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HomeMy WebLinkAboutFinal Report Calista Regional Electric Utility Feasibility Report 1993FINAL REPORT CALISTA REGIONAL ELECTRIC UTILITY FEASIBILITY REPORT Prepared for: Calista Corporation 601 W. 5th Avenue Anchorage, AK 99501 Prepared by: Bettine & Associates P.O. Box 112265 Anchorage, AK 99511-2265 JULY, 1993 FILE (CoPy Do NOT REMOVE 1.0 2.0 3.0 4.0 TABLE OF CONTENTS INTRODUCTION & PURPOSE 1.1 1.2 SUMMARY 2A 22 Introduction Purpose of Report Form of Organization Financial Analysis FORM OF ORGANIZATION 3:1 3.2 3.3 3.4 3.5 3.6 Introduction Types of Business Organizations 3.2.1 3.2.2 3.2.3 3.2.4 3.2.5 3.2.6 For-Profit Corporation Non-Profit Corporation Subsidiary Corporation Non-Profit Member Owned Cooperative Regional Electric Authority Municipal Corporation APUC Certificate of Convenience & Necessity Sources of Financing Ranking the Business Organization Recommendations Page No. 1-1 3-1 3-1 3-1 3-1 3-4 3-7 3-8 3-10 3-13 3-14 3-15 3-22 3-24 FORMING A “FULL SERVICE" REGIONAL ELECTRIC UTILITY 4.1 42 4.3 44 45 Introduction Basic Approach to Forming a REU Obstacles to Regionalization Options to a Regional Electric Utility Single Wire Ground Return Transmission Interties 4-1 4-1 4-5 4-6 4-6 Page No 5.0 MANAGING THE UTILITY 5.1 Introduction 5-1 a2 In-House Management 5-1 5.3 Contract Management 5-5 5.4 Recommendations 5-9 6.0 FINANCIAL ANALYSIS 6-1 6.1 Introduction 6-1 6.2 Description of Alternatives & Discussion of Results 6-1 6.3 Economic Parameters 6-8 6.4 Recommendations 6-9 REFERENCES APPENDIX A A.1 Parameters Used in Financial Forecast & Cost-of-Service A-1 Analysis A.2_ Explanation of Computer Printouts A-8 A3 Calculations A-12 APPENDIX B B.1 Single Wire Ground Return Minimum Cost B-1 Transmission System B.2 Single Phase to Three Phase Conversion In SWGR B-3 APPENDIX C C.1 Existing Facilities C-1 C.2_—_-Historical Information C-1 C3 ~-Future Electric Energy and Demand Projections C-2 TABLES Table 2.1 2-3 Table 2.2 2-4 Table 3.1 3-23 FIGURES Figure 1.1 Figure 2.1 Figure 2.2 Figure 2.3 Figure 2.4 Figure 2.5 Figure 2.6 Figure 4.1 Figure 5.1 Figure 5.2 Figure 5.3 Figure 6.1 Figure 6.2 Figure 6.3 Location Map Relative Ranking of Organizatiions Self-Generation vs. Full Service REU Year 2014 Energy Cost Year 2014 Energy Cost with PCE Present Worth Cost of PCE Payments ($1994) Bethel - No REU vs. Alt. B Energy Cost Three Stages to Forming a Full-Service REU Organizational Structure REU Stage 1 Organizational Structure REU Stage 2 Organizational Structure REU Stage 3 Alternative A Cost Comparison Alternative B Cost Comparison Net Return on Investment "Calista Utilities" Page No. 2-2 2-5 2-5 2-6 2-6 5-2 5-3 5-5 6-3 6-6 DISCLAIMER This study is intended as a long-range guide for developing a regional electric utility. The accuracy of the investment costs, labor and material costs, and the assumptions and parameters used as input for this study is consistent with a feasibility level study. Therefore, the cost of energy and consumer rates derived in the financial analysis section should only be considered as a basis for comparison between the alternatives and not as an absolute projection of future energy costs and rates. Actual costs of services for the various classes of consumers must be developed in detail to satisfy the requirements of the APUC. The feasibility of implementing stages 2 and 3 should be reassessed, if at the time they are implemented, the energy costs and financial conditions differ significantly from the projections and assumptions contained in this study. 1.0. INTRODUCTION & PURPOSE 1.1. INTRODUCTION The Calista Region is located in the Yukon-Kuskokwim delta region of southwest Alaska. The region is about the size of Michigan in area with residents scattered throughout some 49 year-round villages which represents over 25 percent of the total communities and villages in Alaska. The Calista Region is unique in that all the villages are widely separated with no road connections, and is virtually isolated from the remainder of the state except for air travel, since roads are non-existent. (See Figure 1.1 for a location map of the Calista Region.) While the region is blessed with great natural beauty and an abundance of wildlife, the remoteness of the region and lack of infrastructure has compelled the Yup'iks of the Calista Region to endure the highest unemployment rates, the lowest per capita income and the lowest standard of living of any Natives in the state. To exacerbate the problem, the high cost of electrical energy is perhaps the most significant barrier limiting commercial and industrial growth in the region. Except for the villages of Napakiak and Oscarville which are connected to Bethel by electric power lines, the remaining villages surrounding Bethel rely exclusively on small, gener- ally inadequate, diesel power plants. These small power plants are costly to maintain and repair and are inherently inefficient, producing only half the kilowatt hours per gallon of fuel as compared to the larger more efficient plant found in Bethel. In addition, many of the bulk fuel storage facilities associated with the diesel plants are outdated, lack spill containment dikes and do not meet even the most basic environmental guidelines. Therefore, it should not be surprising to find that fuel oil spills occur frequently. These low generation efficiencies when combined with the high cost of diesel fuel in the villages and environmentally unsound practices have resulted in exorbitant electrical energy costs for village consumers. The cost of electrical energy in the villages is rapidly approaching a cost of 50 cents per kilowatt hour which typically exceeds the cost of electricity in Bethel by a factor of two and in Anchorage by a factor of six. At present, the high cost of electrical energy is somewhat offset by the state-funded Power Cost Equalization program (PCE). Under the currently funded PCE program the state pays the portion of electrical energy costs which exceeds 9.8 cents per kwh for the first 700 kwh of usage. del It is highly probable that the PCE program will be phased out over the next few years, which will mean fewer families will be able to afford electricity, fewer jobs for Yup'iks in the region and a continuing decline in the quality of life. In order to reverse this trend and prevent degradation of the quality of life in the villages it is critical to develop a more economical energy source than the system of small generation plants found in the individual villages. 1.2. PURPOSE OF REPORT Calista Corporation is considering creation of a limited regional electric utility in the Bethel area in order to reduce the high cost of electrical energy to villages within the Calista Re- gion. A regional utility has the potential for providing more efficient, reliable and less expensive electric service than the small individual systems presently being used in the villages. Utilizing grant funds provided by the Alaska Energy Authority (AEA), Calista Corporation has retained the firm of Bettine & Associates to prepare this report which evaluates the economic feasibility of establishing some form of limited regional electric utility in the Bethel area. Primarily this study will examine the creation of a limited regional electric utility which would serve the villages of Kwethluk, Akiachak, Akiak, Tuluksak, Napaskiak, Oscarville, Napakiak and the mining camp at Nyac. These villages were chosen as the "core" of this limited regional utility study because a recent study entitled Nyac-Bethel Transmission Line Feasibility Report demonstrated that it would be economically feasible to serve these villages from a transmission line extending from Bethel to the Nyac hydroelectric site. (See Appendix C for a map containing the proposed transmission interties.) To provide Calista Corporation with guidance in creating a regional electric utility, two major tasks were performed: first, various corporate structures were examined to determine the most appropriate organizational form for implementing a regional electric utility; and second, a series of financial analyses were conducted to evaluate the economic feasibility of creating a regional utility. Three of the four corporate structures examined can be used to form non-profit utilities. Two of the corporate structures can be used to create a utility subsidiary of a for-profit corporation such as Calista Corporation. I=2 — - — ARCTIC CIRCLE ST. MATHEW IS. Sy BERING SEA Location Map of the Calista Region, Southwestern Alaska FIGURE 1.1 1-3 2.0. SUMMARY 2.1. FORM OF ORGANIZATION There are four types of business organizations which are customarily used for operating a utility. These may generally be described as: (1) for-profit corporations; (2) nonprofit corporations; (3) public power organizations such as a regional electric authority; and (4) nonprofit member owned cooperatives. Each type of organization was closely analyzed to determine which organization would serve as the most appropriate vehicle for creating a regional electric utility in the Bethel region. The analyses examined several factors including legal requirements, tax consequences, financing alternatives and regulatory requirements intrinsic to each organization. The evaluation produced . . . tas RELATIVE RANKING the following relative ranking which is shown OF ORGANIZATIONS FOR FORMING AN REU in graphical form in Figure 2.1. These rank- ings should be used for comparison purposes only. The rankings suggest that an electric cooperative is the least desirable alternative for establishing a nonprofit regional electric utility. Therefore, the cooperative organiza- iq aaa tion can be eliminated as a viable alternative. 0 ROT COOPERATIVE” NONPROFIT RGEA Although the nonprofit Calista "subsidiary" FIGURE 2.1 and the RGEA are equally ranked, it is rec- ommended the nonprofit Calista "subsidiary" be selected as the vehicle for creating a regional utility. The benefits of selecting a nonprofit Calista "subsidiary" over the RGEA include the ease of formation, affirmative control over development and minimum interference from other organizations. While a for-profit "subsidiary" received the lowest score it is the cus- tomary business organization used for operating a for-profit utility. This report also outlines a basic three staged development plan by which Calista Corporation can form a "full service" regional electric utility in the Bethel area. The regional utility would provide generation, transmission and distribution service to Bethel and villages om within the region. The preferred first course of action in the first stage of the development plan requires Calista to form a “limited service" nonprofit Generation & Transmission utility which would construct and operate a regional transmission intertie system and the Nyac Hydroelectric facility, These facilities would serve the seven villages addressed in the Bethel-Nyac Transmis- sion Line Feasibility Report and the Nyac mining camp. Stage Two involves acquiring and operating the electric utility systems in the seven villages. In Stage Three, Calista Corporation forms "Calista Utilities" as a for-profit subsidiary corporation. Calista Utilities acquires both the non-profit Generation & Transmission (G&T) and Bethel Utilities and commences operations as a "full service" regional electric utility. In addition, this report examines the benefits and disadvantages of using contract management services to provide many of the tasks which would normally be performed by the regional electric utilities' "in-house" per- sonnel. Both Calista Corporation and FIGURE 2.2 THREA were examined as possible pro- SELF GENERATION vs FULL SERVICE REU : : STAGE 1-3, COST COMPARISON viders of contract management services. $1.00 $0.90 +----------------------2-22-2-- eee ee ee ene eee ee eee ee eee eeeeed After careful evaluation of the available information it was concluded that Calista Corporation, under the guidance of THREA or another suitable utility, should provide the management services. 2.2, FINANCIAL ANALYSIS 20 : 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 formed, based on certain assumptions, to -@ Self Gen. -@ Alt-A -@ Alt. B A series of calculations were per- determine the financial feasibility of the several alternatives examined. A listing of the main alternatives examined is contained in Table 2.1. A comprehensive description of each alternative and a discussion of the results obtained from the analysis for each alternative, is contained in Section 6.0. 1 Construction of the intertie transmission system is a financially sound alternative without the Nyac hydro project. 2-2 ALTERNATIVE A. Continued Self-Generation TABLE 2.1 DESCRIPTION Continued Self Generation at Akiachak, Akiak, Kwethluk, Tuluksak and Napaskiak B. Regional Intertie System. Villages of Akiachak, Akiak, Kwethluk, Tuluksak, Napaskiak, Oscarville, Napakiak Intertied to Bethel with Single Pole SWGR Transmission Line. Nyac Hydro NOT Developed Nyac Hydro Developed C. Bethel - No REU Moderate Load Growth: STAGE 1, Alternative A - REU operates at Stage 1 for entire study period. STAGE 1-2, Alternative A - REU implements STAGE 2 level in 1998 and operates at STAGE 2 for remainder of study period. STAGE 1-3, Alternative A - REU implements STAGE 1, 2, and 3. STAGE 3 implemented in year 2000. Bethel Utilities purchased for $6,000,000. Moderate Load Growth: STAGE 1, ALTERNATIVE B - REU operates at Stage 1 for entire study period. STAGE 1-2, ALTERNATIVE B - REU implements STAGE 2 level in 1998 and operates at STAGE 2 for remainder of study period. STAGE 1-3, ALTERNATIVE B REU implements STAGE 1, 2, and 3. STAGE 3 implemented in year 2000. Bethel Utilities purchased for $6,000,000. STAGE 1-3, ALTERNATIVE C - Same as Alternative B, Stage 1-3, except Bethel Utilities purchased for $8,000,000. STAGE 1-3, ALTERNATIVE D - Same as Alternative B, Stage 1-3, except seven village distribution systems purchased for $150,000 each. Low Load Growth STAGE 1-3 - ALTERNATIVE E - Same as Alternative B, Stage 1-3, except investigates the affect of low load growth. Bethel Utilities continues to provide requirements of Bethel. Neither Nyac hydro nor the transmission interties are constructed. 2-3 The financial feasibility of developing a "Full Service" REU has been investigated for four primary alternatives. These are: 1) “Continued Self Generation" in the villages; 2) Alternative A, construction of a regional SWGR transmission intertie system without the Nyac hydroelectric plant; 3) Alternative B, construction of a regional SWGR transmission intertie system with the Nyac hydroelectric plant; and 4) Bethel - No REU. The "Continued Self Generation" and "Bethel - No REU" alternatives are used as the basis for comparison. Secondary Alternatives C-E which were investigated are minor variations of Alternative B. The various costs associated with the three Stages of development for selected alternatives has been summarized in both tabular and graphic format. The graphic exhibits allow easy comparison of the results. The "Continued Self- Generation" Alternative is the least desirable of any of the alternatives investigated. Construc- tion of a regional transmission intertie system and development of the Nyac hydro as described in Alternative B, is the most desirable course of action. Construction of a regional transmission intertie system without the development of the Nyac hydro as described in TABLE 2.2 AVERAGE RATE $/KWH AltA? Alt BY ALC AltD* AILE? Self.Gen. Bethel/No REU 2005 2014 2005 2014 2005 2014 2005 2014 2005 2014 + 2005 2014 2005 2014 WITHOUT PCE Avg. Retail $0.25 $0.32 $0.24 $031 $0.25 $031 $0.25 $0.32 $0.26 $033 $0.62 $0.85 $0.24 $0.31 Residential $0.27 $0.34 $0.27 $0.33 $0.27 $0.34 $0.28 $034 $0.28 $0.36 $0.71 $092 $0.26 $0.34 Small Commercial $0.24 $0.31 $0.24 $0.30 $0.24 $0.31 $0.25 $0.31 $0.25 $0.33 $0.65 $0.84 $0.23 $0.31 Large Commercial $0.22 $0.29 $0.22 $0.28 $0.22 $0.28 $0.23 $0.29 $0.23 $0.30 $0.60 $0.77 $0.22 $0.28 WITH PCE Residential $0.15 $0.20 $0.15 $0.20 $0.15 $0.20 $0.15 $0.20 $0.15 $0.20 $0.17 $0.23 XXX XXX Small Commercial $0.15 $0.20 $0.15 $0.20 $0.15 $0.20 $0.15 $0.20 $0.15 $0.20 $0.17 $0.23 XXX XXX Large Commercial $0.22 $0.29 $0.22 $0.28 $0.22 $0.28 $0.23 $0.29 $0.23 $0.30 $0.60 $0.77 XXX XXX Alternative A, is the second most desirable course of action. Figure 2.2 is a graph which compares the average per kilowatt hour energy cost paid by the end consumer for the "Continued 2 Rates for STAGE 3 REU 2-4 Self-Generation" alternative, Alternative A and Alternative B. Table 2.2 tabulates the | cost of energy for the various alternatives. | An examination of Figure 2.2 quickly illus- | trates the "Continued Self-Generation" alter- native results in energy costs which are approximately three times greater than either Alternative A or B. Figure 2.3 is a bar graph which com- pares the year 2014 energy costs tabulated in YEAR 2014 ENERGY COST WITHOUT PCE BAILA BAB Gi Bethel - No REU CAAIt. C DAK D Table 2.1 for four "Full Service," Stage 3 FIGURE 2.3 REU alternatives and the Bethel - No REU alternative. The graph clearly illustrates that if Calista Corporation were to purchase Bethel Utilities and form a "Full Service" REU, the cost of energy in 2014 for any of the four YEAR 2014 ENERGY COST - WITH PCE $0.80 a & soso o g $0.20 $0.00 . Residential Small Comm. Large Comm. BAA BARB Self Gen. FIGURE 2.4 alternatives represented in the graph, should not exceed the cost of energy provided by Bethel Utilities if no REU were formed. Retail energy cost to consumers in 2014 averages approxi- mately $0.31/kwh for small commercial consumers with the cost to residential and large commercial users, slightly higher and lower. The year 2014 energy cost, ad- justed for PCE payments, is shown in Figure 2.4. While the cost of energy for residential and small commercial consumers, after adjustments for PCE, is approximately equal for Alternative A, B and the "Continued Self Generation," the cost of energy for large commercial users is some 2 1/2 times as great in the "Continued Self Generation" alternative as 2-5 compared to either Alternative A or B. PRESENT WORTH COST Figure 2.5 compares the Present Worth §p>———————— | OF PCE PAYMENTS ($1994) (PW) cost of PCE payments for these three alternatives. The PW cost provides a comparison of the 1994 equivalent dollars the State would pay in PCE to subsidize the cost of electrical energy sales in the villages. The PW cost of PCE payments for the "Continued Self ‘Self Gea Presect Worth Cost includes $2,155,000 for WN apainak and Oscarrite Generation" alternative is approximately $19,000,000, which is more than three FIGURE 2.5 times as great as for either Alternative A or B. The effect of grant funding was investigated for Alternative B, by assuming the transmission system and Nyac hydro project were funded at various levels of grant funding. The results of this analysis are provided in Figure BETHEL - No REU vs. ALT B. ENERGY COST 2.6 and shows that 90% of the combined in 2014 —— cost of the transmission system and Nyac $0.36 hydro project must be funded by grants if the cost of energy in the year 2014 for Alterna- tive B is not to exceed the cost of energy in the Bethel - No REU alternative. é AVG. COST S/KWH Regardless of whether Alternative A i + Lest é 50 ite or B is constructed, the implementation of a PERCENTAGE OF GRANT FUNDS "Full Service" REU drastically lowers the FIGURE 2.6 cost of electrical energy for village users as compared to "Continued Self Generation.". Implementation of either Alternatives A and B results in energy and PCE cost which are basically identical in 2014. However, a close examination of the results will reveal Alterative B is slightly less expensive in 2014 than Alternative A. If the study periods were increased to fifty years, the typical life span of a hydro facility, the cost advantages of Alternative B would become 2-6 much more apparent. Therefore, the recommended course of action to form a "Full Service" REU is the implementation of Alternative B; development of the Nyac hydro and construction of a regional SWGR transmission system to intertie the villages with the Nyac hydro and Bethel. 3.0. FORM OF ORGANIZATION 3.1. INTRODUCTION A fundamental decision when starting a new utility, is to determine the type of business organizational form to be used as the vehicle for conducting the business of the utility. Customarily utilities in the continental United States and in Alaska operate as one of the following four types of business organizations. These may generally be described as: (1) for profit corporations; (2) nonprofit corporations; (3) public power organizations such as a regional electric authority; and (4) nonprofit member owned cooperatives or some combi- nation of these entities’. To determine which of these four business organizations represents the most appropriate organizational form for creating a regional electric utility, the primary advantages and disadvantages associated with the legal requirements, tax consequences, financing alternatives and regulatory requirements intrinsic to each organization, are examined and discussed herein. 3.2. TYPES OF BUSINESS ORGANIZATIONS 3.2.1. For-Profit Corporation A for-profit corporation must be organized in Alaska pursuant to Alaska Statute Title 10, Chapter 6, (A.S. 10.06). A corporation may be organized for any lawful purpose except for the purposes of banking and insurance. Anyone of sound mind over the age of 18 can form a corporation by signing, verifying, and delivering to the commissioner an original and an exact copy of the articles of incorporation for the corporation as set forth in AS 10.06.208- 233. The Corporate existence begins upon the issuance of the certificate of incorporation. In Alaska, the persons organizing and starting the corporation are generally personally respon- sible for all debts and liabilities incurred by the corporation, if they begin carrying on the 1 In Alaska it is possible for a Regional Electric Authority to organize as a nonprofit corporation and retain its status as a political subdivision of the state. 3-1 business of the corporation prior to obtaining a certificate of incorporation. A corporation organized under AS 10.06 must maintain a current Alaska business license. A corporation for-profit is organized to conduct a business that is expected to generate profits which are distributed to its shareholders. The Corporation name shall contain the word "corporation", "company", "incorporated", or "limited", or an abbreviation of one of these words, however, these words may not be used unless the person has been issued a certificate of incorporation. The corporate name may not contain a phrase which indicates or implies the corporation is organized for a purpose other than the purpose contained in the articles of incorporation. The name may not contain the word "city", "borough", or "village" or otherwise imply that the corporation is a municipality. The Articles of Incorporation among other items, shall set out the name, purpose, initial registered office, the class and number of shares of stock and normally contain the number of directors. The officers are elected by the board of directors. The required officers are a president, a secretary and a treasurer. Any two or more offices may be held by the same person, except the offices of president and secretary. Directors, officers, employees, or agents of a cooperative are not usually liable for conduct performed within the scope of their authority, if the person believed that the conduct was in, or not contrary to, the best interest of the corporation. The general powers of the corporation are subject to the limitations set out in its articles of incorporation. Typically a corporation has all the powers of a natural person in carrying out its business activity including the powers set out in AS 10.06.010. These powers include: adopt and use a corporate seal; adopt, amend and repeal bylaws; sue and be sued; appoint officers, agents, employee; incur obligations such as borrow money, issue non-tax- exempt bonds, notes and other forms of indebtedness; etc. Articles of Incorporation would typically grant a corporation formed to operate as an electric utility the authority to generate, manufacture, purchase, acquire, accumulate and trans- mit electric energy and distribute, sell, supply and dispose of electric energy to its members, to governmental agencies and political subdivisions, and to other persons. In addition, AS 42.05.631 grants a utility organized as a for-profit corporation the power of eminent domain for public uses. 3-2 3.2.1.1 Taxation of For-Profit Corporations In general, validly imposed taxes are properly included in the operation expenses of an electric utility for ratemaking purposes, and are to be deducted from the gross revenue of the utility in determining whether the net return is fair. For the purposes of taxation it is assumed a for-profit corporation would be organized as a Chapter C Corporation under the Internal Revenue Code. A complete discussion of corporate taxation is beyond the scope of this study. It suffices to say that a corporation is considered as a separate taxpayer and is subject to federal income tax. The 1992 marginal tax rates for corporations varies between 15% to 34%, based on taxable income. The tax rate is 34% for taxable income in excess of $335,000. It is also worthy to note that any stock dividends paid to shareholders is taxed again as personal income to the shareholders. A for-profit Chapter C Corporation is required to pay state taxes. The marginal tax rate varies between 2% to 9.4% based on taxable income. The tax rate is 9.4% on taxable income in excess of $90,000. 3.2.1.2 APUC Regulation A for-profit corporation must secure a certificate of public convenience and necessity before it can begin operating as a utility. A for-profit corporation which grosses in excess of $325,000 annually is subject to the jurisdiction of the APUC and may not elect to withdraw from APUC regulation. However, if the electric utility does not gross $325,000 annually, the customers of the utility may elect to exempt the utility from APUC regulation pursuant to AS 42.05.712. 3.2.1.3. Financing Alternatives A for-profit corporation may qualify for financing from the following sources: Rural Electrification Administration (REA); REA supplemental lenders; commercial banks; federal and state grant or loan programs. A for-profit corporation may finance its activities through debt (i.e. by borrowing money) which is generally secured by a mortgage, pledge or deed of trust or by the sale of stock and taxable bonds. 3-3 3.2.2. NONPROFIT CORPORATION A nonprofit corporation may be organized in Alaska pursuant to Alaska Statutes Chapter 10, Section 20 for any lawful purpose, including the operation of an electric utility. The Attorney General's opinion of June 7, 1976 noted that there was nothing in AS 10.20 which prevents a nonprofit corporation from owning a public utility which was not operated or managed as a cooperative. Cooperatives such as electric cooperatives may not be organized under this chapter. The characteristics of a nonprofit and for-profit organization are nearly identical. Both require a legal form, have a board of directors and officers, pay compensation, face essentially the same expenses, are able to receive a profit, make investments, and produce goods and/or services. A nonprofit corporation is required to maintain a current Alaska business license. The nonprofit organization generally is not permitted to distribute its profits (net earnings) to those who control and/or financially support it. The private inurement doctrine is the substantive dividing line that differentiates, for legal purposes, between nonprofit organizations and for-profit organizations. While both nonprofit and for-profit organizations are able to generate profit; the distinction between the two entities pivots on what is done with this profit. Typically, no dividends may be paid and no part of the income or profit of a nonprofit corporation may be distributed to its members, directors, or officers except to the extent permitted by AS 10.20 and Internal Revenue Code of 1954. Generally the "profits" earned by an electric utility organized as a nonprofit corporation must be reinvested in the corporation, retained to improve debt/equity ratio, or used to reduce the cost of services to its consumers. Loans to directors and officers are prohibited. The Corporation name shall contain the word "corporation", “company”, "incorporated", or "limited", or an abbreviation of one of these words, however, these words may not be used unless the entity has been issued a certificate of incorporation. The corporate name may not contain any phrase which indicates or implies the corporation is organized for a purpose other than the purpose contained in the articles of incorporation. The name may not contain the word "city", "borough", or "village" or otherwise imply that the corporation is a municipality. The Articles of Incorporation among other items, shall set out the name, purpose, initial registered office, and normally contain the number of directors. The number of 3-4 directors shall be at least three. The officers are elected by the board of directors. The required officers are a president, a secretary and a treasurer. Any two or more offices may be held by the same person, except the offices of president and secretary. Unless limited each member is entitled to one vote. If there are no members or its members have no right to vote, the directors shall have sole voting power. The affairs of the corporation shall be managed by a board of not less than three directors. Directors do not have to be members or residents of the state. A nonprofit corporation may not have or issue shares of stock. A nonprofit corporation may pay compensation in a reasonable amount to its members, directors, or officers for services rendered, may confer benefits upon its members in conformity with its purposes. Directors, officers, employees, or agents of a corporation are not usually liable for conduct performed within the scope of their authority, if the person believed that the conduct was in, or not contrary to, the best interest of the corporation. The general powers of the corporation are subject to the limitations set out in its Articles of Incorporation. Typically a corporation has all the powers of a natural person in carrying out its business activity including the powers set out in AS 10.20. These powers include: adopt and use a corporate seal; adopt, amend and repeal bylaws; sue and be sued; appoint officers, agents, employees; incur obligations such as borrow money, issue taxable bonds, notes and other forms of indebtedness; etc. The Articles of Incorporation would typically grant a nonprofit corporation formed to operate as an electric utility the authority to generate, manufacture, purchase, acquire, accumulate and transmit electric energy and distribute, sell, supply and dispose of electric energy to its members, to governmental agencies and political subdivisions, and to other persons. In addition, AS 42.05.631 grants a utility organized as a nonprofit corporation the power of eminent domain for public uses. 3.2.2.1 Taxation of Nonprofit Corporations Typically a nonprofit corporation is exempt from federal taxation if it follows certain requirements. These requirements are discussed below. The purpose of a nonprofit corporation is central to its operation. A corporation seeking tax-exempt status under Section 501(c) of the Internal Revenue Code, which exempts 3-5 the organization from federal income taxes in connection with its exempt purpose, must be limited to one or more of the exempt purposes specified in Section 501(c). Federal tax exempt qualifications for a nonprofit organization are: 1) an organization being organized and operated exclusively for its specific exempt purpose, in this case a nonprofit electric utility; and (2) no part of the net earnings of the organization inuring to the benefit of any private shareholder or individual. However, tax exempt status is not automatic. An organization must apply to the IRS for a determination letter and its tax-exempt status is not assured until it receives a revenue letter or revenue ruling confirming the status. An electric utility operat- ed as a nonprofit corporation would presumably qualify as a tax-exempt organization under IRC Section 501(c)(12), if at least 85 percent of its income is derived from amounts collected from members for the sole purpose of meeting losses and expenses. In general, a nonprofit corporation is exempt from state taxation if the corporation is exempt from federal taxation. 3.2.2.2 APUC Regulation A nonprofit corporation must secure a certificate of public convenience and necessity before it can begin operating as a utility. A nonprofit corporation which grosses in excess of $325,000 annually is subject to the jurisdiction of the APUC and may not elect to withdraw from APUC regulation. However, if the electric utility does not gross $325,000 annually, the customers or members of the utility may elect to exempt the utility from APUC regulation pursuant to AS 42.05.712. 3.2.2.3 Financing Alternatives A nonprofit corporation may qualify for financing from the following sources: Rural Electrification Administration (REA); REA supplemental lenders; commercial banks; federal and state grant or loan programs. A nonprofit corporation may finance its activities through debt (i.e. by borrowing money) which is generally secured by a mortgage, pledge or deed of trust or by the sale of tax exempt bonds. 3.2.3 SUBSIDIARY CORPORATION (Profit or Nonprofit) A subsidiary corporation is a corporation that is controlled by another corporation. Control ordinarily resides with the majority owner. The dominant corporation is called the parent corporation. A subsidiary can pay reasonable salaries to its managers and employees and contract to the parent company for services and supplies. Should Calista Corporation elect to form an electric utility organized as either a profit or non-profit corporation, it is recommended that the utility be formed and operated as a subsidiary organization. As a for profit subsidiary, Calista should own all or at least a majority of the interest in the subsidiary. If a nonprofit "subsidiary", Calista would retain control of the utility through the Board of Directors. A nonprofit utility would not be a true subsidiary, but would be formed as an independent nonprofit corporation which would be managed by the Board of Directors of Calista Corporation. For the purpose of this report, any profit or nonprofit corporation formed to operate a utility will be referred to as a subsidiary. The primary advantage of forming a subsidiary is the subsidiary is treated as a separate legal entity for tax and liability purposes so long as the parent corporation (Calista) does not control the affairs of the subsidiary to the extent the subsidiary is merely an instrumentality of Calista. The APUC will also require Calista to keep separate business accounts relating to the utility operation to prevent commingling of expenses and profits generated by the utility operation and Calista's other business enterprises. Forming a subsidiary would be the simplest method to satisfy the separate business account requirement. When contracting to the parent company for services or supplies, the APUC will generally disapprove any costs, when fixing rates, that are higher than the subsidiary would pay when purchasing services or supplies directly from an unrelated seller dealing at arm's length. Furthermore, when operating a utility as a for-profit subsidiary, all of the various ways in which the parent company receives profits from the subsidiary will generally be considered in establishing the rate of return the parent company is allowed to receive. It is also unlikely the APUC would allow any profits to be realized from grant funds received by the utility. 3-7 3.2.4 NONPROFIT MEMBER OWNED COOPERATIVE A member owned electric cooperative must be organized in Alaska pursuant to Alaska Statute Title 10, Chapter 25, (AS 10.25) Electric and Telephone Cooperative Act. Although there is no other express language in the Electric and Telephone Cooperative Act, which purports to make it the exclusive means of organizing nonprofit cooperative associations for the development of utility services, this would certainly be a reasonable inference based upon this section and upon the exclusionary language of AS 10.20.005 which eliminates the nonprofit corporation as an alternative means of forming a cooperative. A member owned cooperative shall be operated on a nonprofit basis for the mutual benefit of its members and patrons. The bylaws of a cooperative or its contract with members and patrons shall contain such provisions relating to the disposition of revenues and receipts as may be necessary and appropriate to establish and maintain its nonprofit and cooperative character. Five or more persons, including an existing cooperative, may organize a cooperative. Each of the persons organizing the cooperative must be a member of the cooperative or of another cooperative that is a member of it. The name of the cooperative must include the word "electric" and “cooperative” and the word "inc." As with other corporate entities, a cooperative must file Articles of Incorporation, select a board of directors and adopt bylaws. The business of a cooperative shall be managed by not less than five directors, each of whom shall be a member of the cooperative or of another cooperative that is a member of it. The officers of a cooperative are a president, vice president, a secretary and a treasurer. The officers are elected annually by the board of directors from among the members of the board of directors. The offices of secretary and of treasurer may be held by the same person. Directors, officers, employees, or agents of a cooperative are not usually liable for conduct performed within the scope of their authority, if the person believed that the conduct was in, or not contrary to, the best interest of the cooperative. Under AS 10.25 a cooperative is empowered to generate, manufacture, purchase, acquire, accumulate and transmit electric energy and distribute, sell, supply and dispose of electric energy to its members, to governmental agencies and political subdivisions, and to other persons not exceeding 10 percent of the number of its members. A cooperative may 3-8 enter contracts, incur indebtedness, construct facilities as necessary or appropriate to exercise the powers enumerated to it under section AS 10.25.101. A cooperative organized under Chapter 25 must maintain a current Alaska business license. An important power granted to a cooperative is the power of eminent domain. 3.2.4.1. Taxation of Nonprofit Cooperatives Typically a nonprofit electric cooperative can be exempt from federal taxation if it follows certain requirements. These requirements are discussed below. IRC 501(c)(12)describes tax-exempt associations such as electric cooperatives. To be exempt from tax under this rule, the cooperative must obtain at least 85 percent of its income from amounts collected from members for the sole purpose of meeting losses and expenses. This requirement is applied on the basis of annual accounting periods. Income from all sources is taken into account, including capital gains from the sale of assets and investments; amounts received as gifts or contributions are not regarded as income. (The IRS has ruled that where an electric cooperative leased power facilities to a nonmember power company that in turn sold power to the cooperative, the entire rental income was income from a non- member for purposes of the 85 percent requirement rather than an offset against the cost of acquiring power). Sale of power to nonmembers would also be counted for purposes of the 85 percent rule. A cooperative must apply to the IRS for a determination letter and its tax- exempt status is not assured until it receives a revenue letter or revenue ruling confirming the status. An electric cooperative is required to pay tax to the state, which is based on the number of kilowatt hours sold at retail by the cooperative, during the preceding calendar year. The tax shall be computed as one-fourth mill per kilowatt hour for cooperatives which have furnished electric energy and power to consumers for less than five years and one-half mill per kilowatt hour if in business for more than five years. Mill means one-tenth of one cent. The tax will be refunded to any organized borough or a city of any class incorporated under state law, except for the amount expended by the state in their collection. This tax is paid in lieu of local ad valorem, income and excise tax which may be assessed or levied against the cooperative. 3-9 3.2.4.2. APUC Regulation An electric cooperative must secure a certificate of public convenience and necessity before it can begin operating as a utility. Once formed a non-profit cooperative is subject to the jurisdiction of the APUC. However, pursuant to AS 42.05.712, members of a cooperative may have an election to withdraw from APUC regulation. If the members elect to withdraw from APUC regulation, the board of directors of the cooperative would then set the rates charged to consumers. 3.2.4.3. Financing Alternatives A non-profit cooperative may qualify for financing from the following sources: Rural Electrification Administration (REA); REA supplemental lenders; commercial banks; federal and state grant or loan programs. In general a cooperative may only secure financing through debt (i.e. by borrowing money) which is secured by a mortgage, pledge or deed of trust. A cooperative is not authorized to obtain financing by selling stocks or bonds. 3.2.5. REGIONAL ELECTRIC AUTHORITY Pursuant to Alaska Statute Title 18, Chapter 57, only an existing regional housing authority or an association authorized by AS 18.55.966(a) to form a regional housing authority is empowered to form a Regional Electrical Authority (RGEA). In general, any non- profit native corporation such as the Alaska Village of Council Presidents (AVCP) or Alaska Federation of Natives, Inc. (AFN) is authorized to form a regional housing authority under AS 18.55.996. A RGEA is formed when the board of directors of a regional housing authority or of an entity permitted to form a regional housing authority, by resolution authorizes the formation of an RGEA. The board of directors of the housing authority must also appoint persons to serve as the board of commissioners of the RGEA. The board od directors of the housing authority and the board of commissioner of the RGEA are separate entities, although the same individuals may serve on both the board of directors for the housing authority and the board of commissioners of the RGEA. A RGEA is by statute a public corporation and a political subdivision of the state. A 3-10 RGEA may be organized as a non-profit corporation pursuant to AS 10.20 and must be operated on a nonprofit basis for the mutual benefit of its consumers. A RGEA differs from a typical corporation in two major respects: First, a RGEA is not authorized to sell stock as a means of obtaining capital and second a RGEA cannot be formed directly, but must be formed as a stepchild of either a regional housing authority or entity that is authorized to form a regional housing authority. The bylaws of a RGEA or its contract with members and patrons shall contain such provisions relating to the disposition of revenues and receipts as may be necessary and appropriate to establish and maintain its non-profit character. Once formed a RGEA is authorized to exercise the general corporate powers as listed in AS 18.57. These powers are typical of those powers that every corporation formed in Alaska automatically possess. However, in addition to typical corporate powers, a RGEA has been granted two important additional powers which are, the authority to sell tax-exempt bonds and the power of eminent domain. While an RGEA is considered a political subdivision of the state, the obligations incurred by a RGEA, remain the sole obligation of the issuing RGEA and neither the faith and credit of the state nor the taxing power of the state or of any other political subdivision of the state is pledged for payment of the obligation. (Note: A RGEA may also secure bonds or notes by a pledge of a grant or contribution from state, or federal government or other institute or person.) The number of members of the board of commissioners, their terms of office, and the method used to select commissioners shall be determined by resolution of the governing body of the association forming the RGEA. The RGEA may operate in all or part of the operating area of the association. The board of commissioners may, by resolution, change the area served. A RGEA is authorized to generate, manufacture, purchase, acquire, accumulate and transmit energy and distribute, sell, supply and dispose of electrical energy and other supplies and services as the RGEA determines is necessary, proper, incidental or convenient in connection with it activities. When agreed upon by the parties, an existing electric cooperative or municipality, or other provider of electrical service may, by approval of its governing board, transfer all or part of its plant and assets to a RGEA. Sat 3.2.5.1. Taxation of a Regional Electric Authority Typically a RGEA is tax exempt. A RGEA, as a political subdivision of the state, is recognized as a tax-exempt entity by the IRS. This tax-exemption does not derive from any specific provision in the federal tax law, but is the result of the doctrine of intergovernmental immunity--the doctrine implicit in the U.S. Constitution that the federal government will not tax states. The general principle is that the United States may not tax instrumentalities which a state may employ in the discharge of its essential duties. This tax exemption extends not only to the state but to integral part of a states such as political subdivisions, instrumentalities, agencies and the like. (The Law of Tax-Exempt Organizations, Bruce R. Hopkins, 6th Edition, 1992, John Wiley & Sons, Inc. §34.14) AG's opinion of June 7, 1976 concluded a RGEA may organize as a non-profit corporation per AS 10.20 and retain its status as a political subdivision. It is not clear that a RGEA formed as a for profit corporation would retain its status as a political subdivision. Legislative policy provides that public property used "for an essential public and government purpose" such as real property of a political subdivision (RGEA) may be exempt from taxation as provided by law according to AS 18.57.030. A RGEA is exempt from payment of taxes or assessments on property owned by the authority that is used for generation and transportation of electricity, for a period of twenty years from June 5, 1975. Therefore, it would appear that the property of a RGEA may be subject to local taxation after June 25, 1995. A RGEA is not required to pay the state mill rate tax per kilowatt hour charged to a cooperative. 3.2.5.2. APUC Regulation A RGEA as a political subdivision, is exempted from APUC jurisdiction per AS 42.05.711(b) so long as the RGEA is not in competition with any other utility. A RGEA is, however, still required to obtain a certificate of public convenience and necessity before it can begin operating as a utility. The board of commissioners of the RGEA will be responsible for setting the rates charged to consumers. 3.2.5.3. Financing Alternatives A RGEA is considered a political subdivision of the state and may therefore, issue tax 3-12 exempt revenue bonds to obtain funds to achieve the purpose of the corporation. The interest rate paid on the bonds will be determined by the board of commissioners. Bond maturity date may not exceed 50 years. While AS 18.57.050 (b) authorizes a RGEA to secure bonds and notes with not only the revenues generated by the RGEA, but also property of the RGEA, this statute may conflict with, Art. 9, Section 9 of the Alaska Constitution which restricts a political subdivision, RGEA in this case, to pledging only the revenues generated by the RGEA for capital improvements unless ratified by a majority of the members qualified to vote. Therefore, it would appear that the only security which can be pledged for revenue bonds sold for capital improvements would be the revenues of the RGEA unless members ratified the bond sale. Typically this would not present a problem, as generally, the actual membership of a RGEA would be restricted to only a few individuals such as selected representative(s) from each of the villages served by the RGEA or selected representatives of the authority forming the RGEA. A RGEA may also qualify for financing from the following sources: Rural Electrification Administration (REA); REA supplemental lenders; commercial banks; federal and state grant or loan programs. In general a RGEA may secure financing through debt (i.e. by borrowing money) which is secured by a mortgage, pledge or deed of trust and by the sale of tax exempt bonds as previously discussed. A RGEA is not authorized to obtain financing through the sale of stocks. 3.2.6. MUNICIPAL CORPORATION A municipal corporation formed pursuant to AS 29.05, could also provide regional electric utility services under its powers as a political subdivision of the state. Since a municipal corporation is considered a political subdivision of the state it is a tax-exempt entity and can sell tax exempt bonds. However, in order to form a municipal corporation it would be necessary to undertake a lengthy formal process, which includes filing a petition with the state, public hearings, and holding an election to allow the voters who live within the boundaries of the proposed municipal corporation to accept or reject the proposed municipal corporation. Since there are significantly less burdensome alternatives for forming a regional electric utility, which enjoy the same tax benefits as a municipal corporation, such 3-13 as a RGEA as discussed in the preceding paragraph, the formation of a municipal corporation will not be pursued. 3.3. APUC CERTIFICATE OF CONVENIENCE AND NECESSITY Regardless of what organizational form is selected for a regional utility, it will be necessary for the utility to obtain a certificate of convenience and necessity from the APUC before the utility can begin operating and receiving compensation for providing a commodity or service. To obtain the certificate it will be necessary for the new utility to demonstrate to the satisfaction of the APUC that it is "fit, willing and able" to perform the duties of the utility, and that it is in the public interest to issue the certificate. The "fit" requirement is an important test to the Commission because it means "the ability to finance" and ability to repay debt service as well as pay for all utility operating expenses. The "willing" requirement generally only requires the signature of the entity that desires to provide the service. The “able" requirement is also important because the Commission will carefully scrutinize the expertise and experience of the personnel responsible for managing and operating the new utility before issuing the certificate. The commission may issue a certificate in whole or in part and attach terms and conditions the commission considers necessary to protect and promote the public interest including the condition that the applicant serve an area or provide a service not contemplated by the applicant. As part of the application for a certificate a new utility will generally need to provide the APUC with a complete tariff document, financial forecast and an engineering report. The tariff document must contain a map or maps clearly delineating the boundaries of the area to be served by the utility and a complete set of regulations governing the services offered by the utility. The tariff must also set out schedules of rates and charges for each class of service offered, conditions of service, rules for line-extensions, service connections, billing and collection, and the consumer complaint process among others. The financial forecast should project the utilities revenues, expenses and earning for a period of ten years. This forecast demonstrates that the new utility's future revenues will be sufficient to repay debt service, operations, maintenance and administrative cost. The engineering report would provide estimates of the start-up cost associated with constructing the necessary facilities to 3-14 produce and deliver electricity to the consumer, including any cost of mitigating environmental effects. 3.4. SOURCES OF FINANCING An important key to the successful business start-up and expansion is the ability to obtain and secure appropriate financing. This process can be complex and frustrating. This report will attempt to briefly identify sources of financing and the advantages and consequences associated with each type of financing. There are several sources to consider when looking for funding. It is important that each option available is explored before making a decision. There are basically three alternatives available for financing a regional electric utility. These may be classified as direct loans, sale of stocks and bonds, or grants. These alterna- tives are discussed in various degrees in the subsequent paragraphs. 3.4.1. Grants It may be possible to obtain grant funds from either the State of Alaska or the federal government. Grants may be in the form of monies or equipment. For example, THREA obtained three surplus diesel generator sets from the Atomic Energy Commission. A detailed discussion of the availability of grant funds is beyond the scope of this report and only the following potential sources will be discussed. 3.4.1.1. Alaska Energy Authority/Department of Community and Regional Affairs The Alaska Energy Authority (AEA) has been a source of grant funds for rural electrification. However, the 1993 Alaska legislature chose to reduce AEA's involvement in the rural electrification program and the legislature elected to transfer responsibility for the tural electrification program to the Department of Community and Regional Affairs (DCRA). Transfer of all rural electrification projects to DCRA is scheduled to be accomplished prior to December 31, 1993. It is uncertain as to the amount of support and grant fundings which may be available through DCRA to assist with regional electrification. 3-15 3.4.1.2 National Rural Electric Cooperative Association Limited grant funds may also be available from the National Rural Electric Cooperative Association (NRECA) for constructing a portion of the Single Wire Ground Return (SWGR) transmission line. The NRECA is presently investigating the economic feasibility of constructing SWGR lines in underdeveloped countries as a less costly alternative to conventional three phase power. 3.4.1.3 Alaska Science and Technology Foundation Council (ASTF) Another source of funding may be the Alaska Science and Technology Foundation Council (ASTF). The ASTF may partially fund the development of new products. The ASTF may be interested in partially funding the research and development of low cost, single phase to three phase conversion equipment, which is needed to interface SWGR lines with small three phase systems such as Bethel utilities. This conversion equipment could then be sold in underdeveloped countries where SWGR lines are constructed. 3.4.1.4. TITLE XXVI - Indian Energy Resources Title XXVI has been enacted into law, however, it is uncertain as to whether any funds have been appropriated. This amendment would create a demonstration program to assist Indian tribes” in pursuing energy self-sufficiency and to promote the development of a vertically integrated energy industry on Indian reservations, in order to increase development of energy resources. The amendment contains a provision which would provide development grants to Indian tribes or to joint ventures which are 51 percent or more controlled by an Indian tribe to assist Indian tribes in obtaining the managerial and technical capability needed to develop the energy resources on Indian reservations. Such grants shall include provisions for management training for tribal or village members, improving the technical capacity of the Indian tribe, and the reduction of tribal unemployment. The grants shall be for a period of 3 years. The 2 The provision includes land held by incorporated Native groups, regional corporations, and village corporations under the provisions of the Alaska Native Claims Settlement Act. 3-16 grants would not exceed 50 percent of the project costs. 3.4.1.5. Chapter 45 - Rural & Statewide Energy Programs Several different sources of grant and loan funds may be available through Chapter 45 rural energy programs enacted by the 1993 legislature. These programs include: @ Power Project Fund (AS 42.45.010) @ Rural Electrification Revolving Loan Fund (AS 42.45.020) @ Grants for Utility Improvements (AS 42.45.180) @ Electrical Service Extension Fund (AS 42.45.200) @ Joint Action Agencies (AS 42.45.300) @ Assistance to Rural Utilities (AS 42.45.400) Each of these programs has specific qualifications and limitations. A detailed discussion of the availability of these particular grant and loan funds is beyond the scope of this report. However, these programs represent a potential source of grant funds and low interest loan funds that might be available to partially fund the construction of regional interties. 3.2.4.2. Stocks and Bonds Corporate Securities refers to the stocks and bonds issued by corporations. The securities issued by large, publicly owned corporations are owned by literally millions of different investors. On the other hand, all of the common stock issued by a small closely held corporation may be owned by one individual or company, or by a small group of investors. 3.2.4.2.1. Bonds Financially sound corporations may arrange limited amounts of long-term financing by issuing notes payable to banks or to insurance companies. However, when a corporation needs more capital than any single lender can supply, it will generally sell additional shares of capital stock or issue bonds (debt securities) payable. Absence of voting power in debt securi- ties as well as the income tax advantage has made debt financing almost the preferred method of raising corporate capital. 3-17 There are several advantages for issuing bonds instead of stock, which include: 1. Nonprofit corporations and RGEA's can issue debt securities to virtually the same extent as business corporations. RGEA's can issue tax-exempt bonds. Cooperatives may not issue bonds or stock as a method of financing. 2. Interest payments on notes, bonds and debentures like interest paid on loans from financial institutions are considered an expense of doing business and therefore are deductible for income tax purposes. Dividends paid to stock- holders are not deductible in computing taxable income. 3. Holders of notes, bonds or debentures will have no voice in the selection of the directors or participation in any matters of corporate governance. 3.4.2.2. Stocks For the purpose of this study it is assumed that any utility subsidiary formed by Calista would be a closely held corporation in which Calista would retain all shares. There are few if any good reasons for Calista to sell or issue shares of stock in its utility subsidiary to other investors. For example, neither nonprofit corporations, cooperatives nor rural electric authorities are authorized to sell/issue stock and dividend payments to shareholders are considered distributions of corporate profits and are not deductible for income tax purposes. The preferred method for raising capital would be through the sale of bonds, as previously discussed. 3.4.3. Loans Borrowing from financial institutions can be both secured and unsecured. Unless the corporate business is very well established so that the corporation has an outstanding credit rating, most loans by financial institutions to corporations will be either secured by a lien or mortgage on the corporate assets or guaranteed by individuals having an interest in the corporation. The lending agency may place a requirement that the corporation maintain a 3-18 certain amount on deposit with the financial institution until the debt is paid. The primary lender of funds to rural electrical utilities is the Rural Electrification Administration (REA). The requirements to obtain loans and type of loans available from REA are discussed in some detail below. 3.4.3.1. Rural Electrification Administration - REA REA makes loans and loan guarantees to finance the construction of electric distri- bution, transmission and generation facilities, including system improvements and replacements, required to provide adequate electric service in rural areas. It is important to understand that REA does not lend money for start-up operations of a new utility or in advance of construction. The REA program is set-up to reimburse utilities after construction of individual projects is completed, which means construction loans must be secured in advance of construction from a supplemental lender. The supplemental lender must be ap- proved by REA. There are several pre-approved lenders such as the National Rural Utility Cooperative Financing Corporation (CFC) for supplemental loans. For cooperatives there are several banks available including CoBank and National Cooperative Bank. A few of the organizations REA makes loans to are as follows: corporations, municipalities, cooperatives, and nonprofit organizations, that provide or propose to provide retail electric service needs of tural areas or power supply needs of distribution borrowers. (7 CFR Part 1710.100) It is highly probable 0% and 2% interest REA hardship loans will be discontinued. The 2% loans would be replaced by a 5% hardship loan program, funded at $125 million annually. To qualify for a 5% hardship loan a utility must meet three requirements: 1) have residential revenues per kwh that is at least 20% above the average for all utilities in the state; 2) have total revenue per kwh that is at least 20% above the average for all utilities in the state; and 3) have lower per capita income or lower median family income among its consumers than the state average. For an electric utility to become a qualified REA borrower, it must obtain a feasibility study to illustrate that the new utility's future revenues will be sufficient to repay the REA loans, plus cover all operations, maintenance and administrative costs. An APUC certificate must be obtained and an REA loan application must be submitted. The completion of the 3-19 loan package is a straight-forward exercise, but it is difficult to gain approval. Most important to the approval process is the financial and environmental feasibility studies. REA has been very reluctant to approve new REA borrowers unless it believes the security of the mortgage is absolutely clear. The loan approval process may take up to two years or more. REA assists with two types of loans; insured loans and loan guarantees. Insured loans are for a term of up to 35 years at the standard REA interest rate. It is probable REA's current 5 % loan program will be replaced with a $600 million annual program issuing loans with interest rates tied to the current market yield on municipal bonds (currently about 6 %). An insured loan is generally made for the extension and improvement of electric facilities in rural areas. REA also provides 100 and 90 percent loan guarantees (principal & interest) to enable borrowers to secure financing from certain private lenders. The loan guarantees are made for a term of up to 35 years, and the interest rate is established at a rate agreed to by the borrow- er and the lender, with REA concurrence. To secure its loan, REA will insist on having first lien rights on the borrower's total system or other adequate security. In addition, REA will require the borrower to maintain adequate financial and managerial controls. Loan funds may be used to finance distribution facilities; transmission and generation facilities; ordinary plant replacements; warehouse and garage facilities. The funds may be used for the construction of new transmission and generation facilities or systems and the purchase of an ownership interest in new or existing transmission or generation facilities to serve REA consumers. Generally REA will not loan to utilities which provide "adequate central station service." However, utilities serving Alaska's remote villages may gain access to additional REA loans. Most Alaska communities have some sort of central station service and these utilities have gone through a complex process of proving the service is "inadequate," in order to obtain REA financing. This process may become easier since the language in the new legislation would clarify that these areas are eligible for REA assistance. However, it is unlikely REA would loan Calista any funds to purchase Bethel Utilities, since the service provided by Bethel Utilities would be classified as "adequate central station service." REA might, however, assist Calista in obtaining financing from REA approved lenders. In the event 3-20 REA did loan funds for the acquisition of Bethel Utilities, the maximum amount REA will lend is the value of the property. The borrower will have to provide the remainder of the costs without REA financial assistance. On the other hand, REA is likely to provide loan funds for the construction of the Nyac Hydro project and construction of a transmission line to interconnect the hydro and outlying villages to central station service at Bethel. There is, however, a caveat to this statement. If village electric systems are upgraded to provide “adequate central station service," REA probably would not loan funds for either the transmission line or Nyac hydro. 3.4.3.2. TITLE XXVI - Indian Energy Resources This 1992 amendment would provide for a demonstration program to assist Indian tribes in pursuing energy self-sufficiency and to promote the development of a vertically integrated energy industry on Indian reservations, in order to increase development of energy resources. A provision of the act would provide low interest loans to Indian tribes or Alaska native corporations to promote energy resource exploitation, development and vertical integra- tion. Proposed appropriations are $10,000,000 for each of the fiscal years 1994, 1995, 1996, 1997, 1998, and 1999. In addition, the proposal also provides for grants for the education of employees responsible for enforcing or monitoring compliance with Federal and tribal laws and regulations in relation to the development of tribal inventories of energy resources; ‘environmental quality and enforcement. 3-21 3.5. RANKING THE BUSINESS ORGANIZATION In an attempt to develop an objective yardstick with which to measure the information presented in the preceding paragraphs, Table 3.1 was developed. The table attempts to logically rank each of the four organizational structures examined on the basis of numerous factors which are listed along the left hand side of the table. A point score was assigned to each of these factors. The assigned score was either a 0,1, or 2, with zero being the lowest score and 2 the highest score. The point scores assigned to the various factors for each of the four organizational structures were then totaled. The point score totals were then evaluated from the perspective of both a Calista operated enterprise and a nonprofit enterprise. A Calista enterprise can be considered as either a for-profit or nonprofit “subsidiary” formed by Calista Corporation for the purpose of operating a regional electric utility. A nonprofit enterprise is defined as a not-for-profit utility organized independent of Calista Corporation. The evaluation produced the following relative ranking. The relative ranking of the four organizations are shown in Figure 2.1. These rankings should be used for comparison purposes only and is not intended as an unconditional recommendation. However, the rankings do suggest that an electric cooperative is the least desirable alternative for establishing a nonprofit regional electric utility and the nonprofit or RGEA Calista "subsidiary" is the most desirable. Therefore, the cooperative organization can be eliminated as a viable alternative and will not be investigated further. While a for-profit "subsidiary" received the lowest score it is the customary business organization used for operating a for- profit utility. Calista Enterprise Nonprofit Enterprise Nonprofit "Subsidiary" Nonprofit & RGEA® For-Profit "Subsidiary" Cooperative 3 Operating as a non-profit corporation. 3-22 Ease of Form Formation Income Producing for Calista Federal Tax State Tax State Grants Federal Grants Indian Energy® Resource Grants Issue Stocks Issue Bonds Eligible for REA Loans Indian Energy6 Resource Loans APUC Regulated Power of Eminent Domain Certificate of Convenience & Necessity TOTAL TABLE 3.1 For-Profit Nonprofit Corp. Corp. Cooperative 2 2 1 1 1 o® ° 2 2 ° 2 1 1 2 2 1 2 2 2 2 2 1 O° Oo 1 2 ° 1 2 2 2 2 2 ° fe) 1 2 2 2 ° ° ° 14 21 17 4. Organized as a nonprofit corporation. 21 Scoring Criteria 0=Difficult to 2=Simple to Form O=No Income 2=Max. Income O=Taxable 2=Tax-Exempt 0=Taxable 2=Tax-Exempt O=Ineligible 2=Eligible O=Ineligible 2=Eligible O=Ineligible 2=Eligible 0=Ineligible 2=Eligible 0=Ineligible 2=Tax-Exempt 0=Ineligible 2=Eligible O=Ineligible 2=Eligible O=Full Regulated 2=Unregulated O=Not-Authorized 2=Authorized O =Required 2=Not Required 5. Potentially income producing if G&T utility should contract for management services with Calista Corporation. 6 Grant and Loan Funds contingent on approval of pending amendment to Title XXVI-Indian Energy Resources 3-23 3.6 RECOMMENDATIONS Although the nonprofit Calista "subsidiary" and the RGEA are equally ranked, it is recommended that the nonprofit "subsidiary" be selected as the vehicle for creating a regional utility. The benefits of selecting a nonprofit Calista "subsidiary" over the RGEA include the ease of formation, affirmative control over development and minimum outside interference. 3-24 4.0. FORMING A "FULL SERVICE" REGIONAL ELECTRIC UTILITY 4.1 INTRODUCTION Two approaches in Alaska have proven successful in reducing the cost of electricity in rural villages. These are regionalization and interties. Regionalization involves several villages, which normally operate a stand alone diesel generation plant and distribution system to satisfy their electrical power requirements, joining together to form a regional utility which is then operated as a single business organization. Regionalization lowers energy costs to the participating villages by eliminating needless duplication of management, administrative costs, certain operational costs, and increases financing and purchasing capabilities. In addition regionalization increases political clout and the ability to hire and retain professional management and operation personnel. Interties involve the construction of transmission lines which interconnect villages and towns to larger more efficient centralized power plants. The benefits of interties are well known. They allow transfer of lower cost energy to high cost areas and consolidate a large enough customer base to make it economically feasible to develop projects which are capital intensive to construct but produce lower cost electricity, such as hydroelectric projects. However, just as important, interties reduce the need for stand alone generation systems in the villages and reduce the need to maintain large on-site fuel storage facilities in each village and the associated fuel spill liability. 4.2 BASIC APPROACH TO FORMING A REGIONAL ELECTRIC UTILITY While generation, transmission and distribution services are provided in the Bethel area, no single entity offers all three services. Bethel Utilities and most villages provide a combination of generation and distribution services, but not transmission services. Although there are short "transmission"! lines extending south of Bethel that interconnect the villages of Napakiak and Oscarville to Bethel Utilities, these lines are not owned by Bethel Utilities. At present no single organization exists that is effectively serving the needs of the Bethel region. However, Calista, 1 Although these two lines operate at distribution voltage levels they will be classified as transmission lines because their function is to transport bulk power from Bethel to the villages of Oscarville and Napakiak. 4-1 Corporation or another interested party, could undertake the appropriate steps to form and operate a "full service"? Regional Electric Utility (REU) which could effectively service’ the total electrical requirements of the entire Bethel region, including those of Bethel. A "full service" REU, which prudently combines the advantages of regionalization with the advantages of interties, should prove successful in lowering the cost of electric energy to all consumers within the region. The subsequent paragraphs outline a three staged-approach by which a "full service" REU could be formed and operated in the Bethel region. At the end of the third stage, this report envisions a for-profit subsidiary of Calista Corporation - "Calista Utilities" - owning and operating the REU. The types of services provided at each Stage of development are also described. It is anticipated that Stage two would be fully implemented within two or three years after Stage one had been completed. The time table for accomplishing Stage three is estimated at three to five years after the completion of Stage two. The management and financial implications associated with each of the three stages of development will be addressed at length in later sections of the report. Figure 4.1 contains block diagrams outlining the three stages to forming a "full service" REU. Stage 1 -- Involves the formation of a “limited service" nonprofit generation and transmission (G&T) utility which would construct, own and operate the Nyac hydroelec- tric plant, and a transmission intertie between Bethel and the Nyac hydro. The nonprofit G&T could be formed as either a nonprofit "subsidiary" of Calista Corporation or by an RGEA. These facilities would serve the seven villages addressed in the Bethel-Nyac 2 A utility that provides generation, transmission and distribution services will be referred to as a "full service" utility. A utility which provides less than full service will be classified as a "limited service" utility. 3 There are basically three broad classes of services provided by electric utilities. These may be classified as generation, transmission and distribution services. Generation involves the production of electricity. The difference between a transmission system and a distribution system depends on the function. The function of a transmission system is to transport bulk power to load centers. Typical transmission voltages range from 34.5 kV upwards. Distribution includes all parts of an electric utility system between the bulk power source and the consumers meter. The function of a distribution system is to receive electric power form bulk power sources and to distribute it to consumers at voltage levels acceptable to the various types of consumers. Distribution systems generally operate at a voltage levels below 25 kV. 4-2 THREE STAGES TO FORMING A “FULL-SERVICE” REU STAGE 1 Form Limited Service Nonprofit G&T Utility Bethe! Utilities Bulk Power Sales & Purchases Bulk Power Sales to Villages ‘With Bethel Utilities STAGE 2 Non-Profit Utility Acquires Independent Village Utilities Bulk Power Sales to Villages Bo are] With Bethel Utilities STAGE 3 Calista Corporation Acquires Bethel Utilities and Nonprofit Utility Forming For Profit REU Calista Utilities Non-Profit Utility Retail Power Sales to Individual Consumers Retail Power Sales to Individual Consumers FIGURE 4.1 Transmission Line Feasibility Report and the Nyac mining camp. The transmission line would intertie the Nyac hydro site with Bethel and provide bulk power to the seven villages served by the transmission line. The G&T would own and operate the stepdown substations at each village and Bethel. The G&T would wholesale electricity generated by the Nyac hydro plant directly to the villages and to Bethel Utilities during the summer months. During the winter months when the output from the Nyac hydro would be insufficient to supply the load requirements, the G&T would purchase power from Bethel Utilities for resale to the villages.* Village generators would only be run in the event of an emergency or for testing and maintenance. The G&T would not own or operate the distribution systems within the villages and each village would continue to operate its electric utility independent of other villages and the G&T. Bulk power purchased by the villages from the G&T would displace power normally generated by village diesel plants. Village utilities would remain responsible for processing and collecting PCE payments from the state. Stage 2 -- At the second stage of development, the nonprofit G&T utility would acquire and operate the electric utility systems in the seven villages served by the transmission line. Having acquired the electric utility systems in the villages, the G&T would no longer wholesale electricity to the villages directly, but would instead sell at the retail level to the individual village consumer. Any costs associated with acquiring the village system would be amortized over a number of years. Each village would be required to finance the sale of the village electric system to the nonprofit G&T and would receive yearly or monthly payments from the G&T. The G&T would provide all the required management, administrative and operational services, including the processing and collection of PCE payments from the state. Villages would no longer be primarily responsible for any 4 The construction of a new diesel plant or the operation of existing village diesel plants by the G&T, during the winter months was investigated as an alternative to purchasing village energy requirements from Bethel Utilities. However, an analysis of this alternative revealed that this approach was uneconomical as compared to purchasing village energy requirements from Bethel Utilities. Lower generation efficiencies and higher maintenance cost as compared to Bethel Utilities, plus the labor cost associated with hiring sufficient plant operators to man the G&T diesel plant on a full time basis, resulted in energy cost that exceeded the cost of energy purchased from Bethel Utilities. 4-4 aspect of the village electrical system. At this point, the nonprofit G&T utility would effectively be operating as a “full service" utility. However, since the G&T would only be providing limited services to Bethel, it should not be viewed as a fully functioning REU. Stage 3 -- Calista Corporation forms "Calista Utilities" as a for-profit subsidiary corporation. Calista Utilities acquires the nonprofit G&T utility and Bethel Utilities. Calista Utilities’ would operate as a "full service" REU, providing services to the regional villages served by the transmission line® and to the city of Bethel. All required manage- ment, administrative, operational and maintenance services for operating the REU would be provided by Calista Utilities. At the completion of Stage 3, the primary objectives of forming an REU would have been achieved -- the consolidation of utility services in the Bethel region and the elimination of needless duplication of effort. 4.3 OBSTACLES TO REGIONALIZATION While the formation of a regional electric utility may result in lower cost electricity for the individual consumer, the village corporation, local government, or municipality that owns and operates the village electrical systems, is likely to experience a decline in revenues with the loss of PCE payments. PCE payments will presumably cease either because: (1) the state will terminate PCE payments once a village has access to reasonable cost electric energy; or (2) if PCE payments are continued, these payments will be paid directly to the G&T or REU. PCE payments received by villages, local governments and municipalities are frequently used to fund the local government and offset the cost of other essential services such as water and sewer. Village councils may be reluctant to support a regional electric utility unless this loss of PCE is somehow offset by income from other sources, such as through revenues received from the sale of the village electric utility system to the G&T. 5 As an alternative, the nonprofit G&T could purchase Bethel Utilities and operate as a "full service" REU. 6 Due to the limited funds available only those seven villages addressed in the Bethel-Nyac report have been considered in this study. 4-5 4.4 OPTIONS TO A REGIONAL ELECTRIC UTILITY If a regional electric utility is not formed, then villages in the Bethel area should consider using the management services of an existing electric utility to manage and operate the village electric systems. Three utilities which could provide these services are Bethel Utilities, THREA and AVEC. Past discussions with Bethel management indicates they are less than enthusiastic about providing these type services, however, Bethel Utilities has been hired on occasion to provide maintenance on the power line extending between Bethel and Napakiak. THREA has expressed interest in providing both management and operational support to villages located in the Bethel area. THREA is presently providing such services to other communities located in southeast Alaska. The primary disadvantage of using THREA is the geographic distance separating THREA from Bethel. AVEC has recently implemented a more aggressive policy to add new member villages. Effective July 93, Breig Mission will be the latest addition to AVEC. Ekwok may follow in 1994. Since AVEC is serving other villages in the Bethel area, AVEC would be the logical choice to either provide management and operational support to the villages or add the villages as new AVEC members. It is estimated that AVEC's average cost of energy in 2014 will be approximately $0.65/kWH. This compares to $0.85/kWH in 2014 in villages that continue to operate independent electric utilities. Therefore, should a village elect to join AVEC or use AVEC to provide management and operational services, the cost of energy in the village could conceivable be reduced by as much as twenty cent per kWH in 2014. A village requesting service from AVEC will need to generate sufficient revenues to amortize the investment in the facilities required for electrification. The village must also be served by major air and water transportation routes. Typically, an air terminal in the village is necessary to fly in small parts for routine maintenance, and a navigable waterway is necessary to barge in generation units and large tanks required for bulk fuel storage. 4.5. SINGLE WIRE GROUND RETURN TRANSMISSION INTERTIES In forming any regional electric utility, careful attention should be given to the type of generation, transmission and distribution systems that will be constructed to provide these services. In a region where distances between villages are large and loads are small, it is important to recognize that the application of standard off-the-shelf design or conventional 4-6 engineering practices may result in systems that are over engineered and uneconomical. In a time of dwindling prosperity, it is not enough to simply construct an electric system that can deliver lower cost electric power to isolated villages, but it is equally important to ensure that each dollar spent brings the maximum benefit to the maximum number of consumers. Innovative solutions that vary from conventional norm may be required if any regional electric utility is to survive in the harsh economic realities of western Alaska. One such innovative solution is the Single Wire Ground Return (SWGR) transmission system. While the use of a single energized wire and the earth as a return circuit is unconven- tional in the sense that the application is not common, it is an accepted system of proven use in many areas of the world.’ An 8.5 mile demonstration SWGR project was constructed between Bethel and Napakiak in 1980 and has been operating for approximately thirteen years, safely, economically and reliably, delivering lower cost electric energy from Bethel to Napakiak. This study assumes the transmission intertie between Bethel and the Nyac Hydro will be constructed as an SWGR system. The SWGR system was selected for the transmission intertie because it is approximately three million dollars less costly to construct than a conventional three phase transmission line. The SWGR system proposed for construction would be similar in design to the existing system interconnecting Bethel and Napakiak and would in no way create an operating system with a lesser safety than the "conventional" systems now in use throughout Alaska.* An expanded description of the SWGR transmission system is attached as Appendix B. 7 The National Rural Electric Cooperative Association (NRECA)is presently evaluating the economic and technical feasibility of using SWGR transmission systems as a means of providing electrical service to rural, sparsely populat- ed areas in various countries throughout the world. 8 While the fifth edition of the National Electric Safety Code (NESC) allowed the use of the earth as a return conductor for a power circuit in rural areas, the most recent code does not. In order to construct the experimental SWGR line between Bethel and Napakiak it was necessary to obtain a waiver to the NESC from the State of Alaska, Department of Labor. It is anticipated that a similar waiver would be required to construct and operate any new SWGR line within the State. 4-7 5.0 MANAGING THE UTILITY 5.1 INTRODUCTION In addition to selecting the most appropriate organizational structure by which to form and operate a regional electric utility, it is equally important to select a proper management structure which is capable of achieving the goals of the regional utility. Effective management must take place within the context of basic corporate objectives. The basic management structure of any corporation should be set out in the Bylaws. Both for-profit and nonprofit corporations are largely governed by the terms of the bylaws. The bylaws will be especially important for a nonprofit corporation where there is little or no membership participation and the board of directors are given virtually exclusive management control. There are two distinct management structures that will be addressed and compared in this study. The first of the management structures discussed will be described as "in-house" management and would consist of using permanent employees to provide all the functions necessary to effectively operate the utility. The second type of management structure to be discussed will be described as "contract management" and would utilize the services of an outside firm to provide all but the most essential management functions of the utility. The term management structure is used in a general sense, and is intended to include all the usual management, administrative, operational and maintenance tasks typically performed by employees of a utility. 5.2 IN-HOUSE MANAGEMENT The actual number of in-house employees needed to manage and operate a regional electric utility would vary depending on the stage of development. It is assumed the three stage approach as outlined in the previous sections will be implemented whether the utility is organized as a nonprofit corporation by Calista Corporation or a RGEA. Estimated staffing levels at each stage of development are listed below. These staffing levels would be required whether the regional utility was organized as a nonprofit utility by Calista or a RGEA. The organizational chart for each of the three development stages are shown in Figures 5.1, 5.2 and 5.3. Typical staffing levels at other utilities serving between 1000 and 2000 consumers, generally consists of a General Manager, Financial Officer, Office Manager, Billing Clerk, Data Entry Clerk, General Office Clerk, Customer Service Coordinator, Accountant, Board Secretary and Secretary. Operational staff generally consists of an Operations Manager, Generation Manager, plant operators and linemen. Stage 1 Development -- At this stage of development the nonprofit G&T utility would be responsible for managing and operating the Nyac hydroelectric plant, the transmission intertie between Bethel and the Nyac hydro plant, the stepdown substation located at Bethel and each of the villages. The G&T would wholesale bulk power to the seven villages, Nyac and Bethel for a total of nine customers and would purchase power from Bethel for resale to the villages. It is estimated the basic management structure which would be necessary at this stage of development would consist of a General Manager, a Finan- ORGANIZATIONAL STRUCTURE REU STAGE1 cial Manager and the Execu- NON-PROFIT G&T UTILITY tive/Board Secretary. The general manager selected for the position must be familiar with all aspects of a utility. As part of his duties the gen- eral manager would be re- sponsible for preparing work plans, non-financial reports, Contract Services and contracting for necess . mi FIGURE 5.1 materials, supplies, inspection, maintenance and repair services. The financial officer would be responsible for preparation of financial reports, all aspects of budgeting, accounting, including billings and collections for the G&T's nine customers. The management and administrative office would be located in Anchorage. The nonprofit G&T could rent office space from Calista Corporation. Repairs, maintenance and inspections of the transmission line, eight stepdown substations and the Nyac Dae hydro plant and substation would be performed by contract personnel.’ Each village utility would remain responsible for maintaining and operating the distribution system, customer billings and for collecting PCE payments. For economic reasons the regional G&T should probably contract with the village utilities to obtain monthly meter reads of power sales to the village. The meter would be located at the stepdown substa- tions. These monthly REU STAGE 2 NON-PROFIT G&T UTILITY meter readings could be called in or mailed to the Anchorage office. The number of full-time staff required for operat- } Chief Village Operator i ing a Stage One, non- profit G&T utility would total three. i | Stage 2 Development -- yt 1 J At this stage of devel- opment the nonprofit . Fea Srilrees Village Operator G&T would acquire and operate the electric util- ee ity systems in each of Village Operator the seven villages. In FIGURE 5.2 addition to the staff as discussed above, the Stage Two, non-profit G&T would need to employee a village operator on a one-half time basis, in the seven villages to read meters, operate the village power plants during emergencies, and provide meter connect and disconnect services. The nonprofit G&T would no 1 The Nyac hydroelectric plant would be designed for remote operation. However, routine inspection and maintenance would be accomplished on a semi- annual or quarterly basis. o=9 longer wholesale energy to the villages but would instead sell at the retail level directly to the individual consumers. There is an estimated 700 consumers in the seven villages. In order to provide adequate administrative services to its consumers the G&T in addition to increasing its operational staff, must also increase the management and administrative staff to include a Billing /Data Entry Clerk, General Office Clerk, and a Customer Service Coordinator. At stage two of the development the staff of the nonprofit G&T would resemble the management, administrative and operational staff of other utilities with the same customer base. All management and administrative functions would be performed in Anchorage. The nonprofit G&T could rent office space from Calista Corporation. The equivalent number of full-time staff required for operating the utility at the Stage Two development would total nine and one-half. At this point, the non- profit G&T utility would effectively be operating as a “full service" utility. However, since the G&T is only providing limited services to Bethel, it should not be viewed as a fully functioning REU. Stage 3 Development -- At this last stage of development Calista Corporation forms Calista Utilities as a for-profit subsidiary corporation. Calista Utilities acquires the nonprofit G&T utility and Bethel Utilities. Calista Utilities would operate as a “full service" REU, providing services to the regional villages served by the transmission line and to the city of Bethel. All required management, administrative, operational and maintenance services for operating the REU are provided by Calista Utilities. The REU would serve approximately 2500 consumers, 1800 in Bethel and 700 in the seven intertied villages. Staffing requirements would be similar to those discussed in the Step Two development phase with the exception of the following changes. An Administrative secretary, an Operations Manager, two linemen and seven operator/mechanics would be added to the staff. Excluding the seven part-time village operators, the staffing of the REU closely resembles the existing staff of Bethel Utilities. At this stage it would also be prudent to hire an staff engineer and another secretary that would be shared by the staff engineer and the operations manager. The staff engineer would oversee the design and construction of new and replacement facilities. With the addition of a staff engineer and secretary, the number of full-time staff required for operating a "full service" REU would total twenty two and one-half. Calista Utilities would in effect be providing management services for the entire Bethel region, 5-4 accomplishing — the primary objectives ORGANIZATIONAL STRUCTURE of the Three Stage REU STAGE 3 development plan. FOR PROFIT UTILITY The operations man- CALISTA UTILITIES Board of Directors ager and staff engi- neer should be based in Bethel. Operations and maintenance person- nel would be based in Bethel. The re- mainder of the man- agement, adminis- trative and financial functions could re- main in Anchorage. 5.3. CONTRACT MANAGEMENT SERVICES There may be advantages to uti- lizing the services of Contract Services Half Time Employees an outside firm to manage and operate the nonprofit G&T FIGURE 5.3 utility operating at a Stage One or Two development level. The utilization of contract services allows the organization to hire highly qualified personnel without having to pay the full costs of employee wages and 5-5 benefits. However, it should be recognized that once Calista Utilities begins operation as a “full service" REU in the Bethel region, outside contract management services would no longer be required. Except for the position of general manager and board secretary, all of the jobs performed internally could conceivably be provided by an outside organization.” A wide variety of strategic considerations will enter into the contract-out-decision. The decision must be based on an analysis which not only examines the potential savings to the utility, it must also carefully consider whether the utility can provide adequate and reliable service to its consumers, if the selected services are in fact provided by non-utility personnel. The analysis must determine whether a proportionate reduction in staff or the decision not to hire staff will actually reduce costs or simply redistribute the costs. Another important factor which must be considered in contracting out is the time period involved. An analysis invariably requires assumptions about the future, therefore, the longer the time period, the less reliable the results of the analysis. In the situation where the services can be provided by "in-house" personnel or an outside firm for basically the same cost, it would be necessary to examine the long term objectives of the organization. For example the nonprofit G&T operating at the Stage One or Two development level, may wish to contract-out these services, since the G&T is only a quasi-permanent organization, formed as a interim step in the development of a "full service" REU. The various services which could be provided by a contract management service are discussed below. Where appropriate, reasons for retaining the particular service "in-house" are included. An economic comparison of "in-house" versus contract management services will be performed in a subsequent Chapter of this report. STAGE 1 Development - An examination of the Stage 1 REU, organizational chart, Figure 5.1, reveals the management and administrative staff consist of a general manager, a financial manager and an executive/board secretary. As stated previously, neither the position of general manager or executive/board secretary should be contracted to an outside firm. However, the 2 The positions of general manager and executive/board secretary should remain "in-house" to maintain fiduciary control and to insure the nonprofit G&T utility is not perceived as a mere instrumentality of the parent corpora- tion or the organization providing the management services. 5-6 types of services provided by the financial manager such as accounting, payroll, purchasing, accounts payable, customer billings and collections could be provided by an outside firm. STAGE 2 Development - To augment the staff as discussed above, the G&T would need to increase its operational staffing level to include seven village operators on a one-half basis, and its administrative staffing level to include a Billing/Data Entry Clerk, General Office Clerk, and a Customer Service Coordinator. All of the services provided by these employees could be contracted to outside firms. The G&T could contract with village corporations for village opera- tors to read meters, operate the village power plants during emergencies, and provide meter connect and disconnect services. The administrative and financial services could easily be contracted to the outside organization providing these types of management services. STAGE 3 Development - At this stage, Calista Utilities would operate as a "full service" REU, providing services to the regional villages served by the transmission line and to the city of Bethel. All required management, administrative, operational and maintenance services for operating the REU would be provided by Calista Utilities and outside management services would no longer be required. Calista Utilities would in effect be providing management services for the entire Bethel region. While there are undoubtedly several organizations which could provide the required management services including Bethel Utilities, the only two organizations which will be considered in this report are Calista Corporation and THREA. The benefits and disadvantages of using each of these two organizations are discussed in the following sections. 5.3.1 THREA THREA has considerable experience in managing and operating utilities: THREA not only operates and manages its own utility it also provides these services to other utilities. These services include among others: total financial management services such as accounting, purchasing, accounts payable, and customer billings and collections; total operational services, including day-to-day operations and maintenance, meter reading, major diesel engine overhauls, and the preparation of various reports. Engine overhauls are provided by THREA's maintenance Sai, staff. Day-to-day operations and maintenance is provided by local individuals employed by THREA. While the use of THREA's management services may initially appear attractive, there may be considerable political, logistical and operations problems associated with a REU located in the Calista region using an organization to provide management services which is located in Southeast Alaska, over 800 miles from Bethel. For example, it is difficult to perceive how THREA could effectively and economically provide operational and maintenance support to the REU with existing THREA employees. THREA has acknowledged it would need to hire new employees in the Bethel area or contract with firms located in Bethel or Anchorage to provide these services. THREA management would need to familiarize themselves with the demands and nuances associated with operating a utility in a region where the weather conditions, environmen- tal, operational, engineering and logistical constraints are significantly different than those experienced in southeast Alaska. A difficult task to accomplish by long distance. Conversely THREA could effectively provide administrative services and financial management services to a Stage One and Two, nonprofit G&T for such tasks as accounting, purchasing, accounts payable, and customer billings and collections since only limited knowledge of the region is required to provide these types of services. There are, however, certain disadvantages associated with using THREA to provide financial and administrative management services. The dollars paid to THREA for such services would basically benefit THREA consumers and would not accrue to the benefit of Calista shareholders. Contracting with THREA for these services could simply result in a redistribution of dollars from the Calista region to THREA without a substantial reduction in cost. On the other hand, contracting these services to Calista Corporation could result in increased corporate profits, which should directly or indirectly benefit the shareholders of the region. Another disadvantage of contracting with THREA for Stage One and Two financial services instead of Calista, is Calista would not have the opportunity to accumulate necessary expertise in the financial management of a utility. A careful reading of AS 18.57 also raises a potential jurisdictional question involving THREA's statutory authority to provide contract management service for utilities located outside the operating area of the regional housing authority which formed THREA. AS 18.57 would 5-8 appear to limit THREA's jurisdiction for providing electric utility services to all or part of the operating area of the regional housing authority which formed THREA. It is unclear whether this restriction would apply to contract management services. 5.3.2 Calista Corporation One of the primary long term objectives of Calista Corporation is to acquire Bethel Utilities or construct and operate a major coal or gas fired generation facility’ in the region, if Bethel Utilities cannot be acquired at a reasonable price. Since Calista aspires to become a principal participant in the electric utility industry within the Calista region, it would seem prudent for Calista to begin accumulating the necessary expertise. Furnishing management services to a Stage One and Two nonprofit G&T would be an excellent opportunity to acquire this expertise. During these two transition stages, Calista could provide the G&T with financial management services for accounting, purchasing, accounts payable, customer billings and collec- tions and prepare the required financial reports. Although Calista has little experience in providing the type of financial management services required by a utility, Calista could readily contract with THREA or another utility to instruct and assist Calista in initiating these services. The knowledge and experience acquired by Calista during this transition period, would provide Calista with the necessary background to furnish complete financial services for the "full service" REU formed by Calista in Stage 3 of the development plan. Additionally, with some guidance and direction from THREA or another utility, Calista could easily assist a Stage One and Two, nonprofit G&T with logistical operational and maintenance support. 5.4 RECOMMENDATIONS After careful analysis of the information presented above it is concluded that Calista Corporation, under the guidance of THREA or another utility, should provide the management services for a Stage One and Two, non-profit G&T. Fumishing these services would allow 3 As a possible energy resource for supplying the space heating and generation requirements of the region, Calista Corp. is presently investigating the availability of shallow natural gas within the Calista region. In addition Calista Corp. is working with various federal agencies to determine the feasibility of developing a small coal fired plant that would generate the electrical power requirements of the region. 5-9 Calista to acquire the knowledge and experience needed to manage and operate a "full service" REU. Although Calista has little experience in providing management services for an electric utility, Calista is inherently familiar with the demands and special requirements associated with the region and this advantage alone, will outweigh any disadvantage associated with Calista's inexperience. 5-10 6.0. FINANCIAL ANALYSIS 6.1 INTRODUCTION This section contains a summary of the financial forecast and consumer rates calculated for the various alternatives investigated and REU development stages. The analysis assumes future electrical energy requirements for the villages of Akiachak, Akiak, Kwethluk, Tuluksak, Napaskiak, Oscarville, Napakiak and the mining camp of Nyac (Villages) will be supplied by either continued diesel generation at each village or a regional transmission system. The regional transmission system would intertie the Villages with a hydroelectric plant at Nyac and/or a centralized diesel generation facility at Bethel. Usable energy output from the Nyac hydro is estimated at 5000 MWH per year. These villages were chosen as the "core" of the regional utility study because a recent report entitled Bethel - Nyac Transmission Line Feasibility Report demonstrated that it would be economically feasible to serve these villages from a transmission line extending between Bethel and Nyac. It is assumed the hydro operates for only 7 months of the year, from mid-May through mid-November. The study does not include the costs associated with renovating or expanding fuel storage facilities in the villages. A detailed listing of parameters and assumptions used in the financial forecast model and for calculating the cost of service for the three consumer classes can be found in Appendix A. A comprehensive description of each alternative and a discussion of the results obtained in the analysis for each alternative is presented in the subsequent paragraphs. Individual village power requirements and a map showing the proposed transmission interties can be found in Appendix C. 6.2. DESCRIPTION OF ALTERNATIVES AND DISCUSSION OF RESULTS 6.2.1. Continued Self-Generation Alternative DESCRIPTION: This alternative assumes that the electrical energy requirements in the villages of Akiachak, Akiak, Kwethluk, Tuluksak and Napaskiak will continue to be supplied by diesel driven generators throughout the study 6-1 RESULTS: period. Continued use of diesel generation (Continued Self Generation Alternative) has been used as the basis of comparison for cost in the villages. Electrical energy rates are almost entirely dependent on diesel fuel costs. Energy rates will continue to rise indefinitely under this alternative. The average cost of energy to the end consumer is estimated at $0.45/Kwh in 1994 and is expected to increase to approximately $0.85 by 2014. The 1994 present worth cost' of PCE payments, over the study period, is estimated at over $19,000,000 for the seven villages. 6.2.2 Regional Intertie System Alternative DESCRIPTION: Stage 1 REU: Involves the formation of a "limited service" nonprofit generation and transmission (G&T) utility in 1995. The non-profit G&T could be formed as a nonprofit "subsidiary" of Calista Corporation and would operate as a Stage 1 REU throughout the study period. Under Alternative A, the G&T would construct, own and operate a SWGR transmission system that would intertie the villages of Akiachak, Akiak, Kwethluk, Tuluksak, Napaskiak, Oscarville, Napakiak with Bethel. In Alternative B the G&T in addition to constructing the SWGR transmission system described in Alternative A, the G&T would construct, own and operate the Nyac hydroelectric plant and construct additional SWGR transmission lines to interconnect the Nyac hydro to the transmission system. In both Alternatives A & B, the G&T would own and operate the stepdown substations at each village and Bethel. The G&T would sell electrical energy generated by the Nyac hydro plant directly to the villages and to Bethel Utilities during the summer months. During the winter 1 Present worth (PW) cost of PCE payments, over the length of the study period, was computed for the various alternatives. The PW cost provides a comparison of the 1994 equivalent dollars the State would pay in PCE to subsidize the cost of electrical energy sales in the villages. 6-2 RESULTS: DESCRIPTION: months when the output from the Nyac hydro is not sufficient to supply the village load requirements, the G&T would purchase power from Bethel Utilities for resale to the villages. The average retail rate in the year 2014 for Alternative A is calculated at $0.55/kwh and the PW of PCE payment is $13,069,000. In Alternative B the average retail rate in 2014 is $0.41 and the PW of PCE payments $8,485,000. Alternative A. PW cost of Alternative B is $4,484,000 less than Alterna- Retail rates for Alternative B are $0.14/kwh less than tive A. Alternative B is by far the superior alternative if the REU were to remain at the STAGE 1 development level. Stage 1-2 REU: Alternatives A & B - Implement Stage 1 for the appropriate Alternative as described above. During 1998 and 1999 the utility would transi- tion from Stage 1 to a Stage 2 REU. At ALTERNATIVE A COST COMPARISON the second stage of development, the nonprofit G&T utili- ty would acquire and operate the electric AVG. COST S/KWH ° > distribution systems in the seven villages 0.2 Settee teeta +—+—+—_ +++ served by the trans- = Stage 1 -= Stage 1-2-= Stage 1-3] mission line in both Pe 1994 1996 1998 2000 2002 2004 2006 2008 2016 2012 2014 ; FIGURE 6.1 Alternatives A and B. The alternative assumes the G&T acquires the village distribution systems at no cost. Each village would retain control and ownership of the existing diesel plant. If the village wanted emergency backup generation, 6-3 RESULTS: the village would be responsible for maintaining the plant in emergency standby operating condition. The G&T —— ALTERNATIVE B would no_ longer COST COMPARISON wholesale electricity to the villages direct- ly, but would instead sell at the retail level to the individual vil- AVG. COST $/KWH lage consumer. The G&T would provide ; $0.20 + + 4+ = all the required man- 1994 1997 2000 2003 2006 2009 2012 agement, administra- | [= Stage 1_-= Sage 1-2 © Stage 1-3] FIGURE 6.2 tive and operational services, including the processing and collection of PCE payments from the state. Villages would no longer be primarily responsible for any aspect of the village distribution system. The REU would continue to operate as a Stage 2 utility throughout the remainder of the study period. The average retail rate in the year 2014 for Alternative A is calculated at $0.53/kwh and the PW of PCE payment is $12,259,000. In Alternative B the average retail rate in 2014 is $0.42 and the PW of PCE payments is $8,472,000. Retail rates for Alternative B are $0.11/kwh less than Alternative A. PW cost of Alternative B is $3,787,000 less than Alterna- tive A. Alternative B remains the superior alternative if the REU were to remain at the STAGE 2 development level. However, a comparison of cost between a STAGE 1 and a STAGE 1-2 REU, reveals only minimal additional savings are available when operating as a STAGE 2 REU. This is graphically illustrated in Figures 6.1 and 6.2. 6-4 DESCRIPTION: RESULTS: Stage 1-3 REU: Alternatives A & B - Implement Stage 1-2 as discussed above, but in the year 2000, Calista Corporation forms "Calista Utilities" as a for-profit subsidiary corporation and acquires the nonprofit G&T utility and Bethel Utilities, in both Alternatives A&B. Calista Utilities would operate as a "full service" REU, providing services to the regional villages served by the transmission line and to the city of Bethel. All re- quired management, administrative, operational and maintenance services for operating the REU would be provided by Calista Utilities. An esti- mated purchase price of $6,000,000" is assumed for Bethel Utilities. Two new 2500 kW generators are added during the study period to meet load demand requirements. One generator is added in 2002 and the second unit is added in 2008. The average retail rate in the year 2014 for Alternative A is calculated at $0.315/kwh and the PW of PCE payment is $6,584,000. In Alternative B the average retail rate in 2014 is $0.305 and the PW of PCE payments is $6,123,000. Retail rates for Alternative B are only $0.01/kwh less than Alternative A. PW cost of Alternative B is only $461,000 less than Alternative A. For practical purposes, implementation of either Alterna- tives A and B results in energy and PCE cost which are identical in 2014. However, Alternative B is slightly less expensive in 2014 and if the study period were increase to fifty years, the typical life span of a hydro facility, the cost advantages of Alternative B would become more apparent. Regardless of whether Alternative A or B is constructed, the implementa- tion of a STAGE 1-3 REU drastically lowers the cost of electrical energy to village users as compared to either a STAGE 1 or STAGE 1-2 REU. See Figures 6.1 and 6.2 for a comparison of Stage 1, Stage 1-2 and Stage 1-3 energy costs. 2 Estimated purchase price obtained from "Analysis of Proposed Bethel Utili- ties Corporation Purchase By the City of Bethel", AEA, 1991. 6-5 6.2.3 Regional Intertie System - Moderate Load Growth, Stage 1-3 REU, Alternative C DESCRIPTION: Same parameters and assumptions as used in Stage 1-3, Alternative B, except purchase price of Bethel Utilities is assumed at $8,000,000 to investigate sensitivity of rates and net rate of return to the purchase price. RESULTS: The average retail rate in the year 2014 for this alternative is $0.31/kwh and the PW of PCE payments is $6,252,000 which closely approximates energy cost and PCE payments [| | NET RETURN ON INVESTMENT ; i “CALISTA UTILITIES" in Alternative B. 8.0% However, the average net rate 7.0% 4 of return for this ALT. A&B alternative is 6.0% ALT.C a - only about 5.2% ALT.D while the aver- 5.0% t. age net rate of 4.0% ttt to tt return when pur- 2000 2002 2004 2006 2008 2010 2012 2014 chasing Bethel pYGURE 6.3 Utilities for $6,000,000 is 6.3%. In order to increase the rate of return in Alternative C it would be necessary to increase the rate of return allowed on the - ratebase. The APUC is unlikely to increase the allowable rate of return on the ratebase simply to increase utility profits.’ (See Appendix A for the definitions of ratebase and rate of return.) 3 The actual purchase price paid for the utility does not establish the ratebase. The ratebase is determined by subtracting depreciation from capital investment. Thus the ratebase for Bethel Utilities will remain constant regardless of whether the purchase price is $6,000,000 or $8,000,000. The greater the purchase price the lower the net rate of return to Calista. 6-6 6.2.4 Regional Intertie System - Moderate Load Growth, Stage 1-3 REU, Alternative D DESCRIPTION: RESULTS: Alternative D investigates the affect on rates and net rate of return if the REU were required to purchase the seven village distribution systems for . an average price of $150,000 each, for a total of $1,050,000. Other parameters and assumptions same as in Stage 1-3, Alternative B. The average retail rate in the year 2014 for this alternative is $0.315/kwh and the PW of PCE payments is $6,332,000 which closely approximates energy cost and PCE payments in Alternative B. However, the average net rate of return for this alternative is about 7.0% which is approximately 0.7% greater than in Alternative B. The net rate of return is increased be- cause the utility ratebase has increased by the value of the village distribu- tion system. Since the net rate of return is directly proportional to the ratebase, the utility's net rate of return increase as the ratebase increases. 6.2.5 Regional Intertie System - Low Load Growth, Stage 1-3 REU, Alternative E DESCRIPTION: RESULTS: Alternative E examines the effect of low load growth on energy costs by assuming load growth will stagnate at year 2000 levels. Other parameters and assumptions same as in Stage 1-3, Alternative B, except only one new 2500 kW generator is required. The generator is added in year 2002. The average retail rate in the year 2014 for this alternative is $0.33/kwh or about 5% greater than Alternative B. Since low load growth reduces energy requirements the cost of each kWH sold must be increased to recover capital investment expenses. The results of this alternative demonstrate that in the event low load growth conditions were encoun- tered, forming an REU would continue to remain an economically viable option. 6-7 6.2.6 Bethel - No REU DESCRIPTION: RESULTS: This analysis was performed to obtain an estimate for the cost of electrical energy in Bethel during the study period. The analysis assumes Bethel Utilities will continue supplying the power and energy demands of Bethel, Oscarville and Napakiak, but no additional transmission interties are constructed, nor is the Nyac hydro plant constructed. The "Bethel - No REU" alternative is the basis against which other Stage 3 costs are compared to decide if the energy cost associated with Stage 3 development is comparable to those projected for Bethel. The average retail rate in the year 2014 is calculated at $0.31/kwh which is approximately one-half cent greater than the energy cost in STAGE 1- 3, Alternative B. However, the average net rate of return for this alterna- tive is only about 5.2% while the average net rate of return when purchasing Bethel Utilities for $6,000,000 is 6.3%. In order to increase the rate on return in Alternative C it would be necessary to increase the rate of return allowed on the ratebase. The APUC is unlikely to increase the allowable rate of return on the ratebase simply to increase utility profits. 6.2.7. Other Alternatives Investigated Other alternatives investigated include: a) The primary analysis presumes the Nyac hydroelectric project and the transmission intertie system will be totally funded by grants. However, the effect of grant funding on long term energy costs was investigated for Alternative B, by assuming the transmission system and the Nyac hydro project were funded at various levels. The cost of energy in 2014 for Alternative B, Stage 1-3 REU is calculated at: 1) $0.305/kWH if the hydro and transmission system is entirely funded by grants; 2) $0.335/kWH if funded 50% by grant funds and 50% by a 7% loan; and 3) $0.355/kWH if funded entirely through debt at 7% interest (i.e. 0%. grant funds). 6-8 For the Bethel - No REU alternative the cost of energy in 2014 is calculated at $0.305/kWH. Additional calculations determined that the combined cost of the hydro and transmission line must be approximately 90% funded by grants, if the cost of power in Alternative B is not to exceed the cost of energy in the Bethel - No REU alternative in 2014. b) Two other alternatives which were investigated but are not contained in the computer printouts in Appendix A included the operation of village diesel power plants during the winter months as an alternative to purchasing power from Bethel Utilities and the use of contract labor to provide various administrative and customer services. The operation of a village diesel power plant was briefly investigated and discarded as being uneconomical as compared to purchasing village energy requirements from Bethel Utilities. The use of contract labor, at 75% of in-house rates, for administra- tive and customer service positions has minimal affect on rates. 6.3 ECONOMIC PARAMETERS Standard economic analysis parameters have been used in evaluating the alternative development plans. These are summarized below. A detailed listing and explanation of the parameters used in the analysis is located in Appendix A. a) A general inflation rate of 3.5% per year is applied throughout the 21 year study period. b) The escalation rate for diesel fuel is assumed at 3.5% . c) A single financing rate (i.e. the cost of borrowing money) of 7% has been selected for the analysis. The 7% financing rate is representative of the rates available to fund the portion of the project not funded by grants. It is assumed the SWGR transmission system and the Nyac hydro are funded entirely by grant funds. d) A base discount rate of 3.5% is utilized which is typical of the low yield return available on consumer savings. The discount rate is used to determine the present worth values of PCE payments. e) A depreciation period of 30 years is assumed for new equipment. f) A loan repayment period of 20 years is assumed for all loans, except a 15 year loan repayment period is assumed for the initial capital start-up loan and a five year loan repayment period for the computer system and software. 6.4 RECOMMENDATIONS Careful study of the alternatives suggest Calista Corporation should implement the following development plan. 1. Form a Stage 1, Nonprofit REU as a "subsidiary" of Calista Corporation as the first step in the implementation of Alternative B. The Stage 1 REU would be responsible to secure the necessary grant and/or loan funds for constructing the regional transmission system and the Nyac hydro. 2. Begin preliminary design of the regional SWGR transmission intertie system and the Nyac hydroelectric plant 3. Implement a Stage 2 REU within two-three years after Stage 1 has been fully completed. 4. Purchase Bethel Utilities and implement a "Full Service" REU within two-three years after Stage 2 has been completed. 6-10 AG. Lh 12. 135 14. 15. 16. i7. REFERENCES State of Alaska, "Power Cost Equalization Program Manual", Alaska Energy Authority, Alaska Public Utilities Commission, January 1990. Alaska Energy Authority, "First Annual Statitical Report of the Power Cost Equalization Program", 1988. Alaska Energy Authority, "Second Annual Statistical Report of the Power Cost Equalization Program", 1990. Alaska Energy Authority, "Statistical Report of the Power Cost Equalization Program", Fourth Edition, 1991. "Bethel - Nyac Transmission Line Feasibility Report", prepared by Bettine & Associates, May, 1992. State of Alaska, Division of Energy and Power Development, "Single Wire Power in Alaska", prepared by Robert W. Retherford Associates, 1982. Alaska Village Electric Cooperative, "Nunapitchuk/Kasigluk/Akolmiut Overhead Distribution Tieline Design", prepared by Robert W. Retherford Associates, 1980. Rural Electrification Administration, U.S. Department of Agriculture, REA Bulletin 101-3, 1971. Alaska Statutes, AS 42.05 and AS 42.06 Alaska Statutes, AS 36.30 REA Bulletin 800-1, 1990. 7 CFR Part 1700 & 1710, 1992 REA Informational Publication 100-1, 1990. Calista Corporation, "Final Recommendations for Action Submitted to the Alaska Natives Commission", prepared by Calista Corporation, Land & Natural Resources Department, 1993. Alaska Energy Authority, "Nyac Hydroelectric project power potential study", prepared by HDR Engineering, Inc., 1991. Alaska Energy Authority, Alaska Electric Power Statistics, 1992. Meigs & Meigs, Accounting, The Basis for Business Decisions, Ninth Edition, McGraw Hill, Inc., 1993. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. Fischer, Taylor, & Leer, Advanced Accounting, Fifth Edition, South-Western Publishing Co., 1993. Fletcher, Corporate Practice Deskbook, Vol. 19, Clark, Boardman, Callaghan, 1992. Alaska Administrative Code, Title 3, Chapters 48, 49, 50, and 52, 1992 Tariff Documents, Financial Statements, AVEC, THREA, and Bethel Utilities. Alaska Energy Authority, "Analysis of Proposed Bethel Utility Coporation Purchase By The City of Bethel, Alaska," prepared by CH2M Hill and FPE/Roen Engineers, Inc., 1991. 73: C.d.S. §3 Business Organizations, Matthew Bender Co., 1992. 64 Am. Jur. 2d §1-206 43 U.S.C. §1601 Nonprofit Enterprises, Vol. 1 & 2, Clark Boardman Callaghan, 1992. Fallon, AMA Management Handbook, Second Edition, Library of Congress, 1983. Anthony/Young, Management Control in Nonprofit Organizations, Fourth Edition, Library of Congress, 1988. Advantages & Disadvantages of Tax Exemption, John Wiley & Sons, 1992. APPENDIX A A.1. PARAMETERS USED IN FINANCIAL FORECAST AND COST-OF-SERVICE ANALYSIS A. BASE YEAR A base year of 1994 is used for the study. It is assumed construction of transmission lines interconnecting the villages would begin in 1994 and be completed in 1995. The Nyac hydroelectric plant is estimated to become operational in the summer of 1996 and would supply 2500 MWH of energy during 1996 and full energy output of 5000 MWH beginning in 1997. (A delay in construction of either the transmission line or the Nyac hydro by one or two years should not invalidate conclusions reached in this study.) B. ESCALATION RATES 1. Fuel Costs An escalation rate of 3.5%, is applied to the study period, which is the same as the general inflation rate used in the study. 2. All Other Costs A general inflation rate of 3.5% is applied to all other cost over the study period. C. DEBT SERVICE Debt service on investments, other than the Nyac hydro and the SWGR transmission lines, has been calculated using a 7.0% cost of debt. An amortization period of 20 years is used. There is no debt service for the Nyac hydro and the SWGR transmission lines, as it is assumed both of these projects will be constructed using 100 percent grant funds. All new investments are assumed to be funded by debt. D. DISCOUNT RATE A discount rate of 3.5% has been used in the analysis. The discount rate is equal to the inflation rate. Discount rates are used in the various alternatives to determine present worth values of PCE payments. A 3.5% discount rate is consistent with the rate-of-return available in 1993 on low risk investments. E. POWER DEMAND AND ENERGY REQUIREMENTS The load forecast developed in the Bethel-Nyac Transmission Line Feasibility Report, dated May, 1992, for the villages of Akiachak, Akiak, Kwethluk, Tuluksak, Napaskiak, Oscarville, Napakiak and Nyac was used in this study. A load forecast for Bethel was developed through the year 2014 from historical data and other available information. Distribution losses within each village A-1 is assumed at 8 percent, therefore, energy sold in each village is assumed at 92 percent of purchased or generated energy. The historic line loss and station services usage in Bethel is 16 percent of the total kwh sales, which is somewhat higher than average. Therefore, only 84 percent of the energy generated in Bethel is ultimately sold to the consumer. Village peak demand and Bethel peak demand are added to determine total peak demand. F. GENERATION SOURCES AND SUPPLIES The study assumes electrical energy requirements will be supplied by one of the following: 1. 2. Continued diesel generation at each village; or For alternatives investigating a transmission intertie system, by power purchases from the REU. The REU is assumed to purchase energy for resale from Bethel Utilities during Development Stages 1-2, and/or from the Nyac Hydroelectric plant. Usable energy output from the Nyac hydro is estimated at 5000 MWH per year.’ It is assumed the hydro operates for only 7 months of the year, from mid-May through mid- November. It is assumed sufficient diesel generation capacity will be maintained in each village to meet generation requirements in the event of a transmission line outages. The analysis presumes the Nyac hydroelectric project and the transmission intertie system will be totally funded by grants. However, the effect of grant funding on long term energy costs was investigated for Alternative B, by assuming the transmission system and the Nyac hydro project were: 1) entirely funded by grants; 2) 50% funded by grants and 50% funded through debt at 7% interest; 3) and entirely funded through debt at 7% interest (i.e. 0%. grant funds). The analysis assumes two new 2500 kW diesel generators must be installed in the Bethel diesel plant during the study period. One unit is installed in 2002 and the second unit in the year 2008. The construction of a new diesel plant or the operation of existing village diesel plants by the G&T, during the winter months was investigated as an alternative to purchasing village energy requirements from Bethel Utilities. However, an analysis of this alternative revealed that this approach was uneconomical as compared to purchasing village energy requirements from Bethel Utilities. Lower generation efficiencies and higher maintenance cost as compared to Bethel Utilities, plus the labor cost associated with hiring sufficient plant operators to man the G&T diesel plant on a full time basis, resulted in energy costs 1 The effect of increased energy output and a longer operating season has not been investigated in this study. However, the occurrence of one or both of these conditions is likely to reduce the cost of power. A-2 that exceeded the cost of energy purchased from Bethel Utilities. G. CAPITAL INVESTMENT COSTS Cost of SWGR transmission system for the various alternatives and Nyac Hydro obtained from Bethel-Nyac Transmission Line Feasibility Report, dated May 1992. Cost of 2500 KW diesel generation units estimated at $320 per installed KW in 1992. Obtained from Bethel Utilities' 1992 year end financial statement. Escalated at the general inflation rate. Cost of new computer and software to be used for accounting and customer billing functions is estimated at $60,000. Purchased at beginning of Stage 2. H. PURCHASED POWER AND ENERGY COST During Stage 1-2 Development, the REU can purchase power and energy from Bethel Utilities at it's three phase service rate of $21.29 per kW demand plus $0.104 per kWH for energy charges for Alternatives in which the Nyac hydro plant is constructed.” It is assumed that single phase to three phase conversion equipment will be installed if the Nyac hydro is constructed in order to sell excess hydro energy to Bethel. In addition, with the conversion equipment install, REU can purchase power and energy from Bethel Utilities at the lower three phase consumer rate. For Alternative A, Transmission Interties to Bethel, but Nyac Hydro not constructed, the REU could forego the installation of conversion equipment and purchase energy from Bethel at the single phase power rate of approximately $0.183/kwh plus $2.00/kW of installed transformer capacity. However, the single phase rate will average 2-3 cents per kWH greater than the three phase rates. It is ,therefore, recommended the conversion equipment be installed. All calculations assume installation of three phase to single phase conversion equipment. (Demand and energy costs obtained from Bethel Utilities customer rate schedule and Cost of Power Adjustment schedule.) Demand costs are escalated at the general inflation rate. 80% of energy charge is escalated at the fuel escalation rate, the remaining 20% at the general inflation rate. I. SWGR LINE LOSSES Line losses incurred on the SWGR Intertied System are estimated at 10% for the alternatives which include the Nyac hydro plant and includes losses in the 3 phase to one phase rotary/static phase converter. Line losses are estimated at 6% for the alternatives which do not include ? A kilowatt (kW) is a measure of the power required by the consumer load. A kilowatt hour (kWH) measures the energy used by the load. For example a one horsepower electric motor requires about one kilowatt of power to operate and would use two kilowatt hours of energy if operated for a two hour period. For large power consumers, a utility will generally charge for the amount of power required by the consumer load in addition to the amount of energy used by the load. A-3 development of the Nyac hydro plant. Line losses are increased in alternatives which include development of Nyac hydro to account for losses associated with sending excess Nyac hydro power to Bethel. J. REU ADMINISTRATIVE AND GENERAL EXPENSES Estimated from THREA, AVEC and Bethel Utilities administrative and personnel costs. Escalated at the general inflation rate. K. CONSUMER ACCOUNTS Estimated from THREA, AVEC and Bethel Utilities administrative and personnel costs. Escalated at the general inflation rate. L. VILLAGE ADMINISTRATIVE COST Village administrative cost are estimated at $0.063/kWH in 1994 and escalated at the general inflation rate. Estimated from AEA power cost equalization statistics for the seven villages addressed in this study. M. PCE PAYMENTS PCE is computed on a kwh basis. PCE per kwh is calculated at 95% of that portion of energy cost between a base of $0.097/kwh and a cap of $0.525/kwh for the first 700 kwh. Only residential, small commercial, community facilities and public schools are eligible for PCE. Other federal and state facilities are no longer eligible for PCE payments. Both the base and cap are escalated at the general inflation rate. For the purposes of this study all kWHs sold to residential and small commercial are assumed eligible for PCE payments as neither residential or small commercial consumers are expected to exceed 700 kwh per month usage. N. POWER PRODUCTION COSTS Labor, material and insurance cost estimated from THREA, AVEC and Bethel Utilities costs. Escalated at the general inflation rate. O. NON-FIRM POWER SALES Assumed Bethel Utilities will purchase all excess Nyac hydro energy at a rate of $0.105 per kWH. (Cost obtained from Bethel Utilities non-firm tariff rate.) Escalated at the fuel inflation rate. P. FUEL COSTS The average 1994 cost per gallon for diesel fuel in the villages is assumed at $1.25 per gallon. A-4 Cost of diesel fuel is escalated at the fuel inflation rate. Q. GENERATION FUEL EFFICIENCIES Village Generation Plants - A average diesel generation efficiency of 7 kWH/gal is used for the villages for the base year of 1994. This was calculated from data obtained from the First and Second Annual Statistical Report of the Power Cost Equalization Program, 1989, 1990. Generation efficiency is assumed to increase linearly over the study period to 10 kWH/gallon in 2014. Bethel Generation Plant - A diesel generation efficiency of 14 kWH/gallon is used. R. VILLAGE DIESEL OPERATIONS, MAINTENANCE AND PLANT COST A value of 1994 cost of $0.20/kWH is used to cover the cost of diesel maintenance and replacement costs. This value was calculated from data contained in the First and Second Annual Statistical Report of the Power Cost Equalization Program, 1989, 1990. Escalated at the general inflation rate. S. NYAC HYDRO OPERATION, MAINTENANCE AND INSURANCE COST Estimated at $80,000 in 1994, escalated at the general inflation rate, which covers the cost of a part-time operator and maintenance. Insurance cost is estimated at $40,000 year and is escalated at the general inflation rate. T. COST-OF-SERVICE RATEMAKING Cost-of-service ratemaking approach was used to determine future rates. When using the cost-of- service ratemaking approach the total revenue received by the utility should equal the expected cost for services plus a reasonable return figured on the capital invested and not consumed by the firm. The total revenue is calculated as: =0+rI Where: R is the utility's revenue requirement O is its operating cost I is its invested capital (ratebase) r is rate of return allowed on the utility's investment The cost-of-service rate making approach is an attempt to apply this comparatively simple pricing formula through a series of seemingly mechanical steps: 1. Determine the utility's revenue requirements by adding a. the utility's operating expenses (O) including depreciation and taxes, to b. areasonable profit which is determined by multiplying the ratebase (I) by a rate of return (r). The ratebase is determined by subtracting total historic depreciation from total historic investment. 2. The rates are set so that the utility's gross revenues will equal the revenue requirement (R). 3. Finally, if the utility services more than one class of customer or provides more than one type of service, the revenue must be allocated between the different classes. Bethel Utilities' ratebase was estimated at $3,300,000 in the year 2000. The ratebase between 2001 and 2014 was calculated by subtracting the historical yearly depreciation rate of $200,000 per year from the estimated yearly investments. The APUC typically allows a for-profit utility to receive a 13 percent rate-of-return on its ratebase. This rate of return was applied to the ratebase to determine allowable profit on investment. U. MINIMUM RETAINED EARNINGS Minimum yearly retained earnings (margins) is calculated as 5% of debt service for Stage 1 and 2 and 20% of debt service for Stage 3. Debt service for calculating minimum retained earning is assumed as 7% of total yearly investment plus the actual cost of the transmission system and Nyac hydro. Five percent and twenty percent yearly retained earnings requirement is typical of REA requirement for G&T and distribution utilities, respectively. Retained earnings are accumulated until reaching $1,200,000, which is the approximate amount of retained earnings held by Bethel Utilities. The amount of retained earnings can be increased at the discretion of the operating utility so long as the amount accumulated does not violate IRS guidelines. V. RESIDENTIAL, SMALL COMMERCIAL AND LARGE COMMERCIAL CONSUMER RATES. Calculated average rate by consumer classes. Average cost per kwh covers monthly customer charge plus demand and energy charges as appropriate. W. TAXES An overall combined federal and state effective tax rate of 35% was used to calculate taxes on the for-profit utility. The for-profit utility was assumed to begin operations in the year 2000. Taxes were determined by multiplying the dollar return on ratebase by the effective tax rate. The non profit utility was assumed to have a zero tax liability. X. WASTE HEAT SALES Estimated from Bethel Utilities 1992 Year End Financial Report. Increased in proportion to total kWHs generated in Bethel diesel power plant. Y. VILLAGE DISTRIBUTION SYSTEM COSTS Estimated at $150,000 per village. Cost is net distribution plant value (i.e. initial cost less depreciation). A.2 EXPLANATION OF COMPUTER PRINTOUTS The following is a line by line explanation of the enclosed computer printouts. DESCRIPTION 1. LOAD DEMAND Villages A. Demand - kW B. Energy C. Transmission Line Loss in MWH D. Total Energy Bethel E. Demand - kW F. Energy G. MWH Available from Nyac Hydro H. Village Hydro Use G. Surplus Hydro EXPLANATION Projected Peak Load in kW for villages Projected Energy Requirements in MWH_ for villages including school loads. Estimated Line Losses in MWH. Calculated as percentage of energy. Estimated at 10% for alternatives with Nyac hydro, 6% for alternatives without Nyac hydro. Projected Peak Load in kW for Bethel Projected Energy Requirements in MWH for Bethel Estimated at 5000 MWH per year Calculated as 60% X (Total Energy Requirements - Nyac Energy Requirements) + Nyac Energy Requirements. (Assume all Nyac Energy Requirements will be supplied from hydro in those alternatives where hydro is developed. Surplus Nyac Hydro Energy Available from sale to Bethel Utilities. (MWH available from Nyac Hydro - Village Hydro use). Surplus hydro sales to Bethel estimated at 1680 MWH in 1997 decreasing to 244 MWH in 2014. H. Purchase from Bethel Utilities 2. INVESTMENT COSTS ($1000) A. Transmission Line B. Nyac Hydro C. New Distribution D. Purchase Bethel Utilities E. New Generator 3. INITIAL CAPITAL Total Investment 4. ESTIMATED RATEBASE 5. DEBT SERVICE ($1000) Total Debt Service 6. OPERATING EXPENSES ($1000) A. Power Production Costs Total Village Energy Requirements - Village hydro use. Cost of Transmission Line in 1994 dollars. Assumes transmission Line is constructed in 1994- 1995. Cost of Nyac Hydro plant in 1994 dollars. Assumes Nyac hydro constructed in 1994 & 1995. Investment for new distribution service (i.e. serving new consumers). Estimated at $2500 per new village consumer and $750 per new Bethel consumer. Capital cost to purchase Bethel Utilities. Estimated at $6,000,000 in 2000. - Cost of purchasing a new 2500 kW generator in 2002 and 2008. Capital necessary to finance start-up cost and initial operations. Sum of investment ($1000) by year. Allowable ratebase for calculating consumer rates Debt Service on Investment. Debt Service is calculated using 7%Cost of Money. Small Business Admin. loan payments obtain from Bethel Utilities year-end report. The Sum of Debt Service at 7% Based on Manpower requirements previously outlined for each Stage of development. 1. Nyac Hydro 2. Bethel Generation Plant 3. Village Operators 4. Cost of Purchased Power B. Transmission\Substation C. Distribution D. Administrative & General Expenses E. Consumer Accounts F. Total Expenses G. Energy Sales to Bethel H. Expenses - Sales to Bethel I. Avg. Cost $/Kwh Including Losses 7. FINANCIAL FORECAST A. Avg. $/KWH Wholesale Cost B. Beginning Year Balance Operating Expenses Return on Ratebase @13% Taxes Total Expenses Yearly operating, maintenance and insurance costs. Yearly operating, maintenance and insurance costs. Cost of part-time village operators. Cost of power purchases from Bethel Utilities. Yearly operating and maintenance costs for transmission line and substations. Yearly operating and maintenance costs. Administrative Costs Associated with Operating Stage 1, 2 or 3 regional electric utility. Administration cost for customer accounts. Total of Operating Expenses Non-firm excess Nyac hydro energy sales to Bethel Operating expenses less sales of energy to Bethel Average cost per kwh. Average cost per Kwh charged by regional electric utility. Available dollars at beginning of year. Total of Operating Expenses. Return on ratebase. Calculated at 35% of return on ratebase Sum of Operating Expenses, Return on ratebase and taxes. A-10 10. 11. KWH Sales KWH Sales to Bethel Interest at 5% Waste Heat Sales Total Revenues Revenues - Expense End of Year Balance Minimum Retained Net Return on Investment REGIONAL UTILITY ESTIMATED AVG. RATES VILLAGE UTILITY COSTS ESTIMATED AVG. RETAIL RATES IN VILLAGES WITHOUT PCE ESTIMATED AVG. RETAIL RATES IN VILLAGES WITH PCE PCE Payments Total of KWH sales to consumers. Non-firm excess Nyac hydro energy sales to Bethel Yearly income from interest on retained earnings. Yearly income from waste heat sales in Bethel Sum of KWH Sales, KWH Sales to Bethel, Interest Income and Waste Heat Sales. Difference between revenues and expenses. Retained Earnings at End of year. Minimum recommended accumulated retained earnings. Net return on investment. Calculated as Return on Ratebase divided by (Total Capital Investment less grant funds). Estimated average rates for residential, small commercial and large commercial without PCE. Operating, maintenance, and admin. cost incurred by village utilities. Estimated average rates for residential, small commercial and large commercial in villages without PCE. Estimated average rates for residential, small commercial and large commercial in villages with PCE. Annual PCE Payments, Present Worth of Annual PCE Payments and Accumulated Present Worth of PCE payments A-11 A.3 CALCULATIONS A-12 DATE - 06/17/83, PAGE 1 of 4 ‘%Grant Tine 100% ‘%Grant Hydro: 100% 4. LOAD DEMAND: VILLAGES: ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 6% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL . DEMAND - KWH F, ENERGY - MWH G. MWWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES H. MH PURCHASES FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A. TRANSMISSION LINE Yet Yr2 8. NYAC HYDRO Yet Yr2 C. NEW DISTRIBUTION . PURCHASE BETHEL UTILITIES E. NEW GENERATOR 3. INITIAL CAPITAL TOTAL 4, ESTIMATED RATEBASE 6, DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR INITIAL CAPITAL (AEA LOAN ‘SMALL BUSINESS ADMIN. LOAN TOTAL soo8ed 1904 619.0 2711.9 00 2711.9 0.0 00 ss ss ss ss 1995 639.1 2799.5 2799.5 °° 00 0.0 $0 $0 $0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 General inflation Rate Fuel inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate $/ewh, 1994 650.2 2887.1 oo 2887.1 co 1997 679.3 2974.7 2974.7 0.0 00 1998 600.4 3062.3 0.0 3062.3 3.500% 3.500% 3.50% $0.008 POWER COST STUDY 1998 2000 2001 2002 2003 2004 ‘2005 7195 73S 750.6 7797 800.0 827 845.4 31409 3237.4 33250 34126 «= 3501.0 3805.5 = 3709.9 31499 32374 33250 934126 3501.0 3605.5 3709.9 0 ° ° ° ° 0 0 0 ° ° ° ° 0 ° ° ° ° ° 0 ° ° 00 00 00 00 0° 00 00 00 00 00 00 oo 00 00 00 00 0.0 00 00 00 00 $0 $0 $0 $0 $0 $0 $o $0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 so 30 $0 $0 so $0 $0 $0 so $0 $0 $0 $0 30 $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 so $0 $0 so so so so 000 od 000 2000 y000 2000 000K $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 30.0 $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 $0.0 $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 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0 so $0 $0.0 $0.0 $0.0 $0.0 $0.0 30.0 $0.0 $0.0 $0.0 $0.0 00 00 ss 88 88 AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NAPASKIAK - SELF GENERATION 913.5 4023.2 0.0 4023.2 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 30.0 $0.0 936.2 41277 2707 2° co 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 2010 958.9 4232.1 4232.4 eco 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 2011 981.6 4336.6 0.0 4336.6 00 00 0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2012 1004.3 4441.0 00 4441.0 eo 0.0 0.0 $0 $0 $0 so $0 $0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2013 1027.0 4545.5 4545.5 eo 0.0 0.0 00 $0 $0 $0 $0 so $0 $0.0 $0 so $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2014 1043.4 4618.2 4618.2 00 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 DATE - 06/17/93, PAGE 2 of 4 6. OPERATING EXPENSES ($1000) ‘A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators: O&M Materials Fuel Insurance 3. VILLAGE OPERATORS: 4. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS IN-House 8M Labor 8M Materials Contractor 1994 sss $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 $0.0 $0.0 $0.0 $0.0 $0.0 1995 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 1996 $0.0 $0.0 $0.0 $0.0 30.0 $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 30.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 1997 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 1998 $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 $0.0 $0.0 $0.0 $0.0 1999 $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 $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 $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 $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 $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 $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 $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 $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 $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 $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 $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 $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 $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 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2010 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2011 $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 $0.0 2012 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2013 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2014 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 DATE - 06/17/93, PAGE 3 of 4 E. CONSUMER ACCOUNTS: INHouse Biing/Data Entry Clerk Customer Service Office Clerk ‘Accountant Contractor F, TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES: TO BETHEL H. EXPENSES-SALES TO BETHEL |, AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST A. AVG. $/KWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES TOTAL EXPENSES a SALES ‘SALES TO BETHEL INTEREST AT 5% unum WASTE HEAT SALES: TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) 1904 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 '$0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 1996 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 1997 1998 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.000 $0,000 FINANCIAL FORECAST $0.000 — $0.000 $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 1999 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 ‘$0,000 $0,000 $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 $0.000 ‘$0,000 $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 0.000 $0,000 $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 90.0 $0.0 '$0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2003 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.000 '$0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2004 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 2005 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2006 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 '$0.000 $0.00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2007 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0,000 $0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 '$0.000 $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 $0.000 $0,000 $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 $0.000 $0,000 $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 $0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2012 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0,000 '$0.000 $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 $0.000 $0,000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2014 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.000 $0.000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 DATE - 06/17/93, PAGE 4 of 4 8. VILLAGE UTILITY COSTS 8M Fuel ‘Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS 9, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITHOUT PCE Residential ‘Smal Commercial Large Commercial 10, ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential ‘Small Commercial Large Commercial ‘ANNUAL PCE PAYMENTS PW Annual PCE Payments ACCUMLATED PW PCE 1994 1995 $5424 $579.5 $5036 $526.8 $1708 © $162.5 $0.0 $0.0 $1,216.9 $1,288.8 $0.449 = $0.460 $0.480 $0.50 $0480 = $0.456 $0350 © $0.419 $0.008 = $0.101 $0.12 $0.12 $0.12 $0.12 $0.36 $0.42 $507.6 = $632.3 $5076 = $610.9 $807.6 $1,208.56 1996 $618.5 $550.8 $194.8 $0.0 $1,364.41 $0.514 $0.558 $0.508 90.467 90.105 $0.13 $0.13 $0.47 $741.1 $601.8 $1,900.3 1997 $650.6 $575.5 $207.8 $1,442.9 $0.527 $0.573 $0522 $0.480 $0,100 90.13 $0.13 $0.48 $7823 $705.6 $2,605.9 1998 $702.8 $601.1 $221.4 $0.0 $1,625.3 $0.541 0.588 $0.493 90.112 $0.14 $0.13 $0.49 $625.4 $719.3 $3,325.3 1999 $748.2 $627.5 $235.7 $0.0 $1,611.4 90.556 90.604 0.551 $0.506 $0.116 $0.14 $0.14 $0.51 $870.4 $732.9 $4,058.1 $795.9 $250.7 $0.0 $1,701.58 $0.71 $0.621 $0,566 $0.20 $0.120 $0.15 $0.14 $0.52 $917.5 $746.3 $4,804.5 2001 $846.1 $683.2 $206.5 $0.0 $1,705.68 $0,587 $0.638 $0581 90.534 90.125 $0.15 $0.15 $0.53 $908.5 $759.7 $5,564.2 $008.8 $7124 $283.1 31,8043 $0.603 30.656 $0.597 $0.549 90.129 $0.16 $0.15 $0.55 $1,017.8 $7729 $6,337.1 2003 $954.3 $742.9 $300.6 $1,997.86 $0.620 $0.674 $0.614 $0.564 $0.134 $0.16 $0.16 $0.56 $1,071.6 $786.3 $7,123.4 2004 $1,017.2 $7778 $320.4 $0.0 $2,115.4 $0.631 $0.580 $0.138 $0.17 $0.16 $058 $1,132.86 $7,928.5 2005 $1,083.3 $814.0 $341.2 $0.0 $2,238.5 $0.656 90.713 $0.649 30.597 $0.143 $0.17 $0.17 $0.60 $1,196.68 $819.7 $8,746.2 2006 $1,152.7 $8515 $363.1 $0.0 $2,367.3 $0.675 $0.733 $0.668 90.614 $0.148 $0.18 $0.17 $0.61 $1,263.6 $836.2 $9,582.4 2007 $1,225.8 $890.2 $386.1 $0.0 $2,502.1 $0.604 $0.754 $0.687 $0.632 $0,153 $0.18 $0.18 $0.63 $1,333.5 $852.6 $10,435.1 2008 $1,302. $930.3 $4103 $0.0 $2,643.1 $0.714 $0.776 $0.707 0.650 $0.159 $0.19 $0.19 $0.65 $1,406.5 $868.9 2008 $1,363.1 $971.9 $435.7 $0.0 $2,790.6 $0.735 $0.799 $0.728 $0.669 $0.164 $0.20 $0.19 $0.67 $1,482.7 $885.0 $11,304.0 $12,180.0 2010 $1,487.7 $1,014.9 $462.3 $0.0 $2,044.9 $0.756 $0.622 90.749 $0.688 $0.170 $0.20 $0.20 $0.69 $1,562.4 $901.1 $13,090.0 2011 $1,556.6 $1,059.4 $490.3 $0.0 $3,106.3 $0.79 $0.846 $0.71 $0,709 90.176 $0.21 $0.21 $0.71 $1,645.7 $917.0 $14,007.0 2012 $1,649.8 $1,108.6 $519.7 $0.0 $3,275.41 $0.802 $0.871 $0.794 $0.729 0.182 $0.22 $0.21 $0.73 $1,7326 $14,930.8 2013 $1,747.7 $1,153.3 $550.5 $0.0 $3,451.6 $0.825 $0.897 $0.817 $0.751 $0,188 $0.22 $0.22 $0.75 $1,823.56 $048.5 $15,888.3 2014 $1,637.9 $1,194.68 $578.9 $0.0 $3,611.4 $0.924 $0.841 $0.73 $0.195 $0.23 $0.23 $0.77 $1,905.3 $957.5 $16,645.8 DATE - 07/17/83, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine ‘%Grant Hydro Loan Period initial Capital 4. LOAD DEMAND VILLAGES (A DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 6% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL . DEMAND - KWH F. ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO (USAGE - MWH G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES 1H. MWH PURCHASES FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A TRANSMISSION LINE Yrt Yr2 B. NYAC HYDRO Yet Yr2 C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES E. NEW GENERATOR 3. INITIAL CAPITAL TOTAL 4, ESTIMATED RATEBASE 5. DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR INITIAL CAPITAL SMALL BUSINESS ADMIN. LOAN: TOTAL 100% 100% 1 $3,585, $0 $0 $0.0 $750 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $3,585 $3,424 $0 $0 $0.0 $750 $7,759 $00 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $823 1996 1080.3 4409.4 4737.6 00 00 47378 $3,585, $3,424 $0.0 $750 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 General inflation Rate Fuel Inflation Rate REU Diese! Plant 1=NO, O=Yes Discount Rate PCE Rate $/kwh, 1994 1907 1104.3 4576.9 2746 4851.5 eo 00 4851.5 $3,585 $3,424 3 Ses ss $7,758 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $82.3 1998 1128.4 281.4 4905.4 0.0 4905.4 $3,585 $3,424 $0 $0.0 $760 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $62.3 $0.0 $92.3 1999 1162.5 4791.8 287.5 5079.3 & © co 0.0 5070.3 $3,585 $3,424 $0 $0 $0.0 $750 $7,758 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 1176.6 4809.3 294.0 5193.2 °° 0.0 00 193.2 $3,585 $3,424 90 90 $0.0 $750 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $00 $823 2001 1200.8 5006.7 300.4 5907.1 00 00 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $62.3 $0.0 $82.3 POWER COST STUDY 2002 1224.7 5114.2 5421.0 00 00 5421.0 $3,585 $3,424 $0 $0 $0 $0 $0.0 $750 $7,758 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $82.3 2003 1249.0 5222.8 3134 5536.0 00 0.0 $536.0 $3,585 $3,424 $0 $0 $0.0 $750 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $62.3 $0.0 $82.3 $3,585 $3,424 1309.2 8507.0 330.4 8837.4 co 00 8837.4 $3,585 $3,424 so $0.0 $750 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $62.3 $0.0 $82.3 1330.3 5649.2 5088.2 oo 0.0 5988.2 $3,585, $3,424 $0.0 $750 $7,758 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $82.3 1369.4 5791.4 M75 6138.9 0.0 0.0 6136.9 $3,585 $3,424 $0 $0.0 $750 $7,759 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $82.3 1309.5 $3,585, $3,424 $0 $750 $7,758 $0.0 $0.0 $0.0 $0.0 $0.0 $62.3 $0.0 $82.3 1429.6 6075.8 6440.3 00 00 6440.3 $3,585 $3,424 $0 $0 $0 $0 $0.0 $7,009 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2010 1489.7 6218.0 373.4 6591.1 00 0.0 6591.1 $3,585, $3,424 $0 $0 $0 $0 $0.0 $7,009 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2011 1480.8 6360.2 381.6 6741.8 co 0.0 0.0 6741.8 $3,585 $3,424 $0 $0.0 ‘$7,009 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2012 1519.9 6502.4 300.1 eo 0.0 6892.5 $3,585 $3,424 $0 $0 $0.0 ‘$7,008 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1, ALTERNATIVE A) 2013 1560.0 6644.6 308.7 7043.3 00 0.0 7043.3 $3,585 $3,424 $0 $0 $0 $0 $0.0 $0 $7,008 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2014 1574.8 6750.9 405.1 7186.0 & © co 7156.0 $3,585 $3,424 $0 $0.0 $7,008 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 DATE - 07/17/93, PAGE 2 of 4 6. OPERATING EXPENSES ($1000) A POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators (O&M Materials Fuel Insurance 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS D. ADMIN & GEN. EXPENSES Form Corporation/Uilty ‘APUG Filing Office Equip. INHouse General Manager. BoVExec. Secretary Financial Mor. Admin. See. Staff Engineer Operations Manager Secretary Rent Mise 1994 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $25.0 $10.0 $15.0 $93.8 $43.8 $56.3 $0.0 $0.0 $0.0 $0.0 $12.0 $12.0 1995 sss $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $721.2 $0.0 $0.0 $40.0 $40.0 $97.0 $45.3 $58.2 $0.0 $0.0 $0.0 $0.0 $124 $124 1996 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $764.4 $0.0 $0.0 $414 $414 1907 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $809.7 $0.0 $0.0 $428 $428 $0.0 $0.0 $0.0 $0.0 $0 $10 so $103.9 $48.5 $624 $0.0 $0.0 $0.0 $133 $133 1908 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $857.2 $443 $44.3 $0.0 $0.0 $0.0 $0.0 $0 0 $0 $107.6 $60.2 $64.5 $0.0 $0.0 $0.0 $0.0 $138 $13.8 1999 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $907.1 $0.0 $0.0 $45.9 $45.9 $0.0 $0.0 $0.0 $0.0 $0 $0 90 $114.3 $520 $06.8 $0.0 $0.0 $0.0 $0.0 $14.3 $143 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $050.5 $0.0 $0.0 $47.5 $47.5 $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 $1,014.4 $0.0 $0.0 $49.2 $49.2 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $110.3 $55.7 $71.6 $0.0 $0.0 $0.0 $0.0 $15.3 $153 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,071.9 $0.0 $0.0 $50.9 $60.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,132.5 $0.0 $0.0 $52.7 $52.7 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $1,202.68 $0.0 $0.0 $64.5 $54.5 $0.0 $0.0 $0.0 $0.0 $132.2 $01.7 $79.3 $0.0 $0.0 $0.0 $0.0 $16.0 $16.9 $1,276.7 $0.0 $0.0 $56.4 $56.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,364.3 $0.0 $0.0 $68.4 $58.4 $0.0 $0.0 $0.0 $0.0 $0 $10 $0 $141.7 $06.1 $85.0 $0.0 $0.0 $0.0 $0.0 $18.1 $18.1 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,435.7 $0.0 $0.0 $60.4 $60.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,821.2 $0.0 $0.0 $62.6 $62.6 $0.0 $0.0 $0.0 $0.0 $0 so $161.8 o $0.0 $0.0 $0.0 $19.4 $19.4 $64.7 $0.0 $0.0 $0.0 $0.0 $0 $10 $0 $187.1 $73.3 $04.2 $0.0 $0.0 $0.0 $0.0 $20.1 $20.1 2010 $0.0 $0.0 $0.0 $0.0 $0 $0 $162.6 $75.9 $07.5 $0.0 $0.0 $0.0 $20.8 2011 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,803.9 $0.0 $0.0 $60.4 $69.4 $0.0 $0.0 $0.0 $0.0 2012 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,007.4 $71.8 $71, $0.0 $0.0 $0.0 $0.0 $10 $0 $174.1 $81.3 $104.5 $0.0 $0.0 $0.0 $0.0 $223 $22.3 2013 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $2,016.1 $0.0 $0.0 $74.3 $743 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $180.2 $84.1 $108.1 $0.0 $0.0 $0.0 $23.1 $23.1 2014 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $2,120.0 $0.0 $0.0 $76.9 $76.9 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $186.5 $87.1 $111.9 $0.0 $0.0 $0.0 $23.9 $23.9 DATE - 07/17/83, PAGE 3 of 4 €. CONSUMER ACCOUNTS: IN-House Biling/Data Entry Clerk Customer Service Office Clerk ‘Accountant ‘Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES TO BETHEL 1H. EXPENSES-SALES TO BETHEL |, AVG. COST $/KWH INCLUDING LOSSES 7, PIMANCIAL FORECAST A. AVG. SIKWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES TOTAL EXPENSES KWH SALES: KWH SALES TO BETHEL UTILITIES INTEREST AT 6% WASTE HEAT SALES TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) 1904 $0.0 $0.0 $0.0 $0.0 $0.0 $267.8 $267.8 ($267.6) $482.3 $0.0 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $1,108.98 $0.0 $1,108.9 $0.276 $0.240 $482.3 $1,108.9 $1,108.9 $1,046.9 $0.0 $0.0 $0.0 $1,046.9 ($62.0) $420.2 $272 1996 $0.0 $0.0 90.0 $0.0 $0.0 $1,162.8 $1,162.86 $0.283 $0.285 $420.2 $1,1628 $1,162.86 $1,130.7, $0.0 4 $0.0 $4,940.4 ($21.7) $308.5 $54.3 1997 1998 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $4,229.2 $1,278.2 $00 $0.0 $1,2292 $1,2782 $0.292 © $0.297 FINANCIAL FORECAST $0.265 = $0.270 $3085 86 $384.9 $1,2282 $1,278.2 $1,2202 $1,2782 91,2129 $1,2648 $0.0 $0.0 $27 $44 $0.0 $0.0 $1,215.68 $1,268.8 ($13.6) ($9.3) $3849 = $375.8 $815 $108.6 1999 2000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,339.9 $1,439.5 $0.0 $0.0 $1,330.90 $1,430.5 90.304 © 80.319 $0.275 © $0.300 $375.6 «6 $358.9 $1,330.9 $1,430.5 $1,330.9 $1,430.58 $1,317.7 $1,362.2 $0.0 $0.0 $6.4 $0.8 $0.0 $0.0 $1,323.2 $1,380.0 ($16.7) ($80.5) $358.9 «= $278.3 $1358 8 ©6$162.8 $0.0 $0.0 $0.0 $0.0 $0.0 $1,472.14 $1,472.41 $0.320 $0.320 $278.3 $1,472.1 $1,472.41 $1,474.0 $0.0 $6.1 $0.0 $1,482.1 $10.0 $288.4 $190.1 2002 $0.0 $0.0 $0.0 $0.0 $0.0 $1,542.8 $0.0 $1,542.8 $0.328 2003 $0.0 $0.0 $0.0 $0.0 $0.0 $1,041.9 $0.0 $1,641.9 $0.342 $0.340 $307.8 $1,641.9 $1,641.9 $1,633.6 $0.0 $10.9 $0.0 $1,644.85 $2.6 $310.3 $244.4 2004 $0.0 $0.0 $0.0 $0.0 $00 $4,704.3 $00 $1,701.3 90.345 $0.350 $3103 $1,701.3 $1,701.3 $1,727.5 $0.0 $122 $0.0 $1,739.7 $38.3 $348.7 $2716 $0.0 $0.0 $0.0 $0.0 $0.0 $1,789.8 $1,789.8 $0.353 $0.360 $348.7 $1,789.68 $1,789.8 $1,823.9 $0.0 $13.6 $1,837.5 $477 $3984 $208.7 2006 = 2007-2008 $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 $1,892.5 $4,979.5 $2,081.2 $0.0 $0.0 $0.0 $1,802.5 $1,970.85 $2,081.2 30.364 $0.372 90.381 $0.370 $0.380 $0.380 $3064 © $441.9 = $503.3 $1,8925 $1,0795 $2,081.2 $1,892.5 $1,9705 $2,081.2 $1,923.0 $2,024.7 $2,074.4 $0.0 $0.0 $0.0 $14.9 $16.3 $17.7 $0.0 $0.0 $0.0 $1,037.9 $2,041.0 $2,092.0 $46.5 $61.4 $10.9 $441.8 $503.3 $514.2 $325.9 $353.0 $380.2 $0.0 $0.0 $0.0 $0.0 $0.0 $2,118.3 $2,115.3 $0.378 $0.30 $514.2 $2,115.3 $2,115.3 $2,180.0 $19.0 $0.0 $2,199.0 $03.7 $507.8 $404.7 2010 $0.0 $0.0 $0.0 $0.0 $0.0 $2,216.7 $2,216.7 90.387 $0.390 $597.9 $2,216.7 $2,216.7 $2,231.0 $0.0 $20.2 $0.0 $2,251.3 $34.5 $632.5 $429.3 2011 $0.0 $0.0 $0.0 $0.0 $0.0 $2,333.4 $0.380 $0.300 $632.5 $2,333.4 $2,333.4 $2,282.0 $0.0 $21.5 $0.0 $2,303.5 ($29.9) $602.6 $453.8 2012 $0.0 $0.0 $0.0 $0.0 $0.0 $2,485.5 $2,468.5 $0.412 $0.410 $602.6 $2,465.5 $2,465.5 $2,452.7 $0.0 $22.7 $0.0 $2,478.4 $9.9 $612.5 $478.3 $0.425 $612.5 $2,583.3 $2,583.3 $2,598.0 $0.0 $23.9 $0.0 $2,622.0 $38.7 $651.2 $502.8 $0.430 $051.2 $2,707.1 $2,707.41 $2,670.7 $0.0 $25.1 $0.0 $2,695.8 ($11.3) $630.9 $627.4 DATE - 07/17/83, PAGE 4 of 4 8. VILLAGE UTILITY COSTS O&M Fuel Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS 9. ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITHOUT PCE Residential ‘Small Commercial Large Commercial 10, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITH PCE PCE $/KWH 1904 $700.9 $650.8 $220.8 $0.0 $1,8725 $0.449 $0.480 $0.480 0.350 $0.098 $0.12 $0.12 $0.35 $7722 $7722 $7722 1995 $40.0 $0.0 $04.8 $1,100.7 $1,244.85 $0.310 $0.337, $0.101 90.11 $0.11 $0.28 $480.6 $464.3 $1,236.58 1996 $414 $0.0 $100.5 $1,208.1 $1,360.0 $0.328 90.357 $0.325 $0.299 $0,105 90.12 $0.12 $0.30 $529.1 $403.9 $1,730.4 1997 $42.8 $0.0 $106.6 $1,285.6 $1,435.14 90.341 $0370 $0.337 $0.310 $0.109 $0.12 $0.12 $0.31 $510.3 $2,240.7 1988 $443 ($45.9 i $0.0 $110.5 $1,306.8 $1,862.2 $0.354 90.385 $0.351 $0.322 $0112 $0.116 $0.13 $0.13 $0.12 $0.13 $032 $0.32 $580.5 = $613.4 $513.7 $516.4 $2,754.4 $3,270.09 1999 2000 2001 475 $1,731.09 $0,384 90.418 0.380 $0360 $49.2 $0.0 $133.8 $1,608.3 $1,881.2 $0.408 90.444 $0.404 $0.372 $0.125 = $0.129 $0.14 $0.15 $0.14 $0.14 $0.37 $0.38 $767.7 «= $810.3 $003.4 $615.3 $4,440.9 $5,056.2 2003 2004 2005 $56.4 $0.0 $168.8 $2,101.5 $2,326.7 $0.459 $0.499 $0.455, $0.418 $0.134 90.138 $0.143 $0.18 $0.16 $0.16 $0.16 $0.16 $0.16 $0.39 $0.41 $0.42 $8530 $904.8 $956.8 $626: $041.4 = $655.4 $5,6828 $6,324.2 $6,979.6 $58.4 $0.0 $179.3 $2,215.6 $2,453.3 $0.472 $0.513 $0.467 $0.430 $0.148 $0.17 90.16 $0.43 $1,010.0 $088.4 $7,648.0 2007 $00.4 $0.0 $190.2 $2,332.8 $2,583.4 0.485, $0.527 $0.480 $0.441 90.153 $0.17 $0.17 $0.44 $1,064.2 $680.5 $8,328.4 $62.6 $0.0 $201.7 $2,300.1 $2,654.3 90.486 $0.529 90.481 90.442 $0.159 $0.18 $0.17 $0.44 $1,082.6 $068.8 $8,997.2 $04.7 $0.0 $213.8 $2,511.7 $2,790.2 $0.499 $0.543 $0.404 $0.454 0.164 $0.18 $0.18 $0.45 $1,137.8 $679.1 2010 $67.0 $0.0 $226.4 $2,570.6 $2,064.0 $0.501 $0 544 $0.496 90.456 $0.170 $0.19 $0.19 $0.48 $1,186.0 $006.1 2011 $80.4 $0.0 $239.7 $2,620.3, $2,938.4 $0.502 $0.46 $0.497 90.457 $0.176 $0.19 $0.19 $0.48 $1,171.0 $052.5 2012 $718 $0.0 $253.6 $2,825.9 93,151.4 $0.627 $0.873 $0.522 $0.479 $0.182 $1,267.86 $682.5 2013 $74.3 $0.0 $268.3 $2,093.4 $3,336.0 90.546 $0.593 $0.540 $0.497 $0,188 $0.21 $0.21 $0.50 $1,346.4 $700.3 2014 $76.9 $0.0 $282.1 $3,077.1 $3,496.1 90.553 $0.601 90.548 90.503 90.195 $0.22 $0.21 $0.50 $1,375.7 $001.4 $9,676.3 $10,342.4 $10,004.98 $11,677.4 $12,377.7 $13,069.1 DATE - 07/17/93, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine %Grant Hydro Loan Period initial Capital 4. LOAD DEMAND G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES 1H. MWWH PURCHASES: FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) (A TRANSMISSION LINE Yrt ‘3. INITIAL CAPITAL TOTAL TIMATED RATEBASE 5, DEBT SERVICE (31000) ‘TRANSMISSION LINE. NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL ‘SMALL BUSINESS ADMIN. LOAN TOTAL 100% ~ Boo88e 1994 1032.1 42545 4254.5 ss ss 38 i e3 38 $0.0 $0.0 $0.0 $0.0 $0.0 General inflation Rate Fuel inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate $/kwh, 1994 ———— STAGE 1 1995 1996 1997 1908 1086.2 1080.3 1104.3 (1128.4 4362.0 4460.4 4576.9 4684.3 261.7 268.2 2746 (281.1 4623.7 4737.6 4851.5 4905.4 o ° 0 0 ° 0 o ° ° ° ° 0 00 0.0 oo 00 00 oo 00 00 4623.7 4737.8 4851.5 4065.4 $3,585 «= $3,585 $3,585 = $3,585 $3,424 «= $3,424 $3,424 $3,424 0 $0 $0 $0 $0 $0 $0 $0 so J 0 $50 $0 $0 $0 $0 $0.0 90.0 $0.0 $0.0 $0 $0 $0 $60.0 $750 $750 $750 $750 $7,759 $7,759 $7,759 ($7,869 yo00 v0 »000¢ 000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $00 47 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $146 $823 $823 $823 $82.3 $0.0 90.0 $0.0 90.0 $82.3 $82.3 $8230 ($104.7 3.500% 3.800% 1 3.50% 0.098 1999 1162.5 4791.8 207.8 5079.3 00 00 5079.3 $7,023 $0.0 $0.0 30.8 $0.0 $0.0 $146 $0.0 $106.7 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-2, ALTERNATIVE A) 2000 1176.6 4899.3 294.0 5193.2 °° $750 $8,000 $00 $0.0 $152 $00 $00 $195 $623 $0.0 $117.0 2001 1200.6 300.4 5307.1 eo $3,585, $3,424 $222 $0.0 $80.0 $750 $8,061 90.0 $20.9 90.0 $0.0 $195 $823 $0.0 $122.8 2002 1224.7 5114.2 306.9 5421.0 eo 00 00 5421.0 $3,585 $3,424 $0 $2867 $80.0 $750 $8,126 $0.0 $0.0 $27.4 $0.0 $0.0 $19.5 $82.3 $0.0 $128.9 2003 1249.0 $222.6 313.4 5596.0 00 00 $536.0 $3,585 $3,424 $750 $8,195 $0.0 $0.0 $33.6 $0.0 $0.0 $19.5 $823 $0.0 $135.5 STAGE 2. 2004 2008 2006 2007 2008 2009 2010 2011 2012 2013 2014 12704 1300.2 13803 «13804 «= 1300.5) 1420.6 «= 1459.7 = 1480.8 = 1519.9 1550.0 1874.8 5364.8 507.0 5649.2 ‘8791.4 $933.6 6075.8 6218.0 6360.2 6502.4 6644.6 6750.9 321.9 330.4 339.0 UTS 356.0 364.5 373.1 381.6 390.1 308.7 405.1 5606.7 5837.4 50882 6138.9 62806 6440.3 6501.1 6741.8 6802.5 7043.3 7186.0 oO 0 ° ° ° ° ° ° o 0 ° ° ° 0 ° ° ° 0 ° 0 0 0 ° ° ° ° 0 ° ° ° 0 ° ° 00 0.0 00 0.0 0.0 00 0.0 0.0 0.0 00 0.0 00 00 00 00 00 oo 00 00 00 00 00 seee7 5837.4 «$088.2 «6138.9 «6289.6 «= 6440.3 6501.1 6741.8 © 6802S = 7043.3 7188.0 $3,585 $3,585 $3,585 $3,585, $3,585 $3,585 $3,585 $3,585 $3,585 $3,585 $3,585 $3424 «$3,424 «$3,424 «$3,424 $3,424 $3,424 $3,424 «$3,424 $3,424 $3,424 $3,424 $0 $0 $0 $0 $0 so $0 $0 $0 $0 $0 $0 $0 so $0 $0 so $0 $0 $0 so so $430 ‘$509 $593, $681 $776 $876 $982 $1,095 $1,214 $1,340 $1,474 $0 $0 0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $80.0 $0 $0 so $0 $0 $0 $0 $0 $0 $0 $750 $750 $750 $750 $750 $0 $0 $0 $0 $0 $0 $8,269 $8,268 $8,352 $8,440 $8,535 $7,885 $7,991 $8,104 $8,223 $8,349 $8,483 000 v0 000 v0 000 y000 2000 3000 000% y000 v0 $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 $40.6 $48.0 $55.9 $64.3 $732 $82.7 $92.7 $103.3 $114.6 $126.5 $130.1 $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 30.0 $19.5 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $623 $623 $623 $82.3 $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 $142.5 $130.4 $138.3 $146.7 $155.6 $82.7 $927 103.3 $1148 $126.5 $139.4 DATE - 07/17/03, PAGE 2 of 4 6, OPERATING EXPENSES ($1000) ‘A POWER PRODUCTION COSTS 4. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators O&M Materials Fuel Insurance: 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS IN-House O&M Labor O&M Materials: Contractor O&M Labor O&M Materials 1994 $0 $0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 ———STAGE 1 1905 1998 $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 $721.2 $704.4 $0.0 $0.0 $0.0 $0.0 $40.0 © $41.4 $40.0 © $41.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $0 so $0 $97.0 $100.4 $453 $46.9 $582 $60.3 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $124 $12.0 $124 $129 $124 $12.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $809.7 90.0 $0.0 $42.8 $42.8 $0.0 $0.0 $0.0 $0.0 $10 $103.9 $48.5 $62.4 $0.0 $0.0 $0.0 $0.0 $13.3 $13.3 $13.3 1998 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $45.0 $887.2 $44.3 $443 $0.0 $0.0 $443 $44.3 1999 2000 2001 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $90.0 $907.1 $0.0 $0.0 $45.9 $45.9 $0.0 $0.0 $45.9 $45.9 $0 $0 $0 $111.3 $52.0 $66.8 $0.0 $0.0 $0.0 $0.0 $143 $14.3 $143 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $105.0 $050.5 $0.0 $0.0 $47.8 $47.5 $0.0 $0.0 $47.8 $47.5 $25 $10 $0 $115.2 $53.8 $69.1 $0.0 $0.0 $0.0 $0.0 $14.8 $14.8 $14.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $108.7 $1,014.4 $0.0 $0.0 $49.2 $49.2 $0.0 $0.0 $49.2 $49.2 $0 so $0 $119.3 $55.7 $71.6 $0.0 $0.0 $0.0 $0.0 $15.3 $15.3 $15.3 2002 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $112.5 $1,071.9 $0.0 $0.0 $50.9 $60.9 $0.0 $0.0 $0 $0 $0 $123.5 $67.6 $74.4 $0.0 $0.0 $0.0 $0.0 $15.8 $15.8 $15.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $116.4 $1,132.58 $0.0 $0.0 $52.7 $62.7 $0.0 $0.0 $62.7 $52.7 $0 $10 $15 $127.8 $50.6 $76.7 $0.0 $0.0 $0.0 $0.0 $16.4 $16.4 $16.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $120.5 $1,202.8 $0.0 $0.0 $54.5 $54.5 $0.0 $0.0 $54.5 $54.5 $0 $132.2 $61.7 $79.3 $0.0 $0.0 $0.0 $0.0 $16.9 $16.9 $16.9 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $124.7 $1,276.7 $0.0 $0.0 $56.4 $56.4 $0.0 $0.0 $56.4 $56.4 $136.9 $63.9 $62.1 $0.0 $0.0 $0.0 $0.0 $17.5 $175 $175 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $129.1 $1,364.3 $0.0 $0.0 $58.4 $58.4 $0.0 $0.0 $58.4 $58.4 $10 $0 $141.7 $66.1 $85.0 $0.0 $0.0 $0.0 $0.0 $16.1 $18.1 $18.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $133.6 $1,435.7 $0.0 $0.0 $60.4 $60.4 $0.0 $0.0 $60.4 $60.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $138.3 $1,821.2 $0.0 $0.0 $62.6 $62.6 $0.0 $0.0 $62.6 $62.6 $0 $0 $0 $151.8 $70.8 $91.1 $0.0 $0.0 $0.0 $0.0 $19.4 $19.4 $19.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $143.1 $1,611.0 $0.0 $0.0 $64.7 $64.7 $64.7 $64.7 $0 $10 $17.1 $73.3 $04.2 $0.0 $0.0 $0.0 $0.0 $20.1 $20.1 $20.1 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $148.1 $1,706.1 $0.0 $0.0 $67.0 $67.0 $0.0 $0.0 $67.0 $67.0 $0 $0 so $1626 $75.9 $97.5 $0.0 $0.0 $0.0 $0.0 $208 $20.8 $20.8 2011 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $153.3 $1,803.9 $0.0 $0.0 $69.4 $69.4 $60.4 $69.4 $0 $0 $0 $168.3 $78.5 $101.0 $0.0 $0.0 $0.0 $0.0 $21.5 $21.5 $21.5 2012 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $158.7 $1,907.4 $0.0 $0.0 $71.8 $71.8 $0 $10 $0 $174.1 $81.3 $104.5 $0.0 $0.0 $0.0 $0.0 $22.3 $22.3 $22.3 2013 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $164.2 $2,016.1 $0.0 $0.0 $743 $74.3 $0.0 $0.0 $74.3 $743 $0 $0 $0 $180.2 $84.1 $108.1 $0.0 $0.0 $0.0 $0.0 $23.1 $23.1 $23.1 2014 30.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $170.0 $2,120.0 $0.0 $0.0 $76.9 $76.9 $0.0 $0.0 $76.9 $76.9 $0 $0 $186.5 $87.1 $111.9 90.0 $0.0 $0.0 $0.0 $23.9 $23.9 $23.9 DATE - 07/17/83, PAGE 3 of 4 ——8TAGE 1____ STAGE 2. 1904 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 €. CONSUMER ACCOUNTS IN-House Billing/Date Entry Clerk $0.0 $0.0 $0.0 $0.0 $37.5 $38.8 $40.2 $41.6 $43.0 $44.5 $46.1 $47.7 $40.4 $51.1 $52.9 $54.7 $66.7 $68.6 $60.7 $62.8 $65.0 Customer Service $0.0 $0.0 $0.0 $0.0 $375 $38.8 $40.2 $416 $43.0 $445 $46.4 $47.7 $40.4 $61.1 $62.9 $54.7 $56.7 $58.6 $60.7 $62.8 $65.0 Office Clerk $0.0 $0.0 $0.0 $0.0 $25.0 $25.9 $26.8 $27.7 $28.7 $20.7 $30.7 $31.8 $329 $34.1 $35.3 $36.5 $37.8 $30.1 $40.5 $41.9 $43.3 Accountant $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 Contractor $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 F. TOTAL EXPENSES ($1000) $294.8 $4,124.3 $4,175.6 —$4,242.5 $1,545.0 $1,663.9 $1,796.1 $4,845.7 $1,934.2 $2,054.9 $2,130.8 $2,220.41 $2,344.1 $2,453.4 $2,578.3 $2,636.7 $2,763.58 $2,908.7 $3,086.58 $3,213.2 $3,367.3 G. ENERGY SALE REVENUES $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 TO BETHEL H. EXPENSES-SALES TO BETHEL $204.8 $1,121.3 $1,175.6 $1,242.5 $1,545.0 $1,663.9 $1,706.1 $1,8457 $1,934.2 $2,051.90 $2,130.8 $2,2201 $2,3441 $2,4534 $2,5783 $2,636.7 $2,763.5 $2,906.7 $3,0065 $3,2132 $3,3673 |, AVG. COST $/KWH INCLUDING LOSSES 3000 $0.279 «= $0.286 $0.295 $0.358 $0377 $0308 $0401 $0411 $0.427 $0.432 $0.438 90.451 $0.460 $0.472 $0.472 $0.483 $0.497 90.513 90.526 $0.542 FINANCIAL FORECAST 7. FINANCIAL FORECAST A ANG. $/KWH WHOLESALE COST $0449 §=6$0.230 «= $0.250 $0270 ©$0.300 $0340 $0390 $0400 $0.400 $0.420 $0.420 $0.430 $0.450 $0.450 $0.470 $0.470 $0.470 $0.480 $0.510 0.520 $0.30 8. BEGINNING YEAR BALANCE ($1000) $750.0 $4553 $337.2 $280.2 $2762 $1406 $1114 $1216 $160.1 $160.9 $191.4 $191.5 $2106 $268.6 $2788 $334.9 $306.7 $305.9 $3744 $438.0 $485.4 OPERATING EXPENSES $204.8 $1,121.3 $1,175.6 $1,2425 $1,545.0 $1,663.9 $1,796.1 $1,845.7 $1,034.2 $2,051.9 $2,130.8 $2,220.1 $2,344.1 $2,453.4 $2,578.3 $2,636.7 $2,763.55 $2,908.7 $3,006.5 $3,2132 $3,3673 RETURN ON RATEBASE @ 13% $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 $00 $0.0 $0.0 $0.0 TAXES $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 TOTAL EXPENSES $204.8 $1,121.3 $1,175.6 $1,2425 $1,545.0 $1,663.9 $1,706.1 $1,845.7 $1,034.2 $2,051.90 $2,130.86 $2,220.1 $2,344.1 $2,453.4 $2,578.3 $2,636.7 $2,763.6 $2,908.7 $3,066.5 $3,213.2 $3,367.33 KWH SALES: $0.0 $1,003.3 $1,117.4 $1,235.8 $1,405.3 $1,620.2 $1,757.90 $1,842.5 $1,882.0 $2,018.0 $2,073.0 $2,178.6 $2,338.86 $2,307.6 $2,565.7 $2,627.2 $2,688.7 $2,808.7 $3,050.9 $3,178.8 —$3,291.7 KWH SALES TO BETHEL UTILITIES $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 INTEREST AT 5% $0.0 $0.0 $14 $2.7 $41 $5.5 $68 $82 $0.6 $1141 $12.5 $14.0 $154 $16.9 $183 $10.8 $21.2 $22.6 $24.0 $25.5 $26.9 WASTE HEAT SALES $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 15 $425 $43.4 443 $45.5 $46.7 $479 $49.1 $60.3 $51.5 962.7 $53.9 $55.1 $56.3 $57.2 TOTAL REVENUES $0.0 $1,003.3 $1,118.7 $1,238.58 $1,409.4 $1,634.7 $1,806.2 $1,803.2 $1,995.0 $2,073.44 $2,131.0 $2,230.2 $2,402.1 $2,463.6 $2,634.3 $2,608.5 $2,762.6 $2,685.2 $3,130.1 $3,260.6 $3,375.9 REVENUES - EXPENSES ($204.8) ($118.1) ($86.9) ($4.0) ($135.6) ($29.2) $10.2 475 $0.9 $214 $0.1 $19.1 $58.0 $10.2 $56.1 $61.9 (80.9) ($21.5) $63.6 $47.4 $8.7 END OF YEAR BALANCE ($1000) $455.3 «$337.2 $280.2 $276.2 «$140.8 «= $1114 = 8124.6 $188.1 ($188.9 $1944 $191.5 $210.6 $268.6 $2788 $334.9 $396.7 $306.9 $3744 ‘$438.0 $485.4 $494.0 MINIMUM RETAINED EARNINGS $0.0 $27.2 $54.3 $815 $1000 $136.7 $1647 $1930 $221.4 $250.1 $279.0 $308.0 $3372 $366.7 $306.6 $424.2 $462.2 $480.5 $509.3 $538.5 $568.2 REQUIREMENT ($1000) NET RETURN ON INVESTMENT 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% 8, REGIONAL UTILITY ESTIMATED AVG, RATES WITHOUT PCE Residential 3000 100 0900 wox = $0.328) $0.370 $0424 «= 80.435 0.435 $0.487 $0.457 $0.467 30.489 $0.489 $0.611 $0.511 $0.511 $0.522 0.584 $0.565 $0.576 ‘Small Commercial 3000 3000 000 won $0.297 $0.337 80.386 §=— $0.306 $0,306 90.416 $0.416 $0.426 90.446 $0.446 $0.465, $0.465 $0.465 $0.475 $0.505 $0.515 0.525 Large Commercial 3000 2000 000 wox 0.273 «$0.09 «$0355 = 80.364 = 30.364 $0,382 $0.382 $0.301 90.410 $0.410 90.428 90.428 $0.428 $0.437 0.464 $0.473 $0.482 DATE - 07/17/93, PAGE 4 of 4 9, VILLAGE UTILITY COSTS O&M Fuel Admin & Gen. Expenses: Purchases from G8T/Regional Utility TOTAL ANNUAL COSTS 40. ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITHOUT PCE Residential ‘Small Commercial Large Commercial 41, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential Large Commercial ANNUAL PCE PAYMENTS: PW Annual PCE Payments ACCUMLATED PW PCE $0.12 $0.12 $0.35 $7722 $7722 $7722 $0.101 — $0.108 $0.11 $0.12 $0.11 $0.12 $0.27 $0.29 $444.3 $603.3 $4203 $460.8 $1,201.5 $1,671.4 1998 000 1000 000 y000 2000 v0 $0.326 $0.297 $0.273 $0.109 = $0.112 $0.12 $0.12 $0.12 $0.12 $0.31 $0.27 $564.7 $473.9 $5093 = $412.9 $2,180.7 $2,593.6 3 i S888 &§ 33s 883 90.116 $0.13 $0.13 $0.31 $577.5 $486.2 $3,0708 SAGE? $0.424 $0.386 $0.385 $0.120 90.14 $0.13 $0.36 $711.2 $578.6 $3,658.4 Eoaigde 8 90.435 30.306 0.364 90.125 $0.14 $0.14 $0.36 $745.6 $586.0 ioagnne 8 $0.435 $0.306 $0 364 $0.129 $0.14 $0.14 $0.36 $753.4 $572.2 $4,2445 $4,816.6 a onnnde 8 $0.457 $0.416 90.382 $0.134 $0.15 $0.15 $0.38 $815.8 $508.5 $5,415.2 Ennne 8 30.457 30.416 $0.362 $0.138 $015 $0.15 $038 $629.2 $587.9 $6,003.0 EOHHEEE 8 90.467 90.426 $0.301 $0.143 $0.16 $0.16 $0.39 $870.9 $506.5 $6,599.6 EOREHEEE 3 90.489 90.446 $0.410 90.148 $0.17 90.16 $0.41 $043.3 $6243 $7,2238 bonnnEE $0.489 $0.446 $0.410 $0.153 $0.17 $0.17 $0.41 $955.6 $611.0 $7,834.8 2008 2009 2010 2011 000 3000 2000 2000 2000 3000 3000 »000 000 000 y00K 2000 y000 v0 y000 2000 000 000 2000 r000 000 000 yo00% 2000 90.511 $0.511 $0.511 $0.522 $0.465 $0.465 $0.465 $0.475 $0.428 © $0.428 «= $0.428 = $0.437 90.159 $0.18 $0.17 $0.43 $1,030.6 \e 094; $636.7 $606.4 $609.7 $8,471.5 $9,093.3 201: § EERE 0.554 $0.505 90.464 $0.182 $0.20 $0.20 $0.46 $1,208.1 $650.4 2013 2014 000 7000 000 000 000 y000K vo0% v0 v0 v0 y00%K y000 $0.565 30.576 90.515 $0.525 $0473 $0.482 $0.188 = -$0.195 $0.21 $0.21 $0.20 $0.21 $0.47 $0.48 L7 $1,280.86 $651.6 9648.1 $0,699.7 $10,300.4 $10,950.90 $11,611.85 $12,250.68 DATE - 07/17/93, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine ‘%Grant Hydro Loan Period Initial Capital 4. LOAD DEMAND VILLAGES ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 6% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL E. DEMAND - KWH F. ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES 1H. MWWH PURCHASES: FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES E. NEW GENERATOR F. COMPUTER SYSTEM ‘3. INITIAL CAPITAL TOTAL 4, ESTIMATED RATEBASE 5, DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO (NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL SMALL BUSINESS ADMIN. LOAN TOTAL 100% 100% see Boo 1994 1032.1 4284.6 00 4254.5 eo 00 0.0 00 $3,585 General Inflation Rate Fuel Inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate $/kwh, 1994 ———S Tage 1 1995 1008 1907 1086.2 1080.3 1104.3 43620 4400.4 «(4576.9 261.7 © 288.2 2748 4623.7 47378 (4851.8 ° ° ° 0 0 0 ° 0 ° 0.0 00 00 0.0 0.0 0.0 4623.7 47376 4851.5 $3,585 $3,585 ($3,585 $3,424 $3,424 «($3,424 $0 $0 $0 so so $o $0 $0 $0 $0 30 $0 soo = $0.0 $0.0 $0 $0 $0 $750 $750 $750 $7,759 $7,758 $7,758 ox (0K 00 soo = $0.0 $0.0 $00 = $0.0 $0.0 $00 $0.0 $0.0 $00 $0.0 $0.0 $00 = $0.0 $0.9 $0 $0 $0 $023 $823 $823 $00 © $0.0 $0.0 $8230 ($82.3 382.3 3.500% 3.50% $0,098 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE A) ——STAGE 2— 1998 1999 11284 © 11525 4684.3 4701.8 281.1 287.5 4905.4 8079.3 ° 0 ° 0 0 0 0.0 0.0 0.0 0.0 4965.4 5079.3 $3,585 $3,585 $3,424 = $3,424 $0 $0 $0 $0 $50 $104 $0 $0 $0.0 $0.0 $60.0 $60.0 $750 $750 $7,869 = $7,023 000 7000 $0.0 $0.0 $0.0 $0.0 $47 $9.8 90.0 $0.0 $0.0 $0.0 $146 814.6 $623 © $82.3 $0.0 $0.0 $104.7 = $106.7 1176.6 4899.3 204.0 5193.2 41272 0.0 0.0 0.0 $3,585 $3,424 90 $0 $233 $6,000 $0.0 $80.0 $750 $14,072 $3,413 $0.0 $0.0 $22.0 $806.4 $0.0 $10.5 $82.3 $204.8 $895.0 2001 1200.6 5006.7 300.4 6307.1 6964 43781 0.0 0.0 0.0 $3,585, $3,424 $0 $0 $322 $6,000 $0.0 $80.0 $750 $14,164 $3,302 $0.0 $0.0 $30.3 $506.4 $0.0 $19.5 $82.3 $204.8 $903.4 2002 1224.7 5114.2 308.9 5421.0 7132 0.0 0.0 0.0 $3,585 $3,424 $0 $0 $418 $6,000 $1,125 $80.0 $750 $15,380 $4,321 $0.0 $0.0 $30.3 9506.4 $108.2 $195 $823 $204.8 $1,018.5 2003 1249.0 5222.6 3134 5536.0 44534 0.0 00 00 $3,585 $3,424 $0 $0 $517 $6,000 $1,125 $80.0 $750 $15,484 $4,222 $0.0 $0.0 $488 $566.4 $106.2 $105 $82.3 $0.0 $823.2 1279.1 $364.8 321.9 6686.7 7420.0 45325.9 0.0 00 00 $3,585 $3,424 $0 $624 $6,000 $1,125 $80.0 $750 $15,588 $4,120 $0.0 $0.0 $58.9 $566.4 $106.2 $195 $823 $0.0 $833.3 ———s TA 7540.0 46117.8 0.0 0.0 00 $3,585 $3,424 $0 $0 $738 $6,000 $1,125 $0 $780 $15,622 $3,963 $0.0 $0.0 $69.7 $566.4 $106.2 $0.0 $82.3 $0.0 $824.6 1330.3 5649.2 330.0 5988.2 7660.0 0.0 0.0 0.0 $3,585 $3,424 $0 $0 $859 $6,000 $1,125 $750 $15,743 $3,884 $0.0 $0.0 $81.1 $506.4 $106.2 $0.0 $623 $0.0 $836.0 2007 1369.4 8791.4 3475 6138.9 7780.0 47701.8 0.0 0.0 0.0 $3,585 $3,424 $0 $0 $988 $6,000 $1,125 $0 $750 $15,872 $3,813 $0.0 $0.0 $93.3 $566.4 $106.2 $0.0 $62.3 $0.0 $848.2 2008 1399.5 366.0 6289.6 7900.0 0.0 0.0 0.0 $3,585 $3,424 $0 $0 $1,125 $6,000 $2,575 $750 $17,459 $5,200 $0.0 $0.0 $108.2 $566.4 $243.1 $0.0 $823 $0.0 $998.0 1429.6 6075.8 3645 6440.3 8020.0 49285.4 00 00 00 $3,585 $3,424 $0 $1,270 $8,000 $2,575 $0 $0 $16,854 $5,145 $0.0 $0.0 $119.9 $566.4 $243.1 $0.0 $0.0 $0.0 $929.3 2010 1469.7 6218.0 373.1 6501.1 8140.0 0077.3 0.0 0.0 0.0 $3,585 $3,424 $0 $0 $1,424 $6,000 $2,575 $0 $0 $17,008 $5,090 $0.0 $0.0 $134.4 $566.4 $243.1 $0.0 $0.0 $0.0 $943.9 2011 1489.8 3818 6741.8 8260.0 00 0.0 0.0 $3,585 $3,424 $0 $0 $1,587 $6,000 $2,575 $0 $0 $47,174 $0.0 $0.0 $149.8 $566.4 $243.1 $0.0 $0.0 $0.0 $959.3 2012 1519.9 6502.4 390.1 6892.5 6380.0 51661.1 0.0 00 0.0 $3,585 $3,424 $0 $0 $1,760 $6,000 $2,575 $o $0 $17,344 $5,035 $0.0 $0.0 $166.2 $566.4 $243.1 $0.0 $0.0 $0.0 $975.6 2013 2014 1880.0 1874.8 6644.6 6750.9 398.7 408.1 7043.3 7156.0 8500 8636.0 $2453 3292.2 ° ° 0.0 0.0 0.0 00 0.0 0.0 $3,585 $3,585 $3,424 $3,424 $0 $0 $0 $0 $1,043 $2,137 $6,000 $6,000 $2,575 $2,875 $0 $0 $0 $0 $47,527 $47,724 $6,018 $5,012 $0.0 $0.0 $201.7 $566.4 $243.1 $0.0 $0.0 $0.0 $4,014.2 DATE - 07/17/93, PAGE 2 of 4 6. OPERATING EXPEN! ($1000) ‘A POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Ineurance 2. BETHEL GENERATION PLANT Chiet Plant Operator Six Plant Operators O&M Materials Fuel Insurance 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS. IN-House (O&M Labor O&M Materials ‘Contractor O&M Labor O&M Materials C. DISTRIBUTION IN-House (08M Labor O&M Materials: Contractor 8M Labor 8M Materials D. ADMIN & GEN. EXPENSES Form Corporation/Utility APUC Filing Office Equip. IN-House General Manager. BdExec, Secretary Financial Mgr. Admin, Sec. Staff Engineer Operations Manager Secretary Rent Mise Contractor Attomey/Engr. Consultant 1904 $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 $25.0 $25.0 $15.0 $93.8 $43.6 $56.3 $0.0 $0.0 $0.0 $0.0 $12.0 $12.0 $12.0 ——— STAGE 1. 1996 1995 sss $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $696.8 $0.0 $0.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $97.0 $45.3 $68.2 $0.0 $0.0 $0.0 $0.0 $124 $124 $124 $0.0 $0.0 $41.4 $414 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $100.4 $48.9 $60.3 $0.0 $0.0 $0.0 $0.0 $129 $12.9 $129 1997 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $730.3 $13.3 $13.3 $13.3 ——STAGE 2— 1908 1999 $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 $45.0 $90.0 $747.0 $763.8 $0.0 $0.0 $0.0 $0.0 $44.3 $45.9 $443 $45.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 6 $0 $0 $0 $0 $0 $0 $111.3 $52.0 $66.8 $0.0 $0.0 $0.0 $0.0 $14.3 $14.3 $13.8 $14.3 $0.0 $0.0 $0.0 $85.0 $810.0 $168.0 $5,090.8 $230.0 $105.0 $0.0 $47.8 $47.5 $0.0 $0.0 $160.0 $400.0 $0.0 $0.0 $25 $25 $0 $115.2 $53.8 $69.1 $53.8 $80.0 $80.0 $80.0 $14.8 $50.0 2001 2002 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $88.0 $827.9 $173.9 $5,576.3 $187.4 $108.7 $0.0 $49.2 $80.9 $49.2 © $60.9 $0.0 $0.0 $0.0 $0.0 $165.6 $171.4 $4140 $4285 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $0 $0 $0 $110.3 $123. $578 $74.4 $57.8 $85.7 $85.7 $85.7 $158 $53.6 $53.6 $0.0 $0.0 $0.0 $94.2 $565.4 $186.3 $6,002.9 $0.0 $116.4 $0.0 $52.7 $82.7 $0.0 $0.0 $177.4 $443.5 $0.0 $0.0 $0 $25 $15 $127.8 $50.6 $76.7 $50.6 $88.7 $88.7 $88.7 $16.4 $55.4 $55.4 STAGE 3. 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $108.1 = $111.9 $115.8 $119.9 $124.1 $1329 $137.6 $648.9 $671.6 $695.1 $719.4 $7448 $797.6 $825.5 $213.7 $221.2 $229.0 $237.0 $245.3 $262.7 $271.9 $7,618.2 $7,917.6 $8,335.7 $8,773.4 = $9,231.5 $10,212.6 $10,730.2 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1336 = $138.3) $143.1 $148.1 $183.3 $164.2 $170.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $09.4 $71, $74.3 $76.9 $54.5 $56.4 $58.4 $60.4 $62.68 $64.7 $67.0 $69.4 $71.8 $743 $76.9 $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 $1836 © $190.0 $196.7 $203.6 «= $210.7 $218.1 = $225.7 «$233.6 = $241.8 = $250.2 $250.0 $459.0 $475.1 $491.7 $608.0 $526.7 $545.2 $564.2 $584.0 $604.4 $625.6 $647.5 $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 $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 $25 $0 $0 $25 $0 $0 $25 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $1322 © $136.9 $141.7 $146.6 = $151.8 = $187.1 $162.6 $174.1 $180.2 $186.5 $61.7 $63.9 $66.1 $68.4 $70. $73.3 $75.9 $81.3 $84.1 $87.1 $793 7 $85.0 $88.0 $91. $94.2 $97.5 $1045 © $108.1 $111.9 $61.7 $63. $66.1 $68.4 $70. $73.3 $75.9 $81.3 $64.1 $87.1 $018 $95.0 $98.3 $101.8 $105.3 $109.0 $1128 $120.9 $125.1 $120.5 $01.8 $96.0 $98.3 $101.8 $105.3 $109.0 $1128 $120.9 $125.1 $120.5 $018 $95.0 $98.3 $101.8 $105.3 $109.0 $1128 $120.9 $125.1 $129.5 $16.9 $17.5 $18.1 $18.8 $19.4 $20.1 $20.8 $22.3 $23.1 $23.9 $57.4 $59.4 $61.5 $63.6 $65.8 $68.1 $70.5 $75.6 $78.2 $80.9 $57.4 $50.4 $61.6 $63.6 $65.8 $68.1 $705 $75.6 $78.2 $80.9 DATE - 07/17/83, PAGE 3 of 4 . CONSUMER ACCOUNTS: INHouse Biling/Data Entry Clerk Customer Service ‘Office Clerk ‘Accountant ‘Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES ‘TO BETHEL 1H. EXPENSES-SALES TO BETHEL |, AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST A AVG. SIKWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES ‘TOTAL EXPENSES KWH SALES KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS. REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8. REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Small Commercial Large Commercial 1904 $0.0 $0.0 $0.0 $0.0 $0.0 $204.8 $0.0 $294.8 $0.449 $750.0 $2048 $0.0 $00 $204.8 $00 $0.0 $0.0 $0.0 $0.0 ($204.8) $455.3 $0.0 0.0% ————STAGE 1. — STAGE 2— 1995 1906 1 1998 1909 2000 $0.0 $0.0 $0.0 $3756 $40.2 30.0 $0.0 $0.0 $375 $40.2 $0.0 $0.0 $0.0 $25.0 $26.8 $0.0 $0.0 $0.0 $00 $00.0 $0.0 $0.0 $0.0 $00 90.0 $1,006.0 $1,124.8 $1,163.1 $4,346.14 $1,434.7 $8,011.68 $0.0 $0.0 $0.0 $0.0 $0.0 10.0 $1,006.90 $1,1248 $1,163.1 $1,346.1 $1,434.7 $8,611.6 $0.273 $0.274 $0.276 © $0.312 $0325 = $0.220 FINANCIAL FORECAST $0.250 © $0.250 $0.250 $0.260 © $0.230 $465.3 $448.8 $442.7 $278.0 $95.7 $1,006.9 $1,124.86 $1,163.1 $1,434.7 $8,611.6 $0.0 $0.0 $0.0 $0.0 $443.7 $0.0 $0.0 $0.0 $0.0 $155.3 $1,006.90 $1,1248 $1,163.1 $1,434.7 $9,210.6 $1,000.5 $1,117.44 — $1,144.2 $1,245.9 $9,010.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $14 $27 $5.5 168 $0.0 $0.0 $0.0 $0.0 $371.7 $1,000. $1,1187 $1,146.9 $1,251.3 $9,380.0 (86.5) (86.1) ($16.1) ($147.5) ($183.4) $178.3 $448.8 $442.7 $426.6 = ($279.0 $95.7 = $274.0 $27.2 $54.3 $81.5 $1000 $1367 $333.7 0.0% 0.0% 0.0% 0.0% 6% 000 1000 ox = $0.277 $0.283 $0250 000 000 woox = $0.252 $0.257 | $0.228 000 9000 won = $0.232 $0.37 $0.200 $13,608.86 $13,608.86 $11,073.2 $12,970.5 2014 $65.0 $65.0 $43.3 $104.0 $0.0 $15,530.9 $0.0 $15,539.9 $0.30 90.315 $1,251.6 $15,539.9 $651.6 $228.1 $16,419.6 $16,057.5 $0.0 $60.0 $483.6 $16,601.1 $161.6 $1,433.4 $1,200.0 6.1% $0.342 $0312 $0.287 DATE - 07/17/83, PAGE 4 of 4 8. VILLAGE UTILITY CosTS O8M Fuel ‘Admin & Gen. Expenses Purchases trom G&T/Regional Utity TOTAL ANNUAL COSTS 10, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITHOUT PCE Residential ‘Small Commercial Large Commercial 11, ESTIMATED AVG, RETAIL COST $/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential Small Commercial Large Commercial ANNUAL PCE PAYMENTS PW Annual PCE Payments ACCUMLATED PW PCE 1904 $700.9 $650.8 $220.8 $0.0 $1,872.5 $0.449 $0.480 $0.480 $0.350 $0,098 $0.12 $0.12 $0.35 $772.2 $772.2 $772.2 ————STAGE 4 1995 = 1996 $40.0 $41.4 $00 $0.0 $75.9 $78.1 $1,185.9 $1,184.4 $1,271.8 $1,303. $0317 $0317 $0344 © $0.45 $0314 — $0.314 $0288 $0.280 $0101 $0.05 $0.11 $0.12 $0.11 $0.12 $0.29 $0.29 $495.7 $503.3 $479.0 $460.8 $1,251.2 $1,721.0 1907 $42.8 $0.0 $80.4 $1,212.98 $1,336.1 90.317 $0.345 90.314 $0.289 $0.109 $0.12 $0.12 $0.29 $510.2 $460.2 —STAGE 2— 1908 1999 000 3000 000 3000 000 »000K 2000 y000 1000 v0 y000 000 0.277 — $0.283 $0.252 — $0.257 90.232 $0,237 $0112 $0.116 $0.12 $0.12 $0.12 $0.12 $0.23 $0.24 $3645 = $377.8 $3176 = $318.1 $0.250 $0.228 $0.208 $0.120 90.13 $0.13 $0.21 $301.2 $245.0 $0.125 $0.13 $0.13 $0.21 $208.6 $234.7 $2,181.2 $2,408.09 $2,816.9 $3,061.09 $3,206.6 $0.129 $0.14 $0.13 $0.21 $308.6 $234.4 $3,531.0 $0.261 0.238 $0.218 $0.134 $0.14 $0.14 $0.22 $318.5 $233.7 $3,764.7 $0.261 $0.238 $0.218 $0.138 $0.14 $0.14 $0.22 $316.1 $224.1 $3,088.8 $0.266 $0.243 $0.223 $0.143 $0.15 $0.15 $0.22 $327.3 $224.2 $4,213.0 Sy nyeng $0.248 $0.228 $0.148 $0.15 $0.15 $0.23 $336.1 $223.7 $4,436.7 a ongdny 8 $0.277 $0.252 $0.232 0.183 $0.16 $0.16 $0.23 $348.4 $222.8 $4,659.4 aobngne & $0.293 $0.267 $0.246 $0.159 $0.17 $0.16 $0.25 $300.2 $241.1 $4,900.5 E RnEHE 8 $0,299 $0.272 $0.250 $0.164 $0.17 90.17 $0.25 $400.3 $238.9 $5,139.4 2010 a FREES $0,304 $0.277 $0.255 $0.170 $0.18 $0.18 $0.25 $409.7 $236.3 $5,375.7 2011 § EREEE $0.310 $0.282 $0.250 90.176 $0.18 $0.18 $0.26 $418.5 $233.2 $5,608.90 2012 § REEEE $0.321 $0.292 $0.268 90.182 $0.19 $0.19 $0.27 $444.2 $239.1 $5,848.0 2013 2 RSEEE $0.332 $0.302 $0.278 $0.188 $0.20 $0.19 $0.28 $400.9 $244.4 $6,002.4 2014 § E8888 $0.342 $0.312 $0.287 $0.195 $0.20 $0.20 $0.29 $492.6 $247.6 $6,340.0 DATE - 06/17/83, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine ‘%Grant Hydro Loan Period initial Capital 1, LOAD DEMAND VILLAGES: ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% D. TOTAL ENERGY REQUIREMENTS - MWH_ BETHEL E. DEMAND - KWH F, ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO (USAGE - MWH G. SURPLUS MWH HYDRO SALES TO BETHEL UTILITIES 1H. MWH PURCHASES: FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) ‘A. TRANSMISSION LINE Yet Yr2 B. NYAC HYDRO Yet Yr2 C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES E. NEW GENERATOR 3. INITIAL CAPITAL TOTAL 4. ESTIMATED RATEBASE §. DEBT SERVICE ($1000) ‘TRANSMISSION LINE NYAC HYDRO (NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR INITIAL CAPITAL ‘AEA LOAN: ‘SMALL BUSINESS ADMIN. LOAN TOTAL 100% 100% seg 0.0 00 $7,192 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 00 00 4798.2 $3,742 $3,715 $2,700 $2,689 $0.0 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $623 $0.0 $0.0 $82.3 General inflation Rate Fuel Inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate $/wh, 1994 1996 1080.3 4400.4 4016.4 3249.8 0.0 1606.5 $3,742 $3,715 $2,700 $2,689 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 1907 1104.3 4876.9 487.7 5034.6 3320.7 1679.3 1713.8 $3,742 $3,715 $2,700 $2,889 90.0 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $0.0 $82.3 3.50% $0.008 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE 1908 1128.4 4684.3 5152.8 3391.7 1608.3 1761.1 $3,742 $3,715 $2,700 $2,889 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $0.0 $82.3 1990 1152.5 4791.8 479.2 $271.0 34626 1837.4 1808.4 $3,742 $3,715 $2,700 $2,880 $82.3 (STAGE 1, ALTERNATIVE B) 1176.6 4899.3 5389.2 3533.5 1408.5 1855.7 $3,742 $3,715 $2,700 $2,889 $0.0 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $0.0 2001 1200.6 5008.7 500.7 8807.4 3604.4 1308.6 1903.0 $3,742 $3,715 $2,700 $2,889 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 1224.7 5114.2 511.4 5625.6 3675.4 1324.6 1950.2 $3,742 $3,715 $2,700 $2,680 $0.0 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 2003 1240.0 $222.6 $223 5744.9 3746.9 1253.1 1997.9 $3,742 $3,715 $2,700 $2,889 $0.0 $750 $13,706 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 2004 1270.1 5364.8 $901.3 3840.8 1159.2 2060.5 $3,742 $3,715 $2,700 $2,889 $0.0 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 1309.2 5507.0 $50.7 6087.7 co 3034.6 1065.4 2123.1 $3,742 $3,715 $2,700 $2,889 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 971.5 2185.6 $3,742 $3,715 $2,700 $2,689 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $0.0 2007 1360.4 8791.4 579.1 6370.5 4122.3 877.7 2248.2 $3,742 $3,715 $2,700 $2,889 $0.0 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 1300.5 593.4 6527.0 4216.2 783.8 23108 $3,742 $3,715 $2,700 $2,889 $0.0 $750 $13,796 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $0.0 $82.3 4310.0 690.0 2373.4 $3,742 $3,715 $2,700 $2,880 $13,046 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $3,742 $3,715 $2,700 $2,880 $0 $0 $0.0 $13,046 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2011 1489.8 Peis. ah $3,742 $3,715 $2,700 $2,889 $0.0 $13,048 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2012 1519.9 6502.4 650.2 71828 4591.6 408.4 2561.1 $3,742 $3,715 $2,700 $2,889 $0 $0.0 $13,046 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 2013 1850.0 6644.6 064.5 7309.1 co 4685.4 314.6 2623.6 $3,742 $3,715 $2,700 $2,889 so $0 $0.0 $0 $13,046 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $0.0 2014 18748 6750.9 675.1 7426.0 4755.6 2444 (2670.4 $3,742 $3,715 $2,700 $2,889 $0 $0.0 $13,048 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 DATE - 06/17/93, PAGE 2 of 4 5. OPERATING EXPENSES ($1000) A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance 2. REU DIESEL PLANT ‘Three Plant Operators O&M Materials Fuel Ineurance 3. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators O&M Materials: Fuel ‘neurance 4, VILLAGE OPERATORS 5, COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS INHouse O&M Labor O&M Materials Contractor O8M Labor O&M Materials C. DISTRIBUTION INHouse O&M Labor O&M Materials: Contractor O&M Labor O&M Materials: 0. ADMIN & GEN. EXPENSES Fear oapaeaerny Oce Eup. IN-House General Manager. Bd/Exec, Secretary Financial Mgr. Admin. Sec. Staff Engneer Operations Manager Secretary Rent Miso 1994 $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 $25.0 $10.0 $15.0 $03.8 $43.8 $56.3 $0.0 $0.0 $0.0 $0.0 $12.0 $120 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $739.5 $0.0 $0.0 $40.0 $40.0 1996 $40.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $431.8 $0.0 $0.0 $414 $414 $0.0 $0.0 $0.0 1997 $428 $42.8 $428 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $458.0 $0.0 $0.0 $42.8 $428 $0.0 $0.0 $0.0 $0.0 $10 90 $103.9 $48.5 $624 $0.0 $0.0 $0.0 $0.0 $133 $133 1990 $0 $0 90 $111.3 $52.0 $66.8 $0.0 $0.0 $0.0 $14.3 $14.3 $47.5 $47.5 $47.5 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $544.7 475 $47.5 $0.0 $0.0 $25 $10 #0 $118.2 $53.8 $69.1 $0.0 $0.0 $0.0 $0.0 $148 $148 $49.2 $49.2 $49.2 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $576.5 $0.0 $0.0 $40.2 $40.2 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $110.3 $55.7 $71.6 $0.0 $0.0 $0.0 $0.0 $15.3 $153 $50.9 $50.9 $50.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $123.6 $57.6 $74.1 $0.0 $0.0 $0.0 $0.0 $15.8 $158 $62.7 $52.7 $527 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $645.0 $0.0 $0.0 $52.7 $52.7 $685.7 $0.0 $0.0 $54.5 $54.5 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $132.2 961.7 $793 $0.0 $0.0 $0.0 $0.0 $16.9 916.9 $56.4 $56.4 $56.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $56.4 $56.4 $0.0 $0.0 $0.0 $0.0 $0 $0 90 $136.9 $63.9 $62.1 $0.0 $0.0 $0.0 $0.0 $175 $175 $68.4 $58.4 $68.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $773.4 $0.0 $0.0 $58.4 $68.4 $0.0 $0.0 $0.0 $0.0 $10 $0 $141.7 $66.1 $85.0 $0.0 $0.0 $00 $0.0 $181 $181 $60.4 $60.4 $60.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $820.6 $0.0 $0.0 $60.4 $60.4 $0.0 $0.0 $0.0 $0.0 $62.6 $62.6 $62.6 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $870.1 $70.8 $01.1 $0.0 $0.0 $0.0 $0.0 $19.4 $19.4 $0.0 $0.0 $04.7 $64.7 $0.0 $0.0 $0.0 $0.0 $0 $10 $0 $187.4 $733 $04.2 $0.0 $0.0 $0.0 $0.0 $20.1 $20.1 2010 $67.0 $67.0 $67.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $076.7 $0.0 $0.0 $67.0 $67.0 $0.0 $0.0 $0.0 $0.0 $0 $0 90 $1626 $75.9 $97.5 $0.0 $0.0 $0.0 $0.0 $20.8 $20.8 2011 $69.4 $69.4 $69.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,033.9 $0.0 $0.0 $09.4 $69.4 sss $168.3 $78.5 $101.0 $0.0 $0.0 $0.0 $0.0 $21.5 $215 2012 $0.0 $1,094.0 $0.0 $0.0 $71.8 $71.8 $0.0 $0.0 $0.0 $0.0 $10 $174.4 $81.3 $104.5 $0.0 $0.0 $0.0 $0.0 $223 $22.3 2013 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,187.0 $0.0 $0.0 $74.3 $74.3 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $180.2 $84.1 $108.1 $0.0 $0.0 $0.0 $0.0 $23.4 $23.1 2014 $76.9 $76.9 $76.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,217.7 $0.0 $0.0 $76.9 $76.9 $0.0 $0.0 $0.0 $0.0 $0 $0 so $186.5 $87.1 $111.9 $0.0 $0.0 $0.0 $0.0 $23.9 $23.9 DATE - 06/17/93, PAGE 3 of 4 £. CONSUMER ACCOUNTS: INHouse Biling/Data Entry Clerk Customer Service Office Clerk ‘Accountant Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES TO BETHEL 1H. EXPENSES-SALES TO BETHEL |. AVG. COST $/KWH INCLUDING LOSSES 6. FINANCIAL FORECAST A. AVG. $/KWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES TOTAL EXPENSES KWH SALES KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES: TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) 1994 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $267.8 $4,127.2 $0.0 $0.0 $267.8 $1,127.2 2000 $0.281 $0.449 = $0.190 $750.0 $4823 $2678 $1,127.2 $267.8 $1,127.2 $0.0 $828.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 86 $828.8 ($267.8) ($298.4) $4823 © $183.8 $0.0 “83 1996 $0.0 $0.0 $0.0 $0.0 $0.0 $950.2 $0.0 $950.2 $0.231 $896.3 ($53.9) $130.0 $96.6 1997 1998 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,006.0 $1,038.5 $1955 = $193.8 $810.5 $848.7 $0.192 $0.196 FINANCIAL FORECAST $61.6 $148.1 $199.7 $144.9 = $193.1 1999 2000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,084.9 $1,167.2 $101.7 = $189.3 $803.1 $978.0 $0.203 $0.217 $0.195 — $0.220 $190.7 $250.6 $1,084.9 $1,167.22 $1,084.9 | $1,167.2 $934.4 $191.7 $0.7 $0.0 $1,136.68 $50.9 $250.6 $241.4 2001 $0.0 $0.0 $0.0 $0.0 $0.0 91,184.7 $186.4 $905.3 0.216 $0.0 $0.0 $0.0 $0.0 $0.0 91,2334 $183.2 $1,080.2 $0.223 $0.0 $0.0 $0.0 $0.0 $0.0 $1,312.4 $1793 $1,133.41 $0.236 $0.230 $403.8 $1,312.4 $1,312.4 $1,105.1 $179.3 (88.7) $395.1 $434.6 2004 $0.0 $0.0 $0.0 $0.0 $0.0 $1,347.8 $171.7 $1,176.14 $0.238 90.245 $305.1 $1,478 $1,347.68 $1,200.2 $171.7 $21.7 $0.0 91,4027 $54.9 $450.0 $482.9 2005 $0.0 $0.0 $0.0 $0.0 $0.0 $1,410.8 $163.3 $1,247.58 $0.246 $0.255 $450.0 91,4108 $1,410.8 $1,201.90 $163.3 $24.4 $0.0 $1,479.4 $68.6 $518.6 $531.1 $0.0 $0.0 $0.0 $0.0 $0.0 $1,486.8 $184.1 $1,332.6 $0.256 $0.265 $518.6 $1,486.8 $1,486.8 $1,377.33 $154.1 $26.6 $0.0 $1,568.0 $71.2 $580.8 $579.4 2007 $0.0 $0.0 $0.0 $0.0 $0.0 $1,545.7 $144.1 $1,401.5 $0.263 $0.275 $589.6 $1,545.7 $1,545.7 $1,405.2 $144.1 $29.0 $0.0 $1,638.3 $92.7 $682.5 $627.7 2008 2009 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,617.7 $1,620.6 $133.2 $121.4 $1,484.5 $1,409.3 $0272 $0.268 $0.280 $0.280 $682.5 $757.8 $1,617.7 $1,620.6 $1,617.7 $1,620.6 $1,528.58 $1,565.1 $133.2 $1214 $31.4 $33.8 $0.0 $0.0 $1,693.1 $1,720.38 $75.4 $99.7 $757.8 $857.5 $676.0 $721.7 2010 $0.0 $0.0 $0.0 $0.0 $0.0 $1,689.3 $108.5 $1,580.8 $0.276 $0.280 $857.5 $1,689.3 $1,689.3 $1,601.86 $108.5 $36.1 $0.0 $1,746.4 $57.0 $914.5 $767.3 2011 $0.0 $4,774.58 $04.6 $1,676.9 $0.287 $0.280 $914.5 $1,771.58 $1,715 $1,638.4 $04.6 $38.4 $0.0 $7714 ($0.1) $0144 $813.0 2012 $0.0 $0.0 $0.0 $0.0 $0.0 $1,867.4 $79.7 $1,787.88 $0.209 0.290 $914.4 $1,867.4 $1,867.4 $1,734.8 $70.7 $40.6 $0.0 $1,885.1 ($12.3) $902.4 2013 $0.0 $0.0 $0.0 $0.0 $1,947.2 $63.5 $1,883.7 $0.308 $0.30 $902.1 $1,947.22 $1,947.2 $1,864.5 $63.5 429 $0.0 $1,970.9 $23.7 $925.9 2014 $0.0 $0.0 $0.0 $0.0 $0.0 $2,035.4 $61.1 $1,984.4 $0.320 90.315 $925.9 $2,035.4 $2,035.4 $1,956.4 $51.1 $45.2 $0.0 $2,052.7 $17.2 $943.4 DATE - 06/17/93, PAGE 4 of 4 8. VILLAGE UTILITY COSTS 08M Fuel Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS 9. ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITHOUT PCE Residertial ‘Smal Commercial Large Commercial 10. ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITH PCE PCE S/KWH Residential ‘Small Commercial Large Commercial ANNUAL PCE PAYMENTS PW Annual PCE Payments ACCUMLATED PW PCE $0,098 $0.12 $0.12 $0.35 $7722 $772.2 $772.2 1995 $40.0 $0.0 $75.9 $911.6 $1,027 90.278 $0.253 $0.233 1906 $41.4 $0.0 $78.1 $983.3 $1,102.8 0.268 90.292 0.266 0.244 1997 $42.8 $0.0 $80.4 $906.2 $1,020.4 $0.244 $0.242 $0.222 $0.109 $0.12 $0.12 $0.22 $338.1 $304.9 $1,780.8 1998 $44.3 $0.0 $826 $979.0 $1,108.0 $0.257 90.279 $0.254 90.112 $0.12 $0.12 $0.23 $368.5 $321.1 $2,110.9 1999 $45.9 $00 $04.9 $1,027.86 $1,1586 90.206 $0.260 $0.239 2000 $47.5 $00 $87.1 $1,185.6 $1,3203 $0.293 0.318 $0 290 $0.267 $0.120 $0.13 $0.13 $0.27 $462.4 $376.2 $2,811.1 2001 $40.2 $00 $004 $1,206.7 $1,405.3 $0.305 $0.332 $0.302 90.278 $0.125 $0.14 90.13 90.28 $496.0 $369.9 $3,201.0 2002 $50.9 900 916 91.2039 $1.4984 $0.308 90.332 $0.302 90.278 $0,128 $0.14 $0.14 $0.28 $498.1 $378.3 $3,579.2 2003 $527 900 $039 $1.3213 $1.4679 $0332 $0.302 $0278 $0.134 $0.14 $0.14 $0.26 $499.4 $368.5 $3,945.7 2004 $545 $0.0 $069 $1,4458 $1,507.2 $0324 $0.352 $0.320 $0.204 $0.138 90.15 $0.15 $0.29 $554.5 $303.1 94,3388 2005 $56.4 $00 $09.9 91,5447 $1,701.0 90.365, $0.332 $0,306 90.143, $0.15 $0.15 $0.31 $593.9 $406.8 $4,745.68 2006 $58.4 $0.0 $102.9 $1,646.7 $1,808.0 90.348 $0378 $0.344 $0.317 $0,148 $0.16 $0.16 $0.32 $634.3 $419.7 $5,165.4 2007 2008 $62.6 $0.0 $108.9 $1,627.55 $1,909.0 90.366 $0.308 $0.363 $0.333 $0153 $0.180 $0.17 $0.17 $0.16 $0.17 $0.33 $0.33 $675.4 $098.2 $431.9 $431.3 $5,597.2 $6,028.5 $64.7 $0.0 $1118 $1,871.3 $2,047.9 $0366 $0.308 $0.363 $0.333 $0.164 $0.18 $0.17 $0.33 $700.9 $418.3 $6,446.9 2010 $67.0 $0.0 $114. $1,915.1 $2,097.0 $0.367 $0.308 $0.363 $0.334 $0.170 $0.18 $0.18 $0.33 $702.1 $404.9 $6,851.8 2011 $69.4 $0.0 $117.8 $1,958.90 $2,146.1 $0.367 $0.309 $0.363 $0.176 $0.19 $0.19 $0.33 $701.8 $301.1 $7,242.90 2012 $71.8 $0.0 $120.8 $2,074.3 $2,206.9 $0.379 $0.412 $0.375 $0.345 $0.182 $0.19 $0.34 $742.4 $309.7 $7,642.6 2013 $74.3 $0.0 $123.8 $2,229.3 $2,427.33 $0.397 $0.432 $0.393 $0.361 $0.188 $0.20 $0.20 $0.36 $805.2 $418.8 $8,061.4 2014 $76.9 $0.0 $126.0 $2,330.2 $2,542.14 $0.409 $0.445 $0.405 $0.372 0.195 $0.21 $0.21 $0.37 $842.2 $423.3 $8,484.6 DATE - 06/17/93, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine ‘%Grant Hydro Loan Period initial Capital 1, LOAD DEMAND VILLAGES: ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL E. DEMAND - KWH F. ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES 1H. MWH PURCHASES FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A. TRANSMISSION LINE Yet Yr2 B. NYAC HYDRO. Yet Yr2 C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES E. NEW GENERATOR F. COMPUTER SYSTEM 3. INTIAL CAPITAL TOTAL 4. ESTIMATED RATEBASE §. DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL ‘SMALL BUSINESS ADMIN. LOAN TOTAL 100% 100% uel Boo 1904 1032.1 4254.5 00 4254.5 $3,472 $0 $2,700 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 1086.2 0.0 00 4798.2 $3,472 $3,715 $2,700 $2,889 $750 $13,528 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $62.3 $0.0 $82.3 General Inflation Rate Fuel Inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate S/kwh, 1904 $3,472 $3,715 $2,700 $2,880 $0.0 $750 $13,526 $0.0 $0.0 $0.0 $0.0 $0.0 $623 $0.0 $82.3 1104.3 4576.9 487.7 5034.6 3320.7 1679.3 1713.8 $3,472 $3,715 $2,700 $2,889 $750 $13,526 $0.0 $0.0 $0.0 $0.0 $0.0 $62.3 3.500% 3.800% 3.50% $0.098 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-2, ALTERNATIVE B) 1608.3 1761.4 $3,472 $3,715 $2,700 $2,889 $0.0 $60.0 $750 $13,636 $0.0 $0.0 $47 $0.0 $0.0 $146 1999 1182.5 ATH 479.2 $271.0 3462.6 1537.4 1808.4 $3,472 $3,715 $2,700 $2,889 $104 $0.0 $60.0 2000-2001 2002 1406.5 1855.7 $3,472 $3,715 $2,700 $2,880 $161 $0 $0.0 $80.0 $750 $13,767 $0.0 $0.0 $152 $0.0 $00 $105 $823 900 $117.0 3604.4 1308.6 1903.0 $3,472 $3,715 $2,700 $2,880 $222 $0 $750 $13,828 $0.0 $00 $209 $00 $00 $105 $0.0 $122.8 3675.4 1324.6 1960.2 $3,472 $3,715 $2,700 $2,689 $267 $0 $0 $80.0 $750 $13,893 000 $00 900 $271 $00 $00 $195 $623 $00 $128.9 2003 3746.9 1253.1 1997.9 $3,472 $3,715 $2,700 $2,889 1270.1 $364.8 5901.3 3840.8 1159.2 2060.5 $3,472 $3,715 $2,700 $2,089 $430 $0 $0 $800 $750 $14,036 $0.0 $00 $406 $0.0 $0.0 $195 $623 $0.0 $142.5 1309.2 550.7 6057.7 3034.6 1065.4 212A $3,472 $3,715 $2,700 $2,889 ‘$509 $0 $0 $0 $750 $14,035 $0.0 $0.0 $48.0 $0.0 $0.0 $0.0 $823 $0.0 $130.4 “STAGE 2. 2006 1339.3 5649.2 564.9 6214.1 °° 4028.5 971.5 2185.6 $3,472 $3,715 $2,700 $2,889 $593 $0 $0 $0 $750 $14,119 $0.0 $0.0 $55.9 $0.0 $0.0 $0.0 $823 $0.0 $138.3 2007 1369.4 8791.4 $79.1 63705 41223 6777 2248.2 $3,472 $3,715 $2,700 $2,889 $681 $0 $0 $0 $750 $14,207 $0.0 $0.0 $64.3 $0.0 $0.0 $0.0 $823 $0.0 $146.7 1309.5 503.4 6527.0 4216.2 763.8 23108 $3,472 $3,715 $2,700 $2,889 $776 $0 $0 $0 $750 $14,302 $0.0 $0.0 $73.2 $0.0 $0.0 $0.0 $823 $0.0 $155.6 2010 1459.7 621.8 Beig.. $3,472 $3,715 $2,700 $2,889 $13,758 $0.0 $0.0 $02.7 $0.0 $0.0 90.0 $0.0 $0.0 $92.7 2011 1489.8 636.0 6996.2 4497.7 502.3 2498.5 $13,871 000 $0.0 $0.0 $103.3 $0.0 $0.0 $0.0 $0.0 $0.0 $103.3 2012 1519.9 650.2 71826 4591.6 408.4 2561.1 $3,472 $3,715 $2,700 $2,889 $1,214 $0 30 $0 $0 $13,990 $0.0 $0.0 $114.6 $0.0 $0.0 $0.0 $0.0 $0.0 $114.6 2013 1880.0 6644.6 604.5 7309.1 4685.4 3146 2623.6 $3,472 $3,716 $2,700 $2,889 $1,340 $0 $0 $0 0 $14,116 $0.0 $0.0 $126.5 $0.0 $0.0 $0.0 $0.0 $0.0 $126.5 2014 1874.8 6750.9 675.1 7426.0 4755.6 244.4 2670.4 $3,472 $3,715 $2,700 $2,889 $1,474 $0 $14,250 $0.0 $0.0 $139.1 $0.0 $0.0 $0.0 $0.0 $0.0 $139.4 DATE - 06/17/93, PAGE 2 of 4 5, OPERATING EXPENSES ($1000) (A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators: O&M Materials: Fuel Insurance 3. VILLAGE OPERATORS 4, COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS IN-House (O&M Labor O&M Materials, Contractor O&M Labor O&M Materials: sss $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $25.0 $25.0 $15.0 $93.8 $43.8 $56.3 $0.0 $0.0 $0.0 $0.0 $12.0 $12.0 $12.0 ———STAGE 1. 1995 1906 $0 $40.0 $0 $40.0 so $40.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $730.5 $431.8 $0.0 $0.0 $0.0 $0.0 $400 = $41.4 $400 © $41.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $0 $0 so $97.0 §©6 $100.4 $45.3 $46.9 $58.2 $00.3 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $124 $12.9 $124 $129 $124 $129 $458.0 $0.0 $0.0 $428 $428 $0.0 $0.0 $0.0 $0.0 $10 $103.9 $485 $62.4 $0.0 $0.0 90.0 $0.0 $13. $13.3 $133 1998 $443 $443 $443 $0.0 $0.0 $0.0 $0.0 $45.0 $485.5 $443 $443 1999 $0.0 $0.0 $0.0 $0.0 $0.0 $90.0 $614.4 $475 $475 $475 $0.0 $0.0 $0.0 $0.0 $0.0 $105.0 $844.7 $0.0 $0.0 475 475 $0.0 $0.0 $47.5 $47.5 $49.2 $49.2 $49.2 $0.0 $0.0 $0.0 $0.0 $0.0 $108.7 $576.5 $0.0 $0.0 $50.9 $50.9 $52.7 $62.7 $52.7 $0.0 $0.0 $0.0 $0.0 $0.0 $116.4 $045.0 $54.5 $54.5 $54.5 $00 $0.0 $0.0 $0.0 $0.0 $120.5 $685.7 $0.0 $0.0 $54.5 $54.5 $56.4 $56.4 $56.4 $0.0 $0.0 $0.0 $0.0 $0.0 $124.7 $728.4 $0.0 $0.0 $56.4 $56.4 $0.0 $56.4 $56.4 $136.9 $63.9 $624 $0.0 $0.0 $0.0 $0.0 $175 $17.5 $175 STAGE 2. $58.4 $60.4 $62.6 $58.4 $00.4 $62.6 $58.4 $60.4 $626 . fi oe $0.0 x 10.0 $0.0 a $0.0 $0.0 .« $0.0 $0.0 $0.0 $0.0 $0.0 $129.1 $133.6 $138.3 $773.4 $820.6 $870.1 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $58.4 $60.4 $62.6 $88.4 $60.4 $62.6 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $62.6 $626 $58.4 $58.4 $1518 $70.8 $01.1 $0.0 $0.0 $0.0 $0.0 $19.4 $19.4 $19.4 $04.7 964.7 $64.7 $0.0 $0.0 $0.0 $0.0 $0.0 $143.1 $922.1 $0.0 $0.0 $64.7 $64.7 $0.0 $64.7 $64.7 $10 $187.1 $73.3 $94.2 $0.0 $0.0 $0.0 $0.0 $20.1 $20.1 $20.1 2010 $67.0 367.0 3670 $0.0 $0.0 $0.0 $0.0 $0.0 $148.1 $976.7 $0.0 $0.0 $67.0 $67.0 $0.0 $0.0 $67.0 $67.0 $162.6 $75.9 $97.5 $0.0 $0.0 $0.0 $0.0 $20.8 $20.8 $20.8 2011 $69.4 $69.4 $60.4 $0.0 $0.0 $0.0 $0.0 $0.0 $153.3 $1,033.9 $0.0 $0.0 $60.4 $60.4 $718 $718 $71.8 $0.0 $0.0 $0.0 $0.0 $158.7 $1,094.0 $0.0 $0.0 $718 $718 $0.0 $0.0 $71.8 $71.8 $10 $174.1 $813 $104.5 $0.0 $0.0 $0.0 $0.0 $22.3 $22.3 $223 2013 $743 $74.3 $743 $0.0 $0.0 $0.0 $0.0 $0.0 $164.2 $1,157.0 $0.0 $0.0 $743 $743 $0.0 $0.0 $74.3 $74.3 $0 $0 $0 $180.2 $84.1 $108.1 $0.0 $0.0 $0.0 $0.0 $23.1 $23.1 $23.1 2014 $76.9 $76.9 $76.9 $0.0 $0.0 $0.0 30.0 $0.0 $170.0 $1,217.7 $0.0 $0.0 $76.9 $76.9 $0.0 $0.0 $76.9 $76.9 $1865 $87.1 $111.9 $0.0 $0.0 $0.0 $0.0 $23.9 $23.9 $23.9 DATE - 06/17/93, PAGE 3 of 4 E. CONSUMER ACCOUNTS: Biling/Data Entry Clerk Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES TO BETHEL H. EXPENSES-SALES TO BETHEL | AVG. COST $/KWH INCLUDING LOSSES 6. FINANCIAL FORECAST A AVG. $/KWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES TOTAL EXPENSES KWH SALES: KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 7. REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Small Commercial Large Commercial 1904 $0.0 $294.8 $0.449 $750.0 $204.8 $0.0 $0.0 $0.0 $0.0 ($204.8) $455.3 $0.0 0.0% STAGE 1. STAGE 2. 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2008 2007-2008 2009 2010 2011 2012 2013 2014 $0.0 $0.0 $37.5 $388 $40.2 $416 $430 $445 $461 $477 $40.4 $51.1 $52.9 $54.7 $56.7 $58.6 $60.7 $628 $65.0 $0.0 $0.0 $37.5 $388 $40.2 $416 $430 $445 $461 $47.7 $404 $51.1 $52.9 $54.7 $56.7 $58.6 $00.7 $62.8 $65.0 $0.0 $0.0 $25.0 $25.9 $268 $277 $2867 $207 $307 $318 $329 $34.1 $35.3 $36.5 $37.8 $30.1 $40.5 $41.9 $43.3 $0.0 $0.0 $0.0 0.0 $00 $0.0 s00 $00 $00 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $00 s00 $00 $00 00 $00 900 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $963.0 = $1,019.3 $1,306.3 $1,408.8 $1,523.8 $1,555.39 $1,624.8 $1,722.5 $4,777.9 $1,841.2 $1,9384 $2,049.5 —$2,114.8 —$2,142.0 $2,236.14 $2,344.88 —$2,468.4 = $2,577.1 $2,695.8 $0.0 $0.0 $195.5 $193.8 $101.7 $180.3 $186.4 «$183.2 $1703 $171.7 $163.3 $154.1 $144.1 = $133.2 $121.4 = $108.5 $94.6 $79.7 $63.5 $51.1 $1,130.6 $963.0 $823.8 $1,1125 $1,217.1 $1,3345 $1,368.9 $1,441.6 $1,543.11 $1,605.66 $1,677.86 $1,784.2 $1,875.4 $1,081.6 $2,020.7 $2,127.66 $2,250.2 $23888 $2,5136 $2,6445 $0.284 = $0.234 $0.196 $0.258 © 80.276) $0.208 © $0.287 80.306 © 80.321) 80.325) 80.331 $0343 80.352 80.363 = $0361 = $0372 80.385 «= 80.309 80.411 80.428 FINANCIAL FORECAST $0.200 © $0.210 $0.210 $0230 ©6$0.250 = $0.280 §= 0.300 30.310 $0.320 $0.330 $0.340 $0.340 $0.340 $0.350 0.350 $0360 $0.370 $0.390 $0.400 0.420 $456.3 $188.0 $166.0 $3080 $2800 $2704 $2529 $324.2 $402.8 $462.3 $554.3 $671.6 $730.6 ‘$746.7 $759.4 $782.6 $805.5 $815.1 $857.8 $601.5 $1,139.6 $963.0 $1,019.3 $1,306.3 $1,408.8 $1,523.8 $1,5553 $1,624.8 $1,7225 $1,777.3 $1,841.2 $1,038.4 $2,0195 $2,1148 $2,142.0 $2,236.1 $2,344.8 $2,468.4 $2,577.11 $2,695.6 $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 $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 $1,130.6 $963.0 $1,019.3 $1,308.3 $1,408.8 $1,523.86 $1,5553 $1,624.8 $1,7225 $1,7773 $1,841.2 $1,0384 $2,0195 $2,1144 $2,142.00 $2,236.1 $2,3448 $24684 $2577.11 $2,695.68 $8724 «© $938.6 $961.1 $1,077.4 $1,197.90 $1,262.0 $1,3819 $1.4586 $1,537.65 $1,6268 $1,7226 $1,767.11 $1,811.5 $1,9106 $1,9664 $2,0604 $2,165.0 $2333.1 $24452 $2,6086 $0.0 $0.0 $196.5 $193.8 $191.7 $1893 $1864 $183.2 $179.3 $171.7 $163.3 $164.1 $144.1 $133.2 $121.4 $108.5 e $79.7 $63.5 $81.1 $0.0 $24 4.7 $7.1 $0.5 $11.9 $143 $16.7 $19.1 $21.6 $24.0 $26.5 $29.0 $31.5 $34.0 $36.3 $41.2 $43.6 $46.1 $0.0 $0.0 $0.0 $0.0 $00 $431 $44.1 $45.0 $46.0 $47.2 $48.5 $49.7 $51.0 $52.2 $53.5 $54.7 $67.2 $58.5 $50.4 $8724 «$940.9 «= $1,161.4 $1,278.3 $1,300.2 $1,506.3 $1,626.6 $1,7034 $1,7820 $1,0602 $1,9584 $1,0074 $2,035.6 $2,1275 $2,165.2 $2,259.0 $2,511.1 $2,6108 $2,765.1 ($267.2) ($22.1) $142.1 ($28.0) ($9.6) ($17.5) $713 $78.6 $50.5 $92.0 $117.3 $50.1 $16.1 $127 $23.2 $22.9 $06 $42.7 $33.7 $60.5 $188.0 = $166.0 $308.0 = $280.0 = $2704 «= $252.8 = $324.2 = $402.8 $462.3 $554.3 $671.8 $730.8 $746.7 $759.4 ‘$782.6 $806.5 $815.1 $857.8 $961.0 $47.3 $04.7 $1420 $189.7 $237.7 «$285.8 = $334.2 «= $382.9 $431.7 $480.9 $530.0 $579.4 $629.1 $679.2 $727.0 $775.4 $823.7 $872.6 $922.0 $971.9 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% 100K 0% wox = $0.250 90.272 $0.304 «= 80.328) $0,337 $0.348 $0.369 $0.370 $0.370 $0.370 $0.380 $0.380 $0.391 $0.402 90.424 $0.435 $0.457 000 000 wox $0.228 «80.248 = 80.277 80.287 = $0.07 $0.317 90.327 $0.337 $0.337 $0.337 $0.347 $0.47 $0.356 $0.366 90.386 $0.306 $0.416 000 0% wox $0.209 «80.228 «= 80.255 = 80.273) $0.282 $0.20 $0.300 $0.308 $0.309 $0.30 $0.319 $0.319 90.328 $0.337 $0.355 $0.364 $0.382 DATE - 06/17/93, PAGE 4 of 4 8, VILLAGE UTILITY COSTS 08M Fuel Admin & Gen. Expenses Purchases from G&T/Regional Utility ‘TOTAL ANNUAL COSTS 9. ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITHOUT PCE Residential ‘Smal Commercial Large Commercial 10. ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential ‘Smal Commercial Large Commercial ANNUAL PCE PAYMENTS: PW Annual PCE Payments: ACCUMLATED PW PCE 1994 $700.9 $650. $220. $0.0 $1,5725 $0.449 $0.480 $0.480 $0.350 $0,098 $0.12 $0.12 $0.35 $7722 $772.2 ———STAGE 1. 1995 $40.0 $0.0 $75.9 $950.6 $1,075.58 90.268 $0.291 $0.265 $0.244 $0.101 $0.11 $0.11 $1,148.8 1996 $41.4 $0.0 $78.1 $1,032.4 $1,151.09 $0.305 90.277 0.255 90.105 $0.11 $0.11 $0.25 $418.4 $300.6 $1,536.39 1997 $42.8 $0.0 $80.4 $1,057.3 $1,180.5 $0.280 $0.305 $0.278 $0.255 $0.109 $0.12 $0.12 $0.26 $422.9 $381.4 i OREREE § 0.250 90.228 $0.209 90.112 90.12 $0.12 $0.21 $303.7 $264.7 $1,917.7 $2,1824 $0.272 90.248 $0.228 $0.116 $0.12 $0.12 $0.23 $352.8 $297.0 $0.304 90.277 90.255 $0.120 $0.13 $0.13 $0.25 $429.3 $349.2 $2,479.58 $2,828.7 EonngEE 8 EOHEEEE 3 $0326 $0.297 $0.273 $0.125 $0.13 $0.13 $0.27 $482.7 $379.4 $3,208.1 90.337 90.307 90.282 90.129 $0.14 90.14 $0.28 $510.8 $387.9 $3,596.0 aouugee 30.359 $0.327 80.300 $0.138 $0.15 $0.15 $0.30 $8727 $406.0 $4,307.88 $0.370 $0.337 0.309 $0.143 $0.15 $0.15 $0.31 $608.4 $415.4 $4,813.2 —— TAGE 2: aouggeg 3 $0.370 $0.337 $0.309 $0.148 $0.16 $0.16 $0.31 $6104 $404.0 $5,217.2 EOHEEEE 8 $0.370 $0.337 $0,309 $0,153 $0.16 $0.16 $0.31 $613.1 $302.0 $5,609.2 SB og FERRE 2 sss sss $0.159 $0.17 $0.17 $0.32 $e46.3 $300.3, $6,008.5 Soy FEeEE 8 2010 90.301 0.366 0.328 $0.170 $0.18 $679.9 $392.1 $6,786.8 2011 § REESE $0.402 $0,366 $0.337 $0.176 $0.19 $0.19 $0.34 $713.0 $397.3 $7,184.1 titi 90.424 $0.386 $0.365 $0.182 $0.19 $0.19 $0.35 $781.7 $420.9 $7,604.9 2013 a RREEE $0.435 90.306 $0.364 $0,188 $0.20 $0.36 $015.8 $424.4 $8,029.3 ioaugge 2 $0.457 $0.416 $0.382 $0.195 $0.21 $0.21 $0.38 $881.8 $443.2 $8,4725 DATE - 06/17/83, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine ‘%Grant Hydro Loan Period initial Capital 41. LOAD DEMAND VILLAGES A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% D. TOTAL ENERGY REQUIREMENTS - MWH_ BETHEL E. DEMAND - KWH. F. ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO USAGE - MWH G, SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES 1H. MWH PURCHASES FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) ‘A TRANSMISSION LINE Yrd Yr2 B.NYAC HYDRO Yr4 vr2 C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES E. NEW GENERATOR F. COMPUTER SYSTEM ‘3. INITIAL CAPITAL TOTAL 4, ESTIMATED RATEBASE 5. DEBT SERVICE ($1000) ‘TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL ‘SMALL BUSINESS ADMIN. LOAN TOTAL 100% 100% ancusl 1904 1032.1 4254.5 0.0 4254.5 eo oo 00 00 $3,472 $0 $2,700 $0 $0.0 $750 $6,922 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 General inflation Rate Fuel Inflation Rate REU Diesel Piant 1=NO, O=Yes Discount Rate PCE Rate $/kwh, 1994 STAGE 1. 1908 1996 1086.2 1080.3 43620 4469.4 496.2 © 446.9 4798.2 4916.4 ° ° ° o ° 2500 00 632498 0.0 00 4798.2 = 1666.5 $3,472 0 $3,472 $3,715 = $3,715 $2,700 = $2,700 $2,889 = $2,889 $0 $0 $0 $0 $0.0 $0.0 $0 $0 $750 ‘$750 $13,526 $13,526 00K 2000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $82.3 $82.3 $0.0 $0.0 $82.3 $82.3 1997 1104.3 4576.9 487.7 5034.6 3320.7 1679.3 1713.8 $3,472 $3,715 $2,700 $2,889 $0 $0.0 $0 $750 $13,526 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $82.3 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE B) —STAGE 2— 1908 (1900 11284 11828 48843 4701.8 4084 © 4702 51828 5271.0 ° ° ° o 000 $000 33017 34028 16083 1837.4 1761.1 1808.4 $3,472 $3,472 $3715 $3,718 $2,700 $2,700 $2989 $2,880 $50 $104 $0 $0 $00 $0.0 $60.0 $60.0 $750 $13,636 oor ok $0.0 $0.0 $00 $0.0 $47 I $0.0 $14, $823 $0.0 $104.7 0.0 5000.0 00 $3,472 $3,715 $2,700 $2,889 $6,000 $0.0 $80.0 $3,413 $0.0 $0.0 $22.0 $506.4 $0.0 $19.5 $82.3 $204.8 $895.0 2001 1200.6 $006.7 600.7 5507.4 43781 00 6000.0 0.0 $0.0 $0.0 $30.3 $566.4 $0.0 $10.5 $62.3 $204.8 $903.4 -STAGE 3— 2002 2003 2004 2005 2008 2007 2008 2009 2010 2011 2012 2013 2014 1224.7 = 1249.0 1270.1 = 1309.2 1330.3 1360.4 «= 1309.6 1420.6 = 1450.7 «= 1489.8 = 1519.9 1850.0 1574.8 $114.2 $2226 = $364.8 «= 8607.0 5649.2 5701.4 = 8033.6 = 6075.8 = «6218.0 6360.2 «= 6502.4 = 6644.6 = 6750.9 511.4 5223 $36.5 $60.7 564.9 579.1 593.4 607.6 621.8 636.0 650.2 664.5 675.1 56256 8744.9 = 8901.3 6087.7 © 6214.1 6370.8 «6527.0 6883.4 «= «6839.8 ©=— 6996.2 7152.6 = 7309.1 7426.0 7132 7300 7420.0 «7840.0 © 7660.0 «7780.0 += 7900.0 8020.0 8140.0 8260.0 8380.0 8500 8636.0 43288 44534 © 45325.9 461178 46909.7 4701.6 © 48403.5 -49285.4 © 50077. 50860.2 51661.1 52453 3202.2 5000 5000 $000 ‘5000 000 5000 5000 5000 5000 000 ‘5000 000 $000 00 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5000.0 5000.0 5000.0 5000.0 5000.0 5000.0 000.0 5000.0 000.0 5000.0 6000.0 5000.0 5000.0 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 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3.715 $3,715 $3,715 «= $3,715 $3,715 $3,715 «= $3,715 $3,715 $3,715 «= $3,715 «= $3,715 $3,716 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,860 © $2,880 $2,889 «| $2,889 = $2,880 «= $2,880 «= $2,889» $2,889 «= $2,880 = $2,880 «= $2,889 = $2,889 $517 $624 $738 $8590 $1,125 $1,270 $1,424 $1,587 $1,760 $1,943 $2,137 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $1,125 $1,125 $1,125 $1,125 $2,575 $2,575 $2,575 $2,575 $2,575 $2,575 $2,575 $80.0 $80.0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $750 $750 $750 $750 $750 $750 $750 $0 $0 $0 $0 $0 $0 $24,447 $21,248 = $21,355 $21,389 = $24,510 $21,639 = $23,226 = $22,621 $22,775 $22,938 = $23,111 $23,204 $23,488 $4,321 $4,222 $4,129 $3,963 $3,884 $3,813 $5,200 $5,145 $5,099 $5,062 $5,035 $5,018 $5,012 $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 $488 $69.7 $61.1 $93.3 $106.2 $119.9 $134.4 $1498 $166.2 $183.4 $201.7 $566.4 $666.4 $566.4 $566.4 $666.4 $566.4 $566.4 $566.4 $566.4 $566.4 $106.2 $106.2 $106.2 $243.1 $243.1 $243.1 $243.1 $243.1 $243.1 $243.1 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 y $823 $82.3 $82.3 $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 $823.2 $824.6 $848.2 $998.0 $929.3 $943.9 $959.3 $975.6 $992.9 © $1,041.2 DATE - 06/17/03, PAGE 2 of 4 6, OPERATING EXPENS! ($1000) ‘A. POWER PRODUCTION COSTS 4. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators 8M Materials, Fuel Insurance 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS INHouse 8M Labor O&M Materiais Contractor 8M Labor O&M Materials: 1994 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $25.0 $25.0 $15.0 $03.8 $43.8 $56.3 $0.0 $0.0 $0.0 $0.0 $12.0 $12.0 $12.0 ————STAGE 1 1995 1996 $o $40.0 $o $40.0 $0 $40.0 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $7305 $431.8 soo = $0.0 $00 = $0.0 $40.0 $414 $40.0 $41.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $0 $0 $0 $07.0 $100.4 $453 $48.9 $582 $60.3 $00 = $0.0 $00 = $0.0 $0.0 . $0.0 $124 $124 $129 $124 $120 ——STAGE 2. 1997 1998 1900 2000 2001 2002 2003 $428 $443 $45.9 9475 $40.2 $50 $527 $545 $428 «$443 $480 47S $40.2 $509 $527 $545 $428 $443 $450 $475 $49.2 $500 $527 $545 $0.0 $00 $00 $850 $88.0 sort $042 $075 $0.0 $0.0 $00 $5100 $5279 $5463 $8654 $5852 $0.0 $0.0 $00 $2500 $2568 $2678 $2772 $286.9 $0.0 $0.0 $0.0 $4,5725 $5,031.0 $5,163.0 $5,5009 $5,822.1 $0.0 $0.0 $0.0 $2300 $236.1 $246.4 $2850 $263.9 $0.0 $45.0 $00.0 $1050 $1087 $1128 $116.4 $120.5 $458.0 $4855 $514.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $475 $492 $50.9 $52.7 $54.5 $0.0 $0.0 $00 $475 $49.2 $50.9 $52.7 $54.5 $428 $443 $45.9 $0.0 $0.0 $0.0 $0.0 90.0 $42.8 $44.3 $45.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $160.0 $165.6 $1714 $1774 = $183.6 $0.0 $0.0 $0.0 $400.0 $414.0 $426.5 $443.5 $459.0 $0.0 $443 $45.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $44.3 $45.9 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $25 $0 $0 $0 $0 $10 $0 $0 $25 $0 $0 $25 $0 $0 $0 so $0 $0 $0 $15 $0 $103.9 $107.6 $111.3 $115.2 $119.3 $127.8 $132.2 $48.5 $50.2 $52.0 $53.8 $55.7 $59.6 $61.7 $62.4 $645 $06.8 $60.1 $716 $76.7 $703 $0.0 $0.0 $0.0 $53.8 $55.7 $50.6 $017 $0.0 $0.0 $0.0 $80.0 $628 $88.7 sore $0.0 $0.0 $0.0 $80.0 $82.8 $88.7 $018 $0.0 $0.0 $0.0 $80.0 $82.8 $88.7 sore $13.3 $143 $148 $15.3 $16.4 $16.9 $13.3 $13.8 $143 $50.0 $61.7 $55.4 $67.4 $13.3 $13.8 $143 $50.0 $51.7 $55.4 $57.4 $56.4 $56.4 $56.4 $101.0 $805.7 $206.9 $6,149.5 $273.2 $124.7 $0.0 $56.4 $56.4 $0.0 $0.0 $190.0 $475.1 $0.0 $0.0 $136.9 $63.9 $82.1 $63.9 $95.0 $95.0 $95.0 $17.5 $50.4 $59.4 $58.4 $58.4 $58.4 $104.5 $626.9 $307.3 $6,492.7 $2627 $120.1 $0.0 $60.4 $60.4 $60.4 $108.1 $648.9 $318.1 $6,852.4 $2026 $133.6 $0.0 $60.4 $60.4 $0.0 $0.0 $203.6 $508.9 $0.0 $0.0 $146.6 $68.4 $88.0 $68.4 $101.8 $101.8 $101 $626 $626 3626 $111.0 $671.6 $329.2 $7,220.3 $302.9 $138.3 $0.0 $626 $62.6 $0.0 $0.0 $210.7 $526.7 $0.0 $0.0 $64.7 $64.7 $64.7 $115.8 $695.1 $340.7 $7,624.2 $313.8 $143.1 $0.0 $64.7 $64.7 $0.0 $0.0 $218.1 $545.2 $0.0 $0.0 2010 $67.0 $67.0 $67.0 $119.9 $7194 $352.6 $8,037.8 $324.4 $148.1 $0.0 $67.0 $67.0 $0.0 $0.0 $228.7 $564.2 $0.0 $0.0 $0 $0 $0 $162.6 $75.9 $97.5 $75.9 $1128 $1128 $112.8 $20.8 $705 $70.5 2011 $60.4 $69.4 $00.4 $124.1 $744.6 $365.0 $8,471.41 $335.8 $153.3 $0.0 $69.4 $60.4 $0.0 $0.0 $233.6 $584.0 $0.0 $0.0 $0 $0 $0 $168.3 $78.5 $101.0 $785 $116.8 $116.8 $116.8 $21.5 $73.0 $73.0 2012 $71.8 $71. $71.8 $128.4 $7706 $377.8 $8,924.9 $347.5 $158.7 $0.0 $718 $71.8 $0.0 $0.0 $2418 $604.4 $0.0 $0.0 so $25 $0 $174.4 $81.3 $104.5 $81.3 $120.9 $120.9 $120.9 $22.3 $75.6 $75.6 2013 $743 $743 $743 $132.9 $797.6 $301.0 '$9,400.0 $360.7 $164.2 $0.0 $74.3 $743 $0.0 $0.0 $250.2 $625.6 $0.0 $0.0 $0 $0 $0 $180.2 $84.1 $108.1 $84.4 $125.1 $125.1 $125.1 $23.1 $78.2 $78.2 2014 $76.9 $76.9 $76.9 $1376 $825.5 $404.7 $9,698.9 $372.3 $170.0 $0.0 $76.9 $76.9 $0.0 $0.0 $259.0 $647.5 $0.0 $0.0 $0 $0 $0 $186.5 $87.1 $111.9 $87.1 $120.5 $120.5 $129.5 $23.9 $80.9 DATE - 06/17/93, PAGE 3 of 4 E. CONSUMER ACCOUNTS Biling/Data Entry Clerk Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES TO BETHEL H. EXPENSES-SALES TO BETHEL |. AVG. COST $/KWH INCLUDING LOSSES. 7. FINANCIAL FORECAST ‘A. AVG. SIKWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES: TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTME! 8. REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Smal Commercial Large Commercial 1904 $0.0 $0.0 $0.0 $0.0 $0.0 $294.8 $0.0 $204.8 $0.449 $750.0 $204.8 $0.0 $0.0 $294.8 $0.0 $00 $0.0 $0.0 $0.0 ($204.8) $455.3 $0.0 0.0% ————-STAGE 1 1996 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $1,139.6 $0.0 $1,130.6 $0.284 $0.190 $455.3 $1,139.6 $0.0 $0.0 $1,139.68 $828.8 $0.0 $0.0 $0.0 $828.8 ($310.8) $1444 $47.3 0.0% $0.0 $0.0 $0.0 $0.0 $0.0 $963.0 $0.0 $963.0 $0.234 $0.210 $144.4 $963.0 $0.0 $0.0 $963.0 $938.6 $0.0 $24 $0.0 $040.9 ($22.1) $122.3 $94.7 0.0% —STAGE 2. -STAGE 3. 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $0.0 $375 $38.8 $40.2 $416 $43.0 $445 $46.1 $47.7 $40.4 $51.1 $52.9 $54.7 $56.7 $58.6 $00.7 $62.8 $65.0 $0.0 $375 $38.8 $40.2 416 $43.0 $445 $46.1 $477 $49.4 $51.1 $52.9 $54.7 $56.7 $58.6 $60.7 $628 $65.0 $00 $250 $259 $268 $27.7 $28.7 $20.7 $30.7 $31.8 $329 $34.1 $35.3 $365 $37.8 $39.1 $405 $41.9 $43.3 $0.0 $0.0 $0.0 $60.0 $06.5 $68.9 $713 $738 $763 $79.0 $818 $846 $876 $90.7 $93.8 $97.1 $100.5 $104.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 3 $1,306.2 $1,408.8 $8,308.9 $8,827.9 $0,176.3 $9,472.6 $9,863.5 $10,204.4 $10,790.39 $11,257.4 $11,008.6 $12,388.7 $12,925.2 $13,511.89 $14,149.9 $14,765.2 $15,435.3 $180.0 $187.3 $185.3 $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 $830.3 $1,114; $1,223.58 $8,308.9 $8,827.9 $9,176.3 $9,472.6 $9,863.5 $10,204.4 $10,700.35 $11,257.4 $11,008.6 $12,388.7 $12,025.2 $13,5119 $14,149.9 $14,765.2 $15,4353 90.197 $0.280 $0.278 $0212 $0213 $0.223 $0.224 $0.229 $0.235 $0.242 $0.248 $0.258 0.264 $0.270 $0.278 $0.287 $0.294 $0.303 FINANCIAL FORECAST $0.210 $0.230 $0250 $0225 $0.230 $0.230 $0.235 $0.240 $0.240 $0.245 $0.250 $0,265 0.275 $0.275 $0,285 $0.295 $0.05 $0.305 $1223 $257.9 $223.5 $2075 $4993 $1,030.0 $971.9 $1,1353 $1,348.6 $1,3494 $1,280.7 $1,205.1 $1,1253 $1,263.66 $1,099.86 $1,0681 $1,1314 $1,3265 $1,019.3 $1,306.2 $1,408.8 $6,308.9 $8,8279 $9,1763 $9,472.6 $9,863.5 $10,204.44 $10,790.3 $11,257.4 $11,908.6 $12,388.7 $12,025.2 $13,511.9 $14,149.9 $14,765.2 $15,435.3 $0.0 $0.0 $443.1 $429.2 $561.7 $548.8 $536.8 $515.2 $504.9 $495.7 $676.0 $668.9 $662.9 $658.1 $654.6 $652.4 $651.6 $0.0 $0.0 $1553 $1502 $196.6 $192.1 $187.9 $180.3 $176.7 $173.5 $236.6 $234.1 $232.0 $230.3 $229.1 $228.3 $228.1 $1,306.2 $1,408.8 $8,907.9 $0,407.3 $0,934.6 $10,213.5 $10,588.1 $10,089.9 $11,4720 $11,926.6 $12,821.2 $13,201.6 $13,820.1 $14,400.4 $15,033.6 $15,645.9 $16,316.0 $1,197.9 $8,814.5 $9,518.0 $9,445.4 $9,920.1 $10,322.2 $10,513.3 $10,027.3 $11,340.4 $12,241.3 $12,922.1 $13,141.0 $13,845.7 $14,566.4 $15,302.09 $15,547.86 $185.3 $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 $7.1 $9.5 $119 $25.8 $39.7 $54.5 $69.4 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $0.0 $0.0 $3733 $3043 $301.3 $402.2 $4098 $417.4 $425.0 $432.6 $440.2 $4478 $455.3 $462.9 $470.5 $478.1 $485.7 271.8 $1,3028 $9,199.7 $0,938.1 $9,876.5 $10,376.9 $10,801.5 $10,900.7 $11,4123 $11,841.09 $12,741.4 $13,420.9 $13,656.3 $14,368.7 $15,006.9 $15,841.0 $16,0935 ($34.4) ($16.0) $201.8 © $830.7 ($58.1) $163.4 $213.3 $08 ($58.6) ($84.7) ($79.7) $138.2 = ($163.8) ($31.7) $63.3 $195.1 ($221.5) $223.5 $207.5 $499.3 $4,031 $071.9 $1,135.3 $4,349.4 $4,289.7 $1,205.1 $4,125.3 $1,263.6 $1,099.8 $1,068.1 $1,131.4 $1,326.5 $1,105.41 $180.7 $237.7 $515.4 = $794.4 $1,090.5 $1,387.89 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.09 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.0 0.0% 0.0% 0.0% 6.9% 6.0% 6.7% 6.5% 6.3% 6.0% 5.8% 5.6% 6.5% 6.8% 6.6% 6.5% 6.3% 6.2% 6.1% wox $0250 $0272 $0245 $0250 0.280 $0.255 $0.261 90.261 30.206 $0.272 $0.288 $0.299 $0299 $0.310 $0.321 $0.332 $0.332 won $0.228 $0248 $0223 $0228 30.228 $0.233 $0.236 30.238 $0.243 90.248 $0.262 $0.272 $0.272 $0.282 $0.292 $0.302 $0.302 won $0.2009 $0228 $0205 $0209 0.200 $0214 $0218 90.218 $0.223 90.228 $0.241 $0.250 $0.250 0.259 $0.268 $0.278 $0.278 DATE - 06/17/93, PAGE 4 of 4 9. VILLAGE UTILITY COSTS O8M Fuel Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS 10. ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITHOUT PCE Residential ‘Small Commercial Large Commercial 414, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential ‘Small Commercial Large Commercial ANNUAL PCE PAYMENTS: PW Annual PCE Payments ACCUMLATED PW PCE 1994 81,8725 $0.449 $0.488 90.444 $0,408 $0.098 $0.12 $0.12 $0.41 $773.2 $773.2 $773.2 ———— STAGE 1. 1995 $40.0 $0.0 $2276 $011.6 $1,178.2 $0.204 $0.101 $0.14 $0.11 90.27 $444.3 $429.2 $1,2025 1996 $41.4 $0.0 $234.3 $1,032.4 $1,308.2 $0.318 $0.346 90.315 $0.280 $0.105 $0.12 $0.12 $0.29 $505.7 $472.1 $1,674.5 1907 $42.8 $0.0 $241.1 $1,057.3 $1,341.2 $0.319 $0.46 $0.315 $0.290 $0.108 $0.12 $0.12 $0.29 $513.1 $462.8 ——STAGE 2—— 1998 1999 1000 000 000 2000 000 v0 2000 000 2000 y000 v0 so00 $0.250 © $0.272 $0.228 $0248 $0.209 $0.28 0.112 $0.116 $0.12 $0.12 $0.12 $0.12 $0.21 $0.23 $303.7 = $352.8 $264.7 $297.0 $2,137.3 $2,402.0 $2,609.0 3 8 sss $234. $234.7 $2,933.6 $3,168.3 $0.129 $0.14 $0.13 $0.21 $205.2 $224.1 $3,302.5 $0.134 $0.14 $0.14 $021 $304.6 $223.5 $3,616.0 $0.138 $0.14 $0.14 $0.22 $316.1 $224.1 $3,840.1 $0,143 $0.15 $0.15 $0.22 $3126 $214.1 $4,054.2 $0.243 $0.23 $0.148 $0.15 $0.15 $0.22 $3229 $213.7 $4,267.9 aoudnag 8 $0.272 $0.248 90.228 90.183 $0.16 $0.16 $0.23 $212.8 $4,480.7 BBB E REEEE 3 sss $374.2 $231.2 $4,711.90 gounaa 8 30.299 90.272 0.250 $0.164 $0.17 $0.17 $400.3 $238.9 $4,950.86 2010 $0.299 $0.272 $0.250 $0.170 $0.18 $0.18 $0.25 $302.8 $226.6 $5,177.4 2011 $0.310 $0.282 $0.259 $0.176 $0.18 $0.18 $0.26 $418.5 $233.2 $5,410.58 BBS y EeeeE 3 sss $0.182 $0.19 $0.19 $0.27 $444.2 $230.1 $5.640.7 8 13 i OREEEE $0.332 $0.302 $0.278 $0.188 $0.20 $0.19 $0.28 $469.9 $244.4 $5,894.1 2014 § REESE $0.332 $0.302 $0.278 $0.19 $0.20 $0.20 $0.28 $455.6 $6,123.0 DATE - 07/17/83, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine *%Grant Hydro Loan Period initial Capital 4, LOAD DEMAND VILLAGES ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL E. DEMAND - KWH F. ENERGY - MWH G. MWWH AVAILABLE FROM NYAC HYDRO H, VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO: ‘SALES TO BETHEL UTILITIES H. MWH PURCHASES: FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) C. NEW DISTRIBUTION 0. PURCHASE BETHEL UTILITIES . NEW GENERATOR F. COMPUTER SYSTEM 3. INITIAL CAPITAL ‘TOTAL 4. ESTIMATED RATEBASE 5. DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL SMALL BUSINESS ADMIN. LOAN TOTAL a3 a88ued 1994 1032.1 4284.5 00 4254.8 $3,472 so $2,700 $0 $0.0 $0 $750 $6,922 $163.9 $127.4 $0.0 $0.0 $0.0 $0.0 $0.0 $291.3 General inflation Rate 3.500% Fuel inflation Rate 3.500% REU Diesel Plant 1=NO, O=Yes 1 Discount Rate 3.50% PCE Rate S/kwh, 1994 $0.008 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE B, 50% LOAN FUNDS) ———sTaGe 1 OO, OO | 1995 1906 1997 1908 1909 2000 2001 2002 2003 2004 2005 2006 2007 2008 1056.2 1080.3 1104.3 11284 © 11825 = 1176.6 = 12006 = 12247 = 1240.0» 1279.1 = 1308.2 1330.3 1380.4 = 1300.5 4362.0 4460.4 4576.9 46843 «4701.8 4899.3 $006.7 $114.2 $222.6 5364.8 507.0 5649.2 8791.4 5933.6 436.2 © 448.9 487.7 = 408.4 470.2 489.9 $00.7 6114 $22.3 536.5 550.7 564.9 579.1 503.4 4798.2 © 4016.4 5034.6 $1628 6271.0 53802 58074 86256 $7449 50013 6057.7 62141 63705 6527.0 oO ° ° ° ° 6708 0004 7132 7900-74200 7540.0 © 7860.0 © 7780.0 = 7900.0 ° ° ° 0 ° 41272 43781 49208 44534 453259 © 46117.8 © 46009.7 4701.6 = 48403.5 ° ‘2800 $000 $000 ‘$000 5000 ‘$000 $000 5000 5000 000 5000 ‘$000 5000 0.0 32408 3920.7 3301.7 34626 00 0.0 oo 00 00 0.0 00 0.0 0.0 00 00 1679.3 10083 = 1837.4 5000.0 5000.0 $000.0 $000.0 5000.0 $000.0 5000.0 000.0 5000.0 4798.2 1666.5 1713.8 1761.1 1808.4 00 0.0 00 00 0.0 0.0 0.0 0.0 0.0 $3,472 $3,472 $3,472 $3,472, $3,472 $3,472 $3,472 $3,472 $3472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,715 $3,715 $3,715 «$3,715 $3,715) $3,715 $3,715) = $3,718 83.715 $3,715) $3,715 83.715 = $3,715 = $3,718 $2,700 $2,700 $2,700 © $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,889 «= $2,889 $2,889 «= $2,889 $2,880 Z $2,880 $2,889 $2,689 $2,889 $2,889 $2,880 $2,889 $2,880 $0 $0 $0 $50 $104 $322 $416 $817 $624 $738 $850 $088 $1,125 $0 $0 $0 $0 $0 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,125 $1,125 $1,125 $1,125 $1,125 $1,126 $2,575 $0 $0 $0 $60.0 $60.0 $80.0 $80.0 $80.0 $80.0 so $0 $0 $0 ‘$750 $750 $750 $750 $750 $750 $750 $750 $750 $750 $750 $750 $750 $13,526 $13,526 $13,526 $13,636 $13,600 «$19,839 += $19,028 §=— $21,447 «= $21,248 = $21,355 = $21,389 = $21,510 = $21,639 = $23,228 vo00% v0 yoo ye00 yo00% $9,801 $0,477 $10,283 $9,071 $0,685 = 80.286 = $8,005 «= $8,711 ($9,884 $330.2 © $330.2 $330.2 «6$3398.2 $330.2 $339.2 $330.2 $330.2 $330.2 $330.2 $330.2 $339.2 $339.2 $339.2 $263.8 © $263.8 $263.8 4 «6$263.8 «= $263.8 $263.8 $263.8 $263.8 $263.8 $263.8 $263.8 $263.8 $263.6 $263.8 $0.0 $0.0 $0.0 47 $08 $22.0 $30.3 $30.3 $48.8 $58.9 $00.7 $811 $93.3 $106.2 $0.0 $0.0 $0.0 $0.0 $0.0 $566.4 $566.4 $806.4 $506.4 $566.4 $566.4 $506.4 $806.4 $866.4 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $106.2 $108.2 $106.2 $106.2 $106.2 $106.2 $243.1 $0 $0 $0 $146 $146 $19.5 $10.5 t $19.5 $10.5 $0.0 90.0 $0.0 $0.0 $823 $82.3 $823 $82.3 $62.3 $62.3 $82.3 L' $82.3 $82.3 $62.3 $62.3 $82.3 $823 $0.0 $0.0 $0.0 $0.0 4 $204.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $685.3 = $685.3 9085.3 = $704.7 $1,624.5 $1,426.2 $1,436.39 $1,427.5 $1,439.0 $1,451.1 $1,600.89 2008 1429.6 6075.8 607.6 6683.4 8020.0 49285.4 8000 0.0 5000.0 0.0 $3,472 $3,715 $2,700 $2,889 $1,270 $6,000 $2,575 $0 $0 $22,621 $9,617 $330.2 $263.8 $119.9 $506.4 $243.1 $0.0 $0.0 $0.0 $1,832.3 5000.0 0.0 $3,472 $3,715 $2,700 $2,689 $1,424 $6,000 $2,575 $0 $22,775 $9,358 $330.2 $263.8 $134.4 $566.4 $243.1 $0.0 $0.0 $0.0 $1,546.8 2011 1489.8 6360.2 636.0 6906.2 8260.0 0869.2 5000 0.0 5000.0 0.0 $3,472 $3,715 $2,700 $2,889 $1,587 $6,000 $2,575 $0 $22,938 $9,108 $330.2 $263.8 $140.8 $566.4 $243.1 $0.0 $0.0 $0.0 $1,562.2 2012 1519.9 6802.4 650.2 7152.6 8380.0 51661.1 0.0 5000.0 0.0 $3,472 $3,715 $2,700 $2,889 $1,760 $6,000 $2,575 $0 $0 $23,414 ‘$8.888 $330.2 $263.8 $166.2 $566.4 $243.1 $0.0 $0.0 $0.0 $1,578.6 2013 1550.0 664.5 7309.1 52453 0.0 000.0 0.0 $3,472 $3,715 $2,700 ‘$2,889 $1,043 $6,000 ‘$2,875 $0 $0 $23,204 $6,638 $330.2 $263.8 $183.4 $566.4 $243.1 $0.0 $0.0 $0.0 $1,595.8 2014 1574.8 6750.9 675.1 7428.0 8636.0 $3292.2 0.0 5000.0 0.0 $3,472 $3,715 $2,700 $2,889 $2,137 $6,000 $2,575 $0 $0 $23,488 $6,419 $330.2 $263.8 $201.7 $506.4 $243.1 $0.0 $0.0 $0.0 $1,614.1 DATE - 07/17/03, PAGE 2 of 4 6, OPERATING EXPENSES ($1000) ‘A. POWER PRODUCTION COSTS: 4. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Stx Plant Operators ‘O&M Materials Fuel Ingurance 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER B, TRANSMISSION/SUBSTATIONS: IN-House O&M Labor O&M Materials, Contractor O&M Labor O&M Materials C. DISTRIBUTION IN-House 08M Labor O&M Materials Contractor ‘8M Labor O&M Materials. D. ADMIN & GEN. EXPENSES Form Corporation/Utilty /APUC Filing Office Equip. IN-House General Manager. Bd/Exec. Secretary Financial Mgr. Admin. Sec. ‘Staff Engineer Operations Manager Seoretary Rent Misc Contractor ‘Attomey/Engr. Consutant 1994 $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 $25.0 $25.0 $15.0 $03.8 $43.8 $56.3 $0.0 $0.0 $0.0 $0.0 $12.0 $12.0 $120 ————STAGE 1. 1996 1995 ess $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $730.5 $0.0 $0.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 $97.0 $453 $58.2 $0.0 $0.0 $0.0 $0.0 $124 $124 $124 $40.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $431.8 $0.0 $0.0 $41.4 $41.4 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $100.4 $46.9 $60.3 $0.0 $0.0 $0.0 $0.0 $129 $12.9 $129 1997 $428 $428 $428 $0.0 $0.0 90.0 90.0 $0.0 $0.0 $458.0 $0.0 $0.0 $42.8 $42.8 $0.0 $0.0 $0 $10 $103.9 $48.5 $62.4 $0.0 $0.0 $0.0 $0.0 $13.3 $13.3 $13.3 ——STAGE 2—— 1998 $44.3 $443 $443 $0.0 $0.0 $0.0 $0.0 $0.0 $45.0 $485.5 $0.0 $0.0 $44.3 $44.3 $0.0 $0.0 $443 $44.3 $107.6 $50.2 $64.5 $0.0 $0.0 $0.0 $0.0 $13.8 $13.8 $13.8 $514.4 $0.0 $0.0 $45.9 $45.9 $0.0 $0.0 $45.9 $45.9 $0 $0 $0 $111.3 $52.0 $66.8 $0.0 $0.0 $0.0 $0.0 $14.3 $143 $143 STAGE 3. 2000 2001 2002 2003 2004 2005 2006 2007 2008 2008 2010 2011 2012 2013 2014 $475 $49.2 $50.9 $62.7 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $743 $76.9 $475 $49.2 $50.9 $62.7 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $743 $769 $475 $40.2 $50.9 $52.7 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $743 $76.9 $85.0 $88.0 $01.1 $04.2 $97.5 $101.0 $1045 $108.1 $111.0 $115.8 = $119.9 $124.1 $1284 = $132.9 $137.6 $510.0 $527.9 $546.3 $565.4 $585.2 $605.7 $626.9 $648.9 $671.6 $695.1 $719.4 $744.6 $770.6 $797.6 $825.5 $250.0 $258.8 $267.8 $277.2 $286.9 $296.9 $307.3 $318.1 $329.2 $340.7 $352.6 $365.0 $377.8 $301.0 $404.7 $4,572.5 $5,031.0 $5,163.0 $6,509.9 $5,822.1 $6,149.5 $6,492.7 $6,8524 $7,220.3 $7,824.2 $8,037.8 $8,471.1 $8,924.9 $9,400.0 $9,698.9 $230.0 $238.1 $246.4 $255.0 $263.9 $273.2 $282.7 $292.6 $302.9 $313.5 $324.4 $336.8 $347.5 $360.7 $3723 $108.0 $108.7 $112.5 $116.4 $120.5 $124.7 $129.1 $133.6 $138.3 $143.1 $148.1 $153.3 $158.7 $164.2 $170.0 $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 $47.5 $402 $50.9 $52.7 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $60.4 $718 $74.3 $76.9 $47.5 $49.2 $50.9 $52.7 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $00.4 $718 $743 $76.9 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $160.0 $165.6 $171.4 $177.4 $183.6 $190.0 $196.7 $203.6 $210.7 $218.1 $225.7 $233.6 $2418 $250.2 $259.0 $400.0 $414.0 $428.5 $443.5, $459.0 $475.1 $491.7 $508.9 $626.7 $545.2 $564.2 $584.0 $604.4 $625.6 $647.5 $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 $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 $25 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $25 $0 $0 $0 $0 $25 $0 $0 $25 $0 $25 $0 $0 $0 $0 $0 ‘$0 $0 so $0 $0 $0 $0 $0 $0 $0 $119.3 $123.5 $132.2 $136.9 $1417 $146.6 $151.8 $157.1 $162.6 $174.1 $180.2 $186.5 $55.7 $67.6 $61.7 $63.9 966.1 $68.4 $70.8 $73.3 $75.9 $61.3 $84.1 $87.1 $716 $74.1 $79.3 $82.1 $85.0 $88.0 $9141 $94.2 $97.5 $104.5 $108.1 $111.9 $55.7 $57.6 $61.7 $63.9 $06.1 $68.4 $70.8 $73.3 $75.9 $813 $84.1 $87.1 $828 $85.7 $91.8 $95.0 $983 $1018 = $105.3 $109.0 $112.8 $1209 © $125.1 $120.5 $82.8 $86.7 $91.8 $95.0 $98.3 $101.8 $105.3 $109.0 $112.8 $120.9 $125.1 $129.5 $828 $85.7 $91.8 $95.0 $98.3 $101.8 $105.3 $109.0 $1128 $1209 $125.1 $129.5 $153 $15.8 $16.9 $17.5 $18.1 $18.8 $19.4 $20.1 $20.8 $22.3 $23.1 $23.9 $51.7 $63.6 $67.4 $59.4 $615 $63.6 $65.8 $68.1 $70.5 $75.6 $78.2 $80.9 $617 $53.6 $67.4 $59.4 $615 $63.6 $65.8 $68.1 $70.5 $75.6 $78.2 $80.9 DATE - 07/17/83, PAGE 3 of 4 E. CONSUMER ACCOUNTS: IN-House Billing/Data Entry Clerk Customer Service Office Clerk ‘Accountant Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES ‘TO BETHEL H. EXPENSES-SALES TO BETHEL |. AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST A. AVG. S/KWH WHOLESALE COST 8. BEGINNING YEAR BALANCE ($1000) KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES: TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8. REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Small Commercial Large Commercial 1904 $0.0 $0.0 $0.0 $0.0 $0.0 $586.0 $0.0 $586.0 $0.449 $750.0 $586.0 $0.0 $0.0 $586.0 $0.0 $0.0 $0.0 $0.0 $0.0 ($586.0) $164.0 $0.0 0.0% ————STAGE 1. 1995 1906 1997 $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 $1,742.6 $1,566.0 $0.0 $0.0 $189.0 $1,742.6 $1,566.0 $1,433.53 $0.434 = $0.38 $0340 $0.370 $0,360 $0.360 $164.0 $36.3 $80.6 $1,742.6 $1,566.0 $1,6223 $0.0 $00 $0.0 $0.0 90.0 $00 $1,7426 $1,8660 $1,6223 $1,613.99 $1,600.0 $1,647.7 $0.0 $0.0 $189.0 $0.0 $24 47 $0.0 $0.0 $0.0 $1,613.90 $1,6114 $1,841.4 ($128.7) $46.3 $219.1 $35.3 $80.6 $299.7 473 $04.7 $142.0 0.0% 0.0% 0.0% yoo 000 ed 000 v0 yoo y000 000 yoo FINANCIAL FORECAST $0.360 $290.7 $1,9002 $0.0 $0.0 $1,9002 $1,6864 $1873 $7.4 $00 $1,8808 ($28.4) $2743 $189.7 0.0% $0.301 $0.328 $2,011.8 $185.3 $1,828.5 $0.414 0.370 $271.3 $2,011.8 $0.0 $0.0 $2,011.68 $1,773.0 $185.3 90.5 $0.0 $1,067.86 ($44.0) $227.3 $237.7 0.0% 0.402 90.306 90.337 —STAGE 3. 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 $41.6 $43.0 $445 $46.1 $47.7 $49.4 $61.4 $52.9 $54.7 $56.7 $58.6 $60.7 $628 $41.6 $43.0 $445 $46.1 $47.7 $494 $51.1 $529 $54.7 $86.7 $58.8 $60.7 $62.8 $77.7 $28.7 $20.7 $30.7 $318 $32: $35.3 $36.5 $37.8 $30.1 $405 $41.9 $06.5 $08.9 $71.3 $73.8 $763 $79.0 $84.6 $87.6 $90.7 $93.8 $07.1 $100.5 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $8,911.9 — $9,4: $9,779.3 $10,466.5 $10,897.4 $11,393.3 $11,860.4 $12,511.5 $12,001.68 $13,528.2 $14,114.9 $14,752.8 $15,368.14 $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 $8,911.9 $0,430.9 $9,770.3 $10,075.6 $10,.406.5 $10,807.4 $11,303.3 $11,860.4 $12,5115 $12,001.6 $13,528.2 $14,114.9 $14.7528 $15,368.1 $0.227 = $0.28) 30.238 «= 80.230 80.243 80.240 = 80.285 «= $0.261 «= 80.271 80.278 «= $0.283 «= 80.291 30.208 )= $0.308 $0.270 $0.270 $0.270 $0.275 $0.275 $0.275 $0.280 $0.280 $0.295 $0.305 $0.305 $0.315 0.320 $0.325 $227.3 $658.0 $1,057.3 $002.5 $1,2325 $1,376.5 $1,373.3 $1,374.8 $1,189.6 $1,070.5 $1,230.7 $1,150.1 $1,2628 $1,285.0 $8,911.9 $9,430.9 $9,779.3 $10,075.6 $10,466.5 $10,807.4 $11,303.3 $11,860.4 $12,511.5 $12,901.6 $13,528.2 $14,114.9 $14,7528 $15,368.1 81,2744 $1,2320 $1,3368 $1,296.2 $1,256. $1,207.2 $4,169.2 $1,13924 = $1,285.0 $1,250.2 $1,216.5 $1,184.14 $1,529 $1,123.0 $445.9 $431.2 é $430.8 $4225 $409.3 $306.3 $449.7 $437.6 $425.8 $414.4 $403.5 $393.0 $10,631.9 $11,094.0 $12.162.7 $12,527.2 $12,071.8 $13,380.1 $14,246.3 $14,679.4 $15,1705 $15,7134 $16,002 $16,684.2 $10,577.4 $11,173.3 $11,827.6 $12,046.5 $12,488.4 $12,711.3 $13,627.1 $14331.8 $14,574.6 $15,3032 $158008 $16,3064 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 .« $0.0 $0.0 $0.0 $0.0 $11.9 $25. $69.4 $60.0 $60.0 $60.0 $60.0 .« $60.0 $60.0 $60.0 $60.0 $373.3 $304.3 $409.8 $417.4 $425.0 $432.6 $440.2 $447. $455.3 $462.9 $470.5 $478.1 $10,962.6 $11,593.4 $12,306.86 $12,523.90 $12,973.4 $13,203.9 $14,127.2 $14,630.58 $15,089.9 $15,826.1 $16.331.3 $16,844.5 $330.6 $499.3 $144.1 ($3.3) $1.6 = ($185.2) ($119.0) $160.2 ($80.6) = $112.7 $22.1 ($39.7) $658.0 $4,292.6 «$4,376.5 —$4,373.3$4,374.8 $4,11 ’ $1,150.4 $1,286.0 $1,245.3 $515.4 $1,387.90 —$1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,2000 $1,200.0 $1,200.0 $1,200.0 $1,200.0 9.5% 9.4% 94% 0.7% 84% 8.0% 1% TAK 7.6% 1% Tae 1.2% 6.9% 6.6% $0.293 $0.293 0.293 $0.299 90.299 $0.299 $0.304 $0.304 90.321 90.332 $0,332 90.342 $0.48 $0.353 $0.267 $0.267 $0.267 $0.272 $0.272 $0.272 90.277 $0.277 $0.292 $0,302 $0.302 $0.312 90.317 $0.322 90.246 $0.246 90.246 $0.250 $0.250 $0.250 90.255 90.255 90.268 $0.278 $0.278 $0.287 $0.201 90.296 2014 $65.0 $65.0 $433 $104.0 $00 $16,038.3 $0.0 $16.038.3 $0315 $0.335 $1,248.3 $16,038.3 $1,094.5 $3831 $17,518.9 $17,077.1 $0.0 $60.0 $485.7 $17,6228 $108.9 $1,352.2 $1,200.0 64% $0.364 $0.332 $0.305 DATE - 07/17/93, PAGE 4 of 4 9, VILLAGE UTILITY COSTS: 08M Fuel ‘Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITHOUT PCE 11, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential ‘Small Commercial Large Commercial ANNUAL PCE PAYMENTS PW Annual PCE Payments ACCUMLATED PW PCE 1994 $700.9 $650.8 $220.8 $0.0 $1,672.5 90.449 90.488 $0.444 $0.408 $0.008 $0.12 90.12 $0.41 $773.2 $773.2 $773.2 ———STAGE 1. 1995 $40.0 $0.0 $75.9 $1,776.3 $1,601.2 $0.471 $0,512 $0.467 $0.429 $0.101 $0.12 $0.12 $0.43 $840.1 $611.7 $1,584.90 1996 $41.4 $0.0 $78.1 $1,760.9 $1,880.4 $0.490 $0,455 90.418 $0.105 $0.12 $0.12 $0.42 $830.5 $775.2 $2,360.2 ——STAGE 2—— 1997 1998 1990 $42.8 1000 100 $0.0 000 3000 $80.4 2000 3000 $1,812.4 0006 000 $1,935.7 30001 100 000 y000 90.301 = $0.402 90.356 = $0,366 90.328 «= $0.337 $0.109 = 80.112 80.116 90.13 $0.13 $0.13 . $0.13 $0.42 $0.33 90.4 $846.8 $610.7 = $052.4 8 $6400 $840.3 1.9 $3,063.9 $4,213.2 TOE Sa a OnREEE 3 $0.293 $0,267 $0.246 $0.120 $0.13 $0.13 $0.25 $403.7 $328.4 $4.541.6 $0.293 $0.267 90.246 90.125 $0.13 $0.13 $0.25 $403.8 $3174 $4,859.0 B88 5 FnHnE 8 sss $0,129 $0.14 $0.25 $403.0 $306.0 $5,165.0 EOREHEE 2 $0.290 $0.272 $0.250 90.134 $0.14 $0.14 $0.25 $415.2 $304.6 a HRGGE 2 90.299 90.272 90.250 $0.138 $0.15 $0.14 $0.25 1415.9 $204.8 $5,764.5 EannE 3 $0.209 $0.272 $0.250 $0.143 $0.15 $0.15 $0.25 $415.5 $284.6 $6,049.0 $2725 $6,605.4 a GTEEE 3 90.321 $0.292 $0.268 $0.159 17 $0.27 $470.2 $200.5 $6,895.9 i oEEHE 8 $0.332 $0.302 $0.278 $0.164 $0.17 $0.17 $0.28 $499.0 $297.8 $7,193.7 big 3 90.332 $0.302 $0.278 $0.170 $0.18 $0.18 $0.28 $494.2 $285.0 $7,478.7 2011 $0.342 $0.312 $0.287 $0.176 $0.18 $0.18 $0.20 $522.4 $291.1 $7,760.86 2012 § REEEE 90.348 90.317 0.291 $0.182 $0.19 $0.19 $0.29 $533.0 $287.0 $8,056.8 2013 % RSEEE $0.363 $0.322 $0.296 90.188 $0.20 $0.20 $0.30 $542.7 $262.3 $8,330.1 2014 § RESEE $0.364 $0.332 $0.305 $0.195 $0.20 $0.20 $0.30 $566.8 $284.8 $8,623.9 DATE - 07/17/93, PAGE 1 of 4 Interest Rate 7.00% General inflation Rate 3.600% Deprec. Period 30 Fuel inflation Rate 3.800% Loan Period 20 REU Diese! Plant 1=NO, O=Yes 1 ‘%Grant Tine 0% 100% Discount Rate 3.50% ‘%Grant Hydro 0% 100% PCE Rate S/kwh, 1994 $0.098 Loan Period initial Capital 18 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE B, NO LOAN FUNDS) ———STAGE 1. STAGE 2 sta: 3 1904 1905 1908 1907 19081990 2000 2001 2002 2003 2004 2005 2008 2007 2008) 2009 2010 2011 2012 2013 2014 4. LOAD DEMAND VILLAGES (A. DEMAND - KWH 1032.1 1056.2 1080.3 1104.3 1128.4 1182.5 1176.6 1200.6 1224.7 1249.0 1279.4 1309.2 1330.3 1369.4 1309.5 1429.6 1459.7 1489.8 1519.8 1550.0 1874.8 B. ENERGY - MWH 4254.5 4362.0 4469.4 4576.9 46843 4TH 4899.3 5006.7 6114.2 $222.6 5364.8 $507.0 5649.2 5791.4 5933.6 6075.8 6218.0 6360.2 6502.4 6644.6 6750.9 C. TRANSMISSION 0.0 436.2 4469 487.7 468.4 470.2 489.9 500.7 5114 622.3 $36.5 850.7 564.9 679.1 593.4 607.6 6218 636.0 650.2 6645 676.1 LINE LOSSES @ 10% D. TOTAL ENERGY 42545 4798.2 4916.4 504.6 51528 $271.0 5389.2 5507.4 $625.6 8744.9 $901.3 6087.7 62144 6370.5 6527.0 6683.4 6830.8 6996.2 7182.6 7308.1 7426.0 REQUIREMENTS - MWH BETHEL E. DEMAND - KWH oO o o o 0 ° 6796 6964 7132 7300 7420.0 7640.0 7660.0 7780.0 7900.0 8020.0 8140.0 8260.0 8380.0 8500 8636.0 F. ENERGY - MWH 0 0 0 ° 0 © «= 44272,« «43781 «= 4328844534 «45325. © 46117.8 48000.7 4701.6 484035 49285.4 $007.3 50869.2 S1661.1 52463 $3202.2 G. MWH AVAILABLE ° © 2500 $000 8000 0008000 5000 5000 000 5000 5000 5000 000 000 000 5000 000 5000 000 000 FROM NYAC HYDRO H. VILLAGE HYDRO 00 00 32408 3320.7 «33017 «34826 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 USAGE - MWH G. SURPLUS MWH HYDRO 00 00 oo 1679.3 1608.3 1837.4 5000.0 5000.0 $000.0 $000.0 5000.0 5000.0 5000.0 $000.0 5000.0 5000.0 $000.0 $000.0 $000.0 $000.0 $000.0 ‘SALES TO BETHEL UTILITIES H. MH PURCHASES: 0.0 4708.2 «16885 = 1713.8 «1781.1 «1808.4 00 00 00 00 00 00 00 00 0.0 0.0 00 00 0.0 00 00 FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A TRANSMISSION LINE Yrt $3,472 $3472 $3,472 $3,472.«$3,472.«$3,472_«$3,.472«««$3.472.—«$3,472,««$3472_—«$3,472_—«$3,472_««$3,472,—««$3,472,— $3,472 $3,472-—$3,.472— $3,472 $3,472 $3,472 $3,472 Yr2 $0 $3,718 «$3,715 «$3,715 «$3,718 $3,715 $3,715 $3,715 $3718 $3,715 $3,715 «$3,715 «$3,715 $3,715 STIS «$3715 $3,715 $3715 $3,715 $3,718 «$3,718 B. NYAC HYDRO Yet $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 © $2,700» $2,700 © $2,700 $2,700 Yr2 $0 $2880 $2889 © $2,880 «$2,880 «$2880 «= $2889 «= $2880 «$2,889 «= «$2,889 «$2880 «$2,880 «$2,880 «= $2889 «= $2,880 «= $2889 §«=— $2,880 «= $2889 «= $2889 «= $2,880 $2,880 C. NEW DISTRIBUTION $0 $0 $0 $0 $50 $104 $233 $322 $416 $517 3624 $738 $850 $088 $1,125 $1,270 $1,424 «$1,587 $1,780 $1,043 $2,137 0. PURCHASE BETHEL UTILITIES $0 $0 $0 $0 $0 $0 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 E. NEW GENERATOR $00 © $00 $0.0 $00 © $00 $00 $0.0 $0.0 $1,125 $1,125 $1,125 «$4,125 «$1,125 «$1,125 «$2,878 $2875 «$2875 «$2875 $2578 «$2875 $2,878 F. COMPUTER SYSTEM $0 $0 $0 $0 $600 © $800» $800» $80.0 «= $80.0 = $80.0 = $800 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3. INITIAL CAPITAL $750 $750 $750 $750 $750 ‘$750 $750 $750 $750 $750 $750 $750 $750 $750 ‘$750 $0 $0 $0 $0 $0 $0 TOTAL $6,922 $43,528 $13,526 $43,528 $13,636 $13,090 $19,838 $19,928 $24,147 $24,248 $74,355 $24,389 $24,510 $24,839 $23,228 $22,621 $22,775 $22,038 $23,111 $23,204 $23,488 4. ESTIMATED RATEBASE 0K OK 000 0K 000K 3000 $16,189 $15,652 $16,245 $15,720 $15,201 $14,610 = $14,105 $13,608 $14,560 $14,088 $13,617 $13,154 $12,701 $12,258 $11,626 5. DEBT SERVICE ($1000) TRANSMISSION LINE $327.7 $678.4 «$678.4 «$678.4 «$678.4 $878.4 $678.4 $678.4 © $678.4 «$678.4 «$678.4 «($678.4 $6784 $678.4 «$678.4 = $678.4 «= «$878.4 NYAC HYDRO $2549 © $527.6 $527. $527.6 $627.8 $5276 $527.8 $5278 © $527.8 «$527.6 $6276 © $527.6 «= $527.6 «= $527.8 «= «$527.8 NEW DISTRIBUTION $00 = $0.00 $000 $4. $98 $30.3 358.9 . $81.1 $03.3 $108.2 $1344 $140.8 = $168.2 $183.4 «$201.7 PURCHASE BETHEL UTILITIES $00 ©=— $0.0 $00 $00 = $00 $00 $566.4 $5664 $568.4 $868.4 = $588.4 $588.4 $5664 © $506.4 $5864 «= $5664 «= $588.4 NEW GENERATOR $00 ©= $0.0 $0.0 $00 §=— 800s $00 $0.0 $108.2 $108.2 «$108.2 $1082 «$1082 $243.1 $2431 © $243.1 $243.1 $243.1 $243.1 COMPUTER SYSTEM $0 $0 $0 $0 $146 8148 $19.5 $195 $19.5 $0.0 $0.0 $0.0 300 $0.0 $0.0 $0.0 $0.0 $0.0 INITIAL CAPITAL, $00 © $823 $823 $823 $823 $823 $82.3 $823 $823 $823 8823 88238823 $0.0 $0.0 $0.0 $0.0 30.0 ‘SMALL BUSINESS ADMIN, LOAN $00 = $0.0 = $00 $00 $00 $00 $204.8 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 30.0 TOTAL 3582.6 $1,288.3° $4,288.9 — $1,208.3 $14,907.7 $1,312.7 $2,108.3 $2,028.4 $2,039.3 $2,030.5 $2,042.0 $2,054.1 $2,208.9 $2,136.3 $2,140.8 $2,185.2 $2,184.5 $2,198.8 $2,247.1 DATE - 07/17/93, PAGE 2 of 4 ———— STAGE 1. —STAGE 2— aaa eeeenecee 1904 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 6, OPERATING EXPENSES ($1000) (A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating $0 $0 $40.0 $44.3 $45.9 “7s $402 3509 $827 9845 $56.4 $68.4 $00.4 $62.6 $64.7 $67.0 $60.4 $718 $743 $76.9 Maint. $0 $0 $40.0 $443 $45.9 75 $402 $50.9 $527 $545 $56.4 $58.4 $60.4 $626 $64.7 $67.0 $69.4 $718 $74.3 $76.9 Insurance: $0 $0 $40.0 $443 $45.9 475 $402 $50.9 $627 $645 $56.4 958.4 $60.4 $626 $64.7 $67.0 $60.4 $718 $74.3 $76.9 2. BETHEL GENERATION PLANT Chief Plant Operator $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $85.0 $880 sort $042 $075 $101.0 $1045 $1119 $115.8 $119.9 $124.1 $126.4 $1320 $1376 ‘Six Piant Operators $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $510.0 $5279 $5463 $5654 $5852 $6057 $6269 $6716 $605.1 $719.4 «$744.6 «= $7706 = $797.6 = $825.5 O&M Materiais $0.0 $0.0 $0.0 30.0 $0.0 $0.0 $250.0 $2588 $267.8 $2772 $286.9 $296.9 $3073 $329.2 $340.7 $362.6 $365.0 $3778 $391.0 $404.7 Fuel $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $4,5725 $5,031.0 $5,163.0 $5,500.09 $5,8221 $6,1495 $6,4927 $6,8524 $7,2293 $7,624.2 $8,0378 $8,471.1 $8,9249 $9,4000 $9,806.9 ‘Insurance $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $230.0 $238.1 $246.4 $255.0 $263.9 $273.2 $282.7 $202.6 $302.9 $313.5 $324.4 $335.8 $347.5 $359.7 $3723 3. VILLAGE OPERATORS: $0.0 $0.0 $0.0 $0.0 $450 $90.0 $1050 $1087 $1125 $1164 $1205 $1247 $1201 $1336 $1383 $1431 $1481 $1533 $1587 = $184.2 $170.0 4. COST OF PURCHASED POWER $0.0 $7305 $4318 $458.0 $485.5 $514.4 $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 B. TRANSMISSION/SUBSTATIONS INHouse 8M Labor $00 $0.0 $0.0 90.0 $0.0 $0.0 75 $40.2 $50.9 $62.7 $54.5 $56.4 $58.4 $60.4 $626 $64.7 $67.0 $69.4 $718 $743 $76.9 O&M Materials $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $47.5 $49.2 $50.9 $52.7 $54.5 $56.4 $58.4 $60.4 $62.6 $04.7 $67.0 $60.4 $718 $74.3 $76.9 Contractor 8M Labor $0.0 $40.0 $414 $443 $45.9 $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 O&M Materials: $0.0 $40.0 $414 $443 $45.9 $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 C. DISTRIBUTION IN-House O&M Labor $0.0 $0.0 $0.0 0.0 $0.0 $0.0 $160.0 $165.6 $171.4 sire $183.6 $190.0 $196.7 $203.6 $210.7 $218.1 $225.7 $233.6 $2418 $250.2 $259.0 O&M Materials $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $400.0 $4140 $428.5 $443.5 $459.0 $475.1 $401.7 $508.9 $526.7 $645.2 $564.2 $584.0 $604.4 $625.6 $647.5 Contractor 8M Labor $0.0 $0.0 $0.0 $0.0 $443 $45.9 $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 O&M Materials $0.0 $0.0 $0.0 $0.0 $44.3 $45.9 $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 D. ADMIN & GEN. EXPENSES Form Corporation/Utility $25.0 $0 $0 $0 $0 $0 $25 $0 so $0 so $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 APUC Filing $26.0 $0 $0 $10 $0 $0 $25 $0 $0 $28 $0 $0 $25 $0 $0 $25 $0 so $25 $0 $0 Office Equip. $15.0 $0 $0 $0 $0 $0 $0 so $0 $15 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 INHouse General Manager $03.8 $970 © $100.4 $1113 $1193 $123.5 $136.9 $1407 $187.1 $162.6 $168.3 $1744 $180.2 $186.5 BoExec. Secretary $438 $453 $46.9 $52.0 $55.7 $876 $63.9 906.1 $73.3 $75.9 $78.5 $813 $64.1 $87.4 Financial Mgr. $563 $58.2 $00.3 906.8 $716 $74.1 $82.1 $85.0 $942 907.5 $101.0 $104.5 $108.1 $1118 Admin. Sec. $0.0 $0.0 $0.0 $0.0 $55.7 $67.6 $63.9 $06.1 $73.3 $75.9 $76.5 $81.3 $84.1 $87.1 ‘Staff Engineer $0.0 $0.0 $0.0 $0.0 $828 $85.7 $95.0 $96.3 $108.0 $1128 $120.9 $125.1 $129.5 Operations Manager $0.0 $0.0 $0.0 .« $0.0 $828 $85.7 $95.0 $98.3 $109.0 $1128 $1209 $125.1 $120.5 ‘Secretary $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $828 $85.7 $95.0 $98.3 $109.0 $1128 $1209 $125.1 $129.5 Rent $12.0 $124 $12: $13.3 $13.8 $143 $15.3 $15.8 $175 $18.1 $20.1 $20.8 $223 $23.1 $23.9 Misc $120 $124 $129 $13.3 $13.8 $143 $51.7 $53.6 $50.4 9015 $68.1 $70.5 $75.6 $78.2 $80.9 Contractor Attomey/Engr. Consultant $120 $124 $129 $13.3 $13.8 $143 $61.7 $53.6 $50.4 $615 $68.1 $70.5 $75.6 $78.2 $80.9 DATE - 07/17/83, PAGE 3 of 4 E. CONSUMER ACCOUNTS. IN-House Billing/Data Entry Clerk Customer Service Office Clerk, Accountant Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES ‘TO BETHEL H. EXPENSES-SALES TO BETHEL 1. AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST A AVG. S/KWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES TOTAL EXPENSES KWH SALES: KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES TOTAL REVENUES: REVENUES - EXPENSES END OF YEAR BALANCE (' MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8. REGIONAL UTILITY ESTIMATED AVG, RATES WITHOUT PCE Residential ‘Smal Commercial Large Commercial 1994 ———— STAGE 1. $8773 $0.449 $750.0 $8773 $0.0 $0.0 $877.3 $0.0 $0.0 $0.0 $0.0 $0.0 ($877.3) ($127.3) 00% $2,345.6 90.584 $0.530 (8127.3) $2,345.6 $0.0 $0.0 $2,348.6 $2,311.8 $0.0 $0.0 $0.0 $2,311.8 ($33.7) (3161.1) 473 0.0% $0.540 (8161.1) $2,169.0 $0.0 $0.0 $2,169.0 $2,413.5 $0.0 $24 $0.0 $2,415.90 $246.8 $058 $94.7 0.0% 1997 90.0 $0.0 $0.0 $0.0 $0.0 $2,225.3 $189.0 $2,036.3 $0.484 $0.460 $85.8 $2,225.3 $0.0 $0.0 $2,225.3 $2,105.4 $189.0 $4.7 $0.0 $2,299.1 $738 $159.6 $142.0 aad —STAGE 2— 1908 = 1900 $375 $38.8 $375 $38.8 $250 $25.9 $0.0 $0.0 $0.0 $0.0 $2,512.2 $2,048 $1873 © $185.3 $2,324.8 $2,420.4 $0530 80.551 FINANCIAL FORECAST $2,5122 $00 $0.0 $2,5122 $2,248.5 $187.3 $74 $0.0 $2,4429 ($69.2) $90.3 $189.7 $0.522 90.475 $0.437 0.510 $90.3 $2,614.8 $0.0 $0.0 $2,614.8 $2,443.68 $185.3 $0.5 $0.0 $2,638.6 $23.9 9114.2 $237.7 0.0% 90.554 $0.505 90.464 — rt 3 2000 $40.2 $40.2 $26.8 $60.0 $0.0 $9,514.8 $9,514.8 $0.243 $0.310 $1142 $0,5148 $2,104.68 $736.6 $12,356.0 $12,1444 $0.337 0.307 $0262 2001 $41.6 $41.6 $27.7 $66.5 $0.0 $10,033.9 $10,033.9 $0.242 $0.310 $287.8 $10,033.9 $2,034.7 $712.2 $12,780.7 $12,828.6 $0.0 $25.8 $304.3 $13,248.7 $467.9 $755.7 $794.4 10.2% $0.337 90.307 $0.262 $43.0 $43.0 $287 $08.9 $0.0 $10,382.3 $0.0 $10,382.3 $0.253 $0.310 $765.7 $10,382.3 $2,991.9 $739.2 $13,233.3 $12,730.8 $0.0 $30.7 $301.3 $13,161.8 (871.4) $6843 $1,090.5 10.0% 90.337 90.307 90.282 $44.5 $44.5 $29.7 $713 $0.0 $10,678.6 $10,678.6 $0.253 $0310 $684.3 $10,678.86 $2,043.6 $715.3 $13,437.5 $13,086.1 $0.0 $54.5 $402.2 $13,542.90 $105.4 $749.7 $1,387.09 9.6% $0.337 0.307 90.282 2004 $46.1 $46.1 $30.7 $73.8 $0.0 $11,089.5 $0.0 $11,060.5 $0.257 $0.310 $789.7 $11,069.5 $1,976.2 $601.7 $13,737.3 $13,392.9 $0.0 $00.4 $409.8 $13,812.1 $748 3804.5 $1,200.0 9.3% $0.337 $0.307 $0.282 $47.7 $47.7 $318 $763 $00 $11,500.4 $0.0 $11,500.4 $0.263 $0.315 $864.5 $11,500.4 $1,899.2 $664.7 $14,064.4 $13,798.7 $0.0 $60.0 $417.4 $14,276.14 $211.7 $1,076.2 '$1,200.0 8.9% $0.42 $0.312 $0.287 2006 $40.4 $49.4 $329 $79.0 $0.0 $11,996.2 $0.0 $11,906.2 $0.269 $0.315 $1,076.2 $11,096.2 $1,833.7 $641.8 $14,471.7 $14,040.4 $0.0 $60.0 $425.0 $14,534.4 $628 $1,130.08 $1,200.0 90.342 $0.312 $0.287 2007 $51.1 $51.4 $34.1 $81.8 $0.0 $12,463.4 $12,463.4 $0.275 $0320 $1,138.0 $12,463.4 $1,769.0 $619.2 $14,851.6 $14,527.2 $0.0 $60.0 $432.6 $15,019.68 $168.2 91,307.2 $1,200.0 8.2% $0348 $0317 $0.291 $62.9 $52.9 $35.3 $84.6 $0.0 913,194.5 $0.0 $13,114.56 90.284 $0.330 $1,307.2 $13,114.5 $1,894.0 $062.9 $15,871.4 $15,243.68 $0.0 $60.0 $440.2 $15,744.0 $726 $1,378.8 $1,200.0 8.2% 90.369 $0.327 $0.300 2009 $54.7 $84.7 $878 $0.0 $13,504.6 $0.0 $13,504.6 $0.289 $16,014.3 ($52.9) $1,326.9 $1,200.0 8.1% $0.359 90.327 $0.300 2010 $56.7 $56.7 $378 $90.7 $0.0 $14,131.2 $0.0 $14,131.2 $0.296 $0.335 $1,326.9 $14,131.2 $0.364 $0.332 $0.305 2011 $58.6 $586 $30.1 $03.8 $0.0 $14,717.9 $0.0 $14,717.9 $0.303 $0.340 $1,329.5 $14,717.90 $1,710.0 $598.5 $17,026.4 $16,517.7 $0.0 $60.0 $4629 $17,040.68 $142 $4,343.8 $1,2000 75% $0.370 $0.337 $0.30 2012 $60.7 $60.7 $405 $97.1 $00 $15,355.8 $0.0 $15,365.8 $0.311 ($19.1) $4,324.7 $1,200.0 11% $0.375 $0.342 $0.314 2013 2014 $62. $65.0 $62. $65.0 $41.9 $433 $100.5 $104.0 $0.0 $0.0 $15,971.41 641.3 $0.0 $0.0 $15,971.1 $16,641.3 $0318 = $0.326 $0.350 $0.355 $1,324.7 $1,301.1 $15,071.1 $16,641.39 $1,593.6 = $1,5374 $557.7 $538.1 $18,1224 $18,7168 $17,560.7 $18,096.6 $0.0 $0.0 $60.0 $600 $478.1 $485.7 $16,008.8 $18,6423 ($23.6) ($74.4) $4,301.1 $4,226.7 $1,200.0 $1,200.0 6.8% 6.5% $0.380 $0.386 $0347 $0.351 $0.319 $0.323 DATE - 07/17/93, PAGE 4 of 4 ———STAGE 1. STAGE 2— —_— AE. 1904 1906 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 9. VILLAGE UTILITY COSTS 08M $700.9 $40.0 $41.4 $42.8 2000 7000 3000 3000 70006 000 20006 2000 3000 200% 000 2000 000 100 000 000 900 Fuel $650.8 $0.0 $0.0 $0.0 100 0K 3000 30001 woo 000 000 000K 3000 000 000 000 000 1000 3000 3000 7000 Admin & Gen. Expenses: $220.8 $75.9 $76.1 $80.4 3000 000 3000 900 oO 00K 30000 000 900 00% 0K 0K 000 000 000 2000 000 Purchases from G&T/Regional Utility $0.0 $2,543.0 $2,654.8 $2,315.9 9000 0006 000% 7000 200" 7000 2000 000¢ 3000 000 000 y000 2000 2000 000 000 0K ‘TOTAL ANNUAL COSTS: $1,572.5 $2,658.9 $2,774.3 $2,439.1 3000 3000 000 3000 200% 000% 2000 0K 3000 1000 000 1000 00% 000 000 3000 0K 10. ESTIMATED AVG. RETAIL COST $/KWH $0449 =©6$0.663 $0,675 $0.579 3000 000 3000 000 2000 000 2000 00K 3000 10001 000 000K 000K 3000 000 000 000 IN VILLAGES - WITHOUT PCE Residential $0488 = =©6$0.720 $0.733 $0630 $0522 $0.554 $0.337 90.337 $0.337 90.337 90.337 $0.342 90.342 90.348 $0.369 $0.359 $0.364 $0370 90.375 $0.380 90.386 ‘Small Commercial 90.444 «60.656 §=— $0.668 $0573 $0475 $0.505 $0307 $0.307 $0.307 $0307 $0.307 $0.312 $0.312 $0.317 90.327 $0.327 $0.332 $0.337 90.342 $0.347 90.351 Large Commercial $0.408 = $0.603 $0.614 $0527 $0.437 | $0.464 $0.282 $0.282 $0.282 $0.282 $0,282 $0,287 $0.287 0.291 $0.300 $0.300 $0.305 $0,309 $0.314 90.319 $0.323 11. ESTIMATED AVG, RETA COST S/KWH IN VILLAGES - WITH PCE PCE S/KWH 90.008 §86$0.101 = $0.105 $0109 §=6$0.112 $0.116 $0.120 90.125 $0.129 90.134 $0.138 90.143 $0.159 $0,164 $0.170 90.176 $0,182 90.188 $0.195 Residential $012 $013 $0.14 $013 $0.13 $0.14 $0.13 $0.14 $0.14 $0.14 $0.15 $0.15 $0.17 $0.17 $0. $0. $0.20 $0.20 ‘Small Commercial $0.12 $0.13 $0.13 $0.13 $0.14 $0.13 $0.13 $0.14 $0.14 $0.15 $0.15 $0.17 $0.17 $0. $0.20 $0.20 $0. $0.31 $0.32 $0.32 Large Commercial $0.41 $0.60 $0.53 $0.44 90.46 $0.28 90.28 $0.28 $0.28 $0.28 $0.29 $0.30 $0.30 $0.30 ANNUAL PCE PAYMENTS: $773.2 $1,286.9 $1,324.90 $1,120.4 $911.3 $1,001.09 $506.2 $609.0 $510.8 $511.9 9515.7 $533.0 $582.3 $581.2 $595.5 $609.1 $6218 $633.8 $640.9 PW Annual PCE Payments: $773.2 $1,224.1 $1,2368 $1,0187 $7941 $843.6 $411.8 $400.0 $387.9 $375.6 $365.6 $365.1 $359.7 $346.9 $343.4 $330.4 $3348 $329.7 $322.1 ACCUMLATED PW PCE $773.2 $1,007.3 $3,234.1 $4,252.86 $5,0470 $5,6905 $6,3023 $6,702.4 $7,0003 $7,405.68 $7.8314 $8,196.5 $8,902.66 $9,2623 $9,600.2 $9,952.7 $10,292.0 $10,6268 $10,0565 $11,2786 DATE - 06/17/03, PAGE 1 of 4 Interest Rate Deprec. Period Loan Period ‘%Grant Tine ‘%Grant Hydro Loan Period initial Capital 4. LOAD DEMAND VILLAGES ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% 0. TOTAL ENERGY REQUIREMENTS - MWH BETHEL E. DEMAND - KWH F. ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES H. MH PURCHASES: FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A TRANSMISSION LINE Yrt Yr2 B. NYAC HYDRO Yet v2 C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES £. NEW GENERATOR F. COMPUTER SYSTEM 3. INITIAL CAPITAL TOTAL 4, ESTIMATED RATEBASE 5. DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES: NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL ‘SMALL BUSINESS ADMIN. LOAN TOTAL 100% 100% “al Boo 1904 1032.1 42545 4254.5 eo 00 0.0 0.0 $3,472 $0 $2,700 $0 $0.0 $750 $6,922 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 General inflation Rate Fuel inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate S/kwh, 1994 ———STAGE 1. 1995 1086.2 4362.0 436.2 4798.2 00 00 4798.2 $3,472 $3,715 $2,700 $2,680 $0 $0 $0.0 $750 $13,526 $0.0 $0.0 $0.0 $0.0 $0.0 $82.3 $0.0 $82.3 1996 1080.3 4409.4 446.9 4916.4 co 3249.8 00 1666.5 $3,472 $3,715 $2,700 $2,889 $750 $13,528 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $82.3 1997 1104.3 4576.9 487.7 5034.6 3320.7 1679.3 1713.8 $3,472 $3,715 $2,700 $2,869 $0 $0 $0.0 $750 $13,526 $0.0 $0.0 $0.0 $0.0 so $623 0.0 $82.3 3.500% 3.500% 3.50% $0.098 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE C) ——STAGE 2— 1908 1990 2000 11284 © 11825 46843 «47018 4084 = 470.2 $1528 $2710 53892 ° ° 6796 ° O 41272 5000 $000 5000 3301.7 34626 0.0 10083 18374 = $000.0 17611 1808.4 00 $3,472 $3,472, $3,472 $3,715 $3,715 $3,715 $2,700 = $2,700 = $2,700 $2,889 © $2,889» $2,889 $50 $104 $233 $0 $0 © $8,000 $0.0 $0.0 $0.0 $60.0 $600 $800 $750 $750 $750 $13,636 «$13,600 $21,839 2000 yoo $3.413 $0.0 $0.0 $0.0 $0.0 $47 $22.0 $0.0 $755.1 $0.0 $0.0 $146 $19.5 $823 $823 $823 $0.0 $0.0 $2048 $104.7 «= $106.7 $1,083.8 2001 12006 $008.7 5007 58074 49761 5000.0 00 $0.0 $30.3 $755.1 $0.0 $19.5 $82.3 $204.8 $1,092.2 STAGE 3- 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 12247 12400 1279.1 1309.2 1330.3 13694 13095 14206 14507 14808 15199 1650.0 15748 51142 $2226 «= 8364.8 = $507.0 5649.2 57914 «= 8033.6 ©= 075.8 = «6218.0 6380.2 «= 65024 «= 6844.6 8750.9 si $223 $36.8 $50.7 564.9 $70.1 593.4 607.6 621.8 636.0 650.2 664.5 675.1 86286 © $7449 «= 5901.3 6087.7 6214.1 6370.5 «= 6527.0 6883.4 = 830.8 = 6096.2 71526 = 7308.1 7426.0 492 7900-74200 = 7540.0 © 7680.0 «7780.0 += 7900.0 8020.0 8140.0 8280.0 8380.0 8500 8636.0 49788 44534 453259 © -46117.8 © 40000.7 477016 © 48493.5 49285.4 © 80077.3 50860.2 1661.1 52453 $3292.2 5000 $000 5000 $000 5000 5000 5000 5000 5000 5000 5000 6000 5000 00 00 00 0.0 00 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 $0000 © $0000» $0000 = $000.0 $000.0 © $000.0 8000.0 $000.0 50000 = 8000.0 $000.0 = $000.0 $000.0 00 oo 00 00 00 00 0.0 0.0 0.0 0.0 00 0.0 0.0 $3472 $3,472, $3,472, $3,472, $3,472 $3,472, $3,472, $3,472, $3,472, $3,472 $3,472, $3,472 $3,472 $3715 = $3.75 $3,715 $3,715 $3,715 $3,715 $3,715 = $3,715 $3,718 = $3,715 $3,715 $3,715 $3,715 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,889 «= $2,880» $2,880 = $2,689 «= $2,889 «= $2,889 = $2,880 = $2,889 «= $2,880 = $2,880 = $2,889 = $2,889 = $2,889 $416 $517 $624 $738 $859 $988 = $1,125 $1,270 $1,424 = $1,587 $1,760 $1,943 $2,137 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 125 $1,125 $1,125 $1,125 $1,125 $1,125 $2,575 $2,575 $2,575 $2,575 $2,575 $2,575 $2,575 $80.0 $80.0 $80.0 so $0 $0 $0 $0 $0 $0 $0 $0 $0 $750 $750 $750 $750 $750 $750 $750 $0 so $0 $0 $0 $0 $23,147 $23,248 $23,355 $23,389 «= $23,510 $23,639 = $25,226 $24,621 $24,775 $24,938 $25,111 $25,204 «$25,488 $4,321 $4,222 $4,120 $3,983 $3,884 $3,813 $6,200 $5,145 $5,000 $5,062 $5,035 $5,018 $5,012 $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 $0.0 $0.0 $30.3 $58.9 $69.7 $81.1 $93.3 $106.2 $119.9 $134.4 $149.8 $166.2 $183.4 $201.7 $755.1 $755.1 $765.1 $755.1 $755.1 $755.1 $755.1 $755.1 $755.1 $755.1 $755.1 $755.1 $106.2 $106.2 $106.2 $106.2 $106.2 $243.1 $243.1 $243.1 $243.1 $243.1 $243.1 $243.1 $195 $10.5 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $82.3 $82.3 $82.3 $823 $623 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $204.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $1,207.3 $4,012.0 §$4,022.1 $1,013.3 $1,024.8 1,037.0 $1,186.7 $4,148.1 $1,132.6 $1,148.0 $1,164.4 $1,199.9 DATE - 06/17/93, PAGE 2 of 4 6, OPERATING EXPENSES ($1000) ‘A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators: O&M Materials: Fuel Insurance 3. VILLAGE OPERATORS: 4, COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS INHouse O&M Labor 8M Materials Contractor O8M Labor O&M Materials 1904 sss $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 $25.0 $25.0 $15.0 $03.8 $43.8 $56.3 $0.0 $0.0 $0.0 $0.0 $120 $12.0 $12.0 ———— STAGE 1 ——STAGE 2—— 1996 1995 $0 $0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $739.5 $0.0 $0.0 $40.0 $40.0 $0.0 $00 $0.0 $0.0 $0 $97.0 $45.3 $58.2 $0.0 $0.0 $0.0 $0.0 $124 $124 $124 $40.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $431.8 $0.0 $0.0 $414 $414 $0.0 $0.0 $100.4 $46.9 $60.3 $0.0 $0.0 $0.0 $0.0 $129 $129 $12.9 1997 $42.8 $428 $42. $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $458.0 $0.0 $0.0 $42.8 $42.8 $0.0 $0.0 $0 $10 $103.9 $48.5 $62.4 $0.0 $0.0 $0.0 $0.0 $13.3 $13.3 $13.3 1908 $44.3 $44.3 $44.3 $0.0 $0.0 $0.0 $0.0 $0.0 $45.0 $485.5 $0.0 $0.0 $44.3 $44.3 $0.0 $0.0 $443 $44.3 1999 2000 $45.9 $475 $45.9 475 $45.9 $475 $0.0 $85.0 $0.0 $510.0 $0.0 $250.0 $0.0 $4,5725 $0.0 $230.0 $90.0 $105.0 $514.4 $0.0 $0.0 $47.5 $00 $47.5 $45.9 $0.0 $45.9 $0.0 $0.0 $160.0 $0.0 $400.0 $45.9 $0.0 $45.9 $0.0 $0 $25 $0 $25 $0 $0 $111.3 $115.2 $62.0 $53.8 $66.8 $69.1 $0.0 $63.8 $0.0 $80.0 $0.0 $80.0 $0.0 $80.0 $143 $148 $14.3 $50.0 $14.3 $50.0 -_—_—_—_——— GE 3- 2001 $50.9 $50.9 $50.9 $01.1 $49.2 $49.2 $165.6 $414.0 $0.0 $0.0 $0 $119.3 $71. 6 $15.3 $61.7 $61.7 $5,163.0 $246.4 $112.5 $0.0 $0.0 $0.0 $171.4 $428.5 $0.0 $0.0 $123.5 ‘$57. $74.4 $57.6 $85.7 $85.7 $85.7 $15: $53.6 $83.6 2003 $52.7 $62.7 $52.7 $94.2 $665.4 $277.2 $5,509.90 $255.0 $116.4 $0.0 $52.7 $52.7 $0.0 $0.0 $177.4 $443.5 $0.0 $0.0 $0 $15 $127.8 $59.6 $76.7 $59.6 $88.7 $88.7 $88.7 $16.4 $55.4 $55.4 2004 $54.5 $545 $54.5 $97.5 $585.2 $286.9 $5,822.1 $263.9 $120.5 $0.0 $54.5 $54.5 $0.0 $0.0 $183.6 $450.0 $0.0 $0.0 $56.4 $56.4 $56.4 $101.0 $605.7 $296.9 $6,140.5 $273.2 $124.7 $0.0 $56.4 $56.4 $0.0 $0.0 $190.0 $475.1 $0.0 $0.0 $0 $0 $0 $136.9 $63.9 $82.1 $63.9 $95.0 $95.0 $95.0 $17.5 $59.4 $50.4 2006 $68.4 $58.4 $58.4 $104.5 $626.9 $307.3 $6,492.7 $282.7 $129.1 $0.0 $58.4 $58.4 $0.0 $0.0 $196.7 $491.7 $0.0 $0.0 $141.7 $06.1 $85.0 $66.1 $08.3 $08.3 $98.3 $18.4 $61.5 $61.5 $60.4 $60.4 $60.4 $108.1 $648.9 $318.1 $6,852.4 $202.6 $133.6 $0.0 $60.4 $60.4 $0.0 $0.0 $203.6 $508.9 $0.0 $0.0 $0 $0 $0 $146.6 $68.4 $88.0 $68.4 $101.8 $101.8 $101.8 $18.8 $63.6 $63.6 $626 $628 $626 $111.8 9671.6 $320.2 $7,229.3 $302.9 $138.3 $0.0 $0.0 $0.0 $210.7 $526.7 $0.0 $0.0 $151.8 $70.8 $01.1 $70.8 $105.3 $105.3 $105.3 $19.4 $65.8 $64.7 $64.7 $64.7 $115.8 $605.1 $340.7 $7,624.2 $313.5 $143.1 $0.0 $64.7 $64.7 $0.0 $0.0 $218.1 $545.2 $0.0 $0.0 $0 $25 $157.1 $73.3 $04.2 $73.3 $109.0 $109.0 $100.0 $20.1 $68.1 $68.1 2010 $67.0 $67.0 $67.0 $119.9 $7194 352.6 037.8 $324.4 $148.1 $0.0 $67.0 $67.0 $0.0 $0.0 $225.7 $564.2 $0.0 $0.0 $0 $0 $0 $162.6 $75.9 $97.5 $75.9 $1128 $1128 $1121 $20. $705 $70.5 2011 $69.4 $00.4 $69.4 $124.1 $744.6 $365.0 $8,471.1 $335.8 $153.3 $0.0 $60.4 $69.4 $0.0 $0.0 $233.6 $584.0 $0 $0 $0 $168.3 $78.5 $101.0 $78.5 $116.8 $116.8 $116.8 $215 $73.0 $73.0 2012 2013 $743 $743 $743 $1284 © $1329 37708 $7976 $3778 $301.0 $8,924.9 $9,400.0 $347.5 $359.7 $158.7 $164.2 $0.0 $0.0 $71.8 $743 $71.8 $743 $0.0 $0.0 $0.0 $0.0 $241.8 $250.2 $604.4 $625.6 $0.0 $0.0 $0.0 $0.0 $0 $0 $25 $0 $0 $0 $174.1 $180.2 $81.3 $84.1 $104.5 $108.1 $61.3 $841 $120.8 $125.1 $120.9 $125.1 $120.9 $126.1 $22.3 $23.1 $75.6 $78.2 $75.6 $782 2014 $76.9 $76.9 $137.6 $825.5 $404.7 $9,808.9 $372.3 $170.0 $0.0 $76.9 $76.9 $0.0 $0.0 $259.0 $647.5 $0.0 $0.0 $0 $0 $186.5 $87.1 $111.9 $87.1 $129.5 $129.5 $129.5 $23.9 $80.9 DATE - 06/17/63, PAGE 3 of 4 E. CONSUMER ACCOUNTS INHouse Biling/Data Entry Clerk ‘Customer Service Office Clerk Accountant Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES TO BETHEL H. EXPENSES-SALES TO BETHEL |. AVG. COST $/KWH INCLUDING LOSSES. 7. FINANCIAL FORECAST A. AVG. $/KWH WHOLESALE COST B, BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES TOTAL EXPENSES KWH SALES: KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES TOTAL REVENUES REVENUES - EXPENSES: END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8. REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Small Commercial Large Commercial 1994 $0.0 $0.0 $0.0 $0.0 $0.0 $204.8 $204.8 $0.449 $750.0 $204.8 $0.0 $0.0 $204.8 $0.0 $0.0 $0.0 $0.0 $0.0 ($294.8) $455.3 00% ————STAGE 1 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $1,139.6 $0.0 $1,130.6 ($310.8) $1444 $473 0.0% 88 gRR 1996 $0.0 $0.0 $0.0 $0.0 $00 $963.0 $0.0 $963.0 $0.234 $0.210 $144.4 $063.0 $0.0 $963.0 $938.6 $0.0 $2.4 $0.0 $940.9 ($22.1) $122.3 $94.7 0.0% ——STAGE 2. —STAGE 3. 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 $0.0 $37.5 $386.8 $40.2 $416 $43.0 $445 $46.1 $477 $49.4 $51.1 $52.9 $64.7 $56.7 $58.6 $60.7 $62.8 $00 $375 $388 $402 $41.6 $43.0 $445 $46.1 $477 $49.4 $51.1 $52.9 $54.7 $56.7 $58.6 $60.7 $62.8 $0.0 $26.0 $26.9 $26.8 $27.7 $28.7 $20.7 $30.7 $31.8 $32.9 $34.1 $35.3 $36.5 $37.8 $39.1 $40.5 $41.9 $0.0 $0.0 $0.0 $60.0 $06.5 $68.9 $713 $73.8 $76.3 $79.0 $81.8 $84.6 $87.6 $90.7 $93.8 $97.1 $100.5 $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 $0.0 $1,099.3 $1,306.2 $1,408.8 $8,497.7 $9,965.1 =— $9,664.4 $10,052.39 $10,483.2 1.4 $14,446.2 $12,097.4 $12,577.44 $13,114.0 $13,700.7 $14,338.7 $14,953.9 $195.5 $1938 $191.7 $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 $823.8 $1,1124 $1,217.1 $8,497.7 $9,016.7 $0,365.1 $0,661.4 $10,052.3 $10,483.2 $10,979.1 $11,446.2 $12,097.4 $12,577.4 $13,114.0 $13,700.7 $14,3387 $14,953.9 $0196 $0.258 $0.276 $0217 $0218 $0.228 $0229 $0234 $0.23 $0246 $0252 $0.262 $0.268 $0.274 $0282 $0290 $0.298 FINANCIAL FORECAST $0.210 $0.230 $0250 0.230 $0.230 $0,240 $0.240 $0.240 $0.245 $0.250 $0.255 $0.270 $0.280 $0.280 0.290 $0.205 $0.310 $1223 $264.4 $236.5 «= $228.8 «= $525.8 §=— $869.0 $1,036.68 §$1,225.3 $1,265.5 $1,286.5 $1,261.1 $1,214.6 $1,177.11 $1,361.5 $1,247.9 $1,2704 $1,145.0 $1,019.3 $1,306.2 $1,408.8 $8,497.7 $9,016.7 $0,365.1 $9,661.4 $10,0523 $10,483.2 $10,979.1 $11,446.2 $12,007.4 $12,577.4 $13,114.0 $13,700.7 $14,338.7 $14,953.90 $0.0 $0.0 $00 $443.7 $429.3 $561.7 $548.9 $596.8 $515.2 $504.9 $495.7 $676.0 $668.9 $662.9 $658.1 $654.6 $652.3 $0.0 $0.0 $00 $155.3 $150.2 $196.6 $192.1 $187.9 $180.3 $176.7 $173.5 $236.6 $234.1 $232.0 $230.3 $229.1 $228.3 $1,019.35 $1,306.2 $1,4088 $9,096.7 $9,506.2 $10,123.4 $10,4024 $10,776.9 $11,1787 $11,660.7 $12,115.4 $13,010.0 $13,480.4 $14,008.9 $14,589.1 $15,2223 $15,834.6 $961.1 $1,077.4 $1,197.9 $0,0104 $9,518.0 $9,866.1 $10,131.2 $10,322.2 $10,732.3 $11,150.4 $11,576.3 $12,472.2 $13,187.1 $13,379.9 $14,088.6 $14,566.4 $15,553.68 $195.5 $1938 $191.7 $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 $47 $7.1 $9.5 $110 $27.2 $42.5 $58.7 $75.0 $600 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $0.0 $0.0 $0.0 $373.3 $304.3 $301.3 $402.2 $409.8 $417.4 $425.0 $432.6 $440.2 $447.8 $455.3 $462.9 $470.5 $478.1 $1,161.4 $1,278.3 $1,309.2 $9,305.86 $9,030.5 $10,289.9 $10,502.2 $10,807.1 $11,200.7 $11,636.3 $12,068.9 $12,072.4 $13,664.8 $13,695.3 $14,611.6 $15,006.9 $16,001.09 $142.1 ($27.9) ($0.6) $298.9 $343.3 $166.5 $1808 $30.1 $31.0 ($25.4) ($46.4) (837.6) $184.4 = ($113.6) $22.5 ($125.4) $257.3 $2644 $236.5 $2268 $525.8 $868. $1,035.6 = $4,225.3 $4,255.5 $1,286.5 = $1,284.1 -$1,214.6 9 $1,177.1 $1,361.5 $1,247.9 $1,2704 = $1,146.0 $1,402.3 $1420 $1807 $2377 $543.4 $850.4 $1,174 —$1,400.9 $1,200.00 $1,2000 $1,200.0 $1,2000 $1,200.0 $1,2000 $1,2000 $1.2000 $1,2000 $1,2000 0.0% 0.0% 0.0% 4.9% 4.1% 5am 5.2% 5.1% 4.9% 4.1% 4.6% 5A% 5.6% 5.5% 5Aa% 5.3% 5.2% wox $0.250 $0.272 = $0.250 $0.250 $0.26 $0,261 $0.261 $0.266 90.272 $0.277 $0.293 $0.304 $0.304 90.315 $0.321 $0.337 wox = $0.228 . $0.228 $0.228 $0.238 $0.238 $0.238 $0.243 90.248 $0.252 $0.267 $0.27 $0.277 90.287 $0.292 $0.307 ox = $0.209 90.209 $0.209 $0.218 $0.218 $0.218 $0.223 $0.228 $0.232 $0,246 $0.285 $0.25 $0.264 $0.268 $0.282 2014 $65.0 $65.0 $43.3 $104.0 $0.0 $15,624.41 $0.0 $15,624.1 $0.306 $0.310 $1,402.3 $15,624.1 $651.6 $228.0 $16,503.7 $18,802.7 $0.0 $60.0 $485.7 $16,348.4 ($155.3) $4,246.8 $1,200.0 5.4% $0.337 $0,307 $0.262 DATE - 06/17/93, PAGE 4 of 4 | STAGE 1 ——STAGE 2—— 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2008 2006 2007 2008 2009 2010 2011 2012 2013 2014 9. VILLAGE UTILITY COSTS 08M $40.0 $414 $42.8 3000 000 000 000 300 3000 2000 000 2000 100% 2000 00 200 1000 700% 3000 3000 Fuel $0.0 $0.0 $0.0 000 000 3000 20006 30000 000 1000 2000 1000 00K 2000 2000 000 3000 000 1000 2000 Admin & Gen. Expenses $2276 8=6$244.3 $241.4 2000 000 s000 000 3000 000 1000 00 00 000K 3000 000 000 3000 000 0000 9000 Purchases from G&T/Regional Utility $911.6 $1,0324 $1,057.3 3000 30000 3000 000 2000 1000 3000 cd 00 000 3000 000 000 7000 100% y900 900 TOTAL ANNUAL COSTS $1,179.2 $1,308.2 © $1,341.2 3000 000 3000 00 000K 000 0K 000 3000 3000 000K 2000 000 2000 700% 00 00% 10. ESTIMATED AVG. RETAIL COST $/KWH 90449 §©6$0.294 = $0.318 80.319 000, 00K 000 2000 2000 20006 000 00K 2000 000% 000 y000 1000 v0 000 7000 000 IN VILLAGES - WITHOUT PCE Residential 90.488 §=6$0.319 §=— $0.46 $0346 $0250 $0.272 $0.250 $0.250 $0.26 $0.261 $0.261 $0.266 $0.272 90.277 $0.293 $0.304 $0.304 90.315 $0.321 90.337 $0.337 ‘Small Commercial 90.444 = 80.291 $0.315 $0315 $0228 $0.248 $0228 $0.228 90.238 $0.238 $0.238 80.243, $0.248 $0.252 $0.267 $0.277 $0.277 $0.287 $0.202 $0.307 $0.307 Large Commercial $0.408 = $0.267 —-$0.290 $0.290 $0200 = $0.228 © $0.20 $0.200 $0.218 90.218 90.218 $0.223 $0.228 $0.232 $0.246 $0.255 $0.255 $0.264 $0.268 $0.282 $0.282 44, ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITH PCE PCE S/KWH $0.008 © $0.101 $0.105 $0.109 © $0.112 $0.116 §—$0.120 0.125 $0.129 © $0.134 = $0.138 = $0.143 = $0.148 = 80.153 $0.159 = $0.164 © $0.170 $0.176. © 80.182 $0.188 = 80.195 Residential $0.12 $0.11 = $0.12 $012 $012 $012 = $0.13 $0.13 $0.14 $0.14 $0.14 $0.15 $0.15 $0.16 $0.17 $0.17 $0.18 $0.18 $0.19 $0.20 $0.20 ‘Small Commercial $0.12 $0.17 $0.12 $0.12 $0.12 $0.12 $0.13 90.13 $0.13 $0.14 $0.14 $0.15 $0.15 $0.16 $0.16 $0.17 90.18 $0.18 $0.19 $0.19 $0.20 Large Commercial $0.41 $0.27 $0.29 $0.29 $0.21 $0.23 $0.21 $0.21 $0.22 $0.22 $0.22 $0.22 $0.23 $0.23 $0.25 $0.25 $0.25 $0.26 $0.27 $0.28 $0.28 ANNUAL PCE PAYMENTS: $7732 $444.3 $505.7 $813.1 $303.7 $3628 = $301.2 = $208.6 «= $322.1 = $318.5 = $316.1 $3273 «$338.1 «= $348.4 «= $300.2 $416.7 = $409.7 = $435.8 «= $444.2 = $488.1 $474.1 PW Annual PCE Payments: $773.2 $420.2 $472.1 $462.8 $264.7 $207.0 $245.0 $234.7 $244.6 $233.7 $224.1 $224.2 $223.7 $222. $241.1 $248.7 $236.3 $242.8 $239.1 $253.9 $238.3 $4,792.8 $5,041.6 $5278 $5,520.7 $5,750.8 $6,013.7 $6,252.0 ACCUMLATED PW PCE $773.2 $1,2025 $1,6745 $2,137.3 $2,4020 $2,690.0 $2,9440 $3,178.7 $3,423.3 $3,687.0 $3,881.1 $4,105.33 $4,329.0 $4,551. DATE - 06/17/03, PAGE 1 of 4 Interest Rate Deprec, Period Loan Period ‘%Grant Tine %Grant Hydro Loan Period initial Capital 1. LOAD DEMAND VILLAGES ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL E. DEMAND - KWH F. ENERGY - MWH G. MWH AVAILABLE: FROM NYAC HYDRO H, VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO ‘SALES TO BETHEL UTILITIES 1. MWH PURCHASES FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) ‘A. TRANSMISSION LINE Yet Yr2 B. NYAC HYDRO Yr Yr? C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES E. NEW GENERATOR F. COMPUTER SYSTEM G. VILLAGE DISTRIBUTION ‘3. INITIAL CAPITAL TOTAL ‘4, ESTIMATED RATEBASE 5, DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO: NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR COMPUTER SYSTEM INITIAL CAPITAL SMALL BUSINESS ADMIN. LOAN VILLAGE DISTRIBUTION TOTAL 100% 100% see Boo 1994 1032.1 4254.5 0.0 4254.5 °° 00 0.0 $3,472 $0 $2,700 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 General inflation Rate Fuel Inflation Rate REU Diesel Plant 1=NO, O=Yes Discount Rate PCE Rate $/kwh, 1994 ————STAGE 1: 1995 1996 1056.2 1080.3 43620 © 4469.4 436.2 © 4409 4798.2 © 4916.4 ° ° ° ° ° 2500 0.0 32408 00 00 4798.2 1686.5 $3,472 $3,472 $3,715 $3,715 $2,700 $2,700 $2,889 = $2,889 $0 $0 so $0 $0.0 $0.0 $0 $0 $0 $0 $750 $750 $13,526 $13,526 v0 000% $0.0 0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0 $0 $823 $823 $00 $0.0 $0.0 $0.0 $82.3 $82.3 1997 1104.3 4876.9 487.7 3320.7 1679.3 1713.8 $3,472 $3,715 $2,700 $2,889 $13,528 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $0.0 $0.0 $82.3 3.500% 3.500% 3.50% POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE D) ——STAGE 2— STAGE 3, 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 11284 11828 1176.6 © 12006 = 1224.7 = 1240.0 1278.1 «= 1308.2 1338.3 13694 «= 13005 1420.6) 1450.7 14808 = 1519.9 40843 4701.8 © 4809.3 50087 = 5114.2 = $2226 = 564.8 §=— $507.0 $640.2 5791.4 © 5933.6 §©= 6075.8 = 6218.0 = 6360.2 6502.4 4084 4792 480.9 5007 511.4 $223 536.5 550.7 504.9 579.1 503.4 607.6 621.8 636.0 680.2 51528 $271.0 5389.2 55074 56256 5744.9 50013 6057.7 62141 63705 6527.0 66834 6830.8 60062 71526 ° o 6796 6064 7132 7300 7420.0 7540.0 7660.0 7780.0 7900.0 8020.0 8140.0 8260.0 8380.0 ° 0 4127243781 43288 44834 48325.9 46117.8 48909.7 4770.6 © -48493.5-49285.4 500773 50869.2 1661.1 8000 000 5000 000 5000 000 5000 5000 5000 5000 5000 5000 5000 5000 5000 3301.7 3462.6 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 1608.3 1837.4 8000.0 $000.0 $000.0 $000.0 © $000.0 $000.0 $000.0 5000.0 = $000.0 5000.0 $000.0 = 5000.0 = 5000.0 1761.1 1808.4 0.0 00 0.0 00 0.0 0.0 0.0 0.0 0.0 0.0 00 00 00 $3,472 $3,472, $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,472 $3,715 $3,715 $3,715 $3,715 $3,718 = $3,715 $3,715 = $3,715 $3,715 = $3,715 $3,715 = $3,715 $3,715 $3,715 $2,700 $2,700 © $2,700 = $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,889 «= $2,889 $2,889 «= $2,889 $2,889 $2,880 $2,889 ‘$2,889 $2,889 $2,889 $2,889 $2,889 $2,689 $2,889 $50 $104 $233 $322 $416 $517 $624 $738 $859 $988 $1,125 $1,270 $1,424 $1,587 $0 $0 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $0.0 $0.0 $0.0 $0.0 = $1,125 $1,125 $1,125 $1,125 $1,125 $1,125 = $2,875 = $2,575 $2,575 $2,875 $60.0 $60.0 $80.0 $80.0 $80.0 $80.0 $80.0 $0 $0 $0 $0 $0 $0 $0 $525.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $1,050.0 $750 $750 $750 $750 $750 $750 $750 $750 $750 $750 $750 $0 $0 $0 $0 $14,161 $14,740 $20,889 $20,978 $22,197 $22,298 += $22A05 = $22,439 $22,580 $22,889 $24,276 = $23,671 $23,825 «$23,988 $24,184 000K yo00 $4463 $4,352 $5,371 $5,272, $5,179 $5,013 $4,934 © $4,863 «$6,250 $6,195 = $6,149 = $6,112 $8,085 $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 $0.0 $0.0 $0.0 $0.0 $4.7 $30.3 $30.3 $48.8 $58.9 $60.7 $81.4 $03.3 $108.2 $119.9 $134.4 $149.8 = $186.2 $0.0 $566.4 $566.4 $506.4 $566.4 $506.4 $506.4 $566.4 $566.4 $566.4 $566.4 $566.4 $566.4 $0.0 $0.0 $106.2 $106.2 $106.2 $106.2 $106.2 $106.2 $243.1 $243.1 $243.1 $243.1 $243.1 $14.6 $19.5 $19.5 $19.5 $19.5 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $823 $823 $82.3 $823 $82.3 $823 $823 $82.3 $623 $0.0 $0.0 $0.0 $0.0 $0.0 $88 $6.8 see $88 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $57.6 $1153 $115.3 $115.3 $115.3 $115.3 $1153 $115.3 $115.3 $115.3 $115.3 $116.3 $159.3 ‘$822.6 $937.7 $047.2 $957.4 $930.8 $951.3 $963.4 =$1,113.2 $1,044.68 $1,074.5 — $1,090.9 2013 1550.0 064.5 7309.1 82453 0.0 5000.0 0.0 $3,472 $3,715 $2,700 $2,889 $1,043 $6,000 $2,575 so $1,050.0 so $24,344 $0.0 $0.0 $183.4 $566.4 $243.1 $0.0 $0.0 $0.0 $115.3 $1,108.41 2014 1574.8 6750.9 675.1 7426.0 8636.0 $3292.2 0.0 000.0 0.0 $3,472 $3,715 $2,700 $2,889 $2,137 $6,000 $2,875 $0 $1,050.0 $0 $24,538 $6,062 $0.0 $0.0 $201.7 $566.4 $243.1 $0.0 $0.0 $0.0 $1153 $4,1264 DATE - 06/17/03, PAGE 2 of 4 6. OPERATING EXPENSES ($1000) ‘A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators ‘O&M Materials Fuel Insurance 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER: B. TRANSMISSION/SUBSTATIONS. IN-House ‘O&M Labor (O&M Materials Contractor ‘O&M Labor O&M Materials €. DISTRIBUTION IN-House O&M Labor O&M Materials Contractor O&M Labor O&M Materials 0. ADMIN & GEN. EXPENSES Form Corporation/Utility ‘APUC Filing Office Equip. INHouse General Manager. Bd/Exec. Secretary Financial Mgr. ‘Admin. Sec. Staff Engineer Operations Manager Secretary Rent Misc Contractor ‘Attomey/Engr. Consultant 1994 $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 $25.0 $25.0 $15.0 $93.8 $43.8 $56.3 $0.0 $0.0 $0.0 $12.0 $120 $12.0 ————— STAGE 1996 1995 so $0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $739.5 $0.0 $0.0 $40.0 $40.0 $0.0 $0.0 $0.0 $97.0 $45.3 $68.2 $0.0 $0.0 $0.0 $0.0 $124 $124 $124 $0.0 $0.0 $414 $41.4 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $100.4 $46.9 $60.3 $0.0 $0.0 $0.0 $0.0 $12.9 $12.9 $12.9 ——STAGE 2— 1997 1998 1999 2000 $443 sa7s 3443 7s $443 475 $0.0 $0.0 $00 $850 $0.0 $0.0 $00 $8100 $0.0 $0.0 $00 $2800 $0.0 $0.0 $00 $4.5725 $0.0 $0.0 $00 $2300 $0.0 $45.0 $000 $105.0 $458.0 $4855 $514.4 $0.0 $0.0 $0.0 $0.0 © $47.5 $0.0 $0.0 $00 $47.5 $428 $44.3 $45.9 $0.0 $428 $44.3 $45.9 $0.0 $0.0 $0.0 $0.0 $160.0 $0.0 $0.0 $0.0 $400.0 $0.0 $44.3 $45.9 $0.0 $00 $443 $45.9 $0.0 $0 $0 $0 $25 $10 $0 $0 $25 $0 $0 $0 $0 $103.9 $107.6 © $111.3 $48.5 $52.0 $62.4 $66.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $13.3 $14.3 $13.3 $143 $13.3 $143 2001 $402 $880 $5270 $2588 $5,031.0 $2381 $108.7 $0.0 $49.2 $49.2 $0.0 $0.0 $165.6 $414.0 $0.0 $0.0 $0 $0 $0 $119.3 $55.7 $71.6 $55.7 $82.8 $62.8 $82.8 $15.3 $51.7 $51.7 sort $5463 $2676 $5,163 0 $2464 $112.5 300 $50.9 $50.9 $0.0 $0.0 $171.4 $428.5 $0.0 $0.0 $0 $0 $0 $123.5 $57.6 $85.7 $85.7 $85.7 $15.8 $53.6 2003 $527 $827 $527 $042 $5654 $2772 $5,500 0 $2550 $1164 $00 $527 $527 $0.0 $0.0 $177.4 $443.5 $0.0 $0.0 $0 $25 $15 $127.8 $59.6 $76.7 $59.6 $88.7 $88.7 $88.7 $16.4 $55.4 $55.4 2004 $545 $545 $545 $075 $585.2 $288.9 $5,822.14 $263.9 $1205 $0.0 $54.5 $54.5 $0.0 $0.0 $183.6 $459.0 $0.0 $00 $0 so $0 $132.2 $61.7 $79.3 $61.7 $91.8 $918 $01.8 $16.9 $57.4 $57.4 —_— TAGE 3. 2002 2005 $56.4 $56.4 $56.4 $101.0 $605.7 $206.9 $6,149.58 $273.2 $124.7 30.0 $56.4 $56.4 $0.0 $0.0 $190.0 $475.1 $0.0 $0.0 $0 $0 $0 $136.9 $63.9 $82.1 $63.9 $95.0 $95.0 $95.0 $17.5 $50.4 $59.4 2006 $58.4 $58.4 $58.4 $104.5 $626.0 $307.3 96,492.7 $282.7 $120.1 $00 $58.4 $58.4 $0.0 $0.0 $196.7 $491.7 $0.0 $0.0 $6,852.4 $292.6 $133.6 $0.0 $60.4 $60.4 $0.0 $0.0 $203.6 $508.9 $0.0 $0.0 $0 $0 $0 $146.6 $68.4 $88.0 $68.4 $101.8 $101.8 $101.8 $18.8 $63.6 2008 $62.6 $62.6 $62.6 $111.9 $671.6 $320.2 $7,220.3 $302.9 $138.3 $0.0 $62.6 $62.6 $0.0 $0.0 $2107 $526.7 $0.0 $0.0 $0 $0 $0 $151.8 $70.8 $91.1 $70. $105.3 $105.3 $105.3 $19.4 $65.8 $65.8 $64.7 $64.7 $64.7 $1158 $695.1 $340.7 $7,624.2 $313.5 $143.1 $0.0 $64.7 $64.7 $0.0 $0.0 $218.1 $545.2 $0.0 $0.0 so $25 so $157.1 $733 $04.2 $73.3 $109.0 $109.0 $109.0 $20.1 $68.1 $68.1 2010 $67.0 $67.0 $67.0 $119.9 $719.4 $352.6 $8,037.86 $324.4 $148.1 $0.0 $67.0 $67.0 $0.0 $0.0 $225.7 $564.2 $0.0 $0.0 $0 so $0 $162.6 $75.9 $97.5 $75.9 $1128 $112.8 $112.8 $20.8 $70.5 $70.5 2011 $60.4 $69.4 $69.4 $124.1 $744.6 $365.0 $8,471.1 $335.8 $153.3 $0.0 $69.4 $69.4 $0.0 $0.0 $233.6 $584.0 $0.0 $0.0 $0 $0 so $168.3 $78.5 $101.0 $78.5 $116.8 $116.8 $116.8 $21.5 $73.0 $73.0 2012 $71.8 $71.8 $71.8 $128.4 $770.6 $377.8 $8,924.9 $347.5 $158.7 $0.0 $71.8 $71.8 $0.0 $0.0 $241.8 $604.4 $0.0 $0.0 $0 $25 $0 $174.4 $21.3 $104.5 $81.3 $120.9 $120.9 $120.9 $22.3 $75.6 $75.6 2013 $743 $743 $743 $132.9 $797.6 $391.0 $9,400.0 $359.7 $164.2 $0.0 $743 $743 $0.0 $0.0 $250.2 $625.6 $0.0 $0.0 $0 $0 $0 $180.2 $84.1 $108.1 $04.1 $125.1 $125.1 $125.1 $23.4 $78.2 $78.2 2014 $76.9 $76.9 $76.9 $137.6 $825.5 $404.7 $9,898.9 $372.3 $170.0 $0.0 $76.9 $76.9 $0.0 $0.0 $259.0 $647.5 $0.0 $0.0 $0 $0 $0 $186.5 $87.1 $111.9 $87.1 $129.5 $129.5 $129.5 $23.9 $80.9 $80.9 DATE - 06/17/83, PAGE 3 of 4 . CONSUMER ACCOUNTS IN-House Biling/Data Entry Clerk Customer Service: Office Cierk Accountant ‘Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES ‘TO BETHEL H. EXPENSES-SALES TO BETHEL |, AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST A. AVG. SIKWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES: ‘TOTAL EXPENSES KWH SALES (KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8, REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Small Commercial Large Commercial 1994 $0.0 $0.0 $0.0 $0.0 $0.0 $294.8 $0.0 $204.8 $0.449 $750.0 $204.8 $0.0 $0.0 $204.8 $0.0 $0.0 $0.0 $0.0 $0.0 ($294.8) $455.3 0.0% ————8TAGE 1. 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $1,139.6 $0.0 $1,139.6 $0.284 $0.190 $455.3 $1,139.6 $0.0 $0.0 $1,130.6 $828.8 $0.0 $0.0 $0.0 $628.8 ($310.8) $144.4 $47.3 0.0% gia a8 1996 $0.0 $0.0 $0.0 $00 $0.0 $963.0 $0.0 $963.0 0.234 $0.210 $144.4 $963.0 $0.0 $0.0 $963.0 $938.6 $0.0 $24 $0.0 $940.9 ($22.1) $122.3 $04.7 —STAGE 2— 1998 1999 2000 $0.0 $375 $40.2 $0.0 $375 $40.2 $0.0 $25.0 $26.8 $0.0 $0.0 $60.0 $0.0 $0.0 $0.0 $1,099.3 $4,363.8 $1,530.7 $8,228.2 $189.0 $1873 © $185.3 $0.0 $830.3 $1,176.5 $1,345.3 $8,228.2 $0.197 $0.273 $0305 $0.210 FINANCIAL FORECAST $0.210 $0.230 $1223 $90.4 $1,019.3 $8,228.2 $0.0 $580.2 $0.0 $203.1 $1,019.3 $9,011.4 $961.1 9,010.4 $189.0 $0.0 $47 $122 $0.0 $373.3 $1,154.9 $9,305.8 $135.5 $384.4 $257.9 $483.8 $142.0 $535.6 0.0% 0.0% 0.0% 7.2% yoox $0.25 30.283 $0.250 wox = 0.233 0.257 80.228 woxn $0.214 $0237 $0.209 $8,747.2 $0.211 $0.230 $483.8 $8,747.22 $565.7 $198.0 $9,510.9 $26.8 $304.3 $9,030.1 $426.2 $912. 6.9% $0.250 $0.28 $0,209 2002 $43.0 $43.0 $28.7 $68.9 $0.0 $9,005.6 $0.0 $9,095.6 $0.21 $0.240 $912.0 $9,095.6 $698.2 $244.4 $10,038.2 $9,856.1 $0.0 $41.5 $301.3 $10,288.9 $250.7 $1,162.8 $1,140.1 Tah $0.261 90.238 90.218 $445 $445 $29.7 $71.3 $0.0 $9,596.7 $0.0 $9,596.7 90.227 $0.240 $1,162.8 $9,596.7 $685.3 $239.9 $10,521.9 $10,131.2 $0.0 $87.0 $402.2 $10,500.4 $68.6 $4,231.3 $1,452.2 1.2% $0.26 $0.238 $0218 2004 $46.1 $46.1 $30.7 $738 $0.0 $9,987.6 $0.0 $0,987.6 $0.232 $0.240 $1,2313 $9,087.6 $673.3 $235.6 $10,806.5 $10,322.2 $0.0 $726 $409.8 $10,604.7 ($91.8) $4,130.5 $1,200.0 7.0% $0,261 $0.238 $0.218 $477 $47.7 $31.8 $76.3 $0.0 $10,409.7 $0.0 $10,409.7 $0.238 $0.250 $1,130.58 $10,409.7 $651.7 $228.1 $11,280.58 $10,951.3 $0.0 $80.0 $417.4 $11,428.8 $139.3 $1,278.8 $1,200.0 6.7% $0.272 $0.248 $0.28 $40.4 $40.4 $32.9 $79.0 $0.0 $10,905.6 $0.0 $10,005.6 $0.245 $0.255 91,2788 $10,905.6 $6414 $224.5 $11,771.58 $11,373.4 $0.0 $60.0 $425.0 $11,858.4 $06.8 $1,365.6 $1,200.0 6.6% $0.277 $0.252 $0.232 2007 2008 $51.1 $529 $51.1 $52.9 $35.3 $84.6 $0.0 $0.0 $14,372.7 $12,023.8 $0.0 $0.0 $11,372.7 $12,023.86 90.251 $0.260 $0.260 —$0.270 $1,365.66 © $1,435.4 $11,372.7 $12,023.86 $632.2 $812.5 $221.3 $284.4 $12,226.2 $13,120.7 $11,803.3 $12,4722 $0.0 $0.0 $60.0 $60.0 $432.6 $440.2 $12,205.9 $12,972.4 $69.8 = ($148.3) $1435.4 $4,287.14 $1,200.0 $1,200. 64% 711% $0.283 $0.203 $0.257 $0.267 $0.237 $0.246 2009 $54.7 $54.7 $36.5 $87.6 $0.0 $12,503.9 $0.0 $12,503.9 $0.266 $0.275 $1,287.1 $12,503.9 $8054 $281.9 $13,591.22 $12,922.1 $0.0 $60.0 $4478 $13,429.90 ($161.3) $4,125.7 $1,200.0 TAs $0.299 $0.272 $0.250 2010 $56.7 $56.7 $37.8 $90.7 $0.0 $13,040.5 $0.0 $13,040.5 $0.273 $14,119.7 $13,618.9 $0.0 $60.0 $455.3 $14,134.2 $14.5 $1,140.2 $1,200.0 1.2% $0.310 $0,262 $0.259 2011 $58.6 $58.6 $30.1 $03.8 $0.0 $13,627.2 $13,627.2 $0.281 $0.205 $1,140.2 $13,627.2 $794.6 $278.1 $14,699.9 $14,331.58 $0.0 $60.0 $462.9 $14,854.58 $154.5 $4,294.8 $1,200.0 7.4% $0.321 $0.292 $0.268 2012 $00.7 $60.7 $40.5 $97.1 $0.0 $14,265.2 $0.0 $14,265.2 $0.289 $0.300 $1,294.86 $14,268.2 $799.9 $276.9 $15,333.1 $14,813.3 $0.0 $60.0 $470.5 $15,343.86 $106 $1,305.4 $1,200.0 6.9% $0.326 $0.297 $0.273 2013 $62.8 $62.8 $41.9 $100.5 $0.0 $14,880.4 $0.0 $14,880.4 $0.297 $0.305 $1,305.4 $14,880.4 $788.9 $276.1 $15,045.4 $16,302.9 $0.0 $60.0 $478.1 $18,841.0 ($104.4) $4,204.0 $1,200.0 6.8% $0.332 $0.302 $0.278 $65.0 $65.0 $43.3 $104.0 $0.0 $15,550.68 $0.0 $15,6506 $0.305 $0315 $1,201.0 $15,550.6 $788.1 $275.8 $16,614.5 $16,087.55 $0.0 $60.0 $485.7 $16,603.3 (811.2) $4,189.8 $1,200.0 6.1% $0.342 90.312 $0.287 DATE - 06/17/93, PAGE 4 of 4 9, VILLAGE UTILITY CosTS 08M Fuel Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS 10. ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITHOUT PCE Residential ‘Smat Commercial Large Commercial 14, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITH PCE PCE $/KWH Residential ‘Smal Commercial Large Commercial ANNUAL PCE PAYMENTS PW Annual PCE Payments ACCUMLATED PW PCE ————STAGE 1. 1994 1905 1996 $700.9 $40.0 $41.4 $660.8 $0.0 $0.0 $2208 $2276 $243 $0.0 $9116 $1,0324 $1,572.55 $1,178.2 $1,308.2 $0449 §=6$0.204 «= $0.318 $0.488 86 $0.319 = $0.46 90.444 «= 80.201 $0.315 $0.408 = $0.267 $0.290 90.008 §=6$0.101 $0105 $0.12 $0.11 $0.12 $0.12 $0.11 $0.12 $041 $027 $0.29 $773.2 $444.3 = $505.7 $773.2 $420.2 $472.1 $773.2 $1,2025 $1,674.5 1997 $428 $0.0 $241.4 $1,057.3 $1,3412 $0.319 80.46 $0315 $0.200 $0.109 $0.12 $0.12 $0.29 $513.1 $462.8 ——STAGE 2—— 1998 1999 2000 2001 000 y000¢ s000 2000 000 y000¢ s000 2000 y000 y000 v0 v0 000 00% yo0% so00 000 00% r00% 000 yo00 yo00 yo00 yo00 $0.255 = $0.283 $0.250 © $0.250 $0.233 © $0.257 | $0.228 = $0.228 $0.214 = $0.237 | $0.200»= $0,209 90.112 80.116 = 80.120 $0.128 $0.12 $0.12 $0.13 $0.13 $0.12 $0.12 $0.13 90.13 $0.21 $0.24 $0.21 $0.21 $275.3 $2,137.3 $2,412.86 $2,730.7 $2,975.6 $3,2103 $0.129 90.14 $0.13 $0.22 $322.1 $244.6 $3,455.0 $0.134 $0.14 $0.14 $0.22 $318.5 $233.7 $3,688.6 $0138 $0.14 $0.14 $0.22 $316.1 $224.1 $3,912.7 $0.143 $0.15 90.15 $0.23 $342.0 $234.2 $4,147.0 $0.277 $0.252 $0.232 $0.148 $0.15 $0.15 $0.23 $353.2 $233.7 $4,380.7 $363.9 $232.7 $4,613.4 EHREHE 2 $0.293 $0.267 $0.246 $0.17 $0.16 $0.25 $390.2 $241.1 $4,854.5 EHREHE 2 $0.299 90.272 $0.20 $0.164 $0.17 $0.17 $0.25 $400.3 $238.9 $5,093.4 8 3S TT $0.310 90.282 $0,259 $0.170 $0.18 $0.18 $0.26 $426.6 $246.0 $5,330.4 2011 $0.321 $0.292 $0.268 $0.176 $0.18 $0.18 $0.27 $463.1 $2525 $5,501.9 2012 $0.326 $0.297 $0.273 $0.182 $0.19 $0.19 $0.27 $461.9 $248.7 $5,840.6 201 $0.332 $0.302 $0.278 $0.188 $0.20 $0.19 $0.28 $469.9 $244.4 $6,085.0 2014 $0.342 $0.312 $0.287 $0.195 $0.20 $0.29 $4926 $2476 96,3326 DATE - 06/17/93, PAGE 1 of 4 Interest Rate 7.00% General inflation Rate 3.500% Deprec. Period 0 Fuel Inflation Rate 3.500% Loan Pertod 20 REU Diesel Plant 1=NO, O=Yes 1 ‘%Grant Tine 100% 0 Discount Rate 3.50% ‘%Grant Hycro 100% 0 PCE Rate $/kwh, 1994 $0,008 Loan Period initial Capital 18 POWER COST STUDY AKIACHAK, AKIAK, KWETHLUK, TULUKSAK, NYAC , NAPAKIAK, OSCARVILLE, NAPASKIAK - INTERTIED TO BETHEL WITH NYAC HYDRO AND SINGLE POLE, SWGR TRANSMISSION LINE (STAGE 1-3, ALTERNATIVE E) ———-STAGE 1 stage 2 tices 1994 19951998 1907 1908 20002001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 4. LOAD DEMAND VILLAGES ‘A. DEMAND - KWH 1032.1 1056.2 10803 © 1404.3.««11284 «11825 «1178.6 «11766 =—11786 ~=—11766 = 11786 = 11788 = 1178.6 = 11786 ~=—11786 = 11786 = 11786 = 11786 = 11766 = 11788 11788 B. ENERGY - MWH 42545 43620 © 4469.4. «4576.9 © 4884.3 «4701.8 «© 4800.3 48003 «48003 «48903 4800.3 4800.3 © 4809.3 4800.3 4899.3 4800.3 4800.3 © 4800.3 48093 = 4800.3 4809.3. C. TRANSMISSION 00 864362 448.9 457.7 408447024899 = 4800 = 899) 4800 489D 4899 489.) 489) 489.9) 488.9 489.9) 489.9) 489.9 = 480.9 | 489.9 LINE LOSSES @ 10% D. TOTAL ENERGY 4254.5 4708.2 4016.3 © «6034.6 51827 «$2710 «83802 «83802 «= 839807 ©=—« 8380.2 «= $3892 © $380.2 «5380.2 © 5380.2 5380.2 838.2 389.2 389.2 5389.2 = $389.2 8389.2 REQUIREMENTS - MWH BETHEL , DEMAND - KWH ° ° 0 ° ° 0 6708 e708 0706 6796 6706 6706 6796 6796 6796 6796 6796 6796 6796 6796 F. ENERGY - MWH ° ° ) 0 ° 0 49272, at272,—anar2 anata 4927241272, 4127241272, 41272,— 44272-44272 412T2_—4NDTA_—4NDTA_- 41272 G, MWH AVAILABLE ° 0 == 2800 sooo $000 8000 $000 $000 000 5000 5000 000 000 000 5000 000 5000 000 5000 5000 000 FROM NYAC HYDRO H. VILLAGE HYDRO 00 0.0 3249.8 = 3320.8» 33016 34626 oo 00 00 00 00 00 00 00 00 00 00 00 00 00 00 USAGE - MWH G, SURPLUS MWH HYDRO 0.0 00 00 © ©—18792-« 10084 ©=— 18374 += $0000 $0000 $0000» 50000» $0000» $0000 © $000.0 $000.0 $000.0 $000.0 $000.0 $000.0 $000.0 $000.0 $000.0 SALES TO BETHEL UTILITIES H. MWH PURCHASES: 0.0 4708.2 16885 = 1713.8 1761.1 = (1808.4 00 00 00 00 00 00 cr) 00 00 00 00 00 00 00 00 FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A. TRANSMISSION LINE Yrt $3472 $3472 $3,472 $3,472 $3,472 «$3,472. -$3.472_—«$3.A72_—$3.472_——$3.472_—$9.47Z_— $3,472 $3.472_— $3,472. $3,472, $3,472 $3472 $3,472, 83.472 $3,472, $3,472 Yr2 $0 $3,715 $3,715 $3,715 $3,715 $3,718 $3,715 $3.715—$3.715—$3.715— $3,715 $3,715 $3.75 $3,715 $3,715 $3,715 $3,715 $3,715 $3,715 $3,715 $3,715 B. NYAC HYDRO Yrt $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 © $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 $2,700 Yr2 $0 $2,889 © $2,880 «$2,889 $2889 $2880 $2,880 © $2,880 «$2,880 «= «$2,880 «| $2,889 «= $2,889 «$2,880 «$2,880 = $2,889 © $2,889 © $2,889 © $2,889 © $2,880 $2,889 . NEW DISTRIBUTION $0 $0 $0 $0 $50 $104 $283 ($322 $416 $517 $624 $738 $850 $988 $1,125 $1,270 $1,424 «$1,587 $1,760 $1,043 $2,137 D. PURCHASE BETHEL UTILITIES $0 so $0 $0 $0 $0 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 E. NEW GENERATOR soo = $00 80.0 $00 $00 $00 $00 $00 $1,128 $1,125 $1,128 $1,125 $1,125 $1,125 $1,125 $1,128 $1,125 $1,128 $1,125 $1,125 81,125 F. COMPUTER SYSTEM $0 $0 $0 $0 $80.0 $80.0 © $80.0 © $80.0 «= $80.0 $800 ($80.0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3. INITIAL CAPITAL $750 $750 «$780 $750 $750 «$750 $750 $750 $750 $750 $750 $750 $0 $0 $0 $0 $0 TOTAL $6,922 $13,526 $13,5% $13,526 $13,698 $13,600 $24,147 $24,248 $21,355 $24,389 $24,776 $24,171 $24,325 $24,488 «$24,681 $21,844 4, ESTIMATED RATEBASE 2900 yoo 0008 2000 oon 0008 $4321 © $4,222 $4,120 $3,083 (83,884 $3,750 $3,605 «$3,640 «$3,612 $3,585 83,568 5, DEBT SERVICE ($1000) TRANSMISSION LINE $00 $00 $0.0 $00 $00 $00 $00 $00 $0.0 $00 $0.0 $00 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $00 NYAC HYDRO $00 © $0.0 $00 © $00 $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 NEW DISTRIBUTION $00 © $0.0 $00 89 $4.7 $220 $303 $303 $488 «= $58.9 = $60.7 = $81.1 = $03.3 $108.2 $119.9 $134.4 $166.2 © $183.4 «$201.7 PURCHASE BETHEL UTILITIES $00 $00 $00 © $0.0 10 $506.4 «$506.4 «$568.4 «= $566.4 = $586.4 = $586.4 «= $588.4 = $588.4 «= $588.4 = $588.4 $588.4 $5064 $568.4 «$588.4 NEW GENERATOR $0.0 $00 $00 $00 $00 $00 $108.2 $1062 $1062 $1062 $106.2 $106.2 $108.2 $108.2 $108.2 $106.2 $108.2 $108.2 COMPUTER SYSTEM $0 $0 $146 «$146 «$19.5 $195 $19.5 $195 819.8 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 INITIAL CAPITAL $82.3 $623 $823 «$823 «$823 $8823“ $8NB_—$BZI_—«« HAD BAI $BZS_—-$8ZS_— 82S $0.0 $0.0 $0.0 $0.0 $00 ‘SMALL BUSINESS ADMIN. LOAN $0.0 $0.0 $0.0 $0.0. $204.8 $204.8 $204. $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 TOTAL 382.3 $82.3 $404.7 $108.7 $895.0 © $903.4 $4,018.65 $823.2 $833.3 $824.8 = $898.0 © $848.2 $861.1 = $7924 $807.0 $838.7 $856.0 $874.3 DATE - 06/17/83, PAGE 2 of 4 8. OPERATING EXPEN' ‘A. POWER PRODUCTION COSTS 1. NYAC HYDRO Operating Maint. Insurance ($1000) 2. BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators O8M Materials Fuel Insurance 3. VILLAGE OPERATORS 4. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS. INHouse 8M Labor O&M Materials Contractor 8M Labor 8M Materials C. DISTRIBUTION IN-House ‘O&M Labor O&M Materials 1994 $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 ———STAGE 1. 1996 1995 $0 $0 so $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $739.5 $0.0 $0.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 so $0 so $97.0 $45.3 $58.2 $0.0 $0.0 $0.0 $0.0 $124 $12.4 $12.4 $40.0 $40.0 $40.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $431.8 $0.0 $0.0 $41.4 $41.4 $0.0 $0.0 $0.0 $0.0 $0 $0 $0 $100.4 $46.9 $60.3 $0.0 $0.0 $0.0 $0.0 $12.9 $12.9 $12.9 1997 $42.8 $428 $42.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $458.0 $0.0 $0.0 $42.8 $42.8 $0.0 $0.0 $0.0 $0.0 so $10 $0 $103.9 $48.5 $62.4 $0.0 $0.0 $0.0 $0.0 $13.3 $13.3 $13.3 ——STAGE 2— 1998 1999 2000 $44.3 $45.9 $475 $44.3 $45.9 $47.5 $44.3 $45.9 $47.5 $0.0 $0.0 $85.0 $0.0 $0.0 $510.0 $0.0 $0.0 $250.0 $0.0 $0.0 $4,572.5 $0.0 $0.0 $230.0 $45.0 $90.0 $105.0 $4855 $514.4 $0.0 $0.0 $0.0 $47.5 $0.0 $0.0 $47.5 $44.3 $45.9 $0.0 $443 ($45.9 $0.0 $0.0 $0.0 $160.0 $0.0 $0.0 $400.0 $44.3 $45.9 $0.0 $443 $45.9 $0.0 $0 $0 $25 $0 $0 $25 $0 $0 $0 $107.6 86 $111.3 $115.2 $50.2 $520 $538 $64.5 $66.8 $60.1 $0.0 $0.0 $53.8 $0.0 $0.0 $80.0 $0.0 $0.0 $80.0 $0.0 $0.0 $80.0 $13. $14.3 $14.8 $13: $143 $50.0 $138 © $14.3 $50.0 2001 $49.2 $49.2 $49.2 $88.0 $527.9 $258.8 $4,732.6 $238.1 $108.7 $0.0 $49.2 $49.2 $0.0 $0.0 $165.6 $414.0 $50.9 $50.9 $50.9 $01.4 $546.3 $267.8 $4,898.2 $246.4 $112.5 $0.0 $0.0 $0.0 Si714 $428.5 $0.0 $0.0 $0 $0 $0 $123.5 $57.6 $74.1 $57.6 $85.7 $85.7 $85.7 $15.8 $53.6 $83.6 $52.7 $52.7 $52.7 $04.2 $565.4 $277.2 $5,060.6 $255.0 $116.4 $0.0 $52.7 $52.7 $0.0 $0.0 $177.4 $443.5 $0.0 STAGE 3. 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $718 $743 $76.9 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $71.8 $743 $76.9 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $09.4 $71.8 $743 $76.9 $975 $101.0 $1045 = $108.1 $111.9 = $115.8 = $119.9 $124.1 $1284 = $132.9 = $137.6 $585.2 $605.7 $626.9 $648.9 $671.6 $695.1 $719.4 $744.6 $770.6 $797.6 $825.5 $286.9 $296.9 $307.3 $318.1 $329.2 $340.7 $362.6 $365.0 $377.8 $391.0 $404.7 $5,247.1 $5,430.7 $5,620.8 $5,817.5 $6,021.1 $6,231.9 $6,450.0 $6,675.7 $6,009.4 $7,151.2 $7,401.5 $263.9 $273.2 $2827 «= $202.6 «= $302.9 $313.5 = $324.4 «= $335.8 = $347.5 = $380.7 = $372.3 $120.5 $124.7 $129.1 $133.6 $138.3 $143.1 $148.1 $153.3 $158.7 $164.2 $170.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $64.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $71.8 $743 $76.9 $54.5 $56.4 $58.4 $60.4 $62.6 $64.7 $67.0 $69.4 $71.8 $74.3 $76.9 $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 $183.6 $190.0 $196.7 $203.6 $210.7 $218.1 $225.7 $233.6 $241.8 $250.2 $259.0 $459.0 $475.1 $401.7 $508.9 © $526.7 $545.2 $564.2 $584.0 $604.4 = $625.6 = $647.5 $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 $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 $25 $0 $0 $25 $0 $0 $25 $0 $0 $0 $0 $o $0 so $0 $0 $0 $0 $0 $0 $132.2 $136.9 $141.7 $146.6 = $151.8 $187.1 $168.3 © $1741 = $180.2 $186.5 $61.7 $63.9 $66.1 $68.4 $70.8 $73.3 $78.5 $81.3 $84.1 $87.1 $70.3 $62.1 $85.0 $01.4 $04.2 $101.0 © $1045 $108.1 $111.9 $61.7 $63.9 $66.1 $70.8 $73.3 $78.5 $81.3 $84.1 $87.1 $01. $95.0 $08.3 $101.8 = $108.3 $109.0 $116.8 = $120.9 $128.1 $129.5 $91.8 $95.0 $98.3 $101. $105.3 $109.0 $116.8 = $120.9 $125.1 $120.5 $01.8 $95.0 $98.3 $1014 $105.3 $109.0 $116.8 $120.9 $126.1 $120.5 $16.9 $17.5 $18.1 $18.8 $19.4 $20.1 $21.5 $22.3 $23.1 $23.9 $67.4 $59.4 $61.5 $63.6 $65.8 $68.1 $73.0 $75.6 $78.2 $80.9 $57.4 $50.4 $61.5 $63.6 $65.8 $68.1 $73.0 $75.6 $78.2 $80.9 DATE - 06/17/83, PAGE 3 of 4 1H. EXPENSES-SALES TO BETHEL |. AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST ‘A AVG. $IKWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES ‘TOTAL EXPENSES KWH SALES KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES: TOTAL REVENUES REVENUES - EXPENSES: END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8, REGIONAL UTILITY ESTIMATED AVG. RATES WITHOUT PCE Residential ‘Small Commercial Large Commercial $0.0 $0.0 $0.0 $0.0 $0.0 $204.8 $0.0 $204.8 $0.449 $750.0 $2048 $0.0 $0.0 $204.8 $0.0 $0.0 $0.0 $0.0 $0.0 ($204.8) $455.3 00% PEE: PE: ———STAGE 1 —8TAGE2— 1999 2000 1995 $0.0 $0.0 $0.0 $0.0 $0.0 $1,139.6 $0.0 $1,130.6 $0.264 $0.190 $455.3 $1,130.86 $0.0 $0.0 $1,130.6 $628.8 $0.0 $0.0 $0.0 $828.8 (8310.8) 3444 $473 0.0% 1996 $0.0 $0.0 $0.0 $0.0 $0.0 $963.4 $0.0 $963.1 $0.234 $0.210 $1444 $963.1 $0.0 $963.1 $938.6 $0.0 $24 $0.0 $940.9 ($22.1) $122.3 $94.7 0.0% ae 1997 1998 $0.0 $37.5 $00 $37.5 $0.0 $25.0 $0.0 $0.0 $0.0 $0.0 19.3 $1,306.2 $189.0 $187.3 $830.3 $1,118.9 $0.197 $0.260 FINANCIAL FORECAST $0.210 — $0.230 $1223 «$287.9 $1,019.3 $1,3062 $0.0 $0.0 $0.0 $0.0 $1,019.3 $1,306.2 $961.1 $1,077.4 $189.0 $187.3 $47 $7.1 $0.0 $0.0 $1,184.9 $1,271.8 $135.6 ($34.4) $257.8 = $223.5 $1420 © $189.7 0.0% 0.0% wox — $0.250 wox = $0.228 ox = $0.209 ($16.0) $207.6 $237.7 0.0% $0.272 90.248 $0.228 STAGE 3. 2001 2002 2003 2004 2005 2006 2007 2008 2009 $40.2 $416 $43.0 $445 $461 $47.7 $49.4 $52.9 $54.7 $40.2 $41.6 $43.0 $44.5 $461 $47.7 $49.4 $52.9 $54.7 $268 © $27.7 $28.7 $29.7 $307 $31.8 $32.9 $36.3 $36.5 $60.0 $66.5 $68.9 $713 $738 $76.3 $79.0 $84.6 $87.6 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $8,308.08 $8,5294 $8,9114 $9,0324 $9,2884 $9,575.6 $9,918.4 $10,222.5 $10,563.6 $10,859.5 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $0.0 $0.0 $0.0 $0.0 $8,308.09 $8,5204 $8,0114 $9,0324 $9,2864 $9,575.6 $0,9184 $10,2225 $10,563.6 $10,.859.5 $0.212 -$0.218 $0.227 $0.231 $0.237 $0.244 $0.253 $0.261 $0.270 $0.277 $0.230 © $0.235 $0.240 $0.240 $0.240 $0.255 $0.255 90.265 $0.280 $0.285 $207.5 $695.2 $1,191.7 $1,337.1 $1,3039 $1,225.7 $1,377.7 $1,2008 $1,1239 $1,304.7 $8,308.09 $6,5204 $8,9114 $9,0324 $9,2884 $9,575.6 $9,918.4 $10,2225 $10,563.6 $10,859.5 $443.7 = $429.2 $561.7 $548.8 $536.8 $515.2 $504.9 $495.7 $487.5 $4804 $1553 $150.2 $196.6 $192.1 $187.9 $180.3 $176.7 $173.5 $170.6 $168.1 $8,907.09 $9,108.8 $9,660.8 $9,7733 $10,0131 $10,271.1 $10,600.1 $10,801.7 $11,221.7 $11,508.0 $9,010.4 $9,206.3 $9,402.2 $9,4022 $9,4022 $9,980.8 $9,989.8 $10,3816 $10,060.2 $11,165.1 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $11.9 $25.8 $39.7 $54.5 $60.4 $60.0 $60.0 $60.0 $60.0 $60.0 $373.3 $373.3 $373.3 $373.3 $373.3 $373.3 $373.3 $373.3 $373.3 $373.3 $9,305.86 $9,605.4 $9,815.2 $9,830.0 $9,844.9 $10,423.1 $10,423.1 $10,814.9 $11,4025 $11,508.4 $487.7 «= $496.5 $145.4 $56.7 ($166.2) $182.0 ($178.9) ($76.9) $1808 $90.4 $695.2 $4,194.7 $1,337.1 $4,393.89 $4,2257 —$1,377.7$1,200.8 $1,123.08 $1,304.7 — $1,395.1 $515.4 $704.4 $1,090.5 $1,387.99 $1,2000 $1,2000 $1,2000 $1,2000 $1,2000 $1,2000 6.3% 6.0% 6.1% 6.5% 6.3% 6.0% 5.8% 5.6% 54% 5.1% $0.250 © $0.255 $0.261 $0.261 $0.261 $0.277 $0.277 $0,288 $0.304 $0.310 90.228 © $0.233 $0.238 $0.238 $0.238 $0.252 $0.252 $0.262 $0.277 $0.282 90.208 §=— $0.214 $0.218 $0.218 $0.218 $0.232 $0.232 90.241 $0.255 $0.259 2010 $56.7 $56.7 $37.8 $90.7 $0.0 $11,200.5 $0.0 $11,200.65 $0,288 $0.290 $1,305.1 $11,200.5 $4744 $166.0 $11,841.0 $11,361.0 $0.0 $60.0 $373.3 $11,794.3 ($46.7) $1,348.4 $1,200.0 5.5% $0.315 $0.287 $0.264 2011 $58.6 $58.6 $30.1 $03.8 $0.0 $44,578.7 $0.0 $11,579.7 $0.296 $0.295 $1,348.4 $11,579.7 $469.6 $164.4 $12,213.7 $11,866.9 $0.0 $60.0 $373.3 $11,090.2 ($223.5) $4,1249 $1,200.0 54% $0.321 $0.292 $0.268 2012 $60.7 $60.7 $405 $97.4 $0.0 $11,997.5 $0.0 $11,997.5 $0.306 $0.315 $1,124.9 $11,907.5 $466.1 $163.1 $12,626.8 $12,340.4 $0.0 $60.0 $373.3 $12,773.7 $146.9 $4,274.8 $1,200.0 5.2% $0.342 $0.312 $0.287 2013 $62.8 $62.8 $41.9 $100.5 $0.0 $12,379.5 $0.0 $12,379.58 $0.316 $0.325 $1,271.8 $12,378.56 $463.9 $162.4 $13,006.86 $12,732.1 $0.0 $60.0 $373.3 $13,165.4 $150.7 $1,431.5 $1,200.0 5.4% $0.353 $0.322 $0.296 2014 $05.0 $65.0 $43.3 $104.0 $0.0 $12,801.41 $0.0 $12,801.1 $0.327 $0.330 $1,431.5 $12,801.1 $463.4 $162.1 $13,426.3 $12,928.0 $0.0 $60.0 $373.3 $13,361.3 ($64.9) $1,366.6 $1,200.0 5.0% $0.359 $0.327 $0.300 DATE - 06/17/93, PAGE 4 of 4 9, VILLAGE UTILITY COSTS 08M Fuel ‘Admin & Gen. Expenses Purchases from G&T/Regional Utility TOTAL ANNUAL COSTS 10. ESTIMATED AVG. RETAIL COST $/KWH IN VILLAGES - WITHOUT PCE Residential ‘Sma Commercial Large Commercial 11, ESTIMATED AVG. RETAIL COST S/KWH IN VILLAGES - WITH PCE PCE S/KWH Residential ‘Small Commercial Large Commercial ANNUAL PCE PAYMENTS: PW Annual PCE Payments ‘ACCUMLATED PW PCE $0.098 $0.12 $0.12 $0.44 $773.2 $773.2 $773.2 STAGE 1. STAGE 2 STAGE 3. 1995 1996 1997 1998 = 1999» 2000S 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $40.0 $41.4 $428 2000 2000 000 2000 2000 000 2000 2000 2000 2000 000 2000 2000 000 2000 2000 2000 $0.0 $0.0 $0.0 000 2000 7000 3000 2000 000 7000 7000 30001 000% 000 2000 2000 2000 2000 1000 3000 $2276 $2343 $241.1 000 2000 90001 20001 0K »000¢ 0 2000 9000 30001 000 3000 2000 1000 3000 39000 1000 $011.7 $1,0324 — $1,057.3 yo00% 3000 v0 90000 3000 000 000 3000 y00% 7000 3900 2000 2000 000 y000 od 2000 $1,179.2 $1,308.2 —$1,341.2 3000 000 3000 000K 000 000 7000 000K 000 000K 1000 1000 2000 3000 3000 y000c 2000 $0.204 = $0.318 $0.319 000 3000 3000 20001 000 2000 000 0K 000 000 1000 2000 000% 3000 3000 3000 2000 $0319 $0.46 $0346 $0250 $0272 $0250 $0.255 $0.261 $0.261 $0.261 $0.277 $0.277 $0.288 $0.304 $0.310 $0.315 $0.321 $0.342 $0.353 $0,350 $0.291 = $0.315 $0315 $0228 $0.248 $0228 $0233 90.238 $0.238 $0.238 $0.252 $0.252 $0.262 $0.277 $0.282 $0.287 $0.292 $0.312 $0.322 $0.327 $0.267 $0.200 © $0.200 $0.209 $0.228 §=$0.200 80.214 = 80.218 «= 80.218 «= $0.218 §=— $0.232 80.232 $0.241 «= $0,285 = 80.259 $0.284 «= $0268 «= $0.287 $0.296 §=— $0,300 $0.101 $0.105 90.109 «= $0.112, $0.116 = $0.120 $0.125 90.129 $0,134 90.138 90.143 $0.148 90.153 $0,159 $0.164 $0.170 $0.176 $0.182 90.188 $0.195 $0.11 90.12 $0.12 90.12 90.12 $0.13 90.13 90.14 90.14 $0.14 90.15 $0.15 $0.16 $0.17 $0.17 $0.18 $0.18 $0.19 $0.20 $0.20 $0.11 $0.12 $0.12 $0.12 $0.12 $0.13 $0.13 $0.13 $0.14 $0.14 $0.15 $0.15 $0.16 $0.16 $0.17 $0.18 $0.18 $0.19 $0.20 $0.20 $0.27 $0.29 $0.29 $0.21 $0.23 $0.21 $0.21 $0.22 $0.22 $0.22 $0.23 $0.23 $0.24 $0.28 $0.26 $0.26 $0.27 $0.29 $0.30 $0.30 $444.3 $505.7 $513.1. $303.7 $362.8 = $301.2 $303.9 = $308.3 $2043 $311.1 $290.1 $3124 = $338.0» $387.5 «= $386.6 = $335.1 $371.7 «= $3820 $379.1 $429.2 $472.1 $462. $264.7 $2070 $2450 $238.8 $232.6 $201.5 $213.1 $198.0 $190.7 $208.8 $201.4 $194.1 $186.7 $200.1 $198.7 $190.5 $1,2025 $1,674.55 $2,137.3 $2,4020 $2,690.0 $2,944.0 $3,1829 $3,415.5 $3,633.7 $4,046.8 $4,244.68 $4,444.55 $4,653.3 $4,854.86 $5,048.9 $5,2356 $5.4357 $5.6344 $5,824.9 DATE - 06/17/93, PAGE 1 of 3 interest Rate Deprec. Period Loan Period ‘%Grart Tine Grant Hydro Loan Period initial Capital 100% 100% 4, LOAD DEMAND VILLAGES ‘A. DEMAND - KWH B. ENERGY - MWH C. TRANSMISSION LINE LOSSES @ 10% D. TOTAL ENERGY REQUIREMENTS - MWH BETHEL . DEMAND - KWH F. ENERGY - MWH G. MWH AVAILABLE FROM NYAC HYDRO H. VILLAGE HYDRO USAGE - MWH G. SURPLUS MWH HYDRO SALES TO BETHEL UTILITIES H, MWH PURCHASES FROM BETHEL UTILITIES 2. CAPITAL INVESTMENT ($1000) A TRANSMISSION LINE Yri 2 B. NYAC HYDRO Yi 2 C. NEW DISTRIBUTION D. PURCHASE BETHEL UTILITIES . NEW GENERATOR ‘S. INITIAL CAPITAL TOTAL 4, ESTIMATED RATEBASE 5. DEBT SERVICE ($1000) TRANSMISSION LINE NYAC HYDRO NEW DISTRIBUTION PURCHASE BETHEL UTILITIES NEW GENERATOR INITIAL CAPITAL ‘SMALL BUSINESS ADMIN. LOAN TOTAL > BooRse 1994 0.0 00 0.0 0.0 00 00 ss 8s ss ss 3.500% 3.50% $0,098 POWER COST STUDY ESTIMATED BETHEL UTILITY RATES - WITHOUT REU Generali inflation Rate Fuel inflation Rate REU Diesel Plart 1=NO, 0=Yes Oiscourt Rate PCE Rate $/cwh, 1994 ————STAGE 1 1995 1996 1997 0.0 0.0 00 0.0 00 00 00 0.0 00 00 00 0.0 ° 9 ° 0 0 ° ° ° ° 00 00 0.0 00 0.0 0.0 0.0 0.0 0.0 0 $0 $0 0 $0 $0 90 30 $0 $0 $0 $0 30 $0 $0 $0 $0 $0 $0.0 $0.0 $0.0 $0 $0 $0 0 $0 $0 v000 y00% v0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 $0.0 —STAGE 2— STAGE 3. 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 00 0.0 00 00 00 00 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 00 0.0 00 00 0.0 0.0 0.0 00 0.0 0.0 0.0 00 00 0.0 0.0 0.0 00 0.0 0.0 00 00 0.0 00 00 00 0.0 0.0 0.0 0.0 00 0.0 0.0 00 0.0 00 0.0 00 00 00 0.0 00 00 0.0 0.0 0.0 0.0 00 0.0 00 00 00 00 0.0 ° ° 6796 6964 7132 7300 7420.0 7540.0 7660.0 7780.0 7900.0 8020.0 8140.0 8260.0 8380.0 8500 8636.0 0 0 41272 43781 43288 44534 «453259 © «46117.8 + -48909.7 477016 © 48493.5 -49285.4 © 50077.3 50869.2 51661.1 $2453 53292.2 ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° 00 00 0.0 0.0 00 00 00 00 0.0 0.0 00 0.0 0.0 0.0 00 00 00 00 00 0.0 0.0 0.0 00 00 00 00 0.0 0.0 00 0.0 00 0.0 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 0.0 0.0 0.0 0.0 90 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 $0 $0 $0 90 0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 0 $0 90 30 $0 $0 0 30 $0 $0 $0 $0 $0 0 $0 $0 90 $0 $0 $0 $0 $0 $0 $0 $0 $0 ‘$0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $72 $100 $129 $160 $194 $229 ‘$267 $307 $349 $394 $442 $493 $546 ‘$603 $663 $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 = $1,125 $1,125 $1,125 $1,125 $1,125 $1,125 $2,575 $2,575 $2,575 $2,575 $2,575 $2,575 $2,575 $0 $0 $0 $0 $0 $0 30 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 0 $72 $100 $1,254 $1,285 $1,319 $1,354 $1,392 $1,432 $2,924 $2,969 $3,017 $3,068 $3,121 $3,178 $3,238 0K 000 $3,300 $3,200 $4,154 $3,985 $3,819 $3,654 $3,492 $3,332 $4,624 $4,469 $4,317 $4,168 $4,021 $3,878 $3,738 $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 90.0 $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 $6.8 $9.4 $122 $15.4 $18.3 $21.6 $25.2 $28.9 $33.0 $37.2 $417 $46.5 $51.6 $56.9 $62.6 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $106.2 $106.2 $106.2 $106.2 $106.2 $106.2 $243.1 $243.1 $243.1 $243.1 $243.1 $243.1 $243.1 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $0.0 0.0 $0.0 $0.0 90.0 90.0 30.0 $0.0 $0.0 $0.0 $0.0 $2048 $204.8 $204.8 $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 © $211.6 = $214.2 $323.2 $121.3 $124.5 $1278 $1314 $135.4 $276.0 $280.3 $284.8 $289.6 $294.6 $300.0 $305.7 DATE - 06/17/93, PAGE 2 of 3 6. OPERATING EXPENSES ($1000) A. POWER PRODUCTION COSTS 1. NYAC HYDRO. Operating Mairt. Insurance 2. REU DIESEL PLANT ‘Three Plart Operators ‘O&M Materials Fue Insurance 3, BETHEL GENERATION PLANT Chief Plant Operator ‘Six Plant Operators ‘O&M Materials Fuel Insurance 4. VILLAGE OPERATORS 5. COST OF PURCHASED POWER B. TRANSMISSION/SUBSTATIONS IN-House O&M Labor O&M Materials Contractor O&M Labor O&M Materials C. DISTRIBUTION IN-House O&M Labor O&M Materials Contractor ‘O&M Labor O&M Materials D. ADMIN & GEN. EXPENSES Form CorporatioryUtiity APUC Filing Office Equip. IN-House Generel Manager. Bd/Exec. Secretary Financial Mgr. Adrin. Sec. Staff Engineer Operations Manager ‘Secretary Rert Misc Contractor Attomey/Engr. Consutert 1994 sss $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 90.0 $0.0 $0.0 $0.0 $25.0 $25.0 $15.0 $125.0 $43.8 $60.0 $0.0 $0.0 $0.0 $0.0 $120 $12.0 $0.0 ———STAGE 1. 1995 1996 $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 90.0 $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 $0.0 $0.0 $0 $0 $0 $0 $0 $0 $1294 = $133.9 $45.3 $46.9 $62.1 $64.3 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $124 $12.9 $124 $12.9 $0.0 $0.0 1997 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 83s sss $0.0 $0.0 $0.0 $0.0 838 338 55 55 83 338 55 8&5 $10 $138.6 $48.5 966.5 $0.0 $0.0 $0.0 $0.0 $13.3 $13.3 $0.0 ——STAGE 2. STAGE 3. 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $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 $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 90.0 $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 $0.0 $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 $0.0 $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 $0.0 $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 $85.0 $88.0 $911 $94.2 $97.5 $101.0 $104.5 $108.1 $111.9 $115.8 $119.9 $124.1 $128.4 $132.9 $137.6 $0.0 $0.0 $510.0 $527.9 $546.3 $565.4 $585.2 $605.7 $626.9 $648.9 9671.6 $695.1 $719.4 $744.6 $770.6 $797.6 $825.5 $0.0 $0.0 $168.0 $1739 $1800 $186.3 $192.8 $199.5 $206.5 $213.7 $221.2 $229.0 $237.0 $245.3 $253.9 $262.7 $271.9 $0.0 $0.0 $4,5298 $4,973.4 $5,089.5 $5,419.2 $5,708.6 $8,011.7 $6,328.9 $6,661.0 $7,008.6 $7,372.3 $7,753.0 $8,151.2 $8,567.9 $9,003.7 $9,467.9 $0.0 $0.0 $2300 $238.1 $246.4 $255.0 $263.9 $273.2 $262.7 $292.6 $302.9 $313.5 $324.4 $335.8 $347.5 $359.7 $372.3 $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 $0.0 $0.0 $0.0 $0.0 90.0 $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 $0.0 $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 $0.0 $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 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $160.0 $165.6 $1714 $177.4 $183.6 $190.0 $196.7 $203.6 $210.7 $218.1 $225.7 $233.6 $241.8 $250.2 $259.0 $0.0 $0.0 $400.0 $414.0 $426.5 $443.5 $459.0 $475.14 $491.7 $508.9 $526.7 $545.2 $564.2 $584.0 $604.4 $625.6 9647.5 $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 $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 $25 $0 90 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $25 $0 $0 $25 $0 $0 $25 $0 $0 $25 $0 $0 $25 $0 $0 $0 $0 $0 $0 $0 $15 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $143.4 $1485 $1537 $159.0 $1646 $170.4 $176.3 $182.5 $188.9 $195.5 $202.3 $209.4 $216.7 $224.3 $232.2 $240.3 $248.7 $50.2 $52.0 $53.8 $55.7 $57.6 $59.6 $61.7 $63.9 $66.1 $68.4 $70.8 $73.3 $75.9 $78.5 $81.3 $84.1 $87.1 $68.9 $71.3 $73.8 $76.3 $79.0 $81. $84.6 $87.6 $90.7 $93.8 997.1 $100.5 $104.0 $107.7 $111.4 $115.4 $119.4 $0.0 $0.0 $53.8 $55.7 $57.6 $59.6 961.7 $63.9 $66.1 $68.4 $708 $73.3 $75.9 $78.5 $81.3 $84.1 $87.1 $0.0 $0.0 $80.0 $62.8 $85.7 $88.7 $91.8 $95.0 $98.3 $101.8 $105.3 $109.0 $1128 $116.8 $120.9 $125.1 $129.5 $0.0 $0.0 $80.0 $82.8 $85.7 $88.7 $91.8 $95.0 $98.3 $101.8 $105.3 $109.0 $112.8 $116.8 $120.9 $125.1 $129.5 $0.0 $0.0 $80.0 $62.8 $85.7 $88.7 $91.8 $95.0 $98.3 $101.8 $105.3 $109.0 $112.8 $116.8 $120.9 $125.1 $129.5 $13.8 $14.3 $148 $15.3 $158 $16.4 $16.9 $175 $18.1 $18.8 $19.4 $20.1 $20.8 $21.5 $22.3 $23.1 $23.9 $13.8 $14.3 $50.0 $51.7 $53.6 $55.4 957.4 $59.4 $61.5 $63.6 $65.8 $68.1 $70.5 $73.0 $75.6 $78.2 $80.9 $0.0 $0.0 $50.0 $51.7 $53.6 $55.4 $57.4 $59.4 $61.5 $63.6 $65.8 $68.1 $70.5 $73.0 $75.6 $78.2 $80.9 DATE - 06/17/93, PAGE 3 of 3 , CONSUMER ACCOUNTS IN-House Biling/Data Ertry Cierk ‘Customer Service Office Clerk Accountant Contractor F. TOTAL EXPENSES ($1000) G. ENERGY SALE REVENUES TO BETHEL H. EXPENSES-SALES TO BETHEL |, AVG. COST $/KWH INCLUDING LOSSES 7. FINANCIAL FORECAST A. AVG. $/KWH WHOLESALE COST B. BEGINNING YEAR BALANCE ($1000) OPERATING EXPENSES RETURN ON RATEBASE @ 13% TAXES TOTAL EXPENSES KWH SALES KWH SALES TO BETHEL UTILITIES INTEREST AT 5% WASTE HEAT SALES TOTAL REVENUES REVENUES - EXPENSES END OF YEAR BALANCE ($1000) MINIMUM RETAINED EARNINGS REQUIREMENT ($1000) NET RETURN ON INVESTMENT 8. ESTIMATED AVG. RETAIL COST $/KWH IN BETHEL - WITHOUT PCE Residertial ‘Smal Commerdal Large Commercial 1994 $0.0 $0.0 $0.0 $0.0 $0.0 $317.8 30.0 $317.8 eee HEHE 2 STAGE 1. STAGE 2. STAGE 3 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $0.0 $0.0 $0.0 $37.5 $40.2 $41.6 $43.0 $445 $46.1 $47.7 $49.4 $51.1 $56.7 $58.6 $60.7 962.8 $65.0 $0.0 $0.0 $0.0 $37.5 $40.2 $41.6 $43.0 $445 $46.1 477 $49.4 $51.1 $56.7 $58.6 $60.7 $628 $65.0 $0.0 $0.0 $0.0 $25.0 $26.6 $27.7 $26.7 $297 $30.7 $318 $329 $34.1 $37.8 $39.1 $405 19 $43.3 $0.0 $0.0 90.0 $0.0 $60.0 $66.5 $68.9 $713 $73.8 $763 $79.0 $81.8 $90.7 $93.8 $97.1 $100.5, $104.0 $0.0 $0.0 9.0 $0.0 $60.0 $64.3 $66.5 $689 $713 $738 $763 $79.0 $87.6 $90.7 $938 $97.4 $100.5 $261.6 $270.8 $290.2 = $390.0 $7,261.3 $7,750.5 $8,065.3 $8,326.0 $8,674.6 $9,080.5 $9,529.2 $9,946.6 $10,545.3 $11,0525 $11,530.7 $12,056.0 $12,629.2 $13,1764 $13,781.8 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 900 s00 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $00 $0.0 $00 $261.6 $270.8 $290.2 $390.0 $403.7 $7,261.3 $7,750.5 $8,065.3 $8,3260 $8674.6 $9,080.5 $9,529.2 $9,946.6 $10,545.3 $11,0525 $11,530.7 $12,056.0 $12.6292 $13,1764 $13,781.68 000 000K 3000 000 000K $0209 = $0.211 90.222 $0.223 90.226 90.234 $0.242 90.248 $0.259 $0.267 90.274 $0,282 $0.291 $0.299 $0 308 FINANCIAL FORECAST x00 3000 000K wooo w00 $0.220 — $0.220 $0.230 90.235 90.235 $0.245 $0.250 $0.270 $0.275 $0.280 $0.290 $0.300 $0.300 90.310 2000 000 y000 yoo yoo $1,200.0 $1,316.68 $1,481.0 $1,475.8 $1,500.9 $1,311.68 —$1,259.1 $1,186.7 $1,276.22 —$1,278.5 = $1,229.0 $1,300.29 1,457.1 $1,297.9 000K 0K y00K 3000 000 $7,261.3 $7,7505 $8,326.0 $8,674.6 $9,080.5 $9,529.2 $9,946.6 $10,545.3 $11,0525 $11,530.7 $12,056.0 $12,6292 $13,176.4 $13,781.68 000% 00K s000 y00K 00K $429.0 = $416.0 $618.1 4964 $475.0 $453.9 $433.1 $001.1 $581.0 $561.2 $541.8 $522.8 $504.2 $486.0 000 000 3000 y00K 3000 $150.2 $145.6 $181.3 $173.7 $166.3 $158.9 $151.6 $210.4 $203.3 $196.4 $189.6 $183.0 $176.5 $170.1 00K 000K 3000 y000 0K $7,840.4 $8,312.1 $9,025.4 $9,344.68 $9,721.7 $10,142.0 $10,531.3 $11,356.9 $11,636.86 $12,288.4 $12,787.4 $13,335.0 $13,857.0 $14,437.9 00K 30006 1000 00 y000 $7,627.0 $8,090.8 $8,604.0 $8,947.3 $9,103.7 $9,654.0 $10,017.53 $10,998.3 $11,384.9 $11,778.2 $12,391.7 $13,018.6 $13,218.2 $13,677.3 000 000 000K 000 10001 $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 y000 000K 00K 100K 9000 $0.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 $60.0 yoo 3000 ad 0K 1000 $330.2 $350.3 $356.3 $362.6 $368.9 $375.3 $381.6 $387.9 $394.3 $400.6 $407.0 $413.3 $419.6 $426.3 000 3000 yom 0K 000K $7,957.22 $8,501.0 $9,020.2 $9,369.9 $9,532.6 $10,089.3 $10,458.9 $11,446.3 $11,639.2 $12.238.8 $12,858.7 $13,491.9 $13,697.86 $14,363.6 yoo 000 00K 000 oo site $189.0 ($5.2) $25.1 ($189.1) ($527) (872.4) $89.4 $24 ($49.6) $71.2 $156.9 ($159.2) ($74.3) 00K 000K 000 000 $1,200 $1,316.8 $1,505.7 $1,475.8 —$1,500.9 $1,311.8 $1,259.11 $1,186.7 $1,276.2 $1,2785 —$1,229.0 $1,300.2 $1,457.1 $1,287.98 $1,223.7 woo 0K 000 0K 0K $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.0 $1,200.00 —$1,200.0 $1,200.0 $1,2000 —$1,200.0 —$1,200.0 OK 000K 000K 0K OK 12.7% 12.2% 11.9% 11.3% 10.7% 10.2% 9.1% 9.2% 9.7% 9.3% 8.9% 8.5% 8.1% 78% TAN ———STAGE 1. ——STAGE 2—— STAGE 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 00K y000 v0 000K 000K $0.22 $0.22 $0.23 $0.23 $0.24 $0.24 $0.25 $0.25 $0.27 $0.28 $0.28 $0.29 $0.30 90.30 $0.31 $0,000 $0.000 $0.000 $0.000 $0,000 $0.239» $0.239 $0.250 $0.250 $0.255 90.255 90.266 90.272 $0293 $0.299 $0.304 90.315 90.326 $0.326 $0.337 $0.000 $0.000 $0.000 $0.00 $0.000 $0218 §= 80.218 §=— $0.28 $0.228 90.233 $0.233 $0.243 90.248 90.267 $0.272 90.277 90.287 90.297 $0.297 90.307 $0.000 $0.000 $0.000 $0.000 $0.000 $0.200 80.200 $0.209 $0.209 90.214 90.214 $0.23 90.228 90.246 $0.250 90.255 90.264 $0.273 90.273 90.262 APPENDIX B INFORMATION ON SWGR TRANSMISSION SYSTEMS B.1 SINGLE WIRE GROUND RETURN MINIMUM COST TRANSMISSION SYSTEM Single Wire Ground Return Transmission of Electricity The first electric systems were designed to meet urban needs, and the electric utilities which gradually evolved to manage and expand these systems largely focused their efforts in meeting the ever increasing and sophisticated demands of the burgeoning urban population. Lacking the economic and political incentives, these utilities simply adopted conventional urban designs when forced to start expanding into rural areas. This contributed to high costs and the returns generated from the sale of electricity is generally insufficient to cover the costs incurred. Rather than reassess the conditions and needs in rural areas and then develop technical and institutional designs which address those needs, the option adopted is to subsidize the effort from the state or federal treasury. Single Wire Ground Return (SWGR) transmission is a concept which proposes to deal with these realities. SWGR can best be described as single phase - single wire transmission of electricity that uses the earth as the return conductor. The SWGR transmission concept suggested here is point-to-point with a carefully established grounding system at each point. The substation established at each grounding point would connect to the village multi-grounded neutral distribution through a step-down transformer. The SWGR system proposed herein would in no way create an operating system with a lesser safety than the "conventional" system now in use throughout Alaska. A SWGR transmission line demonstration project was constructed in 1981 to intertie the village of Napakiak with Bethel. The 8.5 miles of line interconnecting the two communities extends over tundra covered terrain which is underlain with permafrost and dotted by numerous small lakes. This demonstration project has operated reliably for 12 years and has proven that a SWGER transmission system is both economically and technically feasible. The SWGR transmission concept described in this proposal has evolved from a recognition of certain basic facts-of-life concerning electric energy in remote western and interior Alaska, which facts are: 1. Small electric loads and the geographic distribution of villages presently limit electric energy supply to small, inefficient fossil-fueled generating plants. 2. Conventional three-phase electric transmission/distribution systems to intertie the outlying communities to more efficient generating plants are mostly impractical because high initial costs penalize the transmitted energy rates. Gs A transmission system using a Single Wire Ground Return (SWGR) line promises good electrical performance and a substantially lower initial capital cost and therefore a lower transmitted energy cost than conventional transmission. A B-1 breakdown of per mile costs for SWGR construction versus conventional three phase construction can be found in this Appendix. 4. The incentive to develop new, alternative energy sources (such as appropriate scale hydroelectric power in the area) is dependent on an economically viable electric transmission scheme that can feasibly deliver such energy to the villages. 5; Lack of road systems, permafrost, and limited accommodations for construction crews throughout most of the region being studied has established certain limitations as to construction techniques which may be utilized. While the use of a single energized wire and earth return circuit is unconventional in the sense that applications are not common, it is an accepted system of proven use in several areas of the world. (See attached information on New Zealand.) Three phase equipment can also be successfully operated from this system by using phase converters. The type of SWGR design recommended for interconnecting Bethel to the outlying villages and the Nyac hydro would consist of a single wood or metal pole with a post insulator mounted vertically to the top of the pole. The pole would be attached to driven H-pile or pipe pile foundation. Span lengths would be approximately 1200 feet. The SWGR transmission line would be designed such that it could be readily converted to a standard three phase line at some time in the future should load or development of new generation sources warrant. Conversion to three phase would be accomplished by insertion of a pole at mid-span, resulting in 600 feet spans, and installation of additional conductors and horizontal post insulators. Estimated conversion cost is $60,000 per mile in 1993 dollars. Although SWGR construction has not received REA's endorsement, it is currently being investigated by the National Rural Electric Cooperative Association (NRECA) as a viable means of providing economical rural electrification in developing countries. (See attached letter from NRECA.) Life expectancy of a SWGR line is expected to be comparable to conventional constructed lines. This assumption is based primarily on two facts: 1) an SWGR line would be constructed with conventional transmission line hardware, and 2) the Bethel to Napakiak SWGR line, which has been in operation for 12 years, has not experienced any greater deterioration than a conventionally constructed line. Construction of SWGR systems within the State should not, however, be allowed to proceed in an uncontrolled manner. The fifth edition of the National Electric Safety Code (NESC) allowed the use of the earth as a return conductor for a power circuit in rural area, however the most recent code does not. In order to construct the experimental SWGR transmission line between Bethel and Napakiak, it was necessary to obtain a waiver to the NESC from the State of Alaska, Department of Labor. It is anticipated that a similar waiver would be required to construct and operate any new SWGR line within the State. Because of the possible B-2 problems associated with safety, and ground return currents such as corrosion or communication interference, each project should require licensing by the State after careful, but timely review. The SWGR system proposed in this report is similar in design to the existing system presently interconnecting Bethel and Napakiak and would not create an operating system with a lesser safety than the "conventional" systems now in use throughout Alaska. However, to prevent personal injury it is imperative that the State require all earthing systems meet or exceed the standards set forth in IEEE guide for substation grounding. B.2 SINGLE PHASE TO THREE PHASE CONVERSION IN SWGR POWER TRANSMISSION Single Wire Ground Return transmission scheme is an attempt to develop an economical method of electrically interconnecting small communities with low energy demands to a lower cost generation source(s), such as the Nyac Hydroelectric project or Bethel Utilities, where conventional 3-phase lines would be too expensive to construct. However, small three phase distribution systems such as found in Bethel cannot supply or absorb large blocks of single phase power without excessive overheating occurring in the generator(s) supplying the distribution system. This overheating is caused by unbalanced electrical currents flowing within the winding of the three phase generators. To eliminate this problem it is necessary to install either rotary or static single phase to three phase conversion equipment. Interconnection between three phase and single phase systems have been made for many years via rotating machinery. The size of these converters ranging from a few kW up to 45 MVA. Static frequency/phase conversion equipment is also available but is presently not an “off the shelf™ item for small 1-2 MW applications. A converter set in the 1 megawatt range as required for this intertie project utilizing a combination of rotating equipment and static conversion equipment is estimated to cost approximately $300/kW installed. Conversion losses is estimated at about 4 percent. In the various alternative's that intertie the Nyac Hydroelectric plant to Bethel and the villages via a SWGR line, the phase converter equipment would be designed to transmit power in two directions. That is, the converter would convert single phase power to three phase power when excess energy from the Nyac hydro plant is being sold to Bethel. Conversely the converter would convert 3 phase power to single phase power when electrical power is purchased from Bethel Utilities by the villages. It is anticipated that existing village distribution systems can readily be re-phased such that the majority of the village load can be supplied from single phase power. This was accomplished at Napakiak in 1981, as part of the SWGR demonstration project, when the village distribution system was easily reconfigured to operate on either single phase or three phase power. The single phase configuration is used when the village is supplied from the SWGR transmission line. The three phase configuration is used when the village is supplied power from B-3 its three phase generators during periods the transmission line is out of service. This was accomplished by installation of a transfer switch at the power plant which allows the power plant operator to either supply the village from the SWGR transmission line or the three phase village generators. Where 3-phase is required it can be provided by small rotary phase converter equipment, such as installed at the Napakiak school in 1981 as part of the SWGR demonstration project. A 52.5 kVA rotary phase converter was installed at the Napakiak school to demonstrate the feasibility of utilizing such equipment. This unit operated unattended and reliably for a number of years on a continuous basis converting single phase power to three phase power to supply the needs of the school. It was only recently that the rotary phase converter was "shut down." This occurred when the school district for economic reasons, decided to generate its own electrical power and ceased purchasing power from the Napakiak Corporation. If a SWGR transmission line is constructed to the Nyac hydro, it would be prudent to generate single phase power from the hydro generator and eliminate the cost of installing additional single phase to three phase conversion equipment at the hydro site. However, to retain maximum future flexibility it is recommended that three phase generator(s) capable of being rewired in the field for single phase operation, be installed at the hydro site. B.3 PILE FOUNDATIONS Steel H-pile or pipe pile foundations will be necessary to prevent frost-jacking of structures embedded in the frost susceptible soils found in the Bethel region. Pile foundations were selected primarily because similar H-pile foundations have proven to be relatively successful in resisting frost jacking forces in the Copper River Basin region of Alaska. A comparison of soil conditions and meteorological data between the Bethel region and the Copper River Basin region has revealed a notable similarity between the two regions. These similarities are as follows: 1) highly frost susceptible fine grain sands and silts are found through both regions; 2) depth of the seasonal active layer is approximately 5 feet in each region; 3) the freezing index and degree days below zero are similar which should account for the similarity in the depth of the seasonal active layer; 4) both regions lie within the discontinuous permafrost zone; and 5) the permafrost found in both regions is relatively warm permafrost in the range of 30-32 degrees fahrenheit. Because of these similarities it is anticipated that H-pile foundations which have proven relatively successful in the Copper River Basin should prove equally successful in the Bethel region. . Pile foundations will consist of a 25 foot section of either appropriately sized pile driven 21 feet into the earth. Experience in the Copper River Basin has shown H-piling can be driven readily into the warm permafrost encountered in the region. Poles will not be embedded into the earth but will instead be bolted to the 4 feet of H-pile left protruding above the ground-line. Installation of the steel pile in this manner will leave approximately 16 feet of pile embedded in soils below the active layer. In general a pile must be embedded at least twice the thickness of the active layer into permafrost or unfrozen soils in order to prevent frost jacking. B-4 HFRAME POLES INSULATORS HPILES HARDWARE CONDUCTOR MISC. TOTAL MOB&DEMOB ENGR/SURVEY SUBTOTAL CONTENGENCIES AT 15% TOTAL $/MI SPSW POLES INSULATORS HPILES HARDWARE CONDUCTOR MISC TOTAL MOB&DEMOB ENGR/SURVEY SUBTOTAL CONTENGENCIES AT 15% TOTAL $/MI TRANSMISSION LINE CONSTRUCTION COSTS SINGLE POLE , 3 WIRE, 3 PHASE AVG/SPAN = 700 STRU/MI = 7.5 # COND. QTY/STRU MATLS LABOR M&L 1 $900 $1,600 $2,500 3 $250 $100 $350 1 $600 $500 $1,100 fl $200 $100 $300 2100 $0.25 1.00 $1.25 1 $150 $100 $250 SINGLE POLE SWGR AVG/SPAN = 1300 STRU/MI = 4.1 #COND QTY/STRU MATLS LABOR M&L 1 $900 $1,600 $2,500 1 $250 $100 $350 1 $600 $500 $1,100 1 $100 $100 $200 1300 0.25 $1.00 $1.25 1 $150 $100 $250 3 TOTAUSTRU TOT MATL/MI TOT LABOR/MI TOT/MILE $2,500 $6,789 $12,069 $18,858 $1,050 $5,657 $2,263 $7,920 $1,100 $4,526 $3,771 $8,297 $300 $1,509 $754 $2,263 $2,625 $3,960 $15,840 $19,800 $250 $1,131 $754 $1,885 $7,575 $23,572 $35,451 $59,023 $35,000 $1,500 $95,523 $14,328 $109,851 1 TOTAUSTRU TOT MATUMI TOT LABOR/MI TOT/MILE $2,500 $3,655 $6,498 $10,154 $350 $1,015 $406 $1,422 $1,100 $2,437 $2,031 $4,468 $200 $406 $406 $812 $1,625 $1,320 $5,280 $6,600 $250 $609 $406 $1,015 $5,775 $9,443 $15,028 $24,471 $25,000 $1,500 $50,971 $7,646 $58,616 Nw ae eu aru Mis | so Se Vw twwees= National Rural Electric _ Cooperative Association 1800 Massachusetts Avenue, N.W. ‘Washington, D.C. 20036-1883 Telephone: (202) 857-9500 March 5, 1993 Robert W. Retherford 6728 Dimond Boulevard Anchorage, Alaska 99502 Dear Robert: Thank you for your letter of February 2 in response to the message I left on your phone. 1 appreciate your taking the time to respond. J have not yet heard from Frank Bettine but hope that a copy of the report is still forthcoming if the Calista Corporation agrees to its release. : I will keep you informed of progress with my effort which may well take a part-time effort for the remainder of this year. In the meantime, I have gathered a number of articles on the subject of SWER, mostly from Australia and New Zealand where the concept was first implemented. For your information, J am enclosing a copy of several pages from a recent Swiss publication on village electrification. It quotes part of an article I received separated from New Zealand but includes a fuller set of illustrations. Of course, any comments you may have on this article would be appreciated. In my letter of October of last year, I had also inquired whether you might have access to several black and white photographs of the Napakiak line, including one which might show a close-up of an A-frame structure and another showing several spans of the line. If you do not have such photographs, could you suggest who might? Thanks you for your continued help. Sincerely, (Mi Rrra. Allen R. Inversin Senior Project Analyst ma ‘Building ona Golden Foundation ® MAR 18°93 89:38 9872434639 PAGE. @1 KWK ; MHPG Series ; Harnessing Water Power on a Small Scale Volume 5 Village Electrification R. Widmer / A. Arter 7 az Ac, RW - MAR 1@ °93 @9:38 Ay VI e4u4HouS PART 6: The first part originates from an article of Mr. Bryan Leyland, Leyland Consultants Lid, 100 Anzac Ave, Auckland, New Zealand. The second is a contribution of Mr. Hanspeter Prinz, Wadenswil, Switzerland. 1. SWER, a Low Cost Ruaat Dis- TRIBUTION System Usina SINGLE Wire Earth Return. Whatis called a standard distribution system, is often based on designs for urban areas or national grids. They exceed by far the requirements of a stand alonc village electrification scheme. Below the description of an adequate low cost system, developed by the DISTRIBUTION SYSTEMS maw ay ve VtHe WU eYYe 6 ee New Zealand engineer Lloyd Mandeno in the 1920s and still today widely uscd in New Zealand and Australian rural areas. . Itis basically a single phase supply (as itis the norm in rural USA) with only one wire and using the carth as the retum conductor. This system is commonly known as the Single Wire Earth Retum, SWER, system. The essential elements of the systcm arc shownin Fig 1. All the voltages are shown for a 22kV main distribution (and in brackets an 11kV). 16kKVA 22'000 (11'000)/240/480V 22 (14)kV supply ‘| I 100kVA 22/25.4 (11/12.7)KV insulating trafo 25'400 (1 3 phase spur line SOKVA 22'000 (11'000)/240/415V 12.7 (6.35)kV SWER line 12°700 (€350)/240V 25.4 (12.7)kY SWER line 10kKVA 2°700)/240/480V LV distribution trato Fig] Comparison between several distribution concepts a) single phase (16kVA) b) three phase (SOkVA) 3 phase system SWER system ¢) directly tapping the LIV line(SkVA) d) with single phase insulating trafo (1O0kVA) -> SWER line (1OkVA) 9872434639 PAGE . 283 66 _Village Electrification 1.1. High Voltage Lines 1.1.1. Conductors Conductors for the three phase lines would be either all aluminium oraluminium alloy suchas “Silmalec”. For the three phase spur lines cither 3/12" galvanized steel wire or 10° or 16 mm? copper equivalent wire would be used, For main lines (supplying several villages) 16, 35 or 50 mm? would be used . Conductors for the single wire spurs would be cither “Silmalec” or 3/12" galvanized stce) wire. 1.1.2. Poles Poles can be cither of stcel or wood. For SWER lines local timber poles should be used if available. Alter- natively where transport is difficult and porters arc used, poles made from conical sections, nested for transport and fitted together on site, would be very suitable. Fig2 _— Nestable pole structure MAR 18°93 @9:48 Polc spacing should be as wide as possible, hence wherever possible they should be placed on rises (hills, ridges etc.); for SWER lines, spacing of 150 to 200m is possibic. 1.1.3. SWER Spur Lines Shon or lightly loaded SWER spurs would be tapped directly off the three phase line and operate at 12.7(6.35)kV to earth (see Fig Ic), Long SWER spurs with loadings in excess ef 50- ° 7TOkVA could be supplicd via a 22/25.4 (11/12.7)kV insulating transformer (see Fig Jd). This has two advantages: it increases the voltage, consequently reducing the current and the losses, and it limits the extent of the earth retum current to the spur line and insulating transformer only. Fig3 Arrangement of configuration d) (see Fig 1) It shows the limited extent of the earth return current between the insulation and the LV distribution transformer. In case of a short to earth, earth currents flow of course close lo consumers. SWER spurs would nat be designed for a latcr upgrading to three phasc, the shorter spans and stronger poles needed would double the cast of the line. Experience has shown, how- ever, that by the time a three phase supply isneeded, the low cost SWER linc has more than paid for itself, ” 9872434639 PAGE . 286 1.2. 1.2. Tran pract phas lincs for 1 (con: volta ing. ' cithe ary ‘ 480* will 5.4 ay seul ewuHUuUD 1.2. Transformers 1.2.3. Type Transformers would follow US rather than European practice. They could be rated at 16kVA for single phase 22 (11)kV (concepta & bin Fig 1). ForSWER lines it would be convenicnt to usc ratings of SkVA for 12.7 (6.35)kV and 10 kVA for 25.4 (12.7)kV (concept c & din Fig 7) with onc standard dual voltage transformer with only onc high tension bush- ing. The high voltage winding can be connected to cither 25.4 (12.7) or 12.7 (6.35)kV. The dual second- ary winding can be connected in series for 240 & 480V at 25.4 (12.7)kV. At 12.7 (6.35)kV, however, only the 480V winding is used (see Fig 4a), which will produce 240V. _ 5.4 (12.7)kV 12.7 (6.35kV a) 25.4(12.7)kV &12.7(6.35)kV SWER 240/480V 20 Distribution Cisteibution 22 (14)kV 22 (114)kV b) 22 (11 )kV single phase 240MB0V 240(415)V Distribution Distribution Fig4 Dual Voliage Transformers. 1.2.2. Construction and Mounting The SWER transformer would be totally scaled. A surge diverter (arrestor) would be secured to the tank. There would be one HV bushing and three LV bushings; no other tappings! The noload voltage ratio would be 25°400:255/510V. For installations in remote areas, accessible only with porters (as for instance in the Himalayas) the weight must be kept below S0kg. ‘This might require a rating as low as LOkVA. Mounting arrangement would follow US practice. The transformers would be secured to a clamp fitted to the pole or simply to a bolt through the pole. MAR 18°93 99:39 _Part6 | _ 67. a) single phase f= with LV distributior}® and earthing Figs @) Pole mounting of a single phase trans- former. b) Symmetrical arrangement of three identical transformers around a pole for a three phase system . The 22 (11)kY single phasc transformer would be similar except that it would have two HV bushings. It would be possible to use three such transformers to give a three phase supply. The secondary winding would be paralleled in this case (refer to Fig 4a). Three transformers can be mounted on a single pole by spacing them equally around it. 1.3. Protection Every spur linc is protected by drop-out fuses. Each transformer would also be protected by fuse and by a tank-mounted surge diverter. Auto recloscrs and sectionalizers should be used in areas where light- ning is a problem. With the SWER lincs, only a single phase unit is needed, so the cost is much reduced. 1.4. Earth Return Currents and Earth- ing Injecting currents into the earth is a complex phe- nomena (see also part: Earthing). In the case of a uniformly conducting soil, the current disperses radi- ally, generating circular equipotential lines. The volt- age drops quickly, forming a “potential funnel", and a few meters from the earthing point, the voltage is not elevated anymore. The steep voltage gradient guarantees a short range of disturbance but poses also the risk of considerable voltages between objects within a person's reach. This might be amplified by a good conducting object entering the “potential " 9872434639 PAGE. G24 68 ; __Village Klectritication funnel” (for instance a water pipe). It is advisable to maintain a distributed earthing system with scvcral earthing points on the LV side. Fig6 Improvement of the earth potential using several earthing systems. a) ‘steep’ and ‘deep’ potential funnel for a single earth at the transformers . b) the obvious betterment using several earthing systems (for instance at each important consumer’ s connection). Where 12.7 (6.35)kV connections arc used, the earth currents retum to the supply transformer neutral (distribution concept Fig Jc). To minimize the neu- tral current the loads must be evenly balanced be- tween the phases. In: perfect balance the supply transformerneutral carries nocurrentat all (not so the SWER LV distribution transformers!). If the 12.7 (6.35)kV load were, say, 100kVA, and the out of balance is 20%, then the current at the supply neutral would still only be 1.5 (3.0)A. This would not cause problems with losses or neutral displacement even if a 60 Ohm neutral resistor were used. Using a single phase insulating transformer, how- ever, its neutral current will be substantial. For 25.4 (12.7)kV anda rating of 100k V A the maximum earth retum current is 4 (8)A. To keep the carth electrode's voltage at less than 20V the earth resistance mustn't exceed 5 (2.5) Ohm. This voltage is accepted as safc in Australia and New Zealand. lt might be a major obstacle to reach earth resistances lowerthan 10 Ohm. This is, however, essential for a proper SWER sys- tem functioning and must be achieved. At a 10/SKVA distribution transformer, the earth current will be 0.4 (0.8)A. Here the earth resistance mustn't exceed 50 (25) Ohm, which is much Icss stringent. In keeping New Zealand practice, the LV neutral carth should be connected to the same electrode as the HV earth. This allows to keep the neutral potential close to the earth potential. But it also adds asubstan- tial risk: if the earth connection is interrupted, the whole LV wiring is on high potential! MAR 10°93 @9:41 a Risk of high tension on the LV distribution. If the only earthing point is the LV disiribu- tion transformer and this connection is interrupted, high tension appears on the low tension side. This risk is reduced when several earthing systems are used. To minimize this risk, the carth wires down the pole should be duplicated and protected. If steel poles are used, they too should be connected to the carth electrode. 1.5, Insulators In both Australia and New Zealand, standard 11kV insulators have been used on 11kV SWER lines with complete success. This is probably a result of the clean atmosphere in rural locations combined with the highimpulse insulation of wooden crossarms and poles. Where stec] poles and crossarms are uscd, a higher level of insulation might be necessary for 12.7kV SWER lines, so insulators rated for 22kV should be used. 1.6. Electric Motors US rural distribution is primarily single phase 120/ 240V, and they do not hesitate to use quite large single phase motors (3k W and more). In New Zealand, 2.2kW single phase motors arc often used and, in some cases, three phase motors have becn connected to a single phase system by using capacitors to create a third phase. If there is a nced to supply a load with large three phase motors, then the revenue it gencr- ates should pay for the cost of the light 11kV three phase line needed to supply it. If it doesn't, the consumer can be offered the choice of paying to have the line upgraded or to use diese! engines to drive his equipment. 1.7, Example: Cost Comparison To show the possibilities of cost reduction by engi- neering, the following example for a 10km HV line, 3km LV distribution for three kampong in rural Malaysia is shown. The costs arc based on ‘87 prices and might have changed considerably, but in this 9872434639 _ PAGE . 287 conte; absoli Figs we veo Figg ‘ context the relative reduction is important, not its absolute valuc. _ r 240/415 distribut ~w = 3 phase LV distribunon wie . sare | noe tet Te pagagovLW | arth — vn { | 2 1kV ; ——+22 (11)kV HT supply with j the | with ‘ sand ed, a om = for 240/480V LV 240/480V LV : 12kV 240/480V LV i Fig 8 Principle diagram for system A, B and C (corresponds to distribution concept b), a) and c) respectively in fig 1) 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% 2 120/ om aland, nd, in HY conductor setngeng ‘nected HV pin me tatons create = dwith ‘i a gener- i wanctermere f ¢ three ‘ tla pote vt, the d Lv cable rive his : i LV conductor singing j Ainge, snaps. : wetoow ay engi- tend. 4V line, . ie contingencies in rural . : ; haere Fig9 Cost comparison of the three concepts A, B and C. All categories are displayed in percent of System's A total costs. EE IY MAR 18°93 @9:48 98724346393 PAGE. @@S5 Cooperative Association. Lo Z National Rural Electric 1800 Massachusetts Avenue, N.W. Washington, D.C. 20036-1883 Telephone: (202) 857-9500 March 29, 1993 Frank Bettine P.O. Box 112265 Anchorage, Alaska 99511-2265 Dear Frank: This letter is a follow-up to our phone conversation the end of last week. As I mentioned, I am slowly trying to put together a "publication" which will address the issue of alternative technical and organizational designs for reducing distribution costs, in part based on experiences gained by people in different countries. In certain countries, this could be as "simple" as adapting some of the REA standards. It would also address the issue of single-wire ground-return (which is something NRECA has to address, as we have been asked for our thoughts in past efforts but have had no clear technical response). There is also a need to address the issue of the North American vs. European approaches, and while the number of issues to be considered complicate this comparison, it may be that only by considering specific typical load scenarios, rather than simple "serving rural areas in developing countries", will it be possible to get a feel of the advantages of each approach in meeting each load scenario and to determine which approach would be most appropriate for each scenario. Grid extension has a number of advantages over alternatives being proposed, especially PV. But the common argument is that grid extension is too expensive. Depending on the circumstances, this may well be the case as conventionally implemented in a number of countries. But the questions which remains is to what extent can this cost be reduced? While being heavily promoted as "appropriate for developing countries", PV is far from being inexpensive, and even less so over the life cycle, and needs to be heavily subsidized for "rural electrification" under most circumstances. If distribution systems are redesigned to meet the actual needs and conditions encountered in developing countries—e.g., low load growth for a number of years into the future, low cost of labor, etc.—how significantly can distribution costs be reduced—e.g., by smaller conductor or single-phase lines, more labor intensive means of construction, etc., respectively? Frank Bettine March 29, 1993 Page 2 Basically, | am recommending that we do what was done in the 1930s in the U.S. or in Ireland in the 1940s: reassess the conditions and needs in rural areas and then come up with technical and institutional designs which address those needs. I am recommending that we + define and focus on specific typical scenarios that one encounters overseas and + get a better feel of what are the major factors which contribute to the costs of serving each of these scenarios. In this manner, we may start to get an idea of what approaches are most cost-effective and how we might be able to further reduce these costs to increase the affordability of grid extension to meet rural loads. As a part of the publication proposed earlier, I am hoping to include comparative costings of various distribution options for typical scenarios one encounters when serving tural loads overseas. Just to give me an idea of what is possible and if you (or others?) are interested in contributing to this effort, I though that I would present a simplified initial scenario—meeting a single load, i.e., a village, at the end of a primary distribution line —and ask for a comparative costing for that. This first scenario is described on the first of the attached pages and is presented to see if this leads to where I want to go. If you are interested in assisting, would you be able to give some thought to preparing the designs requested and associated costing. Any other thoughts on the exercise I am proposing would be welcomed. Depending on the outcome of this, I would redefine the approach if necessary but should have some funding from our core grant from USAID (while it lasts) to cover the costs of some future consultancy time for subsequent efforts. Let me know your thoughts. :Thanks. Sincerely, (Ml, Pues Allen R. Inversin Senior Project Analyst APPENDIX C VILLAGE POWER REQUIREMENTS Obtained from: BETHEL - NYAC TRANSMISSION LINE FEASIBILITY REPORT, MAY 1992 C.1 EXISTING FACILITIES Electrical energy is supplied, to Bethel and the surrounding villages examined in this study, by diesel generators, and possibly a few gasoline powered units serving individual homes. The largest single source of power is Bethel Utilities, with the electrical load in Bethel being some 5 times greater than the combined total of all the villages included in this study. The following is a tabulation of the estimated 1993 peak load requirements for the 7 villages, Nyac and Bethel. Table C-1 Location 1993 Peak Load (kW) Akiachak 197 Akiak 68 Bethel 5500 Kwethluk 167 Napakiak 165 Napaskiak 92 Nyac 228 Oscarville 16 Tuluksak 76 As previously stated, there are no transmission or distribution interties between these communities with the exception that Napakias 1s interned to Bethel by a SWGR transmission line and Oscarville is connected to Bethel by a conventional single phase distribution line. C.2, HISTORICAL INFORMATION The historical data relied on in performing this study was obtained from primarily from the BETHEL - NYAC TRANSMISSION LINE FEASIBILITY REPORT, prepared May 1992 for Calista Corporation. Secondary sources consists of, Reconnaissance Study of the Kisaralik River Hydroelectric Power Potential and Alternative Energy Resources in the Bethel Area, Alaska Power Authority, 1980, the First Annual Statistical Report of the Power Cost Equalization Program, Alaska Power Authority, 1989, the Second Annual Statistical Report of the Power Cost Equalization Program, Alaska Energy Authority, 1990. The information obtained from these sources indicates a compounded annual population growth rate of between 1.9 and 4 percent for the villages included in this study and generally a moderate increase in the electrical energy usage for each consumer class. C.3. FUTURE ELECTRIC ENERGY AND DEMAND PROJECTIONS Population growth rates of between 1.9 and 4 percent were applied to individual villages based on historical growth rates. The 1989 ratio of residential consumers to population is maintained throughout the study period. A nominal relationship exists between the number of commercial and residential consumers. As the number of residential consumers increase, a greater number of commercial consumers can be supported. The 1989 ratio of small and large commercial consumers to residential consumers is maintained throughout the study period. Electric energy consumption for residential, small and large commercial classes of consumers, including schools is projected to increase at the rate of 1/2 percent per year in all villages. Energy consumption calculations are based on the assumption that village school load requirements, except for Tuluksak, are included as part of the energy consumption listed for each village as found in the two statistical reports of the Power Cost Equalization Program. Annual load factor is assumed to be .40 in 1979, increasing to .50 by 1989 and remaining at .50 throughout the study period. ia, eS ee he x he at 4 5) SOSah nee ' al = =f EEE st =a AKIACHAK Population growth between 1979 and 1989 has averaged approximately 1.9% per year. The growth rate is projected to remain at the same rate during the study period. ELECTRIC POWER AND ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPULATION 371 448 483 583 704 (1) # of Residential 50 107 115 139 168 Consumers (2) Average KWH/no/ —- 130 29 244 256 269 consumer (3) MWB/year residential 78.0 306.9 337.6 «= 428.5 543.9 consumers (1)x(2)x12/1000 (4) # of small comercial 6 20 22 26 31 consumers (5) average KvE/no/ 400 373 381 388 396 consumer (6) M4B/year suall 28.8 © 89.5 100.5 -12k.1147.3 comm. consumer (4)x(5)x12/1000 (7) # of large consumers 1 2 2 3 3 plus public buildings (8) average kWH/no/cons. 15,000 14,775 15,073 15,376 15,686 (9) Mvb/year LP’s 180 9354.6 9361.7 $53.6 = 564.7 (7)x(8)x12/1000 (10) System Muh/year (3)+(6)+(9)+8% Losses 309.7. 811.1 «= -863.8 1,191.4 1,356.4 (11) System Load 04 |||||/0:5 || | (6:5:) || 76:5!) | ‘os Factor (12) (System Demand ki $8.4 185.2 197.2 272.0 309.7 (10) /8.760/(11) AKIAK Population growth between 1979 and 1989 has avera 2.7% per year. The growth rate is study period. j ged approximately projected to remain at this rate during the ELECTRIC POWER AMD ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPULATION 190 247 274 387 464 (1) # of Residential 25 60 67 87 13 Consumers i: (2) Average KWH/n0/ 130 31 256 269 283 consumer (3) MWH/year residential 39.0 180.7 204.8 = 279.8 = 382.3 consumers (1)x(2)x12/1000 (4) # of small commercial 4 5 6. 7 9 consumers (5) average kWH/n0/ 175 378 386 393 401 consuzer (6) HW/year snall 6249202 -2257,1 2127-8 2033.01 143;3 Comm. consumer (4)x(5)x12/1000 (7) 4 of large consumers 1 2 2 3 4 plus public buildings (8) average kWH/no/cons. “8,000 1,700 «1,734 »=—-1,823 1,916 (9) Mwh/year LP’s 96 40.8 41.6 65.6 92.0 (7)x(8)x12/1000 . (10) System Mih/year (3)+(6)+(9)+8% Losses 154.9 263.7. 296.1 408.8 = 559.1 (11) Systes Load 0.4 0.5 0.5 0.5 0.5 Factor (12) (System Demand ki 44.2 60.2 67.6 «= 93.3 127.6 (10) /8.760/(11) KWETHLUK Population growth between 1979 and 1989 has averaged approximately 1.3% per year. The growth rate is projected to remain at the same rate during the study period. ELECTRIC POWER AND ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPOLATION 457 518 545 617 700 (1) # of Residential 74 -136 143 162 184 Consuzers (2) Average KaH/no/ 130 204 208 219 230 consuzer (3) Mi/year residential 115.4 332.9 357.1 425.5 506.9 consuners (1)x(2)x12/1000 (4) ¢ of saall commercial 8 8 8. 10 u consusers S) average kai/20/ 400 632 645 658 671 consumer €, Sa /year suall 38.4 60.7 61.9 78.9 88.6 coma. consumer (4)x(5)x12/1000 ~ 4 of large consumers piss pedlic buildings (8) average kK#i/no/cons. 15,000 10,560 10,773 11,324 11,903 (9) Mwb/year LP’s 180 253.4 258.5 9271.8 = 428.5 (7)x(8)x12/1000 (10) System Mwh/year (3)+(6)+(9)+8% Losses 360.5 698.8 731.7 838.2 1,105.9 (11) System Load 0.4 0.5 0.5 0.5 0.5 Pactor (12) (System Demand ki 102.9 159.5 167.1 191.4 252.5 (10)/8.760/(11) TULUKSAK Population growth between 1979 and 1989 is estimated at approximately 2.2% per year. The growth rate is projected to remain at the same rate during the study period. Data for Tuluksak has been estimated by comparison with Akiachak, Akiak and Napaskiak. As in the other villages, the school power requirements has been included as a large consumer load. ELECTRIC POWER AND ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPULATION 240 301 330 413 518 (1) # of Residential 2 TT 8 10 12 Consumers : (2) Average kWH/no/ 10 250 255 268 282 consumer (3) HWH/year residential 49.9 —219.0- -244.6-_ 322.5_-_425.1 consusers (1)x(2)x12/1000 (4) # of small comercial ‘ 6 7 8 10 consumers (5) average kWH/20/ « 7S 3 390 398 consumer (6) MWH/year suall 39.3 7.9 seek 37.5 47.8 comm. consuzer (4)x(5)x12/1000 (7) # of large consumers 2 2 2 3 3 plus public buildings (8) average KWi/no/cons. $000 1,200 1,281,287 1,353 (9) Mwh/year LP’s 96 = 28.8 29.4 46.3 48.7 (7)x(8)x12/1000 (10) System Mub/year (3)+(6)#(9)#8% Losses 178.3 296.8 330.6 «= 438.7 563.3 _ (12) System Load 0.4 05 05 ~ 0.5 0.5 Factor (12) (System Demand ki 50.9 67.8 75.5 100.2 128.6 (10) /8.760/(11) NAPASKIAK Population growth between 1979 and 1989 has averaged approximately 4% per year. The growth rate is projected to remain at the same rate during the study period. ELECTRIC POWER AMD ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPOLATION 20 31 364 539 798 (1) é of Residential 43 7 83 13 182 Consumers (2) Average KWH/n0/ 175 25 240 252 265 consumer (3) MWH/year residential 90.3 200.2 239.0 +=. 372.0 «= 579.2 consumers (1)x(2)x12/1000 (4) # of suall commercial 5 16 19 28 41 consumers (5) average kWH/no/ 400 251 256 261 266 consumer (6) MWH/year suall 24 48.2 58.4 7.8 0 Dl. comm. consumer (4)x(5)x12/1000 (7) # of large consumers 1 5 6. $ 3B plus public buildings (8) average kWH/no/cons. 10,000 1,020 1,041 1,06 1,150 (9) Mwh/year LP‘s 120 61.2 4.9 8.1 179.4 (7)x(8)x12/1000 (10) System Muh/year (3)+(6)+(9)+8% Losses 253.0 334.4 «402.1 624.2 960.8 (includes losses) (11) system Load 04 5S SS Factor (12) (System Demand kW 72.2 16.3 91.8 142.5 219.4 (10) /8.760/(11) OSCARVILLE Population growth between 1979 and 1989 has averaged approximately 2% per year. The growth rate is projected at the same rate during the study period. ELECTRIC POWER AMD ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPOLATION . 52 64 70 86 105 (1) # of Residential 10 12 B 16 20 Consumers (2) Average kWH/no/ ns 250 255 268 282 consumer (3) MWH/year residential : 4.2 36.0 39.9 51.6 66.8 consumers (1)x(2)x12/1000 (4) # of small commercial 1 2 2 3 3 consumers (5) average KWH/no/ 165 375 383 390 398 consumer / (6) MWB/year small 2.0 9.0 9.2 14.0 14.3 com. consumer (4)x(5)x12/1000 (7) ¢ of large consumers 2 2 1 1 2 plus public buildings (8) average KiH/no/cons. 4,000 1,300 1,326 ~=1,394 1,465 (9) Hwh/year LP's 48 15.6 15.9 16.7 35.2 (7)x(8)x12/1000 (10) Systex Mub/year (3)+(6)+(9)#8% Losses 69.3 65.4 70.2 89.0 125.6 (11) Systes Load 0.4 0.5 0.5 0.5 0.5 Factor (12) (System Demand kw : 19.8 149 16.0 0.387 (10)/8.760/(11) NAPAKIAK Population growth between 1979 and 1989 has averaged approximately 1.9% per year. The growth rate is projected to remain at this rate during the study period. ELECTRIC POWER AND ENERGY REQUIREMENTS 1979-2013 1979 1989 1993 2003 2013 POPULATION 293 353 380 458 552 (1) # of Residential 48 89 96 6 139 Consumers (2) Average kWH/x0/ : 175 251 256 269 283 consumer (3) MWi/year residential 100.8 268.1 294.6 373.1 472.5 consumers (1)x(2)x12/1000 (4) ¢ of suall commercial 6 23 u“ 7 20 consumers (5) average kWH/20/ 400 356 363 370 378 consumer (6) MWB/year small 28.8 55.5 61.0 75.6 90.7 comm. consumer (4)x(5)x12/1000 (7) # of large consuners 1 7 8 9 lu plus public buildings (8) average kWH/no/cons. 15,000 3,180 3,244 3,410 3,584 (9) Hwh/year LP’s 1800 -267.1 0 -311.4 0 368.3 473.1 (7)x(8)x12/1000 (10) System K¥h/year (3)+(6)+(9)#8% Losses 334.4 638.0 720.4 «= 882.3 1,119.3 (11) System Load 0.4 0.5 0.5 0.5 0.5 Pactor (12) (System Demand kM 95.4 145.7 164.5 201.4 255.5 (10) /8.760/(11) NYAC Nyac is basically a mining camp which is only occupied during a 5 month period from late spring through early fall. Energy usage is estimated at 750,000 KWH during this period with a peak demand of 228 kW. This information was estimated from data contained in the "Accepted Draft Report, Nyac Hydroelectric Investigation, Alaska Energy Authority, November 1991." A tabulation of past, and projected village loads and energy requirements can be found in Table 3, titled Electric Power and Energy Requirements for Interconnected Villages.