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Juneau 20 year Power Supply Plan Vol 2 1984
[ VOLUME 2 ‘+ | JUNEAU 20 YEAR POWER SUPPLY PLAN Alaska Power Authority LIBRARY COPY NOVEMBER 1984 EBASCO EBASCO SERVICES INCORPORATED 1040C JUNEAU 20-YEAR POWER SUPPLY PLAN VOLUME 2 SUBMITTED TO: ALASKA ELECTRIC LIGHT AND POWER COMPANY GLACIER HIGHWAY ELECTRIC ASSOCIATION ALASKA POWER ADMINISTRATION ALASKA POWER AUTHORITY NOVEMBER, 1984 EBASCO SERVICES INCORPORATED fo JUNEAU 20-YEAR POWER SUPPLY PLAN TABLE OF CONTENTS Page VOLUME _1 1:0” INTRQDUGION = Sn cw op eel ele ee iie oe ee eo 9 pe eee 1-1 2.0 ‘LOAD FOREGASTS 295 5 3 a soe cette 5 te we se ee 8 eo 2-1 2.1 Assumptions Underlying Load Forecasts ........-. 2-1 2.2 Sensitivity of the Forecasts . 2. 26 Sis. www ee 2-5 3.0 POWER SUPPLY ALTERNATIVES . 2. 2. 2 2 6 0 © wo ore oe wee ow 3-1 3.1 Interconnection with Existing Hydroelectric-Based SYUSUGMS ihr. © 3 6 seh wae 6 6 ww whet Sie ene 66 3-3 3.2 Undeveloped Hydroelectric Projects ......-+.+--. 3-14 3.3 Upgrading Existing Hydroelectric Projects ....... 3-46 3.4. .Fossi}-Fuel- tnerma Plante. 29. 6 0 «ens ec ee ew 3-59 3.5 Other Energy Sources ..... 2. eee eee veveveve 3-69 4.0 TRANSMISSION SYSTEM DEVELOPMENT . . 1... ee ee ee eee 4-1 Wel c ATC OMUSGION 5 3. :6_ ctw fo ene 0 0 6G On oh terns © 4-1 4.2 The 69 kV Transmission System. ......-++4+e8- 4-1 4.3 Oistribution/réeder Cosses..<: 6 6 ws we we ge 4-13 4.4 Project-Specific Transmission Lines ........4.-.- 4-16 5.0 PLAN FORMULATION AND EVALUATION ..... 2. ee eee eee 5-1 5.12 Planning: Approach ... . . . wr0 2 oe 5 2 30 S08 5-1 5.2 sEXTSUINGovatem ooo. 6 s&s ce ee ee 6 ober we 6 se 5-5 5.3. Bas@:Gase [ermal Plan <2. 6 6 ws we oo he eww 5-6 5.4 Alternative Thermal Plans .........+4 242 ee ee 5-8 5.5 Hydroelectric Plans . . 2. 2 6 2 6 1 0 6 8 eo go ieere 5-13 §.6 “Intefconnection Plans . . 2 0. 2 6 eee te hw we oe 5-19 5.7 Cost of Power Forecast .... 2.2. 2 eee eee eee 5-23 6.0 FINDINGS AND RECOMMENDATIONS... ~~. 2. ee ee eee eee 6-1 6.1 (‘Steay andings: <5 Se 6 we ee Be lide os 6-1 6.2 Recommended Plan of Action .......2+-+++e+es 6-6 1040C TABLE OF CONTENTS (Continued) VOLUME 1 (Continued) 7.0 APPENDICES 1.1. Tables: of:Stgnificant Oata... ¢ 6 « vitelhw’s Bee 6 6 7.1-1 7.2 T. E. Neubauer and Associates Report ......... 7.2-1 Taide RELORONCES: tiie) «3 wi fe oy, we oe a Se) we oi, ew lw 7.3-1 VOLUME 2 7.0 1040C APPENDICES (Continued) 7.4 Project Financing and System Cost of Power ...... 7.4-1 7.5 PRARBIRG mic a et tt tt wt te we we 7.5-1 7.6 Planing eet Results 5.6 ee eee er ee ew ee 7.6-1 ii ; APPENDIX 7.4 PROJECT FINANCING AND SYSTEM COST OF POWER 0621C PROJECT FINANCING AND SYSTEM COST OF POWER 1.0 INTRODUCTION Financing alternatives available to AEL&P as a separate entity are Numerous. Complicating the situation, however, is the fact that AEL&P is interconnected with the Alaska Power Administration (APA) and the Glacier Highway Electric Association (GHEA). These interconnections bring forth the possibility of ownership of facilities by these other entities and purchase of power by AEL&P, or of joint ownership of facilities by two or more of the interconnected entities. The following section discusses financing possibilities where AEL&P owns the generating and/or transmission facilities. Subsequent sections discuss APA, GHEA, and joint ownership/financing possibilities. The final- section presents a discussion of system retail power costs with and without the Lake Dorothy Project. 2.0 AEL&P OWNERSHIP AND FINANCING There are three general areas of financing that can be employed by AEL&P. These are conventional, project, and government-assisted financing. While these categories may overlap and intertwine to some extent, for the purpose of description and discussion, they present logical areas of categorization. 2.1 CONVENTIONAL FINANCING In conventional financing, owners submit their own funds and obtain additional funds from others to finance a project. In the typical corporation, owners funds are represented by common stock and funds from others including long-term debt and sometimes preferred stock — (which may have certain rights of ownership). Conventional financing is the method that AEL&P has used to date to finance its existing system. As can be seen from its balance sheet dated December 31, 1983, approximately $9 million of equity (includes $2 million of preferred stock) and $14. million of long-term debt have been used to finance AEL&P's long-term assets. AEL&P could continue to finance future capital additions to its system in the same manner, i.e., by issuing additional quantities of common stock, preferred stock, and long-term bonds. Additional common equity - might be required to obtain additional debt since AEL&P's debt ratio (percent of total capital) is around 60% which ‘seems to be at the higher end of the acceptable range for electric utilities. Loans obtained from the State of Alaska might not require additional equity, however, since the State has its own lending criteria which may differ from market enforced criteria (See Section 2.3.2). 0621C 7.4-1 2.2 PROJECT AND OTHER FINANCING This area of financing includes project financing, direct leasing, and leveraged leasing. A description of these financing methods and their applicability to future AEL&P projects follows. 2.2.1 Project Financing This is a method of financing where the lenders are paid interest and principal only from funds generated by the project and not from other general funds that the owner(s) may have. In legal terminology, the lenders do not have recourse to the other assets of the equity participants or owners. A mortgage on the project assets is usually offered as security, but additional security in the form of a take-or-pay contract from the purchasers of the project's product or a guarantee of the debt by a creditworthy party is almost always required. The chief advantage of project financing over conventional is that greater leverage can be obtained. Project financings often have 75% of total capital financed with debt, while utility capital structures (conventional financing) have only 45% to 55% debt. Other possible advantages are off-balance sheet treatment of the projects debt and avoidance of restrictive covenants in existing indentures or loan agreements. Figure 7.4-1 presents a schematic of a project financing. 2.2.2 Direct Leasing Leasing includes ownership characteristics in that the lessor legally owns the facilities, not the electric utility user/lessee. However, long-term leases (both direct and leveraged) are usually considered to be more a means of financing than ownership since the lessee usually operates the facilities and pays the property taxes, 0 & M, and other expenses. In addition, leases often provide an option for the lessee to purchase the facilities. In a direct lease, the lessor/owner would provide all of the capital for the facilities which would be designed, constructed, and operated by AEL&P. The chief advantages to leasing would be that AEL&P would not have to put up any of its owner capital and if AEL&P could not utilize tax benefits (ITC and ACRS) from the facility under conventional ownership, they could be at least partially realized through the lease rate which would probably be lower than conventional debt financing. 2.2.3 Leverage Leasing Leveraged leasing differs from direct leasing in that the lessor, instead of providing 100% of the required capital from its owner funds, provides only a portion of the funds and borrows the remainder on a nonrecourse basis. Since the lenders have no recourse to the lessor's 0621C 7.4-2 e-v'L 25% OF FACILITY CAPITAL REQUIREMENTS 25% OF FACILITY CAPITAL REQUIREMENTS (wo1vuado /4aNMO) AuviaisEns- EXPENSES ”_MORTGAGI ee 3 T+v7Z Jan9T4 ALMovd MHNMO ALTTOIN CEONWNI Loapodd ALTTIOWd NOLIVYHNED 75% OF FACILITY REQUIREMENTS (NON-RECOUASE TO OWNER) other assets, they usually require additional security in the form of a debt service guarantee or an assigned take-or-pay contract from the purchaser of the projects' output. The advantages of a leverage lease are the same as those for a direct lease except that because of the greater leverage involved, the lessee utility can often obtain an even lower lease rate. Leveraged leases are often used in conjunction with a project financing. A schematic of a leverage lease is shown in Figure 7.4-2. To determine if leasing would be advantageous, AEL&P's future tax situation would have to be forecast and an estimate of lease costs determined. The costs would then have to be compared with other financing alternatives. 2.3 GOVERNMENT-ASSISTED FINANCING This area of potential financing for AEL&P includes industrial development bonds (IDBs) and possible loans or other assistance from the State of Alaska. 2.3.1 Industrial Development Bonds IDBs allow a profit-making corporation or other entity to finance facilities with tax-exempt bonds that have an interest cost that is lower than taxable bonds. A municipality with the authority to borrow must issue the bonds. The State of Alaska and probably the City of Juneau have this authority. In addition, the bond issue must qualify under one of two criteria to qualify as a tax-exempt IDB. The “exempt facilities" criteria under which AEL&P might quality is for those facilities used for the local furnishing of electric energy. The main requirements are that the generating facility output must be available for use by members of the general public within the utility's service area and that customers served must be located in no more than two contiguous counties or one city and one contiguous county. If a private utility meets these criteria, there is no limit on the dollar amount of financing. The second criteria used for qualification is the "size of issue" criteria. Included are $1 million issues and $10 million issues. the $1 million issue criteria has very few restrictions attached to it and up to $1 million can therefore be issued and outstanding by a company for most any project. The $10 million issue criteria has limitations on all capital expenditures made by a company. The limitation restricts the company from making capital expenditures in excess of $10 million for any of its facilities located within the boundaries of the Municipality issuing the IDBs during a six-year period beginning three years before the bond issuance and ending three years after. o62i1C 7.4-4 poo Low FIGURE.7.4.-2 GENERATION FACILITY LEVERAGED LEASE FINANCED UTILITY LESSEE UTILITY (LESEE/ OPERATOR) GENERATION FACILITY GUARANTEE OF PAYMENT OF LOAN LEGAL TITLE LEASE PAYMENTS INCOME NOT NEEDED FOR DEBT SERVICE = HORTAGE ON FACILITY INDENTURE TRUSTEE 7.4-5 IDB financing may be possible for AEL&P's future facilities. AEL&P will probably be able to qualify under the exempt facilities criteria, but if not, then qualification under the $1 million or $10 million size of issue criteria should certainly be possible. The tax exempt feature should result in lower financing costs than from regular debt financing even though some tax benefits are lost (ITC is reduced) when IDBs are used. IDBs can also be used in project financing or as part of a leveraged leasing. The Tax Reform Act of 1984 severely limited the quantity of IDBs that a state can issue. The annual limits through 1986 are the greater of $200 million or 150 times the state's population and after 1986 the limits become the greater of $200 million or 100 times the state's population. With an approximate population of 450,000, Alaska would be limited to $200 million for future years. This amount is probably sufficient to finance future AEL&P facilities but AEL&P would be in competition with other Alaskan projects, and there is no assurance that AEL&P would be successful in obtaining IDB funds. 2.3.2 State of Alaska Assistance The State has at least two assistance programs that might be employed by AEL&P and if utilized would probably provide the best means of financing system expansion. There is the Power Project Loan Fund which provides long-term loans at the municipal bond market rate or slightly below and the rural Electrification Revolving Loan Program which provides funds at a rate of 2%/yr for transmission and distribution facilities only. The 2% rate might be increased to a rate nearer market rates if a proposed bill in the Alaska Legislature is passed. Another State program provides rate assistance to a utility's customer, but it is doubtful if AEL&P customers would qualify since their rates are not high enough. If loans can be obtained from the State through either the Power Project Loan Fund or the Rural Electrification Revolving Loan Program, they will almost certainly be preferable to debt obtained in the open market. 3.0 APA OWNERSHIP AND FINANCING The Alaska Power Administration presently owns two hydroelectric facilities in Alaska and sells power from the Snettisham facility to AEL&P and GHEA. Conceivably, the APA could construct an additional facility or facilities and meet all or part of AEL&P's future electrical requirements. The financing cost associated with the power supplied by APA would be equal to some federal government interest rate, probably the market rate of long-term federal government bonds at time of project authorization. APA ownership and financing is worth exploring, but the trend today is away from federal government ownership and financing of electric facilities (and most other facilities which can be developed by private 0621C 7.4-6 enterprise). An exception, of course, is the Long Lake phase of the Snettisham Project, which has been already authorized as a federal development at an extremely advantageous interest rate. 4.0 JOINT OWNERSHIP AND FINANCING WITH GHEA GHEA is interconnected with AEL&P, and GHEA's future requirements may exceed the APA's ability to supply power (particularly so if the APA does not build any additional units). Instead of constructing its owner units, or purchasing from AEL&P, GHEA might be brought into joint ownership with AEL&P. The potential benefit to AEL&P from this arrangement could be a lower effective financing cost brought about by GHEA's ability to obtain Rural Electrification Administration (REA) financing. The current REA insured loan rate, which is fixed by law, is 5%. Relative to the current market, this is an extremely low rate. Whether AEL&P could, through joint ownership effectively share with GHEA in the benefits from this low loan rate is unknown, but the possibility should definitely be investigated. Current action by the Administration and Congress is working to reduce the future availability and increase the cost of REA financing. The Administration has reduced the amount of insured loans that the REA can make for Fiscal Year 1985 and is working to force greater private sector borrowing by Regional Electric Cooperatives (REC). In addition, the Administration wants to increase the 5% lending rate to a level closer to market rates. The Administration's basic approach is to reduce the REC's financial dependence on the government. Congress, through the H.R. 3050 and S.B. 1300, would keep the availability of REA financing at least at its existing level and probably increase it. The Bills would, however, give the REA Administrator the power to increase rates on new loans above the existing 5%. The outlook for REA financing and a possible financially favorable future joint venture between AEL&P and GHEA is not clear and this financing method cannot, therefore, at this time, be considered as a firm possibility. 5.0 OTHER OWNERSHIP AND FINANCING It's conceivable that a third party could own generating units and sell the output to AEL&P (and GHEA) under a long-term energy purchase contract. The advantage from this form of ownership/financing would be realization of tax benefits (ITC and ACRS) if AEL&P were unable to utilize the benefits under its ownership. This method of ownership/ financing would achieve the same results as leasing, that is, removal of the requirement to commit capital and the realization of tax 0621C 7.4-1 benefits through a shift in ownership. However, AEL&P might not be the facility operator under third-party ownership and the loss of control might preclude third-party ownership. A schematic of third-party ownership and. financing is shown in Figure 7.4-3. Not shown, is a take-or-pay contract (hell-or-high-water clause) between the utility and the trustee (assigned to the lender) which might.be required in order to debt finance to the degree shown. 6.0 FINANCING AND ECONOMIC ANALYSIS Financing costs, whether they are debt interest, leasing expenses, or are implicit in the costs of purchased power (from a third party) become costs to AEL&P to provide service to its customers. Detailed analysis of power supply alternatives should include the financing costs as expenses in determining the revenue required from customers. Combining financing costs with all other expenses and AEL&P's adjudicated return on its equity investment will provide the annual revenues required. for the power supply alternative over the 20-year planning period. By levelizing the revenue stream, a comparison can be Made among projects and among financing options. To illustrate alternative financing methods, the proposed Annex Creek Hydroelectric upgrading project has been evaluated using three different financing methods. Some of the relevant costs and economic parameters are not known with any degree of certainty and therefore assumptions as to their values have been made. These assumptions are believed to be reasonable and in most instances impact the alternatives equally. Since the principal purpose of this appendix is to illustrate the method of analyzing alternative financings, the results are to be treated as illustrative rather than as definitive answers. Relevant data on the Annex Creek project is as follows: Capacity 2,900 kW Capital cost $2,770,000 Average annual generation 4,680,000 kwh Annual O & M expense $100,000 Economic life 50 years Construction period . Less than 1 year Other essential economic/financial data concerning the project is as follows: Item Value Source Construction interest rate 13% Assumed Inflation rate 6% Assumed Short-term interest rate 14% Assumed Federal tax depreciation 5 yrs. (ACRS) Internal Revenue code ’ Federal corp. tax rate 46% Internal Revenue code ITC rate - 10% Internal Revenue code 0621C 7.4-8 25-40% OF FACILITY CAPITAL REQUIREMENTS FIGURE 7.4-3 GENERATION FACILITY THIRD PARTY OWNERSHIP & FINANCING GENERATION) FACILITY Od LNSWAVd EXPENSES MORTGAGE ym oe os no a OWNER/ OPERATOR 74-9 75-60% OF FACILITY CAPITAL REQUIREMENTS The three alternative methods of financing the project are described below. Where specific parameters were unknown, values believed to be reasonable were Alternative A - Alternative B - Alternative C - 0621C assumed. Financing is with 100 percent debt obtained from the State of Alaska via an unsecured promissory note. Characteristics of the debt are assumed to be: Term 30 years Interest rate 10% - assumed market rate for municipal long-term debt Repayment Uniform annual amounts Financing cost 3% of face amount (assumed) Financing with 30 percent of equity from AEL&P and 70 percent from the State of Alaska via unsecured promissory note. Characteristics are: Required return on equity (ROE) 16% (assumed) Equity financing cost 5% (assumed) Promissory note Same as for Alternative A Ownership and financing by a third party with sales of energy and capacity to AEL&P (and possibly to Glacier Highway Electric Association). Third party owners or sponsors would probably be a limited partnership which could use the large income tax benefits. Owners are assumed to contribute 25 percent of capital requirements and obtain remaining 75 percent from lenders (this project type financing would probably require a take-or-pay contract with AEL&P with the contract assigned to the lenders). Characteristics of the financing are: Required ROE 20% (assumed) Financing cost 5% (assumed) Loan funds: Term 15 years 7.4-10 Interest rate 15% Repayment Uniform annual amounts Financing cost 2% (assumed private placement) Limited partners assumed to be located in states with state income tax as follows: Marginal tax rate 11% Depreciation 4 years (1 - 40%; 2-4 - 20%) For a meaningful analysis of the alternative financings, revenues from the project must be estimated. For utility ownership, revenue would be what the regulatory authorities would allow and for third-party ownership, the revenue would be the price negotiated between the third-party owner and the utility. For this analysis, the price or value was assumed to be 4.66¢/kWh for energy delivered and $115 per kW of firm capacity. These prices are the relative costs of energy and capacity for Annex Creek from Table 3-12 (the $955/kW has been annualized using an assumed levelized annual capital cost factor of 12 percent). The exact prices used are not critical since they are the same for all alternatives. The prices translate into annual revenues of: Energy = ($0.0466/kWh)(4,680,000kWh/yr) = $218,100 Capacity = ($115/kW)(2,900kW) = $333,500 The three alternative financings were run through a financial model which incorporates the data and parameters described above. The model determines the net present value (NPV) to owners and assumes that all of the tax benefits can be used by AEL&P or the third party owner. If the NPV is positive, the project is acceptable and if negative, not acceptable. The method of financing with the largest NPV would provide the greatest benefit to the owners and should be accepted. Fora regulated utility, the alternative with the lowest cost to customers is preferred, i.e., the alternative with the lowest revenue requirements. To determine the lowest revenue requirements, revenues were adjusted until NPV for each alternative became zero. At zero NPV, the project would just be acceptable to the owners since they would be able to pay all operating and maintenance expenses, debt interest and repayment and recover their investment at their required return (ROE). Exhibits 7.4.1 through 7.4.3 show the NPVs for the three alternative financings at the assumed price or value of electricity calculated above, i.e., 4.66¢/kWh and $115/kW. The NPVs are: 0621C 7.4-11 NP Alternative A $1,251,004 Alternative B 613,753 Alternative C 197,883 A direct comparison can be made between A and B since the owner in both of those alternatives is AEL&P. Since the NPV for Alternative A is greater, that method of financing should be undertaken by AEL&P. The positive NPV results from Alternative C are from the viewpoint of the third-party owner and al] that can be concluded by AEL&P is that third parties would own and finance Alternative C at the price paid for the electricity by AEL&P. Since the NPV of C is positive, AEL&P could offer less for the electricity and still satisfy the limited partnership. In theory, AEL&P could reduce the price until the partnership's NPV was zero and the project would still be implemented by the third-party owners. Similarly, the regulatory authorities could reduce rates or prices from Alternatives A and B so that AEL&P's NPV was zero and AEL&P would still be made whole, earning 16 percent on its equity investment (which is zero in Alternative A). Exhibits 7.4.4 through 7.4.6 present the three alternatives with revenues decreased until the NPV in each case equals zero (or very close to zero). The required revenues are: Annual Revenue Requirements (First Year) Alternative A $141,761 Alternative B 350,300 Alternative C - 443,450 Since Alternative A has the lowest revenue requirements, it would be selected by AEL&P provided the risk to AEL&P (and its customers) was . the same under all three alternatives. The risk, however, may not be the same since in Alternative A, AEL&P has assumed a greater debt load than under B and in C has probably signed a take-or-pay contract with the third party for purchase of electricity. Attempts to quantify and adjust for these different risks is difficult and in most cases.a subjective decision is made as to whether a reduction in risk through accepting increased revenue requirements would be justified. 7.0 SYSTEM COST OF POWER FORECAST In the absence of any accepted financing approach or set of financing terms, a generic set of assumptions were adopted as the basis for estimating the impact on Juneau's retail electric costs of implementing the recommended long-term power supply plan. 0621C 7.4-12 Retail costs were estimated for the base case thermal plan, assuming the mid-range load growth forecast, and also for the Lake Dorothy hydroelectric plan, using the same forecast. The evaluation addressed two alternative in-service dates for Lake Dorothy, 1993 and 1996. The results of the three power cost forecasts are presented in Exhibits 7.4.7 through 7.4.9. The figures are presented for Juneau as a whole, not for individual utilities, and the results are therefore a melded cost. This is in keeping with the approach of the remainder of the report. A 6 percent inflation rate and a 10 percent financing rate are assumed, along with a financing term of 35 years for hydroelectric projects and 20 years for diesel plants. Capital costs of new diesel units and hydroelectric facilities come from the long term planning model, as do the O&M and fuel costs. These O&M costs only include those expenses directly associated with diesel generation; other operating costs are addressed later. The spreadsheet converts constant dollar capital costs to nominal dollars based on the inflation rate, calculates capitalized interest for those projects with multiple year construction periods, and calculates levelized debt service. The next two spreadsheet lines make the comparable conversion from constant to nominal dollars for the O&M and fuel costs mentioned previously. Snettisham Project sales estimated through the long-term planning model are multiplied by an assumed price of 2.5 cents/kWh in keeping with initial Alaska Power Administration guidance. Utility operating costs, exclusive of those O&M and fuel expenses associated with diesel generation (which were addressed previously) are assumed to rise over time with the rate of inflation. Interest expenses on existing debt are assumed fixed through the forecast period. Revenue requirements are divided by forecasted sales to give the estimated unit cost of energy in cents/kwh. The base case thermal plan forecast (Exhibit 7.4.7) indicates stable costs until about 1993 when diesel generation will be required to supplement generation from existing and committed hydroelectric facilities. Costs then rise rapidly, tripling over the next 14 years. With the hydroelectric plan, when Lake Dorothy enters service in 1993, there is a sudden and substantial unit cost increase in 1993, but costs subsequently remain extremely stable throughout the planning period. In the final year, 2010, system costs with the Lake Dorothy plan is forecast to be only 60 percent of the comparable costs with the thermal plan. Delaying Lake Dorothy until 1996 reduces the magnitude of the sudden cost increase (because costs have risen in the interim due to supplemental diesel generation), but over the longer term there is little difference. ‘ 0621C 7.4-13 bI-v'L Y 1986 Capital Required Total $2950080.00 Capacity Total Expenses Oam Prop. Txs. Int. on Wark Cap Sptotel Q@er. Inc. Tx. Depre.-Stat Int. Expense-LT St. Tx. Inc. State Tx. Tx. Oepre.-Fed Fed. Tx. Inc. Fed. Tax 11 MR. Fed. Tx. Tot. Inc. Tx, After Tax Inc. Int. Op.4T Dept Repayment Qa, Repaynt Cap Cap Gp aaRE agit OQuner's Can Flo Net PY Prof Indx (B/C) $1251004.49 Y 1987 $0.00 Y 1988 Y 1989 $2950050.00 Exhibit 7.4.1 Net Present Value Calculation Alternative A Y 1990 Y 1991 Y 1992 Y 1993 $218100.00 — $231186.00 $245057.16 $259760.59 $275346.22 $333500.00 $551600.00 $100000.00 $0.00 $1400.00 $101400.00 $450200.00 $0.00 $290088.25 $160111.73 $0.00 $560509.50 ($400397.75) ($184182.97) $295005.00 ($479187.97) ($479187.97) $929387.97 $290088.25 $98335.00 $98335.00 $0.00 $0.00 $0.00 $540964.72 $333500.00 $564686.00 $106000.00 $0.00 $1484.00 $107484.00 $457202.00 $0.00 $260254.75 $176947.25 $0.00 $944016.00 ($767068.75) _ ($352851.63) ($352851.63) ($352851.63) $610053.63 $280254.75 $9833.00 $196670.00 $608.40 $608.40 $431463.68 $333500.00 $578557.16 $112360.00 $0.00 $1573.08 $113933.04 $464624.12 $0.00 $270421.25 $194202.87 $0.00 $708012.00 ($513809.13) ($236352.20) ($236352.20) ($236352.20) $700976.32 $270421.25 $98335.00 $295005.00 $644.90 $1253.30 $332220.07 $333500.00 $593260.59 $119101.60 $0.00 $1667.42 $120769.02 $472491.57 $0.00 $260587.75 $211903.62 $0.00 $472008.00 ($260104.18) ($119647.92) ($119647.92) ($119647.92) $592139.49 $260587.75 $98335.00 $393340.00 $683.60 $1936.90 $233216.74 $533500.00 $608846.22 $126247.70 $0.00 $1767.47 $128015.16 $480831.06 $250734.25 $230076.81 $0.00 $236004.00 ($5927.19) ($2726.51) ($2726.51) ($2726.31) $483557.57 $250754.25 $98335.00 $491675.00 $724.61 $2661.52 $134468.32 Y 1994 $291867.00 $533500.00 $625367.00 $133822.56 $0.00 $1873.52 $135696.07 $489670.92 $240920.75 $248750.17 $0.00 $248750.17 $114425.08 $114425.08 $114425.08 $575245.84 $200920.75 $98335.00 $590010.00 $768.09 $3429.61 $33990.09 Y 1995 $309379.02 $353500.00 $642879.02 $141851.91 $0.00 $1985.93 $143837.64 $499041.18 $231087.25 $267953.93 $267953.93 $123258.61 $123258.61 $123258.61 $375782.37 $231087.25 $98335.00 $688345.00 $814.18 $4243.78 $46360.12 Y 1996 Y 1997 $377941.76 — $347618.27 $333500.00 — $333500.00 $661441.76 $661118.27 $150363.03 $159384.61 + $0.00 $0.00 $2105.08 $2231.39 $152468.11 $161616.19 $508973.65 $519502.07 $221253.75 — $211420.25 $287719.90 $308081.62 $0.00 $0.00 $287719.90 — $308061.82 $132351.15 $141717.64 $132951.15 $141717.68 $132951.15 $141717.68 $376622.50 $377784.43 $221253.75 $211420.25 $98335.00 $96335.00 $786680.00 $685015.00 $863.03 $914.61 $5106.81 $6021.62 $57033.75 $68029.18 Y 1998 $368475.36 $333500.00 $701975.36 $168947.90 $0.00 $2365.27 $171313.17 $530662.19 $201586.73 $529075.44 $0.00 $329075.44 $151374.70 $151374.70 $151374.70 $379787.49 $201586.75 $98335.00 $963350.00 $969.70 $6991.32 $79365.78 Oper. Inc. Tx, Depre.=Stat Int. Expense-LT St. Tx. Inc. State Tx. Tx, Depre.-Fed Fed. Tx. Inc. Fed. Tax Iw Mt. Fed. Tx. Tot. Inc. Tx. After Tax Inc, Int. Exp. 47 $613752.76 1.95 Y 1987 Y 1988 $0.00 $2937585.00 $0.00 ($872550.00) Exhibit 7.4.2 Net Present Value Calculation Alternative B Y 1969 Y 1990 $218100.00 — $231186.00 $333500.00 — $333500.00 $551600.00 $564686.00 $100000.00 $106000.00 $0.00 $0.00 $1400.00 $1484.00 $101400.00 $107484.00 $450200.00 $457202.00 $0.00 $0.00 $203061.78 $196178.33 $247138.23 — $261023.68 $0.00 $0.00 $392356.65 $660611.20 ($145218.43) ($399787.53) ($66800.48) ($183902.26) $206503.50 ($273303.98) ($183902.26) ($273303.98) ($183902.26) $723503.98 $641104.26 $203061.78 $196178.33 $68834.50 $68834.50 $68834.50 — $137669.00 $0.00 $608.40 $0.00 $608.40 $451607.70 — $376091.44 Y 1991 $245057.16 $333500.00 $578557.16 $112360.00 $0.00 $1573.04 $113933.08 $464624.12 $0.00 $189294.88 $275329.25 $0.00 $493608.40 ($220279.16) ($101328.41) ($101328.41) ($101328.41) $565952.53 $189294.88 $68834.50 $206503.50 $644.90 $1253.30 $307823.16 Y 1992 $259760.59 $333500.00 $593260.59 $119101.60 $0.00 $1667.42 $120769.02 $472491.57 $9.00 $162411.43 $290080.14 $0.00 $330405 60 ($40325.46) ($18549.71) ($1549.71) ($18549.71) $491001.28 $182411.43 $68834.50 $275338.00 $683.60 $1936.90 $239795.35 Y 1993 Y 1994 $275346.272 $291867.00 $333500.00 $333500.00 $608846.22 $625367.00 $126247.70 —$1:339872.56 $0.00 $0.00 $1767.47 $1873.52 $128015.16 $1354696.07 $480831.06 $489670.92 $175527.98 $168644.53 $305303.09 $321026.40 $0.00 $0.00 $165202.80 $140100.29 $321026.40 $64446.13 $147672.18 $6006.13 $147672.14 $64006.13 $147672.18 $416384.93 $341998.78 $175527.98 33 2003430 "$eeene:30 $344172.50 — $419007.00 $724.61 $768.09 $2661.52 $3429.61 $172022.45 $4519.76 Y 1995 $309379.02 + $333500.00 $642879.02 $141851.91 $0.00 $1985.93 $143837.8a $499041.18 $161761.08 $337280.11 . $0.00 $337280.11 $155148.85 $155148.85 $155148.85 $343692.33 $161761.08 $68834.50 $481641.50 $614.18 $4243.78 $113296.76 Y 1996 $377941.76 $333500.00 $661441.76 $150363.03 $0.00 $2103.08 $192468.11 $508973.65 $154877.63 $354096.03 $0.00 $354096.03 $162884.17 $162884.17 $162884.17 $346089.48 $154877.63 $68834.50 $550676.00 $863.03 $5106. $122377.33 Y 1997 $347618.27 $333500.00 $681118.27 $159384.81 $0.00 $2231.39 $161616.19 $519502,07 $147994.18 $371507.90 $0.00 $371507.90 $170893.63 $170893.63 $170893.63 $348608.44 $147994.18 $68834.50 $619510.50 $914.61 $6021.62 $131779.76 Y 1996 $368475.36 $333500.00 $701975.36 $168947.90 $0.00 $2365.27 $171313.17 $590662.19 $141110.73 $369551.47 $0.00 $389951.47 $179193.68 $179193.68 $179193.68 $351468.52 $141110.73 $68834.50 $688345.00 $969.70 $6991.32 $457.29 9T-v°L Y 1986 Capitel Required Total arn Outlay $2212537.50 Revenue Energy Capacity Total Expenses aM Prop. Txs. Int. on Work Cap Suptotal Qper. Inc. Tx, Depre.-Stat Int. Expense-t St. Tx. Inc. State Tx. Tx. Oepre.-Fed Fed. Tx. Inc. Fed. Tax It Mt. Fed. Tx. Tot. Inc. Tx. Y 1987 Y 1968 $2999662.50 ($727125.00) Y 1989 $218100.00 $333500.00 $551600.00 $100000.00 $0.00 $1400.00 $101400.00 $450200.00 $885015.00 $320817.94 ($755632.94) ($83119.62) $420382.13 ($291000.06) ($133860.03) $221253.75 ($355113.78) ($438233.40) $888433.40 $320817.94 $147502.30 $147502.50 $0.00 $0.00 $420112.96 Y 1990 $231186.00 $333500.00 $564686.00 $106000.00 $0.00 $1484.00 $107484.00 $457202.00 $442507.50 $298692.56 ($283998.06) ($31239.79) $708012.00 ($549502.56) ($252771.18) ($252771.18) ($284010.97) $741212.97 $298692.56 $147502.50 $295005.00 $608.40 $608.40 $295017.90 Exhibit 7.4.3 Net Present Value Calculation Alternative C Y ig9l $245057.16 $333500.00 $578557.16 $112360.00 $0.00 $1573.04 $113933.04 $464624,12 $442507.50 $276567.19 ($254450.57) ($27989.56) $531009.00 ($342952.07) ($157757.95) ($157757.95) ($185747.51) $650371.63 $276567.19 $147502.50 $442507.50 $644.90 $1253.30 $226301.95 Y 1992 $259760.59 $333500.00 $593260.59 $119101.60 $0.00 $1667.42 $120769.02 $472491.57 $442507.50 $254441.81 ($224457.75) ($24690. 35) $354006.00 ($135956.25) ($62539.87) ($62539.87) ($87230.22) $559721.79 $254441.81 $147502.50 $590010.00 $683.60 $1936.90 $157777.48 Y 1993 $275346.22 $333500.00 $608846.22 $126247.70 $0.00 $1767.47 $128015.16 $480831.06 $232316.44 $248514.62 $27336.61 $177003.00 $71511.62 $32895.35 $32895.35 $60231.96 $420599.11 $232316.44 $147502.50 $737512.50 $724.61 $2661.52 $407860.17 .$291867.00 $533500.00 $625367.00 $30742.78 $252143.25 $115985.90 $115985.90 $146728.68 $342942.24 $210191.06 $147502.50 $885015.00 $768.09 $3429.61 ($14751.32) Y 1995 Y 1996 $309379.02 $327941.76 $333500.00 $333500.00 $642879.02 $661441.76 $141851.91 — $150363.03 $0.00 $0.00 $1985.93 $2105.08 $143837.84 = $152468,.11 $499041.18 $508973.65 $188065.69 — $165940.31 $310975.49 — $343033.34 $4207.30 $37733.67 $280232.71 $308826.03 $128907.05 $142059.98 $128907.05 $142059.98 $163114.35 $1 7979.64 $335926.83 $329180.01 $188065.69 $165940.31 $147502.50 _ $147502.30 $1032517.50 $1180070.00 $614.18 $863.03 $4243.78 $5106.61 $958.64 $15737.20 Y 1997 Y 1998 $347618.27 —- $368473.36 $333500.00 — $333500.00 $681118.27 -$701975.36 $159364.81 — $168947.90 $0.00 $0.00 $2231.99 $2365.27 $161616.19 = $171313.17 $519502.07 $530662.19 $143814.94 — $121689.56 $375687.13 $408972.63 $41325.58 —-$44986.99 $337953.47 —-$367647.05 $155458.59 = $169117.64 $155458.59 — $169117.68 $196784.18 — $214104.63 $3227717.69 = $316557.56 $143814.98 = $121689.56 $147502.50 _$147502.50 $1377522.50 $1475025.00 $914.61 $969.70 $6021.62 $6991.32 $1400.45 $47365.30 EVES Y 1986 Capital Required Total fon Outlay $2950050.00 Capecity Total Bopenses: Oa Prop. Txs. Int. on Work Cap Subtotal Oper. Inc. Tx. Oepre.-Stet Int. Expense-LT St. Tx. Inc. State Tx. Tx, Depre.-Fed Fed. Tx. Inc. Fed. Tax it Mt. Fed. Tx. Tot. Inc. Tx. After Tax Inc. Int. Exp.-LT Dept Repayment On, Repaynt Inc Work Cap Qu Work Cap Rec Work Cap Rec Land Qemer's Ch Flo Net PY Prof Indx(B/C) $420.13 #01v/0! Y 1987 $0.00 Y 1988 Y 1989 $2950050.00 $6051.00 $85710.00 $141761.00 Fel 888 $101400.00 $40361.00 $0.00 $290088.25 ($249727.25) $0.00 $560509.30 ($810236.75) ($372708.91) $295005.00 ($667713.91) ($667713.91) $708074.91 $290088.25 $98335.00 $96335.00 $0.00 $0.00 $0.00 $319651.66 Exhibit 7.4.4 Revenue Requirements (NPV = 0) Alternative A $59414.06 $85710.00 $145124.06 $280254.75 ($242614.69) ' $0.00 $944016.00 ($1186630.69) ($545850.12) ($545850.12) ($545650.12) $5863490.18 $280254.75 $98335.00 $196670.00 $608.40 $608.40 $204900.43 Y 1991 $62978.90 $65710.00 $148688.90 $112360.00 $0.00 $1573.08 $113933.04 $34755.66 $0.00 $270421.25 ($235663.39) $0.00 $708012.00 ($943677.39) ($434091.60) ($434091.60) ($434091.60) $468847.46 $270421.25 $98335.00 $295003.00 $644.90 $1253.30 $100091.21 Y 1992 $66757.64 $85710.00 $152467.64 $119101.60 $0.00 $1667.42 $120769.02 $31698.62 $0.00 $260587.75 ($228889.13) $0.00 $472008.00 ($700897.13) ($322412.68) ($322412.68) ($322412.68) $354111.30 $260587.75 $98335.00 $393340.00 $683.60 $1936.90 ($4811.45) Y 1993 $70763.10 $85710.00 $156473.10 $126247.70 $0.00 $1767.47 $128015.16 $28457.93 $250754.25 ($222296.32) $0.00 $236004.00 ($458300.32) ($210818.15) ($210818.15) ($210818.15) $239276.08 $250754.25 $98335.00 $491675.00 $724.61 $2661.52 ($109613.17) 3 Y Y 1995 $79509.41 $85710.00 $165219.41 $141851.91 $0.00 $1985.93 $143837.84 $21361.58 $231087.25 ($209705.67) $0.00 ($209705.67) ($96464.61) ($96464.61) ($9646.61) $117846.19 $231087.25 $98335.00 $688345.00 $814.18 $4243.78 ($211576.06) Y 1996 $84279.98 $85710.00 $169989.98 $130363.03 $0.00 $2105.08 $152868.11 $17521.87 $221253.75 ($203731.68) $0.00 ($203731.88) ($93716.66) ($93716.66) ($93716.66) $111238.54 $221253.73 $96335.00 $786680.00 $863.03 $5106.81 ($208350.21) Y 1997 $89336,78 $85710.00 $175046.78 $159384,61 $0.00 $2231.99 $161616.19 $13430.58 $211420.25 ($197989.67) ($197989.67) ($91075.25) ($91075.25) ($91075.25) $104505.83 $211420.25 $98335.00 $885015.00 $914.61 $6021.62 ($205249.42) v 1998 $94696.99 $85710.00 $180406.99 $168947.90 $0.00 $2363.27 $171313.17 $9093.62 $201586.75 ($192492.93) ($192492.93) ($88546.75) ($88546.73) ($88546.75) $97640.57 $201586.75 $98335.00 $983350.00 $969.70 $6991.32 ($207781.18) 8T-v°L ¥ 1986 Capital Required Total am Outlay $2065035.00 Capacity Total Expenses OAM Prop. Txs. Int. on Work Cap Sbtotal Oper. Inc. Tx. Depre.-Stat Int. Expense-LT St. Tx. Inc. State Tx. Tx. Depre.-Fed Fed. Tx. Inc. Fed. Tax re Mm. Fed. Tx. - Tot. Inc. Tx. after Tax Inc. Net PV Prof Inde (B/C) ($508.21) 1.00 Y 1987 $0.00 Y 1988 Y 1989 $2937585.00 $136500.00 $211800.00 $350300.00 $100000.00 $0.00 $1400.00 $101400.00 $248900.00 $0.00 $203061.78 $45838.23 $0.00 $392356.65 ($346518.43) ($159396.48) $206503.50 ($365901.98) ($365901.98) $614801.98 $203061,78 $68834,50 $68834.50 $0.00 $0.00 ($872550.00) $342905.70 Exhibit 7.4.5 Revenue Requirements (NPV = 0). Alternative B Y 1992 Y 1990 Y 1991 $146810.00 $155618.60 — $164955.72 $211800.00 $211800.00 — $211800.00 $358610.00 $367418.60 — $376755.72 $106000.00 $112360.00 $119101.60 $0.00 $0.00 $0.00 $1484.00 $1573.04 $1667.42 $107484.00 ~ $113933.08 — $120769.02 $251126.00 $253485.56 — $255986.69 $0.00 $0.00 $0.00 $196176.33 $189294.88 — $182411.43 $54947.68 — $64190.69 —- $73575.27 $0.00 $0.00 $0.00 $660811.20 — $495608.40 — $330405.60 ($605863.53) ($431417.72) ($256830.33) ($278697.22) ($198452.15) ($118141.95) ($278697.22) ($196452.15) ($128141.95) ($278697.22) ($198452.15) ($118141.95) $529823.22 -$451937.71 -$374128.65 $196178.33 $189294.88 —$182411.43 $68834.50 $6834.50 $68834.50 $137669.00 $206503.50 $275338.00 $608.40 $644.90 $683.60 $608.40 $1253.30 $1936.90 $264810.40 — $193608.33 $122882.72 Y 1993 Y 1998 Y 1995 Y 1996 Y 197 Y 1998 $174853.05 — $185348.24 © $196464.90 — $208252.79 $220707.96 $239992.88 $211800.00 $212800.00 = $211800.00 $211600.00 $211800.00 $211800.00 $386653.05 $3997144.24 — $408264.90 —-$420052.79 $432547.96 $445792.88 $126247.70 —-$193822.56 $141851.91 — $150363.03 $159384.81 — $168947.90 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $2767.47 $1873.52 $1985.93 $2105.08 $2231.39 $2365.27 $128015.16 —-$135696.07 —$103837.84 © $152468.11 —$161616.19 $1 71919.17 $258637.90 — $261408.17 — $2644Z7.06 — $267584.68 —- $270931.76 — $274479.67 $175527.98 —-$168644.53 — $161761.08 $154877.63 $147998.18 —$141110.73 $83109.92 —-$92803.68 $102665.98 — $112707.06 — $122937.59 — $133368.98 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $265202.60 ($82092.08) — $92803.64 $102665.98 $1127707.06 $122937.59 — $1393368.98 ($37762.72) $42689.68 = $47226.33 — $51845.25 = $56551.29 $61349.71 ($37762.72) $42689.68 = $47226.35 -$51805.25 © $56351.29 —-$61349.71 ($37762.72) $42689.68 $4726.95 $51845.23 $56551.29 —$61349.71 _ $296400.62 — $218756.49 = $217200.71 $215799.48 = $214380.47 —$213129.95 $175527.98 $168644.53 $161761.08 $154877.63 $2a7990.18 —$241110.73 $68834.50 — $68834.50 _ $68834.50 -$68834.50 $68834,50 $688 58.50 $344172.50 — $413007.00 -$481841.50 — $550676.00 $619510.50 — $688345.00 $724.61 $768.09 $814.18 $863.03" $914.81 $969.70 $2661.52 $3429.61 $4243.78 $5106.81 $6021.62 $6991.32 $52038.18 ($.18720.53) ($19994.87) ($7972.69) (82088.20) «$9184.73 Exhibit 7,4.6 Revenue Requirements 1 (NPV = 0) Alternative C 6T-7°L ¥ 1986 Y 1987 Y 1988 Y 1989 ¥ 1990 Y 1991 Y 1992 ¥ 1993 v 1998 ¥ 1995 Y 1996 Y 1997 Y 19s Capitel Required Total $2212537.50 fn Outlay $0.00 $2939662.50 “int $175350.00 $185871.00 — $197023.26 — $208848.66 — $221375.33 $234657.86 — $24B737.33 — $263661.57 $779081.26 — $296250.14 Capacity $268100.00. $268100.00 $268100.00 $268100.00 — $268100.00 $268100.00 © $268100.00 $268100.00 —$288100.00 — $266100.00 Total $443450.00 $453971.00 $465123.26 $4 76944.66 — $489A75.33 — $502757.86 — $516837.33 $531761.57 $547581.26 $56350.18 Openses : om $100000.00 $106000.00 $112360.00 $119101.60 $126247.70 — $193822.56 $141851.91 $150363.03 $159384.61 $168947.90 Prop. Tks. $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 . $0.00 Int. on Work Cap $1400.00 $1484.00 $1573.04 $1667.42 $1767.47 $1873.52 $1985.93 $2105.08 $2231.99 $2565.27 ” Saptotal $101400.00 $107484.00 —$1139933.08 = $120769.02 — $128015.16 — g155496.07 $183837.88 $152468.11 $161616.19 $171313.17 . Inc, $342050.00 $346487.00 —- $351190.22 -$356175.63 $361460.17 1.78 . . . ieee oe Bee BE EEE ems une sme wenn qonen suse . T . . 5 . \< 1.06 2 . . . Int. Expense ($365762.98) | (3594713-06) (336708447) ($340773.68) $129143.73 Sisgarocrs Spwseceo SeoaseeaG | Suagelaega | $izuess..3¢ State Tx. ($95016.12) ($43416.44) — ($40467.29) ($37485.10) — $14205.81 —g17255.75 = g705a2.72 —«$23868.85 $26636.51 $29848.21 red. tm ie. eens) checoaly 90) aseses.o7) (qeszziacis) —{s47ess-27) ed. Tx. Inc. 399.150. ° 2 5 ° 2664.91 67678. $199010. $21s681. \. Feds tex (3183609.03) ($903700.08) ($209937.35) ($1605.20) (Szanis.26) *yaze6a-22 Sreve7e.0z $197010-43 $riscal.ze $2a710.05 11 $221253.75 WR. Fed. Tr. ($404862.78) ($303700.08) ($209937.55) ($116045.20) ($22015.26) $65625.86 $7131.62 $68784.60 © $100593.99 — $112567.01 Tot. Inc. Tx. ($499878.90) ($347118.52) ($250408.84) ($159530.31) ($7809.43) $azanl.ea $97070.61 —-$112253.68 © $127279.90 $142015.23 After Tax Inc. $841928.90 $693605.52 $601595.06 $509705.94 $369269.62 $284180.18 —$775528.88 —$267099.82 —-$258733.16 — $250621.74 Int. Bwp.-LT $320817.94 $298692.56 $276567.19 $254AA1.81 $232316.48 $210191.06 — $188065.69 — $165940.31 —$143810.94 —-$.121689.56 Dept Repayment, $147502.50 $147502.50 $147502.50 $147502.50 $147502.30 $147502.50 —$147502.50 —$147502.50 $147502.50 —$147502.50 Gm. Repayat $147502.50 $295003.00 $442507.50 $390010.00 = $737512.50 $885015.00 $1032517.50 $1180070.00 $1327527.50 $1475025.00 Inc Work Cap $0.00 $608.40 $644.90 $683.60 $724.61 $768.09 $814.18 $863.03 $914.81 $969.70 Que Work Cap $0.00 $608.40 $1253.30 $1936.90 $2661.52 $3429.61 $4243.78 $5106.61 $6021.62 $6991.32 Rec Work Cap Pec Land Omer's Cah Flo $0.00 ($727125.00) $373608.46 — $247A10.45 = $177525.37 —- $107761.63 — ($10549.91) ($739515.42) ($60083.31) ($46403.00) ($92862.28) ($18570.32) Nat PY $150.06 Prof. Indx(B/C) 1.00 O2-v°Z POWCOST OCTOBER 19, 1984 THERMAL ASSUMPTIONS INFLATION RATE (8) FINANCING TERM, HYDRO (YRS) FINANCING TERM, DIESEL (YRS) INTEREST RATE (x) YEAR . INFLATION ADJUSTMENT MULTIPLIER NEW DIESEL CAPITAL COST (1984 $000) PRIME UNITS ‘STANDBY UNITS NEW HYDRO CAPITAL COST (1984 $000) OM COSTS (1984 $000) FUEL COSTS (1984 $000) NEW DIESEL CAPITAL COST (NOMINAL $000) CUMULATIVE CAPITAL COST NEW DIESEL DEBT SERVICE ($000) NEW HYDAD CAPITAL COST (NOMINAL $000) CUMULATIVE CAPITAL COST CAPITALIZED INTEREST ($000) NEW HYDRO CAPITAL REQUIREMENT ($000) NEW HYDRO DEBT SERVICE (9000) 08M COSTS (NOMINAL $000) FUEL COSTS (NOMINAL $000) SNETTISHAM NET GENERATION (Gah) SWETTISHAM WHOLESALE RATE (8/Mwh) SNETTISHAM POWER COST ($000) ADJUSTED OPERATING COST (1984 9000) ADJUSTED OPERATING COST (NOMINAL $000) INTEREST EXPENSE REVENUE REQUIREMENTS ($000) SALES FORECAST (Gh) POWER COST FORECAST (CENTS/Kwh) 6.00 10.00 coo 173 1538 176 8176 8176 2049 16336 2s 1985 1.06 176 c-) 4400 6176 8667 2049 coo ooo aoa 4190 176 8176 9187 2069 16448 20297 ese 7.60 7.99 6.39 1987 1.19 Poe & eco 5 coo 605 ‘S371 176 8176 9738 2049 22163 8.76 cocoooo coooo coooco coo coo co Sail) heli Mloceee o coo coo co coco ZnB oo JUNEAU 20-YEAR PLANNING STUDY POWER COST FORECAST (NOMINAL CENTS/KWH) 1992 1993 199 1995 1996 1997 1.59) 1.69 (1,79 1.90 201 213 0 0 0 0 0 o 0 236 2305 0 236 ° 0 0 0 o 4M 12 28 «St | 6883 Se 1299 2120, W931 4977 0 0 4130 4376 0 4919 o 0 4130 8505 8505 13424 0 0 85 999) «999 «1577 o 0 0 0 0 0 0 o 0 0 0 0 0 o 0 0 o 0 6 213° 39 59 761 1030 B64 2195 379757317970 10616 280 280 280 BO OB f=] 3 3 2s 3 3 7000 7000 «7000 «7000 «7000 «7000 8176 «8176 «B176 8176 B176 «8176 13031 13813 14642 15520 16452 17439 2049 2049 «2049 2089 2049-2049 23030 25270 28363 31890 35231 39710 2S ws 2 St 30 3 7.81 8&3 9.09 9.93 10.68 11.71 2000 «2001 25 269 285 Oo 4116 2060 Oo 20 Te 850 3858 11083 24806 35889 2914 «4216 coo coo 15.41 16.89 | o eco 2 3 a § & GSdne § Exhibit 7.4.7 2002 2003 «2004 «2005 2006 «2007 2008 «2009-2010 340 360 3.82 4.05 4.29 4.55 0 o 0 4116 0 6276 0 0 see 0 2306 0 0 0 o 0 0 1037 1097 10971171 1171184 12667 12667 12667 12401 12401 11692 2x51 0 0 34005 0 39052 66378 66378 66378 120383 120383 159435 7737-1137 TTST 14140 14140 18727 ° 0 0 0 0 ° 0 0 0 ° 0 ° 0 0 o 0 0 0 0 ° ° 0 0 0 3729-3953 4190 4741 5026) 5386 43062 45646 48385 Sel! 53223 53191 280 280 2828 BO 2 3 3 3 3 3 r-) 7000 7000 7000 7000 7000 7000 8176 8176 8176 8176 8176 8176 27795 29463 31230 33104 35090 37196 2049 2009 2009 204920492049 91432 95907 100651 111245 116529 123530 wo ow oT oT 23.03 24.16 25.35 28.02 29.35 31.12 Té-v°L Powcost OCTOBER 19, 1984 DOROTHY 1993 ASSUMPTIONS INFLATION RATE (%) FINANCING TERM, HYDRO (YRS) FINANCING TERM, DIESEL (YRS) INTEREST RATE (x) YEAR INFLATION ADJUSTMENT MULTIPLIER NEW DIESEL CAPITAL COST (1984 $000) PRIME UNITS STANDBY UNITS NEW HYDRO CAPITAL COST (1984 $000) WM COSTS (1984 $000) FUEL COSTS (1984 $000) NEW DIESEL CAPITAL COST (NOMINAL $000) CUMULATIVE CAPITAL COST NEW DIESEL DEBT SERVICE ($000) NEW HYDRO CAPITAL COST (NOMINAL $000) CUMULATIVE CAPITAL COST CAPITALIZED INTEREST ($000) NEW HYDRO CAPITAL REQUIREMENT ($000) NEW HYDRO DEBT SERVICE ($000) O&M COSTS (NOMINAL $000) FUEL COSTS (NOMINAL $000) SNETTISHAM NET GENERATION (Geh) SNETTISHAM WHOLESALE RATE ($/Mwh) SNETTISHAM POWER COST ($000) ADJUSTED OPERATING COST (1984 $000) ADJUSTED OPERATING COST (NOMINAL $000) INTEREST EXPENSE REVENUE REQUIREMENTS ($000) SALES FORECAST (Gwh) POWER COST FORECAST (CENTS/Kwh) 6.00 10.00 1984 1.00 coo Biewe coco 173 1538 176 8176 8176 2049 16336 en 7.60 176 8176 (8667 LA 1.12 ialel| ete Beale 472 4190 176 8176 9187 2049 8.39 1987 1.19 - S8oco ecco coo 605 3371 176 6176 9738 2049 22163 8.76 1.26 le he Ne Bictee 47 6643 176 3 8176 10322 2049 24162 262 9.22 1989 1.34 occoceo 6176 10941 2049 19990 ere 1.3 coo 24677 24677 2468 ° 7000 6176 11598 20647 7.40 JUNEAU 20-YEA2 PLANNING STUDY POWER COST FORECAST (NOMINAL CENTS/KWH) 1991 1992 1993 1994 1995 1996 1997 1.50 159 1.69 1.79 1.90 2.01 213 0 0 ° 0 0 0 0 0 0 0 0 0 0 0 32525 25717 ° 0 0 0 ° 0 4 WS HW WS WS o SMe 0 0 0 0 0 0 0 0 0 0 0 0 0 ° 0 0 0 0 o 0 0 0 0 0 0 0 48906 40989 0 0 o 0 0 73582 114571 LIAS71 114572 114571 114571 114571 7358 11457 0 0 0 0 0 135854 14087 14087 14087 14087 14087 0 6 SIS 545 579) (614 65 0 B64 0 0 0 0 0 280 «280 80 B80 80 2B 280 3 t=) 25 25 2 23 235 7000 ©7000 «7000 «7000 «7000 «7000 §=7000 6176 8176 8176 8176 8176 8176 6176 12294 13031 13813 14642 15520 16452 17439 2049 2049 «2049 2049 2049 2049 2089 21343 23030 37464 38324 39235 40201 41225 26 HCHO He LHD 7.46 7.81 12,36 12.28 12.22 12.18 12.16 2.26 es coo 0 114571 0 14087 690 7000 6176 16485 2049 42310 MT 12.19 1999 2000 2.40 we ee o £88 o8oR. o 114571 114571 0 0 14087 14087 818 0 0 280 235 7000 8176 20770 2049 45ai2 366 12,17 12.41 Exhibit 7.4.8 2001 «2002 = 2003 2.69 285 3.03 ° o 0 0 0 2305 "0 0 0 ee Re Ww 0 ° 0 o 0 6974 5858/5858 12832 688 «6881507 0 o 0 MAS71 114571 114571 0 0 ° 14087 14087 14087 867 9191029 0 0 o 280 280 280 3 Fa) 3 7000 7000 «7000 6176 «8176 =B176 22016 «23337 24737 2049 2049-2049 46707 48080 30409 76 wT 12,42 12.42 12.70 2004 «2005 «2006 «= 2007 R21 340 3.60 3.82 0 0 0 0 0 6917 0 0 0 0 0 0 wo 32 «2 32 0 0 0 0 0 23515 0 0 12832 36347 %37 %HT 15307 4269 4269 4269 o o o ° (14571 114571 114571 114571 0 0 0 0 14087 14087 14087 14087 1090 1333) 14131497 0 0 0 0 280 BO 280 RO c=) 3 2 3 7000 ©7000 «7000 7000 6176 «8176 «8176 = 8176 26222 27795 29463 31230 2049 2049 2049-2049 SI9SS 36532 58280 60133 7 3 OT 13.09 14.24 14.68 15.15 2008 «2009-2010 4.05 4.29 4.55 9752 9752 12216 0 0 0 14571 114571 114571 ° 0 ° 14087 14087 14087 1943 2060 «2343 0 0 0 280 280280 En] 3 3 7000 «7000 «7000 8176 «6176 «8176 33104 35090 371% 2049 2049 2049 67935 70038 74890 7 oT OT 17.11 17.64 18,86 2e-b°L POWCOST OCTOBER 19, 1964 DOROTHY = 1996 ASSUMPTIONS INFLATION RATE (*) FINANCING TERM, HYDRO (VRS) FINANCING TERM, DIESEL (YRS) INTEREST RATE (2) YEAR INFLATION ADJUSTMENT MULTIPLIER NEW DIESEL CAPITAL COST (1964 $000) PRIME UNITS STANDBY UNITS NEW HYDRO CAPITAL COST (1984 $000) O48 COSTS (1984 $000) FUEL COSTS (1984 $000) NEW DIESEL CAPITAL COST (NOMINAL $000) CUMULATIVE CAPITAL COST NEW DIESEL DEBT SERVICE (#000) NEW HYDRO CAPITAL COST (NOMINAL $000) CUMULATIVE CAPITAL COST CAPITALIZED INTEREST ($000) NEW HYDRO CAPITAL REQUIREMENT ($000) NEW HYDRO DEBT SERVICE ($000) O8M COSTS (NOMINAL $000) FUEL COSTS (NOMINAL $000) SNETTISHAM NET GENERATION (Gwh) SNETTISHAM WHOLESALE RATE ($/Mwh) SNETTISHAM POWER COST ($000) ADJUSTED OPERATING COST (1984 $000) ADJUSTED OPERATING COST (NOMINAL $000) INTEREST EXPENSE REVENUE REQUIREMENTS ($000) SALES FORECAST (Gh) POWER COST FORECAST (CENTS/Kwh) 6.00 10.00 coo coo 173 1538 176 8176 8176 2049 16336 7.60 18448 231 1.9 1.12 coo coo a8ec5 4190 176 8176 9187 2049 ese 6.39 1987 1.19 ag o ooo coo coo 605 5371 176 8176 9738 2049 22163 8.76 cco coo B8oce 47 6643 176 8176 10322 24162 9.22 1989 1. cocooco coo Pt 8176 10941 ee 1990 1.42 ecco Coo Co eoce co 8176 11598 2049 20647 7.40 1991 1.50 coo ooo Coo oe oo 7.46 JUNEAU 20-YEAR PLANNING STUDY POWER COST FORECAST (NOMINAL CENTS/KWH) 1992 1993 1994 1995 1996 1.69 1.79 1.90 2.01 173% 126 1299 34831 218 2120 28023 uu 3019 Bice s etmec co 0 0 coo 0 0 0 ° coo 0 62377 531% ° 9177 14496 0 171573 17791 390 «59064 37975731 0 280 3 7000 6176 14642 280 35 7000 8176 15520 2049 2049 23030 25270 27878 30891 33) 2 Bt 7.81 834 8.94 9,62 13.33 e8ecco 1997 2.13 coo 0 91767 144963 144963 144963 0 17791 725 0 280 3 7000 6176 17439 2049 45004 339 13.28 2.26 2.40 eofcce coo coo 0 0 144963 144963 0 ° 17791 17791 79 = «BIS 0 0 280 280 3 25 7000 ©7000 8176 «8176 16485 19594 2049 2049 46093 47249 47 357 13,28 13.23 2000 2001 2.54 2.69 2.85 o8cce e8cce alto ore coo cco coo 0 0 0 144963 0 0 o 17791 17791 970 0 ° 280 r=] 7000 8176 23337 2049 2049 48473 49771 SiL47 6 376 AT 13.24 13.24 13.22 3.03 stdeo coo Exhibit 7.4.9 3.21 144963 144963 144963 17791 17791 1029 0 280 25 7000 8176 1090 0 280 3 7000 8176 24737 26222 32606 54152 37 397 R25 13.64 17791 17791 277195 29463 58729 60477 14.79 15.23 2002 2003 «2004 «2005 2006 «2007 2008 2009 2010 340 3.60 3.62 4.05 4.29 4.55 0 0 0 0 0 6917 0 O 11528 0 611 ° ° 0 ° ° 0 Be 682 82 BOSS 0 0 0 o ° 0 23515 0 0 46676 0 20977 23515 23515 23515 70191 70191 91168 2762 «2762 «2762 «8245 = B24S «10709 o 0 o 0 0 0 144963 144963 144963 144963 144963 144963 0 0 0 0 0 0 17791 17791 17791 17791 1333, 14131497) 1943 2060-2343 ° 0 0 0 0 0 280280 2 cn] 7000 = 7000 8176 8176 280 3 7000 8176 31230 280 280280 25 3 3 7000 «7000 ©7000 8176 «8176 = B176 33104-35090 371% 2049 «2049 2049) 2049 2049 2089 62329 70132 72235 77087 m7 3 Tl OT 15.70 17.67 18.20 19,42 0545C APPENDIX 7.5 PLANNING MODEL PLANNING MODEL As part of the planning study, a microcomputer-based planning model was developed. This model provides a means for the sponsors to update the results of the planning study, to run several alternate cases or to change the planning criteria. 1.0 DEVELOPMENT OF THE MODEL The model was developed using the electronic spreadsheet called MULTIPLAN on an IBM PC microcomputer. The minimum required computer system configuration is a computer with two disc drives, a monochrome monitor, 132 column printer, and 128K memory. However, more memory (256K) is recommended for fast, efficient operation. In order to properly perform the planning function, it was necessary to develop a model which would consider all existing resources, their retirement schedule, capacities, and retirement dates; projects currently committed for construction; energy demand and peak load forecasts; transmission losses from out of area resources; in-system transmission and distribution losses; potential projects with their costs and operating parameters; and the overall system economic analysis which will result from applying various planning scenarios. The overall model with the various model components (spreadsheets) and their relationships is shown in the model flow diagram, Figure 7.5-1. On this flow diagram, the boxes represent separate MULTIPLAN spreadsheets, each of which is an integral part of the model. The two active spreadsheets which are used to run the model are the capacity planning spreadsheet CAPPLAN and the economic analysis spreadsheet ECONANAL. These two spreadsheets were developed as the core of the model with one other group of sheets actively interfacing with a user. These are the alternate projects spreadsheets, which are an inventory of potential projects which the user manually interfaces to CAPPLAN and ECONANAL. Other supporting spreadsheets which were developed were the existing hydro projects sheet HYPRO, the existing thermal projects spreadsheet THERPRO, and the loss calculation sheet called JUNLOSS. The results of running the model are output to a summary spreadsheet called JUNPLAN. Detail descriptions of the spreadsheets are presented in Section 2.0, the flow of information among spreadsheets in Section 3.0, use of the model (spreadsheets) in Section 4.0, and a generic description of the output in Section 5.0. 2.0 SPREADSHEET DESCRIPTIONS 2.1 CAPACITY PLANNING - CAPPLAN The CAPPLAN spreadsheet is shown as Table 7.5-1. There are some formatting and notation characteristics used which are common to all of 0545C 7.5-1 e-3°L *UPDATES & CHANGES* HYPRO Based on existing and committed projects, calculates total available hydroelectric capacity and energy. @ AVAILABLE EXISTING HYDRO CAPACITY *PEAK LOAD AND > ! | NEW RESOURCE ADDITIONS, Ucapacity, | LOCATION j& LIFE © CAPPLAN Compare system capacity to or + PROJECT STUDIES, CONCEPTUAL DESIGNS, COST ESTIMATES, ETC.+ ALTERNATIVE PROJECTS Listing of alternate projects with technical and economic data for user selection and input to the model spread sheets. l & AVAILABLE ENERGY FROM EXISTING HYDRO PROJECTS” NEW RESOURCE { ADDITIONS I ENERGY GENERATION, CAPITAL COST, ! LEGEND —— DENOTES EXOGENOUS INPUT — > DENOTES MANUAL SPREAD SHEET LINK DENOTES AUTOMATED G) SPREAD SHEET LINKAGE (EXTERNAL) + DENOTES EXOGENOUS INPUT FROM NON-UTILITY SOURCE * DENOTES EXOGENOUS INPUT FROM UTILITY SOURCE INDIVIDUAL | ! O&M COST, | PROJECT SELECT FUEL COST, PARAMETERS | tprovects LIFE ! NN ! ‘\ 1 TOTAL GENERATION ! CAPACITY MIX, | AND CAPACITY SYSTEM © REQUIREMENTS costs, CAPITAL ECONANAL REQUIREMENTS Dispatch generating resources and calculate system costs. @4© [E— “ENERGY SALES FORECAST* e— *Economic ANALYSIS PARAMETERS* AVAILABLE CAPACITY SYSTEM FROM EXISTING ENERGY THERMAL LOSSES PROJECTS ENERGY REQUIREMENTS RESERVE requirements» | --——— — Ser REQUIREMENTS* ord deteenine (~~ — a reserve margins. CAPACITY ADDITIONS AND TIMING AVAILABLE JUNPLAN EXISTING © ® Summary of THERMAL completed alternative CAPACITY plan; power, energy, and costs SYSTEM CAPACITY DEMAND THERPRO Based on present JUNLOSS configuration and Talculat i planned additions, ad enavgy Tosses @ calculates total within’ the Juneau available thermal ® Area Distribution capacity. — _—_ System E cvvonces & CHANGES* + LOAD FLOW STUDY RESULTS + JUNEAU AREA 20 YEAR POWER SUPPLY PLAN PLANNING MODEL DATE NOV 1984 | FIGURE 7.5-1 EBASCO SERVICES INCORPORATED c-aL ~ CLCOND OSwnre ee one 14 15 16 7 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 Capolan OCTOBER 18, 1964 BASE CASE THERMAL YEAR RESOURCES AS OF 1984 > Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Committed Hydro Resources North of Taku Inlet ) Existing and Committed Thermal Resources (All North of Taku) Total Existing and Committed Net Resources South of Taku Inlet thru Thane Total Existing and Committed Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transmission Losses) DEMAND ( Peak Demand Reserve Requiresents (Eoual to Peak Demand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet (Capacity as measured at Thane) Hydro North of Taku Inlet Thermal North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS Hydro north of Taku Hydro south of Taku Thermal (North of Taku) RESERVE REQUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TOTAL CAPACITY JUNEAU 20 YEAR PLAN Table 7.5-1 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.76 71.78 5.62 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 862 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 38.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21.12 21.12 8.62 110.5 125.6 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 55.1 57.9 60.3 62.6 64.8 66.6 68.5 70.4 72.4 74.4 76.5 78.6 80.7 82.9 85.2 87.5 89.9 92.3 9.8 4.8 4.8 9.8 94.8 4.8 4.8 94.8 35.5 46.5 49.3 51.7 54.0 56.2 56.0 59.9 61.8 63.8 65.8 67.9 70.0 72.1 743 76.6 78.9 61.3 83.7 86.2 86.2 86.2 86.2 B6.2 66.2 86.2 86.2 23.2 24.7 21.9 183 16.0 12.6 10.8 5.4 35 0.4 -6.6 8.7 -12.0 -14.1 -16.3 -21.1 -25.9 -28.3 -30.7 -33.2 -33.2 -50.7 -50.7 -50.7 -73.7 -73.7 -86.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 00 0.0 0.0 00 0.0 0.0 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 00 00 0.0 0.0 0.0 00 0.0 0.0 00 00 00 00 00 50 50 00 50 00 50 50 50 00 50 0.0 15.0 0.0 0.0 25.0 0.0 15.0 0.0 0.0 00 0.0 0.0 00 00 0.0 0.0 00 50 50 00 50 00 50 5.0 5.0 00 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 5.0 10.0 10.0 15.0 15.0 20.0 25.0 3.0 3.0 35.0 35.0 50.0 50.0 50.0 75.0 75.0 90.0 5.82 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 6.62 8.62 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 1.78 71.78 71,78 71.78 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 68 73 73 75.5 78 63 63 68 68 85.5 85.5 85.5 67.5 87.5 35.48 46.48 49,28 51,68 53.98 56,18 57.98 59.68 61.78 63.78 65.78 67.88 69.98 72,08 74.28 76.58 78.88 81.28 83.68 86.18 86.18 86.18 86,18 86.18 86.18 86.18 86,18 23.2 26.7 21.9 18.3 16.0 126 10.8 54 35 04 -1.6 1.3 -2.0 0.9 -1.3 -L1 -0.9 1.7 -07 1.8 1.8 07 0.7 07 1.3 13 3.8 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 144.5 149.5 148.4 153.4 153.4 155.9 156.4 163.4 163.4 168.4 168.4 165.9 165.9 165.9 167.9 167.9 170.4 a the spreadsheets. These include: the name of the spreadsheet in the upper left-hand corner; the date the spreadsheet was last worked on immediately under the spreadsheet name; the actual plan alternative is to be entered in the title block, i.e., BASE CASE, ALL HYDRO CASE, etc.; the years of the plan are horizontal at the top; the specific items addressed are listed vertically at the left; and lastly, the > (greater than) symbol indicates the data in that row is provided externally from another spreadsheet while the < (less than) symbol indicates data which is sent through an external link to another spreadsheet. A line by line description of the data which is included in the CAPPLAN spreadsheet follows: Row 12 - Existing and Committed Net Hydro Resources South of Taku Inlet Through Thane This line lists the net total existing or already committed capacity available by transmission from generating sources south of Taku Inlet. These capacities as listed are the net capacities available to the Juneau area distribution system. That is, the transmission losses to Thane and the transformer losses at Thane have already been deducted. This places these resources on an equal basis with resources which generate within the Juneau distribution area. The resources included are Snettisham, which is already operating, and Crater Lake which will come on line in 1989. Row 14 - Existing and Committed Hydro Resources North of Taku Inlet Here the total dependable capacity of hydro resources north of Taku Inlet, essentially those within the Juneau area, are listed. These are total capacity available within the system; transmission and distribution losses outside the geographical boundary of the system are already accounted for. This is consistent with capacity demand figures which are given as total capacity required to the distribution system. The resources included here are Salmon Creek, Gold Creek, and Annex Creek. Row 16 - Existing and Committed Thermal Resources These are the diesel and combustion turbine resources currently owned and operated by AEL&P and GHEA as well as those already committed for installation by AEL&P. All of these resources are north of Taku Inlet, within system boundaries, and the capacities are, therefore, gross capacities available to the Juneau area system. The sites included are Lemon Creek, Gold Creek, and GHEA. Row 18 - Total Existing and Committed Net Resources South of Taku Inlet Through Thane 0545C 7.5-4 Row 20 - Total Existing and Committed Resources North of Taku Inlet This is the sum of the hydro and thermal resources listed in Rows 14 and 16 above. Row 23 - Existing and Committed Resources as of 1984 The total capacity available to the Juneau distribution system from existing or committed to construct resources is listed on this line. Row 27 - Peak Demand This is the forecast annual peak demand on the Juneau area system. It includes local transmission and distribution losses but does not include transmission losses from remote projects to the Juneau area. This places demand on the same basis as the resource total calculated above. The source for the demand is the Alaska Power Administration 1984 forecast. Row 29 - Reserve Requirements The reserve requirements are calculated on the basis of being able to satisfy all demand with resources north of Taku Inlet. Current policy is that reserve in general will be thermal, and specifically will be maintained at a level equal to the total demand less the hydro existing north of Taku Inlet. That is, no resources south of Taku can be considered as reserve and the worst case assumption is that all ties to resources south of Taku are lost while the hydro plants north of Taku are still available. This is numerically the difference between Rows 27 and 14. Row 32 - Existing Reserve Margin This line is the difference between Rows 16 and 29, Existing and Committed Thermal Resources and Reserve Requirements. As such, it indicates whether the required reserve capacity exists. A positive number in this row indicates that excess capacity exists in a given year, while a negative number indicates a capacity shortfall. Row 36 - Hydro South of Taku Inlet Row 38 - Hydro North of Taku Inlet Row 40 - Thermal North of Taku Inlet Under the general heading of New Resources Additions, these three lines are a primary user interface with the model. In those years that a negative value exists in Row 32, the user should select for insertion in the appropriate row, from the Alternate Projects, a project or projects which best meet economic criteria and whose capacity when 0545C 7,5-5 added in Row 42, Total Annual Added Capacity, most closely equals the absolute value of the negative number in Row 32. This is repeated for each year, beginning with the first year a negative value appears, being sure to recalculate the spreadsheet totals before proceeding to the next year. Row 42 - Total Annual Added Capacity As discussed above, this is the sum of Rows 36, 38, and 40 on an annual basis. Row 44 - Cumulative Added Capacity In each year, this is the total of all preceding years and the current year from Row 42. Row 46 - Totals After Additions Row 47 - Hydro North of Taku Inlet Row 49 - Hydro South of Taku Inlet Row 51 - Thermal (North of Taku Inlet) These three lines, Rows 47, 49, and 51, give the cumulative total of existing and added capacities for the three categories in each year of the study. Row 53 - Reserve Requirements After Additions This line is the new resulting reserve requirement in a given year. It is different from Row 29 only if new hydro capacity north of Taku Inlet has been added. Row 55 - Reserve Margin After Additions This is the resulting measure of how closely actual reserves meet required reserves. A zero value would indicate a perfect match. Row 57 - Resulting Total Capacity This is, for each year, the total capacity available to the system after the addition of new capacity, if any, to meet demand. It is the sum of Rows 23 and 44. 2.2 TRANSMISSION AND DISTRIBUTION - JUNLOSS The transmission and distribution spreadsheet consists of 12 lines with the columns corresponding to the forecast years. The spreadsheet is shown as Table 7.5-2. 0545C 7.5-6 LS: 1 JUNLOSS 2 OCTOBER 18, 1984 3 : BASE CASE 6 Table 7.5-2 7 LOCAL SYSTEM LOSSES 8 9 10 ~—s YEAR 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 199 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 ll 12) PEAK DEMAND (Ma) 41.3 55.1 57.9 60.3 62.6 64.8 66.6 68.5 70.4 72.4 744 765 78.6 80.7 829 €5.2 87.5 89.9 92.3 9.8 94.8 %.8 6 94.8 94.8 8.8 94.8 13 14) ENERGY SALES (Gh) 215.1 230.6 242.4 252.6 262.4 271.5 279 286.9 295 303.3 311.6 320.6 329.3 338.2 347 356.8 366.4 376.3 36.5 397 397 #397 397 «397 «37 3 OT 15 16 LOAD FACTOR 0.59 0,48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0,48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 17 18 LOSS FACTOR 0.39 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 19 20 69KV CAPACITY LOSS (Mw) 0.46 0,82 0.91 0.98 1.06 1.13 1.20 1.27 1.36 142 1.49 1.58 1.67 1.76 1.86 1.95 2.07 2.18 230 2.43 243 2.43 2.43 243 2.43 2.43 2.43 21 22 + 69KV ENERGY LOSS (Gwh) 1.58 1.93 213 231 2.49 267 2.62 298 315 3.33 3.52 3.72 3.93 414 4.36 4.61 4086 5.13 5.41 5.71 S71 S71 S71 S72 5.71 S71 5.71 23 24 FEEDER CAPACITY LOSS (MW) 1.63 255 2.70 264 29 309 3.19 3.30 3.41 3.53 365 3.77 3.90 4.03 417 4.31 4.45 4.61 4.76 4.93 4.93 4.93 4.93 4.93 4.93 4.93 4.93 25 26 FEEDER ENERGY LOSS (Gwh) 10.55 12.84 13.55 14.17 14.76 15.32 15.79 16.28 16.78 17.30 17.84 16.39 18.95 19.52 20.10 20.73 21.35 22.01 22.67 23.37 23.37 23.37 23.37 23.37 23.37 23.37 23.37 27 28 JUNEAU CAPACITY LOSS (Mw) 2.29 3.37 361 3.82 4.02 422 4.39 4.57 4.75 4.95 5.14 5.35 5.57 5.79 6.02 6.27 6.52 679 7.06 7.35 7.35 7.35 7.35 7.35 7.35 7.35 7.35 29 30 JUNEAU ENERGY LOSS (Gwn) 12.13 14,77 15.68 16.48 17.25 17.99 18.61 19.26 19.93 20.64 21.36 22.11 22.88 23.66 24.46 25.34 26.21 27.13 28.08 29,08 29.08 29.08 29.08 29.08 29.08 29.08 29.08 31 32( JUNEAU CAPACITY LOSS (%) 5.55 6.12 623 6.33 6.43 6.52 6.59 6.67 6.75 6.83 6.91 7.00 7.09 7.17 7.26 7.36 7.45 7.55 7.65 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 33 34( JUNEAU ENERGY LOSS (x) 5.64 6.40 6.47 6.52 6.57 6.63 6.67 6.71 6.76 6.00 665 6% 695 7.00 7.05 7.10 715 721 727 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 Row 12 - Peak Demand This line is the forecast peak system demand in each year. It is automatically transferred from the CAPPLAN spreadsheet. Row 14 - Energy Sales This row is the annual forecast energy sales, transferred from the ECONANAL spreadsheet. Row 16 - Load Factor This row is calculated from Rows 12 and 14. It is the ratio of average load of the system in MW to the peak demand. Row 18 - Loss Factor This line shows the loss factor, which is calculated as: (loss factor) = 0.16 x (load factor) x 0.84 x (load factor)2 Row 20 - 69 kV Capacity Loss and Row 24 - Feeder Capacity Loss The losses occurring at capacity (peak) loading are calculated and entered into Row 20 for the 69 kV transmission system and into Row 24 for the feeders (distribution system). Row 22 - 69 kV Energy Loss and Row 26 - Feeder Energy Loss Using the loss factors, the annual energy losses are calculated. For series (12R) losses, the formula energy losses/year = 8,760 x (loss factor) x (capacity loss) is used. Sources of parallel (constant) losses are assumed to be energized all year around. Row 28 - Juneau Capacity Loss The total capacity loss, this row is the sum of Rows 20 and 24. Row 30 - Juneau Energy Loss The total energy loss, this is the sum of Rows 22 and 26. Row 32 - Juneau Capacity Loss (%) This is Row 28, capacity losses, calculated as a percent of total capacity. This is an external link to CAPPLAN. 0545C 7.5-8 Row 34 - Juneau Energy Loss (%) This is Row 30, energy losses, calculated as a percent of total energy sales. This is an external link to ECONANAL. 2.3 SUMMARY OF EXISTING AND COMMITTED THERMAL PROJECTS - THERPRO The existing thermal projects spreadsheet, THERPRO, is shown in Table 7.5-3. Notation and formatting conventions are the same as those described in paragraph 2.1 for the CAPPLAN spreadsheet. The data entered on THERPRO is described below: Rows 13 through 23 - Lemon Creek No. 1 Through Lemon Creek No. 11 Data is listed for the four GM diesels, two gas combustion turbines, and 5 EMD diesels at Lemon Creek. The pertinent data are the capacity, on-line year, and retirement year for each unit. The capacity available from each unit for each year is also listed. Rows 25 through 29 - Gold Creek 1 Through Gold Creek 5 For the five existing diesels at Gold Creek, these lines are the same data as described above for Lemon Creek. Rows 31 and 32 - GHEA 1 and GHEA 2 Same data as above for Glacier Highway Electric Association single diesel unit and single gas turbine. Row 35 - Total Thermal Capacity This line lists the total in each year for the capacity of the units described in Rows 13 through 32. Planned additions as well as retirements are taken into account. The information from this line appears automatically on CAPPLAN through an external link. Row 38 - Existing Prime Diesel This is the sum of the capacity of those units listed in Rows 3 through 32 which are considered prime capacity rather than stand-by. 2.4 SUMMARY OF EXISTING AND COMMITTED HYDRO PROJECTS — HYPRO The HYPRO spreadsheet performs the same function for existing and committed hydro projects as THERPRO does for thermal projects. That is, it lists all pertinent data, the capacity, type of unit, retirement, and shows capacity in the year available. In addition, this spreadsheet also lists, tracks, and totals the energy available from these projects for the years of the study period. It is necessary to track energy available from these projects and check it against demand in order to determine how much thermal generation will be needed in a given year. The HYPRO spreadsheet is presented in Table 7.5-4. 0545C 7.5-9 OT-s°Z TRERPRO QCTOBER 18, 1984 ~enon Creex t Lemon Creek 2 cemon Creex 3 cemcn Creex 4 Lewon Creek 5 ~emon Creek 6 ceron Creek 7 Lemon Creek 8 Lemon Creex 9 cenon Creek 10 cemon Creex 11 Goid Creek 1 Gola Creex 2 Gole Creek 3 Golc Crees 4 Gole Crees 5 GHEA 1 Grea 2 JUNEAU 20 YEAR PLAN SUMMARY OF EXISTING & COWITTED THERA PROJECTS Capacity Gn-iine (mw) Year 250 13%9 2.50 1969 250 1974 2.50 1963 17.50 1980 17.50 1983 2.50 1985 2.50 1985 2.50 1985 2.50 1985, 2.50 1985 1.25 1952 1.20 1954 3.50 i961 1.14 1963 Lid 1966 3.00 1983 2.50 i575 Coras Trermas Cazacity (%#) (Pi Nortn of (Existino Oriwe Diesel (mW) Taxu) esirenent Year 1994 1994 1999 2008 1384 20 2.50 2.50 2.50 1985 2.50 2.50 2.50 2.50 17.50 17.50 17.50 17.50 0.00 0.00 0.00 0.00 0.00 225 1.20 3.50 1.14 iid 3.00 2.50 2.50 2.50 2.50 2.50 2.50 1.25 1.20 3.50 ila 114 3.00 2.50 1386 2.50 2.50 2.50 2.50 17.50 17,50 2.50 €.50 2.50 2.50 2.50 1 1.20 3.50 1.14 Lie 3.0) 2.50 1987 17.50 17.50 2.50 2.50 2.50 2.50 2H 0.00 1.20 3.50 a4 234 3.00 a Canacity dv Year 1988 1589 1990 250 2.50 20 2.50 17.50 17.50 2.50 2.50 2.59 2.50 2.50 2.5) 250 2.50 2.59 2.50 2.50 €.50 17.560 17.50 2.50 2.50 2.50 2.50 2.50 2.50 17.50 17.50 2.50 2.50 2.50 2.50 2H 0.00 1.20 3.50 14 Lel4 0.00 6.00 3.50 11d ile 0.00 0.09 3.50 214 il4 3.00 2.50 2.50 30 3 1991 2.50 2.50 £59 2.50 17.50 17.50 2.50 2.50 2.59 2.50 250 2 3.00 2.0 1593 2.59 in. 17.50 2.50 2.50 250 @.50 25 0.00 0.00 0.00 0.00 tld 3.00 2.50 0.00 0.00 2.50 250 17.50 17.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0,00 0.00 1.14 3.00 2.50 1995 0.00 0.00 2.5) 2.50 17.50 17.50 2.50 2.50 250 2.50 2.50 0.00 0.00 0.00 0.00 14 3.00 2.50 0.00 0.00 2.50 2.50 1397 6.00 0.00 2.50 2.50 17.50 17.50 17.50 17.50 2.50 2.50 2.50 2 20 0.00 0.00 0.00 0.00 0.00 3.00 2.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0,00 3.00 2.50 0.00 0.00 é.50 250 17.50 17.50 17.50 17.50 17.50 17.50 2.5) 2.50 2.50 2.50 20 0.00 0.00 0.00 6.00 0.00 3.00 20 Table 7.5-3 200i 0.00 0.00 0.00 2.50 0.00 0.00 0.00 2.50 0.00 0.00 6.00 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3.00 2.50 3.00 0.00 3.09 0.00 2002 0.00 0.00 0.00 2.50 17.50 17.50 17,50 17.50 2.50 2.50 2.50 2.50 2.50 0,00 0.00 0.00 0.00 0.00 3.00 0.00 2003 0.00 0.00 0.00 2.50 2004 0.00 0.00 0.00 2.50 17.50 17.50 37.50 17.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 2005 0.00 0.00 0.00 2.50 0.00 17.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 0.0 0.00 0.00 2.50 0.00 17.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 0.00 0,00 0.00 2.50 6.00 17.50 2.50 2.50 2.50 2.50 2.50 0,00 0.00 0.00 0.00 0.00 3.00 0.00 2008 0.00 0.00 0.00 0,00 0.00 0.00 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2009 0.00 0.00 6.00 0.00 0.00 0.00 20 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 98.72 71.62 71.22 63.97 69.97 68.77 63.77 65.27 65.27 64.14 59.14 53.14 58.09 54.00 58.00 55.50 53.00 53.00 53.60 53.00 53.00 35.50 35.50 35.50 12,50 12.50 12.50 25.00 25.00 25.09 25.00 25.00 25.00 25.00 25.00 25.00 20.00 20.00 20.00 20.00 20.00 17.50 15.00 15.00 15.00 15.00 15.00 15.00 15.00 £5.00 12.50 12.50 2010 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 6.00 0,00 0.00 0.00 0.00 0.00 6.00 0.00 0.00 6.00 TtI-s"L OCT 16, 1984 BASE CASE (FIRM ENERGY) Galaon Creek forex Creek Gold Creek # Total Existing Hydro Caacity (M. of Taku) Total Potent ial Hydro Energy (N. of Taku) ‘Srettishas Total Existing Hyoro Caoacity (S. of Taku) Total Potential Hydro Energy (S. of Taku) Salmon Creek Expansion Total Exoanded Hydro Capacity (M. of Taku) SUPRARY OF EXISTING & COMMITTED HYDRO PROJECTS Total Expanded Hydro Potential Energy (N. of Taku) Crater Lake Total New Hydro Capacity (8. of Taku) Total Mew Hydro Energy (8. of Taku) Total Existing & Comitted Hydro Capacity (orth of Taku) ‘Transaission Losses (Mi) (eres Creek) ( Existing and Comitted Hydro Capacity (net of Arex Losses and M, of Taku) Total Existing § Comitted Hydro Caoscity (South of Taku) ‘Transmission Losses thru Thane (8) ( Total Existing and Comitted Hydro Capacity (South of Taku, Met thre Thane) Total Hydro Capacity (mw) (het after: Transainsion Losses) Total Existing 6 Committed Hydro Energy Potential (horth of Taku) ‘Transmission Losses (Bn) (Prnex Creek) Existing and Comitted Hydro Energy Potent ial (Net of Amex Losses and North of Taku) Total Existing & Comitted Hydro Energy Potent ial (South of Taku) ‘Transmission Losses to Thane (1) Total Existing § Committed Hydro Enerey Potential (Met at Thane, South of Taku) (Total Hydro Energy Potential (Gx) (Before Local Lossses) ) Local Transeission Losses (1) Total Hydro Energy Potential (Suh) (After Local Losses) oP, ee Oe ENERGY LIME (Gen) ERR 20 340 3s 20 1.0 0.00 6.70 179.0 3.60 1985, ou 27.00 1989 105.0 (JUNEAU 20 YEAR PLAN Table 7.5-4 Capacity & Energy by Year 1984 1985 1986 1987 1968 1989 1990 1991 1952 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2007 200 2.80 a4 30 22.7 0.00 0.00 0.00 10 2.7 0.00 0.00 0,00 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 6.3 3.50 3500 30 350 15 150 3.50 3.50 250 3.50 3.50 250 350 350 35 150 350 3.50 1.50 3.50 350 3.50 350 150 30 390 32.10 22.70 22.70 22.70 22.70 22,70 22.70 22,70 22.70 22.70 22.70 22.70 22.70 22,70 22.70 22,70 22.70 22,70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 0.00 0.00 Ly» 22.7 0.00 0.00 0.00 LD 22.7 0.00 0.00 0.00 Lm” 2.7 0.00 0.00 0.00 Lm” 2.7 0.00 0.00 0.00 Ls 2.7 0.00 0.00 0.00 Ln 22.7 0.00 0.00 0.00 10 2.7 0.00 0.00 0.00 Ly 2.7 0.00 0.00 0.00 Ls 22.7 0.00 0.00 0.00 oo) a7 0.00 0.00 0,00 iw 22.7 0,00 0.00 0.00 Ls 2.7 0.00 0.00 0.00 350 22.7 0.00 0.00 0.00 3% 2.7 0.00 0.00 0.00 30 22.7 0.00 0.00 0.00 30 2.7 0.00 0,00 0.00 Ln 22.7 0.00 0.00 0.00 Ls” 27 0.00 0.00 0,00 350 2.7 0.00 0.00 0.00 3.50 2.7 0.00 0.00 0.00 Ln 2.7 0.00 0.00 0.00 Ls 2.7 0.00 0,00 0.00 Ly 2.7 0.00 0.00 0.00 bw 2.7 0.00 0.00 0.00 10 a7 0.00 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46,70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46,70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 179.0 179.0 179.0 179.0 179.0 i79.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179,0 179.0 179.0 179.0 0.00 0.00 0.00 0,00 5.60 3.40 3.60 3.40 5.60 30 5.60 9.40 360 9.40 3.60 9.40 5.60 5.60 5.60 5.60 5.60 5.60 5.60 S60 5.60 5.60 S60 S60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 560 560 5.60 9.00 9.40 9.40 9,40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.60 9.40 9.40 9.40 9.40 9.40 9.40 9.40 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 S60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.400 9.40 9.400 9.40 9.400 9.40 9.40 0.00 0.0 0.00 0.00 0.0 0.00 0.00 0.0 0.00 0.00 0.0 0.00 0,00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 0.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 0.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 00 6.0 00 0,0 0.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 6.3 9.10 9.10 910 910 9.10 9.10 9.10 9.10 9.10 9,10 910 9.10 9.10 9.10 9.10 9.10 910 910 9.10 9.10 9.10 910 9.10 9.10 9.10 9.10 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0,48 0.48 0,48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.08 0.48 0.48 0.48 0.48 0.48 0.408 0.48 5.62 6.62 6.62 8.62 862 B62 8.62 6.62 B62 8.62 B62 8.62 6.62 0.62 062 B62 8.62 B62 O62 B62 6.62 O62 O62 B62 B62 6.62 8.62 46.70 46.70 46.70 46.70 46,70 73.70 73.70 73.70 73.70 73.70 73.70 73,70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73,70 73.70 73.70 73.70 1,65 1.65 1.65 1.65 1.65 2.60 2.60 2.60 2.60 2.60 260 2.60 2.60 260 260 260 260 260 260 260 2.60 2.60 260 260 260 2.60 2.60 45.93 45,93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 51.75 54.55 54.55 54.55 5A. 55 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 60.40 80.40 80.40 32.10 32.10 32.10 32,10 32.10 32.10 32.10 32,10 32.10 32,10 32.10 32,10 32.10 32.10 32.10 32.10 32.10 32,10 32,10 32.10 32.10 32,10 32,10 32,10 32.10 32.10 32.10 2.83 2.83 2.83 283 2.83 2.83 2.83 2.83 2.83 2.63 263 283 2.83 2.83 2.83 283 28) 283 203 283 263 283 283 28 28d 283 288 29.27 29,27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 179.0 179.0 179.0 179.0 179.0 284.0 284.0 284.0 284.0 284.0 264.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 1,50 1.50 1,50 1.50 1.50 1,00 1,80 1.00 1.80 1.60 1.80 1,60 1.00 1.00 1.80 1.80 1.60 1.80 1,60 1.00 1.80 1.00 1.60 1.80 1.60 1.60 1.60 176.3 176.3 176.3 176.3 176.3 278.9 278.9 276.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 278.9 205.6 205.6 205.6 205.6 205.6 308.2 308.2 308.2 308.2 308.2 308.2 308.2 306.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 08.2 308.2 308.2 308.2 308.2 5.64 6.40 6.47 6.52 6.57 6.63 6.67 6.71 6.76 6.80 6.85 6.90 6.95 7.00 7.05 7.10 7.15 7.21 7.27 7.32 7.32 7.2 7.3 7.2 7.2 1.2 1B 194.0 192.4 192.3 192.2 192.1 287.7 287.6 287.5 267.3 287.2 287.1 286.9 286.7 286.6 286.4 286.3 286.1 285.9 285.8 285.6 285.6 285.6 285.6 285.6 285.6 285.6 285.6 © Petual installed caacity is 1.6 ¥ retiring in 2004 however none of the caoacity is devendabdle. Rows 14 and 15 - Salmon Creek The annual capacity and energy available from the existing Salmon Creek hydro facility. Rows 16 and 17 - Annex Creek The annual capacity and energy available from the Annex Creek Hydro facility. Rows 18 and 19 - Gold Creek The annual capacity and energy available from the Gold Creek hydro facility. Note that by AEL&P policy, Gold Creek supplies capacity only and is not considered a firm energy source. Row 20 - Total Existing Capacity (North of Taku Inlet) The sum of Rows 14, 16, and 18. Row 21 - Total Potential Hydro Energy (North of Taku Inlet) The sum of Rows 15, 17, and 18. Rows 23 and 24 - Snettisham The annual capacity and energy available from the Snettisham project. Rows 25 and 26 - Total Existing Hydro Capacity (South of Taku Inlet) and Total Existing Hydro Energy (South of Taku Inlet) The total capacity and energy available from hydro projects south of Taku Inlet. Rows 28 and 29 - Salmon Creek Expansion The annual capacity and energy available from the Salmon Creek Expansion project (Lower Salmon) which comes on line in 1985. Rows 30 and 31 - Total Expanded Hydro Capacity (North of Taku Inlet) and Total Expanded Hydro Potential Energy (North of Taku Inlet) Total capacity and energy available from new projects north of Taku. Rows 33 and 34 - Crater Lake The annual capacity and energy available from the Crater Lake project after it comes on line in 1988. 0545C 425-12 Rows 35 and 37 - Total New Hydro Capacity (South of Taku Inlet) and Total New Hydro Energy (South of Taku Inlet) Total hydro capacity and energy available from new projects South of Taku. Row 40 - Total Existing and Committed Hydro Capacity (North of Taku Inlet) Total hydro capacity north of Taku Inlet. The sum of Rows 20 and 21. Row 42 - Transmission Losses (Annex Creek) Annex Creek is unique among the north of Taku hydro plants, in that it has significant losses prior to entering the Juneau system. This line details those losses. Row 44 - Existing and Committed Hydro Capacity (Net of Annex Losses and North of Taku Inlet) Row 40 less Row 42. Row 46 - Total Existing and Committed Hydro Capacity (South of Taku Inlet) The sum of Snettisham and Crater Lake capacities. Row 48 - Transmission Losses Through Thane For all projects south of Taku Inlet, this is the sum of loss in capacity for transmission to the Thane substation and the losses in the Thane transformers. Row 49 - Total Existing and Committed Hydro Capacity (South of Taku Inlet) Net available capacity from south of Taku Inlet after the percentage losses given in Row 48 are deducted. This places the south of Taku Inlet projects on an equal basis with those north of Taku Inlet. Row 51 - Total Hydro Capacity (MW) The sum of Rows 44 and 49. Row 54 - Total Existing and Committed Hydro Energy Potential (North of Taku) Sum of Rows 21 and 31. Row 56 - Transmission Losses (Annex Creek) This row is the energy lost in the Annex Creek transmission line. 0545C 7.5-13 Row 58 - Existing and Committed Hydro Energy Potential (Net of Annex Losses, North of Taku Inlet) Row 54 less Row 56. Row 60 - Total Existing and Committed Hydro Energy Potential (South of Taku) Sum of Rows 26 and 34. Row 62 - Transmission Losses to Thane This is the sum of percent energy lost by projects south of Taku for transmission to Thane substation and the losses in the Thane transformer. Row 63 - Total Existing and Committed Hydro Energy Potential (Net Through Thane South of Taku) Net energy from all projects south of Taku Inlet after the percentage transmission losses are deducted. Row 65 - Total Hydro Energy Potential The sum of Rows 54 and 63. This is automatically fed through an external link to ECONANAL. Row 67 - Local Transmission Losses Percentage of energy lost due to local transmission and distribution. This is automatically provided through an external link from JUNLOSS. Row 68 - Total Hydro Energy Potential This is the net hydro energy available for sale. 2.5 ECONANAL SPREADSHEET The ECONANAL spreadsheet is used for two purposes. The first is to determine the energy generation contribution by each type of generation resource in the system, in each year. This is accomplished by adopting a dispatch order and sequentially adding the available energy, after losses, from the system resources until the energy requirements forecast is satisfied. A summary is provided to show the relative contribution of the various resources in any given plan, by year. The second use for ECONANAL is the calculation of system costs. Yearly total costs are shown, as well as a more detailed listing of costs by category (capital, fixed 0 & M, variable 0 & M, fuel and purchased power). ECONANAL also discounts costs to a base year and sums discounted costs over the economic analysis period. Integral to the latter calculation are estimates of replacement costs and salvage 0545C 7.5-14 values for all new capacity added in the plan. Table 7.5-5 shows the ECONANAL spreadsheet, and a description of the lines in the spreadsheet follows. Rows 10 Through 16 These rows on the ECONANAL spreadsheet add local transmission and energy losses to forecast energy sales to determine the Gross Energy Requirement. This is then compared to the Existing and Committed Hydro Generation Potential to determine if there are any energy requirements that are unmet by the hydro potential. Rows 18 Through 34 Space is allowed in this part of the spreadsheet for the addition of two separate hydro projects as part of a new alternative. The unmet energy requirements are listed here to aid in selection of a suitable project. The year of addition, Capital Cost, annual 0 & M cost, and generating potential can be entered. The actual generation is calculated based on the potential and unsatisfied needs. Rows 36 Through 48 The parameters of the transmission project for bringing in outside resources to meet energy and capacity needs may be entered by the user in these rows. The data to be entered are year of addition, capital cost, fixed and variable 0 & M costs, transmission potential, percentage transmission losses, and cost of energy. The actual energy transmitted and total cost of that energy are calculated. Rows 50 Through 70 New diesel units which will be used as prime sources of energy are entered in these rows. The parameters entered are capacity addition, capital cost, fixed 0 & M cost if any, and transmission loss if any. The fuel use rate, initial fuel price, fuel escalation rates, and variable 0 & M rate are also entered by the user. Cumulative capacity added, net generation potential, actual net generation, fuel cost, and variable 0 & M cost are all calculated. Rows 72 Through 78 Parameters for the addition of new stand-by thermal units may be entered in these rows. These include capacity added, unit capital cost and unit fixed 0 & M cost. Year-by-year capital and 0 & M costs are then calculated. Rows 80 Through 100 The ability of the existing prime diesels to satisfy the energy demand requirements not met by other facilities is addressed here. Costs of any energy utilized is then calculated, as is any remaining energy requirement not satisfied by use of these units. 0545C 7.5-15 9I-s°e COrvaneuns 10 ll 12 13 4 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 7 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 % 3 1.3 ENERGY SALES FORECAST (Gh) ) LOCAL LOSSES (x) (GAUSS ENERGY REQUIREMENT (Buh) (AT SUBSTATIONS) EXISTING & COMMITTED HYDRO 213.1 36 27.2 ) NET GENERATION POTENTIAL, (BMH) 208. 6 NET GENERATION ACTUAL (GMh) (NEW HYDROELECTRIC PROJECT: ‘YEAR RODED (CAPITAL COST (9000) FINED 04" COSTS (9000) W8ET ENERGY REDUIRENENTS (Gh) NET GENERATION POTENTIAL (Gin) NET GENERATION ACTURL (Gah) PROJECT: YEAR RODED CAPITAL COST (9000) FINED 04M COSTS (9000). UNPET EXERGY REQUIREMENTS (Buh) NET GENERATION POTENTIAL (Bwh) NET GENERATION ACTURL (Buh) ‘PROJECT ‘YEAR AODED (CAPITA COST (#000) FINED O8* COSTS (#000) (WOET ENERGY REQUIFEMENTS (Gan) NET GENERATION POTENTIAL (Bah) (NET GENERATION ACTUAL (Gah) EXERGY LOSS (1) ENERGY PURCHASED (Ban) (UNIT COST AT SOURCE (8/un) PURCHASED ENERGY COST (9000) NEW PRE THER TEs Prime Diesel CAPACITY AODED (su) CUMULATIVE CADRCITY ADDED (96) 21.6 0.0 21.6 0.0 21.6 0.0 6.40 es4 205.6 205.6 ne 0.0 3.8 0.0 38 0.0 1986 242.4 6.47 28.1 205.6 205.6 32.5 0.0 325 0.0 0.0 1987 232.6 6.32 269.1 205.6 205.6 63.5 0.0 63.5 0.0 63.5 0.0 1988 262.4 6.57 279.7 205.6 205.6 mL 0.0 THA 0.0 m1 0.0 1989 am1.5 6.63 283.5 a2 289.5 0.0 0.0 0.0 0.0 0.0 1990 279.0 6.67 297.6 8.2 257.6 0.0 0.0 0.0 0.0 00 6.71 16.2 wee 6.2 0.0 0.0 0.0 0.0 00 0.0 1992 25.0 6.76 wad 182 wee 68 0.0 68 0.0 6.8 0.0 1993 03.3 6.80 RLY 82 8.2 13.8 0.0 15.8 0.0 13.8 0.0 19% m1.8 6.85 Bw2 wee 8.2 3.0 0.0 8.0 0.0 2.0 0.0 15 320.6 6.90 we7 8.2 008.2 we 0.0 we 0.0 wb 0.0 Table 7.5-5 Sheet 1 of 3 195 1997 B30 «382 65 7.00 32.2 BL9 18.2 108.2 8.2 16.2 “0 37 00 0.0 “0 3.7 0.0 0.0 4.0 37 0.0 0.0 1998 47.0 1.6 LS wee 18.2 63.3 0.0 63.3 0.0 63.3 0.0 1999 36.8 7.10 me. 106.2 8.2 4.0 00 m0 0.0 4.0 0.0 i M4 36.3 71S 7.28 12.6 404 6.2 WEE (308.2 306.2 aS BI 0.0 00 AS 3 0.0 0.0 aS 63 00 0.0 6.5 a 414.6 106.4 0.0 106.4 0.0 106.4 0.0 337.0 1.2 46.1 17.9 0.0 7.9 0.0 79 0.0 397.0 LR 426.1 117.9 0.0 7.9 0.0 7.9 0.0 7.0 1 426.1 117.9 00 47.9 0.0 ung 00 337.0 2 426.1 ung 00 ung 0.0 47.9 0.0 37.0 L2 426.1 7.9 ao 7.9 0.0 17.9 0.0 337.0 LR 6.1 117.9 00 17.9 0.0 117.9 0.0 397.0 LZ 426.1 8.2 82 79 00 117.9 a0 79 00 2010 397.0 1.2 426.1 8.2 8.2 ud 00 7.9 0.0 17.9 0.0 dts Table 7.5-5 55 Herta COST (#000) Sheet 2 of 3 a6 6 wen 56 (OWN CHET (90000 ° 57 UMET QRERGY REDUIRENENT (tn) 2.60 8 RS RSM 00 66 138 OE 37 63 OS HD KI. 5B NET GENERATION POTENTIAL (Gam) 0.67 LORD FAC, rn er) 00 = 0 0.0 00 00 00 060 00 06 B32 oF ek 33 83 STAT 59 NET GENERATION ACTUAL (Gun) 0.0 00 00 rn) 00 8600000 00 800 00 SARE 33 3 TT 60 BARGY LOSS (x) ° 61 BERG SOERTED (Ge ec) i 00 86000 000 TIL 62 FUEL USE Gon) 3 63 INITIA FUEL PRICE (SANIT — 0.59 64 FUEL ESCALATION RATE (X/VERR) 65 tse 1908 o 66 1989-2003 3 67 FU PRICE (sruT CC en ee 68 FUEL COST 140001 00 86000600 OO 00 = 0.0.00 ATLA ARI. PREN.O | PHELO | (AHELO | HERO HELLO SOM SNK 1188.8 69 VOAIABLE OM RATE (CENTS/iem = 8 70 vaRIR@LE OW COST (9000) Cr SC) 71 72 eo STVGRY THERA 3 74 TH: Diesel 75 CRORCITY AODED (Ved) so so 30 00 = 180 00 30 76 CURLATIVE CHORCITY AONED (oi) Cr eS er) 20° 600) 0 OO 1.0 30 200 mo 0k 70.0 77 CReITR. COST (#000) 1.1 (oom 0 00 800 = 0.0.0 eS eM OO 0.0 208.5 0 6916S 0 Co 78 FINED Gan COST (4000) ‘LS (s000/m ° ° ° ° ° ° ° ° o ms 5 5B 23 » 1 17.3 157.5 aS eS OS 79 80 ELISTING PAINE DIESEL 81 82 ) OwRCITY Ow 12s 5 5 8 5 5 5 3 3 3 a ~ 2» 2» oS 3s 18 is 1s 1s 13 3 3 1S eS ° 83 UWET DERG REDUINED (Gen) a6 me SS BS ML | 680) 68) 60 Bk OG MO SRT GSO SOLS 84 COORCITY UTILTIZATION FACTOR = 0.67 85 woreria) 86 NET GOERATION POTENTIAL (Gxt) ThA MT MT TMT MTT TTT ILIA 117.4 117.4 10.7 OO mo) mo kD 87 YET GEERATION FCT (Gun) a6 Bb BS BS MHL OO 80) 0 RI OH M7 6830S mo) 6m me BR 88 BERGY L085 (1) ° ° ° ° ° ° ° ° ° ° ° ° ° o ° ° ° ° ° ° ° 89 DERGY GENERATED (Exh) a6 BO 5S FS ML | 0 OO IS S763 OS Ce | ) 90 FUEL USE (ine /ORL) 135 91 IMITIAR FUEL PRICE (470RL) 0.509 92 FUEL ESCALATION RATE. (3/YERR) 93 1984-1988 ° 94 1989-2003 3 95 FUEL PRICE CoAT) 0.999 0.999 0.5 0.0.97 0.9 1.017 1.01.0) NIEHS TYPES i ee en ee | 96 FUEL COST 14000) 157.8 A261 ALL A510. ELS 0 0.0 ALG 1298.3 2120.3 BOISE 457 GLE ee 97 vaRLAMLE 0 COST (9000) 0 commen «17.2 «83 0.0 Hk OL SNR A EE 616.6 703-7043 7OR OLDS ATL ATO 8 99 WHET DERE REQUIRE (Gn) 00 86000 Oe OOS SSS Sk 100 101 SaWRRY OF NET GDERATION 102 103. EXISTING & COMMTTED HYDRO (8) AT BLT9 73.64.40 THLSL— 100.00 100.00 100,00 97,85 L1T DL Fw A OM RR RR RR BR RR RR RR WR 104 YM HYDROELECTRIC (8) 0.00 0.00 0.000.000.0000 0.000.000.0000 0.000.000.0000 0,000,000 .00 0,000.00 0.00 0.000.000.0000 0.00.00 105 NEM TRWGISSION THOT (8) 0.00 0.00 0.00 0,000.00 0.00 0.000.000.0000 0.00.00 0.00.00 0.000.000.0000 0.00 0,000.00 0.000.000.0000 0.00 106 *€¥ PRIME TERNAL (5) 0.00 0.00 0.000.000.0000 0.000.000.0000 000.00 0.00.00 0.000.000.0087 7.08 OF OF OF AL OLS 107 ELISTIG PRIME DIESEL «H) 9.53 16.21 20.3828. .K9 0.000.000.0018 7.50 10.08 12,50 ABS 17.08 19.36 ASL IM SD 2G OOS OS KS IID D0 108 SORTFAL os 0.00 © 0.00 0.00.00 0.00.00]... 0.00 0.00.00 0.00 0.000.000.0000 0.00 OIF OFF HFS 0D ODD BI-s"d 109 110 SummRY OF AL COSTS un 112 CAPITA COSTS 19000) 113 FINED 08m Cost (9000) 114 VORLABLE 08% COST (90009 115 PUROHRSED ENERGY (90001 116 FUEL COST 140000 7 118 TOTAL ERY COST (9000) 119 120 DISCOUNTED YERALY COST (9000) 121 Ee 122 DISCOUNT MATE (8) 123 ‘124 GU DISCERATED COST (#000) 125 126 GU DISC. COST TD 2010 19000? 127 128 99 MO-OWTTAL COSTS IM 2010 129 (e000 130 VALUE IN 2010 OF HOR-ORPITAL 131 COSTS Tw 2045 (9000) 132 DISCOUNTED MON-CAPTTAL COSTS 133 BEVBe 2010 (8000) 134 135 REASON COST AO SALVRGE VALLE DETERAINETION (NEW UNITS 136 137 wer 138 139 Deo #1 140 HroR0 #2 141 TewertsstOn 142 oe Dew 1 143 Re DeweL ee 144 Re NEw. 83 145 sr@oey TERRE aL 146 sTmoey TEMA 82 147 st@gey TER «3 148 StmoRY TEweL 04 149 Steqey Tewr. 65 150 sr@oey NEM 96 151 Steer hewn. 67 152 sTeoey TEM 06 153. st@oey TEwrL #9 154 Stony Tem 010 155 STORY THER #11 156 STaoRY NeweL 812 157 steqey Mew e13 188 159 sum (9000) 160 OwrciTy om s 3 10 3 5 3 s 5 3 1s r 5 00 0.0 me 0.0 1397.8 m1.0 m1.0 1711.0 16] NET DISCOUNTED REPLACENENT COSTS AO SALVAGE VALUES (9000) 162 163 rom piscouwreD sum COSTS (8000) 318.3 0.0 2826.1 cry a8. 00 0.0 420.0 0.0 we8.1 08.0 wre en es) 00 80.0 00 07.9 SOO 0.0 0.000 4510.3 5261.3 0.0 2 AL a0 4526.1 101.5 0.0 131084 18048,9 1809.9 FERACEENT RADE YER a ERR 82 eet eon ek ° 2» ° 204 20m 201s 2035 2017 e037 aug 2039 020 20M ees 2083 05 0 ees 2030 ° ~» ” 0.0 0.0 0.0 0.0 0.0 0.0 a0 0.0 a0 00 108249.9 PSL TE ELEre 00 | 00 00 © 0.0 We 126.2 0.0 0.0 M6 1293.3 452.4 1088.9 16702,3 19748.2 wrt a6 116.0 278.0 2005.5 2005.5 2005.5 ems. 2005.3 6516.5 222.0 2005.3 2505.3 7.5 200.0 0.0 2120.3 ons a7 Table 7.5-5 Sheet 3 of 3 Ct BO BO OAS et 00 00 0.0 B11 381.2 4977.3 a 360.4 2877. AHA (25900, 2578.0 HA7H2.9 11058,2 se eee 17.4 1563.5, 1097.5 132.8 1303.3 1613.9 1723.1 er 0.0 103.3 764 0.0 00 0 a0 285 os on 0.0 5.9 1162.6 6702.8 ‘1637.6 2085 SLRS VALUE (9000) ao O35 mee 0 wie ms one mT 192.5 wee a 79 ait mAs 0 169.7 7 00 a0 ao a0 a0 se. oes 108.0 8.1 0.0 1266.5 160161 0955.0 2 66.5 197.5 m8 0.0 1866.5 1008.4 00 137.5 8.1 0.0 1866.5 AR 1308.0 ens wha 0.0 12400,7 116007,7 00 ans ALD 0.0 12400.7 0.5 a0 8.1 0.0 1698.2 21498.7 Rows 102 Through 109 This block of the spreadsheet presents a summary of where the total energy demanded is generated. The energy sources broken down by percent are the existing, new, and committed hydroelectric, transmission imports, and new and existing diesel. Rows 111 Through 119 Beginning with these rows, the balance of the spreadsheet deals with economic analysis of the project's operations, additions, and costs as summarized here. This block of rows summarizes the total expenditures in each year of the plan for all costs, which are categorized as either capital, fixed 0 & M, variable O & M, purchased energy, or fuel costs. Rows 121 Through 127 The costs summarized and totaled above are discounted to the base year (1984) and totaled to give cumulative discounted costs. Rows 129 Through 133 This section summarizes and discounts the noncapital cash flows resulting from operation beyond the year 2010. Rows 136 Through 162 The projects which must be replaced or salvaged after the year 2010 have their replacement costs and salvage values summarized and discounted in this section. Row 164 Total discounted plan costs. This row is the sum of Rows 127, 133, and 162. 3.0 INFORMATION FLOW There are three different types of information flow depicted on the model flow diagram, Figure 7.5-1. These are EXOGENOUS (outside) inputs, manual (operator performed) spreadsheet links, and automated (performed by the software) spreadsheet linkages. 3.1 EXOGENOUS INPUTS EXOGENOUS inputs to the model are those which change the fixed values used for calculation in the model. These values include such things as project-specific transmission losses, load forecast, and reserve requirements, and they come from two possible sources. The first is from within the utility. These include such items as economic analysis 0545C 725-19 parameters and reserve margin which are set by policy. The second group consists of parameters which may be added or changed due to such inputs as conceptual design or estimate of a new project or a new system load flow study. These variables will be added as the result of work performed outside the utilities. The specific exogenous inputs from the two sources are discussed below. 3.1.1 EXOGENOUS Inputs From Utility Sources Updates and Changes to HYPRO Changes to this spreadsheet would consist of modification to capacity, available energy, or retirement year of any of the existing projects. Capacity Demand or Reserve Requirements These potential changes to parameters built in to the CAPPLAN spreadsheet will be made manually by the user whenever a new load forecast must be input or when the reserve policy is changed. Updates and Changes to THERPRO Operating policy will dictate any changes to the thermal capacities or retirement dates for the units listed in THERPRO. Economic Analysis Parameters The parameters and methods built into ECONANAL at present are those of the Alaska Power Authority. Any change in these parameters or methods or the use of a different set of guidelines will require revision. Energy Sales Forecast ECONANAL will need to be changed whenever a new load forecast becomes available. 3.1.2 EXOGENOUS Inputs From Nonutility Sources Load Flow Study Results The algorithms for calculating the transmission and distribution losses in capacity and energy that are built into the model are the result of load flow studies performed as part of this study. Periodic updates of the load flow studies should be performed. Project Studies, Conceptual Designs, and Cost Estimates The listing and parameters of the projects that are available for input to create alternate plans will be changed any time a project is 0545C 155-20 redefined, new project identified, or an estimate updated. The new parameters or project should be entered on the appropriate alternative projects spreadsheet. 3.2 MANUAL SPREADSHEET LINKAGES As shown on the model flow diagram, the user's primary interface is with CAPPLAN and ECONANAL. Reviewing the available capacity and capacity requirements of CAPPLAN, the user manually selects projects from available options to satisfy any shortfall. These projects must also be manually input to ECONANAL. Additionally, the selected timing of additions from CAPPLAN is part of the manual input to ECONANAL. The last manual link is the user review of energy sufficiency to determine if further capacity is needed to satisfy energy generation requirements. 3.3 AUTOMATED SPREADSHEET LINKAGES There are nine automated information flow paths shown on the model flow chart. These are listed in Table 7.5-6 along with the specific EXTERNAL name and description of the variable parameter being transferred. EXTERNAL is the MULTIPLAN software name for the automated spreadsheet linking function. These linkages are performed by the computer and do not require any user action. 4.0 USING THE PLANNING MODEL The planning model is set up to be run on an IBM PC microcomputer utilizing the MULTIPLAN software system. All of the spreadsheets are stored on a single disk. These spreadsheets are (listed in the order they appear on the diskette directory): JUNPLAN - Summary of Results of a Completed Alternative ECONANAL - Economic Analysis Spreadsheet JUNLOSS - System Transmission Losses Spreadsheet CAPPLAN - Capacity Planning Spreadsheet THERPRO - Existing Thermal Projects Spreadsheet HYPRO - Existing Hydro Projects Spreadsheet EXHYDPRJ - Existing Hydro Project Data Spreadsheet TRINTALT - Transmission Project Data Spreadsheet UNHYDPRT - Undeveloped Hydro Project Data Spreadsheet THERGEAL - Alternative Thermal Generating Project Data Spreadsheet The first six spreadsheets correspond to the active spreadsheets shown on the model flow diagram. The last four spreadsheets are the data which make up the Alternate Projects block shown on the model flow diagram. Whenever a new project planning scenario, load forecast, or other change which will create a new alternative plan, is to be made, it will be necessary to work with these spreadsheets and MULTIPLAN as described in the following paragraphs. 0545C 7-9-2) Flow Chart No. TABLE 7.5-6 AUTOMATED SPREADSHEET LINKAGES External Name Page 1 of 2 Description 0545C B:HYPRO HYCAPS B:HYPRO HYCAPN B:HYPRO HYNETPOT B:THERPRO THERCAP B: THERPRO EXPRIDIES B:CAPPLAN PEAK B:JUNLOSS ENLOSS B:ECONANAL ENERGY B:CAPPLAN THERENTAX B:CAPPLAN HYNTAK B:CAPPLAN RESMAR 7.5-22 Total capacity of existing and committed hydro resources south of Taku Inlet through Thane substation from HYPRO to CAPPLAN Total capacity of existing and committed hydro resources north of Taku from HYPRO to CAPPLAN Total potential energy available to the Juneau system from hydro projects from HYPRO to ECONANAL Total capacity available from thermal projects existing or committed as of 1984. From THERPRO to CAPPLAN Total prime capacity available from thermal projects existing or committed as of 1984. From THERPRO to ECONANAL System capacity demand. From CAPPLAN to JUNLOSS Energy losses within the Juneau transmission and distribution system. From JUNLOSS to ECONANAL System energy requirements. From ECONANAL to JUNLOSS Existing and committed thermal resources. From CAPPLAN to JUNPLAN. Existing and committed hydro resources north of Taku Inlet. From CAPPLAN to JUNPLAN. Reserve status from CAPPLAN to JUNPLAN Flow Chart No. 10 TABLE 7.5-6 AUTOMATED SPREADSHEET LINKAGES External Name B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL B: ECONANAL ENSALFOR NETGENHY NETGENHY2 NETGENTRAN NETGENTHER NETGENDIES CAPCOS FIXOM VAROM FUELCOS TOTYRCOS TOTDISCOS B: JUNLOSS CAPLOSS Page 2 of 2 Description Generation from existing and committed hydro facilities. ECONANAL to JUNPLAN. From Generation from the initial hydro project addition. From ECONANAL to JUNPLAN Generation from the second hydro project addition. From ECONANAL to JUNPLAN. Energy provided over a transmission project addition. From ECONANAL TO JUNPLAN. Generation from new prime diesel units. From ECONANAL to JUNPLAN. Generation from existing and committed diesel units. From ECONANAL to JUNPLAN. Capital costs from ECONANAL to JUNPLAN. Fixed operation and maintenance costs from ECONANAL to JUNPLAN. Variable operation and maintenance costs from ECONANAL to JUNPLAN. Fuel costs from ECONANAL to JUNPLAN. Total yearly plan cost from ECONANAL to JUNPLAN. Total discounted plan cost. from ECONANAL to JUNPLAN. Capacity losses within the Juneau transmission and distribution system. From JUNLOSS to CAPPLAN. 0545C 7.5-23 4.1 INITIALIZING AN ALTERNATIVE PLAN DISKETTE The first step is to take a new (blank) diskette, format that diskette using the DOS command for format, then copy the contents of the spreadsheet files diskette onto the newly formatted one. After this, remove the original diskette, store it, and be sure to work only with the newly created plan files diskette. Next, one at a time, call up the five active spreadsheets (the first five listed above), go to the upper left-hand corner and label each with a specific label located under the date. The label should identify which alternative this spreadsheet development belongs to. This is illustrated below, showing how the upper left-hand corner of ECONANAL will appear when modified for an All-hydro alternative. 1 1 ECONANAL 2 September 8, 1984 3 ALLHYDRO Note that each time any spreadsheet is worked with, the date in the upper left-hand corner is changed to the current date. Once all spreadsheet labels, title blocks, and dates have been changed, and the spreadsheets saved, the changes necessary to create the alternative can be entered. 4.2 CHANGING THE PLANNING ASSUMPTIONS If there are any changes to be made to the model, other than selection of projects to meet capacity and energy needs, they must be made prior to the project selection process. This will include such items as the demand forecast, economic analysis parameters, reserve requirements, new projects parameters, and/or new cost data on existing projects. These data should be entered on the appropriate spreadsheets, the spreadsheets saved, and automatically linked data checked to be sure no MULTIPLAN externals have been interferred with. Once the planning assumption changes, if any, have been entered and saved, the alternative plan can be run to balance available capacity and energy to demand. 4.3 USING CAPPLAN Prior to loading and modifying CAPPLAN, the user should print a copy of all Alternative Projects spreadsheets for reference while running CAPPLAN. Once the capacity planning spreadsheet is loaded, all changes should be made in the three rows for entering additional new capacity. These are the rows labeled for entering new hydro capacity south of 0545C 7.5-24 Taku Inlet, new hydro capacity north of Taku Inlet, and new thermal capacity. All other changes described with the CAPPLAN spreadsheet are automatic. The first step is to zero all entries in the three rows, this will provide a clean spreadsheet which reflects only existing and committed projects. The values found in the row entitled Existing Reserve Margins will indicate when a project should be added to the system to meet demand. Working chronologically forward from the present, the first year in which a negative value appears for Existing Reserve Margin is year in which the first new project should be added. The project can be selected on any of several basis such as lowest capital cost, cost per kWh, capacity, location or generation type. Regardless, the best use of capacity will result if projects are input at a time and of a size to result in the value for the Reserve Margin After Additions to stay at or above zero for the study period. After inputting the project or projects for the current year, the spreadsheet must be recalculated prior to reviewing the next succeeding year. After recalculation, the process is repeated one year at a time for each of the following years through the end of the planning period. After a satisfactory balance of capacity, demand, and reserve requirements has been achieved for the planning period, the user must be sure that he has accurately recorded which projects were added and their year of addition. This will define which projects' data are to be manually input to ECONANAL. At this point, the CAPPLAN spreadsheet should be saved on the new alternative disk, erasing and replacing the CAPPLAN which previously existed there. 4.4 USING ECONANAL ECONANAL begins with the user entering the energy sales forecast. JUNLOSS must be recalled, calculated, and saved at this point to be sure new energy losses are reflected. Local losses are provided by an automated link from JUNLOSS, and gross energy requirements are then calculated by ECONANAL. Generation available from existing and committed hydroelectric projects is entered automatically from HYPRO. This is compared to gross energy requirements, and ECONANAL selects the lesser of the two as the actual net generation provided from existing and committed hydroelectric units. There are no costs associated with the use of existing or committed hydroelectric projects that vary from one plan to the next, so no costs are included for this generation resource. If a plan calls for the addition of new hydroelectric capacity, that addition should be entered next. (If there is no such addition called for in the plan, the user moves to the next section of ECONANAL.) The name of the project and the year it comes on line are entered by the user as reference. The user uses the results of CAPPLAN and his judgement in determining the year. The user enters capital costs in the appropriate years, along with associated fixed operation and maintenance costs. 0545C 7.5-25 ECONANAL calculates the remaining unmet energy requirement by subtracting existing and committed hydroelectric plants' actual net generation from gross energy requirements. The user enters net generation potential from the hydroelectric project addition, and ECONANAL then calculates the generation actually contributed from this new project by selecting the lesser of the project's net generation potential and unmet energy requirements. ECONANAL provides the opportunity to add a second new hydroelectric project, using the process described above. Any new transmission project is handled next. The user enters the project's name and the year it comes on line, based on results of CAPPLAN and the user's judgement. The associated capital costs are entered by the user in the year they would occur, and fixed 0 & M costs are entered in each year the project is operating. ECONANAL calculates unsatisfied energy requirements, while the user enters the net generation potential associated with the new project. ECONANAL then calculates the actual net generation provided by this project. The remainder of the items under "New Transmission" address the cost of purchased energy. The user enters the percent transmission loss associated with the project. ECONANAL then calculates the amount of energy that would have to be purchased in order to deliver the actual net generation. The unit cost of power purchased at the source is entered by the user, and the yearly cost of purchased energy is automatically calculated. ECONANAL next turns its attention to new thermal additions providing prime power. If there are any such projects in the plan, the user enters the name (or type of resource). From CAPPLAN results and judgement, the user enters the capacity added in each year. ECONANAL then calculates the cumulative capacity additions. The user enters the appropriate capital costs in keeping with the capacity additions entered previously. The unit cost of fixed 0 & M is entered, and ECONANAL then automatically calculates fixed 0 & M cost based on the cumulative added capacity in any year. As previously done for other generation resources, the user enters the potential net generation available from the cumulative capacity addition; this is compared automatically to the remaining current energy requirements calculated by ECONANAL, and ECONANAL selects the lesser value in each year as the actual net generation from this resource. Any transmission loss (not local losses) is entered by the user in percent, and energy generated is automatically calculated. The user enters the fuel use rate, the initial fuel price, and the fuel escalation rates. ECONANAL calculates the fuel price and then the fuel cost. The variable 0 & M rate is entered by the user; ECONANAL calculates the variable 0 & M costs in each year based on the energy generated. 0545C 7.5-26 While new standby thermal units are not assumed to contribute energy, they do have costs associated with them that may vary among plans and so are addressed by ECONANAL. Based on CAPPLAN results, the user enters the project name or type and the capacity added in each year. The cumulative additions are calculated automatically. The user enters the appropriate capital costs in keeping with the capacity additions, and enters the fixed 0 & M unit cost. ECONANAL then calculates the fixed 0 & M cost. The last resource to be dispatched is existing and committed thermal capacity. The amount of diesel capacity considered potentially available for prime power generation is provided automatically through an external link to THERPRO. As before, ECONANAL calculates remaining unmet energy requirements. The user enters the capacity utilization factor applicable to existing and committed prime power thermal plants. This entry is the utilization anticipated if the units were to be run to supplement the other generating resources. The factor used is a matter of judgement, with consideration given to the amount of unmet generation requirements and the position in the load curve. Based on the utilization factor, ECONANAL calculates the potential net generation available from the existing and committed prime diesels, along with the net energy actually generated. Any transmission losses (not local losses) are entered by the user, and the amount of energy generated is calculated by the program. The user enters the fuel use rate, initial fuel price and fuel escalation rates. ECONANAL then calculates fuel prices and yearly fuel costs. With the variable 0 & M rate entered by the user, the variable 0 & M cost is automatically derived. The next line, “unmet energy requirements," shows the shortfall, if any, between forecasted energy requirements and the combined energy generated by the plan, taking account of losses. If there is a remaining unmet requirement, this indicates to the user that the plan is energy deficient (despite sufficient capacity) and suggests that additional generating resources are required. If this is the case, the user should return to CAPPLAN, add the resources needed to provide the energy, and perform another iteration of ECONANAL. (Note: If the plan under consideration includes standby thermal capacity additions, CAPPLAN may not have to be altered. Rather, it may be possible to achieve energy sufficiency by converting some standby capacity additions to prime capacity additions solely using ECONANAL.) The next section of ECONANAL is a “Summary of Net Generation." The program calculates the percent contribution of each resource category to total generation in any given year. ECONANAL then computes the sum of yearly plan costs by cost category and displays them in a section of called "Summary of Plan Costs." The 0545C d.o-27 program sums capital costs, fixed 0 & M costs, variable 0 & M costs, the cost of purchased energy, and fuel costs to give the “Total Yearly Cost." The program then discounts the yearly totals based on the user-entered discount rate and base year. Yearly discounted costs are accumulated and ECONANAL calculates the “Cumulative Discounted Cost to 2010." Noncapital costs occurring in the year 2010 are assumed by ECONANAL to recur each subsequent year of the analysis period, and the program, in two steps, calculates the present value of noncapital costs occurring beyond 2010. Replacement costs and salvage values for all new capacity additions are addressed next. Referencing previous portions of ECONANAL, the user enters the capacity added in any year, by type, and the year it is added. Based on the assumed economic life of the particular unit, ECONANAL calculates the initial replacement year, the subsequent replacement year, if any, and the retirement year. The user enters the associated total capital cost of each unit (1984 $), and then ECONANAL calculates the discounted replacement costs, the salvage value as of 2045, and the discounted salvage value. The program automatically sums the discounted replacement costs and salvage values, determines the net discounted cost of replacements and salvage, and computes the plan's total discounted cost over the economic analysis period. Table 7.5-7 summarizes the sources of input data to ECONANAL. The data can either be an exogenous input or flow from other spreadsheets. Input from other spreadsheets can be either by means of an automated link or by manual transfer by the user. 5.0 PLANNING MODEL RESULTS The results of the model's use will be a system generation scenario which satisfies both capacity and energy requirements. The output for each plan will be a comparison of how the scenario matches both capacity and energy requirements and what the total costs of that scenario are. The spreadsheet which summarizes these is called JUNPLAN and is shown on Table 7.5-8. The items appearing on JUNPLAN are transferred directly from CAPPLAN and ECONANAL. If different output parameters are discussed, it will be a simple matter to modify JUNPLAN and create new EXTERNAL linkages. Application of the model requires integrated use of the various spreadsheets. The following sequence of steps summarizes the suggested general approach to effective use of the model in developing a new long-term plan. 1. Update the four Economic Parameters Summary spreadsheets (Tables 3-1, 3-5, 3-12, and 3-15) to provide an accurate data base for each of the available generation and transmission options. 0545C 7.5-28 TABLE 7.5-7 ECONANAL DATA SOURCES ITEM SOURCE Energy sales forecast Discount rate Local losses Existing and committed hydro net generation potential Project data: capital cost, 0 & M costs, generation potential, transmission loss, fuel use, capital cost timing Economic data: initial fuel price, purchase power price, escalation rates, economic life Timing and magnitude of capacity additions Existing prime diesel capacity o EXOGENOUS 0 EXOGENOUS o JUNLOSS (automatic) o HYPRO (automatic) oO TRINTALT, UNHYDPRJ, EXHYDPRJ and THERGEAL (manual) o TRINTALT, UNHYDPRJ, EXHYDPRJ, and THERGEAL (manual) o CAPPLAN (manual) O THERPRO (automatic) 0545C 7.5-29 O€-S°Z 8 JUNPLAN OCTOBER 4, 1984 1984 1985 PERK DEMAND FORECAST (MH) 41.30 55.10 EXISTING & COMMITTED HYDRO RESOURCES 5.62 6.62 (NORTH OF TAKU INLET) EXISTING & COMMITTED THERWAL RESOURCES 56.72 71.22 CAPACITY AVAILABLE TO MEET PERK (MW) 64,54 79.84 (WITH SNETTISHAM T-LINE QUT OF SERVICE) RESERVE STATUS (MW) 23.24 24,74 ENERGY GALES FORECAST (Gwh) SOURCES OF GENERATION (Gwh) EXISTING & COMMITTED HYDRO NEW HYDROELECTRIC #1 0,00 0.00 NEW HYDROELECTRIC #2 0.00 0.00 NEW TRANSMISSION IMPORT 0.00 0.00 NEW PRIME THERMAL 0.00 0.00 EXISTING DIESEL 21.65 39.78 PLAN COSTS ($000) CAPITAL COSTS 0 0 FIXED O&M 0 0 VARIABLE O&M 173 318 PURCHASED ENERGY 0 0 FUEL COST 1538 2826 TOTAL 1711 3144 TOTAL DISCOUNTED PLAN COST ($000) 1986 57.90 8.62 71.22 79. 84 21.94 0,00 0.00 0.00 0.00 52.49 3729 Alay 1987 60.30 8.62 69.97 78.59 18.29 0.00 0.00 0.00 0.00 63.49 ekeo 4510 ‘5018 62.60 8.62 69.97 78.59 15.99 1989 1990 1991 64.80 66.60 68.50 8.62 8.62 8.62 68.77 68.77 65.27 77.39 77.39 73.89 12.59 10.79 5.39 3.49 0.36 0.00 0.00 0.00 0.00 0.00 coocooo 0.00 0.00 0.00 0.00 0.00 coococo 0.00 0.00 0.00 0.00 0.00 coocoo$o TABLE 7.5-8 JUNEAU 20-YEAR PLANNING STUDY SUMMARY OF RESULTS 1992 1993 1994 1995 1996 70.40 72.40 74.40 76.50 78.60 8.62 8.62 8.62 8.62 8.62 65.27 64.14 64.14 69.14 68.00 73.89 72.76 72.76 77.76 76.62 “1.64 1.26 -1.98 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 6.77 15.78 25.00 34.56 44.02 0 0 2306 2306 0 0 0 18 3 3 4 12 200 276 Se 0 0 0 0 0 S42 129921203019 3961 59 1425 (4643 5636 4348 1997 80.70 8.62 73.00 81.62 0.92 0.00 0.00 0.00 0.00 53.70 2306 53 430 0 4977 7765 1998 8.62 73.00 81.62 71.28 -1.08 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 63.30 73.98 0 2306 33 70 36 | (592 0 0 6043 7274 6602 10242 0. 88 0.00 0.00 0.00 0.00 84.46 2306 88 676 0 8554 11623 1999 2000 2001 85.20 87.50 89.90 8.62 8.62 8.62 75.50 78.00 83.00 84.12 86.62 91.62 1.72 0.00 0.00 0.00 29.35 65.93 4116 88 762 0 %33 14599 2002 2003 2004 «2005 2006) 2007 92.30 94.80 94.80 94.80 94.80 94.80 6.62 8.62 8.62 8.62 8.62 8.62 83.00 88.00 88.00 85.50 85.50 85.50 91.62 %6.62 96.62 94.12 9.12 94.12 0.68 0.00 0.00 0.00 29.35 77.08 651 11120 12059 1.82 0.00 0.00 0.00 29.35 88.04 2306 105 939 0 12667 16016 1.82 0.68 -0,68 -0.68 0.00 0.00 0.00 29.35 88.04 105 12667 13711 0.00 0,00 0.00 0.00 0.00 0.00 29.35 29.35 88.04 88.04 6917 0 158158 939 o 0 12667 12667 20680 13763 0.00 0.00 0.00 29.35 88.04 158 12667 13763 2008 2009 2010 94.80 94.80 94.80 8.62 87.50 %. 12 1.32 0.00 0.00 0.00 56.69 59.23 13338 228 Ws 0 12401 26910 8.62 6.62 67.50 9.00 %.12 98.62 1.2 3.82 215.10 230.60 242.40 252.60 262.40 271.50 279.00 286.90 295.00 303.30 311.80 320.60 329,30 338.20 347.00 356.80 366.40 376.30 386.50 397.00 397.00 397.00 397.00 397.00 397.00 397.00 397.00 205.59 205.59 205.59 205.59 205.59 289.49 297.61 306.16 308.16 308.16 308.16 308,16 308.16 308.16 306,16 308.16 308,16 308,16 308.16 308.16 308.16 308.16 308.16 308.16 308, 16 308.16 308.16 0.00 0,00 0.00 0.00 0.00 0,00 58.69 117,38 59.23 0.00 0 8584 228 aS HI 939 0 0 12401 11692 13572 21460 9. Update THERPRO to provide an accurate representation of existing and committed thermal projects. Update HYPRO to properly reflect the capacity and energy output of existing and committed hydroelectric projects. Input the desired peak load and energy sales forecasts on CAPPLAN and ECONANAL, respectively. Load JUNLOSS to allow automatic recalculation of local system losses in keeping with the load forecast. Add and remove projects on ECONANAL to provide sufficient energy generation over the planning period. Update CAPPLAN to reflect the previous step, and add any additional units to insure that reserve requirements are satisfied. Return to ECONANAL to update in keeping with the status of CAPPLAN and to add energy production potential and cost data. Load JUNPLAN for automatic preparation of the plan summary. Many tasks require only a limited number of the above listed steps. If project data is unchanged, steps one through three can be eliminated. If the load forecast is unchanged, steps four and five are unnecessary. If only economic parameters, such as fuel cost or price of purchased energy, need updating, use of the model can be limited to the final two steps. 0545C 7.5-31 APPENDIX 7.6 PLANNING MODEL RESULTS 0586C PLANNING MODEL RESULTS Exhibit Name Description* 1-A HYPRO Base case 1-B THERPRO Base case 1-C JUNLOSS Base case 1-D CAPPLAN Base case, thermal 1-E ECONANAL Base case, thermal 2-A CAPPLAN Dorothy 1996 2-B ECONANAL Dorothy 1996 3-A CAPPLAN Dorothy 1996 (with Snet. T-line) 3-B ECONANAL Dorothy 1996 (with Snet. T-line) 4-A CAPPLAN Whitehorse Intertie 1996 4-B ECONANAL Whitehorse Intertie 1996 5-A CAPPLAN Tyee Intertie 1996 5-B ECONANAL Tyee Intertie 1996 6-A CAPPLAN Dorothy 1993 6-B ECONANAL Dorothy 1993 1-A CAPPLAN Dorothy 1999 7-B ECONANAL Dorothy 1999 8-A JUNLOSS Low forecast 8-B CAPPLAN Low forecast, thermal 8-C ECONANAL Low forecast, thermal 9-A CAPPLAN Low forecast, Dorothy 1999 9-B ECONANAL Low forecast, Dorothy 1999 10-A JUNLOSS High forecast 10-B CAPPLAN High forecast, thermal 10-C ECONANAL High forecast, thermal 11- CAPPLAN High forecast, Dorothy 1993 11-B ECONANAL High forecast, Dorothy 1993 12-A JUNLOSS Mining forecast 12-B CAPPLAN Mining forecast, thermal 12-C ECONANAL Mining forecast, thermal 13-A ECONANAL Tyee Intertie 1996 (low Tyee cost) 14-A ECONANAL Thermal, no fuel escalation 15-A ECONANAL Dorothy 1996, no fuel escalation * Mid-range load forecast and firm hydroelectric energy, unless other- wise noted. 0586C 7.6-1 pyar GT 18, 1984 BASE CASE (FIRM ENERGY) HYDRO PROJECT Saleon Creek Anrex Creek Gold Creek Total Existing Hydro Capacity (M of Taku) Total Potential tyoro Energy ih. of Tamu) Snettasnam Total Existing Hyoro Caoacity (S. of Taku) Total Potential Hyoro Energy (S. of Taku) Salmon Creek Expansion Total Expanded Hydro Capacity (N. of Taku) Total Expanced Hycro Potential Energy (N. of Taku) Crater Laxe Total Mew hyoro Capacity (S of Taku) Total how Hydro Energy (S. of Taku) Totai Existing & Commtted Hydro Capacity (nortn of Taku) Transaission Losses (Mii) (Annex Creek) ( Existing and Committed Hydro Capacity (hat of Annex Losses and N. of Taku) Total Existing & Commtted Hydro Casacity (South of Taku) Transaission Losses thru Thane (x) ( Total Existing and Commtted hyoro Capacity (South of Taku, Net thru Thane) Total hyoro Capacity (AW) (net after Transmission Losses) Total Existing & Committed Hyaro Energy Potential (wortn of Taku) Transaission Losses (Gan) (fnrex Creex) Exrstinc ano Committed tyoro Energy Potential (net of Annex wosses and North of Taku) Total Existing & Comittes Hydro Energy Potential (South of Taau) Transmission Losses to Thane (x) Total Existing & Committed nydro Enercy Potential (wet at Trane, South of Taku) ( Total Hyoro Energy Potential (Gen) (Before Local Lossses) ) Local Transmission Losses (X) Total HyCro Enercy Potential (Gun) (After Local Losses) Jase eu YEAR PLAN SummARY OF EXISTING & COMMITTED HYDRO PROJECTS CAP, Pre Oh = 1964 1985 1986 1987 1988 1969 19K ENERGY LINE (he) (Gn) YEAR 2.80 2.80 0.00 0.00 0.00 0.00 0.00 0.00 9.40 9.4 0.00 0.00 0.00 0.00 0,00 0.00 350 3.50 3.50 3.50 350 3.50 3.50 3.50 22.70 22.7 22.7 22.7 22.7 22.7 22.7 22.7 1.60 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0.00 0,00 0.00 0.00 0.00 6.30 350 350 3500 250 3250 3.50 Exhibit 1-A Capacity & Energy vy Year 1991 199 1993 “1994 1995 1956 1997 1998 1999 2000 cw 2004 ele 0.00 0.00 0.00 0.00 0.00 0.0 0.00 6.00 0,00 0.00 0.00 0.00 350 350 3.50 350 3.50 350 3.50 3.50 2.7 22.7 62.7 22.7 22.7 22.7 22.7 7 0.00 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3 350 350 350 50 LH 2 350 0.00 0.00 0.00 0,00 3H 30 22.7 22.7 0.00 0,00 0.00 0,00 30 3.50 0.00 0.00 0.0 0.00 0.00 0,00 6.00 0.00 0.00 0.00 0.0 6.0 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0,00 0.00 6.00 0.00 0.00 350 3.50 3.50 350 3.50 350 3.50 15 1.50 3K 22.7 22.7 62.7 22.7 22.7 22.7 22.7 22.7 22.7 2.7 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0,00 0,00 0.00 0.00 6.00 0.00 0.00 0.00 350 3.50 350 350 250 350 3.50 1 LO 30 32.10 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.20 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 22.70 46.70 173.0 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 45.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179,0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 46.70 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 179.0 5.60 1985 0.00 0.00 0.00 0,00 5.60 9.40 5.60 240 5.60 40 5.60 9.40 5.60 9.40 5.60 9.40 5.60 9.40 5.60 9.40 5.60 5.60 9.40 9.40 3.60 5.60 9.40 9.40 a4 27.00 105.0 1989 0.00 0.0 0,00 0.00 0.0 0.00 0.00 0.0 0,00 0,00 0.0 0.00 0.0 0.0 0.0 00 6.80 910 910 910 9.10 9.10 910 0.48 0,48 0.48 0,48 0.48 0.48 0.48 5.82 8.62 6.62 6.62 B62 B62 8.62 0.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 0.0 105.0 205.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 0.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 5.60 5.60 5.60 5.60 9.40 9.40 9.40 9.40 5.60 5.60 5.60 5.60 9.40 9.40 9.40 9.40 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 9.40 9.40 9.40 9.40 9.40 9.40 9.40 9.40 5.60 5.60 5.60 5.60 5.60 5.60 5.60 5.60 9.40 9.40 9.40 9.40 9.460 9.40 9.40 9.40 5.60 5.60 5.60 5.60 5.60 5.60 5.60 9.40 9.40 9.40 9.40 9,40 9,40 9.40 5.60 5.60 5.60 5.60 5.60 5.60 5.60 9.40 9.40 9,40 9.40 9.40 9.40 9.40 5.60 9.40 5.60 9.40 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 27.00 0.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 103.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 9.10 910 910 9.10 910 9.10 9.10 9.10 910 910 G10 910 910 910 910 910 910 910 910 910 0.48 0.48 0.48 0.48 0,48 0.48 0,48 0.48 0.46 0.48 0.48. 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 8.62 8.62 6.62 662 B62 662 8.62 6.62 B62 B62 Be 862 B62 B62 662 B62 B62 B62 B62 8.62 46.70 46.70 46.70 46.70 46.70 73.70 73.70 73.70 73.70 73.70 73.70 73.20 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 73.70 1.65 1.65 1.65 1.65 1.65 2.60 2.60 2.60 2,60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 260 2.60 2.60 2.60 2.60 45.93 45,93 45.93 45.93 45.93 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.76 71.78 71.76 71.78 71.78 71.78 71.78 71.78 71.78 71.78 ‘51.75 54.55 54.55 54.55 54.55 60.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 80.40 0.40 80.40 80.40 80.40 80.40 80.40 60.40 80.40 60.40 80.40 80.40 B10 32.10 32,10 32,10 32,10 52.10 32,10 32,10 32,10 32,10 32,10 32,10 32,10 32,10 32.10 32.10 32.10 32,10 32.10 32,10 32,10 32.10 32.10 32,10 32,10 32,10 32.10 2.83 2.83 263 263 263 2.83 283 263 2.83 2.63 263 283 2.63 263 263 20 28 283 20 28 20 2 2 oe le 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 29.27 24.27 179.0 179.0 179.0 179.0 179.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 284.0 264.0 264.0 284.0 264.0 284.0 284.0 284.0 264.0 284.0 284.0 264.0 284.0 1.50 1.50 1.50 1.50 1.50 1.80 1.60 1,60 1.60 1.60 1.60 1.80 1.60 1.60 1.60 1.60 1.60 1.80 1.60 1.60 1.80 1.80 1.80 1.60 1.60 1.60 1.80 176.3 176.3 176.3 176.3 176.3 278.9 278.9 276.9 278.9 278.9 2769 2789 2789 6789 2789 2789 2789 278.9 278.9 276.9 276.9 278.9 278.9 2789 2789 2769 2789 205.6 205.6 205.6 205.6 205.6 308.2 308.2 308.2 306.2 308.2 308.2 308.2 306.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 308.2 306.2 WB2 5.64 6.40 6.47 6.52 6.57 6.63 6.67 \ 6.71 6.76 6.80 6.85 6.90 6.95 7.00 7.05 7.10 7.15 7.21 7.27 7.32 7.32 7.382 7.322 7.32 7.2 1.2 1.8 194.0 192.4 192.3 192.2 192.1 287.7 287.6 287.5 267.3 267.2 287,1 266.9 286.7 286.6 286.4 286.3 286.1 285.9 265.6 285.6 285.6 285.6 285.6 285.6 285.6 285.6 285.6 * Petual installed caoacity is 1.6 MW retiring im 2004 nowever none of the caoacity 18 ceoendan.e. THERPRO OCTOBER 18, 1984 THERMAL PROJECTS (Ne of Taku) Lewon Creek 1 Lemon Creek 2 Leson Creek 3 Lemon Creek 4 Leaon Creek 5 Lemon Creek 6 Lenon Creek 7 Lemon Creek 8 ieson Creek 9 Lemon Creek. 10 Leaon Creek 11 Gold Creek 1 Gold Creek 2 Gold Creek 3 Gold Creek 4 Gold Creek 5 GHEA 1 GHEA 2 {Total Therwal Capacity (Mid) JUNEAU 20 YEAR PLAN SUMMARY OF EXISTING & COMMITTED THERMAL PROJECTS BeeESIZERE 3 (All North of Taku) (Existing Prime Diesel (MH) 1.25 1.20 3.50 114 1.14 3.00 2.50 On-line Year 199 1969 1974 1983 1980 1983 1985 1985 1985 1985 1985 1952 14 1961 1963 1966 1983 1975 Retirewent Year 1994 1994 1999 2010 2010 2010 2010 2010 1987 1989 1991 1993 1996 1984 250 2.50 2.50 2.50 1985 2.50 2.50 2.50 2.50 Canacity by Year 1986 1987 1988 1989 1990 2.50 2.50 2.50 250 2,50 2.50 250 250 2.50 2.50 2.50 250 250 2.50 250 2.50 2.50 2.50 250 250 1991 2.50 2.50 2.50 2.50 1992 2.50 2.50 200 2.50 1993 2.50 2.50 2.50 2.50 1994 0.00 0.00 2.50 2.50 1995 0.00 0.00 2.50 2.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 0.00 0,00 0.00 0.00 0.00 1.25 1.20 3.50 1.14 1.14 3.00 2.50 2.50 2.50 2.50 2.50 2.50 1.25 1.20 3.50 1.14 bad 3.00 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2,50 2.50 1.25 1.20 3.50 114 114 0.00 1.20 3.50 114 114 0.00 0.00 0.00 1.20 0.00 0,00 3.50 3.50 3.50 11h 14 Led 14 14 1.14 3.00 2.50 3.00 2.50 3.00 2.50 3.00 2.50 3.00 2.50 2.50 2.50 2.50 2.50 250 0.00 0.00 0.00 1.14 114 3.00 2.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 14 1.14 3.00 2.50 250 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 114 3.00 2.50 2.50 2.50 2.50 2.50 2.00 0.00 0.00 0,00 0.00 1.14 3.00 2.50 2.50 2.50 2.5 2.50 2.50 0.00 0.00 0.00 0.00 114 3.00 2.50 1996 0.00 0.00 2.50 2.50 1997 0.00 0.00 2.50 2.50 1998 0.00 0.00 2.50 2.50 Exhibit 1-B 1999 2000 2001 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.50 2.50 2.50 2002 0.00 0,00 0.00 2.50 2003 0.00 0.00 0.00 2.50 2004 0.00 0.00 0.00 2.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17.50 17,50 17.50 17.50 17.50 17.50 17.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0,00 0.00 3.00 2.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0,00 0,00 0.00 3.00 2.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 2.50 2.50 2.50 250 250 250 25 250 25 2.50 2.50 250 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3.00 3.00 3.00 2.50 0.00 0.00 Ns 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 2.50 2.50 2.50 250 2.50 0.00 - 0.00 0.00 0.00 0.00 3.00 0.00 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 *0,.00 0.00 3.00 0,00 2005 0.00 0.00 0.00 2.50 0.00 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 2006 0.00 0.00 0.00 2.50 0.00 2007 0.00 0.00 0.00 2.50 0.00 17,50 17.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0,00 0.00 0.00 3.00 0.00 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 3.00 0.00 2008 0.00 0.00 0.00 0.00 0.00 0.00 2.50 2.50 2.50 2.50 2.50 “0,00 0.00 0.00 0.00 0.00 0.00 0.00 2009 0.00 0.00 0.00 0.00 0.00 0.00 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59,14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53,00 53.00 35.50 35.50 35.50 12.50 12.50 12,50 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 20.00 20.00 20.00 20.00 20.00 17-50 15.00 15.00 15.00 15.00 15.00 15.00 15.00 15.00 12.50 12.50 2010 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 JuNLoss OCTOBER 18, 1984 BASE CASE Exhibit 1-C LOCAL SYSTEM LOSSES YEAR 1984 1985 1986 1987 1988 1989 199 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 ) PEAK DEMAND (Wl) 41.3 55.1 57.9 60.3 626 64.8 66.6 685 70.4 724 74 76.5 76.6 80.7 829 65.2 87.5 89.9 9.3 9.8 94.8 %.8 94.8 94.8 94.8 9.8 98 ) ENERBY SALES (Gen) 215.1 230.6 242.4 252.6 2624 271.5 279 2669 295 303.3 311.8 320.6 329.3 336.2 347 356.8 366.4 3763 3865 397 397 397 «397 «397 397 397397 LOAD FACTOR 0.59 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0,48 0.48 0,48 0.44 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.48 LOSS FACTOR . 0.39 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 G9KV CAPACITY LOSS (Mid) 0.46 (0.82 0.91 0.98 1.06 1:13 1.20 1.27 13h 142 149 1,58 1.67 1.76 1.86 1.96 2.07 2:18 230 243 2.43 243 2.43 2.43 243 243 2.43 GSKV ENERGY LOSS (Gwh) 158 1.93 213 231 2.49 267 282 2.989 315 3.33 352 3,72 3.93 414 4.36 4.61 486 513 5.41 S71 5.71 S71 5.71 5.72 S71 5.71 5.71 FEEDER CAPACITY LOSS (Md) 1.63 2.55 2.70 2.84 2.96 3.09 319 3.30 341 3.53 3.65 377 3.0 4.03 417 43! 4.45 462 4.76 4.93 4.93 4.93 493 4.93 4.93 4.93 4.93 FEEDER ENERGY LOSS (Gwh) 10.55 12.84 13.55 14.17 14.76 15.32 15.79 16.28 16.78 17.30 17.84 18.39 18.95 19.52 20.10 20.73 21.35 22.01 22.67 23.37 23.37 23.37 23.37 23.37 23.37 23.37 23.37 JUNEAU CAPACITY LOSS (MW) 2.29 337 361 3.82 4.02 4.22 439 4,57 475 4.95 5.14 5.35 5.57 5.79 6.02 6.27 6.52 6.79 7.05 7.35 7.35 7.35 7.35 7.35 7.35 7.35 7.35 - JUNEAU ENERGY LOSS (Gwh) 12.13 14.77 15,68 16.48 17.25 17.99 18.61 19,26 19,93 20.64 21.36 22.11 22.68 23,66 24.46 25.34 26.21 27.13 28.08 29,08 29.08 29.08 29.08 29.08 29.08 24.08 29.08 (JUNEAU CAPACITY LOSS (x) 5.55 6.12 6.23 6.33 6.43 6.52 6.59 6.67 6.75 6.83 6.91 7.00 7.09 7.17 7.26 7.36 7.45 7.55 7.65 7.76 7.76 7.76 7676 7.76 7.75 7.76 7276 (JUNEAU ENERGY LOSS (x) 5.64 6.40 6.47 6.52 6.57 6.63 6.67 6.71 6.76 660 665 6% 695 7.00 7.05 710 715 7.21 7.27 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.38 Capolan OCTOBER 18, 1964 BASE CASE THERMAL JUNEAU 20 YEAR PLAN Exhibit 1-D YEAR 1984 1985 1966 1987 1988 1989 199% 1991 1992 1993 1994 1995 1996. 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 RESOURCES AS OF 1984 ) Existing and Committed Net Hydro Resources 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 South of Taku Inlet thru Thane > Existing and Committed Hydro Resources 5.62 8.62 8.62 6.62 8.62 6.62 8.62 8.62 6.62 8.62 8.62 8.62 862 6.62 8.62 8.62 862 8.62 B62 862 G62 B62 8.62 B62 8.62 B62 8.62 North of Taku Inlet ) Existing and Committed Thermal Resources 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 {All North of Taku) Total Existing and Committed Net Resources 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 South of Taku Inlet thru Thane Total Existing and Committed Net Resources 64.54 79.84 79.84 78.59 78.59 77,39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21.12 21.12 8.62 North of Taku Inlet EXISTING AND COMMITTED RESOURCES 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 60.4 (After Transmission Losses) DEMAND ( Peak Demand 41.3 55.1 57.9 60.3 62.6 64.8 66.6 68.5 70.4 72.4 74.4 76.5 78.6 80.7 62.9 85.2 87.5 89.9 92.3 3.8 4.8 94.8 94.8 94.8 94.6 94.8 94.8 Reserve Requirements 35.5 46.5 49.3 51.7 54.0 56.2 580 59.9 61.8 63.8 65.8 67.9 70.0 721 743 76.6 78.9 61.3 83.7 86.2 86.2 86.2 86.2 B62 86.2 86.2 86.2 (Equal to Peak Dewand Less Hydro North of Taku) EXISTING RESERVE MARGIN 232.2 24.7 21.9 183 16.0 12.6 10.8 5.4 35 0.4 6.6 -8.7 -12.0 14.1 -16.3 -21.1 -25.9 -28.3 -30.7 -33.2 -33.2 -50.7 -50.7 -50.7 -73.7 -73.7 86.2 (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet 0.0 0.0 0.0 0.0 0.0 00 0.0 00 0.0 0.0 0.0 00 0.0 00 0.0 00 0.0 0.0 0.0 0.0 0.0 00 0.0 00 0.0 0.0 00 (Capacity as measured at Thane) hydro North of Taku Inlet 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 00 00 00 Thermal North of Taku Inlet 0.0 0.0 0.0 0.0 00 00 00 00 00 00 50 50 00 50 00 50 50 50 00 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 TOTAL ANNUAL ADDED CAPACITY 0.0 0.0 0.0 0.0 00 0.0 0.0 00 00 00 50 50 00 50 00 50 50 50 00 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 CUMULATIVE ADDED CAPACITY 0.0 0.0 0.0 0.0 00 0.0 00 0.0 00 0.0 5.0 10.0 10.0 15.0 15.0 20.0 25.0 3.0 3.0 35.0 35.0 50.0 50.0 50.0 75.0 75.0 9.0 TOTALS AFTER ADDITIONS Hydro north of Taku 5.82 8.62 8.62 6.62 8.62 8.62 6.62 8.62 6.62 862 8.62 8.62 8.62 8.62 G62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 hydro south of Taku 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 Thermal (North of Taku) 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.1469.14 68 73° 73 75.5 78 63 63 68 88 85.5 85.5 85.5 87.5 67.5 W RESERVE REQUIREMENTS AFTER ADDITION 35.48 46.48 49.28 51.68 53.98 56.18 57.98 59.88 61.78 63.78 65.78 67.88 69.98 72.08 74.28 76.58 78.88 81.28 83.68 66.18 86.18 86.16 66.18 86.18 86.18 86.18 66.18 RESERVE MARGIN AFTER ADDITIONS 23.2 24.7 21.9 183 16.0 126 108 5.4 35 04 -1.6 1.3 -2.0 0.9 -1.3 -bed 09 1.7 -0.7 1.8 1.8 07 -0.7 07 1.3 1.3 38 RESULTING TOTAL CAPACITY 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 144.5 149.5 148.4 153.4 153.4 155.9 158.4 163.4 163.4 168.4 168.4 165.9 165.9 165.9 167.9 167.9 170.4 OCT 18,1984 BASE CASE THERMAL ‘YEAR ENERGY SALES FORECAST (Esch) ) LOCAL LOSSES (%) GADSS ENERGY REQUIREMENT (Gah) AAT SUBSTATIONS) EXISTING & COMMITTED HYDRO 1984 215.1 ‘5.64 212 ) NET GENERATION POTENTIAL (BMH) 205.6 NET GENERATION ACTUAL (Gin) ‘NEM HYDROELECTRIC PROJECT: YEAR ADDED CAPITAL COST (#000) FINED 8m COSTS (#000) UAMET ENERGY REQUIREMENTS (Gah) NET GENERATION POTENTIAL (Gen) NET GENERATION ACTUAL (Gh) PROJECT: ‘YEAR ADDED CAPITAL COST ($000) FIXED O8M COSTS ($000) UNMET EXERGY REQUIREMENTS (Gosh) NET GERERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gen) NEM TRANSATSSION PROJECTS YEAR RODED CAPITAL COST (8000) FIXED O8" COSTS ($000) URET ENERGY REQUIREMENTS (Gen) NET GENERATION POTENTIAL (Bah) NET GENERATION ACTUAL (Gen) ENERGY LOSS (x) ENERGY PURCHASED (Gh) UNIT EDST AT SOURCE (8/E«n) PURCHASED ENERGY COST ($000) NEW PRIME THERMAL TYPEa Prise Diesel CAPACITY ADDED (tad CURULATIVE CAPACITY ADDED (mal) 205.6 21.6 0.0 2.6 0.0 21.6 0.0 1985, 20.6 6.40 265.4 205.6 203.6 0.0 3.8 0.0 8 0.0 1986, 242.4 6.47 2581 205.6 205.6 52.5 0.0 525 0.0 0.0 1987 252.6 6.52 269.1 205.6 205.6 0.0 63.5 0.0 0.0 1388 262.4 6.57 273.7 205.6 205.6 74d 0.0 TA 0.0 Ted 0.0 1989 271.5 6.63 289.5 08.2 269.5 0.0 0.0 0.0 0.0 0.0 0.0 1990 273.0 6.67 297.6 308.2 297.6 0.0 0.0 0.0 0.0 0.0 0.0 1991 266.9 6.71 6.2 a2 6.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.8 0.0 1993 433 6.80 Bd 308.2 Wa2 15.8 0.0 15.8 0.0 15.8 0.0 194 3.8 6.85 Be Wa.2 08.2 25.0 0.0 25.0 0.0 5.0 0.0 0.0 0.0 36 0.0 Exhibit 1-£ Sheet 1 of 3 19% = 1997 223 Bae 6.95 7.00 322 9 39 3082 308.2 Wa2 = WR2 44.0 3.7 0.0 0.0 400537 0.0 0.0 440 53.7 0.0 0.0 0 0 1998 7.0 7.05 a5 308.2 wae 0.0 0.0 63.3 0.0 4.0 0.0 1.0 0.0 4.0 0,0 366.4 WAS 392.6 08.2 308.2 0.0 4.5 0.0 aS 0.0 6.3 22 403.4 WR2 8.2 6.3 0.0 6.3 6.3 0.0 e002 003 HE 386.5 1a 14.6 8.2 08.2 106.4 0.0 106.4 0.0 106.4 0.0 37.0 LR 426.1 17.9 0.0 117.9 u7.9 0.0 37.0 LR- 4B 08.2 WOR2 - M79 0.0 M29 0 17.9 0.0 397.0 LR 426.1 308.2 8.2 7.9 0.0 ung 79 0.0 397.0 LR ACB. Ha.2 8.2 117.9 0.0 79 0.0 17.9 0.0 2007 337.0 LR 426.1 08.2 whe 117.9 0.0 7.9 0.0 N79 0.0 2008 397.0 LB 426.1 308.2 8.2 117.9 0.0 7.9 0.0 i17.9 0.0 2009 397.0 LR $26.1 308.2 08.2 17.9 0.0 N29 0.0 U7 10 2010 397.0 LR 426.1 8.2 8.2 79 0.0 79 0.0 17.9 . Exhibit 1-C ChotTm@ COST 19000 Sheet 2 of 3 ous 6 eae FINED OAK COST (60001 o WHET ENEREY REDUIRENENT (Gan) a6 96 SBS TAL 00 8000 6B HSB 50 BO SLT B70 SHS 106 N73 799. NET GENERATION POTENTIAL (Guts) 0.67 LOAD FAC, 00 060 00 60 00 of 0 00 00 00 00 00 00 00 0.0 0.0 oo «830 TTT NET GENERATION ACTUAL, (Gah) 00 06.0 806.0 0 00 00 00 00 0.0 00 800 00 0.0 20 86600 SS Dk BeRGY LOSS (8) ° BERG GOERATED (Gad 00 800 08.000 0.0 rr a) 0.0 a0 8 0.0 0.0 00 60ND TU FEL USE (le UIT 13 . TMITIAL, FUEL PRICE (8/UMITY 0.989 . FUEL ESCALATION ARTE. (3/YERA) 1984-1968 0 1989-2003 3 FUEL PRICE «8/UNIT) 0.959 0.959 0.959 0.959 0.959 0.988107 OM 079 EAS TI AIS ST 289 TST OAS LAA LAW 1A 141A LH + FUEL COST ($000) 00 8060 800 8900 © OO Cr ee) 00 © (00 a0 0.0 00 60 00 00 PAH.9 © B82H.0 8.0 PLO ACO SL SH 1162 OAIRBLE DAN RATE (CENTS iat) o8 WAAIRELE 08M COST (8000 00 80600 0 a) 00 (00 00 84800 O06 00 00 20 866.000 a 2B HB HB HB SS SITLL New STANDBY THERA, TE: Diesel CRORCITY ODED (m8 so) 80 30 3.0 So 30-00 1500 OO CUMULATIVE CRERCITY AOOED OW) a a) 0.0 00 00 0.0 0.0 a) 30 100 100 13.0 1.0 HOO ASAT PITAL COST 180001 461.1 (so007mH 00 0.0 = 0. 0.0 00 860000 0.0 = 0.023055 2853 0.0 285S 002805, 2805.5 00 © 0.0 256.5 0.0 6916.5 0.0 = 0.0 9222.0 0.0 25.5 FINED 04N COST (8000) 25 (900078) 0 0 0 0 0 0 ° 0 o 0 Ins 3s BS BS sas 7 875 OS BLS. 105 105 13S 1S ISS ATS ASS EXISTING PRUE DIESEL > CAPACITY 125 3 a a 3 3 3 a a a 2 2 20 2 2% nS 3 1s 5 1s is 13 1 1@S a5 ° (WET ENERGY REQUIRED (Gab) <r 0.0 0.0 0.0 66 158 20 6 0 S27 623 0S OS Cd 05 CAPRCITY UTILTIQATION FACTOR = 0.67 (POTENTIAL NET GEXERATION POTENTIAL (Bat) TRA 1M6.7 M7 RTT MT TT TMT 7, 74) MTA LIA 102.7 BOLO BLOB. OTA TR 0.0 NET GENERATION ACTUAL (Gah) a6 BS BRS TAL 00 00 0.0 68 158 BO M6 40 SLT 6330 0 SSE OOOH LSP 0.0 DERSY LOSS (8 0 0 0 0 0 0 ° ° 0 0 0 0 0 ° 0 0 0 ° 0 ° 0 0 o ° ° 0 0 ERGY GDERATED (Gud a6 8 SAS BRS TAL 0.0 00 00 66 156 20 %6 40 S27 623 7.0 OS 659 71 BAO BO BAO ba AAO FUEL USE (at GAL) ins INTTIRL FUEL PRICE (9/684) 0.58 FUEL ESCALATION RATE (3/YERR) 1984-1988 9 1989-2003, 3 FUEL PRICE (8/UMITY 0.98 0.959 0.959 0.959 0,988 017A 079M NMS LATS 12NS SL H28 PTR LAS ASAD hha 498 FUEL COST «80000 157.8 2821248103 SAS 000.0 SALB 129% 2120.3 BOK. HEL 497 GON ZTE GSS. AT. © 82H2-1 HS «TANS «ALS «MARS GAS GSA? 6ST 0.0 \VARLAOLE 08K COST (9000) 0.8 COMI «172 HBS AO OSHS LOL 0.0 2 12 200A SA AE SHLB BIST S24 IEG © 70.3703 704.3 TOS 103 ATL ATRL 0 UWET BXERGY REQUIRERENT (Ea) 00 06.0 00.0 Cr a eC) 00 8 0.00 0.0 0.0 © (0.0 00 00 Cn ee) 05 os 05 05 06.0 00 0.5 ‘SIWORY OF MET GENERATION EXISTING & COWITTED HYDRO (6) 9.47 81.79 79.65 76.40 73.51 100,00 100.00 100,00 97.8313 SO 9. 5.16 62.9% G8. 6 HB TR OR OR OR WR WR RR AR NEM HYDROELECTRIC (8) 0.00 0,00 0,000.00 0,00 0.000.000.0000 0,000.00 0.00 0.00 0.00 0,000.00 0,00 0,000.00 000,000.00 .00 0,000,000 NEM TRERMISSION [OORT 18) 0.00 © 0,00 0,000.00 0.00 0.000.000.0000 0.00 0,00 0.00 0.00 0,00 (0,00 0.00 0.00 0.000.000.0000 0.000.000.0000 Nw PIPE THERA 81 0.00 0.00 0.000.000.0000 0,000.00 ,00, 0.00 0,00 0,00 0,000.00 0.00 72) 7.06689 SBF FBT 1B TBS EXISTING PAINE DIESEL «x 352 16.21 2 2860-2649 0.000.000 7.50 10.08 12.50 14.84 17,04 15.35 EST 18.59 2S OG 20S OSLO. SHORTFALL U8 0.00 0.000.000.0000 0.00 0.00000 0.00 0,000.00 0.00.00 0,008.00 0.000013 OSHS OSD 0A Summa OF Lam CO6TS CAPITAL COSTS (#000 00 © 0.0 00 0.0 FIXED 04m COST (8000) ao © 00 20 00 WARLABLE 04M COST (#000) 172 HE 42.0507. PUROPSED ENERGY (90000 a0 8660) 600 FUEL COST (4000) 1537.0 2826.1 372.1 4510.3 TOT YEARLY COST (9000) 17.0 4 4.0 S012 DISCOMNTED YEARLY COST (#000) HM TRA 4526.1 BASE YERR is DISCOUNT RATE (3) as UR DISCOUNTED COST (4000) 6622.2 131484 QM, DISC. COST TO 2010 ‘s000) 130526 SM MON-CAPLTAL COSTS IM 201012876 (9000) VALUE IX 2010 OF MON-CAPLTAL — 257SE3 COSTS THAU 2045 (#000) DISCOMTED MON-CAPITAL COSTS 105289 BEYOND 2010 (40000 SEPLSCENENT COST AAD) SALVAGE VALUE DETERMINATION (NEM UNITS) wit crerciTY vena ODED FEPLACENENT ow vom HrDaO #1 ‘arora 42 ‘TRSWGALSSION PRIME THERA 1 3 e001 mei PRIME THERM 2 3 2008 08 PRIME THER 42 10 2010 2030 STAWOY THERMAL 41 a 194 204 STAROBY THERA 42 s 1995 20s STANDBY THERA 4 3 1997 eur STANOBY THERWA 04 3 1999 209 STANDBY THERMAL 5 5 2000 2020 STANOY THERMAL 06 3 e003 e0e3 STANOGY THERMAL 7 3 2005 oes STANDBY THERNA. 08 a 2008 08 ‘STANDBY THERMAL. 09 5 a0 co STAROBY THER 2 ‘STANDBY THERA, STORY THER 812 ‘STANDBY THERA 13 sum (9000) NET DISCOUNTED REPLACERENT COSTS AAD SALVAGE VALLES (4000) 12383 TOT. DISCOUNTED PLsw COSTS (8000) pred a) 00 © 00 $2.5 00 00 © 00 31500 Se. 0.0 10.5 0.0 18249.916209.9 REPLACEMENT ema we 201 ° ° 2m 2035 0x7 209 2040 203 ° ° ° ” 0.0 0.0 0.0 0.0 a0 a0 18249.9 0.0 0.0 0 0.0 0.0 a0 00 18249.9 RETIRERENT vee eSEZEER SESE EE 0.0 0.0 ae 0.0 16 ws24 18702, 3 0.0 0.0 16.2 0.0 1298.3 nes 1008.9 1978.2 CrerTA. ast ($000) 46.0 4116.0 6278.0 2305.5 25.5 205.5 205.5 2005.5 205.5 6916.5 22.0 2305.5, 2305.5 15 200.0 0.0 2120.3 AR a7 23033.9 Exhibit 1-£ Sheet 3 of 3 205.5 0.0 2405.5 B00 SAS HS B22 A 00 0.0 0.0 BOiS.1 3961.2 4977.3 366.0 AWEI 764.9 360.4 2877.6 4964.9 5900.3 2978.0 4742.9 DIScREPLOL IScREALA2 «sooo (9000) 0.0 0.0 0.0 0.0 0.0 0.0 1182.6 37.3 05.9 0.0 1268.9 0.0 we 28 3.6 8.8 40.9 2.3 691.6 76 68.2 35.8 02.7 02.9 1687. 0.0 2029.8 0.0 1.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 a0 11858.2 23.5, 0.0 52.5 506.4 0.0 on3.e (6602.1 078.7 2005.5 70.0 91.8 0.0 RS 0201.8 une 4504.8 2045 SALAS VALUE (8000) eb ir 1969.5 1037.5 152.8 1383.3 1613.9 17.4 2075.0 0.0 1363.3 56.4 0.0 00 0 0.0 2305.5 5 on. 0.0 ass2.9 1622.6 6102.8 51637.6 4u16.0 os 2.2 0.0 ee 14358.9 He Dist SALE (8000) 03.8 73.7 192.5, 169.7 197.9 ai2.t 2A. 0.0 169.7 0.7 0.0 0.0 0.0 0.0 ans. 0.0 o.5 1.4 0.0 1120.0 12088. 9 482.0 2305.5 105.0 8.1 0.0 1266.5 160161 330.9 4535.0 0.0 108.0 8.1 0.0 1286.5 B06 6916.5 15.5 938.1 0.0 1866.5 2673.6 1081.4 1526.9 0.0 197.5, 933.1 0.0 128. 5S 136.1 AS7.0 7983.8 0.0 157.5 933.1 0.0 1866.5 1376.1 ous yoaeze.4 13338.0 ens WLI 0.0 12000.7 6908.6 1785.2 116007.7 0.0 27.5 wha 0.0 1200.7 1571.6 mee 1217303, 6961.5 205.0 98.1 0.0 1169.2 21988.7 ams 130824.0 i 1 Caaolan ° - - OCTOBER 16,1984 DOROTHY 1996 (w/Seoerate T-Line) YEAR RESOURCES AS OF 1984 ~ ) Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Committed Hydro Resources North of Taku Inlet > Existing and Committed Thermal Resources {All North of Taku) Total Existing and Comitted Net Resources South of Taku Inlet thru Thane Total Existing ano Cowmitted Net Resources North of Taku Inlet EXISTING AND COMMITTED RESTURCES (After Transmission Losses) ‘DEMAND ( Peak Demand Reserve Reauiresents JUNEAU 20 YEAR PLAN Exhibit 2-A 1984 1985 1986 1987 1984 1989 1930 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.62 6.62 8.62 8.62 6.62 6.62 8.62 6.62 B62 8.62 8.62 8.62 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 5.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.52 44.12 21,12 21.12 8.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92,9 B04 41.3 55.1 57.9 60.3 62.6 648 66.6 68.5 70.4 72.4 74.4 76.5 78.6 80.7 82.9 852 87.5 89.9 92.3 94.8 94.8 948 94.8 94.8 94.8 94.8 9.8 33.5 46.5 49.3 51.7 54.0 56.2 58.0 59.9 61.8 63.8 65.8 67.9 44.3 46.4 486 50.9 53.2 55.6 58.0 60.5 60.5 60.5 60.5 60.5 60.5 60.5 60.5 (Equal to Peak Dewand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet = (Capacity as measured at Thane) Hydro North of Taku Inlet ~ Thergal North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY ~ TOTALS AFTER ADDITIONS Hydro north of Taku ~ Hydro south of Taku Thertal (North of Taku) RESERVE REQUIREMENTS AFTER ADDITION ~ RESERVE MARGIN AFTER ADDITIONS RESULTING TOTAL CAPACITY 23.2 24.7 21.9 183 16.0 12.6 10.8 5.4 3.5 0.4 -6.6 -A7 13.7 11.6 94 4&6 0.2 -26 5.0 -7.5 -7.5 -25.0 -25.0 -25.0 -68.0 48.0 -60.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.0 0.0 25.7 0.0 0.0 0.0 00-00 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 0.0 5.0 5.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 15.0 0.0 0.0 25.0 0.0 10.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 00 0.0 5.0 5.0 25.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 15.0 0.0 0.0 25.0 0.0 10.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 5.0 10.0 35.7 35.7 35.7 35.7 35.7 35.7 35.7,35.7 35.7 50.7 50,7 50.7 75.7 75.7 85.7 5.82 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 A.62 8.62 34.32 34,32 34.32 34.32 34.32 34.32 34.32 34.32 34,32 34.32 34,32 14.32 34.32 34.32 4.32 45.93 45.93 45.93 45.93 45,93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64146914 68 68 686 655 63 63 63 63 63 60.5 60.5 60.5 625 625 60 35.48 46.48 49,28 51.68 53,58 56.18 57.98 59,68 61.78 63.78 65.78 67.88 44.28 46.38 48.58 50,88 53.18 55.58 57.98 60.48 60.48 60,48 60,48 60.48 60.48 60.48 60,48 23.2 24.7 21.9 183 16.0 12.6 108 5.4 35 0.4 -1.6 1.3 23.7 21.6 194 146 98 24 5.0 25 25 0.0 0.0 0.0 , 20 20 -0.5 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 144.5 149.5 174.1 174.1 174.1 171.6 169.1 169.1 269.2 169.1 169.1 166.6 166.6 166.6 168.6 168.6 166.1 ECOL OCT 16, 1984 ‘DOROTHY «1996 (u/Severate T-Line) YEAR 1984 [BERSY SALES FORECAST (Gun) rie ) LOCAL LOSSES (8) 5.4 GROSS ENERGY REQUIREMENT (Gah) = 227.2 (AT SUBSTATIONS) . EXISTING & COMMITTED HYDRO > NET GENERATION POTENTIAL (Gel) 205.6 NET GENERATION ACTUAL (Gib) 205.6 NEM HYDACELECTRIC PROJECT: DOROTHY ‘YEAR ADDED 1996 CAPITAL COST (#000) FIXED DIM COSTS (#000) UNMET ENERGY REQUIREMENTS (Gh) = 21.6 ‘NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gah) 0.0 PROJECT: YEAR ADDED COPITAL COST (#000) FIXED O4M COSTS (6000) UNPET ENERGY REQUIREMENTS (Gh) = 21.6 NET GENERATION POTENTIAL (Gah) (NET GENERATION ACTUAL (Bah) 0.0 NEM TRANSAISSION PROJECT: ‘YEAR ADDED CAPITAL COST (#000) FINED Oi" COSTS (#000) UNMET ENERGY REQUIREMENTS (Gch) = 21.6 KET GENERATION POTENTIAL (Gun) NET GENERATION ACTUAL (Gen) 0.0 ENERBY LOSS (1) ENERGY PURCHASED (Gah) UNIT COST AT SOURCE (6/Gen) PURCHASED ENERGY COST (#000) NE PRIRE THERMAL TYPES Prime Diesel CAPACITY ADDED (mu) CUMULATIVE CAPACITY ADDED (Mi) ° 230.6 6.40 2454 205.6 203.6 0.0 0.0 1986 242.4 6.47 Bal 205.6 25.6 32.5 0.0 25 0.0 25 0.0 1987 252.6 6.52 69.1 205.6 203.6 62.5 0.0 5 0.0 63.5 0.0 1988 262.4 6.57 273.7 205.6 205.6 mal 0.0 mal Tl 0.0 1989 271.5 6.63 269.5 0.0 0.0 0.0 0.0 0.0 0.0 1990 273.0 6.67 297.6 8.2 297.6 0.0 0.0 0.0 0.0 0.0 1991 286.9 6.71 6.2 Wa.2 6.2 0.0 0.0 0.0 0.0 1992 295.0 6.76 49 (08.2 8.2 6.8 0.0 6.8 0.0 6.6 0.0 1993 023 6.80 RBL9 e.2 8.2 17398 15.8 0.0 15.8 0.0 15.8 194 3.8 6.85 Be 308.2 8.2 5.0 0.0 0.0 Exhibit 2-B Sheet 1 of 3 1995, 1996 1997 20.6 29.3 38.2 6.90 6.95 7.00 H2.7 B22 B19 WR2 Wa.2 02 Mae Wa.2 8.2 any 304.8 304.8 WE 0 3.7 126 126 0.0 4.0 37 KB 0.0 0.0 0.0 0.0 0.0 H6 0.0 0.0 0.0 0.0 0.0 ° 0 ° 1998 W720 7.05 US 8.2 Wee WB 63.3 126 63.3 0.0 0.0 0.0 0.0 199 356.8 7.10 B24 06.2 6.2 8 74.0 126 14.0 0.0 0.0 0.0 0.0 2000 64 WAS 392.6 06.2 Wa.2 4.8 5 126 a5 0.0 0.0 0.0 0.0 v6.3 22d 03.4 08.2 8.2 We 8.3 126 ‘oe ] 0.0 0.0 0.0 2002-2003 Oh AS 2008, 65 12 414.6 8.2 82 AB 106.4 125 106.4 0.0 0.0 0.0 0.0 397.0 L2 425.1 8.2 wee WB 2.3 126 ung 0.0 0.0 0.0 0.0 337.0 LR ed 8.2 We.2 We u79 126 ung 0.0 0.0 0.0 0.0 397.0 1 4261 82 nO2 a8 17.9 125 429 0.0 0.0 0.0 0.0 397.0 LR A261 08.2 26.2 We 47.9 126, 429 0.0 0.0 0.0 0.0 2007 397.0 ad 461 WB und 126 112.9 0.0 0.0 0.0 2008 397.0 12 426 8.2 wa.2 4.8 N19 126 ung 0.0 0.0 0.0 2009 397.0 1.32 426.1 08.2 8.2 We 79 12 429 0.0 0.0 0.0 0.0 2010 397.0 LR 426.1 08.2 6.2 34.8 M79 12 M79 0.0 0.0 0.0 CAAITAL COST 18000 FLIED Om COST (80001 WHET ERGY REQUIRERENT (Gat) WET GENERATION POTENTIAL (Gun NET GENERATION ACTOR, (Gad ERGY LOSS tx) EXERGY GENERATED (xh) FEL USE (un/tniT) IWITIAL FUEL PRICE (O/LNITD FLEL ESCALATION ARTE (X/YERA) 1984-1988 1989-2003 FEL PRICE «/UMITD FEL CST (40001 VARIABLE OUR RATE (CENTS/iah) ‘VARIABLE OAN COST (9000 HOw STRNOEY THER Te: Diesel CRORCITY ADDED 8A CUMLATIVE CAPACITY AODED Ons CAPITAL COST 190001 FILED 04M COST 460001 LISTING PRIME DIESEL ) CARCITY om UwET DERE REQUIRED (Gan) CAPCITY UTTLTIZATION FACTOR (POTENTIAL NET GENERATION POTENTIAL (Gand NET GENERATION ACTUAL. (Gah) BERGY LOSS 181 EGY DERTED (tae FUEL USE fin BAL INITIAL, FLEL PRICE (976A) FUEL ESCALATION WATE (8/YERRD 1984-1988, 1989-2003, FUEL PRICE (6/T) FUEL COST (9000) \VARIRALE OLN COST (#0001 UWET QENGY REUIRERENT (fon) ‘SLPWARY OF NET GENERATION EXISTING & COmmTtED HDeO (8) NE HYORORLECTANC 08 NEM TRINGAISSION IROORT (3) NeW PAINE THERMAL (8) LISTING PAINE DIESEL (6) SHORTFALL 15) a 216 0.87 LORD FAC, 0.0 0.0 0 0.0 3 os 0 3 0.59 0.0 08 0.0 0.0 461.1 (80007 0.0 ‘13 (9000/m 0 25 2.6 O.6T ma 26 0 a6 125 0.589 0 a 0.989 19.8 0.8 CENT) 1722 0.0 90.47 0.00 0.00 0.00 3.53 0.00 Bb 0.0 0.0 0.0 0.959 0.0 0.0 0.0 0.0 46,7 338 0.959 2626.1 ‘uB83 0.0 83.79 0.00 0.00 0.00 16.21 0,00 52.5 0.0 0.0 0.0 0.959 0.0 0.959 3723.1 420.0 0.0 3.66 0.00 0.00 0.00 20.0 0.00 a5 0.0 0.0 0.0 0.959 0.0 a0 0.0 0.59 4310.3 07.9 0.0 16.40 0.00 0.00 0.00 23.60 0.00 mt 0.0 0.0 0.0 0.958 0.0 0.0 0.0 0.0 G7 mt ma 0.959 61.5 392.5, 0.0 Rest 0,00 0.00 0.00 26.49 0.00 0.0 0.0 0.0 0.0 0.988 0.0 0.0 0.9 0.988 0.0 0.0 0.0 100.00 0.00 0.00 0.00 0,00 0.00 0.0 0.0 - 0.0 0.0 1.017 0.0 0.0 0.0 0.0 146.7 0.0 0.0 1.017 0.0 0.0 0.0 100.00 0,00 0.00 0,00 0.00 6.0 0.0 0.0 0.0 0.0 1.088 a0 0.0 0.0 0.0 1467 0.0 0.0 1.048 0.0 0.0 0.0 100,00 0,00 0.00 4.00 0.00 0.60 6.8 0.0 0.0 0.0 0.0 0.0 46.7 68 ray 1.073 ALB we 0.0 77.85 0.00 0.00 0.00 215 0.00 15.8 0.0 0.0 0.0 Lue 0.0 0.0 0.0 ina 146.7 158 138 ue 1293.3 185.2 95.13 0.00 0.00 0.00 4.87 0.00 0 0.0 0.0 0.0 Ls 0.0 0.0 5.0 5.0 2505.5 15 nn ao a0 14s 21203 200.0 0.0 50 0.00 0.00 0.00 1.0 0.00 46 0.0 0.0 0.0 179 0.0 0.0 5.0 10.0 285.5 una WG Ww 179 3019.1 216.5 0 89.92 0.00 0.00 0.00 10.08 0.06 Exhibit 2-B Sheet 2 of 3 0.0 0.0 0.0 0.0 2s 0.0 0.0 10.0 0.0 ay 0.0 00 1215, 0.0 0.0 0.0 7.50 12.50 0.00 0,00 0.00 0.00 0.0 0.0 0.0 0.0 1.251 0.0 0.0 10.0 0.0 1.251 0.0 0.0 a0 85.16 164 0.00 0,00 0.00 0.00 0.0 0.0 0.0 0.0 1.289 0 0.0 10.0 0.0 47, 0.0 0.0 1.289 0.0 0.0 2.6 12.04 0.00 9.00 0,00 0,00 Lr 0.0 0.0 10.0 0.0 1.5 0.0 102.7 0.0 0.0 Le? 0.0 0.0 0.0 64 19.36 0.00 0.00 0.00 0.00 1.367 0.0 0.0 0.0 10.0 0.0 3s 15 0.0 68.0" 0.0 0 0.0 1,367 0.0 0.0 0.0 78.49 ast 0.00 0.00 0.00 0.00 1.408 0 0.0 0.0 0.0 3s 15 0.0 80 0.0 0 0.0 1408 0.0 0.0 0.0 6 23.62 0.00 0.00 0.00 0.00 0.0 0.0 0.0 0.0 1ASL 0 0.0 10.0 0.0 5 0.0 0 0.0 0.0 Last 0.0 0.0 0.0 ww oer 0.00 0.00 0.00 6,00 0.0 0 0 0.0 1a 0.0 0.0 0.0 10.0 0.0 1s a0 28.0 0.0 0 1.494 0.0 0.0 0.0 22 21.68 0.00 0.00 0.00 0.00 0.0 0.0 0.0 0.0 Law 0.0 00 0.0 10.0 0.0 5 fy 0.0 84.0 0.0 0.0 1.44 0.0 0.0 0.0 Re 27.68 0,00 0,00 0.00 0.00 0.0 0.0 0.0 0.0 144 0.0 0 10 20 6516.5 a5 13 0.0 oa.0 0.0 a0 1498 0.0 0.0 0.0 Rw 20.68 0.00 0.00 0.00 0.00 0.0 0.0 0.0 1498 0.0 a0 0.0 Bo 0.0 15 a0 88.0 0.0 0.0 Law 0.0 0.0 0 Re 21.68 0.00 0.00 0.00 0.00 0.0 0.0 0 0.0 144 0.0 0.0 0.0 a0 0.0 ans 13 0 08.0 0.0 0.0 1498 0.0 0.0 0.0 RB 27.68 0.00 0,00 0.00 0.00 0.0 0.0 0.0 0.0 23.0 50,0 n87.5 15 fas 00 Te 0.0 0.0 1.434 0.0 0.0 Re 21.68 0.00 0.00 0,00 0.00 0.0 0.0 0.0 0.0 0.0 0.0 iS 12.5 0.0 Re 0.0 140 0.0 0.0 0.0 2 22.68 0.00 0.00 0.00 0,00 ° 0.0 0.0 0.0 0.0 an 0.0 0.0 10.0 60.0 4611.0 210 0.0 0.0 0.0 140 0.0 0.0 0.0 cod 22.68 0.00 0.00 0.00 0.00 ‘sspeway OF Ase COSTS CHITA COSTS (4000) FINED Gla COST (8000) ‘VARIABLE O4M COST (9000) PUROSEED DEREY 18000) FUEL CORT (6000) TOIL YEAALY COST (9000) DISCOUNTED YERALY COST (9000) Bree YE DISCOLMT BATE (8) (Om. DISCOUNTED COST 14000) QM. DISC. COST TD 2010 60001 SR MOHOWITA COSTS 1H 2010 tw000) (VALUE 1 2010 OF AOM-CAPITAL, COSTS THAN 2045 (8000 DISCOUNTED MON-CAPITAL, COSTS SEvIRO 2010 (40001 REALRCENET COST (0) SALVAGE VALLE DETERMINATION (NEW UNITS) wat rpm a Hera 82 TROGAISSION PRUE TEL OL PRIME Too 42 PRIME THER 83, STAROBY THERMAL 1 STOwOOY THERMAL 02 ‘STAWDAY THERMAL 03 STORY TERM, STAOSY THERA 5 STROBY THERMAL 66 ‘STiwO8Y THERMAL 47 STORY THERE 68 STAOSY THERA 09 STenosy TERNAL #10 STAMOSY THERA O14 STANDSY THERNL 412 STmCSY THERA. 813 ‘SN (90001 1984 a3 os us 10296 4210 ercity “a a 0.0 0.0 m2 0.0 1597.8 m0 amL.0 m.0 NET DISCOUNTED REPLACERENT COSTS Aad SALVAGE VALLES ($000) TOTAL DISCOUNTED PAW COSTS (HOU) 0.0 0.0 ua3 0.0 826.1 To Pay a8 16 1H 195 ano 0.0 0.0 420.0 0.0 91 4169.0 rhe 622.2 ere 10ST 0.0 0.0 01.9 0.0 4510.3 wine 461 sae RERACERENT YEAR a1 \ 00 8 00 0.0 0.0 532.5 0.0 0.0 0.0 S615 0.0 ES a0 SILLS 0.0 162499 18249.9 PEPE Yaa 92 0 0 «0 0 20H as ° 0 0 0 ” 0 0 ” 00° 0.0 0.0 0.0 0.0 0.0 1249.9 0.0 a0 00 0.0 0.0 0 1249.9 RET OENT EBeees ssesesae 0.0 0.0 2 0,0 ML ae 1702.3 1733.0 0.0 126.2 0.0 121.3 18821,5 13809.9 wee ceria cast (8000) 75628.0 0.0 0.0 0.0 2305.5 2305.5, 6916.5. W275 4611.0 4800.5, 12S 200.0 0.0 2120.3 1168.3 2639.3 ‘8861.5 DIScRERL 280225 3.0 265 0 wat uSLO aura 2036.6 ‘90001 0.0 0.0 0.0 0.0 0.0 8.0 4 TL6 1687.8 Bae wr 0.0 0.0 rx) 0.0 0.0 0.0 0.0 0.0 6787.5 Exhibit 2-8 Sheet 3 of 3 0.0 0.0 Bae Bs 0.0 0.0 0.0 0.0 0.0 0.0 ma a8 29 217.3 061.5 6077.8 DISCRERLA2 (90001 0.0 a0 0.0 0.0 0.0 0.0 412.8 ae 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cr) BA U8 00 © 00 a) a) me B88 20,9 ane . > i co foo, ? - 0.0 £0 00 0.0 09S OAS OO B26 UA RA] IAT 0.0 0.0 0 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0 00 00000 0.0 00 00 00 To) 1960 02.3 182.9 176.7 170.8 ARH. SATO OS 0588.7 1191.5 1367.5 BISTE.S G1TSS.8 AISA 8107.1 BMS 2 ASANO] AEOIRL «912768 SIN7S.8 SESTS.4 2045 sane ‘VALLE 180000 1812.8 0.0 0.0 0.0 1037.5 as, 0.0 124.1 se8 0.0 0.0 0.0 0.0 0.0 0.0 oo 0.0 DISC SALES 190001 15.5 0.0 0.0 0.0 Wenz We 0.0 ait a 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a0 O18 Caoolan OCTOBER 22, 1984 DOROTHY 1996 (w/Snet T-Line) YEAR RESOURCES AS OF 1984 ) Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Comaitted Hydro Resources North of Taku Inlet ) Existing ano Committed Thermal Resources (ALL North of Taku) Total Existing and Committed Net Resources South of Taku Inlet thru Thane Total Existing and Committed Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transuission Losses) DEMAND ( Peak Deeand Reserve Requirewents JUNEAU 20 YEAR PLAN Exhibit 3-A 1984 1985 1966 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2069 2010 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 74.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.82 8.62 6.62 8.62 8.62 8.62 8.62 8.62 6.62 4.62 8.62 6.62 8.62 6.62 B62 B62 8.62 8.62 8.62 8.62 862 862 862 8.62 B62 8.62 8.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 54.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45,93 45,93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 11.78 71.78 71.78 71.78 71.78 74.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44,12 44.12 44.12 21.42 21.12 8.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 60.4 41.3 S51 57.9 60.3 62.6 64.8 66.6 685 70.4 72.4 74.4 76.5 78.6 80.7 82.9 B52 87.5 89.9 92.3 94.8 9.8 94.8 94,8 948 94.8 94.8 948 $5 46.5 49.3 51.7 54.0 56.2 58.0 59.9 61.8 63.8 65.8 67.9 70.0 721 743 76.6 78.9 B13 83,7 B62 86.2 86.2 B62 B62 B62 85.2 66.2 (Equal to Peak Demand Less Hydro North of Taku) EXISTING RESERVE ARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet (Capacity as measured at Thane) Hydro North of Taku Inlet Thermal horth of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS rydro north of Taku Hydro south of Taku Thermal (North of Taku) RESERVE REQUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TOTAL CAPACITY 23.2 24.7 21.9 183 16.0 12.6 108 54 35 0.4 66 -8.7 -12.0 -141 -16.3 -21.1 25.9 -28.3 -30.7 -33,2 ~33.2 -50.7 -50.7 -50.7 -73.7 -73.7 -B6.2 0.0 0.0 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 25.7 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0,0 0.0 0.0 00 0.0 00 5.0 5.0 5.0 00 50 5.0 00 50 0.0 5.0 00 15.0 0.0 0.0 25.0 0.0 10,0 00 00 60 00 00 00 0.0 00 0.0 0.0 5.0 5.0 30.7 0.0 5.0 50 00 5.0 00 5.0 0.0 15.0 0.0 0.0 25.0 0.0 10.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 5.0 10.0 40.7 40.7 45.7 50.7 50.7 55.7 55.7 60.7 60.7 75.7 75.7 75.7 100.7 100.7 110.7 5.82 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 B62 8.62 4.62 8.62 8.62 8.62 8.62 8.62 8.62 6.62 4.62 8.62 8.62 8.62 8.62 8.62 8.62 45.93 45.93 45.93 45,93 45,93 71.78 71.78 71.78 73.78 71.78 71.78 71.78 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 97.48 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 73 73 78 80.5 78 83 83 68 88 85.5 85.5 85.5 87.5 87.5 65 35.48 46.48 49.28 51.68 53.98 56.18 57,98 59,88 61.78 63,78 65.78 67.88 69.98 72.08 74.28 76.58 78.68 61.28 83.68 86.16 86.18 86.18 86.18 86.18 6,18 86.18 B6. 18 23.2 47 21,9 183 16.0 126 108 54 35 Of -16 13°30 0.9 37 39 O19 17 7 18 1.8 07 7 -07 13 13 -b2 110.5 125.8 125.8 124.5 1245 149.2 1492 145.7 145.7 144.5 144.5 149.5 179.1 1791 184.1 186.6 184.1 189.1 189.1 194.1 1941 191.6 191.6 191.6 193.6 193.6 191.1 OCT 22, 1964 ‘DOROTHY «1996 (w/Sret T-Line) YEAR 1984 ENERGY GALES FORECAST (Gah) 21st > LOCAL LOSSES (#) Pao] GROSS ENERGY REQUIREMENT (Gen) = 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDRO > NET GENERATION POTENTIAL (GH) = 205.6 NET GEXERATION ACTUR. (Gem) 2.6 PROJECT: DOROTHY ‘YEAR ADDED 1996 CAPITAL COST (9000) FIXED O44 COBTS (8000) UNPET ENERGY REQUIREMENTS (Gh) = 21.6 NET GENERATION POTENTIAL (Gan) NET GENERATION ACTUAL (Gen) 0.0 PROJECT: YEAR ADDED CAPITA COST (9000) FIXED 06m COSTS (9000) UNMET ENERGY REDUIREMENTS (Gun) = 21.6 NET GENERATION POTENTIAL (Gem) (NET GENERATION ACTUAL (Gen) 00 NEM TRANSMISSION PROJECT: YEAR ADDED CAPITA COST (9000) FINED 08m COSTS (8000) WOET ENERGY REQUIREMENTS (Geen) 21.6 NET GENERATION POTENTIAL (Gan) NET GENERATION ACTUAL (Gen) 0 ENERGY LOSS (1) ENERGY PURDHRSED (Gan) UNIT COST AT SOURCE (6/Gen) PURCHASED ENERGY COST (#000) NEM PRIME THERA TYPE: Prime Diesel CAPACITY ADDED (md) CURATIVE CAPACITY ADDED (nm) o 1985, 20.6 60 rt) 205.6 6 3.8 0.0 ne 0.0 8 0.0 1986 e424 6.47 oe 265.6 258.6 25 0.0 25 0.0 25 0.0 1987 22.6 6.52 9.1 205.6 205.6 63.5 0.0 65 00 63.5 00 1988 262.4 6.57 273.7 205.6 6 ma 0.0 m1 0.0 ma 0.0 1989 27.5 6.63 288.5 0.0 0.0 0.0 0.0 0.0 0.0 1990 279.0 6.67 27.6 wae 21.6 0.0 0.0 0.0 0.0 0.0 1991 266.9 67 6.2 8.2 we2 0.0 0.0 00 0.0 00 0.0 1982 295.0 6.76 ued 6.2 wee 66 00 68 a0 68 0.0 1993 wi.3 6.00 Big Mae wae 16541 13.8 0.0 15.8 00 15.8 0.0 1994 U8 6.85 Be 8.2 wee 3.0 0.0 5.0 0.0 0.0 1995, 20.6 6.90 We7 308.2 we2 we 0.0 0.0 we 0.0 19% B33 6.95 B22 08.2 16.2 4.8 126 “0 0.0 0.0 0.0 0.0 Exhibit 3-B Sheet 1 of 3 1997 1998 36.2 1.0 7.00 71.05 ML TLS 6.2 82 06.2 6.2 we we 3.7 63.3 126 126 37 63.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 199 356.8 7.10 21 08.2 6.2 wre 14.0 126 14.0 00 0.0 0.0 00 2000 6.4 was 382.6 308.2 6.2 wad a5 126 a5 0.0 00 0 00 200) 6.3 12 403.4 82 6.2 48 6.3 126 6.3 0.0 0.0 a0 6.5 1.27 46 8.2 8.2 48 106.4 106.4 0.0 0.0 00 337.0 L2 426.1 6.2 8.2 8 N79 ung 0.0 00 0.0 0.0 397.0 LR 426.1 06.2 wae 4.8 2.9 1a 7.9 0.0 0.0 0.0 a0 397.0 1.2 A261 6.2 62 (304.8 ung 126 17.9 00 00 0.0 0 397.0 L2 426.1 6.2 wae W.8 117.9 126 ung 0.0 0.0 0.0 2007 397.0 L2 426.1 ‘6.2 6.2 (304.8 ung 126 17.9 0.0 a0 0.0 0 2008 397.0 LR 426.1 8.2 wee 8 ung 126 un 0.0 0.0 0.0 00 2008 397.0 LR 426.1 08.2 wee 304.8 7.9 126 729 0.0 00 0.0 0.0 2010 397.0 LR 426.1 308.2 6.2 WA nn 126 ung 0.0 0.0 0.0 0.0 “Exhibit 3-6 ‘PLT COST (9000) Sheet 2 of 3 FLED 0am COST (4000) ° WoT EXERGY REDUIRENEMT (Gan) a6 Be as 0.0 0.0 158 we nr) a0 0 = 0.0 oo 00 YET GEAERATION POTENTIAL (Gen) 67 LORD FAC. oo a0 a0 a0 a0 00 ao 00 ao 20 00 00 00 NET GERRTION CTU. (Ga) 00 00 00 oo 0.0 oo oo 600 00 20 00 00 a0 BeseY LISS (8) ° 6861 GEERT (Gun) oo 00 00 00 060 006 a0 00 006 006 @0 00 006 00 00 06 00 00 006 006 00 06 00 a6 a0 60 FUEL USE (oan imiT INITIAL FUEL PRICE (9/UNIT) FUEL ESCALATION RATE (3/¥ERR) 1904-1908 ° 1989-2003 3 FUEL PRICE (#/uMiT) ee a ee, ec | FEL COST «0001 00 860000 VARIABLE OWN RATE (COMTS/int) = VARIABLE OWA COST (90000 CS SS eS 00 00 00 000 00 Ct) 164 StmonY TE TE Diesel CoeciTY noceD vm so 5050 300 500 30 00) 80 a0 CORLATIVE CAPACITY AOOED OW oo oo 30 «0 6s0 ko mw OO em m0 PLT. COST (9000) 1 ao 0.0 2WS5 2S 2MSS = 0 AMS OMS 0 eS OMS OHS SO FINED un COST «90001 25 (soon ° ° ons BS Ss ws eo 8S OS mw Ss SSS mS LISTING PRUNE DIESEL » caeRCITY om 2s 8 a 3 a a 5 28 a 6 * 2 a * ms S45 13 1s 1s 1s 3 a eo) ° UeET ERGY REDIIMED (int) a6 Wb BS HS m1 | 80) OO) 0k 00 00 000 ©6000 CORCLTY UTILTIZATION FACTOR 067 (POTENTIAL NET GENERATION POTENTIAL (Gnd TA TT TTT MGT 6.7 67 ATLA TTA 108.7 ee eS NET GERATION ACTUR. (end 26 Be BS BS ML OO OO so 18 Bo WG 00) 0k CC < e «ee << BERGY LOSS (8) ° ° ° ° ° ° ° ° ° ° rn) ° ° ° ° ° ° ° ° DENG ERIE (oun) a6 Re BS BS mM OOO so 188 eG Ot Cr << ) FEL USE (iG as TMITUAL FUEL PRICE (8/684) oss FUEL ESCALATION RATE (4/YERR) 1984-1988 ° 1989-2003 3 FUEL PRICE (WMT? et en ee) 10M 0M) 2 AS ATS AIST 1A LAH 14S LALLA LAL Fue. COST (90000 1537.8 28145103 SELLS 0.0 1.6 123 13 HI =D oo 800 00 VARIABLE ON COST (4000) 0.0 (COM) ATL2 |S 4057.9 HRS 0.0 2 12 OAKS 00 00 00 WrET ERGY REWIIROENT (Ge) Cn 00 00 ©6080 CS ee <r) 00 Cr SIAR OF HET GENERATION EXISTING & COnmTTED HrDA0 (8) 90.47 L796 16.40 ESL 100,00 100,00 100.00 97.85 HIS S.A HMO ORR RR RR RR RR RR RR WR is HYOROELECTINC (3) 0.00 © 0.00.00 0.00.00 0.0000.) 0.00 0.00.00 L002 Stk 7.08. ASL RGR GT 12762617... Nie THERSALSSION LAPORT (9 0.0 0.000.000.0000 0.00.00.) 0... 00... Nd PRIME THERA. (8) 0.00 0.000.000.0000 0.00.0)... Ow LISTING PRIME DIESEL (3) SS} 621 AHO.) SOHFAL ( 0.00 = 000 00.00 CHITA COSTS (¥000 FINED Qbx COST (8000) ARIAL 4M COST (4000) PROPSED DENY (4000) (Fue, COST (#000) TOT YERALY COST (9000) DISCOUNTED YEARLY COST (#000) Bee YER DISCO RATE (8) (Om, DISCRUTED COST (4000) m1.0 QM. DISC. COST TO 2010 (9000) SM M-CHPLTAL COSTS Im 2010 ‘90001 VALLE Im 2010 OF MO-CHPLTAL CaSTS THR 2045 (8000) DISCOUNTED MO-CHPITAL COSTS. EVDO 2010 (4000 (EASCROMT COST AHO SALVAGE VALUE DETERMINATION (MEM UNITS) wat ownciTy ~ rom a a kd TRWEMISSION PRIME TEL 1 PRIME THER 42 PRIME THES OD STORY TERRE 41 Tomar THER 82 ‘STAMOBY THERA 43 ‘STORY THER 04 ‘STAWOBY THER 5 ‘STROBY THERA. 06 ‘STORY THERA 47 STAROT THERM 08 STANDBY THER 49 STORY THERA 810 STRMOBY THERMAL #11 STORY THERA #12 ‘SToeY THERA 013 SRGusvvves am (9000) NT DISCOUNTED REALACERENT COSTS MO SALWAGE VALUES (8000) TOT DISCOUNTED ALAM COSTS (#0000 ao a0 83 a0 28.1 a ama a0 meee ns) 00 | (00 2300 ao 860 5 (00 Oe LL a0 4261 510.500 ADIN. 18208,9 18249.9 REA SCERENT REPLSCERENT vena a1 Vena 02 o o 2 0 2 ” a ” ane an as 203s 206 20% ae 2088 2019 an eet 2H 03 203 aves ° 208 ° 0 0 00° 00 0.0 6501.0 ry a0 8600068 00 800 M2 Ihe o ao 00 a0 LG 1 00 860 SISK 178K S 0 = 0.0 A824 1382.6 182499 18209.9 | 18702,3 3186.8 AETIREEMT CATT vou cast (9000) ame 7920.0 © a0 © a0 © 0.0 254 208.5 ans amas 86 205.5 ey ans as 205.5 e061 203.3 2063 2005.5 20s 6916.5 28 4827.5 e080 611.0 2.5 nS 200.0 a0 2120.3 83 eis 8 57100.6 ares Bo mS ao wis 710.0 DISCRERLL (9000) 0.0 oo a0 ao a0 0.0 Exhibit 3-8 Sheet 3 of 3 205.5 37.3 ao a0 ao 0.0 BLA 2005.5 m8 0.0 ao a0 mee 2 HO 1062.2 1655.8 TH72.2 797006 6135.5 DISCRERLA2 (9000) 0.0 a0 a0 0 a0 00 ana. wee se BAT We BS we. 0.0 0.0 0.0 0.0 0.0 a0 2s? 2505.5 we 00 1610.3 e%6.7 313.0 VALUE (4000) ake 0 a0 a0 1037.5 ex] 12680 W986 1613.9 1004.4 2075.0 0.0 1724.1 1s. 0.0 a0 ao 205.5 103.8 a0 ao a0 ana 151.0 4706.0 DISC SALVE (9000) 176.4 W12 we 155 103.8 197.9 26.2 mS 0.0 212.4 ML 0.0 xy 0.0 1816.4 0.0 8.8 a0 a0 00 se. 205.5 27.3 a0 a0 a0 ae Ma. 0.0 7.3 0.0 ao 0.0 era 20.7 6316.5 m8 ao ao ao 78.3 Bae 901.2 a0 3.8 ao 0.0 Cay 0373.3 0.0 m8 a0 ao a0 0586.8 uM7s ao 3 67.3 0.0 oo 86 oo oo 86 00 120.8 367.3 240.1 88 61S 0285.3 Caoolan OCTOBER 22,1984 WHITEHORSE INTERTIE 1996 YEAR RESOURCES AS OF 1984 ) Existing and Comsitted Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Committed Hydro Resources North of Taku Inlet ) Existing and Committed Thermal Resources (All North of Taku) Total Existing and Committed Net Resources South of Taku Inlet tnru Thane Total Existing and Committed Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transmssion Losses) DERAND ( Perak Demand Reserve Requiresents (Equal to Peak Desand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taxu Inlet (Canacity as weasured at Thane) hydro North of Taku Inlet Therwal Nortn of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS Hydro north of Taku Hydro south of Taku Thermal (North of Taku) RESERVE REQUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TOTA. CAPACITY JUNEAU 20 YEAR PLAN Exhibit 4-A 1984 1985 1986 1987 1988 1989 199 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45,93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.62 8.62 8.62 8.62 8.62 8.62 8.62 6.62 462 8.62 8.62 862 8.62 8.62 8.62 862 6.62 8.62 8.62 8.62 8.62 8.62 6.62 8.62 B62 8.62 8.62 5.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 99,14 59.14 58.00 58,00 58.00 55.50 53.00 53.00 53.00 53.00 53,00 35.50 35.50 35.50 12.50 12.50 0,00 45,93 45,93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 74.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79,84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21,12 21.12 8.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 55.1 57.9 60.3 62.6 64.8 66.6 68.5 70.4 72.4 74.4 76.5 78.6 80.7 82.9 85.2 87.5 89.9 92.3 34.8 94.8 94.8 9.8 946.8 4.8 94.8 94.8 35.5 46.5 49.3 51.7 54.0 562 580 59.9 61.8 638 65.8 67.9 51.6 53.7 55.9 582 60.5 629 65.3 67.8 67.8 67.8 67.8 67.8 67.8 67.8 67.8 23.2 24.7 21.9 18.3 16.0 12.6 108 54 35 OF heb -B7 64 43 21 -27 -7.5 -99 -12.3 -14.8 -14.8 -32,3 -32.3 -32.3 -55,3 -55.3 -67.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 184 0.0 0.0 00 0.0 00 00 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 00 0.0 00 00 00 00 0.0 00 00 50 5.0 0.0 0.0 0.0 0.0 00 5.0 0.0. 50 0.0 15.0 0.0 0.0 20.0 0.0 15,0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.0 5.0 184 0.0 0.0 00 0.0 50 00 5.0 0.0 15.0 0.0 0.0 20.0 0.0 15.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 60 0.0 5.0 10.0 28.4 28.4 28.4 28.4 28.4 334 33.4 384 384 S34 534 53.4 73.4 73.4 884 5.82 6.62 8.62 8.62 8.62 8.62 A.62 8.62 8.62 6.62 8.62 8,62 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 27.02 _ 45.93 45.93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 58.72 71.22 71.22 69.97 69.97 68,77 68.77 65.27 65.27 64.14 64.14 69.14 68 68 638 65.5 63 68 68 73 73 70.5 70.5 70.5 67.5 67.5 70 35.48 46.48 49,28 51.68 53.98 56,18 57.98 59.88 61.78 63.78 65,78 67.68 5:.58 53.68 55.68 58.18 60,48 62.68 65.28 67.78 67.78 67.78 67.78 67.78 67.78 67.78 67.78 23.2 24.7 21.9 18.3 16.0 12.6 108 5.4 35 04 16 163 164 143 121 73 25 S1 27 52 52 27 27 27 03 03 22 120.5 125.6 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 144.5 149.5 166.8 166.8 166.8 164.3 161.8 166.8 166.8 171.8 171.8 169.3 169.3 169.3 166.3 166.3 168.8 ECONWAL OCT 22,1984 Exhibit 4-B WHITEHORSE INTERTIE 1996 Sheet 1 of 3 YER 1964 1985 1986 1987 1988 1989 1990 191 198 1993 1994 1935 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005, 2006 2007 2008 2009 2010 ENERGY SALES FORECAST (Gah) 2st 20.6 e424 22.6 262.4 2.5 273.0 286.9 235.0 WLI Ue 320.6 2.3 Bee w7.0 8 M64 363 6.5 397.0 337.0 397.0 397.0 337.0 397.0 337.0 397.0 > LOCAL LOSSES (8) 5.64 60 6.47 6.52 6.57 6.63 6.67 6.71 6.76 6.00 6.85 6.90 6.95 7.00 7.05 7.10 TAS 12h 1.27 1. Le iL LR Le LB LR 1.2 GROSS ENERGY REQUIREMENT (Gun) 21.2 ase co 269.1 273.7 283.5 237.6 6.2 nag B29 BL2 wT B22 Ld TS 2 B26 034 414.6 426.1 426.1 426.1 426.1 426.1 426.1 426.1 426.1 (AT SUBSTAT 10KS) EXISTING & COMMITTED HYDAD > NET GENERATION POTENTIAL (Gk) 205.6 205.6 206.6 205.6 205.6 (82 8.2 8.2 6.2 8.2 08.2 we? 8.2 W682 (8.2 8.2 8.2 3082 08.2 8.2 8.2 8.2 06.2 08.2 6.2 6.2 8.2 (NET GENERATION ACTUAL (Gin) 205.6 a6 205.6 205.6 205.6 289.5 27.6 6.2 wae 08.2 a2 wee wee wee a2 06.2 82 82 Wa.2 wae (06.2 8.2 8.2 wae we2 6.2 308.2 NEM HYDROELECTRIC PROJECT s ’ YEAR ADDED CAPITAL COST (#000) FIXED O&M COSTS (#000) UNMET ENERGY REQUIREMENTS (Gun) 21.6 25 625 hl 0.0 0.0 0.0 6.8 15.8 3.0 we 0 33.7 63.3 T.0 5 6.3 106.4 417.9 ung 7.9 N19 17.9 ung 479 79 NET GENERATION POTENTIAL (Get) NET GENERATION ACTUAL (Gah) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 PROJECT: YEAR ADDED CAPITAL COST (#000) FIXED 06M COSTS ($000) ‘UMPET ENERGY REQUIREMENTS (Gah) 21.6 8 325 6L5 al 0.0 0.0 0.0 6.8 15.8 3.0 Ko 4.0 3.7 63.3 14.0 %.3 106.4 29 79 un a) 7.9 7.9 ung 7.9 NET GENERATION POTENTIAL (Gun) NET GENERATION ACTUAL (Gah) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.0 00 0.0 00 0.0 NE TRANSMISSION PROJECT: WHITEMORSE INTERTIE ‘YEAR ADDED 1996 CAPITAL COST (#000) 15369 7378 293 FIXED O&M COSTS (#000) 1532 ime 1332 1332 1332 1532 1532 1532 1332 1332 1532 1332 1532 1532 1332 UNMET ENERGY REQUIRERENTS (Get) 21.6 38 32.5 635 Tl 0.0 0.0 0.0 6.8 15.8 25.0 wb 4.0 33.7 63.3 74.0 5 5.3 1064 79 IAG NET GENERATION POTENTIAL (Gem) 160 160 160 160 160 160 160 160 160 160 160 160 160 160 160 NET GENERATION ACTUAL (Gen) 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 “0 a7 63.3 m0 a5 BI 106.4 ung 2.9 42.9 ung un nL ung ng ‘ENERGY LOSS (8) 2 ENERGY PURCHASED (Gah) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 416 ‘S81 64.5 0.0 M4 10381 5.2 127.6 127.6 127.6 127.6 127.6 127.6 127.6 127.6 UNIT COST AT SOURCE (6/6) 28000 PURCHASED ENERGY COST ($000) 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1333.6 = 1625.9 1917.8 = 2241.3 255K 7 2886.5 3224.2 ©«— 3872.4 «3872.42.42. S724 3872.4 3872.4 OSTA NEW PRIME THERMAL TYPE: Prime Diesel CAPACITY ADDED (rai) CUMULATIVE CAPACITY ADDED (M64) 0 o o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 © Exhibit 4-8 err. cast (8000 Sheet 2 of 3 ° FINED 4M COST (0001 ° WHET ERGY REDLIAEPENT (Gat) as as 6S OS 0.0 ao 158 Se ee ee a0 OO.) ae. We! ee! ae ae oe NET GENERATION POTENTIAL (Gin) — 0.67 LORD FAC oo 8680 00 a0 0.0 a0 00 0 0. 00 00 8600 o. a0 00 | (ao NET GENERATION ACTURL (Gat) Ch ) 0.0 00 00 00 00 000 0 0.0 Oe 06 08 O02 O62 OO: coe ERGY L055 (8) ° ENERGY GOERATED (Gut) wo 08 08 ef ae 06 688 fe ROS O0 Re OOO ROE Oe 60 COE RO eer Oe Ger Ok eee FUEL USE (hae tT 1s INITIAL FUEL PRICE (9/UNIT) 0989 FUEL ESCALATION RATE. (3/YERRD 1984-1988 ° 1989-2003, 3 FUEL PRICE (OBIT) 0.99 0.999 0.999 0.590.997 0.988 1.017 1.008 10792 AS ATS SFT 3671S AAA 1481. Fue. CST (10000 ao 0B) || ||!) ||| ce ||| tee |||] sec |||) fae.) || || te |||) |) |||) ea) |] see || || (rms |) (||| jie) | |) em] sees)! |/ ec ||| nee || mew) || jm | (]cme || each || ame ee |||] (ree | ae VORIRGLE OU RATE (CENTS /inmd =O. VARIABLE OWN COST (80000 (©. isms ||| ecm) Fc | ees ||| [Fase sam | | ei || | eset || |e) |e || age | (7) | cme) 0c | |||) | FR) |) |e ||| || |) ||| | ews |||) fem) ||| | ces |||) Ceeen||||| 8) |||||/ ae ||||/ ss STORY TERR WE: Diesel CBPRCLTY ROOED Om en 00 oo | 50 se 08 «68 ke keke CUMULATIVE CHPRCITY RODE Oni) 0.0 Cn er) 00 = 3010.0 10.0 tas 10.0 © 10010018010 OOO CKO OOM (ROLL COST (4000) 461.1. (90007) 0. ae 88 0.0 205.5 2055S 0.0000 2S 0 AWS 08K 000 SRR. FLIED 04M COST (9000) 25 (80007 ° ° ° ° ° ° e 1s B s 3 3s 3s Bs 2s 23 » % eS SSS SS LISTING PRIME DIESEL > CHeRCITY om 13 3 a 3 3 3 a 3 a a 2 2 a a eo nS 13 13 13 15 15 15 8 23 its ° VOET DERGY FEDUIED (Gen) as me MS 6S lM lke kk ke kek mee eke eo ee ke eee ee ket CAPACITY UTILTIZATION FACTOR 0.67 o0TeNT) YET GENERATION POTENTIAL (utd W677 TT MTT KT TTT... NET GEERATION ATU et) me 6mslUasl lhl lke keke kM Cee eke kee ett BERGY L055 (8) ° ° ° ° ° ° ° ° ° o o ° ° ° ° ° EASY GENERATED (Gan) mee. ee | Views ||| ace) ||| Feces rece) | coc || so) | dem ||| tee) Ure ||| tect |/ eles ||| | Vaca: || |e) | Yee | | Qe ||| || gre ||| act) ||| rm) ||| bce || cecum || eat ||| /fae))/|/!/(6.6) |||I/ 00 FUEL USE (aa /GAL) Bs INITIAL FUEL PRICE (9/68 0.908 ATE (8/ERR o 3 FEL PRICE (S/UMIT) Ct ee en en cL | FUEL CST (9000) 1507.8 20261 BEAST SELLS 0 AG 2H] 1ZI IL = WARIPRLE O4N COST (8000) CO ee Sr SS <r SS SS SS <n SP nS SS) WHET DERSY REINO (Get) 0111) is! | ha) | ||| 111g as ||| | ||| nc |) sa | |e is 2 Aa ||| 1 00 00 oO 6 406 Oe |) Oe ee ae ae ae ‘SOR OF NET GENERATION ‘EXISTING 4 COWTTED HYDRO «3 0.47 ALTY TRH. TSI 100.00 100,00 100.00 97.85 HIT LS OK OR RR RR RR RR RR WR WR Ns HYOAOELECTRIC (8) 0.00 © 0.000.000.0000 0.00.00 .00 0.00 0.0000 0.00.00. 0.0.07... 0.0.0 NEW TREHSMISSION IMPORT (8) 0.00 0.00 0.000.000.0000 0.00 0.000.000.0000 0.00 20H 17.OF 9K AHSL ARG SGT 27.68 T7627. T7622. NE PRIME THER 0.09 0.00 0.000.000.0000 0.000.000.0000 0,000.00 0.00 0.00.00 00.00 0.000.000.0000 .00 00 0.00 0.00 EXISTING PRIME DIESEL 352 16.21 20.34 23.60 90.00 0.000.001 BT 7.800.080.0000 0.000.000.0000 0.00 0.000.000.0000 0.00 0.00 0,00 SORTFAL (3) 0.00 © 0.00 0.000.000.0000 0.00 0.000.000.0000 0.000.000.0000 .00 000.000.000.000 0.00.00 0.00 © 0,000.00 sarweny OF AK COSTS (HerTm COSTS (40000 FLNED 4x COST (000) ‘vaRIARLE 04M COST (8000 PURORGED EASY (4000! Fue, COST (1000) ToT, YEARLY COST (#000) DISCOUNTED YEAALY COST (#000) BASE YEAR DISCOMT RATE (3) CUR, DISCOUNTED COST (#000) UR. DISC, CAST TO 2010 1000) ‘SUM ON-CPLTAL COSTS 1M 2010 «80001 VALUE 1M 2010 OF MO-CAPITAL COSTS THAL 2045 (90001 DISCOTED NON-CAPITAL COSTS EVDO 2010 (9000) SEPSCENENT CIGT (hd) SALVAGE VALUE DETERRINATION (NEW UNITS) wat 080 #1 kd ‘TRWEAISSION IE THER 1 PRIME THER 42 PRIME THER 0 STORY THERE. ‘STANOBY THER 42 STORY THERMAL €3 STROBY THER 04 STMOY THERMAL «5 STANDBY THERA. 06 ‘STAWOBY THER 47 ‘STAMORY THER. 88 STAWOBY TERN. 09 STROBY THERMAL #10 SIMOY THERM 9 STORY THERA 01 STAMORY THERMAL 413 NET DISCOUNTED REPLACERENT COSTS AAD SALVAGE VALUES (#000) cmciTy ow BIGueuue TOT. DISCOUNTED Asm COSTS (9000) 0.0 0 me 0.0 197.8 1711.0 m1. T1108 0.0 0.0 38.3 0.0 282.1 ae a m8. BERES a9 00 = 0.0 a0 = 0.0 420.0 07.9 00 © 0.0 Wet 4510.3 sao some MTL2 S61 622.2 13104 REPACENENT vem a ” 2026 a 20 2 aon 2015 avai 2023 20e5 aes aves 2 2 2 ae 0.0 0 2.5 0 61.5 aA. a0 0.5 0.0 18249,9 18249.9 PEPLACERENT vem ae setcood i bessse ° 0.0 0.0 a0 0 ao a) 0.0 0. 18249.9 18249.9 RETIREENT vee escliebeaocesh = 0 0.0 we 0.0 M6 14702.3 15369.0 0.0 12 0.0 1298.3 1674.5 1282.6 3024.9 CAPITAL (cast (8000) 102460.0 2305.5 2005.5 2305.5 205.5 6916.5 sez2.0 6916.5, 5683.5 5 200.0 0.0 2120.3 2021.3 3681 4983.0 2018.5 Bo 2.5 0.0 3013.1 BHO eneie.2 205.2 DIScAERLAL (9000) 0.0 0.0 2057.9 0.0 0.0 0.0 any 733.6 45.6 2.7 1687, 209.8 1922.3 0.0 0 0.0 0.0 0.0 0.0 261.2 0.0 1367.0 0.0 16 a0 2900.6 1913.6 1012.7 Exhibit 4-8 Sheet 3 of 3 0.0 1367.0 0.0 1626.9 0.0 ung eoe2 103166.9 DiscRERLAe (9000) 0.0 0.0 0.0 0.0 0.0 0.0 a. wae 5 wed 0.0 a0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 143.0 a0 1367.0 0.0 ee. 0.0 WB 3808.3 2182.8 273.1 0.0 1567.0 0.0 osa7 0.0 aa 2379.3 105319.7 107392.9 109972.2 2008.5 1384.5, 0.0 206.5 a0 676.5, 3.9 1137481 0.0 a0 0.0 were Le 226.2 Fy 0.0 168.7 wee 0.0 0.0 0.0 a0 0.0 0.0 1046.2 0.0 1304.5, 0.0 ene a0 4804.7 e588 11636.9 205.5 1602.0 0.0 sree 0.0 473.9 90.7 1202276 0.0 1602.0 0.0 sree 0 su78.4 2600.5 e288, 1 6916.5 0.0 WAS 1658.5 00 | 00 pres Ie 00 © 00 Wake 52269 3096.5 2452.2 187246 1311768 0.0 1654.5, 0.0 wre a0 5226.9 269.3 1355061 wez.0 00 We.S 172.5. 0.0 6.0 Bree 724 rr) 5189 5256.9 6388.7 2241.4 139908.8 142146.2 6916.5 177.0 0.0 Bree 0.0 2265.9 oe 147160. C)= Caoolan OCTOBER 19, 1984 TYEE INTERTIE (1996) YEAR RESOURCES AS OF 1964 ) Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Committed Hyoro Resources North of Taku Inlet ) Existing and Committed Thermal Resources (All North of Taku) Total Existing and Committed Net Resources South of Taku Inlet thru Thane Total Existing and Committed Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transwission Losses) DEMAND ( Peak Demand Reserve Reouirements (Eoual to Peak Demand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet (Capacity as measured at Thane) Hycro North of Taku Inlet Thermal North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS Hydro nortn of Taku Hyoro soutn of Taku Thermal (North of Taku) RESERVE REQUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TOTAL CAPACITY JUNEAU 20 YEAR PLAN Exhibit 5-A 1984 1985 1986 1987 1988 1989 199% 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 204 2005 2006 2007 cA 2009 2010 45.93 45,93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.62 6.62 6.62 6.62 8.62 8.62 6.62 8.62 8.62 8.62 8.62 6.62 8.62 8.62 6.62 8.62 8.62 6.62 6.62 8.62 8.62 8.62 6.62 6.62 8.62 6.62 8.62 538.72 71,22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 54.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21,12 21.12 8.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 55.1 57.9 60.3 62.6 64.8 66.6 68.5 70.4 72.4 74.4 76.5 78.6 80.7 82.9 85.2 87.5 89.9 92.3 4.8 48 HB 4.8 4.8 4.8 9.8 9.8 35.5 46.5 49.3 51.7 54.0 S62 58.0 59.9 61.8 63.8 65.8 67.9 70.0 72.1 74.3 76.6 78.9 81.3 83.7 86.2 86.2 86.2 86.2 86.2 86.2 86.2 86.2 23.2 24.7 21.9 183 16.0 126 108 54 3.5 0.4 6.6 87 12.0 -14.1 -16.3 -21.1 -25.9 -28.3 -30.7 -33.2 -33,2 -50.7 -50.7 -50.7 -73.7 -73.7 -86.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 27.0 0.0 00 00 00 0.0 0.0 00 00 00 00 00 00 00 00 0.0 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 00 00 00 0.0 0.0 0.0 0.0 00 00 00 00 00 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.0 00 00 50 50 50 00 50 00 50 5.0 0.0 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 0.0 0.0 0.0 00 0.0 00 0.0 0.0 0.0 0.0 50 50 320 00 50 00 50 50 0.0 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 00 00 00 0.0 00 0.0 0.0 0.0 0.0 0.0 5.0 10.0 420 42.0 47.0 47.0 52.0 57.0 57.0 62.0 62.0 77.0 77.0 77.0 102.0 102.0 117.0 5.82 6.62 8.62 6.62 8.62 6.62 6.62 8.62 8.62 6.62 8.62 8.62 8.62 8.62 6.62 8.62 8.62 6.62 8.62 8.62 8.62 62 8.62 8.62 6.62 8.62 8.62 45.93 45,93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 98.78 98.78 98.78 98,78 98.78 98.78 96.78 98.78 98.78 98.78 98.78 98.78 96.78 96.78 98.78 58.72 71,22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 64.14 69.14 73 73 78 75.5 78 63 83 88 68 5.5 85.5 85.5 67.5 67.5 35.48 46.48 49.28 51.68 53.96 56.18 57.98 59.88 61.76 63.78 65.78 67.68 69.98 72.08 74,28 76.58 78,68 61.28 83.68 86.18 86.18 66.18 86.18 86.18 66.18 86.18 66.18 23.2 24.7 21.9 183 16.0 12.6 108 54 35 0.4 -1.6 13 30 06.9 37 1.1 0.9 17 -07 1.8 1.8 0.7 0.7 07 1.3 1.3 38 11005 125.8 125.8 224.5 124.5 149.2 149.2 145.7 145.7 144.5 144.5 149.5 160.4 160.4 165.4 182.9 165.4 190.4 190.4 195.4 195.4 192.9 192.9 192.9 194.9 194.9 197.4 ECON Oct 19, 1984 TYEE IMTERTIE 1996 YEAR EAEAGY SALES FORECAST (Gah) ) LOCA. LOSSES (8) (GROSS ENERGY REOUIRENEMT (fa) (AT SusSTATIONS) EXISTING & COMMITTED HYORD ) AET GENERATION POTENTIAL (Gat) ET GENERATION ACTUAL (Gant NG HYDROELECTIIC. PROTECT YAR ADDED CAPITAL COST (80001 FIXED Otn COSTS 19000) UT EXERGY REQULREAENTS (Gan NET GENERATION POTENTIAL (Gat) AGT GENERATION ACTUAL. (Gund paONeCi ‘YEAR AODED CAPITAL COST (6000) FLYED Dan COSTS (8000) WET BRGY REQUIREMENTS (ae) NT GENERATION POTENTIAL 16) NET GENERATION PACTUAL. (Gand ‘Nb TRORSALSSION PROJECT: THEE IMTERTIE ‘Yena ADDED 196, CAAA, CAST (80000 FINED O4N COSTS (6000) UMET EXERGY REDUTRERENTS (Gand NET GENERATION POTEATIAN (Gan) NET GENERATION ACTUAL (Gan) ENERGY 2055 (8) we ENERGY PURASED (Send walT COST AT SOLACE (6/Gan} ‘76000 PURCHASED ENERGY COST 190601 Nd ALPE Tres, TE: Orise Dzesel CAORCITY RODED (8a GORLATIVE CAZACITY ADDED (ma 1984 asa 5.64 ene 205.6 206 26 0.0 aus 0.0 6.0 0.0 0 1985, 230.6 ase 205.6 0.0 0.0 m8 0.0 0.0 0.0 1986 22 6.47 aaa 205.6 205.6 25 0.0 0.0 25 00 00 0.0 1987 22.6 ad 5.6 25.6 0.0 a5 0.0 625 0.0 0.0 0.0 168 282.4 6.51 273.7 205.6 28.8 ta 0.0 Tet 0.0 ht 0.0 0.0 00 1389 ans 6.63 233.5 38.2 283.5 a0 a0 0.0 0.0 0.0 0.0 0.0 1990 21.0 6.67 an 308.2 291.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1331 266.9 We wae Wee 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 19 295.0 6.76 mag wae a 68 0.0 68 0 68 0.0 a0 0.0 1333 OG 6.6) Rus 18 0.0 15.8 0.0 138 0.0 0.0 6.0 ry m8 6.85 BLE 308.2 wae 25.0 0.0 2.0 0.0 wr00 25.0 0.0 0.0 1995. 0.6 6.90 we 366.2 wae WG 0.0 0.0 15900 HE 0.0 0.0 0.0 Exhibit 5-B Sheet 1 of 3 61997 mad Kee 6.95 7.0 mee 49 308.2 5082 wR2 WAZ 00 SAT 0.0 0.0 4000 517 0.0 0.0 m2 we AO SLT 6 wo SL7 89 887 321 4838.3 0 0 aa BIO 1.05 MS 308.2 308.2 63 0.0 63 0.0 63 86.6 3 10.4 509.7 m0 0.0 no 0.0 m0 86.6 m0 23 6282.1 00 2008 Mee 363 Was 72d Web 084 wee 302 e.g 82 aS 3 0.0 0.0 aS 953 0 00 az 2 as 43 6 06.6 5 66 39 5.3 13.6 TART ar) 65 Lat 4145 wee 08.2 106.4 0 108.4 00 106.4 6.6 6.6 7316.7 2003 37.0 1 A261 308.2 3082 u79 0.0 47.9 0.0 ng 6.6 8.6 B17 2008 37.0 1 426.1 308.2 308.2, 72.9 0.0 47.9 0.0 ung 6.6 66.5 B.S 73187 2005 397.0 wR W261 8.2 308.2 ung 00 ung 00 ung 6.6 6 %.3 738.7 31.0 LR 61 wae wR Ti) 0.0 nnd 0.0 ung 6 6 6.3 7318.7 31.0 Le 26.1 8.2 wee M79 0 47.9 0.0 we un B66 2.6 6.3 7387 BIO 1 Abt 308.2 wR ung. 0.0 ung 0.0 ung 86.6 Ba 6.3 7387 2089 w.0 132 seo wane 8.2 17.9 0.0 Tk) 0.0 nrg 86.6 6.6 6.3 7318.7 ao 17.0 8.2 42.9 0.0 Nn 0.0 wee nrg 86.6 6.6 73:87 CRIT COST (60001 FINED OUm COST ($000) WET ENERGY REDUIRERENT tGan YT GER AAT ION POTENTIAL (Gent SET GENEARTION ACTUAL Gen) EGY LISS 18 Exe Y GENERATED (Gand FE. SE anal INIT Fad, PRICE ASNT « FUEL ESCALATION RATE (S/YERAD 1984-1988 1969-2003 ree (ra Fe. COST 186000 VARIAS.E QUA FATE (CENTS Iran) VORIABLE 08M COST (60001 Nd STAADBY THERA, TE: Diesel CAACITY ADDED cm QUALATIVE CAPACITY AODED Om ‘CAPITAL COST (40001 FILED ObM COST (90001 EXISTING PRUNE DIESEL. > CaERCITY Um WET DERGY REQUIRED (Gat) DAMCITY UTILTIZATION FACTOR (POTENT NET GENERITLON POTEATIAN (Gand AgT GENERATION ACTUAL (Gan) aay LOSS (3) ENERGY GEAERATED 6m) Fie, USE (eas) ISITUR Fuds PRICE (WAI Fue. ESCRLATION RATE (H/VERRY 1984-1585 1989-2003 Fue. PaiCE (set) Ff. COST 180001 VAAIARLE CON COST (40001 UVET EXERGY REQULRERENT (Gant SAAMARY OF NET GENERATION EXISTING 4 COMMITTED nba (81 Nd AYDMOEECTAIC (8) Na TRANGAISSION L2ORT (8) Tevh. Oise. 0 0.67 LORD FAC, o 5 0.989 ° 3 08 461.1 (s000/m0 35 (sooo 0.67 15 0.989 0.8 (CENT said 21.6 0.0 0 0.0 0.989, 0.0 0 0 0 125 a6 The 28 216 0.959 whe 0.0 0.47 0.00 0.00 0.00 9.51 6.00 0.0 0.0 0.0 0.939 0.0 0.0 0.0 0.0 0 146.7 33.8 wa 0.939 61 38.3 0.0 8.79 0.00 6.00 0.00 1B.et 0.06 S25 0.0 0.0 0.0 0.989 00 0.0 0.0 0.0 6.7 25 25 0.959 29.1 420.0 a0 73.66 0.00 4.00) Gi aH ae a5 0.0 0.0 0.0 0.959 0 0.0 0.0 0.959 4510.3 507.9 a0 75.40 6.00 0.00 ato 6.00 Tear 0.0 0.0 0.0 0.959 0.0 0.0 ma MGT te oy 6.939 5261.5 382.5, a0 BS: 0.90 6.00 0.00 49 v.00 a0 Ob 0.0 0.0 0.948 0.0 0.0 0.0 0.0 146.7 0.0 00 0.508 0.0 0.0 a0 100.00 0.06 0.00 v.00 io 2.00 6.0 00 0.0 a0 4.017 0.0 0.0 0.0 a0 6.7 0.0 0.0 1.017 0.0 2.0 ww 4.00 0.60 v.09 8.00 vet 00 0 0.0 0.0 100 0.0 0.0 0.0 0.0 196.7 0.0 0.0 1.048 0.0 0.0 0.0 a0 6.8 0.0 0.0 1.073 O90 0.0 196.7 68 6.8 1.079 HL6 We 0.0 97.85 13.8 2.0 0.0 0.0 0.0 0.0 a 196.7, a 8 a0 0.0 «0 0.0 114s 0.0 0.0 5.0 xo 2403.5 ws ane a0 wo 308 0.0 0.0 4,0 173 0.0 00 3.0 10.0 2308.5 3B ane 36 wo 173 3013.1 216.5 0.0 a9.92 0.00 rae 0.00 10.08 0.00 Exhibit 5-B Sheet 2 of 3 0.6 0.0 0.0 a0 OG 00 ro) was .281 0.0 0.0 lr) 50 1.0 © 180 2005.5 0.0 25 328 20 a a) una une 00 © 0.0 0 ° ro) h2is 4.251 a0 © 0.0 a) 20 a0 65.16 0.6 0.0 0.0 0.0 1.289 0.0 0.0 5.0 2.0 2308.5 une 0.0 0.0 1.289 0.0 0.0 0 62.56 9.00 12.08 0.00 0.69 6.00 0.0 2.0 0 6.6 La 0.0 2.0 0.0 70 m5 0.0 102.7 0.0 00 LRT 0.0 2.0 0.0 0.64 0.60 19.38 0,00 0.00 6.00 0.6 6.0 a0 0.0 1.367 0.0 0.0 3.0 a0 2305.5 2.5 15 0.0 68.0 0.0 0.0 1.367 0.0 0.0 0.0 799 0.00 2.51 0.00 0.00 0.00 47 0.0 0.0 0.0 50 30.0 2505.5 105 1s a7 68.0 ay a7 1.408 63.4 0.0 %M 0.00 aan 0.00 ans 0.00 238 00 0.0 0.0 1.450 0.0 0.0 3.0 0.0 105 15 13.8 8.0 19.8 19.8 1.451 2130.2 158.6 0.0 a3 0.00 20.89 9.00 4.78 0.00 Bd 0.0 0.0 0.0 1.498 00 5.0 Bo 122.5 5 ws $3.0 u3 M3 Law 66.0 205 0.0 Rw 0.00 20.33 0.00 7.38 0.00 BA 0.6 0.0 0.0 14st 0.0 0.0 9.0 3.0 0.0 12.5 rc 3.3 64.0 na ua 14H 66.0 20.5 0.0 Re 0.00 20.33 0.00 1.35 6.00 ad 0.0 0.0 ao 1.434 0.0 0.0 15.0 30.0 6316.5 a5 3 3 68.0 na 33 1.498 3466.0 250.3 0.0 RR 0.60 20.33 0.00 235 0.90 33 6.0 0.0 0.0 1.498 0.0 0.0 0.0 50.0 0.0 173 5 na 8.0 M3 na 1494 W660 20.5 0.0 RR 0.00 20.33 0.00 7.38 0.00 3.3 a0 a0 0.0 1am 0.0 0.0 0.0 0.0 0.0 15 fr] ua 88.0 ud m3 149 466.0 250.5, 0.0 RB 0.00 Eee 0.00 1.35 0.00 a 0.0 0.0 0.0 23.0 73.0 1827.5 22.3 123 a3 m4 uA 3a 1a 66.0 230.5 0.0 RR 0.00 au 0.00 2.35 0.00 ad 0.0 0.0 0.0 Lae 0.0 0.0 6.0 75.0 0.0 22.5 125 m3 1 33 a3 1.498 6.0 250.5 0.0 RR 0.00 au 0.00 1.35 0.00 0.0 0.0 0.0 1.498 0.0 4.0 20 Re 0.6 20.33 6.86 0.00 0.47 Exhibit 5-8 Sheet 3 of 3 Suwmcay OF ARN COSTS CAPITAL COSTS (8000) 00 (00 00 © 00 0.0 CS Ce 0.0 WS 285.5 0.0 2305.5 0.0 0.0 12S 00 FINED GIA CST (9000) 00 80.0 0 i ) 00 125 380 AS 52.0 © 692.0 WS 827.0 TONS HAS, 937.0 1084.5 1084.5 \vaRIABE O4M COST (8000) 12 URI 050.9 HAS 00 0.0.0 S212 LES 0.0 0.0 6.0 0.0 694 SRG OS 80S 5S OS 205 PURCHASED ENERGY (90001 20 00 00 00 © 0.0 20 0.00.0 00 0.0 0.0 320.1 ASAI SHA7 6521 TUB. 7328.7 7508.7 718.7 738.7 78.7 7318.7 FUEL COST (40001 153.8 2826.1 3729145103 S85 0.0 G0 0.0 ALB 129.3 212,39 BNL 00 © 00 0.0 = 0.00.0 O52 21 HE. WOO IME. 3466.0 TOA YEARLY COST 18000) M0 4 410.0 SO1B.2 SBSH. ao © 00 0.0 © SHS SASS SSW] 21536.0 69001 SA1ZB BWTZ TU 1032 LISSA GINS 1428S3 119798 BHR 1AIZS 1203.3 AMATI 1219.8 208:8.1 DISCOUNTED YEARLY COST (4000 17.0 OHTA ASH SHO — 0000 ABBA TOTD2 GSUSS.S 147510 4565.4 HH61.0 5280.3 4254.2 © S970. GAZ SETA AYO GOZO SAIL SOHL SSA. LOSES S124 BKE.S BASE VERA 198 DISCOUNT RATE (5) 35 . CUR, DISCOWNTED COST (40000 W7L.0 47091 052242 NOGA 18249.9 182099 18209.9 18249.9 187023 5775.5 SOGSS.O 65985. 701524 736134 7689.7 B3157.9 8912.3 95350.6 401221.9 108625 LI4GYR1 123870.1 1295190 L9H 148329.6 1500580 1587L4.8 GR, DISC. COST TO 2010 ($000) 138765, SWAN DAPITA, COSTS Im 201011591 (90001 VALE In 2010 OF MCHPITAL 23180 COSTS Trtu 2045 ($0001 DISCOLNTED WORCAPITA COSTS = SHEL BEYOND 2010 190001 REASCEAENT COST xD) SALVAGE VALLE DETERMINATION (NEW UNITS) wit carcrTy vena waned REPLSCORENT HERACENENT RETIRERENT cotta. o1scReReL DIScazDLee 205 Savas DISC SAN im) YERR 01 YEAR #2 Yea (ast (40001 190000 (001 vate (80001 (001 v0 01 » ° 100 0.0 0.0 0.0 0.0 WYDRO #2 0 0.0 TRAGNISSION » 1996 o 06 $8620.0 12925.4 00 PAINE THERA 1 s 2010 ° 250 sni6.0 645.7 00 1029.0 Was.2 PRIME THER 02 ” & 0.0 0.0 PRIRE Trek #3 40 0 00 0.0 ‘STANGY. THERA 0h 5 194 aN ae 2305.5 ag. 122 SMAGSY Trea. 02 5 1995 a 208s 2x5.5 358.8 we SANE THEVA a3 s 19% ae tm ENS. M54 1288.0, 155.5 STANOSY Trem 4 s 1998 e038 20s eu. 39.7 1458.6 83.8 ‘STANOBY THEVA, 0S 5 2000 2000 260 265.5, US.8 1723. a2 SUNLEY TeEirh_ a6 3 on an 261 236.5 BAS 1640.4 226.2 Say Tat a7 s 20 el eer ENS. weg 2075.0 AS Silay “ne is 2005 ° 2095, h65 0.0 0.0 00 SANGEY TEA 0} a ry ° 0 MSc7.S 0.0 ea ee ‘STAADSY TeEtoe 010 0 200 o 9611.0 0.0 1182.8 Le SRAOBY Tee tA. LL OG 0.0 00 ‘STANDBY The we 6.0 0.0 0.0 STANDBY TnERPAL 013 0.0 0.0 00 Sos (90001 2957.7 2513.9 1786.3 (NET DISCOATED Az ACE*EWI COSTS AND SAVAGE VALLES (8000) e897 TCA, EISCANTED ALB COSTS HR cited Caplan OCTOBER 18, 1984 DOROTHY 1993 (w/Seoerate T-Line) YEAR RESOURCES AS OF 1984 ) Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane > Existing and Committed Hydro Resources North of Taku Inlet ) Existing and Committed Thersal Resources {All North of Taku) Total Existing and Committed Net Resources South of Taku Inlet thru Thane Total Existino and Coomitted Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transnission Losses) DEMAND { Peak Dewand Reserve Requiresents (Equal to Peak Demand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet (Capacity as seasured at Thane) Hydro North of Taku Inlet Therwal North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS hydro north of Taku Hyaro south of Taku Therwal (North of Taku) RESERVE REQUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TOTAL CAPACITY JUNEAU 20 YEAR PLAN Exhibit 6-A 1984 1985 1986 1987 1984 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 - 2008 -2009 2010 45.93 45.93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 1.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.82 8.62 8.62 6.62 6.62 6.62 8.62 8.62 8.62 8.62 B62 8.62 O.62 8.62 8.62 8.62 O62 8.62 862 8.62 O62 862 862 8.62 8.62 8.62 6.62 56.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79,84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21.12 21.12 8.62 110.5 125.6 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 135.4 115.9 115.9 115.9 92.9 92.9 60.4 41.3 55.1 57.9 60.3 62.6 64.8 66.6 66.5 70.4 72.4 74.4 76.5 78.6 80.7 82.9 85.2 87.5 89.9 92.3 %.8 4.8 8 4.8 8 8 94.8 4B 35 46.5 49.3 51.7 54.0 56.2 580 599 61.8 381 40.1 42.2 443 46.4 48.6 50.9 53.2 55.6 580 60.5 60.5 60.5 605 60.5 605 60.5 60.5 23.2 24.7 21.9 183 16.0 12.6 10.8 5.4 35 26.4 192 17.0 13.7 116 94 46 0.2 -2.6 -5.0 -7.5 7.5 -25.0 -25.0 -25.0 48.0 -48.0 -60.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 25.7 0.0 0.0 0.0 00 G0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 00 5.0 0.0 0.0 5.0 00 15.0 0.0 0.0 25.0 0.0 10.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 25.7 0.0 0.0 0.0 0.0 00 00 50 0.0 0.0 5.0 0.0 15.0 0.0 0.0 250 0.0 10.0 0.0 00 00 0.0 00 00 00 00 00 25.7 25.7 25.7 25.7 25.7 25.7 25.7 30.7 30.7 30.7 35.7 35.7 50.7 50.7 507 75.7 75.7 85,7 5.62 6.62 8.62 6.62 8.62 8.62 6.62 8.62 8.62 34,32 34.32 34.32 34.32 34.32 34.32 34.32 34.32 34,32 34.32 34.32 34.32 H.32 W328 H.32 4.32 4.32 WB 45.93 45,93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 38.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58 58 58 555 5d 5A S8@ 63 63 60.5 605 60.5 625 625 60 35.48 46.48 49.28-51.68 53,98 56.18 57,98 59.68 61.78 38,08 40.08 42,18 44.26 46.38 48.58 50.88 53.18 55.58 57.98 60.48 60.48 60.48 60.48 60.48 60.48 60.48 60.48 23.2 24.7 21.9 183 160 126 108 5.4 3.5 26.1 191 17.0 137 11.6 94 46 46 24 0.0 25 25 0.0 00 0.0 20 20 0.5 110.5 125.8 125.8 1245 124.5 149.2 149.2 145.7 145.7 170.2 165.2 165.2 164.1 164.1 164.1 161.6 164.1 164.1 164.1 169.1 169.1 166.6 166.6 166.6 168.6 168.6 166.1 ‘ECONANAL OCT 16, 1984 DOROTHY = 1993 (u/Seoerate T-Line) ENERGY SALES FORECAST (Gan) 215.1 > LOCA LOSSES (*) S4 GROSS ENERGY REQUIREMENT (Gem) = 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDAD > NET GENERATION POTENTIAL (MH) 205.6. NET GENERATION ACTUAL (ih) 203.6 MEd HYDROELECTRIC PROJECT: OOROTHY YEAR ADDED 1983 ‘CAPITAL COST (#000) FINED O&M COSTS (9000) UNPET ENERGY REQUIREMENTS (Gen) = 21.6 NET GENERATION POTENTIAL (Gun) (NET GENERATION ACTUAL (Gh) 00 PROJECT: ‘YEAR ODED ‘(CAPITAL COST (9000) FINED O8M COSTS (9000) ‘UMET ENERGY REQUIREMENTS (Gh) = 21.6 NET GENERATION POTENTIAL (Gen) NET GENERATION ACTUAL (Gun) 0.0 PROJECT ‘YEAR ADDED CAPITAL COST (9000) FINED 08M COSTS (#000) UNPET ENERGY REQUIREMENTS (Gh) = 21.6 NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gam) 0.0 ENERGY LOSS (x) ENERGY PURCHASED (Gan) UNIT COST AT SOURCE (8/Gwn) PURCHASED ENERGY COST (#000) (NEM PRIPE THERA TYPE: Prime Diesel CAOACITY ADDED (wa) CUMULATIVE CAPACITY ADDED (red) 0 1985 20.6 60 4 205.6 205.6 BB 0.0 38 0.0 3.8 00 1986, e424 6.47 oe 205.6 205.6 25 0.0 2.5 0.0 2.5 0.0 1987 a2.6 62 269.1 205.6 205.6 65 00 65 0.0 63.5 0.0 1988 262.4 657 273.7 205.6 205.6 mt 00 mal 0.0 ml 00 1989 as 6.63 283.5, 6.2 289.5, 0.0 00 0.0 0.0 0.0 0.0 1990 273.0 6.67 237.6 08.2 297.6 17396 0.0 0.0 0.0 0.0 0.0 0.0 671 6.2 08.2 M62 0.0 0.0 00 0.0 0.0 0.0 1992 235.0 6.76 uaAg 08.2 wee en? 6.8 0.0 68 0.0 68 1993 bia 6.80 RLg 6.2 06.2 W8 5.6 126 15.8 0.0 0.0 19% U6 6.85 Be ‘308.2 wae 8 3.0 3.0 0.0 0.0 0.0 0.0 1995 0.6 6.90 WT 8.2 wee m8 HE 126 wb 0.0 0.0 0.0 00 1996 B33 6.35 B22 06.2 8.2 m8 “0 126 “0 0.0 0.0 0.0 0.0 Exhibit 6-B Sheet T of 3 197 1998 Bae 47.0 7.00 7.05 1.9 TLS 8.2 8.2 W82 = 082 48 8 3.7 63.3 126 126 7 63.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 ° ° 1999 8 7.10 2.1 8.2 82 4.8 14.0 4.0 0.0 0.0 0.0 0.0: 2000 6.4 Tas 382.6 08.2 08.2 we a5 126 aS 00 0.0 0.0 00 2001 6.3 1.21 403.4 8.2 8.2 48 6.3 126 8.3 0.0 0.0 00 0 2002 2003 SS 6.5 1a 414.6 8.2 a2 we 106.4 126 106.4 00 0.0 0.0 0 337.0 LR 426.1 308.2 wee cond ung 17.9 00 0.0 0.0 0.0 337.0 2 426.1 08.2 wae WB ung 12 ung 0.0 0.0 0.0 0 397.0 1.2 426.1 08.2 8.2 8 79 126 ung 0.0 0.0 0.0 0.0 37.0 LR 426.1 Wa.2 a2 Wb un 12 ung 00 00 00 2007 397.0 2 426.1 WB u29 125 ung 0.0 0.0 0.0 00 2008 397.0 2 426.1 308.2 wee 8 ung 126 17.9 0.0 0.0 0.0 a0 2009 397.0 V2 426.1 08.2 wae WA ung 12 ung 0.0 00 0.0 00 2010 337.0 LR 426.1 6.2 6.2 8 ung 1a ung 0.0 0.0 0.0 00 Exhibit 6-6 CAPITA COST (#000) Sheet 2 of 3 ‘FINED Obm COST (9000) o WET ORGY REQUIRENENT (Gat) a6 Bh SS SOM 00 00 00 6 rn 00 800 8900 «680 oe NET GEXERATION POTENTIAL (Gem) — 0.67 LORD FRC, 00 800 6800 OO @0 60 60 00 00 00 00 00 06 06 00 00 00 60 00 66 oo NET GEERATION ACTUAL (Get ao 60 008 00 8600 © (00 00 800 00 66 00 O06 O60 06 06 09 60 00 00 a0 ERGY LOSS (5) ERGY GEERATED (Gn) Cr ee eS ee ee) ) a0 Cn ee eS) CS FURL USE Gann 3 INITIAL FUEL PRICE (9/UMITD ose (FUEL ESCALATION RATE (3/YERR) 1904-1988 ° 1983-2003 a FUL PRICE (W/UNTD O59 0.9 0559 0559 Oss 0.988 es a ee ee ec) FURL COST (4000) CC ee SS SS) en) CC ) 00 = 00 0 00 60 00 00 0606 00 00 00 00 a0 oo 00 VARIABLE OAM RATE (CENTS Vin) = 8 VARIABLE 04M COBT (4000 Cr SS eo) 00 8000 0 Cr en ee ee) 00 Nes STORY TER WE: Diesel CAPACITY AOOED UND x0 300) 18.0 0006 6 00-0 10.0 CUMULATIVE CAPACITY AOUED (md) ow nr) 0.0 0.0 00 00 00 06 00 30 50 S50 100 100 2.0 0 0 Sao 0.0 CAPITAL COST (#0000 461.1 (s000/m0 ry} 00 800 0 a0 ry 0.0 0.0 ee | FIXED O&n COST (9000) ‘25 (s000/mi ° ° o e ° ° ° o ° ° oS SS 5s BS 83s oS OS im ms a0 EXISTING PRINE O1ESEL » CRRCITY om as a 5 CI a a 6 a a 6 2 a 2 a oe ms iss 1s 3 8 3 13 ws 1s 0 WHET EXERGY REQUIRED (Gut) a6 Bh SS SM 00 00 00 68 O06 O06 O20 O89 a0 Cr ao 8600 (OO CAPMCITY UTILTIZATION FACTOR = O67 ‘ (POTENTIAL NET GENERATION POTENTIAL (Geen) a a ee) 0.0 mo Be 14 00 NET GEERATION ACTUAL Gand a6 Bh SS SM %o 00 80 ao 8660 0680 a0 ao en BRGY LOSS (5) ° o ° ° ° ° ° ° o ° o o ° 0 0 o o 0 o ° o ° 0 o ERGY ERATED an) a6 Bb SS Sk 00 00 09 68 00 00 00 00 006 O06 00 a0 00 00 ao ao ) FUEL USE (ans) as INITIAL FUEL PRICE (8/6) ose FUEL ESCALATION RATE (8/YEARD 1904-1988 o 1989-2003 3 FUEL PRICE COUNT) Ce er ee ce ee a el) Fue. COST (x00) T1813 SOO 16 a0 00 00 06 O60 a0 Ce ee ee ao | CC en VARIABLE 04M COST (#000) 2 Mh 2.0. we 00 800 8900 8900 86808 ao G0 8600) 60080 0 00 60 ws oo = 40 PET DENG REQUINENENT (Gut) Cr ee ee 00 00 80 00 00 00 O06 00 00 09 00 00 00 00 00 60 00 a0 a) ‘SUMMARY OF NET GENERATION EXISTING & COMMITTED verba (6) 47 ALS 73.66.40 TSI 100.00 100.00 97.65 513. LGW OR OR RR RR RR RR RR WR NOs HYDROELECTRIC (3) 000 06.00 8.00.00, 0.00 0.00 4.87750 10.08 1231703 RZ GT 27.68 27.68.12 NE TREWGALSSION IMPORT (8) 0.00 0.0.0) 0.00.00, 0.00 0,000.00 0.000.000.0000. 0.00.00 0.00.00 0.000.000.0000 Ns PRIME THER (3) 0.00 0.00 0.00.00. .00 0.00 0.000.000.0000 0.00.00 0.000.000.0000) 00.0.0 0.00 0.00.00 0.00 LISTING PRIME DIESEL (x) 352 162i O.00 0.00 215 0.000.000.0000...) 0.000.000.0000. 00.00 0.00.0 SHORTFALL (x G00 0.00 0.000000 0.00 0.00 0.00 0,00 0,000,000 0000.00.00 00.0000... 0.00.00 Exhibit 6-B Sheet 3 of 3 Suey OF se COTS PLT COSTS «40000 0 00000 O00 ILO SO BNO =o Ce ee 0.0 © 0.0 2W5.S 0 69S OAS FINED Gum COST (60000 00 00 808 00 0 8 A Oo WA A AF FF TTD ars. vane 04M COST (4000) m2 ues 01.9 550 Oo 2 00 00 00 00 00 06 00 00 00 00 06 00 O06 a0 00 00 PRORSED DENGY (4000! CS ee ee Se ®0 00 0 oo 00 0 00 09 O09 00 06 00 06 06 00 o6 a0 oo FUEL CAST (40000 1S.8 2826.1 AL ASI SUELO 00 6 8000 0 00 00 60 G0 O06 00 00 006 06 a6 06 wo TOT. YEARLY COST (#000) ATO HAA ARO SOR2 SASAL—0 173860 BESO ETI A HORT] OS] TUS] OO. SIS DISCOWNTED YEARLY COST (4000) AMO MBL WTR ASSL SOLS OO HHUSI.7 SSA 190822 RGU LTS. ASISS 7G TRS. SRY O77. SLT OO ese YER 1984 DISCOAT RATE (8) as UR DISCOUNTED COST (4000) ATH. ATAS,4 8622.2 LBINR A 18209. 18209. 9 SNOT STSES.9 779K BITL.T 7981.5 793634 B087E.9 BIOS. 1212.0 260K. AZ7TB.7 BGIZT. 7 BGSII.7 BO6BD.S GIWAB.2 GISI.Z SHNE.D Gm. DISC. COST TO 2010 (#000 SUM NO-CAPLTAL, COBTS 1M 2010 180000 VALLE Im 2010 OF MO-ORPLTAL COSTS THRU 2045 (40000 DISCOUNTED MOM-CAPITAL COSTS SEO 2010 (8000) FEAACEENT COST 00 SALVAGE VALLE DETERMINATION (MEW UNITS) wat cooreiry ena ODED RECENT EASEMENT ser eet elt DIScRERLOL DISCREALEE 2045 SAGE bist SANS ~ a wea ee) cast (8000) «s000) (9000) WALuE (#000) (8000) Hrpaa #1 a oy 23 ° 2083 3638.0 7. 0.0 re612.5 0905.3 kd 00 a0 Ti¥GASS1OK 0.0 0.0 PRIME THERA 41 a 0 6 00 a0 0 0.0 a0 PRIME THERON 42 2 “ o a0 0.0 0.0 00 0.0 PRIME THERM 02 2 0 o a0 0.0 0.0 0 0.0 STORY THER O1 8 2000 00 eo 2060 11.0 1336.4 on. 83 ae ‘STOBY THEW 42 3 2003 ees ans 2063 205.5 2.7 wed 2073.0 CAS SiimOY THERM 03 3 2005 oes o e045 6916.5 1687.8 0 00 0 STAROBY THER 4 a 2008 e0e8 o 208 1327.3, asr.e a0 wet ait STANDBY THERM 45 10 a0 20% ° e080 11.0 w. a0 use, ie STANDBY THEW 96 a 0 ” a0 a0 0.0 Siimoey TERM 07 a “ © 0.0 0.0 a0 a0 ‘STRNOBY THERE 88 a 0 0 a0 a0 a0 0.0 ‘STROBY THERWL 69 2 0 o a0 0 0.0 a0 STORY THERE 810 a “ o a0 a0 a0 a0 ‘STmOBY THERA 41 0.0 0 a0 0.0 STieOeY THEW 12 a0 0.0 a0 oo ‘STOBY THERA 813 0.0 00 a0 a0 ‘Sum (9000) 10a m3 7.4 NET DISCOUNTED REPLACENENT COSTS And SALVAGE VALLES (8000) 6086 TOT DISCOUNTED PLAN COSTS (4000) 106oA2 Caoolan OCTOBER 22, 1964 DOROTHY 1999 (w/Secerate T-Line) YEAR RESOURCES AS OF 1984 ) Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Comaitted Hycro Resources North of Taku Inlet ) Existing and Committed Thermal Resources (ALL North of Taku) Total Existing and Committed Net Resources South of Taku Inlet thru Thare Total Existing and Commtted Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transwission Losses) DEMAND ( Peak Dewand Reserve Requiresents (Equal to Peak Demand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hydro South of Taku Inlet (Capacity as seasured at Thane) hycro North of Taxu Inlet Tnermai North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS hydro north of Taku Hyaro south of Taku Tnerwal (North of Taku) RESERVE REGUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESJLTING TOTAL CAPACITY JUNEAU 20 YEAR PLAN Exhibit 7-A 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 20H) 2001 2002 2003 2004 2005 2006 2007 2008 2009 2610 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 74.78 71.78 71.78 71.78 72.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.62 6.62 8.62 6.62 8.62 8.62 8.62 6.62 8.62 862 8.62 8.62 8.62 8.62 862 8.62 6.62 8.62 B62 8.62 862 6.62 B62 6.62 862 862 8.62 58.72 71,22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58,00 55.50 53.00 53.00 53.00 53.00 53.00 35,50 35.50 35.50 12.50 12.50 0.00 45.93 45,93 45,93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.64 79.84 78.59 78,59 77.39 77.39 73.89 73.63 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44,12 44.32 44.12 21.12 21.12 8.62 410.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 135.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 55.1 57.9 60.3 62.6 648 66.6 68.5 70.4 72.4 74.4 76.5 78.6 60.7 82.9 85.2 A7.5 89.9 92.3 94.8 94.8 94.8 948 94.8 94.8 94.8 94.8 35.5 46.5 49.3 51.7 54.0 56.2 580 59.9 61.4 63.8 65.8 67.9 70.0 721 743 50.9 S32 55.6 58.0 60.5 60.5 60.5 60.5 60.5 60.5 60.5 60.5 23.2 24.7 21.9 183 16.0 12.6 108 S.4 35 0.4 -66 87 “12.0 -141 -16.3 46 2 -2.6 ~5.0 -7.5 -7.5 -25.0 -25.0 -25.0 -48.0 -48.0 -60.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.6 0.0 00 60 60 0.0 0.0 00 00 0.0 06.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 60 0.0 0.0 00 60 0.0 25.7 0.0 0.0 00 0.0 0.0 0.0 00 00 00. 0.6 0.0 0.0 00 00 0.0 00 00 00 00 00 00 5.0 50 00 50 0.0 0.0 60 0.0 0.0 0.0 00 10.0 0.0 0.0 25.0 0.0 10.0 0.0 060 00 00 00 00 00 0.0 0.0 06 5.0 5.0 0.6 5.0 06 2.7 0.0 0.0 00 0.0 0.0 10.0 0.0 0.0 25.0 0.0 10.0 0.0 0.0 0.0 00 0.0 0.0 06 0.0 0.0 6.0 5.0 20.0 10.0 15.0 15,0 40.7 40.7 40.7 40.7 40.7 40.7 50.7 50.7 50.7 75.7 75.7 85.7 5.82 6.62 8.62 6.62 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 a.62 34.32 34.32 34.32 34.32 34,32 34,32 34.32 34.32 34.52 34.32 34.32 34.32 45.93 45.93 45,93 45.93 45.93 71,78 71,78 71.78 75.78 73.78 73.78 71.78 71.78 7:.78 71.76 7:.78 71.78 71.78 71,78 71.78 71.78 74.78 71.78 71.78 71.78 71.78 71.78 58.72 71.22 71.22 69.97 69.97 68.77 68,77 65.27 65.27 6414 64.14 69.14 68 73 73 705 68 68 68 68 68 60.5 60.5 605 625 625 60 35.48 46.48 49.28 53.68 53,98 56,18 57.98 59,88 61.78 63.78 65.78 67.88 69,98 72.08 74.28 50,88 53,18 55.58 57.98 60,48 60.48 60.48 60.48 60.48 60.48 60.48 60.48 232 247 21.9 183 16.0 126 106 S4 35 04 -i6 1.3 -20 09 -13 196 148 124 100 7.5 7.5 0.0 0.0 0.0 20 20 -05 11005 165.8 125.8 224.5 i245 165.2 1452 245.7 145.7 144.5 144.5 149.5 146.4 153.4 153.4 176.6 274.2 1742 1742 1741 2742 166.6 166.6 166.6 368.6 168.6 166,: ECON OCT 22, 1964 DOROTHY = 1999 (u/Seoerate T-Line) YeRa 1984 ENERGY GALES FORECAST (Gun) as. » LOCK LOSSES (1) 3 G20SS ENERGY REQUIREMENT (Gan) — 227.2 (AT SJBSTATIONS) EXISTING & COMMITTED HYDRO ) NT GENERATION POTENTIAL (Git) 205.6 ET GENERATION ACTUAL (Gin) 205.6 NEw HYDROELECTRIC PROJECT: DOROTHY YEAR AOGED 199 CAPITAL COST ($000) FINED 08x COSTS (8000) UNMET ENERGY REQUIREMENTS (Gn) 21.6 MET GENERATION POTENTIAL (Gen) NET GENERATION ACTUAL (Gen) 0.0 PROJECTS YEAR ADDED CAPITA COST (#000) FIXED Obm COSTS (8000) UNMET ENERGY REQUIREMENTS (Gun) 21.6 NET GENERATION POTENTIAL (Get) NET GENERATION ACTUAL (Gan) 0.0 NEW TRANSAISSION PROJECT YEAR ADDED CAPIAL COST (9000) FIXED ON COSTS (8000) ENERGY REGUIREMENTS (Gen) 21.6 ARTION POTENTIAL (Gnd NET GENEARTION ACTUAL (end 0.0 ENCAGY LOSS (9) ENEVGY PLACHASED (G0) UNIT COST AT SOuaCE (8/twn) PuacesiSeD ENEAY COST (8000) Nea PRIFE THERA THE: Prime Diesel CAemC!TY ADDED (Ma) Cor. VE CAPACITY ADDED (%w) ° 1985 230.6 6.40 eAS.4 205.6 205.6 3.8 0.0 8 0.0 6 00 0 1986 242.4 6.47 28.1 205.6 205.6 25 0.0 325 0.0 32.5 0.0 1967 22.6 6.52 69.1 205.6 205.6 63.5 0.0 6.5 0.0 63.5 0.0 1988 262.4 6.57 279.7 205.6 5.6 Th 00 Tah 0.0 That 00 1989 271.5 6.63 269.5 WB.2 263.5, 0.0 0.0 0.0 0.0 G0 06 1990 273.0 6.67 297.6 308.2 297.6 0.0 00 0.0 0.0 0.0 0.0 1981 286.9 6.71 M2 0.0 0.0 0.0 0.0 0.0 1982 295.0 6.76 uad 308.2 Wee 6.8 0.0 6.8 0.0 6.8 0.0 1993 W332 6.60 B39 308.2 8.2 15.8 0.0 15.6 0.0 19% Die 6.85 Bie 6.2 wee 25.0 0.0 25.0 0.0 0.0 1995 20.6 6.90 we7 Wa2 WB.2 0.0 0.0 ao 1996 23.3 6.95 B22 a2 8.2 173% 4.0 0.0 0.0 44.0 0.0 Exhtbit 7-B Sheet 1 of 3 19971988 382 © 470 7.00 7.05 19° TLS 308.2 © 308.2 8.2 Mae 525 S17 Su7 633 0.0 0.0 3270 633 0.0 0.0 33.7 63.3 0 0.0 o 0 1999 36.8 7.10 2.1 308.2 WB we 14.0 126 4.0 0.0 00 0.0 0.0 2000 6.4 is 382.6 08.2 WB.2 we #5 16 ws 0.0 0.0 0.0 00 2001 316.3 wat 03.4 8 5.3 126 6.3 0.0 0.0 0.0 0.0 2002 2003 0S 2006 6.5 1.27 414.6 08.2 8.2 8 106.4 126 106.4 0.0 0.0 0.0 00 397.0 1.3 426.1 06.2 a2 WB ung 126 47.9 0.0 0.0 0.0 397.0 LR? 426.1 308.2 82 WB 117.9 126 u79 0.0 0.0 0.0 0.0 397.0 LR 426.1 308.2 82 WA8 7.9 126 ug 0.0 0.0 0.0 00 397.0 LR 426.1 We? wae 48 U7 1% ung 0.0 0.0 0.0 00 2007 397.0 LR 426.1 308.2 8.2 4.8 47.9 12 47.9 00 0.0 2008 387.0 Le 426.1 8.2 a2 8 ung 126 ung 0.0 0 0.0 00 2009 397.0 LR 426.1 6.2 8.2 4.8 7.9 126 29 0.0 0.0 0.0 00 2010 337.0 LR 426.1 06.2 6.2 4.8 7.9 126 ung 0.0 0.0 0.0 0.0 Exhibit 7-B Sheet 2 of 3 ‘CAPI"AL COST (#000) FINED Ob COS™ (9000) ° UWPET ENERGY REQUIREMENT (Gnd 21.6 39.6 25 65 Tel 60 wo 0.0 66 13.6 a0 6 “0 ‘5.7 633 00 00 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 NET GENERATION POTENTIAL (Gand 0.67 LORD FAC. 00 00 0 00 0.0 00 00 Oo. 0.0 0 00 wo 00 a0 00 0 Oo a0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Go Ne? GENERATION ACT (Gan) 00 00 00 00 00 00 0.0 00 0.0 oo 6.0 0 00 Oo 0.0 0.0 nd 0.0 0.0 0.0 0.0 0.0 00 00 00 0.0 ENS 085 (8) ° ENERGY GENERATED (Gund 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 FEL SE bani”) ss INITIAL PL, PRICE (8/UNIT) 0.959 Puc. ESCALATION RATE (X/YEAR) 1984-1968 o 1989-2003 3 Fuk. PALCE (S/UNIT) 0.959 0.959 6.959 0.959 0,959 0.908 1.0.7 1.088 1.079 Lue Las Lamy Lats Lai 1.289 La 1367 1408 1.451 1 ae 10% 148 14% 1a FUEL COST (9000) 00 0.0 00 0 0.0 00 0.0 00 0.0 00 oo 00 0.0 0.0 0.0 0 00 0.0 00 00 0.0 0.0 0.0 0.0 00 VRALAGLE OL RATE (CENTS/iot) 0.8 VAHIABLE 08" COST (8000) 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 00 00 00 00 00 00 00 00 00 00 0 0.0 Ne STANDBY THE, Diesel : CAPACITY RODED (dd 5.0 5.0 3.0 0.0 0.0 10.0 0.0 0.0 Bo 0.0 10.0 CUNAATIVE CAPRCITY RODED OMA) 0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 50 10.0 10,0 15.0 15.0 101.0 ISO SO SO ISO 0 0 0 O00 CAPITA COST (9000) 461.1 (8000/0) 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 «(205.5 205.5 00 = 2305.5 0.0 0.0 0.0 a0 00 0.0 0.0 00 0.0 11527.5 0.0 4611.0 FINED OM COST (8000) L5 (8000/0) 0 ° ° 0 0 ° 0 ° o 0 23 s BS 25 BS S25 Ss VS WS WS WS OS OS OS as 75 20 EXISTING PaUve DIESE. » CRCITY Om 123 a a a a a a a 3 a » 2 2 a a ons is 1s 15 15 15 15 3S 1S ° WET ENERGY REQUIRED (Gun) 26 ae 5 as Te 0 a0 0 oe ise 0 we 4.0 Su7 63 00 0.0 a0 0.0 00 00 00 00 00 00 0.0 CAPACITY UTILTIZATION FACTOR 0.67 (o0"ENT IAD NE” GEREAATION POTENTIAL (Gun) TA 16.7 1%67 146.7 1%6.7 146.7 16.7 146.7 1%6.7 1%.7 ure une he une une 102.7 4.0 (08.0 6.0 84.0 8.0 4.0 0 he he 0.0 (NET GENERATION ACTUAL (Gun) 216 we 25 oS mat 0.0 00 0.0 68 138 3.0 we 4.0 7 6h 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 AGY CSS (8) 0 o ° o o o o o o ° ° o o ° ° 0 ° o 0 o ° ° o ° ° ° Y GENERATED Gan 26 38 SSL OS OMSL TD 00 860080 PEL USE Cea) 25 1 Fue. PRICE (WGA) 0.98 Fue. ESCALATION AATE (1/YEAR) 1964-988 o 8F-eH3 3 Fue Ouuce (HIT 0.959 0.959 0.959 0.959 0.959 0.948 1.017 1,0N8 1.079 HMDS LATS 2S HSL 128] RTT MLAS LA LAS ALA LAA 188 Fut. COST (8000) 1837. 2626.1 2 AS10361. 0.0 0.0 Oo ALG | 1299.3 2120.3 NL BHL2 8977. ONL 0.0 0.0 0.0 00 00 0.0 00 00 00 00 0.0 VAR Chm COST (9000) ACENT /Miwt AT 63 420.0 07.9 592.5 6.0 00 0.0 we 126.2 20.0 276.3 Bee 429.6 06.4 0 60 00 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 LOPET EAERGY REQUIREMENT (Gan) 00 00 60 00 09 «60 0 OOO 00 = 0.0 SUPAERY OF NET GENERATION EASE 6 COMETED HYDRO (1 HAT 63.79 73.66.40 75.SL 10) 1.0)... MOOR OAR OUR OR OR OR TR AR 4.00 0.00 Oc) 000 GG 0.000.000). O00 0.00 0 0.00 GOD O00 ‘S's aie UISSE. 9.53 1621-23646) 2649 OO) ISBT PL ay Ce , ) 0.00 0.009.562 REZ SBT E768 7687676877676. 0.00 © 6.000.000.0000 0,0) 0.00 0.00 0,09 0.000.000.0000 0.0 = 00.00.00 0.00 0.00 0.00 0.09 0,000.00 0,000.00, 14.66 17.06 6,000.00 000.) 0.00 0.00 0.00 0.090.000.0000 0.000.000.0000 000.0000 0.00 0.00 0.000.000.0000 Exhibit 7-8 ‘San OF ALi COSTS Sheet 3 of 3 CHPITA COSTS 180001 ao 00 i ) 6.0 265.5 EWES 173%.0 ON.S 57.0 0.00 00 600 00 0.0 RS 0 . FINED bx COST (4000) a0 00 CS eS ) CS ee ee ee Bs 83 23 N23 VARIABLE OM COST (80000 1.2 MRI 420TH DOH AHS ZOO 00 © 0.0 ee PURC-RSED ENERGY (9000) 20 000 000 00 © 0.0 00 «008 FUEL COST (4000) 107.8 2826.1 372.1 4810.3 SAL 000A 12MHF 21S HOLL IL AHS OOH 00 00 0.0 0.0000 TOTAL YEARLY COST (#000) AM1,0 HAA 40 SOH2 SHAT 00 SIA RSS ARS SMO 217043 MOUS TIDE eS eo DISCOUNTED YEARLY COST (8000) a cS er st ee ee Wee Yee 1984 DISCOAT RATE (8) as CUM. DISCANTED COST (#000 ATUL ATHS.1— O622 13108.4 18209.9 1829.9 18245.9 18249.9 187023 19748.2 23099.9 26900,3 41290.3 67051.9 B7OIK.0 BTEH1.3 A7A3T.4 7636.5 B7B2BLO OBOIA,7 BBINN.2 S06ZI.7 90807. 7 SORES. S622 6447.3 SHOAZ. GUM. DISC. COST TO 2010 s000) 9543 SH NOMCAPITA, COSTS IM 2010 SS. (9000) VALE IN 2010 OF KOCHI 10896, (COSTS TH 2045 (8000) DISCOUNTED MON-CAPLTAL COSTS 410 BEYOND 2010 (40000 wat ercity vena poNED FERSCDOT REPCERENT seTREXT err DISCRERLOL Disc SANG me oan YERR 2 i) (cast (#000) 9000) (9000) Hand ot a 3 o o oo) 73638.0 0.0 met HYDRO 82 0.0 TARWSAISSION 0.0 PRIME THER 01 2 ” C ao a0 PRIME THER AR 2 “ o 00 00 PRIME THEW 0 2 0 6 a0 a0 STRONY HERR 1 3 196 aoe an 2088 2008.3 ee STANDBY TERR 02 8 1955, eos 203s 2085 203.5 736 STANOBY THERM 03 10 2005 202s o 2045 611.0 ese STANDBY THEW 04 a 2008 2028 o ee 1127.5 e537.2 ‘STANDBY THER 05 10 en10 2030 ° 2050 11.0 wre STANDGY THEW 06 3 197 aur en ens? awss STaOBY THER 47 a “ © STONOEY THER 08 2 0 © STRNORY TERR. 09 2 « 0 STORY THEA. 410 2 “ o STANDBY THERNA O11 SRNObY THER 812 STRUT THEW #13 ‘S (9000) | NET DISCOUNTED REPLACENENT COSTS AAO SALVAGE VALLES (6000) 6 i TOTAL DISCOURTED PLiew COS"S (M00) 05368 - JUNLOSS OCTOBER 22, 1984 . . Exhibit 8-A LW FORECAST LOCAL SYSTEM LOSSES YEAR 1984 1985 1986 1987 1988 1989 199 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 ) PEAK DEMAND (MW) 41.3 Sh 56.1 58 59.7 61.3 62.4 63.6 64.8 66 67.3 68.6 70 71.4 72.8 742 75.7 77.2 78.8 80.3° 80.3 80.3 80.3 80.3 60.3 80.3 80.3 ) ENERGY SALES (Gwh) 215.1 226 235 242.9 250.1 256.7 261.4 266.4 271.5 276.8 2821 287.5 293.2 298.9 3048 310.8 317 323.2 3256 336.1 336.1 336.1 336.1 336.1 336.1 336.1 336.1 LOAD FACTOR 0.59 0.48 0.48 0.48 0.48 0.48 0.48 0.48 0.46 0.48 0.48 0.48 0.48 0.48 0,48 0.48 0.48 0.48 0.48 0.48 0.48 0,48 0.48 0.48 0.48 0.48 0.48 LOSS FACTOR , 0.39 0.27 0.27 027 0.27 0.27 0.27 0.27 0.27 0.27 0,27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 G9KV CAPACITY LOSS (Ma) 0.45 0.79 0.85 0.91 0.95 1.01 1.05 1.09 1.13 118 122 $27 1632 1638 1643 149 155 MBL 1668 1.78 17h 174 7A TH LTA 7H 1274 69KV ENERGY LOSS (Gwh) : 1.58 1.85 200 214 226 239 247 257 267 277 2.68 299 311 324 3.36 3.50 366 3.78 3.93 4.09 4.09 4.09 4.09 4.09 4.09 4.09 4.09 FEEDER CAPACITY LOSS (Mid) 1.83 2.49 2.60 271 280 289 295 3.02 3.09 3.16 3.23 3.31 3.39 3.47 3.55 3.64 3.73 3.82 3.91 4.01 4.01 4.01 4.01 4.01 4.01 401 4.01 FEEDER ENERGY LOSS (Gwh) 10.55 12,57 13.10 13.58 14.01 14,42 14.70 35.01 15,32 15,64 15,97 16,31 16.67 17.04 17.41 17.78 1817 18,57 18,99 19.40 19,40 19.40 19.40 19.40 19,40 19.40 19.40 JUNEAU CAPACITY LOSS (PW) 2,29 3.28 345 3.62 3:76 3.91 4.00 Af) 422 4.33 445 458 4.71 4.85 4.98 5.12 5.27 5.43 5.59 5.75 5.75 5.75 5.75 5.75 875 5.75 5.75 JUNEAU ENERGY LOSS (Bh) : 12.13 14.42 15,10 15.72 16.28 16.81 17.18 17.58 17.99 16.41 16.66 19.30 19.79 20.27 20.77 21.28 21.81 22,35 22.92 23,49 23.49 23.49 23.49 23,49 23.49 23.49 23.49 (JUNEAU CAPACITY LOSS (x) 5.55 6.07 616 6.24 631 6.37 642 6.47 652 657 6.62 6.67 673 6.79 685 6% 6.97 7.03 7.09 7.16 7.16 7.16 7.16 7.16 7.16 7.16 7616 (| JUNEAU ENERGY LOSS (x) 5.66 6.38 6,43 6.47 651 6.55 6,57 660 6.63 6.65 6.66 671 6.75 6.78 6.61 6.85 6,88 6.92 6.95 6.99 699 6.99 6.99 6.99 6.99 6,99 6.99 1 Capolan 2 OCTOBER 22, 1984 3 4 THERMAL 5 LOW FORECAST 6 7 8 YEAR 9 10 RESOURCES AS OF 1984 u 12 ) Existing and Committed Net Hydro Resources 13 South of Taku Inlet thru Thane 14) Existing ano Committed Hyoro Resources 15 North of Taku Iniet 16 ) Existing and Commtted Thermal Resources 7 {All North of Taku) 18 Total Existing anc Commttea Net Resources rt ] South of Taku Inlet thru Thane 20 = Total Existing and Committeo Net Resources 21 North of Taku Inlet 22 23 EXISTING AND COMMITTED RESOURCES 24 ~— (After Transmission Losses) 25 26 DEMAND 27 ( Peak Demand 26 29 = Reserve Reouiresents 30 (Equal to Peak Demand Less Hydro North of Taku) u 32 EXISTING RESERVE MARGIN 33 (Excess or shortfall of reserve) » ‘35 NEW RESOURCE ADDITIONS 36 ~~ Hydro South of Taxu Inlet 0 (Capacity as measured at Thane) 38 Hydro North of Taku Inlet 9 4) ~~ Thermal North of Taku Inlet 4 42 TOTAL ANNUAL ADDED CAPACITY 43 44 CUMULATIVE ADDED CAPACITY 45 46 TOTALS AFTER ADDITIONS 47 Hydro north of Taku 48 49 Hydro south of Taku % St Thermal (North of Taku) se S3 RESERVE REQUIREMENTS AFTER ADDITION «4 SS RESERVE MARGIN AFTER ADDITIONS 56 57 RESULTING TOTAL CAPACITY 4 5 6 7 8 9 10 I 12 13 1 35 16 617) 18 19 Ol tlle Oa as BO NBGA (20'¥ena Pion Exhibit 8-B 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 ° 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 7:.78 71.78 7i.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.82 8.62 8.62 8.62 B62 8.62 8.62 8.62 8.62 6.62 6.62 8.62 8.62 6.62 B62 62 8.62 8.62 8.62 8.62 8.62 6.62 8.62 B62 B62 B62 6.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 54.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12,50 12.50 0.00 45,93 45.93 45.93 45.93 45.93 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 78.59 78,59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21.12 21.12 8.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 54.0 56.1 580 59.7 61.3 62.4 63.6 64.8 66.0 67.3 68.6 70.0 71.4 72.8 74.2 75.7 77.2 78.8 80.3 80.3 80.3 80.3 80.3 80.3 80.3 80.3 35.5 45.4 47.5 49.4 Sit 52.7 53.8 55.0 56.2 57.4 58.7 60.0 61.4 62.8 G42 65.6 67.1 686 70.2 71.7 71.7 Te7 717 The7 717 717 71.7 23.2 25.8 23.7 20.6 18.9 0.5 -0.8 -3.4 4.8 6.2 -10.1 -14.1 -15.6 -17.2 -18.7 ~18.7 -¥.2 -¥6.2 -36.2 -59.2 59.2 -71.7 16.1 15.0 103 91 6.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 00 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 00 00 00 00 00 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 00 0.0 5.0 00 00 50 5.0 0.0 0.0 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 0.0 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 00 0.0 50 0.0 00°50 5.0 0.0 0.0 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.0 5.0 5.0 10.0 15.0 15.0 15.0 20.0 20.0 35.0 35.0 35.0 60.0 60.0 75.0 5.62 8.62 8.62 8.62 8.62 8.62 6.62 6.62 B62 B62 8.62 8.62 8.62 8.62 8.62 6.62 8.62 62 B62 6.62 6.62 8.62 8.62 8.62 6.62 8.62 8.62 45.93 45.93 45.93 45,93 45,93 71.78 71.78 71.78 73.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 98.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.145%14 63 63 63 65.5 68 68 68 73 73 70.5 705 70.5 725 725 75 35.48 45.38 47.48 49.38 51.08 52.68 53,78 54.98 56.18 57.38 58.68 59,93 6:.38 62.78 64.18 65.58 67.08 68.58 70.18 71.68 71.68 71.68 71.68 71.68 71.68 71.68 71.68 23.2 25.8 23.7 20.6 189 163 15.0 103 91 68 G5 -06 166 2 -l2 -O1 0.9 -06 -22 163 1.3 -h2 -e2 1.2 0.86 0.8 33 110.5 125.8 125.6 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 143.4 143.4 143.4 145.9 148.4 148.4 148.4 153.4 153.4 150.9 150.9 150.9 152.9 152.9 155.4 ECON OCT 22, 1964 Trea Ow FORECAST vena 1984 ENERGY SALES FORECAST (Gen) as » LOCAL LOSSES (x 5.64 GROSS ENERGY REGUIAENENT (Gm) 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDRO ° ) NET GENERATION POTENTIAL (Git) 205.6 NET GENERATION ACTUAL (Gin) 205.6 ‘Néld HYDROELECTRIC PROJECT: YeRa RODD CAPITA. COST (4000) | FINED O4M COSTS (4000) \ UNPET ENERGY REDUIRCAENTS (Gum) 21.6 NET GENERATION POTENTIAL (Gund NET GENEARTION ACTUAL (Gut) 0 PROJECT YEAR ADDED CAPITAL COST (9000) FINED O4m COSTS (9000) UNAET ENERGY REQUIREAENTS (Gn) 21.6 MT GENERATION POTENTIAL (Gan) NET GENERATION ACTUAL (Gem) 0.0 Ned TRANSNISSION paOJELT: ‘YEAR ADDED CAPITA. COST (9000) FINED O&M COSTS (8000) UNMET ENERGY REQUIREMENTS (Gen) 21.6 NT GENERATION POTENTIAL (Gen) NeT GENEAATION ACTUAL (Gen) 0.0 ENERGY LESS (8) ENERGY PURCHASED (Gund WAIT COST AT SOURCE (8/Gan) PURCHASED ENERGY COST (#0u0) New PRIFE Thonn, TPE Prime Diesel ChORCITY ODED (w Cum AAT IVE CAPREI™Y AODED (4a) 0 ou 240.4 205.6 205.6 we 0.0 we 0.0 we 0.0 6.43 Bt 205.6 205.6 “5S 0.0 “5 00 “5 0.0 1967 242.9 6.47 cy 205.6 205.6 33.0 00 53.0 0.0 33.0 0.0 1968 20.1 6.51 64 0.8 0.0 0.8 0.0 60.8 0.0 1989 6.7 6.55 273.5 6.2 e735 0.0 0.0 0.0 0.0 0.0 0.0 1990 14 6.57 278.6 6.2 278.6 0.0 0.0 0.0 0.0 0.0 0.0 1931 266.4 6.60 24.0 B82 264.0 0.0 0.0 00 0.0 0.0 0.0 1932 as 6.63 263.5 6.2 263.5 0.0 0.0 0.0 0.0 0.0 0.0 1933 276.8 6.65 2.2 306.2 25.2 0.0 0.0 0.0 0.0 0.0 6.0 1994 262.2 6.68 Wi.0 8.2 w1.0 0.0 0.0 0.0 0.0 00 0 1935, 267.5 671 Wee 6.2 M8 0.0 00 0.0 0.0 0.0 0.0 1396 3.2 6.75 abo 6.2 wee on 0.0 48 0.0 “8 00 1937 28.9 6.78 ‘Le 6.2 082 1.0 0.0 11.0 0.0 Exhibit 8-¢ Sheet 1 of 3 138199 cw W.8 HOB | RDO 661 6.8568 UeS.6 Be ae B02 2 ORE a2 We.e a2 a 0.0 00 a0 ne ag wT 00 0 a0 na 2g wT 00 0.0 00 o 0 0 200) Ba2 62 WS.6 6.2 8.2 ne 0 a 0.0 a4 00 ew 0S B36 6% 32.5 W8.2 8.2 a0 we 0 0.0 te 68 33.6 8.2 ‘Be Su a0 S14 a0 S.4 a0 36.1 68 33.6 82 06.2 a4 00 su 0 a4 00 B61 6.9 53.6 8.2 6.2 S4 0.0 54 0.0 S14 0.0: 26.1 6.99 B36 08.2 wee 4 0.0 su 0.0 4 0.0 Be 6.9 33.6 08.2 wee 4 00 Sa a0 Sa 0.0 208 336.1 69 B36 06.2 6.2 3.4 00 a4 0.0 S14 00 208 B61 6a 3533.6 308.2 wa? su 0.0 Su 0.0 su4 a0 zo 67 33.6 Wee WR.2 Se 00 su 0.0 Se 0.0 0 0 CAPITA, COST (8000) FIXED Obm COBT (HHO) WET EXERGY REDUIRERENT Gut) NET GENERATION POTENTIAL (Gan) NET GENERATION ACTUAL (Gm) ENERGY LOSS (x ENERGY GENERATED (Gun) Fu. USE (ment IITIAL FUEL PRICE (9/UNIT) FUEL ESCALATION RATE (8/YERR) 1984-1988 1989-2003 FUEL PRICE (8 WAIT? Fue COST (9000) VARIABLE OWN RATE (CENTS/iaan) VARIABLE 04M COST (#000) Ned STARDBY THERA, WEL Diesel CAPACITY ADDED Om) CURMATIVE CAPACITY AODED ma CAPITAL COST (#000) FIXED Obm COST ($000) LISTING PRIME DIESEL » CRPRCLTY (ma UNPET ENERGY REDUIAED (Gan) (CAPACITY UTILTIZATION FACTOR (POTENTIAL NET GENERATION POTENTIAL (Gut) NET GENERATION ACTUAL (Gan) ENERGY LOSS (3) ENERGY GENERATED (Bat) Fu. USE (aan / GAL) INITIR. Fue. PRICE (9/6) Fue. ESCALATION RATE (8/¥ERAD 1984-1986 1989-2003 Fue. PRICE (W/UNITY Fue. COS" (O00) VARIABLE OAM COST (40000 UNMET ENERGY REQUIRENENT (Gun) SURRY OF NET GENERATION EASTING & COMN:TTED HeDRO (8 Nee RYDROELECTRIC (6) ia TARVGNISSION [PORT (8) New ALE THERM. (8) EXISTING PAINE DIESEL (8) SrGVFAL (1 ry} 461.1 (s000/—00 ‘3 (#000/m) as? rey 0.989 0.8 (CENT) 21.6 a0 0.959 a0 a0 123 2.6 ™ a6 0.999 1537.8 me a0 9.97 0.00 0.00 0.00 9.53 0.00 0.959 a0 146.7 we we 0.959 2474.3 28.7 a0 65.51 0.00 0.00 0.00 1848 0.00 “5 00 00 0.0 0.999 0 0.0 a0 146.7 aS “5 0.959 36.2 361 a0 82.20 0.00 0.00 0.00 17.60 0.00 sho 0.0 0 a0 0.999 0 0 a0 67 sho sno 0.959 were eee a0 BA 0.00 0.09 00 2.51 0.00 0.8 a0 0 00 0.999 a0 00 0 00 146.7 60.8 60.8 0.999 mes 486.3 0 Tab 0.00 0.00 0.06 eae 0 0.0 0.0 0.0 0.0 0.988 0.0 0 0.0 146.7 0 ao 0.988 a0 0.0 a0 100.00 6.00 0.00 0.0 0.00 0.00 0.0 0.0 0.0 0.0 1.0:7 a0 0.0 0.0 0.0 146.7 0.0 00 1.017 0.0 0.0 a0 100.00 0 0.00 0.00 0.00 0.00 «0 0.0. 0.0 a0 1.008 0.0 a0 196.7 0.0 a0 1.008 0 0.0 0.0 100.00 0.0 0.00 0.00 0.00 0.00 0.0 ao 00 a0 1.079 ao 00 6.7 a0 a0 1.079 oo a0 a0 100,00 0.00 00 4.00 6.00 3.00 0.0 0 0.0 0.0 Lane 0 0.0 16.7 0 a0 wane 0 0.0 0.0 100.00 0.00 0.00 0.00 0.00 0.00 0.0 a0 0.0 0.0 Ls ao 0.0 a0 0.0 un a0 a0 Ls a0 0.0 a0 100,00 0.00 0.00 0.00 0.00 0.00 0.0 a0 0.0 a0 1179) 0 a0 0.0 0 ane 0.0 0.0 1.179 0.0 0 0.0 100.00 00 0.00 O00 0.00 6.00 a0 L215, 00 0.0 so 30 2805.5 nS ay “8 ae 12s one wb 0.0 98.46 0.00 6.00 0.00 Ls 0.00 no 0.0 0.0 0.0 est 0.0 30 0.0 ry ve ane 1.0 1.0 12s 1020.7 8.1 0.0 6.35 0,00 0.00 0.00 Bas 0.00 Exhibit 6-c Sheet 2 of 3 me 289 ao 0.0 a) 00 © 0.0 1.290 LRT ao © 00 a) so 30 100 0.0 2x5. nS 5s oO nS m4 Be MTA 1027 me as 0 0 me Be 1.299 eT 1662.2 2351.9 19.3 19.3 0 0 W6S .80 0.00 © 0.00 0.00 0.00 60 0.00 5 1.20 0.00 0.00 wT a0 a0 a0 1.367 a0 a0 0 13.0 205.5 25 5 wu a0 7 a7 1.367 204.7 aas.2 a0 9.95 0.00 0.00 0.00 2.05 0.00 m4 0 a0 a0 00 i908 1.451 0 00 a) 10 130 00 0.0 ws 5 is we 0 a0 nA Ae ° 0 ao 1.408 1.451 30.1 4767.1 a2 oA a0 00 Bb BTL 00 0.00 0.00 0,00 0.00 0.00 10.02 12.59 00 (0.00 se 0.0 0.0 0.0 1.494 0.0 30 20,0 05.70 0.00 0.00 0.00 14.30 0.00 a4 0.0 0.0 0.0 1.494 0.0 0.0 20.0 0.0 15 o4 6.0 se se 1.494 682.0 ae 0.0 85.70 0.00 0.00 0.00 4.0 0.00 se 0.0 0.0 0.0 1494 0.0 13.0 30 6916.5 W235 3 4 wo se se 1.494 3682.0 aL a0 5.70 0.00 0.00 0.00 4.30 0.00 se 0.0 0.0 0.0 1.494 a0 0 0.0 Bo 0.0 2.5 3 se 0 4 se 1.494 3632.0 ae a0 85.70 0.00 0.00 0.00 14.30 0.00 S14 0.0 0.0 0.0 1.498 a0 0.0 Bo 0.0 15 3 se a0 4 1494 5652.0 ae ao 85.70 0.00 0.00 0.00 14.30 0.00 se 0.0 0.0 0.0 1.494 0.0 00 2.0 0.0 1327.5 210 123 se me a4 se 1.494 692.0 Le a0 65.70 0.00 0.00 0.00 14.30 0.00 4 0.0 0.0 0.0 1.494 a0 0.0 0 0.0 0.0 210 23 4 1.498 3692.0 aa 0.0 65.70 0.00 0.00 0.00 14.30 0.00 sere sie 4.7 sua sia 1.494 3228 ae 30 5.0 208.5 215 a0 a0 a0 1.498 0.0 0.0 0.0 45.70 0.00 0.00 40 0.00 0.00 SPW OF PLS COSTE CAPITAL COSTS 19000) FIXED 04M COST 19000) VARIABLE Gan COST (8000) PUORSED ENERGY 16000) FUEL, COST (9000) ‘TOT. YERRLY COST 14000) DISCOMMTED YEARLY COGT (#000) WASE VERA 134 DISCOMNT GATE 18) as GK, DISCOUNTED COT (6000) QM, DISC. COST TO 2010 (6000 KAA? GUN MveCAPLTAL COSTE Im 2010 STK tw040r VALLE IN 2010 OF MO-ORPITAL «1528 (COSTS Twi 2043 190001 DISCOUNTED xOn-CAPITAL COSTS ATLA KENDO 2010 (00) SEALSCENENT COST FAO GALWAGE VALUE DETERMINATION (NEM LITE) wat owrcity ~m wrnid a ed TRWGATSSION PAINE THERA, 01 DRURE TrERWOL. 02 PALE THEOL 03 STANDBY TERA, STRADGY THERA 02 STANDBY THERM 43 STAADBY TrEReRL. 0 STANDEY TERA. 05 STEADY TEAL 06 BIAbY TATA a STANDGY TrERAL STANDBY Trea, 9 SEADBY TreRMA, 010 STANOBE TERM, OL STANDBY TrERDAL STAADBY THERA, W013 ‘ur 19000), 0.0 0.0 he 0 18 m0 AT. m0 NET DISCOUNTED RESLACERENT COSTS AMD SALWGE VALLES 180001 TOR. DISCOATED ASW COSTS (HOW 00 0 278.7 0 078.3, e7sLo 2689.9 ang 2010 196 199 2003 2010 0.0 0.0 361 0.0 nee Bua A 7655.3 arn 0 0,0 eae 0.0 we aise 4 4105.7 REA ACERT YEM a1 2M 2016 2019 20d 2025 0a 2030 20 0.0 0.0 0.0 0.0 486.3 0.0 0.0 0.0 46 0.0 480.9 0.0 M182 0.0 156229 156229 FED SCERENT YEAR 02 40 ” 0 aw 209 2000 2043 0 0 0 0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 18622.9 0.0 + 0.9 0.0 0.0 0.0 00 13622.9 0.0 0.0 0.0 0.0 0.0 0.0 13622.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1362.9 0.0 0.0 6.0 0.0 0.0 0.0 0.0 1562.9 0.0 0.0 0 0.0 a0 0.0 0.0 1562.9 DISCAERLOL (9000) 0.0 0.0 0.0 0.0 0.0 e718.0 2305.5 0.0 S125 Wo BL Ce) 44 1020.7 27%0 1263 1650.4 7202 173 181935 OrscrerLae 1000) 0.0 0.0 0.0 0.0 0.0 0.0 3as.4 WLE 28.8 wo 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 16 Exhibit 6-c Sheet 3 of 3 0.0 2.5 129.3 6.0 1662.2 1619.0 ueR7 1917.2 245.5 38.0 1913 0.0 2551.9 498.7 ans 20S GAL WROE VALE (9000) 0.0 0.0 1369.5 1288.0 161.9 14.4 2073.0 0.0 7244 76.4 0.0 0.0 0.0 0.0 0.0 0.0 2x63 25.2 0.0 OWT 708.0 wie eased 0.0 25 299.2 0.0 BL 0282.7 249.6 27837 DISC GANG (90001 0.0 0.0 182.3 3 199 ate AS 0.0 ae 10.7 0.0 0.0 0.0 0.0 0.0 0.0 1e%5.2 0.0 zw 39 0.0 16 374.5, 2185.8 30619.3 2306.3 10.0 ae 0.0 682.0 wad 04 3068.9 0.0 10,0 ae 0.0 82.0 oe 302.5 3aise.4 6916.5 12.5 aL 0.0 3632.0 13g oul 4374.0 0.0 125 Ate 0.0 3692.0 6225.9 2320.3 4058.9, 0.0 122.5 aL 0.0 3692.0 6225.9 222.1 3017.0 1827.5 210.0 ane 0.0 492.0 17840,9 712.6 0.0 210.0 rey 0.0 452.0 enna een. 0802.0 0383.5 220.5 ane 0.0 S128 103.2 S06A.9 (6666.9 Canolan OCTOBER 22,1984 DOROTHY = 1999 LOW FORECAST YEAR Wert TnKewone 10 RESOURCES AS OF 1984 u 12) Existing and Committed Net Hydro Resources 13 Soutn of Taku Inlet thru Thane 14) Existing and Committed Hyoro Resources 15 North of Taku Inlet 16 > Existing and Committed Thermal Resources 7 (All North of Taku) 18 Total Existing and Committed Net Resources 9 Soutn of Taku Inlet thru Thane 20 = Total Existing and Committed Net Resources al North of Taku Inlet 2 23 EXISTING AND COMMITTED RESOURCES 24 ~~ (After Transmission Losses) 2 z F Reserve Requirements EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS hydro South of Taku Inlet (Capacity as measured at Thane) hydro North of Taku Inlet Thermal North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY BPAAZSESSYRASHKRESBB 46 TOTALS AFTER ADDITIONS 47 hydro nortn of Taku 48 49° Hydro south of Taku 50 St Thermal (North of Taku) se S3 RESERVE REQUIREMENTS AFTER ADDITION Pa] 5 RESERVE MARGIN AFTER ADDITIONS 56 S7 RESULTING TOTAL CAPACITY (Equal to Peak Demand Less Hydro North of Taku) JUNEAU 20 YEAR PLAN Exhibit 9-A 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45,93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 7:.78 71.78 71.78 71.78 71.78 71.78 71.78 5.82 8.62 6.62 6.62 6.62 8.62 8.62 862 8.62 8.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 B62 8.62 8.62 6.62 8.62 8.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 76.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44,12 21.12 21.12 8.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 136.4 136.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 54.0 56.1 58.0 59.7 61.3 62.4 63.6 64.8 66.0 67.3 68.6 70.0 71.4 72.8 742 75.7 77.2 78.6 80.3 80.3 80.3 80.3 60.3 80.3 80.3 80.3 35.5 45.4 47.5 49.4 Sit 52.7 53.8 55.0 56.2 57.4 58.7 60.0 61.4 62.8 64.2 39.9 41.4 42.9 44.5 46.0 46.0 46.0 46.0 46.0 46.0 46.0 46.0 23.2 25.8 23.7 20.6 18.9 16.1 15.0 10.3 91 68 0.5 -0.8 -34 -4.8 6.2 15.6 11.6 101 85 7.0 7.0 -10.5 -10.5 -10.5 -33.5 -33.5 -46.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 00 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0.0 60 0.0 0.0 0.0 0.0 0.0 2&7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 00 00 50 00 00 00 0.0 00 00 0.0 00 5.0 0.0 0.0 25.0 0.0 10.0 0.0 0.0 0.0 0.0 0.0 00 06 0.0 60 00 00 0.0 50 00 00 25.7 0.0 00 00 0.0 00 50 00 0.0 25.0 0.0 10.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 00 0.0 00 5.0 5.0 5.0 30.7 30.7 30.7 30.7 30.7 30.7 35.7 35.7 35.7 60.7 60.7 70.7 5.82 8.62 8.62 8.62 6.62 6.62 862 6.62 8.62 6.62 8.62 8.62 6.62 8.62 8.62 34.32 34,32 34.32 34.32 34.32 34,32 34.32 4,32 34.32 34.32 14.32 34,32 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.76 71.78 71.78 71.78 71.78 71.78 71.78 71.78 7.78 71.78 71.78 71.78 71.78 71.78 1% 71.78 71.78 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 63 63 63 605 58 SB 58 5B SB 45.5 45.5 45.5 47.5 47.5 45 35.48 45.38 47.48 49.38 51.08 52.68 53.78 54,98 55.18 57.38 58.68 59,98 61.38 62.78 64.18 39.88 41.38 42.88 44,48 45.96 45.98 45.98 45.98 45.98 45.98 45.98 45.98 63.2 25.8 23.7 20.6 189 16.1 15.0 103 91 68 O5 -06 1.6 0.2 1.2 20.6 166 15.1 13.5 12.0 120 -05 -5 -05 15 15 -1.0 110.5 125.6 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 143.4 143.4 143.4 106.6 164.1 164.1 164.1 164.1 164.1 151.6 151.6 151.6 153.6 153.6 151.1 OCT 22,1984 Doom «1999 (LOM FORECAST ENERGY SALES FORECAST (Gx) 215.1 ) LOCAL LOSSES (#) ‘5.64 GROSS ENERGY REQUIREMENT (Gen) © 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDAD ) NET GENERATION POTENTIAL (GH) 205.6 (NET GENERATION ACTURL (Gin) 205.6 NEM HYDROELECTRIC PROJECT: OOROTHY YEAR ADDED 199 (CAPITA COST (9000) FINED O84 COSTS (9000) UWET ENERGY REQUIREMENTS (Gh) © 21.6 NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gh) 0.0 PROJECT ‘YEAR ADDED CAPITAL COST (#000) FINED 08m COSTS (9000) (UOET ENERGY REQUIREFENTS (Gh) = 21.6 NET GENERATION POTENTIAL (Gun) NET GENERATION ACTUAL (Gen) 0.0 NEM TRANGAISSION PROJECT YEAR ADDED CAPITAL COST (#000) FIXED 04M COSTS (8000) UNMET ENERGY REQUIREMENTS (Gund = 21.6 NET GENERATION POTENTIAL (Gat) NET GENERATION ACTURL (Gun) 00 ENERGY LOSS (+) ENERGY PURCHASED (Gan) UNIT COST AT SOURCE ($/Guh) PURCHASED ENERGY COST ($000) ‘NEW PRIME THERA TPES Prime Diesel CAPACITY ADDED (Ma) CUPULATIVE CAPACITY ADDED (mai) ° 1985, 6% 240.4 205.6 205.6 0.0 0.0 wo 0.0 643 201 0.0 “5 0.0 “5 0.0 1987 242.9 6.47 258.6 205.6 205.6 33.0 0.0 33.0 0.0 0.0 1988 20.1 6.51 266.4 25.6 205.6 0.0 0.0 0.0 1989 256.7 655 273.5 08.2 273.5 0.0 0.0 0.0 0.0 0.0 0.0 1990 61.4 6.57 278.6 (06.2 278.6 0.0 0.0 0.0 0.0 0.0 0.0 1991 266.4 6.60 284.0 (08.2 284.0 0.0 0.0 0.0 0.0 0.0 0.0 ise 21.35 6.63 289.5 08.2 289.5 0.0 0.0 00 00 0.0 0.0 1933 276.8 6.65 235.2 8.2 26.2 0.0 0.0 0.0 0.0 0.0 0.0 6.68 w1.0 6.2 w1.0 0.0 0.0 0.0 0.0 0.0 0.0 195 287.5 6.71 6.8 308.2 6.8 0.0 00 00 0.0 0.0 0.0 196 233.2 6.75 uo (6.2 08.2 173% ae 0.0 ae 0.0 48 0.0 Exhibit S-B Sheet 1 of 3 197 196 199 238.9 W8 30.8 6.78 6.81 6.85 H9.2 5.6 B21 308.2 8.2 8.2 8.2 8.2 8.2 325 0 eSNi7 8 1.0 124 239 126 0.0 0.0 23.9 1.0 17.4 0.0 0.0 0.0 0.0 1.0 17.4 0.0 0.0 0.0 0.0 ° ° ° 2000 u7.0 6.88 Bee 08.2 wee 14.8 wT 126 wT 00 00 0.0 0.0 2001 B32 6.92 WS.6 wae 82 me ne 126 ne 00 0.0 0.0 0.0 323.6 6.% Bes 06.2 82 m8 “4 125 we 0.0 0.0 0.0 00 B61 6.99 3.6 We 5.4 126 a4 00 00 0.0 0.0 6.1 6.99 3.6 8.2 wee 4.8 4 126 4 0.0 0.0 0.0 0.0 et 6.99 353.6 8.2 8.2 4.8 34 126 4 0.0 0.0 00 0 36.1 6.9 359.6 08.2 a2 wA8 34 126 3.4 0.0 0.0 00 0.0 2007 B61 68 353.6 8.2 wae 8 s4 126 4 0.0 00 0.0 0 (2006 Bet 69 B26 6.2 wee WB 34 126 a4 00 0 0.0 00 2003 Bet 6.9 33.6 8.2 (8.2 WB 31.4 126 4 0.0 0.0 0.0 0 36.1 69 39.6 08.2 6.2 0.0 0.0 00 0.0 (RPITA COST (#000 FIXED OWN COST «90000 WME) EXERGY REDULRENEMT (Gat) NET GENERATION POTENTIAL (Gut) NET GENERATION ACTURL (Gut) ENERGY LOSS (x) EMERGY GENERATED (Gund FUEL USE (haes/UMITD INITIAL FUEL PRICE (9/MIT) FUEL ESCALATION RATE. (3/YERR) 1984-1988 1989-2003 FUEL PRICE «s/UMITD FUEL COST (8000 VARIABLE OWN RATE (CENTS/iaan) \VaRIAGLE OWN COST (90001 ‘TE: Diesel CHPRCITY ADDED mA) (CUMULATIVE CAPACITY ADDED (m) HIT. COST (9000) FIXED 4M COST (4000) » CaeeciTY om VET DERGY REQUIRED (Gun) (CREO TTY UTILIZATION FACTOR \(Porenr i) NET GENERATION POTENTIAL (Gat) NET GOERATION ACT (Gat) ENERGY OBS (8 (ENERGY GENERATED (Gan) FURL USE (nt /6A8) IMITEAL FUEL PRICE (8/6RL) FUEL ESCALATION RATE. (/YERR) 1984-1988, 1989-2003 FUEL PRICE (W/UNIT? FUEL COST (8000) \vORIA@LE OW COST (40000 EXISTING & COMUTTED HYD (x) NEM HYDROELECTRIC (8) NEM TREREISSION IMOORT (8) NEM PRIME THER (8) EXISTING PRIME DIESEL (1) SORTFAL (3) a6 0.67 LORO FRC. [x 0.0 o 0.0 15 0.999 o 3 os 00 on a 00 461.1 (#00070 0.0 3:5 (9000/0) 0 25 2.6 O67 m4 2.6 ° 2.6 115 0.999, ® 3 0.8 (Conran 0 9.47 0.00 0.00 0.00 9.53 0.00 we 0.0 0.0 0.0 099 a0 ao 6.7 we we 0.99 2474.3 20.7 a0 5 0.00 0.00 0.00 149 0.00 “s 0.0 0.0 0.0 0.959 a0 0.0 16.7 “Ss as 0.999 362.2 Tet 0.0 2.20 0.00 0.00 0.00 17.80 0.00 sho 0.0 0.0 0.0 0.98 a0 a0 67 33.0 3.0 0.999 67.2 ene 0.0 ne 0.00 0.00 0.00 2.51 0.00 0.8 0.0 0.0 0.0 0.99 0.0 a0 6.7 0.8 0.999 aes 06.3 oo m8 0.00 0.00 0.00 22,82 0.00 0.0 0.988 0.0 0.0 a0 0.0 67 0.0 0.0 0.988 a0 0.0 100.00 0.00 0.00 0.00 0.00 0.00 0.0 a0 0.0 0.0 1.017 a0 a0 146.7 a0 a0 1.017 a0 a0 a0 100.00 0.00 0.00 0.00 0.00 0.00 0.0 0.0 0.0 0.0 1.008 a0 a0 67 a0 0.0 1.008 a0 a0 ao 100.00 0.00 0.00 0.00 0.00 0.00 0.0 0.0 0.0 0.0 Lory a0 7 0.0 a0 1.079 00 oo 100,00 0.00 0.00 0.00 0,00 0.00 0.0 Luz ao a0 ue a0 0.0 ao 100.00 0.00 0.00 0.00 0.00 0.00 0.0 a0 0.0 0.0 Ls, a0 0.0 may a0 00 115, 0.0 0 100.00 0.00 0.00 0.00 0.00 0.00 a0 ae 00 © 0.0 00 © 0.0 0.0 L179 1.215 ao 8600 a0 30 30 2605.5 13 2a 2 ao | 48 une a ° 0.0 “8 Lie 1.218 00 | (4m 00) 6 er) 100,00 98.46 0.00 0,00 0,00 0,00, 0.00 0,00 0.000 14 0.00 © 0,00 Exhibit 2-8 Sheet 2 of 3 1400 00 © 0.0 0.0 0.0 00 © 0.0 0.0 Lor 29 LT oo 8600 er er) 3006300 00 86000 15S 12S IDS 2 oa ns oT 7.8 7.41087 10140 0.0 12) 1.2097 1020.7 1662.2 0.0 1 183 OO a0 00 65 MES (OO 0.00 © 0.00 7.20 0.00 0.00 0,00 0.00 © 0.00 0,00 345 5.0.00 0.00 © 0.00 (0,00 0.0 137 0.0 oo LT 0 a0 ao 9.98 3.08 0.00 0.00 0.00 0.00 0.0 0.0 0.0 a0 1.408 00 ao 30 0.0 3 mo 0 a0 1.408 0.0 oo ao we 10,82 0,00 0.00 0.00 0.00 a0 Lat a0 a0 so 0 m3 mao a0 0 a0 a0 0.0 a0 1 00 So 0.0 nS m0 0.0 0.0 140 a0 0.0 ao 670 4.0 0.00 0.00 0.00 0.00 ro 00 ao a0 0.0 nS m0 0.0 a0 14% a0 00 ao 5.70 14.30 0.00 0.00 0.00 0.00 oo 0.0 0.0 0.0 18 a0 a0 30 10.0 m0 0 00 a0 a0 6.70 4.0 0,00 0.00 0,00 0.00 a0 1 a0 ao 0 10.0 0.0 1s a0 0 ao 0.0 1490 a0 0 oo 6.7 14.30 0.00 0.00 0.00 0.00 a0 0.0 0.0 a0 144 a0 oo 0.0 10.0 0.0 5 m0 ao a0 1.498 0.0 0.0 57 4.30 0.00 0.00 0.00 0.00 0 a0 ao Bo 1327.5, 12.3 ms ao ao 1a a0 a0 oo an 90 0.00 0.00 0.00 0.00 00 0.0 0.0 0.0 a0 123 ao m4 00 a0 140 a0 a0 oo 6.70 14.30 0,00 0.00 0.00 0.00 a0 0.0 a0 1.4% a0 a0 ao a0 00 1498 a0 0 a0 a7 0 0.00 0.00 0.00 0.00 Exhibit 9-6 ameny OF AL COSTS Sheet 3 of 3 CHITA COSTS (4000) eS ee eS) a0 nr) 0.0 197015 3525.0 2577.0 00 00 00 00 00 00 2M63 00 6.0 1127.5 0.0 HI. FIXED Obw COST (8000) Ce en 0.0 a0 a0 ao | 11S 3 13 23 ek 3 3 Me. \vaaiA@LE 4M COST (#0000 R227 SHLD a0 0.0 a0 1 138.3 00 60 60006 00 ao 8 0000 PUROREED EERGY (9000) Co ee ee) 0.0 a0 a0 0 00 860.0000 00 86000 0 en) 00 86000 FUEL COST (#000) 1SH7.8 203 3622 36.2 AE a0 0.0 a0 1020.7 1662.2 00 860.00 00 a0 a0 TOTAL YERMRLY COST (9000) Se eC i ee ee el SCOUNTED YEAMLY COST (#0000 - 1711.0 2693.9 3204.4 3780.4 418.2 0.0 a Cr) 0.0 13362.6 21516.6 1701.2 192.4 185.9 ATG ATS 167.6 162.0 12S HSA ISAO AIT 2074. se YER r DISCO RATE (5) as (GK, DISCOUNTED COST (8000) AM1L0 4370.9 7OSS.3 1145.7 1S6REY 1SKALY 1S6LEF 1S6Z.F SEALY 186A S62 136229 ABIES. 7 002. GTI. T GTIOG.1 TEGO GMOTI.G GAQNS.1 | GONIZ. 7 GASTA.7 G9HS8.2 0016.6 7017.6 THORS TSMR TIGL GM, DISC. COST TO 2010 (9000) 77663 SM MON-OWITA COSTS IN 2010 Me (9000 VALUE 1X 2010 OF MO-CROITIN, 6 COSTS THA 2043 (4000) DISCOTED MON-CHPITAL COSTS = 3780 EVO 2010 (4000) REPLACEMENT COST AMO SALVAGE VALUE DETERVINATION (MEM UNITS) vat coweciTy ena ODED REAACOOMT REPACERENT RETLROEMT err DIScRERLAL DiscREALe 20kS SALVAGE Dist SAG ~ von vem We vem cast (#000) (8000) (9000) VALUE (#000) (8000) Hoan a 199 2s 73638.0 a0 0.0 rom 82 oo a0 ‘TeWHISSION ao 0.0 * PRIME THER 81 a ” o a0 a0 a0 a0 00 PRIME THER 42 2 ” © 0.0 a0 0.0 a0 0.0 PRIME THER 4 2 ” o 00 0.0 a0 0.0 STORY THER 41 3 195% 2016 2086 2086 208.5 16.8 us 1268.0 1.5, STORY THERMAL 42 3 2005 202s o ans 205.5 8 a0 a0 a0 STORY THERM 43 5 2008 08 ° 208 1827.5 eu. a0 1723.4 ait ‘STANOBY THER 4 10 eno 2030 o e050 wre a0 132.8 11 STRWOBY THERMAL 5 2 “ © 0.0 0.0 0.0 0.0 STAMOBY THERA 06 F 0 0 0.0 0.0 0.0 0.0 STAWORY THER 07 2 0 © 0.0 a0 a0 0.0 STANORY THERWA 08 2 0 o a0 a0 0.0 0.0 STAWOBY THERM #9 2 ” © 0.0 0.0 a0 0.0 TROY THERA #10 2 0 o 0.0 a0 a0 a0 STAMORT THER 0.0 0 0 00 StRORY THEW 812 ao a0 a0 a0 STORY THER 13 a0 0 a0 a0 ‘sm (9000) 814.0 me w.0 (NET DISCOUNTED REPLACEMENT COSTS AAO SALVAGE VALUES (40000 “0 . TOV DISCOUNTED ALA COSTS (4000) 614 JUMOSS OCTOBER 22, 1964 HIGH FORECAST YEAR > PEAK DEMAND (Mid) > ENERGY SALES (Gwh) LOAD FACTOR LOSS FACTOR 69KV CAPACITY LOSS (Mw) 69KV ENERGY LOSS (Gun) FEEDER CAPACITY LOSS (#W) FEEDER ENERGY LOSS (Gh) JUNEAU CAPACITY LOSS (Hw) JUNEAU ENERGY LOSS (Gwh) {JUNEAU CAPACITY LOSS (x) (JUNEAU ENERGY LOSS (x) 1984 a3 215.1 0.59 0.39 0.46 1.58 1.83 10.55 2.29 12.13 5.55 5.64 35.7 233.5 0.48 0.27 0.84 1.97 2.58 13.00 3.42 14.98 6.14 6.41 LOCAL SYSTEM LOSSES 1986 1987 1988 592 625 65.7 248.2 261.6 275.2 0.48 0.48 0.48 0.27 0.27 0.27 0.95 1.05 1.17 2.23 2.48 274 2.77 2.9% 3.14 13.69 14.72 15.55 372 4.01 4.31 16.12 17.20 18.30 6.28 6.42 6.55 6.50 6.58 6.65 1989 68.9 268.5 0.48 0.27 1.28 3.01 3.32 16.38 4.61 19.40 6.69 6.72 1990 71.6 300.1 0.48 0.27 1.38 3.26 3.48 17.10 4.87 20, 36 6.80 6.78 1991 1992 1993 1994 1995 19% 1997 1998 Exhibit 10-A 1999 2000 2001 2002 2003 2004 «2005 «2006 «= 2007 m5 77.5 312.2 324.7 0.48 0.48 0.27 0.27 1.50 1.62 3.53 3.82 3.65 3.83 17,86 18.66 5.15 5.46 21.39 22.47 6.92 7.04 6.85 6.92 337.7 0.48 0.27 1.75 4.13 4.02 19,49 5.76 23.62 7.17 6.99 83.9 351.3 0.48 0.27 1.0 4.47 4.23 20.37 6.13 24.84 7.31 7.07 87.2 365.4 0.48 0.27 2.05 4,83 444 21.28 6.49 26.14 7.44 TAS 379.4 394 0.48 0.48 0.27 0.27 2.22 2.39 5.21 5.62 4.65 4.87 22.21 23.16 6.87 7.26 27.42 28.78 7.58 7.72 7.23 7.30 97.7 409.2 0,48 0.27 2.58 6.06 3.12 e418 7.69 30.24 7.88 7.39 101.4 105.3 424.9 441.2 0.48 0.48 0.27 0,27 2.78 2.99 6.54 7.05 5.36 5.63 25.23 26.34 8.14 8.62 31.76 33.38 8.03 6.19 7.48 7.57 109.4 458.2 0.48 0.27 3.23 7.60 5.91 27.51 9.14 35.11 8. 36 7.66 113.6 475.8 0.48 0.27 3.48 8.20 6.21 28.72 9.69 36.92 8.53 7.76 17.9 4% 0.48 0.27 3.75 8.83 6.52 29.99 10.27 38, 82 8.71 7.86 417.9 494 0.48 0.27 3.75 8.83 6.52 29.99 10.27 36.82 8.71 7.86 117.9 434 0.48 0.27 3.75 8.83 6.52 29.99 10.27 38.82 8.71 7.86 7.9 494 0.48 0.27 3.75 8.83 6.52 29.99 10.27 38.62 8.71 7.86 117.9 494 0.48 0.27 3.75 8,83 6.52 29.99 10.27 34. B2 8.71 7,86 117.9 494 0.48 0.27 3.75 8.83 6.52 29.99 10.27 38.82 8.7) 7.86 2009 117.9 494 0.48 0.27 3.75 8.63 6.52 29.99 10.27 38. 82 8.71 7.86 2010 117.9 AH 0.48 0.27 3.75 8.83 6.52 29.99 10.27 38. 82 8.71 7.86 Caoplan OCTOBER 22, 1984 THERNAL HIGH FORECAST YEAR Cert nKNeune 10 RESOURCES AS OF 1964 ul w 12 ) Existing and Committed Net Hydro Resources 13 South of Taku Inlet thru Thane 14) Existing and Committed Hydro Resources 15 North of Taku Inlet 16 ) Existing and Committed Thermal Resources u (All North of Taku) 18 ~~ Total Existing ana Committed Net Resources 19 South of Taku Inlet thru Thare 20 = Total Existing and Committed het Resources 21 hortn of Taku Inlet 22 23 EXISTING AND COmMITTED RESOURCES 24 =~ (After Transmssion Losses) 25 25 DEMAND 27 ( Peak Demand 28 29 = Reserve Reauirements % = (Equal to Peak Demand Less Hydro North of Taku) a 32 EXISTING RESERVE MARGIN 33° (Excess or shortfall of reserve) Ro 35 NEW RESOURCE ADDITIONS 3% ~~ Hydro Soutn of Taku Inlet 7 (Capacity as measured at Thane) 3% Hydro North of Taku Inlet x3 40 Thermal North of Taku Inlet a 42 TOTAL ANNUAL ADDED CAPACITY 43 44 CUMULATIVE ADDED CAPACITY 4S 46 TOTALS AFTER ADDITIONS 47 hyaro nortn of Taku 48 49° mycro south of Taku x Si Thermal (North of Taku) se S3 RESERVE REQUIREFENTS AFTER ADDITION Pe) SS RESEAVE MARGIN AFTER ADDITIONS 56 S7 RESULTING TOTAL CAPACITY JUNERU 20 YEAR PLAN , Exhibit 10-B 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.82 6.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 862 8.62 8.62 6.62 6.62 8.62 8.62 A.62 8.62 8.62 6.62 8.62 G62 6.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53,00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.64 79.64 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21.12 21.12 6.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 55.7 59.2 62.5 65.7 68.9 71.6 745 77.5 80.6 83.9 87.2 9.6 94.0 97.7 101.4 105.3 109.4 113.6 117.9 117.9 117.9 117.9 117.9 117.9 117.9 117.9 35.5 47.1 50.6 53.9 57.1 60.3 63.0 65.9 68.9 72.0 75.3 78.6 62.0 @5.4 891 92.8 96.7 100.8 105.0 109.3 109.3 109.3 109.3 109.3 109.3 109.3 109.3 23.2 261 20.6 16.1 129 6.5 5.8 0.6 -3.6 -7.8 -16.1 -19.4 -24.0 -27.4 -31.1 -37.3 -43.7 -47.8 -52.0 -56.3 -56.3 -73.8 -73.8 -73.8 -96.6 -96.8 eentes 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 06 00 00 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 00 50 50 50 50 00 50 5.0 100 5.0 5.0 0.0 5.0 0.0 15.0 0.0 0.0 25.0 0.0 15.0 00 0.0 00 66 00 60 60 00 50 50 50 50 0.0 5.0 5.0 100 50 50 00 50 0.0 15.0 0.0 0.0 25.0 0.0 15.0 0.0 0.0 00 0.0 60 0.0 0.0 0.0 5.0 12.0 15.0 20.0 20.0 25.0 30.0 40.0 45.0 50.0 W.0 55.0 55.0 70.0 70.0 70.0 95.0 95.0 110.0 5.62 6.62 8.62 8.62 6.62 8.62 6.62 6.62 462 862 6.62 G62 6.62 B62 862 6.62 6.62 6.62 6.62 8.62 8.62 6.62 6.62 6.62 8.62 B62 6.62 45.93 43.93 45.93 45.93 45.93 71.78 71.78 7..76 7:.78 71.78 71.78 72.78 72.78 74.78 71.78 71.76 72.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 98.72 71,22 71.22 69.97 69.97 68.77 68.77 £5.27 70.27 74.14 74.14 79.14 78 83 64 95.5 98 103 103 108 108 105.5 105.5 105.5 107.5 107.5 110 35.48 47.08 50.58 53.68 57.03 63.28 62.98 65.83 64.65 71.98 75.28 78.53 61.98 65.36 89.08 92.78 95.68 100.8 105 109.3 109.3 109.3 109.3 109.3 109.3 109.3 105.3 23.2 241 2006 161 129 85 5.6 0.6 14 BE mtd 06 40 “24 mld 27 130 22 -20 -1.3 1.3 -3.8 -38 -3.8 -1.6 -1.6 0.7 MOS 125.8 125.8 124.5 124.5 149.2 149.2 145.7 180.7 154.5 154.5 159.5 158.4 163.4 168.4 175.9 178.4 163.4 163.4 186.4 166.4 185.9 185.9 185.9 187.9 187.9 190.4 ELOWO OCT 22, 1984 TE HIGH FOREDRST veRe 1384 ENERGY SALES FORECAST (Gam) 215.1 » LOCA LOSSES «9 34 GROSS ENERGY REDUIREMNT (Ean? — 27.2 (AT SUBSTATIONS) EXISTING & COMMITTED HOR Y NET GENERATION POTENTIAL (BAH) 205.6 NET GENERATION ACTUAL (Gent 205.6 Nu HYDROELECTRIC PROJECTS ‘Yen? AadED CABITA. COST (#0001 FIXED O48 COSTS ($0000 LET EXERGY REQUIREMENTS (Gem) 21.6 NET GENERATION POTENTIAL (Gah) NET GENEARTION CTU [Ger 0.0 paovects YEAR ADDED CHITA. COST 14000) FixzD Obs COSTS (#000) AMET ENERGY REQUIRERENTS (Gan) 21.6 NEY GENERATION POTENTIAL (Gen) NET GENERTION ACTUAL Gn) 0.0 NEw TREASHISSION ROUT: YEAY ADDED caat"a. CAST (8000) FINED O4N COSTS 18000) 21.6 00 nde ALPE Tre RL TW: Praee Diesel CHARITY ODED (a 1985 aus eat 28S, 208.6 wes 0.0 29 0.0 00 28.2 6.9 a3 205.6 25.6 0.0 0.0 1987 261.5 278.8 205.6 205.6 The a0 The 0.0 me 60 1988 a2 6.65 aus 208.6 5.6 1.3 0.0 a9 a9 0.0 1983 288.5 6.72 wg 8.2 Hrd 0.0 0.0 0.0 0.0 6.0 1390 00.1 6.78 20.5 308.2 308.2 13 0.0 123 12.3 0.0 1 wee 6.85 BLS 308.2 8.2 0.0 a4 25.4 60 192 a7 6.2 He wae wa.2 33.0 8.0 BO 6.0 19831954 Bua 7.07 76.1 38.2 308.2 308.2 se 680 0.0 a0 Bh2 68.0 00 © 00 32 68.0 40 60 o a 1985 ws. Tas ILS 0.0 64 ae 0.0 19% 3.4 223 106.8 0.0 98.7 0.0 7 0.0 197 334.0 1.0 22.8 wae wa 16 0.0 10.6 0.0 1A. 0.0 Exhibit 10-C Sheet 1 of 3 a3 0.0 13a 0.0 1d a3, 0.0 48.5 a0 WS 0.0 coo 2001 2 458.2 2ST 1.6 ATG 433.3 3082 308.2 308.2 3082 1664 185.2 0.0 0.0 166.4 185.2 0 0.0 3 2 a73.8 2.18 52.7 wae 8.2 2a 0.0 0.0 434.0 7.86 28 306.2 308.2 0.0 224.7 0.0 224.7 0.0 Be i 45.0 494.0 490 458.0 7.867.887.8578 S26 28 58 SI 308.2 O82 82 08.2 wee m2 EZ = HOA u7 AT AT AT 0 a) 247 247 247 0.0 a) 0.0 a7 AT AT RAT 0.0 0.0 0 00 54.0 7.86 28 308.2 82 a0 224.7 0.0 0.0 434.0 7.85 52.8 308.2 wae 27 a0 224.7 0.0 20.7 0.0 2030 0, 7.85 2.8 308.2 ‘8.2 207 2.7 0.0 2a 0.0 ert COST (4000) FINED Obm COST (8000) WET ENERGY REQUIRENENT (Gee) NET GENERATION POTENTIAL (Gat) NET GENERATION ACTUAL (Gut) ENERGY LOSS (8 ENERGY GENERATED (Gen) Fu USE Guan /UniT? IITIAL FUEL PRICE (9/MT) FUEL ESCALATION RATE (3/YERR) 1984-1988 1989-2003 FURL PRICE (8/UNITD Fue. cost 18000) VARIABLE OAM RATE (CENTE/ia) \VaRIGLE OW COST (9000) VE: Diesel (CAPACITY RODED (md CURATIVE CAMRCITY AODED Or) CRIT CAST (#0000 FINED 08m COST (40000 > CRORCITY mi) UNMET ENERGY REQUIRED (Gat) CAPACITY UTILTIIATION FACTOR (woven) NET GENERATION POTENTIAL (Guan) NET GENERATION CTU (Gun) BRGY LOSS (8 ENERGY GENERATED (Gan) Fue. USE (on /6AL) INITIAL Fue. PRICE (9/09) Fu. ESCALATION RATE (/YERRD 1964-1988 1989-2003 Fuk. palGe (wT Fue. COST (9000) VARIABLE 04 COST (4000) UMMET EXERGY REDUIRENEXT (Gan) SUMORY OF NET GENERATION EAISTING PAINE DIESEL «8 SATA. 0.67 LORD FAC, o a0 3 os ° a 0.998 a0 oe ao oo 461.1 (#00070 00 ‘23 (s000/m ° 1S 2.6 oer me 2.6 o a6 15 098 ° 3 os 1307.8 8 (CENT /Mam) 172.2 00 9.47 0.00 0.00 0.00 333 .@ 2 0 0 a0 0.99 a0 ao ao 67 as as 0.99 wH7.0 BLL 0 2.76 0.00 0.00 0.00 17.26 0.00 a7 a0 0.0 0.0 0.959 a0 a0 a0 a0 7 way Ma? 0.959 aes 63.9 0.0 m8 0.00 0.00 0.00 ee 0.00 me 0.0 0.0 0 0.999 00 a0 467 me Tae 0.99 ‘S201. 45.7 0.0 ae 0.00 0.00 0.00 26 0.00 0.999 0.0 00 “7 os 098 605.0 703.3 a0 70.05 0.00 0.00 0.00 23.95 0.00 a0 0.988 a0 ao ao 0 “7 a0 0.0 0.988 a0 0 a0 100.00 0.00 0.00 0.00 0.00 0.00 12.3 0.0 0.0 a0 1.0.7 ao a0 a0 00 123 67 wa wea 1.017 27.0 8.4 a0 616 0.00 0.00 0 ae 0.00 ae a0. 00 00 1.008 ao a0 0 0 67 ae ae 1.08 1970.2 eu a0 2.38 0.00 0.00 0.00 1.62 6.00 BO She 00 © 00 a) a) 10mg ue 40 ao oo | 00 0 30 30 © 10.0 25.3 28.3 23 3s a a wo | She 7 M67 wo ke ° no Me org 1.12 3s 4377.7 wer a3 oo = 0 55.29 0.00 0.00 0.00 71 0.00 64.0 0.0 0.0 a0 1185, 0 0.0 0 1s0 11s, 3 we 4.93 0.00 0.00 0.00 16.07 0.00 ae 0.0 0.0 a0 Lay 00 a0 5.0 20.0 208.5 179 7e82.4 8 a0 7.71 0.00 0.00 0.00 21.29 0.00 ‘8.7 0 0.0 a0 12s 0 0 2.0 00 une a7 121s 0078.1 783.3 oo 3.75 0.00 0.00 0.00 8.25 0.00 1.6 0.0 00 a0 1.231 a0 00 30 ao 208.5 os 16 une iy a6 Len 1062.7 916.9 a0 R09 0.00 0.00 0.00 an 0.00 Exhibit 10-C Sheet 2 of 3 a6 a 3 Mes a3 wo a3 HO a3 wo 1.29 LRT Bee THe Ae HD mo BO 00 | 0 os ms oS 10.9 6S 102.7 os ° os 281.7 oss ake 0 00 mie 0.00 4.00 0.00 0.00 668 13.28 a2 hee 0.00 0.00 166.4 so 0.0 208.3 ir 3 ms mo me Lar 7338.2 ert ao “0 0.00 0.00 as se 0.00 1.408 11021.0 1.408 7068.4 wed eo ew 00 0.00 aw un 0.00 a6 eeu 146.7 146.7 1741467 ast 1.498 ANS.6 M613. 1 ue ao | MO a0 8600 105 105 15 13 2 19 0 LO o2 19 ° 2 m9 1481 1.498 57.3 8625.3 67.4 2S Cr) 0.10 57. 0.00 0,00 0.00 0,00 22.09 17.00 18.63 0.00 0.00 7 146.7 146.7 1.494 1615.2 178 0.0 1498 625.3 a0 7.4 0.00 0.00 20.4 14.63 0.00 20.7 1.7 67 1467 1.4% 1461.2 ume 120 430 6316.5 73 0 wear 14.7 46.7 67 144 1615.2 ume 13 ns mo ns ns 1.4% 623.3 eas 7.4 0.00 0.00 27.4 m7 1467 146.7 14% 1615.2 ume 0.0 0 00 19.5 1a 623.3 3.5 ao 7.4 0.00 0.00 a4 14.63 0.00 aus wr 1761 176.1 176.1 1494 1732 108.6 14% 7.4 306.7 ao 0.00 Bos wie 0.00 2247 1761 1761 1761 1494 r7su.2 0.0 70.0 0 123 a6 ms “as as 10% 7.4 a7 74 0.00 wos wie 0.00 20,7 28 24.7 207 1.496 em. 1797.3 30 0 ao ao 00 1a 00 a0 ao 7.0 0.00 0.00 216 0.00 0.00 ‘SUA OF PLSW COSTS ‘CAPITAL COSTS (#000) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 285.5 2055 205.5 265.5 FIRED Gdn COST (9000) 0.0 00 0.0 0.0 a0 00 0.0 0.0 ns 3.0 32.5 70.0 VARIAGLE DAM COST (9000) wR? ML 463.9 ‘45.7 LS 0.0 6A 203.5 wat 43.3 ALG 668 PURCRSED BMERGY (8000) 0.0 a0 a0 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 FUEL COST (#000) 1537.6 WAT. AIT2.S S201 6245.0 0.0 R70 19.2 3195 4371.7 5166.5 7262.4 TOT, YEARLY COST (6000) ee oo ed 0.0 102.4 «2177.6 «STB «7102S BHAT 108248 DISCOUTED YEARLY COST (#000) AMO | 3273.5 ABEL 5219.4 6055.0 0.0 B.2 1711.6 437, SRN GLMST OTL (BRSE YEAR 1 ‘DISCOUNT RATE (8) as x, DISCOWMTED COST (1000) WTO 4386.5 9120.2 1453.6 20804.6 2050.6 214280 23100.4 27510.5 27S. MMT. 43068.9, M, DISC. COST TO 2010 (8000) 230081 SUA MON-CWITAL COSTS IN 2010 eu (9000) VALE IN 2010 OF MOFDAPITAL am ‘COSTE THRU 2045 (9000) DISCOLNTED MON-CAPITAL COST 199828 ‘BEYOND 2010 (#000) REASCOOMT COST RO GALWREE VALUE DETERATAATION NEY UNITE! vr oercity ena ODED FERRET FEAROENENT RETRENENT ovr. DiscaEnLeL om YoR vena a2 Yea Cast (1000) «60001 ‘HYDRO OL 0.0 ‘AYDRO #2 0.0 TRRGAISSION 0.0 rE THER 3 1558 28 2088 2058 s6.0 27.9 BRINE THERA, 02 10 199 2019 2039 2053 (278,06 10.3 PAINE THER a3 3 2001 eee ry e061 416.0 32.6 STANDBY THER s 2003 2023 2043 2063 4116.0 1076.0 ‘STANDBY TrERMAL 02 10 2010 2030 o 2080 6278.0 1289.9 STOADBY THERA 63 3 1982 ane ae zo 2308.3 873.9 ‘STANDBY THERA 04 s 1933 2013 2033 2083 2035 650.4 ‘STAADBY THERM 05 s 194 eat ry 24 25.5 A214 STPADEY TrER*e, 06 5 39S 2015 20aS 2085 2005.5 793.6 STANDBY THEVA €7 s wer 207 207 as? 26.5 40.9 STANDBY ThEAWA, 08 3 2000, 2020 2000 2060 205.5 56.2 STANDBY THERA 09 s 2005 2023 oO 2005 6316.5 (1687.8 STANDBY THER, 810 a 2008 eee oO 2008 1527.3, 2397.2 ‘STORDBY THERE BLL s e010 200 0 2050 2u6.S amh7 ‘S"PADbY THERA, 012 . 0.0 ‘STANDRY THEOL 413 0.0 SM (4000) 16132.6 ‘NET DISCOATED RELACENENT COSTE FAD GALWEEE VALLES (9000) 18168 . TOT. DISCOLNTED ALsw COSTS 14000) 9887 0.0 10,0 169.3 0.0 6878.1 aA Ao 2012.9 2ms.s a5 916.9 0.0 10623.7 1353.6 2305,2 12.1 Exhib Sheet 116.0 a7.5 1050.3 0.0 12253.3 173074 1085.6 7137.7 it 10-C 3 of 3 278.0 ans 1188.4 0.0 1332.3 1290.8 12708,3 64046,0 as 1010 ime 0.0 159642 197061 136 6210.6 4116.0 105.0 1481.2 0.0 10090,4 23792.6 132573 1067.9 0.0 105.0 1636.5 0.0 207189 2280.4 12091.8 121559.7 An16.0 108.0 1797.3 0.0 2200.5 9288.8 15219.1 1718.9 0.0 105.0 197.3 0.0 220.5 251428 12535.9 6916.5 IS A197.3 0.0 28200.5 Rue 155925 1494148 165007.3 0.0 Asn 2519.3 11820.4 176827,7 0.0 (2.5 1797.3 0.0 23240. 25193.3 1420.7 188248.3 150.5 245.0 192.3 0.0 2205.7 0601.5 1781.7 206034, 1 0.0 245.0 1797.3 0.0 2245.7 24588.0 218891.0 es82.5 2.5, 1792.3 0.0 203 3021.3 1350.3 230081.3 Capolan OCTOBER 22, 1964 DOROTHY HIGH FORECAST YEAR RESOURCES AS OF 1964 ) Existing and Committed Net Hydro Resources South of Taku Inlet thru Thane ) Existing and Committed Hyaro Resources North of Taku Inlet ) Existing and Commtted Thermal Resources (All North of Taku) Total Existing anc Committed Net Resources South of Taxu Inlet thru Thane Total Existing and Committed Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transmission Losses) DEMAND ( Peak Demand Reserve Requirements (Equal to Peak Demand Less Hyoro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS Hyaro South of Taku Inlet (Capacity as measured at Thane) Hycro North of Taku Inlet Thermal North of Taku Inlet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS Hydro north of Taku hydro soutn of Taxu Thermal (Nortn of Taku) RESERVE REQUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TCTAL CAPACITY JUNEAU 20 YEAR PLAN Exhibit 11-A 1964 1985 1966 1967 1988 1989 1990 1991 1992 1993 1994 1995° 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2W7 2008 2009 2010 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 7:.78 71.76 71.76 71.78 71.78 7:.78 71.78 71.76 71.78 73.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 72.78 71.78 5.82 8.62 6.62 6.62 8.62 8.62 8.62 8.62 8.62 8.62 8.62 862 8.62 862 8.62 6.62 8.62 8.62 6.62 6.62 6.62 6.62 6.62 8.62 6.62 8.62 6.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 58.00 58.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 7:.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79.84 78.59 78.59 77.39 77.39 73.89 73.69 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21,12 21.12 6.62 110.5 125.8 125.8 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 136.4 138.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 60.4 41.3 55.7 59.2 62.5 65.7 68.9 71.6 74.5 77.5 80.6 83.9 87.2 90.6 94,0 97.7 101.4 105.3 109.4 113.6 117.9 117.9 117.9 117.9 117.9 117.9 117.9 117.9 35.5 47.1 50.6 53.9 57.1 60.3 63.0 65.9 68.9 46.3 49.6 52.9 56.3 59.7 63.4 67.1 71.0 75.1 79.3 63.6 63.6 63.6 63.6 63.6 63.6 83.6 83.6 23.2 241 20.6 161 129 65 5.8 0.6 -3.6 17.9 96 63 1.7 -1.7 -5.4 -11.6 -18.0 -22.1 -26.3 -30.6 -.6 -48.1 -48.1 -48.1 71.1 -71.1 -83.6 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 00 0.0 00 0.0 0.0 0.0 0.0 00 0.0 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 00 0.0 25.7 0.0 0.0 00 0.0 0.0 0.0 00 0.0 0.0 00 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 50 00 00 00 00 00 00 5.0 10.0 0.0 5.0 5.0 0.0 20.0 0.0 0.0 20.0 0.0 15.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 5.0 25.7 0.0 00 0.0 0.0 0.0 5.0 100 0.0 5.0 5.0 0.0 20.0 0.0 0.0 20.0 0.0 15.0 0.0 0.0 0.0 00 00 00 0.0 0.0 5.0 30.7 307 30.7 30.7 30.7 30.7 35.7 45.7 45.7 50.7 55.7 55.7 75.7 75.7 75.7 95.7 95.7 110.7 5.82 8.62 8.62 6.62 6.62 8.62 6.62 8.62 8.62 34,32 34,32 34,32 34.32 34.32 34,32 34,32 34,52 34,32 4.32 4.32 H,32 34.32 34,32 W.32 4,32 34.32 4.32 45.93 45.93 45.93 45.93 45.93 71.78 71.76 71.78 71.78 71.78 72.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 72.78 71.78 71.78 71.78 71.78 71.78 7:.78 71.78 71.78 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 70.27 69.14 64.14 64.14 63 63 63 65.5 73 73 78 63 83 65.5 85.5 85.5 62.5 825 85 35.48 47,08 50.58 53.88 57.08 60.28 62.98 65.68 68.68 46.8 49,58 52.68 56.26 59.68 63.38 67.08 70.98 75.08 79.28 83.58 63.58 63.58 63.58 83.58 63.58 83.58 63.58 23.2 24.1 206 161 129 85 5.8 -0.6 1.4 229 166 113 67 33 4 -16 2.0 -21 -13 -0.6 06 1.9 19 19 “Led -het bed 110.5 125.8 125.6 124.5 124.5 149.2 143.2 145.7 250.7 175.2 170.2 170.2 169.1 169.1 1691 171.6 1791 1791 184.1 189.1 189.1 191.6 191.6 191.6 168.6 168.6 191.1 OCT 22,1984 Exhibit 11-B ‘DOROTHY HIGH FORECAST Sheet 1 of 3 YEAR 1984 1985 1986 7 1988 1989 1990 1m 1992 1993 19% 1995 199% 197 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2008 2010 ERGY SALES FORECAST (Gen) 2S.1 as 248.2 261.6 275.2 288.5 WO.) yee 4.7 337.7 Bi 4 w3.4 34.0 03.2 424.9 1.2 458.2 475.8 4H.0 494.0 44.0 44.0 44.0 494.0 44.0 44.0 > LOCAL LOSSES (x) oa oa 6.0 6.58 6.65 6.72 6.78 6.65 6.9 68 1.07 VAS 12 1.» a] 7.48 1S) 1.66 7.76 7.06 7.6 7.6 7.66 7.66 7.66 7.06 7.6 GAOSS ENERGY REQUIREMENT (Gwh) 227.2 268.5 3 276.8 23.5 w7.9 20.5 Bie W12 M13 76.1 B15 406.8 422.8 433.4 456.7 474.6 493.3 312.7 see 2.8 ‘32.8 ‘32.8 see 332.6 332.8 32.8 (AT SUBSTATIONS) EXISTING & COMMITTED HYDAD > MET GENERATION POTENTIAL (GiH) 205.6 205.6 205.6 205.6 205.6 6.2 8.2 82 6.2 be 06.2 6.2 06.2 wa? W862 08.2 6.2 62 6.2 6.2 8.2 6.2 6.2 6.2 6.2 8.2 Wb.2 NET GENERATION ACTUAL (Gem) m6 6 25.6 5.6 28.6 wd (wee wee wae wee we? wae 6.2 wee 6.2 we? 8.2 382 we? we? wae wae 82 wee v6.2 wee wee Ed HYDROELECTRIC PROJECT: DOROTHY YEAR ADDED 193 CAPITAL COST (#000) 173% ws 2ni7 FINED 08M COSTS (#000) w8 wae m8 48 8 AB 8 8 M8 we 4.8 8 304.8 (304.8 4.8 8 8 w.8 (URPET ENERGY REQUIREMENTS (Gn) 21.6 42.9 ‘4.7 13.2 87.9 0.0 12.3 ae 0 33.2 4.0 3.4 6.7 14.6 13.3 148.5 166.4 185.2 204.6 4.7 a7 a? 24.7 7 4.7 224.7 4.7 NET GENERATION POTENTIAL (Gam) 126 16 126 1 1a 1a 126 1 «1a 12 126 12 1% 126 126 126 126 126 NET GENERATION ACTUAL (Gum) 00 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 Se 0 a4 6.7 114.6 126.0 126.0 126.0 126.0 126.0 126.0 126.0 12.0 126.0 126.0 126.0 126.0 128.0 PROJECT: YEAR AODED CAPITA COST (9000) FINED 06m COSTS ($000) UMPET ENERGY REQUIREMENTS (Gh) 21.6 429 “7 The 67.9 0.0 12.3 ae 0 0.0 0.0 0.0 0.0 0.0 33 25 0.4 2 78.6 67 7 *7 6.7 8.7 67 %.7 4.7 NET GENERATION POTENTIAL (Gen) NET GENERATION ACTUAL (Gat) 0.0 0.0 0.0 00 00 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.0 00 0 0.0 0.0 0.0 00 00 0.0 NEM TRANGAISSION PROJECT: ‘YEAR ADDED CAPITA COST (9000) FLIED O4M COSTS (9000) UNMET ENERGY REQUIREMENTS (Gah) = 21.6 29 “7 The og 0.0 12.3 ae 3.0 0.0 0.0 0.0 0.0 0.0 33 2.5 0.4 2 78.6 67 67 *7 6.7 6.7 6.7 4.7 8.7 NET GENERATION POTENTIAL (Gun) (NET GENERATION ACTUAL (Gun) 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 00 0.0 0.0 00 0.0 0.0 a0 0.0 0.0 ‘ENERGY LOSS (x) ENERGY PURCHASED (Gann) ‘UNIT COST AT SOURCE (8/Gen) PURCHAGED ENERGY COST (#000) NEM PRIME THERMAL, TE: = Prame Diesel CAPACITY ADDED (ma) 0 0 o 5 Ss 10 CUMULATIVE CAPACITY ADDED (mai) ° ° o ° ° o o o ° o o 0 o ° 0 0 ° o o 5 5 5 5 5 10 10 a (Cert COST (#000) FINED OWN COST (#000) (VOET ERGY REQUIREMENT (ed YET GENERATION POTENTIAL (Gat) NET GEERTION ACT (Gat) DENY LOSS (8) ERGY GDERATED (Ga) FUEL USE (hoe /uMIT INITIAL FUEL PRICE (#/UNITD FUEL ESCALATION RATE. (/YERR) 1904-1908 1989-2003, FUEL PRICE (#/uMiT? FUEL COST (8000) VORIABLE OWN RATE (CENTE/tas) \vaRIAGLE 04M COST (9000) TE: Diesel BORCITY AODED (md QURLATIVE CRPRCITY AOED Omi) (reITA COST (#000) FINED O&M COST (#000) LISTING PRIME DIESEL » CReeITY om (OPE BERGY REQUINED (Get CRORCKTY UTILTLIATION FACTOR (woven) NET GEMTION POTETIAL (tae) HET GDEMTION CTU (Gat) DENY L058 (1) DENY GENERATED (Gen) FUEL USE (ime) INITIAL FUEL PRICE (8/000) (FUEL ESCALATION RATE. (/YERR) 1904-1908 1989-2003, FUEL PRICE (#/UNIT) FUEL COST (000) ‘VARIABLE 4M COST (9000) LISTING & COMBETTED HYDRO (x) NE HYDROELECTRIC «8 HEM TRWENISSION [OORT (8) HON PRIME THER (8) EXISTING PRIME DIESEL (8) DORTFAL «H) os 461.1 (8000/0 2:3 (9000/0 O67 0.8 (CENT a6 a0 ao a0 re a0 ao a0 a0 12.3 a6 ma 2.6 a6 0.98 1397.8 ime a0 a7 0.00 0.00 0.00 9.33 0.00 es ao 0.0 0.0 0.99 a0 a0 16.7 es es 0.99 BB a0 an 0.00 0.00 0.00 11.6 0.00 aT a0 0.0 0.0 cr) 00 a0 a0 a0 1%7 M7 ma 0.99 aes “3.9 a0 7.78 0.00 0.00 0.00 ae 0.00 me 0.0 0.0 a0 0.99 0.0 a0 a0 00 46.7 me me 0.989 S011 8.7 ao m7 0.00 0.00 0.00 25.26 0.00 0.99 0 oo 0.0 0.0 0.989 6245.0 703.3 0.0 70.05 0.00 0.00 0.00 a0 0.00 0.0 ao 0.0 0.0 0.988 0.0 a0 a0 0.0 146.7 a0 a0 0.908 0.0 0.0 0.0 100.00 0.00 0.00 0.00 0.00 0.00 2.3 0.0 0.0 a0 ao ao 0.0 12.3 67 123 ea 1.017 oo 16 0.00 0.00 0.00 36 0.00 ae 0 00 0 1.008 00 a0 167 ae ae 1.048 1974.2 eu a0 2 0.00 0.00 0.00 1.62 0.00 no 0 0.0 a0 1.079 313.5 wet a0 0.76 0.00 0.00 0.00 1.24 6.00 a0 a0 0.0 a) 12 1.185 ao 8600 en) a0 x0 0.0 m3 11S 1143, 0.0 00 CC ) so 41.3 7 1kOT 0.00 0.00 0.00 0.00 a0 a0 0.0 0.0 1.179 a0 ao a0 So a0 nS une a0 a0 L179 0.0 0.0 a0 mn a2 0.00 0.00 0.00 0.00 Exhibit 11-8 Shes a0 0.0 a0 00 215 ao a0 0 0.0 ns Leis 0.0 00 ao Bn Cw) 0.00 0.00 0.00 0,00 2 of 3 ° ao | 33 ao 00 a) a0 1.211.289 00 860.0 en ) x0 a ns 2 E} ao 8683 un sa ° 33 Le 1.289 0.0 SA.6 00 | 48 ao 8 40 We.12 67 0.00 0.00 1.20 0.00 25 0.0 a0 a0 a] a0 ao 10.0 208.5 3 2s 102.7 2s as 127 ein 180.1 ao oe a8 0.00 0.00 a0 0,00 a4 0.0 0 a0 1.367 ao ao 10.0 20.0 uo 13 04 4.0 4 1.7 04.3 Re oo an aD 0.00 0.00 ase 0.00 me a0 00 00 a0 2.0 0.0 3 m2 a0 me m2 1.408 6170.6 ome a0 a7 aH 0.00 0.00 19 0.00 ™s a0 a0 00 1.431 a0 a0 30 a0 2005.5 as 3 m6 oo 76 ™s 0.10 237 0.00 0.00 15.32 0.00 ue 7 a3 as 3 30 v0 2305.5 105 15 63.3 1.494 601.7 oS a0 74 e363 0.00 331 1.01 0.00 87 a3 a3 as 0.0 3.0 0.0 108 33 1.494 1.7 AS 0.0 ay ae 0.00 so 13.01 0.00 a7 a3 a3 a3 2.0 0.0 seze.0 175 13 63.3 4.0 3.3 3.3 1.494 11.7 aS a0 7.4 23.65 0.00 33 12.01 0.00 a7 a3 a3 0.0 0.0 0.0 175 13 63.3 3.3 1498 601.7 AS ao v4 23.63 0.00 331 13.01 0.00 “7 a3 a3 ar 0.0 0.0 0.0 175 1498 1.7 AS ao 74 23.65 0.00 a3 13.01 0.00 ar “7 a7 7 1.494 01 “3.5 20.0 70.0 see.0 3 40.0 me 0.0 a0 1.494 mens 19.8 00 7.4 anes 0.00 11.08 1.50 0.00 m7 ar a7 wT 1.494 06.1 0.0 7.0 14% weg 39.8 a0 74 ae 0.00 11.08 1.0 0.00 en wr une a7 8.7 1.4% 827.6 1n0 50 6316.3 2.5 a0 a0 0 1.498 0.0 0.0 00 7.4 eas 0.00 wese 0.00 0.00 (er TA COSTS (S000) FINED 08M COST (#000) ‘VARIABLE OWN COST (9000) PUROREED OENGY (90000 FUEL COST (8000) TOTAL YERALY COST (#000) DISCOUNTED YEAALY COST (#000) SE YEAR DISCOUMT RATE. (x SUM MOF-OWPITAL COSTS IN 2010 «90000 VALUE IK 2010 OF SOF-CTTA COSTS THRU 2045 (80001 DISCOUNTED MON-CRPITAL COSTS EVDO 2010 (8000) 1904 as me 71.0 3901 mi AT11.0 4986.3, REPLACEVENT COST FO SALVRGE VALUE DETERRINGTION (NEW UNITS) vat erm 1 wrnRO #2 ‘TRVENISSION PRIME THE OL PRIME THERA 42 RIE THE O3 Simoey MEL #1 STORY THERE 42 STORY THER 43 STROBY THER 04 ‘STRAOBY THER #5 STORY THERE 66 STeoeY THERE 47 ‘STANOBY THEW, 06 STORY THERM #9 STRNOBY THERA 41 ‘STRNOBY THER #11 STOMORY THER 8) STANDBY THER #13 owreity a 238288 g NET DISCOUNTED REPLACEMENT COSTS AAO SALVREE VALUES (#900) ‘TOT DISCOUNTED SLi COS"S ‘90n0) 00 860080 00 800 860.0 MS7 702300 o Cee i. a M4 56.9 ORO 437 -5219.4 O00 $020.2 ASTS.G O86 2058.6 RCO FEPLACERENT vn Yea a 203 ° ees Cs) 2030 ° a “ aoe ee ang 09 neo a0 enee one e0e3 2083 ees ° anes o 2030 2 ” 2 0 2 ” 2es13 au 1739.0 352.0 0.0 aus 0.0 1978.2 WAI. 4 34702.6 14985.8 27276.0 seckddeReaic8k wet 0.0 33.5 371.6 2398.9 675.3 0.0 2.3 0.0 a0 00 nerTrL (ast +000) 7538.0 a0 27.0 ems.5 ems. wiL.0 ans 205.5 22.0 see. 6916.5 Ce) e230 ee3 00 © 0.0 0.0 0.0 Exhibit 11-8 Sheet 3 of 3 a0 | 00 e230 B23 a0 80.0 0.0 e230 eS 21.3 206.1 0.0 2.3 a3 0.0 con 5.9 7655.3 87861.4 88398.3 205.3 me 180.1 0.0 ay 07.4 611.0 TA Bh 0.0 Om.3 weds 1005.7 $6888 2045 SALINE VALUE (80000 704.4 163.3 0.0 ms 1613.9 WS 1998.7 2075.0 0.0 1388.3 1728.1 0.0 a0 00 0.0 a0 0.0 0.0 6170.6 7018.6 310.8 DISC SALVE (8000) 4.3 12.5 0.0 0 192.9 went 200.3 AS 0.0 169.7 ai2.4 0.0 0.0 0.0 0.0 ao M3 ems. 32.3 eens 0.0 ous 1787.8 635.3 107074.9 w2.s 3.8 73.3 0.0 1059.7 1m1s.4 We 116548.7 0.0 8 708.3 0.0 1004.7 1793.9 122476.9 22.0 a8 708.3 0.0 1054.7 10238. 7 1RNS6 0.0 8 1063.9 0.0 38 798.3 a0 1099.7 7.7 eon. 00 1%. we 63 8.3 708.3 00 8 00 102700 927.6 116081 2617 4912.3 9881.2 13897.4 1678.6 SuNCSS OCTOBER 29, 1984 MINING FORECAST YEAR > BEAK DEMAND (Mii) ) ENERGY SALES (Gwn) LOAD FACTOR LOSS FACTOR G9KV CAPACITY LOSS (Mw) 69KV ENERGY LOSS (Gwh) FEEDER CAPACITY LOSS (HW) FEEDER ENERGY LOSS (wh) JUNEAU CAPACITY LOSS (HW) JUNEAU ENERGY LOSS (Bw) { JUNEAU CAPACITY LOSS (x) (JUNEAU ENERGY LOSS (x) 1984 41.3 215.1 0.59 0.39 0.46 1.58 1.83 10.55 2.29 12.13 5.55 5.64 1985 3.1 230.6 0.48 0.27 0.82 1,93 2.55 12,84 3.37 14.77 6.12 6.40 LOCAL SYSTEM LOSSES 1966 1987 57.9 60.3 242.4 252.6 0.48 0.48 0.27 0.27 0.91 0.98 213 231 2.70 2.84 13,55 14.17 3.61 3.62 15.68 16.48 6.23 6.33 6.47 6.52 1988 62.6 262.4 0.48 0.27 1.06 2.49 2% 14.76 4.02 172.25 6.43 6.57 1989 1990 64.8 81.6 271.5 410.4 0.48 0.57 0.27 0.37 1.13 1.80 2.67 5.81 3.09 4,09 15.32 21.95 4.22 5.88 17.93 27.76 6.52 7.21 6.63 6.76 1991-1992 63.5 85.4 418.3 426.4 0.57 0.57 0.37 0.36 1.88 1.97 6.04 6.28 4.20 4.32 22.48 23.01 6.09 6.29 28.52 29.30 7.29 (7.37 6.62 6.67 1993 1994 67.4 89.4 434.7 443.2 0.57 0.57 0.36 0.36 2.06 2.16 6.53 6.60 445 4.58 23.57 24.14 6.51 6.73 BL W.4 7.45 7.53 6.93 6.98 1995 9.5 452 0.56 0.36 2.26 7.08 4.71 24.74 6.97 31.62 7.62 7.04 1996 460.7 0.56 0.36 2.37 7.36 4.85 25.34 7.21 32.69 wn 7410 1997 $5.7 469.6 0.56 0.35 2.47 7.65 4.98 25, 94 7.46 33.59 7.79 715 1998 97.9 478.4 0.56 0.35 2.59 2.95 5.13 26.56 2.72 H4.51 7.88 7.21 1999 2000 100.2 102.5 488.2 497.8 0.56 0.55 0.35 0.35 271 2.84 8.28 8.62 5.26 5.44 27.23 27.0 7.99 6.28 35.52 36.52 7.98 8.07 7.28 7.34 200: 104.9 507.7 0.55 0.34 2.97 8.97 5.60 28.60 6.57 7.57 8.17 7.40 Exhibit 12-A 107.3 5317.9 0.55 0.34 3.41 3.34 5.77 29.31 6.88 36.66 6.27 7.46 <003 2004 105.8 109.6 526.4 528.4 0.55 0.55 0.34 0.34 32 3.26 9.74 9.74 5.94 5.94 30.06 30,06 9.20 9.20 39.79 39.79 8.37 8.37 7.53 7.53 109.8 109.6 526.4 526.4 0.55 0.55 0.34 0.34 3.26 63.26 9.74 974 54 5.94 30.06 30,06 9.20 9.20 39.79 39.79 8.37 6.37 7.53 7.53 2007 2008 109.8 109.6 528.4 See.4 0.55 0.55 03 0.54 3.26 3.26 9.74 9.74 5.94 5.94 30.06 30.06 9.20 9.20 39.79 39.79 6.37 8.37 7.53 7.53 109.8 528.4 0.55 0.34 3.26 9.74 5.94 W.06 9.20 39.79 8.37 7.53 2010 109.8 Sea. 4 0.55 Ou 3.26 9.74 5.94 30, 06 9.20 33.79 6.37 7.53 Canaian OCTOBER 29, 1964 THERMAL MINING FORECAST YEAR RESOURCES AS OF 1964 ) Existing ano Committed Net Hyoro Resources Soutn of Taku Inlet thru Thane > Existing ano Committed Hydro Resources North of Taku Inlet ) Existing ana Committed Thermal Resources (All North of Taku) Total Existino anc Committec Net Resources South of Taku Inlet thru Thane Total Exasting and Committed Net Resources North of Taku Inlet EXISTING AND COMMITTED RESOURCES (After Transmssion Losses) DEMAND ( Peak Demand Reserve Reouirements (Equal to Peak Demand Less Hydro North of Taku) EXISTING RESERVE MARGIN (Excess or shortfall of reserve) NEW RESOURCE ADDITIONS hydro South of Taku Inlet (Capacity as measured at Thane) hyaro North of Taku Inlet Tnermal North of Taku Iniet TOTAL ANNUAL ADDED CAPACITY CUMULATIVE ADDED CAPACITY TOTALS AFTER ADDITIONS hyoro rortn of Taku Hycro south of Taxu Thermal (North of Taku) RESERVE REGUIREMENTS AFTER ADDITION RESERVE MARGIN AFTER ADDITIONS RESULTING TOTAL CAPACITY JUNEAG 20 YEAR PLAN Exhibit 12-B 1984 1985 1986 1987 1988 1989 199%) 1991 1992 1993 1994 1995 199% 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 45.93 45.93 45.93 45,93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 7.78 71,78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 5.62 6.62 6.62 6.62 6.62 8.62 8.62 6.62 8.62 8.62 6.62 6.62 6.62 662 8.62 8.62 8.62 8.62 8.62 6.62 8.62 8.62 8.62 6.62 8.62 6.62 8.62 58.72 71.22 71.22 69.97 69.97 68.77 68.77 65.27 65.27 64.14 59.14 59.14 56.00 58.00 58.00 55.50 53.00 53.00 53.00 53.00 53.00 35.50 35.50 35.50 12.50 12.50 0.00 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 7i.78 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 71.78 71.78 64.54 79.84 79,84 78.59 78.59 77.39 77.39 73.89 73.89 72.76 67.76 67.76 66.62 66.62 66.62 64.12 61.62 61.62 61.62 61.62 61.62 44.12 44.12 44.12 21.12 21.12 8.62 110.5 125.8 125.6 124.5 124.5 149.2 149.2 145.7 145.7 144.5 139.5 139.5 138.4 138.4 136.4 135.9 133.4 133.4 133.4 133.4 133.4 115.9 115.9 115.9 92.9 92.9 80.4 41.3 55.1 57.9 60.3 62.6 64.8 61.6 35.5 46.5 49.3 51.7 54.0 56.2 73.0 23.2 24.7 21.9 18.3 16.0 12.6 -4&2 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 00 5.0 0.0 0.0 06 00 0.0 00 5.0 0.0 0.0 00 00 00 0.0 5.0 5.62 8.62 6.62 6.62 8.62 862 6.62 63.5 85.4 87.4 69.4 91,5 93.6 95.7 97.9 100.2 102.5 104.9 107.3 109.6 109.8 109.8 109.6 109.6 109.6 109.8 109.8 74.9 76.8 78.8 60.8 82.9 85.0 87.1 89.3 91.6 93.9 96.3 98.7 101.2 101.2 101.2 101.2 101.2 101.2 101.2 101.2 79.6 ~11.5 -14.6 -21.6 -23.7 -27,0 -29.1 -31.3 -36.1 -40.9 -43.3 -45.7 -48.2 -48.2 -65.7 -65.7 -65.7 -86.7 -88.7 #eneet 0.0 00 00 0.0 00 00 00 00 0.0 0.6 00 0.0 00 0.0 00 00 00 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 0.0 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 5.0 5.0 00 50 50 50 00 0.0 5.0 100 00 00 5.0 0.0 150 0.0 0.0 25.0 0.0 10,0 5.0 5.0 00 50 50 50 0.0 G0 SO 100 06 G0 5.0 00 15.0 00 0.0 25.0 0.0 10.0 10.0 15.0 15.0 20,0 25.0 30,0 30.0 30.0 35,0 45.0 45.0 45.0 50,0 50.0 65.0 65.0 65.0 90.0 90.0 100.0 6.62 862 6.62 8.62 6.62 6.62 862 6.62 6.62 8.62 6.62 8.62 6.62 8.62 8.62 8.62 8.62 6.62 8.62 8.62 45.93 45.93 45.93 45.93 45.93 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.76 74.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71.78 71,78 71.78 71.78 71.78 58.72 71.22 71.22 69.97 69.97 68.77 73.77 75.27 60.27 79.14 79.14 84.14 86 a8 BB 905 = 98 BH 103- 103 100.5 100.5 100.5 102.5 102.5 100 35.48 46.48 49,28 51.68 53,98 56.18 72.98 74,68 76.78 78.78 80.78 82.88 84.96 87.08 83,28 91.58 93.68 96.28 98,68 101.2 101.2 101.2 101.2 101.2 101.2 101.2 101.2 232.2 24.7 21.9 163 16.0 12.6 0.6 220.5 125.8 125.8 164.5 124.5 149.2 542 155.7 160.7 O4 35 04 -6 3 20 09 -1.3 -10 4&1 17-07 1.8 18 -07 -0.7 07 13 13-12 159.5 159.5 164.5 168.4 168.4 168.4 170.9 178.4 178.4 178.4 183.4 183.4 160.9 180.9 180.9 182.9 182.9 180.4 OCT 29, 1984 TER MINING FORECAST ENERGY SALES FORECAST (Gun) 2st ) LOCAL LOSSES (1) 5.64 GROSS ENERGY REQUIREMENT (Gh) 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDAD ) NET GENERATION POTENTIAL (GMH) 205.6 (MET GENERATION ACTUAL (Gen) 205.6 (NEM HYDROELECTRIC PROJECT ‘YEAR ADDED CAPITAL COST (8000) ‘FINED OM COSTS (9000) UMPET ENERGY REQUIREMENTS (Gum) 21.6 NET GENERATION POTENTIAL (Gun) NET GENERATION ACTUAL (Gah) 0.0 PROJECT: ‘YEAR ADDED CAPITAL COST (9000) FINED 08m COSTS (9000) UPET EXERGY REQUIREMENTS (Ge) 21.6 NET GENERATION POTENTIAL (Gh) NET GENERATION ACTUAL (Gen) a0 (NEW TRANGHISSION PROJECT: YEAR ADDED CAPITA COST (#000) FIXED 08M COSTS ($000) (PET ENERGY REQUIREMENTS (Gem) 21.6 NET GENERATION POTENTIAL (Gen) NET GENERATION ACTUAL (Gun) 0.0 ENERGY LOSS (8) ENERGY PURCHASED (Gen) UNIT COST AT SOURCE (8/Eqn) PURCHASED ENERGY COST ($000) NEM PRIME THERMAL TYPES: Prime Diesel CAPACITY ADDED (Mma) (CUMULATIVE CAPACITY ADDED (mw) o 1985, 230.6 60 25.4 3.8 0.0 38 0.0 3.8 0.0 1986 242.4 647 258.1 205.6 25.6 2.5 0.0 32.5 0.0 0.0 1987 22.6 6.52 269.1 205.6 205.6 63.5 0.0 63.5 0.0 63.5 00 1986 262.4 67 279.7 205.6 205.6 AA 0.0 Tat 0.0 ml 0.0 1983 ans 6.63 269.5 08.2 283.5 0.0 0.0 00 0.0 0.0 0.0 1980 10.4 6.76 438.2 8.2 wae 130.0 0.0 0.0 1991 418.3 6.82 46.8 6.2 6.2 1387 0.0 14.7 00 138.7 0.0 1982 426.4 6.87 455.7 8.2 6.2 147.5 0.0 147.5 0.0 M25 0.0 44.7 6.93 64.8 6.2 08.2 0.0 0.0 1% 443.2 6.98 Tat 8.2 ee 0.0 0.0 166.0 0.0 1935 452.0 7.04 483.8 8.2 06.2 175.7 0.0 173.7 0.0 173.7 0.0 198 460.7 7.10 493.4 6.2 08.2 185.2 0.0 185.2 0.0 185.2 0.0 199 988.2 7.268 ‘323.7 6.2 6.2 215.6 0.0 215.6 0.0 215.6 Exhibit 12-C Sheet 1 of 3 7 1998 469.6 478.4 715 72h 3.2 ‘312.9 8.2 8.2 6.2 8.2 195.0 204.8 0.0 0.0 15.0 204.8 0.0 0.0 195.0 200.8 0.0 0.0 ct 15 00 2000 497.8 cy SHI 6.2 08.2 226.2 0.0 226.2 0.0 0.0 2001 907.7 1.0 WS. 0.0 0.0 0.0 Bo ‘37.9 1% wae 6.2 288.4 00 ae 0.0 oe 00 ‘528.4 Ss 82 8.2 wee 0.0 0.0 00 326.4 1.33 68.2 08.2 be 260.0 0.0 00 0.0 326.4 Ls 368.2 260.0 0.0 00 260.0 0.0 ‘384 1.33 8.2 8.2 wee 260.0 0.0 00 0.0 2007 64 LS 68.2 8.2 6.2 0.0 00 260.0 00 ‘eae LS 82 08.2 8.2 0.0 00 00 Bu 2003 sea4 LS 68.2 ‘6.2 wae 260.0 0.0 260.0 00 260.0 00 e010 ‘28.4 .S 8.2 6.2 8.2 260.0 0.0 0.0 260.0 0.0 Exhibit: 12-¢ Sheet 2 of 3 (HeLTAL COST (8000) ate ane sue 6 eB ° sue em FINED O4N COST (#000) ° WHET ENERGY REDUIREMENT (Gut) 16 OS LS ML 0019.0 1387 136.6 166.0 175.7 185.2 195.0 204.8 21S. TT.1 AMA 260.0 HLH. HO HOH HO. NET GENERATION POTENTIAL (Goh) O67 LORD FAC. = 0.00 Ce a ee nL Se SS 2 3] NET GENERATION ACTUAL (Gan) 00 8606.00.00 a ee ee SS SL SL BERGY LOSS (4) ° ENERGY GOERATED (Gut) 0.0 0.0.0.0 00000 ASSLT ST BO BOOB LIT A ATG LAMBA ATG A76 1 ATG ATE N77 205.4 205.4 260.0 FUEL USE (hat /UMIT) 15 INITIAL FUEL PRICE (W/UNIT) = 0.959 FUEL ESCALATION RATE (3/YERR) 1984-1988 ° 1989-2003 3 FUEL PRICE (#/UMIT) 0.959 0.99 0.959 0.959 0.990.988 1.017 1.088 wu S79 | FUEL COST (6000 o. 00° ©6000 0 00H A17S.O HNO. INLD TH6A.3 10388.3 16050.0 16831,5 17027.4 1739.2 ITSIL2 ITSBLZ ITSIRZ 1759.2 200613 2061.3 25900.8 VARIABLE OWN RATE (ENTS /iad = 0.8 ‘VARIABLE OWN COST (8000) Cr 4693.5 6S TOS 70,3703 SIL 10K. G IMO. IMO. 1H08.G HONG HRS HOG HOG NEHA GLA 2080.3 NEN STRNOBY THERA, WE: Diesel (REOCITY RODED so 3.0 0.0 0.0 3.0 2.0 0.0 CUPLATIVE CAPACITY AOUED (ms) 20 86600000 S010 1.01.0 10K KO ISO 130 180 1800 5.0 5.0 (OLA COST (4000) 61.1 0007 = 0.0000 00.0 2S AMES 000M 00 00.0 28.5 222.0 0.0 FINED Obm COST (4000) 35 (9000) ° ° ° ° o o ms B 3s 3B B BS WS Ws ss 25 2S eS » 12.5 1925 1925 EXISTING PRIME DIESEL » CRORCITY (ne 125 3 3 3 3 a 3 3 a a @ 20 2 2 125 S83 13 3 13 1s 3 nS ° UPET ERERGY REDUIFED (Gut) 2.6 BSS RS TAL OO 1390.0 LTA 12,3 107.3017. GTZ STO TS OOO CROACITY UTILTIZATION FACTOR 0.67 (POTENTIAL) NET GENERATION POTENTIAL (Bat) ThA 716767 67M TMT TTT TA LIT 17.4 102,708.0 0 © 007TH NET GENERATION ACTURL (Gut) a6 8 SS RSMO 13.0212. 167 982 SOL 73 0 0 OGG BERT LOSS (8) o ° ° ° o ° ° ° ° ° ° ° ° ° ° ° 0 ° ° ° o o ° ° ° ENERGY GENERATED (Gan) 2.6 8 SRSA 0 1.0L A S10 TR 67 2 OL 3 0 0 OG FUEL USE (ho /BAL) 135 INITIAL FUEL PRICE (9/884) 0.959 FUEL ESCALATION ARTE (X/YERR 1984-1988 ° 1989-2003, 3 FUEL PRICE (#/UMIT) 0.99 0.970.999 0.9590.99 0.988 1.017100 NEMS ATP LISA 281 ee ee ee eo! FUEL COST (8000) 226.1 FTG. A503 “SELLS 0.097973 107.3 AS.7 1OMLG 9100.6 102189 BINGE HITZ 1142.4 SESE OTR TM.2 91.7 9.7 HT GEHTS GOAL GOA. 0.0 VARIPRLE 04% COST (8000) 0.8 (COMTI) 173.2 HHS A200 507.9 SHS 0.0 1080.0 1108.3 HSS 10184 BSS TST TT. 78S. 4 400.7 AG 6.7 67.7 GT TT 67769 AI OO (ET ERGY REQUIRREXT (Gh) 0.0 860.000 ‘SPOOR OF NET GENERATION . EXISTING & COPWITTED HYDRO (1) 0.47 BLY 79.65 75.40 73.51 100.00 70,338.97 GT.62 6A. GREY ERG ELH Ca Se ee ee) NEW HADROELECTRIC. (1) 0.00 0.000.000.0000 0.00 0.000.000.0000 0.000.000.0000 0.00 © 0.09 0.000.000.0000 00.00.00. 00 NEW TREMISSION IMPORT (1) 0.00 0.00 «0.000.000.0000 0.00 0.000.080.0000 0.000.000. 00 0.00 0.00 0.00 0.00 0.000.000.0000 0.000.000.0000 NEW PRIME THEI) 0.00 0,00 0,00 0,.000.00 0.000.000.0044 S12 SB ISTH 7.30 2M RS WI 6 9 ISIS LG LISTING PRIME DIESEL (8) 953 16.21 20.98 23.60 6.49 0.00 ATS SM A7.3D RGF ANI 19.7 21TH 12.9948 A784 7B 4TH 1478. 8.6L (0.00 SORTFAL 0.00 0.00 0.000.000.0000 0.000.000.0000 0.00000 0.00 0.00 0.000.000.0000 0.00 0.00 0.000.000.0000 0.00 Exhibit 12-¢ Sheet 3 of 3 ‘SpeRY OF PLAN COSTS: CAPITAL COSTS (9000) 0.0 0.0 0.0 0.0 0.0 205.5 205.5 4116.0 0.0 4116.0 = 2305.5 4116.0 0.0 0.0 4116.0 6278.0 0.0 0.0 2305.5 0.0 6916.5 0.0 0.0 13338.0 0.0 FINED 08" COST (#000) 0.0 00 0.0 0.0 0.0 ns 5.0 3.0 m0 5.0 32.5 2.5 2.5 25 25 25 25 25 10.0 70.0 122.5 122.5 122.5 12.5 192.5 ‘VARIABLE 06" COST (9000) 173.2 nes 420.0 07.9 32.5 0.0 1000.0 = 1109.3 1180.3 1253.2 1327.9 1405.3 1481. 1560.3 1638.0 = 1728.5 1808.3 18%.9 1987.2 2080.3 2080.3 2080.3 2080.3 2080.3 2080.3 2080.3 SURCHRSED ENERGY (9000) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 00 00 0.0 0.0 0.0 0.0 ‘FUEL COST (#000) 1337. (2026.1 729.1 4510.3 SAG. 0.0 © $797.3 10763.3 1361.4 «12658. 7 1ESBL.1 14833.9 | 15876.7 17261.2 8706.7 2002.1 2123.0 22899.2 © 20798.6 = 265890.0 26890.0 26830.0 6880.0 26890.0 2650.2 6505.2 ‘TOTAL YEAALY COST (9000) 171.0 314.4 4149.0 SOI SBA 13160.3 142131 16892.7 13946.9 19060.0 18597.1 21527.1 18874,0 —20397.2 25955.1 29262.9 NONE. 7 OBA 3128S? 28980.2 «G2 29082.7 «29032.7 A2115.9 2877.9 AAS. DISCOUNTED YEAALY COST (#000) 171.0 OME MATZ SAK S101. 0.0 10705.9 1171.4 12828.5 10233.2 13812.0 12738.0 142862 2068.1 12601.0 158804 168761 MNS. LAMME 7 162734 14564. 178S5.9 13620.7 1360.1 18845.0 1217.3 140851 (BASE YEAR 18 DISCO RATE (8) a5 CUR. DISCOUNTED COST (8000) ATUL.O © 4749.1 8622.2 131884 18269,9 18249,9 28955.7 40127.1 S29SS.6 © GIIB8.8 —76700.8 = B9A38.8 109.1 LISTSS.2 128354.2 14384.6 160710.7 170556. 1890052 20527R.G 219803.1 237299.0 250919.7 26A079.8 282524.8 294702.1 308787.2 (UM. DISC. COST TO 2010 (#000) 308787 SUM MON-CAPLTAL COSTS IN 2010 28174 sw DISCOUNTED WON-CRPITAL COSTS — 230376 ‘EVO 2010 (8000) (EAPC COST AAD SALVAGE VALUE DETERWINATION (NEW UNITS) wat nerciTy YEAR ODED FEPLACOENT REPLACENENT FETIEEMT cerra DISCRERLL DISCRERLE 2045 SALVAGE DISC SAG om ERR a Vena 82 YeR (cast (9000) (9000) 9000) ‘VALUE (9000) «90001 Hrpno #1 0.0 0.0 HYDRO 42 0.0 0.0 ‘TREWEAISSION 0.0 0.0 PRIME THERMAL #1 3 1982 ane 2032 euse 116.0 1570.9 703.5 176.7 PRIME THERA 42 5 198 aoe 20m 204 4116.0 166.4 71.0 ane PRIME THER 03 3 1996 2016 20% 2056 116.0 1368.9 68.0 2m.6 STORY THERA. 5 199 209 2039 2089 4116.0 1234.7 4 ‘STANDBY THERMAL 42 10 2000 00 20K0 2060 6278.0 1819.6 7.5 STORY THERA 03, 5 2008 nes 0 2088 4116.0 m7 STANDBY THERA 04 10 2010 2030 0 2080 6278.0 192.5 STAMOBY THER 65, 3 1990 2010 20% 2080 2305.5 70.7 STRNOBY THERM 06 3 1991 eon e031 20st 205.5 we ‘STRMOBY THER 07 5 1955 201s 2035 2055 205.5 wa ‘STANOBY THER 08 3 2003 20e3 2083 2063 205.5 AS STANDBY THERMAL 09 3 2005 20e3 0 2045 6916.5 2.0 STORY THERA 810 ~ 2008 2028 ° oe 222.0 163.7 STOMOBY THERA €11 00 STORY THER 812 a0 STAMDRY TERNAL 413 0 ‘Sm (#0001 : 382.5 2601.5 NET DISCOUNTED REPLACEMENT COSTS AMD SALVAGE VALUES (8000) 19805 TOT DISCOUNTED SLAW COSTS (4000) 58568 econ OCT 13,1964 TYEE INTERTIE 1996, Low Tyee Cost ERGY SALES FORECAST (Gxh) » LOCAL LOSSES (1 (GROSS ENERGY REQUIREMENT (Bahn) (AT SUBSTATIONS) EXISTING & COMTTTED HYDRO ) NET GENERATION POTENTIAL (GMA) NET GENERATION ACTURL (Gi) NE HYDROELECTRIC PROJECT: ‘Yea ODED CRPITAL COST (9000) FIXED OAM COSTS (0001 ET ENERGY REQUIREMENTS. (Gut) NET GENERATION POTENTIAL (Ga) NET GENERATION ACTUAL (Gat) PROJECTS ‘YEAR ADDED (CAPITAL COST (#000 FIXED OWN COSTS (4000) UWPET ENERGY REDUIREMENTS (Gut) NET GENERATION POTENTIAL (Gud) NET GENERATION ACTUAL (Gut) NEM TRNEKISSION PROJECT: TYEE INTERTIE YEAR ODED 1996 CAPITAL COST (#000) FIXED OWM COSTS (9000) UNPET ENERGY REQUIREMENTS (Gut) NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gah) ENERGY LOSS (x we ENERGY PURCHASED (Gut) UNIT COST AT SOURCE (8/6) e200 PURCHASED ENERGY COST (8000) NEM PRIME THEW, TYPE: rame Diesel CRORCITY ADDED vw) CUMULATIVE CARCITY ADDED (Md) 1984 215.1 S64 ene 205.6 208.6 0.0 21.6 0.0 0.0 0.0 230.6 6.40 as. 205.6 0.0 Be 0.0 Bb 0.0 0.0 0.0 242.4 6.47 8.1 205.6 25 0.0 5 0.0 0.0 0.0 1987 22.6 6.52 23.1 205.6 635 0.0 65 0.0 65 0.0 0.0 “a0 2.4 6.57 23.7 205.6 mt 0.0 mt 0.0 m1 0.0 0.0 amn.5 6.63 283.5 08.2 209.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1990 273.0 6.67 27.6 0.0 0.0 0.0 0.0 a0 0.0 0.0 0.0 6.71 306.2 308.2 306.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1982 235.0 6.76 349 308.2 308.2 68 0.0 68 0.0 68 0.0 0.0 0.0 1993 3.3 6.80 BL 308.2 306.2 15.8 13.8 a0 138 0.0 0.0 1994 we 6.85 whe 308.2 308.2 25.0 0.0 2.0 0.0 30700 0.0 0.0 0.0 6.90 we 08.2 wo 00 We 0.0 15900 Ww 0.0 0.0 0.0 1956 wad 6.55 B22 308.2 8.2 0 0.0 4.0 0.0 0 6.6 40 4.9 1233.5 Exhibit 13-A Sheet 1 of 3 1997 8.2 7.00 BLS 308.2 08.2 337 su 0.0 33.7 6.6 53.7 38.7 1508.8 1998 47.0 7.05 v5 308.2 08.2 6.3 0.0 63.3 0.0 63.3 6.6 63.3 70.4 173.8 193 36.8 7.10 B21 308.2 8.2 m0 a0 m0 0.0 m0 66 m0 2073.1 2000 64 1S 32.6 308.2 308.2 aS 0.0 0.0 aS 6.6 ws 93.9 266.7 oor 202 363 6S net 127 10.4 4148.6 8.2 yee 308.2 M82 BS 1064 00 © 0.0 BS 106.4 Ct) we tee H.3 106.4 66 6 6.6 66 %.3 HI 2626.7 2426.7 ° o 37.0 i 426.1 17.9 0.0 117.9 0.0 17.9 66 63 2026.7 7.0 LR 425.1 17.9 0.0 ung 0.0 9 6.6 66 6.3 2426.7 ung 0.0 47.9 0.0 17.9 6.6 6 6.3 2426.7 31.0 LR 426.1 08.2 8.2 7.9 0.0 ung 0.0 n729 6.6 66 63 2426.7 397.0 Le 426.1 8.2 wee ung 0.0 47.9 0.0 ung 6.6 66 6.3 2026.7 337.0 1 426.1 08.2 308.2 117.9 ao 47.9 0.0 ung 6.6 6.6 6.3 2026.7 357.0 1 1 308.2 308.2 47.9 00 172.9 0.0 17.9 6.6 6.6 206.7 a0 37.0 1 426.1 08.2 308.2 17.9 0.0 0.0 47.9 6.6 6.5 6.3 2426.7 CRPITAL DUST (90001 FIXED Ow COST (6000) WWRET EXERGY REDUIRERENT (Gan) NET GENERATION POTENTIAL (Gah NET GENERATION ATUL (a) BERSY LOSS (5) ENERGY GENERATED (Gadd FUEL USE (lab /UNITD INITIAL FUEL RICE (8/UMIT) FLEL ESCALATION ARTE (3/¥ERR) 1984-1988 1589-2003, FEL RICE (8/UMITY FUEL COST (#000) VORTROLE 01M RATE (CENTS /iatd VRATROLE CAN COST (#900) Nou STROBY TERA, Te: Diesel CAPCITY ADDED UMA) CURULATIVE CAMCITY AOOED OM) CAPITAL COST ($000) FINED Gkx COST (80001 EXISTING PRIME DIESEL. » caeeciTY om UPET BEREY REDUIRED (Gah) CAPACITY TILTHZATION FACTOR (POTENTIAL NET GENERATION POTENTIAL (Gah) NET BENERATION PCTURL. (Gut ENERGY LOSS 18) BERG GERATED (Gah) FUEL USE than /6AL) INITIAL FUEL PRIDE (8/6RL) FUEL ESCALATION ARTE (3/YERR) 1904-1968 1989-2003, FUEL PAICE (SANITY FEL COST 140002 \WRALRELE OWN COST (40001 UWWET DEREY REDUIROENT (fat) SUPPORY OF NET GENERATION EXISTING & COMMITTED HYDRO (8) NEW WYDADELECTRIC. (8) Nw TRARUISSION INOORT (8) Neu PRUE THERMAL (81 EXISTING PRLPE DIESEL (#1 SHORTFALL (9 0.67 LORO FAC. O8 461.1 (900070 25 (so00/m 0.67 13 0.559 (DT na 21.6 0.0 a0 0.0 0.999 0.0 0.0 0.0 0.0 123 21.6 m4 24.6 21.6 on 187.8 m2 a0 9.47 0.00 0.00 0.00 9.53 0.00 Bo 0.0 0.0 0.0 0.99 00 0.0 46.7 38 3.8 0,959 2826.1 Hed 0.0 8.79 0,00 0.00 0.00 i621 0.00 25 0.0 0.0 0.0 0.959 0.0 0.0 0 0.0 146.7 325 32.5 0.939 3.1 420.0 0.0 79.65 0.00 0.00 20.34 0.00 65 0.0 0.0 0.0 0.989 a0 0.0 0.0 0.0 48,7. 65 65 0.958 4810.3 01.9 a0 76.40 0.00 0.00 0.00 23.60 0.00 ma 0.0 0.0 0.0 0.958 0.0 0.0 0.0 0.0 Ta 46.7 ma ml 0.958 SOLS se O90 72.51 0.00 0.00 0.00 26.49 0.00 0.0 0.0 0.0 0.0 0.988 0.0 0.0 0.0 0.0 46.7 0.0 0.0 0.988 0.0 0.0 0.0 100.00 0.00 0.00 0.00 0,00 0,00 00 0.0 0* 0.0 00 = 00 0.0 0.0 1.017 0.0 00 00 00 0.0 0.0 0.0 ° 0 a 3 0.0 0.0 146.7 146.7 0.0 9.0 ° Q a) 1.017 1.088 0 © 0.0 0.0 0.0 0.0 0.0 100.00 100,00 0.00 0,00 0.00 0.00 0.00 © 0.00 0.00 0,00 0.00 0.00 6.8 0.0 0.0 0.0 1.073 0.0 0.0 0.0 16,7 68 ce) 1.079 ALS 2 0 97.85 0.00 0.00 0.00 2.15 9.00 15.8 0.0 0.0 Luz, 0.0 0.0 15.8 446.7 18 138 1ue 1293.3 125.2 0.0 1d 0.00 0.00 0,00 4.87 0.00 25.0 0.0 0 0.0 115 0.0 0.0 3.0 3.0 2305.5, 125 1.145, 2120.3 200.0 0.0 92.50 0.00 0.00 0.00 1.50 0.00 WG 0.0 0.0 0.0 1.179 0.0 0.0 5.0 10.0 208.5 5s A We we 1179 worst 26.5 0.0 09.92 0.00 0.00 0.00 10.08 0.00 Exhibit 13-0 Sheet 2 of 3 0.0 © 0.0 0.0 0.0 0.9 0.0 0.0 cs) Cr ) Lats 16251 1.289 00 8-00 0.0 2.0 © 00 0.0 30 50 130 180 -20,0 205.5 0.0 MB. 25 BS 10 2 2 2 00 ) 24 t 00 00 0.0 0 0 0 0.0 0.0 0.0 215 SLL 0.0 00 0.0 00 0.0 0.0 0.0 0.0 87.390 6516 82.96 0.00 © 0,00 0,00 12.50 18h 17.08 0.00 © 0.00 0,00 0.00 © 0,00 0,00 0,00 0.00 0,00 0.0 0.0 0.0 0.0 137 0.0 0.0 20.0 0.0 0 ms 0.0 102.7 0.0 0.0 LEr 0.0 0.0 0.0 60.64 0,00 19.36 0.00 0.00 0.00 0.0 0.0 0.0 0.0 1367 0.0 a0 3.0 a0 2305.5, os 5 0.0 28.0 0.0 1.7 0.0 0.0 0 78.49 0.00 ais 0.00 0.00 0,00 a7 0.0 0.0 0.0 1.408 0.0 a0 30 w.0 205.5 105 1s ar 8.0 a7 a7 1.408 5.2 69.4 0.0 6.38 0.00 aa7 0.00 2.15 0.00 19.8 0.0 0.0 0.0 1451 0.0 0.0 0 0.0 105 13 18 88.0 90 13.8 14st ame 156 0.0 md 0.00 20.89 0.00 478 0.00 wa 0.0 0.0 0.0 1.494 0.0 13 33 8.0 ua 1.494 46.0 250.5 0.0 Ra 0,00 20,33 0.00 13 0.00 ua 0.0 0.0 0.0 14 0.0 0.0 0.0 Bo 1225 3 na 68.0 M3 ua 148 WO 250.5 0.0 Te.32 0.00 20.33 0.00 LS 0.00 33 0.0 0.0 0.0 144 0.0 a0 10 0.0 6916.5, 175 15 M3 88.0 ue m3 1a W660 205 0.0 RR 0.00 20.8 0.00 13S 0.00 ua 0.0 0.0 00 1494 0.9 0.0 0.0 0.0 13 15 m3 28.0 U3 1498 W6.0 20.5 0.0 RB 0,00 20.33 0,00 1.35 0.00 ua 0.0 0.0 0.0 1496 0.0 0.0 0.0 0.0 15 15 m3 68.0 wa ua 1.490 We0 e0.8 0.0 Re 0,00 20,33 9.00 2S 0.00 ua 0.0 0 1a 0.0 0.0 Bo 730 11827.5 a5 25 ua Th wa 148 W6E0 20.5 0.0 Re 0.00 20,33 0.00 138 0.00 43 0.0 0.0 0.0 1454 0.0 0.0 0.0 m0 a0 aes 125 3 ma ud ua 1.494 66.0 20.5 Re 0.00 20.33 0.00 7.35 0.00 aus na 2.3 2.3 23.3 1.44 2a185 10.0 65.0 4511.0 225 0.0 0.0 0.0 1498 0.0 0.0 2.0 RB 0.00 20.33 688 0.00 O47 CAPITAL COSTS (9000) FIXED 04M COST (9000) VARIABLE 04M COST (9000 PURCHASED ENERGY (8000) FUEL O06T (9000) TOTAL YEARLY COST (#000) DISCOUNTED YEAALY COST (#000) RSE YEAR DISCOUNT RATE (1) CUR, DISCOUNTED COST (4000) CM. DISC. COST TO 2010 (#000) ‘SM NON-CAPITAL COSTS 1m 2010 (9000 VALUE IN 2010 OF NOM-CAPITAL, (COSTS THRU 2045 (8000) DISCOUTED MON-CAPITAL COSTS BEYOND 2010 (4000) REPLACERENT COST AMO SALVAGE VALUE DETERVINATION (NEW UNITS) wat HYDAD #1 vRa 42 TREWSAISSION PRIME THERA OL PRIME THERWAL 42 PRIME THER. 03 STANDBY THERM. 81 STRNORY THERA 42 STANDBY THERE. 63 STANDBY THERA 14 STEROBY THERMAL €5 STANOBY THERNA 06 STORY THERM 47 STANDBY THERWA 08 STANDBY THERWA 9 STANOBY THERA #10 STANDBY THERM 811 STORY THER #12 STANOBY THERMAL 413 um (9000) 1900 35 wm crenciTy ~ SRGususues 0.0 0.0 wae 0.0 1337.8 im11.0 m1.0 m1.0 NET DISCOUNTED REPLACEMENT COSTS AMD SALVAGE VALUES (8000) TOT DISCOUNTED PLAN COSTS (4000) a0 0.0 38.3 0.0 2826.1 st 3038.1 m8. 194 1995 1996 1998 2001 ano 0.0 0.0 420.0 0.0 e3.4 3.0 waTh2 622.2 20es7 203738 00 0.0 07.9 0.0 4510.3 3018.2 4526.1 13s REPLACEENT vom 00 © 0.0 0.0 0.0 32.5 (0.0 00 © 0.0 L500 B58. a0 5101.5 0.0 1249.9 1829.9 REPLACENENT vena 42 ° ° o 0 C) Ey 2035 2036 2038 20N0 2041 2083 ° o 0 00° 0.0 0.0 0.0 0.0 0 0.0 18249.9 0.0 0.0 0.0 a0 0.0 0.0 0.0 18249.9 ‘i SEZRRERRReccdk 0.0 0.0 M2 0.0 16 220.0 0.0 1.2 0.0 1298.3 645.5 07.2 crerTAL (cast (9000) 54820.0 4116.0 2305.5, 2005.5, 2305.5 2305.5, 2305.5 2305.5, 205.5 6316.5 41827.5 4611.0 3005.5, 113. 200.0 0.0 2120.3 BULI 18205. 35.0 26.3 0.0 19.1 21536.0 14751.0 DISCRERLL (9000) 0.0 0.0 12925.4 ws 0.0 0.0 we Le 766.8 113.8 668.2 645.6 02.7 1687. 2537.2 wr 0.0 0.0 0.0 23957.7 205.5 ams 0.0 1233.5 0.0 wns 2520.8 Exhibit 13-0 Sheet 3 of 3 235.3, 0.0 a5 92.0 882.0 0.0 0.0 0.0 1904.8 1773.8 2078.1 0.0 00 00 2398.3 4971.3 265.1 1521.3 WOM.2 1769.8 |SCREALN2 (90000 0.0 0.0 0.0 0.0 0.0 0.0 ane. wee 35.4 B37 35.8 AS we. 0.0 0.0 0.0 0.0 0.0 0.0 2519.9 2045 SALVAGE VALUE (#000) 0.0 1023.0 0.0 0.0 1037.5, 138 1268.0 1496.6 1723.1 1644.4 2078.0 0.0 1729.1 1182.8 0.0 0.0 0.0 2305.5 03.5 0.0 2366.7 0.0 ‘81.7 B13.0 205.5 27.0 69.4 2426.7 905.2 63.8 5%.4 1784.6 SC SANG (9000) 0.0 15.2 0.0 0.0 127.2 114 158.5 163.8 212.4 228.2 oS, 0.0 212.4 ML 0.0 0.0 0.0 1780.3 0.0 27.0 138.6 2426.7 2130.2 ees 3037.7 nee.3 2305.5 4.5, 250.5 2426.7 3466.0 9383.3 4886.0 0.0 mS 20.5 2426.7 3466.0 B62. su270.3 6916.5 0.0 7.0 $97.0 250.5 250.5 2426.7 2426.7 66.0 466.0 1056.8 7140.3 6825.6 38.9 100095.9 103445. 7 0.0 91.0 250.5, 2426.7 36.0 7140.3 RK 1327.5 0.0 1084.5 1084.5, 250.5 250.5 2626.7 2426.7 W660 466.0 18755.3 7227.8 e2is.0 3058.4 114896.3117954.7 8727.0 113.5 24 2426.7 218.5 154261 6306.8 1282615, ECOWAL OCT 22,1984 BASE CASE THERMAL (ero Fuel Escalation) YEAR 1984 ENERGY SALES FORECAST (Gah) 215.1 ) LOCAL LOSSES (4) ‘5.64 GROSS ENERGY REQUIREMENT (Gah) 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDAD ) NET GENERATION POTENTIAL (6iH) 205.6 NET GENERATION ACTUAL (58h) 205.6 NEM HYDROELECTRIC PROJECT: ‘YEAR ADDED CAPITAL COST (9000) FIXED OAM COSTS ($000) UNMET EMERGY REQUIREMENTS (60h) 21.6 NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gen) 0.0 PROJECTS ‘YEAR ADDED CAPITAL COST (#000) FIXED O8M COSTS ($0001 UNMET ENERGY REQUIREMENTS (Gun) 21.6 NET GENERATION POTENTIAL (Ban) NET GENERATION ACTUAL (Gah) 0.0 NEW TRANSMISSION PROJECT: YEAR ADDED CAPITAL COST ($000) FIXED OFM COSTS (6000) UWFET ENERGY REQUIREMENTS (Gah) 21.6 NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Ban) 0.0 ENERGY LOSS (x) ENERGY PURCHASED (Buh) UNIT COST AT SOURCE (6/fadh) PURCHRSED ENERGY COST (8000) NEW PRIME THERMAL TYPES Prime Diesel CAPACITY ADDED (rei) CUMULATIVE CAPACITY ADDED (mi) o 1985 230.6 6.40 245.4 205.6 205.6 0.0 3.8 0.0 33.8 0.0 1985 242.4 6.47 256.1 205.6 205.6 25 0.0 32.5 0.0 0.0 1987 252.6 6.52 269.1 63.5 0.0 63.5 0.0 635 0.0 e624 6.57 273.7 Thal 0.0 Tal 0.0 mal 1989 271.5 6.63 209.5 0.0 0.0 0.0 0.0 0.0 0.0 1990 279.0 6.67 297.6 0.0 0.0 0.0 0.0 0.0 0.0 1991 286.9 6.71 6.2 308.2 36.2 0.0 0.0 0.0 0.0 0.0 0.0 1992 295.0 6.76 uaAg 0.0 0.0 6.8 15.8 0.0 15.8 0.0 15.8 0.0 1994 8 6.85 Be 308.2 082 25.0 0.0 0.0 G.0 0.0 - 00 0.0 0.0 19% 29.3 6.55 B22 44.0 0.0 0 0.0 Exhibit 14-A Sheet 1 of 3 1997 1998 1999 38.2 N70 356.8 7.00 2.05 7410 B19 5 B21 6.2 308.2 308.2 308.2 308.2 WB.2 53.7 63.3 4.0 0.0 0.0 0.0 52.7 63.3 Th.0 0.0 0.0 0.0 32.7 63.3 74.0 0.0 0.0 0.0 0 0 0 2000 4 WAS 32.6 308.2 8.2 aS 0.0 5 0.0 0.0 2001 2002 2003 2004 376.3 346.5 12k 127 4034 414.6 08.2 = 308.2 308.2 = 08.2 6.3 106.4 0.0 0.0 35.3 106.4 0.0 0.0 95.3 106.4 0.0 0.0 i 5 3 397.0 LR 426.1 308.2 082 79 0.0 29 0.0 79 0.0 397.0 1 426.1 308.2 Be 7.9 0.0 79 + 0.0 117.9 0.0 17.9 0.0 47.9 0.0 12.9 0.0 397.0 7.32 426.1 7.9 17.9 0.0 2g 0.0 2007 397.0 17.9 0.0 47.9 0.0 M29 0.0 7.9 0.0 ung 0.0 172.9 0.0 Ww 2009 397.0 ed 426.1 17.9 0.0 179 117.9 0.0 2010 337.0 LR 426.1 308.2 Wa. 79 0.0 47.9 0.0 M79 0.0 CAPITAL COST (#000) FIXED 04m COST (6000) RET ENERGY REQULRENENT. (Gxt) NET GENERATION POTENTIAL (Gxt) NET GENERATION ACTURL (Gut) DERGY LOSS (x ENERGY GENERATED (Gan) FUEL USE Cha /UNIT) IITA, FUEL PRICE (/UNIT) FUEL ESCALATION RATE (5/YERR) 1984-1988 1989-2003 FUEL PRICE (#/UNIT) FUEL COST (000) VARIABLE OWN RATE (CENTS /lah) VARIABLE 04M COST (9000) TWPE: Diesel CAPRCITY ROOED OM) CUMULATIVE CAPACITY ROOED OM (CHITA COST (#0000 FIRED OWN COST (9000) > CRERCITY Om WET EXERGY REQUIRED (Gut) CAPACITY UTILTLZATION FACTOR (POTENTIAL) NET GENERATION POTENTIAL (Gat) NET GENERATION ACTURL (Gxt) EXERGY OBS (8 (ENERGY GENERATED (Gut) FUEL USE (aan /6A) INITIR FUEL PRICE (4/68) FUEL ESCALATION RATE. (3/YERR) 1984-1988 1989-2003, FUEL PRICE (8/UNIT) ‘FUL COST (9000) ‘VARIABLE 4M COST (4000) WET DERGY REDUIROEXT (Gat) ‘SUPMORTY OF MET GENERATION LISTING & COMUITTED HYDRO (x) NEW FYDROELECTAIC (8) Ne TRENGAISSION IMPORT (3) NE PRIME THERA (5) LISTING O8iME DIESEL (8) SHORTFALL 21.6 0 0.0 08 0 0.0 a0 125 21.6 0.67 ma 2.6 2.6 15 os 90.47 0.00 0.00 0.00 9.53 0.00 Bb 0.0 0.0 0.0 os a0 0.0 ao 00 a0 79 0.00 0.00 0.00 6.21 0.00 25 0.0 0.0 a0 0.959 0 0.0 ao 0.0 146.7 25 25 0.999 Tea. 420.0 a0 13.66 0.00 0.00 0.00 20.38 0.00 ous 00 00 0.0 0.959 0.0 00 a0 a0 146.7 635 as 0.959 4510.3 07.9 a0 76.40 0.00 0.00 0.00 23.60 0.00 0.0 0.989 a0 0.0 ao 00 146.7 md ma 0.999 61.5 92.5 0.0 131 0.00 0.00 0.00 26.49 0.00 0.0 0.0 0.0 a0 0.99 ao 0.0 00 0.0 146.7 0.0 0.0 0.999 a0 0.0 0.0 100.00 0.00 6.00 0.00 0.00 0.00 0.0 00° a0 0.0 0.959 a0 0.0 0.959 a0 0.0 0.0 100,00 0.00 0.00 0.00 0.00 0.00 0.0 0.0 0.0 0.0 0.959 0.0 0.0 a0 0 146.7 0.0 0 0.99 0.0 0 0.0 100.00 0.00 0.00 0.00 0.00 0.00 66 0.0 00 0.0 0.999 0.0 a0 0.959 a2 we a0 97.85 0,00 0,00 0,00 215 0.00 0.99 a0 00 0.0 0.0 s8 17 158 36 0.959 1120.8 126.2 a0 95.13 0.00 0.00 0.00 “er 0.00 3.0 0.0 0.0 0.0 0.959 00 0.0 30 30 2005.5, 3 Ta) a0 0.959 1.73.7 200.0 2.50 0.00 0.00 0.00 1.30 0.00 we a0 0.0 ao 0.958 0.0 a0 30 10.0 265.5 une wo we 0.959 2458.8 26.5 0.0 09.92 0.00 0.00 0.00 10.08 0.00 Exhibit 14-0 Sheet 2 of 3 4000 SLT 683 HO 0.0 0 0.0 0.0 0.0 0 00 00 00 860.000 0.959 0.9589 0.959 0.959 00 800 0 00 = 00 a0 30 30 10.0 1300 130 0.0 205.5 = 00 28.5 B BS BS » 2 2 2 ns “0 0 67 HO He ANT, 102.7 4000 SRT 63 TO o ° o ° “00067 HO 0.99 0.989 0.990.959 H27.0 MINT 97 SRE B22 6 84 HL a ) a) 05.16 82.96 80.64 0.00 © 0.00 0.00 0.00 © 0.00 0.00 0.00 © 0.00 0.00 12.50 146.86 17.08 19.36 0.00 0.00 0.00 0.00 ws 0.0 0 0.0 0.999 0.0 0.0 30 zo 205.5 os 8.0 aS 0.959 97.5 3.7 a0 16 8.3 a3 23 a3 0.959 1876.2 ao 0.0 os 0.999 603.5 zr.4 0 1.38 0.00 0.00 nar 16.4 0.00 106.4 2.3 as ao 0 os 0.959 wTS.4 616.6 0.0 Wd 0.00 0.00 7.06 1059 0.00 ung un 33 (28.3 23 a8 a3 a3 0.998 1876.2 8 30 00 m0 MO 205.5 0.0 105 105 3 15 5 mG 8.0 88.0 68.0 BO ° 0 m0 = a0 0.99 (0.999 6EA.0 620.0 70.3 704.3 os OS 2 eR 0.00 0.00 0.00 0.00 609 6.89 2.66 2.66 O13 Ons ung 3.3 as 0.999 1876.2 15.0 40 6516.5 137.5, 0.959 st.0 704.3 os TR 0.00 0.00 6.89 20.66 ry 47.9 23.3 a3 a3 0.989 1676.2 0.0 0 197.5 099 0.0 104.3, as RR 0.00 0.00 6.89 2.6 O13 ung a3 233 a3 0.959 1676.2 ae 0.0 45.0 0.0 197.5 1s 6 68.0 8.0 a0 0.999 6254.0 704.3 os aR 0.00 0.00 6.89 2.66 ar) au6 ung a7 87 0.959 wIS4 2.0 65.0 22.0 ens 1.5 3.2 ma a2 saz 0.959 4207.2 ame 0.0 Rw 0.00 0.00 8 15.90 0.00 ung 38.7 38.7 a7 0.999 TTS2.4 63.5, a0 6.0 0.0 ans 5 sae ne s.2 0.958 eon. whe a0 72.32 0.00 0.00 13.78 1.90 0.00 ung un uns une 0.959 7504.8 939.1 30 70.0 265.5 0.0 0.0 a0 0.959 0.0 0.0 72.32 27.35 0.00 O13 SUMPAY OF LEW COSTS: CAPITAL CnSTS 19000) FILED BN COST (60001 VARIABLE Gm COST ($000) PURD-AGED ENERGY (4000) FUEL CST (8000) TOTAL YEARLY COST (6000) DISCOUNTED YEARLY COST (W000) BASE YEAR 1904 DISCOUNT RATE (8) a5 CUM, DISCOUNTED COET 110001 CUM, DISC, COST TO 2010 (9000) 108483 SUM NOW-CAPITAL COSTS 1K 2010 6689 «40001 WRWLE 1M 2010 OF MON-CAPITAL, 173782. (COSTS THR 2085 (4000) DISCOUNTED HON-CAPITAL COSTS §— 71049) BEYONO 2010 (4000) SEPLACEREXT COST PAD SALVAGE VALUE DETERRINATION {NEW UNITS) var camciTy m Heo HrDRO #2 ‘TRSWSAISSION PRIME THERA 1 PRIME THERM. @2 PAINE THERMAL, 03 STAMDRY THERNA. HL STONDGY THERM 42 STRMORY THERMAL 83 STANDBY THER 4 STANDBY THERM. @5, STANDBY THERA, 06 STOWUSY THERA. 07 STANDBY THERMAL 0B STAWORY THERMAL, 69 STANDBY THERA, 10 STAMDBY THERMAL 1D STANDBY THERM 12 ‘STHADEY THERA 013 oa ‘SUN (8000) 0.0 0.0 173.2 0.0 1597.8 s1.0 1.0 m0 NET DISCOUNTED REPLACENENT COSTS AND SALVAGE VALUES (4060) TOTAL DISCOUNTED LEN COSTS 19000) 0.0 0.0 318.3, 0.0 2026.1 aA 3038.1 ama YEAR ADDED 2001 2010 1998 1995 1957 199 2003 2008 aw 0.0 0.0 420.0 0.0 me. 4143.0 wre 622.2 12593 teaien 0.0 0.0 07.9 0.0 4510.3 01.2 4526.1 131484 REPLACEMENT YERR #1 2021 eoee 2030 2014 2015, 2017 2019 e0eo 2023 aes 2030 0.0 0.0 0.0 0.0 592.5, 0.0 0.0 0.0 5261.5 0.0 S641 0.0 5101.5 0.0 18209,9 1824.9 REPLACEMENT YEAR #2 20 2034 2037 039 20a Beoo 0.0 * 0.0 0.0 0.0 0.0 0.0 0.0 18249,9 RETIREMENT 0.0 0.0 0.0 0.0 0 0.0 0.0 10249,9 e061 2008 205s 20s? 205 2008 0.0 0.0 She 0.0 481.2 sm.4 406.6 10655.4 0.0 0.0 125.2 0.0 1120.8 147.0 99 1571.4 cart. (CasT «80001 4116.0 4116.0 6278.0 2W5.5 2305.5 265.5 2405.5, 2005.5 205.5 5916.5 922.0 2805.5, 2405.5, 35.0 2165 0.0 2054.8 5071.7 wg 260927 DISCREPLAL (80001 0.0 0.0 0.0 1152.6 6.9 1289.9 82.4 733.6 140.9 691.6 668.2 602.7 168. 2029. 413.7 0.0 0.0 0.0 0.0 1488.2 Exhibit 14-0 Sheet 3 of 3 0.0 38.0 382.2 0.0 3127.0 si 2325.6 20418.3 205.5 S25 423.6, 0.0 SAAT 6602.3 4221.5 3263.6 DISCRED.#2 «90001 0.0 0 0.0 m9. 0.0 0.0 128 Bae w2.3 Wb 335.8 2.9 0.0 0.0 0.0 0.0 9.0 0.0 0.0 209.5 6.0 25 16.4 0.0 4996.7 5055.6 8222.6 223.3 49080 35763,140671.0 2008.5 67.5 615.7 0.0 5999.5 068.2 9229.7 43900.7 2045 SALVAGE VALUE (#000) 3252.8 678 1569.5, 1037.5 182.8 1383.3 1613.9 1729.4 2075.0 0.0 1383.3, 576.4 0.0 0.0 0.0 0.0 4116.0 82.5 162.2 0.0 6559.7 11825.4 6422.0 2322.7 DISC SALVE 18000) 403.8 15.7 192.5 wee MLA 169.7 197.9 ait 25 0.0 169.7 10.7 0.0 0.0 0.0 0.0 2015.4 402.3 6716.0 205.5 105.0 933.4 0.0 2130.1 4479.7 571.2 6275.3 0.0 105.0 978.4 0.0 0130.1 9174.2 4610.6 67367.9 6916.5 15.5 933.1 0.0 130.1 16142 7838.7 75206.6 0.0 137.5 939.1 0.0 8130.1 9226.7 4x87 79535.3 0.0 197.5 9393.1 0.0 8130.1 9226.7 162.3 8317.7 1338.0 220.5 Wa 0.0 7959.6 268.4 40,2 93857.9 0.0 8883.5 227.5 245.0 W323 91 0.0 0.0 7959.6 7504.8 9130.4 172723 3863.5 7061.6 7421.4 1082.9 CONAN OCT 22, 1984 DOROTHY = 1996 (w/Seoerate T-Line) (1ero Fuel Escalation) YEAR 1984 ENERGY SALES FORECAST (Gen) 215.1 ) LOCAL LOSSES (x) 5.4 GROSS ENERGY REQUIREMENT (Gem) 227.2 (AT SUBSTATIONS) EXISTING & COMMITTED HYDAD > NET GENERATION POTENTIAL (GMM) 205.6 NET GENERATION ACTUAL (Gin) 205.6 NEW HYDROELECTRIC PROJECT: DOROTHY ‘YEAR ADDED 1996 CAPITAL COST (9000) FIXED 08" COSTS (#000) UNMET ENERGY REQUIREMENTS (Buh) 21.6 NET GENERATION POTENTIAL (Gah) NET GENERATION ACTUAL (Gun) 0.0 PROJECTS ‘YEAR ADDED CAPITAL COST (9000) FIXED O&M COSTS ($000) UNMET ENERGY REQUIREMENTS (Gh) 21.6 NET GENERATION POTENTIAL (Gwh) NET GENERATION ACTUAL (Gwh) 0.0 NEW TRANSMISSION PROJECT ‘YEAR ADDED CAPITAL COST (9000) FIXED 08" COSTS (#000) UMPET ENERGY REQUIREMENTS (uh) 21.6 NET GENERATION POTENTIAL (wh) NET GENERATION ACTUAL (Gun) 0.0 ENERGY LOSS (1%) ENERGY PURCHASED (Gah) UNIT COST AT SOURCE (/60h) PURCHASED ENERGY COST ($000) NEW PRIME THERMAL TPES Prime Diesel CAPACITY ADDED (mw) CUMULATIVE CAPACITY ADDED (i) 0 1985 230.6 6 245.4 205.6 205.6 38 0.0 38 0.0 3.8 0.0 1986 242.4 6.47 28.1 205.6 205.6 52.5 0.0 0.0 5 0.0 1967 252.6 6.52 269.1 205.6 205.6 63.5 0.0 63.5 0.0 63.5 0.0 1988 262.4 6.57 279.7 205.6 205.6 Al 0.0 mA 0.0 Ted 1989 27.5, 6.63 209.5 08.2 283.5 0.0 0.0 0.0 0.0 0.0 1990 273.0 6.67 297.6 08.2 297.6 0.0 0.0 0.0 0.0 0.0 0.0 1991 286.9 6.71 6.2 8.2 06.2 0.0 0.0 0.0 0.0 0.0 0.0 1992 235.0 6.76 uAg9 82 6.2 6.8 6.8 0.0 68 0.0 1993 303.3 6.80 R39 6.2 wae 173% 15.6 0.0 15.8 0.0 15.8 0.0 194 UL 6.85 B2 08.2 08.2 25.0 0.0 2.0 0.0 2.0 0.0 1995, 220.6 6.9 we2.7 w8.2 08.2 esni7 wb 0.0 0.0 wb 0.0 1996 293 65 B22 08.2 wee 4.8 0 126 40 0.0 0.0 0.0 Exhibit 15-A Sheet 1 of 3 19971998 338.2 © 47.0 7.0 7.05 M19 LS 8.2 = 308.2 We2 308.2 304.8 304.8 63.3 126 126 33.7 63.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 ° ° 199 36.8 7.10 82.1 W082 8.2 304.8 4.0 126 4.0 0.0 0.0 2000 6.4 AS 392.6 082 6.2 4.8 AS 1% aS 0.0 0.0 00 0.0 e001 76.3 1a 03.4 08.2 8.2 m8 6.3 126 3 00 00 0.0 0.0 2002 = 2003, 00h 20S 200 200720082009 6.5 1a 46 08.2 08.2 we 106.4 126 106.4 0.0 0.0 0.0 0.0 7.0 12 426.1 8.2 a2 m8 17.9 ung 0.0 0.0 0.0 0.0 37.0 LB 426.1 08.2 08.2 8 17.9 1% ung 0.0 0.0 0.0 00 397.0 ad 426.1 18.2 08.2 m8 17.9 126 17.9 0.0 0 0.0 0.0 397.0 2 426.1 8.2 18.2 WB 7.9 126 17.9 0.0 0.0 0.0 0.0 37.0 LR 426.1 108.2 8.2 8 72.9 126 ung 0.0 0.0 0.0 0.0 397.0 LR 426.1 wae 8.2 WB ung 126 72.9 0.0 0.0 0.0 0.0 397.0 LR 426.1 308.2 8.2 m8 ung 126 17.9 0.0 0.0 0.0 0.0 2010 397.0 ed 426.1 08.2 8.2 we nnd 126 7.9 0.0 0.0 Exhibit 15-A CHITA. COST (8000) Sheet 2 of 3 FIXED GUM COST (8000) ° WHET EXERGY REQUIREMENT (Gu) a6 88 5 LSM OOO 66 158 0 G00 eS eS ee) NET GENERATION POTENTIAL (Gnd OGTLOD FAC. = 0000 0.0 00 0000 0 0.0 00 00 80.00 NET GENERATION ACTURL (Get) 00 866000 00 00 G0 00 00 00 00 060 00 00 00 a0 00 8000 600 ERGY LOSS (3 ° ERGY GENERATED (Gut) Cr eS 0 00 00 O06 00 00 O06 00 00 06 06 00 00 00 00 O06 O06 00 060 60 60 00 FUEL USE (ian 1S INITIRL FUEL PRICE (SIT) —— 0.958 FUEL ESCALATION RATE. (A/YERRD 1984-1588 ° 1989-2003 ° FUL PRICE (SANITY 0.959 0.959 0.959 0.989 0.990.959 0.959 0.989.859 0.959 0.559 0.959 0.959 0.989 0.957 0.959 0.989 0.50.59 OOF OT. .SOLSF FueL COST (40000 00 «46000 ©6000 HH VARIABLE OWN RATE (CENTS/ian) = 0.8 VARIABLE O4N COST (80000 00 «0.000 00 00 00 Nu STIMOBY THERE TE: Diesel CRPPCITY AODED (mA) 0.0 00 ©6000 CURATIVE CRORCITY AODED (mid ao 00 a0 a0 en 10.0 = 10.0 10.0 10.0 10.0 10.01 OBO ‘oerTm COST (0000 61.1 (so007m 0.0.0 a0 00 a0 8600 re Se << Se XS FINED OW COST (80000 35 (sooo ° ° ° o ° ° ons s s s 3B B BOS B 3s Bos 85 OS mH OI ELISTING PRIME DIESEL » CHPRCITY Omi) ws 3 a 3 3 3 as a 3 3 20 ~ 2 2» nS 313 3 15 15 5 13 3 25S WET ENERGY REQUIRED (Gat) 26 «8 SSO KO HF OO OOH CHORCITY UTILTIZATION FACTOR 0.67 (POTENTIAL NET GENERATION POTENTIAL (Gat) TA 1M. 7 171467 146.7 1671467 M7 146,7 174 1141741710278. OOOO mo Te A 00 NET GENERATION ACTUAL (Gat) 2.6 «38 2S OLS 00 00 00 68 158 6 80.0.0 0008 6 0000 ERGY (055 (8) o ° ° ° ° ° ° ° ° o ° ° ° ° o 0 ° ° ° ° ° ERGY GENERATED (Gt) 2.6 0 BA 5 RS oo 800 600k WE 6.00 Cr ee D FUEL USE (hon) 135 INITIAL FUEL PRICE (9/684) 0.959 FUEL ESCALATION RATE (S/YERRD 1984-1988 1389-2003 FUEL PRICE (9/UNIT) ee ee ee er ee ee ee ee ee | 0.959 0.959 0.959 FUEL COST «90000 1537.8 201 STAAL AIS SMELLS O00 MHASH DODO 00 000 WAAIABLE 04M COST (9000 Oe eT XS 2 00 000 WET ENERGY REQUIREMENT (Gat) 00 00 © 0.00 OOOO OOO a a) ‘SWORY OF NET GENERITION EXISTING & COMMITTED HYDRO (8) 9.47 83.79 79.65 76.40 73:51 100.00 100.00 100,00 97.85.13 SB. $5.16 02.9% OH HOM TAR AR OR RK WR WR WR WK EM HYDROELECTRIC (9 0.00 0.00 0.000.070.0000 0.00.00. .00 0.00.00 125014170 1S. AIS ARE GGT 78GB 27.68 27.7.7. 27.68 27.68 27.68 Nid TRIRSAISSION INEORT CX) 0.00 0.00 0.00 0.000.000.0000 0.0.00 (0.000.000.0000 0.000.000.0000 0,000.00 0.000.000.0000 0.00 0.00 0.00 Nid PRIME THERMAL (3) 0.00 0.00.00). .00 0.00 0.000.000.0000 000.00 0.000.000.0000 0.00 0.0.00 EXISTING PRIME DIESEL (8) $5) 2 hOB 7.50 10.08 0.000.000.0000 0.00 0.000.000.0000 0.00 0.000.000.0000 0.00 SORTA. «3 00 0.000.000.0000 0.00.00 000.09 0D (meLT. COSTS (4000) 00 000 00 0.0 0.0 17396.0 3890.5 28022. FLXED OWN COST «80000 oo 000 0 00 000 00S BO VARIABLE OWN COST (80000 72 WD OOO HS OO 0.0 AR ae 5 PROSGED (ENEY (9000) oo 00 0k 00 00) 80 ‘FUEL COST (9000 157.8 M21 ASI SELS 00 0.0 M2 112.8 17 ONO TOTAL YEAALY COST (90000 ATLO -MAL4 440 SOUL2 SA 00 SISA MALO MBER 307887 DISCOWNTED YERMLY COST (#000) 171.0 WML MTLZ ASL SIO. 00. MOG 167K 6105.0 210886 ee Ow 1904 ISCO MATE (8) as CM, DISCOUNTED COST (#0000 ATUL. 4708.1 0622.2 ASIN A 18245,9 | 18RN9.9 18H. 82H. NMESKL A RISA SOMO THRO CM DISC. COST TO 2010 «900m STH SUK HOHOWITAL COSTE IH 2010 SIS «8000 VALUE 1K 2010 OF MO-CHPITA, 10036 (COSTS THRU 2045 (80009 DISCOUNTED MO-OWITA COSTS ARO EVDO 2010 (4000) JEAUCOENT COST 0 SALVAGE VALUE DETERMINATION (NEM UNITS) wat coeeciTy Yes sone fenscoer ferret see corte. DIscRERLAL ~ roan vom we von (cost «40001 «90000 eroaa #1 a 19% ° ° am Tio 00 roa #2 oo TARHISSION ao PRIME THERA 2 ” o 0.0 PRIME THERMAL 42 2 ” o 0.0 PRIME THER 3 2 “ o 0.0 STORY THER #1 3 194 ane ao 2054 es ‘STORY THER 42 3 195 2015 20s 2055 76 ‘STORY THERA 43 I 2005 ees ° 20s 1687.8 ‘STEADY THER 04 a 208 es ° ene 1127.5 a.e STRWOBY THER 65 10 210 2030 ° 2080 wiLo wns STRWOBY THERMAL. 96 2 0 © 00 ‘STAWOBY THERA 67 2 ” o 0.0 STOBY THER 08 2 ” © 0.0 STORY THERE 9 2 “ © 00 STORY THERA 10 2 ” © 00 STORY TER 411 00 STORY THERE 12 a0 ‘STAWOBY THERA. 013 00 ‘3 (1000) ons AT DISCOUNTED AEPLICENENT COSTS HO SALVAGE VALUES (1000) ore TOT DISCOUNTED La CORTS «4000 1069 Exhibit 15-7 Sheet 3 of 2 00 oO m8 UB ao 8 00 ao 8 00 ao 8 00 Be 88 es e173 797.9 TTL oT 00 we 00 86 00 xy 00 a0 8600 m8 Ue Oe a9 me IK BO1bi.1 8038.9 OST. 20S SALRGE VALE (4000) 1128 1037.3 us28 0 wT. 1s.8 0 me a0 a0 a0 0.0 me a0 ao a0 0.0 me a0 oo a0 0.0 1827.5 8 0.0 ao ao ao a0 1207.3 1%.7 170.8 078.2 CZ HZ NG SONG IOS 0.0 00 0.0 Le a0 at m4 0 00 0 oo ao ao a0 a0 0.0 38 ao oo ao 8 11.0 sia a0 a0 a0