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Power-Cost Study 1979-1993 Copper Valley Electric Association Inc, March 1979
VAL 003 a DATE ISSUED TO HIGHSMITH 42-225 PRINTED IN U.S.A. POWER-COST STUDY 1979. > 1993 COPPER VALLEY ELECTRIC ASSOCIATION, INC. Project 118-904 Prepared by ROBERT W. RETHERFORD ASSOCIATES Consulting Engineers Anchorage, Alaska VAL 005 March, 1979 WHEREAS, WHEREAS, WHEREAS, RESOLUTION the Board of Directors of the Copper Valley Electric Association, Inc. authorized Robert W. Retherford Associates to prepare an updated Power Cost Study, and the study is based on the March 1979 Power Requirements Study as prepared by Rural Electrification Administration Field Representatives, and the Board of Directors of Copper Valley Electric Association, Inc. has reviewed the study in general as well as the various alternatives discussed in the study and concludes that the information contained therein reasonably represents the anticipated system buss bar KWH costs for the various alternatives during the period of the study, BE IT THEREFORE RESOLVED, that the Board of Directors of Copper Valley Electric Association, Inc. accepts the Power Cost Study with the understanding that the Administrator of the Rural Electrification Administration give Copper Valley Electric Association, Inc. further reconsideration for favorable financing of the Solomon Gulch Hydroelectric Project based on the anticipated buss bar costs of the current financing as compared to alternate approaches and the concern for a system project. CERTIFICATION I, Alfred M. Lee, Secretary of the Copper Valley Electric Association, Inc., do hereby certify that the foregoing is a true and correct excerpt from the minutes of the March 26, 1979 Board Meeting. OR bud Ro Alfred|M. Lee Secretary POWER COST STUDY RECEIVED APR 6 ALASKA POWER AUTHORITY Table of Contents Page “12 Introduction 1 tl. Conclusion and Recommendations 3 Hd. Background a IV. Glennallen System 9 V. Valdez System 10 Vi. Analysis of Options 12 Vit. Power Cost 7 TABLES hs Power Cost Summary 7 Hi Comparison of Alternate interest Rates 8 tM. Power Cost Study, Plan A 23-25 © IVs Maximum Useable Hydro Output, By Month 26 Ve Load Division, Plan A 27 vi. Fuel Calculations, Plan A 28 Vil. Power Cost Study, Plan B 29-31 Vili. Load Division, Plan B 32 IX. Fuel Calculations, Plan B 33 Xx. Power Cost Study, Plan C, Glennallen 34-35 Xi. Power Cost Study, Plan C, Valdez 36-37 Xi. Load Division, Plan C 38 Xt. Fuel Calculations, Plan C 39 TABLES (cont.) XIV. Power Cost Study, Plan D, Glennallen 40-41 XV. Power Cost Study, Plan D, Valdez 42-43 XVI. Load Division, Plan D 44 XVII. Fuel Calculations, Plan D 45 Power Cost Study Page 1 |. INTRODUCTION This is one more of several continuing updates to a Power Cost Study which was performed in March, 1975, as part of Definite Project Report FPC 2742. The purpose of that report was to assess the feasibility of developing the Solomon Gulch Hydroelectric site at Valdez to serve the electrical power needs of Valdez and Glennallen. The original power cost studies, and updates prior to this one have served their intended purpose. The feasibility of the project was demonstrated, an REA loan for construction was approved May 12, 1978, a license to construct was received from the Federal Energy Regulatory Commission (FERC) June 21, 1978, design work is proceeding on schedule, and some site work has been done. Conditions change and this study is being performed to assist in analyzing timing and financial impact of implementing the presently scheduled projects under these changed conditions. Previous load projections were made prior to or during construction of the Trans-Alaska Pipeline System (TAPS) oil line from Prudhoe Bay to Valdez. There was no historical basis for projecting either TAPS loads or community load growth as a consequence of the presence of the pipeline. Now that the pipeline is completed to first stage level of 1.2 million barrels per day and has been operating for approximately 15 months, we can refine load projections. A newly completed REA Power Requirements Study (March, 1979) indicates that previous load projec- tions for the Valdez area were reassuringly accurate. For the Glennallen area, the TAPS loads are considerably below the previously projected levels, but the community loads are, as in Valdez, near previous projec- tions. The PRS load projections in Glennallen (after allowing for reduced TAPS loads) are only slightly below previous PRS projections. In response to concerns expressed by the City Council and City Manager of Valdez regarding their perception that the transmission line to Glenn- allen is not prudent and should not be built there is included in the Power Cost Study Page 2 following study an analysis of the power costs CVEA would experience without this transmission system. In addition to adjustment in load projections, this revision also uses latest construction cost estimates, interest rates and inflation rates. Power Cost Study Page 3 Il. CONCLUSION AND RECOMMENDATIONS Plan A considers construction of a 12 MW hydroelectric production plant at Solomon Gulch near Valdez, a transmission line to Glennallen, and associated substations. Plan B is the same as Plan A except for inclusion of a 9 MW pressure- reducing turbine (PRT) in the oil pipeline near Valdez. This PRT will use the kinetic energy of the oil as it descends from Thompson Pass into Valdez to generate electrical energy. The force of the moving oil can produce 5.9 MW and 50860 MWH/year at the present flow rate of 1.2 million barrels per day (MBD) of oil; 7.9 MW and 67,800 MWH/year at 1.6 MBD; and 9.8 MW and 77,263 MWH/year at full design flow of 2.0 MBD. Plan C is based upon operating without an intertie, and continuing to generate with diesel in both Glennallen and Valdez. Plan D is an alternate to Plan C. it is based upon continuing to operate without an intertie, but constructing the hydroelectric facilities at Valdez. Plans C and D are included only for comparison purposes, to provide added perspective and reassurance regarding the presently scheduled projects for constructing both the hydroelectric facilities and the transmission line. An examination of the power cost summary, Table |, reveals that Plan C, all diesel, requires the least investment and fixed costs, while Plan B, Hydro/PRT/Transmission requires the largest investment and fixed costs. To offset this, Plan B requires the least production costs while Plan C requires the highest. The bus bar cost of all plans considered is the same for the years 1979 and 1980, as there are no plant additions during that time. In 1981, the first year of hydroelectric production, Plan C, All Diesel, gives the lowest bus bar cost. In the first year of hydro production, the full Power Cost Study Page 4 benefit of the "hydro" energy is not obtained in the other plans. How- ever, in the years after 1981, Plan B produces the lowest average costs and Plan C produces the highest average bus bar cost of all plans con- sidered. Plan D, diesel generation at Glennalien, hydroelectric generation at Valdez, and no transmission intertie, produces the lowest system bus bar cost during the years 1982 - 1986, but after 1986 the costs exceed those of either Plan A or Plan B, and continue to rise producing a substantially higher average cost than Plan B. For instance the Plan D bus bar cost in 1982 is 1.4¢/kWh less than Plan B, is approximately equal in 1987, and in 1993 is 4.4¢/kWh greater. Therefore Plan D is not considered a viable long- term solution to meeting total system power supply requirements. Therefore we conclude that both the hydroelectric and transmission facil- ities should be constructed as presently scheduled. Plan C and D are given no further analysis. Additional analyses of Plans A and B are directed toward effect of interest rates and timing of investments. Table \l lists bus bar energy costs for all plans, and various alternates to Plans A and B. Plan A-1, transmission loan at 5% and hydro loan at 7% will produce a bus bar cost approximately 0.4¢ per kWh less than Plan A during the early years of the study period, declining to approximately 0.2¢/kWh at the end of the period. Plan A-2, transmission loan at 2% and hydro loan at 5% produces a bus bar cost approximately 2¢ per kWh less than Plan A during the first part of the study, declining to 1.1¢/kWh in later years. If the lower interest rates could be obtained, it would be possible to add the new facilities and continue approximately the present bus bar costs. Plan B-1 and B-2 show similar savings to A-1 and A-2 at the lower interest rates. Plan B-3 is identical to Plan B except for 2% interest for the transmission line instead of 5%. B-4 will produce a savings of Power Cost Study Page 5 approximately 1.1¢/kWh in the early years but will be 0.6¢/kWh more costly in later years compared to Plan B. These later increased costs will more than offset the temporary gain. Plan B-4 considers delaying construction of the transmission line until 1985 and escalated construction cost at a conservative 7% per year. If construction of the transmission line is delayed until 1985, the appre- ciated cost of construction, even at 7% per year increase, will increase the bus bar costs approximately 0.6¢ per kWh above that obtained with Plan B, which is based upon a 7% per year increase in the cost of fuel. If the price of fuel and construction continue to escalate at the rate of 11% per year as has been true for the past two years even the temporary early years benefit of delaying construction disappears. Plan B-4 there- fore has only a temporary early benefit that is later lost - it should not be implemented. Plan B assumes installation of the PRT in 1985. In 1985 at the projected fuel cost escalation rate of 7% fuel savings will approximately offset depreciation and interest charges on the PRT. However, if fuel costs escalate at a higher rate, as discussed above or if a more detailed finan- cial analysis indicates that the PRT can be installed earlier without caus- ing a cash flow problem, it should be installed before 1985 so that the pre- 1985 usable energy from the crude oil flow will not be lost forever. In summary Plan B offers the lowest total production cost in each year of the study after the PRT is installed, with the cost advantage over the other plans becoming more pronounced each year. The power cost study demonstrates without doubt that plan B is the most economical choice. CVEA should therefore proceed to construct the Solomon Gulch Hydro- electric facilities, substations, and transmission intertie as presently scheduled. Although investment costs are relatively high for the Solomon Gulch Project and transmission tie line compared to other alternatives, the operating cost advantage plus the lower depreciation rate of the hydro- Power Cost Study Page 6 electric facilities gives Plan B a substantial advantage over other plans. Savings in annual costs for Plan B from 1981 through 1993 are over $13,000,000 compared to Plan A, $39,000,000 compared to Plan C, and $9,000,000 compared to Plan D. (If the PRT were added to Plan D, Plan B would still show savings of about $8,000,000 during the study period.) These savings represent a substantial contribution to the economy of the service area. The cost incurred in the hydroelectric operation is largely paying back the loan for construction of the project; hence, represents a substantial equity in a long-lived project which the Copper Valley Electric Association will own outright in about 35 years. The dividend to the Association at that time will be a substantial quantity of low cost power for the remaining 40 years of the expected life of the project. The transmission line will also provide the opportunity for future ex- changes of energy with other areas of Alaska. For example, the present studies being carried out on the Susitna Hydroelectric Project indicate probable completion by 1992. This study shows that even by using all the hydro and PRT energy available it is certain that the CVEA system will require more by the mid-1990's. The transmission system will provide a vital link to Valdez for such an energy supply. Conversely, if a large electric energy source should be found practical! for the Valdez area, the transmission system will provide a vital link to other market areas (such as Fairbanks) that will make possible a better energy project for the Valdez area. Power Cost Study Page 7 TABLE | POWER COST SUMMARY Total Investment - X$1000 1979 1983 1988 1993 PLAN A 8232.4 42452.5 43452.5 43452.5 PLAN B 8232.4 43452.5 53179.8 53179.8 PLAN C 8232.4 13632.4 18807.4 22217.4 PLAN D 8232.4 23547.3 23547.3 25937.1 Total Firm Capacity PLAN A 5024 23761 23761 23761 PLAN B 5024 23761 23761 23761 PLAN C 5024 14961 20961 22585 PLAN D 5024 20961 19961 23585 Annual Operating Costs - $X1000 PLAN A FIXED 578.3 3685.1 3600.9 3413.2 PRODUCTION 2720.5 127C:8 3008.5 6384.9 TOTAL 3298.8 4958.0 6609.4 9798.1 PLAN B FIXED 578.3 3685.1 4715.2 4546.0 PRODUCTION 2720.5 1272.9 939.9 1487.4 TOTAL 3298.8 4958.0 5655.1 6033.4 PLAN C FIXED 578.3 1006.8 1417.8 1665.0 PRODUCTION 2720.5 4127.7 7419.9 13476.8 TOTAL 3298.8 5134.5 8837.7 15141.8 PLAN D FIXED 878.3 1973.9 1923.4 atti <4 PRODUCTION 2720.5 2233.2 4148.4 8395.4 TOTAL 3298.8 4207.1 6071.8 10512.8 Energy Requirements Annual MWH 45735 54960 73820 99197 Peak KW 9275 11710 15540 20622 Energy Cost $/kWh PLAN A -07213 -09021 - 08953 . 09877 PLAN B .07213 -09021 -07661 . 06082 PLAN C -07213 . 09342 -11972 -15259 PLAN D -07213 .07655 -08225 - 10593 Power Cost Study PLAN PLAN PLAN PLAN PLAN PLAN PLAN PLAN PLAN PLAN A TL 5%, A-1 TL 5%, A-2 TL 2%, B TL 5%, B-1 TL 5%, B-2 TL 2%, B-3 TL 2%, B-4 TL 5%, D Delay Diese Diese TABLE 11 COMPARISON OF ALTERNATE INTEREST RATES COST OF PRODUCTION $/KWH INTEREST Hydro 9%/5% Hydro 7% Hydro 5% Hydro 9%/5%, PRT 7% Hydro 7%, PRT 7% Hydro 5%, PRT 7% Hydro 9%/5%, PRT 7% Hydro 9%/5%, PRT 7% T-line to 1985 1 5% 1 5%, Hydro 7% 1983 -09021 - 08647 - 07003 -09021 - 08647 . 07003 -07934 -07484 - 09342 -07655 1988 - 08953 - 08671 - 07464 -07661 -07324 -06117 - 06869 - 08263 -11972 -08225 Page 8 1993 - 09877 - 09663 - 08807 - 06082 -05581 -04725 - 05532 - 06503 peas - 10593 Power Cost Study Page 9 Il. BACKGROUND The Copper Valley Electric Association is a distribution type R.E.A. borrower which generates all of its power requirements from two diesel plants. These plants serve two distinct areas, Glennallen and Valdez, which are not electrically connected. The Glennallen plant has 7648 kW Capacity and the Valdez plant has 10,113 kW capacity. The plant at Glennallen was constructed during 1959 with one unit added in 1963, two in 1966 and two in 1975-76. The plant at Valdez was constructed during 1966-67 with one unit added in 1972, two units in 1975 and a gas turbine unit added in 1976. The system loads in the Glennallen and Valdez areas experienced a period of rapid growth due to increased population and industrial activity associated with the construction of the Trans-Alaska Pipeline System, but are now approaching lower historical growth rates. This study covers a fifteen year period and compares four possible plans for developing a reliable power supply for the CVEA system. PLAN A Diesel/Hydro With Transmission Tie Utilize the existing internal combustion diesel units and oil fired gas turbine; plus development of the Solomon Gulch Hydro Project; plus a transmission tie circuit between Valdez and Glennallen. PLAN B Diesel/Hydro/Pressure Reducing Turbine With Transmission Tie Same as Plan A except add energy recovery by a pressure reducing turbine (PRT) in the crude oil stream of the Trans-Alaska Oil Pipeline at Block Valve #125 near Valdez. Power Cost Study Page 10 PLAN C PLAN D Diesel Only Under this plan the utility would continue to operate in the two areas without an intertie. Additional generation at both Glennallen and Valdez would be by diesel powered generators. Hydro/Diesel Under this plan the utility would also continue to operate as two separate areas without an intertie, would use diesel powered generators at Glennallen, and would construct the hydroelectric project to reduce diesel generation in Valdez. Power Cost Study IV. GLENNALLEN SYSTEM The Glennallen System serves approximately 890 consumers over about Page 11 250 miles of distribution lines. The present system extends from about 70 miles west of Glennallen along the Glenn Highway to about 39 miles north and 55 miles south of Glennallen along the Richardson Highway. The existing power plant contains the following diesel electric units: - 320 kW, 720 rpm Fairbanks Morse (1959) - 560 kW, 720 rpm Fairbanks Morse (1963) 600 kW, 720 rpm Fairbanks Morse (1966) - 2624 kw, 450 rpm Enterprise (1975-76) nm — DY i Total Installed Capacity Less Largest Unit Total Installed Firm Capacity 640 560 1200 kW kW kW kw 5248 7648 kw kW 2624 5024 kW This plant, based upon the March, 1979 power requirements study, has sufficient firm capacity through 1982. Power Cost Study Page 12 V. VALDEZ SYSTEM The Valdez System came into existence following the March 27, 1964 earthquake which demolished the town. Studies following the quake determined that the townsite be abandoned. A new Valdez was built at a location approximately 5 miles west of the original townsite. The Valdez Light, Power and Telephone Company served the Valdez area prior to the earthquake. The generating and distribution facilities of this company were purchased by the Urban Renewel Agency which, in turn, sold the facilities to Copper Valley Electric Association. The old facilities were obsolete, in poor condition and were used only until new facilities were operable. The Copper Valley Electric Association obtained a Certificate of Conve- nience from the State of Alaska and a franchise from the new City of Valdez to own and operate the electric system serving the new Valdez. The Certificate of Convenience covers the general area and is not confined to the limits of the new townsite. The Valdez system presently serves approximately 1153 consumers over about 21 miles of distribution lines. The system serves the new City of Valdez, the Old Valdez area and consumers from Old Valdez to the airport area and 10 miles east of Old Valdez along the Richardson Highway. The existing power plant contains the following diesel and gas turbine units: 2S - 600 kW, 720 rpm, Fairbanks Morse (1967) 1800 kW 1 - 1928 kW, 400 rpm, Enterprise (1972) 1928 kW 1 - 965 kW, 360 rpm, Enterprise (1975) 965 kw 1 - 2620 kW, 450 rpm, Enterprise (1975) 2620 kW 1 - 2800 kW, gas turbine (1976) 2800 kW Total Installed Capacity 10113 kW Firm Installed Capacity 7313 kW Power Cost Study Page 13 This plant based on the March, 1979 Power Requirements Study, has sufficient firm capacity through 1985. Power Cost Study Page 14 VI. ANALYSIS OF OPTIONS The salient technical points of each of the three alternate plans are narrated below. Detailed statistical comparisons are provided in Section Vit. PLAN A Under this plan, the Solomon Guich Hydro Project and the transmission line intertie will be constructed during 1979 and 1980 and will be avail- able for service in 1981. The first unit is scheduled to be operational in the first quarter of 1981 and the second unit in the second quarter. The hydroelectric supply and transmission system will, even with some delay, be operational before Glennallen load levels exceed present firm capacity. Glennallen has firm diesel capacity through 1982 if loads develop as predicted. At that time the Glennallen load is projected to be 5210 kW. The installed diesel capacity will be 7648 kW, and the firm diesel capacity will be 5024 kw. This plan assumes that the 2800 kW turbine will be moved from Valdez to Glennallen in 1983 to provide firm backup to the transmission intertie. This will provide double-contingency backup for Glennallen in that the largest Glennallen unit and the transmission line would have to be out of service during peak load conditions to cause a power supply shortage at Glennallen. Under these conditions Valdez will have firm power supply through 1990 with one hydro unit and the 2620 kW diesel unit out of service. Power Cost Study Page 15 In 1983 and 1993, with the intertie, conditions can be summarized as follows: 1983 1993 Installed Diesel Capacity 14,961 kW 14,961 kW Gas Turbine 2,800 kW 2,800 kW Solomon Gulch Hydro 12,000 kw 12,000 kw Total 29,761 kW 29,761 kW Less Largest Hydro Unit 6,000 kw 6,000 kW Firm Power 23,761 kW 23,761 kW Less Valdez Predicted Peak 6,500 kw 11,378 kW Firm Available for Glennallen 17,261 kW 12,383 kW Glennallen Predicted Peak 5,210 kw 9,244 kW Total Investment X$1000 43,452.5 43,452.5 Annual Fixed and Production Cost, X$1000 4958.0 9798.1 System Bus Bar Cost $/kWh - 09021 - 09877 It should be noted that during the period covered by this study, the reservoir proposed for construction at Solomon Gulch does not fully regulate waterflow. Water is lost during the summer months and there is insufficient water during the winter months to sustain full power output. The flow could be fully regulated by constructing a higher dam and impounding more water during the summer months. However an engineering/economic analysis indicates that the recommended height of 115 is the optimum economic height. With load growth as projected in the March, 1979 Power Requirements Study, even the maximum summer flow of water will be utilized in 1994. As a consequence, it will still be necessary to produce a limited amount of energy with the existing diesel units even after the hydroelectric and transmission facilities become operational. However, in 1982, the first full year of hydroelectric opera- tion, expenditures for diesel fuel will be reduced by more than 75%. Power Cost Study Page 16 PLAN B This is the same as Plan A except for the installation of a 9,000 kW pressure reducing turbine (PRT) in the Trans-Alaska oil pipeline in 1985, which will recover kinetic energy from the moving oil. Since the availability of this energy is subject to interruptions based upon the operating requirements of the pipeline, the energy supplied becomes secondary energy. It requires 100% backup to insure its delivery. However, if its price is low enough, it can substantially reduce the requirements for more expensive energy. For purposes of this study we have assumed that CVEA will pay to Alyeska an energy charge of one-half cent per KWH in 1979, based upon a proposal CVEA has made to Alyeska. For this Power Cost Study we have escalated that rate at 7% per year beyond 1979. The installation date for the PRT was determined by minimum overall operating costs. During the early years of the study, interest and depreciation for the turbine would exceed the cost of diesel fuel re- quired to augment hydroelectric generation. With load growth and increased cost of fuel, a point is reached where fuel costs are greater than the cost of interest and depreciation for the turbine. That "breakeven" point occurs in 1985. Therefore the study is based upon installing the PRT in that year. However, in view of recent oi! prices and current domestic and international events it seems most probable that oil prices will escalate at much higher rates in the immediate future than the 7% used in this study. If a detailed financial analysis indicates no cash flow problem, the PRT should be installed as soon as practical. It is noteworthy that after the PRT is installed, no additional diesel generation is required during the period covered by this study. The depreciation of the turbine is based upon a 30 year life, even though proven oil reserves are calculated sufficient to keep the pipeline operating only to about 2005. It is reasonable to assume that additional oil will be discovered which will extend the operating life of the pipeline. Had a 20 Power Cost Study year life been assumed, depreciation expense would have been increased only $161,000 per year which is not significant when compared to total annual operating costs of over $5,000,000. In 1983 and 1993, with the intertie and the PRT, conditions are summa- rized as follows: Installed diesel capacity Gas Turbine Solomon Gulch Hydro Total Less Largest Hydro Unit Firm Power* Less Vaidez Predicted Peak Firm Available for Glennallen Glennallen Predicted Peak Total Investment, X$1000 Annual Fixed and Production Cost, X$1000 System Bus Bar Cost, $/kWh *The 9000 kW capacity of the PRT is not included in these calculations since it produces only secondary energy and is not considered a prime power unit. 1983 14,961 kW 2,800 kw 12,000 kw 29,761 kW 6,000 kw 23,761 kW 6,500 kw 17,261 kW 5,210 kW 43,452.5 4958.0 -09021 Page 17 1993 14,961 kW 2,800 kw 12,000 kw 29,761 kW 6,000 kw 23,761 kW 11,378 kw 12,383 kW 9,244 kw §3,179.8 6033.4 -06082 Power Cost Study Page 18 PLAN C This plan assumes that CVEA will continue to operate as two separate areas without an intertie, and that all additional generation requirements will be met by diesel units. It is included only for purposes of compari- son, as CVEA has received approval and funding, and has committed to building the hydroelectric and transmission facilities. The plan assumes that the 2800 kW turbine will be moved from Valdez to Glennallen in 1983, a 5000 kW diesel unit will be installed in Valdez in 1983, another in 1986, and that a 2624 kW diesel unit will be installed in Glennallen in 1990. In 1983 and 1993, conditions with Plan C are summarized as follows: Glennatlen 1983 1993 Installed diesel capacity 7648 kw 10272 kW Gas Turbine 2800 kW 2800 kW Total 10448 kw 13072 kW Less Largest Unit 2800 kW 2800 kW Firm Power 7648 kW 10272 kW Projected Peak 5210 kW 9244 kw Valdez 1983 1993 Installed diesel capacity 12313 kW 17313 kW Less Largest Unit 5000 kW 5000 kW Firm Power 7313 kW 12313 kW Projected Peak 6500 kw 11378 kW Total System Investment, X$1000 13632.4 21217.2 Total Fixed and Projection Cost X$1000 5134.5 15054.4 Bus Bar Cost $/kW - 09342 15289 Power Cost Study Page 19 PLAN D This plan incorporates features of both plans A and C. CVEA would continue to operate the two systems without an intertie, but would build the hydroelectric facilities at Valdez. In 1983 and 1993, conditions with Plan D are summarized as follows: Glennallen 1983 1993 Installed diesel capacity 7648 kW 10272 kW Gas Turbine - 2800 kW 2800 kw Total 10448 kW 13072 kW Less Largest Unit 2800 kW 2800 kW Firm Power 7648 kW 10272 kw Projected Peak 5210 kW 9244 kW Valdez 1983 1993 Installed diesel capacity 7313 kW 7313 kW Solomon Gulch Hydro 12000 kw 12000 _kw Total 19313 kW 19313 kW Less Largest Hydro Unit 6000 kw 6000 kW Firm Power 13313 kW 13313 kW Projected Peak 6500 kw 11378 kW Total System Investment, X$1000 23547 .3 25957.1 Total Fixed and Projection Cost X$1000 4207.1 10425.4 Bus Bar Cost $/kW -07655 - 10593 Plan D is included only to demonstrate the overall effect of not construct- ing the transmission intertie. The potential impact of adding the PRT at Valdez has also been checked, but because of the late date (about 1991) when its energy might be economically added to the system its impact is minimal. This also results in the loss of at least five years of energy output from the PRT that can never be recovered. Power Cost Study : Page 20 Vil. POWER COST Existing Plant Value Taken from the Association's General Ledger as of December 31, 1978. Insurance - Facilities Diesel plant_and the adjacent substations, Valdez $2.04/$1000 invested, Glennallen $2.25/$1000 invested. The rate per one thousand is escala- ted 7% per year for each year of the study and applied to the investment of the respective years of the study. Insurance costs for Valdez in 1978 was $7,500. Insurance costs for Glennallen in 1978 was $6000. Costs at Glennallen are due to increase in the near future as the warran- ties expire on the latest units installed. Hydro, $1.43/$1,000 invested 1979, escalated 7% per year thereafter. Applied on $6,669,380 of the total investment (powerhouse, substations, and enclosed equipment). PRT, $5/$1000 invested, 1976 rate escalated 7% per year thereafter. Labor Six full-time employees at each plant year end 1978, with an average base salary of $37,000 plus. Taxes, insurance, and all fringe benefits total approximately 20% of the base salary, and are included in the total dollar value listed as labor. This cost of labor is for 1978, and is escalated 7% per year for each employee through each year of the study. Plans A and B employ 6 employees at Valdez from 1979 through 1993, 6 employees at Glennallen from 1979 through 1981, and two employ- ees at Glennallen from 1982 through 1993. Power Cost Study Page 21 Fuel? See tables that accompany the respective plans. Fuel cost as of March 1, 1979 was $.443 delivered in Valdez and $.468 delivered in Glennallen. The increase in fuel cost through 1977 and 1978 have averaged 11% per year. Rather than escalate at this rate the March 1, 1979 price was esca- lated 7% and used as the average price for 1979. The price in the remaining years are escalated 7% per year above the 1979 average price. Lube Oil, Grease and Operating Supplies? Calculated as 10% of the fuel costs. Escalation of 7% per year is thereby automatically included. Diesel Maintenance Materials (Repair Materials) Estimated at $6.15/MWH generated in 1979 and escalated at 7% per year through 1993. The 1979 maintenance cost per MWH was calculated by summing the maintenance cost at Glennallen and Valdez, adjusting for 7% inflation, for the years 1976, 77, 78 and dividing by the total number of MWH generated. Hydro Maintenance Materials Estimated at $1.40 per installed kW in 1981, escalated at 7% per year from the 1976 estimate of $1.00/installed kW. The rate is escalated 7% from 1981 through 1993. Transmission Line Maintenance The present design engineers of the transmission line have recommended $200 per mile. This figure was used for 1978, escalated 7% each year from 1978 through 1993. 1It should be understood that for the years where zero diesel generation is listed that a small fraction of one percent of diesel may actually be employed. The costs associated with this nominal amount of diesel generation will be negligible and can therefore be ignored. Power Cost Study Page 22 Pressure Reducing Turbine Maintenance Estimated at $1.00 per installed kW in 1976, escalated 7% per year beyond 1976 through 1993. Interest Existing loans with interest rates of 28 and 5% were separated from the Association's records. The expenses for the respective years for each loan were calculated and summed. All additions to facilities are 35 year loans with 5 year deferred principal payments. The rate of interest is indicated with the respective addition. A summary is available using various interest rates for the additions within the separate plans. PRS - MAR. '79 PCS - MAR. '79 ALASKA 18 COPPER VALLEY POWER COST STUDY TABLE IIL DDS/FJB DIESEL/HYDRO W/TRANSMISSION TIE PLAN A 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1. LOAD DATA A. DEMAND - kW Glennallen 4217 4446 4687-4942 $210 «5517-5843 6188 ©6553 6940 7350 «7783 «8243-8729 9244 Valdez 5058 5385 5734 6105 6500 6874 7270 7689 8132 8600 9095 9619 10173 10759 11378 TOTAL DEMAND - kW 9275 9831 10421 11047 11710 12391 13113 13877 14685 15540 16645 17402 18416 19488 20622 B. ENERGY - MWH Glennallen 20886 21418 21965 22525 23100 24625 26251 27983 29831 31800 33899 36137 38523 41066 43777 Valdez 24849 26482 28165 29956 31860 33673 35590 37616 39757 42020 44412 46940 49611 52435 55420 TOTAL ENERGY - MWH 45735 47900 50130 52481 54960 58298 61841 65599 69588 73820 78311 83077 88134 93501 99197 2. SOURCES A. GLENNALLEN - DIESEL 320 kW Units 1,2 (Exist) 640 640 640 640 640 640 640 640 640 640 640 640 640 640 640 560 kW Unit 3 (Exist) 560 560 S60 560 S60 560 560 560 S60 560 560 560 560 S60 560 600 kW Units 4,5 (Exist) 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 2624 kW Units 6,7 (Exist) 5248 5248 5248 5248 5248 5248 5248 5248 5248 5248 5248 5248 5248 5248 5248 B. GLENNALLEN - GAS TURBINE 2800 kW Unit 8 (Exist) (1) -- -- = = 2800 2800 2800 2800 2800 2800 2800 2800 2800 2800 2800 TOTAL CAPACITY - GLENNALLEN - kW 7648 7648 7648 7648 10448 10448 10448 10448 10448 10448 10448 10448 10448 10448 10448 FIRM CAPACITY - GLENNALLEN - kW 5024 5024 $024 5024 7648 7648 7648 7648 7648 7648 7648 7648 7648 7648 7648 C. VALDEZ - DIESEL 600 kW Units 1,2,3 (Exist) 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1928 kW Unit 4 (Exist) 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 2620 kW Unit 5 (Exist) 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 965 kW Unit 6 (Exist) 965 «965 «(9655S (iS: iéHS «KSC (iH (iS (HS (KS (ESS HSS D. VALDEZ - GAS TURBINE 2800 kW Unit 7 (Exist) (1) 2800 2800 2800 2800 -- = ad = - -- -- -- - - - E. VALDEZ - HYDRO - kW 6000 kW Units 1,2 (Add) - = 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 ¢ 4979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 TOTAL CAPACITY - VALDEZ - kW 10113 10113 22113 22113 19313 19313 19313 19313 19313 19313 19313 19313 19313 19313 19313 FIRM CAPACITY - VALDEZ - kW 7313 7313 16113 16113 13313 13313 13313. 13313 13313 13313 13313 13313 13313. 13313) 13313 F. TOTAL SYSTEM CAPACITY W/TRANS, INTERTIE = kW -- - 29761 29761 29761 29761 29761 29761 29761 29761 29761 29761 29761 29761 29761 Less Largest Unit = == (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) System Firm Capacity - kW -- =~ 23761 23761 23761 23761 23761 23761 23761 23761 23761 23761 23761 23761 23761 (1) Portable Unit would be moved to Glennallen (Becomes Unit 8 in Glennallen.) CVEAO3/h1,2 after the winter 1982-83, to be used as a standby unit in the system. €z e8eq PRS - MAR. '79 PCS - MAR. '79 DDS/FIB 3. INVESTMENTS (X $1000) A. GLENNALLEN - DIESEL Existing Plant (1) B. VALDEZ - DIESEL Existing Plant (1) TOTAL DIESEL C. VALDEZ HYDRO D. GLENNALLEN - SUBSTATIONS Existing New - 1981 - PS#11 TOTAL SUBSTATION - GLENNALLEN E. VALDEZ - SUBSTATIONS Existing New - 1981 - MEALS New @ Hydro - 1981 TOTAL SUBSTATION - VALDEZ TOTAL SUBSTATIONS F. TRANSMISSION ~ TIE 104 miles - 138 kV G. TOTAL INVESTMENTS ALASKA 18 COPPER VALLEY POWER COST STUDY DIESEL/HYDRO W/TRANSHISSION TIE TABLE Il] (cont.) PLAN A 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 4386.4 4386.4 4386.4 4386.4 5112.3 5111.3 5221.3 5221.3 5122.3 5121.3 $112.3 5111.3 5111.3 5111.3 5121.3 3517.1 3517.1 3517.1 3517.1 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 o <> 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 163.7 163.7 163.7. 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 =: =: 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 163.7 163.7 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 165.2 165.2 165.2 165.2 165.2 165.2) 165.2.) 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 - ed 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 = =< 239,3> 299.1 239.3 239.3 239.2 23943 239.3 239.3 239.1 299.3 299.1 239.) 239.1 165.2 165.2 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 328.9 328.9 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 2: ~~ 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 8232.4 8232.46 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 43452.5 (1) $724,900 value of gas turbine transferred from Valdez to Glennallen after winter load of 1982-83. CVEAO3/h3 yz e8eq PRS - Pcs - D.D. STEEBY/F.J. BETTINE MAR. '79 MAR. '79 4. FIXED COSTS (X$1000) A. DEPRECIATION Diesel Generation - 3% Hydro Generation - 2% Substations - 2.88% Transmission - 2.66% INTEREST Existing - 2% Existing - 5% Additions - 1981 - 5% (1) Additions - 1981 - 9% (1) + INSURANCE Diesel Plant & Adj. Subs. Hydro Plant & Adj. Subs. TOTAL FIXED COSTS 5. PRODUCTION COSTS (X$1000) AL B. c. MOOe>Q mmo LABOR FUEL LUBE OIL, GREASE & OPERATIONAL SUPPLIES DIESEL MAINTENANCE . HYDRO MAINTENANCE TRANSMISSION MAINTENANCE TOTAL PRODUCTION COSTS OST OF POWER + FIXED COST (X$1000) + PRODUCTION COSTS (X$1000) + TOTAL COSTS (X$1000) ENERGY GROSS - MWH $/KWH 7. $/kWh - ALTERNATE #1 TL-S% HYDRO-7% Interest 8. $/kWh - ALTERNATE #2 .TL-2% HYDRO-S% Interest (1) Total 1981 investment = $35,220,100. $12,800,000 funded with a 35 year loan at 9% interest and principal payments deferred 5 years. The balance $22,420,100 funded with a 35 year loan at S% interest and principal payments deferred 5 years. CVEAO3/h15 ALASKA 18 COPPER VALLEY POWER COST STUDY DIESEL/HYDRO W/TRANSMISSION TIE TABLE IIT (cont.) PLAN A 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 237.1 237.1 237.1 4237.1 237.2 237.1 237.1 237.1 237.1 237.1 237.1 237.1 237.1 237.1 2aiat ad a 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 9.5 9.5 46.8 46.8 46.8 46.3 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 = hod 501.4 501.4 $01.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 31.8 30.4 29.0 27.4 26.1 24.5 23.0 21.5 19.9 18.2 16.5 14.9 13.4 11.8 10.4 281.7 277.1 272.6 «=. 267.7 = 262.6 = 257.2 251.6 9245.6 9239.5 232.7 225.8 9=218.7 9 =211.0 9203.1 194.5 - - 1121.0 1121.0 1121.0 1121.0 1121.0 1114.7 1098.1 1080.2 1061.6 1041.9 1021.5 999.7 977.1 as om 1152.0 1152.0 1152.0 1152.0 1152.0 1148.9 1140.7 1131.8 1122.0 1111.3 1099.3 1086.6 1072.6 18.2 19.6 20.9 22.3 24.1 25.8 27.5 29.5 31-5 33.7 36.1 38.6 41.2 44.2 47.2 se oo 10.9 11.7 12.5 13.4 14.3 18.3 16.4 17.5 18.7 20.1 21.5 23.0 24.6 578.3 573.7 3693.2 3688-9 3685-1 3680-7 3676.2 3662.3 3632.9 3600.9 3567.5 3532.3 3494.0 3455.2 3413.2 $73.8 614.0 657.1 467.3 500.0 534.9 572.4 612.5 655.4 701.3 750.4 802.9 859.1 919.2 983.6 1695.9 1899.5 1193.3 440.5 571.6 707.8 903.7 1102.3 1381.4 1765.0 2004.6 2404.6 2948.4 3432.4 4183.5 169.6 190.0 119.3 44.1 $7.2 70.8 90.4 110.2 138.1 176.5 200.5 240.5 294.8 343.2 418.4 281.2 315.2 197.7 TEI 97.5 120.7 154.1 187.9 235.3 300.5 341.1 408.7 500.5 582.0 707.9 = - 16.8 18.0 19.3 20.6 22.1 23.6 25.3 27.0 28.9 30.9 33.1 35.4 37.9 = = 23.8 25.5 27.3 29.2 21-2 33.4 35.7 38.2 40.9 43.8 46.8 50.1 53.6 2720.5 3018.7 2208-0 1070.5 1272.9 148450 1773.9 2069.9 2471.2 3008-5 3366.4 3931.4 4682.7 5362.3 6384.9 578.3 573.7 3693.2 3688.9 3685.1 3680.7 3676.2 3662.3 3632.9 3600.9 3567.5 3532.3 3494.0 3455.2 3413.2 2720.5 3018.7 2208.0 1070.5 1272.9 1484.0 1773.9 2069.9 2471.2 3008.5 3366.4 3931.4 4682.7 5362.3 6384.9 3298.8 3592.4 5901.2 4759.4 4958.0 5164.7 5450.1 5732.2 6104.1 6609.4 6933.9 7463.7 8176.7 8817.5 9798.1 45735 47900 50130 52481 54960 58298 61841 65599 69588 73820 78311 83077 88134 93501 99197 «07213 .07500 «11772 .09069 .09021 .08859 08813 .08738 .08772 .08953 .08854 .08984 .09278 .09430 .09877 +07213 .07500 .11361 .08677 .08647 .08506 .08480 .08425 .08560 .08671 .08587 .08731 .09038 .09204 .09663 «07213 .07500 .09559 .06955 .07003 .06957 .07020 .07050 .07271 .07464 .07457 .07675 .08052 .08285 .08807 SZ aseg Month JAN FEB MAR APR MAY JUN JUL AUG SEPT OcT NOV DEC TOTAL MWH (1) Available 3300 2982 3300 3195 3300 6924 6924 7253 7457 3595 3195 3300 54725 Page 26 TABLE IV MAXIMUM USABLE HYDRO OUTPUT MONTH PEAK kW (2) Hydro Plant Load Factor 1.0 0.8 0.6 4435 5544 7392 4438 5547 7396 4435 5544 7392 4438 5547 7396 4435 5544 7392 9617 12000 12000 9306 11633 12000 9749 12000 12000 10357 12000 12000 4832 6040 8053 4438 5547 7396 4435 5544 7392 (1) Based upon water flow. (2) Peak kW available to the utility at various monthly load factors. CVEA03/c1 PRS - MAR. PCS - MAR. "79 aa D.D. STEEBY/F.J. BETTINE Use heat rate of: LOAD DIVISION - PLAN A DIESEL/HYDRO/TRANSHISSION TIE 11,600 Btu/kWh for 600 kW units or less 10,500 Btu/kWh for larger than 600 kW Assume: 138,000 Btu/gal TABLE V 11.897 kWh/gal small unit 13.143 kWh/gal large unit HYDRO/DIESEL MWH DIESEL GLENNALLEN DIESEL VALDEZ DIESEL SYSTEM TIE TOTAL % HYDRO MWH (1) MWH GLENNALLEN 2: LARGE (5) MWH MWH ‘% LARGE MWH MWH YEAR MWH % DIESEL HYDRO DIESEL ‘% VALDEZ MWH SMALL LARGE SMALL MWH %_SMALL LARGE SMALL 1979 45735 0/100 0 45785 45.67/54.33 20886 98/2 20468 418 24849 98/2 24352 497 1980 47900 0/100 ° 47900 44.71/55.29 21418 98/2 20990 428 26482 98/2 25952 530 1981(3) 50130 44/56 18047 28073 48/52 13475 98/2 13206 270 14598 98/2 14306 292 1982 52481 81/19 42510 9971 0/100 o -< -- - 9971 100/0 9971 = 1983 54960 78/22 42869 12091 0/100 0 - : 12091 100/0 12091 = 1984 58298 76/24 44306 13992 0/100 ° -- ° 13992 100/0 13992 es 1985 61841 73/27 45144 16697 0/100 o o ooo = 16697 100/0 16697 = 1986 65599 71/29 46575 19024 99 190 100/0 190 : 18834 100/0 18834 = 1987 69588 68/32 47320 22268 2/98 445 100/0 445 : 21823 100/0 21823 - 1988 73820 64/36 = 47245 26575 3/97 797 100/0 7197 - 25778 100/0 25778 = 1989 78311 64/36 = 50119 28192 4/96 1128 100/0 1128 - 27064 100/0 27064 = 1990 83077 62/38 51508 31569 6/94 1894 100/0 1894 - 29675 100/0 29675 = 1991 88134 59/41 51999 36135 8/92 2891 100/0 2891 . 33244 100/0 33244 es 1992 93501 58/42 54231 39270 10/90 3927 100/0 3927 - 35343 100/0 35343 = 1993 99197 55/45 54558 44639 12/88 5357 100/0 5357 - 39282 99/1 38889 393 (1) Maximum annual output of a hydro is 54,725 MWH (2) Assumes that all large diesel units placed on line prior to small units. (3) First hydro unit on line first quarter 1981, second unit second quarter. CVEAO3/hS Hydro furnishes 44% of total MWH for 1981. LZ o3eg PRS - MAR. '79 PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE FUEL CALCULATIONS - PLAN A DIESEL/HYDRO/TRANSMISSION TIE TABLE VI GLENNALLEN VALDEZ GALLON OF GALLON OF GALLON OF GALLON OF FUEL FUEL TOTAL COST PER COST FUEL FUEL TOTAL COST PER cost YEAR LARGE UNIT SMALL UNIT GALLONS GALLON (1) DOLLARS LARGE UNIT SMALL UNIT GALLONS GALLON (2) DOLLARS 1979 1557352 35111 1592464 0.5010 797824 1852851 G1774 1894625 0.4740 898052 1980 1597020 36006 1633026 0.5361 875416 1974615 44519 2019133 0.5072 1024064 198163) 1004755 22653 1027408 0.5736 589316 1088491 24541 1113032 0.5427 604023 1982 - ad td 0.6137 a 758655 a 758655 0.5807 440528 1983 = a = 0.6567 == 919957 o- 919957 0.6213 571585 1984 - - - 0.7027 ao 1064597 o 1064597 0.6648 707754 1985 me = a 0.7519 - 1270410 - 1270410 0.7113 903701 1986 14456 —_ 14456 0.8045 11630 1433006 ed 1433006 0.7611 1090719 1987 33858 sea 33858 0.8608 29146 1660428 -- 1660428 0.8144 1352286 1988 60641 a 60641 0.9211 55854 1961348 - 1961348 0.8714 1709177 1989 85825 co 85825 0.9855, 84584 2059195 —— 2059195 0.9324 1920055, 1990 144107 - 144107 1.0545 151965 2257856 == 2257856 0.9977 2252662 1991 219965 - 219965 1.1283 248197 2529407 we 2529407 1.0675 2700240 1992 298790 i 298790 1.2073 360739 2689112 —~ 2689112 1.1423 3071683 1993 407593 = 407593 1.2918 526548 2958913 33033 2991946 1.2222 3656958 (1) Price in Glennallen, 1979 @ 50.1¢/gal. esc. at 7%/year through 2003 (2) Price in Valdez, 1979 @ 47.4¢/gal. esc. at 7%/year through 2003 (3) First hydro unit on line first quarter 1981, second unit second quarter. Hydro furnish 22,266 mWh of power in 1981. CVEA03/h6 TOTAL FUEL cOsT 1695876 1899480 1193339 440528 571585 707754 903701 1102349 1381432 1765031 2004639 2404627 2948437 3432422 4183506 8z a3eg PRS = MAR. '79 ALASKA 18 COPPER VALLEY TABLE VI PCS - MAR. '79 POWER COST STUDY aT DDS/FJB DIESEL/HYDRO W/TRANSMISSION TIE AND PRESSURE REDUCING TURBINE PLAN B 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1. LOAD DATA A. DEMAND - kW Glennallen 4217 4446 = 4687 494252105517 5843 «1886553. 6940 «©7350 «7783-8243 «87299244 Valdez 5058 5385 $734 6105S 65006874 = 7270» -7689-= 8132 8600 «9095-9619 -:10173 «10759 11378 TOTAL DEMAND - kW 9275 9831 10421 «11047 «1171012391 «13113-13877 14685 15540 16445 17402-18416 19488 20622 B. ENERGY - MWH Glennallen 20886 21418 += 21965 22525-23100 24625 26251-27983 «29831-31800 33899-36137 3852341066 «43777 Valdez 24849 26482 28165 29956 31860 33673 35590 37616 © 39757 42020 44412 46940 49611 52435 55420 TOTAL ENERGY - MWwH 45735 47900 50130 52481 54960 58298 61841 65599 69588 73820 78311 83077 88134 93501 99197 2. SOURCES A. GLENNALLEN - DIESEL 320 kW Units 1,2 (Exist) 640 640 640 640 64064040 KO 40 KOK KD 640 40H 560 kW Unit 3 (Exist) S60 560 560 560 560 560 S60 560 S60 560 560 560 560 560 560 600 kW Units 4,5 (Exist) 1200 1200»: 1200 «1200S 1200S 1200 1200-1200» 1200S 1200» 1200» 1200» 1200» 1200 -~—1200 2624 kW Units 6,7 (Exist) 5248 5248 = 5248 «= 52485248 = 5248 = 5248 = 5248 «= $248 «= S248 = 5248 «= 5248 = 5248 «= 5248 S248 B. GLENNALLEN - GAS TURBINE 2800 kW Unit 8 (Exist) (1) -- -- -- --_ 2800 © 2800» 2800» 2800» 2800» 2800 «2800-2800» 2800» 2800-2800 TOTAL CAPACITY - GLENNALLEN - kW 7648 7648 7648 7648 10448 10448 10448 10448 10448 10448 10448 10448 10448 10448 10448 FIRM CAPACITY ~ GLENNALLEN - kW 5024 5024 5024 = 5024 © 7648 «= 7648 = 7648 «= 7648 = 7648 «= 7648 «= 7648. 7648 «= 7648 «= 76487648 . VALDEZ - DIESEL 600 kW Units 1,2,3 (Exist) 1800 1800 1800 =—:1800 «1800-1800 =1800»S«:1800 «1800 »=«:1800»=««1800 «1800S 1800-1800 «1800 1928 kW Unit 4 (Exist) 1928 1928 +='1928. 1928.» :1928._ 1928 ©1928» 1928. «S928 = 1928» :1928 += 1928) 1928» 1928-1928 2620 kW Unit 5 (Exist) 2620 2620» -2620 2620-2620» 2620-2620» 2620-2620» 2620-2620 2620-2620» 2620-2620 965 kW Unit 6 (Exist) 965 965 965 965 965 965 965 965 965 965 965 965 965 (9656S D. VALDEZ - GAS TURBINE 2800 kW Unit 7 (Exist) (1) 2800 2800 ©2800 2800 =~ -- -- -- -- -- -- = = - -- E. VALDEZ - HYDRO - kW 6000 KW Units 1,2 (Add) -- =-_ 12000 , 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 ls = PRT (2 i Moyea aoe 2) a os a -- == _== 9000 ©9000 9000 9000 + _9000 9000 9000 9000 _9000 TOTAL CAPACITY = VALDEZ - kw TOIIS. «TOIIS) 22i13 22113. T93V3.«- THSTS «19313 «19313 19313 19313 19313 T9313. 19313, 19313-19313 FIRM CAPACITY - VALDEZ = kW 7313 7313«-:16113.««:16213| «1331313323 13313-13313. - 13313-13323. 13313| 13323-13323. :13313 13313 . TOTAL SYSTEM CAPACITY ‘ Tuieauie® INTERTIE - kW 29761 29761 29761 29761-29761 --29761 29761-29761 29761 29761 pis t Unit -kW 6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000 Seba EEeaicaS ret 23761 23761 23761 23761 + 23761 +©«23761 + 23761 «= «23761 +2376) System Firm Capacity - kW (1) Portable Gas Turbine Unit moved (Becomes Unit 8 in Glennallen.) 23761 to Glennallen after the winter 1982-83, to be used as a standby unit in the system. (2) PRT considered secondary energy only and is not counted when determining capacity. CVEA 03/b16,17 67 e3eg PRS - MAR. '79 PCS - MAR. '79 DDS/FJB 3. INVESTMENTS (X $1000) A. GLENNALLEN - DIESEL Existing Plant (1) B. VALDEZ - DIESEL Existing Plant (1) TOTAL DIESEL C. VALDEZ HYDRO D. VALDEZ Pressure Reducing Turbine E. GLENNALLEN - SUBSTATIONS Existing New - 1981 - PS#11 (2) TOTAL SUBSTATION - GLENNALLEN F. VALDEZ - SUBSTATIONS Existing New - 1981 - MEALS New @ Hydro - 1981 TOTAL SUBSTATION - VALDEZ TOTAL SUBSTATIONS G. TRANSMISSION - TIE 104 miles - 138 kV H. TOTAL INVESTMENTS ALASKA 18 COPPER VALLEY POWER COST STUDY DIESEL/HYDRO W/TRANSMISSION TIE AND PRESSURE REDUCING TURBINE TABLE VII (cont.) PLAN B 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 4386.4 4386.4 4386.4 4386.4 5111.3 S111.3 S1M2.3 S221.3 S212.3 5112.3 S111.3 SILL.3 S111.3 5112.3 5111.3 3517.1 3517.1 3527.1 3517.1 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 7903.5 os - 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 == = - - os = 9727.3 9727.3 9727.3 9727.3 9727.3 9727.3 9727.3 9727.3 9727.3 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 = = 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 435.5 163.7 163.7 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 599.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 - oo 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 620.6 — oS) 239.1 239.1 239.1 239.1 239.1 239.1 239.1 239.1 239.1 239.1 239.1 239.1 239.1 165.2 165.2 1024-9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 1024.9 328.9 328.9 1626.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 1624.1 = bate 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 18849.1 8232.4 8232.4 43452.5 43452.5 43452.5 43452.5 53179.8 53179.8 53179.8 53179.8 53179.8 53179.8 53179.8 53179.8 53179.8 (1) $724,900 value of gas turbine transferred from Valdez to Glennallen after winter load of 1982-83. (2) Cost of substation facilities at Pump Station #12 is not included in this study as they will be reimbursed by Alyeska. CVEA03/h19 og e8ea PRS - MAR. '79 PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE 10 (1) Totsl 1981 investment = $35,220,100. (2) (3) . FIXED COSTS (X$1000) A. DEPRECIATION Diesel Generation - 3% Hydro Generation - 2% PRT Generation - 3.33% Substations - 2.88% Transmission - 2.66% B. INTEREST Existing - 2% Existing - 5% Additions - 1981 - 5% (1) Additions - 1981 - 9% (1) Additions - 1985 - 7% (2) C. INSURANCE Diesel Plant & Adj. Subs. Hydro Plant & Adj. Subs. PRT TOTAL FIXED COSTS + PRODUCTION COSTS (X$1000) LABOR FUEL . PRT GENERATION SERVICE CHARGE . LUBE OIL, GREASE & OPERATIONAL SUPPLIES . DIESEL MAINTENANCE MATERIALS + HYDRO MAINTENANCE MATERIALS . PRT MAINTENANCE MATERIALS TRANSMISSION MAINTENANCE TOTAL PRODUCTION COSTS rOomm com> + COST OF POWER A. FIXED COST (X$1000) B. PRODUCTION COSTS (X$1000) C. TOTAL COSTS (X$1000) D. ENERGY GROSS - MWH E. $/Kwii . $/kWh ALTERNATE 91° TL-5% HYDRO-7% Interest + $/kWh ALTERNATE #2 TL-2% HYDRO-S% Interest » $/kwWh Alternate #3 TL-2% HYDRO 9%/5% -$/kWwh Alternate @4 (3) TL-S% HYDRO 9%/5% Delay TL to 1985 ALASKA 18 COPPER VALLEY POWER COST STUDY DIESEL/HYDRO W/TRANSMISSION TIE AND PRESSURE REDUCING TURBINE TABLE VIL (cont.) PLAN B 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 237.1 237.10 «237.20 237.1 237.10 237.1 237.10 237-1 -237-1 237.1 237-1 237.1 237-1 237.1 237.1 301.5 301.5 301.5 301.5 301.5 301.5 301-5 301.5 301.5 301.5 301.5 301.5 301.5 — cate ee - -- oa 323.9 323.9 323.9 323.9 323.9 323.9 323.9 323.9 323.9 9.5 9.5) 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 46.8 - -- 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 501.4 31.8 30.4 29.0 27.4 26.1 24.5 23.0 21.5 19.9 18.2 16.5 14.9 13.4 11.8 10.4 281.7 277.1 «272.6 267.7 262.6 257.2 251.6 245.6 239.5 232.7 225.8 218.7 211.0 203.1 194.5 - = 1121.0 1121.0 1121.0 1121.0 1121.0 1114.7 1098.1 1080.2 1061.6 1041.9 1021.5 999.7 977.1 1152.0 1152.0 1152.0 1152.0 1152.0 1148.9 1140.7 1131.8 1122.0 1111.3 1099.3 1086.6 1072.6 = _ ae a — —_ 680.9 680.9 680.9 680.9 680.9 678.3 671.2 663.5 655.3 18.2 19.6 20.9 22.3 24.1 25.8 27.5 29.5 31.5 33.7 36.1 38.6 41.2 44.2 47.2 = ~~ 10.9 11.7 12.5 13.4 14.3 15.3 16.4 17.5 18.7 20.1 21.5 23.0 24.6 ot = “ oe i ~o 89.4 95.7 102.4 _109.5 117.2 125.4 134.2 _143.6 153.6 578.3 573.7 3693.2 3688.9 3685.1 3680.7 4770.4 4762.8 4740.1 4715.2 4689.5 4659.9 4624.0 4586.2 4546.0 573.8 614.0 657.1 467.3 500.0 534.9 572.4 612.5 655.4 701.3 750.4 802.9 859.1 919.2 983.6 1695.9 1899.5 1193.3 440.5 571.6 707.7 - ae ae oo oo =a -- ad —— a - = = = oo 83.5 102.7 126.9 153.1 186.1 221.0 271.0 314.2 383.9 169.6 190.0 119.3 44.1 57.2 70.8 -- - a = - -- = - -o 281.2 315.2 197.7 75.1 97.5 120.7 =< = -- - - -- - -- a = = 16.8 18.0 19.3 20.6 22.1 23.6 25.3 27.0 28.9 30.9 33.1 35.4 37.9 se = = = => = 16.5 17.7 18.9 20.3 21.7 23.2 24.8 26.6 28.4 =. — 23.8 25.5 27.3 29.2 31.2 33.4 35.7 38.2 40.9 43.8 46.8 50.1 53.6 2720.5 3018.7 2208.0 1070.5 1272.9 1484.0 725.7 789.9 862.2 939.9 1028.0 1121.8 1234.8 1345.5 1487.4 578.3 573.7 3693.2 3688.9 3685.1 3680.7 4770.4 4762.8 4740.1 4715.2 4689.5 4659.9 4624.0 4586.2 4546.0 2720.5 3018.7 2208.0 1070.5 1272.9 1484.0 _725.7 789.9 862.2 _939.9 1028.0 1121.8 1234.8 1345.5 1487.4 3298.8 3592.4 5901.2 4759.4 4958.0 5164.7 5496.1 5552.7 5602.3 5655.1 5717.5 5781.7 5858.8 5931.7 6033.4 4573S 47900 50130 52481 54960 58298 61841 65599 69588 §=— 73820-78311 83077 88134 93501 99197 -07213. .07500 .11772 .09069 .09021 .08859 .08887 .08465 .08051 .07661 .07301 .06959 .06648 .06344 .06082 .07213 .07500 .11361 .08677 .08647 .08506 .08555 .08117 .07709 .07324 .06911 .06636 .06332 .06036 .05581 -07213 .07500 .09559 .06955 .07003 .06957 .06420 .06742 .06420 .06117 .05841 .05591 .05346 .05117 .04725 .07213 .07500 .10580 .07931 .07934 .07835 .07922 .07557 .07202 .06869 .06563 .06272 .06008 .05750 .05532 +07213 .07500 .09526 .08026 .07484 .07964 .09631 .09122 .08679 .08263 .07879 .07505 .07151 .06807 .06503 1985 PRT investment = $9,727,300, funded with a 35 year 7% loan, principal payments deferred 5 years. 1985 investment $26,091,700. T-line $24,707,300, 20 MVA substation $813,500, 10 MVA substation $570,900. CVEAO3/h20/21 $12,800,000 funded with a 35 year loan at 9% interest and principal payments deferred 5 years. The balance $22,420,100 funded with a 35 year loan at 5% interest and principal payments deferred 5 years. TE aeg PRS - MAR. '79 LOAD DIVISION - PLAN B TABLE VIII PCS - MAR. '79 DIESEL/HYDRO/PRT/TRANSMISSION TIE D.D. STEEBY/F.J. BETTINE Use heat rate of: 11,600 Btu/kWh for 600 kW units and below Assume: 138,000 Btu/gal 10,500 Btu/kwh for larger than 600 kW 11.897 kWh/gal small unit 13.143 kWh/gal large unit HYDRO/PRT/DIESEL MwH_ DIESEL GLENNALLEN DIESEL VALDEZ_DIESEL SYSTEN TIE % HYDRO TOTAL © % PRT MwH (1) MWH (3) MW % GLENNALLEN % LARGE Mwit MWH % LARGE Mw MwH YEAR Mw GDIESEL HYDRO PRT DIESEL % VALDEZ MWH % SMALL LARGE SHALL MWH -%& SMALL LARGE = SHALL 1979 45735 0/0/100 -- -- 45785 45.67/54.33 20886 98/2 20468 418 24849 98/2 24352 497 1980 47900 -0/0/100 -- -- 47900 44.71/55 .29 21418 98/2 20990 428 26482 98/2 25952 530 1981(4) $0130 44/0/56 ~—-18047 -- 28073 48/52 13475 98/2 13206 270 14598 98/2 14306 292 1982 52481 81/0/19 42510 -- 9971 0/100 -- -- -- -- 9971 100/0 9971 --- 1983 54960 78/0/22 42869 -- 12091 0/100 -- -- -- -- 12091 100/0 12091 -- 1984 58298 76/0/24 44306 -- 13992 0/100 -- -- - - 13992 100/0 13992 -- 1985(2) 61841. «= 73/27/0 = 45144 16697 -- -- -- -- -- - -- -- -- -- 1986 65599 71/29/0 46575 19024 -- -- -- -- -- -- -- -- -- -- 1987 69588 68/32/0 47320-22268 -- -- -- -- -- -- - -- -- -- 1988 73820 66/34/0 48721 + —-25099 -- -- -- -- -- -- -- -- -- -- 1989 78311 64/36/0 50119-28192 - -- -- -- -- -- -- -- -- -- 1990 83077 62/38/0 51508 += 31569 -- -- -- -- -- -- -- -- -- -- 1991 88134 59/41/0 51999 36135 -- -- -- -- = -- -- -- -- -- 1992 93501 58/42/0 $4231 39270 -- - -- -- -- -- -- -- -- -- 1993 99197 $5/45/0 $4558 44639 -- -- -- -- -- -- -- -- -- -- (1) Maximum annual output of hydro is 54,725 MWH. (2) PRT goes on line January 1985. ¢ (3) Maximum annual output of PRT is 78,840 MWH less 2% down time equals 77,263 MWH. (4) First hydro unit on line first quarter 1981, second unit second quarter. Hydro furnishes 44% of total MWH for 1981. CVEA03/h7 ze o8eg PRS - MAR. '79 FUEL CALCULATIONS - PLAN B TABLE IX PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE VALDEZ GLENNALLEN DIESEL DIESEL PRT Pe GALLON OF GALLON OF GALLON OF GALLON OF FUEL FUEL TOTAL COST PER cost FUEL FUEL TOTAL “COST PER COST PRT kWh PRT COST YEAR LARGE UNIT SMALL UNIT GALLONS GALLON (1) DOLLARS LARGE UNIT SMALL UNIT GALLONS GALLON (2) DOLLARS cost (3 DOLLARS 1979 1557352 35111 1592464 0.5010 7978246 1852851 41774 1894625 0.4740 898052 “~< 1980 1597020 36006 1633026 0.5361 875416 1974615 44519 2019133 0.5072 1024064 — =F 1981(4) 1004755 22653 1027408 0.5736 $89316 1088491 24541 1113032 0.5427 604023 - = 1982 -- -- - - -- 758655 = 758655 0.5807 440528 pees ae 1983 = = 2) ae aa 919957 = 919957 0.6213 571585 ae ra 1984 oo -e - - - 1064597 - 1064597 0.6648 707754 ad a 1985 - -- = - -- = - = -- - +0050 83485 1986 -- - -- = = -- -- -- -- -- +0054 102730 1987 ae ae eS es 5 == =o ae -- -- 0057 126928 1988 -- -- -- -- -- -- - -- - -- -0061 153104 1989 ee ea aS a5 =a ar == ee -- -- 0066 186067 1990 - -- - - - -- - -- -- -- -0070 220983 1991 -- -- -- -- -- -- -- -- -- -- 0075 271013 1992 eb a a aa Sy ae Es - - - -0080 314160 1993 -- -- -- -- -- -- -- -- -- -- +0086 383895 (1) Price in Glennallen, 1979 @ 50.1¢/gal. esc. at 7%/year through 2003 (2) Price in Valdez, 1979 @ 47.4¢/gal. esc. at 7%/year through 2003 (3) PRT cost/kwWh, 1979 @ 0.S¢/KWH esc. at 7%/year through 2003 (4) First hydro unit on line first quarter 1981, second unit second quarter. Hydro furnishes 44% of total MWH for 1981. CVEAO3/h8 TOTAL Cost 1695876 1899480 1193339 440528 571585 707754 83485, 102730 126928 153104 186067 220983 271013 314160 383895 €€ e8eg PRS - MAR. '79 ALASKA 18 COPPER VALLEY TABLE X PCS - MAR. '79 POWER COST STUDY 3/12/79 DIESEL ONLY D.D. STEEBY/F.J. BETTINE PLAN C_GLENNALLEN 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1. LOAD DATA A. DEMAND - kW 4217 4446 4687) 4942, 5210 S517 5843 6188) «6553. 6940 «7350 «= 7783-8243 8729 9244 B. ENERGY - MWH 20886 21418 21965 22525 23100 24625 26251 27983 29831 31800 33899 36137 38523 41066 43777 2. SOURCE A. EXISTING DIESEL 320 kW Units 1,2 640 640 640 640 640 640 640 640 640 640 640 640 640 640 640 560 kW Unit 3 560 560 560 560 560 560 560 560 560 560 560 560 560 560 560 600 kW Units 4,5 1200 1200 1200-1200 1200-1200 1200 1200 1200 1200 1200 1200 1200 1200 1200 2624 kW Units 6,7 $248 5248 5248 5248 5248 5248 5248 5248 5248 S248 5248 $248 5248 5248 5248 B. EXISTING GAS TURBINE 2800 kW Unit 8 (1) on = o- == 2800 2800 2800 2800 2800 2800 2800 2800 2800 2800 2800 C. ADDITIONAL DIESEL 2624 kW Unit 9 (2) oo o oo om aa = =< a 2 oo o= 2624 _ 2624 2624 _2624 D. TOTAL CAPACITY 7648 7648 7648 7648 10448 10448 10448 10448 10448 10448 10448 13072 13072 13072 13072 : Less Largest Unit (2624) (2624) (2624) (2624) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) FIRM CAPACITY 5024 5024 5024 $024 7648 7648 7648 7648 «= 7648 = 7648 7648 10272 10272 10272 «10272 3. INVESTMENTS ($1000) A. GENERATION Existing Plant (1) 4386.4 4386.4 4386.4 4386.4 5111.3 5111.3 5111.3 $112.3 5112.3 5121.3 S111.3 SI11.3 5112.3 SU11.3 S111.3 Addition - Unit 9 (3) = — oe o a eee < 2 o ee -- 3370.0 3370.0 3370.0 3370.0 TOTAL 5386.4 4386.4 4386.4 4386.4 5111.3 5111.3 5111.3 S111.3 5111.3 5111.3 5111.3 8481.3 8481.3 8481.3 8481.3 B. SUBSTATIONS - EXISTING 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 163.7 _163.7 _163.7 163.7 163.7 _163.7 _163.7 C. TOTAL INVESTMENT 4550.1 4550.1 4550.1 4550.1 5275.0 5275.0 5275.0 5275.0 5275.0 5275.0 5275.0 8645.0 8645.0 8645.0 8645.0 (1) Gas Turbine moved from Valdez to Glennallen after the winter 1982-83, $724,900. (2) Existing Plant has facilities for this unit. (3) Est. 570/kW installed in 1978 escalated 7% per year to 1990. = $3,370,000. CVEA03/h4 ye a3eg PRS - MAR. '79 PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE 4. FIXED COSTS (X$1000) A. DEPRECIATION Diesel Generation - 3% Substations - 2.88% « INTEREST Existing - 2% Existing - 5% Additions - 5% + INSURANCE Diesel Plant & Adj. Subs. TOTAL FIXED COSTS 5. PRODUCTION COSTS (X$1000) A. B. c. D LABOR . FUEL LUBE OIL, GREASE & OPERATIONAL SUPPLIES . DIESEL MAINTENANCE TOTAL PRODUCTION COSTS 6. COST OF POWER poop? FIXED COST (X$1000) PRODUCTION COST (X$1000) TOTAL COSTS (X$1000) ENERGY GROSS - MWH $/KWH 7. cone SYSTEM/COST OF POWER voe> Eg. CVEA03 . FIXED COST (X$1000) + PRODUCTION COSTS (X$1000) TOTAL COSTS (X$1000) ENERGY GROSS MWH $/kWh /b14 ALASKA 18 COPPER VALLEY POWER COST STUDY DIESEL AND GAS TURBINE PLAN C_GLENNALLEN TABLE X_(cont.) 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 131.6 131.6 131.6 131.6 153.3 153.3 153.3 153.3 153.3 153.3 153.3 284.4 254.4 254.4 254.4 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 10.6 10.0 9.4 8.7 8.2 7.4 6.7 6.1 5.4 4.7 3.9 3.2 2.6 2.0 1.6 173.3 170.6 167.8 165.0 194.7 190.8 186.8 182.5 178.1 173.2 168.3 163.2 157.7 152.0 145.8 -- = - -- - -- - -- - - o- 168.5 168.5 168.5 168.5 10.2 11.0 11.7 12.5 15.6 16.7 17.8 19.1 20.4 21.8 23.4 41.0 43.8 46.7 50.2 330.4 327.9 325.2 322.5 376.5 372.9 369.3 365.7 361.9 357.7 353.6 635.0 631.7 628.3 625.2 285.2 305.2 326.6 349.4 373.9 400.0 428.0 458.0 490.1 524.4 S61.1 600.4 642.4 687.3 735.5 797.8 875.4 960.6 1054.1 1156.6 1319.3 1504.9 1716.5 1957.9 2235.6 2552.6 2905.5 3314.2 3780.3 4311.9 79.8 87.5 96.1 105.4 115.7 131.9 150.5 171.7 195.8 223.6 255.3 290.6 331.4 378.0 431.2 128.4 140.9 154.7 _169.6 186.2 212.4 242.3 _276.3 _315.2 _359.5 _410.1 _467.8 _533.6 _608.6 _694.2 1291.2 1409.0 1538.0 1678.5 1832.4 2063.6 2325.7 2622.5 2959.0 3343.1 3779.1 4264.3 4821.6 5454.2 6172.8 330.4 327.9 325.2 322.5 376.5 372.9 369.3 365.7 361.9 357.7 353.6 635.0 631.7 628.3 625.2 1291.2 1409.0 1538.0 1678.5 1832.4 2063.6 2325.7 2622.5 2959.0 3343.1 3779.1 4264.3 4821.6 5454.2 6172.8 1621.6 1736.9 1863.2 2001.0 2208.9 2436.5 2695.0 2988.2 3320.9 3700.8 4132.7 4899.3 5453.3 6082.5 6798.0 20886 «621418 }+=21965 22525 23100 24625 26251 27983 = 29831 31800 33899 36137 38523 41066 = 43777 -07764 .08110 .08483 .08883 .09562 .09894 .10266 .10678 .11132 .11638 .12191 .13558 .14156 .14812 .15529 578.3 573.7 569.1 564.0 1006.8 1002.6 998.4 1405.3 1402.1 1417.8 1410.6 1688.8 1680.9 1670.4 1660.0 2720.5 3018.6 3348.7 3746.7 4127.7 4636.4 5210.7 5858.8 6590.6 7419.9 8357.3 9407.2 10600.8 11950.3 13476.8 3298.8 3592.3 3917.8 4310.7 5134.5 5639.0 6209.1 7264.1 7992.7 8837.7 9767.9 11096.0 12281.7 13620.7 15136.8 45735 47900 50130 52481 = 554960 58298 §= 61841 65599 69588 §=— 7382078311 = 83077 88134 §=—93501 = 99197 +07213 .07500 .07815 .08214 .09342 .09673 .10040 .11073 .11486 11972 «12473 «13356 «13935 14567). 15259 GE e3eg PRS - MAR. '79 ALASKA 18 COPPER VALLEY TABLE XI PCS - MAR. '79 POWER COST STUDY D.D. STEEBY/F.J. BETTINE DIESEL/ONLY PLAN C_ VALDEZ 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1. LOAD DATA fi A. DEMAND - kW 5058 5385 5734 6105 6500 6874 7270 7689 8132 8600 9095 9619 10173 10759 11378 B. ENERGY - MWH 24849 26482 «= 28165 «= 29956 §=— 331860 333673. «35590 9=- 337616 )§9= 39757 = 42020 44412 46940 §=— 49611 = 5.2435 = 55420 2. SOURCES A. EXISTING DIESEL 600 kW Units 1,2,3 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1928 kW Unit 4 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 2620 kW Unit S 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 965 kW Unit 6 965 965 965 965 965 965 965 965 965 965 965 965 965 965 965 B. GAS TURBINE 2800 kW Unit 8 (1) 2800 2800 2800 2800 on asad = ad ay a. - ~~ ara ~ 7 C. ADDITIONAL DIESEL 5000 kW Unit 8 (2) me 2 wan a 5000 5000 5000 5000 5000 5000 5000 5000 5000 $000 5000 5000 kW Unit 9 (3) -- - - “ = sy a 5000 5000 5000 5000 5000 5000 5000 5000 D. TOTAL CAPACITY 10113) 10113-10113 10113-12313 12313 12313 17313 W7313—-17313 17313 17313 17313 17313 17313 Less largest unit (2800) (2800) (2800) (2800) (5000) (5000) (5000) (5000) (5000) (5000) (5000) (5000) (5000) (5000) (5000) FIRM CAPACITY 7313 7313 7313 7313 7313 7313 7313 12313 12313 12313 12313 12313 12313 12313 12313 3. INVESTMENTS ($1000) A. GENERATION Existing (1) 3517.1 3517.2 3517.2 3517.1 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 2792.2 Addition - Unit 8 (2) a ad oe — 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 Addition - Unit 9 (3) = -- 2 hed ~— oo oo 4925.0 4925.0 4925.0 4925.0 4925.0 4925.0 4925.0 4925.0 TOTAL 3517.1 3527.1 3517.1 3517.1 8192.2 8192.2 8192.2 13117.2 13117.2 13117.2 13217.2 13117.2 13117.2 13117.2 13117.2 B. SUBSTATIONS Existing 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 Addition (4) o- 2 =e a= = 2 2 s- se 250.0 _250.0 _250.0 (250.0 _250.0 _250.0 TOTAL « 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 165.2 415.2 415.2 _415.2 _415.2 _415.2 _415.2 D. TOTAL INVESTMENT 3682.3 3682.3 3682.3 3682.3 8357.4 8357.4 8357.4 13282.4 13282.4 13532.4 13532.4 13532.4 13532.4 13532.4 13532.4 (1) Gas Turbines moved to Glennallen after the winter of 1982-83. (2) Est. $800/kW installed in 1983 for the 5000 kW unit. Building 85' x 70’ with stalls for (3) 9000 kW units. Est. cost in 1983 = $235 per square foot. (3) Est. $985/kW installed in 1986 for the 5000 kW unit. (4) Est. $50/KVA, addition of a 5 MVA transformer to the existing substation. CVEA03/h22 gE e8eg PRS - MAR. PCS - MAR. ih) *79) D.D. STEEBY/F.J. BETTINE 4. FIXED COSTS (X$1000) A. DEPRECIATION Diesel Generation - 3% Substations - 2.88% B. INTEREST -% Existing Sk Existing - Addition - 1983 - 5% 1986 - 5% Addition - 1988 - 5% Addition - C. INSURANCE -FACILITIES D. TOTAL FIXED COSTS PRODUCTION COSTS (X$1000) A. LABOR B. FUEL C. LUBE OIL, GREASE & OPERATIONAL SUPPLIES D. MAINTENANCE MATERIALS E. TOTAL PRODUCTION COSTS COST OF POWER A. FIXED COST (X$1000) B. TOTAL PRODUCTION COSTS C. TOTAL COSTS (X$1000) D. ENERGY - GROSS MWH E. $/KWH COMBINED SYSTEM COST OF POWER A. FIXED COST (X$1000) B. PRODUCTION COSTS (X$1000) C. TOTAL COSTS (X$1000) D. ENERGY - GROSS MW E. $/kWwh CVEA03/h30 ALASKA 18 COPPER VALLEY TABLE XI (cont.) POWER COST STUDY DIESEL ONLY PLAN C VALDEZ 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 105.5 105.5 150.5 105.5 245.8 245.8 245.8 393.5 393.5 393.5 393.5 393.5 393.5 393.5 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 12.0 12.0 12.0 12.0 12.0 12.0 21.2 20.4 19.6 18.7 17.9 7.1 16.3 14.5 13.5 12.6 11.7 10.8 9.8 8.8 108.4 106.5 104.8 102.7 67.9 66.4 64.8 61.4 69.5 57.5 55.5 53.3 Sl... 48.7 so -- - o 270.0 270.0 270.0 270.0 268.5 264.5 260.2 255.7 250.9 246.0 = -- cd = = -- - 246.3 246.3 246.3 246.3 244.9 241.2 237.3 o -- = -- - - = -- 12.5 12.5 12.5 12.5 12.5 12.4 8.0 8.6 9.2 9.8 23.9 25.6 7.4 49.7 54.3 58.1 62.1 66.5 71.1 76.1 247.9 245.8 243.9 241.5 630.3 629.7 629.1 1040.2 1060.1 1057.0 1053.8 1049.2 1042.1 1034.8 288.6 308.8 330.5 353.6 378.3 404.8 433.2 494.9 530.6 567.8 607.5 650.1 695.6 744.2 898.1 1024.1 1165.4 1326.3 1509.3 1706.8 1930.3 2468.7 2791.9 3157.4 3570.7 4038.1 4566.7 5164.5 89.9 102.4 116.5 132.6 150.9 170.7 193.0 246.9 279.2 315.7 357.1 403.8 456.7 516.5 152.8 174.3 198.3 225.7 256.8 290.5 328.5 420.1 475.1 537.3 607.6 687.2 777.1 878.8 1429.3 1609.6 1810.7 2068.2 2295.3 2572.8 2885.0 3631.6 4076.8 4578.2 5142.9 5779.2 6496.1 7304.0 247.9 245.8 243.9 241.5 630.3 629.7 629.1 1039.6 1040.2 1060.1 1057.0 1053.8 1049.2 1042.1 1034.8 1429.3 1609.6 1810.7 2068.2 2295.3 2572.8 2885.0 3236.3 3631.6 4076.8 4578.2 5142.9 5779.2 6496.1 7304.0 1677.2 1855.4 2054.6 2309.7 2925.6 3202.5 3514.1 4275.9 4671.8 5136.9 5635.2 6196.7 6828.4 7538.2 8338.8 24849 26482 28165 29956 31860 33673 35590 37616 39757 42020 44412 46940 49611 52435 55420 -06750 .07006 .07295 .07710 .09183 .09511 .09874 .11367 .11751 .12225 .12688 .13201 .13764 .14376 .15047 578.3 573.7 569.1 564.0 1006.8 1002.6 998.4 1405.3 1402.1 1417.8 1410.6 1688.8 1680.9 1670.4 1660.0 2720.5 3018.6 3348.7 3746.7 4127.7 4636.4 5210.7 5858.8 6590.6 7419.9 8357.3 9407.2 10600.8 11950.3 13476.8 3298.8 3592.3 3917.8 4310.7 5134.5 5639.0 6209.1 7264.1 7902.7 8837.7 9767.9 11096.0 12281.7 13620.7 15136.8 45735 47900 50130 52481 54960 58298 61841 65599 69588 73820 78311 83077 88134 93501 99197 +07213 .07500 .07815 .08214 .09342 .09673 .10040 .11073 .11486 .11972 .12473 .13356 .13935 .14567) .15259 L€ e8eg PRS - MAR. '79 LOAD DIVISION - PLAN C TABLE XII PCS - MAR. '79 DIESEL NO INTERTIE D.D. STEEBY/F.J. BETTINE Use heat rate of: 11,600 Btu/kWh for 600 kW units and below Assume: 138,000 Btu/gal 10,500 Btu/kWwh for larger than 600 kW 11.897 kWh/gal small unit 13.143 kWh/gal large unit GLENNALLEN DIESEL VALDEZ DIESEL TOTAL TOTAL YEAR eae i a) TARE mat on A SHALL) LARG AL YEAR wit LARGE SMALL “MH = & SHALL LARGE. = SMALL. 1979 20886 98/2 20468 418 24849 98/2 24352 497 1980 21418 98/2 20990 428 26482 98/2 25952 530 1981 21965 98/2 21526 439 28165 98/2 27602 563 1982 22525 98/2 22075 451 29956 98/2 29357 599 1983 23100 98/2 22638 462 31860 © 98/2 31223 637 1984 24625 98/2 24133 493 33673 98/2 33000 673 1985 26251 98/2 25726 525 35590 98/2 34878 712 1986 27983 98/2 27423 560 37616 98/2 36864 752 1987 29831 98/2 29234 597 39757 98/2 38962 795 1988 31800 97/3 30846 954 42020 98/2 41180 840 1989 33899 96/4 32543 1356 44412 98/2 43524 888 1990 36137 98/2 35414 723 46940 98/2 46001 939 1991 38523 98/2 37753 770 49611 98/2 48619 992 1992 41066 98/2 40245 821 52435 98/2 51386 1049 1993 43777 98/2 42901 876 55420 98/2 54312 1106 (1) Assumes small units run a minimum of 2%/yr. CVEAO3/h12 gE e3eg PRS - MAR. PCS - MAR. "79 o79) D.D. STEEBY/F.J. BETTINE CVEAO3/h11 GLENNALLEN DIESEL FUEL CALCULATIONS - PLAN C VALDEZ DIESEL TABLE XIII GALLON OF GALLON OF GALLON OF GALLON OF FUEL FUEL TOTAL COST PER COST FUEL FUEL TOTAL COST PER cOsT YEAR LARGE UNIT SMALL UNIT GALLONS GALLON (1) DOLLARS LARGE UNIT SMALL UNIT GALLONS GALLON (2) DOLLARS 1979 1557352 35111 1592464 0.5010 797824 1855834 41841 1897674 0.4740 899498 1980 = 1597020 36006 1633026 0.5361 875416 1974615 44519 2019133 0.5072 1024064 1981 1637807 36925 1674432 0.5736 960618 2100107 47348 2147455 0.5427 1165386 1982 1679563 37867 1717430 0.6137 1054067 2233651 50359 2284010 0.5807 1326257 1983 1722438 38833 1761271 0.6567 1156642 2375622 53560 2429182 0.6213 1509293 1984 = 1836149 41397 1877546 0.7027 1319311 2510807 56608 2567415 0.6648 1706842 1985 1957390 44130 2001521 0.7519 1504875 2653747 59830 2713577 0.7113 1930293 1986 2086536 47042 2133578 0.8045 1716456 2804815 63236 2868051 0.7611 2182989 1987 2224331 50149 2274480 0.8608 1957898 2964457 66835 3031292 0.8146 2468746 1988 = 2346953 80188 2427141 0.9211' 2235562 3133196 70640 3203836 0.8714 2791918 1989 2476074 113975 2590049 0.9855 2552604 3311554 74661 3386215 0.9324 3157408 1990 2694534 60750 2755284 1.0545 2905532 3500053 78911 3578964 0.9977 3570732 1991 2872445 64761 2937206 1.1283 3314190 3699215 83401 3782616 1.0675 4038089 1992 3062062 69036 3131098 1.2073 3780276 3909785 88148 3997933 1.1423 4566705 1993 3264206 73593 3337799 1.2918 4311921 4132359 93166 4225526 1.2222 5164544 (1) Price in Glennallen, 1979 @ 50.1¢/gal. esc. at 7%/year through 2003 (2) Price in Valdez, 1979 @ 47.4¢/gal. esc. at 7%/year through 2003 6€ 33eg PRS - MAR. '79 PCS - MAR. ‘79 3/12/79 D.D. STEEBY/F.J. BETTINE 1. LOAD DATA A. DEMAND - kW B. ENERGY - MWH 2. SOURCE A. EXISTING DIESEL 320 kW Units 1,2 560 kW Unit 3 600 kW Units 4,5 2624 kW Units 6,7 B. EXISTING GAS TURBINE 2800 kW Unit 8 (1) C. ADDITIONAL DIESEL 2624 kW Unit 9 (2) D. TOTAL CAPACITY Less Largest Unit FIRM CAPACITY 3. INVESTMENTS ($1000) A. GENERATION Existing Plant (1) Addition - Unit 9 (3) TOTAL B. SUBSTATIONS - EXISTING C. TOTAL INVESTMENT ALASKA 18 COPPER VALLEY TABLE _X1V POWER COST STUDY DIESEL ONLY PLAN D_GLENNALLEN 1979 1980 +=:1981 «= «1982 «1983S «1984 = 1985 «1986 ~= «1987 19881989 «199019911992 1993 4217 4446. 4687 = 4942s“ 5210» S517“ 5843 G6 18B = 6553. 69407350 = 7783 = 8243 8729 92K4 20886 21418 «21965 22525-23100 24625 «26251-27983 «29831 = 31800 33899 «36137 38523 41066 «43777 640 640 640 640 640 640 640 640 640 640 640 640 640 640 640 560 560 560 560 560 560 560 560 560 560 560 560 560 560 560 1200 1200 =1200 «©1200» 1200» 1200S «1200 «Ss 1200 «Ss 1200S 1200.2 1200S 1200S 1200» 1200-1200 5248 5248 5248 5248 5248 5248 5248 $248 5248 5248 5248 5248 5248 $248 5248 -- -- -- -: 2800 2800 2800 2800 2800 2800 2800 2800 2800 2800 2800 -- -- -- -- -- -- =: = -- -- -- 2624 2624 2624 + _ 2624 7648 7648 7648 7648 10448 10448 10448 10448 10448 10448 10448 13072 13072 13072 13072 (2624) (2624) (2624) (2624) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) (2800) $024 50246 5024 5024 7648 7648 7648 7648 7648 7648 7648 10272 10272 10272 10272: 4386.4 4386.4 4386.4 4386.4 5111.3 5111.3 5111.3 5111.3 S112.3 S112.3 $212.3 $111.3 5112.3 5112.3 5111.3 -- -- -- -- --_ - -- -- -- -- =-__ 3370.0 3370.0 3370.0 3370.0 7386.4 386.4 4386.4 0386.4 Sti1.3 5111.3 Sili.3 Stii.3 Siti.3 ST11.3 ST11.3 8481.3 8481.3 8481.3 8481.3 163.7 163.7 163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 _163.7 4550.1 4550.1 4550.1 4550.1 5275.0 5275.0 5275.0 $275.0 $275.0 5275.0 5275.0 8645.0 8645.0 8645.0 8645.0 (1) Gas Turbine moved from Valdez to Glennallen after the winter 1982-83, $724,900. (2) Existing Plant has facilities for this unit. (3) Est. Price for 1978 $1,000,000 ESC. 7% per year to 1990. CVEA03/h31 Ov a8eg PRS - MAR. '79 PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE 4. FIXED COSTS (X$1000) A. DEPRECIATION Diesel Generation - 3% Substations - 2.88% B. INTEREST Existing - 2% Existing - 5% Additions - 5% C. INSURANCE Diesel Plant & Adj. Subs. TOTAL FIXED COSTS 5. PRODUCTION COSTS (X$1000) A. LABOR B. FUEL C. LUBE OIL, GREASE & OPERATIONAL SUPPLIES D. DIESEL MAINTENANCE TOTAL PRODUCTION COSTS 6. COST OF POWER A. FIXED COST (X$1000) B. PRODUCTION COST (X$1000) C. TOTAL COSTS (X$1000) D. ENERGY GROSS - MWH E. $/KWH 7. COMBINED SYSTEM/COST OF POWER A. FIXED COST (X$1000) B. PRODUCTION COSTS (X$1000) C. TOTAL COSTS (X$1000) D. ENERGY GROSS MWH EB. $/kwh CVEAO3/h32 ALASKA 18 COPPER VALLEY POWER COST STUDY DIESEL AND GAS TURBINE PLAN D_GLENNALLEN TABLE XIV (cont.) 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 131.6 131.6 131.6 131.6 153.3. 153.3 153.3 153.3 153.3. 153.3. 153.3 254.4 254.4 254.4 254.4 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 10.0 9.4 8.7 8.2 7.4 6.7 6.1 5.4 4.7 3.9 Sez 2.6 2.0 1.6 170.6 167.8 165.0 194.7 190.8 186.8 182.5 178.1 173.2 168.3 163.2 157.7 152.0 145.8 -- -- -- -- -- -- -- -- -- -- 168.5 168.5 168.5 168.5 1032)) L910 | :13=7) | | 1012-5) | | 1526) | 6278) 41728) |) 21951) | 2056) | 12158) | 52828. | 114120) | A328) | | 46271) |) 15052 330.6 327.9 325.2 322.5 376.5 372.9 369.3 365.7 361.9 357.7 353.6 635.0 631.7 628.3 625.2 285.2 305.2 326.6 349.4 373.9 400.0 428.0 458.0 490.1 524.4 561.1 600.4 642.4 687.3 735.5 797.8 875.4 960.6 1054.1 1156.6 1319.3 1504.9 1716.5 1957.9 2235.6 2552.6 2905.5 3314.2 3780.3 4311.9 96.1 115.7 131.9 150.5 171.7 195.8 223.6 255.3 290.6 331.4 378.0 431.2 154.7 186.2 212.46 242.3 276.3 _315.2 _359.5 410.1 467.8 533.6 608.6 694.2 1538.0 1832.4 2063.6 2325.7 2622.5 2959.0 3343.1 3779.1 4264.3 4821.6 5454.2 6172.8 330.4 327.9 325.2 322.5 376.5 372.9 369.3 365.7 361.9 357.7 353.6 635.0 631.7 628.3 625.2 1291.2 1409.0 1538.0 1678.5 1832.4 2063.6 2325.7 2622.5 2959.0 3343.1 3779.1 4264.3 4821.6 5454.2 6172.8 1621.6 1736.9 1863.2 2001.0 2208.9 2436.5 2695.0 2988.2 3320.9 3700.8 4132.7 4899.3 5453.3 6082.5 6798.0 20886 21418 +21965 22525 2310024625 «26251 += 27983 «29831 31800 © 33899-36137 38523. 41066 = 43777 +07764 .08110 .08483 .08883 .09562 .09894 .10266 .10678 .11132 .11638 .12191 .13558 .14156 .14812 .15529 ‘ 578.3 573.7 1960.3 1956.0 1973.9 1969.5 1965.0 1956.5 1940.6 1923.4 1905.4 2172.3 2153.4 2133.4 2112.4 2720.5 3018.6 2609.1 2053.1 2233.2 2492.4 2830.0 3220.4 3668.0 4148.4 4776.1 5536.6 6375.2 7285.4 8395.4 3298.8 3592.3 4569.4 4009.1 4207.1 4461.9 4795.0 5176.9 5608.6 6071.8 6681.5 7708.9 8528.6 9418.8 1050).8 45735 47900 50130 52481 54960 58298 61841 65599 69588 73820 78311 83077 88134 93501 99197 07213 07500 .09115 .07639 .07655 .07654 .07754 .07892 .08060 .08225 .08532 .09279 .09677 .10073 .10593 Ty o8eq PRS - MAR. '79 PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE 3. (1) Gas Turbines moved from Valdez to Glennallen after + LOAD DATA A. DEMAND - kW B. ENERGY - MWH . SOURCES A. EXISTING DIESEL 600 kW Units 1,2,3 1928 kW Unit 4 2620 kW Unit 5 965 kW Unit 6 « HYDRO - (Add. 1981) 6000 kW Units 1,2 + EXISTING GAS TURBINE (1) + TOTAL CAPACITY - VALDEZ - kW Less largest unit FIRM CAPACITY - VALDEZ - kW INVESTMENTS ($1000) A. GENERATION Existing Diesel (1) Addition - Hydro TOTAL » SUBSTATIONS Existing @ diesel site Addition @ hydro site TOTAL TOTAL INVESTMENT CVEA03/h13 winter of 1981-82. ALASKA 18 COPPER VALLEY TABLE XV POWER COST STUDY DIESEL/HYDRO PLAN D VALDEZ 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 5058 5385 5734 6105 6500 6874 7270 7689 8132 8600 9095 9619 10173 10759 11378 24849 26482 «28165 = 29956 §=— 331860) 33673-35590 )9=- 337616 )3=— 39757 §=— 42020 44412 46940 = 49611 = 552435 55420 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 1800 ~ 1800 1800 1800 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 1928 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 2620 965 965 965 965 965 965 965 965 965 965 965 965 965 965 965 = Coa 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 12000 2800 2800 2800 2800 -- ad -- 7 — - = = -- -- a 10113 10113, 22113-22113 19313 19313, 19313 19313 19313 19313 19313 19313 19313 19313 19313 (2800) (2800) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) (6000) 7313 713 16113 16113 13313 13313-13313 13313 13313 13313-13313 13313 13313 13313 13313 3517.1 3517.1 3517.1 3517.1 2792.2" 2792.2 2792. 2792.2 2792. 2792.2 2792.2 2792. 2792.2 2792.2 2792.2 == = 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 15075.8 3517.1 3517.1 18592.9 18592.9 17868.0 17868.0 17868.0 17868.0 17868.0 17868.0 17869.0 17868.0 17868.0 17868.0 17868.0 165.2 165.2 165.2 165.2 165.2 165.2 165. 165.2 165. 165.2 165.2 165. 165.2 165.2 165.2 een a 239217929921) (23921 7 (239.1 |) 2385 239.1 239. 239.1 239.1 239. 239.1 239.1 239.1 165.2 165.2 404.3 404.3 404.3 404.3 404. 404.3 404, 404.3 404.3 404. 404.3 404.3 404.3 _ 3682.3 3682.3 18997.2 18997.2 18272.3 18272.3 18272. 18272.3 18272.3 18272.3 18272.3 18272.3 18272.3 18272.3 18272.3 Zy ase PRS - MAR. '79 PCS - MAR. ‘79 D.D. STEEBY/F.J. BETTINE 4, FIXED COSTS (X$1000) A. DEPRECIATION Diesel Generation - 3% Hydro Generation - 2% Substations - 2.88% B. INTEREST Existing - 2% Existing - 5% Additions - 1981 - 7% C. INSURANCE Diesel Plant & Adj. Subs. Hydro Plant & Adj. Subs. TOTAL FIXED COSTS 5. PRODUCTION COSTS (X$1000) A. LABOR B. FUEL C. LUBE OIL, GREASE & OPERATIONAL SUPPLIES D. DIESEL MAINTENANCE MATERIAL £. HYDRO MAINTENANCE TOTAL PRODUCTION COSTS 6. COST OF POWER A. FIXED COST (X$1000) B. PRODUCTION COSTS (X$1000) C. TOTAL COSTS (X$1000) D. ENERGY GROSS - MWH E. $/Kwit 7, COMBINED SYSTEM/COST OF POWER + A. FIXED COST (X$1000) B. PRODUCTION COSTS (X$1000) C. TOTAL COSTS (X$1000) D. ENERGY GROSS MWH E. $/kwh CVEA03/h18 ALASKA 18 COPPER VALLEY POWER COST STUDY TABLE XV (cont. DIESEL/HYDRO PLAN D VALDEZ 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 105.5 -- 7 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 301.5 4.8 4.8 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 21.2 20.4 19.6 18.7 17.9 7.1 16.3 15.4 14.5 13.5 12.6 11.7 10.8 9.8 8.8 108.4 106.5 104.8 102.7 67.9 66.4 64.8 63.1 61.4 59.5 57.5 55.5 $3.3 51.1 48.7 - - 1072.0 1072.0 1072.0 1072.0 1072.0 1068.0 1056.7 1044.7 1031.7 1017.8 1003.0 987.0 969.9 8.0 8.6 9.2 9.8 8.5 9.1 9.7 10.4 let 11.9 12.7 13.6 14.5 15.6 6 = -- 10.9 11.7 12.5 13.4 14.3 15.3 16.4 17.5 18.7 20.1 21.5 _ 23.0 __ 6 247.9 245.8 1635.1 1633.5 1597.4 1596.6 1595.7 1590.8 1578.7 1565.7 1551.8 1537.3 1521.7 1505.1 1487.2 288.6 308.8 330.5 353.6 378.3 404.8 433.2 463.5 495.9 530.6 567.8 607.5 650.1 695.6 744.2 898.1 1024.1 569.8 - 7 -- 38.5 87.2 147.8 195.0 315.1 498.9 685.1 865.9 1133.8 89.8 102.4 57.0 3.0 3.2 3.4 3.9 8.7 14.8 19.5 31.5 49.9 68.5 86.6 113.4 152.8 174.3 97.0 oo ed 7 6.6 14.9 25.2 33.2 53.7 85.1 116.8 147.7 193.3 -- 2° 16.8 18.0 19.3 20.6 22.1 23.6 25.3 27.0 28.9 30.9 33.1 35.4 37.9 1429.3 1609.6 1071.1 374.6 400.8 428.8 504.3 597.9 709.0 805.3 997.0 1272.3 1553.6 1831.2 2222.6 247.9 245.8 1635.1 1633.5 1597.4 1596.6 1595.7 1590.8 1578.7 1565.7 1551.8 1537.3 1521.7 1505.1 1487.2 1429.3 1609.6 1071.1 374.6 400.8 428.8 504.3 597.9 709.0 805.3 997.0 1272.3 1553.6 1831.2 2222.6 1677.2 1855.4 2706.2 2008.1 1998.2 2025.4 2100.0 2188.7 2287.7 2371.0 2548.8 2809.6 3075.3 3336.3 3709.8 24849 26482 28165 29956 31860 33673 35590 37616 39757 42020 44412 46940 49611 52435 55420 06750 .07006 .09608 .06703 .06272 .06015 .05901 .05819 .05754 .05643 .05739 .05986 .06199 .06363 .06694 578.3 573.7 1960.3 1956.0 1973.9 1969.5 1965.0 1956.5 1940.6 1923.4 1905.4 2172.3 2153.4 2133.4 2112.4 2720.5 3018.6 2609.1 2053.1 2233.2 2492.4 2830.0 3220.4 3668.0 4148.4 4776.1 5536.6 6375.2 7285.4 8395.4 3298.8 3592.3 4569.4 4009.1 4207.1 4461.9 4795.0 5176.9 5608.6 6071.8 6681.5 7708.9 8528.6 9418.8 10507.8 45735 47900 50130 52481 54960 58298 61841 65599 69588 73820 78311 83077 88134 93501 99197 -07213 .07500 .09115 .07639 .07655 .07654 .07754 .07892 .08060 .08225 .08532 .09279 .09677 .10073 .10593 €y a8eq PRS - MAR. '79 LOAD DIVISION - PLAN D TABLE XVI PCS - MAR. '79 DIESEL/HYDRO NO INTERTIE D.D. STEEBY/F.J. BETTINE Use heat rate of: 11,600 Btu/kWh for 600 kW units and below Assume: 138,000 Btu/gal 10,500 Btu/kWh for larger than 600 kW 11.897 kWh/gal small unit 13.143 kWh/gal large unit GLENNALLEN DIESEL VALDEZ HYDRO DIESEL TOTAL TOTAL DIESEL DIESEL ~~ DIESEL ANNUAL —% LARGE (9) MWH MWH ANNUAL % HYDRO HWH (y) WH % LARGE MWH WH YEAR MW SMALL LARGE SMALL MWH_ -% DIESEL HYDRO DIESEL © %_SMALL LARGE SMALL 1979 20886 98/2 20468 418 24849 0/100 -- 24849 98/2 24352 497 1980 21418 98/2 20990 428 26482 0/100 -- 26482 98/2 25952 530 1981 21965 98/2 21526 439 28165 51/49(3) 14393-13772 98/2 13497 275 1982 22525 98/2 22075 451 29956 100/0 29956 -- -- -- -- 1983 23100 98/2 22638 462 31860 100/0 31860 -- -- -- -- 1984 24625 98/2 24133 493 33673 100/0 33673 -- -- -- -- 1985 26251 98/2 25726 525 35590 98/2 34878 712 100/0 712 -- 1986 27983 98/2 27423 560 37616 96/4 36111 1505 00/0 1505 -- 1987 29831 98/2 29234 597 39757 94/6 37372 2385 —-100/0 2385 -- 1988 31800 97/3 30846 954 42020 93/7 39079 2941 1100/0 2941 -- 1989 33899 96/4 32543 1356 44412 90/10 39971 4441 100/0 4441 -- 1990 36137 98/2 35414 723 46940 86/14 40368 6572 — 100/0 6572 -- 1991 38523 98/2 37753 770 49611 83/17" 41177 8434 — 100/0 8434 - 1992 41066 98/2 40245 821 52435 81/19 42472 9963 100/0 9963 -- 1993 43777 98/2 42901 876 55420 78/22 43228 © 12192--100/0 12192 -- (1) Maximum annual output of a hydro is 54,725 MWH (2) Assumes small units run a minimum of 2%/yr. when all diesel generation. (3) First hydro unit on line first quarter 1981, second unit second quarter. Hydro furnishes 51% of total MWH for 1981. CVEA03/h9 oy a8eg PRS - MAR. '79 FUEL CALCULATIONS - PLAN D TABLE XVII PCS - MAR. '79 D.D. STEEBY/F.J. BETTINE GLENNALLEN VALDEZ, GALLON OF GALLON OF GALLON OF GALLONOF = FUEL FUEL TOTAL COST PER cost FUEL FUEL TOTAL COST PER COST YEAR LARGE UNIT SMALL UNIT GALLONS GALLON (1) DOLLARS LARGE UNIT SMALL UNIT GALLONS GALLON (2) DOLLARS 1979 1557352 35111 1592464 0.5010 797824 1852851 1774 1894625 0.4740 898052 1980 1597020 36006 1633026 0.5361 875416 1974615 44519 2019133 0.5072 1024064 1981 1637807 36925 1674432 0.5736 960618 1026901(3) 23152 1050053 0.5427 569846 1982 1679563 37867 1717430 0.6137 1054067 - == = 0.5807 — 1983 1722438 38833 1761271 0.6567 1156642 om - - 0.6213 - 1984 1836149 41397 1877546 0.7027 1319311 aad o - 0.6648 S 1985 1957390 44130 2001521 0.7519 1504875 54173 —— 54173 0.7113 38536 1986 2086536 47042 2133578 0.8045 1716456 114510 - 114510 0.7611 87158 1987 2224331 50149 2274480 0.8608 1957898 181465 - 181465 0.8144 147789 1988 © 2346953 80188 2427141 0.9211 2235562 223769 —) 223769 0.8714 194999 1989 2476074 113975 2590049 0.9855 2552604 337899 ae 337899 0.9324 315067 1990 = 2694534 60750 2755284 1.0545 2905532 500038 - 500038 0.9977 498888 1991 2872445 64761 2937206 1.1283 3314190 641710 -- 641710 1.0675 685051 1992 3062062 69036 3131098 1.2073 3780276 758046 Saad 758046 1.1423 865891 1993 3264206 73593 3337799 2.2918 4311921 927642 -- 927642 1.2222 1122788 (1) Price in Glennallen, 1979 @ 50.1¢/gal. esc. at 7%/year through 2003 (2) Price in Valdez, 1979 @ 47.4¢/gal. esc. at 7%/year through 2003 (3) Fuel cost with hydro furnishing 14,392 MWH of power during 1981. CVEA03/h10 Gy ase