734 10996 = 34736 © 359929 217763 2000 6406 45 254 0 0 0 800 0 4905 16311 118394 159 0 1247 2107 72607 10996 = 35403385807 226621 2001 6689 4s 254 0 0 0 800 0 4905 16311 120762 759 0 1530 2107 90836 10996 = 36083 408439 = 232927 CUMULATIVE PRESENT WORTH 3040329 30 YEARS (2002-2031) CUM. PW AT NO ADDITIONAL GROWTH 4565476 TOTAL CUMULATIVE PH OP ALTERNATIVE 7605804 SUSITNA CAPITAL COST ($/KW) 2952.00 NENANA COAL ($/MMBtu) 1.43 BELUGA COAL ($/HHBtu) 1.69 COAL HEAT RATE (Btu/KWh) 10000 COAL ESCALATION — ($/KW) 2,02 COAL CAPITAL COST ($/KW) 2051.00 COAL FIXED O4M ($/KW-YR) 16.72 COAL VAR. O64 (ills/KWh) 0.60 NATUKAL GAS ($/HMBtu) 0.69 OIL COST ($/MMBtu) RATE 6.93 COMB. TURBINE HEAT RATE 12000 NAT. GAS ESC. THRU 1996 2.143 NAT. GAS ESC. AFTER 1996 1,02 OIL ESCALATION —OST($/KW) 1.02 COM.TUR. CAPITAL COST($/KW) — 266.00 COM.TUR. PIXED O64 ($/KW-YR) 2.70 COM. TUR. VAR. O6H ($/MWh) DISCOUNT FACTOR — (MW) SPINNING RESERVES (MW) SPINNING RSRVS. W/COAL (MW) 8-2 € AIGVL R. W. B ck and Associat KENAI PENINSULA Inc. POWER SUPPLY AND TRANSMISSION STUDY TOTAL = -----~ ENERGY TOTAL EXIST. REQS. CAPAC, — GEN. (EAR (Gith) (aw) (Guh) 1982 3020 45 254 1983 3206 45 254 1984 3410 45 254 1985 3597 45 254 1966 3687 45 254 1967 3776 45 254 1966 3671 45 254 1969 3965 45 254 1990 4064 45 254 1991 4264 45 254 1992 447. 45 254 1993 4693 1065 254 1994 4923 1065 254 1995 5166 1065 254 1996 5392 1065 254 1997 5630 1065 254 1998 5776 1065 254 1999 6136 1065 254 2000 6406 1065 254 2001 6689 1065 254 SUSITNA CAPITAL COST ($/KW) NENANA COAL ($/HMBtu) BELUGA COAL ($/HMBtu) COAL HEAT RATE (Btu/KWh) COAL ESCALATION COAL CAPITAL COST ($/KW) COAL FIXED O6M (§/KW-YR) COAL VAR. O6M (mills/KWh) NATURAL GAS ($/HMBtu) OIL Cost ($/HMBtu) COMB. TURBINE HEAT RATE NAT. GAS ESC, THRU 1996 NAT. GAS ESC. AFTEK 1996 OIL ESCALATION COM.TUR. CAPITAL COST($/KW) COM.TUR. PIXED O6K($/KW-YR) COM.TUK. VAR. O4M ($/HWL) DISCOUNT FACTOR SPINNING RESERVES (MW) SPINNING KSKVS. W/COAL (MW) HYDROELECTRIC 0 0 0 0 oO 0 0 o o 0 0 3459 3459 3459 3459 3459 3459 3459 3459 3307 1.43 1.69 10000 1.02 2051 16.71 0.60 0.69 6.93 12000 1.143 1.02 1.02 266 2.70 48 1.03 100 200 eccceccccce a3il0 131110 132110 131110 131110 131110 131110 131110 wile eccecccccee £ = Ss 5100 5100 5100 5100 5100 5100 5100 5100 eccceccee RAILBELT ECONOMIC ANALYSIS PLAN D-COMBUSTION TURBINES WITH SUSITNA 0 0 0 0 o 0 0 o 0 0 0 o 0 0 0 0 0 0 ° 0 cap. cost ($000) eececoccceecceccccce ecccccece FUEL cost ecccceccoe TOTAL cap. (an) 929 977 977 977 977 977 977 977 2013 1013 1011 1002 987 967 COMBUSTION TURBINES OIL CT NAT.GAS GEN (Gwh) 345, 415, 267 306 316 331 337 355 363 eccececce GEN. (Gwin) 2145 2261 2593 2761 2641 2917 3004 3060 371 3351 3519 960 1210 1453 1679 1917 2063 2423 2693 2976 CAP. cost $000) o 746 146 146 146 146 746 746. 1428 1428 2107 2107 2107 2107 2107 2107 2107 2107 2107 2107 Onn cost ($000) 14459 15483 16460 17360 17789 16227 18675 19128 19697 20659 21646 7408 6473 9583 10415 11384 11994 13679 14976 16332 FUEL cost ($000) 46449 56601 52675 61144 6a5e8 77507 87026 96918 221853 130456 153686 35292 49620 68351 90298 105177 115468 136292 156794 176707 ‘TRANSMISSION CUMULATIVE PRESENT WORTH 6H cost (000) =~ SPINNING RESERVE cost ($000) 3819 4165 4560 5012 5528 6118 6793 7564 e445 9452 10603 eccccccee TOTAL cost ($000) 69592 81938 84746 944g 102922 112955 123683 136888 152046 172710 196855 225688 241262 260922 263701 299549 310450 334958 354759 376027 30 YEARS (2002-2031) CUM, PW AT NO ADDITIONAL GROWTH TOTAL CUMULATIVE PW OP ALTERNATIVE Pw TO JAN 82 ($000) 69592 79552 79681 66434 9144s, 97436 203583 111303 120026 132368 147967 163042 169230 177675 187560 192269 193462 202655 206383 214443 2828306 4203175 7031481 6-2 € AIGVL SECTION 4 BRADLEY LAKE CAPACITY This section reviews the recommended capacity of the Bradley Lake Hydroelectric Project (Project). A detailed review of the Army Corps of Engi- neers' (Corps) recommendation is included in Section 4.1. An updated benefit/ cost analysis for the 90 MW and 135 MW Project alternatives is undertaken in Section 4.2, using the Authority's financial parameters and cost data. 4.1 Review of Corps' Analysis In its General Design Memorandum - Draft Appendix a> » the Corps evaluated three alternative plant factors (60%, 40%, and 27%) as well as six alternative reservoir elevations (1160, 1170, 1180, 1190, 1200, and 1210) for the Project. At El 1170, the three plant factors correspond to installed capacities 60 MW, 90 MW, and 135 MW, respectively. A review of the Corps' benefit/cost analysis indicates that the firm energy, secondary energy, ca- pacity, and employment benefits assigned to the three alternative plant ca- pacities were based on reasonable assumptions concerning the types of thermal generating alternatives that the Project would displace. In order to deter- mine the sensitivity of the Corps' benefit/cost analysis to the value of spin- ning reserve benefits, an economic comparison was undertaken for the El 1170 reservoir as shown in Table 4.1-1. Table 4.1-1 indicates that increasing the Project plant capacity from 60 to 90 MW would be justified solely on the basis of incremental capaci- ty and energy benefits. However, a further increase in capacity from 90 to 135 MW would not be justified on that basis. Thus, the assignment of spinning reserve benefits is necessary to justify a 135 MW plant. Spinning reserve is essentially unused capacity that can quickly accept a load increase. For example, a 50 MW hydroelectric unit generating at 40 MW would provide 10 MW of spinning reserve. Because of the need for rapid 4-2 load acceptance capability, spinning reserve can be provided by hydroelectric or combustion turbine generating facilities. The speed with which spinning reserves must accept load increases is usually set by the operators of the electric power system. In the Pacific Northwest, for example, spinning re- serves must be capable of coming to full load within 5 minutes. In its as- sessment of the Project, the Corps assumed that spinning reserve capacity must be capable of accepting load immediately. The quantity of spinning reserve required in an electric power sup- ply system is a function of the desired system reliability level, and is fre- quently equal to the capacity of a number of the largest units or a percentage of the system's peak capacity. Although the Corps' estimate of the Kenai- Anchorage system's reserve requirement varies from 121 MW in 1985 to 266 MW in 2005, the Corps placed the upper limit on the spinning reserve eapability of the Project at 65 MW, the assumed capacity of the upgraded Kenai-Anchorage transmission intertie. The Corps assumed that the intertie would be upgraded from its existing 40 MW capability by 1995. In its evaluation, the Corps assumed that, without the Project, the spinning reserve requirement would be met by continuously running gas combus- tion turbines at speed-no-load. The cost of speed-no-load operation was esti- mated at 1/3 the cost of running the gas turbines during normal operation. The Project's spinning reserve benefit was assumed equal to the number of "kWh" of speed-no-load gas turbine operation that the Project could displace, subject to the instantaneous 65 MW limitation imposed by the Anchorage-Kenai intertie. Spinning reserve benefits were not credited during periods when the Project was scheduled for maintenance or when it was generating firm peaking energy. Based on the Corps' analysis, until 1995, Bradley Lake could only contribute 40 MW of spinning reserve to the Anchorage area because of trans- mission intertie limitations. The Corps, therefore, estimated the need for spinning reserve on the Kenai Peninsula during that time frame. The Corps assumed that the Kenai Peninsula's spinning reserve requirement would be equal to 70 MW, if the 90 or 135 MW Project alternatives were built. This value is equal to the base load portion of the Project's capability. (General Design Memorandum - Draft Appendix A, p. A-18.)> Another approach would be to estimate the Kenai Peninsula's spinning reserve requirement at 45 MW, the pro- posed capacity of each Bradley Lake generation unit. The 135 MW Project could only supply 45 MW of spinning reserve because, if 70 MW of the Project's ca- pability failed, two of the 45 MW units would be inoperable. Similarly, for the 90 MW alternative, no spinning reserve capability could be provided to the Kenai, however, 20 MW of spinning reserve could be contributed to the Anchor- age area. Using this approach, the need for spinning reserve and the amount that the Project could contribute during this period would have been less. This approach indicates that the actual spinning reserve benefits would be 20 MW for the 90 MW plant, and 45 MW for the 135 MW plant. As previously mentioned, the annual spinning reserve benefit calcu- lated by the Corps was limited by the 65 MW Anchorage-Kenai intertie. Thus, the spinning reserve benefits for all of the 27% plant factor reservoir ele- vation alternatives were equal even though the installed capacity of reservoir alternatives above 1170 would be greater than 135 MW. If the Corps' 65 MW limitation were removed, the optimal capacity of the Project could be greater than 135 MW or, more precisely, greater than that associated with a 27% plant factor. Typically, because the optimal generating level of a unit is below its full capacity, on-line generating units provide some spinning reserve ca- pability, and the residual system requirement for spinning reserves would be defined by the following relation: The residual system spinning reserve requirement equals the system spinning reserve requirement minus the full capacity on-line units plus the instantaneous output on-line units. (In the above relation, on-line units include those which are actu- ally on-line and those which are capable of coming on-line and accepting load within the spinning reserve response time set for the system.) For a system with peaking and reserve capacity supplied by combustion turbines, the Corps' assumption that up to 65 MW of speed-no-load spinning reserve would continu- ously be available for displacement by the Project's spinning reserve capa- bility appears reasonable. However, the Corps' assumption that running com- bustion turbines at speed-no-load would be the only alternative to the Project to meet spinning reserve requirements throughout the period of analysis did not take into account that additional hydroelectric facilities such as the Susitna Project are planned for the Railbelt area. The Corps indicates that it is not customary to base a hydroelec- trie project's benefits on other hydroelectric Projects. While this may be valid for capacity and energy benefits, the evaluation of spinning reserves May merit other considerations. If potential hydro projects are evaluated on the basis of assigning spinning reserve benefits equal to the cost of running combustion turbines at speed-no-load in addition to capacity and energy bene- fits based on thermal generation alternatives, it could result in a system with too much capacity. In fact, for the Project, the incremental increase in capacity to 135 MW could be justified solely on the basis of the spinning re- serve benefits attributed by the Corps. Based on the Railbelt Electric Power Alternatives Study (Battelle, 1982! 0) it is likely that either the Chackachamna or Upper Susitna Hydro- electric Projects will be built to serve the Railbelt area. These large fa- eilities could provide considerable spinning reserve capability because they would not always be operating all units at full capacity. The spinning reserve benefit for Bradley Lake would be considerably reduced once these facilities come on-line in that the need for running combustion turbines at speed-no-load would occur less frequently. It should be emphasized, however, that Bradley Lake's peaking capacity would continue to accrue benefits throughout the period of analysis. In order to test the sensitivity of the Corp's analysis to spinning reserve benefits the kWh of spinning reserve required to justify a 135 MW plant has been calculated. The annual amount of spinning reserve benefit that would justify a Bradley Lake Project capacity of 135 MW can generally be de- termined by dividing the absolute value of the incremental annual benefit be- tween 90 MW and 135 MW (see Table 4.1-1) by the cost/kWh speed-no-load combus- tion turbine operation. This calculation is shown below: kWh/yr spinning reserves = $1,664,000/yr $0256 7ewnel ) = 67.64 x 106 (1) - Based on 1/3 the cost of running combustion turbines for generation = 1/3 x 7.38 cents/kWh. Until 1995, the maximum spinning reserve contribution of the 135 MW Project alternative would be limited to 45 MW, the spinning reserve requirement on the Kenai and is equal to the capacity of one of the Bradley Lake Project units. During this same period, the maximum spinning reserve contribution of the 90 MW Project would be equal to 20 MW, the maximum amount of spinning reserve benefit which the 90 MW alternative can contribute. Thus, only 25 MW of spinning reserve would be attributable to the incremental capacity between the 90 and 135 MW (El 1170) plant capacities. Twenty-five MW of incremental spin- ning reserve and a required benefit of 67.64 x 10° kWh corresponds to the 135 MW Project supplying spinning reserves, 2,706 hours per year, or 31% of the time. After 1995, the maximum contribution of the 135 MW Project would be 65 MW and the incremental contribution would be 45 MW. Forty-five MW of in- cremental spinning reserve and a required benefit of 67.64 x 10° kWh corre- sponds to the 135 MW Project supplying spinning reserves, 1,503 hours per year, or 17.2% of the time. Thus, although the Corps may have used a different basis for esti- mating its assignment of spinning reserve benefits over the entire period of analysis, the amount of annual speed-no-load operation needed to economically justify an incremental increase in the Project's capacity from 90 to 135 MW is 4-6 not large enough to rule out the Corps' conclusion that the 135 MW capacity is the most desirable. 4.2 _Benefit/Cost Analyses - Bradley Lake Project Capacity To confirm the conclusions of the Corps' analysis, a similar bene- fit/cost evaluation of the Project's capacity was undertaken. This evaluation utilized load-resource data developed by RWBI and other data supplied or ap- proved by the Authority. Net benefits (1982 present-worth) for the 90 and 135 MW plant capacities were developed with and without Susitna scenarios and on the basis of coal-fired steam plants and gas combustion turbines as the alternative to the Project's base load capacity and energy. For convenience these comparisons will be identified as follows: Case I - Bradley Lake Project without Susitna - Coal-fired steam as major base load alternative Case II - Bradley Lake Project with Susitna IIA - Coal-fired steam as major base load alternative IIB - Gas combustion turbine as base load alternative Only the 90 and 135 MW plant capacities were evaluated because an updated con- struction cost estimate was not available for the 60 MW alternative, nor were construction cost estimates available for alternative reservoir elevations other than the El 1170 alternative. In addition, capacities above 135 MW were not examined even though it is assumed that the Anchorage-Kenai intertie would not necessarily be limited to 65 MW. (See Section 4.1.) The types of energy and capacity provided by the 90 MW and 135 MW Project alternatives are given in Table 4.2-1. The financial parameters and the assumptions used in the evaluation are shown in Table 4.2-2. 4.2.1 Peak Energy Benefits Peak energy benefits were calculated on the basis of the fuel and variable 0&M costs for combustion turbines, the most likely thermal alterna- tive. Because combustion turbines will be providing both peak and base load energy until 1993 (the assumed on-line date for a coal-fired steam plant or large hydroelectric plant), natural gas supplies will not provide adequate fuel during this period and will have to be supplemented with oil. Thus, dur- ing that period, the Project's peak energy benefits were based on the value of displaced oil. From 1993-2038, the Project's peak energy benefits were based on natural gas. Peak energy benefits were calculated to be $1,552,600/GWh as shown in Table 4.2-3. 4.2.2 Base Load Energy Benefits For Cases I and IIA the Project's base load energy benefits were based on the fuel cost plus variable O&M for a combustion turbine from 1988- 1992 and for a coal-fired steam plant from 1993-2038. It was conservatively assumed that displaced base load combustion turbine generation would be fueled with natural gas. If some base load oil generation was displaced, the base load energy benefits would be larger than the $572,800/GWh shown in Table 42-4, For Case IIB, the Project's base load energy benefits would be equal to the fuel cost plus variable O&M for combustion turbines from 1988- 2038. As shown in Table 4.2-5, these benefits were calculated to equal $1,242, 200/GWh. 4.2.3 Secondary Energy Benefits The Project's secondary energy benefits were assumed to equal 1/2 the value of base load energy because the secondary energy would tend to be produced in off-peak months (General Design Memorandum - Draft Appendix A, Pe A-52)° and would not always be required when generated. Thus, secondary energy benefits for Cases I and IIA equal $286,400/GWh, and secondary energy benefits for Case IIB equal $627,100/GWh. 4.2.4 Capacity Benefits The Project would provide both base load and peaking capacity bene- fits based on the combustion turbine and coal-fired steam plant capacity val- ues shown in Table 4.2-6. These capacity values were based on the capital and fixed 0&M costs provided by the Authority, the transmission costs developed by RWBI, and transmission losses adapted from the Corps' General Design Memo- randum - Draft Appendix A (p. A-36).> The fixed O&M costs were assumed to include all annual fixed costs such as taxes, insurance, fuel inventory and administration. Four percent and eight percent capacity adjustment factors were applied to the combustion turbine and coal plant capacity values, respec- tively. These factors were recommended by FERC to reflect the greater relia- bility of hydroelectric projects and were used by the Corps in its assignment of capacity values to the Project.> The full benefit of the Project's capacity would not be realized until after the 1988 on-line date because the Railbelt will not require its entire capacity at that date. To determine the Project's capacity benefits, it was assumed that the following actions would be taken to provide capacity in the absence of the Project: ° Purchase of new combustion turbines (see load/resource analysis - existing resources, Table 2.2-2) would be on the following schedule: Year New Cap. 1988 0 1989 19 1990 20 1991 74 1992 17 ° In 1993, for Cases I and IIA, combustion turbines used for base load generation would be retired, or transferred to peaking/reserve status. Thus, for Cases I and IIA the Project would accrue base load ca- pacity benefits of $234,286,000 based on the value of displaced combustion turbine capacity from 1989-1992 and based on the value of displaced coal plant capacity from 1993-2038 as shown in Table 4.2-7. For Case IIB, base load ca- pacity benefits were based on the value of displaced combustion turbine ca- pacity from 1988-2038 and equal $81,102,000. (See Table 4.2-7.) The Project's peaking capacity benefits were assumed to accrue from 1991-2038 and were also based on the capacity value of gas combustion tur- bines. As shown in Table 4.2-8, peak energy benefits equal $22,420,000 and $71,916,000 for the 90 MW and 135 MW capacities, respectively. 4.2.5 Spinning Reserve Benefits Spinning reserve benefits were assumed to be equal to 1/3 of the natural gas fuel cost for combustion turbines plus 1/3 of the variable O&M. No additional value from transmission losses were included in the spinning reserve benefit. Although the Corps treated spinning reserve benefits as a capacity benefit, peaking capacity benefits have already been claimed for the 20 MW and 65 MW peak capacities. More accurately in this case, spinning re- serve benefits should be treated as an "energy" benefit based on the amount of time the Project's peaking capacity is available to provide spinning re- serves. Thus, spinning reserve benefits were applied only to that portion of time that the Project's peaking capacity was not being utilized to produce peak or secondary energy, or was off-line for maintenance (5% of the time). The hours available for spinning reserve benefit are shown below: 4-10 Energy Attributable to Peaking Capacity Plant Peaking Peaking GWh/Yr. GWh/Yr.(1) GWh/Yr. Size Cap. Cap. GWh/Yr. Peaking Secondary Available for (MW) (Mw) GWh/Yr. Maintenance Energy Energy Sprining Reserve 90 20 175.2 8.8 9.2 9.1 148.1 135 65 569.4 28.5 10.9 17.4 512.6 (1) Secondary energy attributable to peak capacity approximately equals Secondary Energy Plant - Secondary Energy 60 MW plant (Secondary Energy 60 MW = 21.4 GWh, Secondary Energy 90 MW = 30.5 GWh, Secondary Energy 135 MW = 38.8 GWh). As discussed in Section 4.1, those spinning reserve benefits above and beyond the peaking capacity benefits should only be accrued to the Project during the time that speed-no-load turbine operation would be necessary. Thus, for Cases IIA and IIB - with Susitna, spinning reserve "energy" benefits were assumed to accrue only until 1993. This assumption has been confirmed with the Authority. In reality, some speed-no-load operation may continue to be required beyond 1992; however, estimation of the actual amount of oper- ation is beyond the scope of this study. A continued need for speed-no-load operation may occur if ramping rate restrictions preclude or restrict the use of Susitna for spinning reserve supply. The present-worth of spinning reserve benefits with and without Susitna are shown in Table 4.2-9. 4.2.6 Project Costs Project costs for the 90 MW and 135 MW Project alternatives are shown in Table 4.2-10. These costs were based on Project construction and O&M costs provided by the Authority and on transmission and 0&M costs developed by RWBI. 4.2.7 Benefit/Cost Analysis - Case I The benefit/cost analysis for Case I was based on the assumption that combustion turbines would be the most likely alternative to the Project's peaking capability and that a coal-fired steam plant would be the most likely 4-11 alternative to the Project's base load capability. In addition, spinning re- serve benefits were assumed to accrue throughout the Project's economic life. These assumptions led to the following values for Project benefits. ° Peak Energy Benefits - fuel and variable 0&M costs for combustion turbines. Fuel was oil from 1988 through 1992 and natural gas from 1993 to 2038. Transmission losses of 3.4597 were added to the at-site present-worth to obtain the at-market present-worth of $1,552,600/GWh. (Table 4.2-3.) Base Load Energy Benefits - fuel (natural gas) plus variable O&M costs for combustion turbines from 1988 through 1992 and fuel (coal) plus variable O&M costs for a coal-fired steam plant from 1993 to 2038. Transmission losses of 3.4587 were added to the at-site present-worth to obtain the at-market present-worth of $572,800/GWh. (Table 4.2-4.) Secondary Energy Benefits - One-half base load energy benefits, or $286 , 400/GWh. Peak Capacity Benefits - capital cost plus fixed 0&M for combustion turbines from 1991 to 2038. Transmission losses were adapted from the Corps' General Design Memorandum - Draft Appendix a> to re- flect 3% financing were added to the at-site present-worth to ob- tain the at-market present-worth of $22,420,000 for the 90 MW plant and $71,916,000 for the 135 MW plant, respectively. (See Tables 4,2-6 and 4.2-8.) Base Load Capacity Benefits - capital cost plus fixed 0&M for com- bustion turbines from 1989 through 1992 (see Section 4.2.4) and capital cost plus fixed 0&M for a coal-fired steam plant from 1993 to 2038. Transmission losses adapted from the Corps' General De- sign Memorandum - Draft Appendix a? to reflect 3% financing were 4-12 added to the at-site capacity values to obtain the total present- worth at-market capacity benefit of $234,286,000. (See tables 42-6 and 4.2-7.) ° Spinning Reserve Benefits - cost of running combustion turbines at speed-no-load from 1988 to 2038. The cost of speed-no-load oper- ation was assumed to equal 1/3 of the fuel (natural gas) plus vari- able O&M costs for running a gas combustion turbine for generation, or $404,100/GWh. (Table 4.2-9.) No transmission losses were in- cluded in the spinning reserve benefit. Table 4.2-11 shows the total benefits for the Project under Case I. Energy and capacity benefits were reduced by 3% and 2% respectively, to reflect Project transmission losses. Total adjusted benefits for the 90 MW and 135 MW alternatives are equal to $504,099,000 and $704,765,000, respec- tively. Net benefits are shown in Table 4.2-13 and are equal to $65,234,000 and $218,648,000 for the two alternatives. These values correspond to bene- fit/cost ratios of 1.15 for the 90 MW alternative and 1.45 for the 135 MW alternative. Of the three cases evaluated in Section 4.2, Case I is the most similar to the analysis of Project capacity undertaken by the Corps in its General Design Memorandum - Draft Appendix AL? Differences in Case I and the Corps analysis can in part be attributed to: the different periods of analysis and discount rate; different cost estimates for the Project; and the different assumed on-line date for the coal-fired steam plant. However, Case I does confirm the Corps' conclusion that, in the absence of any other hydroelectric plants capable of supplying spinning reserves, the 135 MW al- ternative is the most economically attractive. 4.2.8 Benefit/Cost Analysis - Case IIA The benefit/cost analysis for Case IIA was based on the assumption that combustion turbines would be the most likely thermal alternative to the 4-13 Project's peaking capability and that a coal-fired steam plant would be the most likely alternative to the Project's base load capability. Thus, the value of the Project's peak energy benefits, base load energy benefits, secon- dary energy benefits, peak capacity benefits, and base load capacity benefits are the same as those developed for Case I. Because the Susitna Project is assumed to come on-line in 1993, the value of spinning reserve benefits is based on the cost of running combustion turbines at speed-no-load from 1988 through 1992, or $38,200/GWh. After 1992, it was assumed that combustion turbines running at speed-no-load would not be required to supply the Railbelt's spinning reserves. However, the Project's peaking capacity would continue to contribute to the need for reserve capacity until 2038. As shown in Table 4.2-12, the total adjusted benefits for the 90 MW and 135 MW alternative capacities are $449,909,000 and $517,204,000, respec- tively. Net benefits are shown in Table 4.2-13 and are equal to $11,134,000 and $31,087,000 for the two capacities. These values correspond to benefit/ cost ratios of 1.03 for the 90 MW alternative and 1.06 for the 135 MW alterna- tive. Thus, the analysis undertaken for Case IIA indicates that the Project would be marginally economic and that the 135 MW plant would be slightly more beneficial than the 90 MW plant. By reducing the spinning reserve benefit, the incremental benefits of the 135 MW plant are substantially reduced from those calculated in Case I. 4.2.9 Benefit/Cost Analysis - Case IIB The benefit/cost analysis for Case IIB assumed that gas combustion turbines would be the most likely thermal alternative to the Project's peaking and base load capability. This Case was evaluated because it most closely corresponded to the load-resource plans evaluated in Sections 3 and 4, and be- cause FERC has recommended that combustion turbines be used as the most likely thermal alternative. The value of Project benefits is discussed below: 4-14 Peak Energy Benefits - fuel and variable 0&M costs for combustion turbines. Fuel was oil from 1988 through 1992 and natural gas from 1993 to 2038. Transmission losses of 3.45%° were added to the at-site present-worth to obtain the at-market present-worth of $1,552,600/GWh. (Table 4.2-3.) Base-Load Energy Benefits - fuel (natural gas) plus variable 0&M costs for combustion turbines from 1988-2038. Transmission losses of 3.45% were added to the at-site present-worth to obtain the at-market present-worth of $1,254,200/GWh. (Table 4.2-5.) Secondary Energy Benefits - one-half the value of base load energy benefits, or $627,100/GWh. Peaking Capacity Benefits - capital cost plus fixed O&M for combus- tion turbines from 1991-2038. Transmission losses adapted from the Corps’ General Design Memorandum - Draft Appendix a to reflect 3% financing were added to the at-site capacity values to obtain the at-market present-worth of $22,420,000 for the 90 MW alterna- tive and $71,916,000 for the 135 MW alternative. (Tables 4.2-6 and 4,2-8.) Base Load Capacity Benefits - capital cost plus fixed 0&M for com- bustion turbines from 1991-2038. Transmission losses adapted from the Corps' General Design Memorandum - Draft Appendix a> to re- flect 3% financing were added to the at-site present-worth of $81,102,000. (Tables 4.2-6 and 4.2-7.) Spinning Reserve Benefits - cost of running combustion turbines at speed-no-load from 1988-1992, or $38,200/GWh. (Table 4.2-9.) No transmission losses were included in the spinning reserve benefits. 4-15 Total Project benefits under Case IIB are shown in Table 4.2-12. Energy and capacity benefits were reduced by 3% and 2%, respectively, to re- flect Project transmission losses. Total adjusted benefits are $512,520,000 and $582,558,000 for the 90 MW and 135 MW alternatives, respectively. The resulting net benefits are $73,745,000 and $96,441,000 as shown in Table 4,.2-13. These values correspond to benefit/cost ratios of 1.17 and 1.20, respectively. Thus, comparing Bradley Lake entirely to combustion turbines increases the net benefits over those calculated for Case IIA. However, the relative benefits remain the same: without spinning reserve benefits over the entire period of analysis, the 135 MW alternative is only slightly more at- tractive than the 90 MW alternative. 4.2.10 Results as follow: The major results of the preceding review of Project capacity are In the absence of the Susitna Project, the most economical plant capacity for the Project is 135 MW. This conclusion is reached when the Project is compared with combustion turbines as the peak- ing alternative and coal-fired steam plants as the major base load alternative. Using data provided by the Authority, the net benefits decrease significantly if the Susitna Project is built. When compared to combustion turbines and coal, the two alternatives are marginally economic. However, if combustion turbines are considered the most likely alternative for peak and base load generation, the net Proj- ect benefits increase. In either case, the 135 MW plant is only marginally more economic than the 90 MW plant if the Susitna Proj- ect is built. This conclusion is based on the assumption that spinning reserve fuel benefits could not be credited to the Project beyond 1992. 4-16 All three benefit/cost economic comparisons indicate that the 135 MW Project is the least costly. Without Susitna, the incre- mental net benefits of the 135 MW plant are significant. With Susitna, the incremental net benefits of the 135 MW plant are mar- ginal but still positive. It is therefore concluded for this analysis that the 135 MW alternative is the preferred capacity for the Project. TABLE 4.1-1 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE ECONOMIC COMPARISON (1) ($1,000) Total Total Annual Plant Capacity Energy Employment Annual Annual Net Capacity Benefit Benefit Benefit Benefit Cost Benefit 60 MW 8,156 12,229 355 20,740 11,655 9,085 90 MW 10,073 12,867 355, 23,295 13,514 9,781 Iner. $2,555 $1,859 $+696 135 MW 11,362 13, 146 355 24 ,863 16,746 8,117 Iner. $1,568 $3,232 $-1,664 (1) General Design Memorandum - Draft Appendix AD (based on 3-1/4% Federal financing). TABLE 4.2-1 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT CAPACITY AND ENERGY(1) Firm Firm Plant Base Load Peaking Base Load Peaking Secondary Capacity Capacity Capacity Energy Energy Energy (MW) (Mw) (MW) (GWh) (GWh) _ ___(GWh) 90 70 20 306.6 9.2 30.5 135 70 65 306.6 10.9 38.8 (1) General Design Memorandum - Draft Appendix A.9 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY PARAMETERS/ASSUMPTIONS USED IN BRADLEY LAKE ECONOMIC ANALYSIS Financial/Economic Parameters Interest ...ceeseeeeeeeeceee tee cece eee eee see e eee sees Finance Periods Bradley Lake .... Combustion Turbines .... Coal-Fired Steam Plant .. Inflation Discount Rate (to 1982 Period of Analysis .. Bradley Lake Parameters Total Investment Costs ($1982) 90 MW .... 135 MW. Transmission ........... Plant O&M ...seseeeeeeeeeee Transmission O&M ...... Project On-Line Date .. Combustion Turbine Parameters Capital Costs ($1982) Turbine .. Transmission . oe Combustion Turbine Heat Rate . sees Natural Gas Price ($1982) .......seeeeeereeeee ec eeceeeens Natural Gas Escalation through 9/1996 .. Natural Gas Escalation 1997-2001 ..... Oil Cost ($1982) ...... Oil Escalation through 2001 Combustion Turbine Fixed O&M . Combustion Turbine Variable O&M . Transmission O&M ......-..+00- eee Coal-Fired Steam Plant Parameters Capital Costs ($1982) Plant ........ Transmission . Coal Heat Rate ... Beluga Coal . Coal Escalation through 2001 Fixed O&M ...eeeec eee eeeeee Variable O&M ....... Transmission O&M ... 3%/Year 50 Years 30 Years 30 Years 30 Years 0%/Year 3%/Year 1988-2038 $360,400,000 $406,485,000 $ 81,494,000 $9,000/MW-Yr. $1,376,000/Yr. Jan. 1988 $266,000/MW $564,523 /MW 12,000 MMBtu/ GWh $0.69/MMBtu 14.3%/Yr. 2.08/Yr. $6.93/MMBtu 2.08/Yr. $2,700/MW-Yr. $4,800/GWh $9,534/MW-Yr. $2,051, 000/™W $564,523/MW 10,000 MMBtu/GWh $1.69/MMBtu 28/Yr. $16,710/MW-Yr. $600/GWh $9,534/MW-Yr. TABLE 4.2-2 Year 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002-2038: Variable O&M: Total At-Site Present Value: (3.45%) Transmission Losses: R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY Oil Cost (1) ($1,000/GWh) 93.7 95.5 97.4 99.4 101.4 NOTES: (1) (2) $6.93/MMBtu x 12,000 MMBtu/GWh $93.7/GWh 1988. $0.69/MMBtu x 12,000 MMBtu/GWh — 1,000 $36.0/GWh 1993. BRADLEY LAKE PROJECT PEAK ENERGY BENEFITS CASES I, IIA & IIB Gas Cost (2) ($1,000/GWh) 36.0 41.2 47.1 53.8 54.9 56.0 57.1 58.2 59. (59.4) (21.8127) (.5537) = 4.8 (25.7298) (.8375) = u Present- Worth Factor -8375 -8131 -7894 - 7664 oTHN1 -7224 «7014 -6810 -6611 -6419 -6232 -6050 -5874 -5703 TABLE 4.2-3 Present-Worth 1982 ($1,000/GWh) 78.4 TT.7 76.9 76.2 75.5 26.0 28.9 32.1 35.6 35.2 34.9 34.5 34.2 33.9 $680.0 T1724 103.4 $1,500.8 51.8 $1,552.6 1,000 = $83.16/GWh 1982 x (1.02)6 = $8.28/GWh 1982 x (1.143)11 = Year 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT BASE LOAD ENERGY BENEFITS CASES I AND IIA ($1,000) Gas Cost (1) Coal Cost(2) Present-Worth Per GWh Per GWh Factor _ 18.5 -8375 21.1 8131 24.1 -7894 27.6 - 7664 31.5 T4411 21.0 7224 21.4 -7014 21.9 -6810 22.3 6611 22.7 6419 23.2 -6232 23.7 - 6050 24.1 5874 24.6 5703 Present-Worth Coal (2002-2038) = $24.6 (21.8127) (.5537) = Present-Worth Coal Var. 0&M (1993-2038) Present-Worth C.T. Var. O&M (1988-1992) Total Present-Worth At-Site: Transmission Losses: (3.45%) Total Present-Worth At-Market: NOTES: Q) (2) $0.69/MMBtu x 12,000 MMBtu/GWh $18.5/GWh 1988. $1.69/MMBtu x 10,000 MMBtu/GWh $21.0/GWh 1993. 1,000 = $8.28/GWh 1982 x (1.143)6 1,000 = $16.9/GWh 1982 x (1.02)11 = $0.6 (24.5187) (.7224) $4.8 (4.5797) (.8375) = TABLE 4.2-4 Present-Worth per GWh 1982 15.5 17.2 19.0 21.1 23.5 15.2 15.0 14.9 14.7 14.6 14.4 14.3 4.2 14.0 $227 .6 297.1 10.6 18.4 $553.7 19.1 $572.8 TABLE 4.2-5 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT BASE LOAD ENERGY BENEFITS CASE IIB ($1,000) Present- Present-Worth Gas Cost (1) Worth per GWh Year Per GWh Factor 1982 1988 18.5 -8375 15.5 1989 21.1 -8131 17.2 1990 24.1 -7894 19.0 1991 27.6 - 7664 21.1 1992 31.5 7441 23.5 1993 36.0 -7224 26.0 1994 41.2 7014 28.9 1995 47.1 -6810 32.1 1996 53.8 6611 35.6 1997 54.9 6419 35.2 1998 56.0 -6232 34.9 1999 57.1 - 6050 34.5 2000 58.2 5874 34.2 2001 59.4 -5703 33.9 $391.6 Present-Worth Gas (2002-2038): $59.4 (21.8127) (.5537) = 717.4 Present-Worth Var. O&M (1988-2038): $4.8 (25.7298) (.8375) = 103.4 Total Present-Worth At-Site: $1,212.4 Transmission Losses: (3.45%) 41.8 Total Present-Worth At-Market: $1,254.2 (1) $0.69/MMBtu x 12,000 MMBtu/GWh 1,000 = $8.28/GWh 1982 x (1.143)6 = $18.5/GWh 1988. TABLE 4.2-6 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY JANUARY 1982 CAPACITY VALUES ($1,000/MW/YR) Combustion Coal-Fired Turbine (Gas) Steam Capital Cost 266.0 2,051.0 Annual Costs Amortization 13.6 104.6 Fixed 0&M 2.7 16.7 Total: At-Site $16.3 $121.3 Transmission Losses (1) 1.6 8.9 Transmission Cost (2) _ 38.3 38.3 Total: At-Market Cost $56.2 $168.5 Capacity Value Adjustment (3) 2.3 13.5 $58.5 $182.0 NOTES: (1) Transmission losses taken from General Design Memorandum - Draft Appendix AD and adjusted to 3% discount rate. (2) Annual transmission costs = (564,923)(.051) + 9,534. (3) Capacity adjustment @ 4% for combustion turbine and 8% for coal-fired steam. TABLE 4.2-7 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT BASE LOAD CAPACITY BENEFITS ($1,000) New Cap. Base Load Annual Required Cap. Claimed Cost Years Present-Worth Year __ __ (MW) (MW) ($1,000) Claimed 1982 CASES I AND IIA 1988 0 0 0 - 0 1989 19 19 1,111.5 4 3,359.4 1990 20 20 1,170.0 3 2,612.5 1991 74 31 1,813.5 2 2,659.5 . 1992 TT 0 0 - 0 1993-2038 70 12,740.0 45 225, 654.8 TOTAL PRESENT-WORTH: $234 286 CASE IIB 1988 0 0 0 - 0 1989 19 19 1,111.5 49 23,034.7 1990 20 20 1,170.0 48 23, 316.6 1991 7 31 1,813.5 47 34,751.0 TOTAL PRESENT-WORTH: $81,102 Year 1991 1991 1992 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT PEAKING CAPACITY BENEFITS ($1,000) Peak Capacity Annual Claimed Cost Years (MW) ($1,000) Claimed 90 MW 20.0 1,170.0 47 135 MW 43.0 2,515.5 47 22.0 1,287.0 46 1982 _ TABLE 4.2-8 Present-Worth $22,420 $48 , 203.0 23,712.5 $71,916 TABLE 4.2-9 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT SPINNING RESERVE BENEFITS (103/GWh) CASE I - WITHOUT SUSITNA Present-Worth Natural Gas (1988-2038) = 1,109.0 Present-Worth Variable 0&M (1988-2038) = 103.4 1,212.4 x 1/3 Present-Worth Spinning Reserve = 404.1/GWh CASES IIA & IIB - WITH SUSITNA Present-Worth Natural Gas (1988-1992) = 96.3 Present-Worth Variable 0&M (1988-1992) 7 18.4 $114.7 x 1/3 Present-Worth Spinning Reserve = $38.2 TABLE 4.2-10 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT COSTS ($1,000) 90 MW __135 MW Total Investment Cost ($1,000) Project 360,400 406 , 485 Transmission 81,494 81,494 Annual Costs ($1,000) Amortization Project (1) 14,020 15,812 Trans, (2) 4,156 4,156 Project 0&M(3) 810 1,215 Trans. O&M 1,376 1,376 TOTAL 20 , 362 22,559 Present-Worth (1982) (4) 438,775 486,117 NOTES: (1) 50 Years Capital Recovery Factor = .0389 (2) 30 Years Capital Recovery Factor = .0510 (3) $9/kW (4) (Annual Cost) (A/P, 50, 3%) (F/P, 6, 3%) = Annual Cost (25.7298) (.8375) R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BRADLEY LAKE PROJECT BENEFITS CASE I WITHOUT SUSITNA, 1982 ($1,000) Adjusted 1982(1) Benefits Units Unit Values 1982 Present-Worth Present-Worth 90 MW Peak Energy 9.2 GWh 1,552.6/GWh $ 14,284 $ 13,856 Base Load Energy 306.6 GWh 572.8/GWh 175,620 170,351 Secondary Energy (2) 30.5 GWh 286.4/Gwh 8,735 8,473 Peak Capacity 20 MW L.S. 22,420 21,972 Base Load Capacity 70 MW L.S. 234,286 229,600 Spinning Reserve 148.1 GWh 404.1/GWh 59,847 59,847 $515,192 $504,099 135 MW Peak Energy 10.9 GWh 1,552.6/GWh $ 16,923 $ 16,415 Base Load Energy 306.6 GWh 576.5/GWh 175,620 170,351 Secondary Energy (2) 38.8 GWh 288.3/GWh 11,112 10,779 Peak Capacity 65 MW L.S. 71,916 70,478 Base Load Capacity 70 MW L.S. 234,286 229,600 Spinning Reserve 512.6 GWh 404.1/GWh 207,142 207,142 $716,999 $704,765 NOTES: (1) Energy benefits reduced by 3% to reflect Bradley Lake transmission losses. Capacity benefits reduced by 2% to reflect Bradley Lake transmission losses. (2) Secondary energy benefits = 1/2 base load energy benefits, Tt-2°b ATqwL R. W. Beck and Associates, Inc. KENAI PENINSULA BRADLEY LAKE PROJECT BENEFITS WITH SUSITNA, 1982 ($1,000) Unit Values POWER SUPPLY AND TRANSMISSION STUDY 1982 Present-Worth Adjusted 1982(1) Present-Worth Benefits Units Case IIA Case IIB Case IIA Case IIB Case IIA Case IIB 90 MW Peak Energy 9.2 GWh 1,552.6/Gwh 1,552.6/GWh $ 14,284 $ 14,284 $ 13,856 $ 13,856 Base Load Energy 306.6 GWh 272.8/GWh 1,254.2/GWh 175,620 384,538 170,351 373,002 Secondary Energy (2) 30.5 GWh 286.4/GWh 627.1/GWh 8,735 19,127 8,473 18,553 Peak Capacity 20 MW L.S. L.S. 22,420 22,420 21,972 21,972 Base Load Capacity 70 MW L.S. L.S. 234,286 81,102 229,600 79,480 Spinning Reserve 148.1 GWh 38.2/GWh 38.2/GWh 5,657 5,657 5,657 5,657 $461,002 $527,128 $449,909 $512,520 135 MW Peak Energy 10.9 GWh 1,552.6/GWh 1,552.6/GWh $ 16,923 $ 16,923 $ 16,415 $ 16,415 Base Load Energy 306.6 GWh 572.8/GWh 1,254.2/GWh 175,620 384,538 170,351 373,002 Secondary Energy (2) 38.8 Gwh 286.4/Gwh 627.1/GWh 11,112 24,332 10,779 23,602 Peak Capacity 65 MW L.S. L.S. 71,916 71,916 70,478 70,478 Base Load Capacity 70 MW L.S. L.S. 234,286 81,102 229,600 79,480 Spinning Reserve 512.6 GWh 38.2/GWh 38.2/GWh 19,581 19,581 19,581 19,581 $529,438 $598,392 $517,204 $582,558 NOTES: (1) Energy benefits reduced by 3% to reflect Bradley Lake transmission losses. Bradley Lake transmission losses. (2) Secondary energy benefits = 1/2 base load energy benefits. Capacity benefits reduced by 2% to reflect @T-2*°b ATAVL Benefit Cost Net Benefit Benefit-Cost Ratio Benefit Cost Net Benefit Benefit-Cost Ratio TABLE 4.2-13 R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY BENEFIT/COST SUMMARY 1982 ($1,000) CASE I - WITHOUT SUSITNA ___90 MW 135 MW 504,099 704,765 438,775 4861117 $65, 324 $218, 648 1.15 1.45 CASE II - WITH SUSITNA ee Tew, . 135_MW Case IIA Case IIB Case IIA Case IIB 449 ,909 512,520 517,204 582,558 438,775 438,775 486,117 486,117 $11,134 $73,745 $31,087 $96,441 1.03 1.17 1.06 1.20 SECTION 5 ALLOCATION OF TRANSMISSION COSTS The transmission facility costs must be allocated to the following five user utilities for the recommended alternative plan: Chugach Electric Association, Homer Electric Association, Matanuska Electric Association, Seward Electric System and Anchorage Municipal Light and Power. 5.1 Transmission Costs The recommended alternative plan as identified in Section 3 are Plans AA and AB, Bradley Lake Project at 135 MW and 90 MW respectively with the Susitna Project. The transmission facilities for Plans AA and AB are the same as defined in Sections 2.3.1 and 2.3.2 and shown on Figure 2-1. The transmission system includes the facilities as shown in Table 5.1-1. The facilities' costs have been determined in January 1982 dollars with no inflation and a 3 percent present-worth discount percentage as shown in Table 5.1-1. The total present-worth cost of the transmission facilities as projected by this study are $620,343,000. 5.2 Allocation of Costs All utilities in the Railbelt area will use the transmission fa- cilities depending on their load demand and energy needs. If we assume the Railbelt area is interconnected and the user utilities will share in the costs, it is appropriate that the utilities share based on their needs. A very simplistic approach is to allocate the transmission facili- ties' costs to the user utilities on the basis of peak capacity requirements 5-2 of the utilities. Based on historical peak load data, the utilities' costs should be allocated as follows: Percentage Costs ($1,000) Chugach Electric Association 55.7 $345,531 Anchorage Municipal Light and Power 19.3 119,726 Homer Electric Association 12.9 80,024 Matanuska Electric Association 10.9 67,618 Seward Electric System 1.2 Ti Ha Total Present-Worth $620 , 343 The allocation of transmission costs can be adjusted if a specific utility uses more or less of a particular facility. In this analysis, the Fairbanks area utilities were not included because the emphasis of the studies is on the Kenai Peninsula. The costs for the transmission facilities which relate to the Fairbanks area are included because information was not availa- ble to separate these costs from the Anchorage and Kenai area costs. The costs should be fairly close because the costs attributable to the Fairbanks area utilities will be fairly low in comparison. Further studies should be performed to determine a more exact utility allocation. The allocations dis- cussed are to give relative costs only. R. W. Beck and Associates, Inc. KENAI PENINSULA POWER SUPPLY AND TRANSMISSION STUDY TRANSMISSION COSTS, PLANS AA AND AB Annual Cumulative Annual 1982 Operation and Present- In-Service Capital Cost Maintenance Worth (1) Date Transmission Facilities ($1,000) Cost ($1,000) ($1,000) 1988 Fritz Creek - Soldotna - 115-kV 22,291 376 26,306 Includes: Fritz Creek to Bradley Junction Bradley Junction to Soldotna Bradley Junction Switching Station 1988 Soldotna-Anchorage - 230-kV 59,203 1,000 69,895 Includes: Overhead and Submarine Switching Stations 1993 Susitna to Fairbanks and Anchorage - 345-kV 523,800 8,846 524,142 (2) Includes: Anchorage to Fairbanks Watana I and II to the intertie Switching Stations Total $620,343 NOTES: (1) Cumulative present-worth of annual operation and maintenance cost and annualized capital costs over the 50-year study period. (2) This cost includes transmission costs to the Fairbanks area. T-T°S ATavL SECTION 6 RECOMMENDED TRANSMISSION STUDIES The scope of this study did not include the design, environmental studies or route selection of the transmission facilities for the recommended alternative plan. This additional work must be completed before the transmis- sion facilities plan can be completed. The recommended plan is for the entire Railbelt area but the transmission facilities of major concern are those on the Kenai Peninsula. 6.1 Transmission System Studies In order to identify the performance and to finalize the design of the electrical transmission lines and substation facilities, as well as to evaluate the need for future transmission additions, system studies should be conducted. These studies would include load flow, stability, short circuit and overvoltage studies for the entire Railbelt area and specifically for the Kenai Peninsula. The load-resource plan should be confirmed for the specific needs of the Kenai Peninsula and future utility expansion plans. The system con- figuration and voltage level would be determined based on these studies in- cluding contingency conditions. The electrical criteria for tower design and conductor selection should be established. 6.2 Route Selection The electrical transmission line routes should be selected based on feasible and acceptable considerations with respect to technical, economic, sociological and environmental factors. A logical selection methodology which includes the concerns of all of the entities involved and impacted should be 6-2 developed. The evaluation process should include field investigations, and public and agency meetings. An environmental impact report should be prepared discussing the transmission facilities. 6.3 Transmission System Design The results of the system studies and the route selection should be utilized to perform the transmission system design. The transmission line insulation and conductor should be designed based on the criteria established in the transmission system studies. Economic conductor studies should be included. The transmission structures and foundations should be designed based on the criteria established in the transmission system studies, the technical field investigations and the environmental studies. Costs estimates and specifications for the material and construc- tion should be prepared based on the design and schedule. 6.4 Scope of Work The following is an outline which defines the scope of work for the route selection, environmental studies and the design for the Plan AA and AB transmission facilities relating to the Kenai Peninsula. I. System Studies A. Establish data base for load flow, stability, short circuit and overvoltage studies. B. Confirm the established load-resource plan specifically for the Kenai Peninsula. Cc. Establish system power configuration and voltage levels. D. Establish electrical design criteria for tower design and conductor configuration selection. E. Prepare cost estimates and construction schedules for se- lected alternatives and perform an economic analysis for sys- tem optimization. I. II. III. IV. 6-3 System Studies (continued) E. F. G. H. I. J. Prepare a final analysis and report indicating system re- quirements and recommended engineering features. Selection Establish data base for alternative corridor identification and evaluation. Identify alternative corridors. Perform field investigations including technical, geotechni- cal, and environmental studies. Perform an alternative corridor evaluation and identify pos- sible routes. Plan and conduct a public participation program. Complete liaison with local, State and Federal agencies hav- ing interest in the project. Prepare an environmental impact analysis. Prepare engineering material for submittal for various public and private grants, permits and clearances. Prepare a feasibility report. Prepare licensing application submittals if necessary. Transmission System Design A. B. Cc. D. E. F. G. H. I. J. K. L. Prepare design basis. Prepare schedule from design to energization. Perform survey of the route. Prepare plan and profile drawings. Prepare detailed design of the transmission facilities in- cluding: ° engineering calculations foundations and structures plans and profiles substations and switching stations ° protective relay Prepare specifications and contract documents for material procurement and construction. Prepare detailed cost estimates. Prepare detailed procurement and construction schedules. Prepare monthly project progress reports. Assist with the evaluations and recommendations for bid award. Review manufacturer and construction drawings to determine compliance with the contracts. Stake transmission line structure location and alignment. ooo Construction Management A. Establish field office(s) with necessary staffing near the construction site(s). Iv. Construction Management (continued) B. Cc. D. E. F. G. H. I. Review materials, equipment and construction to establish that facilities are built in conformance with the contract plans and specifications. Prepare contract change orders and documentation of the need for and cost of any such changes. Prepare and maintain construction records to document receipt of materials, daily construction activity, current project staffing, construction progress, minutes of meetings and field changes. Perform tests and checks throughout the construction period. Perform final checkout of completed facility. Prepare "as constructed" plans and contract documents. Summarize final construction costs. Prepare operating and maintenance plans. 2. APPENDIX A DATA SOURCES Electric Power Consumption for the Railbelt: A Projection of Require- ments, S. Goldsmith and L. Huskey, University of Alaska, Institute of Social and Economic Research, June 1980. Bradley Lake Power Market Report, U.S. Department of Energy, Alaska Power Administration, January 1982. Railbelt Area Peak Demand Mid-Range Forecast (MW) and Railbelt Area Ener- gy Mid-Range Forecast (GWH), prepared by the U.S. Department of Energy, Alaska Power Administration, sent to R. W. Beck and Associates, Inc. on March 23, 1982 from Robert W. Loney, Power System and Marketing Analysis. Backup tables 1-4 to the Bradley Lake Power Market Report provided by Robert W. Loney, Power System and Marketing Analysis Department of the Alaska Power Administration, sent on March 5, 1982, to R. W. Beck and Associates, Inc. Preliminary Draft - Appendix A - Power Studies, Bradley Lake Project General Design Memorandum, Corps of Engineers, March 1982. Record of Telephone Conversation, between Messrs. Smith of R. W. Beck and Associates, Inc. and T. Welman of Chugach Electric Association, April 1982. Anchorage-Fairbanks Transmission Intertie Route Selection Report, pre- pared by Commonwealth Associates, Inc. for the Alaska Power Authority, October 1981. 10. 11. 12. APPENDIX A Page 2 First Draft, Susitna Hydroelectric Project Feasibility Report, Volume 1, Sections 9-16, prepared by Acres for the Alaska Power Authority. Draft Bradley Lake Project General Design Memorandum, Corps of Engineers, October 1981. Railbelt Electric Power Study: Evaluation of Railbelt Electric Energy Plans, prepared by Battelle Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Division of Policy Development and Planning and the Governor's Policy Review Committee, February 1982. Draft Appendix A: Technical Data Sheets for Electric Energy Generation and Conservation Options, J.C. King and M.J. Scott, prepared by Battelle Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Division of Policy Development and Planning and the Governor's Policy Review Committee, March 1982. Anchorage-Fairbanks Transmission Intertie Transmission System Data (Draft), prepared by Commonwealth Associates, Inc. for the Alaska Power Authority, November 1980, Revised June 1981.